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201-156
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. You don't often get email from benjamin.walters@hilcorp.com. Learn why this is important From:Lau, Jack J (OGC) To:Benjamin Walters Cc:Abbie Barker; Torin Roschinger Subject:RE: PBU K-317B (PTD: 201-156), Sundry 326-028. Completed Sundry 326-028 Date:Tuesday, January 27, 2026 9:59:12 AM Ben, Your plan below is approved. Jack From: Benjamin Walters <benjamin.walters@hilcorp.com> Sent: Tuesday, January 27, 2026 9:16 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Abbie Barker <Abbie.Barker@hilcorp.com>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: RE: [EXTERNAL] Completed Sundry 326-028 Good morning Jack, This is for PBU K-317B (PTD: 201-156), Sundry 326-028. We are requesting permission for the CDR rig to perform the first service coil rig up steps in the procedure. Here is a summary of the steps from the first service coil rig up. Mill fish at 10,259 ft MD. Mill and tag TD in 2-3/8” slotted liner Run GR/CCL & 24 arm caliper for tie-in Set CBP and test with Baker inflatable packer Perform injectivity test to determine the LLR The CDR rig is waiting on the ice road to move over to Endicott and there is an opportunity for CDR to get there sooner with the ability to perform some of the service coil steps. Talking this over with the Drilling team, we will be using hydril to perform some of the work and would be under CO823. Thank you, Ben Walters GPB GC1 Operations Engineer D, E, F, G, K, P, Y pads C: (907) 214-2028 benjamin.walters@hilcorp.com From: Benjamin Walters Sent: Tuesday, January 27, 2026 8:31 AM To: 'jack.lau@alaska.gov' <jack.lau@alaska.gov> Cc: Abbie Barker <Abbie.Barker@hilcorp.com>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: RE: [EXTERNAL] Completed Sundry 326-028 Good morning Jack, We are requesting permission to perform some of the service coil steps with the CDR rig. The CDR rig is waiting on the Ice road to move over to Endicott and we would like the rig to perform some of the service coil steps. Talking this over with the Drilling team, we will be using hydril to perform some of the work and would be under CO823. Thank you, Ben Walters GPB GC1 Operations Engineer D, E, F, G, K, P, Y pads C: (907) 214-2028 benjamin.walters@hilcorp.com From: Abbie Barker <Abbie.Barker@hilcorp.com> Sent: Monday, January 26, 2026 1:36 PM To: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Benjamin Walters <benjamin.walters@hilcorp.com> Subject: FW: [EXTERNAL] Completed Sundry 326-028 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Gents, See attached approved 10-403 for K-317B Scab Liner Install. Note conditions of approval and annotations in the program. Thank you, Abbie From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Sent: Monday, January 26, 2026 1:30 PM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Daniel Taylor <dtaylor@hilcorp.com>; Darci Horner <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Gordon Piltz - (C) <Gordon.Piltz@hilcorp.com>; Abhijeet Tambe - (C) <abhijeet.tambe@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] Completed Sundry 326-028 Hello, Attached is the completed Sundry for PBU K-317B. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 Grace Christianson at (907-793-1230) or (grace.christianson@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. 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 thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By: Date: APPROVED BY THE AOGCCCOMMISSIONER PBU K-317B Scab Liner Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 201-156 50-029-22537-02-00 ADL 0028303 11935 Surface Intermediate Liner Liner Liner 8830 3672 8482 1397 1362 1657 11902 10-3/4" 7-5/8" 4-1/2" 3-3/16" 2-3/8" 8830 35 - 3707 32 - 8514 8337 - 9734 8993 - 10355 10278 - 11935 2610 35 - 3703 32 - 8302 8155 - 8589 8561 - 8866 8806 - 8830 10259, Unknown 2480 4790 7500 10530 11780 None 5210 6890 8430 10160 11200 10442 - 11902 4-1/2" 12.6# L-80 30 - 83398927 - 8830 Conductor 80 20" 36 - 116 36 - 116 1530 520 4-1/2" Baker S3 Packer No SSSV Installed 8282, 8110 Date: Torin Roschinger Operations Manager Ben Walters benjamin.walters@hilcorp.com 907-564-4899 PRUDHOE BAY 2/1/2026 Current Pools: LISBURNE OIL Proposed Pools: LISBURNE OIL Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2026.01.14 12:36:11 - 09'00' Torin Roschinger (4662) 326-028 By Grace Christianson at 1:01 pm, Jan 14, 2026 *BOP Test 3500 psi, Annular to minimum 2500 psi. A.Dewhurst 16JAN26 10-404 DSR-1/22/26J.Lau 1/26/26JLC 1/26/2026 01/26/26 Haliburton K-317B Coil Flag Aug 24, 2021 (-8 ft shift from reference depths) MIRU 1.5 service coil for 2-3/8 slotted liner (ID = 1.92) MU tie-in logging BHA with GR/CCL & 24 arm Caliper. RIH to ~10,278 MD. Flag pipe and pull tie-in pass for CBP. Tie-in to Haliburton K-317B Coil Flag Aug 24, 2021 (-8 ft shift from reference depths) o o Hilcorp Alaska, LLC Hilcorp Alaska, LLC Set CBP at ~10,242 ft MD 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 K-317B Cement Squeeze Damaged Liner, Liner Lap Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 201-156 50-029-22537-02-00 11935 Surface Intermediate Liner Liner Liner 8830 3672 8482 1397 1362 1657 11902 10-3/4" 7-5/8" 4-1/2" 3-3/16" 2-3/8" 8830 35 - 3707 32 - 8514 8337 - 9734 8993 - 10355 10278 - 11935 35 - 3703 32 - 8302 8155 - 8589 8561 - 8866 8806 - 8830 10259, Unknown 2480 4790 7500 10530 11780 None 5210 6890 8430 10160 11200 10442 - 11902 4-1/2" 12.6# L-80 30 - 8339 8927 - 8830 Conductor 80 20" 36 - 116 36 - 116 1530 520 4-1/2" Baker S3 Packer 8282, 8110 8282 8110 Torin Roschinger Operations Manager Kirsty Glasheen Kirsty.Glasheen@hilcorp.com 907.564.5258 PRUDHOE BAY, LISBURNE OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028303 30 - 8157 8900 - 9075'MD Squeeze 7-bbls of 15.8-ppg Class G Cement with final squeeze pressure = 3000-psi. 232 562 6803 10397 312 2335 1350 1500 178 260 N/A 13b. Pools active after work:LISBURNE OIL No SSSV Installed 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 3:57 pm, Mar 22, 2024 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2024.03.22 14:59:55 -08'00' Torin Roschinger (4662) RBDMS JSB 040224 WCB 2024-07-01 DSR-3/29/24 ACTIVITY DATE SUMMARY 2/28/2024 LRS CTU #2 1.75" CT 0.156" WT - Job Objective: Cement Squeeze MIRU CTU. Make up HES GR/CCL logging tools w/ 2.65" nozzle. Function test BOPs and PT PCE. ***In Progress*** 2/29/2024 LRS CTU #2 1.75" CT - 0.156 WT - Job Objective: Cement Squeeze RIH w/ HES logging BHA (2.2" OD Carrier), 2.65" JSN to 9500' CTM. Log from 9500' to 8000' CTM w/ flag at 9000' CTM. POOH, Load well w/ 220bbls 1% KCL, well on vac @ 4bpm. FP w/ 10bbls meth. Break down logging tools and confirm good data. (+3' Correction, Correlated to HES Coil Flag Log 24-Aug-2021). Replace and pressure test reel swivel. RIH w/ Northern 3-3/16" CBP (2.50" OD). Re-kill Tbg down backside with 173 bbls 1% KCL. Set Top of 3-3/16" CBP at 9075'. Pooh. Keep hole full down backside w/ 1% KCL. Able to maintain positive Whp at 1bpm after setting plug - good sign plug is holding. At surface Injectivity = 1bpm @ ~ 250-300psi. Make up cementing BHA w/ 2.25" BDJSN and RIH keeping hole full w/ KCL pumping down the back side. Bullhead 110bbls diesel down the well for underblance. Roll coil to water and reciprocate across liner from 9075' - 8900'. ***Job In Progress*** 3/1/2024 LRS CTU #2 1.75" CT - 0.156" Wall - Job Scope: Cement Squeeze Jet 1% KCL across Liner/Holes down to CBP from 8900' - 9075'. No issues passing thru parted Liner, holes or Dep Slv. Park nozzle at 9070' (~ 5' above CBP). Pump 15.8ppg Class G Cement. Let 1 bbl around nozzle and lay in up to 8900' (above all holes and parted Lnr). Close the choke and continue pumping Cement. Achieved bump very quickly up to 1800psi Whp. Cut cement at surface and lay in a full Coil volume of Cement up to 6500'. Close choke and PUH to Safety. Apply Squeeze pressure in 500psi increments up to 3000psi. Hold 3000psi for 10 mins. Whp lost 100psi. Slowly bleed pressure back to ~ 700psi. Estimate ~ 7 bbls behind pipe. Circulate Powervis to Nozzle and cleanout Cement. Hit a hard Tag at 8912' (above all holes and parted Lnr). Unable to jet thru at max rate 3bpm at ~ 4100psi Circ Pressure. Try over 1hr trying different rates and speeds with no success. Tagging hard Cement at 8912' still within 2/3 of Thickening Time remaining. Pump final Gel Sweep and Chase OOH at 80%. Reciprocate across GLM's. Jet BOP's. RBIH and lay in Diesel FP from 1:1 returns entire time cleaning out. Recover 5/8" steel ball. Perform Weekly BOP Test. Make up BOT Motor/Mill. Stab on PT, and RIH. ***In Progress*** Daily Report of Well Operations PBU K-317B () g Set Top of 3-3/16" CBP at 9075'. Pooh. Keep hole full down backside w/ 1% KCL. Able to maintain positive Whp at 1bpm after setting plug - good sign plug is holding. Park nozzle at 9070' (~ 5' above CBP). Pump () 15.8ppg Class G Cement. Let 1 bbl around nozzle and lay in up to 8900' (above allgy( holes and parted Lnr). Close the choke and continue pumping Cement. Achieved )g bump very quickly up to 1800psi Whp. Cut cement at surface and lay in a full Coil yy y volume of Cement up to 6500'. Close choke and PUH to Safety. Apply Squeezeyy pressure in 500psi increments up to 3000psi. Hold 3000psi for 10 mins. Whp lost 100psi. Slowly bleed pressure back to ~ 700psi. Estimate ~ 7 bbls behind pipe. y Circulate Powervis to Nozzle and cleanout Cement. Hit a hard Tag at 8912' (above g( all holes and parted Lnr). Unable to jet thru at max rate 3bpm at ~ 4100psi Circ)j Pressure. Try over 1hr trying different rates and speeds with no success. Tagging yyg ggg hard Cement at 8912' still within 2/3 of Thickening Time remaining. Pump final Gel g Sweep and Chase OOH at 80%. Reciprocate across GLM's Jet 1% KCL across Liner/Holes down to CBP from 8900' - 9075'. No issues passing thru parted Liner, holes or Dep Slv g Roll coil to water and reciprocate across liner from 9075' - 8900'. Daily Report of Well Operations PBU K-317B 3/2/2024 LRS CTU #2 1.75" CT - 0.156" Wall - Job Scope: Cement Squeeze Continue RIH w/ Baker 3.79" Junk Mill (w/ 3.79" Stabilizer above Motor). Start seeing cement stringers at ~ 8200'. Work through w/ mill to XN Nip @ 8327' MD. Run mill through XN Nip and make several passes through area to ensure it's clear. Work down to 8728' CTM and hit hard cement. Mill Cement. Run into hard stalls at 8972' ctm. Unable to mill past this depth. Having immediate Stalls. Suspect 4-1/2" parted Lnr. Discuss w/ OE. Chase OOH to change up BHA. RIH w/ Baker 3.79" String MIll & 3.79" Round Nosed Mill. RIH and dry tag @ 8954'. Begin milling down to 8969' and hard stall. Work mill to depth a couple times w/ hard stalls. Able to start getting good motor work at 8969' and slowly mill. When attempting to PUH to reset become bit stuck. Attempt to free tools. Jars not hitting up. Pressure up and dump backside. Still bit stuck. ***Standby 1.5hrs waiting on Worley Vac Truck to deliver KCL Fluids. Call out ASRC Adhoc Vac Truck to help get caught up on Fluids*** ***In Progress*** 3/3/2024 LRS CTU #2 1.75" CT - 0.156" WT Bit stuck @ ~8966'. Continue to work pipe, pump gel pill. Max pull 55k-60k. Can't get jars to hit up. Circulate safelube around for better weight transfer. Finally get up Jar Licks after stacking down for 15mins and bleeding Coil pressure off. No movement after 48 cycles, Circulate 60/40 Meth around to Freeze Protect Coil, well and surface lines. Pump 7/8" disconnect ball. Ball on seat, pressure to 7100psi and shear. Disco released POOH. Break down tools and cut 150' of pipe. Make up Baker fishing BHA w/ 3" GS Spear and RIH. ***In Progress*** 3/4/2024 LRS CTU #2 1.75" CT - 0.156" WT Job Objective: Cement squeeze Continue in hole w/ Baker Fishing BHA 3" G Spear. Latch up to fish and begin jarring pulling to max pull of 55k. Hit 41 jar licks and come free. POOH to check tools. Recover Milling BHA Fish. No obvious signs that we were milling on metal, mill and string reamer are clean. Discuss w/ OE. Trim 150' of pipe. RIH w/ Baker 3.60" Tapered Milling BHA. ***In Progress*** Bit stuck @ ~8966'. Continue to work pipe, pump gel pill. Max pull 55k-60k. Can't @g get jars to hit up. Circulate safelube around for better weight transfer. Finally get up gj g Jar Licks after stacking down for 15mins and bleeding Coil pressure off. No gg movement after 48 cycles, Circulate 60/40 Meth around to Freeze Protect Coil, well y and surface lines. Pump 7/8" disconnect ball. Ball on seat, pressure to 7100psi and shear. Disco released POOH. Break down tools and cut 150' of pipe. Make up Baker fishing BHA w/ 3" GS Spear and RIH. Continue RIH w/ Baker 3.79" Junk Mill (w/ 3.79" Stabilizer above Motor). Start seeing () cement stringers at ~ 8200'. Work through w/ mill to XN Nip @ 8327' MD. Run millgg@ through XN Nip and make several passes through area to ensure it's clear. Workgg down to 8728' CTM and hit hard cement. Mill Cement. Run into hard stalls at 8972' ctm. Unable to mill past this depth. Having immediate Stalls. Suspect 4-1/2" parted g Lnr. Discuss w/ OE. Chase OOH to change up BHA. RIH w/ Baker 3.79" String MIll gg & 3.79" Round Nosed Mill. RIH and dry tag @ 8954'. Begin milling down to 8969' yg@ g g and hard stall. Work mill to depth a couple times w/ hard stalls. Able to start getting gg good motor work at 8969' and slowly mill. When attempting to PUH to reset become gyg bit stuck. Attempt to free tools. Jars not hitting up. Pressure up and dump backside. Still bit stuck j Continue in hole w/ Baker Fishing BHA 3" G Spear. Latch up to fish and begin jarringggj pulling to max pull of 55k. Hit 41 jar licks and come free. POOH to check tools. gj Recover Milling BHA Fish. No obvious signs that we were milling on metal, mill and ggg string reamer are clean. Discuss w/ OE. Trim 150' of pipe. RIH w/ Baker 3.60" g Tapered Milling BHA. Daily Report of Well Operations PBU K-317B 3/5/2024 LRS CTU #2 1.75" 0.156" CT Job Scope: Cement Squeeze Finish breaking down 3-1/8" tools, marks on tapered mill face in the 2.9" - 3.2" range. Make up Baker 2-1/8" motor/mill assembly w/ 2.70" 5-bladed junk mill. RIH w/ motor/mill, Dry drift passed previous tag (8969') to 8978'. Begin milling cement from 8978'. Mill Cement at a consistent ROP from 0.7 -1 fpm with 1:1 returns. Stalled at 9045'. Could be the CBP. Pump Gel Sweep and circulate out. Pressure Test Squeeze to 1075psi. Lost 417psi in 20 mins. Inform OE. Resume milling. Continue milling cement. Lost returns at 9056' (CBP). Returns came back shortly after plug let loose to 1:1. Push plug to the 2.70" Dep Slv at 10259'. Pooh. Freeze Protect Coil w/ Diesel. RIH w/ 2-1/8" Venturi + 2.70" Burnshoe. No issues passing thru parted liner or dep slv. Tag at 10259'. Attempt to burnover CBP. Pooh. Drop 1/2" ball and open circ-sub. Lay in Diesel FP from 2500' TVD. Check tools at surface. ***No core Recovered*** Slips, shavings and some cement in burn shoe. RDMO ***Job Complete*** 3/6/2024 ***WELL S/I ON ARRIVAL*** RAN 4.5" BRUSH, 3.80" G. RING TO X NIP @ 8306' MD SET 3.81" X LOCK DREAMCATCHER IN X NIP @ 8306' MD RAN 4.50" CHECK SET (Good) ***CONT WSR ON 03-07-2024*** 3/7/2024 ***WSR CONT FROM 03-06-2024*** RIG DOWN POLLARD UNIT 61 *** WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED OF WELL STATUS*** Resume milling. Continue g milling cement. Lost returns at 9056' (CBP). Returns came back shortly after plug let g() loose to 1:1. Push plug to the 2.70" Dep Slv at 10259'. Pooh. RIH w/yj motor/mill, Dry drift passed previous tag (8969') to 8978'. Begin milling cement fromyg()gg 8978'. Mill Cement at a consistent ROP from 0.7 -1 fpm with 1:1 returns. Stalled at 9045'. Could be the CBP. 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 K-317B Pull LTP, Patch Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 201-156 50-029-22537-02-00 11935 Surface Intermediate Liner Liner Liner 8830 3672 8482 1397 1362 1657 11935 10-3/4" 7-5/8" 4-1/2" 3-3/16" 2-3/8" 8830 35 - 3707 32 - 8514 8337 - 9734 8993 - 10355 10278 - 11935 35 - 3703 32 - 8302 8155 - 8589 8561 - 8866 8806 - 8830 Unknown 2480 4790 7500 10530 11780 None 5210 6890 8430 10160 11200 10442 - 11902 4-1/2" 12.6# L-80 30 - 8339 8927 - 8830 Conductor 80 20" 36 - 116 36 - 116 1530 520 4-1/2" Baker S3 Packer 8282, 8110 8282 8110 Stan Golis Sr. Area Operations Manager Kirsty Glasheen Kirsty.Glasheen@hilcorp.com 907.564.5258 PRUDHOE BAY, LISBURNE OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028303 30 - 8157 N/A N/A 232 Well Not Online 6803 312 1350 1200 178 1060 N/A 13b. Pools active after work:LISBURNE OIL No SSSV Installed 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 Meredith Guhl at 7:33 am, Jan 23, 2023 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2023.01.20 16:29:13 -09'00' Stan Golis (880) PRUDHOE BAY, LISBURNE OIL 201-156 WCB 11-3-2023 PBU K-317B Pull LTP, Patch Sundry Number DSR-1/23/23 RBDMS JSB 020723 N/A ACTIVITY DATE SUMMARY 1/4/2023 ***WELL S/I ON ARRIVAL*** (Profile modification) TAG 45KB LTP AT 8,916' SLM / 8,945' MD W/ 3.80" SWAGE (Ring from fish neck). THUNDERBIRD LOADED TUBING W/ 220 BBLS OF CRUDE. SET, TEST, & PULL 2.813" CAT STANDING VALVE FROM 8,916' SLM / 8,945' MD. THUNDERBIRD PERFORMED SUCCESSFUL MIT-T TO 2121 PSI. RAN 4-1/2" GS (Dogless) TO 45KB LTP AT 8,945' MD (Sheared - High deviation test run). ***JOB IN PROGRESS, CONTINUED ON 1/5/23 WSR*** 1/4/2023 Assist SL with Load and test TBG (PROFILE MODIFICATION) Pumped 221 bbls crude down Tbg to load, MIT-T to 2250 psi max applied ****PASSED**** Pumped 3 bbls crude down Tbg to reach test pressure 1st 15 min Tbg lost 102 psi 2nd 15 min Tbg lost 34 psi Passed at 2121 psi Bled back ~ 2 bbls crude Slickline in control of well per departure FWHP's 268/1238/73 1/5/2023 ***CONTINUED FROM 1/4/23 WSR*** (Profile modification) LATCH 45KB LTP AT 8,916' SLM W/ 4-1/2" GR (Sheared in 10 oil jar hits). POLLARD #60 ON WEATHER HOLD DUE TO HIGH WINDS. ***JOB IN PROGRESS, CONTINUED ON 1/6/23 WSR*** 1/6/2023 ***CONTINUED FROM 1/5/23 WSR*** (Profile modification) POLLARD #60 ON WEATHER HOLD DUE TO HIGH WINDS. ***JOB IN PROGRESS, CONTINUED ON 1/7/23 WSR*** 1/7/2023 ***CONTINUED FROM 1/6/23 WSR*** (Profile modification) POLLARD #60 WEATHER HOLD DUE TO HIGH WINDS. PULL COMPLETE BAKER 45KB LTP W/ SNAP LATCH FROM 8,916' SLM. PULL SNAP LATCH RECEPTACLE SPACER W/ SNAP LATCH #2, #3, & #4. CURRENTLY RIH W/ 3-1/2" GS TO PULL NS 350-272 ANCHOR PACKER. ***JOB IN PROGRESS, CONTINUED ON 1/8/23 WSR*** 1/8/2023 ***CONTINUED FROM 1/7/23 WSR*** (Profile modification) PULL NS 350-272 ANCHOR PACKER (Missing 1-1/2 elements) ASSEMBLY FROM 8,984' SLM. DRIFT TO DEVIATION AT 8,991' SLM W/ 3-1/2" BRUSH, 2.63" WIRE GRAB (No recovery). ***WELL S/I ON DEPARTURE, NOTIFIED PAD OPERATOR OF WELL STATUS*** Daily Report of Well Operations PBU K-317B PULL SNAP LATCH RECEPTACLE SPACER W/ SNAP LATCH #2, #3, & #4. CURRENTLY RIH W / 3-1/2" GS TO PULL NS 350-272 ANCHOR PACKER THUNDERBIRD PERFORMED SUCCESSFUL MIT-T TO 2121 PSI. The LTP was pulled from the top of the 3-3/16" liner. The new WBS only shows the deployment sleeve, as it should. -WCB PULL COMPLETE BAKER 45KB LTP W / SNAP LATCH FROM 8,916' SLM. ( TAG 45KB LTP AT 8,916' SLM / 8,945' MD () LATCH 45KB LTP AT 8,916' SLM W/ 4-1/2" GR (Sheared in 10 oil jar hits). 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:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: Producer K-317 (PTD #201156) TIFL Passed post GLV changeout Date:Thursday, November 10, 2022 4:31:23 PM Attachments:image001.png Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Wednesday, November 9, 2022 12:19 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Stan Golis <sgolis@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: OPERABLE: Producer K-317 (PTD #201156) TIFL Passed post GLV changeout All, Producer K-317B (PTD #201156) passed a TIFL on 11/08/22 post gas lift valve changeout which verifies tubing integrity. At this time, the well is classified as OPERABLE. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: PB Wells Integrity Sent: Monday, October 17, 2022 2:08 PM To: jim.regg@alaska.gov Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Stan Golis <sgolis@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: UNDER EVALUATION: Producer K-317 (PTD #201156) Sustained Casing Pressure Over NOL IA Mr. Regg, Producer K-317B (PTD #201156) was reported by operations with IA casing pressure over NOL ~2130 psi on 10/17/22. A subsequent TIFL failed which verifies failure of one or more well barriers. At this time, the well is classified as UNDER EVALUATION and on a 28 day clock to be resolved. Plan Forward: 1. Slickline: Change out gas lift valves 2. Downhole Diagnostics: TIFL 3. Well Integrity: Further action as needed. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Wednesday, January 22, 2020 1:16 PM To: 'Regg, James B (DOA) (jim.regg@alaska.gov)' <jim.regg@alaska.gov>; AK, OPS EOC Specialists <AKOPSEOCSpecialists@bp.com>; Ak, OPS GC1 Facility PTL <AkOPSGC1FacilityPTL@bp.com>; Ak, OPS GC1 Field PTL <AkOPSGC1FieldPTL@bp.com>; AK, OPS GC1 OSM <AKOPSGC1OSM@bp.com>; AK, OPS GC1 Wellpad Lead <AKOPSGC1WellpadLead@bp.com>; AK, OPS PCC Ops Lead <AKOPSPCCOpsLead@bp.com>; AK, OPS Prod Controllers <akopsprodcontrollers1@bp.com>; AK, OPS Well Pad DG <AKOPSWellPadDG@bp.com>; AK, OPS Well Pad EKG <AKOPSWellPadEKG@bp.com>; AK, OPS Well Pad YP <AKOPSWellPadYP@bp.com>; Ak, Ops West Area TL <AkOpsWestAreaTL@bp.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt2@bp.com>; AKOpsProdEOCTL <AKOPSPCCEOCTL@bp.com>; Derrick, Laurie R <Laurie.Derrick@bp.com>; Stone, Christopher <Christopher.Stone@bp.com> Cc: 'chris.wallace@alaska.gov' <chris.wallace@alaska.gov>; AK, GWO Completions Well Integrity <AKDCWLCompletionsSupt@bp.com>; AK, GWO DHD Well Integrity <AKD&CDHDWellIntegri@bp.com>; AK, GWO Projects Well Integrity <AKDCProjectsWellIntegrityEngineer@bp.com>; AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com>; AK, GWO Well Integrity Well Information <akgwowellintegritywe@bp.com>; AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com>; AKIMS App User <akimsuser.service@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; Dempsey, David G <David.Dempsey1@bp.com>; Hibbert, Michael <Michael.Hibbert@BP.com>; Janowski, Carrie <Carrie.Janowski@bp.com>; Montgomery, Travis J <Travis.Montgomery@bp.com>; Obrigewitch, Beau <BEAU.OBRIGEWITCH@bp.com>; Smith, Travis T (CONOCOPHILLIPS) <travis.smith1@bp.com>; Sternicki, Oliver R <Oliver.Sternicki@bp.com>; Tempel, Joshua <Joshua.Tempel@bp.com>; Worthington, Aras J <Aras.Worthington@bp.com> Subject: OPERABLE: Producer K-317 (PTD #2011560) passed warm TIFL post OGLV change out All, Producer K-317 (PTD # 2011560) was made Under Evaluation on 01/11/20 for anomalous inner annulus casing pressure above NOL and failing a warm TIFL. On 01/19/20 Slickline replaced the screened orifice and on 01/22/20 DHD performed a passing warm TIFL. The passing TIFL indicates the well has two competent barriers to formation and will now be classified as OPERABLE. Please respond with any questions. Andrew Ogg Well Integrity Engineer BP Global Wells Organization – Alaska Office: 907-659-8110 From: AK, GWO Well Integrity Well Information <akgwowellintegritywe@bp.com> Sent: Saturday, January 11, 2020 7:22 AM To: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com>; AK, OPS EOC Specialists <AKOPSEOCSpecialists@bp.com>; Ak, OPS GC1 Facility PTL <AkOPSGC1FacilityPTL@bp.com>; Ak, OPS GC1 Field PTL <AkOPSGC1FieldPTL@bp.com>; AK, OPS GC1 OSM <AKOPSGC1OSM@bp.com>; AK, OPS GC1 Wellpad Lead <AKOPSGC1WellpadLead@bp.com>; AK, OPS PCC Ops Lead <AKOPSPCCOpsLead@bp.com>; AK, OPS Prod Controllers <akopsprodcontrollers1@bp.com>; AK, OPS Well Pad DG <AKOPSWellPadDG@bp.com>; AK, OPS Well Pad EKG <AKOPSWellPadEKG@bp.com>; AK, OPS Well Pad YP <AKOPSWellPadYP@bp.com>; Ak, Ops West Area TL <AkOpsWestAreaTL@bp.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt2@bp.com>; AKOpsProdEOCTL <AKOPSPCCEOCTL@bp.com>; Derrick, Laurie R <Laurie.Derrick@bp.com>; Stone, Christopher <Christopher.Stone@bp.com>; Sauve, Mark A <Mark.Sauve@bp.com> Cc: AK, GWO Completions Well Integrity <AKDCWLCompletionsSupt@bp.com>; AK, GWO DHD Well Integrity <AKD&CDHDWellIntegri@bp.com>; AK, GWO Projects Well Integrity <AKDCProjectsWellIntegrityEngineer@bp.com>; AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com>; AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com>; AKIMS App User <akimsuser.service@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; Dempsey, David G <David.Dempsey1@bp.com>; Dickerman, Eric <Eric.Dickerman@bp.com>; Hibbert, Michael <Michael.Hibbert@BP.com>; Janowski, Carrie <Carrie.Janowski@bp.com>; Montgomery, Travis J <Travis.Montgomery@bp.com>; Obrigewitch, Beau <BEAU.OBRIGEWITCH@bp.com>; O'connor, Katherine <Katherine.O'connor@bp.com>; Sternicki, Oliver R <Oliver.Sternicki@bp.com>; Tempel, Joshua <Joshua.Tempel@bp.com>; Worthington, Aras J <Aras.Worthington@bp.com> Subject: UNDER EVALUATION: Producer K-317B (PTD #2011560) Sustained Casing Pressure IA All, Producer K-317 (PTD #2011560) was called in for IA pressure over NOL while shut in on 01/05/20. On 01/08/20 DHD performed a failing TIFL indicating failed primary well barrier. The well is now classified as UNDER EVALUATION and is on the 28 day clock for repair. Plan forward: 1. Slickline: Change out GLV’s 2. DHD: Warm TIFL 3. WIE: Additional diagnostics as needed Please respond with any questions. Ryan Holt Well Integrity BP Global Wells Organization – Alaska Office: 907-659-5102 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 messageand 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 asit considers appropriate. 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:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: UNDER EVALUATION: Producer K-317 (PTD #201156) Sustained Casing Pressure Over NOL IA Date:Monday, October 17, 2022 2:44:19 PM Attachments:image001.png PBU K-317 (PTD 2011560) Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Monday, October 17, 2022 2:08 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Stan Golis <sgolis@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: UNDER EVALUATION: Producer K-317 (PTD #201156) Sustained Casing Pressure Over NOL IA Mr. Regg, Producer K-317B (PTD #201156) was reported by operations with IA casing pressure over NOL ~2130 psi on 10/17/22. A subsequent TIFL failed which verifies failure of one or more well barriers. At this time, the well is classified as UNDER EVALUATION and on a 28 day clock to be resolved. Plan Forward: 1. Slickline: Change out gas lift valves 2. Downhole Diagnostics: TIFL 3. Well Integrity: Further action as needed. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Wednesday, January 22, 2020 1:16 PM To: 'Regg, James B (DOA) (jim.regg@alaska.gov)' <jim.regg@alaska.gov>; AK, OPS EOC Specialists <AKOPSEOCSpecialists@bp.com>; Ak, OPS GC1 Facility PTL <AkOPSGC1FacilityPTL@bp.com>; Ak, OPS GC1 Field PTL <AkOPSGC1FieldPTL@bp.com>; AK, OPS GC1 OSM <AKOPSGC1OSM@bp.com>; AK, OPS GC1 Wellpad Lead <AKOPSGC1WellpadLead@bp.com>; AK, OPS PCC Ops Lead <AKOPSPCCOpsLead@bp.com>; AK, OPS Prod Controllers <akopsprodcontrollers1@bp.com>; AK, OPS Well Pad DG <AKOPSWellPadDG@bp.com>; AK, OPS Well Pad EKG <AKOPSWellPadEKG@bp.com>; AK, OPS Well Pad YP <AKOPSWellPadYP@bp.com>; Ak, Ops West Area TL <AkOpsWestAreaTL@bp.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt2@bp.com>; AKOpsProdEOCTL <AKOPSPCCEOCTL@bp.com>; Derrick, Laurie R <Laurie.Derrick@bp.com>; Stone, Christopher <Christopher.Stone@bp.com> Cc: 'chris.wallace@alaska.gov' <chris.wallace@alaska.gov>; AK, GWO Completions Well Integrity <AKDCWLCompletionsSupt@bp.com>; AK, GWO DHD Well Integrity <AKD&CDHDWellIntegri@bp.com>; AK, GWO Projects Well Integrity <AKDCProjectsWellIntegrityEngineer@bp.com>; AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com>; AK, GWO Well Integrity Well Information <akgwowellintegritywe@bp.com>; AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com>; AKIMS App User <akimsuser.service@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; Dempsey, David G <David.Dempsey1@bp.com>; Hibbert, Michael <Michael.Hibbert@BP.com>; Janowski, Carrie <Carrie.Janowski@bp.com>; Montgomery, Travis J <Travis.Montgomery@bp.com>; Obrigewitch, Beau <BEAU.OBRIGEWITCH@bp.com>; Smith, Travis T (CONOCOPHILLIPS) <travis.smith1@bp.com>; Sternicki, Oliver R <Oliver.Sternicki@bp.com>; Tempel, Joshua <Joshua.Tempel@bp.com>; Worthington, Aras J <Aras.Worthington@bp.com> Subject: OPERABLE: Producer K-317 (PTD #2011560) passed warm TIFL post OGLV change out All, Producer K-317 (PTD # 2011560) was made Under Evaluation on 01/11/20 for anomalous inner annulus casing pressure above NOL and failing a warm TIFL. On 01/19/20 Slickline replaced the screened orifice and on 01/22/20 DHD performed a passing warm TIFL. The passing TIFL indicates the well has two competent barriers to formation and will now be classified as OPERABLE. Please respond with any questions. Andrew Ogg Well Integrity Engineer BP Global Wells Organization – Alaska Office: 907-659-8110 From: AK, GWO Well Integrity Well Information <akgwowellintegritywe@bp.com> Sent: Saturday, January 11, 2020 7:22 AM To: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com>; AK, OPS EOC Specialists <AKOPSEOCSpecialists@bp.com>; Ak, OPS GC1 Facility PTL <AkOPSGC1FacilityPTL@bp.com>; Ak, OPS GC1 Field PTL <AkOPSGC1FieldPTL@bp.com>; AK, OPS GC1 OSM <AKOPSGC1OSM@bp.com>; AK, OPS GC1 Wellpad Lead <AKOPSGC1WellpadLead@bp.com>; AK, OPS PCC Ops Lead <AKOPSPCCOpsLead@bp.com>; AK, OPS Prod Controllers <akopsprodcontrollers1@bp.com>; AK, OPS Well Pad DG <AKOPSWellPadDG@bp.com>; AK, OPS Well Pad EKG <AKOPSWellPadEKG@bp.com>; AK, OPS Well Pad YP <AKOPSWellPadYP@bp.com>; Ak, Ops West Area TL <AkOpsWestAreaTL@bp.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt2@bp.com>; AKOpsProdEOCTL <AKOPSPCCEOCTL@bp.com>; Derrick, Laurie R <Laurie.Derrick@bp.com>; Stone, Christopher <Christopher.Stone@bp.com>; Sauve, Mark A <Mark.Sauve@bp.com> Cc: AK, GWO Completions Well Integrity <AKDCWLCompletionsSupt@bp.com>; AK, GWO DHD Well Integrity <AKD&CDHDWellIntegri@bp.com>; AK, GWO Projects Well Integrity <AKDCProjectsWellIntegrityEngineer@bp.com>; AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com>; AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com>; AKIMS App User <akimsuser.service@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; Dempsey, David G <David.Dempsey1@bp.com>; Dickerman, Eric <Eric.Dickerman@bp.com>; Hibbert, Michael <Michael.Hibbert@BP.com>; Janowski, Carrie <Carrie.Janowski@bp.com>; Montgomery, Travis J <Travis.Montgomery@bp.com>; Obrigewitch, Beau <BEAU.OBRIGEWITCH@bp.com>; O'connor, Katherine <Katherine.O'connor@bp.com>; Sternicki, Oliver R <Oliver.Sternicki@bp.com>; Tempel, Joshua <Joshua.Tempel@bp.com>; Worthington, Aras J <Aras.Worthington@bp.com> Subject: UNDER EVALUATION: Producer K-317B (PTD #2011560) Sustained Casing Pressure IA All, Producer K-317 (PTD #2011560) was called in for IA pressure over NOL while shut in on 01/05/20. On 01/08/20 DHD performed a failing TIFL indicating failed primary well barrier. The well is now classified as UNDER EVALUATION and is on the 28 day clock for repair. Plan forward: 1. Slickline: Change out GLV’s 2. DHD: Warm TIFL 3. WIE: Additional diagnostics as needed Please respond with any questions. Ryan Holt Well Integrity BP Global Wells Organization – Alaska Office: 907-659-5102 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 intendedrecipient 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 inerror, 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 messageand 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. Operator Name:2. Development Exploratory Service 5 Permit to Drill Number:201-156 6.50-029-22537-02-00 PRUDHOE BAY, LISBURNE OIL Hilcorp North Slope, LLC 5. Well Name and Number:8. 10.Field/Pools: Well Class Before Work4. Present Well Condition Summary:11. Total Depth: measured feet feet Plugs measured feet feet Effective Depth: measured feet feet Packer measured feet feettrue vertical true vertical 11935 11935 8830 8282 / 8347 8947 None 8110 / 8164 Casing: Length: Size: MD: TVD: Burst: Collapse: Conductor 80 20" 39 - 119 39 - 119 1530 520 Surface 3670 10-3/4" 37 - 3707 37 - 3703 5210 2480 Intermediate 8479 7-5/8" 35 - 8514 35 - 8302 6890 4790 Liner 1397 4-1/2" 8337 - 9734 8155 - 8589 8430 7500 Liner 1362 3-3/16" 8993 - 10355 8561 - 8866 10160 10530 Perforation Depth: Measured depth: 10442 - 11902 feet True vertical depth:8927 - 8830 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# L-80 33 - 8339 33 - 8157 8282 / 8347 8110 / 8164Packers and SSSV (type, measured and true vertical depth) BKR S-3 / TIW S-6 Liner 1657 2-3/8" 10278 - 11935 8806 - 8830 11200 11780 12. Stimulation or cement squeeze summary: Intervals treated (measured): Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 176 514 350 1548 4612 2522 1150 28350 443 195 Representative Daily Average Production or Injection Data Prior to well operation: Subsequent to operation: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Contact Email: Noel Nocas noel.nocas@hilcorp.com Authorized Name:Stan Golis Authorized Title: Authorized Signature with Date:Contact Phone:907.564.5278 Treatment descriptions including volumes used and final pressure: 13. Sr Operations Manager Operations Performed1. Abandon Plug Perforations Fracture Stimulate Pull Tubing GSTOR WINJ WAG GINJ SUSP SPLUG 16. Well Status after work:Oil 5 Gas Exploratory Development 5 Stratigraphic 15. Well Class after work: Service WDSPL 14. Attachments: (required per 20 AAC 25.070.25.071, & 25.283) Daily Report of Well Operations Copies of Logs and Surveys Run true vertical measured8830 Sundry Number or N/A if C.O. Exempt: N/A No SSSV Installed Junk Packer Printed and Electronic Fracture Stimulation Data 5 Pull/Set LTP Operations shutdown Change Approved Program 5 Senior Pet Engineer:Senior Res. Engineer: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Suspend Perforate Other Stimulate Alter Casing Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well5 3.Address: 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 7.Property Designation (Lease Number):ADL 0028303 LISB K-317B 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): Stratigraphic Other: API Number: Form 10-404 Revised 03/2020 Submit Within 30 days of Operations By Meredith Guhl at 8:56 am, Sep 03, 2021 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2021.09.02 12:15:47 -08'00' Stan Golis (880) DSR-9/3/21 SFD 9/7/2021RBDMS HEW 9/3/2021 MGR11OCT2021 ACTIVITYDATE SUMMARY 8/22/2021 CTU #6 1.75" CT Job Objective: Fish LTP/ Caliper / Set New LTP MIRU CTU. ***Continued on 08/23/21*** 8/23/2021 CTU #6 1.75" CT Job Objective: Fish LTP/ Caliper / Set New LTP Make up Baker Fishing BHA w/ 3.65" WFD Retrieval Tool. Latch into ER packer and hit 5 up jar licks and came free. Upper packer and spacer retrieved with all slips and elements. Make up Spacer Pipe Fising BHA with 4-1/2" hydraulic GS and RIH. Straight pull 20k over and pop free. POOH and recover Spacer Pipe. All seals recovered and no signs of erosion. M/U & RIH w/WFT 2.71" Retrieval Tool. Unable to latch 3.5" WidePak, friction bites 3-5k over. Online down coil and jet on 3.5" WFT WidePak. Attempt to latch 3-8k down, friction bites. Pooh to inspect BHA. On surface w/WFT 2.71" Retrieval Tool. C/O pulling tool to BOT 3" sure catch (2.55" slip OD). RIH w/BHA. ***Comtinued on 08/24/21*** 8/24/2021 CTU #6 1.75" CT Job Objective: Fish LTP/ Caliper / Set New LTP RIH w/BOT 3" hydraulic G-spear. Latch 3.5" WFT WidePak - 10k over at 8,990' ctm. Hit one jar lick and release, RIH and travel freely 10' past latch depth. Pooh w/BHA. Recovered 3.5" WFT WidePak PKR w/mule shoe WLEG. M/U Drift BHA & RIH w/2.74" drift bar & 2.67" DJN, run down to 9,250' ctm w/no issues. Pooh w/BHA. Make up HES logging BHA GR/CCL/24 Arm Caliper. RIH to top of 2-3/8" deployment sleeve at 10277' CTMD. Log up to 8000' stopping to paint a white/red tie-in flag at 8900'. POOH and confirm +21' correction, Corrected EOP @ Flag = 8,899.61'. Caliper data sent for rapid processing. Make up drfit BHA with 3.70" JSN and RIH. Tie-in at flag and confirm clean drift across liner hole to TOL at 8996'. POOH. On surface w/3.70" drift. Review HES caliper analysis, discussed plan forward with OE. Make up NS 2.72" lower packer BHA (BHA OAL = 31.89', EOP to TOE = 23.2'). RIH w/lower packer BHA. ***Job In progress*** 8/25/2021 CTU #6 1.75" CT Job Objective: Fish LTP/ Caliper / Set New LTP Continue RIH w/lower packer BHA. At flag corrected EOP = 8,899.61' + 23.2' (EOP to COE) = 8,922.81' MD. Correct counter and set lower packer COE at 9,042' MD, Top of snap latch receptacle at 9031'. Pooh w/BHA. Make up & RIH Spacer Pipe BHA #1 with snap latch pinned to 7.3k. Tie-in to flag to confirm spacing, set into lower packer section and confirm with 4.5k overpull. Top of snap latch receptacle at 9009'. Pump off and POOH. Trim 50' of pipe and change pack-ofs, chain insp. Make up Spacer Pipe BHA #2 with snap latch pinned to 5.6k and RIH. Tie-in to flag to confirm spacing, set into lower packer section and confirm with 3k overpull.Top of snap latch receptacle at 8985'. Pump off and POOH. Make up Spacer Pipe BHA #3 with snap latch pinned to 4.0k and RIH. Tie into flag to confirm spacing, set into lower packer section and confirm with 3k overpull. Top of snap latch receptacle at 8962.5'. Pump off and POOH. 10bbl meth cap on well. Make up final BOT KB liner top packer/snap latch assemply. ***Job In Progress*** 8/26/2021 CTU #6 1.75" CT Job Objective: Fish LTP/ Caliper / Set New LTP RIH w/4.5" KB LTP BHA.w/snap latch assembly. At flag, corrected EOP = 8849.6' + 28.75' (EOP to Snap Latch No-go) = 8878.35'. Correct counter and sting into lower snap latch receptacle @ 60 fpm. 2500# over pull. Set 4.5" KB Liner Top Packer w/snap latch assembly. Top of Packer = 8944.74' MD. Packer COE = 8946.12' MD. Pooh w/BHA. Well freeze protected with 38bbl of diesel. Pad operator notified of well status and to work plan to POP with DPBGL. RDMO. ***Job Complete*** Daily Report of Well Operations PBU K-317B STATE OF ALASKA •ALASKA OIL AND GAS CONSERVATION COMM N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Pull Tubing 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Alter Casing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Repair Well 0 Re-enter Susp Well 0 Other:Pull/Set Liner Top Packe H 2. Operator Name: BP Exploration(Alaska),Inc 4. Well Class Before Work 5. Permit to Drill Number: 201-156 3. Address: P.O.Box 196612 Anchorage, Development H Exploratory 0 AK 99519-6612 Stratigraphic 0 Service ❑ 6. API Number: 50-029-22537-02-00 7. Property Designation(Lease Number): ADL 0028303 8. Well Name and Number: LISB K-317B 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pools: PRUDHOE BAY,LISBURNE OIL 11.Present Well Condition Summary: Total Depth: measured 11935 feet Plugs RECEIVED measured feet t CC true vertical 8830 feet Junk measured 8947 feet FEB 0 1 2016 Effective Depth: measured 11935 feet Packer measured 8347 feet true vertical 8830 feet Packer true vertical 8163.85 feet AOS""+CC Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 80 20"94#H-40 39-119 39-119 1530 520 Surface 3668 10-3/4"45.5#NT-8 38-3706 38-3702 4560 1730 Intermediate 8479 7-5/8"29.7#L-80 35-8514 35-8302 6890 4790 Production Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation Depth: Measured depth: 10442-11902 feet 10442-11902 feet True vertical depth: 8927-8830 feet 8927-8830 feet Tubing(size,grade,measured and true vertical depth) 4-1/2"12.6#L-80 33-8339 33-8157 Packers and SSSV(type,measured and See Attachment See Attachment See Attachment true vertical depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): SCANNED MAA ti 8 L i'l; 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: 81 36582 4 450 1056 Subsequent to operation: 1507 105 478 1800 220 14.Attachments:(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations H Exploratory ❑ Development H Service 0 Stratigraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil H Gas 0 WDSPL 0 Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ 0 WAG 0 GINJ 0 SUSP 0 SPLUG 0 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 Catron,Garry R(Wipro) Email Garry.Catron@bp.com Printed Name Catron,Garry R/ yyy///(Wipro) Title PDC Principal Engineer Signature /84.404.4t C, Phone +1 907 564 4424 Date 2/1/16 Form 10-404 Revised 5/2015 VIL Zh 9 ij RBDMS L-L FEB 0 2 2016 Submit Original Only 4f//‘ • S No cc?, 0 N-O U v) Ooo00C .cr0 co co CA co CO Lo InooI-- ct a`to m CO CO 0) CO • (NI N O) 0) N C0 O I'- O O Cfl 00 CO O CO Lo r r M In Lo 00 co co co co CO o0 a0 CO 00 F- CO O) — N CO 0) CO (0 LC) CO C0 (O O CO CO CO CO T- r LO In CO CO CO CO CO CO CO it C) co .4- V .4- co L-Lc) Lo co CO to co c) 00) M 0 (c M co 00 CA 00 M V p 4-1 Lia Q r V co CO co CT CO LO CO LI) 0) O CO co co co co co O 0) N co CD I 00 co co co cO co cnO J co, 0 0 0 00 0 0 0 0 O 00 co co 00 00 Z J J J J J J • d L N Cr CO M •� N LC) ON M • N (Q C)) N - - c- U O C N N c- CO N r � N co 17.6 V � -C".6 O M CV V CO CD L Cr)O CO W N- CO LO LC) CO C co CO tY M CO (0 M 0) CO a) r c- CO -J W U C O W c Q j 2 CD U 0 W E E Z Z W W W W W W m O D H Z Z Z Z Z D O W Z J J J J J • i Packers and SSV's Attachment LISB K-317B SW Name Type MD TVD Depscription K-317B TBG PACKER 8347.16 8163.85 5-1/2"TIW Packer K-317B PACKER 8957 8553.03 4-1/2"WFD ER Packer • • a O c c a O CU c CO Q y -O co 4- c c p a0 L CU N ) ra a)CL > a) aa) Q U 2 0 T cn o Un co a) j c ca a) E Q a) L .Fs• 0 L a) o - _0 � v) 3 Ca- E 0 O T:). f F- - o a) Q c >,;= a ca �_ L J '= c a. 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C.) 0) o •- ( 2 5 = = 0 = c .R w < » b t = J - 2 E - m # o m \ 2 2 3 f . % @ \ ? 2 R o c a) _ / » 0 , I- o c- 03 - 0_ o - 6 y .@ U 2 as m o = w o : O O i W a o of o O e o 8 8 nrr N 9 5cCN ce)9 7 E & A int= 4"CMV • K_3 1 7 B, -AD,NOTES: WELL>70°@ 8916'***MAX VNELL.HEAD= FMC ACTUATOR= BAKER C DOGLEG:39.4°@ 10561'*** (PRE CTD: PRUDHOE WELL K-17A) OKB.EL.EV= 59.25' BF.ELEV= 31.75' 1 KOP= 9733' I Max Angle= 101°©1123T2177' -�4-1/2"I ES HXO SVLN NWID=3.813" • Datum MD= 10,34T [tum TVD= 8800'SS GAS LET MANDRELS 10-3/4"CSG,45.5#,NT-80,D=9.953" -1 3707' ST MD TVD DEV TYPE VLV LATCH PORT DATE 1111 4 3072 3068 1 M6RfA DOME BK 16 11/10/14 3 5044 5039 1 MERLA DOME BK 16 11/10/14 2 6810 6796 15 MERLA DMY BK 0 05/19/15 1 8204 8046 34 ME RLA DMY BK 0 05/19/15 Minimum ID = 1.72" @ 9073' - 2.72" RS ANCHOR SEAL IN ER PKR ' 8271' H4-1/2"HES x NIP,ID=3.813" 2911 8282' H7-5/8"X 4-1/2"BKR S-3 PKR,D=3.875" 8306' -14-1/2'FES X NP,D=3.813" ' 8327' H4-1/2"HES XN MD,WILLED TO 0=3.80" 8337' -16-1/2'TM/TACK SLY,D=5.744" 4-1/2"TBG,12.6#,L-80 NSCT, -1 $339' , 8339' -{4-1/2"WLEG,0=3.958' .0152 bpf,D=3.958" 8364' H E_MD TT LOGGED 07/17/98 8347' —7-5/8"X 5-1/2'TWW S-6 PKR, D=4.975" 8349' H 7-5/8"X 5-1/2"TIW DTH-S HGR, 13=5.508" 7-5/8'CSG,29.7#,L-80,D=6.875' 8986' / 8354' J-::::2:: =3.9 '( MLLOUT W526'WIN1 iii• 'USAF" i� - --. 8957'-9017' LATCHED CTM —4-1/2"ER PKR w/2-7/8'SPACER PPE LATCHED WO 2-3/8"SPACER PPE w/3-1/2' WDEPACK PKR-DAL 60.68',D=1.72"(01/04/16) SPLIT N 4-1l2"LI*?CONF -18982' ELMD 8993' H3.70"BKR DEPLOY SLV,D=3.00' FEREV VIDEO ON 12/10/13 8998' H3-1/2'X 3-3/16"XO CTU PALLED TO 2.90"N 2013 4-1/2'LHR,12.6#,L-80 BT, --1 --9734 MLLOUT WINDOW(K-31713) 9734"-9742' 0152 bpf,D=3.958" ` �� \ 10278' H2.70"BKR DEPLOY SLV,D=2.25" • .04 10284'AH2-3/4'X 2-3/8"XO PN,D=1.92" • PERFORATION SUMv6ARY ,•• 3-3t16'LNR, -j 10355' `` ? --FISH:-2"PECE OF GLM REF LOG: MWD GR ON 01/22/03 `•` (05/19/15) ANGLE AT TOP PERF:RYA 6.2#,L-80 TCt, . .,4 Note:Peter to Production DB for historical pert data .0076 bpf,ID=2.805" ` SIZE SPF INTERVAL Opn/Sqz SHOT SQZ 2-3/8" 4 10442-11902 PREDRILL 01/22/03 PST() 11902' 2-3/8"LHR,4.43#,L-80 STUFL4S, --I 11935' .0036 bpf,D=1.92" DATE REV BY I COMMENTS DATE REV BY COMNHNTS LISBURNE UNIT(AS OF 01/24/03) 05/06/95 4ORIGINAL COMPLETION 01/14/16 LLYJMD RESET PATCH(01/04/16) WFI I: K-3178 06/17/98 RIG SIDETRACK(K-17A) PERMIT No:12011560 01/24/03 DAC/TU-CTD SIDETRACK(K-3176) APR No: 50-029-22537-02 11/10/14 MSS/PJC GLV CJO SEC 4,T11N,R14E,3280'NSL&4078'WEL 11/17/14 PJC CLEANUP AND REFORMAT WBS 05/28/15 GJB/JM7 GLV 00&FISH(05/19/15) BP Exploration(Alaska) Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWelllntegrityCoordinator@bp.com> Sent: Wednesday, May 20, 2015 8:40 PM To: AK, OPS GC1 OSM;AK, OPS GC1 Field O&M IL;AK, OPS GC1 Wellpad Lead;AK, OPS Prod Controllers;Cismoski, Doug A; Daniel, Ryan;AK, D&C Well Services Operations Team Lead;AK, D&C Wireline Operations Team Lead;AK, RES GPB West Wells Opt Engr; AK, OPS Well Pad EKG;AK, RES GPB East Wells Opt Engr; 'chris.wallace@alaska.gov'; Regg,James B (DOA); Derrick, Mackie Cc: AK, D&C DHD Well Integrity Engineer;AK, D&C Well Integrity Coordinator;AK, D&C Projects Well Integrity Engineer;AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Pettus,Whitney Subject: OPERABLE: Producer K-317B (PTD#2011560)TIFL passed post valve changeout Attachments: image001.png All, Producer K-317B (PTD#2011560) passed a TIFL on 05/20/15 following gas lift valve work. This passing test confirms two competent barriers in the wellbore. The well is reclassified as Operable. Please call with any questions or concerns. Thank you, Whitney Pettus (Alternate: Kevin Parks) SCONEO MAY 2 2 2015 BP Alaska-Well Integrity Coordinator GIN1! C o:.1'1'Jc 0.94'1 tot O'1 WIC Office: 907.659.5102 WIC Email: AKDCWeIllntegrityCoordinator@BP.com From: AK, D&C Well Integrity Coordinator Sent: Tuesday, May 19, 2015 10:26 PM To: AK, OPS GC1 OSM; AK, OPS GC1 Field O&M TL; AK, OPS GC1 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, OPS Well Pad EKG; AK, RES GPB East Wells Opt Engr; 'chris.wallace@alaska.gov'; 'Regg, James B (DOA) (jim.regg@alaska.gov)'; Derrick, Mackie Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Pettus, Whitney Subject: UNDER EVALUATION: Producer K-317B (PTD #2011560) Inner Annulus exceeded MOASP All, Producer K-317B (PTD#2011560) inner annulus exceeded MOASP on May 16th, 2015 with T/I/O= 2160/2160/10 psi. A subsequent cold and warm TIFL failed,demonstrating a lack of competent barriers in the wellbore. At this time the well has been reclassified as Under Evaluation for additional diagnostics. Plan Forward: 1 1. Downhole diagnostics: Cold 11FL—FAILED 05/16/15 2. Downhole diagnostics: Warm TIFL—FAILED 05/18/15 3. Slickline: Change out gas lift valves 4. Downhole diagnostics:Warm TIFL 5. Well Integrity Engineer:Additional diagnostics as needed. A copy of the TIO plot and wellbore schematic have been included for reference. Please call with any questions or concerns.Thank you, Whitney Pettus (Alternate:Kevin Parks) BP�Allaska-Well Integrity Coordinator Gs VV WIC Office: 907.659.5102 WIC Email: AKDCWeIIIntegrityCoordinator@BP.com 2 Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com> Sent: Tuesday, May 19, 2015 10:26 PM To: AK, OPS GC1 OSM; AK, OPS GC1 Field O&M TL;AK, OPS GC1 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, OPS Well Pad EKG; AK, RES GPB East Wells Opt Engr;Wallace, Chris D (DOA); Regg, James B (DOA); Derrick, Mackie Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Pettus, Whitney Subject: UNDER EVALUATION: Producer K-317B (PTD #2011560) Inner Annulus exceeded MOASP Attachments: image001.png; Producer K-317B (PTD#2011560) TIO Plot 05-19-15.docx; Producer K-317B (PTD #2011560) Wellbore Schematic.pdf All, Producer K-317B (PTD#2011560) inner annulus exceeded MOASP on May 16th, 2015 with T/I/O = 2160/2160/10 psi. A subsequent cold and warm TIFL failed, demonstrating a lack of competent barriers in the wellbore. At this time the well has been reclassified as Under Evaluation for additional diagnostics. Plan Forward: 1. Downhole diagnostics: Cold TIFL—FAILED 05/16/15 2. Downhole diagnostics: Warm TIFL—FAILED 05/18/15 3. Slickline: Change out gas lift valves SCANNED MAY 4. Downhole diagnostics: Warm TIFL 2 8 2015 5. Well Integrity Engineer: Additional diagnostics as needed. A copy of the TIO plot and wellbore schematic have been included for reference. Please call with any questions or concerns.Thank you, Whitney Pettus (A/tei i(ilr: kt' 'in MIA,) BP Alaska-Well Integrity Coordinator GW WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator@BP.com 1 Producer K-3178(PTD#2011560) TIO Plot May 19, 2015 Wel ell. s —0 M+ CO. Moo. nae mint ova awe al.Awe OM,wm,S u«,'OM"PPM WO*an.awe aero MSM asn as-a corn aw,S Man wars MUM sn.n MA.%MAWS aero amt au-n Mea waa TREY- 4'CNV S -"K 1 7 B ' NOTES: WELL>70°@ 8916'"•MAX WELLHEAD= FMC ACTUATOR= BAKER C DOGLEG:39.4° 10561'*" (PRE CTD: PRUDHOE WELL K-17A) KB.ELEV= 61' BF.ELEV= 31 75' KOP= 9733' Max Angle= 101 @ 11237' O 217T --14-1/2'FES HXO SVLN NIP,D=3.813" Datum ND= 10,347' Datum TVD= 8800'SS GAS LIFT MANDRELS 10-3/4"CSG,45.5#,NT-80,D H ST MD=9.953" 3707' VLV DEV TYPE V LV LATCH PORT DATE 4 3072 3068 1 tvERLA DOME BK 16 11/10/14 3 5044 5039 1 MERtA DOME BK 16 11/10/14 2 6810 6796 15 M LA DOME BK 16 11/01/14 Minimum ID = 1.75" @ 9006' 1 8204 8046 34 MLA SO BK 24 11/10/14 2.70" ANCHOR SEAL IN ER PKR ' { 8271' --14-1/2"FES X NP,ID=3.813" [ 8282' H7-5/8"X 4-1/2"BKR S-3 PKR,D=3.875" ' 1 8306' H4-1/2"HES X NP,D=3.813" ' { 8327' -14-1/2"HES XN MP,MLLED TO D=3.80" 8337' 6-1/2'TNV TEE33ACK SLV,D=5.744" 4-1/2"TBG, 12.6#,L-80 NSCT, - 8339' `-, -� 8339' -{4-1/2'WLEG,D=3.958" .0152 bpi,U=3.958' 1 ( 8364' I]--1E LMD TT LOGGED 07/17/98 8347' ]H7-5/8"X 5-1/2"TM/S-6 PKR, D=4.975" I \ 8349' i--17-5/8"X 5-1/2"TNV DTH-S HGR, D=5.508" 7-5/8'CSG 29.7#,L-80,D=6.875" 8986' �{ 8354' 1-15-1/2"X 4-1/2'XO,ID=3.94" i� woo MLLOUT WINDOW(K-17A) 8514'-8526' • Vii ,iii - 8968' -9012'CTM -4-1/2"ER PKR w/2-7/8"SPACER PPE& SO TEEBK LATCHED MO 3-1/2"WIDFPACK- OAL44',D=1.75'(11/08/14) 111 L 8993' H3.70"BKR DEPLOY SLV,D=3 00" 8998' --13-1/2"X 3-3/16"XO,ID=" r i" 4-1/2"LNR, 12.64,L-80 EBT, I- -9734 ML, LOUT WINDOW(K-3176) 9734'-9747 0152 bpi,D=3.958" J �' 10278' —2 70"BKR DEPLOY SLV,ID=2.25" 10284' —12-3/4"X 2-3/8'XO PN,ID=1.92"] PERFORATION SUMMARY REF LOG: MWD GR ON 01/22/03 3-3/16"LNR 1 10355' ` , , ANGLE AT TOP PERF:WA 6.2#,L80 TCI, Note:Refer to Roduction DB for historical pert data 0076 bpi,D=2.805" ,� SCE SPF INTERVAL Opn/Sqz SHOT SQZ PB7D - 11902' 2-3/8" 4 10442- 11902 FRE DRILL 01/22/03 2-3/8"LNR,4.434,L-80 STUFL4S, - 11935' - - -- .0036 bpf,D=1.92" DATE REV BY CONVENTS DATE REV BY CONMNTS LISBURrE UNIT(AS OF 01/24/03) 05/06/95 ORIGINAL COMPLETION 11/07/14 MSS/PJC SET ER PKR VVELL K-317B 06/17/98 RIG SIDETRACK(K-17A) 11/10/14 MSS/PJC GLV C/O FFRMT No:' 011560 01/24/03 GAC/TLE CTD SIDETRACK(K-317B) 11/17/14 PJC CLEANUP AND REFORMAT WBS AR No: 50-029-22537-02 05/01/07 DAV/TLH GLV GO(04/18/07) SEC 4,T11 N,R14E 3280'NEL R.4078'WEl 12/12/08 NBMSV GLV GO(12/03/08) 06/01/11 CJW PJC GLV GO(05/27/11) BP Exploration(Alaska) ) ) Image Project Well History File Cover 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. :;}. 0 1 - 100 Well History File Identifier Production Scanning Stage 1 Page Count from Scanned File:3~ (Count does include cover sheet) Page Count Matches Number in SCa~ning Preparation: / YI;S NO , Date:Õ íJ.y oS /5/ Organizing (done) o Two-sided 111111111I111111111 R9CAN 0' Color Items: D Greyscale Items: DI9JT AL DATA z1' Diskettes, No. I D Other, No/Type: D Poor Quality Originals: D Other: NOTES: BY: Helen ~ Project Proofing BY: Helen ~ Scanning Preparation ~~ x30= O¡O BY: Helen ~ BY: Helene-Maria ") Stage 1 If NO in stage 1, page(s) discrepancies were found: BY: Helen Maria Scanning is complete at this point unless rescanning is required. ReScanned BY: Helen Maria Comments about this file: ~scan Needed OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) D Logs of various kinds: o Other:: , . I JAA 0 Date: (1311 ðS- /s/ y r I , . I . Date{3 ;)..'1 OS /5/ VV1P , . + J = TOTAL PAGES o¡ I (coun. t d6s not i 'elude cover sheet) II\J...P Date:,~ a'l, CJ!5; /s/ r VI mP YES NO Date: /5/ III III 1111 III 1111 II Date: /5/ Quality Checked 1111111111111111111 OPERABLE: Producer K - 317B (PTD4011560) Passing MIT -IA • Page 1 of 2 Regg, James B (DOA) From: AK, D &C Well Integrity Coordinator [AKDCWeIIIntegrityCoordinator @bp.com] Sent: Sunday, May 29, 2011 9:12 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, PS GC1 OSM; AK, OPS GC1 Field O &M TL; AK, OPS GC1 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; AK, D &C Well Services Operations Team Lead; AK, D &C Wireline Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Yeager, Kevin E Cc: King, Whitney; Ramsay, Gavin Subject: OPERABLE: Producer K -317B (PTD #2011560) Passing MIT -IA All, Producer K -317B (PTD #2011560) passed an MIT -IA on 5/27/2011 after dummy gas lift valves were set. The passing test proves two competent barriers therefore the well has been reclassified as Operable. The IA is fluid packed so please be prepared for thermal expansion when bringing the well online. Thank you, Mehreen Vazir (Alternate: Gerald Murphy) Well Integrity Coordinator BP Alaska Drilling & Wells xispia JUN 1 2U111 Well Integrity Office: 907.659.5102 Email: AKDCWeIIIntegrityCoordinator @BP.com From: AK, D &C Well Integrity Coordinator Sent: Sunday, May 22, 2011 3:12 PM To: 'Maunder, Thomas E (DOA)'; 'Regg, James B (DOA)'; 'Schwartz, Guy L (DOA)'; AK, OPS GC1 OSM; AK, OPS GC1 Field O &M TL; AK, OPS GC1 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; AK, D &C Well Services Operations Team Lead; AK, D &C Wireline Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Daniel, Ryan Cc: Walker, Greg (D &C); Ramsay, Gavin Subject: UNDER EVALUATION: Producer K -3178 (PTD #2011560) Sustained Casing Pressure on the IA All, Producer K -317B (PTD #2011560) was found to have sustained casing pressure above MOASP on the IA. The wellhead pressures were tubing /IA/OA equal to 2540/2480/30 psi on 05/19/2011. The well failed a TIFL on 05/19/2011 with the well shut in confirming tubing integrity is compromised. The well has been reclassified as Under Evaluation and may be produced under a 28 -day clock while efforts to mitigate the communication are completed. The plan forward is: 1. Operations: POP 2. DHD: re -TIFL 3. Slickline: Set DGLVs and MIT -IA pending results of TIFL A wellbore schematic and TIO plot are attached for reference. « File: K- 317B.pdf » « File: K -317B TIO 05- 22- 11.doc » 5/31/2011 OPERABLE: Producer K -317B (PTDo011560) Passing MIT -IA Page 2 of 2 Thank you, Mehreen Vazir (Alternate.: Gerald Murphy) Well Integrity Coordinator BP Alaska Drilling & Wells Well Integrity Office: 907.659.5102 Email: AKDCWelllntegrityCoordinator @BP.com 5/31/2011 UNDER EVALUATION: Producer K•7B (PTD #2011560) Sustained Casiniessure on the IA Page 1 of 1 Regg, James B (DOA) From: AK, D &C Well Integrity Coordinator [AKDCWeIIIntegrityCoordinator @bp.com] Sent: Sunday, May 22, 2011 3:12 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS GC1 OSM; AK, OPS GC1 Field O &M TL; AK, OPS GC1 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; AK, D &C Well Services Operations Team Lead; AK, D &C Wireline Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Daniel, Ryan Cc: Walker, Greg (D &C); Ramsay, Gavin Subject: UNDER EVALUATION: Producer K -3178 (PTD #2011560) Sustained Casing Pressure on the IA Attachments: K- 317B.pdf; K -317B TIO 05- 22- 11.doc All, ,f Producer K -317B (PTD #2011560) was found to have sustained casing_pressure above MOASP on the IA. The wellhead pressures were tubing /IA/OA equal to 2540/2480/30 psi on 05/19/2011. The well failed a TIFL on 05/19/2011 with the well shut in confirming tubing integrity is compromised. The well has been reclassified as Under Evaluation and may be produced under a 28 -day clock while efforts to mitigate the communication are completed. The plan forward is: 1. Operations: POP 2. DHD: re -TIFL 3. Slickline: Set DGLVs and MIT -IA pending results of TIFL A wellbore schematic and TIO plot are attached for reference. «K- 317B.pdf» «K -317B TIO 05- 22- 11.doc» Thank you, ;' J 1 j m ;Y 2 5 20) Mehreen Vazir (Alternate: Gerald Murphy) Well Integrity Coordinator BP Alaska Drilling & Wells Well Integrity Office: 907.659.5102 Email: AKDCWeIIIntegrityCoordinator @BP.com 5/24/2011 PBU K -317B PTD #2011560 5/22/2011 TIO Pressures Plot Well: K -317 4,000 • 3,000 - • Tbg —III— IA Ii , • • • - ----- • 02/26/11 03/05/11 03/12/11 03/19/11 03/26/11 04/02/11 04/09/11 04/16/11 04/23/11 04/30/11 05/07/11 05/14/11 05/21/11 TREE »" 4" CIW WELLHEAD = FMC • BAKER 1 1/4 -3 1 7 B SAFETY ES: WELL > 70° @ 8916' ACTUATOR = , , TE EV= - 1 - .. BF. ELEV = 31.75 (PRE CTD: PRUDHOE WELL K-17A) ' KOP = 9733' Max Angle = 101° @ 11237 1 2177' J-14-1/2" HES 1-1X0 SVLN NIP, ID = 3.813" 1 Datum MD = 10,534' 0 Datum TVD = 8900' SS 1 10-3/4" CSG, 45.5#, NT-80, ID = 9.953" H 3707' 1-41 1. GAS LIFT MANDRELS ST MD ND DEV TYPE VLV LATCH PORT DATE 110 4 3072 3006 1 MERLA DOME BK 16 04/18/07 3 5044 4977 1 MERLA DOME BK 16 04/18/07 2 6810 6734 15 MERLA DOME BK 16 04/18/07 1 8204 7983 34 MERLA SO BK 24 12/03/08 Minimum ID = 1.92" @ 10284 2-3/4" X 2-3/8" XO i 1 I 8271' H 4-1 /2" HES X NIP, ID = 3.813" I 8282' H7-5/8" X 4-1/2" BKR S-3 PKR, ID = 3.875" I I 1 1 8306' H 4-1 /2" HES X NIP, ID = 3.813" 1 I i 8327' H 4-1 /2" HES XN NIP, MILLED TO ID = 3.80" 1 8337' H TOP OF TIW TIEBACK SLV, ID = 5.744" I 4-1/2" TBG. 12.6#, L-80„0152 bpf, ID = 3.958" H 8337' I---7, \J 8339' H4-1/2" WLEG, ID = 3.958"] 2f iK 8364' H ELMD TT LOGGED 07/17/98 I 8347' 1-17-5/8" X 5-1/2" TIW S-6 PKR & DTH-S LNR HGR, ID = 4.975" 1 7-5/8" CSG, 29.7#, L-80, ID = 6.875" F-1 8986' MILLOUT WINDOW 9734' - 9742' Ail 4' *f-' ormArit V Willflffr ,, , vMAIla .: I I 8993' 1-14" BKR DEPLOY SLV, ID = 3.00" I IWO/1a vfir PERFORATION SUMMARY REF LOG: MWD GR ON 01/22/03 1 8998' H 3-112" X 3-3/16" XO, ID = 2.79" ANGLE AT TOP PERF: 53 @ 10442' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE , 10278' H3" BKR DEPLOY SLV, ID = 2.25" I *N/A 4 10442 - 11902 0 01/22/03 -...P. *. 10284' H 2-3/4" X 2-3/8" XO, ID = 1.92" 1 *PRE DRILLED LINER, NO GUNS USED . A lif ' A l, s 4-1/2" LNR, 12.6#, L-80, ID = 3.958" 13982' A* A , s • , • 13 , • -3/16" LNR, 6.2#, L-80, .0076 bpf, ID = 2.805" H 10355' , • • 12-3/8" LNR, 4.43#, L-80, .0036 bpf, ID = 1.92" H 10442' I s • s s ' , , • , • , • 12-3/8" PRE-DRILLED LNR, 4.43#, L-80, ID = 1.92" 1 11902' * • , N 1PBTD 1 11902' 2-3/8" LNR, 4.43#, L-80. .0036 bpf, ID = 1.92" H 11935' I DATE REV BY COMMENTS DATE REV BY COMMENTS LISBURNE UNIT (AS OF 01/24/03) 05/06/95 ORIGINAL COMPLETION 03/01/07 RL DATUM MD WELL: K-317B 06/17/98 RIG SIDETRACK (K-17A) 05/01/07 DAV/TLH GLV C/O (04/18/07) PERMIT No: '2011560 01/24/03 DAC/TLH CTD SIDETRACK (K-31713) 12/12/08 MBM/SV GLV CIO (12/03/08) API No: 50-029-22537-02 01/26/03 JM/TLH GLV C/O SEC 4, T1 1N, R14E, 3280' NSL & 4078' WEL 09/22/05 KSB/TLH GLV C/O 08/24/06 KSB/PAG GLV C/O BP E6laration (Alaska) UNDER EVALUATION: K-317 (PTD #2011560) for Sustained Casing Pressure Page 1 of 1 • Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Thursday, November 27, 2008 9:04 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr Central (GC1/3/FS3); GPB, GC1 OTL; GPB, GC1 Wellpad Lead; GPB, Well Pad EKG; GPB, Wells Opt Eng; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor; GPB, Prod Controllers; GPB, Optimization Engr Cc: Winslow, Jack L.; Townsend, S. Eliot; Randall, Jaclyn S; NSU, ADW Well Integrity Engineer Subject: UNDER EVALUATION: K-317 (PTD #2011560) for Sustained Casing Pressure Attachments: K-317 TIO.doc; K-317B.pdf All, Well K-317 (PTD #2011560) has been found to have sustained casing pressure on the IA. The TIOs were 2100/2190/0+ psi on 11/26/08. On the same date the well failed a TIFL, thus confirming TxIA communication. The well has been reclassified as Under Evaluation and placed on a 28-day clock. The plan forward for the well is as follows: 1. DHD: TIFL -FAILED 2. S: DMY GLV's 3. F: MIT-IA to 3000 psi «K-317 TIO.doc» «K-3176.pdf» A TIO plot and wellbore schematic have been included for reference. Please call with any questions or concerns. Thank you, Taylor Wellman filling in for Anna Dube/Andrea Hughes Office: 659-5102 Pager: 659-5100 x 1154 ~~~~' t.1~.f ~` a ZOQ '~ ~~~ ~ ~. ~(?~ ~~ 7 ~~ ~ ~-~--- ~~~ ~~ ~v 11/28/2008 ~ ~ K~ • C fV r a :; b P :j ~~~ a-- TREE = 4" CNV WELLHEAD- -- - FMC ^ ACTUATOR= BAKER KB. ELEV = 61' 8F. ELEV - 31.75' KOP = _.... 9733' Max Angle = 101'' @ 11237 Datum MD = 10.534' Datum TV D = 8900' SS •- K-317B {PRE CTD: PRUDHOE WELL K-17A) 110-3/4'° CSG, 45.5#, NT-80, ID = 9.953" {-1 3707' Minimum ID =1,92" @ 10284 2-3/4" X 2-3/8" XO t.! NOTES: WELL> 70° @ 8916' 2177' {-{4-112" HES HXO SVLN NIP, ID = 3.813" GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 4 3072 3006 1 MERLA DOME BK 16 04t18/fl7 3 5044 4977 1 MERLA DOME BK 16 04!18/07 2 6810 6734 15 MERLA DOME BK 16 04118(07 1 8204 7983 34 MERLA SO BK 24 04/18/07 8271' -~4-112" HES X NIP, ID = 3.813" 8282' 7-5f8" X 4-1t2" BKR S-3 PKR, ID = 3.875" ) 4-1/2" TBG, 12.6#, L-80, .0152 bpf, ID = 3.958" {-{ 8337 17-5/8" CSG, 29.7#, L-80, iD = 6.875" I~ 8986' PERFORATION SUMMARY REF LOG: MWD GR ON 01/22/03 A NGLE AT TOP PERF: 53" @ 10442' Note: Refer to Produckion DB for historical perf data SIZE SPF INTERVAL OpntSgz DATE "N/A 4 10442 - 11902 O 01!22!03 8308` ~-~4-1/2" HES X NIP, ID = 3.813" 8327' 4-112" HES XN NIP, MILLED TO !D = 3.80" 8337' TOP OF TIW TIEBACK SLV, ID = 5.744" 8339' 4-112" WLEG; ID = 3.958" 8364' ELMD TT LOGGED 07117!98 8347 7-5f8" X 5-1t2" TMr S-6 PKR & DTH-S LNR HGR, tD = 4.975" MILLOUT WINDOW 9734' - 9742' 8993' 4" BKR DEPLOY SLV, ID = 3.04" 899$' ~-{ 3-112" X 3-3116" XO, fD = 2.79" 10278" -j 3'° BKR DEPLOY SLV, ID = 2.25" ^ /~ 10284' 2-314" X 2-3/8" XO, ID = 1.92" PRE-DRILLED LINER, NO GUNS USED 4-1l2" LNR. 12.6#, L-80, ID = 3.958" 13982' ` ~ . 3-3(16" LNR, 6.2#, L-80, .0076 bpf, ID = 2.805" 10355' 2-318" LNR, 4.43#. L-80, .0036 bpf, ID = 1.92" 10442' ` , ` ` 2-3/8" PRE-DRILLED LNR, 4.43#, L-80, ID = 1.92" 11902' , ` ,~ PBTD 11902' 2-3t8" LNR, 4.43#, L-80, .0036 bpf, ID= 1.92" 11935' DATE REV 8Y COMMENTS DATE REV BY COMMENTS 05(06195 ORIGINAL COMPLETION 03701!07 RL DATUM MD 06/17198 RIG SIDETRACK {K-17A} 05I01/07 DAVITLH GLV C70 {04!18!07) 01124103 DACITL CTD SIDETRACK {K-3176) 01/26!03 JM/TLH GLV C/O 09(22105 KSBiTLH GLV C/O 08!24(06 KSB(PAG GLV C(O LISBURNE UNIT {AS OF 01/24/03) WELL: K-3178 PERMIT No: 2011560 API No: 50-029-22537-02 SEC 4, 711 N, R14E, 3280' NSL & 4078' WEL BP Exploration {Alaska} . . MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Marlœr.doc .. STATE OF ALASKA .. ALA_ OIL AND GAS CONSERVATION COM~ION REPORT OF SUNDRY WELL OPERATIONS o o o 1. Operations Abandon 0 Repair Well 0 Performed: Alter Casing 0 Pull Tubing 0 Change Approved Program 0 Operat. Shutdown 0 2. Operator BP Exploration (Alaska), Inc. Name: P.O. Box 196612 Anchorage, AK 99519-6612 7. KB Elevation (ft): 3. Address: 8. Property Designation: 59.8 KB ADL-028303 11. Present Well Condition Summary: Total Depth Effective Depth Casing Conductor Surface Production Liner Liner Liner Perforation depth: measured 11935 true vertical 8829.98 measured 11902 true vertical 8830.15 Length 80 3678 8486 1397 1362 1657 Size 20" 91.5# H-40 10-3/4" 45.5# L-80 7-5/8" 29.7# L-80 4-1/2" 12.6# L-80 3-3/16" 6.2# L-80 2-3/8" 4.43# L-80 Plug Perforations Perforate New Pool Perforate 4. Current Well Class: Development M Stratigraphic feet feet feet feet MD 30 - 110 29 - 3707 28 - 8514 8337 - 9734 8993 - 10355 10278 - 11935 Measured depth: True Vertical depth: .:- Slotted Liner 10442' 11902' - Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): 4-1/2" 12.6# tJO\J {j q f\· y \J hi ØttMlk[JM. Waiver 0 Time Extension 0 Re-enter Suspended Well 0 5. P~rmitt.oDrill Number: ",'ri-'" , ¡.:i,ji'~ ;" G~¡' Stimulate 0 Exploratory Service . N 50-029-22537-02-00 9. Well Name and Number: K-317B 10. Field/Pool(s): PRUDHOE BAY Field/ LISBURNE OIL Pool Plugs (measured) Junk (measured) None None TVD 30 - 110 29 - 3702.59 28 - 8301.96 8155.43 - 8588.6 8560.8 - 8865.85 8805.69 - 8829.98 Burst 1490 5210 6890 8430 Collapse 470 2480 4790 7500 - .:- L-80 28 - 8339 4-1/2" Baker S-3 Perm Packer 5-1/2" TIW Packer 8282 8347 .... . ØC .<~ S 2-GOS 5t;AN,ìiJ:~-¡ Dr. "" RBDMS 8Ft Treatment descriptions including volumes used and final pressure: see attached fluid summary T/I/O 0/260/0 13. Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 3208 412 40 3222 330 60 15. Well Class after proposed work: Exploratory Development M 16. Well Status after proposed work: Oil M Gas WAG 17. I hereby certify that the foregoing is true and correct-to the best of my knowledge. Oil-Bbl 355 379 Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations x Contact Sharmaine Vestal Printed Name Sharmaine Vestal Signat~~, Form 10-404 Revised 04/2004 Q 3 2005 Tubing pressure 220 140 Service D WDSPL Title Data Mgmt Engr Date 10/26/2005 Phone 564-4424 /1.. L /"\ Submit Original Only to\ ,. e e K-317B DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY I ACTIVITYDATE I SUMMARY 10/3/2005 cTU # 9 w/1.50". DrifUTag. RU and perform weekly BOP test. SD for leaking ASRc SSV. Grease valve and fix leak leak in stem packing. Proceed with BOP test. Good test.. ASRC lines and valves PT'd...... Continued 10/4/05 *** Job In Progress *** 10/4/2005 Job in progress..... Continued from 10103/05 Job scope: D& T and acidize RIH wi 1.50" JSN. Tag PBTD @ 11,884 down... PU 11,881'. Wt off bottom 16.5K. POH to 10,100. Establish Inj. Rates in 1-1/2 cT= 1/2 bpm 265 psi, 1bpm 1630 psi, 1-1/2 bpm 3233 psi & 1-3/4 bpm 3950 psi. Wellhead pres. 32 to 52 psi during IRT. Pump acid per program unit! stage # 9 when we were getting differently stuck across perfs @ 11517' ctm, target depth was @ 11750' ctm switched from the XSE acid to the VDA with 39 bbls remaing on stage. Once the next 15% VDA stage hit nozzle we were able to reciprocate across perforations per program. Did not any no major breaks from acid diversion. Pumped the earlier 39 bbls of acid in the last XSE stage instead. Average injection rate and pressure was approximately 1.2 bbllmin @ 3800 psi through out job. Displace acid wi 2% KcL. POH & RD. Turn well over to ASRc & PO to POP *** Job Complete *** FLUIDS PUMPED BBLS 72.8 Meth 230 2% KCL 17 2% KCL w/1 0% U66 22 3% J529 74 15% HCL acid 450 15$ SXE acid 151 15% VDA acid 1016.8 TOTAL ;). 7> FJ'b ;)~~ ,-- DATA SUBMITTAL COMPLIANCE REPORT 2/1/2005 Permit to Drill 2011560 MD Well Name/No. PRUDHOE BAY UN LIS K-317B ./ Operator BP EXPLORATION (ALASKA) INC ;< ò ^ -. ,-,,^ ~ Sp u.¿ ~ rvt"\ 1- API No. 50-029-22537-02-00 11935 / / 8830 .- lVD Completion Date 1/23/2003 Completion Status . - --------- ~._---- ---_.------ -- -- REQUIRED INFORMATION --------- Mud Log No Samples No - ----- - ------ DATA INFORMATION Types Electric or Other Logs Run: MWD, GR, Memory GR, CCL, CNL Well Log Information: Jßr- ~og i riL09 ! IL09~ 4~:: @. C ]Log i ! Log ./ I Log L,.: Log ----------------- 1-01L Current Status 1-01L UIC N Directional SUNOY X Y 4.. (data taken from Logs Portion of Master Well Data Maint) Log Log Run Interval Scale Media No Start Stop 1 9730 11 935 10257 11935 25 Blu J/)) 1 0357 11935 25 Blu ~724 1 0327 9730 11935 10257 11935 8905 10310 Name Directional Survey LIS Verification Gamma Ray Gamma Ray Cbiféctional Survey Lt1577 LIS Verification ~5 Neutron Gamma Ray 25 Blu ~eutron 25 Blu I Gamma Ray ¡",.;""'- 25 Blu L I'Gamma Ray 25 Blu LCasing collar locator 25 Blu ~34 Gamma Ray ,/' s:!roduction Blu r Spinner Blu Temperature Blu ...... Pressure Blu 7/23/2003 ....-Production Profile ( w/DEFT- \ SpinlTemp/Press/Deft \ 7/23/2003 \ Production Profile w/DEFT - ~pinlTemp/PresslDeft 7/23/200V Production Profile w/DEFT - SpinlTemp/Press/Deft 11890 Case 7/23/2003 Production Profile w/DEFT - SpinlTemp/Press/Deft jrvl> 10357 11935 r--W8877. 10315 f 9724 z:.., 0327 ! Lf8877 10315 k:---a877 10315 9325 ,-8200 \ 1 0355 Open 11890 Case Logl Electr Data Digital Dataset Type Med/Frmt Number :RPt- ---- - -- ~- - ----- ; Rpt 00g [j.,t'óg ~--D ¡ c:a:(' C C 8200 11890 Case ¿;;.,,/ 8200 11890 Case '" 8200 ~ OH/ CH Received Comments Open 2/26/2003 Case 3/4/2003 Case 3/4/2003 Open 217/2003 Open 2/26/2003 Case 3/4/2003 Open 217/2003 Case 3/4/2003 217/2003 217/2003 217/2003 217/2003 217/2003 -" Open Open Open Open DATA SUBMITTAL COMPLIANCE REPORT 2/1/2005 Permit to Drill 2011560 Well Name/No. PRUDHOE BAY UN LIS K-317B Operator BP EXPLORATION (ALASKA) INC MD ~- 11935 TVD 8830 ----- - ------ ---~ Pressure QY9 I I ___ Pressure --- .. -----~- Well Cores/Samples Information: Name ADDITIONAL INFORMAæN Well Cored? Y /It!) Chips Received? "y / ~~ _...-/ Analysis Received? ~- -----~-- --- -~------------- Comments: -~----- -- ------ ---- --- ---- ------ Compliance Reviewed By: Completion Date 1/23/2003 'L I Completion Status 5 Blu 1-01L Current Status 1-01L 4158 Case 7/23/2003 d£ Blu v8126 9044 Open 3/26/2004 Interval Start Stop Sample Set Number Comments Sent Received Daily History Received? ~N ~N Formation Tops API No. 50-029-22537-02-00 UIC N Static Bottom Hole Pressure Survey w/Jewelry Pass Static Bottom Hole Pressure Survey with Jewelry ----. Date: ;{À (V~AAN\~- ~' $, , ~ 'M c-:::¡ 't ~'<." ¡,,~ 1Æ/'~ '~~ I' iI' ¡ ¡ : i! ,.,1J'\ iU! [, I ' I r I" " t! ,.,., W f, ,I' t....:....... tn; ,r6-" I .. ~ : : t ~ i \ f i' . \~U ) '®. il ,fi'\":. (OJ. ~.n. '.V."(··,7 [Æ,r' ,~ \., lQï I i j!J, \\\ ij t\' ,1J, LnJ LLnJ @J U\~,' rl \. ) Ii I~ 'r A"~A.SKA OIL AND GAS CONSERVATION COMMISSION March 4,2005 / .I I / j FRANK H. MURKOWSKI, GOVERNOR 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CERTIFIED MAIL - RETURN RECEIPT REQUESTED 7002 315000053521 1409 Mr. Bruce Williams BP Exploration Alaska, Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Subject: Defeated SVS at PBU Well K-317B Increased SVS Testing at PBU K-pad Dear Mr. Williams: On February 13, 2005 Alaska Oil and Gas Conservation Commission ("Commission") Inspector Lou Grimaldi accompanied by a BP Exploration Alaska, Inc. ("BPXA") representative performed safety valve system (SVS) inspections at Prudhoe Bay K-pad. Mr. Grimaldi noted that the surface safety valve (SSV) on Well K-317B (PTD 2011560) had been defeated some time prior to the inspection - the low-pressure sensor root valve was blocked resulting in a gagged pilot preventing the SSV from operating with a low-pressure pilot trip or emergency shutdown of the SVS. A copy of the inspection report is attached. You are reminded that Conservation Order 207 A (Prudhoe Bay Field, Lisburne Oil Pool), Rule 7 modifies the requirements of20 AAC 25.265 ("Automatic Shut-in Equipment") as follows: (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The SVS shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. CO 207 A replaced the requirements of earlier CO 207 field rules by providing for the elimination of subsurface safety valves (SSSV) in certain wells. The elimination of the SSSV in , Mr. Bruce Williams March 4, 2005 Page 2 of2 ') ) Prudhoe Bay field wells increases the reliance on the surface safety equipment. The facts reported by our inspector appear to indicate a failure to maintain an operable SVS, which would be a violation of State regulations. Within 14 days of receipt of this letter, you are requested to provide the Commission with an explanation of how this event happened and what will be done in the future to prevent its occurrence in BPXA-operated fields. Also, an SVS component failure rate of 13.6 percent was identified during the above-noted inspection. Commission policy, as outlined in a letter dated November 14, 1995, states that the testing frequency will be increased when a failure rate exceeds 10 percent. Effective February 13, 2005, and until an acceptable level of performance is achieved, the safety valve systems associated with wells located on PBU K-pad must be tested every 90 days. When testing is scheduled, you must notify the Commission Field Inspector (907-659-2714) at least 24 hours in advance to provide an opportunity to witness the SVS test. The Commission reserves the right to pursue enforcement action in connection with this apparent violation as provided by 20 AAC 25.535. Should you have any questions regarding this correspondence, please contact Mr. James Regg 7) 793-1236. ~ Attachment Safety Valve & Well Pressures Test Report Reviewed By: P.I. Suprv Comm Pad: PBU_K Insp Dt 2/13/2005 Inspected by Lou Grimaldi Interval 90 Days InspNo svsLG050213192421 Field Name PRUDHOE SAY Operator BP EXPLORATION (ALASKA) INC Operator Rep Steve Matonis Related lnsp: Reason 180~ Day Src: Inspector i Weil Data I. .. . PUots :. J ~s'V:1 :SS~·v-tShU~Ï'¡·j)t . WeIlType:_ ·)J'eIlPressures· .1 Gas LiftT'PaiJ,er I -~ COI1U1'e;~-¡;-----1 ,. . i___.._ Well Permit Separ Set LIP Test Test Test Date SI Oil,WAG,GINJ, Inner Outer Tubing Number Number PSI PSI Trip Code Code Code GAS,CYCLE, Sl PSI PSI PSI YeslNo YeslNo r- ------.-------- 658 550 550 P P I-OIL K-Ol 1831210 --- ------- ---- --- K-038 2041150 658 550 525 P P I-OlL ----------- --- K-048 2022530 658 550 540 P P I-OIL -- K-05C 2041180 658 550 550 P P I-OIL K -06A 1981360 658 550 540 P P I-OIL -----~.._._-----~ -----.------- ---- K-07C 1991090 658 550 545 P P I-OIL j--.---------- --- -~_._~---_._- ._-~- . K-12A 2002070 153 125 105 P P I-OIL n - - -------_..~~---- -- ------.--- --~-------- K-14 1870950 658 550 550 P 4 I-OIL - -----._---------- -- - --- K-16A 1981800 658 550 550 P 5 I-OIL 0-_- _. "____________ ~__ K-19A 1981680 153 125 115 P P I-OIL -----------~ K-3178 2011560 153 125 100 45 P I-OIL -~-- Comments Performance K -14 had slow SS V leak will be serviced and retested later. K-I6 SSV would not close fully, left we" shut-in.K-3178 LPS root valve blocked resulting in gagged pilot. Wells Components Failures Failure Rate ____1..1 22 _--.-J 13.64% ---~~_.~_._--- Wednesday, March 02, 2005 ~©}?)V Conservation Order No. 207 A ) ) STATE OF ALASKA "&~ mCMot k f; ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF ARCO ALASKA, INC. for an order eliminating the requirement for subsurface safety valves in wells drilled to the Lisbu rne Oil Pool ) Conservation Order No. 207A ) Prudhoe Bay Field ) Lisburne Oil Pool December 20, 1996 IT APPEARING THAT: 1. ARCO Alaska, Inc., operator of the Lisburne Oil Pool in the Prudhoe Bay Oil Field, submitted an application dated October 28, 1996 requesting a revision to Rule 7 of Conservation Order No. 207. The revision would eliminate the requirement for subsurface ' safety valves in wells drilled to the Lisburne Oil Pool. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on November 23, 1996 pursuant to 20 MC 25.540. 3. No protests to the application were received. FINDINGS: 1. Commission regulation. 20MC 25.265 requires surface (SSV) and subsurface safety valves (SSSV) in offshore wells capable of unassisted flow of hydrocarbons to the surface. Discretion to require SSV's and SSSV's in other areas is also provided. 2.Wells capable of unassisted flow of hydrocarbons to the surface that are equipped with both a SSV and a SSSV are afforded redundant protection from an uncontrolled flow. 3.Conservation Order 207, Rule 7, requires all wells in the Lisburne Oil Pool capable of unassisted flow of hydrocarbons to the surface to be equipped with a SSV and a SSSV. 4. Previous commission policy was to require multiple safety valves in onshore production wells (for permafrost areas) capable of unassisted flow of hydrocarbons to the surface. 5. The initial requirement for SSSV's was largely related to concern for the loss of well control from casing collapse due to freeze back of the permafrost. The magnitude and extent of freeze back forces and appropriate mitigating well construction techniques, had not been shown through experience to be correctly anticipated and was not well understood when the requirement for SSSV's was imposed. I of3 3/2/2005 1:46 PM Conservation Order No. 207 A ..) ) 6.vyells drilled to the Lisburne Oil Pool have been constructed uSing cement formulated for permafrost conditions, and casing grades and annular fluids capable of preventing appreciable deformation of casing due to permafrost freeze back. 7. The Commission has no record of an SSSV being used in ALaska to prevent uncontrolled flow from a North Slope onshore production well. 8. ARCO intends to use a risk based management system which will include producing rate, potential for environmental damage, corrosion concerns, proximity to facilities and populated areas, and economics as factors in evaluating wells for SSSV removal. 9.SSSV's contribute to higher costs, and increased difficulty and risk for some downhole operations. 1 G.The Commission has eliminated the requirement for SSSV's in onshore wells in other North Slope oil pools. CONCLUSIONS: 1. SSSV's may reduce ultimate recovery by contributing to higher operating costs, and may increase the chance of an accidental release of hydrocarbons when conducting certain downhole operations. 2.Extensive experience indicates the potential for casing failures through the permafrost due to freeze back has been greatly reduced by use if appropriate construction techniques in North Slope production wells. 3.SSSV's in the Lisburne Oil Pool productions wells have provided limited benefit to public safety, environmental protection or resource recovery. 4.Eliminating the requirement for SSSV's in Lisburne Oil Pool production wells is not likely to contribute to waste and may improve safety of certain well operations and greater ultimate recovery. NOW, THEREFORE, IT IS ORDERED Rule 7 of COnservation Order 207 is amended to: Rule 7. Automatic Shut-in Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The SVS shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1) Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2) A list of wells with SVS deactivated, the dates and reasons for deactivating, and the estimated reactivation dates must be maintained current and available for the Commission on request. (c)A representative of the Commission will witness operation and performance tests at 20f3 3/2/2005 1 :46 PM Conservation Order No. 207 A , inte,rvals and times as presJbed by the Commission to confirm rJat the SVS and all associated equipment are in proper working order. DONE at Anchorage, Alaska and dated December 20, 1996. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission Tuckerman Babcock, Commissioner Alaska Oil and Gas Conservation Commission .ç:ons,erva~ion Ç>rder Ind~x 30f3 3/2/2005 1 :46 PM Schlumberger Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503·2838 A TTN: Beth Well C-04A /9. ÚJ '- 09 ~~ N-21A I) (¡lo - r cr ( (., 0.5. 15-27 J 9 Ô 'l'(,~) ~ H-11 1550 ~ c-' «(., SS K-317B §i". \ - \ p.\ (p Job # 10649975 10703973 10703977 10703978 10708049 03/04/04 NO. 3123 Company: State of Alaska Alaska Oil & Gas Cons Comm AUn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay Log Description Color Date Blueline Prints CD 06/26/03 1 1 Id.L/ "c.~ 02/15/04 1 02123/04 1 02124/04 1 02106/04 1 ~ RST-SIGMA LEAK DETECTION LOG LEAK DETECTION LOG LEAK DETECTION LOG SBHP SURVEY .~: PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: ---'K~D\\\ ~ RECEIVt=D Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth . . . '-, ."\ 6 r\"." .! ~ -, '" "'U' 'L' l·~_·~.; -: L. .. Li) ¡ ~ "t--_ ,. Received b~(" ~ ~,Y\.~~'--Y"'-:"'l'\..-.l~,,\ ::~l :~': :~: ~~I:;~I C~1i1;;:~~~: );~f;hfjrage ScblUIDbepgep Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth Well Job # ~:;~ 2-141W-~ ~ \q~-6u}5 N-11B \(~'- \e>.S D.S.15-088. ~~~ .. D-03A f9.. --I, ~ K-317B . ¿qð\ '- l;::'.) ( {J D.S. S-04A j-q lo.... .1.- D-13A ß("y')--C3?5" ( D.S. S-02A ðO\ --A. 4 ~ ,,-, 07/22/03 NO. 2916 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay Endicott Log Description Color Date Blueline Prints CD 07/19/03 1 07/17/03 1 07/16/03 1 07/16/03 1 07/14/03 1 06/19/03 1 06/09/03 1 06/14/03 1 06/23/03 1 06/10/03 1 PROD LOG WIDEFT RSTGRAVEL PACK LDL SBHP SURVEY RST GRAVEL PACK MEM PROD PROFILE PROD PROFILE W/DEFT MEM PROD PROFILE MEM PROD PROFILE MEM PROD PROFILE PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: ~~~~~ Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Beth .-. R~CEû'V~FD ,.- ,. Received~\5"_<:" 1~t..Çì~y\ JU;'" 2:3 2DGo pJa~â (;~~ ~~ ;2-~~:- ::(':~: ¿~-c .~:-~-;r¡;~¡;:~ci:~l1 :~~~~~"~-~i:r~f~-:: ) ( ) ab/-) 5tp } 1577 r&.. II ~~I~-I~nl~'~ I "'T~'" ILI"I),MTt"If BAKER HUGHES Transmittal Form INTEQ Anchorage GEOScience Center ¡r~ '. "r; ~': :~r1:: ",,~,_.:-~ ¡- "":'''(IJ.:; ¡~.~....,.....~.".., ."...~".,_,..'~". ..,~¡,¡ i :~." ::~.. -:.. ~- I ~'~II(X~l I~;!.;······~~"··_····_~ .._.,;~_..,. .~~ "...-......, ........',....., . To: AOGCC 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Attention: Lisa Weepie Reference: K-317B Contains the following: 1 LDWG Compact Disc (Includes Graphic Image files) 1 LDWG lister summary -..... ¡. ¡ ~§~ l~.~.. .."~___.___~__.__·-'-~'._m~J·l l~::_~~~ti~=:~ 1II!aI¡ ¡ ,.. '~IY,~- :~;~~j~l~~· .----'" 1 blueline - OR/Directional Measured Depth Log 1 blueline - OR/Directional TVD Log I'. ·(I'·',,''''~'.''''J, Io!.', _.~~~_n~~ .~__._._.___ "'"' t. !. ~ Sent By: Glen Horel ReceivedB~ ~ Date: Mar 3, 2003 LAC Job#: 409691 Date: PLEASE ACKNOWLEDGE RECEIPT BY SIGNING & RETURNING OR FAXING YOUR COPY FAX: (907) 267-6623 I:E!t· ; - ~\--- Baker Hughes INTEQ 7260 Homer Drive Anchorage, Alaska 99518 Direct: (907) 267-6612 FAX: (907) 267-6623 - RECEIVED --"-- ---- MAR 04 2003 Alaafœ Oii & Gas Cons. Commiaeion ~_.._-----_._------ Anchcnge ) ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well 181 Oil 0 Gas 0 Suspended 0 Abandoned., n Service , 2. Name of Operator ' .L".4 -"'¡~,~ 't t'I~'.oo;" 7. Permit Number BP Exploration (Alaska) Inc. l·· i~r;C)3: 'J æ' ~:; 201-156 3. Address : . ~. ;'._~, ( .:-"" '. ~S11J ~ 8. API Number P.O. Box 196612, Anchorage, Alaska 99519-6612t,~;:·~,:¿J,~:~~.._ ~3~t;. \ ..../"1 50-029-22537-02 4. Location of well at surface - 9. Unit or Lease Name 3280' NSL, 4078' WEL, SEC. 04, T11 N, R14E, UM X = 671471, Y = 5975221 Prudhoe Bay Unit At top of productive interval 3088' NSL, 1472' WEL, SEC. 04, T11 N, R14E, UM X = 674081, Y = 5975089 10. Well Number At total depth 1615' NSL, 1372' WEL, SEC. 04, T11N, R14E, UM X = 674219, Y = 5973619 11. Field and Pool 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Prudhoe Bay Field / Lisburne Pool KBE = 59.8' ADL 028303 12. Date Spuddeq, 13. Date T.D. Reafhed 14. Date Camp., Susp., or Aband. 12/28/2002 1/22/2003 1/23/2003 · 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey 11935 8830 FT 11935 8830 FT 181 Yes 0 No 22. Type Electric or Other Logs Run MWD, GR, Memory GR, CCL, CNL Classification of Service Well K-317B 15. Water depth, if offshore 16. No. of Completions N/A MSL One 20. Depth where SSSV set 21. Thickness of Permafrost (Nipple) 2177' MD 1900' (Approx.) -r71t1~"..¡ ""'153- I hI'þ ~>Z$> r TVJ5. 23. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE Top BOTTOM SIZE 20" 91.5# H-40 30' 110' 30" 10-3/4" 45.5# NT-80 35' 3707' 13-1/2" 7-5/8" 29.7# L-80 32' 8514' 9-7/8" 4-1/2" 12.6# L-80 8337' 9734' 6-3/4" 3-3/16" 6.2# L-80 8993' 10355' 4-1/8" 2-3/8" 4.43# L-80 10278' 11935' 3" 24. Perforations open to Production (MD+ TVD of Top and 25. Bottom and interval, size and number) 2-3/8" Slotted Section CEMENTING RECORD 260 sx Arctic Set (Approx.) 1050 sx PF 'E', 375 sx Class 'G' 472 sx Class 'G' 452 sx Class 'G' 72 sx Class 'G' Uneemented Slotted Liner TUBING RECORD DEPTH SET (MD) 8339' AMOUNT PULLED SIZE 4-1/2", 12.6#, L-80 PACKER SET (MD) 8282' MD TVD 1 0442' - 11902' 8927' - 8830' MD TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 5000' Freeze Protected with 76 Bbls of Diesel 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) January 26, 2003 Flowing Date of Test Hours Tested PRODUCTION FOR OIL-BBL 02/21/2003 4 TEST PERIOD 827 Flow Tubing Casing Pressure CALCULATED Press. 24-HoUR RATE OIL -BBL GAs-McF 11 ,725 GAs-McF WATER-BBL 20 WATER-BBL CHOKE SIZE 62.65° OIL GRAVITY-API (CORR) GAS-OIL RATIO 14,183 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. No core samples were taken. I· '. ~ I I Form 10-407 Rev. 07-01-80 RtlDMS H~ l ~ ¡v¿i-~~ 4 tL.... " .-/ G\~ Submit In Duplicate ) ) 29. Marker Name Geologic Markers Measured Depth 30. Formation Tests True Vertical Depth Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Zone 1 B 10068' 8666' Zone 1 A 10108' 8687' Kavik I Base Sadlerochit 10225' 8764' Top Lisburne I Zone 7 & 6 10354' 8865' Zone 5 10455' 8934' Zone 5 11120' 8907' 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 Tenie Hubble ~ ~ Trtle Technical Assistant Date ó:;l..· ~ 7' Q3 K-317B 201-156 Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Drilling Engineer: Ted Stagg, 564-4694 Permit No. I Approval No. 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 (OF, 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 ) ) BP EXPLORATION Page 1 öf 18 Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From~ To Hours Task Code· NPT Phase Description of Operations 12/25/2002 00:00 - 11 :00 11.00 MOB P PRE Start mobilization to K-317B from M-09B. On location at 1100 hrs 12-25-02. During the night the Well Support team removed the wellhouse from K-317B, set 16" mousehole to 20'. Site prep began at 1130 hrs. Nordic #2 on stand-by with crews from 1100 hrs. 11 :00 - 14:00 3.00 MOB P PRE Shoot grade and level pad area for Nordic #2. Rig on "stand-by w/crews" 14:00 - 17:00 3.00 MOB P PRE MIRU over K-317B 17:00 - 18:15 1.25 BOPSUR P DECOMP Accept rig at 1700 hrs. Start NU of BOPE. A non-recordable spill occured while lowering the BOP stack onto the wellhead, both hydraulic lines from the HCR valve were pinched. This resulted in the loss of 3 gallons of hydraulic oil, less than 1 gallon reaching the gravel pad. 18:15 - 18:40 0.42 BOPSUR P DECOMP TL and PJSM with crews. 18:40 - 21 :00 2.33 BOPSUR P DECOMP Continue nipple up BOPE and level rig. 21 :00 - 00:00 3.00 BOPSUR P DECOMP Test BOP. 250 psi low /3500 psi high. 12/26/2002 00:00 - 02:00 2.00 BOPSUR P DECOMP Test BOPE. 250 psi low / 3500 psi high for 5 min each. Check accumulator bottle pre-charge pressures and perform draw down test. Notified AOGCC of test without responce . 02:00 - 02:30 0.50 BOPSUR P DECOMP Pressure test lap squeeze to 2000 psi. Good test. 02:30 - 03:30 1.00 BOPSUR P DECOMP Pressure test inner reel valve, CTC and pull test same to 35k. 03:30 - 04:30 1.00 CLEAN P DECOMP PU BHA #1. Wrong WE x-over from motor to MHA 04:30 - 05:30 1.00 CLEAN N WAIT DECOMP Wait on x-over. 05:30 - 06:05 0.58 CLEAN P DECOMP Finish plu BHA #1. P/U and stab on injector. 06:05 - 07:45 1.67 CLEAN P DECOMP RIH tag top of XN nipple at 8333' CT depth. Correct -6' to 8327' . 07:45 - 08:10 0.42 CLEAN P DECOMP Milling on XN nipple. 1360 psi free-spin. <1k WOB <100 psi motor work. 08:10- 08:12 0.03 CLEAN N DPRB DECOMP Milling on XN nipple. Notice increase in flow on micro-motion from 2.5 bpm to 3.5 bpm. Shutdown pump flow continued to increase to 5.8 bpm. Shut-in well. 08:12 - 12:30 4.30 CLEAN N DPRB DECOMP Initial SICP 240 psi stabilzing at 370 psi after 20 min. Bumped CT flow to obtain SICTP of 40 psi. Monitor well. Same time prep to bleed-off to flowback tank, the "new line" laid lastnight seems to be frozen somewhere. While waiting RIH to tag XN nipple at 8327'. RIH to 8333' without tagging. PUH to 7500'. 12:30-13:25 0.92 CLEAN N DPRB DECOMP Bleed-off gas to flowback tank. SICP 337 psi bleeding to 0 in 5 min. Line-up and circulate 30 bbls to tank. FP same. Same time RIH to 8352' did not tag anything. Expecting to possibly tag backed off tbg tail at 8335'. (maximum drop of 8' to top of TIW S-6 Liner Packer). Repeat to 8357'. PUH to 8300' and PT liner lap to 2000 psi for 5 min. Good test. 13:25 - 14:15 0.83 CLEAN P DECOMP RIH at min rate. Small stringer at 8925' bring pump rate up to 2.2 bpm 1185 pis FS. Tagged at 9775' p/u and retag unable to mill appears to be solid CIBP.. Flagged EOP @ 9600' 14:15 -16:00 1.75 CLEAN P DECOMP TOH. Setback injector. 16:00 - 16:15 0.25 CLEAN P DECOMP UD BHA #1 16:15 -17:15 1.00 STWHIP P WEXIT P/U Weatherford 41/2" LSX whipstock set for 160 deg RH tray set, BHA #2 and stab on injector 17:15-19:15 2.00 STWHIP P WEXIT TIH 19:15 - 22:45 3.50 STWHIP P WEXIT Tag CIBP and PU 38 ft to put top whip at 9730 on collar log (9720 on OH log). Pump 5/8" ball. Shear ball at 2450 psi. Printed: 1/27/2003 953:51 AM ") ) BPEXPLORATION Page2of18 Operations Sumnl~ryReport Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 . Date From - To Hours Task Code NPT Phase . Descri ptionof Operations 12/26/2002 19:15 - 22:45 3.50 STWHIP P WEXIT Slack off. Looks good. POH. 22:45 - 23:35 0.83 STWHIP P WEXIT Sperry Inclinmoter reads 52 degrees Right. Per previous decision with Mark Johnson we will perf sqz holes, set an old style LSX whipstock at 160 deg R using Anadrill MWD and Torq orienter, then sqz to secure whipstock and deal with any channel that might be present. Scrapes on weight bars show that the whipstock rode high side. Swivel appears OK. 23:35 - 00:00 0.42 STWHIP N DPRB WEXIT Call out sqz gun and Anadrill MWD. W'Ford to assemble LSX whipstock wlo belville washers. 12/27/2002 00:00 - 02:00 2.00 STWHIP N DPRB WEXIT Wait for delivery of perf gun. 02:00 - 02:30 0.50 STWHIP N DPRB WEXIT Perforating safety meeting with all personnel. 02:30 - 03:40 1.17 STWHIP N DPRB WEXIT PU 20 ft gun, 2.5" 00,4 SPF. 03:40 - 09:10 5.50 STWHIP N DPRB WEXIT RIH with gun tag top of 1 st whipstock. Pick-up 20'. On depth at 0600 hrs. Wait on Weatherford to call back before dropping ball. Having problems with old style LSX whipstock and setting bars in their shop. Later confirming with Weatherford, this style whipstock setting system will NOT work with Anadrill MWD equipment. This setting sys. requires a .625" ball to divert flow to the "Fury Setting Tool". Re-configure setting tools using Baker FAIV on top of Fury tool. Should work no problem. Drop ball for perforating. Town crew dicussing options and disadvantages using this old style LSX whipstock. Tendency to fail with low side set. Decided plan forward would be to use the 1 st whipstock and it's setting of 52 deg RH. Continue to perforate and check for injectivity. 09:10 - 09:35 0.42 STWHIP N WEXIT Continue pumping perf ball, RIH 20' and put lower shot 2' above top of whipstock at 9730'. On seat and guns fired at 0920 hrs. PUH to 9600' close in Micro Motion. Pressure up on annulus to 585 psi and observe slow leak-off to 390 psi after 5 min. Did not try to breakdown perfs. Looks good. No plans for remedial squeeze cement job. Plan forward is to pick-up window milling assembly. Perfs: 9728' - 9708' 4 spf HJ 2506 RDX 09:35 - 11 :00 1.42 STWHIP N WEXIT TOH 11 :00 - 11 :30 0.50 STWHIP N WEXIT PJSM LID perf gun, all shots fired. 11 :30 - 12:45 1.25 STWHIP P WEXIT P/U window milling BHA and stab-on injector. 12:45 - 14:55 2.17 STWHIP P WEXIT TIH. Tagged pinch point of whipstock at 9733'. Correct to 9731' paint flag. 14:55 - 00:00 9.08 STWHIP P WEXIT Milling window f/9731'. 1440 psi free-spin at 2.4 bpm, avg. 2-300 psi motor work, 2-3k wob. Motor stalled three times 9738'-9'. Calling window f/97~1.9' to 9739.2 12/28/2002 00:00 - 00:40 0.67 STWHIP P WEXIT Drilling formation fl 9739 to 9748' @ 2.5 in 12.5 out 1400 psi FS, 1500 on btm. Same time starting mud swap to 8.6 ppg Flo-Pro mud 00:40 - 01 :50 1.17 STWHIP P WEXIT Ream and clean-up window area. Looks good withlwo pumps. Swapping to Flo-Pro. 01 :50 - 04:00 2.17 STWHIP P WEXIT POOH. Flag pipe at 9500' EOP. 04:00 - 05:00 1.00 STWHIP P WEXIT LD milling BHA. Normal wear, mills in gage. Diamond string reamer had no significant wear -- just some scratches. Probably has two to three more wells of life left. 05:00 - 06:30 1.50 DRILL P LNR1 Rehead. Pull and PT CTC. MU drilling BHA (BHA #5) -- HCC Printed: 1/27/2003 9:53:51 AM ) ) BP EXPLORATION Operations.SummaryREJPort Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17 A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Date From-To Hours Task Code NPT Phase 12/28/2002 05:00 - 06:30 06:30 - 08:45 1.50 DRILL P 2.25 DRILL P LNR1 LNR1 08:45 - 09:30 0.75 DRILL P LNR1 09:30 - 09:45 09:45 -14:15 0.25 DRILL P 4.50 DRILL P LNR1 LNR1 14:15 - 15:00 0.75 DRILL P LNR1 15:00 - 16:30 1.50 DRILL P LNR1 16:30 - 18:15 1.75 DRILL P LNR1 18:15 - 20:40 2.42 DRILL N DFAL LNR1 20:40 - 21 :30 0.83 DRILL N DFAL LNR1 21 :30 - 22:30 1.00 DRILL N DFAL LNR1 22:30 - 00:00 1.50 DRILL N DFAL LNR1 12/29/2002 00:00 - 00:40 0.67 DRILL N DFAL LNR1 00:40 - 05: 1 0 4.50 DRILL P LNR1 05:10 - 05:30 0.33 DRILL P LNR1 05:30 - 06:00 0.50 DRILL P LNR1 06:00 - 08:45 2.75 DRILL P LNR1 08:45 - 09: 15 0.50 DRILL P LNR1 09:15 -10:00 0.75 DRILL P LNR1 10:00 -10:15 0.25 DRILL P LNR1 10:15-11:00 0.75 DRILL P LNR1 11 :00 - 16:45 5.75 DRILL P LNR1 16:45 - 17:15 0.50 DRILL P LNR1 17:15 - 18:00 0.75 DRILL P LNR1 18:00 - 19:00 1.00 DRILL P LNR1 19:00 - 19:55 0.92 DRILL Ip LNR1 I Page 3 of 18 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 3-3/4" x 4-1/8" bicenter bit, 1.04 deg motor, Anadril MWD. RIH. Shallow test good. Check flag. Within l' -- no correction. Log tie-in at 9080' GR feature. Looks like about a +10' correction, but not definitive (lost some log quality because of noise). Will not do any adjustments yet, will wait until we identify RA, then PU to 8570' feature to get more definitive tie-in. RIH thru window with 35R TF. Tag dry at 9752'. Try drilling from 9751' (2.7/2750 FS). Very grabby. Numerous stalls. Drill to 9781' (drilled 30' in 4 hours), gradually working TF from high right to low right. Stalls with any more than about 200 psi MW. Saw RA at 9741' uncorrected. Continue drilling slow to 9790'. Samples show 25 - 30% chert; also, significant pyrite. PUH and log tie-in down at 8570' GR marker. Correct depth (+1)'. RIH. CORRECTED WHIPSTOCK TOP = 9733'. CORRECTED WINDOW 9734' - 9742'. RA at 9742'. RIH. Went thru window clean at LS TF. Continue drilling. Less grabby, but a little slow for 22. Drilled to 9800'. Lost MWD reception. Total on bottom drilling time: 6.91 hrs TOH for MWD. Setback injector. Check make-up torque on breaks coming out. LID MWD, download TORC. Bit re-runable P/U new MWD M/U BHA #6 RIH. Shallow hole test good. Continue to TIH. Correct to flag depth at 9600'. No correction Directionally drill ahead fl 9800 to 9950'. 2.8 bpm in lout 3050 psi FS, 3200 psi on-bottom 30'/hr 3-5k wob. Total on-bottom drilling time: 3.0 hrs Wiper trip to window. Survey and orient. Drill 80 FPH, start weighting system with 600 sacks of NaCI. System getting a little aired-up, add some defoamer. TORC orienter TF shifts on stalls. Have to send continuous rotate command for it to find itself. Drill to 10100'. Wiper trip to 50 deg (about 8600'). Log tie-in at 8570' GR marker. No correction. RIH. Survey a couple of spots on the way down. Verified that continuous azimuths are good -- should not need to pump up surveys again. Drill. MW up to 9.4 ppg. No noticable change in FS circulating conditions (2.8/2900). Finish weight-up to 9.6 ppg, Kla-Gard at 8 ppb. Continue drilling. Markers coming in shallow. Big ROP drop starting about 10210'. We may be in Kavik here. Drill to 1 0250'. Wiper to window. Hole in good shape. Drill to 10270'. 4-6k wob 2.9/2.9 Saw an increase in ROP the last 5 ft. PU off bottom and circulate a sample to surface. Drill to 10285'. 5-7k wob 2.8 1 2.8 Printed: 1/27/2003 9:53:51 AM ') ') BP EXPLORATION Operations $ummaryReport Page 4 of18 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From ~To Hours Task Code NPT Phase Descriptionbf Operations 12/29/2002 19:55 - 20:50 0.92 DRILL P LNR1 Circulate bottoms-up. Wiper trip. Kavik looks good. 20:50 - 22:35 1.75 DRILL P LNR1 Drill from 10285' to 10305'. 2.9 bpm 7k wob Stalling numerous times at 10300' - 05'. +/- 94 TVD feet of Kavik drilled so far. 22:35 - 23:25 0.83 DRILL P LNR1 Circulate samples 23:25 - 00:00 0.58 DRILL P LNR1 Drill from 10305' to 10310'. 12/30/2002 00:00 - 02:50 2.83 DRILL P LNR1 Continue drilling ahead f/1 031 0' looking for p-rate change, taking 5' samples drilled to 10338'. Stacking wt. 02:50 - 03:25 0.58 DRILL P LNR1 Wiper trip to window. Hole in good shape. 03:25 - 04: 1 0 0.75 DRILL P LNR1 Drill ahead. 2.7 in lout 2950 FS 3200-3300 on btm. Stacking wt 8-11 k wob drilling off bit may be balled/bald 04:10 - 05:00 0.83 DRILL P LNR1 Circulate samples. 05:00 - 06:00 1.00 DRILL P LNR1 Drill ahead fl 10345' 6k wob 2.8 I 2.8 06:00 - 07:00 1.00 DRILL P LNR1 Drill and circulate samples to 10357'. Started losing returns here at about 0.4 BPM. Stop drilling. 07:00 - 07:45 0.75 DRILL P LNR1 Wiper trip to 8600' 07:45 - 08: 15 0.50 DRILL P LNR1 Log tie-in at 8570' GR marker. Correct depth (-3'). 08:15 - 08:45 0.50 DRILL P LNR1 RIH. Very clean thru Kavik. Tag corrected TO 10355'. Check circulation. 2.5/2.3. Losses have improved. 08:45 - 12:00 3.25 DRILL P LNR1 POOH at 3.0 BPM; 70 FPM. Place 1000' of water at surface for running liner. 12:00 - 12:30 0.50 DRILL N SFAL LNR1 SB inj. RU alternate surface circulation path because of froze-up line. 12:30 - 12:45 0.25 DRILL P LNR1 Safety meeting -- LD BHA. 12:45 - 13:30 0.75 DRILL P LNR1 LD drilling BHA. 13:30 - 14:00 0.50 CASE P LNR1 Safety meeting. PHASE II DRIVING CONDITIONS 14:00 - 20:15 6.25 CASE P LNR1 MU 44 joints of 3-3/16" TCllliner. Fill pipe after 25 joints. Baker-lock shoe components and two jts above O-ring sub. RU false table. MU 21 stands of CSH. Drifting CSH with 1" rabbit. PU CTLRT. Fill liner wi water. M/U CTLRT to liner. 20:15 - 21:15 1.00 CASE P LNR1 Circulate dart thru coil to verify MM numbers. 58.4 calc I 58.2 actual. 21 :15 - 22:00 0.75 CASE P LNR1 Rehead to Baker eTC. PT to 5k pull test to 35k. 22:00 - 00:00 2.00 CASE P LNR1 MU injector. RIH min rate (BHA 1371.45') Set pump trips to 1 k. P/U at window 40.6k RIH no problem at window. 12/31/2002 00:00 - 00:15 0.25 CASE P LNR1 Continue RIH with 3 3/16" drlg liner. Took wt @ 10222' and fell thru. RIH to bottom with no more set downs. Check wt 44.5k. 00:15 - 01:05 0.83 CASE P LNR1 P/U off bottom. Circulate at min rate .19 in I .17 out 830 psi. Load, launch and pump .625" phenolic ball. RIH set down with 10k on bottom. Pick up rate to 2.40 in 12.16 out @ 3100 psi. On seat at 52.7 bbls away sheared CTLRT at 3825 psi. Pick-up wt 35k confirm loss of liner. Setdown with 10k. 01 :05 - 02:40 1.58 CASE P LNR1 Displace well to 2% KCL. Initial 2.5 in I 2.15 out 3230 psi final loss rate the same. Same time PJSM with all crews on cement job. 02:40 - 04:00 1.33 CEMT P LNR1 Pump 5 bbls FW ahead. PT lines to 4k - ok. Start pumping cement 14.6 bbls away. Load and launch CT wiper dart. Confirm launch. Displace cement (2.2 bpm in 1.8 out 2400 psi) with 20 bbls KCL w/2# bio followed by 40.3 bbls 2% KCL. Wiper plug bump at calculated volume 60.3 bbls. CIP @ 0355 hrs. At 44 bbls away cement hit CSH and pressures climbed to 4k at 2.2 bpm. Slowed remainder of displacement to 0.8 bpm and 750 psi. Printed: 1/27/2003 9:53:51 AM ) ) BPEXPLORATION Page Operations Summary· Repo.rt Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17 A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date FrOI11- To Hours Task Code NPT Phase DescriptiOn of Operations 12/31/2002 02:40 - 04:00 1.33 CEMT P LNR1 Losses subsided last half of cement displacement from +/- 80% returns to almost full returns. Sting out of O-ring sub. Shear dart seat with 3500 psi. 04:00 - 06:30 2.50 CEMT P LNR1 TOH Lay-in 2# bio through out liner pumping at min rate (keeping ECD's low across top of cement) 06:30 - 08:15 1.75 CEMT P LNR1 Standback injector. Hole is full. LD CSH in singles (metal displacement = 1.5 bbls). 08:15 - 08:30 0.25 CEMT P LNR1 Safety meeting 08:30 - 11 :30 3.00 CEMT N DPRB LNR1 Prep to PU motor/mill. Well flowing. SI. lAP = 217. Monitor pressure buildup. 09:30 -- WHP = 95 psi; lAP = 207 psi. Cement in lab at 500 psi. 10:30 -- WHP = 100 psi; lAP = 200 psi. 11 :30 -- WHP = 100 psi; lAP = 190 psi (typical cooling). Cement in lab at 1050 psi. 11 :30 - 12:00 0.50 CEMT N DPRB LNR1 Bleed well, all water. Let it flow for ten minutes Uust a trickle) to see if it stops -- it didn't -- total bleed and flowback about 0.75 bbl. 12:00 - 14:00 2.00 CEMT N DPRB LNR1 SI well again and monitor pressure buildup. Order KCL weight material from MI. 14:00 - 17:00 3.00 CEMT N DPRB LNR1 Raise brine weight to 9.0. Install nozzle & stinger assembly on coil. Cement UCA up to 1900 psi at 1600 hrs. 17:00 - 18:45 1.75 CEMT N DPRB LNR1 Get on well. RIH with 3.0" od nozzle. Hold +/-150 psi well head pressure while RIH tagged at 8600'. 18:45 - 20:30 1.75 CEMT N LNR1 Holding 180 psi on backside circulate 9.0ppg brine around. First part of circulation seen some oil, clearing up then +/- 20 bbls bio/cement to surface. The return 9.0 ppg brine does have brown stain. Opened choke circulated 1/2 hr. Shutdown observe well 1 0 min. Dead (lost 2bbls within that 1/2hr circ while circ 9ppg) Check if well is full - yup. 20:30 - 23:00 2.50 CEMT N LNR1 TOH. Stop at 8100' to do a quick injectivity test. At +/- 0.3bpm 1500 psi and climbing. (Very difficult to maintain a constant pump rate with the way these pumps are hooked up to the SCR system. As pressures increase the rates decrease. NOT ideal. This is a problem even while drilling) Continue TOH setback injector 23:00 - 23:50 0.83 CEMT N LNR1 UD nozzle and P/U 2 7/8" motor with 3.80" parabolic mill. Stab on injector 23:50 - 00:00 0.17 CEMT N LNR1 RIH 1/1/2003 00:00 - 01 :25 1.42 CEMT LNR1 TIH w/3.80" mill. Tagged at 8607 uncorrected depth. 01 :25 - 03:00 1.58 CEMT LNR1 Washing soft cement from 8607' 2.3 bpm in /2.3 out 1770 psi. 9'/min tagged hard cement at 8882'. 03:00 - 05:20 2.33 CEMT LNR1 Drilled cement from 8882'. 2.5/2.5 2000psi FS, 2275 psi on btm. Several stalls while drilling cement on down to 8984' top of liner. Made several wiper trips back to 8450' and pumping bio sweeps. 05:20 - 07: 15 1.92 CEMT LNR1 TOH 07:15 - 08:00 0.75 CEMT LNR1 Get off well. LD clean out assembly. 08:00 - 10:00 2.00 CEMT LNR1 MU BOP stack clean out assembly. Flush BOP stack to remove excess liner cement. 10:00 - 11 :00 1.00 CEMT LNR1 Pressure test liner & lap to 1560 psi for 15 minutes. Bled off to 1452 psi. (9.2 ppg fluid in well adds an extra 300 psi, so actual Printed: 1/27/2003 9:53:51 AM ) J BPEXPLORATION Page 6 of 18 Operations. 'Summary. Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17 A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Date Frbrn- To Hours Task Code NPT Phase 1/1/2003 10:00 - 11 :00 11 :00 - 13:00 13:00 - 15:00 15:00 - 18:00 1.00 CEMT 2.00 CEMT 2.00 CASE 3.00 CEMT LNR1 LNR1 LNR1 LNR1 18:00 - 20:00 2.00 CEMT 20:00 - 22:45 2.75 CEMT 22:45 - 23:00 0.25 EVAL 23:00 - 00:00 1.00 EVAL 1/2/2003 00:00 - 00:15 0.25 EVAL P 00: 15 - 03:00 2.75 EVAL P 03:00 - 04:35 1.58 EVAL P 04:35 - 07:00 2.42 EVAL P 07:00 - 07:15 0.25 EVAL P 07:15 - 10:30 3.25 CASE P LNR1 LNR1 LNR1 LNR1 LNR1 LNR1 LNR1 LNR1 LNR1 LNR1 10:30 -11:15 0.75 CASE P LNR1 11 : 15 - 13:00 1.75 DRILL P PROD1 13:00 - 16:00 3.00 DRILL P PROD1 16:00 - 17:00 1.00 DRILL P PROD1 17:00 - 00:00 7.00 DRILL P PROD1 1/3/2003 00:00 - 04:00 4.00 DRILL P PROD1 04:00 - 06:00 2.00 DRILL P PROD1 06:00 - 13:00 7.00 DRILL P PROD1 13:00 - 18:00 5.00 DRILL P PROD1 18:00 - 18:20 18:20 - 00:00 0.33 DRILL P 5.67 DRILL P PROD1 PROD1 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 . oescriptionof Operations hydostatic test was 1860 psi/1752 psi, assuming 8.5 ppg fluid) MU 2.75" mill & motor on 44 jts 1-1/4" CSH. Get on well. RIH. Tag cement at 8994'. 1.7 bpm@1965 psi fs. Mill out cement. Hit several hard stringers from 8991' to 9020'. Liner clean from 9020' to 10313'. Circulate 2# 50bbl bio sweep around to clean hole. Circulate OOH. LID CSH and milling BHA PJSM handling logging tools P/U CNLlCCLlgr BHA. ( Begin all rig & related charges to AFE PBMWPK017) Continue P/U BHA #8. Stab-on well wI injector. TIH to 8900'. Get on depth wI Schlumberger. Start logging down fl 8900' wI Memory CNLlCCLlgr . Tagged at 10315' CTD. Logged back to 8860'. TOH wI logs. Hold PJSM before LD logging tools. Address source handling procedures, etc. RIH with all CSH in derrick. POOH laying down singles. Download logs. Tie into PDS jewelry log from 7-17-98 and Sperry CNL log from 1-11-95. Top of liner located at 8984'. Liner shoe at 10347'. RA tag found at 9742'. Test 3-3/16" liner to 1000 psi for 5 minutes. Slight bleed off. Pressure to 1500 psi, then 2100 psi. Shut in for 15 minutes. No bleed off. Liner & lap holding tight. MU nozzle assy. Get on well. FP with 50/50 meoh from 2000'. POOH. Get off well. LD nozzle assy. RU to blow down 2-3/8" coil with N2. Blow down same. RD N2 & equipment. Get off well. Prep to load pipe shed with reel injection equipment. Unstab 2.375" coil from injector and secure to reel. Continue to secure 2.375" coil to reel. Attach overhead crane, open doors and lower same to bed truck. Position 2" coil reel, attach crane and raise into reel house. Close doors and secure. Same time this was happening, opened pipe shed's overhead door. With "Cherry-Picker" set in E-line cable injection equipment and rigged up sam~ for injection later today. Also cleaned pits 3,4,5 isolating 200 bbls 9.2 brine in tank 2. Start dressing CT injector for 2" coil. Also check N2 bottle pressures on BOP accumulator. Swap BOP pipe rams to 2" Combi's. Continue transition to 2" coil. Work on injector, goose neck, BOPS component swap. Continue cleaning pits. Repair ram attachment points on pipe shed roof. BHI installing computer system equipment. Rig off day rate at 1000 due to e-line injection process. Complete rig up to inject e-line into coil. Pull 2" coil into pipe shed. MU to injection hardline. PT lines to 3500 psi. PJSM with on coming crews about e-line injection. Inject e-line into 2" coil with freshwater @ 2.4 - 2.6bpm, 11 0-120'/min, 3200-3600 psi. Printed: 1/27/2003 9:53:51 AM ), ) BP EXPLORATION .Operations Summary Report Page 7 of 18 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From -·To Hours Task Code NPT Phase Description of Operations 1/4/2003 00:00 - 04:30 4.50 DRILL P PROD1 Pump a 10 bbl corrosion inhibiter pill into 2 coil and follow by blowing down coil w/ N2. Secure EOP back to reel. Rig reel to overhead hoist, open door and lower to bed truck. (This reel will be the back-up reel stored in Deadhorse) 04:30 - 06:00 1.50 DRILL P PROD1 Position 2nd reel. Attach overhead hoist and lift into position in reel house and secure. 06:00 - 10:00 4.00 DRILL P PROD1 Pull coil over ops cab and secure to injection skid. Complete RU to inject 2nd reel. 10:00 - 13:30 3.50 DRILL P PROD1 Inject 5/16" e-line into 2" coil reel. 13:30 - 17:00 3.50 DRILL P PROD1 RD injection equipment from pipe shed. Rig back on day rate at 1330. 17:00 - 19:30 2.50 DRILL P PROD1 Spool coil back onto reel. Prep to run same through horse head. 19:30 - 19:50 0.33 DRILL P PROD1 PJSM covering coil stabbing procedures. 19:50 - 23:15 3.42 DRILL P PROD1 Stab 2" coil to injector. Same time replacing 4 bad bladders found during Komey bottle pre-charge pressure tests. 23:15 - 00:00 0.75 DRILL P PROD1 Re-configure BOP ram order. Top>down: Annular - Blind/Shear - 2" combi - Mud Cross - 2 3/8" combi - 2"combi. Same time start installion of injector pack-off. 1/5/2003 00:00 - 04:30 4.50 DRILL P PROD1 Continue with re-configuring BOP ram order. Top>down: Annular - Blind/Shear - 2" combi - Mud Cross - 2 3/8" combi - 2"combi. Repacking" Standard Pack-off' injector pack-off assembly. 04:30 - 04:45 0.25 DRILL P PROD1 PJSM for test BOP's. 04:45 - 06:00 1.25 BOPSURP PROD1 Testing BOPE. Notified AOGCC John Spaulding wavied witnessing. 06:00 - 06:45 0.75 BOPSURP PROD1 Hold on tour PJSM/Tech limit mtg to discuss lessons learned from stabing coil. Discuss plan forward for tour. 06:45 - 16:30 9.75 BOPSURP PROD1 Continue BOP test. Test choke manifold & tree valves. No body test. Call grease crew. Tree still leaking, call out BPV crew. Still leaking off. Re-grease entire tree. Continue to RU for 2" coil. Access to rig floor restricted during BOP test. Complete installing iron inside coil reel. Complete RU of super choke. Redress "Standard Pack-off' try to install under injector but mounting pins will not matchup with injector. MU and test alllnteq coil track BHA's on cat walk. 16:30 - 00:00 7.50 BOPSURP PROD1 Continue BOP test. Second tree grease job apparently solved problem. Using charge pump flushed choke manifold with FW. Completely start over and test choke manifold and BOP stack to 250 psi low and 3500 psi high f/ 5 min each. Same time dress "Side Door" pack-off assembly f/ 2.375" to 2". 1/6/2003 00:00 - 00:45 0.75 BOPSURP PROD1 Finish testing BOPE. Work on injector pack-off assembly. 00:45 - 02:45 2.00 DRILL P PROD1 Finish redressing pack-off assembly. Prep lubricator for picking up. Work on lubricator pack-off converting from .108" to .125" wire. 02:45 - 02:55 0.17 DRILL P PROD1 PJSM review plan forward. 02:55 - 04:10 1.25 DRILL P PROD1 Position injector over pack-off assembly and attach. Stab coil through pack-off. Move injector to side. 04:10 - 04:35 0.42 DRILL P PROD1 Pull BPV. Test continuity of e-line OK 04:35 - 09:00 4.42 DRILL P PROD1 Head up coil with BHI coil connector. Put slick line lubricator pack-off together. Mousehole 1 st 30' section of lubricator. 09:00 - 10:00 1.00 DRILL P PROD1 Hold PJSM to discuss pressure deployment procedures and rig Printed: 1/27/2003 9:53:51 AM ) ) BPEXPLORATION Page8of18 Op~rations· Summ:aryR.eport Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From - To Hours Task· Code NPT Phase Descri ptionofOperations 1/6/2003 09:00 - 10:00 1.00 DRILL P PROD1 up of equipment for same. 10:00 - 12:00 2.00 DRILL P PROD1 RU slick line lubricator. Thread slick line and tools in same. Pull lubricator into derrick with tugger. Arrange lubricator to avoid interference with derrick equipment. 12:00 - 16:00 4.00 DRILL P PROD1 Step through pressure deployment procedure with coil track tools with day crew. Adjust equipment rig up as needed. Document same. 16:00 - 17:30 1.50 DRILL N DPRB PROD1 Unable to get mwd BHA past 30'. Determine ice plug formed in tubing. Likely from BOP test water displacing freeze protect fluid near surface. Steam out same. 17:30 - 18:30 1.00 DRILL N DPRB PROD1 RD equipment used to thaw ice plug. Prep floor area for MU milling BHA. 18:30 - 20:30 2.00 DRILL N DPRB PROD1 Thaw out choke/kill lines from BOP stack. 20:30 - 21 :05 0.58 DRILL P PROD1 MU float equipment milling assembly (2-3/8" motor with 2.75 long gauge diamond mill, jars, 1 jt 2-1/16" drill pipe) 21 :05 - 22:00 0.92 DRILL P PROD1 Stab injector to BHA. (new problems here. Extra care with "wet connect") Check continuity 400 ohm -ok. Reposition tieback chains on injector due to increased lubricator height for Inteq's MHA. (Reel tension on higher injector intensifies the pull on injector towards the reel) 22:00 - 00:00 2.00 DRILL P PROD1 RIH. Trouble with depth/encoder. Unable to acturately determine depth. Using mechanical counter. Adding bio-zan to mud system. 1/7/2003 00:00 - 02: 15 2.25 DRILL N SFAL PROD1 RIH to 7200'. SLB tech on location working on depth counter problem. 02:15 - 03:30 1.25 DRILL P PROD1 RIH in 100' increments. Calibrate Inteq and Sperry depth counter K-factors. RIH w/ circ sub open 2.0 bpm 2618 psi. Close circ sub 2.0 bpm 3650 psi. RIH tagged at 10321' correct back to top of o-ring sub depth 10306'. 03:30 - 04: 15 0.75 DRILL P PROD1 Drill shoe track. 1.9/ 1.9 bpm 3350 free-spin 100-200 psi motor work. Mud wt 9.08 ppg system has +/- 1 1/2ppb bio-zan. Drill o-ring sub, 10' pup, to top of float collar at 10317.5' 04:15 - 04:30 0.25 DRILL P PROD1 Wiper trip back through to 10000' 04:30 - 07: 15 2.75 DRILL P PROD1 Continue drilling shoe track 10,344'. 07: 15 - 09:45 2.50 DRILL N DFAL PROD1 Coiltrack system shorted. Unable to activate disconnect. POOH to trouble shoot same. 09:45 - 11 :45 2.00 DRILL N DFAL PROD1 Get off well. Stand back injector. LD BHA. Determine short is in EDC module. Replace same. Add 2.75" string reamer to BHA. Get on well. Test mwd (good). RIH. (Note: Getting off the well with this BHA simulated the space ouUstrip off clearance needed for pressure un-deployment. 4' of lubricator below stuffing box is sufficient) 11:45-14:30 2.75 DRILL N DFAL PROD1 RIH with milling BHA. Tag btm. Correct depth -18'. 14:30 - 17:00 2.50 DRILL P PROD1 Mill ahead from 10344'. Mill through float shoe. Drill 10' of open hole to 10357' (Formation drilled at 30 fph rop with full returns) 17:00 - 18:30 1.50 DRILL P PROD1 Begin displacement to 8.6 ppg flo pro. Catch btms up samples from formation. 18:30 - 19:30 1.00 DRILL P PROD1 POH to 3000'. While circulating new mud around. 19:30 - 20:45 1.25 DRILL P PROD1 Monitor well no flow no losses. 20:45 - 21 :30 0.75 DRILL P PROD1 POH to surface. Flow check at 500' No Flow. 21 :30 - 23:00 1.50 DRILL P PROD1 Changout out milling assembly for drilling assembly. Practice pressure deployment. Printed: 1/27/2003 9:53:51 AM ') ) BP EXPLORATION Operati 0 nSSuml11é1.ryReport P~ge90f 18 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 .. Date From - To Hours . Task Code NPT Phase Description of Operations 1/7/2003 23:00 - 23:45 0.75 DRILL P PROD1 RIH to 2700'. 23:45 - 00:00 0.25 DRILL P PROD1 FIT test to 790 psi. Lost 140 psi in 10 minutes. 1/8/2003 00:00 - 01 :30 1.50 DRILL P PROD1 RIH to 9800 with BHA #10. 01 :30 - 02:30 1.00 DRILL P PROD1 Tie-in to RA tag. -11' correction. RIH Tag bottom at 10,357'. 02:30 - 03:30 1.00 DRILL P PROD1 Directionally drill 1.48/1.48 bpm 3955 psi FS = 3550 psi. Drilled to 10,368'. Gas at shaker. Max out gas detector at 10,000 units. Down hole annulus pressure 4019 psi static. 03:30 - 04:00 0.50 DRILL P PROD1 No Flow. Shut in for 10 min 26 psi. Open well no flow. 04:00 - 04:30 0.50 DRILL P PROD1 Circlate at 1.25 bpm at 3050 psi. thru gas buster. Down hole annulus pressure 4550 psi.making ECD = 530 psi. Gas 4500 units at shaker. No gas from gas buster vent. 04:30 - 05:00 0.50 DRILL P PROD1 Stop circulating. Drain gas buster and monitor well. No Flow. 05:00 - 07:30 2.50 DRILL P PROD1 Directionally drill 1.63/1.63 bpm @ 3950 psi. FS = 3700 psi. Down hole annular pressure 4600 psi making ECD = 580psi. ROP 20 ft/hr. Drill to 10385'. 07:30 - 10:00 2.50 DRILL P PROD1 Pull up to 8560 to re log Shublik tie in point. Log to 8590'. No correction. RIH to log RA tag. Find RA tag at 9742'. No correction. This is same depth as mwd tie in depth from 4-1/8" hole section. This indicates 3-3/16" shoe is at 10358'. Kavik should not be exposed. Only un-explained mystery is why cased hole CNL showed correct liner top & PBTD, butAA tag logged at 9752' (10' deep). All future survey tie-ins will be made using RA tag at 9742'. 10:00-10:15 0.25 DRILL P PROD1 Measure static & circulating annular pressures at 8950' (TOL) 3940 static/4245 psi @ 1.72 bpm (305 psi diff) Annular pressure near shoe (10336') 4171 psi static /4654 psi psi @ 1.72 bpm (393 psi diff) 10:15 -13:00 2.75 DRILL P PROD1 Drill ahead. 3580 psi fs @ 1.67 bpm. 200-500 dpsi. 1.7 in/out WOB: 2.0K# ROP: 10-20 fph. Drill to 10414'. 13:00 - 16:00 3.00 DRILL P PROO1 Drill ahead to 10450'. Avg ROP: 13 fph. 16:00 - 17:00 1.00 DRILL P PROD1 Drill ahead to 10457'. Est avg rop:14 fph. 3340 psi fs @ 1.7 bpm. Full rtns. 2-3K # WOB. Begin to reduce mud LSRV from 60K to 45K to try and reduce pump pressures. 17:00 - 19:30 2.50 DRILL N DFAL PROD1 Coiltrack orienter failed. POOH to check/replace orienter. We were advised of change of target TVDSS from 8920 to 8905. Will run 2.3 degree motor to get required build rates of 25 degrees/100ft. 19:30-21:15 1.75 DRILL N PROD1 Change out orienter and bit .The bit was in new condition, but looking for more ROP will try Hycalog bicentered bit. 21 :15 - 23:00 1.75 DRILL N PROO1 RIH to 9740'. Tie in point. 23:00 - 23:30 0.50 DRILL N PROD1 Tie-in log (-10' correction.) 23:30 - 00:00 0.50 DRILL N PROD1 Drill to 10,465' 1.6 bpm 3800 psi FS = 3630 psi. 1/9/2003 00:00 - 00:30 0.50 DRILL P PROD1 Drill from 10,465 to 10,477. MWD not performing Azmuth data all over the map. High gas alarm 40 bbl prior to bottom up. Reviewed the ECO data prior to alarm. No ECD change was noted. i.e. no bubble expanding. 00:30 - 01 :30 1.00 DRILL N DFAL PROD1 Pull to liner. Shut-in and monitor well 30 minutes. 125 psi on wellhead. 01 :30 - 02:00 0.50 DRILL N DFAL PROD1 Circulate at 1 bpm while circulating through the choke holding 70-100 psi. 02:00 - 02:15 0.25 DRILL N DFAL PROD1 RIH to get survey tool data at 10,430 and 10,460'. Reading requested to help diagnose MWD problem. Printed: 1/27/2003 9:53:51 AM ) ) BP EXPLORATION Page10of18 Operations. Summary. Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17 A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From - To Hours Task Code NPT Phase Description of Operations 1/9/2003 02:15 - 04:00 1.75 DRILL N DFAL PROD1 POH. Monitor well at 500' No Flow. 04:00 - 04:30 0.50 DRILL N DFAL PROD1 LD BHA and prep MWD for yard test. 04:30 - 11 :30 7.00 DRILL N DFAL PROD1 Will yard test 2nd MWD directional package by removing tool from metal interference, align tool to magnetic north and check its readings with and without the mud motor. The mud motor may be magnetized and the source of interference. Tools's azimuth varies as tool is turned. Looks like a bad tool. Return tool to Dead horse for additional testing. Test a 3rd tool outside on ground. Working well. Discuss options with town. Decide to run 3rd tool and compare to first tool. MU & program/test 3rd tool on catwalk. 11:30-12:15 0.75 DRILL N DFAL PROD1 Get on well. New red tugger/pulley arrangement and new hamster hole (to set back injector & circulate without needing a hose) works well for aligning injector to stab on tools & lubricator. 12:15 - 14:15 2.00 DRILL N DFAL PROD1 RIH with 2.6 mtr & Hycalog 2.75 x 3.0 bi-center bit. 14:15 - 14:30 0.25 DRILL N DFAL PROD1 Log gr tie in at RA tag (9742') Subtract 13' correction. 14:30 - 14:45 0.25 DRILL N DFAL PROD1 Continue in hole. Tag btm at 10477'. 14:45 - 16:00 1.25 DRILL N DFAL PROD1 Circulate well to 8.9 ppg flopro. Take some gas during circulation. Diverted through gas buster. 100 psi max whp. 16:00 - 00:00 8.00 DRILL P PROD1 Drill ahead. 3550 psi fs @ 1.8 bpm 200-550 dpsi. Full rtns. 2.0-2.5k# WOB. 10-15 FPH ROP. PU weight 30K SO 18K. TF 30R to 10525 , 40R to 10531' and 90R to 10556. 1/10/2003 00:00 - 07:15 7.25 DRILL P PROD1 Directionally drill 1.8 /1.8 bpm at 3,740 psi to 10,561 FS = 3,550 psi. At 10,561'. Hit a hard streak. Hard to get any motor work. Finally broke thru @ 1 O,563'.Logs indicate a shale stringer most probable cause. Continue drilling 1.8 / 1.8 bpm at 3,740 psi to 10,590 FS = 3,550 psi. End of build called at 10,585 MD @ 8,897 tvdss. Continue to drill 85 R to align azm to 170 for lateral section. Drill to 10628'. ROP very low. 07: 15 - 09:45 2.50 DRILL P PROD1 POOH for gyro survey. 09:45 - 12:30 2.75 DRILL P PROD1 Unstab from well. LD drilling bha. MU gyro tool BHA. Some difficulty getting gyro depth encoder to work. Stab on well. 12:30 - 13:30 1.00 DRILL N DFAL PROD1 Problems with EDC module & depth system in Ops cab. Repair same. Re-start gyro tool. 13:30 - 18:30 5.00 DRILL P PROD1 RIH. Depth counters working correctly. Survey stations taken at 5K,6K, 7K,9K,9900, 1 01 00,10400,1 0500,TD. Repeat surveys while POOH. (approx. 5 minutes per station) 18:30 - 19:30 1.00 DRILL P PROD1 POH to surface. LD BHA. 19:30 - 21 :30 2.00 DRILL P PROD1 Down load Gyro survey data. Data was acquired in the low angle continuous mode from 5000' to 7000'. with good results. Data was acquired from 7000' to 10500' and from 10500 back to 6700' in the high angle continuous mode. The high angle continuous mode data was unable to be processed. After discussions with Bakersfield it was decided rerunning the gyro wouldn't be productive. Further investigation into the cause of the problem will continue. Off site attempts to reprocess the data will also continue. 21 :30 - 22:00 0.50 DRILL P PROD1 MU BHA for drilling latetral section 1.1 motor. 22:00 - 23:20 1.33 DRILL P PROD1 RIH to 9740'. 23:20 - 23:35 0.25 DRILL P PROD1 Tie-in (Correction -9'). 23:35 - 00:00 0.42 DRILL P PROD1 RIH tag at 10626. 1/11/2003 00:00 - 01 :50 1.83 DRILL P PROD1 Drilling at 1.75/1.75 bpm 3640 psi FS 3500 psi. Up 22K SO Printed: 1/27/2003 9:53:51 AM ) ) BP EXPLORA rrON Page 11 of18 O·perations S.ul11>maryReport 18K. 8-1 OK WOB Rap 20. No gas on bottoms up. Drill to 10658'. Wiper 100'. Hole smooth. Drilling at 1.75/1.75 bpm 3640 psi FS 3500 psi. Up 22K SO 18K.2-3K WOB Rap 20. Drilling with negative weight -8000 @ 10669'. Red line -9200#. PU -900 while running back to bottom. Mud currently has 3% lubtex called for additional lubricrants. Start adding FloLube. Will add a total of 8 drums of FloLube adding 2% increasing the total lubricants to 5%. PROD1 Drilling at 10669 hard spot acting like previous shale drilling at 1.8 /1.8 bpm 3560 psi FS= 3500 psi 2K wob. With the addition of the lubricant we seen an increase of available weight on bit from 1900 # to 3200#. Continue to drill on hard spot at 10669'. Try slamming into btm with pumps off. Bring pump on line. Motor should be stalled but is not. Bit may be balled or motor worn out. POOH to check BHA. At surface. Unstab from well. LD motor. Bit ok. One chipped cutter on face. Wait 15 minutes on replacement motor. Check e-line. MU motor & bit. Scribe same. Get on well. RIH with 1.0 2-3/8" mtr with 2.75" Hycalog pdc. Drill ahead from 10669'. 3300 psi fs@1.53 bpm. Very very hard. Stacking -7K# coil weight, 4200# downhole weight on bit. Able to make about l' per hr. Calculate thickness of hard zone based on previous penetration shows estimated 6'-8' of hard spot to drill. Can't get bit to stall no mater what we do. Drill to 10674' Drill ahead. 3550 psi fs @ 1.65 bpm. 200-300 dpsi. Full rtns. 3000# WOB. ROP:12 fph. Drill ahead from 10688' at 1.6/1.6 bpm 3550 psiFS 3550 # WOB. Drill to 10692' hit hard streak. Unable to get stall WOB up to 3900#. POH for bit change unable to make any hole. POH. Monitor well at 500'. No Gas. POH to surface. Change out Bit and motor.Bit and motor like new. Pick up natural diamond bit and extreme motor. RIH with 1.1 Inteq Extreme motor and Hughes natural diamond bit. Tie - in Correction -10' corrected 9,775.5' (mechanical counter 9,725'.) RIH and tag at 10684.3'. Drill at 1.67/1.67 bpm at 3900 psi FS = 3400 psi. WOB = 2500 # UP 28K, SO 18K, TF 75R. Drill to 10691'. Drilling ahead. 3300 psi fs @ 1.6 bpm. 250 dpsi. Full rtns. WOB: 3300#. Rap: 1-2 FPH. TF:75r. Very hard. Good weight to bit, but very very slow Rap. Drill to 10694'. Short trip into liner. Hole smooth. Drill ahead after wiper trip. Driling mechanics improved. 300-500 dpsi, 5K# wob, drilling off. However, Rap is still very low (5 fph). Still, looks like short trip helped. Short lived improvement. Drill to 10703'. PROD1 POOH to change back to pdc bi-center. PROD1 Get off well. Change out bit from 2.75 hyc to bi-center hycalog. Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17 A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Qate From - To Hou rs Task Code NPT Phäse 1/11/2003 00:00 - 01 :50 1.83 DRILL P PROD1 01 :50 - 01 :55 0.08 DRILL P PROD1 01 :55 - 04:00 2.08 DRILL P PROD1 04:00 - 06:00 2.00 DRILL P 06:00 - 07:45 1.75 DRILL P PROD1 07:45 - 09:30 1.75 DRILL P PROD1 09:30 - 11 :00 1.50 DRILL P PROD1 11 :00 - 12:45 1.75 DRILL P PROD1 12:45 - 16:00 3.25 DRILL P PROD1 16:00 - 18:00 2.00 DRILL P PROD1 18:00 - 22:30 4.50 DRILL P PROD1 22:30 - 00:00 1.50 DRILL P PROD1 1/12/2003 00:00 - 00:30 0.50 DRILL P PROD1 00:30 - 01 :15 0.75 DRILL P PROD1 01 :15 - 03:00 1.75 DRILL P PROD1 03:00 - 03:30 0.50 DRILL P PROD1 03:30 - 03:50 0.33 DRILL P PROD1 03:50 - 06:00 2.17 DRILL P PROD1 06:00 - 09:45 3.75 DRILL P PROD1 09:45 - 10:00 0.25 DRILL P PROD1 10:00 - 12:00 2.00 DRILL P PROD1 12:00 - 13:45 13:45 - 14:45 1.75 DRILL P 1.00 DRILL P Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Description of Operations Printed: 1/27/2003 9:53:51 AM ) ) BP EXPLORATION Page 12 of18 Operations Summary RépO.rt Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17 A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From- To Hours Task Code NPT Phase Description of Operations 1/12/2003 13:45 - 14:45 1.00 DRILL P PROD1 Get on well. 14:45 - 16:30 1.75 DRILL P PROD1 RIH with 1.1 extreme motor w/ 3.0 hycalog bicenter bit. 16:30 - 16:45 0.25 DRILL P PROD1 Log gr tie in from 9770'. Subtract 12' correction. 16:45 - 17:00 0.25 DRILL P PROD1 RIH. Tag tight spots from 10690 to 10698' Ream through same. 17:00 - 18:00 1.00 DRILL P PROD1 Drill ahead from 10698' (actual btm with out stacked coil). 3300 psi fs @ 1.71 bpm. 300 dpsi. Full rtns. 26K# up, 16K# dn wt. 2.5-3.5K# WOB. 10-12 FPH ROP. 18:00 - 20:00 2.00 DRILL P PROD1 Drill to 10737. 1.6/1.8 bpm 3440 psi 3200 FS. Start displacing to new mud while drilling ahead. 20:00 - 23:30 3.50 DRILL P PROD1 At 10,737. Starting lossing 1 bpm before it partially heald. Losses varing from full losses to .5 bpm returnms. Called for KCL water. Drill to 10761 averaging 20 ftIhr over the last three hours. Stall at 10,761'. Continue drilling at 1.65/1.1 bpm @ 3350 psi with 600 psi dp. Drilled to 10,780'. 23:30 - 00:00 0.50 DRILL P PROD1 Water on location. Shut-in choke while drilling ahead. Stabilized well head pressure while bullheading 8.9 mud was 450 psi. Annular down hole pressure while shutin = 4750 psi. @ 8892 TVDss. 10.3 EMW. Open choke. 1.65/1.35 bpm at 3350 psi dp 500psi. While continuing to drill ahead displace coil to 2% KCL slick water to bit. 1/13/2003 00:00 - 00:10 0.17 DRILL P PROD1 Drill ahead( hard spot at 10,781') while continuing to displace coil to 2% KCL water. 00: 1 0 - 02:30 2.33 DRILL P PROD1 Shut in choke and drill with 2% KCL. Drill a 1.6 bpm @ 2,600 psi. Well head pressure 670 psi. 4,829 down hole annulus pressure. dp=630 psi. Drill to 10,787'. good weight transfer. Have seen down hole annular prerssures as high as 5,000 psi 10.8 ppg EMW. 02:30 - 04:00 1.50 DRILL P PROD1 Continue to drill 1.6 bpm. 2,780 psi 660 psi dp. have seen 1,000 psi dp on hard spots. Good weight transfer. Annular pressure down hole 4,900 psi 10.6 EMW. 880 psi motor work. WOB 4K. 04:00 - 08:00 4.00 DRILL P PROD1 Drill to 10,794. Very slow ROP. WHP increased from 850 psi @ 1.45 bpm to 1,100 psi. Excessive ECD may be slowing ROP. Possibly charging the formation. 08:00 - 10:30 2.50 DRILL P PROD1 Discuss procedure for bleeding well and managing fluids on location. Slowly bleed WHP down from 1,100 to 100 psi. Got a lot of "gas" back. Mud loggers did not measure any gas increase, so suspect only air on top of fluid column. Maintain 100 psi whp while circulating out remaining KCL water. Mud weight varying from 8.6 to 8.9 ppg. 10:30 - 12:45 2.25 DRILL P PROD1 Short trip to 8,000'. Get a lot of cuttings back over shaker. Hole smooth. 12:45 - 15:00 2.25 DRILL P PROD1 Drill ahead. 2,800 psi fs @ 1.55 bpm. 200-300 dpsi. 1.5 in/1.3 out. 3,500-4,000# WOB. ROP:6-8 FPH. Drill to 10,814'.Getting some gas. Divert through gas buster. 15:00 - 20:00 5.00 DRILL P PROD1 Drill ahead to 10,827'. Holding 150 psi well head. 20:00 - 22:20 2.33 DRILL P PROD1 Open choke bottom hole annulus pressure 4,475 psi 9.67 EMW 1.66/1.7 bpm 8.75ppg in and 8.75 ppg out. Continue to drill 3,000 psi 550 psi dp 3,300# WOB. drill to 10,830'. 22:20 - 00:00 1.67 DRILL P PROD1 Begin mud swap 9.0 pph with 6% lub. Operation parameters with 8.7 ppg mud before mudx swap.1.67/1.65 bpm @ 3,105 psi 670psi. dp,WOB 3,277#. Operational parameters with 8.97 Printed: 1/27/2003 9:53:51 AM ) ') BP EXPLORATION Operations Summary Report . Page 13 of18 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From - To HöLlrs Task Code NPT Phase Description of Operations 1/13/2003 22:20 - 00:00 1.67 DRILL P PROD1 ppg mut to bit. 1.66/1.66 bpm 640 psi dp,WOB 3,024#. Operation parmaters after mud swap. 1.67/1.49 bpm @ 3,370 psi, 662 psi. dp WOB 3,550#. Drilled to 10,838'. 1/14/2003 00:00 - 06:00 6.00 DRILL P PROD1 Directionally drilling 1.66/1.55 bpm @ 3475 psi ,734 psi dp, Wob: 3800#, ROP: 4 ftlhr. Drilled to 10,841. Continued to drill to 10,862' with 1.65/1.63 bpm at 3300 psi, 595 psi dp, WOB 3100#, ROP 3-4. Good weight transfer. 06:00 - 09:30 3.50 DRILL P PROD1 Drilling ahead. 3100 psi @ 1.66 bpm. 150 dpsi. 1.66 in/1.61 out. WOB:2700#. ROP: 4-5 FPH. 09:30 - 11 :30 2.00 DRILL P PROD1 Drill ahead. Drilling at 95.8 inc. Begin to increase angle with high side TF. Drill to 10877'. 11 :30 - 12: 15 0.75 DRILL P PROD1 Short trip to liner shoe at 10358'. Hole smooth. 12:15 -13:15 1.00 DRILL P PROD1 Drill to 10,882'. 13:15 - 15:15 2.00 DRILL P PROD1 POOH 1.0 BPM for BOP test and to check bit. Densities in/out about 8.75 ppg. 15:15 -16:45 1.50 DRILL N DPRB PROD1 Flowcheck at 500' -- well flowing. SI. Pressure built to 150 psi in 30 minutes and stabilized here. Bleed to zero, about 4 bbls, thru buster (minimal gas). SI again. Pressure built to 160 psi in 15 minutes. Discuss with Anchorage. Will run to bottom of 3-3/16" and build system back to 9.0 ppg. 16:45 - 18:00 1.25 DRILL N DPRB PROD1 RIH w/o pumping, maintaining 150 psi WHP. RIH to 10,300'. Weight up to 9.0 ppg. 18:00 - 21 :30 3.50 DRILL N DPRB PROD1 Circulate well with 9.0 ppg mud. Lots of crude in the returns. 21 :30 - 21:40 0.17 DRILL N DPRB PROD1 Well flowing .5 bpm. Stilll gas cut. 21:40 - 00:00 2.33 DRILL N DPRB PROD1 Circulate well 2 bbl minute 3,150 psi 2.20/2.65 bpm. Down hole annulus pressure = 4,540' at 8,770 tvd 9.9 EMW. Shut in well. Well head pressure 178 psi down hole annular pressure 4,400 psi.@ 8,770 'tvd, 9.6 ppg EMW. Circulate bottoms up holding down hole annulus pressure ar 4,400 psi @.6 bpm. 1/15/2003 00:00 - 00:45 0.75 DRILL N DPRB PROD1 Continue to circulate bottoms up holding bottom hole pressure constant at 4,400 psi. 00:45 - 01 :00 0.25 DRILL N DPRB PROD1 Attempt to hold 180 with choke while slowing pump. Choke closed 100% while pumping with no immediate pressure. Shutin and monitor pressure builds to 140 psi in 15 min. 01 :00 - 02:30 1.50 DRILL N DPRB PROD1 POH with well shutin. Fill rate .45 bpm at 100 ftI min. Fill rate = metal replacement. 02:30 - 03: 15 0.75 DRILL N DPRB PROD1 PJSM for Pressure Un-deployment of BHA with 150 psi. surface pressure. 03:15 - 06:30 3.25 DRILL P PROD1 Pressure un-deploy BHA. 06:30 - 07:00 0.50 DRILL P PROD1 Safety meeting. 07:00 - 11 :30 4.50 DRILL P PROD1 Cut off connector. Shrink-wrap cable. Stab onto well. Pump back thru coil -- started at 2.0 BPM, but didn't hear cable movement until about 2.3 BPM. Pump for about 15 minutes at 2.5 BPM; 3800 psi pump pressure. PU injector. Cut 24' of coil to find E-line. Rehead (one hour). Pull inj back over BH to establish circ again (freeze-up concerns). BH able to take 2.0 BPM w/o overflowing -- pump cable forward at 2.0 BPM for 10 minutes. PT CTC to 3000 psi, then to 5000 psi for pressure bulkhead. Pull test CTC to 15k. 11 :30 - 12:00 0.50 BOPSU~ P PROD1 Safety meeting -- new procedure for testing BOPE. 12:00 - 17:30 5.50 BOPSU P PROD1 Perform weekly BOP test. Witness waived by AOGCC's Chuck Scheve. Printed: 1/27/2003 9:53:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: ) ) BP EXPLORATION Page 14 of 18 Operations Summary Report K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 1/15/2003 Date From - To Hours Task Code NPT 1/16/2003 1/17/2003 17:30 - 18:30 18:30 - 19:00 19:00 - 20:30 20:30 - 22:15 22: 15 - 22:30 22:30 - 23:00 23:00 - 00:00 00:00 - 02:30 02:30 - 04:00 04:00 - 05:00 05:00 - 05:30 05:30 - 09: 15 09:15 - 09:45 09:45 - 14:30 14:30 - 18:00 18:00 - 18:45 18:45 - 19:45 19:45 - 20:00 20:00 - 20:45 20:45 - 22:30 22:30 - 22:45 22:45 - 23:30 23:30 - 00:00 00:00 - 03:00 1.00 DRILL P PROD1 0.50 DRILL P 1.50 DRILL P 1.75 DRILL P 0.25 DRILL P 0.50 DRILL P 1.00 DRILL P PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 2.50 DRILL P PROD1 1.50 DRILL P PROD1 1.00 DRILL P PROD1 0.50 DRILL P 3.75 DRILL P PROD1 PROD1 0.50 DRILL P 4.75 DRILL P PROD1 PROD1 3.50 DRILL P PROD1 0.75 DRILL P PROD1 1.00 DRILL P 0.25 DRILL N 0.75 DRILL N 1.75 DRILL N 0.25 DRILL N 0.75 DRILL P 0.50 DRILL P PROD1 DFAL PROD1 DFAL PROD1 DFAL PROD1 PROD1 PROD1 PROD1 3.00 DRILL P PROD1 Prep for PU BHA. Check WHP -- 50 psi. Bleed and monitor pressure buildup. PJSM for pressure deployment. Bleed off pressure. No Flow. PU BHA. RIH with BHA 17 to 9760'. Tie-in correct -15' RIH tag bottom at 10878. Losses while running in hole 14 bbl. Directionally drill at 1.62/1.35 bpm @ 2,930 psi, FS 2,800 psi with 170 psi dp. 10.3 EMW Up wt 28K , ON wt 18K, WOB 900. Drilled to 10,895'. Directionally drilling 1.6/1.47 bpm @ 3,109 psi 2,800 psi FS, 390 psi dp. Down hole annular pressure 4600 psi @ 8882 TVDss, EMW = 9.95. WOB 1,000#. Drilled to 10,950' Dilling at 10,960' 1.61/1.50 bpm at 3,080 psi. 2,800 psi FS, 500 psi dp, Down hole annular pressure 4,623 psi at 8,875 tvdss. 10.0 EMW WOB 1,300#. ROP 30. Good smooth drilling. Drilled to 11,000'. Drilling at 11,000' 1.6/1.5 bpm @ 3230psi 2,800 psi FS. 850 psi dp. Down hole annular pressure 4600 psi @ 8865 tvdss 9.98 EMW. WOB 2250# ROP 35. Drill to 11029'. Wiper trip to shoe. Drill 1.6/1.5 about 30 FPH, 4600 psi annular P, 0 - 2000 Ib WOB. Some stacking. Drill to 11150' Wiper to 10300'. Drill 30 FPH to 11166', losses unchanged at about 8 BPH. Survey shows 23 deg DL 20' back, maybe deflection from dirty streak at 11135'. Hit hard spot here at 11166', lost all ROP at 2k WOB. Could not get any significant motor work. Try numerous things to make progress (varying pump rates, running into it, swapping hole to new mud for better weight transfer, changing TF's, patience, etc)-- didn't make an inch in 3 hours. On one of our PUH and "run at it" attempts, sat down at 11145'. POOH to check bit. Open circ sub inside shoe, maintain 2.0 BPM up to 60 deg and for a full BU after, then lower pump rate to minimum, monitoring returns. Stop at 4000' and check for flow -- minimal (0.1 BPM). Continue POOH. POH and change out bit. Bit in gauge with chipped teeth and broken cutter with about 20% wear. Bit rep was pleased with its condition but didn't recommending rerunning it as the wear rate would increase at a higher rate due to the extent of the existing wear. Bit ROP didn't indicate any decreased performance until it hit the hard spot. RIH to 500 POH MWD failure. Repair short in flow sub of upper quickconnect. RIH to 9760'. Tie-in correction -10'. RIH tag at 11,165'. Drilling at 1.57/1.41 bpm 3250 psi, 3150 psi FS, 500 psi dp, Down hole annular pressure 4633 psi at 8840 tvdss, 10.0 EMW. WOB 1400#. Drilled to 11,170'. Continue drilling to 11,175'.1.57/1.48 bpm at 3330 psi 600 psi Printed: 1/27/2003 9:53:51 AM ) ) BP EXPLORATION Qperati()n~Summét ryR~port Page 150f18 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Date From - To Hours· Task Code NPT . Phase Descri ption. of. Operations 1/17/2003 00:00 - 03:00 3.00 DRILL P PROD1 dp. WOB 1600-2200#. Weight transfer is poor limiting weight on bit and motor work. Drilled to 11,188'. Based on sample and gamma log projection believe we are out of shale and back in limestone Trip for bit to improve ROP. 03:00 - 05:00 2.00 DRILL P PROD1 POH 05:00 - 06:00 1.00 DRILL P PROD1 Change out bit. Bit showed wear similar to the previous diamond bit run on BHA 16 1-12-2003. Wear in matrix which backed up the Diamonds. Bit was ingauge. MU DPI MT3BB2. 06:00 - 07: 15 1.25 DRILL N DFAL PROD1 RIH to 200'. Short in lower quick connect. POOH. C/O sub. 07:15 - 10:00 2.75 DRILL P PROD1 RIH. Correct depth at RA (-14'). Tag TO 11,189' 10:00 - 16:30 6.50 DRILL P PROD1 Drill. Took off at 40 FPH. 3000 psi FS; 300 psi MW, 4600 psi AP, 1500 - 2500 Ib WOB. Losses have increased to 0.2 BPM. Increase in gas returns on bottoms-up (7000 - 10000 units). Drill at 40 FPH to 11,231', and hit hard spot here. Try working past for 4-1/2 hours -- no progress, even with as much as 3000 Ib WOB. Tried a bunch of stuff to get going, similar to yesterday, but can't get a bite. 16:30 - 19:30 3.00 DRILL P PROD1 Mix two drums EMI-712 in 100 bbls of mud. EMI-712 is a metal-to-metal friction reducer and anti-agglomerate. Will see if we can get significant increase in WOB with this product and hopefully a better bite. Pump pill. Started with about 3200 Ib WOB (-9k surface push) as EMI-712 exits bit. Not seeing any weight change with EMI moving up the backside, but we're getting a hint of progress. WOB 2,900 after pill displaced. No obvious benefit from EMI-712. 19:30 - 22:00 2.50 DRILL P PROD1 Directionally drilling at 11,245'. 1.66/1.58 bpm 3,250 psi. 460 psi dp. Down hole annular pressure 4,640 psi at 8,824 tvdss 10.1 EMW. WOB 3000# ROP 1-4. Drilled to 11,249' with 2,700 -3,300 # WOB, 3,250 psi.430 psi dp, Down hole annular pressure 4,629 psi. 8,824 tvdss 10.1 EMW. After corrolating with drilling parameters thru the same zone at 10-20 ftlhr in the build section with a BiCenter PDC feel we may have damaged bit on hard spot. 22:00 - 00:00 2.00 DRILL P PROD1 POH to surface. 1/18/2003 00:00 - 01 :30 1.50 DRILL P PROD1 Stand back injector. Straighten pipe. PU New bit,M-09 Surface check MWD. Change out MWD flow sub. Bleed off well 117 psi. MU BHA and stab injector. DPI MT3BB2 Bit had most significant wear seen yet on this well. Significant wear on shoulder cutters indicative of hard formation. Also, three of the four shoulder cutter PDC wafers were broken/chipped parallel to the face of the cutter. 01 :30 - 03:30 2.00 DRILL P PROD1 RIH to 9,760'. 03:30 - 03:45 0.25 DRILL P PROD1 Tie in -11' correction. 03:45 - 04:15 0.50 DRILL P PROD1 RIH. Tag at 11,245'. 04:15 - 06:30 2.25 DRILL P PROD1 Directionally drill 1.61/1.49 bpm 3,127 psi. FS 3,060 psi. 456 psi dp. WOB 1140#, Down hole annular pressure 4618 psi at 8824' 10.6 EMW. Gradually increasing WOB to 3000# 480 psi dp. Same drilling performance as previous bit. PU and run into bottom unable to stall. Drill to 11247' (tag depth w/o weight down). 06:30 - 09:30 3.00 DRILL P PROD1 POOH to PU diamond mill. 09:30 - 10:30 1.00 DRILL P PROD1 Slight trickle at surface. C/O BHA w/o pressure deployment. M-09 had essentially no wear -- just very slight flattening at Printed: 1/27/2003 9:53:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: ) ) BP EXPLORATION Opérati.ons Summary Report Page 16 of18 K-17A K-17 A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Description of Operations 1/18/2003 09:30 - 10:30 From ~ To Hours Task Gode NPT Phase 1.00 DRILL P PROD1 edge of a couple of cutters, no chips, gage slots contained claystone. PU used S248 ballaset diamond mill. C/O motor (although do not suspect motor trouble). Well flowed about 4 bbls while changing BHA. PROD1 RIH with BHA #22. Tie-in at RA. Correct depth (-15'). RIH. Tag TO 11246'. PROD1 Drill 1.6/1.4 (losses about 10 BPH), 2000 WOB. BU gave us up to 8000 units of gas and a skim of oil. Drill l' to 11247' in 3.5 hours -- same story, minimal motor work. Either polishing a hard spot or spinning on clay. POOH to put on bicenter bit. Change out for bicentered bit. Diamond mill in gauge with slight wear. RIH to 9,760'. Tie-in - 12' correction. RIH mad pass 11,195 TO 11,225'. Tag bottom at 11,247'. Drill to 11,254'. 1.61/1.48 BPM AT 3200 PSI. WOB 2800# 490 psi pd. Down hole annulus pressure 4,602 psi at 8,824' TVDSS. Made all footage when first on bottom with 600 psi motor work. Then stopped drilling. PR001 Drill at 1.58/1.51 bpm at 3100 psi DP 400 psi. Drill to 11,254 no progress. Pumped 30 bbl pill with two sacks of G-seal and one drum EMI 712. (4-5 #/bbl EMI) pumped 10 bbl out bit. POH 100' laying in pill. Run to bottom drilling. WOB gradually increased from 2200# to 4600# and pd increased 150 psi dp to 550 psi. But still not drilling. PR001 POH to liner 3-3/16 liner shoe (10,357') PROD1 Shut in well and monitor down hole annulus pressure build up. Initially well flowing at .6 bpm. Shut in Surface well head pressure built to 260psi. Bottom hole annular pressure decreased from 4417 to 4393 in 40 minutes. See data table in remarks section of 1-18-2003 report. PR001 POH PROD1 LD BHA. Well trickled 9 bbls during BHA C/O. Bit (Hyc DS100 rebuild) had slight flattening of lead cutters on pilot and a little more flattening on all lead cutters on bicenter blades. C/O motor and put on another bicenter bit (Hyc DSX100 new). PR001 RIH. Correct depth at RA (-9'). RIH. Slight MW at 11190'. RIH. Tag TO 11255', started into a stall (900 psi MW), then drill off and stack with minimal motor work. NOTE: RIH weight = 16k. PR001 Drill 1.6/1.5 with 100 psi MW, 2500 Ib WOB (2k - 5k surface weight). Drill 15 FPH. Occasional spikes in motor work (particularly in 11300' and 11320' vicinity). ROP gradually increased to 25 FPH starting about 11315'. Gas to surface while drilling at 11350'. Drill to 11355' (100' drilled -- avg 15 FPH). PROD1 Continue drilling, slowly losing DWOB and ROP. Drill to 11360'. PROD1 Drilling break. Drill 1.62/1.53 bpm, 3300 psi. 450 psi dp.Down hole annular pressure WOB 800 - 1300#. Drill to 11,400'. PROD1 Drilling at 1.62/1.55 bpm at 3200 psi 500 psi dp. Down hole annular prressure 4630 psi WOB 1360 # ROP 16-24.Drilled to 11434'. 10:30 - 13:00 13:00 - 17:00 2.50 DRILL P 4.00 DRILL P 17:00 - 19:00 2.00 DRILL P PROD1 19:00 - 19:30 0.50 DRILL P PROO1 19:30 - 21 :00 1.50 DRILL P PROD1 21:00-21:15 0.25 DRILL P PROD1 21:15-21:45 0.50 DRILL P PROD1 21 :45 - 00:00 2.25 DRILL P PROD1 1/19/2003 00:00 - 04:00 04:00 - 04:30 04:30 - 05:15 05:15 - 07:00 07:00 - 08:00 08:00 -10:15 10:15 - 17:00 17:00 - 18:00 18:00 - 20:00 20:00 - 22:00 4.00 DRILL P 0.50 DRILL P 0.75 DRILL P 1.75 DRILL P 1.00 DRILL P 2.25 DRILL P 6.75 DRILL P 1.00 DRILL P 2.00 DRILL P 2.00 DRILL P Printed: 1/27/2003 9:53:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1/19/2003 1/20/2003 1/21/2003 ) ') BPEXPLORATION Operations.$u mmaryRepott K-17 A K-17A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 22:00 - 22:30 From- To Hours Task Code NPT Phase PROD1 22:30 - 23:15 23:15 - 00:00 00:00 - 01: 15 01 :15 - 02:00 02:00 - 03:45 03:45 - 04:00 04:00 - 04:45 04:45 - 11 :00 11 :00 - 11: 1 0 11:10-13:15 13:15 - 14:30 14:30 - 18:30 18:30 - 21 :30 21 :30 - 22:15 22: 15 - 00:00 00:00 - 03:40 03:40 - 06:45 06:45 - 09:00 09:00 - 11 :30 11 :30 - 12:30 12:30 - 15:30 15:30 - 00:00 0.50 DRILL P 0.75 DRILL P PROD1 0.75 DRILL N 1.25 DRILL N 0.75 DRILL N DFAL PROD1 DFAL PROD1 DFAL PROD1 1.75 DRILL N 0.25 DRILL N 0.75 DRILL P 6.25 DRILL P DFAL PROD1 DFAL PROD1 PROD1 PROD1 0.17 DRILL P 2.08 DRILL P 1.25 DRILL P 4.00 DRILL P PROD1 PROD1 PROD1 PROD1 3.00 DRILL P PROD1 0.75 DRILL P 1.75 DRILL P PROD1 PROD1 3.67 DRILL P PROD1 3.08 DRILL P PROD1 2.25 DRILL P PROD1 2.50 DRILL P PROD1 1.00 DRILL P PROD1 3.00 DRILL P PROD1 8.50 DRILL P PROD1 Page 17 oft8 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 DescriptiOlt of Operations· Drilling at 1.65/1.58 bpm at 3240 psi 517 psi dp. Down hole annulus pressure 4630 psi WOB 1300#. Drill to 11440'. Wiper to 3-3/16 shoe. Up wt 27K. 17K On. Hole clean. Start running in hole when MWD failed. Shorted out. POH MWD failure. POH to surface. Flow check. NO FLOW. Change out MWD lower quick connect, ball valve sub and bit. Bit had both back ream cutters broken as well as one nose cutter broked. The balance of the T-Rex cutters look excellect. Bit was drilling good when pulled for the MWD failure. RIH to 9750'. Tie - in (-11 ' correction) RI H tag bottom at 11436'. RI H wt at TO = 15k. Drill with 1.6/1.5 bpm. FS 3050 psi, 300 - 400 psi MW. WOB 1500#, surface weight 5000 - 9000#. Drill to 11540'. Lost some ROP the last couple of feet; stacking. 200' wiper. Drill to 11575'. Stacking. Wiper to 3-3/16" shoe. Hole in good shape. Drill 1.6/1.5 about 10 FPH to 11630', then big drilling break -- ROP bounced between 30 FPH and 75 FPH over about 10ft (keeping same weight on bit). No change in our in/out rates. Drilling at 10645' and back to 15 FPH. Continue drilling to 11,672' Noteing a fall off on drilling rate gradually from 15 to 7 ft/hr. Corrolates with lithology drilled at 11,168' . Wiper to shoe. Hole in good shape. Smooth trip. Drill 1.52 - 1.52 at 3250 psi. FS 3,100 psi 520 psi dp. WOB 2,160 # ROP 7-12 Seem increase in weight on bit 1000+#. DRILL TO 11,682' Drill at 11,682. 1.58/1.52 bpm, with 3200 psi, 3,100 psi FS, 495 psi dp with 2,000# WOB, ROP 7. Per Geologist we are drilling same lithology as 11,150'-11,180' where we drilled with a diamond bit with similar ROP. Expect to see drilling break similar to 11,170. Estimated at 11,715 +-. Drill to 11,708. Fluid loss rate decreasing gradually to 6 bph. Continue to drill 1.58/1.55 bpm at 3200 psi. 500 psi dp. Down hole pressure 4,657 psi at 8,784 tvdss. ROP about 5 FPH. Drill to 11725'. ROP at 5 - 10 FPH at 11725'. Continue drilling 1500# WOB to 11745'. POOH for bit change. Circ at 2.5 BPM in liner up to 8600', continue at this rate for BU at this depth, then POOH at minimum rate. SB inj. LD BHA. No wear on bit. Maybe very slight flattening on a couple of pilot shoulder cutters, but would need magnifying glass to confirm. PU new bicenter bit anyway. Also, revised target -- increase motor bend to 1.5 deg. The well flowed continuously during BHA change-out (total of 4 bbls). RIH. Correct depth at RA (-10'). RIH. Hole clean. Tag TO 11746'. RIH wt at TO = 15k. Drill 1.6/1.5 (6 BPH loss) with ROP averaging 10-15'/hr 2975 Printed: 1/27/2003 9:53:51 AM ") ) BP EXPLORATION OperationsSumrnary Report PROD1 psi free-spin, 3180 psi on btm. 10.19 EMW. WOB --1200#- 2000#. Circ out trip gas. Drill from 11746' to 11875'. Several drilling breaks in the 30'/hr range no increase in losses. PR001 Continue directionally drilling ahead fl 11875'. 1.5k WOB, 1.60 bpm in 1 1.56 out to 11917'. ROP slowed to <7'/hr. PROD1 Wiper trip to shoe. RIH sat down with MW at 10,880'. PU. RIH, MW same spot and fell through. PROD1 Directionally drill ahead 5 - 10 FPH to 11935'. Call this TO per Anchorage team. PROD1 Wiper trip to shoe, open circ sub, wiper to 8600' at 2.0 BPM. RIH at 2.0 BPM to 9742'. Log tie-in. Correct depth (+3'). Close EDC. RIH to TO, displacing well to 9.6 ppg mud (wt-up existing system). No set downs. Tag corrected TO 11935'. POOH to shoe. Open circ sub. Finish weighting up mud 9.6 ppg. In and out about 9.5 ppg heavy. Max ECD noted = 10.3 ppg. PUH to 8656' (8348' SSTVD). SO pumps. Flow stopped after 30 minutes. BHP at this depth = 4250 psi and falling slowly. POOH. LD drilling BHA. Bit 1-1. Well static -- no flow or suck. Safety meeting. MU 2-3/8" 4.43# L-80 FL4S/STL pre-drilled 4 SPF liner (1656.64'). M/U Baker CTLRT. Confirm BHA length to confirm ability to shut Master Valve after displacing well to diesel. Stab on injector. Open BHI Circ Sub. COMP TIH at min pump with 2 3/8" liner to flag at 8600'. Correct -12'. RIH spend 15 min working liner to bottom from 11920' to 11935' TO. Check up weight at 34k. Close circ sub. Increase pump rate to 1.7 and 3200 psi. P/U lost 9k weight confirmed liner disconnect. COMP PJSM review swapping well to lighter fluids KCLldiesel. COMP With EOP at 10252' (8725' tvd) swapping well to 8.4pgg KCL increasing annulus pressure to 550 psi. PUH to 5000' tvd and switch to diesel. Lay-in diesel to surface increasing annulus pressure 50 psi/10 bbls layed in. Shutdown pumping at 600' md. 830 psi final WHP. Close Master Valve 23.5 turns. Bleed off BOP stack, master holding. Circulate across stack and clear coil and stack of all diesel PJSM review plan forward to LID BHA, blow back coil with air and secure. Stab injector off well. LO liner running BHA. RU to unstab coil. Crew change safety meeting. Unstab coil. Safety meeting. LD P-deployment lubricator. Clean pits. NO BOPE. NU and test tree cap to 3000 psi. Release rig 13:00 hrs 1/23/2003. Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: K-17A K-17 A REENTER+COMPLETE NORDIC CALISTA NORDIC 2 Date From- Tö Hours Task Code NPT Phase 1 121 /2003 15:30 - 00:00 8.50 DRILL P 1/22/2003 00:00 - 04:10 4.17 DRILL P 04:10 - 05:30 1.33 DRILL P 05:30 - 08:30 3.00 DRILL P 08:30 -11:15 2.75 DRILL P 11:15-12:00 0.75 DRILL P PROD1 12:00 - 13:00 1.00 DRILL P PROD1 13:00 - 13:30 0.50 DRILL P PROO1 13:30 - 15:15 1.75 DRILL P PROD1 15:15 - 16:00 0.75 DRILL P PROD1 16:00 - 16:30 0.50 CASE P COMP 16:30 - 21 :35 5.08 CASE P COMP 21 :35 - 00:00 2.42 CASE P 1/23/2003 0.17 CASE P 3.92 CASE P 00:00 - 00: 1 0 00:10 - 04:05 04:05 - 04:25 0.33 CASE P COMP 04:25 - 04:35 0.17 CASE P COMP 04:35 - 05:30 0.92 CASE P COMP 05:30 - 06:30 1.00 RIGD P COMP 06:30 - 07:00 0.50 RIGD P COMP 07:00 - 07:45 0.75 RIGD P COMP 07:45 - 08:00 0.25 RIGD P COMP 08:00 - 13:00 5.00 RIGD P COMP Page ·18 of 18 Start: 12/25/2002 Rig Release: 1/23/2003 Rig Number: N2 Spud Date: 12/30/1994 End: 1/23/2003 Description öf Operations Printed: 1/27/2003 9:53:51 AM ') ) BP Baker Hughes INTEQ Survey Report IN'IEQ Company: Field: Site: Well: Wellpath: BP Amoco Prudhoe Bay PB K Pad K-17 K-317B Date: 2/19/2003 Time: 08:32:50 Page: Co-ordinate(NE) Reference: Well' K-17. True North Vertical (TVD) Reference: 34 : 175/27/1998 15:0059.8 Section (VS) Reference: Well (O.OON .0.00E,159.00Azi) Survey Calculation Method: Minimum Curvature Db: Oracle Field: Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Coordinate System: Geomagnetic Model: Alaska, Zone 4 Well Centre BGGM2002 Site: PB K Pad TR-11-14 UNITED STATES: North Slope Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 ft Ground Level: 0.00 ft 5973161.33 ft 670342.10 ft Latitude: 70 19 Longitude: 148 37 North Reference: Grid Convergence: 57.435 N 5.245 W True 1.30 deg Well: K-17 Slot Name: 17 K-17 Well Position: +N/-S 2033.35 ft Northing: 5975220.71 ft Latitude: 70 20 17.432 N +E/-W 1175.34 ft Easting : 671470.88 ft Longitude: 148 36 30.917 W Position Uncertainty: 0.00 ft Wellpath: K-317B 500292253702 Current Datum: 34: 175/27/199815:00 Magnetic Data: 1/14/2003 Field Strength: 57545 nT Vertical Section: Depth From (TVD) ft 0.00 +N/-S ft 0.00 Drilled From: Tic-on Depth: Above System Datum: Declination: Mag Dip Angle: +E/-W ft 0.00 K-17APB1 9730.00 ft Mean Sea Level 26.04 deg 80.85 deg Direction deg 159.00 Height 59.80 ft Survey Program for Definitive Wellpath Date: 2/19/2003 Validated: Yes Actual From To Survey ft ft 165.65 8315.55 8361.21 8477.15 8514.00 9730.00 9730.00 11935.00 Version: 6 Toolcode Tool Name 1 : MWD - Standard (0) 1 : MWD - Standard (1) 4 : MWD - Standard (3) MWD MWD MWD MWD MWD MWD - Standard MWD - Standard MWD - Standard MWD - Standard Annotation MD TVD ft 9730.00 8588.48 KOP 11935.00 8829.80 TO Survey: MWD Start Date: 1/22/2003 Company: Baker Hughes INTEQ Tool: MWD,MWD - Standard Engineer: Tied-to: From: Definitive Path ) ') ii. BP BA IS Baker Hughes INTEQ Survey Report ...".....".............,....".....",... INl'EQ Company: BPArnoco Date:<2119/2003 Time: ·08:32:50 Page: Field: Prudhqé Bay qH.u;dinat¢(NE)R.¢(erence: Well: K-17. True Nprth Site: PB K Pad Vertical (TVD) Reference: 34 : 17 5/27/1998 15:0059.8 Well: K-17 Section (VS) Reference: Well (0.00N,O.00E,159.00Azi) WelJpath: K-317B Survey Calculation Method: Minimum Curvature Db: Oracle Survey 9730.00 90.30 93.51 8588.48 8528.68 .. 28.18 2147.73 5975297.99 673617.26 743.37 0.00 9749.50 90.93 93.51 8588.27 8528.47, 26.98 2167.19 5975297.24 673636.75 751.46 3.22 9784.50 89.97 96.09 8588.00 8528.20 24.06 2202.07 5975295.11 673671.67 766.69 7.86 9818.86 85.44 98.63 8589.37 8529.57 19.66 2236.11 5975291.50 673705.80 782.99 15.11 9877.64 77.82 103.07 8597.93 8538.13 8.75 2293.17 5975281.89 673763.09 813.63 14.96 9914.00 72.90 106.27 8607.11 8547.31 -0.15 2327.19 5975273.78 673797.31 834.13 15.99 9949.98 70.90 110.84 8618.30 8558.50 -11.02 2359.60 5975263.65 673829.96 855.89 13.29 9977.96 68.38 115.07 8628.04 8568.24 -21.24 2383.75 5975253.99 673854.33 874.09 16.79 10009.99 66.10 119.29 8640.43 8580.63 -34.72 2410.02 5975241.11 673880.90 896.08 14.08 10042.50 64.52 122.83 8654.01 8594.21 -49.95 2435.32 5975226.46 673906.54 919.37 11.02 10076.00 60.22 127.54 8669.55 8609.75 -67.02 2459.57 5975209.95 673931.18 944.00 17.88 10115.50 55.19 129.26 8690.65 8630.85 -87.74 2485.74 5975189.84 673957.81 972.72 13.25 10148.00 51.38 126.42 8710.08 8650.28 -103.73 2506.30 5975174.32 673978.72 995.02 13.65 10181.00 46.52 122.52 8731.75 8671.95 -117.83 2526.78 5975160.69 673999.53 1015.52 17.21 10210.50 40.96 122.43 8753.05 8693.25 -128.78 2543.98 5975150.14 674016.97 1031.91 18.85 10239.50 39.04 127.78 8775.28 8715.48 -139.48 2559.23 5975139.80 674032.46 1047.36 13.58 10270.50 37.77 135.41 8799.58 8739.78 -152.23 2573.62 5975127.38 674047.13 1064.42 15.82 10301.50 37.99 139.72 8824.05 8764.25 -166.27 2586.45 5975113.64 674060.29 1082.13 8.56 10325.59 39.05 142.99 8842.90 8783.10 -177.99 2595.82 5975102.14 674069.91 1096.42 9.53 10353.00 39.45 143.79 8864.13 8804.33 -191.91 2606.16 5975088.46 674080.57 1113.12 2.35 10403.00 44.33 143.72 8901.34 8841.54 -218.82 2625.89 5975062.00 674100.91 1145.32 9.76 10444.00 53.35 136.01 8928.32 8868.52 -242.27 2645.85 5975039.02 674121.40 1174.37 26.13 10470.11 63.90 131.39 8941.90 8882.10 -257.61 2661.97 5975024.06 674137.87 1194.46 43.12 10500.29 73.42 138.23 8952.88 8893.08 -277.42 2681.84 5975004.70 674158.18 1220.08 37.94 10533.51 83.60 139.58 8959.49 8899.69 -301.93 2703.20 5974980.70 674180.10 1250.61 30.90 10560.69 85.14 150.23 8962.16 8902.36 -324.03 2718.73 5974958.96 674196.12 1276.81 39.40 10590.10 89.54 158.70 8963.53 8903.73 -350.51 2731.37 5974932.78 674209.37 1306.06 32.42 10620.27 93.04 169.35 8962.85 8903.05 -379.46 2739.66 5974904.02 674218.32 1336.06 37.14 10661.09 93.08 177.88 8960.67 8900.87 -419.93 2744.19 5974863.67 674223.77 1375.47 20.87 10690.40 93.26 180.21 8959.05 8899.25 -449.19 2744.68 5974834.43 674224.93 1402.96 7.96 10723.35 94.67 183.74 8956.77 8896.97 -482.03 2743.55 5974801.57 674224.55 1433.22 11.51 10749.69 94.13 188.58 8954.75 8894.95 -508.14 2740.73 5974775.41 674222.33 1456.58 18.44 10781.56 92.68 182.75 8952.85 8893.05 -539.78 2737.59 5974743.71 674219.92 1484.99 18.82 10810.15 93.17 177.72 8951.39 8891.59 -568.32 2737.48 5974715.17 674220.45 1511.60 17.65 10845.56 95.53 170.98 8948.70 8888.90 -603.44 2740.95 5974680.15 674224.72 1545.62 20.11 10893.23 97.23 185.63 8943.38 8883.58 -650.66 2742.35 5974632.97 674227.21 1590.21 30.75 1 0921 . 1 3 99.16 189.18 8939.40 8879.60 -678.04 2738.80 5974605.52 674224.28 1614.50 14.37 10950.01 99.50 190.32 8934.72 8874.92 -706.12 2733.97 5974577.34 674220.10 1638.99 4.07 10980.20 98.89 185.79 8929.89 8870.09 -735.62 2729.80 5974547.75 674216.60 1665.03 14.95 11010.50 100.02 184.79 8924.91 8865.11 -765.38 2727.04 5974517.94 674214.53 1691.83 4.95 11056.27 99.52 179.61 8917.14 8857.34 -810.44 2725.31 5974472.86 674213.83 1733.27 11.21 11101.56 99.18 172.83 8909.77 8849.97 -855.00 2728.26 5974428.37 674217.79 1775.93 14.79 11134.03 99.08 165.17 8904.61 8844.81 -886.45 2734.37 5974397.08 674224.62 1807.48 23.29 11176.74 100.85 163.06 8897.22 8837.42 -926.90 2745.88 5974356.90 674237.05 1849.37 6.39 11205. 17 101.16 167.40 8891.79 8831.99 -953.88 2752.99 5974330.09 674244.78 1877.11 15.02 11237.15 101.49 161.33 8885.51 8825.71 -984.06 2761.44 5974300.11 674253.91 1908.31 18.64 11266.95 99.53 164.84 8880.07 8820.27 -1012.09 2769.96 5974272.29 674263.07 1937.53 13.32 11304.93 96.70 164.90 8874.71 8814.91 -1048.38 2779.77 5974236.23 674273.71 1974.93 7.45 11340.60 94.92 172.68 8871.09 8811.29 -1083.16 2786.66 5974201.62 674281.40 2009.87 22.26 11371.74 94.36 175.02 8868.57 8808.77 -1114.02 2789.99 5974170.85 674285.42 2039.87 7.70 11401.78 92.18 176.66 8866.86 8807.06 -1143.93 2792.16 5974141.00 674288.28 2068.57 9.08 11432.33 91.35 181 .86 8865.92 8806.12 -1174.45 2792.56 5974110.50 674289.37 2097.21 17.23 11466.90 90.64 181.81 8865.32 8805.52 -1209.00 2791.45 5974075.94 674289.06 2129.06 2.06 ) ) BP Baker Hughes INTEQ Survey Report .,.....,....'.."."........................"....,,,, lNiIEQ çompallY: B P Amoco Date:·· ·2/19/2003 TÎlne: 08:32:50 Page: Fièld: Prudhoe Bay Co-ordinate(NE} Reference: Well: K-17, True North Sit¢: PB K Pad Vertical (TVD) Reference: 34 : 17 5/27/1998 15:00 59.8 Wèll: K-17 Section (VS) Reference: Well (0.00N,O.00E,159.00Azi) W¢lIpath: K-317B Survey Calculation Method: Minimum Curvature Db: Oracle Survey 11499.04 91.81 184.14 8864.63 8804.83 -1241.09 2789.78 5974043.82 674288.12 2158.42 8.11 11530.77 94.61 186.64 8862.85 8803.05 -1272.62 2786.81 5974012.23 674285.87 2186.80 11.82 11560.57 94.91 191 .00 8860.38 8800.58 -1301.96 2782.26 5973982.80 674281.99 2212.55 14.62 11591.12 96.73 193.73 8857.28 8797.48 -1331.64 2775.75 5973952.97 674276.17 2237.94 10.70 11621.19 97.49 197.46 8853.56 8793.76 -1360.38 2767.73 5973924.07 674268.81 2261.89 12.57 11652.03 96.78 200.54 8849.73 8789.93 -1389.31 2757.77 5973894.92 674259.51 2285.33 10.17 11681.76 95.77 197.29 8846.48 8786.68 -1417.26 2748.19 5973866.76 674250.57 2307.99 11.38 11714.46 96.42 195.21 8843.01 8783.21 -1448.47 2739.09 5973835.34 674242.19 2333.87 6.63 11751.83 97.48 190.84 8838.48 8778.68 -1484.61 2730.73 5973799.03 674234.66 2364.61 11.95 11780.54 93.72 190.71 8835.68 8775.88 -1512.67 2725.39 5973770.86 674229.97 2388.89 13.10 11811.54 91.78 193.47 8834.19 8774.39 -1542.94 2718.91 5973740.44 674224.17 2414.83 10.87 11842.51 92.79 187.88 8832.96 8773.16 -1573.34 2713.18 5973709.93 674219.14 2441 .15 18.33 11872.09 94.24 184.70 8831.14 8771.34 -1602.68 2709.94 5973680.52 674216.58 2467.39 11.80 11901.32 90.31 178.18 8829.98 8770.18 -1631.86 2709.21 5973651.34 674216.51 2494.36 26.03 11935.00 90.31 178.18 8829.80 8770.00 -1665.52 2710.28 5973617.71 674218.35 2526.17 0.00 Parent Wellpath: Tie on MD: Rig: Ref. Datum: BP Amoco ra.. ..,.. ~~~-~----- INTEQ LEGEND K-17,K-317B,Plan # 26 K-17 (K-17) K-17 (K-17A) K-17 (K-17APB1) K-17 (K-17APB2) --~~- K-17 (K-17PB1) K-17 (K-17PB2) K-317B T ^M ,\ é Direct: {GO?} 2d7-6513 E·;,n~ì¡: t:-jl_pc);¡·;is~~h:ieq.c-coì 8aker Hughes iNTEQ- {9071 257-f~t¡'D0 Wellpath: (K-17/K-317B) Azimuths to True North Magnetic North: 26.04· Stre~~t~~;~~~~~ Dip Angle: 80.85· Date: 1/14/2003 Model: BGGM2002 Created By: Brij Potnis Date: 2/19/2003 WEllPATH DETAILS K-317B 500292253702 K-17APB1 9730.00 bp C~.-;rÚ¡ç~ ;nfof:-n3tion Nordic 2 34 : 17 5/27/1998 15:00 59.80ft 1000·H. Starting From TVD V.Section Origin Origin Angle +N/-S +E/-W 159.00· 0.00 0.00 800~~ 0.00 600-' REFERENCE INFORMATION Co-ordinate (N/Ej Reference: Well Centre: K-17, True North Vertical (TVD Reference: System: Mean Sea Level Section (VS Reference: Slot - 17 (O.ooN,O.OOE) Measured Depth Reference: 34: 175/27/199815:00 59.80 Calculation Method: Minimum Curvature ANNOTATIONS TVD MD Annotation 8528.68 9730.00 KOP 8770.00 11935.00 TO 8250 8300 8350 8400 ë'8450 ~8500 ;: ~550 .. Be600 Q _ 8650 '~8700 V:·17(K.17A)1 1:: fD >8750 fD 28800·; ... 8850 8900 8950 9000 ~j:~~ frilr124 , 1<-3178112'53 K·]IlBT12'52 +EJ-W Shape ~~ :j~ ~~i~ ~ 2000 West(-)/East(+) [200ft/in] 1750 Vertical Section at 159.00° [50ft/in] 750 800 850 900 2/19/2003 8:31 AM '-.- .--- Schlumbel'gel' Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Beth Well Job# Log Description Date K-317B fq0/-Ic;/P 23013 MCNL 01/02/03 L5-09 J f)-I rl, t.J 23001 RST-SIGMA 11/03/02 L-02 ~nl-~OJ 23003 OH EDIT PEX,AIT & BHC (PDC) 12/08/02 L-02 23003 PEX-RESISTIVITY 12/08/02 L-02 23003 PEX-NEUTRON/DEN 12/08/02 L-02 23003 PEX-BHC 12/08/02 L-02 V 23003 PEX-CALIPER 12/08/02 D.S. 1-19A d~-æd. 22510 MCNL (PDC) 11/06/02 J-21A d Orl-~O 23014 MCNL 11/15/02 L3-02 J'ð/n-J f) 23006 RST -SIGMA 11/10/02 K-317B ::lY-J ~(" 23045 OH EDIT LWD GR & ROP5 12/30/02 K-317B 23045 MD SLIMPULSE GR 12/30/02 K-311B 23045 TVD SLlMPULSE GR 12/30/02 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson Blvd. EIVED Anchorage, Alaska 99508 REC· Date Delivered: fFB 07 2003 AJask! œ & Gas Cons. Commission Anchoœge Blueline 01/30103 NO. 2835 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay Lisburne Sepia Color Prints '--" CD 1 1 1 1 1 1 1 1 1 1 1 1 1 1 ---- Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Beth Reœive~~ K-I 7 A prep for K-3 I 7b } Subject: K-17A prep for K-317b 'GA.?! - l'S;fÞ Date: Thu, 19 Dee 2002 14:26:29 -0600 From: "Stagg, Ted 0 (ORBIS)" <StaggTO@BP.eom> To: "Winton Aubert (E-mail)..<Winton_Aubert@admin.state.ak.us> CC: "Warner, Dwight" <WarnerDW@BP.eom>, "Johnson, Mark 0" <JohnsoMO@BP.eom> Winton, Prudhoe K-17a is being preped for a coil sidetrack into the Lisburne reservoir. Sundry 301-217 was issued on 8/07/01 for this work. However, after setting a CIBP above all perfs we found a high rate leak. A second bridge plug was set but the high rate leak still exists. A Leak Detection Log is currently in progress. Until this logging is done we are speculating on the cause but I strongly suspect a leak in the K-17a 4 1/2" liner lap. If this turns out to be fact, we will want to do a liner lap cement squeeze to seal this lap before going forward with the K-317b sidetrack. I will report the Leak Detection Log results and advise you of the plan forward. Ted K-317b Permit to Drill ) Subject: K-317b Permit to Drill Date: Tue, 17 Dee 2002 19:05 :46 -0600 From: "Stagg, Ted 0 (ORBIS)" <StaggTO@BP.eom> To: "Winton Aubert (E-mail)..<Winton_Aubert@admin.state.ak.us> Winton, The spud date for this Lisburne sidetrack has again moved up, it appears. Nordic 2 is currently on M-09a and it looks like they could finish in 5 days. If that happens then Nordic 2 could be moving onto K-317b by Dec. 22. Ted K-317b Permit to Drill ) ) Subject: K-317b Permit to Drill Date: Fri, 13 Dee 2002 15:25:54 -0600 From: "Stagg, Ted 0 (ORBIS)" <StaggTO@BP.eom> To: "Winton Aubert (E-mail)..<Winton_Aubert@admin.state.ak.us> Winton I It looks like the Lisburne sidetrack, K-317b, is going to be approved by all concerned. We would like to spud the sidetrack about Dec. 25, 2002 rather than the January 6 date in the pending application. The current application was submitted because of a change in BHL. The original Permit to Drill was approved on Aug. 8, 2001. Ted ALASKA (J AND ~:~~g~S~~~:;;ON COMMI, )ON PERMIT TO DRILL 20 AAC 25.005 1 b. Type of well 0 Exploratory 0 Stratigraphic Test II Development Oil o Service 0 Development Gas 0 Single Zone 0 Multiple Zone 5. Datum Elevation (DF or KB) 10. Field and Pool KBE = 59.8' Prudhoe Bay Field I Lisburne 6. Property Designation Pool / ADL 028303 7. Unit or Property Name Prudhoe Bay Unit 8. Well Number K-317B 9. Approximate spud date . r 'LIZ- ~ I ð t.g;1J(tY103 ~(,k Amount $200,000.00 /' 14. Number of acres in property 15. Proposed depth (MD and TVD) 2560 11920' M D I 8764 TVDss o 17. Anticipated pressure {S9'20 AAC 25.035 (e) (2)} 100 Maximum surface 2585 psig, At total depth (TVD) 8900' I 3475 psig Setting Depth Top Bottom LenQth MD TVD MD TVD 900' 9500' 8520' 10400' 8800' 1570' 10350' 8766' 11920' 87641 1 a. Type of work 0 Drill II Redrill ORe-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3280' NSL, 4078' WEL, SEC. 04, T11 N, R14E, UM At top of productive interval 3271' NSL, 858' WEL, SEC. 04, T11 N, R14E, UM At total depth 1662' NSL, 1315' WEL, SEC. 04, T11N, R14E, UM 12. Distance to nearest property line 13. Distance to nearest well ADL 028300,3617' MD No Close Approach 16. To be completed for deviated wells Kick Off Depth 9730' MD Maximum Hole Angle 18. Casin9 Program Specifications Size CasinQ WeiQht Grade CouplinQ 3-1/2" 8.2# L-80 ST-L 2-3/8" 4.7# L-80 ST-L Hole 4-1/8" 3" ilJ. (íA- ill rs( ð' 't Revised: 11/18/02 11. Type Bond (See 20 AAC 25.025) Number 2S100302630-277 Quantitv of Cement (include staae data) 29 sx Class 'G' ' Uneemented Slotted Liner 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured 13982 feet Plugs (measured) IBP set at 130501 (11/98) true vertical 8736 feet Effective depth: measured 13050 feet Junk (measured) true vertical 8770 feet Casing Length Size Cemented 12516' - 125761, 12650' - 12900', Open, Below Bridge Plug: 13310' - 13560', 13700' - 13890' true vertical 8754' - 8766', 8770' - 8766' AI ka Oil & Gas Gons. Commission Open, Below Bridge Plug: 8759' - 8724', 8721' - 8734' as AnchQraQe II Filing Fee 0 Property Plat II BOP Sketch 0 Diverter Sketch II Drilling Program II Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 0 20 AAC 25.050 Requirements Contact Engineer NamelNumber: Ted Stagg, 564-4694 Prepared By Name/Number: Terrie Hubble, 564-4628 21. Is~:~:Y ~~i;m::attheH~e and correct tO~E~g~:i~~~~ Date I)~ ~ pOl'mit "Ii'mber API Number Approval Date See cover letter ~ ...::! ð / - / .s- tG 50- 029-22537-02 08/08/01 for other reQuirements Conditions of Approval: Samples Required 0 Yes L! No Mud Log Required 0 Yes 18 No Hydrogen Sulfide Measures BYes 0 No Directional Survey Required IS Yes 0 No Required Working Pressure for BQPE 0 2K 0 3K 0 4K 0 5K 0 10K 0 15K 0 3.5K psi for CTU Other: Të-~;;ot-- ISo rl:: to £.1000 p~ J 4 ORIGINAL SIGNED BY M ~ . ~iII Structural Conductor Surface Intermediate Production Liner 80' 20" 3672' 10-3/4" 8482' 7-5/8" 5645' 4-1/2" Perforation depth: measured 20. Attachments Approved By Form 10-401 Rev. 12-01-85 260 sx Aretieset (Approx.) 1050 sx PF 'E', 375 sx Class 'G' 472 sx Class 'G' MD TVD 110' 110' 3707' 37031 8514' 8302' 235 sx Class 'G' 8337' - 13982' 8155' - 8736' RECEIVED NOV 1 92002 ~m"'is~i~r: t ¡: t·" Ii: i: \"....i \ \; 1;,,_, ~ by order of ,~~h, commission ,,",\ L~ Date I (~ I q é: ~ Subm't In Tr'plieate ) ') BP K-317b Sidetrack (Revised for BHL on 11/18/02) Summary of Operations: / ./ A CTD sidetrack of PBU K-17a will be drilled into the Lisburne (Wahoo) as a producer. The Lisburne will be isolated from the Ivishak by a drilling liner cemented across the Kavik shale. BOP equipment for pressure deployment of the drilling BHA and "dynamically overbalanced" 'árilling will be used from the start of the sidetrack. ' Initial drilling in Zone 1 and the Kavik will be done with Oppg Flo-Pro to provide increased hole stablll~,.ilit ,.. through the Kavik. After cementing a drilling liner (3 V2~e Wahoo will be penetrated with the samej!¿~ ppg Flo-Pro. If reservoir pressure exceeds 9.5 ppg then the dynamically overbalanced drilling technique will be employed. Expected reservoir pressure is 3475 psi at 8900ss (7.~pg). ~ Lost circulation to Wahoo fractures is expected. LCM will not be used in order to minimize damage to the potentially productive Wahoo fractures. If losses are light then drilling will proceed with Flo-Pro. If losses are heavy then drilling will continue with 2% KCI. The Wahoo producer will be completed with a pre-drilled liner if lost circulation is minimal but will be completed open hole if losses are heavy. Phase 1: Isolate existing Zone 1 perfs with a CIBP, set a low side whipstock. Planned for Dec. 2, 2002. /' · An MIT on the IA has been successfully performed. · The existing 4 V2" tubing has been drifted. · The wellhead and tree valves will be tested. · Service coil will drift the 4 V2" liner and set a cast iron bridge plug at approx. 9830' MD (852655) to shut off all existing Zone 1 perfs. · Service coil will set a through tubing whipstock for a low side window at approx. 9730' MD (852955). I ~ ·I'7.~ I Z,001- vJ5b· Phase 2: Mill window, Drill and Complete CrD sidetrack: Planned for J~03. /' · 23/8" drilling coil and 2% KCI will be used to mill a 3.8" window at approx. 9730' MD (8529ss). .; · 41/8" hole will be drilled with 9.5 ppg Flo-Pro to top Wahoo at approx. 10,400' MD (880055). Max. hole angle will be 100 degrees. / · 3 1/2" liner will be cemented from top Wahoo to approx. 9500' MD (8520ss). · 3" open hole will be drilled through the Wahoo. Initial drilling will be with 9.5 ppg Flo-Pro. · Wahoo completion will be either a 2 3/8" pre-drilled liner or open hole. / /' Mud Program: · Phase 1: 2% KCI £,-1 · Phase 2: 2% KCI and Flo-Pro M'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" ST-L, L-80, solid liner will be cemented from top ~. 00 10,400'md (8,800' ss) to approx. 9500' MD (8520'ss). This liner will be cemented with approx~bls of 15.8ppg class G cement. ) ) Well Control: · BOP diagram is attached. ./' · Pipe rams, blind rams and the CT pack off will be pressure tested to 300 psi and to 4000 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. Logg ing · An MWD Gamma Ray log will be run over the open hole section. Hazards The maximum H2S measured in produced fluids from Lisburne wells in this area is 50 ppm. Shale stability in the Kavik and lost circulation in the Wahoo are the primary drilling hazards. Reservoir Pressure Estimated res. pressure is 3475 psi at 8900ss or 7.5 ppg. Maximum surface pressure with gas (0.10 psi/ft) to surface is 2585 psi. /' TREE = 4" CrN WELLHEA D= FMC Ä'CTUATÕFr;"'·""'BÄ'Kffi ...H.'.·,w,'.',·,.........."".......y"'M'.w,..................""......'M'....·........·,·v KB. ELEV = 61 Bï=:"äE\i;'''''''31':is 'KÕp";·"'"M_~~M'^'''''~~-"'''''''~"-ã"g5õ' '"Max'Ä'ñg'ìe"';;"_··1'Ö1'@"1'3275 'î5ã'iumwr;.;rõ'";;"'M__'''''''"'^'''NM'F33T3' 'Õãium-iVÕsš;"w""'^""8ã'Öõ'i ) K-317B PROPOSED CTD SIDETRACK - 2177' ) 1-14-1/2" HES HXO SVLN NIP, 10=3.813" 110-3/4" CSG, 45.5#, NT80, 10=9.953 1-1 ~ GAS LIFT MANDRELS ST MD iVD DEV TYPE VLV L TCH SIZE 4 3072 3006 1 MERLA TMPDX BK 4-1/2 3 5044 4977 1 MERLA TMPDX BK 4-1/2 2 6810 6734 15 MERLA TMPDX BK 4-1/2 1 8204 7983 34 MERLA TMPDX BK 4-1/2 8271' 1-14-1/2" HES 'X' NIP, ID=3.813" I 8282' 1-17-5/8" x 4-1/2" BKR S-3 PKR, ID=3.875 I 8306' 1-14-1/2" HES 'X' NIP, ID=3.813" I 8327' 1-14-1/2" HES 'XN' NIP, ID=3.725 ~ 3707' L I :8: I :& ~ ~ I I 8337' 8339' 8347' 14-1/2" TBG, 12.6#, L80, .0152 bpf, ID=3,958 1-1 8339' I ITOP OF 4-1/2" LNR 1-1 8347' ~ ~ PERFORA TION SUMMARY REF LOG: MEMDRY NEU. CNL ANGLE AT TOP PERF: 180 @ 12516 Note: Refer to Production DB for historical perf data SIZE SPF INTERV AL Opn/Sqz DA TE 23/4 4 12516-12576 0 11/21/98 23/4 4 12650-12900 0 06/17/98 23/4 4 13310-13560 0 11/07/98 23/4 4 13700-13890 0 11/07/98 I-fTIE BACK SLY I 1-14-1/2" WLEG, ID=3.958 I 1-1 TrN S-6 LNR PKR & DTH-S LNR HGR /1 9500' 1-1 Top of Proposed 3-1/2" Liner 9730' 1-1 Mill Window off Mechical Whipstock 8514' 1-1 TOP OF WHIPSTOCK 1 17-5/8" CSG, 29.7#, L80, ID=6.875 1-1 8986' I~ 15-1/2" LNR, 17#, NT80, .0232 bpf, 10=4.892 1-110794'1 .. ~ 14 1/8" open hole 1 I 3-1/2" Liner - Cerrented 1-1 10400' I 2 3/8" pre-drilled liner or open hole DA TE REV BY COMMENTS 06/18/98 02/24/01 SIS-SL T 03/03/01 SIS-MD 05/04/01 pcr ORIGINAL COMPLETION SIDETRACK COMPLETION CONVERTED TO CANV AS FINAL K-17B ST Proposal 9830' 1-1 Proposed CIBP Placerrent 13050' I~ I 4-1/2" LNR Shoe 1-1 13982' I 1-1 11920'1 PRUDHOE BAY UNIT WELL: K-17B ST Proposed ÆRMIT No: 98-0610 API No: 50-029-22537-02 Sec.3,T11N,R14E BP Exploration (Alaska) K-317B) Direct: (907) 267·6613 E-mail: brijpotnis@inteq.com Baker Hughes INTEQ: (907) 267-6600 (K-17/Plan#12 Plan: Plan #12 Created By: Bnj Patrus T Azimuths to True North ^ ,M Magnetic North: 26.10° p / e Stre~~~~~¥~~~~ Dip Angle: 80.85° Date: 11/13/2002 Model: BGGM2002 LEGEND ! K-04 (Plan K-Q4B J K-17 (K-17A) K-17 (K-17APBI) K-17 (K-17APB2) Plan#121 K-317B Plan #121 ., ~ ':;'~I~....""'::- I M.tI BAKER . .... -IIUCIIIS ObP BP Amoco WliLLPATH DITAlLS 'lo"Uf K-3f78 500282213702 K·17AP81 1711.25 ~ _----1 K-17 (K-17APB2)-"'__ -~---- L.'VTEQ -300 _ -40(}'::- C æ -500~- o ~ -600 - +' -700-~ :!" ~ 1:: -800 -= o ~ -900- - . :!" -1000:= .. ~ 0-1100-- tn -1200---n--= - -1300-~:=::::::- -- -1400 ~ -1 SOO-:-=-----m -200~~=:~: : -100 Yaraet W 1178127/1... 11:00 O+~ ~~= ::=Tto 0.00 0.00 0.00 Co-ordinate (NIE¡ Reference: Well Centre: K-17, True North v~~~~) ~:::;~~: ~r:~f; t~t.'~~)eI Measured Depth Reference: 34: 17 5127/199815:00 59.80 Calculation Method: Minimum CurvatlJ"e vsee ,...., 742..51 8a.30 835.34 1037.11 11H.5' 1230.52 1350.81 1..,5.37 1780M 1831.51 2'122.20 250f.14 TA.R:òET DETAILS TW +NI-S """ SECTION DITA.... +Jt~ +£-W DL., TFace 30.13 2128.35 0.00 0.00 28." 2147.17 ~ 3&57 -4~::~ rut:~:: ~~= -toe..... 2...8..0 10.06 142.22 ~m~i ªªª :~§ ª* ::ifm äª~! t§ ~ª TV. ....... 852t..... 6551.153 ........ 8713.72 "".38 ....... aeG7.3ð "12.70 "'&oM _n aaU.33 eruet ANNOTATIONS TVD N 0 AJlllotatl~ "Z'AI 1711.35 TIP a.2IM Ino.oo KOP '713.72 11270,00 1 a7l1~1 10400.00 2 1112.70 10710.00 . 1171Aa fftOO.oo . _.12 1UOO.oo . a''403' 1UOO.oo a 17'J,,1 11120.00 TD 8350 Pa,..t W......Uu Tie oa MD! 1U1' Ref. Datllm: V.s.ctlan Aq" UI.OO· he liD Me All ¡ :ti~H §:fi :H~ e to.tOO.OO ....05 ta.8' U~ª~ ~5 ¡fi~ H Hm515~ ~5:n 8250 8300 8400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 4100 West( -)/East( +) [100ft/in] .~ -1600--=------- --- KOP-' .ß:-i7IK-17Af------ f QIp ---- - C 8450 ~ 8500 II) - .c 8550 .. 8'8600 a "ii 8650 U :e 8700 a. > 8750 a. 2 8800 I- 8850 --- 8900 2350 2400 2450 2500 2550 2600 11/13/2002 6:08 PM 2150 2200 2250 2300 2100 2050 2000 --- ~1~1~15OO1~1~1~1~1~18001~1~1~ Vertical Section at 159.00· [50ft/in] 300 1250 1200 150 100 1050 1000 950 900 850 800 750 700 650 8950 9000 Company: Field: Site: Well: _. ~~~I.~~~b~_ .. ObP ) .-: tN""i~E.d·, ) BP Baker Hughes INTEQ Planning Report "~---",,-,, """""'''~''~'' ....-.__. · .'.... ·Q~~;',':11./1.~/?~02..·"·TiD1'e;.:::,1~:p~:2ß';i'~:';(,\',.. ····i..,a~ç:···· .. "1::,." Co,;.ordlnate(~E)Referenfe:' "WelI:I<~17,I1:"rue~orth' Vertical.(TV:D) Referenc~: . System: Mean$ea~evel Section (VS) . Reference: '. ' . WeU(O,OON,O.OOE.159.00Azi) . - .-. -. -.:,=....:.c:~::.:.:-,~":==_c:c:~.:-:,,.-~:::.. .,=_:_:.~~:::,=~~~.~!r.=~~!~~~~~~~.~-:~~~~~~-=:::~!v1~~L~=~~~.s~~~~:~~~_:c-.:::_:,,_~-.~~~L~~~'~. ~ ... ... BP'Amoco PrudhoEfBay PBKPad ,. K~17 Plan#t21K~317B , ',.......;."......,.,..:..,,~-"...__..._._~;...- '-.'--.-.'."".-'-'."..'...'-.'.-.-. .- Field: Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Alaska, Zone 4 Coordinate System: Well Centre Geomagnetic Model: BGGM2002 .'.. .. ._",- ._......_.,,'-...,-.._-"~._.......__....._._"-,------ ..---.-.-......--......" -- --.".,--"-,.,-.._...'....._'._,,. .,- -....-.-.,...-..... ._..........._..",---...'-,--._" .Vh"_"_' __.._......~__"____.",."__,...,_...._."...,._..._..,,,....,,...__._"...._'_._.h...__.'___..'.,__.__,,_ .. .._ __..._."....._..__....,..__ ._._.______.______..._...__..'''. Site: PB K Pad TR-11-14 UNITED STATES: North Slope Site Position: Northing: 5973161.33 ft From: Map Easting: 670342.10 ft Position Uncertainty: 0.00 ft Ground Level: 0.00 ft .."... -... ._...,,---"'... -------,,--,-,--~- Latitude: 70 19 57.435 N Longitude: 148 37 5.245 W North Reference: True u ,_~!!~_<?~_n_~!.~~~~_~~.:.. ___.____.. _..___.._!:~_~,.~:~.._. ., ..._._.....___ ...__._...___.__,..._.. ... ..-..,...-.- .__.._..._----'.~--."._~".~._,......__._-_.__.._,. ..- .._----------_.."--_._-'...__...._~,-_._,---_.._..._.._-_. ._._-_..__._._----,._-~._~_.---_._'.._,."-- Well: K-17 K-17 Well Position: Position Slot Name: 17 +N/-S 2033.35 ft +E/-W 1175.34 ft 0.00 ft 5975220.71 ft 671470.88 ft Northing: Easting : Latitude: Longitude: 70 20 17.432 N 148 36 30.917 W _.._...._.._._,..__.~._.___._,,_. ·____·_·_~,··___,'·,·____,,__·___..____w._..,,_....._·_"'._..___.'_W_._. _.~.__.. _'_'.'__.~"_'W'·_____. . .._..___ '"' .._...,._. ._,._,_____.,.... ,_._ .'.n._.. .__,____.... U_"_._'_''''_ ......~ Wellpath: Plan#121 K-317B 500292253702 Current Datum: 34: 17 5/27/199815:00 Magnetic Data: 11/13/2002 Field Strength: 57542 nT Vertical Section: Depth From (TVD) ft .-. _ .._~ w..__.__·.·.,_·.,_._·,_..__.... '~.n 0.00 Targets I· Annotation 9711.35 9730.00 10270.00 10400.00 10780.00 11100.00 11300.00 1.1. 1500.00 11920.00 ¡Plan: ! : Principal: Drilled From: Tie-on Depth: Above System Datum: Declination: Mag Dip Angle: +E/-W ft 0.00, K-17APB1 9711.35 ft Mean Sea Level 26.10 deg 80.85 deg Direction Height 59.80 ft +N/-S ft 0.00 . ---...- .-'-'-"'--" "._,-, -..-~-"'- - 159.00 .. _.f . _.' ..~ . _.......~'_, ",."'~ "." _ ._.._...w.., .. ,.""......_,,__~,. .. ...._"".._,.'."". "._ . ~"_.-..-~-",7'.-:'._~~"".:--..~'-;:~.: h......,___..,..___ ...-.- ····-:·_·_.._···7-.......-·~--:--- .~-.. - ··..·..,··-·-·7--··-----··-·-·· .....~':"-.-.~...-;-.. -.- ..-... _._-~_. ---.. - -'''1-'-'''--'-·1·'· ---..~-......-. --.--. ..~._-~...-. ...-.....- Name Map Map . <----'Latitude---> <---Longitude ,;,--> Description TVD +N/~S+E/-W Northing' ·Easting I)~g Min· Sec Deg Min Sec ... ~ w"".. ,.~~~ :,,_"'~. ~,.. _" ..,,". _... .~,~~~:.. '''_'''''. _...... ..,.' ~ .:.. _,_._~w_', L. ..... _.~~':'~N'~' ... ~._ ~ ~__'._., _,~_, ~~..... ~~~. .'~_ ,,'_ :, ~'N::: ._~: ::: .~~:~...: .~1'" ~::.',~.~ .: .: .'. _~~:2:,~:".:~_~~ ,... '.'. ,~.:i~:i.'~': ~:L.:.~'_'" ~ ~',,;,~;_,,~~'.:.:.~ :.;.': .....~: :'~~,~~.~. :~ .,~.:~~~.~~~.. __ :.., ~~;~~,~:w,~:.:',.L~:L.! }.~~." . :.:,.~~ ~:~'~~:~~'_~"L'~" ::"''''''~ .. . , ..-, -.." ~._.._. ",.~.,,_.~. _....~.. -....,.........--.-..------..--,--,--,---- - --- ------.-----.------"----,.-....---,.---,-..,,..- .. -- . ---,--.-.--.-.-.--.---.-.---,-- 8528.45 TIP 8528.48 KOP 8713.72 1 8799.36 2 8912.70 3 8876.66 4 8848.12 5 8814.33 6 8763.61 TO - - .------ _.~..."._... "..-- .--'. ..,-- Plan #121 Similar to Ted's Case121 Yes Date Composed: Version: Tied-to: 11/13/2002 2 From: Definitive Path MD ft 9711.35 9730.00 9919.00 10108.00 , 10270.00 I 10400.00 10526.67 10653.33 Plan Section Information . --·-Î~'~ï-' ------.-- ~i;··---···---··TVD· ..-.. '-+-Nï=S·-- . --¡EÎ~w··----·--DLS----B-;.ild Turn------TFO···-·-·T-a-;:g~ .-----.----.----.---- --1 deg deg ft ft ft deg/10OO deg/10OO deg/10OO deg ; . ..-... .. - ---..----,-----.. .-...-,.- -.-..-.,--..--.---..-------.--.-.-.----..----.--- ·---,---·---·-----·----,--·,---·--·----·----·-----·---·1 89.51 92.88 8528.45 30.23 2129.35 0.00 0.00 0.00 0.00 90.30 93.51 8528.48 29.19 2147.97 5.42 4.24 3.38 38.57 75.67 99.90 8551.53 7.52 2333.69 8.43 -7.74 3.38 156.88 61.27 113.46 8620.98 -41.67 2501.46 10.11 -7.62 7.17 141.09 48.97 126.63 8713.72 -106.84 2616.43 10.08 -7.59 8.13 142.32 49.05 143.85 8799.36 -176.04 2685.04 9.98 0.06 13.25 95.32 64.50 154.05 8868.68 -266.78 2738.69 13.91 12.20 8.05 31.87 79.90 162.98 8907.36 -378.67 2782.30 13.88 12.16 7.05 30.41 , !. ) ) ---. INrEQ bp BP Baker Hughes INTEQ Planning Report . '. -~""'-" .~..'"_.._.." "_"_'~_"_""""'_M""i_' ···,,··..·~-,··,~·..,...·..·······..~,,·,,~-_·,··"·,,·,--......,'''''1-'--_."_.__._""___....._~_,_...._,,_.._.__._ -,--_._--_.,~._~ . ..~_.._.~~._"""_.-.._.._-_..-...'_..__._.~,.'~.._."..".,..".,,"""".~._.. Company: BP Amoco Field: PrudhòeBay Site: PB K Pad Well: K~17 ~~~~~~!~ :.... Pla~~~.~.~_.~.~1!~_.. '"'. .._'M·,....._...."...."".,..',_,~:."_~h~ D~te::11h3/290~'"...... .·...·...·.:1'inlè:1~:O~,:2~ ... ··l~ag~: (;o~l'dimlte(IS.E)~~f~r~lIçe:. ". Well: .~;.17,1)ueNqrth' ..................;, .y er;t~~;\I('{yP)Ref,,~~~~e: ~ystern:Me~nße~L~vel.···..·..¡,.', Sect~on(Vs~:Jl~fe~~n.çe~ . .. .......... ......V\I~II(O.(JON~0.00E,159.QO~i) ... . .'. ., . '..:.. ....._,._.L......:...L§~.~~~"'2'.'~Hl~~~I!~,~~~~E:__....'j.~i~i_'P:.~~'.E~r.:'~,~~:i_::L._..._..;J?~:,j3t~2.I~,................ 2 Plan Section Information ......_ '~".._."'..___~..~._w._".._.__.__,..,,,._ ~-,.. . ':H,.,..",,_:. .~..~.- _.~,.:-'- _.~..::..".., . "~~"",:--:,~:'"7'::-':~:'-;':~,;'.'~~~ ,',~ ,........ ~ :,r,~..,"T·~~'-..~-:-~·'::"'·~-' "...~.:~: ~.~:,~'~~:'~~~ .:._~~._,~~-:"'::~~ ":::~"._.~ ~"'~,~W'~"::-':~~,','7~~~:"":r~~',": ~"-:-:~7""- "?:~~,~"'; _w,w:·":"~"",,,-·-·~~..-~-t:~'7:'~·~·:~~· ':...~- .' ..~...~- "~"i~ '~........"'~,.,. '. ',' ,. ":':"--'':'"~-,~ '..- MD lncl Azim :.. TVI)··· ··.·.+N/~~ .. +~!~W,.···...··.·.,.··.~~$ ...;~uil~,:¡urll'..··.·.··..,TF'O''farge~. ' . ft deg deg. ..... ... ..ft .... ... ...··ft.....·....i ....ift!,.".'· ..·....d,1;!9ltP®cjeg!.1!qpftdeg(tppft..deg ,:::" :,:,',,-,:':;.'.,':', ',,; ,";",,',' I ,:.:. ',;,,.:., '",',: ..,~ ....--'......,..........,..,.,.... -.; ~ "".'... .."" ,," ....I.,.._w.." ,. ',. ",_ ".~'" ".,.,.,.: ..' ,...,.~.~. ._". ._"., ,..:-_.~.. ., ...~. .J~;~.~.,., ..'....J.,_.;. , ..'~~~...:.;.. _~,"':":....:..L. J..:¡.~~" _.~~ .~..:....'1.:.......'__~...~...J...;...:.;,;~..~ ..',..:.,,_~'"'.......~.:.' _.....~.. :_~" ,.:.:,.....;~_.....:.." ::~~......, ~J-'.~'~.~~~,:,. ~~_~.....:~ ;.~_~.,.....'..;.,..I.~. ,...,:_,~.,;,. .'. ","...;~.....: I~:''''.'.''''; .":'. ..~_,.;.;:..:.._I,'......:'...L _. 10780.00 95.26 171.44 8912.70 -501.62 2810.15 13.83 12.13 6.68 29.12 11100.00 97.46 197.03 8876.66 -816.08 2787.02 7.98 0.69 8.00 83.70 11300.00 98.84 180.96 8848.12 -1010.95 2756.13 7.98 0.69 -8.03 276.07 111500.00 100.49 164.85 8814.33 -1205.92 2780.33 7.98 0.82 -8.05 277 .25 11920.00 93.00 198.28 8763.61 -1616.48 2768.15 8.10 -1.78 7.96 100.33 _. __·..···_·_·'··_·,'_··__~_·.·n....·'n~ ___.___._, '~·_'_._n._..~._ ._._"._.,__.~_~._ ....-._..-._'....._--~-".....~_.._....,,_.. ."'......._.. w...."..._..__.._,_~,...._,..,,'. .. -. -.----... -_...__.~ _ .. -----. - -"_. --------~. ----- --- ...-.--...-- -.-. ._..._-~..-.~- . -...,---..--.-.... 9711.35 89.51 92.88 8528.45 30.23 2129.35 5975299.62 673598.84 734.87 0.00 0.00 TIP 9725.00 90.09 93.34 8528.50 29.49 2142.98 5975299.19 673612.48 740.45 5.42 38.57 MWD 9730.00 90.30 93.51 8528.48 29.19 2147.97 5975299.01 673617.48 742.51 5.42 38.57 KOP 9750.00 88.75 94.17 8528.65 2"1.85 2167.93 5975298.12 673637.46 750.92 8.43 156.88 MWD 9775.00 86.81 95.00 8529.62 25.85 2192.83 5975296.69 673662.39 761.70 8.43 156.87 MWD 9800.00 84.87 95.83 8531.43 23.50 2217.65 5975294.91 673687.26 772.80 8.43 156.84 MWD 9825.00 82.94 96.67 8534.08 20.79 2242.36 5975292.77 673712.02 784.18 8.43 156.78 MWD 9850.00 81.00 97.52 8537.58 17.73 2266.92 5975290.27 673736.65 795.84 8.43 156.69 MWD 9875.00 79.07 98.37 8541.90 14.33 2291.31 5975287.43 673761.11 807.75 8.43 156.57 MWD 9900.00 77.14 99.23 8547.06 10.59 2315.48 5975284.24 673785.36 819.91 8.43 156.43 MWD 9919.00 75.67 99.90 8551.53 7.52 2333.69 5975281.59 673803.63 829.30 8.43 156.25 MWD 9925.00 75.20 100.29 8553.03 6.50 2339.41 5975280.70 673809.37 832.30 10.11 141.09 MWD 9950.00 73.24 101.96 8559.83 1.86 2363.01 5975276.61 673833.07 845.09 10.11 140.99 MWD 9975.00 71.30 103.65 8567.45 -3.41 2386.23 5975271.86 673856.40 858.33 10.11 140.54 MWD 10000.00 69.37 105.39 8575.86 -9.31 2409.02 5975266.49 673879.32 872.01 10.11 140.03 MWD 10025.00 67.46 107.16 8585.06 -15.82 2431.33 5975260.49 673901.77 886.08 10.11 139.44 MWD 10050.00 65.57 108.99 8595.03 -22.93 2453.13 5975253.88 673923.72 900.53 10.11 138.79 MWD 10075.00 63.70 110.88 8605.74 -30.63 2474.36 5975246.67 673945.13 915.33 10.11 138.06 MWD 10100.00 61.85 112.82 8617.17 -38.90 2494.99 5975238.87 673965.94 930.44 10.11 137.25 MWD 10108.00 61.27 113.46 8620.98 -41.67 2501.46 5975236.26 673972.47 935.34 10.11 136.36 MWD 10125.00 59.92 114.67 8629.33 -47.70 2514.98 5975230.53 673986.13 945.83 10.08 142.32 MWD 10150.00 57.95 116.51 8642.23 -56.95 2534.30 5975221.73 674005.65 961.38 10.08 141.73 MWD 10175.00 56.01 118.43 8655.85 -66.62 2552.89 5975212.49 674024.46 977.07 10.08 140.78 MWD 10200.00 54.11 120.44 8670.17 -76.68 2570.74 5975202.83 674042.53 992.86 10.08 139.73 MWD 10225.00 52.24 122.55 8685.16 -87.13 2587.80 5975192.78 674059.83 1008.73 10.08 138.58 MWD 10250.00 50.40 124.77 8700.78 -97.95 2604.05 5975182.34 674076.31 1024.65 10.08 137.31 MWD 10270.00 48.97 126.63 8713.72 -106.84 2616.43 5975173.73 674088.90 1037.39 10.08 135.93 1 10275.00 48.93 127.29 8717.00 -109.11 2619.45 5975171.53 674091.96 1040.59 9.98 95.32 MWD 10300.00 48.76 130.60 8733.46 -120.94 2634.08 5975160.04 674106.86 1056.88 9.98 94.89 MWD 10325.00 48.69 133.92 8749.96 -133.57 2647.98 5975147.73 674121.05 1073.65 9.98 92.71 MWD 10350.00 48.71 137.24 8766.46 -146.98 2661.13 5975134.63 674134.49 1090.88 9.98 90.52 MWD 10375.00 48.84 140.55 8782.94 -161.14 2673.49 5975120.75 674147.17 1108.53 9.98 88.33 MWD 10400.00 49.05 143.85 8799.36 -176.04 2685.04 5975106.13 674159.06 1126.58 9.98 86.14 2 10425.00 52.03 146.18 8815.25 -191.85 2696.09 5975090.57 674170.48 1145.30 13.91 31.87 MWD 10450.00 55.05 148.32 8830.10 -208.76 2706.96 5975073.91 674181.73 1164.98 13.91 30.39 MWD 10475.00 58.10 150.32 8843.87 -226.71 2717.60 5975056.22 674192.77 1185.55 13.91 29.12 MWD 10500.00 61.18 152.18 8856.51 -245.62 2727.97 5975037.55 674203.57 1206.92 13.91 28.02 MWD 10525.00 64.29 153.94 8867.96 -265.43 2738.03 5975017.98 674214.08 1229.02 13.91 27.08 MWD 10526.67 64.50 154.05 8868.68 -266.78 2738.69 5975016.64 674214.77 1230.52 13.91 26.27 MWD 10550.00 67.30 155.83 8878.21 -286.07 2747.71 5974997.56 674224.23 1251.76 13.88 30.41 MWD 10575.00 70.33 157.65 8887.24 -307.48 2756.91 5974976.37 674233.92 1275.05 13.88 29.68 MWD 10600.00 73.37 159.40 8895.03 -329.59 2765.60 5974954.47 674243.11 1298.80 13.88 29.02 MWD 10625.00 76.42 161.10 8901.54 -352.30 2773.75 5974931.95 674251.78 1322.93 13.88 28.47 MWD 10650.00 79.49 162.76 8906.76 -375.54 2781.33 5974908.89 674259.89 1347.34 13.88 28.03 MWD 10653.33 79.90 162.98 8907.36 -378.67 2782.30 5974905.78 674260.92 1350.61 13.88 27.69 MWD bp ) ) BP Baker Hughes INTEQ Planning Report ~ ~~,._,-,.~ .,~ .,-- ~,~_.....- ~_.,._- .,...,.. '~~._.:':_... .._,,_~."~,_.. ,_...~.,~..._".-:-._'4 '"'''''--~'''''''-;'''-'''''''''''''''''':'''-'''-''·''~,_-O:-:-'h'__~''~~~~'''....,........ -"'''--'''1'''''''" ,~._,___~__".._~_.,..,~ ~__'_'''''r''R',___'~'"''·,''____''-''''''I_~__·_''·'·__''''·'·:,'''_''_''"'H'" _._-_..,..~--'--,..~'";"---,...'-'_.-:",.. "....-... IN'f RQ Dá1t~{i1Î13/2g9? !':'irf~~: ,1:~:Òå:28i'/ ... .' ..........,.. ·,pag¢: .., 3:· ., ,ç()~~d¡~~!~P'ì~i'~~(~re..c~: ' , ,.. ",YY~lt;'':<r~ 7',!rµ~t-4'Or1~·'........'.'. ...............,........... .'..' .'.. I y~~~~.('I'~P~,~f~~e~ce:,\ 'sy~~eQ1:M~a.rI~~Ei,yE:!yel .'... .........'..,.)' ' , Sectiori(VS) R~rereric~:' WelI'{0:OON,O.OOE;159.00AZi) '._h_. .__ ..h~~~:~r_<::~I,c_~I~t~~~_l\1!~~~~:_______~~~i~~~ Curvature _._J?~:___~~~!.~:_,~, _," Company: BPAn-Ioco Field: PrudhoeBÇlY Site: PB K Pad Well: K-17 Well path: Plan#121 K-317B Survey MD ft - . - --.- -".-. - - ..-- -.. - - 10675.00 10700.00 10725.00 10750.00 10775.00 10780.00 10800.00 10825.00 10850.00 10875.00 10900.00 10925.00 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 11300.00 11325.00 11350.00 11375.00 82.52 85.55 88.59 91.62 94.65 95.26 95.43 95.64 95.85 96.04 96.23 96.42 96.59 96.76 96.91 97.06 97.20 97.34 97.46 97.67 97.86 98.05 98.23 98.40 98.56 98.70 98.84 99.09 99.32 99.55 11400.00 99.76 11425.00 99.96 11450.00 100.15 11475.00 100.33 11500.00 100.49 11525.00 100.12 11550.00 99.74 11575.00 99.35 11600.00 98.94 11625.00 98.53 11650.00 11675.00 11700.00 11725.00 11750.00 11775.00 11800.00 11825.00 11850.00 11875.00 11900.00 11920.00 98.10 97.66 97.22 96.77 96.31 95.84 95.36 94.88 94.39 93.90 93.40 93.00 164.45 166.13 167.79 169.44 171.11 171.44 173.03 175.02 177.02 179.01 181.01 183.01 185.01 187.01 189.01 191.01 193.02 195.02 197.03 195.03 193.02 191.02 189.01 187.00 184.99 182.97 180.96 178.96 176.95 174.94 172.92 170.91 168.89 166.87 164.85 166.87 168.89 170.90 172.91 174.92 176.92 178.91 180.90 182.89 184.87 186.85 188.83 190.80 192.77 194.74 196.71 198.28 8910.67 8913.26 8914.54 8914.50 8913.13 8912.70 8910.83 8908.42 8905.92 8903.33 8900.65 8897.90 8895.07 8892.16 8889.19 8886.15 8883.04 8879.88 8876.66 8873.37 8869.99 8866.53 8862.99 8859.37 8855.69 8851.94 8848.12 8844.23 8840.23 8836.13 8831.94 8827.66 8823.29 8818.85 8814.33 8809.86 8805.55 8801.40 8797.43 8793.63 8790.02 8786.59 8783.35 8780.30 8777.46 8774.81 8772.38 8770.14 8768.12 8766.32 8764.72 8763.61 -399.23 -423.28 -447.59 -472.10 -496.70 -501.62 -521.35 -546.10 -570.91 -595.76 -620.62 -645.45 -670.23 -694.92 -719.50 -743.93 -768.19 -792.25 -816.08 -839.90 -863.93 -888.14 -912.51 -937.01 -961.60 -986.26 -1010.95 -1035.64 -1060.30 -1084.90 -1109.41 -1133.79 -1158.03 -1182.08 -1205.92 -1229.77 -1253.85 -1278.12 -1302.55 -1327.12 -1351.79 -1376.54 -1401.33 -1426.13 -1450.91 -1475.63 -1500.28 -1524.82 -1549.21 -1573.42 -1597.44 -1616.48 2788.30 2794.61 2800.25 2805.18 2809.40 2810.15 2812.84 2815.43 2817.16 2818.02 2818.01 2817.14 2815.41 2812.81 2809.35 2805.04 2799.87 2793.87 2787.02 2780.18 2774.18 2769.02 2764.72 2761.27 2758.69 2756.98 2756.13 2756.15 2757.03 2758.77 2761.38 2764.84 2769.16 2774.32 2780.33 2786.33 2791.50 2795.83 2799.30 2801.92 2803.68 2804.58 2804.62 2803.80 2802.12 2799.58 2796.19 2791.94 2786.85 2780.92 2774.16 2768.15 5974885.37 5974861.48 5974837.29 5974812.91 5974788.41 5974783.51 5974763.85 5974739.17 5974714.40 5974689.58 5974664.73 5974639.89 5974615.08 5974590.34 5974565.69 5974541.16 5974516.79 5974492.60 5974468.63 5974444.66 5974420.50 5974396.17 5974371.71 5974347.15 5974322.51 5974297.82 5974273.12 5974248.43 5974223.80 5974199.25 5974174.81 5974150.51 5974126.39 5974102.46 5974078.76 5974055.06 5974031.11 5974006.94 5973982.60 5973958.09 5973933.4 7 5973908.75 5973883.97 5973859.16 5973834.35 5973809.58 5973784.86 5973760.24 5973735.74 5973711.39 5973687.23 5973668.05 674267.39 674274.25 674280.44 674285.94 674290.71 674291.58 674294.72 674297.87 674300.17 674301.60 674302.16 674301.86 674300.69 674298.66 674295.76 674292.01 674287.40 674281.94 674275.65 674269.35 674263.90 674259.30 674255.56 674252.67 674250.65 674249.50 674249.22 674249.80 674251.25 674253.55 674256.72 674260.74 674265.61 674271.32 674277.87 674284.42 674290.14 674295.01 674299.05 674302.23 674304.55 674306.02 674306.62 674306.37 674305.26 674303.28 674300.45 674296.77 674292.24 674286.86 674280.65 674275.09 1371.95 1396.66 1421.38 1446.03 1470.51 1475.37 1494.76 1518.79 1542.57 1566.08 1589.28 1612.15 1634.66 1656.78 1678.49 1699.76 1720.56 1740.86 1760.66 1780.44 1800.72 1821.48 1842.69 1864.33 1886.36 1908.76 1931.51 1954.57 1977.91 2001.50 2025.31 2049.32 2073.49 2097.79 2122.20 2146.62 2170.95 2195.16 2219.22 2243.09 2266.76 2290.18 2313.34 2336.20 2358.73 2380.90 2402.70 2424.08 2445.03 2465.51 2485.51 2501.14 13.83 13.83 13.83 13.83 13.83 13.83 7.98 7.98 7.98 7.98 29.12 MWD 28.90 MWD 28.72 MWD 28.64 MWD 28.64 MWD 28.73 3 83.70 MWD 83.85 MWD 84.04 MWD 84.24 MWD 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 84.44 MWD 84.66 MWD 84.88 MWD 85.10 MWD 85.34 MWD 85.57 MWD 85.82 MWD 86.07 MWD 86.32 4 276.07 MWD 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 7.98 275.81 MWD 275.54 MWD 275.26 MWD 274.98 MWD 274.68 MWD 274.39 MWD 274.09 5 277.25 MWD 276.94 MWD 276.62 MWD 276.29 MWD 275.95 MWD 275.61 MWD 275.26 MWD 274.90 6 8.10 8.10 8.10 8.10 8.10 100.33 MWD 100.69 MWD 101.04 MWD 101.37 MWD 101.69 MWD 102.00 MWD 102.29 MWD 102.56 MWD 102.82 MWD 103.06 MWD 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10 103.29 MWD 103.49 MWD 103.69 MWD 103.86 MWD 104.02 MWD 8.10 8.10 104.17 MWD 104.29 TD ) Per Alaska Oil and Gas Conservation Comlllission Regulation 20 AAC 25.015 Changes to a Prograln in a Pertnit to Drill sub section (a) (1) submit and obtain the cOllln1ission's approval of a new application for a Pern1it to Drill if the surface location is changed, if the bottol11-hole location or the location of an objective formation is changed by rnore than 500 feet laterally or vertically, or if the change requires a spacing exception under 20 AAC 25.055; however, no additional fee is required ) ) TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERlP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ¡D.Ii bl .k,. 3 J 7 ß PTD# 20/- /...t;c CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API num ber last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function' of the . original API number stated above. HOLE In accordance with 20 AAC 25.005(t), all records, data and 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). PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. WELL PERMIT CHECKLIST COMPANY AP X. WELL NAME/.lÚ k - .~/74 PROGRAM: Exp _ Dev..K.. Redrll-X- Re-Enter _ Serv _ We II bore seg _ FIELD & POOL G YòJq~ INIT CLASS no..IV /-ð,ï GEOL AREA -¡./,) UNIT# IIr;.Sñ ON/OFF SHORE..d!V ADMINISTRATION 1. Permittee attached. . . . . . . . . . . . . . . . . . . . . . . IV N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . Y N 3. Unique well name and number. . . . . . . . . . . . . . . . . Y N 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . Y N 5. Well located proper distance from drilling unit boundary. Y N 6. Well located proper distance from other wells. . Y N 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . Y N 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . Y N 9. Operator only affected party.. . . . . . . . . . . . . . . . . . Y N 10. Operator has appropriate bond in force. . . . . . . . . . . . . Y N 11. Permit can be issued without conservation order. . . . . . . . Y N 12. Permit can be issued without administrative approval.. . . . . }tv. ~ (Service Well Only) 13. Well located wlin area & strata authorized by injection order#_ Y /'_)..~ " (Service Well Only) 14. All wells wlin X mile area of review identified. . . . . . . . .. Y ENGINEERING 15. Conductor string provided. . . . . . . . . . . . . . . . . . . ¢' N 16. Surface casing protects all known USDWs. . . . . . . tr) N 17. CMT vol adequate to circulate on conductor & surf esg. . . ~--N- ^'I A- 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . ¥-M'" 19. CMT will cover all known productive horizons. . . . . . . .. . J' " N 20. Casing designs adequate for C, T, B & permafrost. . . . . . . rJ N 21. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . N 0"T D/;( . 22. If a re-drill, has a 10-403 for abandonment been approved. . .'-" NN ..g 17/ z-ð 0 I . 23. Adequate wellbore separation proposed.. . . . . . . . . . . . 24. If diverter required, does it meet regulations. . . . . . . . . . Ai/k- 25. Drilling fluid program schematic & equip list adequate. . . . . N 1M ~ Yl1. "......1 ~. S- r ~1 ' 26. BOPEs, do they meet regulation. . . . . . . . . . . . . . .. N /' ;) _0 APPR DATE 27. BOPE press rating appropriate; test to L/- 0 éJ 0 psig. N /VI ~ r '2..$ \\ c; r So J. '11 iG^ I 'J 28. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N ~ ~ I Z- / ~/01.- 29. Work will occur without operation shutdown. . . . . . . . . . . N 30. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . ::v N '50 pflNL (Service Well Only) 31. Mechanical condition of wells within AOR verified. . . . . . . . -¥-N- ^'11t- GEOLOGY 32. Permit can be issued wlo hydrogen sulfide measures. . . . . jf APPR DATE 33. Data presented on potential overpressure zones. . . . . . . . Y ~ . J ~ 34. Seismic analysis of shallow gas zones. . . . . . . . . . . . . Y ¡It). 4 t 't. JI/ZA 'Q_ 35. Seabed condition survey (if off-shore). . . . . .. ...... Y N Exploratory nly) 36. Contact namelphone for weekly progress reports. ...... N APPR DATE ÛL- 1/1~)..2- ) ) ~~ I''''~-'''¡ - $.. r''')'J~'&¡~¡ I~~ " J I"""iJ J ~.S'"u·V1 7"_ /VÞ,,,isr(!r/ ~h~.,.L~k"/ 1''1ð! n.Je-.r, - Æft: ~ /( "'-") e~'.~t/lJ' ~ tJt j ,,-~ . ~ t) q. . GEOLOGY: PETROLEUM ENGINEERING: RESERVOIR ENGINEERING UIC ENGINEER COMM ISSIONER: Commentsllnstructions: RPC_ TEM JDH JBR COT øt "?/l) ¿-{or DTS / MJW M LB /"*'- L..CS SFD_ WGA Rev: 10/15/02 G:\geology\perm its\checklist.doc ) ') ¡ ~~!Æ~E ~ F !Æ~!Æ~ ~~!Æ TONY KNOWLES, GOVERNOR ~ AlASKA OIL AND GAS CONSERVATION CO.MMISSION 333 W. ]TH 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 99519-6612 Re: Prudhoe Bay Unit K-317 A BP Exploration (Alaska) Inc. Permit No: 201-156 Sur Loc: 1440' SNL, 887' EWL, SEC. 22,T11N, RI4E, UM Btmhole Loc. 349' SNL, 2572' EWL, SEC. 15, TIIN, RI4E, UM Dear Mr. Stagg: Enclosed is the approved application for peImit to drill the above referenced well. The permit to drill 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 K-317 A. Blowout prevention equipment (BOP E) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, ðL{j-·(!~ /\/1, W -l¡(/7?::J'/ Julie M. Heusser Con1missioner BY ORDER OF THE COMMISSION DATED this S t!1- day of August, 2001 jjc/Enclosures cc: Department of Fish & Game, Habitat Section wlo encl. Department of Environmental Conservation wlo encl. ') STATE OF ALASKA ') ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 1 a. Type of work 0 Drill B Redrill 1 b. Type of well ORe-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3280' NSL, 4078' WEL, SEC. 04, T11 N, R14E, UM At top of productive interval 3271' NSL, 858' WEL, SEC. 04, T11N, R14E, UM At total depth 3567' NSL, 1106' WEL, SEC. 04, T11 N, R14E, UM 12. Distance to nearest property line 13. Distance to nearest well ADL 028300,1712' MD No Close Approach 16. To be completed for deviated wells . Kick Off Depth 9800' MD Maximum Hole Angle 18. CasinfJ Program Specifications $17e Hole CasinQ WeiCJht Grade Couplina I enQth 4-1/8" 3-3/16" 6.2# L-80 TCII 2000' 2-3/4" 2-3/8" 4.7# L-80 ST-L 680' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner 13982 feet 8736 feet 13050 feet 8770 feet Length Size 80' 20" 3672' 10-3/4" 8482' 7-5/8" 5645' 4-1/2" o Exploratory 0 Stratigraphic Test B Development Oil o SelVice 0 Development Gas 0 Single Zone 0 Multiple Zone 5. Datum Elevation (OF or KB) 10. Field and Pool KBE = 59.81 Prudhoe Bay Field I Lisburne 6. Property Designation Pool ADL 028303 7. Unit or Property Name Prudhoe Bay Unit 8. Well Number K-317B 9. Approximate spud date 08/20/01 Amount $200,000.00 14. Number of acres in property 15. Proposed depth (MD and TVD) 2560 10930' MD I 9176 TVDss o 17. Anticipated pressure {see 20 MC 25.035 (e) (2)} 92 Maximum surface 3510 psig, At total depth (TVD) 8900' I 4400 psig Setting Depth TQp Botom MD TVD MD TVD 8400' 8148' 10400' 8800' 10250' 8520' 10930' 9176' 11. Type Bond (See 20 AAC 25.025) Number 2S 100302630-277 Quantity of Cement (include staae data) 59 sx Class IG' Uneemented Slotted Liner kl::CC/VFrJ Plugs (measured) IBP set at 13050' (11/98) JUL 2 5 2001 Alaska Oil & Gas C AnChor~~~ Commission Junk (measured) Cemented MD TVD 260 sx Aretieset (Approx.) 1101 110' 1050 sx PF lEI, 375 sx Class IG' 3707' 3703' 472 sx Class 'G' 85141 8302' 235 sx Class 'GI 8337' - 13982' 8155' - 8736' Perforation depth: measured 12516' - 12576', 12650' - 12900', Open, Below Bridge Plug: 13310' - 13560', 13700' - 13890' true vertical 8754' - 87661, 8770' - 8766' Open, Below Bridge Plug: 8759' - 8724', 8721' - 8734' 20. Attachments 181 Filing Fee 0 Property Plat 181 BOP Sketch 0 Diverter Sketch 181 Drilling Program 181 Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 0 20 AAC 25.050 Requirements Contact Engineer NameINumber: Ted Stagg, 564-4694 Prepared By NameINumber: Terrie Hubble, 564-4628 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Ted Stagg ~~,<j.!;"cO",::~T:~I~:=~~:~e;r Date .%-1é/ Permit Number API Number ApPr:A7Va, Date See cover letter z.o / - ISh 50- 029-22537-02 '6 J ~/ [) I for other requirements Conditions of Approval: Samples Required 0 Yes J8I No Mud Log Required 0 Yes BI No Hydrogen Sulfide Measures IS Yes 0 No Directional Survey Required ~ Yes 0 No Required Working Pressure for BOPE 0 2K 0 3K 0 4K 0 5K 0 10K 0 15K }(3.5K psi for CTU Other: by order of the commission Approved By Form 10-401 Rev. 12-01-85 DUr~~Eðah~ner Date ~ 1~1 f)) Sublnit In Triplicate ) ) BP K317b Sidetrack Summary of Operations: A CTD sidetrack of PBU K-17a will be drilled into the Lisburne (Wahoo) as a producer. The Lisburne will be isolated from the Ivishak by a drilling liner cemented across the Kavik shale. BOP equipment for pressure deployment of the drilling BHA and "dynamically overbalanced" drilling will be used from the start of the sidetrack. Initial drilling in Zone 1 and the Kavik will be done with 9.7 ppg Flo-Pro to provide increased hole stability through the Kavik. After cementing a drilling liner the Wahoo will be penetrated with the same 9.7 ppg Flo- Pro. If reservoir pressure exceeds 9.7 ppg then the dynamically overbalanced drilling technique will be employed. Lost circulation to Wahoo fractures is expected. LCM will not be used in order to minimize damage to the potentially productive Wahoo fractures. If losses are light then drilling will proceed with Flo-Pro. If losses are heavy then drilling will continue with 20/0 KCI. The Wahoo producer will be completed with a pre-drilled liner if lost circulation is minimal but will be completed open hole if losses are heavy. Phase 1: Isolate existing Zone 1 perfs with a CIBP, set a low side whipstock. Planned for August 13, 2001 · An MIT on the IA has been successfully performed. · The existing 4 Y2" tubing has been drifted. · The wellhead and tree valves will be tested. · Service coil will drift the 4 Y2" liner and set a cast iron bridge plug at approx. 9900' MD to shut off all existing Zone 1 perfs. · Service coil will set a through tubing whipstock for a low side window at approx. 9800' MD. Phase 2: Mill window, Drill and Complete CTD sidetrack: Planned for August 20, 2001 · 23/8" drilling coil and 2% KCI will be used to mill a 3.8" window at approx. 9800' MD (8527ss). · 4 1/8" hole will be drilled with 9.7 ppg Flo-Pro to top Wahoo at approx. 10,400' MD (8800ss). · 33/16" liner will be cemented from top Wahoo to approx. 8400' MD (8148ss). · 2 %" (or 3") hole will be drilled through the Wahoo. Initial drilling will be with 9.7 ppg Flo-Pro. · Wahoo completion will be either a 2 3/8" pre-drilled liner or open hole. Mud Program: · Phase 1: 2% KCI · Phase 2: 2% KCI and Flo-Pro (9.7 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: · 33/16" ,TCII, L-80, solid liner will be cemented from top Wahoo 10,400'md (8,800' ss) to approx. 8400' MD (8148' ss). This liner will be cemented with approx. 12 bbls of 15.8ppg class G cement. Well Control: · BOP diagram is attached. · Pipe rams, blind rams and the CT pack off will be pressure tested to 300 psi and to 4000 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 log will be run over the open hole section. · A memory Induction log will be run over the Wahoo interval. Hazards The maximum H2S measured in produced fluids from Lisburne wells in this area is 50 ppm. Shale stability in the Kavik and lost circulation in the Wahoo are the primary drilling hazards. Reservoir Pressure P-50 estimated res. pressure is 4400 psi at 8900ss or 9.5 ppg. Maximum surface pressure with gas (0.10 psi/ft) to surface is 3510 psi. TREE: 4" CIW WELLHEAD: FMC ACTUA TOR:BAKER 13707' I I 8337' I I 8347' I ) 10-3/4",45.5 #/ft, NT-80, BTC ANNULUS CAP: .0262 BBLS/FT. 4-112", 12.6#/ft, L-80, NSCT TUBING ID: 3.958" CAPACITY: .0152 BBUFT MAX. ANGEL OF TBG. 340 TIE-BACK SLEEVE TIW S-6 LINER PKR & DTH - S LINER HANGER 4 1/2"LlNER 12.6# L-80 3.958"I.D. CAP.= .0152 I 8514' I WHIPSTOCK 18825' 1 18986' 1 I WINDOW 851~8526' 4 1/2TBG. CUT @ 860S' 7 S/8"PKR. TOP OF S-112" LINER 7-5/8", 29.7#fft, L-80, NSCC K-17 A o -~ L :8: . l.. ..'.'. II ) KB. ELEV = 61.00' BF. ELEV = 31.75' H.E.S. 4.5"HXQ SVLN I 2177' 1 3.813"I.D. .. MERLA TMPDX 4.S"x 1 "GLMS MIN.I.D. 3.857" BK LATCHES NO. MD TVDss. DEV. 4 3072' 3006 6 3 5044' 4977' 0 2 6810' 6734' 16.7 1 8204' 7983' 34.6 z- H.E.S. 4.5"X- NIPPLE 3.813"I.D. BAKER 7 5/8"S-3 PKR. 3.875"I.D. H.E.S. 4.5"X- NIPPLE 3.813"I.D. H.E.S. 4.5"XN- NIPPLE 3.725"I.D. WLEG 1 8271' 1 1 8282' 1 1 8306' 1 1 8327' 1 1 8339' 1 1 1 ELMD ~ \ SHOE 113982' 1 ~ ~ELL~~TtL @.,92,0~' . - iif . - IBP set @ 13.0::':MD 1113901' I .. ì . Baker IBP set at 10340' '!i'I1:; 110750' I PBTD 110794' I 5-1/2",17 #1ft, NT-80, NSCC DATE 6/18198 11/7/98 11/21/98 REV. BY JONES! LlDDELOW WALKERn..UECKER BUNDY COMMENTS SIDETRACK I DOYON 14 SET IBP ADD PERFS PERFORATION SUMMARY SIZE SPF INTERVAL OPEN/SQZ'D 2 3/4" 4 12,516'· 12,576' (yEN 11/98 23/4" 4 12,650'- 12,900' OPEN 13,OSO CTMD IBP 2 3/4" 4 13,310'- 13,S60' OPEN 2 3/4" 4 13,700'- 13,890' OPEN Prudhoe Bav Unit Well: K-17A API NO:50-029-22537 SEe 03,T11N,R14E,UM BP Exploration (Alaska) - . ) K317B ) PROPOSED CTD SIDETRACK TREE = 4" CW WB.LHEAO= FMC ÄCi'ûAi'OR;' BAKER Kif - 8:.8/';;·" ". 61' ·BF.'/3j:\ï ';;;. 31 : is 'kÒp;' ,. "8550 Mâx·Äi,gìê~·· -1 01@ -13275 oatlJmMD== '.- .., ·13313 bâtum WOSs';' , 'S800' 110-3/4" CSG, 45.5#, NT80, 10=9.953 1-1 3707' ¡-J 14-1/2" TBG, 12.6#, L80, .0152 bpf, 10=3.958 1-1 8339' 1 1 TOP OF 4-1/2" LNR 1'1 8347' 1 ÆRFORA TION SUMMARY REF LOG: MEMORY NEU. CNL ANGLEATTOPÆRF: 180 @ 12516 Note: Refer to Production OB for historical perf data SIZE SPF INTERVAL Opn/Sqz OATE 23/4 4 12516-12576 0 11/21/98 2 3/4 4 12650-12900 0 06/17/98 23/4 4 13310-13560 0 11/07/98 2 3/4 4 13700-13890 0 11/07/98 8514' I-1TOPOFWHIPSTOCK 1 1 7-5/8" CSG, 29.7#, L80, 10=6.875 1'1 8986' ~ 15-1/2" LNR, 17#, NT80, .0232 bpf, 10=4.892 1-110794'1 - L I :g I :& t ~ I I ~ ~ 2177' 1'14-1/2" HES HXO SVLN NIP, 10=3.813" ~ GAS LIFT MANDRELS ST MO lVO DEV 1YÆ VLV L TCH SIZE 4 3072 3006 1 MERLA ìMPOX BK 4-1/2 3 5044 4977 1 MERLA ìMPOX BK 4-1/2 2 6810 6734 15 MERLA ìMPOX BK 4-1/2 1 8204 7983 34 MERLA ìMPOX BK 4-1/2 8271' 1-14-1/2" HES 'X' NIP, 10=3.813" I 8282' Ii 7 -5/8" x 4-1/2" BKR 8-3 PKR, 10=3.875 1 8306' 1-14-1/2" HES 'X' NIP, 10=3.813" 1 8327' 1'14-1/2" HES 'XN' NIP, 10=3.725 8337' 1'1 TIE BACK SL V 1 8339' 1'14-1/2" WLEG, 10=3.958 I 8347' 1-1 TW S-6 LNR PKR & OTH-S LNR HGR I 8400' 1'1 Top of Proposed 3-3/16" Liner I 9800' 1-1 Mill Window off Mechical Whipstock 9900' 1-1 Proposed CIBP Aacement 13050'I~ 1 4-1/2" LNR Shoe 1-1 13982' , /"~~~, '>'t~:~~'¡i:r,..' 14 1/8" open hole 1 13-3/16" TC II Liner - Cemented H 10300' 1 2 3/8" pre-drilled liner or open hole H 10930'1 DATE REV BY COMMENTS ORIGINAL COMA..ETlON 06/18/98 SIDETRACK COMR..ETlON 02124/01 SIS-SLT CONVERTED TO CANVAS 03/03/01 SIS-MD FINAL 05/04/01 per K-17B ST Proposal PRUDHOE BA Y UNIT Wa.L: K-17B ST Proposed PERMIT No: 98-0610 API No: 50-029-22537-02 Sec.3,T11N,R14E BP exploration (Alaska) - - ___n _ __ 0____0__ _______.~____~~_________ _____ -_._--------~---------- -~- rei M5 K-17A Marker Depths @Orig Wellbore Top Lisb 8800 1 8,800 ft TVD Top Vertical Section Path Distance (Feet) 0 500 8300 8350 -- 8400 - 8450 - 8500 -- It 8550 - 8600 - 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 Top Kavik 8694 1 8,694 ft TVD Top ~ TD Wahoo 91751 9, 175 ft TVO TOW; 01 Olft TVD Angle @ K.O.= 92 deg MO:9800 K317b (Lisburne) case 1 06 June 29,2001 Ted x4694 Kick Off 8,527 ft TVD 9,800 ft MD 2,232 ft Deprtr @KO 8650 - 8700 ~ Top Kavik 8694 / MO KO Pt 9,800 - .... . 44 deg. MO New Hole 1130 Q) Q) !:;,a750 - c Total MD 10,930 ;:: 8800 -Top Lisb 8800 TVDTO 9,1 76 8850 DLS 8900 - deg/100 Tool Face Length Curve 1 12 145 20 ~ 8950 - Curve 2 12 160 250 Curve 3 12 -140 200 9000 - 12 -90 130 Curve 4 9050 - Curve 5 12 -90 200 Curve 6 12 90 200 9100 -. Tot Orld:1130 ft Curve 7 12 -90 130 :.~45 deg. angle 10930 TO 9150 - 1,130 - TO Wahoo 9175-· --...--....--.- 9200 - -- ---..----- - --------- ----- --- --------------- -------- --- --.' " --- ------.------ K31 7b (Lisburne) Case 106 500 ~ June 29, 2001 Ted x4694 r Well Name K-17A CLOSURE Distance 2,985 ft Az 83 deg NEW HOLE E/W (X) NIS (Y) Kick Off 2,216 74 TD 2,964 356 State Plane 674,435 5,975,577 Surface Lac 671,471 5,975,221 .~ K-17A 1,000 .. ~ ... DLS deg/100 Tool Face Length o~ .+.0 Curve 1 12 145 20 E -.-...-------'---'-. Curve 2 12 160 250 .g o~ Curve 3 12 -140 200 CI) . u 12 -90 130 c Curve 4 ca ~ Curve 5 12 -90 200 ~ >- Curve 6 12 90 200 Curve 7 12 -90 130 1 ,1 30 --/ -500 ~ -1,000 2,200 2,700 X distance from Sfe Lac 3,200 - ------ --- ----- Drawn: 7/1 9/2001 16:18 Plan Name: Case 1 22 I [ [ [ I '- ..... ...I .- __ Pipe/Slip ~ ~/~~~d - n rJ - HCR ~ JFLOW[ ~ ~ _~_] TEE [_~_~ ) 2 3/8" CT ----- 10,000 psi Pack-Off Lubricator~ ~ ~ - ~ I I r 7 1/16" Annular -r.....,.....,.....,~/ : ~/1.6: 5~ ?~i < Blind/Shear 71/16" r;';""''''''r-I~ ~7 ~~16~ ~ 5¡~ ~Si ~ c::::>... - - Pipe 7 1/16" Pipe/Slips ') Nordic 1 K317b CT Drilling & Completion BOP ~ -- _.. 2 3/8" ~ -1,- ..... J- ::::::r- _.. _.. VBR 2 3/8" SWAB OR MASTER VALVE ) ) ~~~~E :J !Æ~!Æ~~~~ ALASKA. OIL AND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. TH 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 99519-6612 Re: Prudhoe Bay Unit K-317B BP Exploration (Alaska) Inc. Permit No: 201-156 Sur Loc: 1440' SNL, 887' EWL, SEC. 22,T11N, R14E, UM Btmhole Loc. 349' SNL, 2572' EWL, SEC. 15, T11N, R14E, UM Dear Mr. Stagg: Please disregard previous letter. Enclosed letter is corrected to reflect correct well name ofK-317B. Enclosed is the approved application for permit to drill the above referenced well. The permit to drill 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 K-317B. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, ~~ Julie M. Heusser Commissioner BY ORDER OF THE~OMMISSION DATED this f3 ~ day of August, 2001 jj c/Enc1osures cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. 1 a. Type of work 0 Drill IBI Redrill ORe-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3280' NSL, 4078' WEL, SEC. 04, T11 N, R14E, UM At top of productive interval 3271' NSL, 858' WEL, SEC. 04, T11N, R14E, UM At total depth 3567' NSL, 1106' WEL, SEC. 04, T11 N, R14E, UM 1 b. Type of well ~k V" ~<¥i ~ o Exploratory 0 Stratigraphic Test IBI Development Oil o Service 0 Development Gas 0 Single Zone 0 Multiple Zone 5. Datum Elevation (DF or KB) 10. Field and Pool KBE = 59.8' Prudhoe Bay Field I Lisburne 6. Property Designation Pool ADL 028303 7. Unit or Property Name Prudhoe Bay Unit 8. Well Number K-317B 9. Approximate spud date 08/20101 Amount $200,000.00 14. Number of acres in property 15. Proposed depth (MD and TVD) 2560 10930' MD I 9176 TVDss 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} 920 Maximum surface 3510 psig, At total depth (TVD) 89001/4400 psig Setting Depth T~D Botom MD TVD MD TVD 8400' 8148' 10400' 8800' 10250' 8520' 10930' 9176' 11. Type Bond (See 20 AAC 25.025) ) STATE OF ALASKAì ALASKA OIL AND GAS CONSERVATION COMfvlo,..;t)ION PERMIT TO DRILL 20 AAC 25.005 Number 2S100302630-277 12. Distance to nearest property line 13. Distance to nearest well ADL 028300, 1712' MD No Close Approach 16. To be completed for deviated wells Kick Off Depth 9800' MD Maximum Hole Angle 18. Casin~ Program Specifications 517e Hol~ CasinQ WeiQht Grade CouolinQ LenQth 4-1/8" 3-3/16" 6.2# L-80 TCII 2000' 2-3/4" 2-3/8" 4.7# L-80 ST-L 680' Quantity of çement (include staç¡e data) 59 sx Class 'G' Uneemented Slotted Liner KFCE\VCO 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing 13982 feet 8736 feet 13050 feet 8770 feet Length Plugs (measured) JUL 2 5 2001 IBP set at 13050' (11/98) . . k 0·, & Gas Cons Commission Alas a I . Anchorage Junk (measured) Size Cemented MD TVD 260 sx Aretieset (Approx.) 110' 110' 1050 sx PF 'E', 375 sx Class 'G' 3707' 3703' 472 sx Class 'G' 8514' 8302' 235 sx Class 'G' 8337' - 13982' 8155' - 8736' Structural Conductor Su rfaee Intermediate Production Liner 80' 20" 3672' 10-3/4" 8482' 7-5/8" 5645' 4-1/2" 20. Attachments 12516' - 12576', 12650' - 12900', Open, Below Bridge Plug: 13310' - 13560', 13700' - 13890' true vertical 8754' - 8766', 8770' - 8766' Open, Below Bridge Plug: 8759' - 8724', 8721' - 8734' IBI Filing Fee 0 Property Plat IBI BOP Sketch 0 Diverter Sketch IBI Drilling Program IBI Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 0 20 AAC 25.050 Requirements Contact Engineer Name/Number: Ted Stagg, 564-4694 Prepared By Name/Number: Terrie Hubble, 564-4628 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Ted Stagg ~~.., .," Titl,e.....CT....D..,rill.i.ngE.ngineer t{7. CommISsion Use OnlY Date '1.>0/)1 Perforation depth: measured Permit Number 20/ -), 5"b Conditions of Approval: API Number AP~7~l(oatel See cover letter 50- 029-22537-02 () I 0/ ( for other requirements Samples Required 0 Yes ~ No Mud Log Required 0 Yes ŒI No Hydrogen Sulfide Measures BYes 0 No Directional Survey Required ~ Yes 0 No Required Working Pressure for BOPE 0 2K 0 3K 0 4K 0 5K 0 10K 0 15K ~5K psi for CTU Other: Approved By Form 10-401 Rev. 12-01-85 ORIGINAL SIGNED BY J. M. f-IAlIUAr Commissioner ORIG!~JAL by order of the commission Date 'ill ~) / {'\,/ S~bnlit In Triplicate ) ) BP K317b Sidetrack Summary of Operations: A CTD sidetrack of PBU K-17a will be drilled into the Lisburne (Wahoo) as a producer. The Lisburne will be isolated from the Ivishak by a drilling liner cemented across the Kavik shale. BOP equipment for pressure deployment of the drilling BHA and "dynamically overbalanced" drilling will be used from the start of the sidetrack. Initial drilling in Zone 1 and the Kavik will be done with 9.7 ppg Flo-Pro to provide increased hole stability through the Kavik. After cementing a drilling liner the Wahoo will be penetrated with the same 9.7 ppg Flo- Pro. If reservoir pressure exceeds 9.7 ppg then the dynamically overbalanced drilling technique will be employed. Lost circulation to Wahoo fractures is expected. LCM will not be used in order to minimize damage to the potentially productive Wahoo fractures. If losses are light then drilling will proceed with Flo-Pro. If losses are heavy then drilling will continue with 2% KCI. The Wahoo producer will be completed with a pre-drilled liner if lost circulation is minimal but will be completed open hole if losses are heavy. Phase 1: Isolate existing Zone 1 perfs with a CIBP, set a low side whipstock. Planned for August 13, 2001 · An MIT on the IA has been successfully performed. · The existing 4 Y2" tubing has been drifted. · The wellhead and tree valves will be tested. · Service coil will drift the 4 Y2" liner and set a cast iron bridge plug at approx. 9900' MD to shut off all existing Zone 1 perfs. · Service coil will set a through tubing whipstock for a low side window at approx. 9800' MD. Phase 2: Mill window, Drill and Complete CTD sidetrack: Planned for August 20,2001 · 23/8" drilling coil and 2% KCI will be used to mill a 3.8" window at approx. 9800' MD (8527ss). · 4 1/8" hole will be drilled with 9.7 ppg Flo-Pro to top Wahoo at approx. 10,400' MD (8800ss). · 33/16" liner will be cemented from top Wahoo to approx. 8400' MD (8148ss). · 2 JA" (or 3") hole will be drilled through the Wahoo. Initial drilling will be with 9.7 ppg Flo-Pro. · Wahoo completion will be either a 2 3/8" pre-drilled liner or open hole. Mud Program: · Phase 1: 20/0 KCI · Phase 2: 2% KCI and Flo-Pro (9.7 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: · 33/16" ,TCII, L-80, solid liner will be cemented from top Wahoo 10,400'md (8,800' S5) to approx. 8400' MD (8148' 5S). This liner will be cemented with approx. 12 bbl5 of 15.8ppg class G cement. Well Control: · BOP diagram is attached. · Pipe rams, blind rams and the CT pack off will be pressure tested to 300 psi and to 4000 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 log will be run over the open hole section. · A memory Induction log will be run over the Wahoo interval. Hazards The maximum H2S measured in produced fluids from Lisburne wells in this area is 50 ppm. Shale stability in the Kavik and lost circulation in the Wahoo are the primary drilling hazards. Reservoir Pressure P-50 estimated res. pressure is 4400 psi at 8900ss or 9.5 ppg. Maximum surface pressure with gas (0.10 psi/ft) to surface is 3510 psi. BP Exploration (Alaska) Prudhoe Bav Unit Well: K-17A API NO:50-029-22537 SEC 03,T11 N,R14E,UM OPEN OPEN 23/4" 4 13,310'- 13,560' 23/4" 4 13,700'- 13,890' 23/4" 4 12,516'- 12,576' Œ'EN 11/98 23/4" 4 12,650'- 12,900' OPEN 13,050 CTMD IBP SIZE SPF INTERVAL OPEN/SQZ'D PERFORATION SUMMARY IIBP set@ 13,050'CTMD I PBTD 113901' I \10750' I PBTO 110794' \ 5-1/2",17 #/ft, NT-80, NSCC DATE REV. BY COMMENTS 6/18/98 JONES/ LIDDELOW SIDETRACK / DOYON 14 11/7/98 WALKER/LUECKER SETIBP 11/21/98 BUNDY ADD PERFS 1~lt.f ;ì '~r,'~!~.~' h;·~\IJ&j:·1j ~'\~¡:¡f<t"'~'~i^:~:~~'t: .' : r .m'~''''Ù.f !~¡f,.".....~ ~î!~t;: ~\ SHOE 113982' I ~......................... .............. ~ELL HORIZONTIAL@9200' w.....··" ""...m....' ,...,.,._.e.·._ , I 'rii: B %';{ p I 8271' 1 1 8282' I 1 8306' 1 I 8327' I I 8339' 1 I I ELMD H.E.S. 4.5"X- NIPPLE 3.813"1.0. BAKER 7 5/8"S-3 PKR. 3.875"1.0. H.E.S. 4.5"X- NIPPLE 3.813"1.0. H.E.S. 4.5"XN- NIPPLE 3.725"1.0. WLEG ) KB. ELEV = 61.00' BF. ELEV= 31.75' H.E.S. 4.5"HXO SVLN I 2177' 1 3.813"1.0. ~ MERLA TMPDX 4.5"x 1 "GLMS MIN. J.D. 3.857" BK LATCHES NO. MD TVDss. DEV. 4 3072' 3006 6 3 5044' 4977' 0 2 6810' 6734' 16.7 1 8204' 7983' 34.6 1 II ~- :g L o K-17 A Baker I BP set at 10340' 18986' I 7-5/8", 29.7#/ft, L-80, NSCC 18825' I TOP OF 5-1/2" LINER 7 5/8"PKR. 4 1/2TBG. CUT @ 8605' I WINDOW 8514Z8526' I 8514' I WHIPSTOCK 4 1/2"LINER 12.6# L-80 3.958"I.D. CAP.= .0152 TIW S-6 LINER PKR & OTH - S LINER HANGER I 8337' \ I 8347' 1 TIE-BACK SLEEVE 4-1/2", 12.6#/ft, L-80, NSCT TUBING ID: 3.958" CAPACITY: .0152 BBLlFT MAX. ANGEL OF TBG. 340 ANNULUS CAP: .0262 BBLS/FT. -~ 13707' 1 10-3/4",45.5 #/ft, NT-80, BTC TREE: 4" CIW WELLHEAD: FMC ACTUA TOR:BAKER ) 4"CrN FMC BAKER ) K317B ) PROPOSED CTD SIDETRACK TREE = . W8.LHEAD= . ""''''''.''''"''''''''''''..,~,""".,".'."."", ,,,,,......'... ".... ..'. òCTUA TOR= '....""..-"".",..,,,..,.,,'..,,,,.....,,',.....,,..'"'. KB. ELEV = ",,',,-, ".."."".,,,.,,,,, "'"",',,.., "'...." BF. ELEV = KOP= ...~~..~~~¡~;" Datum MD = Datum TVDss= 31.75 8550 .'.....,....,..."....,..,.,-",.."...,,,,.,,'.,,..,,.........,.. .. ..1g~~1 ~~!~ 13313 8800' - 110-3/4" CSG, 45.5#, NT80, ID=9.953 1-1 3707' ~ L I :8: I :& t ~ I I r 4-1/2" TBG, 12.6#, L80, .0152 bpf, ID=3.958 \-1 8339' I I TOP OF 4-1/2" LNR 1-1 8347' I 2s: ~ ÆRFORA TION SUMMARY REF LOG: MEMDRY NEU. CNL ANGLEATTOPÆRF: 180 @ 12516 Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 23/4 4 12516-12576 0 11/21/98 2 3/4 4 12650-12900 0 06/17/98 23/4 4 13310-13560 0 11/07/98 2 3/4 4 13700-13890 0 11/07/98 8514' I-ITOPOFWHIPSTOCK \ I 7-5/8" CSG, 29.7#, L80, ID=6.875 1-1 8986' 1----'" 15-1/2" LNR, 17#, NT80, .0232 bpf, 10=4.892 \-110794'1 2177' 1-14-1/2" HES HXO SVLN NIP, ID=3.813" ~ GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LTCH SIZE 4 3072 3006 1 MERLA TMPDX BK 4-1/2 3 5044 4977 1 MERLA TMPDX BK 4-1/2 2 6810 6734 15 MERLA TMPDX BK 4-1/2 1 8204 7983 34 MERLA TMPDX BK 4-1/2 8271' \-14-1/2" HES 'X' NIP, ID=3.813" I 8282' 1-17-5/8" x 4-1/2" BKR S-3 PKR, ID=3.875 I 8306' 1-14-1/2" HES 'X' NIP, ID=3.813" I 8327' \-14-1/2" HES 'XN' NIP, ID=3.725 8337' 1-1 TIE BACK SL V I 8339' 1-14-1/2" WLEG, ID=3.958 I 8347' \-1 TrN S-6 LNR PKR & DTH-S LNR HGR I 8400' 1-1 Top of Proposed 3-3/16" Liner I 9800' 1-1 Mill Window off Mechical Whipstock 9900' 1-1 Proposed CIBP Placement 113050'1~ \ I 4-1/2" LNR Shoe 1-1 13982'/ 1 3-3/16" TC II Liner - Cemented 1-1 10300' I 2 3/8" pre-drilled liner or open hole DA TE REV BY COMMENTS 06/18/98 02124/01 SIS-SL T 03/03/01 SIS-MD 05/04/01 pcr ORIGINAL COMPLETION SIDETRACK COMPLETION CONVERTED TO CANVAS FINAL K-17B ST Proposal \-1 10930'1 PRUDHOE BA Y UNIT W8.L: K-17B ST Proposed ÆRMIT No: 98-0610 APt No: 50-029-22537-02 Sec. 3, T11 N, R14E BP Exploration (Alaska) rei M5 Vertical Section -- ._._-------~ K-17A Path Distance (Feet) o 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 8300 , \ \ í i i I 8350 8400 8450 - 8500 - 8550 - 8600 - 8650 - 8700 ~ Top Kavik 8694 - ..... cv cv !t.8750 c ~ 8800 -Top Lisb 8800 8850 8900 - 8950 - 9000 - 9050 - 9100 - 9150 - ·,TD Wahoo 9175· 9200 1 Angle @ K.O.= 92 deg MD:9800 K317b (Lisburne) case 1 06 June 29,2001 Ted x4694 ... ~ \ '" / I . 44 deg. Tot Drld:1130 ft 10930 TO <=,~~~",_~L~~- de~.~an~:__ ==~~_ =~~ -- --_._----~ Marker Depths @Orig Wellbore Top Lisb 8800 I 8,8001ft TVD Top Top Kavik 8694 I 8,6941ft TVD Top ~ TD Wahoo 91751 9,1 751ft TVD TDW. 01 0lft TVD Kick Off 8,527 ft TVD 9,800 ft MD Deprtr @KO 2,232 ft ---. MD KO Pt MD New Hole 9,800 1130 10,930 9,176 DLS deg/100 Tool Face Length 12 145 20 .~ 12 160 250 12 -140 200 12 -90 130 12 -90 200 12 90 200 12 -90 130 1 ,1 30 Total MD TVDTD Curve 1 Curve 2 Curve 3 Curve 4 Curve 5 Curve 6 Curve 7 K-17A I Well Name K-17A 1,000 - CLOSURE Distance 2,985 ft Az 83 deg NEW HOLE E/W (X) N/S (Y) Kick Off 2,216 74 K317b (Lisburne) Case 1 06 500 - June 29, 2001 TD 2,964 356 Ted x4694 State Plane 674,435 5,975,577 Surface Lac 671,471 5,975,221 ~> 0 . 0 DLS ..J 0 deg/100 Tool Face Length o~ -+-¢' Curve 1 12 145 E ----~~~~ 20 0 0- l Curve 2 12 160 250 J:: Q) Curve 3 0 12 -140 200 c: ca +-' Curve 4 12 -90 130 U) :c >- Curve 5 12 -90 200 Curve 6 12 90 200 Curve 7 12 -90 130 1 ,130 -500 - ~ -1,000 2,200 2,700 X distance from Sfc Loc 3,200 - -- --- Drawn: 7/1 9/2001 16:18 Plan Name: Case 122 r [ [ r .... L..I...... .- __ Pipe/Slip ~ ~/~~~d - - n rJ - HCR ~ JFLOW[ ~ ~ ~JTEE[~~ - - -- ) 2 3/8" CT ~ 10,000 psi Pack-Off Lubricator~ ~ ~ i11 ~ r 7 1/16" Annular '-- , ~r-Ir-Ir-I~ ~ ~ ~/1.6~ 5?~O ~~i ~ Blind/Shear 7 1/16" ~I"""II"""II"""I~ ~7 ~~16:o ~ 5:qoq ~Si~ D... - - Pipe 71/16" Pipe/Slips ') Nordic 1 K317b CT Drilling & Completion BOP ~ -- -~ 2 3/8" ~ -, t I- L..I -' D- -~ -~ VBR 2 3/8" SWAB OR MASTER VALVE · tIIÞ bp June 26th, 2001 Gary Limb Phillips, Inc. 700 G St. Anchorage, AK. 99510 ) k317- ß yeA.r VA 1\ t v,. ¿~.w..!.. . Exxon Company, USA 3301 C Street, Suite 400 Anchorage, AK. 99519 Subject: Lisburne ~ LK-17B Rig Sidetrack Gentlemen ) BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 o Technical approval is requested for a planned sidetrack of K-17 A. The incremental rate profile and reserves justifyingLK-17B are attached. The drilling cost estimate is $1.37 million, PSO Incremental reserves of 1.3mmstb are expected at a cost of 1.05 $lbbl. A preliminary spud date of August 20th has been programmed for this well; any technical questions can be referred to Michael-James Hey, Daniel Schafer or Mike Helton at (907) 564-5294, 5098 or 4108. Regards, Anne L. Shaw Greater Point McIntyre Area (GPMA), Team Leader Attachment: LK-17B Coil Tubing Sidetrack Technical Package LK-17B Statement of Requirement cc: Ted Stagg: Lamar Gantt: Michael Johnson Dwight Warner: Paul Taylor: Michael-James Hey: Mike Helton: Daniel Schafer: Richard Tawse Coil Tubing Drilling Coil Tubing Drilling GPB Drilling Coordinator (X OM) Petroleum Engineer Reservoir Engineer Reservoir Engineer Geophysicist Geologist Commercial Summary ) ) The LK-17B sidetrack offers the opportunity for additional reserves to be accessed in the upper Lisburne Wahoo formation. Successful production from this sidetrack will increase confidence in the methodologŸ employed to select the LK-17B location. Furthermore, successful extrapolation of such methodology has the potential to add up to 1600bbls a day and additional recoverables of up to 5.2mmbbls by side tracking 4 wells to areas of increased producti vi ty. Additional business and strategic objectives for this well are; · To deliver a step change in cost structure for Lisburne penetrations · Prove use of coil tubing drilling in Lisburne field, (Rotary drilling used to date) · Prove application of solids free drilling fluid in Lisburne Wahoo formations · Access large un-drained Western Wahoo Extended Area (WWEA) · Confinn WWEA reservoir pressure at or near virgin Lisburne reservoir pressure · Evaluate Seismic identification and preferential well azimuth process · Deliver a LI-31100k-a-like based on well perlonnance K17 A watered out in late 2000 and is presently shut-in on K-pad. The well is not a viable side track candidate for the Prudhoe Bay Field. However, due to it's unique location, a low cost coiled tubing deepening can take it into the unexploited Lisburne Western Area where it can potentially match the production success of the recent LI-31 well (Reference attachment 1.0). LK-17B is expected to encounter 400 feet of un-drained naturally fractured carbonate in the upperLisburne Wahoo formation. P50 Annual A verage incremental production rates and ultimate recoverable volumes are estimated at 394bbls/d and 1.3 mmbbls. Extensive seismic reprocessing and log correlation has driven the upper LK-17B well target and wellbore profile. This sidetrack will be drilled with a 3 3/4" hole out of the 7 5/8" Liner with a KOP at 8514':MI)SS. 3 3/16" casing will then be run across the Kavik shale and tied back into the original 7 5/8" casing. A 3.0" hole will then be drilled to TD and a 2 7/8" slotted/pre-drilled liner will be run across the reservoir and tied back into the original 4.5", 12.6# wellbore tubing. The expected P50 cost for this well is $1.37 MM resulting in a $/bbl cost of $1.05. ) ) Reservoir Discussion: Lisburne is a carbonate reservoir that has only produced 120 mmbbls of it's estimated 3-5 billiQ...IlSTOllP. The field is located below a three-way dip closure and extended fault to the North, this in turn, is overlaid by the Kavik Shale. Reservoir development started in 1985 and continued to late 1997 when a combination of disappointing flow rates and high GOR's led to the cessation of all well work. Subsequently the most prolific wells were either flowed continuously, or cycled in order to maximize Oil and minimize GOR rates through the LPC (Lisburne Production Facility). Lisburne competes with the Pt McIntyre, Niakuk, North Prudhoe Bay and West Beach fields for space in the LPC. Initial studies in 1997 concluded that the majority of the Lisburne production came from the upper naturally fractured Wahoo interval and that the reservoir was compartmentalized in the South East (IA area). Declining Pt McIntyre production in late 1999 ignited new interest in Lisburne, this ultimately resulted in the LI-31 well. Although the original LI-31 lower Lisburne Alapah formation failed to perform, production rates from the Upper Wahoo target matched top quartile performance for the field. ·As a result extensive seismic and log studies have been performed in order to identify reasons for the LI-31 success. The LK-17B well location is based upon the conclusion of these studies, details of which are presented herein. Selection ofK-Pad The Prudhoe Bay field overlies the Western area of the Lisburne field; as such deepening one of the shut-in K pad wells, versus a stand-alone project saves significant cost. In addition, resultant Oil flow from LK-17B will be directed through the K-pad GC1 processing facilities. The GC1 facilities have a lower incremental oil rate than the LPC facilities thus increasing the lOR and return on investment from the well. Log Rationalisation Study & Production Profiles A detailed investigation into the relationship between known well performance, log porosity, well bore deviation, azimuth and producing horizon concluded that there was no clear predictive method for differentiating between good and poor wells based on actual well log data. However, some correlation was noted between well azimuth and enhanced productivity (Ref Attachment 2.0) which is believed to be due to common fracture system trending from the SE to NW of the field. This has been further corroborated by an earlier Lisburne study as detailed in SPE paper 18174. After grouping all the known production and incremental Oil volumes for each of the Western Area wells, it was possible to perform a probability simulation to establish the P90, 50 and 10 estimated ultimate recoverables and production profiles for a new penetration into the Lisburne formation (Ref Attachment 3.0 & 4.0 a,b,c). This simulation did not take into account the new tools such as, improved seismic prediction for identifying areas of enhanced production, wellbore azimuth, separation of the Western Area through geochemistry data and absence of known upper Wahoo gas bearing intervals. As such it represents a conservative estimate, all production profiles have been adjusted for Gas net-debit at the Prudhoe Bay GC-l gathering facility. ) ) Geophysical Discussion: A top Lisburne structure map detailing the LK-I7B sidetrack can be seen in Attachment 5.0 wi!!t_ the location annotated as LK-I7Bwp6. The orientation of the arbitrary well seismic line (Ref Attachment 6.0) constructed along the proposed well trajectory is depicted in red with the drilling target polygon in pink. This location will test an upthrown 3-way structure (Ref Attachment 7.0) about 200 ft. SW of an east-west trending, down-to-the-north fault. The Top Lisburne structure should be encountered at a depth of -8800 ft. tvdss with an vertical uncertainty of +/- 40 ft. Assuming a lateral positioning uncertainty of 110 ft. could place the fault in the well bore near TD. Attachment 8.0 is an arbitrary seismic profile along the same orientation as the well seismic line in Attachment 5.0. The color scale shows the strength of the amplitude associated with the positive (peak) event associated with the Top Lisburne. Stronger amplitude values trend toward the red and yellow colors while weaker amplitudes trend toward the green color. Within the ellipse, the weak amplitudes are visible for a lateral distance of about 1000 ft. Observation of other Lisburne well locations indicate better production associated with these low amplitude zones in the Top Lisburne interval, potentially through enhanced fracture porosity. Although the seismic dataset had an amplitude-friendly, partial pre-stack migration applied to improve fault imaging, it is noted that close fault proximity may cause diminished amplitude response. Attachment 9.0 is the Total Sample Energy calculated from the bandlimited Acoustic Impedance data volume for a 30 ms interval below the Top Lisburne. The Total Sample Energy (EOY) calculates the total energy of samples bounded by two horizons at each live trace. Total energy is defined as the sum of the squares of the samples. This 30 ms interval is depicted on Attachment 8.0 by the area between the blue and pink horizons. Higher values of EOY are shown in the hotter colors and relate to stronger amplitude values within the interval while lower values of EOY are shown in cooler colors to white and relate to weaker amplitude values within the interval. Poor correlation of log impedance to seismic impedance (discussed later) suggests a probable correlation of low amplitude (low EOY) to the presence of fracture porosity. Areas near faults may have lower amplitude (lower EOY) values due to poor imaging and accurate amplitude preservation rather than an increase in fracture porosity. Seismic inversion of the udgd3d data set was used to estimate the acoustic impedance and porosity between well locations. The purpose of the inversion was to derive a porosity map of Top Lisburne as an indicator of the best areas for the sidetrack. The impedance-porosity transfonn was derived from well log data. Crossplots of acoustic impedance and porosity logs from 26 wells from Top Lisburne to Wahoo Zone 4 showed a good and consistent linear trend (Ref Attachment 10). Seven wells had enough sonic and density data for wavelet estimation. The wavelets show good lateral consistency of phase of the data of 25-30° (Ref Attachment 11). The consistency of the wavelets show that it is meaningful to apply seismic inversion with a single derived wavelet. The chosen wavelet was an average of three wavelets estimated from the vertical wells with the longest sonic and density logs. Well correlations of seismic and synthetic data show good match in the Shublik and lower Lisburne fonnation. However, Top Lisburne does not match well in amplitude or phase for any of the wells. Attachment 12 shows an example for well L2-06. The reason for the poor correlation is not understood, but fractures in Lisburne may playa role. The poor match of acoustic impedance at Top Lisburne gives errors in the derived porosity as also seen in Attachment 10. We conclude that the udgd3d seismic data set is not a reliable indicator of porosity for Top Lisburne. In addition, cross plots of well porosity and production data showed no correlation; hence, fractures or well completions are assumed to be the important components for productivity. .,.1iI ) ) Geological Discussion: Attachment 13 is a log section from well L2-06. The L2-06 well shows the Log Model output ~f Lithology, Water Saturation, Porosity and Penneability. Common lines of 40% Sw, 10% porosity, and 5 md of penneability are superimposed on the log for reference. This well is cored and highlights the core (symbols) to log (curves) match, which served as the core standard in building the log model. Zonal net to gross values (net = > 10% porosity = Pay Flag» are identified opposite the uppennost stratigraphic zones. Zones 1-3 have very low net to gross values. The base of Zone 4 is the equivalent stratigraphic TD of the proposed K-17B well. Attachment 14 is a structural cross section showing the relationship of the proposed K-17B well to the deepest logged IP A wells and the furthest west LPA wells. The top of the Wahoo Fm is correlated along with the base of Wahoo Zone 4. The prospective Lisburne section is expected in Zones 4 -7 with the top of Zone 7 prognosed at -8800 feet. The field aoc (-8600) and the OWC (-9150) are highlighted on the cross section. Attachment 15 shows net to gross maps for zones 4 -7. The map from zone 7 reflects the Pre-Echooka Unconfonnity truncation of the uppennost Wahoo interval (zone 7). The net to gross maps are included to show the areas of increased "storage capacity" or reserves. It is important to note that the area around the K-17B proposed well is not populated by any well data. The concept of targeting the Lisburne further off structure to avoid fractures that may be tied into the gas cap is also supported in Attachment 16. Attachment 16 shows net to gross values (Zone 4, furthest off-structure) from wells correlated to their cumulative and estimated ultimate recovery (EUR). As the Log Rationalization discussion above spoke to no clear correlation between porosity (net / gross) and production, this plot does show a rather good correlation to those L-2 wells in zone 4. This further helps mitigate the risk associated with not encountering conductive fractures. This data from zone 4 in the L-2 area seems to suggest that there is a correlation between net to gross (porosity) and production at this horizon and hence fractures may not be needed to attain Wahoo production. Logging requirements: Sperry-Sun real time Gamma Ray and a PDS post drilling Memory Induction Resistivity log will be run in the LK- 17B wellbore. A contract well-site geologist will be on location during all drilling operations. Risk Discussion: As with all well operations, a certain amount of safety, production and cost risk is always present. LK-17B will be drilled within the parameters of safe working practice as established on the slope over many years. The Production risk has been identified by the P90, 10 and 50 expected flow rate and estimated ultimate recoverable values as presented herein. The APE number of $1.37m is based upon a P50 cost estimate and will be closely tracked during the drilling operation, any likely overrun will be highlighted and fonnally discussed with partners. .dÆ_/.~~ ._, ~ /-I'? L 1-31 Production History 9000 2000 8000 ="-- Oil ~ - 1800 ~-~ Gas -c- 1 600 7000 6000 t~ ¡. - 1400 I i I - 1200 ~ 5000 ... ~ C LL - 1 000 ~ (.) ~ 4000 .,¡ m - 800 3000 ,r ;/~- I - 600 2000 ~ . r - 400 513 MBO Produced to Date ~J 1000 I - 200 0 0 I I I I . I I 8/<8/79 7</6/79 3/7$/<0 6/<3/<0 70/7/<0 7/9/<00 4/79/<0 //<8/<0 99 99 00 0000 7 07 07 '. ) ) Lisburne Well Azimuth vs Known Cumulative Production 5980000 ~ 'õ ë= Q) en Q) 0:: .E = nl - co c =e o o (.) > 5955000 675000 685000 690000 700000 680000 X Co-ordinates in Reservoir 5984000 5968000 - 5966000 . . 5964000 682000 684000 686000 688000 690000 692000 694000 696000 698000 700000 702000 704000 X Co-Ordinate in Rese rvoir Stress fracture study as detailed in SPE paper 18174 notes a general fracture direction from NW to SE. Hence wells trending in a SW to NW tend to cum greater production from the field. This data is supported by the associated plots and log rationalization study. NB (This is not a 100% correlation can be used with seismic and other work to increase chance of successful well) IIlæ1-/41eúf ~·o Structural Cross Section Through K-17B Proposed Well West Lisburne (Wahoo) -- Structural Cross Section Ll-31 I ~ ,~Ä":~) - -'''f,:'''' ~t'~· . ~ ~ --=-= .,. ~ :..:.: ~~ .-= f ~ := . ¥;- ~t:- ~-~- - ~ ~.~ _~r~__ ~ .,--.~. 0' ~:. E-6 .~~. i i : r:¡r~~ :.¡ " I~ IhoIt_H_I\4, K-17B ._~ --..... L2-29 L2-06 _______º-'Y..~:2.12.CL '- 8500' ~ 4686' 8874' 7462' Distance between wells ¡I Distance along section ~ 8500' 13186' 22060' Distance from K-17B to LI-31 producer 39677' = 7.51 Miles = Total Section Distance IRcmotefschafcdb'dbs _wahoo _ xsec.edit 6950' 29522' 3205' 36472' I f 39677' I#/~ /{;. Ø-;Ødl/~ø/~ C/o white to greenish colors indicate low EGY value /' ~. C I - -/ ... West to East Seismic Profile vvith Well Trajectory for LK -17Bvvp6 o 0- I K-17 A/LK-17Bwp6L 1350 I I I I I I ' I L 11400 I - 1 500 , , \ , ~.!!~ ~ ÞÞÞ~¡¡I( it!¡ ~\ ~~Wf I.ï'ï'ï'~'~~r' (,)~) ¿I: '( i (,..~..~ } w( \" (/ i L I~~~I \,' ( · ( ) ~ <r~)1 (I ' I ( < {N)i ( ,¿ ¿¿ Æ ~ ~ ~ w< " ' ')) ¿ ¿ ~ 1\ I :{ «((<<? ) \..~ ) )) t n~u 'nÜìlà.l~ U l ( I( (( ( ~, I~ \ «(~(,{(,(((~( (I (((((( ) )~[.,} ÄTr 0 \ \, I \ I) I )) (u : ( « t.f I ( ~ ( ~ ~ í )55 ') ~) " "\) ..., L I " }))( )!( } ll' ,\. · »»( « J ,(.( ~~¿<~))( »<) '( ~{(~~ ~(, ~ " ~ T. Sad þ I ~~, {" I ), ») ( ( . ( ) N (I , \, ~ ;~ ~ ~( ~.Þ ""1!~ 0 t¿ )) ),~ tt "~ ~ ~ ~ ~~«( :,~ ( ~ .<.< Tr q .tc«/ «(( ~\\ ~þ ~\.Y-mñ'~' ~ ~,~~~~ ~»~ ~( ,~'(~(~~' ),~ " .( r((( ",l ' , / ,( Þ ~/ ~ );)/ }!< )?I~«)< T. Sad ~.~ ~ i ~1: ~ ~ ~ 11 :«<~ r~H~ ~(); ( « ) .~ (~\lP"~ '~. ..((((q .( ~ ... ~~ ~)' ), ( \\~ <. ,( r' ~ '\ ì Ii, J' :( ( 1 "lolf1'" , ~"l"·--' _ 111 ")' I<~, r t I ~ (~. Lisb J ( ( ( ( ( r ~ L - L. '\ . ~ 1'0 ~~ , I~ ... '.. I ' I #i . , '- t-r-T . ~/. ..}", þ:---'-jJr h -.'~ '/// ',r"'''~~· ~.~~ ï/ ~ '-'1"" .- - --.4(' 'J~-':,~,,--.. ~ ~ UII IÇJ J J /IJ/~;lt~~/lJl.I"/'N~:! _ [L .(j' {/ ({IIJ't J '/~/~ (\ ,( ~"c.... . I tll\...-' III ~,'/'I(f/'I/I. S'\\ ",\ W\\...~ ~ lt~ » I), )), .(, ") }»)) I\I( ( ~( oTcfiSb~ - 2000 1(\ \"" ,\.~ ~ to ~ (~ ." " " .~ ~ < ~ · t ) ~ t ,), .. ... I Vfi¡¡~r~ '( '()) ) (( / ()~{ ~. ~ l' '1'1"(( '( ,( ~~ ~ ~ ~ ~);l~~ I r(f'((rM (¡({( \\:\(l\«(\)\ J ~j~(~) )( ( ~.< / ) ~~()~»} ~~; :?ç<,< < )~~I r ){1~1J1(~\¡. - ~ , ;, IC ,(ì \\~\ \\, 1 , '. þ ( ,< ~ ) 9 (' ,I ((W\" « «,(C~~ ,;)/~)) {H¿J .( ~t-'((~ ~' ~ ',' I I ,',t . Þ . l')) r( '. þþ' Þ \\,., ( ':C\(~~~~«'\ ~()/?)(I,~ ~ '~~. J' , ., \nN)<~(," ~.~. .þ J't·\. ~~., ,,, (') II, 'It' n'" IT~" I\~))))¡{/;( ( ~\l\\ ~~~~(~~H~ "tl\t( It fl\«(((~~\([(1 .( ('(~((\',\~f\(~{(I\~((((((( ·' j~l~~~\~!«(i( /u~))/~{~«(~.lll; -- ~ aitm_ban01.3dv W I< ~ 646' XLINE 1781 E /J~~ r~ ) ) It ; ~~... H 193324 DATE 07/06/01 CHECK NO. 00193324 /f~" .' DATE INVOICE / CREDIT MEMO DESCR!PTION GROSS VENDOR DISCOUNT At ARK-AnItA NET 00 070201 CK070201K PYMT COMMENTS: HANDLING INST: 100.00 100.00 Pernit to Qrill Fee S/H - Terrie Hubble X4628 or Sandra Steuman X4750 \\·3\1ß :: ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL ~ 100 00 100 00 BP EXPLORATION, (ALASKA) INC. P.O. BOX 196612 ANCHORAGE, ALASKA 99519·6612 FIRST NATIONAL BANK OF ASHLAND AN AFFILIATE OF NATIONAL CITY BANK CLEVELAND. OHIO No~H 193324 CONSOLIDATED COMMERCIAL ACCOUNT 56"389 --¡:j"2 00193324 P'AY ,':- '", :"'{.':",.," >,";"'" , , : ,.,..;: ";', ::,..:::, :;':>::r ',:':, <':::':',.:;:, ':\::' :'\ ',' ::',,::::;:: :',:<:';";, :,.,.,::,::).': '::"::",::"~ O~E.HuNDRED 8< OO/10(j~***,************~.*;i*~~*~*********** u.~. DöLLAR To The ORDER Of .ALASKA OIL AND GAS CONSERVATIQNCOMMISSION 333.·.·WEST 7TH AVENUE SUITE 100 ANCHORAGE AK 99501 . ··DATE/ Q?/(j6/01 ···ÄMOUNT $100.<.OQ NQTVALlD AFTER 120 DAYS " ;,":', ':",,: ..",:'" "::::::-: ' ~,~.ÍYß~~ /II ~ ., :I :I 2 L. /II I: 0 ~ ~ 2 0 :I a ., 5 I: 0 0 a ~ ~ ~., 1/1 ... JANSMIT AL LETTER CHECK LI~ A) CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSNUTTAL LETTER WELL NAME CHECK 1 STANDARD LETTER DEVELOPMENT CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If api number last· two (2) digits are between 60-69) DEVELOPMENT REDRD..L / PILOT HOLE (PH) EXPLORATION ANNUL~ ANNULAR DISPOSAL INJECTION .WELL <-> YES INJECTION WELL RED RILL ANNULAR DISPOSAL THIS WELL r\L-)\Ì\. ') "CLUE" The permit is for a new wellbore segment of existing well ~ Permit No, API No. Production should continue to be reported as a function of the original API number stated above. In accordance with 20 AAC 25.005(t), all records, data and 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). Annular disposal has not been requested. . . Annular Disposal, of drilling wastes will not be approved. . . Annular Disposal of drilling wastes will not be approved. . . DISPOSAL INTO OTHER Please note that an disposal of fluids generated. . . ANNULUS <-> YES + SPACING EXCEPTION Templates are located m drive\jody\templates Enclosed is the approved application for permit to drill the above referenced well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) will assume the liability of any protest to the spacing exception that may occur. ffj Ú{ WELL PERMIT CHECKlIST¡4 ~ COMPANY ~ fJ WELL NAME 1:- 3/7 (j PROGRAM: exp _ dev .2L redrll -2L- serv _ wellbore seg _ann. disposal para req _ FIELD & POOL t:£./t?}~¢r9 INITCLASS /J<".-./ /"'ð/) GEOLAREA ?5'o UNIT# ð/JhSn ON/OFFSHORE 0...) ADMINISTRATION 1. Pennitfee attached. . . . . . . . . . . . . . . . . . . . . . . Cf¿ N 2. lease number appropriate. . . . . . . . . . . . . . . . . . . ~ N ,d 3. Unique well name and number. .. . . . . . . . . . . . . . . . ¥:. N 1-1 I? 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . N I J¡ 5. Well located proper distance from drilling unit boundary. N ~,,// 6. Well located proper distance from other wells.. . . . . . . . . 21l N 7. Sufficient acreage available· in drilling unit.. . . . . . . . . . . z::;& NN' 8. If deviated. is wellbore plat included.. . . . . . . . . . . ... . c;:t¿ 9. Operator only affected party.. . . . . . . . . . . . . . . . . . ~~ N~ 10. Operator has appropriate bond in force. . . . . . . . . . . . . 11. Pennit can be issued without conservation order. . . . . . . . 12. Pennit can·be issued without administrative approval.. . . . . ~ N 13. Can permit be approved before 15-day wait.. . . . . . . . . . Ú) N 14. Conductor string provided . . . . . . . . .. . . . . . . . . . Y Nl 15. Suñace casing protects all known USDWs. . ., . . . . . . . Y N " -~..L.....\. - (\ . ~\'\:t'--~ ~~ \ \ 16. CMT vol adequate to circulate on conductor & suñ csg. . . . . Y N '') \ö~'(:-~",..,.: -:> 17. CMT vol adequate to ,tie-in long string to suñ csg. . . . . . . . ;:t N, 18. CM~will co:,erall known productive horizons. . . . .'~ . . . . ~ ~~\\'\Cé a~ ~~"'\>~-\~"- 19. Casing designs adequate for C. T. B & permafrost. . . . . . . ' N l ~ L 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . ,N f:~~~ ~ s.!:~a ~~fu't' ~\ '\' 21. If a re-drill, has a 10-403 for abandonment been approved. . . N ~O \ -~ \ -~ 22. Adequate well bore separation proposed.. . . . . . . . . . . . Y N 23. If diverter required. does it meet regulations . . . . . . . . . . ~ ~ 24. Drilling ,fluid program schematic & equip list adequate. . . . . IN 25. BOPEs, do they meet regulation . . . . . . . \~. . ~ . . N t\ C"\ ~. 0' 26. BOPE press rating appropriate; test to ~ psig. N "'~c;~ ~~ ~ ~ C:;\Ç ~ " 27. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N \ 28. Work will occur without operation shutdown. . . . . . . . . . . K t::'.. '" fJ', _. <:'\ I' . I\; {\ 29. Is presenceofH2Sgas probable.. . . . . . . . . . . . . . .. . Y ®\1\~~~~\(J~\~e ~ot'\.~" ,¿,'S~~~~~~- ~~~~u"'-~ 30. Permit can be issued w/o hydrogen sulfide measures. . . .,. )(N 31. Data presented on potential overpressure zones . . . . . . . Y·· A' 32. Seismic analysis of shallow gas zones. . . . . '. . . . . . . . N ~. I AJ~~ JJI'!~ 33. Seabed condition survey (if off-shore). . . . . . . . . . . . . . N ' <t1~{. ,~d-/ 34. Contact name/phone for weekly progress reports [exploratory 0 1 Y N 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. . . ~~~ce; , (C) will not impair mechanical integrity pf the well used for disposal; Y N (0) will not damage producing formation or impair recovery from a Y N pool; and (~) will not circumvent 20 MC 25.252 or 20 MC 25.412. Y N GE~GY: ENGINEERING:,' UI£/Annular COMMISSION: ~Þö'v ~ ~m WM 'KM~SH rllf. i;¡ 1~M IB-s1):{?i'-t.. Jí ð/ ~;/ ~ APPR .._9A!ß ð?J ff1s'fð/ ENGINEERING ~ Itt^<{E GEOLOGY APPR DATE r-l/;)/ ,.f' k- / /' A fcc ßJ~_ 0.//",/ weß) 7-7r/ ,d-- /;!;r,/N"H_ ,-,,/ rl ~Æ'k c o z ( o -4 ~ ::0 -4' m -' Z -4 ::I: " en > ::u .( m » Y N Y N c:\msoffice\wordian\diana\checklist (rev. 11/01/100) N.~~ '? ~~~ // ------" ~ ~\\,,,-~b, - ------ .- - Comments/Instructions: ) ) Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Pennitting Process but is part of the history file. To inlprove the readability of the Well History file and to simplify finding infomlation, infonnation of this nature is accumulated at the end of the file under APPEN.DIX. No special effort has been made to chronologically organize this category of information. ) **** REEL HEADER **** MWD 03/03/01 BHI 01 LIS Customer Format Tape **** TAPE HEADER **** MWD 03/03/01 409691 01 2.375" CTK *** LIS COMMENT RECORD *** ) ~OI-15tp { 15 71 ! ! !!!! !! !! ! !!! !!!!! Remark File Version 1.000 ! ! !!! !!! !! ! !!! !!!!! Extract File: ldwg.las -Version Information VERSo 1.20: WRAP. NO: -Well Information Block #MNEM.UNIT Data Type #--------- ------------- STRT.FT 10355.0000: STOP.FT 11935.0000: STEP.FT 0.2500: NULL. -999.2500: COMP. COMPANY: WELL. WELL: FLD . FIELD: LOC . LOCATION: W CNTY. STAT. SRVC. TOOL. DATE. API . -Parameter #MN"EM. UNIT #--------- COUNTY: STATE: SERVICE COMPANY: TOOL NAME & TYPE: LOG DATE: API NUMBER: Information Block Value CWLS log ASCII Standard -VERSION 1.20 One line per frame Information ------------------------------- Starting Depth Ending Depth Level Spacing Absent Value BP Exploration (Alaska), Inc. K-317B Prudhoe Bay Unit 70 deg 20' 17.432" N 148 deg 36' 30.917" North Slope Bourgh Alaska Baker Hughes INTEQ 2.375" CTK 22-Jan-03 500292253702 ------------------------------- ------------------------- Description SECT. TOWN.N RANG. PDAT. EPD .F LMF . FAPD.F DMF EKB . F EDF .F EGL .F CASE.F OS1 . 4 11N 14E MSL o RKB 59.8 KB 59.8 N/A N/A 10357 DIRECTIONAL Section Township Range Permanent Datum Elevation Of Perm. Datum Log Measured from Feet Above Perm. Datum Drilling Measured From Elevation of Kelly Bushing Elevation of Derrick Floor Elevation of Ground Level Casing Depth Other Services Line 1 liner OS2 . -Remarks (1) All (2) All (3) All ( 4 ) The shoe depths are Measured Depths (MD) unless otherwise noted. depths are Bit Depths unless otherwise noted. Gamma Ray data presented is realtime data. 2.75" hole section of K-317B was drilled from the 3 3/16" ) PRESSTEQ I other Services Line 2 at 10357' MD (8807' SSTVD) to TD at 11935' MD (8770' SSTVD) on Run 19. (5 ) (6 ) Circulating Baker Hughes Inteq utilized CoilTrak downhole tools and ADVANTAGE surface system. Tools ran in the string included CCL, Electrical Disconnect and pressure, sub, a Drilling Performance Sub (inner and outer downhole Directional downhole weight on bit, down hole temperature), a Gamma and sub, and an Orienting sub with a near bit inclination sensor. (7) The data presented here is final and has not been depth shifted to a PDC. The Baker Hughes INTEQ MWD GR is PDC (Primary Depth Control) on this portion of the wellbore (per BPXA Petro Technical Data Center) . The interval from 11906' MD (8770' SSTVD) to 11935' MD (8770' (8 ) SSTVD} was not logged, due to sensor to bit offset. (9) Tied into Schlumberger Slim Pulse - Gamma Ray Log spud date 27- Dec-02. MNEMONICS: GRCX -> Gamma Ray MWD-API [MWD] (MWD-API units) ROPS -> Rate of Penetration, feet/hour SENSOR OFFSETS: RUN GAMMA 3 23.61 ft. 4 23.61 ft. 5 29.28 ft. 7 29.28 ft. 8 31.02 ft. 9 29.09 ft. 10 29.28 ft. 11 29.11 ft. 12 29.10 ft. 13 29.10 ft. 14 29.11 ft. 15 29.10 ft. 16 29.30 ft. 17 29.30 ft. 18 29.30 ft. 19 29.30 ft. EOZ END Tape Subfile: 1 Minimum record length: Maximum record length: **** FILE HEADER **** MWD .001 1024 DIRECTIONAL 22.39 ft. 24.46 ft. 28.20 ft. 28.20 ft. 29.94 ft. 28.01 ft. 28.20 ft. 28.03 ft. 28.02 ft. 28.02 ft. 28.03 ft. 28.02 ft. 28.20 ft. 28.20 ft. 28.20 ft. 28.20 ft. 82 records... 10 bytes 132 bytes feet **** FILE TRAILER **** 10355.000000 11934.750000 0.250000 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 76 Total Data Records: 8 ------- 4 4 API F/HR GR ROP 1 1 68 68 MWD MWD 4 4 Size Length Name Tool Code Samples Units 2 Curves: 1 2 Tape depth ID: F 0.250 * F ONE DEPTH PER FRAME FRAME SPACE = Data record type is: 0 Datum Frame Size is: 12 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 * FORMAT RECORD (TYPE# 64) 0.0 0.0 GRCX ROPS GR ROP ---------------------------------------------------- GR ROP ODEP *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 The data presented here is final and has not been depth shifted to a PDC (Primary Depth Control). The Baker Hughes INTEQ MWD GR is PDC on this portion of the wellbore (per BPXA Petro Technical Data Center) . *** LIS COMMENT RECORD *** calgary.xtf 150 BP Exploration (Alaska), Inc. K-317B Prudhoe Bay Unit North Slope Bourgh Alaska WDFN LCC CN WN FN COUN STAT -------------------------------------- *** INFORMATION TABLE: CONS MNEM VALU ) ') '. FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size Length 1 GRCX MWD 68 1 API 4 4 2 ROPS MWD 68 1 F/HR 4 4 ------- Data record type is: 0 Datum Frame Size is: 12 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 * FORMAT RECORD (TYPE# 64) 0.0 0.0 GRCX ROPS GRCX ROPS GRCX ROPS ---------------------------------------------------- ODEP *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ! !!! !! ! !!! ! ! ! ! !! !!! Remark File Version 1.000 The data contains the unedited field raw data. *** LIS COMMENT RECORD *** calgary.xtf 150 BP Exploration (Alaska), K-317B Prudhoe Bay Unit North Slope Bour Alaska WDFN LCC CN WN FN COUN STAT -------------------------------- *** INFORMATION TABLE: CONS MNEM VALU 1024 MWD .002 **** FILE HEADER **** 54 bytes 4124 bytes Minimum record length: Maximum record length: 85 records... Tape Subfile: 2 ) ) , . ) Total Data Records: 76 Tape File start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 10355.000000 11934.750000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 3 85 records... Minimum record length: Maximum record length: 54 bytes 4124 bytes **** TAPE TRAILER **** MWD 03/03/01 409691 01 **** REEL TRAILER **** MWD 03/03/01 BHI 01 Tape Sub file: 4 2 records... Minimum record length: Maximum record length: 132 bytes 132 bytes ) 8 ) ) Tape Subfile 1 is type: LIS ) Tape Subfile 2 is type: LIS DEPTH 10355.0000 10355.2500 10400.0000 10500.0000 10600.0000 10700.0000 10800.0000 10900.0000 11000.0000 11100.0000 11200.0000 11300.0000 11400.0000 11500.0000 11600.0000 11700.0000 11800.0000 11900.0000 11934.7500 GR 35.5568 37.6988 9.7405 11.2271 10.2181 6.5219 14.2447 14.6130 7.5497 11. 5915 25.6854 19.2155 17.6959 21.3182 23.7980 20.8159 20.7675 51.5716 -999.2500 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units ) ROP -999.2500 -999.2500 13.8769 10.2846 11.9143 0.8000 7.4000 18.8000 38.4000 37.7000 24.4000 14.7000 13.9000 15.5000 13.1000 7.4000 15.3000 22.6000 -999.2500 10355.000000 11934.750000 0.250000 feet ) ) Tape Subfile 3 is type: LIS DEPTH GRCX ROPS 10355.0000 35.5568 -999.2500 10355.2500 37.6988 -999.2500 10400.0000 9.7405 13.8769 10500.0000 11.2271 10.2846 10600.0000 10.2181 11.9143 10700.0000 6.5219 0.8000 10800.0000 14.2447 7.4000 10900.0000 14.6130 18.8000 11000.0000 7.5497 38.4000 11100.0000 11.5915 37.7000 11200.0000 25.6854 24.4000 11300.0000 19.2155 14.7000 11400.0000 17.6959 13.9000 11500.0000 21. 3182 15.5000 11600.0000 23.7980 13.1000 11700.0000 20.8159 7.4000 11800.0000 20.7675 15.3000 11900.0000 51.5716 22.6000 11934.7500 -999.2500 -999.2500 Tape File Start Depth 10355.000000 Tape File End Depth 11934.750000 Tape File Level Spacing 0.250000 Tape File Depth Units feet ~ " ) ) Tape Subfile 4 is type: LIS
