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Home My WebLink About192-080Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov December 29, 2025 Mr. Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: OTH-25-044 Notice of Violation - Closeout Failure to Notify of Changes to Approved Permit Kuparuk River Unit 2M-07 (PTD 1920800) Dear Mr. Hobbs: The Alaska Oil and Gas Conservation Commission (AOGCC) sent a notice of violation and request for information (Notice) to ConocoPhillips Alaska, Inc. (CPAI) on October 28, 2025, for changes to an approved program or activity without AOGCC approval. The AOGCC reviewed CPAI’s response to the Notice dated November 7, 2025, and the steps taken to prevent recurrence. CPAI has satisfied the request made in the Notice and the AOGCC does not intend to pursue any further enforcement action regarding this violation. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: Phoebe Brooks (AOGCC) Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.12.29 14:32:29 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.12.29 14:41:48 -09'00' November 7, 2025 Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Comm’n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Gregory Wilson Commissioner Alaska Oil and Gas Conservation Comm’n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 VIA E-MAIL (samantha.coldiron@alaska.gov) Re: Docket No. OTH-25-044 Notice of Violation (NOV) – Failure to Notify of Changes to Approved Permit Request for Information (RFI) Kuparuk River Unit (KRU) 2M-07 (PTD 1920800) Commissioners Chmielowski and Wilson: On October 28, 2025, the AOGCC sent the above-referenced NOV and RFI (Notice) to ConocoPhillips Alaska, Inc. (CPAI). The Notice states that on July 28, 2025, without AOGCC approval, CPAI implemented a “substantive change” (referencing 20 AAC 25.507(a)) from the steps in the AOGCC-approved sundry for operations on KRU well 2M-07. Specifically, the Notice states, “by backing out the tubing hanger lockdown screws and attempting to relieve tubing compression by allowing the tubing to expand against casing jacks. These actions were undertaken before nippling up BOPE, contrary to the approved Sundry procedure.” The Notice requires CPAI “to provide the AOGCC with what has or will be done in the future to prevent this violation’s recurrence.” Very early Monday morning, July 28, in normal workover operations on 2M-07, following tree removal, CPAI discovered significant upward subsidence compression force on the adapter flange. In our many decades of operations, CPAI had not previously observed this level of subsidence compression force on the adapter flange, and after unsuccessfully attempting to counteract the compression, CPAI paused operations. This pause was safe and appropriate because we had previously confirmed the well was dead, having tested the mechanical integrity of the downhole barrier (draw down test on production plug and packer). However, even though the well was dead, before proceeding with non- Scott Kolstad Intervention & Integrity RWO CTD Manager 700 G Street, ATO 1470 Anchorage, AK 99501 (907) 265-6347 (office) Scott.Kolstad@conocophillips.com By Samantha Coldiron at 6:16 am, Nov 12, 2025 2 emergent workover operations, CPAI internal procedures required two barriers for this well. The upward compression on the adapter flange had potentially compromised our second barrier (at surface), so CPAI sought internal approval to proceed. CPAI’s planned fix included backing out the tubing hanger lockdown screws to allow the safe expansion of the casing and tubing under casing jack pressure, in order to allow us to set the BOPE. However, we failed to recognize that the approved sundry procedure required us to set the BOPE before backing out the tubing hanger lockdown screws. Because we did not recognize that our plan reversed this part of the approved sundry sequence, we also did not recognize that we needed AOGCC verbal approval to proceed. However, as soon as our internal plan approvals were obtained Monday evening, we attempted to reach the AOGCC engineer at 5pm and 7:15pm to brief him. Those attempts were unsuccessful, and we commenced our remedial operation. Later that night, the AOGCC engineer responded and instructed us to pause operations, and we immediately stood down the rig. After further conversations with AOGCC Tuesday July 29, we received AOGCC approval of our plan, and CPAI fixed the compression issue and continued with normal operations. CPAI has identified several lessons learned. First, early engagement with the AOGCC engineer Monday morning, when we discovered the subsidence compression issue and began to formulate our remedial plan, would have drawn attention to the previously approved sundry sequence, and AOGCC approval of the sequence change could have been quickly obtained. Second, although CPAI was not aware of this at the time, the AOGCC engineer in this case had previously encountered a similar, though much more severe, subsidence compression issue at Prudhoe Bay and could have shared that expertise. Third, we identified a gap in our technical procedures to address similar subsidence compression issues. Regarding these lessons, CPAI has refreshed and intensified our focus on proactive AOGCC engagement. On October 16, 2025, CPAI noted upward subsidence pressure on the 1E-11 adapter flange, and we obtained AOGCC approval before proceeding. Although the actual compression force was determined to be much less than 2M-07, early AOGCC engagement allowed us to more quickly address the issue and proceed with normal workover operations. CPAI also has modified our written workover procedures for similar wells, as follows: When ND tubing head adapter flange, back off nuts from the adapter flange to ensure they can move.ଉ Tighten the nuts back up to make contact with the flange face but allow them to remain loose.ଉ Backoff and retighten all nuts independently. ଉCheck the tightness of the loosened nuts after removing all but two and determine if force was transferred to the loosened nuts.ଉ Repeat this for the last nut.ଉ If at any time it is determined that force is found to be transferred back to the loosened nuts, STOP.ଉ Call RWO ENGR and swap well over to KWF before continuing to ND. After ND is completed and BOP’s are installed the well can be swapped back to SW 3 if mechanical barriers areଉin place and the well passes a 30 min no flow to SW. ଉIf no additional tightness is observed, continue ND as planned. We are confident that these steps will prevent recurrence of the issues addressed in the Notice. If there are further questions or requests, please do not hesitate to reach out. Sincerely, Scott Kolstad Intervention & Integrity RWO CTD Manager ConocoPhillips Alaska, Inc. Digitally signed by Scott Kolstad DN: OU=Intervention & Integrity RWO CTD Manager, O=ConocoPhillips, CN=Scott Kolstad, E=Scott.Kolstad@ConocoPhillips.comReason: I agree to the terms defined by the placement of my signature in this document Location: Anchorage, AK Date: 2025.11.07 13:38:48-09'00' Foxit PDF Editor Version: 13.1.6 Scott Kolstad Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov October 28, 2025 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7018 0680 0002 2052 9839 Mr. Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: OTH-25-0 Notice of Violation (NOV) – Failure to Notify of Changes to Approved Permit Request for Information (RFI) Kuparuk River Unit (KRU) 2M-07 (PTD 1920800) Dear Mr. Hobbs: KRU development well 2M-07 was drilled in September 1992 and completed in July 1993. An Application for Sundry Approvals Form 10-403 (Sundry) 325-352 was approved by the AOGCC on July 23, 2025, to perform a rig workover to repair subsurface subsidence damage. Step 3 of the "Rig Work" section of the approved Sundry required the operator to set a back pressure valve (BPV), nipple up blowout prevention equipment (BOPE), and conduct pressure testing. During operations, CPAI encountered an issue in which the tubing head adapter (THA) could not be removed due to tubing compression caused by subsidence-related forces. These forces had sheared the tubing hanger lockdown screws, resulting in upward tubing movement under the THA. CPAI proceeded under its internal single-barrier waiver process and deviated from the approved procedure by backing out the tubing hanger lockdown screws and attempting to relieve tubing compression by allowing the tubing to expand against casing jacks. These actions were undertaken before nippling up BOPE, contrary to the approved Sundry procedure. The AOGCC was notified of the change in well operations on July 28, 2025, after deviations from the approved Sundry had already occurred. Per 20 AAC 25.507, an operator may not undertake a substantive change to an approved program or activity without AOGCC approval. 20 AAC 25.507(a) further describes the information that must be submitted to AOGCC. To make a change, the well’s current condition and proposed change must be provided to AOGCC for review and approval. Docket Number: OTH-25-051 Notice of Violation October 28, 2025 Page 2 of 2 Within 14 days of receipt of this letter, you are requested to provide the AOGCC with what has or will be done in the future to prevent this violation’s recurrence. This information request is made pursuant to 20 AAC 25.300. Failure to comply with this request will be an additional violation. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Questions regarding this notice should be directed to Jack Lau at 907-793-1244. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: Jack Lau Jim Regg Phoebe Brooks AOGCC Inspectors Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.28 09:52:56 -08'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.10.28 13:41:51 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Replace Tubing Development Exploratory Stratigraphic Service 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10340'feet None feet true vertical 6127'feet 1809', 7775', 10252'feet Effective Depth measured 10252'feet 7218', 7369'feet true vertical 6126'feet 5685', 5775'feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth)2-7/8" 3-1/2" L-80 J-55 7339' 8034' 5758' 6037' Packers and SSSV (type, measured and true vertical depth)7218' 7369 5685'' 5775' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Kuparuk Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 3262'2773' Burst Collapse 10294' Casing 6127'10333' 3220' 121'Conductor Surface Production 16" 9-5/8" 79' measured TVD 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 192-080 50-103-20178-00-00 P.O. Box 100360 Anchorage, AK 99510 3. Address: ConocoPhillips Alaska, Inc. N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: 7. Property Designation (Lease Number): ADL0025586,ADL0025589 Kuparuk River Field/ Kuparuk Oil Pool KRU 2M-07 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) N/A Gas-Mcf MDSize 121' Well Shut-In 325-450 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Packer: SLB Blue Pak Packer: BAKER HB Retrievable SSSV: None Adam Klem adam.klem@conocophillips.com (907) 263-4529Staff RWO/CTD Engineer 8110-8150', 8170-8250', 8400-8490', 8560-8700', 8790-9100', 9480-9520', 10000-10070' 6053-6061', 6065-6081', 6099-6105', 6106-6107', 6109-6116', 6121-6121', 6121-6122' Fra O s 6. A PG , g Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 1:20 pm, Sep 02, 2025 Digitally signed by Adam Klem DN: CN=Adam Klem, E=adam.klem@ conocophillips.com, C=US Reason: I am approving this document Location: Date: 2025.09.02 12:30:43-08'00' Foxit PDF Editor Version: 13.1.6 Adam Klem DSR-9/11/25J.Lau 11/4/25 RBDMS JSB 090425 Page 1/5 2M-07 Report Printed: 9/2/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 7/27/2025 08:00 7/27/2025 09:00 1.00 MIRU, MOVE RURD P Rig down and pull pits away from sub, prep moving system pulll sub off well for 2M-07 0.0 0.0 7/27/2025 09:00 7/27/2025 10:00 1.00 MIRU, MOVE RURD P Prep around well for spotting rig 0.0 0.0 7/27/2025 10:00 7/27/2025 16:00 6.00 MIRU, MOVE RURD P Spot rig over well, level up and shim rig, ensure centered over well, Spot pits aginst rig spot rig mats under modules and rig 0.0 0.0 7/27/2025 16:00 7/27/2025 17:00 1.00 MIRU, MOVE RURD P Safe out rig, prep for taking on fluids, perform rig accept checklist Rig Accepted @ 16:30 on 7/27/25 0.0 0.0 7/27/2025 17:00 7/27/2025 22:30 5.50 MIRU, WELCTL CIRC P R/U Take on S/W Fill system Test Lines T/ 2500 psi All Good IA 125 psi and tubing 125 Bleed off System T/ 0 Stat pumping W/ 25 bbls clean sweep 8.6 S/W Down Tubing and Take Returns T/ Out side tiger tank Through choke Manifold.Tot Pump 340 BBLS S/W Shut Down Monitor Well F/ Flow 30 Mins No Flow All Good 0.0 0.0 7/27/2025 22:30 7/27/2025 23:30 1.00 MIRU, WELCTL WWSP P Blow Down System and Set FMC BPV and Test T/ 1000 psi All Good 0.0 0.0 7/27/2025 23:30 7/28/2025 00:00 0.50 MIRU, WHDBOP NUND P N/D FMC Tree 0.0 0.0 7/28/2025 00:00 7/28/2025 06:00 6.00 MIRU, WHDBOP NUND T Remove Tree and as we were Attempt to moveTubing adapter W/ FMC Hand started growing upward and shut down and Notice 1 LDS were Shear off Call well Head Hand in W/ cameron Tools Decision was made to Attempt to Pull down w/ plates to secure hanger so we could N/U Tree Test Flange T/ 250 T/2500 PSI T/ pump down Kill wt Fluids Down Tubing and IA W/ 9.4 Kill wt Fluids so we could Grow and Stretch Order Fluids 9.4 KWF 600 bbls 0.0 0.0 7/28/2025 06:00 7/28/2025 20:00 14.00 MIRU, WHDBOP WAIT T Wait for plan forward from town **** Start of Dispensation Work ***** 0.0 0.0 7/28/2025 20:00 7/28/2025 22:00 2.00 MIRU, WHDBOP OWFF T AS Plan Peform 30 mins NFT Cont N/D Tree ND THA using Cameron subsidence jacks ND THA using Cameron subsidence jacks, back out LDS and allow tubing hanger to grow with THA. 0.0 7/28/2025 22:00 7/29/2025 00:00 2.00 MIRU, WHDBOP OWFF T Cameron Needs to Add to Jacks Call Engineers in town T/get Approval No go Wait on State F/ Apporval @ 0900 AM on the 7-29-25 7/29/2025 00:00 7/29/2025 09:00 9.00 MIRU, WHDBOP OWFF T Cameron Needs to Add to Jacks Call Engineers in town T/get Approval No go Wait on State F/ Apporval @ 0900 AM on the 7-29-25 Be on Call. AOGCC halted operations and told not to proceed until after 09:00 in person meeting during office hours. 0.0 0.0 7/29/2025 09:00 7/29/2025 10:00 1.00 MIRU, WHDBOP OWFF T Rig up jacks on well head. 0.0 0.0 7/29/2025 10:00 7/29/2025 13:00 3.00 MIRU, WHDBOP OWFF T Wait on orders from town. 0.0 0.0 7/29/2025 13:00 7/29/2025 15:30 2.50 MIRU, WHDBOP CUTP P Control grow tubing 17-7/8". Cut tubing and LD tubing hanger. 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 8/4/2025 Page 2/5 2M-07 Report Printed: 9/2/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 7/29/2025 15:30 7/29/2025 17:15 1.75 MIRU, WHDBOP NUND P NU BOPE 0.0 0.0 7/29/2025 17:15 7/29/2025 18:00 0.75 MIRU, WHDBOP BOPE P Shell test BOP's to 1800 PSI for 5 minutes. 0.0 7/29/2025 18:00 7/29/2025 18:45 0.75 MIRU, WHDBOP FISH P Attempt to engage tubing with spear and packoff. pack off would not drift tubing. Pulled spear to floor packoff was damaged beyond repair. 7/29/2025 18:45 7/29/2025 23:15 4.50 MIRU, WHDBOP WAIT T Process tubing in pipe shed while waiting on smaller grapples and short catch overshot with pack off. 7/29/2025 23:15 7/30/2025 00:00 0.75 MIRU, WHDBOP RURD T RU overshot to DP engage overshot on top of cut. RU to circulate. 7/30/2025 00:00 7/30/2025 01:30 1.50 MIRU, WHDBOP CIRC T Circulate in 9.4# NaCl SxS 3BPM at 180 PSI 9.4# in and out. Dispensation ended when we got 9.4 ppg NaCl KW fluid all the way around at 01:30. 0.0 0.0 7/30/2025 01:30 7/30/2025 02:00 0.50 MIRU, WHDBOP OWFF T OWFF for 30 minutes. No flow at surface 0.0 0.0 7/30/2025 02:00 7/30/2025 05:00 3.00 MIRU, WHDBOP CUTP T RU Cameron casing de-tensioning tool and grow casing. Casing grew 56". Observe casing for growth for 30 minutes. RD Cameron tools. RU wachs saw and cut casing. 0.0 0.0 7/30/2025 05:00 7/30/2025 09:00 4.00 MIRU, WHDBOP CUTP T Let casing relax for 30 minutes then RD casing de-tensioning tool. Remove old tubing spool. Cut 7" casing with Wachs cutter. Connection at wellhead, break connection and remove cut joint. NU tubing spool and adapter. 0.0 0.0 7/30/2025 09:00 7/30/2025 10:30 1.50 MIRU, WHDBOP NUND P NU BOP stack on well head. 0.0 0.0 7/30/2025 10:30 7/30/2025 16:00 5.50 MIRU, WHDBOP RURD P BWM open doors, clean, inspect and take pictures. Change rams to 2-7/8 x 5" on top and 7" fixed rams on bottom. 0.0 0.0 7/30/2025 16:00 7/30/2025 21:00 5.00 MIRU, WHDBOP BOPE P Initial BOPE test, Tested BOPE at 250/2500 PSI for 5 Min each, Tested annular on 2-7/8" and 7" test joints, UVBR's, w/2-7/8", 3-1/2" and 4" test joint. LPR's on 7". Test blinds rams. Upper IBOP and lower top drive well control valves. Test 3 1/2" HT-38 safety valve, FOSV, and IBOP. Test 2" rig floor Demco kill valves. Test manual and HCR kill valves & manual and HCR choke valves. Test two ea. 2 1/6" gate auxiliary valves below LPR. Perform accumulator test. Initial pressure=3100 PSI, after closure=1650 PSI, 200 PSI attained =15 sec, full recovery attained = 122 sec. UVBR's= 6 sec, Annular= 26 sec. Simulated blinds= 6 sec. LVBR’s=6 sec. HCR choke & kill= 1 sec each. 5 back up nitrogen bottles average = 2100 PSI. Test Witness Waived by AOGCC rep Sean Sullivan 0.0 0.0 7/30/2025 21:00 7/30/2025 22:15 1.25 PROD1, WELLPR NUND P Empty out stack, pull test plug and riser, ND BOP's. 0.0 7/30/2025 22:15 7/30/2025 23:30 1.25 PROD1, WELLPR WAIT T Wait on overshot to pull casing in tension. 7/30/2025 23:30 7/31/2025 00:00 0.50 PROD1, WELLPR RURD P MU overshot BHA to joint of DP. Rig: NABORS 7ES RIG RELEASE DATE 8/4/2025 Page 3/5 2M-07 Report Printed: 9/2/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 7/31/2025 00:00 7/31/2025 02:30 2.50 PROD1, WELLPR CUTP P Overshot 7" casing work up to 145K over blocks. Stretched casing 15.25". Set slips w/145K on slips. RU Wachs saw and cut casing to install pack off and tubing head. Installed primary 7" intermediate casing packoff. 7/31/2025 02:30 7/31/2025 03:30 1.00 PROD1, WELLPR NUND P NU tubing head and BOP's. Installed wear ring in tubing head. 7/31/2025 03:30 7/31/2025 04:00 0.50 PROD1, WELLPR PRTS P Test intermediate casing packoff to 3000 PSI for 10 minutes. 7/31/2025 04:00 7/31/2025 04:15 0.25 PROD1, WELLPR BHAH P MU spear to DP. 7/31/2025 04:15 7/31/2025 04:30 0.25 PROD1, WELLPR FISH P Engage spear in tubing. Pull 135K W/blocks (Blocks weight=30K) weight broke back to 100K. 7/31/2025 04:30 7/31/2025 05:00 0.50 PROD1, WELLPR OWFF P OWFF for 30 minutes. 7/31/2025 05:00 7/31/2025 07:45 2.75 COMPZN, RPCOMP PULL P POOH laying down old 4" completion spooling up control line. SSSV with 6.0" OD pulled out of the hole with out a hicup. No damaged tubing. 7,334.0 5,422.0 7/31/2025 07:45 7/31/2025 08:00 0.25 COMPZN, RPCOMP RURD P RD control line spooler and release Halliburton. 5,422.0 5,422.0 7/31/2025 08:00 7/31/2025 14:15 6.25 COMPZN, RPCOMP PULL P Continue POOH laying down old 4" completion from pre-rig cut at 7,334', spooling up control line. SSSV with 6.0" OD pulled out of the hole with out a hicup. No damaged tubing. 5,422.0 0.0 7/31/2025 14:15 7/31/2025 14:45 0.50 PROD1, WELLPR PULD P Talley and drift 6 Drill Collars. 0.0 0.0 7/31/2025 14:45 7/31/2025 15:15 0.50 PROD1, WELLPR CLEN P Clean and clear rig floor to MU BHA #5 0.0 0.0 7/31/2025 15:15 7/31/2025 15:45 0.50 PROD1, WELLPR SVRG P Service rig power tongs and draw works. 0.0 0.0 7/31/2025 15:45 7/31/2025 16:30 0.75 PROD1, WELLPR PRTS P Close Blind rams and PT 7" casing to 2500 psi for 30 minutes. 0.0 0.0 7/31/2025 16:30 7/31/2025 18:00 1.50 PROD1, WELLPR BHAH P MU clean out dress off BHA. 0.0 235.0 7/31/2025 18:00 7/31/2025 23:00 5.00 PROD1, WELLPR PULD P Single in the well F/235' T/7200' PUW= SOW= 235.0 7,200.0 7/31/2025 23:00 7/31/2025 23:30 0.50 PROD1, WELLPR REAM P Wash and ream from 7200' T/7300 60RPM TQ=4.4K PR=3BPM @ 420 PSI. 7,200.0 7,300.0 7/31/2025 23:30 7/31/2025 23:45 0.25 PROD1, WELLPR PULD P Continue in hole F/7300' T/7313' PUW=142K SOW=102K 7,300.0 7,313.0 7/31/2025 23:45 8/1/2025 00:00 0.25 PROD1, WELLPR MILL P Establish milling parameters Rot wt=118K 60 RPM 4.5K Tq. PR=3 BPM 480 PSI Mill down F/7313' T/7315' 7ES RKB Wahsed over stump to 7321' swallowed stump 6' 7,313.0 7,321.0 8/1/2025 00:00 8/1/2025 01:00 1.00 PROD1, WELLPR CIRC P Circulate 25 BBL sweep SxS at 7BPM 1700PSI 7,321.0 7,321.0 8/1/2025 01:00 8/1/2025 02:15 1.25 PROD1, WELLPR PRTS P Pressure test casing to 2500 PSI for 30 minutes after cleaning and reaming casing and dressing off tubing stump. Bled off pressure form test, RD testing equipment and blew down surface lines. 7,321.0 7,321.0 8/1/2025 02:15 8/1/2025 06:30 4.25 PROD1, WELLPR PULD P POOH F/7321' T/235 7,321.0 235.0 8/1/2025 06:30 8/1/2025 08:00 1.50 PROD1, WELLPR BHAH P LD DC's and BHA. 235.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 8/4/2025 Page 4/5 2M-07 Report Printed: 9/2/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/1/2025 08:00 8/1/2025 10:00 2.00 PROD1, WELLPR RURD P RU to run 2-7/8" completion. Pull wear bushing. Load the rest of the jewelery into the pipeshed. 0.0 0.0 8/1/2025 10:00 8/1/2025 10:30 0.50 COMPZN, RPCOMP SFTY P PJSM to Run 2-7/8" completion. 0.0 0.0 8/1/2025 10:30 8/1/2025 19:30 9.00 COMPZN, RPCOMP PUTB P Run 2-7/8" completion per tally. Apply Jet lube Run-N-Seal pipe dope torque to 2,250 ft-lbs. Max running speed for SLB packer per rep is 75 fpm. Located top of tubing stump sheared pins saw 8K weight broke back. traveled 3.5' set down 10K. PUW=72K SOW=57K 0.0 7,334.0 8/1/2025 19:30 8/1/2025 20:30 1.00 COMPZN, RPCOMP HOSO P Space out completion MU tubing hanger and landing joint to string. 7,315.0 7,315.0 8/1/2025 20:30 8/1/2025 22:15 1.75 COMPZN, RPCOMP CIRC P Line up to pump CI. closed in UPRS. Circulated down IA taking returns up the tubing. Pumped corrosion inhibited seawater SxS 3 BPM at 880PSI. 8/1/2025 22:15 8/1/2025 22:45 0.50 COMPZN, RPCOMP THGR P Land tubing hanger RILDS. 8/1/2025 22:45 8/2/2025 00:00 1.25 COMPZN, RPCOMP PRTS P Attempted to set packer, pressured tubing up to 3800 PSI for 30 minutes. Bled pressure back to 1500 PSI. Isolated tubing. Pressured up on IA to 2500 PSI, tubing tracked with IA. 8/2/2025 00:00 8/2/2025 00:45 0.75 COMPZN, RPCOMP PRTS P Land hanger, RILDS, Drop B&R (1-5/16" ball x 109" long roller rod w/o rollers. Pressure up on tubing to set packer T/3900 PSI, hold for 30 minutes. Good test.Bleed TBG down to 1500 psi and pressure up IA to 2500 psi and TBG PSI equalized. Trouble shoot setting the packer to 4300 psi as per SLB rep. 0.0 0.0 8/2/2025 00:45 8/2/2025 03:45 3.00 COMPZN, RPCOMP RURD T RD test Equipment, prep landing joint w/FOSV. Prep for wireline. 0.0 0.0 8/2/2025 03:45 8/2/2025 05:00 1.25 COMPZN, RPCOMP SLKL T RU SL unit and MU catcher. 0.0 0.0 8/2/2025 05:00 8/2/2025 06:00 1.00 COMPZN, RPCOMP SLKL T RIH with SL and set catcher on top of the ball and rod. POOH to surface. 0.0 0.0 8/2/2025 06:00 8/2/2025 08:30 2.50 COMPZN, RPCOMP SLKL T RIH and pull SOV F/Mandrel at 3138'. Install DMY valve in same mandrel. 0.0 0.0 8/2/2025 08:30 8/2/2025 09:30 1.00 COMPZN, RPCOMP MPSP T PT tubing to 3000 psi. Holding good. Bleed tubing to 1500 psi and attempt to PT IA T/2500 psi and tubing tracked the IA pressure. 0.0 0.0 8/2/2025 09:30 8/2/2025 14:00 4.50 COMPZN, RPCOMP SLKL T RIH and replace DV at 6896', first two attempts failed. No latch on valve. On the third attempt the the valve pulled and was replace. Also had driller PT tubing to 3000 psi for 5 minutes to verify GLM DVs are holding. 0.0 0.0 8/2/2025 14:00 8/2/2025 15:00 1.00 COMPZN, RPCOMP CIRC T Pump down IA taking returns up tubing to verify circulation. Half barrel per minute returns at 500 psi. 0.0 0.0 8/2/2025 15:00 8/2/2025 21:00 6.00 COMPZN, RPCOMP SLKL T RIH with SL and pull catcher on top of the ball and rod. POOH to surface. Pull DMY valve iin Sta #3 set HFCV. RD Slickline clear tools off floor and Move off. 0.0 0.0 8/2/2025 21:00 8/2/2025 21:30 0.50 COMPZN, RPCOMP SVRG T Service top drive C/O gripper blocks on backup wrench 0.0 Rig: NABORS 7ES RIG RELEASE DATE 8/4/2025 Page 5/5 2M-07 Report Printed: 9/2/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/2/2025 21:30 8/2/2025 22:45 1.25 COMPZN, RPCOMP CIRC T Circulate seawater SxS 3.5 BPM at 800 PSI. 0.0 8/2/2025 22:45 8/2/2025 23:15 0.50 COMPZN, RPCOMP PULL T BOLDS. Pull hanger to floor PUW=100K Broke over to 80K. 8K drag over PUW when RIH. 8/2/2025 23:15 8/3/2025 00:00 0.75 COMPZN, RPCOMP RURD T Set floor up to stand back tubing. 8/3/2025 00:00 8/3/2025 05:00 5.00 COMPZN, RPCOMP TRIP T TOOH F/7339.3' T/surface. Inspected packer at surface, lower slips were expanded upper slips did not shear. 7,339.3 0.0 8/3/2025 05:00 8/3/2025 06:00 1.00 COMPZN, RPCOMP RURD T RD floor clear and clean after TOOH. Unload GLM's for trasport to SLB for valve replacement and testing. clean floor prep to run completion 0.0 0.0 8/3/2025 06:00 8/3/2025 06:30 0.50 COMPZN, RPCOMP BOPE T Perform weekly BOP function test. 0.0 0.0 8/3/2025 06:30 8/3/2025 15:30 9.00 COMPZN, RPCOMP CLEN T Clean and send excess handling equipment and subs off the rig floor. 0.0 0.0 8/3/2025 15:30 8/3/2025 18:00 2.50 COMPZN, RPCOMP WAIT T Wait for SLB GLM's to pass pressure test and arrive on location. Put away food order that was placed. 0.0 8/3/2025 18:00 8/3/2025 18:30 0.50 COMPZN, RPCOMP SFTY T PJSM to run completion. Verify running order, GLMs and packer were in order in pipe shed. Inspect equipment condition. 8/3/2025 18:30 8/4/2025 00:00 5.50 COMPZN, RPCOMP PUTB T Start RIH w/2-7/8" completion per tally T/6230'. 8/4/2025 00:00 8/4/2025 01:00 1.00 COMPZN, RPCOMP TRIP T Con't RIH F/6230' T top of stump at 7336' ORKB tag stump set down 8K sheared out pins saw 3.5' of travel. 8/4/2025 01:00 8/4/2025 01:30 0.50 COMPZN, RPCOMP HOSO T Space out completion. 8/4/2025 01:30 8/4/2025 02:00 0.50 COMPZN, RPCOMP THGR T MU tubing hanger and landing joint to string RU to reverse circulate. 8/4/2025 02:00 8/4/2025 03:45 1.75 COMPZN, RPCOMP CIRC T Circulate corrosion inhibited seawater down IA up tubing SxS at 3 BPM 615 PSI. 8/4/2025 03:45 8/4/2025 04:15 0.50 COMPZN, RPCOMP PUTB T Land tubing hanger, RILDS. drop ball and rod. 8/4/2025 04:15 8/4/2025 05:30 1.25 COMPZN, RPCOMP PACK T Pressure test tubing to 3800 PSI for 30 minutes. Bleed tubing back to 1500 PSI. Pressure IA to 2500 PSI for 30 minutes. Bleed tubing down sheared open SOV. 8/4/2025 05:30 8/4/2025 06:00 0.50 COMPZN, RPCOMP RURD P RD from testing blow down surface lines and pump. 0.0 0.0 8/4/2025 06:00 8/4/2025 06:45 0.75 COMPZN, WHDBOP MPSP P Set BPV and PT from below to 1000 psi for 10 min. Good test. 0.0 0.0 8/4/2025 06:45 8/4/2025 08:45 2.00 COMPZN, WHDBOP RURD P Remove blind rams and 7" Lower rams from stack. Remove handling equipment from rig floor. 0.0 0.0 8/4/2025 08:45 8/4/2025 11:30 2.75 COMPZN, WHDBOP NUND P ND tree, remove DSA, clean hanger profile, install tree test dart. Test tree and hanger void to 5000 psi for 10 minutes, good test. 0.0 0.0 8/4/2025 11:30 8/4/2025 12:00 0.50 COMPZN, WHDBOP MPSP P Remove BPV and test dart. 0.0 0.0 8/4/2025 12:00 8/4/2025 15:00 3.00 DEMOB, MOVE FRZP P Freeze protect with 75 bbls diesel at 2 bpm at 500 psi. Take returns to tiger tank. Sim-ops clean under rig floor. Rig release at 15:00. Final pressures T/IA/OA=10/40/20 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 8/4/2025 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:10,252.0 2M-07 7/18/1993 WV5.3 Conversion Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set GLVs and pulled plug post RWO 2M-07 8/17/2025 rmoore22 Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 42.0 121.0 121.0 62.58 H-40 WELDED SURFACE 9 5/8 8.92 41.7 3,261.5 2,772.8 47.00 L-80 BTC PRODUCTION 7 6.28 39.3 10,332.6 6,126.6 26.00 L-80 AB-MOD Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 0.0 Set Depth … 7,339.3 String Max No… 2 7/8 Set Depth … 5,758.1 Tubing Description Tubing – Completion Upper Wt (lb/ft) 6.50 Grade L-80 Top Connection EUE ID (in) 2.44 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 37.6 37.6 0.08 Hanger 7.000 FMC Gen 4 tubing hanger FMC TC-1A- EN 3.900 3,145.5 2,684.1 40.27 Mandrel – GAS LIFT 5.403 2-7/8" MMG Mandrel W/SOV S#25622-03 SLB MMG 2.366 5,467.3 4,412.0 42.21 Mandrel – GAS LIFT 5.398 2-7/8" MMG Mandrel S#25622-02 SLB MMG 2.366 6,874.3 5,450.4 43.00 Mandrel – GAS LIFT 5.350 2-7/8" MMG Mandrel S#25622-01 SLB MMG 2.366 7,218.4 5,685.4 52.06 Packer 6.276 3-1/2" X 7" SLB blue Pack Packer SLB Bluepac k max RH cut to release 2.885 7,308.6 5,740.2 53.37 Nipple - X 3.675 2.313" X-Nipple W/RHC installed S#G3043191 HES 2.313" X 2.313 7,333.5 5,754.8 54.85 Overshot 4.500 3-1/2" PBOS 3.58' from bottom to shear pins (Spaced out 1.5' off tag) NS 3.880 Top (ftKB) 7,336.0 Set Depth … 8,033.5 String Max No… 3 1/2 Set Depth … 6,036.7 Tubing Description Tubing – Completion Lower Wt (lb/ft) 9.30 Grade J-55 Top Connection EUE8RDMOD ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,355.6 5,767.3 55.96 PBR 5.125 BAKER PBR w/ 10' STROKE BAKER 3.000 7,369.3 5,774.9 56.38 PACKER 6.063 BAKER HB RETRIEVABLE PACKER BAKER HB 2.890 7,406.9 5,795.5 57.20 NIPPLE 4.540 CAMCO D NIPPLE NO GO CAMCO D 2.750 8,032.7 6,036.5 77.84 WLEG 4.500 BAKER WIRELINE RE-ENTRY GUIDE BAKER 3.015 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 1,809.0 1,685.6 43.18 FISH LOST 1 SLIP & 2 ELEMENTS FROM LOWER PARAGON PKR 9/27/2024 0.000 7,775.0 5,962.4 70.26 FISH LOST DOG FROM 4" PRGS TOOL. 5/24/2018 0.000 10,252.0 6,125.8 89.32 FISH 1" GLV & 1" DV Also Lower Arm Assembly of Merla KO Tool 4/22/1994 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 3,145.5 2,684.1 40.27 1 GAS LIFT GLV RKP 1 1/2 1,260.0 8/11/2025 JMI 0.250 5,467.3 4,412.0 42.21 2 GAS LIFT GLV RK 1 1/2 1,245.0 8/12/2025 SLB 0.250 6,874.3 5,450.4 43.00 3 GAS LIFT OV RK 1 1/2 8/12/2025 SLB 0.250 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,110.0 8,150.0 6,052.8 6,061.1 C-4, A-5, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,170.0 8,250.0 6,065.2 6,081.2 A-4, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,400.0 8,490.0 6,099.3 6,104.9 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,560.0 8,650.0 6,106.4 6,107.2 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,650.0 8,690.0 6,107.2 6,107.2 A-3, 2M-07 7/12/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 8,690.0 8,700.0 6,107.2 6,107.2 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,790.0 9,100.0 6,108.6 6,116.3 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 9,480.0 9,520.0 6,121.1 6,120.9 A-3, 2M-07 7/7/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 10,000.0 10,040.0 6,121.3 6,121.9 A-3, 2M-07 6/4/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 2M-07, 9/2/2025 10:07:53 AM Vertical schematic (actual) PRODUCTION; 39.3-10,332.6 FISH; 10,252.0 APERF; 10,030.0-10,070.0 IPERF; 10,000.0-10,040.0 IPERF; 9,480.0-9,520.0 IPERF; 8,790.0-9,100.0 Primary – Full Bore; 7,450.0 ftKB IPERF; 8,690.0-8,700.0 IPERF; 8,650.0-8,690.0 IPERF; 8,560.0-8,650.0 IPERF; 8,400.0-8,490.0 IPERF; 8,170.0-8,250.0 IPERF; 8,110.0-8,150.0 FISH; 7,775.0 PACKER; 7,369.3 Nipple - X; 7,308.6 Packer; 7,218.3 Mandrel – GAS LIFT; 6,874.3 Mandrel – GAS LIFT; 5,467.3 SURFACE; 41.7-3,261.5 Mandrel – GAS LIFT; 3,145.5 Squeeze – Behind Casing Squeeze; 1,694.0 ftKB Primary – Full Bore; 430.0 ftKB FISH; 1,809.0 CONDUCTOR; 42.0-121.0 Grouting / Top-Up; 0.0 ftKB Hanger; 37.6 KUP PROD KB-Grd (ft) RR Date 9/17/1992 Other Elev… 2M-07 ... TD Act Btm (ftKB) 10,340.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032017800 Wellbore Status PROD Max Angle & MD Incl (°) 91.03 MD (ftKB) 9,659.65 WELLNAME WELLBORE2M-07 Annotation Last WO: End DateH2S (ppm) 60 Date 11/1/2014 Comment SSSV: TRDP Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,030.0 10,070.0 6,121.7 6,122.4 A-3, 2M-07 7/2/1993 4.0 APERF 180 deg. phasing, 4 1/2" TCP Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 0.0 120.0 0.0 120.0 Grouting / Top -Up Top Job 16 bbl Class C **TOC calculated from annulus volume based on hole diameter + 20% enlargement ^^Csg OD=9.625 430.0 3,262.0 430.0 2,773.2 Primary – Full Bore Lead 235 bbl 12.3 ppg Permafrost E + Tail 104.5 bbl 15.8 ppg Class G... Circ & cond hole prior to cement job - Total volume circ = 465 bbl 9.6 ppg mud. Pump 100 bbl FW Spacer. Mix & pump 670 sxs PF 'E' Lead, 510 sxs Class G Tail. Displ w/233.4 bbl. Bump plug w/2000 psi - Floats held. Full returns except 225 bbl into Lead cement, lost 20 bbl - No cmt returns to surface. Recip csg until 30 bbl from bumping plug. CIP @ 22:00 9/11/92. Rig up for top job. **TOC calculated from annulus volume based on hole diameter + 20% enlargement ^^Csg OD=9.625 7,450.0 10,329.0 5,818.5 6,126.6 Primary – Full Bore Lead 43.8 bbl 10.14 ppg Class G + Tail 86.9 bbl 15.6 ppg Class G... Circ & cond mud prior to cmt job - Circ @ 6 BPM w/82% returns (Total loss of 233 bbl). PT HOWCO lines to 4000 psi. Pump 20 bbl Preflush, drop top plug #1. Pump 50 bbl Spacer @ 11.0 ppg. Mix & pump 50 sxs Class G Lead, 400 sxs Class G Tail. Displ w/391 bbl 10.4 ppg brine. Bump plug w/3500 psi - Held 1.5 min before plug gave and lost all press - Could not press >50 psi on csg - Annulus flowing @ 1 BPM - Floats held. CIP @ 09:30 9/19/92. Recip throughout job w/full returns. ^^Csg OD=7 1,694.0 2,836.0 1,600.2 2,448.4 Squeeze – Behind Casing Squeeze Top Job 33.4 bbl 15.6 ppg Permafrost C + Tail 50.3 bbl 7.3 ppg Arctic Pack... ArcticPack 7" x 9-5/8" annulus - Inject 437 bbl water wash @ 10 BPM, 1150 psi. Mix & pump 199 sxs PF 'C', followed by 50.3 bbl ArcticPack @ 6.2 BPM, Initial Press = 600 psi, Final Press = 800 psi. CIP @ 16:45 9/19/92. Press Test ArcticPack 9/29/92 w/1000 psi - After 60 min press bled to 900 psi - Good test. **TOC calculated from annulus volume based on hole diameter + 20% enlargement ^^Csg OD=7 2M-07, 9/2/2025 10:07:53 AM Vertical schematic (actual) PRODUCTION; 39.3-10,332.6 FISH; 10,252.0 APERF; 10,030.0-10,070.0 IPERF; 10,000.0-10,040.0 IPERF; 9,480.0-9,520.0 IPERF; 8,790.0-9,100.0 Primary – Full Bore; 7,450.0 ftKB IPERF; 8,690.0-8,700.0 IPERF; 8,650.0-8,690.0 IPERF; 8,560.0-8,650.0 IPERF; 8,400.0-8,490.0 IPERF; 8,170.0-8,250.0 IPERF; 8,110.0-8,150.0 FISH; 7,775.0 PACKER; 7,369.3 Nipple - X; 7,308.6 Packer; 7,218.3 Mandrel – GAS LIFT; 6,874.3 Mandrel – GAS LIFT; 5,467.3 SURFACE; 41.7-3,261.5 Mandrel – GAS LIFT; 3,145.5 Squeeze – Behind Casing Squeeze; 1,694.0 ftKB Primary – Full Bore; 430.0 ftKB FISH; 1,809.0 CONDUCTOR; 42.0-121.0 Grouting / Top-Up; 0.0 ftKB Hanger; 37.6 KUP PROD 2M-07 ... WELLNAME WELLBORE2M-07 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Replace Tubing 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A Yes No 9. Property Designation (Lease Number):10. Field: Kuparuk Oil Pool Kuparuk Oil Pool 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10340'2149 1809', 7775',10252' Casing Collapse Conductor Surface Production Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 907-263-4529 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7387' 9-5/8" 79'121' BAKER HB Retrievable SSSV: Otis TRSV 6127'10252'6126' 7" 16" KRU 2M-07 8110-8150' 8170-8250' 8400-8490' 8560-8700' 8790-9100' 9480-9520' 10000-10070' 10294' 6053-6061' 6065-6081' 6099-6105' 6106-6107' 6109-6116' 6121-6121' 6121-6122' 3220' 10333' Perforation Depth MD (ft): 4x3-1/2" 121' 3262' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025589 192-080 P.O. Box 100360, Anchorage, AK 99510 50-103-20178-00-00 ConocoPhillips Alaska, Inc Will perfs require a spacing exception due to property boundaries? AOGCC USE ONLY Tubing Grade:Tubing MD (ft): 7369'MD/5775'TVD 1799'MD/1679'TVD 8034' Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Proposed Pools: 2773' Burst 7/28/2025 Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size Kuparuk River Field TVD Perforation Depth TVD (ft): MD 6127' Adam Klem adam.klem@conocophillips.com RWO/CTD Engineer Subsequent Form Required: Suspension Expiration Date: J-55 m n P s 1 6 5 6 t g N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:29 pm, Jul 30, 2025 Digitally signed by Adam Klem DN: CN=Adam Klem, E=adam.klem@ conocophillips.com, C=US Reason: I am approving this document Location: Date: 2025.07.30 13:31:48-08'00' Foxit PDF Editor Version: 13.1.6 Adam Klem 325-450 A.Dewhurst 31JUL25 DSR=8/5/25 Jack Lau 7/29/25 10-404 JJL 8/4/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.06 08:24:53 -08'00'08/06/25 RBDMS JSB 080725 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 1 of 4 PPre-Rig Work Remaining 1. Pull RBP from 7,377’ MD 2. Set nipple reducer and plug at 7,406’ MD (or HEX plug in tubing tail) 3. Pull GLVs and install DMYs, leaving lowest open for circulation point 4. CMIT-TxIA to 2,500 psi 5. MIT-OA to 1,800 psi 6. Cut tubing at ~7,334’ MD 7. Prepare well for rig arrival Rig Work MIRU 1. MIRU Nabors 7ES on 2M-07. No BPV will be set for MIRU due to Nabors 7ES internal risk assessment. 2. Circulate seawater. Record shut in pressures on the T & IA. Circulate KWF as needed and complete 30-minute NFT. Verify well is dead. 3. Set BPV and confirm as barrier if needed, Discuss contingency well kill plan with crew before starting work. Keep spear with packoff available on rig floor. If the well begins to flow and there are signs that the HEX plug or packer have failed at any point during this work, pick up spear with packoff, RIH, engage tubing and circulate KWF. 1. Perform 30-minute NFT. 2. ND Tree. 3. ND THA using Cameron casing jacks, back out LDS and allow tubing hanger to grow with THA. a. Maximum travel on casing jacks as currently configured is 21”. If travel is exceeded while THA is still under upward force, remove studs one at a time and install extensions. i. 2’ and 7’ extensions are available if required. b. Maximum anticipated travel is 85” (Total subsidence estimate for 2M-07) 4. As needed for height to NU BOPs, cut tubing and control line below tubing hanger and remove tubing hanger. 5. NU BOPs to tubing head – Shell test to 1,800 psi for 15 minutes against HEX plug. a. This test will likely be pressuring up on OA since 7” casing packoffs are likely failing now. b. Circulate 9.4# KWF as soon as possible once BOPs are shell tested. This KWF will provide a 97 psi overbalance to below the plug. 6. LD 1 jt of tubing, band control line to tubing. RIH and drop tubing off on pre-rig cut 7. If test plug cannot be set, follow contingency plan: 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 2 of 4 1. ND BOPs and tubing head, allow casing and tubing head to grow using Cameron casing jacks. 2. In the gap between the tubing head and casing head, cut casing, tubing, and control line. Remove tubing head. 3. NU new tubing head to casing head. 4. NU BOPs to new tubing head with DSA. 5. Set test plug and test BOPs to 250/2,500 psi Retrieve 4” x 3-1/2” Completion 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 4” and 3-1/2” tapered tubing string and jewelry from pre-rig cut at ~7,334’ RKB. a. On TOOH, MU string mill and TIH through wellhead to confirm drift for SSSV. 7” Casing Subsidence Repair 6. MU drift BHA for RBP, RIH on drillpipe to SC shoe. 7. Set plug in 7” casing 100’ above SC shoe. PT to confirm plug is set. a. If drift for RBP was not achieved, RIH and set IBP. 8. ND BOPE, ND tubing head and grow casing as needed using de-tensioning system, pull casing in tension and set slips, NU BOPE to casing head. a. BOPE flange break unable to be tested at this point. Flange break to be tested as soon as practical once test plug can be installed. 9. MU drift BHA for new completion and RIH to SC shoe. a. If drift is achieved, skip ahead to Step 19. b. If drift is not achieved, proceed with 7” Casing Subsidence Repair section. 7” Casing Subsidence Repair 10. RIH with open-ended drillpipe to plug. Dump sand on plug. 11. RU E-Line and pull CBL from SC shoe to surface to identify TOC in OA. a. Calculated top of Arctic Pack cement is 1,964’ RKB. 12. RIH and cut 7” casing. Shut in and circulate freeze protect out of OA as needed. 13. Spear 7” casing, split BOPE stack and remove casing slips. NU BOPE to casing head. 14. Pull 7” casing from cut. a. Make additional cuts in 7” casing to remove in sections as necessary. b. Test BOPE flange break once 7” casing is pulled. 15. RIH with mills to ensure drift for overshot casing patch, and cementer. Bore out 9-5/8” casing to create drift as necessary. 16. MU and RIH with overshot casing patch, cementer, and new 7” casing. 17. Engage overshot and PT casing against RBP to 2,500 psi. 18. Cement 7” x 9-5/8” annulus to surface. 19. ND BOPE, set casing slips, cut excess 7” casing and install packoffs, NU tubing head and BOPE. Test breaks to 250/2,500 psi. 20. RIH and mill up cement and cementer plugs as necessary. Perform additional cleanout runs as necessary. 21. RIH and wash sand and debris from top of RBP. Retrieve RBP. 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 3 of 4 Casing Cleanout Run 22. MU BHA, TIH and perform casing cleanout and tubing dress off runs if necessary, based on tubing condition. Install New 2-7/8” Gas Lift Completion with Stacked Packer 23. MU new 2-7/8” completion with non-sealing overshot, nipple profile, packer, and GLMs. RIH to tubing stub. 24. Once on depth, space out as needed. Circulate corrosion inhibited fluid. 25. Land tubing hanger, RILDS, drop ball and rod and set packer. 26. Pressure test tubing to 3,000 psi for 30 minutes. 27. Pressure test IA to 2,500 psi for 30 minutes. ND BOP, NU Tree 28. Confirm pressure tests, then shear out SOV. 29. Install BPV and test. ND BOPE. NU tree and PT packoffs. 30. Pull BPV and freeze protect well. 31. RDMO. PPost-Rig Work 1. Pull SOV and DVs. Install new GLD. 2. Pull ball and rod used for setting packer. 3. Pull pre-rig plug from liner. General Well Information: Estimated Start Date: 7/28/2025 Current Operations: Shut in Well Type: Producer Wellhead Type: FMC Gen IV. 11” 3M casing head top flange. 7-1/16” 5M tubing head top flange. Scope of Work: Pull the existing 4” x 3-1/2” completion from pre-rig cut, perform 7” subsidence repair to obtain drift for new completion as needed, cleanout/dress off run, install a new 2-7/8” gas lift completion with stacked packer. BOP Configuration: Annular / Pipe Rams / Blind Rams / Pipe Rams Following subject to change with Pre-Rig Work: MIT Results: CMIT-TxIA: Passed (2,000 psi, 10/25/2024) 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 4 of 4 MIT-OA: Passed (10/15/2024) Tubing POT & PPPOT: Passed (6/4/2025) IC POT & PPPOT: Passed (6/4/2025) Static BHP: 2,723 psi / 5,735’ TVD measured on 9/12/2024 MPSP: 2,149 psi using 0.1 psi/ft gradient PPersonnel: Workover Engineer: Cy Eller (907-265-6049 / Cy.Eller@conocophillips.com) Production Engineer: Will Parker Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:10,252.0 2M-07 7/18/1993 WV5.3 Conversion Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Cut Tbg 2M-07 6/27/2025 bworthi1 Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 42.0 121.0 121.0 62.58 H-40 WELDED SURFACE 9 5/8 8.92 41.7 3,261.5 2,772.8 47.00 L-80 BTC PRODUCTION 7 6.28 39.3 10,332.6 6,126.6 26.00 L-80 AB-MOD Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 37.6 Set Depth … 8,033.5 String Max No… 4 Set Depth … 6,036.7 Tubing Description TUBING 4x3.5 Wt (lb/ft) 11.00 Grade J-55 Top Connection DSSHTC ID (in) 3.48 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 37.6 37.6 0.08 HANGER 8.000 FMC GEN IV TUBING HANGER 4.000 1,799.2 1,678.5 43.11 SAFETY VLV 6.000 OTIS TRSV SERIES 10 SAFETY VALVE W/ FRAC SLEEVE INSERT MILLED OUT 8/12/21 OTIS TRSV 2.800 3,173.5 2,705.5 40.28 GAS LIFT 5.898 CAMCO KBMG CAMCO KBMG 3.351 4,987.9 4,056.4 41.92 XO Reducing 4.000 CROSSOVER 4 x 3.5 3.500 5,019.2 4,079.7 41.98 GAS LIFT 5.390 CAMCO KBUG CAMCO KBUG 2.920 6,267.2 5,000.3 41.74 GAS LIFT 5.390 CAMCO KBUG CAMCO KBUG 2.920 6,803.3 5,398.6 43.16 GAS LIFT 5.390 CAMCO KBUG CAMCO KBUG 2.920 7,307.8 5,739.7 53.34 GAS LIFT 5.750 CAMCO MMG-2 CAMCO MMG-2 2.920 7,355.6 5,767.3 55.96 PBR 5.125 BAKER PBR w/ 10' STROKE BAKER 3.000 7,369.3 5,774.9 56.38 PACKER 6.063 BAKER HB RETRIEVABLE PACKER BAKER HB 2.890 7,406.9 5,795.5 57.20 NIPPLE 4.540 CAMCO D NIPPLE NO GO CAMCO D 2.750 8,032.7 6,036.5 77.84 WLEG 4.500 BAKER WIRELINE RE-ENTRY GUIDE BAKER 3.015 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 771.0 768.9 10.80 TIGHT SPOT Tight spot @ 771'. Unable to get passed with DMY Patch drift. Able to drift 2.72" DMY RBP drift. 8/20/2024 0.000 1,799.2 1,678.5 43.11 SLEEVE 3.35" X 110" MODIFIED FRAC SLEEVE (2.70") SET IN SAFETY VALVE ( MILLED OUT TO 2.80") 8/12/2021 7/20/2015 2.800 1,809.0 1,685.6 43.18 FISH LOST 1 SLIP & 2 ELEMENTS FROM LOWER PARAGON PKR 9/27/2024 0.000 7,334.0 5,755.1 54.88 CUT WELLTEC MECHANICAL TBG CUT AT 7334' RKB 6/27/2025 2.992 7,386.8 5,784.6 56.78 PLUG 180-350 HEX PLUG MID- ELEMENT AT 7390' RKB, OAL 5.95' INTERW ELL HEX N/A 6/23/2025 0.000 7,775.0 5,962.4 70.26 FISH LOST DOG FROM 4" PRGS TOOL. 5/24/2018 0.000 10,252.0 6,125.8 89.32 FISH 1" GLV & 1" DV Also Lower Arm Assembly of Merla KO Tool 4/22/1994 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 3,173.5 2,705.5 40.28 1 GAS LIFT DMY BK5 1 0.0 6/11/2025 0.000 5,019.2 4,079.7 41.98 2 GAS LIFT DMY BK5 1 0.0 6/11/2025 0.000 6,267.2 5,000.3 41.74 3 GAS LIFT DMY BK5 1 0.0 12/27/2019 0.000 6,803.3 5,398.6 43.16 4 GAS LIFT DMY BK-5 1 5/8/2021 0.000 7,307.8 5,739.7 53.34 5 GAS LIFT Open 1 1/2 6/12/2025 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,110.0 8,150.0 6,052.8 6,061.1 C-4, A-5, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,170.0 8,250.0 6,065.2 6,081.2 A-4, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,400.0 8,490.0 6,099.3 6,104.9 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,560.0 8,650.0 6,106.4 6,107.2 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,650.0 8,690.0 6,107.2 6,107.2 A-3, 2M-07 7/12/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 8,690.0 8,700.0 6,107.2 6,107.2 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,790.0 9,100.0 6,108.6 6,116.3 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 9,480.0 9,520.0 6,121.1 6,120.9 A-3, 2M-07 7/7/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 2M-07, 7/30/2025 8:46:56 AM Vertical schematic (actual) PRODUCTION; 39.3-10,332.6 FISH; 10,252.0 APERF; 10,030.0-10,070.0 IPERF; 10,000.0-10,040.0 IPERF; 9,480.0-9,520.0 IPERF; 8,790.0-9,100.0 Primary – Full Bore; 7,450.0 ftKB IPERF; 8,690.0-8,700.0 IPERF; 8,650.0-8,690.0 IPERF; 8,560.0-8,650.0 IPERF; 8,400.0-8,490.0 IPERF; 8,170.0-8,250.0 IPERF; 8,110.0-8,150.0 FISH; 7,775.0 PLUG; 7,386.8 PACKER; 7,369.3 CUT; 7,334.0 GAS LIFT; 7,307.8 GAS LIFT; 6,803.3 GAS LIFT; 6,267.2 GAS LIFT; 5,019.2 SURFACE; 41.7-3,261.5 GAS LIFT; 3,173.5 Squeeze – Behind Casing Squeeze; 1,694.0 ftKB Primary – Full Bore; 430.0 ftKB FISH; 1,809.0 SAFETY VLV; 1,799.2 SLEEVE; 1,799.2 TIGHT SPOT; 771.0 CONDUCTOR; 42.0-121.0 Grouting / Top-Up; 0.0 ftKB KUP PROD KB-Grd (ft) RR Date 9/17/1992 Other Elev… 2M-07 ... TD Act Btm (ftKB) 10,340.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032017800 Wellbore Status PROD Max Angle & MD Incl (°) 91.03 MD (ftKB) 9,659.65 WELLNAME WELLBORE2M-07 Annotation Last WO: End DateH2S (ppm) 60 Date 11/1/2014 Comment SSSV: TRDP Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,000.0 10,040.0 6,121.3 6,121.9 A-3, 2M-07 6/4/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 10,030.0 10,070.0 6,121.7 6,122.4 A-3, 2M-07 7/2/1993 4.0 APERF 180 deg. phasing, 4 1/2" TCP Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 0.0 120.0 0.0 120.0 Grouting / Top -Up Top Job 16 bbl Class C **TOC calculated from annulus volume based on hole diameter + 20% enlargement ^^Csg OD=9.625 430.0 3,262.0 430.0 2,773.2 Primary – Full Bore Lead 235 bbl 12.3 ppg Permafrost E + Tail 104.5 bbl 15.8 ppg Class G... Circ & cond hole prior to cement job - Total volume circ = 465 bbl 9.6 ppg mud. Pump 100 bbl FW Spacer. Mix & pump 670 sxs PF 'E' Lead, 510 sxs Class G Tail. Displ w/233.4 bbl. Bump plug w/2000 psi - Floats held. Full returns except 225 bbl into Lead cement, lost 20 bbl - No cmt returns to surface. Recip csg until 30 bbl from bumping plug. CIP @ 22:00 9/11/92. Rig up for top job. **TOC calculated from annulus volume based on hole diameter + 20% enlargement ^^Csg OD=9.625 7,450.0 10,329.0 5,818.5 6,126.6 Primary – Full Bore Lead 43.8 bbl 10.14 ppg Class G + Tail 86.9 bbl 15.6 ppg Class G... Circ & cond mud prior to cmt job - Circ @ 6 BPM w/82% returns (Total loss of 233 bbl). PT HOWCO lines to 4000 psi. Pump 20 bbl Preflush, drop top plug #1. Pump 50 bbl Spacer @ 11.0 ppg. Mix & pump 50 sxs Class G Lead, 400 sxs Class G Tail. Displ w/391 bbl 10.4 ppg brine. Bump plug w/3500 psi - Held 1.5 min before plug gave and lost all press - Could not press >50 psi on csg - Annulus flowing @ 1 BPM - Floats held. CIP @ 09:30 9/19/92. Recip throughout job w/full returns. ^^Csg OD=7 1,694.0 2,836.0 1,600.2 2,448.4 Squeeze – Behind Casing Squeeze Top Job 33.4 bbl 15.6 ppg Permafrost C + Tail 50.3 bbl 7.3 ppg Arctic Pack... ArcticPack 7" x 9-5/8" annulus - Inject 437 bbl water wash @ 10 BPM, 1150 psi. Mix & pump 199 sxs PF 'C', followed by 50.3 bbl ArcticPack @ 6.2 BPM, Initial Press = 600 psi, Final Press = 800 psi. CIP @ 16:45 9/19/92. Press Test ArcticPack 9/29/92 w/1000 psi - After 60 min press bled to 900 psi - Good test. **TOC calculated from annulus volume based on hole diameter + 20% enlargement ^^Csg OD=7 2M-07, 7/30/2025 8:46:57 AM Vertical schematic (actual) PRODUCTION; 39.3-10,332.6 FISH; 10,252.0 APERF; 10,030.0-10,070.0 IPERF; 10,000.0-10,040.0 IPERF; 9,480.0-9,520.0 IPERF; 8,790.0-9,100.0 Primary – Full Bore; 7,450.0 ftKB IPERF; 8,690.0-8,700.0 IPERF; 8,650.0-8,690.0 IPERF; 8,560.0-8,650.0 IPERF; 8,400.0-8,490.0 IPERF; 8,170.0-8,250.0 IPERF; 8,110.0-8,150.0 FISH; 7,775.0 PLUG; 7,386.8 PACKER; 7,369.3 CUT; 7,334.0 GAS LIFT; 7,307.8 GAS LIFT; 6,803.3 GAS LIFT; 6,267.2 GAS LIFT; 5,019.2 SURFACE; 41.7-3,261.5 GAS LIFT; 3,173.5 Squeeze – Behind Casing Squeeze; 1,694.0 ftKB Primary – Full Bore; 430.0 ftKB FISH; 1,809.0 SAFETY VLV; 1,799.2 SLEEVE; 1,799.2 TIGHT SPOT; 771.0 CONDUCTOR; 42.0-121.0 Grouting / Top-Up; 0.0 ftKB KUP PROD 2M-07 ... WELLNAME WELLBORE2M-07 ORIGINATED TRANSMITTAL DATE: ALASKA E-LINE SERVICES TRANSMITTAL #: 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5527 2M-07 50103201780000 Plug Setting Record 23-Jun-2025 RECIPIENTS Conoco DIGITAL FILES PRINTS CD'S 1 FTP Transfer 0 0 USPS Attn: NSK-69 Richard.E.Elgarico@conocophillips.com 700 G Street Anchorage, AK 99503 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 192-080 T40722 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.30 15:03:34 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com From:Lau, Jack J (OGC) To:Eller, Cy Cc:Dodson, Kate; Klem, Adam; Rixse, Melvin G (OGC); Loepp, Victoria T (OGC); McLellan, Bryan J (OGC); Boman, Wade C (OGC); Coberly, Jonathan Subject:RE: KRU 2M-07 RWO Plan Forward (Sundry# 325-352) (PTD192-080) Date:Tuesday, July 29, 2025 11:46:29 AM Thank you Cy. Verbal approval for your proposed plan outlined below and highlighted in yellow is granted. A 10-403 for change of approved program must be submitted to the AOGCC within three days. Contact the AOGCC immediately if any deviation to plan occurs. Jack From: Eller, Cy <Cy.Eller@conocophillips.com> Sent: Tuesday, July 29, 2025 11:28 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Dodson, Kate <Kate.Dodson@conocophillips.com>; Klem, Adam <Adam.Klem@conocophillips.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Coberly, Jonathan <Jonathan.Coberly@conocophillips.com> Subject: RE: [EXTERNAL]RE: KRU 2M-07 RWO Plan Forward (Sundry# 325-352) Hi Jack, Thank you for meeting with us today. Please see below for the requested information. Discuss contingency well kill plan with crew before starting work. Keep spear with packoff available on rig floor. If the well begins to flow and there are signs that the HEX plug or packer have failed at any point during this work, pick up spear with packoff, RIH, engage tubing and circulate KWF. 1. Perform 30-minute NFT. 2. ND Tree. 3. ND THA using Cameron casing jacks, back out LDS and allow tubing hanger to grow with THA. a. Maximum travel on casing jacks as currently configured is 21”. If travel is exceeded while THA is still under upward force, remove studs one at a time and install extensions. i. 2’ and 7’ extensions are available if required. b. Maximum anticipated travel is 85” (Total subsidence estimate for 2M-07) 3. As needed for height to NU BOPs, cut tubing and control line below tubing hanger and remove tubing hanger. 4. NU BOPs to tubing head – Shell test to 1,800 psi for 15 minutes against HEX plug. a. This test will likely be pressuring up on OA since 7” casing packoffs are likely failing now. b. Circulate 9.4# KWF as soon as possible once BOPs are shell tested. This KWF will provide a 97 psi overbalance to below the plug. 5. LD 1 jt of tubing, band control line to tubing. RIH and drop tubing off on pre-rig cut 6. Set BOP test plug, test BOPs to 250/2,500 psi. 7. If test plug cannot be set, follow contingency plan: Contingency Plan If test plug cannot be set, or drift through casing impingement cannot be achieved, follow contingency plan as follows: 1. ND tubing head, allow casing and tubing head to grow using Cameron casing jacks. 2. In the gap between the tubing head and casing head, cut casing, tubing, and control line. Remove tubing head. 3. NU new tubing head to casing head. 4. NU BOPs to new tubing head with DSA. 5. Shell test BOPs against HEX plug to 1,800 psi for 15 minutes. a. This test will likely be pressuring up on OA since 7” casing packoffs are likely failing now. b. Circulate 9.4# KWF as soon as possible after BOPs are shell tested. This KWF will provide a 97 psi overbalance to below the plug. 6. Set test plug and test BOPs to 250/2,500 psi 7. The tubing head by casing head flange break is unable to be tested to full BOP test pressure until 7” casing is pulled. KWF is the secondary barrier until this break is tested Please let me know if you have any questions. Thank you, Cy Eller RWO/CTD Engineer ConocoPhillips Alaska Office: 907-265-6049 Cell: 907-232-4090 From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Tuesday, July 29, 2025 10:47 AM 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. To: Eller, Cy <Cy.Eller@conocophillips.com> Cc: Dodson, Kate <Kate.Dodson@conocophillips.com>; Klem, Adam <Adam.Klem@conocophillips.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Boman, Wade C (OGC) <wade.boman@alaska.gov> Subject: [EXTERNAL]RE: KRU 2M-07 RWO Plan Forward (Sundry# 325-352) CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Cy, Our team has discussed, and we require the following before we can grant verbal approval to proceed on 2M-07. Detailed procedure of the requested work including the use of casing jacks and extensions. Max total travel of casing jacks for relieving the tubing compression along with the max estimated potential travel of the tubing. Entire content used in today’s meeting including the presentation, slides, and pictures. Note: After verbal approval is granted you must submit a 10-403 for change of approved program to the AOGCC within three days. Jack From: Eller, Cy <Cy.Eller@conocophillips.com> Sent: Monday, July 28, 2025 7:18 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Coberly, Jonathan <Jonathan.Coberly@conocophillips.com>; Dodson, Kate <Kate.Dodson@conocophillips.com>; Nezaticky, Peter <P.Nezaticky@conocophillips.com>; Klem, Adam <Adam.Klem@conocophillips.com> Subject: KRU 2M-07 RWO Plan Forward (Sundry# 325-352) Good evening Jack, I wanted to provide you with an update on the 2M-07 RWO. We began to ND the tree and tubing head adapter after circulating seawater, and while doing so the tubing hanger appeared to be pushing upwards on the tubing head adapter. One of the lockdown pins was removed to inspect it, and the tip of it was sheared off and the tubing hanger showed signs of upward travel. The tubing head adapter was compressed back down and the tree was re-installed as a plan forward was determined. Our plan forward to ND the tree and NU and test BOPs is as follows: 1. Perform NFT. 2. ND Tree. 3. ND THA using Cameron subsidence jacks, back out LDS and allow tubing hanger to grow with THA. 4. Cut tubing and remove hanger as needed. 5. NU BOPs to tubing head – Shell test to 1,800 psi (previous MIT-OA pressure) for 15 minutes against HEX plug. 6. LD jt of tubing, RIH and drop tubing off on pre-rig cut. 7. Set BOP test plug, test BOPs to 250/2,500 psi. 8. If test plug cannot be set, follow contingency plan: Contingency Plan If test plug cannot be set, or drift through probable casing impingement in wellhead cannot be achieved, follow contingency plan as follows: 1. ND tubing head, allow casing and tubing head to grow using Cameron subsidence jacks. 2. In the gap between the tubing head and casing head, cut casing, tubing, and control line. Remove tubing head. 3. NU new tubing head to casing head. 4. NU BOPs to new tubing head. 5. Shell test BOPs against HEX plug to 1,800 psi (previous MIT-OA pressure) for 15 minutes. 6. Set test plug and test BOPs to 250/2,500 psi 7. The tubing head by casing head flange break is unable to be tested to full BOP test pressure until 7” casing is pulled removed from across test plug profile. a. KWF is the secondary barrier until this break is tested. Please let me know if you have any concerns with this plan. Thank you, Cy Eller RWO/CTD Engineer ConocoPhillips Alaska Office: 907-265-6049 Cell: 907-232-4090 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Replace Tubing 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A Yes No 9. Property Designation (Lease Number): 10. Field: Kuparuk Oil Pool Kuparuk Oil Pool 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10340'2149 1809', 7775',10252' Casing Collapse Conductor Surface Production Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 907-265-6049 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Cy Eller cy.eller@conocophillips.com RWO/CTD Engineer Subsequent Form Required: Suspension Expiration Date: J-55 Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size Kuparuk River Field TVD Perforation Depth TVD (ft): MD 6127' Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Proposed Pools: 2773' Burst AOGCC USE ONLY Tubing Grade:Tubing MD (ft): 7369'MD/5775'TVD 1799'MD/1679'TVD 8034' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025589 192-080 P.O. Box 100360, Anchorage, AK 99510 50-103-20178-00-00 ConocoPhillips Alaska, Inc Will perfs require a spacing exception due to property boundaries? 8/4/2025 4x3-1/2" 121' 3262' KRU 2M-07 8110-8150' 8170-8250' 8400-8490' 8560-8700' 8790-9100' 9480-9520' 10000-10070' 10294' 6053-6061' 6065-6081' 6099-6105' 6106-6107' 6109-6116' 6121-6121' 6121-6122' 3220' 10333' Perforation Depth MD (ft): BAKER HB Retrievable SSSV: Otis TRSV 6127'10252'6126' 7" 16" 7377' 9-5/8" 79'121' m n P s 1 6 5 6 t g N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:07 am, Jun 10, 2025 325-352 10-404 DSR-6/18/25 X AOGCC Witnessed BOP and annular test to 2500 psi. SFD 7/22/2025JJL 6/16/25 , ADL0025586 SFD JLC 7/22/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 14:50:07 -08'00'07/23/25 RBDMS JSB 072425 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 5, 2025 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to work over KRU 2M-07 (PTD# 192-080). Well 2M-07 was drilled in September of 1992 by Parker 245 and completed by Nordic 1 in July of 1993 as a Kuparuk A Sand producer. The well was brought online and had a healthy life until it failed a TIFL in 2015. A leak detect log was run and revealed a tubing leak in the gas lift mandrel at 7,307’ MD. A tubing patch was set across the GLM from 7,303’ – 7,325’ MD and the well was brought back online until it failed a subsidence surveillance drift with tubing restrictions noted at ~770’ MD in August of 2024. The tubing patch was removed, and the well was moved to a workover candidate. To return the well to production, we are requesting approval to proceed with a rig workover. We plan to pull the 4” x 3-1/2” completion from a pre-rig cut above the packer, then grow and stretch the 7” casing and verify drift. If drift is not achieved, the damaged 7” casing will be cut and pulled, then new 7” production casing will be run, and the OA cemented to surface. Once the subsidence damage is repaired, a new 2-7/8” gas lifted completion with a non-sealing overshot and stacked packer will be installed. If you have any questions or require any further information, please contact me at 907-265-6049. Cy Eller Rig Workover Engineer CPAI Drilling and Wells 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 1 of 3 PPre-Rig Work Remaining 1. Pull RBP from 7,377’ MD 2. Set nipple reducer and plug at 7,406’ MD (or HEX plug in tubing tail) 3. Pull GLVs and install DMYs, leaving lowest open for circulation point 4. CMIT-TxIA to 2,500 psi 5. MIT-OA to 1,800 psi 6. Cut tubing at ~7,334’ MD 7. Prepare well for rig arrival Rig Work MIRU 1. MIRU Nabors 7ES on 2M-07. No BPV will be set for MIRU due to Nabors 7ES internal risk assessment. 2. Circulate seawater. Record shut in pressures on the T & IA. Circulate KWF as needed and complete 30-minute NFT. Verify well is dead. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/2,500 psi. Test annular 250/2,500 psi. Retrieve 4” x 3-1/2” Completion 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 4” and 3-1/2” tapered tubing string and jewelry from pre-rig cut at ~7,334’ RKB. a. On TOOH, MU string mill and TIH through wellhead to confirm drift for SSSV. 7” Casing Subsidence Repair 6. MU drift BHA for RBP, RIH on drillpipe to SC shoe. 7. Set plug in 7” casing 100’ above SC shoe. PT to confirm plug is set. a. If drift for RBP was not achieved, RIH and set IBP. 8. ND BOPE, ND tubing head and grow casing as needed using de-tensioning system, pull casing in tension and set slips, NU BOPE to casing head. a. BOPE flange break unable to be tested at this point. Flange break to be tested as soon as practical once test plug can be installed. 9. MU drift BHA for new completion and RIH to SC shoe. a. If drift is achieved, skip ahead to Step 19. b. If drift is not achieved, proceed with 7” Casing Subsidence Repair section. 7” Casing Subsidence Repair 10. RIH with open-ended drillpipe to plug. Dump sand on plug. 11. RU E-Line and pull CBL from SC shoe to surface to identify TOC in OA. a. Calculated top of Arctic Pack cement is 1,964’ RKB. 12. RIH and cut 7” casing. Shut in and circulate freeze protect out of OA as needed. 13. Spear 7” casing, split BOPE stack and remove casing slips. NU BOPE to casing head. 14. Pull 7” casing from cut. a. Make additional cuts in 7” casing to remove in sections as necessary. b. Test BOPE flange break once 7” casing is pulled. 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 2 of 3 15. RIH with mills to ensure drift for overshot casing patch, and cementer. Bore out 9-5/8” casing to create drift as necessary. 16. MU and RIH with overshot casing patch, cementer, and new 7” casing. 17. Engage overshot and PT casing against RBP to 2,500 psi. 18. Cement 7” x 9-5/8” annulus to surface. 19. ND BOPE, set casing slips, cut excess 7” casing and install packoffs, NU tubing head and BOPE. Test breaks to 250/2,500 psi. 20. RIH and mill up cement and cementer plugs as necessary. Perform additional cleanout runs as necessary. 21. RIH and wash sand and debris from top of RBP. Retrieve RBP. Casing Cleanout Run 22. MU BHA, TIH and perform casing cleanout and tubing dress off runs if necessary, based on tubing condition. Install New 2-7/8” Gas Lift Completion with Stacked Packer 23. MU new 2-7/8” completion with non-sealing overshot, nipple profile, packer, and GLMs. RIH to tubing stub. 24. Once on depth, space out as needed. Circulate corrosion inhibited fluid. 25. Land tubing hanger, RILDS, drop ball and rod and set packer. 26. Pressure test tubing to 3,000 psi for 30 minutes. 27. Pressure test IA to 2,500 psi for 30 minutes. ND BOP, NU Tree 28. Confirm pressure tests, then shear out SOV. 29. Install BPV and test. ND BOPE. NU tree and PT packoffs. 30. Pull BPV and freeze protect well. 31. RDMO. Post-Rig Work 1. Pull SOV and DVs. Install new GLD. 2. Pull ball and rod used for setting packer. 3. Pull pre-rig plug from liner. General Well Information: Estimated Start Date:8/4/2025 Current Operations: Shut in Well Type: Producer Wellhead Type: FMC Gen IV. 11” 3M casing head top flange. 7-1/16” 5M tubing head top flange. 2M-07 Kuparuk Producer Tubing Swap with Subsidence Repair PTD: 192-080 Page 3 of 3 Scope of Work: Pull the existing 4” x 3-1/2” completion from pre-rig cut, perform 7” subsidence repair to obtain drift for new completion as needed, cleanout/dress off run, install a new 2-7/8” gas lift completion with stacked packer. BOP Configuration: Annular / Pipe Rams / Blind Rams / Pipe Rams FFollowing subject to change with Pre-Rig Work: MIT Results: CMIT-TxIA: Passed (2,000 psi, 10/25/2024) MIT-OA: Passed (10/15/2024) Tubing POT & PPPOT: Passed (6/4/2025) IC POT & PPPOT: Passed (6/4/2025) Static BHP: 2,723 psi / 5,735’ TVD measured on 9/12/2024 MPSP: 2,149 psi using 0.1 psi/ft gradient Personnel: Workover Engineer: Cy Eller (907-265-6049 / Cy.Eller@conocophillips.com) Production Engineer: Will Parker Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:10,252.0 2M-07 7/18/1993 WV5.3 Conversion Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pulled OV & added RBP @ 7380' RKB 2M-07 10/25/2024 jconne Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 42.0 121.0 121.0 62.58 H-40 WELDED SURFACE 9 5/8 8.92 41.7 3,261.5 2,772.8 47.00 L-80 BTC PRODUCTION 7 6.28 39.3 10,332.6 6,126.6 26.00 L-80 AB-MOD Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 37.6 Set Depth … 8,033.5 String Max No… 4 Set Depth … 6,036.7 Tubing Description TUBING 4x3.5 Wt (lb/ft) 11.00 Grade J-55 Top Connection DSSHTC ID (in) 3.48 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 37.6 37.6 0.08 HANGER 8.000 FMC GEN IV TUBING HANGER 4.000 1,799.2 1,678.5 43.11 SAFETY VLV 6.000 OTIS TRSV SERIES 10 SAFETY VALVE W/ FRAC SLEEVE INSERT MILLED OUT 8/12/21 OTIS TRSV 2.800 3,173.5 2,705.5 40.28 GAS LIFT 5.898 CAMCO KBMG CAMCO KBMG 3.351 4,987.9 4,056.4 41.92 XO Reducing 4.000 CROSSOVER 4 x 3.5 3.500 5,019.2 4,079.7 41.98 GAS LIFT 5.390 CAMCO KBUG CAMCO KBUG 2.920 6,267.2 5,000.3 41.74 GAS LIFT 5.390 CAMCO KBUG CAMCO KBUG 2.920 6,803.3 5,398.6 43.16 GAS LIFT 5.390 CAMCO KBUG CAMCO KBUG 2.920 7,307.8 5,739.7 53.34 GAS LIFT 5.750 CAMCO MMG-2 CAMCO MMG-2 2.920 7,355.6 5,767.3 55.96 PBR 5.125 BAKER PBR w/ 10' STROKE BAKER 3.000 7,369.3 5,774.9 56.38 PACKER 6.063 BAKER HB RETRIEVABLE PACKER BAKER HB 2.890 7,406.9 5,795.5 57.20 NIPPLE 4.540 CAMCO D NIPPLE NO GO CAMCO D 2.750 8,032.7 6,036.5 77.84 WLEG 4.500 BAKER WIRELINE RE-ENTRY GUIDE BAKER 3.015 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 771.0 768.9 10.80 TIGHT SPOT Tight spot @ 771'. Unable to get passed with DMY Patch drift. Able to drift 2.72" DMY RBP drift. 8/20/2024 0.000 1,799.2 1,678.5 43.11 SLEEVE 3.35" X 110" MODIFIED FRAC SLEEVE (2.70") SET IN SAFETY VALVE ( MILLED OUT TO 2.80") 8/12/2021 7/20/2015 2.800 1,809.0 1,685.6 43.18 FISH LOST 1 SLIP & 2 ELEMENTS FROM LOWER PARAGON PKR 9/27/2024 0.000 7,377.3 5,779.4 56.57 RBP 2.60" ME RBP W/ EQUALIZING VALVE & DEBRIS EXTENSION, MOE @ 7380', OAL = 7.62' TTS PIIP CPME P3500 1, CPEQ 287S C14 10/25/2024 0.000 7,775.0 5,962.4 70.26 FISH LOST DOG FROM 4" PRGS TOOL. 5/24/2018 0.000 10,252.0 6,125.8 89.32 FISH 1" GLV & 1" DV Also Lower Arm Assembly of Merla KO Tool 4/22/1994 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 3,173.5 2,705.5 40.28 1 GAS LIFT GLV BK5 1 1,275.0 3/16/2020 0.188 5,019.2 4,079.7 41.98 2 GAS LIFT OPEN BK5 1 10/25/2024 6,267.2 5,000.3 41.74 3 GAS LIFT DMY BK5 1 0.0 12/27/2019 0.000 6,803.3 5,398.6 43.16 4 GAS LIFT DMY BK-5 1 5/8/2021 0.000 7,307.8 5,739.7 53.34 5 GAS LIFT DMY RK 1 1/2 0.0 6/4/2015 HI- SEAL EXT PKG 8:00 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,110.0 8,150.0 6,052.8 6,061.1 C-4, A-5, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,170.0 8,250.0 6,065.2 6,081.2 A-4, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,400.0 8,490.0 6,099.3 6,104.9 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,560.0 8,650.0 6,106.4 6,107.2 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,650.0 8,690.0 6,107.2 6,107.2 A-3, 2M-07 7/12/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 2M-07, 6/5/2025 1:59:32 PM Vertical schematic (actual) PRODUCTION; 39.3-10,332.6 FLOAT SHOE; 10,330.7- 10,332.6 FISH; 10,252.0 FLOAT COLLAR; 10,245.4- 10,247.1 APERF; 10,030.0-10,070.0 IPERF; 10,000.0-10,040.0 IPERF; 9,480.0-9,520.0 IPERF; 8,790.0-9,100.0 IPERF; 8,690.0-8,700.0 IPERF; 8,650.0-8,690.0 IPERF; 8,560.0-8,650.0 IPERF; 8,400.0-8,490.0 IPERF; 8,170.0-8,250.0 IPERF; 8,110.0-8,150.0 WLEG; 8,032.7 FISH; 7,775.0 NIPPLE; 7,406.9 RBP; 7,377.3 PACKER; 7,369.3 PBR; 7,355.6 GAS LIFT; 7,307.8 GAS LIFT; 6,803.3 GAS LIFT; 6,267.2 GAS LIFT; 5,019.2 SURFACE; 41.7-3,261.5 FLOAT SHOE; 3,259.5-3,261.5 GAS LIFT; 3,173.5 FLOAT COLLAR; 3,176.1- 3,177.9 FISH; 1,809.0 SAFETY VLV; 1,799.2 SLEEVE; 1,799.2 TIGHT SPOT; 771.0 CONDUCTOR; 42.0-121.0 HANGER; 41.7-45.0 HANGER; 37.6 KUP PROD KB-Grd (ft) RR Date 9/17/1992 Other Elev… 2M-07 ... TD Act Btm (ftKB) 10,340.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032017800 Wellbore Status PROD Max Angle & MD Incl (°) 91.03 MD (ftKB) 9,659.65 WELLNAME WELLBORE2M-07 Annotation Last WO: End DateH2S (ppm) 60 Date 11/1/2014 Comment SSSV: TRDP Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,690.0 8,700.0 6,107.2 6,107.2 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 8,790.0 9,100.0 6,108.6 6,116.3 A-3, 2M-07 7/21/1993 1.7 IPERF 180 deg. phasing, 4 1/2" TCP 9,480.0 9,520.0 6,121.1 6,120.9 A-3, 2M-07 7/7/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 10,000.0 10,040.0 6,121.3 6,121.9 A-3, 2M-07 6/4/1993 4.0 IPERF 180 deg. phasing, 4 1/2" TCP 10,030.0 10,070.0 6,121.7 6,122.4 A-3, 2M-07 7/2/1993 4.0 APERF 180 deg. phasing, 4 1/2" TCP 2M-07, 6/5/2025 1:59:32 PM Vertical schematic (actual) PRODUCTION; 39.3-10,332.6 FLOAT SHOE; 10,330.7- 10,332.6 FISH; 10,252.0 FLOAT COLLAR; 10,245.4- 10,247.1 APERF; 10,030.0-10,070.0 IPERF; 10,000.0-10,040.0 IPERF; 9,480.0-9,520.0 IPERF; 8,790.0-9,100.0 IPERF; 8,690.0-8,700.0 IPERF; 8,650.0-8,690.0 IPERF; 8,560.0-8,650.0 IPERF; 8,400.0-8,490.0 IPERF; 8,170.0-8,250.0 IPERF; 8,110.0-8,150.0 WLEG; 8,032.7 FISH; 7,775.0 NIPPLE; 7,406.9 RBP; 7,377.3 PACKER; 7,369.3 PBR; 7,355.6 GAS LIFT; 7,307.8 GAS LIFT; 6,803.3 GAS LIFT; 6,267.2 GAS LIFT; 5,019.2 SURFACE; 41.7-3,261.5 FLOAT SHOE; 3,259.5-3,261.5 GAS LIFT; 3,173.5 FLOAT COLLAR; 3,176.1- 3,177.9 FISH; 1,809.0 SAFETY VLV; 1,799.2 SLEEVE; 1,799.2 TIGHT SPOT; 771.0 CONDUCTOR; 42.0-121.0 HANGER; 41.7-45.0 HANGER; 37.6 KUP PROD 2M-07 ... WELLNAME WELLBORE2M-07 Originated: Delivered to:17-Jan-25Halliburton Alaska Oil and Gas Conservation Comm.Wireline & Perforating Attn.: Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska 99501Anchorage, Alaska 99518Office: 907-275-2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPEDATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#1 1E-07A 50-029-20495-01 909619502 Kuparuk River Packer Setting Record Field- Final 20-Oct-24 0 12 1E-28A 50-029-20832-01 n/a Kuparuk River Packer Setting Record Field- Final 16-Jan-25 0 13 1F-08 50-029-20836-00 909737879 Kuparuk River Plug Setting Record Field- Final 3-Dec-24 0 14 1H-101 50-029-23585-00 909606936 Kuparuk River Multi Finger Caliper Field & Processed 28-Oct-24 0 15 1R-20 50-029-22207-00 909678505 Kuparuk River Packer Setting Record Field- Final 11-Nov-24 0 16 2A-16 50-103-20042-00 909780661 Kuparuk River Multi Finger Caliper Field & Processed 1-Jan-25 0 17 2C-03 50-029-20968-00 909740014 Kuparuk River Plug Setting Record Field- Final 14-Jan-25 0 18 2M-07 50-103-20178-00 909618938 Kuparuk River Plug Setting Record Field- Final 25-Oct-24 0 19 2W-01 50-029-21273-00 909740411 Kuparuk River Radial Bond Record Field- Final 7-Jan-25 0 110 3B-04 50-029-21323-00 909740412 Kuparuk River Multi Finger Caliper Field & Processed 3-Jan-25 0 1PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:T39999T40000T40001T40002T40003T40004T40005T40006T40007211-062213-095182-162217-138191-108185-147183-089192-080185-010185-061T400081/23/20252M-0750-103-20178-00909618938Kuparuk RiverPlug Setting RecordField- Final25-Oct-2401183 089192-080185 010Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.01.23 15:13:51 -09'00' Originated: Delivered to:9ͲOctͲ24Halliburton Alaska Oil and Gas Conservation Comm.Wireline & PerforatingAttn.:Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska99501Anchorage, Alaska 99518Office: 907Ͳ275Ͳ2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#12AͲ04 50Ͳ103Ͳ20026Ͳ00 909593518 Kuparuk River Plug Setting Record FieldͲFinal 29ͲSepͲ24 0 122AͲ05 50Ͳ103Ͳ20030Ͳ00 909524907 Kuparuk River Plug Setting Record FieldͲFinal30ͲAugͲ24 0 132AͲ11 50Ͳ103Ͳ20057Ͳ00 909594128 Kuparuk River Multi Finger CaliperField & Processed 4ͲOctͲ24 0 142AͲ12 50Ͳ103Ͳ20058Ͳ00 909524545 Kuparuk River Multi Finger CaliperField & Processed 22ͲAugͲ24 0 152AͲ12 50Ͳ103Ͳ20058Ͳ00 909524545 Kuparuk River Packer Setting Record FieldͲFinal 24ͲAugͲ24 0 162GͲ10 50Ͳ029Ͳ21140Ͳ00 n/a Kuparuk River Multi Finger CaliperField & Processed 23ͲAugͲ24 0 172MͲ07 50Ͳ103Ͳ20178Ͳ00 ALSL765Ͳ008 Kuparuk River Multi Finger CaliperField & Processed 15ͲSepͲ24 0 182NͲ329 50Ͳ103Ͳ20257Ͳ00 909593520 Kuparuk River Packer Setting Record FieldͲFinal 20ͲSepͲ24 0 192ZͲ10 50Ͳ029Ͳ21378Ͳ00 909593519 Kuparuk River Multi Finger CaliperField & Processed 25ͲSepͲ24 0 110 3IͲ09 50Ͳ029Ͳ21561Ͳ00 909619414 Kuparuk River Leak Detect Log FieldͲFinal 5ͲOctͲ24 0 1PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:T39689T39690T39691T39692T39692T39693T39694T39695T39696184-053184-067186-003186-004184-106192-080198-067185-137186-055T3969710/21/2024Gavin GluyasDigitally signed by Gavin Gluyas Date: 2024.10.21 10:49:24 -08'00'2MͲ0750Ͳ103Ͳ20178Ͳ00 ALSL765Ͳ008KuparukRiverMultiFingerCaliperField&Processed15ͲSepͲ2401T39694184 106192-080198 067 WELL NAME API #SERVICE ORDER # FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPEDATE LOGGEDCOLOR PRINTS CDsCD5-1950103207600000 CRU WLSetting RecordFINAL FIELD3-Aug-21CD5-1950103207600000 CRU WLSetting RecordFINAL FIELD11-Aug-21CD5-9650103208110000 CRU WLPERFFINAL FIELD21-Jul-21CD2-31050103208260000 CRU WLDCSTFINAL FIELD16-Sep-21CD2-31050103208260000 CRU WLUSITFINAL FIELD24-Aug-21CD2-31050103208260000 CRU WLUSITFINAL FIELD25-Aug-21CD5-3150103208280000 CRU WLPERFFINAL FIELD27-May-21CD1-01A50103202990100 CRU WLRSTFINAL FIELD12-Sep-21MT7-0650103208310000 GMTU WLCORROSIONFINAL FIELD3-Oct-21MT6-0850103207720000 GMTU WLPSRFINAL FIELD14-Sep-21MT6-0850103207720000 GMTU WLPSRFINAL FIELD22-Oct-21MT7-0650103208310000 GMTU WLMECH CUTTERFINAL FIELD2-Sep-21MT7-0650103208310000 GMTU WLUSITFINAL FIELD12-Dec-21MT7-0650103208310000 GMTU WLUSITFINAL FIELD16-Dec-21MT7--0150103208320000 GMTU WLSCMTFINAL FIELD15-Nov-21MT7-0650103208310000 GMTU WLUSITFINAL FIELD19-Feb-21Lookout 150103203590000 GMTU WLRSTFINAL FIELD29-Mar-21Lookout 150103203590000 GMTU WLRSTFINAL FIELD2-Apr-21Delivery Receipt______ďďǇĞůů_____X_______________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.A Delivery Receipt signature confirms that a package (box, envelope, etc.) has been received. The package will be handled/delivered per standard company reception procedures. The package's contents have not been verified but should be assumed to contain the above noted SLB Auditor-Originated:PTS - PRINT CENTER600 E 57th Pl - Ste AAnchorage, AK 99518Delivered to:AOGCCATTN: Natural Resources Technician333 W. 7th Ave., Suite 100Anchorage, AK 99501-3539Transmittal Date:20-Dec-21Transmittal #:________________Signature12/21/2021Wd͗ϭϵϮϬϴϬϬͲ^Ğƚ͗ϯϲϮϰϵJRBy Abby Bell at 1:43 pm, Dec 21, 2021 3M-1750029217290000 KRU WLWFLFINAL FIELD24-Apr-213M-1950029217370000 KRU WLLDLFINAL FIELD25-Apr-213H-0150103200840000 KRU WLCHCFINAL FIELD26-Aug-213H-1250103200880000 KRU WLCCLFINAL FIELD23-Sep-213H-1250103200880000 KRU WLCHCFINAL FIELD29-Aug-213H-1250103200880000 KRU WLCUTTERFINAL FIELD23-Sep-213H-1250103200880000 KRU WLCUTTERFINAL FIELD24-Sep-211L-1250029220330000 KRU WLSBHPSFINAL FIELD6-Nov-213G-2450103201450000 KRU WLTBG CORRFINAL FIELD29-Oct-211A-2550029221160000 KRU WL WHIPSTOCKFINAL FIELD12-Oct-211A-2350029221310000 KRU WLRBPFINAL FIELD12-Jun-211R-2050029222070000 KRU WLPPROFFINAL FIELD2-Jun-212M-1150103201590000 KRU WLPPROFFINAL FIELD27-Aug-212M-0750103201780000 KRU WLBACKOFFFINAL FIELD5-Aug-211Y-1950029223910000 KRU WLPPROFFINAL FIELD31-May-212T-3050103202190000 KRU WLLDLFINAL FIELD2-May-211Q-20A50029225890100 KRU WLSET RECFINAL FIELD2-Aug-212M-3350103202400000 KRU WLLDLFINAL FIELD18-Oct-211F-03A50029208530100 KRU WLPERFFINAL FIELD19-Oct-211Q-08A50029212250100 KRU WLIPROFFINAL FIELD30-Apr-211E-3350029227970000 KRU WLPPROFFINAL FIELD26-Mar-211D-13550029228160000 KRU WLLDLFINAL FIELD16-Jul-213F-13A50029214990100 KRU WLGLSFINAL FIELD17-Jul-212N-318 50103203430000 KRU WLSCMTFINAL FIELD12-Nov-211C-12750029230240000 KRU WLIPROFFINAL FIELD17-Nov-213S-24A50103204560100 KRU WLCUTTERFINAL FIELD25-Oct-213S-0350103204580000 KRU WLIBPFINAL FIELD26-Oct-211B-2050029231640000 KRU WLPPROFFINAL FIELD22-Apr-211E-11950029231980000 KRU WLLDLFINAL FIELD26-Jun-212W-1750029233700000 KRU WLPPROFFINAL FIELD28-Aug-211H-11850029235780000 KRU WLIPROFFINAL FIELD4-Nov-211H-11450029235840000 KRU WLIPROFFINAL FIELD23-Jun-211H-11350029235880000 KRU WLWFLFINAL FIELD22-May-21 Originated:Delivered to:28-May-21 Halliburton Alaska Oil and Gas Conservation Comm. Wireline & Perforating Attn.: Natural Resource Technician Attn: Fanny Haroun 333 West 7th Avenue, Suite 100 6900 Arctic Blvd.Anchorage, Alaska 99501 Anchorage, Alaska 99518 Office: 907-275-2605 FRS_ANC@halliburton.com The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of the sender above WELL NAME API #SERVICE ORDER #FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS #DIGITAL # 1 2E-10 50-029-21246-00 907100157 Kuparuk River Packer Setting Record Field- Final 19-Apr-21 0 1 2 2H-11 50-029-20052-00 n/a Kuparuk River Packer Setting Record Field- Final 18-May-21 0 1 3 2M-07 50-103-20178-00 907126248 Kuparuk River Plug Setting Record Field- Final 30-Apr-21 0 1 4 3K-03 50-029-21602-00 907097693 Kuparuk River Leak Detect Log Field- Final 16-Apr-21 0 1 5 3K-03 50-029-21602-00 907132626 Kuparuk River Packer Setting Record Field- Final 5-May-21 0 1 6 3K-30 50-029-22777-00 907098723 Kuparuk River Multi Finger Caliper Field & Processed 16-Apr-21 0 1 7 3K-30 50-029-22777-00 907098126 Kuparuk River Packer Setting Record Field- Final 6-May-21 0 1 8 3Q-06 50-029-21674-00 907089173 Kuparuk River Multi Finger Caliper Field & Processed 13-Apr-21 0 1 9 10 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com Date:Signed: Transmittal Date: 06/01/2021 PTD: 1920800 E-Set: 35189 Originated: Halliburton Wireline & Perforating Attn: Fanny Sari 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-275-2605 FRS—ANC@halliburton.com Delivered to: Alaska Oil and Gas Conservation Comm. Attn.: Natural Resource Technician 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of the sender above Transmittal Date: RECEIVED APR 13 2020 A®GCC 192080 32787 13 -Mar -20 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Fanny Sari, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com Date: V! (i�l (�ozL ; Signed: WELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # CD # 1 2M-07 50-103-20178-00 906173399 Kuparuk Plug Setting Record Final -Field 14 -Dec -19 0 1 2 113-04 50-029-20429-00 906174414 Kuparuk Packer Setting Record Final -Field 16 -Dec -19 0 1 3 1A 01 50-029-20590-00 906236618 Kuparuk Packer Setting Record Final -Field 24 -Jan -20 0 1 4 1A 15 50-029-20711-00 906270889 Kuparuk Packer Setting Record Final -Field 26 -Jan -20 0 1 5 1A-17 50-029-22102-00 906333945 Kuparuk Packer Setting Record Final -Field 21 -Feb -20 0 1 6 113-04 50-029-20595-00 906221237 Kuparuk Packer Setting Record Final -Field 4 -Jan -20 0 1 7 8 -Jan -20 8 1D-130 50-029-22815-00 906340407 West Sak Packer Setting Record Final -Field 10 -Mar -20 0 1 9 1D-135 50-029-22816-00 906236619 West Sak Packer Setting Record Final -Field 14 -Jan -20 0 1 10 15 -Jan -20 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Fanny Sari, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com Date: V! (i�l (�ozL ; Signed: STATE OF ALASKA ALAR OIL AND GAS CONSERVATION COIIIISION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon r Plug Perforations rFracture Stimulate [ Pull Tubing r Operations Shutdown fl Performed: Suspend fl Perforate fl Other Stimulate r Alter Casing r Change Approved Program r Rug for Redrill f Perforate New Pool r Repair Well Re-enter Susp Well r Other: SetnattCvhh0>q P 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number. ConocoPhillips Alaska, Inc. Development 17 Exploratory n 192-080 3.Address: 6.API Number: Stratigraphic r Service r P. O. Box 100360,Anchorage,Alaska 99510 50-103-20178-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 25589 KRU 2M-07 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): none Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 10340 feet Plugs(measured) none true vertical 6127 feet Junk(measured) 10252 Effective Depth measured 10242 feet Packer(measured) 7300,7321,7369 true vertical 6126 feet (true vertical) 5735,5748,5775 Casing Length Size MD TVD Burst Collapse CONDUCTOR 79 16 121 121 SURFACE 3220 9.625 3262 2773RECEIVED PRODUCTION 10293 7 10333 6127 AUG 18 2015 CI NOV 12 2015AOGCC Perforation depth: Measured depth: 8110-8150, 8170-8250, 8400-8490,8560-8700, 8790-9100,9480-9520, 10000-10070 True Vertical Depth: 6053-6061,6065-6081,6099-6105,6106-6107,6109-6116,6121-6121,6121-6122 Tubing(size,grade,MD,and TVD) 3.5, J-55,8033 MD,6037 TVD Packers&SSSV(type,MD,and TVD) UPPER PACKER-2.72"UPPER PARAGON PACKER @ 7300 MD and 5735 TVD LOWER PACKER-2.72"LOWER PARAGON PACKER @ 7321 MD and 5748 TVD PACKER-BAKER HB RETRIEVABLE PACKER @ 7369 MD and 5775 TVD SAFETY VLV-OTIS TRSV SERIES 10 SAFETY VALVE @ 1799 MD and 1678 TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): no stimulation or cement squeeze during this operation 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 191 723 1140 221 139 Subsequent to operation 236 589 1283 226 122 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations P Exploratory fl Development p- Service fl Stratigraphic Copies of Logs and Surveys Run fl 16.Well Status after work: Oil 1 Gas r WDSPL Printed and Bectronic Fracture Stimulation Data r GSTOR rWINJ r WAG r GINJ rSUSP rSPLUG r 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: none Contact Tyson Wieseq@ 263-4250 Email Tyson.M.Wiese a(�conocophillips.com Printed Name Tyson Jiese Title Sr. Wells Engineer Signature Phone:263-4250 Date Cti`1 /'�7b15 fril._ g/2// RBDM9\ AUG 1 9 2015 Form 10-404 Revised 5/2015 A Q0�� Submit Original Only r . i:'' KUP PROD • 2M-07 �OI"IOCtl 11llIpSK4a T , Well Attributes Max Angle&MD TD Alaska,Inc Wellbore API/UWI Field Name Wellbore Statusnol(°) MD(ftKB) Act Btm(ftKB) Conocokhops 501032017800 KUPAR UK RIVER UNIT PROD ' 91.03 9,659.65 10,340.0 •.. Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 2M-07,7/28/20152:36:40 PM SSSV:TRDP 60 11/1/2014 Last WO: 9/17/1992 :Vesical schematc(actuah Annotation Depth(ftKB) End Date Annotation Last Mod By End Date , Last Tag: 10,252.0 7/18/1993 Rev Reason:SET PATCH AND FRAC SLEEVE hipshkf 7/28/2015 HANGER,37.6 1.1 Casing Strings I Casing Description OD(in) ID(in) Top(ftKB) Set Depth(RKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread CONDUCTOR 16 15.062 42.0 121.0 121.0 62.58 H-40 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(DKB) Set Depth 171: ., WtlLen(L..Grade Top Thread !� SURFACE 9 5/8 8,921 41.7 3,261.5 8 47,00 J-55 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(IGrade Top Thread PRODUCTION 7 6.276 39.3 10,3326 6,126.6 26.00 L-80 AB-MOD ✓A CONDUCTOR;42.0-121.0- Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(ND)(...Wt(Ibttt) Grade Top Connection TUBING 4x3.5 4 3.476 37.6 8,033.5 6,036.7 11.00 J-55 DSSHTC SLEEVE 1 799.2, Completion Details SAFETY VLV;1,799.2 t p Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) 37.6 37.6 0.08 HANGER FMC GEN IV TUBING HANGER 4.000 1,7992 1,678.5 43.11 SAFETY VLV OTIS TRSV SERIES 10 SAFETY VALVE 3.313 4,987.9 4,056.4 41.92 XO Reducing CROSSOVER 4 x 3.5 3.500 GAS LIFT;3,173.5 7,355.6 5,767.3 55.96 PBR BAKER PBR w/10'STROKE 3.000 7,369.3 5,774.9 56.38 PACKER BAKER HB RETRIEVABLE PACKER 2.890 7,406.9 5,795.5 57.20 NIPPLE CAMCO D NIPPLE NO GO 2.750 8,032.7 6,036.5 77.84 WLEG BAKER WIRELINE RE-ENTRY GUIDE 3.015 Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) SURFACE;41.7-3,2615-4 Top(ND) Top Incl Top(ftKB) (ftKB) (°) Des Com Run Date ID(in)1,799.2 1,678.5 43.11 SLEEVE 3.35"X 110"MODIFIED FRAC SLEEVE(2.70")SET 7/20/2015 2.700 IN SAFETY VALVE 117,300.0 5,735.0 52.97 UPPER 2.72"UPPER PARAGON PACKER 7/20/2015 1.630 PACKER GAS LIFT;5,019.2 - 7,303.8 5,737.3 53.13 SPACER PATCH ASSEMBLY SPACER PIPE 7/20/2015 0.016 PIPE 7,321.3 5,747,7 54.09 LOWER 2.72"LOWER PARAGON PACKER 7/19/2015 1.630 PACKER GAS LIFT;6,267.2 xI 10,252.0 6,125.8 89.32 FISH 1"GLV 8 1"DV Also Lower Arm Assembly 0)Merle 4/22/1994 0.000 KO Tool GAS LIFT;6,803.3 Perforations&Slots Shot Dens UPPER PACKER,7,300.0Top(ND) Btm(ND) (shotslf t I Top(MB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Corn 8,110.0 8,150.0 6,052.8 6,061.1 C-4,A-5,2M- 7/21/1993 1.7 IPERF 180 deg.phasing,41/2" GAS LIFT'7,307.8 07 TCP SPACER PIPE;7,303.8 I', 8,170.0 8,250.0 6,065.2 6,081.2 A-4,2M-07 7/21/1993 1.7 (PERF 180 deg.phasing,4 1/2" TCP 8,400.0 8,490.0 6,099.3 6,104.9 A-3,2M-07 7/21/1993 1.7 IPERF 180 deg.phasing,41/2" LOWER PACKER;7,321.3 ea' j TCP ii 8,560.0 8,650.0 6,106.4 6,1072 A-3,2M-07 7/21/1993 1.7 IPERF 180 deg.phasing,4 1/2" TCP .I 8,650.0 8,690.0 6,107.2 6,107.2 A-3,2M-07 7/12/1993 4.0 IPERF 180 deg.phasing,4 1/2" PBR;7,355.6 TCP PACKER;7,369.3 '� 8,690.0 8,700.0 6,107.2 6,107.2 A-3,2M-07 7/21/1993 1.7 IPERF 180 deg.phasing,4 1/2" allTCP NIPPLE,7,4069 8,790.0 9,100.0 6,108.6 6,116.3 A-3,2M-07 7/21/1993 1.7 IPERF 180 deg.phasing,4 1/2" TCP I9,480.0 9,520.0 6,121.1 6,120.9 A-3,2M-07 7/7/1993 4.0 IPERF 180 deg.phasing,4 12" WLEG;8.0327 TCP 10,000.0 10,040.0 6,121.3 6,121.9 A-3,2M-07 6/4/1993 4.0 IPERF 180 deg.phasing,4 1/2" TCP 10,030.0 10,070.0 6,121.7 6,122.4 A-3,2M-07 7/2/1993 4.0 APERF 180 deg.phasing,4 12" TCP � w IPERF;8,110.0-8,150.0- Mandrel Inserts St ati IPERF;8,170.0-8,250.0- on Top(ND) Valve Latch Port Size TRO Run N Top(ftKB) (ftKB) Make Model OD lin) Sery Type Type (in) (psi) Run Date Com _,.„ 1' 3,173.5 2,705.5 CAMCO KBMG 1 GAS LIFT GLV BK5 0.188 1,225.0 8/2/2009 10:00 IPERF;8,400.0.8,490.0- 2 5,019.2 4,079.7 CAMCO KBUG 1 GAS LIFT GLV BK5 0.250 1,325.08/2/2009 3:30 3 6,2672 5,000.3 CAMCO KBUG 1 GAS LIFT OV BK5 0.250 0.0 4/20/2015 9:30 IPERF;8,560.0.8,650.0-, r 4 6,8033 5,398.6 CAMCO KBUG 1 GAS LIFT DMY BK5 0.000 0.0 7/24/1993 2:30 - - 5 7,307.8 5,739.7 CAMCO MMG-2 1 12 GAS LIFT DMY RK 0.000 0.0 6/4/2015 HI- IPERF;8E50.0.8690.0- SEAL IPERF;8,690.0-5700.0-- A_ EXT _ .__ PKG 8:00 IPERF;8,790.0-9,100.0- Notes:General&Safety - 'm- End Date Annotation -• ---- 11/10/2010 NOTE:View Schematic w/Alaska Schematic9.0 IPERF;9,480 0-9,520.0- IPERF;10,000.0-10,040.0- APERF;10,030.0-10,070.0- -. .- f FISH;10,252.0 PRODUCTION;39.3-10,332.6 • 2M-07 WELL WORK SUMMARY ' DATE SUMMARYOPS 4/12/2015 (AC EVAL)TIFL- FAILED DUE TO INFLOW (1130'TOTAL)AND PRESSURE INCREASE. IC POT- PASSED; IC PPPOT- PASSED. 4/20/2015 DRIFTED TBG WITH 2.49" & 5'x 2" BAILER TO 8015' SLM (-78 DEG DEVIATION). PULLED OV(CHECK FOULED) @ 6267' RKB AND REPLACED IN KIND. BLED 500 PSI OFF IA. COMPLETE. 4/23/2015 (AC EVAL) : RE-TIFL (FAILED) DUE TO IA PSI INCREASE AND IA FL INFLOW DURING MONITOR. 5/3/2015 WELL FLOWING ON ARRIVAL RAN LDL TO IDENTIFY LEAK© STA.#5 MANDREL ATTEMPTED TO PULL STA.#5 RK-OV. IN PROGRESS. 5/4/2015 RAN 1.7" LIB TO STA.#5 MANDREL(see log details) PULLED STA.#5 RK-DMY© 7,308' RKB RAN POCKET POKER TO STA.#5 SET STA.#5 RK-DMY @ 7,308' RKB. JOB COMPLETE. 5/7/2015 (AC EVAL) RE-TIFL- FAILED DUE TO IA FLUID INFLOW AND PRESSURE INCREASE. 5/26/2015 PULL FRACE SLEEVE FROM SSSV& HANG UP REPEATEDLY IN TBG, ATTEMPT TO DRIFT FRAC SLEEVE W/O PACKING BUT UNABLE TO DRIFT FREELY IN TBG DOWN SSSV, HAVING FRAC SLEEVE DRILLED FOR SHEAR STOCK TO USE AS HOLD OPEN SLEEVE DURING JOB...JOB IN PROGRESS. 5/27/2015 DRIFT FOR 2.75" CA-2 TO NIPPLE @ 7407' RKB, PULL RK-DGLV FROM ST#5, SET CA-2 IN NIPPLE © 7407' RKB, SET 2.80" CATCHER ON TOP OF CA-2 @ 7407' RKB JOB IN PROGRESS. 5/28/2015 LRS CIRCS OUT DOWN TBG & UP IA TAKING RETURNS TO 2M-08 FLOWLINE, 178 BBLS OF SEAWATER& 77 BBLS OF DIESEL, U-TUBE, PERFORM PASSING CMIT-TxIA TO 2500#, SET RK-DGLV IN ST# 5 @ 7307' RKB, ATTEMPT TO MIT-T TO 2500# BUT IA TRACKS....JOB IN PROGRESS. 5/29/2015 SET FRAC SLEEVE IN SSSV @ 1799' RKB, LOG LDL PUMP @ .45 BPM DOWN TBG & UP IA, SHOW ST# 5 @ 7308' RKB IS LEAKING, CONFIRMED W/STATION STOPS ABOVE & BELOW, ATTEMPT TO PULL ST#5...JOB SUSPENDED DUE TO UNIT MAINTENANCE. 6/3/2015 SET HOLD OPEN SLEEVE IN TRSV© 1799' RKB. ATTEMPTED TO PULL ST#5, SAT DOWN IN ST#3 © 6267' RKB WHILE RIH & COULDN'T PASS. *JOB IN PROGRESS 6/4/2015 SET MODIFIED FRAC SLEEVE (3.35" OD x 110", 2.70" ID) IN TRSV @ 1799' RKB. PULLED DMY VLV FROM ST#5 @ 7307' RKB AND SET EXT PACKING DMY VLV IN SAME. LRS ATTEMPTED MIT-T TO 2500#, BUT IA TRACKED. PULLED VLV FROM ST#5 AND REPLACED WITH HIGH-SEALABILITY EXT PACKING DMY VLV. LRS ATTEMPTED MIT-T TO 2500#. FAILED MIT-T. READY FOR ELINE CALIPER. JOB IN PROGRESS 6/9/2015 LOGGED 24-ARM MULTIFINGER CALIPER SURVEY FROM TAGGED TD OF 7370' TO SURFACE. CORRELATED TO THE WELL JEWELRY. 7/4/2015 DRIFT THROUGH HOLD OPEN SLEEVE W/23'X 2.69" DMY PATCH DRIFT DOWN TO 7330' SLM; PULLED HOLD OPEN SLEEVE © 1799' RKB; ATTEMPT TO PULL CATCHER @ 7356' SLM (SHEARED GS). IN PROGRESS. 7/5/2015 PULLED CATCHER © 2.75" CA-2 PLUG @ 7407' RKB; SET HOLD OPEN SLV @ 1799' RKB; DRIFT W/ DMY GYRO DOWN TO 8153' RKB (STOPPED DUE TO DEVIATION); MEASURE BHP @ 8182' RKB. IN PROGRESS. 7/6/2015 PULLED HOLD OPEN SLV @ 1799' RKB; BRUSH n' FLUSH PATCH INTERVAL DOWN TO 7407' RKB; DRIFT CLEANLY W/23'X2.74" DMY PATCH DOWN TO 7407' RKB (OIL JARS HUNG UP IN TRDP COMING OOH, PUMP DOWN TBG @ 1.25 BPM TO GET BACK THROUGH). READY FOR DSL (PATCH) 7/19/2015 SET 2.72" PARAGON PACKER @ 7,325' RKB SET TEST TOOL IN LOWER PACKER @ 7,325' RKB LRS PERFORMED PASSING CMIT TxIA TO 2,500 PSI. IN PROGRESS. 7/20/2015 SET 2.27" PARAGON PA ER AND SPACER PIPE IN LOWER ANCOR @ 9,325' RKB (mid element of upper packer ,303' RKB) ' SET PARAGON PACKER EST TOOL IN UPPER PACKER @ 7,241' SLM LRS PERFORMED PASSING MIT-T TO 3,000 PSI SET FRAC SLEEVE (2.7" ID, 110" oal) @ 1,799' RKB ATTEMPTED MIT-IA TO 2,500 PSI, UNABLE TO PRESSURE UP ON IA. IN PROGRESS. 7/21/2015 BLED IA DOWN TO 0 PSI, IA GAINING PRESSURE BACK PULLED FRAC SLEEVE @ 1,755' SLM (1,799' RKB) PULLED UPPER PATCH ASSEMBLY @ 7,303' RKB. IN PROGRESS. 7/22/2015 SET TTS TEST TOOL IN PARAGON II PACKER @ 7,325' RKB LRS PERFROMED PASSING CMIT TxIA TO 2,500 PSI. SET 2.72" PARAGON II PACKER AND SPACER PIPE @ 7,303' RKB CENTER ELEMENT SET TTS TEST TOOL IN UPPER PARAGON II PACKER @ 7,303' RKB PERFORMED PASSING MIT-T TO 3,000 PSI, PERFROMED PASSING DRAW DOWN TEST ON IA SET FRAC SLEEVE (3.35" od, 2.7" id, 110" oal) @ 1,799' RKB. READY FOR E-LINE GYRO. 7/24/2015 PERFORMED GYRO SURVEY FROM SURFACE TO 7294'. TAGGED AT 7294'. DID NOT ATTEMPT TO WORK THROUGH AS LOGGING INTERVAL ENDED AT 7300'. WELL HANDED BACK OVER TO DSO TO PUT IN PRODUCTION. JOB COMPLETE. 7/27/2015 (AC EVAL) RE-TIFL PASSED. \g2.-015 0 7-5q"\1 WELL LOG TRANSMITTAL DATA LOGGED 1 K BND't4E/2o1; To: Alaska Oil and Gas Conservation Comm. June 18, 2015 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 1 '} JUN 26 2ti1 RE: Multi Finger Caliper(MFC) : 2M-07 Run Date: 6/9/2015 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Chris Gullett, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com 2M-07 Digital Data(LAS), Digital Log file, Casing Inspection Report, 3D Viewer 1 CD Rom 50-103-20178-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Chris Gullett 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fax: 907-273-3535 FRS_ANC@halliburton.com Date: Signed: 6...eAceet XHVZE Pages NOT Scanned in this Well History File This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. l~ ~.-'- ~ 0 File Number of Well History File PAGES TO DELETE Complete RESCAN n Color items- Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original - Pages: Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED · [] ' Logs 'of various kinds . [] Other COMMENTS: n Scanned by: ianna Vincent Nathan Lowell TO RE-SCAN Notes: - Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: Is~ CanocoPhillips P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 17, 2010 Mr. Dan Seamount Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 ~, h~~. ~~ • ~~~~~ APR ~ `~ 2010 ~ask~ CJii ~ Gas Gans, c;ommissior, ~nchoraa ~a o7 a~ Dear Mr. Dan Seamount: Enclosed please fmd a spreadsheet with a list of wells from the Kuparuk field (KRil). Each of these wells was found to have a void in the conductor. These voids were filled with cement if needed and corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement was pumped January 16, March 21, 2010. The corrosion inhibitor/sealant was pumped April 15, 16 and 17, 2010. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Perry Klein or MJ Loveland at 907-659-7043, if you have any questions. Projects Supervisor • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Kuparuk Field 4/17/2010 26, 2E, 2G 2H 2K, 2M 2V 2W 2X, 2Z 8~ 3S PAD's Well Name API # PTD # Initial top o cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft al 2B-05 50029210670000 ' ' 1840040 24" n/a 24" n/a 4.2 4/16/2010 26-08 50029210790000 1840260 21" 3.30 7" 1/16/2010 2.5 4/16/2010 26-16 50029211460000 1841140 92" 0.65 3/21/2010 2.5 4/16/2010 2E-10 50029212460000 1842300 SF Na n/a Na 5.9 4/16/2010 2E-17 50029224190000 1931740 8'9" 1.50 19" 1116/2010 3.4 4/16/2010 2G-13 50029211600000 1841290 SF Na 22" n/a 3.4 4/16/2010 2H-07 50103200450000 1851700 SF n/a 17" Na 2.1 4/15/2010 2H-09 50103200500000 1852590 SF n/a 17" Na 2.5 4/15/2010 2H-15 50103200340000 1840860 SF n/a 17" Na 2.5 4/15/2010 2H-16 50103200350000 1840870 SF n/a 17" Na 2.5 4/15/2010 2K-19 50103201180000 1891090 53" 0.50 9" 1/16/2010 2.1 4/15/2010 2M-07 50103201780000 1920800 SF Ma 17" Na 3.4 4/15/2010 2M-08 50103201840000 1921010 SF Na 17" Na 2.1 4/15/2010 2M-20 50103201690000 1920480 SF n/a 17" Na 2.5 4/15/2010 2M-22 50103201700000 1920490 SF n/a 17" n/a 2.5 4/15/2010 2M-28 50103201740000 1920700 SF n/a 18" Na 2.1 4/15/2010 2V-06 50029210540000 1831790 SF Na 19" Na 7.6 4/16/2010 2V-10 50029213100000 1850480 SF Na 19" Na 2.5 4/16/2010 2V-16 50029212960000 1850330 SF Na 21" Na 5.1 4/16/2010 2W-03 50029212740000 1850110 SF Na 37" Na 4.2 4/16/2010 2X-11 50029211880000 1841640 SF n/a 17" Na 6 4/17/2010 2Z-11 50029213790000 1851380 SF n/a 19" n/a 2.5 4/15/2010 2Z-12A 50029213800100 1951480 SF n/a 19" Na 2.5 4/15/2010 2Z-13A 50029213600100 2061700 SF n/a 22" n/a 4.25 4/15/2010 2Z-19 50029218820000 1881300 SF n/a 16" n/a 2.1 4/15/2010 3S-09 50103204320000 2022050 SF Na 45" Na 23 4/17/2010 THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR BEFORE NO,,VEMBER 13, 2ooo -E p-L MATER I T-' H' IS E IA L U N D E II M A R K-E-R R G e o I o9 ~ c a 1 F,i a t e r' ~i' a '1 s Z n v e n t ,c,/" ',:/ T DAT,-4 PI US tI!.,D"i' /,...-L 8000 ..... 9336 CORRECTED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ~ WELL COMPLETION OR RECOMPLETION REPORT AND LO 1 Status of Well Classification of Service Well OIL E~ GAS ~ SUSPENDED ['--] ABANDONED E~ SERVICE r'--] 2 Name of Operator 7 Permit Number ARCO Alaska, Inc 92-80 ~ _ 3 Address 8 APl Number P.O. Box 100360, Anchorage, AK 99510-0360 50-103-20178 4 Location of well at sudace ~ ~,~:~ ~ ~" ~"~'~?"*~7 '~~ 9 UnitorLeaseName 114' FSL, 94' FWL, SEC 27, T11N, R8E, UM [~ ~ j KUPARUK RIVER At Top Producing Inte~al i ~~! ~: ,"~ ~.j' 10 Well Number ~~¢ r ~IED' ~~,' ~ ;~[;~ ~ 11 Field 2M-07 and 731' FSL, 1468' FEL, SEC 33, T11N, R8E, UM~~'-~ ~ At Total Depth ~-~J . Pool 1351' FNL, 2249' FEL, SEC 4, T10N, R8E, UM KUPARUK RIVER 5 Elevation in feet (indicate KB, DF, etc.) 6 Lease Designation and Serial No. KUPARUK RIVER RKB 146', PAD 105' GL ADL 25589 ALK 2675 12 Date Spudded 13 Date T.D. Reached 14 Date Comp., Susp. or Aband. 15 Water Depth, if offshore }16 No. of Completions 9/10/92. 9/17/92. 07/23/93. NA feet MSLI 1 1'~ Total Depth (MD+TVD) 18 Plug Back Depth (MD+~D) 19 Directional Suwey ~20 Depth where SSSV set ~ 21 Thickness of permafrost MD, 6127'TVD 10242'(BP ~ 10238')MD, 6126'TVD YES ~ NO ~~ 1799' feetUD~ 1400' APPROX 10340' 22 Type Electric or Other Logs Run CDR, CDN, CET, GR/CCL, CET, CBT, GCT 23 CASING, LINER AND CEMENTING RECORD SE~ING DEPTH MD CASING SIZE ~ GRADE TOP ~ HOLE SIZE CEMENT RECORD 16" 62.5~ H-40 SURF 121' 20" 245 ASII CMT .... 9-5/8" 36ff J-55 SURF 3262' 12.25" 670 PF E CMT, 510 SX CLASS G CMT TOP JOB- 95 SX TYPE C CMT "7 26ff J-55 SURF 10329' 8.5" 450 SX CLASS G CMT I 24 Pedorations open to Production (MD+TVD of Top and BoEom and 25 TUBING RECORD intewal, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 8110'-9100' W/ 4-1/2" TCP GUN MD 6053'-6116' TVD 4"/3.5" 11f/9.3~ J-55 8034' 7369' 9450'-10070' W/4-1/2" TCP GUN MD 6121'-6122' TVD 26 ACID, FRACTURE, CEMENT SQUEEZE, ETC DEPTH INTERVAL (MD) I AMOUNT & KIND OF MATERIAL USED *See affached Fractur~Stimulation repeals 27 PRODUCTION TEST Date First Production ~Method of Operation (Flowing, gas lift, etc.) Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO TEST PERIOD ~ FIowTubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OILGRAVITY-API (corr) Press. 24-HOUR RATE ~ ..... 28 CORE DATA .... Brief description of lithology, porosi~, fractures, apparent dips and presence of oil, gas or water. Submit core chips. RECEIVED $ EP - 1993 Alaska 0il & 6~s 0ohs. 6om~¢ss~o~ Anch0rago Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. i,.~ ~' GEOLOGIC MARKERS FORMATION TESTS NAME' %' Include interval tested, pressure data, all fluids recovered and gravity, ~ "~ MEAS DEPTH TRUE VERT. DEPTH GOR, and time of each phase. TOP OF. ,~PARUK C 81 1 1' 6 0 5 3' 31. LIST OF A~ACHMENTS RE~ OF OPE~TIONS, 2 COPIES OF DIRECTION~ SURV~, F~R~STIMU~TION RE~S 32. I hereby certify that the foregoing is true and correct to the best of my knowlege. Signed .P~~~'. _ Title ~~5 ~~ . DATE ~~ INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 ADDENDUM WELL: O6/O7/93 2M-07 PERFS: Stage 1. Stage 2 Stage 3 Stage 4 10,000'- 10040' Pmp 150 bbl SIk H20 @ 35 bpm 3600-2860 psi ISIP: 1597 Pmp 100 bbl SIk H20 @ 35 bpm 3370-2773 psi ISIP 1533 Pmp 234 bbl YF 140D SW @ 35-20 bpm 3160-4600 psi Pmp 400 bbl SLK Diesel Flush @ 20-25 bpm 4600-5100 psi Well started pressuring out with SLK H20 @ perfs Fluid to recover: 474 Sand in zone: 0 Sand in casing: 0 Drilling Superintendent Date ADDENDUM WELL: O7/O3/93 2M-07 PERFS: Stage 1. Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 Stage 7 Stage 8 10,000'-10040' & 10030'-10070' Data Frae 350 bbls Delay XL gel sw @ 50 bpm 4000-3950 psi Flush 382 bbls Non XL gel sw @ 35 bbls 3950-3050 psi ISIP 1986 psi, FG .77, Perf Fric 500 psi Pad 380 bbls Delay XL gel sw @ 10 bpm 3700-3430 psi 1 PPA 270 bbls Delay XL gel sw 1 PPG 16/20 @ 35 bpm 3430-3500 psi 2 PPA 260 bbls Delay XL gel sw 2 PPG 16/20 @ 35 bpm 3500-3270 psi 4PPA 230 bbls Delay XL gel sw 4 PPG 12/18 @ 35 bpm 3270-3050 psi 6 PPA 150 bbls Delay XL gel sw 6 PPG 12/18 @ 35 bpm 3050-2900 psi 8 PPA 175 bbls Delay XL gel sw 8 PPG 12/18 @ 35 bpm 2900-4120 psi Screened out instantaneously w/5 ppg @ perfs Fluid to recover: 1800 Sand in zone: 55000 Sand in casing: 82000 Drilling Supe'rinte"'ndent ' RECEIVED S E P -- 2 199,3 Alaska Oil & Gas Cons. bumrnission Anchorage Date ADDENDUM WELL: 07/08/93 2M-07 PERFS: Stage 1. Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 Stage 7 Stage 8 Stage 9 Stage 10 Stage 11 9480'-9520' Pmp 350 bbls Delay XL GW @ 50 bpm 4050-3616 psi Pmp 362 bbls SLK water @ 35 bpm 3616-2490 psi Shut In Pad 468 bbls DXL GW @ 35 bpm 3703-3607 psi @ perf Pad 362 bbls DXL GW @ 10 bpm 2348-2408 psi @ perf Pmp Pmp Pmp Pmp Pmp Pmp Pmp Pmp 270 Delay XL GW 1 PPG 16/20 @ 35 bpm 3602-2948 ps~ 260 Delay XL GW 2 PPG 16/20 @ 35 bpm 3177-2720 ps~ 230 Delay XL GW 4 PPG 12/18 @ 35 bpm 2760-2490 ps~ 150 Delay XL GW 6 PPG 12/18 @ 35 bpm 2640-2430 ps~ 240 Delay XL GW 8 PPG 12/18 @ 35 bpm 2504-2357 ps~ 321 Delay XL GW 10 PPG 12/18 # 35 bpm 2408-2577 ps~ 50 bbls Flush sw 2403-2577 psi 305 10.7 brine 2577-2055 psi Fluid to recover: 3090 bbls Sand in zone: 236,314# Sand in casing: 356# Drilling Superintendent RECEIVED S E P - 2 t993 Alaska 0il & Gas f.;o¢~s, bufllFnJssJ0¢ Anchorage Date ADDENDUM WELL: 0712/93 2M-07 PERFS: Stage 1. Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 Stage 7 Stage 8 Stage 9 Stage 10 Stage 11 Stage 12 8650'-8690' Pmp 350 bbls Delay XL GW @ 50 bpm 2091-4238 psi Pmp 330 bbls SLK water @ 35 bpm 4500-3611 psi Pad 330 bbls DXL GW @ 10 bpm 3004-2668 psi @ perf Pad 385 bbls DXL GW @ 35 bpm 4165-3451 psi @ perf Pmp Pmp Pmp Pmp Pmp Pmp Pmp Pmp Pmp 270 Delay XL GW 1 PPG 16/20 @ 35 bpm 3451-2924 psi 260 Delay XL GW 2 PPG 16/20 @ 35 bpm 3011-2531 psi 230 Delay XL GW 4 PPG 12/18 @ 35 bpm 2590-2274 psi 150 Delay XL GW 6 PPG 12/18 @ 35 bpm 2366-2173 psi 240 Delay XL GW 8 PPG 12/18 @ 35 bpm 2247-2004 psi 300 Delay XL GW 10 PPG 12/18 @35 bpm 2041-1784 psi 96 Delay XL GW 12 PPG 12/18 @ 35 bpm 1835-1913 psi 15 Delay XL GW @ 35 bpm 1963 psi 309 10.7 Brine @ 35 bpm 1684 FIH Fluid to recover: 2947 bbls Sand in zone: 252,134# Sand in casing: 8335# RECEIVED S E P - 2 '~99~ Alaska Oil & Gas Cons. commission Anchorage Drill~enden~t~' Date ARCO ALASKA INC. DAILY OPERATIONS PAGE: 1 WELL: BOROUGH: UNIT: FIELD: LEASE: API: PERMIT: APPROVAL: 2M-07 NORTH SLOPE KUPARUK RIVER KUPARUK RIVER 50-103-20178 ACCEPT: 09/10/92 01:09 SPUD: 09/10/92 09:00 RELEASE: 07/23/93 07:30 OPERATION: DRLG RIG: PARKER 245 WO/C RIG: NORDIC 1 09/10/92 ( 1) PARKER 245 TD: 121'( 121) 09/11/92 ( 2) PARKER 245 TD: 3202'(3081) 09/12/92 ( 3) PARKER 245 TD: 3285'( 83) 09/13/92 ( 4) PARKER 245 TD: 6060'(2775) PU HWDP 9-5/8"~ 3262' MW: 9.2 VIS: 80 MVE RIG F/2M-12 TO 2M-07. SET RIG MODULE OVER 2M-07. MAKE UTILITY MODULE & CPM. ACCEPT RIG 0100 HRS. NU 20" ANN & DIVERTER LINES 42.10 TO STARTING HEAD F/TEST DIVERTERS & FILL CK FOR LEAKS W/STATEMAN. BAG CLOSE TIME 34 SEC. PU HWDP & JARS. TORQUE UP & SET'BACK. DRILL & SURVEY 9-5/8"@ 3262' MW: 9.6 VIS: 63 COMPLETE TORQUE UP & SET BACK OF HWDP & JARS. PU 3 STEEL DC & 3 MONEL, SET BACK. PU NAVIDRILL, CHANGEOUT STAB. PU BHA & MWD, ORIENT TOOLS-LOAD FLOOR W/INSPECTED TOOLS-CIRC & CHECK EQUIP FOR LEAKS. SPUD ~ 09:00 HRS 09/10/92. DRLG 12.25 HOLE F/121'-920'. REPAIR GLYCOL LEAK-TOP DRIVE. DRLG F/920'-2145' DRLG 12.25 HOLE F/2145'-3202' NU BOPE 9-5/8"~ 3262' MW: 9.6 VIS: 46 DRLG F/3202'-3285' CIRC & COND FOR SHORT TRIP. DRY JOB. SHORT TRIP TO HWDP. WASH & REAM F/1750'-1475' COMING OUT. CLEAR ON TRIP IN. CIRC & COND. DROP SURVEY. DRY JOB. POOH. LD BHA. RU TO RUN CSG. RUN 79 JTS 9-5/8", 47#, L-80 & 36#, J-55 BTC CSG. FS ~ 3262' & FC @ 3176' CIRC & COND. CMT W/670 SX PF E & 510 SX CLASS G CMT. PLUG DOWN W/2000 PSI. TEST CSG TO 2000 PSI. REPAIR BRIDGE CRANE. RD CSG EQUIP, RIG FLOOR, LD/LANDING JT. ND 20" ANNULAR. PERFORM TOP JOB W/95 SX TYPE C CMT. CHANGE OUT CSG ELEVATORS & BALES-ON W/STARTING HEAD. NU BOP-CHANGE OUT 13-5/8" RISER. TORQUE TO 15,000. DRILL & SURVEY 9-5/8"8 3262' MW: 9.6 VIS: 32 FIN NU BOPE. TEST ALL BOPE TO 3000 PSI. TEST WITNESSSED BY AOGCC. TEST TOOLS & SET WEAR BUSHING. PU BHA #2-CHANGE OUT BEARING SECTION IN TURBINE. PU ANADRILL & ORIENT TOOLS. TEST MUD ~ 400' RIH TO 3161' CUT 133' DRLG LINE. CIRC FOR CASING TEST. TEST CSG TO 2000 PSI. CLEAN OUT CMT F/3161'-3177'. DRILL PLUGS & FLOAT COLLARS. CLEAN OUT CMT TO 3261' DRILL SHOE & CMT F/3261'-3285' & 10' NEW HOLE TO 3295' CIRC F/FIT & RUN FIT ~ 3295' DRILL 8.5" HOLE F/3295'-~060' RECEIVED S E_ P - 2 t99 Alaska Oil & Gas Cons. commisSior~ Anchorage WELL: .2M-07 API: 50-103-20178 PERMIT: PAGE: 2 09/14/92 ( 5) PARKER 245 TD: 7532'(1472) 09/15/92 ( 6) PARKER 245 TD: 8884'(1352) 09/16/92 ( 7) PARKER 245 TD: 8884'( o) 09/17/92 ( 8) PARKER 245 TD:10057'(1173) 09/18/92 ( 9) PARKER 245 TD:10340'( 283) DRILL & SURVEY 9-5/8"8 3262' MW: 9.2 VIS: 35 DRILL 8.5" HOLE F/6060'-6965' CHANGE OUT SWIVEL PACKING NUT & SERVICE TOP DRIVE & RIG. DRILL 8.5" HOLE F/6965'-7340' CIRC HOLE CLEAN ~ 7340' POH TO 3536' REAM DOWN FOR LWD F/3536'-3627' POH TO MWD & LWD. CHECK SCREWS IN MWD & DN LOAD LWD INFO. FIN POH. LD TURBINE-BIT & PONY COLLAR. PU BIT NAVI DRILL & RIH TO SHOE. FILL PIPE-TEST ANADRILL TOOLS. TRIP IN HOLE. FILL PIPE & WASH & LOG F/ANADRILL 7290'-7340' DRILL KICKOFF #2 F/7340.'-7532' DRILL & SURVEY 9-5/8"8 3262' MW:10.4 VIS: 42 D~ILL & SLIDE Ff7532' 8884'. SURVEY EVERY 30' 5 S-135 @ 7683 ON 0~/14/92. STARTED PU DRILL & SURVEY 9-5/8"8 3262' MW:10.4 VIS: 45 DRILL & SURVEY F/8884'-8970' CIRC & COND MUD. INCREASE MUD WT TO 10.6 PPG. DRILL & SURVEY F/8970'-9053' CIRC & COND MUD. LOST 31 BBLS. WIPER TRIP TO 6500'_ RIH TO BTM, NO TIGHT SPOTS OR FILL. CBU ~ 9053'. LOST 66 BBLS WHILE CIRC. LOWER MUD WT F/10.6 PPG TO 10 4 PPG. DRILL & SURVEY F/9053'-9677'. LOST 38 BBL MUD. MUD GAS CUT TO 9.4 PPG. CBU, MUD @ 10 4 PPG ON BU. DRILL & SURVEY F/9677'-9730' RIH AFTER C/O BHA 9-5/8"8 3262' MW:10.4 VIS: 44 DRILL & SURVEY F/9730'-9964' CIRC HOLE CLEAN. WIPER TRIP TO 6500' NO TIGHT SPOTS. SERVICE RIG & TOP DRIVE. RIH TO BTM. CIRC & COND MUD, GAS-CUT TO 9.8 PPG. LOST 28 BBLS WHILE CIRC. DRILL & SURVEY F/9964'-10057' MWD FAILED. CIRC & COND MUD IN PREP F/TRIP TO C/O MWD. POOH. DOWNLOAD LWD. LD MWD, LWD MACH 1 MOTOR, & BIT. PU NEW BIT, MOTOR, MWD & LWD TOOLS(C/O BHA). PROGRAM LWD & RIH 400' TO TEST MWD. RIH. POOH TO RUN 7" CSG 9-5/8"8 3262' MW:10.4 VIS: 43 RIH TO 10057'. NO FILL ON BTM. CIRC & COND MUD. GAS-CUT TO 8.9 PPG. DRILL & SURVEY F/10057'-10146' SERVICE RIG & TOP DRIVE. DRILL & SURVEY F/10146'-10340'. CDR FAILED DUE TO HIGH SHOCKS TO TOOL. CIRC & COND MUD F/TRIP. WIPER TRIP TO 9-5/8" SHOE @ 3262'. SLIP & CUT DRILLING LINE. RIH TO 10340'. FILL PIPE @ 6000' & 8000'. WASH TO BTM F/10280'-10340' NO FILL. CIRC & COND MUD. GAS-CUT TO 9.5 PPG. INCREASE MUD WT TO 10.5 PPG F/CSG RUN. POOH TO 10130' AND WASH F/10130'-10340' TO ATTEMPT TO GET CDR LOG. CDR TOOL FAILED AGAIN ~ 10180'. SPOT PILL. POOH F/7" CSG RUN. LD S135 DP. RECEIVED o c. P - ~ 199;~'~ Alaska Oil & Gas Cons. Commission Anchorage WELL: API: PERMIT: 2M-07 50-103 -20178 PAGE: 3 09/19/92 (10) PARKER 245 TD:10340'( 09/20/92 (11) PARKER 245 TD:10340'( o) 12/04/92 (13) TD: 0 PB: 0 o) CIRC 7" CSG 8 TD 7"@10329' MW:10.4 VIS: 41 POOH. DOWN LOAD LWD & LD BHA. PULL WEAR BUSHING. RU GBR CSG EQUIP. HELD PRE-JOB SAFETY MEETING. RAN 7" CSG TO 4514' LOST 63 BBLS. CIRC @ 4514' PMP 180 BBLS-LOST 67 -- BBLS. RAN 7" CSG TO 6701' LOST 17 BBLS. CIRC @ 6701' · PMP 202 BBLS-LOST 35 BBLS. RAN 7" CSG TO 8502'. LOST 2 BBLS. CIRC @ 8502'. PMP 270 BBLS-LOST 69 BBLS. RAN 7" CSG TO 10329'. RU HOWCO. CIRC PRIOR TO CMT JOB. CBU ~ 2-3 BPM TO MINIMIZE MUD LOSS. REDUCED MUD WT OUT F/10.7 TO 10.4 PPG & INCREASED CIRC RATE TO 6 BPM. PIPE FREE. NO PACKING OFF PROBLEMS WHILE CIRC. PMP 1050 BBLS-LOST 200 BBLS. CURRENTLY CIRC @ 6 BPM WITH 82% RETURNS. HOWCO STARTED BATCH MIXING CMT @ 05:00 HRS. MVING TO 2M-04 7"~10329' MW:10.4 VIS: 0 CIRC @ 6 BPM W/82% RETURNS WHILE HOWCO MIXED CMT. RU HOWCO & PMP 450 SX CLASS G CMT. BUMPED TOP PLUG, PRESS TO 3500 PSI-LOST ALL PRESS. PMP ANOTHER 1/2 BBL, COULD NOT PRESS UP MORE THAN 50 PSI ON CSG. ANN FLOWING @ 1 BPM. CHECKED FLOATS-OK. SI WELL & MONITOR PRESS ON BACKSIDE. WAITED ON HOWCO & VAC TRUCK FOR ARCTIC PACK. OPENED ANN ~ 1500 HRS, FLOWING 1 BPM. FINAL SI PRESS ON ANN @ 124 PSI. RU FOR ARCTIC PACK. RIG PMP 440 BBL FRESH WATER, 1150 PSI 8 10 BPM. SWITCHED LINES TO HOWCO, PMP 33.4 BBL PERMAFROST C CMT W/.1 PPS NA CITRATE @ 6 BPM & 1000 PSI INITIAL, ~4.8 BPM & 550 PSI FINAL. PMP 50.3 BBL ARCTIC PACK.~ 6 BPM & 600 PSI INITIAL(INC TO 800 PSI BEFORE LOWERED RATE), 3 BPM & 600 PSI FINAL. 450 PSI SI PRESS. WOC. PRESS ON ANN DROPPED TO 0 PSI. OPEN CHOKE & MONITOR, NO FLOW BACK. ND STACK. PU STACK & SET SLIPS 8 130K. BLOW DOWN LANDING JT & MECHANICALLY CUT CSG. ND BOP & SET BACK. NU FMC 11" 3K X 7-1/16" 5K TBG SPOOL. TEST TREE & PACKOFF TO 3000 PSI-OK. MVE /2M-07 TO 2M-04. RELEASE RIG ~ 0500 HRS 09/20/92. ATTEMPT GR/CCL/CET/CBT 7"810329' MW: 0.0 MVE IN CTU W/E-LINE. RU SWS, RIH W/BR/CCL/CET/CBT, TIE INTO KUPARUK SANDS CDR @ 8200'. LOGGING DOWN. HAD GOOD CMT. TOOLS STOPPED SUDDENLY ~ 9252' LOST ALL TOOL SIGNALS, PU 150' ATTEMPT TO GO DOWN, NO RESULTS. PULL 100' & ATTEMPT TO GO DOWN. UNABLE TO GO, TBG STACKING OUT, NO TOOL SIGNAL, POH, RD, SECURE WELL. NOTE: NO NOTICABLE TOOL DAMAGE, WIRE SHORTED OUT IN HEAD CAUSING TOOL FAILURE. RECE V'ED S E P - 2 t99 Alaska Oil & Gas Cons. Oommission Anchorage WELL: API: PERMIT: 2M-07 50-103 -20178 PAGE: 4 01/05/93 (14) TD:10340 PB:10242 01/06/93 (15) TD:10340 PB:10242 01/07/93 (16) TD:10340 PB:10242 06/02/93 (17) TD:10340 PB:10242 RIH/BIT & SCRAPER 7"@10329' MW: 0.0 MVE RIG F/2M-29 TO 2M-07. ACCEPT RIG ~ 20:30 HRS ON 01/04/93. ND DRY HOLE TREE. NU BOP. REPAIR CHECK VALVE ON CHOKE LINE. SET TEST PLUG. TEST BREAKS IN BOP TO 3000 PSI. PULL TEST PLUG. SET WEAR BUSHING. RIH W/6-1/8" BIT & 7" CSG SCRAPER ON 3-1/2" DP. POOH & LD 3-1/2" 7"@10329' MW: 0.0 SERV RIG, CHECK CROWN. CONT RIH W/3-1/2" DP TO TAG ~ 10231' PU KELLY, WASH DOWN TO 10247'. PU & CBU @ 4 BPM & 1300 PSI. MIX & PMP HI-VIS SWEEP AROUND. ROTATE & RECIP WHILE PMP. BLOW DN & STAND BACK KELLY, RU TO POOH. POOH TO TOP OF HORIZONTAL KICKOFF @ 7000'. CBU @ 4.4 BPM & 1050 PSI. RIH TO 10227'. MIX HI-VIS PILL. PU KELLY, CIRC SWEEP AROUND ~ 4.4 BPM & 1500 PSI. ROTATE & RECIP WHILE PUMPING. CLEAN PTI #3 & RU FILTRATION UNIT. REVERSE CIRC @ 4 BPM WHILE STARTING FILTRATION, BRINE CLEANING UP WELL. REVERSE CIRC FILTERED BRINE @ 3 BPM & 1000 PSI, STOPPING OCCASIONALLY TO ALLOW UNIT TO CATCH UP & FILL PIT. MIX & PMP 25 BBL DRY JOB. POOH & LD 3-1/2" DP IN PREP FOR MOVE TO 2H-12. RIG RELEASED 7"@10329' MW: 0.0 SERV RIG, HELD BOP DRILL. CONT POH W/3-1/2" DP, SEND OUT SAME. RU CIRC EQUIP. FREEZE PROTECT 450' W/DIESEL. RD CIRC. FIN POH W/DP & SEND OUT, BREAK BHS. RD FLOOR EQUIP, ND FLOW RISER, HANG BLOCKS. ND BOP'S. PULL WEAR BUSHING. RELEASE RIG ~ 12:00 HRS 01/06/93. RIH W/RTTS 7"@10329' MW:10.4 NaCl/Br MOVE RIG OFF 2M-08. PU MATS & LINER. SET ON 2M-07. MOVE RIG ON 2M-07. ACCEPT RIG @ 12:30 HRS 06/01/93. ND TREE. SET TEST PLUG. NU 7-1/16" FULL OPENING MASTER VALVE. NU BOPS. TEST BOPS & CHOKE MANIFOLD TO 3000 PSI. TEST BLIND RAMS TO 4000 PSI. TEST WITNESS WAIVED BY JOHN SPAULDING OF AOGCC. ATTEMPT TO TEST CASING TO 4000 PSI. AT 3800 PSI, PRESS BROKE BACK TO ZERO. MONITOR WELL FOR FLOW WHILE WAITING FOR HOWCO RTTS & TOOL HAND. LOAD & STRAP 128 JTS OF 3-1/2" DP. REDUCE WT OF BRINE IN PITS F/10.9 PPG TO 10.4 PPG. MOVE DCS, SET WEAR BUSHING. UNLOAD & STRAP RTTS. MU RTTS & RIH TO 500' CIRC DIESEL CAP OUT OF WELL. RIH W/RTTS ON 3-1/2" DP (SPINNING WRENCH BROKE, CHAINING INTO HOLE). REPAIR LATCH ON DP ELEVATORS. CONT RIH (CHAINING) W/RTTS. RE£E VED S E P - 2 199; Alaska Oil & Gas Cons. CommissiOn Anchorage WELL: API: PERMIT: 2M-07 50-103 -20178 PAGE: 5 06/03/93 (18) TD:10340 PB:10242 06/04/93 (19) TD:10340 PB:10242 06/05/93 (20) TD:10340 PB:10242 06/30/93 (22) TD:10340 PB:10242 RIH W/PERF ASSY 7"@10329' MW:10.4 NaC1/Br CONT RIH W/RTTS ON 3-1/2" DP. TAGGED PBTD 8 10262'. SET RTTS 8 10236'_ TESTED BELOW TOOL:WELL TOOK FLUID 8 1 BPM, 1800 PSI. TESTED ANN ABOVE TOOL: HELD 2500 PSI OK. RELEASED RTTS. POH,LD RTTS. PU & DRESS HOWCO EZSV BP & RUNNING TOOL. RIH W/EZSV ON 3-1/2" DP. TAGGED 8 10261' PU TO 10256' & SET EZSV. PU & SHEAR OUT 8 200M LBS UP WT. WT TESTED BP TO 20M LBS. TEST 7" CSG TO 4000 PSI FOR 15 MIN-OK. POH. LD BRIDGE PLUG RUNNING TOOL. SLIP & CUT DRLG LINE. MU PERF ASSY IN ROTARY TABLE. RIH W/PERF ASSY ON 3-1/2" DP. POH LAYING DOWN DP 7"810329' MW:10.7 NaC1/Br CONT RIH W/PERF ASSY ON 3-1/2" DP. RU SWS & RIH W/WIRELINE TO SPACE OUT & ORIENT GUNS. POH W/MALFUNCTIONING SOUND DETECTOR. RIH W/WIRELINE. ROTATE DP TO ORIENT GUNS. RECEIVED CLEAR ORIENTING SIGNAL. POH W/WIRELINE & RD SWS. PRESS UP ANN TO 3000 PSI FOR 1 MIN, THEN BLED OFF. GUNS FIRED IN 17 MIN. PRESS CSG TO VERIFY PERF HOLES. CBU-GAS & OIL TO SURF. MONITOR WELL. WT UP BRINE IN PITS TO 10.7 PPG BRINE. MONITOR WEL-STABLE. PREP TO POH. POH LAYING DOWN DP. RIG RELEASED 7"810329' MW:10.7 NaC1/Br CONT POH LAYING DOWN DP. BREAK & LD PERF GUN ASSY. RIH W/DC'S & POH LAYING DOWN SAME. PULL WEAR RING. ND BOP'S. NU 7-1/16" VALVE. UNLOAD PIPE SHED & CLEAN PITS. RIG RELEASED 8 1500 HRS 06/04/93. SLIP & CUT DRLG LINE 7"810329' MW:10.7 NaC1/Br MOVE RIG F/iH PAD TO 2M PAD. REMOVE WHEELS F/CELLAR-INSTALL, LANDING, STAIRS, & CHOKE & KILL LINE. HANG BOPE IN SUB-STRUCTURE. MOVE RIG OVER 2M-07 WELL. ACCEPT RIG 8 1500 HRS 06/29/93. BLEED PRESS OFF WELL, 150 PSI. LEVEL RIG & SUB-BASE TO CLEAR 7-1/16" FULL OPEN VALVE. ND 7-1/16" VALVE & SET TEST PLUG. NU BOPE, FLOW RISER, CHOKE & KILL LINES. TEST BOPE, CHOKE & MUD MANIFOLD, ACUMMULATOR, & FLOOR VALVES. BOP TEST WITNESSED BY DOUG AMOS OF AOGCC. LOAD 3-1/2" DP. INSPECT & REPAIR HCR & 3" VALVE ONMUD CROSS WHICH FAILED DURING TEST. RU FLOOR EQUIP TO PU DP. RETEST 3 FAILED VALVES AFTER REPAIRS-ALL VALVES OK. LOAD & STRAP DC'S. SLIP & CUT DRILLING LINE. RECEIVED Alaska Oil & Gas Cons. Comm~Ss~of~ Anchorage WELL: API: PERMIT: 2M-07 50-103-20178 PAGE: 6 07/01/93 (23) TD:10340 PB:10242 07/02/93 (24) TD:10340 PB:10242 07/03/93 (25) TD:10340 PB:10242 07/04/93 (26) TD:10340 PB:10242 POH W/DP & BHA 7"810329' MW:10.7 NaC1/Br CONT TO LOAD & STRAP 3-1/2" DP. SLIP & CUT 50' OF DRILLING LINE. REPAIR LEAK IN DRILLING NIPPLE. LOAD & STRAP DRILL COLLARS & BOTTOMHOLE TOOLS. MU BHA & RIH W/TOTAL OF 304 JTS 3-1/2" DP TO 10019' MU KELLY, REAM & CIRC F/10019'-10252'. CBU @ 3 BPM. WELL PRODUCING SMALL AMT OF FORMATION SAND OVER SHAKERS. HAD SMALL SPILL (1 BBL BRINE) WHEN CIRC RATE-WAS INCREASED TO 4 BPM & FLUID CAME OVER BELL NIPPLE ON FLOW RISER. REPORT IN INCIDENT IS BEING PREPARED. BREAK & BLOW DOWN KELLY. RU TO POOH. POOH W/5 STDS DP PULLING WET. MIX & PMP DRY JOB FOR TRIP OUT OF HOLE. POOH W/DP & DC STD'S, STAND BACK SAME IN DERRICK. POOH W/3-1/2" DP & PERF GUNS 7"810329' MW:10.7 NaC1/Br CONT TO POH W/3-1/2" DP & BHA. LOAD SWS GUNS. HOLD SAFETY MEETING. MU GUNS. RIH W/SWS GUNS ON DP, FILLING DP EVERY 8 STDS. RU SWS WL. RIH, CORRELATE GUNS ON DEPTH. POH. RD SWS. PRESS DP TO 2200 PSI TO INITIATE PERF FIRING HEAD. GUNS FIRED AFTER 20 MIN DELAY. PERF F/10030'-10070' CBU @ 3.5 BPM & 1000 PSI. WELL STILL PRODUCING FAIR AMT OF FORMATION AND OVER SHAKERS. MIX & PMP DRY JOB. POOH LAYING DOWN SINGLES, STAND BACK 3-1/2" DP DOUBLES. PREP FOR FRAC 7"810329' MW:10.7 NaC1/Br CONT POH. LD DC'S & SWS GUNS. MOVE OUT GUNS & CLEAR FLOOR. MU C/O BHA & RIH ON 3-1/2" DP TO 8000' SLIP & CUT 50' DRILLING LINE. PU KELLY & RIH ONE JT @ A TIME, CIRC, ROTATE, & RECIP EA JT TO C/O HORIZONTAL SECTION OF CASED HOLE F/8000'-10256' TD USING TRI-STATE CIRC SUB. SIGNIFICANT AMT OF FORMATION SAND BEING CIRC OUT. STAND BACK KELLY. POOH W/6 STDS TO ABOVE PERFS. CBU TWICE. HOLE CLEANED UP W/NO SOLIDS EVIDENT AFTER SECOND BTMS UP. BEGIN CHANGING WELL OVER TO CLEAN,. NON-VISC BRINE IN PREP FOR FRAC. RIH F/DISPLACEMENT 7"~10329' MW:10.7 NaC1/Br CONT CHANGING WELL OVER TO CLEAN, NON-VISC BRINE IN PREP FOR FRAC. POOH STANDING BACK DP. INJ 4 BBLS CLEAN BRINE INTO PERFS @ 1 BPM & 1600 PSI TO VERIFY OPEN PERFS. ND BOP'S. BACK RIG OFF OF WELL FOR FRAC. HOLD SAFETY MEETING. WORKED ON RIG. MOVE RIG OVER WELL ACCEPT RIG @ 0000 HRS 07/04/93. NU BOPE. TEST BOPE. CONT NU FLOW RISER. UNABLE TO SET WEAR RING DUE TO SAND IN BOWL. WASH OUT BOWL & SET WEAR RING. RU TO RIH W/3-1/2" DP. RIH TO 1000'. BREAK CIRC. CONT TO RIH. RECEIVED S E P - 2 t995 Alaska Oil & Gas Cons. Commis$ior~ Anchorage WELL: API: PERMIT: 2M-07 50-103-20178 PAGE: 7 07/05/93 (27) TD:10340 PB:10242 07/06/93 (28) TD:10340 PB:10242 07/07/93 (29) TD:10340 PB:10242 07/08/93 (30) TD:10340 PB:10242 REVERSE CIRC HOLE CLEAN 7"@10329' MW:10.7 NaC1/Br HOOK UP LINES TO JET FLOWLINE. CONT RIH W/DP SLOWLY TO 2100' CIRC OUT FRAC GEL & SAND TAKING RETURNS OUT ANN VALVE & INTO OUTSIDE FLOW TANKS. RIH 10 STDS TO 2750', REVERSE CIRC FRAC GEL & SAND TAKING RETURNS OVER RIG SHAKERS. CONT RIH, REVERSE CIRC OUT GRAC FLUIDS & SAND EVERY 1000' TO 7750' BRING BRINE WT BACK UP TO 10.7 PPG. CONT TO RIH TO 7800' & TAG FILL. RU TO RIH WASHING DOWN 1 STD @ A TIME. WASH DOWN 5 STANDS TO 8150', PUMPING DOWN DP. REVERSE OUT FRAC FLUIDS & SAND. CONT RIH WASHING DOWN STANDS, AS NEEDED, & REVERSE CIRC OUT FRAC FLUIDS & SAND EVERY 750' TO 9650'. REVERSE CIRC HOLE CLEAN @ 3.5 BPM POOH 7"@10329' MW:10.7 NaCl/Br CONT REVERSE CIRC @ 100 SPM UNTIL RETURNS CLEAN. CIRC DOWN DP WHILE RECIP. OBTAINED LARGE AMT OF CARBOLITE @ BU. CONT CIRC & RECIP UNTIL RETURNS CLEAN. PMP DRY JOB. POOH. NU HALLIBURTON RUNNING TOOL & EZSV. RIH ON DP TO SET EZSV. RU CIRC HEAD & CIRC AREA CLEAN F/9540'-9560' TO SET EZSV. SET EZSV @ 9550'. PU W/22OK LBS TO SHEAR FREE F/EZSV. TEST EZSV TO 3500 PSI F/10 MIN-OK. PMP DRY JOB & POOH W/DP & EZSV RUNNING TOOL. RIH F/CLEAN OUT RUN 7"@10329' MW:10.7 NaC1/Br SERVICE RIG. CUT 50' OF DRILLING LINE. HOLD SAFETY MEETING. MU SWS GUNS. RIH W/SWS GUNS ON 3-1/2" DP. RU SWS WL. RIH W/GR/CCL/NOISE LOG TO ORIENT & CORRELATE DEPTH. J. B KEWIN REQUESTED THAT PERF INTERVAL BE CHANGED F/9450'-9490' TO 9480'-9520'. POH W/WL. PU ONE JT OF DP. RIH W/WL & ORIENT & CORRELATE GUNS. POH. RD SWS. PRESS DP TO 2800 PSI TO FIRE GUNS, PERF F/9480'-9520' CBU @ 3 BPM & 800 PSI. MIX & PMP DRY JOB. POH & LD 48 SINGLES. LD SWS GUNS. RIH W/6.125" BIT TO CLEAN OUT WELLBORE. POH 7"@10329' MW:10.7 NaC1/Br SERVICE RIG. WASH & REAM F/8005'-8266'. RIG DOWN. REPAIR SCR. WELL STABLE. WASH & REAM F/8266' 9553' TAGGED BRIDGE PLUG. CBU. ROTATE & WORK DP. CHANGE OVER TO CLEAR BRINE. BLOW DOWN KELLY. POH W/3-1/2" DP. Ri CE]VED S E P - t99 Alaska Oil & Gas Cons. CommissiOr~ Anchorage WELL: API: PERMIT: 2M-07 50-103-20178 PAGE: 8 07/09/93 (31) TD:10340 PB:10242 07/10/93 (32) TD:10340 PB:10242 07/11/93 (33) TD:10340 PB:10242 07/12/93 (34) TD:10340 PB:10242 MONITOR WELL PRESSURE 7"~10329' MW:10.7 NaC1/Br SERV RIG. FIN POH W/3-1/2" DP. PULL WEAR RING. ND BOP. CLOSE 7" MASTER VALVE. MOVE RIG OFF WELL TO RU FOR FRAC. MOVE RIG BACK OVER WELL. TEST ANN, RAMS, CHOKE & KILL LINES, & CHOKE MANIFOLD TO 3000 PSI. MONITOR PRESS ON WELL=250 PSI. BLEED OFF 12 BBLS. PRESS @ 250 PSI. BLEED OFF ANOTHER 12 BBLS. PRESS 8 250 PSI. MONITOR PRESS FOR ONE HOUR, DROPPED TO 230 PSI. MONITOR WELL FOR ONE HOUR, DROPPED TO 215 PSI. BLEED OFF 5 BBLS. MONITOR PRESS FOR ONE HOUR, PRESS ~ 95 PSI. BLEED OFF ANOTHER 5 BBLS & MONITOR PRESS. MONITOR WELL 7"~10329' MW:10.7 NaC1/Br MONITOR PRESS, DROPPED F/195 PSI TO 165 PSI. BULLHEAD , PRESS KEPT DROPPING. BLEED OFF PRESS, WELL DEAD. SET WEAR BUSHING. RIH W/3-1/2" DP & BIT. CHANGE WELL OVER TO VISC BRINE. POH. FLUID LEVEL NOT DROPPING, APPEARS WELL IS TRYING TO FLOW. RIH TO 8750' W/NO RETURNS. CBU & MONITOR WELL. WELL STABLE, NO FLOW. LOST FLUID WHILE CIRC. POH. 16 STDS, FLUID LEVEL DID NOT DROP. BULLHEAD AGAIN SEVERAL TIME UNTIL FLUID LEVEL DROPPED. MONITOR WELL. RIH W/TCP GUNS 7"@10329' MW:10.7 NaC1/Br SERV RIG. POH W/3-1/2" DP. MU BAKER MODEL D PKR W/TP & RIH W/3-1/2" DP. SET PKR @ 8750' RELEASE PKR SETTING TOOL. TEST PKR & BLANKING PLUG TO 3500 PSI FOR 15 MIN. SLIP & CUT 50' OF DRLG LINE. ATTEMPT TO PMP DRY JOB. BY PASS ON RUNNING TOOL NOT OPEN. COULD NOT GET CIRC THROUGH THE TOOL. POOH WET. MONITOR CELLAR TO PREVENT OVERFLOW. BAKER SETTING TOOL APPEARED OK FROM VISUAL INSPECTION. HOLD SAFETY MEETING. MU SWS 4-1/2" TCP GUNS. RIH W/SWS GUNS ON 3-1/2" DP. CHANGE OVER TO CLEAR BRINE 7"~10329' MW:10.7 NaC1/Br SERV RIG. RIH W/4-1/2" TCP SWS GUNS ON 3-1/2" DP. GUNS ARE LOADED W/ 4 SPF, 180 DEG PHASING, 34B CHARGE ORIENT TO TOP OF HOLE, 34C ORIENT TO BTM OF HOLE. RU SWS WL. RIH W/GR/CCL/NOISE LOG TO ORIENT & CORRELATE DEPTH. CORRELATE GUNS. POH. RD SWS. PRESS DP TO 2800 PSI THEN BLEED OFF TO FIRE GUNS, PERF 8605'-8690'. CBU @ 2 BPM TO MINIMIZE FLUID LOSS. POH & LD 24 SINGLES. LD SWS GUNS. MU BIT & RIH W/3-1/2" DP TO 7993' PU KELLY. SERV KELLY. WASH & REAM FROM 7993'-8752'. TAGGED PKR ~ 8752' CBU. DISPLACE WELL TO CLEAR BRINE. RECEIVED S E F - Z 199 Alaska Oil & Gas Cons. Oornmissio~ Anchorage WELL: API: PERMIT: 2M-07 50-103-20178 PAGE: 9 07/13/93 (35) TD:10340 PB:10242 07/14/93 (36) TD:10340 PB:10242 07/15/93 (37) TD:10340 PB:10242 07/16/93 (38) TD:10340 PB:10242 WT UP BRINE & MONITOR 7"@10329' MW:10.7 NaC1/Br FIN DISPL WELL TO CLEAR BRINE. SERV RIG. POH W/3-1/2" DP. PULL WEAR BUSHING. ND BOP. MOVE RIG OFF WELL. STANDBY DURING FRAC. CONT ELECTRICAL MAIN. WORK ON MOVING SYSTEM. MOVE RIG OVER WELL & LEVEL. NU BOP & FLOW NIPPLE. TEST ALL BROKEN FLANGES. FLOW BACK 20 BBLS TRYING TO BLEED OFF WELL PRESS. PRESS 8 260 PSI. START WT UP BRINE TO 11.5 PPG. MONITOR WELL, BLEED OFF 5 BBLS EVERY HOUR. FINAL PRESS DROPPED TO 150 PSI. RIH TO MILL/RETRV PKR 7"810329' MW:10.7 NaC1/Br BLEED OFF 5 BBLS, PRESS 150 PSI. BLEED OFF ADDITIONAL 5 BBLS, PRESS 150 PSI. BLEED OFF ADDITIONAL 5 BBLS, PRESS 140 PSI. LOAD 11.4 PPG BRINE IN PITS. BULLHEAD 30 BBLS OF 11.4 PPG BRINE. MONITOR PRESS, BLEED 2 BBLS, MONITOR (55 PSI). BULLHEAD 15 BBLS. MONITOR, BLEED 2 BBLS, MONITOR (11 PSI). BULLHEAD 15 BBLS. MONITOR-WELL DEAD. INSTALL WEAR BUSHING & RIH W/OPEN-ENDED DP. HOLE STARTED TAKING FLUID WHILE RIH. TAG FILL 8 8100' RU TO WASH DOWN STANDS. VACUUM OUT PITS. TRANSFER VISCOUS BRINE TO PITS. RU TO DISPOSE OF RETURNS. WASH DOWN STANDS FROM 8100' TO PKR 8 8752' WHILE DISPLACING WELL TO 10.7 PPG VISC BRINE. CIRC OUT HOLE 8 4-1/2 BPM WHILE RECIP DP. POH, LD 42 JTS DP. POH, S/B REST OF DP. TALLY BHA. MU PKR MILLING/RETRIEVING BHA, RIH ON 3-1/2" DP. RIH TO RETRIEVE PKR 7"810329' MW:10.7 NaC1/Br CONT TO RIH W/PKR MILLING/RETRIEVING ASSY. SLIP & CUT 50' OF DRILLING LINE. CONT RIH TO 8025'. TAG FILL. WASH STDS DOWN TO PKR TOP 8 8751'. PU KELLY, ENGAGE PKR W/GRAPPLE & MILL ON PKR SLIPS. CIRC & RECIP UNTIL RETURNS CLEAN. MIX & PMP DRY JOB. STAND BACK KELLY & POH W/FISHING STRING. NO RECOVERY. CHANGE OUT FISHING TOOLS & RIH TO RETRIEVE PKR. POH W/FISHING TOOLS 7"810329' MW:10.7 NaC1/Br MU KELLY, ATTEMPT TO ENGAGE PKR. MIX & PMP DRY OB. S/B KELLY & RU TO POH. POH W/FISHING TOOLS. NO RECOVERY. WAIT ON TRI-STATE TOOLS. PU & MU FISHING TOOLS. RIH. MU KELLY & WORK FISH. FISH BROKE LOOSE & STARTED MOVING FREELY. PU SINGLES & PUSH FISH DOWNHOLE. TAGGED UP WITH BTM OF PKR/TAILPIPE ASSY 8 9541' CIRC HOLE CLEAN. POH W/FISHING TOOLS. RECEIVED Ataska Oil & Gas Cons. CommiSSiOn Anchorage WELL: API: PERMIT: 2M-07 50-103-20178 PAGE: 10 07/17/93 (39) TD:10340 PB:10242 07/18/93 (40) TD:10340 PB:10242 07/19/93 (41) TD:10340 PB:10242 07/20/93 (42) TD:10340 PB:10242 LD FISH 7"@10329' MW:10.9 NaC1/Br CONT POH W/FISHING TOOLS. NO RECOVERY. TEST BOPE. TEST WITNESS WAIVED BY LOU GRIMALDI OF AOGCC. SLIP & CUT DRILLING SIRE. MU NEW FISHING TOOL ASSY. RIH W/FISHING TOOLS ON 3-1/2" DP. TAG UP @ 9541' MU KELLY & CIRC& ROTATE DOWN TO FISH. WORK FISH. PMP DOWN BAR TO SHEAR PMP OUT SUB. MIX & PMP DRY JOB. TEST UPPER & LOWER KELLY VALVES (COMPLETION OF BOP TEST). STAND BACK KELLY. POH SLOWLY-FISH HANGING UP IN COLLARS. RECOVERED ENTIRE PKR & TAILPIPE ASSY. BREAK DOWN & LD FISH. CIRC HOLE CLEAN 7"@10329' MW:10.8 NaCl/Br BREAK DOWN & LD FISH. CLEAR FLOOR. MU CLEAN-OUT BHA (6" CONCAVE MILL W/2 BOOT BASKETS.) RIH W/CLEAN-OUT BHA ON 3-1/2" DP. TAG BRIDGE PLUG @ 9552'. MU KELLY & LINE UP MUD FLOW TO PITS & MI SOLIDS CONTROL UNIT. MILL ON JUNK & BRIDGE PLUG. PUSH BRIDGE PLUG TO 9655' WHERE IT STOPPED ON FILL. FINISH DRILLING UP BRIDGE PLUG. PU SINGLES & ROTATE & CIRC TO PBTD. TAG PBTD (BRIDGE PLUG) @ 10251' CIRC HOLE CLEAN WHILE ROTATING & RECIP DP. 3-1/2 BPM, 1100 PSI. BLOW DN, S/B KELLY, POH STO 9500' & MU KELLY. CIRC HOLE WHILE ROTATING & RECIP DP. RIH W/PERF GUNS 7"810329' MW:10.8 NaCl/Br CIRC HOLE WHILE ROTATING & RECIP DP @ 9500' BLOW DOWN & S/B KELLY. POH 11 STDS TO 8860' MU KELLY, CIRC HOLE WHILE ROTATING & RECIP DP @ 8860' BLOW DOWN & S/B KELLY. POH 10 STDS TO 8100'. MU KELLY, CIRC HOLE WHILE ROTATING & RECIP DP @ 8100' BLOW DOWN & S/B KELLY. RIH TO 10252' PBTD. MU KELLY. CIRC HOLE WHILE ROTATING & RECIP DP @ PBTD. BLOW DOWN & S/B KELLY. RIG TO LD DP. TRANSFER FLUID, MIX & PMP SLUG. RD MI SOLIDS UNIT. POH. LD 12 JTS DP. POH STANDING BACK DP. LD BHA. RACK SWS PERF GUNS. MU & RIH 750' OF PERF GUNS. RIH W/3-1/2" DP, FILLING PIPE EVERY 8 STDS. PREP PERF GUNS F/RUN #2 7"@10329' MW:10.8 NaC1/Br CONT RIH W/SWS PERF GUNS ON 3-1/2" DP, FILLING PIPE EVERY 8 STDS. RU SCHLUMBERGER WL. RIH W/ORIENTING TOOLS. ORIENT GUNS. POH W/SWS ORIENTING TOOLS. RD SWS WL. RU TO PRESS DP. PRESS TO 2300 PSI TO ACITVATE FIRING HEAD, THEN CONT PRESS UP TO OPEN CIRC VALVE. VALVE OPENED @ 3300 PSI. WAIT FOR GUNS TO FIRE. GUNS FIRED @ 1524 HRS. CIRC GUN GAS F/WELL. LOST 6 BBLS BRINE TO FORMATION @ BEGINNING OF CIRC, THEN NO MORE LOSSES. PMP SLUG & POH, LAYING DOWN 45 JTS DP. POH SETTING BACK STDS. POH W/PERF GUNS. LD & SEND OUT GUNS. PREP SWS GUNS FOR SECOND RUN. CLEAN PITS, FLUSH LINES, TRANSFER FLUID, PREP CLEAR, NON-VISCOSIFIED BRINE FOR DISPLACEMENT. RECEIVED S E P - 2 i99 Alaska 0il & 6as 6o'ns. 6ommission Anchorage WELL: ·API: PERMIT: 2M-07 50-103-20178 PAGE: 11 07/21/93 (43) TD:10340 PB:10242 07/22/93 (44) TD:10340 PB:10242 07/23/93 (45) TD:10340 PB:10242 07/24/93 (46) TD:10340 PB:10242 SET STORM PKR 7"$10329' MW:10.8 NaC1/Br CONT RIH W/SWS PERF GUN. RU SWS WL. RIH W/ORIENTING TOOLS. SET PIPE ON DEPTH & ORIENT GUNS. POH & RD SWS WL. RU TO PRESS DP. PRESS TO 2500 PSI TO ACTIVATE FIRING HEAD, ONT UP TO 4200 PSI TO OPEN CIRC VALVE. VALVE DID NOT OPEN. BLEED OFF & REPRESS SEVERAL TIMES. STILL DID NOT OPEN. WAIT FOR GUNS TO FIRE & PERF INTERVALS F/8110'-9100' $ 2 SPF. DRESS DP TO 3800 PSI & CIRC VALVE OPENED THIS TIME. RU TO CIRC. CBU $ 3.5 BPM & 850 PSI. DISPLACE VISC BRINE W/CLEAR BRINE. POH 10 STDS. RU STORM PKR & ATTEMPT TO SET. RUNNING COMPLETION 7"$10329' MW:10.8 NaC1/Br TEST STORM PKR TO 3000 PSI. ND BOP. REMOVE 7-1/16" FULL OPENING VALVE. NU BOP. PULL WEAR RING. SET TEST PLUG & TEST BROKEN FLANGES. PULL STORM PKR. SET WEAR RING. POH & LD DP. LD SWS GUNS. REMOVE GUNS F/PIPE SHED. LOAD ADDITIONAL BRINE VOL IN PITS. LOAD TBG IN PIPE SHED. STRAP & DRIFT SAME. INSTALL SEAL RINGS. PULL WEAR RING. MU WL RE-ENTRY GUIDE & RIH W/3-1/2" TBG. CLEANING WELLL AREA 7"$10329' MW:10.7 NaC1/Br SERV RIG. RIH W/3-1/2" X 4" COMP STRING. MU FMC HGR & SSSV CONTROL LINE. TEST TO 5000 PSI. RILDS. RU OTIS SL. RIH W/SL & SET STANDING VALVE IN D NIPPLE. TEST TO 3000 PSI. POH. PRESS TBG TO 3500 PSI & SET BAKER PKR. BLEED OFF PRESS. BOLDS. PU TBG 10'. PBR ALREADY SHEARED. PRESS ANN & TBG TO 1000 PSI. BLEED OFF CONTROL LINE PRESS & CLOSE SSSV. BLEED TBG PRESS TO 500 PSI. HOLD FOR 15 MIN. PRESS TBG TO 1000 PSI & OPEN SSSV. TEST TBG & ANN TO 2500 PSI. INCREASE TBG PRESS TO 3000 PSI. BLEED OFF PRESS. RIH W/SL & PULL STANDING VALVE. RD OTIS SL. CLOSE SSSV. ND FLOW RISER. ND BOP. ND CHOKE & KILL LINE. NU FMC TREE. PULL BPV. TEST TREE TO 250 PSI & 5000 PSI. TEST PACKOFF TO 5000 PSI. OPEN SSSV. PMP 11 BBLS OF DIESEL CAP IN ANN. FREEZE PROTECT TBG W/6 BBLS. SECURE WELL. RIG RELEASED 7"$10329' MW:10.7 NaC1/Br CLEAN WELL AREA & SECURE WELL. RELEASED RIG $ 0730 HRS ON 07/23/93. MOVE RIG TO 1G-01. SIGNATURE: DATE: RECEIVED A,)aska Oil & Gas Cons. Gorm,rdssio~'~ Anchorage , SUB- SURFACE DIRECTIONAL SURVEY ~l UIDANCE r~l ONTINUOUS ~-100L Company Well Name Field/Location ,~taska OJi & Gas Cci~s. Commissio~ anohoFage ARCO ALASKA, INC. 2/4-07 (114' FSL, 94' FWL, SEC 27, T11N, R8E, UN) KUPARUK, NORTH SLOPE, ALASKA Job Reference No. 93016 Lo~m¢med Bv: dOHNSON Date lO-dAN-93 Computed By: KRUWELL · SCHLIJNIBF_..I~OER · GCT DIRECTIONAL SURVEY CUSTOMER LISTING FOR ARCO ALASKA INC 2M-07' KUPARUK RIVF_R NOR'IH SLOPE, ALASKA SURVEY DATE: iO-JAN-93 ENGINEER' G. JOHNSON METHODS OF COMPUTATION TOOL LOCATION: TANGENTIAL- Averaged deviation and azimuth INTERPOLATION: LINEAR VERTICAL SECTION: HORIZ. DIST. PROJECTED ONTO A TARGET AZIMUTH OF SOUTH I9 DEG 2 MIN WEST ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA COMPUTATION DATE: T-FEB-93 PAGE 1 DATE OF SURVEY: lO-JAN-93 KELLY BUSHING ELEVATION: 146.00 FT ENGINEER: G. JOHNSON INTERPOLATED VALUES FOR EVEN 100 FEET OF MEASURED DEPTH TRUE SUB-SEA COURSE MEASURED VERTICAL VERTICAL DEVIATION AZIMUTH DEPTH DEPTH DEPTH DEG MIN DEG MIN 0 O0 100 O0 200 O0 300 O0 400 O0 500 O0 600 O0 700 O0 800 O0 900 O0 0 O0 -146. O0 lO0 200 3OO 40O 5OO 599 699 797 894 0 0 O0 -46.00 0 13 O0 54.00 0 11 O0 154 O0 0 11 O0 254 O0 0 10 O0 354 O0 0 38 85 453 85 5 8 O1 553 O1 9 4 651 39 11 28 748 92 14 5 39 92 N 0 0 E N 16 49 W N35 5 W N 28 54 W N 34 20 W S 27 47 W S 14 55 W S 20 31W S 21 56 W S 23 37 W VERTICAL DOGLEG RECTANGULAR COORDINATES HORIZ. DEPARTURE SECTION SEVERITY NORTH/SOUTH EAST/WEST DIST. AZIMUTH FEET DEG/IO0 FEET FEET FEET DEG MIN 0. O0 -0.08 -0.33 -0.52 -0.73 -0.62 4.28 17. O1 34.87 56.86 0 O0 0 O1 0 23 0 O0 0 27 3 O0 4 45 1 87 2 42 1 55 0 O0 N 0 09 N 0 41N 0 68 N 0 95 N 0 91N 3 83 S 15 94 S 32 57 S 52 87 S 0 O0 E 0 02W 0 19 W 0 37 W 0 51 W 0 72 W 2 03 W 5 98 W 12 50 W 21 11 W 0 O0 N 0 0 E 0 0 0 1 1 4 17 34 56 O9 N 10 25 W 45 N 24 33 W 78 N 28 35 W 08 N 28 20 W 16 N 38 39 W 33 S 27 55 W 02 S 20 34 W 89 S 21 0 W g3 S 21 46 W 1000 O0 1100 1200 1300 1400 1500 1600 1700 1800 1900 991.41 845.41 16 44 O0 1086.29 940.29 19 39 O0 1179.53 1033.53 22 38 O0 1270.47 1124.47 26 35 O0 1358.28 1212 28 30 31 O0 1443.20 1297 20 32 59 O0 1525.97 1379 97 35 49 O0 1604.76 1458 76 40 24 O0 1679.05 1533 05 43 7 O0 1752.02 1606 02 42 54 S 24 52 W S 25 47 W S 25 34 W S 24 9 W S 22 8 W S 22 11W S 22 56 W S 23 37 W S 22 55 W S 22 57 W 82 99 114 35 150 22 191 53 239 22 291 93 347 93 409 29 476 02 544 25 4 30 2 19 2 76 4 11 3 78 2 03 4 80 4 75 0 79 0 79 76 84 S 105 137 175 219 268 32O 376 438 501 31 74 W 31S 45 86 S 61 48 S 78 53 S 97 45 S 117 28 S 138 77 S 162 23 S 189 22 S 215 83 14 S 22 27 W 37 W 114 O0 W 150 62 W 192 18 W 240 O1W 292 46 W 348 85 W 410 33 W 477 94 W 545 66 S 23 19 W 76 S 23 52 W 29 S 24 8 W 08 S 23 53 W 84 S 23 33 W 93 S 23 23 W 46 S 23 23 W 38 S 23 22 W 76 S 23 18 W 2000 O0 1825.42 1679 42 42 48 2100 O0 1898 94 1752 2200 2300 2400 2500 2600 2700 2800 2900 O0 1972 O0 2047 O0 2121 O0 2195 O0 2270 O0 2345 O0 2421 O0 2497 83 1826 03 lgO1 30 1975 79 2049 58 2124 68 2199 18 2275 05 2351 S 23 13 W 94 42 31 S 22 31 W 679 83 42 14 · S 19 25 W 746 03 42 3 S 19 31 W 813 30 41 58 S 19 38 W 880 79 41 41 S 19 49 W 947 58 41 27 S 19 38 W 1014 68 41 9 S lg 32 W 1080 18 40 49 S 19 29 W 1145 05 40 31 S 19 21 W 1210 612 O0 60 95 99 95 66 03 06 63 78 3000 O0 2573 18 2427 18 40 23 3100 3200 3300 3400 3500 3600 3700 3800 3900 O0 2649 O0 2725 O0 2802 O0 2878 O0 2953 oo 3O29 O0 3104 O0 3180 O0 3254 37 2503 37 40 18 68 2579 68 40 11 38 2656 38 39 59 42 2732 42 40 52 97 2807 97 41 43 2883 43 40 54 98 2958 98 40 54 52 3034.52 41 6 98 3108.98 42 27 S 19 28 W 1275 62 S 19 31 W 1340 38 S 19 19 W 1405 O1 S 18 17 W 1469 18 S 17 42 W 1534 11 S 17 33 W 1599 S 17 28 W 1665 S 17 30 W 1730 S 17 33 W 1796 S 19 42 W 1862 6O 19 69 19 92 0.20 2.47 0.18 0.41 0 31 0 22 0 23 0 61 0 35 0 34 0 30 0 29 0 69 1 40 0 36 0 27 0 44 0 29 1 27 0 65 563 72 S 242 52 W 613 68 S 23 17 W 626 689 752 815 878 940 1002 1064 1126 05 S 269 11S 292 33 S 315 41S 337 22 S 36O 7O S 382 92 S 4O4 73 S 426 17 S 448 15 W 681 84 W 748 18 W 815 65 W 882 14 W 949 55 W 1015 67 W 1081 57 W 1147 22 W 1212 45 S 23 16 W 75 S 23 1W 68 S 22 44 W 55 S 22 30 W 20 S 22 18 W 51 S 22 8 W 48 S 21 58 W O0 S 21 50 W 09 S 21 42 W 1187 35 S 469 71W 1276 88 S 21 35 W 1248 1309 1370 1431 1494 1556 1619 1681 1745 38 S 491 35 S 512 07 S 533 86 S 553 31S 573 88 S 593 40 $ 612 91S 632 14 S 653 36 W 1341 81W 1406 57 W 1470 55 W 1535 36 W 1600 10 W 1666 72 W 1731 36 W 1796 70 W 1863 60 S 21 29 W 19 S 21 23 W 30 S 21 17 W 14 S 21 8 W 53 S 20 59 W 03 S 20 51W 44 S 20 43 W 86 S 20 36 W 56 S 20 32 W COMPUTATION DATE: 7-FEB-g3 PAGE 2 ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA DATE OF SURVEY' lO-JAN-93 KELLY BUSHING ELEVATION' 146.00 ET ENGINEER' G. JOHNSON INTERPOLATED VALUES FOR EVEN 100, FEET OF MEASURED DEPTH TRUE SUB-SEA COURSE MEASURED VERTICAL VERTICAL DEVIATION AZIMUTH DEPTH DEPTH DEPTH DEG MIN DEG MIN VERTICAL DOGLEG RECTANGULAR COORDINATES HORIZ. DEPARTURE SECTION SEVERITY NORTH/SOUTH EAST/WEST DIST. AZIMUTH FEET DEG/iO0 FEET FEET FEET DEG gin 4000 O0 3328 69 3182.69 .42 32 4100 4200 4300 4400 4500 4600 4700 4800 4900 O0 3402 O0 3476 O0 3549 O0 3623 O0 3697 O0 3770 O0 3843 O0 3916 O0 3990 43 3256.43 42 26 19 3330.19 42 31 85 3403.85 42 32 55 3477:55 42 35 04 3551.04 42 45 42 3624.42 42 51 73 3697.73 42 52 94 3770.94 42 57 92 3844.92 41 49 S 19 56 W 1930 49 S 20 5 W 1998 S 20 13 W 2065 S 20 18 W 2133 S 20 25 W 2200 S 20 27 W 2268 S 20 25 W 2336 S 20 25 W 2404 S 20 16 W 2472 S 17 58 W 2539 04 54 16 73 53 45 44 54 81 0 13 0 28 0 03 0 18 0 27 0 10 0 24 0 12 1 22 0 25 1808 70 S. 676 65 W 1931 13 S 20 31 W 1872 1935 1999 2062 2125 2189 2253 2317 2380 18 S 699 58 S 722 03 S 746 40 S 769 96 S 793 63 S 817 38 S 840 25 S 864 86 S 886 75 W 1998 98 W 2066 38 W 2133 90 W 2201 53 W 2269 25 W 2337 93 W 2405 65 W 2473 53 W 2540 68 S 2O 3O W 20 S 20 29 W 83 S 20 28 W 42 S 20 28 W 23 S 20 28 W 17 S 20 28 W 18 S 20 28 W 31 S 20 28 W 55 S 20 25 W 5000 O0 4065 42 3919 42 41 57 5100 5200 5300 5400 5500 5600 5700 5800 5900 O0 4139 O0 4214 O0 4288 O0 4362 O0 4436 O0 4509 O0 4583 O0 4657 O0 4730 76 3993 02 4068 14 4142 16 4216 16 4290 96 4363 83 4437 54 4511 86 4584 76 42 0 02 42 5 14 42 14 16 42 17 16 42 20 96 42 29 83 42 26 54 42 35 86 43 7 S 17 50 W 26O6 51 S 17 38 W 2673 S 17 26 W 2740 S 17 11W 2807 S 16 51W 2874 S 16 35 W 2941 S 16 11W 3009 S 15 42 W 3076 S 15 4 W 3143 S 14 48 W 3211 38 32 43 61 82 23 54 98 8O 0 34 0 25 0 45 0 29 0 16 0 60 0 62 0 17 0 21 0 48 2444 35 S 907 O0 W 2607 20 S 20 2I W 2508 2571 2636 2700 2764 2829 2894 2959 3025 05 S 927 91S 947 O1S 967 30 S 987 71S 1006 45 S 1025 27 S 1044 42 S 1062 11S 1079 40 W 2674 56 W 2740 52 W 2807 18 W 2875 54 W 2942 58 W 3009 08 W 3076 05 W 3144 59 W 3211 02 S 2O 18 W 91 S 2O 14 W 96 S 2O 9 W 09 S 20 5 W 24 S 20 0 W 58 S 19 55 W 84 S 19 50 W 22 S 19 44 W 98 S 19 38 W 6000 O0 4803 92 4657 92 43 0 6100 6200 6300 6400 6500 6600 6700 6800 6900 O0 4877 O0 4950 O0 5024 O0 5099 O0 5174 O0 5249 O0 5323 O0 5396 O0 5469 04 4731 41 4804 85 4878 92 4953 92 5028 52 5103 18 5177 15 5250 20 5323 04 42 49 41 42 24 85 41 29 92 41 21 92 41 35 52 41 53 18 42 59 15 43 10 20 42 57 S 14 8 W 3279 87 S 13 16 W 3347 78 S 12 24 W 3415 32 S 13 12 W 3481 69 S 12 14 W 3547 S 11 54 W 3613 S 12 23 W 3679 S 15 46 W 3746 S 15 28 W 3814 S 15 12 W 3882 34 O0 O6 49 74 89 0 56 1 27 1 83 0 92 0 43 0 59 3 18 0 63 0 27 0 31 3091 24 S 1096 61 W 3279 99 S 19 32 W 3157 3223 3288 3353 3418 3483 3548 3614 3680 52 S 1112 77 S 1127 93 S 1142 37 S 1156 06 S 1170 23 S 1184 63 $ 1201 50 S 1219 35 S 1238 75 W 3347 81W 3415 43 W 3481 94 W 3547 75 W 3613 43 W 3679 60 W 3746 97 W 3814 06 W 3883 85 S 19 25 W 35 S 19 17 W 69 S 19 9 W 34 S 19 2 W O1 S 18 54 W 10 S 18 47 W 55 S 18 42 W 83 S 18 39 W O1 S 18 36 W 7000 O0 5541 59 5395 59 45 29 7100 7200 7300 7400 7500 7600 7700 7800 7900 O0 5609 O0 5674 O0 5735 O0 5791 O0 5844 O0 5892 O0 5934 O0 5970 O0 6002 92 5463 03 5528 03 5589 78 5645 06 5698 23 5746 69 5788 7O 5824 53 5856 92 48 23 03 51 32 03 52 58 78 57 3 06 59 36 23 62 52 69 66 24 70 70 40 53 72 38 S 15 17 W 3951 71 S 15 37 W 4024 S 15 42 W 4101 S 16 4 W 4180 S 15 22 W 4262 S 16 35 W 4347 S 17 34 W 4435 S 19 6 W 4525 S 2O 39 W 4618 S 21 24 W 4713 58 16 27 42 52 O8 59 83 58 5 99 5 17 3 32 3 96 2 05 1 O9 3 21 2 60 1 76 4 86 3746 94 S 1256 06 W 3951 86 S 18 32 W 3817 3891 3967 4046 4128 4212 4298 4386 4474 22 S 1275 17 S 1296 45 S 1317 75 S 1339 75 S 1362 46 S 1388 36 S 1417 06 S 1449 61S 1482 77 W 4024 25 W 4101 72 W 4180 76 W 4262 99 W 4347 83 W 4435 38 W 4526 08 W 4619 91W 4713 77 S 18 29 W 40 S 18 25 W 55 S 18 22 W 76 S 18 19 W 91 S 18 16 W 50 S 18 15 W 02 S 18 15 W 24 S 18 17 W g3 S 18 20 W -) COMPUTATION DATE: 7-FEB-93 PAGE 3 ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA DATE OF SURVEY: lO-JAN-93 KELLY BUSHING ELEVATION: 146.00 ET ENGINEER: G. JOHNSON INTERPOLATED VALUES FOR EVEN 100 FEET OF MEASURED DEPTH TRUE SUB-SEA COURSE MEASURED VERTICAL VERTICAL DEVIATION AZIMUTH DEPTH DEPTH DEPTH DEG MIN DEG MIN VERTICAL DOGLEG RECTANGULAR COORDINATES HORIZ. DEPARTURE SECTION SEVERITY NORTH/SOUTH EAST/WEST DIST. AZIMLFFH FEET DEG/IO0 FEET FEET FEET DEG MIN 8000 O0 6029 13 5883.13 76 30 8100 8200 8300 8400 8500 8600 8700 88OO 8900 O0 6050 O0 6071 O0 6089 O0 6099 O0 6105 O0 6106 O0 6107 O0 6108 O0 6111 70 5904.70 77 51 20 5925.20 78 19 34 5943 34 82 7 30 5953 30 85 27 22 5959 22 88 10 74 5960 74 89 24 14 5961 14 90 9 85 5962 85 88 19 01 5965 01 89 4 S 22 59 W 4809.71 S 23 35 W 4907 08 S 24 12 W 5004 S 22 25 W 5102 S 21 1W 5202 S 21 31W 5301 S 22 5 W 5401 S'22 0 W 5501 S 21 57 W 5601 S 22 7 W 5701 62 68 O4 78 61 51 39 28 4 28 2 48 I 98 7 75 3 19 4 71 2 68 1 44 2 14 4 29 4563 83 S 1519 06 W 4810 O0 S 18 25 W 4653 4743 4833 4925 5018 5111 5204 5297 5390 50 S 1557 08 S 1597 49 S 1635 74 S 1672 79 S 1709 41S 1746 38 S 1783 44 S 1820 53 S 1856 70 W 4907 14 W 5004 76 W 5102 98 W 5202 11W 5301 75 W 5401 59 W 5501 12 W 5601 29 S 18 30 W 76 S 18 37 W 78 S 18 42 W 10 S 18 46 W 82 S 18 48 W 64 S 18 52 W 52 $ 18 55 W 40 S 18 58 W 57 W 5701.29 S 19 0 W 9000 O0 6113 45 5967.45 88 21 9100 920O 9300 9400 9500 9600 9700 9800 9900 O0 6116 O0 6119 O0 6120 O0 6121 O0 6120 O0 6119 O0 6118 O0 6117 O0 6119 29 5970.29 88 14 06 5973.06 88 56 22 5974.22 89 26 O0 5975 O0 89 42 98 5974 98 90 24 75 5973 75 90 50 28 5972 28 90 36 65 5971 65 89 23 24 5973 24 88 53 S 20 37 W'%'.5801 20 S 20 51W 5901 S 21 0 W 6001 S 20 19 W 6100 S 19 45 W 6200 S 19 58 W 6300 S 2O 6 W 6400 S 19 11W 6500 S 18 36 W 6600 S 18 46 W 6700 11 02 97 95 93 89 87 87 85 2 56 0 60 1 45 0 9O 1 17 1 70 2 32 1 74 3 26 0 92 5483 99 S 1892 04 W 5801 20 S 19 2 W 5577 5670 5764 5858 5952 6045 6140 6234 39 S 1927 79 S 1963 33 S 1998 22 S 2033 12 S 2067 83 S 2102 07 S 2135 74 S 2167 6329.40 S 2200 64 W 5901 26 W 6001 6O W 6100 02 W 6200 39 W 6300 29 W 6400 67 W 6500 87 W 6600 08 W 6700 11 S lg 4 W 02 S 19 6 W 98 S 19 7 W 96 S 19 8 W 94 S 19 9 W 91 S 19 10 W 89 S 19 11W 88 S 19 10 W 87 S 19 10 W 10000.00 6121.24 5975.24 89 5 10100.00 6122.87 5976.87 89 7 10200.00 6124.96 5978.96 88 55 10300.00 6126.26 5980.26 89 23 10340.00 6126.69 5980.69 89 23 S 18 5 W 6800.83 S 18 21 W 6900.81 S 19 42 W 7000.78 S 19 32 W 7100.77 S 19 32 W 7140.76 1 . 12 3.27 4.32 0.84 0.00 6424.19 S 2231.87 W 6800.84 S 19 9 W 6518.78 S 2264.26 W 6900.82 S 19 9 W 6613.31 S 2296.78 W 7000.79 S lg 9 W 6707.62 S 2330.00 W 7100.78 S 19 9 W 6745.32 S 2343.37 W 7140.78 S 19 9 W COMPUTATION DATE: 7-FEB-93 PAGE 4 ARCO ALASKA INC 2M-07 KUPARUK-RIVER NORTH SLOPE, ALASKA DATE OF SURVEY: lO-JAN-g3 KELLY BUSHING ELEVATION: 146.00 FT ENGINEER: G. JOHNSON INTERPOLATED VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH TRUE SIB-SEA C01~SE VERTICAL DOGLEG RECTANGULAR COORDINATES HORIZ. DEPAR]]JRE MEASURED VERTICAL VERTICAL DEVIATION AZIMUTH SECTION SEVERITY NORTH/SOUTH EAST/WEST DIST. AZIMUTH DEPTH DEPTH DEPTH DEG MIN DEG MIN FEET DEG/IO0 FEET FEET FEET DEG MIN 0 O0 1000 2000 3000 4000 5000 6000 7000 80OO 9000 0.00 '-146.00 0 0 N 0 0 E O0 991.41 845.41 '16 44 S 24 52 W 82 O0 1825.42 1679.42 42 48 S 23 13 W 612 O0 2573.18 2427,18 40 23 S 19 28 W 1275 O0 3328,69 3182:69 42 32 S 19 56 W 1930 O0 4065.42 3919.42 41 57 S 17 50 W 2606 O0 4803.92 4657.92 43 0 S 14 8 W 3279 O0 5541.59 5395.59 45 29 S 15 17 W 3951 O0 6029.13 5883.13 76 30 S 22 59 W 4809 O0 6113.45 5967.45 88 21 S 20 37 W 5801 0 O0 99 O0 62 49 51 87 71 71 2O 0 O0 4 30 76 0 20 563 0 30 1187 0 13 1808 0 34 2444 0 56 3091 5 99 3746 4 28 4563 2 56 5483 0 O0 N 84 S 31 72 S 242 35 S 469 70 S 676 35 S 907 24 S 1096 94 S 1256 83 S 1519 99 S 1892 0 O0 E 74 W 83 52 W 613 71W 1276 65 W 1931 O0 W 2607 61W 3279 O6 W 3951 06 W 4810 04 W 5801 0 O0 N 0 0 E 14 S 22 27 W 68 S 23 17 W 88 S 21 35 W 13 S 20 31W 20 S 20 21W 99 S 19 32 W 86 S 18 32 W O0 S 18 25 W 20 S 19 2 W 10000.00 6121.24 5975.24 89 5 S 18 5 W 6800.83 10340.00 6126.69 5980.69 89 23 S 19 32 W 7140.76 1.12 6424.19 S 2231.87 W 6800.84 S 19 9 W 0.00 6745.32 S 2343.37 W 7140.78 S 19 9 W COMPUTATION DATE- T-feB-g3 PAGE 5 ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA DATE OF SURVEY' lO-JAN-93 KELLY BUSHING ELEVATION' 146.00 FT ENGINEER' G. JOHNSON INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA COURSE MEASURED VERTICAL VERTICAL DEVIATION AZIMUTH DEPTH DEPTH DEPTH DEG MIN DEG MIN VERTICAL DOGLEG RECTANGULAR COORDINATES HORIZ. DEPARTURE SECTION SEVERITY NORTH/SOUTH EAST/WEST DIST. AZIMUTH FEET DEG/IO0 FEET FEET FEET DEG MIN 0 O0 146 O0 246 O0 346 O0 446 O0 546 02 646 43 747 67 849 69 952 76 0 O0 -146.00 146 O0 246 O0 346 O0 446 O0 546 O0 646 O0 746 O0 846 O0 946 O0 0 0 N 0 0 E 0.00 0 12 N 28 22 W 100.00 0 11 N 35 39 W 200.00 0 12 N 24 45 W 300.00 0 6 N 56 35 W 400.00 2 41 S 15 16 W 500.00 7 lg S 17 26 W 600.00 10 17 S 21 30 W 700.00 12 38 S 23 1 W 800.00 15 13 S 23 40 W 0 O0 -0 20 -0 41 -0 63 -0 78 0 64 9 30 25 02 45 19 70 06 0 O0 0 O0 0 O0 0 16 0 07 4 88 3 71 1 90 3 48 3 25 0 O0 N 0 24 N 0 53 N 0 81 N 1 03 N 0 29 S 8 66 S 23 41 S 42 12 S 64 99 S 0 O0 E 0 O8 W 0 28 W 0 44 W 0 59 W 1 12 W 3 43 W 8 85 W 16 47 W 26 43 W 0 O0 N 0 0 E 0 25 N 19 30 W 0 60 N 27 31W 0 92 N 28 10 W 1 18 N 29 47 W I 16 S 75 34 W 9 31 S 21 35 W 25.03 S 20 43 W 45.22 S 21 21W 70.16 S 22 8 W 1057 33 1046 O0 1163 1272 1385 1503 1624 1754 1891 2028 2163 900.00 18 46 81 1146 78 1246 77 1346 34 1446 87 1546 99 1646 77 1746 05 1846 74 1946 O0 1000.00 21 41 O0 1100.00 25 27 O0 1200.00 29 58 O0 1300 O0 33 3 O0 1400 O0 36 50 O0 1500 O0 42 17 O0 1600 O0 42 58 O0 1700 O0 42 45 O0 1800 O0 42 19 S 25 43 W S 25 36 W S 24 57 W S 22 15 W S 22 12 W S 23 12 W S 23 18 W S 22 56 W S 23 18 W S 19 SO W 100 39 136 68 179 65 232 04 293 75 362 63 445 54 538 65 631 O0 722 56 2 14 2 86 4 55 4 03 1 94 3 56 3 07 0 84 0 52 i 65 92 65 S 125 164 212 27O 333 410 496 581 666 39 26 W 100 63 S 22 58 W 57 S 55 62 S 73 86 S 94 13 S 117 84 S 144 12 S 177 06 S 213 23 S 250 13 S 284 11W 137 67 W 180 47 W 232 70 W 294 23 W 363 36 W 446 76 W 540 04 W 632 66 W 724 13 S 23 42 W 36 S 24 7 W 89 S 23 56 W 66 S 23 33 W 67 S 23 22 W 83 S 23 23 W 15 S 23 19 W 73 S 23 17 W 41 S 23 8 W 2298.61 2046 O0 1900.00 42 3 2433.21 2146 2567.18 2246 2700.42 2346 2832 77 2446 2964 32 2546 3095 58 2646 3226 56 2746 3357 20 2846 3489 44 2946 O0 2000.00 41 56 O0 2100 O0 41 33 O0 2200 O0 41 9 O0 2300 O0 40 41 O0 2400 O0 40 23 O0 2500 O0 40 18 O0 2600 O0 40 0 O0 2700 O0 40 37 O0 2800 O0 40 59 S 19 31W S 19 37 W 9O3 S 19 43 W 992 S 19 32 W 1080 S 19 27 W 1167 S 19 22 W 1252 S 19 31W 1337 S 19 13 W 1422 S 17 51W 1506 S 17 33 W 1592 813 06 15 29 34 03 51 52 12 17 67 0 41 0 25 0 54 0 62 0 45 0 14 0 3O 0 88 1 O0 0 36 751 45 S 314 87 W 814 75 S 22 44 W 836 920 1003 1084 1165 1245 1325 1405 1487 32 S 345 22 S 375 18 S 404 90 S 433 54 S 462 69 S 490 50 S 518 25 S 545 70 S 571 10 W 904 24 W 993 76 W 1081 70 W 1168 03 W 1253 41W 1338 45 W 1423 03 W 1507 27 W 1593 72 S 22 25 W 79 S 22 11W 75 S 21 58 W 37 S 21 47 W 78 S 21 37 W 74 S 21 29 W 29 S 21 22 W 24 S 21 12 W 61 S 21 0 W 3621 93 3046 O0 2900 O0 40 56 3754 3887 4023 4159 4294 4430 4566 4703 4839 28 3146 84 3246 48 3346 05 3446 77 3546 51 3646 70 3746 09 3846 55 3946 O0 3000 O0 3100 O0 3200 O0 3300 O0 3400 O0 3500 O0 3600 O0 3700 O0 3800 O0 40 56 O0 42 24 O0 42 32 O0 42 29 O0 42 32 O0 42 40 O0 42 49 O0 42 52 O0 42 22 S 17 24 W 1679 55 S 17 25 W 1766 S 19 34 W 1854 S 19 57 W 1946 S 20 8 W 2037 S 20 18 W 2129 S 20 24 W 2221 S 20 27 W 2313 S 20 25 W 2406 S 19 14 W 2499 21 72 36 88 63 39 82 54 37 0 23 0 41 1 27 0 20 0 27 0 2O 0 24 0 16 0 13 3 52 1570 59 S 597 40 W 1680 37 S 20 50 W 1653 1737 1823 1909 1995 2081 2168 2255 2342 30 S 623 41S 65O 62 S 682 61S 713 72 S 745 77 S 777 41S 809 36 S 841 48 S 873 36 W 1766 95 W 1855 06 W 1947 44 W 2038 16 W 2130 10 W 2222 35 W 2314 67 W 2407 76 W 2500 92 S 20 40 W 35 S 20 32 W O0 S 20 30 W 53 S 20 29 W 29 S 20 28 W 08 S 20 28 W 53 S 2O 28 W 29 S 2O 28 W 13 S 20 27 W ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA COMPUTATION DATE: 7-FEB-g3 PAGE 6 DATE OF SURVEY: lO-JAN-93 KELLY BUSHING ELEVATION: 146.00 FT ENGINEER: G. JOHNSON INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA COURSE MEASURED VERTICAL VERTICAL DEVIATION AZIMUTH DEPTH DEPTH DEPTH DEG MIN DEG MIN VERTICAL DOGLEG RECTANGLLAR COORDINATES HORIZ. DEPARTURE SECTION SEVERITY NORTH/SOUTH FAST/WEST DIST. AZIMUTH FEET DEG/IO0 FEET FEET FEET DEG MIN 4973 gl 4046 O0 3900.00 .4! 52 5108 5243 5378 5513 5648 5784 5920 6057 6194 40 4146 12 4246 16 4346 31 4446 81 4546 34 4646 74 4746 60 4846 03 4946 O0 4000.00 42 O0 4100.00 42 10 O0 4200.00 42 16 O0 4300.00 42 23 O0 4400.00 42 20 O0 4500.00 42 33 O0 4600.00 43 10 O0 4700.00 43 4 O0 4800.00 42 29 S 17 50 W 2589 09 S 17 38 W 2679 O0 S 17 19 W 2769 24 S 16 55 W 2859 93 S 16 32 W 2950 S 15 57 W 3042 S 15 9 W 3133 S 14 39 W 3225 S 13 38 W 3319 S 12 26 W 3411 78 10 42 94 04 33 0 48 0 22 0 43 0 18 0 31 0 99 0 49 0 58 1 34 2 16 2427 76 S 901 66 W 2589 79 S 20 22 W 2513 2599 2686 2773 2861 2949 3038 3129 3219 4O S 929 51S 956 24 S 982 31S 1009 08 S 1034 19 S 1059 82 S 1083 43 S 1106 84 S 1126 10 W 2679 2O W 2769 92 W 2860 10 W 2951 69 W 3042 29 W 3133 20 W 3226 02 W 3319 95 W 3411 63 S 20 17 W 8O S 2O 12 W 42 S 2O 6 W 19 S 20 0 W 43 S 19 53 W 66 S 19 45 W 10 S 19 37 W 13 S 19 28 W 36 S 19 17 W 6328 20 5046 O0 4900.00 41 20 6461 6595 6731 6868 7006 7155 7318 7503 7728 39 5146 27 5246 21 5346 29 5446 34 5546 58 5646 42 5746 84 5846 94 5946 O0 5000.00 41 24 O0 5100.00 41 51 O0 5200.00 43 3 O0 5300 O0 43 1 O0 5400 O0 45 45 O0 5500 O0 50 19 O0 5600 O0 53 54 O0 5700 O0 59 38 O0 5800 O0 67 48 S 12 58 W 35OO 24 S 12 1W 3587 S 12 11W 3675 S 15 37 W 3767 S 15 20 W 3861 S 15 22 W 3956 S 15 25 W 4066 S 15 56 W 4195 S 16 37 W 4350 S 19 29 W 4552 62 93 74 32 25 77 05 83 23 1 08 0 32 2 43 0 78 0 44 5 01 1 86 6 47 1 40 7 45 3307 09 S 1146.65 W 3500 24 S 19 7 W 3393 3480 3569 3659 3751 3857 3981 4131 4323 04 S 1165.46 W 3587 15 S,1183.76 W 3675 12 S 1207 36 W 3767 49 S 1232 37 W 3861 32 S 1257 27 W 3956 98 S 1287 O1W 4066 67 S 1321 79 W 4195 93 S 1363 94 W 4351 51S 1426 17 W 4552 62 S 18 57 W 97 S 18 47 W 81 S 18 41W 43 S 18 37 W 40 S 18 32 W 99 S 18 27 W 34 S 18 22 W 22 S 18 16 W 66 S 18 15 W 8077.66 6046.00 5900.00 77 50 10340.00 6126.69 5980.69 89 23 S 23 2 W 4885.31 S 19 32 W 7140.76 1.40 O. O0 4633.47 S 1549.03 W 4885.54 S 18 29 W 6745.32 S 2343.37 W 7140.78 S 19 9 W COMPUTATION DATE: T-FEB-93 PAGE ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA MARKER 9 5/8" CASING LAST READING GCT TOP KUPARUK C BASE KUPARUK C TOP KUPARUK A PBTD 7" CASING DATE OF SURVEY' lO-JAN-93 KELLY BUSHING ELEVATION' 146.00 FT ENGINEER' G. JOHNSON INrl'E~POLATED VALUES FOR CHOSEN HORIZONS SURFACE LOCATION = 114' FSL & 94' FWL, SEC27 TllN R8E UM MEASURED DEPTH 'I-VD BELOW KB FROM KB SUB-SEA 3262 O0 7960 79 8111 O0 8134 O0 8134 O0 10242 O0 10329 O0 10340 O0 2773.20 6019.45 6053.01 6057.79 6057.79 6125.60 6126.58 6126.69 2627 20 5873 45 5907 01 5911 79 5911 79 5979 60 5980 58 5980 69 RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST 1346 98 S 4528 86 S 4663 37 S 4683 95 S 4683 95 S 6652 92 S 6734 95 S 6745 32 S 525.84 W 1504 50 W 1561 99 W 1571 06 W 1571 06 W 2310 73 W 2339 70 W 2343 37 W COMPUTATION DATE: 7-FEB-g3 PAGE 8 ARCO ALASKA INC 2M-07 KUPARUK RIVER NORTH SLOPE, ALASKA MARKER 9 5/8" CASING LAST READING GCT TOP KUPARUK C BASE KUPARUK C TOP KUPARUK A PBTD 7" CASING DATE OF SURVEY: lO-JAN-93 KELLY BUSHING ELEVATION: 146.00 FT ENGINEER: G. JOHNSON ************ STRATIGRAPHIC SUMMARY SURFACE LOCATION = 114' FSL & 94' FWL, SEC27 TllN RSE UM MEASURED DEPTH BELOW KB TVD FROM KB SUB-SEA RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST 3262 O0 7960 79 8111 O0 8134 O0 8134 O0 10242 O0 10329 O0 10340 O0 2773.20 6019.45 6053.01 6057.79 6057.79 6125.60 6126.58 6126.69 2627 20 5873 45 5907 O1 5911 79 5911 79 5979 60 5980 58 5980 69 1346.98 S 525.84 W 4528.86 S 1504.50 W ~6,63_,_37 S 1561.99 W 4683.95 S 4683.95 S 1571.06 W ,~6652.92 S 2310.73 W 6734.95 S 2339.70 W 6745.32 S 2343.37 W -) FINAL WELL LOCATION AT 'I-D: TRUE SUB-SEA MEASURED VERTICAL VERTICAL DEPTH DEPTH DEPTH 10340.00 6126.69 5980.69 HORIZONTAL DEPARTURE DISTANCE AZIMUTH FEET DEG MIN 7140.78 S 19 9 W DIRECTIONAL SURVEY CO~'AaY ARCO ALASKA INC ~.u~ KUPARUK RIVER w;u 2M-07 COUNTRY USA ~UN 1 DATE LO(3(3ED 10 - JAN - 93 [:Irt. PT It UNIT FEET · · REFERENCE 93O16 WELL: 2H-07 HORIZONTAL (114' FSL, 94' FWL, SEC 27, T11N, R8E, Ulq) PRO~IECTION -8000 2000 ,~C) 6000 8000 )JELL' 21t£07 '~ ?.~. {114' FSL, 94' FWL, SEC ;. T11N, RSE, VERTICAL PROJECTION 10OO0 1200(2) ARCO Alaska, Inc. Date: August 13, 1993 Transmittal #: 8836 RETURN TO: ARCO Alaska, Inc. Attn: Sarah Bowen Kuparuk Operations File Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted below are the following open hole items. receipt and return one signed copy of this transmittal. 1Y-2495"?Z' HLDT/CNTG 8-06-93 ct'5-~(o 1H-21 CDR Enhancement 5-25-93 LWD/Depth Corrected CDR LWD/Depth Ccrrected CDR LWD/Depth Corrected CDN LWD/Depth Corrected CDR LWD/Depth Corrected CDR LWD/Depth Corrected CDR LWD/Depth Corrected CDN LWD/Depth Corrected R~"' t°ut 2M-32 9%--~, ~ H-21 H-21 ~z,-~o~ 2 M-07 ct-c-ti-1 2M-29 ~;5.-70 (,I Y-22 Y-22 5-25-93 5-25-93 1-19-92 5-27-93 7-14-93 7-14-93 Please acknowledge 7543-8232 4674-8317 ~c 2995 43,,.,- I 4665'8319 4665-8319 3180-10345 3669-13018 3508-6036 3508-6036 Receipt Acknowledged' DISTRIBUTION: D&M Drilling NSK Date: RECEIVED Catherine Worley(Geology) AUG 'l 7 199;~ Alaska Oil & Gas Cons. Commission Anchorage State of Alaska, (+Sepia) ARCO Alaska, Inc. Date: July 23, 1993 Transmittal #' 8812 RETURN TO: ARCO Alaska, Inc. At"tn: Sarah Bowen Kuparuk Operations File Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted here with are the following items. and return one signed copy of this transmittal. ~'"J,-~29 ~'q ';'TLIs Tape and Listing: · 10-18-92 92622 -07 '" '~1'?'7Bit Runs of CDR. Corrected HLDT -) L LIS Tape and Listing: · 9-18-93 92563 . f,1,?,,,\ 3 Bit Runs of CDR. Corrected HLDT 21 5~ O LIS Tape and Listing: '3-27-93 93132 ./,'~ 9; CDR/CDN & QRO Enhanced Resistivity -32 3' ,~, LIS Tape and Listing: 11-17-92 - 92686 \\CDR Runs '1 & 2, Averaged Cased Hole HLDT ~ LIS Tape and Listing: 6-26-93 93292 ,,,,.~'"~ ,~-,'1 \~ UTE/SUN & CNTH . ~'~"~3 ~ ~ LIS Tape and Listing: '6-9-93 93263 ~0 J.,,,~'~ CDR/CDN & GR CBT in LDWG Format ~'~':-22 '~- I'-, LIS Tape and Listing: 5-29-93 93244 ~.L,.~,~,,~ _. ].,,~ ~CDR/CDN in 1 Bit Run, GR from CBT ,~'~~'17 ~ ~, /LIS._Tape and Listing: 5-23-93 93241 ~"~,1o\ .J.,,'t,/-.CDR Runs 1 & 2, CDN Run 2, QRO Processed ~'~'~-12 <:::J/~ '"LIS Tape and Listing: 5-18-93 93239 ~.~--/ 'l CNTG/HLDT & Arithmetic Average Receipt Ackno~l~dged.~,..~.//~/~ / "iZ./?/ ...Y~,~,---~/Date: DISTRIBUTION: Please acknowledge receipt Bob Ocanas State of Alaska MEMORANDUM STATE Ol~ ·,,LASKA ~IIMSK/I OIL AND GAS CONSER V~I TION COMMISSION TO: David Johnst~.~~ Chairman...-.'~ THRU: Blair Wondzell ~-~~ P.I. Supervisor FROM: ~ug Amos Petroleum Inspector D,4 TE: June 29, 1993 FILE NO: abuhf3ab. DOC PHONE NO.: 279-1433 SUBJECT: BOPE Test Nordic 1 AAI KRU 2M-7 Kuparuk Rv. Field PTD No. 92-80 Tuesday June 29: 1993: I traveled this date to AAI's KRU 2M-7 well to witness the BOPE test on Nordic No. 1 Rig. The location was very clean and organized with ample room on the pad for other equipment should the need arise. The driller and his crew were familiar with our test procedure and very knowledgeable about their BOP equipment and it's operation. As the attached AOGCC BOPE Test Report indicate~,there were 4 failures The Gas Detector on the rig floor, the BOP Stack Coke Line HCR and Manual Gate Valve, and the stack side by-pass vent line 4" Choke Manifold-' Gate Valve failed to test. I instructed the AAI representative Bill Penrose to have all failures repaired and retested before commencing workover operations on this well.. Wednesday June 30; 199~ The testing was concluded at 1:00 a.m. this date and all failures repaired and retested at 5:00 a.m.. IN SUMMARY, witnessed BOPE test at AAI KRU 2M-07 well on Nordic 1, test time 6 hours, 19 valves tested, 4 failures. Attachment ABUHF3AB.XLS STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: Drlg Contractor: Operator: Well Name: Casing Size: 7" Test: Initial Workover: X DATE: 6/29/93 NORDIC Rig No. 1 PTD # 92-80 Rig Ph.# 659-7115 ARCO ALASKA INC. Rep.: BILL PENROSE KRU 2M-07 Rig Rep.: LANCE JOHNSSON Set @ 6,147 Location: Sec. 27 T. 11N R. 8E Meridian Umiat X Weekly Other Test MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) Reserve Pit N/A Well Sign YES Drl. Rig OK BOP STACK: Annular Preventer Pipe Rams Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Quan. Test Pressure P/F 3, OOO P 1 3,000 P 0 N/A N/A I 3,000 P 2 3,000 F I 3,000 F 2 3,000 P ONe.NE N/A MUD SYSTEM: Visual Alarm Trip Tank OK OK Pit Level Indicators OK OK Flow Indicator OK OK Gas Detectors See Note See Note FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Quan. Pressure P/F N/A N/A N/A N/A N/A N/A I 3,000 P I 3,000 P CHOKE MANIFOLD: No. Valves 12 No. Flanges 28 Manual Chokes 1 _- Hydraulic Chokes I Test Pressure P/F 3,000 Note 3,000 P FUNCTIONED FUNCTIONED P P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure 0 System Pressure Attained 1 Blind Switch Covers: Master: Nitgn. Btl's: 1 ~ 2,000 1 ~ 2,200 3,000 P 2,350 P minutes 15 minutes 2 Yes Remote: Psig. sec. sec. Yes Number of Failures: 4 ,Test Time: 6.00 Hours. Number of valves tested 19 Repair or Replacement of Failed Equipment will be made within See Note days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: Note 1.) The gas detector on the rig floor failed but was replaced and retested during the test. Note: 2.) The Stack Choke line HCR and manual valves failed along with the 4" choke manifold bypass vent line valve. As per my instructions all failures were repaired and retested before begining the workover operations. The driller and crew were familiar with our test procedure and all the related BOP equipment. Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c -Inspector FI-021 L (Rev. 2/93) STATE WITNESS REQUIRED? YES YES NO 24 HOUR NOTICE GIVEN YES YES NO Waived By: N/A Witnessed By: AB U H F3AB.XLS Signed: Doug Amos P.I. ARCO Alaska, Inc. Date' June 04, 1993 Transmittal #: 8¢55 RETURN TO: ARCO Alaska, Inc. Attn: Nikki Stiller Kuparuk Operations File Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted below are the following ~ items. receipt and return one signed copy of t,~rm-trar~mittal. CDN-LWD/Depth Corrected CDR-LWD/Depth Corrected CDN-LWD/Depth Corrected CDR-LWD/Depth Corrected HLDT, Corrected CH Density HLDT-Corrected CH Density HLDT-Corrected CH Density Please acknowledge Receipt Acknowledged' DISTRIBUTION: D&M NSK 3/2-5/93 4414-7561 3/2-5/93 4414-7561 3/17-20/93 5317-11034 3/!7-20/93 5317-11034 1/9/93 8000-9336 5/18/93 8030-8682 1/8/93 10448-12014 Drilling Date: St..ate.of. Alaska(+Sepia) V e ndorP ackag e (Joh nst o'(~?~¢. ~, Kathy Worley(Geology)~* ARCO Alaska, Inc. Date: February 19, 1993 Transmittal #: 8667 RETURN TO: ARCO Alaska, Inc. Attn: Nikki Stiller Kuparuk Records Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted here with are the following items. Please acknowledge receipt and return one signed copy of this transmittal. Sub-Surface Directional 01-10-93 93016 Survey Sub-Surface Directional 0 1 -3 1 -93 93 052 Survey Sub-Surface Directional 01 - 1.0 -93 9301 7 Survey Re ce ipt Ack no wle d g e~-~ "';'""-~-~ DI~;TRIBUTION: D&M State of Alaska (2 copies) Date: .............. RECEIVED 7Uaska Oil & Gas Cons. Commission Anchorage ARCO Alaska, Inc. Date: January 15, 1993 Transmittal #: 8644 RETURN TO: ARCO Alaska, Inc. ATTN: Nikki Stiller Kuparuk Operations File Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted here with are the following Cased Hole items. Please acknowledge receipt and return one signed copy of this transmittal. 1H-20 H-20 H-19 2~-07 -20 Cement Bond Log Cement Evaluation Log Cement Evaluation Log Cement Bond Log Cement Bond Log Cement BOnd Log Cement Evaluation Log Cement Evaluation Log 01 -08-93 3950-10145 01 -08-93 3950-10164 01 -07-93 6950-8882 01 -07-93 6950-8863 01 -09-93 7000-9308 01-08-93 9900-11979 01 -09-93 7000-9350 01 -08-93 9900-12027 Receipt Drilling Acknowledge: State of Alaska(+sepia) Date: RECEIVED NSK JAN 1 9 1993 Alaska 011 & Gas Cons. Commission Anchorags MEMORANuUM St , e of Alaska ALASKA OIL AND GAS CONSERVATION COMMISSION TO: Leigh A Griffin ~. DATE: October 12, 1992 Commissioner ~ ~J] FILE NO: LOU910-2. doc THRU: BI. air E Wondze ~ Petr Engineer FROM: ~u Grimaldi Petr Inspector TELEPHONE NO: SUBJECT: Diverter/BOP Test: Parker Rig 4,~245 (659-7670) ARCO 2M- 7 Kuparuk Rv U Permit ~92-80 Thursday~,~ Septemb.er.. !0, !P~.g: I travelled to Parker's Rig ~245 to witness the diverter function test prior to their spudding of ARCO's well 2M-7. I fomnd the diverter system to be well laid out and of solid construction. Parker uses a ball t'v.~, pc_ vent line 'valve versus the knife type. I have found these to be a more positive and faster-acting valve. When the diverter system was operated, closure time was 37 second, s £or the annular preventer with the vent line valve opening immediately. ~mber 121992: I returned to this rig to witness the initial BOP test. after surface casing had. been set~ Darrell Gladden (Parker toolpusher) performed a good test and alii. equi_pment I observed fmmtioned properly and held its respective pressure test.. Parker;s crew seemed well practiced to the drill, and the test was completed i~'t one hour and 45 minutes with no failures observed, In summary, I witnessed a diverter function test and initial BOP test Parker Rig ~245 in the Kuparuk River Unit with no failures observed. A t taclnnen ts 02-00lA (Rev. 6/89) 20/11/MEMO1.PM3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION BOP Test Report OPERATION: Drlg ~X~ Wkvr Operator /~ ~[[ (-) Dr,g contrctr, p~ ~~/~ TEST: Initial Rep '~)/~t~ ~P-~~ Weekly.__ Other Ri g phone # ~ ~- ?~7~ Location: Sec T R M csg set @ Location (general) Housekeeping (ggneral Rsrve pit/W/>' MUD SYSTEMS: Trip tank Pit gauge Flow monitor Gas detectors ft BOPE STACK: Annular preventer Pipe rams Blind rams Choke line valves HCR valve Kill line valves Check valve Test Pressure ACCUMULATOR SYSTEM: Full charge pressure Press after closure Pump incr clos press 200 psig psig psig Full charge press attained Controls: Master ~/~ Remote O~ Blind switch cover KELLY AND FLOOR SAFETY VALVES: Upper Kelly Lower Kelly Ball type Inside BOP Choke manifold ~)~/~ Number valves Number flanges Adjustable chokes Hydraulically operated choke mi n ,L~/ sec min ~--~ sec Test pressure Test pressure Test pressure Test pressure Test pressure TEST RESULTS: Failures Test time / '*'~/ hrs Repair or replacement of failed equipment to be made within days. Notify the Inspector, and follow with written/FAXed [276-7542] verification to Commission office. Remarks O ~]){~)~b '~ '-=-- Distribution: orig - AOGCC c - Operator c - Supervisor C.004 (rev 07/92) STATE WITNESS REQUIRED? yes X no 24-HR NOTI~/ GIVEN? yes?~, no~ Waived by: Witnessed by: ~ AOGCC phone 279-1433 - FAX 276-7542 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISS,uN Rig/BOPE Inspection Report . OPERATION: Drlg~ Compl Wkvr Location: Sec ~ 7 T//~ R ~ ........ M"(] Drl'g contr ~~ Rig~~~ Location (gen'l) ~ ~ O~ Well sign IN COMPLIANCE; yes no n/a A. DIVERTER 2. od () 3. ~,N:~( ) ~.(X) () s.O~ () 6. e~ () 7. j>Q () 8.() () ( 9.() () (, lO.() () ( ii.() () 12. ( ) ( ) ( 13. ( ) ( ) lq. ( ) ( ) is.() () 16. ( ) ( ) 17. ( ) ( ) 18. ( ) ( ) 19. ( ) ( ) 20. ( ) ( ) 21. ( ) ( ) 22. ( ) ( ) line sz & length line conn& anchored bifurcated & dwn wind 90° targeted turns vlvs: auto & simultaneous annular pack-off condition B. BOP STACK wellhead flg wkg press stack wkg press annular preventer pipe rams blind rams stack anchored chke/kill line sz 90° turns targeted (chke & kill ln) HCR vlvs (chke & kill) manual vlvs (chke & kill) connections (flgd, whd, clmpd) drl spool flow nipple flow monitor control lines fire protected C. CLOSING UNITS wkg press fluid level oprtg press press gauges sufficient vlvs regulator bypass 4-way vlvs (actuators) blind handle cover driller control panel remote control panel Representative We]] name ~ /'i Representative Phone No: ~~. IN COMPLIANCE; yes n~ n/a 33. ~ ( ) ( ) firewall 34. ~ ( ) ( ) nitrogen power source (back-up) 35. ~) ( ) ( ) condition (leaks, hoses, eta) D. MUD SYSTEM 36. (~ ( ) ( ) pit level floats installed 37. (~ ( ) ( ) flow rate sensor8 38. (~ ( ) ( ) mud gas separator 39. (~ ( ) ( ) dega~ser 40. ~ ( ) ( ) ~eparator bypass 41. ~ ( ) ( ) gas sensor 42. ( ) ( ) ~) chke In conn 43. ~) ( ) ( ) trip tank E. RIG FLOOR 44. ~ ( ) ( ) kelly cocks (upper,)ower, IBOP) 45. ~ ( ) ( ) floor vlvs (dart vlv, ball vlv) 46. (~ ( ) ( ) kelly & floor vlv wrenches 47. ~ ( ) ( ) driller's con~ole (flow monitor, flow rate indicator, pit level indicators, gauges) ( ) ~ kill sheet up-to-date ( ) ( ) gas ~etection monitors (H-S & methane) 50. ( ) ( ) ~ hydr chke panel 51. ( ) ( ) (~ chke manifold F. MISC EQUIPMENT 52. ( ) ( ) ~) flare/vent line 53. ( ) ( ) ~ 90° turns targeted (dwn strm choke Ins) 54. ( ) ( ) ~ reserve pit tankage 55.~ ( ) ( ) personnel protective equip avail 56. ( ) ( ) ( ) all drl site suprvs trained for procedures s7. ~ ( ) ( ) H~S probes 58. ~ ( ) ( ) rig housekeeping 48.() 23. (7~ ( ) 2~. (-~) ( ) 25. ~K) () 26. (7~) ( ) 27.0<) ( ) 28. Q0 () 29.00 ( ) 3o. ,(~ () 31. ~). ( ) 32. (;~<) ( ) RECORDS: Date of last BOP inspection: Date of last BOP test: Resu] ting non-compl iance: ~/~C' b ~'~ ~'"~"S~'~/~ Non-compliances not corrected & why: Date corrections will be completed: BOP test & results properly entered on daily record? ~ Kill sheet current? /t~/~ C.0013 (rev 06/30/92) ARCO Alaska, Inc. Date: October 2, 1992 Transmittal #: 8561 RETURN TO: ARCO Alaska, Inc. Attn: Nikki Stiller Kuparuk Operations File Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted here with are the following Open hole items. and return one signed copy of this transmittal. Please acknowledge receipt 2M-07 CDR 9/1 2-1 8/92 Receipt Acknowledged: DISTRIBUTION: D&M Drilling Date: 3261-10340 RECEIVED 0CT 0 5 1992 Alaska 011 & Gas Cons. Commission Anchorage Vendor Package(Johnston) NSK State of Alaska(+Sepia) WALTER J. HICKEL, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 September 10, 1992 Mr. A W McBride Area Drilling Engineer ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 2M-07 Revised ARCO Alaska, Inc. Permit No. 92-80 Sur Loc 114'FSL, 94'FWL, Sec. 27, T11N, RSE, UM Btmhole Loc 1317'FNL, 2290'FEL, Sec. 4, T10N, RSE, UM Dear Mr. McBride: Enclosed is the approved revised application for permit to drill the above referenced well. The provisions of the original approved permit dated August 3, 1992 are in effect for this revision. Chairman BY ORDER OF THE COMMISSION dlf/Enclosures CC: Department of Fish & Game, Habitat Section W/o encl Department of Environmental Conservation w/o encl STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of Work Drill X Redrill E] lb Type of Well Exploratory D Stratigraphic Test E] Development Oil X Re-Entry BI Deepen D Service D Development Gas BI Sin.qleZone X Multiple Zone r'~ 2.. Name of Operator 5. Datum Elevation (DF or KB) 1 0. Field and Pool ARCO Alaska, Inc. RKB 146', Pad 105' GL feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchorage, AK 99510-0360 ADL 25589, ALK 2675 4. Location of well at surface 7. Unit or property Name 1 1. Type Bond (see 20 AAC 25.025) 114' FSL, 94' FWL, Sec. 27, T11N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 386' FSL, 1634' FEL, Sec. 33, T11N, R8E, UM 2M-07 #UG630610 At total depth 9. Approximate spud date Amount 1317' FNL, 2290' FEL, Sec. 4, T10N, R8E, UM 9/1 0/92 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 2M-06 10,324' MD 1317 @ TD feet 15' @ 0' MD feet 2560 6,147' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 500 feet Maximum hole angle 88.65° Maximumsudace 1 640 osia At total deoth fTVD) 3206 Dsia 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 24" 16" 62.5# H-40 Weld 80' 41' 41' 121' 121' +200 CF 12.25" 9.625" 47.0# L-80 BTC 3,255' 41' 41' 3,255' 2,771' 310 Sx Permafrost E & HF-ERW 510 Sx Class G 8.5" 7" 26.0# ~-~1f) BTCMOE 3,944' 41' 41' 3,944' 3,275' HF-ERW 24 Sx Lt. Wt. Class G & 8.5" 7" 26.0# J-55 BTC 6,398' 3,944' 3,275' 10,324' 6,1 47' 400 Sx Class G HF-ERW Top 500' above Kuparuk 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Structural Length Size CementedREcEIV~'' I'~ ~, II~ed depth True Vertical depth Conductor Sudace Intermediate Produc,,o. S E P - 1 1992 Liner Pedoration depth: measured Alaska 0il & Gas Cons. 6or~rcissiot~ true vertical Anchorage 20. Attachments Filing fee X Property plat E] BoP Sketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot r"'] Refraction analysis E] Seabed report r-] 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best o! my knowledge s,..., ,,,,e oa, / ~ Commission Use Only / ~ Permit Number ]APl number J Ap~v~l.~l¢, Ieee cover letter for (:~ .~- ~ 50- //(3 ,~ ~ ~ 4:2,,/7 ~ -" -- ~;;:t;~ other requirements Conditions of approval Samples required D Yes '~ No Mud Io¢3required r'"] Yes /~ No Hydro.qensultidemeasures BI Yes ~[ No Directional survey required ~' Yes D No ~.:,?,0:i,~)d Copy Required working pressure for DOPE'BI 2M ~ 3M D 5M BI lOB D 15M Returned Other: ~- / O' ~2 Original Signed By by order of ?//~/ / Approved by David W, Johnston Commissioner the commission Date-/. ¢t' ~'='~ · . . Form 10-401 Rev. 7-24-89 Submit in triplicate GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 2M-07 . . o . . . . . , 10. 11. 12. 13. 14. 15. 16. 17. 18. Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (3,255')according to directional plan. Run and cement 9-5/8" casing. Install and test BOPE. Test casing to 2000 psi. Drill out cement and 10' of new hole. Perform leak off test to 12.5 ppg EMW. Drill 8-1/2" hole to total depth (10,324') according to directional plan. Run open hole evaluation logs or LWD tools as needed. Run and cement 7" casing. (If significant hydrocarbon zones are present above the Kuparuk, sufficient cement will be pumped for isolation in accordance with Rule 20 AAC 25.030. Alternatively, if significant hydrocarbon zones occur within 200' TVD of the surface casing shoe, cement will be down squeezed in the annular space between the surface and production casing after the primary cement job is completed.) Pressure test to 3500 psi. ND BOPE and install lower production tree assembly. Secure well and release rig. Run cased hole cement evaluation and gyro logs Move in and rig up Nordic #1. Install and test BOPE. Perforate, stimulate and run completion assembly, set and test packer. ND BOPE and install production tree. Shut in and secure well. Clean location and release rig. RECEIVED S E P - 1 1992 Alaska Oil & Gas Cons. Commission Anchorage ARCO ALASKA, Inc. Structure : Pad 2M Well : 7 ~0 my : Jo. Es For: B MATHEWS ~LO'n'Eo : 26-AUG-92 REFERENCE IS 7 VERSION I~S. ~INATES ARE IN FEET REFERENCE SLOT #7. VERTICAL DEPTHS ARE REFERENCE WELLHEAD. LECO S 19.04 DEG W 52,98' (TO TARGET) *'* PLAN~ OF PROi~OSAL o 80O 1200 . 1600. 2000. . 24-oo. 32oo-~ 3500_ 4000 ' 4+OO. . 4800- Field : Kuparuk River Unit Location : North Slope. Alaska <-- West 2400 2000 t 600 1200 800 400 0 I I I I I I I I I I I I 60001 RKB ELEVATION: 146' KOP TVD:500 TMD:§O0 DEP:O r 6.00 I TARGET LOCATION: I ~ ~2.oo ,~,LO~O~/,oo' I ' ' ' I 18.00 I SEC. 33, rl 1N, RBE J 24 O0 '~ ' B/ PERMAFROST TVD:1396 TMD:1433 DEP=223 ~k~ 30.00 T/ UGNU SND$ TVD=1436 TMD=1478 DEP=245 '~, 36.00 ~,,N42.00 EOC TVD=1800 TMD--1930 DEP=511 T/ W SAK SNDS 'rVD=2011 TMD=2218 DEP=707 ~ B/ W SAK SNDS TVD=2§71 TUD:2982 DEP=1227 / ~,,"'~ 9 5/8"CSG PT TVD=2771 TMD:3255 DEP=1413 "VD=2836 TMD=334.4 DEP=1473 ~ AVERAGE ANGLE ~, 42.89 DEG K-5 'rVD:4326 TMD:5378 DEP=2857 ~b'oa{) ~ ~ OEG / ~00' DO~LE~ P T ~ KOP ~2 TVD--5494 TMD=6972 DEP=3942 N~. ~b.,.2. o)~bg,~ T/ ~D--6 30 1 TMD--8021 DEP:4818 "x,. ro '.~. g T/ zONE-A-T~D=6047' TMD=8074 DEP=4-078 "'x',,.. ZONE A TVD=6047 TMD=8074 DEP=4-078 b A3 INTERVAL TVD=6095 TMD=8353 DEP=5152 T,~J~GET - Mid A3 - FINAL EOC TVD=6104 TMD=8499 DEP=S298 jTD TIfD=6147 TMD=I0324 DEP=7122 0 400 800 t 2001600 20oo 2 0 oo 3 0 36 4o 4.400 4~00 5 5 oo SCALE 1 : 200.00 VeHlcal Section on 199.04 azimuth with reference 0.00 N, 0.00 E from slot i~7 JSURFACE LOCATION: J 1 14' FSL, 94' FWL SEC. 27, T1 1N, RSE JTOP KUP SNDS LOCATION:I 835'FSL, 14-64' FEL SEC.33, Tl lN, RSE TD LOCATION: I 1317' FNL, 2290' FEL SEC. 4, TI ON, R8E I I I I I l 60O0 64-0O 6800 400 .. ~Joo I~J t 200 0 . .t 600 . .2000 - -2a. O0 - -2800 - -3200 - -]60O - _4-000 5200 - -5600 · .&O00 · .~4oO - -6800 TARGET ANGLE 88.65 DEG I I 7200 O C:: I I Y SEP - ! Alaska Oil & Gas Cons. 6ommissio[~ Anchorage RECEIVED ARCO LASKA, Inc. Sfrucfure : Pad 2M Field : Kuparuk River Unlf Well: 7 INCLUDES PROPOSED 1F/~U/BV/121 Locoflon : North Slope, Alosko 200 I 150 100 50 I I I I I I ,'&'~ ~ ",A.. 700 go0 9OO 1100 1100 300 O0 1 30O 0 1500 W e s f ,; ,o.oo 0 50 1 O0 1 50 500 1100 1300 I I 13OO 500 9OO 1100 1300 RECEIVED S E P - 1 1992 Alaska Oil & Gas Cons. Gorem~ss~ Anchorage 50 _ 0 _50 _1 O0 _15O _2OO _25O _300 _35O _4-00 I V DRILLING FLUID PROGRAM Well 2M-07 Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids Spud to 9-5/8" surface casing 9.0-10.0 15-25 15-35 50-100' 5-15 15-40 10-12 9-10 10% +_ Drill out to weight up 8.4-9.6 5-15 5-8 3O-4O 2-4 4-8 8-10 9-10 4-7% Weight up to TD 10.1-10.6 16-22 12-20 40-50 2-4 4-8 4-6 9-10 9-12% Drilling Fluid System: Tandem Brandt Shale Shakers Triple Derrick Shale Shakers Solids Processing System to minimize drilling waste Mud Cleaner, Centrifuges, Degasser Pit Level Indicator (Visual and Audio Alarm) Trip Tank Fluid Flow Sensor Fluid Agitators Notes: Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.O33. Maximum anticipated surface pressure is calculated using a surface casing leak-off of 13.5 ppg EMW and a gas gradient of 0.11 psi/ft. This shows that formation breakdown would occur before a surface pressure of 1640 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 2M-07 is 2M-06. As designed, the minimum distance between the two wells would be 15' @ 0' MD. The wells would diverge from that point. Incidental fluids developed from drilling operations will be hauled to the nearest permitted disposal well or will be pumped down the surface/production casing annulus of a previously drilled well on 2M pad. That annulus will be left with a non-freezing fluid during any extended shut down (>4hr) in pumping operations. The annulus will be sealed with 175 sx of cement followed by arctic pack upon completion of fluid pumping. *Spud mud should be adjusted to a FV between 80-100 sec/qt to drill gravel beds. Adjust FV to 50-60 sec/qt below gravel beds. RECEIVED S E P -- 1 1992 Alaska Oil & Gas Cons. Commission Anchorage CASING DESIGN/cE. .NT CALCULATIONS 1 -Sep-92 Well Number: Surface Csg MD: Surface Csg TVD: MD: TVD: Top of West Sak, TMD: Top of Target, TMD: Top of Target, TVD: Estimated Mud Weight: Surface Casing Choice (1, 2, 3, or 4): Production Casing Choice (1 or 2): Production Casing Frac. Pressure 2M-07 3,255 ft 2,771 ft I O,342 ft 6,147 ft 2,218 ft 8,499 ft 6,104 ft 10.1 ppg I! !i ** See Page4 I~i For Casing Choices 3,500 psi Maximum anticipated surface pressure Estimated BH pressure at top of target zone TVD surface shoe {(13.5'0.052)-0.11}*TVDshoe Anticipated Mud Weight = Top of Target Zone, TVD. = 100 psi Overbalance = =L 2,771 ft 1,640 psi! 10.1 ppg 6,104 ft 3,306 psi 3206 psiI Surface lead: Top West Sak, TMD = 2,218 ft Design lead bottom 500 ft above the Top of West Sak = 1,718 ft Annular area = 0.3132 cf/If Lead length * Annulus area = 538 cf Excess factor = 15% Cement volume required = 619 cf Yield for Permafrost Cmt = 1.97 Cement volume required =[ 310 sxJ Surface tail: TMD shoe (surface TD - 500' above West Sak) * (Annulus area) Length of cmt inside csg ~ ~ Internal csg volume ~,.(~ ~V Cmt required in casing = Total cmt S~P - 1, ¥~'¢~,,.,~ Excess factor AJaSkg. 0ii & Gas 0ohs. Cement volume required ,,,,,,.t~or~,.qe, Yield for Class G cmt Cement volume required 1 3,255 ft 481 cf 80 ft 0.4110 cf/If 33 cf 514 cf 15% 591 cf 1.15 510 sxJ CASING DESIGN/CEiv, E. NT CALCULATIONS 1 -Sep-92 Production lead light weight: Horizontal section 1,843 ft Lite wate 25% of Annulus area (9" Hole) = 0.04363 (TD-TOC)*Annulus area = 102 cf Total cmt = 102 cf Excess factor = 0% Cement volume required = 102 cf Yield for Class G cmt = 4.33 Cement volume required =[ 24 sx Production tail: TM D = 10,342 ft Top of Target, TMD = 8,499 ft Want TOC 500' above top of target = 7,999 ft Annulus area (9" Hole) = 0.1745 (TD-TOC)*Annulus area = 409 cf Length of cmt wanted in csg = 80 ft Internal csg volume = 0.2148 Cmt required in casing = 17 cf Total cmt = 426 cf Excess factor = 15% Cement volume required = 490 cf Yield for Class G cmt = 1.23 Cement volume required =[ 400 sxJ TENSION - Minimum Design Factors are: T(pb)=l.5 and T(js)=l.8 Surface (Pipe Body): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy - 9.6ppg*.052*TVD Surf. Cas.*X-sect. Area Casing Rated For: MD surface shoe = Casing Wt (Ib/ft)= Dead Wt in Air - Buoyancy = Tension (Pipe Body) = Design Factor =[ 1086000 lb 3,255 ft 47.00 Ib/ft 152985.0 lb 18774.4 lb 134210.6 lb 8.1] Surface (Joint Strength): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy = 9.6ppg*.052*TVD Surf. Cas.*X-sect. Area RECEIVED Casing Rated For: MD surface shoe = Casing Wt (Ib/ft) = Dead Wt in Air - Buoyancy = Tension (Joint Strength) = Design Factor =1 Alaska 0il & Gas Cons. Com~issio~ Anchorage 2 1161000 lb 3,255 ft 47.00 Ib/ft 152985.0 lb 18774.4 lb 134210.6 lb 8.7J CASING DESIGN/CE~,c.:NT CALCULATIONS 1-Sep-92 Production (Pipe Body): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy =Mud Gradient*.052*TVD Prod.*X-sect. Area Casing Rated For: TMD = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Pipe Body)= Design Factor =[ 415000 lb 10,342 ft 26.00 Ib/ft 268892.0 lb 24371.6 lb 244520.4 lb 1.71 Production (Joint Strength): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (WEft) Buoyancy =Mud Gradient*.052*TVD Prod.*X-sect. Area Casing Rated For: TMD = Casing Wt (Ib/ft)= Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor =[ 490000 lb 10,342 ft 26.00 Ib/ft 268892.0 lb 24371.6 lb 244520.4 lb 2.0[ BURST - Minimum Design Factor = 1.1 Surface Casing: Burst = Maximum surface pressure Casing Rated For: Max Shut-in Pres = Design Factor =1 6870 psi 1640.4 psi 4.2J Production Casing: 1. Design Case - Tubing leak while well is SI Inside pres=Csg Frac pres(3500 psi)+Mud Wt*.052*TVD Outside Pres=Backup Gradient (8.9ppg *0.052*TVD) Net Pressure = Pressure inside-Pressure outside Design Factor = Rating/Net Pressure Casing Rated For: Inside pressure = Outside Pressure = Net Pressure = Design Factor =[ 4980 psi 6728 psi 2845 psi 3884 psi 1.31 COLLAPSE - Minimum Design Factor = 1.0 Surface Casing 1. Worst Case - Lost circulation and casing pressure = 0 2. External pressure =Mud Wt * 0.052 * TVD Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Internal Pressure = Design Factor =[ 4750 psi 0.525 Ib/ft 1455 psi 0 psi 3.3J Production Casing 1. Worst Case - Full evacuation of casing 2. Mud weight on outside = Mud Wt * 0.052 * TVD RECEIVED Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Internal Pressure = Design Factor =[ 4320 psi 0.525 Ib/ft 3228 psi 0 psi 1.31 s E P - ! 1992 Alaska Oii & Gas Cons. Cor~missiSB 6nP, h~rmqp, CASING DESIGN/CEMENT CALCULATIONS 1-Sep-92 Surface Casing Choices OD ID Ib/ft Grade Metal X-Section Jt Strength Body Strength Collapse Burst I 9.625 8.681 47 L-SO 13.5724 sq. in. 1161000 lb 1086000 lb 4750 psi 6870 psi 2 9.625 8.835 40 L-80 11.4538 sq. in. 979000 lb 916000 lb 3090 psi 5750 psi 3 9.625 8.921 36 J-55 10.2545 sq. in. 639000 lb 564000 lb 2020 psi 3520 psi 4 10.750 9.950 45.5 J-55 13.0062 sq. in. 931000 lb 715000 lb 2090 psi 3580 psi Production Casing Choices OD ID Ib/ft Grade Metal X-Section Jt Strength Body Strength Collapse Burst I 7.000 6.276 26 L-80 7.5491 sq. in. 667000 lb 604000 lb 5410 psi 7240 psi 2 7.000 6.276 26 J-55 7.5491 sq. in. 490000 lb 415000 lb 4320 psi 4980 psi RECEIVED I 992 Alaska Oil & Gas Cons. Con~rnissio~'~ Ancl~orage 7 6 5 4 I I 13 5/8" 5000 I--$1 BOP STACK ACCUMULATOR CAPACITY TEST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TO PROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI WITH 1500 PSI DOWNSTREAM OF THE REGULATOR. 3. OBSERVE TIME, THEN CLOSE ALL UNITS SIMULTANEOUSLY AND RECORD THE TIME AND PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI REMAINING PRESSURE. BOP STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH WATER. 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG WILL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSI AND HOLD FOR 10 MINUTES. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 10 MINUTES. BLEED TO ZERO PSI. 5. OPEN ANNULAR PREVENTOR AND MANUAL KILL AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, LINES, AND CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE BOTTOM PIPE RAMS. TEST BOTTOM RAMS TO 250 PSI AND 3000 PSI. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 10 MINUTES. BLEED TO ZERO PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE MANIFOLD AND LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI. 12. TEST KELLY COCKS AND INSIDE BOP TO 3000 PSI WITH KOOMEY PUMP. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. 1. 16" - 2000 PSI STARTING HEAD 2. 11" - 3000 PSI CASING HEAD 3. 11" - 3000 PSI X 13-5/8" - 5000 PSI SPACER SPOOL 4. 13-5/8" - 5000 PSI PIPE RAMS 5. 13-5/8" - 5000 PSI DRLG SPOOL W/ CHOKE AND KILL LINES 6. 13-5/8" - 5000 PSI DOUBLE RAM W/ PIPE RAMS ON TOP, BLIND RAMS ON BTM 7. 13-5/8" - 5000 PSI ANNULAR ECE I V E D Alaska Oil & Gas Coi s. Commission A chorage ,.JPARUK RIVER UNI'~ 20" DIVERTER SCHEMATIC 5 I 5 4 I · 3 DO NOT SHUT IN DIVERTER AND VALVES AT SAME TIME UNDER ANY CIRCUMSTANCES. MAINTENANCE & OPERATION 2. UPON INITIAL INSTALLATION, CLOSE PREVENTER AND VERIFY THAT VALVE OPENS PROPERLY. CLOSE ANNULAR PREVENTER IN THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN APPROPRIATE VALVE TO ACHIEVE DOWNWIND DIVERSION. ARCO ALASKA, INC., REQUESTS APPROVAL OF THIS DIVERTER SYSTEM AS A VARIANCE FROM 20AAC25.035(b) 1. 16" CONDUCTOR 2. SLIP-ON WELD STARTING HEAD 3. DIVERTER ASSEMBLY WITH ONE 2-1/16"- 2000 PSI BALL VALVE 4. 20" - 2000 PSI DRILLING SPOOL WITH TWO 10" OUTLETS. 5. 10" HCR BALL VALVES WITH 10" DIVERTER LINES, A SINGLE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. VALVES CAN BE REMOTELY CONTROLLED TO ACHIEVE DOWNWIND DIVERSION 6. 20" - 2000 PSI ANNULAR PREVENTER RE6EIVED Alaska 0il a Gas Coils. C;ommission Anchorage EDF 3/10/~2 2J'VP'TCS¢:'~.XI,.,,S Alasl,o~ 2M...7 KLJPARLJK 9/8192 M. Minder Casino Iht Iht I::)esc [:)es(.', I:)eso "Tension ,.,tz~.:.~ []o~om Top Length Lbs Grad~.,, "i"hr~.~ad Lbs l.A 'f 6 121 44 80 6205 H.-4.0 WIELD 2A 9.625 2771 4.1 3255 4,'7 L..,..80 E]'"r'c: 0 8A '7 3275 4.1 10243 26 I,.,:,,80 13']"C 0 4,A '7 614,7 3275 6398 26 J...55 []TO o 'SA 0 0 0 0 () 0 0 0 6A 0 0 0 0 0 0 0 0 7A 0 0 0 0 0 0 0 0 8A 0 0 0 0 0 0 0 0 9A (3 0 0 0 0 () () 0 10A 0 0 0 0 0 0 0 0 3B Mud Wi¢%~ht 10,0 9.6 10,6 10.6 0,0 (3.0 0,0 (3.O 0,0 0.0 I'"'ly(J Gr~dient psi/ft 0,520 0.44~t9 0.551 0.551 0,000 0.000 0.000 0.000 0,000 0,000 psi N/A 1385 '3206 0 0 0 0 0 0 Minimum Yield 0 68'7(:1 724.0 44i~80 0 0 0 0 5,,0 ~'..3 # #D~ViO~ .# It:)llV~0~ 4,C: 5C aC 7C 8C 9C 't Tension K/LJ~s 4.96.4. 152.985 266,3't 8 166.34.8 0 0 0 0 0 Stren gth F</Lbs 786 't (386 604. 4,15 0 0 0 0 0 1383 18[.)5 3388 0 0 0 0 0 0 C,.:~ t I ap ~ ~.~ Resist. 6 70 4.75O 54,'10 4,3.2.,0 0 () 0 0 0 0 OlDE 2.,997 #1:)~V~0~ ALASKA OIL AND GAS CONSERYATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 August 3, 1992 A. W. McBride Area Drilling Engineer ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 2M-07 ARCO Alaska, Inc. Permit No: 92-80 Sur. Loc. ll4'FSL, 94'FWL, Sec. 27, TllN, RSE, UM Btmhole Loc. 1775'FNL, 1579'FWL, Sec. 21, TllN, R8E, UM Dear Mr. McBride: 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. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, BY ORDER OF THE COMMISSION dlf/Enclosures CC: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF AI_.A~KA ALAStv-~ OIL AND GAS OONSERVATION OOMMI$S~,I PERMIT TO DRILL 20 AAO 25.005 la. Type of Work Drill X Redrill E] lb Type of Well Exploratory E] Stratigraphic Test E] Development Oil X Re-Entn/ [] Deepen D Service D Development Gas E] Sin~leZone X aultipleZone 2.. Name of Operator 5. Datum Elevation (DF or KB) 1 0. Field and Pool ARCO Alaska, Inc. RKB 146', Pad 105' GL feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchorage, AK 99510-0360 ADL 25571, ALK 2669 4. Location of well at surface 7. Unit or property Name 1 1. Type Bond (see 2o AAC 25.025) 114' FSL, 94' FWL, Sec. 27, T11N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 1970' FNL, 1665' FWL, Sec. 21, T11N, R8E, UM '. 2M-07 #UG630610 At total depth ' 9~ Approximate spud date Amount 1775' FNL, 1579' FWL, Sec. 21, T11N, R8E, UM 8/1 0/92 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 2 M- 5 11,926' MD 1579 ~ TD feet 25.4' ~ 525' MD feet 2560 6,276' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 2o AAC 25.035(e)(2)) Kickoff depth 300 feet Maximum hole angle 66.70 Maximum surface 1635 osio At total deoth fTVD) 3257 esi. 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include statue dataI 24" 16" 62.5# H-40 Weld 80' 41' 41' 121' 121' _+200 CF 12.25" 9.625" 47.0# L-80 BTC 4253' 41' 41' 4294' 2,762' 352 Sx Permafrost E & HF-ERW 777 Sx Class (3 8.5- 7- 26.0# L-80 BTCMOC 5536' 41' 41' 5577' 3275' .., HF-ERW 8.5" 7 - 26.0# J-55 BTC 6349' 5577' 3275' 11,926' 6,276' 152SxClassG HF-ERW Top 500' above Kuparuk 1 9. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented ~Measured dep. th True Vertical depth Structural :-.' ? .... ~ .... !~ !i~' :~ ', i' '.-, ;: '; ~' Conductor ;;- Surface Intermediate ., . Production ,. i i, ~ ,i.~ ~'' !~ '~ ~ '?' 0 Liner .;-'i i~.i ?. !¢¢., ..... . _~ ,_~,~;i ,~.~ ~il;i:~-i ~,~:,~'"'"'"'",;;. Perforation depth: measured true vertical 2-., ~.,,.; ~0~' ~.:, ;~ 20. Attachments Filing fee X Property plat E] BOP Sketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot r'~ Refraction analysis E] Seabed report E] 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed /~ ~~..~, Title Area Drillin, En,ineer Date ~/~'"~//~'~__ ~ ' / Commission Use Only Permit Number ] APl number I Approval date ~ ISee c°vor letter f°r Conditions of approval Samples required E] Yes ,j~ No Mud Io.q required E] Yes ,~ No Hydro¢len sulfide measures E] Yes ]~ No Directional survey reauired ~[ Yes E] No Required working pressure for BOPE r-! 2M ~ 3M [] SM [] 10M [] 15M Other: Ori~inal Signed David W, Johnstonbyorder of Approved by Commissioner the commission Date ~' Form 10-401 Rev. 7-24-89 " ARCO ALASKA, Structure : Pad 2M Well : 7 Field : Kuparuk River Unit Location : North Slope, Alaska iCREATED BY : JONES For: DATE PLOTTED : 29-JUN-92 PLOT REFERENCE IS 7 VERSION #2. ICOORDINATES ARE IN FEET REFERENCE SLOT #7. TRUE VERTICAL DEPTHS ARE REFERENCE WELLHEAD.i A Baker Hughes company N 23.63 DEG W 9~5Z' (TO TARGET) · ' ¢5O_ -~ 9oo_ 1350_ 1800_ 225¢ I I V 4050 4SOO~ 4950~ 5850~ 6300~ 6750 I I I I I I 13150 I 18100 o 450 900 SCALE 1 : 225.00 TD LOCATION: I 1775' FNL, 1579' FWL SEC. 21, TIlN, RBE <-- West 4-050 3600 3150 2700 2250 1800 1350 TARGET LOCATION: I970' FNL, 1665' FWLI SEC. 21, TllN, R8E TARGET TVD=6022 TMD=11594 DEP=9252 NORTH 8476 WEST 5709 REC VED RKB ELEVATION: 14-7' KOP TVD--300 TMD=300 DEP=O 3.00 . 9.00 .k I 5.00 21.00 BUILD 3 DEG / 100' ~x 27.00 Xx 33.00 B/ PERMAFROST TVD=1397 TMD=1469 DEP=346 x% 39.00 T/ UGNU SNDS TVD--14-47 TMD--1530 DEP=383 '",-,~,576~3'~00 T/ W SAK SNDS TVB=20,2 TMD=24-23 DEP=1063 -~-.~... LOC TVD=2051 TMB=2514- DEP=114-6 ~ B/ W SAK SNDS TVD=2562 TMD=3794- DEP=2319 ~ 9 5/8"CSG PT TVD=2762 TMD--4294- DEP=2777 ~v-'~ K-lO-- TVD=2837 TMD=4481 DEP=294-9 AB MODIFIED CSG PT ~ TVD--3275 TMD--5577 DEP--3953 ~ MAXIMUM ANGLE ~. 66.43 DEG '"~-~ K-5 TVD=4317 TMD=8183 DEP--6342 ~ Alaska. Oil .& ~as Cam A.~ch0rag,, 900 4.50 I I I I SURFACE LOCATION: 114' FSL, 94' FWL SEC. 27, TI1N, RS[ o I 9ooo _ _8550 _ _81oo _ _7650 _ _7200 5750 .3oo _ _5850 _ _5400 - - -4-500 - 7 _4050 3600 - .3150 - _2700 -- _2250 - _1800 _ _1350 09 - ff-- _ 900Frl - ,. _ 4-50 ° © TARGET ANGLE 40 DEG BEGIN ANGLE DROP TVD=4976 TMD--9832 DEP=7853'"'"'"'--,.,~,..~ 66~03t00 DROP 1.5 DEG / lO0' ~ 54-.00 4-5 O0 T/ ZONE A TVB=6023 TMD=11595 BEP=9253 ~ ' B/ KUP SNDS TVD=6123 TMB=11726 BEP=9337 xx TD / LOGGING PT TVD=6276 TMD=II926 DEP=9465 I I I I I I 90100 I 94150 99100 i 4.;50 Joo i 58150 6;00 J .... i .... 150 .1100 .5150 I [ I [ 36100 [ 40150 4.5100 I I I 2215027100 31150 Veriicol Section on 336.37 azimuth with reference 0.00 N, 0.00 E from slot #7 Wesf SCALE 1 : 50.00 300 25O I I I 200 I 150 I 2100 100 50 0 50 100 150 % % ARCO ALASKA, Inc. Structur, :Pad 2M 1~l]1,'[. #6/?/2?/28 Field : Kupuruk River Unit Loc(~tlon : North Slope, Alaska 400 _35O _3OO _25O _2OO _1 50 _1 O0 5O 0 DRILLING FLUID PROGRAM Well 2M-07 Spud to 9-5/8" surface casing Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids 9.0-9.6 15-25 15-35 50-100' 5-15 15-40 10-12 9.5-10 +10% Drill out to weight up 8.4-9.6 5-15 5-8 30-40 2-4 4-8 8-10 9.5-10 4-7% Drilling Fluid System: Tandem Brandt Shale Shakers Triple Derrick Shale Shakers Solids Processing System to minimize drilling waste Mud Cleaner, Centrifuges, Degasser Pit Level Indicator (Visual and Audio Alarm) Trip Tank Fluid Flow Sensor Fluid Agitators Notes' Weight up to TD 10.4 10-18 8-12 35-50 2-4 4-8 4-5 thru Kuparuk 9.5-10 <12% Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.033. Maximum anticipated surface pressure is calculated using a surface casing leak-off of 13.5 ppg EMW and a gas gradient of 0.11 psi/ft. This shows that formation breakdown would occur before a surface pressure of 1635 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 2M-07 is 2M-5. As designed, the minimum distance between the two wells would be 25.4' @ 525' MD. The wells would diverge from that point. Incidental fluids developed from drilling operations will be hauled to the nearest permitted disposal well or will be pumped down the surface/production casing annulus of the last well drilled. That annulus will be left with a non-freezing fluid during any extended shut down (> 4hr) in pumping operations. The annulus will be sealed with 175 sx of cement followed by arctic pack upon completion of fluid pumping. *Spud mud should be adjusted to a FV between 80-100 sec/qt to drill gravel beds. Casing Design / Cement Calculations 27-Jul-92 WELL INFQRMATIQN Well Number: Spud Date: GL: RKB + GL: Property Desgination: Surface Location: Target Location: Bottom Hole Location: Distance to Property Line: Nearest Well: Distance to Nearest Well: KOP: Maximum Hole Angle: Surface Csg MD: Surface Csg TVD: MD: TVD: Top of West Sak, TMD: Top of Target, TMD: Top of Target, TVD: Estimated Mud Weight: Surface Casing Choice (1, 2, or 3): Surface Casing X-Section Area of Steel: Surface Casing Ib/ft: Production Casing Choice (1 or 2): Prod. Casing X-Section Area of Steel: Surface Casing Ib/ft: Production Casing Frac. Pressure PRESSURE INFORMATION Maximum anticipated surface pressure Estimated BH pressure at top of target zone 2M-07 8/10/92 105 ft 146 ft ADL 25571, ALK 2669 114' FSL,94' FWL,Sec. 27,T11N,R8E,UM 1970' FNL,1665' FWL,Sec 21 ,T11 N,R8E,UM 1775' FNL,1579' FWL,Sec. 21 ,T11N,R8E,UM 1,579 ft 2M-05 25.4' @ 525'MD 300 ft 67° 4,294 ft 2,762 ft 11,926 ft 6,276 ft 2,423 ft 11,594 ft 6,022 ft 10.4 ppg 47.0O Ib/ft 7.549 sq. iff. 26.00 Ib/ft 3,500 psi TVD 9-5/8" shoe {( 13.5'0.052)-0.11 }*TVDshoe 2,762 ft 1,635 psiI Anticipated Mud Weight = Top of Target Zone, TVD = 100 psi Overbalance = -I 10.4 ppg 6,O22 ft 3,357 psi 3257 psi] Surface Casing Choices OD ID I b/ft Grade Metal X-Section Jt Strength Body Strength Collapse Burst 1 9.625 8.681 47 L-80 13.5724 sq. in. 1161000 lb 1086000 lb 4750 psi 6870 psi 2 9.625 8.835 40 L-80 11.4538 sq. in. 979000 lb 916000 lb 3090 psi 5750 psi 3 9.625 8.921 36 J-55 10.2545 sq. in. 639000 lb 564000 lb 2020 psi 3520 psi Production Casing Choices OD ID I b/ft Strength Metal X-Section Jt Strength Body Strength Collapse Burst 1 7.000 6.276 26 L-80 7.5491 sq. in. 667000 lb 604000 lb 5410 psi 7240 psi 2 7.000 6.276 26 J-55 7.5491 sq. in. 490000 lb 415000 lb 4320 psi 4980 psi Casing Design / Cement Calculations 27-Jul-92 CASING DESIGN TENSION - Minimum Design Factors are: T(pb)=l.5 and T(js)=l.8 Surface (Pipe Body): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy = 9.6ppg*.052*TVD Surf. Cas.*X-sect. Area Casing Rated For: MD 9-5/8" shoe = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Pipe Body) = Design Factor =[ Surface (Joint Strength): Tension (Pipe Body) = Dead Wt in Air- Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy = 9.6ppg*.052*TVD Surf. Cas.*X-sect. Area Casing Rated For: MD 9-5/8" shoe = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor =[ Production (Pipe Body): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Dead Wt in Air = Length * (Wt/ft) Buoyancy =Mud Gradient*.052*TVD Prod.*X-sect. Area Casing Rated For: TMD = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Pipe Body)= Design Factor =[ Production (Joint Strength): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy =Mud Gradient*.052*TVD Prod.*X-sect. Area Casing Rated For: TMD = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor =[ BURST- Minimum Design Factor = Surface Casing: Casing Rated For: Burst = Maximum surface pressure ~ '~ :~ ~ ~:. ;~Max Shut-in Pres = ...... ~,,,~,~-,~Design Factor =J Production Casing: Casing Rated For: 1. Design Case - Tubing leak while well is SI Inside pres=Csg Frac pres(3500 psi)+Mud Wt*.052*TVD Inside pressure = Outside Pres=Backup Gradient (8.9ppg *0.052*TVD) Outside Pressure = Net Pressure = Pressure inside-Pressure outside Net Pressure = Design Factor = Rating / Net Pressure Design Factor 1086000 lb 4,294 ft 47.00 Ib/ft 201818.0 lb 18713.4 lb 183104.6 lb 1161000 lb 4,294 ft 47.00 Ib/ft 201818.0 lb 18713.4 lb 183104.6 lb 6.3J 415000 1 b 11,926 ft 26.00 Ib/ft 310076.0 lb 46065.4 lb 264010.6 lb 1,6J 490000 lb 11,926 ft 26.00 Ib/ft 310076.0 lb 46065.4 lb 264010.6 lb 1.9J 6870 psi 1635.1 psi 4980 psi 6894 psi 2905 psi 3990 psi 1.2j Casing Design / Cement Calculations COLLAPSE - Minimum Design Factor = 1.0 Surface Casing 1. Worst Case - Lost circulation and casing pressure = 0 2. External pressure =Mud Wt * 0.052 * TVD Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Internal Pressure = Design Factor =1 27-Jul-92 4750 psi 0.541 Ib/ft 1494 psi 0 psi 3.2J Production Casing 1. Worst Case - Full evacuation of casing 2. Mud weight on outside = Mud Wt * 0.052 * TVD Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Internal Pressure = Design Factor =1 4320 psi 0.541 Ib/ft 3394 psi 0 psi, Casing Design / Cement Calculations 27-Jul-92 CEMENT CALCULATIONS 9-5/8" Surface Casing Cement: Surface lead: Top West Sak, TMD Design lead bottom 500 ft above the Top of West Sak Annular area Lead length * Annulus area Excess factor Cement volume required Yield for Permafrost Cmt Cement volume required Surface tail: TMD 9-5/8" shoe (surface TD - 500' above West Sak) * (Annulus area) Length of cmt inside csg Internal csg volume (36#, J-55 Shoe Joints) Cmt required in casing Total cmt Excess factor Cement volume required Yield for Class G cmt Cement volume required 7" Production Casing Cement: Production tail- TMD Top of Target, TMD Want TOC 500' above top of target Annulus area (9" Hole) (TD-TOC)*Annulus area Length of cmt wanted in csg Internal csg volume (26#, J-55 Shoe Joints) Cmt required in casing Total cmt Excess factor Cement volume required Yield for Class G cmt Cement volume required 2,423 ft 1,923 ft 0.3132 cf/If 602 cf 15% 693 cf 1.97 352 sxJ 4,294 ft 743 cf 80 ft 0.434 35 cf 777 cf 15% 894 cf 1.15 777 sxI 11,926 ft 11,594 ft 11 ,O94 ft 0.1745 145 cf 80 ft 0.2148 17 cf 162 cf 15% 187 cf 1.23 152 sxJ ~.UPARUK RIVER UN/, 20" DIVERTER SCHEMATIC I 6 5 I I 5 DO NOT SHUT IN DIVERTER AND VALVES AT SAME TIME UNDER ANY CIRCUMSTANCES. MAINTENANCE ~, OPERATION . UPON INITIAL INSTALLATION, CLOSE PREVENTER AND VERIFY THAT VALVE OPENS PROPERLY. CLOSE ANNULAR PREVENTER IN THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN APPROPRIATE VALVE TO ACHIEVE DOWNWIND DIVERSION. ARCO ALASKA, INC., REQUESTS APPROVAL OF THIS DIVERTER SYSTEM AS A VARIANCE FROM 20AAC25.035(b) 1. 16" CONDUCTOR 2. SLIP-ON WELD STARTING HEAD 3. DIVERTER ASSEMBLY WITH ONE 2-1/16"- 2000 PSI BALL VALVE 4. 20" - 2000 PSI DRILLING SPOOL WITH TWO 10" OUTLETS. 5. . 10" HCR BALL VALVES WITH 10" DIVERTER LINES, A SINGLE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. VALVES CAN BE REMOTELY CONTROLLED TO ACHIEVE DOWNWIND DIVERSION 20" - 2000 PSI ANNULAR PREVENTER EDF 3/10 J .I 7 6 13 5/8" 5000 F.,,I BOP STACK ACCUMULATOR CAPACITY TI~ST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TO PROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI WITH 1500 PSI DOWNSTREAM OF THE REGULATOR. 3. OBSERVE TIME, THEN CLOSE ALL UNITS SIMULTANEOUSLY AND RECORD THE TIME AND PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI REMAINING PRESSURE. BOP STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH ARCTIC DIESEL. 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG WILL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TESTALL COMPONENTS TO 250 PSI AND HOLD FOR 10 MINUTES. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 10 MINUTES. BLEED TO ZERO PSI. 5. OPEN ANNULAR PREVENTOR AND MANUAL KILL AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILLAND CHOKE LINES. 7. TEST TO 250 PSi AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, LINES, AND CHOKES WITH A 250 PSI LOWAND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE BOTTOM PIPE RAMS. TEST BOTTOM RAMS TO 250 PSI AND 3000 PSI. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 10 MINUTES. BLEED TO ZERO PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE MANIFOLD AND LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI. 12. TEST KELLY COCKS AND INSIDE BOP TO 3000 PSI WITH KOOMEY PUMP. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. 1. 16"- 2000 PSI STARTING HEAD 2. 11" - 3000 PSI CASING HEAD 3. 11" - 3000 PSI X 13-5/8" - 5000 PSI SPACER SPOOL 4. 13-5/8"- 5000 PSI PIPE RAMS 5. 13-5/8"-5000 PSi DRLG SPOOL W/ CHOKE AND KILL LINES 6. 13-5/8"- 5000 PSI DOUBLE RAM W/ PIPE RAMS ON TOP, BLIND RAMS ON BTM 7. 13-5/8"- 5000 PSI ANNULAR CASING AN[] TUBING 0ESIGN "ELL ~ .~. -- 7 FIELD ,. CASING STRING . BOROUGH' STATE A~ASKA le I.~0 Vi]', I 9, ~ ~/q. )IYD GR. I . Z/?~ psi/rt. Huo WT. Ii INTERVAL DESCRIPTION CASING SIZE Bottom Top LENGTH Wt. Grade Thread 1. . I~ " . I,,~1' /-/! ~'o '~,5" W -'da su~?-ss lO,' ~ I ~/~' HYD. GR. II , ~"'¢/1 psi/rt. WEIGHT TENSION MINIMUM W/ 8F , -top of STRENGTH I. W/O BF~ section TENSION lbs ~,~lbs 1000 lbs TOF' COLLAPSE CC~_LAPSE INTERN~t, PRESS. Q RESIST. I,/,~ BURST MINIMUM 1.0 bottom tension P~ESSURE YIELD psi psi CDF psi psi _ 8O...._~F / - · ** CHECK LIST FOR NEW WELL PERMITS ** ITEM ~ DATE (1) Fee , ~;~//~'Z 1. (2) Lo, c /?f~, ~/~/c? 2. 2. [2 thru 8] 3. 4. 5. 6. 7. 8. (~) Adm~n ~e~ g~~ ~. ~'['~ ~hru 13]TM 10. [10 g 1~] 12. 15. (4) ,Casg ~z~ ¢_g_?~ 14. [14 thru 22] 15. [23 thru 28] (5) BOPE 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. Company, Is permit fee attached ............................................... Is well to be located in a defined pool .............................. Is well located proper distance from property line ................... Is well located proper distance from other wells ..................... Is sufficient undedicated acreage available in this pool ............. Is well to be deviated $ is wellbore plat included ................... Is operator the only affected party .................................. Can permit be approved before 15-day wait ............................ Does operator have a bond in force ................................... Is a conservation order needed ....................................... Is administrative approval needed .................................... Is lease nLmber appropriate .......................................... Does well have a unique name & nLrnber ................................ Is conductor string provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ Will cement tie in surface & intermediate or production strings ...... Will cement cover all known productive horizons ..................... Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore ................... Is old wellbore abandonment procedure included on 10-403 ............. Is adequate wellbore separation proposed ............................. Is a diverter system required ........................................ Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams $ descriptions of diverter & BOPE attached .... Does BOPE have sufficient pressure rating -- test to ~C:N:)~ psig ..... Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... (6) Other ~?~'. [29 thru 31] (7) Contact 29. 30. 31. 32. 33. FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone nuT, er of contact to supply weekly progress data ...... Additional requirements ............................................. / geol ogy_D eng i n,eer i nq' DWd~ MTM_~_ RAD R PC~..W~ BEW____ d~~'/~ INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~ SHORE Additional remarks' rev 08/18/92 jo/6.011 0 --~ -cz ~-~o --I m Z ITEM (1) Fee (2) Loc -'-' CHECK LIST FOR NE~ ~LL PERMITS ,"',, APPROVE DATE [2 ~hru (3) Adm ' n. [~/]~_ E9 thru 13] [10 ~ 13] ( ) C []4 thru (5) BOPE ~. v';~. ; ' [23 thru ~28] 'E'~-"thFu 3]']' (6) Other (7) Contact /////~ E32] (8) Add l ~ ~,~.~"'~,~..___ / Company //~'_~) Lease & Well YES NO 1. Is permit fee attached ............................................... j~_ , 2. Is well to be located in a defined pool .............................. ~ 3. Is well located proper distance from property line ................... 4. Is well located proper distance from other wells ..................... , ', ..... 5. Is sufficient undedicated acreage available in this pool ............. ~ 6. Is well to be deviated & is we!lbore plat included ................... ~ _ 7. Is operator the only affected party .................................. 8. Can permit be approved before 15-day wait ............................ REMARKS Be 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. Does operator have a bond in force ................................... Is a conservation order needed ....................................... Is administrative approval needed .................................... Is lease n~nber appropriate ........................................... Does well have a unique name $ m~nber ................................ Is conductor string provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ Will cement tie in surface & intermediate or production strings ...... Will cement cover a11 known productive horizons ..................... Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore.' .................. Is old wellbore abandonment procedure included on 10-403 ............. Is adequate wel 1bore separation proposed ............................. Is a diverter system required ........................................ Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams & descriptions of diverter g BOPE attached .... Does BOPE have sufficient pressure rating -- test to .'~Oom psig ..... Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... 29. 30. 31. 32. 33. FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone n~rnber of contact to supply weekly progress data ...... Additional requirements ............................................. // g ZEZ c~rrl geology' eng i n_eer i rig' DWJ M TM~._-~ LC~ dH rev 04/92 jo/6.011 INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~ SHORE Additional remarks' Well HistorY File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history' file. To improve the readability of the Well History file and to simplify finding information, informati;3n of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. ACA~A COMPUTING CENTER *---'--' ~CHLUMBERGER ----m--~ COMPANY NAME : ARCO ALASKA, INC, WELL NAME : 2M'07 FIELD NAME : KUPARUK RIVER BOROUGH : NORTH SLOPE STATE : ALASKA API NUMBER : 50-103'20177 REFERENCE NO : 92563 ~'Is ?a~e veriflcatio~ L[stino ;chlum[~er~er Alaska Computing Center **** REEL HEADER **** SERVICE NAME : EDIT DATE : 93/05/18 ORIGIN : FLIC REEf NAME : 92563 CONTINUATION # : PREVIOUS REEL COMMENT : ARCO .ALASKA, INC.,KUPARUK R' " ..... **** TAPE HE~DER **** SERVICE NAME : EDIT DATE : 9~/05/~B ORIGIN : FLIC TAPE NAME : 9256] CONTINUATION # : 1 PREVIOUS TAPE : COM~E..~I : ARCO ALASKA INC.,KUPA~UK RIVER UMIT,2M~07,50'10~-20~77-00 TAPE HEADE~ KUPARUK RIVER UNIT MWD/MAD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: #. jOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATIOM(FT FRO~ ESL 0) KELLY BUSWlNG: DERRICK FLOOR: GROUND LEVEL: 2 I~ -07 so o3 o1 oo A CO 'I c' SCHLUMBERGER WELL SERVICES # WELL CASING RECORD I. ST STRING 2ND STRING BlT RUN I BlT RUN 2 BIT RUN 3 92563 92563 92553 ST. AM:OUR ST, AMOUR ST, AMOUR 27 llN BE 114 94 146.00 146,00 105.00 OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 9.625 ]261.0 ;Chlum..ergerb Alasl<a ComPUtl. n~ Center ~RD STRING PRODUCTION STRING , ********** ~uN t ********** GR_ _TO BIT =:. 65,3~, RES;: TO BIT =, 75.76 9~ILLED INTEEVAL:'~261 TO 73.35' ********* ~uu: 2,********** ' GR TO BIT =:~ 44.!', '~RES~T:Q BIT GE TD BIT = 44.5',~ R. ES TO BIT DRILLED :t~NTERVALt~ t0057' TO '~0340' WASMDO~N DATA PRESENTED !0126' loll0' RGS RESISTIVITY FAILURE AT 10t3TO ' . 0 GR DATA VALID TO TD.: ' 'N ~ ' Y DATA ~RON DOW~HO~E ME~OR~. DA~A SAMPLED EVERY 20 SECO~DS,;N SOFTWARE: V2.:3D/4.0C 20-~4Ay-lgg3 08:56 **** ~[:~ .~a~. **** FILE NAME: : EDIT .001 s~v~c~ : F~C v~s~o~ : oo~o7 DA~r~ : o3/0S/18 ~AX nRC FILE TYPE : BO L~$T FILE : EDITED ~ERGED Depth Shifted and cl~Pped curves; all blt runs merged, DEPTH INCREMENT 0.5000 # FILE SU~gARY PBU TOOL CODE START DEPTH ~D 3261.0 $ B~SELINE CURVE FOR SHIFTS~ GR CURVE SHIFT DATA (MEASURED DEPTH) BASELINE DEPTH 88888, g~13o5 9204.5 STOP DEPTH 10340,0 ----------EQUIVALENT UNSHIFTED DEPTH---------- 888 9213.0 9~O3.5 Alaska Computing Center 91t2.0 9055'0 8996 ' 8895'0 8849 ~ 5 8838 5 8807 5 8760 5 8702 5 8663 0 8642 5 861 o 5 856:2 5 8525:0 8460.5 843~.5 8406,.5 8390 ' o 8361,5 8348;5 8243,0 8219,5 8181 0 8 !:20 5 81t5 0 8076 0 8018 5 7958 5 7939 0 7883 0 7850 0 7816 5 7812 0 7730 5 769] 0 7638 5 7612!0 7591 5 7572,0 7549,0 7512.5 7482,0 7452,0 7433.5 741g.5 7369,5 7348.0 7338.5 7316.0 7283,0 7235,0 7193 5 7142!0 7t32 0 9 o 9' 9053,!5 8996'0 8937'5 8894,5 8847.5 8838.0 8807.5 8760'5 8702,:0 8662'0 :864! 8563 8458.~5 8437.5 8403 8357'0 8345':0 8240.0 8218'5 8176-5 8113:.::5 8109,5 8074".5 8015'5 7955.0 7935.5 7879,0 7847.5 7814,0 7, o. o 7727..0 7692'5 7637,0 7611,5 7591,5 7571.5 7549,0 7512.0 7482.5 7452.5 7434.0 7419,5 7371.0 7346.5 7337.5 7314,0 7281,5 7241.0 7200.0 7149.0 7138.0 ~O-~AY'!993 08:56 Tame Verification Listing ~chlumberger A~ask:a Compu. tlng Center' 20-~AY-19g3 08:56 7101.5 7107,5 7091,5 7097.5 7048.0 7053.5 70{4,5 70!~ 0 ioo.o lo ~s $ PASS NO. MERGE TOP MERGE BASE THE DEPTH SHIFTS ABOVE· REFLECT MWD GR TO CASED HOLE GR FROM CET/CBT RUN ON 09'J.AN-93, THE CBT WAS LOGGED WITH TO0[,S ON END OF COZLED TUBZNG, ASL OTHER CURVES WERE CARRIED WITH THE GR SHIFT. # LIS F{]R~AT DATA PAGE: ** DATA FORMAT SPECIFICATION RECORD ** **SETTYPE TYPE R. EPR CODE VASUE 1 66 0 2 66 0 3 73 20 4 66 ! 5 66 6 73 7 65 11 66 51 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** ~.~ s~v '~ '"""'"'""""'""'"'"'"~' ' ID ORDER # UOG TYPE CBAS$ MOD NUMB SAMP Ebe~ CODE (HEX) '"'"'~e~, .... ""'"'"'"""'"'"'"'"'""'"'"'"'"'"'"'"'"",'"",,,"'""e, oo ooo oo o ~ ~ ~ ~ . o ooo ~. .~ OH~ ooooo oo o ~ , , 4 ~ oooooooooo ~ ..~ o...ooooo oo o ~ , , 4 ~ oooooooooo ~IS Tame Yertficatlon Listtnq ;chiumberqer Alaska ComputlnQ Center 20-MAY-t993 08:56 PAGE: NAM~ SERV UNIT SERVICE AP1 API AP1 API FILE NUMB NU SIZE EPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) ROP MND F/HR O0 000 00 0. I 1 X 4 68 0000000000 GR .ND GAPI 00 000 00 0 i I 1 4 68 0000000000 ** DATA D~P.' i0340:.500 ~A MWD 999 250 RP ~W'D -999 250 ROP MWD GR.MWD -999,250 DEPT. 10300 000 RA.MWD -999.250 RP,MWD -999.:250 ROP,M'WD GR.MWD -999:250 DEPT, 10200.000 RA.MWD -999,250 RP,MWD -999.250 ROP,~WD GR.MWD 31,470 DEPT. 10100,000 RA,MWD '29,376 RP,MWD 134,566 GR,NWD 36,005 DEPT, I0000,000 RA.MWD $1,377 RP,MWD 353.585 ROP,MWD GR,MWD 48,362 DEPT 9900.000 RA.MWD 28,598 RP,MWD 51.046 RDP,MWD GR:MWD 56,245 DEPTGR:MWD 9800:.794 36:000 RA,MWD 21,196 RP.MWD 68.711 ROP,MWD DEPT. 9700,000 RA,MWD 32,991 RP,MWD 40,39~ ROP,MWD G~.MWD 56,782 DEPT, 9600,000 RA,MWD 29,249 RP,MWD 58.917 ROP,MWD GR,MWD 34,670 DEPT,. 9500,000 RA,MWD 26,288 RP,MWD 87,147 ROP,MWD GR,MWD 47,672 DEPT, 9400,000 RA,MWD 26,2~8 RP,MWD 18,465 ROP,MWD GR,MWD 62,031 DEPT, 9]00,000 RA,MWD 30,630 RP,MWD 20,881 ROP,MWD G~,MWD 61,175 D~PT, 9~00,000 RA,MWD 29,920 RP,MWD ]0,477 ROP,M~D GR.MWD 60,699 D£PT, 9100'000 RA*MWD 29,047 ~P,MWD ~6.427 ROP'MWD G~.~WD 63,060 -716,714 77,922 154,303 43,902 33,898 40,448 50,.141 69,765 109.081 77,584 49,726 60,4~4 60,607 63,378 Tape Vet~:f:~tCatlOn Li:stin~ ;cl~lumbetqer~ Alaslca: Comput!hq DEPT- 9000,000 GR.MWD 3!.257 DEPt. 8900.000 GR.~WD 37,994 D~P~<' a8oo..ooo Gn'MWD 39.624 ~':, ~7oo'ooo G~.MWD 57.845 DKPT",: 8600.000 G~oMWD 55.957 DEPT., 8400.000 GR.MWD 68.666 DEPT. 8300'000 GR.MWD 42.425 ~,.~.. ~oo'ooo GR.:,,WD 1~0-552 DEPT. 8000.000 GR.MWD 109.478 DEPT 7900 ~00 G~:MWO ~0~:~ 7~ DEPT, 7800.000 CR.MWD DEPT. 7700.000 G~..WD 9~.56~ D~PV., 7600.000 D~P?. ?~00.000 D~PT' 7400.000 Dee?. 7300.000 Center RA'MWD RA'MWD RA,MWD RA.MWD RA',MWD RA*MWD RA'MWD RA,~MWD RA.MWD RA'MWD RA.MWD RA'MWD RA.MWD RA'MWD RA'MWD ~A.MWD RA.MWD 28.277 24.854 ~29'67! 28,742 ~34.398 26.:~88 11,067 8'~32 23.2~9 3.571 2.629 2.819 2.474 2.225 4.273 2.720 2.600 3.375 RP,MWD RP*MWD RP..MWD RP'MWD RP'MWD R P' M W D RP-:MWD RP,MWD RP.MWD R P- M RP-MWD RP,MWD RP.MWD RP,MWD RP.MWD RP.MWD RP,MWD RP,MWD 63'775 75~447 66-~66 40'440 9'696 45'954 4'375 4'B20 6.725 4.22~ 3'650 5,990 3'512 4.022 3.533 n0P'MWD RDP'MWD ROP~MWD RO:P'MWD ROp*NWD RO:p'MWD ROp'MWD ROP~MWD ROPiM~D ROP'MWD ROP*MWD ROP,MWD ROP,MWD ROP,MWD ROP,MWD ~O~.~wD ROP,~WD ROP.HWD 56~05 42'660 97'292 66'6~9 ~5t'996~ 10.3~094 65'217 100'004 100'556 69.769 74'028 102.697 93.863 174.502 135"639 7~.53! 288.875 ~chlumberger AlasKa Computing' Center D~, 7200.000 DEPT'~ 7t00;000 RA,.MWD GR'MWD 96'472 DEPT' 7000'000 ~A'MWD GR.MWD 86,232 GR'~WD 83,.473 DEPT~ 6700'000 RA~iMWD DEPT':~ 6600'000 RA~,HWD D~PT' 6:500.000 RA-MWD GR.~WD: i08'778 · DEPT-:~ 6300,000 RA~!MWD GR':MWD 63,396 , DEPT,~ 620 ~00 RA-MWD GR.MWD 82.810 DEPT.. 6000'000 RA.MWD GR.MWD 89.829 DEPT. 5900,000 RA.MWD GR.MWD 95.0?7 DEPT. 5800.000 RA.MWD GR.MWD 111.168 DEPT. 5700.000 RA.MWD GR.MWD 110.077 DEPT. 5600*000 RA.MWD G~.MWD 134.396 20-~AY'! 993: 08:56 3'::~65 RPoMWD 4,524 I~P,MWD t'347 RP'MWD 3 · $ ~ 7 ~ ~' M w D 3.123: RP.MWD 3,243' RP~MWD< 2.332 RP'MWD 3,842 RP,MWO 2.824 RP,MWD 2,974 RP,MWD 3.618 RP.MWD 3.769 RP.MWD 3.469 RP.MWD 2.984 RP,MWD 1.889 RP,MWD 4'024 4'~i178 !'050 3':~! 63 · 2~:9I 3 ~2'990 2'i179 3'546 2'629 2,771 3.290 3.547 3.292 2,624 1.745 ROP~MWD ROp'MWD ROP'MWD R0P'MWD ROP~MWD ROP,MWD ROP'~WD ROP'HWD ROP.~WD ROP'MWD ROp. MWD ROP'H~D ROP.MWD ROPoMWD PAGE:~ 289.3!5 328~394 31:0'544 328'644 :1374.709 ~46'337 ~:185'897 141,730 229,490 245.580 269,000 252.450 241,580 297.082 396,063 168,491 ;Chlumberger Alaska~ Computing DEPT* G~*MWD DEPT~ G~,MWD DE:PT',; GpoMWD, DEPT" GR.MWD D pT' G~.,MwD GR.MWD GR,~WD GR,MWD GR.MWD GR.MWD GR.MWD GR.MWD DEPT GR~MWD DEPT, DEPT. G~.MWD 5500,000 '117,920 5400,000 90'936 5300'000 84,182 5200,.000 5100'000 76.~95 5000'000 103':~65 4900~000 72-723 48001.000 86'628 4700,000 84,386 46.00'*:0.00 83.365 4500,000 72.545 4400000 e 1459 4300~00 85~ 62 4200,000 74,817 4100.000 58.795 4000.000 72.337 3900.000 76.042 3BO0.OO0 85,798 center RA*,MWD RA'MWD RA~:!MWD RA'MWD RA'MWD, RA'MWD: RA~MWD 'RA~MWD RA'MWD RA'MWD RA'MWD RA,MWD RA'MWD RA,MWD RA.MWD RA,MWD RA,MWD os:se:: 4,341 'eos 3,806 3*592 3-32? '3.622 4,i06 3,062 3,648 21.774 2,464 2,970 3,284 4.103 3.904 4.337 RP.MWD~ RP,MWD~ RP~:MWD RP'MWD RP'MWD RP,MWD RP,MWD RP,MWD RP,MWD RP,MWD RP.MWD RP,MWD RP.MWD RP,MWD RP.MWD RP.MWD 4;384 i'676 .3~580 ':3~,511 2':913 3.736 2'661 2.374 2.882 3.078 3.~74 3.659 4.061 ROP;MWD ROP'MWD ROP'MWD ROP',WD ROp,M~D ROP,M~D ROP,M~D ROP,M~D ROP'M~D 437'169 4!8'798 :340'68! 442~923 420'433, 451'I69 438'272 ~529,220 441,~828 480,969 312,797 t83,551 515,642 465,617 409.667 ~Chlumberger~ A~as~Z Computing center PAGE{. D~P?. 3700.000 ~A.MWD GR.MWD 85,128 DEPT. 3600,000 RA..:.MWD GR.~WD DEPT 3500,000 GR:~WD ~6,808 DEPT. 3400.000 RA,MWD G.P.MWD 80.546 D~PT. 3300,000 RA,MWD GR.MWD DEPT. 326!,000 RA,MWD G~,MWD 42.915 END OF DATA 4,888 8.596 RP:'MWD: 4'260 8.725 4-386 0.005i' ~P*~WD~ 8 W O 4 3 8' 7.41 .. 4:2:0 ROp~MWD ROP'~WD ROp'~WD ROP*MWD ROP',MWD 419'953 44:1'571 562"594 268'326 708'017 -999'.250 **** F:iLE:TRA{LER: **** FILE NA'~E : EDI~ :.O01 SERVICE ~ :FbfCi VERSION: : 001A07 DATE : 93/05/I8 ~AX REC sIZE~ : ~{0~4 FILE TYPE : 60 bAST FILE : **** FILE HEADER FILE NA~E : EDIT ,002 S~R. VICE : FLIC VERSION : 00fA07 DATE MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE FILE HEADER FILE NUMBER 2 RAW MWD Curves and log header data for each bit run in separate BIT RUN NUMBER: 1 DEPTH INCREMENT{ 0.5000 FILE SUMMARY VENDOR TOOL cODE START DEPTH STOP DEPTH Tape veriflcat!on 'Slst~n~ ;chlumberger Alaska Computln~ Center 20-MAY-1.993 08:56 PA o CDR 3189.5 HEADER DATA DATE LOGGED~ SOFTWARE SURFACE SOFTWARE DOWNHOLE SOFTWARE VERSION: DATA TYPE CMEMORY OR REAL-TIME): TD DRILLER TD LOGGER(F~): TOP LOG .INTERVAL (FT): BOTTO~ LOG: INTERVAL (FT)~ BIT ROTATIONAL SPEED ~OLE INCLINATION (DEG) MI.NI~U~ ANGLE~ MAXIMUM ANGLE: 7335.0 12'SEP'92 FAST 2,3D V4,0 MEMORY 7335,0 7335.0 3261'0 7~35.0 TOOL STRING .(TOP TO BOTTOm) VENDOR TOOL CODE TOOb TYPE CDR RESISTIVITY CDN NEUTRON DENSITY $ OPEN HOLE BIT SIZE ( (FT)I BORENOLE CONDITIONS ~UD TYPE~ MUD DENSITY (LB/G)~ MUD VISCOSITY ~UD MUD CHLORIDES FLUID LOSS (C3)i ~AXIMU~ RECORDED TEMPERATURE (DEGF): RESISTIVITY (OHMM) AT TEMPE~ATUR~ [DEGF): ~UD AT MEASURED TEMPERATURE MUD AT MAX CIRCULATING TEMPERATURES MUD FILTRATE AT MUD CAKE AT (MT): NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF EWR FREQUENCY (HZ)~ GR TO BlT : 65,3', RES TO BIT = 75 76 DRILLED INTERYAL: 3261~ TO 73~5'. ' TOOL NDe042 8 50 BRINE 10,40 140,0 1,998 2,027 72.0 72.0 ;chlumberger Alas)~a, ¢omputln~ Center 20-MAY-1993 08:56 # bTS FORMAT ~ATA FROM DOWNHOLE MEMORY... DATA SAMPLED EVERY 20 SECONDS. SOFTWARE~ V2..3D/4,0C $ DATA FORMAT SPECIF~CR?:ION RECORD ** SET TYPE ~ 64EB ** TYPE REPR CODE VALUE ! 66 0 2 66 0 3 73 20 4 66 1 5 66 6 73 7 65 9 65 1! 66 51 1~ 6~ 13 66 0 14 65 FT ~5 66 68 16 66 1 0 6~ I ** S NAME SERV UN ID DEPT FT ATR LWi OH PSR LWI OH ET TYPE - CHAN ** IT SERVICE AP1 API API AP1 FILE NUMB NUMB SiZE REPR PROCESS ORDER # LOG TYPE CLASS MOD NUMB SAMP ELE~ CODE (HEX) ~mmmmmm~mmmmmmmmmm~mm~mmmmmmmmmmmmmmmmm~mmmmmmmmmmmmmm~.;mmmm~.mmm.m--mm O0 000 O0 0 2 I I 4 6 00000000 M~ O0 000 O0 0 2 1 I 4 68 0000000000 M~ O0 000 O0 0 2 1 1 4 68 0000000000 ROPE LWI F/HR O0 000 O0 0 2 1 ! 4 68 0000000000 GR LW1 GAPI O0 000 O0 0 2 1 I 4 6B 0000000000 mmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmmm~mmmmmmmmmmmmmmmmmmmmmmmm~mmm DATA ** D~PT. 7335.000 G~.LW1 121.480 ATR.LW1 3.592 PSR,LWi 4.119 ROPE.LW! 132.348 ~chlumberger AlasKa Computing Center DEPT' 7300'000 ATR~i, LWI GR,LW! 90,51,8 D P?' 7200'000 A?R. Wl G~,LWI 12X.454 DEPT. 7000'000 G~iLWI 90':i70 DEPT.,~ 6900~000 ATR-LW! GR.LW1 86.2129 G~.LW! 80;909 G.:bW! ~02.345 6400'000 · DEPT 6300,000 ~TR'LWl DEP? 6200 TR' G.:[,wl 80.20! DEPT. 6000.000 ATR.LWl GR.LW'! 93.656 DEPT 5900.000 ATR.LW1 G~:LWl 96.t88 DEPT. 5800.000 ATR.LW1 GR.LW1 105.451 DEPT. 5700.000 ATR.LWI GR.LW! 112.507 D~PT 5600,000 ATR.LWl GR:LW1 132,334 20,,,.MAY'~.993 08:56 3,469 PSR'LWI 3.892 PSR'LWl 3-387 P$R.LW1 4.677 PSR'LW1 3'5!7 PSR'LW1 1'129 P$Ri'LWI 3,.567 3 ,: 222 P S R :, b w 1 3.221 PSR'LWl '358 3,119 PSR.LWl 2.929 PSR.LWI 2.957 PSR,LWl 3.398 PSR.LW1 3.785 PSR.LWl 3.478 PSR.LWl 3,300 PSR,LWl 1.805 PSR.LWI 3'784 3,897 3'397 4'566 31.344 0'981 3.259 31,038 2'988 2"247 2"756 2.592 2'864 2.941 3.705 3.313 3.073 1.687 ROpE.I,,WI ROPE. LW I R 0 P E '. L W 1 ROPE.LWl ROpE.LW1 ROPE.LWI ROP~'LW! ROPE.LW! ROPE.LW! ROPE.LWI ROpE,[.,T~I ROPE.LWl ROPE.L~I 299'5!3 18 3.6 7 7 :397.538 346,943 30 .I, 921 .313.899 176' :002 166'367 156.~53 250,543 249.130 268,739 253,484 224.410 297.774 386.517 148.061 ~Is :?a~e: verification !~.l. St~ng ,¢hlumberqer Alaska Computing Center DEP~o 5500,00:0 GR.5W! 11.4'043 DEPT.. 5400.'000 G~.LW! 10i,245 G~.hW1 85;983 u Pm',, s2oo'ooo GR.bWl 1:20-:647 DEPT.~:w 5100 0~ DEPT.:~ 5000,:000 9oo' oo DEPT.~i 4800 ~00 DEPT. 4600-000 GR.LW! 85.324 DEPT. 4500 00 4oo'ooo oo.ooo GR.LW! 87.519 D~PT. 4200.000 GR.LWi 81.812 D£PT. 4100.000 GR.LW1 58.137 DEPT. 4000.000 GP.LWi 70.770 DEPT. 3900.000 GP.I. Wl 79.247 ATR,:,LW! ATR~i5W1 ATRi'LW! ATR~iLN1 ATR~i, W1 ATR',LWI ATR~!LwI ATR.bW1 ATR'bWl ATR'LWI ATR.LWl ATR.LW! ATR.LW1 ATR.LWl ATR.LWl 20-MAY-1993 08:56 4.353 PSR,LW! 1.911 PSR:,bWl 1.822 PSR'bWl 4,092 PSR,~W! 3'896 PSR'bW! 3.297 PSR'LWl 4.422 PSR~:.SW:I 3.618 PSR*LWl 3-040 PSR'bW1 3.341 PSR'LWl 2.807 PSR.bW1 2.295 PSR'bW! 2.962 PSR.bWI 3.19] PSR.SWl 4.307 PSR.bW1 3.8&3 PSR.LWl 4~:.610 1'903 1.603 3~:948 .2'825 4~9! 2.821 3.140 2'678 2'242 ~.030 4.004 3.539 ROPE'LWt ROPE,LW1 ROp ' wI ROp£,.LW1 ROpE*LWI ROPE'LWI ROpE'SW1 ROPE'LWI ROpE~bW1 ROPE.LWI ROP£'LW1 ROPE'LW1 ROPE.LW1 ROPE.LW! ROp£.LW1 ROPE.LW1 PAGE: ,I3 435'332 406!.:$!7 335'187 359,355 491.:~.48 449.973 42!'282 4!3'426 451'354 388.606 535'304 416'562 531.098 328.993 374'114 545.934 456.612 .,IS Tape Veriflcation Listing ~chlumberger Alaska Computing DEPT. 3800.000 G~oL~I 79.048 3700,000 DEPT"LWI 91 865 DEPT. GR.LW1 75,059 too.ooo .. GR.LWI 71,360 DEPT. 3189..500 GR.I, W1 44,366 Center ATR.LW1 ATR.LWI ATR.LWI ATR.LW1 ATR.LW! ATR.LWl ATR.LW1 4,528 4,426 8,335 4~305 8.000 4,4!2 '9991,250 4"184 4'448 7,8t5 4':23! ~999-250 :ROPE~LWl ROpE'L~I ROpE-LWl ROPE'LW1 ROPE'LWI PAGE ~ 14 424'968 419,067 438'225~ 570:'459 286,860. 736'41:2 -999'~250 FILE NAMiE : EDIT ,002 SERVICE : FLIC VERSION : 00!A07 DATE ~ 93/05/18 MAX REC $IZ~ ~ 1.024 FIL~ TYPE ~ LO LAST FILE FILE NAME : EDIT ,003 SERVICE : FbIC VERSION : O01A07 DATE : 93/05/18 MAX R~C SIZE : 1024 FXL~ TYPE : LO LAST FILE : FILE HEADER FILE NUMBER 3 RAW MWD Curves and log header data BIT RUN NUMBER: 2 DEPTH INCREMENT: 0,5000 for each bit run in separate f~lles. ;cl~l,U~ber~er~ Alaska Computing Center FILE SUMMARY VENDOR TOOL CODE START DEPTH , CDR LOG HEADER DAT~ DATE LOGGED~ SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION~ DATA TYPE (MEMORY OR REAL-TIME) I TD DRILLER TD LOGGER(FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL 8IT ROTATIONAL SPEED HOLE INCLINATION [DEG) ~INI~U~ ANGLE~ ~AXI~U~ ANGLE: TOOL STRING (TOP TO BOTTOM) VEN...~OR TOOL CODE TOOl, TYPE --------- RESI&TIVITY CON NEUTRON DENSITY $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY MUD VISCOSITY MUD ~UD CHLORIDES FLUID LOSS MAXXMUM RECORDED TEMPERATURE (DEGF~ RESISTIVITY (OHMS) AT TEMPERATURE MUD AT MEASURED TEHPERATURE (MT): MUD AT MAX CIRCULATING TEMPERATURE: ~UD FILTRATE AT (MT): MUD CAKE AT (MT): NEUTRON TOoL ~ATRIX: MATRIX DENSITY~ · HOLE CORRECTION (IN): TOOL STANDOFF (IN E~R FREQUENCY (HZI~ REMARKS: ********** RUN 2 ********** STOP DEPTH 10057,0 V4.0 Mi E M 0 R Y {,0057'0 TO0 i~ N U M B£ R RGS022 NDS042 8,500 3261.0 BRINE· 10,40 140,0 1,998 2,027 72.0 72.n ~ch!umberger AlasKa ¢omputlng Center 2 o- M A ¥- ! 9,9.3 0 8: 5 6 :R TO St..,-' 44. , :ORILL£D INTERV.A~,: ~'0 :~oo57,, · 90' ;WASHDO~N INTERVAL: TO 7335 , ATA~ FROM DOWN~OLE DA~A; SAMPLED EVERY 20 SECON~DS SO~ TWARE: V2 TYP~. R!~PR ~,., C:UD~ I 66 0 2 66 0 3 73 20 4 66 5 66~ 6 73 7 65 I1 66 51 12 68 13 66 0 14 65 ~T 15 66 68 16 66 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API AP1 AP1 APl FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP EbEM CODE (HEX) oo ooo oo oooooooooo ATR LW2 OHMM O0 000 O0 0 3 1 1 4 68 0000000000 PSR LW2 OHMM O0 000 O0 0 3 ~ 1 4 68 0000000000 ROPE LW2 F/HR O0 000 O0 0 3 I I 4 68 0000000000 GR LW2 GAPI O0 000 O0 0 3 1 1 4 68 0000000000 DATA ,~t8 ?a~e ver~ftcat~on b~st~ng ,chlumbetqer Alaska CompUt~n~ Center DEPT DEPT. GR,SW2 DEPT, DEP?. G~ 'LW2 DEPT. DEPT' GR.hW2 DEPT' DEPT' ~. DEPT,. GR,LW2 DEPT, GR,LW2 DEPT, DEPT, G~,LW2 DEPT, GR.LW2 DEPT. GR.LW2 D~PT GR:LW2 10057'000 ATR:j:::LW2 -99:9,250 ~'999,250 .!0000,:000 ATR'LW2 32,,434 :PSR,LW2 49'508 9900'000 ATR'LW2 30.630 PSR'bW2 57,~40 ' 9800'900 A?R'.LW2 21,196 PSR,LW2 36:,~89 9700,000 ATR'LW2 3:2.99.1 PSR,LW2 57,321 960033::~025.:0 ATRi':LW2 28..598 PSR"hW2 9500.000 ATR'LW2 25'272 PSR.bW2 48.048 6~:'166 9300'000 ATR':SW2 29,920 PSR,:SW2: 61,10~ · 9200,000 ATR.SW2 29.920 PSR.~W2 60,~62 9100'000 ATR,LW2 26.288 PSR,LW2 62.524 38:681 8800.000 ~?~o5~2 29.67! P~o5~2 39.624 8700,000 ATR,SW2 31,377 PSR,~W2 57,819 8600,000 ATR,LW2 33,867 PSR,SW2 53,843 8500.000 ATR.LW2 27.~93 PSR,LW2 60,066 8400 000 ATR.LW2 9.307 PSR,LW2 72:1917 '999' so 436,463 51':463 40-344 59'871 86'6~4 20~.~19 30;<78! 26,786 62,73! 74.553 ~40'695 39.054 7~,43! 9.486 ROPE,LW2 ROPE!,LW~ ROPE'LW2 ROpE*LW~ ROPE'LW2 ROPE,LW2 ROPE'bW2 ROpE.LW2 ROPE,5W2 ROPE.LW2 ROPE.LW2 ROPE.SW2 ROPE.LW2 ROP£.LW2 ROPE.LW~ ROPE.Lw2 .40 ' 44 8 50,14I 77'259 84'.90~ 49'726 59,210 56,427 55,158 45,455 97,292 69,920 151.268 132.5~4 75.634 ~chlumberqer Alaska. Computing Center DEPT.L_ G~'SW2 DEPT. DEPT. DEPT.Lw2 DEPT DEPT* Gp,Lw2 DEPT DEPT. DEPT.~ GR.LW2 DEPT,: G~.LW2 DEPT. G~.LW2 D~PT. GR.LW2 END OF 8300,000 66'825 8200'000 43,228 8 00.000 15'782 8000,:000 7900o,000 107-223' : 7800,.000 102-:273 7700,000 ~05'530 v6oo,,ooo 131,070 ,soo: oo 227~73 7400~00 178:47 7300000 9o251 7243~000 89.087 DATA 20-NAY-t993 08:56 **** FILE FILE NAPE SERVICE VERSION DATE MAX REC SIZE FIL~ TYPE LAST FILE TRAILER **** ~ EDIT °0O3 : 001A07 : 93/05/18 : 1024 : LO ATR'LW~ B,':090 PSR-LW2: .9":117 ATR-LW2 24.333 PSR'~W2 48.852 ATR'~PW2 :3,079 PSR'LW2 4'686 ATR'LW2 2'603 PSR,LW2 4'487 ATR'LW2 9.858 PSR,LW2 6'658 ATR"LW2 2.~82 PSR,LW2 3.~81 ATR.LW2 4,237 PSR,LW2 .6.010 ATR:.LW2 2,726: PSR..~W2 3'~582 ATR.LW2 2.603 PSR.bW2 3,254 ATR.LW2 3.469 PSR.LW2 3.784 ATR.LW2 -999,250 PSR,bW2 -999'250 ROPK~LW2 ROPE'LN2 ROpE.~W~ ROpE~LW2 ROpE'LW2 ROPE,LW2 ROPEoLW~ ROPE'LW2 ROpE'bN2 ROpE.L~2 ROPE'bW2 ROPE'bN2 PAGE: !8 81'594 931.748 96'257 85'795 70'590 t02'272 88,676 174'318 135.940 8t,449 I09.755 '999'250 ~chlumberger AlaSka Computin8 Center 20-~AY.!993 08:56 PAGE~ 19 {*~{ FILE HEADER $$~ FILE NA~E { EDIT ,004 SERVICE : Fb!C VERSION : 001A07 DATE : 93/05/I=8 MAX REC SIZE :: 1024 FIL~ TYPE : 50 L~STFILE : FILE READER FILE NUMBER 4 RA~ Curves and 1o~ header data ~or each bit run {n seDarate files, BIT RUN NUMBER: DEPTH INCREMENT: 0.5000 VENDOR TOOL CODE START DEPTH ' $ LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TI~E): TD DRILLER (FT){ TD LOGGER(ET){ TOP LOG INTERVAL (FT): BOTTO~ LOG INTERVAL BIT ROTATIONAL SPEED (RPM)~ HOLE INCLINATION (DEG) ~INIMUM ANGLE: M~XIMUM ANGLE: $ # BO~EHOLE AND CASING BAT4 OPES HOLE BlT SIZE (IN): DRILLERS CASING DEPTH BORENOLE CONDITIONS MUD TYPE: ~UD DENSITY (LB/G): ~UD VISCOSITY STOP DEPTH mmmmmmmm~m I0340,0 18-$EP-9~ FAST2,3D V4,0 MEMORY 10340 0 10340,0 10014,0 10340,0 TOOL NUMBER mmmmmmmmmmm RGS022 NDS042 8,500 3261,0 BRINE 10.40 ;chlumberger Alas~a Computin~ Center 2'O-MAY-199'3 08:56 HUD PHI MUD CHLORIDES FLUID bOSS fC3)~ RESISTIVITY ~EUTRON TOOL MATRIX: ~ATRIX DENSITY: HOLE CORRECTION TOOL STANDOFF (INIt EWR FREQUENCY (HZ GR WA RG GR $0 # LIS FORMAT DATA 140.0 1.998 2,027 ILLED INTERVAL 0057' TO 1034 SHDOW~ DATA PRESENTED I0126' TO RESISTIVITY FAILURE AT: 10130'. DATA VALID TO TO. TA FROM DOWNHOLE ME~DRY. TA SAMPLED EVERY 20 SECONDS. FTWARE: V2.3D/4,0C 7 2 "0 p A G E: ~2o ** DATA FORMAT SPECIFICATION RECORD ** SET TYPE - 64EB ** TYPE REPR CODE VAt, E i 66 0 2 66 0 3 73 20 4 66 5 66 6 73 7 65 B 68 0,5 9 65 FT ii 66 51 12 68 13 66 0 14 65 15 66 68 Tape Ver.ification bist'ing ;chlumberqer AlasKa ComPuting Center 20-~A¥'-1993 08~56 PAGE: ¸2i TYPE CODE V'AhUE 16 66 1 0 .66 1 ID ORDER # hOG TYPE CLASS ~:OD NUMB SAMP, ELEM CODE (HEX) DEPT FT 00 O00 00 0 4 ~ ~ 4 68 0O00000 ooo ATR LW3 OH~ O0 O00 O0 0 4 1 1 4 68 0000000000 PSR LW3 OHM~ O0 000 O0 0 4 t 1 4 68 0000000000 ROPE LW3 F/H~ O0 000 O0 0 4 1 1 4 68 0000000000 G~ LW3 GAPI O0 000 O0 0 41 1 1, 4 68 0000000000 : ** DATA ** DEPTGR:LW3 I~34~,000.99 ,250 A'TR-LW'3 9999.2$0 PSR..bW3 -999.250 DEPT.GR.LW3 1~300999:~005.0 ATR.LW3 -999.250 PSR,bW3 -999,250 DEPT, 10200,000 ATR.t, W3 -999,250 PSR,SW3 -999,250 GR. w] o.al2 D~PT. 10100.000 ATR.LW3 29.376 PSR,bW3 134,322 GR. ,w a .,lo4 DEPT. 10014 000 ATR,bW3 -999,250 PSR.bW3 -999,250 G~oLW3 39:827 END OF DATA ROP'E'LW3 ROPE.LW] ROPE.LW3 ROPE.LW3 ROPE.bW] -716,714 77.922 146.253 43.902 -999.250 **** FILE TRAIhER **** FILE NAME : EDIT ,004 SERVICE : FLIC VERSION : O0!A07 DAT~ : 93/05/18 MAX REC SIZE : 1024 FIL~ TYPE : bO LAST FILE : iChlumberger asKa COm~utln~ center 8:56 PAGE **** FI LE HEAD~:R **** FiLE NA~E EDi~~ ,005 VERSION 00 NAX REC~:SIZE: : 10~4 FILE: TYPE:: I LO b.~ :$ T F I L RA~ CURVES Curve. sam~ 1o~ be:adeT data '~or PASS DEPTM INCREMENT~ -,5000 FILE SUMMARY VENDOR TOOLi.CODE START DEPTM MLDT 9336,0 LOG HEADER DATA DATE LOGGED: TOOL STRING (TOP TO VENDOR TOOL CODE HLDT HbDT HbDT HLDT HLDT HLDT HLDT HLDT HLDT HLDT HLDT HLOT BO~EHOLE AND CASIMG DATA OPEN ~OLE BIT SIZE (IN): each BOTTOM) TOOL TYPE AUXILLIARY NEASURMENTS COLLAR LOCATOR TELEMETRY CARTRIDGE GAMMA RAY SONDE COMP, FORMATION DENS CEMENT BOND CARTRIDGE CEMEMT BOND SONDE HLDT HI VOLTAGE HLDT CARTRIDGE HLDT SONDE 8002,0 CP 32,6 1830 8000 900,0 NO TOoL NUMBER AMS-AA-950 CAL-YA-28 TCC-B-278 SGC-SA-271 CBC-EB-160 CBS-DA-160 HLDV-AA-~9 HLDC-AA-20 HLD~-BA-20 CEEC-B-756 CESS-A-76~ 12.250 ,raw ~I$ Ta~e Verification hlst~n ;chlumberger Alaska. Computin~ Center 20-MA.Y-lEg3 08:'56 DRILLERS CASING DEPTH (FT)) LOGGERS CASING DEPTH (FT) t ~OREHOLE CONDITIONS FLUID TYPEt FLUID DENSITY SURFACE TEMPERATURE (DEGF)~ BOTTOM HOLE TEMPERATURE (DEGF]~ FLUID SALINITY FLUID bEVEL (FT)~ FLUID RATE AT WELLHEAD (BP~)~ WATER CUTS (PCT}I GAS/OIL RATIOI CHOKE (DEG)t NEUTRON TOOL TOOL TYPE (EPITSERMAL OR THERMAL){ MATRIX 80bE CORRECTION BbUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW BASE NORMALIZING WINDOW (FT)~ BbUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE bOW SCALE FAR COUNT RATE HIGH SCALE ¢CP NEAR COUNT RATE bOW SCALE (CP NEAR COUNT RATE HIGH SCALE (C TOOL STANDOFF (IN)~ 10329.0 BR{NE 10.40 157,0 2.65 REMARKS~ HORIZONTAL WELL. WELL LOGGED WITH TOOLS OM THE END OF COILED TUBING, TIE~ INTO bWD CDR, UNABLE TO REACH DRILLERS PBTD DUE TO COILED TUBING STACKING OUT 886' BEFORE TO, AFTER SURVEY TOOL CHECK NOT DONE BECAUSE TOOL STRING LENGTH ~ADE IT IMPRACTICAL TO REMOVE HLDT SOURCE WHILE KEEPING TOOL CONNECTED TO COiL HEAD, $ LIS FORMAT DATA ,iS ?a~e VerifiCation b~st~ng ;chlumberger Alaska ComPu:ing Center DATA FORMAT SPECIFICATION RECORD TYPE - 64EB CODE V ! 66 0 2 66 0 3 73 4 66 5 66 6 7 65 9 ii 66 36 1~ 68 ~3 66 0 14 65 FT 15 66 68 {6 66 0 66 ~ E'~ TYPE CHAN ** --,,------------------,,,-----------------------------------------,,------------------- N E SERV UNIT SERV API API APl AP1 FI[,E NUMB NUMB $I REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUmB SAMP ELEM CODE (HEX) DEPT FT O0 000 O0 0 5 i 1 4 68 0000000000 RHOB HLDT G/C3 O0 000 O0 0 5 1 I 4 68 0000000000 DRHO HLDT G/C3 O0 000 O0 0 5 1 I 4 68 0000000000 LSRH HLDT GtC3 O0 000 O0 0 5 1 1 4 68 0000000000 $SR~ HLDT G/C3 O0 000 O0 0 5 1 I 4 68 0000000000 CCL MLDT V 00 000 OD 0 5 I 1 4 68 0000000000 GR HLDT GAPI O0 000 00 0 5 1 I 4 68 0000000000 DEPT. 9336.000 RHOB.HLDT -I002.036 ORHO.HbDT -99g.250 LSRH.NLOT SSRW.HLDT 2.785 CCb. HLDT 3.7~0 GR.HLDT -0.954 DEPT. 9300,000 RHOB.HLDT -1002.033 ORHO,HLDT -999.250 LSRH.HLDT CCb.. D R..b T SSRH:HLDT 2,766 CCL,HLDT 3:647 GR,HLDT 0 81 DEPT, 9~00,000 RHOB.HLDT -~002.121 DRHO,HLDT -999.250 LSRH.HLDT SSR~,HLDT 2,871 CCL.HLDT 3.955 GR,HLDT '1.054 -999.250 -999.250 -999,250 -999.250 ~chlumberger Alaska Computing center DEPT. 9000,000 RHOB.HLDT SSRH'HbDT 2.$24 CC5,HLDT SRH~HUDT 2~,7i2 CCL'HLDT DEPT' 88001'000 RHOB'HLDT DEPT~ ~?00-000 ~HOB~HLDT SSRH~HLDT 2'836 CCb,.HLDT DEPT'. 8600,000 RHOB'HLDT SSRH.HLDT 2'729 CCL,HLDT DEPT,~ 8500'000 RHOB-HLDT SSRN.'HL. DT 2'93! CCL'~HLDT DEPT,.~ 8400'000 RHOB,HLDT SSRH.HLDT 31.021 CCL.HLDT DEPT'~ D 8300.000 RHOB'HLDT SSRH.HL T 2'868 CCb'HLDT : DEPT.: 8200,:000 RHOBoHLDT $$RH.HLDT 2.773 CCb. HLDT DEPTo 8100o000 RHOB'HLDT $SRH.HLDT 2.889 CCb. HbDT DEPTo. 80021,000 RHOB'HLDT $SRH.HLDT 3,.0~4 CCL-HLDT END OF DATA 20-MAY-1993 08:56 -1001.974 DRHO,HLDT -Egg's50 3'69! GR,~LDT -0'g67 700 GR'HLDT -0'988 3'557 GR,HLDT -I00~',086 DRHO,H5DT -999':259 '803 GR..,H~DT 3,706 GR,HSDT -0°976 4.0 9 GR..HSDT 8 GR,.HLDT '1:;167 5 GR'HLD? 0,947 '1002,023 DRHO-HLDT -999'~R50 3,819 GR,HLDT -t.045 3,858 GR,HLDT 0'969 -I002,274 DRHO'HLDT 4o190 GR'HLDT -1.~166 LSRH.HLDT LSRH'H5DT LSRH'HLDT LSRH'HLDT LSRH'HLDT LSRH*HLDT LSRH*iHLDT 5$RH*HLDT LSRH*~LDT LSRH.HLDT LSRH.HLDT -999'250 ~-999~50 "999~250 -999.250 -999,~50 -999'250 -999"~50 -999'250 -999-~50 -999'R50 -999'250 **** FILE TRAILER FILE NAME : EDIT .005 SERVICE : FLIC VERSION : 00~A07 DATE : 93/05/~8 ~AX REC $IZ~ : FILE TYPE : bO LAST FILE Tape Ver'i~lcat'fon Listing ;ChlUmberger Alaska Computing Center **** TAPE TRA. IbER SERVICE NAME : EDIT DATE : 93/05/18 O~IGtN { PE NANE : 92563 CONTINUATION # PREVIOUS TAPE COMMENT : ARCO A[~ASKA, INC,;.,KUPARUK RIVER UNiT,2M-07,50'!O]-201?7-O0 SERVICE N~ME I EDIT DATE : 93/05/18 ORIGIN : FbXC REEl., NAME : 92563 C~NTINUATION # ~ P. EVIO~S REEL : COMMENT : ARCO ALASKA, INC',KuPARUK RtVE~ UNXT,2M-07,50'lO]-20177'O0