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196-072
STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 2M-33 JBR 01/12/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:3 Started testing alarms @ 1830,Pits FP Meth and LEL (calibrate), FP on Cellar LEL (calibrate) finish last test @0330. Multiple testing equipment leaks on test # 2 and 3(all addressed). Tested with 3.5" and 5" test joints. Test #2 CMV6 Failed, greased ,retest, Pass. No other issues Test Results TEST DATA Rig Rep:Tony MoralesOperator:ConocoPhillips Alaska, Inc.Operator Rep:Mark Adams Rig Owner/Rig No.:Nabors 7ES PTD#:1960720 DATE:11/7/2023 Type Operation:WRKOV Annular: 250/3500Type Test:INIT Valves: 250/4000 Rams: 250/4000 Test Pressures:Inspection No:bopSTS231109115251 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 9 MASP: 3166 Sundry No: 323-289 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 16 FPNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8 P #1 Rams 1 31/2 x 5 1/2 P #2 Rams 1 blinds P #3 Rams 1 3 1/2 x 5 1/2 P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8 P HCR Valves 2 3 1/8 P Kill Line Valves 2 3 1/8 , 2 P Check Valve 0 NA BOP Misc 2 2 1/16 gate P System Pressure P2950 Pressure After Closure P1550 200 PSI Attained P20 Full Pressure Attained P111 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P5@2050 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P FPMeth Gas Detector P FPH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P26 #1 Rams P5 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9999 9 9 9 9 9FP FP FP FP on Cellar LEL Test #2 CMV6 Failed, ,Pits FP Meth and LEL 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Replace Tubing Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 16340'feet 15205'feet true vertical 6229' feet none feet Effective Depth measured 16217'feet 15189'feet true vertical 16215' feet 6052'feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth) 3-1/2" 3-1/2" L-80 L-80 15074' 15494' 6018' 6122' Packers and SSSV (type, measured and true vertical depth)15189' 6052'' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: Kuparuk 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: Contact Name: Contact Email: Contact Phone: Burst CollapseCasing 2789' 6228' 4874' 16331' 15129' 5-1/2" 15166' 6046' 121'Conductor Surface 16"80' Production Tie-Back String 4833' 16293' measured TVD 9-5/8" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 196-072 50-029-20240-00-00 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: ADL0025586, ADL0025590, ADL0025585 Kuparuk River Field/ Kuparuk Oil Pool KRU 2M-33 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf MDSize 121' Well Shut-In 323-289 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl N/A PACKER: Baker SAB-3 SSSV: None Sydney Long sydney.long@conocophillips.com (907) 265-6312 15580-16235' 6137-6217' Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name and Digital Signature with Date: Authorized Title: Senior RWO/CTD Engineer By Grace Christianson at 9:52 am, Dec 13, 2023 Page 1/9 2M-33 Report Printed: 12/7/2023 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) 11/4/2023 06:00 11/4/2023 15:30 9.50 MIRU, MOVE RURD P Rig down rig equipment and prep to move camp and shop // Prep rig for transport to 2M pad // Vac water from pits and fresh water from pits, move pits away from rig stage on pad, install jeep on pits, move rig out of the way so pits can move by, prep shop and satilite camp for transpor t 0.0 0.0 11/4/2023 15:30 11/4/2023 20:30 5.00 MIRU, MOVE MOB P Transport pits, office complex, and shop to 2M pad. Spot on location. Crew returned to 1Y pad to start sub base move. Prep to move sub base off location. 0.0 11/4/2023 20:30 11/5/2023 00:00 3.50 MIRU, MOVE MOB P Moving Sub base to 2M-33. 11/5/2023 00:00 11/5/2023 05:00 5.00 MIRU, MOVE MOB P Continue moving to 2M pad at CPF2 at 5AM. 0.0 0.0 11/5/2023 05:00 11/5/2023 06:30 1.50 MIRU, MOVE WAIT P Wait for Operator crew changeout. 0.0 0.0 11/5/2023 06:30 11/5/2023 08:30 2.00 MIRU, MOVE MOB P Continue moving to 2M pad from CPF-2. 0.0 0.0 11/5/2023 08:30 11/5/2023 10:30 2.00 MIRU, MOVE MOB P Rig on pad @ 09:00, prep well for spotting rig over, pull out herculite 0.0 0.0 11/5/2023 10:30 11/5/2023 16:00 5.50 MIRU, MOVE RURD P Spot rig over 2M-33 and back pits up to rig. Place piit liner under sub. 0.0 0.0 11/5/2023 16:00 11/6/2023 00:00 8.00 MIRU, MOVE RURD P Safe out rig. Finish berming in rig. Connect inter-connect. Raise derrick, Raise cattle chute. Bridal down derrick. complete pre acceptance checklist. 0.0 0.0 11/6/2023 00:00 11/6/2023 02:30 2.50 MIRU, MOVE RURD P R/U derrick and R/D down bridle lines. Run pit rinse load through all pits. Start loading pits. Hardline to kill tank complete 0.0 0.0 11/6/2023 02:30 11/6/2023 03:30 1.00 MIRU, MOVE SFTY P Hold Pre-spud meeting with crew for plan forward. 0.0 0.0 11/6/2023 03:30 11/6/2023 09:00 5.50 MIRU, MOVE RURD P Transfer fresh water to pits 3 and pill pit. Continue rigging up floor to circulate and pull tubing. Rig up to circulate in the cellar to the kill tank pumping down the tubing taking returns up the IA. confirm lines to kill tank are not obstructed. Blow air through lines, 0.0 0.0 11/6/2023 09:00 11/6/2023 11:00 2.00 MIRU, WELCTL DISP P Pressure test tiger tank lines to 2500 psi. Circulate well to 9.8# brine. 6 bbls/min @ 1750 psi. 5200 stks 6 bbls/min @ 1900 psi 7200stks 6 bbls/min @ 1930 psi. 9200stks 6 bbls/min @ 2188 psi. 9.8 ppg brine back @ 9800 stks continue to pump 10,000 stks clean 9.8# brine back at tiger tank 0.0 0.0 11/6/2023 11:00 11/6/2023 11:30 0.50 MIRU, WELCTL OWFF P OWFF in cellar. No flow observed 0.0 0.0 11/6/2023 11:30 11/6/2023 12:15 0.75 MIRU, WELCTL MPSP P Install ISA BPV. Chart tested to1000psi for 10 min. 0.0 0.0 11/6/2023 12:15 11/6/2023 17:30 5.25 MIRU, WHDBOP NUND P Nipple down and hang production tree in cellar. Install overshot blanking plug. Install 7" x 13" DSA spool on tubing head. Function LDS ensure proper function. Pull RKB for ULDS @ 26.08'. Nipple up BOP's 0.0 11/6/2023 17:30 11/6/2023 18:00 0.50 MIRU, WHDBOP NUND P Service BOP test equipment. Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 2/9 2M-33 Report Printed: 12/7/2023 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) 11/6/2023 18:00 11/6/2023 20:30 2.50 MIRU, WHDBOP RURD P Pick up and M/U BOP test tools and equipment. Dummy run donut joints and mark joints. Flood stack, purge air out of system. perform shell test. 11/6/2023 20:30 11/7/2023 00:00 3.50 MIRU, WHDBOP BOPE P Start testing BOPE. Initial BOPE test, Tested BOPE at 250/4000 PSI for 5 Min each, Tested annular on 3-1/2" test joint, UVBR's, LVBR's w/3-1/2" and 5 1/2" test joint. Test blinds rams. Choke valves #1 to #16, upper IBOP and lower top drive well control valves. Test 3 1/2" HT-38 safety valve, FOSV, and IBOP. Tested 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. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure=XXXX PSI, after closure=1500 PSI, 200 PSI attained =XX sec, full recovery attained = XXX sec. UVBR's= 5 sec, Annular= 30 sec. Simulated blinds= 5 sec. LVBRs=6 sec. HCR choke & kill= 1 sec each. 5 back up nitrogen bottles average = XXXX PSI. Test gas detectors, PVT and flow show. Test witnessed by AOGCC rep Sean Sullivan. 11/7/2023 00:00 11/7/2023 03:30 3.50 MIRU, WHDBOP BOPE P Start testing BOPE. Initial BOPE test, Tested annular on 3- 1/2" test joint to 3500PSI. Tested BOPE at 250/4000 PSI for 5 Min each, UVBR's, LVBR's w/3-1/2" and 5 1/2" test joint. Test blinds rams. Choke valves #1 to #16, upper IBOP and lower top drive well control valves. Test 3 1/2" HT-38 safety valve, FOSV, and IBOP. Tested 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. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure=2950 PSI, after closure=1550 PSI, 200 PSI attained =20 sec, full recovery attained = 111 sec. UVBR's= 5 sec, Annular= 26 sec. Simulated blinds= 6 sec. LVBRs=6 sec. HCR choke & kill= 1 sec each. 5 back up nitrogen bottles average = 2050 PSI. Test gas detectors, PVT and flow show. Test witnessed by AOGCC rep Sean Sullivan. 0.0 0.0 11/7/2023 03:30 11/7/2023 04:45 1.25 MIRU, WHDBOP RURD P R/D Bop testing equipment. Evacuate water out of BOP stack. L/D test joints and X-O's. Configure safety valve for 3- 1/2" EUE threads. R/U to pull tubing. P/U blanking plug R&R tool on 3-1/2" EUE 8rd test joint. Pull blanking plug. L/D Blanking plug R&R test joint and blanking plug. 0.0 0.0 11/7/2023 04:45 11/7/2023 05:15 0.50 COMPZN, RPCOMP RURD P Rig up floor to pull tubing. 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 3/9 2M-33 Report Printed: 12/7/2023 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) 11/7/2023 05:15 11/7/2023 06:15 1.00 COMPZN, RPCOMP MPSP P PU T-bar and BPV setting tool, verify 0 PSI under plug. C/O setting tool with pulling tool. Pull BPV 0.0 0.0 11/7/2023 06:15 11/7/2023 08:00 1.75 COMPZN, RPCOMP OTHR P Rig up bleed trailer and monitor OA. Initial pressure 200 psi bled down to 20 psi and continued to bleed. Close OA while pulling hanger to floor. 0.0 0.0 11/7/2023 08:00 11/7/2023 08:15 0.25 COMPZN, RPCOMP PULL P PU 3-1/2" EUE landing joint M/U to tubing hanger, set down 10K on joint. B.O.L.D.S. 0.0 0.0 11/7/2023 08:15 11/7/2023 08:45 0.50 COMPZN, RPCOMP THGR P Pull hanger off seat 110K Pick up wt ratty pick up max up wt 130K. Pull hanger to floor for circulation. Free up Wt. 110K, Weight erratic while picking up. 0.0 15,160.0 11/7/2023 08:45 11/7/2023 19:45 11.00 COMPZN, RPCOMP CIRC P Continue to circulate well while processing 370 jts 5.5" 15.5# Hydril 563 casing. PR= 3 bbls/min @ 380 psi Simultaneously fingerprinting OA Initial bleed OA Intitial=200 PSI Bled to 0 PSI Time bled = 2 hours. Volume gained=1" in bleed trailer. Shut in for 1 hour 2nd bleed Starting OA PSI=100 PSI Bled to 0 in 2 hours Shut in for 1 hour 3rd bleed Starting OA PSI=40 PSI Bled to 0 instantly Shut in. OA PSI at 6PM=40PSI OA initial had 200 psi bled to bleed trailer 1" of fluid over 3 hrs, shut in OA for 1 hr pressure build to 100 psi, open to bleed trailer 2 hrs no change in fluid level shut in for 1 hr pressure. 15,160.0 15,160.0 11/7/2023 19:45 11/7/2023 22:00 2.25 COMPZN, RPCOMP CIRC P Continue to circulate well. PR= 3 bbls/min @ 380 psi Continue processing 370 jts 5.5" 15.5# Hydril 563 casing. Completed processing casing. Load 33 Joints of DP in the shed. Simultaneously fingerprint OA 4th bleed Starting OA PSI=60 PSI Bled for 30 minutes Shut in. PSI=0 PSI 5th bleed Starting OA PSI=10 PSI Bled for 30 minutes 15,160.0 15,130.0 11/7/2023 22:00 11/7/2023 22:30 0.50 COMPZN, RPCOMP OWFF P OWFF for 30 minutes. No flow. 15,130.0 15,130.0 11/7/2023 22:30 11/8/2023 00:00 1.50 COMPZN, RPCOMP PULL P Lay down 3-1/2" tubing F/15,130' T/14,500' 15,130.0 14,500.0 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 4/9 2M-33 Report Printed: 12/7/2023 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) 11/8/2023 00:00 11/8/2023 03:00 3.00 COMPZN, RPCOMP PULL P Lay down 3-1/2" tubing F/14,500' T/11,340'. Continue to monitor and bleed OA: 0130, bled OA 5PSI, no fluid gas. Would not bleed to 0 PSI open for 30 minutes. 0230 Bled OA. 5PSI, no fluid gas. Would not bleed to 0 PSI open for 30 minutes. 15,130.0 14,500.0 11/8/2023 03:00 11/8/2023 03:30 0.50 COMPZN, RPCOMP RURD P Move BHA components to rig floor. Change elevators. Prep to run DP. 14,500.0 11,389.0 11/8/2023 03:30 11/8/2023 04:30 1.00 COMPZN, RPCOMP BHAH P MU BHA 11,398.0 11,450.0 11/8/2023 04:30 11/8/2023 06:30 2.00 COMPZN, RPCOMP PULD P RIH with BHA F/Surface T/1000' drift 7" casing to 5.75" Continue to monitor OA pressures: 0600 OA pressure 20 psi 11,450.0 12,225.0 11/8/2023 06:30 11/8/2023 07:00 0.50 COMPZN, RPCOMP TRIP P TOOH F/1000' T/Surface 12,225.0 11,225.0 11/8/2023 07:00 11/8/2023 08:00 1.00 COMPZN, RPCOMP BHAH P LD BHA #1 11,225.0 11/8/2023 08:00 11/8/2023 08:30 0.50 COMPZN, RPCOMP RURD P RD DP handling eq. RU tubing handling eq. 11/8/2023 08:30 11/8/2023 16:30 8.00 COMPZN, RPCOMP PULL P Lay down 3-1/2" Tubing F/ 11,340' T/3,300' Continue to monitor and bleed OA: 08:30 pressure was 25psi Bleed off pressure to bleed trailer, pressure instantly bled to 0 psi Closed in with no pressure increase will continue to monitor pressure 10:30 Pressure 25 psi Bleed off pressure to bleed trailer, pressure instantly bled to 0 psi, Closed in with now pressure increas will continue to monitor pressure pressure build to 10 psi Open and bleed to trailer for 30 min minimal diesel returns to bleed trailer Close valve after 30 min 5 psi on gauge , continue to monitor OA no dicernable volume increase in bleed trailer 14:00 OA pressure 22 psi Open OA to bleed trailer, pressure instantly bled to 0 psi Continue to bleed for 30min diesel and gas returns Close after 30 min pressure under 5 psi no discernable returns in bleed trailer 11,225.0 0.0 11/8/2023 16:30 11/8/2023 17:00 0.50 COMPZN, RPCOMP SVRG P Service rig // Grease tongs and TD 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 5/9 2M-33 Report Printed: 12/7/2023 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) 11/8/2023 17:00 11/8/2023 18:00 1.00 COMPZN, RPCOMP RURD P R/D floor from pulling tubing. Prep to RU E-Line. Continue to monitor and bleed OA: 16:00 OA=20 psi Open up and bleed pressure, pressure instantly bled to 0 psi 1/4 of 5 gal bucket of fluid over 30 min ( no flow after 5 min ) some gas returns Close in 5 psi increase continue to monitor OA 0.0 0.0 11/8/2023 18:00 11/8/2023 18:30 0.50 COMPZN, RPCOMP SFTY P PJSM Scope hazards and mitigations with Yellow jacket crew and Nabors. 0.0 0.0 11/8/2023 18:30 11/8/2023 20:00 1.50 COMPZN, RPCOMP ELNE P RU Yellow jacket E-line 0.0 0.0 11/8/2023 20:00 11/9/2023 00:00 4.00 COMPZN, RPCOMP ELNE P RIH W/CBL to 5000' Log back to surface. Swap tools PU 40 arm caliper. RIH to 5000' Start logging up. 0.0 11/9/2023 00:00 11/9/2023 02:15 2.25 COMPZN, RPCOMP ELNE P Started logging up from 5000' caliper failed to open or was fouled with debris. POOH to surface inspect tools. Caliper functioned good RIH to 5000' opened caliper arms appeared fouled. PUH 1000' to 4000' arms still fouled, PUH to 3000' arms still fouled, PUH to 2500' Arms still appeared fouled. Logged with compromised arms to 2000'. Phase 3 called at 200 A.M. POOH with E-Line. 0.0 11/9/2023 02:15 11/9/2023 02:45 0.50 COMPZN, RPCOMP ELNE T RD E-Line unit. 11/9/2023 02:45 11/10/2023 00:00 21.25 COMPZN, RPCOMP WAIT T Phase 3. Lay down 1/2 of the crew. 1/2 crew dry watch rig. rotate every 6 hours. 11/10/2023 00:00 11/11/2023 00:00 24.00 COMPZN, RPCOMP WAIT T Phase 3. Lay down 1/2 of the crew. 1/2 crew dry watch rig. rotate every 6 hours. 11/11/2023 00:00 11/11/2023 04:30 4.50 COMPZN, RPCOMP WAIT T Phase 3. Lay down 1/2 of the crew. 1/2 crew dry watch rig. rotate every 6 hours. 11/11/2023 04:30 11/11/2023 05:30 1.00 COMPZN, RPCOMP WAIT T Start cleaning up location around rig and locate buried equipment and tools. IMT requested slow start to operations. 11/11/2023 05:30 11/11/2023 06:00 0.50 COMPZN, RPCOMP SFTY P Pre-tour meeting with incoming crew. Discussed the operations and plan forward. Hazards and mitigations. 11/11/2023 06:00 11/11/2023 07:00 1.00 COMPZN, RPCOMP RURD P Load 4-3/4" collars in pipe shed. strap and tally collars. RD E-line clear floor and derrick of ice from weather conditions. Clear drifts and snow from walk ways and doors. 11/11/2023 07:00 11/11/2023 07:30 0.50 COMPZN, RPCOMP SVRG P Service top drive blocks and crown. 11/11/2023 07:30 11/11/2023 10:00 2.50 COMPZN, RPCOMP BHAH P MU 6.125" Rigid BHA 0.0 198.5 11/11/2023 10:00 11/11/2023 12:45 2.75 COMPZN, RPCOMP PULD P Single in well F/198.54 T/1792.25 198.5 1,792.3 11/11/2023 12:45 11/11/2023 13:30 0.75 COMPZN, RPCOMP TRIP P TIH F/1792.25' T/2792.25 1,792.3 2,792.3 11/11/2023 13:30 11/11/2023 14:15 0.75 COMPZN, RPCOMP CIRC P Circulate at 2800' Monitor OA. Perform active bleed. Returned .5 gallons diesel in 30 minutes. Swapped to gas. 2,792.3 2,792.3 11/11/2023 14:15 11/11/2023 14:45 0.50 COMPZN, RPCOMP OWFF P OWFF for 30 minutes. Simultaneously monitor OA. OA=0 PSI no flow. 2,792.3 2,792.3 11/11/2023 14:45 11/11/2023 16:15 1.50 COMPZN, RPCOMP TRIP P TOOH F/2792.3 T/198.5 2,792.3 198.5 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 6/9 2M-33 Report Printed: 12/7/2023 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) 11/11/2023 16:15 11/11/2023 17:00 0.75 COMPZN, RPCOMP BHAH P L/D BHA 198.5 0.0 11/11/2023 17:00 11/11/2023 17:30 0.50 COMPZN, RPCOMP SVRG P Service RIG 0.0 0.0 11/11/2023 17:30 11/11/2023 18:00 0.50 COMPZN, RPCOMP BHAH P PJSM, Check well, P/U G-plug - S/N 13728217 OAL=22.91' COE=14.66' 0.0 23.0 11/11/2023 18:00 11/11/2023 18:00 COMPZN, RPCOMP TRIP P TIH, on stands Stand 26 and a single 23.0 2,515.0 11/11/2023 18:00 11/11/2023 20:00 2.00 COMPZN, RPCOMP MPSP P Set G-plug PUW=61k SOW=58k 2,515.0 2,515.0 11/11/2023 20:00 11/11/2023 20:30 0.50 COMPZN, RPCOMP MPSP P Plug released, PUH 5', line up and brake circulation 2,515.0 2,510.0 11/11/2023 20:30 11/11/2023 20:45 0.25 COMPZN, RPCOMP MPSP P Test & Chart G-plug 10 mins - Good test 2,510.0 2,510.0 11/11/2023 20:45 11/11/2023 21:00 0.25 COMPZN, RPCOMP TRIP P Crew Changeout Bleed off pressure, blow down top drive TOOH on stands 2,510.0 14.6 11/11/2023 21:00 11/11/2023 22:30 1.50 COMPZN, RPCOMP BHAH P OOH, L/D setting tools 14.6 0.0 11/11/2023 22:30 11/11/2023 23:00 0.50 COMPZN, RPCOMP Test and chart G-plug to 2,500 psi 0.0 0.0 11/11/2023 23:00 11/12/2023 00:00 1.00 COMPZN, RPCOMP NUND P Blow down surface lines, line up to suckout stack Observe No-flow 30 mins 0.0 0.0 11/12/2023 00:00 11/12/2023 01:30 1.50 COMPZN, RPCOMP NUND P Suck out stack, N/D BOP Stack and secure back on pedestal, remove DSA 0.0 0.0 11/12/2023 01:30 11/12/2023 04:45 3.25 COMPZN, RPCOMP CUTP P R/U Hydratight. Grow casing, 16 3/4" total growth observed. 183,600 lbs/force 0.0 0.0 11/12/2023 04:45 11/12/2023 05:15 0.50 COMPZN, RPCOMP CUTP P R/D Hydratight equipment Remove tubing head 0.0 0.0 11/12/2023 05:15 11/12/2023 10:00 4.75 COMPZN, RPCOMP WWSP P P/U Spear, spear 7" casing, pull to160k on weight indicator. Set casing slips and slacked off. Removed spear. Set primary intermediate casing packoff. Cut off casing from stretch 4.74' over all cut off. Installed 11" 3K x 11"5K casing spool with secondary reducer bushing. Torqued connection. Tested 7" casing packoff void to 3000 PSI for 10 minutes. 0.0 0.0 11/12/2023 10:00 11/12/2023 11:30 1.50 COMPZN, RPCOMP RURD P LD spear and empty collars out of pipe shed. Prep to NU BOP's. NU DSA. Installed test plug in wellhead. 0.0 0.0 11/12/2023 11:30 11/12/2023 12:00 0.50 COMPZN, RPCOMP SVRG P Service bridge crane in cellar 0.0 0.0 11/12/2023 12:00 11/12/2023 14:00 2.00 COMPZN, RPCOMP NUND P Set stack, Torque DSA to wellhead and stack. install riser 0.0 0.0 11/12/2023 14:00 11/12/2023 15:30 1.50 COMPZN, RPCOMP BOPE P Test BOP to well head flange break to 250/4000 PSI for 5 min, R/D testing equipment, remove test plug, install wear bushing, 0.0 0.0 11/12/2023 15:30 11/12/2023 16:00 0.50 COMPZN, RPCOMP SVRG P Service Rigs Iron Roughnecks 0.0 0.0 11/12/2023 16:00 11/12/2023 17:15 1.25 COMPZN, RPCOMP BHAH P P/U BHA #4 G-plug retrieval tool and XO 0.0 14.6 11/12/2023 17:15 11/12/2023 20:00 2.75 COMPZN, RPCOMP TRIP P TIH, unseat G-plug, circulate BU, check well for flow 14.6 2,515.0 11/12/2023 20:00 11/12/2023 22:00 2.00 COMPZN, RPCOMP TRIP P TOOH w/DP sideways 2,515.0 14.6 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 7/9 2M-33 Report Printed: 12/7/2023 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) 11/12/2023 22:00 11/12/2023 22:30 0.50 COMPZN, RPCOMP BHAH P L/D and inspect G-plug 14.6 0.0 11/12/2023 22:30 11/13/2023 00:00 1.50 COMPZN, RPCOMP PUTB P Prep RF for liner ops, M/U cross overs to floor valves, bring GBR tongs to RF, load remaining 5.5" into pipe shed. 0.0 0.0 11/13/2023 00:00 11/13/2023 01:15 1.25 COMPZN, RPCOMP PUTB P Contiue to thaw/prep 5.5" liner in pipe shed, 0.0 0.0 11/13/2023 01:15 11/13/2023 01:45 0.50 COMPZN, RPCOMP SFTY P PJSM with all involved for picking up pipe 0.0 0.0 11/13/2023 01:45 11/13/2023 20:00 18.25 COMPZN, RPCOMP PUTB P M/U 5.5" tie back liner Start RIH with 5.5" casing F/ surface T/(15,137' 7ES RKB), (15,147' ORKB.) PUW=160K SOW 80K. set down 24K unable to see shear screws engage cut at 15165'. 0.0 15,137.0 11/13/2023 20:00 11/13/2023 21:00 1.00 COMPZN, RPCOMP PUTB T Called town engineers discussed options for plan forward. Decision made to POOH L/D casing. 15,137.0 15,137.0 11/13/2023 21:00 11/13/2023 23:30 2.50 COMPZN, RPCOMP PULL T Start POOH W/15.5# 5.5" Hyd 563 casing PUW=160K F/15,137' T/13,247' 15,137.0 13,247.0 11/13/2023 23:30 11/14/2023 00:00 0.50 COMPZN, RPCOMP SVRG P Perform derrick inspection. Clear ice out of derrick. 13,247.0 13,247.0 11/14/2023 00:00 11/14/2023 11:30 11.50 COMPZN, RPCOMP PULL T Continue POOH W/15.5# 5.5" Hyd 563 casing PUW=153K F/13,247' T/3,800' 13,247.0 3,800.0 11/14/2023 11:30 11/14/2023 12:00 0.50 COMPZN, RPCOMP SVRG P Service rig draw works 3,800.0 3,800.0 11/14/2023 12:00 11/14/2023 17:00 5.00 COMPZN, RPCOMP PULL T Continue POOH W/15.5# 5.5" Hyd 563 casing PUW=70K F/3,800' T/surface. RD GBR tongs. 3,800.0 0.0 11/14/2023 17:00 11/14/2023 21:30 4.50 COMPZN, RPCOMP BHAH T Load 3.5" HT-38 DP in shed, strap and tally 2 rows. Load BHA on top of DP. Prep floor to run BHA. 0.0 0.0 11/14/2023 21:30 11/14/2023 23:00 1.50 COMPZN, RPCOMP BHAH T MU and RIH with CO BHA #6. (6" cut lip, 5-3/4" TSS extension, Tripple connect bushing, 4-3/4" drill collar, 6-1/8" string mill, two string magnets, 4-3/4 bumper sub, 4-3/4" fishing jar, two 4-3/4" drill collars, 4-3/4" intensifier then XO to drillpipe. 0.0 161.0 11/14/2023 23:00 11/15/2023 00:00 1.00 COMPZN, RPCOMP PULD T RIH on DP singles from 161' to 1,900' PUW=41K 161.0 1,900.0 11/15/2023 00:00 11/15/2023 02:30 2.50 COMPZN, RPCOMP TRIP T RIH on DP singles from 1,900' to 2,817' PUW= 61K / SOW=55 1,900.0 2,817.0 11/15/2023 02:30 11/15/2023 04:30 2.00 COMPZN, RPCOMP PULD T Load 92 jts of 3.5" HT-38 DP in pipe shed, strap and tally. 2,817.0 2,817.0 11/15/2023 04:30 11/15/2023 07:00 2.50 COMPZN, RPCOMP TRIP T RIH on DP singles from 2,817' to 5978' PUW= 76K / SOW=65 2,817.0 5,978.0 11/15/2023 07:00 11/15/2023 09:00 2.00 COMPZN, RPCOMP PULD T Load 92 jts of 3.5" HT-38 DP in pipe shed, strap and tally. 5,978.0 5,978.0 11/15/2023 09:00 11/15/2023 11:30 2.50 COMPZN, RPCOMP TRIP T RIH on DP singles from 5,978' to 8,879' PUW= 105K / SOW=74 5,978.0 8,879.0 11/15/2023 11:30 11/15/2023 12:00 0.50 COMPZN, RPCOMP SVRG P Service Rig 8,879.0 8,879.0 11/15/2023 12:00 11/15/2023 13:30 1.50 COMPZN, RPCOMP PULD T Load 92 jts of 3.5" HT-38 DP in pipe shed, strap and tally. 8,879.0 8,879.0 11/15/2023 13:30 11/15/2023 16:00 2.50 COMPZN, RPCOMP TRIP T RIH on DP singles from 8,879' to 11,780' PUW= 130K / SOW=80 8,879.0 11,780.0 11/15/2023 16:00 11/15/2023 18:30 2.50 COMPZN, RPCOMP PULD T Load 92 jts of 3.5" HT-38 DP in pipe shed, strap and tally. 11,780.0 11,780.0 11/15/2023 18:30 11/15/2023 21:00 2.50 COMPZN, RPCOMP TRIP T RIH on DP singles from 11,780' to 14,675' PUW= 134K / SOW=93 11,780.0 14,675.0 11/15/2023 21:00 11/15/2023 22:00 1.00 COMPZN, RPCOMP PULD T Load 3.5" HT-38 DP in pipe shed, strap and tally. 14,675.0 14,675.0 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 8/9 2M-33 Report Printed: 12/7/2023 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) 11/15/2023 22:00 11/15/2023 22:30 0.50 COMPZN, RPCOMP TRIP T RIH on DP singles from 14,675' to 15,123' PUW= 158K / SOW=92 14,675.0 15,123.0 11/15/2023 22:30 11/15/2023 23:30 1.00 COMPZN, RPCOMP MILL T Kelly up, Rotate at 58 rpm, circ at 190 GPM. Tag tubing stump at 15,130. Circulate over stump down to 15,136'. Mill tubing stump down to 15,140' with 14K WOB. Note: With 5.85' of swallow the top of tubing was left at 15,134.15'. 15,123.0 15,140.0 11/15/2023 23:30 11/16/2023 00:00 0.50 COMPZN, RPCOMP BKRM T Ream up and down with string reamer 3 times to cleam up packer setting area. 15,140.0 15,140.0 11/16/2023 00:00 11/16/2023 03:00 3.00 COMPZN, RPCOMP CIRC T Circulate two high vis sweeps to clean up hole at 8 BPM. 15,140.0 15,140.0 11/16/2023 03:00 11/16/2023 06:00 3.00 COMPZN, RPCOMP PULD T POOH from 15,140' to 11,650'. PUW 168K. 15,140.0 11,650.0 11/16/2023 06:00 11/16/2023 07:30 1.50 COMPZN, RPCOMP SVRG P Slip and cut drill line 11,650.0 11,650.0 11/16/2023 07:30 11/16/2023 08:00 0.50 COMPZN, RPCOMP SVRG P Service Rig 11,650.0 11,650.0 11/16/2023 08:00 11/16/2023 17:00 9.00 COMPZN, RPCOMP TRIP T TOOH, laying down DP. PUW 135K 11,650.0 161.0 11/16/2023 17:00 11/16/2023 19:00 2.00 COMPZN, RPCOMP BHAH T L/D Cleanout BHA #6 161.0 0.0 11/16/2023 19:00 11/16/2023 21:00 2.00 COMPZN, RPCOMP BHAH T RU GBR casing crew to run casing. 0.0 0.0 11/16/2023 21:00 11/17/2023 00:00 3.00 COMPZN, RPCOMP RUNL T Run 5.5" HYD 563 tie back liner to 2176'. 0.0 2,176.0 11/17/2023 00:00 11/17/2023 05:00 5.00 COMPZN, RPCOMP RUNL T Run 5.5" HYD 563 tie back liner from 2176' to 6587'. 2,176.0 6,587.0 11/17/2023 05:00 11/17/2023 14:00 9.00 COMPZN, RPCOMP RUNL T Continue in hole with 5.5" HYD 563 tie back liner from 6587'-15,105', PU Joint 355 PUW=160 k, SOW=78 k 6,587.0 15,105.0 11/17/2023 14:00 11/17/2023 14:15 0.25 COMPZN, RPCOMP RUNL P PJSM, slowly RIH, slight bobble seen @ 15,137', shear pins @ 15,146', continue IH to no-go @ 15,149'. 15,105.0 15,149.0 11/17/2023 14:15 11/17/2023 15:30 1.25 COMPZN, RPCOMP RUNL P PUH PUW 160 k 15,165', R/U head pin and pump manifold on RF 15,149.0 15,149.0 11/17/2023 15:30 11/17/2023 17:30 2.00 COMPZN, RPCOMP CIRC P Bring pump online 1.5 bpm @ 530 psi. Reverse circulate 135 bbls 9.8# CI. 15,149.0 15,149.0 11/17/2023 17:30 11/17/2023 18:00 0.50 COMPZN, RPCOMP CIRC P RU LRS and pump 20 bbls of diesel down IA at 1BPM and 500 psi down OA. 15,149.0 15,149.0 11/17/2023 18:00 11/17/2023 21:00 3.00 COMPZN, RPCOMP PACK P Run casing in hole over tubing stub, PU to neutral weight and set packer by pressuring up to 3700 psi. Hold pressure and chart inside 5.5" casing pressure 3500 psi for 30 minutes. pressure test and chart back side of packer 5.5" x 7" to 1000 psi for 30 minutes. 15,146.0 15,146.0 11/17/2023 21:00 11/17/2023 23:30 2.50 COMPZN, RPCOMP MPSP P MU, RIH and set 5.5" RBP at 91'. PT to 1000 psi for 10 minutes. 15,146.0 15,146.0 11/17/2023 23:30 11/18/2023 00:00 0.50 COMPZN, RPCOMP SVRG P Service rig. 15,146.0 15,146.0 11/18/2023 00:00 11/18/2023 06:00 6.00 COMPZN, RPCOMP WWSP P Pull 5.5" casing in tension, splt the stack, set the casing in emergrncy slips and cut off excess casing. Simultaneously load tally and drift 487 jts of 3.5" tubing. 0.0 0.0 11/18/2023 06:00 11/18/2023 08:00 2.00 COMPZN, RPCOMP NUND P Instal and torque tubing spool Simultaneously load tally and drift 487 jts of 3.5" tubing. 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Page 9/9 2M-33 Report Printed: 12/7/2023 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) 11/18/2023 08:00 11/18/2023 12:00 4.00 COMPZN, RPCOMP NUND P N/U BOPE 0.0 0.0 11/18/2023 12:00 11/18/2023 13:00 1.00 COMPZN, RPCOMP BOPE P P/T & Chart BOPE 250/4000 psi 0.0 0.0 11/18/2023 13:00 11/18/2023 13:30 0.50 COMPZN, RPCOMP PULL P Pull test plug 0.0 0.0 11/18/2023 13:30 11/18/2023 13:45 0.25 COMPZN, RPCOMP SFTY P PJSM, w/crew, R/U to pull IBP 0.0 91.0 11/18/2023 13:45 11/18/2023 15:00 1.25 COMPZN, RPCOMP PULL P Pull RBP, confirm no pressure, TOOH, LD & inspect plug 91.0 0.0 11/18/2023 15:00 11/18/2023 23:30 8.50 COMPZN, RPCOMP PUTB P Continue to process 3.5" 9.3# L-80 tubing in pipeshed 0.0 0.0 11/18/2023 23:30 11/19/2023 00:00 0.50 COMPZN, RPCOMP SVRG P Service rig. 0.0 0.0 11/19/2023 00:00 11/19/2023 01:30 1.50 COMPZN, RPCOMP PUTB P Finish organizing completion in pipeshed 0.0 0.0 11/19/2023 01:30 11/19/2023 06:00 4.50 COMPZN, RPCOMP PUTB P MU and run 3.5", 93#, L-80 EUE 8rd tubing 0.0 2,503.0 11/19/2023 06:00 11/19/2023 23:30 17.50 COMPZN, RPCOMP PUTB P Contiinue TIH w/3.5", 93#, L-80 EUE 8rd tubing. Tagged top of the PBR at 15,043'. Pumping slowly saw pressure come up when seal entered the PBR. Fully located then spaced out 4'. 2,503.0 15,056.0 11/19/2023 23:30 11/20/2023 00:00 0.50 COMPZN, RPCOMP SVRG P Service rig 0.0 0.0 11/20/2023 00:00 11/20/2023 05:30 5.50 COMPZN, RPCOMP PRTS P Pressure test the tubing to 3000 psi for 30 minutes P/T & chart IA 2,500 psi for 30 mins while keeping 1,000 psi on tubing 0.0 0.0 11/20/2023 05:30 11/20/2023 06:00 0.50 COMPZN, RPCOMP SVRG P Rig service 0.0 0.0 11/20/2023 06:00 11/20/2023 06:15 0.25 COMPZN, RPCOMP PRTS P Dump pressure on tubing to shear SOV R/D testing equipment 0.0 0.0 11/20/2023 06:15 11/20/2023 06:30 0.25 COMPZN, WHDBOP RURD P Back out Landing joint 0.0 0.0 11/20/2023 06:30 11/20/2023 07:30 1.00 COMPZN, WHDBOP RURD P Flush/Suck out stack 0.0 0.0 11/20/2023 07:30 11/20/2023 08:30 1.00 COMPZN, WHDBOP PRTS P Install BPV, line up and test BPV from below to 1,000 psi (good test) 0.0 0.0 11/20/2023 08:30 11/20/2023 11:30 3.00 COMPZN, WHDBOP NUND P N/D BOPE, N/U tubing head adapter, 0.0 0.0 11/20/2023 11:30 11/20/2023 14:30 3.00 COMPZN, WHDBOP NUND P N/U & P/T 3-1/8" 5k wellhead to 5k (good test) 0.0 0.0 11/20/2023 14:30 11/20/2023 15:00 0.50 COMPZN, WHDBOP PULL P Pull BPV 0.0 0.0 11/20/2023 15:00 11/20/2023 17:00 2.00 COMPZN, WHDBOP FRZP P Free protect well w/50 bbls diesel to 2,359'. 0.0 0.0 11/20/2023 17:00 11/20/2023 17:30 0.50 COMPZN, WHDBOP RURD P R/D LRS and secure well 0.0 0.0 11/20/2023 17:30 11/20/2023 21:30 4.00 DEMOB, MOVE DMOB P RDMO from well 0.0 0.0 11/20/2023 21:30 11/21/2023 00:00 2.50 DEMOB, MOVE DMOB P Trucks on location, PJSM Pull service module away from rig Remove snow from well 15 Release rig at midnight. 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 11/20/2023 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: Hard TAG - RKB 16,217.0 2M-33 9/28/2017 pproven Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Post rig Added Mangrel inserts 2M-33 12/6/2023 fergusp Notes: General & Safety Annotation End Date Last Mod By NOTE: Production casing leak foung @ 9906' RKB 9/9/2020 fergusp 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 41.0 121.0 121.0 62.58 H-40 WELDED SURFACE 9 5/8 8.83 40.5 4,873.6 2,788.9 40.00 L-80 BTC PRODUCTION 7 6.28 38.3 16,330.7 6,227.8 26.00 L-80 BTC-MOD Tie-Back String 5 1/2 4.89 38.6 15,166.0 6,045.5 17.00 L-80 Hyd 563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 0.0 Set Depth 15,074.0 String Max No 3 1/2 Set Depth 6,018.1 Tubing Description Tubing - Production Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE 8rd 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) 36.7 36.7 0.03 Hanger 6.980 3-1/2" EUE FMC Gen 5 tubing hanger FMC Gen 5 2.992 4,170.6 2,570.2 72.06 Mandrel 4.757 3 1/2" x 1" KBG 2-9 GLM #1 SN#23941-08 KBG SLB 2.818 10,013.6 4,375.9 72.26 Mandrel 4.757 3 1/2" x 1" KBG 2-9 GLM #2 SN#23941-05 KBG SLB 2.818 13,581.5 5,533.7 71.47 Mandrel 4.757 3 1/2" x 1" KBG 2-9 GLM #3 SN#23941-06 KBG SLB 2.818 14,976.9 5,988.1 71.63 Mandrel - valve 4.757 3 1/2" x 1" KBG 2-9 w/SOV BEK Latch 4130, GLM #4 SN#23941-04 KBG SLB 2.818 15,034.0 6,005.8 72.05 Nipple 4.190 3 1/2" X-nipple with 2.813" profile SN#4890017-05 HES HES 2.813 15,055.2 6,012.4 72.21 Locator 4.500 Locator 3.000 15,070.9 6,017.1 72.33 Seal Assembly 3.980 80-40 GBH-22 LTSA, 3-1/2" EUE mod Box x 1/2 Mule shoe w/Seals Baker Baker 2.990 Top (ftKB) 15,162.0 Set Depth 15,493.7 String Max No 3 1/2 Set Depth 6,123.5 Tubing Description Tubing Production Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdMOD ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 15,180.8 6,049.8 73.14 NIPPLE 4.540 CAMCO W NIPPLE w/NO GO PROFILE CAMCO W 2.812 15,188.8 6,052.1 73.22 PACKER 6.150 BAKER SAB-3 PACKER w/K22 ANCHOR SEAL ASSEMBLY BAKER SAB-3 3.000 15,205.8 6,057.0 73.50 NIPPLE 4.540 D NIPPLE w/NO GO PROFILE CAMCO D 2.750 15,493.0 6,123.4 80.16 WLEG 4.500 WIRELINE RE-ENTRY GUIDE BAKER 3.000 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) 9,906.0 4,343.4 72.61 Production casing leak Found 7" production casing leak with Archer acoustic tool. 9/9/2020 6.260 15,162.0 6,044.3 73.00 CUT 2.375" WELLTEC MECHANICAL TUBING CUT AT 15,162' RKB 6/28/2023 2.992 15,205.0 6,056.7 73.49 TUBING PLUG 2.75" CA-2 Plug (30" OAL) 6/17/2023 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) 4,170.6 2,570.2 72.06 1 GAS LIFT DMY BTM 1 0.0 11/18/2023 0.000 10,013.6 4,375.9 72.26 2 GAS LIFT DMY BTM 1 0.0 11/18/2023 0.000 13,581.5 5,533.7 71.47 3 GAS LIFT DMY BTM 1 0.0 11/18/2023 0.000 14,976.9 5,988.1 71.63 4 GAS LIFT SOV BTM 1 0.0 11/18/2023 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 15,059.4 6,013.6 72.24 SBR 4.500 Seal Bore Receptacle 80-40 x 20' w/5" H521 P x 4.5" H521 B Baker 80-40 SBR 3.990 15,090.8 6,023.2 72.47 Nipple - X 4.500 2.813" X-Nipple S# 004890017-02 HES X Nipple 2.813 15,111.5 6,029.4 72.63 Packer 5.959 SLB BluPack 3.5" by 7" SN# C23P-0278 SLB BluePack 2.885 15,137.6 6,037.1 72.82 Nipple - X 4.478 2.81" X-Nipple W/DFCV installed S# 0004680681-7 HES X Nipple 2.813 15,159.1 6,043.4 72.98 Overshot 4.500 3.5" Poor-Boy Overshot Baker Poorboy Overshot 3.980 2M-33, 12/7/2023 12:03:14 PM Vertical schematic (actual) PRODUCTION; 38.3-16,330.7 IPERF; 16,194.0-16,235.0 IPERF; 15,760.0-16,160.0 Hydraulic Fracture; 15,580.0 Hydraulic Fracture; 15,580.0 Perf; 15,580.0-16,235.0 Perf; 15,580.0-16,235.0 APERF; 15,805.0-15,835.0 APERF; 15,775.0-15,805.0 APERF; 15,600.0-15,620.0 APERF; 15,580.0-15,600.0 TUBING PLUG; 15,205.0 PACKER; 15,188.8 Tie-Back String; 38.6-15,166.0 CUT; 15,162.0 Tubing; 15,034.9 Nipple; 15,034.0 Tubing; 14,983.7 Mandrel - valve; 14,976.9 Tubing; 14,966.7 Tubing; 13,588.3 Mandrel; 13,581.4 Tubing; 13,571.3 Tubing; 10,020.4 Mandrel; 10,013.6 Tubing; 10,003.5 Production casing leak; 9,906.0 SURFACE; 40.5-4,873.6 Tubing; 4,177.4 Mandrel; 4,170.6 Tubing; 4,160.6 CONDUCTOR; 41.0-121.0 Tubing; 40.2 Hanger; 36.7 KUP PROD KB-Grd (ft) 47.00 RR Date 4/30/1996 Other Elev 2M-33 ... TD Act Btm (ftKB) 16,340.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032024000 Wellbore Status PROD Max Angle & MD Incl (°) 83.45 MD (ftKB) 16,264.24 WELLNAME WELLBORE2M-33 Annotation Last WO: End DateH2S (ppm) 90 Date 12/15/2019 Comment SSSV: NIPPLE Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 15,580.0 16,235.0 6,137.1 6,216.8 C-4, 2M-33 9/6/2017 0.5 15,580.0 16,235.0 6,137.1 6,216.8 C-4, 2M-33 8/27/2017 0.2 15,580.0 15,600.0 6,137.1 6,140.0 C-4, 2M-33 8/13/2010 6.0 APERF Millenium guns, 60° phase 15,600.0 15,620.0 6,140.0 6,142.8 C-4, UNIT B, A- 4, 2M-33 8/12/2010 6.0 APERF Millenium guns, 60° phase 15,760.0 16,160.0 6,160.5 6,208.1 A-3, 2M-33 7/26/1996 4.0 IPERF 4 1/2" TCP; 180° phase 15,775.0 15,805.0 6,162.2 6,165.7 A-3, 2M-33 9/3/2017 6.0 APERF HES TITAN PROSPECTOR GUNS (60° PHASING) 15,805.0 15,835.0 6,165.7 6,169.2 A-3, 2M-33 9/2/2017 6.0 APERF MALLINIUM II GUNS 6 SPF 60° PHASE 2.5"X21.0') (MALLINIUM II GUNS 6 SPF 60° PHASE 2.5"X11.0') OAL= 40.04' 16,194.0 16,235.0 6,212.1 6,216.8 A-3, 2M-33 7/26/1996 4.0 IPERF 4 1/2" TCP;180 deg. phase Stimulation Intervals Top (ftKB) Btm (ftKB) Inter val Num ber Type Subtype Start Date Proppant Designed (lb) Proppant Total (lb) Vol Clean Total (bbl) Vol Slurry Total (bbl) 15,580.0 16,275.0 1 Hydraulic Fracture 8/28/2017 22,566.0 1,665.00 1,689.00 15,580.0 16,275.0 1 Hydraulic Fracture 9/6/2017 100,000.0 20,131.0 935.00 956.00 2M-33, 12/7/2023 12:04:31 PM Vertical schematic (actual) PRODUCTION; 38.3-16,330.7 IPERF; 16,194.0-16,235.0 IPERF; 15,760.0-16,160.0 Hydraulic Fracture; 15,580.0 Hydraulic Fracture; 15,580.0 Perf; 15,580.0-16,235.0 Perf; 15,580.0-16,235.0 APERF; 15,805.0-15,835.0 APERF; 15,775.0-15,805.0 APERF; 15,600.0-15,620.0 APERF; 15,580.0-15,600.0 TUBING PLUG; 15,205.0 PACKER; 15,188.8 Tie-Back String; 38.6-15,166.0 CUT; 15,162.0 Tubing; 15,034.9 Nipple; 15,034.0 Tubing; 14,983.7 Mandrel - valve; 14,976.9 Tubing; 14,966.7 Tubing; 13,588.3 Mandrel; 13,581.4 Tubing; 13,571.3 Tubing; 10,020.4 Mandrel; 10,013.6 Tubing; 10,003.5 Production casing leak; 9,906.0 SURFACE; 40.5-4,873.6 Tubing; 4,177.4 Mandrel; 4,170.6 Tubing; 4,160.6 CONDUCTOR; 41.0-121.0 Tubing; 40.2 Hanger; 36.7 KUP PROD 2M-33 ... WELLNAME WELLBORE2M-33 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? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 16340'N/A 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: 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: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 15580-16235' 16293' 6137-6217'3-1/2" 7" 16" 9-5/8" 80' 4833' Perforation Depth MD (ft): MD 121' 2789' 121' 4874' 6228'16331' Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 6229'16217'16215'3166 15205' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025590 196-072 P.O. Box 100360, Anchorage, AK 99510 50-103-2024-00-00 ConocoPhillips Alaska, Inc. KRU 2M-33 Kuparuk Oil PoolKuparuk Oil PoolKuparuk River Field N/A Tubing Grade:Tubing MD (ft): Packer: 15189'MD/6052'TVD SSSV: None Perforation Depth TVD (ft):Tubing Size: L-80 15494' 7/15/2023 Packer: Baker SAB-3 w/K-22 SSSV: None 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY sydney.long@conocophillips.com (907) 265-6312 Rig Workover Engineer P s 66 t Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Sydney Long By Grace Christianson at 1:50 pm, May 15, 2023 323-289 DSR-5/15/23MDG 06/09/2023 BOP test to 3500 psig Annular preventer to 2500 psig ADL0025586, 20240 X , ADL0025585 X 10-404 VTL 6/27/2023JLC 6/27/2023 06/27/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.27 20:52:40 -05'00' RBDMS JSB 062923 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 11, 2023 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 2M-33 (PTD# 196- 072). 2M-33 was drilled and completed in 1996 as a Kuparuk Producer. The well currently has multiple tubing leaks and a production casing leak. 2M-33 also has high subsidence risk. The well has been shut in since 2020. The existing 3-1/2” tubing will be pulled from a pre-rig cut above the production packer. If the drift of the 7” casing is compromised due to subsidence, it will be cut and pulled. Regardless of the 7” casing being pulled or remaining intact, a 5-1/2” x 3-1/2” liner will be run with two packers. A new 3-1/2” completion will then be run inside the liner. If you have any questions or require any further information, please contact me at 907-265-6321. Sydney Long Rig Workover Engineer CPAI Drilling and Wells 2M-33 Kuparuk Producer RWO Procedure PTD: 196-072 Page 1 of 2 PPre-Rig Work 1. Set plug at 15,206’ RKB 2. DDT-T-IA 3. T-PPPOT and T-POT tests. 4. Cut the tubing at ~15,160’ RKB in the middle of the first full joint above the packer. 5. Prepare well within 48 hrs of rig arrival. Rig Work MIRU 1. MIRU 7ES on 2M-33. No BPV set for MIRU or RDMO due to 7ES internal risk assessment. 2. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete 30-minute NFT. Circulate KWF as needed. Verify well is dead. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/3,500 PSI. Test annular 250/3,500 PSI. Retrieve 3-1/2” Tubing 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 3-1/2” tubing down to the pre-rig cut at ~15,160’ RKB. 6. Perform a cleanout run, based on tubing condition, and dress off 3-1/2” tubing stub - if necessary. Contingency Subsidence Cut and Pull of Production Casing 7. Evaluate 7” casing for subsidence. 8. Cut 7” casing at ~1800’ RKB 9. Pull 7” casing to ~1800’ RKB Install 5-1/2” x 3-1/2” Tieback with Stacked Packer 10. Set 7” plug. PT. ND old tubing spool. Install new tie-back spool. NU BOPEs. Test break. a. Break will be tested to 3,000 psig due to flange rating. 11. Pull 7” plug. 12. PU 5-1/2” x 3-1/2” tieback liner. a. 3-1/2” x 7” packer on bottom, XO to 5-1/2”, 5-1/2” x 7” packer above XO 13. Reverse circulate in CI fluid at opportune time. 14. Set packers. 15. Set 5.5” RBP. PT. ND BOPE. Terminate 5.5” at surface. NU Tubing spool. NU BOPE. Test break. Pull 5.5” RBP. 16. Run in with new tubing, pull sleeve across communication port. 17. PT IA 18. POOH 3-1/2” and RB Install 3-1/2” Completion 19. MU and RIH with 3-1/2” completion with GLM, nipples, and seal assembly. 20. Once on depth, space out as needed. Circulate corrosion inhibited fluid. 21. Engage seals, land tubing hanger, RILDS, PT packoffs. 2M-33 Kuparuk Producer RWO Procedure PTD: 196-072 Page 2 of 2 22. Pressure test tubing to 3,000 PSI for 30 minutes. 23. Pressure test IA to 2,500 PSI for 30 minutes on chart. ND BOP, NU Tree 24. Confirm pressure tests, then shear out SOV with pressure differential. 25. Install BPV and test. ND BOPE. NU tree. 26. Pull BPV and freeze protect well. 27. RDMO. PPost-Rig Work 1. Run GLD 2. Pull any plugs. General Well Information: Estimated Start Date: 7/15/2023. Current Operations: Shut In Well Type: Producer Wellhead Type: FMC GEN IV 5M BOP Configuration: Annular / Pipe Rams / Blind Rams / Pipe Ram Static BHP: 3,778 psi / 6,121’ TVD measured 9/26/2022 MPSP: 3,166 psi using 0.1 psi/ft gradient Scope of Work: Pull the existing 3-1/2” completion to a pre-rig cut directly above the top packer; install 5-1/2”x 3-1/2” tieback and a new 3-1/2” completion. Contingency cut and pull of 7” casing pending subsidence severity. Personnel: Workover Engineer: Sydney Long (265-6321 / Sydney.Long@conocophillips.com) Reservoir Surveillance Engineer: Mandy Pogany Production Engineer: Natalie Dye Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: Hard TAG - RKB 16,217.0 2M-33 9/28/2017 pproven Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pulled Patches, Iso Slv, & Set CA-2 Plug 2M-33 9/26/2022 zembaej Notes: General & Safety Annotation End Date Last Mod By NOTE: Production casing leak foung @ 9906' RKB 9/9/2020 fergusp Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 41.0 Set Depth (ft… 121.0 Set Depth … 121.0 Wt/Len (lb/ft) 62.58 Grade H-40 Top Connection WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 40.5 Set Depth (ft… 4,873.6 Set Depth … 2,788.9 Wt/Len (lb/ft) 40.00 Grade L-80 Top Connection BTC Casing Description PRODUCTION OD (in) 7 ID (in) 6.28 Top (ftKB) 38.3 Set Depth (ft… 16,330.7 Set Depth … 6,227.8 Wt/Len (lb/ft) 26.00 Grade L-80 Top Connection BTC-MOD Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 36.0 Set Depth … 6,123.5 String Ma… 3 1/2 Tubing Description TUBING Set Depth (ftKB) 15,493.7 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdMOD ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 36.0 36.0 0.03 HANGER 8.000 FMC GEN IV TUBING HANGER 3.500 484.3 483.6 7.74 NIPPLE 4.540 CAMCO DS NIPPLE w/NO GO PROFILE CAMCO DS 2.812 4,995.6 2,828.0 70.86 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 7,956.3 3,755.3 72.09 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 9,870.6 4,332.9 72.72 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 11,495.6 4,855.9 71.46 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 12,901.8 5,322.4 70.34 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 14,149.5 5,719.4 71.05 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 15,142.4 6,038.5 72.86 GAS LIFT 5.500 CAMCO KBMM CAMCO KBMM 2.920 15,180.8 6,049.8 73.14 NIPPLE 4.540 CAMCO W NIPPLE w/NO GO PROFILE CAMCO W 2.812 15,188.8 6,052.1 73.22 PACKER 6.150 BAKER SAB-3 PACKER w/K22 ANCHOR SEAL ASSEMBLY BAKER SAB-3 3.000 15,205.8 6,057.0 73.50 NIPPLE 4.540 CAMCO D NIPPLE w/NO GO PROFILE CAMCO D 2.750 15,493.0 6,123.4 80.16 WLEG 4.500 BAKER WIRELINE RE-ENTRY GUIDE BAKER 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Make Model SN ID (in) 9,906.0 4,343.4 72.61 Production casing leak Found production casing leak with Archer acoustic tool. 0.000 11,906.0 4,984.5 71.41 Tubing Leak Tubing leak found w/ Relay 8/13/20 0.000 12,226.0 5,089.4 70.21 LEAK - TUBING Tubing leak found with Eline @ 12,226.5 0.000 15,205.0 6,056.7 73.49 TUBING PLUG 2.75" CA-2 Plug (30" OAL) 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) 4,995.6 2,828.0 70.86 1 GAS LIFT GLV BK 1 1,325.0 7/18/2020 0.188 7,956.3 3,755.3 72.09 2 GAS LIFT OV BK 1 0.0 7/17/2020 0.250 9,870.6 4,332.9 72.72 3 GAS LIFT DMY BK 1 0.0 8/20/2017 0.000 11,495.6 4,855.9 71.46 4 GAS LIFT DMY BK 1 0.0 8/22/2017 0.000 12,901.8 5,322.4 70.34 5 GAS LIFT DMY BK5 1 0.0 4/23/2002 0.000 14,149.5 5,719.4 71.05 6 GAS LIFT DMY BK5 1 0.0 11/7/1996 0.000 15,142.4 6,038.5 72.86 7 GAS LIFT DMY BK 1 0.0 9/8/2020 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 15,580.0 16,235.0 6,137.1 6,216.8 C-4, 2M-33 9/6/2017 0.5 15,580.0 16,235.0 6,137.1 6,216.8 C-4, 2M-33 8/27/2017 0.2 15,580.0 15,600.0 6,137.1 6,140.0 C-4, 2M-33 8/13/2010 6.0 APERF Millenium guns, 60° phase 15,600.0 15,620.0 6,140.0 6,142.8 C-4, UNIT B, A- 4, 2M-33 8/12/2010 6.0 APERF Millenium guns, 60° phase 15,760.0 16,160.0 6,160.5 6,208.1 A-3, 2M-33 7/26/1996 4.0 IPERF 4 1/2" TCP; 180° phase 15,775.0 15,805.0 6,162.2 6,165.7 A-3, 2M-33 9/3/2017 6.0 APERF HES TITAN PROSPECTOR GUNS (60° PHASING) 15,805.0 15,835.0 6,165.7 6,169.2 A-3, 2M-33 9/2/2017 6.0 APERF MALLINIUM II GUNS 6 SPF 60° PHASE 2.5"X21.0') (MALLINIUM II GUNS 6 SPF 60° PHASE 2.5"X11.0') OAL= 40.04' 16,194.0 16,235.0 6,212.1 6,216.8 A-3, 2M-33 7/26/1996 4.0 IPERF 4 1/2" TCP;180 deg. phase 2M-33, 9/26/2022 9:24:33 PM Vertical schematic (actual) PRODUCTION; 38.3-16,330.7 IPERF; 16,194.0-16,235.0 IPERF; 15,760.0-16,160.0 Hydraulic Fracture; 15,580.0 Hydraulic Fracture; 15,580.0 Perf; 15,580.0-16,235.0 Perf; 15,580.0-16,235.0 APERF; 15,805.0-15,835.0 APERF; 15,775.0-15,805.0 APERF; 15,600.0-15,620.0 APERF; 15,580.0-15,600.0 WLEG; 15,493.0 NIPPLE; 15,205.8 TUBING PLUG; 15,205.0 PACKER; 15,188.8 NIPPLE; 15,180.8 GAS LIFT; 15,142.4 GAS LIFT; 14,149.5 GAS LIFT; 12,901.8 LEAK - TUBING; 12,226.0 Tubing Leak; 11,906.0 GAS LIFT; 11,495.6 Production casing leak; 9,906.0 GAS LIFT; 9,870.6 GAS LIFT; 7,956.3 GAS LIFT; 4,995.6 SURFACE; 40.5-4,873.6 NIPPLE; 484.3 CONDUCTOR; 41.0-121.0 HANGER; 36.0 KUP PROD KB-Grd (ft) 47.00 RR Date 4/30/1996 Other Elev… 2M-33 ... TD Act Btm (ftKB) 16,340.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032024000 Wellbore Status PROD Max Angle & MD Incl (°) 83.45 MD (ftKB) 16,264.24 WELLNAME WELLBORE2M-33 Annotation Last WO: End DateH2S (ppm) 90 Date 12/15/2019 Comment SSSV: NIPPLE Stimulation Intervals Top (ftKB) Btm (ftKB) Inter val Num ber Type Subtype Start Date Proppant Designed (lb) Proppant Total (lb) Vol Clean Total (bbl) Vol Slurry Total (bbl) 15,580.0 16,275.0 1 Hydraulic Fracture 8/28/2017 22,566.0 1,665.00 1,689.00 15,580.0 16,275.0 1 Hydraulic Fracture 9/6/2017 100,000.0 20,131.0 935.00 956.00 2M-33, 9/26/2022 9:24:34 PM Vertical schematic (actual) PRODUCTION; 38.3-16,330.7 IPERF; 16,194.0-16,235.0 IPERF; 15,760.0-16,160.0 Hydraulic Fracture; 15,580.0 Hydraulic Fracture; 15,580.0 Perf; 15,580.0-16,235.0 Perf; 15,580.0-16,235.0 APERF; 15,805.0-15,835.0 APERF; 15,775.0-15,805.0 APERF; 15,600.0-15,620.0 APERF; 15,580.0-15,600.0 WLEG; 15,493.0 NIPPLE; 15,205.8 TUBING PLUG; 15,205.0 PACKER; 15,188.8 NIPPLE; 15,180.8 GAS LIFT; 15,142.4 GAS LIFT; 14,149.5 GAS LIFT; 12,901.8 LEAK - TUBING; 12,226.0 Tubing Leak; 11,906.0 GAS LIFT; 11,495.6 Production casing leak; 9,906.0 GAS LIFT; 9,870.6 GAS LIFT; 7,956.3 GAS LIFT; 4,995.6 SURFACE; 40.5-4,873.6 NIPPLE; 484.3 CONDUCTOR; 41.0-121.0 HANGER; 36.0 KUP PROD 2M-33 ... WELLNAME WELLBORE2M-33 2M-33 Proposed Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread Conductor 121 121 16 15.06 62.58 H-40 Welded Surface 4873 2789 9.625 8.83 40 L-80 BTC Production/ Intermediate 16330 6227 7 6.28 26 L-80 BTCM Liner 15100 6024 5.5 4.95 15.5 L-80 Hyd563 x EUE Tubing 15493 6123 3.5 2.99 9.3 L-80 EUE PROPOSED TUBING COMPLETION 3-1/2" 9.3# L-80 EUE 8rd Tubing to surface 3-½" X nipple at 500' RKB (2.813" min ID) 3-1/2" Camco KBG29 gas lift mandrels @ TBD 3-1/2" Seals TIE-BACK LINER (7.0" x 5.5" crossover at surface IF required) 5.5" L80, 15.5# HYD563 MS to surfce 5.5" x 3.5" crossover with 3.5" PBR 3.5" x 7.0" Packer @ ~15,110' RKB (4" ID) 3-½" Nipple at ~15,140' RKB (2.75" min ID) 3-1/2" Non-sealing Overshot REMAINING COMPLETION LEFT IN HOLE W Nipple @ 15,180' RKB (2.812" ID) Packer @ 15,188' RKB (4" ID) D Nipple @ 15,205' RKB (2.750" ID) Surface Casing Production/Intermediate Conductor Casing Leak 9,906' RKB 2M-33 Proposed Schematic - Contingency COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread Conductor 121 121 16 15.06 62.58 H-40 Welded Surface 4873 2789 9.625 8.83 40 L-80 BTC Production/ Intermediate 16330 6227 7 6.28 26 L-80 BTCM Liner 15100 6024 5.5 4.95 15.5 L-80 Hyd563 x EUE Tubing 15493 6123 3.5 2.99 9.3 L-80 EUE PROPOSED TUBING COMPLETION 3-1/2" 9.3# L-80 EUE 8rd Tubing to surface 3-½" X nipple at 500' RKB (2.813" min ID) 3-1/2" Camco KBG29 gas lift mandrels @ TBD 3-1/2" Seals TIE-BACK LINER (7.0" x 5.5" crossover at surface IF required) 5.5" L80, 15.5# HYD563 MS to surfce 5.5" x 3.5" crossover with 3.5" PBR 3.5" x 7.0" Packer @ ~15,110' RKB (4" ID) 3-½" Nipple at ~15,140' RKB (2.75" min ID) 3-1/2" Non-sealing Overshot REMAINING COMPLETION LEFT IN HOLE W Nipple @ 15,180' RKB (2.812" ID) Packer @ 15,188' RKB (4" ID) D Nipple @ 15,205' RKB (2.750" ID) WELG @ 15,493' RKB Surface Casing Production/Intermediate Casing Conductor Casing Leak 9,906' RKB Originated: Delivered to:20-Jun-22Halliburton 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 TYPE DATA TYPE LOGGING DATE PRINTS #DIGITAL #1 1D-135 50-029-22816-00 n/a Kuparuk River Packer Setting Record Field- Final 9-Jun-22 0 12 1F-03A 50-029-20853-60 907799903 Kuparuk River Multi Finger Caliper Field & Processed 9-Apr-22 0 13 1H-103 50-029-23593-00 n/a Kuparuk River Leak Detect Log Field- Final 3-Jun-22 0 14 1H-103 50-029-23593-00 n/a Kuparuk River Leak Detect Log Field- Final 4-Jun-22 0 15 1H-103 50-029-23593-00 n/a Kuparuk River Multi Finger Caliper Field & Processed 3-Jun-22 0 16 1H-104 50-029-23610-00 n/a Kuparuk River Leak Detect Log Field- Final 6-Jun-22 0 17 1H-104 50-029-23610-00 n/a Kuparuk River Multi Finger Caliper Field & Processed 7-Jun-22 0 18 2M-33 50-029-22816-00 n/a Kuparuk River Packer Setting Record Field- Final 15-May-22 0 19 3R-107 50-029-23660-00 n/a Kuparuk River Packer Setting Record Field- Final 20-May-22 0 110PLEASE 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: 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 #:________________Signature12/21/2021Wd͗ϭϵϲϬϳϮϬ Ͳ^Ğƚ͗ϯϲϮϱϯJRBy 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:22-Sep-21Halliburton 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 TYPE DATA TYPE LOGGING DATE PRINTS #DIGITAL #1 1B-09 50-029-20655-00 907383247 Kuparuk River Multi Finger Caliper Field & Processed 11-Sep-21 0 12 2M-19 50-103-20158-00 907335394 Kuparuk River Multi Finger Caliper Field & Processed 19-Aug-21 0 13 2M-19 50-103-20158-00 907335394 Kuparuk River Plug Setting Record Field- Final 20-Aug-21 0 14 2M-27 50-103-20175-00 907335397 Kuparuk River Plug Setting Record Field- Final 18-Aug-21 0 15 2M-33 50-103-2024-00 907316545 Kuparuk River Packer Setting Record Field- Final 8-Aug-21 0 16 2N-333 50-103-20525-00 907331967 Kuparuk River Radial Bond Record Field- Final 17-Aug-21 0 17 2N-333 50-103-20525-00 907383501 Kuparuk River String Shot Record Field- Final 13-Sep-21 0 18 2T-207 50-103-20287-00 907326322 Kuparuk River Packer Setting Record Field- Final 15-Aug-21 0 19 2V-04 50-029-21041-00 907398078 Kuparuk River Correlation Record Field- Final 20-Sep-21 0 110 2V-11 50-029-21311-00 907365411 Kuparuk River Leak Detect Log Field- Final 1-Sep-21 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:09/23/2021Wd͗ϭϵϲϬϳϮϬ Ͳ^Ğƚ͗ϯϯϱϳϬϯBy Abby Bell at 10:25 am, Sep 23, 2021 Originated: Delivered to:1-Jul-21Halliburton 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 TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL #1 1A-24 50-029-22984-00 907203651 Kuparuk River Packer Setting Record Field- Final 11-Jun-21 0 12 1E-34 50-029-22805-00 n/a Kuparuk River Leak Detect Log Field- Final 27-Jun-21 0 13 1E-34 50-029-22805-00 n/a Kuparuk River Plug Setting Record Field- Final 27-Jun-21 0 14 1J-168 50-029-23260-00 907188201 Kuparuk River Packer Setting Record Field- Final 3-Jun-21 0 15 2M-33 50-103-20240-00 907209681 Kuparuk River Packer Setting Record Field- Final 17-Jun-21 0 16 2N-347 50-103-20337-00 906961909 Kuparuk River Plug Setting Record Field- Final 14-Jun-21 0 17 2T-207 50-103-20287-00 907201320 Kuparuk River Leak Detect Log Field- Final 9-Jun-21 0 18 2T-207 50-103-20287-00 907199652 Kuparuk River Multi Finger Caliper Field & Processed 9-Jun-21 0 19 2V-03 50-029-21040-00 907177252 Kuparuk River Plug Setting Record Field- Final 27-May-21 0 110 3F-08 50-029-21464-00 907196137 Kuparuk River Plug Setting Record Field- Final 10-Jun-21 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:07/01/2021Wd͗ϭϵϲϬϳϮϬ Ͳ^Ğƚ͗ϯϱϯϮϭBy Abby Bell at 3:53 pm, Jul 01, 2021 Originated:Delivered to:9-Nov-20 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 1A-24 50-029-22984-00 906642121 Kuparuk River Plug Setting Record Field- Final 5-Aug-20 0 1 2 1C-27 50-029-22943-00 n/a Kuparuk River Packer Setting Record Field- Final 25-Aug-20 0 1 3 1F-19 50-029-22660-00 906642776 Kuparuk River Packer Setting Record Field- Final 6-Aug-20 0 1 4 1Y-27 50-029-22379-00 n/a Kuparuk River Production Profile Field- Final 29-Aug-20 0 1 5 2B-02A 50-029-21154-01 906679203 Kuparuk River Multi Finger Caliper Field- Processed 29-Aug-20 0 1 6 2C-15 50-029-21219-00 n/a Kuparuk River Packer Setting Record Field- Final 30-Aug-20 0 1 7 2G-08 50-029-21125-00 906659316 Kuparuk River Packer Setting Record Field- Final 16-Aug-20 0 1 8 2L-301 50-103-20588-00 906671629 Kuparuk River Plug Setting Record Field- Final 24-Aug-20 9 2L-301 50-103-20588-00 906671629 Kuparuk River Tubing Punch Record Field- Final 25-Aug-20 10 2M-33 50-103-20240-00 906598622 Kuparuk River Leak Detect Log Field- Final 13-Aug-20 0 1 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: 0 1 Received by the AOGCC 11/09/2020 11/09/2020 Abby Bell PTD: 1960720 E-Set: 34233 Originated:Delivered to:9-Nov-20 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 2N-345A 50-103-20264-01 906623204 Tarn Perforation Record Field- Final 25-Jul-20 0 1 2 2U-02 50-029-21268-00 906648446 Kuparuk River Packer Setting Record Field- Final 11-Aug-20 0 1 3 CPF-1A 50-029-21243-00 n/a Shallow Sands Leak Detect Log Field- Final 26-Aug-20 0 1 4 2G-08 50-029-21125-00 906640095 Kuparuk River Leak Detect Log and Plug Setting RecordField- Final 4-Aug-20 0 1 5 2M-24 50-103-20171-00 906622440 Kuparuk River Packer Setting Record Field- Final 7-Aug-20 6 2M-24 50-103-20171-00 906622440 Kuparuk River Packer Setting Record Field- Final 8-Aug-20 7 2M-33 50-103-20240-00 906598622 Kuparuk River Multi Finger Caliper Field- Processed 9-Aug-20 0 1 8 1A-23 50-029-22131-00 n/a Kuparuk River Leak Detect Log Field- Final 11-Aug-20 0 1 9 2B-02A 50-029-21154-00 n/a Kuparuk River Leak Detect Log Field- Final 27-Aug-20 0 1 10 2M-10 50-103-20157-00 906659029 Kuparuk River Multi Finger Caliper Field- Processed 15-Aug-20 0 1 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: 0 1 Received by the AOGCC 11/09/2020 11/09/2020 Abby Bell PTD: 1960720 E-Set: 34234 STATE OF A RtC IVED ALL OIL AND GAS CONSERVATION COM ION m ��..� S1 OCT OF SUNDRY WELL OPERATIONS 1 f 0 9 201 1.Operations Abandon ❑ Plug Perforations❑ Fracture Stimulate i] Pull Tubing❑ ;^, Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ AlkaGGOrogram ❑ Plug for Redrill ❑ 'erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: ConocoPhillips Alaska, Inc. Development 0 Exploratory❑ 196-072 3.Address: P. O. Box 100360,Anchorage,Alaska Stratigraphic❑ Service❑ 6.API Number: 99510 50-103-20240-00 7.Property Designation(Lease Number): 8.Well Name and Number: KRU 2M-33 ADL 25590 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 16,340 feet Plugs measured None feet true vertical 6,229 feet Junk measured None feet Effective Depth measured 16,232 feet Packer measured 15,189 . feet true vertical 6,216 feet true vertical 6,052 feet Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 feet 16 " 121' MD 121 TVD SURFACE 4,833 feet 9 5/8" 4,874' MD 2789 TVD PRODUCTION 16,292 feet 7 " 16,331' MD 6228 TVD Tubing(size,grade,measured and true vertical depth) 3.5 " L-80 15,494'MD 6,123'TVD Packers and SSSV(type,measured and true vertical depth) PACKER-BAKER SAB-3 PACKER WIK22 ANCHOR SEAL ASSEMBLY 15,189' MD 6,052'TVD SSSV - NONE 12.Stimulation or cement squeeze summary: Intervals treated(measured): 15580-15620,15760-16160,16194-16235 Treatment descriptions including volumes used and final pressure: SCANNED NOV 0 3201Z Total Well-1 Stage 28,538lbs placed see attached schematic for full FRAC details 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 250 1100 650 1080 ' 255 Subsequent to operation: Waiting for Hookup 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) ,` 15.Well Class after work: Daily Report of Well Operations 1:1 C/4Y"\�\� Exploratory ❑ Development ❑ Service❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ \0 16.Well Status after work: Oil D Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-302 Contact Name: Sandeep Pedam Authorized Name: Sandeep Pedam Authorized Title: Staff Co• ': Contact Email: Sandeep.Pedam@cop.com s�Engiinnee- �rte. Q/..2.. -j/) Contact Phone: (907)263-4724 Authorized Signature: jDate: / RE';:-: 1,k-- Gni "; 1 2v17 Form 10-404 Revised 4/2017Submit Original Only 4l4✓ (o/i 7/2-07 d- S • 2M-33 DTTM JOBTYP SUMMARYOPS START 8/28/17 DRILLING ATTEMPTED SINGLE STAGE REFRAC WITH DESIGN VOLUME OF 201,600# 16/20 SUPPORT- CARBOLITE, AND 2851 BBLS CLEAN VOLUME. PUMPED 1,665 BBLS AND EXPENSE REI PLACED 17,700# PROPPANT INTO FORMATION. DURING INJECTION, TREATING PRESSURES CONTINUE TO RISE ON PAD, 0.25 PPA, AND 0.50 PPA PROP CONC. LOWEST PUMP TRIPPED AT 6,500 PSI WHILE ON 1 PPA PROP CONC. PRV SET @ 7,000 PSI. ABLE TO INJECT 23 BBLS FLUSH BEFORE PRESSURED OUT. LEFT APPROX. 4,866# PROPPANT IN WELLBORE. 8/30/17 DRILLING PERFORMED FILL CLEAN OUT TO PBTD AT 16,238 RKB, CLEANED FRAC SUPPORT- GEL/SAND OUT OF TUBING, TAGGED FILL AT 15,622 RKB, MOST PERFS EXPENSE REI COVERED, RESULTS OF INJECTIVITY TEST TO FOLLOW. 8/31/17 DRILLING PUMPED 62 BBLS DSL DOWN TBG FOR INJECTIVITY TEST SUPPORT- EXPENSE REI 2 BBLS/MIN= 1600 PSI 4 BBLS/MIN= 2300 PSI 5 BBLS/MIN=2750 PSI EACH RATE WAS 5 MIN • ( JOB COMPLETE) 9/2/17 DRILLING SUPPC RIH WITH 32' OF HES MILLENNIUM II GUNS (60 DEGREE PHASING, 6 SPF), LOCATE 2.75" NIPPLE AT 15205.8' RKB AND CORRECT DEPTH TO TOP SHOT AT 15211.2' RKB, FIRE GUNS FROM TOP SHOT AT 15805' RKB TO 15835' RKB, JOB IN PROGRESS. 9/3/17 DRILLING RIH WITH 32' OF HES TITAN PROSPECTOR GUNS (60 DEGREE PHASING, 6 SUPPORT- SPF), LOCATE 2.75" NIPPLE AT 15205.8' RKB AND CORRECT DEPTH TO TOP EXPENSE REI SHOT AT 15211.2' RKB, FIRE GUNS FROM TOP SHOT AT 15775' RKB TO 15805' RKB, PERFORM INJECTIVITY TEST UP TO 6 BBL/MN AT 2530 WHP, LRS INJECTIVITY TEST TO FOLLOW, READY FOR FRAC. 9/4/17 PUMPING PUMPED 140 BBLS DSL DOWN TBG FOR INJECTIVITY TEST- EACH RATE WAS TRACKING HELD FOR 5 MINUTES ONLY 2 BBLS/MIN= 1400 PSI 4 BBLS/MIN= 1700 PSI 6 BBLS/MIN=2200 PSI 8 BBLS/MIN=2700 PSI JOB COMPLETE • • • 9/6/17 DRILLING PERFORMED A/C FRAC TREATMENT PUMPING DATA FRAC AND INITIAL SUPPORT- SCOUR STAGE FOLLOWED BY 1 AND 2 PPG SAND STAGES. ENCOUNTERED EXPENSE REI HIGH TREATING PRESSURES FROM BEGINNING, WENT TO FLUSH DURING 2# STAGE, HOWEVER, SCREENED OUT BEFORE GETTING ALL FLUSH AND NO FREEZE PROTECT AWAY. MADE MULTIPLE UNSUCCESSFUL ATTEMPTS TO SURGE WELL TO RE-ESTABLISH INJECTIVITY. 10,838#OF 16/20 PROPPANT (11% OF DESIGN) PLACED INTO FORMATION. UNABLE TO RIG DOWN FROM WELL AS WIND SPEEDS PREVENTING USE OF MANLIFT. CTU WILL FOLLOW WHEN POSSIBLE FOR CLEANOUT. Note: See attached treating report for additional info 9/8/17 DRILLING PERFORM FILL CLEANOUT WITH 1.5"COIL, ENCOUNTERED FIRST FRAC SAND SUPPORT- AT 5200' CTMD, MAINTAINED 1:1 RETURNS, WHP INCREASES TO 3200 PSI AND EXPENSE REI REDUCES OUR PUMP RATE TO .6 BPM, UNABLE TO GET AN EFFICIENT FCO AT THIS RATE, 11800' CTMD CHASE GEL OOH, WELL LEFT F/P, JOB IN PROGRESS. 9/27/17 DRILLING PERFORMED POST FRAC FILL CLEANOUT FROM 11427' CTMD TO 16195' CTMD, SUPPORT- HEAVY FRAC SAND CONCENTRATIONS IN RETURNS, MAINTAINED 1:1 UNTIL EXPENSE REI WE LOST ALL RETURNS AND STUCK PIPE MULTIPLE TIMES, RE-ESTABLISH CIRCULATION AND SWEEP HOLE FROM TBG TAIL (15495' RKB)TO SURFACE, RETURN IN AM TO CONTINUE WITH FCO USING DIESEL, JOB IN PROGRESS. • • • _ _ ° ' 'G ca ii N Q. 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Top(ftKB) Set Depth(ft.. Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection TUBING 3 1/21ID(in)2.9921 36.01 15,493.71 6,123.51 9.301 L- 80 1EUE8rdMOD -,-".CONDUCTOR;41 0-121 0- - H ..i.11,-..Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(.) Item Des Com (in) NIPPLE;484.3 36.0 36.0 0.03 HANGER FMC GEN IV TUBING HANGER 3.500 484.3 483.6' 7.74 NIPPLE CAMCO DS NIPPLE w/NO GO PROFILE 2.812 15,180.8 6,049.8 73.14 NIPPLE CAMCO W NIPPLE w/NO GO PROFILE 2.812 • 15,188.8 6,052.1 73.22 PACKER BAKER SAB-3 PACKER w/K22 ANCHOR SEAL 3.000 ASSEMBLY 15,205.8 6,057.0 73.50 NIPPLE CAMCO D NIPPLE w/NO GO PROFILE 2.750 15,493.0 6,123.4 80.16 WLEG BAKER WIRELINE RE-ENTRY GUIDE 3.000 SURFACE,40.5-4,873.6 • Perforations&Slots Shot GAS LIFT,4,995.6 Dens Top(ND) Btm(ND) (shots/ Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 15,580.0 15,600.0 6,137.1 6,140.0 C-4,2M-33 8/13/2010 6.0 APERF Millenium guns,60 deg phase GAS LIFT;7,956.3 15,600.0 15,620.0 6,140.0 6,142.8 C-4,UNIT B, 8/12/2010 6.0 APERF Millenium guns,60 deg A-4,I 2M-33 phase 15,760.0 16,160.0 6,160.5 6,208.1 A-3,2M-33 7/26/1996 4.0 (PERF 4 1/2"TCP;180 deg. GAS LIFT;9,8706 phase 16,194.0 16,235.0 6,212.1 6,216.8 A-3,2M-33 7/26/1996 4.0 (PERF 41/2"TCP;180 deg. phase GAS LIFT,11,495.6 Mandrel Inserts a�t o Top(ND) Valve Latch Port Size TRO Run GAS LIFT;12,901.8 N, Top(ftKB) (ftKB) Make Model OD(in) Sew Type Type (in) (psi) Run Date Com 1 4,995.6 2,828.0 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/21/2017 2 7,956.3 3,755.3 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/21/2017 3 9,870.6 4,332.9 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/20/2017 GAS LIFT;14,149.5 4 11,495.6 4,855.9 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/22/2017 5 12,901.8 5,322.4 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 4/23/2002 6 14,149.5 5,719.4 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 11/7/1996 GAS LIFT;15,142.34 7 15,142.4 6,038.5 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 4/23/2002 Notes:General&Safety End Date Annotation 11/17/2010 NOTE VIEW SCHEMATIC w/Alaska Schematic9.0 NIPPLE;15,180.8 /F II 1- .., PACKER 15,188.8 NIPPLE;15,205.8 I e_ • I WLEG;15,493.0 Tr APERF',15,580.0-15,600.0 APERF;15,600.0-15,620.0 1 IPERF;15,760.0-16,160 0 IPERF;16,194.0-16,235.0- PRODUCTION,38.3-16,330.7 KUP D 2M-33 Con Phillips 3 Well Attribute Max Angle D TD Afask&IN,:,Il•iC; Wellbore API/UWI Field Name Wellbore Status nal(") MD(ftKB) Act Btm(RKB) Coraca`Philkps 'i, 501032024000 KUPARUK RIVER UNIT PROD 83.45 16,264.24 16,340.0 ,,.. l ,,, Comment HES(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 2M-33,10/9/201710x228 AM SSSV:NIPPLE 25 12/5/2016 Last WO. 47.00 4/30/1996 Vertical schematic.(actual).. Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:RKB 16,228.0 11/16/2013 Rev Reason:TAG,H2S,SET PLUG 8 pproven 8/28/2017 ..� _ CATCHER,GLV CIO,PULL PLUG 8 CATCHER HANGER;38.0 1 � 1r� Casing Strings Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread CONDUCTOR 16 15.062 41.0 121.0 121.0 62.58 H-40 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(RKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread SURFACE 95/8 8.835 40.5 4,873.6 2,788.9 40.00 L-80 BTC Casing Description OD(in) ID(in) Top(RKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Lenp...Grade Top Thread 1� IPRODUCTION 7 6.276 38.3 16,330.7 6,227.8 26.00 L-80 BTC-MOD J Tubing Strings_ ,,,,„,,,,,,,,,,,•,...,............,.,,,,..,,, I I gpi,Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..i Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection 4TUBING 31/2 2.992 36.0 15,493.7 6,123.5 9.30 L-80 EUE8rdMOD -^-".CONDUCTOR;41.0-121.a Completion Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl(') Item Des Corn (in) NIPPLE;4843 36.0 36.0 0.03 HANGER FMC GEN IV TUBING HANGER 3.500 484.3 483.6 7.74 NIPPLE CAMCO DS NIPPLE w/NO GO PROFILE 2.812 15,180.8 6,049.8 73.14 NIPPLE CAMCO W NIPPLE w/NO GO PROFILE 2.812 15,188.8 6,052.1 73.22 PACKER BAKER SAB-3 PACKER w/K22 ANCHOR SEAL 3.000 ASSEMBLY 15,205.8 6,057.0 73.50 NIPPLE CAMCO D NIPPLE w/NO GO PROFILE 2.750 15,493.0 6,123.4 80.16 WLEG BAKER WIRELINE RE-ENTRY GUIDE 3.000 SURFACE;40.5-4,873.6 Perforations&Slots Shot GAS LIFT;4,995.8 Dens Top(TVD) Btm(TVD) (shots/ Top(8K13) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 15,580.0 16,235.0 6,137.1 6,216.8 8/27/2017 0.2 GAS LFT.],9563 15,580.0 16,235.0 6,137.1 6,216.8 9/6/2017 0.5 15,580.0 15,600.0 6,137.1 6,140.0 C-4,2M-33 8/13/2010 6.0 APERF Millenium guns,60 deg phase GAS LIFT;9,8706 15,600.0 15,620.0 6,140.0 6,142.8 C-4,UNIT B, 8/12/2010 6.0 APERF Millenium guns,60 deg A-4,2M-33 phase 15,760.0 16,160.0 6,160.5 6,208.1 A-3,2M-33 7/26/1996 4.0 IPERF 4 1/2"TCP;180 deg. phase GAS LIFT;11,495.6 16,194.0 16,235.0 6,212.1 6,216.8 A-3,2M-33 7/26/1996 4.0 (PERF 41/2"TCP;180 deg. phase GAS LIFT;12,901.8 Stimulations&Treatments Proppant Designed(Ib) Proppant In Formation(Ib) Date 0.0 8/28/2017 Stimulations&Treatments GAS LIFT,14,149.5 Vol Clean Pump Stg# Top(ftKB) Btm(ftKB) Date StimtTreat Fluid (bbl) Vol Slurry(bbl) 1 15,580.0 16,275.0 8/28/2017 WATER FRAC G 25#-SBM(15346), 87.37 87.37 Pad GAS LIFT;15,142.4 2 15,580.0 16,275.0 8/28/2017 HYBOR G 25#-SBM(21113),Frac 227.99 227.99 Fluid 3 15,580.0 16,275.0 8/28/2017 HYBOR G 25#-SBM(21113),Frac 0.00 0.00 Fluid NIPPLE;15,180.8 4 15,580.0 16,275.0 8/28/2017 HYBOR G 25#-SBM(21113),Frac 642.72 647.46 Fluid 5 15,580.0 16,275.0 8/28/2017 HYBOR G 25#-SBM(21113),Frac 59.48 60.17 a'r Fluid PACKER;15,168.8 a # 6 15,580.0 16,275.0 8/28/2017 HYBOR G 25#-SBM(21113),Frac 380.43 388.61 Fluid 7 15,580.0 16,275.0 8/28/2017 HYBOR G 25#-SBM(21113),Frac 272.49 282.98 Fluid NIPPLE;15,205.8 Proppant Designed(Ib) Proppant In Formation(lb( Dote II 0.0 9/6/2017 Stimulations&Treatments WLEG;15,493.0 iir Vol Clean Pump Stg# Top(ftKB) Btm(ftKB) Date Stim/Treat Fluid (bbl( Vol Slurry(bbl( 1 15,580.0 16,275.0 9/6/2017 WATER FRAC G 25#-SBM(15346), 72.78 72.78 Pad 2 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 137.14 137.14 Fluid 3 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 0.00 0.00 Fluid APERF;15,580.0-15,600.0 4 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 139.48 139.54 Fluid APERF;15,600.0-15,620.0 5 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 157.56 159.34 Pert,15,580.0-16,235.0Fluid Pen;15,5800-16,235.0 6 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 108.72 111.34 Hydraulic Fracture;15,580 0 Fracture;Frre;15,580.0 Fluid /PERF,15,760.0-16,160.0 7 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 151.36 158.56 Fluid 8 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 110.82 121.21 Fluid a. 9 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 18.66 19.20 Fluid IPERF;18,194.0-16,235.0 11 15,580.0 16,275.0 9/6/2017 WATER FRAC G 25#-SBM(15346), 38.52 38.54 ' y Flush 13 15,580.0 16,275.0 9/6/2017 HYBOR G 25#-SBM(21113),Frac 0.00 0.00 Fluid Mandrel Inserts St ati NTop(TVD) Valve Latch Port Size TRO Run Top(ftKB) (Po(B) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com 1 4,995.6 2,828.0 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/21/2017 2 7,956.3 3,755.3 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/21/2017 3 9,870.6 4,332.9 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/20/2017 4 11,495.6 4,855.9 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 8/22/2017 PRODUCTION,38.3-16,330 7 . 5 12,901.8 5,322.4 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 4/23/2002 KUPD 0 2M-33 ConocoPhillips ; ConocoPh9lypt -tillHANGER;36.0 .. 1an.re nse s Top(ND) Valve Latch Port Size TRO Run Top(ftKB) (RKB) Make OD(in) Sew Type Type (in) (psi) Run Date fr 0����i1��� 0 000=El0 000 =E 411 1/7/1996 996 _ I I s Notes:General&Safety 1 1 iii I Annotation CONDUCTOR;41.0-121 0- ��I �^P1 1 11/17/2®NOTE'VIEW SCHEMATIC w/Alaska Schematic9.0 j. NIPPLE;484.3 I SURFACE,40.5-4,873.6 GAS LIFT;4,995.6111 GAS LIFT;7,956.3 111 GAS LIFT;9,870.6 tnt GAS LIFT;11495.6 lit III GAS LIFT;12,901.8 1111 GAS LIFT;14,149.5 III GAS LIFT;15,142.4 ill NIPPLE;15,180.8 1111 PACKER;15,188.6 111 NIPPLE;15,205.81. WLEG;15,493.0 II�� APERF;15,580.015,600.0 I I , APERF;15,600.015,620.0 Pert;15,580.016,235.0 ) Pert,15,580.016,235.0 Hydraulic Fracture,15,580.0 Hydraulic Fracture,15,580.0 IPERF;15,760 0-16,160.0 IPERF;16,194.0-16,235.0 PRODUCTION;38.3-16,330 7 • • OF Tit AO' /7,6. THE STATE Alaska Oil and Gas 4 Of L sKA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ^ti Main: 907.279.1433 a1" AL AS Fax: 907.276.7542 www.aogcc.alaska.gov Sandeep Pedam scats AUG 1 1 2017 Staff Completion Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3M-33 Permit to Drill Number: 196-072 Sundry Number: 317-302 Dear Mr. Pedam: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair, Commissioner "` DATED this2-'' day of July, 2017. RBDMS LL AUG - 9 2017 • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION -JUN 2 9 2017 APPLICATION FOR SUNDRY APPROVALS � � 20 AAC 25.280 � , , Ca ' 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate 0 ' 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:❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Exploratory ❑ Development p, 196-072 ' 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: P. O. Box 100360,Anchorage,Alaska 99510 50-103-20240-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/a • KRU 2M-33 , Will planned perforations require a spacing exception? Yes ❑ No 11 7 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 25590 ' Kuparuk River Field I Kuparuk River Oil'Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 16,340' 6,229' 16232 6216 NONE NONE Casing Length Size MD ND Burst Collapse Conductor 80' 16" 121' .121' Surface 4,833' 10" 4,874' 2,789' Production 16,292' 7" 16,331' 16,331' Perforation Depth MD(ft): • Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 15580-15600, 15600-15620, 6137-6140,6140-6143, 3.500" L-80 15,494' 15760-16160.'6194-16235 6160-6208,6212-6219 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): PACKER-BAKER SAB-3 PACKER W/K22 ANCHOR SEAL ASSEMBLY • MD=15189 TVD=6052 12.Attachments: Proposal Summary El Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 2 • Service ❑ 14.Estimated Date for 9 iigizo aw4121715.Well Status after proposed work: Commencing Operations: I? OIL ❑ • WINJ IDWDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 0 WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: GINJ 0 Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Sandeep Pedam Contact Name: Sandeep Pedam Authorized Title: aff Completion En.ineer Contact Email: Sandeep.Pedam@cop.com 1Contact Phone: (907)263-4724 Authorized Signature: 4,0„.',-, /g Date: V IV 7.- 1 O COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: •S r7- 02 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test LI Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No [T Spacing Exception Required? Yes ❑ No ivr Subsequent Form Required: j /b — I0(-' RBDMS L- AUG - 9 2017 APPROVED BY Approved by: ✓r-C-1------ COMMISSIONER THE COMMISSION Date:'"'r I4 Cq. 4),,CeoRIGINAL i 74/2jl� vii- 7/Z8/t7--" &Dt•.) 7//2/Zot7 nSubmit Form and ' l/ Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • • ConocoPhillips RECEIVED Alaska, Inc. JUN 2 9 2017 Paul K.Wharton Staff Landman AOGCC P.O.Box 100360—Suite ATO 1482 Anchorage,Alaska 99510-0360 Phone(907)263-4076 Paul.K.Wharton@conocophillips.corn To: Operator and Owners (shown on Exhibit 2) Re: Notice pursuant to 20 AAC 25.283 (1) 2M-33 Well Kuparuk River Unit, Alaska ADL 25590, KRU Tract 74; ADL 25585, KRU Tract 69; and ADL 25586, KRU Tract 68 Dear Sirs: ConocoPhillips Alaska, Inc. ("CPAI") as Operator and on behalf of the Kuparuk River Unit ("KRU") working interest owners, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing pursuant to the provisions of 20 AAC 25.280 ("Application") for the 2M-33 Well (the "Well"). The Application will be filed with the Alaska Oil and Gas Conservation Commission ("AOGCC") on or about June 2, 2017. This Notice is being provided pursuant to 20 AAC 25.283. The Well has been drilled as a directional well as shown on the attached plat (Exhibit 1). Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well, including the reservoir section ("Notification Area"). Exhibit 2 is a list of the names and addresses of all owners, landowners and operators of record of all properties within the Notification Area. Upon your request CPAI will provide a complete copy of the Application to you. If you require any additional information, please contact the undersigned. Very truly yours, Paul Wharton Staff Landman cc: Lynn Aleshire Rebecca Swensen 2M-33 Hydraulic Fracturing Notice Letter • June 1, 2017 Page 2 Exhibit 1 `_ -i3126142 _! ADL390503 2M-11 \ADL025671 /2M- 21 ADL025570 2M-13 JJ 2M-19 2M-20 2M-18 2M-05\ \10 2M,06 2M-36 / ADL025586 ......... 2M-03 '2M 16 2M-372M-36P61 2M-25 7M-01 - _ ��1 / 2M-23 ADL390691 ADL025585 `All1 `� - ADL025587 2M-28 /// 2M-24 2M-27 -12 i Southern 2M-31 .,/�- .�� ' M i Iuveach �� 2M-22 Unit ! A 2M-17 • 2M-29 2M-09A 2M-02 2M-07 2M-14 /, 2M-32 2M-04 2 1P81 211-08 211-09 I 3zuPsz ADL025589 ADL390680 25-14 211-34 ADL025588 ADL025590 211 32L1 2M-32L1-01 2M-35 ;uparuk PA 2M-08Ll-01 ( i 2M-08L1 1 Kuparuk River Unit • Frac Points Trajectory ADL025603 ADL025604 ADL025605 Open Interval - Half Mile Frac Point Radius _ Half Mile Trajectory Radius Wells within Trajectory RadiusN ConocoPhillips L____.] Kuparuk PA Alaska,Inc. L._.; AK Unit A 2M-33 CPAI Leases ADL025' 0 0.2 0.4 0.6 0.8 1 1.2 1.4 DI Lease Plat BRPC Miles 5/17/2017 2M-33 Hydraulic Fracturing Notice Letter June 1, 2017 Page 3 Exhibit 2 Mineral Owners: Operator: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO 1220 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attention: Erik Keskula, Manager, NS Development Non-Operators: BP Exploration (Alaska) Inc. P.O. Box 196612 900 E. Benson Boulevard (Zip 99508) Anchorage, AK 99519-6612 Attention: Mr. John Dittrich Chevron U.S.A. Inc. 310 K Street, Suite 406 Anchorage, AK 99501 Attention: Mr. Dave White ExxonMobil Alaska Production Inc. P.O. Box 196601 3301 C Street, Suite 400 (Zip 99503) Anchorage, AK 99519-6601 Attention: Mr. Jamie Long Surface Owners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Attention: Director TO TH•LASKA OIL AND GAS CONSERVATION CO•ISSION Before the Commissioners of the ) Alaska Oil and Gas Conservation ) Commission in the Matter of the ) AFFIDAVIT OF Paul K.Wharton Request of ConocoPhillips Alaska, Inc. for ) Hydraulic fracturing for the 2M-33 Well ) under the Provisions of 20AAC 25.280 ) STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT ) Paul K.Wharton, being first duly sworn, upon oath, deposes and states as follows: 1. My name is Paul K.Wharton, and I have personal knowledge of the matters set forth herein. 2. I am Staff Landman for the well operator, ConocoPhillips Alaska, Inc. ("CPAI") 3. Pursuant to 20 AAC 25.283 (1) CPAI prepared the attached Notice of Operations ("Notice"). 4. On or about June 1, 2017, CPAI sent a copy of the Notice by certified mail to the last known address of all other owners, landowners,surface owners,and operators of record within a one-half mile radius of the current proposed well trajectory. Subscribed and sworn to this 1st day of June, 2017. Paul K.Wharton STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT ) This instrument was acknowledged before me this 1St day of June, 2017, by Paul K.Wharton. C Notary Public, State of Alaska My Commission Expires: STATE OF ALASKA 4. NOTARY PUBLIC REBECCA SWENSEN ‘`,-;;E-74, My Commission Ex.ires Au..27,2020. • Section 1—Affidavit 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators within one- half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283(a)(1) Affidavit • • Section 2—Plat 20 AAC 25.283 (a)(2) Plat 1: Wells within 0.5 miles .AQ41.97625.1UE3g050.1 i1.4-1I ,L I NI) / 2m-23 711/8 2MC5 ‘3.1-'0 1 2h4 ei ADU:r25586 4 21.10 /21.41, .. „ --0T--- 2"IM -'',--4.:7-'., , ,./ ADL390691 ! ADU025585 ; , ADL025507 27 11.`:, 21,42;„ Southern . Miluveach ,,,,, Ri,71. ei"'" Ot>y/ 4 Unit / , 2WD ! , k , k 1 . I 1 / / \ , 1 N-32 /i .2%.1Alt‘L'I 7A4r,4 API. ; / 12UL) A01_025589 AD1300680 1 'S14 214-34 e / A0L025566 ADL025590 2t1021.1 i 2'e'V. 1 11 el 235/ f ) Ku pa r u k PA 21.4-38u-c 1 , (71414.11 1 , I 1 I i i , Kuparuk River \ 25 Unit ..,.._..., "3* * Frac Points Trajectory ADL025603 ADL025604 ADL025605 --......Open Interval EDHalf Mile Frac Point Radius F-1 Half Mile Tmectory Radius --- Wells within Trkeolory Radi,.is N ConocoPhillips Li Kuparuk PA ' •AK Unit _ AAla*kak — 2M-33 CPAI Leases ADL0251 0 02 0.4 0.6 0.8 1 12 14 D Lease Plat Miles BRPC ..i 5/17:2017 • • Table 1:Wells within a 0.5 miles Wells within 1/2 mile buffer of well track * Data from SDE layer: AK_WELL_BOTTOM_TD_ATDB_DD83 API Well Name Well Type Status 509993001600 2M PERM 1 OBS PROP 501032073300 2S-14 PROD ACTIVE 501032015500 2M-23 DISP PA 501032018400 2M-08 PROD ACTIVE 501032018463 2M-08L1 PROD ACTIVE 501032018464 2M-08L1-01 PROD ACTIVE 501032069100 2M-36 PROD ACTIVE 501032069170 2M-36PB1 EXPEND PA 501032074500 2M-37 PROD ACTIVE 501032024100 2M-31 INJ ACTIVE 501032024200 2M-34 INJ ACTIVE 501032024300 2M-35 INJ ACTIVE 501032015000 2M-17 INJ ACTIVE 501032015100 2M-18 INJ ACTIVE 501032015200 2M-25 PROD ACTIVE 501032015300 2M-16 INJ ACTIVE 501032015400 2M-15 PROD ACTIVE 501032015600 2M-21 PROD ACTIVE 501032015700 2M-10 PROD ACTIVE 501032015800 2M-19 INJ ACTIVE 501032015900 2M-11 PROD ACTIVE 501032016000 2M-03 INJ ACTIVE 501032016100 2M-13 PROD ACTIVE 501032016800 2M-05 INJ ACTIVE 501032016900 2M-20 PROD ACTIVE 501032017000 2M-22 PROD ACTIVE 501032017100 2M-24 PROD ACTIVE 501032017200 2M-26 INJ ACTIVE 501032017300 2M-14 INJ ACTIVE 501032017400 2M-28 PROD ACTIVE 501032017500 2M-27 INJ ACTIVE 501032017600 2M-06 INJ ACTIVE 501032017700 2M-09 INJ PA • • 501032017701 2M-09A INJ ACTIVE 501032017800 2M-07 PROD ACTIVE 501032017900 2M-02 INJ ACTIVE 501032018000 2M-30 INJ ACTIVE 501032018100 2M-12 PROD ACTIVE 501032018200 2M-04 INJ ACTIVE 501032018300 2M-29 PROD ACTIVE 501032018500 2M-01 PROD SUSP 501032018600 2M-32 PROD ACTIVE 501032018660 2M-32L1 PROD ACTIVE 501032018661 2M-32L1-01 PROD ACTIVE 501032018670 2M-32L1PB1 EXPEND PA 501032018671 2M-32L1PB2 EXPEND PA Section 3—Freshwater Aquifers 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within one-half mile radius of the current or proposed wellbore trajectory. None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), "That portions of the aquifers on the North Slope described by a 1/4 mile area beyond and lying directly below the Kuparuk River oil and gas producing field". / Section 4—Plan for Baseline Water Sampling for Water Wells 20 AAC 25.283(a)(4) There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. / Section 5—Detailed Cementing and casing information 20 AAC 25.283(a)(5) All casing is cemented in accordance with 20 AAC 25.030(b) and tested in accordance with 20 AAC 25.030 (e) when completed. See Wellbore schematic for casing details. Section 6—Assessment of each casing and cementing operation to be performed to construct or repair the well 20 AAC 25.283(a)(6) • • Casing &Cement Assessments: The 9-5/8" casing cement pump report on 4/19/1996 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 840Sx AS III and 950 Sx Class G. Took cement returns to surface. The 7"casing cement pump report on 4/29/1996 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 250 S X Class G cement. Took cement returns to surface. The floats were checked and they held. TOC?? Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successful fractured within design limits. Section 7—Pressure test information and plans to pressure test casing and tubings installed in the well 20 AAC 25.283 (a)(7) 20 AAC 25.283. Hydraulic fracturing (a) Before hydraulic fracturing, the operator must submit an Application for Sundry Approvals (Form 10- 403) under 20 AAC 25.280. Unless modified or altered by pool rules established under 20 AAC 25.520, the application must include (7) pressure test information if available and plans to pressure-test the casings and tubing installed in the well; On 7/08/2008 the 9-5/8" casing passed a MIT-OA was pressure tested to 1,800 psi. On 07/27/1996 the 7" casing was pressure tested to 3,500 psi. On 10/22/1996 the 3.5"tubing was pressure tested to 4,000 psi (PPPOT-IC, PPPOT-T passed). It will be tested to 4635 psi prior to the frac. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 6,530 Annulus pressure during frac 2,500 Annulus PRV setpoint during frac 2,600 Annulus pressure test 2,750 Tubing pressure Test 4,635 Nitrogen PRV 7,030 Highest pump trip 6,830 Table 1: Required Pressures • • Section 8—Pressure ratings and schematics for the Wellbore,Wellhead, BOPE and Treating head 20 AAC 25.283(a)(8) Size Weight Grade API Burst API Collapse 9 &5/8" 40 L-80 5,750 psi 3,090 psi 7" 26 L-80 7,240 psi 5,140 psi 3 &%2" 9.3 L-80 11,560 psi 12,120 psi Table 2: Pressure Ratings • • Stimulation Surface Rig-Up 4, C, Bleed!Tattle Tale Tank `* Da T �• �$ 0 o 0 4 ►rta CD c M0® dv g� d C a � � a 04 Y d W � l dwnd Pop-Off Tank Pop-Off rank 141 Pump Truck gz> Hca f �-J e J g Frac Pump 41.2%1-- - -{j- Frac Pump Frac Pump - -- --1d- Frac Pump Frac Pump - Frac Pump S Ill Tree Saver with Wellhead re OIL STATES PROPOSAL: Energy Services (Canada) Inc. QUOTE#: DATE: Maximum Allowable Pumping Rates SIZE ID OD RATE miimin CSG 2.250 3.750 10 m3imin 3 1/2" Big Bore 1.750 2.750 6 ms/min 2 7/8"&3 1/2" 1.438 2.360 4 ms/min 2 3/8" 1.000 1.900 2 nf/min 3 1/16&4 1/16 with tapered mandrel 2,750 4.000 15 m5/min 1 4 1/16 X Tool Mandrel 3.610 4.760 24 m3/min _........_... ............_ OPEN PosinoN CLesie Mums k 4.4 fril At.rd!1 IhNi i41.0,4 1 tAtt.tbl I INit X 114 (1 /Z:ritiryr" r) i .......... , r I 1 • I., 1 P 1 I WACO briVENO I 111 ['AM I. A /NW IV Wag I 1 ff4 1 1 •4'1' 1 r ...'1 f , I OW 11 L , .,, I' t AI .4 LIM lit APO .....:, V4.1#Varrl IlvettliCi WkevIl .:4' e on\I. Atint4.4+9 %%nal 4 ZI (1 $110 '''... tks,t: .....,,u 1.4 Alltwat 04,-- - note is two) i i i KO' to. ....,-r, I,,,,,,, www.osescanada.com • • Wellhead Schematic ,•„ KUP 2M-33 ConocoPhillips wee sass Angie i MO TO .,„.,t, ..4.....,.,,. ....,* .., k t..... ..c,.,.._ ...._..m, SMIC.AYrd+K+� LuPa04.0,Po FA LArieY moo - �- l w 4?.. ... wMMeet�iyl t,r,c...2exw 1SS8Y:8YJ"4'i.i 9i 9,12T1 .w.Wt t c� L.M T..1.CY •6.�. .s._a ..fowrM .x«r.w T.w.�=�... ,�� ( _��. . v, .£ _..._.__ ......._..__.._. ._ 6 Calanetnrig • x.a 4.. iw.Ca..O A, R t+r0tt. 4: ...4 `+Nrx!- +.. Q ....CAG CONN ACTOR i SC 1;1 C 1:4 i T„.A M.4,1 WIF,Dc r., L.M.♦a.u.MYr.... <.Arai 3..P.M Ir sat 0.0(.Crwc, A.w4 A,T...r..- 505.0 i.#4 SLIAFAC,f -• APS aATia .T*T: 44,ZC ..0C OTC ta...1.4054.0. „. - ...Soo.*a_540 G.../.1rc4_L1,440K_ 3+*.K-. 5*S*3 tut M. PAO.�CMAJCC.T4d. 69 ?' T ^8 •4.C* _44, F^vW.?Ci Sng r wYua SWuver ' tI”- L(i�s.. „. .+. fi r-7-,-,,,7:-.-13-74.,----m-1-7-,--:,-,„,--U Cat[ a•,.,.... +4... pr. 1 Wo '..-:h.Fs LF MaJ W F0M:t,LF S i. t4.SOP -"., . `t f ..1.,r.w' 3i 0* C.CS3 tkOt I F C SOC tS 18XS rc ` S.FA AO-T PACxFA kit AMt'FFJP.SEAL AS:.PMM: :00 ,..-c c.,P t..M;F w..+,c.,Me,3f'.,t !^ti.; Pa4tOFAttgals i 3o sw Sr.m AMM 5+►MVO.M0,11 Mmm 10M ..... .7 4 9as VAIN Sm. ba+. r` •,,,,M. .6'1;; .t?S9 4,t 995lC-a..•IV.,e? ;k'1S a..&Y i:. ... a,1144 is,ta7t c.. T.1T AIN Nf:l:V10 r~,:>'AF•F Af V,e., ..„ :+.xa 400. 41iY [F' C *opt Hou . Notes Sonora!6. . ..,... If.. 1 GO.sa Awa III reaxF sra+_.............. [ am co +A;000 -.0 ! I. t4a4t..*xms ,atl.o t4,4e u.t... _ 'mcs ec.:... Marra MM 1 a. sa H+s .a,Ns>541W ��s "'�1ss 1. Av% L ad.. .SM%%:V.M.00 IA ra. � • 4 W?T a LCh M _A.M:ni.EVM 4 FT QV! PAT5 �.ta8 1 M1 . (05444 a00.4.4 7'AA,..aAerK..banw .+.L.t.FY by 6x.5 6;SU S t7.2Gn S.i.^u5 5 70 3A.=v..,aa.Cr#04015 1 CAA iFY OIM. AAA P.DCA _ - . .. 4 tsta0 ST:-.a 7.41*;.A1KXa thaw 0 OA4 L.#Y t n' *4,4 C.KC .r. 3 (501 4.4i Jd.a?0Ae i..4M' J�.8Y4 k.:4&LIFT sort 60.5 so,,, ._.._.. .. .a, • • Section 9—Data for Fracturing zone and confining zones 20 AAC 25.283(a)(9) CPAI has formed the opinion based on seismic, well and other subsurface information currently available that: The Kuparuk interval is approximately 91'TVD thick, with the top and base picked at 15,552' MD/5,986'TVDSS and 16,297' MD/6,077'TVDSS, respectively . The Kuparuk Interval is composed of fine-grained sandstones, siltstones and shale interbeds. The estimated fracture gradient for the Kuparuk interval is 12.5ppg. The overlying confining zone consists of greater than 313'ND of Kalubik and HRZ mudstones. The fracture gradient for each of these zones is estimated to be 15ppg and 16ppg respectively. The top of the overlying confining zone is picked at 14,463' MD/5,673'TVDSS. The underlying confinement zone consists of approximately 117'TVD of mudstones comprising the Miluveach Shale. The estimated fracture gradient for the Miluveach Shale is 15-18ppg with fracture gradient increasing with depth. Section 10—Location, Orientation and a Report on Mechanical Condition of Each Well that may Transect Confining Zone 20 AAC 25.283(a)(10) The plat shows the location and orientation of each well that transects the confining zone. ConocoPhillips has formed the opinion, based on the following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within one-half mile radius of the proposed wellbore trajectory. Casing&Cement assessments for all wells that transect the confining zone: 2M-34: The 7" casing cement report on 5/23/1996 shows that the job was pumped as designed, indicating competent cementing operations.The cement job was pumped with (250Sx) class"G". The plug bumped and the floats were checked and they held. Well Name Status Casin Size Top of Oil Top of Top of cement Zonal Cement Operations Mechanical g Pool Cement determined byReservoir status Isolation Summary integrity Baker (5/23/1996)7"casing Open hole for pumped (2505x class MIT-IA passed 2M-34 Inj 7" 6221'TVD 15,900'MD Calculation Packer injection 16,342'RKB "G"cement)as 1/17/17 designed Baker (4/29/1996)7"casing Open hole for pumped(250 Sx class TFILpassed 2M-33 Prod 7" 6221'TVD 15,025'MD Calculation Packer production 15,189'RKB "G"cement)as 7/24/12 designed Section 11—Location of, Orientation of and Geological Data for Faults and Fractures that may Transect the Confining Zones 20 AAC 25.283(a)(11) • • CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that there are 7 mapped faults that transect the Kuparuk interval and enter the confining zone (Kalubik and HRZ) within one half mile radius of the wellbore trajectory for 2M-33. The 4 north-south trending faults and the 3 east-west trending faults around 2M-33 terminate within shales of the confining zone, and fault throw ranges between 5-45' (see table below). No mapped faults intersect the 2M-33 wellbore trajectory. Fracture gradients within the confining zone will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. Thickness and fracture pressure for the confining zone is discussed in Section 9. 2M-33 Area Faults Orientation Throw in Feet Fault #1 North-South 15-40' Fault #2 North-South 5-15' Fault #3 North-South 10-20' Fault #4 North-South 15-25' Fault #5 East-West 15-25' Fault #6 East-West 5-10' Fault #7 East-West 5-10' • Plat 2: 2M-33 Fault Analysis t;. . �► 03 ADL025571 Att1�?25a31' 1 I+ f l 7)21MADL390691A01025585ADL025587i ADL // 586 Miluveach Unit • A }l ApL340680 21.4 ADL025589 40025588 ADL025590 Kuparuk River Unit • i=raa Points Trajectory + ►Open Interval ADL025603 ADL025604 ADL02$805 Half Mile Frac Point Radius n Half Mile trajectory Radius Faults within Frac Point Radius Wells within Frac Pint Radius ConotoPhil lips � Kuparuk PAA, Alaska Inc, AK Unit - 2M-33 l (CPAI Leases Frac Plat ADL025+ 0 02 0.4 0"6 0.$ 1 1.2 1.4 Dl I $RPC Miles 5/17/2017 • • Section 12 - Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) 2M-33 was completed in 1996 as horizontal producer in the Kuparuk A sand formation. In 2010 the C-sand was perforated. The well was completed with 3.5" tubing and a 4.5" liner with perforations. A single stage frac will be pumped through the A and C sand perforations. / Proposed Procedure: Halliburton Pumping Services: (A & C Sand Frac) 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre existing conditions. 2. Ensure all Pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to 2,000' TVD. 3. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 4. MIRU 6 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100° F seawater (approx. 2,677 bbls are required for the treatment with breakdown, maximum pad, and 450 bbls usable volume per tank). 5. Ensure lift plan is reviewed and signed prior to RU of Frac equipment requiring lifts. 6. MIRU HES Frac Equipment. 7. PT Surface lines to 9,000 psi using a Pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Pump the 120 bbl breakdown stage (25# linear gel) according to the attached excel HES pump schedule. Bring pumps up to maximum rate of 18 BPM as quick as possible, pressure permitting. Increase annulus pressure to 2,500 psi. Ensure sufficient volume is pumped to load the well with Frac fluid, prior to shut down. 10. Perform a hard shut down, Obtain ISIP and fluid efficiency estimates. 11. Pump the Frac job by following schedule with a maximum expected treating pressure of 6,530 psi. S Section 13 - Post-Fracture Wellbore Cleanup and Fluid Recovery Plan 20 AAC 25.283(a)(13) Flowback will be initiated through a third party flowback vendor until the fluids clean up at which time it will be turned over to production. 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String ID...Top(RKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd CONDUCTOR 16 15.062 41.0 121.0 121.0 62.58 H-40 WELDED Casing Description String 0... String ID...Top(RKB) Set Depth(f...Set Depth(ND)...String Wt...String...String Top Thrd SURFACE 95/8 8.835 40.5 4,873.6 2,789.2 40.00 L-80 BTC Casing Description String 0... String ID...Top(RKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd PRODUCTION 7 6.276 38.3 16,330.7 6,227.8 26.00 L-80 BTC-MOD 9 7 Tubing Strings Tubing Description String 0... String ID_.Top(RKB) Set Depth(f...Set Depth(ND)...String Wt...String...String Top Thrd I TUBING 31/2 2.992 36.0 15,493.7 6,123.3 9.30 L-80 EUE8rdMOD Completion Details Top Depth CONDUCTOR, (ND) Top Incl Nomi... 41-121 Top(RKB) (RKB) (°) Item Description Comment ID(in) MK 36.0 36.0 -7.20 HANGER FMC GEN IV TUBING HANGER 3.500 NIPPLE.484nr 484.3 483.6 7.74 NIPPLE CAMCO DS NIPPLE w/NO GO PROFILE 2.812 ,t 15,180.8 6,049.8 73.14 NIPPLE CAMCO W NIPPLE w/NO GO PROFILE 2.812 15,188.8 6,050.3 72.69 PACKER BAKER SAB-3 PACKER w/K22 ANCHOR SEAL ASSEMBLY 3.000 15,205.8 6,055.8 73.08 NIPPLE CAMCO D NIPPLE w/NO GO PROFILE 2.750 15,493.0 6,123.2 80.54 WLEG BAKER WIRELINE RE-ENTRY GUIDE 3.000 Perforations&Slots SURFACE, A -.i II. Shot 41-4,874 Top(ND) Btm(TVD) Dens Top(RKB)Btm(RKB) (RKB) (RKB) Zone Date (Sir.- Typo Comment 15,580.0 15,600.0 6,136.9 6,139.9 C-4,2M-33 8/13/2010 6.0 APERF Millenium guns,60 deg phase GAS LIFT, 4,996 15,600.0 15,620.0 6,139.9 6,142.8 C-4,UNIT B,A-4,8/122010 6.0 APERF Millenium guns,60 deg phase 2M-33 15,760.0 16,160.0 6,160.7 6,208.3 A-3,2M-33 7/26/1996 4.0(PERF 4 1/2"TCP;180 deg.phase GAS 7,956 LIFT, 16,194.0 16,235.0 6,212.2 6,216.9 A-3,2M-33 7/26/1996 4.0 IPERF 4 12"TCP;180 deg.phase Notes:General&Safety End Date Annotation GAS LIFT. ^..�, 11/17/2010 NOTE:VIEW SCHEMATIC w/Alaska Schematic9.0 9,871 GAS LIFT, 11,496 f l°- GAS12LIFT, ,902 GAS LIFT, 14,149 1 GAS LIFT, 1s,u2 11.----,, NIPPLE,15,181 PACKER ' ��--�-.-� , 15,189 '.- .:. , NIPPLE.15.206 WLEO,15493 APERF, n 15,580.15,600 APERF, I 15,600-15,620 AU X IPERF. a. _ Mandrel Details 15.760-16.180 1. Top Depth Top Port (ND) Incl OD Valve Latch Size TRO Run Stn Top(ttKB) (RKB) (') Make Model (in) Sem Type Type (in) (psi) Run Date Corn... 1 4,995.6 2,828.2 70.86 CAMCO KBMM 1 GAS LIFT GLV BK5 0.156 1,300.0 8/8/2010 2 7,956.3 3,743.9 69.12 CAMCO KBMM 1 GAS LIFT GLV BK5 0.156 1,292.0 8/8/2010 IPERF. _ 16,194-16,235 3 9,870.6 4,336.5 72.86 CAMCO KBMM 1 GAS LIFT GLV BK5 0.188 1,318.0 8/7/2010 _ 4 11,495.6 4,855.2 71.46 CAMCO KBMM 1 GAS LIFT OV BK5 0.250 0.0 8/7/2010 5 12,901.8 5,322.3 70.34 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 4232002 TD,1Q340 6 14,149.5 5,722.6 72.16 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 11/7/1996 7 15,142.4 6,038.4 72.86 CAMCO KBMM 1 GAS LIFT DMY BK5 0.000 0.0 4232002 PRODUCTION, 38-1Q340 ' • i 4J4 /'Ji Oto a=-+ f0 Q = ++ CO N - N N Q L _ O 4-, in cp CU CI) o o 0 CU o N �) OA o c L CO h I\ :(-1.-).-- a) 0 O - 2 O I i v c" 2 v -- f0 O N v a "_ _c o - " Q. c Q. 00 4-, (N '� Q. O — 0 = acro CL CU ; •� v � � CY) To cu O L, N 0 M v C 2 °' E 45 2 f0 %—io N N c f0 U N f0 O : c E m f0 0 CO •D vii 0 c > N .+-, � Q_ _ H LO CO •_ a) LJ LJ "0 N N o v L- C v c c _ N c N _ a f0 v Etta) _C U }, D .n o +., c ,-, 4- -0 0 0 o v o 0 CN Z o IX C L_ E N •-0 D (0 Ti) N • E N (13 •Q U co �O .� L a) u 1-- .N Q. m c MD CO N ci 0 . • Bettis, Patricia K (DOA) From: Pedam, Sandeep <Sandeep.Pedam@conocophillips.com> Sent: Tuesday, July 11, 2017 4:01 PM To: Bettis, Patricia K (DOA) Cc: Neville, David J; Gross, Ben Subject: RE: [EXTERNAL] KRU 2M-33 (PTD 196-072): Hydraulic Frac Sundry Application Patricia, Thank you for your email. Please see answers to your questions below: #1: The 2M-33 wellbore did not penetrate the Miluveach Shale. #2: Please see below,we've included it per your request. Could you please let us know if this information has already been provided with the permit to drill? Well 2M-33 Footages Location FNL FEL Township Range Section Meridian Surface 5165' 4914' T11N R8E 27 Umiat Top Open Interval 3350' 4709' T1ON R8E 5 Umiat Bottomhole 3814' 25' T1ON R8E 6 Umiat #3: The general SHmax stress orientation in this area of the field is North-South and it is expected that the fractures will propagate in this orientation. If there are indications that a fracture has intersected a fault during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. CPAI has formed the opinion, based on seismic, well and other subsurface information currently available that the apparent faults will not interfere with containment. #4:There were no losses encountered while drilling. Thanks and hope you have a nice day, Regards, Sandeep From: Bettis, Patricia K(DOA) [mailto:patricia.bettis@alaska.gov] Sent: Friday,July 07, 2017 2:21 PM To: Pedam, Sandeep<Sandeep.Pedam@conocophillips.com> Subject: [EXTERNAL] KRU 2M-33 (PTD 196-072): Hydraulic Frac Sundry Application Good afternoon Sandeep, Please provide the following information for the sundry application: 1. Did KRU 2M-33 penetrate the Miluveach Shale? 2. Please provide the legal description of the well (surface,top production interval and bottomhole locations) include township, range and section, and footage from section lines. • 3. Discuss the principle horizontal stress orientation of the area. Which direction would the induced hydraulic fractures propagate? Based on mapping in the area,will the fracture wings extend into the faults or suspected faults? If the hydraulic fracture wings intersect faults or suspected faults,what would be ConocoPhillips' mitigation plan to halt fluid leakage into the fault zones(s)? 4. Discuss any occurrences of lost circulation in KRU 2M-33. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Ste 100 Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 2 • Wallace, Chris D (DOA) From: Pedam, Sandeep <Sandeep.Pedam@conocophillips.com> Sent: Tuesday, July 11, 2017 4:02 PM To: Wallace, Chris D (DOA) Subject: RE: [EXTERNAL] Hydraulic Fracturing Application Sundry 317-302 2M-33 (PTD 1960720) Attachments: 2M-33 Frac Dimensions_2.pdf Chris, Thank you for your email. Please see answers to your questions below: 20 AAC 25.283(a)(12)(F) requires the fractures, height, length, MD, and TVD to top and description of fracturing model use. Please provide. I've attached a pdf with this information 20 AAC 25.283(a)(8) requires pressure ratings and schematics of wellbore, wellhead, BOPE, treating head. The application has a schematic of the Oil States tree saver but this has no rating? Possibly 15,000 psi? My apologies for not including this earlier. You're right, it's 15,000 psi. Also, the sundry application is missing the Box 14: Estimated date for commencing operations. I can add that in if provided. Current start date estimate for 2M-33 is Sep 18, 2017. Thanks and hope you have a nice day, Sandeep From:Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent:Wednesday,July 05, 2017 2:51 PM To: Pedam,Sandeep<Sandeep.Pedam@conocophillips.com> Subject: [EXTERNAL] Hydraulic Fracturing Application Sundry 317-302 2M-33 (PTD 1960720) Sandeep, We are reviewing the Frac stimulation sundry for 2M-33. 20 AAC 25.283(a)(12)(F) requires the fractures, height, length, MD, and TVD to top and description of fracturing model use. Please provide. 20 AAC 25.283(a)(8) requires pressure ratings and schematics of wellbore, wellhead, BOPE, treating head. The application has a schematic of the Oil States tree saver but this has no rating? Possibly 15,000 psi? Also, the sundry application is missing the Box 14: Estimated date for commencing operations. I can add that in if provided. Please provide at your earliest so we can progress the sundry application. • • Bettis, Patricia K (DOA) From: Pedam, Sandeep <Sandeep.Pedam@conocophillips.com> Sent: Friday,July 7, 2017 2:21 PM To: Bettis, Patricia K(DOA) Subject: Automatic reply: [EXTERNAL] KRU 2M-33 (PTD 196-072): Hydraulic Frac Sundry Application Please note that I will be out of the office(on vacation)until July 9th and will have no access to email and cell phone during this time. Regards, Sandeep Pedam Completions Engineer ConocoPhillips Alaska Office:(907)263-4724 Cell:(512) 507-9537 Sandeep.Pedam@ ConocoPhillips.com 1 • Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Friday, July 7, 2017 2:21 PM To: Sandeep.Pedam@conocophillips.com Subject: KRU 2M-33 (PTD 196-072): Hydraulic Frac Sundry Application Good afternoon Sandeep, Please provide the following information for the sundry application: 1. Did KRU 2M-33 penetrate the Miluveach Shale? 2. Please provide the legal description of the well (surface,top production interval and bottomhole locations) include township, range and section, and footage from section lines. 3. Discuss the principle horizontal stress orientation of the area. Which direction would the induced hydraulic fractures propagate? Based on mapping in the area,will the fracture wings extend into the faults or suspected faults? If the hydraulic fracture wings intersect faults or suspected faults,what would be ConocoPhillips' mitigation plan to halt fluid leakage into the fault zones(s)? 4. Discuss any occurrences of lost circulation in KRU 2M-33. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Ste 100 Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Wednesday, July 5, 2017 2:51 PM To: sandeep.pedam@conocophillips.com Subject: Hydraulic Fracturing Application Sundry 317-302 2M-33 (PTD 1960720) • Sandeep, We are reviewing the Frac stimulation sundry for 2M-33. 20 AAC 25.283(a)(12)(F) requires the fractures, height, length, MD, and TVD to top and description of fracturing model use. Please provide. 20 AAC 25.283(a)(8) requires pressure ratings and schematics of wellbore, wellhead, BOPE, treating head. The application has a schematic of the Oil States tree saver but this has no rating? Possibly 15,000 psi? Also, the sundry application is missing the Box 14: Estimated date for commencing operations. I can add that in if provided. Please provide at your earliest so we can progress the sundry application. Thanks and Regards, Chris Wallace,Sr. Petroleum Engineer,Alaska Oil and Gas Conservation Commission,333 West 7th Avenue,Anchorage,AK 99501, (907)793-1250(phone), (907) 276-7542(fax),chris.wallace@alaska.gov CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. LOG rAL AN mir 0. W WELL L DATA LOGGED /2.t/2017 PROACTIVE PROACTIVE DIAGNOSTIC SERVICES, INC. M. K. BENDER To: AOGCC RECEIVED Makana Bender 333 West 7th Avenue Suite 100 JUN 13 2017 Anchorage, Alaska 99501 (907) 793-1225 AOGCC RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: ProActive Diagnostic Services, Inc. Attn: Ryan C. Rupe 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 SCANNED AIN 2 2 2_017, 1) Caliper Report 28-May-17 2M-33 1 Report /CD 50-103-20240-00 2) Signed : / valeiSze.0 / Date : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGE@MEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM D:\Achives\MasterTemplateFi Ie s\Templates\Di stribution\Transmittal Sheets\ConocoPhil I ip s_Transmit.docx t -D12, RRECEIVED • 276,2°11 JUN 13 2017 Memory Multi-Finger Caliper AOGCC Log Results Summary Company: ConocoPhillips Alaska, Inc. Well: 2M-33 Log Date: May 28, 2017 Field: Kuparuk Log No.: 14827 State: Alaska Run No.: 1 API No. 50-103-20240-00 Pipe Description: 3.5 inch 9.3 lb. L-80 EUE 8RD MOD Top Log Interval: Surface Pipe Use: Tubing Bottom Log Interval: 15,143 Ft. (MD) Inspection Type : Corrosive and Mechanical Damage Inspection COMMENTS : This caliper data is tied into the top of GLM 7 at 15,142 feet(Driller's Depth). This log was run to assess the condition of the tubing with respect to internal corrosive and mechanical damage. The caliper recordings indicate the 3.5 inch tubing logged appears to be in good to fair condition, with a maximum recorded wall penetration of 25% in a line of corrosion in joint 106 (3,425 ft). No significant areas of cross-sectional wall loss or I.D. restrictions are recorded throughout the tubing logged. MAXIMUM RECORDED WALL PENETRATIONS : 0, c,o;iid)t; f'El CF C f Line Corrosion 25 106 3,425 Ft. (MD) Line Corrosion 25 200 6,410 Ft. (MD) Line Corrosion 24 131 4,238 Ft. (MD) Line Corrosion 24 123 3,980 Ft. (MD) Line Corrosion 23 199 6,372 Ft. (MD) MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (>6%)are recorded throughout the tubing logged. MAXIMUM RECORDED ID RESTRICTIONS : No significant I.D. restrictions are recorded throughout the tubing logged. T. Leckband C. Waldrop J. Fama F nguleer(s) tts? ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565-9085 Fax (281) 431-7125 E-mail: PDSAnalysis@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax (907) 659-2314 • . Correlation of Recorded Damage to Borehole Profile II Pipe 1 3.5 in (97.6'-15,143.4') Well: 2M-33 Field: Kuparuk Company: ConocoPhillips Alaska,Inc. Country: USA Survey Date: May 28, 201 7 ■ Approx.Tool Deviation ■ Approx.Borehole Profile 1 101 50 1,654 100 3,232 GLM 1 150 4,812 200 6,399 a _a ti GLM 2 Z 250 7,986 .c GLM 3 300 9,572 350 • 11,158 GLM 4 GLM 5 400 - 12,749 GLM 6 450 14,347 GLM 7 474.1 15,142 0 50 100 Damage Profile(%wall)/Tool Deviation (degrees) Bottom of Survey=474.1 • • PDS Report Overview 4-4 Body Region Analysis Well: 2M-33 Survey Date: May 28,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pi.e 3.5 in. 9.3 ..f L-80 EUE 8RD MOD Analyst: C.Waldrop Pipe Nom.OD Weight Grade&Thread Nom.ID Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD 2.992 in. 98 ft. 15,143 ft. Penetration (%wall) Damage Profile(%wall) 500 Emi Penetration body Metal loss body 0 50 100 0.1 400 300 49 200 99 100 0 149 0 to 20 to 40 to over GLM 1 (4:00) 20% 40% 85% 85% Number of joints analyzed(total=475) 441 34 0 0 198 Damage Configuration(body) GLM 2 (2:00) 218 ' 150 297 — GLM 3 (2:00) 100 346 GLM 4(7:00) 50 395 GLM 5 (10:00) 0 Isolated General Line Other Hole/ GLM 6(10:00) Pitting Corrosion Corrosion Damage Pos.Hole Number of joints damaged(total= 144) GLM 7 19 0 125 0 0 Bottom of Survey=474.1 • • PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28, 2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 0.1 98 0 0.03 13 0 2.93 Pup Lt. Deposits. 1 101 0 0.03 13 2 2.91 Lt. Deposits. • 2 132 0 0.03 13 2 2.91 Lt. Deposits. wi 3 163 0 0.03 13 2 2.91 Lt. Deposits. • 4 195 0 0.03 12 4 2.90 Lt. Deposits. • 5 226 0 0.03 12 2 2.92 Lt. Deposits. • 6 258 0 0.03 10 2 2.92 Lt. Deposits. • 7 290 0 0.04 14 2 2.92 Lt. Deposits. • 8 321 0.04 0.04 15 2 2.92 Shallow Line of Pits.Lt. Deposits. mi 9 353 0,04 0.03 11 2 2,90 Lt. Deposits. • 10 384 0 0.03 11 2 2.92 Lt. Deposits. • 11 416 0 0.04 16 2 2.92 Shallow Line of Pits.Lt. Deposits. ■ 12 448 0 0.03 13 2 2.92 Lt. Deposits. im 13 479 0.05 0.04 14 2 2.91 Lt. Deposits. • 14 511 0 0.04 15 2 2.90 Shallow Line of Pits.Lt. Deposits. 14.1 543 0 0 0 0 2.80 CAMCO DS NIPPLE NO GO 15 544 0.04 0.04 15 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 16 575 0 0.03 12 2 2.91 Lt. Deposits. • 17 607 0 0.04 17 2 2.92 Shallow Line of Pits.Lt. Deposits. a 18 639 0 0.03 11 2 2.93 Lt. Deposits. • 19 671 0 0.04 14 , 2 2.91 Lt. Deposits. • 20 702 0 0.03 13 3 2.93 Lt. Deposits. • 21 734 0.04 0.02 9 2 2.92 Lt. Deposits. 22 766 0 0.02 9 2 2.92 Lt. Deposits. 23 798 0 0.04 15 2 2.91 Shallow Pitting. Lt.Deposits. ■ 24 829 0 0.03 11 2 2.92 Lt. Deposits. • 25 861 0 0.03 10 2 2.92 Lt. Deposits. • 26 893 0 0.03 11 2 2.91 Lt. Deposits. • 27 925 0 0.03 11 2 2.92 Lt. Deposits. • 28 956 0 0.03 10 2 2.91 Lt. Deposits. 29 988 0 0.02 8 2 2.92 Lt. Deposits. 30 1020 0 0.03 11 2 2.92 Lt. Deposits. • 31 1052 0 0.03 11 2 2.91 Lt. Deposits. • 32 1083 0 0.03 13 2 2.92 Lt. Deposits. , 33 1115 0 0.03 10 2 2.93 Lt. Deposits. 34 1147 0 0.03 10 2 2.92 Lt. Deposits. 35 1178 0 0.03 11 2 2.92 Lt. Deposits. • 36 1210 0 0.03 10 2 2.93 Lt. Deposits, 37 1242 0 0.03 10 2 2.91 Lt. Deposits. li 38 1273 0 0.02 8 2 2.93 Lt. Deposits. 39 1305 0 0.04 15 2 2.92 Shallow Pitting. Lt.Deposits. 40 133 7 0 0.02 9 2 2.92 Lt. Deposits. 41 1368 0 0.04 15 2 2.92 Shallow Line of Pits.Lt. Deposits. 11 42 1400 0 0.03 10 2 2.92 Lt. Deposits. r 43 1432 0 0.04 14 2 2.92 Lt. Deposits. • 44 1464 0 0.03 11 2 2.91 Lt. Deposits. • 45 1495 0 0.03 10 2 2.92 Lt. Deposits. 11 46 1527 0 0.03 10 2 2.92 Lt. Deposits. J 47 1559 0 0.03 11 2 2.92 Lt. Deposits. • 48 1591 0 0.03 13 2 2.93 Lt. Deposits. Penetration Body Metal Loss Body Page 1 • S 1111 CI PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28, 2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 49 1622 0 0.03 11 2 2.93 Lt. Deposits. ■ 50 1654 0 0.03 11 3 2.91 Lt. Deposits. 51 1686 0 0.03 12 2 2.93 Lt. Deposits. 52 171 7 0 0.03 11 2 2.92 Lt. Deposits. ■ 53 1749 0 0.03 11 2 2.93 Lt. Deposits. 54 1781 0 0.03 12 2 2.93 Lt. Deposits. 55 1813 0 0.03 10 2 2.93 Lt. Deposits. 56 1844 0 0.03 10 2 2.93 Lt. Deposits. ■ 57 1876 0 0.04 15 2 2.93 Shallow Line of Pits.Lt. Deposits. 58 1908 0 0.03 10 2 2.92 Lt. Deposits. 59 1940 0 0.04 15 2 2.93 Shallow Pitting. Lt.Deposits. ■ 60 1971 0 0.03 12 3 2.93 61 2001 0 0.03 13 2 2.92 Lt. Deposits. 62 2030 0 0.03 12 2 2.92 Lt. Deposits. 63 2062 0 0.04 15 3 2.91 Shallow Line of Pits.Lt. Deposits. 64 2093 0 0.03 13 2 2.92 Lt. Deposits. 65 2125 0 0.03 13 3 2.92 Lt. Deposits. ■ 66 2157 0 0.04 17 4 2.93 Shallow Line of Pits. ■ 67 2188 0 0.04 16 2 2.93 Shallow Line of Pits.Lt. Deposits. ■ 68 2220 0 0.04 14 3 2.92 Lt. Deposits. 69 2252 0 0.04 14 3 2.92 Lt. Deposits. 70 2283 0 0.04 15 2 2.92 Shallow Line of Pits.Lt. Deposits. 71 2315 0 0.04 14 3 2.93 Lt. Deposits. 72 2346 0 0.04 16 2 2.91 Shallow Line of Pits.Lt. Deposits. 73 2378 0 0.05 19 3 2.93 Shallow Line Corrosion.Lt. Deposits. ■ 74 2410 0 0.05 18 2 2.92 Shallow Line of Pits.Lt. Deposits. 75 2441 0 0.04 15 4 2.92 Shallow Line of Pits.Lt. Deposits. 76 2473 0 0.05 19 4 2.92 Shallow Line of Pits.Lt. Deposits. 77 2505 0 0.03 12 2 2.93 Lt. Deposits. ■ 78 2536 0 0.04 14 3 2.93 Lt. Deposits. ■ 79 2568 0 0.05 19 5 2.91 Shallow Line of Pits.Lt. Deposits. ■ 80 2599 0 0.05 20 3 2.92 Line Corrosion. Lt.Deposits. ■ 81 2631 0 0.04 15 2 2.90 Shallow Line of Pits.Lt. Deposits. ■ 82 2663 0 0.04 17 3 2.93 Shallow Line of Pits.Lt. Deposits. 83 2694 0 0.04 16 3 2.93 Shallow Line of Pits.Lt. Deposits. 84 2726 0 0.04 15 2 2.92 Shallow Pitting. Lt.Deposits. 85 2758 0 0.04 14 2 2.93 Lt. Deposits. ■ 86 2789 0 0.05 19 4 2.92 Shallow Line Corrosion.Lt. Deposits. 87 2821 0 0.05 19 3 2.91 Shallow Line of Pits.Lt. Deposits. 88 2853 0 0.04 16 4 2.91 Shallow Line of Pits.Lt. Deposits. 89 2884 0 0.05 20 5 2.92 Line of Pits. Lt.Deposits. 90 2916 0.05 0.05 20 4 2.90 Isolated Pitting. Lt.Deposits. ■ 91 2947 0 0.05 18 3 2.92 Shallow Line Corrosion.Lt. Deposits. 92 2979 0 0.06 22 4 2.91 Line Corrosion. Lt.Deposits. 93 301 1 0.04 0.05 20 3 2.91 Line Corrosion. Lt.Deposits. 94 3042 0 0.05 19 4 2.92 Shallow Line Corrosion.Lt. Deposits. ■ 95 3074 0 0.04 14 2 2.92 Lt. Deposits. ■ 96 3106 0 0.03 13 3 2.90 Lt. Deposits. ■ 97 3137 0 0.05 19 4 2.91 Shallow Line Corrosion.Lt. Deposits. 98 3169 0 0.04 15 2 2.91 Shallow Pitting. Lt.Deposits. IPenetration Body Metal Loss Body Page 2 • • PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28, 2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 99 3201 0.04 0.04 15 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 100 3232 0.05 0.05 21 4 2.91 Line Corrosion. Lt.Deposits. ■ 101 3264 0 0.05 19 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 102 3296 0 0.04 14 3 2.90 Lt. Deposits. ■ 103 332 7 0.04 0.05 18 4 2.91 Shallow Line Corrosion.Lt. Deposits. ■ 104 3359 0 0.03 12 2 2.91 Lt. Deposits. ■ 105 3390 0 0.04 14 4 2.92 Lt. Deposits. ■ 106 3422 0 0.06 25 6 2.91 Line Corrosion. Lt.Deposits. ■ 107 3454 0.04 0.04 17 4 2.90 Shallow Line of Pits.Lt. Deposits. ■ 108 3486 0 0.06 22 4 2.91 Line Corrosion. Lt.Deposits. ■ 109 3517 0 0.04 15 3 2.90 Shallow Pitting. Lt.Deposits. ■ 110 3549 0 0.05 . 20 3 2.91 Isolated Pitting. Lt.Deposits. ■ 111 3580 0 0.05 , 18 3 2.91 Shallow Line of Pits.Lt. Deposits. ■ 112 3612 0 0.06 22 5 2.92 Line Corrosion. Lt.Deposits. ■ 113 3643 0 0.04 14 3 2.90 Lt. Deposits. ■ 114 3675 0 0.05 20 6 2.91 Line Corrosion. Lt.Deposits. ■ 115 3707 0 0.05 19 4 2.92 Shallow Line Corrosion.Lt. Deposits. ■ 116 3738 0 0.05 18 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 117 3770 0.05 0.05 20 4 2.90 Line Corrosion. Lt.Deposits. ■ 118 3801 0 0.04 14 3 2.92 Lt. Deposits. ■ 119 3833 0.04 0.04 16 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 120 3865 0.04 0.03 13 3 2.94 ■ 121 3896 0 0.04 17 2 2.92 Shallow Line of Pits.Lt. Deposits. ■ 122 3928 0 0.03 10 2 2.91 Lt. Deposits. ■ 123 3959 0 0.06 24 5 2.91 Line Corrosion. Lt.Deposits. ■ 124 3992 0.04 0.04 15 3 2.90 Shallow Line of Pits.Lt. Deposits. ■ 125 4023 0.04 0.04 15 3 2.90 Shallow Line of Pits.Lt. Deposits. ■ 126 4055 0 0.05 . 19 3 2.91 Shallow Line Corrosion.Lt. Deposits. ■ 127 4086 0 0.04 17 3 2.93 Shallow Line of Pits. ■ 128 4118 0 0.04 14 2 2.93 Lt. Deposits. ■ 129 4149 0.04 0.05 20 4 2.93 Line Corrosion. Lt.Deposits. ■ 130 4181 0.04 0.04 15 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 131 4213 0 0.06 24 4 2.93 Line Corrosion. Lt.Deposits. ■ 132 4244 0.05 0.05 21 3 2.91 Line Corrosion. Lt.Deposits. ■ 133 4276 0 0.05 19 4 2.92 Shallow Line Corrosion.Lt. Deposits. ■ 134 4307 0 0.05 18 4 2.90 Shallow Line Corrosion.Lt. Deposits. ■ 135 4339 0.05 0.05 19 3 2.93 Shallow Line of Pits. ■ 136 4369 0.04 0.06 22 5 2.89 Line Corrosion. Lt.Deposits. ■ 137 4400 0 0.05 21 4 2.91 Line Corrosion. Lt.Deposits. ■ 138 4433 0.05 0.04 15 2 2.94 Shallow Line of Pits. ■ 139 4464 0 0.04 17 3 2.91 Shallow Line Corrosion.Lt. Deposits. ■ 140 4496 0.05 0.06 23 5 2.91 Line Corrosion. Lt.Deposits. ■ 141 4527 0.04 0.04 17 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 142 4559 0 0.05 19 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 143 4591 0.05 0.05 21 4 2.93 Line Corrosion. Lt.Deposits. ■ 144 4622 0.05 0.04 17 3 2.92 Shallow Pitting. Lt.Deposits. ■ 145 4653 0 0.04 16 2 2.90 Shallow Line of Pits.Lt. Deposits. ■ 146 4685 0 0.03 13 3 2.91 Lt. Deposits. ■ 147 471 7 0.04 0.04 17 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 148 4748 0 0.03 13 3 2.90 Lt. Deposits. IPenetration Body Metal Loss Body Page 3 • • fLiii PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28, 201 7 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments ((V°wall) (in.) (in.) % (in.) 0 50 100 149 4781 0.04 0.05 20 4 2.93 Line Corrosion. ■ 150 4812 0 0.05 21 5 2.92 Line Corrosion. Lt.Deposits. ■ 151 4843 0 0.04 17 4 2.92 Shallow Pitting. Lt.Deposits. 152 4875 0 0.04 15 2 2.90 Shallow Line of Pits.Lt. Deposits. ■ 153 4907 0 0.04 15 2 2.90 Shallow Line of Pits.Lt. Deposits. ■ 154 4939 0 0.04 15 2 2.89 Shallow Line of Pits.Lt. Deposits. ■ 155 4970 0.05 0.04 14 2 2.91 Lt. Deposits. ■ 156 5002 0 0.06 23 4 2.91 Line Corrosion. Lt.Deposits. 156.1 5033 0 0 0 0 2.86 GLM 1 (LATCH @ 4:00) 157 5039 0.04 0.05 18 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 158 5071 0.04 0.04 14 3 2.91 Lt. Deposits. ■ 159 5103 0 0.04 17 4 2.91 Shallow Line Corrosion.Lt. Deposits. 160 5135 0.05 0.05 20 4 2.93 Line Corrosion. Lt.Deposits. ■ 161 5166 0 0.04 15 3 2.90 Shallow Line of Pits.Lt. Deposits. 162 5198 0 0.04 15 4 2.93 Shallow Line of Pits. 163 5229 0.04 0.04 17 4 2.93 Shallow Line of Pits.Lt. Deposits. 164 5261 0 0.03 13 2 2.93 Lt. Deposits. 165 5292 0 0.05 18 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 166 5325 0.05 0.05 21 3 2.93 Line of Pits. 167 5356 0 0.04 15 4 2.89 Shallow Line of Pits.Lt. Deposits. 168 5388 0.04 0.05 18 4 2.93 Shallow Line of Pits.Lt. Deposits. 169 5419 0 0.04 17 4 2.90 Shallow Line of Pits.Lt. Deposits. 170 5451 0.06 0.05 18 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 171 5482 0.05 0.06 22 3 2.92 Line Corrosion. Lt.Deposits. ■ 172 5514 0 0.05 19 4 2.93 Shallow Line of Pits.Lt. Deposits. ■ 173 5545 0 0.04 14 3 2.91 Lt. Deposits. 174 5578 0.04 0.05 21 4 2.92 Line Corrosion. Lt.Deposits. 175 5609 0.06 0.06 23 4 2.92 Line Corrosion. Lt.Deposits. 176 5641 0 0.04 14 2 2.92 Lt. Deposits. 177 5672 0 0.03 12 3 2.91 Lt. Deposits. 178 5704 0 0.04 14 4 2.92 Lt. Deposits. 179 5736 0.05 0.04 . 15 3 2.93 Shallow Line of Pits.Lt. Deposits. 180 5766 0 0.03 13 3 2.92 Lt. Deposits. 181 5798 0 0.03 . 12 3 2.93 Lt. Deposits. 182 5830 0 0.05 19 3 2.92 Shallow Line Corrosion.Lt. Deposits. 183 5861 0.05 0.06 23 4 2.92 Line Corrosion. Lt.Deposits. ■ 184 5893 0 0.04 17 3 2.92 Shallow Line of Pits.Lt. Deposits. 185 5924 0 0.04 16 4 2.90 Shallow Line of Pits.Lt. Deposits. 186 5956 0 0.05 21 5 2.92 Isolated Pitting. Lt.Deposits. ■ 187 5987 0 0.04 17 3 2.90 Shallow Line Corrosion.Lt. Deposits. ■ 188 6020 0.05 0.04 15 3 2.94 Shallow Line of Pits. 189 6051 0.04 0.04 15 2 2.92 Shallow Line of Pits.Lt. Deposits. 190 6082 0.04 0.04 16 4 2.93 Shallow Line Corrosion.Lt. Deposits. 191 6114 0.05 0.04 16 3 2.93 Shallow Line of Pits.Lt. Deposits. 192 6145 0 0.04 14 2 2.91 Lt. Deposits. 193 6178 0.04 0.05 19 4 2.93 Shallow Line Corrosion.Lt. Deposits. 194 6209 0.05 0.04 17 3 2.92 Shallow Line of Pits.Lt. Deposits. 195 6241 0.04 0.04 16 4 2.94 Shallow Line of Pits. ■ 196 6272 0.05 0.04 16 3 2.92 Shallow Line of Pits.Lt. Deposits. 197 6304 0.06 0.05 19 4 2.91 Shallow Line Corrosion.Lt. Deposits. IPenetration Body Metal Loss Body Page 4 • PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28, 201 7 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 198 6335 0.04 0.05 20 3 2.90 Line Corrosion. Lt.Deposits. 199 6367 0.04 0.06 23 5 2.94 Line Corrosion. ■ 200 6399 0.04 0.06 25 6 2.90 Line Corrosion. Lt.Deposits. 201 6431 0 0.03 12 3 2.90 Lt. Deposits. 202 6462 0 0.05 18 4 2.93 Shallow Line Corrosion. 203 6493 0 0.04 16 4 2.90 Shallow Line of Pits.Lt. Deposits. 204 6525 0 0.03 10 3 2.89 Lt. Deposits. 205 6557 0 0.03 11 2 2.94 • 206 6588 0 0.04 15 3 2.90 Shallow Line of Pits.Lt. Deposits. ■ 207 6620 0 0.03 12 3 2.93 Lt. Deposits. 208 6652 0 0.02 9 2 2.92 Lt. Deposits. • 209 6684 0 0.02 9 2 2.94 • 210 6715 0 0.03 12 2 2.92 Lt. Deposits. 211 6746 0 0.02 8 3 2.93 Lt. Deposits, 212 6778 0 0.04 16 3 2.91 Shallow Line of Pits.Lt. Deposits. 213 6810 0 0.03 10 2 2.92 Lt. Deposits. U 214 6842 0 0.03 11 2 2.91 Lt. Deposits. 215 6873 0 0.02 9 2 2.93 Lt. Deposits. 216 690 5 0 0.04 14 4 2.93 217 693 7 0 0.04 . 14 2 2.90 Lt. Deposits. 218 6969 0 0.03 13 4 2.92 Lt. Deposits. • 219 6999 0 0.03 12 2 2.92 Lt. Deposits. 220 7031 0 0.02 9 2 2.89 Lt. Deposits. • 221 7063 0 0.03 12 3 2.92 Lt. Deposits. 222 7095 0.04 0.03 12 2 2.93 Lt. Deposits. 223 7126 0 0.04 15 3 2.94 Shallow Pitting. 224 7158 0 0.03 11 3 2.91 Lt. Deposits. 225 7190 0 0.03 11 2 2.92 Lt. Deposits. mg 226 7221 0 0.03 10 2 2.93 227 7253 0 0.03 13 2 2.92 Lt. Deposits. • 228 7285 0 0.03 13 2 2.94 229 7316 0 0.02 9 2 2.91 Lt. Deposits. 230 7348 0 0.03 10 2 2.92 Lt. Deposits. 231 7379 0 0.04 15 4 2.91 Shallow Pitting. Lt.Deposits. 232 7411 0 0.02 9 3 2.93 • 233 7442 0 0.02 9 2 2.92 Lt. Deposits. 234 7475 0 0.04 15 3 2.93 Shallow Line of Pits.Lt. Deposits. 235 7506 0 0.04 14 2 2.92 Lt. Deposits. 236 7537 0 0.03 11 2 2.91 Lt. Deposits. 237 7570 0 0.03 11 2 2.93 Lt. Deposits. 238 7601 0 0.04 17 4 2.93 Shallow Line of Pits.Lt. Deposits. ■ 239 7632 0 0.05 21 2 2.92 Line Corrosion. Lt.Deposits. 240 7664 0 0.03 11 2 2.90 Lt. Deposits. 241 7697 0 0.04 . 17 3 2.93 Shallow Line of Pits. 242 7728 0 0.04 14 3 2.95 • 243 7760 0 0.03 12 2 2.92 Lt. Deposits. 244 7791 0 0.02 9 2 2.93 Lt. Deposits. • 245 7823 0 0.02 8 2 2.92 Lt. Deposits, • 246 7854 0.04 0.04 15 2 2.93 Shallow Line of Pits.Lt. Deposits. 247 7886 0 0.03 13 2 2.91 Lt. Deposits. IPenetration Body Metal Loss Body Page 5 • . ili PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 248 7919 0 0.04 15 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 249 7948 0.05 0.04 14 3 2.92 Lt. Deposits. 249.1 7980 0 0 0 0 2.88 GLM 2(LATCH @ 2:00) 250 7986 0 0.04 17 5 2.92 Shallow Line of Pits.Lt. Deposits. ■ 251 8018 0 0.03 12 2 2.92 Lt. Deposits. • 252 8050 0 0.03 12 2 2.90 Lt. Deposits. • 253 8082 0 0.03 11 2 2.91 Lt. Deposits. N 254 8114 0 0.04 14 _ 2 2.89 Lt. Deposits. • 255 8145 0 0.03 13 2 2.90 Lt. Deposits. I 256 8177 0 0.03 13 3 2.90 Lt. Deposits. • 257 8209 0 0.04 15 2 2.90 Shallow Line of Pits.Lt. Deposits. ■ 258 8240 0 0.03 10 2 2.91 Lt. Deposits. • 259 8272 0 0.04 15 2 2.90 Shallow Pitting. Lt.Deposits. 260 8304 0 0.02 7 1 2.91 Lt. Deposits. 261 8336 0 0.03 11 2 2.90 Lt. Deposits. • 262 8368 0 0.03 . 11 2 2.92 Lt. Deposits. • 263 8399 0 0.03 13 2 2.88 Lt. Deposits. • 264 8431 0 0.04 15 2 2.90 Shallow Pitting. Lt.Deposits. • 265 8463 0 0.04 14 2 2.90 Lt. Deposits. EI 266 8495 0 0.02 9 3 2.91 Lt. Deposits. J 267 852 7 0 0.03 11 2 2.91 Lt. Deposits. si 268 8558 0 0.03 13 4 2.91 Lt. Deposits. • 269 8590 0 0.03 12 2 2.90 Lt. Deposits. • 270 8622 0 0.03 10 2 2.91 Lt. Deposits. • 271 8654 0 0.03 11 2 2.91 Lt. Deposits. • 272 8686 0.04 0.03 13 2 2.89 Lt. Deposits. 273 8717 0 0.02 8 2 2.90 Lt. Deposits. 274 8749 0 0.03 11 2 2.90 Lt. Deposits. • 275 8781 0 0.03 13 2 2.89 Lt. Deposits. • 276 8812 0 0.03 12 2 2.91 Lt. Deposits. IN 277 8844 0 0.03 10 2 2.90 Lt. Deposits. 278 8876 0 0.02 9 2 2.90 Lt. Deposits. 279 8907 0 0.04 14 2 2.90 Lt. Deposits. • 280 8939 0 0.04 14 2 2.91 Lt. Deposits. 281 8971 0 0.02 9 2 2.92 Lt. Deposits. 282 9002 0 0.03 13 2 2.90 Lt. Deposits. • 283 9034 0 0.03 11 2 2.90 Lt. Deposits. as 284 9066 0 0.03 11 2 2.91 Lt. Deposits. • 285 9097 0 0.02 9 2 2.90 Lt. Deposits. 286 9129 0 0.02 9 2 2.91 Lt. Deposits. 287 9161 0 0.02 9 2 2.91 Lt. Deposits. • 288 9192 0 0.03 12 2 2.90 Lt. Deposits. • 289 9224 0 0.03 11 2 2.90 Lt. Deposits. • 290 9256 0.04 0.03 11 2 2.92 Lt. Deposits. • 291 9288 0 0.03 13 2 2.89 Lt. Deposits. • 292 9319 0 0.03 11 3 2.90 Lt. Deposits. 293 9351 0 0.02 9 2 2.90 Lt. Deposits. 294 9383 0 0.02 9 2 2.89 Lt. Deposits. 295 9414 0 0.02 8 2 2.90 Lt. Deposits. 296 9446 0 0.03 11 4 2.90 Lt. Deposits. Penetration Body Metal Loss Body Page 6 • ! I Mme. PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28,201 7 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 297 9477 0 0.03 11 2 2.91 Lt. Deposits. 298 9509 0 0.02 9 2 2.92 Lt. Deposits. 299 9540 0 0.03 12 2 2.92 Lt. Deposits. 300 9572 0 0.04 15 2 2.91 Shallow Pitting. Lt.Deposits. 301 9604 0 0.03 10 2 2.92 Lt. Deposits. 302 9635 0 0.03 13 2 2.92 Lt. Deposits. r 303 9667 0 0.03 10 2 2.90 Lt. Deposits, r 304 9697 0 0.03 11 2 2.91 Lt. Deposits. • 305 9729 0 0.03 10 2 2.91 Lt. Deposits. 306 9761 0 0.03 13 2 2.91 Lt. Deposits. 307 9792 0 0.03 12 2 2.91 Lt. Deposits. 308 9824 0 0.03 11 2 2.91 Lt. Deposits. • 309 9856 0 0.02 9 2 2.90 Lt. Deposits. U 309.1 9888 0 0 0 0 2.86 GLM 3(LATCH @ 2:00) 310 9894 0 0.04 14 3 2.90 Lt. Deposits. 311 9926 0 0.03 11 2 2.92 Lt. Deposits. 312 9957 0 0.03 12 2 2.92 Lt. Deposits. • 313 9989 0 0.04 15 4 2.91 Shallow Line of Pits.Lt. Deposits. 314 10021 0 0.02 9 3 2.90 Lt. Deposits. 315 10052 0 0.02 8 3 2.92 Lt. Deposits. 316 10084 0 0.03 11 2 2.90 Lt. Deposits. 317 101 16 0 0.02 9 2 2.92 Lt. Deposits. U 318 10147 0 0.03 10 2 2.90 Lt. Deposits. • 319 10178 0 0.03 11 3 2.93 Lt. Deposits. • 320 10210 0 0.03 11 2 2.90 Lt. Deposits. • 321 10242 0 0.03 11 2 2.90 Lt. Deposits. • 322 10274 0 0.03 13 2 2.90 Lt. Deposits. U 323 10305 0 0.03 12 3 2.90 Lt. Deposits. 111 • 324 10337 0 0.03 13 2 2.92 Lt. Deposits. 325 10369 0 0.03 10 2 2.92 Lt. Deposits. • 326 10400 0 0.04 14 2 2.91 Lt. Deposits. im 327 10432 0 Q.03 13 2 2.92 Lt. Deposits. 328 10463 0 0.03 11 3 2.92 Lt. Deposits. 329 10495 0 0.03 11 2 2.91 Lt. Deposits. • 330 10527 0 0.03 12 2 2.91 Lt. Deposits. • 331 10558 0 0.03 11 2 2.91 Lt. Deposits. • 332 10589 0 0.02 9 3 2.90 Lt. Deposits. 333 10621 0 0.03 12 3 2.92 Lt. Deposits. • 334 10652 0 0.03 11 2 2.90 Lt. Deposits. ■ 335 10684 0 0.02 9 2 2.92 Lt. Deposits. 336 10716 0 0.03 12 2 2.89 Lt. Deposits. 337 10748 0 0.03 12 3 2.91 Lt. Deposits. 338 10778 0 0.03 12 2 2.90 Lt. Deposits. 111. 339 10810 0 0.04 17 2 2.91 Shallow Line of Pits.Lt. Deposits. 340 10842 0 0.03 12 2 2.90 Lt. Deposits. • 341 10873 0 0.03 11 2 2.91 Lt. Deposits. 342 10905 0 0.03 11 2 2.90 Lt. Deposits. 343 10937 0 0.02 9 2 2.91 Lt. Deposits. 111 344 10969 0 0.04 15 2 2.91 Shallow Line Corrosion.Lt. Deposits. 345 11000 0 0.03 12 2 2.90 Lt. Deposits. IPenetration Body Metal Loss Body Page 7 • • 11111 PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 346 11032 0 0.03 13 2 2.91 Lt. Deposits. In 347 11064 0 0.04 15 3 2.93 Shallow Line of Pits.Lt. Deposits. 348 11095 0 0.03 12 3 2.91 Lt. Deposits. 349 11127 0 0.03 . 12 3 2.91 Lt. Deposits. 350 11158 0 0.02 9 3 2.92 Lt. Deposits. 351 11190 0 0.02 9 2 2.92 Lt. Deposits. 352 11222 0 0.03 11 2 2.91 Lt. Deposits. MI 353 11254 0 0.03 10 3 2.91 Lt. Deposits. 354 11285 0 0.03 11 2 2.88 Lt. Deposits. 355 11317 0 0.04 16 3 2.91 Shallow Line of Pits.Lt. Deposits. 356 11349 0 0.03 11 2 2.91 Lt. Deposits. 357 11381 0 0.02 8 2 2.92 Lt. Deposits. MI 358 11412 0 0.03 10 2 2.91 Lt. Deposits. 359 11444 0 0.03 12 3 2.89 Lt. Deposits. 360 11476 0.05 0.03 12 3 2.92 Lt. Deposits. 360.1 11507 0 0 0 0 2.89 GLM 4(LATCH @ 7:00) 361 11514 0 0.03 13 6 2.92 Lt. Deposits. 362 11546 0 0.03 11 2 2.92 Lt. Deposits. 363 11578 0 0.03 10 2 2.92 Lt. Deposits. 364 11609 0 0.02 8 2 2.91 Lt. Deposits. 365 11640 0 0.03 11 2 2.90 Lt. Deposits. 366 11672 0.04 0.04 15 2 2.92 Shallow Line of Pits.Lt. Deposits. 367 11704 0.04 0.04 14 2 2.90 Lt. Deposits. 368 11735 0 0.03 12 3 2.91 Lt. Deposits. U 369 11767 0 0.02 9 2 2.92 Lt. Deposits. 370 11799 0 0.02 9 2 2.91 Lt. Deposits. 371 11831 0 0.03 10 2 2.91 Lt. Deposits. • 372 11863 0 0.04 14 2 2.91 Lt. Deposits. 373 11894 0 0.03 11 2 2.92 Lt. Deposits. • 374 11926 0 0.03 11 2 2.91 Lt. Deposits. • 375 11958 0 0.03 11 2 2.92 Lt. Deposits. • 376 11989 0 0.03 11 2 2.92 Lt. Deposits. • 377 12021 0 0.02 9 2 2.92 Lt. Deposits. • 378 12053 0 0.03 11 2 2.90 Lt. Deposits. • 379 12084 0.04 0.02 9 2 2.92 Lt. Deposits. • 380 12116 0 0.03 13 2 2.92 Lt. Deposits. • 381 12148 0 0.04 14 2 2.91 Lt. Deposits. I•� 382 12179 0 0.03 12 2 2.90 Lt. Deposits. 383 12211 0 0.03 10 3 2.91 Lt. Deposits. • 384 12243 0 0.02 8 2 2.92 Lt. Deposits, 385 122 74 0 0.03 10 2 2.92 Lt. Deposits, • 386 12306 0 0.03 10 2 2.91 Lt. Deposits. • 387 12337 0 0.02 9 2 2.90 Lt. Deposits. • 388 12369 0 0.03 13 3 2.92 Lt. Deposits. • 389 12401 0 0.03 12 2 2.91 Lt. Deposits. • 390 12432 0 0.03 13 2 2.90 Lt. Deposits. 391 12464 0 0.03 13 2 2.90 Lt. Deposits. 392 12496 0 0.03 11 2 2.92 Lt. Deposits. • 393 12527 0 0.04 14 2 2.90 Lt. Deposits. 394 12559 0 0.02 9 2 2.92 Lt. Deposits. • Penetration Body Metal Loss Body Page 8 • PDS Report Joint Tabulation Sheet Well: 2M-33 Survey Date: May 28, 2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 395 12591 0 0.03 11 3 2.91 Lt. Deposits. 396 12622 0 0.03 11 3 2.94 397 12654 0 0.03 11 2 2.92 Lt. Deposits. 398 12685 0 0.03 10 2 2.91 Lt. Deposits. U 399 12717 0 0.03 10 2 2.92 Lt. Deposits. • 400 12749 0.04 0.03 10 2 2.91 Lt. Deposits. U 401 12781 0 0.03 10 2 2.92 Lt. Deposits. 402 12812 0 0.03 12 3 2.91 Lt. Deposits. 403 12844 0 0.02 8 2 2.91 Lt. Deposits. 404 12876 0 0.03 11 2 2.90 Lt. Deposits. 404.1 12907 0 0 0 0 2.87 GLM 5(LATCH @ 10:00) 405 12914 0 0.03 13 2 2.90 Lt. Deposits. 406 12946 0.05 0.02 8 2 2.92 Lt. Deposits. • 407 12978 0 0.03 13 2 2.90 Lt. Deposits. 408 13010 0 0.04 14 3 2.92 Lt. Deposits. `! 409 13041 0 0.02 9 2 2.91 Lt. Deposits. 410 13073 0 0.03 11 2 2.91 Lt. Deposits, ■ 411 13105 0 0.03 12 2 2.92 Lt. Deposits. 412 13137 0 0.03 12 2 2.92 Lt. Deposits. 413 13169 0 0.03 11 2 2.92 Lt. Deposits. 414 13200 0.04 0.03 10 2 2.89 Lt. Deposits. 415 13232 0 0.02 9 2 2.89 Lt. Deposits. 416 13264 0 0.03 13 2 2.91 Lt. Deposits. mi 417 13296 0 0.02 9 2 2.92 Lt. Deposits. • 418 13328 0 0.03 13 3 2.91 Lt. Deposits. 419 13359 0 0.03 11 2 2.91 Lt. Deposits. 420 13391 0 0.04 15 2 2.92 Shallow Pitting. Lt.Deposits. 421 13423 0 0.04 14 2 2.92 Lt. Deposits. • 422 13455 0 0.03 13 2 2.91 Lt. Deposits. • 423 13486 0 0.03 11 2 2.92 Lt. Deposits, U 424 13518 0 0.02 9 2 2.91 Lt. Deposits. 425 13550 0 0.03 13 2 2.91 Lt. Deposits. • 426 13581 0 0.03 10 2 2.92 Lt. Deposits. • 427 13613 0 0.03 12 2 2.91 Lt. Deposits. • 428 13645 0 0.03 12 3 2.91 Lt. Deposits. • 429 13676 0 0.03 12 2 2.92 Lt. Deposits. U 430 13708 0 0.03 11 3 2.91 Lt. Deposits. • 431 13738 0 0.03 11 2 2.92 Lt. Deposits. • 432 13770 0 0.03 12 2 2.91 Lt. Deposits. 433 13802 0 0.02 9 2 2.91 Lt. Deposits. • 434 13833 0 0.03 10 3 2.92 Lt. Deposits. • 435 13865 0 0.03 12 2 2.92 Lt. Deposits. • 436 13897 0 0.04 15 2 2.92 Shallow Pitting. Lt.Deposits. 437 13928 0 0.03 13 3 2.92 Lt. Deposits. • 438 13960 0 0.04 14 2 2.91 Lt. Deposits. 439 13992 0 0.03 12 2 2.92 Lt. Deposits. • 440 14023 0 0.03 12 2 2.92 Lt. Deposits. • • 441 14055 0 0.03 13 2 2.92 Lt. Deposits. 442 14087 0 0.03 12 4 2.92 Lt. Deposits. A 443 14118 0 0.02 9 2 2.92 Lt. Deposits. Penetration Body Metal Loss Body Page 9 • • PDS Report Joint et. p t )o Tabulation Sheet Well: 2M-33 Survey Date: May 28, 201 7 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 98 ft 15,143 ft. Joint it.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 443.1 14150 0 0 0 0 2.88 GLM 6(LATCH C@ 10:00) 444 14157 0 0.03 11 2 2.92 Lt. Deposits. ■ 445 14188 0 0.03 11 2 2.92 Lt. Deposits. ■ 446 14220 0 0.03 11 2 2.91 Lt. Deposits. ■ 447 14251 0 0.03 11 2 2.91 Lt. Deposits. ■ 448 14283 0 0.03 11 2 2.92 Lt. Deposits. ■ 449 14315 0 0.03 13 2 2.91 Lt. Deposits. ■ 450 14347 0 0.03 11 2 2.91 Lt. Deposits. ■ 451 143 78 0 0.03 12 2 2.92 Lt. Deposits. ■ 452 14410 0 0.03 11 2 2.91 Lt. Deposits. ■ 453 14442 0 0.03 11 2 2.89 Lt. Deposits. • 454 14474 0 0.03 10 2 2.92 Lt. Deposits. ■ 455 14506 0 0.03 11 3 2.92 Lt. Deposits. 456 14537 0 0.02 9 2 2.91 Lt. Deposits. 457 14569 0 0.03 13 2 2.92 Lt. Deposits. ■ 458 14601 0.04 0.03 11 3 2.91 Lt. Deposits. ■ 459 14633 0 0.03 10 2 2.90 Lt. Deposits. ■ 460 14664 0 0.03 12 2 2.91 Lt. Deposits. ■ 461 14696 0 0.03 12 2 2.92 Lt. Deposits. ■ 462 14728 0 0.03 13 2 2.91 Lt. Deposits. ■ 463 14759 0 0.03 11 2 2.92 Lt. Deposits. ■ 464 14791 0 0.03 . 10 2 2.91 Lt. Deposits. ■ 465 14823 0 0.03 12 2 2.91 Lt. Deposits. ■ 466 14855 0 0.03 13 2 2.91 Lt. Deposits. ■ 467 14886 0 0.03 12 2 2.92 Lt. Deposits. ■ 468 14919 0 0.04 14 2 2.91 Lt. Deposits. ■ 469 14950 0 0.03 12 2 2.92 Lt. Deposits. ■ 470 14982 0 0.03 12 2 2.91 Lt. Deposits. ■ 471 15014 0 0.03 10 2 2.91 Lt. Deposits. ■ 472 15046 0 0.03 12 2 2.91 Lt. Deposits. 473 15078 0 0.02 9 2 2.91 Lt. Deposits. 474 151 11 0 0.04 15 2 2.92 Shallow Pitting. Lt.Deposits. 474.1 15142 0 0 0 0 2.89 GLM 7(NO DEVIATION) IPenetration Body Metal Loss Body Page 10 • • 11:-1 )\-S PDS Report Cross Sections Well: 2M-33 Survey Date: May 28,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Analyst: C.Waldrop Cross Section for Joint 106 at depth 3,425.1 10 ft. Tool speed= 57 Nominal ID=2.992 Nominal OD=3.5 Remaining wall area=94% Tool deviation= 72° j 1 Finger= 11 Penetration=0.064 in. Line Corrosion 0.06 in.=25%Wall Penetration HIGH SIDE= UP • • PDS Report Cross Sections Well: 2M-33 Survey Date: May 28,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Analyst: C.Waldrop Cross Section for Joint 200 at depth 6,409.710 ft. Tool speed=52 Nominal ID=2.992 Nominal OD=3.5 Remaining wall area=94% Tool deviation= 73° / 1 Finger= 12 Penetration=0.063 in. Line Corrosion 0.06 in.= 25%Wall Penetration HIGH SIDE= UP • 0 verified 2M-33 ConocoPhiMi Well Attributes Max Angie&MD TO 0 S10w.AF1111wT 01.0..tame W.51.4. l-.I- r,t!pl C Alce..r TAM, J1L1rJaa,irr_ .,., «.. SOi0.3.1 4:r-r k:LPAA......-ITER UN IT :131R.30 33.43 1. 6424 .6340!) __. Coma... 020414.4 by A.am•at.b. L.Co. ,,,o,,,,,,IM R.11.10..I.. yea Cs,. iY�Nls5eas5 ,SSs *.PELF 33 1nowail 1......WO 47 La 4130/993 g a ,Ayr.t Av..11. Depth 170.1 r bA Dr. A.... Le!Metl_am now 1.4417.2.4._t 16,:18 3 01 17:20 3 R........1 W.t.irb-dere4'CSr c 4.4”4 • -.41 7'242201: Casing Strings RAMC.. awnpr Coble SiscrIpeon 4121..O.. 58Y.a ID.-.Top lift ee M..f F..oDep.1T l Dep. -_ SU.,WL-1..._.GPM.Toplion CONDUCTOR i 6 '5.067 41 C 121 0 121 a 6256 .1.40 WELDED f� Ce14e 04.r41o0.. ....9 a_. 5bwe ID...lop 111001 S.0 11.95.S.-9.1 Camp.170101.- OMYe MS_SIMS-.moi Top Mai SURFACE Cl S'3 0.830 405 4,373.6 2.749.2 4004 1400 BTC Cabe C►.vtplor 06010 O-. S1..e ID.-.lop Ilfi Sot Dep.9..5•l Delo,11191.- Iib SM-Sir..-.SOM.Top l.nl PR 02730.110/5 7 6-:713 36 3 '6.730 7 6,72711 70 011 I,AD BTC.AAOQ Tubing Strings rublee Do.... 0ble10 0_. S).re IC... lop Ilbt111 5.t 11.91.p...wl appal IiVOl... SSLv.1M_. 1S1n1.. 341.q lop Thrd 1 I 17/0.1150 3117 257 lltt •549'3? 617.7 3J; 130 7.1.1F1,24017,7.1.1F1,24017,Completion op[I.p# Z 0CT1N1 Detalis ITMUl Tap Mpl 1,N11 Top TRS. TBe1In ......... C-ammee 1e 11.¢ 360 36.0 .7.20 PIANGER FMC GEN Di TIJRSPI311RN13ER 3500 IIPCU..4 in 434-3 483.6 7.74 POPPLE CA610005 NIPPLE WW1 GO PR6)FLE 2$12 449p 15,120-8 60402 7314 NFPLF CAMCO W NIPPLE w.NO 00 PEOPLE 2.312 15,13 10 670-3-T,e9 0-4724. FR 6,41141 SA8-1 PA1.I609 wl{77 APACCHO-SFAI ASSFM):,.3. - 36100 18,205.8 6955.8 73.08 RIPPLE' CAK°DNPPLE.440 G0 PROFILE 7 7511 15.493.© 51231 6754 WtECi 64)159 WIRES INF RF-FI.T5V:2354_F- 2 206 Perforations,i Sioft 0.91 M.rlii� • lamp 11.0) II.11'rot Ce.. Top/Mei dm Pete) 95111 9S1(81. taw 014. q.1.- Typ. Ca.se11 15,580.0 15,8070 6.1300.9 5,133.5 0-4.200.33 811312010 611 APERF 10 .,....60 11.8 WV. Gr1S LET, 3,/Y Cl C+' 15,500.0 15,670 0 6 139 9 6..142.0 C-4.UNIT 13,4. .1912!21110 50 APECF .A:1..t.., I WS..50 day 1'41.9 a 2K33 ( 15,760.0 16,160.0 6.1607 672083 A 3,700-33 7.1260996 46 1PEP.F 41!7 TCP 1804*4.W.I. �LVT O� 4. r. '0.174 3 16.2350 02122 6,:167 A 3, 9O 33 7126,4.006 40 r PERF a•..7 T17P'80dam/!1.:.1140 Notes:General 8 Safety ...Po A.eaeWn COO 1.7, 1 I ",:015 NCTF V)6W 19C:.FMATC 941..3.1 S_-,2,111.5-8.0 .JOS GYS� C... GAB YAM II/� r}AS.4 '- 14 I r GAS LFT. e ..I. e6 OF f1•q a FAL.LR S illft 11-- ._. II IlIPPLC..3. II 111 410*'S.S IN.:: 6191711. I 3 02715 RF APdt' t5.a0ti1S P. P91T Mandrel Details. - ri:ffiM,w ' lOTl;.pf, Fc2 4"'")...146 020 1 I cl CO Y.h. ete run pare So. Icp r 0314) 111881 rI N.Y.. MaaV Vnr SC. IIe9 TYw Ip.1P pre.G1e _,.r-. 7526 24282 70.86 CAMCC 05.010,1 1 CJIS LIFT OLv 8105 0.156 1.3009 8'621110 :Fi.3 37431 5!1.12 C3W CO kB A41A 1-GA.S LIFT 'CILti 8105 4.156 1,287.0.8'857.10 ,./.....!;17;-1 5 4 0.6 4038$72.195 CA.VCO it&A07- i i5 L1FT Ut.Y '0105 0.19% 1318x7 872070 a -15.5 3465?71.06 17440,0 01101*1 1 GAS LIFT AV 6145 0150 0A 8)7:2010 . 77 t.8 5.3723 70.33 0}':1111 080123 1-CJS LIFT DWSY 811:5 0.000 0.0 4,232072 Cl 14 149.5 5722.672.16 0614013 i�IdA1 I GAS LIFT 0615 11105 0 0111(-11.0'11.11102E 7 75,742.4 603861 72.86 2'.61400 W$1 3 1 GAS LIFT 0016 -8105 0000 02 41231207 -1,1.-cTr..:0,1 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. (~ ~ 0"~ File Number of Well History File PAGES TO DELETE RESCAN Complete [] 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: Scanned by: Bevedy~Vincent Nathan Lowell [] TO RE-SCAN Notes: Re'Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: Isl 2M-33 (PTD 1960720) Report Oiled TIFL Regg, James B (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Wednesday, February 13, 2008 9:16 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: NSK Well Integrity Proj; NSK Problem Well Supv Subject: 2M-33 (PTD 1960720) Report Of Failed TIFL Attachments: 2N-33 TIO Plot.jpg; 2M-33 Wellbore Schematic.pdf Tom & Jim, ~~~ ~'l,4"I~~ Kuparuk gas lifted producer 2M-33 (PTD 1960720) failed a diagnostic TIFL on 2/12!08 and has been added to the weekly SCP report. The TIO prior to shut in for the TIFL was 230/1250/600. A leaking GLV is suspected so slickline will trouble i/ shoot the suspected tubing leak and repair if possible. Attached is a 90 day TIO plot and a schematic. Please let me know if you have any questions. «2N-33 TIO Plot.jpg» «2M-33 Wellbore Schematic.pdf» Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Cell Phone (907) 943-1720 Pager (907) 659-7000 pgr. 909 ~'~~` ~ FED ~ 2E~L~~ • Page 1 of 1 2/14/2008 KRU 2M-33 PTD 196-072 TII/O Plot - 2M-33 1500 vi 1000 t~. 500 0 01-Dec-07 01-Jan-O~ Date 01-Feb-08 '00 150 c. E a~ 100 0 s v 50 0 • ~~'r~`}~ PH~LLIP~ Alaska, Inc. KRU ~~ a S~.IfJ~idiar,~ ::fi RHILtiF'=: F~ETRnLEUh~1 C,rihrlFAhIY 2M-33 NIP (484-485, API: 501032024000 Well T e: PROD OD:3.500) f4 SSSV Type: Nipple Orig 4/30/1996 C I t' Gas Lift l MandrelNalve 1 (4996-0997, OD:5.390) Gas Lift MandrelNalve ~ ~ , 2 (7956-7957, ® OD:5.390) i Gas Lift MandrelNalve ~ Q 3 (9871-9872, OD:5.390) ~~ ~ .1 f ~, I r ~. ~ -_ NIP (1 51 81-1 51 82, OD:3.500) PACKER (15189-15190, OD:6.151) NIP (15206-15207, OD:3.500) TUBING (4.15494, OD:3.500, ID:2.992) Perf (15760-16160) 2M-33 An le TS: 81 de 15552 Angle @ TD: 83 deg @ 16340 om a ion. Annular Fluid: Last W/O: Rev Reason: GLV desi n b Imo Reference Lo Ref Lo Date: Last U date: 4/27/2002 Last Ta :16238 TD: 16340 ftKB Last Ta Date: 7/26/1996 Max Hole An le: 83 de 16340 Casin Strin -ALL STRINGS HORIZONTAL WELL Descri lion Size To Bottom TVD Wt Grade Thread CONDUCTOR 16.000 0 121 121 62.58 H-40 SUR. CASING 9.625 0 4874 2790 40.00 L-80 PROD. CASING 7.000 0 16321 6227 26.00 L-80 Tubin Strin -TUBING Size To 3.500 0 Perforations Summa Interval TVD Bottom TVD ~Sa~,-? i23 Zone Status Ft Wt Grade~_ Thread 9.30 L- ~ _FUE 8RD MOD _ SPF Date T e Comment 15760 - 16160 6160 - 6208 A-3,A-3 400 4 7!26/1996 IPERF 4 1/2" TCP; 180 de h 16194 - 16235 6212 - 6217 A-3 41 4 7!26/1996 IPERF 4 1/2" TCP;180 de h Gas Lift MandrelsNalves St MD TVD Man Mfr Man V Mfr T e - --__ _ - V Type V OD Latch Port TRO Date Run Vlv Cmnt 1 4996 2829 Camco KBMM GLV 1.0 BK5 0.156 1339 4/25/2002 2 7956 3756 Camco KBMM GLV 1.0 BK5 0.188 1357 4/25/2002 3 9871 4333 Camco KBMM OV 1.0 BK5 0.250 0 4/25/2002 4 11496 4855 Camco KBMM DMY 1.0 BK5 0.000 0 4!24/2002 5 12902 5322 Camco KBMM DMY 1.0 BKS 0.000 0 4/23/2002 6 14149 5719 Camco KBMM DMY 1.0 BKS 0.000 0 11!7!1996 7 15142 6038 Camco KBMM DMY 1.0 BKS 0.000 0 4!23/2002 Other lu s, a ui .etc. -JEWELRY De th TVD T e Descri lion ID 484 483 NIP Camco'DS' Ni le NO GO 2.812 15181 6050 NIP Camco 'W Ni IeNOGO 2.812 15189 6052 PACKER Baker'SAB-3' Perm. 3.000 Baker Perf (1619416235) • Con ~ ' ' ocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 • RECErVED JAN ~ 8 Z00~ ArBSIIe Oil & Gea GpRi. ComNtN~tipn January 6, 2008 Ancitorape Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7~' Avenue, Suite 100 ~~,~;;~~~~ i ~' ~~~ Anchorage, AK 99501 '~~~ ~ ~ ~~~~ ~'~~ Deaz Mr. Maunder: Enclosed please find 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 by surface casing annulus. The voids that were greater than 3 feet were first filled with cement to a level of 12". The remaining volume of annulaz void respectively was filled with a corrosion inhibiter, RG2401, 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 top-fill operation was completed on Dec 25, 2007. We mixed 15.7 ppg Class G cement in a blender tub. The cement was pumped into the conductor bottom and cemented up via a hose run to the existing top of cement. The corrosion inhibitor/sealant was pumped in a similar manner Jan 6, 2008. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call me at 907-659-7043, if you have any questions. Sincerely, r°. Perry ConocoPhillips Well Integrity Projects Supervisor • • ConocoPhillips Alaska Inc. Surtace Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Kuparuk Fieid n~+e ! . -, ... ~ ConocoPh ¡IIi pS Alaska P.o. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 2, 2004 Mr. Tom Maunder )x J) rrv! Alaska Oil & Gas Commission ?4 r f 333 West ih Avenue, Suite 10 5 ( H..."- 0 ~ Anchorage, AK 99501 Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids were filled with cement to the top of the circulation ports in the conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place. The top-fill operation was completed on April 29, 2004. Dowell-Schlumberger batch-mixed Arctic Set II cement to 15.7 ppg in a blender tub. The cement was placed in the conductor from the bottom-up via a hose ran to the bottom of the void. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volume used on each conductor. Please call Marie McConnell or me at 907-659-7224, if you have any questions. Sincerely, ~4\(_rL'('J"{¿"-\\"\ (.L.,>,\~ \.0 ~~k~« (\~ . \ ~ "ù \-- \.5 "'- ,'::f:>....:x" '\ ~ \ \- ~ Ck: O'-"-<L v~~ -\-6 \? .\-u \l ~(j \ \ \Y:3,~~i(. {~ \ \ <--t¿ \\,-,,(( ,,'-- \- \a ~~ \: "'" '\-\~~ .~\ ~~ '-k.)(èw "~\,\~--;\(¡,-'~\""""<é Cú~~c~c-. kt 1í!Y(!; (~-Gtj ?c~ Jerry Dethlefs ConocoPhillips Problem Well Supervisor Attachment RECEIVED MAY 042004 Alaska Oil & Gas Cons. Commission Anchorage , t -"" WELL NAME 2C-09 2M-33 3H-21 3H-24 3H-28 3H-32 3K-12 ConocoPhillips Alaska, Inc. Surface Casing by Conductor Annulus Cement Top-off Kuparuk Field April 29, 2004 PTD# SERVICE CEMENT TOP VOLUME ~O'-.J"t: TYPE ft BBLS v" -- '-J<':' \o,j ~'""'- Q: 1842210 Producer 54.0 9 .~ ~\ 1960720 Producer 40.0 5 <;,.1, 1880080 Producer 34.0 5 L-\ L.\ 1960150 Injector 25.0 3 ~,;) 1960370 Producer 20.0 4 ;) ,Cc 2000010 Producer 10.0 2 1.3 1861650 Injector 48.0 10 (" d. Arctic Set 1115.7 PPG Cement \~\ ~.';¿ \S II \ \) --.¡. ~Ç/ß" U\^"'\ - ,,\(=t~ '0"1.0 y+ \- oN OR BEFOP ANuARY 03 2001 W c:LORI~]:UM.DO C PERMIT AOGCC Individual Well Geological Materials Inventory DATA T DATA PLUS Page: 1 Date: 07/07/98 RUN RECVD 96-072 96-072 96-072 96-072 96-072 Are dry ditch samples required? 7316 ~DR/CDN 16340-4763 CDN ~SEPIA 4770-16340 CDR ~'SEPIA 4810-16340 CDN /~/~L 4760-16340 CDR ~BL 4810-16340 10-407 ~~C~MPLETION DATE DAILY WELL OPS ~R/V//~/~ / TO yes ~g~d received? 07/03/96 FINAL 07/03/96 FINAL 07/03/96 FINAL 07/05/96 FINAL 07/05/96 Ioi '? I¢~ I ?~I 2 I~ I Was the well cored? yes ~?-_Analysis & description received? Are well tests required? yes ,/n-6) Received? Well is in compliance /~ Initial COMMENTS ~ ;, ~ .~.,.~ Q~, ~ ~.i,,,~iI I~ - I ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMIfdb~ION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Operation Shutdown__ Pull tubing Alter casing Stimulate X Plugging Perforate Repair well Other 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development X Exploratory _ Stratigraphic _ Service Location of well at surface 114' FSL, 367' FEL, SEC 27, T11N, R8E, UM At top of productive interval 1943' FSL, 595' FWL, SEC 5, T10N, R8E, UM At effective depth 1527' FSL, 62' FWL, SEC 5, T10N, R8E, UM At total depth 1 12. 6. Datum elevation (DF or KB) RKB 41 7. Unit or Property name Kuparuk River Unit 8. Well number 2M-33 9. Permit number/approval number 96-72 10. APl number 50-103-20240-00 11. Field/Pool 462' FSL, 23' FEL, SEC 6, T10N, R8E, UM Present well condition summary Total Depth: measured true vertical 16340 6229 feet feet feet Kuparuk River Field/Oil Pool Plugs (measured) None Effective depth: measured 1 6232 true vertical 6 2 1 6 feet feet Junk (measured) None 13. 14. Casing Length Size Structural Conductor 8 0' 1 6" Surface 4833' 9 5/8" Intermediate Production 1 6 2 8 2' 7" Liner Perforation depth: Cemented Measured depth True vertical depth 183 Sx AS I 121' 121' 840 Sx AS III & 4874' 2790' 950 ex Class G 250 Sx Class G 16321' 6227' measured 15760' 16160', 16194' - 16235' true vertical 61 60' - 6194', 6197' - 61 99' Tubing (size, grade, and measured depth) 3.5", 9.3#/ft., L-80 @ 15494' Packers and SSSV (type and measured depth) Packer: Baker SAB3 @ 15189'; SSSV: Stimulation or cement squeeze summary Fracture stimulate 'A' sands on 10/12/96. Intervals treated (measured) 15760' - 16160', 16194' 16235' None, nipple @ 485' ORIGINAL Treatment description including volumes used and final pressure Pumped 204.1 Mlbs of 20/40, 16/20, & 12/18 ceramic proppant into form., final pressure - 8800 psi. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 4 0 8 218 18 1295 215 Subsequent to operation 2158 990 262 1347 230 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of well classification as: Oil X Gas Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~.¢¢J.,,,,,,~ ~z.( Form 10-~4 ¢RCv/'~6~¢¢¥¢'~ .... .z,...~_,~' Title Wells Superintendent / Date /2~-~ SUBMIT IN DUPLICATE ARCO Alaska, Inc. .(UPARUK RIVER UNIT WELL SERVICE REPORT '~ K1 (2M-33(W4-6)) WELL JOB SCOPE JOB NUMBER 2M-33 FRAC, FRAC SUPPORT 1006961929.1 DATE DAILY WORK UNIT NUMBER 10/1 1/96 "A" SAND FRAC DAY OPERATION COMPLETE I SUCCESSFUL KEY PERSON SUPERVISOR 3 O Yes (~ NoI O Yes ~ No DS-GALLEGOS CHAN£Y ' ~ FIELD AFC# CCC DAILY COST ACCUM COST Si~ne~ .~ t ESTIMATE 998549 230DS28ML $10,950 $30,789 ..~.,- ~' ~ ,' Initial Tbcl Press Final TbCl Press Initial Inner Ann Final Inner Ann I Initial Outer Ann I Final Outer Am}-" 900 PSI 700 PSi 1000 PSI 2000 PSII 300 PSII ~O'0 PSI DAILY SUMMARY "A" SAND FRAC INCOMPLETE. ENCOUNTERED FLUID AND EQUIPMENT PROBLEMS AFTER THE BREAKDOWN AND DATAFRAC PORTION WAS COMPLETED. TOTAL FLUID VOLUME PUMPED WAS 2603 BBLS. USED 8416 LBS OF #20/40 PROP FOR CONDITIONING. MAX PSI WAS 9300 PSI. WELL FREF__.ZE PROTECTED W/DIESEL. WILL CONTINUE IN AM. TIME LOG ENTRY 06:30 11:00 12:30 14:30 16:15 20:30 20:45 23:00 MIRU DOWELL FRAC EQUIP, LRS HOT OIL UNIT, APC DIESEL TANKER, AND APC VAC TRK. HELD SAFETY MTG (17 ON LOCATION). PT'D BACKSIDE LINES TO 4000 PSI.HAD PROBLEMS SE'I-I'ING THE TREESAVER, BUT EVENTUALLY GOT IT TO SET. PT'D HI-PRESS LINES TO 9800 PSI. PUMP HPBD/DIVERSION/CONDITION W/SLICKWATER(J313) & 50# DELAY-XL GW @ 25 TO 40 BPM. DURING 50# DIVERSION, LOST SUCTION 2 DIFFERENT TIMES AND TURBINES SHUT DOWN, HAD PROBLEMS RESTARTING SOME OF THE TURBINES AND COULD NOT ACHIEVE MAXIMUM RATE. GOT THRU THE DIVERSION PORTION AND WAS ABLE TO GET ALL TURBINES RUNNING AND ACHIEVE 40 BPM. SCOURED PERFS W/8416 LBS OF #20/40 PROP. FLUID VOLUME PUMPED WAS 2110 BBLS. MAX PSI WAS 9300 PSI AND ENDING PSI WAS 8800 PSI. S/D FOR ISlP (2228 PSI) AND STOODBY FOR CLOSURE. PUMP DATAFRAC W/50# DELAY-XL GW @ 10 TO 40 BPM. TRIPPED OUT A TURBINE IN THE DATAFRAC PORTION, RESTARTED AND MAINTAINED RATE. FLUID VOLUME PUMPED WAS 403 BBLS. MAX AND ENDING PSI WAS 8750 PSI. S/D FOR ISlP (2240 PSI) AND STOODBY FOR CLOSURE AND PAD VOLUME DETERMENATION. FREEZE PROTECTED SURFACE LINES W/DIESEL AND DISPLACED THE WELL W/30 BBLS OF DIESEL.STOODBY TO GET MORE GEL FROM PBU TO COMPLETE FRAC. GEL BROUGHT OVER FROM PBU BAD AND UNABLE TO TRANSFER TO PCM. PCM TRANSFER PUMP NOT WORKING ALSO. RE- FREEZE PROTECTED SURFACE LINES AND DISPLACED WELL W/40 BBLS MORE OF DIESEL. 70 BBLS TOTAL DOWN THE WELL. WELL SECURED. RDFN AND SENT DOWELL IN TO REPAIR PCM AND TURBINES. WILL A-I-I'EMPT AGAIN IN AM. NOTIFIED DSO OF STATUS. A - ,5- 1.9;97 SERVICE COMPANY - SERVICE DAILY COST ACCUM TOTAL APC $7,000.00 $9,210.00 ARCO $750.00 $750.00 DOWELL $0.00 $0.00 HALLIBURTON $0.00 $10,039.00 LI'T-I'LE RED $3,200.00 $10,790.00 TOTAL FIELD ESTIMATE $1 0,950.00 $30,789.00 ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 October 28, 1996 Mr. David J. Johnston Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: Annular Pump Volumes on Well Completion Reports Dear Mr. Commissioner: It has come to our attention that there are 3 wells whose annular injection volumes were not reported on the well completion reports as originally submitted. In an effort to correct this oversight, the enclosed spreadsheet reports these volumes. If there are any questions, please cml 263-4183. Sincerely, D. K. Petrash Drilling Engineer Kuparuk Drill Site Development DKP/skad Sheet1 ANNULUAR PUMP VOLUMES: i i TOTAL THIS TOTALS TO WELLS: ...~GATEGORY1tCATEGORY2 tOATEGORY3 TIMEPERIOD DATE 3_~-,n4"'~"~"270171 100l 0 27117 27117 ~M-33 30101! 1001 0. 30201 30201 3M-27 15328i 1 00i 01 15428, 15428 Page 1 ARCO Alaska, Inc. Post Office Box 10036u Anchorage, Alaska 99510-0360 Telephone 907 276 1215 October 4, 1996 Mr. David J. Johnston Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: 2M-33 (Permit No. 96-72) Well Completion Report Dear Mr. Commissioner: Enclosed is the well completion report for the completion on KRU 2M-33. If there are any questions, please call 263-4622. Sincerely, W. S. Isaacson Drilling Engineer Kuparuk Drill Site Development WSI/skad STATE OF ALASKA ,-,,_ASKA OIL AND GAS CONSERVATION C,...,.iMISSION WELL COMPLETION OR REOOMPLETION REPORT AND LOG 1 Status of Well Classification of Service Well OIL E~] GAS [~ SUSPENDED [~ ABANDONED [] SERVICE E~ 2 Name of Operator 7 Permit Number ARCO Alaska, Inc 96-72 3 Address 8 APl Number P.O. Box 100360, Anchorage, AK 99510-0360 50-103-20240 4 Location of well at surface ~ ..................... ~,~--,,~ ........ ,._~ 9 Unit or Lease Name 114' FSL, 367' ~L, Sec. 27, T11N, R8E, UM~ .......... ~ATF ¢ ~ :~'~;L; ".i: Kuparuk River Unit At Top Producin, Inte~al ¢~~ t~~~ 10 Well Numar 1943' FSL, 595' FWL, Sec. 5, T10N, R8E, UM ~ ~/F~F~?., f 2M-33 At Total Depth ; ~~2__ .' ~;*:~~! 11 Field and Pool 1462' FSL, 23' FEL, Sec. 6, T10N, R8E, UM KUPARUK RIVER 5 Elevation in feet (indi~te KB, DF, etc.) I 6 Lease ~signation and Serial No. RiG RKB 41' PAD 106'~ ADL 25590 ALK 2676 12 Date Spudded 13 Date T.D. Reached 14 Date ~mp., Susp. or A~nd. I 15 Wa~er Depth, if offshore 116 No. of Completions 17-Apr-96 26-Apr-96 25-Jul-96 (peGd)[ NA feet MSL[ 1 17 Total Depth (MD+TVD) 18 Plug Back Depth {MD+TVD) 19 Directional Su~ey 120 Deplh where SSSV set 21 Thickness of ~rmafrost 16340' MD & 6229' ~D 16232'MD&6216'~D YES ~ NO ~I NA feelMD =1380'ss APPROX 22 Ty~ Electric or Other Logs Run G~CD~CDN-RT 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE ~ GRADE TOP ~ HOLE SIZE CEME~ ~C~D 16" 151.5¢ X-65 SURF. 121' 24" 183 sx AS I 9.625" 40¢ L-80 SURF. 4874' 12.25" 840 sx AS III, 950 sx Class G 7" 26¢ D80 SURF. 16321' 8.5" 250 sx Class G 24 Perforations o~n lo Production (MD+TVD of Top and Bottom and 25 TUBING RECORD inte~al, size and numar) SIZE DEPTH SET (MD) PACKER SET (MD) 3.5" 15494' 15189' 15760'-16160' MD 4 spf 6160'-6208' TVD 16194'-16235' MD 4 spf 6212'-6217' ~D 26 ACID, FRACTURE, CEMENT SQUEEZE, ETd DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27 PRODUCTION TEST Date First Production ~Melhod of Operation (Flowing, gas li~, etc.) 8/8~6I Gas Li~ Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO 9~6 20 TEST PERIOD E 29 5 157 ~ 176 535 Flow Tubing Casing Pressure CALCU~TED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 218 11 91 24-HOUR RATE E 35 4 189 16 =24° 28 CORE DATA Brief description of lithology, ~rosity, fractures, apparent dips and presen~ of oil, gas or water. Submii core chips. RECEIVED ORIGINAL ~aska 0il & Gas Cons, C~mmission Anchor2ge Form 10-407 Submit in duplicate Rev. 7-1-80 CQNTINUED ON REVERSE SIDE 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top Kuparuk C 15552' 6133' Bottom Kuparuk C 15662' 6148' Top Kuparuk A 15662' 6148' Bottom Kuparuk A 16298' 6224' FREEZE PROTECT ANNULUS WITH DIESEL 31. LIST OF ATTACHMENTS Directional Survey, Daily Drilling History 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed d'~ ~1~. ~ ....,,-.-,--,--..- Title O~'~'&"["~c" ~_..1~,'["~1. DATE ~ / I~/ 0~ 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- lng 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. R ~ E E IV E B Item 28: If no cores taken, indicate "none". Form 10-407 Or'T 0 7 ,9,,6 Alaska 0il & Gas Cor~s. Commission Date: 9/6/96 ARCO ALASKA INCORPORATED WELL SUMMARY REPORT Page: 1 WELL:2M-33 RIG:PARKER 245 WELL ID- AK8525 AFC- AK8525 TYPE: STATE:ALASKA AREA/CNTY' NORTH SLOPE WEST FIELD: KUPARUK RIVER UNIT SPUD:04/17/96 START COMP: BLOCK: FINAL- WI: 0% SECURITY:0 AFC EST/UL:$ 1990M/ 2380M API NUMBER: 50-103-20240-00 04/16/96 ( 1) TD' 121' ( 121) SUPV:RLM DAILY: 04/17/96 ( 2) TD: 614' (493) SUPV:RLM DAILY: 04/18/96 (3) TD: 4439' (3825) SUPV:RLM DAILY: 04/19/96 ( 4) TD' 4890' ( 451) SUPV:RLM DAILY: 04/20/96 ( 5) TD: 5825' (935) SUPV:RLM DAILY' 04/21/96 ( 6) TD: 9304' (3479) SUPV:RLM DAILY: 04/22/96 (7) TD:12563' (3259) SUPV'RLM MW: 9.4 PV/YP: 27/29 APIWL: 12.5 LOAD SHED WITH DRILL PIPE Prepare rig for pad move. Move rig from 2A pad to 2M pad. Line up on 2M-33 and cantiliver over well. Accepted rig at 0300 hrs. 4/17/96. $86,203 CUM: $86,203 ETD: $0 EFC: $2,076,203 MW: 9.4 PV/YP: 27/29 APIWL: 12.5 DRILLING AT 1350' Accept rig at 0300 hrs. 4/17/96. Function test diverter. Held pre-spud meeting. Spud @ 1700 hrs. 4/17/96. Rotary drill from 121' to 614' $91,919 CUM: $178,122 ETD: $0 EFC: $2,168,122 MW' 10.2 PV/YP' 23/32 APIWL: 6.8 WIPE HOLE FOR CASING Directional drill 12.25" hole from 614' to 4439' $84,927 CUM: $263,049 ETD- $0 EFC: $2,253,049 MW: 10.2 PV/YP: 21/14 APIWL: 6.2 NIPPLE UP STACK Directional drill 12.25" hole from 4439' to 4890' POOH, pumped out from 2520 to 1200 due to tight hole. RIH, no fill. Held pre-job safety meeting. Run 9-5/8" casing to 4874' Cement 9-5/8" casing. $203,509 CUM: $466,558 ETD: $0 EFC: $2,456,558 MW: 8.7 PV/YP: 12/19 APIWL: 11.2 DRILLING CIP at 0021 hrs. 4/20/96. Performed top job on casing. Nipple up 13-5/8" stack. Test all manifold, kill and choke line valves, rams and Hydril to 300/3000 psi. Test casing to 2000 psi for 30 minutes. Drill cement, FC and shoe and 10' new hole to 4900' Perform FIT to 12.5 ppg. Drill 8.5" hole from 5218' to 5825' $92,039 CUM: $558,597 ETD: $0 EFC: $2,548,597 MW: 9.1 PV/YP: 11/21 APIWL: 6.8 DRILLING @ 10,100' Directional drill 8.5" hole from 5825' to 7745' Noticeable reduction in cuttings return. POOH from 7745' to 7095' Tight and swabbing, back ream out to shoe at 4874' RIH, hole free, no fill. Drill from 7745' to 9304' $84,467 CUM: $643,064 ETD: $0 EFC: $2,633,064 MW' 9.3 PV/YP: 15/25 APIWL: 6.0 CIRCULATE @ 13067' Directional drill 8.5" hole from 9304' to 10,365' Wipe hole to shoe. Pulled out to 9902' hole tight. Back ream from 9902' to 7745' Circulate hole clean. Significant Date: 9/6/96 ARCO ALASKA INCORPORATED WELL SUMMARY REPORT Page: 2 DAILY: 04/23/96 ( 8} TD:14008' (1445) SUPV:GRW DAILY: 04/24/96 ( 9} TD:15346' (1338) SUPV:GRW DAILY: 04/25/96 ( 10} TD:15746' ( 400} SUPV:GRW DAILY: 04/26/96 (11) TD:16340' (594) SUPV:GRW DAILY: 04/27/96 ( 12} TD:16340' ( 0) SUPV:GRW DAILY: 04/28/96 (13) TD:16340' ( 0) SUPV:GRW DAILY: 04/29/96 (14) TD:16340' ( 0) SUPV:GRW DAILY: 04/30/96 ( 15) TD'16340' ( 0) SUPV:GRW DAILY· cuttings return during entire circulation. RIH, hole free, no fill. Drill 8.5" hole from 10365' to 12563' $83,310 CUM' $726,374 ETD: $0 EFC: $2,716,374 MW: 9.2 PV/YP: 11/19 APIWL: 6.6 DRILLING @ 14690' Directional drill 8.5" hole from 12563' to 14008' $54,001 CUM: $780,375 ETD: $0 EFC: $2,770,375 MW: 10·3 PV/YP: 15/20 APIWL: 4.2 DRILLING @ 14690' Directional drill 8.5" hole from 14008' to 15346' Pump visc. pill. Circulate. Short trip to shoe. Pulled to 13900' for flow/swabbing. Pump slug and POOH. $96,137 CUM: $876,512 ETD: $0 EFC: $2,866,512 MW: 10.3 PV/YP: 18/22 APIWL: 4.2 DRILLING @ 15931' Directional drill 8.5" hole to 15746' · $80,421 CUM: $956,933 ETD: $0 EFC: $2,946,933 MW- 10.3 PV/YP' 18/15 APIWL: 4.2 TRIPPING Directional drill 8.5" ;hole from 15746' to 16340' $84,260 CUM: $1,041,193 ETD: $0 EFC: $3,~31,193 MW: 10.4 PV/YP: 21/18 APIWL: 3.8 RUNNING 7" CASING Pump out of hole. After 13 stands + sgl hole tight and packing off. Work pipe. Pump out of hole 14 stds to 15080'. Hole tight and packing off. Work up to 15020' Run 2 stds and still packing off. TIH hit bridges all of the way to 16340' Work pipe and rotate to regain circulation. Pump lo-vis and hi-vis sweeps. Pump out of hole 20 stds. Worked thru tight spot @ 15080' with no swabbing. Monitor hole. $75,124 CUM: $1,116,317 ETD: $0 EFC: $3,106,317 MW: 10.3 PV/YP: 18/16 APIWL: 4.4 RUNNING 7" CASING Finish POOH. Held crew safety meeting. Run 7" production casing. $73,792 CUM: $1,190,109 ETD: $0 EFC: $3,180,109 MW: 10.3 PV/YP: 18/14 APIWL: 4.6 LAYING DOWN DP Run 7" casing. Casing packed off and stuck @ 14750' . Work pipe free. Continue to run 7" casing. Cement casing. CIP @ 1708 hrs. N/D BOPE. Inject into 9-5/8" x 7" annulus. $355,887 CUM: $1,545,996 ETD: $0 EFC: $3,535,996 MW: 10.3 PV/YP: 18/14 APIWL: 4.6 RIG RELEASED Freeze protect9-5/8" x 7" annulus. Release rig at 1200 hrs. 4/30/96· $35,136 CUM: $1,581,132 ETD: $0 EFC: $3,571,132 R [C ltV b OCT (J 7 '~99S Date' 9/6/96 ARCO ALASKA INCORPORATED WELL SUMMARY REPORT Page' 3 REMEDIAL AND COMPLETION OPERATIONS WELL:2M-33 RIG'PARKER 245 WELL ID: AK8525 AFC: AK8525 TYPE: -- STATE:ALASKA AREA/CNTY: NORTH SLOPE WEST FIELD: KUPARUK RIVER UNIT SPUD:04/17/96 START COMP: BLOCK: FINAL: WI: 0% SECURITY:0 AFC EST/UL:$ 1990M/ 2380M API NUMBER: 50-103-20240-00 07/22/96 (16) TD: 0' PB: 0' SUPV:DKP DAILY: MOVING TO DS 2M Moving rig to DS 2M. $22,732 CUM: $1,626,596 ETD' MW: 0.0 $0 EFC: $3, 616,596 07/23/96 (17) TD: 0' PB: 0' SUPV:DKP DAILY: NU & PREP TO TEST BOPE MW: 0.0 Continue moving rig to 2M. Accept rig @ 0300 hrs. 7/23/96. NU BOPE. $34, 694 CUM' $1,695,984 ETD' $0 EFC' $3, 685,984 07/24/96 (18) TD: 0' PB:16231' SUPV:RLM DAILY: P/U 3.5" TUBING MW: 0.0 Test all rams, lines and valves to 250/3500 psi. Test Hydril to 250/3000 psi. Test 7" casing to 3500 psi for 30 minutes, no loss. RIH with TCP guns on 3.5" tubing. $35,882 CUM: $1,767,748 ETD: $0 EFC: $3,757,748 07/25/96 (19) TD: 0' PB:16231' SUPV:RLM DAILY: REVERSE CIRCULATING MW:10.3 RIH with TCP guns on 3.5" tubing. Run correlation log. Spaced out TCP guns. Pressured tubing and casing to 3300 psi. Guns fired. Monitor hole. $42,087 CUM: $1,851,922 ETD: $0 EFC: $3,841,922 07/26/96 (20) TD: 0' PB:16231' SUPV:RLM DAILY: RUN COMPLETION MW: 0.0 POH w/3.5" tubing and 4.5" TCP guns. Ail shots fired. Run 3.5" completion. $271,148 CUM: $2,394,218 ETD: $0 EFC: $4,384,218 07/27/96 (21) TD: 0' PB:16231' SUPV:RLM/ML DAILY: RIG RELEASED MW: 0.0 Finished RIH w/completion assembly on 3.5" tubing. ND BOP. NU tree. Tested tree to 250/5000 psi. Freeze protect annulus. Set packer. Pressure tested tubing and casing and tested packer. Released rig @ 2400 hrs. 7/26/96. $48,536 CUM: $2,491,290 ETD: $0 EFC: $4,481,290 End of WellSummary for Well:AK8525 PAGE NO, ********** ANAl)RILL ********** S~]HkLfltBE'I~GER ********** ********** *******--******************************************** AFE: AI< 8525 APl: 50-103-20240-00 COMPANY ARCO ALASI<A: INC. W~I,L NAMB 2M-33 LOCATION 1 XUPA~qJK LOCATION 2 ALASI~ MAGN~IC D~LINATION 27.58 GRID CONU~G~NC£ ANGL£ 0.00 gATE: 27-APR-96 WL:I,L NU~Bm 0 WELL HEAD LOCATION: LAT(N/-S) 0.00 AZIMLKI"H ROM ROTARY TABLE TO TARGET IS TIE IN POINT(TIP) : M~4]RIED D~TH 121,00 ~ VI~RT DEPT~ 121.00 INCLINATION 0,00 AZIMUTH 0.00 LATITUDE(N/-S) 0.00' D~ARI'UP,~(E/-W) 0.00 DEP(E/-W) 0,00 230.16 ~;'""' .... DE'TH U'ni' i ~'~ ft ft ,uu ,:/~ ,00 150,0 271,00 342,00 71,0 341,97 432,00 ?'0,0 431.71 522,00 ~,n~ STATION AZ!~UTH .... O,O0 O,O0 0,00 0,00 ^ ~ 0.25 218,00 ~' ~^ i.99 2,50 218,00 -i,60 8,61 6.00 228.00 -6,30 20.35 9,00 ~ ~ ~ - £/-W ft ft -0.20 u,3o -t,25 2,03 -5,96 8,67 ,~: 20,38 deg/ dea !OOft - ),00 0,00 218,00 0.17 218,00 3.17 2~.41 3,96 227,0'? 3.36 40,.~ ii8.5 637.24 · ...:,,., 9i,8 726,59 822,4! 90,1 813,84 9i3,88 9!,5 i¢Q3,44 89,6 42,87 12.95 233.98 -~7.52 63.78 13,46 234.43 -39,78 86,39 15,63 23i,93 -53,37 ~m .: !7,24 ?37,63 -68.23 140,03 i9.38 238,14 -&3,19 -32,87 42.87 230,06 3,37 -49.88 63,80 231,43 0,57 -67,y7 86.42 ~31.8o 2,50 -89,13 1i2,25 232,56 2,49 -112,96 !40.29 2~,63 2.39 !092.38 ii83,54 i~t..07 136Y,o~ 1460,48 ~.9 1069,84 91.2 1153.84 ?2.9 1237,85 93.3 !320,00 90,8 i.397,82 171,ti 21.82 Z35,44 -i00.35 206.35 23,86 235,04 -i20,53 ~'~ ~ 7 ~4j.~ 26.55 ~,04 -143,F' 289,73 29,9i z'~.~3 -i68,86 336,48 32,16 ~2,89 -.96,o, -i68,17 206,91 234,37 2,24 -ivO,~8 ?46.45 234,48 2,90 -236 ~= 290,55 234.47 3.65 -274.01 :337.37 234.31 2,53 I551,12 1647,43 1742,64 1834.40 i925,39 ~,6 1473,87 96,3 t552,01 95,2 I625,24 91,8 1691,75 91.0 1753.92 385,73 3~,76 233,32 -226.42 441,92 37.76 233,00 -260,16 502,63 41,67 Z34,.46 -296,12 565,67 45,39 233,67 -:333.21 631,99 '.48,41 T33'43 -372,68 -313,45 386.67 234.16 1,79 -358,48 442,93 234,03 4,15 -~7.54 503.76 234,00 4,23 -458,69 566,94 234,00 4,09 -5i2.12 633,37 2~,96 3,33 20D,18 21i2,21 220A '~ 94,8 i814,83 92,0 !870,31 94,4 !923,4t 9!,8 !971.02 96,5 2016,78 7M,47 51,61 233.60 -4!5,86 777.79 54,23 2~.49 -460,00 855.84 57,33 ~0,93 934,26 60.14 231.33 -557,61 zvl~.z~ 63.22 -570.51 705,98 233,?1 3.38 -..~,i~ 779,~' ~33,8o 3,01 -.?~.44 857.42 233,63 3,55 -751,50 935,78 233.42 3.09 -~l/,Jz ~u20,o~ 233.~ 3.23 24M.77 ~82.48 2676.91 3051.60 91.9 2056,45 95.7 2093.59 94.4 2i25.52 9~+5 ~"~ ~ 281,2 2235.69 1!02.03 65,63 231,89 -662,82 I190.19 68,70 231.63 -717,41 1279,01 71,77 231,92 -772,39 1368.20 73,40 '~+27 -827.?,2 !636.,92 72,60 231.97 -992,32 -882,21 1t03,46 233,08 2,86 -951.48 1191.64 232.98 3.22 -1021.29 1280,".4 2~,90 3.27 in9~ :a 1369,71 232,85 1.78 --~. &It ~ - i6~8,J. 232,73 0,30 -1303,91 ' ~ =A 3610.83 3890.63 4451,89 279.1 2321,60 280,1 2404,70 279.8 2485,21 282,1 £~70,8i ~o2.~5 7t,55 231.68 -I156.4A 2169.81 73.94 2~.80 -i323.95 2437,76 72.61 ~7.51 "~ 2./'06,60 72,06 293,29 -i668.78 ~ _~, -i.639,o~ 2971,7/ 71.57 -1512.66 1'~)4.08 232.60 -t721 ~' 217I ~ .~.-~,~ ,ia 0.91 .. ~,l~ O,A5 -1'~6.97 24~,28 '~ '~ . -zi~2+~: ~,'07.,o ~1.96 0.33 - ~J. 68 4972. :o 231,78 0.28 4804.07 .l:"j.J--. 9Q 5333.81 5619.07 58~7.56 352.2 Z67.35 248.4 2846.82 281,3 2937.42 285.3 .,'~v s' Z8,5 oo0o.~ 72,22 2~.07 ~^~ m s541 ~? ' ./,' 70,46 ~o,80 -2211+'71 3807,89 71,97 226,96 -2~0,55 ~.77/.97 71,21 2~,93 -2577,02 ~ 7' ~" A7 _ 4341,3c . ~,28 a~o.., -2755,8~ -2589,71 3307.44 -2964,69 3~$8,42 -o£o0,84 '.078,Z3 -3354,63 4341.45 R 231.54 0.24 231,36' 0,71 ~1,i2 0.82 230.81 0,43 230,60 0.93 ECEI1/Ei) ()C'l~ ()'/ !99S MEASURED ~mnRVAL VERTICAL DEFTH D~PTH 6270,61 373.0 :~34.30 67~.75 466.1 3381,17 z~ll.~,~* J74,8 3497,27 7484.85 7862,>~ 375.7 3726,64 ~z37,19 6706.18 9080,83 9453,70 9823.15 10574,03 1.0943,54 11~1,Ii 44 ' ~ 1i6¥8,o8 12048,85 !2443,13 12807.32 12992,67 13260,95 13539,50 13813.44 14088.49 14344,17 i-%40,08 14912,33 15187,2i 15273,~2 15367.25 i5458.8! 15558,71 15647,03 15824.67 16011.74 16!02+01 16264,24 16340.00 £i'{ 374.7 ~43.96 %9,0. 3983,58 374,7 4090,98 372,9 4206.12 369,5 4318,75 ?'~GET STATION ............... ~ S~TID~ INCLN, N/-S ft deg de9 ft 4695.40 72,08 229.49 -2987.78 5137.72 71.I9 228.78 -3277.23 5494.09 72,73 2~,88 -3507.11 5851,55 71.84 230,15 -3734.41 6209,i0 72,44 230,98 -3961,53 i 6564.87 71.06 23i.33 -4184,69 7012,16 74,30 233,40 -4457.96 7370.68 72,39 2'~2.24 -4674,83 ~25.10 71,64 L.~,ll -4892,~ 8076,9! 72,87 229,67 -5114,27 DBF'ARffURE DISPLACEMENT at AZIMUTH DLS dc<j/ -3622.24 4695.47 230.48 0.30 -3956,80 5137,75 230.37 0,24 -4229.12 ~ ' *~ ~ ~4Y4,ii co0,33 0.67 -4505,01 5851,58 230,34 0,30 -4781.18 6209.14 230.36 0,26 -5058,32 6564.93 2~,40 -5412,&~ 7012,30 230,53 -5898.83 7370,93 230,64 -5978.% 7725,45 230.71 -6251,95 8077.2? ~30.~ 376.4 4433.35 374,5 4555,32 369,5 4677,14 377,6 4799,61 377.3 4919,33 8435,40 71,67 .~.98 -5345,~ 8789,45 70,31 229,15 -5575,18 9t38,25 71,19 229,~ -5803.i2 9495.32 70,96 228,63 -6037.72 9852,98 72,04 22%04 -6273.20 -8525,87 8435,75 230,~ -6795,38 8789,75o 230,63 -,~?.,o 9138,50 230,58 -7~8,75 9495.50 230.52 -7598.08 9853,12 230.$5 370,5 5037.03 374,3 ~" =' 364.2 5290.52 i85.3 5352.90 ~68.o 5434,45 10204,11 70.91 227,99 -6505,88 1~55,53 69,25 226.60 -6744,52 10896,52 70,29 226.25 %980,08 11070,74 70,38 ,_~V.23 -7099,69 I1o'"25,38 73,32 227.97 -7271,55 -7841,23 10204,19 230.Y? %119.80 10555,56 230.29 -8367,~ 10896,52 230,17 -8494,45 11070.74 230.11 -8682,70 11325.40 230,05 278,6 552O,35 273.9 5608,96 · -2.75,0 5499.~ 275,7 5788,35 · ~?~ o 5878.12 ~/ ~JTv,,.. 71,62 22.7+62 -7449.97 11849.76 70,64 227.95 -7624,14 12109.36 70,93 ?.29,06 -7796,21 12370,26 71,46 228.50 -7%8.19 12631.04 70,56 .328,58 -8140,93 -8879,~5 11590,8t ~0,00 0071,45 11849,83 229.95 -9265,98 12109,47 229.92 -9~2,26 12370,38 22?.90 -9657,77 12631.20 E29+87 272,3 5967.41 274,9 6051,58 86,6 ../-.075,56 93,4 6098,59 A' 91,6 .I17,34 12888,07 71,15 227.68 -8312,59 13149,49 73,19 '.227,76 -8488,62 13232,67 74,65 229,12 -8543,82 13323,19 76,81 22%02 -8/~3.14 13412,80 79,55 230.26 -8661,17 -9849,28 12888,Z7 22?,84 -10042,88 13149,76 229.79 -10105,16 13232,95 229,79 -10173,56 13323,49 229,78 -10241,85 13413,10 229,78 99.9 6i33,92 88,3 6i46,40 86,4 6157.26 91.2 o16i.~8 92.9 6i79.-'.30 13511.31 81,34 ~.s30,% -8723,68 I~98+73 82.41 231,47 -8778,44 134~.47 83,16 231,37 -8831.92 13775.00 83.33 ~1,54 -8888.35 13867.20 83,05 231+91 -8945,~ -10317.~? 13511.80 229.79 -10386,14 13599.01 229,80 -10453.18 13684,73 229.81 -10524.01 13775.25 229.82 -I0596,42 13867,44 229.83 94.~2 81%,37 90.3 6201,21 :o2,.- 6220.15 13960.64 83,08 232.31 -9002,90 !4050,19 83,14 .!32,47 -9057,59 14211.15 83.45 232,96 -9155.19 -10670.20 l~o,~.oTov.oo"~ 22?,84 -10741,20 14050,39 229.86 -I0849.~7 14211.31 229,89 , THH FINAL SURVEY iS A F~ECTICC4 TO TOYAL DEPTH, 75.8 6228,79 14286.32 ~.45 232,96 -9200,53 -i0929.47 14286,1.~ 229,91 0.38 0.81 0,59 0.20 0.71 0,33 0.42 0,24 0,17 0,31 0,41 0,57 0,30 0,50 1,13 0,62 0,37 0.39 0,27 0,33 0,38 0,74 2,26 2,31 3,27 1,92 i ,34 0,87 0,26 0,50 0,43 0,19 0,35 0,04 ARCO Alaska, Inc. Date: July 2, 1996 Transmittal #: 9712 RETURN TO' ARCO Alaska, Inc. Attn.: Julie Nash Kuparuk Operations File Clerk ATO-1119 B 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. j~M-33 ~M-33 CDR Acknowledged:CDN -~~ ~/ O4/27/96 04/27/96 DISTRIBUTION' Mr. Vernon E. Pringle Jr. DeGIoyler and MacNaughton One Energy Square Dallas, TX 75206 ChapmanZbspan NSK Wells Group NSK 69 Sharon AIIsup-Drake DS Development ATO - 1205 'Larry G r~'ht~ AC)GCC 3001 Porcupine Drive Anchorage, AK 99501 Please acknowledge Date: 50-103-20240-00 JUL 0 5 1996 ,~aska 0ii & Gas Cons. Commission Anchorage Clifton Posey Geology ATO - 1251 GeoQuest 500 w. International Airport Road Anchorage, AK 99518-1199 A'I'TN: Sherrie NO. 10264 Company: 6/28,/96 Alaska Oil & Gas Cons Comm Attn: Howard Okland 3001 Porcupine Drive Anchorage, AK 99501 Field: Kuparuk (Open Hole) LIS Well Job # Log Description Date BL RF Sepia DIR MWD Tape ~ ~,lfV~- ~ 96,!69 CDR/CON - 960427 1 'IH~-94l ,~,/V'~, ....,~ 1~ 96169 CDR 960427 I 1 ~3 ,,~/V'/- } ,,~ 96169 CDN 960427 I 1 ..... PLEASE NOTE: NO DEPTH SHIFTING PER DAVE SHAFER Please sign and return one copy of this transmittal to Sherrie at the above address. Thank you. RECEIVED DATE: II II ~ ~ ~nnl~ Alaska Oil & Gas Cons. Commi~0n ~d~o~o ~KA 0IL AND GAS / CONSERVATION COMMISSION / TONY KNOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 April 10, 1996 Michael Zanghi, Drill Site Develop Supv ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 2M-33 ARCO Alaska, Inc. Permit No 96-72 Surf Loc. 114'FSL, 367'FWL, Sec. 27, T11N, R8E, UM Btmhole Loc. 1214'FSL, 412'FEL, Sec. 6, T10N, R8E, UM Dear Mr. Zanghi: Enclosed is the approved application for permit to ddll 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 659-3607. Sincere~ J. David Norton, P. E. Commissioner BY ORDER OF THE COMMISSION /encl c: Dept of Fish & Game, Habitat Section - w/o encl Dept 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 [~ lb Type of Well Exploratory E] Stratigraphic Test [~] Development Oil X Re-Entry [~ Deepen r~ Service r~ Development Gas r~ Single Zone X aultipleZone ';~. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RKB 41', Pad 106' feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchorage, AK 99510-0360 ADL 25590, ALK 2676 4. Location of well at Sudace 7. Unit or property Name 1 1. Type Bond (see 2o AAC 2,5.025) 114' FSL, 367' FWL, Sec. 27, T11N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET) 8. Well number Number 1868' FSL, 372' FWL, Sec. 5, T10N, R8E, UM 2M-33 #U-630610 At total depth 9. Approximate spud date Amount 1214' FSL, 412' FEL, Sec. 6, T10N, R8E, UM 4/1 5/96 $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-16 16821' MD 3412 @ TD feet 6.7' @ 475' feet 2501 6383' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 300' feet Maximum hole angle 71 .62° Maximurnsurface 1829 pslg At total depth ('I'VD) 3300 pslg 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD 'rVD MD TVD (include stage data) 24" 16" 62,5# H-40 Weld 80' 41' 41' 121' 121' +200 CF 12.25" 9,625" 40.0# L-80 BTC 5747' 41' 41' 5788' 3090' 670 Sx Arcticset III & HF-ERW 1240 Sx Class G 8.5" 7" 26.0# L-80 BTCMOE 16780 41' 41' 16821' 6383' 290SxClassG 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 Length Size Cemented Measured depth True Vertical depth Structural Conductor ~,~..U ~__~ [ V ~D Sudace Intermediate Production Liner APR 0 3 1996 Per/oration depth: measured true vertical Alaska Oil & Gas Cons. Cemmissio~ An, chr~r~.qe 20. Attachments Filing fee X Property plat r'] BOPSketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot BI Refraction analysis BI Seabed report BI 20 AAC 25.050 requirements X 21 I hereby cedily that the foregoin, g is true and correct to the best of my knowledge Signed , Title Drill Site Develop. Supv. Date Commission Use Only Approval See cover . nL~oe date_~/_/~) letter for . .-- other requirements Conditions of approval Samples required' O Yes ,~ No Mud log required [-1 Yes '~ No Hydrogen sulfide measures j~ Yes BI No Directional survey required [] Yes D No Required working pressure for BOPE E~] 2M [] 3M [~ 5M E] 1OM r~ 15M Other: ORIGINAL SIGNED BY & David Nor~, P.E. by order of Approved by Commissioner the commission Date -,- - Form 10-401 Rev. 7-24-89 Submit in tri[~licate GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD KRU 2M-33 . . . 10. 11. 12 13 14 15 16 17 Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (5,788')according to directional plan. Run and cement 9-5/8" casing. Install and test BOPE to 3000 psi. 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 (16,821') according to directional plan. Run open hole evaluation logs or LWD tools as needed. Run and cement 7" casing string. (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.) ND BOPE. NU tubinghead & either full opening valve (if logging planned) or master valve and upper tree assembly (if no logging planned). Note: As a dedicated producer, no cased hole cement bond logs will be run unless there are problems with the cement job. Secure well and release rig. Move in and rig up Nordic #1. Install and test BOPE. Pressure test 7" casing to 3500 psi. Run completion assembly. Set packer and pressure test tubing and annulus. ND BOPE and install production tree. Shut in and secure well. Clean location and release rig in preparation for perforating. DRILLING Well FLUID KRU PROGRAm,. 2M-33 Spud to 9-5/8" surface casing Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids 9.0-10.0 15-25 15-35 50-80' 5-15 15-40 10-12 9.5-10 _+10% Drill out to wei~lht up 8.4-9.6 5-15 5-8 30-40 2-4 4-8 8-10 9.5-10 4-7% Weight up to TD 10.7 10-18 8-12 35-50 2-4 4-8 4-5 through Kuparuk 9.5-10 <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 APR 0 5 '~$96 ,Anchorage General Notes: 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 1,829 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest existing well to 2M-33 is 2M-16. As designed, the minimum distance between the two wells would be 6.7' @ 475' MD. Drilling Area Risks' Risks in the 2M-33 drilling area include lost circulation and high pressures in the Kuparuk formation. Lost circulation above the Kuparuk will be addressed with lost circulation material (LCM) and reduced circulating rates as needed. 7" casing will be topset above the Kuparuk and Nordic Rig #1 will drill out a 6-1/8" hole, and run a 5" liner to TD if lost circulation cannot be controlled with LCM and reduction of circulating pressure alone. Efforts to reduce Kuparuk geopressure at the target location and careful analysis of pressure data from offset wells show that a mud weight of 10.7 ppg will provide sufficient overpressure to safely drill, trip pipe, and cement. The 9-5/8" casing shoe will be tested to an equivalent mud weight of 12.5 ppg upon drilling out of the surface casing. *Spud mud should be adjusted to a FV between 50-80 sec/qt to drill gravel beds. .-.,.'~NULAR PUMPING OPERATi,.,NS WELL KRU 2M-33 Incidental fluids developed from drilling operations will be pumped down the surface/production casing annulus of an existing well or the nearest dedicated disposal well (2M-23). (Note that cement rinseate will not be iniected down the dedicated disposal well but will be recycled or held for an open annulus.) The open annulus will be left with a non- freezing fluid during any extended shut down (> 4 hr) in pumping operations. The 2M-33 surface/production casing annulus will be filled with diesel after setting the production casing and prior to the drilling rig moving off of the well. If isolation is required per regulations on significant hydrocarbons, the annulus will later be sealed with cement from the surface shoe to the base of the permafrost, with Arctic pack fluid or diesel from the base of the permafrost to the surface, if the surface shoe is within 200' TVD of the top of the hydrocarbons. Alternatively, if the hydrocarbons are far below the shoe then sufficient cement volume will be pumped during the production cement job to cover the formation. It is requested that 2M-33 be permitted for annular pumping occurring as a result of drilling operations, per proposed regulations 20 AAC 25.080. Any zones containing significant hydrocarbons will be isolated prior to initiating any annular pumping. There will be no USDW's open below the shoe or potable/industrial water wells within one mile of the receiving zone. Please reference the enclosed directional drilling plan for other formation markers in this well. A list of all publicly recorded wells within 1/4 mile of the disposal operation is included in this permit application. Surface casing will be set in the Cretaceous shales below the base of the West Sak Sands. These 300-500' thick shales are part of the Colville Group and are known to provide vertical barriers to fluid flow. The surface casing shoes will be set +_200' vertical below the base of the West Sak into the heart of the shales. The maximum volume of fluids pumped down the annulus of this well will not exceed 35,000 bbls without the specified permission of the AOGCC. Fluid densities will range from diesel to a maximum of 12.0 ppg for drilling wastes. Using 12.0 ppg fluid and the rig's specified maximum pumping pressure of 1500 psi, the maximum pressure at the surface casing shoe is estimated by: Max Shoe Pressure = (12.0 ppg) * (0.052) * (Surf. Shoe TVD) + 1500 psi Max Pressure = 3430 psi The surface and production casing strings exposed to the annular pumping operations are determined to have sufficient strength by using the 85% collapse and burst ratings listed below. OD Wt Conx Collapse 85% of Burst 85% of (in) (Ib/ft) Grade Range Type (psi) Collapse (psi) Burst 9.625 40 L-80 3 BTC 3090 2627 5750 4888 7.000 26 L-80 3 BTC-M 5410 4599 7240 6154 Fluids to be disposed of in subject annulus will be limited to drilling wastes associated with drilling a well as defined in 20 AAC 25.254 (g) (1). ARCO ALASKA, Inc. Pad 2M 33 slot #33 Kuparuk River Unit North Slope, Alaska CLEARANCE REPORT by Baker Hughes !NTEQ Your ref : 33 Version #11 Our ref : prop1571 License : Date printed : 29-Mar-96 Date created : 13-Mar-96 Last revised : 29-Mar-96 Field is centred on nTO 16 18.576,w150 5 56.536 Structure is centred on nTO 16 17.458,w150 5 54.03 Slot location is n70 16 18.579,w150 5 43.346 Slot Grid coordinates are N 5948985.412, E 488207.654 Slot local coordinates are 114.00 N 367.00 E Reference North is True North Main calculation performed with 3-D Minimum Distance method Object wellpath 9B Version #6,,9B,Pad 2M PMSS <3542-4022'>~,9,Pad 2M PGMS <0-12177'>,,9A,Pad 2M PMSS <0-3464'>~,23~Pad 2M PGMS <0-7119'>~12~Pad 2M PMSS <O-10399'>~,6,Pad 2M PGMS <O-9810'>,,14,Pad 2M PGMS <O-7947'>,,17wPad 2M PMSS <1579-3318'>,,1,Pad 2M PGMS <O-9800'>,w1A,Pad 2M PGMS <O-7855'>,~27~Pad 2M PGMS <O-9835'>,,28,Pad 2M PGMS <O-6765'>~26~Pad 2M PGMS <O-7445'>,,25,Pad 2M PGMS <0 - 9130'>~,19~Pad 2H PGMS <0-7510'>~3,Pad 2M PGMS <0 - 10598'>,~21~Pad 2M PGMS <0 - 7926'>,w18~Pad 2M PGMS <0 - 12125'>~,13~Pad 2M PGMS <0-7020'>~,15~Pad 2M PGMS <0-8931'>,~5~Pad 2M PGMS <0-9070'>,,20~Pad 2M PGMS <0-7800'>,,lO,Pad 2M PGMS <0-7450'>~24~Pad 2M PGM$ <0 - 9515'>,,11,Pad 2M PGMS <0-6848'>,~16~Pad 2M PGMS <0-10340'>~,7~Pad 2M PGMS <0-8598'>,,22,Pad 2M PGMS <0-13385'>~,32,Pad 2M Closest approach with 3-D minimum distance method Last revised Distance M.D. Diverging from M.D. 13-Mar-96 2853.5 3600.0 8520.0 11-Nov-92 87.0 1375.0 1375.0 9-Feb-96 87.0 1375.0 1375.0 27-Apr-92 162.0 300.0 16821.2 11-Nov-92 117.1 1025.0 5340.0 11-Nov-92 261.7 850.0 12480.0 22-0ct-92 30.7 800.0 800.0 22-0ct-92 12.0 0.0 0.0 5-Jan-93 279.8 1237.2 1237.2 5-Jan-93 279.8 1237.2 1237.2 11-Nov-92 260.4 1400.0 1400.0 22-0ct-92 298.6 1275.0 12~5.0 22-0ct-92 226.9 120.0 120.0 1-Jul-91 212.0 0.0 16645.6 3-Apr-92 62.0 0.0 12480.0 9-Apr-92 343.6 1175.0 1175.0 3-Apr-92 112.0 100.0 16034.8 3-Apr-92 37.0 120.0 16645.6 3-Apr-92 74.0 600.0 600.0 9-Apr-92 23.2 625.0 625.0 30-Ju[-92 195.6 1200.0 1200.0 30-Jul-92 87.0 0.0 16045.6 3-Apr-92 134.9 1100.0 15360.0 30-Ju[-92 186.1 300.0 300.0 3-Apr-92 171.7 850.0 15746.4 1-Jul-91 6.7 475.0 15401.9 22-Feb-93 44.4 1800.0 8520.0 3-Aug-94 137.0 20.0 300.0 18-Feb-93 161.1 3260.0 13660.0 PGMS <O-g350'>,,~d,Pad 2M PGMS <O-11003'>,,2,Pad 2M PMSS <10783-13015'>,,29,Pad 2M PMSS <O-11241>,,29,Pad 2M PGMS <O-12151,,8,Pad 2M PGHS <O-12370'>,,4,Pad 2M 2M-A Version #7,,35,Pad 2M 2M-E Verson #5,,2M-E,Pad 2M 2M-G Version ~/6,,2M-G,Pad 2M 2M-F/M Version #4,,2M-F/M,Pad 2M 2M-C Version #5,,2M-C,Pad 2M --,, v .iv .v, UlVl! n/iiM, i vI, MM ~.'1 11-Nov-92 11-Nov-92 8-Dec-95 1-Feb-93 6-Jan-93 11-Nov-92 13-Mar-96 13-Mar-96 13-Mar-96 13-Mar-96 13-Mar-96 ~_u-- ~L 242.3 =~8.2 2658.2 153.4 1875.0 1875.0 331.9 1825.0 12840.0 331.9 1825.0 11160.0 123.5 1515.2 1515.2 202.4 1975.0 1975.0 50.0 300.0 300.0 32.1 675.0 675.0 53.3 725.0 725.0 16.3 575.0 575.0 25.0 300.0 3180.0 West Scale 1- 425.00 11900 11050 10200 9350 8500 7650 6BO0 5950 5100 4250 5400 2550 1700 I]50 0 850 ESTIMATED ARCO ALASKA, InC. Structure : Pad 2M Well : 33 Field : Kuporuk River Unit Locofion: Nodh Slope, Aloskai 1 Creoted by : jones FOl': D Do~e plotted : 29-Mor-96 Plot Reference is 53 Version ~11, Coordinates ore in feet reference slot t~33. True Vertical Depths are reference RKB (Porker j/245). . SURFACE LOCATION: 114' FSL, 567' FWL SEC. 27, T11N, RSE % % S 50.16 DEC W 13747' (TO TARGET) TD LOCATION: 1214' FSL, 41 2' FEL SEC. 6, TION, RSE 850 _ _ 850 _ _ 1700_ _ 2550_ - 34oo_ - 4250_ _ 51oo_ -- 5950_ 6800_ %% % TARGET LOCATION: I 1868' FSL, 372' FWL TARGET SEC. 5, TI ON, R8E ITVD=6205 ITMD=15785 DEP= 15747 APR 0:5 18S _ 850 · . 850 tO .. 0 _ 1700 _ 2550 _ 3400 _ _ 4250 _ 5100 _ 5950 - _ 6800 _ 7650 _ 8500 _ 9350 % %-¢.,~'% __10200 '.l>~ ~ SOUTH 8806 4%. WEST 10555 27.00 ~.00 ./~.OST WD:~.~7 ~:~9~ ~.oo V u~,u s,os wo:,~ mo:,~o o~:~s~ TANGENT ANGLE 45.00 51 0 ~~00 1/ W S~ ~DS ~¢=2013 1U~=2425 D[~=1065 71.0~ DEG EOC ~vu=211z ,MD=2687 DEP=1308 ~ B/ W SAK SNDS ~D=2890 ~D=5153 DEP=3648 Camp Sst ~ TABASCO SNDS ~D=2903 TMD=5195 DEP=3687 ~~~ ~=3o~o ~=s~ss ~[~=~2so . TD ANGLE ~-~o 75.g4 DEG HRZ MIDPOINT WD 5908 TMD-14725 DEP-12731 B/ HRZ ~=6008 TMD=15042 OEP=IS032 BEGIN R~L BUILO ~:6121 TMD:15402 DEP=13374 TARGET ANGLE vUNIT C ~=6193 TMD:lS700 DEP:13663 83 11 DEG r~r - T/ ~a SNDS T~=OZOa · BEGIN SLOW DROP ~=6235 TMD=16035 DEP=13995 B/ KUP SNOS W0=6335 TM0=16621 0E~=14572 ~=6383 ~=1fi821 DEP=14767 850 0 850 1700 2550 5400 4250 5100 5950 6800 7650 8500 9350 10200 11050 11900 12750 15600 14450 15500 Scale 1 · 425.00 Vertical Section on 230.16 azimuth with reference 0.00 N, 0.00 W from slot #33 Creo[ecl by : jones For: D PETRASHi Date plotted : 2g-Mer-96 jPIot Reference is ~ Version ~11. J Coordinates ore in feet reference slot True Vertical Depths~are reference RKB (Parker JJ ARCO ALASKA, Structure : Pod 2M Well : 33 Field : Kuparuk River Unit Location : NoPrh Slope, Alaska I I V < 260 240 220 200 180 160 140 120 1 O0 20( West 8O 28O 60 I I I I I I I I I I I I I I I I I 40 11 O0 113001700 500 o ~_ 1 lOO~ 500 % 20 500 40 ~o 6O % 80 280 900 1100 I I I I I I 260 240 220 200 180 160 140 120 1 O0 80 <-- West 9O0 1700 1100 Scale 1 · 10.00 0 20 40 60 1500 Cons. Com:flissio~ ~chom9e 1300 60 40 20 0 20 60 40 20 0 20 40 60 80 140 60 180 _~00 .260 280 $00 I 60 Scale 1 ' 10.00 I I V C~--ot¢o by : jones For: D PETRASH] ~te piotteo : plo~ Reference is .3.3 version ~] 1. coordinotes ore im feet reference $iot True Veaical Depths ore reference RKEI (Porker Ii'lC Structure : Pod 2M Well : .33 Field : FuDaruk River Unit Location : Nodh Slope, Alaska~ t { West ~co,~ ~. ~o.oo 920 880 840 800 760 720 680 640 600 560 520 480 440 400 560 320 280 240 oo~ ~ ~ / ,/~ /.//,~oo ~,o0 r~o° _ __/ /- : .... ...,' ' .... ' / /' / :.~ _280 ~ ~ / -'"' --"' -/ / ," /' ,~oo ~ ~ ~o ~ 52o 700 /'" /'"' ' //'/ /1300 // :/ /-'" --/ ./>/ 1900 / / // ?,oo ..::,/ :' ? // .:: 360: 400t 4401 480_ 520_ _ 560_ _ 600_ 5~O_ 720_ 760_ _ 800_ _ 340_ J / /'~500 i I i ! 880 840 // ./~300 /900 1700 ,' ~' ': ¢,:;;, :' "'.,, ~. ¥ ~';2'' r. / / / / /' / .,,:-., ~,pp, 0 3 1996' >' / .:/? .,/ -~,i~.~. o~1 ~ ~,~: c¢.,. ,~,,'~.~i / //,/' / ' /'2100 / , / / / / / / 800 760 720 680 640 600 560 520 480 440 400 560 520 West _560 _ _400 440 480 _520 _ _560 _ _600 _640 _680 L720 I760 800 I [ I t840 280 240 Scale 1 · 20.00 I I V Created b~ : jon~ For: D PETRASH Oate plotted : 2g-Mor-g6 Plot Reference is ~ Version ~11. Coord~n~ am ~n f~t reference slot r~e Ve~ic~l Depths o~e reference RKB ANCO ALASKA, I1~C. Structure : Pod 2M Well : 33 Field : Kuparuk River Unit Location : North Slope, Alaska 2400 2500 2200 21 O0 2000 1900 1800 1700 1600 1500 14-00 1300 1200 11 O0 1000 900 800 0 0 '-' Co 700 800 900 100_ 200 I I V 1600 1700 1800 2000 21001 2200 1 , 24.00 2300 5300, 5700 '.700 500 600 ' · 700 0 80O Io0 9OO 1000 , - ,-or#,,aission .... ~.~ska Oi~ & Gas ,,ans. u. /~°A~ora . ,aoo 2200 I I ~2I I I I"'l I I I~'1 I [' I I I I I I I I I I I I I I I I 2200 100 2000 1900 1~00 1700 1800 1,500 1400 13~0 120~ 1100 1000 gO0 800 Wesf 100 o 14O0 I t 500 [ V ~.LIPARUK RIVER UNI. 20" DIVERTER SCHEMATIC 6 I4 I 5 3 DO NOT SHUT IN DIVERTER AND VALVE AT SAME TIME UNDER ANY CIRCUMSTANCES. . MAINTENANCE & OPERATION UPON INITIAL INSTALLATION: · CLOSE VALVE AND FILL PREVENTER WITH WATER TO ENSURE NO LEAKS. · CLOSE PREVENTER TO VERIFY OPERATION AND THAT THE VALVE OPENS IMMEDIATELY. CLOSE ANNULAR PREVENTER IN THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN VALVE TO ACHIEVE 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 ONE 16' OUTLET. 5. ONE 16" HCR KNIFE VALVE WITH 16' DIVERTER LINE. THE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. DIVERTER LINE WILL BE PLACED FOR OPTIMUM DISPERSION IN PREVAILING WIND CONDITIONS. 6. 20" - 2000 PSI ANNULAR PREVENTER. DKP 11/9/94 7 , 6 5 1. 16" - 2000 PSI STARTING HEAD 2_ 11 "- 3000 PSI CASING HEAD 3. 11" - 3000 PSI X 1 3.5/8" - 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 13 5/8" 5000 PS, ,.'tOP 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. ;~ 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 3 MINUTES. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 3 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 BO'I-rOM PIPE RAMS. TEST BO'FI-OM RAMS TO 250 PSI AND 3000 PSI FOR 3 MINUTES. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 3 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 FOR 3 MINUTES. 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. VBRS WILL ACCOMODATE 3-1/2" TO 5-1/2" OR 5" TO 7" PIPE ODS AS APPROPRIATE. 7 , 6 I 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 13 5/8" 5000 P. BOP STACK ACCUMULATOR CAPACr'I-Y 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. & 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. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSI AND HOLD FOR 3 MINUTES. INCREASE PRESSURE TO 3(X)O PSI AND HOLD FOR 3 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 W1TH 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. & OPEN TOP PIPE RAMS AND CLOSE Bo,-rOM PIPE RAMS. TEST BO~-~OM RAMS TO 250 PSI AND 3000 PSI FOR 3 MINUTES. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 3 MINUTES. BLEED TO 7ERO 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 FOR 3 MINUTES. 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. VBRS VVILL ACCOMODATE ~1/2" TO 5-1/2" OR 5" TO 7" PIPE ODS AS APPROPRIATE. APR 0 5 '1996 -Oil & Gas Cons, .v .LL PERMIT CHECKLIST 'IELD ,; POOL INIT CLASS ~.,A," GEOL AREA PROGRAM: exp [] dev~ redrll [] aery [] wellbore seg [] ON/OFF SHORE___~__ ADMINISTRATION 1. Permit fee attached ................... ~Y 2. Lease number appropriate ................ ! 3. Unique well name and number ............... 4. Well located in a defined pool ............. 5. Well located proper distance from drlg unit boundary.. 6. Well located proper distance from other wells ...... 7. Sufficient acreage available in drilling unit ..... ./~ 8. If deviated, is wellbore plat included ........ 9. Operator only affected party .............. 10. Operator has appropriate bond in force ......... 11. Permit can be issued without conservation order .... 12. Permit can be issued without administrative approval..~ 13. Can permit be approved before 15-day wait ....... ENGINEERING REMARKS 14. Conductor string provided ............... Y~ N 15. Surface casing protects all known USDWs ........ ~ N 16. CMT vol adequate to circulate on conductor & surf csg.. Y~ N 17. CMT vol adequate to tie-in long string to surf csg . . .,~Y ~ 18. CMT will cover all known productive horizons ...... _~ N 19. Casing designs adequate for C, T, B & permafrost .... ~ N 20. Adequate tankage or reserve pit ............. N 21. If a re-drill, has a 10-403 for abndnmnt been approved..~ 22. Adequate wellbore separation proposed. ~.~.~ N 23. If diverter required, is it adequate..'.'.'.'.'.'.'.'.'~ N 24. Drilling fluid program schematic & equip list adequate .~ N 25. BOPEs adequate .................... '~ N 26. BOPE press rating adequate; test to ~~ psig. Y~ N 27. Choke manifold complies w/API RP-53 (May 84) ...... ~Y =~/~ 28. Work will occur without operation shutdown ....... ~ N 29. Is presence of H2S gas probable ............ ~ N GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures .... Y N / 31. Data presented on potential overpress~re zones ..... Y N// /9 ] ~ 32. Seismic analysis of shallow gas zones .......... yN _ /~_~'~/~ ~ 33. Seabed condition survey (if off-shore) ........ / N 34. Contact name/phone for weekly progress reports . . . .//. Y N [exploratory only] // GEOLOGY: ENGINEERING: COMMISSION: BEW DWJ Comments/Instructions: 'q\cheklist rev 11/95 Well HistorY File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. * ALASKA COMPUTING CENTER * ....... SCHLUMBERGER ....... COMPANY NAME : ARCO ALASKA, INC. WELL NAME : 2M-33 FIELD NAME : KUPARUK RIVER BOROUGH : NORTH SLOPE STATE : ALASKA API NUMBER : 50-103-20240-00 REFERENCE NO : 96169 RECEIVED JUL 0 ;5 1996 Alaska Oil & Gas Cons. Com~ ~,~e * ALASKA COMPUTING CENTER * ....... SCHLUMBERGER ....... COMPANY NAME : ARCO ALASKA, INC. WELL NAME : 2M- 33 FIELD NAJViE : KUPARUK RIVER BOROUGH : NORTH SLOPE STATE : ALASKA API NUMBER : 50-103-20240-00 REFERENCE NO : 96169 LI~ Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 1~.~0 PAGE: **** REEL HEADER **** SERVICE NA~E : EDIT DATE : 96/06/20 ORIGIN ' FLIC REEL NAME : 96169 CONTINUATION # : PREVIOUS REEL : CO~ff4~NT : ARCO ALASKA INC., KUPARUK 2M-33, API #50-103-20240-00 **** TAPE HEADER **** SERVICE NAME : EDIT DATE : 96/06/20 ORIGIN : FLIC TAPE NAME : 96169 CONTINUATION # : 1 PREVIOUS TAPE : COMMENT : ARCO ALASKA INC. ~ KUPARUK 2M-33, API #50-103-20240-00 TAPE HEADER KUPARUK RIVER MWD/MAD LOGS WELL NA~E : 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: ELEVATION (FT FROM MSL O) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: WELL CASING RECORD 1ST STRING 2ND STRING 2M-33 501032024000 ARCO ALASKA, INC. SCHLUMBERGER WELL SERVICES 20-JUN-96 BIT RUN 1 96169 SRL/DOM MORRISON BIT RUN 2 BIT RUN 3 27 llN 8E 114 367 147.00 147.00 106.00 OPeN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 8.500 9.625 4873.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 1~40 3RDSTRING PRODUCTION STRING REMARKS: Well drilled 20-APR through 27-APR-96 with CDR/CDN. All data was collected in a single bit run. $ $ PAGE: **** FILE HEADER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01CO1 DATE · 96/06/20 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER: 1 EDITED MERGEDMWD Clipped curves; all bit runs merged. DEPTH INCRE~IENT: 0.5000 FILE SUM~JhgY LDWG TOOL CODE START DEPTH M~FD 4763.0 $ BASELINE CURVE FOR SHIFTS: NONE CURVE SHIFT DATA (M~ASURED DEPTH) BASELINE DEPTH .............. $ ~iERGED DATA SOURCE LDWG TOOL CODE $ RENARKS: No depth adjustments were made per Dave Shafer. This file also contains the Very Enhanced QRO resisitivity with 2' average that was reprocessed at GeoQuest. $ STOP DEPTH .......... 16340.0 .......... EQUIVALENT UNSHIFTED DEPTH .......... ....... BIT RUN NO. MERGE TOP MERGE BASE LIS FORMAT DATA LIS' Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 1~.~0 PAGE: 3 ** DATA FORMAT SPECIFICATION RECORD ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 56 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 18 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 630372 O0 000 O0 0 1 1 1 4 68 0000000000 RA MWD 0Pff4~630372 O0 000 O0 0 1 1 1 4 68 0000000000 RP MWD OH~ff~ 630372 O0 000 O0 0 1 1 1 4 68 0000000000 VRA MWD OHMM630372 O0 000 O0 0 1 1 1 4 68 0000000000 VRP MWD OPE4~ 630372 O0 000 O0 0 1 1 1 4 68 0000000000 DER I4WD 0PI~630372 O0 000 O0 0 1 1 1 4 68 0000000000 ROP MWD FPHR 630372 O0 000 O0 0 1 1 1 4 68 0000000000 FET MWD HR 630372 O0 000 O0 0 1 1 1 4 68 0000000000 GR MWD GAPI 630372 O0 000 O0 0 1 1 1 4 68 0000000000 RHOBMWD G/C3 630372 O0 000 O0 0 1 1 1 4 68 0000000000 DRHOMWD G/C3 630372 O0 000 O0 0 1 1 1 4 68 0000000000 PEF MWD BN/E 630372 O0 000 O0 0 1 1 1 4 68 0000000000 CALNMWD IN 630372 O0 000 O0 0 1 1 1 4 68 0000000000 NPHIMWD PU-S 630372 O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA ** DEPT. 16339.000 RA.MWD -999.250 RP.MWD -999.250 VRA.MWD -999.250 VRP.MWD -999.250 DER.MWD -999.250 ROP.MWD 160.978 FET.MWD -999.250 GR.MWD -999.250 RHOB.MWD -999.250 DRHO.MWD -999.250 PEF.MWD -999.250 CALN.MWD -999.250 NPHI.MWD -999.250 LIS Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 1~.~0 PAGE: DEPT. 4763.000 RA.M~FD -999.250 RP.MWD -999.250 VRA.MWD VRP.MWD -999.250 DER.MWD -999.250 ROP.MWD -999.250 FET.MWD GR.MWD -999.250 RHOB.MWD -999.250 DRHO.MWD -999.250 PEF.MWD CALN.MWD -999.250 NPHI.I~arD 48.900 -999.250 -999.250 -999.250 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01CO1 DATE : 96/06/20 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NA~E : EDIT .002 SERVICE : FLIC VERSION : O01CO1 DATE : 96/06/20 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE FILE HEADER FILE AUJMBER 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: 0.5000 FILE SURmLARY VEaVDOR TOOL CODE START DEPTH MWD 4763.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE: SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY or REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : STOP DEPTH .......... 16340.0 27-APR-96 FAST 2.5 4.0C MEMORY 16340.0 4763.0 16340.0 75 LIS Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 14:40 PAGE: HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE CDR RESISTIVITY CDN NEUT./DENS. $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT) : BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3): RESISTIVITY (OHF~4) AT TEMPERATURE (DEGF) : MUD AT M~ASURJED TEMPERATURE (MT): MUD AT MAX CIRCULATIONG TEMPERATURE : MUD FILTRATE AT (MT): MUD CAKE AT (MT): 72.2 83.4 TOOL NUMBER ........... RGS051 NDSO57 8.500 4873.0 LSND 10.30 52.0 9.5 600 3.8 2.980 55.0 2.290 55.0 R~W-2~r~KS: ************ RUN 1 DRILLED INTERVAL 4890' - 16340' HOLE ANGLE AT TD = 83.45 DEG @ 16340' RES TO BIT: 41.51 '; GR TO BIT: 51.93 ' NEUT TO BIT: 101.47'; DENS TO BIT: 94.49' TD WELL @ 18:00 26-APR-96 CDR NOT BHC. UP TRANSMITTER ONLY. ATR BAD FROM 15552' TO 16108'. SOFTWARE V4.0C $ LIS FORMAT DATA TOOL STANDOFF (IN): 1.0 EWR FREQUENCY (HZ): 20000 NEUTRON TOOL MATRIX: SANDSTONE MATRIX DENSITY: 2.65 HOLE CORRECTION (IN): LIS' Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 14:40 PAGE: ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 60 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 17 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 630372 O0 000 O0 0 2 1 1 4 68 0000000000 ATR LW1 OHMM 630372 O0 000 O0 0 2 1 1 4 68 0000000000 PSR LW1 OPiM~ 630372 O0 000 O0 0 2 1 1 4 68 0000000000 DER LW1 OPL~94630372 O0 000 O0 0 2 1 1 4 68 0000000000 ROPE LW1 F/HR 630372 O0 000 O0 0 2 1 1 4 68 0000000000 TABR LW1 HR 630372 O0 000 O0 0 2 1 1 4 68 0000000000 GR LW1 GAPI 630372 O0 000 O0 0 2 1 1 4 68 0000000000 RHOB LW1 G/C3 630372 O0 000 O0 0 2 1 1 4 68 0000000000 DRHO LW1 G/C3 630372 O0 000 O0 0 2 1 1 4 68 0000000000 PEF LW1 BN/E 630372 O0 000 O0 0 2 1 1 4 68 0000000000 CALN LW1 IN 630372 O0 000 O0 0 2 1 1 4 68 0000000000 TNPH LW1 PU 630372 O0 000 O0 0 2 1 1 4 68 0000000000 TABD LW1 630372 O0 000 O0 0 2 1 1 4 68 0000000000 DPHI LW1 PU 630372 O0 000 O0 0 2 1 1 4 68 0000000000 DCAL LW1 IN 630372 O0 000 O0 0 2 1 1 4 68 0000000000 ** DATA ** DEPT. 16339. 000 ATR. LW1 -999. 250 PSR. LW1 -999. 250 DER. LW1 ROPE. LW1 160. 978 TABR. LW1 - 999. 250 GR. LW1 - 999.250 RHOB. LW1 DRHO.LW1 -999.250 PEF.LW1 -999.250 CALN. LW1 -999.250 TNPH.LW1 TABD.LW1 -999.250 DPHI.LW1 -999.250 DCAL.LW1 -999.250 -999,250 -999,250 -999,250 LIS'~ Tape Verification Listing Schlumberger Alaska Computing Center 20-JUN-1996 14.=0 PAGE: ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION . O01CO1 DATE : 96/06/20 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** TAPE TRAILER **** SERVICE NAME : EDIT DATE : 96/06/20 ORIGIN : FLIC TAPE NAME : 96169 CONTINUATION # : 1 PREVIOUS TAPE : COMMENT : ARCO ALASKA INC., KUPARUK 2M-33, API #50-103-20240-00 **** REEL TRAILER **** SERVICE NAME : EDIT DATE : 96/06/20 ORIGIN : FLIC REEL NAME : 96169 CONTINUATION # : PREVIOUS REEL : CO~iENT : ARCO ALASKA INC., KUPARUK 2M-33, API #50-103-20240-00
