Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
204-031
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: 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 7090'feet 6343', 6373', 6420'feet true vertical 3660'feet none feet Effective Depth measured 6343'feet 6103'feet true vertical 3155'feet 3023'feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth) 3-1/2" L-80 6136' MD 3040' TVD Packers and SSSV (type, measured and true vertical depth) 6103' MD N/A 3023' TVD N/A 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: West Sak Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: 3310' 2051' Burst Collapse Production Liner 7061' Casing 3658'7087' 3280' 108'Conductor Surface Intermediate 16" 9-5/8" 77' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 204-031 50-029-23198-00-00 P.O. Box 100360 Anchorage, AK 99510 3. Address: ConocoPhillips Alaska, Inc. N/A 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL25651, ADL25660 Kuparuk River Field/ West Sak Oil Pool KRU 1E-119 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 MD ~ Size 108' ~~~ INJECTOR ~~ ~ 323-552/ 323-684 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG ~ Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Packer: Baker SABL-3 Packer SSSV: None Allen Eschete allen.eschete@conocophillips.com 265-6558Interventions Engineer 6454-6524', 6562-6614', 6788-6810', 6827-6852', 6860-6872' 3223-3268', 3294-3329', 3448-3464', 3475-3493', 3498-3507' Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 12:15 pm, Apr 11, 2024 Digitally signed by Allen Eschete DN: CN=Allen Eschete, E=Allen.Eschete@ConocoPhillips.com Reason: I am the author of this document Location: Date: 2024.04.11 12:06:53-08'00' Foxit PDF Editor Version: 13.0.0 Allen Eschete RBDMS JSB 041824 DSR-4/12/24 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 11, 2024 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: Allen Eschete Interventions Engineer CPAI Drilling and Wells ConocoPhillips Alaska, Inc. hereby submits a Report of Sundry Well Operations on KRU 1H-102 (PTD: 204-031). The work from sundry number 323-684 (Change Approved Program Casing Squeeze) has been completed but was unsuccessful. An MIT-T was performed with the coil unit and failed. The well will remain shut in until a path forward is created and approved. If you have any questions or require any further information, please contact me at 265-6558. DTTMSTART JOBTYP SUMMARYOPS 11/20/2023 REPAIR WELL RIH WITH 2" BALL DROP NOZZLE, CIRCULATE WELL OVER TO FRESHWATER. PERFORM INJECTIVITY TEST. UNABLE TO INJECT AT 850 PSI. WHP INCREASE WHP TO 1050 PSI AND ABLE TO INJECT AT 0.1 BPM. BATCH UP CEMENT AND PUMP 11 BBL OF 13 PPG FINECEM. PUMP 1 BBL CEMENT AHEAD AND LAY IN 4 BBL OF CEMENT. PERFORM HESITATIONS UNTIL ACHIEVING 1500 PSI WHP. SQUEEZE TOTAL OF 9 BBL TO FORMATION. CLEAN OUT CEMENT DOWN TO 6,300' RKB AND WASH ACROSS JEWELRY WHILE CHASING RETURNS TO SURFACE. FREEZE PROTECT TUBING WHILE POOH. READY FOR STATE WITNESSED TAG AND TEST IN 48 HRS. 11/25/2023 REPAIR WELL TAG 2.75" D NIPPLE @ 6124' RKB FOR CORRECTION, TAG CEMENT @ 6298' RKB W/ 1.75" SAMPLE BAILER (VERY MINIMAL CEMENT IN BAILER) PERFORM MITT TO 1650 PSI (PASSED), RE TAG CEMENT @ 6298' RKB W/ 2.5" BAILER (GOOD SAMPLE OBTAINED) 11/26/2023 REPAIR WELL STATE WITNESS TAG TOC @ 6300' RKB (GOOD SAMPLE), MITT TO 1670 PSI (PASSED). READY FOR CTU 11/28/2023 REPAIR WELL MIRU. RUN GR/CCL TAG @ 6288' CTMD & PAINTED RED FLAG @ 6201' CTMD (NO DATA) RERUN BACK UP TOOLS W/ GOOD DATA (CORRECTED TAG DEPTH @ 6296' RKB / CORRECTED EOP @ FLAG DEPTH IS 6195.25' RKB). CORRECT TO LDL ON (10/20/18). RIH W/ UNDEREAMER & 2.72" BEAR CLAW MILL W/ TOOLS & 5500' CTMD BEGIN TO HAVE PACKOFF/INJECTOR ISSUES. CALL FOR MANLIFT AND POOH TO INSPECT. 11/29/2023 REPAIR WELL REPAIR STRIPPER LUBE REGULATOR. RAN 2.72" BEAR CLAW MILL & 4.92" UNDERREAM, CORRECT DEPTH AT FLAG, DRY TAG TOC AT 6295'. MILL/UR HARD CEMENT F/ 6295' T/ 6343' RKB. ATTEMPT TO MITT TO 1500 PSI (FAILED W/ EST 4 GPM LLR). JOB SUSPENDED FOR PLAN FORWARD. 11/30/2023 REPAIR WELL RIG DOWN CTU 6, LEAVE LOCATION FOR 2P-451. 3/21/2024 REPAIR WELL TAGGED TOC @ 6342' CTMD. ESTABLISH INJECTIVITY TEST UP TO 1 BPM @ 2000 PSI CIRC PSI W/ TBG @ 1360 PSI. PUMPED CALCIUM CHLORIDE & SODIUM SILICATE IN ATTEMPT TO SEAL OFF LEAK (TBG NEVER LOCKED UP WHILE PUMPING ALL OF THE SODIUM SILICATE) WAIT 1 HOUR AND ATTEMPT TO MIT OR ESTABLISH ANOTHER INJECTIVITY TEST FOR FUTURE PLANNING. 3/22/2024 REPAIR WELL ATTEMPT TO MITT POST CALCIUM CHLORIDE/SODIUM SILICATE TREATMENT (FAILED) ESTABLISH INJECTIVITY RATE UP TO 1.5 BPM @ 3000 CIRC PSI - 1445 TBG. RE-TAG TOC @ 6342' CTMD. JOB SUSPENDED FOR PLAN FORWARD. 1E-119 Repair Summary of Operations Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 6,343.0 1E-119 11/28/2023 zembaej Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: MIlled Cement down to 6343' RKB 1E-119 11/28/2023 zembaej Notes: General & Safety Annotation End Date Last Mod By NOTE: Fullbore RPPG Treatment 4590 lbs to D MBE 4/28/2017 pproven 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 31.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 30.2 3,309.8 2,050.8 40.00 L-80 BTC PRODUCTION 5 1/2 4.95 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 22.7 Set Depth … 6,136.1 Set Depth … 3,040.0 String Max No… 3 1/2 Tubing Description TUBING 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) 22.7 22.7 0.00 HANGER 8.000 VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE 4.610 CAMCO DS NIPPLE w/ 2.875" NO GO 2.875 4,464.1 2,456.0 72.85 GAS LIFT 4.725 CAMCO KBG-2-9 2.900 6,026.1 2,985.4 61.47 GAS LIFT 4.725 CAMCO KBG-2-9 2.900 6,078.1 3,010.7 60.27 NIPPLE 4.470 CAMCO DS NIPPLE w/ 2.812" NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR 4.000 LOCATOR SUB & SPACEOUT 3.000 6,088.6 3,015.9 60.04 PBR 4.790 BAKER 80-40 SLIMLINE PBR w/ 14' SEAL ASSEMBLY 3.000 6,102.6 3,023.0 59.73 ANCHOR 4.500 BAKER K-22 ANCHOR 2.980 6,103.3 3,023.3 59.72 PACKER 4.560 BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE 4.500 HES X NIPPLE w/ 2.75" PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG 4.520 CPAI WIRELINE ENTRY GUIDE PART #546397 2.990 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) 6,338.0 3,151.7 53.83 LEAK - CASING CASING LEAK IN THE 5-1/2", 0.5 BPM LLR, 11/20/2018 4.950 6,343.0 3,154.6 53.67 Cement 15.8 cement. Updated cement top depth 6,336' CTM tag on 10/1 prior to pumping re- squeeze MILLED CEMENT W/ 2.72" BEAR CLAW MILL DOWN TO 6343' RKB (New Cement Top) 11/28/2023. 7/10/2020 0.000 6,373.0 3,172.6 52.75 Sand Plug Dump bail sand from top of IBP @ 6420' RKB to 6373' RKB. Also ~ 3' of safe carb on top. 2/27/2019 0.000 6,420.0 3,201.5 51.31 Retrievable IBP 2.50" IBP 11/7/2018 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) 4,464.1 2,456.0 72.85 1 GAS LIFT DMY INT 1 0.0 4/13/2004 11:30 0.000 6,026.1 2,985.4 61.47 2 GAS LIFT DMY INT 1 0.0 2/9/2005 3:00 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 6,454.0 6,524.0 3,223.0 3,268.5 WS D, 1E-119 10/7/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B, 1E-119 10/6/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,594.0 6,614.0 3,315.3 3,328.9 WS B, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,827.0 6,852.0 3,475.4 3,492.8 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,860.0 6,872.0 3,498.4 3,506.8 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 6,300.0 6,317.0 3,129.5 3,139.4 Remedial 13 PPG FINECEM 11/20/2023 1E-119, 4/5/2024 11:24:16 AM Vertical schematic (actual) PRODUCTION; 26.6-7,087.4 IPERF; 6,860.0-6,872.0 IPERF; 6,827.0-6,852.0 IPERF; 6,788.0-6,810.0 IPERF; 6,594.0-6,614.0 IPERF; 6,562.0-6,594.0 IPERF; 6,454.0-6,524.0 Retrievable IBP; 6,420.0 Sand Plug ; 6,373.0 Cement; 6,343.0 LEAK - CASING; 6,338.0 Remedial; 6,300.0 ftKB PACKER; 6,103.3 GAS LIFT; 6,026.1 GAS LIFT; 4,464.1 SURFACE; 30.2-3,309.8 NIPPLE; 506.9 CONDUCTOR; 31.0-108.0 KUP INJ KB-Grd (ft) 31.42 RR Date 4/13/2004 Other Elev… 1E-119 ... TD Act Btm (ftKB) 7,090.0 Well Attributes Field Name WEST SAK Wellbore API/UWI 500292319800 Wellbore Status INJ Max Angle & MD Incl (°) 73.02 MD (ftKB) 5,488.12 WELLNAME WELLBORE1E-119 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 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: ___________________ 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft):Junk (MD): 7090'None Casing Collapse Structural Conductor Surface Intermediate Production Liner 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 Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 1/15/2024 3-1/2" Packer: Baker SABL-3 Packer SSSV: None Perforation Depth MD (ft): L-80 3280' 6454-6524', 6562-6614', 6788-6810', 6827-6852', 6860-6872' 7061' 3223-3268', 3294-3329', 3448-3464', 3475-3493', 3498-3507' 5-1/2" Perforation Depth TVD (ft): 108' 3310' 3658'7087' 16" 9-5/8" 77' 6136' MD 108' 2051' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY West Sak Oil Pool TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL25651, ADL25660 204-031 P.O. Box 100360, Anchorage, AK 99510 50-029-23198-00-00 Kuparuk River Field West Sak Oil Pool AOGCC USE ONLY Tubing Grade: Tubing MD (ft): Packer: 6103' MD and 3023' TVD SSSV: N/A Allen Eschete Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: allen.eschete@conocophillips.com (907) 265-6558 Interventions Engineer KRU 1E-119 3660'6373', 6420' N/A Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Effective Depth MD: 6343' Effective Depth TVD: 3155' Digitally signed by Allen Eschete DN: CN=Allen Eschete, E=Allen.Eschete@ ConocoPhillips.com Reason: I am the author of this document Location: Date: 2023.12.21 04:04:38-09'00' Foxit PDF Editor Version: 13.0.0 Allen Eschete 323-684 By Grace Christianson at 3:21 pm, Dec 21, 2023 SFD 12/26/2023 X VTL 01/04/2024 X 10-404 *&:JLC 1/4/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.01.04 13:55:29 -09'00'01/04/24 RBDMS JSB 010924 KRU 1E-119 (PTD 204-031) 10-403 Change of Approved Program (sundry #323-552) Well Work Jus&'ca&on & Objec&ves: 1E-119 has a producon casing leak below the producon packer that has been unsuccessfully squeezed 3 mes. A!er the most recent squeeze the leak rate is approximately .02 bbl/min based on having to pump 0.1 bbl every 5 minutes to bump pressure up to 1500 psi. The goal of this procedure is to us e calcium chloride and sodium silicate to seal o) the remaining leak point. Risk/Job Concerns: •Casing leak @ 6338 •Previous cement squeeze milled down to 6343' RKB •~0.1 bpm leak rate •This job requires a 10-403. Steps: Coil: 1. MIRU CTU 2. RIH with coil and tag top of cement @ 6343' RKB. 3. Pull up ~1' and spot 3 bbls of calcium chloride (CaCl2). 1. This puts the top of the CaCl2 @ ~ 6217' RKB. 4. PUH and squeeze away at least 2 bbls of the CaCl2 to the leak. 5. RIH to 6343' and circulate out any remaining CaCl2 with minimal pressure to minimize pushing the CaCl2 further out from the leaks. 1. Any remaining will =ash set with sodium silicate (Na2SO4) 6. AAempt to squeeze away 3 bbls of Na2SO4. 1. The 2 chemicals may react quickly to plug o) the leaks and not allow for the full 3 bbls to be squeezed. 7. Circulate out any remaining Na2SO4. 8. RIH to 6343' and then perform MIT to 1500 psi. 1. If unable to reach 6343', mill unl past leaks and then perform MIT to 1500 psi then connue milling to top of plug @ 6420' RKB. 9. RIH and pull plug @ 6420' RKB. 10. RIH and FCO/FnS to TD. 11. RDMO. Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 6,343.0 1E-119 11/28/2023 zembaej Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: MIlled Cement down to 6343' RKB 1E-119 11/28/2023 zembaej Notes: General & Safety Annotation End Date Last Mod By NOTE: Fullbore RPPG Treatment 4590 lbs to D MBE 4/28/2017 pproven 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 31.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 30.2 3,309.8 2,050.8 40.00 L-80 BTC PRODUCTION 5 1/2 4.95 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 22.7 Set Depth … 6,136.1 Set Depth … 3,040.0 String Max No… 3 1/2 Tubing Description TUBING 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) 22.7 22.7 0.00 HANGER 8.000 VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE 4.610 CAMCO DS NIPPLE w/ 2.875" NO GO 2.875 4,464.1 2,456.0 72.85 GAS LIFT 4.725 CAMCO KBG-2-9 2.900 6,026.1 2,985.4 61.47 GAS LIFT 4.725 CAMCO KBG-2-9 2.900 6,078.1 3,010.7 60.27 NIPPLE 4.470 CAMCO DS NIPPLE w/ 2.812" NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR 4.000 LOCATOR SUB & SPACEOUT 3.000 6,088.6 3,015.9 60.04 PBR 4.790 BAKER 80-40 SLIMLINE PBR w/ 14' SEAL ASSEMBLY 3.000 6,102.6 3,023.0 59.73 ANCHOR 4.500 BAKER K-22 ANCHOR 2.980 6,103.3 3,023.3 59.72 PACKER 4.560 BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE 4.500 HES X NIPPLE w/ 2.75" PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG 4.520 CPAI WIRELINE ENTRY GUIDE PART #546397 2.990 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) 6,338.0 3,151.7 53.83 LEAK - CASING CASING LEAK IN THE 5-1/2", 0.5 BPM LLR, 11/20/2018 4.950 6,343.0 3,154.6 53.67 Cement 15.8 cement. Updated cement top depth 6,336' CTM tag on 10/1 prior to pumping re- squeeze MILLED CEMENT W/ 2.72" BEAR CLAW MILL DOWN TO 6343' RKB (New Cement Top) 11/28/2023. 7/10/2020 0.000 6,373.0 3,172.6 52.75 Sand Plug Dump bail sand from top of IBP @ 6420' RKB to 6373' RKB. Also ~ 3' of safe carb on top. 2/27/2019 0.000 6,420.0 3,201.5 51.31 Retrievable IBP 2.50" IBP 11/7/2018 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) 4,464.1 2,456.0 72.85 1 GAS LIFT DMY INT 1 0.0 4/13/2004 11:30 0.000 6,026.1 2,985.4 61.47 2 GAS LIFT DMY INT 1 0.0 2/9/2005 3:00 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 6,454.0 6,524.0 3,223.0 3,268.5 WS D, 1E-119 10/7/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B, 1E-119 10/6/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,594.0 6,614.0 3,315.3 3,328.9 WS B, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,827.0 6,852.0 3,475.4 3,492.8 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,860.0 6,872.0 3,498.4 3,506.8 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 6,300.0 6,317.0 3,129.5 3,139.4 Remedial 13 PPG FINECEM 11/20/2023 1E-119, 12/20/2023 11:35:34 AM Vertical schematic (actual) PRODUCTION; 26.6-7,087.4 IPERF; 6,860.0-6,872.0 IPERF; 6,827.0-6,852.0 IPERF; 6,788.0-6,810.0 IPERF; 6,594.0-6,614.0 IPERF; 6,562.0-6,594.0 IPERF; 6,454.0-6,524.0 Retrievable IBP; 6,420.0 Sand Plug ; 6,373.0 Cement; 6,343.0 LEAK - CASING; 6,338.0 Remedial; 6,300.0 ftKB PACKER; 6,103.3 GAS LIFT; 6,026.1 GAS LIFT; 4,464.1 SURFACE; 30.2-3,309.8 NIPPLE; 506.9 CONDUCTOR; 31.0-108.0 KUP INJ KB-Grd (ft) 31.42 RR Date 4/13/2004 Other Elev… 1E-119 ... TD Act Btm (ftKB) 7,090.0 Well Attributes Field Name WEST SAK Wellbore API/UWI 500292319800 Wellbore Status INJ Max Angle & MD Incl (°) 73.02 MD (ftKB) 5,488.12 WELLNAME WELLBORE1E-119 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE C:\Users\kmjunke\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\H2LGR515\2023-11-28_15959_KRU_1E-119_CoilFlag_Transmittal.docx DELIVERABLE DISCRIPTION Ticket # Field Well # API # Log Description Log Date 15959 KRU 1E-119 50-029-23198-00 Coil Flag 28-Nov-23 DELIVERED TO Company & Address DIGITAL FILE # of Copies LOG PRINTS # of Prints CD’s # of Copies 1 AOGCC Attn: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Ak. 99501-3539 Delivered By: CPAI Sharefile ______________________________ ______________________________________ Date received Signature PLEASE RETURN COPY VIA EMAIL TO: DIANE.WILLIAMS@READCASEDHOLE.COM READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM PTD: 204-031 T38160 12/1/2023 Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.01 09:44:26 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:21 Township:11N Range:10E Meridian:Umiat Drilling Rig:N/A Rig Elevation:N/A Total Depth:7,090 ft MD Lease No.:ADL0025651 Operator Rep:Suspend:P&A:X Conductor:16"O.D. Shoe@ 108 Feet Csg Cut@ Feet Surface:9-5/8"O.D. Shoe@ 3310 Feet Csg Cut@ Feet Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet Production:5-1/2"O.D. Shoe@ 7087 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet Tubing:3-1/2"O.D. Tail@ 6136 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 6,420 ft 6300 ft 8.3 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1670 1620 1620 IA 570 570 570 OA 140 140 140 Remarks: Attachments: The plan was to run in with a bailer and tag the top of cement and get an accurate depth then perform an MITT to 1500 PSI. The tool assembly consisted of a 10 feet x 1-7/8" weight pipe roller assembly, 3 feet oil jars, an 8-foot set of spangs, with a 7 foot x 2-1/2" bailer and mule shoe with a flapper valve. Approximate weight of 200 LBS. With their 31-foot correction factor top of cement was tagged at 6,300 ft MD. Tools were pulled out of the hole and slickline rigged down. LRS rigged up for the MITT. I checked the certified guages and made sure they were current and reading correctly. November 26, 2023 Josh Hunt Well Bore Plug & Abandonment KRU 1E-119 ConocoPhillips Alaska inc. PTD 2040310; Sundry 323-552 none Test Data: P Casing Removal: Brent Rogers/ Roger Mauser Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2023-1126_Plug_Verification_KRU_1E-119_jh Plug Verification – KRU 1E-119 (PTD 2040310) Photo by AOGCC Inspector J. Hunt 11/26/2023 Cement sample from tag with bailer 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: Cement Squeeze 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? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,090'None Casing Collapse Structural Conductor Surface Intermediate Production Liner 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 Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7,087' 3,658' 11/5/2023 3 1/2" PACKER - BAKER SABL-3 PACKER SSSV - NONE Perforation Depth MD (ft): L-80 3,280' 6454- 6524, 6562- 6594, 6594- 6614, 6788- 6810, 6827-6852, 6860-6872 7,061' 3223-3268, 3294- 3315, 3315-3329, 3448-3464, 3475-3493, 3498-3507 5 1/2" Perforation Depth TVD (ft): 108' 3,310' 16" 9 5/8" 77' 6,136' MD 108' 2,051' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY West Sak Oil Pool TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 25651, ADL 25660 204-031 P.O. Box 100360, Anchorage, AK 99510 50-029-23198-00-00 Kuparuk River Field West Sak Oil Pool AOGCC USE ONLY Tubing Grade: Tubing MD (ft): Packer: MD= 6103 TVD= 3023 SSSV: N/A Allen Eschete Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Allen.Eschete@ConocoPhillips.com (907) 265-6558 Intervention Engineer KRU 1E-119 3,660' 6,317' 3,139'6317', 6336', 6373', 6420' N/A Perforate Repair Wepair Well Stratigraphic Development Service BOP Test No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:48 pm, Oct 05, 2023 Digitally signed by Allen Eschete DN: CN=Allen Eschete, E=Allen.Eschete@ConocoPhillips.com Reason: I have reviewed this document Location: Date: 2023.10.05 10:01:45-08'00' Foxit PDF Editor Version: 12.1.2 Allen Eschete 323-552 SFD 10/6/2023 DSR-10/5/23 X X 10-404 VTL 10/25/2023$%8 Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.10.26 08:18:49 -08'00'10/26/23 RBDMS JSB 102623 1D-119 Casing Leak Re-Squeeze Date: 10/4/2023 Network Number: 10451623 Prepared by: Allen Eschete 661-348-2949 _________________________ Approved by: Will Earhart 907-265-1077 _________________________ Digitally signed by Allen Eschete DN: CN=Allen Eschete, E=Allen.Eschete@ ConocoPhillips.com Reason: I have reviewed this document Location: Date: 2023.10.05 09:34:08-08'00' Foxit PDF Editor Version: 12.1.2 Allen Eschete Digitally signed by Will Earhart DN: OU=Engineering Supv, O=Well Integrity and Intervention, CN=Will Earhart, E=william.c.earhart @conocophillips.com Reason: I have reviewed this document Location: Date: 2023.10.05 09:45:12-08'00' Foxit PDF Editor Version: 12.1.2 Will Earhart Contents Contents ........................................................................................................................................................ 1 Objective ....................................................................................................................................................... 1 Job Design Data ............................................................................................................................................. 1 Reservoir Data: .......................................................................................................................................... 1 Design Envelope: ....................................................................................................................................... 1 Job Risks & Concerns: ............................................................................................................................... 2 Prework ......................................................................................................................................................... 3 1. Coil Tubing Well Supervisor - Make Contacts ................................................................................... 3 Cement Squeeze ........................................................................................................................................... 3 1. CTU – Cement Re-Squeeze ................................................................................................................ 3 2. SL – Cement Tag: ............................................................................................................................... 8 3. Coil Tubing – Underream Cement, FCO Sand, Pull IBP, PBTD Tag ..................................................... 8 Appendix ..................................................................................................................................................... 10 1E-119 Schematic ........................................................................................................................................ 10 1 Objective This slant well has an MBE in the D-sand to 1E-166. After multiple failed attempts to pump RPPG in 2017 we realized that the production casing was leaking above the D- sands, so they set an IBP to isolate the sands then went to pumping cement into the production casing leaks. There have been two squeezes to date, which have decreased the leak rate but hasn’t solved the issue. At the time it was assumed that the reason the RPPG was failing was because of this production casing leak. The goal of this procedure is to attempt another re-squeeze of the casing leak to seal it. Job Design Data Reservoir Data: SBHP: FSBHP = 1241 psi with WHP = 350 psi taken on 12/22/2017 Volumes/Capacities: 3.5” Tubing x 2” Coil = 0.0048 bbl/ft x 6135.6 RKB = 29.5 bbls 5.5” Casing x 2” Coil = 0.0199 bbl/ft x 181 RKB = 3.6 bbls 3.5” Tubing from 6136’ to 6056’ = 0.0087 bbl/ft x 80 RKB = 0.7 bbls 5.5” Casing from 6136’ to TOC= 0.0199 bbl/ft x 181 RKB = 3.6 bbls 2” Coil = 0.0238 bbl/ft or 42 ft/bbl 3.5” Tubing x 2” Coil = 0.0048 bbl/ft or 208 ft/bbl 5.5” Casing x 2” Coil = 0.0199 bbl/ft or 50.2 ft/bbl 3.5” Tubing = 0.0087 bbl/ft or 115 ft/bbl 5.5” Casing = 0.0238 bbl/ft or 42 ft/bbl Diesel FP, to 2000’ TVD = 3162 RKB = (.0087 bbl/ft x 2000) = 27.5 bbls Design Envelope: Tubing: 3-1/2”, 9.3#/ft, L-80: Maximum allowable surface pressure = 7040 psi (80% of tubing burst when liquid packed with Seawater to TT), but 1E-119 has 5000 psi Wellhead equipment, so 5000 psi x 80% safety factor = 4000 psi, so Wellhead MASP = 4000 psi, and also Tubing MASP = 4000 psi. 2 Production Casing: 5-1/2”, 15.5#/ft, L-80: MASP = 5110 psi (80% of casing burst if IA is liquid packed with Seawater to Packer), but Wellhead MASP = 4000 psi, so Production Casing MASP = 4000 psi. Surface Casing: 9-5/8”, 40#/ft, L-80: Surface Casing MASP = 3866 psi. This MASP assumes casing is new, and that no backside pressure support exists, and that an 80% safety factor has been applied. Wellhead: Vetco Grey Horizontal, 4-1/16”, 5000 psi rated. With 80% safety factor applied, Wellhead MASP = 4000 psi. Job Risks & Concerns: 1. Frac gradient is 0.70 psi/ft so we need to keep ECD < 13.5 ppg. a. This puts holding back pressure no higher than 800 – 850 psi. 2. Utilize hesitations during the Re-Sqz as needed to help build squeeze pressure during the job. Displace some cement away to Csg leak, followed by halt pumping for short period, then displace a couple more bbls cement to leak, followed by hesitate again for short period, etc. This should achieve a rise to target squeeze pressure of ~850 psi before all cement gets displaced to the leak and we proceed to cement cleanout. Do hesitations holding max choke backpressure at 800 - 850 psi to keep below Frac pressure 3. Worst case TOC is 6055’ RKB assuming 0 cement gets squeezed away. 3 Prework 1. Coil Tubing Well Supervisor - Make Contacts 1) Schlumberger: schedule CTU for pumping a cement job from a Halliburton Cement Van. 2) Halliburton: Bryce Hinsch, Bryce.Hinsch@halliburton.com, (307)-359-0067. Request UCA sheets. Cement should have 6 - 7 hr thickening time and API fluid loss between 100cc - 200cc @ 30 min, and Yp < 5. Request pumpable 5 bbls of 13 ppg FineCem for job. 3) Order Fluids: request a full 290 bbl warm Freshwater transport for Pre-Flush, and for mixing 5 bbls Cement, circulating fluid, injectivity test, and as spacer fluid during the Cement Sqz job. Also, request a Diesel transport for CT FP (50 bbls), and for tubing FP to 2000’ TVD (27.5 bbls). Cement Squeeze 1. CTU – Cement Re-Squeeze 1) MIRU Schlumberger CTU with 2” OD CT. MIRU Halliburton Cement Van, Diesel transport, and warm Freshwater transport. RU 30 to 40 bbl Trip Tank (for step 17 below). Do not mix cement batch until requested. 2) PT equipment as required. Mitigate crew exposure during PT. 3) RIH with CT with cementing nozzle (use ball drop cementing nozzle). 4) Tag TOC at ~6317’ RKB, then PU 10’ and flag pipe. 5) PUH with nozzle to 6217’ RKB (~100’ above TOC), then open CT x Tbg to tanks, and circulate in FW to remove the Diesel column from the well. 6) Pump ~2 CT volumes (~100 bbls) of Freshwater down CT at 1 bpm, to get clean consistent fluid density on the CT backside, and to displace all Diesel from CT & tubing. Monitor return tanks for flow from CT x Tbg annulus to tanks (we may have some split going to Csg leak). Pump at 1 bpm until Diesel returns are seen flowing to tanks, then apply 100 psi backpressure with the choke to help prevent formation fluid from entering the well from the casing leak. 4 a. CT Backside Volumes if circulating with the nozzle at 6236' RKB: i. 2” CT x 2.992” ID Tubing volume to 6136’ RKB (at Tubing Tail) = 29.5 bbls. ii. 2” CT x 4.95” ID Casing volume from 6136 to 6217’ (at Nozzle) = 1.6 bbls iii. 2” CT Backside Total volume to 6236’ RKB = (29.5 + 1.6) = 31.1 bbls 7) While Diesel returns are seen from CT backside to tanks, hold 1 bpm and slowly apply 200 psi of backpressure with choke to prevent formation fluid from entering wellbore. 8) When no more Diesel is seen in returns, perform a short injection test to verify casing leak LLR below Frac pressure. Perform injection test by slowly dropping pump rate to lowest minimum rate that the pump can hold stable (assumed to be 4 gpm) while slowly SI returns by closing choke to let backside pressure rise as needed to get minimum stable injected rate away to casing leak, but limit max backpressure held on choke to < 850 psi (Frac pressure) 9) If it is not possible to inject minimum stable rate (4 gpm) away to casing leak with CT backside SI and choke backpressure held to < 850 psi max, then hold choke backpressure at < 850 psi while taking some returns to tanks, as needed. a. Record accurately as possible in WSR what percent of minimum stable rate is injecting to casing leak vs. going tanks. Record the stable minimum rate and final backpressure on choke to get casing leak to take all minimum stable pump rate (if this was possible with < 850 psi max backpressure), else record that it was not possible to get minimum stable rate pumped away to the leak below 850 psi Frac pressure. Note, failed MIT-T of 10/6/20 had LLR = 4 gpm at 1360 psi 10) If we could not inject to the Casing leak, or if injectivity rate to casing leak was below minimum stable pump rates (4 gpm) while holding max backpressure on choke < 850 psi, then we will likely have to pump some cement to the Casing 5 leak above Frac pressure to get some cement behind pipe. This means max backpressure held on choke be > 850 psi. However, if we have to frac cement away, we can limit pumping cement at minimum stable rate that the pump can provide, and limit maximum backpressure held on choke to 1500 psi. These parameters help mitigate fracing severity as much as possible while performing a resqueeze of casing leak. 11) Perform the following injection test only if injectivity test results attained in step 8 showed that minimum stable pump rate (4 gpm) could not inject away to casing leak with backpressure held on choke limited to < 840 psi: a. Set pump rate to lowest minimum rate that the pump can hold stable (assumed 4 gpm) while slowly SI returns by closing choke to let backside pressure rise as needed to get minimum stable injected rate to casing leak, provided this can be done with maximum backpressure held on choke kept < 1500 psi. If needed, hold 1500 psi max backpressure on choke while taking some returns to tanks, then estimate accurately as possible and record in WSR the splits of minimum stable rate is going to casing leak vs. returning to tanks. As long as we get some reasonable injection split to casing leak at < 1500 psi held on choke, we will plan to proceed with the resqueeze. b. If it is not possible to inject minimum stable rate (4 gpm) away to casing leak with CT backside SI and choke backpressure < 1500 psi max, or if injectivity to casing leak is very low, call Allen Eschete, 661-348-2949, to discuss a plan forward. We may consider decreasing volume of cement to be pumped or terminate the resqueeze due to unacceptable injectivity. c. If remaining acceptable leak rate to the casing leak was confirmed per the injectivity tests, then start mixing a cement batch. 12) If Csg Leak takes acceptable LLR per injectivity testing, then continue pumping Freshwater to casing leak at minimum pump rate needed to maintain some positive wellhead pressure while mixing a 5 bbl batch of 13 ppg FineCem. Batches should have working time of 6 - 7 hrs. Obtain UCA sheets 6 13) Pump 5 bbls of 13 ppg FineCem down CT while adjusting choke to hold ~100 psi (target) of back pressure on CT x Tbg annulus. RIH to flag depth (~10’ above TOC) before cement gets to nozzle. 14) Pump 5-10 bbls freshwater spacer behind cement, followed by cement contaminant for cement cleanout. Cement contaminant type and bbl volume TBD by Halliburton Rep and/or Wells Supervisor. 15) With CT ~10’ above TOC, let the Lead Cement exit nozzle 16) Allow first 1 bbl of cement to fill rathole above TOC and Csg leak at ~6317’ RKB. Wait for pressure bump before circulating in remaining cement. Any additional amount of cement pumped outside CT before bump is observed should be counted as cement behind pipe. 17) Once pressure increase of 300 to 500 psi is observed, open returns through the choke and maintain that additional backpressure while stacking in all remaining cement. Take all returns to a 30 - 40 bbl open top trip tank with accurate barrel markers to accurately monitor returned volume. a. If choke backpressure held reaches > 800 psi, slowly open choke to maintain ~800 psi max backpressure on choke to avoid fracing as cement is being stacked into well. 18) Monitor returns carefully and note any difference between volume pumped and volume returned. Any difference should be counted as additional barrels of cement placed behind pipe over what was originally monitored. 19) Once starting to take returns, lay in cement one for one unless barrel counter on surface tanks indicates we are not getting 1:1 returns. Laying in cement with CT can be accomplished by monitoring pumping rates and return rates on a spreadsheet. 20) Keep CT Nozzle 50 to 100’ below the expected Cement top. As the last barrel of cement leaves the CT, increase the running speed to pull out of the cement top. Check and note the return volume in gauged tank as last barrel of cement exits CT, then swap to taking returns to large open top tanks. 7 21) Once all Cement has exited CT, continue to circulate, and POOH with CT to safety at 500’ above the worst possible Cement top at 6055’ RKB. Continue to circulate fluid until CT backside is believed to have contaminant from nozzle depth to surface. We can increase pump rate but should maintain the same backpressure on choke. 22) Once CT nozzle is at safety depth and contaminant is circulated, SD pumping and SI returns. Allow pressures to stabilize on tubing and CT x Tbg annulus. Pressure should stabilize at some pressure close to circulating pressure but well above zero. While SD, drop ball to convert nozzle to jet swirl circulation. Hesitate for 30 minutes and monitor pressure to ensure stability. If needed, pump additional fluid to maintain ~500 psi backpressure on choke or the circulation pressure (whichever is lower). Any additional volume pumped away is counted as additional cement placed behind pipe. 23) Hesitate until all pressures have bled to a stable level, then resume circulating contaminant while holding the stable pressure established. Do not allow held pressure to build or bleed off anymore, and maintain held pressure during entire cement cleanout and during FP. 24) RIH to circulate out excess cement. There is no need to wait on the ball to reach the nozzle, and this will also help clean up tubing during POOH. 25) RIH jetting down with CT nozzle. Make sure that enough contaminant is pumped for every barrel of cement that is being penetrated (2:1 mix ratio of contaminant to Cement is typical). Pump rate should be at least 1.5 bpm to keep annular fluid velocity over 150 fpm for good lifting of all contaminated cement. Using the mix ratio. Open choke as needed to maintain constant backpressure on well. Avoid application of any excess pressure with choke. Slight drops in pressure are less damaging than excess pressure. 26) Jet wash cement down to tubing tail at 6136’ RKB, then down to ~6200’ RKB in 5.5” casing to leave ~117’ of uncontaminated cement over last TOC @ 6317’ RKB. This will give us ~138’ of cement above the casing leak @ 6338’ RKB. 8 27) Chase cement OOH at 80% of returned fluid velocity (use spreadsheet to calculate this value based on pump rate). 28) If we run out of contaminant, chase OOH with water and displace top 2000’ TVD (3163’ RKB) of Tubing with Diesel FP (27.5 bbls). RD CTU. WOC at least 48 hrs. 2. SL – Cement Tag: 1) MIRU 2) After WOC at least 48 hrs, MIRU SL. RIH & tag TOC in tubing or casing. Correct SL MD to RKB depth and record RKB tag depth in WSR. This RKB reference should be noted when CT tags TOC to flag pipe for depth control before CT starts to underream cement. Perform MITT to 1500 psi of Cement Plug to verify Cement Plug I Sqz integrity. RD DSL. a. If MITT failed and TOC is shallower than the casing leak, then we may need to run an LDL to verify the leak point. Contact Allen Eschete, 661- 348-2949, to request LDL procedure, if needed. If MITT passed, we proceed. 3. Coil Tubing – Underream Cement, FCO Sand, Pull IBP, PBTD Tag 1) If MITT passed, but TOC tagged was above Csg Leak at 6338’ RKB, then cement needs to be removed to open up casing to below the Casing leak to enable an MIT against the squeezed Casing leak. If cement removal is required, make the following contact. 2) Contact Quadco for underreamer that can drift through 2.75” TT nipple at 6124’. a. Bi-Center Bit Milling BHA option to mill 2.98” pilot hole is not recommended to mill Cement in deviated 5.5” Csg, since it will likely exit tubing and then pilot hole along low side of casing to create an off-center pilot hole through the Cement Plug. A better option is a reliable UR BHA to get more fully open 4.95” casing ID. 3) MIRU CTU. Spot Water & Diesel transports. RIH with Underreamer BHA of largest OD available for best durability that will drift through the 2.75” Min ID X Nipple at 6124’ RKB. 9 a. Make initial tag on TOC & flag pipe before underreaming. Reference TOC RKB tag depth DSL made on TOC to flag pipe as the same depth. Underream cement in 5.5” Csg to 6343’ RKB (referencing CT ‘flag’ for depth control) while taking returns to tanks. Do not mill past 6343’ RKB, since BHA will be 5’ below squeezed leak at 6338’ RKB, and we want to keep BHA above TOS and IBP fish neck, and leave some Cement Plug for MITT above IBP, and to leave some cement bottom plug for possible re-squeeze, if needed. 4) MITT to 1500 psi on CT x Tbg to verify if cement squeeze is holding. Do not MITT over 1500 psi since we do not expect to ever exceed WHP > 1500 psi on well in the future for a RPPG treatment. a. If MITT failed: record LLR & pressure data in WSR. Depending on MITT leak rate, we will decide on need for possible re-squeeze of casing leak. i. Contact Allen Eschete: (661)-348-294, regarding MITT results to decide if we should RD CTU & MOL for new plan forward for well or continue with additional CT work b. If MITT passes, proceed as follows: i. Continue milling Cement Plug to top of sand at ~6373’ RKB while verifying 1:1 returns to tanks. Avoid milling on IBP set at 6420’ RKB (element). POOH with milling BHA. ii. PU & RIH with jetting nozzle to perform CaCO3 Cap/Sand Plug FCO to IBP at 6420’ (element). POOH with Nozzle. iii. RIH with pulling tool to pull Baker 2.5” run OD IBP at 6420’ RKB. Allow time for IBP element to relax, then POOH with IBP. iv. RIH to tag TD. Perform with CT if it will not add another CT workday, else let SL make a tag. 5) RDMO. 10 Appendix 1E-119 Schematic 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 #:________________Signature12/21/2021Wd͗ϮϬϰϬϯϭϬ Ͳ^Ğƚ͗ϯϲϮϲϰJRBy 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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y Samantha Carlisle at 10:04 am, Oct 28, 2020 John W Peirce Digitally signed by John W Peirce Date: 2020.10.28 08:48:44 -08'00' DSR-10/28/2020 RBDMS HEW 10/28/2020 VTL 11/03/20 !"! # "$ %! & $ ' () * &&! " + ,%"! (%! ) & + % !-"$ , %! % + & !-"$ , %! '* ' , %! . ,% %! ! ," ! " + "&%! . ,%&! + ! /! # + % 0 ,&#&! # 12 * + 321 451 6 789:312 ;9<< 12%=53547>?74@A73,&&<:?B;9<<;51B C=9?B;719= 71AB:374@3:D3 <? " A9D941 :D3C=2DC<7>,&"& 22?9=91:=4?7C19=/ <?A9D91 2:12C42EE<9 91 <?F9B54>3539 <?541:F54> 12 ?7C91G17=1A2417D35<<@2;4 22?97<<=91:=4? # # ,##! +! 0 ! &#&! * "( ) ' %=5354;51B:4@9==97D9=91@2;4,$ =532:14?39A1:4@9==97D9=5>B194F<7@9?=535417A8 2:1,=532:1 5<<:4@9==97D9= " 5=7447D5<< =5354A<9747>,9A5312!<974=53 2:1 75<G:4@9==97D9==5354A<97412, 17=1:4@9==97D54>99D212=;2=8,<7> 4@9==97D@2;412&!5@45>B1@931B # 24154:9:4@9==97D54>C=2D&! 9=C2=D75<& , %#" @2;412&& * +9D941H:99E9 :DD7=G2C39=71524? * "12 * + 321A9D9419=? 5>:3 A9D919=?=5354B2<9 7>,&& 39=C2=D 54I9A15J51G19?1?F<91254I9A1& ,+% 71AB:3 A9D941 24154:9A5=A:<7154>C=9?B;719=;B5<9F71AB54>A9D941 :D3 # <?A9D941 7G5412,%H:99E9& <? F9B54@3539 A2417D54719C<:?B2:1A9D94112+"!5=A 2:1A2417D =99E93=219A1C=2D&!(2F 2D3<919) ,%! * , '% =7J9<C=2D 12 ?321:3=5>:3 9=C2=D545157< 19?1 ' , !( %! *K! ) +#%! &+! & &%! % 0 &"! #$ &#"! % &#"! &+! 0 ! %"$ (%"$)#$ &+ ! & %! " & %!* & #! 0 * 0 0 0, "&#! *$ (#"L) * 0 & "%! & "%! 0 ! & #!' 0 & , " 0 *%% 0 0 *%& 0 * + !" #$%$%$&'()* ) + ,- ./ 01230&0'4''5!, 67 , , '4'%8$0))9*:+" !"!" # $%%& !'() * + , - # ! "# $ %!&' ( )**+ ! " #$ $ ! $ $ $ % & '() )'*+,-)% & . % ./.% 0 1 2 +3)!)!'4)5%2 (# ,6789/ 0 1 $7 :7 ( !'()$%%&2; < # *= + > !'(). * 7 :7 ( 6: + ?3)!!)@ A)@A)!9 BA!A)!C7, )! '@?7 &7 ( D) - %) @ %E< +: 7,( BABA)!C7, 5)BB=$F; 2*,,'!! @A)BA)!E 53!!=$F;2*,,'!! G !3 (($0"B' 7 5= 533@=$F; %HH<I$87,E ' 533@=$F;H (($ !' A!! !3 A"B' 7 * H&77 !"!" !"!3 J !K $%%&2;> 6: + ?3'5 A3A9 A)BA47,*;% B3=$F; )A!)A4:'L% B)3B)@L$F; )A!5A4K 3! )MF7(; % K !)' .<% # !!.<% 8 + B' 8 !3' .<% 5'! :8> > +* $8 + , + $%%& + * 2; 6 7%I*;%9, 2; "A)!A)!47, *;% B3= 8( *;% 33)!L7,28 @A3!A)!4% > + )'! : +"B 8 )!! :A.' )' :A.)3 )':A."B8 K%!'() # > C )5 !'() > - )5 !'() > + )5 2; !'() - 2; !'()* $%%& !'() H )!)! 2; - K $%%&)A!5A + 7%6 B3)"=$F; 8( < < 8 9 2; B3B)CB3BB=$F; 8( + $%%& $%%&> : + ?3'5 A3A !A3A7 !'() + ) 7%6 DB3)'$F;9 7 6 B")5=$F;9 8( ( 2; '= $%%& + ,- - 7 - B")5 @!!5= $F; 2;- + + $%%& + 7 + $%%& + 2; +* '=H( B3B)CB3BB=$F; 8( $%%& * !"!3 J $ % : . 7%*8 I. 6!B9)5'5"B Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: RKB 6,317.0 10/16/2020 1E-119 rogerba Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Update TOC post Under Reaming 10/16/2020 1E-119 rogerba Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 31.0 Set Depth (ftKB) 108.0 Set Depth (TVD) … 108.0 Wt/Len (l… 62.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 30.2 Set Depth (ftKB) 3,309.8 Set Depth (TVD) … 2,050.8 Wt/Len (l… 40.00 Grade L-80 Top Thread BTC Casing Description PRODUCTION OD (in) 5 1/2 ID (in) 4.95 Top (ftKB) 26.6 Set Depth (ftKB) 7,087.4 Set Depth (TVD) … 3,658.1 Wt/Len (l… 15.50 Grade L-80 Top Thread BTC-MOD Tubing Strings Tubing Description TUBING String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 22.7 Set Depth (ft… 6,136.1 Set Depth (TVD) (… 3,040.0 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 22.7 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE CAMCO DS NIPPLE w/ 2.875" NO GO 2.875 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE w/ 2.812" NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR LOCATOR SUB & SPACEOUT 3.000 6,088.6 3,015.9 60.04 PBR BAKER 80-40 SLIMLINE PBR w/ 14' SEAL ASSEMBLY 3.000 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 6,103.3 3,023.3 59.72 PACKER BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE HES X NIPPLE w/ 2.75" PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG CPAI WIRELINE ENTRY GUIDE PART #546397 2.990 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) SN 6,317.0 3,139.4 54.44 Cement 13.5 ppg FineCem cement. Pumped cement contaminated down to 6,295'. Updated new cement top after Under Reaming down to 6317' 10/2/2020 6,336.0 3,150.5 53.89 Cement 15.8 cement. Updated cement top depth 6,336' CTM tag on 10/1 prior to pumping re- squeeze 7/10/2020 0.000 6,338.0 3,151.7 53.83 LEAK - CASING CASING LEAK IN THE 5-1/2", 0.5 BPM LLR, 11/20/2018 4.950 6,373.0 3,172.6 52.75 Sand Plug Dump bail sand from top of IBP @ 6420' RKB to 6373' RKB. Also ~ 3' of safe carb on top. 2/27/2019 0.000 6,420.0 3,201.5 51.31 Retrievable IBP 2.50" IBP 11/7/2018 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 6,454.0 6,524.0 3,223.0 3,268.5 WS D, 1E-119 10/7/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B, 1E-119 10/6/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,594.0 6,614.0 3,315.3 3,328.9 WS B, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,827.0 6,852.0 3,475.4 3,492.8 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient 6,860.0 6,872.0 3,498.4 3,506.8 WS A2, 1E-119 10/5/2004 6.0 IPERF 2.5" HSD 2506 PJ, 60 deg phase, random orient Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 4,464.1 2,456.0 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 11:30 2 6,026.1 2,985.4 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 2/9/2005 3:00 Notes: General & Safety End Date Annotation 4/28/2017 NOTE: Fullbore RPPG Treatment 4590 lbs to D MBE 1E-119, 10/27/2020 4:34:07 PM Vertical schematic (actual) PRODUCTION; 26.6-7,087.4 IPERF; 6,860.0-6,872.0 IPERF; 6,827.0-6,852.0 IPERF; 6,788.0-6,810.0 IPERF; 6,594.0-6,614.0 IPERF; 6,562.0-6,594.0 IPERF; 6,454.0-6,524.0 Retrievable IBP; 6,420.0 Sand Plug ; 6,373.0 Cement; 6,336.0 LEAK - CASING; 6,338.0 Cement; 6,317.0 WLEG; 6,135.6 NIPPLE; 6,124.1 PACKER; 6,103.3 ANCHOR; 6,102.6 PBR; 6,088.6 LOCATOR; 6,085.2 NIPPLE; 6,078.1 GAS LIFT; 6,026.1 GAS LIFT; 4,464.1 SURFACE; 30.2-3,309.8 NIPPLE; 506.9 CONDUCTOR; 31.0-108.0 HANGER; 22.7 KUP INJ KB-Grd (ft) 31.42 Rig Release Date 4/13/2004 1E-119 ... TD Act Btm (ftKB) 7,090.0 Well Attributes Field Name WEST SAK Wellbore API/UWI 500292319800 Wellbore Status INJ Max Angle & MD Incl (°) 73.02 MD (ftKB) 5,488.12 WELLNAME WELLBORE1E-119 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY John Peirce Sr. Wells Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, West Sak Oil Pool, KRU 1E-119 Permit to Drill Number: 204-031 Sundry Number: 320-028 Dear Mr. Peirce: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov Enclosed is the approved application for the 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, re Price Chair j DATED this I& of January, 2020. 3BDM&� JAN 3 11010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 JAN 21 2020 OTS //27/ 20 A0GCC 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: Cement SqueezeO 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhilll sAlaska Inc. Exploratory ❑ Development ❑ Stratigraphic ❑ Service O 204-031 3. Address: 6. API Number: P. 0. Box 100360, Anchorage, Alaska 99510 50-029-23198-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A KRU 1E-119 Will planned perforations require a spacing exception? Yes ❑ No El 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 25651 ADL 25660 1 Kuparuk River Field / West Sak Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD Pfective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,090' 3,660' 6999 3596 1300psi 6420 NONE Casing Length Size MD TVD Burst Collapse Conductor 77' 16" 108' 108' Surface 3,280' 95/8 3,310' 2,051' Production 7,061' 51/2 7,087' 3,658' Perforation Depth MD (R): I Perforation Depth TVD (ft): ITubing Size: Tubing Grade: Tubing MD (ft): 6454-6524,6562-6594,6594-6614, 3223-3268,3294-3315,3315-3329, 1 3.500" L-80 6,136' 6788-6810 687-6 6860-6872 3484-3464. 3475-3492 3498-3507 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): PACKER - BAKER SABL-3 PACKER MD= 6103 TVD= 3023 SSSV -NONE N/A 12. Attachments: Proposal Summary 0 Wellbore schematic ❑ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development❑ Service E] 14. Estimated Date for 2/612020 15. Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG 71 GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. John Peirce Contact Name: John Peirce Authorized Name: Authorized Title: Sr. Wells Engineer Contact Email: John.W.Pelrce@cop.com 1 ) Contact Phone: (907) 265-6471 Authorized Signature: ,% __ > _ Date:.L Z G Zv26 11Z012 -e,26 /7- COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: //// O/ „ c• Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other. IBDMSL''-JAN 3 12020 / Post Initial Injection MIT Req'd? Yes ElNo Ig Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /,�7 — q ¢ �, APPROVED BY Approved by: ' COMMISSIONER THE COMMISSION Date: ✓�.JLjV U rri- 1/"/z0 f�7 l I G I N A L Submit Form and Form 10-40 evised 4/201] Approved application is valid for 12 months fro the ate of approve)., � Attachments in Duplicate e.B 611L2./ZO� KUP INJ WELLNAME 1E-119 WELLBORE 1E-119 'W1 " ell Attributes Max Angle & MD TD COIIOCUPII)��ip5 Ri she WellEoreA SP We:han.S.He 1111 MDli A.1.1.KBB) Alaska, Ir1C. IWFST SAH I5nns0>41oPnn lim n cn os -.noon eat WO: 1E-115. 1/16000) a. w: 44 PM Last Tag taMwlualmosopceJl Annotation Depth page) End Data I Walllure Lest Moa 9y Last Tag: PIKE 6,890.0 3/262018 1E+119 j1ansen8 I """"""""""' """""" Last Rev Reason rwrvcER;p9 Annotation End Data wellEore lest moa ay Be, Reason; Dump bail sand plug IuAeAAU19 1E-118 Inergusp, Casing Strings Casing Descriplion ISO (in) m(in) 11 DORSET set Depm ttllgel set Death Ili WVLen (L.. Grade iop Thread CONDUCTOR i6 15.06 31.0 1080 108.0 62.50 H-40 WELDED Casing Osionetion -riont I ID on) I Top Ging set Dap. algBp I a. dept. (log....n g.....ae Tap Thread SURFACE 9518 8.83 30.2 3,309.8 2,050.8 4000 L-80 BTC Prong 0escriprian I DD(int I IV (in) TOP(XKo) Sel Oepon aKBl set pep. TAD)... WVLen(/ ).,nye Top Thread PRODUCTION 5la 4.95 26fi ],08)4 3,658.1 15.50 L-80 BTO MOD Tubing Strings Tubing Description String Ma... 10 (in) Top (RKs) set Dep. (R, aM Dep. (ND) (... W[(Ib.) G,atla Top deantttlon TUBING 31/2 2.99 22] 6,136.1 3,040.0 9.30 L-80 EVEBROMO) Completion Details mp(TFvo Top Incl ..ni TOP roar) (Ratio P) /rem Des Com to (In) CGNDUcioR: 3f nlO 22.] 227 000 HANGER VETCO GRAY TUBING HANGER 3500 506.9 502.2 16.12 NIPPLE CAMCO IDS NIPPLE .12,875- GO 2.875 xIPPLE; w6.e19 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE eel 2.812"NO GO 2.812 6,085.2 7014.2 60.12 LOCATOR LOCATOR SUB B SPACEOUT 3.000 6,088.6 3,015.9 60.04 PBR BAKER 8040 SLIMUNE PER wl 14' SEAL ASSEMBLY 3000 6,102.6 7.023.0 5973 ANCHOR BAKER K22 ANCHOR 2.980 6,103.3 3,0233 5972 PACKER BAKER SABL3 PACKER 2.780 SURFACE, 3033 30A S_ 6,124.1 3,033.9 5926 NIPPLE HES X NIPPLE wl 2.75" PROFILE 2750 6,135.6 3,039.81 59.01 17LEG CPAI WIRELINE ENTRY GUI DE PART#546397 2.990 'Or IIHola,,IYYireiine retrievable plugs, valves, pumps, fish, etc.) TOP(No) Topa Top page) el (°) Des Co. Run Data ID (in) Goa LIFT. 4,4aa.t 6,338.0 3,1517 53.83 LEAK -CASING CASING LEAK IN THE 5-1/2,0.5 BPM LLR, 11/20/201 4950 8 6,373.0 3,1726 52.75 Sand Plug Dump bail sand romtopoi RK8 to 6373 22712019 0.000 RKB. Also- 3' M safe Parti on top. 6,4200 3,2015 51.31 Retrievable 2.50- TE 110/2018 0.000 CAP drd; ag36.1 Surge Plug Perforations & Slots shot NIPPLE Fo]ef TOPaar) ahn(nKS) Top(TVD) ded S.H.) (tog.) Gnendzone DaR Den "Foram ) Typs Co. 6,454.0 6,5240 3,223.0 3,268.5 AS D, 1E-119 10012004 6.0 (PERF.5" HSD2506 PJ, 60 deg LOCPTDa: 6.[BS] phase, random orient 6,582.0 6,594.0 3,293.8 3,3153 WS B,1E-119 10/W004 6.0 (PERF 5" HSD2506PJ, 60d Pan: gagart phase, random orient MCHOR161ma 65940 6,fi1410 3,3153 3,328.9 WS B, 1E-119 10)5/2004 6.0 /PERF .6"HSD 2506 PJ. fi deg PACKER; .1W.a phase, random orient 6,]88.0 6,810.0 3,448.4 3.463.6 WS AP,1E-119 10152004 60 /PERF 2.5HSD2 PJ, deg Chose, read.. anent 6,82].0 8,852.0 3"]5.4 3,492.8 WS A2,1 E-119 10/52004 6.0 /PERF 2.5" H D PJ, 60 deg mwLE, 6,1341 phase, random orient 6,860.0 68]20 3,498.4 3,506.8 ei 1E-119 10)512004 8.0 /PERF .5"H D 506 PJ, 60 deg phase, random orient WIfG;gles.6 Mandrel Inserts se LEAK-CASING:6.336.0 Mt ^ N io.Be Val, F.F. Top,4KB) (2U45 Metre Model 00 (in) Type Po(in) TRORun (psp Run Date Com semose .,.a 6,464.1 2,456.0 CAMCO KB -2- 1 GAS LIFT DMV INT LIF MY 9 00 0.000 0.0 411312004 1130 Re.mNe adds. Pip; sum o 2 6,026,1 2,985.4 DAMGG KBG-2- 1 GASLIFT DMY INT D.000 0.0 2/02005 3:00 9 Notes: General &Safety End Dene i Annotation (PERF; 4c5 L.oe.5u.o� NOTE'. IBP SET AT 6420' RKB 41281201) NOTE: FUFDOM RPPG Treatment 4590 lot, to D MBE 8252010 INOTE: View Schematic wl Alaska SchematiC9.0 /PERF: 6ago.'el IPERCePo S,i (PERF; 6.]9&06,a10.0- PERF.SW.04a5F IPERF:6,890.0ePi PRODUSOVoN:R87,0814 Proposed 1E-119 Coil Tubing Cement Squeeze of Production Casing Leak 1E-119 West Sak Injector has 3.5", 9.3#, L-80 Tbg to at 6136' RKB, and 5.5", 15.5#, L-80 Prod Csg to 7087' RKB, that is perfed in WS D, B, and A Sds. Two failed RPPG jobs were pumped in 1E-119 in 2017 to treat a D MBE. A 5/30/18 (PROF shows upward crossflow was present from the D MBE to above the highest point logged. This indicated a leak point existed up hole that may have impacted the MBE treatments. An IBP was set 11/7/18 at 6420' RKB to isolated all perfs, and an LDL of 11/20/18 verified a Csg leak exists at 6338' RKB that took Diesel at 0.5 bpm during LDL. This leak may be to a thief zone, fault, or channel, and may have taken a large split during RPPG treatments &/or caused crossflow, to leave the D MBE improperly treated. It was earlier proposed that a Cement Sqz be performed using a Cement Retainer to seal off the casing leak before reattempting a D MBE RPPG treatment. A 10-403 Sundry was approved on 2/4/19 to perform the work, but work was delayed and now approval #319-040 is set to expire on 2/4/2020. Thus, it is requested that Cement Squeeze work reapproved for execution in 2020. The Cement Sqz proposal below has now been modified to eliminate the use of a Cement Retainer. Pre-Sqz work completed during 2019 included dump bailing sand on top of the IBP to leave TOS at 6373' RKB on 2/27/19 in preparation for Cement Sqz. No additional work has yet been performed. Procedure: 1) Coil Tubing - Cement Squeeze: a) Hold PJSM. Establish site control, erect signs, inspect work site, mitigate hazards. Note wind direction, establish muster points, and then PT equipment as required. b) RIH with CT cementing nozzle. Tag TOS at 6373' RKB, then PU 10' and flag pipe. POOH to 6273' RKB (100' above TOS). Open CT x Tbg to tanks and circulate FW down CT to load well. c) With Diesel returns seen from CT x Tbg to tanks, maintain 1 bpm and slowly apply 100 - 200 psi backpressure with choke to avoid formation fluid entry to well. When Diesel stops flowing to tanks, drop rate to 0.5 bpm, close CT x Tbg, then monitor CT x Tbg injection test to casing leak. d) If injectivity to casing leak looks good, mix 20 bbls of pumpable 15.8# Cl G Cement while continuing to pump Freshwater down CT until the cement batch is ready to pump. e) Pump 20 bbls Cement down CT at 0.5 bpm to squeeze casing leak with to 1500 psi max, to limit the max dP acting across the IBP. Perform hesitations, if needed, to attain 1500 psi Sqz target. f) 5 bbls Freshwater Spacer behind cement, followed by XX bbls Cement Contaminant for jetting the cement cleanout, followed by 27.5 bbls Diesel to FP tubing to 2000' TVD. g) RIH to jet out excess cement down to 6275' RKB in 5.5" casing to leave —63' uncontaminated cement above squeezed casing leak at 6338' RKB, then POOH & Diesel FP Tbg to 2000' TVD. h) RD CTU & MOL. i) WOC at least 48 hours. 2) Digital Slickline -Tag Cement & MITT: a) After WOC at 48 hrs, MIRU DSL. RIH & tag TOC in 5.5" casing RKB depth. This RKB tag will be referenced when CT tags TOC to RKB flag pipe for depth control to underream cement (below). b) Perform MITT to 1500 psi. If MITT passes, RD DSL. Proceed to step 4 (below). c) If MITT failed & TOC tags above casing leak at 6338' RKB, then run LDL to find leak. RD DSL. If a leak was found, halt work per this procedure here for a revised plan forward. 3) Coil Tubing - Underream Cement: If MITT passed in step 2, and TOC tagged above casing leak at 6338' RKB, then cement needs to be milled from 5.5" casing to open casing to below casing leak to ena le MIT against the squeezed casing leak. a) MIRU CTU. Spot Water & Diesel transports. RIH with Underreamer BHA of largest OD available for durability that drifts through 2.75" Min ID X Nipple at 6124' RKB. Make initial tag on TOC & flag pipe. Reference TOC RKB tag depth DSL made (step 2) and flag CT as same depth. b) Underream Cement in 5.5" Casing to 6343' RKB referencing CT 'flag' for depth control while taking returns to tanks. Halt UR at 6343' RKB. This halts BHA 5' below squeezed leak at 6338' RKB, but keeps BHA above TOS and IBP fish neck, to leave some Cement Plug for MITT above IBP, plus a reinforced bottom plug for a resqueeze, if needed. c) MITT to 1500 psi on CT x Tbg to verify if Cement Sqz is holding. Do not MITT over 1500 psi. d) If MITT indicates a leak, record LLR & pressure data. Depending on MITT leak rate, we will decide on the need for a possible re -squeeze of the casing leak. e) If MITT passed, continue milling Cement Plug to TOS at 6373' RKB while verifying 1:1 returns to tanks. Avoid milling on IBP set at 6420' RKB (element). POOH with milling BHA. f) RIH with jetting nozzle to perform CaCO3 Cap/Sand Plug FCO to IBP at 6420' (element). POOH with nozzle. g) RIH with pulling tool to pull Baker IBP at 6420' RKB. h) RIH to tag PBTD, else RD CTU to let SL make this tag. A new well work procedure will be written to install a permanent bottom plug in the sump of the 5.5" production casing to halt up flow from sump to D Sand MBE (detected during LDL S/ pass thru 5.5" casing). Following plug set in sump, a fullbore D MBE RPPG retreatment will be pumped (without flow from sump contaminating the RPPG) to seal the open MBE to offset 1E-166 producer. Pno a04--4131 Loepp, Victoria T (CED) From: Peirce, John W <1ohn.W.Peirce@conocophillips.com> Sent: Thursday, January 16, 2020 12:44 PM To: Loepp, Victoria T (CED) Subject: RE: [EXTERNAL]RE: Request for extension of the expiration date of 10-403 Sundry approval for 1 E-119 Cement Sqz Follow Up Flag: Follow up Flag Status: Flagged Victoria, I cannot say with good certainty if the work will be completed within the next month, so get a new 10-403 sent over by early next week. Thanks, John Peirce Sr Wells Engr CPAI Drilling & Wells (907)-265-6471 office From: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Sent: Thursday, January 16, 2020 11:41 AM To: Peirce, John W <John.W.Peirce@conocophillips.com> Subject: [EXTERNAL]RE: Request for extension of the expiration date of 10-403 Sundry approval for 1E-119 Cement Sqz John, Will the work be done within the next month? If not, please submit a new 10-403. Tha nx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. LoeppCc)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 Victoria Loepp at (907)7931247 or Victoria.[ oeou@alaska oov From: Peirce, John W <John.W.Peirce @conocophillips.com> Sent: Thursday, January 16, 2020 11:04 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.xov> Subject: Request for extension of the expiration date of 10-403 Sundry approval for 1E-119 Cement Sqz HI Victoria, We are still interested in pumping 1E-119 Cement Sqz job, but 10-403 approval #319-040 of 2/4/19 to perform the job expires 2/4/2020 after 1 year. This job was delayed last year due to executing other higher priority jobs that used limited resources we needed to complete this job. We are planning to get 1E-119 Cement Sqz job done as soon as possible. Thus, I am requesting AOGCC approval to extend current 10-403 approval # 319-040 for another year. Let me know if this can be done by email or do I need to submit a new 10-403 for approval. The 1E-119 Cement Sqz procedure we plan to execute has not changed from the original proposed procedure that was attached to the original 10-403 that was approved 2/4/19. I have attached a copy of the original 10-403 approval for reference. So far we have only completed step 1 of the proposed procedure outline attached to the 10-403. Thanks, John Peirce Sr Wells Engr CPAI Drilling & Wells (907)-265-6471 office THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY John Peirce Sr. Wells Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, West Sak Oil Pool, KRU 1E-119 Permit to Drill Number: 204-031 Sundry Number: 319-040 Dear Mr. Peirce: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Enclosed is the approved application for the 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, V/�2� Daniel T. Seamount, Jr. Commissioner / `✓ DATED this day of February, 2019. SCANNED FEB 0 4 2019 EECOVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 3 0 2019 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon El Plug Perforations ❑ Fracture Stimulate EI Repair Well ❑ s down❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Cement SqueezeEl 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhilli s Alaska Inc. Exploratory ❑ Development ❑ Stratigraphic ❑ Service El 204-031 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-029-23198-00-60 7. If perforating: 8. Well Name and Number: -t 5 What Regulation or Conservation Order governs well spacing in this pool?N/A a 113g(I 1E-119 Will planned perforations require a spacing exception? Yes El No 121KRU 9. Property Delsignation (Lease Number): 10. Field/Pool(s): ADL 25651, ADL 25660' 1 Kuparuk River Field / West Sak Oil Pool 11, PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD "active Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,090' 3,660' 6999 3596 1300psi 6420 NONE Casing Length Size MD TVD Burst Collapse Conductor 77' 16" 108' 108' Surface 3,280' 95/8 3,310' 2,051' Production 7,061' 51/2 7,087' 3,658' Perforation Depth MD (ft) I Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6454-6524,6562-6594,6594-6614, 3223-3268, 3294-3315, 33153329, 3.500" L-80 6,136' 678M81 0 6827- 72 3475-3492, 3498-3507 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): PACKER - BAKER SABL-3 PACKER MD= 6103 TVD= 3023 SSSV - NONE N/A 12. Attachments: Proposal Summary ❑, Wellbore schematic ❑ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service I] 14. Estimated Date for 3/1/2019 15. Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG 0 GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. John Peirce Contact Name: John Peirce Authorized Name: Authorized Title: Sr. Wells Engineer Contact Email: John.W.Peirce@cop.com Contact Phone: (907) 265-6471 Authorized � /2 Signature: p./� — Date: � 1- r COMMISSION USE ONLY Conditions of approval: Notify Commission 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 S/ Spacing Exception Required? Yes ❑ No Subsequent Form Required:z&1-2��- APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: �r` 2-1 q ORIGINAL RBDMeAV\FEB 0 5 1019�tF/&1� Form 10-003 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate 5-' k. 0. (SO&? Proposed 1E-119 Coil Tubing Cement Squeeze of Production Casing Leak 1E-119 West Sak Injector has 3.5", 9.3#, L-80 Tbg to at 6136' RKB, and 5.5", 15.5#, L-80 Prod Csg to 7087' RKB, that is perfed in WS D, B, and A Sds. Two failed RPPG jobs were pumped in 2017 to treat a D MBE. A 5/30/18 IPROF shows upward X -flow existed from D MBE to above highest point logged. This suggested a Csg leak existed up hole that may have impacted MBE treatment. An IBP set 11/7/18 at 6420' RKB to isolated all perfs, and an LDL of 11/20/18 found a Csg leak at 6338' RKB taking Diesel at 0.5 bpm. This leak may be to a thief zone, fault, or channel, and could have tafcen a large split during the RPPG treatments and/or caused crossflow to leave the D MBE inadequately treated. It is proposed that a Cement Sqz be performed to seal the leak before attempting another D MBE RPPG treatment. Procedure: 1) Slickline or DSL: Dump bail Sand Plug on top of 2.5" IBP set at 6420' RKB to get TOS at 6380' RKB in 5.5" Csg. Make final tag to verify TOS is at target depth. This sand plug is to keep Cement (in step 3) well above the IBP fish neck, so we can fish the IBP later (in step 4). 2) DSL or E -line: RIH with millable Cement Retainer and set the Retainer in the Tubing Tail at 6130' RKB just below 2.75" X Nipple at 6124' RKB. POOH & RD. 3) Coil Tubing Cement Squeeze: RIH with Stinger to sting into Retainer at 6130'. Pump 100 bbls Freshwater down CT at 0.5 bpm displacing Diesel from CT to leak at 6338' RKB. Open CT x Tbg to tanks during pumping to monitor returns. If returns are seen to tanks, we will correct this issue before pumping Cement down CT. Keep 0.5 bpm during all pumping for lowest possible dP's acting across IBP to reduce odds of an IBP set failure. After 100 bbl Freshwater down CT with no returns observed, pump 20 bbls 8.6# Ultralight Cement, then 5 bbls Freshwater, followed by XX bbls Cmt contaminant, followed by 27.5 bbls Diesel FP. Perform either i or ii: i) If all Cement passes Retainer and net treating psi increase < 1000 psi, then overdisplace Cement thru Retainer by 1 bbl Freshwater, then PU CT off Retainer to leave —4 bbls of Cement in 5.5" Csg below Retainer and 16 bbls Cement squeezed to Csg leak. POOH. RD CT. WOC. ii) If some Cement passed Retainer and net treating psi increased by 1000 psi (max net Sqz pressure to mitigate IBP failure and keep below Frac psi), then PU CT off Retainer & POOH laying in remaining cement on Retainer, followed by 5 bbls Freshwater and XX bbls contaminant, while RBIH to Retainer jetting contaminant through excess Cement to Retainer, followed by Freshwater volume to circ out contaminated cement above Retainer until clean returns seen to tanks, then POOH with CT pumping Diesel FP. This leave < 16 bbls Cement thru leak and —5 bbls Cement in 5.5" Csg. POOH w/CT pumping Diesel FP. RD CTU. WOC. 4) Coil Tubing: RIH with Milling BHA thru 2.75" X Nipple at 6124' RKB. Tag Retainer at 6130' and 'flag' pipe. Mill Retainer and Cement to TT at 6136' RKB, then Circ out cuttings, followed by POOH. RIH with UR BHA thru X Nipple at 6124' RKB and underream Cement in Csg to 6343' RKB. Perform MITT to 1000 psi to verify if Sqz is holding. Do not MITT >1000 psi which would likely exceed West Sak Frac gradient. if MITT passed, mill Cement to TOS at —6380' RKB. POOH with milling BHA. PU & RIH with a jetting nozzle to perform CaCO3 Cap/Sand Plug FCO to IBP at 6420' (element). POOH with Nozzle. RIH with pulling tool to pull Baker 2.5" run OD IBP at 6420' RKB. Allow time for element to relax, then POOH with IBP. Prepare procedure for RPPG retreatment attempt of D MBE. A_KUPa INJ WELLNAME 1E-119 WELLBORE 1E-119 COOOCOPhillip5 -' Well Attributes Max Angie 8 MD TD Fe'M'. ne Wenloare APWWI Wellno�e SUlua cl^'I MO Min kI arm IRKS) Alaska. Inn IWFCT CAK im"it"hoAnll IINi i ca or nnnnn .N WO' IE -119, Istrati 3W:ATPe Last Tag VnEcdaelMgpc lend) Annoblion OepIESONd 1 End Date I WeR.. Diarrheas US! lag: RKB 6,890.0 31262018 1E-119 inancents ........................................................ ....._........._.____...... Last Rev Reason HAHGER,m Annotation EM o"' W¢IlGare teal MM By Rev Reason DOCUMENT LEAK 1/d/2019 ntliwo 1E-119 cj Casing Strings eaam90eecrlpbnn oD Onl 101m1 Top InK91 set Oepm lnK9) se10ePIn 1TV01_. wur.en 6... Gude rop Tnre.e CONDUCTOR 16 15.06 310 1080 108.0 62.50 HoWELDED Gsnq Dnctlption ODllnl IDIMI TopinK6) Set OepM nKK81 Set Oepm II VD I'adlen 11... Gr Me Topre Thad SURFACE 9w 8.83 302 3,309.8 2,050.8 40.011 L-80 BTC Galtppaserlgbn DO pn) ID 9n) TOp (flKBI Sel Oepm ryD(B) SN DapM nVDI... WIMn p... OrMe Tap TnreM PRODUCTION 5112 4.95 26.6 ],0874 3,658.1 15.50 L-80 BTC -MOD am Tubing Strings iuem90escnption sinlp ma... 1011n) rop (nnal Stl Depm (IL. sN De ant RVD11...W111Wn) erode Top Connection TUBING 312 2.99 227 6,136.1 30400 930 L-80 EUEBRDMGD Completion Details Top TWDJ Topmcl Noi Top MEd Met I') nem Gs cors ID pen 22.7 227 000 HANGER VETCO GRAY TUBING HANGER 3.500 rANpWTORl al ulae.p 8 502.2 18.1 NIPPLE CAMCO DS NIPPLE ed/ 2a75"NO GO 28]5 rvWPLE:bme AN 6, 781 3,010NI .] 802 PPLE CAMCO DS NIPPLE vel 2812"NO GO 2.812 ,0852 3,0142 60.12 LOCATOR LOCATOR SUB B SPACEOUT 3.000 6,088.6 3,0158 60.04 PBR BAKER 8040 SLIMUNE PBR al 1P EAL ASSEMBLY 3-000 6102.6 3,023.0 59.73 ANCHOR BAKER K -i2 ANCHOR 2.980 6,103.3 3,023.3 5.72 PACKER BAKER SABL-3 PACKER 2780 6.124.1 3,033.9 5 26 NIPPLE HESX NIPPLE w/2.J5'PROFILE 2750 suRFAW:3D 2a sw.e- 6.135.6 3,039.8 5901 WLEG CPAIWIRELINE ENTRY GUIDE PART3546397 29M Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (NDI Tap bel Top lmla 1 IRK81 1'1 D¢s cors Ron. ID lint 6.3380 3,151.] 5383 LEAK - CASING CASING LEAK IN THE 5-112, 0.5 BPMLLR, 11 4.950 DAa uFr; 4.aea.1 1 I 8 6420.0 3,201.5 5131 BeidevTDle 2.50"IBP 1102018 Bridge Plug Perforations S Slots Shot . UFT:60Am -PMS) Drm Me) ToROVO) MR) dra RVD) MB) jn. Zone Date Dene Isnnlam 1 Type Cun 6,454.0 6,524.0 3,2M.0 3,26.5 WS D, 1E-119 1002004 60 IPERFPJ, deg phase, random orient "n"U:b.mdl 6,5620 6,5940 3293.8 $315.3 WS B,1E-119 1M0000. 6.0 IPERF PJ, 60deg phase, random orient mCROR:dm6II 6,594.0 8614.0 3,315.3 3,328.9 WSB. 1E-119 10152004 6.0 IPERF H 66 PJ,6Gdeg phase, random orient MR. dome 6788.0 8810-0 3448.4 463.6 WSA2,1E-119 IDI52B04 6.0 IPERF H PJ,6Odeg ANCHOR:d102a tt phase, random orient PACKEa:films 6,8270 68520 74754 WSA2.1E-119 101512N14 60 IPERF "H D 506 PJ,60deg phase, random orient 6,860.0 7.0 3,498.4 3,5 WS A2, 1E-119 10152004 60 PERF 2.5"H U20 PJ, deg phase, random orient NwPUE.6124.1 Mandrel Inserts St an wLEO:6.r359 N TAPMB) Top lrvD) IM(9) MCKe MMN 00god Sery velw Wcn Fairness Type Type IW TRO Run I.R Run Gb Com 4,464.1 2.456.0 CAMCO -- 1 GAS LIFT DMV INT 0.000 0 4/132004 1130 9 LEAs-CAsiHo:e.33ta 2 6,026.1 29854 CAMCO KEOi 1 GASLIFi DMTINT 0.000 00 29/2005 3.00 9 I Notes: General & Safety End Gd Annnenon 8/252010 NOTE: Veri Schematic wl Alaska Scnematic90 IPERF: easaoa.42a.p� 4/2WO17 N TE: FWlbore RPPG I reannent 4590 has WDMISE INOTE IBP SET AT 6420RKB IPERF', 8.5mOdCa40� IPERF: dmy.0e6160----- IPERF', BTmOB,910.0� IPERF:6.9270,1 R52.O-- IPERR dB30.Od.ry20� Mod..., 2db.7.0d a &9403)0 Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> -� '��i Sent: Thursday, May 31, 2018 5:20 AM c9 ` ie To: Regg, James B (DOA); CPF1 DS Lead Techs; CPF1 Ops Supv; NSK W II`Integrity Supv CPF1 and 2; CPF1&2 Ops Supt;Autry, Sydney; Braun, Michael (Alaska); Fox, Pete B; N5K Optimization Engr; Sudan, Hari Hara Subject: LPP/SSV Returned to Service on CPAI well 1E-119 Jim, The low pressure pilot (LPP) on well 1E-119 (PTD#204-031)was returned to service and removed from the "Facility Defeated Safety Device Log" last night, 5/30/2018, after the well was shut-in post diagnostic wellwork. The LPP had been defeated on 5/27/2018 after wellhead pressure fell below the LPP setpoint of 500 psi while injecting at recommended rate.This notification is in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. Courtney Gallo /Marina Krysinski West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 scow c ► ® JUN 0 b2B1Fi 1 KR l E-)lc • S PTt ZZ9O310 Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Sunday, May 27, 2018 9:13 AM '" e/.1 6k/116 To: Regg,James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Well Integrity Supv CPF1 and 2; NSK Optimization Engr; CPF1&2 Ops Supt; Autry, Sydney; Braun, Michael (Alaska); Fox, Peie B; Sudan, Hari Hara; NSK West Sak Prod Engr Subject: Defeated LPP/SSV on CPAI well 1E-119 on 5/27/2018 Jim, The low-pressure pilot(LPP) on injector 1E-119(PTD#204-031)was defeated today 5/27/2018 to assist in well work diagnostic efforts (IPROF). The well is currently injecting at a wellhead pressure of 100 psi or less and a stable rate of 1130 BWPD.The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Feel free to contact us if you have any questions. Pete Fox for Marina Krysinski/Courtney Gallo WestSak PE (907) 659-7234 SCANNED JUN 012018 • Kfe- 1-E-10 111 • P Z04o3ro Regg, James B (DOA) • From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Monday, January 8, 2018 6:10 AM 191 t� To: Regg, James B (DOA) l Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Well Integrity Supv CPF1 and 2; CPF1&2 Ops Supt;Autry, Sydney;Targac, Gary; Fox, Pete B; Sudan, Had Kara Subject: LPP/SSV Returned to Service on CPAI Well 1E-119 - 1/7/2018 Jim, The low pressure pilot(LPP) on well 1E-119 (PTD#204-031)was returned to service and removed from the "Facility Defeated Safety Device Log" yesterday, 1/7/2018, after the well was shut-in. The LPP had been defeated on 1/6/2018 when the well was returned to service after an extended shut-in period.This notification is in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Marina Krysinski / Mitch Autrey West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 • 4 SCO ;'. . z 1 • • Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Saturday, January 6, 2018 4:09 PM 1` t To: Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Well Integrity Supv CPF1 and 2; NSK Optimization Engr; CPF1&2 Ops Supt;Autry, Sydney;Targac, Gary; Fox, Pete B; Sudan,. Hari Hara Subject: Defeated LPP/SSV on CPAI Well 1E-119 on 1/6/2018 Jim, The low pressure pilot (LPP) on well 1E-119 (PTD#204-031)was defeated today, 1/6/2018, after the well was returned to service after an extended shut-in period.The well is currently injecting at a wellhead pressure of 6 psi and a rate of 985 BPWD.The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. Marina Krysinski /Mitch Autrey West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 1 • ;, .tau® STATE OF ALASKA iioZ I T 70 AOKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS a3A13O H 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing❑ Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 'erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: RPPG D MBE E 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: ConocoPhillips Alaska, Inc. Development❑ Exploratory❑ _ 204-031 3.Address: P. O. Box 100360,Anchorage,Alaska Stratigraphic El Service 6.API Number: 99510 50-029-23198-00 7.Property Designation(Lease Number): 8.Well Name and Number: KRU 1E-119 ADL 25660,ADL 25651 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kuparuk River Field/West Sak Oil Pool 11.Present Well Condition Summary: Total Depth measured 7,090 feet Plugs measured None feet true vertical 3,660 feet Junk measured None feet Effective Depth measured 6,999 feet Packer measured 6,103 feet true vertical 3,596 feet true vertical 3,023 feet Casing Length Size MD TVD Burst Collapse CONDUCTOR 77 feet 16 108' MD 108 RECEIVED C'v C n SURFACE 3,280 feet 9 5/8" 3,310' MD 2051 Il G V G G V PRODUCTION 7,061 feet 5 1/2" 7,087' MD 3658 DEC 1 1 2017 Perforation depth Measured depth 6554-6524,6562-6594,6594-6614,6788-6810,6827-6852,6860-6872 feet ((�� True Vertical depth 3223-3268,3294-3315,3315-3329,3448-3464,3475-3493,3498-3507 feet AOGVC Tubing(size,grade,measured and true vertical depth) 3.5" L-80 6,136'MD 3,040'TVD Packers and SSSV(type,measured and true vertical depth) PACKER- BAKER SABL-3 PACKER 6,103' MD 3,023'TVD SSSV: NONE 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A p 4 Treatment descriptions including volumes used and final pressure: scoNED ,.i lk, 2 til{) 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: — — Shut-In — — Subsequent to operation: — — Shut-In — — 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ Development ❑ Service 0 Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ E WAG 0 GINJ ❑ SUSPE 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: 317-360 Contact Name: John Peirce Authorized Name: John Peirce Contact Email: John.W.Peirce@cop.com Authorized Title: Sr.Wells Engineer � j / Contact Phone: (907)265-6471 Authorized Signature: - /4 1 ' — Date: 2 /.L V Ti //Z/l' , Form 10-404 Revised 4/2017 � RBD- S L L-Ca:C 1 2 2617 Submit Original Only • 1 E- 1 1 9 RPPG D MBE TREATMENT DTTMSTAF JOBTYP SUMMARYOPS 11/10/17 NRWO Performed full-bore RPPG treatment pumping 151 bbls of— 0.85 ppg RPPG placing 5016# of RPPG into formation followed by 550 lb of—0.46 ppg crystal seal. Displaced with 27 bbls seawater and 28 bbl diesel freeze protect. KUPiii •• 1E-119 ,CariocaPhilli Well Attrib Max Angle&MD TI) Alaska,no Wellbore APUUWI Field Sante Wellbore Status ncl(1) MD(ftKB) Act Btm(ftKB) corlocaphilk, 500292319800 WEST SAK INJ 73.02 5,488.12 7,090.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 1E-119,12(7/20173.01.35 PM SSSV:NIPPLE Last WO: 31.42 4/13/2004 Vertical Schema..(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:RKB 6,571.0 4/14/2017 Rev Reason:MBE TREATMENT-SEE NOTES pproven 5/22/2017 Casing Strings HANGER,22 7 illi it.5° . Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(L..Grade Top Thread CONDUCTOR 16 15.062 31.0 108.0 108.0 62.50 H-40 WELDED Casing Description 'OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread SURFACE 95/8 8.835 30.2 3,309.8 2,050.8 40.00 L-80 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(L..Grade Top Thread PRODUCTION 51/2 4.950 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..I Set Depth(ND)(...Wt(Ib/ft) Grade Top Connection TUBING 31/2 2.992 22.7 6,136.1 3,040.0 9.30 L-80 EUE8RDMOD ,,,,,,,,,,,,,,,,,,,,,,,,.,,, �F Completion Details .,,,, ft+u Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) 22.7 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE CAMCO DS NIPPLE w/2.875"NO GO 2.875 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE w/2.812"NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR LOCATOR SUB 8 SPACEOUT 3.000 CONDUCTOR;31.6106.0 j 1. `-^^ 6,088.6 3,015.9 60.04 PBR BAKER 80-40 SLIMLINE PBR w/14'SEAL ASSEMBLY 3.000 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 NIPPLE;506.9 • I 6,103.3 3,023.3 59.72 PACKER BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE HES X NIPPLE w/2.75"PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG CPAI WIRELINE ENTRY GUIDE PART#546397 2.990 Perforations&Slots • Shot Den Top(TVD) Btm(TVD) (shots/ SURFACE;30.2-3,309.8-. Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 6,454.0 6,524.0 3,223.0 3,268.5 WS D,1E- 10/7/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 • 119 deg phase,random orient • 6,562.0' 6,594.0' 3,293.8 3,315.3 WS B,1E-119 10/6/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 I deg phase,random orient CAT uE-.a 464 6,594.0 6,614.0 3,315.3 3,328.9 WS B,1E-119 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 Ideg phase,random orient 1 6,788.0 6,810.0 3,448.4 3,463.6 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 I 119 deg phase,random orient GAS LIFT;6,1726.1 6,827.0 6,852.0' 3,475.4 3,492.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 6,860.0 6,872.0 3,498.4 3,506.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient NIPPLE,6,078.1 Mandrel Inserts St LOCATOR;6,085.2 ai ._` N n Top(TVD) Valve Latch Port Size TRO Run PBR;6,0886 ,i ( Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com 1 4,464.1 2,456.0 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 11:30 ANCHOR;6,102.6 lin 9 2 6,026.1 2,985.4 CAMCO KBG-2- ' 1 GAS LIFT DMY INT 0.000 0.0 2/9/2005 3:00 PACKER;8,103.3 9 Notes:General&Safety End Date Annotation 8/25/2010 NOTE:View Schematic w/Alaska Schematic9.0 NIPPLE;6,124.1 4/28/2017 NOTE:Fullbore RPPG Treatment 4590 lbs to D MBE WLEG.6,1356 L. IPERF;5454.0-6,524.0 _ IPERF;6,562.08,594.0 a IPERF;6,594.06,614.0 IPERF;6,788.0-6,810.0 IPERF;6,827.06,852.0 IPERF;6,880.0-6,8770 PRODUCTION;26.8-7,087.4 SOF ro • *t)" // s THE STAT• �\I//�; ,, Alaska Oil and Gas N OfALASKA Conservation Commissi®n r=�- 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: ALASFax: 907.276.7542 www.aogcc.alaska.gov John Peirce Senior Wells Engineer SCANNED AUG 1 .1 2017 ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, West Sak Oil Pool, KRU 1E-119 Permit to Drill Number: 204-031 Sundry Number: 317-360 Dear Mr. Peirce: 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, Cathy . Foerster Commissioner DATED this day of August, 2017. RBDMS L - AUG - 9 2017 • • RECEIVED STATE OF ALASKA .AUG 0 34017 ALASKA OIL AND GAS CONSERVATION COMMISSION �TS P ' / 7 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 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 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ , Other: RPPG D MBE TrtmtU 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Exploratory ❑ Development ❑ 204-031 3.Address: Stratigraphic ❑ Service 0. 6.API Number: P. O. Box 100360,Anchorage,Alaska 99510 50-029-23198-00 ' 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A ' KRU 1E-119 • Will planned perforations require a spacing exception? Yes ❑ No 0 / 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 25660,ADL 25651 - Kuparuk River Field/West Sak 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): 7,090' ' 3,660' . 6999 ' " 3596 'rDD NONE NONE Casing Length Size MD TVD Burst Collapse Conductor 77' 16" 108' 108' Surface 3,280' 9 5/8 3,310' 2,051' Production 7,061' 51/2 7,087' 3,658' Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 6454-6524,6562-6594,6594-6614, 3223-3268,3294-3315,3315-3329, 3.500" L-80 6,136' 6788-6810.6827-6852,6860-6872' 3448-3464,3475-3493,3498-3507 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): , PACKER-BAKER SABL-3 PACKER MD=6103 TVD=3023 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑ Service 0 14.Estimated Date for 9/1/2017 15.Well Status after proposed work: Commencing Operations: OIL ❑ WINJ 0 WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG 0 ' GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown 0 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: John Peirce Contact Name: John Peirce Authorized Title: Sr. Wells Engineer Contact Email: John.W.Peirce@cop.com p Contact Phone: (907)265-6471 Authorized Signature: (/‘_,L,c1. . Date: p/2/17 ICOMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: X17-3LQa Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ Nopacing Exception Required? Yes o No EZ Subsequent Form Required: /67 ,�/'J, RBDMS c'�- FiAUG - 2017 APPROVED BY Approved by: A/ , COMMISSIONER THE COMMISSION Date: 8-¢.- /7 � 0 RiallaNIALalid Subin Form ane - 03 RForm 1 evised 4/2017 for 12 months from the date of approval. Attachmentss in Duplicate • S Proposal for Retreatment of 1E-119 to 1E-166 D Sand MBE with RPPG 1E-119 is a single vertical injector that was drilled & completed in 2004 with 3.5", L-80 Tubing and 5.5", L-80 Production Casing. On 5/27/15, an MBE occurred from 1E-119 to offset producer 1E-166. A Flowing Temp Log in 1E-119 on 6/6/15 verified a D MBE existed at 6454' RKB, and top of fill was at 6583' RKB covering all A sand perfs and lower B sand perfs. On 9/19/15, a fullbore Crystal Seal job was pumped in 1E-119 to the D MBE. 1E-119 was then returned to 'D sand only' PWI for-1 year before the MBE treatment eventually failed. On 4/28/17, a fullbore RPPG (Reformed Polymer Particle Gel) job was pumped to try to reseal the D MBE. A total of 4,590 lbs of RPPG was placed into the MBE, but no treating pressure ever developed and the treatment failed. On 5/2/17, A CT FCO removed fill and RPPG from the well to 6995' RKB. On 5/27/17, an (PROF then verified that 100% of injection was still entering the D sand MBE. 1E-119 RPPG job was the first RPPG job that was ever pumped on the Slope. A key learning from the job was that the RPPG concentration we pumped was far too light to be effective in sealing off an MBE. The RPPG concentration needed to seal off the MBE should have been at least double of what was pumped to develop non-flowing crosslinked gel placement in the MBE. The following procedure is proposed to seal the D MBE at 6454' RKB with RPPG to return 1E-119 to PWI service. The RPPG slurry concentration to be pumped will be increased to 0.6 - 0.7 ppg range. Procedure Pumping: 1) About 24 hrs before the RPPG job, shut-in 1E-166 producer, and place 1E-119 on PWI at -1000 BWPD to establish injection through the D MBE to 1E-166. RU mixing van and pumping equipment on 1E-119. When ready to fullbore pump into 1E-119, contact DSO to SI PWI to 1E-119, and then swap over to fullbore pumping RPPG slurry at a steady rate in 1.0 to 1.5 bpm range. Mix slurry in 3% KCL Water (or Seawater) by adding 1 - 4 mm mesh RPPG to make up water for steady 0.6 - 0.7 ppg slurry concentration mixed on-the-fly in the mixing van, and then fullbore pump the slurry down 1E-119 tubing. Continue pumping at a steady rate and slurry concentration until WHIP eventually reaches -800 psi, and then swap from RPPG slurry to pumping 27 bbls of Seawater spacer, followed by -28 bbls Diesel freeze protection, followed by Shutdown. Wait 2 days for the swelling RPPG particles to fully crosslink in the MBE to form stout amalgamated non-flowing crosslinked gel before returning 1E-166 to production. Coil Tubing: 2) RIH with jet swirl nozzle and tag top of RPPG in well, then jet down through RPPG and fill to as deep as possible to shear and mechanically break any RPPG remaining in the well, and to uncover all the perforation intervals to injection. Maintain 1:1 returns to tanks during FCO. POOH. RD CTU. Place 1E-119 on PWI to evaluate results of the MBE treatment. KUP I 1 E-119 ConocoPhillips - ) Well Attribut Max Angle D TD Alaska,IIAt; Wellbore API/UWI Field Name Wellbore Status ncl I°) MD(ftKB) Act Btm(ftKB) tanotpphigtps 500292319800 WEST SAK INJ 73.02 5,488.12 7,090.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) -Rig Release Date 1E-119,7/25/20173:21:39 PM SSSV:NIPPLE Last WO: 31.42 4/13/2004 Vertical sdwmaoc.(actuap Annotation Depth(ftKB) End Date Annotation last Mod By End Date Last Tag:RKB 6,571.0 4/14/2017 Rev Reason:MBE TREATMENT-SEE NOTES pproven 5/22/2017 Casing Strings HANGER,22.7 Nit'MN Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len O...,Grade Top Thread CONDUCTOR 16 15.062 31.0 108.0 108.0 62.50 H-40 _WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(1...Grade Top Thread SURFACE 9 5/8_' 8.835 30.2 3,309.8 2,050.8 40.00 L-80 BTC I € Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread PRODUCTION 51/2 4.950 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)I...Wt(Ib/ft) Grade Top Connection f TUBING 31/2 2.992 227 6,136.1 3,0400 9.30 L-80 EUE8RDMOD „nn,.,.,•„n,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, IIl Completion Details .,,. Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl c) Item Des Com On/ 22.7 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE CAMCO DS NIPPLE w/2.875"NO GO 2.875 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE w/2.812"NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR LOCATOR SUB&SPACEOUT 3.000 • • ,---- 6,088.6 3,015.9' 60.04 PBR BAKER 80-40 SLIMLINE PBR w/14'SEAL ASSEMBLY 3.000 CONDUCTOR;31.0.108.0 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 NIPPLE;506.9 6,103.3 3,023.3 59.72 PACKER BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE HES X NIPPLE w/2.75"PROFILE 2.750 • 6,135.6 3,039.8 59.01 WLEG CPAI WIRELINE ENTRY GUIDE PART#546397 2.990 1 III Perforations&Slots 6'_' Shot Den SURFACE,30.2-3,309.8-. Top(ND) Btm(ND) (shots/ `, Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Coin 6,454.0 6,524.0 3,223.0 3,268.5 WS D,1E- 10/7/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B,1E-119 10/6/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 deg phase,random orient GAS LIFT;4,464.111. 6,594.0 6,614.0 3,315.3 3,328.9 WS B,1E-119 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 Ideg phase,random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient GAS LIFT;6,026.1- 6,827.0 6,852.0 3,475.4 3,492.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient I 6,860.0 6,872.0 3,498.4 3,506.8 WS A2,1E- 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 119 deg phase,random NIPPLE;6,07E13IE Orient Mandrel Inserts St ehLOCATOR;6,005.2 on Top(ND) Valve Latch Port Size TRO Run PBR;6,068.6 _ff .. Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com 1 4,464.1 2,456.0 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 11:30 ANCHOR;6,102.6 =' 9 r rt . 2 6,026.1 2,985.4 CAMCO KBG-2- 1 GAS LIFT DMY INT - 0.000' 0.0 2/9/2005 3:00 PACKER;6,103.3 9 Notes:General&Safety End Date Annotation 8/25/2010 NOTE.View Schematic w/Alaska Schematic9.0 NIPPLE;6,124.1 4/28/2017 NOTE Fullbore RPPG Treatment 4590 lbs to D MBE WLEG.6,135 6 (PERF;0454.0-6,524.0 1 IPERF,6,562.0-E594.0--- IPERF,6,504.0-6,614.0 (PERF;6,788.06,010D (PERF;6,627.06,852.0 (PERF;6,660.06,672.0 • PRODUCTION;26.6-7,067.4 1- 0 Cr( C . r X a• vi OI Wci) > ""Z4 °' h O o—W ( - 1 r4 Q�Y CO O N U N ate, > Q Jt _ O .C., r (0 ++ O w cu 0 U a a C C 4.' 0 c _ W }, C -6 a _ c a xr. ❑ t Ou a a D < ❑ .3 W N N N N N N N N N N N N v E p CO Q l7 _J < 0 T T T T T T T T r r r r E +L'' L to jk O rL r2 7 7 7 7 L _ C -C-C4': n I )y,1 ? _ f0 U .0 aJ V) F.. in CO c0 r co O r r r N M V� O +- i C Q N N N N N M M M U -_ n0 ZQ ¢ 0 cc v a) E �- u F- = aJ .2 c 0 u ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ _ s_ v -, 1_ 1 W J J J J J J J J J J J J OA _ — O y W W W W W W W W W W W W 'N aJ .0 U "- F- LL LL LL LL LL LL LL LL LL LL LL LL 4-+ a) a a) -0 O Q J J J J J J J J J J J J O'- 'O > Y a U) I- < < < < < < < < < < < < a) ,n C 4- p - O Z Z Z Z Z Z Z Z Z Z Z Z Ucu (0 a) O a) CO LL LL LL LL LL LL LL LL LL LL LL LL = .-, E' > To +U-+ > +(0C u 0 ",1,J1 - z N- a a1 U > _ ^ C v 0 C _0 v_ T.) Y E U -0 0 O I z C co a 0 0 l0 tti KC U Q a) a ,n C a 4 c. O ❑ a • a -I O LL a O E ill a O 0 a • V � O ", .� R -ia maw �v To co '� y CO U U U d U U U \ �: • E a +c1. y w C > sof W U rdn o • 03 010 KC 15▪ rapt: Nx X � W O (Q a0 V 0. J J J J J J J J J J J J I W '9 w0CIJ MCGCLCCCLC4CLCLCZWCLC W W W W W W W W W W W W mu z Y Y Y Y Y Y Y Y Y Y Y Y NO > > > > > > > > > > > > W Q Q Q Q Q Q Q Q Q Q Q Q > QLL a a a a a a a a a a a a a W Y Y Y Y Y Y Y Y Y Y Y Y c = ro 'lc)! .~— cc. X cn U W= Co co CO CA O N M co eT co Co N @ �� ❑ _,•: co co co co CA O) O O) 0 0 0) CA cc O O 0 O O O O O O O O O E 0mow o o O O O O O O O O O O y W 0 0 0 0 0 0 0 0 0 0 0 0 Q v r. g. g. r; 1; I� r r r r 1� r• 143 co CO CO CO CO CO CO CO CO CO CO CO C VV > E E E E E 2 E E E E 2 2 Co ` ;r`` ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ C � = Co 0 CC 8 O O O OON 000000 C O O O 0 0 0 0 0 0 0 0 0 0a 0 u) ,-ii) 0) C) V COO (0 N M N OE (*7 � a r O) C) N e- 0 0 V CO N L U i� M N N M O O O O N O O O N ENNNNNNNNNNNN i - eQ 6 O) O) 6 6 6 M M M O) O) M a) Q N NNNNNOOONNO '� 01 0 0 0 O 0 0 r 0 0 O o o o o 0 0 c 0 0 0 0 6 +, O a) en 4 C IA If) 1A N 141LO N )n )n 1A 1.n 1f) a V .,' C on E U a Na a) Ci.7 U r+ Q W i E v v 43- "="1 H y ai ,^-1 Q CI) m o CD to m v v o 1n co co ° v) • EZ S Z r e- r p O O N 0 0 N 1e1 el , +.,• E y H 9 moo a ul O [' w a W ❑ N N M N — NN E z H ra i' G r ''1 Za� 60 � •n C _ ttl v, U O C/9 a a a Q Pm 2Mo.o t o Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Sunday, May 28, 2017 5:08 AM To: Regg,James B (DOA) 1 1 ( --qtr Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Well Integrity Supv CPF1 and 2; NSK Optimization Engr; CPF1&2 Ops Supt;Jensen, Marc D; Sullivan, Michael; Krysinski, Marina L;Targac, Gary; Effiong, Michael; Stanley, Scott M Subject: LPP/SSV Returned to Service on CPAI Well 1E-119 on 05/27/17 Jim, The low pressure pilot(LPP) on well 1E-119 (PTD#204-031)was returned to service and removed from the safety defeat log on 05/27/17, after the well was shut-in following completion of the planned injection profile log. The LPP had originally been defeated on 05/26/2017 when the well was restarted in preparation for the logging operation. This notification is in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. Thank you. Best regards, Michael Effiong (Alternate: Scott Stanley) West Sak Production Engineer ConocoPhillips Alaska Inc. Office: 1 907 659-7234 Pager: 1 907 659-7000 pg. #497 Email: n1638conocophillips.com SCANNED JUL1 4201, 1 • t<EC( 1 -l(9 ZJ4--O3/0 Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> • Sent: Friday, May 26, 2017 4:00 PM r 6/L61(-7 To: Regg, James B (DOA) ( G Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Well Integrity Supv CPF1 and 2; NSK Optimization Engr; CPF1&2 Ops Supt;Jensen, Marc D; Sullivan, Michael; Krysinski, Marina L;Targac, Gary; Effiong, Michael Subject: Defeated LPP/SSV on CPAI well 1E-119 on 05/26/2017 Jim, The low pressure pilot(LPP) on well 1E-119 (PTD#204-031)was defeated today, 5/26/2017, after the well was put on water injection service in preparation for a planned injection profile logging operation. The well is currently injecting at a wellhead injection pressure of 14 psi and rate of 1120 BWPD. The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Best regards, Michael Effiong (Alternate: Scott Stanley) West Sak Production Engineer ConocoPhillips Alaska Inc. Office: 1 907 659-7234 Pager: 1 907 659-7000 pg. #497 Email: n1638(a conocophillips.com SCANNED .JUL 1. 42'017 STATE OF ALASKA ' ALA.OIL AND GAS CONSERVATION COMMISSO REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing❑ Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: MBE GEL JOB El 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: ConocoPhillips Alaska, Inc. Development❑ Exploratory❑ 204-031 3.Address: P. O. Box 100360,Anchorage,Alaska Stratigraphic El Service U 6.API Number: 99510 50-029-23198-00 7.Property Designation(Lease Number): 8.Well Name and Number: KRU 1E-119 ADL 25660,ADL 25651 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kuparuk River Field/West Sak Oil Pool 11.Present Well Condition Summary: Total Depth measured 7,090 feet Plugs measured None feet true vertical 3,660 feet Junk measured None feet Effective Depth measured 6 ggg feet Packer measured 6,103 feet true vertical 3,596 feet true vertical 3,023 feet Casing Length Size MD TVD Burst Collapse CONDUCTOR 77 feet 16 " 108' MD 108 SURFACE 3,280 feet 9 5/8" 3,310' MD 2051 PRODUCTION 7,061 feet 51/2" 7,087' MD 3658 RECEIVED MAY 222017 Perforation Depth Measured depth 6454-6524,6562-6594,6594-6614,6788-6810,6827-6852,6860-6872 feet AOGCC True Vertical depth 3223-3268,3294-3315,3315-3329,3448-3464,3475-3493,3498-3507 feet Tubing(size,grade,measured and true vertical depth) 3.5" L-80 6,136' MD 3,040'TVD Packers and SSSV(type,measured and true vertical depth) PACKER-BAKER SABL-3 PACKER 6,103' MD 3,023'TVD SSSV: - NONE 507' MD 502'TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): SCANNED JUN 1 3 2017 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: SHUT-IN Subsequent to operation: SHUT-IN 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations U Exploratory❑ Development0 Service D Stratigraphic 0 Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR 0 WINJ 0 WAG 0 GINJ❑ SUSP 0 SPLUG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-080 Contact Name: John Peirce Authorized Name: John Peirce Contact Email: John.W.Peirce@conocophillips.com Authorized Title: Sr.Wells Engineer if:". r Contact Phone. (907)265-6471 Authorized Signature: ,..v (.�/• . Date:--S12 Form 10-404 Re ised 4/2017 (/71- 6/ // 5j r. Submit Original Only i/7�2 RBD�t1S w MP? 4 ,_",Ii KUP 1E-119 ConocoPhillips Q Well Attribli Max Ang D TD Alaska.�t1C Wellbore API/UWI Field Name Wellbore Status ncl('1 MD(ftKB) Act Btm(ftKB) Cawtoittigips 500292319800 WEST SAK INJ 73.02 5,488.12 7,090.0 .-. Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) \Rig Release Date 1E-119,5/22/20172:25:12 PM SSSV:NIPPLE Last WO: 31.42 4/13/2004 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag.RKB 6,571.0 4/14/2017 Rev Reason:MBE TREATMENT-SEE NOTES pproven 5/22/2017 Casing Strings HANGER;22.7 1.1Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... WtlLen(I...Grade Top Thread CONDUCTOR 16 15.062 31.0 108.0 108.0 62.50 H-40 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread SURFACE 95/8 8.835 30.2 3,309.8 2,050.8 40.00 L-80 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...WtlLen(I...Grade Top Thread PRODUCTION 51/2 4.950 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..i Set Depth(ND)(...Wt(lb/ft) Grade Top Connection TUBING 31/2 2.992 22.7 6,136.1 3,040.0 9.30 L-80 EUE8RDMOD ,,,,r,r,,,,n„a,,,,,,,,,,,,,,,,,,,,,r,,,,,,,„, I` ,r Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Ind(*) Item Des Corn (in) 22.7 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12'NIPPLE CAMCO DS NIPPLE w12.875'NO GO 2.875 6,078.1 3,010.7 6027 NIPPLE CAMCO DS NIPPLE w/2.812"NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR LOCATOR SUB 8 SPACEOUT 3.000 CONDUCTOR;31.0-108.0 6,088.6 3,015.9 60.04 PBR BAKER 80-40 SLIMLINE PBR w/14'SEAL ASSEMBLY 3.000 • 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 NIPPLE;506.9 - 6,103.3 3,023.3 59.72 PACKER BAKER SABL-3 PACKER 2.780 • 6,124.1 3,033.9 59.26 NIPPLE HES X NIPPLE w/2.75"PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG CPA/WIRELINE ENTRY GUIDE PART#546397 2.990 Perforations&Slots Shot Dens SURFACE;30.2-3,30 8-4Top(ND) Btm(ND) (shots/ Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 6,454.0 6,524.0 3,223.0 3,268.5 WS D,1E- 10/7/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B,1E-119 10/6/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 deg phase,random orient GAS LIFT;4,464.111 6,594.0 6,614.0 3,315.3 3,328.9 WS B,1E-119 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 deg phase,random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2,1E- 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 I 119 deg phase,random orient GAG AT 6,02x.1 6,827.0 6,852.0 3,475.4 3,492.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 6,860.0 6,872.0 3,498.4 3,506.8 WS A2,1E- 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 119 deg phase,random NIPPLE,8,078.1 , ..J u:. orient Mandrel Inserts st ab LOCATOR,6,085.2 P N Top(TVD) Valve Latch Port Site TRO Run PBR,6,068.6 i---r Top(ftKB) (ftKB) Make Model OD(in) Sew Type Type (in) (psi) Run Date Com 1 4,464.1 2,456.0 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 11:30 ANCHOR;6,102.6 "- 9 2 6,026.1 2,985.4 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 2/9/2005 3:00 PACKER;6,103.3 9 N is Wi Notes:General&Safety I End Date Annotation 8/25/2010 NOTE:View Schematic w/Alaska Schematic9.0 NIPPLE,6,124.1 4)28/2017 NOTE:Fullbore RPPG Treatment 4590 lbs to D MBE WLEG;6,135.6 IPERF;6,454.0-6,524.0 IPERF;6,562.0-6,594.0 a i IPERF;6,594.08,614.0 IPERF;6.788.0-6,810.0 -.IPERF;6,827.06,852.0 IPERF;6,860.08,872.0 PRODUCTION;26.6-7,087.4 • • 1E- 119 DTTMS JOBTYF SUMMARYOPS 4/14/17 NRWO TAGGED FILL @ 6571' RKB (D-SANDS ARE OPEN ALONG W/9' OF B-SANDS); MEASURED BHP (754 psi) @ 6568' RKB. JOB COMPLETE AND READY FOR RPPG TREATMENT. 4/28/17 NRWO PUMPED FULLBORE RPPG MBE TREATMENT PLACING 345 BBL RPPG SLURRY(4590 LBS DRY PRODUCT) INTO FORMATION, FOLLOWED BY 22 BBL SW AND 33 BBL DIESEL FREEZE PROTECT, NO INCREASE IN TREATING PRESSURE OBSERVED DURING JOB, IN PROGRESS ***LEAVE SHUT-IN UNTIL CTU FCO*** 5/2/17 NRWO RIH WITH DJN, START CLEANING OUT AT 6100' CTMD, TAKING 100' BITES AND CHASING UP TO THE TUBING TAIL, WE CLEANED OUT DOWN TO 6995' RKB, WELL FREEZE PROTECTED (JOB COMPLETE) COMMENT Evaluating well for 2nd RPPG Treatment; Likely requires a"larger"treatment. • Kies te 6gc3)o Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Monday, May 8, 2017 11:09 PM -getict qt/(7 To: Regg,James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Well Integrity Supv CPF1 and 2; NSK Optimization Engr; CPF1&2 Ops Supt;Jensen, Marc D; Sullivan, Michael; Krysinski, Marina L;Targac, Gary; Effiong, Michael Subject: Defeated LPP/SSV on CPAI well 1E-119 on 05/08/2017 Jim, The low pressure pilot (LPP) on well 1E-119 (PTD# 2040310) was defeated today, 5/08/2017, after the well was put on water injection service following and extended shut-in period. The well is currently injecting at a wellhead injection pressure of 200 psi and rate of 750 BWPD. The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Best Regards, Scott Stanley / Michael Effiong West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 n1638@conocophillips.com schtita 1 OF Tit, S 4,31.� I// .4*sTHE STATE Alaska Oil and Gas *" OfLASIc;A Conservation Commission - A 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov John Peirce Sr. Wells Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 SC014a Anchorage, AK 99510 Re: Kuparuk River Field, West Sak Oil Pool, KRU 1E-119 Permit to Drill Number: 204-031 Sundry Number: 317-080 Dear Mr. Peirce: 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, 4AP/ Daniel T. Seamount, Jr. Commissioner DATED thisZ' day of February, 2017. RDDMS 1'--FE3 2 7 2017 • • • RECEIVED STATE OF ALASKA FEB 15 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon EPlug Perforations E Fracture Stimulate 1 Repair Well E Operations Shutdown L Suspend E Perforate fl Other Stimulate r Pull Tubing EChange Approved Program E Plug for Redrill E Perforate New Pool E Re-enter Susp Well E Alter Casing E Other: MBE GEL JOB F 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska,Inc. Exploratory 1 Development E 204-031 ' 3.Address: 6.API Number: P.0.Box 100360,Anchorage,Alaska 99510 Stratigraphic Service 50-029-23198-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A it spacing exception? Yes I No " ,/ KRU 1E-119 ' Will planned perforations require a pac g 9.Property Designation(Lease Number): 043 10.Field/Pool(s): ADL 25660 + a.S(05 I Kuparuk River Field/West Sak Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): 7,090' ' 3,660' • 6999 • 3596 • 1475 NONE NONE Casing Length Size MD ND Burst Collapse Structural Conductor 77' 16" 108' 108' Surface 3,280' 9 5/8 3,310' 2,051' Production 7,061' 51/2 7,087' 3,658' Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 6454-6524,6562-6594,6594-6614 3223-3268,3294-3325,3315-3329 3.500" L-80 6,136' 6788-6810,6827-6852,6860-6872 ' 3448-3464,3475-3493,3498-3507 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): PACKER-BAKER SABL-3 PACKER ' MD=6103 ND=3023 SSSV: NONE N/A 12.Attachments: Proposal Summary 0 Wellbore schematic 2 13.Well Class after proposed work: Detailed Operations Program E BOP Sketch ❑ Exploratory E Stratigraphic E Development E Service F A 14.Estimated Date for 3/14/2017 15.Well Status after proposed work: Commencing Operations: OIL ] WINJ WDSPL E Suspended f 16.Verbal Approval: Date: GAS fl WAG F' GSTOR I® SPLUG ig�^�^ Commission Representative: GINJ E Op Shutdown E Abandoned q. 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact John Peirce @ 265-6471 Email John.W.Peirce@conocophillips.com Printed Name John Peirce , Title Sr.Wells Engineer "4. ' . Z 114/1'7 Signature " " Phone 265-6471 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 \-7- 0560 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ %-k5¶ 11°0 Other: �"t Post Initial Injection MIT Req'd? Yes ❑ No L`1 /� Spacing Exception Required? Yes ❑ No d Subsequent Form Required: I f� -- 4-/j RBDMS 1 u. FEB 2 7 2017 APPROVED BY 2 1 Approved by:a 13-4;KINAL COMMISSIONER THE COMMISSION Date: 2 17 Pm g`5�R�. VI Submit Form and Form 0-403 Revised 11/2015 is valid for 12 months from the date of approval. Attachments in Duplicate fj* 474,-47 a KUP I 1 E-119 • con©coPhillips ; Well Attribunir Max Angle TD AINSka h1C: Wellbore API/UWI Field Name Wellbore Status ncl(°) MD(ftKB) Act Btm(ftKB) • c o'sm-,prp,'! 500292319800 WEST SAK INJ 73.02 5,488.12 7,090.0 -.. a,. Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) -Rig Release Date 1E-119,2/13/20177:10:34 AM SSSV:NIPPLE Last WO: 31.42 4/13/2004 Verbal sclgma0c.(ectua0 Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:SLM 6,564.0 9/9/2015 Rev Reason.TAG lehallf 9/13/2015 R Casing Sings HANGER;22.7i-e' w Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread CONDUCTOR 16 15.062 31.0 108.0 108.0 62.50 H-40 WELDED Casing Description 'OD(in) ID(in) Top(ftKB) Set Depth(ORB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread SURFACE 9 5/8 8.835 30.2 3,309.8 2,050.8 40.00 L-80 BTC i. Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread PRODUCTION 51/2 4.950 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection +' ff TUBING 31/2 2.992 22.7 6,136.1 3,040.0 9.30 L-80 EUE8RDMOD 4 , , �il Completion Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl(°) Item Des Com (in) 22.7 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE CAMCO DS NIPPLE w/2.875"NO GO 2.875 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE w/2.812"NO GO 2.812 ' 6,085.2 3,014.2 60.12 LOCATOR LOCATOR SUB 8 SPACEOUT 3.000 6,088.6 3,015.9 60.04 PBR BAKER 80-40 SLIMLINE PBR w/14'SEAL ASSEMBLY 3.000 CONDUCTOR;31.0-108.0 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 NIPPLE;506.9 6,103.3 3,023.3 59.72 PACKER BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 5926 NIPPLE HES X NIPPLE w/2.75"PROFILE 2.750 „5 6,135.6 3,039.8 59.01 WLEG CPAI WIRELINE ENTRY GUIDE PART#546397 2-990 Perforations&Slots Shot Dens Top(TVD) Btm(TVD) (shots/ SURFACE;392-3,309.8-. Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 6,454.0 6,524.0 3223.0 3268.5 WS D,1E- 10/7/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 11 6,562.0 6,594.0 3293.8 3,315.3 WS B,1E-119 10/6/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 deg phase,random orient GAS LIFT,4,464.1 6,594.0 6,614.0 3,315.3 3,328.9 WS B,1E-119 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 deg phase,random orient 6,788.0 6,810.0� 3,448.4 3,463.6 WS A2,1E- 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 6,827.0 6,852.0 3,475.4 3,492.8 WS A2,1E- 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 GAS LIFT;8,026.1t. 119 deg phase,random orient it6,860.0 6,872.0 3,498.4 3,506.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 I 119 deg phase,random orient NIPPLE;6,078.1 Mandrel Inserts St an LOCATOR;8,085.2 N Top(ND) Valve Latch Port Size TRO Run r Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com PBR;6,088.6 ) / 1 4,464.1 2,456.0 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 11:30 9 ANCHOR;6,102.6 M) 2 6,026.1 2,985.4 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 2/9/2005 3:00 9 PACKER,6,103.3 A-1, Notes:Notes:General&Safety End Date Annotation 8/25/2010 NOTE View Schematic w/Alaska Schematic9.0 NIPPLE;6,124.1 WLEG;6,135.6 ill IPERF;6,454.0-6,524.0 1 IPERF;6,562.0-6,594.0 1 IPERF,6,594.08,614 0 1 1 IPERF;6,788.0-6,810.0 1 1 IPERF;6,827.08,852.0 1 IPERF;6,860.0$872.0 1 PRODUCTION;26.6-7 087 4 • Proposal for 1E-119 to 1E-166 D Sand MBE Treatment with RPPG 1E-119 single vertical injector was drilled & completed in 2004 with 3.5", L-80 Tubing and 5.5", L-80 Production Casing. On 5/27/15, an MBE event occurred from 1E-119 to offset producer 1E-166. A Flowing Temperature Log was performed on 6/6/15 which verified the D MBE at 6454' RKB. Fill was also tagged at 6583' RKB which covered all A sand perfs and the lower B sand perfs. On 9/19/15, a fullbore Crystal Seal job was pumped in 1E-119 to the D MBE then returned to D sand only injection to verify the MBE treatment was holding. 1E-119 remained on PWI for —1 year to D sand only until the MBE treatment failed. The 289' fill still remains covering A and B sand perfs. The following procedure is proposed to reseal a presumed reopened D MBE at 6454' RKB with RPPG (aka: Reformed Polymer Particle Gel) to return 1J-105L1 to PWI service. RPPG is a newly developed synthetic dehydrated crystalline particle polymer gel product that hydrates and swells in water. RPPG is like Crystal Seal in appearance and swellability. However, unlike Crystal Seal, RPPG has a delayed crosslinking feature that bonds individual swollen particle polymer grains together into an amalgamated gel after placement to the MBE. This crosslinking feature should give RPPG MBE treatment better resilience to disaggregation and breakdown vs. Crystal Seal when the treatment is subjected to drawdown pressure by flowing the producer. Unlike previous Crystal Seal MBE treatments performed to date in West Sak MBE's, we propose injecting the initial 50 bbls of gel slurry at maximum concentration to the MBE while drawdown is applied on the MBE by flowing 1E-166 offset producer. Procedure: Slickline: 1) RIH to tag fill to verify that the D MBE is still unobstructed by fill. Also obtain SBHPS at the D sand perfs. If the tag shows fill above 6524' (base of D sand perfs), bail fill to fully uncover the D sand perf interval at 6454 - 6524' RKB. Pumping: 2) Put 1E-166 producer and 1E-119 injector online 12 to 24 hrs before pumping RPPG into 1E-119. Have 1 E-166 flow to 1 E test separator. This reestablishes flow through the D MBE between the wells. RU mixing van and pumping equipment on 1E-119. When ready to fullbore pump into 1E-119, contact DSO to SI PWI to 1E-119, then swap over to pumping a 10 - 20 bbl Step Rate Injection Test (SRIT) with Seawater from transports down tubing to determine optimal injection rate for slurry pumping. Pump rate for slurry is likely to be in 1 - 1.5 bpm range. Start blending Seawater with 1 - 4 mm mesh RPPG at 0.25 ppg slurry concentration on-the-fly in mixing van and fullbore pump slurry down tubing at steady established rate while producing 1E-166. Pump the first 50 bbls of slurry into the D sand MBE at —6454' RKB. After 50 bbls of slurry exits the wellbore to the MBE, shut-in 1E-166 (to avoid any significant placement of RPPG to the producer), while continuing slurry pumping to 1E-119. Continue pumping steady rate and slurry concentration until WHIP reaches —800 psi, then swap from RPPG slurry to pumping to 27 bbls of Seawater spacer, followed by —28 bbls Diesel FP followed by Shutdown. Wait 2 days for RPPG particles to fully crosslink in MBE before returning 1 E-166 to production. If step 2 is executed as planned, 1 E-166 producer will be allowed to flow back to the plant with low odds that it will create plant upset due to gel production. • • Coil Tubing: 3) RIH with jet swirl nozzle and tag top of RPPG in well, then jet down through RPPG and fill to as deep as possible to shear and mechanically break any RPPG remaining in the well, and to uncover all the perforation intervals to injection. Maintain 1:1 returns to tanks during FCO. POOH. RD CTU. Place 1E-119 on PWI to evaluate results of the MBE treatment. E-line (optional): 4) RIH with (PROF BHA. Log passes to verify that the MBE is sealed off, and to determine new zonal injection splits. POOH. RD E-line. Return 1E-119 to PWI. • Kiat 1E- P 24*-5 lb 4c5lb Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Sunday, April 24, 2016 10:59 AM wept 4(2c-N, To: NSK West Sak Prod Engr; Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; CPF1&2 Ops Supt; Sullivan, Michael; NSK Prod Engr Specialist; CPF1 Prod Engr; Targac, Gary; NSK Optimization Engr; CPF1 DS Operators; Sullivan, Michael; Hall, Tyler A Subject: Return to service of LPP/SSV on well 1E-119 Jim, The low pressure pilot (LPP) on well 1E-119 (PTD#204-031)was returned to service today, 4/24/16, with a pilot setting of 50 psig . The well is currently stabilizing at a wellhead injection pressure of 190 psigand rate at 550 BWPD. The well has been removed from the "Facility Defeated Safety Device Log." This notification is in accordance with "Administrative Approval No. CO 4066.001." The AOGCC will be notified when the injection pressure has increased to above 500 PSIG and the LPP/SSV function is - returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Regards, David Haakinson / Tyler Hall West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 n1638@conocophillips.com SCANNED SEP 2 6 2016 1 a • Kitt !L-/riDns z6,4031,0 (� Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Friday, April 22, 2016 12:37 PM 2{(ZS1I4, To: Regg, James B (DOA) (I Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; CPF1&2 Ops Supt; Sullivan, Michael; NSK Prod Engr Specialist; CPF1 Prod Engr; Targac, Gary; NSK Optimization Engr; CPF1 DS Operators; Sullivan, Michael; Hall, Tyler A Subject: Defeated LPP/SSV on well 1E-119 Jim, The low pressure pilot(LPP) on well 1E-119 (PTD#204-031)was defeated today, 4/22/16, after the well was brought online after a shut-in period . The well is currently stabilizing at a wellhead injection pressure of 100 psi and rate at 550 BWPD. The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 PSIG and the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Regards, David Haakinson / Tyler Hall West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 n1638@conocophillips.com SCANNED SEP.2 6 20i6 • • c4 (E-0 704zi31d Regjj, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Wednesday, April 13, 2016 1:08 PM Cl r 411-511Q, /c,, To: Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; CPF1&2 Ops Supt; Sullivan, Michael; Jensen, Marc D; NSK Prod Engr Specialist; CPF1 Prod Engr; Targac, Gary; NSK Optimization Engr; CPF1 DS Operators; Stanley, Scott M; Haakinson, David Subject: LPP/SSV on well 1E-119 was returned to service • Jim: The low pressure pilot(LPP) on well 1E-119 (PTD# 204-031)was returned to service and removed from the safety defeat log today, April 13th, 2016, after the wellhead injection pressure stabilized above the LPP trip point of 500 PSI. This notification is in accordance with "Administrative Approval No. CO 4066.001." The current wellhead injection pressure is 611 psi at an injection rate of 1,000 BWPD. Please let me know if you have any questions. Regards, Tyler Hall / David Haakinson West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 n1638@conocophillips.com OW SEP. 2 1 2016 1 • • Kr!..A.A l E- Jt`1 �m 6)4o v Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> Sent: Thursday, March 17, 2016 10:09 AM t ,— To: Regg, James B (DOA) • (C7 Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; CPF1&2 Ops Supt; Sullivan, Michael; Jensen, Marc D; NSK Prod Engr Specialist; CPF1 Prod Engr;Targac, Gary; NSK Optimization Engr; CPF1 DS Operators; Stanley, Scott M; Haakinson, David Subject: LPP/SSV on well 1E-119 was returned to service Jim: The low pressure pilot (LPP) on well 1E-119 (PTD#204-031)was returned to service and removed from the safety defeat log today, March 17th, 2016, after the wellhead injection pressure stabilized above the LPP trip point of 500 PSI. This notification is in accordance with "Administrative Approval No. CO 4066.001." _ The current wellhead injection pressure is 600 psi at an injection rate of 950 BWPD.-Please let me know if you have any questions. Regards, Tyler Hall / David Haakinson West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 n1638@conocophillips.com SCANNED SEP. 2 12016 • • KizitI t- ((tel P71\ 2)4©sic Regg, James B (DOA) From: NSK West Sak Prod Engr <n1638@conocophillips.com> 1J 44110 Sent: Saturday, March 12, 2016 4:27 PM ` ( To: Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; CPF1&2 Ops Supt; Sullivan, Michael; NSK Prod Engr Specialist; CPF1 Prod Engr;Targac, Gary; NSK Optimization Engr; CPF1 DS Operators; Stanley, Scott M; Haakinson, David Subject: Defeated LPP/SSV on well 1E-119 Jim, The low pressure pilot(LPP) on well 1E-119 (PTD#204-031)was defeated today, 3/12/16, when the well was brought online on water injection after a long term shut-in period. The well is cur rn fy stabilizing at a wellhead injection pressure of 440 psi and rate at 1000 BWPD. The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 PSIG and the LPP/SSV function is r returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Regards, Tyler Hall / David Haakinson West Sak Production Engineers ConocoPhillips Alaska, Inc. Office: (907) 659-7234 Pager: (907) 659-7000 #497 SCANNED SEP 2 1 2016 n1638@conocophillips.com 1 2_04 - D3 • 24,53`� WELL LOG TRANSMITTAL# To: Alaska Oil and Gas Conservation Comm. December 3, 2015 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 DATA LOGGED Anchorage, Alaska 99501 a ‘2,./V/2015 wl.K.BENDER RE: Multi Finger Caliper (MFC): 1E-119 Run Date: 10/15/2015 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Fanny Sari, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com 1E-119 Digital Data(LAS), Digital Log file, Casing Inspection Report, 3D Viewer 1 CD Rom 50-029-23198-00 iCANNEID PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline &Perforating Attn: Fanny Sari 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-275-2605 Fax: 907-273-3535 FRS_ANC@halliburton.com Date: Signed: p.),,,,L.,44) d3���y STATE OF ALASKA A•KA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon r Rug Perforations r Fracture Stimulate r Pull Tubing r Operations Shutdown r Performed: Suspend p Perforate r Other Stimulate r Alter Casing r Change Approved Program Rug for Redrill r Perforate New Pool r Repair Well r Re-enter Susp Well r Other:Crystal Seal MBE Treatment 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 204-031 _ 3.Address: 6.API Number: Stratigraphic r Service p P. O. Box 100360,Anchorage,Alaska 99510 50-029-23198-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 25651,25660 KRU 1E-119 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): none Kuparuk River Field/West Sak Oil Pool 11.Present Well Condition Summary: Total Depth measured 7090 feet Plugs(measured) none true vertical 3660 feet Junk(measured) none Effective Depth measured 6999 feet Packer(measured) 6103 true vertical 3596 feet (true vertical) 3023 Casing Length Size MD TVD Burst Collapse CONDUCTOR 77 16 108 108 SURFACE 3280 9.625 3310 2051 PRODUCTION 7061 5.5 7087 3658 SCOW/ 13F. 0 1 RECEIVED Perforation depth: Measured depth: 6454-6524,6562-6614,6788-6810,6827-6852,6860-6872 O C T 14 2015 True Vertical Depth: 3223-3269,3294-3329, 3448-3464,3475-3493,3498-3507 AO GCC Tubing(size,grade,MD,and TVD) 3.5, L-80,6136 MD, 3040 TVD Packers&SSSV(type,MD,and TVD) PACKER-BAKER SABL-3 PACKER @ 6103 MD and 3023 ND NIPPLE-CAMCO DS NIPPLE w/2.875"NO GO @ 507 MD and 502 TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment descriptions including volumes used and final pressure: see attached summary 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation shut-in Subsequent to operation shut-in 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations p Exploratory r Development r Service R Stratigraphic r Copies of Logs and Surveys Run r 16.Well Status after work: Oil r Gas r WDSPL r Printed and Bectronic Fracture Stimulation Data r GSTOR r WINJ r WAG P GINJ r SUSP r SPLUG r 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt 315-424 Contact John Peirce t_a'�,265-6471 Email John.W.Peirceconocophillips.com Printed Name John Peirce Title Sr. Wells Engineer Signature � Phone:265-6471 Date 10't 311.5 it TL. 10/'t/t 5 ,j.A- ( oA-76 - J(/ RBDMS (IL 114 201 Form 10-404 Revised 5/2015 ubmit Original Only 1E-119 CRYSTAL SEAL TREATMENT DATE . SUMMARY • 5/27/2015 FREEZE PROTECT F/L WITH 3 BBLS METH FREEZE PROTECT TBG WITH 30 BBLS DIESEL JOB COMPLETE 6/2/2015 TAG FILL @ 6564' SLM (EST. 289' FILL); MEASURED BHP @ 6579' RKB (994 PSI). JOB COMPLETE. 6/6/2015 MEASURE INJECTION TEMPERATURE SURVEY @ 6400', 6540', &6583' RKB. JOB COMPLETE 6/7/2015 FREEZE PROTECT F/L W/5 BBLS METHANOL FREEZE PROTECT TUBING W/3 BBLS METHANOL, FOLLOWED BY 30 BBLS DIESEL JOB COMPLETE 9/9/2015 TAGGED FILL @ 6564' SLM —299' FILL. MEASURED BHP @ 6559' RKB. JOB COMPLETE 9/17/2015 INJECTIVITY TEST W/S/W PUMPED 56 BBL @ 1 BPM PUMPED 10 BBL @ 1.5BPM PUMPED 10 BBL@ 2BPM FREEZE PROTECT TBG WITH 33 BBL OF DIESEL JOB COMPLETE 9/19/2015 PUMPED FULLBORE MBE TREATMENT PLACING 275 BBLS 3% KCL, 36 SW w/ 1-2-4 &4 MIL CRYSTAL SEAL (495# 124 &2695#4 mil, 3190#s total) SURRY INTO FORMATION. WELLFREEZE PROTECTED W/35 DIESEL. Note: Do not bring well back on injection or offset producer 1E-166 on prod until after 20:00, 9/20. 9/29/2015 PUMPED 30 BBLS OF DSL DOWN TBG FOR INJECTIVETY TEST JOB COMPLETE KUP INJ • 1E-119 ConotoPhI ips Well Attributes Max Angle&MD TD Alaska Inc. , Wellbore API/UWI Field Name Wellbore Status ncl(.1 MD(ftKB) Act Btm(ftKB) ,r.ay.,n,al,r,,, 500292319800 WEST SAK INJ 1 73.02 5,488.12 7,090.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 1E-119,903/20153'18'26 PM SSSV:NIPPLE Last WO: 31.42 4/13/2004 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:SLM 6,564.0 9/9/2015 Rev Reason:TAG lehallf 9/13/2015 HANGER;22 7 Casing:Strings Casing Description OD in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...WtlLen(I...Grade Top Thread CONDUCTOR 16 15.062 31.0 108.0 108.0 62.50 H-40 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread SURFACE 9 5/8 8.835 30.2 3,309.8 2,050.8 40.00 L-80 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread PRODUCTION 51/2 4.950 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings Tubmg Description String Ma...ID(n) Top(ftKB) Set Depth(ftSet Depth(TVD)(. Wt(Ib/ft) Grade Top Connection ATUBING 1 31/21 29921 2271 6 3040.01 9 L-80 'Top MILIIIMAIIIIIIIIIIIIIIIIIIMINIEW111/114 NIL Completion Details A Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl C) Item Des Corn (in) 227 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE CAMCO DS NIPPLE w/2.875"NO GO 2.875 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE w/2.812"NO GO 2.812 6,0852 3,0142 60.12 LOCATOR LOCATOR SUB 8 SPACEOUT 3.000 ,° & a-' 6,088.6 3,015.9 60.04 PBR BAKER 80-40 SLIMLINE PBR w/14'SEAL ASSEMBLY 3.000 CONDUCTOR 31.0-108.0 0, 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 NIPPLE,506.9 ,1, a 6,103.3 3,023.3 59.72 PACKER BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE HES X NIPPLE w/2.75"PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG CPAI WIRELINE ENTRY GUIDE PART#546397 2.990 Perforations&Slots Shot Den Top(TVD) Btm(ND) (shots/I SURFACE;30.2-3,309.8-.+ Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Corn 6,454.0 6,524.0 3,223.0 3,268.5 WS D,1E-119 10/7/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 deg phase,random orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B,1E-119 10/6/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 GAS LIFT,4,464.1 deg phase,random orient 6,594.0 6,614.0 3,315.3 3,328.9 WS B,1E-119 10/5/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 deg phase,random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2,1E- 10/5/2004 6.0 (PERE 2.5"HSD 2506 PJ,60 119 deg phase,random GAS LIFT;6,026.1 orient 6,827.0 6,852.0 3,475.4 3,492.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random orient 6,860.0 6,872.0 1498.4 3,506.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random NIPPLE;6,078.1 p ¢ orient Mandrel Inserts att LOCATOR;6,085.2 i on Top(ND) Valve Latch Port Size TRO Run PBR;6.068.6 1^-1 N Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com I' 4,464.1 2,456.0 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 ANCHOR 6,102.6 LULU9 r1, 2 6,026.1 2,985.4 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 2/9/2005 PACKER,6.103.3 9 -1' Notes:General&Safety P End Date Annotation 8/25/2010 NOTE View Schematic w/Alaska Schematic9.0 NIPPLE,6,124.1 i WLEG;6135.6 IPERF.6,4540-6.524.0 - - IPERF,6,5620-6,594.0 - - IPERF;6.5940-6614.0 - IPERF,6,788.0-6,810.0 _ _ IPERF;6,827.0-6,852.0 _ _ IPERF;6860 0-6,872.0 - PRODUCTION;26.6-7,087.4 F T�(r0 I�j;cs. THE STATE Alaska Oil and Gas ofALA�h:A Conservation Commission 'Oh - 333 West Seventh Avenue " -t GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS*P Fax: 907.276 7542 www.aogcc.alaska.gov John Peirce SCANNED ; ' 920,L Sr. Wells Engineer b ` , -o 3 1 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, West Sak Oil Pool, KRU 1E-119 Sundry Number: 315-424 Dear Mr. Peirce: 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, Cathy P. oerster Chair DATED this day of July, 2015 Encl. STATE OF ALASKA ' .SKA OIL AND GAS CONSERVATION CO: ;SION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request Abandon r Flug Perforations r Fracture Stimulate r Pull Tubing r Operations Shutdown '— Suspend r Perforate r Other Stimulate r Alter Casing r Change Approved Program r Rug for Redrill r Perforate New Pool r Repair Well r Re-enter Susp Well r OtherCrystal Seal MBE Treatment Frit 2.Operator Name: 4.Current Well Class: 5 Permit to Drill Number: ConocoPhillips Alaska, Inc. • Exploratory r Development r 204-031 • _ 3.Address: 6 API Number: Stratigraphic r Service F.- P.O. Box 100360,Anchorage,Alaska 99510 50-029-23198-00 7.If perforating, 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? / Will planned perforations require spacing exception'' Yes r No WV KRU 1 E-119 . 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 25651,25660 • Kuparuk River Field/West Sak Oil Pool - 11. PRESENT WELL CONDITION SUMMARY Total depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft) Effective Depth TVD(ft): Plugs(measured): Junk(measured): 7090 - 3660 ' 6999' • 3596'• none none Casing Length Size MD TVD Burst Collapse CONDUCTOR 77 16 108' 108' SURFACE 3280 9.625 3310' 2051' RECEIVED D V E PRODUCTION 7061 5.5 7087' 3658' Y id JUL 14 2015 Q'r 7/1.4/ Is. AOGCC Perforation Depth MD(6454-6524,6562-6614, Perforation Depth TVD(ft): 3223-3269, Tubing Size: Tubing Grade: Tubing MD(ft): 6788-6810,6827-6852,6860-6872 • 3294-3329,3448-3464,3475-3493,3498-3507 3.5 L-80 6136 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft) PACKER-BAKER SABL-3 PACKER MD=6103 TVD=3023 NIPPLE-CAMCO DS NIPPLE w/2.875"NO GO MD=507 TVD=502 • 12.Attachments: Description Summary of Proposal r 13. Well Class after proposed work. Detailed Operations Program • BOP Sketch ) " Exploratory r Stratigraphic r Development r Service ri 14.Estimated Date for Commencing Operations: 15 Well Status after proposed work. 7/29/2015 OIL r WINJ r WDSPL r Suspended r 16.Verbal Approval: Date. GAS r WAG r . GSTOR r SPLUG r Commission Representative: GINJ r Op Shutdown r Abandoned r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: John Peirce @ 265-6471 Email. John W.Peirce@conocophillips.com Printed Name John Peirce Title: Sr. Wells Engineer Signature0,,Zi_ '�/ ..e.,•-c,, Phone:265-6471 Date 7/J 3 1 1S srCommission Use Only Sundry Number: Conditions of approval. Notify Commission so that a representative may witness 3 16 L.I. Plug Integrity r BOP Test r Mechanical Integrity Test r Location Clearance r Other: Spacing Exception Required? Yes ❑ No [✓] Subsequent Form Required: /6 - 9CI- APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 7-2-(t1---/-s- v7-L. -4�-/S vTL / //5-- pproved a plication Is all t r 12 months,11�, tr m he date of approval. Submit Form and Form 10-403 Revised 5/2015 1 1 I 1 9 I er�Cl r�j�(/� AttacF epts in Duplicate .. KUP INJ 1E-119 ConocoPhillips LL Well Attributes Max Angle&MD TD Alaska,Inc. Wellbore APIIUWI Field Name Wellbore Status ncl(°) MD(BBB) Act Btm(ftKB) Carroon`f1r. 500292319800 WEST SAK INJ 73.02 5,488.12 7,090.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) leg Release Date 1E-119,6/4/20159:21:54 AM SSSV:NIPPLE Last WO: 31.42 4/13/2004 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:SLM 6,564.0 6/2/2015 Rev Reason:TAG hipshkf 6/4/2015 .................................................... .--, ,�3� HANGER;72.7 =--$"!""E- 1 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 31.0 108.0 108.0 62.50 H-40 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...WtlLen(I...Grade Top Thread SURFACE 95/8 8.835 30.2 3,309.8 2,050.8 40.00 L-80 BTC Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread PRODUCTION 51/2 4.950 26.6 7,087.4 3,658.1 15.50 L-80 BTC-MOD Tubing Strings Tubing Description String Ma...ID(in) Top(1188) Set Depth(ft..Set Depth(TVD)(...Wt(I hitt) Grade Top Connection TUBING auu u4xtwaaa.Completion Detailsl31/21 2.9921 22.71 6,136.11 3,040.01 9.301 L-80 1EUE8RDMOD �����LLL733377LLLLLL Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl I") Item Des Com (in) 227 22.7 0.00 HANGER VETCO GRAY TUBING HANGER 3.500 506.9 502.2 16.12 NIPPLE CAMCO DS NIPPLE w/2.875"NO GO 2.875 -- 6,078.1 3,010.7 60.27 NIPPLE CAMCO DS NIPPLE w/2.812"NO GO 2.812 6,085.2 3,014.2 60.12 LOCATOR LOCATOR SUB&SPACEOUT 3.000 ^....A.,,, .n..M.� 6,088.6 3,015.9 60.04 PBR BAKER 80-40 SLIMLINE PBR w/14'SEAL ASSEMBLY 3.000 CONDUCTOR;31.0-108.0-4I to l 6,102.6 3,023.0 59.73 ANCHOR BAKER K-22 ANCHOR 2.980 NIPPLE;508.9 _ 6,103.3 3,023.3 59.72'PACKER BAKER SABL-3 PACKER 2.780 6,124.1 3,033.9 59.26 NIPPLE HES X NIPPLE w/2.75"PROFILE 2.750 6,135.6 3,039.8 59.01 WLEG CPAI WIRELINE ENTRY GUIDE PART#546397 2.990 Perforations&Slots Shot Dens Top(TVD) Btm(TVD) ( lf SURFACE;30.2-3,309.6- Top(68KB) etm(ftKB) (ftKB) (ftKB) Zone Date 1) Type Com 6,454.0 6,524.0 3,223.0 3,268.5 WS D,1E-119 10/7/2004 6.0 (PERF 2.5"HSD 2506 PJ,60 deg phase,random [.. - orient 6,562.0 6,594.0 3,293.8 3,315.3 WS B,1E-119 10/6/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 GAS LIFT;4464.1 b deg phase,random orient 6,594.0 6,614.0 3,315.3 3,328.9 WS B,1E-119 10/5/2004 6.0 IPERF 25"HSD 2506 PJ,60 deg phase,random orient 6,788.0 6,810.0 3,448.4 3,463.6 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 or 119 deg phase,random GAS LIFT;6,026.1 Orient 6,827.0- 6,852.0 3,475.4 3,492.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 119 deg phase,random - orient 6,860.0 6,872.0 3,498.4 3,506.8 WS A2,1E- 10/5/2004 6.0 IPERF 2.5"HSD 2506 PJ,60 NIPPLE;6,078.1 119 dOrienteg phase,random I Mandrel Inserts -' St LOCATOR;6,085,2 ati Top(TVD) Valve Latch Port Size TRO Run PBR;6,088.6 j. ;1 N Top(ftKB) (ftKB) Make Model OD(M) Sery Type Type (in) (psi) Run Date Com -{ 4,464.1 2,456.0 CAMCO KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 4/13/2004 ANCHOR;6,102.6 CUD9 2 6,026.1 2,985.4 CAMCO 'KBG-2- 1 GAS LIFT DMY INT 0.000 0.0 2/9/2005 PACKER,6,103.3 i�.[r� 19 Notes:General&Safety End Date Annotation 8/25/2010 NOTE:View Schematic w/Alaska Schemalic9.0 NIPPLE;6,124.1 WLEG;6,135.61 IPERF;6,454.0-6.524.0-1 -- IPERF;6.562.0-6.594.0 WERE;6.594.0-6.614.0- - IPERF;6,788.66,810.0 ((( Ip IPERF;6,827.66,852.0 _rl I_ 1 IPERF;6,860.66,872. I PRODUCTION;28.6.7.087.4 1E-119 D MBE to 1E-166 Crystal Seal Treatment Proposal An MBE occurred between 1E-119 vertical injector and the offset 1 E-166 tri-lateral producer on 5-27-15. A SL tag was attained in 1E-119 on 6-2-15 at 6583' RKB (289' fill), and a SBHP was taken at 6579' RKB (3305' TVD) = 994 psi (EMW 5.8 ppg). A 6-6-15 Flowing Temp Survey in 1E-119 confirms the D sand perfs at 6454 - 6524' RKB act as a thief zone due to a D MBE communicating with 1E-166. A 1E-166 well test on 5-27-15 shows a sudden high spike in watercut from 35% to 95% (1515 BWPD). 1E-119 has been SI since 5-27-15 due to the D MBE. Per this procedure, the D MBE will be sealed off by fullbore pumping Crystal Seal down 1E-119. This will enable the return of 1E-119 to PWI service to the West Sak A, B, and D sand ASAP. Procedure: Pumping 1. FB Step Rate Injection Test with Seawater at 0.5 to 1.5 bpm to verify good injectivity. 2. FB Crystal Seal treatment to seal the D sand MBE. Initiate pumping with 56 bbls Seawater down tubing to determine optimal steady rate to pump Crystal Seal slurry. Immediately after Seawater pumping and constant pump rate determination, continue pumping 3% KCL water with 0.05 ppg of 4 mm Crystal Seal down tubing at the established rate. Volume of this stage (and all subsequent stages) is TBD during pumping based on treating pressure responses seen during pumping. Ramp stages as they are called at: 0.10, 0.15, 0.20 and 0.25 ppg (4 mm Crystal Seal) at the established rate, else swap to pumping Flush when signs of a screen out development are seen. If screenout development is noted, attempt to pump 55 bbls of Diesel Flush down tubing to displace all the Crystal Seal from the tubing to the MBE. Underdisplace Crystal Seal from the tubing by -1 barrel to leave the D MBE entirely sealed with Crystal Seal to the wellbore. If screenout has not been seen, but it is time to call Flush, pump 55 bbls of Diesel to displace Crystal Seal from the tubing at stable established rate, then SD. RD. Coil Tubing: 3) RIH with Jet Swirl Nozzle to perform a Crystal Seal & fill cleanout. Perform cleanout jetting Seawater with FR to as deep as possible. FP well with 28 bbls Diesel. RD CTU. E-line (optional): 4) Perform an IPROF to verify that the D MBE has been sealed off. Return 1E-119 to PWI. Obtain well tests at 1 E-166 producer to verify watercut trends as key indicator for presence of an open MBE, or not. JWP 7/13/2015 e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. c1 Q If - 0 3 J Well History File Identifier Organizing (done) D Two-sided ""1111111" 111111 D Rescan Needed II 11111111111 111111 R¡SCAN ~ ;olor Items: ¢GreYSCale Items: }. fq.5 D Poor Quality Originals: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, NolType: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: D Other:: BY: ~ 151 ~p Scanning Preparation BY: C:::-Maria J 1111111111111' "III Project Proofing BY: ~ 151 mp + l Lf = TOTAL PAGES '1lt- (Count does not include cove~ ¡JJ 151 ( - Production Scanning Stage 1 Page Count from Scanned File: !f-5- (CO"ol does ;OC7' sheel) Page Count Matches Number in Scanning Preparation: . YES BY CMam0 Dale S/Irlot; Stage 1 If NO in stage 1, page(s) discrepancies were found: YES 11I1/111111 III "III NO 151 mp NO BY: Maria Date: 151 11/111111111111111I Scanning is complete at this point unless rescanning is required. ReScanned "' 111/1111111 "III BY: Maria Date: 151 Comments about this file: Quality Checked III 1111111111111111 1 0/6/2005 Well History File Cover Page.doc David P. Jamieson Supervisor, Reservoir Engineering ' Greater Kuparuk Area Development C o � � � J 700 G r Alaska, Inc. Me 700 G Street Anchorage, AK 99501 phone 907.265.6543 D ,S6Zb10 September 23, 2010 SEP Z 3 2010 Daniel T Seamount, Jr., Commission Chair Alaska Oil and Gas Conservation Commission M Pill go 333 W. 7th Ave #100 Anchorage, Alaska, 99501 -3539 RE: West Sak Viscosity Reducing Water Alternating Gas Pilot Project Administrative Approval Area Injection Order 213.044 Administrative Approval Conservation Order 40613.009 Dear Mr. Seamount: Enclosed is the West Sak Viscosity Reducing Water Alternating Gas (VRWAG) Pilot Project Status Report for the reporting period of July 1 2009 through June 30 2010. As per conditions described in the pilot approval document, this report was to be submitted to the Commission by September 30, 2010 and contain items specific to the project performance and achievements. Please contact R.Scott Redman (263 - 4514), Mark Hutcherson (265- 1034), or Lubble Jenkins (265 -6912) if you have questions or require additional information. Sincerely, r' ✓�j' f Vi/Gl1f SHI .� David Jamieson Supervisor, Reservoir Engineering Greater Kuparuk Area Development cc: King, Warwick. Jenkins, Lubbie Seitz, Brian Rodgers, James 1'1 oP i i �o oc WS- VRV1/AG P I I.OT P ROJ EST STATUS REPORT REPORTING PERIOD 7/1/2009 -- 6/30/2010 Submitted: 9/30/2010 Prepared By: Mark Nut rson, West Sak DriNsite Petroleum Engineer Reviewed By: e& R , west Sak Reservoir Engineer Approved By: /`�?. 1+�`N 5'N t David Jamieson, OKA Reservoir Engineering Supervisor WS -VRWAG Pilot Proiect Status Report Executive Summary This document is the annual West Sak Viscosity Reducing Water Alternating Gas (VRWAG) Pilot Project Status Report, submitted to the Alaska Oil and Gas Conservation Commission (AOGCC), as required by Area Injection Order 213.044 and Conservation Order 4066.009. The AOGCC, through a letter dated September 9, 2009, requires that the operator vovide the Commission with a report on the status of the VRWAG pilot project by September 30 of each year, beginning in 2010. The WS -VRWAG Pilot Project entails Injecting hydrocarbon enriched gas for 6 WAG (Water Alternating Gas) cycles in 4 patterns in the West Sak Field 1E Drillsite and 1 J Drillsite. An incremental recovery of 3 -6% of the original oil in place is expected in addition to the -20% waterflood recovery estimate. Four injectors were selected for the pilot (1E -102, 1E -117, 1J -122, and 1J -170) targeting five offset producers on gas lift (1E -121, 1E-170, 1J -168, 1J -166, and 1J -120). TD-date-none of the 4 targeted patterns is mature enough in the FOR RMlect to show enhanced production. However, t he 1E -102 injector experienced an MBE (Matrix Bypass Eve nfl with the 1 E -121 producer 37 days into the first MI cycle. It is believed that the MBE is unrelated to the pilot project and would have occurred regardless. The other 3 patterns do not show any adverse effects from to the MI and are continuing forward as planned. J0N-P3 I i e - 10;L ao5 - o0o I E -1 r? ao1f -o'30 15_,aa Introduction The WS -VRWAG Pilot Project is an expansion of the current development plan for the West Sak Reservoir with potential to significantly increase the recovery of oil from the pool. The pilot was approved by the AOGCC on 9/10/09 and the first VR -WAG cycle began 11/23/09 on two of the four patterns, which effectively started the clock on the 36 month planned pilot. The graphic below shows and field overview with the patterns outlined in red: y �• A Ib : / r ,q ^ Sri POL W4 3 s R• yl } 1 Pjcln. �i IJ 1122 a 1E -14 f LQZB 9a 1 Are E r r 9 I? t I 12 4 { i s • Project Performance and Achievements It is still early in the VR -WAG Pilot to detect any uplift or response from the producers. 1 E -102 Pattern • Offset producers: 1 E -121 & 1 B -101 (possible) • Dual lateral well selected for D lateral injection only l l (B lateral was previously isolated due to pre _ pilot MBE) • Began first MI cycle 11/23/09 f I • Experienced MBE in D lateral on 12/29/09, 37 days after beginning MI, and was shut -in 0 Pulled from pilot and remains SI to this date awaiting MBE remediation • Due to the MBE occurring in 1E-102, replacement candidates are being reviewed. • No premature breakthrough events detected j • No oil production response from FOR detected at offset producers r 1� 1 w f i r O 1 E -117 Pattern w • Offset producers. 1E-170, U-168 & 1 E -166 ♦m (Possible) • Tri- Lateral Injection Well (A, B, and D Sands) • Began first MI cycle 11/23/09 • Completed first MI cycle 3/15/10 and was on i produced water injection through the end reporting period of 6/30/10 ! %� • No premature breakthrough events detected • No oil production response from FOR detected at offset producers N Lh 0 1J -170 Pattern to Offset producers: 1J -166 & 1J -168 (Possible) • Tri- Lateral injecting to A & D Sands only (B Sand isolated from pre -pilot MBE to 1J -166) Began first MI cycle on 4/4/10 • On first MI cycle through the end of reporting period of 6130/10 with plans to place back on water \ injection in July 2010 • No premature breakthrough events detected • No oil production response from FOR detected at offset producers ` J i 1 � V a I � � 1 ' 1 0 3 I r t 1 U-122 Pattern r • Offset producer. 1J -120 f • Tri - Lateral injecting to A, B & D Sands • Began first MI cycle on 4/4/10 i' Al • On first MI cycle through the end of reporting period of 6/30/10 with plans to place back on water Injection in T July 2010 • No premature breakthrough from detected • No oil producition response from FOR detected at offset j producers 1 r 0 Infection Performance and FOR Response The VRWAG flood is being managed by injection pressure. Operating rates vary according to geology, well configuration, pore pressure, and injection pressure. Injection rates have been limited to 2.0 MMSCF /d until the maximum operating injection pressure is achieved. At that time, injection rate is controlled by the downhole injection pressure limit. When the wells are converted back to produced water injection (PWI), the downhole pressure remains as the injection rate control limit. The following graphs indicate water /gas injection rates on the 4 pilot injectors and oil production rates and GOR on the 4 primary focus producers and 2 possible response producers. 1E -102 Water /Gas Infection Daily Rates 1500 ■ <nie r<i ❑ <.nLOV 3100 1400 1%0 13M 1120 1200 1680 1100 1540 1001 j 1400 i 700 / 1260 k a � eoo 1,20 980 F D 800 810 T 500 / 200 400 %() 700 420 200 280 100 140 0 0 1a,00 Felts Nres Apes %V" Ants MOO Mges SwM 041@ lk " D"M Jm1/ F.1,10 44r10 Ap10 MpW10 An10 1E -117 Water /Gas Iniection Daily Rates f740 ■ 0 < _ 0 • _ O < _ 2016 1600 1838 1500 / 1770 1400 1652 1700 1574 12M 1416 1100 / 1298 t000 neo s Bop 1062 Sw YIN 500 J MO 700 U4 200 0 e 4.01 FILM M.-M Apes Mavis M09 JJM Awes tern odes MwM 0.09 Jute Fits M.18 Apt* McFle Aw10 • 0 1J -170 Water/Gas Infection Daily Rates 1800 O una_wwi 13 uno_s vwr ■ umo_o vwr 0 un0.ecwr ❑ 2181 1700 2346 1600 2208 1500 2070 r 7100 1932 = , 1300 . 1794 1200 16% e 7100 1518 R 1000 1380 1242 TIC Soo 1104 +i L � i 700 966 600 928 500 690 552 414 276 700 138 0 � Jw09 Fab D9 Mr09 Ap09 May09 Jun OS JJ09 Au009 Sap09 Od09 Nor09 OWD9 Jan10 Fab10 MxiO Apr10 161400 Jun /0 1J -122 Water/Gas Infection Daily Rates 1100 Q unia vwr Q v-rLO Vau uxia oar C7 uara.oarm 2926 1000 2660 9m 234! 000 2128 700 1862 0 m l NJSS 2 ISM 1 330 400 300 IM 3" A Jan oS Fab o9 Mr 09 Ap 09 Map M Jun 09 JJ 09 "09 Sp 09 Od OS /tar 09 C w D0 Am ID Fe610 Mar 10 Ap l M4Y 10 Jiw29 A'. 1E -170 Oil Production Daily Rates 3w M E -170 A OPRI ❑ IC-00 B OPRI O IE -170 O OPRI 1200 1100 1000 900 > 800 a 700 B 600 d � 600 goo V, 3o f . 200 100 0 Jen 09 Feb D9 M&09 Aa O9 May09 Jv109 Jd09 Au009 Sp09 0009 140v09 Dw09 Jan10 Fab10 M4110 A0110 May10 A-10 U -168 Oil Production Daily Rates 1300 ■ k' AOPPI 13 14-16 BOPR/ 0 UJMOOOPRI 1200 1100 1000 !00 > B00 a 700 coo ( r 5w �Y� 400 900 200 100 0 JwN FAA! Mao! Apo! M4y09 Jun09 JJ09 AuyOS Sp09 0d09 Nov09 Dw09 Jan10 F4610 Mr IA Ap10 Ma1F1A MU • • 1J -166 Oil Production Daily Rates W-166 AOPRI Q 14Ke BOPAI ILKe OOPRI 3000 4 y 2000 O 1000 0 Jan 09 JAM Ma 09 Apr C9 May D9 Jun 09 JJ 09 &V OS Sep 09 Ot109 Nw 09 Da 09 Jr+ 70 Feb /0 Mall 70 AP 10 M* 70 J+n 70 1J -120 Oil Production Daily Rates 11� 92 N-I20 A OPRI Cl IJ-U B OPRI 1L�. UL120 O OPRI I 1300 1200 1100 1000 900 700 500 X00 200 r . ♦ J , V\_ 0 Jsn 09 FbC9 Mr 09 Ap 09 May 09 Jun 09 JJ 09 Au009 Sep 09 Od 09 W" Cs Dr 09 Jen 70 i.b10 Mw 1 0 Ap 10 Md 10 Jun 10 i • 1B -101 Oil Production Daily Rates 1600 M w -IoLe DPRI 13 t8 -tol_D OPRI 1500 1100 1300 1200 1100 1000 Q 900 0 n t300 700 O 6w 500 100 300 200 100 8 J-09 FL3 Ma09 App 09 May 09 J-09 JJ09 A-909 5-009 Oct09 Nov09 D.cO9 Jsn10 fsb10 Mm10 Ap10 M-00 Jun10 1E -121 Oil Production Daily Rates 1000 ® IE d21_B OPRI ❑ K -IZLD DPRI 900 000 700 i 600 000 S 100 300 200 100 0 "on 11400 Mr00 Apo! MryIS JIw09 JJ09 Atg09 Sp09 OA09 M-09 D-09 J.n10 Abm MwIO Ap10 M4p10 Jut 0 1E -123 Oil Production Daily Rates 0 1E El E-123_00PR1 100 i 300 1 e: g S 200 100 Je1109 fob09 M&09 Aer09 M4y09 Ju+09 JJ03 Auy09 S"09 0d09 11*v09 Oet09 Jen10 feb10 Mx10 Ap10 Mey10 J-10 FOR Response Plots The FOR Response Plots are shown for the following injector /producer well pairs: I njector /Producer Open Injector Zones Open Producer Zones 1E- 102/1E -121 D Sand D and B Sands 1E- 117/1E -170 D, B and A2 Sands D, B and A2 Sands 1E- 117 /1J -168 D, B and A2 Sands D, B and A2 Sands 1J- 170/1E -166 D and A2 Sands D, B and A2 Sands 1J- 122/1J -120 D, B and A2 Sands D, B and A2 Sands 1E- 102/16 -101 D Sand D and B Sands 1E- 102 /1E -123 D Sand D and B Sands Each set of FOR Response Plots includes an Oil Production Plot, a GOR and Watercut Plot and a VRWAG Injection Well Plot on the same page. The injection plot shows the timing of water and gas slugs on the same time scale as the offset production well's Oil Rate, GOR and watercut performance. 1 E -10211 E -121 VRWAG Response Plots West Sak 1E -121 Oil Production 3000 2500 -- oil production 2000 N 1500 1000 500 i , I 0 Jan-05 Jan-06 Jan -07 Jen-08 Dec-M Dec-09 Dec -1 West Sak 1 E -121 GOR and Watercut 50 — - 100 4.5 ®90f 90 4.0 - - wale rcut - -- - s0 35 70 Q 30 60 LL r° U �+ 2.5 ....... 50 O 2.0 - - -- - 40 CO 1.5 30 i 1.0 20 I 0.5 10 I 0.0 Ji 0 Jan Jan Jon-07 Jan -08 Dec-00 Dec-08 Dec-10 West Sak 1E -102 VRWAG Injection Well 3500 3000 —Gas Injection Rate to 2500 —Water Injection Rate A 2000 LL U N 'g 1500 ai o: c 1000 500 0 Jan-05 Jan-06 Jan -07 Jan-08 Dec-08 Dec-09 Dec -10 • 0 1E -117ME -170 VRWAG Response Plots West Sak 1E -170 Oil Production 2500 - - - -- ---- .._.__- - - - - -. 2000 --oil production 1500 1000 a 500 Jan -05 J01•06 Jan -07 Jan-08 Dac-08 Dec-09 Dec-1 West Sak 1E -170 Watercut and GOR 5.0 -- - - - -- — 100 4.5 gor 90 tS — Ovate rcut 4.0 so 3.5 70 30 - 60 yc h 2.5 a 2.0 40 K 1.5 30 1.0 _. ..__. 20 05 _.._. _ _._.. 10 0.0 — 0 Jan -05 Jan-06 Jan -07 J" Dec-08 Dec-09 Dec -10 West Sak 1E -117 VRWAG Injection Well 4000 3500 Gas Injection Rate —Water Injection Rate 3000 N 5 2500 LL 2000 1500 !C 1000 C 500 0 Jan05 Jan45 Jm*7 Jan-08 Dec49 Dec-09 Dec -10 1E- 117/1J -168 VRWAG Response Plots West Sak U -168 Oil Production 2500 — – - - -.. 2000 —oil production 1500 m 1000 a b 500 Jan-05 Jan-08 Jan -07 Jan-08 Dec-M Dec .09 Dec - W est Sak U -168 GOR and Watercut 5.0 — _.____ --- - - -- 100 4.5 90 4.0 �. gor 80 S_5 — Wat @fCUt 70 m Q 30. 60 :k LL 2.5 so � v o 2.0 40 f.9 1.5 .._ 30 to _ ___ 20 0.5 - _.. _._ ' 10 00 i 0 Jan -05 Jan-05 Jan -07 Jane Dec-08 Dec-09 Dec -10 West Sak 1E -117 VRWAG Injection Well 4000 3500 —Gas Injection Rate Q —Water Injection Rate 3030 0 T 2500 e �2000 1500 o: 1000 € 500 0 – Jan -05 Jars -X Jan -07 Jan08 Cac-0e Dec-09 Dec - ! • 1J- 12211J -120 VRWAG Response Plots West Sak 1J -120 Oil Production 3000 - — 2500 —oll production d 2000 1500 1000 a 0 Jan.-05 Jan-06 Jan -07 Jan -08 Dec-08 Dec-09 Dec 1 West Sak 1J -120 GOR and Watercut 5.0 100 4.5 go 4.0 -� gor 89 — watercut 3 5 70 P 30 60 a t 25 s 20 40 1.5 30 10 0,5 10 0.0 0 Jan -05 Jan -06 Jan-07 Jen-08 Dec-08 Dec-09 Dec•10 West Sak 1J -122 VRWAG Injection Well 4000-- 35M -Gas Injection Rate 3000 Water Injection Rate 0 IV 2500 ai 2000 at r0 1500 K C 1000 L c 500 0 Jan-05 Jan-06 Jan -07 Jan-08 Dec08 Dec49 Dec -10 • • 1J- 17011E -166 VRWAG Response Plots West Sak 1J -166 Oil Production 6000 -- — S000 oil production 4000 N 3! M I 2000 O 1000 .. _ ........ ......... ... Jan -05 Jen-06 Jen-07 Jan-08 Dec-M Dec-09 Dec -1 West Sak 1J -166 GOR and Watercut 5.0 ----- -- -- - -- - - - - -- - - -- 100 4.5 90 4.0 — WaterCUt 6D 35 70 30 6 x LL 2 5 `0 O 2.0 1.5 30 10 20 0.5 10 00 0 Jan-05 Jan-08 Jaa07 Jan-06 Dec-08 Dec4)9 Dec -10 West Sak 1J -170 VRWAG Injection Well 4500 4000 _.......__.. —Gas Injection Rate 3500 —Water Injection Rate H �3000 2 2500 2000 � ,5w C 0 1000 f 500 0 Jan -05 Jan-06 Jan-07 Jan-08 Dec–M Dec-M Dec-1 1E -102MB -101 VRWAG Response Plots West Sak 1B -101 Oil Production 3000 -- - - - - -- - -- - - - - - -- 2500 oil production lsw 6 1000 ..... ...._. .... 500 Jan -03 Jan-04 Dea04 Dec-05 Dac-06 Dec -07 Dec-06 pec-09 Dec -10 West Sak 1 B -101 GOR and Watercut 200— - -- 10o 180 —gor e0 160 — WaterCUt 80 u-0 70 120 x to 100 so so.. _..._ __... _._. _.. _.._ _ 40 O C7 6 .0 .__..__.__ - ._ _---- 30 40 20 2.0 10 00 0 Jen03 Jan-04 Dec-04 Dec-05 Dec-05 DecV Dec-08 Dec-09 Dec -10 West Sak 1 E -102 VRWAG Injection Well 4000 - - -- — _ -- 1� 35W Gas Injection Rate — Water Injection Rate a 3000 0 p 25ao Q 2000 1500 a 1000 60o 0 32m03 Jan-04 Dec04 Dec45 Dec-06 Dec -07 Dec48 Dec-09 Dec-10 1E- 102 /1E -123 VRWAG Response Plots West Sak 1E -123 Oil Production 4000 3500 . oil production 3000 25w 2000 1500 O 1000 500 0 Jan -03 Jan -04 Dec-04 Dec -05 Dec-06 Dec -07 Dec-08 Dec-09 Dec -10 West Sak 1E -123 GOR and Watercut 5.0 - - -- 100 4.5 gOr 9 4.0 — watercut BO 35 70 30 60 T U u) 25 60 O 20 40 3 c� 15 30 1.0 20 05 10 0.0 i 0 Jan-03 Jan-04 Dec-04 Dec -05 Dec-06 Dec -07 Dec-08 Dec-09 Dec -10 West Sak 1E -102 VRWAG Injection Well 4000 - -- _ - - -- 3500 as Injection Rate —Water Injection Rate 3000 2500 Q N 2000 1500 C _ 1^90 b 500 0 Jan Jan-04 Dec Dec-05 Dec-06 Dec -07 Decd Dec-09 Dec -10 • 0 Monitoring and Testing Per the results of gas sample tests from offset producers, no significant gas breakthrough is detected and, therefore, the VR -WAG cycles will continue as planned on the three remaining VR- WAG injectors. Primary focus for MI producer response monitoring is on wells 1E -170, 1J -168, 1J -166, and 1J- 120. A plot of 1E-121 produced gas analysis is also included to show the impact of MI breakthrough from the MBE on gas composition. 1E -121 Produced Gas Samples 1E -121 Gas Analyses 1000 100 _ - 10 e 1 CL 0.1 0.01 CO2 N2 C1 C2 C3 I -C4 N -C4 I-05 N-05 C6 C7 C8 C1 /C3 Ratio Component D 5/4/09 6 12;29109 0 12 / 3 1/09 01/15110 117/2/10 1E -170 Produced Gas Samples 1 E -170 Gas Analyses 100 10 —— Ifl 0.1 0.01 CO2 N2 C1 C2 C3 I-C4 N-C4 1-05 N -05 C6 C7 C8 C1 /C3 Ratio Component D 10/17/09 ® 12/30/09 0 317/10 o 7/6/10 I 1J -168 Produced Gas Samples 1J -168 Gas Analyses 100 10 d d 1 i? a 0.1 0.01 CO2 N2 C1 C2 C3 1-C4 N-04 I -05 N -05 C6 C7 C8 C1 /C3 Ratio Component ❑ 10/17/09 ■ 12/30/09 ❑ 3/7/10 ❑ 7/6/10 1J -166 Produced Gas Samples 1J -166 Gas Analyses 100 - 10 o, � 1 u a 01 0.01 CO2 N2 C1 C2 C3 I -C4 N -C4 I -05 N -05 C6 C7 C8 C1 /C3 Ratio Component ❑ 5/4/09 •5/21/10 o 7/14/10 0 0 1J -120 Produced Gas Samples 1J -120 Gas Analyses 100 -- - - -- - - -- - -- - - -- - — - - -- — 10 a 0.1 0.01 J. CO2 N2 C1 C2 C3 1 C4 N-C4 I C5 N-05 C6 C7 C8 C1 1C3 Ratio Component 0 4/2v10 • 6/27/10 a 7/12/10 1 E -121 and 1 E -123 will be monitored for VR -WAG Pilot- specific response, but none is expected to be observed since MI was active for such a short period of time on the 1E -102. 113-101 was determined initially to potentially receive support from the 1E -102. The 113-101 was brought online following a workover on 4/10110. Following flush production resulting from an extended shut -in period, the well has since gone back to pre - workover rates indicating there is no significant support from the 37 day gas injection period on the 1E -102. However, the 1B -101 will continue to be monitored. MBE Development The 1E -102 experienced an MBE shortly after commencing the first VRWAG Pilot gas injection period. It is possible the gas injection cycle accelerated the rate at which the MBE path became fully established, but in all likelihood, the MBE path was nearly developed at the time the VRWAG Pilot began and would have fully developed within a short period of time regardless. The three remaining patterns continue to be monitored closely to determine if the pilot program has affected the likelihood of an MBE to occur. To this date there is no evidence to suggest any change in likelihood. I� • WELL LOG TRANSMITTAL To: Alaska Oil and Gas Conservation Comm. Attn.: Christine Shartzer 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Bottom Hole Pressure Survey: 1 E-119 Run Date: 8/25/2010 August 27, 2010 ;~ ~ <, +t ..~ .. ~ ... ,.:. 3 r. f.~ :.. The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Klinton Wood, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 1E-119 Digital Data in LAS format, Digital Log Image file 1 CD Rom 50-029-23198-00 Shut In Bottom Hole Pressure Survey Log 1 Color Log 50-029-23198-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Klinton Wood 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fax: 907-273-3535 kinton. of I ~ ' { •~' _ ~~ ! Date: ~~~= ~ ~v ~?1";~ 4 l~r ~' . ~~`fls ~ Igo q~'3 ~~.r~~~" ~u-v3 r `~'oo(O~ Signed: n U MEMORANDUM TO: Jim Regg ~ ~ ~~Z~ ! ~ P.I. Supervisor t FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, June 30, 2010 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC ]E-I19 KUPARUKRIV U WSAK 1E-119 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv J~'~- Comm Well Name: KUPARUK RIV U WSAK 1E-119 API Well Number: 50-029-23198-00-00 Inspector Name: Bob Noble Insp Num: mitRCN100628075028 Permit Number: 204-031-0 Inspection Date: 6/24/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ~1E-119 Type Inj. ~ W I ~ ~TVD~ 3oza ~~ ------ -- IA ~ ] ]s ~ 19aa ~ -fi- --~- -~9zs ~ 19zs ~ - , - D ~oaoslo T eTest ~ SPT P T t si ]soo ~ Test OA 1~0 ~ ]~s 16s 16s yp . . p Interval avRTST p/F P '' Tubing Igo ~_~go 7so~ ego Notes: ~~ ~ -k'~~'- ~~ I Sbt~'S; At~ ~e - ~l fiJ ~.{_t „:,ib~ ;~4 I~; .~ t_ ~ ...M~ Wednesday, June 30, 2010 Page 1 of 1 ISI~III~G~rs1- ~ _ -~-~, ~. a _. is Schlumberger -DCS 2525 Gambell Street, Suite 400 ., Anchorage, AK 99503-2838 ~`'t•~~` ~~ ~ ~t~~.`~ ATTN: Beth Well Job # ~r Log Description NO. 5063 Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Date BL Color CD 02/09/09 1 L-13 11978475 PRODUCTION PROFILE / - L ~ 08/16/08 1 1 2A-26 AZJZ-00010 USIT ~- ~ 01/16/09 1 1 1D-141A ANHY-00041 FLOWING BHP 01/21/09 1 1 3K-15 604C-00004 INJECTION PROFILE " ~ 01/21/09 1 1 1E-105 AZED-00019 INJECTION PROFILE 01/23/09 1 1 1E-119 AYS4-00023 INJECTION PROFILE v 01/23/09 1 1 3J-01 AYS4-00024 INJECTION PROFILE , 'r 01/24/09 1 1 2V-06 AZED-00022 INJECTION PROFILE /$~- 1 01/26/09 1 1 2K-22 AZED-00024 LDL r~,~ / 01/28/09 1 1 2L-301 AZED-00025 SBHP SURVEY 01/29/09 1 1 iR-03A ANHY-00045 INJECTION PROFILE T ''~-S 02/09/09 1 1 26-11 AZED-00028 INJECTION PROFILE 02/01/09 1 1 2F-16 AZED-00029 INJECTION PROFILE U 02/02/09 1 1 3J-05 AZED-00030 INJECTION PROFILE 02/03/09 1 1 3G-07A AYS4-00033 PRODUCTION PROFILE j S 02/04/09 1 1 i D-03 ANHY-00042 LDL ~ ~1 .- - 02/05/09 1 1 g Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. .1 LPP/SSV returned to service on 1E-119 Page 1 of 2 Maunder, Thomas E (DOA) From: NSK West Sak Prod Engr [n1638@conocophillips.com] Sent: Monday, October 06, 2008 12:57 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; Targac, Gary; NSK Problem Well Supv; Jenkins, Lubbie Allen; NSK West Sak Prod Engr Subject: LPP/SSV returned to service on 1 E-119 Tom /Jim, The LPP/SSV function has been returned to normal on 1 E-119 (PTD 204-031). The well is currently injecting 555 bwpd at 593 psi wellhead pressure. '-" Please let me know if you have any questions. Regards, Hai Hunt ,~,, ~:.~ . +.. From: NSK West Sak Prot! Engr Sent: Sunday, October 05, 2008 4:37 PM To: 'Maunder, Thomas E (DOA)'; 'jim.regg@alaska.gov' Cc: CPF3 DS Lead Techs; CPFl Prod Supt; Targac, Gary; NSK Problem Well Supv; Jenkins, Lubbie Allen; NSK West Sak Prod Engr Subject: LPP/SSV defeated on IE-119 Tom /Jim, The low pressure pilot (LPP) on 1 E-119 (PTD 204-031) was defeated on 10/5/2008 when the well was returned to service after being shut in for an extended period of time, Wellhead pressure started at 400 psi at 519 bwpd injection rate. Wellhead pressure is trending up and we expect to have the LPP/SSV back in service tonight. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4066.001". Please let me know if you have any questions. Regards, Hai Hunt Hai Hunt /Eric Hollar NSK West Sak Production Engineer GonocoPhiltips Alaska, Inc. Phone: (907) 659-7061 10/6/2008 • ConocoP hi~lips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 17, 2008 ~~~~~ AUK ~ ~ ~~~$ Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Maunder: RECE~VE® AUK 2 5 20pg Alaska Oil & Gas Cons., Anchorage C°rnr;~>.;sion ~aay.-a3, 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. These voids were filled with cement if needed and corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The corrosion inhibitor/sealant was pumped August 2-17, 2008. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call MJ Loveland or Perry Klein at 907-659-7043, if you have any questions. Sincerely, Perry Kle ~ ~ Z ~~C~ ~ ConocoPhillips Well Integrity Projects Supervisor • • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Kuparuk Field Date 'Nell Name PTD # Initial top o cement f Vol. of cement um ed Final top of cement Cement top c date ft bbls ft 2H-05 185-168 SF N/A SF N/A 2H-17 200-019 6" N/A 6" N/A 2K-27 201-169 10" N/A 10" N/A 2M-03 191-141 16" N/A 16" N/A 1 B-14 194030 SF N/A SF N/A 1 B-18 194-061 9" N/A 9" N/A 1 B-19 194-064 SF N/A SF N/A 16-20 203-115 21" N/A 21" N/A 1 B-101 203-133 3" N/A 3" N/A 1 B-102 203-122 4" N/A 4" N/A 1Y-05 183-087 6" N/A 6" N/A 1Y-07 183-068 6" N/A 6" N/A 1Y-17 193-068 SF N/A SF N/A 1Y-22 193-070 SF N/A SF N/A 1Y-26a 188-116 SF N/A SF N/A 1Y-30 188-090 SF N/A SF N/A 1E-112 204-091 14" N/A 14" N/A 1E-119 204-031 14" N/A 14" N/A 1 E-121 204-246 6" N/A 6" N/A 1 E-123 204-074 5" N/A 5" N/A s/~ ~/2nns ff Corrosion inhibitor Corrosion inhibitor/ sealant date al 5.10 8/2/2007 1.27 8/2/2007 8.92 8/2/2007 2.13 8/2/2007 1.70 8/13/2008 8.07 8/13/2008 5.10 8/13/2008 5.95 8/13/2008 1.00 8/17/2008 1.00 8/17/2008 1.27 8/13/2008 1.27 8/13/2008 1.27 8/13/2008 2.12 8/13/2008 3.83 8/13/2008 3.83 8/13/2008 5.95 8/17/2008 4.67 8/17/2008 1.00 8/17/2008 1.00 8/17/2008 • ~- MICROFILMED 03/01 /2008 DO NOT PLACE ya„~: --. ~-=Y ~ ,t ~.: ;,_ ;: ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_InsertslMicrofilm Marker.doc Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Job # ,,~ /i~1~51 ~., 4~ m : V ~ ~~~7 +~~~ ~Q Log Description Date ` 11 /07/07 . NO. 4482 Company: Alaska Oil 8~ Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 1 Anchorage, AK 9 ~ ~ y Field: Kup `~ (~.~ J C BL Color D 3J-10 11850465 SBHP SURVEY / ~ 10/31/07 1 1B-08A 11839682 INJECTION PROFILE Z - 10131/07 1 1D-01 11846458 LDL 11/01/07 1 2A-15 11846459 PRODUCTION PROFILE 5 - '~ (o 11102107 1 1E-02 11850470 _ PRODUCTION PROFILE '$ -(~s 11/04/07 1 2N-310 11745242 SCMT 11/04/07 1 1E-119 10687772. OH LDWG EDIT d} ~/ 04/08/04 1 1E-119 10687772 CMR c7QL - 04/08/04 1 1 E-119 10687772 MDT 04/08/04 1 • Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. MEMORANDUM e State of Alaska e Alaska Oil and Gas Conservation Commission TO: Jim Regg P.I. Supervisor ---- I / !(,;7/,,0, , ì ~ ~I l l Iqt~" ~o, ~,!...~ - 1 DATE: Wednesday, June 07, 2006 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC lE-119 KUPARUK R]V U WSAK lE-119 "\J¡ , 0 '?7 \ ~O FROM: Chuck Scheve Petroleum Inspector Src: Inspector Reviewed By: P.I. suprvJßi2- Comm Well Name: KUPARUK RIV U WSAK lE-l19 API Well Number 50-029-23198-00-00 Inspector Name: Chuck Scheve Insp Num: mitCS060605134152 Permit Number: 204-03 ¡ -0 Inspection Date: 6/4/2006 ReI Insp Num Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well I IE-\19 IType Inj. ì W ! TVD í 3024 IA 40 2025 I 1945 I ]940 ! ! I I , , I P.T. 2040310 TypeTest , SPT ! Test psi I 1500 10A 160 i 220 ! 170 ¡ 160 , I Tubing I - Interval 4YRTST P/F P 740 740 ¡ 740 740 i I I i I Notes Pretest pressures were observed and found stable, Well demonstrated good mechanical integriy NON-CONFIDENTIAL 0'·· \1U· -1\\ ;~......M;;\,!-r; .'; j\j ·~v:rth¡~,",- ... ~ r" 'ì n tj \:J' tJ Lv',,¡ Wednesday, June 07, 2006 Page 1 of 1 I} M"'} ~.~ DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Permit to Drill 2040310 5'p Iti ) /l¡J .2 ð 0 Ý Well Name/No. KUPARUK RIV U WSAK 1E-119 Operator CONOCOPHILLlPS ALASKA INC API No. 50-029-23198-00-00 3660 / Completion Date 4/13/2004 / Completion Status 1WINJ C~ 1W~ G~ Y. d MD 7090/ TVD REQUIRED INFORMATION Mud Log No Samples No Directional S~ ~ 2. DATA INFORMATION Types Electric or Other Logs Run: GRlReslDensNeutron Well Log Information: (data taken from Logs Portion of Master Well Data Maint Name Interval Start Stop Log Log Run Interval OH/ Scale Media No Start Stop CH Received Comments 6117/2004 25 Blu 4 3317 7049 Open 5/21/2004 DSN 12566 25 Blu 4 3317 7049 Open 5/21/2004 DSN 12566 25 Blu 4 3317 7049 Open 5/21/2004 DSN 12566 25 Blu 4 3317 7049 Open 5/21/2004 DSN 12566 4 3317 7049 Open 5/21/2004 GRAPHICS, LDWG, INTEQ META, TBL 4 3317 7049 5/21/2004 DSN 12566 Blu 0 6960 1 0/15/2004 CEMENT BOND LOG (SLIM CEMENT MAP TOOL) WITH JEWELRY 5 Blu 6150 6898 2/22/2006 INJECTION PROFILE SPINITEMP/PRESS Sample Set Sent Received Number Comments . Log/ Electr Data Digital Dataset Type Med/Frmt Number Name È: Directional Survey Density og Density og Induction/Resistivity Induction/Resistivity C Tf 12566 -tIícI u ction/Res istivity LIS Verification Cement Evaluation I ~ Injection Profile I i Well Cores/Samples Information: . ADDITIONAL INFORMATION Well Cored? Y~ Chips Received? "r1-M-- Daily History Received? @/N f(}/N Formation Tops Analysis Received? ~ Comments: DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Permit to Drill 2040310 Well Name/No. KUPARUK RIV U WSAK 1E-119 Operator CONOCOPHILLlPS ALASKA INC MD 7090 Completion Date 4/13/2004 Completion Status 1WINJ Current Status 1WINJ TVD 3660 ---~- fL.1 Compliance Reviewed By: Date: API No. 50-029-23198-00-00 UIC Y Co 'S-~~_._. . . 02/21/06 Schlumberger NO. 3691 Schlumberger -DCS .'~ ¡ ,\) ¡ ª .~ 2525 Gambell Street, Suite 400 Com pany: Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 FEB 2 Z 2006 Attn: Helen Warman A TTN: Beth 333 West 7th Ave, Suite 100 .;.... -"iÌl~. ",uIIU!H:>SIOI, Anchorage, AK 99501 Anchorage Field: Kuparuk . Well Job # Log Description Date BL Color CD 1 B-17 /q4 - 045" 11216283 SBHP SURVEY 02/18/06 1 1 E-36 /98-,,2/3 11216282 SBHP SURVEY 02/18/06 1 3H-07 /9,7-n7Q 11217023 LDL 02/11/06 1 3H-07 ,I 1', 11166757 STATIC SURVEY 01/20/06 1 2A-09 fßfo-rDJ 11154126 PRODUCTION PROFILE 02/09/06 1 1A-10 fP.f- Ill'll) 11213710 INJECTION PROFILE 02/08/06 1 2M-14 I'f';)- /)10:2. 11154127 INJECTION PROFILE 02/10/06 1 1 E-05 /91')- /)6Ç< 11166747 PRODUCTION PROFILE WIDEFT 12/25/05 1 2H-12 /Pl:)-,~({) 2 11154128 PRODUCTION PROFILE WIDEFT 02/11/06 1 1 C-21 11154131 PRODUCTION PROFILE WIDEFT/GHOST 02/14/06 1 3G-18 IqO-/:J~ 11154129 PRODUCTION PROFILE WIDEFT 02/12/06 1 1E-119 ~04-{)õl 11217025 INJECTION PROFILE 02/13/06 1 2U-13 /B4-;J'f{¿; 11166753 PRODUCTION PROFILE 01/14/06 1 1Y-09 /8-"3- ~ 11213128 INJECTION PROFILE 02/06/06 1 . 1 E-1 05 11162832 MEMORY INJECTION PROFILE 01/28/06 1 2C-08 /B":Z.¡-c¡q~ 11141255 INJECTION PROFILE 01/28/06 1 2C-02 /R7¡- f'R3 11213129 INJECTION PROFILE 02/07/06 1 1C-25 /QQ-03! 11144074 GLS 02/02/06 1 2C-14 /f34- fO 11166759 PRODUCTION PROFILE 01/25/06 1 2C-10 /13-1- 't 11144067 PRODUCTION PROFILE 01/26/06 1 1A-18 /qn- ~ ~ 11144070 PRODUCTION PROFILE 01/29/06 1 2C-01 /8!;-C; ~ 11213709 INJECTION PROFILE 02/07/06 1 1D-32 t)()()-173 11141252 LEAK DETECTION LOG 01/25/06 1 2C-12 IR4-~ 11141260 PRODUCTION PROFILE 02/02/06 1 2C-15 184 - :;'6~ 11141254 PRODUCTION PROFILE 01/27/06 1 1J-154 N/A PRODUCTION LOG W/TRACTOR 02/05/06 1 1 E-1 04 11217024 INJECTION PROFILE 02/12/06 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to·(907) 561-8317. Thank you. ~~ MEMORANDUM . State of Alaska . Alaska Oil and Gas Conservation Commission TO: Jim Regg 'V ~ 3/' 4-1~Ç P.I. Supervisor 1~1 DATE: Wednesday, March 02, 2005 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1E-1l9 KUPARUKRIVUWSAK 1E-1l9 t l"' 03\ dv°"l FROM: Chuck Scheve Petroleum Inspector Src: Inspector Reviewed By: ,..-c-&-- P.I. Suprv 0 . Comm NON-CONFIDENTIAL Well Name: KUPARUK RIV U WSAK IE-I 19 API Well Number: 50-029-23198-00-00 Inspector Name: Chuck Scheve Insp Num: mitCS05022416552I Permit Number: 204-031-0 Inspection Date: 2/24/2005 Rei Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well IE-II9 IType Inj.' i P TVD I 3024 IA I 70 1640 I 1610 I 1610 i I P.T. 2040310 ITypeTest I SPT Test psi I 756 OA I 160 170 I 170 ¡ 170 I i Interval INITAL P/F P Tubing I 860 860 I 860 I 860 I I Notes: Pretest pressures were observed and found stable. SCANNED JAN 0 3 2007 -'i/.'-- . Wednesday, March 02, 2005 Page I of I . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Winton_Aubert@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. KRU 1E-119 02/23/05 Arend I Savageau AES Chuck Scheve s P I P Well P.T.D. Notes: Well P.T.D. Notes: Well P.T.D. Notes: Well P.T.D. Notes: Test Details: TYPE INJ Codes F = Fresh Water Inj G = Gas Inj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= Other (describe in notes) MIT Report Form Revised: 06/19/02 MIT KRU 1E-119 02-23-05.xls . Conoc~illips . Mike Mooney Wells Group Team Leader Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4574 November 15, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ¡th Avenue Suite 100 Anchorage, Alaska 99501 ~ î Subject: Report of Sundry Well Operations for 1 E-119 (APD # 204-031) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent perforation operations on the Kuparuk well 1 E-119. If you have any questions regarding this matter, please contact me at 263-4574. Sincerely, f1- ¡f¡f tlV"J M. Mooney Wells Group Team Leader CPAI Drilling and Wells MM/skad IG'~JAL · STATE OF ALASKA I ALASKA Oil AND GAS CONSERVATION COMMIS ION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon 0 Repair Well 0 Plug Perforations 0 Stimulate 0 Other 0 Alter Casing 0 Pull Tubing 0 Perforate New Pool 0 Waiver 0 Time Extension 0 Change Approved Program 0 Ope rat. ShutdownD Perforate E! Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development 0 Exploratory 0 204-031 I 3. Address: Stratigraphic 0 Service E! 6. API Number: P. O. Box 100360, Anchorage, Alaska 50-029-23198-00 7. KB Elevation (ft): 9. Well Name and Number: RKB 28' 1 E-119 8. Property Designation: 10. Field/Pool(s): ADL 25651 & 25660 Kuparuk River Field I Kuparuk River Oil Pool 11. Present Well Condition Summary: Total Depth measured 7090' feet true vertical 3660' feet Plugs (measured) 6124',6538',6683' Effective Depth measured 6975' feet Junk (measured) true vertical 3579' feet Casing Length Size MD TVD Burst Collapse Structural CONDUCTOR 80' 16" 108' 108' SURFACE 3282' 9-5/8" 3310' 2051' PRODUCTION 7060' 5-1/2" 7087' 3658' Perforation depth: Measured depth: 6454'-6524',6562'-6614',6788'-6810', 6827'-6852', 6860'-6872' true vertical depth: 3223'-3269',3294'-3329',3448'-3464', 3476'-3493', 3498'-3507' Tubing (size, grade, and measured depth) 3-1/2" , L-80, 6136' MD. Packers & SSSV (type & measured depth) Baker SABL·3 packer @ 6103' Cameo nipple @ 507' 12. Stimulation or cement squeeze summary: Intervals treated (measured) n/a RBDMS BFL NOV 1 7 2004 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil·Bbl Gas-Me! Water-Bbl Casina Pressure Tubina Pressure Prior to well operation -- Subsequent to operation SI -- 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory 0 Development 0 Service E! Daily Report of Well Operations_X 16. Well Status after proposed work: Oil 0 GasD WAGD GINJD WINJE! WDSPLD 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A i! C.O. Exempt: Contact Mike Mooney @ 263-4574 Printed Name MiVOOney Title Kuparuk Wells Team Leader ~ Signature 1. ¡II. Phone Date // /'6 ¿> ?- M IV r 1ft'Y' .A" PrRnared bv Sh ron ~ Drake 263·4612 '/ Form 10-404 Revised 04/2004 0;\lG\i'~AL Submit Original Only · 1E-119Well Events Summary . Date Summary 10/05/04 PERFORATED THE INTERVALS: A2 SANDS 6860'-6872'; 6827-6852'; 6788'-6810'; B SANDS 6594'-6614' USING 2.5" HSD GUNS LOADED WITH 2506 POWERJET HMX CHARGES AT 6 SPF. API CHARGE DATA: 25.2" PENETRATION & 0.32" ENTRANCE HOLE. CORRELATED TO SWS CEMENT BOND LOG DATED 4 OCT 04. TAGGED TD AT 6974'. BULLHEAD 30 BBL DIESEL INTO FORMATION TO AVOID LOSS OF FREEZE PROTECT. 10/06/04 PERFORATED INTERVAL B SAND: 6562' - 6594' USING 2.5" HSD GUNS LOADED WITH 2506 POWERJET HMX CHARGES AT 6 SPF. API CHARGE DATA: 25.2" PENETRATION & 0.32" ENTRANCE HOLE. CORRELATED TO SWS CEMENT BOND LOG DATED 4 OCT 04. [Perf] 10/07/04 PERFORATE 6454' - 6524' RKB (D SAND) W/2.5" HSD/6 SPF/60 DEG PHASING/RANDOM OR I ENTATION/2506 POWERJET HMX CHARGES -- PENETRATION=25.2"; HOLE DIA=0.32" -- CORRELATED TO SWS SCMT LOG 4 OCT 04. [Perf] 10/08/04 SET TWO BAKER 2-1/2" RETRIEVABLE IBP WITH DUAL SPARTEK GAUGES ATTACHED: LOWER IBP SET WITH MID ELEMENT AT 6690', TOP AT 6683' ,OAL= 16.49' -- UPPER IBP SET WITH MID ELEMENT AT 6545', TOP AT 6538', OAL= 16.25' -- GAUGES SET TO RECORD PRESSURE AND TEMPERATURE. 10/10/04 BRUSHED & FLUSHED X-NIPPLE @ 6124' RKB; SET DUAL SPARTEK GAUGES (5 MIN SAMPLES) ON X-LOCK @ 6124' RKB. 0 [Pressure Data] . ConocoPhillips Alaska, Inc," . KRU 1 E-119 i,""'i';)) )))ii) ii ·.).)i)ii )++ API: 500292319800 Well TVDe: INJ Anale (â) TS: dea (â) TUBING SSSV Type: NIPPLE Orig 4/13/2004 Angle @ TD: 45 deg @ 7090 (23-6136. Comoletion: 00:3.500. Annular Fluid: Last W/O: Rev Reason: TAG, PERF, set 10:2.992) Pluo & ~au~es Reference Loa: 28' RKB Ref Loa Date: Last UDdate: 10/1212004 Last Taa: 6975 TD: 7090 ftKB Last Tag Date: 10/4/2004 Max Hole 73 deg @ 5488 Anole: )) )t)i ii 'ROOUCTlON Descriotion Size Too Bottom rvD Wt Grade Thread (27-7087. 00:5.500. PRODUCTION 5.500 27 7087 3658 15.50 L-80 BTC-M Wt:15.50) SURFACE 9.625 28 3310 2051 40.00 L·80 BTC CONDUCTOR 16.000 28 108 108 62.50 H-40 WELDED ii ¡¡ Gas Lift I Size I Too I Bottom I TVD I Wt I Grade Thread MandrelNalve I 3.500 I 23 I 6136 I 3040 I 9.30 I L-80 EUE8rd 2 """,;",.".;;" ) (6026-6027. Interval TVD Zone Status Ft SPF Date TVDe Comment 6454 - 6524 3223 - 3269 WSD 70 6 10m2004 IPERF 2.5" HSD 2506 PJ, 60 deg Dhase random orient 6562 - 6594 3294 - 3315 WSB 32 6 10/612004 IPERF 2.5" HSD 2506 PJ, 60 deg NIP ohase. random orient (6078-6079, 00:4.470) 6594 - 6614 3315 - 3329 WSB 20 6 10/5/2004 IPERF 2.5" HSD 2506 PJ, 60 deg ohase. random orient 6827 - 6852 3476 - 3493 WSA2 25 6 10/5/2004 IPERF 2.5" HSD 2506 PJ, 60 deg chase random orient 6860 - 6872 3498 - 3507 WSA2 12 6 10/5/2004 IPERF 2.5" HSD 2506 PJ, 60 deg PBR Dhase random orient (6088-6089, 00:4.790) i' ii j St MD rvD Man Man Type V Mfr V Type VOD Latch Port TRO Date Vlv Mfr Run Cmnt 1 4464 2456 CAMCO KBG-2-9 DMY 1.0 INT 0.000 0 4/13/2004 ANCHOR 2 6026 2986 CAMCO KBG-2-9 SOY 1.0 INT 0.000 0 4/13/2004 (6102-6103, < i¡.""'i +..,;ji/ ,·,"iii .;i...¡ '.¡))ff ii:·",'·.··.· 00:4.500) DeDth rvD Tvae DescriDtion ID PACKER 23 23 HANGER VETCO GRAY TUBING HANGER 4.500 (6103-6104, 507 502 NIP CAMCO 'DS' NO GO LANDING NIPPLE 2.875 00:4.560) 6078 3011 NIP CAMeO 'DS' NO GO NIPPLE 2.812 6088 3016 PBR BAKER 80-40 SLlMLlNE PBR W/14' SEAL ASSEMBLY 3.000 6102 3023 ANCHOR BAKER K-22 ANCHOR 2.980 6103 3024 PACKER BAKER SABL-3 PACKER 2.780 NIP 6124 3034 NIP HES X NIPPLE 2.750 (6124-6125, 6124 3034 PLUG 2.75" X-LOCK w/DUAL SPARTEK GAUGES set 10/10/04 0.000 00:4.500) 6135 3039 WLEG CPAI WIRE LINE GUIDE Dart #546397 2.990 6136 3040 TTL 2.992 6538 3278 PLUG BAKER IBP w/DUAL SPARTEK GAUGES HUNG BELOW wlTOP OF 0.000 WLEG IBP @ 6538', MID-ELEMENT @ 6545', OAL IBP & GAUGES 16.25' set (6135-6136. 00:4.520) 10/8/04 6683 3376 PLUG BAKER IBP w/DUAL SPARTEK GAUGES HUNG BELOW wlTOP OF 0.000 IBP @ 6683', MID-ELEMENT @ 6690', OAL IBP & GAUGES 16.49' set Perf - 1 0/8/04 (6454-6524) - - - - PLUG (6538-6539. 00:4.950) Perf (6562-6594) - - - - PLUG (6683-6684, 00:4.950) Perf :;;;;;;; - (6827-6852) = Perf (6860-6872) - - - - = = - - Se~lum~ePDep Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 A TTN: Beth . Well Job# ~~f J 1E-119 190 _()3cfj1L-09 /5'",5- tJSr 2V-14 / 8~ - I ;l.~12K-02 / q/d~. 3J-17 Ct? - (..,-( v 3A-07 /~5 - :2.23]V 1 E-04 180 -{)57 1E-11 /YJ,. -051 J 2H-12 I~ð - ~{¡:,'2.. 10884033 10802915 10884026 10884027 10884031 10884030 10884023 10884024 10884022 . Log Description Date 1 0106/04 NO. 3231 Company: Alaska Oil & Gas Cons Comm Attn: Robin Deason 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk BL Color CD SCMT PRODUCTION PROFILE W/DEFT PRODUCTION PROFILE W/DEFT PRODUCTION PROFILE W/DEFT PRODUCTION PROFILE INJECTION PROFILE INJECTION PROFILE INJECTION PROFILE PRODUCTION PROFILE 10/04/04 07/26/04 09/27/04 09/28/04 10/02/04 10/01104 09/24/04 09/25/04 09/23/04 1 1 1 1 1 1 1 1 1 c(~ f It iH'H'~ DATE, /ö~ÞI ~NED:fJ ~ J~ Please sign and retur~e copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. e e Randy Thomas Kuparuk Drilling Team Leader Drilling & Wells Conoc~hillips P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-6830 July 26, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ]'h Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for 1 E-119 (APD # 204-031 /304-107) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Well Completion Report for the recent drilling operations of the Kuparuk well 1 E-119. If you have any questions regarding this matter, please contact me at 265-6830 or Steve Shultz at 263-4620. šJ¡~ -r / ¡t¿Jí/ 7k~ ~ R. Thomas Kuparuk Drilling Team Leader CPAI Drilling RT/skad nIGl~IAL e STATE OF ALASKA __ ALASKA Oil AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil 0 Gas U Plugged 0 Abandoned U Suspended U WAG 0 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0 GINJ 0 WINJ 0 WDSPL 0 No. of Completions _ Other - Service 0 Stratigraphic Test 0 2. Operator Name: 5. Date Comp., Susp., 12. Permitto Drill Number: .; ConocoPhillips Alaska, Inc. or Aband.: April 13,2004 204-031/304-107 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 100360, Anchorage, AK 99510-0360 April 1 , 2004 50-029-23198-00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 29' FNL, 228' FEL, Sec. 21, T11 N, R10E, UM April 7, 2004 , 1E-119 , At Top Productive 8. KB Elevation (It): 15. Field/Pool(s): Horizon: 163' FSL, 357' FWL, Sec. 22, T11 N, R10E, UM 28' RKB Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): .!$J.U:I"'" lit l}i~OOI $]). 294' FNL, 410' FWL, Sec. 27, T11 N, R10E, UM 6999' MD I 3596' TVD (.,ùe.$f '1'-1;". C 'I 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 550301 y- 5959561 Zone-4 , 7090' MD I 3660' TVD ADL 25651 & 25660 TPI: x- 550930 y- 5954477 Zone- 4 11. Depth where SSSV set: 17. Land Use Permit: Total Depth: x- 550987 . y- 5954020 r Zone- 4 Landing Nipple @ 506' ALK 469 & 470 18. Directional Survey: Yes 0 NoU 19. Water Depth, if Offshore: 20. Thickness of N/A feet MSL Permafrost: 1927' MD 21. Logs Run: G RIRes/Dens/Neutron 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING SIZE CEMENTING RECORD WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE PULLED 16" 62.5# B 28' 106' 28' 106' 42" 541sxASI 9.625" 40# L-80 28' 3310' 28' 2051' 12.25" 533 sx AS Lite, 155 sx LiteCrete 5.5" 15.5# L-80 28' 7087' 28' 3658' 8.5" 316 sx DeepCrete 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET 3.5" 6136' 6103' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 26. PRODUCTION TEST Date First Injection Method of Operation (Flowing, gas lift, etc.) not available Injector Date of Test Hours Tested Production for OIL-BBL GAS-MCF W A TER-BBL CHOKE SIZE GAS-OIL RATIO Test Period --> Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - API (corr) press. psi 24-Hour Rate -> 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". ) CåMPLÚION , i DAj§ ,0<1 ¡ç;O<"c, \aY-~ NONE I~!L <D~«>' /ft'tl\.~I~~ . . . . I GF Form 10-407 Revised 12/2003 CONT~Eh .1-., n~'I&..Is~ L G '·,,/.\!VII\1 RBDMS Bfl AU6 0 5 10{ ~\ 28. 29. GEOLOGIC MARKERS FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". 1 E-119 West Sak D 6456' 3224' N/A 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Steve Shultz @ 263-4620 Signature Date 712ð/o~ KUDaruk Drillina Team Leader Prepared by Sharon Allsup-Drake 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 a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, salt water disposal, water supply for injection, observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 2/2003 OF(\G\~\\AL Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: 3/30/2004 00:00 - 02:30 2.50 MOVE DMOB MOVE 02:30 - 09:30 7.00 MOVE MOVE MOVE 09:30 - 11 :30 2.00 MOVE RURD MOVE 11 :30 - 15:00 3.50 MOVE POSN RIGUP 15:00 - 19:00 4.00 MOVE RURD RIGUP 19:00 - 21 :30 2.50 MOVE POSN RIGUP 21 :30 - 00:00 2.50 MOVE RURD RIGUP 3/31/2004 00:00 - 07:00 7.00 WELCT NUND RIGUP 07:00 - 09:30 2.50 DRILL RIRD RIGUP 09:30 - 12:00 2.50 DRILL PULD RIGUP 12:00 - 16:00 4.00 DRILL RIRD RIGUP 16:00 - 18:30 2.50 DRILL PULD RIGUP 18:30 - 21 :00 2.50 RIGMNT RSRV RIG UP 21 :00 - 22:00 1.00 WELCT OTHR RIGUP 22:00 - 23:30 1.50 DRILL PULD RIG UP 23:30 - 00:00 0.50 DRILL SFTY RIGUP 4/1/2004 00:00 - 02:15 2.25 DRILL PULD SURFAC 02:15 - 02:45 0.50 DRILL CIRC SURFAC 02:45 - 03:30 0.75 DRILL DRLG SURFAC 03:30 - 04:00 0.50 RIGMNT RGRP SURFAC 04:00 - 04:45 0.75 DRILL DRLG SURFAC 04:45 - 05:15 0.50 DRILL PULD SURFAC 05:15 - 13:30 8.25 DRILL DRLG SURFAC 13:30 - 14:15 0.75 DRILL CIRC SURFAC 14:15 - 15:15 1.00 DRILL TRIP SURFAC 15:15 - 15:45 0.50 DRILL PULD SURFAC 15:45 - 17:00 1.25 DRILL TRIP SURFAC Cont rig move, Peak traveled from 1 E pad to Scout #1 and loaded rig camp Moved rig camp, SPU and rock washer 68 miles from Scout #1 to 1 E pad and spotted camp and rock washer on pad RU camp and SPU Spot sub base over well 1 E-119 and set in pits, pumps, motors and boiler complex's Accepted Rig at 15:00 Hrs 3/30/04 Hooked up service lines to complex's, got air, water and steam going around rig Set in pipe shed and rock washer Leveled and RU pipe skate and shed, bermed around and RU rock washer, took on water into pits, began RD camp and preparing to move ahead on pad, needing to move camp away from 1 E pad microwave tower to allow communications between pads Note: Camp was initially set in place at the recommendation of pad operator and electricians for highline hook-up MU Vetco Gray speed head on 16" conductor, NU 21 1/4" diverter spool, 16" knife valve and NU 21 1/4" 2M diverter, installed 16" x 75' of divertor line Loaded 12 1/4" BHA into pipe shed Bring subs, valves, reamer and 12 1/4" bit to rig floor for 12 1/4" BHA, cleared rig floor of FMC wear bushings, test plugs and running tools Loaded 5" DP & 5" HWDP into pipe shed and strapped, cont to mix and weight up spud mud PU & stood back 27 stds (81 jts) of 5" DP NOTE: Put rig camp on highline power at 16:15 hrs Performed annual calibration on rigs gauges, Quadco calibrated weight indicator, mud pump and iron roughneck's gauges tIIIIiIIId,~~,""'uIøtOr',held dMIfter " aocumulator drill ~~.~.WIIfj·AœcC·vmMId~.pfæst PU & stood back 29 jts of 5" HWDP and jars Held pre-spud meeting with both rig crews and service company personnel at rig camp MU 12 1/4" BHA #1, adjusted mud motor from 1.3 deg to 1.6 deg, oriented and uploaded MWD, tagged cmt insided conductor at 105', btm of conductor set at 106' Flooded conductor and checked mudline for leaks and ck ok Spudded well and drilled 12 1/4" hole from 106' to 150' (44') Repaired idler sprocket on drag chain to rock washer Drilled 12 1/4" hole from 150' to 170' (20') Stood back 1 std of 5" HWDP and PU 3-6 3/4" flex DC's Drilled 12 1/4" hole per directional plan from 170' to 1,074' MD/1 ,007' TVD (904') ART 1.4 Hrs, AST 5.8 Hrs, 15-25K wob, 50 rpm's, 130 spm, 550 gpm, off btm pressure 1,300 psi, on btm 1,600 psi, off btm torque 2K ft-Ibs, on btm 3.6K ft-Ibs, rot wt 78K, up wt 83K, dn wt 79K, 9.3 ppg MW with 300 vis Circ 3X btms up and circ hole clean at 550 gpm, 1,300 psi POOH with no problems Checked bit and ck ok, adjusted mud motor from 1.6 deg to 1.3 deg bend RIH with BHA #2 to 984' and washed 90' to btm with no problems Printed: 6/23/2004 10:36:03 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: 4.00 DRILL DRLG SURFAC Drilled 12 1/4" hole per directional plan from 1,074' to 1,452' MD/1 ,301' TVD (378') ART 1.1 hrs, AST 1.4 hrs, 15-25K wob, 550 gpm, off btm pressure 1,400 psi, on btm 1,700 psi, off btm torque 2K ft-Ibs, on btm 4.5K ft-Ibs, rot wt 87K, up wt 89K, dn wt 82K, 9.5 MW with ave 200 vis, NOTE: Unable to get desired build rate with 1.3 deg bend in motor, decision made to trip and adjust motor back to 1.6 deg. 4/1/2004 17:00 - 21 :00 21 :00 - 21 :30 0.50 DRILL CIRC SURFAC 21 :30 - 22:45 1.25 DRILL TRIP SURFAC 22:45 - 23:15 0.50 DRILL PULD SURFAC 23: 15 - 00:00 0.75 DRILL TRIP SURFAC 4/2/2004 00:00 - 01 :00 1.00 DRILL TRIP SURFAC 01 :00 - 12:00 11.00 DRILL DRLG SURFAC 12:00 - 22:00 10.00 DRILL DRLG SURFAC 22:00 - 23:00 1.00 DRILL CIRC SURFAC 23:00 - 00:00 1.00 DRILL REAM SURFAC 4/3/2004 00:00 - 05:45 5.75 DRILL REAM SURFAC 05:45 - 08:00 08:00 - 09:15 09:15 - 09:30 09:30 - 15:00 2.25 DRILL 1.25 CASE 0.25 CASE 5.50 CASE PULD SURFAC RURD SURFAC SFTY SURFAC RUNC SURFAC 15:00 - 17:00 2.00 CEMEN CIRC SURFAC 17:00 - 17:30 17:30 - 18:30 0.50 CEMEN PULD SURFAC 1.00 CEMEN CIRC SURFAC NOTE: Rig on Highline Power at 19:00 hrs 4/1/04 Circ 2X btms up and circ hole clean at 550 gpm, 1,400 psi POOH with no problems Checked bit and ck ok, adjusted mud motor from 1.3 deg to 1.6 deg bend RIH to 353' with BHA #3 Cont RIH after adjusting MM to 1.6 deg bend from 353' to 1,362', washed 90' to btm with no problems Drill, Slide & Survey 12 1/4" hole per directional plan from 1,452' to 2,473' MD/1 ,773' TVD, (1,021') ART 2.6 hrs, AST 4 hrs, 15-30K wob, 60 rpm's, 140 spm, 600 gpm, off btm pressure 1,800 psi, on btm 2,000 psi, off btm torque 5K ft-Ibs, on btm 6K ft-Ibs, rot wt 86K, up wt 95K, dn wt 80K, 9.6 ppg MW with an ave 175 vis, no hydrates seen DrØl,aüde&~ey from 2,473' 103,317' MOl 2,053' TVO (844'),9518"· 6sgPoint, ART 5.3 hrs, AST 1.5 hrs, 15-25K wob, 60 rpm's, 600 gpm, off btm pressure 1,800 psi, on btm 2,000 psi, off btm torque 7K ft-Ibs, on btm 8K ft-Ibs, rot wt 86 pu wt 11 OK, dn wt 65K, 9.6 ppg MW, ave 160 vis, drittEìdsartd sElCtion fì'om 3,135' to 3,185' ånd had 40 units gas then gas dropped back to -0- units Pumped 30 bbl weighted hi vis sweep (2# over MW) and circ out, had 10% increase in cuttings back from sweep, circ a total of 2X btms up, circ at 600 gpm, 1,850 psi at 60 rpm's Precautionary backreamed out of hole to run 9 5/8" csg from 3,317' to 2,750', backreamed out at 60 rpm's, 600 gpm at 1,800 psi and 30'/min Cont to backream out of hole to run 9 5/8" Csg, backreamed out from 2,750' to 1,173' at 580 gpm, 1,500 psi and 60 rpms, LD ghost reamer, pumped out of hole from 1,173' to 260' at 550 gpm at 1,200 psi, had a large amount of clay back from reaming and pumping out, no other problems POOH LD 12 1/4" BHA #3 and cleared rig floor RU Doyon's csg equipment with Franks fill up tool Held PJSM with tong operator and rig crew on running of 9 5/8" csg _1." 49#, L-80, B~"8;'31~ MU weatherford float shoe, 2 jts 9 5/8" csg and fit collar, thread locked conn's below fit collar, circ thru shoe track and ck ok, cont RIH with 41 jts 9 5/8" csg to 1,635' with no problems, circ btms up staging pump up to 6 bpm at 250 psi, st up wt 97K, dn wt 77K, cont RIH with an add 43 jts of 9 5/8" csg (86 total jts)~;MU Vetco Gray hanger, est circ thru Franks fill up tool and landed csg in hanger, Ran a total of 86 jts of 9 5/8" csg, fit equip. and hanger = 3,279.66' Began circ and conditioning mud for cementing, Circ 100 bbls of 9.6 ppg mud thru Franks fill up tool,r~ocatedcsg, .~taged pump rate up to 6 bpm at 250 psi, st up wt 1451{', dn wt 90K LD Franks fill up tool and MU Dowell cement head Finished circ and conditioned mud for cementing, with 9.6 ppg MW, lowered YP from 30 to 15, lowered PV from 32 to 25 with 56 vis out, Printed: 6/23/2004 10:36:03 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: staged pump rate up to 7 bpm at 400 pSi,7V'__tlg,';UP wt 130K, dn wt 90K, held PJSM on cement job with Dowell, vac truck drivers and rig crew 2.00 CEMEN PUMP SURFAC Turned over to Dowell and pumped 10 bbls of CW1 00 at 8.3 ppg, pressure tested lines to 3,500 psi, pumped add. 40 bbls of CW100 (50 total), pumped 50 bbls of Mudpush at 10.5 ppg, ave 5 bpm at 135 psi, dropped btm plug and followed withîI2ØbbIs,_..ohArctic set lite at 10.7 ppg and 4.43 yield with additives, ave 7 bpm, initial circ press 200 psi, final pressure 300 psi, switched to..:»t,..~ 69, t?þls, 155SX$of LUeCretecmt at 12.0 Wi and"2&yleldwlth additives, ave 7 bpm at 300 psi, shut down and dropped top plug. Note: ~.pIpe white pumpiAg-cmt attempted to move pipe at 20:00 hrs and was unable to move pipe, left landed in hanger Csg landed with float shoe at 3,310' and float collar at 3,227 1.00 CEMEN DISP SURFAC Dowell pumped 20 bbls water and turned over to rig, rig displaced cmt with 9.6 ppg mud, ave 6.5 bpm with a max pressure of 575 psi, slowed pump to 3 bpm with 20 bbls left in displacement, bumped plug on calc displ. pressured up to 1,200 psi and held for 5mi'\ . .... ts arnHloeIIs"t1eId, harttlJltrêtUtl'1S throughoUt job, lM~~· /: fi0.7 ppg cmt, CIP at 21 :15 hr Flushed out diverter and lines, RD cement head and LD landing jt, RD csg equipment and cleared rig floor Began ND Diverter system Fin ND 21 1/4" Diverter, 16" knife valve and diverter line and set out same. Note: 1 Hr time change for daylight savings Prep wellhead, orient and NU 135/8" 5M Vetco Gray MB 222 csg head and test wellhead seals to 5,000 psi for 5 min. Removed 13 5/8" x 11" adapter flange from BOP stack, NU 13 5/8" 5M BOP stack and changed outl~wE!r rarn~fr~m 4" DP to 5" DP Installed test plug, R"W~têtt~, VàNës;"manifold and rams to 250 psi low and5,OOOpsi high, tested Annular to 250 psi and 3,500 psi. ~·t.WG'lfmåìdi WfthAOOCC......... J I I iO(t.oøI ieSt . Pulled test plug, installed Vetco Gray long wear bushing and LD running tool Changed out upper IBOP on top drive, tested IBOP to 250 psi and 5,000 psi, good test PU and stood back 23 stds (69 jts) of 5" DP Began PU & MU 8 1/2" BHA #4 with bit #2, 6314" mud motor with 1.2 deg bend and orient and upload MWD Held PJSM on loading radioactive sources Loaded radioactive sources and fin MU 8 1/2" BHA #4, RIH with HWDP and MU ghost reamer TIH with BHA #4 PU 63 jts of 5" DP from pipe shed, TIH to 3,065' Slip & cut 59' of drilling line, service top drive and adjusted brakes on drawworks TIH from 3,065', est circ and tagged TOC at 3,221', (Fit Collar @ 3,227') Circ 1 complete circ for csg test, 9.6 ppg MW in & out RU & tested 9 5/8" csg to 3,500 psi for 30 min, good test Drilled out float collar at 3,227', shoe track and float shoe at 3,310', drilled 20' of new formation from 3,317' to 3,337', drilled with 5-1 OK wob, 50 rpm's, 425 gpm at 1,450 psi 18:30 - 20:30 20:30 - 21 :30 21 :30 - 23:00 1.50 CEMEN RURD SURFAC 23:00 - 00:00 1.00 WELCT SURFAC 4/4/2004 00:00 - 03:00 3.00 WELCT SURFAC 03:00 - 06:30 3.50 WELCT SURFAC 06:30 - 11 :00 4.50 WELCT EQRP SURFAC 11 :00 - 15:30 4.50 WELCT SURFAC 15:30 - 16:30 1.00 WELCT OTHR SURFAC 16:30 - 20:00 3.50 RIGMNT RGRP SURFAC 20:00 - 22:30 2.50 DRILL PULD SURFAC 22:30 - 00:00 1.50 DRILL PULD SURFAC 4/5/2004 00:00 - 00:15 0.25 DRILL SFTY SURFAC 00:15 - 02:00 1.75 DRILL PULD SURFAC 02:00 - 03:30 1.50 DRILL TRIP SURFAC 03:30 - 04:30 1.00 RIGMNT RSRV SURFAC 04:30 - 05:15 0.75 DRILL TRIP SURFAC 05:15 - 05:30 0.25 DRILL CIRC SURFAC 05:30 - 07:00 1.50 CASE DEQT SURFAC 07:00 - 08:15 1.25 CEMEN DSHO SURFAC Printed: 6/23/2004 10:36:03 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: 4/512004 08:15 - 09:00 0.75 DRILL CIRC SURFAC 09:00 - 09:30 0.50 DRILL LOT SURFAC 09:30 - 10:30 1.00 DRILL CIRC PROD 10:30 - 00:00 13.50 DRILL DRLG PROD 4/612004 13.00 DRILL DRLG PROD 00:00 - 13:00 13:00 - 14:00 14:00 - 00:00 1.00 RIGMNT RGRP PROD 10.00 DRILL DRLG PROD 4/7/2004 00:00 - 14:30 14.50 DRILL DRLG PROD 14:30 - 16:00 1.50 DRILL CIRC PROD 16:00 - 16:15 0.25 DRILL OBSV PROD 16:15 - 19:00 2.75 DRILL TRIP PROD 19:00 - 20:00 1.00 DRILL CIRC PROD 20:00 - 20:15 0.25 DRILL OBSV PROD 20:15 - 00:00 3.75 DRILL TRIP PROD 4/8/2004 00:00 - 02:15 2.25 DRILL PULD PROD 02:15 - 02:30 0.25 LOG SFTY PROD 02:30 - 05:30 3.00 LOG PULD PROD 05:30 - 07:30 2.00 LOG DLOG PROD 07:30 - 07:45 0.25 LOG CIRC PROD 07:45-11:15 3.50 LOG DLOG PROD Circ hole clean for LOT, Circ at 50 rpm's, 510 gpm at 1,600 psi RU & performed LOT to 12.8 pt:)gEMWWltht;6 ppg MW, 2,051' TVD ¡ntii38'psi Displaced out 9.6 ppg spud mud with new 9.1 ppg Flo Pro mud system Drill, slide & survey 8 1/2" hole per directional plan from 3,337' to 4,642' MD/2,506' TVD, (1,305') ART 6.2 hrs, AST 2.6 hrs, 2-10K wob, 100 rpm's, 130 spm, 550 gpm, off btm pressure 1,600 psi, on btm 1,850 psi, off btm torque 9.9K ft-Ibs, on btm 9.5K ft-Ibs, rot wt 95K, up wt 138K, dn wt 68K, 9.2 ppg Flo Pro mud with 62 vis, 1)0--11 "L"~tþi$ ...,., Drill, slide & survey 8 1/2" hole per directional plan from 4,642' to 5,478' MD/2,784' TVD, (836') ART 5.1 hrs, AST 3.6 hrs, 2-10K wob, 100 rpm's, 130 spm, 550 gpm, off btm pressure 1,800 psi, on btm 2,000 psi, off btm torque 10.5K ft-Ibs, on btm 11.7K ft-Ibs, rot wt 98K, up wt 155K, dn wt 70K, ave BGG -0-, 9.2 ppg Flo Pro mud with 63 vis Changed out swivel packing Drill, slide & survey 8 1/2" hole per directional plan from 5,478' to 6,340' MD/ 3,153' TVD, (862') ART 5.0 hrs, AST 1.5 hrs, 2-1 OK wob, 100 rpm's, 130 spm, 550 gpm, off btm pressure 1,850 psi, on btm 2,100 psi, off btm torque 12.6K ft-Ibs, on btm 13.6K ft-Ibs, rot wt 105K, up wt 175K, dn wt 75K, ave BGG -0-, rTlØ'9Þš18unit'$from ap .')fOX6,15O', 9.1 + ppg Flo Pro mud with 58 vis, calc ECD 10.59 ppg Drill, slide & survey 8 1/2" hole per directional plan from 6,340' to 7,090' MD/3,660' TVD, (750') (T.D.) ART 9.2 hrs, AST 1.1 hrs,2-15K wob, 100 rpm's, 130 spm, 550 gpm, off btm pressure 1,900 psi, on btm 2,100 psi, off btm torque 13.5K ft-Ibs, on btm 14.5K ft-Ibs, rot wt 120K, up wt 220K, dn wt 85Kd:¡QG·fr.!mt8lbiWeW8l!lt~þQ aGG-o... max ~ 975~in WMtSak from ap II(8Ke.íìOO',iSurtitIt.fromapprox 6.875' then dfÐPf*i ~..o- unit&, 9.25 ppg Flo Pro mud with 55 vis, calc ECD 10.68 ppg, drilled siderite section from 6,480' to 6,487' ave 3'/hr Top mW.US8k·D at 6,456', West SakA at 6,788' Pumped hi vis sweep and circ hole clean, circ at 560 gpm at 2,200 psi, 100 rpm's, at btms up with sweep had no increase in cuttings, 9.2 ppg Flo Pro mud in & out Monitored Well-Static Precautionary back reamed out of hole at drlg rate from 7,090' to 5,400', backreamed out till top ghost reamer was inside surface csg at 3,310', backreamed out at 100 rpm's, 560 gpm, 2,200 psi and 30'/min with no problems Circ hole clean at 5,400', circ 3x btms up and clean at shakers, circ at 560 gpm, 2,100 psi and 100 rpm's, 9.2 ppg Flo Pro mud in & out Monitored Well-Static POOH wet on elevators to 200', stood back HWDP and jars, LD ghost reamers, moniotored well at shoe and at HWDP and well was static Fin POOH LD 8 1/2" BHA #4, LD NMDC's, held PJSM then removed radioactive sources and downloaded MWD Held PJSM with rig crew and Schlumberger on running DP conveyed logs PU & MU SWS MDTICMR logging tools, tool length 160', latched onto tool and performed operational check and ck ok TIH.wRhtoggingtoolSon 5" DP to 3,200' (above 9 51&" csg shoe) Est CÎrc and circ at 3 bpm at 90 psi, PU wt 87K, dn wt 62K Cont TIH with logging tools to 6,355', broke circ every 5 stds while TIH Printed: 6/23/2004 10:36:03 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: 4/8/2004 0.25 LOG CIRC PROD 1.50 LOG RURD PROD 11:15 -11:30 11 :30 - 13:00 13:00 - 00:00 11.00 LOG DLOG PROD 4/9/2004 00:00 - 08:30 8.50 LOG ELOG PROD 08:30 - 09:30 1.00 LOG DLOG PROD 09:30 - 10:30 1.00 LOG CIRC PROD 10:30 - 14:30 4.00 LOG DLOG PROD 14:30 - 18:00 3.50 LOG PULD PROD 18:00 - 18:45 0.75 DRILL PULD PROD 18:45 - 22:45 4.00 DRILL TRIP PROD 22:45 - 23:00 0.25 DRILL REAM PROD 23:00 - 00:00 1.00 DRILL CIRC PROD 4/10/2004 00:00 - 00:30 0.50 DRILL CIRC PROD 00:30 - 00:45 0.25 DRILL OBSV PROD 00:45 - 04:00 3.25 DRILL TRIP PROD 04:00 - 04:45 0.75 DRILL PULD PROD 04:45 - 05:15 0.50 DRILL OTHR PROD 05:15 - 06:45 1.50 CASE RURD PROD 06:45 - 07:00 0.25 CASE SFTY PROD 07:00 - 15:30 8.50 CASE RUNC PROD 15:30 - 16:00 0.50 CASE OTHR PROD 16:00 - 17:15 1.25 CASE CIRC PROD 17:15 - 17:30 0.25 CEMEN PULD PROD Est circ at 3 bpm at 220 psi to fill pipe and wash latching tool MU side entry sub, RIH with E-line and latched onto logging tools, held PJSM with crew coming on tour on running logs RIH with logging tools on DP to 6,890' logged up with CMR tool from 6,890' to 6,390', Ran<~Bttoo ~__~MDT pressures and sampIe8, 1* 1~s.m"IIUIt""".at~ üme taking 2nd ~é\t6,568. Monitoring weir thru trip tank while logging, hole taking an ave of 1/2 bbl/h r Fin running 2nd set of MDT samples and pressures at 6,568', RIH and ran 3rd set of MDT samples and pressures at 6,791', then took sample CMR measurements at MDT sample points, no problems logging and hole taking an ave 1/2 bbl/hr mud POOH 5 stds to 6,355' to side entry sub, unlatched from logging tools and POOH with E-line Circ to clear DP after logs, circ DP cap. at 3 bpm at 300 psi Monitored well-static, POOH with DP to logging tools, no problems POOH Held PJSM, LD CMRlMDT logging tools and RD Schlumberger, had full recovery from all 3 samples taken MU 8 1/2" cleanout BHA #5, RR#2 8 1/2" bit, NBS, NMDC, stab and xo TIH with BHA #5 to 6,987',while RIH broke circ at, 1875',3,274' (shoe), 4,666',5,594' and 5,523'. Washed and reamed 103' to btm with no problems, staged pump rate up to 595 gpm, 1,150 psi and 110 rpm's Began circ hole clean and conditioned mud for running csg, circ at 595 gpm, 1,100 psi and 110 rpm's, rNtXg&$ atbtmsup 340uni1s then dropped out, at report time have circ 2 1/2 X btms up with 9.2 ppg 51 vis Flo Pro mud in & out rot wt 115K, up wt 195K dn wt 80K, off btm torque 12K ft-Ibs Fin circ hole clean for 5 1/2" csg, circ a total of 4X btms up, circ at 595 gpm, 1,100 psi and 110 rpm's, rot wt 115K, up wt 195K, dn wt 80K Monitored well-static POOH wet 10 stds to 6,140 with no problems, pumped dry job and cont POOH to BHA #5 to 947',monitored well at shoe, well static, no problems POOH Stood back HWDP & Jars and LD remaining BHA Pulled wear bushing and cleared rig floor RU Doyons csg equipment with Franks fill up tool and changed out elevater bales Held PJSM with tong operator and rig crew on running csg ~&;~¡~1~rL"';8TGM~,tGJ',051', MU weatherford float shoe, 2 its 51/2" csg and fit collar, thread locked conn's below fit collar, circ thru shoe track and ck ok, cont RIH with 70 its 5 1/2" csg to 2,976', circ csg cap at shoe at 5 bpm at 375 psi, Cont RIH with an add 94 its of 51/2" csg (166 total its) with no problems MU Vetco Gray hanger andattempt«tto land 089. W$8 unabte'to get hanger thN ataIeK; deCisiotImedetoland csg wRh...-gency slips, LD hanger and PU add it of 5 1/2" csg Est circ thru Franks fill up tool and washed down to 7,087', staged pump rate up to 6 bpm at 510 psi, r~~pipe,upM 125K, dn wt 60K, circ 100 bbls thru fill up tool LD Franks fill up tool and MU Dowell cement head Printed: 6/23/2004 10:36:03 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: 4/10/2004 17:30 - 19:30 2.00 CEMEN CIRC PROD 19:30 - 20:45 1.25 CEMEN PUMP PROD 20:45 - 21 :30 0.75 CEMEN DISP PROD 21 :30 - 00:00 2.50 CASE OTHR PROD 4/11/2004 00:00 - 01 :00 1.00 CASE NUND PROD 01 :00 - 07:30 6.50 DRILL PULD PROD 07:30 - 08:00 0.50 CMPL TN RURD CMPL TN 08:00 - 08:30 0.50 RIGMNT RSRV CMPL TN 08:30 - 19:30 11.00 CMPL TN RUNT CMPL TN 19:30 - 21 :30 2.00 CMPL TN PCKR CMPL TN 21 :30 - 22:30 1.00 CMPL T RUNT CMPL TN CMPL TN CMPL TN 22:30 - 22:45 22:45 - 00:00 4/12/2004 00:00 - 04:30 4.50 CMPL TN TRIP CMPL TN 04:30 - 06:45 2.25 FISH TRIP CMPL TN 06:45 - 10:15 3.50 FISH TRIP CMPL TN 10:15 -11:30 1.25 FISH TRIP CMPL TN Cont to circ hole and condition mud for cmtg, staged pump rate up to 7 bpm at 520 psi, reciprocating csg with122K up wt and 60K dr1 YIlt, lowered MW F/9.3 to 9.2 ppg, Vis F/53 to 47, YP F/25 to 19 and PV F/11 to 12, held PJSM on cmtg with Dowell and rig crew while circ. Turned over to Dowell and pumped 5 bbls of CW1 00 at 8.3 ppg, pressure tested lines to 3,500 psi, pumped add. 25 bbls of CW100 (30 total), pumped 40 bbls of Mudpush at 10.5 ppg, dropped btm plug and followed with,127'bbls, 316 sxsof Deep Crete cmt at 12.5 ppg and 2.26 yield wijtl~\IØê. aveS bpm at 220 psi, had full returns and r~_ while pumping cmt, shut down and washed up lines to rig floor Dropped top plug and rig displaced cement with 8.5 ppg seawater, ave displacement rate at 7 bpm, initial pressure 450 psi, max pressure 825 psi, with 20 bbls left in displacement slowed to 3 bpm at 400 psi, bumped plugs on calc displ. and pressured up to 1,500 psi, held for 5 min, bled off and ck floats and floats held, CIP at 21 :15 Hrs, recipl:ocateØpthroughout displ. and had full retums WriJ19 job, Est TOC at 5,100' ND Vetco Gray MB 222 csg head, PU BOP stack and set 5 1/2" csg slips with 90K st wt, made rough cut on csg and LD cut-off, (cut-off 31.93') made final cut on 5 1/2" csg and installed pack-off NOTE: Landed 5 1/2" Csg with float shoe at 7,087' and float collar at 7,002', Total pipe and float equip in hole 7,060.87' NU wellhead and stack, tested pack-off to 4,000 psi for 10 min, good test LD 29 jts of 5" HWDP, jars and 213 jts of 5" dp from derrick RU to run31*~0I1 Serviced top drive and blocks RIH with 31/2" completion assembly with 193 jts of 31/2",9.3#, L-80, BTCM tbg to 6,138', MU WLEG, Baker SABL3 packer, nipples and GLM's per well program and RIH on 3 1/2" tbg, st wt 72K, dn wt 50K Noté: Sim Op's, ~.lOT on 51/2" x 9 5Ifr ar1mJIUs to 12.0 ppg EMW', then fIosned with 200 bbls fresh water. Camp went off highline at 17:00 hrs Dropped RHC ball and rod on rollers, held PJSM on completion, Began pressuring up to set packer, pressured up to 1,200 psi f/5 min, 2,200 psi f/5 min and 2,500 psi f/5 min, began pressuring up to set pkr and at 2.640pst.p¡p.;umped and packer appeared to ha\'eshetVeå off PU add jt of 3 1/2" tbg and RIH to 6,169' and saw no obstruction, appears pdet'Sheared off and fell down hole, (length of tool assembly from PBR to WLEG, 47.39' with float collar at 7,002') Held PJSM on POOH w/3 1/2" tbg LD 2 jts tbg and POOH with completion assembly to 4,980', standing back 12 stds of 3 1/2" tbg Note: Reoievêd 24 extension on BOP test from John Spautding With AOGCC Fin POOH LD, GLM's and profile nipples, recovered seal assembly and LD same, fish left in hole from PBR to WLEG 47.39', est TOF at 6,955' MU Baker PBRlPacker retrieving tool and RIH to 160' and set down, POOH and checked tool, ground down tong marks on XO sub TIH with retrieving tool to 6,004' with 3 1/2" tbg from derrick Note: Camp went back on highline at 09:00 hrs PU 3 1/2" singles from pipe shed and TIH, tagged TOF at 6,955', Printed: 6/23/2004 10:36:03 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 1 E-119 1 E-119 ROT - DRILLING Doyon Drilling Inc Doyon 141 Start: 3/30/2004 Rig Release: 4/13/2004 Rig Number: Spud Date: 4/1/2004 End: 4/13/2004 Group: latched onto PBRlPkr, pu wt 78K, dn wt 52K PQØH<8Ifow tö P8R/Pf<,., had full rêCOVeI'Y LD PBR and broke out K-22 anchor, then LD packer, cleaned out contaminated mud out of pup jts. X nipple and WLEG, checked tools and ck ok to re-run MU new PBRlPacker assembly with K-22 anchor, re-pinned Pkr to begin setting at 800 psi and PBR to shear at 53,400# Began RIH MU 3 1/2" completion on 31/2",9.3#, L-80 BTCM tbg, installing GLM's and profile nipples per well plan, RIH at 3,300' Continue RIH w/3 1/2" completion on 3 1/2", 9.3#, L-80 BTCM tbg, installing GLM's and profile nipples per well plan, RIH wi WLEG to 6136' RU andMt Baker SASl.-3 packer @ 6103' - 61(}7'. Shear fI P9R w/60k overpul\. Space out. MU two 3 1/2" EUE mod pup joints below joint 191 (last joint in hole). MU Vetco gray 133/8" x 41/2" hanger w/4 1/2" IBT mod pin x 3 1/2" EUE pin crossover and 3 1/2" pup joint. PU/MU landing joint wi 4.909 MCA threads on top of hanger. Land tubing, verify position of hanger. PU hanger to rig floor to circ. 2.00 CMPL TN CIRC CMPL TN Circ @ 3BPM, 120 bbls fresh water down tubing, follow w/ 80 bbls inhibited seawater w/ Concor 303A (MI product), follow wi 45 bbls seawater. 1.00 CMPL TN SOHO CMPL TN Land tubing string. PU wt 72k, SO wt 51 k, blocks 35k. RILDS, torque to 475 ftIlb. Test lower hanger seals to 5000 psi f/10 min. OK. Test upper tubing hanger body seals to 5000 psi f/1 0 min. OK 1 .50 CMPL TN DEQT CMPL TN . RUI Test tubing to.geso psi fl 30 min wi annulus open (chart ~)~OK. Bleed tubing to 2000 psi. Pressure 5 112" X 3 1Jr'8I'InUlæ to 3~ psi. T~þ. 1IIIJtin._edti02675p8i wRb'OOR'lprÐssion (chart test). OK. etèedtûblng, ~ DCt<-3 shear YEllvein·foWef GLM wi 2200 àiffeAmtiat UD landing joint. Set TWC. NID 135/8" BOP stack. NU Vetco Gray 41/16" 5m tree. Test hanger void to 5000 psi f/10 min. OK. Test Vetco gray 4 1/16 5m tree to 250 psi low and 5000 psi high, both 10 min. OK. RU Little Red, Test lines, ~.~ 3-112";)( 5-:1í21' annuIas wi 60 bb/lfdieøel. Rig & U-Tube tubing and annulas, IiItI~RIIIt_S-1í2"x9-5I8" aMulalu,1(f'fnJèzeprotect welJWl1<4() bbIs dleS'eI. Set BPV, Secure well, Record pressures- Tube pressure= 0 psi, 3-1/2 x 5-1/2= 0 psi, 5-1/2 x 9-518= 150 psi. Lay down excess 3-1/2" tubing in derrick. Release rig @ 24:00 hrs 4/13/04. 4/12/2004 10:15 -11:30 1.25 FISH TRIP CMPL TN 11 :30 - 17:00 5.50 FISH TRIP CMPL TN 17:00 - 18:00 1.00 FISH PULD CMPL TN 18:00 - 20:00 2.00 CMPL TN PULD CMPL TN 20:00 - 00:00 4.00 CMPL TN RUNT CMPL TN 4/13/2004 00:00 - 03:00 3.00 CMPL TN RUNT CMPL TN 03:00 - 06:30 3.50 CMPL TN PCKR CMPL TN 06:30 - 10:30 4.00 CMPL TN SOHO CMPL TN 10:30 - 12:30 12:30 - 13:30 13:30 - 15:00 15:00 - 15:30 0.50 WELCT OTHR CMPL TN 15:30 - 16:30 1.00 WELCT NUND CMPL TN 16:30 - 18:30 2.00 WELCT NUND CMPL TN 18:30 - 19:00 0.50 WELCT CMPL TN 19:00 - 20:30 1.50 CMPL TN FRZP CMPL TN 20:30 - 21 :30 1.00 CMPL TN FRZP CMPL TN 21 :30 - 22:30 1.00 CMPL TN OTHR CMPL TN 22:30 - 00:00 1.50 CMPL T PULD CMPL TN Printed: 6/23/2004 10:36:03 AM · Conoc;p.,illips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit, North Slope, Alaska wellp'MWD w/SC&MC<0-3250'>MWD w/SC<3351-7090'> Date Printed: 7-May-2004 ,&¡. BAKER IRJGHES INTEQ 'q'/i}, I cr~~ed 2-A r-2004 :":<{'::';;';^'t, I Last ~eVised 23-A r-2004 ;'i:''';'-; '1 ~ '" ":;¡~l~;'~¡¡~¡'Dj}, »\ I L7~~D~~6~~d :i\:;"";::;t:XKi':''; :):~~Yi:fNG) "l ·t~0, ~ ·I~~;~~~~ as'/ ¡~~k RNe< lJ,' I EaStin~ 87754 6208 INorth~ 48985 8206 I~~~ 1_"- I < .. ,.. ..,CAN OAl1JM 1927 "',m{o>e All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 RKB 94.9ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5583.03 Feet on azimuth 173.32 degrees from Wellhead Calculation method uses Minimum Curvature method ",.."ted by .,k" H",he, 1,,,,,,,,,,,,1ed :). () '1 .. 0") I . Conoc;p.,illips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit,North Slope, Alaska wellP! MWD w/SC&MC<O-3250'>MWD w/SC<3351-7090'> Date Printed: 7-May-2004 ,&¡. BAKER HUGHES INTEQ WellDath (Grid) ReDort MD[ft] Inc[deg] Azi[deg] TVD[ft] Station Station Dogleg Severit) Vertical Easting Northing Position(Y) Po5Ïtion(X) Sectionrftl 000 000 000 000 o OON o om: 000 000 ¡;¡;n':\nn ¡;n 10600 000 000 10600 OOON OooF 000 000 ¡;¡;n':\nn <;n lJ 199.23 2.60 185.93 199.20 2.10S 0.22W 2.79 2.06 550300.30 5959558.60 ?Q? <;Q <;QQ 1 A':\ <;A ?Q? ?A Q07~ 074W ':\64 8Q':\ ¡;¡;n?aa R? ¡;a¡;a¡;¡;1I=:? 38180 10.44 18108 38056 2181 S 11QW 500 21.52 "'C","''''''' At> 473.34 14.72 176.15 469.88 41.71S 0.56W 4.82 41.37 550300.22 5959518.99 564 60 1854 17? Q4 55731 676QS ?ooF 430 6746 652.82 20.52 172.87 640.45 96.95S 5.65E 2.24 96.95 ¡;¡;n':\nA 70 745.54 23.29 177.10 726.47 131.40S 8.59E 3.44 131.50 550309.97 5959429.38 835.94 29.17 177.87 807.53 171.29S 10.32E 6.52 171.33 <;<;0':\11 QI=: Q?<; 4A ':\? QA 17fì4<; AM?O 217.445 12.64E 4':\':\ ?17.44 <;<;03145Q 1015.86 34.40 174.94 959.40 267.43S 16.41 E 1.82 267.52 550318.70 5959293.41 1116.51 36.72 172.82 1041.28 325.61S 22.68E 2.61 ':\?fì 04 ¡;¡;n':\?¡; <¡A 1?07 AA ':\A ':\4 172.06 111':\.74 ':\AO.7Q~ ':\0.01F 1.114 381 70 .16 1302.04 38.85 171.04 1187.33 438.885 38.65E 0.87 440.40 550342.08 5959122.13 1::!Q? 7Q 41 ':\':\ 1 fìQ A<; 1?<;fì 7fì 4C¡¡:; <;1~ 48.36E ? Afì 4QA 7fì ¡;¡;n<¡¡;? 1R "","nnt::. "0 14AQ61 4646 170 71 1::!?6 <;0 <;6?6<;~ <;Q67F <;':\':\ 565 77 1581.29 51.16 171.35 1386.86 630.78S 70.41E 5.15 634.69 550375.12 5958930.47 167? O? <;':\n 170 fìA 144? 47 701 <;A~ A1 fì1 F ? ':\<; 70fì ':\1 {~ '.75 1768.13 55.57 17040 14QA42 77866~ Q445F 245 784.36 ""':I'M'" .,,, 1859.84 58.91 175.08 1548.06 855.13S 104.14E 5.63 861.44 550410.35 5958706.37 1Q5?60 63n 1774':\ 15Q? Q? Q':\fì 1?~ 10Q 40F 516 Q4?4Q 550416.15 2045.10 65.76 176.51 163275 11382E 288 1025.80 <;<;04?1 1':\ .,., 2139.53 71.99 174.67 1666.77 1107.25S 120.62E 6.84 1113.77 550428.52 5958454.39 2231.36 7073 17383 16Q6.12 11Q3A?~ PQ':\4F 162 1200.76 550437.81 2324.43 71.22 173.09 1726.46 1281.23S 139.36E 0.92 1288.75 """'A.IO A... 2417.28 69.65 172.98 1757.55 1368.08S 149.97E 1.69 1376.23 550459.60 5958193.79 2509.87 70.64 172.31 178900 1454 44S 161.1?F 127 1463.31 550471.33 5958107.51 2602.76 71.57 173.55 1819.08 1541.665 171.93E 1.61 1551.19 <;<;04A? 7':\ 2695.98 72.12 173.93 1848.13 1629.71S 181.59E 0.71 1639.77 550492.97 5957932.41 2788.37 70.67 17384 187760 19091E 157 1727.32 "''''''',,'''... 00 ?AA1 1A 71 1 Q 17':\ 1<1 1Qn7 Q,:\ 200.86E o Q1 1A1<;04 """'''i'' Ai 2973.78 70.81 175.71 1938.08 1891.05S 209.37E 2.66 1902.57 550522.50 5957671.28 ':\01=:<; ? A 71 7Q 172.71 1967.42 218.12E ':\ ?Q 1 QAQ ?? ,,¡;n¡;<¡1 R? 1.11. ':\1 <;6<;A fìQ ?4 17417 1 QQ7 A7 ??7 QfìF ':\ 17 ?075?A ¡;¡;n<;.ð.? ?A 3250.82 70.06 174.86 2030.65 2150.71S 236.40E 1.11 2163.61 550551.27 5957411.83 ':\':\<;1 Q4 fìQ Q7 174 Ofì ?Ofì<; ?O ?4<;<;7F 07<; ??<;A fì':\ ¡;¡;n¡;I=:1 n7 h~h{;1' ;1L 3445.03 6837 172Q4 209831 ?<¡<¡1 7AC: ?554?F 205 2':\45.63 <;<;n<;71 <;() 3539.35 65.69 174.05 2135.11 2418.01 S 265.26E 3.04 2432.46 550581.92 5957144.76 3631.00 67.':\4 174.98 2171.64 ?501fì8~ ?73':\OF 2.03 2516.49 550590.51 59570fì1 1<; 3723.99 67.46 174.85 2207.37 258719S 280.90E 0.18 2602.31 <;<;O<;QA.fìQ 3815.35 68.79 175.06 2241.41 2671.655 288.36E 1.47 2687.06 550606.71 5956891.31 3908.81 68.37 173.71 227554 296.87E 1.42 2774.04 """A"" A" 7Q 4001.78 70.20 172.66 2308.43 "'0. "'7~ 307.19E 2.23 ?Afì1 00 ¡;¡;nA?1=: 7n "'... 4094.61 72.13 170.90 2338.40 2931.52S 319.76E 2.75 2948.82 550639.84 5956631.68 4187.52 71.23 171.86 2367.60 :1I1HS. 'L:-> 332.98E 1.38 3036.96 """A¡;<¡A" "0 4?AO 71 70 fìfì 17? Q1 2398.03 344.66E 1 ?':\ ':\1?<; 0':\ ¡;¡;nAA¡; an <¡I=: 4373.98 71.40 174.53 2428.35 3193.70S 354.30E 1.82 3213.23 550676.13 5956369.76 4464.90 72.86 175.78 2456.25 361.61E 2.07 ,:\?QQ 7? ,,¡;ru::RII n? 4<;<;AQ4 714':\ 17<; <;? ?4A<; OA <¡<¡AO .,7<:: ':\fìA ,:\QF 154 ':\':\AQ 1<; ¡;¡;nl=:a1 An .. 4652.95 70.00 175.11 2516.13 3457.60S 375.64E 1.58 3477.83 550699.24 5956106.03 All data is in Feet unless otherwise stated Coordinates are from Slot MO's are from Rig and TVD's are from Rig ( Doyon #141 RKB 94.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5583.03 Feet on azimuth 173.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . ~illip5 ConocoPhm;ps Alas!nc..SloI #119 Pad 1 E, Kuparuk River Unit, North Slope, Alaska wellPI MWD w/SC&MC<0·3250'>MWD w/SC<3351-7090'> Date Printed: 7-May-2004 '&1. BAKER HUGHES INTEQ Northing 5955847.82 5955586.62 550884.63 5954815.74 4983.37S 550915.65 5954581.83 5197.445 550944.31 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 RKB 94.9ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5583.03 Feet on azimuth 173.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~lIips ConocoPhm,ps AI.'lnc..Slo! #119 Pad 1 E, Kuparuk River Unit,North Slope, Alaska well!: MWD w/SC&MC<O-3250'>MWD w/SC<3351-7090'> Date Printed: 7-May-2004 ,&¡. BAKER HUGHES INTEQ 5545.19S Pro·ec!ed Data - NO SURVEY Hole Sections Diameter Start Start Start Start End End End Start Wellbore O.OON Casin s Name Wellbore All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 RKB 94.9ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5583.03 Feet on azimuth 173.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated e ~o<f-o¿,1 . / L 5(qÞ Transmittal Form '&ill BAKER HUGHES INTEQ Anchorage GEOScience Center To: AOGCC 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Attention: Reference: lE-119 Contains the following: 1 LDWG Compact Disc (Includes Graphic Image files) 1 LDWG lister summary 1 blueline - MPR Measured Depth Log 1 blue line - MPR TVD Log 1 blueline - CCN/ORD Measured Depth Log 1 blueline - CCN/ORD TVD Log LAC Job#: 655751 Re<:::::::G;~HZ 1 h{~d'L> . ( Date: May 20, 2004 Date: 1/1 c¡ loci I ¡ í \j" PLEASE ACKNOWLEDGE RECEIPT BY SIGNING & RETURNING OR FAXING YOUR COpy FAX: (907) 267-6623 Baker Hughes INTEQ 7260 Homer Drive Anchorage, Alaska 99518 Direct: (907) 267-6612 FAX: (907) 267-6623 -~ " .' e . STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 Suspend 0 Repair well 0 Pull Tubing 0 1. Type of Request: Abandon 0 Alter casing 0 Change approved program 0 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360, Anchorage, Alaska 99510 7. KB Elevation (ft): 41' RKB 8. Property Designation: ADL 25660, 256511 ALK 469, 470 11. Total Depth MD (ft): nla Casing Structural Conductor Surface Total Depth TVD (ft): Effective Depth MD (It): nla nla Length Size Intermediate Production Liner Perforation Depth MD (ft): Operational shutdown 0 Plug Perforations 0 Perforate New Pool 0 Perforate 0 Stimulate 0 Variance 0 Annular Dispos.D Time Extension 0 Other 0 Re-enter Suspended Well 0 5. Permit to Drill Number: 4. Current Well Class: Development 0 Stratigraphic 0 Exploratory 0 Service 0 204-031 6. API Number: 50-029-23198-00 9. Well Name and Number: 1 E-119 10. Field/Pools(s): Kuparuk River Field / Kuparuk River Oil Pool PRESENT WELL CONDITION SUMMARY Effective Depth TVD (ft): Plugs (measured) Junk (measured): n/a MD rvD Burst Collapse Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Perforation Depth TVD (ft): Packers and SSSV MD (ft): 12. Attachments: Description Summary of Proposal 0 Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for Commencing Operations: 4/5/2004 16. Verbal Approval: Date: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ,30~ . I b Î PluglntegrityD ~oPTest. 0 . M. eChanicall~rityTestD, Loca~ionClearance 0 RECEIVEr ~~~Q..c~<è-~\-\,o~~ru\J~) ~s ;)0 Þ\~Cc)S-( '--l~OCCL)" - . Other: C)",~S\\~~ '\ ,\>«-n""--\\~t~::~::J~\\CJ\-~ 0'V~\'-I APR - 72004 su_u~ DUPlrCATE,-\(),¡ <>.\~~ o~ ,,->~~ta 0",;,, (( .Jt1 ~ï¡J BY ORDER OF Approved ur X / ttA.... __ COMMISSIONER THE COMMISSION '-" '-"" Printed Name R. Thomas ~~~ J Signature \ Form 10-403 Revised 2/2003 13. Well Class after proposed work: Exploratory 0 Development 0 15. Well Status after proposed work: Oil 0 Gas 0 WAG 0 GINJ 0 Service 0 Plugged 0 WINJ 0 Abandoned 0 WDSPL 0 Contact Dan Lowe @ 265-6992 Title Kuparuk Team Leader Phone 265-6830 COMMISSION USE ONLY Date 't (G (z:> t( ~BFr APRq 1004 Date:f/!f!# I I I SUBMIT IN DUPLICATE JI \ .. Subject: lE-119 and lE-104'cker setting depth Winton, Here is our proposal for the production packer setting depth for the West Sale 1 E-119 Injection well (permit:204-031, API: 029-23198-00), and the similar lE-104 injector (yet to be permitted): e The lE-119 will be an injection well with surface pipe set at 3,500' tmd (9-5/8") and a 5-1/2" , 15.5Ib/ft, L-80, BTC-M longstring, with the estimated TOC at 5,000' tmd (the well TD is 7,242'). * The tubing tail is presently designed to be 100' above the top perforation, and that puts the packer +/-32' above the tubing tailor 132' above the top perforation. * We would like to move the packer up the wellbore to be 350' above the top perforation, or 350' above the West Sak D sand 6,563'-350' = 6213' tmd. (This would put the packer across the Ugnu A) * With theoretical cement coverage up to +/-5,000' tmd, we would still have +/-1,213' of cement coverage, above the packer. * Our plan is to run a cement bond log, through 3-1/2" tubing, during post rig work. This will help to ensure that we will see good cement bonding in the 200' of exposed 5-1/2" casing, below the tubing tail. A similar situation will be the lE-104 injector well with 7-5/8" surface pipe set at +/-3,000' tmd and a 5-1/2" long string of casing set at 5,326' tmd. The calculated top of cement has yet to be determined. We would like to set the packer to be 350' above the top perforation in that well also, for the same reasons as above. Let me know if these changes are acceptable, and we will follow this email with a Sundry Notice(s), for formal approval. Thanks, Dan Lowe - 265-6992 Re: FW: IE-I 19 and IE-104 Packer setting depth e . Subject: Re: FW: lE-119 and lE-104 Packer setting depth From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Tue, 30 Mar 200407:40:46 -0900 To: "Shultz, Steven M" <Steven.M.Shultz@conocophillips.com>, Dan Lowe <Dan.E.Lowe@conocophillips.com> Dan and Steve, You might want to check the spelling on Winton's last name. This should not be a problem. Is the additional distance for future perforations?? This is a routine request from Alpine injectors. What we have done there is allow packer setting within 200' tvd of the perfs/top of sand. You do correctly cite where the TOC would be in relation to the packer. I see you will be running 3-112" inside 5-112". Pretty tight. I presume that fishing concerns have been addressed. I look forward to your reply. Tom Maunder, PE AOGCC Shultz, Steven M wrote: -----Original Message----- From: Lowe, Dan E Sent: Tuesday, March 23, 2004 3:17 PM To: 'Winton Abert@admin.state.ak.US' Cc: Allsup-Drake, Sharon K¡ Shultz, Steven M¡ Brockway, Thomas A¡ McKeever, Steve Subject: 1E-119 and 1E-104 Packer setting depth Winton, Here is our proposal for the production packer setting depth for the West Sak 1E-119 Injection well (permit:204-031, API: 029-23198-00), and the similar 1E-104 injector (yet to be permitted) : The 1E-119 will be an injection well with surface pipe set at 3,500' tmd (9-5/8") and a 5-1/2" , 15.5 lb/ft, L-80, BTC-M longstring, with the estimated TOC at 5,000' tmd (the well TD is 7,242'). * The tubing tail is presently designed to be 100' above the top perforation, and that puts the packer +/-32' above the tubing tailor 132' above the top perforation. * We would like to move the packer up the wellbore to be 350' above the top perforation, or 350' above the West Sak D sand 6,563'-350' 6213' tmd. (This would put the packer across the Ugnu A) * With theoretical cement coverage up to +/-5,000' tmd, we would still have +/-1,213' of cement coverage, above the packer. * Our plan is to run a cement bond log, through 3-1/2" tubing, during post rig work. This will help to ensure that we will see good cement bonding in the 200' of exposed 5-1/2" casing, below the tubing tail. A similar situation will be the 1E-104 injector well with 7-5/8" surface pipe set at +/-3,000' tmd and a 5-1/2" longstring of casing set at 5,326' tmd. The calculated top of cement has yet to be determined. We would like to set the packer to be 350' above the top perforation in that well also, for the same reasons as above. Let me know if these changes are acceptable, and we will follow this email with a Sundry Notice(s), for formal approval. 4/7/200412:14 PM bRLG / WELLS . 130bFleckenstein (AOGCC) . ... Steve. Shultz (ConocoPhillip$) Re: Corrections for IE-II9 Surfa.ce Location Page: Comments: It looks like there is a typing error on the original permit request concerning the legal description. Tbe original reads 29~ FNL and 228' FWL, after corrections it should read 29' FNL and 228' FEL. Thanks Steve 263-4620 [:< f: (; f:: J V í: i ': L...:.c \fAR 1 0 200 AJiJ:j-" 11·' ., '" ,~ ,-~ ~¡ -:'V ," ~--'i- ,.. , u",,s l-ons r: ;~,. . 1. .Il ¡'HII¡~lon . nr:f>lìr.'[: MAR-09-2004 14:46 DRLG / WELLS . 907 265 1336 P.02 I'\PPHCBLtUr I nJI r 'O'pun ,"" ¡..uii) ......... ... .._ . sa:;i~~.~~ 13. Proposed On tlingProgra"'......... ..'..0 ...m........ ......... ........ ..~....... 'o.............no 0...............6 Requirements of 20AAC 25.oo5(Ç)(13) .......................... ..............................., ............................,.......6 14.Di$c~s$ion of Mud and Cuttings Disposal and Annular Dlsposal.....no................7 Requirements of 20 AAC 25.005 (c)(14) ............................................................................................. 7 15. Attachments ...;..... " ......... ........ "..-,-...... .....,.. ... .... ........ .,_.. Ii... it.. fa ..... ..e........... ...~........ I............"..... Ii 7 Attachment 1 ()iréctiontllPlan ..,...... ...... ..... ..........., ...... ........ ....... '.' ........................................... ............ ..., Attachment 2 Diøgramsnd Description of theBJowout Preventionfquipment.Nordic 3... ........... .....~ ~ Attachment 3 Drilling Hazards Summary................................ ....'1................." ........................ ....... .... 7 Attachment 4 .Ceme~t ù>adsand CernCADE. Summary. ............ .......,..... ................ ......... ...................1 Attachment 5 Di8f1rantand QfJ$Çriptk}n of the .Diverter Systef'rJ. Nof(j~3 ....:........m..........."..............l Attachrne.nt 6 Diag~ of the. MiJdSystem.Nordìc3 ..............; ......... ............... .......... '... ..................... 7 Attachment 7 Well Schematic..,... .:... .... ................. .......... .................. ........."...... .................. ........ ...... 7 1. Wett Name Requirements of 20 AAC 25.005 (f) ~t Silk 1£-119 The well for which this Application is submitted will be designated as 1 E-119. 2. Location Summary Requirements of 2Q MC 25.00$(c)(¿) An iJPP/kiltion "". il Permit to Drill tnU$t be ðCCOmpi!K1ìed by eðêh of thé following iteft'/$; except l()r an item 8Ireðdyon file with rhe commìssicn and ir;1entifieå In the IJ{JplfcaliOn: (2) a plat ÎdeI1t1fying the property 11M the prol/ftrty's oWners ân<J shoWing (A)the CC1OIÚÌI1ðfS$ of the þr()pCJ$ed /ct:1Jt/on of the will at the surface, Bt the top of each objective formation, ¡ f7(j ill total depl:h, reference(! tv gavemmenf4/ G«tIqn lines. . . (8) the t;lJOf(fll1aœs of the prO{JOSed IcciKiOn of the well at the surtiq releref1Ct!:d to t/N/ stare plane coordii?8Œ system for this SflJte as lTIãintained by the NlJdonðl Geodetic Survey in the NiJtIonalOceaniC and Atmospheric Adminlstratión; (C) the /JIWJO$ed depth of the well at the ttJp of elJch ()/.)jeCtive t'Qrmatlon i1f1(/ at tot(J/ depth; Location at Suñace NGS 0xJrd"tnate$ lVorthlngs: 5,959,561.00 EastingS: 550,301.00 See 21 T11N RIOE UM RKB Elevation kg Elevation 95.0' AMSL 53.8 AMSL Location at Top of Productive InterVal We6t Sak "0" Sand NGS OxJr(/mate5 Northings: 5,954,427 5167.26' FNl, 4918.00' Fa, See 22, TUN, Rl0E, UM 6563 3266 3171 Eastings: 550,936 Measured Total Vertical Total Vertical Location at Total 364' FSl 417' fWl NGS Coorálf1ðtes Northin!iS: 5,953,950.26 Eôstings; 550,994.96 See 27 TllN R10E UM Mæsured ()e, th RK8: Total Vertical D th RKB: Total Vertkal th 55: 7242 3746.42 3651.42 Lø.cation at Top of Productive InterVal est Sak -8" Sand 5232.32' FNl, 4910.58' FEL, See 22, TUN, RlOE, UM DUPLICATE PermIt It 1E·119.doc P$99 20f7 Print&d: S.Feb-04 TOTAL P. 02 ÂI . FRANK H. MURKOWSKI, GOVERNOR A I,ASIiA. OIL Al'O) GAS CONSERVATION COMMISSION Randy Thomas Kuparuk Team Leader ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 w. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kuparuk 1 E-119 ConocoPhillips Alaska, Inc. Permit No: 204-031 Surface Location: 29' FNL, 228' FWL, SEe. 21, TIIN, RI0E, UM Bottomhole Location: 364' FNL, 417' FWL, SEC. 27, TllN, RlOE, UM Dear Mr. Thomas: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field !!tsPecto at 9-3607 (pager). BY ORDER~!IiIHE COMMISSION DATED this~y of February, 2004 cc: Department ofFish & Game, Habitat Section w/o encI. Department of Environmental Conservation w/o encl. ~. . ~ ConocoPhillips Conoco/Phillips, Inc. Post Office Box 100360 Anchorage, Alaska 99510 RECEIVED FEB 0 6 2004 February 5, 2004 Alsrka Oil & Gas Cons. Corrllmssion Anchorage Commissioner Alaska Oil and Gas Conservation Commission 333 West th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 279-1433 Re: Application for Permit to Drill: 1E-119 Surface Location: Target Location: Bottom Hole Location: 29' FNL, 228' FWL, Sec 21 T11 N, R10E, UM 123' FSL, 362' FWL, Sec 22, T11 N, R10E, UM 364' FNL, 417' FWL, Sec27, T11N, R10E, UM Dear Commissioner: Conoco/Phillips Alaska, Inc. hereby applies for a "Permit to Drill" to drill 1 E-119 as a injector well. The well will be drilled and completed using Nabors #3. Please utilize documents on file for this rig. The following logs are to be run on this well: GR/Res. Subject to AOGCC approval, fluids and cuttings generated from drilling the well will be hauled to an approved Prudhoe or GKA Class II disposal well. The following people are the designated contacts for reporting responsibilities to the Commission: A) Completion Report (20 MC 25,070) Sharon Allsup-Drake, Drilling Technologist 263-4612 B) Geologic Data and Logs (20MC 25.071) Mike Werner, Geologist 265-6191 If you have any questions or require further information, please contact Dan Lowe at (907) 265-6992. Sincerely, --».. t .-.-.. -~. :-. -.- '<~ ' l-\5-~ R. Thomas Kuparuk Drilling Team Leader RECEI\/E,D FEB 0 6 2004 Alaska Oil & Gas Anchoragf: ~. . ~I H.,û STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: Drill 0 RedrillU 1b. Current Well Class: ExploratoryU Development Oil U Multiple Zone D Re-entry D Stratigraphic Test D Service 0 Development Gas D Single Zone 0 2. Operator Name: 5. Bond: ~ Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180 1 E-119 3. Address: 6. Proposed Depth: 12. Field/Pool(s): ~ ./ Kuparuk River Field P.O. Box 100360 Anchorage, AK 99510-0360 MD: 7242' TVD: 3651' 4a. Location of Well (GO~~I Section): 7. Property Designation: Surface: 29' FNL, 228' ,Sec. 21, T11N, R10E, UM ,/ APi- ~5660: 25651 'þÞ Kuparuk Oil Pool Top of Productive Horizon: 8. land Use Permit: 13. Approximate Spud Date: 123' FSL, 362' FWL, Sec. 22, T11 N, R10E, UM ,/ ADL 469, 470 3/15/2004 Total Depth: 9. Acres in Property: 14. Distance to 364' FNL, 417' FWL, Sec. 27, T11N, R10E, UM ... 2560 Nearest Property: 123' 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest / J~t:.... v v' Surface: x- 550301 y- 5959561 Zone- 4 RKB 41' Well within Pool: 1E 21ì, 89' @ 27§:,. 16. Deviated wells: ./ 17. Anticipated Pressure (see 20 AAC 25.035) ... I Kickoff depth: 250 ft. Maximum Hole Angle: 70° Max. Downhole Pressure: 1649 psig I Max. Surface Pressure: 1237 psig 18. Casing Program Setting Depth Quantity of Cement Size SDecifications Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 40' 16" 62.5# H-40 Welded 120' 41' 41' 161' 161' 9 cu yds High Early 12.25' 9-5/8' 40# L-80 BTC 3500' 41' 41' 3500' 2047' 640 sx AS Lite, 320 sx Class G 8.5" 5.5" 15.5# L-80 BTC, AB-M 7242' 41' 41' 7242' 3747' ~ sx Class G '\. ;) t;, If{:.iJ"1'fI/1 '....'\0 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (It): Total Depth TVD (It): Plugs (measured) Effective Depth MD (It): Effective Depth TVD (It): Junk (measured) Casing Length Size Cement Volume MD rvD Structu ral Conductor n....... I"' t: 1\ Ie. n Surface ' ,- i"""'-'''' -- Production LL 1\ ~ ?nnL1 Liner .- - - AI...,L.. nil R, ft. CI ..... ~,¡.¡x ~UlIS. ;ommISSIOf\ Perforation Depth MD (ft): Perforation Depth TVD (ft): Anchorage 20. Attachments: Filing Fee 0 BOP Sketch~ Drilling program~ Time v. Depth Plot U Shallow Hazard Analysis D Property Plat D Diverter Sketch 0 Seabed Report D Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Lowe @ 265-6992 Printed Name R. Thomas Title Kuparuk Team Leader Signature < , Phone 2.-<:" )" (:,""8 '<:>0 Date 1....(.Y ( 0 '-1 \ ...<:....~ Á ~.. .. I - ~ n AII~lIn-Drpkp Commission Use Only Permit to Drill . '-/. API Number: Permit Approval ~ See cover letter Number: 26 -c ;3 f 50- ð2-t].2.3 /C¡8~éx") Date: .2/Í;;), éx.f for other requirements Conditions of approval: Samples required .i Yes 1š,fNo Mud log required DYes ª No ~,"Ifide meas"os Y!E· 'No Directional survey required $(Yes D No b'" Othe'~ .", ""'\\ \-"\\~ ~S'\O . ~""\~",\M..J""-I. ß~\? ~<;."~ . '.' U ~S\ M-z/ (// BY ORDER OF Approved biT . / COMMISSIONER THE COMMISSION Date: L./ v. '-- I I ! . . Form 10-401 Revised 3/2003· ORIGINAL SubmIt In duplicate ·. . Application for Permit to Drill, We1l1E-119 J Revision No.O Saved: 5-Feb-04 Permit It - West Sak Well # 1 E-119 Application for Permit to Drill Document Mo):<:imizE Well l/oll,I~ Table of Contents '1. Well Name .....................................................................................................................2 Requirements of 20 AAC 25.005 (f) ..... ..... ....... ......... ..... ......... ..... ....... ............ ........ ....... .... .......... ....... 2 2. Location Su m mary ....................................................................................................... 2 Requirements of 20 AAC 25.005(c)(2) ... ........ ....... ...... ......... ............ ....... .................... ....... .... .... ......... 2 Requirements of 20 AAC 25.050(b) . ...... ....... ........ ..... ....................... ....... ............. ............. ........ ......... 3 3. Blowout Prevention Equipment Information ............................................................3 Requirements of 20 AAC 25.005(c)(3) ....... .............. ........ ........ ...... ....... ....... ..... ........ ...... ........ ...... ...... 3 4. Dri II i ng Hazards Information ...................................................................................... 3 Requirements of 20 AAC 25.005 (c)(4) ...............................................................................................3 5. Procedure for Conducting Formation Integrity Tests.............................................4 Requirements of 20 AAC 25.005 (c)(5) ...............................................................................................4 6. Casing and Cementing Program................................................................................4 Requirements of 20 AA C 25.005(c)(6) . ........ ........ ..... ....... .......... ............. ..... ..... ........ ....... .......... .... ..... 4 7. Diverter System Information ......................................................................................4 Requirements of 20 AAC 25.005(c)(7) ..... ....... ................ ........ .... ........ ......... .... ....... ........ .............. ...... 4 8. Dri II i ng Flu i d Prog ram................................................................................................. 5 Requirements of 20 AAC 25.005(c)(8) .... ....... ........ ....... ....... ................ ..... ...... ...... ........ ..... .......... ....... 5 9. Abnormally Pressured Formation Information ........................................................ 5 Requirements of 20 AAC 25.005 (c)(9) ...............................................................................................5 10. Seismic Analysis ........... ............. ......... ....... ........... .................... ...... .................... ......... 5 Requirements of 20 AAC 25.005 (c)(10) .............................................................................................5 11. Seabed Condition Analysis. ........... ............. ....... ........... ......... ............. ....................... 5 Requirements of 20 AAC 25.005 (c)(11) ............................................................................................. 5 12. Evi dence of Bon ding ................................................................................................... 6 Requirements of 20 AAC 25.005 (c)(12) .............. ..... ........ ........ ............. ............. .............. ..... ............. 6 ORIGINAL Permit It 1E-119.dac Page 1 af7 Printed: 5-Feb-04 · ..APPlication for Permit to Drill, Well 1 E-119 Revision No.O Saved: 5-Feb-04 13. Proposed Dri lIing Program ....................................................... ........ .......................... 6 Requirements of 20 AAC 25.005 (c)(13) .. ................... ............... ......................................................... 6 14. Discussion of Mud and Cuttings Disposal and Annular Disposal........................7 Requirements of 20 AAC 25.005 (c)(14) ................................. .................................................... ........ 7 15. Attach ments.................................................................................................................. 7 Attachment 1 Directional Plan........................................... .......... .................................... ..... .............. 7 Attachment 2 Diagram and Description of the Blowout Prevention Equipment, Nordic 3....................7 Attachment 3 DrH/ing Hazards Summary..................................................................... ....................... 7 Attachment 4 Cement Loads and CemCADE Summary.....................................................................7 Attachment 5 Diagram and Description of the Diverter System, Nordic 3........................................... 7 Attachment 6 Diagram of the Mud System, Nordic 3.......................................................................... 7 Attachment 7 Well Schematic.... ................ ................... .......................... ............................................ 7 1. Well Name Requirements of 20 AAC 25.005 (f) West Sak 1E-119 The well for whieh this Application is submitted will be designated as 1E-119. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed location of the well at the surfac~ at the top of each objective formation, and at total depth, referenced to governmental section lines. (8) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic SUlvey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Location at Surface 28.55' FNL, 227.7' FWL, See 21, TUN, R10E, UM ¡/ NGS Coordinates RKB Elevation Northings: 5,959,561.00'/ Eastings: 550,301.00'/ Pad Elevation 95.0' AMSL 53.8 AMSL Location at Top of 5167.26' FNL, 4918.00' FEL, See 22, TUN, R10E, UM ./ Productive Interval (West Sak "D" Sand) NGS Coordinates Measured Depth/ RKB: 6,563 Northings: 5,954,427 Eastings: 55~936 Total Vertical Depth RKB: 3,266 Total Vertical Depth, 55: 3,171 Location at Total De th 364' FSL, 417' FWL, NGS Coordinates Northings: 5,953,950.26 Eastings: 550,994.96 See 27 TUN RlOE, UM Measured De th RKB: Total Vertical De th RKB: Total Vertical De th 55: 7242 3746.42 3651.42 Location at Top of Productive Interval (West Sak "8" Sand) 5232.32' FNL, 4910.58' FEL, See 22, TUN, RlOE, UM ORIGINAL Permit It 1E-119.doc Page 2 of 7 Printed: 5-Feb-04 · ..APPlication for Permit to Drill, Well 1 E-119 Revision No.O Saved: 5-Feb-04 NGS Coordinates Measured Depth RKB: 6.656.2 Northings: 5,954,362 Eastings: 550,944 Total Vertical Depth, RKB: 3,232 Total Vertical Depth, 55: 3,237 Location at Top of 115.47' FNL, 4892.02' FEL, See 27, TllN, R10E, UM Productive Interval West Sak "A2" Sand NGS Coordinates Northings: 5,954,199 Eastings: 550,964 6 886.7 3,496 3,401 Location at Total De th NGS Coordinates Northings: 5,953,950.26 364.45' FNL, 4863.25' FEL, See 27, TllN RlOE, UM Measured De th RKB: Eastings: 550,994.96 Total Vertical De th RKB: Total Vertical De th 55: 7242 3746.42 3651.42 and (D) other information required by 20 MC 25.050(b}; Requirements of 20 AAC 25.050(b) [fa well is to be intentionallydeviatect the application for a Permit to Drill (Form 10-401) must (l) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed wel¿' Please see Attachment 1: Directional Plan and (2) for all wells within 200 feet of the proposed wellbore (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mai¿' or (O) state that the applicant is the only affected owner. The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (3) a diagram and description ofthe blowout prevention equipment (BOPE) as required by 20 MC 25.035, 20 Me 25.036, or 20 MC 25.037, as applicable; Please see Attachment 2: Diagram and Description of the Blowout Prevention Equipment for Nordic Rig 3. 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient; ,/ The expected reservJir pressures in the West Sak sands in the 1E pad area is 1,371 psi or 0.43 to 0.45 psi/ft, or 8.3 to 8.7 ppg EMW (equivalent mud weight). These are pressures obtained from actual well test data from the nearby wells. The maximum potential surface pressue (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11) and the vertical depth of the expected base of the West Sak formation is 1459 psi, calculated thusly: MPSP =(3747 ft)(0.44 - 0.11 psi/ft) ORIGINAL Permit It 1E-119.doc Page 30f7 Printed: 5-Feb-04 · .PPIiCatiOn for Permit to Drill, Well 1 E-119 Revision No.O Saved: 5-Feb-04 = 1,237 psi / (8) data on potential gas zones; The well bore is not expected to penetrate any gas zones. and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 3: Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required under 20 MC 25.030(f); The well will be completed with a surface casing string that will be drilled out, and a Leak Off Test is planned. Blowout prevention equipment will be installed prior to drilling out, and a Leak Off test will be performed in accordance with the LOT / FIT procedure that Phillips Alaska has on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (6) a complete proposed casing and cementing program as required by 20 MC 25.030, and a description of any slotted liner, pre- perforated liner, or screen to be installed; Casing and Cementing Program Hole Top Btm Csgfrbg Size Weight Length MDfrVD MDfrVD OD (in) (in) (Ib/ft) Grade Connection (ft) (ft) (ft) Cement Program 16 40 62.5 H-40 Welded 120 41/41 161 / 161 Cemented to surface with 9 cy High Early 9-5/8 12-1/4 40 L-80 BTC 3500 0/0 3500/2047 Cemented to surface w/ AS Lite \ "G" tail 5-1/2 8-1/2 15.5 L-80 BTC,AB 7242 0/0 7242/ 3747 Cemented Modified with 720 sx 3-1/2 9.3 L-80 EUE 8rd, 7242 0/0 7242/ 3747 Class "G" tbg AB Modified *Note: An MDT is planned for this well where samples will be taken for analysis. In the event that the open hole MDT malfunctions/" a contingency string of seven inch casing will be run in place of the 5 1/2 .. inch string giving us the opportunity to perform cased hole MDT's at a later date. 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 MC 25. 035, unless this requirement is waived by the commission under 20 MC 25.035(h)(2); Please see Attachment 5: Diagram And Description of the Diverter System For Nordic 3. ORIGINAL Permit It 1E-119.doc Page 4 of 7 Printed: 5-Feb-04 · ... pplicalion for Permit to Drill, Well 1 E-119 , Revision No.O Saved: 5-Feb-04 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (8) a drlïling fluid program, including a diagram and description of the drilling fluid system, as required by 20 MC 25.033; Drilling will be done with a bentonite slurry having the following properites over the listed intervals: Saud to Base of Permafrost Base of Permafros to Total Death Initial Value Final Value Initial Value Final Value Density (ppg) 8.5 9.4 - 9.6* 9.4 9.4 Funnel Viscosity 150-200 150-200 150 75 (seconds) Yield Point 30-60 30-60 25-45 25-45 (cP) Plastic Viscostiy 8-15 11- 22 11-22 11-22 (lbI1 00 sf) 10 second Gel 15-30 10-25 15-30 15-30 Strength (lb1100 sf) 10 minute Gel 25-55 25-55 25-55 25-55 Strength (lb1100 sf) pH 8-9 8-9 API Filtrate(cc) 8-15 6 5-6 5-6 Solids (%) 5-8 5-8 5-8 6-11 *9.8 ppg if hydrates are encountered Please see Attachment 6: Diagram of Mud System, Nordic 3. This drilling fluid system of Nordic 3 consists of: (3) ContincnKlI Emsco FB 1600 ~1ud PI:Jmps, Steel ~1ud pits witt:! 1100 b;:mcl CJpùcity, Pill Pit, Trip TJnk, (3) Dcrrick Flo linc ShJlc ShJI~rs (rated at 600 gpm), BFJndt ~10del SRS 2 DCSJndcr, Derrick ~10dcl S8S ~1ud Clcaner, (2) AlphJ LJ';;:JI ~10dcl118 \[f S Centrifugcs, DegJssers, PVT System 'Nith visuùl Jnd ùudio alùrms, Trip TùAk, Flo'J¡,' Sensor, Jnd Fluid AgiKltors. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 MC 25.033. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (9) for an exploratory or stratigraphic test we/~ a tabulation setting out the depths of predicted abnormally goo-pressured strata as required by 20 MC 25.033(f); Not applicable: Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test we/~ a seismic refraction or reflection analysis as required by 20 MC 25.061(a); Not applicable: Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (11) for a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vesse~ an analysis of seabed conditions as required by 20 MC 25.061(b); Not applicable: Application is not for an offshore well. ORIGINAL Permit It 1E-119.doc Page 5 of 7 Printed: 5-Feb-04 · .APPlication for Permit to Drill, Well 1 E-119 Revision No.O Saved: 5-Feb-04 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (12) evidence showing that the requirements of 20 AAC 25.025 {Bonding}have been met; Evidence of bonding for Phillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: The proposed drilling program is listed below. Please refer as well to Attachment 7, Well Schematic. 1. Excavate cellar, install cellar box, set and cement 16" conductor. Weld landing ring on conductor. 2. MIRU Nordic 3. Install diverter and function test same. '~"'-\d '/'-\" le.~ >ÚO ./ 3. Spud and directionally drillß~·~hole to 3,500' tmd. Run MWD/LWD/ PWD logging tools in drill string as required for directional monitoring and formation data gathering. 4. Circulate and condition hole to run casing. POOH. 5. Run and cement 9-5/8" 40 Ib/ft, L-80 BTC casing string to surface. Displace cement with mud and perform top job if required. 6. Nipple down diverter and install wellhead. Nipple up BOP stack and pressure test to 5,000 psi. 7. RIH, drill out float equipment, drill 20' of new hole, displace to new mud and perform LOT. 8. Drill ahead to TO, CBU and POOH. 9. RU and run MDT pressure/fluid sampler. Run wireline logs, POOH and rig down. 10. Run and cement 5-1/2" 15.5# L-80 BTCM casing string to surface. RU and cement casing. Displace cement with mud. Note: As a contingency, a string Of 7" casing will be run in place of the 5 V2" casing if the MDT run earlier proved to be unsuccessful. 11. PU and RIH with 3-1/2" X 5 V2" permanent packer on 3 V2" tubing and position same 100' above the West Sak sand 12. Using diesel, freeze protect the well, drop ball and set packer, pressure test tubing and annulus each to 3,000 psi for 30 minutes per AOGCC regulations. Record results. Install back pressure valve. 13. Nipple down BOP stack. Install production tree and pressure test same. 14. Secure well and release Nordic Rig 3. v 15. Rig up E-line unit and RIH with CBL / CIT. Run cement bond log across West Sak interval. Report results to office for remedial action if necessary. 16. Rig up E-line unit and RIH with through-tubing perforating guns. ORIGINAL Permit It 1E-119.doc Page 60f7 Printed: 5-Feb-04 · .,APPlicatiOn for Permit to Drill, Well 1 E-119 Revision No.O Saved: 5-Feb-04 17. Perforate well overbalanced. POOH with perforating guns. Repeat runs as required to perforate all desired West Sak intervals. Rig down E-line unit. 18. Install back pressure valve, shut in and secure well. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application for a Permit to Drill mustc be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 MC 25.080 for an annular disposal operation in the wel/.; Waste fluids generated during the drilling process will be disposed of either by pumping authorized fluids into a permitted annulus or by hauling the fluids to a KRU Class II disposal well. All cuttings generated will be either stored temporarily on site or hauled to the Prudhoe Bay Field for temporary storage and eventual processing for injection down an approved disposal well. Phillips Alaska does not intend to request authorization for the use of this well for annular disposal operations. 15. Attachments Attachment 1 Directional Plan ¡/ Attachment 2 Diagram and Description of the Blowout Prevention Equipment, Nordic 3 Attachment 3 Drilling Hazards Summary Attachment 4 Cement Loads and CemCADE Summary. ,.. Attachment 5 Diagram and Description of the Diverter System, Nordic 3 Attachment 6 Diagram of the Mud System, Nordic 3 Attachment 7 Well Schematic. ORIGINAL Permitlt 1E-119.doc Page 70f7 Printed: 5-Feb-04 Rig: Nordic 3 Location: West Sak Client: ConocoPhillips Alaska, Inc. Revision Date: 1/30/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265~205 Mobile: (907) 229-6266 email: martin13@slb.com r < Toe at Surface It ~¡¡¡~ t :::':>.. m Previous Csg. < 16",62.6# casing at 80' MD < Base of Permafrost at 2,500' MD (1,699' TVD) ... i I .:.: ¡:¡: ¡¡¡¡, ¡m:. r~ li/ii: III~: il:: < Top of Tail at 2,700' MD < 95/8",40.0# casing in 121/4" OH TD at 3,500' MD (2,047' TVD) Mark of Schlumberger Schluer Preliminary Job Design based on limited input data. For estimate purposes only. Volume Calculations and Cement Systems Volumes are based on 250% excess in the permafrost and 35% excess below the permafrost. The top of the tail slurry is designed to be at 2,700' MD. Lead Slurrv Minimum pump time: 220 min. (pump time plus 90 min.) ARCTICSET Lite @ 10.7 ppg -4.43 ft3/sk 3 0.7632 ft 1ft x (80') x 1.00 (no excess) = 0.3132 ft31ft x (2500' - 80') x 3.50 (250% excess) = 0.3132 ft3/ft x (2700' - 2500) x 1.35 (35% excess) = 61.1 ft3 + 2652.8 ft3+ 84.6 ft = 2798.5 ft3/ 4.43 ft3/sk = Round up to 640 sks 61.1 ft3 2652.8 ft3 84.6 ft3 2798.5 ft3 631.7 sks Have 250 sks of additional Lead on location for Top Out stage, if necessary. Tail Slurrv Minimum pump time: 150 min. (pump time plus 90 min.) 15.8 ppg Class G + 0.5%S1, 0.2%046, 0.3%065, 0.4%0167 - 1.17 ft3/sk 0.3132 ft3/ft x (3500' - 2700') x 1.35 (35% excess) = 0.4257 ft3/ft x 80' (Shoe Joint) = 338.3 ft3 + 34.1 ft3 = 372.4 ft3/1.17 ft3/sk = Round up to 320 sks 338.3 ft3 34.1 ft3 372.4 ft3 318.3 sks BHST = 39°F, Estimated BHCT = 60T (BHST calculated using a gradient of 2.6°F/1 00 f1. below the permafrost) PUMP SCHEDULE Stage Pump Rate (bpm) Stage Volume (bbl) Cumulative Stage Time Time (min) (min) CW100 5 50 10.0 10.0 Drop Bottom Plug 5.0 15.0 MudPUSH II 5 50 10.0 25.0 Lead Slurry 7 503 71.9 96.9 Tail Slurry 6 67 11.2 108.1 Drop Top Plug 5.0 113.1 Displacement 7 244 34.9 148.0 Slow Rate 3 15 5.0 153.0 MUD REMOVAL Recommended Mud Properties: 9.8 ppg, Pv < 15, T y < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 10.5 ppg MudPUSH* II, Pv? 17-21, Ty ? 20-25 Centralizers: Recommend 1 per joint on bottom 700' of hole ORIGINAL Rig: Nordic 3 Location: West Sak Client: ConocoPhillips Alaska, Inc. Revision Date: 1/30/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-<3205 Mobile: (907) 229-6266 email: martin13@slb.com :0:0:;: t? .:.:-:- ~ ::;:-~ m < Previous Csg. < 9 5/8", 40.0# casing at 3,500' MD :::::' '::::: :.:.: ¡lit- ::::::: ::::::: ::::::: :~:., ¡1¡I!ii 111111. :.:.:.: ~¡¡¡¡¡¡. ¡¡1¡¡¡: ¡¡¡¡¡¡: i[!1i: ::~¡: < Top of Tail at 5,000' MD < 7", 26.0# casing in 81/2" OH TD at 7,242' MD (3,746' TVD) Schl:ulPger Preliminary Job Design based on limited input data. For estimate purposes only. Volume Calculations and Cement Svstems Volumes are based on 60% excess. Tail slurry is designed for 1200' TVD above TO - (2242' MD annular length). Tail Slurrv Minimum thickening time: 160 min. (Pump time plus 90 min.) 15.8 ppg Class G + 0.2%046, 0.3%065, 0.35% 0167, retarder as required - 1.16 ft3/sk 0.1268 ft 31ft x 2242' x 1.60 (60% excess) := 0.2148 ft31ft X 80' (Shoe Joint) := 454.9 ft3 + 17.2 ft3:= 472.1 ft31 1.16 ft3/sk:= Round up to 410 sks 454.9 ft3 17.2ft3 472.1 ft3 407.0 sks BHST := 83°F, Estimated BHCT := 72T (BHST calculated using a gradient of 2.6°F/1 00 ft. below the permafrost) PUMP SCHEDULE Stage Pump Rate (bpm) Stage Volume Cumulative Stage Time Time (min) (bbl) (min) CW100 5 30 6.0 6.0 Drop Bottom Plug 5.0 11.0 MudPUSH II 5 30 6.0 17.0 Tail Slurry 5 85 17.0 34.0 Drop Top Plug 5.0 39.0 Displacement 7 254 36.3 75.3 Slow Rate 3 20 6.7 82.0 MUD REMOVAL Recommended Mud Properties: 10.5 ppg, Pv < 15, T y < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 12.0 ppg MudPUSH* II, Pv? 19-22, Ty? 22-29 Centralizers: Recommend 1 per joint across zones of interest for proper cement placement. '-.0,' \-\ ~'~~ì ORIGINAL Rig: Nordic 3 Location: West Sak Client: ConocoPhillips Alaska, Inc. Revision Date: 1/30/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com Previous Csg. < 9 5/8", 40.0# casing at 3,500' MD ~~~: i:illi !I~;; I 1111i 1\1\li :::::: ::¡:~:: < Top of Tail at 5,000' MD < 51/2",15.5# casing in 8 1/2" OH TO at 7,242' MD (3,746' TVD) Schlumberger 1~IIII,al~I~I¡I~~ršîIBi~0~~~? .......... ...". ..............." ""............ Preliminary Job Design based on limited input data. For estimate purposes only. Volume Calculations and Cement Svstems Volumes are based on 60% excess. Tail slurry is designed for 1200' TVD above TO - (2242' MD annular length). Tail Slurrv Minimum thickening time: 150 min. (Pump time plus 90 min.) 15.8 ppg Class G + 0.2%046,0.3%065,0.35% 0167, retarder as required - 1.16 ft3/sk 3 0.2291 ft 1ft x 2242' x 1.60 (60% excess) = 0.1336 ft31ft x 80' (Shoe Joint) = 821.8 ft3 + 10.7 ft3 = 832.5 ft3/1.16 ft3/sk = Round up to 720 sks 821.8 ft3 10.7 ft3 832.5 ft3 717.7sks BHST = 83°F, Estimated BHCT = 72°F. (BHST calculated using a gradient of 2.6° F/1 00 ft. below the permafrost) PUMP SCHEDULE Cumulative Stage Time Time (min) (min) Stage Pump Rate (bpm) Stage Volume (bbl) CW100 5 30 6.0 6.0 Drop Bottom Plug 5.0 11.0 MudPUSH II 5 30 6.0 17.0 T ail Slurry 5 149 29.8 46.8 Drop Top Plug 5.0 51.8 Displacement 7 150 21.4 73.2 Slow Rate 3 20 6.7 79.9 MUD REMOVAL Recommended Mud Properties: 10.5 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 12.0 ppg MudPUSH* II, Pv? 19-22, Ty ? 22-29 Centralízers: Recommend 1 per joint across zones of interest for proper cement placement. ORIGINAL Tie-In 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 1 70 45.00 3292.24 550939.22 0.00 71 45.00 3362.95 550947.90 0.00 72 45.00 3433.66 550956.58 0.00 73 45.00 3504.37 550965.26 0.00 74 45.00 3575.08 550973.94 0.00 75 45.00 3599.00 550976.87 0.00 76 45.00 3645.79 550982.61 0.00 77 45.00 3716.50 550991.29 0.00 78 45.00 3746.41 550994.96 0.00 . ConocJ'Phillips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit, North Slope, Alaska . r&ií. BAKER HUGHES INTEQ PROPOSAL LISTING Page 1 Well bore: 1E-119 Wellpath: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORfGrN,ð\L . ConocJPhillips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit,North Slope, Alaska . PROPOSAL LISTING Page 2 Well bore: 1E-119 Well path: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 J&ií. BAKER HUGHES INTEQ 0.00 0.00 0.00 0.00 O.OON O.OOE 0.00 0.00 1nn nn 0.00 0.00 100.00 O.OON O.OOE 0.00 nnn ?nn nn n nn n nn ?nn nn nnnN nnm:: n nn nnn 250.00 0.00 173.33 250.00 O.OON O.OOE 0.00 0.00 350.00 3.00 173.33 349.95 260S 030E 3.00 2.62 4<;n on ñ nn 17'1 '1'1 .:149.63 10.39S 1.22E 'I nn 1n.4ñ 550.00 9.00 173.33 548.77 23.36S 2.73E 3.00 23.51 650.00 14.00 173.33 646.73 4315S 504E 5.00 43.44 7<;0.00 19.00 173.33 742.58 71.35S 8.34E 5.00 71.84 850.00 24.00 173.33 835.59 107.74S 12.59E 5.00 108.48 950.00 29.00 173.33 925.06 152.05S 1777E 5.00 153.08 10<;000 '14.00 173.33 1010.30 203.93S 23.84E 5.00 ?n<; '11 1150.00 39.00 173.33 1090.66 262.99S 30.74E 5.00 264.78 1250.00 44.00 173.33 1165.53 "I.?R 7R~ 3843E 5.00 331.02 1'1<;0.00 4q nn 17'1 '1'1 1234.34 400.80S 46.85E <; nn 40<1.<;'1 1450.00 54.00 173.33 1296.57 478.51S 55.94E 5.00 481.77 1550.00 59.00 173.33 1351.75 I;ñ1 "I.1~ 65.61 E 5.00 565.13 1 ñ<;n nn ñ.:1 nn 17'1 '1'1 1 'IqQ .:1<; ñ..:1R <;7~ 75.81E <; nn ñ<;? qq 1750.00 69.00 173.33 1439.31 739.63S 86.46E 5.00 744.66 17ñ'l.:17 69.67 173.33 1444.07 752.14S 87.92E 5.00 757.26 1800 00 ñq ñ7 17'1 '1'1 U<;ñ 7<; 786.17~ q1 qn¡= n 00 7q1 <;? 1900.00 69.67 173.33 1491.49 879.318 102.79E 0.00 885.29 ?OOO 00 ñq ñ7 17'1 '1'1 1<;?ñ ?'I Q7? .:1<;~ 113.67E n nn q7q 07 210000 ñqñ7 17'1 '1'1 1 <;ñO qñ 1?.:1 <;6F 000 107?R4 2200.00 69.67 173.33 1595.70 1158.72S 135.45E 0.00 1166.61 ?<IOOOO 6q.67 17'1.'1'1 1ñ3044 1251.868 146.34E n.oo 1260.'18 240000 69.67 173.33 166<; 18 1 <\.:1<;.OOS 1 <;7.22E 0.00 13!14.16 2500.00 69.67 173.33 1699.91 1438.148 168.11E 0.00 1447.93 2600.00 6967 173.3'1 17'1.:1 ñ<; 1531.288 17q nnF 0.00 1541.70 2700.00 6967 173.33 1769.3q 16?4.4?S 1 8q R8F 0.00 163548 2800.00 69.67 173.33 1804.12 1717.55S 200.77E 0.00 1729.25 ?qOOOO 6q 67 17'1 '1'1 18'18 8ñ ?11 ññF 000 1 8?<1 O? 3000.00 6967 17333 187'1 60 ??? <;<;F 000 19167q 3100.00 69.67 173.33 1908.34 1996.97S 233.43E 0.00 2010.57 3?00.00 6q 67 17'1 '1'1 1q.:1'1 n7 ?.:1.:1 'I?F 000 ?10.:1 '1.:1 3300.00 6967 17333 1q7781 ?<;<; ?1 F 000 219811 3400.00 69.67 173.33 2012.55 2276.39S 266.10E 0.00 2291.89 350000 6967 17'13'1 ?0.:17 ?8 ?76 98F 000 ?38566 3600.00 69.67 173.33 208202 ?8787E 000 2479.43 3700.00 69.67 173.33 2116.76 2555.80S 298.76E 0.00 2573.20 3800.00 69.67 1733'1 21<;1.49 2648.94S 'I09.6<;E 000 ?66n.98 3900.00 69.67 173.33 2186.?<I ?742 08S 3?0 53F 0.00 276075 4000.00 69.67 173.33 2220.97 2835.22S 331.42E 0.00 2854.52 4100.00 6967 173.33 22<;<; 7n 2928.368 342.31E 0.00 2948.'10 4200.00 69.67 173.33 ??90 4.:1 3021.49S 'I<;'I.19F 0.00 3042.07 4300.00 69.67 173.33 2325.18 3114.63S 364.08E 0.00 3135.84 4400no 69.67 17'1.'1'1 ?'I<;q.92 3207.778 374.97E o.nn '1229.61 450000 6967 17'1 '1'1 ?<I9.:1 6<; 'I8<;.86F 000 'I'I?<I'I9 4600.00 69.67 173.33 2429.39 3394.05S 396.75E 0.00 3417.16 .:170000 6967 17'1 '1'1 ?.:1ñ..:1.13 407.63E n nn 'I<;1n q'l 480000 6967 17'1 '1'1 ?.:198 86 .:118 <;?F 000 '160.:170 4900.00 69.67 173.33 2533.60 3673.47S 429.41 E 0.00 3698.48 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.0ft above mean sea level) Vertical 8ection is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORfGIf\LAL . ConocJ:)hillips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit,North Slope, Alaska . r&iá. BAKER HUGHES L.~TEQ PROPOSAL LISTING Page 3 Well bore: 1 E-119 Well path: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 "' MÐlftìI J ",iliiL 5000.00 69.67 173.33 2568.34 3766.60S 440.29E 0.00 3792.25 510000 f\Q 1'17 173.33 2603.07 <\R5Q 74e::: 451.18E 0.00 <\RRf\ O? 5?00.00 f\Q 1'17 17<\ <¡'I 2637.81 <\Q5? RRe::: 462.07E 000 <¡Q7Q RO 5300.00 69.67 173.33 2672.55 4046.02S 472.96E 0.00 4073.57 5400.00 69.67 173.33 270728 413916S 483.R4E 0.00 4167.34 5500 00 f\Q 1'17 173.33 2742.02 4?<\?<\0e::: 494.73E 0.00 4?f\1 11 5600.00 69.67 173.33 2776.76 4325.448 505.62E 0.00 4354.89 5700.00 69.67 173.33 281150 LlLI1R I;7e::: 51651E 0.00 4448.66 5740.44 69.67 173.33 2825.55 4456.248 520.91 E 0.00 4486.59 5840.44 66.67 173.33 2862.72 4548.448 531.69E 3.00 4579.41 5940.44 63.67 173.33 2904.70 4638.57S 542.22E 3.00 4670.16 f\M044 60.67 173.33 2951.38 4726.40S 552.49E 3.00 4758.58 6140.44 57.67 173.33 3002.62 4811.68S 562.46E 3.00 4844.44 6240.44 54.67 173.33 3058.28 4894.18S 572.10E 300 4927.51 1'1'140.44 51.67 173.33 3118.21 4973.68S 581.39E 3.00 5007.54 6440.44 48.67 173.33 3182.25 5049.95S 590.31E 3.00 5084.33 6540.44 45.67 173.33 325022 51??79S 59R82E 3.00 5157.67 f\5f\? RQ 4500 17'1 <¡'I 3266.00 5138.65S 600.68E 3.00 517'1 1'1'1 6600.00 45.00 173.33 3292.24 5164.708 603.72E 0.00 5199.87 1'1700 00 45.00 173.33 3362.95 I;?<\LlMe::: 611.93E 0.00 5270.58 f\ROO 00 4500 17'1 <¡'I '14'1'1 1'11'1 <:<In<' 17C 620.14E 000 5'141 ?Q 6900.00 45.00 173.33 3504.37 5375.40S 628.35E 0.00 5412.00 7000 00 4500 173.33 3575.08 5L1L11; Me::: 636.56E 0.00 5482.71 7o::!3R<¡ 4500 17'1 <¡'I <¡5QQOO <:AAO <lOC f\<¡Q 'l4F 000 5501'16'1 7100.00 45.00 173.33 3645.79 5515.878 644.77E 0.00 5553.42 7200.00 4500 17'1 <¡'I 3716.50 5586.10S 652.98E 0.00 5624.14 724230 45.00 17'1'1'1 '1746.41 5615.R1<::: 65f\.4f\E 000 51'154 05 All data is in Feet unless otherwise stated Coordinates are from 810t MD's are from Rig and TVD's are from Rig ( Datum #1 95.Oft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORIGINAL . ~illips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit, North Slope, Alaska . PROPOSAL LISTING Page 4 Well bore: 1 E-119 Well path: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 J&iá. BAKER HUGHES INTEQ All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORIGINAL . ConocJPhillips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit, North Slope, Alaska . PROPOSAL LISTING Page 1 Wellbore: 1E-119 Wellpath: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 Jl:il8 BAKER HUGHES INTEQ All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORIGINAL . ConocÓÁ1i11ips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit,North Slope, Alaska . r&ií. BAKER HUGHES INTEQ PROPOSAL LISTING Page 2 Well bore: 1 E-119 Well path: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 000 000 000 0.00 ~~. nn e;e;Oq01 00 "'70 1R 1 O~Q W14Q::Ie; ':1':1 (U)O 10000 000 000 10000 nn "'70 1R 1 O::l4Q W14Q ::15 ':1"'1 qQRQ o.nn 200.00 0.00 0.00 200.00 5959561.00 550301.00 N70 18 1.0349 W149 35 33.3989 0.00 ?e;ooo 000 17::1 ::Iq 250.00 nn <::<::n':ln1 nn "'70 1R 1 O::l4Q W14Q ::15 ':1':1 ':IQRQ 000 ::15000 q 00 17q ::1::1 ~QQ5 .40 <::<::n':ln1 ':I? "'70 18 100Q::I W14Q ::15 ':1"'1 qQOO ? R? 450.00 6.00 173.33 449.63 5959550.62 550302.28 N70 18 0.9326 W149 35 33.3635 10.46 e;e;o 00 QOO 173.33 548.77 ·t:.7 rrn.,n" on "'70 18 080e;? W14Q ::15::1::1 ::I1Q::I n51 Re;o.OO 14.00 17::1.::Iq 646.73 e;Qe;Qe; 17 8Q N70 18 0.R10e; W14Q ::15 33.2518 4::1.44 750.00 19.00 173.33 742.58 5959489.71 550309.82 N70 18 0.3331 W149 35 33.1557 71.84 Re;o.oo· ?400 173.33 835.59 595Q4e;q qR e;e;o"'l14 q1 N70 17 59.9752 W149 35 3::1 0317 108.48 Qe;o 00 2Q.00 17q.qq 925.06 595940Q.OQ e;e;m1Q.7Q "'70 17 5Q}i::lQ5 W14Q ::15 "'I? RRnR 1<;3.08 1050.00 34.00 173.33 1010.30 5959357.26 550326.20 N70 17 59.0293 W149 35 32.7040 205.31 11e;0 00 ::IQ.OO 173.33 1090.66 5959298.2e; e;e;oqq::l.e;o "'70 17 58.4484 W149 35 ':I? <;n?~ ?fì4 78 12e;0 00 44.00 17::1.::1::1 1165.53 e;Qe;Q?32.e;2 e;e;O::l41.R::I "'70 17 e;7.801::l W14Q ::15 ':I? ?7R<; "'1"'11.02 1350.00 49.00 173.33 1234.34 5959160.56 550350.53 N70 17 57.0930 W149 35 32.0331 403.53 14e;0 00 <:;4 00 173.33 1296.57 0.., <::<::n'>t:.n 1'> "'70 17 e;R ::I?R7 W149 35::11 7R8::1 481 77 1 e;e;o 00 e;Q 00 17q qq 1::1e;1 7e; ?n "'70 17 e;e; e;144 W14Q ::15 ':11 ;l.RR? <;R<; 1"'1 1650.00 64.00 173.33 1399.45 5958913.02 550381.15 N70 17 54.6562 W149 35 31.1889 652.99 17e;0 00 RQOO 17::1 ::Iq 1439.31 ~~--~~ .~ "'70 17 e;::I 7R07 W14Q ::Ie; ':In R7RR 744Rfì 17R::I 47 RQR7 17::1 ::1::1 144407 <::A "'70 17 5::1fì::l7R W14Q ::15 "'In RqRO 7e;7 ?R 1800.00 69.67 173.33 1456.75 5958775.54 550398.15 N70 17 53.3029 W149 35 30.7200 791.52 1 QOO 00 RQR7 17::1 ::1::1 14Q1 4Q .~ "'70 17 e;? ::I8RQ W14Q ::I5.,n An..,- RR<; ?Q ?OOO 00 fìQR7 17::1 ::1::1 1e;?Rn .., e;e;04?117 "'70 17 51470Q W149 35 "'In OR<:;4 Q7Q 07 2100.00 69.67 173.33 1560.96 5958496.38 550432.68 N70 17 50.5549 W149 35 29.7681 1072.84 2200.00 RQ.R7 17::1.::1::1 1e;Qe; 70 .,., e;e;n444 19 N70 17 4Q R::I8Q W14Q ::15 2Q.4<;n7 11RR R1 2::100.00 6Q67 173.33 163044 . 7 N70 17 48722Q W149 35 29.1::1::14 1?RO ::IR 2400.00 69.67 173.33 1665.18 5958217.22 550467.21 N70 17 47.8069 W149 35 28.8161 1354.16 ?500 00 fiC!.fi7 17::1::1::1 1fìQQ.Q1 59581741 fi e;e;n4787? N70 17 4fì8QOQ W14Q 35 28.49R9 1447.Q~ 2Rnn nn 69.67 17333 1734.65 5~1.11 550490.23 N70 17 45.9748 W149 35 28.1816 1541.70 2700.00 69.67 173.33 1769.39 5957938.05 550501.73 N70 17 45.0588 W149 35 27.8643 1635.48 ?800 00 fiQfi7 17::1 ::1::1 1804 1? <::<::n<::.., "}A N70 17 4414?8 W14Q 35 ?7<:;470 17?Q ?<; ?Qnn- nn fiQfì7 17333 18::18Rfi <::~.OA <;<;n<;?;I. 7<; N70 17 43.2268 W149 35 18?q O? 3000.00 69.67 173.33 1873.60 5957658.89 550536.26 N70 17 42.3108 W149 35 26.9125 1916.79 ':I1nn.nn fìQR7 17333 1Q0834 ~~[ ~4( N70 17 413Q48 W149 35 n~ rnr., ?010 e;7 q?OO no RQR7 173.33 1 Q43.07 <::<::"'<::<::0 ..,,, N70 17 40.4787 W149 35 ?1n4 ~ 3300.00 69.67 173.33 1977.81 5957379.73 550570.79 N70 17 39.5627 W149 35 25.9609 2198.11 "'I;l.nn nn fiQfì7 17333 ?01?55 7 <;<;n<;<>? "'In N70 17 38fì4fì7 W149 35 ??Q1 RQ qe;OO 00 RQR7 173.33 2047.28 <::<::,.,<::0'> "1 N70 17 37.7307 W149 35 ?::I8e; RR 3600.00 69.67 173.33 2082.02 5957100.56 550605.32 N70 17 36.8147 W149 35 25.0092 2479.43 3700.00 6C!.fì7 173.33 211fì.76 5Q57007.51 e;e;Ofi 1 fì. 83 N70 17 358987 W149 35 24 R9?0 2e;p.2° qROO no 69.67 173.33 2151.49 5Q56914.4<; 550fì28.34 N70 17 34.9827 W149 35 24.::I74Q 266R.Q8 3900.00 69.67 173.33 2186.23 5956821.40 550639.85 N70 17 34.0666 W149 35 24.0577 2760.75 4000.00 fìQ.fì7 17::1 ::1::1 2220Q7 5956728 35 e;e;Ofie;1.::Ifi N70 17 3::1 150fì W14Q 35 23.740<; 2R<:;4.<;? 4100.00 69.67 173.33 ??55 70 5Q5fìfì35.2Q 550fìfi2.87 N70 17 322346 W149 35 n., .,>.,., ?Q48.30 4200.00 69.67 173.33 2290.44 5956542.24 550674.38 N70 17 31.3186 W149 35 23.1062 3042.07 4::100.00 6Q.fi7 17::1.::1::1 2325.18 595644Q.18 e;e;068e;.RQ N70 17 30.4026 W14Q 35 ??78Q1 3135.84 ;I.;I.nn nn fìQR7 17::1::1::1 ne;QQ? 1':1 e;e;OfiQ740 N70 17 2Q48fìfì W14Q 35 nn .....n q??Q R1 4500.00 69.67 173.33 2394.65 5956263.07 550708.90 N70 17 28.5705 W149 35 22.1548 3323.39 4fiOO 00 fiQfi7 17::1 ::1::1 ?4?Q ::IQ e;Qe;R170 O? e;e;07?0 41 N70 17?7 fie;4e; W14Q 35?1 R"'I77 ~171-¡; ;l.7nn nn fìQfì7 17333 ?4fi4 13 <::"<::"n..." "" <;<;n7':11 Q? N70 17 2fi 7385 W149 35 21 e;?oe; qe;10 Qq 4800.00 69.67 173.33 2498.86 5955983.91 550743.43 N70 17 25.8225 W149 35 21.2034 3604.70 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORIGINAL e ~illips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit, North Slope, Alaska . r&ii. BAKER HUGHES INTEQ PROPOSAL LISTING Page 3 Well bore: 1E-119 Well path: 1E-119 VerS#1.D Date Printed: 3-Feb-2004 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORIGINAL e ConocÓPhillips ConocoPhillips Alaska, Inc.,Slot #119 Pad 1 E, Kuparuk River Unit,North Slope, Alaska . J&iï8 BAKER HUGHES INTEQ PROPOSAL LISTING Page 4 Wellbore: 1E-119 Well path: 1E-119 Vers#1.D Date Printed: 3-Feb-2004 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 95.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 173.33 degrees Bottom hole distance is 5654.05 Feet on azimuth 173.33 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ORIGINAL e . Baker Hughes Incorporated Anticollision Report NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD Interval: 25.0 ft Depth Range: 0.0 to 7242.3 ft Maximum Radius: 5280.0 ft Reference: Error Model: Scan Method: Error Surface: Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse Survey Program for Definitive Wellpath Date: 12/31/2003 Validated: No Planned From To Survey ft ft 0.0 7242.3 Planned: 1 E-E1 Vers#1.D V5 Version: 0 Toolcode Tool Name MWD+SAG MWD + Sag correction Summary Pad 1 E 10 1E-10 VO 300.0 325.0 1219.6 3.5 1216.1 Pass: Major Risk Pad 1 E 102 102 B-Lateral VO Plan: 269.7 275.0 520.2 3.3 516.9 Pass: Major Risk Pad 1 E 103 103 VO Plan: 1E-B1 VER 270.0 275.0 480.2 3.3 476.9 Pass: Major Risk Pad 1 E 104 104 VO Plan: 1E-C1 VER 270.2 275.0 460.2 3.3 456.9 Pass: Major Risk Pad 1E 105 105 A2-Lateral VO Plan 270.5 275.0 420.2 3.3 416.9 Pass: Major Risk Pad 1 E 105 105 D-Lateral VO Plan: 270.5 275.0 420.2 3.3 416.9 Pass: Major Risk Pad 1 E 11 1E-11 VO 266.3 275.0 1116.5 3.0 1113.5 Pass: Major Risk Pad 1E 112 112 A2-Lateral VO Plan 272.4 275.0 220.2 3.3 216.9 Pass: Major Risk Pad 1 E 112 112 B-Lateral VO Plan: 272.4 275.0 220.2 3.3 216.9 Pass: Major Risk Pad 1E 112 112 D-Lateral VO Plan: 272.4 275.0 220.2 3.3 216.9 Pass: Major Risk Pad 1 E 114 114 A2-Lateral VO Plan 273.5 275.0 120.2 3.3 116.8 Pass: Major Risk Pad 1 E 114 114 D-Lateral VO Plan: 273.5 275.0 120.2 3.3 116.8 Pass: Major Risk Pad 1 E 115 115 VO Plan: 1 E-D1 VER 273.8 275.0 100.2 3.3 96.8 Pass: Major Risk Pad 1 E 1 1 E-01 VO 294.2 300.0 457.5 3.4 454.1 Pass: Major Risk Pad 1 E 1 1 E-01A VO 294.2 300.0 457.5 3.4 454.1 Pass: Major Risk Pad 1 E 121 121 B-Lateral VO Plan: 282.3 300.0 1080.8 3.5 1077.2 Pass: Major Risk Pad 1 E 12 1E-12 VO 284.0 300.0 1017.4 3.3 1014.2 Pass: Major Risk Pad 1 E 123 123 B-Lateral V4 Plan: 282.8 300.0 1043.9 3.5 1040.3 Pass: Major Risk Pad 1 E 123 123 D-Lateral VO Plan: 282.8 300.0 1043.9 3.5 1040.3 Pass: Major Risk Pad 1 E 126 126 A2-Lateral VO Plan 283.7 300.0 970.9 3.6 967.3 Pass: Major Risk Pad 1 E 126 126 B-Lateral VO Plan: 283.7 300.0 970.9 3.6 967.3 Pass: Major Risk Pad 1 E 126 126 D-Lateral VO Plan: 283.7 300.0 970.9 3.6 967.3 Pass: Major Risk Pad 1 E 13 1E-13 VO 285.5 300.0 922.4 3.3 919.1 Pass: Major Risk Pad 1 E 14 1E-14 VO 287.2 300.0 832.9 3.3 829.6 Pass: Major Risk Pad 1 E 15 1E-15 VO 289.0 300.0 754.0 3.3 750.7 Pass: Major Risk Pad 1 E 16 1E-16 VO 311.5 325.0 684.6 3.7 680.9 Pass: Major Risk Pad 1 E 166 166 A2-Lateral VO Plan 1319.1 1475.0 254.7 32.2 222.5 Pass: Major Risk Pad 1 E 166 166 B-Lateral VO Plan: 1319.1 1475.0 254.7 32.2 222.5 Pass: Major Risk Pad 1 E 166 166 D-Lateral VO Plan: 1319.1 1475.0 254.7 32.2 222.5 Pass: Major Risk Pad 1 E 168 168 A2-Lateral V3 Plan 1570.9 1675.0 84.9 50.5 34.4 Pass: Major Risk Pad 1 E 168 168 D-Lateral VO Plan: 1570.9 1675.0 84.9 50.5 34.4 Pass: Major Risk Pad 1 E 169 1 E-L3 A2 Lateral VO PI 1499.6 1475.0 104.6 41.6 63.0 Pass: Major Risk Pad 1 E 169 1 E-L3 D Lateral VO Pia 1499.6 1475.0 104.6 41.6 63.0 Pass: Major Risk Pad 1 E 170 170 A2-Lateral VO Plan 2724.0 2525.0 432.7 143.4 289.3 Pass: Major Risk Pad 1 E 17 1E-17 VO 314.8 325.0 634.4 3.7 630.7 Pass: Major Risk Pad 1 E 18 1 E-18 VO 269.4 275.0 560.5 3.0 557.4 Pass: Major Risk Pad 1 E 19 1 E-19 VO 269.8 275.0 500.5 3.0 497.4 Pass: Major Risk Pad 1 E 20 1 E-20 VO 290.7 300.0 439.6 3.4 436.2 Pass: Major Risk Pad 1E 21 1 E-21 VO 291.8 300.0 380.2 3.4 376.8 Pass: Major Risk Pad 1 E 2 1 E-02 VO 291.9 300.0 521.0 3.4 517.6 Pass: Major Risk Pad 1E 22 1 E-22 VO 292.9 300.0 318.5 3.4 315.1 Pass: Major Risk Pad 1 E 23 1 E-23 VO 272.0 275.0 260.1 3.1 257.0 Pass: Major Risk Pad 1 E 24 1 E-24 VO 291.3 300.0 397.6 3.4 394.2 Pass: Major Risk Pad 1E 24 1 E-24A VO 291.3 300.0 397.6 3.4 394.2 Pass: Major Risk Pad 1 E 25 1 E-25 VO 273.3 275.0 139.9 3.1 136.8 Pass: Major Risk Pad 1 E 26 1 E-26 VO 274.0 275.0 80.0 3.1 76.9 Pass: Major Risk Pad 1 E 26 1 E-26A VO 274.0 275.0 80.0 3.1 76.9 Pass: Major Risk Pad 1 E 27 1 E-27 VO 1115.8 1075.0 447.9 26.1 421.8 Pass: Major Risk Pad 1 E 28 1 E-28 VO 907.3 900.0 427.5 18.3 409.2 Pass: Major Risk Pad 1 E 29 1 E-29 VO 569.9 575.0 420.5 8.6 411.8 Pass: Major Risk Pad 1 E 30 1 E-30 VO 343.6 350.0 420.1 4.2 416.0 Pass: Major Risk ORIGINAL -- . Baker Hughes Incorp~ated Anticollision Report Pad 1E 31 1 E-31 V1 287.4 300.0 824.0 3.5 820.5 Pass: Major Risk Pad 1E 31 1E-31PB1 VO 287.4 300.0 824.0 3.5 820.5 Pass: Major Risk Pad 1 E 3 1 E-03 V1 289.8 300.0 602.6 3.4 599.3 Pass: Major Risk Pad 1 E 32 1 E-32 VO 532.9 575.0 628.1 8.4 619.8 Pass: Major Risk Pad 1 E 33 1 E-33 VO 273.1 275.0 154.6 3.2 151.3 Pass: Major Risk Pad 1 E 33 1E-33PB1 VO 273.1 275.0 154.6 3.2 151.3 Pass: Major Risk Pad 1 E 34 1 E-34 VO 268.3 275.0 778.2 3.1 775.0 Pass: Major Risk Pad 1 E 35 1 E-35 VO 1354.5 1475.0 334.4 36.8 297.6 Pass: Major Risk Pad 1 E 35 35A VO Plan: 35A ST Ve 1354.5 1475.0 334.4 36.8 297.6 Pass: Major Risk Pad 1 E 36 1 E-36 VO 250.0 250.0 1208.0 2.7 1205.2 Pass: Major Risk Pad 1 E 4 1 E-04 VO 269.0 275.0 695.3 3.0 692.3 Pass: Major Risk Pad 1 E 5 1 E-05 VO 268.1 275.0 791.4 3.0 788.4 Pass: Major Risk Pad 1 E 6 1 E-06 VO 250.0 250.0 900.5 2.7 897.8 Pass: Major Risk Pad 1 E 7 1E-07 VO 283.2 300.0 1007.2 3.3 1003.9 Pass: Major Risk Pad 1E 8 1 E-08 V1 300.0 325.0 1115.3 3.5 1111.8 Pass: Major Risk Pad 1 E 9 1 E-09 VO 265.1 275.0 1326.4 3.0 1323.4 Pass: Major Risk Pad 1 E WSR#2 WS2 V1 2710.3 1800.0 1548.3 115.8 1432.5 Pass: Major Risk ORIGINAL .,¡: íÑiiEQ-··~ Scale 1 em = 200 ft ConocoPhillips Alaska, Inc. Location: North Slope, Alaska Field: Kuparuk River Unit Installation: Pad 1 E -2400 -2000 -1600 -1200 -800 -400 SURFACE LOCATION: 29' FNL, 227' FEL ,/ SEC.21,T11N,R10E TARGET LOCATION: 113' FSL, 362' FWL SEC. 22, T11N,R10E TD LOCATION: 364'FNL,367'FVVL SEC. 27, T11N,R10E Slot: Slot #119 Well: 119 Wellbore: 1 E-119 East (feet) -> o 400 800 1200 1600 2000 2400 2800 3200 3600 KOP Bid 5/100 EOC Base Permafrost Top T-3 Top K-15 j l 9 5/8in Casing Top Ugnu C Drop 3/100 Top Ugnu B Top Ugnu A K13 C Top W.Sak D Tgt-EOD v ~~ l ~i Base W.Sak TO, Csg PI. / ORIGINAL ConocÓPhillips Created by : Planner Date plotted: 3-Feb-2004 Plot reference is 1E-119. Ref well path is 1E-119Vers#1.D. Coordinates are in feet reference Slot #119. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft. Plot North is aligned to TRUE North. 400 0 -400 -800 -1200 e- -1600 -2000 -2400 ^ I -2800 Z 0 ~ -3200 .=: ø' CD - -3600 - -4000 -4400 -4800 -5200 -5600 en () -6000 ~ () 3 -6400 II N 0 0 -6800 ;::I! fBiitR ~ ¡Ñ:¡;ïiijm r. ~ _mm_~ ConoeoPl1illips Alaska, Ine.. --Tocãtiõii:m North-Slope, Alaska· ~_·SJot: Slot #119 m Field: Kuparuk River Unit Well: 119 Installation: Pad 1E Wellbore: 1E-119 -- - ---- ----- Plot RefwelJpath Is iE-119 VerS#i.D. Coordinates are In feet reference Slot #1 i 9. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft. Plot North is aligned to TRUE North. Scale 1 em = 20 ft -280 -240 -200 -160 -120 2100 TVD -80 -40 120 160 200 240 280 2500 TVD 300 TVD ' , o TVD ..~~. 3200 TVD TVD' m \ 3300 TVD TVD 2000 TVD 3400 TVD 500 TVD 600 TVD 3500 TVD 2600 TVD 2200TVD 3600 TVD 800 TVD 3700 TVD 3900 TVD 1000 TVD 1100 TVD 1400 2500 TVD 2600 TVD TVD 1500 1900 TVD 1600 300TVD 2900 2700 TVD ·ii&1II ~ iN;¡f'ij" Scale 1 em ::: 40 ft -400 -320 -240 -160 ConocoPhillips Alaska, Inc.. Alaska Field: Kuparuk River Unit Installation: Pad 1E Well: 119 Wellbore: 1E-119 -80 East lfE~et) -> 160 ~40 320 3900 TVD 3900 TVD 4100 TVD 17 4100 TVD 2700 TVD 4300 TVD 4300 TVD 4500 TVD TVD 4700 TVD 4700 4900 TVD o 80 2100 3300 TVD 2300 400 480 3500 TVD 2500 5100 TVD ¡----¡ ....,.,¡ !~I ¡IT'- ! , I \V '1Þ:/ ConocoPhiUips Refwellpath is 1E-119 Ven¡#1,D, Coordinates are in feet reference Slot #119, True Verticai Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft, Plot North is aligned to TRUE North. 560 720 880 800 640 3100 TVD -720 4900 -800 ~ -880 -960 -1040 -1120 -1200 3300 TVD -1280 -1360 ^ . Z 0 -1440 ~ 3500 TVD ::T - ø' -1520 ~ - -1600 -1680 -1760 3700 TVD -1920 -2000 (f) () !:\) ¡:j) -2080 -' () :3 II -2160 .þ.. o ;:: > '-1&111 -Ell' - ï;;¡'iiV·· Alaska., Inc.. Co Field: Kuparuk River Unit Pad 1 E Well: 119 Well bore: 1E-119 Scale 1 em ::: 80 ft -960 -800 -640 -480 East (feet\ -> 160 320 480 640 800 -320 -160 o 3900 TVD 2100 TVD 3500 TVD 2300 TVD 3700 TVD 2500 TVD 3900 2700 TVD ~7: ~ 7, / ---'.~'" 4300 5500 TVD ~CreaTe¡fbY:·Pj¡¡¡:¡¡íer-~ Date plotted: 3-Feb-2004 Plot reference is 1E-1i9. Refwellpath Is 1E-119 Vers#1.D. Coordinates are In feet reference Slot #119. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft. Plot North Is aligned to TRUE North. 960 1120 1280 1440 4100 TVD 4900 4300 TVD 4500 TVD TVD ~ End of Hold - 2825.55 Tvd, 5700 TVD grjD -2080 -2560 -3520 -3840 -4000 ConocoPhillips Alaska, Inc.. Canoe mips ,..c...".""""«.".,,....., Field: Kupðruk River Unit Well: 119 INTM] Installation: Pad 1E Wellbore: 1E-119 Date Plot reference is Refwellpath is 1E-119 Vers#1.D. Coordinates are in feet reference Slot #119. True Vertical Depths are reference Rig Datum. Measured Depth<> are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft. Scale 1 cm = 150 ft East tfeÐt) -:> Plot North is aligned to TRUE North. ../ -1500 -1200 -900 -600 -300 0 300 600 00 1200 1500 1800 2100 2400 2700 3000 3300 4000 TVD .5500 T 5500 TVD . 6000 TVD TVD6000 TVD " 1 r~~!:. Al 6500 35.00 TVD 500~ 4500 TVD 4500 TVD 5~!'t~D Æl 5000 TVD 5000 TVD 5500 TVD ~ 5500 TVD T.D. & of Hold - 3578.00 Tvd, 6657.80 S 6000 TVD ~ 5000 TVD 5500 TVD 5000 TVD 6000 TVD 6500 TVD 5500 TVD 6000 TVD TVD :~00055MeTVD 6000 TVD 4500 TVD -1800 -2100 -2400 -2700 -3000 -3300 -3600 -3900 -4200 {\ Z o -4500 ª - ;' -4800 ~ - -5100 -5400 -5700 -6000 -6300 -6600 en (") ro (iJ -6900 ;:: 3 II ...... -7200 U1 o ;:;: :! ConocoPhillips Alaska, Inc. .. ..... iÑT£Q~~"""~"~ Location: North Slope, Alaska Field: Kuparuk River Unit Installation: Pad 1 E Slot: Slot #119 Well: 119 Wellbore: 1E-119 ConoccrPhillips // 1700 ~~ ~'~O @'RUE ::l1~ 340 \, 350 500091'0 20 Created by : Planner Date plotted: 3-Feb-2004 Plot reference is 1E-119. Refwellpath is 1E-119 Vers#1.D. Coordinates are in feet reference Slot #119. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft. Plot North is aligned to TRUE North. § 300 330 30 @ 320 40 310 50 60 290 70 280 80 270 90 260 100 250 110 240 120 230 130 220 140 210 150 200 160 190 180 170 Normal Plane Travelling Cylinder - Feet All depths shown are Measured depths on Reference Well O~ ¢:: 0 -300 Ll) ~ II E 0 -0 ( ) ~ C/) 300 600 900 - - 1200 Q) .æ - 1800 ~ 2100 2400 V 2700 3000 3300 3600 3900 4200 I KOP 6.00 Bid 5/100 19.00 29.00 ConocoPhillips Alaska, Inc. Conoc;Phillips Location: North Slope, Alaska Field: Kuparuk River Unit Installation: Pad 1 E Slot: Slot #119 Well: 119 Wellbore: 1E-119 DLS: 5.00 deg/100ft Created by : Planner Date plotted : 3-Feb-2004 Plot reference is 1 E-119. Refwellpath is 1E-119 VerS#1.D. Coordinates are in feet reference Slot #119. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 95.00 ft. Plot North is aligned to TRUE North. WELL PROFILE DATA Point MD Inc Azi TVD North East deg/100ft V. Sect Tie on 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 End of Turn 250.00 0.00 173.33 250.00 0.00 0.00 0.00 0.00 KOP 550.00 9.00 173.33 548.77 -23.35 2.73 3.00 23.51 End of Build 1763.47 69.67 173.33 1444.06 -752.14 87.92 5.00 757.26 End of Hold 5740.44 69.67 173.33 2825.55 -4456.24 520.91 0.00 4486.59 Target WS 1 E E1 D TOP 6562.89 45.00 173.33 3266.00 -5138.65 600.68 3.00 5173.63 End of Hold 7033.83 45.00 173.33 3599.00 -5469.39 639.34 0.00 5506.63 T.D. & End of Hold 7242.30 45.00 173.33 3746.41 -5615.81 656.46 0.00 5654.05 . 49.00 54.00 59.00 64.00 EOC 69.00 Base Permafrost -300 0 300 Scale 1 em = 150 ft 600 Top T-3 ~op K-15 9 5/8in Casing ~ . Top Ugnu C Drop 3/100 66.67 Top Ugnu B DLS: 3.00 deg/100ft 63.67 To U nu A 54.67 P g 51.67 K13 Top W.Sak D Tgt_EOD45.67 CB A~3 A2 A1 Base W.Sak "-. ~ TD, Csg pt. t> i__ 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 Vertical Section (feet) -> Azimuth 173.33 with reference 0.00 N, 0.00 E from Slot #119 . . SHARON K. ALLSUP-DRAKE CONOCOPHILLlPS ATO 1530 700 G STREET ANCHORAGE AK 99501 1043 .. ./.., i i.." .... ,. DATE h.~t), c.'· >/ (: ¿(:(,4,··-6~-14/311 PAY TO THE OnDER .11IIII.... CHASE Chase Manhattan Sank USA, N.A. Valid Up To 5000 Dollars '-, 200 White Clay Center Dr.. Newa.rk. DE 19111 MEMO.__...______....".___..________ I: 0 ~ ¡. ¡. 0 0 ¡. ~ ~ I: 2 ¡. 8 ~ 7 ¡. 90 7 9 2 7 bill ¡. 0 ~ ~ . . TRANSMJT AL LETTER CHECKLIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME £RI( IE-/lj PTD# 2Dt./·-õ 31 \r\\~\<D('~Q.\ \ CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI Tbe permit is for a new wenbore segment of LATERAL existing well , Permit No, API No. . (If API number Production. sbould continue to be reported as last two (2) digits a function· of tbe original API number. stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(1), all (PH) records, data and logs acquired for the pilot bole must be clearly differentiated in botb name (name on permit plus PH) . and API Dumber (50 - 70/80) from records, data and logs acquired for wen (name on permit). SPACING Tbe permit is approved subject ·to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes tbe liability of any protest to tbe spacinge:xception tbat may occur. DRY DITCH AlJ dry ditch sample sets submitted to tbe SAMPLE Commission must be in no greater than 30' sample intervals from below tbe permafrost or from where samples are first caught and 10' sample intervals through target zones. Rev: 07/10/02 C\jody\templates PTD#: 2040310 Administration Well bore seg Annular Disposal Appr Date SFD 2/9/2004 Engineering Appr Date TEM 2/10/2004 ~ Geology Appr SFD Date 2/9/2004 Field & Pool KUPARUK RIVER, WEST SAK OIL - 490150 Well Name: KUPARUK RIV U WSAK 1 E-119 Program SER Company CONOCOPHILLlPS ALASKA INC Initial ClasslType SER I PEND GeoArea 890 Unit 11160 On/Off Shore On 1 P~rmitfee attache.d. . . . . . . _ _ . _ . . . _ _ . . . . .. .. .Y~s . . . . . . .. ......_ 2 .Leas~.numberappropriate.. . . _ _ . .. ............ _ . . . . . . . .Y~s . . . _ _ . . . . . . _ . . . . . _ _ _ . . . _ ....... _ _ _ _ . . . . . . _ . _ . _ _ . . . . . . 3 _U_nique weltnam~_a[1d OlJ.mb_er _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ . . . . . _ . . _ _ _ _ _ . _ _ . . _ _ y~s _ _ _ _ _ . . _ . . . . _ . . _ _ _ _ _ _ _ _ . . . . . _ _ . _ _ _ _ _ _ _ . _ _ . _ _ _ _ . . _ _ . _ _ _ . . _ . . _ _ _ _ _ _ _ _ _ _ . . . _ _ _ 4 WellJQcat~d in a define.dppol. . . . . . . . . . _ . . . . . . . . . . . . . _ _ _ . . . . . . . Y~s. _ . . . . . Kuparuk River UnJt, WesI.S.a~ Oil POQI:. Conservatio[1 Ord.er !\Io.A06A . . . . . . . .. ..... _ . _ 5 WellJQcat~d proper .distance from driJIing unitb9und_ary. . . . . . . . . . . . _ _ . . . . . . . y~s _ . . . _ . . . _ _ . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . _ _ . _ . . . . . . . . . . 6 Well JQcat~d pr.oper _distance. from otber wells_ _ . . . _ _ . . . . . . . . . . . . . . Yes . . . . .. ....... _ _ . . . . . _ _ . _ _ . . . . . . . . . . . . . . . . . . . . . . . 7 .S.ufficientacreage.ayailable in.drilliog lJ.njl. _ _ _ . . .. ..... _ . . . . .Y~s . !\Iomioal $pa_cing uoitswjtbi[1 theppolwjll.b.e.1 0 <icres.. . . . . . . _ _ . . . . 8 Jtd~viated, js wellbQre pl<ltincJuded . . . . . _ _ . . _ _ . .. .................. _ . Yes _ . . . . . . . . . _ . _ . . . . . . . . . _ . _ . . . . . . . . 9 .Operator only: affected party. . . . . . _ _ _........ . _ . . . . . . . _ . . Yes. . _ _ _ . _ . . . . . . . . . . . .. . _ _ _ . . . . . . . . . . . . _ . _ _ . . . . . . _ . . . . . . 10 .Oper.ator bas_apprppriate.b.ond in.force . _ _ . _ _ _ _ . _ _ _ _ . . . . . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ y~s _ _ _ _ _ . _ _ _ . . . _ _ _ _ _ _ . _ _ _ _ . . _ . _ . _ . . _ _ _ . _ . . . _ _ _ . _ _ _ . _ . _ _ _ _ . . . . . _ _ _ _ _ _ _ _ _ _ . . . _ _ 11 P~rmit c.ao be iSSlJ.ed wjtbQut conserva.tion order. . . . . . .. .... Yes _ _ . . . . _ . . . . . . . _ . . . . . . . _ . . . . . _ . . . . . . . . . 12 P~rmitc.a[1beisSlJ.edwjtbQutad.ministratÌ\le_apprpvaJ_ _....... ...... Y~s........ .. _... ...... ..... _. 13 Can permit be approved before 15-day wait Yes 14 WellJQcat~d within area andstrata.authorized by lojectipo Ord~r # (puUOtl inc.omm.eot$) (For. Yes _ . . I\rea Injectjo_nQrder Np.. 2B . . . . . . . . _ . . . . . . . . _ _..... 15 .AJlwells.witninJ/4.mile.area_ofreyiewjd~ot[fied(FprsefVjc.e.we[lpnly:)... _ _ _ _ _.... _ _. Y~L _ _ _ _ _ .!\Ion.e.currently: _ _ _ _ _ _... _. _ _. _.. _ _ _ _ _. _ _ _. _. _. _ _ _ _ _ _ _.. ~.. _ _ _. _ _ _ _ _ _ _ _. _ __ 16 Pre-produced. injector; .duration of pre-pro.ductipn I~Ss. than 3 months (For_service well onJy) . . No_ . . . . . . . _ . . . . . . . . . . . _ _ _ _ . _. ...... _ .. _ . . . 17 AÇMP.findingof Con.si$te[1cy.h.as been Jssued. forJhis pr.oject . . . . . . . . . . . _ . . . . . . .NA _ _ _ . . . . Well drilled. frQm exisiiog pa.de . . . . . . . . . . . . . . . . . _ . . . . . . . . . . 18C_oodu.ctor stringprQvided . _ . . . . . . . . . _ . _ . . . . . . . . . . . . . . . . . . . Y~s . . . . . . . . . _ _ . . _ . . . . . . . . _ . . . . . . . . . . . . . . . _ _ . . . _ 19Surfac~.casingprotec.tsaILknownUSQWs _ _ _... _ _.... . _ _....... NA... _.. .I\llaquifersex~mpted40CFRj47.102(b)(3).. _ _............ _. _ _........ _. _ _ _. 20 .CMTv.oladeQlJ.ateJo Ci rc.u late o_n cond.uctpr.8. SUJtC$g . . . . . . . .. .... YeL _ . . . . . . . . _ . . . . . . . . . . . _ . . . . . 21CMT v.ol adeQuateJo tie-inJQng .stri[1g to.surf csg. . _ . . . . . . . . . . . . . . . . . . No_ . _ . . . . . . . . . _ _ . . . . . . . . . . _ _ . . . _ _ . . . . . . . . . . . . _ _ 22 .CMTwill coyer.aU kOQw_npro_ductiYe hQrilonS_ . _ . . . . Y~s. . . . . _ . . _ _ . . . . . . . . . . 23C_asiog desigos ad_ec¡uaie fpr C,.T~ B.&permafr_ost. . _ _ . . . . . . . . Yes . . . . . _ _ . . . . . . . . . . . . . . _ . . . . . . . . _ . _ . . . . . 24 .A.dequ<itetankage.or re.serve pit. . . . . . .Y~s . _ . . Rig js.e.quippe.d.with st~el.pits.. No. reseJlle_pjtplanoe.de Waste.to an approyed. annulus or .dispos_al well.. . . 25 JfaJe-drill~ has_a 10-40;3 fQr abandonment be~o <lPPJQved . . . . . . . . . . . . . . . . . . . NA . . . . . . . . . . . . . . . . . . _ . . . . . . . . . . . _ . . _ _ . . _ _ . . . _ . . . . 26 A.dequ<ite.weUbore sep<lratjo.nproppsed _ _ _ _ _ _ _ _ _ _ _ _ . . . . _ _ _ _ . . _ _ _ _ _ _ . . _ _ _ Y~s _ . . _ _ . . I?rpJ5:imity: an<ilysis pertorme.de Ç!ose <lpprQache_sJd.entjfi.ed.. TralleJinQ c.y[in.der plQt jn.ctuded. _ _ _ _ _ _ . . _ . 27 Jfdjvecter req.uired, dQes it meet regulations. . . . . . . . . . . . _ . . _ _ . . . . . . . . . Y~s _ _ . _ . . . . . . . . . . . _ . . . . . . . . . . . . . . . . . . _ _ . . . . . . . . . . . . . . _ . . . . . _ . . . . . . . 28 DriUiog fluid. program sc.hematic.& eq.uipJist.adequale . . . . . . . _ _ _ . . Yes. . . . BI:Œ' inWS expected. be.tweeo8..3:8J. EMWe Planned.MW.9.4. . . _ . . . . . . . 29B.OPEs,.dothey meet regulation. . . . . . . .. _ _ . . . . . . . Yes. _ . . . . . . _ _ . . . . . . _ . _ . . . . . . . . . . _ _ 30 .BOPEpre.ss raiiog appropriate; .testto(put psig in .comments). . . . . . . . . . . . Y~s·. _ . CalcuJated.MASP 12;37 psi.. 3500 psiappropriateeCPA.u$uaJly tests to. 5000 psi.. . . . _ . . . . . . 31 Choke. manifold complies. w/API. RF'-53 (May 64)_ . . _ _ . . . . . . . . . . . . . . . Y~s _ . . . . . . _ _ _ _ . _ _ . . . . . . . . . . _ . . . . . . . . _ . _ . . _ _ . . . . . . . . . . _ _ 32 WQrk will pcc.ur withput.operationshlJ.tdo.wn. . . _ _ . . _ . . . . . . . . . . . . . . Y~s _ _ . . . . . . . . . . . . . . . _ . . . . . . . . . . _ . _ . . . . . _ . . _ . . . . . . . . 33 Is. pres.e[1ce Qf H2S gas. prob.able . . . . . . . . _ _ _ . . . . . . . . . . .. . _ . . . . . . . . . . No Mud sh.ould preclude. any H2S pn the rig.. Rig js_e_quippedwith sen.sors _aod alarm.s.. . . . . . . . _ _ _ . . . . . . . 34 MecbanicaLcpodjt[o[1 pf wells within I\OR yerified (fpr.serviCß well onJy) . . _ . . . . . . . .Y.es . _ _ . . . . 1 E-35 -1500',.1E-32.-.2500' away _at 35_00' .TVPe _SurfaCß .c<lsjngsetthr.ough. WS <iod. ceme[1ted to.5_urfac~. ~ - - - - - - - - - - - - - - - - - - - - D D . . Geologic Commissioner: (jTJ' - - - - - - - - - - - - - - - - - - - - - - 35 P~rmilc.ao be iSSlJ.ed wlo hydrogen.s.ulfide meaSUre$. . . . No. 36D.ata.preseoted on_ pote_ntial pverpressur~ .zones _ _ _ . _ . . . . . . . . . . . . . . Yes _ . 37 .S~ismicanalysjs. Qf sballow gas.zpoes . . . . . . . . _ . . . . . . . . . . . . . . . . NA . 38S~abedcondjtipo survey (if off-shore) . . . _ _ _ . . . . . . . .NA 39 _ CQnta.ct name/pnone.forweelsly prpgress.reports [explor<ltpry .0[1lyt . . . _ . . . . . . . . . . . . NA _ _ . . . . KRU WestSak wells_1 miJeto east <lreH2S-.bearing. _ . . . . . . . . . . . . . . . . . Expected. reservojr prssure js8.3 -8..7' ppgEMW;.will bedrilled.with9Appg m.ud. ....... - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Date: Engineering Commissioner: Date Public Commissioner Date <-{ -¿/1- e e 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. e dO f~o3 ( e z¡Þ j¿5eo!o **** REEL HEADER **** LDWG 04/05/19 AWS 01 **** TAPE HEADER **** LDWG 04/05/19 01 *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! LDWG File Version 1.000 !! ! ! !! ! ! !! !! !! !! ! !! Extract File: LISTAPE.HED TAPE HEADER KUPARUK RIVER UNIT MWD /MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA lE-1l9 500292319800 ConocoPhillips Alaska, Inc. BAKER HUGHES INTEQ 19-MAY-04 JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 4 4 C. WONG F. HERBERT MWD RUN MWD RUN # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION(FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: 21 llN 10E 95.00 67.00 # WELL CASING RECORD OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 1ST STRING 2ND STRING 3RD STRING 12.250 PRODUCTION STRING 8.500 9.625 3310.0 7090.0 # REMARKS: PER CONOCOPHILLIPS ALASKA STANDING ORDER, THE e e GAMMA RAY CURVE FROM THIS LOG IS THE DEPTH REFERENCE FOR THIS WELL. AS SUCH, NO DEPTH SHIFTS HAVE BEEN APPLIED. SURFACE LOCATION: LAT: N 70 DEG 18' 01.032" LONG: W149 DEG 35' 33.413" LOG MEASURED FROM D.F. AT 95.0 FT. ABOVE PERM. DATUM (M.S.L.) . COMMENTS: (1) Baker Hughes INTEQ runs 1 through 3 utilized a Directional only tool from 106 - 3317 feet MD(106 - 2053 TVD) . (2) Baker Hughes INTEQ run 4 utilized the Advantage Porosity Logging Service (APLS) which includes the Optimized Rotational Density (ORD), Caliper Corrected Neutron (CCN), along with Drill Collar Pressure (DCP) and MPR Resistivity services from 3317 - 7090 feet MD (2053 - 3660 TVD). (3) It was determined upon post well examination of the ORD tool (Optimized Rotational Density) and the density data, that severe wear had occurred on the outside surface of the tool. The wear resulted in irregular metal loss of up to several millimeters in the vicinity of the ORD source port. It is believed that the wear occurred at roughly 4900 feet MD when a piece of abrasive debris was lodged between the wear pad above the source and the fluid displacer over the detectors. The wear on the ORD tool effected the response characteristics of the density measurement. Initially, the bulk density and delta-Rho measurements were reading anomalously high. The ORD tool was recalibrated in the shop to compensate for the new response characteristics caused by the wear. The data was then reprocessed utilizing the new ORD calibration. The density correction measurement, Delta-Rho, was adversely effected by the imperfect recalibration which results from the irregular wear surface. The reprocessed Delta-Rho curve reads predominately negative values and thus the use of the atypical Delta-Rho curve scale -0.25 to +0.25 g/cc. The bulk density is the curve of primary importance and was the focus of the recalibration effort. In spite of the difficulties associated with the irregular wear and the negative correction, it was found that the reprocessed bulk density measurement is in good agreement with offset well data. (4) Per ConocoPhillips Alaska instructions, the Gamma Ray curve from this log is the depth reference for this well. As such, no depth shifts have been applied. REMARKS: (1) Depth of 9 5/8" Casing Shoe - Logger: 3310 feet MD (2051 TVD) Depth of 9 5/8" Casing Shoe - Driller: 3310 feet MD (2051 TVD) (2) The interval from 7049 to 7090 feet MD (3629 - 3660 TVD) was not logged due to sensor-bit offset at TD. $ Tape Subfile: 1 99 records... Minimum record length: Maximum record length: 8 bytes 132 bytes **** FILE HEADER **** LDWG .001 1024 e *** LIS COMMENT RECORD *** e !!!!!!!!!!!!!!!!!!! LDWG File Version 1.000 !!!!!!!!!!!!!!!!!!! Extract File: FILE001.HED FILE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE MWD $ 1 and clipped curves; all bit runs merged. .5000 START DEPTH 3310.0 STOP DEPTH 7090.0 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH -~------- BASELINE DEPTH $ # MERGED DATA SOURCE PBU TOOL CODE MWD $ # REMARKS: BIT RUN NO MERGE TOP 2 3310.0 MERGE BASE 7090.0 MERGED PASS. NO DEPTH SHIFTS WERE APPLIED AS THIS LOG IS THE DEPTH REFERENCE FOR THIS WELL. # $ *** INFORMATION TABLE: CONS MNEM VALU ------------------------------------ WDFN LCC CN WN FN COUN STAT 1e-119 5.xtf 150 ConocoPhillips Alaska, Inc. 1E-119 Kuparuk River North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ---------------------------------------------------- ODEP GR RPD RPM RPS RPX RHOB DRHO PEF NPHI ROP GR RPD RPM RPS RPX RHOB DRHO PEF NPHI ROP GRAM RPD RPM RPS RPX BDCM DRHM DPEM NPCKSM ROPS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 e e FET MTEM FET MTEM RPTH TCDM 0.0 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 52 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.500000 Frame spacing units: [F ] Number of frames per record is: 19 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 12 Curves: Name Tool Code Samples Units Size Length 1 GR MWD 68 1 GAPI 4 4 2 RPD MWD 68 1 OHMM 4 4 3 RPM MWD 68 1 OHMM 4 4 4 RPS MWD 68 1 OHMM 4 4 5 RPX MWD 68 1 OHMM 4 4 6 RHOB MWD 68 1 G/C3 4 4 7 DRHO MWD 68 1 G/C3 4 4 8 PEF MWD 68 1 BNIE 4 4 9 NPHI MWD 68 1 PU-S 4 4 10 ROP MWD 68 1 FPHR 4 4 11 FET MWD 68 1 HR 4 4 12 MTEM MWD 68 1 DEGF 4 4 ------- 48 Total Data Records: 398 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 3310.000000 7090.000000 0.500000 feet **** FILE TRAILER **** Tape Subfile: 2 445 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** LDWG .002 1024 *** LIS COMMENT RECORD *** e !!!!!!!!!!!!!!!!!!! LDWG File Version 1.000 !!!!!!!!!!!!!!!!!!! Extract File: FILEOll.HED FILE HEADER FILE NUMBER: RAW MWD Curves and BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD $ 2 e log header data for each bit run in separate files. 2 .2500 START DEPTH 3250.0 STOP DEPTH 7090.0 # 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): HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DIR CCN ORD MPR GRAM $ BOTTOM) TOOL TYPE DIRECTIONAL CAL. COR. NEUTRON OPT. ROT. DENSITY MULT. PROP. RESIS. GAMMA RAY # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TEMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: BIT RUN 2 (MWD Run 4). GR/MPR/oRD/CCN. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) 07-APR-04 MSB 18655 6.75 TC MEMORY 7090.0 3317.0 7090.0 o 45.3 73.0 TOOL NUMBER DHA 90427 CCN 29572 ORD 28636 MPR 67280 SRIG 5078 8.500 3310.0 FLO-PRO 9.20 .0 .0 31000 .0 .000 .000 .000 .000 107.0 .0 .0 .0 Sandstone .00 .000 .0 o e e RPCL - DEEP PHASE RESISTIVITY (OHMM) RPSL - MEDIUM PHASE RESISTIVITY (OHMM) RPCH - SHALLOW PHASE RESISTIVITY (OHMM) RPSH - EXTRA SHALLOW PHASE RESISTIVITY (OHMM) BDCM - BULK DENSITY COMPENSATED (G/CC) DRHM - DENSITY CORRECTION (G/CC) DPEM - PHOTOELECTRIC CROSS SECTION (B/E) NPCK - NEUTRON POROSITY, CALIPER & SALINITY CORRECTED (SANDSTONE PU) ROPS - RATE OF PENETRATION (FPHR) RPTH - FORMATION EXPOSURE TIME (MIN) TCDM - TEMPERATURE (DEGF) PER CONOCOPHILLIPS ALASKA (WAYNE CAMPAIGN), THE FOLLOWING CURVES ARE NOT PRESENTED ON THE MPR RESISTIVITY LOG BUT ARE PRESENTED HERE FOR THE SAKE OF COMPLETENESS: RACL - DEEP ATTENUATION RESISTIVITY (OHMM) RASL - MEDIUM ATTENUATION RESISTIVITY (OHMM) RACH - SHALLOW ATTENUATION RESISTIVITY (OHMM) RASH - EXTRA SHALLOW ATTENUATION RESISTIVITY (OHMM) $ # *** INFORMATION TABLE: CONS MNEM VALU -------------------------------- WDFN LCC CN WN FN COUN STAT 1e-1l9.xtf 150 ConocoPhillips Alaska, I 1E-1l9 Kuparuk River North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GRAM GRAM GRAM 0.0 RPCL RPCL RPD 0.0 RPSL RPSL RPM 0.0 RPCH RPCH RPS 0.0 RPSH RPSH RPX 0.0 RACL RACL RAD 0.0 RASL RASL RACSLM 0.0 RACH RACH RAS 0.0 RASH RASH RACSHM 0.0 BDCM BDCM BDCM 0.0 DRHM DRHM DRHM 0.0 DPEM DPEM DPEM 0.0 NPCK NPCK NPCKSM 0.0 ROPS ROPS ROPS 0.0 RPTH RPTH RPTHM 0.0 TCDM TCDM TCDM 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 68 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 14 e One depth per frame (value= 0) Datum Specification Block Sub-type is: FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 16 Curves: Name Tool Code Samples Units 1 GRAM MWD 68 1 GAPI 2 RPCL MWD 68 1 OHMM 3 RPSL MWD 68 1 OHMM 4 RPCH MWD 68 1 OHMM 5 RPSH MWD 68 1 OHMM 6 RACL MWD 68 1 OHMM 7 RASL MWD 68 1 OHMM 8 RACH MWD 68 1 OHMM 9 RASH MWD 68 1 OHMM 10 BDCM MWD 68 1 G/C3 11 DRHM MWD 68 1 G/C3 12 DPEM MWD 68 1 BN/E 13 NPCK MWD 68 1 PU-S 14 ROPS MWD 68 1 FPHR 15 RPTH MWD 68 1 MINS 16 TCDM MWD 68 1 DEGF Total Data Records: 1098 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 3250.000000 7090.000000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 3 1208 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** TAPE TRAILER **** LDWG 04/05/19 01 **** REEL TRAILER **** LDWG 04/05/19 AWS 01 e 1 Size Length 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 ------- 64 <' Tape Sub file : 4 Minimum record length: Maximum record length: e e 2 records... 132 bytes 132 bytes
