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Home My WebLink About203-154CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Some people who received this message don't often get email from leslie.manning@conocophillips.com. Learnwhy this is important From:Davies, Stephen F (OGC) To:Gluyas, Gavin R (OGC) Cc:Loepp, Victoria T (OGC) Subject:FW: [EXTERNAL]KRU_2P-447 (PTD 203-154, Sundry 326-014) - Question Date:Wednesday, January 28, 2026 9:27:18 AM Attachments:2P-447 sch.pdf Hi Gavin, Could you please place a copy of the attached wellbore schematic drawing and a copy of the email thread below in the Well History File for KRU 2P-447 (PTD 203-154)? Thanks, Steve From: Manning, Leslie <Leslie.Manning@conocophillips.com> Sent: Wednesday, January 28, 2026 8:36 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]KRU_2P-447 (PTD 203-154, Sundry 326-014) - Question Steve – My apologies for the delayed response to your question; I was out of the office when your email arrived, and it was inadvertently overlooked. Please see the attached updated schematic, which includes additional information regarding the shallow perforation intervals you referenced. Regards, Leslie Manning Sr. CTD/RWO Engineer ConocoPhillips Alaska Cell: 512.755.6782 Office: 907.263.3731 From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Wednesday, January 14, 2026 10:31 AM To: Manning, Leslie <Leslie.Manning@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov> Subject: [EXTERNAL]KRU_2P-447 (PTD 203-154, Sundry 326-014) - Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hello Leslie, I'm reviewing CPAI's Sundry Application (326-014) for KRU_2P-447. In addition to Victoria's request, appended below, I have an additional question. On the application form and on the wellbore schematic drawing that accompanies it, there are listed many very shallow perforation intervals, but no dates, comments, or additional information are provided. I checked the Well Completion and Sundry Reports that AOGCC currently has on file but could find no details. To ensure that AOGCC's records and databases are accurate, could CPAI please provide additional information regarding these intervals? Thanks and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. _____________________________________________ From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Monday, January 12, 2026 8:35 AM To: Manning, Leslie <leslie.manning@conocophillips.com> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: DS 2P Suspension Extensions Could you please include the work remaining to be completed and the current status of the P&A. Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Updated TOC after slickline tag 2P-447 8/21/2025 rmoore22 Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC Upper Intermediate 7 6.28 25.2 2,655.0 2,287.4 26.00 L-80 BTC-MD Lower intermediate 7 6.28 2,728.0 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth … 2,519.0 Set Depth … 2,205.4 String Max No… 3 1/2 Tubing Description Tubing – Kill String Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE-M 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) 23.2 23.2 0.00 Hanger 10.880 FMC 11' x 3 1/2" Gen V TBG hanger, 3 1/2" EUE top thread FMC Gen V 2.910 Top (ftKB) 3,050.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description Tubing – Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,670.1 2,296.4 53.46 CEMENT RETAINER 4 1/4" Inflatable Cement Retainer Baker Huges 12/21/2025 0.000 2,800.0 2,373.5 53.60 CIBP CIBP RIH by Baker, set @ 2800' top of plug. J-1 CIBP 11/20/2025 0.000 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 275.0 290.0 275.0 290.0 12/27/2025 APERF 5.70" Gator Mechanical Perforating Tool, 7 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 400.0 415.0 400.0 415.0 12/27/2025 APERF 5.70" Gator Mechanical Perforating Tool, 7 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 2P-447, 12/25/2026 Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 Plug – Plug Back / Abandonment Plug; 2,728.0 ftKB SURFACE; 28.1-2,705.6 CEMENT RETAINER; 2,670.1 Upper Intermediate; 25.2- 2,655.0 Cement Plug; 2,543.0 ftKB APERF; 2,190.0-2,200.0 APERF; 1,510.0-1,525.0 Cement Off 7 x 9 5/8; 300.0 ftKB Cement Casing; 34.0 ftKB APERF; 1,040.0-1,050.0 APERF; 900.0-910.0 APERF; 790.0-800.0 APERF; 700.0-710.0 APERF; 590.0-600.0 APERF; 540.0-550.0 APERF; 400.0-415.0 APERF; 275.0-290.0 CONDUCTOR; 30.0-108.0 Hanger; 23.2 Plug & Abandonment; 23.2 ftKB KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 540.0 550.0 539.8 549.7 12/26/2025 APERF 5.70" Gator Mechanical Perforating Tool, 6 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 590.0 600.0 589.5 599.4 12/26/2025 APERF 5.70" Gator Mechanical Perforating Tool, 6 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 700.0 710.0 698.2 708.1 12/26/2025 APERF 5.70" Gator Mechanical Perforating Tool, 6 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 790.0 800.0 787.0 796.9 12/26/2025 APERF 5.70" Gator Mechanical Perforating Tool, 6 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 900.0 910.0 895.6 905.4 12/26/2025 APERF 5.70" Gator Mechanical Perforating Tool, 5 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 1,040.0 1,050.0 1,032.9 1,042.7 12/25/2025 APERF 5.70" Gator Mechanical Perforating Tool, 3 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 1,510.0 1,525.0 1,470.7 1,483.7 12/25/2025 APERF 5.70" Gator Mechanical Perforating Tool, 3 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 2,190.0 2,200.0 1,994.9 2,001.6 12/25/2026 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 3 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 2,780.0 2,810.0 2,361.6 2,379.4 7/4/2025 12.0 APERF 4.5" GUNS, 12 SPF, 45 DEGREE PHASE, W/ GEO 23 GRAM CHARGES 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 34.0 2,705.0 34.0 2,317.1 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 105Drag up (lbs): 120Time started reciprocating: 05:30Time stopped reciprocating: 12:10Cement Found Between Shoe and Collar (Y/N): NCement found on liner tool (Y/N): NAnnular flow after cement job (Y/N): NPressure before cementing (psi): 325Hours circulated between stages: 4Bbls cmt to surf: 161.8Method used to measure density: DensometerMethod used for mixing cement in this stage: TUBReturns (pct): FullTime cementing mixing started: 11:10 12/8/2003 300.0 2,655.0 300.0 2,287.4 Cement Off 7 x 9 5/8 Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NMethod used for mixing cement in this stage: FlyTime cementing mixing started: 22:58 12/21/2003 4,648.0 7,562.0 3,520.6 5,305.9 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NPressure before cementing (psi): 310Hours circulated between stages: 2.5Bbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): 0Time cementing mixing started: 09:45 12/21/2003 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NBbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: on FlyPressure left on after job (psi): 3Returns (pct): 0Time cementing mixing started: 19:42 12/21/2003 2P-447, 12/25/2026 Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 Plug – Plug Back / Abandonment Plug; 2,728.0 ftKB SURFACE; 28.1-2,705.6 CEMENT RETAINER; 2,670.1 Upper Intermediate; 25.2- 2,655.0 Cement Plug; 2,543.0 ftKB APERF; 2,190.0-2,200.0 APERF; 1,510.0-1,525.0 Cement Off 7 x 9 5/8; 300.0 ftKB Cement Casing; 34.0 ftKB APERF; 1,040.0-1,050.0 APERF; 900.0-910.0 APERF; 790.0-800.0 APERF; 700.0-710.0 APERF; 590.0-600.0 APERF; 540.0-550.0 APERF; 400.0-415.0 APERF; 275.0-290.0 CONDUCTOR; 30.0-108.0 Hanger; 23.2 Plug & Abandonment; 23.2 ftKB KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,415.0 8,010.0 5,226.0 5,546.3 Cement Liner Pipe movement: Rotate & RecipDrag down (lbs): 87Drag up (lbs): 148Time started reciprocating: 08:45Time stopped reciprocating: 12:00Time started rotating: 08:45Time stopped rotating: 12:00Init torque (ft-lbf): 5500Max torque (ft-lbf): 5500Annular flow after cement job (Y/N): NPressure before cementing (psi): 700Hours circulated between stages: 2.5Bbls cmt to surf: 10Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): FullTime cementing mixing started: 10:30 12/25/2003 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2,728.0 2,900.0 2,330.8 2,433.1 Plug – Plug Back / Abandonment Plug 23 BBLS 15.8 PPG CMNT pumped on 11/24/25 F/ 2728'- 2150' AOGCC witnessed tag @ 2244' along with 1500 psi 30 min test 11/24/2025 2,900.0 2,950.0 2,433.1 2,463.3 Cement Plug WASH/LAY IN 15.8 PPG CLASS G CEMENT PLUG FROM 2950-2480' 7/13/2025 2,543.0 2,728.0 2,220.0 2,330.8 Cement Plug HES pump 4.5 Bbls fresh water @ .5 BPM, 2000 PSI. Pump 22 Bbls for 5 Bbls under plug 16.0 PPG PTA cement @ 610 PSI. Hessitate for 5 Min. Pump 5 for 10 under plug Bbls @ .5 BPM 565 PSI. Hessitate for 10 Min. Pump 5 for 15 Bbls Under plug @ .5 BPM 800 PSI. Hessitate for 10 Min. Pump 9 for 24 Bbls under plug @ .5 BPM 590 PSI. Hessitate for 10 Min. Pump 5 water for 29 Bbls under plug @ .5 BPM, 615 PSI. Hessitate for 10 Min. Pump 3 seawater for 32 Bbls under plug @ .5 BPM 890 PSI. Pump 4 Bbls seawater fo 36 under plug @ .5 BPM, Bio;t 355 PSI. Pulled out of retainer, balance 5 Bbls on top of plug. 12/22/2025 12/22/2025 23.2 2,543.0 23.2 2,220.0 Plug & Abandonment Pump cement per program // Squeeze 500 psi on perfs last 15 bbls // Wash up and blow down lines Cement returns observed @ 90 bbls pumped 15.8# cement at surface @ 100 bbls pumped w/ 200 psi back pressure apply 500 psi back pressure continue pump 20 bbls 15.8# cement returns Shut down pumps @ 120 bbls pumped Shut down pumps trap 100 psi on IA No communication with OA durring cementing operations OA pressure 0 psi Cement job as follows 30 BBLS 8.4# Fresh water w/ Pump Surfactant Wash (0.5 gal/bbl each of Musol and Dual B) 5 bbls Fresh water 130 bbls Mix and Pump PTA Cement 15.8 PPG 50 bbls Wash-Up w/ Citric/MMCR 12/31/2025 2P-447, 12/25/2026 Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 Plug – Plug Back / Abandonment Plug; 2,728.0 ftKB SURFACE; 28.1-2,705.6 CEMENT RETAINER; 2,670.1 Upper Intermediate; 25.2- 2,655.0 Cement Plug; 2,543.0 ftKB APERF; 2,190.0-2,200.0 APERF; 1,510.0-1,525.0 Cement Off 7 x 9 5/8; 300.0 ftKB Cement Casing; 34.0 ftKB APERF; 1,040.0-1,050.0 APERF; 900.0-910.0 APERF; 790.0-800.0 APERF; 700.0-710.0 APERF; 590.0-600.0 APERF; 540.0-550.0 APERF; 400.0-415.0 APERF; 275.0-290.0 CONDUCTOR; 30.0-108.0 Hanger; 23.2 Plug & Abandonment; 23.2 ftKB KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 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: Extend Suspension Date 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): 8015' 2949' 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 (907) 263-3731 Senior CTD/RWO Engineer KRU 2P-447 5549' 2369' 2111' 23', 2244', 2543', 2800', 2950', 5715', 7574' N/A 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: Leslie.Manning@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Leslie Manning STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Suspended TVD Burst 7466' MD 108' 2317' 5306' 108' 2706' 16" 9-5/8" 78' 7"7537' 2677' 7562' 275-290', 400-415', 540-550', 590- 600', 700-710', 790-800', 900-910', 1040-1050', 1510-1525', 2190-2200', 2780-2810', 2812-2930', 7600-7640', 7700-7800' (below cement plug) 3-1/2" 275-290', 400-415', 540-550', 590-599', 698-708', 787-797', 895-905', 1033- 1043', 1470-1484', 1995-2002', 2362- 2379', 2380-2451', 5325-5346', 5376- 5430' (below cement plug) Perforation Depth TVD (ft): 12/31/2025 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 approval: Notify AOGCC so that a representative may witness Sundry Number: BOP Test Mechanical Integrity Test Location Clearance ns of Approval: ction MIT Req'd? Yes No Subsequent Form Required: Suspension Expiration Date: AOGCC USE ONLY Contact Name: Contact Email: Contact Phone: e: (907) 263-3731 Senior CTD/RWO Engineer certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. me and re with Date:Leslie.Manning@conocophillips.com Leslie Manning Date for 15. Well Status after proposed work: Operations:OIL WINJ WDSPL Suspended proval:Date:GAS WAG GSTOR SPLUG esentative:GINJ Op Shutdown Abandoned 12/31/2025 quest:Abandon Plug Perforations Fracture Stimulate Reppair Well Operations shutdown Suspend Perforate Other Stimulate Pulll Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Extend Suspension Date er Casing ame:4. Current Well Class:5. Permit to Drill Number: Exploratory Development Stratigraphic Service 6. API Number: g:8. Well Name and Number: tion or Conservation Order governs well spacing in this pool? Yes No signation (Lease Number):10. Field: D (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD:Junk (MD): 2949' g Collapse al or e ate on SSV Type:Packers and SSSV MD (ft) and TVD (ft): ts: Proposal Summary Wellbore schematic 13. Well Class after proposed work: ations Program BOP Sketch Exploratory Stratigraphic Development Service KRU 2P-447 5549'2369'2111'23', 2244', 2543', 2800', 2950', 5715', 7574' N/A uire a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): Tubing Size:Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226'TVD N/A ADL0373112, ADL0389058 203-154 60, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended s Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Suspended TVD Burst 7466' MD 108' 2317' 5306' 108' 2706' 16" 9-5/8" 78' 7"7537' 2677' 7562' 5', 540-550', 590- 90-800', 900-910', 0-1525', 2190-2200', 2-2930', 7600-7640', w cement plug) 3-1/2" 275-290', 400-415', 540-550', 590-599', 698-708', 787-797', 895-905', 1033- 1043', 1470-1484', 1995-2002', 2362- 2379', 2380-2451', 5325-5346', 5376- 5430' (below cement plug) Perforation Depth TVD (ft): 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None pth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 326-014 By Grace Christianson at 10:29 am, Jan 09, 2026 VTL 1/22/2026 BOP test to 2500 psig X 30 day pressure monitoring per AOGCC request. Surface Excavation procedures will begin once monitoring is complete. DSR-1/22/26 XX March 1, 2026 SFD 1/22/2026 10-407 JLC 1/23/2026 01/23/26 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner, State of Alaska January 7, 2026 Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: Please find attached, the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. Well KRU 2P-447 (PTD# 203-154). This 10-403 is being submitted to request an extension of the Suspension Expiration Date to March 1, 2026. If you have any questions, please contact me at (907) 263-3731. Sincerely, Leslie Manning Senior CTD/RWO Engineer Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Updated TOC after slickline tag 2P-447 8/21/2025 rmoore22 Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC Upper Intermediate 7 6.28 25.2 2,655.0 2,287.4 26.00 L-80 BTC-MD Lower intermediate 7 6.28 2,728.0 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth 2,519.0 Set Depth 2,205.4 String Max No 3 1/2 Tubing Description Tubing Kill String Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE-M 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) 23.2 23.2 0.00 Hanger 10.880 FMC 11' x 3 1/2" Gen V TBG hanger, 3 1/2" EUE top thread FMC Gen V 2.910 Top (ftKB) 3,050.0 Set Depth 7,466.0 Set Depth 5,254.5 String Max No 4 1/2 Tubing Description Tubing Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,670.1 2,296.4 53.46 CEMENT RETAINER 4 1/4" Inflatable Cement Retainer Baker Huges 12/21/2025 0.000 2,800.0 2,373.5 53.60 CIBP CIBP RIH by Baker, set @ 2800' top of plug. J-1 CIBP 11/20/2025 0.000 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 275.0 290.0 275.0 290.0 APERF 400.0 415.0 400.0 415.0 APERF 540.0 550.0 539.8 549.7 APERF 590.0 600.0 589.5 599.4 APERF 700.0 710.0 698.2 708.1 APERF 790.0 800.0 787.0 796.9 APERF 900.0 910.0 895.6 905.4 APERF 1,040.0 1,050.0 1,032.9 1,042.7 APERF 1,510.0 1,525.0 1,470.7 1,483.7 APERF 2P-447, 1/7/2026 3:45:49 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 Plug Plug Back / Abandonment Plug; 2,728.0 ftKB SURFACE; 28.1-2,705.6 CEMENT RETAINER; 2,670.1 Upper Intermediate; 25.2- 2,655.0 Cement Plug; 2,543.0 ftKB APERF; 2,190.0-2,200.0 APERF; 1,510.0-1,525.0 Cement Off 7 x 9 5/8; 300.0 ftKB Cement Casing; 34.0 ftKB APERF; 1,040.0-1,050.0 APERF; 900.0-910.0 APERF; 790.0-800.0 APERF; 700.0-710.0 APERF; 590.0-600.0 APERF; 540.0-550.0 APERF; 400.0-415.0 APERF; 275.0-290.0 CONDUCTOR; 30.0-108.0 Hanger; 23.2 Plug & Abandonment; 23.2 ftKB KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE ? No dates or comments. SFD Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 2,190.0 2,200.0 1,994.9 2,001.6 4.0 APERF 2,780.0 2,810.0 2,361.6 2,379.4 7/4/2025 12.0 APERF 4.5" GUNS, 12 SPF, 45 DEGREE PHASE, W/ GEO 23 GRAM CHARGES 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 34.0 2,705.0 34.0 2,317.1 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 105Drag up (lbs): 120Time started reciprocating: 05:30Time stopped reciprocating: 12:10Cement Found Between Shoe and Collar (Y/N): NCement found on liner tool (Y/N): NAnnular flow after cement job (Y/N): NPressure before cementing (psi): 325Hours circulated between stages: 4Bbls cmt to surf: 161.8Method used to measure density: DensometerMethod used for mixing cement in this stage: TUBReturns (pct): FullTime cementing mixing started: 11:10 12/8/2003 300.0 2,655.0 300.0 2,287.4 Cement Off 7 x 9 5/8 Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NMethod used for mixing cement in this stage: FlyTime cementing mixing started: 22:58 12/21/2003 4,648.0 7,562.0 3,520.6 5,305.9 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NPressure before cementing (psi): 310Hours circulated between stages: 2.5Bbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): 0Time cementing mixing started: 09:45 12/21/2003 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NBbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: on FlyPressure left on after job (psi): 3Returns (pct): 0Time cementing mixing started: 19:42 12/21/2003 7,415.0 8,010.0 5,226.0 5,546.3 Cement Liner Pipe movement: Rotate & RecipDrag down (lbs): 87Drag up (lbs): 148Time started reciprocating: 08:45Time stopped reciprocating: 12:00Time started rotating: 08:45Time stopped rotating: 12:00Init torque (ft-lbf): 5500Max torque (ft-lbf): 5500Annular flow after cement job (Y/N): NPressure before cementing (psi): 700Hours circulated between stages: 2.5Bbls cmt to surf: 10Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): FullTime cementing mixing started: 10:30 12/25/2003 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2,728.0 2,900.0 2,330.8 2,433.1 Plug Plug Back / Abandonment Plug 23 BBLS 15.8 PPG CMNT pumped on 11/24/25 F/ 2728'- 2150' AOGCC witnessed tag @ 2244' along with 1500 psi 30 min test 11/24/2025 2,900.0 2,950.0 2,433.1 2,463.3 Cement Plug WASH/LAY IN 15.8 PPG CLASS G CEMENT PLUG FROM 2950-2480' 7/13/2025 2,543.0 2,728.0 2,220.0 2,330.8 Cement Plug HES pump 4.5 Bbls fresh water @ .5 BPM, 2000 PSI. Pump 22 Bbls for 5 Bbls under plug 16.0 PPG PTA cement @ 610 PSI. Hessitate for 5 Min. Pump 5 for 10 under plug Bbls @ .5 BPM 565 PSI. Hessitate for 10 Min. Pump 5 for 15 Bbls Under plug @ .5 BPM 800 PSI. Hessitate for 10 Min. Pump 9 for 24 Bbls under plug @ .5 BPM 590 PSI. Hessitate for 10 Min. Pump 5 water for 29 Bbls under plug @ .5 BPM, 615 PSI. Hessitate for 10 Min. Pump 3 seawater for 32 Bbls under plug @ .5 BPM 890 PSI. Pump 4 Bbls seawater fo 36 under plug @ .5 BPM, Bio;t 355 PSI. Pulled out of retainer, balance 5 Bbls on top of plug. 12/22/2025 12/22/2025 2P-447, 1/7/2026 3:45:50 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 Plug Plug Back / Abandonment Plug; 2,728.0 ftKB SURFACE; 28.1-2,705.6 CEMENT RETAINER; 2,670.1 Upper Intermediate; 25.2- 2,655.0 Cement Plug; 2,543.0 ftKB APERF; 2,190.0-2,200.0 APERF; 1,510.0-1,525.0 Cement Off 7 x 9 5/8; 300.0 ftKB Cement Casing; 34.0 ftKB APERF; 1,040.0-1,050.0 APERF; 900.0-910.0 APERF; 790.0-800.0 APERF; 700.0-710.0 APERF; 590.0-600.0 APERF; 540.0-550.0 APERF; 400.0-415.0 APERF; 275.0-290.0 CONDUCTOR; 30.0-108.0 Hanger; 23.2 Plug & Abandonment; 23.2 ftKB KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 23.2 2,543.0 23.2 2,220.0 Plug & Abandonment Pump cement per program // Squeeze 500 psi on perfs last 15 bbls // Wash up and blow down lines Cement returns observed @ 90 bbls pumped 15.8# cement at surface @ 100 bbls pumped w/ 200 psi back pressure apply 500 psi back pressure continue pump 20 bbls 15.8# cement returns Shut down pumps @ 120 bbls pumped Shut down pumps trap 100 psi on IA No communication with OA durring cementing operations OA pressure 0 psi Cement job as follows 30 BBLS 8.4# Fresh water w/ Pump Surfactant Wash (0.5 gal/bbl each of Musol and Dual B) 5 bbls Fresh water 130 bbls Mix and Pump PTA Cement 15.8 PPG 50 bbls Wash-Up w/ Citric/MMCR 12/31/2025 2P-447, 1/7/2026 3:45:50 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 Plug Plug Back / Abandonment Plug; 2,728.0 ftKB SURFACE; 28.1-2,705.6 CEMENT RETAINER; 2,670.1 Upper Intermediate; 25.2- 2,655.0 Cement Plug; 2,543.0 ftKB APERF; 2,190.0-2,200.0 APERF; 1,510.0-1,525.0 Cement Off 7 x 9 5/8; 300.0 ftKB Cement Casing; 34.0 ftKB APERF; 1,040.0-1,050.0 APERF; 900.0-910.0 APERF; 790.0-800.0 APERF; 700.0-710.0 APERF; 590.0-600.0 APERF; 540.0-550.0 APERF; 400.0-415.0 APERF; 275.0-290.0 CONDUCTOR; 30.0-108.0 Hanger; 23.2 Plug & Abandonment; 23.2 ftKB KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 Current Status of the KRU 2P Pad Plug and Abandon Campaign As of 01/13/2026 2P-422A 01/07/2026: Pulled shore can. Will request Final site clearance with 2P-424A and 2P-429. 2P-424A 01/10/2026: Pulled cellar box 01/09/2026: Wellhead cut and removed. Excavation is on hold due to weather conditions. 2P-429 01/11/2026: Pulled cellar box 01/10/2026: Wellhead cut and removed. Excavation is on hold due to weather conditions. 2P-406 Cemented to Surface 01/13/2026: Continue to monitor well pressures per AOGCC request. A new 10-403 will be submitted prior to any further intervention. (Reference Extension Request for further details.) 2P-447 Cemented to Surface 12/31/2025: 30 day pressure monitoring per AOGCC request. Surface Excavation procedures will begin once monitoring is complete. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Manning, Leslie To:Roby, David S (OGC); Loepp, Victoria T (OGC) Cc:Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Hobbs, Greg S Subject:RE: [EXTERNAL]RE: DS 2P Suspension Extensions Date:Wednesday, January 21, 2026 9:52:02 AM Some people who received this message don't often get email from leslie.manning@conocophillips.com. Learn why this is important Dave - ConocoPhillips aimed to complete the abandonment of all remaining 2P wells by December 31, 2025, and as of the check in meeting on December 11, 2025, we were striving to meet that goal. However, due to weather conditions and operational delays encountered in late December, full abandonment could not be completed prior to the expiration of the wells suspension status. Following December 31, 2025, we evaluated the status of all remaining 2P wells and contacted the AOGCC to determine appropriate next steps for the work scope. Based on their guidance, we proceeded with submitting suspension extension requests for each well. Regards, Leslie Manning Sr. CTD/RWO Engineer ConocoPhillips Alaska Cell: 512.755.6782 Office: 907.263.3731 From: Roby, David S (OGC) <dave.roby@alaska.gov> Sent: Friday, January 16, 2026 3:45 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Manning, Leslie <Leslie.Manning@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL]RE: DS 2P Suspension Extensions CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Leslie, Please also provide an explanation for why the suspension renewal requests were not submitted until after the suspensions had expired. Thank you, Dave Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 _____________________________________________ From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Monday, January 12, 2026 8:35 AM To: Manning, Leslie <leslie.manning@conocophillips.com> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: DS 2P Suspension Extensions Could you please include the work remaining to be completed and the current status of the P&A. Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 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): Effective Depth MD: Effective Depth TVD: Junk (MD): 8015' 2949' 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 10/27/2025 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 7537' 2677' 7562' 2780-2810', 2812-2930', 7600- 7640', 7700-7800' (below cement plug) 3-1/2" 2362-2379', 2380-2451', 5325- 5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 108' 2706' 16" 9-5/8" 78' 7" 7466' MD 108' 2317' 5306' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended AOGCC USE ONLY Victoria Loepp 12/15/2025 Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A James Ohlinger 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: James.J.Ohlinger@conocophillips.com (907) 265-1102 Staff CTD Engineer KRU 2P-447 5549' 2369' 2111' 2244', 2800', 2900', 2950', 5715', 7574' N/A approval: Notify AOGCC so that a representative may witness Sundry Number: BOP Test Mechanical Integrity Test Location Clearance ons of Approval: ection MIT Req'd? Yes No Subsequent Form Required: Suspension Expiration Date: AOGCC USE ONLY quest: Abandon Plug Perforations Fracture Stimulate Reppair Well Operations shutdown Suspend Perforate Other Stimulate Pulll Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alteer Casing Other: ame:4.Current W ell Class:5.Permit to Drill Number: Exploratory Development Stratigraphic Service 6. API Number: g:8. Well Name and Number: ation or Conservation Order governs well spacing in this pool? Yes No esignation (Lease Number): 10. Field: D (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD:Junk (MD): 2949' g Collapse al or e ate on SSSV Type:Packers and SSSV MD (ft) and TVD (ft): nts: Proposal Summary Wellbore schematic 13. Well Class after proposed work: ations Program BOP Sketch Exploratory Stratigraphic Development Service Date for 15. Well Status after proposed work: Operations:OIL WINJ WDSPL Suspended proval:Date:GAS WAG GSTOR SPLUG esentative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: le: 10/27/2025 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None epth MD (ft): L-80 7537' 2677' 7562' 812-2930', 7600- 800' (below 3-1/2" 2362-2379', 2380-2451', 5325- 5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 108' 2706' 16" 9-5/8" 78' 7" 7466' MD 108' 2317' 5306' s Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst ADL0373112, ADL0389058 203-154 360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended Victoria Loepp 12/15/2025 Tubing Grade: Tubing MD (ft): 7429'MD and 5234'TVD 7415' MD and 5226' TVD N/A James Ohlinger quire a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ame and ure with Date: Tubing Size: James.J.Ohlinger@conocophillips.com (907) 265-1102 Staff CTD Engineer KRU 2P-447 5549'2369'2111'2244', 2800', 2900', 2950', 5715', 7574' 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 325-760 By Grace Christianson at 8:29 am, Dec 16, 2025 12/31/2025 BOP test to 2500 psig X 10-407 A.Dewhurst 16DEC25 X 12/15/2025 VTL 12/17/2025 12/18/25 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 15, 2025 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby resubmits a Change of Approval to Plug & Abandon 2P-447 (PTD 203-154). This sundry covers the portion to be performed on-rig by Nabors 7ES starting in December 2025. 2P-447 was an injector that has been shut in since mid-2021. This well has been suspended with a reservoir cement plug and an intermediate cement plug (covered in separate 10-403). Sundry #324-627 pulled the tubing from a pre-rig cut, perforated below the surface casing shoe on Nordic 3, and set a plug/cap in and above the C80 formation. The OA DDT shows a small pressure build up over several days. Under Sundry 325-355 Nabors 7ES milled out the cement in the 7 production casing down to 2900 RKB. Then section milled the casing from 2655 down to 2728 RKB for a cement balanced plug. The top of cement was found at 2244 RKB and passed a 1500 pressure test, but the OA continued to pressurize. The OA has been on surveillance since 11/24/25, with no change in OA pressure. Operations will rig up again to P&A the C80. Once the OA DDT satisfies testing requirements, the OA and Production Casing will be cemented and prepped for abandonment operations. If you have any questions or require any further information, please contact me at 907-229-3338. James Ohlinger CTD/RWO Staff Engineer CPAI Drilling and Wells 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355/325-587 Page 1 of 6 General Well info Estimated Start Date: 12/15/2025 Workover Engineer: James J Ohlinger (+1-907-265-1102/ James.J.Ohlinger@conocophillips.com) Current Operations: This well is Suspended as of 11/23/24 Well Type: Injector History: 2P-447 was an injector that has been shut in since mid-2021. This well has been suspended with a reservoir cement plug and an intermediate cement plug (covered in a separate 10-403). The steps outlined in sundry 324-627 included pulling the tubing from a pre-rig cut, setting a plug across the C80 formation, and Perforating below the surface casing shoe on Nordic 3 in preparation for a perf/ wash/ cement job to isolate the C80 formation. The PWC was attempted 7/13/25 (38 bbls Class G cement). A passing MIT was obtained (1500psi), however the OA has repressurized. There was an OA down squeeze performed on rig 12/21/2003 with 94 Barrels (197sx @ 12ppg) of ArctiCrete Cement. Under Sundry 325-355 Nabors 7ES milled out the cement in the 7 production casing down to 2900 RKB. Then section milled the casing from 2655 down to 2728 RKB for a cement balanced plug. The top of cement was found at 2244 RKB and passed a 1500 pressure test, but the OA continued to pressurize. The OA has been on surveillance since 11/24/25, with no change in OA pressure. Operations will rig up again to P&A the C80. 2P pad does not have any facilities or surface line hookups, and the pad is slated to be used as storage for the Willow development project in 2026. The objective of this procedure is to stop the OA pressurization that builds up to ~170 psi within 2 days, and continue to fully P&A. BOP configuration: Annular/Variable Bore Rams/Blind Rams/Pipe Rams Following subject to change/be updated with pre-rig work: Meltwater Formation: Reservoir pressure 4/19/2018 = 2942 psi @ 5533 TVD MASP = 0 psi (Cemented) C-80 Formation: OA Pressure = 366 psi (9/2/24) (cemented OA, assume diesel gradient) MASP = 949 psi using 0.1 psi/ft gas gradient Intermediate plug TOC = 2244 (SL Tagged) Tubing cut depth = 3050 RKB Most recent tests: MIT-T 11/28/25 to 1500psi DDT-OA 12/14/25 to Vac/128 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355/325-587 Page 2 of 6 Pre-Rig Work 1. Prepare well within 48 hrs of rig arrival. Rig Work MIRU 1. MIRU Nabors 7es on 2P-447. 2. Record shut-in pressures on the T & OA. If there is pressure, bleed off OA and/or tubing pressure and complete 30-minute NFT. Verify well is dead. 3. ND Tree, NU BOPE and test to 250/2,500 psi. Test annular 250/2,500 psi. a. Will not set BPV due to three test cement plugs below providing barriers to formation. b. BOPE Configuration: Annular/Variable Bore Rams/Blind Rams/Pipe Rams ***The following work has been performed*** Remove cement from Production Casing 4. PU 6-1/8 Steeltooth Tricone to remove cement from the upper plug a. Slickline tagged top of cement ~ 2369 MD, drill down to ~2900 MD b. Gator Tool punches from 2780-2930, with CIBP @ 2950 MD c. Circulate hole clean for following slickline run 5. RU Slickline/Eline a. CBL log from 2900 MD to surface b. NOTE: Cement in place i. 94 bbls of 12# Class G Arcticrete Cement down squeezed OA on rig: OA is 76 bbls ii. 163 bbls of 12# Class G Arcticrete Cement through stage collar @ 3108 MD iii. No returns during stage job: OA OBSTRUCTED w/ CEMENT @ SURFACE - 11/12/12 iv. PWC was attempted 7/13/25 (38 bbls Class G cement). A passing MIT was obtained (1500psi), however the OA has repressurized. Section Mill Production Casing 6. PU Baker Hughes Heavy Metal Section Milling BHA a. Tool is assembled to mill a 50 section 7. RIH to set the milling knives ~2740 MD, and mill up to 2690 MD. Actual footage: 2655-2710 RKB a. Expecting 4-6/hr 8. Confirm there is communication to the permeable zone Cementing OA at the Surface Casing Shoe Changed to balance plug; approved 11/22/25 9. PU Cement Retainer, set @ 2650 MD. Using a cement retainer has a higher probability of squeezing cement into what appears to be a micro-annulus that allows the OA to build pressure over several days. a. Cement volume ~ 11.5 bbls (2900 MD to 50 above retainer) b. Prepare a 25 bbl batch of 15.8 ppg cement prepped for gas migration retardant. Cement retainer depth and volume to be modified on CBL log results 10. Pump cement through retainer, leaving 50 of cement on top of retainer 11. When cement has reached 500 psi compressive strength, based on refrigerator and model samples. Conduct OA DDT test. 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355/325-587 Page 3 of 6 Cementing Upper OA & Surface Cap Not performed; approval to pause & RDMO; approved 11/28/25 12. MU Gator perforator (570 version, 4 blade) 13. Make 2 perforations every 3 ft, starting above the top of cement till circulation is established through the OA to surface. 14. Prepare a minimum of 250 bbl batch of 15.8 ppg cement prepped for gas migration retardant a. IA = 99 bbl, OA = 73 bbls b. 150% excess 15. Circulate around and establish stable parameters, and remove ArcticPack a. May require a hot diesel circulation 16. Pump cement around filling OA and Production Casing. a. Adequate for surface abandonment procedures 17. Wait on cement, conduct DDT/MIT and IA/OA 18. ND BOPE. NU dry hole tree. Freeze protect WH/tree with diesel. 19. RDMO. ***The following is New Procedure*** Remove cement from Production Casing 20. PU 6-1/8 Steeltooth Tricone to remove cement from the upper plug a. Tagged top of cement ~ 2244 MD, drill down to ~2716 MD Section Mill Production Casing/Cement Removal 21. PU Baker Hughes Heavy Metal Section Milling BHA 22. RIH to set the milling knives ~2660 MD, and mill down to 2716 MD. a. Expecting 4-6/hr 23. RIH with under-reamer to clean out to Surface Casing ID; ream from 2660 to 2716 Cementing OA at the Surface Casing Shoe 24. PU Inflate/Cement Retainer, set @ 2675 MD. a. Cement volume ~ 5.6 bbls (2716 MD to 2640, 50 above retainer) i. Depending on injection pressures we may lead with a NaSi pill to aid in achieving cement injection pressure b. Prepare a 33 bbl batch of 15.8 ppg cement prepped for gas migration retardant. c. If the Inflate fails initial 1000 psi pressure test, the rig will set a cement retainer in the 7 casing ~2650 RKB and increase the cement batch to 40 bbls. 25. Pump cement through retainer, leaving 50 of cement on top of retainer 26. When cement has reached 500 psi compressive strength, based on refrigerator and model samples. Conduct OA DDT test. Removing cement, not milling casing - VTL 12/16/25 State witnessed tag and pressure test. VTL 12/16/2025 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355/325-587 Page 4 of 6 Cementing Upper OA & Surface Cap 27. MU Baker Hughes Multi-string cutter 28. Cut 7 production casing ~260 RKB, remove from hole 29. Set 9-5/8 Cast Iron Bridge Plug At 250 RKB a. Pressure Test to 1000 psi for 10 min. 30. Run in and land 4-1/2 kill string with hanger. Install packoff and RILDS. 31. Nipple down BOPs. NU old 4-1/16 tree. a. Pressure up against cement plug to PT tree flange breaks to 1,000 psi for 10 minutes. 32. RU cementing equipment. 33. Circulate through tree, taking returns from OA valve. Circulate 2 STS of seawater to condition wellbore for cementing. 34. Pump cement surface to surface through the tree taking returns from OA valve until clean cement returns are 35. observed. a. Cement volume will depend on depth of CIBP; ~19 bbls. 36. Prepare a minimum of 28 bbl batch of 15.8 ppg cement prepped for gas migration retardant a. IA = 4 bbl, OA = 15 bbls b. 150% excess 37. Circulate around and establish stable parameters 38. Pump cement around filling OA and Production Casing. a. Adequate for surface abandonment procedures: 150 TVD 39. Wait on cement, conduct DDT/MIT and IA/OA 40. RDMO. Surface Excavation 1. DHD to perform drawdown test on tubing, IA, and OA 2. Remove well house. 3. Bleed off T/I/O to ensure all pressure is bled off the system. 4. Remove tree in preparation for excavation and casing cut. 5. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent loose ground from falling into the excavation. 6. Cut off wellhead and all casing strings at 4 feet below original ground level. 7. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 8. Send the casing head with stub to materials shop. Photo document. 9. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 2P-447 c. PTD #: 203-154 d. API #: 50-103-20468-00-00 10. Remove cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 11. Obtain site clearance approval from AOGCC. RDMO. 12. Report the final P&A has been completed to the AOGCC. Photo document final location condition after work is completed 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355/325-587 Page 5 of 6 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355/325-587 Page 6 of 6 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Updated TOC after slickline tag 2P-447 8/21/2025 rmoore22 Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC Upper Intermediate 7 6.28 0.0 2,655.0 2,287.4 26.00 L-80 BTC-MD Lower intermediate 7 6.28 2,728.0 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 3,050.0 Set Depth 7,466.0 Set Depth 5,254.5 String Max No 4 1/2 Tubing Description Tubing Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,800.0 2,373.5 53.60 CIBP CIBP RIH by Baker, set @ 2800' top of plug. J-1 CIBP 11/20/2025 0.000 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 2,780.0 2,810.0 2,361.6 2,379.4 7/4/2025 12.0 APERF 4.5" GUNS, 12 SPF, 45 DEGREE PHASE, W/ GEO 23 GRAM CHARGES 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 2P-447, 12/15/2025 11:53:55 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB APERF; 7,600.0-7,640.0 RPERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 SURFACE; 28.1-2,705.6 Upper Intermediate; 0.0-2,655.0 Plug Plug Back / Abandonment Plug; 2,244.0 ftKB Cement Casing; 34.0 ftKB Cement Off 7 x 9 5/8; 0.0 ftKB CONDUCTOR; 30.0-108.0 KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 34.0 2,705.0 34.0 2,317.1 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 105Drag up (lbs): 120Time started reciprocating: 05:30Time stopped reciprocating: 12:10Cement Found Between Shoe and Collar (Y/N): NCement found on liner tool (Y/N): NAnnular flow after cement job (Y/N): NPressure before cementing (psi): 325Hours circulated between stages: 4Bbls cmt to surf: 161.8Method used to measure density: DensometerMethod used for mixing cement in this stage: TUBReturns (pct): FullTime cementing mixing started: 11:10 12/8/2003 0.0 2,705.0 0.0 2,317.1 Cement Off 7 x 9 5/8 Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NMethod used for mixing cement in this stage: FlyTime cementing mixing started: 22:58 12/21/2003 4,648.0 7,562.0 3,520.6 5,305.9 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NPressure before cementing (psi): 310Hours circulated between stages: 2.5Bbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): 0Time cementing mixing started: 09:45 12/21/2003 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NBbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: on FlyPressure left on after job (psi): 3Returns (pct): 0Time cementing mixing started: 19:42 12/21/2003 7,415.0 8,010.0 5,226.0 5,546.3 Cement Liner Pipe movement: Rotate & RecipDrag down (lbs): 87Drag up (lbs): 148Time started reciprocating: 08:45Time stopped reciprocating: 12:00Time started rotating: 08:45Time stopped rotating: 12:00Init torque (ft-lbf): 5500Max torque (ft-lbf): 5500Annular flow after cement job (Y/N): NPressure before cementing (psi): 700Hours circulated between stages: 2.5Bbls cmt to surf: 10Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): FullTime cementing mixing started: 10:30 12/25/2003 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2,244.0 2,800.0 2,030.7 2,373.5 Plug Plug Back / Abandonment Plug 23 BBLS 15.8 PPG CMNT pumped on 11/24/25 F/ 2728'- 2150' AOGCC witnessed tag @ 2244' along with 1500 psi 30 min test 11/24/2025 2,900.0 2,950.0 2,433.1 2,463.3 Cement Plug WASH/LAY IN 15.8 PPG CLASS G CEMENT PLUG FROM 2950-2480' 7/13/2025 2P-447, 12/15/2025 11:53:55 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB APERF; 7,600.0-7,640.0 RPERF; 7,600.0-7,640.0 CIBP; 7,574.5 Lower intermediate; 2,728.0- 7,562.0 TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 Cement Plug; 2,900.0 ftKB APERF; 2,811.5-2,930.0 CIBP; 2,800.0 APERF; 2,780.0-2,810.0 SURFACE; 28.1-2,705.6 Upper Intermediate; 0.0-2,655.0 Plug Plug Back / Abandonment Plug; 2,244.0 ftKB Cement Casing; 34.0 ftKB Cement Off 7 x 9 5/8; 0.0 ftKB CONDUCTOR; 30.0-108.0 KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 Originated: Delivered to:4-Dec-25Alaska Oil & Gas Conservation Commiss04Dec25-NR !"#$$%$ !&$$'($) *%+ ($)*%,-.WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED2P-447 50-103-20468-00-00 203-154 Kuparuk River WL IBC-CBL FINAL FIELD18-Nov-253S-08&50-103-20450-03-00 207-163 Kuparuk River WL Cutter FINAL FIELD 21-Nov-253S-09 50-103-20432-00-00 202-205 Kuparuk River WL Cutter FINAL FIELD 22-Nov-253S-705 50-103-20915-00-00 225-047 Kuparuk River WL TTiX-iPROF-SCMT FINAL FIELD 28-Nov-253S-721 50-103-20911-00-00 225-025 Kuparuk River WL TTiX-iPROF FINAL FIELD 1-Dec-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1Please return via courier or sign/scan and email a copy to Schlumberger."2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8" ! - +"8#!(3 . 8)"3 8#!9 3 : 8" +868 8 "8#!;" " 3 - 3" 3""+ 3 + <+3!% T41188T11189T41190T41191T411922P-44750-103-20468-00-00203-154Kuparuk RiverWLIBC-CBLFINAL FIELD18-Nov-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.12.05 11:22:02 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Loepp, Victoria T (OGC) To:Ohlinger, James J Cc:McLellan, Bryan J (OGC) Subject:KRU 2P-447(PTD 203-154, Sundry 325-587) and KRU 2P-406(PTD 204-022, Sundry 325-589) APPROVAL Date:Tuesday, October 28, 2025 12:33:28 PM Attachments:2P-447_406 Sundry Letter.docx James, The outlined modifications to the approved sundries are approved. Please include this approval with each of your copies of the approved sundries. Thank you, Victoria Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Ohlinger, James J <James.J.Ohlinger@conocophillips.com> Sent: Tuesday, October 28, 2025 8:45 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: 2P-447 and 2P-406 Sundry Please find the attached updates to the Sundries listed. James J. Ohlinger CPAI CTD Staff Engineer Office: 907-265-1102 Cell: 907-229-3338 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 27, 2025 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: We are expecting to move the rig to 2P-406 after 2T-208 which is to begin operations shortly, so we estimate to begin Nov. 1st-7th. Recently ConocoPhillips submitted and received sundries for 2P-406 (325-589) and 2P-447 (325-587). The basic operations are summarized as: Plan • Drill out cement • IBC/DSLT (CBL) logging tool • Section Mill casing • Set cement retainer • Pump cement • Pressure test OA • Punch casing • Cement casing and OA to surface We are writing the operational procedural and have had several meetings to discuss lessons learned and best practices. Upon review, we’d like to discuss a few variables that may or may not affect the original sundry. Section Milling – We are relying on the IBC/DSLT log to depict where we section mill. The preference is to complete the 50' of section milling entirely above the Surface Casing shoe to repair inadequate cement within the surface casing. My sundry application has it described to mill from 10-14’ inside the surface casing down, for a 50’ total. Cementing – The base plan is to set a cement retainer above the section milled area; however a balanced plug may be required. We have developed a list of pros/cons for either option and will let wellbore conditions and injection rate determine if a cement retainer or balanced plug is used. Cement retainer • if we see high flow rate into the OA with low pressure • Ability to apply and keep pressure, perform hesitation squeezes • Only limited to amount of cement available at surface Cement Plug • low rate with high injection pressure • Just as good if we have circulation • Faster and less rig up equipment • Can easily mill out if needed Cementing – This concept applies to 2P-406. Currently the OA DDT test will pass after the OA pressure is bleed off and monitored for an hour. It takes several days to build any pressure; i.e. between 7/29 and 7/31 it built 13 psi. If we are able to verify injectivity through the existing cement down squeeze in the Surface Casing, we request the ability to utilize an option to cut and pull the production casing above the TOC within the Surface casing. This would be followed by utilizing a kill string to pump cement from the casing cut to surface and squeezing cement down through the inadequate cement. Please let us know if you have questions, comments, or suggestions. James Ohlinger CTD/RWO Staff Engineer CPAI Drilling and Wells 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9.625" L-80 2317' 7" L-80 5306' 3-1/2" L-80 5546' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 7562' SIZE DEPTH SET (MD) 8010' 25' 5226' 62.5# 40# 108' 25' Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 51 bbls 15.8ppg Class G cement 2369-2950' Wash/Lay in 15.8 ppg Class G Cement Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing 5715' (SW TOC)-7313' MD 7509-7575' SUSPENDED 2780-2810' MD and 2362-2379' TVD (below cement plug) 2812-2930' MD and 2380-2451' TVD (below cement plug) 7600-7640' MD and 5325-5346' TVD (below cement plug) 7700-7780' MD and 5376-5419' TVD (below cement plug) 7780-7800' MD and 5419-5430' TVD (below cement plug) Gas-Oil Ratio:Choke Size: Dump bailed cement on CIBP Per 20 AAC 25.283 (i)(2) attach electronic information 7429' MD/ 5234' TVD (seal assembly) PACKER SET (MD/TVD) 42" 12.25" 7.6 bbl AS I 28'446 sx AS Lite, 284 sx LiteCrete 9.2# 30' 7415' 2706'28' 30' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# WT. PER FT.GRADE 12/24/2003 CEMENTING RECORD 5864553 1377' MD/ 1352' TVD SETTING DEPTH TVD 5864223 TOP HOLE SIZE AMOUNT PULLED 441203 441011 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A BOTTOM Kuparuk River Field/ Meltwater Oil Pool- Suspended N/A 50-103-20468-00-00 KRU 2P-447 ADL0373112, ADL0389058 1017' FNL, 1603' FWL, Sec. 17, T8N, R7E, UM 396' FNL, 930' FEL, Sec. 19, T8N, R7E, UM ALK 32092/ 32409 12/6/2003 8015' MD/ 5549' TVD 2369' MD/2111' TVD P.O. Box 100360, Anchorage, AK 99510-0360 443562 5868863 65' FNL, 739' FEL, Sec. 19, T8N, R7E, UM 9. Ref Elevations: KB: 28' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 8/20/2025 203-154/ 324-591 ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 150 sx Class G6.125" TUBING RECORD 165 sx Class G w/GasBlok, 340 sx ArcticCrete8.5" 7415' MD/ 5226' TVD 7466' MD4-1/2" CASING Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 11:10 am, Oct 06, 2025 Suspended 8/20/2025 JSB RBDMS JSB 102725 xGDSR-11/26/25SFD 1/14/2026 GL: 224' DF: 252' SFD Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1377' 1352' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Jill Simek Digital Signature with Date:Contact Email:Jill.Simek@conocophillips.com Contact Phone:(907) 263-4131 Staff Interventions Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A- Suspended Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Authorized Name and Authorized Title: N/A - Suspended Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. INSTRUCTIONS Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Jill Simek Digitally signed by Jill Simek Date: 2025.10.06 10:41:06 -08'00' Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Updated TOC after slickline tag 2P-447 8/21/2025 rmoore22 Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 3,050.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description Tubing – Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 2,780.0 2,810.0 2,361.6 2,379.4 7/4/2025 12.0 APERF 4.5" GUNS, 12 SPF, 45 DEGREE PHASE, W/ GEO 23 GRAM CHARGES 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 2P-447, 10/3/2025 1:06:13 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 APERF; 2,780.0-2,810.0 SURFACE; 28.1-2,705.6 Cement Plug; 2,369.0 ftKB Cement Casing; 34.0 ftKB Cement Off 7 x 9 5/8; 0.0 ftKB CONDUCTOR; 30.0-108.0 KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 34.0 2,705.0 34.0 2,317.1 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 105Drag up (lbs): 120Time started reciprocating: 05:30Time stopped reciprocating: 12:10Cement Found Between Shoe and Collar (Y/N): NCement found on liner tool (Y/N): NAnnular flow after cement job (Y/N): NPressure before cementing (psi): 325Hours circulated between stages: 4Bbls cmt to surf: 161.8Method used to measure density: DensometerMethod used for mixing cement in this stage: TUBReturns (pct): FullTime cementing mixing started: 11:10 12/8/2003 0.0 2,705.0 0.0 2,317.1 Cement Off 7 x 9 5/8 Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NMethod used for mixing cement in this stage: FlyTime cementing mixing started: 22:58 12/21/2003 4,648.0 7,562.0 3,520.6 5,305.9 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NPressure before cementing (psi): 310Hours circulated between stages: 2.5Bbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): 0Time cementing mixing started: 09:45 12/21/2003 Cement Casing Stage Pipe movement: ReciprocatingDrag down (lbs): 90000Drag up (lbs): 230000Time started reciprocating: 07:00Time stopped reciprocating: 12:15Annular flow after cement job (Y/N): NBbls cmt to surf: 0Method used to measure density: DensometerMethod used for mixing cement in this stage: on FlyPressure left on after job (psi): 3Returns (pct): 0Time cementing mixing started: 19:42 12/21/2003 7,415.0 8,010.0 5,226.0 5,546.3 Cement Liner Pipe movement: Rotate & RecipDrag down (lbs): 87Drag up (lbs): 148Time started reciprocating: 08:45Time stopped reciprocating: 12:00Time started rotating: 08:45Time stopped rotating: 12:00Init torque (ft-lbf): 5500Max torque (ft-lbf): 5500Annular flow after cement job (Y/N): NPressure before cementing (psi): 700Hours circulated between stages: 2.5Bbls cmt to surf: 10Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): FullTime cementing mixing started: 10:30 12/25/2003 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2,369.0 2,950.0 2,111.3 2,463.3 Cement Plug WASH/LAY IN 15.8 PPG CLASS G CEMENT PLUG FROM 2950-2480' 7/13/2025 2P-447, 10/3/2025 1:06:14 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 Cement Liner; 7,415.0 ftKB RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Casing Stage ; 4,648.0 ftKB Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 APERF; 2,780.0-2,810.0 SURFACE; 28.1-2,705.6 Cement Plug; 2,369.0 ftKB Cement Casing; 34.0 ftKB Cement Off 7 x 9 5/8; 0.0 ftKB CONDUCTOR; 30.0-108.0 KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 SUNDRY NOTICE 10-407 ConocoPhillips Well 2P-447 Plug and Abandonment October 1, 2025 ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 2P-447, per Sundry #325-355. After PWC steps were performed, the P&A program was aborted due to failing drawdown tests on the OA. This 10-407 will close out P&A activities to this point. A rig will be used to finish the abandonment activities, under a separate sundry application. DT T M S T A R T JO B T Y P S U M M A R Y O P S 6/ 2 2 / 2 0 2 5 CH A N G E W E L L TY P E W A I T F O R A P L A C E T O G O , T R A V E L T O 2 P , M I R U . R I H L A T C H W R P , R E L E A S E . R I H D R I F T W I T H 6" O D W R P T O T A G A T 2 , 9 3 9 ' C T M D . P O O H W I T H P L U G . F P T O 2 0 0 0 ' W I T H D I E S E L . J O B I N PR O G R E S S . 6/ 2 3 / 2 0 2 5 CH A N G E W E L L TY P E LA Y D O W N P L U G A N D B H A . R I G D O W N 7 I N C H G E A R N O R M A L U P W E L L H E A D . J O B I N PR O G R E S S . R E A D Y F O R E - L I N E . 7/ 4 / 2 0 2 5 CH A N G E W E L L TY P E PE R F O R A T E F R O M 2 7 8 0 ' - 2 8 1 0 ' W / 4 . 5 " G U N S L O A D E D 1 2 S P F , 4 5 D E G P H A S I N G W / G E O 2 3 GR A M C H A R G E S LO G C O R R E L A T E D T O P E R F O R A T I O N S D O N E O N R I G F R O M 2 8 1 1 . 5 ' - 2 9 3 0 ' W E L L L E F T S E C U R E 7/ 1 1 / 2 0 2 5 CH A N G E W E L L TY P E MI R U C T U 6 W / 1 1 , 5 0 0 ' O F 2 " C T , M P F P U M P , & S U P P O R T E Q U I P M E N T . R I G U P H Y D R A U L I C CU T T E R & B E G I N C U T T I N G 1 0 0 0 ' O F C T ( H A L L I B U R T O N M I C R O B O N D T O B L E N D C E M E N T W I L L NO T B E A V A I L A B L E U N T I L N O O N T O M O R R O W ) . I N P R O G R E S S . 7/ 1 2 / 2 0 2 5 CH A N G E W E L L TY P E CO M P L E T E D C U T T I N G 1 0 0 0 ' O F C T ( C T U 6 N O W H A S 1 0 , 5 0 0 ' O F 2 " C T w / 2 6 . 8 F U V ) , C H A N G E PA C K O F F S , & P E R F O R M B O P T E S T . DR I F T W / 5 . 8 7 5 D R I F T D O W N T O T O P O F C I B P @ 2 9 5 0 ' R K B ( A B L E T O I N J E C T I N T O W E L L @ 1 . 5 BP M W / 6 0 0 W H P , A B L E T O B L E E D W H P T O Z E R O & R E T U R N S T O 3 5 0 P S I I N 3 0 M I N . R I H W / 5. 8 7 5 " H Y D R A W E L L P O W E R W A S H C E M E N T B H A W / M I D N I G H T D E P T H O F 2 0 0 0 ' . I N P R O G R E S S . 7/ 1 3 / 2 0 2 5 CH A N G E W E L L TY P E TA G @ 2 9 5 0 ' R K B . P E R F W A S H 2 9 3 0 ' - 2 7 8 0 ' . U P / D O W N / U P / D O W N P E R P R O C E D U R E P U M P I N G SL I C K F R E S H W A T E R A T 3 . 5 0 B P M . W A S H / L A Y I N 6 8 B B L S O F C L A S S G C E M E N T U P T O 1 2 9 0 ' RK B . C L E A N O U T D O W N T O C E M E N T T O P @ 2 4 8 0 ' . I N P R O G R E S S . 7/ 1 4 / 2 0 2 5 CH A N G E W E L L TY P E FR E E Z E P R O T E C T W E L L F R O M 2 4 7 5 ' W / D I E S E L . R E A D Y F O R T A G n ' T E S T I N 4 8 H O U R S ( T O C - 24 8 0 ' ) 7/ 1 6 / 2 0 2 5 CH A N G E W E L L TY P E (P & A ) B L E E D O A ( I N P R O G R E S S ) 7/ 1 6 / 2 0 2 5 CH A N G E W E L L TY P E PE R F O R M E D A M I T - T T O 1 5 0 0 P S I , * P a s s * . R E A D Y F O R S L I C K L I N E S T A T E W I N T N E S S T A G n ' TE S T . 7/ 2 0 / 2 0 2 5 CH A N G E W E L L TY P E (P & A ) B L E E D O A T O 0 P S I A N D M O N I T O R F O R 3 0 M I N ( C O M P L E T E ) 7/ 2 2 / 2 0 2 5 CH A N G E W E L L TY P E (P & A ) O A D D T T O 0 P S I . ( I N P R O G R E S S ) 7/ 2 3 / 2 0 2 5 CH A N G E W E L L TY P E (P & A ) O A D D T T O 0 P S I ( I N P R O G R E S S ) 8/ 2 0 / 2 0 2 5 CH A N G E W E L L TY P E AO G C C W I T N E S S : J O S H H U N T TA G T O C @ 2 3 6 9 ' S L M , O B T A I N P A S S I N G M I T - T 1 5 0 0 P S I 2P - 4 4 7 S u s p e n d / P l u g a n d A b a n d o n Su m m a r y o f O p e r a t i o n s 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): Effective Depth MD: Effective Depth TVD: Junk (MD): 8015' 2949' 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 (907) 265-1102 Staff CTD Engineer KRU 2P-447 5549' 2369' 2111' 2369', 2950', 5715', 7509', 7574' N/A 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: James.J.Ohlinger@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A James Ohlinger STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst 7466' MD 108' 2317' 5306' 108' 2706' 16" 9-5/8" 78' 7"7537' 2677' 7562' 2780-2810', 2812-2930', 7600- 7640', 7700-7800' (below cement plug) 3-1/2" 2362-2379', 2380-2451', 5325- 5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 10/27/2025 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 m n Pe R 4 C 5 P itClass: Se L C t P N/A d f We o 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 11:08 am, Sep 30, 2025 Digitally signed by James J. Ohlinger DN: CN=James J. Ohlinger, E=James.J.Ohlinger@ cop.com Reason: I am the author of this document Location: Date: 2025.09.30 10:17:41-08'00' Foxit PDF Editor Version: 13.1.6 James J. Ohlinger 325-587 Surface cement plug must be minimum of 150' in length, extending to ground surface. Weight test TOC to 15 klbs and pressure test CMIT IAxOA to 2000 psi. Provide AOGCC 24 hrs notice. XX A.Dewhurst 14OCT25 OA DDT spans at least 24 hrs after cement is circulated in place. Provide 24 hrs for AOGCC to witness last 1 hr of DDT. Submit results of DDT and obtain approval from AOGCC before perforating for surface cement job. DSR-10/15/25 BOP test to 2500 psi. BJM 10/21/25 10-407 Record daily wellhead pressure readings for 30 days after placing cement plugs. Report any signs of sustained casing pressure to AOGCC. 10/22/25 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355 1 5 General Well info Estimated Start Date: 10/27/25 Workover Engineer: James J Ohlinger (+1-907-265-1102/ James.J.Ohlinger@conocophillips.com) Current Operations: This well is Suspended as of 11/23/24 Well Type: Injector History: 2P-447 was an injector that has been shut in since mid-2021. This well has been suspended with a reservoir cement plug and an intermediate cement plug (covered in a separate 10-403). The steps outlined in sundry 324-627 included pulling the tubing from a pre-rig cut, setting a plug across the C80 formation, and Perforating below the surface casing shoe on Nordic 3 in preparation for a perf/ wash/ cement job to isolate the C80 formation. The PWC was attempted 7/13/25 (38 bbls Class G cement). A passing MIT was obtained (1500psi), however the OA has repressurized. There was an OA down squeeze performed on rig 12/21/2003 with 94 Barrels (197sx @ 12ppg) of ArctiCrete Cement. The last passing MIT-OA was 2/24/2022, but now slowly repressurizes. 2P pad does not have any facilities or surface line hookups, and the pad is slated to be used as storage for the Willow development project in 2026. The objective of this procedure is to stop the OA pressurization that builds up to ~170 psi within 2 days, and continue to fully P&A. BOP configuration: Annular/Variable Bore Rams/Blind Rams/Pipe Rams Following subject to change/be updated with pre-rig work: Meltwater Formation: Reservoir pressure 4/19/2018 = 2942 psi @ 5533 TVD MASP = 0 psi (Cemented) C-80 Formation: OA Pressure = 366 psi (9/2/24) (cemented OA, assume diesel gradient) MASP = 949 psi using 0.1 psi/ft gas gradient Intermediate plug TOC = 2369 (SL Tagged) Tubing cut depth = 3050 RKB Most recent tests: MIT-T 8/20/25 to 1500psi Intial I/O = 0/275 DDT-OA 7/23/25 to Vac/171, 30 mins Vac/42 psi 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355 2 5 Pre-Rig Work Rig Work MIRU Remove cement from Production Casing Section Mill Production Casing Cementing OA at the Surface Casing Shoe 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355 3 5 Cementing Upper OA & Surface Cap Minimum surface cement plug must be 150' in length, extending to ground level. -bjm 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355 4 5 2P-447 RWO Procedure KUPARUK RIVER UNIT Producer PTD #203-154 Sundry #325-355 5 5 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Updated TOC after slickline tag 2P-447 8/21/2025 rmoore22 Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 3,050.0 Set Depth 7,466.0 Set Depth 5,254.5 String Max No 4 1/2 Tubing Description Tubing Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 2,780.0 2,810.0 2,361.6 2,379.4 7/4/2025 12.0 APERF 4.5" GUNS, 12 SPF, 45 DEGREE PHASE, W/ GEO 23 GRAM CHARGES 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 2P-447, 8/21/2025 4:39:23 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 APERF; 2,780.0-2,810.0 SURFACE; 28.1-2,705.6 Cement Plug; 2,369.0 ftKB CONDUCTOR; 30.0-108.0 KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2,369.0 2,950.0 2,111.3 2,463.3 Cement Plug WASH/LAY IN 15.8 PPG CLASS G CEMENT PLUG FROM 2950-2480' 7/13/2025 2P-447, 8/21/2025 4:39:23 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 APERF; 2,780.0-2,810.0 SURFACE; 28.1-2,705.6 Cement Plug; 2,369.0 ftKB CONDUCTOR; 30.0-108.0 KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Loepp, Victoria T (OGC) To:Jill Simek Cc:Greg S Hobbs; Lau, Jack J (OGC) Subject:Re: 2P-447 P&A Next Steps (PTD#203-154/Sundry#324-591)APPROVAL Date:Thursday, August 21, 2025 3:03:32 PM Jill, Approval is granted for the milling steps. Please include this approval with your copy of the approved sundry. Based on your evaluation, a change of approved program will be required for further work. Victoria Sent from my iPhone On Aug 21, 2025, at 2:50 PM, Simek, Jill <jill.simek@conocophillips.com> wrote: Victoria, On July 12-13, 2025, Perforate/Wash/Cement operations were performed on 2P-447, per Approved Sundry #324-591. Unfortunately, the PWC plug has failed, as evidenced by a failed extended drawdown test on the OA. ConocoPhillips requests permission to mill out cement in the production casing, for further evaluation of the failed PWC plug. Next steps will be determined after this evaluation, and a 10-403 Change of Approved Sundry will be submitted accordingly. Please let me know if milling steps are approved. Thank you, Jill Simek Well Interventions Engineer | ConocoPhillips Alaska ATO-1400 M: 907-980-7503 / O: 907-263-4131 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:19 Township:8N Range:7E Meridian:Umiat Drilling Rig:Rig Elevation:Total Depth:8015 ft MD Lease No.:ADL0373112 Operator Rep:Suspend:X P&A: Conductor:16"O.D. Shoe@ 108 Feet Csg Cut@ Feet Surface:9-5/8"O.D. Shoe@ 2706 Feet Csg Cut@ Feet Intermediate:7"O.D. Shoe@ 7562 Feet Csg Cut@ Feet Production:O.D. Shoe@ Feet Csg Cut@ Feet Liner:3-1/2'O.D. Shoe@ 8010 Feet Csg Cut@ Feet Tubing:4-1/2"O.D. Tail@ 7466 Feet Tbg Cut@ 3080 Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Annulus Bridge plug 2950 ft 2369 ft 6.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1515 1420 1385 IA 1515 1420 1385 OA 275 275 275 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Ryan Moore Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): See attached August 20, 2025 Josh Hunt Well Bore Plug & Abandonment KRU 2P-447 ConocoPhillips Alaska PTD 2031540; Sundry 324-591 Remarks; Photo Test Data: P Casing Removal: rev. 3-24-2022 2025-0820_Plug_Verification_KRU_2P-447_jh                     2025-0820_Plug_Verification_KRU_2P-447_remarks_jh Page 1 of 1 Plug Verification – KRU 2P-447 (PTD 2031540) AOGCC Inspector J. Hunt 8/20/2025 I was already at KRU 2P for the other plug verifications. Ryan Moore and I went over the Sundry and plan forward for this well. This is the third plug in a series of four. A standard BHA was rigged up, consisting of oil jar, weight pipe, and a 1.75-inch ID bailer and a 2.70- inch OD stabilizer. This BHA assembly was about 30 feet in length and weighed about 200 lbs. They ran in the hole without issue and tagged the TOC at 2369 feet MD. I had them hit it several times, the depth stayed the same. Photo - Very little cement was observed in/on the bailer. ORIGINATED TRANSMITTAL DATE: 7/30/2025 ALASKA E-LINE SERVICES TRANSMITTAL #: 5550 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk River PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5550 2P-447 50103204680000 Perf Record 4-Jul-2025 RECIPIENTS Conoco DIGITAL FILES PRINTS CD'S 1 FTP Transfer 0 0 USPS Attn: NSK-69 lorna.c.collins@conocophillips.com 700 G Street Anchorage, AK 99503 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 203-154 T40726 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.30 15:10:05 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com 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: Extend Suspension Date 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): 8015'2949' 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 (907) 265-1053 Senior Well Integrity Engineer KRU 2P-447 5549' 2500' 2194' 2500', 2950', 5715', 7509', 7574' N/A 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: Jaime.Bronga@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Jaime Bronga STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Suspended TVD Burst 7466' MD 108' 2317' 5306' 108' 2706' 16" 9-5/8" 78' 7"7537' 2677' 7562' 7600-7640', 7700-7800' (below cement plug) 3-1/2" 5325-5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 6/30/2025 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Jaime Bronga DN: OU=Conoco Phillips Alaska, CN=Jaime Bronga, E=jaime.bronga@conocophillips.com Reason: I am the author of this document Location: Date: 2025.06.10 16:02:23-08'00' Foxit PDF Editor Version: 13.1.6Jaime Bronga 325-355 By Grace Christianson at 8:41 am, Jun 11, 2025 none December 31, 2025Well abandonment must be complete by 12/31/2025. DSR-6/18/25VTL 6/11/2025 A.Dewhurst 20JUN25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.24 06:12:46 -08'00'06/24/25 RBDMS JSB 062425 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 10, 2025 Commissioner Jessie Chmielowski Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Chmielowski, Please find the attached 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. well KRU 2P-447 (PTD 203-154). We are requesting to Extend the Suspension date to December 31, 2025, to complete the Plug and Abandon procedure. If you need additional information, please contact us at 265-1053. Sincerely, Jaime Bronga Well Integrity Engineer ConocoPhillips Alaska, Inc. Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added jet cut at 3080' RKB 2P-447 10/6/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 3,050.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description Tubing – Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,500.0 2,193.7 52.00 WRP WRP, set by Yellowjacket, baited for Wireline retieve 11/22/2024 0.000 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2P-447, 6/10/2025 10:27:38 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 SURFACE; 28.1-2,705.6 WRP; 2,500.0 CONDUCTOR; 30.0-108.0 KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 1 Gluyas, Gavin R (OGC) From:Lau, Jack J (OGC) Sent:Friday, January 17, 2025 9:31 AM To:AOGCC Records (CED sponsored) Subject:FW: 2P-447 (PTD: 203-154) Perf Wash Cement - Completing Perfs Attachments:FW: 2P-447 FYI; 2P-447 PWC approved Sundry_324-591_120624.pdf From: O'Connor, Katherine <Katherine.OConnor@conocophillips.com> Sent: Friday, January 17, 2025 9:16 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: 2P-447 (PTD: 203-154) Perf Wash Cement - Completing Perfs Hello, In November the rig was unable to complete perforating the 150’ interval for the upcoming perf, wash, and cement job. Wanted to inform that E-line will finish perforating the interval from ±2810 – 2780’ KB before coil rigs up. I expect the coil work to occur mid February. Let me know if you have any concerns or questions about this operation. Thank you! Katherine O’Connor CPF2 Interventions Engineer 907-263-3718 (O) 214-684-7400 (C) CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Gluyas, Gavin R (OGC) From:Tuttle, Elliott <Elliott.Tuttle@conocophillips.com> Sent:Wednesday, January 15, 2025 2:56 PM To:O'Connor, Katherine Subject:FW: 2P-447 FYI Elliott Tuttle C: 907.252.3347 From: Tuttle, Elliott Sent: Friday, November 22, 2024 3:31 PM To: victoria.loepp@alaska.gov; Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: NSK RWO CM <NSKRWO.CM@conocophillips.com>; Glasheen, Brian <Brian.Glasheen@conocophillips.com> Subject: 2P-447 FYI Victoria, We got a total of 79 casing perforation intervals completed with the mechanical perforator and we have run into tool troubles. We still have roughly 32’ that needs to be perforated to complete the 150’ interval stated in the sundry. As of right now, we will most likely pivot to completing these perforations oƯ rig so that they can address the BHA before we attempt to perforate again. Plan forward: - Set WRBP above perforations made, test, POOH without filling hole - FP casing with diesel. - Swap stack for dry hole tree - RDMO moving over to 2P-406 We are still pulling out of hole with the second set of perforating tools and we suspect the same failure as the first. Do you feel comfortable that we will have the sundry for 2P-406 by COB today? Thank you, Elliott Tuttle | CTD/ RWO Drilling Engineer | ConocoPhillips O: 907.263.4742| C: 907.252.3347 | Desk: 1480 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9.625" L-80 2317' 7" L-80 5306' 3-1/2" L-80 5546' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 150 sx Class G6.125" TUBING RECORD 165 sx Class G w/GasBlok, 340 sx ArcticCrete8.5" 7415' MD/ 5226' TVD 7466' MD4-1/2" CASING STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 11/23/2024 203-154/ 324-627 50-103-20468-00-00 KRU 2P-447 ADL0373112, ADL0389058 1017' FNL, 1603' FWL, Sec. 17, T8N, R7E, UM 396' FNL, 930' FEL, Sec. 19, T8N, R7E, UM ALK 32092/ 32409 12/6/2003 8015' MD/ 5549' TVD 2950' MD/2463' TVD P.O. Box 100360, Anchorage, AK 99510-0360 443562 5868863 65' FNL, 739' FEL, Sec. 19, T8N, R7E, UM 9. Ref Elevations: KB: 28' WT. PER FT.GRADE 12/24/2003 CEMENTING RECORD 5864553 1377' MD/ 1352' TVD SETTING DEPTH TVD 5864223 TOP HOLE SIZE AMOUNT PULLED 441203 441011 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A BOTTOM Kuparuk River Field/ Meltwater Oil Pool- Suspended N/A 7429' MD/ 5234' TVD (seal assembly) PACKER SET (MD/TVD) 42" 12.25" 7.6 bbl AS I 28'446 sx AS Lite, 284 sx LiteCrete 9.2# 30' 7415' 2706'28' 30' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# 5715' (SW TOC)-7574' MD 51 bbls 15.8ppg Class G cement Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing SUSPENDED 7600-7640' MD and 5325-5346' TVD (below cement plug) 7700-7780' MD and 5376-5419' TVD (below cement plug) 7780-7800' MD and 5419-5430' TVD (below cement plug) Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 7562' SIZE DEPTH SET (MD) 8010' 25' 5226' 62.5# 40# 108' 25' Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 11:58 am, Dec 23, 2024 Suspended 11/23/2024 JSB RBDMS JSB 010225 xGDSR-4/7/25 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1377' 1352' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Elliott Tuttle Digital Signature with Date:Contact Email: elliott.tuttle@conocophillips.com Contact Phone:(907) 263-4742 Staff RWO/CTD Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A- Suspended Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Authorized Name and Authorized Title: N/A - Suspended Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. INSTRUCTIONS Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov 'HF Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added jet cut at 3080' RKB 2P-447 10/6/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 3,050.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description Tubing – Production Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.8 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.4 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,500.0 2,193.7 52.00 WRP WRP, set by Yellowjacket, baited for Wireline retieve 11/22/2024 0.000 2,949.0 2,462.7 52.81 FISH 3 pieces of 4" x 1" x 1" metal from Gator perfing tool broke off and left on CIBP. Drive Sleeve pieces. 11/22/2024 0.000 2,950.0 2,463.3 52.80 CIBP CIBP ran by YJOS, set @ 2950' Top of plug YJOS CIBP 11/21/2024 0.000 3,050.0 2,524.1 52.24 CUT JET CUT @ 3050' RKB 11/21/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 2,811.5 2,930.0 2,380.3 2,451.2 11/22/2024 0.0 APERF 5.70" Gator Mechanical Perforating Tool, 4 cuts at 90deg phasing at 1.5' Spacing. Rotated 45deg each cut. 79 Total perforations completed out of 100 planned. 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 2P-447, 12/19/2024 11:43:34 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 SURFACE; 28.1-2,705.6 WRP; 2,500.0 CONDUCTOR; 30.0-108.0 KUP SVC KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status SVC Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2P-447, 12/19/2024 11:43:34 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 CUT; 3,050.0 CIBP; 2,950.0 FISH; 2,949.0 APERF; 2,811.5-2,930.0 SURFACE; 28.1-2,705.6 WRP; 2,500.0 CONDUCTOR; 30.0-108.0 KUP SVC 2P-447 ... WELLNAME WELLBORE2P-447 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 23, 2024 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: Elliott Tuttle Staff Wells Engineer CPAI Drilling and Wells ConocoPhillips Alaska, Inc. would like to accompany the 10-407 submission on permit 324-627 with this letter. On Nordic 3's RU, 79 casing perforations were made out of 100 planned with the mechanical perforator due to tool troubles. We still have roughly 32’ that needs to be perforated to complete the 150’ interval stated in the sundry. We are requesting that the last 32' of perforations be addressed on permit 324-591 (Post Rig P&A Permit) since Nordic 3 has rigged down from 2P-447. If you have any questions or require any further information, please contact me at 907-252-3347. Please let us know if that is an appropriate way to proceed or if additional documentation needs to be provided. CPAI Drilling and Well Page 1/4 2P-447 Report Printed: 12/18/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 11/19/2024 12:00 11/20/2024 00:00 12.00 MIRU, MOVE MOB P Lay rig mats. Pull support equipment away from rig. RD hardline. Warm up hydraulic system. Pull rig off 2P-448 @ 16:00. Stage rig center of pad, level out cellar area due to uneven surfaces 1800 to 2130 . Lay T-mats, cellar pit liner, and dance floor @ 2P-447. Stage dry hole tree behind well. 0.0 0.0 11/20/2024 00:00 11/20/2024 05:00 5.00 MIRU, MOVE RURD P Pull rig over well. Spot in support equipment. Spot in tanks. RU hardline. RU cellar circ hardline for well kill. Work through rig acceptance checklist. Accept rig @ 05:00. Load 9.8# KW brine into pits. 0.0 0.0 11/20/2024 05:00 11/20/2024 09:00 4.00 MIRU, WELCTL RURD P Mix and heat up 35 bbl Deep Clean pill. Record Initial Pressures (T/I/O) = 0 / 0 / 340 psi. PJSM for well kill. PT hardline to tanks w/ air. Listen for leaks. Flood lines and PT hardline with brine to 3,000 psi. Bleed OA to 280 psi. Blowdown hardline. Bleed free gas F/ Tubing and IA. Pad Op on location to pump open SSV. Hook up bleed hose to OA to allow bleed off during well kill. 0.0 0.0 11/20/2024 09:00 11/20/2024 10:00 1.00 MIRU, WELCTL KLWL P PJSM. Bring pumps online @ 2 BPM / 60 psi. Ramp rate up to 4 BPM / 210 psi. Hold 100 psi back pressure at choke / blooie line. Choke @ 250 psi. Blooie @ 180 psi. Pump 30 bbls heated Deep Clean. Pump xxx BBLS 9.8# Brine. Measure clean 9.8# fluid from IA. SD Pumps. ICP = 210 psi. FCP = 397 psi. OA press during kill = 80 psi. Bleed off. Blow down lines. 0.0 0.0 11/20/2024 10:00 11/20/2024 10:30 0.50 MIRU, WELCTL OWFF P R/D cellar circ hardline from tree. OWFF for 30-min. 0.0 0.0 11/20/2024 10:30 11/20/2024 17:00 6.50 MIRU, WHDBOP NUND P ND old tree. Kick outside. Inspect hanger neck threads. Good condition. Test with blanking plug. Get 7 turns w/ 4 1/2" NSCT. Functioned LDSs. Set BPV + test dart. NU BOP. Open UPR doors. Install new Top Seals on VBR's. Close doors. 0.0 0.0 11/20/2024 17:00 11/20/2024 18:30 1.50 MIRU, WHDBOP RURD P Install flow riser. Grease valves. RU trip tank hose. RU testing equipment for shell test. Perform shell test. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 11/23/2024 Page 2/4 2P-447 Report Printed: 12/18/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 11/20/2024 18:30 11/21/2024 00:00 5.50 MIRU, WHDBOP BOPE P Initial BOPE test, Tested BOPE at 250/2500 PSI for 5 Min each, Tested annular, UVBR's, w/ 3 1/2" & 4 ½” test joints. Test blinds rams. Choke valves #1 to #13, upper and lower top drive well control valves. Test 3 1/2" IF FOSV and IBOP. Test 4 ½” EUE FOSV. Test 2" rig floor Demco kill valve MM #13. Test manual and HCR kill valves & manual and HCR choke valves. Test two ea 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure =3000 PSI, after closure = 1800 PSI, 200 PSI attained =22 sec, full recovery attained = 106 sec. UVBR's = 4 sec Annular = 20 sec. Simulated blinds = 4 sec. HCR choke & kil l= 1 sec each. 4 back up nitrogen bottles average = 2050 PSI. Test gas detectors, PVT and flow show. Witnessed waived by AOGCC Inspector Josh Hunt. 0.0 0.0 11/21/2024 00:00 11/21/2024 01:00 1.00 COMPZN, RPCOMP CLEN P Clean up floor from BOP test, prep for pulling BPV and completion 0.0 0.0 11/21/2024 01:00 11/21/2024 01:45 0.75 COMPZN, RPCOMP MPSP P Pull BPV 0.0 0.0 11/21/2024 01:45 11/21/2024 03:00 1.25 COMPZN, RPCOMP THGR P Pick up landing Jt. // Make up 3.5" IF x 4.5" XO // Make up landing jt to hanger // Set down 10K BOLDS // Pull to 250k no pipe movement // Continue to work pipe, pump SxS no abnormalities with returns 0.0 3,080.0 11/21/2024 03:00 11/21/2024 10:00 7.00 COMPZN, RPCOMP WAIT T Continue to work pipe while waiting on E -line for cut. AK E-line on location @ 10:00AM. 3,080.0 3,080.0 11/21/2024 10:00 11/21/2024 13:15 3.25 COMPZN, RPCOMP ELNE T RU EL. RIH w/ 3.50" OD Jet Cutter. Cut 4 1/2" Tubing mid joint above pre-rig cut. Cut @ 3,050'. POOH. Stand back E-line. 3,080.0 3,050.0 11/21/2024 13:15 11/21/2024 14:00 0.75 COMPZN, RPCOMP PULL T Pull hanger to rig floor @ 65K. Release E-line. L/D landing joint and 4 1/2" hanger. Prep rig floor to Pull 4 1/2" Tubing. RD AK Eline. 3,050.0 3,050.0 11/21/2024 14:00 11/21/2024 17:30 3.50 COMPZN, RPCOMP PULL P Pull and lay down 97 jts of 4.5" IBT-M tubing from cut @ 3,050', PUW = 65K. Cut Joint = 20.25'. 3,050.0 0.0 11/21/2024 17:30 11/21/2024 18:30 1.00 COMPZN, RPCOMP CLEN P Clean and clear rig floor for picking up BHA and tripping pipe 0.0 0.0 11/21/2024 18:30 11/21/2024 19:00 0.50 COMPZN, RPCOMP BHAH P Pick up 7" CIBP BHA# 1 0.0 10.0 11/21/2024 19:00 11/21/2024 20:45 1.75 COMPZN, RPCOMP TRIP P TIH w/ 7" CIBP T/ 2,950 10.0 2,950.0 Rig: NORDIC 3 RIG RELEASE DATE 11/23/2024 Page 3/4 2P-447 Report Printed: 12/18/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 11/21/2024 20:45 11/21/2024 21:30 0.75 COMPZN, RPCOMP MPSP P Set CIBP per YJOS // Up wt. 70K Dn wt. 65K // Top of plug 2950' bottom 2952' // Pinned 3500 psi // 4.5 bbls pump to catch pressure // Pressure up 1600 psi tool stroke start setting proceedure // Pressure up to 2000 psi gain 7K WOB hold for 2 min // Pressure up 2500 psi no change WOB hold for 2 min Pick up to 2K WOB // Pressure up 3600 psi tool did not shear // bleed off pump pressure // Pump back to 3800 psi no shear, pick up 5K tool shear gain circulation, top of plug set @ 2950' // Blow down TD for trip out of hole 2,950.0 2,950.0 11/21/2024 21:30 11/21/2024 22:45 1.25 COMPZN, RPCOMP TRIP P TOOH for Gator Perf Tools 2,950.0 0.0 11/21/2024 22:45 11/21/2024 23:15 0.50 COMPZN, RPCOMP PRTS P Test CIBP 2,500 psi 5 min // Pump 17 stks = .99 bbls to 2640 psi // Calculated volume to pressure up on plug @ 2,950' = 1.06 bbls 0.0 0.0 11/21/2024 23:15 11/22/2024 00:00 0.75 COMPZN, RPCOMP BHAH P PU 5.70” OD Gator Tool. MU CPAI XO #781 (3 ½” IF x 2 7/8” PAC) to top of tools 0.0 19.0 11/22/2024 00:00 11/22/2024 01:30 1.50 COMPZN, RPCOMP TRIP P TIH w/ 5.70” Gator Perforating tool go 2,930’ 19.0 2,930.0 11/22/2024 01:30 11/22/2024 05:15 3.75 COMPZN, RPCOMP PERF P Tag plug @ 2,951' space out for perf // Get baseline for perf as follows. Pits 323.5 bbls total volume. OA start pressure= 380 psi 1bpm=322psi 1.5bpm= 737psi 2 bpm = 1139psi 2.5 bpm = 1825psi 3 bpm = 2527psi 3.25 bpm = 3100psi End base test PVT= 319.2 bbls Start perfs @ 2943.3' pick up 1.5' per interval for 100 intervals. At 05:15AM, saw 25K overpull on Stage #59. Visual pressure drop (breakover) on #58 was not seen. Tool rep concerned tool may be packed w/ debris. Decide to POOH and inspect tools. Drop 1.50" ball. Sheared out at 1,400 psi. Perf indicator: When perf casing, pistons react quickly, and we see a slight pressure drop at surface. Saw drop on all perfs except #58 and #59. 2,930.0 2,843.0 11/22/2024 05:15 11/22/2024 05:45 0.50 COMPZN, RPCOMP CIRC P Circ. BU. 2,843.0 2,843.0 11/22/2024 05:45 11/22/2024 07:45 2.00 COMPZN, RPCOMP TRIP P TOOH w/ 5.7" OD Gator Tool to check tools after over pull on Stage #59 (2,843') 2,843.0 20.0 11/22/2024 07:45 11/22/2024 09:00 1.25 COMPZN, RPCOMP BHAH P L/D 5.70" Gator Tools. Found drive sleeves sheared off (3 out of 4). LIH dimensions of sheared drive sleeve, L = 4" W = 1.1" H = 1.3" (X3 dirve sleeves pieces) Discuss with Gator Tool Rep. 20.0 0.0 11/22/2024 09:00 11/22/2024 09:30 0.50 COMPZN, RPCOMP BHAH P MU backup 5.70" Gator Perf Tool. 0.0 20.0 11/22/2024 09:30 11/22/2024 12:00 2.50 COMPZN, RPCOMP TRIP P TIH w/ 5.70" OD Gator tool to 2,843'. 20.0 2,843.0 Rig: NORDIC 3 RIG RELEASE DATE 11/23/2024 Page 4/4 2P-447 Report Printed: 12/18/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 11/22/2024 12:00 11/22/2024 13:00 1.00 COMPZN, RPCOMP PERF P Obtain parameters. Cont. perfs from 2,843' to 2,811.5' (Stage #79 of 101. See 30K overpull. Worked tool free. Discussed w/ Gator Tool rep. Decide to TOOH and inspect tools. Top depth of final perf 2,811.5'. 2,843.0 2,813.0 11/22/2024 13:00 11/22/2024 13:30 0.50 COMPZN, RPCOMP CIRC P Circ STS. Call out FMC to set Upper Test Plug. Call out magnets, stem, and lifting cap w/ sucker rod to fish potential drive sleeve pieces out of BOP stack. 2,813.0 2,813.0 11/22/2024 13:30 11/22/2024 13:45 0.25 COMPZN, RPCOMP OWFF P OWFF for 15-min 2,813.0 2,813.0 11/22/2024 13:45 11/22/2024 14:30 0.75 COMPZN, RPCOMP TRIP P TOOH w/ 5.70" Gator Tool Run #2. 2,813.0 1,620.0 11/22/2024 14:30 11/22/2024 15:00 0.50 COMPZN, RPCOMP OTHR P At 1,813' became temporarily detailed. Pulled 20K over. Circ @ 6 BPM and 440 psi. Worked DP and freed up stuck Gator Tools. After pipe was free, circ'd STS @ 7 BPM / 606 psi. SD Pumps. 1,620.0 1,620.0 11/22/2024 15:00 11/22/2024 17:30 2.50 COMPZN, RPCOMP TRIP P Cont. TOOH w/ 5.70" OD Gator Tool Run #2. tool hanging up pull slow avoid getting stuck 1,620.0 20.0 11/22/2024 17:30 11/22/2024 19:30 2.00 COMPZN, RPCOMP OTHR T Part off of cutting tool wedged into packoff preventing BHA from coming out of hole // Work metal out of well head // Attempt to fish with magnet // Dropped down hole 20.0 20.0 11/22/2024 19:30 11/22/2024 20:30 1.00 COMPZN, RPCOMP BHAH P L/D and inspect Gator Tool. Tool in tact 20.0 0.0 11/22/2024 20:30 11/22/2024 21:00 0.50 COMPZN, RPCOMP BHAH P Pick up WRBP 0.0 10.0 11/22/2024 21:00 11/22/2024 22:30 1.50 COMPZN, RPCOMP TRIP P TIH w/ Plug T/ 2500' 10.0 2,500.0 11/22/2024 22:30 11/22/2024 23:15 0.75 COMPZN, RPCOMP MPSP P Set plug @ 2,500' // Up Wt. 67 Dn Wt 63 // Pump in stages tool stroke 1400 psi, stop at 2000 and 2500 psi, pump 3800 psi no shear, pick up 2K shear from tool 2,500.0 2,500.0 11/22/2024 23:15 11/23/2024 00:00 0.75 COMPZN, RPCOMP PRTS P Rig up test equipment, Test plug 2,500 psi 30 min good test 2,500.0 2,400.0 11/23/2024 00:00 11/23/2024 00:30 0.50 COMPZN, RPCOMP PRTS P Rig down test equipment 2,400.0 2,400.0 11/23/2024 00:30 11/23/2024 02:30 2.00 COMPZN, RPCOMP SLPC P Slip and cut drill line 2,400.0 2,400.0 11/23/2024 02:30 11/23/2024 04:30 2.00 COMPZN, RPCOMP TRIP P Trip out of hole, lay down setting tool 2,400.0 0.0 11/23/2024 04:30 11/23/2024 05:00 0.50 COMPZN, RPCOMP FRZP P Freeze protect well with 15 bbls LEPD 0.0 0.0 11/23/2024 05:00 11/23/2024 11:30 6.50 COMPZN, WHDBOP NUND P Drain Stack. Disconnect trip tank hose. Pull Riser. ND BOP. NU 11" x 7 1/16" Dry Hole Tree. NU 7 1/16" Dry Hole Tree. NU 7" Otis on top of Dry Hole Tree. 0.0 0.0 11/23/2024 11:30 11/23/2024 12:30 1.00 COMPZN, WHDBOP PRTS P Fill dry hole tree with Diesel. RU test pump. PT dry hole tree to 1,500 psi for 15-min. Bleed off. 0.0 0.0 11/23/2024 12:30 11/23/2024 14:00 1.50 DEMOB, MOVE RURD P RD testing equipment. Clean and clear cellar. Obtain Final Pressures (T/IA/OA) = 0 / 0 / 400 psi. Rig release @ 14:00. Prep for rig move to 2P-406. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 11/23/2024 DTTMSTART JOBTYP SUMMARYOPS 11/19/2024 RECOMPLETION Lay rig mats. Pull support equipment away from rig. Warm up hydraulic system. Pull rig off 2P-448. Stage rig center of pad. Lay T-mats, cellar pit liner, and dance floor @ 2P-447. Pull rig over well. Spot in support equipment. Spot in tanks. RU hardline. RU cellar circ hardline for well kill. Work through rig acceptance checklist. 11/20/2024 RECOMPLETION Completed setting T-mats and double stacking dance floor, spot rig over well, rig up hard line and safe out rig. Complete rig acceptance check list. Accept rig @ 05:00. Load 9.8# brine into pits. Record Initial Pressures. PT hardline to tanks. Bleed free gas. PJSM. Perform well kill. Pump 30 bbls heated Deep Clean pill. Chase with 122 bbls 9.8# Brine. See clean 9.8# returns from IA. SD pumps. Blowdown lines. OWFF for 30-min. ND and pull tree. Set BPV for BOP test, nipple down production tree, check hanger threads, nipple up BOPs get rkbs and install riser, flood surface lines and grease valves, shell test stack, perform AOGCC witness waived test 250/2500 psi all componants on 3.5" and 4.5" test joints 11/21/2024 RECOMPLETION Rig down test equipment. Pick up landing jt for 4.5" NSCT hanger, install landing joint, set down 10K, BOLDS, pull hanger free from profile, pull up to 250k no pipe movement, continue to work pipe waiting on e-line. E-line arrived on location. RU E-line. RIH w/ Jet Cutter and cut 4 1/2" Tubing @ 3,050'. POOH. Stand back E-line. MU Landing Joint w/ 4 1/2" NSCT XO. Pull 4 1/2" hanger to rig floor @ 65K. L/D hanger and landing joint. Prep floor to pull 4 1/2" Tubing. RD E-line. Pull 4 1/2" Tubing from jet cut @ 3,050'. Cut Joint = 20.25'. Lay down, pick up and trip in hole with CIBP T/ 2950' top of plug, Set CIBP per YJOS // Up wt. 70K Dn wt. 65K // Top of plug 2950' bottom 2952' // Pinned 3500 psi // 4.5 bbls pump to catch pressure // Pressure up 1600 psi tool stroke start setting proceedure // Pressure up to 2000 psi gain 7K WOB hold for 2 min // Pressure up 2500 psi no change WOB hold for 2 min Pick up to 2K WOB // Pressure up 3600 psi tool did not shear // bleed off pump pressure // Pump back to 3800 psi no shear, pick up 5K tool shear gain circulation, top of plug set @ 2950' // Blow down TD for trip out of hole 11/22/2024 RECOMPLETION Trip in hole with Gator tool, tag CIBP @ 2,951' , get base line pressures, start perfing w/ 5.70" OD Gator Tool @ 2,930'. Did not see perf indicator (breakover) #58. Saw 25K overpull on #59. Tool rep concerned debris may be in tool. Decision made to TOOH and inspect tools. Drop ball. Shear drain sub. Circ BU. TOOH on 3 1/2" DP. L/D and inspect Gator Tools. Inspect tools. Found 3 of 4 drive sleeves sheared off (Est. LIH dimensions = L = 4" W = 1.1" H = 1.3"). Discuss w/ Gator Tool Rep. MU backup 5.70" Gator perf tool. TIH and continue perforating from 2,843 to 2,813'. At Perf Stage #79 of 101 saw 30K overpull. Worked tools free. Depth of last perf = 2,811.5'. Decision made to TOOH and inspect tool. Dropped ball. Shear drain sub. Circ STS. OWFF. Blowdown. TOOH with Gator Tool. Became temporarily detained @ 1,620'. Worked DP Came free. Circ BU. Blow down TD. Cont. TOOH w/ Gator Tool Run #2. pulled slow to well head where tools became hung up, chunk of metal in packoff, worked free dropped down hole, lay down cutter bha PIck up WRBP, trip in hole and set @ 2500' TOP, pressure test 2,500 psi for 30 min 11/23/2024 RECOMPLETION Rig down test equipment, cut and slip drill line. TOOH. L/D WRBP setting tool. Drain Stack. Fill approx. 300' void with Diesel freeze protect. OWFF. ND BOP. NU DSA, Dry Hole Tree, and 7" Otis cap. PT dry hole tree to 1,500 psi. Bleed off. RD. Obtain Final Pressures. Clean and Clear Cellar. Rig Release @ 14:00. Prep for rig move to 2P-406. 2P-447 Plug and Abandon- Rig Summary of Operations 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: Perf-Wash Cement 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): 8015' 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 12/1/2024 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 7537' 2677' 7562' 7600-7640', 7700-7800' (below cement plug) 3-1/2" 5325-5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 108' 2706' 16" 9-5/8" 78' 7" 7466' MD 108' 2317' 5306' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Katherine O'Connor 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: katherine.oconnor@conocophillips.com (907) 263-3718 Senior Well Intervention Engineer KRU 2P-447 5549' 5830', 7509', 7574' 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: 5715' Effective Depth TVD: 4180' By Grace Christianson at 8:03 am, Oct 11, 2024 Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU =Wells Group, E=katherine.oconnor@ conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2024.10.10 15:53:55-08'00' Foxit PDF Editor Version: 13.0.0 Katherine O'Connor X See attached "Conditions of Approval" JJL 12/6/24 10-407 Abandon 949 X DSR-10/14/24 June 30, 2025 SFD 10/27/2024 12/06/24 KRU 2P-447 Abandonment Conditions of Approval: 1. A variance is granted from 20 AAC 25.112(a)(1)(A) which requires a cement plug from 100' below the base of the hydrocarbon-bearing strata. 2. A variance is granted under 20 AAC 25.112(i) to allow the alternate plug placement described as perf/wash/cement job below the surface casing shoe and a cement plug placed across this open hole section and 150' into the surface casing. The plug must pass a State Witnessed pressure test and tag according to 20 AAC 25.112(g). 3. A variance to Order 196 is granted that will eliminate the requirement of logging the cement placed across the hydrocarbon-bearing strata. 4. A failed pressure test of the surface casing shoe plug requires the submission of a new sundry (10-403) to cover the rigless abandonment scope if planned. Completion of workover operations under the original sundry will be complete and a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days following the completion of workover operations. 5. If surface abandonment operations are not initiated within 30 days after the successful placement of the surface casing shoe plug (State witnessed pressure test and tag), a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days after the completion of workover operations to date. 6. Plugging of the surface of a well must meet the requirements of 20 AAC 25.112(d) and 20 AAC 25.120. 7. AOGCC witness is required after the wellhead cutoff and prior to a top job. Variances granted provide for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. Top Bottom Size ID bbls/ft ft volume ft/bbl notes 4-1/2" tubing 0 7330 4.5" 12.6# 3.96" 0.0152 7330 111.7 65.6 from punch depth 4-1/2" x 7" Annulus 0 7330 4.5" 12.6# x 7" 26# 6.28" x 4.5" 0.0186 7330 136.6 53.6 from punch depth Tubing Cement 5830 7330 4.5" 12.6# 3.96" 0.0152 1500 22.9 65.6 Annular Cement 5830 7330 4.5" 12.6# x 7" 26# 6.28" x 2.875" 0.0186 1500 28.0 53.6 Procedure Rig operations are planned to cut and pull tubing from ~3080 KB, set a plug, and mechanically perforate 150 of production casing from approx. 2930 KB to 2780 KB Coil 1. MIRU. 2. RIH with wash/cement tool. Gently tag the CIBP. 3. PU and wash perfs per wash/cement tools vendor procedure. 4. After wash procedure, cement through perforations per wash/cement tools vendor procedure. POOH. Job is planned for ±65bbls cement, including excess. 5. Leave Top of Cement in production casing ±150ft above top perforation at ±2790ft KB (Note, TOC depth may be somewhat adjusted well conditions encountered). Circ out excess. 6. RDMO. Wait on cement. Slickline 1. RIH and tag TOC (AOGCC witness) 2. Pressure test plug to 1500 psi (AOGCC witness) Monitor OA for 30 days for OAP build up to ensure isolation from C80 Coil 1. Pump cement plug in produc on casing from 2000 to surface 2P-447 Perf Wash & Cement Prepared by: Katherine OConnor (214-684-7400) Background & Objec ve 2P-447 was an injector shut-in in mid 2021. The OA was cemented to surface on rig in 2023. The OA passes a pressure test but builds OAP over time. This well was suspended in 2024 with a reservoir plug and 1500 intermediate balanced plug. The rig will cut and pull tubing before this procedure takes place. The objective of this procedure is to get a lateral barrier above the C80 for abandonment and fully abandon the well. Well Data C80 pressure = 1194 psi MASP C80 = 949 psi OA cemented to surface, passing MITOA 2022 on 2/24/2022 The OA fails drawdown test and has slow OAP buildup Reservoir suspended 8/9/24 with passing MITT, intermediate balanced plug was tagged and pressure tested to 1500 psi on 10/5/24. Rig operations are planned to cut and pull tubing from ~3080 KB and mechanically perforate 150 of production casing from ~2930 KB to 2780 KB Surface Excavation 3. DHD to perform drawdown test on tubing, IA and OA 4. Remove well house. 5. Bleed off T/I/O to ensure all pressure is bled off the system. 6. Remove production tree in preparation for excavation and casing cut. 7. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent lose ground from falling into the excavation. 8. Cut off wellhead and all casing strings at 4 feet below original ground level. 9. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 10. Send the casing head with stub to materials shop. Photo document. 11. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 2P-447 c. PTD #: 203-154 d. API #: 50-103-20468-00-00 12. Remove cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 13. Obtain site clearance approval from AOGCC. RDMO. 14. Report the final P&A has been completed to the AOGCC. Photo document final location condition after work is completed cementing unit and associated equipment. 2P-447 P&A Summary (RWO Portion) Meltwater Injector PTD# 203-154 Page 4 of 4 Production Casing Cement Stage 1: 34 bbls of 15.8# Class G Cement Calculated TOC @ 6,057' KB Liner Cement: 31.3 bbls of 15.8# Class G Cement Calculated TOC @ 7,415.5' KB 2P-447 Well Suspension Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 163 bbls of 12# Class G Arcticrete Cement TOC: Surface Note: No returns during stage job. 94bbl OA downsqueeze on rig 3 5 Production Casing: 7" 26# L-80 BTCMD Set @ 7,562 KB T-3 Peforations: @ 7,600' 7,800' KB (200') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 2,705.6' KB Production Tubing: 4.5" 12.6# L-80 IBT-M Set @ 7,466' KB 7 Item Depth - tops (KB) 1 TUBING HANGER 23' 2 CAMCO NO GO 'DB' NIPPLE 502.7' 3 BAKER CMU SLIDING SLEEVE W/ 3.75" NO GO PROFILE 7,365.70 4 CAMCO D NIPPLE W/ 3.813" DB PROFILE 7,382.4' 5 ZXP HR LINER TOP ISOLATION PACKER W/ TIE BACK 7,415.5' 6 G-22 LOCATOR 7,428.1' 7 BAKER 80-40 SEAL W/ 1/2 MULESHOE 3.98" x 3.00"7,429.3' 8 RS PACKOFF SEAL NIPPLE 7,434.4' 9 BAKER FLEX-LOCK LINER HANGER 7,437.2' 10 BAKER 80-40 SEAL BORE EXTENSION 7,446.5' 11 CROSSOVER BUSHING 7465.7' 6 8 4 9 10 11 Liner: 3.5" 9.3# L-80 SLHT Set @ 8,010 KB C80 @ 2930' KB C80 @ 2930' KB Plug #1 Reservoir TOC ±7,509' RKB (SL tagged) Plug #2 Intermediate TOC 5715' RKB (SL tagged) BOC @ 7330' RKB Plug #2 Intermediate TOC @ surface BOC @ 2000' RKB Plug #3 Surface Shoe, PWC TOC @ 2630' RKB BOC @ 2930' RKB Tubing cut at 3080' KB w/ jet cutter Perforations 2930 - 2780' KB Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added jet cut at 3080' RKB 2P-447 10/6/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.0 Set Depth 7,466.0 Set Depth 5,254.5 String Max No 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 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) 23.0 23.0 0.00 HANGER 10.850 4.500 502.7 502.6 3.79 NIPPLE 5.630 CAMCO NO GO 'DB' NIPPLE 3.875 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.7 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.3 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,000.0 1,862.3 43.49 TUBING PUNCH TBG PUNCH FROM 2000' TO 2000' RKB W/ 4 SPF 9/28/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 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) 7,316.2 5,168.9 54.03 1 Gas Lift DMY BK 1 11/19/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2P-447, 10/10/2024 3:34:33 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 SURFACE; 28.1-2,705.6 TUBING PUNCH; 2,000.0 NIPPLE; 502.7 CONDUCTOR; 30.0-108.0 KUP INJ KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status INJ Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Tuttle, Elliott To:Davies, Stephen F (OGC) Cc:Hobbs, Greg S; Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]KRU 2P-447 (PTD 203-154, Sundry 324-627) - Question Date:Monday, November 4, 2024 2:07:44 PM Attachments:EXTERNALRE KRU 2P-447 (PTD 203-154) 10-403 PA-RIG.msg RE EXTERNALRE KRU 2P-447 (PTD 203-154) 10-403 PA-RIG.msg Steve, I apologize for the confusion, but I have messed this up by including aogcc.permitting@alaska.gov in an email to Victoria about timing. The original rig sundry request was made 10/11/2024. We are currently estimating to be on 447 around the 12th-15th followed by 406. Thank you, Elliott Tuttle | CTD/ RWO Drilling Engineer | ConocoPhillips O: 907.263.4742| C: 907.252.3347 | Desk: 1480 From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, November 4, 2024 1:46 PM To: Tuttle, Elliott <Elliott.Tuttle@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]KRU 2P-447 (PTD 203-154, Sundry 324-627) - Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Elliott, Im reviewing CPAIs Sundry Application to perform pre-abandonment operations on well KRU 2P-447. This application was received by the AOGCC on the afternoon of November 1st, and the Estimated Date for Commencing Operations is listed on the application form as being that same day. Is this start date accurate? If not, please let me know. Please also take note of the attached Memo to Operators. This helps AOGCC senior staff prioritize our work. Regards and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov 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: Perf-Wash Cement 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): 8015'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 12/1/2024 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 7537' 2677' 7562' 7600-7640', 7700-7800' (below cement plug) 3-1/2" 5325-5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 108' 2706' 16" 9-5/8" 78' 7" 7466' MD 108' 2317' 5306' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Katherine O'Connor 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: katherine.oconnor@conocophillips.com (907) 263-3718 Senior Well Intervention Engineer KRU 2P-447 5549'5830', 7509', 7574' 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: 5715' Effective Depth TVD: 4180' By Grace Christianson at 8:03 am, Oct 11, 2024 Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU =Wells Group, E=katherine.oconnor@ conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2024.10.10 15:53:55-08'00' Foxit PDF Editor Version: 13.0.0 Katherine O'Connor 324-591 X See attached "Conditions of Approval" JJL 12/6/24 10-407 Abandon 949 X DSR-10/14/24 June 30, 2025 SFD 10/27/2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.06 13:21:11 -09'00'12/06/24 RBDMS JSB 121324 KRU 2P-447 Abandonment Conditions of Approval: 1. A variance is granted from 20 AAC 25.112(a)(1)(A) which requires a cement plug from 100' below the base of the hydrocarbon-bearing strata. 2. A variance is granted under 20 AAC 25.112(i) to allow the alternate plug placement described as perf/wash/cement job below the surface casing shoe and a cement plug placed across this open hole section and 150' into the surface casing. The plug must pass a State Witnessed pressure test and tag according to 20 AAC 25.112(g). 3. A variance to Order 196 is granted that will eliminate the requirement of logging the cement placed across the hydrocarbon-bearing strata. 4. A failed pressure test of the surface casing shoe plug requires the submission of a new sundry (10-403) to cover the rigless abandonment scope if planned. Completion of workover operations under the original sundry will be complete and a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days following the completion of workover operations. 5. If surface abandonment operations are not initiated within 30 days after the successful placement of the surface casing shoe plug (State witnessed pressure test and tag), a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days after the completion of workover operations to date. 6. Plugging of the surface of a well must meet the requirements of 20 AAC 25.112(d) and 20 AAC 25.120. 7. AOGCC witness is required after the wellhead cutoff and prior to a top job. Variances granted provide for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. Top Bottom Size ID bbls/ft ft volume ft/bbl notes 4-1/2" tubing 0 7330 4.5" 12.6# 3.96" 0.0152 7330 111.7 65.6 from punch depth 4-1/2" x 7" Annulus 0 7330 4.5" 12.6# x 7" 26# 6.28" x 4.5" 0.0186 7330 136.6 53.6 from punch depth Tubing Cement 5830 7330 4.5" 12.6# 3.96" 0.0152 1500 22.9 65.6 Annular Cement 5830 7330 4.5" 12.6# x 7" 26# 6.28" x 2.875" 0.0186 1500 28.0 53.6 Procedure Rig operations are planned to cut and pull tubing from ~3080’ KB, set a plug, and mechanically perforate 150’ of production casing from approx. 2930’ KB to 2780’ KB Coil 1. MIRU. 2. RIH with wash/cement tool. Gently tag the CIBP. 3. PU and wash perfs per wash/cement tool’s vendor procedure. 4. After wash procedure, cement through perforations per wash/cement tool’s vendor procedure. POOH. Job is planned for ±65bbls cement, including excess. 5. Leave Top of Cement in production casing ±150ft above top perforation at ±2790ft KB (Note, TOC depth may be somewhat adjusted well conditions encountered). Circ out excess. 6. RDMO. Wait on cement. Slickline 1. RIH and tag TOC (AOGCC witness) 2. Pressure test plug to 1500 psi (AOGCC witness) Monitor OA for 30 days for OAP build up to ensure isolation from C80 Coil 1. Pump cement plug in produc(on casing from 2000 ) to surface 2P-447 Perf Wash & Cement Prepared by: Katherine O’Connor (214-684-7400) Background & Objecve 2P-447 was an injector shut-in in mid 2021. The OA was cemented to surface on rig in 2023. The OA passes a pressure test but builds OAP over time. This well was suspended in 2024 with a reservoir plug and 1500’ intermediate balanced plug. The rig will cut and pull tubing before this procedure takes place. The objective of this procedure is to get a lateral barrier above the C80 for abandonment and fully abandon the well. Well Data C80 pressure = 1194 psi MASP C80 = 949 psi OA cemented to surface, passing MITOA 2022 on 2/24/2022 The OA fails drawdown test and has slow OAP buildup Reservoir suspended 8/9/24 with passing MITT, intermediate balanced plug was tagged and pressure tested to 1500 psi on 10/5/24. Rig operations are planned to cut and pull tubing from ~3080’ KB and mechanically perforate 150’ of production casing from ~2930’ KB to 2780’ KB Surface Excavation 3. DHD to perform drawdown test on tubing, IA and OA 4. Remove well house. 5. Bleed off T/I/O to ensure all pressure is bled off the system. 6. Remove production tree in preparation for excavation and casing cut. 7. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent lose ground from falling into the excavation. 8. Cut off wellhead and all casing strings at 4 feet below original ground level. 9. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 10. Send the casing head with stub to materials shop. Photo document. 11. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 2P-447 c. PTD #: 203-154 d. API #: 50-103-20468-00-00 12. Remove cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 13. Obtain site clearance approval from AOGCC. RDMO. 14. Report the final P&A has been completed to the AOGCC. Photo document final location condition after work is completed cementing unit and associated equipment. 2P-447 P&A Summary (RWO Portion) Meltwater Injector PTD# 203-154 Page 4 of 4 Production Casing Cement Stage 1: 34 bbls of 15.8# Class G Cement Calculated TOC @ 6,057' KB Liner Cement: 31.3 bbls of 15.8# Class G Cement Calculated TOC @ 7,415.5' KB 2P-447 Well Suspension Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 163 bbls of 12# Class G Arcticrete Cement TOC: Surface Note: No returns during stage job. 94bbl OA downsqueeze on rig 3 5 Production Casing: 7" 26# L-80 BTCMD Set @ 7,562’ KB T-3 Peforations: @ 7,600' – 7,800' KB (200') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 2,705.6' KB Production Tubing: 4.5" 12.6# L-80 IBT-M Set @ 7,466' KB 7 Item Depth - tops (KB) 1 TUBING HANGER 23' 2 CAMCO NO GO 'DB' NIPPLE 502.7' 3 BAKER CMU SLIDING SLEEVE W/ 3.75" NO GO PROFILE 7,365.70 4 CAMCO D NIPPLE W/ 3.813" DB PROFILE 7,382.4' 5 ZXP HR LINER TOP ISOLATION PACKER W/ TIE BACK 7,415.5' 6 G-22 LOCATOR 7,428.1' 7 BAKER 80-40 SEAL W/ 1/2 MULESHOE 3.98" x 3.00"7,429.3' 8 RS PACKOFF SEAL NIPPLE 7,434.4' 9 BAKER FLEX-LOCK LINER HANGER 7,437.2' 10 BAKER 80-40 SEAL BORE EXTENSION 7,446.5' 11 CROSSOVER BUSHING 7465.7' 6 8 4 9 10 11 Liner: 3.5" 9.3# L-80 SLHT Set @ 8,010’ KB C80 @ 2930' KB C80 @ 2930' KB Plug #1 – Reservoir TOC ±7,509' RKB (SL tagged) Plug #2 – Intermediate TOC 5715' RKB (SL tagged) BOC @ 7330' RKB Plug #2 – Intermediate TOC @ surface BOC @ 2000' RKB Plug #3 – Surface Shoe, PWC TOC @ 2630' RKB BOC @ 2930' RKB Tubing cut at 3080' KB w/ jet cutter Perforations 2930 - 2780' KB Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added jet cut at 3080' RKB 2P-447 10/6/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 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) 23.0 23.0 0.00 HANGER 10.850 4.500 502.7 502.6 3.79 NIPPLE 5.630 CAMCO NO GO 'DB' NIPPLE 3.875 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.7 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.3 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,000.0 1,862.3 43.49 TUBING PUNCH TBG PUNCH FROM 2000' TO 2000' RKB W/ 4 SPF 9/28/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 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) 7,316.2 5,168.9 54.03 1 Gas Lift DMY BK 1 11/19/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2P-447, 10/10/2024 3:34:33 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 SURFACE; 28.1-2,705.6 TUBING PUNCH; 2,000.0 NIPPLE; 502.7 CONDUCTOR; 30.0-108.0 KUP INJ KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status INJ Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Tuttle, Elliott To:Davies, Stephen F (OGC) Cc:Hobbs, Greg S; Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]KRU 2P-447 (PTD 203-154, Sundry 324-627) - Question Date:Monday, November 4, 2024 2:07:44 PM Attachments:EXTERNALRE KRU 2P-447 (PTD 203-154) 10-403 PA-RIG.msg RE EXTERNALRE KRU 2P-447 (PTD 203-154) 10-403 PA-RIG.msg Steve, I apologize for the confusion, but I have messed this up by including aogcc.permitting@alaska.gov in an email to Victoria about timing. The original rig sundry request was made 10/11/2024. We are currently estimating to be on 447 around the 12th-15th followed by 406. Thank you, Elliott Tuttle | CTD/ RWO Drilling Engineer | ConocoPhillips O: 907.263.4742| C: 907.252.3347 | Desk: 1480 From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, November 4, 2024 1:46 PM To: Tuttle, Elliott <Elliott.Tuttle@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]KRU 2P-447 (PTD 203-154, Sundry 324-627) - Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Elliott, I’m reviewing CPAI’s Sundry Application to perform pre-abandonment operations on well KRU 2P-447. This application was received by the AOGCC on the afternoon of November 1st, and the Estimated Date for Commencing Operations is listed on the application form as being that same day. Is this start date accurate? If not, please let me know. Please also take note of the attached Memo to Operators. This helps AOGCC senior staff prioritize our work. Regards and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov ORIGINATED TRANSMITTAL DATE: 11/22/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 5175 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk River PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5175 2P-447 50103204680000 Tubing Cut Record 21-Nov-2024 RECIPIENTS Conoco DIGITAL FILES PRINTS CD'S 1 FTP Transfer 0 0 USPS Attn: NSK-69 Richard.E.Elgarico@conocophillips.com 700 G Street Anchorage, AK 99503 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 203-154 T39797 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.22 09:44:32 -09'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com 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: Abandon-Rig Ops 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): 8015'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 11/1/2024 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 7537' 2677' 7562' 7600-7640', 7700-7800' (below cement plug) 3-1/2" 5325-5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 108' 2706' 16" 9-5/8" 78' 7" 7466' MD 108' 2317' 5306' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Suspended TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Elliott Tuttle 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: elliott.tuttle@conocophillips.com (907) 263-4742 Senior RWO Engineer KRU 2P-447 5549'5830', 7509', 7574' 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: 5715' Effective Depth TVD: 4180' Digitally signed by Elliott Tuttle DN: OU=CTD/ RWO Senior Engineer, O=Conoco Phillips, CN=Elliott Tuttle, E=elliott.tuttle@ conocophillips.com Reason: I am approving this document Location: Date: 2024.10.10 16:09:43-08'00' Foxit PDF Editor Version: 13.0.0 Elliott Tuttle 324-627 By Grace Christianson at 2:45 pm, Nov 01, 2024 10-407 XX X DSR-11/6/24 X BOP Test to 2500 psi, Annular test to 2500 psi. See attached "Conditions of Approval" June 30, 2025 Suspended SFD 11/4/2024 11/12/2024 SFD Nov 01, 2024 1/202411/1/ VTL 11/14/2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.15 08:23:38 -09'00'11/15/24 RBDMS JSB 111524 KRU 2P-447 Abandonment Conditions of Approval: 1. A variance is granted from 20 AAC 25.112(a)(1)(A) which requires a cement plug from 100' below the base of the hydrocarbon-bearing strata. 2. A variance is granted under 20 AAC 25.112(i) to allow the alternate plug placement described as perf/wash/cement job below the surface casing shoe and a cement plug placed across this open hole section and 150' into the surface casing. The plug must pass a State Witnessed pressure test and tag according to 20 AAC 25.112(g). 3. A variance to Order 196 is granted that will eliminate the requirement of logging the cement placed across the hydrocarbon-bearing strata. 4. A failed pressure test of the surface casing shoe plug requires the submission of a new sundry (10-403) to cover the rigless abandonment scope if planned. Completion of workover operations under the original sundry will be complete and a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days following the completion of workover operations. 5. If surface abandonment operations are not initiated within 30 days after the successful placement of the surface casing shoe plug (State witnessed pressure test and tag), a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days after the completion of workover operations to date. 6. Plugging of the surface of a well must meet the requirements of 20 AAC 25.112(d) and 20 AAC 25.120. 7. AOGCC witness is required after the wellhead cutoff and prior to a top job. Variances granted provide for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 10th, 2024 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby resubmits an Application for Approval to Plug & Abandon 2P-447 (PTD 203- 154). This sundry covers the portion to be performed on-rig by Nordic 3 starting in early-November 2024. 2P-447 was an injector that has been shut in since mid-2021. This well has been suspended with a reservoir cement plug and an intermediate cement plug (covered in separate 10-403). The steps outlined in this sundry request will include pulling the tubing from a pre-rig cut, setting a plug across the C80 formation, and Perforating below the surface casing shoe on Nordic 3. Cementing off the shoe by way of perf wash and cement (PWC), plug abandonment cement plug to surface and ultimately execute final abandonment will be outlined in an additional sundry request. If you have any questions or require any further information, please contact me at 907-252-3347. Elliott Tuttle Senior Rig Workover Engineer CPAI Drilling and Wells Digitally signed by Elliott Tuttle DN: OU=CTD/ RWO Senior Engineer, O=Conoco Phillips, CN=Elliott Tuttle, E=elliott.tuttle @conocophillips.com Reason: I am approving this document Location: Date: 2024.10.10 16:10:01 -08'00' Foxit PDF Editor Version: 13.0.0 Elliott Tuttle final abandonment will be outlined in an additional sundry reques 2P-447 P&A Summary (RWO Portion) Meltwater Injector PTD# 203-154 Page 1 of 4 2P-447 Plug and Abandonment (RWO Portion) Background & Objective 2P-447 was an injector that has been shut in since mid-2021. This well has been suspended with a reservoir cement plug and an intermediate cement plug (covered in separate 10-403). The steps outlined in this sundry request will include pulling the tubing from a pre-rig cut, setting a plug across the C80 formation, and Perforating below the surface casing shoe on Nordic 3 in preparation for a perf/ wash/ cement job to isolate the C80 formation. There was an OA downsqueeze performed on rig 12/21/2003 with 94 Barrels (197sx @ 12ppg) of ArctiCrete Cement. The last passing MIT-OA was 2/24/2022, but now slowly repressurizes. 2P pad does not have any facilities or surface line hookups, and the pad is slated to be used as storage for the Willow development project in 2026. The objective of this procedure is to prepare for an off rig PWC job above the C80 and final P&A. Well Data Meltwater Formation: Reservoir pressure 4/19/2018 = 2942 psi @ 5533’ TVD MASP = 0 psi (Cemented) C-80 Formation: OAP = 366 psi (9/2/24) (cemented OA, assume diesel gradient) MASP = 949 psi using 0.1 psi/ft gas gradient Intermediate plug TOC = 5715’ RKB (SL Tagged) Tubing cut depth = 3080’ RKB Most recent passing MIT-OA 2/24/2022 to 1800psi 2P-447 P&A Summary (RWO Portion) Meltwater Injector PTD# 203-154 Page 2 of 4 2P-447 P&A Summary (RWO Portion) Meltwater Injector PTD# 203-154 Page 3 of 4 RWO P&A Setup Date: 10/8/2024 Prepared by: Elliott Tuttle Estimated Start Date: 11/15/2024 MIRU 1. MIRU on 2P-447. 2. Record shut-in pressures on the T & IA. If there is pressure, bleed oE IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead before proceeding. 3. ND Tree and NU BOPE. Test rams and annular to 250/2,500 PSI. a. Will not set BPV due to two tested cement plugs below providing two barriers to formation. b. BOPE ConFguration: Annular / Variable Bore Rams / Blind Rams / Pipe Rams 4. Circulate tubing and IA to brine. Retrieve Tubing 5. MU landing joint and BOLDS. 6. Pull tubing from pre-rig cut at 3080’ RKB to surface and LD. Prepare for and Perforate Below Casing Shoe 1. Set bridge plug in production casing at 2950’ RKB. 2. MU Gator perforator (570 version, 4 blade) 3. Make 2 perforations every 3 ft (or more if CFD suggests), starting at 2930’ RKB, making last perforation at 2780’ RKB noting overpull on each actuation. Observe well for How 4. MU WRPB, set at 1100’ RKB (permafrost measured at 1050’ TVD), PT plug to 2500psi for 30 minutes, POOH keeping hole full with KWF 5. ND BOPE. NU dry hole tree. Freeze protect WH/ tree with diesel. 6. RDMO. without filling hole. Fill hole with diesel. 2P-447 P&A Summary (RWO Portion) Meltwater Injector PTD# 203-154 Page 4 of 4 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added jet cut at 3080' RKB 2P-447 10/6/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 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) 23.0 23.0 0.00 HANGER 10.850 4.500 502.7 502.6 3.79 NIPPLE 5.630 CAMCO NO GO 'DB' NIPPLE 3.875 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.7 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.3 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,000.0 1,862.3 43.49 TUBING PUNCH TBG PUNCH FROM 2000' TO 2000' RKB W/ 4 SPF 9/28/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 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) 7,316.2 5,168.9 54.03 1 Gas Lift DMY BK 1 11/19/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2P-447, 10/10/2024 3:34:33 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 SURFACE; 28.1-2,705.6 TUBING PUNCH; 2,000.0 NIPPLE; 502.7 CONDUCTOR; 30.0-108.0 KUP INJ KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status INJ Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9.625" L-80 2317' 7" L-80 5306' 3-1/2" L-80 5546' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 7562' SIZE DEPTH SET (MD) 8010' 25' 5226' 62.5# 40# 108' 25' Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 5715' (SW TOC)-7574' MD 51 bbls 15.8ppg Class G cement Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing SUSPENDED 7600-7640' MD and 5325-5346' TVD (below cement plug) 7700-7780' MD and 5376-5419' TVD (below cement plug) 7780-7800' MD and 5419-5430' TVD (below cement plug) Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 7429' MD/ 5234' TVD (seal assembly) PACKER SET (MD/TVD) 42" 12.25" 7.6 bbl AS I 28'446 sx AS Lite, 284 sx LiteCrete 9.2# 30' 7415' 2706'28' 30' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# WT. PER FT.GRADE 12/24/2003 CEMENTING RECORD 5864553 1377' MD/ 1352' TVD SETTING DEPTH TVD 5864223 TOP HOLE SIZE AMOUNT PULLED 441203 441011 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A BOTTOM Kuparuk River Field/ Meltwater Oil Pool- Suspended N/A 50-103-20468-00-00 KRU 2P-447 ADL0373112, ADL0389058 1017' FNL, 1603' FWL, Sec. 17, T8N, R7E, UM 396' FNL, 930' FEL, Sec. 19, T8N, R7E, UM ALK 32092/ 32409 12/6/2003 8015' MD/ 5549' TVD 5715' MD/ 4180' TVD P.O. Box 100360, Anchorage, AK 99510-0360 443562 5868863 65' FNL, 739' FEL, Sec. 19, T8N, R7E, UM 9. Ref Elevations: KB: 28' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 10/6/2024 203-154/ 324-486 ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 150 sx Class G6.125" TUBING RECORD 165 sx Class G w/GasBlok, 340 sx ArcticCrete8.5" 7415' MD/ 5226' TVD 7466' MD4-1/2" CASING Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 4:28 pm, Oct 10, 2024 Suspended 10/6/2024 JSB RBDMS JSB 101724 xGDSR-11/22/24 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1377' 1352' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Katherine O'Connor Digital Signature with Date:Contact Email: katherine.oconnor@conocophillips.com Contact Phone:(907) 263-3718 Senior Well Interventions Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: N/A - Suspended Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. INSTRUCTIONS Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Authorized Name and Authorized Title: Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A- Suspended Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=Wells Group, E=katherine.oconnor@conocophillips.com, C=US Reason: I am the author of this documentLocation:Date: 2024.10.10 16:04:05-08'00'Foxit PDF Editor Version: 13.0.0 Katherine O'Connor Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added jet cut at 3080' RKB 2P-447 10/6/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 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) 23.0 23.0 0.00 HANGER 10.850 4.500 502.7 502.6 3.79 NIPPLE 5.630 CAMCO NO GO 'DB' NIPPLE 3.875 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.7 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.3 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,000.0 1,862.3 43.49 TUBING PUNCH TBG PUNCH FROM 2000' TO 2000' RKB W/ 4 SPF 9/28/2024 3.960 3,080.0 2,542.5 52.14 CUT JET CUT @ 3080' RKB 10/6/2024 3.960 7,311.0 5,165.8 53.99 TUBING PUNCH TBG PUNCH FROM 7311' TO 7313' RKB W/ 6 SPF 9/10/2024 3.960 7,330.0 5,177.0 54.13 TUBING PUNCH TBG PUNCH FROM 7330' TO 7333' RKB W/ 6 SPF 9/10/2024 3.960 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 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) 7,316.2 5,168.9 54.03 1 Gas Lift DMY BK 1 11/19/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 5,715.0 7,313.0 4,180.1 5,167.0 Cement Plug PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. 9/26/2024 2P-447, 10/10/2024 3:34:33 PM Vertical schematic (actual) LINER; 7,415.5-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 RPERF; 7,600.0-7,640.0 APERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 Cement Plug; 7,509.0 ftKB TUBING PUNCH; 7,330.0 GAS LIFT; 7,316.2 TUBING PUNCH; 7,311.0 Cement Plug; 5,715.0 ftKB CUT; 3,080.0 SURFACE; 28.1-2,705.6 TUBING PUNCH; 2,000.0 NIPPLE; 502.7 CONDUCTOR; 30.0-108.0 KUP INJ KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status INJ Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE DTTMSTART JOBTYP SUMMARYOPS 8/22/2024 ACQUIRE DATA (P & A) T DDT (PASSED) 9/2/2024 ACQUIRE DATA (P&A) FUNCTION TEST ALL T LDS/GNS (COMPLETE), T POT (PASSED) T PPPOT (PASSED), FUNCTION TEST ALL IC LDS/GNS (COMPLETE), IC POT (PASSED) IC PPPOT (PASSED), 9/10/2024 CHANGE WELL TYPE SHOOT 1-9/16" TUBING PUNCH FROM 7330'-7333', NO T X IA COMMUNICATION SHOOT 2" TUBING PUNCH FROM 7311'-7313', PRESSURED UP ON TUBING W/ TRIPLEX TO CONFIRM T X IA COMMUNICATION JOB COMPLETE, READY FOR INTERMEDIATE CEMENT PLUG 9/24/2024 MAINTAIN WELL STEP RATE TEST PUMP 35BBLS OF DSL 3BPM AT 350 PSI ON TBG U TUBE WELL FOR FREEZE PROTECT JOB COMPLETE 9/26/2024 CHANGE WELL TYPE INTERMEDIATE CEMENT BALANCE PLUG. LOAD TBG & IA WITH 10.9 PPG NaCl/NaBr KWF. PUMPED 51 BBLS OF 15.8 PPG CEMENT & DISPLACED CEMENT w/ 88 BBLS OF 10.9 PPG NaCl/NaBr KWF. PLACING TOC IN TBG & IA @ ~5830' MD. WAIT ~48 HRS TO PUNCH HOLES & FREEZE PROTECT. IN PROGRESS 9/28/2024 CHANGE WELL TYPE SHOT 2" TUBING PUNCH FROM 2000'-2003' LRS CIRCULATED & U-TUBED 68 BBL DIESEL T X IA JOB IS READY FOR SL SW TAG TOC & CMIT 10/5/2024 CHANGE WELL TYPE STATE WITNESS ( SULLEY ) TAG TOC 5715' SLM, GOOD SAMPLE. PERFORM 1500 PSI CMIT W/ PASSING RESULTS. READY FOR E-LINE. 10/6/2024 CHANGE WELL TYPE CUT TUBING AT 3080' WITH 3.5" JET CUTTER LOG CORRELATED TO TUBING TALLY DATED 1/19/2004 WELL LEFT S/I 2P-447 Intermediate Suspend Summary of Operations ORIGINATED TRANSMITTAL DATE: 10/9/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 5105 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk River PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5105 2P-447 501032046800 Tubing Cut Record 6-Oct-2024 RECIPIENTS ConocoPhillips Alaska, Inc. DIGITAL FILES PRINTS CD'S 1 0 0 0 USPS 0 0 0 0 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 203-154 T39641 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.09 12:39:02 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com ORIGINATED TRANSMITTAL DATE:10/9/2024 ALASKA E-LINE SERVICES TRANSMITTAL #:5086 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk River PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET #WELL #API #LOG DESCRIPTION DATE OF LOG RECIPIENTS DIGITAL FILES PRINTS CD'S 1 0 0 0 USPS 0 0 0 0 Received By:Received By: Signature Signature DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By:Received By: Signature Signature DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method:USPS Received By:Received By: Signature Signature Please return via e-mail a copy to both: AR@ake-line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com DNR AOGCC ConocoPhillips Alaska, Inc. 2P-447 Tubing Puncher Record501032046800 28-Sep-29245086 203-154 T39641 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.09 12:37:25 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 17 Township: 8N Range: 7E Meridian: Umiat Drilling Rig: N/A Rig Elevation: N/A Total Depth: 8015 ft MD Lease No.: ADL 0373112 Operator Rep: Suspend: X P&A: Conductor: 16" O.D. Shoe@ 108 Feet Csg Cut@ Feet Surface: 9 5/8" O.D. Shoe@ 2706 Feet Csg Cut@ Feet Intermediate: 7" O.D. Shoe@ 7562 Feet Csg Cut@ Feet Production: O.D. Shoe@ Feet Csg Cut@ Feet Liner: 3 1/2" O.D. Shoe@ 8010 Feet Csg Cut@ Feet Tubing: 4 1/2" O.D. Tail@ 7466 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Balanced 7,330 ft 5,711 ft 10.9 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1840 1745 1725 IA 1760 1730 1725 OA 293 290 285 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Traveled to KRU 2P pad for plug tag and MIT-TxIA combo test of the intermediate balanced plug on 2P-447. Wire line tool was 28 ft long with 150lbs of weight bar and a flap bailer on the end. Initial tag was made at 5,710 ft MD and beat down to 5,711 ft MD for final tag. The bailer returned a good cement sample. 1.4bbl in and 1.4 bbl out during the MIT. October 5, 2024 Sully Sullivan Well Bore Plug & Abandonment KRU 2P-447 ConocoPhillips Alaska Inc. PTD 2031540; Sundry 324-486 none Test Data: P Casing Removal: Sid Ferguson Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-1005_Plug_Verification_KRU_2P-447_ss 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.11.18 16:06:40 -09'00' ORIGINATED TRANSMITTAL DATE: 9/16/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 5051 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk River PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5051 2P-447 50103204680000 Tubing Puncher Record 10-Sep-2024 RECIPIENTS ConocoPhillips Alaska, Inc. DIGITAL FILES PRINTS CD'S 1 0 0 0 USPS 0 0 0 0 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 203-154 T39570 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.17 08:02:40 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com 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: Suspend-Intermediate Plug 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): 8015'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 (907) 263-3718 Well Interventions Engineer KRU 2P-447 5549' 7509' 5278' 7509', 7574' N/A 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: katherine.oconnor@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Katherine O'Connor STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool - Suspended ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Suspended TVD Burst 7466' MD 108' 2317' 5306' 108' 2706' 16" 9-5/8" 78' 7"7537' 2677' 7562' 7600-7640', 7700-7800' (below cement plug) 3-1/2" 5325-5346', 5376-5430' (below cement plug) Perforation Depth TVD (ft): 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 09/10/2024 By Grace Christianson at 8:11 am, Aug 22, 2024 Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O= ConocoPhillips, OU=Wells Group, E= katherine.oconnor@conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2024.08.21 15:53:02-08'00' Foxit PDF Editor Version: 13.0.0 Katherine O'Connor 324-486 VTL 9/3/2024 SFD 8/28/2024 10-407 X June 30, 2025 X DSR-8/26/24 0 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.03 16:34:44 -08'00'09/03/24 RBDMS JSB 090524 2P-447 Suspension Prepared by: Katherine O’Connor (214-684-7400) Background & Objecve 2P-447 was an injector shut-in in mid 2021. It has no known tubing or IA integrity issues, and the OA was cemented to surface on rig in 2023. The OA does not pass a pressure test. This well is ultimately slated to be P&Ad on rig as part of the 2P pad abandonment. 2P pad does not have any facilities or surface line hookups, and the pad is slated to be used as storage for Willow development project in 2026. This well was suspended in 2024. The objective of this procedure is to pump and intermediate cement plug before rig P&A in Q4 2024. Well Data Reservoir pressure 04/19/2018 = 3033 psi at 5400’ TVD = 0.562 psi/ft MASP = 2493 psi OA cemented to surface, no passing MITOA Suspended 8/9/24 with passing MITT Procedure Wireline & Pumping 1. Punch tubing at ±7330’ RKB 2. Pump the following schedule taking returns up the IA: a. ±50 bbls surfactant wash b. ±250 bbls KWF c. ±51 bbls cement d. ±88 bbls KWF 3.This should leave TOC in tubing and IA hydrostatically balanced with cement top at 8830’ MD 4. RIH and tag TOC and perform CMIT-TxIA to 1500 psi (AOGCC Witnessed) Eline/Relay 5. Cut tubing at ±3080’ RKB Top Bottom Size ID bbls/ft ft volume ft/bbl notes 4-1/2" tubing 0 7330 4.5" 12.6# 3.96" 0.0152 7330 111.7 65.6 from punch depth 4-1/2" x 7" Annulus 0 7330 4.5" 12.6# x 7" 26# 6.28" x 4.5" 0.0186 7330 136.6 53.6 from punch depth Tubing Cement 5830 7330 4.5" 12.6# 3.96" 0.0152 1500 22.9 65.6 Annular Cement 5830 7330 4.5" 12.6# x 7" 26# 6.28" x 2.875" 0.0186 1500 28.0 53.6 Production Casing Cement Stage 1: 34 bbls of 15.8# Class G Cement Calculated TOC @ 6,057' KB Liner Cement: 31.3 bbls of 15.8# Class G Cement Calculated TOC @ 7,415.5' KB 2P-447 Well Suspension Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 163 bbls of 12# Class G Arcticrete Cement TOC: Surface Note: No returns during stage job. 94bbl OA downsqueeze on rig 1 2 3 5 Production Casing: 7" 26# L-80 BTCMD Set @ 7,562’ KB T-3 Peforations: @ 7,600' – 7,800' KB (200') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 2,705.6' KB Production Tubing: 4.5" 12.6# L-80 IBT-M Set @ 7,466' KB 7 Item Depth - tops (KB) 1 TUBING HANGER 23' 2 CAMCO NO GO 'DB' NIPPLE 502.7' 3 BAKER CMU SLIDING SLEEVE W/ 3.75" NO GO PROFILE 7,365.70 4 CAMCO D NIPPLE W/ 3.813" DB PROFILE 7,382.4' 5 ZXP HR LINER TOP ISOLATION PACKER W/ TIE BACK 7,415.5' 6 G-22 LOCATOR 7,428.1' 7 BAKER 80-40 SEAL W/ 1/2 MULESHOE 3.98" x 3.00"7,429.3' 8 RS PACKOFF SEAL NIPPLE 7,434.4' 9 BAKER FLEX-LOCK LINER HANGER 7,437.2' 10 BAKER 80-40 SEAL BORE EXTENSION 7,446.5' 11 CROSSOVER BUSHING 7465.7' 6 8 4 9 10 11 Liner: 3.5" 9.3# L-80 SLHT Set @ 8,010’ KB C80 @ 2930' KB C80 @ 2930' KB Plug #1 – Reservoir TOC ±7,509' RKB Plug #2 – Intermediate TOC ±5830' RKB BOC @ ±7330' RKB CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:O"Connor, Katherine To:Loepp, Victoria T (OGC) Subject:RE: [EXTERNAL]RE: DS-2P Intermediate plug sundries Date:Tuesday, September 3, 2024 2:08:14 PM Yes - MASPS should all be zero. My perspective for having MASP there was just thinking about KWF and force of habit for calculating surface pressure. Here is a table of data requested. All witnessed tests passed. Prod/Inj Well Tubing Size PC Size Fluid Weight Well Suspended Tag Depth Pressure Test MASP Prod 2P-406 3.5 5.5 8.6 6862 1500 0 Prod 2P- 424A 3.5 5.5 8.6 10599 1500 0 inj 2P-427 3.5 5.5 10.7 9569 1500 0 inj 2P-432 3.5 7 10.2 5683 1500 0 Prod 2P-441 3.5 5.5 8.6 6848 1500 0 inj 2P-447 4.5 7 10.9 7509 1500 0 Prod 2P- 448A 3.5 5.5 8.6 7118 1500 0 Thanks, Katherine O’Connor CPF2 Interventions Engineer 907-263-3718 (O) 214-684-7400 (C) -----Original Message----- From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Tuesday, September 3, 2024 11:30 AM To: O'Connor, Katherine <Katherine.OConnor@conocophillips.com> Subject: [EXTERNAL]RE: DS-2P Intermediate plug sundries CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Dump bail cement on CIBP 2P-447 7/10/2024 fergusp Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 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) 23.0 23.0 0.00 HANGER 10.850 4.500 502.7 502.6 3.79 NIPPLE 5.630 CAMCO NO GO 'DB' NIPPLE 3.875 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.7 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.3 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 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) 7,316.2 5,168.9 54.03 1 Gas Lift DMY BK 1 11/19/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 2P-447, 8/15/2024 10:35:09 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 SHOE; 8,008.3-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 APERF; 7,600.0-7,640.0 RPERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 CASING SHOE; 7,560.5-7,562.0 Cement Plug; 7,509.0 ftKB FLOAT COLLAR; 7,474.8- 7,476.1 XO BUSHING; 7,465.7-7,467.7 SBE; 7,446.5-7,465.7 SEAL ASSY; 7,429.3 HANGER; 7,437.2-7,446.5 NIPPLE; 7,434.4-7,437.2 LOCATOR; 7,428.1 PACKER; 7,415.5-7,434.4 NIPPLE; 7,382.4 SLEEVE; 7,365.7 GAS LIFT; 7,316.2 STAGE COLLAR; 3,105.2- 3,107.6 SURFACE; 28.1-2,705.6 FLOAT SHOE; 2,703.9-2,705.6 FLOAT COLAR; 2,621.0-2,622.5 NIPPLE; 502.7 CONDUCTOR; 30.0-108.0 CASING HANGER; 28.1-30.6 CASING HANGER; 25.2-27.2 KUP INJ KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status INJ Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9.625" L-80 2317' 7" L-80 5306' 3-1/2" L-80 5546' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 150 sx Class G6.125" TUBING RECORD 165 sx Class G w/GasBlok, 340 sx ArcticCrete8.5" 7415' MD/ 5226' TVD 7466' MD4-1/2" CASING STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 8/9/2024 203-154/ 323-609 50-103-20468-00-00 KRU 2P-447 ADL0373112, ADL0389058 1017' FNL, 1603' FWL, Sec. 17, T8N, R7E, UM 396' FNL, 930' FEL, Sec. 19, T8N, R7E, UM ALK 32092/ 32409 12/6/2003 8015' MD/ 5549' TVD 7509' MD/ 5278' TVD P.O. Box 100360, Anchorage, AK 99510-0360 443562 5868863 65' FNL, 739' FEL, Sec. 19, T8N, R7E, UM 9. Ref Elevations: KB: 28' WT. PER FT.GRADE 12/24/2003 CEMENTING RECORD 5864553 1377' MD/ 1352' TVD SETTING DEPTH TVD 5864223 TOP HOLE SIZE AMOUNT PULLED 441203 441011 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A BOTTOM Kuparuk River Field/ Meltwater Oil Pool- Suspended N/A 7429' MD/ 5234' TVD (seal assembly) PACKER SET (MD/TVD) 42" 12.25" 7.6 bbl AS I 28'446 sx AS Lite, 284 sx LiteCrete 9.2# 30' 7415' 2706'28' 30' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# 7509'-7574' MD 0.6 bbls Class G cement Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing SUSPENDED 7600-7640' MD and 5325-5346' TVD (below cement plug) 7700-7780' MD and 5376-5419' TVD (below cement plug) 7780-7800' MD and 5419-5430' TVD (below cement plug) Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 7562' SIZE DEPTH SET (MD) 8010' 25' 5226' 62.5# 40# 108' 25' Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 3:40 pm, Aug 15, 2024 Suspended 8/9/2024 JSB RBDMS JSB 081624 xGDSR-8/27/24 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1377' 1352' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Katherine O'Connor Digital Signature with Date:Contact Email: katherine.oconnor@conocophillips.com Contact Phone:(907) 263-3718 Senior Well Interventions Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A- Suspended Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Authorized Name and Authorized Title: N/A - Suspended Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. INSTRUCTIONS Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=Wells Group, E=katherine.oconnor@conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2024.08.15 15:11:51-08'00' Foxit PDF Editor Version: 13.0.0 Katherine O'Connor Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB 7,690.0 2P-447 3/31/2019 aappleh Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Dump bail cement on CIBP 2P-447 7/10/2024 fergusp Notes: General & Safety Annotation End Date Last Mod By NOTE: OA OBSTRUCTED w/ CEMENT @ SURFACE 11/12/2012 ninam NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 6/14/2004 WV5.3 Conversio n 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 30.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 2,705.6 2,317.5 40.00 L-80 BTC INTERMEDIATE 7 6.28 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD LINER 3 1/2 2.99 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.0 Set Depth … 7,466.0 Set Depth … 5,254.5 String Max No… 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M ID (in) 3.96 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) 23.0 23.0 0.00 HANGER 10.850 4.500 502.7 502.6 3.79 NIPPLE 5.630 CAMCO NO GO 'DB' NIPPLE 3.875 7,316.2 5,168.9 54.03 GAS LIFT 5.984 CAMCO KBG-2 3.938 7,365.7 5,197.7 54.68 SLEEVE 5.500 BAKER CMU SLIDING SLEEVE w/3.813" DB PROFILE 3.813 7,382.4 5,207.4 54.94 NIPPLE 5.530 CAMCO 'DB' NIPPLE w/3.75" NO GO PROFILE 3.750 7,428.1 5,233.4 55.68 LOCATOR 5.000 G-22 LOCATOR 3.010 7,429.3 5,234.1 55.71 SEAL ASSY 4.000 BAKER 80-40 SEAL w/1/2 MULESHOE 3.98" x 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 7,574.5 5,312.4 59.07 CIBP 2.630" CIBP W/ MOE @ 7575' RKB, OAL = 1.37 TTS CIBP 2105- 263- AC- 001S R 7/2/2024 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) 7,316.2 5,168.9 54.03 1 Gas Lift DMY BK 1 11/19/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 7,415.5 5,226.2 55.45 PACKER 7.000 ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,236.9 55.82 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 7,465.7 5,254.4 56.53 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 3/1/2004 6.0 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7,600.0 7,640.0 5,325.4 5,345.7 T-3, 2P-447 2/24/2014 6.0 RPERF 2.5" X 20' hsc, 6 SPF, 60 DEG PHASING MILLENIUM 7,700.0 7,780.0 5,376.2 5,419.0 T-3, 2P-447 2/7/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 7,780.0 7,800.0 5,419.0 5,429.9 T-3, 2P-447 2/6/2004 6.0 IPERF 2.5" HSD PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,509.0 7,574.5 5,277.9 5,312.4 Cement Plug Dump Bailed cement on CIBP 7/9/2024 7/8/2024 2P-447, 8/15/2024 10:35:09 AM Vertical schematic (actual) LINER; 7,415.5-8,010.0 SHOE; 8,008.3-8,010.0 IPERF; 7,780.0-7,800.0 IPERF; 7,700.0-7,780.0 APERF; 7,600.0-7,640.0 RPERF; 7,600.0-7,640.0 CIBP; 7,574.5 INTERMEDIATE; 25.2-7,562.0 CASING SHOE; 7,560.5-7,562.0 Cement Plug; 7,509.0 ftKB FLOAT COLLAR; 7,474.8- 7,476.1 XO BUSHING; 7,465.7-7,467.7 SBE; 7,446.5-7,465.7 SEAL ASSY; 7,429.3 HANGER; 7,437.2-7,446.5 NIPPLE; 7,434.4-7,437.2 LOCATOR; 7,428.1 PACKER; 7,415.5-7,434.4 NIPPLE; 7,382.4 SLEEVE; 7,365.7 GAS LIFT; 7,316.2 STAGE COLLAR; 3,105.2- 3,107.6 SURFACE; 28.1-2,705.6 FLOAT SHOE; 2,703.9-2,705.6 FLOAT COLAR; 2,621.0-2,622.5 NIPPLE; 502.7 CONDUCTOR; 30.0-108.0 CASING HANGER; 28.1-30.6 CASING HANGER; 25.2-27.2 KUP INJ KB-Grd (ft) 27.98 RR Date 1/20/2004 Other Elev… 2P-447 ... TD Act Btm (ftKB) 8,015.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032046800 Wellbore Status INJ Max Angle & MD Incl (°) 59.82 MD (ftKB) 7,662.99 WELLNAME WELLBORE2P-447 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE DTTMSTART JOBTYP SUMMARYOPS 6/24/2024 CHANGE WELL TYPE OBTAIN PASSING MIT-IA TO 1500 PSI, DRIFT FOR CIBP TO 7600' RKB, NO ISSUES. READY FOR E-LINE LOAD & SET CIBP. 7/2/2024 CHANGE WELL TYPE PUMP 120 BBLS OF 10.9 BRINE AND 35 BBLS DIESEL DOWN TUBING. SET CIBP AT 7575.0' RKB. PERFORM MITT TO 2500 PSI (PASSED). JOB IS READY FOR SL. 2105-263-AC-001SR 7/9/2024 CHANGE WELL TYPE DUMP BAIL ~4 GAL OF CEMENT ON TOP OF CIBP @ 7575' RKB, IN PROGRESS. 7/10/2024 CHANGE WELL TYPE DUMP BAIL ~37' OF CEMENT ON TOP OF CIBP @ 7575' RKB. RUN 1.75" SAMPLE BAILER TO TAG TOC @ 7509' RKB. READY FOR SW TAG & TEST IN 72 HOURS. 8/9/2024 CHANGE WELL TYPE AOGCC WITNESSED STATE WITNESS (AUSTIN McLEOD) TAG TOC @ 7509' RKB. PERFORM PASSING MIT-T TO 1500 PSI. READY FOR NEXT P&A STEPS. 2P-447 Suspend Sumary of Operations MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 17 Township: 8N Range: 7E Meridian: Umiat Drilling Rig: NA Rig Elevation: NA Total Depth: 8015 ft MD Lease No.: ADL 0373112 Operator Rep: Suspend: X P&A: NA Conductor: 16" O.D. Shoe@ 108 Feet Csg Cut@ NA Feet Surface: 9-5/8" O.D. Shoe@ 2706 Feet Csg Cut@ NA Feet Intermediate: 7" O.D. Shoe@ 7562 Feet Csg Cut@ NA Feet Production: NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet Liner: 3-1/2" O.D. Shoe@ 8010 Feet Csg Cut@ NA Feet Tubing: 4-1/2" O.D. Tail@ 7466 Feet Tbg Cut@ NA Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Tubing Bridge plug 7575 ft MD 7508 ft MD 10.9/6.7 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1750 1670 1650 IA 360 360 360 OA 354 354 354 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: I traveled to location to witness the tag and mechanical integrity test (MIT) of the bottom perforation isolating plug inside the wells liner. The cement plug on top of the cast iron bridge plug (7575 ft MD ft MD) was dumped bailed on 7/10/24. Using your generic 2-1/4 inch slickline string they tagged the plug at 7508 ft MD (inclination 58°) with multiple hard set downs. A passing MIT was then done to a target of 1500psi. Top perforation at 7600 ft MD. August 9, 2024 Austin McLeod Well Bore Plug & Abandonment Kuraruk River Unit 2P-447 ConocoPhillips Alaska, Inc. PTD 2031540; Sundry 323-609 none Test Data: MITT P Casing Removal: Mike Scoles Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-0809_Plug_Verification_KRU_2P-447_am 9 9 99 99 9 9 9 9 9 9 9 9 9 9 9 9 9 999 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.10.24 15:06:38 -08'00' ORIGINATED TRANSMITTAL DATE: 7/10/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 4909 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 4909 2P-447 50103204680000 Plug Setting Record 2-Jul-2024 RECIPIENTS Conoco DIGITAL FILES PRINTS CD'S 1 FTP Transfer 0 0 USPS Attn: NSK-69 tom.osterkamp@conocophillips.com 700 G Street Anchorage, AK 99503 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 203-154 T39139 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.10 10:18:57 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com tom.osterkamp@conocophillips.com 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): Effective Depth MD: Effective Depth TVD: Junk (MD): 8015'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 12/1/2023 8010'594' 4-1/2" 5546' Packer: Baker 80-40 Seal Packer: ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 7537' 2677' 7562' 7600-7640', 7700-7800' 3-1/2" 5325-5346', 5376-5430' Perforation Depth TVD (ft): 108' 2706' 16" 9-5/8" 78' 7" 7466' MD 108' 2317' 5306' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Suspended TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 203-154 P.O. Box 100360, Anchorage, AK 99510 50-103-20468-00-00 Kuparuk River Field Meltwater Oil Pool AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 7429' MD and 5234' TVD 7415' MD and 5226' TVD N/A Katherine O'Connor 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: katherine.oconnor@conocophillips.com (907) 263-3718 Well Interventions Engineer KRU 2P-447 5549' 7690' 5371' None 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 By Grace Christianson at 10:20 am, Nov 14, 2023 Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU= Wells Group, E=katherine.oconnor@ conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2023.11.09 12:46:48-09'00' Foxit PDF Editor Version: 13.0.0 Katherine O'Connor 323-609 SFD 11/16/2023 X 10-407 VTL 11/14/2023 12/31/2024 DSR-11/16/23 X *&:JLC 11/17/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.17 13:13:39 -09'00'11/17/23 RBDMS JSB 112023 I 2P-447 Suspension Date Wrien: 10-30-23 Execuon Date: Dec 1, 2023 Prepared by: Katherine O’Connor (214-684-7400) Background & Objecve 2P-447 was a producer shut-in in mid 2021. It has no known tubing or IA integrity issues, and the OA was cemented to surface on rig in 2023. The OA does not pass a pressure test. This well is ultimately slated to be P&Ad on rig as part of the 2P pad abandonment. 2P pad does not have any facilities or surface line hookups, and the pad is slated to be used as storage for Willow development project in 2026. This well will be suspended in 2023, and it is currently planned to be fully abandoned in 2024. Well Data Reservoir pressure 04/19/2018 = 3033 psi at 5400’ TVD MASP = 2493 psi OA cemented to surface, no passing MITOA Last TD tag 12/20/2019 7673’ CTMD – coil unable to clean out past that depth Procedure Wireline & Pumping 1. Drift with dummy CIBP to TD. If unable to get within 50’ of perforations, contact Katherine O’Connor 2. Fluid pack tubing & IA as necessary with KWF and freeze protect 3. Set CIBP @ ±7,575 ’ RKB (must be set within 50’ of the top of perforations). 4. Perform MIT-T to 2500 psi, record results 5. Dump bail at least 30’ of cement on top of CIBP 6. Allow 72 hours for cement to harden, notify AOGCC at least 24 hours in advance 7. RIH and tag TOC, approx. 7,545’ RKB (MUST BE AOGCC WITNESSED) 8. RU LRS as necessary. Perform pressure test to 1500 psi (MUST BE AOGCC WITNESSED) 9. Perform DDT to 0 psi and record results DHD 1. Schedule wellsite inspection within 12 months of suspension approval Production Casing Cement Stage 1: 34 bbls of 15.8# Class G Cement Calculated TOC @ 6,057' KB Liner Cement: 31.3 bbls of 15.8# Class G Cement Calculated TOC @ 7,415.5' KB 2P-447 Well Suspension Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 163 bbls of 12# Class G Arcticrete Cement TOC: Surface Note: No returns during stage job. 94bbl OA downsqueeze on rig 1 2 3 5 Production Casing: 7" 26# L-80 BTCMD Set @ 7,562’ KB T-3 Peforations: @ 7,600' – 7,800' KB (200') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 2,705.6' KB Production Tubing: 4.5" 12.6# L-80 IBT-M Set @ 7,466' KB 7 Item Depth - tops (KB) 1 TUBING HANGER 23' 2 CAMCO NO GO 'DB' NIPPLE 502.7' 3 BAKER CMU SLIDING SLEEVE W/ 3.75" NO GO PROFILE 7,365.70 4 CAMCO D NIPPLE W/ 3.813" DB PROFILE 7,382.4' 5 ZXP HR LINER TOP ISOLATION PACKER W/ TIE BACK 7,415.5' 6 G-22 LOCATOR 7,428.1' 7 BAKER 80-40 SEAL W/ 1/2 MULESHOE 3.98" x 3.00"7,429.3' 8 RS PACKOFF SEAL NIPPLE 7,434.4' 9 BAKER FLEX-LOCK LINER HANGER 7,437.2' 10 BAKER 80-40 SEAL BORE EXTENSION 7,446.5' 11 CROSSOVER BUSHING 7465.7' 6 8 4 9 10 11 Liner: 3.5" 9.3# L-80 SLHT Set @ 8,010’ KB C80 @ 2930' KB C80 @ 2930' KB Plug #1 – Reservoir TOC ±7,545' RKB 1 Regg, James B (OGC) From:Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent:Wednesday, August 17, 2022 10:00 AM To:Regg, James B (OGC); Wallace, Chris D (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay Subject:CPAI 2P-Pad shut in tests 08-16-22.xlsx Attachments:MIT KRU 2P PAD SI TESTS 08-16-22.xlsx All Attached is the 10 426 form for the shut in tests performed on 2P pad on the 16 th of Aug 2022. Please let me know if you have any questions or concerns. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2040170 Type Inj N Tubing 2605 2620 2610 2610 Type Test P Packer TVD 5209 BBL Pump 3.2 IA 470 3590 3500 3480 Interval V Test psi 2900 BBL Return 3.1 OA 203 360 310 290 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2011820 Type Inj N Tubing 827 827 828 828 Type Test P Packer TVD 5428 BBL Pump 1.0 IA 460 3210 3145 3130 Interval V Test psi 2900 BBL Return 0.9 OA 277 363 319 309 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2020180 Type Inj N Tubing 808 1001 980 953 Type Test P Packer TVD 5456 BBL Pump 2.3 IA 410 3200 3090 3075 Interval V Test psi 2900 BBL Return 2.0 OA 277 576 515 484 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2011020 Type Inj N Tubing 875 876 876 876 Type Test P Packer TVD 5219 BBL Pump 2.1 IA 390 3200 3110 3100 Interval V Test psi 2900 BBL Return 1.8 OA 236 569 539 531 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2020910 Type Inj N Tubing 1091 1091 1091 Type Test P Packer TVD 5177 BBL Pump 3.2 IA 450 3200 2105 Interval V Test psi 2900 BBL Return OA 278 405 345 Result F Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031530 Type Inj N Tubing 886 887 887 887 Type Test P Packer TVD 5141 BBL Pump 1.6 IA 470 3210 3110 3090 Interval V Test psi 2900 BBL Return 1.6 OA 254 356 321 312 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2010820 Type Inj N Tubing 112 288 298 294 Type Test P Packer TVD 5274 BBL Pump 1.7 IA 950 3210 3110 3100 Interval V Test psi 2900 BBL Return 1,6 OA 211 428 303 253 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031540 Type Inj N Tubing 882 882 882 882 Type Test P Packer TVD 5234 BBL Pump 2.0 IA 210 3210 3110 3110 Interval V Test psi 2900 BBL Return 1.8 OA 438 444 444 443 Result P TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting 2P-438 2P-447 MITIA every 2 yr to max anticipated injection pressure per AIO 21C.002 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 2P-429 2P-432 2P-434 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 2P-427 Notes:MITIA every 2 yr to max anticipated injection pressure per AIO 21C.001 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 ConocoPhillips Alaska Inc, Kuparuk / KRU / 2P Pad Witness Waived by Guy Cook Beck / Borge 08/16/22 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 Tubing plug set at 8110' MD Notes: Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 2P-419 2P-420 Form 10-426 (Revised 01/2017)2022-0816_MIT_KRU_2P-pad_8wells 2P-447 MEMORANDUM TO: Jim Regg % r, P.I. Supervisor FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, August 6, 2020 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 2P-447 KUPARUK RIV U MELT 2PA47 Src: Inspector Reviewed By: P.I. Supry tTG� Comm Well Name KUPARUK RIV U MELT 2P-447 API Well Number 50-103-20468-00-00 Inspector Name: Guy Cook Permit Number: 203-154-0 Inspection Date: 8/1/2020 Insp Num: mitGDC2008031 1 1 3 54 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min wi - PTD 2031540 Type Test Test psi! 2900 - IA 17s loco loso . ' SPT p Ioso � Well 2P-447 Type InJ TVD 5226 Tubing 1076 3220 3150 " 3140 -- - BBL Pumped: 23 BBL Returned: 2-3 OA 1179 �— 1192 1217 1226 " 1 - L — Interva] REQVAR ;p/F L P Notes: MIT -IA every 2 years to max anticipated surface injection pressure per AIO 2 1 C rule 4. Testing was completed with a Little Red Services pump truck and calibrated gauges. Well is waivered for the OA charging from the formation and allows the OA to pressure up to 1800 psi while the well is in operation. The waiver expires on 10/21/20 at the expiration of AIO 21B (currently expected 10/21/20), whichever comes first. Thursday, August 6, 2020 Page 1 of I Operations Abandon Performed: Suspend ❑ Plug for Redrill ❑ Dperator ConocoPhillips Alask; ne: Iddress: P. O. Box 100360, An 'roperty Designation (Lease Number; 'ace: ADL 373112, ADL: 389058 None STATE TI ALASKA OIL AND G CONSERVATION STION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Plug Perforations Fracture Stimulat Perforate Pull Tubing ❑ Other Stimulat] Alter Casing ❑ Perforate New Pool ❑ Inc. Repair Wel❑ Re-enter Susp Well ❑ 4. Well Class Before Work: Development ❑ Ex loratory 5P 'Ofa9e. Alaska 99510 Stratigraphic ❑ p ❑ 203-1: Service 6. API per 2P-447 tal Depth None feet measured N_nefeet measured measured 8�feet true vertical 5— 234' feet true vertical 54=feet Plugs � Junk active Depth measured 7800' true vertical 5_� feet feet Packer 'ing Length Size Structural MD TVD Conductor 78 Surface 2480 161,108' 9625 108' Intermediate 7537' 2706' 2318' Production 7„ 7562' 5306' Liner 595' 3.5" 8010' 5546' ,ration depth Measured depth 7600-7800' feet True Vertical depth 532 feet 9 (size, grade, measured and true vertical t``ak.v 38 TAp�po- tions shutdowh Changved Progrzin ❑Other: Wnjection startup ❑✓ measured None feet measured N_nefeet measured 7429' feet true vertical 5— 234' feet Burst Collapse ca depth) 4.5" � LL -B=-- 7466' rs and SSSV (type, measuretl — and true vertical depth)5255' SEAL ASSY: BAKER 80-40 W80-40 W/�ESHOE SEAL ASSY: MD=7429', TVD=523 mutation or cement squeeze summary: SSSV: NONE— �_ NONE Is treated (measured): NONE ant descriptions including volumes used and final pressure: NONE Prior to well operation: Subsequent to operation: 14. Attachments (regwred per 20 qqc 25.0 70 , zs.o71, s 21.2e37 Daily Report of Well Operations Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ 17. I hereby certify that the foregoing is true and Abbas Staff Petroleum Enoineer or Exploratory ❑ Development❑ Service Nell Status after work: ❑ Stratigraphic ❑ OR E]WINJ Oil ❑ Gas ❑ WDSPL ❑ WAG the best of my V7 -L 9ql-f/j 9 Form 10-404 Revised 4/2017 / y `//, 0 GINJ ❑ SUSP❑ SPLUG e. Sundry Number or N/A if C.O. Exempt: 318-449 Contact Name:Sayeybas Contact Email: saveed abbas@conocoohilliDs com 0 B'r 20I Contact Phone: 907-265-1109 REIMS AUG 157mQ Submit Original Only ConocoPhillips Alaska, Inc. 700 G St. Anchorage, AK 99501-3448 August 5th, 2019 AOGCC Commissioner State of Alaska, Oil & Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, AK 99501 Dear Commissioner, ConocoPhillips Alaska, Inc. has completed changing the service of the Kuparuk River Unit (Meltwater) Well 2P-447 from Gas Injection to Water Alternating Gas Injection. Enclosed you will find a 10-404 report of Sundry Well Operations for ConocoPhillips Alaska, Inc. If you have any questions regarding this matter, please contact me at 907-265-1109. Sincerely, Sayeed Abbas Staff Petroleum Engineer ConocoPhillips Alaska, Inc. Attachments: Report of Sundry Well Operations Daily report of Well Operations Well Schematic 1 ^� KUP INJ WELLNAME 2P-447 WELLBORE 2P-447 Conoc Phillips Ai988a. Ino. o' Well Attributes Max Angle & MD TD Fieltl Name A" N"'APIlUµ4 Well bare 5taluz ncH- MO2,99 MELTWATER 5010321]46800 INJ 9.62 ],662.99 BLISS(fiKBI 8,015.0 CanmerA R2slppMS SSSV: NIPPLE -R, Mnoution In, Dm KBGM IRI Lamm: 27.98 the Rebae Dale 11202004 2P-44].]QEQ19]:31:4]AM Last Tag nal e,hemzaamcwell MnoWM Depen'Kel Em 0. wmllwr, DetMm By c0NCUCTOR:M.O1SO 0 NPPLE; wiz sSRrACE:2at-2]C3.6 WS LIFT 1,SId2 9LEEYE', 7,3aS7 MPPLE: ].aB2.a LOCATOR. 7.4al 4 SEAL ASSY: ] 4E3 IMERMEDIATE', 25.LZMC0 RPERF; 1.0-16100 APERIF 7KOV-7,640.0 (PERF: 7,1SC.SZ MOS IKIFF;],]M O?.B O- UMER.741i560100� Last Tag'. RKB ],690.0313112019 juppien Last Rev Reason MnolAionEna Dale j We11Wre ILae[Moa By Rev Reason'. Pulled A-1 Injection Valve I]l2ffi019 2144] krgusp Casing Strings S) se Depth MKBJ sx Depin UVUl-. WOLenll._Died. Top Thread CONDUCTOR 16 15108.0 1080 62.50 H-40 WELDED Casing oexoapnon 006" M,jTpp Ca51ng 0ezc1,H- 00 (in) IDhIS set Depth(RKBI Set Depth NVOt. WI IT.. Guee Topinool SURFACE 9518 8.82.705.6 2,31].5 40.00 L-80 BTC Colne Dnmlption Ot ID(in) Ksl Sn Depth MKS) Set Depth LOO).. Ofti(L.. Gh. TopThreatlINTERMEDIATE ] 8.2],582.0 5,305.9 26.00 L41 BTC -MD Casing Description 00(Inl 10(S) S, Do"'("a) SN Depth TWO)... When IT Grade Top ThteaaLINER 3112 2.95 8,010.0 5546.3 9.30 L-80 SLUT Liner Details Ton MKs) Tap (Trt11IRKB) TDpIM pI 1. Dee Corn (in) (les) ],415.5 5.226.2 SS.dS PACKER ZXP HIS LINER TOP ISOLATION PACKER eoNE 4.730 BACK 7,434.4 5.3.9 55.82 NIPPLE RS RACKOFF SEAL NIPPLE 4.250 74372 ------5 2r8-5 55. HAN ER BAKER FLEXLOCK LINER HANGER 0 7,4,16.5 5247-7 5 .10 BE BAKER ROAD 7,4657 52544 56.53 %O BUSHIN CROSSOVER BUSHING 3.000 Tubing Strings Tnbmg Deaoaptun ming Me... m(nl rop(nl<BI sN Depth (n.. sal Depin (TVD (_Wlnhml Gnae TUBING 41/2 396 230 1,4660 5,254.5 12.60 L-80 Top ennnedinn IBT-M Completion Details Top(TVDI I Topind Top MKB) I MKD) PI tum Des Com Nominal ID1in1 23.0 23.01 0.00 HANGER 4.500 502.7 502.6 379 NIPPLE CANCNO GO'OB'NIPPLE 3.875 7,365.7 5,18].) 54.68 SLEEVE BAKER MU LIDNG SLEEVE M3.813'DB PROFILE 3.813 ],382.4 5,20].4 54.94 NIPPLE CAMC0'DB' NIPPLE w0]5 -NO GO PROFILE 3750 ],428.1 1111A 55.68 LOCATOR G-22 LOCATOR 3.010 ]429.3 5234.1 55.]1 SEALASSY BAKER 80.40 SEAL w11,2 MULESH0E 3.98"x300- 3.000 Perforations .& Slots roe MKs) atm (nasi TopDene LIMED BIMI]VD1 MKB/ nKea UI Dale Shot (swlsm 1 TVFo m 7.600.0 7.640.0 5,325.4 5,3453 T-3, 1P447 M12004 6.0 APERF 2.5- HSD PJ ChMs, 60 deg phase 71600.0 7,6,10.0 5.325.4 5.3453 TJ. 2Pi17 2]24GD14 6.0 RPERF 25"X 20' hsc.8SPF. S SPF. PHASING MIL ENIUM 7=.7. _7771160-0 5,376.2 5,419.0 T-& 2P447 2/-20 6.0 (PERF TVHBO PJ CMgs, 60 ON phase 7,780.0 7,800.0 5.419.0 5.42.9 Td, 2P447 26)2004 6.0 /PERF 2.5-HSD PJ CI,,giL6 deg phase Mandrel Inserts Sl Non Top (RKB/ iop14.) (RKB) make MetlN OD (n) Sery Valor Type latch Type Pon Slee 1n1 TRO Run 1.11 Run Date Co. ],3162 5.1689 CAMCO KBG-2 1 as Lifl DMV BK 0.000 0.0 1127/2004 Not": General & Safety End Sate Mrrotatlon 6114/2004 NOTE: WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 12/92008 N0 TE VIEW SCHEMATIC w1Na6Pa ScrematC9.0 11/12,2012 NOTE: OA OBSTRUCTED wI CEMENT @t SURFACE 2P-447 DAILY REPORT WELL OPERATIONS 713112019: 2P-447 started water injection as part of the process to change the well from Gas Injection (GINJ) designation to Water -Alternating -Gas (WAG) designation THE STATE Alaska Oil and Gas 01 ASKA Conservation Commission GOVERNOR BILL WALKER Adam Childs Staff Petroleum Engineer ConocoPhillips Alaska, Inc. P.O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Meltwater Oil Pool, KRU 2P-447 Permit to Drill Number: 203-154 Sundry Number: 318-449 Dear Mr. Childs: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.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. J,%,, DATED this V4 day of October, 2018. Sincerely, Hollis S. French Chair RBDMS, OCT 2 2 2018 . mks® c a - J , STATE OF ALASKA OCT 0 8 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION C A ,+.tG APPLICATION FOR SUNDRY APPROVALS Oil JJ @@ 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 ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: _Convert GINJ to WAG_ ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhilli s Alaska Inc. Exploratory ❑ Development B- 203-154 Stratigraphic ❑ Service R 6. API Number: 3. Address: P. O. Box 100360, Anchorage, Alaska 99510 $,Z;6, 50-103-20468-00 —00 Z If perforating: 8. Well Nam and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A KRU 2P-447 Will planned perforations require a spacing exception? Yes El No D 9. Property Designation (Lease Number): 10. Field/Pool(s): Surface: ADL 373112/ BH: ADL 389058 Kuparuk River Field / Mellwater 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). 8,010' 5,546' 7,800' 5,430' None None Casing Length Size MD TVD Burst Collapse Structural Conductor 78' 16" 108' 108 Surface 2,480' 9-5/8" 2,706' 2,318' Intermediate 7537' 7" 7,562' 5,306' Production Liner 595' 3-1/2" 8,010' 5,546' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7,600-7,81 5,325 - 5,430' 4.500" L-80 7,466' Packers and SSSV Type: SEAL ASSY: BAKER 80-40 w/ MULESHOE Packers and SSSV MD (ft) and TVD (ft): SEAL ASSY: MD= 7,429, TVD= 5,234' SSSV: A-1 INJ VALVE ON 3.875" DB LOCK W.806 BEAN, HSS -120 SSSV: MD= 502', TVD= 502' 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Iv[ Service 14. Estimated Date for 15. Well Status after proposed work: .1 Commencing Operations: 10/15/2018 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑✓ 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. Authorized Name: Adam Childs Contact Name: Adam Childs Authorized Title: Staff Petroleum Engineer ContactEmail: adam.g.childs@conocphillips.com Contact Phone: 907-263-4690 Authorized Signature: Date: (O COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. tf/'if I - N UI �,r Plug Integrity F-1BOP Test ❑ Mechanical Integrity Test EJLocation Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No E Spacing Exception Required? Yes ❑ No d Subsequent Form Required: APPROVED BY Approved by: ' COMMISSIONER THE COMMISSION Date: 1 O /t ot 1 I°.. R (rc C Dry 10 /7 �t8 ` `�� //O ) �D (� Submit Farm and Form 10403 Revised 4/2017 ABIyn,A&.1&d aMl�a2 o t he a of oval. Attachments in Duplicate W�1YY�1JJ�nLL�r WW1 ConocoPhillips Alaska, Inc. 700 G St. Anchorage, AK 99501-3448 October 8th, 2018 AOGCC Commissioner State of Alaska, Oil & Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, AK 99501 Dear Commissioner, ConocoPhillips Alaska, Inc. requests approval to change the service of the Kuparuk River Unit (Meltwater) Well 213-447 from Gas Injection to Water Alternating Gas Injection. Enclosed you will find a 10-403 Application seeking Sundry Approval for ConocoPhillips Alaska,lnc. If you have any questions regarding this matter, please contact me at 907-263-4690. Sincerely, Adam Childs Staff Petroleum Engineer ConocoPhillips Alaska, Inc. Attachments: Sundry application Proposal Summary Well Schematic I 2P-447 DESCRIPTION SUMMARY OF PROPOSAL Commensurate with the recently revised and approved AIO 21C, ConocoPhillips Alaska Inc. is in the process of facility and wellbore modifications to enable water injection in Meltwater. As part of these changes, ConocoPhillips Alaska Inc. is seeking approval to change the service type of Meltwater injector 2P-447 from its current Gas Injection (GINJ) designation to Water -Alternating -Gas (WAG). The 2P-447 successfully passed an MIT -IA test to 3300 psia on 8/15/18. AM§%k KUP INJ 2P-447 Gon«V011illi Il Attributes --- Maz AngM&MD TD P$ WNIMIe API1 WIl FINE Name Wellbore SWUS nG (• MpINNB) IICI B1m IXS Alaska, InC. 501032046800 MELTWATER INJ 59.82 ],68299 8,0150 Comment X23(Ppm) WIa MIIWat-- E -Dale KB Grd 1f11 He Re"' -'a SSSV: NIPPLE Last NO: 27.98 112012004 2-447, pOvRon7sa:a8 AM Last Tag Ann0tYc11pepd(Po(BI End 0. 11 Mat By Lae[Tag'RKE 70860 4/192018 himusp Last Rev Reason Aan.tlion End DelLast Matl By Revftert A-11njeLllon valve pull tlue t.,. P1.9, Re -the A-1 4/221l 2019 fergusp RaIRasO Casing Strings Lasing 0eecrlplbn UD in)Top IXHeI sm pepm lnKB sel lhpm lrvp)... wuLen X._Gutla mpmreatl CONDUCTOR 062 300 108.0 1000 5250 H-40 WELDED Casing Ib6CXP11On WTop IXMB) Se10epIn INKS) Set Ceplh lNp).. WXLen l., Glxle Top Thrmt SURFACE .835 28.1 2.705.6 2,31]5 4000 L-00 BTO Casing Dencdplion 00TOP Kit8l Sel Oeplb lllKie IWIe hIND)... WXLen 11... Gtatle Top ThreesINTERMEDIATE An .276 252 1.562.0 5,3059 2500 L-60 BTO MDCasing nexcriplion OD Top IXKa) Set Oeplh INKBI Set Depth OND)... WXLen II.. Gr., Top Thread LINER .992 7415.5 00100 5,546.3 9.30 L-60 SLAT Liner Details uem Des eom (In) ftKONomin, Tnp 1741 raP fn'D)22KB)62 ropy 7,415.5 52262 5545 PACKER ZAP HR LINER TOP ISOLATION PACKER wRIE 4]30 4 BACK coNOucroR'aoo4m0 7,4344 5,238.9 55.82 NIPPLE RBPACKOFF SEAL NIPPLE 4.250 ],43]2 5,230.5 55.89 HANGER BAKER FLEXLOCK LINER HANGER 5.0M MINFURA2v 7,446,5 5,2431 58.10 SBE BAKER 80.40 4000 7465,7 5,254.4 56.53 NO BUSHING CROSSOVER BUSHING 3.000 Tubing Strings bin,N.- ription Slnng Ma... lD lin Top IXKR) Sel Depth (fl.. Sel Deplh ITVp 1.,. W111bIX) Gratle Tap Connection TUBING 4112 3958 230 )466.0 52505 1260 L-80 6T.M Completion Details Tap IND) TOP mN Nominal Top IXKBI (XKB) 1°) em Das Com 1. "n' 230 23.0 0.00 1 HANGER 4.500 5021 5026 3.79 NIPPLE CAMCO NO GO Go' NIPPLE 3.875 SURFACE', ffi I.27MB 7.3857 5,19)] 5468 SLEEVE BAKER CMU SLIDING SLEEVE wl3.813"pB PROFILE 3.813 7,3826 5,207A 54.94 NIPPLE CA SO'DEBNIPPLEw1.7V NO GO PROFILE 3.750 7428.1 5.233.4 5568 LDOATOR G-22LOCATOR 3010 7,4293 5,234.1 55 fl I SEAL AGSV I BAKER 60-40 SEAL W/1/2 MULESHOE 3 9W 3.00' 3000 Other in Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) on (ND) Top Incl Top ln0el (ftKC) I I°1 Des cam un Oale ID lint 5020 5019 3.76 A -i 11 3.5]5"DB L11184.5".6055EAN, HSS -120 4/22/2016 0.806 GASUFL1ms2 Valve Perforations & Slots Choi Den SLEEVE: 7J65] TOPInKB) 61miXKB) Top INE) (IMKB) B1m 1ND) LMe Drte 15hD t 1 Type Com ],600.0 ],640.11 5.325.4 5,3457 T3,2P-447 2242014 60 RPERF 25" X 20' hsc. 6 SPF. 6O DEG PHASING MILLENIUM NIPPLE, 7024 7,6000 7,640.0 5.325.4 5.3457 T -3,2P-447 3/1/2004 6e AP ERF 2.5" HBO PJ Chlgs, 60 deg phase ],]000 7.7800 5,375.2 5,419.0 T-3, 2P-447 20/2004 Be IPERF 25" HSD PJ Chrgs, 60 deg phase ]]800 28000 5,4190 5,429.9 T-3. 2P-447 23/2006 60 (PERF 25"HSD PJ Chrgs, 60 deg phase Mandrel Inserts 51 LOCATOR; 748.1 DnioPINp N Top IKKB) TOP Make Matlel 00 (n) Sory Valve Type Lalcb Type Poll (n)) T(ps.) (psi) Run Oale tom 0 1 13162 5.160.9 CAMCO KBG2 1 Gas Lifl OMY BK 0000 09 1/27/2004 Notes: General & Safety Em B." SEAL ACI7,Ue2 6/14/2004 NOTE. WAIVERED OA'. PRESSURE CHARGING FROM RESERVOIR 12312006 NOTE: VIEW SCHEMATIC W/Alaska Schema[ic90 111122012 NOTE: OR OBSTRUCTED w/ CEMENT @ SURFACE INTERMEOMTE', 252-7562E APERF', 7.6000.7,6400'',5s RPERF; 76000.7.N00 -em IPEFF;77000�ohI IPERF;77000�78W 0� LINER:7.41558.0100� Loepp, Victoria T (DOA) From: Childs, Adam G <Adam.G.Childs@conocophillips.com> Sent: Thursday, October 11, 2018 9:59 AM To: Loepp, Victoria T (DOA) Subject: 2P Injector Sundry Requests Victoria, I received your voicemail regarding the 2P sundry requests. The majority of those MITIAs performed last month were state witnessed, but not all of them. Three of the injectors were shut-in at the time of testing, and were therefore non - state witnessed tests. A separate 10-426 form was sent to the state with the results of these tests. Please see table below including which of the wells tested in August were state witnessed, and when the last witnessed tests were for those that were shut-in. Well Name 2P-419 August 2018 State Witnessed Test? Yes Status Of Test Passed Last State Witnessed Test Status of Last Test 2P-420 Yes Passed 2P-427 No Passed 8/20/16 Passed 2P-429 Yes Passed 2P-432 Yes Passed 2P-434 No Passed 11/09/14 Passed 2P-438 No Passed 9/30/16 Passed 2P-447 Yes Passed Let me know if you have any other questions. Thanks, Adam Childs 907-263-4690 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg r r DATE: Monday,August 22,2016 P.T.Supervisor feel 66(ZS i SUBJECT: Mechanical Integrity Tests 1 CONOCOPHILLIPS ALASKA INC 2P-447 FROM: Brian Bixby KUPARUK RIV U MELT 2P-447 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry J V— NON-CONFIDENTIAL Comm Well Name KUPARUK RIV U MELT 2P-447 API Well Number 50-103-20468-00-00 Inspector Name: Brian Bixby Permit Number: 203-154-0 Inspection Date: 8/20/2016 Insp Num: mitBDB160821044658 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2P-447 ]Type Inj G 'TVD 5226 Tubing 2525 2525 ' 2525 - 2525 ' PTD 2031540 ' Type Test SPT Test psi 2900 ' IA 750 3300 - 3250 - 3240 Interval REQVAR P/F P '/ OA 1219 1225 _ 1 1253 1260- Notes: A1O-21B.001 The IA looked to be stabilizing but the OA was coming up a little: SCANNED MAY. 92017 1 Monday,August 22,2016 Page 1 of 1 Wallace, Chris D (DOA) From: Regg, James B (DOA) Sent: Sunday, March 01, 2015 1:07 PM To: NSK Problem Well Supv;Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: Report of insufficient MIT test pressures 2P-419 (PTD 204-017) and 2P-447 (PTD 203-154,AIO 21A.006) 3-1-15 Attachments: 2P-419 90 day 110 3-1-15.JPG; 2P-447 90 day TIO 3-1-15.JPG Understand the time to clean up due to last night's storm. I don't think a retest is necessary. More important is how this happened - the initial test was done to the required pressure so why not the subsequent test? CPAI's new WellTrak system should have prevented this. Jim Regg Supervisor, Inspections AOGCC 907-793-1236 Sent from Samsung Mobile SCANNED i\aAt.: Original message From: NSK Problem Well Supv<n1617@conocophillips.com> Date: 03/01/2015 11:18 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov>,"Wallace, Chris D (DOA)" <chris.wallace@alaska.gov> Cc: "Senden, R. Tyler" <R.Tyler.Senden@conocophillips.com> Subject: Report of insufficient MIT test pressures 2P-419 (PTD 204-017) and 2P-447 (PTD 203-154, AIO 21A.006) 3-1-15 Jim, Chris, During a routine audit, it was identified that 2 gas injectors at Meltwater, namely 2P-419 (PTD 204-017)and 2P-447 (PTD 203-154 AIO 21A.006) recently had witnessed MITs performed to insufficient test pressures. Per AIO 21A,the MITs need to be performed to the maximum anticipated injection pressure. Both wells were shut-in at the time of the 2 yr pad testing in August 2014 and had witnessed MITs performed at that time. These tests were appropriately performed to the anticipated injection pressure (see attached MITs for reference). After returning to injection on 12-11-14, 2P-419 and 2P-447 were tested on 12-26-14 after reaching stabilization. However those tests pressures were insufficient to meet the requirements of Meltwater's Area Injection Order. It is CPAI's intention to keep the wells online and to schedule witnessed retests ASAP. However, if you believe it is appropriate,we can shut in the wells. Of note, an intense Phase 3 storm came in last night and it is expected to take many days of cleanup. Therefore it will probably be several days before we will be able to schedule the tests. Please let us know if you disagree with the plan. 1 Well Name 2P-447 Notes: Start Date 1211/2014 Days 90 End Date 3/1/2015 Annular Communication Surveillance CCC — 140 VJHP :::: : _ - 100 2500 • — S0� •o- 2000 — 60 1500 _ — 40 1000 - `OC — 20 C 0 Nor-1. Nor-14 Dec-14 Dec-14 Dec-14 Jan-15 Jan-15 Jan-15 Feb-15 Feb-15 Feb-1E Mar-15 4_{U 3500- WC! "a000t ZOO _...._.... 4til m 1500 e- - 1000 500 Sep-14 Dec-14 Mar-15 Date Brent Rogers/ Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc Desk Phone (907) 659-7224 Pager(907) 659-7000 pgr 909 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Re DATE: Friday,January 09,2015 gg c � Ic - P.I.Supervisor ( 1 S SUBJECT:Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-447 FROM: John Crisp KUPARUK RIV U MELT 2P-447 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry ,Tg NON-CONFIDENTIAL Comm Well Name KUPARUK RIV U MELT 2P-447 API Well Number 50-103-20468-00-00 Inspector Name: John Crisp Permit Number: 203-154-0 Inspection Date: 12/26/2014 InSp Num mitJCrl41231122145 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well i 2P-447 Type Inj G iTVD 1 5226 Tubing 2700 2700 2700 2700 PTD L2031540 'Type Test SPT Test psi 1500 ' I IA 1620 2217 - 2197 r 2195 Interva !OTHER P/F P ✓ OA 913 910 910 912 - Notes: 4 bbl pumped for test.2 year per AIO 21 A SCANNED Friday,January 09,2015 Page 1 of 1 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. ~03 - 15 'f- Well History File Identifier D Two-sided 1111111111111111111 Organizing (done) D Rescan Needed 1111111111111 111111 R~AN ¢ Color Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, Norrype: D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: Dale3/0/00 r I D Other:: BY: ~ 151 rnP 1111111111111111111 & Project Proofing BY: ~ Dale 3/ b!o~ 3 0 151 Scanning Preparation BY: Date: f + ;]",3 = TOTAL PAGES J /3 (Count does not include cover sheet) , 151 Production Scanning Stage 1 Page Count from Scanned File: I J LJ- (Count does include cover sheet) Page Count Matches Number in scanntg I. P.reparation: L YES BY: ~ Date: 31blDb Stage 1 If NO in stage 1, page(s) discrepancies were found: YES II 111111111/11 ,,11/ NO 151 m¡P NO BY: Maria Date: 151 1111111111111111111 Scanning is complete at this point unless rescanning is required. ReScanned III 11111/11I11 "III BY: Maria Date: 151 Comments about this file: Quality Checked 111111111111111111I 10/6/2005 Well History File Cover Page.doc w��\\I%% s9 THE STATE Alaska Oil and aS ®f CG .serva ion Com! dssion GOVERNOR SEAN PARNELL 333 West Seventh Avenue O ""�++mr ' Anchorage, Alaska 99501-3572 ALASY' Main: 907.279.1 433 Fax: 907.276.7542 Thomas Nenahlo SCANNE'6 Pti C `F t1 1 Drillsite Petroleum Engineer 6-ConocoPhillips Alaska, Inc. Lif P.O. Box 100360 p 3 _- Anchorage, AK 99510 Re: Kuparuk River Field, Meltwater Oil Pool, 2P-447 Sundry Number: 313-569 Dear Mr. Nenahlo: 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, athy P. oerster Q'f Chair, C mmissioner DATED this U day of November, 2013. Encl. r. ^ E °L.a -.. • STATE OF ALASKA O 25 2013 SKA OIL AND GAS CONSERVATION COMMON '4 ( 5 APPLICATION FOR SUNDRY APPROVALS \V#\ 20 AAC 25.280 ( $,, CC.;. 1.Type of Request: Abandon r Plug for Redrill r Perforate New Pool r Repair w ell r Change Approved Program r Suspend r Rug Perforations r Perforate r Pull Tubing r Time Extension r Operational Shutdown r Re-enter Susp.Well r Stimulate r Alter casing r Other: Logging 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Exploratory r Development r 203-154 3.Address: 6.API Number: Stratigraphic r Service 17 P.0.Box 100360,Anchorage,Alaska 99510 50-103-20468-00 7.If perforating, What 8.Well Name and Number: Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require spacing exception? Yes r No r 2P-447 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL03731121ADL0389058 Kuparuk River Field/Meltwater 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): 8015 5549 Casing Length Size MD TVD Burst Collapse CONDUCTOR 78 16 108' 108' • SURFACE 2678 9 5/8 2706' 2318' INTERMEDIATE 7537 7 _ 7562' 5306' LINER 595 3 1/2 8010' 5546' Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 7600-7640,7700-7780,7780-7800 5325-5345,5375-5419,5419-5430 4.5 L-80 _ 7466 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft) SEAL ASSY-BAKER 80-40 SEAL W/1/2 MULESHOE 3.98"X 3.00" MD=7429 TVD=5234 12.Attachments: Description Summary of Proposal F7 13. Well Class after proposed work: Detailed Operations Program BOP Sketch r Exploratory r Stratigraphic r Development r Service P. 14.Estimated Date for Commencing Operations: 15. Well Status after proposed work: 2/1/2014 Oil r Gas r WDSPL r Suspended r 16.Verbal Approval: Date: WINJ r GINJ 13 WAG r Abandoned r Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Tommy Nenahlo Email: Thomas.L.NenahloCa cop.com Printed Name Thomas Nenahlo Title: Drillsite Petroleum Engineer Signature .-7, // /. Phone:265-6934 Date: 10/25/2013 Commission Use Only Sundry Number: Conditions of approval: Notify Commission so that a representative may witness 3‘3®®- S(q Plug Integrity r BOP Test r Mechanical Integrity Test r Location Clearance r t1B MS NOV 2 h Other: �P,�.� I-0 o pexa�"A IA a cC arc6Y1 C-e_ 60 f\1 2.►q.0 ti,3 Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: / l 4 t 4. APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Il $ '�3 ro�ication is valid for 12 months from the date of approval.pp application pp Form 10-403(Revised 10/2012) / Submit Form and Attachments in Duplicate V/ritiG //3 OR1011\4AL �w 3, ,3 • : ` ► OCT 1 72013 1✓ ConocoPhillips AOGGC Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 October 17th, 2013 Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7 th Avenue, Suite 100 Anchorage, AK 99501 SUBJECT: Requests for Administrative and Sundry Approvals for Meltwater Surveillance Initiatives Dear Mr. Wallace: As discussed in the meeting held on September 26th, 2013, between the Alaska Oil and Gas Conservation Commission (AOGCC) and ConocoPhillips Alaska, Inc. (CPAI), the Meltwater team is pursuing a number of surveillance initiatives to aid in the characterization and understanding of the Meltwater shallow gas issue while collecting further data for the evaluation of development options. Attached within this communication are the technical justifications for the necessary administrative and sundry approvals to achieve the objectives of these surveillance initiatives. The surveillance initiatives that are currently being pursued are as follows: • An extended outer annulus bleed at well 2P-431 o Pertaining to this initiative, please find a request for Administrative Approval via Rule 10, Area Injection Order 21A (Amended), for Meltwater production well 2P-431 (PTD 202-053) in regard to Rule 3 (annular pressure limits). Also enclosed is an Application for Sundry Approval (10-403) for authorizing annular flow from 2P-431. • Video and Spectra-Flow® logging at wells 2P-419, 2P-420, 2P-427, 2P-429, 2P- 434, 2P-447 o Pertaining to this initiative, please find a request for Administrative Approval via Rule 10, Area Injection Order 21A(Amended), for Meltwater injection wells 2P-419 (PTD# 204-017), 2P-420 (PTD# 201- 182), 2P-427 (PTD#202-018), 2P-429 (PTD# 201-102), 2P-434 (PTD# 203-153), 2P-447 (PTD# 203-154) in regards to Rule 7 (authorized injection pressure) and Rule 8 (authorized fluids for injection). Please call Tommy Nenahlo at 265-6934, or me at 265-1464 if you have any questions. • • Conoco Phillips p Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 Sincerely, Jerry Dethlefs ConocoPhillips Well Integrity Director Tommy Nenahlo ConocoPhillips Meltwater Drill Site Petroleum Engineer Enclosures: Technical Justification for Administrative Relief Requests Application for Sundry Approval Wellbore Schematic • • ConocoPhillips Alaska,Inc. Kuparuk River Unit Meltwater Pool Injection Wells Technical Justification for Administrative Relief Request,AIO 21A,from Rules 7 and 8 Purpose ConocoPhillips Alaska, Inc. (CPAI)requests that the AOGCC approve this Administrative Relief as per Area Injection Order(AIO)21A(Amended),Rule 10,for temporary relief from criteria set forth in Rules 7 and 8 that defines the authorized pressure and fluids for injection,respectively. CPAI requests temporary relief from these rules to conduct video and Spectra Flow®logging on six Meltwater injectors, 2P-419(PTD#204-017),2P-420(PTD#201-182),2P-427(PTD#202-018),2P-429(PTD#201-102), 2P- 434(PTD#203-153),and 2P-447(PTD#203-154). By conducting video logging on these injectors,the Meltwater team is looking to inspect possible collapsed liner, as has been indicated by recent and historic well work. By conducting Spectra Flow®logging,the Meltwater team is looking to determine if there is fluid movement around the production casing cement shoe over a range of sand face injection pressures. Video Logging Campaign Summary During recent and historic well work, indications of potentially collapsed liner in injectors 2P-419, 2P- 420,2P-429,2P-434, and 2P-447 have arisen. In a number of these injectors it is believed that these potential collapsed liner locations are limiting our injection into the Bermuda formation. To aid in characterizing and understanding these potential collapsed liner locations, as well as to formulate a plan to remediate this issue, it is necessary to run video logs to inspect the locations. To safely execute a video log on a miscible injectant(MI) injector it is necessary to adequately displace the near wellbore formation to ensure that MI returns are not taken to surface. Therefore, it is recommended that the near wellbore formation be displaced with a minimum three tubing volumes of hot diesel. Upon adequately displacing the near wellbore formation,the video log will be run while injecting filtered sea water to allow for the optimum video resolution to inspect these potential collapsed liner locations. The ability to provide a sufficient injection rate at Meltwater is critical as it is necessary to ensure that adequate lift gas temperatures are maintained at the Meltwater's Drill Site,2P. Drill Site 2P is located approximately twelve miles from the nearest drill site,2N. This distance provides a significant amount of time for cooling of the MI that is used as injection fluid as well as a lift gas for the producers. During winter months and low injection rate periods,the temperature of the lift gas has historically become low enough to cause rapid paraffin deposition in the upper wellbore of the producers and can choke flow to a point at which the well would need to be shut in. If enough production is shut in the temperature of the Meltwater produced oil line could become low enough to require it to be shut in and de-inventoried to mitigate the potential for the line to freeze. In 2012, modeling was completed to determine the minimum MI gas delivery temperature at Meltwater to ensure that this issue can be mitigated. As anticipated,the variable with the greatest effect on the MI gas delivery temperature at Meltwater is the MI injection rate. By completing video logs on these potential collapsed liner locations to aid in developing a remediation strategy it is believed that this risk of low lift gas temperature and a produced oil line freezing scenario can be reduced. To successfully complete this video logging campaign,temporary relief from AIO 21A(Amended) Rules 7 and 8 is requested to adequately displace the formation and conduct these video logs. CPAI Well Integrity Director 10/17/2013 • • Spectra Flow®Logging Campaign Summary To successfully complete this Spectra Flow®logging campaign,temporary relief from AIO 21A (Amended)Rule 8 is requested to allow for the temporary injection of sea water into the Bermuda formation. Sea water is not an authorized injection fluid in AIO 21A(Amended). The Halliburton®Spectra-Flow logging technology is capable of identifying fluid movement around the production casing shoe by identifying the presence of oxygen. Sea water will provide the oxygen in the injection fluid to ensure the logging campaign can be completed successfully. To achieve the most information from the logging campaign,temporary relief from AIO 21A(Amended) Rule 7 is requested for exceeding the established pressure limit during injection of sea water into the Bermuda formation while logging. The Meltwater team would like to vary the injection pressures of the sea water while performing Spectra Flow®logging runs to complete the following objectives: 1. To confirm there is not fluid movement around the production casing shoe when injecting within the sand face injection pressure limit established by Rule 7 in AIO 21A(Amended). 2. To determine if MI migration is a result of historic sand face injection pressures at Meltwater prior to the issuance of AIO 21A(Amended). The second objective stated above is intended to further the Meltwater team's understanding of the MI migration mechanism. As discussed in the November 2012 hearing with the AOGCC,the Meltwater team proposed two potential MI migration mechanisms. One of these migration mechanisms includes the possibility of MI migration around the production casing cement shoe. By completing the aforementioned objectives,the Meltwater team will be able to make more informed decisions to ensure the field is operated safely and effectively. Video and Spectra Flow®Logging Procedure Outline The following is an outline of the procedure for the proposed Spectra Flow®Logging campaign to be performed on each of the six injectors. 1. Displace the near wellbore formation with a minimum three tubing volumes of hot diesel to mitigate the risk of taking MI returns at surface during well work operations. o Injection pressure at surface not to exceed 2,495 psig with diesel(4475 psig at perf depth assuming 0.36 psi/ft gradient and 5,500 ft TVD to mid-perfs) 2. Rig up E-Line with Spectra-Flow®Logging tools and IPROF string to monitor bottomhole conditions. 3. Little Red Services(LRS)to pump sea water down on well using a step rate approach as defined below. During each step,the Spectra-Flow®logging tool will be passed up and down to identify the possible height of injected fluid above the perforations. a. Step 1: 500 psi WHIP(2975 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) b. Step 2: 750 psi WHIP(3225 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) c. Step 3: 1,000 psi WHIP(3475 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs)\ d. Step 4: 1,250 psi WHIP(3725 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) e. Step 5: 1,500 psi WHIP (3975 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) CPAI Well Integrity Director 10/17/2013 2 • • f. Step 6: 1,750 psi WHIP(4225 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) g. Step 7: 2,000 psi WHIP(4475 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) 4. Upon completion of the step rate logging runs,E-Line and LRS will rig down and move off the well. 5. Injection of seawater will cease on each individual well after the logging runs are completed. 6. The well bores will then be freeze protected with the injection of hot diesel with the injection pressure at surface not to exceed 2,495 psig(4475 psig at perf depth assuming 0.36 psi/ft gradient and 5,500 ft TVD to mid-perfs) Administrative Approval Request: CPAI requests temporary relief from(AIO)21A(Amended),Rules 7 and 8 to conduct Video and Spectra Flow®logging on six Meltwater injectors: 2P-419(PTD#204-017), 2P-420(PTD#201-182), 2P-427(PTD#202-018), 2P-429(PTD#201-102), 2P-434(PTD#203-153), 2P-447(PTD#203-154). 1. Temporary relief from AIO 21A(Amended)Rule 7 is requested for exceeding the pressure limit during injection of sea water into the Bermuda formation during the logging operations only. The approval is requested for a period of six months from the date of the AOGCC approval. 2. Temporary relief from AIO 21A(Amended)Rule 8 is requested to allow for injection of sea water into the Bermuda formation for the purposes of performing the logging operations only. The approval is requested for a period of six months from the date of the AOGCC approval. CPAI Well Integrity Director 10/17/2013 3 • • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 October 25th, 2013 Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Response to Questions Regarding Requests for Administrative and Sundry Approvals for Meltwater Surveillance Initiatives Dear Mr. Wallace: Thank you for your reply regarding our requests for Administrative and Sundry Approvals for the Meltwater surveillance initiatives. Please find below the responses to your questions in your emails that were sent October 22nd, 2013. Injected Volumes and Duration Per the plan developed by the Meltwater team, it is expected that no more than 6,000 barrels of Beaufort seawater will be required to be injected at each injector to complete the video and Spectra-Flow®logging initiatives. This estimate of 6,000 total barrels includes the procedures to complete the miscible injectant displacement, video logging, and Spectra-Flow®logging procedures. Below is a high level breakdown of this estimate for clarity: • Displacement volume estimate: 1,000 BBLs of seawater per well o This is volume that we may need during the video and/or Spectra-Flow®logging campaign to mitigate the potential for having miscible injectant present in the wellbore. • Video Logging volume estimate: 1,600 BBLs of seawater per well o To minimize the turbidity of the fluid, and thus increase our video resolution at the potential collapsed liner locations, filtered seawater will be used to displace the wellbore and ensure it remains displaced throughout the video logging procedure. • Spectra-Flow®Logging volume estimate: 3,400 BBLs of seawater per well o This estimated volume of 3,400 BBLs is planned to be split evenly amongst the seven pressure stages outlined in the Technical Justification for Administrative Relief Request, AIO 21A(Amended), from Rules 7 and 8, that was submitted to the AOGCC on October 17th, 2013. o It is preferred that seawater be used for the Spectra-Flow®logging as upright tanks will be on location at Drill Site 2P to store the seawater that will support the aforementioned video logging. Operationally, it is preferred that Kuparuk produced water be kept separated from seawater due to corrosion concerns. The above logging initiatives may require up to 168 hours(7 days)to complete, per well. • • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 Beaufort Seawater Compatibility Study A Meltwater field fluid sensitivity and stimulation study was completed in March of 2001. This study utilized core samples from the Meltwater North #1 and Meltwater North #2 wells that included an investigation into the sensitivity of preserved reservoir samples to the proposed flood waters. These proposed flood waters included a Kuparuk produced water blend and a 75% Kuparuk produced water/25% Beaufort seawater blend. The investigation into the sensitivity of the Meltwater North#1 and Meltwater North#2 core samples to the proposed flood waters concluded that there were no adverse reactions to the75°/o Kuparuk produced water/25% Beaufort seawater blend identified. The Meltwater team plans to inject 100% Beaufort seawater to minimize the turbidity of the fluid while conducting video logging. Although we do not have fluid sensitivity studies completed with 100% Beaufort seawater, the salinities of the Kuparuk produced water and the Beaufort seawater are similar, and no appreciable compatibility problems for either the Meltwater formation or its confining zones are expected. If injectors do incur damage from sea water injection the damage will be contained within a small radius of the wellbore due to the small volume of fluid required to complete the logging initiatives. Any damage to the near wellbore formation that may arise can be reversed by employing remedial treatments. Sundry Requests Attached you will find six Application for Sundry Approvals, one for each of the six wells that we are requesting approval to conduct video and Spectra-Flow®logging. If you require any further information, please do not hesitate, I would be more than happy to address them for you. Thanks, &.e Tommy Nenahlo Drill Site Petroleum Engineer 2T (Kuparuk&Tabasco) &2P (Meltwater) North Slope Operations& Development ConocoPhillips Alaska Anchorage: (907)265-6934 Mobile: (720)273-2685 Enclosures: Applications for Sundry Approval (Quantity 6) Wellbore Schematics (Quantity 6) k 0 • KUP 2P-447 Conocor ll llp5 "' Well Attributes Max Angle&MD TD Alaska Inc, Wellbore API/UWI Field Name I Well Status Inc!(°) MD(ftKB) Act Btm(ftKB) ca ou fr�lhps 501032046800 MELTWATER INJ 59.82 7,662.99 8,015.0 Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date "' SSSV: NIPPLE Last WO: 27.98 1/20/2004 Well Gentle -2P-447,11/13/2012 6:08:36 AM Schematic-Actual Annotation Depth(ftKB) End Date Annotation Last Mod... End Date Last Tag:SLM 7,671.0 , 9/18/2012 Rev Reason:OBSTRUCTION NOTE ninam 11/13/2012 Casing Strings Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd CONDUCTOR 16 15.062 30.0 108.0 108.0 62.50 H-40 WELDED Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd • z:., • SURFACE 9 5/8 8.835 28.1 2,705.6 2,318.0 40.00 L-80 BTC Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd INTERMEDIATE 7 6.276 25.2 7,562.0 5,305.9 26.00 L-80 BTC-MD Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd LINER 31/2 2.992 7,415.5 8,010.0 5,546.3 9.30 L-80 SLHT 51 ''!i' Liner Details Top Depth (TVD) Top Inc! Nomi... -t Top(ftKB) (ftKB) (°) Item Description Comment ID(in) 7,415.5 5,226.2 55.40 PACKER ZXP HR LINER TOP ISOLATION PACKER w/TIE BACK 4.730 7,434.4 5,235.6 55.70 NIPPLE RS PACKOFF SEAL NIPPLE 4.250 7,437.2 5,237.3 55.76 HANGER BAKER FLEXLOCK LINER HANGER 5.000 7,446.5 5,242.8 55.99 SBE BAKER 80-40 4.000 CONDUCTOR, ,. 7,465.7 5,253.8 56.45 XO BUSHING CROSSOVER BUSHING 3.000 30-108 'o Tubing Strings NIPPLE,503 Er Tubing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd TUBING 41/2 3.958 23.0 7,466.0 5,254.0 12.60 L-80 IBT-M Completion Details Top Depth (TVD) Top Intl Nomi... _' Top(ftKB) (ftKB) (°) item Description Comment ID(In) 23.0 23.0 -0.40 HANGER 4.500 ;` 502.7 502.5 4.98 NIPPLE CAMCO NO GO'DB'NIPPLE 3.875 __ 7,365.7 5,197.0 54.27 SLEEVE BAKER CMU SLIDING SLEEVE w13.813"DB PROFILE 3.813 7,382.4 5,207.0 54.65 NIPPLE CAMCO'DB'NIPPLE w/3.75"NO GO PROFILE 3.750 SURFACE, , 7,428.1 5,231.9 55.55 LOCATOR G-22 LOCATOR 3.010 28-2,706 7,429.3 5,232.6 55.58 SEAL ASSY BAKER 80-40 SEAL w/1/2 MULESHOE 3.98"x 3.00" 3.000 Perforations&Slots Shot i Top(TVD) Btm(TVD) Dens illi Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date (sh••• Type Comment 7,600 7,640 5,325.4 5,345.7 T-3,2P-447 3/1/2004 6.0 APERF 2.5"HSD PJ Chrgs,60 deg phase tit 7,700 7,780 5,375.7 5,419.0 T-3,2P-447 2/7/2004 6.0 IPERF 2.5"HSD PJ Chrgs,60 deg phase GAS LIFT, -IM:7,316 7,780 7,800 5,419.0 5,429.9 T-3,2P-447 2/6/2004 6.0 IPERF 2.5"HSD PJ Chrgs,60 deg phase MI Notes:General&Safety "61 .te , End Date Annotation 6/14/2004 NOTE:WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR 12/5/2008 NOTE:VIEW SCHEMATIC w/Alaska Schematic9.0 SLEEVE,7,366 i 11/12/2012 NOTE:OA OBSTRUCTED w/CEMENT @ SURFACE NIPPLE,7,382 ' 1 5 m IA, LOCATOR, 7,428 lib it I SEAL ASSY, .• I I .. 7,429 if• I NTERMEDIATE, L 25-7,562 Mandrel Details ; .:::.:. ..:. .. APERF, Top Depth Top Port 7,600-7,640 (TVD) Inc! OD Valve Latch Size TRO Run Stn Top(ftKB) (ftKB) (% Make Model (in) Sery Type Type (In) (psi) Run Date Com... IPERF, 1 7,316.2 5,168.9 54.03 CAMCO KBG-2 1 Gas Lift DMY BK 0.000 0.0 1/27/2004 7,700-7,780 IPERF, 7,780-7,800 LINER, 7,415-8,010 ■TD,8,015 -- Hunt, Jennifer L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, June 26, 2013 12:39 PM To: NSK Fieldwide Operations Supt Cc: Hunt, Jennifer L (DOA) Subject: RE: Meltwater SSSV Testing I missed that one...thanks.Transposed with 2P-419 PTD too. Here is updated corrected wells and PTD's. So a total of six wells. Well PTD 2P-447 203-154 P-41 204-017 2P-434 203-153 2P-427 202-018 2P-420 201-182 2P-429 201-102 Guy Schwartz SCANNED FEB 2 0 2014 Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: NSK Fieldwide Operations Supt [mailto:NSKFieldwideOperationsSupt @conocophillips.com] Sent: Wednesday, June 26, 2013 12:30 PM To: Schwartz, Guy L (DOA) Subject: RE: Meltwater SSSV Testing Guy, We also have well 2P-447 s a WAG injector. I don't have the PTD number handy, but I do have the API number— 501032046800. Thanks, Larry Larry Baker/Glynn Jones NSK Fieldwide Operations Superintendent N2072ConocoPhillips.com 907-659-7042 Pager 659-7000 x604 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, June 26, 2013 10:59 AM To: NSK Fieldwide Operations Supt Cc: Regg, James B (DOA); Ferguson, Victoria L (DOA); Hunt, Jennifer L(DOA) Subject: [EXTERNAL]RE: Meltwater SSSV Testing Larry, 1 After further discussion and thought It would be best to reclassify the WAG injection wells on the Meltwater pad to GINJ (gas injector). The wells should be included in the upcoming SVS testing to be done in July. At some point in future if water is again available for injection on Meltwater the status can be reverted back to WAGIN. The wells in our database that need to have status changed from WAGIN to GINJ are: Well PTD P- 19 203-15 2P-434 203-153 2P-427 202-018 2P-420 201-182 2P-429 201-102 We will change status in our database today... Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell III 907-793-1226 office From: NSK Fieldwide Operations Supt [mailto:NSKFieldwideOperationsSupt©conocophillips.com] Sent: Tuesday, June 25, 2013 4:35 PM To: Schwartz, Guy L(DOA) Subject: Meltwater SSSV Testing Guy, We talked several months ago about the well classification status of the Meltwater(DS-2P) injectors and whether they should remain as WAG injectors or if we should change the well classification to GINJ. At that time you replied that it was your preference to leave the well as a WAG well status even though it will stay on MI for an indefinite period. We are going to perform the SVS testing for DS-2P in July and I just wanted to verify that you still wanted the well classification to remain as WAG. Please confirm that DS-2P should remain classified as a WAG injector. As a SSSV test is not required for a WAG injector, we also ask you to please confirm that we are not required to perform a SSSV test or report SSSV testing for DS-2P during the July pad SVS testing. I look forward to hearing back from you soon. Please feel free to call me at 659-7042 if you have any questions. Thanks, Larry Larry Baker/Glynn Jones NSK Fieldwide Operations Superintendent N2072(c�ConocoPhillips.com 907-659-7042 Pager 659-7000 x604 2 Hunt, Jennifer L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, June 26, 2013 11:26 AM To: Hunt, Jennifer L (DOA) Subject: meltwater wells status change WAGIN to GINJ Put this in comments for 5 Meltwater wells: Well status change to GINJ: No injection water available on Meltwater pad for foreseeable future. Well needs to have SSSV tested every 6 months. Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office 1 Page 1 of 3 Maunder, Thomas E (DOA) From: NSK Prod Engr Specialist [n1139 @conocophillips.com]i Sent: Thursday, January 27, 2011 9:09 AM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); Colombie, Jody J (DOA); NSK Prod Engr & Optimization Supv; NSK Fieldwide Operations Supt; Bradley, Stephen D Subject: FW: RE: Request for Approval Attachments: Kuparuk Gas Injector Flow back Volumes.xls Tom, Attached you will find the Kuparuk Gas Injector Flowback information per your request. Bob Christensen / Darrell Humphrey NSK NSK Production Engineering Specialist ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7535 Kuparuk Pager: 659.7000; #924 CPAI Internal Mail: NSK -69 This email may contain confidential information. If you receive this e-mail in error 'lease notify the sender and delete this email immediately. From: Maunder, Thomas E ( DOA) jmailto :tom.maunder @alaska.gov] Sent: Tuesday, January 25, 2011 9:09 AM To: NSK Prod Engr & Optimization Supv Subject: RE: Request for Approval Gary/Denise, Following up on my brief conversation with Gary the other day, could one of you provide some information with regard to the flowback of these WAG injectors while TAPS was unavailable. Please copy everyoned as before with your response. Thanks in advance, Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Tuesday, January 11, 2011 9:59 AM To: 'NSK Prod Engr & Optimization Supv' Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist; Colombie, Jody J (DOA) Subject: RE: Request for Approval Gary, et al, I have spoken with Commissioner Foerster and she has given her approval to proceed with the planned flowback of the listed wells as described. Volumes should be tracked /recorded as planned. At this time it is not necessary to submit Form 10 -403 for the wells. Form 10 -404 will likely need to be submitted for each well following the conclusion of this extraordinary situation. Gas disposition will also need to be reported. I will place a copy of this message in the well files. Please keep us advised of the situation. Call or message with any questions. 1/27/2011 • • Page 2 of 3 Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [ mailto :n2046@conocophillips.com] Sent: Monday, January 10, 2011 4:44 PM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist Subject: RE: Request for Approval Tom, my estimate is that we could need this as early as tomorrow morning /afternoon. Pilots will be calibrated to meet the 25% flowing tubing pressure rule. Thanks for the timely response. Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 From: Maunder, Thomas E (DOA) Umai Ito :tom.maunder @alaska.gov] Sent: Monday, January 10, 2011 4:38 PM To: NSK Prod Engr & Optimization Supv Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA) Subject: RE: Request for Approval Gary, I acknowledge your request. Do you have any best estimate of when this could be needed? Will there be any modification of the pilot settings on the "new producers "? Sundries will not be necessary. Having to ability to test is appropriate for allocation purposes. I have copied this to my colleagues so they may make necessary assessments. I do not have the authority for this approval, but based on responses to others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [ mailto :n2046(&conocophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Prod Engrs; CPF3 Prod Engrs; NSK Fieldwide Operations Supt; CPF1 &2 Ops Supt; CPF3 Ops & DOT Pipelines Supt; Bradley, Stephen D 1/27/2011 • Page 3 of 3 • Subject: Request for Approval Importance: High Tom, GKA is requesting AOGCC approval to initiate WAG injector flowbacks at Kuparuk if needed to maintain an adequate fuel gas for our turbo - machinery due to the current TAPS proration. Doing so should help ensure that we maintain life support and safety systems at each facility. At this time, it is unclear if this will become necessary as the repair status at Pump Station #1 is still evolving. As part of our planning contingency, GKA is currently configuring the 5 WAG injectors (listed below) for flowback to production via adjacent shut -in producers. The duration of the flowbacks would be directly tied to the length of the TAPS proration. This will be accomplished by hard -line connections between the Gas Injector to an adjacent shut -in producer via tree cap connections. Each well will be equipped with functional SVS which will be capable to shut -in the gas production in the event of a failure and we are in the process of completing a PHA for each of these installations. All injectors will have well testing capabilities for allocation purposes. ' lowback PTD# Adjacent PTD# Estimated Prod ;as Injector SI Producer (Mscfd) -4 20 1 -182 2P -422A 20 2 -067 4 ®?P 2 0 4,500 `' , a4P -447 20 - 54 2P -448A 202 -005 2,000 au-03 185 -006 2U -02 185 -005 3,500 `5S -09 202 -205 3S -08C 207 -163 7,500 3S -26 201 -040 3S -24A 204 -061 6,500 24,000 Please let me know if the AOGCC approves of this plan in the event we have to implement it during non -office hours. Regards, Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 1/27/2011 2P -420 2P-447 ; -09 2P -420 2P -447 3S -09 PROD MTR- MTR- MTR- PROD MTR- MTR- MTR- PROD MTR- MTR- MTR - DATE -TIME HRS 2P- 420 -OIL 2P- 420 -H2O 2P- 420- FORM_GAS HRS 2P- 447 -OIL 2P- 447 -H2O 2P-447-FORM HRS 3S -09 -OIL 3S-09-H20 3S-09-PROD BBLS BBLS MSCF BBLS BBLS MSCF BBLS BBLS MSCF 01/09/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 01/10/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 01/11/11 0.6 0.7 100.1 74.7 11.3 900.3 0.0 5975.3 10.8 2.3 0.0 865.9 01/12/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 8.9 1.7 0.0 866.4 01/13/11 6.9 8.1 1250.6 1056.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 01/14/11_ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Totals 7.5 8.8 1350.7 1131.3 11.3 900.3 0.0 5975.3 19.7 3.9 0.0 1732.3 • • • Page 1 of 2 Maunder, Thomas E (DOA) From: Roby, David S (DOA) Sent: Monday, January 10, 2011 5:21 PM 1 To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Request for Approval All, Seems like a reasonable plan to me. There shouldn't be any impacts to ultimate recovery as the volumes of gas that would be removed from these injectors should be negligible in the grand scheme of things, assuming the proration does not go on indefinitely. On a side note. Should we require, or at least strongly encourage, all operators to develop contingency plans that we can pre- approve to handle situations like this in the future so that they and us don't have to jump through a bunch of hoops to try to get something approved in a very short period of time? Dave Roby (907)793 -1232 .rom: Maunder, Thomas E (DOA) JAN ?Olt - t: Monday, January 10, 2011 4:38 PM To: Prod Engr & Optimization Supv Cc: Foer -r, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA) Subject: R • equest for Approval Gary, I acknowledge your re• . -st. Do you have any best estimate of when this could be needed? Will there be any modifica of the pilot settings on the "new producers "? Sundries will not be necessar Having to ability to test is appropriate for allocation purposes. I have copied this to my colleagu- so they may make necessary assessments. I do not have the authority for this as oval, but based on responses to others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [mailto:n204: '►conocophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Prod Engrs; CPF3 Prod Engrs; Fieldwide Operations Supt; CPF1&2 Ops Supt; CPF3 Ops & DOT Pipelines Supt; Bradley, Stephen D Subject: Request for Approval Importance: High Tom, GKA is requesting AOGCC approval to initiate WAG injector flowbacks at Kuparuk if nee • -d to maintain an adequate fuel gas for our turbo - machinery due to the current TAPS proration. Doing so sho help ensure that we maintain life support and safety systems at each facility. At this time, it is unclear if this will become necessary as the repair status at Pump Station #1 is still ev. ing. As part of our planning contingency, GKA is currently configuring the 5 WAG injectors (listed below) for flowb. to production via adjacent shut -in producers. The duration of the flowbacks would be directly tied to the length . he 1/11/2011 • • Page 1 of 3 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, January 11, 2011 9:59 AM To: 'NSK Prod Engr & Optimization Supv' Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist; Colombie, Jody J (DOA) Subject: RE: Request for Approval Gary, et al, I have spoken with Commissioner Foerster and she has given her approval to proceed with the planned flowback of the listed wells as described. Volumes should be tracked /recorded as planned. At this time it is not necessary to submit Form 10 -403 for the wells. Form 10 -404 will likely need to be submitted for each well following the conclusion of this extraordinary situation. Gas disposition will also need to be reported. I will place a copy of this message in the well files. Please keep us advised of the situation. Call or message with any questions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [mailto:n2046 @conocophillips.com] Sent: Monday, January 10, 2011 4:44 PM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist Subject: RE: Request for Approval Tom, my estimate is that we could need this as early as tomorrow morning /afternoon. Pilots will be calibrated to meet the 25% flowing tubing pressure rule. Thanks for the timely response. Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Monday, January 10, 2011 4:38 PM To: NSK Prod Engr & Optimization Supv Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA) Subject: RE: Request for Approval 1/11/2011 • Page 2 of 3 Gary, I acknowledge your request. Do you have any best estimate of when this could be needed? Will there be any modification of the pilot settings on the "new producers "? Sundries will not be necessary. Having to ability to test is appropriate for allocation purposes. I have copied this to my colleagues so they may make necessary assessments. I do not have the authority for this approval, but based on responses to others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [mailto:n2046 @conocophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Prod Engrs; CPF3 Prod Engrs; NSK Fieldwide Operations Supt; CPF1&2 Ops Supt; CPF3 Ops & DOT Pipelines Supt; Bradley, Stephen D Subject: Request for Approval Importance: High Tom, GKA is requesting AOGCC approval to initiate WAG injector flowbacks at Kuparuk if needed to maintain an adequate fuel gas for our turbo - machinery due to the current TAPS proration. Doing so should help ensure that we maintain life support and safety systems at each facility. At this time, it is unclear if this will become necessary as the repair status at Pump Station #1 is still evolving. As part of our planning contingency, GKA is currently configuring the 5 WAG injectors (listed below) for flowback to production via adjacent shut -in producers. The duration of the flowbacks would be directly tied to the length of the TAPS proration. This will be accomplished by hard -line connections between the Gas Injector to an adjacent shut -in producer via tree cap connections. Each well will be equipped with functional SVS which will be capable to shut -in the gas production in the event of a failure and we are in the process of completing a PHA for each of these installations. All injectors will have well testing capabilities for allocation purposes. ' lowback Adjacent Estimated Prod ;as Injector PTD# SI Producer PTD# (Mscfd) ,D ;P -420 201 -182 2P -422A 202 -067 4,500 ;P -447 203 -154 2P -448A 202 -005 2,000 DU-03 185 -006 2U -02 185 -005 3,500 3S -09 202 -205 3S -08C 207 -163 7,500 3S -26 201 -040 3S -24A 204 -061 6,500 24,000 Please let me know if the AOGCC approves of this plan in the event we have to implement it during non -office hours. Regards, Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 1/11/2011 MEMORANDUM • State of Alaska • Alaska Oil and Gas Conservation Commission DATE: Tuesday, August 10, 2010 To: Jim Regg P.I. Supervisor SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-447 FROM: gob Noble KUPARUK RIV U MELT 2P-447 Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv NON-CONFIDENTIAL Comm Well Name: KUPARUK RIV U MELT 2P-447 API Well Number: 50-103-20468-00-00 Inspector Name: Bob Noble Insp Num: mitRCN100809172802 Permit Number: 203-154-0 Inspection Date: 8/8/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. ~ 2P-447 ~ _-~- Well ~ .Type Inj. ~ ~ ~ TVD 5226 IA 240 1840 ~ _ 1810 1810 ~ P.T.D' 2o31saa TypeTest sPT Test psi l8ao ~ pA ~ ups n76 n9s 1201 ~ InterVal4YRTST p~F, P Tubing 3500 3500 3500 3500 Notes: ~1 i ~ , (-P ~ ~~ ~S ~ (S~~ ~ r' Tuesday, August 10, 2010 Page 1 of 1 ~~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg~alaska.gov; phcebe.bmoks@alaslca.gov; tom.rr~under~a~ska.gov; doa.aogcc.prudhce.bay@alaska.gov OPERATOR: FIELD (UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Kuparuk /KRU / 2P 08/08/10 Colee /Coleman - AES Robert None Packer Pretest Initial 15 Min" 30 Min. We11 2P-419 T In'. G TVD 5,202' T 3,700 3,700 3,700 3,700 Interval 4 P.T.D. 2040170 T test P Test 1500 2,716 3,300 3,260 3,260 P/F P Notes: OA 291 335 338 336 We11 2P-420 T In'. G TVD 5,428' Tatra 3,050 3,050 Interval 4 P.T.D. 2011820 T test P Test 1500 1,850 1,769 P/F F Notes: Pumped 13bbLs. With no pressure increase. OA 291 275 We11 2P-427 T in'. G TVD 5,456' T 3,100 3,100 3,100 3,100 Interval 4 P.T.D. 2020180 T test P Test 1500 1,925 2,600 2,520 2,520 P/F P Notes: OA 675 676 676 676 Well 2P-429 T Iri . N TVD 5,218' T 910 910 910 910 Interval 4 P.T.D. 2011020 T test P Test 1500 435 1,820 1,770 1,760 P/F P Notes: OA 310 442 349 339 We11 2P-434 T In'. N TVD 5,129' T 1,625 1,625 1,625 1,625 Interval 4 P.T.D. 2031530 T test P Test 1500 Cast 5 2,390 2,290 2,280 P/F P Notes: OA 100 101 101 101 Well 2P-447 T I '. G TVD 5,226' T 3,500 3,500 3,500. 3,500 Interval 4 P.T.D. 2031540 T test P Test 1500 240 1,840 1,810 1,810 P/F P Notes: OA 1175 1176 1195 1201 Welt T in'. TVD T trrterval P.T.D. T test Test C P/F Notes: OA Well T In'. TVD T Interval P.T.D. T test Test P/F Notes: OA ~~ t t~1 {~~R TYPE INJ Codes TYPE TEST Codes ~. r ~~ ~ 4 ~ w~ ~'~ ~~ t~ ,~, ~+ ~ `~ i'3 INTERYAI. Codes D =Drilling Waste M =Annulus Monitoring ~ 1=initial Test G =Gas P =Standard Pressure Test 4 =Four Year Cycle I =Industrial Wastewater R = Inlemal Radioactive Tracer Survey V =Required by Variance N =Not Injecting A = Temperature Arwmaly Survey T =Test during Workover W =Water D = DiFferenti~ Temperature Test O =Other (describe in notes) MIT Report Form BFL 11/27/07 MIT KRU 2P Pad 08-08-10.x1s • • .~ ~; - ;` 11 ~ ~~~~~iTl~~~~ o3~o~izoos DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:~L.aserFiche\C~rPgs_Inserts~Nlicrofilm_Marker.doc r,'~!'~"!'i. ~::,,,.!::~ ~:': ':;.1 !'~'~:'.., 1'1 \l if r.~.:-.-~.~ !:!t ~ ..~~ ~ ,~,..-" \ I! ' I,I:-ð~ j.....' 11, 1'1 \' \ \ r" t1 '!~. _~" \\.J',--,, '."'--, ð¡'16"'.-'.'Ci· '11 f; ')IJ' U'111 '".Nl,,' ~ . -u \." ScbluOlbepger /~~~,~ ff¡~ 8~ r'i~~ Ü:!n~1, Il')fit9:i~~~,t ~(;ANNEÐ OC1' 3 1 200e 1\r.td[n¡¡~·F~ Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Com pany: U.J-~ db3-/~1 Field: Well Job# Log Description Date BL 1J-127 11404957 PROD PROFILE W/DEFT 09/14/06 1 2W-10 11404958 INJECTION PROFILE 09/15/06 1 2W-14 11404960 INJECTION PROFILE 09/17/06 1 2U-01 11404964 PROD PROFILE W/DEFT 09/20/06 1 2A-19A 11415618 PROD PROFILE WIDEFT 09/03/06 1 1 E-04 11421627 INJECTION PROFILE 09/13/06 1 2W-02 11296718 INJECTION PROFILE 09/14/06 1 3H-10B 11296723 PATCH/STATIC SURVEY 09/19/06 1 2T-39 11296724 PROD PROFILE W/DEFT 09/20/06 1 1L-04 11415626 SBHP SURVEY 09/24/06 1 2V -04 11415628 INJECTION PROFILE 09/26/06 1 1A-17 11415622 PROD PROFILE WIDEFT 09/21/06 1 1 L-06 11415625 SBHP SURVEY 09/24/06 1 1 F-07 11415629 LDL 09/27/06 1 2F-06 11434750 FLOWING BHP SURVEY 10/03/06 1 2A-17 11434751 PROD PROFILE W/DEFT 10/04/06 1 2P-447 11404966 INJECTION PROFILE 10/06/06 1 2V-08A 11216327 US IT 09/21/06 10/13/06 Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Kuparuk ( Color CD ( 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. c_~~... -- Conoc~hillips Alaska ht: ~ ~1sa ~ JUL ~--'\ E -v U 2006 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 ~1 )..1 ~ ~~.-~~-1. Gg~ ii~~l~$~\~ ___ _-<4 GD1~1mi5$ion l~Bthûr~ge June 06, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AI< 99501 ~Ç^NNEf) .jUL ..= 0nOt:.: Û '{ LU ·u ~' \~ù¡ ~O Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids that were greater than 6 feet were first filled with cement to a level of2.5 feet. The remaining volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter, RG2401, then filled with a viscous hydrocarbon based sealant, Royfill404B, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement top-fill operation was completed on May 05,2006. Schlumberger Well Services mixed 15.7 ppg Arcticset I in a blender tub. The cement was pumped into the conductor bottom and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and sealant were pumped in a similar manner on May 18th, 19th and 31 S\ 2006. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Marie McConnell or myself at 907-659-7224, if you have any questions. .~ :;¿¡o Perry Klein ConocoPhillips Problem Well Supervisor ("t.-~~---J d~ I / 06/~O, 06 Attachment -- '~ ConocoPhillips Alaska Inc. Suñace Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Kuparuk Field June 6,2006 Corrosion Well Initial top Vol. of cement Final top of Cement top Royfill4048 inhibitor/ Name PTD# of cement pumped cement off date RG2041 vol vol. sealant date ft bbls ft gal gal 5/19/2006 2P~ 204-022 4 o~o 4 na 5~7 17.1 5/1912006, 2P-415a 201-226 5.5 0.0 5.5 na 7.1 30.9 5/19/2006 2P-417 201-069 . 7.5 0.7 2.5 5/1/2006 05.7 ' ·:9 ' 5/1.812006' 2P-419 204-017 1 0.0 1 na 6.7 0 5/18/2006 . 2P:-420 201-182 3.5 0:0 3~5' na 7.1 17~3 '5l1812oo6 2P-422a 202-067 13.5 2.3 2.5 5/1/2006 7.1 10.7 5/18/2006 2P424a" ; 204-009 4.5 0.0 4.5 ·'~na 5;7 17.6 5/1812006 2P-427 202-018 10 1.6 2.5 5/1/2006 7.1 13.7 5/18/2006 2P-4J29 . . , 201-102 2 .0.0 2 na 3.8 5.7 5/1812006 2P-431 202-053 13 1.9 2.5 5/1/2006 7.1 10.1 5/18/2006 2P-432 202-091 8.5 0.9 2.5 5/1/2006 5~7 13.8 5/1812006 2P-434 203-153 14 2.0 2.5 5/1/2006 5.7 6.2 5/18/2006 ·2P:-438 201-082 5 0.0 5 na , 5.7 21.9 5/1812006 2P-441 202-107 15 2.0 2.5 5/1/2006 7.1 13.1 5/18/2006 2P-443 204-032' 3;5 0.0 3.5 na 8.7 11.4 5/1"812006,' 2 P-447 203-154 2.5 0.0 2.5 na 9.5 0 5/18/2006 2P-448a 202-005 1.5 0.0 1.5 na 9:5 0 5/.18/2006 . 2P-449 204-026 3 0.0 3 na 5.7 11.5 5/31/2006 2P-451 ' 202-008 10 2.1 2.5 5/1/2006 . 7.1 6.5 5/1812006 ¿ ) Conoc~illips Alaska \::"" I"') :F· fi, fff:' 1= :":\~0ì L. \~c ""\~l ~',~ 'IJ\¡ "\ :.\.'i¡ J, hI ._ .(,," i.: 'ì À~æmt<3J Œ~& Gas ~i¡jf¡¡5. G0!mrrÜ~;¡$¡'!]ì1 Am;hIDní~e P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 f) ^ "-2. ~- I C::"4 ".., úl -~ ) ..:>' --.",-" June 06, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 SCANNED JUN 2 &1 2006 Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids that were greater than 6 feet were first filled with cement to a level of 2.5 feet. The remaining volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter, RG2401, then filled with a viscous hydrocarbon based sealant, Royfill 404B, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement top-fill operation was completed on May 05,2006. Schlumberger Well Services mixed 15.7 ppg Arcticset I in a blender tub. The cement was pumped into the conductor bottom and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and sealant were pumped in a similar manner on May 18th, 19th and 31 S\ 2006. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Marie McConnell or myself at 907-659-7224, if you have any questions. \~. . \.. PerrH<lein ConocoPhillips Problem Well Supervisor Attachment ) ConocoPhillips Alaska Inc. ') Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Kuparuk Field June 6,2006 Well Initial top Vol. of cement Final top of Cement top Name of cement pumped cement off date RG2041 va; I ,V:,:;;i.':::2 ft bbls ft , , .9,al. . ?-~:,:1,t2P:~(if:~'<' : ,,: :,~4" '·':,(to::" , ,:. ;4,> " '~:', ""l;1a .. .' ~,5~:7, '. ' 2P-415 5.5 0,0 5.5 na 7.1 ~~,2tæ;¡¡1'-:r'.~·", ,1~5,',' '/:Ó:7' :,: .,. <,:2~5 ,:..: >':,:.',51112006: '.' ,,;/,' :.':5~7~, 2P-419 1 0.0 1 na 6.7 f/*Ø1~i.f!:;:::-':"~;$:5:::: ;',";:( ':','o:'ò"::;, " :;:::::3:5:': ,;',:," ':"',âå\:~ ..>,7A,:,-" 2P-422 13.5 2.3 2.5 5/1/2006 7.1 ;¡;/iît4fZ4f>.(./;<,,:":;,;~5';",,:~·::¡,' :.:'.:':. -::~O>': ';~4~,5',::; ;': :':~,:':nEf<,:<'>,;,:'" 5~t::", ;',":' 2P-427 10 1.6 2.5 5/1/2006 7.1 ":~~1t::::>: ,:':2;::;'", ",;:,,:·:Oin-",':' ,; ".' :,:::2-:;' ',:::-;: ;':'.. ',,;,"ôa(\ ';:":,'~':' '.3';~:8,'" ; " 2P-431 13 1.9 2.5 5/1/2006 7.1 , ',·..·:,;2ft./~..,', :'j{;.:; ,'", \,8;5;;', ,;"., '::0..';9' ,':,',',:',:,,:2$.:'.:: .....,'..,:~::. :5/1, 'l~(" :,: . "S 7" . ~~ ,,' :~, _ ., '. ~.U.\:lU'. " '.¡' '., "': _, ,'.,'" 2P-434 14 2.0 2.5 5/1/2006 5.7 ,·:,',e~~;F\:;\;',::,"·::5:'.:·; .;"~' '::;:Ô~:O,'::,: ~,,:"':X:~;5;': ....' <:å¡;,'):,,;..'..:; ," ::::' :',/5;~t,::,",:: 2P-441 15 2.0 2.5 5/1/2006 7.1 :''':~\:'':'~:' , ',,3~5\>' "': !:~""! :'<ó.O . .. :' :,', '.~:a.~5'", :;,,' "'hä::, " .',' ':: ' -:<':"8:.7': '., 2P-447 2.5 0.0 2.5 na 9.5 '::2'þ,~',':;;-;'::,:;,t~S>: .:" ',<a~ò':, '~,.. '..' ';,4~:5:,',.',·"': ': Oä:' ".',,'; :".:,~:',9.5::,·o':":": 2P-449 3 0.0 3 na 5.7 ,::,2P~1; ,>·,:::1-Ò,'.~'f ',::2.5: ...., '51'.1:12006 ': ':::',7:1 Corrosion Royfill4048 inhibitor/ vol. sealant date qal 5/19/2006 ,J '" ,1~'1~'~t':' "~~"" S1f;~Ø$:' 30.9 5/19/2006 , " /"":':',:9":;'" : ',,~,~_ß¡::t' o 5/18/2006 '. ',', "17..3,, .'" ", '-:M:~:,'::::, 10.7 5/18/2006 .' :1"7~'6:": ,,', ':':"::5·,:/.òii~ð~6·'~ ,:" . '., '. . ,.. " ", f;f.~~UI ."\ 13.7 5/18/2006 . . ',' :5' ,;,7"; . ,: . " ,"¢~otcü-\'-'œ' . ,\::" ,: . .... ..", \ 'j' " R..~·,~~::Ji~6~.... .', ' 10.1 5/18/2006 13.:8:", ;,;,;,:;~~::>,; 6.2 5/18/2006 .. ," ':2' 1"· '9' .. ~ , ..- ,:: :, ,::,; ilill.'iliâ-'_"'" . , _..'..: ~'. ~...,' .·;·'lfl;'~t~~~. 13.1 5/18/2006 .. :':'1''-'1:' 4· , ' ';., .'': " .:"J::'~~~~; ';':: , ~;. . " "..~~~I!Pf.~~~;. - .' o 5/18/2006 , . 0, ' :, ".,... ,t: . ..$l1Þ12~·:"': 11.5 5/31/2006 ;, 6~5, ' , ;, > ." $if.8J.200a:", " G M~ vr~~ DATA SUBMITTAL COMPLIANCE REPORT 2/6/2006 )(1 V).. ? ~ À.k~ .3 Well Name/No. KUPARUK RIV U MELT 2P-447 Operator CONOCOPHILLlPS ALASKA INC API No. 50-103-20468-00-00 5549... Completion Date 2/6/2004 ~~_ Completion Status WAGIN Current StatG~ C·~;~·V Permit to Drill 2031540 MD 8015 REQUIRED INFORMATION Samples No _ Directional S~"') --~-~.---,_..__._--- ~--_...,_.. // TVD Mud Log No DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Logl Data Digital Type Med/Frmt ~ I I J/ ~ I I ~" ~J F C Pdf I¡)tD C Lis i t~ I ¡§.PC Pdf pÓ C Lis I 1- (data taken from Logs Portion of Master Well Data Maint Electr Dataset Number Name --_..,-----_._----~ Injection Profile Interval OHI Start Stop CH 7450 7850 Case 108 8015 Open 6000 7754 Case ---""---~-~-- Log Log Run Scale Media No 5 Blu 1 Received Comments ----~--_.._-- 9/28/2005 Injection Profile Log Spinner, Temp, Pressure, GR, CCL 18 Aug 2005 1/28/2004 1/30/2004 Cement Bond Log SCMT- BB/PSP PresslTemp Cement Bond Log SCMT- BB/PSP PresslTemp Cement Bond Log SCMT- BB/PSP PresslTemp Perforating Record SBHP and WRP Setting Record Perforating Record SBHP and WRP Setting Record Multiple Propagation Resistivity-Gamma Ray Multiple Propagation Resistivity-Gamma Ray Multiple Propagation Resistivity-Gamma Ray Multiple Propagation Resistivity-Gamma Ray Caliper Corrected Neutron, Optimized Roational Density Caliper Corrected Neutron, I Optimized Roational ji Density Directional Survey Cement Evaluation Pressure Temperature Perforation Pressure 12482 Induction/Resistivity 12482 InductionlResistivity Induction/Resistivity f"ID I nd uction/Resistivity ìvA 12482 Neutron 5 Col 5 Col 5 Col 5 Blu 5 Blu 25 25 25 Blu 25 25 6000 7754 Case 1/30/2004 6000 7754 Case 1/30/2004 7536 7912 Case 3/26/2004 7536 7912 Case 3/26/2004 108 8015 Open 3/26/2004 108 8015 Open 3/26/2004 108 8015 Open 3/26/2004 108 8015 Open 3/26/2004 108 8015 Open 3/26/2004 108 8015 Open 3/26/2004 12482 Neutron . . DATA SUBMITTAL COMPLIANCE REPORT 2/6/2006 Permit to Drill 2031540 Well Name/No. KUPARUK RIV U MELT 2P-447 Operator CONOCOPHILLlPS ALASKA INC API No. 50-103-20468-00-00 MD 8015 TVD 5549 Completion Date 2/6/2004 Completion Status WAGIN Current Status WAGIN UIC Y Î Neutron Mt) 25 Slu 108 8015 Open 3/26/2004 Caliper Corrected Neutron, Optimized Roational Density ~~ Neutron ìlt' ~ 25 108 8015 Open 3/26/2004 Caliper Corrected Neutron, Optimized Roational ~ Density C Pdf 12482 Density 25 108 8015 Open 3/26/2004 Caliper Corrected Neutron, Optimized Roational . I Density I / fÆ'D C Lis 12482 Density 108 8015 Open 3/26/2004 Caliper Corrected Neutron, I Optimized Roational Density og Density MO 25 Slu 108 8015 Open 3/26/2004 Caliper Corrected Neutron, Optimized Roational Density Density ,Vi) 108 8015 Open 3/26/2004 Caliper Corrected Neutron, Optimized Roational , Density I Log Sonic Col 2208 7545 Open 12/31/2004 ULTRASONIC IMAGING TOOL W/CEMENT SOND LOG(SSL T) Log Sonic Col 100 7400 Case 12/31/2004 ULTRASONIC IMAGER I TOOL USIT/GRlCCJ C Pdf 12969 Injection Profile 7400 7758 2/1/2005 W' 12969 Injection Profile 5 Slu 7400 7758 l~'L 2/1/2005 . Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORM~ION Well Cored? Y ~ Daily History Received? '@/N Œ;N Chips Received? ~~ Formation Tops Analysis Received? .!..!.J;V' .-~~-~.~ Comments: DATA SUBMITTAL COMPLIANCE REPORT 2/6/2006 Permit to Drill 2031540 Well Name/No. KUPARUK RIV U MELT 2P-447 Operator CONOCOPHILLlPS ALASKA INC MD 8015 TVD 5549 Completion Date 2/6/2004 Completion Status WAGIN Current Status WAGIN Jt;-- Date: JS íih ~þ Compliance Reviewed By: API No. 50-103-20468-00-00 UIC Y . . . . Mike Mooney Wells Group Team Leader Drilling & Wells ConocóPhillips P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4574 December 5, 2005 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, Alaska 99501 RECE'lVED DEe 1 3 2005 " Alaska Oil & Gas C "' . A (Ins. Commlssícm nchorage Subject: Report of Sundry Well Operations for 2P-447 (APD # 203-154) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent stimulation operations on the Kuparuk well 2P-447. If you have any questions regarding this matter, please contact me at 263-4574. Sincerely, d, 11~ ~~~ooney Wells Group Team Leader CPAI Drilling and Wells M M/skad . . 1. Operations Performed: Abandon D Repair Well D Plug Perforations D Stimulate 0 Other D .. Alter Casing D Pull Tubing D Perforate New Pool D Waiver D Time Extension D Change Approved Program D Opera!. ShutdownD Perforate D Re-enter Suspended Well D 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development D Exploratory D 203-1541 3. Address: Stratigraphic D Service 0 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20468-00 7. KB Elevation (ft): 9. Well Name and Number: RKB 28' 2P-447 8. Property Designation: 10. Field/Pool(s): ADL 373112/389058, ALK 320921 32409 Kuparuk River Field 1 Meltwater Oil Pool 11. Present Well Condition Summary: Total Depth measured 8015' feet true vertical 5549' feet Plugs (measured) 7670' Effective Depth measured 7909' CTMD feet Junk (measured) true vertical feet Casing Length Size MD TVD Burst Collapse Structural CONDUCTOR 108' 16" 108' 108' SURFACE 2677' 9-5/8" 2705' 2317' PRODUCTION 7534' 7" 7562' 5306' LINER 595' 3-1/2" 8010' 5546' Perforation depth: Measured depth: 7600'-7640',7700'-7800' true vertical depth: 5325'-5346',5377'-5430' Tubing (size, grade, and measured depth) 4-1/2", L-80, 7415' MD. R.BDMS 8Ft DEC 1 3 2005 Packers & SSSV (type & measured depth) ZXP HR isolation pkr @ 7415' Cameo 'DB' nipple @ 502' 12. Stimulation or cement squeeze summary: Intervals treated (measured) 7600' - 7640' Treatment descriptions including volumes used and final pressure: 750 bbls seawater 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Casing Pressure Tubina Pressure Prior to well operation na na not available -- Subsequent to operation na na not available -- 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory D Development D Service 0 Daily Report of Well Operations _X 16. Well Status after proposed work: OilD GasD WAG 0 GINJD WINJD WDSPL D 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: Contact Mike Mooney @ 263-4574 Printed Name Mike Mc¡ney Title Wells Group Team Leader Signature 1~!uLf- ,;¡Ó~ Phone 263-4574 Date !Z¿iø 5 Preoared bv Sharo All -Drake 263-4612 l - ..} RECEIVE . STATE OF ALASKA. DEC 1 3 2005 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERA TIONSAI..ka Oil & Gas Cons. Con,m,;~¡0tt Form 10-404 Revised 04/2004 ORIGINAL Submit Original Only TUBING (0-7415, 00:4.500, 10:3.958) SURFACE (0-2705, 00:9.625, Wt:40.00) PUP (7415-7430, 00:4.500) Perf (7600-7640) Perf (7700-7780) ConocoPhillips Ala!, Inc. ?P_AA7 1I 11III .. - - C1 - - - - - - - - - - - - . KRU ~-447 API: 501032046800 ~§$\itype: :~!'pPLE ~~ Annular Fluid: . H_._.1--__Y'Jell TYf?_~__ ..._ . _~ c;ompleti~n: '1/20/2004. _ Last W/O: __Angl~~~_deg @___" _ _ Angl~:,. 56 deg~__, Rev Reason: Set Gauges, WRP, TAG Last Update: 10/30/2005 Reference Loa: 28' RKB Ref Loa Date: Last Taa: 7909 CTMD TD: 8015 ftKB Last Tagpate:,13!\J/2005 Max Hole )\l1g~ ~g_@}~~3 Casing S~r!D.g - ALL STR!NqS __. _ Description Size Top Bottom CONDUCTOR 16.000 0 108 SURFACE 9.625 0 2705 PRODUCTION 7.000 0 7562 LINER 3.500 7415 8010 jhTI2.IBIN~ Top o ___h_._____u_.. ...-..-----., - ... ---_. ----..-- IUDma Size 4.500 TVD 108 2317 5306 5546 I Wt I Grade I 12.60 I Grade H-40 L-80 L-80 L-80 Thread WELDED BTC BTC-MD SLHT Wt 62.50 40.00 26.00 9.30 I Bottom I 7415 Zone I I Date 3/1/2004 I L-80 I Type APERF Thread IBT-M TVD 5226 I Comment 2.5" HSD PJ Chrgs, 60 deg phase 2/7/2004 IPERF 2.5" HSD PJ Chrgs, 60 deg phase 2/6/2004 IPERF 2.5" HSD PJ Chrgs, 60 deg phase ~á! Hftvørvç;:oii St MD TVD Man Mfr Man Type I V Mfr I V Type I V 00 I Latch I Port TRO I ~~~ I c"r:,~t _,.1. 7316 5169 CAMÇO KBG::1HJ I [J,ML...L..lQ_L_ BK I 0.0.00..._ 0 I 1/27/2Q04:J_ º!_~~.r_Dluas. eauiD" etc.) - JEW~~RY__,____.. ___.._ I P~~th T~D HI~~~R 14.5"FMë'-GEN"VTUBING HANGER~/~~~i~~ÞCONNECTIOÑ'--' ~ !. "502 502 N"IP .-. CAMCO '0"8' NTp~-" -- "". .--- --- ...n ¡ . 7365 5197 SLEEVE' BAKER ëMU sLIDING SLEEVC -. 'H ,-- ,- .. __ ~,: '=--i3' :.li7~51io- 7382--- 5207- ...~--.-.. cAMtg 'DB' NIPpLE WiNO GO ¡:>.8ç)F.iLE '.. ------.. 7415 I 522'6 H puP' m -" ; 3.958- ~:'5233 rLOCATOR '!3AKER G-22 LOCAT6R SEAL ASSEMBLY _'H_h_ -- .,- 3.010-'- ;1~~ : '~~g:' :' .-:-~~~~ -t~~KJ~L~Oi~;tðL AS,~EMBCF ,. . :=' --:=',: '----- --=~--~.~~...~_._~ -- Other plugs: eQuip., etc~) -TINER JEïNE[~-- . . .-.----, m . - DeDth TVD Tvee ----... _'__M' DescriDtiOn -......- 7415 5226 PACKER ZXP HR LINER TOP ISOLATION PACKER WITIE BACK 7434 5237 NIP RS PACKOFF SEAL NIPPLE 7437 5238 HANGER BAKER FLEXLOCK LINER HANGER 7446 5243 SBE BAKER 80-40 PBR/SBR 7466 5254 BUSHING XO BUSHING 5" TKC x 3.5" SLHT 7670 5361 PLUG 3.5" WRP set 10/29/2005 ~~~~'. .~!~r~1' : I::~:~:~::~~::~:EL::RS=~STQP set 1 0/2~!2~'o~,_ :1ººªl5545 ¡ SHQ:E,"BOT FLO~tS!:IÖE-----:-_ .- ,__:'::_ ,- ~~~ªt ~~::s__.__ __. 1/20/2004 TREE: FMC / GEN V / TB / 5 K TREE CONNECTION: 7" OTIS 6/14/2004 WAIVERED OA: PRESSURE CHARGING FROM RESERVOIR Interval TVD 7600 - 7640 5325 - 5346 7700 - 7780 5377 - 5419 7780 - 7800 5419 - 5430 Status Ft SPF 40 6 80 6 20 6 __N_ ." .. 10 4.370 4.250 5.000 4.000 2.990 0.000 - . N" ö])õQ --T 1~~~ .._,~ --2.992 . -.. --- --- -...------ ----- . 2P-447 Well Events Summary . Date Summary 10/29/05 DRIFT TUBING. 11/01/05 COMPLETED POOR BOY HPBD. PUMPED 750 BBLS OF COLD (60 DEG. F) SEAWATER IN 4 STAGES. SAW SOME SIGNS OF BREAKDOWN IN EACH STAGE. RETURNED WELL TO PW INJECTION. . WELL LOG TRANSMITTAL . c:03- ¡Sf ProActive Diagnostic SelVices, Inc. To: State of Alaska AOGCC 333 W. 7"'Street Suite # 700 Anchorage. Alaska 99501 RE: Distribution - Final Print[s] The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of : Joey Burton / Jeni Thompson ProActive Diagnostic Services, Inc. P. O. Box 1369 Stafford, TX 77497 BP Exploration (Alaska), Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, AK 99508 LOG DIGITAL MYLAR / BLUE LINE REPORT WELL DATE TYPE OR SEPIA PRINT[S) OR CD-ROM FilM COLOR Open Hole 2P447 9-1 9-04 Res. Eval. CH 1 1 1 Mech. CH 1 Caliper Survey 1 Signed: Date. #~ PI!OACTiv[ DiAGNOSlic SrllVicrs, INC., PO Box I ~b9 SlAflORd lX 77477 Phonc:(281) 565-9085 Fax:(281) 5(,5-1369 E-mail: pds(á1mcmory1og.com Wcbsitc: \vww.mcmorv1o~.com 12/30104 Schlumberger NO. 3297 Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 A TTN: Beth Company: Alaska Oil & Gas Cons Comm Attn: Helen Warman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk . ótð;--f54 181-, ~~{ Well Job # Log Description Date BL Color CD . ~ 2P-447 10709677 USIT 12/24103 1 2P-447 10696820 USIT 01107/04 1 If? 1A-06 10942812 INJECTION PROFILE 12/21/04 1 0 3F-21 10942813 INJECTION PROFILE 01107104 1 1 H-05A 10687716 MDT 12/13/04 1 1 /\ - )(~Jj¡¡M/~ I k3tJ' SIG DATE: Please 51 n .nd ..tole co / ¡ of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank ou. ./ g py y e e Mike Mooney Wells Group Team Leader Drilling & Wells ConocóP'hillips P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4574 May 13, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations for 2P-447 (APD # 203-154) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent stimulation operations on the Kuparuk well 2P-447. If you have any questions regarding this matter, please contact me at 263-4574. Sincerely, J1¡j~ M. Mooney Wells Group Team Leader CPAI Drilling and Wells MM/skad RECEIVED MAY 1 4 2004 Alaska Oil & Gas Cons, Commission Anchorage ORIGiNAL e e STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon D RepairWell D Plug Perforations D Stimulate 0 Other D Alter Casing D Pull Tubing D Perforate New Pool D Waiver D Time Extension D Change Approved Program D Opera!. ShutdownD Perforate D Re-enter Suspended Well D 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development D Exploratory D 203-1541 3. Address: Stratigraphic D Service 0 6. API Number: P. O. Box 100360 50-103-20468-00 7. KB Elevation (ft): 9. Well Name and Number: RKB 28' 2P-447 8. Property Designation: 10. Field/Pool(s): ADL 373112/389058, ALK 32092132409 Kuparuk River Field I Meltwater Oil Pool 11. Present Well Condition Summary: Total Depth measured 8015' feet true vertical 5549' feet Plugs (measured) Effective Depth measured 7913' feet Junk (measured) true vertical 5492' feet Casing Length Size MD rvD Burst Collapse Structural CONDUCTOR 108' 16" 108' 108' SURFACE 2677' 9-5/8" 2705' 2317' PRODUCTION 7534' 7" 7562' 5306' LINER 595' 3-1/2" 8010' 5546' RECEIVED Perforation depth: Measured depth: 7600'-7640',7700'-7800' MAY 1 4 2004 true vertical depth: 5325'-5346',5377'-5430' Alaska Oil & Gas Cons. Commission Tubing (size, grade, and measured depth) 4-1/2' , L-80, 7447' MD. Anchorage Packers & SSSV (type & measured depth) isolation packer pkr @ 7415' SSSV= Cameo 'DB' NIP SSSV= 502' 12. Stimulation or cement squeeze summary: Intervals treated (measured) 7600'-7800' MD Treatment descriptions including volumes used and final pressure: see attached summary 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Casino Pressure Tubina Pressure Prior to well operation nla -- Subsequent to operation nla 16176 mmcfld nla -- nla 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory D Development D Service 0 Daily Report of Well Operations_X 16. Well Status after proposed work: oilD GasD WAG0 GINJD WINJD WDSPLD 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: Contact Mike Mooney @ 263-4574 Printed Name Mike Mooney Title Wells Group Team Leader 5j', (;, . Signature AI. Jj ~"d, ~ Phone Date d: r3 'tJ 1- "'ronared b,:<:hor';n AlfsuD-Dr~ko 2R~-4612 . , -=.J U~ I G~l~L MAY ,1 4 lfi~ Form 10-404 Revised 04/2004 "'-'I \4! .fflll!! S C Submit Original Only "" e e KRU 2P-447 ConocoPhillips Alaska, Inc. 2P-447 API: 501032046800 Well TVDe: INJ Anale (ã) TS: dea (ã) TUBING SSSV Type: NIPPLE Orig 1/20/2004 Angle @ TO: 56 deg @ 8015 (0-7415, . Completion: 00:4.500, Annular Fluid: Last W/O: Rev Reason: FCO Tag, PERF, ID:3.958) 1 pull WRP set DMY Reference Loa: 28' RKB Ref Loa Date: Last Update: 3/20/2004 ! : Last Taa: 7913 CTMD TD: 8015 ftKB SURFACE -- Last Taa Date: 3/112004 Max Hole Anole: 60 dea (ã) 7663 (0·2705. I Casino Strino - ALL STRINGS 00:9.625. I Description Size Top Bottom TVD Wt Grade Thread Wt·40.00) CONDUCTOR 16.000 0 108 108 62.50 H-40 WELDED i SURFACE 9.625 0 2705 2317 40.00 L-80 BTC PRODUCTION 7.000 0 7562 5306 26.00 L-80 BTC-MD 'RODUCTION - .._ LINER 3.500 7415 8010 5546 9.30 L-80 SLHT ; Tubino Strina - TUBING (0-7562, I . OD.7.nOD. Size I Top I Bottom I TVD I Wt I Grade I Thread Wt:26.01J) I 4.500 1 0 1 7415 I 5226 1 12.60 1 L-80 1 IBT-M Perforations Summarv Interval TVD Zone Status Ft SPF Date Tvpe Comment 7600 - 7640 5325 - 5346 40 6 3/1/2004 APERF 2.5" HSD PJ Chrgs, 60 deg phase 7700 - 7780 5377 - 5419 80 6 21712004 IPERF 2.5" HSD PJ Chrgs, 60 deg ! phase 7780 - 7800 5419 - 5430 20 6 216/2004 IPERF 2.5" HSD PJ Chrgs, 60 deg SLEEVE .-. .- phase (7365-731ì6. Gas Lift MandrelsNalves 00'5500) St I MD I TVD I Man Man Type I V Mfr I V Type V 00 I Latch I Port I TRO I ~~~ I C~~t . , ! I Mfr 1 1 73161 51691CAMCOI KBG-2 I 1 DMY I 1.0 1 BK I 0.000 1 0 11/27/20041 NIP - Other (I luos. e Juip. etc.\ - JEWELRY (73R2-7383. Depth ~D TVDe . . .. Descrjption._ _ 10 0::1:5.530) 23 23 HANGER 4.5" FMC GEN V TUBING HANGER WINSCT TOPCONNECTION 3.500 502 502 NIP CAMCO 'DB' NIPPLE 3.875 7365 5197 SLEEVE BAKER CMU SLIDING SLEEVE 3.813 Pl.:P- .- :.~ 7382 5207 NIP CAMCO 'DB' NIPPLE WINO GO PROFILE 3.750 (7415-7430. 7415 5226 PUP 3.958 OD:4.!,OOi 7428 5233 LOCATOR BAKER G-22 LOCATOR SEAL ASSEMBLY 3.010 ~. .. :: 7429 5234 SEAL BAKER 80-40 SEAL ASSEMBLY 3.000 7466 5254 SHOE 1/2 MULE SHOE 3.000 Other (I luos. e JUID. etc.\ - LINER JEWELRY DeDth TVD TVDe Description 10 LINER .. - 7415 5226 PACKER ZXP HR LINER TOP ISOLATION PACKER WfTlE BACK 4.370 i7415-RO '0, 7434 5237 NIP RS PACKOFF SEAL NIPPLE 4.250 00 3 ~OíJ. 7437 5238 HANGER BAKER FLEXLOCK LINER HANGER 5.000 Wt:!J.30) 7446 5243 SBE BAKER 80-40 PBRISBR 4.000 11II .. 7466 5254 BUSHING XO BUSHING 5" TKC x 3.5" SLHT 2.990 7910 5490 COLLAR BAKER LANDING COLLAR 3.500 8008 5545 SHOE BOT FLOAT SHOE 2.992 SBE .............."'.'.'............ ...............'....... » ...........".......... >e '....'..'....' ".........' ..:e..e. '..'.....'......'...... ..:.........."':'..'}.........",,, >e} (7446-7447, Date Note OD:S.S90) 1/20/2004 TREE: FMC I GEN V I TB I 5 K TREE CONNECTION: 7" OTIS BUSHING (7466-7467, 00:5.570) Perf - - (7600-7640) - - Perf - - (7700-7780) - - - - - - - - Perf - - (7780-7800) - - COLLAR (7910-7911, OD:4.000) .... ... . PHILLIPS Alaska, Inc. . WELL 2P-447 DATE 03/15/04 DAY 14 1605 PSI KUPARUK RIVER UNIT _LL SERVICE REPORT 2P-447(4-1 » JOB NUMBER 0102041823.2 UNIT NUMBER FRAC EQUIP SUPERVISOR YOAKUM I'iIIfi1l[}- Depth 2.990" 8010 FT DAILY SUMMARY PUMP HPBD TREATMENT USEING HIGH RATE, PRESSURE, ROCKSAL T DEVERSHION AND 20/401# SCOUR STAGES TO INCREASE INJECTION RATE. [HPBD] TIME LOG ENTRY 08:00 DS ON LOCATION RIG UP AND PREPARE FOR HPBD. 12:20 PJSM MUSTER AT THE PAD ENTERANCE, SLICK SURFACES, 11 DS, 2 LRS, 1 APC. 13:37 HYDROLlC COOLER ON NEW HIGH PRESSURE PUMP LEAKING INTO SECONDARY CONTAINMENT. RIG PUMP AND GO WITH 4 PUMPS. 13:58 OPEN WELL HEAD 1600 PSI ON WELL PUMP TREESAVER DOWN AND SET. 14:05 PRESSURE TEST TO 9500 PSI. 14:09 HPBD @ 40 BPM 3600 PSI BROKE BACK TO 3064 PSI. WATER TEMP 52 DEG F. 14:19 PUMP 1 PPG SCOUR STAGE 40 BPM 3042 PSI WHP 50 BBLS 2011# 20/40 CARBO-LITE. 14:22 FLUSH SCOUR STAGE @ 40 BPM 3008 WHP 300 BBLS. 14:28 STUT DOWN ISIP 542 PSI 14:34 START GEL DIESEL 10 BBLS ROCK SALT 840# DIRVERTER STAGE 7 BPM. 14:36 10 BBL GEL DIESEL SPACER @ 7 BPM 468 PSI. 14:42 SECOND ROCKSALT STAGE 15 BBLS, 1260# RS, @ 7BPM 560 PSI. 14:44 DIESEL SPACER 7 BPM @ 534 PSI. 10 BBLS. 14:46 WATER FLUSH 150 BSLS @ 40 BPM, 14:51 ROCKSAL T ON FORMATION LOST ONE PUMP TO ROCKSAL T. 40 BPM @ 2079 PSI 14:52 SCOUR STAGE 50 BBLS 1 PPG @ 40 BPM 2035 PSI 14:53 I FLUSH SCOUR STAGE 400 BBLS. TIME LOG ENTRY 15:01 SHUTDOWN ISIP 540 PSI. 15:04 DIVERT STAGE 10 BBLS 840# ROCKSALT @ 7 BPM 362 PSI. 15:05 SPACER 10 BBLS GEL DIESEL 15:07 DIVERTER STAGE 15 BBLS 1260# @ 7 BPM 372 PSI. 15:09 10 BBL SPACER GEL DIESEL. 15:10 DIVERTER FLUSH 150 BBLS SLICK WATER. 15:16 DIVERTER ON FORMATION 2000 PSI TO 3200 PSI 1200 PSI DIVERSION. @ 40 BPM. 15:20 I ADD A 25 1 PPG STAGE AND FLUSH. 15:30 100 BBL SCOUR STAGE 1 PPG @ 40 BPM 2087 PSI 15:33 FLUSH SCOUR STAGE 125 BBLS @ 40 BPM 2054 PSI. 15:38 SHUT DOWN FREEZE PRTECT PUMPS AND WELL HEAD. 532 PSIISIP. e 2P-447 Well Events Summary e Date Summary 03/15/04 PUMP HPBD TREATMENT USEING HIGH RATE, PRESSURE, ROCKSALT DEVERSHION AND 20/401# SCOUR STAGES TO INCREASE INJECTION RATE.D [HPBD] . Transmittal Form . &ð3'~ J~i r'__ BAKER HUGHES INTEQ To: AOGCC 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Attention: Lisa Weepie Reference: 2P-447 Anchorage GEOScience Center Contains the following: 1 LDWG Compact Disc J3 L18~ (Includes Graphic Image files) 1 LDWG lister summary 1 blueline - MPR Measured Depth Log 1 blueline - MPR TVD Log 1 blueline - CCN-ORD Measured Depth Log 1 blueline - CCN-ORD TVD Log LAC Job#: 593016 Sent By: Glen Horel ~ "> ~" ''':) .~' Received By: \,-t'Ì)\"-~_jy-.., \\, ç <':'~~~i~ Date: Date: Mar 22, 2004 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 ~"DN\~ RECEIVED \ ? 6 ?N'4 ,.... ..... IJ & Gas Cons. Commiselon '; .~","nl'age L: c"! ,1!tY"W' -,.... 03/05/04 Sc~lumbepgep NO. 3125 Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 A TTN: Beth Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Well Job# Log Description Date BL Color CD -- 1C-190;:)C3-(Y.')-= 10709706 INJECTION PROFILE 02/16/04 1 1 E-34 JCí ":¡ 'II tJ ¡, 10709710 PRODUCTION PROFILE 02/21/04 1 1C-15L 1~C3l',?~J 10709713 PRODUCTION PROFILE 02/25/04 1 2Z-10 19:,c;-, ~'"'1- 10696843 PRODUCTION PROFILEIDEFT 02/26/04 1 2P-447,Qr~-,&:jL 10696847 PERF/SBHP 03/01/04 1 n ~r~r- n 'I. ". , ~\: ..... VI-I \i L-....., - ~ ' --- SIGNED: "" r,) \~ ,,~ '<'- \~"") '- (' 0- ;~ <::::- .J"',..-..... , '- DATE: , , ;" I") 6 f);ìUi"l f ¡ . ~ ,.:., '.' t Ii . ,,-.;\ L . L\J Lt 'ï;~)\;{~ Œc~ ~~ Gas COilS. Commi$!!on Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. An:;tíOrage Rß~n\~ MEMORANDUM e e State of Alaska TO: Alaska Oil and Gas Conservation Commission THRU: Jim Regg 12ø1ti 31,,:>(04- P.I. Supervisor ( DATE: Tuesday, March 16,2004 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-447 KUPARUK RIV U MELT 2P-447 FROM: John Crisp Petroleum Inspector Src: Inspector NON-CONFIDENTIAL API Well Numbe 50- I 03-20468-00-00 InspN mitJCr0403 I 5092020 Inspection Date: 3/14/2003 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well: 2P-447 Type Inj. G TVD 5226 IA 350 3460 3420 3400 P.T. 2031540 TyþeTest SPT Test psi 1306.5 OA 500 517 520 525 Interval Initial Test PIF Pass Tubing 2800 2800 2800 2800 Notes: No problems witnessed. Operator requested 3500 psi test. Type INJ. Fluid Codes F =FRESH WATER INJ. G=GAS INJ. S=SALT WATER INJ. N=NOT INÆCTING Type Test M=Annulus Monitoring P=Standard Pressure Test R=lntemaJ Radioactive Tracer Survey A=Temprature Anomaly Surve D=Differential Temprature Test Interval 1=lnitiaJ Test 4=Four Year Cycle. V=Required by Variance W=Test during WOIkover O=Other (describe in notes) Tuesday, March 16,2004 Page I of I . Conoc~hillips . Randy Thomas Kuparuk Drilling Team Leader Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-6830 March 11, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for 2P-447 (APD # 203-154/303-389/304-010) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Well Completion Report for the recent drilling operations of the Meltwater well 2P-447. If you have any questions regarding this matter, please contact me at 265-6830 or Philip Hayden at 265-6481. Sincerely, ~~ R. Thomas Kuparuk Drilling Team Leader CPAI Drilling RT /skad RECEIVED IViAH 1 2 2004 t'J~ka Oil & Gas Cons. Commission 1a. Well Status: Oil 0 Gas U Plugged D Abandoned D Suspended D 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., '~b l 2åJ' 12. Permit to Drill Number: ConocoPhillips Alaska, Inc. r~'" . 203-154/303-389/304-010 or Aband.: .Jam¡afY~ 3. Address: 6. Date Spudded: 13. API Number: 3'?~-t." P. O. Box 100360, Anchorage, AK 99510-0360 December 6, 2003 50-103-20468-00 4a. location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number. Surface: 1017' FNL, 1603' FWL, Sec. 17, T8N, R7E, UM December 24, 2003 2P-447 At Top Productive 8. KB Elevation (It): 15. Field/Pool(s): Horizon: 65' FNL, 739' FEL, Sec. 19, T8N, R7E, UM 28' RKB Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): Meltwater Oil Pool 396' FNL, 930' FEL, Sec. 19, T8N, R7E, UM 7913' MD 15492' TVD 4b. location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 443562 .' y- 5868863' Zone-4 8015' MD 15549' TVD' ADL 373112 I 389058 TPI: x- 441203 y- 5864553 Zone- 4 11. Depth where SSSV set: 17. land Use Permit: Total Depth: x- 441011 I y- 5864223' Zone-4 none ALK 32092 I 32409 18. Directional Survey: Yes 0 NoU 19. Water Depth, if Offshore: 20. Thickness of NIA feet MSL Permafrost: 1377' MD 21. logs Run: GRlRes/Den/Neu, US IT, SCMT 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CEMENTING RECOtjL 4EIVcS.QllED CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE 16" 62.5# B Surface 108' 42" 7.6 bbl AS I 9.625" 40# L-80 Surface 2705' 12.25" 446 sx AS Lite, 284 sx LiteCrete IVIf\r\ -/ ? ?flfld 7" 26# L-80 Surface 7562' 8.5" 165 sx Class G w/Ga~lok, 34Q.~x ArcticCrete 3.5" 9.2# L-80 7415' 8010' 6.125" 150 sx Class G ' "'UGlR,", ',II.; (! """,.$, ,~omge 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 (MD) 4.5" 7447' 7415' 7700' - 7800' MD 5377' - 5430' TVD 6spf 7600' - 7640' MD 5326' - 5346' TVD 6spf 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED N/A 26. PRODUCTION TEST Date First Injection Method of Operation (Flowing, gas lift, etc.) March 8, 2004 WAG Injector Date of Test Hours Tested Production for Oll-BBl GAS-MCF WATER-BBl CHOKE SIZE GAS-Oil RATIO NIA Test Period --> Flow Tubing Casing Pressure Calculated Oll-BBl GAS-MCF WATER-BBl Oil GRAVITY - API (corr) press. psi 24-Hour Rate -> not available 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separ~e sheet, if necessary). Submit core chips; if none, state "none". I GGMP[t'ï:¡Öìf1 2. .Dj~ A.A yo NONE VFJtf..pj7- ,,', ... . STATE OF ALASKA __ ALA Oil AND GAS CONSERVATION COM"'ON WELL COMPLETION OR RECOMPLETION REPORT AND LOG D[)í[ ì¡MS ~~:,..j".,..c ~p MAR 1 (.) 100\ G Form 10-407 Revised 2/2003 CONTINUED ON REVERSE SIDE Submit in duplicate , .... 28. 29. GEOLOGIC MARKER FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intelVals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". 2P-447 T3 T2 7562' 7896' 5306' 5483' NIA 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, Schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Philip Hayden @ 265-6481 Printed Nam~ Signature . \ <;., ~_. Title: ~ ~hone Kuoaruk Team Leader Zc.;.S - (,-£ ?>ö Date 3/(0(0"-( 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 1a: 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 frorn 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 1 0-407 Revised 2/2003 .. ConocoPhillips Alaska Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Event Name: ROT - DRILLING Contractor Name: Doyon Rig Name: Doyon 141 Date From- To Hours Code '50~el Phase 12/5/2003 12:00 - 12:30 0.50 MOVE RURD MOVE 12:30 - 15:00 2.50 MOVE MOVE MOVE 15:00 - 16:30 1.50 MOVE MOVE MOVE 16:30 - 19:00 2.50 MOVE MOVE MOVE 19:00 - 22:00 3.00 MOVE RURD RIGUP 22:00 - 00:00 2.00 WELCT NUND RIGUP 12/6/2003 00:00 - 01 :00 1.00 WELCT RIGUP 01 :00 - 01 :30 0.50 WELCT RIGUP 01 :30 - 02:30 1.00 DRILL RIRD RIGUP 02:30 - 04:00 1.50 DRILL PULD RIG UP 04:00 - 08:00 4.00 DRILL PULD RIGUP 08:00 - 08:30 0.50 DRILL CIRC RIGUP 08:30 - 09:00 0.50 DRILL PULD RIGUP 09:00 - 10:00 1.00 RIGMNT RGRP RIGUP 10:00 - 10:30 0.50 DRILL REAM SURFAC 10:30 - 11 :30 1.00 DRILL DRLG SURFAC 11 :30 - 12:00 0.50 DRILL PULD SURFAC 12:00 - 00:00 12.00 DRILL DRLG SURFAC 1217/2003 00:00 - 03:30 3.50 DRILL DRLG SURFAC 03:30 - 05:00 1.50 DRILL CIRC SURFAC 05:00 - 17:30 12.50 DRILL DRLG SURFAC 17:30 - 19:00 1.50 DRILL CIRC SURFAC 19:00 - 20:15 1.25 DRILL TRIP SURFAC 20:15 - 21:30 1.25 DRILL TRIP SURFAC 21 :30 - 00:00 2.50 DRILL PULD SURFAC 12/8/2003 00:00 - 01 :30 1.50 CASE RURD SURFAC 01 :30 - 05:30 4.00 CASE RUNC SURFAC 05:30 - 07:00 1.50 CASE CIRC SURFAC 07:00 - 07:30 0.50 CEMEN PULD SURFAC 07:30 - 10:00 2.50 CEMEN CIRC SURFAC 10:00 - 13:00 3.00 CEMEN PUMP SURFAC Page 1 of 14 Spud Date: 12/17/2003 End: 1/20/2004 Group: Start: 12/5/2003 Rig Release: 1/20/2004 Rig Number: 141 Description of Operations Prep. for rig move. Move rig off of well 2P-434. Spot sub over well #2p-447, Level & Shim. Spot Modules, Rockwasher, Pipe shed & Tank farm. Rig up all components, Work on rig acceptance check list. Install 4' valves on conductor, Nipple up Diverter system, Take on water for spud mud. Note: Accept rig at 22:00 hrs 12/5/2003 Nipple up Diverter riser & Hook up accumulator hoses. Function test Diverter system & Accumulator, Test waived by AOGCC Jeff Jones. Change out handling tools to 5", Start mixing spud mud. Bring all BHA tools to rig floor, Thaw out same. Make up 12-1/4" BHA #1, Bit, NMDC, Stab, XO, MPR, MWD, Program MWD. Fill conductor with mud and check for leaks. Make up UBHO sub, XO, 1 stand HWDP, Tag ice @ 95', Stand back HWDP. Change out failed swivel packing cartridge on top drive. Break circ, Pick up stand of HWDP, Drill out ice from 95' to 108'. Spud well at 10:30 hrs 12/6/2003, Drill f/1 08' to 196' ART = 0.5 hrs. Stand back 1 stand HWDP, Orient UBHO sub, Pick up 1 stand 8" NMDC's to 196'. Drill f/ 196' to 1,100' (1,090' TVD) ART = 2.9 hrs AST = 3.6 hrs WOB 10/20K, 80 RPM, 600 gpm @ 1500 psi, UP 95K, ON 95K, ROT 95K, TQ 3K, Mud wt. 9.0 ppg, Vis. 293. Drill f/11 00' to 1384' ART = .75 hrs, AST = 1.0 hrs Note; Held detailed Diverter drill with all rig personal, Including Diverter kill drill with Kill mud tank farm. Pump sweep & circ hole clean, Circ & Correct surveys to IFR with Sperry-Sun due to magnetic storm. Drill f/1384' to 2716' (2324' TVD) 9-5/8" csg. point, ART = 5.65 hrs, AST= 3.1 hrs, WOB 10/25K, 90 RPM, 650 gpm @ 2100 psi, UP 108K, ON 100K, ROT 103K, TQ 5/10K, Mud wt. 9.4 ppg, Vis 166. Note; Had 3286 units gas @ 1988'. Pump Hi-vis weighted sweep, Circ hole clean with 3 times btm's up at rate of 650 gpm @ 1800 psi, 100 RPM. Back ream out of hole (Precautionary) at drilling rate to 1620', Hole in very good shape, Circ btm's up on last 2 stands pulled. Pump dry job, Blow down top drive, POOH to BHA. Down load MWD, PJSM, Lay down BHA, Clear rig floor of BHA tools. Rig Doyon casing equipment, PJSM. Rig & run 9.625" 40# BTC csg to 2,705' MD ( ran total 63 jts) - M/U hanger - MU landing jt, UP 120K, ON 105K. Break circ wI Franks fill up tool, Stage circ rate up to 6 bpm @ 325 psi, Btm's up gas 128 units, BGG 29 units. Lay down Franks fill up tool, Rig up Dowell cement head. Circ & condition mud for cement, Lower propertys from PV 38, YP 49 to PV 26, YP 14, Circ at rate of 6 bpm @ 325 psi, Held PJSM, Start batch mix spacers, Casing wt. UP 120K, ON 105K. Rig Dowell, Mix & pump 10 bbls CW100 at 8.3 ppg at rate of 5.0 bpm @ 95 psi, Shut down, Test lines to 3000 psi, Continue pumping CW100 to total of 40 bbls, Mix & pump 40 bbls MudPUSH II with red dye added Printed: 3/10/2004 10:14:49 AM Page 2 of 14 ConocoPhillips Alaska Operations Summary Report mixed at 10.5 ppg at rate of 1.1 bpm @ 45 psi (Had difficulty getting barite from silo's), Shut down and drop btm plug, Mix & pump 446 sxs (340.1 bbls) Lead ArcticSet III cmt mixed at 10.7 ppg wI additives at rate of 6.8 bpm @ 235 psi, Followed by 284 sxs (121.7 bbls) Tail LiteCRETE cmt mixed at 12.0 ppg wI additives at rate of 6.7 bpm @ 215 psi, Shut down and drop top plug, Displace cmt wI 20 bbls fresh water, Shut down and turn over to rig pumps and continue to displace wI 176.8 bbls 9.3 ppg mud (total of 196.8 bbls to bump plug) at rate of 7.0 bpm @ 700 psi, Slowed rate to 3.0 bpm @ 425 psi for last 10 bbls of displacement, Bump plug wI 1100 psi, Floats held- OK, CIP @ 12:52 hrs 12/8/03, Had good returns thru out job, Reciprocate csg. 15' until MudPUSH to surface then pipe got tight, Had 161.8 bbls good cmt returns to surface. Rig down Dowell cement head, Lay down landing joint, Lay down all casing tools. Nipple down Diverter system. Install FMC Gen 5 well head, Test same to 1000 psi- OK Nipple up BOPE & Test equip. Test BOPE to 250 psi Low & 5000 psi High, Test waived by AOGCC Jeff Jones, Blow down Choke manifold, Remove test plug, Install wear bushing. Slip & cut drilling line. Fin. slip & cut drlg line (65') Serviced rig & top drive, adjusted brakes on drawworks PU 135 jts of 5" DP from pipe shed and stood back MU 8 1/2" BHA #2, orient and upload MWD, held PJSM then loaded radioactive sources and shallow pulse test MWD Fin TIH with BHA #2, TIH with HWDP, MU pump out sub and ghost reamer TIH with BHA #2, PU 5" DP to 2,000' Held stripping and well kill drills with both crews Cont TIH with BHA #2 PU 5" DP to 2,505' Washed down and tagged float collar at 2,619', circ btms up at 420 gpm at 1,000 psi, 9.3 ppg MW in & out, rot wt 90K, pu wt 90K, dn wt 90K Attempted to test csg to 3,500 psi and couldn't get to hold pressure, made several attempts with upper VBR rams and Hydril with no success, checked surface lines and unable to find leak Pumped dry job and POOH, stood back HWDP Held PJSM, removed radioactive sources and LD MM Closed blind rams and pressure tested 9 5/8" csg to 3,500 psi for 30 min, good test Installed test plug and pressure tested top set of VBR rams to 250 psi low and 5,000 psi high, good test, tested Hydril to 250 psi and 3,500 psi and had good test, changed out stem & seat on 2" blow down line and pressure tested surface lines to 3,500 psi, good test 1.25 DRILL TRIP SURFAC Started MU 8 1/2" BHA #3, Uploading MWD Legal Well Name: 2P-447 Common Well Name: 2P-447 Event Name: ROT - DRILLING Contractor Name: Doyon Rig Name: Doyon 141 Date From - To I Hours ,Code Sub Phase Code 12/8/2003 10:00 - 13:00 3.00 CEMEN PUMP SURFAC 13:00 - 14:30 1.50 CEMEN PULD SURFAC 14:30 - 16:30 2.00 WELCT SURFAC 16:30 - 17:00 0.50 WELCT SURFAC 17:00 - 18:30 1.50 WELCT SURFAC 18:30 - 23:30 5.00 WELCT SURFAC 23:30 - 00:00 0.50 RIGMNT RSRV SURFAC 12/9/2003 00:00 - 00:30 0.50 RIGMNT RSRV SURFAC 00:30 - 01 :30 1.00 RIGMNT RSRV SURFAC 01 :30 - 07:00 5.50 DRILL PULD SURFAC 07:00 - 10:30 3.50 DRILL PULD SURFAC 10:30 -11:15 0.75 DRILL TRIP SURFAC 11 :15 - 12:00 0.75 DRILL TRIP SURFAC 12:00 - 14:00 2.00 DRILL SFTY SURFAC 14:00 - 15:00 1.00 DRILL TRIP SURFAC 15:00 - 16:00 1.00 DRILL CIRC SURFAC 16:00 - 17:00 1.00 DRILL DEOT SURFAC 17:00 - 18:30 1.50 DRILL TRIP SURFAC 18:30 - 19:30 1.00 DRILL TRIP SURFAC 19:30 - 20:45 1.25 DRILL DEOT SURFAC 20:45 - 22:45 2.00 WELCT BOPE SURFAC 22:45 - 00:00 Start: Rig Release: Rig Number: 12/5/2003 1/20/2004 141 Spud Date: 12/17/2003 End: 1/20/2004 Group: Description of Operations 12/10/2003 00:00 - 02:30 NOTE: Checked Outer Annulus pressure on 2P-432 had 250 psi, 2P-434 had 150 psi 2.50 DRILL TRIP SURFAC Fin MU 8 1/2" BHA #3, shallow test MWD, TIH and tagged up on float collar at 2,619' 1.00 CEMEN DSHO SURFAC Drilled out Float collar at 2,621', med cement in shoe track and float 02:30 - 03:30 Printed: 3/10/2004 10: 14:49 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/10/2003 ConocoPhillips Alaska Operations Summary Report 03:30 - 04:00 0.50 DRILL CIRC INTRM1 04:00 - 05:00 1.00 DRILL LOT INTRM1 05:00 - 05:30 0.50 DRILL CIRC INTRM1 05:30 - 06:15 0.75 DRILL DRLG INTRM1 2P-447 2P-447 ROT - DRILLING Doyon Doyon 141 From,~Jo I Hours .~ode I ¿,~Je Phase 02:30 - 03:30 1.00 CEMEN DSHO SURFAC 06: 15 - 06:45 06:45 . 09:00 09:00 - 09:15 09:15 - 12:00 12:00 - 12:15 12:15 - 12:30 12:30 - 14:00 14:00 - 16:00 16:00 - 17:30 17:30 - 18:00 18:00 - 19:00 0.50 WELCT 2.25 WELCT 0.25 WELCT 2.75 WELCT 0.25 WELCT 0.25 WELCT 1.50 WELCT INTRM1 INTRM1 INTRM1 INTRM1 INTRM1 INTRM1 INTRM1 2.00 DRILL DRLG INTRM1 1.50 DRILL CIRC INTRM1 0.50 DRILL CIRC INTRM1 1.00 DRILL DRLG INTRM1 19:00 - 19:30 0.50 DRILL CIRC INTRM1 19:30 - 20:15 0.75 DRILL DRLG INTRM1 20:15 - 20:30 0.25 DRILL CIRC INTRM1 20:30 - 00:00 3.50 DRILL DRLG INTRM1 Page 3 of 14 Spud Date: 12/17/2003 End: 1/20/2004 Group: Start: 12/5/2003 Rig Release: 1/20/2004 Rig Number: 141 Description of Operations shoe at 2,705', cleaned out to 2,716' and drilled 20' of new formation to 2,736' MOl 2,335' TVD Displaced out 9.3 ppg spud mud with 9.6 ppg LSND mud, circ at 500 gpm at 1,600 psi and 99k rot wt, 9.6 ppg mud, 57 vis in & out RU & performed LOT to 15.4 ppg EMW with 9.6 ppg mud, at 2,317' TVD and 700 psi Monitored well-static, made conn and survey, took slow pump rates with new 9.6 ppg mud Drilled 8 1/2' hole from 2,736' to 2,788' MOl 2,366' TVD (52'), 5K wob, 60 rpm's, 500 gpm at 1,600 psi, 5K ft-Ibs torque on & off btm, rot wt 100K, up wt 126K, dn wt 88K, while drilling at 2,788' gas increased to 7,300 units and had a 12 bbl pit gain, and shut in well Monitored well at choke, after 30 min SIDPP 10 psi, SICP 80 psi Circ out gas thru choke using drillers method at 30 spm at 300 psi, max gas at btms up was 14,000 units, 9.6 ppg mud gas cut to 7.8 ppg, circ a total of 2 complete circ and gas was down to 250 units, shut down Monitored well at choke, SIDPP 10 psi, SICP 70 psi Cont to circ well thru choke raised MW from 9.6 to 9.9 ppg, circ at 30 spm at 260 psi, max gas at btms up after monitoring well was 2,000 units, ave gas 300 units while circ thru choke, shut down Monitored well thru choke-static, open well up and monitored, well-static Circ btms up at 500 gpm at 1,650 psi, max gas at BU 1,400 units, 9.9 ppg mud gas cut to 9.6 ppg Circ & raised MW from 9.9 to 10.1 ppg, est PWD baseline and 10.6 ppg cleanhole ECD, ave BGG 200 units Drilled 8 1/2" hole from 2,788' to 2,967' (179'), 5-15K wob, 90 rpm's, 550 gpm at 2,000 psi, had 1 conn with 4,300 units gas and 10.1 mud gas cut to 7.7ppg, hole started taking mud at 30 bph rate at 550 gpm Circ and cond mud, raised MW from 10.1 to 10.3 ppg and added 15 ppb LCM to mud, slowed pumps to 500 gpm at 1,800 psi and losses slowed to 5-8 bph loss, ave BGG 100 units Made conn and circ btms up, max gas at btms up 1,000 units, 10.3 mud gas cut to 10.0 ppg, circ at 500 gpm at 1,800 psi Drilled from 2,967' to 3,060' MD/2,529' TVD (93'), raised mw from 10.3 to 10.5 ppg while drilling, ave BGG 100 units, ran PWD baseline with 10.5 ppg mud and had clean hole ECD of 11.4 ppg Circ btms up, max gas at btms up 1,400 units, 10.5 mud gas cut to 9.6 ppg Drilled from 3,060' to 3,153' (93') Circ btms up, max gas at btms up 3,000 units, 10.5 mud gas cut to 9.1 ppg, circ at 500 gpm at 1,850 psi Drilled from 3,153' to 3,380' MOl 2,728' TVD (227') 5-15K wob, 90 rpm's, 500 gpm, off btm press 1,850 psi, on btm 2,200 psi, off btm torque 4K ft-Ibs, on btm 6K ft-Ibs, rot wt 102k, up wt 114K, dn wt 92K, ave BGG 100 units, conn gas ranging from 2,500 to 4,500 units then drops down to back ground, Drilling with 10.5 ppg mud, ave ECD 11.8 ppg and minimal losses with 15 ppb LCM in system, mud lost to hole 26 bbls, pumped a high vis sweep with no increase in cuttings ART last 24 hrs 5.9 hrs, -0- AST NOTE: Checked Outer Annulus pressure on 2P-432 had 400 psi up from 250 psi, 2P-434 had 180 psi, up from 150 psi Printed: 3/10/2004 10:14:49 AM /- ~ . - ConqcoPhillips Alaska Page 4 of 14 Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Spud Date: 12/17/2003 Event Name: ROT - DRILLING Start: 12/5/2003 End: 1/20/2004 Contractor Name: Doyon Rig Release: 1/20/2004 Group: Rig Name: Doyon 141 Rig Number: 141 , t .. ¡SUb ! Date From - To : Hours co~e Code Phase Description of Operations - - 12/11/2003 00:00 - 12:00 12.00 DRILL DRLG INTRM1 Drilled 8 1/2" hole from 3,380' to 4,080' MOl 3,166' TVD (700') ART 9.0 hrs, AST 0.3 hrs, 5-20K wob, 90 rpm's 550 gpm, off btm press 2,150 psi, on btm 2,400 psi, off btm torque 5K ft-Ibs, on btm 9K ft-Ibs, rot wt 105K, up wt 130K, dn wt 101 K, ave ECD of 11.8 ppg with 10.6 ppg MW, ave BGG 100 units, conn gas ranged from 900 to 2,500 units depending on length of conn (gas coming from +1- 2,780'), pumped 1-30 bbl wt'd sweep at 1# over MW and had 10% increase in cuttings, lost approx 20 bbls wlcirc out and regained mud back after shutting down to make conn 12:00 - 00:00 12.00 DRILL DRLG INTRM1 Drilled from 4,080' to 5,008' MOl 3,742' TVD (928') ART 7.4 hrs, AST 1.2 hrs, 5-20K wob, 90 rpm's, 550 gpm, off btm press 2,500 psi, on btm 2,700 psi, off btm torque 6K ft-Ibs, on btm 9K ft-Ibs, rot wt 120K, up wt 145K, dn wt 105K, ave ECD of 12.0 ppg with 10.6 ppg MW, ave BGG 90 units with conn gas ranging from 500 units to 1,900 units depending on conn time, 10.6 ppg mud gas cut to 9.3 to 9.8 ppg, pumped 1-40 bbl wt'd sweep 2# over MW with no increase in cuttings, lost approx 25 bbls wlcirc out and regained mud back wIdrig and making conn's -0- mud lost to hole last 24 hrs, 26 bbls total lost to hole NOTE: Checked Outer Annulus pressure on 2P-432 had 700 psi up from 400 psi, 2P-434 had 200 psi, up from 180 psi 12/12/2003 00:00 - 12:00 12.00 DRILL DRLG INTRM1 Drilled 81/2" hole from 5,008' to 5,937' MD/4,319' TVD (929') ART 8.1 hrs, AST 1.1 hrs, 5-20K wob, 90 rpm's, 550 gpm, off btm press 2,650 psi, on btm 2,900 psi, off btm torque 8K ft-Ibs, on btm 10K ft-Ibs, rot wt 125K, up wt 165K, dn wt 111 K, ave 12.0 ppg ECD with 10.6 ppg MW, and no mud losses, ave BGG 90 units, ave conn gas 600-900 units, max conn gas 1,200 units, pumping hi vis sweeps every 400' with little to no increase in cuttings 12:00 - 00:00 12.00 DRILL DRLG INTRM1 Drilled from 5,937' to 6,660' MOl 4,760' TVD (723') ART 7.5 hrs, AST 1.6 hrs, 10-20K wob, 90 rpm's, 550 gpm, off btm press 2,650 psi, on btm 2,950 psi, off btm torque 9K ft-Ibs, on btm 12K ft-Ibs, rot wt 140K, up wt 190K, dn wt 120K, ave ECD 11.9 ppg with 10.6 ppg MW, ave bgg 60-70 units with conn gas ranging from 400-900 units and no gas cut mud, pumping hi vis sweeps every 400' with little to no increase in cuttings -0- mud lost to hole last 24 hrs, 26 bbls total lost to hole NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi up from 700 psi, 2P-434 had 200 psi, no change 12/13/2003 00:00 - 06:30 6.50 DRILL DRLG INTRM1 Drilled 81/2" hole from 6,660' to 7,052' MOl 5,009' TVD (392') ART 4.7 hrs, AST 0.8 hrs, 10-20K wob, 90 rpm's, 550 gpm, off btm press, 2,750 psi, on btm 3,150 psi, off btm torque 10K ft-Ibs, on btm 11.5K ft-Ibs, rot wt 136K, up wt 190K, dn wt 120K, ave ECD of 11.9 ppg with 10.6 ppg MW, ave BGG 50 units, with 300-600 units conn gas, no mud loss 06:30 - 10:30 4.00 DRILL CIRC INTRM1 Circ hole and raised LCM concentration from 15 ppb to 25 ppb prior to drlg Cairn sand, began by-passing shakers Note: Phase 3 Conditions in effect at 07:00 hrs 10:30 - 13:30 3.00 DRILL CIRC INTRM1 Circ hole and raised MW from 10.7 ppg to 11.1 ppg prior to drlg Caim sand, slowed pump rate from 550 gpm to 440 gpm due to seepage, circ hole by-passing shakers at 440 gpm at 2,100 psi 13:30 - 00:00 10.50 WAlTON WOW INTRM1 Phase 3 still in effect, cont to circ hole and standing back 1 std every 90 mins to 6,495' while waiting on weather, circ at 440 gpm at 2,100 psi Printed: 3/10/2004 10: 14:49 AM ConocoPhillips Alaska c>perations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-447 2P-447 ROT - DRILLING Doyon Doyon 141 Date Sub From - Tö' :Hours Code Code Phase Page 5 of 14 Start: Rig Release: Rig Number: Spud Date: 12/17/2003 End: 1/20/2004 Group: 12/5/2003 1/20/2004 141 Description of Operations -------- 10.50 WAlTON WOW INTRM1 and 90 rpm's, ave bgg 20-30 units, conn gas ave 100-150 units, ave ECD at 440 gpm with 11.1 ppg mud 11.85 to 12.0 ppg, performed 2 exhale tests, test # 1 at 18:00 hrs gained 16 bbls in 15 min, initial rate of 120 bph, final rate after 15 min, 24 bph, btms up gas after test #1 480 units, test #2 at 22:00 hrs gained 14 bbls in 15 min, initial rate 108 bph, final rate after 15 min, 24 bph, btms up gas after test #2 480 units, rot wt 135K, up wt 190K, dn wt 120K Lost 49 bbls of mud last 24 hrs, total mud lost to hole 75 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change 5.50 WAlTON WOW INTRM1 Phase 3 still in effect, Cont to circ hole and POOH standing back 1 std every 90 minutes to 6,033' while waiting on weather, performed exhale test at 04:00 hrs at 6,126', gained 14 bbls in 25 min, initial rate after 5 min 72 bph, rate after 15 min 24 bph, rate after 20 min 12 bph, final rate after 25 min 12 bph, CBU and max gas from test 288 units, ave bgg 20-30 units TIH to 6,683' and circ btms up, max gas 218 units TIH to btm with no problems, Cire btms up, max gas 300 units, circ at 400 gpm at 1,750 psi and 90 rpm's, rot wt 135K, up wt 185K, dn wt 110K POOH from, 7052' to 6,033' on elevators with no problems circ btms up at 6,033', max ags at btms up 2,020 units, circ at 400 gpm at 1,750 psi, ave BGG 40 units, POOH on elevators to 3,712' with no problems, circ btms up every 600' while POOH, max gas wlcirc btms up 913 units, ave gas while circ btms up 625 units Pumped out of hole from 3,712' to 2,700' to inside 9 5/8" esg shoe, pumped out across C-80 sand and gas from 2,780', pumped out at 375 gpm at 1,300 psi Circ hole at shoe and cond mud lowering PVIYP while eire, circ at 375 gpm at 1300 psi, no rotation, st wt 80K, ave BGG 20 units, circ at lower rate to keep ECD in the 11.9 ppg range and minimize mud losses (ave 10 bph losses) 6.00 WAlTON WOW INTRM1 Phase 3 still in effect on 2P pad and phase 2 in the field, staged in hole from 2,700' to 6,495', TIH to btm to raise MW to control gas at 2,780', circ btms up after every 5 stds while RIH, min btms up gas 175 units, max 525 units NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change 0.50 WAlTON WOW INTRM1 TIH from 6,495' to 7,052', washed last 93' to btm 1.00 WAlTON WOW INTRM1 Cire btms up from 7,052', max gas at btms up 212 units, ave bgg 30 units, circ hole with 11.2 ppg mud at 375 gpm at 1,600 psi with no mud loss, rot wt 137K, up wt 195K, dn wt 115K 1.25 WAlTON WOW INTRM1 Cire and raised MW from 11.2 to 11.4 ppg 0.50 WAlTON WOW INTRM1 Performed exhale test with 11.4 ppg mud, gained 15.5 bbls in 30 min, initial rate after 5 min, 48 bph, 5 min rate after 15 min, 33 bph, last 10 min rate was .25 bpm or 15 bph 0.75 WAlTON WOW INTRM1 Circ btms up, max gas from exhale test 232 units, cire at 375 gpm at 1,600 psi, ave BGG 30 units 12/13/2003 13:30 - 00:00 12/14/2003 00:00 - 05:30 05:30 - 06:00 0.50 WAlTON WOW INTRM1 06:00 - 07:00 1.00 WAlTON WOW INTRM1 07:00 - 08:00 1.00 WAlTON WOW INTRM1 08:00 - 08:30 0.50 WAlTON WOW INTRM1 08:30 - 12:00 3.50 WAlTON WOW INTRM1 12:00 - 13:30 1.50 WAlTON WOW INTRM1 13:30 - 18:00 4.50 WAlTON WOW INTRM1 18:00 - 00:00 12/15/2003 00:00 - 00:30 00:30 - 01 :30 01 :30 - 02:45 02:45 - 03:15 03:15 - 04:00 Lost 177 bbls of mud last 24 hrs, total mud lost to hole 252 bbls. Printed: 3/10/2004 10:14:49 AM ConocoPhillips Alaska Operations Summary Report 1.50 WAlTON WOW INTRM1 Circ and raised mw from 11.4 to 11.6 ppg, began loosing 10% returns, slowed pump to 350 gpm, 1,400 psi with no change in returns 0.25 WAlTON WOW INTRM1 Performed exhale test with 11.6 ppg mud, gained 9 bbls in 15, initial rate after 5 min's 48 bhp, final rate last 5 min 29 bph 2.25 WAlTON WOW INTRM1 Circ btms up, max gas from exhale test 55 units, ave bgg 30 units, initial circ rate 350 gpm, slowed to 300 gpm, 1,200 psi and 40 rpms with 10-15% losses, mixed 40 ppb LCM in pill pit 2.50 WAlTON WOW INTRM1 Pumped 50 bbl, 40 ppb LCM pill at 235 gpm at 775 psi, with pill in open hole increased rate to 350 gpm at 1,400 psi and increased rpm's f/40 to 70 to increase ECD's and squeeze LCM away and function test MWD tool, MWD tool ck ok, initial results, losses slowed but began to increase wlcirc, slowed pump to 235 gpm at 775 psi and 40 rpm's and circ with full returns, no ECD reading due to slow pump rate Pumped out of hole from 7,052' to 5,400', pumped out of hole at 235 gpm at 750 psi, no losses Circ btms up max gas at btms up 30 units, circ at 235 gpm Pumped out of hole from 5,400' to 4,000' Pumped and spotted 70 bbl, 40 ppb pill out bit POOH on elevators from 4,000' to 2,960' Circ hole above LCM pill, max gas at btms up 80 units, circ at 150 gpm at 300 psi, losses ranging from 10-20%, ave BGG 20-30 units Performed exhale test at 2,960', gained 9.25 bbls in 30 min, initial rate after 5 min 48 bph, 5 min rate after 15 min, 15 bph, final rate after 30 min 4.8 bhp Circ btms up after exhale test, max gas 30 units, BGG ave 10 units, circ at 150 gpm at 300 psi with 10-15% losses, pumped and spotted 40 bbl, 40 ppg LCM pill POOH on elevators to 2,400' (95/8" Shoe @ 2,705') Circ and above LCM pil at 150 gpm at 300 psi and losses still 10-15%, slowed pump to 125 gpm at 250 psi with no change in losses, lost 50 bbls wlcirc TIH from 2,400' to 3,335' Phase 3 still in effect, circ btms up at 3,335', circ at 150 gpm at 300 psi with 80% returns, max gas at btms up 133 units, ave bgg 10 units, rot wt 100K, up wt 104K, dn wt 95K Legal Well Name: 2P-447 Common Well Name: 2P-447 Event Name: ROT - DRILLING Contractor Name: Doyon Rig Name: Doyon 141 Date I From - To Hours I Code Sub Code Phase' 12/15/2003 04:00 - 05:30 05:30 - 05:45 05:45 - 08:00 08:00 - 10:30 10:30 - 12:15 1.75 WAlTON WOW INTRM1 12:15 - 13:00 0.75 WAlTON WOW INTRM1 13:00 - 14:30 1.50 WAlTON WOW INTRM1 14:30 - 15:00 0.50 WAlTON WOW INTRM1 15:00 - 15:30 0.50 WAlTON WOW INTRM1 15:30 - 19:00 3.50 WAlTON WOW INTRM1 19:00 - 19:30 0.50 WAlTON WOW INTRM1 19:30 - 21 :00 1.50 WAlTON WOW INTRM1 21 :00 - 21 :30 0.50 WAlTON WOW INTRM1 21 :30 - 22:30 1.00 WAlTON WOW INTRM1 22:30 - 23:00 0.50 WAlTON WOW INTRM1 23:00 - 00:00 1.00 WAlTON WOW INTRM1 Page 6 of 14 Start: Rig Release: Rig Number: Spud Date: 12/17/2003 End: 1/20/2004 Group: 12/5/2003 1/20/2004 141 Desçription of Operations Lost 850 bbls of mud last 24 hrs, total mud lost to hole 1,027 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change Recieved 24 Hr extension on BOP test from Chuck Scheeve with AOGCC 0.75 WAlTON WOW INTRM1 Phase 3 still in Effect, pumped and spotted 50 bbl, 40 ppb LCM pill out bit, 40 ppb Icm pill contained, mix II course at 8 ppb, mix II med at 8 ppb, mica at 5 ppb, nut plug med at 5 ppb, safe carb 250 at 5 ppb, safe carb 200 at 5 ppb and safe carb 500 at 4 ppb POOH slow from 3,335' to 2,690', well breathing WIPOOH, pulled up inside 9 5/8" csg Monitored well at shoe-static, no breathing POOH 3 stds from 2,695' to 2,400', well swabbed 3.5 bbls, monitored well 5 min- static Circ btms up at 2,400' at 100 gpm at 200 psi with no losses or gas at 12/16/2003 00:00 - 00:45 00:45 - 01 :45 1.00 WAlTON WOW INTRM1 01 :45 - 03:15 1.50 WAlTON WOW INTRM1 03: 15 - 03:30 0.25 WAlTON WOW INTRM1 03:30 - 06:00 2.50 WAlTON WOW INTRM1 Printed: 3/10/2004 10: 14:49 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To 12/16/2003 03:30 - 06:00 06:00 - 12:00 12:00 - 13:30 13:30 - 15:00 15:00 - 16:00 16:00 - 17:30 17:30 - 19:00 19:00 - 20:45 20:45 - 21 :15 21:15 - 00:00 12/17/2003 00:00 - 02:00 Page 7 of 14 ConocoPhillips Alaska Operations Summary Report 2P-447 2P-447 ROT - DRILLING Doyon Doyon 141 Hours I co~e ~o~e Phase:;· 2.50 WAlTON WOW INTRM1 6.00 WAlTON WOW INTRM1 1.50 WAlTON WOW INTRM1 1.50 WAlTON WOW INTRM1 1.00 WAlTON WOW INTRM1 1.50 WAlTON WOW INTRM1 1.50 WAlTON WOW INTRM1 1.75 WAlTON WOW INTRM1 0.50 WAlTON WOW INTRM1 2.75 WAlTON WOW INTRM1 Spud Date: 12/17/2003 End: 1/20/2004 Group: Start: 12/5/2003 Rig Release: 1/20/2004 Rig Number: 141 Description of Operations btms up, ave BGG 7 units Monitored well at 2,400', well breathed back 4.2 bbls in 2 hrs then static remaining 4 hrs. Circ btms up at 2,400' at 84 gpm at 180 psi with no gas at btms up or losses Monitored well-static, mixed 120 bbls of 50 ppb LCM pill with 30 ppb G-seal, 7 ppb, safe carb 30-50, 7 ppb safe carb 250, and 7 ppb S-200 while monitoring well TIH from 2,400' to 3,610' Pumped 117 bbls of 50 ppb LCM pill and spotted 43 bbls out bit, pumped at 84 gpm at 210 psi, lost 60 bbls mud while spotting pill Pumped out of hole from 3,610' to 2,130' laying in LCM pill, pumped at .5 bpm at 80 psi at 30'/min Monitored well, breathing slightly, circ btms up at 2 bpm, lost 23 bbls mud while circ btms up, 60-70% returns, ave BGG 6-8 units, max gas 35 units Monitored well, breathing slightly, closed annular and squeeze 9 bbls of LCM into formation, ave .5 bpm, max press 104 psi, ave press 95 psi, shut down and press dropped to 45 psi, monitored for 10 min with no decrease, bled off and opened well Phase 3 still in effect, monitored well at 2,130', gained 4 bbls in 2.75 hrs, gained 1.75 bbls the 1 st 15 min, gained .2 bbls last 15 min, began mixing 62 ppb LCM pill, nut plug course at 18 ppb, mica course at 17 ppb, G-seal at 16 ppb, mix II at 8 ppb and celloflake at 3 ppb Lost 214 bbls of mud last 24 hrs, total mud lost to hole 1,241 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change Recieved 24 Hr extension on BOP test from Lou Grimaldi with AOGCC 2.00 WAlTON WOW INTRM1 Phase 3 in effect, cont to monitor well at 2,130', gained 0.6 bbls in 2 hrs, last 30 min gained .2 bbls, mixed 62 ppb LCM pill while monitoring well, mixed nut plug course at 18 ppb, mica course at 17 ppb, G-seal at 16 ppb, mix II at 8 ppb and celloflake at 3 ppb Began TIH from 2,130' to 2,695' and determined circ sub dart would not go thru ghost reamer Pumped out of hole from 2,695' to 1,114' and LD ghost reamer TIH from 1,114' to 3,702' with 50% returns 02:00 - 02:30 0.50 WAlTON WOW INTRM1 02:30 - 04:15 1.75 WAlTON WOW INTRM1 04:15 - 06:15 2.00 WAlTON WOW INTRM1 06:15 - 07:45 1.50 DRILL CIRC INTRM1 07:45 - 09:00 1.25 DRILL TRIP INTRM1 09:00 - 09:45 0.75 DRILL OBSV INTRM1 09:45 - 12:30 2.75 DRILL TRIP INTRM1 Note Phase 3 lowered to phase 2 at 05:00 hrs Est circ at 3,702' at 84 gpm at 250 psi, 100 gpm at 280 psi, dropped circ sub dart and opened circ sub, (sub @ 3,410') took 8 min's to land and 1,150 psi to open, at 84 gpm had 130 psi and at 100 gpm 150 psi, slowed pump to 84 gpm and spotted 90 bbls of 62 ppb LCM pill, had 50% returns while spotting pill, while displacing pill with 40 bbls of 11.6 ppg mud, returns increased to 73% Pumped out of hole slow to lay in LCM plug from 3,410' to shoe at 2,705', POOH to 2,310' with circ sub at 2,018', had 6 bbl gain Monitored well, breathed back 6 bbls in 30 min and remained static final 15 min's Pumped out of hole at.5 bpm, -0- psi from 2,310' to 290' to BHA #3, stood back HWDP & Jars, hole took proper displacement, LD circ sub Printed: 3/10/2004 10:14:49 AM ConocoPhiUips Alaska Operations Summary Report·· . Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-447 2P-447 ROT - DRILLING Doyon Doyon 141 From - To I Hours Code I ¿;ouJe Phas~ Date Page 8 of14 Start: Rig Release: Rig Number: 12/5/2003 1/20/2004 141 Spud Date: 12/17/2003 End: 1/20/2004 Group: Description of Operations and re-built on loc. Pumped thru & flushed out MWD tool, downloaded MWD and removed radioactive sources and LD BHA #3 Pulled wear bushing RU & tested BOPE, all valves, choke manifold and rams to 250 psi low, 5,000 psi high, tested annular to 250 psil 3,500 psi, no problems with test, monitored well in cellar, gained 20 gal's 1st hr, last hr gained 5 gal's, Note: John Crisp with AOGCC waived witnessing of test 0.50 DRILL OTHR INTRM1 Installed wear bushing and cleared rig floor 2.00 DRILL PULD INTRM1 PU & MU 8 1/2" BHA #4, (rotary drlg assembly) uploaded MWD, RIH to 154' and surface tested MWD 1.00 DRILL TRIP INTRM1 TIH with HWDP, jars, circ sub & 5' DP on BHA #4 to 1,400' Phase 2 in field, have Larry Davis with Securityl EMT on location in case phase 3 is called 12/17/2003 09:45 - 12:30 2.75 DRILL TRIP INTRM1 12:30 - 15:00 2.50 DRILL PULD INTRM1 15:00 - 15:30 0.50 DRILL PULD INTRM1 15:30 - 20:30 5.00 WELCT BOPE INTRM1 12/18/2003 20:30 - 21 :00 21 :00 - 23:00 23:00 - 00:00 00:00 - 00:30 00:30 - 00:45 00:45 - 01 :00 01 :00 - 02:30 02:30 - 06:30 06:30 - 08:15 08:15 - 10:45 10:45 - 14:00 14:00 - 16:30 16:30 - 17:30 17:30 - 00:00 0.50 DRILL 0.25 DRILL 0.25 DRILL 1.50 DRILL TRIP INTRM1 CIRC INTRM1 TRIP INTRM1 CIRC INTRM1 4.00 DRILL TRIP INTRM1 1.75 DRILL CIRC INTRM1 2.50 DRILL TRIP INTRM1 3.25 DRILL CIRC INTRM1 2.50 DRILL DRLG INTRM1 1.00 DRILL CIRC INTRM1 6.50 DRILL DRLG INTRM1 Lost 124 bbls of mud last 24 hrs, total mud lost to hole 1,365 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change TIH from 1,400' to 2,080', access road and pad in phase 2 Est circ at 85 gpm at 120 psi, circ 30 bbls and lost 6 bbls TIH to 2,640' with 50% returns Est circ at 2,640' at 25 spm at 170 psi, cont to circ and stage pumps up to 315 gpm at 750 psi, max gas at btms up 63 units, circ 330 bbls of 11.6 ppg mud with 38 ppb LCM and lost 20 bbls w/circ, last 175 bbls mud pumped only lost 5 bbls, st wt 100K, dn wt 85K Staged in hole from 2,640' to 4,961' stopping every 5 stds to circ, circ ave of 90 bbls each time staging pumps up from 85 gpm at 190 psi to 100 gpm at 220 psi and 60 rpm's, circ with 90% returns, circ at 3,105', 3,569' and 4,033', then TIH to 4,961',314 Hr actual trip time Circ btms up at 4,961' staged pumps up from 85 gpm at 190 psi to 212 gpm at 420 psi, circ with 90% returns, max gas 133 units at 4,960' Staged in hole from 4,961' to 7,000' stopping every 5 stds to circ, circ ave of 60 bbls each time staging pumps up from 85 gpm at 200 psi to 212 gpm at 500 psi and 60 rpm's, circ with 95% returns, circ at 5,432', 5,904' and 6,376', then TIH to 7,000',314 Hr actual trip time Circ btms up at 7,000' with clean 11.6 ppg mud with 38-42 ppb LCM, staged pumps up from 85 gpm at 230 psi to 212 gpm at 540 psi, circ with 95% returns, max gas 144 units at 7,000', ave BGG 40 units, increased rate to 380 gpm at 1,300 psi prior to drlg ahead with no change in losses, rot wt 140K, up wt 177K, dn wt 95K, 11 K ft-Ibs torque with 60 rpm's, made connection and washed to btm at 7,052' Drilled 8 1/2" hole from 7,052' to 7,209' MOl 5,106' TVD (157') ADT 2.2 hrs, 10-20K wob, 90 rpm's, 380 gpm, off btm pressure 1,280 psi, on btm 1,310 psi, off btm torque 11 K ft-Ibs, on btm 15K, rot wt 145K, up wt 190K, dn wt 115K, ave bgg 30 units, max gas 130 units from conn at 7,088', ave ECD 12.4 ppg, with penetration rate of 70'/hr, ECD's increased to 12.5 ppg and ave losses of 30-40 bph increased to 60 bph losses Circ btms up at 7,209' at 250 gpm at 670 psi, lowered ECD's to 12.4 and stabilized losses down to 30 bph Drilled from 7,209' to 7,420' MOl 5,230' TVD (211 ') ADT 5.4 hrs, 10-15K wob, 70 rpm's, 365 gpm, off btm pressure 1,200 psi, on btm 1,300 psi, Printed: 3/10/2004 10: 14:49 AM ~ .J I ~ ] ConocoPhillips Alaska Page 9 of 14 Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Spud Date: 12/17/2003 Event Name: ROT - DRILLING Start: 12/5/2003 End: 1/20/2004 Contractor Name: Doyon Rig Release: 1/20/2004 Group: Rig Name: Doyon 141 Rig Number: 141 Date From ~To I Hours I Code Sub Phase Description of Operations Code -- 12/18/2003 17:30 - 00:00 6.50 DRILL DRLG INTRM1 off btm torque 12K ft-Ibs, on btm 15K ft-Ibs, rot wt 145K, up wt 200K, dn wt 115K, ave bgg 20 units, max conn gas 50 units at 7,283', conn gas coming from C-80, no gas on btms up, ave ECD 12.4 ppg with 11.6 ppg mud, ave 30 bph losses, well breathing approx 20 bbls back on each conn. phase 2 on access road & pad Lost 397 bbls of mud last 24 hrs, overall ave 25 bph losses w/circ & drlg Total mud lost to hole 1,762 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change 12/19/2003 00:00 - 07:30 7.50 DRILL DRLG INTRM1 Drilled 8 1/2" Hole from 7,420' to 7,620' MOl 5,336' TVD (200') ADT 6.7 hrs, 1 0-20K wob, 70-80 rpm's, 365 gpm, off btm press 1,250 psi, on btm 1,300 psi, off btm torque 12K ft-Ibs, on btm 15K ft-Ibs, rot wt 146K, up wt 203K, dn wt 116K, 11.6 ppg MW with 38-40 ppb LCM, ave mud losses 20 bph, ave ECD 12.3 ppg, ave BGG 35 units, max gas 125 units from conn at 7,558', drilled into Berumda at 7,560' MOl 5,306' TVD, 30' to 35' TVD higher than anticipated Phase 2 lowered to phase 1 at 06:00 hrs 12/19/03 07:30 - 09:15 1.75 DRILL CIRC INTRM1 Circ hole for samples and btms up gas, circ at 295 gpm, 920 psi with 50 rpm's, max gas 305 units from C-80 sand at 2,780', ave BGG 45 units, re-confirmed drlg into the Bermuda sand 09: 15 - 09:30 0.25 DRILL OBSV INTRM1 Performed exhale test, gained 41 bbls in 15 min 09:30 - 10:00 0.50 DRILL CIRC INTRM1 Circ and monitored gas, circ out 280 units gas from C-80 at 2,780' 10:00 - 10:30 0.50 DRILL OBSV INTRM1 Performed exhale test, gained 51 bbls in 30 min's, gained 7 bbls in last 5 min's for a 84 bph rate 10:30 - 12:00 1.50 DRILL CIRC INTRM1 Circ btms up after exhale test, circ at 168 gpm at 560 psi, ave BGG 45 units, max gas 306 units from C-80, no gas increase from btm (Bermuda) 12:00 - 12:30 0.50 DRILL OBSV INTRM1 Performed exhale test, gained 26 bbls in 30 min's, gained 2.6 bbls last 5 min's for a 31 bph rate 12:30 - 14:00 1.50 DRILL CIRC INTRM1 Circ btms up after exhale test, circ at 168 gpm at 560 psi, ave BGG 45 units, max gas 153 units from upper zone, POOH spotting a 10 bbl, 60 ppb hi vis LCM pill from 7,620' to 7,550' 14:00 - 16:00 2.00 DRILL CIRC INTRM1 Circ btms up at 7,550', circ at 126 gpm at 300 psi, circ at lower rate to ease breathing, ave BGG 45 units, max gas 50 units, 16:00 - 21 :30 5.50 DRILL TRIP INTRM1 Pumped out of hole from 7,550' to 2,640', circ at 105 gpm at 180 psi, max gas while pumping out 150 units, ave 45 units BGG, calc fill on trip out 37.5 bbls, had 25 bbl gain from breathing while pumping out to 9 5/8" shoe at 2,705'. 21 :30 - 22:45 1.25 DRILL CIRC INTRM1 Circ btms up at 2,640', circ at 100 gpm at 120 psi, ave BGG 40 units with no gas at btms up 22:45 - 23:30 0.75 DRILL OBSV INTRM1 Peformed exhale test at 2,640', gained 2.25 bbls in 45 min's, last 5 min's gained .2 bbls for a final rate of 2.4 bph 23:30 - 00:00 0.50 DRILL CIRC INTRM1 Began circ btms up at 2,640' after exhale test, circ at 84 gpm at 130 psi Lost 108 bbls of mud last 24 hrs Total mud lost to hole 1,870 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change Phase 3 on 2P access roads and pads as of 01 :00 hrs 12/20103 12/20/2003 00:00 - 01 :00 1.00 DRILL CIRC INTRM1 Fin circ btms up after exhale test at 2,640', circ at 84 gpm at 130 psi Printed: 3/10/2004 10:14:49 AM ~ I IIIIIII m . ConocoPhillipsAlaska Page 10 of 14 Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Spud Date: 12/17/2003 Event Name: ROT - DRILLING Start: 12/5/2003 End: 1/20/2004 Contractor Name: Doyon Rig Release: 1/20/2004 Group: Rig Name: Doyon 141 Rig Number: 141 Date ' I From - To Hours I Code ~SUb Phase Description of Operations . Code --- --- - 12/20/2003 00:00 - 01 :00 1.00 DRILL CIRC INTRM1 with no increase in gas at btms up, BGG 35 units and no losses 01 :00 - 03:30 2.50 DRILL TRIP INTRM1 Pumped out of hole from 2,640' to HWDP, monitored well, breathing slightly, cont pumping out standing back HWDP & jars 03:30 - 06:00 2.50 DRILL PULD INTRM1 Stood back NMDC's, LD stab's, flushed thru MWD tool, downloaded MWD and LD BHA #4 06:00 - 06:30 0.50 DRILL OTHR INTRM1 Pulled wear bushing and installed test plug, phase 3 lowered to phase 2 at 06:00 hrs 06:30 - 07:30 1.00 WELCTL OTHR INTRM1 Changed out top set of 31/2" x 6" VBR's over to 7" csg rams and tested door seals to 1 ,500 psi 07:30 - 09:00 1.50 CASE RURD INTRM1 RU Doyon's 7" csg equipment with Franks fill up tool, changed out elevator bales 09:00 - 09:15 0.25 CASE SFTY INTRM1 Held PJSM with csg hand and crew on running 7" csg 09:15 - 12:30 3.25 CASE RUNC INTRM1 Began running 7", 26#, L-80, BTC-M csg, MU Weatherford's 7" float shoe, 2 jts csg and float collar, thread locked conn below float collar, installed insert baffle ring in top of jt #3, attempted to pump thru fit equip, had to pressure up to 1,200 psi to open Franks fill up tool, fit equip ck, ok, RIH with 7" csg. lossing 50% returns. 12:30 - 14:00 1.50 CASE RUNC INTRM1 Run 7" csg - TIH slowly ( 20 fpm) with 29 jts. Lossing returns 50 - 75 %. 14:00 - 14:45 0.75 CASE CIRC INTRM1 Circu staging pump up very slow to 1.2 bpm - lossing 60 to 80 % returns the first 39 min. The last 15 min showed no loss. Lost 49 bbls. 14:45 - 16:30 1.75 CASE RUNC INTRM1 TIH slowly( 15 fpm) lossing 60 - 85 % returns. 16:30 - 17:30 1.00 CASE CIRC INTRM1 Circu staging pump up very slow to 1.2 bpm - lossing 80 to 90 % returns the first 25 min. The last 5 min showed 10 % losses. Lost 50 bbls. 17:30 - 18:00 0.50 CASE RUNC INTRM1 TIH slowly( 15 fpm) lossing 90 % returns. 18:00 - 19:00 1.00 CASE CIRC INTRM1 Attempted to circ btms up at 2,675' at 42 gpm at 110 psi and only had 20% retums 19:00 - 22:30 3.50 CASE RUNC INTRM1 RIH with 7" csg to 4,150', Pumped 12 stds down at 8 spm, RIH 10 stds, then pumped 13 jts down to 4,150' at 8 spm 20-30'/min (98 total in hole) 22:30 - 00:00 1.50 CASE CIRC INTRM1 Attempted to circ btms up at 4,150' with no success, only able to circ at .75 bpm at 200 psi with only 20-30% returns, any increase in pump and losses increased, csg st wt 115K up, 90K dn Lost 370 bbls of mud last 24 hrs, 310 bbls wlrunning csg, includes pipe displacement Total mud lost to hole 2,240 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change 12/21/2003 00:00 - 07:00 7.00 CASE RUNC INTRM1 Fin RIH with 7" 26#, L-80, BTC-M csg from 4,150' to 7,562', would RIH 10 stds, pumping 2 down to 7,562' wino returns, lost approx 100 bbls W/RIH, MU hanger and landed csg with float shoe at 7,562', float collar at 7,475' and stage collar at 3,105', ran a total of 177 jts with 2-pup jts, Total including float equip & hanger = 7,536.75' St up wt 235K, On wt 85K 07:00 - 08:00 1.00 CASE CIRC INTRM1 Attempted to circ btms up at 7,562', circ at 38 gpm at 550 psi thru Franks tool with minimal returns, pumped 51 bbls and lost 41 bbls 08:00 - 08:30 0.50 CASE RURD INTRM1 RD Franks fill up tool & MU Dowell's cmt head 08:30 - 10:00 1.50 CEMEN CIRC INTRM1 Cont to circ hole at 7,562', circ at 1 bpm at 310 psi and reciprocated pipe with very little returns, lost 140 bbls mud, held PJSM on cmtg 7" csg and batch mixed cmt 10:00 - 10:45 0.75 CEMEN PUMP INTRM1 Cemented 1st stage of 7" csg, Dowell pumped 10 bbls of CW 100 at 8.3 ppg, pressure tested lines to 4,000 psi, pumped add. 10 bbls of CW Printed: 3/10/2004 10: 14:49 AM Page 11 of 14 ConocoPhillips Alaska Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 2P-447 2P-447 ROT - DRILLING Doyon Doyon 141 I Sub From - To Hours Code Code Phase 12/21/2003 0.75 CEMEN PUMP INTRM1 10:00 - 10:45 10:45 - 13:00 2.25 CEMEN DISP INTRM1 13:00 - 17:00 4.00 WAlTON CMT INTRM1 17:00 - 17:15 0.25 CEMEN CIRC INTRM1 17:15 - 18:45 1.50 WAlTON CMT INTRM1 18:45 - 19:00 0.25 CEMEN SFTY INTRM1 19:00 - 20:30 1.50 CEMEN PUMP INTRM1 20:30 - 21:15 0.75 CEMEN DISP INTRM1 21:15 - 22:00 22:00 - 22:45 22:45 - 23:30 0.75 CEMEN RURD INTRM1 0.75 CASE DEQT INTRM1 0.75 CEMEN PUMP INTRM1 23:30 - 00:00 0.50 CEMEN RURD INTRM1 12/22/2003 00:00 - 01 :00 1.00 CEMEN INTRM1 01 :00 - 01 :45 0.75 DRILL INTRM1 01 :45 - 04:00 2.25 WELCT INTRM1 04:00 - 05:45 1.75 RIGMNT RSRV INTRM1 Start: Rig Release: Rig Number: Spud Date: 12/17/2003 End: 1/20/2004 Group: 12/5/2003 1/20/2004 141 Description of Operations 100, followed by 30 bbls of MudPush at 12.5 ppg, pumped at 2.9 bpm at 650 psi, pumped 34 bbls (165 sxs) of Class "G" GasBlok cmt with celloflakes and add's. at 15.8 ppg and 1.17 yield, pumped at 2.9 bpm at 540 psi, reciprocated pipe while pumping cement, up wt 230K, dn wt 90K, no returns while pumping cement, shut down, Calculated TOC @ 6,860' Dropped shut off plug and Dowell pumped 5 bbls water, turned over to rig and rig displaced cmt with 11.6 ppg mud, displaced at an ave rate of 84 gpm, init circ press, 210 psi, saw dart go thru stage tool, had 20 psi increase, cont to displace cmt at 84 gpm, final circ press 510 psi, bumped plug to 800 psi, held for 5 min, ck floats and held CIP at 12:48 hrs, no returns w/displacing cmt, pressured up to 3,550 psi and opened stage tool at 3,105', reciprocated pipe until CW 100 was around shoe, then landed in hanger W.O.C on 1st stage, monitored well-static Attempted to est circ at stage tool at 3,105', staged pump up to 105 gpm at 180 psi, after pumping 4.2 bbls still had no returns and shut down W.O.C. on 1st stage, well-static Held PJSM with Dowell & rig crew on pumping 2nd stage and possible cmt job on annulus Pumped 2nd stage cmt job thru stage tool at 3,105, Dowell pumped 5 bbls water, press tested lines to 3,500 psi, pumped 30 bbls of 11.6 ppg MudPush with dye spacer followed with 163 bbls (340 sxs) of 12.0 ppg, 2.68 yield ArctiCrete cmt with celloflakes and add's. ave 4 bpm while pumping, initial circ press 285 psi, final press 160 psi, had no returns, shut down Dropped stage tool closing plug, Dowell pumped 10 bbls water, turned over to rig and rig displaced cmt with 11.6 ppg mud, ave 4 bpm, initial press 275 psi, final press 350 psi, bumped closing plug, pressured up to 900 psi and closed stage tool, press up to 1,250 psi and held for 3 min, bled off press and ck stage tool and tool closed, CIP at 21 :05 hrs, no returns throughout job RD cmt head and LD landing jt Installed FMC 7" pack-off and tested to 5,000 psi for 10 min Performed down-squeeze and cemented off 7" x 9 5/8" annulus, Dowell pumped 2 bbls water, pressure tested lines to 2,500 psi, mixed and pumped 94 bbls (197 sxs) of ArctiCrete cmt at 12.0 ppg, 2.68 yield with add., pumped at 4 bpm, initial pressure 580 psi, final pressure 400 psi, followed cmt with 1 bbl water to clean lines, CIP at 23:20 Rd cementers & cleared rig floor Lost 944 bbls of mud last 24 hrs Total mud lost to hole 3,184 bbls. NOTE: Checked Outer Annulus pressure on 2P-432 had 800 psi no change, 2P-434 had 200 psi, no change Fin RD Csg equip. and changed out elevator bales, MU stack washer tool and cleaned out stack with fresh water, cleaned out a large amount of LCM from ram bodies. Installed test plug, changed out top set of rams from 7" back to 31/2" x 6" VBR's, lower rams are 4" pipe rams. Changed overt top drive to 4" DP, adjusted grabbers and bell guides, serviced top drive and blocks Printed: 3/10/2004 10:14:49 AM Page 12 of 14 ConocoPhillips Alaska Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Event Name: ROT - DRILLING Contractor Name: Doyon Rig Name: Doyon 141 Date From - To Hours I Code Sub Phase Code 12/22/2003 05:45 - 11 :30 5.75 DRILL PULD INTRM1 11 :30 - 12:00 0.50 DRILL RIRD INTRM1 12:00 - 16:00 4.00 WELCT BOPE INTRM1 16:00 - 16:30 0.50 DRILL OTHR INTRM1 16:30 - 17:30 1.00 DRILL PULD INTRM1 17:30 - 18:30 1.00 RIGMNT RSRV INTRM1 18:30 - 21 :00 2.50 DRILL PULD INTRM1 21:00 - 21:15 0.25 DRILL SFTY INTRM1 21 :15 - 22:30 1.25 DRILL PULD INTRM1 22:30 - 00:00 1.50 DRILL TRIP INTRM1 12/23/2003 00:00 - 00:.30 0.50 DRILL TRIP INTRM1 00:30 - 03:00 2.50 DRILL DRLG INTRM1 03:00 - 06:45 3.75 DRILL TRIP INTRM1 06:45 - 08:00 1.25 DRILL CIRC INTRM1 08:00 - 09:00 1.00 DRILL DEOT INTRM1 09:00 - 13:00 4.00 DRILL DRLG INTRM1 13:00 - 13:30 0.50 DRILL DRLG INTRM1 13:30 - 14:30 1.00 DRILL CIRC INTRM1 14:30 - 15:00 0.50 DRILL FIT INTRM1 15:00 - 00:00 9.00 DRILL DRLG PROD 12/24/2003 00:00 - 03:00 3.00 DRILL DRLG PROD 03:00 - 04:00 1.00 DRILL CIRC PROD 04:00 - 04:30 0.50 DRILL WIPR PROD 04:30 - 05:00 0.50 RIGMNT RSRV PROD 05:00 - 05:15 0.25 DRILL WIPR PROD 05:15 - 06:30 1.25 DRILL CIRC PROD 06:30 - 11 :30 5.00 DRILL TRIP PROD 11 :30 - 12:30 1.00 DRILL TRIP PROD 12:30 - 14:30 2.00 DRILL PULD PROD 14:30 - 21:00 6.50 LOG ELOG PROD 21 :00 - 00:00 3.00 CASE PULR PROD Start: Rig Release: Rig Number: 12/5/2003 1/20/2004 141 Spud Date: 12/17/2003 End: 1/20/2004 Group: Description of Operations RU & LD 180 jts of 5" DP from derrick, repositioned 18 stds DP to offdrillers side, to leave for rig move.( Will be used to drill surface on next well) Changed out handling equip on rig floor from 5" to 4" DP RU and tested BOPE, valves, manifold and rams to 250 psi low and 5,000 psi high, tested annular to 250 psi & 3,500 psi, no problems with test, Note: John Crisp with AOGCC waived witnessing of test Pulled test plug and installed wear bushing PU & stood back 24 jts of 4" HT-39 DP Slip & cut 78' of drlg line MU 6 1/8" BHA #5, orient & uploaded MWD, RIH to 97' Held PJSM on loading radioactive sources Loaded radioactive sources and fin MU BHA #5 to HWDP Single in hole PU 29 jts 4" HWDP, jars & 48 jts of 4" HT-39 DP to 2,609' Continue picking up 4" drill pipe to 3105' (Stage collar). Drill out Stage collar @ 3105', 295 gpm @ 1700 psi, 50 RPM, 2/3K WOB. Pick up 4" drill pipe to Insert Baffle @ 7432'. Circ & change over from 11.6 ppg to 10.4 ppg mud at 295 gpm @ 2100 psi. Rig & test 7" csg to 3500 psi fl 30 min. Drill out Insert Baffle @ 7432', Float collar @ 7474', Shoe @ 7560' & cement to 7620',300 gpm @ 2050 psi, 50 RPM, 2/3 WOB, TO 7K, Monitor well- static. Drill 20' new hole fl 7620' to 7640' (5346' TVD). Circ hole clean for FIT. Perform 12.5 ppg FIT wI 552 psi, 5307 TVD & 10.5 ppg mud. Drill fl 7640' to 7900' ART = 4.6 hrs, AST = 1.3 hrs, WOB 5/1 OK, 100 RPM, 270 gpm @ 2060 psi, UP 155K, ON 90K, ROT 115K, TQ 8K on/off. ""MAx Gas units while drilling= 54 units @ 7700', 324 units @ 7713', 550 units @ 7762' and 1170 units @ 7777' - At TD BGG running 50 - 60 units. Drillfl 7900' to 8015' AST = 0 hrs, ART = 2.5 hrs, WOB 2/12K, RPM 100,270 gpm @ 2100 psi, Mud wt. 10.4 ppg, BGG 9 - 50 units. Circ & condo mud, Pump Hi-vis sweep, 270 gpm @ 2100 psi, 100 RPM, Observe well- Static. Back ream out to shoe @ 7562' pumping at drill rate, Hole in very good shape. Service top drive and blocks. RIH to 7936', Precautionary ream to 8015'. Circ & condo mud, 270 gpm @ 2100 psi, 100 RPM, Observe well- Static, Trip gas 220 units, BGG below 50 units. Back ream out to shoe @ 7562' pumping at drill rate, Back ream out to 7095' at rate of 168 gpm @ 900 psi, 20 RPM, Observe well- Static, Pump dry job, Blow down top drive, POOH on elevators to BHA @ 1113'. Observe well- Static, POOH & stand back HWDP. PJSM, Remove RA sources, Down load MWD, Lay down BHA. Rig Schlumberger wire line, Run US IT log f/7545' to 2208' showed very poor bond, Rig down SWS. PJSM, Rig & run 17 joints 3-1/2", 9.3#, L-80, SLHT liner, Pick up Baker Printed: 3/10/2004 10: 14:49 AM / ~ ..... Page 13 of 14 ConocoPhillips Alaska Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Event Name: ROT - DRILLING Contractor Name: Doyon Rig Name: Doyon 141 Date From - To Hours '..1 Sub Phase Code Code 12/24/2003 21 :00 - 00:00 3.00 CASE PULR PROD 12/2512003 00:00 - 00:30 0.50 CASE PULR PROD 00:30 - 06:00 5.50 CASE RUNL PROD 06:00 - 06:15 0.25 CASE RURD PROD 06:15 - 08:00 1.75 CASE CIRC PROD 08:00 - 08:45 0.75 CASE RUNL PROD 08:45 - 11 :15 2.50 CEMEN CIRC PROD 11:15-12:30 1.25 CEMEN PUMP PROD 12:30 - 13:00 0.50 CASE MIT PROD 13:00 - 13:30 0.50 CASE CIRC PROD 13:30 - 15:30 2.00 CASE CIRC PROD 15:30 - 16:00 0.50 CEMEN PULD PROD 16:00 - 16:30 0.50 CASE DEOT PROD 16:30 - 21:30 5.00 DRILL TRIP PROD 21 :30 - 23:00 1.50 DRILL TRIP PROD 23:00 - 00:00 1.00 WELCT EORP PROD 12/26/2003 00:00 - 01 :00 1.00 WELCT EORP PROD 01 :00 - 01 :45 0.75 WELCT NUND PROD 01:45 - 03:15 1.50 WELCT NUND PROD 03:15 - 04:15 1.00 WELLS DEOT PROD 04:15 - 06:00 1.75 WELLS RURD PROD 1/19/2004 00:00 - 01 :00 1.00 MOVE DMOB DEMOB 01 :00 - 03:00 2.00 MOVE MOVE MOVE 03:00 - 06:00 3.00 MOVE MOVE MOVE 06:00 - 08:00 2.00 MOVE RGRP MOVE Start: Rig Release: Rig Number: 12/5/2003 1/20/2004 141 Spud Date: 12/17/2003 End: 1/20/2004 Group: Description of Operations liner hanger and tools, Liner wt. UP 38K, ON 37K. Mix & Install Pal mix into top of liner. RIH w/liner on drill pipe to 7548' filling pipe every 10 stands and break circ every 20 stands, Had good displacement while RIH, No mud lost. Make up 10' pup to Baker cement head, Lay down on skate. Circ btm's up, Stage rate up from 1.5 to 3.5 bpm @ 700 psi, Had 22 units btm's up gas, Obtain UP, ON & ROT weights, Check TO. RIH to 8012', Pick up Baker cement head, Tag btm @ 8015'. Circ & Condo mud for cement job, Stage rate up f/1.5 bpm to 3.5 bpm @ 700 psi, Trip gas 40 units, No mud lost, Mud check before= Wt. 10.5, vis 50, PV 19 YP 23, After= Wt. 10.3+, vis 42, PV 15, YP 15, Obtain UP wt of 148K, ON 87K, ROT 106K, TO 5500 ftllb, Held PJSM with all rig personal for cement job, Batch mix cement. Switch to Dowell, Pump 10 bbls 8.3 ppg CW100, Shut down & test lines to 4500 psi, Pump 10 more bbls CW100 at rate of 4.0 bpm @ 885 psi, Pump 25 bbls 11.5 ppg MudPUSH at rate of 4.0 bpm @ 900 psi, Pump 31.3 bbls (150 sxs) Class 'G' cmt mixed at 15.8 ppg w/.03%B155, .40%065, .20%047, 2.0%D600G, pumped at rate of 4.0 bpm @ 725 to 250 psi, Shut down, Wash lines to rig floor, Drop plug, Displace cmt wI 10.0 bbls Fresh water followed by 73.0 bbls 10.3 ppg mud (Note: Seen pressure spike when plug went thru top of liner and continued to pump 4.3 bbls to displace liner), Slowed rate to 2 bpm @ 600 psi for the last 10 bbls, Pumped plug wI 1500 psi, C.I.P at 12:10 hrs 12/25/03, Reciprocated csg. 15' & Rotate until last 10 bbls of displacement, Had good circ thru out job. Continue to pressure up to 2500 psi to set hanger, Slack off 25K to check that hanger is set- OK, Pressure up to 4000 psi to release from liner, Bleed off & check floats holding- OK (Bleed back 1 bbl), Swith to rig pumps, Pick up 9' to expose dogs, Slack off 10 K to check dogs exposed- OK, Bleed off all pressure, Slack off 50K and set casing packer, Close Hydrill & pressure annulas to 1000 psi- OK, Bleed off pressure, pressure drill pipe to 500 psi, Pick up 5' until pressure bled off & Pick up an additional 5'. Note: Shoe set @ 8,010', TOL @ 7,415'. Circ btm's up at rate of 8.0 bpm @ 1970 psi, Had CW100, MudPUSH & 10.0 bbls cmt & cmt contaminated mud return to surface. Pump 23 bbls Hi-vis spacer pill followed by 280 bbls Fresh water, Pump 23 bbls Hi-vis spacer pill followed by 310 bbls 11.0 ppg Brine. Lay down Baker cement head. Test casing to 3500 psi for 10 min.- OK POOH & lay down 4" drill pipe, Lay down Baker liner running tool. Lay down 4" HWDP from derrick. Clear rig floor, Pull wear bushing. C/O rams to 5" ( 3.5" VBRs Top, 5" rams Bttm) NID BOPs and set back on stump. NIU Dry hole tree wI full open 71/16" valve. RIU & Test Csg and tree assy to 3500 psi on chart for 30 min. NID outter ann valve, clean out cellar - Secure well **Release Rig 0600 hrs 12/26/2003** RD and Moved rig off 2P-424 Moved rig from 2P-424 and spotted sub base on 2P-447 Spotted rig's, pits, pumps, motors, boiler, pipe shed and rock washer complex's Hooked up service loops for rig, began working on rig acceptance Printed: 3/10/2004 10: 14:49 AM ~ ConocoPhillips Alaska Page 14 of 14 Operations Summary Report Legal Well Name: 2P-447 Common Well Name: 2P-447 Spud Date: 12/17/2003 Event Name: ROT - DRILLING Start: 12/5/2003 End: 1/20/2004 Contractor Name: Doyon Rig Release: 1/20/2004 Group: Rig Name: Doyon 141 Rig Number: 141 C d I SUbl I Date From -To Hours .. 0 e Code Pha$e I Description of Operations --- 1/19/2004 06:00 - 08:00 2.00 MOVE RGRP MOVE check list 08:00 - 08:30 0.50 CMPL TN OBSV CMPL TN Monitored well 30 min-well static, installed secondary annulus valve and completed rig acceptance check list Accepted Rig @ 08:00 hrs, 1-19-04 08:30 - 09:30 1.00 CMPL TN NUND CMPL TN NO dry hole tree and adapter flange 09:30 - 11 :30 2.00 CMPL TN NUND CMPL TN NU 135/8" 5M BOP stack 11 :30 - 19:30 8.00 WELCTL BOPE CMPL TN RU & tested BOPE, tested all valves manifold and rams to 250 psi, low, 5,000 psi high, annular to 250 psi and 3,500 psi, performed accumulator test, RD and pulled test plug Note: John Crisp witnessed accumulator test. 19:30 - 20:30 1.00 RIGMNT RSRV CMPL TN Cut & Slip 130' of drlg line 20:30 - 21 :30 1.00 CMPL TN RURD CMPL TN RU Doyons 4 1/2" tbg handling equipment 21 :30 - 21 :45 0.25 CMPL TN SFTY CMPL TN Held PJSM with Baker Rep, Doyon tong operator and rig crew on running 4 1/2" compo 21 :45 - 22:45 1.00 CMPL TN OTHR CMPL TN PU seal assmbly & RIH, tagged ice plug at 30', LD assembly, PU std of 4" DP, RIH and washed out 6-8" of ice at 30' 22:45 - 00:00 1.25 CMPL TN RUNT CMPL TN Ran 4 1/2" completion to 990', MU Baker 3 1/2" GBH-22 Seal assembly, locator sub, with XO from 3 1/2" EUE-M to 41/2" IBT-M, 1 jt of 41/2" 12.6# L-80 IBT-M tbg, Camco DB nipple W/3.75" no go, 4 1/2" CMU sliding sleeve WI DB nipple W/3.813" profile, 1-jt of 41/2" tbg, 4 1/2" x 1" Camco KBG-2 GLM with DCK shear valve, RIH with completion assembly PU 4 1/2" 12.6# L-80 IBT-M tbg (30 Jts PU) to 990' 1/20/2004 00:00 - 05:00 5.00 CMPL TN RUNT CMPL TN Continue running total of 238 joints 4-1/2" completion string. 05:00 - 06:30 1.50 CMPL TN CIRC CMPL TN Rig & change over f/11.0 ppg brine to clean seawater. 06:30 - 08:45 2.25 CMPL TN SOHO CMPL TN Pick up 2 pup joints 1 jt. below hanger & Land hanger @ 7,447' (2' above fully located positon). 08:45 - 10:30 1.75 CMPL TN DEQT CMPL TN Rig & Preesure test tubing to 3500 psi f/30 min.- OK, Bleed tubing press. down to 1500 psi, Pressure test 7" x 4-1/210 annulas to 3500 psi fl 30 min.- OK, Bleed off tubing preesure & Shear out DCK valve. 10:30 - 11:00 0.50 CMPL TN PULD CMPL TN Lay down landing joint & clear rig floor. 11 :00 - 12:30 1.50 WELCTL NUND CMPL TN Install 2 way check, Nipple down BOPE 12:30 - 14:30 2.00 WELCTL NUND CMPL TN Nipple up & test FMC Gen 5 Tree to 5000 psi f/15 min- OK, Pull 2 way check. 14:30 - 17:00 2.50 CMPL TN FRZP CMPL TN Pump 80 bbls diesel down 7"x 4-1/2" annulas & U-tube to freeze protect well @ 2366'. 17:00 - 18:00 1.00 WELLSF PLGM CMPL TN Set BPV, Secure well. Note: Release rig at 18:00 hrs 1/20/2004 Outer annulas pressures= 2P-432 750 psi, 2P-434 500 psi, 2P-447 0 psi. Printed: 3/10/2004 10: 14:49 AM . . Well Name Date Summary 2P-447 02/06/04 PERFORATED: 7780' -7800', 6 SPF POWERJETO [Perf] 2P-447 02/07/04 PERFORATED: 7700' - 7780', 6 SPF, 60 DEG PHASING, POWERJET CHARGES.O [Perf] 2P-447 03/01/04 SBHP AT 7650'= 1559.0 PSIA & TEMP= 134.8 DEGF, SBHP AT 7750'= 1582.1 PSIA & TEMP= 135.7 DEGF (SBHP MEASUREMENTS TAKEN WITH 7700'- 7800' PERFED ONLY), -- PERFORATED: 7600' TO 7640', 6 SPF POWERJET -- SET WEATHERFORD WRP PLUG WITH MID ELEMENT AT 7680' - TAGGED at 7913'. ¥ ConocOPhillips ConocoPhlmpS Alaslc..SIO' #441 Drill Site 2P, Meltwater,North Slope, Alaska _d-O,3-- }5'i wellPaaWD w/IFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 r&i. BAKER HUGHES INTEQ I~ÌlbOr¡, 447 Iwell ~ I Created 7 -Dec-2003 I Last Revised 29-Dec-2003 Slot Name I 4 Installation Drill Site 2P I ~g_~~~~~~t61~oo I ~~~~~:~~~~ 441964.238 True I írtéli!; ~:ater I Eastina I Northina 441964 238 I~~ ~ INtl!bðlj,mont I 5869891466 . ..... .. ..... RERICAN~:U:'~:: \;<iTru, Created Bv Comments \~ß~\\\~ I ^ f'l ? 0 l)t\1'!4 ...... \! '- fJ '-Uti '\I..œl Gas Cons. Commiefan All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Doyon #141252.00 above mean sea level Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ..Q.Q.(J ..Q.Q.(J 0,91 ..Q..8f¡ 2..9!1 6.87 ..9.2Z JU.I 8.99 .1Q..2j 12.44 16.58 ..u!..2Z ..2!l.&ì 24.38 ~ ..J2..n 35.02 ..Jfi.l..1 ~ 42.48 M..81 AM!: 49.06 ~ ~ 52.31 ~ ~ 53.68 ~ ~ 52.18 ..5.1Jlij .M..2Z 51.41 ..alÆ ~ 50.8C ~ ~ 51.2~ ~ ..Q.1..U 52.8<1 ~ ~ 50.44 ~ ..51.1f 51.4~ ~ 1585.69 165113~ 1714 44~ 1778.87~ 1841 48~ 1904 21~ 1970.61~ 2036 18~ 2100 52~ 2163.59~ 2227 53~ 2291 72~ 2355.64~ North[ft] 1393.92 Dogleg Easting de 11001'[ 2679.2 ~ 443562 3~ 443560.9: 443559 6- 443557 5~ 443552.71 443545 1 443536.0- 443527.4- 443519.11 443509 9: 443498.61 443485 01 443469 71 443452.5 443432 1 I 443409 4! 443384.5~ 443357 41 443328 6: 443297.91 443265 8: 443233 5! 443199.51 443164.9' 443130.1- 443095.4~ 443060.01 443047 T 442993.1 : 442956 9' 442921 51 442886.3' 442850 5! 4428156' 442781.1 ! 4427471: 442713 3 442680.1: 442645.7' 442611.8: 442577.0: 442543.4! 442509 71 442474.31 442439.2~ 442404 31 442370.3: 442336 11 442302 3' 442268.2 5867091.4 5867029 1 5866966 6 5866900.5 5866835 2 5866771 1 5866708.3: 5866644 6- 5866580 7 5866517.0. ..6; 5867863.3 5867797 6 5867732 5, 5867668.1 ' 5867603 0 5867538 g 5867474.8 58674113 5867347 1 5867283.8 5867218.1 1':, 5868862 9: 5868862 9: 5868862.4' 5868861 81 5868859 8: 5868853.7 5868843 5! 5868832.0 5868820.41 5868808.31 5868792.9' 5868771.3: 5868744 8: 586871671 5868685.7: 5868648 8: 5868606 8' 5868561.4 58685139 5868464 3 5868411.5 5868355 5 5868298 2 5868237.6 58681757 58681129 5868050.0 WeUpath {Grid~ Report MD[ft] nc[deg] Azi[deg] I TVD[ft] East[ft] Northing ~illips ConocoPhmlps Alaslco,slOI #447 Drill Site 2P, Meltwater,North Slope, Alaska weIlP&WD wll FR+MC+Sag<0-2642'>MC+Sag<2783 8015'> Date Printed: 22-Jan-2004 "... BAKER HUGHES INTEQ y ConocoPhillips ConoeoPh;U;ps Alas.le..slol #447 Drill Site 2P, Meltwater,North Slope, Alaska wellPaaWD wIlFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 "~i. BAKER HUGHES INTEQ WellDath (Grid' Reøort . MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing dea/100ftl Sectionlftl 4R?R4' fi1Çf 21 OR~ ::IR::I17: ?<11A 7f'.' 1:1 (XV 17F ?7fi1 R: ~ l' 4Ç18.3! 51.7~ 209.Of 3688.fi ?<1A 1 <1,,' 1 "I~ ?R?11 ,-.-- 7: 5012.0 51.51 208.9( 3746.6 2545.66 1384.29V 0.2E 2897.5 442159.4 5866327.S. fi10fiO! fi20: 207.Çf 3R0421 ?f'.00 0"1' 0Ç7 ?070 f'. ~ A. fi1Ç8.1: 51.9: 207.2f 3861.fi: ,)&:7A an' o f'.1 ;'¡M"IOI 1: 5291.3 51.6 207.2 3919.1 2740.04 1486.57V 0.2E 3117.1 442055.7 5866134.2 fi3R3Ç~ fi2 .4~ 2075f 3Ç7R1: ?AO<1 A7C o A'J ~ ~ ~nnn^^' f'.' 5476.7 52.4E 207.2, 40"l? f'. ?A70 1 fi~ 1"'''' .^'''' o "Ir "I?f'."I f'.1 4410A7."I, 5866004.6~ 5569.7 51.7~ 207.21 4089.8 2935.45 1587.64V 0.7 3337.0 441953.2 5865939.6 5662.5' 5UE 207.1 ( 4147.5! "'^^^ ^^' o f'.C ~ ~~ "0&:"07" ?' 5755.3: fi1 Rc ?07."I~ 4?Ofi.4 ':In&:'" 1:;1' O.R~ ":t4A? .0' <141 AAfi.<:! 5865811.0! 5848.6 52.2 207.5 4262.9 3129.76 1687.88V 0.5c 3555."-' 441851.5 5865746.0 5941.61 51.8~ ?07 <1' 4"1?0.1 "I1a4.Rm 17?1 70V 04 "IR2R.R~ 441R' 5865681.21 RO::l2.fi~ fi1 1 c ?07 7~ 4::17R.7 ::I2fi7.RR! A~~ nn.. 0.7F "IRaa.a' ,..~nn n. I:;A&:I:;&:1A LI' 6125.8( 51Æ 207.OL 4434.7 3322.65 1788.27V 0.9~ 3772.9 441749.7 5865553.9 6217.0! fi::lfi1 ?OR "f <140011 1A,)1 nn" 1 R7 "1M" 4, .._ ,n _. I:;A&:I:;AAa "I' R::I1? ?~ fi::l O~ ?ORO' 4!'\4R a! nA~~ n., 1 R<;4 7RV o R7 "Ia?1 fi( I:;A&:I:;"',)1 '), 6403.9 52.4~ 206.9.1 4602.5 3521.19 1887.35V 0.9c 3994.5 441649.1 5865356.1 Ma701 fi1af ?OR a( 4Rfia4( n~nn ~M o fi7 40RR 0, AA 1&:11:; ':I, I:;A&:I:;')an A: Rfia1 fi: fi1 ?f ?07R~ 471R 1c A^~' nn.. 10r 414? l' I:;Af'.I:;??1:; ':I, 6684.9 50.9C 208.4{ 4776.8 3716.59~ 1989.07V 0.6 4214.7 441546-:0: 5865161.5- R777 a' fiO 4f ?Oa "II 4R"Ifi 7 o R< 4?RR 7, "H'.^ () I:;A&:l:;naA 7' RR70 4' fiO a: ?ORR( 4Ra4 ::I! o R~ 4::1"R ::II A A. A "7'" "'. I:;A&:l:;n':lf'. ",. 6962.6 50.7C 208.4 4952.5 3904.90~ 2092.83V 0.3 4429.7 441440.9 5864974.0 70fi? 11 fiO R~ ?OR.O' fiooa ?I ?1?fi R7\A 0.4 4400 1, 441407.R I:;A&:Aa1':11 714::1 7' fi?3f 20R.?c fiORRO' ?1 fia.!'\4V 1.Rf 4fi70 ell 441::17::1.?· I:;Af'.LlAI:;O 1 7238.0 53.~ 208.9.1 5122.9 4095.34~ 2195.57V 1.2< 4646.1 441336.7 5864784.3 7::1;:¡0 a~ !'\4 1 ~ ?Oa.Of fi177 R' 41RO.a?~ ?2;:¡1.afiV 07~ 47?1.1 441?aa 01 5864719.01 74nR~ fifi.fif 20Ç.aL fi?::I11' 4?2R.Rfi~ 17: 47QR.RI 4412R2.0< fiRMRfi::l.4 7517.5 57.7( 210.1 5282.8 4294.79~ 2308.55V 2.2E 4875~ 441222.3 5864585.7 7fi7Rfi fiQ 1~ ?OR a, fi::l1::1 7' ?CIA 4a?fi RI I:;A&:"'I:;"',) '), 7RR?Ç fiÇR~ 2111' fi3fi7Rl ??F 1:;0000/ ~ I:;Af'.LlLl7A 1: 7757.4 57.1 209.4 5406.9 4472.44~ 2411.20IA 3.2~ 5080.4 441118.3 5864408.9 7RfiO"-' fiR7fi 20Q7, !'\4fi7 7~ o fir fi1 fiR fi~ AA.n"7n ,., I:;Af'.LI':ILl1 ':I, 7Ç::I2.7~ 55.95 209.Rf fifi03.::I' ooc ~ ~ l' 8015.0( 55.95 209.61 5549.31 4658.95~ 2517.38IA O.OC 5295.1< 441010.8 5864223.2 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Doyon #141 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated y ConocoPhillips ConocoPhitlips Alaslc.,slot #447 Drill Site 2P, Meltwater,North Slope, Alaska weIlP.MWD w/IFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 r'¡. BAKER HUGHES INTEQ Hole Sections Start All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated TUBING (0-7415, 00:4.500, 10:3.958) SURFACE (0-2705, 00:9.625, Wt:40.00) 'ROOUCTION (0-7562, 00:7.000, Wt:26.00) Gas Lift MandrelNalve 1 (7316-7317, SLEEVE (7365-7366, 00:5.500) NIP (7382-7383, 00:5.530) PUP (7415-7430, 00:4.500) LINER (7415-8010, 00:3.500, Wt:9.30) SBE (7446-7447, 00:5.590) BUSHING (7466-7467, 00:5.570) COLLAR (7910-7911, 00:4.000) SHOE (8008-8009, 00:3.50Ql. . .---ra-.. "' I II"!". t ,.. ~í ~ L . f, I'" 11III ~ ~ ':""'!'",§ .. .~ ¡ I:~ þ.~ . -r ~ ID 3.500 3.875 3.813 3.750 3.958 .3.010 .:tOOL 3.000 ~"'I[j"- 4.370 4.250 5.000 4.000 2.990 3.500 2.992 I~o!' ~.. ,~. KBG-2 Bottom :::m:.[: 1 Man Type V Mfr Ref Log Date: TD: Max Hole Angle: - - Size Top 16.000 -.JL 9.625 0 7.000 -0 3.500 7415 DCK Sheared V Type ¡¡¡¡¡¡¡¡IOQ Description CONDUCTOR SURFACE PRODUCTION LINER Øfûblrm$tôí:ìf;ji",TUSIt!lS _.m ;~~eo .....-1 T~P Gäs Lift MandrelsNalves -St"it,ïfD : TVD, Märi--j I Mfr 1, 731S'L316ICAMCO I ' other (plugs. equi·p-., etc.\ .; JEWELRY Dë- th ~_TVD :. -- Type. Description 23 23· HANGER 4.5" FMC GEN V TUBING HANGER WINSCT TOPCONNECTION 502 n"5~nNIP CAMCO 'DB' NIPPLE 7365 Tn?~§.~EËVE BAKER CMU SLIDING SLEEVE 7382 j. 7382 . N!~_ CAMCO 'DB' NIPPLE WINO GO PROFILE 7415 ,7415 PUP 7428 :--7428 ; 'LOCATOR BP.KER.C3:?2 LOCATOR SEAL ASSEMBLY 7429 : 7429 " SEAL BAKER 80:40 S.EAL ASSEMBLY 7466 , 7466. SHOE 1/2 MULE SHOE other (plugs, e.quip.. etc.) 4 De th.L TVD. TyP!!_ 7415 :..741~..PACKER ZXP HR LINER TOP ISOLATION PACKER WfTlE BACK 7434 ' 7434. NIP RS PACKOFF SEAL NIPPLE 743i~.: 7437 'I' HAÑG~R BAKER FLEXLOCK LINER HANGER 7446 7446 SBE BAKER 80-40 PBRISBR 7466. :'-7466-1 BU.SHING XO BUSHING 5" TKC x 3.5" SLHT 7910 . 791q_1 COLLAR BAKER LANDING COLLAR 8008 : 8008 SHOE BOT FLOAT Sê:~~.r..ªi Not~s nn.__ Date Note 1/20/2004 TREE: f::MC I GEN V I TB 15 K 1 TREE CONNECTION: 7" OTIS 1 VOD .0 BK Latch 0.000 Port o TRO Date Run 1/19/2004 Vlv Cmnt + TVD 7415 t Bottom 108 2705 7562 8010 1 Wt 2.60 t TVD 108 2705 7562 8010 Grade L-80 t Wt 62.50 40.00 26.00 9.30 Thread IBT-M l1rade H-40 ! L-80 l L-80 L-80 Thread WELDED BTC BTC-MD SLHT Reference Lo : 28 Last Ta : Last Tag Date: 8010 ftKB Odeg@ Annular Fluid: e: SVC Orig Com letion: Last W/O: . ConocoPhillips Alaska, Inc. . KRU 2P-447 Rev Reason: NEW WELL w/com letion Last Ucdate: 1/28/2004 01/27/04 Scblumbel'ger NO. 3100 Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Well Job# Log Description Date BL Color CD . J<6'-1 '053 J950ô-- ) ~4 'CE:z3 ,~-)~~ 9a> 13 [p Y3'1-)\ \ ~-6« XB- )5.3 'PCì?) -cr:¡ \ 2A-04 10709682 INJECTION PROFILE 12/27/03 1 2T -28 10709867 STATIC SURVEY 01115/04 1 2A-04 10709691 RST 01/19/04 1 2K-01 10696828 LDL 01/14/04 1 1D-140 10696827 LDL 01/13/04 1 3H-03 10709688 PRODUCTION PROFILE 01/16/04 1 2P-447 10696819 SCMT 01104/04 1 2P-434 10709667 USIT/CBL 12/02/03 , 1 2P-432 - 10696818 PERF RECORD & SBHP 01/03/04 1 .- ',' ['..!: · _.!".,.I V ..:: L.I . ~~" "--~ SIGNED:'~~ \ ~J. /'\1,--:\--') \. () C't ~ r- /v"- - . J/\ì'! ~j C 2004 l\t3$ka 011 & Gas Cons. CommØlloo Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. A,¡¡r,homge DATE: -.-< -- c' \)~~ ,f",,, ,~ CônoeJ'ftmips . Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Fax: (907) 265-1535 Email: randy.l.thomas@conocophillips.com January 12, 2004 Alaska Oil and Gas Conservation Commission 333 West yth Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 Re: Application for Sundry Approval to return to well 2P-447 and complete the well as a 4 W' injector Dear Sir / Madam: ConocoPhillips Alaska, Inc. hereby files this Application for Sundry Approval to return to we1l2P-447 and complete the well as a 4 W' injector. After running a USIT log in the 7" intermediate casing and an SCMT log in the 3 W' liner it has been determined, in consultation with the commission, that sufficient isolation exists for the interval to be used for injection. It is therefore our intention to return to this well as soon as operations on 2P-424A are concluded and complete the well as a 4 W' injector. Please note that the original application for a Permit to Drill called for a 3 W' injector but as the reservoir quality and thickness in this well have surpassed expectations ConocoPhillips plan to run a 4 W' completion. If you have any questions or require any further information, please contact Philip Hayden at 265-6481. Sincerely, .~ ' ' \~~ Randy Thomas GKA Drilling Team Leader RECEIVED JAN 1 3 2004 Alaska Oil & Gas Cons. Commission Anchorage OR\GiNAl · STATE OF ALASKA . ALASKA Oil AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL kilL\, f7i:~ II t 4tlJ 1 20 AAC 25.280 7f I( (.¡Iv 1. Type of Request: Abandon D Suspend D Operational shutdown D Perforate D Variance D Annular bis~~.D Alter casing D Repair well D Plug Perforations D Stimulate D Time Extension D Other D Change approved program D Pull Tubing D Perforate New Pool D Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development D Exploratory D 203-154 3. Address: Stratigraphic D Service 0 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20468-00 7. KB Elevation (ft): 9. Well Name and Number: 28' RKB, 252' AMSL 2P-447 8. Property Designation: 10. Field/Pools(s): ADL 373112/389058/ L 32092/32409 Kuparuk River Field / Meltwater Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (It): Effective Depth TVD (ft): Plugs (measured) Junk (measured): 8015 5549 7910 5491 Casing Length Size MD rvD Burst Collapse Structural Conductor 80' 16" 108 108 Surface 2677 9.625" 2705 2317 5750 3090 Intermediate 7534 7" 7562 5306 7240 5320 Production Liner 601 31/2" 8010 5546 10160 10530 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Packers and SSSV MD (ft): 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program D BOP Sketch D Exploratory D Development D Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 1/15/2004 Oil D Gas D Plugged D Abandoned D 16. Verbal Approval: Date: WAG 0 GINJD WINJD WDSPL D Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Philip Havden @ 265-6481 Printed Name R. Thomas Title Kuparuk Team Leader Signature ~~,~- W~·~_~ Phone 265-6830 Date \ / t ê. /0 ':r 1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Mechanical Integrity Test~ 304 -tJ!ò Plug IntegrityD BOP Test D Location Clearance D RECEIVED Other: JAN 1 3 2004 Subsequent Form Required: \...\0 '\ v.J~ "~E..\.\' '1::) ~-\~ Ca ~ K)t'V\.Ct \Alaska Oil & Gas Cnns. Commission ((. I. '") ~ \)o.-\~ Anchorage BY ORDER OF Datei% If ~r Approved by: COMMISSIONER THE COMMISSION f ....BFl ,.lQ2M ORIGIN{~ SUBMIT IN DUPLICATE Form 10-403 Revised 2/2003 Re: 2P-447 (203-154) Future plans . . Subject: Rc: 2P-447 (203-154) Future plans From: Thomas Maunder <tom_maundcr@.admin.state.ak.us> Date: Fri, 09 Jan 2004 14:40:48 -0900 To: "Hayden, Philip" <Philip.Hayden@conocophillips.com> CC: "Jackson, Darron B." <darron.b.jackson@conocophillips.com>, "Schwartz, Guy L" <Guy.L.Schwartz@conocoph11lips.com> Philip, et al: I confirm our meeting to examine the multiple bond logs from 2P-447 (203-154). Based on our examination of the bond logs, it does not appear that any benefit could be gained with remedial actions in the 7". It appears that there is cement there, although it is likely contaminated. The bond log of the 3-1/2" liner does look very good. when the 0 pressure pass is compared with the 1000 psi pass, there is essentially no difference. The liner does appear well isolated. I agree with your point 4 that no remedial work is necessary prior to completing the well. Tom Maunder, PE AOGCC Hayden, Philip wrote: Tom, With reference to our meeting this afternoon concerning future plans for the currently suspended well 2P-447 I would like to summaries as follows: 1. The second USIT run in the 7" shows some more developed bonding, albeit of poor quality, of cement and pipe. It is our opinion that a squeeze operation here would be unsuccessful. 2. The cement bond as measured by the SCMT in the 3 1/2" liner is excellent and covers the interval from the top of the reservoir to the 7" casing - a distance of approximately 34 ft MD. 3. We feel that the 34 ft of excellent bond in the 3 1/2" provides adequate isolation of the injection interval and that remedial work on the 7" would not improve on this due to its low chance of success. 4. We propose, after submitting the relevant Sundry Notice to complete this well without any remedial work. If you have any questions or comments please let me know. Regards Philip lof2 1/14/2004 10:19 AM RE: 2P-447 Suspended . . Subject: RE: 2P-447 Suspended From: "Lowry, Scott L" <Scott.L.Lowry@conocophillips.com> Date: Tue, 30 Dec 2003 10:48:36 -0900 To: "I Jowry, Scott L" <Scott.L.Lowry(4{conocophillips.com>, tom _ maunderØ~adl11in.state.ak.us, winton_ aubert(@admin.state.ak.us CC: "Brockw'ay, Thomas A" <Thomas.A.ßrockway@conocophillips.com>, "Thomas, Randy L" <Randy.L.ThomasC?.Ðconocophil1ips.com>, "Hayden, Philip" <Philip.Hayden@conocophillips.cOJl1>, "Schwartz, Guy L" <Guy .L.Schwartz@conocophillips.com> There was one more mistake on the formation tops. Sorry for the inconvenience. «Visio-2P-447 Suspended Well Schematic.jpg» -----Original Message----- From: Lowry, Scott L Sent: Tuesday, December 30, 2003 9:57 AM To: 'tom maunder@admin.state.ak.us' ¡ 'winton aubert@admin.state.ak.us' ..........-..-...------.......-.................................-----.....-.....-....-.........-.--.....----.......................... Cc: Brockway, Thomas A¡ Thomas, Randy L¡ Hayden, Philip¡ Schwartz, Guy L Subject: FW: 2P-447 Suspended Tom, The schematic had some incorrect depths on it. Please see the corrected version attached. The sundry application was sent over last night for the well suspension. Please replace the existing schematic with the corrected version. Sorry Winton, I should have included you in the original response yesterday. Thanks, Scott Lowry « File: Visio-2P-447 Suspended Well Schematic.jpg » -----Original Message----- From: Lowry, Scott L Sent: Monday, December 29, 2003 4:39 PM To: Cc: Brockway, Thomas A¡ Thomas, Randy L¡ Hayden, Philip¡ Schwartz, Guy L Subject: 2P-447 Suspended Tom, lof6 1/512004 11 :29 AM RE: 2P-447 Suspended . . I answered the questions below. The sundry application will be over tomorrow. Attached is a schematic of the well as it sits today. Call if you have questions. Thanks, Scott Hi Scott, How did the cement look. Did any get above the Cairn?? What about the cement up high?? Our initial interpretation of the bond log is that inadequate cement bonding exists in the confining zone and above the Cairn. I included a pick for the Cairn formation top, but the Cairn is poorly developed in this well. I think we will run another bond log prior to commencing remedial work to make sure cement did not set up after the first bond log. We came up into cased hole and started to see better bonding inside the surface casing shoe. We are reviewing our inputs for the USIT log since we were logging two different densities of slurries. >From the bond log you can see cement from ± 4100' MD to 7100' MD which indicates cement probably went south during the 2nd stage of the cement job. Since most of the phase II development team is on vacation this week (including Philip Hayden), we will convene next week to finalize a plan forward. My observation of 2P-447 is that it had more complications than any well so far drilled at Meltwater. Is that correct?? I don't know if that's completely true. We used all of our contingency casing strings on 2P-432 (the first well in phase II) The Phase III weather conditions contributed 65% of our total trouble time thus far. After experiencing shallow pressured gas, we wanted to scratch the top of the Bermuda sand in the intermediate interval, but the sand came in 30-35'TVD higher than expected. This resulted in us exposing more of the Bermuda sand than we wanted. We set 7" casing 60' off bottom to leave all of the pay in the production hole. We drilled good cement in the rathole when we drilled out, which indicates cement was likely going into the Bermuda while cementing. Where (in depth) did the losses begin?? Were losses incurred with the Cairn open prior to cutting the Bermuda?? I seem to remember that you successfully got below the Cairn but that the further problems came up as the well was prepared to drill deeper into the Bermuda. Is 20f6 1/512004 11 :29 AM RE: 2P-447 Suspended . . fhat correct?? Losses began up around 2800'-2900' MD. Losses did occur with the Cairn open prior to cutting the Bermuda, but losses were occurring prior to drilling the Cairn. I don't believe the Cairn was a factor on this well since it wasn't well developed geologically. For 2P-424, does it make sense to look to set the 7" between the Cairn and Bermuda?? I know that is dependant on what the well tells you as various zones are penetrated, but in the wells so far on this campaign it appears that having Cairn and Bermuda open in the same wellbore section has led to problems. On 2P-434 we scratched the top of the Bermuda with the Cairn interval open in the intermediate hole. We ran and cemented the 7" casing with minimal mud losses. We had some gas in the production interval below (Bermuda), but nothing of any signifigance. On 2P-432 we set 7" casing below the Cairn, but encountered another gas streak below the 7" shoe that required higher mud weight to control. We scratched the top of the Bermuda and ran and cemented a 5 1/2" liner with manageable losses (losses tend to occur toward the base of the Bermuda). Then we drilled 4 3/4" hole and set a 3 1/2" liner. This well required us to use all of our contingencies to get it down. If we just scratch the top of the Bermuda we have had reasonably good luck cementing the casing/liner string with higher mud weights. If we get deeper into the Bermuda (or all the way through it), the mud losses increase with the higher mud weights. In a normally pressured area, we should be able to drill the well to TD in the 8 1/2" hole. I believe our approach of scratching the top of the Bermuda interval prior to setting intermediate casing is fine (when high mud weight is required). We just need to make sure we don't drill too deep into the zone by stopping sooner to let the mud loggers check samples and confer with the geologist. The 2P-424 is the first well to penetrate the southeastern quadrant of the reservoir and pressures are predicted to be normal in this area. This is my observation, I'd appreciate your thoughts. Tom Maunder, PE 30f6 1/5/2004 11 :29 AM y ConocoPhillips ConocoPhimps Alasklc.,sIO! #447 Drill Site 2P, Meltwater,North Slope, Alaska d-CJ3 -. )5'i wellPaaWD w/IFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 "~i. BAKER HUGHES INTEQ I~Jlbo..e 447 I Created 7 -Dec-2003 I Last Revised 29-Dec-2003 IWèll ~~ I ~g-~~~~~~~~OO I ~~~b=:~~~~ Slot Name I 47 Installation 441964.238 5869891.466 AK4 on NORTH AMERICAN DATUM 1927 datum True Drill Site 2P I Fiéld ~'œ' I Eastina I Northina 441964238 I~=~ 1-- I 58698~:= · ··(R · . FRICAN DATI,:"" d~:t< ·i. ... Tme I HI ? 0 ,)f\I\4 ....,;~t ....u '-w '\f.j{~& Gas Cons. Comn1iion All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Doyon #141 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated "'K\::;~\\\ ~ y ConocoPhillips ConocoPhm;ps Alaslco,s,ol #447 Drill Site 2P, Meltwater,North Slope, Alaska weIlP&WD w/IFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 "i. BAKER HUGHES INTEQ WellDathtGrid' Report MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing dea/100ftl Sectionrftl GO( GGr GGr 0.0( n 00" o oo~ OGr 0.0( . a 10A OJ o Of O.OC 108.0f 000" o OO~ o or OO! . a 302.6 0.91 251.11 302.6 0.50~ 1.461/1 0.4 1.1! 443560.9 5868862.4 <\a4 "I' G.Af 238.7' 394.3 1 oa~ ? 74\A 0.2~ 22! '>ARAAR1 A 4A"I1 ? a./l 221.6: 483.0. <\ 14~ 4 A?\A ? 4r '>O( , ° 573.9 6.87 215.6 573.51 9.29~ 9.541/1 4.3E 12.71 443552.7 5868853.7 I;M<\I 9.2] 217.51 663.0. 1C1 41;! 171411I ?¡;OJ 25.3, 44<\'>4'> 1 I:;"A"ALI<\ I:; 7<;'> ?' CI.<\7 ?17.7 752.7: <\1.1?' 2R.1<\1II o 11 <\CI.CI 44<\'>"IR 0. 845.& 8.99 214.6 841.81 42.73~ 34.641J1 0.6f 54.1! 443527.4 5868820.4 a<\"I4 10 ?1 213.3: 928.5, <;4 ACI! 4? A<\\A 1.41 68.81 443519.1 '>. 10?,>.nl 1? 4./1 ?nR.1 1n1R <\1 7G<\R! '>1.Cl4\A 2.Rf RR 71 443'>nCl CI 1122.4 16.5€ 2062 1112.5 92.09 63.041/1 4.2E 111.1 443498.6 5868771.3 1?1R 1 1 CI R7 ?n7 4~ 1203.5! 11R R4~ 7R '>?\A 3 ?' 140. Rf 4''>,00<:.'' ~n~n~ n' 1<\10.4 ?n RÇ 2G8.R' 1290..1 146R4~ 91.621/1 1.4 172.RI 443469.7 1402.7 24.3P 208.21 1375.2 178.03~ 108.58\1\ 3.7~ 208.3 443452.5 5868685.7 14C1R ?, ?ClH ?nR '>, 14'>R 71 21'> nR~ . '>0 ,,,.. '> l' ?,>n '>! 4434<\? 1 1 '>RQ O! <\? 7~ ?G7'>' 1'>383< ?<;7 ?1C 1'>1.061/1 3RI 29R? 1681.9 35,0 208.91 1615.5 302.82~ 175.581/1 2.6 349.9! 443384.5 5868561.4 177'> 3< 3R 71 ?nCl R~ 1RCl1 1 <\'>G'>1~ ?n?3RI/I 1 RI 4G46f LlLI<\<\1:;7 LI 1RR79: 399f 20.971 17631' ~<\A~ ?<\o A?III 3'>1 46211 AA'>'>'>o "- "n~nA"'A '" 1960.S. 42.4f 209.7 1833.4 453.36~ 261.091J1 2.7 523.1 443297.9 5868411.5 ?O<;4 11 44 R7 ?nCl 1 190.1 n! ,>nQR4~ ?CI?R?V ? ,>ç '>A77: 44",,?AI:; " ?14'>7' 4R Rr 2GRR: 19R49: ~11;~ <\?4 RAV ?1: 65341 44<\?<\<\ <; 2239.3 49.0f 208.9( 2027.6 628.01~ 358.23V 2.41 722.91 443199.5 5868237.6 ?<\<\? 4 '>0. ?! ?nRR: ?GR7Q: RClG 19~ <\CI?35V 1 <\r 793Æ 44<\1M a 5R6R175.7 ?4?561 50.61 2G85! 21472: ~?7~ 426.72V 0..4':: 865.7: 4431301. 2517.3 52.31 208.3! 2204.3 816.39' 460.95V 1.8C 937.5 443095.4 5868050.0 ?ROQ CI: '>3.1 ?nR.?! ??RG4 RR124~ 4C1'>.R6V 0. Cl1 10.11.1 44<\01;00 5R67985.4 ?R4?O: 534! 2G8G~ 2279.6: om: a?! <:,,7 ami OBI 1036.A 4430477 2783.2 53.61 208.5! 2363.5 1003.90 561.89V 0.3E 1150.4 442993.1 5867863.3 ?R7R '>: '><\ ?I ?GR?: 24191 ,n,n n~, '>Q757V G5! 12254. 44 ?a<;1; a ?9R9.4: 5261 208.01 2475.0: "-"''>1:;,,-'' On..:: 1299,5 44?a?1 <; 3061.9 52.11 208.31 2531.4 1199.83 667.22V 0.6C 1372.8 442886.3 5867668.1 <\1'>R1, 51Af 2G83! 25A9.3: 70? <;?V 0.2: 1447.11 44?A<;O <; <:0"'''''''''' n <\?4a 0, <;1 I;~ 207.9: 2646.71 '~n lIHV o 4f 1'>?O 1 44?R1'> R <:0"-"<:"0 3341.9 51.41 207.8 2704.5 1393.92 770.981J1 0.29 1592.9 442781.1 5867474.8 ':tð.':tð.4' <;1 1. 207.6] 2762.4 onA I:;AI~ o <\? 1RR'> 0: 442747.1 '>RR7411 3 "I'>?7 '>~ '>1 1< ?n7 oc ?R?n R! 11:;?? 1A' R<\7 Cl11/1 0. 4f 17<\7 '>~ 44?713 3 <;¡¡1;7':tð.71 3619.5 50.8C 207.3 2878.7 1585.69~ 870.621/1 0.4.:: 1808.9 442680.1 5867283.8 <\714 ?! '>1 '>f 207.4( 2938.1: 1R'>1 1<\! Cl04.'><\1/I 0.7 1 RR? RI 44?R4'> 7 <;¡¡1;7? 1" 7 <\RO'> RI '>1 '>! ?nR?! ?995 0.1 1714.44! CI<\79AI/I 0. 7f 19<;41! 44?R11 R 5AR7155.6, 3899.1( 51.2 207.8 3053.3 1778.87 972.321/1 0.5 2027.1 442577.0 5867091.4 "IClClO 41 '>04f ?n7 Rf 3111.01 18414R! 1""<: "'01. n.R~ ?nCl7.CI 44?<;4<\.4 <;AI;70?a 1 4nA 1 R: 51 7~ ?G811 316A.3: Ann n.. 1wlxf'lV' 1.3] 216901 44250.9 7 l:;oA,,-a,,-,,-,,- 4176.4 52.8<1 207.3 3226.3 1970.61~ 1073.581J1 1.3' 2243.9 442474.3 5866900.5 4 ?RCI CI, '>? 1< ?nR3 3283.2: 110.81'>1/1 1 1 ?31R.n~ 44?4<\CI.? 5A66A35.2' 4<\R? CI! '>1 3: ?nR 1 3340. A< 0. Rf 23910.1 5866771.1. 4455.0 50.4.11 207.8~ 3398.9 2163.59~ 1176.18V OÆ 2462.4 442370.3 5866708.3 4<;4A 41 '>0 CI' ?n7 RI <\4'>R 1: 0. '>: ?'>34 7 LILI ?<\<\I; 1 <:0"-"-"-,0,0 1;. 4R41 4: '>1 1f ?nR ClI 35165' ??a1 7?' 0. 7: 2RG7G: ,7 4733.9 51.4~ 208.6 3574.4 2355.64~ 1276.89V 1.4 2679.2 442268.2 5866517.0. All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Doyon #141252.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated Conoc~illips ConocoPh;tlips AlasJc.,slot #447 Drill Site 2P, Meltwater,North Slope, Alaska wellPaaWD wllFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 "~i. BAKER HUGHES INTEQ WellDathlGrid' ReDort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing dea/100ftl Sectionlftl 4R?R 4' <;1 Q" ?1 0 R~ 'IR'I17' 'JA1R 7~' 17P ?7<;1 Ri AA'J'J':I1 R, ~^^^ . ~. l' 4Q1R'I' <;17d ?OQ O~ 'IRRR <; ?4R 1 4<;~ 1 'IF ?R?4 1: '^.,^~ ~^^^^^. 71 5012.0 51.51 208.9C 3746.6 2545,66 1384.29V 0.2E 2897.5 442159.4 5866327.8- <;10<; OJ <;? 0" ?07 Qf 'IRM ?I 'J~na a':l' o Q7 ?Q70 n AA'J1'JA 11 ~^^^^. '^ R, <;1QR 1: <;1 Q~ ?07 ?~ 'IRR1 <;: 'J~7 A an' OR' 'IM'I QI 1: 5291.3 51.6 207.2 3919.1 2740.04 1486.57V 0.2E 3117.1 442055.7 5866134.2 <;'IR'I QI <;? 4~ ?07 <;f 'IQ7R 1 'JRnA R7' o R7 'I1QO 1 44?0?1 R: ~^^^^^^ ~. <;47R.7 "2.4F 207.2 40'l2.RI 2R70.1 ,,~ 1 "<;4.021,' O.'IC 'I?R'I.RI 441QR7'11 "RRR004.R! 5569.7 51.7~ 207.2~ 4089.8 2935.45 1587.64V 0.7 3337.0 441953.2 5865939.6 "RR? ,,: "1 1F ?071r 4147 ,,! ':Innn n'J' 1 R?O 7RV O.RÇ 'I40Q ,,! 441Q1Q."i "RR"R7"?! "7"".3: "1.RÇ 207.3f 420".4 'IOR4 C;1 O.R~ 34R20! 441RR"Q "RR"R110! 5848.6 52.2 207.5 4262.9 3129.76 1687.881,' 0.5~ 3555.5 441851.5 5865746.0 "Q41ßI "1.Rd 2074: 4320.11 "I1QA Rn' 1721 701,' 0.4 3R21\.R: 441R17.2. ~n~~~n. ?I 6032S 51.1Ç 207.7f 4376.71 'I?C;7 RR! ."7r "0" 0.7E 3699.9! 441783.81 A' 6125.8 51.8" 207.0 4434.71 3322.65 1788.27V 0.94 3772.9 441749.7 5865553.9- R2170! "3"1 20R"f 44QO 1( "I"IR7 AC;' 1R?1 nmJ 1R7 3R4"4. ~n~~ .n^ "IJ 6312.2: 53.0d 206.0: 4546.9! "14<;<; R l' 1 R<;4 7RIJ 0.67 3921."! ?I 6403.9 52.4~ 206.9 4602.5 3521.19 1887.35V 0.9~ 3994.5 441649.1 5865356.1 ß4Q7.0( "1Qf 20R.Q~ 46"Q.4! ':I¡::R~ 7':1' 0"7 40RR.0. AA1"": ':I, rn"rn^^ Ri 6591.5: 51.2f 207.8~ 4718.1! 'IRC;? C;1! ."rA 0'''' 1.0C 4142.1 ':II 6684.9 50.9C 208.4f 4776.8 3716.59 1989.07V 0.6 4214.7 441546.0 5865161.5- R777Q! "O.M 20Q.3( 4R3".71 O.R~ 42RR7. ¡::"~¡::na" 7' 6870.4! 50.9: 208.8e 4894.3! 'IR4? ?<I! 0.6d 4358.31 ¡::R~¡::n':l~ A' 6962.6 50.7C 208.4 4952.5 3904.90 2092.83V 0.3 4429.7 441440.9 5864974.0 70"2.11 50.8f 208.0: 5009.2( .",,,,, ^n' 0.4 44QQ.1 "864913.1 7143.7' 52.3f 208.2~ 5066.0: 4029.3m 2159.54V 1.6E 4570.91 ¡::R~AR¡::n 1 7238.0 53.44 208.9 5122.9( 4095.34 2195.57V 1.2E 4646.1 441336.7 5864784.3 7330.9~ 54.1d 209.Of 5177.8' 4160.92~ 2231.95V 0.7f 4721.1 "864719.01 7423.6: 55.5f 209.9¿ 5231.1' 4226.85~ 2269.27V 1.7 4796.8i 441262.0! A' 7517.5 57.7C 210.1 5282.8 4294.79 2308.55V 2.2E 4875.3- 441222.3 5864585.7 7576.51 59.1~ 208.9] 5313.7 4'1'1R C;O! 2.94 4925.61 ?I 7RR? Q <;QR~ ?11 11 "'1<;7 RI AAn'J a'J' ? ?P <;00001 111rn 1 : 7757.4 57.1" 209.4 5406.9 4472.44 2411.20V 3.2~ 5080.4 441118.3 5864408.9 7850.5< 56.7E 209.7] <;4<;7 7' A¡::An 'JR' 0.5C 5158.5: ,.n"7n" ':I, 7Q'I? 7~ <;<; Qf ?OQ R~ <;<;0'1 'I: A<;QQ 7A' o QÇ <;??RQ' AA1nAA Q, l' 8015.0 55.9E 209.6~ 5549.3 4658,95 2517.38V O.OC 5295.1 441010.8 5864223.2 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Doyon #141 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated y ConocoPhillips ConocoPh;U;ps Alaslc.,slot #447 Drill Site 2P, Meltwater,North Slope, Alaska weIlP.MWD w/IFR+MC+Sag<0-2642'>MC+Sag<2783 - 8015'> Date Printed: 22-Jan-2004 "~i. BAKER HUGHES INTEQ Hole Sections Start All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 252.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 209.14 degrees Bottom hole distance is 5295.56 Feet on azimuth 208.38 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . ConocoPhilUps Alaska, Inc. 2P-447 ru:J'NG W·/":1!i, oa.4 ~O(), ID 3 ¡¡56) SI.J~FAC= o~~: ~~~: \"It.t.o.om >qODUCTlO"J ~O-75()2. OD:7.000. W!:26.00) Gas lift-· \1andrul!Val\K! 1 (l3I1i-7317. 5L; I VE ,.?:InS-73m;. OD" 5 500) ""P--" ;?:I8~ I~!ö:" on ~: ~):j(i) P;JP ..74·5-74:~O. OJ to. ~(~O! IINr;.~-- 1,7.c11!IB010. OJ:! !i':=O. W~:H :10, SBE (7446-7447, OD:S.S90) BUSHING (7466-7467, OD:S.S70) COLLAR .. --. (7910-7911, OD:4.000) SHOE (8008-8009, 00:3.500 KRU 2P-447 I API: ~ 501932046800 . W~II.T.Y~: i SVç_....._. ....~..__~@.T..§~ ,deg@..____.; , -SSSV Type: i NIPP·LE------j . . Orig Angle@TD:deg@ [ f COI'!1P!~~..n I =Ã.~:nUléJr Fluid: :. - -- n: La~t.~/O: ! __...... ... _...I Rev Re~s~ñ: ¡ ~~:~~I~~;n :.. Ref~r.~nce Log: 28 . __~. Ref Lqg..!:?ate: ._ _ _ j___ ..Last UpdéJt~: 1128/2004.._ _~_~~!.:rag:. ..__.... __ . .n?:...!!010 ftKB____ . ... : .... _ __ Last Tag DéJte~!_...__..... . ~ Max I-!qle Angl~.:..:...Q_p~g @ _... __ .__ _ ..... _____.. ~ C~I?[I,g String - AJJ. .~TRINGS i Descrip!i9~ .. . . _.. Size Top.. .'__" Bottom _J. TVD' . I Wt . Gr.~d.~ ¡..... Thread r ...__ç~~~~~¿~Bn.. ......1 ~~60205Q-=r--~· .._: 2;0~5~2.!79ö85'" ':__X~J~ '-l~:g t-~~~ED PROPY.ÇTION ! ....7.000 :. .-....Q..........J... 7562 7562! 26.00 L~8q... BTC~~D LINER 3.500 7415 .I!.o_10 i 801()_....I. '9.39 __ L-80 SLHT ·TUb¡rjï~s~z~ng.~...TP."ØJ-~l?~p. . I' -~~itom" ....=.~:..- TVD I-'.~ Wt....·..~..--Gr~.c;I~ I Thread _...._ 4:~00.... ¡ . ....0 _____: 7415 : -..- 74J.~. r 12:~0 I L-80 ___, .. .I!3...I:M.........__... 'Gas Lift MandrelsNalves S~MD TVD 'I' NÎã'n ! Man Type' v Mfr "'~-V Type ¡'rOD I Latch fpOrtTi'R'Ö; Date" Vlv , i Mfr. -- - I - ¡ Run .çmnt f_~~1:.3.16ICAMCOL.KBG-2 L_n___ l'~-~~~ed !'-'fo _;.._..~K :--O~~~.~ 0 í"1/1~~2~04: ........ _Other (plugl!.~Q.uip.. etc.) - -!EWELRX _.....__ ....... _..___ ..... .n.. __ ~~~:~ ~ ~~ . !:i;~~t~CnG~N V 1\J.siÑG HAN~~~~~~~~T .!..bPCONNECTIQ~_·I":--3.~0 502 i 502 ~ NIP CAMCO 'DB' NIPPLE 3.875 '7365' I 73651 SLEËVË BAKEï~CMU SLlDING--SLEEVE' . . . . . ---3.813 ~-~¡~rT ~¡~~ :""''' ~~ ·ICA~Ç():'Öi3' NIPPLE..W/NO GO PROFILE -...__~__:...----..:_.~:~~~ 7428 . 7428 LOCATOR, BAKER G-22 LOCATOR SEAL ASSEMBLY 'I 3.010 7429 I 7429: SEAL BAKER 80-40 SEAL ASSEMBLY 3.000 . 7466 i 7466 ¡SHOE 112 MULE SHOE ' 3.000 : Other (plugs, equip., etc.) - LINER JEWELRY . lPepth: TVD! TyP!!_...........:...___........ . .__--º_escription ......______ I 7415 7415 PACKER iZXP HR LINER TOP ISOLATION PACKER WtTlE BACK 7434n 7434 - NIP i RS PACKõ"FFSEAL NIPPLE .-..... 7437 7437 t IÃNGER fBAKER FLEX LOCK LiNER HANGER n____ 744(_:..J~~~. SBE . BAKä(80-40 EB.RISBR .---.-. .____... . ·----~~__m 7466 7466 BUSHING XO BUSHING 5" TKC x 3.5" SLHT 791.Q__"Z.~10 CÒLLAR. BAKE.8 LAND.I..r~JG COLLAR - -: n._n.__ 8008 : 8008 SHOE BOT FLOAT SHOE 13enerai Notes'" .... -------- . ··-·-··-bate ...~ Not~. . . .___ __" . .. ...-...--. 1í20/2004 TREE: FMC I GEN V I TB I 5 K ___ TREE CONNECTION: 7" OJIS __.. . JP 4.370 4.250 , 5.000 ! '(ÖÕO i 2.990 -----. 1"3.500' -_.'.:-~-'....~?.. ----. .-----...... -.-- J<fY/ '053 J95V1ô-- ) 'öLf 'C83 ,~- ;';;¡d-. jLO' )3 ~ ~ '3'1- \I ~- \S~ gig- )53 :Po~--Cr:1 \ 01/27/04 SChl!umbepgep NO. 3100 Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Well Color . Job# Date BL CD Log Description 2A-04 10709682 INJECTION PROFILE 12/27103 1 2T -28 10709867 STATIC SURVEY 01/15/04 1 2A-04 10709691 RST 01/19/04 1 2K-01 10696828 LDL 01/14/04 1 10-140 10696827 LDL 01/13/04 1 3H-03 10709688 PRODUCTION PROFILE 01/16/04 1 IP-447 10696819 SCMT 01/04/04 1 2P-434 10709667 USIT/CBL 12/02/03 1 2P-432 10696818 PERF RECORD & SBHP 01/03/04 1 -~r-n j~r~.. " I"'( r::\~"")!.j.,,~ ,I . ~ '~, SIGNED: ,.~ \ 'ì...J.. /,\/,-'\~ \. () ú"'t ~ C" "'/""\. "- . ! ^ ~ ¡ -.. (, "004 ..J;~\' d·' L. l\l8$ka Oil & Gas Cons. Commi'ftOO Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. AJ\morage DATE: -~-~ ~-- ,~." ~ CÐhôcri'PTu11ipS . Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Fax: (907) 265-1535 Email: randy.l.thomas@conocophillips.com January 12, 2004 Alaska Oil and Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 Re: Application for Sundry Approval to return to well 2P-447 and complete the well as a 4 }2" injector Dear Sir I Madam: ConocoPhillips Alaska, Inc. hereby files this Application for Sundry Approval to return to well 2P-447 and complete the well as a 4 }2" injector. After running a USIT log in the 7" intermediate casing and an SCMT log in the 3 }2" liner it has been determined, in consultation with the commission, that sufficient isolation exists for the interval to be used for injection. It is therefore our intention to return to this well as soon as operations on 2P-424A are concluded and complete the well as a 4 Y2" injector. Please note that the original application for a Permit to Drill called for a 3 }2" injector but as the reservoir quality and thickness in this well have surpassed expectations ConocoPhillips plan to run a 4 }2" completion. If you have any questions or require any further information, please contact Philip Hayden at 265-6481. Sincerely, ·T~~- , ~ Randy Thomas GKA Drilling Team Leader ~ RECEIVED JAN 1 3 2004 Alaska Oil & Gas Cons. Commíssiol1 Anchorage OR\GiNAl · STATE OF ALASKA . ALASKA Oil AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL Áh,-\ ø;~ II t 4J/j; 1 20 AAC 25.280 7f ¡({{/V 1. Type of Request: Abandon 0 Suspend 0 Operational shutdown 0 Perforate 0 Variance 0 Annular bisp~~.D Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Other 0 Change approved program 0 Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development 0 Exploratory 0 203-154 3. Address; Stratigraphic 0 Service 0 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20468-00 7. KB Elevation (ft): 9. Well Name and Number: 28' RKB, 252' AMSL 2P-447 8. Property Designation: 10. Field/Pools(s): ADL 373112/389058 / L 32092/32409 Kuparuk River Field / Meltwater Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (It): Effective Depth TVD (ft): Plugs (measured) Junk (measured): 8015 5549 7910 5491 Casing Length Size MD rvD Burst Collapse Structural Conductor 80' 16" 108 108 Surface 2677 9.625" 2705 2317 5750 3090 Intermediate 7534 7" 7562 5306 7240 5320 Production Liner 601 31/2" 8010 5546 10160 10530 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Packers and SSSV MD (ft): 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 1/15/2004 Oil 0 Gas 0 Plugged 0 Abandoned 0 16. Verbal Approval: Date: WAG 0 GINJD WINJ 0 WDSPL 0 Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Philic Havden @ 265-6481 Printed Name R. Thomas Title Kuparuk Team Leader Signature t ~ Phone 265-6830 Date ( It '2./0 'r - \ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Mechanical Integrity T estR 3D4 -tJIO Plug IntegrityD BOP Test 0 Location Clearance 0 RECEIVED Other: JAN 1 3 2004 Subsequent Form Required: L..\Q '\ v.J"'((,"~E.\\ t ~~ ~\~ G~ H:)t''''-C.t \Alaska Oil & Gas Cons. Commission ":> ~ ~ Anchorage BY ORDER OF Dateð//;rÞr Approved by: COMMISSIONER THE COMMISSION r _BfL ,"1~ 2. ORIGINß: SUBMIT IN DUPLICATE Form 10-403 Revised 2/2003 Re: 2P-447 (203-154) Future plans . . Subject: Re: 2P-447 (203-154) Future plans From: Thomas Maunder <tom_maullder@admill.state.ak.us> Date: Fri, 09 Jan 2004 14:40:48 -0900 To: "I-layden, Philip" <Philip.I-Iayden@collocophil1ips.com> CC: "Jackson, Darron B." <darron.b.jackson@conocophillips.com>, "Schwartz, Guy L" <Guy.L.Schwartz(q)conocophillips.com> Philip, et al: I confirm our meeting to examine the multiple bond logs from 2P-447 (203-154). Based on our examination of the bond logs, it does not appear that any benefit could be gained with remedial actions in the 7". It appears that there is cement there, although it is likely contaminated. The bond log of the 3-1/2" liner does look very good. When the 0 pressure pass is compared with the 1000 psi pass, there is essentially no difference. The liner does appear well isolated. I agree with your point 4 that no remedial work is necessary prior to completing the well. Tom Maunder, PE AOGCC Hayden, Philip wrote: Tom, With reference to our meeting this afternoon concerning future plans for the currently suspended well 2P-447 I would like to summaries as follows: 1. The second USIT run in the 7" shows some more developed bonding, albeit of poor quality, of cement and pipe. It is our opinion that a squeeze operation here would be unsuccessful. 2. The cement bond as measured by the SCMT in the 3 1/2" liner is excellent and covers the interval from the top of the reservoir to the 7" casing - a distance of approximately 34 ft MD. 3. We feel that the 34 ft of excellent bond in the 3 1/2" provides adequate isolation of the injection interval and that remedial work on the 7" would not improve on this due to its low chance of success. 4. We propose, after submitting the relevant Sundry Notice to complete this well without any remedial work. If you have any questions or comments please let me know. Regards Philip 10f2 1/14/2004 10:19 AM RE: 2P-447 Suspended . . Subject: RE: 2P-447 Suspcnded From: "Lo\vry, Scott I J" <Scott. L. Lowry~þconocoph ill ips.com> ])~lte: Tue, 30 Dee 2003 10:48:36 -0900 To: "Lowry, SeottL" <Scott.L.Lowry@).conocophillips.com>, tom_ maundcr@?admin.state.ak.us, winton _ aubert@dadmin.statc.ak.us CC: "Broek\vay, Thomas A" <Thomas.A.Brockway@}eonocophillips.com>, "Thomas, Randy L" <Randy.L.Thomas(~)conocophjllips.eom>, "Hayden, Philip" <Philip.Hayden@).conoeophil1ips.eom>, "Schwartz, Guy L" <Guy. L.Schwartz@conoeophil1ips.com> There was one more mistake on the formation tops. Sorry for the inconvenience. «visio-2P-447 Suspended Well Schematic.jpg» -----Original Message----- From: Lowry, Scott L Sent: Tuesday, December 30, 2003 9:57 AM To: 'tom maunder@admin.state.ak.us'; 'winton aubert@admin.state.ak.us' ..............................M......__..___....·.·..·_····.............__.................................._._............._......._.....__............_._._____..................... Cc: Brockway, Thomas A; Thomas, Randy L; Hayden, Philip; Schwartz, Guy L Subject: FW: 2P-447 Suspended Tom, The schematic had some incorrect depths on it. Please see the corrected version attached. The sundry application was sent over last night for the well suspension. Please replace the existing schematic with the corrected version. Sorry Winton, I should have included you in the original response yesterday. Thanks, Scott Lowry « File: visio-2P-447 Suspended Well Schematic.jpg » -----Original Message----- From: Lowry, Scott L Sent: Monday, December 29, 2003 4:39 PM To: Cc: Brockway, Thomas A; Thomas, Randy L; Hayden, Philip; Schwartz, Guy L Subject: 2P-447 Suspended Tom, lof6 1/5/2004 11 :29 AM RE: 2P-447 Suspended . . I answered the questions below. The sundry application will be over tomorrow. Attached is a schematic of the well as it sits today. Call if you have questions. Thanks, Scott Hi Scott, How did the cement look. Did any get above the Cairn?? What about the cement up high?? Our initial interpretation of the bond log is that inadequate cement bonding exists in the confining zone and above the Cairn. I included a pick for the Cairn formation top, but the Cairn is poorly developed in this well. I think we will run another bond log prior to commencing remedial work to make sure cement did not set up after the first bond log. We came up into cased hole and started to see better bonding inside the surface casing shoe. We are reviewing our inputs for the USIT log since we were logging two different densities of slurries. >From the bond log you can see cement from ± 4100' MD to 7100' MD which indicates cement probably went south during the 2nd stage of the cement job. Since most of the phase II development team is on vacation this week (including Philip Hayden), we will convene next week to finalize a plan forward. My observation of 2P-447 is that it had more complications than any well so far drilled at Meltwater. Is that correct?? I don't know if that's completely true. We used all of our contingency casing strings on 2P-432 (the first well in phase II) The Phase III weather conditions contributed 65% of our total trouble time thus far. After experiencing shallow pressured gas, we wanted to scratch the top of the Bermuda sand in the intermediate interval, but the sand came in 30-35'TVD higher than expected. This resulted in us exposing more of the Bermuda sand than we wanted. We set 7" casing 60' off bottom to leave all of the pay in the production hole. We drilled good cement in the rathole when we drilled out, which indicates cement was likely going into the Bermuda while cementing. Where (in depth) did the losses begin?? Were losses incurred with the Cairn open prior to cutting the Bermuda?? I seem to remember that you successfully got below the Cairn but that the further problems came up as the well was prepared to drill deeper into the Bermuda. Is 20f6 1/5/2004 11 :29 AM RE: 2P-447 Suspended . . that correct?? Losses began up around 2800'-2900' MD. Losses did occur with the Cairn open prior to cutting the Bermuda, but losses were occurring prior to drilling the Cairn. I don't believe the Cairn was a factor on this well since it wasn't well developed geologically. For 2P-424, does it make sense to look to set the 7" between the Cairn and Bermuda?? I know that is dependant on what the well tells you as various zones are penetrated, but in the wells so far on this campaign it appears that having Cairn and Bermuda open in the same wellbore section has led to problems. On 2P-434 we scratched the top of the Bermuda with the Cairn interval open in the intermediate hole. We ran and cemented the 7" casing with minimal mud losses. We had some gas in the production interval below (Bermuda), but nothing of any signifigance. On 2P-432 we set 7" casing below the Cairn, but encountered another gas streak below the 7" shoe that required higher mud weight to control. We scratched the top of the Bermuda and ran and cemented a 5 1/2" liner with manageable losses (losses tend to occur toward the base of the Bermuda). Then we drilled 4 3/4" hole and set a 3 1/2" liner. This well required us to use all of our contingencies to get it down. If we just scratch the top of the Bermuda we have had reasonably good luck cementing the casing/liner string with higher mud weights. If we get deeper into the Bermuda (or all the way through it), the mud losses increase with the higher mud weights. In a normally pressured area, we should be able to drill the well to TD in the 8 1/2" hole. I believe our approach of scratching the top of the Bermuda interval prior to setting intermediate casing is fine (when high mud weight is required). We just need to make sure we don't drill too deep into the zone by stopping sooner to let the mud loggers check samples and confer with the geologist. The 2P-424 is the first well to penetrate the southeastern quadrant of the reservoir and pressures are predicted to be normal in this area. This is my observation, lid appreciate your thoughts. Tom Maunder, PE 30f6 1/5/2004 11 :29 AM conöC~illiPs . Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Fax: (907) 265-1535 Email: randy.l.thomas@conocophillips.com RECEIVED DEC 2 92003 Alaska Oil & Gas Cons. Commission Anchorage December 29,2003 Alaska Oil and Gas Conservation Commission 333 West ylh Avenue Suite 1 00 Anchorage, Alaska 99501 (907) 279-1433 Re: Application for Sundry Approval to suspend we1l2P-447 (Permit #: 203-154) Dear Commissioner: ConocoPhillips Alaska, Inc. hereby files this Application for Sundry Approval to suspend well 2P-447. A preliminary cement bond log of the 7" intermediate casing string indicates inadequate cement bonding across the confining interval. CPAI plans to mobilize a coiled tubing unit to well 2P-447 to perform remedial cementing work. Afterward, a rig will be moved onto the well to finish completing the well. Attached is the wellbore schematic with cementing details. If you have any questions or require any further information, please contact Scott Lowry at 265-6869. ./ .'" Si..n?..,.e....,r....ß ,~·....··.··..········/····/'k'.· .. .' .' //' ,./"/ ./ I / ¿~/. V í~ / l/'-'v¿ '~ Randy Thomas C/ GKA Drilling Team Leader ðor ¡¿Vtc'? /1~~ qj . STATE OF ALASKA ALAS IL AND GAS CONSERVATION COMM~N APPLICATION FOR SUNDRY APPRWtAL ¡)~ /IÇ&~1 RE~fVEÓAJ C29 r;- DE '. 20 MC 25.280 1. Type of Request: Abandon U Suspend l.:d Operational shutdown U Perforate U Waiver.W Annular Dispos. U Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 ~m§~QnsªnGa Cons. Co.~pt] Change approved program 0 Pull Tubing 0 Perforate New Pool 0 ~ orage Re-enter Suspended We I 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development 0 Exploratory 0 203-154 3. Address: Stratigraphic 0 Service 0 6. API Number: P.O. Box 100360 Anchorage, AK 99510-0360 50-103-20468-00 7. KB Elevation (ft): 9. Well Name and Number: 28' 2P-447 8. Property Designation: 10. Field/Pools(s): ADL 373112/389058 Kuparuk River Field I Meltwater 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): 8015' 5549 7910 5491 - - Casing Length Size MD rvD Burst Collapse Structural Conductor 108' 16 x 30' insulated 108' 108' Surface 2678' 9-5/8" 2705' 2317' Intermediate 7536' 7" 7562' 5306' Production Liner 601' 3-1/2" 8010' 5546' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A NIA NIA NIA Packers and SSSV Type: N/A Packers and SSSV MD (ft): N/A 12. Attachments: Description Summary of Proposal U 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: Suspended Well 12126/03 Oil 0 Gas 0 Plugged 0 Abandoned 0 16. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Scott Lowry (907)-265-6869 Printed NameltoßfI c.-~ 4 c 6/?:~J, vU';. VI 5~ í4.0...JJle S¡. Dït~'1ç b??,/} .ee/ );2/2- '7/D3 Signature ~¿- , /; D~_ ..í~~~. Phone Date " ~ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ?;¿i/)" :) gct Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: ~ft ~~ ~ , v...)C:'\~ ~ \""l ~ \ó(. \ .,j \ 'f'-\a w~:\ \ ç~",û\\1t. <-::. ('ð,-(v\' ~O ~ jA~ ij ð Ah~~ ~\- \-\r....\ ~ \ \ """-~ ~-"I~,. Subsequent Form Required: '" 'C '\.......<L. ~~',~. YÅ~~ BY ORDER OF )1ot-t Approved by: Ý \() COMMISSIONER THE COMMISSION Date: l Form 1 0-403 R~ised Ut2003 y If)/STRttCTIONSroN iRE.~E SE Submit in Duplicate '. T ''t Visio-2P-447 Suspended Well Schematic.jpg (JPEG Ima... . . 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"'-- ...",,1,11I111II111.. 'ijij~111III1 r' "I '~'~~~ ~. ..~ ¡~:I'¡"" . 'I~ ~".'. ?).(:IIIL·f,.'vr..,¡ ; "",1'11II.11I':"'0' r··'·'·'"""",,"'I"'·' ,'" . "I,," ,I", r ,1' ,,"I . :"" II";' \. " !I' ~ ';' "í ~.: ;f~'~:::<1' :11 t·;, '~..'!"¡';" '¡.. I ~I",·: ~""~.!j~::1'.: ,~~~. 1 -4, ~ ~~ II ;.~' ~c·· :~I.6~')~~~·:·····:; '1'." :~'·."'r'fr¡'.'¡:11:.~¡ \~,; :;.~: ':,~. if. iJIf,.;' ~Bl:~"'- r,': f;;:,,,:,¡~,t,,r ,~:(, ~~~, '$; ~)r'.~~ ¡;::,,~I'~i:::~~I¡::¡,V~: :.. ~~t~, ,~:. i.~~~~~~,Jt~ '\,,::ir~~:" L~·.t. . .3. tJ,,:~·, I' t~ fI pH' '!\~'¡~ ~''''~(~ rf.oI!'>R, ND¡" .:.,~' ___ 'r~,.~:l !'::"t<>1~,J';;,~~:::,"'1 :.;; . ' I~_~" :) 1" 9 ,:~~~~I~ ¡ , :., \.,1.' ~·i ':i.j(); .:1 ~,'[):' , : ;fTVDI 1',':·''í'IIÞ,'n¡~·.!·''Jt·;· ':::J.) !i!ad¡',~" .~: r.~·~·~,) I,~! I, f~\·; '<:," (;,.'}.:..: ;"':/ ~:tlH;"t" rnu~:·d £~ '1~'~ ,.... ;.:,,~; f'l~;n f~W: I)'¡J~ "'itl'l>~.r '.',' ~\1nfJr~Ij' ;'!:(ij!~~:·".i :::(I~,(I,~i:k.l~:~~ ~c· ,.~ I ,::f ":::,~,W¡·.·IH ~t'...f'~t '!r~~~¡( :...: 't'~"r~~: ~~,# !.,.'."J ,:.~..~H :n~ 3,:') !""·~.ih~d ;5" t(,~,· f'::: ,~"~~:'f L ~w !I::jri;:~ ~, :1 :::Ø ;;: ~'M.. j:~," I :':t~ ,;.;;j ..:;;i."H1" t};:r,!rl,.,1 ~~,'~ ,~::~ e:~~~:H~:,t~~,' ;';':t~i; ();Jia 2 ,t,~~ /·1,"';~43~) ~-\þ ,"n '::'~ ~ ~.¡ t~þtrln~; J 1·!~H.·e.;~··~ ~.;..,,:~ ·:.I'.:,:,.~,:, '- '> .:.t1 L···~'·r, ~.;:~'.:"·~;r:~ 1 of2 1/5/2004 11 :26 AM KRU - 2P-447 Injeclr Wellbore Schematic Well suspended 12/26/2003 Base Permafrost @ 1377' MD /1352' TVD Base West Sak @ 2118' MD /_ 1952' TVD Top C-80@ 2924' MD /2450' - TVD Top C-50 @ 3644' MD /2895' _ TVD Top C-40 @ 4222' MD /3255' _ TVD Top C-37 @ 4448' MD /3395' _ TVD Top T-7 @ 6155' MD /4450'_ TVD (Cairn) TopT-4.1 @7515'MD/5065'_ TVD (Bermuda) Top T-3 @ 7694' MD /5323' - TVD Top T-2 @ 7865' MD /5465' _ TVD 11.0 ppg brine left in casing - liner lap pressure tested to 3500 psi . ~ ConoœPhilliþS Well capped with a dry hole tree allowing full-bore access to the 7" casing string 16"x30" insulated conductor @ +1- 108' MD Surface csg. Cemented with 446 sx lead 284 sx tail Circulated 162 bbl cement to surface Surface csg. 9-5/8"40# L-80 BTC (2705' MD I 2317' TVD) Stage Collar placed at 3105' MD / 2558' TVD h Stage: 340 sacks (163 bbls) of ArctiCrete cement mixed at 12.0 ppg - no returns while cementing Performed downsqueeze through surface casing valve - bullheaded 197 sacks (94 bbls) of ArctiCrete - final SIP of 400 psi Intermediate csg. 7" 26.0# L-80 BTCM (7562' MD /5306' TVD) Cemented in 2 stages pi Stage: 165 sacks (34 bbls) Class "G" GasBlok cement mixed at 15.8 ppg - no returns while cementing Production Liner 3-1/2" 9.3# L-80 SLHT (8010' MD /5546' TVD) Cemented with 150 sacks (31 bbls) of Class "G" Gasblok cement mixed at 15.8 ppg - full returns while cementing - circulated approximately 10 bbls of cement from liner top Liner Assemblv (too of liner at 7415' MD Baker 7" x 5" 'z)(P' Liner Top Isolation Packer with HR profile Baker 7" x 5" 'Flexlock' Liner Hanger Baker 20' Seal Bore Extension XO Sub, 5" Stub Acme box x 3-1/2" SLHT pin 3-1/2" 9.3# L-80 SLHT liner as needed 3-1/2" Baker Landing Collar 1 jt 3-1/2" 9.3# L-80 SLHT tubing 3-1/2" Baker Float Collar 2 jts 3-1/2" 9.3# L-80 SLHT tubing 3-1/2" Baker Float Shoe Scott Lowry 12/29/03 . (ID~ ~~~~æ~ AI.ASIiA OIL AND GAS CONSERVATION COMMISSION Randy Thomas Kuparuk Drilling Team Leader ConocoPhillips (Alaska), Inc. PO Box 100360 Anchorage AK 99510 . FRANK H. MURKOWSKI, GOVERNOR 333 W. T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kuparuk River Field 2P-447 ConocoPhillips (Alaska), Inc. Permit No: 203-154 Surface Location: 1017' FNL, 1603' FWL, Sec. 17, T8N, R 7E, UM Bottomhole Location: 363' FNL, 993' FEL, Sec. 19, T8N, R7E, 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 inspector at 659-3607 (pager). 8e?L-< Commissioner BY ORDER OF THE COMMISSION DATED this €' day of September, 2003 cc: Department ofFish & Game, Habitat Section w/o end Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section fit - 4r s-- STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: Drill~ 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 2P-447 3. Address: 6. Proposed Depth: 12. FieldlPool(s): P.O. Box 100360 Anchorage, AK 99510-0360 MD: 8058' . TVD: 5602' Kuparuk River Field 4a. Location of Well (Govemmental Section): 7. Property Designation: Surface: 1017' FNL, 1603' FWL, Sec. 17, T8N, R7E, UM L 32092 I 32409 ~ Meltwater Oil Pool Top of Productive Horizon: 8. Land Use Permit: )J' 13. Approximate Spud Date: 87' FNL, 838' FEL, Sec. 19, T8N, R7E, UM ADL373112 1389058 12/17/2003 Total Depth: 9. Acres in Property: 14. Distance to 363' FNL, 993' FEL, Sec. 19, T8N, R7E, UM 5760 Nearest Property: 87' @ Target 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Surface: x- 443562 . 5868863 Zone- 4 Well within Pool: 2P-448 , 22.92 y- 252' AMSL feet 16. Deviated wells: 17. Anticipated Pressure (see 20 AAC 25.035) Kickoff depth: 400 ft. Maximum Hole Angle: 52.18° Max. Downhole Pressure: 2249 psig I Max. Surface Pressure: 1646 psig 18. Casing Program Setting Depth Quantity of Cement Size Specifications Top Bottom c. 1. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 16" 62.5# H-40 Weld 80 28' 28' 108' 108' 90 sx ArticCrete (preinstalled) 12.25" 9.625" 40# L-80 BTC 2687 28' 28' 2715 2325 533 sx ASLite & 277 sx LiteCRETE 8.5" 5.5" 15.5# L-80 BTCM 7030 28' 28' 7058 4988 359 sx LiteCRETE 8.5" 3.5" 9.3# L-80 EUE8RDM 1000 7058 4988 8058 5602 (Included above) 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured) Effective Depth MD (It): Effective Depth TVD (ft): Junk (measured) Casing Length Size Cement Volume MD rvD Structural Conductor Detailed Operations Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee 0 BOP SketchU Drilling Program ~ Time v. Depth Plot U Shallow Hazard Analysis Q Property Plat D Diverter Sketch D 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 Philip Hayden 265-6481 Printed Name R. Thomas Title Kuparuk Drilling Team Leader Signature ~5 J~~ Phone '4,)"6 ~ So Date C( (¿ (i» -.., p~ ~L - , Commission Use Only Permit to Drill API Number: Permit Approval See cover letter Number: 2-D 3 - /51 50- /D3- 2.0c.¡fø~ -00 Date: l' / ~ Õ7 for other requirements Conditions of approval : Samples required DYes.k$t No Mud log rø{¡uiré'd DYes ~ No Hydrogen sulfide measures D Yes ~ No Directional survey required ~ Yes D No Other: ,",,\~c..Q:.~~\--s.. ~\~..\-l \0 ~ ':>S()()~c;\ M.," ~'k~~ ~(J Ç> ~~.\.. Approved by: ~ A ~ ~_ _ BY ORDER OF /;5j¿)? 10~Ei . THE COMMISSION Date: Form 10-401 Revised £003 . UKlblNAL /' / Submit in du licate p e "ation for Permit to Drill, Well 2P-447 _ Revision No.O Saved: 29-Aug-03 Permit It - Meltwater Well #2P-447 Application for Permit to Drill Document MoximizE Well VQlu~ Table of Contents 1. Well Name ....... ........... ......... ........... ........ ........... ......................... ........... .... ....... ......... 2 Requirements of 20 AAC 25.005 (f)......... ......... .......... ............ ...... ................. ...................... ............. ......2 2. Location Sum 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 AAC 25.005(c)(6) .............. ............. ........ ........ ................. ....... .............. ......... ......... 4 7. Diverter System Information ...................................................................................5 Requirements of 20 AAC 25.005(c)(7) ......... ........ .......... ........... ........... ......... .................... ... ............. ..... 5 8. Dri II i ng FI u id Program .... .... .............. ........... ........................... ............. ...... .............. 6 Requirements of 20 AAC 25.005(c)(B) ......... ............ ...... ...................... ...... ........... ................. ................ 6 Surface Hole Mud Program (extended bentonite) .................................................................................. 6 Production Hole Mud Program (LSND) ...... ........ ....... ................ ......................... ............... .............. ....... 6 9. Abnormally Pressured Formation Information ...................................................... 6 Requirements of 20 AAC 25.005 (c)(9) .................................................................................................. 6 10. Seism ic Analysis ....... .................... ........... ....... ............ ....... ................ ............. ......... 6 Requirements of 20 AAC 25.005 (c)(10) ................................................................................................6 11. Seabed Condition Analysis ..................................................................................... 7 Requirements of 20 AAC 25.005 (c)(11) ................................................................................................7 12. Evidence of Bonding ............................................................................................... 7 ORIGINAL 2P-447 PERMIT IT.doc Page 1018 Printed: 29-Aug-03 e ~ation for Permit to Drill, Well 2P-447 ,., Revision No.O Saved: 29-Aug-03 Requirements of 20 AAC 25.005 (c)(12) ................................................................................................ 7 13. Proposed Drilling Program ..................................................................................... 7 Requirements of 20 AAC 25.005 (c)(13) ................................................................................................ 7 14. Discussion of Mud and Cuttings Disposal and Annular Disposal....................... 8 Requirements of 20 AAC 25.005 (c)(14) ................................................................................................ 8 15. Attachments.. ....... ....... ......... ............ .......... ......... ......... .................. .... ..... ................. 8 Attachment 1 Directional Plan (15 pages) .............................................................................................. 8 Attachment 2 Drilling Hazards Summary (1 page) ................................................................................. 8 Attachment 3 Cement Loads and CemCADE Summary (2 page) ......................................................... 8 Attachment 4 Well Schematics (1 page) ................................................................................................ 8 1. Well Name Requirements of 20 AAC 25.005 (f) Each well must be Identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 MC 2S.040(b). For a well with multiple well branche~ each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this Application is submitted will be designated as 2P-447. 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 Item~ 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 surface, at the top of each objective formation, and at total depth, referenced to govemmental section lines. (B) 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 Survey 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 I NGS Coordinates Northings: 5,868,863 Eastings: 443,562 1017' FNL, 1603' FWL, Section 17 T8N, R7E, UM I RKB Elevation I 252' AMSL I Pad Elevation I 224' AMSL / Location at Top of Productive Interval Bermuda Sand NGS Coordinates Northings: 5,864,532 87' FNL, 838' FEL, Section 19, T8N, R7E, UM Eastings: 441,104 Measured De th RKB: Total Vertical De th RKB: Total Vertical De th 55: 7657 5356 5104 Location at Total De NGS Coordinates Northings: 5,864,257 Eastings: 440,948 363' FNL 993' FEL Section 19 T8N R7E UM Measured De th RKB: Total Vertical De th RKB: Total Vertical De th 55: ./ 8058 5602 5350 and ORIGINAL 2P-447 PERMIT IT. doc Page20fB Printed: 29-Aug-03 e .lication for Permit to Drill, Well 2P-447 Revision No.O Saved: 29-Aug-03 (D) other information required by 20 AAC 25.050(b); Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviatett the application for a Permit to Drill (Form 10-401) must (1) 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 well; 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 mall,' or (8) 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 of the blowout prevention equipment (80PE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; An API 13 5/8" x 5,000 psi BOP stack (RSRRA) will be utilized to drill and complete well 2P-447. Please see information on the Doyon Rig 141 blowout prevention equipment placed on file with the Commission. 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 encounterett criteria used to determine it, and maximum potential surface pressure based on a methane gradient; The expected reservoir pressures in the Bermuda sands in the 2P-447 area vary from 0.26 to 0.41 psi/ft, ,/ or 5.0 to 7.9 ppg EMW (equivalent mud weight). These pressures are predicted based on actual bottom hole pressure data from existing wells on the field together with reservoir model forecasts. The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11) and the deepest planned vertical depth of the Bermuda sand formation is 1646 psi, calculated as follows: MPSP =(5485 ft)(0.41 - 0.11 psi/ft) =1646 psi .I (8) data on potential gas zones; Due to the presence of high annular pressures on some of the Meltwater wells (2P-431, 451 & 438) there is the risk of encountering a pressured shallow zone. This interval may be encountered through the C-80 and C-37 formations. The original high pressures recorded in these annuli were of concern but as can be seen from the following table a series of annular bleeds together with an observed natural decline in pressures have reduced the potential maximum pressure considerably: Original 08/22/2003 Well Surface Fluid C-80 C-80 Equivalent Surface Fluid C-80 C-80 Equivalent Pressure Level Pressure Gradient (ppg) Pressure Level Pressure Gradient (ppg) 2P-431 1600 2387 1751 13.85 1260 1822 1473 11.66 2P-451 1380 2160 1541 12.23 940 2281 1074 8.53 2P-438 879 895 1245 9.83 820 682 1244 9.83 ORIG1NAL 2P-447 PERMIT IT. doc Page 3 of 8 Printed: 29-Aug-03 e .iCatiOn for Permit to Drill, Well 2P-447 Revision No.O Saved: 29-Aug-03 Using the latest annular pressures available the highest pressure that would be expected is approximately 1480 psi at 2435 ft 1VD or 11.7 ppg EMW. Most of the previously drilled Meltwater wells had an FIT/LOT of approximately 16 ppg thus indicating that this pressured interval, should it exist, can be safely controlled with standard well control methods. Further annular bleeds are planned to take place before spud in order to reduce further the potential / maximum pressure that could be encountered in the C-80 and C-37 intervals. and (C) data concerning potenäal causes of hole problems such as abnormally geo-pressured strata, lost circulaäon zones, and zones that have a propensity for differential sticking; Please see Attachment 2: Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An applicaäon fòr a Permit to Drill must be accompanied by each of the following items, except for an Item already on file with the commission and idenäfied in the applicaäon: (5) a descripäon of the procedure for conducting formation integrity tests, as required under 20 MC 25.030(f); 2P-447 will be completed with 9 5/8" surface casing landed above the C-80 mudstone interval. The casing shoe will be drilled out and a leak off test will be performed in accordance with the "Leak Off Test Procedure" that Phillips Alaska placed on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An applicaäon 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 idenäfied in the applicaäon: (6) a complete proposed casli1g and cemenäng 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 I See also Attachment 3: Cement Summary Hole Top Btm CsgITbg Size Weight Length MO/TVO MO/TVO 00 (in) (in) (Ib/ft) Grade Connection (ti) (ft) (ft) Cement Proqram 16 42 62.5 H-40 Welded 80 28 / 28 108 / 108 Cemented to surface with 90 sx ArticCRETE 9 5/8 12 V4 40 L-80 STC 2687 28 / 28 2715 / 2325 Cement to Surface with 533 sx ASLite Lead, 277 sx LiteCRETE Tail 5 V2 8 V2 15.5 L-80 STCM 7030 28 / 28 7058 / 4988 Cement Top planned @ 3 V2 8 V2 9.3 L-80 EUE8RD 1000 7058 / 4988 8058 / 5602 6758' MD / Mod 4804' 1VD. Cemented w/ 359 sx LiteCRETE ORIGINAL 2P-447 PERMIT IT.doc Page 4 of 8 Printed: 29-Aug-03 e .ication for Permit to Drill, Well 2P-447 ,., Revision No.O Saved: 29-Aug-03 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); A 21 V4", 2000 psi annular with a 16" diameter diverter line will be the diverter system used in the drilling of 2P-447. Please see diagrams of the Doyon 141 diverter system on file with the Commission. ORIGINAL 2P-447 PERMIT IT.doc Page 5 of 8 Printed: 29-Aug-03 . _cation for Permit to Drill, Well 2P-447 . Revision No.O Saved: 30-Aug-03 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(B) An application for a Permit to Drill must be accompanied by each of the following item~ except for an item already on file wIth the commission and identified in the application: (8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25. 033; Drilling will be done with muds having the following properties over the listed intervals: Surface Hole Mud Program (extended bentonite) Spud to Base of Permafrost Base of Permafrost to 95/8" Casin(7 Point Initial Value Final Value Initial Value Final Value Density (ppg) 8.6 <9.2 <9.2* 9.6 Funnel Viscosity 250 250 150-200 55-65 (seconds) Yield Point 35-45 35-45 30-35 12-15 (eP) pH 9-9.5 9-9.5 9-9.5 9-9.5 API Filtrate 6 6 4-6 4-6 (ee / 30 min)) Chlorides (mg/I) <600 <600 <600 <600 *9.6 ppg if hydrates are encountered Production Hole Mud Program (LSND) 95/8" Casin 7 Shoe to TD Initial Value Final Value Density (ppg) 9.6 9.6 Yield Point 22-28 10-15 (eP) pH 9-9.5 9-9.5 API Filtrate 4-6 4 (ee /30 min)) HTHP @ 15d' (ee)) <12 <12 ,/ Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Please see information on file with the Commission for diagrams and descriptions of the fluid system of Doyon Rig 141. 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 item~ except for an item already on file with the commission and identified in the application: (9) for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnomlally geo-pressured strata as required by 20 AAC 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 Item~ except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061{a); Not applicable: Application is not for an exploratory or stratigraphic test well. ORIGINAL 2P-447 PERMIT IT. doc Page 6 of 8 Printed: 30-Aug-03 e Alication for Permit to Drill, Well 2P-447 ,., Revision No.O Saved: 29-Aug-03 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 platfonn, mobile bottom-founded structure, jack-up rig, or floating dnlling vessel, an analysis of seabed conditions as required by 20 MC 25.061(b); Not applicable: Application is not for an offshore well. 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 MC 25.025 {Bonding}have been met; Evidence of bonding for ConocoPhillips 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 also to Attachment 4, Well Schematics. 1. Move in / rig up Doyon Rig 141. Install 21 V4" Annular with 16" diverter line and function test (conductor has already been installed and cemented). 2. Spud and directionally drill 12 V4" hole to casing point at 2715' MD /2325' 1VD as per directional plan. Run MWD tools as required for directional monitoring and LWD tools as required for data acquisition. ~~.e.t:~ 3. Run and cement 95/8",40# L-80, BTC casing to surface. Displace cement with mud. Perform top job if required. 4. Remove diverter system and install wellhead and test. Install and test 13 5/8" x 5,000 psi BOP's and test to 5000 psi (annular preventer to 3500 psi). Notify AOGCC 24 hrs before test. 5. PU 8 V2" bit and 6 V4" drilling assembly, with MWD and LWD. RIH, clean out cement to top of float equipment. Pressure test casing to 3500 psi for 30 minutes and record results. 6. Drill out cement and 20' of new hole. Perform LOT or FIT to 18.0 ppg EMW, recording results. 7. Directionally drill to 5 V2" X 3 V2" casing point at 8058 MD / 5602' 1VD. 8. Run 5 V2", 15.5# L-80, BTC Mod x 3 V2", 9.3# L-80, EUE8RD Mod casing to TD. Pump cement and displace with water and mud. Note that the cross over and seal bore extension for the completion will be positioned 200' MD above the Cairn interval, if present, as this is an interval that may be produced later in the life of the field. t;/C.../K:éS./ J>GAI /NEl{. 9. Make up completion string as required and RIH to depth. Locate seal bore extension, space out and land completion. Pressure test completion and production casing to 3500 psi for 30 minutes and record results. Shear RP shear valve in gas lift mandrel. 10. Install BPV, nipple down stack, nipple up and test tree to 5,000 psi. Pull BPV 11. Freeze protect well with diesel by pumping into tubing, taking returns from annulus and allowing to equalize. Carry out LOT and injection test on the outer annulus. Sweep the annulus with water and freeze protect. 12. Set BPV and move rig off. 13. Rig up wire line unit. Pull BPV. Set dummy valve in place of RP shear valve in gas lift mandrel. Perform MIT pressure tests of tubing and annulus (Tubing and annulus to 3500 psi). 14. Run cement bond log and perforate. Rig down wire line unit. ORIGINAL 2P-447 PERMIT IT. doc Page 7 of 8 Printed: 29-Aug-03 e Alication for Permit to Drill, Well 2P-447 .. Revision No.O Saved: 29-Aug-03 is. Freeze protect well and turn well over to production. 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 dnlling 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 well.; Waste fluids generated during the drilling process will be disposed of either by pumping authorized fluids r/ into a permitted annulus on 2P Pad, or by hauling the fluids to a KRU Class II disposal well. All cuttings generated will be disposed of either down a permitted annulus on 2P Pad, hauled to the Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and used on the pad in accordance with a permit from the State of Alaska. At the end of drilling operations, an application may be submitted to permit 2P-447 for annular disposal of fluids occurring as a result of future drilling operations on 2P pad. 15. Attachments Attachment 1 Directional Plan (15 pages) Attachment 2 Drilling Hazards Summary (1 page) Attachment 3 Cement Loads and CemCADE Summary (2 page) Attachment 4 Well Schematics (1 page) ORIGiNAL 2P-447 PERMIT IT. doc Page 8 of 8 Printed: 29-Aug-03 0 400 BOO 1200 1600 ............ +- Q) 2000 Q) '+- "-" ...c 2400 +- 0 c.. Q) 0 ::::0 2BOO 0 - ü G) +- 3200 ... Q) - > Z Q) 3600 ::::¡ » ... l- I I 4000 V 4400 4BOO 5200 5600 6000 KOP 2,00 4.00 6.00 8.00 ConocoPhillips Alaska, Inc. RKB Elevatian: 252' Structure : Drill Site 2P Field : Meltwater Location : Narth Slope, Alaska Weil : 447 DLS: 2,00 deg per 100 ft 15.00 18,00 OLS: 3,00 deg per 100 It 21.00 24.00 Base Permafrast 27.00 30,00 33,00 39,00 45.00 Base West Sak 51,00 EOC "'Plane of Proposal-.. 209.14 AZIMUTH 4981' (TO TARGET) ~ 9 5/8 CSG C80 C50 C40 C37 TANGENT ANGLE 52.18 DEG 400 o T7 5 1/2 X 3 1/2 XO T4,1 (Top Cairn) 2P-447 Top Berm Tg\ 22 Jul 03 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 Vertical Section (feet) - > Azimuth 209.14 with reference 0.00 N. 0.00 E from slot #447 T3 (Top Bermuda) T2 (Base Bermuda) c35 (Top Albian) TO, Csg PI. Conoc;r;hillips C'eoted by bmichoel FOR: P Hayden Dote plotted: 27-Aug-2003 Plot Reference is 2P-447 Version #8.8. Coordinates are in feel reference slol #447. Vertical Depth5 ore reference RKB (Doyon 141). 1ft. .... INTEQ e e Created by bmÎcha~1 For; P Hoyden Dote plotted: 28-Au9-2OO3 Plot Reference is 2P-447 Version 118.8. CtIordinotes are În feet reference slot 1447_ True Vertical DepU"Is ore reference RKB (Doyon 141). .- .- -- INTEQ e e ConocoPhillips Alaska, Inc. Structure: Drill Site 2P Well : 447 Field : Meltwater Location : North Slope, Alaska - ---------------------"._~--~- ----_._-~.._--_.".._...~ "...----.--..---------.---.-- <- West (feet) 3300 3000 2700 2400 2100 1800 1500 1200 600 300 900 SURFACE LOCATION: 1017' FNL, 1603' FWL SEC 17, T8N. R7E 209.14 AZIMUTH 4981' (TO TARGET) ***Plane of Proposol*** , TRUE XO 2P-447 Top Berm T9\ 22 Jul 03 13 (Top Bermuda) T2 (Base Bermuda) .;,,¡ C35 (Top Albian) TD, C5g Pt. TARGET LOCATION: 87' FNL, 838' FEL SEC. 19, T8N, R7E TD LOCATION: 363' FNL, 993' FEL SEC. 19, T8N, R7E ORIGINAL ~ ConocoPhillips o 300 300 o 300 600 900 1200 1500 1800 If) 0 C 2100 -+ :r ~ -+. 2400 <D <D -+ '--' 2700 I V 3000 3300 3600 3900 4200 4500 4800 o ::::0 - (J) - z: » r- II Created by bmíCMoel For: P Hayden I Dote plotted: 28-Aug-2003 ; P'lo~ Reference is 2P-447 Version #B.8. i Coordinotes ore ín feet reference 310l #447. ¡True Vertical Depths ore reference RKB (Doyon 141). i .£ INTEQ ==== ----- Point ----- . KOP Bose Permafrost Bose West Sak EOC 9 5/8 CSG C80 C50 C40 C37 T7 5 1/2 X 3 1/2 XO T4.1 (Top Cairn) 13 (Top Bermuda) T2 (Base Bermuda) C35 (Top Albian) TD Csa pt, ConocoPhillips Alaska, Inc. Structure: Drill Site 2P Well: 447 Field: Meltwater Location : North Slope, Alaska PROF~LE COMMENT MO 400.00 1376.93 2117.85 2305.95 2714.51 2836.82 3746.80 4214.83 4459.45 5912.48 7057.88 7257.88 7657.42 7867.79 7937.91 8057.79 lnc 0.00 24.31 46.54 52.18 52.18 52.18 52.18 52.18 52.18 52.18 52.18 52.18 52.18 52.18 52.18 52.18 Oir 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 209.14 TVO 400.00 1352.00 1952.00 2074.47 2325.00 2400.00 2958.00 3245.00 North 0.00 -160.55 -533.27 -657.87 -939.75 -1024.13 -1651.94 -1974.85 Conoc~hillips DATA East 0.00 -89.52 -297.35 -366.83 -524.01 -571.06 -921.13 -1101.18 3395.00 -2143.61 -1195.29 4286.00 -3146.09 -1754.27 4988.36 -3936.32 -2194.91 5111.00 -4074.30 -2271.84 5356.00 -4349.95 -2425.55 5485.00 -4495.09 -2506.48 5528.00 -4543.47 -2533.46 5601.51. -4626.17 -2579.57 ==== e V. Sect 0.00 183.82 610.57 753.24 1075.97 1172.58 1891.40 2261.11 2454.34 3602.13 4506.91 4664.89 4980.50 5146.68 5202.07 5296.76 Oeg/100 0.00 3.00 3.00 3.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 e ConocoPhillips Alaska, Inc. Structure: Drill Site 2P Well : 447 pf ConocoPhmips Plot R"ferMc<¡ is 2P-447 Vørsion #8.s' C{ordil'lQtas orB in fee!: referencs slot 11447. Ved;col Depths ore reference RK8 (Ooyon 141). Field: Meltwater Location : North Slope, INTEQ UE NORTH ~ 35~ 10 340 20 240 330 210 30 40 50 290 70 280 80 270 O@Ð 90 260 100 2 110 2~~;"" 1 2 0 ~ 230 130 220 140 210 150 200 160 190 180 170 Normal Plane Travelling Cylinder ~ All pths shown ore Measured depths on Reference Well J j Created by bmkhoel For: P Hoyden Dote plotted; 28-Aug-2003 PIQt Referanc'€! Îs 2P-447 Version #8.B. CaordÎnotes ore in feat referaoca slot 11447. True VertÍ!::a! Deplhs ore reference RKB (Doyon .. -==- INTEQ 560 520 440 480 / , (j) Structure: Drill Site 2P Well : 447 ConocoPhillips Alaska, Inc. ",./ ConocoPhillips Field : Meltwater Location : North Slope, ?i'500 1'700 / ¡6900 / / /1100 / / / / /1300 / / / / / / 1'1500 / / / / / / / / /1700 / / / / / / / / / / / ¿ 1900 / / / / / / / / / / / / (j; < - West (feet) 400 160 360 320 280 240 200 1500 / / 700 / / / 1900 , , 120 80 40 o 40 80 ~. 100 900 500 :e- I r 700 I 1900 I I / 1300 / /1100 I I I I 120 80 40 0 40 80 120 160 200 (f) 0 240 C -+- ::J ,-.... 280 -+, CD CD -+- '--'" 320 I V 360 400 440 480 520 560 600 640 ConocoPhillips Alaska, Inc. For: P Hoyden Date plotted: 28-Aug·-2003 Plot R"feren<:e ìs 2P-44'l Version #8_R Coordinates ore ín faat referencE! slQt 11-447_ True Vedical Depths <:Ire reference RKB (Doyen INTEQ 3500 3000 3250 / / (!} .~ ConocoPhmips Field : Meltwater Structure: Drill Site 2P Well : 447 2750 2500 2000 2250 4000 4500 5000 5500 / ¡ 3500 /4000 / / / / / / ,/4500 / Location : North Slope, < - West (feet) 1750 1250 / / / 12000 2000 / / I' / / / / / / / ,¡ 2500 / / / I' 2500/ / / / /3000 / / / jooo / / ¡ 3500 / / / / / / / ,¡ 4000 / / / / / / /4500 / / / / / / ¡ 5000 / / / / / / / " 5500 / B 1500 / / 1000 750 250 250 500 500 o / / / / / / / 2500 2500 3000 3500 I I 4000 / I r 4000 / / / &1 j i 750 250 500 750 1000 1250 1500 1750 2000 2250 (J') 0 C -+ 2500 ::J ~ - ill 2750 ill -+ '-../ I 3000 V 3250 3500 3750 4000 4250 4500 4750 5000 e e ConocoPhillips Alaska, Inc. Drill Site 2P 447 slot #447 Meltwater North Slope, Alaska PRO P 0 S ALL I S TIN G by Baker Hughes INTEQ Your ref Our ref License 2P-447 Version #8.B prop4476 Date printed Date created Last revised 28-Aug-2003 22-Feb-200l 25-Aug-2003 Field is centred on 44l964.235,5869891.466,999.00000,N Structure is centred on 441964.235,5869891.466,999.00000,N Slot location is n70 3 8.522,w150 27 5.907 Slot Grid coordinates are N 5868862.924: E 443562.391 / Slot local coordinates are 1016.43 S 1606.10 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North ORIGiNAL e e ConocoPhillips Alaska, Inc. PROPOSAL LISTING Page 1 Drill Site 2P,447 Your ref 2P-447 Version #8.B Meltwater,North Slope, Alaska Last revised : 25-Aug-2003 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S DegllOOft Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.00 209.14 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 209.14 200.00 0.00 N 0.00 E 0.00 0.00 300.00 0.00 209.14 300.00 0.00 N 0.00 E 0.00 0.00 400.00 0.00 209.14 400.00 0.00 N 0.00 E 0.00 0.00 KOP 500.00 2.00 209.14 499.98 1.52 S 0.85 W 2.00 1. 75 600.00 4.00 209.14 599.84 6.09 S 3.40 W 2.00 6.98 700.00 6.00 209.14 699.45 13.71 S 7.64 W 2.00 15.69 800.00 8.00 209.14 798.70 24.35 S 13.58 W 2.00 27.88 900.00 10.00 209.14 897.47 38.01 S 21. 20 W 2.00 43.52 966.67 12.00 209.14 962.90 49.12 S 27.39 W 3.00 56.24 1066.67 15.00 209.14 1060.13 69.51 S 38.76 W 3.00 79.58 1166.67 18.00 209.14 1156.00 94.31 S 52.59 W 3.00 107.98 1266.67 21.00 209.14 1250.25 123.46 S 68.84 W 3.00 141. 36 1366.67 24.00 209.14 1342.63 156.88 S 87.48 W 3.00 179.62 1376.93 24.31 209.14 1352.00 160.55 S 89.52 W 3.00 183.82 Base Permafrost 1466.67 27.00 209.14 1432.88 194.48 S 108.44 W 3.00 222.67 1566.67 30.00 209.14 1520.75 236.15 S 131. 68 W 3.00 270.38 1666.67 33.00 209.14 1606.01 281.78 S 157.12 W 3.00 322.62 1766.67 36.00 209.14 1688.41 331. 24 S 184.70 W 3.00 379.26 1866.67 39.00 209.14 1767,74 384.41 S 214.35 W 3.00 440.13 1966.67 42.00 209.14 1843.77 441.12 S 245.97 W 3.00 505.06 2066.67 45.00 209.14 1916.30 501.24 S 279.49 W 3.00 573.89 - 2117.85 46.54 209.14 1952.00 533.27 S 297.35 W 3.00 610.57 Base West Sak 2166.67 48.00 209.14 1985.12 564.58 S 314.81 W 3.00 646.42 2266.67 51. 00 209.14 2050.06 630.99 S 351. 84 W 3.00 722.45 2305.95 52.18 209.14 2074.47 657.87 S 366.83 W 3.00 753.24 EOC 2500.00 52.18 209.14 2193.46 791.75 S 441. 48 W 0.00 906.52 2714.51 52.18 209.14 2325.00 939.75 S 524.01 W 0.00 1075.97 9 5/8" CSG 2836.82 52.18 209.14 2400.00 1024.13 S 571.06 W 0.00 1172.58 C80 3000.00 52.18 209.14 2500.06 1136.71 S 633.83 W 0.00 1301. 48 3500.00 52.18 209.14 2806.66 1481. 67 S 826.18 W 0.00 1696.45 3746.80 52.18 209.14 2958.00 1651. 94 S 921.13 W 0.00 1891. 40 C50 4000.00 52.18 209.14 3113.26 1826.63 S 1018.54 W 0.00 2091. 41 4214.83 52.18 209.14 3245.00 1974.85 S 1101.18 W 0.00 2261.11 C40 4459.45 52.18 209.14 3395.00 2143.61 S 1195.29 W 0.00 2454.34 C37 4500.00 52.18 209.14 3419.86 2171.59 S 1210.89 W 0.00 2486.37 - 5000.00 52.18 209.14 3726.47 2516.55 S 1403.24 W 0.00 2881. 33 5500.00 52.18 209.14 4033.07 2861. 51 S 1595.59 W 0.00 3276.30 5912.48 52.18 209.14 4286.00 3146.09 S 1754.27 W 0.00 3602.13 T7 - 6000.00 52.18 209.14 4339.67 3206.47 S 1787.94 W 0.00 3671.26 6500.00 52.18 209.14 4646.27 3551.43 S 1980.29 W 0.00 4066.22 7000.00 52.18 209.14 4952.87 3896.39 S 2172.64 W 0.00 4461.19 7057.88 52.18 209.14 4988.36 3936.32 S 2194.91 W 0.00 4506.91 5 1/2" X 3 1/2" XO 7257.88 52.18 209.14 5111.00 4074.30 S 2271.84 W 0.00 4664.89 T4.1(Top Cairn) 7500.00 52.18 209.14 5259.47 4241. 35 S 2364.99 W 0.00 4856.15 7657.42 52.18 209.14 5356.00 4349.95 S 2425.55 W 0.00 4980.50 2P-447 Top Berm Tgt 22 Jul 03 7867.79 52.18 209.14 5485.00 4495.09 S 2506.48 W 0.00 5146.68 T2 (Base Bermuda) 7937.91 52.18 209.14 5528.00 4543.47 S 2533.46 W 0.00 5202.07 C35 (Top Albian) - 8000.00 52.18 209.14 5566.07 4586.30 S 2557.34 W 0.00 5251.11 All data is in feet unless otherwise stated. Coordinates from slot #447 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level) . Bottom hole distance is 5296.76 on azimuth 209.14 degrees from wellhead. Total Dogleg for wellpath is 52.18 degrees. Vertical section is from wellhead on azimuth 209.14 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ORIGINAL e e ConocoPhillips Alaska, Inc. Drill Site 2P,447 Meltwater,North Slope, Alaska PROPOSAL LISTING Page 2 Your ref 2P-447 Version #8.B Last revised : 25-Aug-2003 Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth R E C TAN G U L A R COO R DIN ATE S Dogleg Deg/lOOft Vert Sect 8057.79 52.18 209.14 5601. 51 4626.17 S 2579.57 W 0.00 5296.76 TD, Csg Pt. All data is in feet unless otherwise stated. Coordinates from slot #447 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 5296.76 on azimuth 209.14 degrees from wellhead. Total Dogleg for wellpath is 52.18 degrees. Vertical section is from wellhead on azimuth 209.14 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ORIGINAL e e ConocoPhillips Alaska, Inc. Drill Site 2P,447 Meltwater,North Slope, Alaska PROPOSAL LISTING Page 3 Your ref 2P-447 Version #8.B Last revised : 25-Aug-2003 Comments in wellpath -------------------- -------------------- MD TVD Rectangular Coords. Comment ----------------------------------------------------------------------------------------------------------- 400.00 400.00 0.00 N 0.00 E KOP 1376.93 1352.00 160.55 S 89.52 W Base Permafrost 2117.85 1952.00 533.27 S 297.35 W Base West Sak 2305.95 2074.47 657.87 S 366.83 W EOC 2714.51 2325.00 939.75 S 524.01 W 9 5/8" CSG 2836.82 2400.00 1024.13 S 571. 06 W C80 3746.80 2958.00 1651.94 S 921.13 W C50 4214.83 3245.00 1974.85 S 1101.18 W C40 4459.45 3395.00 2143.61 S 1195.29 W C37 5912.48 4286.00 3146.09 S 1754.27 W T7 7057.88 4988.36 3936.32 S 2194.91 W 5 1/2" X 3 1/2 " XO 7257.88 5111. 00 4074.30 S 2271. 84 W T4.1(Top Cairn) 7657.42 5356.00 4349.95 S 2425.55 W 2P-447 Top Berm Tgt 22 Jul 03 7867.79 5485.00 4495.09 S 2506.48 W T2 (Base Bermuda) 7937.91 5528.00 4543.47 S 2533.46 W C35 (Top Albian) 8057.79 5601.51 4626.17 S 2579.57 W TD, Csg Pt. Casing positions in string 'A' ------------------------------ ------------------------------ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 O.OON O.OON O.OOE 2714.51 2325.00 O.OOE 8057.79 5601.51 939.75S 4626.178 524.01W 9 5/8" CSG 2579.57W 3 1/2" CSG Targets associated with this wellpath ------------------------------------- ------------------------------------- Target name Geographic Location T.V.D. Rectangular Coordinates Revised ----------------------------------------------------------------------------------------------------------- 2P-447 Top Berm Tgt 441104.000,5864532.000,999.00 5356.00 4349.95S 2425.55W 19-5ep-2002 ORIGINAL e . ConocoPhillips Alaska, Inc. Drill Site 2P 447 slot #447 Meltwater North Slope, Alaska PRO P 0 S ALL I S TIN G by Baker Hughes INTEQ Your ref Our ref License 2P-447 Version #8.B prop4476 Date printed Date created Last revised 28-Aug-2003 22-Feb-2001 25-Aug-2003 Field is centred on 441964.235,5869891. 466,999.00000, N Structure is centred on 441964.235,5869891.466,999.00000,N Slot location is n70 3 8.522, w150 27 5.907 Slot Grid coordinates are N 5868862.924, E 443562.391 Slot local coordinates are 1016.43 S 1606.10 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North ORIGJNAL e e ConocoPhil1ips Alaska, Inc. PROP05AL LI5TING Page 1 Drill 5ite 2P.447 Your ref 2P-447 Version #8.B Meltwater,North Slope, Alaska Last revised : 25-Aug-2003 Measured Inclin Azimuth True Vert R E C TAN GULAR G RID COO R D 5 G E o G RAP HIe Depth Degrees Degrees Depth C 0 0 R DIN ATE 5 Easting Northing C 0 OR DINATE 5 0.00 0.00 0.00 0.00 O.OON O.OOE 443562.39 5868862.92 n70 08.52 w150 27 05.91 100.00 0.00 209.14 100.00 O.OON o .OOE 443562.39 5868862.92 n70 08.52 w150 27 05.91 200.00 0.00 209.14 200.00 O.OON O.OOE 443562.39 5868862.92 n70 08.52 w150 27 05.91 300.00 0.00 209.14 300.00 O.OON o .OOE 443562.39 5868862.92 n70 08.52 w150 27 05.91 400.00 0.00 209.14 400.00 O.OON O.OOE 443562.39 5868862.92 n70 08.52 w150 27 05.91 500.00 2.00 209.14 499.98 1.525 0.85W 443561. 53 5868861. 41 n70 08.51 w150 27 05.93 600.00 4.00 209.14 599.84 6.095 3.40W 443558.95 5868856.86 n70 08.46 w150 27 06.00 700.00 6.00 209.14 699.45 13.715 7.64W 443554.64 5868849.28 n70 08.39 w150 27 06.13 800.00 8.00 209.14 798.70 24.355 13 . 58W 443548.63 5868838.68 n70 08.28 w150 27 06.30 900.00 10.00 209.14 897.47 38.015 21. 20W 443540.91 5868825.08 n70 08.15 w150 27 06.52 966.67 12.00 209.14 962.90 49.125 27.39W 443534.63 5868814.02 n70 08.04 w150 27 06.70 1066.67 15.00 209.14 1060.13 69.515 38.76W 443523.11 5868793.72 n70 07.84 w150 27 07.02 1166.67 18.00 209.14 1156.00 94.315 52.59W 443509.09 5868769.02 n70 07.59 w150 27 07.42 1266.67 21. 00 209.14 1250.25 123.465 68.84W 443492.62 5868740.00 n70 07.31 w150 27 07.89 1366.67 24.00 209.14 1342.63 156.885 87.48W 443473.73 5868706.73 n70 06.98 w150 27 08.43 1376.93 24.31 209.14 1352.00 160.555 89.52W 443471.65 5868703.07 n70 06.94 w150 27 08.49 1466.67 27.00 209.14 1432.88 194.485 108.44W 443452.48 5868669.30 n70 06.61 w150 27 09.03 1566.67 30.00 209.14 1520.75 236.155 131. 68W 443428.93 5868627.81 n70 06.20 w150 27 09.70 1666.67 33.00 209.14 1606.01 281. 7 85 157.12W 443403.14 5868582.38 n70 05.75 w150 27 10.43 1766.67 36.00 209.14 1688.41 331.245 184.70W 443375.19 5868533.13 n70 05.26 w150 27 11.23 1866.67 39.00 209.14 1767.74 384.415 214.35W 443345.14 5868480.20 n70 04.74 w150 27 12.08 1966.67 42.00 209.14 1843.77 441.125 245.97W 443313.09 5868423.73 n70 04.18 w150 27 12.99 2066.67 45.00 209.14 1916.30 501. 245 279.49W 443279.12 5868363.88 n70 03.59 w150 27 13.96 2117.85 46.54 209.14 1952.00 533.275 297.35W 443261. 01 5868331. 99 n70 03.28 w150 27 14.48 2166.67 48.00 209.14 1985.12 564.585 314.81W 443243.32 5868300.81 n70 02.97 w150 27 14.98 2266.67 51. 00 209.14 2050.06 630.995 351. 84W 443205.79 5868234.70 n70 02.32 w150 27 16.05 2305.95 52.18 209.14 2074.47 657.875 366.83W 443190.59 5868207.93 n70 02.05 w150 27 16.48 2500.00 52.18 209.14 2193.46 791. 755 441. 48W 443114.93 5868074.64 n70 00.74 w150 27 18.63 2714.51 52.18 209.14 2325.00 939.755 524.01W 443031.29 5867927.29 n70 59.28 w150 27 21. 01 2836.82 52.18 209.14 2400.00 1024.135 571.06W 442983.60 5867843.27 n70 58.45 w150 27 22.36 3000.00 52.18 209.14 2500.06 1136.715 633.83W 442919.97 5867731.19 n70 2 57.34 w150 27 24.17 3500.00 52.18 209.14 2806.66 1481. 675 826.18W 442725.02 5867387.73 n70 2 53.95 w150 27 29.71 3746.80 52.18 209.14 2958.00 1651.945 92l.13W 442628.79 5867218.21 n70 2 52.28 w150 27 32.45 4000.00 52.18 209.14 3113.26 1826.635 1018.54W 442530.06 5867044.28 n70 2 50.56 w150 27 35.25 4214.83 52.18 209.14 3245.00 1974.855 1101.18W 442446.30 5866896.71 n70 2 49.10 w150 27 37.63 4459.45 52.18 209.14 3395.00 2143.615 1195.29W 442350.92 5866728.69 n70 2 47.44 w150 27 40.34 4500.00 52.18 209.14 3419.86 2171.595 1210.89W 442335.11 5866700.83 n70 2 47.17 w150 27 40.79 5000.00 52.18 209.14 3726.47 2516.555 1403.24W 442140.15 5866357.38 n70 2 43.77 w150 27 46.33 5500.00 52.18 209.14 4033.07 2861. 515 1595.59W 441945.20 5866013 .93 n70 2 40.38 w150 27 51. 87 5912.48 52.18 209.14 4286.00 3146.095 1754.27W 441784.37 5865730.60 n70 2 37.58 w150 27 56.44 6000.00 52.18 209.14 4339.67 3206.475 1787.94W 441750.24 5865670.48 n70 2 36.99 w150 27 57.41 6500.00 52.18 209.14 4646.27 3551. 435 1980.29W 441555.29 5865327.03 n70 2 33.59 w150 28 02.95 7000.00 52.18 209.14 4952.87 3896.395 2172.64W 441360.33 5864983.58 n70 2 30.20 w150 28 08.48 7057.88 52.18 209.14 4988.36 3936.325 2194.91W 441337.77 5864943.82 n70 2 29.81 w150 28 09.12 7257.88 52.18 209.14 5111. 00 4074.305 2271.84W 441259.79 5864806.45 n70 2 28.45 w150 28 11.34 7500.00 52.18 209.14 5259.47 4241.355 2364.99W 441165.38 5864640.13 n70 2 26.81 w150 28 14.02 7657.42 52.18 209.14 5356.00 4349.955 2425.55W 441104.00 5864532 .00 n70 2 25.74 w150 28 15.76 7867.79 52.18 209.14 5485.00 4495.095 2506.48W 441021.97 5864387.50 n70 2 24.31 w150 28 18.09 7937.91 52.18 209.14 5528.00 4543.475 2533.46W 440994.63 5864339.33 n70 2 23.84 w150 28 18.87 8000.00 52.18 209.14 5566.07 4586.305 2557.34W 440970.42 5864296.68 n70 2 23.42 w150 28 19.56 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #447 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 5296.76 on azimuth 209.14 degrees from wellhead. Total Dogleg for wellpath is 52.18 degrees. Vertical section is from wellhead on azimuth 209.14 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ ORIGINAL e e ConocoPhillips Alaska, Inc. Drill Site 2P,447 Meltwater,North Slope, Alaska PROPOSAL LISTING Page 2 Your ref 2P-447 Version #8.S Last revised : 25-Aug-2003 Measured Inclin Depth Degrees Azimuth Degrees True Vert Depth R E eTA N G U L A R COO R DIN ATE S G RID COO R D S Easting Northing G E 0 G RAP HIe COO R DIN ATE S , 8057.79 52.18 209.14 5601.51 4626.17S 2579.57W 440947.89 5864256.98 n70 223.02 w150 28 20.20 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #447 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 5296.76 on azimuth 209.14 degrees from wellhead. Total Dogleg for wellpath is 52.18 degrees. Vertical section is from wellhead on azimuth 209.14 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ ORIGiNAL e e ConocoPhillips Alaska, Inc. Drill Site 2P,447 Meltwater,North Slope, Alaska MD TVD - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --- - - - - - - - - - - - - - - - -- -- - - - - - - - - - - - - - - - - -- - - - - - - - - - - - -- 400.00 1376.93 2117.85 2305.95 2714.51 2836.82 3746.80 4214.83 4459.45 5912.48 7057.88 7257.88 7657.42 7867.79 7937.91 8057.79 400.00 1352.00 1952.00 2074.47 2325.00 2400.00 2958.00 3245.00 3395.00 4286.00 4988.36 5111. 00 5356.00 5485.00 5528.00 5601. 51 TOp MD Top TVD PROPOSAL LISTING Page 3 Your ref 2P-447 Version #8.B Last revised : 25-Aug-2003 Comments in wellpath -------------------- -------------------- Rectangular Coords. O.OON 160.55S 533.27S 657.87S 939.75S 1024.13S 1651.94S 1974.85S 2143.61S 3146.09S 3936.32S 4074.30S 4349.95S 4495.09S 4543.47S 4626.17S Comment O.OOE KOP 89.52W Base Permafrost 297.3SW Base West Sak 366.83W EOC 524.01W 9 5/8" CSG 571. 06W C80 921.13W C50 1101.18W C40 1195.29W C37 1754.27W T7 2194.91W 5 1/2" X 3 1/2" XO 2271.84W T4.1(Top Cairn) 2425.55W 2P-447 Top Berm Tgt 22 Jul 03 2506.48W T2 (Base Bermuda) 2533.46W C35 (Top Albian) 2579.57W TD, Csg Pt. Casing positions in string 'A' ------------------------------ ------------------------------ Bot MD Bot TVD Rectangular Coords. Casing 0.00 0.00 O.OON O.OON Rectangular Coords. 524.01W 9 5/8" CSG 2579.57W 3 1/2" CSG 0.00 0.00 - - - - - - - - - - - - - - - - - - - -- - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- Target name O.OOE 2714.51 2325.00 O.OOE 8057.79 5601. 51 939.75S 4626.17S Targets associated with this wellpath ------------------------------------- ------------------------------------- T.V.D. Rectangular Coordinates Revised Geographic Location - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - -- - - - - - - - - -- 4349.95S 2425.55W 19-5ep-2002 2P-447 Top Berm Tgt 441104.000,5864532.000,999.00 5356.00 Ri G!NAL Compan~': Field: Reference Site: Reference Well: Reference Wcllparh: - - taaker Hughes IncorporaA Anticollision Report ConocoPhillips Alaska, Inc. Meltwater 2P Pad 447 2P-447 Vers#8b NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD + Stations Interval: 25.00 ft Depth Range: 0.00 to 8057.79 ft Maximum Radius: 5280.00 ft Survey Program for Definitive Wellpath Date: 8/12/2003 Validated: No Planned From To Survey ft ft 0.00 8057.79 Planned: 2P-447 Vers#8b V6 Summary --. . ... <~,--------' Offset Wellpath --.;';,. --+2.:..> Site Well .., Wellpath 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad 2P Pad Meltwater North#1 Meltwater South #1 MWN#2 MWN#2 406 414 415 415 416 417 419 420 422 422 424 427 429 431 432 434 438 441 443 445 448 448 448 449 451 MWN#1 MWS#1 MWN#2 MWN#2 2P-406 Vers#2.A V2 Pia 2P-414 Vers#3a V1 Plan 2P-415 VO 2P-415A VO 2P-416 Version#O.A VO 2P-417 VO 2P-419 Vers#3.A V1 Pia 2P-420 VO 2P-422 V7 422A VO 2P-424 Vers#3.a V1 Pia 2P-427 VO 2P-429 VO 2P-431 V1 2P-432 Version#4,b V7 2P-434 Vers#9b V1 Plan 2P-438 VO 2P-441 VO 2P-443 Vers#3 V1 Plan: 2P-445 Vers#4 VO Plan: 2P-448 V2 2P-448A VO 2P-448PB1 VO 2P-449 Vers#6.b V1 Pia 2P-451 VO MWN#1 VO MWS#1 VO MWN#2 VO MWN#2A VO ... Date: 8/28/2003 Time: 16:21 :01 'aJ.:e: I , ; Co-ordinalc(:'IiE) ~cfercnce: Well: 447, True North ! Vertical (TVI» I~eferellce: Doyon 141 (0Id2) 252.0 ! i Db: Oracle ! .. ... .. u... . .__u_ - --.. ..--..j Reference: Principal Plan & PLANNED PROGRAM Error Model: ISCWSA Ellipse Scan Method: Trav Cylinder North Error Surface: Ellipse Version: 2 Tootcode Tool Name MWD+SAG MWD + Sag correction Reference Offset ctr-Ctr No-Go Allowable MD MD Distance Area Deviation Warning ft ft ft ft ft " 420.94 425.00 820.10 7.87 812.23 Pass: Major Risk 464.88 475.00 660.37 8.73 651.63 Pass: Major Risk 299.95 300.00 640.25 4.90 635.35 Pass: Major Risk 299.95 300.00 640.25 4.90 635.35 Pass: Major Risk 421.81 425.00 619.82 7.87 611.95 Pass: Major Risk 421.81 425.00 602.64 7.65 594.99 Pass: Major Risk 374.96 375,00 560.94 6.55 554.39 Pass: Major Risk 444.30 450.00 541.33 7.56 533.76 Pass: Major Risk 399.90 400.00 500.30 6.73 493.56 Pass: Major Risk 399.90 400.00 500.30 6.73 493.56 Pass: Major Risk 399.98 400.00 460.39 7.26 453.13 Pass: Major Risk 491.29 500.00 400.89 8.38 392.51 Pass: Major Risk 423.00 425.00 362.37 7.45 354.92 Pass: Major Risk 446.48 450.00 318.01 7.55 310.46 Pass: Major Risk 470.03 475.00 300.45 8.81 291.64 Pass: Major Risk 470.65 475.00 260.38 8.82 251.56 Pass: Major Risk 951.33 975.00 178.04 18.80 159.23 Pass: Major Risk 448.60 450.00 120.01 7.82 112.19 Pass: Major Risk 744.06 750.00 80.39 12.99 67.40 Pass: Major Risk 573.05 575.00 40.21 10.37 29.84 Pass: Major Risk 475.34 475.00 22.92 8.50 14.42 Pass: Major Risk 475.34 475.00 22.92 8.50 14.42 Pass: Major Risk 475.34 475.00 22.92 8.50 14.42 Pass: Major Risk 374.99 375.00 40.89 6.82 34.07 Pass: Major Risk 325.00 325.00 80.62 5.50 75.12 Pass: Major Risk 8048.50 5150.00 3478.93 249.67 3229.26 Pass: Major Risk Out of range 500.00 525.00 4274.80 8.61 4266.19 Pass: Major Risk 2414.52 5650.00 4057.71 103.24 3954.47 Pass: Major Risk ORIGI~JAL e e MEL TW A TER - DRILLING HAZARDS SUMMARY 12 1-4" Open Hole & 9 5/8" Surface Casing Interval Event Risk level MitiQation Strateav I Continaency Broach of conductor Low Monitor cellar continuouslv durina interval Gas Hydrates Low If observed - control drill, reduce pump rates, reduce drilling fluid temperatures, additions of Lecithin Running sands & gravel Moderate Maintain planned mud parameters, Increase mud weight/viscosity, Use weighted sweeps, monitor fill on connections Drill surface hole into shallow Low Do not exceed the surface hole TD as detailed pressured interval- C-80 in the individual well plans, ensure that all charged stands (in the derrick or in the hole) are accounted for at all times Hole swabbingffight hole on Moderate Circulate hole clean prior to trip, proper hole trips filling (use of trip sheets), pumping out of hole as needed Stuck surface casing Low Clean the hole before running casing, pump hiQh density hiQh viscosity sweeps, wiper trip Stuck pipe Low Keep hole clean, use high density high viscosity sweeps, keep pipe moving/rotating with pumps on whenever possible Lost circulation Low Keep hole clean. If losses occur - reduce pump rates and mud rheoloav, use LCM co ./ r/ I 8 Iii' Open Hole & 5 Vi' x 3 Vi' Production Casing Interval Event Drill through a shallow pressured interval: C-80 to C-37 Insufficient or undetermined LOT Risk level Moderate Moderate High ECD / Tight hole on trips/ Swabbing Moderate Differential sticking Moderate Barite sa Lost circulation Low High Miti ation Strate I Contin enc Carry out well control drills. Kill fluid stored on location, contingency 7" casing string on location, hei htened awareness Importance of LOT communicated to all parties, all parties familiar with LOT procedure. Test will be carried out until leak off is observed or to an FIT of 18 MW e uivalent Condition mud & clean hole prior to trips. Monitor ECDs with PWD tool while drilling across reservoir interval. Hole cleaning best practices. Backream out on trips as a last resort, proper hole filling (use of trip sheets Keep hole clean, periodic wiper trips, keep pipe movin /rotatin with urn s on whenever ossible Good drillin ractices as documented in well Ian Pretreat mud before drilling reservoir section, keep hole clean - use PWD to monitor hole cleaning. If losses occur - reduce pump rates and mud rheolo ,use LCM ./ Oi~lGINAL Meltwater Drilling Hazards Summary Prepared by Philip Hayden 9/112003 Rig: Doyon 141 Location: Kuparuk (Meltwater) Client: ConocoPhillips Alaska, Inc. Revision Date: 8/27/2003 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com < TOC at Surface Previous Csg. < 16",62.6#, H-40 grade Welded Connection at 108 ft. MD < Base of Permafrost at 1,377 ft. MD (1,352 ft. TVD) < Top of Tail at 1,400 ft. MD < 95/8", 40.0#, L-80 grade BTC, AB Modified in 12 1/4" OH TO at 2,715 ft. MD (2,325 ft. TVD) Mark of Schlumberger A 2P-447 CemCADE" Preliminary Job Design 9518" Surface Preliminary Job Design based on limited input data. For estimate purposes only. Volume Calculations and Cement Systems (Volumes are based on 450% excess in the permafrost and 45% excess below the permafrost. Top of tail slurry is designed to be 23' below base of permafrost.) Lead Slurrv (minimum pump time 215 min.) ArcticSet Lite @ 10.7 ppg -4.28 ft3/sk 3 0.7632 ft 1ft x (108') x 1.00 (no excess) = 0.3132 ft31ft x (1377' -108') x 5.50 (450% excess) = 0.3132 ft3/ft x (1400' - 1377') x 1.45 (45% excess) = 82.4 ft3 + 2186 ft3+ 10.4 ft3 = 2278.8 ft3 14.28 ft3/sk = Round up to 533 sks 82.4 ft3 2186 ft3 10.4 ft3 2278.8 ft3 532.4 sks Have 410 sks of additional Lead on location for Top Out stage, if necessary. Tail Slurrv (minimum pump time 157 min.) LiteCRETE @ 12.0 ppg - 2.28 ft3/sk 0.3132 ft31ft x (2715' -1400') x 1.45 (45% excess) = 0.4257 ft31ft x 80' (Shoe Joint) = 597.2 ft3 + 34.1 ft3 = 631.3 ft3¡ 2.28 ft3/sk = Round up to 277 sks 597.2 ft3 34.1 ft3 631.3 ft3 276.9sks BHST = 5rF, Estimated BHCT = 74°F. (BHST calculated using a gradient of 2.6°F/100 ft. below the permafrost) PUMP SCHEDULE Stage Pump Rate (bpm) Stage Yolume Cumulative Stage Time Time (min) (bbn (min) CW100 5 10 2.0 2.0 Pressure test lines 10.0 12.0 CW100 5 30 6.0 18.0 MudPUSH II 6 40 6.7 24.7 Drop Bottom Plug 4.0 28.7 ASIII-Lite 7 406 58.0 86.7 LiteCRETE 5 112 22.4 109.1 Drop Top Plug 4.0 113.1 Water 5 20 4.0 117.1 Switch to rig 4.0 121.1 Displacement 7 160 22.9 144.0 Bump Plug 3 20 6.7 150.7 MUD REMOVAL Recommended Mud Properties: 9.6 ppg, Pv < 15, Tv < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 10.5 ppg MudPUSH* XL, Pv? 17-20, Tv ? 20-25 Centralizers: Recommend 1 per joint across zones of interest for proper cement placement. RIGINAL Rig: Doyon 141 Location: Kuparuk (Meltwater) Client: ConocoPhillips Alaska, Inc. Revision Date: 8/29/2003 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6226 email: martin13@slb.com Previous Csg. < 9 5/8", 40.0#, L-80 grade BTC, AB Modified at 2,715 ft. MD < 51/2",15.5#, L-80 grade BTC, AB Modified in 8 1/2" OH < Top ofTail at 6,758 ft. MD < X-over at 7,058 ft. MD < Top of Cairn Fm. at 7,258 ft. MD < 3 1/2", 9.3#, L-80 grade EUE, 8rd Modified in 8 1/2" OH TO at 8,058 ft. MD (5,601 ft. TVD) Mark of Schlumberger .. 2P-447 CemCADE" Preliminary Job Design 51/2" x 31/2" Production Casing umberger Preliminary Job Oesign based on limited input data. For estimate purposes only. Volume Calculations and Cement Systems Volumes are based on 75% excess. Top of tail slurry is designed to be 300' above casing X-over. Tail Slurrv (minimum thickening time 145 min.) 12.5 ppg LiteCRETE, 1.94 ft3/sk 0.2291 ft3/ft x 300' x 1.75 (75% excess) = 0.3272 ft3/ft x (8058' - 7058') x 1.75 (75% excess) = 0.0488 ft3/ft x 60' (Shoe Joint) = 120.3 ft3 + 572.6 ft3 + 2.9 ft3 = 695.8 ft3/1.94 ft3/sk = Round up to 359 sks 120.3 ft3 572.6 ft3 2.9 ft3 695.8 ft3 358.7 sks BHST = 142°F, Estimated BHCT = 121°F. (BHST calculated using a gradient of 2.6°F/100 ft. below the permafrost) PUMP SCHEDULE Stage Pump Rate (bpm) Stage Yolume Cumulative Stage Time Time (min) (bb!) (min\ CW100 5 10 2.0 2.0 Pressure test lines 10.0 12.0 CW100 5 50 10.0 22.0 Drop Bottom Plug 5.0 27.0 MudPUSH XL 6 30 5.0 32.0 Tail Slurry 7 124 17.7 49.7 Drop Top Plug 5.0 54.7 Displacement 8 161 20.1 74.8 Bump Plug 3 15 5.0 79.8 MUD REMOVAL Recommended Mud Properties: 9.6 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 11.0 ppg MudPUSH* XL, Pv ? 22-25, Ty ? 37-39 Centralizers: Recommend 1 per joint 5-1/2" casing and 1.5 per joint across the 3-112" casing to aide in mud removal and good isolation. ORIGiNAL Meltwater 2P-447 I.ctor Proposed Completion Schematic 3-1/2" Completion String 30" x 16" 62.6# @ +1- 108' MD (Insulated) Depths are based on Doyon 141 RKB Surface csg. 95/8" 40.0# L-80 BTC +/- 2715' MD 12325' TVD 5 Yo" 15.5# L-80 BTCM x 3 Yo" 9.3# L-80 EUE8RD Mod crossover at +1- 7058' MD I 4988' TVD Future Perforations Production csg 5 Yo" 15.5# L-80 BTCM x 3 Yo" 9.3# L-80 EUE8RD Mod +/- 8058' MD I 5602' TVD I 3 Yo" FMC Gen 5 Tubing Hanger, 3 Yo" L-80 EUE8RD Mod pin down 3 Yo" 9.3# L-80 EUE8RD Mod Spaceout Pups as Required 3 W' 9.3# L-BO EUE8RD Mod Tubing to Surface 3 W' Camco 'DS' nipple wI 2.875" No-Go Profile. 3 Yo" x 6' L-80 handling pups installed above and below, EUE8RD Mod, set at +/- 500' MD 3 Yo" 9.3# L-80 EUE8RD Mod tubing to landing nipple 3 Yo" x 1" Camco 'KBG-2-9' mandrel wI shear valve, pinned for 3000 psi shear (casing to tubing differential), 3 W' x 6' L-80 handling pups installed above and below, EUE8RD Mod 3 Yo" Baker 'CMU' sliding sleeve wI 2.813" Cameo OS profile, EUE8RD Mod box x pin. 3 Yo" x 6' L-80 EUE8RD Mod handling pup installed above 3 W' Camco 'D' nipple w/2.75" No-Go profile. 3 W' x 16' L-BO EUE8RD Mod spacaeout pup installed above, 3 Yo" x 6' handling pup installed below 3 Yo" Baker 80-40 GBH-22 casing seal assembly w/15' stroke, 3 W' L-80 EUE8RD Mod box up, 3 Yo" x 6' L-80 EUE8RD Mod handling pup installed on top Baker Seal Bore Extension, 5 W' BTCM x 3 Yo" EUE8RD Mod SBE set at +1- 200' MD above the top of the Bermuda interval (or 200' MD above the Cairn if present) ORIGINAL 08/27103 e . U T 5000 Dollars / O·CHAœ :::=::-'=::'''~g~~.dt'¥~ MEMO _80000 a. 2 7 2 5 7111 ~O 5 q 1:0 ~. .00 .1.1.1. 2. e . . TRANSMITAL LETTER CHECKLIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME !::R¿¿ z,p- t/c.f7 PTD# 2-0.3 - / s-t-f CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well --' Permit No, API No. . (If API number Production should continue to be reported as last two (2) digits a function· of the 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 . hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from records, data and logs acquired for well (name on permit). SPACING The 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. (Companv Name) assumes the liability of any protest to the spacing . exception that may occur. DRY DITCH All dry ditch sample sets submitted to the 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 ajody\templates 30 00 W 150 28 00 W t:t-·, ~ '~..:.. c) ~~' (-:'. ·..."',:t~:..::-. .. 150 26 orFw . "...,.-. .:~'-..~._--.._..~...... ./) -.............. ~ ~......., <t.:::. ~~ 2P-420 ,- ',,- ~ rÞ -""", rt5' ..........., >\ \ \~\)\) . I '\ ffJ I \<§'J \~ ~.. - ~, I , I J-." ./ fJ' ~ XÝ"ð <b /,y>.% ç¿, /-. '~~ç I // ~ 4,Xx;¡ 7- -Q I ,/~ /' <b ......... / ~-, ..,/0/ 'ß ~~4a 'ß ~ ,.yfJ'0....p \\~.. \~ " !:) _\.~<;:F J,I)O~ . .1,500 \ \~0 4500 saM N ~ KRU 2P-447 Feet 440,000 I , 2,000 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, MELTWATER OIL - 490140 PTD#: 2031540 Administration Appr Date . 9/3/2003 Engineering Appr Date ~5/2003 Geology Appr SFD Date 9/3/2003 Company CONOCOPHILLlPS ALASKA INC 1 P~(rTJitfee attaçhe~t 2Leas~numberappropriate 3 UniqUe weltnam~and O~rTJb_e( 4 WeB JOCÇIt~d ina definej:! J)ool_ 5 WeJI JQCÇlt~d proper _distance from driJlin9 unitb_oundary_ 6 WeB JOCÇIt~d proper _distance_ from otber wells_ 7 Suffiçientacreage ayailable in_drilJiOg unit 8 Itd~viated. is weJlbore plaUncJuj:!ed 9 Qper.ator onl}' affected party _ 10 _OJ)er_ator bas_appropriateJlond inJorce 11 P~(rTJit can be iss~ed witbout conservaJion order_ 12 P~(rTJit ca[1 be iss~ed witbout ad_rTJini!!t(ative_approvaJ 13Ca[1 permit be approv~d befon¡ _15-day_ wajt 14 WellJoCÇIt~d within area and_strata authQrized byJ[1jectioo Ord~( # (putlO# in_comm.e[1tsJ-{For 15AJI wells_witnin _1L4_mite.area_of (eyiew id~ottfied (FO( !!ervic~ welJ on I}'). 16 Pre-produ.ced injector; jjuration_of pre-J)rojjuctioo I~ss than 3 montbs (For _service welt only) 17 ACMP_ Finding _of Consistency has been J~sued_ for_ tbis proleçt Initial ClasslType Y~s Yes Y~s Y~s Y~s Y~s Y~s Y~s Y~s Y~s Y~s Yes Y~s Yes Y~s No NA 18Co[1duçtor st(ingprov[ded 19Swface _CÇl~ing_ protecJ~ alLknown USDW!! 20CMT vot adequ_ate_ to çirc_utate _ on conductor_ & !!urt q5g 21CMT v_ot adequ_ate to tie-in Jong _string to.surf C!ìg 22 _CMTwill coyer_all koown,pro_ductiYe borizons 23 _Casi[1g de_si-9n!! adeQuate fo( C,_T. B_&_permafrpst 24 Mequatetankageor re_serve pit 25 JtaJe-d(ilt has_a_ tOA03 for abandonment be~o approved 26 Ajjequate well bore !!eparation J)ropo!!ed_ 27 Jfdjvel"ter required, does itmeetreguJa_tions_ 28 DrilJiog fluid prograrTJ schemattc_&_ equip Jistadequat~_ 29 _BOPEs. _ dp _they meet reguJation 30 _B.QPE-PJess raJi[1g appropÖate; _test to _(pu_t P!!ig in _comment!!)_ 31 _C_hokemanifold cOrTJpJie~ w/APLR~-53 (May 84)_ 32 Work will OCCU( withoutoperation _sbutdown_ 33 Js presence of H2S gas prob_able _ 34 MeçbaniCÇILcoodJtto[1 pt wells wiJhin ,ll.OR yerified (For_s_ervice wel] only)_ -- 35 P~(rTJit ca[1 be iss~ed wfo_ hydr:ogen_ s_utfide meaSu(es . 36 _Data_ preseoted on pote_ntial oveJRres_suœ _zones _ 37 _S.eismic_analysjs. of sbaJlow gas_zooes_ 38S.eabed conditioo s~rvey Jif Off-shp(e) 39 . Conta.ct nameLpnoneforweekly progress.reports [exploratory _only] . . . Geologic Engineering Date Public Date Commissioner: Date: Commissioner: Commissioner ~~ CÀ.~~"'~ ~ ~~ , "" Y~s NA Y.es No Y~s Y.es Yes NA Y.es Y~s Y.es Y~s Y.es Y.es Y.es No_ Y~s Y.es Y.es NA NA NA Well Name: KUPARUK RIV U MELT SER I PEND GeoArea 890 o o 2P-447 Unit Program SER On/Off Shore On Well bore seg Annular Disposal 11160 _ Gov_emed by CO -456: _10:a_c(e_spacjn-9. AI 0_2_1 _ KRU 21='-438 - - _ This weJI_name o(iginall}' permitted asJ20t-t04ì issued 6/5/01. t-Jew 6HL is _187'6' S &3096' E ot prio(. . _ M aquifers ex.empted 40 cm H7_.102(b)(3) _ ,ll.nnula( di!!ppsal may be propo_sed. _ _ Rig js_e_quippedwith st.eelJ)il!ì. _ No re!!eJ'.(e.pjtptanoed, Waste to approved annulu!! or_dispos_al well, _ E'roximitv- analy!!i!! perfp(11)edand trav.eljn~Lcyl[nder.pJot provided, _ MaxjmurTJ aotiçipated fp(rTJaJion pressure.at TO 7.9 EMW. _ MW pJanned 9.6._ _ Some loca]ized _sballow pr:es!!ure_s _have beeo seen PO 3 welJs, NeaœstweU (2P:4.38). h.as C-80 £MW ot 9.8. _ _ M.A.SI=' ca.lcuJate.d_at 1646 psi, 35QO_psLappcopriate. PPCousuaJly t.ests to. 5-000 psi. _ E'rod~ction s_tringcemenJi[1g of 2P:438 appears adequate for [solatio_n, _Higb annula( pre~sur.es in_2P43t 45t& 438de[1ote sorTJe risk otshallow, bigh_ pressur.e, HignesJ _ _ expected_ is 1 t Z ppg_ EMW._ Operator rat.es Ösk_as .low to moderate. PotentiaL and mjtigation measureS_ are _ ad.dresse_dJn the Drilling_Ha~ard!! Summary. Ut-JOER~RE_SSURED: expected pressur_eJn 6ermuda re!!erv:oir _ is 5.0: 7.9 ppg EMW, 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. **** REEL HEADER **** LDWG 04/03/22 AWS 01 **** TAPE HEADER **** LDWG 04/03/22 01 *** LIS COMMENT RECORD *** e ! ! ! !! !!! !!!!! !!! !!! LDWG File Version 1.000 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! Extract File: LISTAPE.HED TAPE HEADER MELTWATER UNIT MWD/MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 1 1 S. TUFT ON F. HERBERT MWD RUN 4 4 M. VALUCH F. HERBERT # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION(FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: # WELL CASING RECORD 1ST STRING 2ND STRING '"", ~~" ' ~~X~\'<\~ e c9 0,3 ~ } s tl j2c/fJ- RECEIVED t.1,~p ? 6 ?O,04 . .. ". "- ~...U ,i.~"'ir f\:1 0 G f"A C .. /,,~{,;E.h!!H.I\ as wns. ommlSlfOn s"11r:horage 2P-447 501032046800 ConocoPhillips Alaska, Inc. BAKER HUGHES INTEQ 22-MAR-04 MWD RUN 2 MWD RUN 5 5 C. WONG D. GLADDEN 19 8N 7E 252.00 224.00 OPEN HOLE CASING BIT SIZE (IN) SIZE (IN) 16.000 12.250 9.625 DRILLERS DEPTH (FT) 108.0 2705.0 MWD RUN 3 3 G. SUTING F. HERBERT MWD RUN e e 8.500 6.125 7562.0 8015.0 # REMARKS: 3RD STRING PRODUCTION STRING 7.000 Tape Subfile: 1 PER CONOCOPHILLIPS ALASKA STANDING ORDER, THE GAMMA RAY CURVE FROM THIS LOG IS THE DEPTH REFERENCE FOR THIS WELL. AS SUCH, NO DEPTH SHIFTS HAVE BEEN APPLIED. INDIVIDUAL MWD RUN DATA WAS MERGED IN THE FIELD PRIOR TO DELIVERY FROM THE WELL SITE. SURFACE LOCATION: LAT: N 70 DEG 03' 8.522" LONG: W150 DEG 27' 5.907" LOG MEASURED FROM D.F. AT 252.0 FT. ABOVE PERM. DATUM (M.S.L.) . COMMENTS: (1) Baker Hughes INTEQ run 1 utilized a Multiple Propagation Resistivity (MPR) and Gamma Ray with Near Bit Inclination services from 108 - 2716 feet MD (108 - 2324 TVD). (2) No logging was done on run 2 due to a trip out of the hole to test BOPs. (3) Baker Hughes INTEQ run 3 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 2716 - 7050 feet MD (2324 - 5008 TVD). (4) Baker Hughes INTEQ run 4 utilized a Multiple Propagation Resistivity (MPR) and Gamma Ray with Drill Collar Pressure (DCP) services from 7050 - 7620 feet MD (5008 - 5336 TVD). (5) Baker Hughes INTEQ run 5 utilized the slimhole Advantage Porosity Logging Service (APLS) which includes the Optimized Rotational Density (ORD), Caliper Corrected Neutron (CCN), along with a NaviTrak II Annular Pressure tool and MPR Resistivity services from 7620 - 8015 feet MD (5336 - 5549 TVD). (6) 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: 2705 feet MD (2317 TVD) Depth of 9 5/8" Casing Shoe - Driller: 2705 feet MD (2317 TVD) (2) The interval from 2661 to 2716 feet MD (2291 - 2324 TVD) was not logged due to the presence of the 9 5/8" casing. (3) The interval from 7009 to 7050 feet MD (4982 - 5008 TVD) was logged up to 115.3 hours after being drilled due to a halt in drilling operations caused by severe weather conditions (phase 2 & phase 3) and a trip to test BOPs. (4) Run 4 utilized MPR & DCP tools only. No APLS bulk density or neutron porosity tools were used from 7050 - 7620 feet MD(5008 - 5336 TVD). (5) Depth of 7" Casing Shoe - Logger: 7558 feet MD (5304 TVD) Depth of 7" Casing Shoe - Driller: 7562 feet MD (5306 TVD) (6) The interval from 7972 to 8015 feet MD (5525 - 5549 TVD) was not logged due to sensor-bit offset at TD. $ 105 records... Minimum record length: 8 bytes e e Maximum record length: 132 bytes **** FILE HEADER **** LDWG .001 1024 *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! 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 108.0 STOP DEPTH 8015.0 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH $ # MERGED DATA SOURCE PBU TOOL CODE MWD MWD MWD MWD $ BIT RUN NO 1 3 4 5 MERGE TOP 108.0 2661. 0 7009.0 7562.0 MERGE BASE 2661.0 7009.0 7562.0 8015.0 # REMARKS: 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 2P-447 5.xtf 150 ConocoPhillips Alaska 2P-447 Meltwater Unit North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GR GR GRAM 0.0 e e RPD RPD RPD 0.0 RPM RPM RPM 0.0 RPS RPS RPS 0.0 RPX RPX RPX 0.0 RHOB RHOB BDCM 0.0 DRHO DRHO DRHM 0.0 PEF PEF DPEM 0.0 NPHI NPHI NPCKSM 0.0 ROP ROP ROPS 0.0 FET FET RPTH 0.0 MTEM MTEM TCDM 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 GAP I 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 BN/E 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: 833 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 108.000000 8015.000000 0.500000 feet **** FILE TRAILER **** Tape Subfile: 2 883 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** e LDWG .002 1024 *** LIS COMMENT RECORD *** !!!!!!!!!!!! ! ! ! !!!! LDWG File Version 1.000 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! Extract File: FILE011.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. 1 .2500 START DEPTH 106.0 STOP DEPTH 2661. 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 MPR GRAM $ BOTTOM) TOOL TYPE DIRECTIONAL MULT. PROP. GAMMA RAY RESIST. # 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): # 07-DEC-03 MSB 18655 8.25 MPR MEMORY 2716.0 106.0 2661.0 o .0 53.4 TOOL NUMBER DHA 7113 MPR 8028 SRIG 58017 12.250 108.0 Spud 9.10 .0 .0 200 .0 .000 .000 .000 .000 80.0 .0 .0 .0 .00 .000 e e .0 # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): o REMARKS: # BIT RUN 1 (MWD Run 1) . GR/MPR. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) RPCL - DEEP PHASE RESISTIVITY (OHMM) RPSL - MEDIUM PHASE RESISTIVITY (OHMM) RPCH - SHALLOW PHASE RESISTIVITY (OHMM) RPSH - EXTRA SHALLOW PHASE RESISTIVITY (OHMM) 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) NO LOGGING WAS DONE ON BIT RUN 2 (MWD Run 2). $ *** INFORMATION TABLE: CONS MNEM VALU ------------------------------ WDFN LCC CN WN FN COUN STAT 2P-447.xtf 150 ConocoPhillips Alaska 2P-447 Meltwater Unit 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 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: 52 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: 19 One depth per frame (value= 0) e e Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 12 Curves: Name Tool Code Samples Units Size Length 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 OHMM 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 OHMM 4 4 9 RASH MWD 68 1 OHMM 4 4 10 ROPS MWD 68 1 FPHR 4 4 11 RPTH MWD 68 1 MINS 4 4 12 TCDM MWD 68 1 DEGF 4 4 ------- 48 Total Data Records: 538 Tape File Start Depth Tape File End Depth Tape File Level spacing Tape File Depth Units 106.000000 2661.000000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 3 638 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** LDWG .003 1024 *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! LDWG File Version 1.000 !!!!!! !!! ! ! ! ! !!! ! !! Extract File: FILEOI2.HED FILE HEADER FILE NUMBER: RAW MWD Curves and BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD 3 log header data for each bit run in separate files. 3 .2500 START DEPTH 2661.0 STOP DEPTH 7009.0 e $ # 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. RES IS. 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): # e 13-DEC-03 MSB 18655 6.75 TC MEMORY 7050.0 2661.0 7009.0 o 50.4 53.7 TOOL NUMBER DHA 75787 CCN 71631 ORD 46894 MPR 6245 SRIG 92230 8.500 2705.0 LSND 10.60 .0 .0 200 .0 .000 .000 .000 .000 110.0 .0 .0 .0 Sandstone .00 .000 .0 o BIT RUN 2RR1 (MWD Run 3) . GR/MPR/oRD/cCN. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) 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 REMARKS: e e 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) NO LOGGING WAS DONE ON BIT RUN 2 (MWD Run 2) . $ # *** INFORMATION TABLE: CONS MNEM VALU ------------------------------ WDFN LCC CN WN FN COUN STAT 2P-447.xtf 150 ConocoPhi11ips Alaska 2P-447 Meltwater Unit 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 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 16 Curves: Name Tool Code Samples Units Size Length e e 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 OHMM 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 OHMM 4 4 9 RASH MWD 68 1 OHMM 4 4 10 BDCM MWD 68 1 G/C3 4 4 11 DRHM MWD 68 1 G/C3 4 4 12 DPEM MWD 68 1 BN/E 4 4 13 NPCK MWD 68 1 PU-S 4 4 14 ROPS MWD 68 1 FPHR 4 4 15 RPTH MWD 68 1 MINS 4 4 16 TCDM MWD 68 1 DEGF 4 4 ------- 64 Total Data Records: 1243 Tape File Start Depth 2661.000000 Tape File End Depth 7009.000000 Tape File Level Spacing 0.250000 Tape File Depth Units feet **** FILE TRAILER **** Tape Subfile: 4 1354 records. . . Minimum record length: 8 bytes Maximum record length: 4124 bytes **** FILE HEADER **** LDWG .004 1024 *** LIS COMMENT RECORD *** !!!!!!!!!!!!!! !!!!! LDWG File Version 1.000 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! Extract File: FILEOI3.HED FILE HEADER FILE NUMBER: RAW MWD Curves and BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD $ 4 log header data for each bit run in separate files. 4 .2500 START DEPTH 7009.0 STOP DEPTH 7562.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: 19-DEC-03 MSB 18655 6.75 MPR e 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 MPR GRAM $ BOTTOM) TOOL TYPE DIRECTIONAL MULT. PROP. GAMMA RAY RESIS. # 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: # e MEMORY 7620.0 7009.0 7562.0 o 59.1 53.7 TOOL NUMBER DHA 99030 MPR 97378 SRIG 5309 8.500 2705.0 LSND 11. 60 .0 .0 250 .0 .000 .000 .000 .000 104.0 .0 .0 .0 Sandstone .00 .000 .0 o BIT RUN 2RR2 (MWD Run 4) . GR/MPR. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWÐ-API) RPCL - DEEP PHASE RESISTIVITY (OHMM) RPSL - MEDIUM PHASE RESISTIVITY (OHMM) RPCH - SHALLOW PHASE RESISTIVITY (OHMM) RPSH - EXTRA SHALLOW PHASE RESISTIVITY (OHMM) 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 e e ------------------------------ WDFN LCC CN WN FN COUN STAT 2P-447.xtf 150 ConocoPhillips Alaska 2P-447 Meltwater Unit 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 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: 52 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: 19 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 12 Curves: Name Tool Code Samples Units Size Length 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 OHMM 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 OHMM 4 4 9 RASH MWD 68 1 OHMM 4 4 10 ROPS MWD 68 1 FPHR 4 4 11 RPTH MWD 68 1 MINS 4 4 12 TCDM MWD 68 1 DEGF 4 4 ------- 48 Total Data Records: 117 e e Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 7009.000000 7562.000000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 5 216 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** LDWG .005 1024 *** LIS COMMENT RECORD *** ! !!!!!!!!!!!! ! ! !!!! LDWG File Version 1.000 !!!!!!!!!!! ! ! ! ! !!!! Extract File: FILEOI4.HED FILE HEADER FILE NUMBER: RAW MWD Curves and BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD $ 5 log header data for each bit run in separate files. 5 .2500 START DEPTH 7562.0 STOP DEPTH 8015.0 # 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: 24-DEC-03 MSB 18655 4.75 SDN MEMORY 8015.0 7562.0 8015.0 o 55.9 59.8 # TOOL STRING (TOP TO VENDOR TOOL CODE DIR CCN ORD MPR GRAM $ BOTTOM) TOOL TYPE DIRECTIONAL CAL. COR. NEUTRON OPT. ROT. DENSITY MULT. PROP. RES IS. GAMMA RAY TOOL NUMBER DHA 18412 SDN 45227 SDN 45227 MPR 1033 SRIG 60365 # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): 6.125 7562.0 # BOREHOLE CONDITIONS e e 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: LSND 10.70 .0 .0 500 .0 .000 .000 .000 .000 118.0 .0 .0 .0 # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): Sandstone .00 .000 # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): .0 o # REMARKS: BIT RUN 3 (MWD Run 5) . GR/MPR/oRD/CCN. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) 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 2P-447.xtf 150 ConocoPhillips Alaska 2P-447 Meltwater Unit North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP GRAM RPCL ---------------------------------------------------- GRAM RPD GRAM RPCL 0.0 0.0 e e 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 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 16 Curves: Name Tool Code Samples Units Size Length 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 Om-1M 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 OHMM 4 4 9 RASH MWD 68 1 OHMM 4 4 10 BDCM MWD 68 1 G/C3 4 4 11 DRHM MWD 68 1 G/C3 4 4 12 DPEM MWD 68 1 BN/E 4 4 13 NPCK MWD 68 1 PU-S 4 4 14 ROPS MWD 68 1 FPHR 4 4 15 RPTH MWD 68 1 MINS 4 4 16 TCDM MWD 68 1 DEGF 4 4 ------- 64 Total Data Records: 130 Tape File Start Depth 7562.000000 Tape File End Depth 8015.000000 Tape File Level Spacing 0.250000 Tape File Depth Units feet **** FILE TRAILER **** Tape Subfile: 6 240 records... · . Minimum record length: Maximum record length: **** TAPE TRAILER **** LDWG 04/03/22 01 **** REEL TRAILER **** LDWG 04/03/22 AWS 01 Tape Subfile: 7 Minimum record length: Maximum record length: e e 8 bytes 4124 bytes 2 records... 132 bytes 132 bytes