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Home My WebLink About201-1331. 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: ESP Swap 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? 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): 9,405'N/A Casing Collapse Conductor N/A Production Liner 5,410psi OA Liner 7,500psi OB Liner 7,500psi 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: Wells Manager 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 4,214' 9,405' 4,214' 975 N/A MILNE POINT / SCHRADER BLUFF OIL 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: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT G-14 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 5/1/2025 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 & ADL0315848 201-133 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23031-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 112' 112' 6.4# / 13Cr-85 / JFE-Bear TVD Burst 5,504' 8,430psi MD N/A 8,430psi 7,240psi4,513' 4,215' 7,132' 112' 20" 7"7,097' 4-1/2"2,850' 9,348' See Schematic 2,377' See Schematic 2-7/8" 4,214'4-1/2" VTL, SLZXP & ZXP LTP and N/A 6,077 MD/ 4,087 TVD, 6,286 MD/ 4,172 TVD & 7,037 MD/ 4,476 TVD and N/A Todd Sidoti todd.sidoti@hilcorp.com 777-8443 9,405' Perforation Depth MD (ft): Noooo No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-225 By Gavin Gluyas at 1:51 pm, Apr 14, 2025 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.04.14 13:33:17 - 08'00' Taylor Wellman (2143) MGR18APR2025 DSR-4/17/25 10-404 A.Dewhurst 16APR25 * BOPE test to 2500 psi. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.18 18:35:23 -08'00'04/18/25 RBDMS JSB 042125 ESP Change-Out Well: MPU G-14 Well Name: MPU G-14 API Number: 50-029-23031-00 Current Status: Shut-in ESP Producer Pad: G-Pad Estimated Start Date: May 1st 2024 Rig: ASR Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 201-133 First Call Engineer: Todd Sidoti (907)-777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (O) (907) 947-9553 (M) AFE Number: Current Bottom Hole Pressure: 1345 psi @ 3,698 TVD ESP Pressure Gauge 12/20/23 – 7.0 PPG Maximum Expected BHP: 1345 psi @ 3,698’ TVD ESP Pressure Gauge 12/20/23 – 7.0 PPG MPSP: 975 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 63° @ 3,550’ MD Brief Well Summary: MPU producer G-14 was drilled and completed as a Schrader Bluff N, OA, and OB producer in 2001. The well is a dual lateral slotted liner producer in the OA and OB sands and completed with screens across the N sand. The well was last completed in July 2019 and ran until February 2020 at which point the well was SI due to suspected tubing leak. The subsequent leak detect log confirmed 1 BPM TxIA communication at 700 psi through 4 separate locations which appeared to be connection leaks. The TBG and ESP were replaced August 22, 2021 and an ESP packer was installed due to offset injectors over pressuring the block. MP G-14 ESP failed due to suspected broken shaft after an unplanned hard shut down on 10/9/2021. The ESP was replaced 11/30/2021. In May 2023 MPG-14 experienced a SI that caused the pump to lose efficiency and the FBHP started to climb from 800 to 1100 psi. In December 2023 the ESP died and was replaced. For 2024 the well was consistently drawn down to 650 psi and solids production increased. The ESP died in March 2025 and the purpose of this project is to replace it. Notes Regarding Wellbore Condition x The 7” production casing passed an MIT to 1,500 psig from 3,440’ MD on 8/19/2021. Objective: x Pull 2-7/8” Tubing String and Baker ESP. x Install new Baker ESP Non- Sundried work Slickline: 1. Pull bottom GLV leave open 2. Pull top GLV and dummy off Sundried Procedure (Approval Required to Proceed) Fullbore: 3. RU FB and PT lines to 3,000 psi. 4. Pump diesel spear followed by 250 bbls KWF (source water) down the tubing taking returns up the IA. 5. Confirm well is dead. 6. RD FB. ESP Change-Out Well: MPU G-14 7. Clear and level pad area in front of well. Spot rig mats and containment. 8. RD well house and flowlines. Clear and level area around well. 9. RU crane. Set BPV. ND Tree. Inspect the tubing hanger lift thread and note any damage. 10. NU BOPE. RD Crane. 11. Spot mud boat. RWO Procedure: 12. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 13. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well with KWF prior to pulling BPV. 14. Set TWC. 15. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “ASR 1 BOP Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 16. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ KWF as needed. 17. Rig up spoolers for ESP cable and cap string. 18. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. PUW was 38klbs and SO was 21klbs during installation. 19. Lay down tubing hanger. 20. Ensure to have handling equipment for pulling chrome TBG. Inspect and verify equipment. 21. POOH and lay down the 2-7/8” tubing while spooling ESP cable and capstring. Lay down ESP and motor. a. Inspect the connections b. Re-use existing TBG, Inspect the connections c. Note any sand or scale inside or on the outside of the ESP in WSR. d. The completion has the following amount of clamps: i. 95 Cross Collar Clamps ii. 5 Protectolizers iii. 2 Flat Guards 22. PU new ESP and RIH on 2-7/8” 6.5# 13-CR tubing. Set base of ESP assembly at ± 5,500’ MD. a. Review JFE Bear connection data sheet, Opt MU Torque – 2,040 ft-lbs b. Check ESP cable conductivity every 2,000’. Proposed Running Order a. Base of ESP centralizer @ ±5,500’ MD b. Motor gauge c. Baker Hughes Motor d. Tandem Gas Separator with gas avoider ESP Change-Out Well: MPU G-14 e. GINPSH Pump f. Baker Hughes Flex 27 g. Downhole gauge for discharge temperature and pressure. h. 1 joint of 2-7/8”, 6.5#, JFE Bear 13-Cr i. 2-7/8” XN (2.205” No-Go) Nipple on pups j. 1 joint of 2-7/8”, 6.5#, JFE Bear 13-Cr k. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV l. 2 joints of 2-7/8”, 6.5#, JFE Bear 13-Cr m. 2-7/8” Sandcatcher on pups n. ± XXX joints 2-7/8”, 6.5#, JFE Bear 13-Cr o. GLM, 2-7/8”x1”, OV installed with pups (setting depth +/- 200’ MD). p. +/- XXX joints, 2-7/8”, 6.5#, JFE Bear 13-Cr TBG 23. PU and MU the 2-7/8” tubing hanger with landing joint. Make the final splice of the ESP cable to the penetrator, MU the chemical injection line to the tubing hanger. Plug off any additional control line ports if present. 24. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 25. Set TWC. 26. RDMO ASR. Post-Rig Procedure: 27. RD mud boat. RD BOPE house. Move to next well location. 28. RU crane. ND BOPE. 29. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 30. Pull TWC. 31. RD crane. Move returns tank and rig mats to next well location. 32. Replace gauge(s) if removed. 33. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: TDF 2/27/2024 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 1/28/2024 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” TAM Port Collar @ 1,011’ MD 3 PBTD =9,405’(MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 2 6 & 7 8 & 9 10 & 11 14 4 & 5 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID =3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr-85 / JFE-Bear 2.441 Surface 5,504’ 1/4” Capstring Stainless Steel N/A Surface 5,504’ JEWELRY DETAIL No Depth Item 1 191’STA#2: GLM - 2-7/8"x 1" 13Cr BxB; DPSOV w/ BK-2 Latch 2 5,327’STA#1: GLM - 2-7/8"x 1" 13Cr BxB; Dummy w/ BK-2 Latch 3 5,385’ 2-7/8” XN Profile 2.313"w/ (2.205" No-Go) 4 5,439’ Bolt On Discharge Head: 5 5,410’ Zenith Ported Sub: 6 5,440’ Pump #2: 538PMSXD FLEX27 82 FER H6 12CRC 7 5,458’ Pump #1: 538PMSXD 20 GINPSHH H6 FER 12CRC 8 5,468’ Gas Separator: 9 5,473’ Intake: GPXARCINT FER H6 10 5,474’ Upper Tandem Seal: 11 5,481’ Lower Tandem Seal: 12 5,488’ Motor: 562XP 150/1505/61/6R 12CRC 13 5,499’ Motor Gauge: 14 5,502’ 2-3/8" EUE Centralizer: Bottom at 5,504’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 ESP Change-out by ASR #1 – 11/30/2021 ESP Change-out by ASR #1 –1/28/2024 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole _____________________________________________________________________________________ Revised By: TD F 4/11/2025 PROPOSED Milne Point Unit Well: MPU G-14 Last Completed: 1/28/2024 PTD: 201-133 28 30Slotted Liner Slotted Liner 29 27 TD =9,405’(MD) / TD = 4,210’(TVD) 20” 5 2 PBTD =9,405’(MD) / TD = 4,210’(TVD) Orig. KB Elev.:62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 4 8 9 & 10 11 & 12 15 6 & 7 7” 22 23 24 25 “OA” Lateral “OB” Lateral 26 Min ID = 3.985” 16 18 N Sands 17 19 20 21 Min ID = 3.907” 13 14 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr / JFE 2.441 Surface ±5,500’ JEWELRY DETAIL No Depth Item 1 ±XXX’STA#2:GLM –2-7/8" Side Pocket w/ OV Installed 2 ±X,XXX’ Tam Port Collar 3 ±X,XXX’ 2-7/8” Sandcatcher 4 ±X,XXX’STA#1:GLM –2-7/8" Side Pocket w/ Dummy 5 ±X,XXX’ 2-7/8” XN Profile (2.205" No-Go) 6 ±X,XXX’ Bolt On Discharge Head: 7 ±X,XXX’ Ported Discharge Head: 8 ±X,XXX’ Pump: 9 ±X,XXX’ Gas Separator: 10 ±X,XXX’ Gas Avoider: 11 ±X,XXX’ Upper Tandem Seal: 12 ±X,XXX’ Lower Tandem Seal: 13 ±X,XXX’ Motor: 14 ±X,XXX’ Motor Gauge 15 ±X,XXX’ 2-3/8" EUE Centralizer: Bottom at ±5,500’ 16 6,077’ 7” Halliburton VTL Packer (3.880” ID) 17 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 18 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 19 6,286’ 7” Baker SLZXP Packer 20 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 21 6,330’ 4-1/2” WLEG (3.958” ID) 22 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 23 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 24 7,028’ OB Lateral Tie Back Sleeve 25 7,037’ OB Lateral ZXP Liner Top Packer 26 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 27 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 28 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 29 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E –8/14/2001 Completed by Nabors 4ES –9/25/2001 ESP Repair by Nabors 3S –7/24/2008 ESP Repair by Nabors 4ES –8/24/2008 ESP Repair & Tbg Change by Doyon 16 –2/10/2013 ESP Change-out by ASR –7/22/2019 ESP Change-out by ASR #1 –11/30/2021 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30' Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ESP Swap Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,405'feet N/A feet true vertical 4,214'feet N/A feet Effective Depth measured 9,405'feet feet true vertical 4,214' feet 4,087, 4,172 & 4,476 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8"6.4 / 13Cr-85 / JFE-Bear 5,504' 3,724' Packers and SSSV (type, measured and true vertical depth)N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: 6,077, 6,286 & 7,037 VTL, SLZXP & ZXP LTP 323-683 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Brian Glasheen Brian.Glasheen@hilcorp.com 907-564-5277 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 270 Gas-Mcf MD 112' 100 Size 112' 4,513' 772 30068 0 00 256 measured TVD 4-1/2" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 201-133 50-029-23031-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025906, ADL0315848 MILNE POINT / SCHRADER BLUFF OIL Milne Point Unit G-14 Plugs Junk measured Length OB Liner 2,850' 2,377' Casing Conductor 4,150' 4,214' 9,348' 9,406' 2,377' 7,132'Surface Production OA Liner 20" 7" 4-1/2" 112' 7,097' 7,500psi 7,500psi 7,240psi 8,430psi 8,430psi 8,430psi 9,405' 4,214' Burst N/A Collapse N/A 5,410psi 7,500psi PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 9:28 am, Feb 29, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.02.28 10:14:04 - 09'00' Taylor Wellman (2143) RBDMS JSB 022924 DSR-3/4/24WCB 2024-07-08 _____________________________________________________________________________________ Revised By: TDF 2/27/2024 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 1/28/2024 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” TAM Port Collar @ 1,011’ MD 3 PBTD =9,405’(MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 2 6 & 7 8 & 9 10 & 11 14 4 & 5 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID =3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr-85 / JFE-Bear 2.441 Surface 5,504’ 1/4” Capstring Stainless Steel N/A Surface 5,504’ JEWELRY DETAIL No Depth Item 1 191’STA#2: GLM - 2-7/8"x 1" 13Cr BxB; DPSOV w/ BK-2 Latch 2 5,327’STA#1: GLM - 2-7/8"x 1" 13Cr BxB; Dummy w/ BK-2 Latch 3 5,385’ 2-7/8” XN Profile 2.313"w/ (2.205" No-Go) 4 5,439’ Bolt On Discharge Head: 5 5,410’ Zenith Ported Sub: 6 5,440’ Pump #2: 538PMSXD FLEX27 82 FER H6 12CRC 7 5,458’ Pump #1: 538PMSXD 20 GINPSHH H6 FER 12CRC 8 5,468’ Gas Separator: 9 5,473’ Intake: GPXARCINT FER H6 10 5,474’ Upper Tandem Seal: 11 5,481’ Lower Tandem Seal: 12 5,488’ Motor: 562XP 150/1505/61/6R 12CRC 13 5,499’ Motor Gauge: 14 5,502’ 2-3/8" EUE Centralizer: Bottom at 5,504’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 ESP Change-out by ASR #1 – 11/30/2021 ESP Change-out by ASR #1 –1/28/2024 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole Well Name Rig API Number Well Permit Number Start Date End Date MP G-14 ASR 50-029-23031-00-00 201-133 1/23/2024 1/29/2024 1/19/2024 - Friday No operations to report. 1/17/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/18/2024 - Thursday No operations to report. Test Fire and Gas alarm systems. Phase 3 called, suspend operations. (02:00 - 11:15). Bleed IAP from 80ps to 0psii. Accept rig at 15:30. P/U M/U test joint. Set 2-7/8" test joint in BOPs, Fill test pump water tank, Lock in rams. Fill stack. Begin testing BOPE. No operations to report. 1/20/2024 - Saturday No operations to report. 1/23/2024 - Tuesday 1/21/2024 - Sunday No operations to report. 1/22/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP G-14 ASR & WH 50-029-23031-00-00 201-133 1/23/2024 1/29/2024 No operations to report. Continue PU/MU ESP Assembly. Rig crew noticed armor for MLE to Round Cable unravled. Remove and replace armor, retest cable - Good. RIH w/ 2-7/8",6.4#,13Cr-85, JFE-Bear ESP completion - maintain 2x displacement or 2.5 BBL/HR pumping. Test ESP cable every 1000'. 1/27/2024 - Saturday WELLHEAD: BOP stack removed, clean hgr void, install seal subs (3) and R54 gasket. PU and land tree/adapter, torque to spec and test 500/5000 (PASS). Pull 2.5" Bpv with T bar. All valves in correct position. T/I/O=0/0/0 Freeze Protect (Post RWO) Pumped 10 bbls diesel down TBG. Final Whps=0/0/0 1/30/2024 - Tuesday 1/28/2024 - Sunday Continue RIH w/ 2-7/8",6.4#,13Cr-85, JFE-Bear ESP completion F/3600' - maintain 2.5 BBL/HR pumping. PUW = 38K | SOW= 21K . Land Hanger while monitoring ESP. RILDS. FINAL CLAMP COUNT: 95 CC, 5 Protectolizers, 2 Flat Guards. Set 2.5" Bpv into hgr, PU LJ and hgr MU to string. Term. 1/4" CL into bottom of hgr, Baker install penn and splice ESP cable. Five ft hgr into profile RKB 20.27' RILDS. 1/29/2024 - Monday 1/26/2024 - Friday Continue POOH F/ 766' while maintaining continuous hole fill. (all equipment recovered) BO/LD ESP BHA. RD Tongs, prepare Rig Floor for RIH w/ Doyon CSG Torque Turn equipment. Use crane to pull rig tongs and tong rack off rig floor. Place casing tongs and equipment on rig floor. Place esp ESP equipment in pipe shed. Pull old ESP from spooler and place cap line inside spooler. Run ESP motor lead and cap line through sheave and hang sheave.Prep rig floor to P/U M/U ESP equipment. Purge & plumb Chem/INJ line. Pressure up, chemical Injection Sub cracking pressure = 1550psi (surface) w/ 7.2ppg Diesel. 1/24/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue testing BOPE. Box end of FOSV leaking failing final test. STBY for replacement. Mobilize XO for new FOSV. Finish testing BOP as per approved sundry. 250 low 2500 high. AOGCC waived witness. Pump 200 BBLs down TBG taking returns up IA to the flowback tank. Returns oily and gas cut. Pump until clean returns. Ensure well is static, BOLDS. 43K to unseat TBG Hanger and pull to floor. ESP Cable reading a fault. Cut off ESP plug and disconnect 3/8" Chem. INJ. Line. BO HNGR/LJ and LD. ESP Spooler found out of hydraulic oil. Currently replacing seals & filling w/ oil. 1/25/2024 - Thursday VMS replaced leaking seals on ESP Spooling Unit. Continue POOH F/ 5474' while maintaining 2x displacement, swap to constant hole fill @ 20 BBL/HR. POOH T/ 766' while maintaining constant hole fill. Ensure well is static, BOLDS. 43K to unseat TBG Hanger and pull to floor Continue RIH w/ 2-7/8",6.4#,13Cr-85, JFE-Bear ESP completion F/3600' - maintain 2.5 BBL/HR pumping. PUW = 38K | SOW= 21K . Land Hanger while monitoring ESP. RILDS. Finish testing BOP as per approved sundry. 250 low 2500 high. AOGCC waived witness 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:Alaska NS - ASR - Well Site Managers To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Alaska NS - ASR - Well Site Managers Subject:MPG-14 | ASR-1 Initial BOPE Test Results Date:Wednesday, January 24, 2024 11:03:16 PM Attachments:MPG-14 BOPE test report (initial ).xlsx Please find attached. Thank you, Mike Heinz-Brown | Milne Point | DSM | Hilcorp Alaska Rig Office: 907-685-1266 | Cell: 480-296-5214 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 0LOQH3RLQW8QLW* 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m itt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:ASR 1 DATE: 1/24/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #22011330 Sundry #323-683 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:975 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 2FP Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)3000 P Kill Line Valves 3 2 1/16"P Pressure After Closure (psi)1900 P Check Valve 0NA200 psi Attained (sec)12 P BOP Misc 0NAFull Pressure Attained (sec)52 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4 / 2206 PSI P No. Valves 16 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 23 P #1 Rams 8 P Coiled Tubing Only:#2 Rams 7 P Inside Reel valves 0NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:18.0 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/21/24 07:31 Waived By Test Start Date/Time:1/23/2024 17:30 (date) (time)Witness Test Finish Date/Time:1/24/2024 11:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Brian Bixby Hilcorp Tested w/ 2-7/8" test joint. Bottle average pre-charge = 1,035.42 PSI. Test # 7 F/P due to leak on TIW #2 (ball type).Change out TIW & retest. (good test) C.Pace / J.Werlinger Hilcorp Alaska LLC A.Haberthur/M.Heinz-Brown MPU G-14 Test Pressure (psi): skans-asr-toolpushers@hilcorp.c ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022) 2024-0124_BOP_Hilcorp_ASR1_MPU_G-14 9 9 9 9 9 9 9999 9 9 9 9FP 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: ESP Swap 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? 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): 9,405'N/A Casing Collapse Conductor N/A Surface 5,410psi Production Liner 7,500psi OA Liner 7,500psi OB Liner 7,500psi 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: Brian Glasheen 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 6,077 MD/ 4,087 TVD, 6,286 MD/ 4,172 TVD & 7,037 MD/ 4,476 TVD and N/A Brian.Glasheen@hilcorp.com 907-564-5277 9,406' Perforation Depth MD (ft): VTL, SLZXP & ZXP LTP and N/A 9,348' See Schematic 2,377' See Schematic 2-7/8" 5,464'4-1/2" 112' 20" 7" 4-1/2" 7,097' 4-1/2"2,850' 2,377' MD N/A 8,430psi 7,240psi 8,430psi 4,513' 4,214' 5,439' 7,132' 9,405' Length Size Proposed Pools: 112' 112' 6.4# / 13Cr/ JFE TVD Burst 5,506' 8,430psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 & ADL0315848 201-133 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23031-00-00 Hilcorp Alaska LLC C.O. 477.05 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 1/1/2024 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: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT G-14 4,214' 9,405' 4,214' 975 N/A MILNE POINT / SCHRADER BLUFF OIL Noooo No 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 Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.12.21 13:32:37 - 09'00' Taylor Wellman (2143) 323-683 By Grace Christianson at 2:42 pm, Dec 21, 2023 1/1/2024 MGR26DEC23 SFD 12/26/2023 10-404 * BOPE pressure test to 2500 psi. *&:JLC 12/27/2023 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.12.27 09:33:06 -09'00'12/27/23 RBDMS JSB 122823 ESP Change-Out Well: MPU G-14 Well Name:MPU G-14 API Number: 50-029-23031-00 Current Status:Shut-in ESP Producer Pad:G-Pad Estimated Start Date:January 1st 2024 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:201-133 First Call Engineer:Brian Glasheen 907-545-1144 Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907)-947-9553 (M) AFE Number: Current Bottom Hole Pressure:1345 psi @ 3,698 TVD ESP Pressure Gauge 12/20/23 – 7.0 PPG Maximum Expected BHP:1345 psi @ 3,698’ TVD ESP Pressure Gauge 12/20/23 – 7.0 PPG MPSP:975 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 63° @ 3,550’ MD Brief Well Summary: MPU producer G-14 was drilled and completed as a Schrader Bluff N, OA, and OB producer in 2001. The well is a dual lateral slotted liner producer in the OA and OB sands and completed with screens across the N sand. The well was last completed in July 2019 and ran until February 2020 at which point the well was SI due to suspected tubing leak. The subsequent leak detect log confirmed 1 BPM TxIA communication at 700 psi through 4 separate locations which appeared to be connection leaks. The TBG and ESP were replaced August 22, 2021 and an ESP packer was installed due to offset injectors over pressuring the block. MP G-14 ESP failed due to suspected broken shaft after an unplanned hard shut down on 10/9/2021. The ESP was replaced 11/30/2021. In May 2023 MPG-14 experienced a SI that caused the pump to lose efficiency and the FBHP started to climb from 800 to 1100 psi. December 2023 the ESP experienced another SI and will no longer surface fluids. Notes Regarding Wellbore Condition x The 7” production casing passed an MIT to 1,500 psig from 3,440’ MD on 8/19/2021. Objective: x Pull 2-7/8” Tubing String and Baker ESP. x Install new Baker ESP Non- Sundried work SL: Pull Bottom GLV leave open Pull top GLV and DMY Sundry Procedure (Approval Required to Proceed) Pre-Rig Procedure 1. RU FB and PT lines to 3,000 psi. 2. Review the well Kill procedure with the engineer, plan to pump estimated 8.3 ppg source water kill wt fluid down the TBG taking returns to the IA . Shut the well in obtain updated shut-in well pressures with known fluids. . 3. Confirm well is dead. 4. RD FB. ESP Change-Out Well: MPU G-14 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU crane. Set BPV. ND Tree. Inspect the tubing hanger lift thread and note any damage. 8. NU BOPE. RD Crane. 9. Spot mud boat. RWO Procedure: 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 11. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well w/8.33 ppg Source water prior to pulling BPV. 12. Set TWC. 13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “ASR 1 BOP Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14.Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 15. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.3 ppg source water as needed. 16. Rig up spoolers for ESP cable and cap string. 17. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. 21.5 Klbs when landed by ASR in August 2021 18. Lay down tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. ESP Change-Out Well: MPU G-14 a. Evaluate pulled tubing hanger for possible damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 19. Ensure to have handling equipment for pulling chrome TBG. Inspect and verify equipment. 20. POOH and lay down the 2-7/8” tubing while spooling ESP cable and capstring. Lay down ESP and motor. a. Inspect the connections b. Re-use existing TBG, Inspect the connections c. Note any sand or scale inside or on the outside of the ESP in WSR. d. The completion has the following amount of clamps: i. 96 Cross Collar Clamps ii. 4 LaSalle clamps iii. 1 Flat Cannon clamp iv. 2 Flat Guards Pulled Equipment Disposition Tubing hanger Visually inspect on site then re-stock Tubing & Pup joints Re-use ESP Cable Inspect GLMS Re-use ESP Equipment Visually inspect on site then provide to Baker for tear down, PU new ESP Clamps Re-use XN Nipple Re-use 21. PU new ESP and RIH on 2-7/8” 6.5# 13-CR tubing. Set base of ESP assembly at ± 5,500’ MD. Install ¼” Cap string from the base of the ESP to surface. a. Review JFE Bear connection data sheet, Opt MU Torque – 2,040 ft-lbs b. Check ESP cable conductivity every 2,000’. Proposed Running Order (Note: Equipment should be coated) a. Base of ESP centralizer @ ±5,500’ MD b. Motor gauge c. Baker Hughes Motor d. Tandem Gas Separator with gas avoider e. GINPSH Pump f. Baker Hughes Flex 27 (Coated) g. Downhole gauge for discharge temperature and pressure. h. 1 joint of 2-7/8”, 6.5#, JFE Bear 13-Cr i. 2-7/8” XN (2.205” No-Go) Nipple j. 1 joint of 2-7/8”, 6.5#, JFE Bear 13-Cr k. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV l. ± XXX joints 2-7/8”, 6.5#, JFE Bear 13-Cr ESP Change-Out Well: MPU G-14 m. GLM, 2-7/8”x1”, OV installed with 10’ handling pups above and below (setting depth +/- 200’ MD). n. +/- XXX joints, 2-7/8”, 6.5#, JFE Bear 13-Cr TBG 22. PU and MU the 2-7/8” tubing hanger with landing joint. Make the final splice of the ESP cable to the penetrator, MU the chemical injection line to the tubing hanger. Plug off any additional control line ports if present. 23. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 24. Set TWC. 25. RDMO ASR. Post-Rig Procedure: 26. RD mud boat. RD BOPE house. Move to next well location. 27. RU crane. ND BOPE. 28. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 29. Pull TWC. 30. RD crane. Move returns tank and rig mats to next well location. 31. Replace gauge(s) if removed. 32. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: DH 12/27/2021 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 8/21/21 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” 4 2 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 3 7 8&9 10 & 11 14 5&6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID = 3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr / JFE 2.441 Surface 5,506’ 1/4” Capstring Stainless Steel N/A Surface 5,506’ JEWELRY DETAIL No Depth Item 1201’STA#2: GLM – 2-7/8" 6.4# 13-Cr GLM OV, ID= 2.441” 2 1,011’ Tam Port Collar 35,337’STA#1: GLM – 2-7/8" 6.4# 13-Cr GLM Dummy, ID=2.441” 4 5,395’ 2-7/8” XN Profile (2.205" No-Go) 5 5,447’ Bolt On Discharge Head: 2.875 FPDIS 400 6 5,447’ Ported Discharge Head: 7 5,448’ Pump: 400PMSXD 134 Flexer H6 8 5,472’ Gas Separator: 538GSTHVEVXMT H6 9 5,477’ Gas Avoider: SN-13322877 10 5,478’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 11 5,485’ Lower Tandem Seal: GSBDB H6 SB/AB PFSA 12 5,492’ Motor: 562SP 125/1085/71, SN-14487229 13 5,502’ Zenith Motor Gauge SN-15295454 14 5,504’ 2-3/8" EUE Centralizer: Bottom at 5,506’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 ESP Change-out by ASR #1 – 11/30/2021 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole _____________________________________________________________________________________ Revised By: TD F 12/21/2023 PROPOSED Milne Point Unit Well: MPU G-14 Last Completed: 8/21/21 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” 4 2 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 3 7 8&9 10 & 11 14 5&6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID =3.985” 15 17 N Sands 16 18 19 20 Min ID =3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr / JFE 2.441 Surface ±5,500’ 1/4” Capstring Stainless Steel N/A Surface ±5,500’ JEWELRY DETAIL No Depth Item 1 ±XXX’STA#2: GLM – 2-7/8" Side Pocket w/ OV Installed 2 ±X,XXX’ Tam Port Collar 3 ±X,XXX’STA#1: GLM – 2-7/8" Side Pocket w/ Dummy 4 ±X,XXX’ 2-7/8” XN Profile (2.205" No-Go) 5 ±X,XXX’ Bolt On Discharge Head: 6 ±X,XXX’ Ported Discharge Head: 7 ±X,XXX’ Pump: 8 ±X,XXX’ Gas Separator: 9 ±X,XXX’ Gas Avoider: 10 ±X,XXX’ Upper Tandem Seal: 11 ±X,XXX’ Lower Tandem Seal: 12 ±X,XXX’ Motor: 13 ±X,XXX’ Motor Gauge 14 ±X,XXX’ 2-3/8" EUE Centralizer: Bottom at ±5,500’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 ESP Change-out by ASR #1 – 11/30/2021 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. 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Supry m&l Zt2- � 200 PSI Attained 16 BOPE Test Report for: MILNE PT UNIT G-14 MISC. INSPECTIONS: Comm Contractor/Rig No.: Hilcorp ASR 1 PTD#: 2011330 DATE: 12/1/2021 Inspector Bob Noble Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Anderson Rig Rep: Beshea Inspector Type Operation: WRKOV ,.. Sundry No: Test Pressures: Inspection No: bopRCN211206131600 NA Housekeeping: Rams: Annular: Valves: MASP: Pit Level Indicators P Type Test: INIT 321-579. 250/2500 , 250/2500 250/2504 1217 - Related Insp No: Flow Indicator rd Misc TEST DATA System Pressure 3090 P Pressure After Closure 1900 P 200 PSI Attained 16 P ' MISC. INSPECTIONS: MUD SYSTEM: Blind Switch Covers: All Stations' P P/F P" Visual Alarm NA Location Gen.: P Trip Tank NA NA Housekeeping: P Pit Level Indicators P P PTD On Location P Flow Indicator P P Standing Order Posted P I Meth Gas Detector P P " Well Sign P H2S Gas Detector P P Drl. Rig P MS Misc NA NA H Sec P ' NA ACCUMULATOR SYSTEM: Misc Time/Pressure P/F System Pressure 3090 P Pressure After Closure 1900 P 200 PSI Attained 16 P ' Full Pressure Attained 66 _ P Blind Switch Covers: All Stations' P Nitgn. Bottles (avg): _4 (a, 2210 P" ACC Misc 0 NA " CHOKE MANIFOLD: Quantity P/F No. Valves 15 FP Manual Chokes 1 P Hydraulic Chokes 1 P CH Misc 1 FP INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 NA Number of Failures: 2 - Test Results Test Time 8 Remarks: FP on grayloc on kill side of stack. Test #7 FP, C-12, C-14, and C-16 were serviced. Closing times were, Annular 24 sec, pipe and blind rams were 5 sec each, HCR was 2 sec. Misc NA n FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Quantity Size P/F Upper Kelly ____ 0 NAF Stripper 0 _ __ NA_ _ Lower Kelly _____ 0 _ _NA Annular Preventer _ 1 _ 11" P Ball Type 1__ P, #1 Rams 1 2 7/8 x 5" - P ' Inside BOP 1 P, #2 Rams 1 Blinds P - FSV Misc _ 0 NA #3 Rams 0 NA #4 Rams _ 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" P HCR Valves 1 " 2 1/16" P Kill Line Valves 3 ' 2 1/16" P " Check Valve 0 NA BOP Misc 0 NA " CHOKE MANIFOLD: Quantity P/F No. Valves 15 FP Manual Chokes 1 P Hydraulic Chokes 1 P CH Misc 1 FP INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 NA Number of Failures: 2 - Test Results Test Time 8 Remarks: FP on grayloc on kill side of stack. Test #7 FP, C-12, C-14, and C-16 were serviced. Closing times were, Annular 24 sec, pipe and blind rams were 5 sec each, HCR was 2 sec. 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: ESP Change-out 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,405'N/A Casing Collapse Conductor N/A Surface 5,410psi Production Liner 7,500psi OA Liner 7,500psi OB Liner 7,500psi 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: David Gorm Contact Email: Contact Phone: 907-777-8333 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng See Schematic 2,377' See Schematic 11/25/2021 2-7/8" Viking ESP, VTL, SLZXP & ZXP LTP and N/A 2,798 MD/ 2,426 TVD, 6,077 MD/ 4,087 TVD, 6,286 MD/ 4,172 TVD & 7,037 MD/ 4,476 TVD and N/A 2,850' 2,377' 9,406' Perforation Depth MD (ft): 9,348' 112'20" 7" 4-1/2" 7,097' 5,439' 7,132' 9,405' 5,464'4-1/2" 4-1/2" Length Size 112'112' 6.4# / 13Cr/ JFE TVD Burst 5,464' 8,430psi MD N/A 8,430psi 7,240psi 8,430psi 4,513' 4,214' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 & ADL0315848 201-133 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23031-00-00 Hilcorp Alaska LLC MILNE PT UNIT G-14 MILNE POINT / SCHRADER BLUFF OIL C.O. 477.05 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY dgorm@hilcorp.com Operations Manager 4,214' 9,405' 4,214' 1,217 N/A ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. 321-579 By Meredith Guhl at 7:28 am, Nov 12, 2021 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.11.11 12:57:36 -09'00' David Haakinson (3533) MGR12NOV2021 1,217 BOPE Test to 2500 psi. 10-404 DLB 11/12/2021 DSR-11/12/21 X dts 11/12/2021 11/15/21 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.11.12 17:43:30 -10'00' RBDMS HEW 11/15/2021 ESP Change-Out Well: MPU G-14 Well Name:MPU G-14 API Number: 50-029-23031-00 Current Status:Shut-in ESP Producer Pad:G-Pad Estimated Start Date:Nov. 25th, 2021 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:201-133 First Call Engineer:David Gorm (907) 777-8333 (O) (505)-215-2819 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907)-947-9553 (M) AFE Number:Well EZ Entries Required Yes Current Bottom Hole Pressure:1,637 psi @ 4,200’ TVD ESP Pressure Gauge 11/8/2021 -8.1 PPG Maximum Expected BHP:1,637 psi @ 4,200’ TVD ESP Pressure Gauge 11/8/2021 -8.1 PPG MPSP:1,217 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 63° @ 3,550’ MD Max Dogleg:4.5°/100ft @ 2,435’ MD Brief Well Summary: MPU producer G-14 was drilled and completed as a Schrader Bluff N, OA, and OB producer in 2001. The well is a dual lateral slotted liner producer in the OA and OB sands and completed with screens across the N sand. The well was last completed in July 2019 and ran until February 2020 at which point the well was SI due to suspected tubing leak. The subsequent leak detect log confirmed 1 BPM TxIA communication at 700 psi through 4 separate locations which appeared to be connection leaks. The TBG and ESP were replaced August 22, 2021 and an ESP packer was installed due to offset injectors over pressuring the block. MP g-14 ESP failed due to suspected broken shaft after an unplanned hard shut down on 10/9/2021. The offset injectors were shut in and monitoring the ESP bottom hole gauge has shown the bottom hole pressure has been drawn down below the 8.55 ppg threshold. Notes Regarding Wellbore Condition x The 7” production casing passed an MIT to 1,500 psig from 3,440’ MD on 8/19/2021. x CO 390A: A packer is not required on this ESP completion as the reservoir pressure of 8.1 ppg EMW Is less than the 8.55 ppg EMW. x Offset Injector Support o G-07: Offline o G-17: Offline o J-12: Offline o J-05: Offline Objective: x Pull 2-7/8” Tubing String, ESP packer and Baker ESP. x Install new Baker ESP and removing the ESP packer. Sundry Procedure (Approval Required to Proceed) Pre-Rig Procedure 1. RU hot oil and PT lines to 3,000 psi. 2. Review the well Kill procedure with the engineer, plan to pump estimated 8.3 ppg source water kill wt fluid down the TBG taking returns to the IA (70 bbls TBG volume, 425 bbls IA volume). Shut the well in -00 DLB ESP Change-Out Well: MPU G-14 obtain updated shut-in well pressures with known fluids. Contact the operations Engineer to work with to re-calculate kill weight fluids. Estimate 8.3 ppg kill weight fluid. 3. Confirm well is dead. 4. RD hot oil truck. 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU crane. Set BPV. ND Tree. Inspect the tubing hanger lift thread and note any damage. 8. NU BOPE. RD Crane. 9. Spot mud boat. RWO Procedure: 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 11. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well w/8.33 ppg Source water prior to pulling BPV. 12. Set TWC. 13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “ASR 1 BOP Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14.Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 15. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.3 ppg source water as needed. 16. Rig up spoolers for ESP #2RD cable, cap string and vent line for packer. a. Baker Hughes representative should be onsite for ESP pull. 17. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. The PU= 34K when landed by ASR in August 2021 ESP Change-Out Well: MPU G-14 b. The Viking ESP packer is pinned to release at ~49 Klbs, estimate PU to 67 klb to release the packer. c. Wait 1 hour to allow the packer time to relax before pulling. 18. Lay down tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 19. Ensure to have handling equipment for pulling chrome TBG. Inspect and verify equipment. 20. POOH and lay down the 2-7/8” tubing while spooling 2AWG SOLBC ESP cable. Lay down ESP and motor. a. Inspect the connections on the TOH b. Re-use existing TBG, Inspect the connections on the TOH c. Note any sand or scale inside or on the outside of the ESP in WSR. d. The completion has the following amount of clamps/guards/cap-string: i. 96 Cross Collar Clamps ii. 3 Pump Clamps iii. 2 Protectolizers iv. ¼” Chemical injection line from 5,463’ to surface v. ¼” vent valve line from packer to surface Pulled Equipment Disposition Tubing hanger Visually inspect on site then re-stock Tubing & Pup joints Re-use ESP Cable Inspect GLMS Re-use ESP Equipment Visually inspect on site then provide to Baker for tear down, PU new ESP Clamps Re-use XN Nipple Re-use 21. PU new ESP and RIH on 2-7/8” 6.5# 13-CR tubing. Set base of ESP assembly at ± 5,500’ MD. Install ¼” Cap string from the base of the ESP to surface. a. Review JFE Bear connection data sheet, Opt MU Torque – 2,040 ft-lbs b. Check ESP cable conductivity every 2,000’. Proposed Running Order (Note: Equipment should be coated) a. Base of ESP centralizer @ ±5,500’ MD b. Motor gauge c. Baker Hughes Motor d. Tandem Gas Separator with gas avoider e. Baker Hughes 134stage Flex ER ESP (Coated) ESP Change-Out Well: MPU G-14 f. Downhole gauge for discharge temperature and pressure. Connected with a jumper from the lower sensor. g. 1 joint of 2-7/8”, 6.5#, JFE Bear 13-Cr h. 2-7/8” XN (2.205” No-Go) Nipple i. 1 joint of 2-7/8”, 6.5#, JFE Bear 13-Cr j. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV k. ± XXX joints 2-7/8”, 6.5#, JFE Bear 13-Cr l. GLM, 2-7/8”x1”, OV installed with 10’ handling pups above and below (setting depth +/- 200’ MD). m. +/- XXX joints, 2-7/8”, 6.5#, JFE Bear 13-Cr TBG 22. PU and MU the 2-7/8” tubing hanger with landing joint. Make the final splice of the ESP cable to the penetrator, MU the chemical injection line to the tubing hanger. Plug off any additional control line ports if present. 23. PU and MU the tubing hanger with landing joint. 24. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 25. Set TWC. 26. RDMO ASR. Post-Rig Procedure: 27. RD mud boat. RD BOPE house. Move to next well location. 28. RU crane. ND BOPE. 29. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 30. Pull TWC. 31. RD crane. Move returns tank and rig mats to next well location. 32. Replace gauge(s) if removed. 33. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: TDF 11/8/2021 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 8/21/21 PTD: 201-133 28 30Slotted Liner Slotted Liner 29 27 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” 5 2 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 4 8 9&10 11 & 12 15 6&7 7” 22 23 24 25 “OA” Lateral “OB” Lateral 26 Min ID = 3.985” 16 18 N Sands 17 19 20 21 Min ID = 3.907” 13 14 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr / JFE 2.347 Surface 5,464’ 1/4” Capstring Stainless Steel N/A Surface 5,464’ JEWELRY DETAIL No Depth Item 1260’STA#2: GLM – 2-7/8" 6.4# 13-Cr GLM OV, ID= 2.441” 2 1,011’ TAM Port Collar 3 2,798’ 7” x 2-7/8” Viking ESP Packer w/ 3/8" Control Line and Chemical line 42,823’STA#1: GLM – 2-7/8" 6.4# 13-Cr GLM Dummy, ID=2.441” 5 5,357’ 2-7/8” XN Profile (2.205" No-Go) 6 5,409’ Bolt On Discharge Head: 2.875 FPDIS 400 7 5,409’ Ported Discharge Head: HEAD S/A B/O PRESS PORT 400P 8 5,410’ Pump: PMP 400PMSXD 119 FLEX10 H6 FER STD_PNT 9 5,433’ Gas Separator: GASSEP 400GSEV MT H6 NO_PNT 10 5,435’ Gas Avoider: 400 Gravity Cup LS H6 NO_PN 11 5,437’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 12 5,444’ Lower Tandem Seal: GSBDB H6 SB/AB/PFSA 13 5,451’ Motor, 562XP 100/1820/34 14 5,459’ Zenith Motor Gauge 15 5,462’ 2-3/8" EUE Centralizer: Bottom at 5,464 16 6,077’ 7” Halliburton VTL Packer (3.880” ID) 17 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 18 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 19 6,286’ 7” Baker SLZXP Packer 20 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 21 6,330’ 4-1/2” WLEG (3.958” ID) 22 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 23 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 24 7,028’ OB Lateral Tie Back Sleeve 25 7,037’ OB Lateral ZXP Liner Top Packer 26 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 27 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 28 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 29 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 30 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole _____________________________________________________________________________________ Revised By: TDF 10/12/2021 PROPOSED Milne Point Unit Well: MPU G-14 Last Completed: 8/21/21 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” 4 2 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 3 7 8&9 10 & 11 14 5&6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID = 3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr / JFE 2.347 Surface ±5,500’ 1/4” Capstring Stainless Steel N/A Surface ±5,500’ JEWELRY DETAIL No Depth Item 1 ±260’STA#2: GLM – 2-7/8" 6.4# 13-Cr GLM OV, ID= 2.441” 2 ±1,011’ TAM Port Collar 3 ±2,823’STA#1: GLM – 2-7/8" 6.4# 13-Cr GLM Dummy, ID=2.441” 4 ±5,357’ 2-7/8” XN Profile (2.205" No-Go) 5 ±5,409’ Bolt On Discharge Head: 6 ±5,409’ Ported Discharge Head: 7 ±5,410’ Pump: 8 ±5,433’ Gas Separator: 9 ±5,435’ Gas Avoider: 10 ±5,437’ Upper Tandem Seal: 11 ±5,444’ Lower Tandem Seal: 12 ±5,451’ Motor: 13 ±5,459’ Zenith Motor Gauge 14 ±5,498’ 2-3/8" EUE Centralizer: Bottom at ±5,500’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole Milne Point ASR Rig 1 BOPE BOPE ~4.48' ~4.54' 2.00' 5000# 2-7/8" x 5" VBR 5000#Blind DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Swap Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,405 feet N/A feet true vertical 4,214 feet N/A feet Effective Depth measured 9,405 feet feet true vertical 4,214 feet 2,426', 4,087, 4,172 & 4,476 feet Perforation depth Measured depth N/A feet True Vertical depth N/A feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / 13Cr 5,464' 3,705' Packers and SSSV (type, measured and true vertical depth)N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name:Chad Helgeson Contact Name: Authorized Title: Contact Email: Contact Phone: Hilcorp Alaska LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 5,410psi Burst N/A 7,240psi 777-8333 20" 7" 4-1/2" 4,513' 4,214' 7,500psi WINJ WAG Surface OB Liner Oil-Bbl 8,430psi 8,430psi 8,430psi 7,500psi dgorm@hilcorp.com 250 MILNE PT UNIT G-14 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 106 Gas-Mcf 500 Casing Pressure Tubing Pressure 83 5. Permit to Drill Number: MILNE POINT / SCHRADER BLUFF OIL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-358 226 Authorized Signature with date: David Gorm 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data N/A0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 201-133 50-029-23031-00-00 Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Plugs ADL025906 / ADL0315848 N/A measured 7,097' measured true vertical Packer Size N/A Casing Conductor Length 112' MD 112' 7,132' 9,406' TVD 4,150' 112' 9,348' 4,214' 1,555 Operations Manager 0 Water-Bbl 2,377' 7,500psi Viking ESP, VTL, SLZXP & ZXP LTP 2,798', 6,077, 6,286 & 7,037 OA Liner Production Liner 2,377' 2,850' 4-1/2" 4-1/2" 9,405' Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 4:21 pm, Sep 08, 2021 Chad Helgeson (1517) 2021.09.08 10:48:34 - 08'00' SFD 9/9/2021 RBDMS HEW 9/10/2021 DSR-9/8/21MGR14OCT21 Well Name Rig API Number Well Permit Number Start Date End Date MP G-14 ASR #1 50-029-23031-00-00 201-133 8/16/2021 8/21/2021 8/18/2021 POOH with 2 7/8" Tbg and ESP completion from 250' Up Wt 10k to 60' LD GLM with Dummy valve, GLM was plugged, POOH LD XN POOH to ESP pump, pumping calculated pipe displacement every 15jts. and an ave of 20bbls of 9.8# NaCL to keep gas away from surface and rinse off the pipe, Oil sheen seen on the pipe but no other issues. POOH from 60' LD Baker ESP pump, LD in 2 sections. LD 183jts of 2 7/8" Tbg to be junked, Clear rig floor and pipe rack of Baker ESP equip. Offload 3 1/2" work string, clean and tally pipe. Installed wear bushing, (9" ID). MU Yellow Jacket 7" test packer RIH on 3 1/2" NC/31, adjusted wt, 10.37#, RIH to 1,000' and attempted to set same with no success, contacted YJ and decision was made to POOH & C/O Pkrs. POOH from 1000' LD 3 1/2" WS and 7" Pkr. MU 2nd Yellow Jacket 7" Test pkr. RIH w/ 2jts to 89' and set Pkr & ck'd ok, RIH with 2 more jts. to 170' reset & Ck'd ok. Cont. RIH from 170' PU 3 1/2" WS RIH with 7" test Pkr RIH a total of 87jts. to 3,490', PU wt. 29K Down wt 21K, MU swivel, and took it took several attempts to get the packer to set in tension, Pkr set in tension with 15k overpull, Pkr set @ 3,480'. Utilizing centrifugal pump, filled backside to get the air out, IA capacity is 92bbls, after pumping 85bbls, lined up to rig pump, shut pipe rams in attempt to build pressure on IA. after pumping 15 bbls and still no pressure. Released pkr, reset same and cont. to pump 30bbls with no press. Discussed with town. POOH LD 1 JT to 3,440' , set Pkr in compression with 25k wt. dn. Press. IA to 1500psi and pkr set & holding. Pressured up several times to work the air out then tested 7" csg to 1,500 psi for 30min. Good test. sent test chart to the OE and he approved the test. Released Pkr, PU wt 31K, POOH LD 3 1/2 work string and test pkr from 3,440' to 200'. With 30jts out at 2300' PU wt was 22K. Hilcorp Alaska, LLC Weekly Operations Summary Finish RU & Tested BOPE to 250-2,500psi, Good test, RU Landing Jt, pumped tbg. vol. w/BOLDS, PU 34k on Hgr. POOH LD same, Cont. POOH LD 2-7/8" ESP Comp. to 250'. Connect riser spool and connect flow line. Tested Fire and gas alarms and Fin. NU BOP's and performed Shell test. Tested BOPE per Sundry as following. Annular 250-2,500psi, Valves 250-2,500psi, Rams 250-2,500psi. Performed the Koomey Drawdown Test. No failures recorded, Tested with both 2-7/8" and 3-1/2" test Joints. Witness was waived by Lou Laubenstien on 8/16/21 @ 8:12pm. L/D Testing equipment. Spotted cable spooler, hung cable sheave and elephant trunk, Threaded rope from spooler over sheave to rig floor. Checked IA= static, Pulled test dart and checked for pressure under BPV static, pulled BPV. Made up landing jt. and Attempted to displace out tbg and found several hoses not lined up properly, reconnected hoses. Pumped a tbg volume of 31 bbls at 1bpm while backing out LDS, 1bpm at 1300psi, shut down and well was on a vacuum. Pulled hanger off seat at 34k, pipe was free with the 34k up wt. Pulled hanger to rig floor, de-completing and LD same. POOH with 2-7/8" Tbg and ESP completion from 5,667' to jt. 60 out, 4,100' Up Wt 23k, pumping calculated pipe displacement every 15jts. and an ave of 20bbls of 9.8# NaCL to keep gas away from surface and rinse off the pipe, Oil sheen seen on the pipe but no other issues. Monitored well while crew ate lunch. POOH with 2-7/8" Tbg and ESP completion from 4,100' to jt# 178 at 250' Up Wt 10k, pumping calculated pipe displacement every 15jts. and an ave of 20bbls of 9.8# NaCL to keep gas away from surface and rinse off the pipe, Oil sheen seen on the pipe but no other issues. Pipe is to be junked. (Pressure test surface lines 250/2,500 psi) (Well Kill) Pumped 400 bbls 9.9 brine down TBG up IA tanking returns to tank. Got 9.8 brine to surface. Just before shutting down TBG spiked up to 1,350 psi and returns t tank stopped. Pumped fluid to return tank (clear). Pumped down TBG up IA and TBG pressured up to 850 psi at 1 bpm and didn't get any returns. Pumped 2 bbls 60/40 to flush lines. 8/17/2021 8/16/2021 Well Name Rig API Number Well Permit Number Start Date End Date MP G-14 ASR #1 50-029-23031-00-00 201-133 8/16/2021 8/21/2021 Hilcorp Alaska, LLC Weekly Operations Summary LD Rig. Moved rig off mud boat and took rig to the ASR test on A pad for maint. Spot in crane and removed rig floor and wellhouse. Removed BOP stack with crane, Baker and wellhead reps made their final checks. NU tree, tested void to 5,000 psi , good test. Removed BPV and job complete. Cont. to Move rig to L-04 well. See L-04 report. 8/19/2021 Continue to POOH laying down 3-1/2" work string from 200' to surface. Lay down the test packer. Move the pipe rack. Clean and clear the catwalk and containment area. Remove the rig tongs from the carriage and off the rig floor. Mobilize GBR tongs to the rig floor with torque turn equipment. Load XN nipple, GLM's and ESP equipment onto the catwalk. Mobilize cannon clamps to the rig floor. Set the pipe racks in place. Load, strap and tally 180 joints of 2-7/8", 6.5#, 13Cr, JEF Bear tubing. Strap and tally completion equipment. Finalize the tally. Run the c hemical injection line and ESP cable over sheaves to the rig floor. PU & MU the centralizer, motor gauge and motor. Service the motor. Function test the chemical injection check valve. Service the seals and MU the MLE. PU and MU the pump, ported discharge head, bolt on discharge and XO to 56'. Began RIH with the new Baker ESP completion on 2-7/8", 6.5#, 13Cr, JFE Bear tubing. MU 1 jt. and XN Nipple. Continue to RIH per the completion tally to jt. 63 at 2,060'. Dn Wt. 13k. Baker tested cable conductivity and checked ok, crew ate lunch. Continue to RIH with the new Baker ESP completion on 2-7/8", 6.5#, 13Cr, JFE Bear tubing from 2,060' to 2,624' (Jt. 81). MU GLM Assy #1 Patco GLM SN: 04130610-10 w/DV installed, Then PU & RIH with 7" Viking Pkr RIH to 2665'. 20K up, 16K down. Checked cable continuity and checked good, then measured up the ESP cable and made the splice on cable. Currently making splices tp the Pkr. 8/20/2021 Continue to MU the ESP cable packer splices. Test ESP cable electrical conductivity - good. Cut chemical injection line and MU feedthrough to the packer. MU dual vent valves with single vent valve operating line. Function vent valves. Vent valves opened at 3,000 psi. RIH with ESP completion per tally from 2,665' to 5,430' testing electrical conductivity every 1,000'. Torqued with GBR torque turn to 3,470 ft-lbs,PU and MU 11" x 2-7/8" EUE 13Cr tubing hanger with crossover pup to 2-7/8" JFE Bear. Splice ESP cable to the tubing hanger penetrators. Cut vent valve and chemical injection control lines and MU to tubing hanger penetrators. Land the tubing hanger and RILDS. 21K Dn Wt. RU to drop rod and ball in prep. to set 7" Viking Pkr. Drop 1.3" Ball and Rod, observed TIW not fully tq'd up, LD Ldg jt. PU 3 pups & MU TIW back up. Attempted to test the line & TIW would not test, removed TIW and installed Lo-Tq valve & test lines 4,000 psi. Filled tbg w/ 9.8 NaCl working air out of the system. Proceeded to set 7" Viking Pkr, saw packer set at 3,200 psi, took it on up to 4000 psi & held for 15mins. Bled off to zero & press. up to 4,000psi held f/5min. Bled off 4,000 psi from the tbg, observed oil back into the pits. RU on the IA, proceeded to fill the IA working the air out, Proceeded to test the IA to 1,500 psi for 30min, good test, bled off the pressure and installed BPV. Began to RD the rig in prep. for moving to L-04, removed pipe racks, catwalk and cleared rig floor. Began breaking the bolts down on the BOP stack. 8/21/2021 _____________________________________________________________________________________ Revised By: DH 9/7/2021 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 8/21/21 PTD: 201-133 28 30Slotted Liner Slotted Liner 29 27 TD =9,405’(MD) / TD = 4,210’(TVD) 20” 5 2 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 1 4 8 9&10 11 & 12 15 6&7 7” 22 23 24 25 “OA” Lateral “OB” Lateral 26 Min ID = 3.985” 16 18 N Sands 17 19 20 21 Min ID = 3.907” 13 14 3 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.4 / 13Cr / JFE 2.347 Surface 5,464’ JEWELRY DETAIL No Depth Item 1260’STA#2: GLM – 2-7/8" 6.4# 13-Cr GLM OV, ID= 2.441” 2 1,011’ TAM Port Collar 3 2,798’ 7” x 2-7/8” Viking ESP Packer w/ 3/8" Control Line and Chemical line 42,823’STA#1: GLM – 2-7/8" 6.4# 13-Cr GLM Dummy, ID=2.441” 5 5,357’ 2-7/8” XN Profile (2.205" No-Go) 6 5,409’ Bolt On Discharge Head: 2.875 FPDIS 400 7 5,409’ Ported Discharge Head: HEAD S/A B/O PRESS PORT 400P 8 5,410’ Pump: PMP 400PMSXD 119 FLEX10 H6 FER STD_PNT 9 5,433’ Gas Separator: GASSEP 400GSEV MT H6 NO_PNT 10 5,435’ Gas Avoider: 400 Gravity Cup LS H6 NO_PN 11 5,437’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 12 5,444’ Lower Tandem Seal: GSBDB H6 SB/AB/PFSA 13 5,451’ Motor, 562XP 100/1820/34 14 5,459’ Zenith Motor Gauge 15 5,462’ 2-3/8" EUE Centralizer: Bottom at 5,464 16 6,077’ 7” Halliburton VTL Packer (3.880” ID) 17 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 18 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 19 6,286’ 7” Baker SLZXP Packer 20 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 21 6,330’ 4-1/2” WLEG (3.958” ID) 22 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 23 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 24 7,028’ OB Lateral Tie Back Sleeve 25 7,037’ OB Lateral ZXP Liner Top Packer 26 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 27 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 28 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 29 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 30 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole 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: ESP Change-out 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,405'N/A Casing Collapse Conductor N/A Surface 5,410psi Production Liner 7,500psi OA Liner 7,500psi OB Liner 7,500psi 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 Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: 6/5/2020 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Tubing Grade:Tubing MD (ft): dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 / ADL0315848 201-133 50-029-23031-00-00 MILNE POINT / SCHRADER BLUFF OIL Length Size 4,214' 9,405' 4,214' 1,340 MD N/A MILNE PT UNIT G-14 C.O. 477.05 112'112' 6.5# / L-80 / EUE TVD Burst 5,699' 8,430psi N/A 8,430psi 7,240psi 8,430psi 4,513' 4,214' 5,439' 7,132' 9,405' 112'20" 7" 4-1/2" 7,097' 2,377' Authorized Signature: 8/15/2021 2-7/8" Perforation Depth MD (ft): See Schematic See Schematic Perforation Depth TVD (ft): VTL, SLZXP & ZXP LTP and N/A 6,077 MD/ 4,087 TVD, 6,286 MD/ 4,172 TVD & 7,037 MD/ 4,476 TVD and N/A Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 9,406' 9,348' 2,377' 5,464'4-1/2" 4-1/2"2,850' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 1:16 pm, Jul 20, 2021 321-358 Chad Helgeson (1517) 2021.07.20 12:15:53 - 08'00' BOPE test to 2500 psi. Annular to 2500 psi. DLB 07/20/2021 10-404 X DSR-7/21/21MGR23JUL21 dts 7/23/2021 JLC 7/23/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.23 12:19:41 -08'00' RBDMS HEW 7/26/2021 ESP Change-Out Well: MPU G-14 Well Name:MPU G-14 API Number: 50-029-23031-00 Current Status:Shut-in ESP Producer Pad:G-Pad Estimated Start Date:Aug 15th, 2021 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:201-133 First Call Engineer:David Gorm (907) 777-8333 (O) (505)-215-2819 (M) Second Call Engineer:David Haakinson (907) 777-8343 (O) (307)-660-4999 (M) AFE Number:Well EZ Entries Required Yes Current Bottom Hole Pressure:1,675 psi @ 3,955’ TVD Downhole Gauge: 2 month PBU (6/3/20)8.12 PPG Maximum Expected BHP:1,735psi @ 3,955’ TVD 2-Month PBU Extrapolation |8.40 PPG MPSP:1,340psi Gas Column Gradient (0.1 psi/ft) Max Inclination 63° @ 3,550’ MD Max Dogleg:4.5°/100ft @ 2,435’ MD Brief Well Summary: MPU producer G-14 was drilled and completed as a Schrader Bluff N, OA, and OB producer in 2001. The well is a dual lateral slotted liner producer in the OA and OB sands and completed with screens across the N sand. The well was last completed in July 2019 and ran until February 2020 at which point the well was SI due to suspected tubing leak. The subsequent leak detect log confirmed 1 BPM TxIA communication at 700 psi through 4 separate locations which appeared to be connection leaks. A follow-up tubing caliper performed 4/4/20 confirmed extensive internal tubing corrosion. Notes Regarding Wellbore Condition x The 7” production casing passed an MIT to 1,500 psig from 5,927’ MD on 2/6/2013. x Offset Injector Support o G-07: Offline o G-17: Offline o J-12: Offline Objective: x Pull 2-7/8” Tubing String, Baker Hughes 76 HP motor, and Baker 114 P6 ESP. x Install new Baker Hughes 76 HP motor, and Baker 114 P6 ESP, and new 2-7/8” tubing. Sundry Procedure (Approval Required to Proceed) Pre-Rig Procedure 1. RU hot oil and PT lines to 3,000 psi. 2. Review the well Kill procedure with the engineer, plan to pump estimated 8.6 ppg NaCl kill wt fluid down the TBG taking returns to the IA (70 bbls TBG volume, 425 bbls IA volume). 3. Confirm well is dead. a. Contact the Engineer to review freeze protecting the well depending on timing for arrival of the ASR. 4. RD hot oil truck. 5. Clear and level pad area in front of well. Spot rig mats and containment. ESP Change-Out Well: MPU G-14 6. RD well house and flowlines. Clear and level area around well. 7. RU crane. Set BPV. ND Tree. Inspect the tubing hanger lift thread and note any damage. 8. NU BOPE. RD Crane. 9. Spot mud boat. RWO Procedure: 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 11. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well w/8.6 ppg NaCl prior to pulling BPV. 12. Set TWC. 13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “ASR 1 BOP Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14.Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 15. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.6 ppg NaCl as needed. 16. Rig up spoolers for ESP #2RD cable. a. Baker Hughes representative should be onsite for ESP pull. 17. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. The SD = 19K when landed by ASR in July 2019 b. ~5,700’ of 6.5 # 2-7/8” tubing weighs ~ 37Klbs(dry) or 32Klbs (buoyed by 8.6 ppg fluid) c. If needed, circulate (long or reverse) pill with lubricant, source-water, and/or baraclean pill prior to laying down the tubing hanger. 18. Lay down tubing hanger. ESP Change-Out Well: MPU G-14 Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 19. POOH and lay down the 2-7/8” tubing while spooling 2AWG SOLBC ESP cable. Lay down ESP and motor. a. Due to heavy corrosion of tubing it will be junked. b. Note any sand or scale inside or on the outside of the ESP in WSR. c. The completion has the following amount of clamps/guards/cap-string: i. 107 Cross Collar Clamps 1. Clamps every other except for: 2. Joints 108-112 and 127-129 are clamped on every joint. ii. 4 Pump Clamps iii. 4 Protectolizers Pulled Equipment Disposition Tubing hanger Visually inspect on site then re-stock Tubing & Pup joints Junk ESP Cable Junk GLMS Junk ESP Equipment Visually inspect on site then provide to Baker for Redress Clamps Visually inspect on site then re-stock XN Nipple Junk 20. PU new ESP and RIH on new 2-7/8” 6.5# 13-CR tubing. Set base of ESP assembly at ± 5,700’ MD. a. Check ESP cable conductivity every 2,000’. Proposed Running Order (Note: Equipment should be coated) a. Base of ESP centralizer @ ±5,700’ MD b. Motor gauge c. 75 HP Baker Hughes 562XP Motor d. Tandem Gas Separator with gas avoider e. Baker Hughes 114 stage P6 ESP f. Downhole gauge for discharge temperature and pressure. i. Connected with a jumper from the lower sensor. Does not require a separate tech-wire. g. 1 joint of 2-7/8”, 6.5#, EUE 8rd tubing h. 2-7/8” XN (2.205” No-Go) Nipple i. 3 joints of 2-7/8”, 6.5#, EUE 8rd tubing j. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV k. ± 171 joints 2-7/8”, 6.5#, EUE 8rd tubing l. Upper 2-7/8”x 1” Side-pocket GLM @ ± 200’ MD with 0.25” OV m. ± 5 joints 2-7/8”, 6.5#, EUE 8rd tubing ESP Change-Out Well: MPU G-14 21. PU and MU the tubing hanger with landing joint. 22. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 23. Set TWC. 24. RDMO ASR. Post-Rig Procedure: 25. RD mud boat. RD BOPE house. Move to next well location. 26. RU crane. ND BOPE. 27. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 28. Pull TWC. 29. RD crane. Move returns tank and rig mats to next well location. 30. Replace gauge(s) if removed. 31. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: NL W 4/08/2021 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 7/22/19 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD =9,405’ (MD) / TD = 4,210’(TVD) 20” 4 1 PBTD =9,405’(MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 2 3 7 8 & 9 10 & 11 14 5& 6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID =3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.5 / L-80 / EUE 2.347 Surface 5,699’ JEWELRY DETAIL No Depth Item 1189’STA#2: GLM – 2-7/8" 6.5# L-80 EUE GLM DGLV Set 04-08/21 2 1,011’ TAM PORT COLLAR 35,484’STA#1: GLM – 2-7/8" 6.5# L-80 EUE GLM *** DGLV pulled and left empty on 6/3/2020*** 4 5,598’ 2-7/8” XN Profile (2.205" No-Go) 5 5,647’ Bolt On Discharge Head: PMP 400 2.88X8 EUE CS 6 5,647.7’ Ported Discharge Head: PRESS PORT 400P 7 5,648’ Pump: 400PMSXD 141 P6 M FER N 8 5,664’ Gas Separator: 538GSTHVEVX MT H6 FER 9 5,670’ Gas Avoider: 513 HD HS 1" 10 5,673’ Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 11 5,679’ Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 12 5,686’ Motor: KMHG 562 76Hp /1,360V/34A 04R 13 5,695’ Motor Gauge: Zenith 14 5,697’ 2-3/8" EUE Centralizer:Bottom at 5,699’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9405’OB Lt l41/2” Bt f G id Sh WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole _____________________________________________________________________________________ Revised By: TDF 7/19/2021 PROPOSED Milne Point Unit Well: MPU G-14 Last Completed: 7/22/19 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD =9,405’ (MD) / TD = 4,210’(TVD) 20” 4 1 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 2 3 7 8 & 9 10 & 11 14 5 & 6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID = 3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.5 / CR-13 / EUE 2.347 Surface ±5,700’ JEWELRY DETAIL No Depth Item 1 ±200’STA#2: GLM – 2-7/8” x 1” w/ 0.25” Orifice Valve 2 1,011’ TAM PORT COLLAR 3 ±5,484’STA#1: GLM – 2-7/8" 6.5# L-80 EUE GLM Dummy 4 ±5,598’2-7/8” XN Profile (2.205" No-Go) 5 ±5,647’Bolt On Discharge Head: 6 ±5,647.7’Ported Discharge Head: 7 ±5,648’Pump: 8 ±5,664’Gas Separator: 9 ±5,670’Gas Avoider: 10 ±5,673’Upper Tandem Seal: 11 ±5,679’Lower Tandem Seal: 12 ±5,686’Motor: 13 ±5,695’Motor Gauge: 14 ±5,697’2-3/8" EUE Centralizer:Bottom at ±5,700 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole Milne Point ASR Rig 1 BOPE 2020 Updated 1/09/2020 11” BOPE 4.48' 4.54' 2.00' INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind11'͛- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 09/29/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU G-14 (201-133) Leak Detection Log 03/07/2020 Please include current contact information if different from above. Received by the AOGCC 09/29/2020 PTD: 2011330 E-Set: 34006 Abby Bell 09/29/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 09/15/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU G-14 (201-133) Multi Finger Caliper Log 04/04/2020 ANALYSIS FIELD DATA Please include current contact information if different from above. Received by the AOGCC 09/16/2020 PTD: 2011330 E-Set: 33894 Abby Bell 09/16/2020 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: ESP Change-out 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,405'N/A Casing Collapse Conductor N/A Surface 5,410psi Production Liner 7,500psi OA Liner 7,500psi OB Liner 7,500psi 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 Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: 6/5/2020 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Tubing Grade:Tubing MD (ft): dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 / ADL0315848 201-133 50-029-23031-00-00 MILNE POINT / HILCORP ALASKA LLC Length Size 4,214' 9,405' 4,214' 1,340 MD N/A MILNE PT UNIT G-14 C.O. 477.05 112'112' 6.5# / L-80 / EUE TVD Burst 5,699' 8,430psi N/A 8,430psi 7,240psi 8,430psi 4,513' 4,214' 5,439' 7,132' 9,405' 112'20" 7" 4-1/2" 7,097' 2,850' 2,377' Authorized Signature: 7/15/2020 2-7/8" Perforation Depth MD (ft): See Schematic See Schematic Perforation Depth TVD (ft): VTL, SLZXP & ZXP LTP and N/A 6,077 MD/ 4,087 TVD, 6,286 MD/ 4,172 TVD & 7,037 MD/ 4,476 TVD and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 9,406' 9,348' 2,377' 5,464'4-1/2" 4-1/2" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. For C. Helgeson By Samantha Carlisle at 11:55 am, Jun 05, 2020 320-245 Digitally signed by David Haakinson DN: cn=David Haakinson, ou=Users Date: 2020.06.05 11:10:40 -08'00' David Haakinson Schrader Bluff Oil SFD 6/9/2020 SFD 6/9/2020 ESP Change-out gls 6/9/20 XASR * 2500 psi BOPE test * 7" casing test to 1500 psi 6/9/2020 1,340 10-404 (Monobore) Comm 6/10/2020 dts 6/9/2020 JLC 6/10/2020 RBDMS HEW 6/12/2020 ESP Change-Out Well: MPU G-14 Date: 06-03-20 Well Name:MPU G-14 API Number: 50-029-23031-00 Current Status:Shut-in ESP Producer Pad:G-Pad Estimated Start Date:July 15th, 2020 Rig:ASR Reg. Approval Req’d?Yes Date Reg.Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:201-133 First Call Engineer:David Gorm (907) 777-8333 (O) (505)-215-2819 (M) Second Call Engineer:David Haakinson (907) 777-8343 (O) (307)-660-4999 (M) AFE Number:Well EZ Entries Required Yes Current Bottom Hole Pressure:1,675 psi @ 3,955’ TVD Downhole Gauge: 2 month PBU (6/3/20)8.12 PPG Maximum Expected BHP:1,735psi @ 3,955’ TVD 2-Month PBU Extrapolation |8.40 PPG MPSP:1,340psi Gas Column Gradient (0.1 psi/ft) Max Inclination 63° @ 3,550’ MD Max Dogleg:4.5°/100ft @ 2,435’ MD Brief Well Summary: MPU producer G-14 was drilled and completed as a Schrader Bluff N, OA, and OB producer in 2001. The well is a dual lateral slotted liner producer in the OA and OB sands and completed with screens across the N sand. The well was last completed in July 2019 and ran until February 2020 at which point the well was SI due to suspected tubing leak. The subsequent leak detect log confirmed 1 BPM TxIA communication at 700 psi through 4 separate locations which appeared to be connection leaks. A follow-up tubing caliper performed 4/4/20 confirmed extensive internal tubing corrosion. Notes Regarding Wellbore Condition x The 7” production casing passed an MIT to 1,500 psig from 5,927’ MD on 2/6/2013. x Offset Injector Support o G-07: Offline o G-17: Offline o J-12: Offline Objective: x Pull 2-7/8” Tubing String, Baker Hughes 76 HP motor, and Baker 114 P6 ESP. x Install new Baker Hughes 76 HP motor, and Baker 114 P6 ESP, and new 2-7/8” tubing. Sundry Procedure (Approval Required to Proceed) Pre-Rig Procedure 1. RU hot oil and PT lines to 3000 psi. 2. Bullhead 70 bbls of 8.4 ppg produced/source water down tubing to the formation. 3. Bullhead 425 bbls of 8.4 ppg produced/source water down IA to the formation. 4. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 MeOH. a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 5. RD hot oil truck. 6. Clear and level pad area in front of well. Spot rig mats and containment. The subsequent leak detect log confirmed 1 BPM TxIA communication at 700 psi through 4 separate locations which appeared to be connection leaks.tubing leaks ASR ESP Change-Out Well: MPU G-14 Date: 06-03-20 7. RD well house and flowlines. Clear and level area around well. 8. RU crane. Set BPV. ND Tree. Inspect the tubing hanger lift thread and note any damage. 9. NU BOPE. RD Crane. 10. Spot mud boat. RWO Procedure: 11. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 12. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well w/8.4 ppg produced/source water prior to pulling BPV. 13. Set TWC. 14. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “ASR 1 BOP Test Procedure” dated 11/03/2015. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15.Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 16. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.6 ppg filtered seawater or weighted source water as needed. 17. Rig up spoolers for ESP #2RD cable. a. Baker Hughes representative should be onsite for ESP pull. 18. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. The SD = 19K when landed by ASR in July 2019 b. ~5700’ of 6.5 # 2-7/8” tubing weighs ~ 37Klbs(dry) or 32Klbs(buoyed by 8.6 ppg fluid) c. If needed, circulate (long or reverse) pill with lubricant, source-water, and/or baraclean pill prior to laying down the tubing hanger. 19. Lay down tubing hanger. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High BOPE test to 2500 psi MIRU Hilcorp ASR #1 WO Rig, ESP Change-Out Well: MPU G-14 Date: 06-03-20 Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 20. POOH and lay down the 2-7/8” tubing while spooling 2AWG SOLBC ESP cable. Lay down ESP and motor. a. Due to heavy corrosion of tubing it will be junked. b. Note any sand or scale inside or on the outside of the ESP in WSR. c. The completion has the following amount of clamps/guards/cap-string: i. 107 Cross Collar Clamps 1. Clamps every other except for: 2. Joints 108-112 and 127-129 are clamped on every joint. ii. 4 Pump Clamps iii. 4 Protectolizers Pulled Equipment Disposition Tubing hanger Visually inspect on site then re-stock Tubing & Pup joints Junk ESP Cable Junk GLMS Junk ESP Equipment Visually inspect on site then provide to Baker for Redress Clamps Visually inspect on site then re-stock XN Nipple Junk 21. PU 7” test packer and RIH to +/- 5750’ MD 22. Pressure Test 7” casing to 1,500 psi for 30 minutes a. If pressure test fails, begin moving up-hole and testing in intervals to determine possible leak point. 23. POOH w/test packer and lay down equipment. 24. PU new ESP and RIH on 2-7/8” 6.5# 13-CR tubing. Set base of ESP assembly at ± 5,700’ MD. a. Check ESP cable conductivity every 2,000’. Proposed Running Order (Note: Equipment should be coated) a. Base of ESP centralizer @ ±5,700’ MD b. Motor gauge c. 75 HP Baker Hughes 562XP Motor d. Tandem Gas Separator with gas avoider e. Baker Hughes 114 stage P6 ESP f. Downhole gauge for discharge temperature and pressure. i. Connected with a jumper from the lower sensor. Does not require a separate tech-wire. g. 1 joint of 2-7/8”, 6.5#, EUE 8rd tubing h. 2-7/8” XN (2.205” No-Go) Nipple PU ESP and RIH Pressure Test 7” casing to 1,500 psi for 30 minutes POOH and lay down the 2-7/8” tubing while spooling 2AWG SOLBC ESP cable. MIT casing ESP Change-Out Well: MPU G-14 Date: 06-03-20 i. 3 joints of 2-7/8”, 6.5#, EUE 8rd tubing j. Lower 2-7/8”x 1” Side-pocket GLM with Dummy GLV k. ± 171 joints 2-7/8”, 6.5#, EUE 8rd tubing l. Upper 2-7/8”x 1” Side-pocket GLM @ ± 200’ MD with 0.25” OV m. ± 5 joints 2-7/8”, 6.5#, EUE 8rd tubing 25. PU and MU the tubing hanger with landing joint. 26. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 27. Set TWC. 28. RDMO ASR. Post-Rig Procedure: 29. RD mud boat. RD BOPE house. Move to next well location. 30. RU crane. ND BOPE. 31. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 32. Pull TWC. 33. RD crane. Move returns tank and rig mats to next well location. 34. Replace gauge(s) if removed. 35. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic 4. Blank RWO MOC Form NOte: SVS system test within 5 days _____________________________________________________________________________________ Revised By: JCM 4/09/2020 SCHEMATIC Milne Point Unit Well: MPU G-14 Last Completed: 7/22/19 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD =9,405’ (MD) / TD = 4,210’(TVD) 20” 4 1 PBTD =9,405’(MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 2 3 7 8 & 9 10 & 11 14 5& 6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID =3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.5 / L-80 / EUE 2.347 Surface 5,699’ JEWELRY DETAIL No Depth Item 1189’STA#1: GLM – 2-7/8" 6.5# L-80 EUE GLM Orifice 2 1,011’ TAM PORT COLLAR 35,484’STA#2: GLM – 2-7/8" 6.5# L-80 EUE GLM Dummy 4 5,598’ 2-7/8” XN Profile (2.205" No-Go) 5 5,647’ Bolt On Discharge Head: PMP 400 2.88X8 EUE CS 6 5,647.7’ Ported Discharge Head: PRESS PORT 400P 7 5,648’ Pump: 400PMSXD 141 P6 M FER N 8 5,664’ Gas Separator: 538GSTHVEVX MT H6 FER 9 5,670’ Gas Avoider: 513 HD HS 1" 10 5,673’ Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 11 5,679’ Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 12 5,686’ Motor: KMHG 562 76Hp /1,360V/34A 04R 13 5,695’ Motor Gauge: Zenith 14 5,697’ 2-3/8" EUE Centralizer:Bottom at 5,699’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole NOTE: Monobore well _____________________________________________________________________________________ Revised By: DG 6/2/2020 PROPOSED Milne Point Unit Well: MPU G-14 Last Completed: 7/22/19 PTD: 201-133 27 29Slotted Liner Slotted Liner 28 26 TD = 9,405’ (MD) / TD = 4,210’(TVD) 20” 4 1 PBTD =9,405’ (MD) / TD = 4,210’(TVD) Orig. KB Elev.: 62.93’/ Orig. GL Elev.: 29.5’ RKB – Hanger: 25.55’ (Doyon #16) Min ID = 2.205” 2 3 7 8 & 9 10 & 11 14 5 & 6 7” 21 22 23 24 “OA” Lateral “OB” Lateral 25 Min ID = 3.985” 15 17 N Sands 16 18 19 20 Min ID = 3.907” 12 13 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92 / H-40 / Welded N/A Surface 112' 7" Production 26 / L-80 / BTC-MOD 6.151 Surface 7,132’ 4-1/2” Liner “A” 12.6 / L-80 / IBT 3.833 6,499’ 9,348’ 4-1/2” Liner “B” 12.6 / L-80 / IBT 3.833 7,028’ 9,405’ TUBING DETAIL 2-7/8” Tubing 6.5 / CR-13 / EUE 2.347 Surface ±5,700’ JEWELRY DETAIL No Depth Item 1 ±189’STA#2: GLM – 2-7/8" 6.5# L-80 EUE GLM Orifice 2 1,011’ TAM PORT COLLAR 3 ±5,484’STA#1: GLM – 2-7/8" 6.5# L-80 EUE GLM Dummy 4 ±5,598’2-7/8” XN Profile (2.205" No-Go) 5 ±5,647’Bolt On Discharge Head: 6 ±5,647.7’Ported Discharge Head: 7 ±5,648’Pump: 8 ±5,664’Gas Separator: 9 ±5,670’Gas Avoider: 10 ±5,673’Upper Tandem Seal: 11 ±5,679’Lower Tandem Seal: 12 ±5,686’Motor: 13 ±5,695’Motor Gauge: 14 ±5,697’2-3/8" EUE Centralizer:Bottom at ±5,699’ 15 6,077’ 7” Halliburton VTL Packer (3.880” ID) 16 6,097’ 4-1/2” LLP Screen 12/20 Resin-Coated Mesh 20 Gauge (3 joints; 4.000” ID) 17 6,285’ Baker Seal Assembly, 5.69’ Long (4.50” ID) 18 6,286’ 7” Baker SLZXP Packer 19 6,319’ 4-1/2” XN Profile (3.813” Packing Bore ID; 3.725” No-Go Min ID) 20 6,330’ 4-1/2” WLEG (3.958” ID) 21 6,499’ OA Lateral Hook Wall, Hanger above 7” Window 22 6,520’ OA Lateral Hook Wall, Hanger below 7” Window 23 7,028’ OB Lateral Tie Back Sleeve 24 7,037’ OB Lateral ZXP Liner Top Packer 25 7,042’ OB Lateral 7” x 5” HMC Liner Hanger 26 9,304’ OA Lateral Pack-Off Bushing (Min ID = 2.500”) 27 9,348’ OA Lateral 4-1/2” Btm of Guide Shoe 28 9,362’ OB Lateral Pack-Off Bushing (Min ID = 2.500”) 29 9,405’ OB Lateral 4-1/2” Btm of Guide Shoe WELL INCLINATION DETAIL KOP @ 300’ MD Max Wellbore Angle = 86.6 deg @ 6,691’ MD Hole Angle = 64.0 deg @ 5,908’ MD GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E – 8/14/2001 Completed by Nabors 4ES – 9/25/2001 ESP Repair by Nabors 3S – 7/24/2008 ESP Repair by Nabors 4ES – 8/24/2008 ESP Repair & Tbg Change by Doyon 16 – 2/10/2013 ESP Change-out by ASR – 7/22/2019 LATERAL WINDOW DETAIL Top of “OA” Window @ 6,508’ MD; Bottom @ 6,520’ MD; Angle @ top of window is 74 deg Top of “OB” Window @ 7,028’ MD; Bottom @ 7,042’ MD; Angle @ top of window is 85 deg TREE & WELLHEAD Tree 2-9/16”- 5M FMC Wellhead 11” 5M Gen 6 w/ 2-7/8” EUE 8 rd Top & Btm Thread. Tubing Hanger w/ CIW ‘H’ Profile. OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30” Hole 7" Cmt w/ 860 sx PF ‘L’, 512 sx Class “G” in 9-7/8” Hole Milne Point ASR Rig 1 BOPE 2020 Updated 1/09/2020 11” BOPE 4.48' 4.54' 2.00' INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind11'͛- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureDate: June 3rd, 2020Subject: Changes to Approved Sundry Procedure for Well G-14Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Step Page Date Procedure ChangeHAKPreparedBy (Initials)HAKApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Operations Manager DatePrepared:Operations Engineer Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS a 1. Operations Abandon LJ Plug Perforations Li Fracture StimulatLJ Pull Tubing Li Operations shutdown Ll Performed: Suspend ❑ Perforate ❑ Other Stimulat❑ Alter Casing ❑ Change Approved Program ❑ Plug for Reddll ❑ >rforate New Pool ❑ Repair We[-] Re-enter Susp Well ❑ Other: ESP Change -out ❑� 2. Operator 4. Well Class Before Work: 5. Permit t0 Drill Number: Name: Hilcorp Alaska LLC Development p ❑ Stratigraphic❑ Ex Exploratory ry ❑ Service ❑ 201-133 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23031-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025906 / ADL0315848 MILNE PT UNIT G-14 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A MILNE POINT / HILCORP ALASKA LLC 11. Present Well Condition Summary: Total Depth measured 9,405 feet Plugs measured N/A feet true vertical 4,214 feet Junk measured N/A feet 6,077, 6,286 & Effective Depth measured 9,405 feet Packer measured 7,037 feet 4,087, 4,172 & true vertical 4,214 feel true vertical 4,476 feet Casing Length Size MD TVD Burst Collapse Conductor 112' 20" 112' 112' N/A N/A Surface 7,097' 7" 7,132' 4,513' 7,240psi 5,410psi Production Liner 2,377' 4-1/2" 9,405' 4,214' 8,430psi 7,500psi OA Liner 2,850' 4-1/2" 9,348' 4,150' 8,430psi 7,500psi OB Liner 2,377' 4-1/2" 9,406' 4,214' 8,430psi 7,500psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 / EUE 5,699' 3,814' VTL, SLZXP & Packers and SSSV (type, measured and true vertical depth) ZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 540 0 Subsequent to operation: 98 71 206 240 213 14. Attachments (required per 20 AAc 25.070.25.o71, & 25.283) 15. Well Class after work: Daily Report of Well Operations [a Exploratory[-] Developmentlz Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil E] Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-302 Authorized Name: Chad Helgeson Contact Name: David Haakins n Authorized Title: Operations Manager Contact Email: dhaakinson(Whilcorp.cor Authorized Signature: Date: 8/20/2019 Contact Phone: 777-8343 Form 10-404 Revised 412017 i�BDMSIAUG 2 3 2019 Submit Original Only Milne Point Unit Well: MPU G-14 SCHEMATIC Last Completed: 2/10/2013 Ililcoro Aloaka. Ll.f. PTD: 201-133 TREE & WELLHEAD OPEN HOLE / CEMENT DETAIL Tree 2-9/16"- 5M FMC 20"Cmt w/ 260 sx of Arcticset I in 30" Hole Wellhead 11"5M Gen 6 w/2-7/8"EUE 8 rd Top &Btm 7" Cmt w/860 sx PF'L', 512 sx Class "G"in 9-7/8"Hole Od&KBElev.:62.93'/(ri&GLFJev.:29.5' Thread. Tubing Hanger w/OW'H'Pro file. RKB-Hanger. 25.55' (Doyon #16) CASING DETAIL Mo ID=225" 3 4 f 7 6&9 10 & 11 I 12 r13 14 i 15 6 N Sails l 1] 18 19 20 i 5 21 MnID=3.985:i Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 92/H-40/Welded N/A Surface 112' 7" Production 26/L-80/BTC-MOD 6.151 Surface 7,132' 4-1/2" Liner"A" 12.6/ L-80 / IBT 3.833 6,499' 9,348' 4-1/2" Liner"B" 12.6 / L-80 / IBT 3.833 7,028' 9,405' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 1 2.347 1 Surface 1 5,699' WELL INCLINATION DETAIL KOP @ 300' MD Max Wellbore Angle=86.6 deg @ 6,691' MD Hole Angle = 64.0 deg @ 5,908' MD LATERAL WINDOW DETAIL Top of "OA" Window @ 6,508' MD; Bottom @ 6,520' MD; Angle @ top of window is 74 deg Top of "OB" Window @ 7,028' MD; Bottom @ 7,042' MD; Angle @ top of window is 85 deg JEWELRY DETAIL No Depth Item 1 189' STA#1: GLM - 2-7/8" 6.5# L-80 EUE GLM Orifice 2 1,011' TAM PORT COLLAR 3 5,484' STA#2: GLM - 2-7/8" 6.5# L-80 EUE GLM Dummy 4 5,598' 2-7/8" XN Profile (2.205" No -Go) 5 5,647' Bolt On Discharge Head: PMP 400 2.88X8 EUE CS 6 5,647.7' Ported Discharge Head: PRESS PORT 400P 7 5,648' Pump: 40OPMSXD 141 P6 M FER N 8 5,664' 1 Gas Separator: 538GSTHVEVX MT H6 FER 9 5,670' 1 Gas Avoider: 513 HD HS 1" 30 5,673' UpperTandem Seal: GSB3DB H6 SB/AB PFSA 11 5,679' Lower Tandem Seal: GS83DB H6 SB/AB PFSA 12 5,686' Motor: KMHG 562 76Hp /1,360V/34A 04R 13 5,695' Motor Gauge: Zenith 14 5,697' 2-3/8" EUE Centralizer: Bottom at 5,699' 15 6,077' 7" Halliburton VTL Packer (3.880" ID) 16 6,097' 4-1/2" LLP Screen 12/20 Resin -Coated Mesh 20 Gauge (3 joints; 4.000" ID) 17 6,285' Baker Seal Assembly, 5.69' Long (4.50" ID) 18 6,286' 7" Baker SLZXP Packer 19 6,319' 4-1/2" XN Profile (3.813" Packing Bore ID; 3.725" No -Go Min ID) 20 6,330' 4-1/2" WLEG (3.958" ID) 21 6,499' OA Lateral Hook Wall, Hanger above 7" Window 22 6,520' OA Lateral Hook Wall, Hanger below 7" Window 23 7,028' OB Lateral Tie Back Sleeve 24 7,037' OB Lateral ZXP Liner Top Packer 25 7,042' OB Lateral 7" x 5" HMC Liner Hanger 26 9,304' OA Lateral Pack -Off Bushing (Min ID=2.500") 27 9,348' OA Lateral 4-1/2" Btm of Guide Shoe 289,362' OR Lateral Pack -Off Bushing (Min ID= 2.500" 29 9,405' OB Lateral 4-1/2" Btm of Guide Shoe 26 "ON Late Slotted Liner 27 23 25 28 MnID=3.90T ..��erg Slotted Liner 29 r TD=9,405' IND) / TD=4,210'(M) PBTD =9,405' (ND) /TD=4,210'(M) GENERAL WELL INFO API: 50029-23031-00-00 Drilled by Nabors 27E-8/14/2001 Completed by Nabors 4ES - 9/25/2001 ESP Repair by Nabors 3S-7/24/2008 ESP Repair by Nabors 4ES-8/24/2008 ESP Repair & Tbg Change by Doyon 16-2/10/2013 ESP Change -out by ASR - 7/22/2019 Revised By: TDF 8/20/2019 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP G-14 ASR 1 50-029-23031-00-00 201-133 7/13/2019 7/22/2019 Daily Operations. 7/10/2019- Wednesday No operations to report. 7/11/2019 -Thursday No operations to report. 7/12/2019 - Friday No operations to report. 7/13/2019 -Saturday Rig up ASR over the hole. RU all Pump lines and Flow lines. RU TBG tongs and work floor equipment. Start BOPE shell test. Chasing leak found leak on the Speed head just below the surface in the cellar buttoned up and retest. test was good. Start first test against the blinds failed high test. Chase leak but couldn't find any surface leaks tighten lock down, checked all fittings, and function rams. ended up testing the pressure censor to chart and found that the blatter was leaking. Going to rebuild and try again in the morning. 7/14/2019 -Sunday Start and service rig and equipment. Put new bladder in the Pressure sensor. Rig up and shell test good shell test. Conduct BOPE test on 2-7/8" Test jnt. 250/low 2,500/high as per sundry. Had one fail pass on valve C-09 replaced valve and had a good test. Blow down and rig down Test equipment. Pull test plug, Pull BPV had to let pressure bleed off, BOLDS( had some trouble getting gland nuts backed out possibly need to replace one), unland TBG 38k up wt. Break out TBG hanger. POOH/w ESP on 2-7/8" C-13 6.4# VamTop TBG POOH to 3,791'MD. Pulling at a slower speed 735'/hr to Keep any oil from the Schrader Bluff cleaned off pipe and cable. Clamp and cut cable prep the cable to be spliced back on and finish out of the hole in the morning. Sink back in the well in order to shut in the well. Secure well for the night. 7/15/2019 - Monday Start and service rig and equipment. Check pressure on the well and bleed off Pressure slight blow TSTM. Open well pull up and Splice on ESP cable. POOH/w 2-7/8" 6.4# Cr -13 VamTop TBG to 3,565'MD Pulling slow and fighting tbg slips with the oil try a number of cleaning tactics. Changed out slips to Type -C this seemed to do the trick. POOH/w 2-7/8" 6.4# Cr -13 VamTop TBG to 4,278 'MD when the tbg stopped draining. RU to circulate. Pump 135 BBLS down the tbg. Got returns back 15Bbls away. circulating @ 4BPM/400psi 60 total BBLS return when cleaned up. 2 to 1 returns. RD and blow down lines. / Cont. POOH to ESP to 110'MD when crew noticed flow at surface. Crew cut cable at clamp and sunk At then shut Pipe rams. Crew monitored flow at flow back tank. decision was made to shut in and Bull head 240 Bbls down CSG. Bull head 4BPM @ 600psi. Stop and monitor well watch pressure go on a vac. Lay down Last 2 jnts of 2-7/8" 6.4# Cr -13 VamTop TBG. and ESP Equipment Total clamp count= 102 CC -clamps, 2 flat guards, 4 Protectilizers;secure well for the night. 7/16/2019 -Tuesday Start and service rig and equipment, Check Pressure on the well 50 psi bleed off. Prep the test hanger and set in the well RILDS, Prep the 2-7/8" test mandril;Fill the stack and try to get shell test. chased a leak at gland nut on lock down screw, also at pump through T. Tighten up and get a good shell test. Call out the state. Start loading Used 2-7/8" c-13 6.4# on the racks start clean and inspect thread and box ends for any damage while wait on state inspector. Plan is to run it back in the hole. State arrive conduct a good BOPE usage Retest 250/low and 2,500/high test on the pipe rams with 2-7/8" test mandril. also test C5,C9,C10,K3 valves and FOSV. Do Draw down on accumulator. Start working on Scheduled Maintenance on rig as well as continue to inspect Cr -13 tbg. Deep clean rig floor from coming out of the hole. secure the well for the Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP G-14 ASR 1 50-029-23031-00-00 201-133 7/13/2019 7/22/2019 Daily Operations. 7/17/2019- Wednesday No operations to report. 7/18/2019-Thursday No operations to report. 7/19/2019 - Friday Perform daily rig services. Verify well control equipment, rig pit fluid levels and parameters, as well as pipe handling equipment. Bullhead 85 bbls of 120 deg produced water down the well bore in order to place warm fluids across the permafrost well section. Pump @ 3BPM w/ 490psi. Shut down pumps and monitor well. Pressure quickly bled down to 10psi. Set TWC in TBG hanger. Continue w/ rig maintenance activities. Pressure wash pits and internal walls of rig pits. Clean out cargo area in rig pits and organize. Replace whisker/brushes on V-door. Swap out all chrome TBG handling equipment for standard dies. Remove chrome TBG in prep for running L-80 instead. Notify AOGCC of upcoming BOPE test. Ask for inspector to witness in the am if possible. 7/20/2019-Saturday Perform daily rig services. Prep to test BOPE. Fill stack w/ fluid, burp out any air from system and close annular on 2-7/8" test mandrel. Attempt to perform shell test on annular and test mandrel in prep for calling AOGCC witness Matt Herrera. Unable to get good test. Track down leak to well bore. Call wellhead rep to location and swap out TWC. Rubber seals on TWC found to be corroded. Swap out TWC. Attempt to test again. Leak found to be going down hole again. Contact wellhead rep and swap out TWC dressed w/ new seals. Perform shell test. (Good Test). Contact AOGCC rep Matt Herrera and begin process of testing BOPE. Test BOPE to 250psi low f/ 5 charted min, 2,500psi high f/ 5 charted mins. Unable to get a good test on test sequence # 1. Contact wellhead rep and Swap out TBG hanger w/ blanking plug. Continue to test BOPE. Locate leak coming through hydraulic valves # 4. Open hydraulic valve # 4 and test against back kelly valve. Kelly valve found to be leaking as well. Swap out rear kelly valve and continue w/ BOPE test. Continue to test BOPE w/ state rep witness. All test pass, except testing the annular element. Discuss plan forward w/ AOGCC rep Matt Herrera. Decision made to pull test plug and continue testing annular element in the am. Roads and pads bring out back up annular from stack # 1. 7/21/2019-Sunday Perform daily rig maintenance. Monitor well bore. 250psi found below blind rams on BOPE. Bleed off pressure to tiger tank for 15 mins. 7bbls of what looks to be crude oil returned during bleed. Wellbore pressure fell down to 50psi. Continue to bleed well bore, watching to ensure a reduction in flow rate, or flow trend and pressure. P/U 2-7/8" test mandrel and attempt to test annular again, watching for fluid returns in the rig pits. Annular element seems to be holding. No fluid returns seen through the annular. Rig up chart recorder and perform pressure test on annular as per Sundry to 250psi low, 2,500psi high f/ 5 charted mins each. Oil and gas returns seen in BOP stack void between blind rams and annular. Burp and re-test. Good test. Contact AOGCC rep Matt Herrera and send him test chart results. Given permission to move forward from state rep. SIMOPS: Mix 250bbis of 8.5ppg KCI in rig pits. Once fluids up to weight, bullhead 250bbls of 8.5ppg KCI down the well bore @ 4BPM w/ 790psi pump pressure. Shut down and observe well. Well bore on losses. Drain BOPE and R/D test equipment. L/D test mandrel and break off TIW/ pump -in sub. Rig crews break out for lunch. Monitor well bore after bullhead and ensure it remains on losses. Baker Centrilift on location w/ ESP pump @ 1pm. Load and tally pump equipment. P/U pump and begin process of servicing. Load and tally 185jnts of 6.5# L-80 EUE TBG for completion run. Pull MLE cable across ESP sheave and plug into ESP, M/U discharge head and prep. Leave pump hanging in derrick, ready to begin tripping in hole on TBG. Rig crew secure well via blind rams and mud cross. Shut down location for the night. Total losses for the day = 250bbls of 8.5ppg KCI. Well secured until morning. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPG -14 ASR 1 50-029-23031-00-00 201-133 7/13/2019 1 7/22/2019 Daily Operations. 7/22/2019- Monday Perform daily rig maintenance actives in prep for operations. 250psi pressure seen below blind rams on well bore. Line up to bleed off pressure. R/U Baker Centrilift in prep for RIH. RIH w/ ESP completion on 2-7/8" 6.5# EUE TBG f/ 50' and to 1,814' and (504'/hr). Testing ESP cable @ 500' md, 1500' md. Clamp cable every other joint with the exception ofjnts 108- 112 and 127-129 which are clamped every joint. Hole consistently venting gas at low levels. Issue with rig elevators. Shut down and trouble shoot. Trouble shoot faulting hydraulic elevators. Discuss w/ Prostar. Re -set rig electronic system and elevators began to work again. RIH w/ ESP completion on 2-7/8" 6.5# EUE TBG f/1814' and to 5697' and (706'/hr). Test cable @ 2,500' and and every 2,000' and thereafter. Clamp cable every otherjoint with the exception of jnts 108-112 and 127-129 which are clamped everyjoint. Hole consistently venting gas at low levels. M/U TBG hanger and perform ESP cable penetrator splice. Land TBG hanger, RILDS and set BPV. R/D for the night. 7/23/2019 - Tuesday No operations to report. AFU G-(4- Regg, James B (CED) Prn 0011330 From: Carl Linaman - (C) <clinaman@hilcorp.com> Sent: Monday, July 15, 2019 9:56 PM ��'/�q /� y. To: DOA AOGCC Prudhoe Bay Cc: Ian Toomey - (C); Cody Rymut - (C); Chad Helgeson; Taylor Wellman Subject: BOBE Usage Report Date/Time Used: July, 15`h 2019 16:30HRS, Well/Location/PTD: MPU G-14 PTD:201-133 Rig Name: ASR#1 Operator Contact: Carl Linaman 685-1266 Office, Cell 307-277-0813 Operations Summary: While POOH with ESP completion on 2-7/8" TBG flow was noted by the pit watcher at the possum belly. ASR #1 operator stabbed a TIW valve on t e TFGand shut the VBR rams on the 2 7/8" TBG to divert the flow of fluids from up the IA to an outside flow back tank via the choke manifold. Prior to seeing flow operator was managing wellbore fluids using a trip sheet. Filling the I.A. every 15jnt with 1.9Bbls of displacement with 8.4# source water. Flow was diverted to the flow back tank and monitored. Flow was noted to be diminishing. After 15 mins flow had reduced to a trickle. Well was then shut in via HCR choke and bull headed with 240 Bbls of 8.4ppg source water down I.A.. Well went on a vac. Crew opened up wellbore and finished laying down 2 Joints and ESP Equipment. BOP Used: 2-7/8" x 3-1/2" VBR -� Reason For BOP Use: To contain and divert well bore fluids to a safe location. Actions Taken / To Be Taken: Notifications we're made to the state. Set test plug and re -test 2-7/8" x 3-1/2" VBR rams as well as HCR choke. BOPE was last tested on 07/11/2019. Thanks! Carl Linaman Company Rep, ASR #1 Hilcorp, Alaska Cell: 307-277-0813 Office: 907-685-1266 clinaman@hilcorp.com THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU G-14 Permit to Drill Number: 201-133 Sundry Number: 319-302 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wvdw. a o g c c. a l a s k a. g o v Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this�&y of June, 2019. RBDMSL' JUN 2 6 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 90 AAC 25 280 JUS! 19 919 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q • Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casin g ❑ Other: ESP Change -out ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 201-133 - 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23031-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C. 0. 477.05 Will planned perforations require a spacing exception? Yes ❑ No Q MILNE PT UNIT G-14 9. Property Designation (Lease Number): 10. Field/Pool(s): [ �� L-2j /cirp ADL0315848 Pi- U'ZY MILNE POINT / F, CDRP-ktfc3KRtt$ 1t. % 6'25-: PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,405' • 4,214' 9,405' 4,214' 1,201 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 112' 29' 112' 112' N/A N/A Surface 7,097 T' 7,132' 4,513' 7,240psi 5,410psi Production Liner 2,377' 4-1/2" 9,405' 4,214' 8,430psi 7,500psi OA Liner 2,850' 4-1/2" 9,348' 5,439' 8,430psi 7,500psi OB Liner 2,377 4-112^ 9,406 5,464' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8" 6.4#! 13 -Cr / Vern Top 5,930' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): VTL, SLZXP & ZXP LTP and N/A 6,077 MD/ 4,087 TVD, 6,286 MD/ 4,172 TVD & 7,037 MD/ 4,476 TVD and N/A 12. Attachments: Proposal Summary 0 Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑Q Exploratory ❑ Stratigraphic ❑ Development ❑✓ * Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 7/2/2018 OIL Q 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: Chad Helgeson Contact Name: David Haakinson Authorized Title: Operations Manager Contact Email: dh22klnsOn hillOrn.com Contact Phone: 777-8343 Authorized Signature: Date: 6!1712019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: !✓, (_AI Plug Integrity ❑ BOP Test 19/ Mechanical Integrity Test ❑ Location Clearance ❑ Other: i i QU Z8r ei'— /S`: Post Initial Injection MIT Req'd? Yes ❑ No ❑�(/ :WMS JUN 2 6 2019 Spacing Exception Required? Yes El No I� Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date � /2 4; (PI/�111 G zs'/9 Form 10-403 Revised 412017 Approved applicatQis Rid fQ24he date of approval. Submit Farm and Attachments in Duplicate n Hile p Alaska, LU ESP Change -Out Well: MPU G-14 Date: 06-11-19 Well Name: MPU G-14 API Number: 50-029-23031-00 Current Status: Shut-in ESP Producer Pad: G -Pad Estimated Start Date: July 2nd, 2019 Rig: ASR Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 201-133 First Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) Second Call Engineer: Ian Toomey (907) 777-8434 (0) (907) 903-3987 (M) AFE Number: Job Type: ESP Swap Current Bottom Hole Pressure: 1,480 psi @ 3,990' TVD Maximum Expected BHP: 1,600 psi @ 3,990' TVD MPSP: 1,201 psi Max Inclination 63° @ 3,550' MD Max Dogleg: 4.5°/100ft @ 2,435' MD BPV Profile: 2-1/2" CIW Type H Downhole Gauge: 1 -month PBU (6/11/19) 17.13 PPG 2 -Month PBU Extrapolation 17.70 PPG Gas Column Gradient (0.1 psi/ft) Brief Well Summary: MPU producer G-14 was drilled and completed as a Schrader Bluff N, OA, and OB producer in 2001. The well is a dual lateral slotted liner producer in the OA and OB sands and completed with screens across the N sand. The well was last completed in February 2013 with an ESP completion that had an extended run life until May 2019 at which the well was SI due to a suspected broken shaft. The producer averages approximately 150 BOPD. The well was noted to have past scale problems and thus a scale inhibitor squeeze will be pumped as part of the pre -rig work. The producer was shut-in on 5/7/19 after an apparent motor shaft break. Notes Regarding Wellbore Condition t g'p'— • The 7" production casing passed an MIT to 1,500 psig from 5,927' MD on 2/6/2013. • Tubing passed a pressure tested to 2,000 psig post ESP failure to confirm no tubing leak exists. • Note that well is currently completed with Chrome -13 tubing. Offset Injector Support o G-07: Online 1200 psig WHIP @ 700 BWIPD o G-10: Online 760 psig WHIP @ 500 BWIPD Objective: • Pull 2-7/8" Tubing String, P17 and P75 tandem ESPs, and 114 HP motor. • Install new Baker Hughes 75 HP motor, 141 -stage P6 ESP, and new 2-7/8" tubing. Pre -Rig Procedure: 1. MIRU Slickline Unit a. Pull OV from GLM @ 139' MD b. Pull DV from GLM @ 5,688' MD c. Install DV in GLM @ 139' MD 2. RU LRS and PT lines to 3000 psi. 3. Bullhead 70 bbls of 8.3 ppg produced or source -water down tubing to the formation. 4. Bullhead 425 bbls of 8.3 ppg produced or source -water down IA to the formation. 5. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH. U liilm A6ska LU ESP Change -Out Well: MPU G-14 Date: 06-11-19 a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 6. RD Little Red Services. 7. Clear and level pad area in front of well. Spot rig mats and containment. 8. RD well house and flowlines. Clear and level area around well. 9. RU crane. Set BPV. NO Tree. Inspect the tubing hanger lift thread and note any damage. 10. NU BOPE. RD Crane. 11. Spot mud boat. Brief RWO Procedure: 12. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 13. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well w/ 8.3 ppg produced or source -water prior to pulling BPV. 14. Set TWC. 15. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per "ASR 1 BOP Test Procedure" dated 11/03/2015. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 16. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. �Q.v�., b. With stack out of the test path, test choke manifold per standard procedure j� c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 17. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ 8.3 ppg produced or source -water as needed. 18. Rig up spoolers for ESP #1RD cable. a. Baker Hughes representative should be onsite for ESP pull. 19. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. The PU weight= 75K and SO= 671(when landed by Doyon 16 with block weight of 40K. K [iik.m Alaska, LL, ESP Change -Out Well: MPU G-14 Date: 06-11-19 b. If needed, circulate (long or reverse) pill with lubricant, source -water, and/or baraclean pill prior to laying down the tubing hanger. 20. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 21. POOH and lay down the 2-7/8" tubing spooling ESP cable. Lay down ESP and motor. a. Send all tubing to G&I for washing and preparation for inspection in Deadhorse. b. Note any sand or scale inside or on the outside of the ESP on the morning report. c. The completion has the following amount of clamps/guards/cap-string: i. 102 Cannon Clamps 1. Cannon clamps on first 9 joints, and then every other joint thereafter. 2. Joints 108-112 and 127-129 are clamped on every joint. ii. 5 Pump Protectolizers iii. 1 Motor Protectolizer iv. 4 Armsterguards v. 6 Protectolizers 22. PU new ESP and RIH on 2-7/8" 6.5# L-80 tubing. Set base of ESP assembly at 6,000' MD. a. Check ESP cable conductivity every 2,000'. b. Optimum tubing make-up torque: 2,250 ft -lbs a. Base of ESP centralizer @ ±5,700' MD b. Motor gauge c. 75 HP Baker Hughes 562XP Motor d. Tandem Gas Separator with gas avoider e. Baker Hughes 141 stage P6 ESP f. Downhole gauge for discharge temperature and pressure. i. Connected with a jumper from the lower sensor. Does not require a separate tech -wire. g. 1 joint of 2-7/8", 6.5#, L-80, EUE 8rd tubing h. 2-7/8" XN (2.205" No -Go) Nipple i. 3 joints of 2-7/8", 6.5#, L-80, EUE 8rd tubing j. Lower 2-7/8"x 1" Side -pocket GLM with Dummy GLV k. ± 171 joints 2-7/8", 6.5#, L-80, EUE 8rd tubing I. Upper 2-7/8"x 1" Side -pocket GLM @ ± 200' MD with 0.25" OV m. ± 5 joints 2-7/8", 6.5#, L-80, EUE 8rd tubing 23. PU and MU the tubing hanger with landing joint. 24. Land the tubing hanger and RILDS. Lay down landing joint. Note Pick-up and slack -off weights on tally. 25. Set TWC. 26. RDMO ASR. HESP Change -Out Well: MPU G-14 Ilileore .Tasha. LU Date: 06-11-19 Post -Rig Procedure: 27. RD mud boat. RD BOPE house. Move to next well location. 28. RU crane. ND ROPE. 29. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 30. Pull TWC. 31. RD crane. Move returns tank and rig mats to next well location. 32. Replace gauge(s) if removed. 33. Turn well over to production. RU well house and flowlines. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic 4. Blank RWO MOC Form n eorp AI.A., LLC Ong. IB Elev.: 62.937 Orig. GL Bev.: 29.5' RKB-Harger: 25.55' (Doyon916) AMD=22 Milne Point Unit Well: MPU G-14 SCHEMATIC Last Completed: 2/10/2013 PTD: 201-133 TRFF P WFI I HEAT) Tree 2-9/16"-5M FMC Wellhead 11"5M Gen 6w/2-7/8"EUE8 rd Top &Btm Thread. Tubing Hanger w/ Cl W 'H' Profile. -E^�- OPEN HOLE /CEMENT DETAIL RCl1 20" Cmtw/260sxofArctiuetlin30"Hole 7" Cmt w/ 860 sx PF'U, 512 sx Class "G"in 9-7/8"Hole i CASING DFTAII 2 Size Type Wt/Grade/Conn Drift ID Top Btm 20" Conductor 92/H-40/Welded N/A Surface 112' 7" Production 26/L-80/BTC-MOD 6.151 Surface 7,132' 4-1/2" Liner "A" 12.6 / L-80 / IBT 3.833 6,499' 9,348' 4-1/2" Liner"B" 12.6/L-80/IBT 3.833 7,028' 9,405' TUBING DETAIL 2-7/8" Tubing 6.4/13-Cr/Vam Top 2.867 Surface 5,930' 3 WELL INCLINATION DETAIL kOP @ 300' MD ax Wellbore Angle=86.6 deg @6,691'MD 4 Hole Angle =64.0 deg @5,908'MD LATERAL WINDOW DETAIL 5 6 7 JEWELRY DETAIL No Depth 12 1 139' Sta #2: GLM -Camco KBMM-2 2_7/R-. 1" -OGLV set 7/31/2004 BEK Latch 2 1,011' 13 N Ms 5,688' Sta #1: GLM -Camco KBMM-2 2-7/8" x 1" - DGLV set 7/31/2004 SBK-2C Latch 4 5,831' 2-7/8"XNProfile1Packin0eore MinlD=2.205") 5 5,875' 14 6 5,876' 15 7 5,894' 6 8 5,899' 7 9 5,905' 'is MnlD=3995' 5,912' Motor KMH-114 HP JEWELRY DETAIL No Depth Item 1 139' Sta #2: GLM -Camco KBMM-2 2_7/R-. 1" -OGLV set 7/31/2004 BEK Latch 2 1,011' TAM PORT COLLAR 3 5,688' Sta #1: GLM -Camco KBMM-2 2-7/8" x 1" - DGLV set 7/31/2004 SBK-2C Latch 4 5,831' 2-7/8"XNProfile1Packin0eore MinlD=2.205") 5 5,875' Discharge Head: FPHVDIS 6 5,876' Tandem Pumps: 79 P17 / 18 P75 7 5,894' Gas Separator: GRSFTX 8 5,899' Upper Tandem Seal 9 5,905' Lower Tandem Seal 10 5,912' Motor KMH-114 HP 11 5,923' Centralizerw/ Pump Mate Sensor - Bottom @ 5,930' 12 6,077' 7" Halliburton VTL Packer (3.880"ID) 13 6,097' 4-1/2" LLP Screen 12/20 Resin -Coated Mesh 20 Gauge (3 joints; 4.000" ID) 14 6,285' Baker Seal Assembly, 5.69' Long (4.50" ID) 15 6,286' 7" Baker SLZXP Packer 16 6,319' 4-1/2"X Profile (3.813" Packing Bore ID; 3.725" No -Go Min ID) 17 6,330' 4-1/2" WL----------- G(3958"ID)18 18 6,499' OA Lateral Hook Wall, Hanger above 7"Window 19 6,520' OA Lateral Hook Wall, Han er below 7" Window 20 7,028' OB Lateral Tie Back Sleeve 21 7,037' OB Lateral ZXP Liner Top Packer 22 7,042' OB Lateral 7" x 5"HMC Liner Hanger 23 9,304' OA Lateral Pack -Off Bushing (Min ID=2.S00") 24 9,348' OA Lateral 4-1/2" Btm of Guide Shoe 25 9,362' OB Lateral Pack -Off Bushing (Min ID = 2.500") 26 9,405' OB Lateral 4-1/2" Btm of Guide Shoe x + "W Ultra! Slotted Liner 24 p 21 22 25 Vin ID=3.907 r OB' -Lawd Slotted Liner 26 TD= 9,405' (MD) /TD=4,210'(TVD) P13TD=9,405' (MD)/TD=4,210'(nID) GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E-8/14/2001 Completed by Nabors 4ES - 9/25/2001 ESP Repair by Nabors 35 - 7/24/2008 ESP Repair by Nabors 4ES-8/24/2008 ESP Repair & Tbg Change by Doyon 16 - 2/10/2013 Revised By: TDF 6/17/2019 Milne Point Unit Well: MPU G-14 PROPOSED Last Completed: 2/10/2013 .P Alaska. LLC PTD: 201-133 TREE A WFI 114FAn Orig. HB Bev.: 62.93/ Orig. GL Elev.: 29.5' RIB -Hanger. 25.55' (Doyon #16) W ID= kin ID= 3.985' lig Tree OPEN 2 -9/16" -SM FMC Wellhead 11"SM Gen6w/2-7/8"EUE8 rd ton Thread. Tubing Hanger w/ CIW'H' Profile. OPEN HOLE/CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 30" Hole 7" 1 Cmt w/ 860 sx PF'L', 512 sx Class "G"in 9-7/8" Hole CASINO nFTAII Size*ism Depth Grade/ Conn Drift ID Top Eton 20" 1,011' -00/Welded N/A Surface 112' 7" ±5,624' -80/BTC-MOD 6.151 Surface 7,132' 6 ±5,662' 6/L-80/IBT 3.833 6,499' 9,348'-1/2"6/L-80/IBT 8 ±5,688' Motor: 76 HP 3.833 7,028' 9,405' TUBING DETAIL F.1 2-7/8" Tubing I 6.S/L-80/EUE8RD 1 2.347 Surface ±5,630' 3 WELL INCLINATION DETAIL KOP @ 300' MD Max Wellbore Angle =86.6 deg @ 6,691' MD 4 '' Hole Angle =64.0 deg @5,908'MD 9 LATERAL WINDOW DETAIL y6 E7, �JJ 7 8 r -n 10 1t 12 13 14 15 JEWFI RV nFTAII No Depth Item 1 ±200' STA#I:GLM -Cameo KBMM-22-7/8"x1"-0.25"DPOV 2 1,011' TAM PORT COLLAR 3 ±5,530' STA#2:GLM-Cameo KBMM-22-7/8"xi"-DUMMY GLV 4 ±5,624' 2-7/8" XN Profile (Packing Bore Min ID 22.205") 5 ±5,660' Discharge Head 6 ±5,662' ESP: 400 119 -Stage Flex10 7 ±5,682' Gas Separator: GRSFTX 8 ±5,688' Motor: 76 HP 9 ±5,698' Centralizer w/ Pump Mate Sensor -Bottom@5,700' 10 6,077' 7"Halliburton VTL Packer 13.880"ID) 11 6,097' 4-1/2" LLP Screen 12/20 Resin -Coated Mesh 20 Gauge (3 joints; 4.000" ID) 12 6,285' Baker Seal Assembly, 5.69' Long (4.50" ID) 13 6,286' 7" Baker SLZXP Packer 14 6,319' 4-1/2" XN Profile (3.533" Packing Bore ID; 3.725" No -Go Min ID) 15 6,330' 4-1/2" WLEG (3.958" IDJ 16 6,499' OALateral Hook Wall, Hanger above 7"Window 17 6,520' OA Lateral Hook Wall, Hanger below 7MWindow ,028 OB Lateral Tie Back Sleeve 19 7,037' OB LateralZL20 7,042' OBLateraY'21 9,304' OALateralckOffBushing (Min ID = 222 9,348' OALatefal/2"Guide S23 9,362' OB Lateral Pack -Off Bushing (Min ID = 2 24 9,405' OB Later 14-1/2" Btm of Guide Shoe 21 -M'laBxai Slotted Liner 22 181 •19 g7 23 Htn ID=3 ST' Y' '03' Lateral Slotted Liner 24 TD=9,405' (MD)/TD=4,210r(TVD) PBTD=9,405' (MD) /TD=4,210'(TVD) GENERAL WELL INFO API: 50-029-23031-00-00 Drilled by Nabors 27E -8/14/2001 Completed by Nabors 4ES - 9/25/2001 ESP Repair by Nabors 35 -7/24/2008 ESP Repair by Nabors 4ES - 8/24/2008 ESP Repair & TbChan eby Doyon 16 - 2/10/2013 Revised By: TDF 6/17/2019 Milne Point ASR Rig 1 BOPE n.�t. ►..l.u; 2018 11" BOPE Updated 1/05/2018 BR or Pipe Rams ind UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: June 1811, 2019 Subject: Changes to Approved Sundry Procedure for Well G-14 Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call" engineer. AOGCC written approval of the change is required before implementing the change. HAK Step Page Date Procedure Change Prepared B Initials -HA K Approved B Initials AOGCC Written Approval Received Person and Date Approval: Prepared: Operations Manager Date Operations Engineer Date STATE OF ALASKA RECEIVED KA OIL AND GAS CONSERVATION CISSION REPORT OF SUNDRY WELL OPERATIONS FEB 2 8 2013 1. Operations Performed: AOGCC ❑ Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate ❑ Re -Enter Suspended Well ❑ Alter Casing ® Pull Tubing ❑ Stimulate - Frac ❑ Waiver ® Other ❑ Change Approved Program ❑ Operation Shutdown ❑ Stimulate - Other ❑ Time Extension Change Out ESP 2. Operator Name: 4. Well Class Before Work: 5. Permit To Drill Number: BP Exploration (Alaska) Inc. ❑ Exploratory ❑ Stratigraphic 201 - 133 3. Address: ® Development ❑ Service 6. API Nur be P.O. Box 196612, Anchorage, Alaska 99519 - 6612 50.029 23031 - 00 - 00 7. Property Designation (Lease Number): 8. Well Name and Number: r ADL 025906 & 315848 ' MPG -14 9. Logs (list logs and submit electronic and printed data per 20AAC25.071): 10. Field / Pool(s): Milne Point Unit / Schrader Bluff 11. Present well condition summary: Total depth: measured 9405' feet Plugs:(measured) None feet true vertical 4214' feet Junk: (measured) None feet Effective depth: measured 9405' feet Packer: (measured) 6077' & 6286' feet true vertical 4214' feet Packer: (true vertical) 3979' & 4062' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 78' 20" 34' - 112' 34' - 112' 1490 470 Surface 7097' 7" 35' - 7132' 35- 4208' 7240 5410 Intermediate Production Liner 2377' 4 - 1/2" 7028' - 9405' 4201' - 4214' 8430 7500 Perforation Depth: Measured Depth: Perf6110 -6270, Slotted 7137 - 6362' feet True Vertical Depth: Perf 3992' - 4056', Slott 4208' - 4215' feet Tubing (size, grade, measured and true vertical depth): 2 6.4# 13Cr80 5930' 3917' 4 - 1/2 ", 12.6# L - 80 6077' - 6331' 3979' - 4079' Packers and SSSV (type, measured and true vertical depth): 7" Halliburton 23 - 29#'VTL' Versa - trieve Pkr 6077' & 6286' 3979' & 4062' & 7" Baker'SLZXP' Packer 12. Stimulation or cement squeeze summary: Intervals treated (measured): APR 7 5 Treatment description including volumes used and final pressure: SCANNE' I\ R 1 d 2013 13 Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 77 50 284 240 183 Subsequent to operation: 153 87 382 220 337 14. Attachme ❑Copies of Logs and Surveys run 15. Well Class after work: o ❑ Exploratory ❑ Stratigraphic ® Development ❑ Service ® Daily Report of Well Operations 16. Well Status after work: ® Oil ❑ Gas ❑ WDSPL ® Well Schematic Diagram ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact: Noel Nocas, 564 -4667 N/A Email: Noel.Nocas @bp.com Printed ame. Joe Lc stufk Title: Drilling Technologist i Signature ` Phone: 564 -4091 Date: 2/x 1 f IS Form 10-404 Re . ed 10/2012 RSDMS MAR 01 C��" - 1 , I Submit Original Only ii-! t 13 -446 • • O peration Summary Repo Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UVM: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 2/5/2013 02:00 - 04:00 2.00 MOB N PRE WAIT ON MPU ROADS AND PADS TO PREP MPG -14 - PREP RIG FOR MOVE AND PERFORM MAINTENANCE 04:00 - 09:00 5.00 MOB P PRE PJSM, FOR MOVE OFF MPG -15 - SPREAD HERCULITE AND PLACE MATS AROUND WELL NOTIFY PAD OPERATOR OF MOVE - BOTH TOOLPUSHERS AND WSL PRESENT TO PULL OFF WELL - PULL OFF MPG -15 AND SPOT AWAY FROM WELL TO ALLOW FOR RIG MAT PLACEMENT - MOVE OVER WELL MPG -14 - WSL TOOLPUSHER PRESENT. RIG ACCEPTED AT 09001-IRS 2/5/2013. 09:00 - 13:30 4.50 WHSUR P DECOMP PJSM, R/U KILL MANIFOLD IN CELLAR. - CIRCULATING LINE TO WELL HEAD. - TAKE ON 130 DEG F. SEAWATER (8.5PPG KWF) TO PITS. - CAN NOT BLOW THRU HARD LINE. REMOVE 2" VALVE, PLUGGED WITH SNOW FROM THE FIRST BLOW DOWN ATTEMPT. HEAT HARD LINE WITH STEAM. AMBIENT TEMP -40 DEG. F. - FILL LINES WITH DIESEL - PRESSURE TEST KILL MANIFOLD AND HARD LINE. - 250 / 3500 PSI F/5 CHARTED MIN. PASSED. 13:30 - 14:30 1.00 WHSUR P DECOMP HELD RIG EVACUATION DRILL. - HEAD COUNT WAS 16 WORKERS. AAR - IT WOULD BE HELPFUL IF THE TYPE OF EVACUATION DRILL WAS ANNOUNCED, FIRE, GAS, KICK, ECT. - SCBA WAS NOT PLACED IN THE CASE IN THE READY POSITION TO DON THE FACE MASK IN ATIMELY MANNER. - EVAC SIRENS ON EACH SIDE OF THE RIG NOWARE FULLY FUNCTIONAL. - IMPLEMENTED A PLAN TO HAVE BOTH ENTRANCES TO THE PAD BLOCKED DURING EVAC. 14:30 - 16:30 2.00 WHSUR P DECOMP PJSM PUDSM LUBRICATOR. RU TEST HOSES. - TEST LUBRICATOR TO 250 / 3500 PSI FOR 5 CHARTED MIN. EACH. - PULL BPV WITH TESTED LUBRICATOR. SITP = 450 PSI. SICP = 650 PSI - LD LUBRICATOR PER DSM REPS. -CLOSE OUT WWT ON MPG -15 Printed 2/18/2013 3:01:21 PM +rth America ALASKA BP °' Vi a Operation Summary Report Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UVN: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 16:30 - 17:30 1.00 WHSUR P DECOMP PJSM ON DDI WELL KILL SOP. - SITP = 450 PSI. SICP = 650 PSI. - WSL & TOOL PUSHER VERIFY VALVE ALIGNMENT. - BLEED GAS FROM THE IA TO FLOW BACK TANK. - BLEED IA FROM 650 PSI IN 22 MINUTES SITP = 150 PSI. - NO FLUID IN THE RETURNS. 17:30 - 19:30 2.00 WHSUR P DECOMP R/U TO BULLHEAD WELL VIA WELL KILL SKID IN CELLAR. - WSL &TOOL PUSHER VERIFY VALVE ALIGNMENT. - BULLHEAD DOWN 2 7/8" TBG AND IA SIMULTANEOUSLY. - - BULLHEAD WITH 130 DEGREE 8.5 PPG SEAWATER. 8.5.p _PG 585 BBLS KWF @ 7 BPM. - ICP TBG = 200 PSI. I/A = 200 PSI. - FCP @ TBG @ 7 BPM = 525 PSI I/A = 550 PSI. - SLOW TO 1 BPM @ TBG = 300 PSI. I/A = 300 PSI. PUMPS OFF @ 18:45 HRS. - SITP = 200 PSI. SICP = 200 PSI. - 10 MINUTES 50 PSI BOTH. 20 MINUTES TBG AND IA ON A VACUUM. - MONITOR WELL FOR THE FULL 30 MINUTES. 19:30 - 20:00 0.50 WHSUR P DECOMP BLOW DOWN & RIG DOWN CIRCULATING LINES & KILL MANIFOLD -R /U SECONDARY KILL LINE TO I/A -PUMP 70 BBLS TO TRY AND CATCH FLUID -BEGIN CONTINUOUS HOLE FILL © 20 BPH - SENT SECOND E -MAIL NOTICE TO AOGCC, BECAUSE WE RECEIVED NO 12 HR REPLY TO FIRST E -MAIL. 20:00 - 21:00 1.00 VVHSUR P DECOMP PJSM ON R/U LUBRICATOR AND SETTING TWC -R /U LUBRICATOR, CHART TEST 250 PSI LOW AND 3500 PSI HIGH 21:00 - 22:30 1.50 WHSUR P DECOMP . PERFORM ROLLING TEST FROM BELOW TW C -PUMP 89 BBLS © 7 BPM = 400 PSI. CHART FOR 10 MINS _-TEST TWC FROM ABOVE 250 PSI LOWAND 3500 PSI HIGH, CHARTED. 22:30 - 23:30 1.00 WHSUR P DECOMP PJSM TO DRAIN AND NIPPLE DOWN TREE & N/U BOPE - NIPPLE DOWN TREE -FMC REP CLEAN AND INSPECT EUE 8RD HANGER THREADS - CONFIRM 9 1/2 TURNS BY HAND 23:30 - 00:00 0.50 BOPSUR P DECOMP PJSM, NIPPLE UP BOPE - N/U 13 -5/8" BOPE STACK. -AOGCC , JEFF JONES WAIVED STATES ,RIGHT OF WITNESS BOP TEST - MAINTAIN HOLE FILL TO IA AT 20 BPH WITH 8.5 PPG SEAWATER. 2/6/2013 00:00 - 03:00 3.00 BOPSUR P DECOMP FINALIZE NIPPLE UP OF13 -5/8" BOPS -HOLD PJSM TO DISCUSS BOPE TEST Printed 2/18/2013 3:01:21 PM orth America - ALASKA Aeration Summary Report' Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:00 - 03:30 0.50 BOPSUR P DECOMP PREPARE FOR BOP TEST -R /U TEST EQUIPMENT -FILL RISER, NOTICE RISER AIR BOOT IS NOT SEALING AROUND RISER -PULL RISER FOR EXTENSION 03:30 - 04:30 1.00 BOPSUR N DECOMP SEND RISER TO SHOP AND EXTEND 8 ". - REINSTALL RISER. - PERFORM DERRICK INSPECTION -SERVICE DRAVWVORKS -MAKE SPCC CHECKS 04:30 - 14:30 10.00 BOPSUR P DECOMP PJSM, TEST THREE PREVENTER BOPE AND RELATED EQUIPMENT - TEST BOPE ACCORDING TO AOGCC REGULATIONS AND DOYON PROCEDURES TEST ANNULAR WITH 2 7/8" TEST JOINT TO 250 PSI LOW, 3500 PSI HIGH, 5 MINUTES EACH, CHARTED - TEST 2 7/8" X 5" VARIABLE RAMS WITH 2 7/8" AND 4" TEST JOINT, 250 PSI, 3500 PSI, 5 MIN, CHARTED - TEST BLIND RAMS, FLOOR VALVES, AND CHOKE MANIFOLD TO 250 PSI, 3500 PSI, 5 MIN, CHARTED - TEST VITH FRESH WATER - PERFORM ACCUMULATOR DRAW DOWN TEST. - NO FAILURES. II - JEFF JONES OF AOGCC WAIVED STATES RIGHT TO WITNESS BOP TEST - MAINTAIN CONTINUOUS HOLE FILL TO THE IA DURING TEST. 14:30 - 15:00 0.50 BOPSUR P DECOMP RDBOPETESTEQUIPMENTAND ASSOCIATED HOSES. - BD SURFACE LINES AND RIG CHOKE MANIFOLD. 15:00 - 17:30 2.50 BOPSUR P DECOMP PJSM, FILL BOPE, P/U AND R/UDSM LUBRICATOR / OFFSET EXTENSION. - CLOSE ANNULAR AND PRESSURE TEST T/ 250 / 3500 PSI AND CHART F/ 5 MINUTES EACH. - PULL TWCAND R/D DSM LUBRICATOR AND EXTENSION. 17:30 - 19:30 2.00 PULL P DECOMP PJSM PRIOR TO PULLING HANGER -VERIFY THAT NO PRESSURE IS BELOW HANGER, IA IS ON A VACUUM -MAKE UP TIW TO LANDING JOINT -MAKE UP TO FMC 11" X f7/8" HANGER, 9 1/2 TURNS, FMC REP BOLDS -PULL HANGER @ 73K, PUW= 65K, SOW =75K - REMOVE ESP CABLE FROM HANGER -R /U CIRC LINES TO HANGER - CONTINUE HOLE FILL @ 20 BPH Printed 2/18/2013 3:01:21 PM Operation Summary Report Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date /me: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 19:30 - 21:00 1.50 PULL P DECOMP BULLHEAD DOWN TUBING -CLOSE ANNULAR - BULLHEAD 40 BBLS OF 8.5 PPG SEAWATER @ 5 BPM & 970 PSI DOWN TUBING - VERIFY NO TRAPPED PRESSURE AND OPEN ANNULAR, TUBING & IA ON VACUUM -BLOW DOWN AND RIG DOWN CIRC LINES -LAY DOWN TUBING HANGER AND LANDING JOINT -HANG ESP SHEAVE AND TRUNK 21 00 - 00:00 3.00 PULL P DECOMP PJSM, PULL ESP COMPLETION ASSEMBLY -POOH W/ 6.5 #, 2 7/8" EUE 8RD TUBING, STANDING BACK -POOH FROM 6004 MD. PUW =65K, SOW= 75K - CONTINUAL HOLE FILL @ 20 BPH W/ 8.5 PPG SEAWATER -301 BBLS LOST 2/7/2013 00:00 - 01:00 1.00 PULL P DECOMP POOH W/ 6.5 #, 2 7/8" EUE 8RD TUBING, STANDING BACK - AT 3040' MD. PUW =58K, SOW= 63K 01:00 - 01:30 0.50 PULL P DECOMP _ KICK WHILE TRIPPING DRILL AAR - QUICK TO ARRIVE TO ASSIGNED STATIONS AND COMMUNICATE STATUS - SAFETY VALVE -JOINT WAS EASILY ACCESABLE - DISCUSSED THE NEED TO P/U TOP DRIVE ENOUGH TO ALLOW CLEARANCE TO EASILY STAB SAFETY VALVE - DISCUSSED ISOLATION OF CEMENT LINE AND ANY LINES THAT MAY BE OPEN DURING SPECIFIC OPERATIONS - CLEAN AND CLEAR RIG FLOOR 01:30 - 04:00 2.50 PULL P DECOMP PJSM TO DISCUSS LAYING DOWN SPECIFIC JOINTS POOH W/ 6.5 #, 2 7/8" EUE 8RD TUBING, STANDING BACK - LAY DOWN JOINTS 132,133,134 - JOINT 133 HAS 2 DIME SIZED HOLES. - 1ST HOLE IS -7FT FROM UPPER COLLAR, 2ND HOLE IS -16FT FROM UPPER COLLAR - CONTINUE POOH TO ESP PUMP MOTOR AND ASSEMBLY 04:00 - 05:30 1.50 PULL P DECOMP LAY DOWN ESP PUMP AND MOTOR ASSEMBLY - FEED ESP CABLE THROUGH SHEAVE AND SPOOL UP ON REEL IN SPOOLING UNIT 05:30 - 07:30 2.00 PULL P DECOMP RIG DOWN CENTRALIFT - R/D SHEAVE - ESP FAILURE TO BE DETERMINED AT SHOP - CLEAN AND CLEAR RIG FLOOR. - SET WEAR RING. - MAINTAIN CONTINUOUS HOLE FILL WITH 8.5 PPG SEAWATER AT20 BPH. Printed 2/18/2013 3:01:21 PM • ;; North America - ALASKA, Operation Summary Report =a • s �, °. < r /ice = �`' Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 07:30 - 11:30 4.00 EVAL P DECOMP PJSM PU HES 7" CHAMP PACKER ON27/8" L -80 EUE TBG FROM DERRICK - HES REP, WSL, TOOL PUSHER IN ATTENDANCE. - RIH WITH HES PACKER ON 2 7/8" TBG FROM DERRICK TO 5900' MD. 11:30 - 12:00 0.50 EVAL P DECOMP PJSM, SET AND TEST 7" CSG. OBTAIN PARAMETERS. PU WT. = 65K INCLUDING 40K TOP DRIVE. WT. SO WT. = 63K. - SET CHAMP PACKER 5927' MD. PER HES WEPT -DISCUSSED CHARACTERISTICS OF THE HOLE IN TBG @ 4158' MD, WITH TOWN RWO TEAM. -TEST PRESSURE WILL BE CHANGED ON 7" MIT -IA TO 1,500 PSI. 12:00 - 14.00 2.00 EVAL P DECOMP PJSM, MIT -IA, 7 "L -80 26# CSG BY 2-7/8" EUE ANNULUS. - PUMPED 17 STKS (1.4 BBLS) TO / 1,500 PSI fOR 30 MINUTES. DISCUSS W/ TOWN RWO ENGINEER. MAINTAIN CONTINUOUS HOLE FILL WITH KWF DURING TEST. - MIT -IA TEST, MEETS BP STP CRT- AK -10 -45 CRITERIA. -- RECEIVED PERMISSION TO PROCEED FROM WTL. - BLEED OFF PRESSURE. " 0 " READING. BLED BACK 1 BBLS. - WSL VERIFIED NO TRAPPED PRESSURE BELOW PACKER. - FILLED TBG WITH KWF. RELEASED CHAMP PACKER PER HES REP. - MONITOR WELL FOR 10 MIN. WITH CONTINUOUS HOLE FEED. - SEE ATTACHMENTS 14:00 - 14.30 0.50 EVAL P DECOMP PJSM, POH WITH CHAMP PACKER. - WSL / DRILLER CONFIRM ANNULAR IS OPEN. - BLOW DOWN AND R/D ALL CIRC LINES AND HEAD PIN. - PREP FLOOR AND PIPE SHED TO LD 2 7/8" EUE TBG 1X1 TO PIPE SHED. COMPLETE 'WELL WORK TRANSFER PERMIT WITH PAD OPS FOR MPI -19. 14:30 - 19:30 5.00 CASING P DECOMP PJSM, POOH WITH HES CHAMP PACKER ON 2 7/8" EUE TBG. FROM 5927' MD. PU WI .= bbK INUTUDTNG 4IIK TOP DRIVE WT. SO WT. = 63K. - LD 2 -7/8" TBG 1X1 TO PIPE SHED TO BE NORM TESTED AND SENT OUT. RWO AND CTD SUPERINTENDENT VISITED THE RIG. 19:30 - 20:00 0.50 CASING P DECOMP PJSM TO LAY DOWN CHAMP PACKER -L /D 7" CHAMP PACKER PER HES -ALL ELEMENTS INTACT Printed 2/18/2013 3:01:21 PM �t 4 i Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 20:00 - 21:30 1.50 WHSUR P DECOMP LAY DOWN RUNNING TOOL -SPOT SWS SLICK LINE UNIT -CLEAN AND CLEAR RIG FLOOR 21:30 - 00:00 2.50 EVAL P DECOMP PJSM W/ SLICKLINE AND RIG CREW ON RIG UP OF FULL PRESSURE CONTROL AND EQUIPMENT - INSTALL DUTCH RISER -BRING SLICKLINE BOPS, LUBRICATOR, ETC TO RIG FLOOR CONTINUE HOLE FILLAT 22 BPH W/ 8.5 PPG SEAWATER 783 BBL LOST FOR THE DAY - MAINTAIN HOLE FEED AT 20 -27 BPH WITH 8.5# SEAWATER. 2/8/2013 00:00 - 03:00 3.00 EVAL P DECOMP RIG UP SWS SLICKLINE WITH FULL PRESSURE CONTROL - RIG UP SLICKLINE PRESSURE CONTROL - M/U SLICKLINE EQUIPMENT - M/U PDS CALIPER - SURFACE TEST PDS 7" CALIPER - PRESSURE TEST LUBRICATOR 250 PSI LOW AND 1500 PSI HIGH FOR 5 MINS EACH TEST MAINTAIN CONTINUOUS HOLE FILL WITH 8.5 PPG SEAWATER AT20 BPH. 03:00 - 03:30 0.50 ,EVAL P DECOMP RUN IN HOLE WITH PDS CALIPER - RIH W/ CALIPER ON SWS SLICKLINE TO 1100' MD 03:30 - 06:00 2.50 EVAL P DECOMP AT SURFACE WITH PDS CALIPER - WAIT 15 MINS TO ALLOW CALIPER ARMS TO CLOSE BEFORE PULLING TOOL TO FLOOR - PJSM WITH SWS, PDS, AND RIG TO DISCUSS BREAKING DOWN TOOLS AND PRESSURE CONTROL EQUIP. - R/D SLICK LINE EQUIPMENT. 06:00 - 07:00 1.00 EVAL P DECOMP PJSM, LD DUTCH RISER SYSTEM TO PIPE SHED. - PULL WEAR RING. CLEAN AND CLEAR FLOOR OF LOGGING EQUIPMENT. 07:00 - 09:00 2.00 RUNCOM P RUNCMP RU TO RIH WITH 2_7/8"_ CR 13 VAMTOP TBG ESP COMPLETION. HANG ESP SHEAVE IN DERRICK PULL ESP CABLE THRU SHEAVE TO FLOOR. - RU TORQUE TURN HANDLING EQUIPMENT FOR CR 13 TBG. 09:00 - 12:00 3.00 RUNCOM P RUNCMP PJSM, P/U ESP PUMP AND MOTOR ASSY - LOAD OIL AND SERVICE MOTOR - TIE IN ESP CABLE AND CHECK FOR CONDUCTIVITY - LOSSES TO WELL LAST 12 HOURS = 283 BBLS KWF. Printed 2/18/2013 3:01:21PM North America ALASKA - BP /,,„;, ,/,,: i . :: 1' ,, , ;;;'::::':;:::::. ::t :LT: ::::::::: Q •eration Summa Repor Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:OO:OOAM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @ 63 . Oft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 12:00 15:00 3.00 RUNCOM P RUNCMP RUN 2 -7/8" 6.4 #, CR13 VAMTOP TBG ESP COMPLETION P/U TUBING 1X1 FROM PIPE SHED - WITH DOYON CASING TORQUE TURN / COMPENSATOR SYSTEM. - USE JET LUBE SEAL GUARD PIPE DOPE OPTIMUM M/U 1850 FT /LB TORQUE. DERRICK STABBING BOARD USED. - RUN PER PROGRAM. -WITH ESP CABLE AND CANON CLAMPS. - CHECK ESP CABLE CONDUCTIVITY EVERY 2000' - M/U FOSVAND FLUSH ESP PUMP EVERY 2000' MAINTAIN CONTINUOUS HOLE FILL 20 -27 BPH WITH KWF. 15:00 16:00 1.00 RUNCMM P RUNCMP PJSM, WEEKLY AND TOP CREW CHANGE FROM TOWN - PERFORM PRE -TOUR CHECKS INSPECT STABBING BOARD DRIVE. - WSL DISCUSS WELL CONTROL WITH DRILLER, MOTOR MAN AND PIT WATCHER. DRILLER AND CREW CHECK PIPE COUNT AND FLAGS ON PIPE. RIH FROM SURFACE TO 950' MD. - CHECK ESP CABLE CONDUCTIVITY @ 950' MD. 16:00 00:00 8.00 RUNCOM P RUNCMP CONTINUE TO RIH WITH 2 7/8" VAM TOP CR 13 TBG FROM 950' MD. - CHECK ESP CABLE CONDUCTIVITY EVERY 1000' - M/U FOSVAND FLUSH ESP PUMP EVERY 2000' AT 1 BPM / 900 PSI. FLUSHED PUMP WITH 5 BBLS SEAWATER AT 1 BPM AND 900 PSI AT 4000' MD CONTINUAL HOLE FILL OF 8.5 PPG SEWATER @ 24 BPH 24 HR FLUID LOSS = 524 BBLS 2/9/2013 00:00 03:30 3.50 RUNCOM P RUNCMP RUN IN HOLE WITH 2 7/8 13CR VAM TOP TUBING AND ESP ASSEMBLY RIH FROM 4291' MD - WITH DOYON CASING TORQUE TURN / COMPENSATOR SYSTEM. USING JET LUBE SEAL GUARD PIPE DOPE OPTIMUM M/U 1850 FT /LB TORQUE. - DERRICK STABBING BOARD USED. - INSTALLING ESP CABLE AND CANON CLAMPS. - CHECK ESP CABLE CONDUCTIVITY EVERY 1000' M/U FOSVAND FLUSH ESP PUMP' AT 1 BPM / 900 PSI. @ 5400' MD CLAMPS INSTALLED - CANNON CLAMPS= 102 - PROTECTOLIZERS= 6 -FLAT GUARDS= 5 Printed 2/18/2013 3:01:21 PM " 'r "' -,, h America - A KA • • eration Summary Report Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project: Milne Point Site: M Pt G Pad Rig Name /No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:30 - 05:30 2.00 RUNCOM P RUNCMP MAKEUP FMC 2 7/8" x 11" HANGER - M/U 2 7/8" EUE LANDING JOINT W/ FOSV TO HANGER - PUW= 75K , SOW= 67K - INSTALL PENETRATOR AND BLANK IN HANGER - TERMINATE ESP CABLE TO PENETRATOR 05:30 - 06:00 0.50 RUNCOM P RUNCMP PJSM 11" TBG HANGER. FMC REP, WSL, CENTRALIFT REP IN ATTENDANCE. - LAND HANGER PER FMC REP. PU WT= 75K, SOW = 67K. - INCLUDING 40K TOPDRIVE WT. - RILDS PER FMC REP. LD LANDING JOINT. 06:00 - 07:30 1.50 WHSUR P RUNCMP PJSM, INSTALL AND TEST TWC. - FMC REP INSTALLED 2" Type "H" BPV. - PERFORM ROLLING TEST FROM BELOW TWC FOR 10 CHARTED MIN. PASSED. - 25 BBLS TO CATCH FLUID. - 9 BPM = 500 PSI, 92 BBLS PUMPED AWAY - TEST FROMABOVE TWC, 250 / 3500 PSI, 5 CHARTED MIN. PASSED. 07:30 - 09:00 1.50 BOPSUR P RUNCMP PJSM, R/D LONG BAILS AND TORQUE -TURN EQUIPMENT & N/D BOPE. - LAY DOWN LONG BAILS TO PIPE SHED. - N/D 13 5/8" BOPE - REMOVE FLOW NIPPLE AND TURNBUCKLES. - LOTO KOOMYAND REMOVE HOSES. - SET BACK BOP STACK 09:00 - 12:00 3.00 WHSUR N WHDTRE ORIGINAL 11" FMC TBG HEAD ADAPTER NOT COMPATIBLE WITH NEW TBG HANGER / -- 1 - ORIGINALADAPTER HAS SMALL STYLE HEAT TRACE PORT. - NEWADAPTER HAS LARGE STYLE HEAT TRACE PORT. - WAIT ON CORRECT ADAPTER FLANGE TO ARRIVE FROM PBU WAREHOUSE. WELL CONTROL DRILL: - WSLAND TOOLPUSHER HELD A SCENARIO BASED DRILL: - WITH THE BOP SET BACK FOR TRANSPORT WITHOUT TREE INSTALLED. AAR: - DRILLER SAID, PJSM ON THE SPOT AND ASSIGN ALL CREW MEMBERS A TASK - HAND PLACEMENT WHEN RESETTING BOP STACK. - INSTALL NEWAPI RING GASKET. LOSSES TO WELL LAST 12 HOURS = 363 BBLS KWF. 12:00 - 14:00 2.00 WHSUR P WHDTRE PJSM, N/U 2- 9/16" CAMERON PRODUCTION TREE / ADAPTER. - FMC REP CLEAN AND INSPECT TBG HANGER VOID. - M/U TREE AND ADAPTER PER FMC. - N/U ADAPTER TO TBG SPOOL. Printed 2/18/2013 3:01:21 PM North America - ALASKA - BP M , ®• eration Summary Report Common Well Name: MPG -14 AFE No Event Type: WORKOVER (WO) Start Date: 2/5/2013 End Date: 2/9/2013 X4- 00X69 -E:RIG (1,560,000.00 ) Project Milne Point Site: M Pt G Pad Rig Name/No.: DOYON 16 Spud Date/Time: 8/9/2001 12:00:00AM Rig Release: Rig Contractor: DOYON DRILLING INC. UWI: Active datum: Kelly Bushing / Rotary Table @63.0ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 14:00 - 15:00 1.00 WHSUR P WHDTRE - FMC REP PRESSURE TEST ADAPTER VOID - 250 PSI FOR 5 CHARTED MINUTES, PASSED. - 5000 PSI FOR 30 CHARTED MINUTES. PASSED. - WITNESSED BY WSL. 15:00 - 16:30 1.50 WHSUR P WHDTRE PRESSURE TEST TREE. - 2- 9/16 ", 5M CAMERON TREE TESTED TO 250 / 5000 PSI - WITH DIESEL FOR 5 CHARTED MIN. EACH. PASSED. 16:30 - 17:00 0.50 WHSUR P WHDTRE HELDA "BP ONE TEAM" MEETING WITH MILNE POINT WELL SUPPORT, FMC REP, - WSL, TOOLPUSHER, PIPE FITTER AND RIG CREW. DISCUSSED PRODUCTION TREE ORIENTATION TO ENSURE CORRECT ALIGNMENT FOR FLOW LINE TIE-IN. - REDUNDANT. SYSTEMS TO BE USED FOR TREE ORIENTATION PRE AND POST RWO. 17:00 - 21:30 4.50 WHSUR P WHDTRE PJSM, P/U DSM LUBRICATOR. R/U TEST HOSES. - TEST LUBRICATOR TO 250 / 3500 PSI FOR 5 CHARTED MIN. EACH. PULL TWC - LUBRICATOR ICED UP, LAY DOWN LUBRICATOR - STEAM LUBRICATOR AND WELL HEAD - TEST LUBRICATOR TO 250 / 3500 PSI FOR 5 CHARTED MIN. EACH. - INSTALL 2" TYPE 'H' BPV. - LD LUBRICATOR PER DSM REPS. 21:30 - 22:00 0.50 WHSUR P WHDTRE PERFORM ROLLING TEST FROM BELOW BPV - LINE UP SECONDARY KILL LINE - PUMP 7 BPM AT 300 PSI. 0 PRESSURE ON TREE, CHART FOR 10 MINS 22:00 - 00:00 2.00 WHSUR P WHDTRE SECURE TREE AND CELLAR - BLOW DOWN & RIG DOWN LINES - INSTALL FLANGE AND PRESSURE GAUGE ON ANNULUS - CLEAN PITS - RIG DOWN MUD MANIFOLD, PREP FOR RIG MOVE, BRIDLE UP - RELEASE RIG AT 2400 HRS FOR MOVE TO MPI -19. LOSSES TO WELL LAST 24 HOURS = 562 BBLS KWF Printed 2/18/2013 3:01:21 PM Tree: 2- 9/16" - 5M FMC MPG-14 ink KB - SL = 63' (NABORS 27E) Wellhead: 11" 5M Gen 6 w/ /8" lir KB - GL = 30' (NABORS 27E) EUE 8rd top and btm.thread Tubing Hanger with CIW "H" BPV profile NOTE:4ESCanNotworkonthiswellw /o G -16's well house being moved back 24" or 20 ", 92 #/ft H -40 Welded 112' completely removed. Camco 2 -7/8" x 1" 139' sidepocket KBMM -2 GLM Tam Ported Collar 1011' 0 2 7/8" 6.4 ppf., Cr13 Vam Top Tbg. ( drift ID = 2.347 ", cap. = 0.00592 bpf) Camco 2 -7/8" x 1" 7" 26 ppf, L -80, Btc -mod production casing sidepocket KBMM -2 GLM 5,688' ( drift ID = 6.151 ", cap. = 0.0383 bpf) �� 2 -7/8" XN nipple 5,831' (ID 2.205 ") t, Tandem Pump 79 -P17 Model PMSXD 1:1 5,875' KOP @ 300 ' al 18 -P75 Model PMSXD 1:1 Max wellbore Angle: 63° @ 3500' MD -ma +. Gas Separator 5,894' 60 degrees + past 2800' MD GRSFTXAR H6 Hole angle trough perfs = 90 deg. ' Tandem Seal Section �r GSB3DBUT /GSB3DBLT 5,899' mins Model KMH Motor 5,912' Mgt 114hp / 2330v / 30 amp Num PumpMate XTO 411) w/6 fin Centralizer 5,923' SacrificialAnode 7" Halliburton 23 -29# "VTL" Versa - trieve Packer 6077' 5 1/2" LTC x 4 1/5" BTRS " X -O _ �;�: : „ti = 30 of 4 -1/2” LLP Screen (6097'- 6127`) .... — 12/10 Resin Coated 0.020 Gauge N SAND PERFORATION SUMMARY Size SPF Interval (TVD) — = 30' of 4 -1/2" LLP Screen (6178' - 6208') 3 3/8" 6 6110' - 6130' 3988' - 3996' = ON.* — 12/10 Resin Coated 0.020 Gauge 3 3/8" 6 6190' - 6210' 4020' - 4028' M 3 3/8" 6 6250' - 6270' 4045' - 4053' �"' 30' of 4 -1/2" LLP Screen (6237' - 6267') = All shots fired, pert jets at 60 deg phasing '•;•;•;...N• 12/10 Resin Coated 0.020 Gauge = 7" Baker "SLZXP" Packer (4.5" ID) 6286' 4 -1/2" Halliburton XN Nipple (3.725" ID) @ 6318' WLEG 6329' Baker Hook Wall Hanger above 7" 6499' 6 1/8" Hole td @ 9430' Window in 7" Casing @ 6508' - 6520' -- Well inclination @ window = 74 deg. OA Horizontal 70 Its. of Pre Drilled 4 1/2" Slotted Liner 12.6# L80 IBT (6,570' - 9,304') Baker Hook Wall Baker 4 1/2" Packoff Bushing 9304' Baker Tie Back Sleeve 7028' Hanger below 7" 6520' 4 1/2" Guide Shoe 9348' Baker ZXP Liner Top Packer 7037' Baker Down Swivel -up lock sub 6522' Baker 5x7" HMC Liner Hanger 7042' A Halliburton Float Collar 7046' 6 1/8" Hole td ® 9419' Halliburton Float Shoe 7132' OB Horizontal 57 its of pre - drilled 4 1/2" slotted liner 12.6# L -80 IBT (7137' - 9362') Baker 4 1/2" Packoff Bushing 9362' 4 1/2" Guide Shoe 9405' DATE REV. BY COMMENTS MILNE POINT UNIT 8/1 4/01 B. Hasebe Nabors 27E Drill Multilateral WELL G-14 9/25/01 B. Hasebe Nabors 4ES ESP Completion 7/24/08 REH Nabors 3S ESP changeout API NO: 50- 029 - 23031 -00 8/24 /08 MOM Nabors 4 -es ESP RWO G -14L1 API NO: 50- 029 - 23031 -60 2/10/13 B. Bixby Doyton 16 ESP and Tbg. Changeout BP EXPLORATION (AK) ' STATE OF ALASKA RECEIVED mit OIL AND GAS CONSERVATION COMM SION REPORT OF SUNDRY WELL OPERATIONS 21 2012 1. Operations Abandon II Repair Well Plug Perforations Perforate o 6 !x! CC t Performed: Alter Casing ❑ Pull Tubing U Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: BP Exploration (Alaska), Inc Development El Exploratory ❑ . 201 -133 -0 3. Address: P.O. Box 196612 Stratigraphic ❑ Service ❑ it. API Number: Anchorage, AK 99519 -6612 50- 029 - 23031 -00 -00 7. Property Designation (Lease Number): 8. Well Name and Number: , ADL0315848 MPG -14 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): To Be Submitted MILNE POINT, SCHRADER BLFF OIL 11. Present Well Condition Summary: Total Depth measured 9405 feet Plugs measured None feet true vertical 4213.88 feet Junk measured None feet Effective Depth measured 9405 feet Packer measured See Attachment feet true vertical 4213.88 feet true vertical See Attachment feet Casing Length Size MD TVD Burst Collapse Structural None None None None None None Conductor 78 20" 34 - 112 34 - 112 0 0 Surface 7099 r 26# L -80 33 - 7132 33 - 4207.91 7240 5410 Intermediate None None None None None None Production None None None None None None Liner 2377 4 -1/2" 12.6# L -80 7028 - 9405 4201.01 - 4213.88 8430 7500 Perforation depth Measured depth See Attachment feet SCA NNED JAN 2 2013. True Vertical depth See Attachment feet Tubing (size, grade, measured and true vertical depth) See Attachment See Attachment See Attachment Packers and SSSV (type, measured and true vertical depth) See Attachment See Attachment " See Attachment Packer None None None SSSV 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 141 63 349 0 178 Subsequent to operation: 162 100 281 0 185 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory Development - Service Stratigraphic Daily Report of Well Operations X 16. Well Status after work: Oil - 0 ❑ WD U GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPIUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Nita Summerhays Prepared by Nita Summerhays 564 -4035 Printed Name Nita Summerh. Title petrotechnical Data Technician Sign .• - ---,Ii1/ _ /Ay , gip_ Phone 564 -4035 Date 9/21/2012 , Form 10-404 Revised 11/2011 RaDMS SEP 2 4 ' I 1 (0i1-- Submit Original Only S • Daily Report of Well Operations ADL0315848 ACTIVITYDATE I SUMMARY INITIAL T /IA= 250/400 SSV,SWAB= CLOSED, IA =OTG RIH WITH HEAD /2 EQFs 43 /UPCT /FIRING HEAD /SETTING TOOL/WFD ER PKR OAL =32', OVERALL WEIGHT =220 #, MAX OD= 2.24 ", MIN ID WFD ER PKR = 1.438 "" CCL TO MID ELEMENT 12.7', CCL STOP DEPTH 4170.4', PKR SET AT 4183.1' SWAB,SSV= CLOSED, IA =OTG FINAL T /IA= 380/400 8/5/2012 * **JOB COMPLETE * ** WELL S/I ON DEPARTURE ** *WELL S/I ON ARRIVAL * ** RIG UP 8/15/2012 * * *CONT'D ON 8- 16 -12 * ** * * *CONID FROM 8- 15 -12 * ** SET 25' x 2 7/8" WFD TBG PATCH @ 4166' SLM 8/16/2012 ** *WELL S/I ON DEPARTURE * ** FLUIDS PUMPED BBLS 20 DIESEL 20 TOTAL • • • Perforation Attachment ADL0315848 Perf Opera Meas Meas Operation tion Depth Depth TVD Depth TVD Depth SW Name Date Code Top Base Top Base MPG -14 8/14/01 PER 6110 6130 3991.87 3999.94 MPG -14 8/14/01 PER 6190 6210 3961.34 3969.36 MPG -14 8/14/01 PER 6250 6270 3985.21 3993.02 MPG -14 8/14/01 SL 7137 9362 4145.27 4152.16 AB ABANDONED MIR REMOVED APF ADD PERF MIS MECHANICAL ISOLATED BPP PULLED MLK MECHANICAL LEAK BRIDGE OPEN BPS PLUG SET OH HOLE FCO FILL CLEAN OUT STC STRADDLE PACK, CLOSED FIL FILL STO STRADDLE PACK, OPEN SQF SQUEEZE FAILED SPS SAND PLUG SET SQZ SQUEEZE SL SLOTTED LINER PER PERF SPR SAND PLUG REMOVED RPF REPERF Casing / Tubing Attachment ADL0315848 Casing Length Size MD TVD Burst Collapse LINER 2377 4 -1/2" 12.6# L -80 7028 - 9405 4201.01 - 4213.88 8430 7500 SURFACE 7099 7" 26# L -80 33 - 7132 33 - 4207.91 7240 5410 TUBING 5887 2 -7/8" 6.5# L -80 32 - 5919 32 - 3912.1 10570 11160 TUBING 254 4 -1/2" 12.6# L -80 6077 - 6331 3978.61 - 4078.95 8430 7500 CONDUCTOR 78 20" 34 - 112 34 112 • • a • Packers and SSV's Attachment ADL0315848 SW Name Type MD TVD Depscription MPG -14 PACKER 6077 3915.68 Halliburton 23- 29 # 'VTL' Versa -trie% MPG -14 PACKER 6286 3999.18 7" Baker SLZXP Packer MPG -14 PACKER 7037 4138.75 7" Baker ZXP Top Packer " Tree* 2- 9/16" - 5M FMC • MPG-14 • KB - SL = 63' ( NABORS 27E) Wellhead: 11" 5M Gen 6 w/7/8" Orig. KB - GL = 30' (NABORS 27E) EUE 8rd top and btm.thread 1 p Tubing Hanger with CIW "H" BPV rofile NOTE: 4ES Can Not work on this well w/o p G -16's well house being moved back 24" or 20 ", 92 #/ft H - 40 Welded 112' PPF completely removed. Camco 2 -7/8" x 1" 140' sidepocket KBMM -2 GLM Tam Ported Collar 1011' 0 New Patch set 08/16/12 / ER Packer patch top element @ 4158' 2 7/8" 6.5 ppf, L -80, 8 rd, EUE production tubing [ and bottom element @ 4183'. ( drift ID = 2.347", cap. = 0.00592 bpf) fir» \\ Hole at 4170' MD 7" 26 ppf, L -80, Btc -mod production casing Camco 2-77F-0--- 5, 674' ( drift ID = 6.151", cap. = 0.0383 bpf) sidepocket KBMM -2 GLM 1 1 2 -7/8" XN nipple 5,825' (ID 2.205 ") 1 Tandem Pump 79 -P17 Model PMSXD 1 :1 5,867' KOP @ 300 ' t 18 -P75 Model PMSXD 1:1 Max wellbore Angle: 63° @ 3500' MD j Gas Separator 7 5,885' 60 degrees + past 2800' MD Hole angle trough perfs = 90 deg. s Tandem Seal Section • GSB3DB UT /LT SB /SB PFSA 5,891' - 1 Model KMH -A Motor 5,904' ■ 114hp / 2330v / 30 amp PumpMate XTO 5,919' w/6 fin Centralizer 7" Halliburton 23 -29# "VTL" Versa - trieve Packer 6077' 0 5 1 /2" LTC x 4 1 /5" BTRS " X -O _ 30' of 4-1/2" LLP Screen (6097'- 6127`) — 12/10 Resin Coated 0.020 Gauge N SAND PERFORATION SUMMARY Size SPF Interval (TVD) ■ 30' of 4 LLP Screen (6178' - 6208') 3 3/8" 6 6110' - 6130' 3988' - 3996' = — 12/10 Resin Coated 0.020 Gauge 3 3/8" 6 6190' - 6210' 4020' - 4028' 1I 3 3/8" 6 6250' - 6270' 4045' - 4053' „,..... 30' of 4 LLP Screen (6237' - 6267') All shots fired, perf lets at 60 deg phasing — 12/10 Resin Coated 0.020 Gauge _ 11, 7" Baker "SLZXP" Packer (4.5" ID) 6286' 4 -1/2" Halliburton XN Nipple (3.725" ID) @ 6318' WLEG 6329' Baker Hook Wall Hanger above 7" 6499' 6 1/8" Hole td @ 9430` Window in 7" Casing @ 6508' - 6520' r Well inclination @ window = 74 deg. OA Horizontal 70 jts. of Pre Drilled 4 1/2" Slotted Liner 12.6# L -80 IBT (6,570' - 9,304') Baker Hook Wall Baker 4 1/2" Packoff Bushing 9304' Baker Tie Back Sleeve 7028' Hanger below 7" 6520' 4 1/2" Guide Shoe 9348' Baker ZXP Liner Top Packer 7037' Baker Down Swivel -up lock sub 6522' Baker 5x7" HMC Liner Hanger 7042' A Halliburton Float Collar 7046' 6 1/8" Hole td @ 9419' Halliburton Float Shoe 7132' N OB Horizontal 57 its of pre - drilled 4 1/2" slotted liner 12.6# L -80 IBT (7137' - 9362') Baker 4 1/2" Packoff Bushing 9362' 4 1/2" Guide Shoe 9405' DATE REV. BY COMMENTS MILNE POINT UNIT 8/14/01 B. Hasebe Nabors 27E Drill Multilateral WELL G -14 9/25/01 B. Hasebe Nabors 4ES ESP Completion API NO: 50- 029 - 23031 -00 G -14L1 API NO: 50- 029 - 23031 -60 7/24/08 REH Nabors 3S ESP changeout 8/24/08 MOM Nabors 4 -es ESP RWO BP EXPLORATION (AK) • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 SJ NN FEB 2 4 20l2 December 30, 2011 Mr. Tom Maunder 3 3 Alaska Oil and Gas Conservation Commission aot- 333 West 7 Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of MPG -Pad Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from MPG -Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir BPXA, Well Integrity Coordinator • • BP Exploration (Alaska ) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) MPG -Pad 10/10/2011 Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft gal MPG -01 1890290 50029219270000 Tanko conductor NA NA NA NA NA MPG-02 1890280 50029219260000 Tanko conductor NA NA NA NA NA MPG -03A 2042190 50029219420100 Tanko conductor NA NA NA NA NA MPG-04 1890450 50029219410000 Tanko conductor NA NA NA NA NA MPG-05 1910230 50029221380000 1.1 NA 1.1 NA 5.1 8/14/2011 MPG -07 1910250 50029221400000 0.1 NA 0.1 NA 3.4 9/4/2011 MPG-08A 1930480 50029221410100 0.2 NA 0.2 NA 2.6 10/10/2011 MPG -09 1971170 50029227790000 1.3 NA 1.3 NA 15.3 10/30/2009 MPG -10 1971180 50029227800000 2.1 _ NA 2.1 NA 20.4 10/30/2009 MPG-11 1971190 50029227810000 0.8 NA 0.8 NA 5.1 8/14/2011 MPG -12 1971420 50029227920000 1.3 NA 1.3 NA 8.5 8/14/2011 MPG -13 1971200 50029227820000 1.2 NA 1.2 NA 102 10/30/2009 -- -3 MPG -14 2011330 50029230310000 0.8 NA 0.8 NA 4.3 9/4/2011 MPG-15 1971220 50029227840000 2.9 NA 2.9 NA 34.0 10/30/2009 MPG -16 2032100 50029231890000 1.8 NA 1.8 NA 17.0 8/15/2011 MPG-17 2040130 50029231920000 1.6 NA 1.6 NA 14.5 8/15/2011 MPG -18 2040200 50029231940000 1.6 NA 1.6 NA 13.6 8/15/2011 MPG-19 2041920 50029232280000 1.6 NA 1.6 NA 13.6 8/15/2011 ` STATE OF ALASKA ~`~~~ A~ OIL AND GAS CONSERVATION COIVA~fSSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: ^ Abandon ®Repair Well ~ ^ Plug Perforations ^ Stimulate ^ Re-Enter Suspended Well ^ Alter Casing ®Pull Tubing ^ Perforate New Pool ^ Waiver ®Other ^ Change Approved Program ^ Operation Shutdown Change Out ESP ^ Perforate ^ Time Extension 2. Operator Name: 4. Well Class Before Work: 5. Permit To Drill Number: BP Exploration (Alaska) Inc. ®Development ^ Exploratory 201-133 ' 3. Address: ^ Service ^ Stratigraphic 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-23031-00-00 ' 7. KB Elevation (ft): 62 93' 9. Well Name and Number: MPG-14 8. Property Designation: 10. Field /Pool(s): , ADL 315848 Milne Point Unit / Schrader Bluff 11. Present well condition summary Total depth: measured 9405 ' feet true vertical 4214 feet Plugs (measured) None Effective depth: measured 9405 • feet Junk (measured) None true vertical 4214 ~ feet Casing Length Size MD TVD Burst Collapse Structural Conductor 78' 20" 112' 112' 1490 470 Surface 7097' 7" 7132' 4208' 7240 5410 Intermediate Production Liner 2377' 4-1/2" 7028' -9405' 4201' - 4214' 8430 7500 ~~~~~i~~ ~~~ ~ ~ Z~~$ Perforation Depth MD (ft): Parrs>>o~-sz~o~,sionea~~ar-sasz' Perforation Depth ND (ft}: Pert 399r - floss', slated azos' - 4215' 2-7/8", 6.5# L-80 5919' Tubing Size (size, grade, and measured depth): 4_7/2^ 12 B# , Packers and SSSV (type and measured depth): 7" Halliburton 23 - 29#'VTL' Versa-trieve Packer and a 6077' 7" Baker'SLZXP' Packer 6286' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment description including volumes used and final. pressure: 13. Re resentative Dail Avera a Production or In'ection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation: 0 0 0 280 0 Subsequent to operation: 272 72 419 240 217 14. Attachments: ^ Copies of Logs and Surveys run 15. Well Class after work: ^ Exploratory ®Development ^ Service ® Daily Report of Well Operations 16. Well Status after work: ® Well Schematic Diagram ®Oil ' ^ Gas ^ WAG ^ GINJ ^ WINJ ^ WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NIA if C.O. Exempt: Contact Howard West, 564-5471 N/A Printed Name Sondra Stewma Title Drilling Technologist ~{~ `` Prepared By NamelNumber 50 D r"^ ` Si ature Phone 564-47 atelT l : Sondra Stewman 564-4750 Form 10-404 Revised 04/2006 ~#~°~ ~~~ ~ Z~d~ Submit Original O~ Tree: 2-9/16" - 5M FMC Wellhead: 11" 5M Gen 6 w/ /8" EUE 8rd top and btm.thread Tubing Hanger with CIW "H" BPV profile 20", 92 #/ft H-40 Welded 112' MPG -144~'~1 t~6 - GL = 30' (NABOBS 27E) NOTE: 4ES Can Not work on this well w/o G-16's well house being moved back 24" or completely removed. Camco 2-7/8" x 1" 140' sidepocket KBMM-2 GLM Tam Ported Collar 1011' 2 7/8" 6.5 ppf, L-80, 8rd, EUE production tubing Camco 2-7/8" x 1" ' ( drift ID = 2.347", cap. = 0.00592 bpf) sidepocket KBMM-2 GLM 5,674 7" 26 ppf, L-80, Btc-mod production casing ( drift ID = 6.151", cap. = 0.0383 bpf) 2-7/8" XN nipple " 5,825' (ID 2.205 ) Tandem Pump ' 79-P17 Model PMSXD 1:1 5,867 KOP ~ 300 ' 18-P75 Model PMSXD 1:1 Gas Separator 885' 5 Max wellbore Angle: 63° @ 3500' MD 0024043887 , 60 degrees + past 2800' MD Hole angle trough perfs = 90 deg. Tandem Seal Section ' GS63DB UT/LT SB/SB PFSA 5,891 Model KMH-A Motor 904` 5 114hp / 2330v / 30 amp , PumpMate XTO w/6 fin Centralizer 5,919` 7" Halliburton 23-29# "VTL" Versa-trieve Packer 6077' 5 1/2" LTC x 4 1/5" BTRS " X-O 30' of 4-112" LLP Screen (6097'-6127`) 12/10 Resin Coated 0.020 Gauge N SAND PERFORATION SUMMARY Size SPF Interval (ND) 3 3/8" 6 6110' - 6130' 3988' - 3996' 3 3/8" 6 6190' - 6210' 4020' - 4028' 3 3/8" 6 6250' - 6270' 4045' - 4053' All shots fired, pert jets at 60 deg phasing Window in 7" Casing @ 6508' - 6520' Well inclination @ window = 74 deg. Baker Tie Back Sieeve 7028' Baker ZXP Liner Top Packer 7037' Baker 5x7" HMC Liner Hanger 7042` Halliburton Float Collar 7046' Halliburton Float Shoe 7132' DATE REV. BY COMMENTS 8/14/01 B. Hasebe Nabors 27E Drill Multilateral 9/25/01 B. Hasebe Nabors 4ES ESP Completion 7/24/08 REH Nabors 3S ESP changeout 8/24/08 MOM Nabors 4-es ESP RWO 30' of 4-1/2" LLP Screen (6178' - 6208`) 12/10 Resin Coated 0.020 Gauge 30' of 4-1/2" LLP Screen (6237' - 6267`) 12/10 Resin Coated 0.020 Gauge 7" Baker "SLZXP" Packer (4.5" ID) 6286' 4-1/2" Halliburton XN Nipple (3.725" ID) Cdr 6318' WLEG 6329' Baker Hook Wall Hanger above 7" 6499' '.~. ~ OA Horizontal 70 jts. of Pre-Drilled 4 1/2" Slotted Liner 12.6# L-80 IBT (6,570' - 9,304') Baker Hook Wall Baker 4 1!2" Packoff Bushing 9304' Hanger below 7" 6520' 4 1/2"Guide Shoe 9348' Baker Down Swivel-up lock sub 6522' OB Horizontal 57 jts of pre-drilled 4 1/2" slotted liner 12.6# L-80 IBT (7137' - 9362') Baker 4 1/2" Packoff Bushing 9362' 4 1/2" Guide Shce 9405' MILNE POLNT UNIT WELL G-14 API NO: 50-029-23031-00 BP EXPLORATION jAKL Page 1 of 1 • V1/ell: MPG-14 Well History Well Date Summary MPG-14 7/23/2008 INSTALL DPSOV IN GLM #2 IN PIPE SHED MPG-14 7/24/2008 (Post Rig Freeze Protect TBG and IA) T/I/O=0/0/0 Pump 15 bbls dead crude down TBG followed by 65 bbls dead crude down IA to freeze protect well. Awgers continued on 07-25-08 MPG-14 7/25/2008 (Freeze Protect TBG and IA) T/I/0= 0/0/0 Pump 15 bbls dead crude down TBG followed by 65 bbls dead crude down IA to freeze protect well. FWHP= 0/0/0 swab=closed/ wing=closed/ ssv=closed/ master=closed/ IA open to gauge. MPG-14 7/25/2008 The Well Support Techs rigged up and set the foundation, installed the flowlines and set the wellhouse. They then removed the back pressure valve and leak tested the flowlines to 1150 psi. NOTE: The leak test was GOOD and the BPV was left OUT... MPG-14 7/31/2008 ***ARRIV ON LOC WELL S/I *** DRIFT TUBING*** PULLED 1" BEK-DPSOV FROM 172' MD, SET NEW 1"BEK-DPSOV DRIFTED TO RESTRICTION AT 5275' SLM W/ 2.31" GAUGE. ***JOB CANCEL FOR HIGH WIND *** MPG-14 8/1/2008 *** WELL SI ON ARRIVAL *** RWO RAN 2.15" CENT, 2" BAILER TO 5,943' SLM. RECOVERED 1 TBS. SCALE MPG-14 8/1/2008 MPG-14 8/1/2008 Assist Slickline T/I/0=100/140 Continued on 08-02-08 AWGRS. Pumped 19 bbls of 50/50 Diesel and crude mixture down tubing to assist in finding leak. MPG-14 8/2/2008 ***CONTINUE FROM 8/1/08*** DRIFT TUBING RAN HOLE FINDER, NARROWED LEAK DOWN TO BETWEEN 2137' AND 2000' SLM. DRIFTED W/ 2.15" CENT, S-BAILER TO ESP AT 5,945' SLM RAN PDS CALIPER TUBING FROM 5,935' TO SURFACE ~ 50FPM ***TURN WELL OVER TO DSO *** MPG-14 8/2/2008 Assist Slickline Continued from 08-01-08 AWGRS. Pumped 29 bbls of 50/50 Dead Crude and Diesel mixture down tubing while slickline ran D&D hole finder. FWHP=100/140 Left while slickline still on well. MPG-14 8/10/2008 *** WELL S/I ON ARRIVAL *** (rwo prep) PULLED 1" BK-DGLV FROM STA# 1 ~ 5769' MD, POCKET LEFT OPEN PULLED 1" BEK-DPSOV FROM STA# 2 ~ 172' MD, SET 1" BK-DGLV SET BPV ***WELL S/I ON DEPART*** MPG-14 8/16/2008 Well Techs said BPV was set then demobe well house flow lines and foundation .All blinds are TO spec. MPG-14 8/21/2008 Standby for rig to move off well. Job postponed. MPG-14 8/21/2008 (Post RWO Freeze protect TBG and IA) T/I= 0/0 Pump 15 bbls dead crude down TBG followed by 65 bbls dead crude down IA to freeze protect well. FWHP= 0/0 Valve position =swab-closed /wing-closed / ssv-closed /master-closed / IA and OA open to gauges. MPG-14 9/2/2008 ASRC Unit #5, 6 hour test **job complete** MPG-14 9/2/2008 ASRC Unit #5, divert well, stabilize **job in progress** Note: tried to test MPG-02, pump failure, tried to test MPG-16, divert will not open. 2nd WSR on MPG-14 for 9/2/08. MPG-14 9/3/2008 ASRC Unit #5, 6 hour test **job complete** Print Date: 9/18/2008 Page 1 of 1 Assist S-line Job Postponed. • BP EXPLORATION Page 1 of 2 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: WORKOVER Start: 8/17/2008 End: 8/21/2008 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 8/21/2008 Rig Name: NABOBS 4ES Rig Number: Date .From - To Hours Task Code NPT Phase ~ Description of Operations 8/18/2008 03:00 - 06:30 3.50 RIGD P PRE R/D rig & suppoert equip. Scope down & Lower derrick. 06:30 - 08:00 1.50 MOB P PRE Move Rig sub & pits From~Pl-15 to MPG -14. 08:00 - 09:00 1.00 RIGU P PRE Lay out herculite & matting boards. Attempt to spot in rig sub. no success. 09:00 - 10:30 1.50 MOB P PRE Move camp pipe shed from MPI-15 to MPG-14. spot camp& I level camp. 10:30 - 12:30 2.00 RIGU N WAIT PRE Unable to spot in rig. Re-drilled well is on 25' center. Nedd to r m d'acent well house. Wait on wellhouse removal. skid well house back ~ 18" to allow Rig to spot over wellhead. 12:30 - 14:00 1.50 RIGU P PRE Spot in rig sub, pipe shed & pit modules. Begin R/U same. 14:00 - 15:00 1.00 RIGU P PRE Raise & scope up derrick. 15:00 - 16:30 1.50 RIGU P DECOMP R/U lines to tree & tiger tank. Install 2nd annulus valve. Begin taking on seawater. Accepted rig ~ 15:00 hrs. 16:30 - 17:30 1.00 WHSUR P DECOMP P/U lubricator & test to 500 psi. Pull BPV. L/D lubricator & BPV. AOGCC rep John Crisp waived witness ~ 17:15 hrs. 17:30 - 19:00 1.50 KILL P DECOMP RU lines to tree & tiger tank. P/T lines to 3500 psi. Test lines to tiger tank to 500 psi. 19:00 - 00:00 0.00 KILL P DECOMP Initial SIP's = 110 psi on tubing, 130 psi on IA. Bleed pressures to 0 psi thru choke to tiger tank, bled all gas. Circulate 50 bbls down tubing ~ 5 BPM / 680 psi, taking gas returns thru choke. Crude returns started ~ 40 bbls into circulation. Shut choke and bullhead 30 bbls down tubing ~ 4 BPM / 560 psi. Open choke & circulate taking returns thru choke to tiger tank ~ 5 BPM / 800 psi returned crude & gas to tank. Reduce rate to 3 BPM / 300 psi 2 + annulus volumes and well did not clean up (mix of thick crude, gas & SW). Shut down and monitor well for 30 min. Tubing & IA building gas 1 psi /min. Circulated 452 bbls and lost 259 bbls to formation. Fluid weight off truck 8.42 ppg / 110 degree. 8/19/2008 00:00 - 02:00 2.00 KILL P DECOMP Take on more fluid to pits of 115 degree - 8.43 ppg produced water. Bullhead 20 bbls down tubing ~ 5 BPM / 250 psi. Bullhead 300 bbls down IA ~ 6 BPM / 530 psi. Monitor well for 20 min. Tubing & IA on vacuum.. -Total fluid bullheaded: 350 bbls 02:00 - 02:30 0.50 WHSUR P DECOMP Dry rod in TWC. P/T from above to 3500 psi for 10 min - charted. P/T rolling test to 500 psi from below for 10 min - charted. 02:30 - 04:00 1.50 WHSUR P DECOMP ND tree. 04:00 - 06:00 2.00 BOPSU P DECOMP NU ROPE. RU test lines. 06:00 - 08:00 2.00 BOPSU P DECOMP Finish N/U BOPE. 08:00 - 12:00 4.00 BOPSU P DECOMP R/U test equip. Pressure test BOPE as per BP/AOGCC requirements. LP 250 psi, HP 3500 psi. Used 2 7/8" test jt. No failures. BOP test witnessing waived by John Crisp w/ AOGCC. 12:00 - 13:00 1.00 WHSUR P DECOMP P/U lubricator & test to 500 si. Pull TWC. L/D TWC & lubricator. 13:00 - 14:00 1.00 PULL P DECOMP Circulate bottoms up. Pump 5 BPM ~ 800 psi. Lost 65 bbls during circulation. Pumped total of 221 bbls. 14:00 - 15:00 1.00 PULL P DECOMP M/U landin 't. BOLDS. Pull han er to floor. Disconnect ESP cable. L/D hanger & landing jt. 15:00 - 16:30 1.50 PULL P DECOMP POH L/D 2-7/8" tubing to 1st 2-7/8" x 1" GLM while stringing ESP cable over sheave wheel and through elephant trunk to cable spooler. Secure ESP cable to empty spool in spooler. 16:30 - 18:00 1.50 PULL P DECOMP POH la in down 2-7/8" tubin 1 x 1 through pipe shed and Printed: 9/8/2008 11:11:53 AM ~ ~ BP EXPLORATION Page 2 of 2 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: WORKOVER Start: 8/17/2008 End: 8/21/2008 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 8/21/2008 Rig Name: NABOBS 4ES Rig Number: Date. From - To Hours I Task Code I NPT Phase , Description of Operations 8/19/2008 16:30 - 18:00 1.50 PULL P DECOMP spooling ESP cable. OOH w/ 56 jts. 18:00 - 18:30 0.50 PULL P DECOMP Crew change. Service rig. Check PVT alarms. Inspect derrick. 18:30 - 00:00 5.50 PULL P DECOMP Finish to POOH & UD 2 7/8" ESP completion. Spool up ESP cable. Use double displacement method while POOH. Recovered 178 jts of 2 7/8" tubing, 2 GLM assys, "XN" nipple & 2 -10' pups. No holes were noted in t~bina. 8/20/2008 00:00 - 02:30 2.50 PULL P DECOMP Break down & inspect ESP. Had -5' of sand in 10' pup above pump. Top of pump had was sand packed. No damage to pump was noted. Plan is to Change out pump section & seal seaction of ESP. New cable will also be used. Notified town engineer & Milne Pt Well ops supnr of sand in tubing. Elected not to make clean out run. 02:30 - 03:30 1.00 PULL P DECOMP Hold weekly safety meeting w/ all hands. 03:30 - 05:00 1.50 PULL DECOMP Clear & Clean rig floor. Change out reels in spooling unit. 05:00 - 08:30 3.50 BUNCO RUNCMP Re-dress & service ESP. Connect cable & meg same. Install flat guards and protectorlisers on motor lead cable. 08:30 - 09:30 1.00 BUNCO RUNCMP RIH with 2-7/8" ESP com letion ickin u i e 1 x 1 from i e shed and attaching Lasalle cable clamps every other tubing coupling. Meggered ESP cable and filled tubing every 2000'. Filling hole while RIH with 1%KCI at double steel displacement plus 1-Bbl. per every 1000' of ESP cable ran. 09:30 - 10:30 1.00 BUNCO RUNCMP Close in well and hold safety standdown with all crew members. Verified review of all safety incidents detailed in recent "Safety Focus" dated 8/19/2008. Reviewed 8 Golden Rules with emphasis on Vehicle Safety. Reviewed rig scorecard with all crew. 10:30 - 17:30 7.00 BUNCO RUNCMP Monitor and o e II. - completion picking up pipe 1 x 1 from pipe shed and attaching Lasalle cable clamps every other tubing coupling. Meggered ESP cable and filled tubing every 2000'. Filling hole while RIH with 1%KCI at double steel displacement plus 1-Bbl. per every 1000' of ESP cable ran. Ran total of 185 jts. Bottom of centralizer ~ 5917'. Discharge head ~ 5867'. XN Nipple ~ 5825'. GLM w/ Dummy ~ 5674'. GLM w/ DOSV ~ 140'. Used 5 Protectolizers, 3 Flat Guards & 90 LaSalle clamps. 17:30 - 18:00 0.50 BUNCO RUNCMP M/U landing jt & hanger. 18:00 - 21:00 3.00 BUNCO RUNCMP Make field splice. Install penetrator & attach to ESP. Pump thru ESP 1 BPM ~ 1000 psi. 21:00 - 21:30 0.50 BUNCO RUNCMP Land ESP com letion. UD landing jt. P/U Wt = 43K, S/0 Wt = 35K. 21:30 - 23:00 1.50 WHSUR P RUNCMP n er. Pressure test from to w/ 3500 psi for 10 min. Test from below 4 BPM ~ 100 psi. for 10 min. Charted test. Tighten 2 leaky lock down screws. Blow down & R/D lines. 23:00 - 00:00 1.00 BUNCO RUNCMP Hold 1 hr safety stand down. Revied latest incidents, & 8 Golden Rules. 8/21/2008 00:00 - 02:30 2.50 BOPSU P RUNCMP Drain stack. N/D BOPE. 02:30 - 04:30 2.00 WHSUR P RUNCMP N/U tree & adapter flange. Test hanger void & tree to 5000 psi, Ok. Made final check on ESP. 04:30 - 06:00 1.50 WHSUR P RUNCMP P/ b i t & t st to 500 si k. ull TWC. Install BPV. Pressure test BPV, 4 BPM ~ 100 psi for 10 min. charted same. Secured rtree & cellar. RELEASE RIG ~ 0600 hrs. Printed: 9/8/2008 11:11:53 AM STATE OF ALASKA~~~~;p}~~RR ALA OIL AND GAS COIV~/~AT71C3f~Y"COMI~ION REPORT OF SUNDRY U~EL~~~~Tc1~ONS ~,:~ 1. Operations Abandon ~ Repair Well ~ ati ns ~ Stimulate ~ Other ~ ,ACID TREATMENT ~ Performed: Alter Casing ~ Pull Tubing ~ Perforate New I~o`~~ ~ Waiver ~ Time Extension Change Approved Program ~ Operat. Shutdown ~ Perforate ~ Re-enter Suspended Well 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development ~ i Exploratory ~~ 201-1330 ' 3. Address: P.O. Box 196612 Stratigraphic Service ~' 6. API Number: Anchorage, AK 99519-6612 50-029-23031-00-00 7. KB Elevation (ft): 9. Well Name and Number: 62.93 KB ~ MPG-14 8. Property Designation: 10. Field/Pool(s): ADLO-315848 ~ MILNE POINT Field/ SCHRADER BLFF OIL Pool 11. Present Well Condition Summary: Total Depth measured 9405 ` feet Plugs (measured) None true vertical 4210 - feet Junk (measured) None Effective Depth measured 9405 feet true vertical 4210 feet Casing Length Size MD TVD Burst Collapse Conductor 78' 20" 92# H-40 34' - 112' 34' - 112' Production 7097' 7" 26# L-80 35' - 7132' 35' - 4208' 7240 5410 SL Liner 2377' 4-1/2" 12.6# L-80 7028' - 9405' 4201' - 4214' 8430 7500 S~:~NNE~ JUL 2 ~ 200 Perforation depth: Measured depth: SEE ATTACHED True Vertical depth: Tubing: (size, grade, and measured depth) 2-7/8" 6.5# L-80 SURFACE - 6014' 4-1/2" 12.6# L-80 6077' - 6331' Packers and SSSV (type and measured depth) 7" 23-29# VTL PKR 6077' 7" SLZXP PKR 6286' BAKER ZXP LINER TOP PKR 7037' 0 0 12. Stimulation or cement squeeze summary: Intervals treated (measured); Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing pressure Prior to well operation: 279 73 382 0 215 Subsequent to operation: SI 0 0 0 0 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory ~ Development ~ Service ~ Daily Report of Well Operations X 16. Well Status after proposed work: Oil ~ Gas WAG ~ GINJ ~' WINJ WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Gary Preble Printed Name Gary Preble Title Data Management Engineer Signature Phone 564-4944 Date 6/12/2008 Form 10-404 R ised 04/2006 `~-'~ (~~ ~ ~.,~ ~ ~~ ~ _ ')~~' ~ `~ ~DO$ Submit Original Only ~ ~~a MPG-14 201-1330 PERF ATTACHMENT ., • Operation Date Perf Operation Code Meas Depth Top Meas Depth Base Tvd Depth Top Tvd Depth Base 8/14/01 PER 6,110. 6,130. 3,991.87 3,999.94 8/14/01 PER 6,190. 6,210. 4,024.27 4,032.29 8/14/01 PER 6,250. 6,270. 4,048.14 4,055.95 8/14/01 SL 7,137. 9,362. 4,208.2 4,215.09 8/14/01 SL 6,570. 9,304. 4,149.44 4,150.59 AB ABANDONED PER PERF APF ADD PERF _ RPF REPERF BPP BRIDGE PLUG PULLED _ SL SLOTTED LINER BPS BRIDGE PLUG SET SPR SAND PLUG REMOVED FCO FILL CLEAN OUT SPS SAND PLUG SET FIL FILL SQF SQUEEZE FAILED MIR MECHANICAL ISOLATED REMOVED SQZ SQUEEZE MIS MECHANICAL ISOLATED STC STRADDLE PACK, CLOSED MLK MECHANICAL LEAK STO STRADDLE PACK, OPEN OH OPEN HOLE • • MPG-14 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY ACTIVITYDATE SUMMARY J 6/4/2008 T/1=100/100 Acid Treatment (ESP WashZ Spear in tbg w/2 bbls 60/40 ',:methanol & 15 bbls 90'`F crude. Pumped 10 bbls 7.5% HCL DAD acid, 3 bbls 60/40 methanol & 25 bbls 90*F crude to displace acid to pump/screens. Turn well over to pad op for 20 min soak/pump run as per procedure. Verify casing valve open to gauge, tag well. Final WHP's=50/100 6/4/2008 T/I=0/40 Flush Acid from ESP -Pumped tbg w/50 bbls crude & 10 bbls diesel to flush acid treatment from ESP to formation. Verify casing valve open to gauge & notify operator. Final WHP's=0/40 FLUIDS PUMPED BBLS 5 60/40 METH 10 7.5%HCL DAD ACID 75 CRUDE 10 DIESEL 100 TOTAL e e MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFicbe\CvrPgs _ Inserts\Microfilm_ Marker. doc Permit to Drill 2011330 MD 9405 ?- '['VD DATA SUBMITTAL COMPLIANCE REPORT 101312003 Well Name/No. MILNE PT UNIT SB G-14 Operator BP EXPLORATION (ALASKA) INC 4210 ~-~ Completion Date 9/18/2001 ~ Completion Status 1-OIL Current Status 1-OIL APl No, 50-029-23031-00-~)0 UIC N REQUIRED INFORMATION Mud Log No Samples N__9o Directional Survey N._g.o DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name Log Log Run Scale Media No (data taken from Logs Portion of Master Well Data Maint) Interval OH I Start Stop CH Received Comments Rpt ED D Directional Survey Directional Survey FINAL 3 FINAL 114 9405 Open 9/21/2001 Directional Survey Open 11/2/2001 Open 9/21/2001 Directional Survey Well Cores/Samples Information: Name Start Interval Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? Y / Chips Received? Analysis Received? Daily History Received? ~,~' N Formation Tops ~ N Compliance Reviewed By: Date: .6 ..~.~:~ ~.,,-. 10/30/2001 GeoQuest 3940 Arctic Blvd Anchorage, AK 99503 ATEN: Sherrie NO. 1580 Company Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Milne Point (Cased Hole) Well Job # Loq Description Date CD Sepia BL MPG-14 ~Ot-tS,j~ 21423 CDR, IMP 09/20/01 1 MPG-14 21423 MDVISION RESISTIVITY 09/20/01 1 1 MPG-14 21423 TVD VISION RESISTIVITY 09/20/01 1 1 MPG-14 L1C-~0}- !~_'_~ 21424 CDR, IMP 09/25/01 1 MPG-14 L1 21424 MD VISION RESISTIVITY 09/25/01 1 1 MPG-14 L1 21424 TVD VISION RESISTIVITY 09/25/01 1 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data cent _CE VED 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 NOV 0 2 2.001 Date Delivered: 0il & Gas Cons. Comm;,~,on .An~orege Schlumberger GeoQuest 3940 Arctic Blvd Anchorage, AK 99503 AI-rN: Sherrie gyro/data B.P. EXPLORATION '~~ G PAD, WELL NO. MPG-14 MILNE POINT FIELD, ALASKA Gyro Multishot Inside 9.625", 7" Csg. Survey date :8/19/01 Job number :AK0801GCE519 .gyro/data CONTENTS JOB NUMBER :AK0801GCE519 1. DISCUSSION , SURVEY CERTIFICATION SHEET 2. SURVEY DETAILS 3. OUTRUN SURVEY LISTING 4. QUALITY CONTROL 5. EQUIPMENT AND CHRONOLOGICAL REPORT .gyro/data~t· ~, ,, 1. DISCUSSION , SURVEY CERTIFICATION SHEET gyro/data DISCUSSION JOB NUMBER · AK0801GCE519 Tool 066 was run in MPG-14 on wireline. The survey was run without any problems. gyro/data SURVEY CERTIFICATION SHEET JOB NUMBER: AK0801GCE519 The data for this survey and the calculations for this survey were obtained and performed by me according to standards and procedures as set forth by Gyrodata Limited, true and correct to the best of my knowledge. TOM STODDARD OPERATIONS ENGINEER The data and calculations for this survey have been checked by me and conform to the standards and procedures as set forth by Gyrodata Limited. This report represents a directional survey of this well based on. the original data obtained at the wellsite. Checked by :- WALTER KILEY OPERATIONS MANAGER ,gyro/data 2. SURVEY DETAILS gyro/data CLIENT: RIG: LOCATION: WELL: LATITUDE: LONGITUDE: SURVEY DATE: SURVEY TYPE : DEPTH REFERENCE: MAX. SURVEY DEPTH: SURVEY TIED ONTO: SURVEY INTERVAL: TARGET DIRECTION: GRID CORRECTION: CALCULATION METHOD: SURVEY DETAILS JOB NUMBER: AK0801GCE519 B.P. EXPLORATION G PAD MILNE POINT FIELD, AK MPG-14 70.450 N 149.600 E 8/19/01 CONTINUOUS ROTARY TABLE ELEVATION 7000' N/A 0 -7000' 331.32 N/A MINIMUM CURVATURE SURVEYOR: TOM STODDARD gyro/data 3. OUTRUN SURVEY LISTING A Gyrodata Directional Survey for B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 Run Date: 8/19/01 10:24:05 AM Surveyor: Tom Stoddard Calculation Method: MINIMUM CURVATURE Survey Latitude: 70.450000 deg. N Sub-sea Correction from Vertical Reference: 62.93 ft. Azimuth Correction: Gyro: Bearings are Relative to True North Proposed Well Direction: 331.320 deg Vertical Section Calculated from Well Head Location Closure Calculated from Well Head Location Horizontal Coordinates Calculated from Local Horizontal Reference A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 MEASURED I N C L AZIMUTH DOGLEG VERTICAL SUBSEA VERTICAL CLOSURE DEPTH SEVERITY DEPTH DEPTH SECTION DIST. AZIMUTH feet deg. deg. deg./ feet feet feet feet deg. 100 ft. 0.0 0.00 0.00 100.0 0.42 224.03 200.0 0.54 242.77 300.0 0.81 270.30 400.0 3.97 307.37 0.00 0.0 -62.9 0.0 0.42 100.0 37.1 -0.1 0.20 200.0 137.1 -0.2 0.42 300.0 237.1 0.1 3.35 399.9 337.0 3.7 450.0 4.42 306.88 500.0 4.90 306.80 550.0 5.37 306.24 600.0 5.88 306.16 650.0 6.35 305.59 0.91 449.8 386.8 7.0 0.95 499.6 436.7 10.7 0.96 549.4 486.5 14.7 1.01 599.2 536.2 19.2 0.95 648.9 585.9 24.0 700.0 6.91 304.12 750.0 7.77 302.52 800.0 8.55 302.05 850.0 9.41 302.15 900.0 10.76 302.63 0.0 0.0 0.4 224.0 1.2 231.3 2.3 245.1 5.6 281.7 950.0 11.57 303.62 1000.0 12.70 304.34 1050.0 14.16 304.80 1100.0 15.23 304.57 1150.0 16.49 304.61 9.1 291.7 13.0 296.3 17.5 298.9 22.3 3O0.5 27.6 301.6 1200.0 18.09 304.76 1250.0 19.50 304.81 1300.0 20.55 304.11 1350.0 22.00 304.08 1400.0 23.37 303.88 HORIZONTAL COORDINATES feet 0.00 N 0.26 S 0.74 S 0.96 S 1.15 N 3.35 N 5.79 N 8.45 N 11.34 N 14.46 N 1.17 698.5 635.6 29.2 33.4 302.1 17.76 N 1.77 748.1 685.2 34.8 39.8 302.3 21.26 N 1.58 797.6 734.7 41.0 46.9 302.3 25.05 N 1.71 847.0 784.1 47.8 54.7 302.3 29.20 N 2.72 896°2 833.3 55.5 63.4 302.3 33.89 N 73.1 302.4 83.6 302.6 95.2 302.8 107.9 303.1 121.6 303.2 1.65 945.3 882.4 64.0 2.29 994.2 931.2 73.3 2.93 1042.8 979.9 83.7 2.14 1091.2 1028.2 95.1 2.52 1139.3 1076.3 107.3 3.19 1187.0 1124.1 120.5 2.82 1234.3 1171.4 135.0 2.15 1281.3 1218.4 150.2 2.91 1327.9 1265.0 166.4 2.75 1374.0 1311.1 183.5 136.4 303.4 152.5 303.5 169.7 303.6 187.8 303.7 207.1 303.7 39.18 N 45.06 N 51.65N 58.87 N 66.63N 75.O9 N 84.28 N 93.96 N 104.13 N 114.91N 0.00 E 0.26W 0.93 W 2.06W 5.52W 8.43W 11.68W 15.28W 19.24W 23.55W 28.29W 33.63W 39.63W 46.24W 53.63W 61.74W 70.45W 80.01W 90.44W 101.69W 113.91W 127.14W 141.26W 156.28W 172.27W B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 A Gyrodata Directional Survey MEASURED I N C L AZIMUTH DOGLEG VERTICAL SUBSEA VERTICAL CLOSURE DEPTH SEVERITY DEPTH DEPTH SECTION DIST. AZIMUTH feet deg. deg. deg./ feet feet feet feet deg. 100 ft. 1450.0 24.65 304.39 1500.0 25.17 304.97 1550.0 26.25 305.48 1600.0 27.44 304.85 1650.0 27.93 304.61 1700.0 29.50 304.13 1750.0 30.60 303.48 1800.0 32.72 302.03 1850.0 33.78 301.27 1900.0 33.92 301.04 1950.0 33.79 300.89 2000.0 33.62 300.61 2050.0 35.45 300.12 2100.0 37.60 299.86 2150.0 39.30 300.45 2200.0 41.25 301.28 2250.0 43.17 301.70 2300.0 44.76 302.39 2350.0 46.19 303.12 2400.0 48.06 304.31 2.59 1419.7 1356.8 201.6 227.4 303.7 1.15 1465.0 1402.1 220.4 248.5 303.8 2.21 1510.1 1447.2 239.9 270.2 303.9 2.44 1554.7 1491.8 260.2 292.7 304.0 1.01 1599.0 1536.0 280.9 316.0 304.1 3.16 1642.8 1579.9 302.3 340.0 2.30 1686.1 1623.2 324.5 365.0 4.50 1728.7 1665.7 347.6 391.3 2.28 1770.5 1707.6 371.4 418.7 0.38 1812.0 1749.1 395.5 446.5 0.31 1853.5 1790.6 419.5 474.3 0.45 1895.1 1832.2 443.4 502.0 3.70 1936.3 1873.4 467.7 530.3 4.31 1976.5 1913.6 493.1 560.0 3.49 2015.6 1952.7 519.7 591.1 4.05 2053.8 1990.9 547.6 623.4 3.87 2090.8 2027.9 576.7 657.0 3.33 2126.8 2063.9 607.0 691.7 3.04 2161.9 2098.9 638.3 727.3 4.13 2195.9 2133.0 670.8 764.0 4.60 2228.6 2165.6 704.6 801.8 2.62 2260.1 2197.1 739.5 840.6 4.68 2290.3 2227.4 775.3 880.3 2.23 2319.4 2256.5 812.1 920.9 2450.0 50.30 305.01 2500.0 51.59 305.28 2550.0 53.88 305.91 2600.0 54.99 306.02 304.1 304.1 304.0 303.8 303.7 303.5 303.4 303.2 303.0 302.9 302.8 302.7 302.7 302.7 302.7 302.8 302.9 303.0 303.2 HORIZONTAL COORDINATES feet 126.32 N 138.31N 150.82 N 163.82N 177.06 N 190.62 N 204.55 N 218.74 N 233.12 N 247.53 N 261.86 N 276.05 N 290.37 N 305.24 N 320.86 N 337.45 N 355.00 N 373.42 N 392.71N 413.05 N 434.57 N 456.92 N 480.08 N 5O3.96 N 189.11W 206.43W 224.15W 242.61W 261.70W 281.53W 302.33W 324.41W 347.74W 371.58W 395.47W 419.31W 443.77W 469.54W 496.42W 524.17W 552.81W 582.23W 612.21W 642.68W 673.80W 705.55W 737.90W 770.82W B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 A Gyrodata Directional Survey MEASURED I N C L AZIMUTH DOGLEG VERTICAL SUBSEA VERTICAL CLOSURE DEPTH SEVERITY DEPTH DEPTH SECTION DIST. AZIMUTH feet deg. deg. deg./ feet feet feet feet deg. 100 ft. 2650.0 56.41 306.23 2.86 2700.0 57.57 306.16 2.32 2750.0 58.82 305.67 2.64 2800.0 59.92 305.31 2.29 2850.0 61.12 305.03 2.45 2900.0 61.21 305.05 0.19 2950.0 61.06 305.12 0.32 3000.0 60.80 305.14 0.54 3050.0 61.09 305.28 0.64 3100.0 62.06 305.28 1.94 3150.0 62.34 305.44 0.63 2347.6 2284.7 849.4 962.2 303.3 2374.8 2311.9 887.4 1004.1 303.4 2401.2 2338.3 925.8 1046.5 303.5 2426.7 2363.7 964.5 1089.5 303.6 2451.3 2388.3 1003.6 1133.0 303.7 2475.4 2412.5 1042.8 1176.8 303.7 2499.5 2436.6 1082.1 1220.6 303.8 2523.8 2460.9 1121.3 1264.3 303.8 2548.1 2485.2 1160.6 1308.0 303.9 2571.9 2509.0 1200.1 1351.9 303.9 2595.2 2532.3 1239.9 1396.2 303.9 3200.0 62.07 305.59 0.61 2618.5 2555.6 1279.7 3250.0 61.97 305.62 0.20 2642.0 2579.1 1319.5 3300.0 62.44 305.81 1.00 2665.3 2602.4 1359.3 3350.0 62.62 306.06 0.56 2688.4 2625.4 1399.4 3400.0 63.00 306.25 0.83 2711.2 2648.3 1439.7 3450.0 62.99 306.26 0.02 3500.0 63.14 306.41 0.40 3550.0 63.44 305.72 1.38 3600.0 62.90 304.06 3.14 3650.0 62.79 303.76 0.59 3700.0 61.35 303.14 3.08 3750.0 61.17 302.98 0.45 3800.0 60.73 302.92 0.89 1440.4 304.0 1484.5 304.0 1528.7 304.1 1573.1 304.1 1617.5 304.2 HORIZONTAL COORDINATES feet 528.32 N 553.07 N 577.99 N 602.97 N 628.04 N 653.19 N 678.36 N 703.51N 728.71N 754.11N 779.70 N 805.39 N 831.10 N 856.92 N 882.95N 909.19 N 2733.9 2671.0 1480.0 1662.0 304.3 935.54N 2756.6 2693.6 1520.4 1706.6 304.3 961.95N 2779.0 2716.1 1560.8 1751.2 304.4 988.24N 2801.6 2738.7 1600.8 1795.8 304.4 1013.77N 2824.4 2761.5 1640.3 1840.3 304.4 1038.59N , 2847.9 2784.9 1679.3 1884.5 304.3 1062.94N 2871.9 2809.0 1717.9 1928.3 304.3 1086.85N 2896.2 2833.2 1756.4 1972.0 304.3 1110.63N 804.18W 838.02W 872.43W 907.46W 943.04W 978.90W 1014.73W 1050.48W 1086.19W 1122.08W 1158.15W 1194.16W 1230.06W 1265.98W 1301.89W 1337.80W 1373.72W 1409.63W 1445.74W 1482.33W 1519.25W 1556.11W 1592.86W 1629.54W A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 MEASURED I N C L AZIMUTH DOGLEG VERTICAL SUBSEA VERTICAL CLOSURE DEPTH SEVERITY DEPTH DEPTH SECTION DIST. AZIMUTH feet deg. deg. deg./ feet feet feet feet deg. 100 ft. 3850.0 60.96 302.84 3900.0 61.27 302.91 0.47 2920.5 2857.6 1794.8 2015.7 304.2 0.64 2944.7 2881.8 1833.3 2059.4 304.2 3950.0 61.24 303.02 4000.0 61.71 302.80 4050.0 61.40 300.95 4100.0 61.31 300.66 4150.0 59.81 300.16 0.21 2968.7 2905.8 1871.9 1.03 2992.6 2929.7 1910.5 3.31 3016.4 2953.5 1948.8 0.53 3040.4 2977.5 1986.6 3.13 3065.0 3002.0 2024.0 4200.0 59.66 300.13 4250.0 60.04 300.10 4300.0 60.10 300.01 4350.0 60.21 300.20 4400.0 59.85 300.31 0.30 3090.2 3027.2 2060.9 0.77 3115.3 3052.4 2097.9 0.20 3140.2 3077.3 2134.9 0.39 3165.1 3102.2 2172.0 0.75 3190.1 3127.2 2209.1 4450.0 60.43 300.39 4500.0 60.34 300.44 4550.0 60.60 300.33 4600.0 60.87 300.42 4650.0 60.24 300.46 1.18 3215.0 3152.1 2246.3 0.21 3239.7 3176.8 2283.6 0.56 3264.3 3201.4 2320.9 0.56 3288.8 3225.8 2358.3 1.26 3313.4 3250.4 2395.7 4700.0 60.59 300.50 4750.0 60.42 300.54 4800.0 60.51 300.55 4850.0 60.79 300.54 4900.0 60.87 300.47 0.69 3338.0 3275.1 2433.0 0.34 3362.7 3299.7 2470.4 0.18 3387.3 3324.4 2507.8 0.56 3411.8 3348.9 2545.2 0.21 3436.2 3373.3 2582.7 4950.0 61.19 300.65 5000.0 61.05 300.68 0.70 3460.4 3397.5 2620.3 0.27 3484.6 3421.6 2658.0 2103.3 304.2 2147.2 304.2 2191.1 304.1 2234.9 304.1 2278.4 304.0 2321.5 3O3.9 2364.6 303.8 2407.8 303.8 2451.1 303.7 2494.4 303.7 2537.7 303.6 2581.1 3O3.5 2624.5 303.5 2668.1 303.4 2711.5 303.4 2755.0 303.3 2798.4 303.3 2841.9 303.3 2885.4 303.2 2929.0 303.2 2972.7 303.1 3016.5 303.1 HORIZONTAL COORDINATES feet 1134.33 N 1158.10 N 1181.95 N 1205.81N 1229.03 N 1251.50 N 1273.54 N 1295.23 N 1316.92 N 1338.62 N 1360.38 N 1382.20 N 1404.11N 1426.12 N 1448.12 N 1470.17 N 1492.23N 1514.29 N 1536.39N 1558.50 N 1580.64 N 1602.81N 1625.05 N 1647.38 N 1666.21W 1702.97W 1739.76W 1776.64W 1813.97W 1851.66W 1889.21W 1926.55W 1963.95W 2001.46W 2038.98W 2076.39W 2113.81W 2151.30W 2188.83W 2226.46W 2264.00W 2301.47W 2338.96W 2376.42W 2413.96W 2451.57W 2489.24W 2526.90W gyro/data 4. QUALITY CONTROL gyro/data QUALITY CONTROL REPORT JOB NUMBER: AK0801GCE519 TOOL NUMBER: 066 MAXIMUM GYRO TEMPERATURE: 77.61 C MAXIMUM AMBIENT TEMPERATURE: 20.02 C MAXIMUM INCLINATION: 84.66 AVERAGE AZIMUTH: 310.53 WIRELINE REZERO VALUE: REZERO ERROR/K: N/A CALIBRATION USED FOR FIELD SURVEY: 4179 CALIBRATION USED FOR FINAL SURVEY: 4179 PRE JOB MASS BALANCE OFFSET CHECK: -1.1 POST JOB MASS BALANCE OFFSET CHECK~: -.92 CONDITION OF SHOCK WATCHES UPON ARRIVAL AT RIG: OK UPON COMPLETION OF SURVEY: OK UPON RETURN TO ATLAS OK BOTTOM LINE COMPARISIONS M.D. INC AZIMUTH TVD NORTHING EASTING FIELD SURVEY N/A FINAL SURVEY 7000 84.60 0.90 4198.6 3048.4N 3564.9W gyro/data FUNCTION TEST JOB NUMBER' AK0801GCE519 5 Survey stations were collected at the measured depth shown below. The tables show the repeatability of the gyro tool in both inclination and azimuth at one measured depth. INCLINATION M.D. ft 1 2 3 4 5 1000 12.31 12.31 12.31 12.31 12.31 AZIMUTH M.D. ff 1 2 3 4 5 1000 304.39 304.24 304.34 304.09 304.18 gyro/data 5. EQUIPMENT AND CHRONOLOGICAL REPORT gyro/data EQUIPMENT REPORT JOB NUMBER: AK0801GCE519 DOWNHOLE ELECTRONICS SURFACE ELECTRONICS PRIMARY TOOL No. 066 GYRO SECTION A0285 DATA SECTION C0159 POWER SECTION C0197 COMPUTER POWER SUPPLY PRINTER INTERFACE A0527 A0107 A0029 A0166 BACKUP TOOL No. 402 GYRO SECTION A0102 DATA SECTION C0211 POWER SECTION C0207 COMPUTER POWER SUPPLY PRINTER INTERFACE A0693 A0085 A0165 WIRELINE COMPANY: SCHLUMBERGER CABLE SIZE: 3/8" RUNNING GEAR 1.75" HOUSING w ECCENTRIC BAR TOTAL LENGTH OF TOOL: 24.75' MAXIMUM O.D.: TOTAL WEIGHT OF TOOL: 193 POUNDS ,gyro/data CHRONOLOGICAL REPORT JOB NUMBER: AK0801GCE519 SATURDAY, 8/18/01 11:15 13:00 18:00 19:00 20:30 TO DEADHORSE ARRIVE DEADHORSE TO LOCATION ARRIVE LOCATION, MU TOOL SPOT UNIT, STANDBY SUNDAY, 8/19/01 02:30 03:15 05:15 06:45 08:00 10:00 17:00 RU WIRELINE RIH W/GYRO, PUMP TOOL DOWN END INRUN ~ 7000', START OUTRUN LD TOOL, RD WIRELINE TO DEADHORSE ARRIVE DEADHORSE, CHECK TOOL, PROCESS SURVEY, FAX RESULTS TO RIG W/RESULTS MONDAY, 8/20/01 08:00 10:15 12:00 SHIP TOOLS TO ANCHORAGE LEAVE DEADHORSE ARRIVE ANCHORAGE A Gyrodata Directional Survey for B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS Run Date: 8/19/01 10:24:05 AM Surveyor: Tom Stoddard Calculation Method: MINIMUM CURVATURE Survey Latitude: 70.450000 deg. N Sub-sea Correction from Vertical Reference: 62.93 ft. Azimuth Correction: Gyro: Bearings are Relative to Tree North Proposed Well Direction: 331.320 deg Vertical Section Calculated from Well Head Location Closure Calculated from Well Head Location Horizontal Coordinates Calculated from Local Horizontal Reference A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS SUBSEA I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. -62.9 0.00 0.00 37.1 0.42 224.03 137.1 0.54 242.77 237.1 0.81 270.30 337.0 3.97 307.37 0.00 0.42 0.20 0.42 3.35 386.8 4.42 306.88 436.7 4.90 306.80 486.5 5.37 306.24 536.2 5.88 306.16 585.9 6.35 305.59 0.91 0.95 0.96 1.01 O.95 635.6 6.91 304.12 685.2 7.77 302.52 734.7 8.55 302.05 784.1 9.41 302.15 833.3 10.76 302.63 VERTICAL VERTICAL CLOSURE DEPTH SECTION DIST. AZIMUTH feet feet feet deg. 882.4 11.57 303.62 931.2 12.70 304.34 979.9 14.16 304.80 1028.2 15.23 304.57 1076.3 16.49 304.61 0.0 0.0 0.0 0.0 100.0 -0.1 0.4 224.0 200.0 -0.2 1.2 231.3 300.0 0.1 2.3 245.1 399.9 3.7 5.6 281.7 1124.1 18.09 304.76 1171.4 19.50 304.81 1218.4 20.55 304.11 1265.0 22.00 304.08 1311.1 23.37 303.88 449.8 7.0 9.1 291.7 499.6 10.7 13.0 296.3 549.4 14.7 17.5 298.9 599.2 19.2 22.3 300.5 648.9 24.0 27.6 301.6 HORIZONTAL COORDINATES feet 0.00 N 0.26 S 0.74 S 0.96 S 1.15 N 3.35 5.79 8.45 11.34 14.46 1.17 698.5 29.2 33.4 302.1 17.76 1.77 748.1 34.8 39.8 302.3 21.26 1.58 797.6 41.0 46.9 302.3 25.05 1.71 847.0 47.8 54.7 302.3 29.20 2.72 896.2 55.5 63.4 302.3 33.89 945.3 64.0 73.1 302.4 994.2 73.3 83.6 302.6 1042.8 83.7 95.2 302.8 1091.2 95.1 107.9 303.1 1139.3 107.3 121.6 303.2 1187.0 120.5 136.4 303.4 1234.3 135.0 152.5 303.5 1281.3 150.2 169.7 303.6 1327.9 166.4 187.8 303.7 1374.0 183.5 207.1 303.7 1.65 2.29 2.93 2.14 2.52 3.19 2.82 2.15 2.91 2.75 39.18 45.06 51.65 58.87 66.63 75.09 84.28 93.96 104.13 114.91 N N N N N N N N N N N N N N N N N N N N 0.00 E 0.26W 0.93 W 2.06W 5.52W 8.43W 11.68W 15.28W 19.24W 23.55W 28.29W 33.63W 39.63W 46.24W 53.63W 61.74W 70.45 W 80.01W 90.44W 101.69W 113.91W 127.14W 141.26W 156.28W 172.27W A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS SUBSEA I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. 1356.8 24.65 304.39 1402.1 25.17 304.97 1447.2 26.25 305.48 1491.8 27.44 304.85 1536.0 27.93 304.61 1579.9 29.50 304.13 1623.2 30.60 303.48 1665.7 32.72 302.03 1707.6 33.78 301.27 1749.1 33.92 301.04 1790.6 33.79 300.89 1832.2 33.62 300.61 1873.4 35.45 300.12 1913.6 37.60 299.86 1952.7 39.30 300.45 1990.9 41.25 301.28 2027.9 43.17 301.70 2063.9 44.76 302.39 2098.9 46.19 303.12 2133.0 48.06 304.31 2165.6 50.30 305.01 2197.1 51.59 305.28 2227.4 53.88 305.91 2256.5 54.99 306.02 2.59 1.15 2.21 2.44 1.01 3.16 2.30 4.50 2.28 0.38 0.31 0.45 3.70 4.31 3.49 4.05 3.87 3.33 3.04 4.13 4.60 2.62 4.68 2.23 VERTICAL VERTICAL CLOSURE DEPTH SECTION DIST. AZIMUTH feet feet feet deg. 1419.7 201.6 227.4 303.7 1465.0 220.4 248.5 303.8 1510.1 239.9 270.2 303.9 1554.7 260.2 292.7 304.0 1599.0 280.9 316.0 304.1 1642.8 302.3 340.0 304.1 1686.1 324.5 365.0 304.1 1728.7 347.6 391.3 304.0 1770.5 371.4 418.7 303.8 1812.0 395.5 446.5 303.7 1853.5 419.5 474.3 303.5 1895.1 443.4 502.0 303.4 1936.3 467.7 530.3 303.2 1976.5 493.1 560.0 303.0 2015.6 519.7 591.1 302.9 2053.8 547.6 623.4 302.8 2090.8 576.7 657.0 302.7 2126.8 607.0 691.7 302.7 2161.9 638.3 727.3 302.7 2195.9 670.8 764.0 302.7 2228.6 704.6 801.8 302.8 2260.1 739.5 840.6 302.9 2290.3 775.3 880.3 303.0 2319.4 812.1 920.9 303.2 HORIZONTAL COORDINATES ket 126.32 N 138.31 N 150.82 N 163.82 N 177.06 N 190.62 N 204.55 N 218.74 N 233.12 N 247.53 N 261.86 N 276.05 N 290.37 N 305.24 N 32O.86 N 337.45 N 355.00 N 373.42 N 392.71 N 413.05 N 434.57 N 456.92 N 480.08 N 503.96 N 189.11W 206.43 W 224.15W 242.61 W 261.70W 281.53W 302.33W 324.41 W 347.74 W 371.58W 395.47W 419.31W 443.77W 469.54 W 496.42W 524.17W 552.81W 582.23W 612.21W 642.68W 673.80W 705.55 W 737.90W 770.82 W A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS SUBSEA I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. 2284.7 56.41 306.23 VERTICAL VERTICAL CLOSURE DEPTH SECTION DIST. AZIMUTH feet feet feet deg. 2311.9 57.57 306.16 2338.3 58.82 305.67 2363.7 59.92 305.31 2388.3 61.12 305.03 2412.5 61.21 305.05 2.86 2347.6 849.4 962.2 303.3 2436.6 61.06 305.12 2460.9 60.80 305.14 2485.2 61.09 305.28 2509.0 62.06 305.28 2532.3 62.34 305.44 2.32 2374.8 887.4 1004.1 303.4 2.64 2401.2 925.8 1046.5 303.5 2.29 2426.7 964.5 1089.5 303.6 2.45 2451.3 1003.6 1133.0 303.7 0.19 2475.4 1042.8 1176.8 303.7 2555.6 62.07 305.59 2579.1 61.97 305.62 2602.4 62.44 305.81 2625.4 62.62 306.06 2648.3 63.00 306.25 HORIZONTAL COORDINATES feet 528.32 N 553.07 N 577.99 N 602.97 N 628.04 N 653.19 N 0.32 2499.5 1082.1 1220.6 303.8 678.36 N 0.54 2523.8 1121.3 1264.3 303.8 703.51 N 0.64 2548.1 1160.6 1308.0 303.9 728.71 N 1.94 2571.9 1200.1 1351.9 303.9 754.11 N 0.63 2595.2 1239.9 1396.2 303.9 779.70 N 0.61 2618.5 1279.7 1440.4 304.0 805.39 N 0.20 2642.0 1319.5 1484.5 304.0 831.10 N 1.00 2665.3 1359.3 1528.7 304.1 856.92 N 0.56 2688.4 1399.4 1573.1 304.1 882.95 N 0~83 2711.2 1439.7 1617.5 304.2 909.19 N 2671.0 62.99 306.26 0.02 2733.9 1480.0 1662.0 304.3 2693.6 63.14 306.41 0.40 2756.6 1520.4 1706.6 304.3 2716.1 63.44 305.72 1.38 2779.0 1560.8 1751.2 304.4 2738.7 62.90 304.06 3.14 2801.6 1600.8 1795.8 304.4 2761.5 62.79 303.76 0.59 2824.4 1640.3 1840.3 304.4 3.08 0.45 0.89 2784.9 61.35 303.14 2809.0 61.17 302.98 2833.2 60.73 302.92 2847.9 1679.3 1884.5 304.3 2871.9 1717.9 1928.3 304.3 2896.2 1756.4 1972.0 304.3 935.54 N 961.95 N 988.24N 1013.77 N 1038.59 N 1062.94N 1086.85 N 1110.63 N 804.18W 838.02W 872.43 W 907.46W 943.04 W 978.90W 1014.73W 1050.48W 1086.19W 1122.08W 1158.15W 1194.16W 1230.06W 1265.98W 1301.89W 1337.80W 1373.72W 1409.63W 1445.74W 1482.33W 1519.25W 1556.11W 1592.86W 1629.54W B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS SUBSEA I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. 2857.6 60.96 302.84 2881.8 61.27 302.91 A Gyrodata Directional Survey 2905.8 61.24 303.02 2929.7 61.71 302.80 2953.5 61.40 300.95 2977.5 61.31 300.66 3002.0 59.81 300.16 VERTICAL VERTICAL CLOSURE DEPTH SECTION DIST. AZIMUTH feet feet feet deg. 3027.2 59.66 300.13 3052.4 60.04 300.10 3077.3 60.10 300.01 3102.2 60.21 300.20 3127.2 59.85 300.31 0.47 2920.5 1794.8 2015.7 304.2 0.64 2944.7 1833.3 2059.4 304.2 3152.1 60.43 300.39 3176.8 60.34 300.44 3201.4 60.60 300.33 3225.8 60.87 300.42 3250.4 60.24 300.46 0.21 1.03 3.31 0.53 3.13 3275.1 60.59 300.50 3299.7 60.42 300.54 3324.4 60.51 300.55 3348.9 60.79 300.54 3373.3 60.87 300.47 0.30 0.77 0.20 0.39 0.75 3397.5 61.19 300.65 3421.6 61.05 300.68 1.18 0.21 0.56 0.56 1.26 2968.7 1871.9 2103.3 304.2 2992.6 1910.5 2147.2 304.2 3016.4 1948.8 2191.1 304.1 3040.4 1986.6 2234.9 304.1 3065.0 2024.0 2278.4 304.0 3090.2 '2060.9 2321.5 303.9 3115.3 2097.9 2364.6 303.8 3140.2 2134.9 2407.8 303.8 3165.1 2172.0 2451.1 303.7 3190.1 2209.1 2494.4 303.7 3215.0 2246.3 2537.7 303.6 3239.7 2283.6 2581.1 303.5 3264.3 2320.9 2624.5 303.5 3288.8 2358.3 2668.1 303.4 3313.4 2395.7 2711.5 303.4 0.69 3338.0 2433.0 2755.0 303.3 0.34 3362.7 2470.4 2798.4 303.3 0.18 3387.3 2507.8 2841.9 303.3 0.56 3411.8 2545.2 2885.4 303.2 0.21 3436.2 2582.7 2929.0 303.2 0.70 0.27 3460.4 2620.3 2972.7 303.1 3484.6 2658.0 3016.5 303.1 HORIZONTAL COORDINATES feet 1134.33 N 1158.10 N 1181.95 N 1205.81N 1229.03 N 1251.50 N 1273.54 N 1295.23 N 1316.92 N 1338.62N 1360.38 N 1382.20 N 1404.11N 1426.12 N 1448.12N 1470.17N 1492.23N 1514.29 N 1536.39N 1558.50 N 1580.64N 1602.81N 1625.05 N 1647.38 N 1666.21W 1702.97W 1739.76W 1776.64W 1813.97W 1851.66W 1889.21W 1926.55W 1963.95W 2001.46W 2038.98W 2076.39W 2113.81W 2151.30W 2188.83W 2226.46W 2264.00W 2301.47W 2338.96W 2376.42W 2413.96W 2451.57W 2489.24W 2526.90W B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS SUBSEA I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. 3445.7 61.27 301.44 3469.8 61.28 302.14 3493.8 61.43 302.30 A Gyrodata Directional Survey 3517.6 61.62 302.42 3541.4 61.56 302.48 3565.1 61.91 302.58 3588.7 61.67 302.49 3612.3 62.10 302.73 VERTICAL DEPTH feet 3635.7 61.98 302.82 3659.1 62.21 302.97 3682.4 62.25 305.10 3705.6 62.47 305.79 3728.5 63.00 306.11 VERTICAL CLOSURE SECTION DIST. AZIMUTH feet feet deg. 3751.2 63.04 306.96 3773.8 63.26 309.63 3796.3 63.23 311.05 3818.7 63.51 313.48 3840.9 63.85 315.11 1.40 3508.7 2695.8 3060.2 303.1 1.22 3532.7 2733.9 3104.1 303.1 0.41 3556.7 2772.3 3147.9 303.0 3862.7 64.46 317.36 3884.1 64.84 318.43 3904.8 66.15 322.18 3924.9 66.35 323.39 3945.2 65.94 324.80 0.44 3580.5 2810.7 3191.9 303.0 0.16 3604.3 2849.3 3235.9 303.0 0.73 3628.0 2887.8 3279.9 303.0 0.51 3651.6 2926.5 3324.0 303.0 0.96 3675.2 2965.1 3368.1 303.0 3965.4 66.37 327.26 0.27 3698.6 3003.9 3412.2 303.0 0.53 3722.0 3042.8 3456.4 303.0 3.76 3745.3 3082.1 3500.6 303.0 1.31 3768.5 3122.0 3544.9 303.0 1.21 3791.4 3162.1 3589.3 303.1 1.51 3814.1 3202.6 3633.8 303.1 4.78 3836.7 3243.6 3678.2 303.2 2.53 3859.2 3285.3 3722.5 303.3 4.38 3881.6 3327.6 3766.6 303.4 3.00 3903.8 3370.4 3810.7 303.5 4.24 3925.6 3413.9 3854.6 303.7 2.08 3947.0 3457.8 3898.4 303.8 7.30 3967.7 3502.5 3942.0 304.0 2.25 3987.9 3547.7 3985.4 304.2 2.72 4008.1 3593.1 4028.4 304.4 4.58 4028.3 3638.6 4071.0 304.7 HORIZONTAL COORDINATES feet 1669.97 N 1693.07 N 1716.47 N 1739.99 N 1763.59 N 1787.27 N 1810.96 N 1834.73N 1858.64 N 1882.64N 1907.40 N 1933.08 N 1959.18N 1985.71N 2013.35 N 2042.25N 2072.30 N 2103.60 N 2136.10 N 2169.62 N 2204.63 N 2241.07 N 2278.11N 2316.03 N 2564.42W 2601.69W 2638.81W 2675.93W 2713.04W 2750.17W 2787.32W 2824.47W 2861.60W 2898.70W 2935.36W 2971.45W 3007.42W 3043.22W 3078.23W 3112.26W 3145.34W 3177.42W 3208.54W 3238.83W 3267.88W 3295.56W 3322.38W 3347.93W A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519SS SUBSEA I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. VERTICAL VERTICAL CLOSURE DEPTH SECTION DIST. AZIMUTH feet feet feet deg. 3985.2 66.84 328.57 2.57 4004.5 67.75 330.85 4.59 4022.8 69.27 332.93 4.91 4040.0 70.54 335.80 5.96 4048.2 3684.4 4113.2 304.9 4067.5 3730.5 4155.1 305.2 4085.8 3777.0 4196.7 305.5 4103.0 3823.9 4237.9 305.8 4056.1 72.04 337.86 4.93 4070.7 74.00 339.24 4.72 4083.4 76.48 340.08 5.22 4093.6 79.99 341.12 7.32 4100.2 84.83 342.21 9.91 4119.0 3871.1 4278.5 306.1 4133.6 3918.5 4318.9 306.5 4146.3 3966.3 4359.5 306.8 4156.5 4014.6 4400.2 307.2 4163.1 4063.4 4441.1 307.5 4103.9 86.67 345.20 7.01 4107.5 85.14 349.36 8.84 4112.5 83.37 352.79 7.69 4118.9 81.90 354.30 4.19 4125.6 82.81 357.41 6.43 4166.8 4112.1 4481.5 307.9 4170.4 4160.0 4520.1 308.3 4175.4 4206.8 4556.7 308.7 4181.8 4252.7 4592.0 309.2 4188.5 4297.8 4626.2 309.6 4131.0 84.66 0.24 6.75 4135.7 84.60 0.90 1.32 4193.9 4341.9 4658.8 310.1 4198.6 4385.3 4690.6 310.5 Final Station Closure: Distance: 4690.58 ft Az: 310.53 deg. HORIZONTAL COORDINATES feet 2354.91N 2394.74 N 2435.77N 2478.10N 2521.63 N 2566.14 N 2611.47 N 2657.63N 2704.67 N 2752.52 N 2801.15N 2850.29 N 2899.56 N 2948.98 N 2998.66N 3048.44N 3372.31W 3395.57W 3417.48W 3437.79W 3456.42W 3473.90W 3490.71W 3506.96W 3522.54W 3536.53W 3547.51W 3555.23W 3560.80W 3564.39W 3565.40W 3564.91W . STATE OF ALASKA , ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well [] Oil [] Gas [] Suspended [] Abandoned [] Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 201-133 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-23031-00 4. Location of well at surface .' ~~-~ 9. Unit or Lease Name 2015' NSL, 3446' WEL, SEC. 27, T13N, R10E, UM ·~:~' Milne Point Unit At top of productive interval~,~' I ¥2,~f:? I' 5182' NSL, 1700' WEL, SEC. 28, T13N, R10E, UM ' ..~..'__..:'O/ ISu~-IL-'~[---~I 10. Well Number ^t tota, depth 2124' NSL, 1081' WEL, SEC. 21, T13N, R10E, UM' .,~.,~.,.._~.~, 11. Field and Pool 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Milne Point Unit / Schrader Bluff KBE = 62.93' ADL 315848 12. Date Spudded 8-9-2001 113' Date T'D' Reached 114' Date C°mp'' Susp'' °r Aband' 8-20-2001 9-18-2001 115' Water depth' if °ffsh°re N/A MSL II 16' N°' °f C°mpleti°ns One 17. Total Depth (MD+TVD) 118. Plug Back Depth (MD+TVD) 119. Directional Survey 1 20. Depth where SSSV set1 21. Thickness of Permafrost 9405 4210 FTI 9405 4210 FTI [] Yes [] NoI N/A MDI 1800' (Approx.) 22. Type Electric or Other Logs Run MWD, DIR, GR, RES, PWD, ABGR, ABI 2,'~. CASING~ LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE TOP BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 20" 92# H~40 34' 112' 30" _~60 SX Arctic Set (Approx.) 7" 26# L-80 35' 7132' 9-7/8" B60 sx PF 'L'I 512 sx Class 'G' 4-1/2" 12.6# L-80 7028' 9405' 6-1/8" LJncemented Slotted Liner 24. Perforations open to Production (MD+'I-VD of Top and 25. TUBING RECORD Bottom and interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3-3/8" Gun Diameter, 6 SPF 4-1/2" Slotted Liner 2-7/8", 6.5#, L-80 6014' 6077' MD TVD MD TVD 4-1/2", 12.6#, L-80 6077'- 6331' 6286' 6110' - 6130' 3988' - 3997' 7137' - 9362' 4204' - 4211' 6190' - 6210' 4021' - 4029' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 6250' - 6270' 4045' - 4052' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protected with 80 bbls Dead Crude 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) September 29, 2001 Electric Submersible Pump Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO 10-1-2001 12 TEST PERIOD 1710 619 56 100I 362 Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (CORR) Press. 24-Hour RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. RECEIVED OCT 0 5 2001 Alaska 0il & Gas Cons. Commissior~ Form 10-407 Rev. 07-01-80 ORIGINAL Anchorage Submit In Duplicate 129. Geologic Markers 30. Formation Tests Measured True Vertical Include interval tested, pressure data, all fluids recovered Marker Name Depth Depth and gravity, GOR, and time of each phase. Schrader NA 6031' 3956' Schrader NB 6112' 3989' Schrader NC 6190'. 4021' Schrader NE 6250' 4045' Schrader NF 6387' 4095' Top of Schrader CA 6500' 4131' Basd CA / Top Schrader BC 6723' 4164' Top Schrader OB 7094' 4202' RECEIVED OCT 0 5 Z001 Alaska Oil & Gas Cons. Commissio~ Anchorage 3"-I'i LIS{' Of'~tt~hm~'nt'~: ....... S'drn'rnary'of' DailY"D~iil'ing'RePort'sl SurveyS, 'Leak'off Integrity Test ...... 32. I hereb'y certifY thai th"e fo'regoing"is t;'ue and Correct io th'e best of my knowledge ....................... SignedTerrie Hubble~/,~~,' ~~~U~. Title Technical Assistant Date lO"O~:~-0 I MPG-14 201-133 Prepared By Name/Number: Sondra Stewman, 564-4750 Well Number Permit No. / Approval No. INSTRUCTIONS {~ENERAL: This form is designed for submitting a complete and correct well completion report and Icg on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 ORIGINAL Legal Name: MPG-14 Common Name: MPG-14 : ~:: Test:Date i i :i ::::: i :: Test Ty~ : : Te~t Dept~ ~TMD): Te~ Depth i~D) AMWi: ::sUrface:PreSSure Leak Off Pressure (BHP) EMW 8/18/2001 FIT 7,168.0 (ft) 4,205.0 (ft) 9.20 (ppg) 450 (psi) 2,460 (psi) 11.26 (ppg) Printed: 9/4/2001 5:06:11 PM BP EXPLORATION Page 1of 9 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description.of Operations 8/6/2001 16:30 - 00:00 7.50 RIGU P PRE Moving to rig G- pad, pipe sheds and welding shop on pad 8/7/2001 00:00 - 02:00 2.00 MOB P PRE Moved sub from F pad to L pad. 02:00 - 02:30 0.50 MOB P PRE Checked tires on motor room and sub 02:30 - 05:30 3.00 MOB P PRE Moved from L pad to Milne Point Y to turn around. Check tire and let cool on sub. 05:30 - 06:30 1.00 MOB P PRE Moved pits and motor room to G pad. 06:30 - 10:00 3.50 MOB P PRE Return for sub and broke tongue. Repair sub and lay mats. 10:00 - 12:00 2.00 MOB P PRE Move sub from Milne Point Y turn-a-round to G-pad. 12:00 - 15:30 3.50 MOB P PRE Move tires on sub and spot over well. 15:30 - 18:30 3.00 MOB P PRE Set mats and spot pipe shed and drilling line spool. 18:30 - 20:30 2.00 MOB P PRE Set mats and spot pits. 20:30 - 23:00 2.50 MOB P PRE Set mats and spot motor room. 23:00 - 00:00 1.00 MOB P 'PRE Spot pumps. 8/8/2001 00:00 - 05:00 5.00 MOB P PRE Accepted rig at 0001 hrs 08/08/2001. Nipple up 21" diverter with 16" knife valve. Rigged up skate. 05:00 - 12:00 7.00 MOB P PRE Take on water to pits - build spud mud - load pipe shed wi5" drill pipe - clean and pick up rig for spud - take down drlg nipple to modify 12:00 - 15:00 3.00 MOB P PRE Con't loading 5" drill pipe in pipe shed - set in mouse hole 15:00 - 16:00 1.00 MOB P PRE Service top drive - check all bolts, safety keepers 16:00 - 17:30 1.50 MOB P PRE P/U 3 joints of 5" drill pipe and function test annular and knife valve. 17:30 - 00:00 6.50 MOB P PRE P/U 5" drill pipe in mouse hole and rack in derrick 8/9/2001 00:00 - 00:30 0.50 MOB P PRE Rig service 00:30 - 04:30 4.00 MOB P PRE P/U 5" drill pipe 04:30 - 07:30 3.00 MOB P PRE P/U 5" hwdp and bha - stand in derrick 07:30 - 12:00 4.50 MOB P PRE Install drilling nipple - hook up flow line riser - Install stiff arms on drilling nipple 12:00 - 13:00 1.00 MOB P PRE Weld 4" collar on divertor line. 13:00 - 14:00 1.00 MOB P PRE P/U motor, bit, XO and one stand dp. 14:00 - 14:30 0.50 MOB P PRE Pre Spud meeting 14:30 - 15:30 1.00 MOB P PRE Break circ and repair leak in riser 15:30 - 16:30 1.00 DRILL P SURF Spud in at 112' - 75 spm 450 psi - 60 rpm @ 2700 ft lbs - drill ~ce plug @ 43'- clean outto 112'- drill to 150' 16:30 - 18:00 1.50 DRILL N SFAL SURF Flow line plugged - clean out gravel, sand 18:00 - 18:30 0.50 DRILL P SURF Drlg from 150' to 211' - 80 spm 700 psi - 50 rpm @ 2500 ft lbs 18:30 - 19:00 0.50 DRILL P SURF POH 2 stands of hwdp 19:00 - 20:30 1.50 DRILL P SURF P/U bha and make up same 20:30 - 22:00 1.50 DRILL N SFAL SURF Flow line plugged - gravel, sand 22:00 - 00:00 2.00 DRILL P SURF Drlg from 211'to 378' - 100 spm 1300 psi - 51 rpm @ 2500 ft lbs - P/U 70k - S/O 70K 8/10/2001 00:00 - 14:30 14.50 DRILL P SURF Directional drill 9 7/8" surface hole from 378' to 1966' 14:30 - 16:30 2.00 DRILL N FLUD SURF Cir¢ mud - thick mud, due to addition of Le¢itin for gas hydrates Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 2 of 9 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 'Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 :Contractor Name: NABORS Rig Release: 9/3/2001 !Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 1811012001 14:30 - 16:30 2.00 DRILL N FLUD SURF - gas hydrates belching in drlg nipple - only able to pump 2 bpm to keep mud from over flowing drilling nipple 116:30 - 17:30 1.00 DRILL P SURF Directional Drilling from 1966' to 2146' - 420 gpm 1300 psi - 25k wob - 50 rpm - 6k torque 17:30 - 19:30 2.00 DRILL N FLUD SURF gas hydrate problem - gas belching in drlg nipple overflowing nipple - causing celler to over fill spilling drilling mud onto pad from under rig sub - flow line not handling thick mud - pumping at 4 bpm 19:30 - 21:00 1.50 DRILL P SURF Directional drill from 2146' to 2393' -wob 15~20 - rpm 50 - 435 gpm 1400 psi - torqe 5k to 6k 21:00 - 21:30 0.50 DRILL P SURF Circ for short trip - 435 gpm 1400 psi - 85 rpm - torque 5k 21:30 - 23:00 1.50 DRILL P SURF Pull 10 stands pumping out - string weight 120k to 110k - pull stand 11 w/o/p string weight 110k to 120k- stand 12 @ 1320' pulled tight to 160k work twice no go - top drive up - pump out string weight 11 Ok to 115k - pump out stand 13 string weight 100k to 105k - pull stands 14, 15, 16 with out pump string weight 100k to 110k pull to 904'- Hole in good condition 23:00 - 23:30 0.50 DRILL P SURF Rig service 23:30 - 00:00 0.50 DRILL P SURF RIH from 904' to 2230' - break circ - precautionary wash from 2330' to 2393' - hole in excellent shape - no problems on trip in - no hydrates seen on trip out or in - 8/11/2001 00:00 - 13:00 13.00 DRILL P SURF Directional Drilling from 2393' to 4000' - 525 gpm 2000 psi - 20-30k wob - 125 rpm - 9-10k torque 13:00 - 13:30 0.50 DRILL P SURF Circulate bottoms up before short trip. 13:30 - 17:00 3.50 DRILL P SURF Pumped out of hole 4000' to 1579'. POH to 1296' without pumping. No problems hole in excellent shape 17:00 - 17:30 0.50 DRILL P SURF Service top drive. 17:30 - 18:30 1.00 DRILL P SURF RIH to 4000' - No tight spots 18:30 - 00:00 5.50 DRILL P SURF Precautionary wash from 3920' to 4000' - Directional drilled !from 4000' to 4678'. - 500 gpm 2200 psi - 20-30k wob - 100 .rpm 9-10k torque - P/U 135 - S/O 110 - Rotating 120 8/12/2001 00:00 - 10:00 10.00 DRILL P SURF Directional drill from 4678' to 5772'. Torque 11-12k, WOB 25-30, 100rpm, 545gpm, 2250psi, PU 165, SO 115, ROT 135. 10:00 - 12:00 2.00 DRILL P SURF Pumped out of hole and backream from 5772' to 5143'. Pulled out of hole to 3930' without pumping. No problems hole in excellent shape. 12:00 - 12:30 0.50 DRILL P SURF Service top drive. 12:30 - 13:00 0.50 DRILL P SURF RIH to 5710'. Precautionary wash from 5710' - 5772'. No 3roblems hole in good shape. 13:00 - 17:30 4.50 DRILL P SURF Directional drill from 5772' to 6093'. Torque 11-13k, WOB 20-25, 80rpm, 545gpm, 2300psi, PU 175, SO 125, ROT 135 17:30 - 19:30 2.00 DRILL P SURF CBU for bit change - mix dry job - pump dry job 19:30 - 00:00 4.50 DRILL P SURF Trip for bit due to trouble sliding and no reaction on slide - POH to 1689' - one tight spot at 2357' - work once with out pump or rotary ok 8/13/2001 00:00 - 00:30 0.50 DRILL P SURF Con't poh to hwdp at 920' 00:30 - 03:00 2.50 DRILL P SURF Pull bha - break off bit - service motor - rih down load CDR - change out MWD - stand back 03:00 - 04:30 1.50 DRILL P SURF Pick up 3 1/2" dp in mouse hole - stand back in derrick 04:30 - 10:00 5.50 DRILL P SURF Make up bit #2 - rih - filling every 25 stands - tight hole at 2630 to 2850 / 4115 to 4396 - no other tight spots were noted Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 3 of 9 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 8/13/2001 10:00 - 00:00 14.00 DRILL P SURF Directional; drill from 6093' to 6742'. Torque 13-14k, WOB 20-30k, 80rpm, 545gpm, 2350psi, PU 170, SO 125, ROT 140. 8/14/2001 00:00 - 10:00 10.00 DRILL P SURF Directional drill from 6742 to 7138' - T.D. 9 7/8" hole -wob 40 to 50k - 513 pm 2150 psi - P/U 175 S/O 110 ROT 125 10:00 - 13:00 3.00 DRILL P SURF Pump sweep - circ / cond hole for short trip - ream from 7138 to 6931 - pump dry job 13:00 - 20:00 7.00 DRILL P SURF POH w/o pump from 7138' to 3078' - ratty from 6800' to 6450' - 10 to 30k over - pump out from 3078' to 1573' - tight at 2670 to 2430 work through tight spots - pull from 1573' to 920' 20:00 - 21:00 1.00 DRILL P SURF Rig Service 21:00 - 00:00 3.00 DRILL N RREP SURF Rig repair - tilt link system would not release to neutrel - Solenoid worn out - Replace solenoid - no power from switch to solenoid to release valve letting tilt float. 8/15/2001 00:00 - 00:30 0.50 DRILL N RREP SURF Replacing solenoid on tilt link system 00:30 - 03:00 2.50 DRILL P SURF RIH from 920' to 2428' work through tight spot wlol pump - rih from 2450' to 6450' - filling pipe every 25 stands 03:00 - 04:30 1.50 DRILL P SURF wash and ream ratty hole from 6450' to 7138' - hole in good shape no tight spots washing in from 6450' 04:30 - 07:00 2.50 DRILL P SURF Pump hi-vis sweep - circ / cond hole for running 7" casing - build dry job - pump dry job 07:00 - 10:30 3.50 DRILL P SURF POH to BHA - hole in good shape no tight spots noted 10:30 - 14:00 3.50 DRILL P SURF Stand back hwdp in derrick - Lay down flex collars - mwd - cdr - motor - service motor 14:00 - 17:00 3.00 CASE P SURF Rig up casing equipment - hold safetry meeting on 7" casing job. 17:00 - 19:00 2.00 CASE P SURF Rig service - lubricate top drive, rig 19:00 - 00:00 5.00 CASE P SURF Run 7" casing - Break circ pump casing vol Joint # 100 @ 4100'- 120 joints in hole @ 00:00 hrs 8/16/2001 00:00 - 03:00 3.00 CASE P SURF Finish Running 7" 26# L-80 Btc-Mod casing - Total 174 jts 7,087', Landed on mandrell casing hanger - shoe at 7,132' 03:00 - 04:00 1.00 CEMT P SURF Circulate and condition mud - slowly increase pump rate 2 bpm to 8 bpm 650 psi - Mud wt. 9.5 ppg 04:00 - 05:00 1.00 CEMT P SURF Rig down Frank's fill up tool - Make up Halliburton double plug cement head 05:00 - 06:30 1.50 CEMT P SURF Continue Circulating casing 8 bpm 650 psi - full returns - did not reciprocate pipe 06:30 - 10:00 3.50 CEMT P SURF Pre-Job safety meeting - pump 5 bbls water -Test lines to 4000 psi, Pump 20 bbl water + 50 bbls Alpha spacer mixed at 10.2 ppg, Followed by 860 sx Class 'L' cement, Yield 4.15 cf/sx, 635 bbls slurry mixed at 10.7 ppg Tailed with 515 sx 'Premium'w/ .2% Halid 344 +.2% CFR-3 + 1% cacl - Yield 1.15 cf/sx, 105 bbls slurry mixed at 15.8 ppg - Drop top plug with 20 bbls water & Displaced with rig pump 247 bbls mud, 8 bbl/min 1200 psi - Bump to 2000 psi - full returns - 300 bbls cement to surface - ClP 10:00 hrs 8/16/01 10:00 - 12:00 2.00 CEMT P SURF Check floats, ok - Rig down cement head, Back out landing jt and lay down - Rig down casing tools 12:00 - 15:00 3.00 BOPSUF P SURF Nipple down 20" diverter system 15:00 - 16:00 1.00 WHSUR P PROD1 Nipple up FMC Gen 6 SO x 11" 5000# wellhead - Test seal to 1000 psi ok 16:00 - 20:00 4.00 BOPSUF P PROD1 Nipple up 11" x 13 5/8" 5000# adapter spool and 13 5/8" 5000# Bop stack - Nabors Rental 3 1/2" pipe rams top and Bottom, Blind rams middle Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 4 of 9 Operation Summa Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 8/16/2001 20:00 - 23:00 3.00 DRILL P PROD1 Slip and cut drlg line - adjust brake linkage 23:00 - 00:00 1.00 DRILL P PROD1 Changing 5" saver sub to 3 1/2" on top drive 8/17/2001 00:00 - 01:30 1.50 DRILL P PROD1 Finish changing top drive saver sub from 5" to 3 1/2" - Install bails - elevators 01:30 - 03:00 1.50 DRILL P PROD1 Install drilling nipple, drip pan 03:00 - 16:00 13.00 DRILL P PROD1 Lay down 5" HWDP - 5" drill pipe in mouse hole 16:00 - 18:30 2.50 DRILL N RREP PROD1 Work on top drive - lub/oil - Rig down time 18:30 - 20:00 1.50 DRILL P PROD1 Rig up to test bop's 20:00 - 00:00 4.00 DRILL P PROD1 Test Bop's - Annular 250 Iow 3000 high - Top / Btm 3 1/2" pipe rams 250 Iow 3500 high - Manifold valves 250 Iow 3500 high accumulator test 3000 psi - shut pipe rams, annular, hydralic choke, hydralic kill valve psi 1850 - 200 psi increase 23 sec - full pressure 1 min 10 sec 3000 psi - 8 bottles avg 2350 - con't testing bop's 8/18/2001 00:00 - 02:00 2.00 DRILL P PROD1 Test bop's - blind rams 250 Iow 3500 high - upper, lower, TIW, IBOP 250 Iow 3500 high - finish choke valves 02:00 - 03:30 1.50 DRILL P PROD1 Pull test plug - install wear ring - rig down testing equipment - blow down choke manifold - cementing line - top drive 03:30 - 07:30 4.00 DRILL P PROD1 P/U 3 1/2" dp - stand back 14 stands in derrick 07:30 - 10:00 2.50 DRILL P PROD1 P/U bha # 3 - - flow test motor / mwd - 60 spm 800 psi 10:00 - 17:30 7.50 DRILL P PROD1 P/U 3 1/2" dp - rabbit each joint on skate - rih to 6980' 17:30 - 18:30 1.00 DRILL P PROD1 wash cement stringers from 6980' to 7043' 18:30 - 19:30 1.00 DRILL P PROD1 CBU for casing test 19:30 - 20:00 0.50 DRILL P PROD1 Test casing to 3500 psi - hold for 30 mins - ok 20:00 - 22:00 2.00 DRILL P PROD1 Drill float equipment - 30' new hole to 7168' - wob 5k - rpm 50 - spm 60 - 2050 psi 22:00 - 22:30 0.50 DRILL P PROD1 CBU for FIT test 22:30 - 23:00 0.50 DRILL P PROD1 Run FIT test to equiv 11.26 - 450 psi surface pressure with 9.2 mud wt in hole TVD 4205' 23:00 - 00:00 1.00 DRILL P PROD1 Displace spud mud with - 9.2 FIo-Pro 8/19/2001 00:00 - 01:00 1.00 DRILL P PROD1 Displace to 9.2 FIo-Pro mud 01:00 - 07:00 6.00 DRILL P PROD1 PJSM with Schlumberger on rigging up to run gyro - rig up Schlumberger - Run Gyro to 7000' - Log up - Rig down Schlumberger 07:00 - 00:00 17.00 DRILL P PROD1 Directional drill from 7168' to 8230' - WOB 5k - SPM 60, 1650 psi- GPM 250 - RPM 115 - P/U 130k - S/O 90k - Rot 95k 8/20/2001 00:00 - 14:00 14.00 DRILL P PROD1 Directional drill from 8230' to 9405' T.D. well - 120 rpm - wob 2/5k - 1950 psi - 250 gpm - P/U 125k - S/O 80k - Rot 90k - 7k tq 14:00 - 17:00 3.00 DRILL P PROD1 CBU - 3 times 7400 stks - 66 spin - 120 rpm - 2150psi 17:00 - 19:30 2.50 DRILL P PROD1 Trip to shoe @ 7132' - trip out pumping 24 stds at 60 spin - string wt 125k - hole in good condition. 19:30 - 20:00 0.50 DRILL P PROD1 Rig service - top drive / drawworks - monitor well - well static 20:00 - 22:00 2.00 DRILL P PROD1 RIH to 9405'- no problems on trip in - hole in good condition - string wt 60k to 80k 22:00 - 00:00 2.00 DRILL P PROD1 CBU ~ three times @ 66spm - 2150 psi - 120 rpm - string wt 125k up - 80k s/o - 90k rot - oil show in mud - gas cut mud back 9.2+ with pressurized scale - 8.7 with regular scale - no flow / no gain on btms up. 8/21/2001 00:00 - 00:30 0.50 DRILL P PROD1 Finish spotting new mud in open hole, 00:30 - 04:00 3.50 DRILL P PROD1 Pumping up into csg.@7132, pumping out with 10spm and 400 psi, no problems 04:00 - 09:00 5.00 DRILL P PROD1 Monitor well, trip out to BHA Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 5 of 9 Operations Summa Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From- To Hours Activity Code NPT Phase Description of Operations 8/21/2001 09:00 - 11:00 2.00 DRILL P PROD1 Monitor well, lay down BHA 11:00 - 11:30 0.50 CASE P COMP Clear floor, rig up to pick up liner 11:30 - 15:00 3.50 CASE P COMP Picking up 57 jts Slotted 3 Blank Jts 4 1/2 12.6# L-80 And Baker 5x7 HMC liner hanger with baker ZXP liner top packer total talley 2368 ft. ( no inter string) 15:00 - 17:00 2.00 CASE P COMP Trip in with liner to 9405, liner top 7029 ( no problems) Pick up wt 138,000 slack offwt. 80,000 17:00 - 18:00 1.00 CASE P COMP circ volume of pipe, drop ball and set packer ball sheared out with 3800# 18:00 - 19:00 1.00 CASE P COMP Circ bottoms up from 7000 ft and pump slug 19:00 - 22:00 3.00 CASE P COMP Strapping out with drill pipe, pipe strap OK 22:00 - 00:00 2.00 BOPSUF P PROD1 Rig up, pull wear ring, testing BOPS 250-3500 8/22/2001 00:00- 04:00 4.00 BOPSUF.P PROD2 Testing BOPS 250-3500# (OK) 04:00 - 05:00 1.00 BOPSUF.P PROD2 Install wear ring and blow down 05:00 - 07:00 2.00 STVVHIP P PROD2 Pick up 15 its of 3.5 and seal ass. for space out of whip stock 07:00 - 10:30 3.50 STWHIP P PROD1 Pick up whip stock and MWD 10:30 - 15:00 4.50 STWHIP P PROD1 Trip in with whip stock to 6450 15:00 - 16:00 1.00 STWHIP P PROD1 Orient whip stock and sting in to OB liner @ 7028- set whip stock anchor w/15,000, tool face 5 Dregees left highside, pull test 10,000 over and shear off whip stock w/35,000 16:00 - 19:00 3.00 STWHIP P PROD1 Mill window in 7" csg 6508-6520 pilot hole to 6530 19:00 - 20:30 1.50 STWHIP P PROD1 Circ 3 bottoms up 5100 pump st. 20:30 - 00:00 3.50 STWHIP P PROD1 Trip out with mill 8/23/2001 00:00 - 02:00 2.00 STWHIP P PROD2 Finish trip out with Mills 02:00 - 02:30 0.50 STWHIP P PROD2 Flush out BOPS 02:30 - 03:00 0.50 STWHIP P PROD2 Pick up 12 jts of 3.5 and stand in derrick 03:00 - 05:30 2.50 DRILL P PROD2 Pick up BHA #2 adjust motor to 1.15 test mwd tool, rerun sec. pdc bit 05:30 - 08:30 3.00 DRILL P PROD2 Trip in hole fill pipe every 25 sds. 08:30 - 09:00 0.50 DRILL P PROD2 Orient and slide tru window @ 6508 09:00 - 12:00 3.00 DRILL P PROD2 Drlg from 6532 to 6607 (MWD failed) 12:00 - 15:00 3.00 DRILL N DF^L PROD2 Tripping out for MWD tool 15:00 - 17:30 2.50 DRILL N DF^L PROD2 Lay down motor and mwd tools., pick up new motor and mwd and test same-- bit FM2643 w/3/13 jets, motor XP AIM w/ 1.50, nm flex, nm stab, mwd, pwd,3 nm flex, jars 17:30 - 18:30 1.00 DRILL N DFAL PROD2 Trip in to 2500 18:30- 19:00 0.50 DRILL N DFAL PROD2 Service rig and topdrive 19:00 - 21:00 2.00 DRILL N DFAL PROD2 Tripping in from 2500 to 6532 21:00 - 22:00 1.00 DRILL N DFAL PROD2 logging hole from 6508 to 6607 22:00 - 00:00 2.00 DRILL P PROD2 Drilling from 6607 to 6698 with 1600# PP, 250 gals min, 5/10,000 bit wt. sliding 2 hrs 8/24/2001 00:00 - 00:00 24.00 DRILL P PROD2 Directional drill from 6698-8247 with 5/10,000# 1800 # PP 251 gals rain 120 rpms AST 9.75 ART 8, control drlg 180 ft per hr. 8/25/2001 00:00 - 16:00 16.00 DRILL P . PROD2 Directional drill from 8247-9400 TD with 5/10,000# 1800 # PP 1251 gals min 120 rpms AST 2.5 ART 9.25, control drlg 180 ft per hr. 16:00 - 17:00 1.00 DRILL P PROD2 Circ with 66 ps 3500# (Motor failed) jets plug, down to 17 spm 4000# 17:00 - 19:30 2.50 DRILL P PROD2 Pumping out to window 6508, no problems, no overpull, pumping with 25 spm pump press drop to 1000# 19:30 - 23:30 4.00 DRILL P PROD2 Monitor well, tripping out to BHA, wet 23:30 - 00:00 0.50 DRILL P PROD2 Laying down BHA 8/26/2001 00:00 - 01:30 1.50 DRILL P PROD2 Laying down BHA Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 6 of 9 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 8/26/2001 01:30 - 03:00 1.50 DRILL P PROD2 Making up BHA #7--6 1/8 hole opener,foat sub, 4 3/4 dc, 6" stab, 4 3/4 dc, 6" stab, 4 3/4 dc, 3 jts hw, jars 03:00 - 05:30 2.50 DRILL P PROD2 Tripping in w/hole opener to 6428 05:30 - 07:30 2.00 DRILL P PROD2 Slip and cut drilling line 07:30 - 08:00 0.50 DRILL P PROD2 Tripping in to 6654 08:00 - 15:00 7.00 DRILL P PROD2 Reaming hole wih hole opener from 6654 to 9400 0~4,000 on hole opener, 300 gpm, 1600 psi, 120 rpm 5,000 torque 15:00 - 17:00 2.00 DRILL P PROD2 Circ, three bottoms up and spot new mud 17:00 - 19:30 2.50 DRILL P PROD2 Pumping to window @ 6508, no problems, no over pull pumped with 10 spin 150# 19:30 - 20:00 0.50 DRILL P PROD2 monitor well, pump slug 20:00 - 22:00 2.00 DRILL P PROD2 Trip out 22:00 - 23:00 1.00 DRILL P PROD2 Lay down BHA #7 23:00 - 00:00 1.00 DRILL P PROD2 Pick up BHA #8---Whipstock ret. tool, 1 hwdp, MWD, Bumper sub, oil jars, 9 dc 8/27/2001 00:00 - 00:30 0.50 DRILL P PROD2 Finish picking up BHA#8---VVhipstock ret. tool, 1 hwdp, MWD, Bumper sub, oil jars, 9 dc 00:30 - 03:00 2.50 DRILL P PROD2 Tripping in to 6450 03:00 - 04:00 1.00 DRILL P PROD2 Orient tools and lach on to whip stock at 6,511' - pulled free w/ 175,000 - 50,000 over string wt. 04:00 - 04:30 0.50 DRILL P PROD2 Monitor well, pump slug 04:30 - 08:00 3.50 DRILL P PROD2 i Trip out w/whipstock 08:00 - 10:00 2.00 DRILL P PROD2 :lay down BHA, whipstock and stringer 10:00 - 11:00 1.00 CASE P PROD2 Clear floor, rig up casers 11:00 - 14:00 3.00 CASE P PROD2 Picking up 'OA' slotted liner, 70 jts 4.5 slotted 12.6# 1-80 IBT, 2 jts 4.5 blank 12.6# 1-80 IBT, Baker wall hook hangerwith Swivel =14:00 ~ 14:30 0.50 CASE P PROD2 Rig service : 14:30 - 16:30 2.00 CASE P PROD2 Tripping in with liner to 6550, 30' below window, with drill pipe m tension, rotare 1.5 turns to the right & pick up to top of window- RIH set down on 'OB' liner top @ 7,028' - POOH to 20 ft above window- 1 turn to the right- RIH set down @ 7,028' - Pooh to middle of window rotate until rotating torque broke over - TIH, exit window no problem 16:30 - 19:00 2.50 CASE P PROD2 Trip in hole with slotted liner to 9348 Pick up wt 125,000 slack off 80,000 19:00 - 20:00 1.00 CASE P PROD2 Latch wall hook hanger on bottom of window @ 6,520' - latch window by rotating sring in compression 1/4 turn to the right and slacking off - latch window on the seventh attempt, circ the pipe vol. with 40spm 850#-- drop ball pump down with 40 spm shear ball with 3600 #, string wt picking up 115,000# 20:00 - 20:30 0.50 CASE P PROD2 Monitor well, pump slug 20:30 - 00:00 3.50 CASE P PROD2 Trip out, lay down excess drlg pipe 8/28/2001 00:00 - 01:30 1.50 CASE P PROD2 lay down excess drlg pipe 01:30 - 05:00 3.50 CASE P PROD2 Pickup Baker Bridge plug trip into 6454 05:00 - 06:00 1.00 CASE P PROD2 Circ and set bridge plug with 2500# pump pressure @ 6450 06:00 - 06:30 0.50 CASE P PROD2 Attempt to test bridge plug 35 spin 350# would pump away 06:30 - 09:30 3.00 CASE P PROD2 Tripping out with running tool 09:30 - 12:00 2.50 CASE P PROD2 Tripping in with baker plug retrieving tool latch on to plug @ 6450 12:00 - 17:00 5.00 CASE P PROD2 Tripping out with plug (wet retrieving tool pluged with small chunks of rubber and steel shavings) bottom rubber looked new top rubber was in poor shape, had one piece missing Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 7 of 9 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 8/28/2001 12:00 - 17:00 5.00 CASE P PROD2 about 1 in wide and 3 in long rubber was still together should have tested 17:00 - 21:00 4.00 CASE P PROD2 Pick up new baker plug and trip in to 6445 21:00 - 22:30 1.50 CASE P PROD2 Attempt to set plug @ 6445, circ pipe vol., drop ball pressure up to 2500# no set, repressure to 2500# still didn't set, bleeded off pressure, start to pull plug out of the hole, picked up to 6430 and plug was hanging up, pulled 20,000 over string wt. attempt to set plug again with pressure went up to 2500# with no overpull on plug and it shear off and went down hole. should be on hook wall hanger top @ 6498 22:30 - 23:00 0.50 CASE P PROD2 circ bottom up 23:00 - 00:00 1.00 CASE P PROD2 Tripping out for retrieving tool 8/29/2001 00:00 - 02:00 2.00 CASE N DPRB PROD2 Trip out for retrieving tool 02:00 - 05:00 3.00 CASE N DPRB PROD2 Tripping in w/Baker retrieving tool to 6400 05:00 - 05:30 0.50 CASE N DPRB PROD2 Circ bottoms up 50 Spm 750# 05:30 - 06:30 1.00 CASE N DPRB PROD2 Engage Plug @ 6499 the top of hook wall hanger, pull 2 stands fish hung up at 6460, came free 06:30 - 07:00 0.50 CASE N DPRB PROD2 Monitor well, pump Slug 07:00 - 10:30 3.50 CASE N DPRB PROD2 Trip out with Bridge plug, Lay down same 10:30 - 11:30 1.00 CASE N DPRB PROD2 Breaking down plug, Body lock ring was in backward was why this plug didn't set, wait on orders 11:30 - 16:00 4.50 CASE N DPRB PROD2 Mu 7" Baker Lock Set Bridge plug Trip in to 6300 16:00 - 17:00 1.00 CASE N DPRB PROD2 Set bridge plug @ 6300, r/u up to test, pump away 2 bbls min 600#, tested surface lines to 1500# 17:00 - 00:00 7.00 CASE N DPRB PROD2 Tripping out setting and testing csg 65277, 4323,3365 2410, 1080 no test pumping away, pulled to 890 csg tested 2500 # for 10 min. tripping out for tam shifing tool, tam port collar set @ 1011 to 1013 8/30/2001 00:00 - 00:30 0.50 CASE N DPRB PROD2 Clean rig floor. 00:30 - 01:30 1.00 CASE N DPRB PROD2 Make up Tam combo tool and run in hole to 1011'. 01:30 - 02:00 0.50 CASE N DPRB PROD2 Latched into Tam Port Collar. Pressure tested collar and was able to establish injection at 3 bbl/min at 300 psi. Shifted collar 3-3~4" (full stroke is 7") to close tool. Pressure tested collar to 1100 psi for 10 minutes. Good test. 02:00 - 03:00 1.00 CASE N DPRB PROD2 Pulled out of hole and laid down Tam combo tool. 03:00 - 07:30 4.50 CASE N DPRB PROD2 Made up Baker 7" bridge plug and ran in hole with 3-1/2" drill pipe to 6400'. 07:30 - 08:00 0.50 CASE N DPRB PROD2 Circulated drill pipe volume. 08:00 - 09:00 1.00 CASE N DPRB PROD2 Dropped setting ball and pumped down and set bridge plug at 6400'. Sheared off setting tool. Pulled 30' and pressure tested plug and casing to 2500 psi for 30 minutes. Good test. 09:00 - 09:30 0.50 CASE P PROD2 Dropped ball and rod to open circulating sub and pumped down hole and opened circ sub. 09:30 - 11:00 1.50 CASE P PROD2 Flushed all lines with seawater. Displaced hole with 300 bbls of seawater at 6 bpm at 1200 psi. Rotated 50 RPM and = Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 8 of 9 Operations Summary Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 8/30/2001 09:30 - 11:00 1.50 CASE P PROD2 reciprocated pipe during displacement. Displace seawater in hole with 250 bbls of 9.2 ppg KCL at 6 bpm at 1200 psi. 11:00 - 17:00 6.00 CASE P PROD2 Laying down 3.5 pipe 17:00- 17:30 0.50 CASE P PROD2 Clearfloor 17:30 - 18:00 0.50 CASE P PROD2 Service rig 18:00 - 20:00 2.00 CASE P PROD2 Slip and cut drilling line 20:00 - 20:30 0.50 CASE P PROD2 Pull wear ring 20:30 - 00:00 3.50 CASE P PROD2 Rig up, and picking up Baker bridge plug retieving tool and 2 7/8 6.5 1-80 Eue 8rd tubing 9/1/2001 00:00 - 01:30 1.50 CASE X DPRB PROD2 Wait on brine. 01:30 - 02:00 0.50 CASE X DPRB PROD2 Take on 9.5 ppg brine and cut to 9.2ppg. 02:00 - 03:30 1.50 CASE X DPRB PROD2 Displace diesel with 9.2ppg brine. Total displacement 32bbl. Set two way check valve and test to 1000psi. 03:30 - 09:30 6.00 CASE X DPRB PROD2 ND tree and NU BOP. Change BOP bottom rams to 3 1/2". 09:30 - 12:00 2.50 CASE X DPRB PROD2 Wait on 2 7~8" rams. 12:00 - 14:30 2.50 CASE X DPRB PROD2 change rams to 2 7/8 in top 14:30 - 20:00 5.50 CASE X DPRB PROD2 Test Bops to 250-3500 repair one leak in coke manifold replace seal ring 20:00 - 21:30 1.50 CASE X DPRB PROD2 Pull two way check and pull hanger 21:30 - 22:30 1.00 CASE X DPRB PROD2 Circ Bottoms up with 500# 4bbls min, lost 2.5 bbls into cellar tru leak in csg. 22:30 - 23:00 0.50 CASE X DPRB PROD2 Monitor well, pump slug 23:00 - 00:00 1.00 CASE X DPRB PROD2 laying down 2 7/8 tubing 9/2/2001 00:00 - 06:30 6.50 CASE X DPRB PROD2 POH. LD 2 7~8" tubing. 06:30 - 07:00 0.50 CASE X DPRB PROD2 Clear rig floor 07:00 - 08:30 1.50 CASE X DPRB PROD2 Hold PJSM on testing. RU test equipment and test bottom 3 1/2" pipe rams. RD testing equipment. 08:30 - 09:00 0.50 CASE X DPRB PROD2 Land wear bushing. 09:00 - 12:00 3.00 CASE X DPRB PROD2 PU TAM Port Collar combo tool. PU 3 1/2" DP to 1012'. Sting tool into port collar and RU to circulate. 12:00 - 14:00 2.00 CASE X DPRB PROD2 Closed port collar. Pressure tested collar to 1000 psi. Good test. Slacked off and opened port collar. Established injection rate 1 bpm at 240 psi, 1.5 bpm at 320 psi and 2 bpm at 340 psi. Pumped a total of 21 bbls of 9.2 brine. Had partial returns to cellar. Closed port collar and retested collar to 1000 psi. Slacked of and opened port collar. Established injection at 1 bpm at 240 psi, 1.5 bpm at 275 psi and 2 bpm at 310 psi. Returns stopped in cellar with an additional 20 bbls of 9.2 ppg brine pumped. Decided not to pump lead slurry since returns had been lost. 14:00 - 15:30 1.50 CASE X DPRB . PROD2 Held PJSM. Pumped 2 bbls water and tested lines to 2000 psi. Pumped additional 3 bbls of water. Followed water with 16.8 bbls of Class C cement weighted to 15.8 ppg. Displaced cement with fresh water and left one bbl of cement in drill pipe. Closed tool and pessure tested collar to 1000 psi. Bleed off 3ressure and released Tam combo tool from Tam port collar. Pulled above port collar. 15:30 - 16:30 1.00 CASE X DPRB PROD2 Pressured up to 2200 psi and sheared Tam combo tool. Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 9 of 9 Operations Summa Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: DRILL+COMPLETE Start: 8/6/2001 End: 9/3/2001 Contractor Name: NABORS Rig Release: 9/3/2001 Rig Name: Nabors 27E Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 9/2/2001 15:30 - 16:30 1.00 CASE X DPRB PROD2 Circulated hole clean. Did not see any cement to surface. Pressure tested casing string to 1000 psi for 5 minutes. Good test. 16:30 - 17:30 1.00 CASE X DPRB PROD2 Pulled out of hole laying down 3-1/2" drill pipe and Tam combo tool. 17:30 - 18:30 1.00 CASE PROD2 Pull wear ring, rig to run tubing 18:30 - 00:00 5.50 CASE X DPRB PROD2 Pick up baker retieving tool and 201 jts of 2 7/8 tubing total tally 6330 Pu 27,000 So 16,000 (no block wt.) 9/3/2001 00:00 - 02:00 2.00 CASE X DPRB PROD2 Land hangar. Test two way check valve to 1000psi. Test annulus to 1000psi. 02:00 - 02:30 0.50 CASE X DPRB PROD2 Clear rig floor of tubing equipment. 02:30 - 04:00 1.50 CASE X DPRB PROD2 Change top and bottom BOP rams to 4". 04:00 - 05:00 1.00 CASE X DPRB PROD2 ND BOP stack. 05:00 - 06:30 1.50 CASE X DPRB PROD2 NU Tree. 06:30 - 07:30 1.00 CASE X DPRB PROD2 Test hangar void and tree to 5000psi. 07:30 - 08:00 0.50 CASE X DPRB PROD2 RU lubricator and pull two way check valve. 08:00 - 11:30 3.50 CASE X DPRB I PROD2 RU HB&R test line and pump 80bbl diesel. Suck back 3bbl and allow to u-tube. 11:30 - 12:00 0.50 CASE P PROD2 Set back pressure valve. Release rig at 1200hrs. Printed: 9/24/2001 4:58:07 PM BP EXPLORATION Page 1 of 1 Operations Summa Report Legal Well Name: MPG-14 Common Well Name: MPG-14 Spud Date: 8/9/2001 Event Name: COMPLETION Start: 9/16/2001 End: 9/20/2001 Contractor Name: NABORS Rig Release: 9/20/2001 Rig Name: NABORS 4ES Rig Number: 4ES Date From - To Hours Activity Code NPT Phase Description of Operations 9/16/2001 17:00 - 23:00 6.00 RIGU COMP MIRU. RAISE & SCOPE DERRICK. SPOT ,BERM & RU TIGER TANK. ACCEPTED RIG @ 23:00 HRS. 23:00 - 00:00 1.00 REST COMP R/U TO CIRC. SEAWATER & DIESEL FROM WELLBORE. 9/17/2001 00:00 - 00:30 0.50 REST COMP RU TO CIRC. SEAWATER & DIESEL FROM WELLBORE. 00:30 - 01:00 0.50 REST COMP PULL BPV. 01:00 - 02:30 1.50 REST COMP CIRC. SEAWATER & DIESEL FROM WELLBORE W/9.2 BRINE. 02:30 - 04:00 1.50 REST COMP SET & TEST TWC. ND TREE. 04:00 - 06:00 2.00 REST COMP NU BOPE. 06:00 - 06:30 0.50 REST COMP SERVICE RIG. 06:30 - 10:30 4.00 REST COMP NU BOPE. 10:30 - 14:00 3.50 REST COMP PRESS. TEST BOPE 250/2500 PER BP/AOGCC REGS. WITNESSING WAIVERED BY CHUCK SCHEVE @ 3:00AM 9-17-01. 14:00 - 15:30 1.50 REST COMP PULL TWC. PU LANDING JT. MU HANGER. BOLDS. PULL HANGER TO FLOOR. L/D HANGER. PU WT. 37K. SO WT. 25K. 15:30 - 17:30 2.00 REST COMP RIH TO 6428'. LATCH & RELEASE BP. CIRC. MONITOR WELL. 20 PSI ON TBG. 40 PSI ON CSG. 17:30 - 19:30 2.00 REST COMP CIRC. & WT. UP BRINE TO 9.4. MONITOR WELL. 19:30 - 23:00 3.50 REST COMP POOH W/2 7/8" TBG. & BP. 23:00 - 23:30 0.50 REST COMP OOH. L/D BP. CLEAR FLOOR. 23:30 - 00:00 0.50 REST COMP RU SWS TO PERF. "N" SAND. 9/18/2001 00:00 - 07:30 7.50 REST COMP PERF. "N" SAND. 6250'-6270.6190'-6210'. 6110'-6130'. 3 3/8" PJ 6 SPF 60 DEGREE PHASING. ALL SHOTS FIRE. RD SWS. 07:30 - 08:00 0.50 REST COMP SERVICE RIG. 08:00 - 09:00 1.00 REST COMP MU BAKER 7' SLZXP PACKER W/XN NIPPLE & RE ENTRY GUIDE. 09:00 - 16:00 7.00 REST COMP PU 3 1/2" DP & TIH. 16:00 - 16:30 0.50 REST COMP SET BAKER 7" SLZXP PACKER @ 6,286'. RKBM. 16:30 - 19:30 3.00 REST COMP POOH W/3 1/2" DP. 19:30 - 20:30 1.00 REST COMP LD SETTING TOOLS. CLEAR FLOOR. 20:30 - 22:30 2.00 REST COMP MU HALCO SCREEN ASSM & PACKER. 22:30 - 00:00 1.50 REST COMP RIH W/HALCO PACKER & SCREEN ASSM. ON 3 1/2" DP. 9/19/2001 00:00 - 02:30 2.50 REST COMP CONT. RIH W/HALCO PACKER & SCREEN ASSM. 02:30 - 03:30 1.00 REST COMP STING IN & SPACE OUT. SET PACKER. TEST PACKER TO 2500 PSI. PU WT. 67K. SO WT. 54K. 03:30 - 06:00 2.50 REST COMP POOH LD 3 1/2" DP. 06:00 - 06:30 0.50 REST COMP SERVICE RIG. 06:30 - 09:00 2.50 REST COMP CONT. POOH LD 3 1/2" DP. 09:00 - 11:00 2.00 REST COMP LD HLCO SETTING TOOL & 18 JTS. 2 7/8" TBG. 11:00 - 12:30 1.50 REST COMP CLEAR FLOOR. RU TO RUN ESP. 12:30 - 16:00 3.50 REST COMP PU PUMP & MOTOR. SERVICE & TEST. 16:00 - 20:00 4.00 REST COMP RIH W/2 7/8" TBG. & ESP. 20:00 - 23:00 3.00 REST COMP MU HANGER & LANDING JT. INSTALL PENETRATOR. SPLICE EFT & TEST. LAND HANGER.RILDS. PU WT. 45K. SO WT. 32K. SET & TEST TVVC. 23:00 - 00:00 1.00 REST COMP ND BOPE. 9/20/2001 00:00 - 01:00 1.00 REST COMP NIPPLE DOWN BOP 01:00 - 02:30 1.50 REST COMP NIPPLE UP TREE & TEST SAME. 02:30 - 04:00 1.50 REST COMP PULL TWC & INSTALL BPV & SECURE WELL HEAD & CELLAR AREA (RIG RELEASED @ 0400 HRS. 9/20/2001 Printed: 9/24/2001 4:58:49 PM ANADRILL SCHLUMBERGER Survey report Client ................... : BP Exploration (Alaska), Inc. Field .................... : Milne Point Well ..................... : MPG-14 API number ............... : 50-029-23031-00 Engineer ................. : R.Harmer COUNTY: .................. : Nabors 27E STATE: ................... : Alaska Survey calculation methods Method for positions ..... : Minimum curvature Method for DLS ........... : Mason & Taylor Depth reference Permanent datum .......... : MEAN SEA LEVEL Depth reference .......... : Drill Floor GL above permanent ....... : 29.50 ft KB above permanent ....... : -999.25 ft DF above permanent ....... : 62.93 ft Vertical section origin Latitude (+N/S-) ......... : Departure (+E/W-) ........ : 0.00 ft 0.00 ft Platform reference point ............... Latitude (+N/S-) ......... : -999.25 ft Departure (+E/W-) ........ : -999.25 ft Azimuth from rotary table to target: 331.32 degrees 22-Aug-2001 09:31:51 Page 1 of 5 Spud date ................ : 09-Aug-01 Last survey date ......... : 20-Aug-01 Total accepted surveys...: 113 MD of first survey ....... : 0.00 ft MD of last survey ........ : 9405.00 ft Geomagnetic data Magnetic model ........... : BGGM version 2000 Magnetic date ............ : 06-Aug-2001 Magnetic field strength..: 1148.91 HCNT Magnetic dec (+E/W-) ..... : 26.21 degrees Magnetic dip ............. : 80.79 degrees MWD survey Reference Criteria Reference G .............. : 1002 69 mGal Reference H .............. : 1148 91 HCNT Reference Dip ............ : 80 79 degrees Tolerance of G ........... : (+/-) 2 50 mGal Tolerance of H ........... : (+/-) 6 00 HCNT Tolerance of Dip ......... : (+/-) 0 45 degrees Corrections Magnetic dec (+E/W-) ..... : 26.22 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-) .... : 26.22 degrees (Total az corr = magnetic dec - grid cony) Sag applied (Y/N) ........ : No degree: 0.00 [ (c)2001 Amadrill IDEAL ID6 lC 10] ANADRILL SCHLUMBERGER Survey Report Seq Measured Incl Azimuth Course # depth angle angle length - (ft) (deg) (deg) (ft) 1 0.00 0.00 0.00 2 113.54 0.30 255.15 3 199.15 0.61 228.26 4 295.07 1.11 285.11 5 383.93 2.62 308.41 0.00 113.54 85.61 95.92 88.86 6 475.91 4.05 309.07 7 565.27 4.86 307.52 8 654.39 5.85 308.09 9 745.34 7.29 302.45 10 837.47 9.33 300.98 91.98 89.36 89.12 90.95 92.13 11 931.51 11.38 304.29 12 1023.61 13.64 305.26 13 1119.18 16.09 304.64 14 1212.56 18.90 305.48 15 1306.25 21.01 303.77 94.04 92.10 95.57 93.38 93.69 16 1400.84 23.72 303.72 94.59 17 1496.30 25.29 305.98 95.46 18 1587.90 27.29 305.07 91.60 19 1683.18 29.02 304.41 95.28 20 1776.01 31.43 302.92 92.83 22-Aug-2001 09:31:51 TVD Vertical Displ Displ Total depth section +N/S- +E/W- displ (ft) (ft) (ft) (ft) (ft) 0.00 0.00 0.00 113.54 0.07 -0.08 199.15 0.02 -0.44 295.06 0.55 -0.53 383.87 3.02 0.95 475.69 7.96 4.30 564.78 14.34 8.60 653.51 21.97 13.70 743.86 31.28 19.66 835.02 42.85 26.64 927.52 57.69 35.79 1017.43 75.55 47.18 1109.80 97.51 61.21 1198.85 122.68 77.35 1286.91 151.24 95.50 1374.37 183.14 115.49 1461.24 218.58 138.13 1543.36 255.10 161.69 1627.36 295.30 187.30 1707.56 336.68 213.19 21 1869.22 33.77 301.80 93.21 1786.09 22 1964.67 33.73 301.70 95.45 1865.45 23 2059.72 36.09 299.93 95.05 1943.39 24 2152.25 39.54 300.97 92.53 2016.48 25 2242.56 42.82 301.62 90.31 2084.44 26 2339.84 45.89 303.50 27 2434.94 49.99 305.10 28 2529.15 53.15 305.88 29 2622.35 55.87 306.58 30 2716.28 58.36 306.28 380.61 240.05 426.73 267.95 473.58 295.79 522.27 324.55 573.75 355.45 97.28 95.10 94.21 93.20 93.93 2153.99 633.37 392.07 2217.69 696.27 431.87 2276.24 762.69 474.72 2330.34 831.42 519.57 2381.34 902.96 566.41 0.00 -0.29 -0.84 -2.12 -4.54 -8.71 -14.17 -20.74 -29.25 -40.59 -54.79 -71.17 -91.27 -114.24 -140.56 -170.48 -202.96 -235.98 -272.93 -311.83 -354.25 -399.34 -446.06 -494.95 -545.75 -603.04 -661.33 -721.41 -782.61 -846.07 Page At Azim (deg) 0.00 0.30 0.95 2.19 4.64 9 16 24 35 48 65 85 109 137 169 205 245 286 331 377 427 480 535 591 651 719 789 863 939 1018 .72 .57 .85 .24 .55 .44 .39 .90 .96 .93 .92 .50 .06 .01 .73 .92 .91 .23 .87 .29 .29 .86 .59 .38 .16 0.00 255.15 242.63 255.86 281.83 296.29 301.26 303.45 303.90 303.28 303.15 303.54 303.85 304.10 304.19 304.11 304.24 304.42 304.46 304.36 304.12 303.86 303.55 303.25 303.08 303.03 303.15 303.35 303.58 303.80 2 of 5 DLS (deg/ I00f) 0.00 0.26 0.43 0.97 1.87 1.56 0.92 1.11 1.73 2.23 2.27 2.46 2.57 3.02 2.34 2.87 1.92 2.23 1.84 2.72 2.59 0.07 2.70 3.79 3.66 3.43 4.49 3.42 2.98 2.66 Srvy tool type TIP IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR Tool qual type [(c)2001 Anadrill IDEAL ID6 lC 10] ANADRILL SCHLUMBERGER Survey Report 22-Aug-2001 09:31:51 Page 3 of 5 Seq Measured Incl Azimuth Course # depth angle angle length - (ft) (deg) (deg) (ft) TVD depth (ft) Vertical Displ Displ Total At section +N/S- +E/W- displ Azim (ft) (ft) (ft) (ft) (deg) 31 2808.59 60.24 305.09 92.31 2428.47 974.51 612.70 -910.54 32 2904.21 60.98 304.95 95.62 2475.39 1049.20 660.51 -978.77 33 3001.87 60.77 305.38 97.66 2522.93 1125.78 709.64 -1048.51 34 3095.69 62.13 305.38 93.82 2567.76 1199.88 757.36 -1115.70 35 3185.88 62.07 306.06 90.19 2609.97 1271.77 803.89 -1180.42 1097.49 1180.79 1266.08 1348.47 1428.15 303.94 304.01 304.09 304.17 304.26 36 3280.79 62.08 305.95 37 3376.82 62.77 306.50 38 3472.68 63.01 306.64 39 3565.34 63.29 304.92 40 3658.73 62.58 304.47 94.91 2654.41 1347.57 853.19 -1248.26 1511.98 304.35 96.03 2698.87 1424.66 903.49 -1316.92 1597.05 304.45 95.86 2742.55 1502.15 954.33 -1385.45 1682.33 304.56 92.66 2784.40 1576.74 1002.66 -1452.52 1764.97 304.62 93.39 2826.90 1651.08 1050.00 -1520.89 1848.14 304.62 41 3752.23 61.10 303.34 42 3844.56 60.93 303.11 43 3936.43 61.26 303.14 44 4031.23 61.61 302.07 45 4125.69 60.39 301.10 93.50 92.33 91.87 94.80 94.46 2871.02 2915.76 2960.17 3005.50 3051.30 46 4219.41 59.66 300.30 93.72 3098.12 47 4310.05 60.22 300.39 90.64 3143.52 48 4403.92 60.06 300.86 93.87 3190.26 49 4498.62 60.31 300.61 94.70 3237.34 50 4594.71 60.81 301.10 96.09 3284.57 51 4688.47 60.51 301.03 93.76 3330.51 52 4778.62 60.48 300.92 90.15 3374.91 53 4873.73 60.88 300.71 95.11 3421.49 54 4964.90 61.38 301.28 91.17 3465.51 55 5059.29 61.32 302.29 94.39 3510.76 56 5154.91 61.75 302.73 57 5249.57 61.69 302.91 58 5342.17 61.85 303.21 59 5434.90 62.18 303.24 60 5530.13 62.26 305.05 1724 25 1795.50 1866 38 1939.40 2011 14 2081 01 2148.27 2218 27 2289.00 2361 13 2431.73 2499.44 2570.89 2639.80 2711.87 2785.53 2858.79 2930.65 3002.89 3077.84 1095.98 1140.24 1184.19 1229.05 1272.32 1313.77 1353.40 1394.87 1436.87 1479.78 1521.96 1562.34 1604.82 1645.93 1689.56 1734.74 1779.92 1824.43 1869.30 1916.59 -1589.30 -1656.86 -1724.22 -1794.35 -1864.73 -1934.53 -2002.23 -2072.29 -2142.91 -2214.75 -2284.76 -2352.03 -2423.25 -2491.69 -2562.10 -2632.98 -2703.04 -2771.41 -2839.92 -2909.64 95.62 94.66 92.60 92.73 95.23 3556.34 3601.19 3644.99 3688.50 3732.89 1930.56 2011.30 2091.70 2174.92 2257.44 304.59 304.54 304.48 304.41 304.31 2338.46 2416.74 2498.01 2580.05 2663.62 304.18 304.06 303.94 303.84 303.75 2745.27 2823.64 2906.47 2986.23 3069.03 303.67 303.59 303.51 303.45 303.40 3153.08 3236.44 3318.02 3399.91 3484.15 303.38 303.36 303.36 303.35 303.37 DLS (deg/ I00f) 2.32 0.78 0.44 1.45 0.67 0.10 0.88 0.28 1.68 0.87 1.91 0.29 0.36 1.06 1.57 1.07 0.62 0.47 0.35 0.68 0.33 0.11 0.46 0.77 0.94 0.60 0.18 0.33 0.36 1.68 Srvy tool type IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR Tool qual type [(c)2001 /knadrill IDEAL ID6 lC 10] -- -- ANADRILL SCHLUMBERGER Survey Report Seq Measured Incl Azimuth Course # depth angle angle length - (ft) (deg) (deg) (ft) 22-Aug-2001 09:31:51 Page 4 of 5 TVD Vertical Displ Displ Total At DLS Srvy Tool depth section +N/S - +E/W- displ Azim (deg/ tool qual (ft) (ft) (ft) (ft) (ft) (deg) I00f) type type 61 5623.32 62.62 306.21 93.19 3776.00 62 5717.89 63.07 308.84 94.57 3819.17 63 5812.05 63.50 312.68 94.16 3861.51 64 5908.24 64.22 316.50 96.19 3903.91 65 6002.59 65.20 319.56 94.35 3944.22 66 6095.75 66.12 323.90 93.16 3982.63 67 6187.71 66.14 327.85 91.96 4019.85 68 6279.47 67.26 330.40 91.76 4056.15 69 6372.21 69.77 334.12 92.74 4090.13 70 6468.59 72.19 338.42 96.38 4121.55 71 6526.98 75.72 340.02 72 6564.00 77.60 340.23 73 6598.82 80.56 341.34 74 6629.52 83.53 341.74 75 6657.42 85.74 343.06 4137.69 4146.23 4152.82 4157.07 4159.68 4161.91 4163.92 4166.31 4169.55 4173.39 58.39 37.02 34.82 30.70 27.90 76 6690.67 86.57 345.64 77 6721.64 86.00 348.50 78 6752.78 85.20 351.20 79 6784.64 83.13 352.84 80 6815.19 82.41 354.78 33.25 30.97 31.14 31.86 30.55 81 6846.58 82.13 354.87 31.39 4177.61 82 6879.12 82.27 356.33 32.54 4182.03 83 6908.91 83.02 359.14 29.79 4185.84 84 6940.15 84.45 0.41 31.24 4189.25 85 6973.12 84.68 359.70 32.97 4192.38 31.44 31.60 20.03 162.46 94.91 3152.28 3229.27 3308.00 3390.68 3473.69 3557.36 3641.05 3725.25 3811.51 3902.26 3957.83 3993.42 4027.14 4057.06 4084.32 4116.64 4146.38 4175.81 4205.46 4233.46 4261.98 4291.37 4317.83 4345.13 4373.91 4401.26 4428.49 4445.74 4583.00 4659.30 1964.71 -2976.79 2015.96 -3043.51 2070.87 -3107.20 2131.48 -3168.67 2194.90 -3225.71 2261.52 -3278.25 2331.12 -3325.41 2403.45 -3368.65 2479.82 -3408.78 2563.21 -3445.42 2615.67 -3465.31 2649.54 -3477.56 2681.82 -3488.81 2710.66 -3498.44 2737.14 -3506.83 2769.08 -3515.78 2799.20 -3522.70 2829.75 -3528.17 2861.14 -3532.57 2891.27 -3535.84 2922.25 -3538.64 2954.39 -3541.11 2983.91 -3542.28 3014.96 -3542.40 3047.78 -3542.37 3079.09 -3542.14 3110.57 -3541.32 3130.54 -3540.76 3292.40 -3530.90 3386.36 -3518.11 86 7004.56 84.83 1.16 87 7036.16 85.83 1.82 88 7056.19 85.97 1.40 89 7218.65 87.50 5.57 90 7313.56 88.56 9.93 3566.70 3650.63 3734.06 3818.86 3901.64 303.43 303.52 303.68 303.93 304.23 3982.64 4061.10 4138.16 4215.36 4294.29 304.60 305.03 305.51 306.04 306.65 4341.67 4371.90 4400.45 4425.69 4448.57 307.05 307.30 307.55 307.77 307.97 4475.32 4499.43 4522.77 4545.90 4567.45 308.22 308.47 308.73 309.01 309.27 4589.28 4611.71 4631.57 4651.73 4673.05 309.55 309.84 310.11 310.40 310.71 4693.35 4713.45 4726.23 4827.74 4883.08 311.00 311.30 311.48 313.00 313.91 4195.25 4197.82 4199.26 4208.51 4211.78 1.17 2.52 3.67 3.64 3.11 4.36 3.93 2.83 4.61 4.91 6.59 5.11 9.06 9.76 9.22 8.13 9.40 9.02 8.27 6.73 0.94 4.47 9.69 6.11 2.25 4.65 3.79 2.21 2.73 4.72 IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR [ (c)2001 Anadrill IDEAL ID6 lC 10] ANADRILL SCHLUMBERGER Survey Report Seq Measured Incl Azimuth Course # depth angle angle length - (ft) (deg) (deg) (ft) 22-Aug-2001 09:31:51 Page 5 of 5 TVD Vertical Displ Displ Total At DLS Srvy Tool depth section +N/S- +E/W- displ Azim (deg/ tool qual (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type 91 7409.35 88.18 16.04 95.79 4214.50 92 7503.54 88.94 20.88 94.19 4216.87 93 7599.50 91.13 18.79 95.96 4216.81 94 7695.91 91.37 20.11 96.41 4214.71 95 7791.69 90.07 20.87 95.78 4213.51 4730.80 4794.83 4858.39 4922.73 4985.35 96 7885.31 89.21 22.26 93.62 4214.10 5045 97 7981.93 90.14 21.43 96.62 4214.64 5106 98 8076.15 90.44 18.57 94.22 4214.17 5168 99 8169.92 87.19 13.77 93.77 4216.11 5235 100 8268.10 90.24 13.89 98.18 4218.31 5307 101 8364.71 88.56 14.78 96.61 4219.32 5378 102 8460.05 88.80 14.40 95.34 4221.52 5447 103 8555.51 90.99 16.44 95.46 4221.69 5516 104 8651.84 89.79 13.49 96.33 4221.03 5585 105 8744.82 91.64 14.52 92.98 4219.87 5654 106 8841.34 90.41 14.34 96.52 4218.15 107 8937.13 91.16 15.04 95.79 4216.84 108 9032.14 89.04 15.10 95.01 4216.67 109 9128.91 90.51 13.89 96.77 4217.05 110 9221.04 91.85 15.15 92.13 4215.15 111 9316.45 91.34 15.87 95.41 4212.50 112 9347.74 91.61 16.09 31.29 4211.69 3479.62 -3496.60 3568.91 -3466.80 3659.17 -3434.25 3750.05 -3402.16 3839.77 -3368.64 .21 .64 .84 .27 .62 3926.83 -3334.23 4016.51 -3298.28 4105.03 -3266.06 4195.04 -3239.96 4290.33 -3216.50 .25 .65 .20 .90 .24 4383.93 -3192.58 4476.17 -3168.57 4568.18 -3143.19 4661.23 -3118.32 4751.43 -3095.82 5724.69 5794.31 5862.94 5933.51 6000.65 4844.89 -3071.77 4937.54 -3047.48 5029.28 -3022.78 5122.96 -2998.56 5212.13 -2975.47 6069.04 5304.03 -2949.97 6091.28 5334.10 -2941.35 6131.92 5389.09 -2925.49 Final Survey Projected to total depth: 113 9405.00 91.61 16.09 57.26 4932.95 314.86 6.39 4975.52 315.83 5.20 5018.32 316.82 3.16 5063.36 317.78 1.40 5107.98 318.74 1.57 5151.41 319.67 5197.21 320.61 5245.80 321.49 5300.53 322.32 5362.16 323.14 5423.23 323.94 5484.15 324.71 5545.08 325.47 5608.12 326.22 5671.00 326.91 5736.62 327.62 5802.28 328.32 5867.78 328.99 5936.00 329.66 6001.64 330.28 1.75 1.29 3.05 6.18 3.11 1.97 0.47 3.14 3.31 2.28 4210.08 1.29 1.07 2.23 1.97 2.00 6069.18 330.92 0.92 6091.32 331.13 1.11 IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR IFR 6131.95 331.50 0.00 proj [(c)2001 Anadrill IDEAL ID6 lC 10] A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 MEASURED I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. 5050.0 61.27 301.44 5100.0 61.28 302.14 5150.0 61.43 302.30 VERTICAL SUBSEA VERTICAL DEPTH DEPTH SECTION feet feet feet 5200.0 61.62 302.42 5250.0 61.56 302.48 5300.0 61.91 302.58 5350.0 61.67 302.49 5400.0 62.10 302.73 1.40 3508.7 3445.7 2695.8 1.22 3532.7 3469.8 2733.9 0.41 3556.7 3493.8 2772.3 5450.0 61.98 302.82 5500.0 62.21 302.97 5550.0 62.25 305.10 5600.0 62.47 305.79 5650.0 63.00 306.11 0.44 3580.5 3517.6 2810.7 0.16 3604.3 3541.4 2849.3 0.73 3628.0 3565.1 2887.8 0.51 3651.6 3588.7 2926.5 0.96 3675.2 3612.3 2965.1 5700.0 63.04 306.96 5750.0 63.26 309.63 5800.0 63.23 311.05 5850.0 63.51 313.48 5900.0 63.85 315.11 CLOSURE DIST. AZIMUTH feet deg. 5950.0 64.46 317.36 6000.0 64.84 318.43 6050.0 66.15 322.18 6100.0 66.35 323.39 6150.0 65.94 324.80 3060.2 303.1 3104.1 303.1 3147.9 303.0 6200.0 66.37 327.26 3191.9 303.0 3235.9 303.0 3279.9 303.0 3324.0 303.0 3368.1 303.0 0.27 3698.6 3635.7 3003.9 3412.2 303.0 0.53 3722.0 3659.1 3042.8 3456.4 303.0 3.76 3745.3 3682.4 3082.1 3500.6 303.0 1.31 3768.5 3705.6 3122.0 3544.9 303.0 1.21 3791.4 3728.5 3162.1 3589.3 303.1 1.51 3814.1 3751.2 3202.6' 4.78 3836.7 3773.8 3243.6 2.53 3859.2 3796.3 3285.3 4.38 3881.6 3818.7 3327.6 3.00 3903.8 3840.9 3370.4 4.24 3925.6 3862.7 3413.9 2.08 3947.0 3884.1 3457.8 7.30 3967.7 3904.8 3502.5 2.25 3987.9 3924.9 3547.7' 2.72 4008.1 3945.2 3593.1 '3633.8 303.1 3678.2 303.2 3722.5 303.3 3766.6 303.4 3810.7 303.5 3854.6 303.7 3898.4 3O3.8 3942.0 304.0 3985.4 304.2 4028.4 304.4 4.58 4028.3 3965.4 3638.6 4071.0 304.7 HORIZONTAL COORDINATES feet 1669.97 N 1693.07 N 1716.47 N 1739.99 N 1763.59 N 1787.27 N 1810.96 N 1834.73 N 1858.64 N 1882.64 N 1907.40 N 1933.08 N 1959.18 N 1985.71N 2013.35 N 2042.25 N 2072.30 N 2103.60 N 2136.10 N 2169.62 N 2204.63 N 2241.07 N 2278.11N 2316.03 N 2564.42W 2601.69W 2638.81W 2675.93W 2713.04W 2750.17W 2787.32W 2824.47W 2861.60W 2898.70W 2935.36W 2971.45W 3007.42W 3043.22W 3078.23W 3112.26W 3145.34W 3177.42W 3208.54W 3238.83W 3267.88W 3295.56W 3322.38W 3347.93W A Gyrodata Directional Survey B.P. Exploration Well: MPG-14, 3.5" DP Location: G PAD, MILNE POINT FIELD, AK Job Number: AK0801GCE519 MEASURED I N C L AZIMUTH DOGLEG DEPTH SEVERITY feet deg. deg. deg./ 100 ft. VERTICAL SUBSEA VERTICAL DEPTH DEPTH SECTION feet feet feet CLOSURE DIST. AZIMUTH feet deg. 6250.0 66.84 328.57 2.57 6300.0 67.75 330.85 4.59 6350.0 69.27 332.93 4.91 6400.0 70.54 335.80 5.96 4048.2 3985.2 3684.4 4067.5 4004.5 3730.5 4085.8 4022.8 3777.0 4103.0 4040.0 3823.9 4113.2 304.9 4155.1 305.2 4196.7 3O5.5 4237.9 305.8 6450.0 72.04 337.86 4.93 6500.0 74.00 339.24 4.72 6550.0 76.48 340.08 5.22 6600.0 79.99 341.12 7.32 6650.0 84.83 342.21 9.91 4119.0 4056.1 3871.1 4133.6 4070.7 3918.5 4146.3 4083.4 3966.3 4156.5 4093.6 4014.6 4163.1 4100.2 4063.4 4278.5 306.1 4318.9 306.5 4359.5 306.8 4400.2 307.2 4441.1 307.5 6700.0 86.67 345.20 7.01 6750.0 85.14 349.36 8.84 6800.0 83.37 352.79 7.69 6850.0 81.90 354.30 4.19 6900.0 82.81 357.41 6.43 4166.8 4103.9 4112.1 4170.4 4107.5 4160.0 4175.4 4112.5 4206.8 4181.8 4118.9 4252.7 4188.5 4125.6 4297.8 4481.5 307.9 4520.1 308.3 4556.7 308.7 4592.0 309.2 4626.2 309.6 6950.0 84.66 0.24 6.75 7000.0 84.60 0.90 1.32 4193.9 4131.0 4341.9 4198.6 4135.7 4385.3 4658.8 310.1 4690.6 310.5 Final Station Closure: Distance: 4690.58 ft Az: 310.53 deg. HORIZONTAL COORDINATES feet 2354.91N 2394.74 N 2435.77 N 2478.10 N 2521.63 N 2566.14 N 2611.47 N 2657.63 N 2704.67 N 2752.52 N 2801.15 N 2850.29 N 2899.56 N 2948.98 N 2998.66 N 3048.44 N 3372.31W 3395.57W 3417.48W 3437.79W 3456.42W 3473.90W 3490.71W 3506.96W 3522.54W 3536.53W 3547.51W 3555.23W 3560.80W 3564.39W 3565.40W 3564.91W bp Date: 09-17-2001 Transmittal Number:9224~..~ BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. Top SW Name Date Contractor Log Run Depth Bottom Depth Log Type MPG-14 08-22-2001 ANADRILL 1 0 9405 MWD SURVEY; MPG-14L1 08-27-2001 ANADRILL 1 0 9400 MWD SURVEY; "'Pt~se-~ign and Retur~ one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center Attn: Lisa Weepie (AOGCC) RECEIVED SEP ?_ 1 7.001 Alaska Oil & Gas Cons. C, ommts~r; Anchorage Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 ALASKA OIL AND GAS CONSERVATION COPlMISSION TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Pat Archey Senior Drilling Engineer BP Exploration (Alaska) PO Box 196612 Anchorage AK 99519-6612 Re: Milne Pint Unit MPG- 14 BP Exploration (Alaska) Permit No: 201-133 Sur Loc: 2015' NSL, 3446' WEL, SEC. 27, T13N, R10E, UM Btmhole Loc. 2111' NSL, 1097, WEL, SEC. 21, T13N, R10E, UM Dear Mr Archey: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Annular disposal has not been requested as part of the Permit to Drill application for Milne Pint Unit MPG-14. -- Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given ' by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, Julie M. Heusser CommiSsioner BY ORDER OF THE COMMISSION DATED this ~'] ~ day of July, 2001 jjc/Enclosures CC: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ' ALAS ILAND GAS CONSERVATION CO SION PERMIT TO DRILL 20 AAC 25.005 la. Type of work [] Drill [] Redrill 11 b. Type of well [] Re-Entry [] Deepen I [] Service [][] DevelopmentEXpl°rat°ry Gas []r"l~StratigraphiCs.~, ~gle Zone Test [][] MultipleDeVel°pmentzone OII 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. Planned KBE -- 61' Milne Point Unit / Schrader 3. Address 6. Property Designation ~ P.O. Box 196612, Anchorage, Alaska 99519-6612 ADL 315848~ ~2~"~ Bluff 4. Location of well at surface 7. Unit or Property Name 1. Type Bond (See 20 AAC 25.025) 2015' NSL, 3446' WEL, SEC. 27, T13N, R10E, UM Milne Point Unit At top of productive interval 8. Well Number 5271' NSL, 1697' WEL, SEC. 28, T13N, R10E, UM MPG-14 Number 2S100302630-277 At total depth 9. Approximate spud date 2111' NSL, 1097' WEL, SEC. 21, T13N, R10E, UM 07/27/01 Amount $200,000.00 12. Distance to nearest property line 113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL 025516, 1097' MD I No Close Approach 1280 9420' MD / 4201' TVD 16. To be completed for deviated wells 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Kick Off Depth 300' MD Maximum Hole An~lle 90 ° Maximum surface 1407 psi~l, At total depth (TVD) 4201' / 1890 psig 18. Casing Program Setting Depth ~ize Specifications T~ o Bot :om Quantitv of (;ement Hole Casina Weiaht Grade Couolina Length MD TVD MD 'rVD (include staae d~ta) 30" 20" 92# H-40 Welded 80' 30' 30' 110' 110' 260 sx Arctic Set (Approx.) 9-7/8" 7" 26# L-80 BTC 7147' 30' 30' 7177' 4197' 762 sx PF 'L'f 566 sx Class 'G' 6-1/8" 4-1/2" 12.6# L-80 IBT-Mod 2343' 7077' 4192' 9420' 4201' Uncemented Slotted Liner 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented MD TVD Structural Conductor Surface ProductionIntermediate RECEIVED Liner JUL 0 ~ ZOO1 Perforation depth: measured Alaska Oil &Gas Cons, Commission Anchorage true vertical 20. Attachments [] Filing Fee [] Property Plat [] BOP Sketch [] Diverter Sketch [] Drilling Program [] Drilling Fluid Program [] Time vs Depth Pict [] Refraction Analysis [] Seabed Report [] 20 AAC 25.050 Requirements Contact Engineer Name/Number: James Franks, 564.4468 Prepared By Name/Number: Sondra Stewman, 564-4750 21. I hereby certify that the forego~g i§ true and correct, to the best of my knowledge . . Sign Permit Number I APl Number ~2-~/'~'/~ ~-.~, 50' ~)Z.~' ' ,~ O,~//" ~~) I ~t~r~;~a~)t' 7 ISee cOver letter for other re(3uirements Conditions of Approval: Samples Required [] Yes ~[ No Mud L~l'R~equ~'~l~ I [] Yes ~'No Hydrogen Sulfide Measures [] Yes ~'No Directional Sudvey Required [~Yes [] No Required Working Precsure for BOPE •2K •3K F'I4K •5K r'110K I-I15K 1-13.5K psi for (~TU Other: ~ 0~7-- "t ~s-~ ~ ~,5-o'~ {;)~"/ byorderof // Al:)l:)roved By ORI{~INAL, -. ,~SI(~NED ....... ElY Commissioner the commission Date ~'~ /~/~ / Form10-401 Rev. 12-01-85 ..,,,~ r'~ t ~",,kl /~, |U ['~ ~,~ ['~J"~L- Sul t. MPG-14 Drillin~l Permit 1. Well Plan Summary IWell Name: I MPG-14 I I T)/pe of Well (producer or injector): I Schrader Bluff Multilateral producer- Lower leg I Surface Location: 2015' FSL, 3446' FEL, SEC. 27, T13N, R10E X = 557156.65 Y = 6014450.44 G-14 Target: 5271' FSL, 1697' FEL, SEC. 28, T13N, R10E X = 553595 Y = 6017680 Z = 4198 TVDss G-14 Target (Bottom Hole 2111' FSL, 1097' FEL, SEC. 21, T13N, R10E Location): X = 554174 Y = 6019804 Z = 4201 TVDss ~ Nabors 27E J Estimated Start Date: July 27, 2001 I MDrkb ~ 9420' ~ I TVDrkb(TD) Operatin~l days to complete: I 16 I Max. Inc. ~ 90° ~ ~ Well Design (conventional, slim hole, etc.): I Multilateral Producer Scope: I Drill and Complete a Multilateral Producer in the Schrader Bluff OA and OB sands. Version #1, 6/26/2001 MPG-14 Drilling Permit 2. Current Well Information 2.1 General 2.2 2.3 Well Name: MPG-14 APl Number: Well Type: Current Status: BHP: BHT: Current Mechanical MPG-14: Nabors 27E: Conductor: Target Estimates Estimated Reserves: Expected Initial Rate: Expected 6 month avg: MPG-14 Development - Schrader Bluff Multilateral Producer- lower leg Conductor Set 1890 psi @ 4201' TVDrkb Top of Schrader Bluff OB Sands. 80°F @ 4000' TVDss Estimated (SOR) Condition Cellar Box above MSL = 29.5' KB / MSL = 31.5' 20", 92 Ib/ft, H-40 Welded set at 80' MD 1.4MMBBL 286O BOPD 84O BOPD UPG-14 Drilling Permit 3. Drilling Hazards and Contingencies 3.1. Well Control MANDATORY WELL CONTROL DRILLS: Drill Type Frecluency Comments D1 Tripping (1) per week, per crew Conducted only inside casing. D2 Drilling (1) per week, per crew Either in cased or open hole. DO NOT shut-in well in open hole. D3 Diverter N/A N/A D4 Accumulator Prior to spud or RWO Approx. every 30 days, thereafter at convenient times. D5 Well Kill Prior to drill out, Prior to drill out the intermediate and production strings. Never per crew carry out this drill when open hole sections are exposed. 3.2. Hydrates 3.2.1. It is a good possibility that gas hydrates will be encountered while drilling the G-14 Surface hole at and around the base of the permafrost. Five of the six wells drilled in 1997 encountered hydrates. The magnitude of the hydrates was in the order of light to moderate and dissipated after drilling the next few stands with moderate increases to the mud weight -9.3 ppg. 3.3. Kick Tolerance 3.3.1. The 7" casing will be cemented to surface. The top of the 15.8 lb/gal tail cement slurry is planned to be 500' MD above the NA Sands -6801' MD. 3.3.2. The Kick Tolerance for the production casing based on the 8.65 expected pore pressure is infinite. 3.4. Lost Circulation 3.4.1. Lost circulation has occurred in the pre-1997 wells drilled on G-pad when displacing the cement. Surface casings for these occurrences were set at just below the base of the permafrost indicating a week shoe. Since 1997, no signs of lost circulation have been encountered. 3.4.2. Follow the LOST CIRCULATION DECISION MATRIX in the well plan if fluid losses occur while drilling. Break circulation slowly in all instances and get up to recommended circulating rate slowly prior to cementing. 3.5. Unexpected Pressures 3.5.1. It is unlikely there will be unexpected overpressure when drilling to the Schrader Bluff formation. Reservoir pressure is expected to be 1890 psi (8.65 lb/gal). In this well, the Schrader Bluff formation will be drilled with 9.2-ppg mud. 3.6. Stuck Pipe 3.6.1. Sticky clays have been seen when drilling from the base of the permafrost down to the Schrader Bluff. Along with the sticky clays is the possibility of tight hole in the interval from the permafrost to TD of the well. Frequent wiper trips may be required while drilling the interval. In all the wells drilled after 1997 on G-pad, no instances of stuck pipe have been seen. 3.6.2. Good drilling practices to avoid differential sticking are required. Minimum mud weights and proper mud properties as outlined in the M-I mud program must be closely followed. Stuck Pipe: Go 3 MPG-14 Drilling Permit immediately to SURE manual, determine stuck pipe mechanism, follow recommendations in the SURE manual. DO NOT JAR UP if packed-off! 3.7. Pad Data Sheet 3.7.1. Please Read the G-Pad Data Sheet thoroughly. 3.8. Hydrocarbons 3.8.1. Hydrocarbons will be encountered in the Ugnu and Schrader Bluff intervals. 3.11 Hydrogen Sulfide 3.11.1. MPG Pad is not designated as an H2S Pad. Below is a summary of the most recent H2S readings: Well G- Well Type H2S Status Date taken li SBF Inj Injector Feb 2000 2 SBF Prod <2.00 June 2001 3i SBF Inj <2.00 Apr 2000 4 SBF Prod <2.00 June 2001 5i SBF Inj Injector Feb 2000 6 SBF Prod <2.00 June 2001 7i SBF Inj Shut in Feb 2000 8 SBF Prod <2.00 June 2001 9i SBF Inj Injector Feb 2000 10 Long Term Shut in Feb 2000 11 SBF Prod <2.00 June 2001 12 SBF Prod <2.00 June 2001 13i SBF Inj Injector Feb 2000 15 SBF Prod <2.00 June 2001 4. Drilling Program Overview MPG-14 Drilling Permit 4.1. Surface and Anti-Collision Issues Surface Shut-in Wells: No wells need to be shut-in for the rig move on and off MPG-14 Close Approach Wells: There are no close approach wells Well Name Current Production Precautions Status Priority/ N/A N/A N/A N/A 4.2. Well Control Expected BHP Max Exp Surface Pressure BOPE Ratin~l Planned BOPE Test Pres. 1890 psi @ 4201' 1407 psi 13 5/8" 5M Rams & Valves: 3500 psi/250 psi TVDrkb/estimated) I0.115 psi/ft ~las ~radient) Annular: 2500 psi/250 psi 4.3. Mud Program 9-7/8" Surface Hole Mud Properties: Density (ppg) I Funnel visc ! YP I HTHP 8.6-9.2 I 50-150 ! 15-40I N/A 6-1/8" Production Hole Mud Properties: OA/OB Density(ppg) IFunnelvisc I YP HTHP 9.2 40 - 55 22 - 27 < 10 Spud - LSND Freshwater Mud pH I API Filtrate LG Solids 9.0-9.5I <6 <6.5 KCI-CaCO3 FIoPro pH I API Filtrate LG Solids 8.0-8.5I 4-6 <12 LCM Restrictions: No Organic LCM products in the Schrader Bluff formation Waste Disposal: NO ANNULAR INJECTION. Drill Cuttings taken to DS-4 disposal site Call the Pad 4 waste disposal site prior to truck leaving location so the site can be ready to unload waste. Exempt liquid wastes can be taken to DS-4 or Phillips KRU 1R. MPG-14 Drillin~l Permit 4.4. Formation Markers Formation Tops ft MD ft TVDrkb Pore Ipsi) EMW (ppg) Base Permafrost 1861 1800 Top Ugnu 5033 3475 1563 8.65 Top Ugnu M 5839 3850 1732 8.65 Schrader-N^ 6081 3952 1778 8.65 Schrader-NB 6162 3983 1792 8.65 Schrader-NC 6247 4014 1805 8.65 Schrader-NE 6309 4035 1815 8.65 Schrader-NF 6450 4079 1835 8.65 TSBD-OA 6576 4113 1850 8.65 TSBC - Base OA 6714 4144 1864 8.65 TSBB-OB 6966 4183 1882 8,65 TD 9420 4201 1890 8,65 4.5. Casing/Tubing Program Hole Size Csg! Wt/Ft Grade Conn Length Top Bottom Tb~ O.D. MD / TVDrkb MD / TVDrkb 30" 20" 92# H-40 Welded 80' 30'/30' 110' / 110' 9-7/8" 7" 26# L-80 BTC 7147' 30' / 30' 7177' / 4197' 6-1/8" 4-1/2" Slotted 12.6# L-80 IBT-Mod +/- 2343' 7077' / 4192' 9420' / 4201' TUbin~l 2-7/8" 6.3# L-80 EUE-Mod +/- 6081' 30' / 30' 6081' / 3952' 4.6. Cement Calculations 7" 26 Ib/ft L-80 BTC-M 250% excess over gauge hole in permafrost interval, 50% excess over gauge hole below permafrost A TAM Port Collar will be Total Cement Volume: at 1000' MD as a Wash 50 bbl Freshwater Lead Tail for cement not displacin~l to surface in one sta¢ 75 bbl of Viscosified Alpha Spacer weighted to 10.20 ppg 564 bbls 10.7 al Permafrost L cement - 762 sacks 116 bbls 15.8 lb/gal Class G + adds - 566 sacks BHST = 80° F from SOR, BHCT 65° F 4.7. Survey and Logging Program 9-7/8" Hole Section: Open Hole: MWD / DIR / GR / Res / PWD 6-1/8" Hole Section: Open Hole: Cased Hole: MWD / DIR(IFR) / ABGR / Res ! PWD / ABI Res placed as close to bit as possible. None 5. MPG-14 Operations Summary MPG-14 Drilling Permit 5.1. Pre-Rig Operations 1. Grade and level pad. 2. Install 20" Conductor. 5.2. Procedure . 6. 7. 8. MIRU, NU diverter on 20" conductor, PU 5" drill pipe Drill 9-7/8" surface hole as per directional plan. Maximum tangent angle 90° Condition mud with lubes and spot casing running lube pill prior to 7" casing run. POOH laying down DP Run and cement 7" casing from TD to surface. TAM Port Collar @ 1000' as contingency should cement not reach the surface. ND Diverter Install FMC 11" 5m horizontal wellhead N/U and test 13 %" 5m BOP Drill 6-1/8" OB horizontal production hole as per directional plan. 100' inside 7" c~ ng asSemblY Wi'th'i'bo'~om trip anchor and MWD. a~ent and set whipstock to place window at top of the CA interval. "~ b~ and mill window thru 7" casing. 12~ateral geosteering and short tripping as required. Maintain FIoPro mud properties. 13~r trip with Hole Opener to TD. 14~ with clean FioPro mud ~~:j2o~l,a,,n,d._p_u_ll whipstock , ~,'th~_..2,,7/_,."_i_nner string, Baker Hook Hanger and hang off in 7' casing 17~own3 Y2' drill pipe / 18~ 2 7/¢ tubing to top of CA liner 19~sing to 9.1 lb/gal completion fluid 20. Land tubing hanger ) 21. Set tu_bi_ng plug and BPV 22. ND BOP 23. Install and test tree (' 24. Pull tubing plug and BPV 25~t the tubing and annulus 26. Inst.all BPV and secure the well 6. MPG-14 Nabors 4ES Operations Summary MPG-14 Drillin~l Permit 1. MI/RU Nabors 4ES. 2. Circulate out freeze protection with 9.1 ppg brine. 3. Remove tree and install BOP. 4. Pull and stand back the 2 %" tubing. 5. Make up the ESP completion and run in on the 2 %" tubing. Freeze protect the well. 6. Set tubing plug and BPV. Remove the BOP. Install and test the tree. 7. RD/MO. 8. Hook up flowlines and instrumentation. COMPANY I)IiT^ILS REFERENCE INFORblATION .qURVEY I'R¢3~iR~,',t Plan: Ml'O-Jelhro Wld)2 (MI'O-14/MP(l-Jclht, lip An~n.a~ Coqmlinate (N/E) R~fei~'nc~.~ Well C,mt~e: MPG-14, Tm,~ ~,'th I ]3."plh To Surv.-?/Iqan T~:! {;nralc'd By: K~.m Alhm ])ale: 612. Vc{~ical (TVD) Rer~,mwa:~: Plan MPG-Jelhto 61.0' 61.00 Cab.. Mell~l: I'd~im~m~Cm'valu{~ Section (VS} Refi~tenc~ Us,.a"Derm*M (0.00N.O.00k~} 500.00 Planncxk Ml'G-J,~thm'~,'p02 VI CB-GYRO-SS ''~,rSy~era: ISCWSA Mea~ut~dDep~hRel'e~-nc~. PlanMl'G-Jelhm61.~Y 61.00 ~00.00 9419.52 Plann~Ml~;JcmmwpO2Vm MWD*IFR+MS ChecklM: [)ale:__ .%an M~th,nl: Tray Cylinder Noah Ca!culalkm Melh~nk Min~num C~'valu.,~ Revicwcxl: I)alc: Em,rSur~acc: Elliptical + Ca~ing Wamin~ M~h~xl: Ruk's Based WELl. DEIAIId'; CASING DETAILS FORMATION TOP DETAILS NO. TVD MD Name Size No. TVDPath MDPath Formation Mi,a-mn 2718.16 78038 601,145030 557157.11 7O~T0O.417N 149°32'01.2'1~W -1000-- I 4197.25 7177.45 7" 7.000 ! 3475.00 5032.89 Top Ugnu 2 4201.00 9419.51 41/2" 4.500 2 3850.00 5838.64 Top Ugnu M 3 3952.00 6081.01 Schrader NA 4 3983.00 6161.79 Schrader NB ]'/,R~ET OET^IL.',; 5 4014.00 6247.41 Schrader NC ~ rvp 6 4035.00 6308.87 Schrader NE ! i 7 4079.00 6450.06 Schrader ]N~ MPG.Jethm t2 4206.00 3943.51 .3347.70 6018367.(,5 553779.59 Poin! i MPG-Jethm 13 4201.00 5376.62 -2941.81 6019803.69 $54174.44 point 8 4113.00 6576.28 TSBD-OA MPG-Jethmllc 4198.00 3.256.~? -3537.92 ~ ! 9 4144.00 6714.19 TSBC (Base OA) MPG-J~hmPolyg,,n 419~.00 i " SECTION DETAILS _ i ~-- Start Dir 17/I00': 300' MD, 300~FVD .' I 31.50 0.00 0.00 31.50 0.00 0.00 0.00 0.00 0.00 ......... 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 i i ~ Start Dir2?/100': 700' MD, 699.68'TVD 3 700.00 4.00 303.50 699.68 7.70 -I 1.64 1.00 303.50 12.34 .... ...... ....... 4 lO00.00 ,0.00 303.5o 997.3o 27.87 .4:.,, 2.o0 0.00 44.67 5 1800.00 34.00 303.50 1733.64 192.07 -290.19 3.00 0.00 307.80 1000- i i~ Start Dir 3'7/100': 1000' MD, 997.3q'VD 6 2060.98 34.00 303.50 1950.00 272.62 -411.89 0.00 0.00 436.88 i l00q \ 7 2764.80 62.15 303.50 2415.53 558.78 -844.17 4.00 0.01 895.42 0.00 0.00 ] ~ 9 7216.45 89.33 7.00 4198.00 3256.87 -3537.92 4.40 77.52 4555.43 MPG-Jethro tlc , ~~\, l0 7478.24 89.33 17.47 4201.07 3512.34 -3482.52 4.00 90.06 4752.95 i: ! i : 11 7870.29 89.33 17.47 4205.65 3886.28 -3364.81 0.00 -68.070'00 5066.475024'47 / i~ ... "" :",~ ................ i' 12 7930.03 90.00 15.81 4206.00 3943.51 -3347.70 3.00 MPG-Jethro t2 ~ ' i i i {13 7936.4690.19 15.81 4205.99 3949.70 -3345.95 3.00 1.01 5071.06 ~ ~ "~ EndlDir :i1800'MD, 1733.64'TVD 14 9419.52 90.19 15.81 4201.00 5376.62 -2941.81 0.00 0.00 6128.81 MPO-Jethrot3 2000-- i i i 2000 ' .~:-- Start Dir 47~100'i 2060.98' MD, 1950~I'VD ANNOTATIONS ~ ~ ...i ~ I 300.00 300,00 Start Oir I?/100': 300' MD, 300'rVD i i ! % .,-~-!EndDir : 2764.8' MD, 2415.SYTVD ssTVDplus6 1' forRKBE. 2699.68 700.00 Start Dir2?/100': 700'MD, 699.68'TVD 3 997.30 1000.00 Start Dir Y?/100': 1000' MD, 997.3'1'VD I 4 1733.64 1800.00 End Dir: 1800' MD, 1733.64'TVD - ~. 3000 '~..<~i~- 5 1950.00 2060.98 Start Dir 4?/100' : 2060.98' MD, 1950'TVD i i i i-- :.- : 6 2415.53 2764.80 End Dir : 2764.8' MD, 2415.5Y TVD - i ....... i' ~ ..... :. .......... i ' ..... '"~"<~ i ....... ii' '" 7 3789.845706.90 StartDirn.a'!/lOO':5706.9'MD, 3789.sn~rVD ~ 8 4198.00 7216.45 Stad Dir 47/100': 7216.45' MD, 4198'TVD 3000--- .................... } .................... i ............. i ............. i .... i ........................... ~"{~'~'-'--'i ............. ! ......... ....................... ;'- 9 4201.07 7478.24 EndDir :7478.2n'MD, n201.07'TVD i i i i : i 0 0 "i. i ~ ~ i 10 4205.65 7870.29 Start Dir 371100' :,7870.29' MD, 4205.65'TVD I I 4205.99 7936.46 End Dir : 7936.46' MD, 4205.99' TVD .... i ~ Start Dir 4.47/100': 5706.9' MD, 3789.84'TVD i i i ! "-i : i / Top Ugnu M 12 4201.00 9419.51 Total Depth: 9419.52' MD, 4201'TVD 400O--- i i { i S, '~rt Di~ 4?/100' 7216.45, Mb, 41~a'rVt) } / { i i 0 1000 2000 3000 4000 5000 6000 7000 8000 Vertical Section at 331.31 o [ 1000t'din] Emir System: ISCWSA Scan Method: Tray Cylinde* Ntmh Error Surface: Elliplkal + Casing Wamin~ M~hc, d: RuI~s REFERENCE INFORNtATION C~ndimte ~ Reference: Well Centre: MPG-14, Tree Neath Veak. al {7VD) Refeeer~e: Plan MPG-Jet, to 61_0' 61.~ Section (rS) Rererer~. U~r Defined (O.OON, O.OOE) Mea s',l'~l Depth Re f¢~nce: Plan MPG-Jethm 61.0' 61.00 Calculation IMetlac, d: Minimuln CtlrvahJl~ All TVD depths are ssTVD plus 61' for RKBE. 4 1/2" ~ ~ Total Depth: 9419.52' MD, 4201' TVD ] i :.. : MPG-Jethrot3 ........... '?' ., i I.rd l~ir i 7936.46' MD, 4205.99' TVD . MPG-Jethro t2 ...... Stall Dir 37/i00': 7870.29' MD, 4205.65'TVD Endi I Y~ · 7478.24' MD, 4201.07' TVD / Start .lj~- -'-'.'/100': 7216.45' MD, 4198'TVD / / .,.: ./ ~: M I'¢ l-Jethro tl c ........... T" .~_..? .F.. %...A !;k. )~. .i~. '%..../ :~!: .~7 i '¥:¥i ::;i '.i ....... i.i. .......... .... Start Dir 4.47/100': 5706.9' MD, 3789.84'TVD '"5;.;;..i.: iooo- "iT.....Z...L" ii .i......'.25 ' ........ .................... i 'i 'i ....... ............ } ........... i'"204~ '"i' '~ih'~i'Dir. 4?/100': 2060.98' MD, 1950'TVD ! ..... .... i i .i ............ i ........... ~ End Dir: 1800'MD, 1733.64'TVD : i i i i ~5o0~x. i i. i i i~ i ! i . 1000~ Start Dir 3'?/100': 1000' MD, 997.3TVD i i i i i 5001 'X., ! Start Dir 2'?/100': 700' MD, 699.68q'VD i i i i i ! ' Sta. r)i~ moo' : 300' Mr), 300~rvr) -4000 -5:;00 -2000 - 1000 0 1000 SURVEY PROGRAM I Plan: MP(bJcihm wpl}2 {MI'G- 14;Ml'G-Jclhr.-' ~ DepthTo Survey/Plan Tm,I I Crealcd By: Kcm Allol Date: 6/2. 500.~O Planned: MPG-Jelhm wp02 VI CB-GYRO-S.q Checked: Dale: ~00.00 9419~2 Planned: [',tPG-J,,:~ wp02 VI MWD+IFR4MS Reviewed: Date: __ WELL DEI'^ILS i'qame *lq/oS +Fd-W Nt nlhin8 F.a~lingI Jtilude i.ongilUl]~ Sh,I MPG-14 2718.16 78038 6O1445O3O 557157.11 70"27'6O.417N 149~32'01.2?t8W 14 I'ARGEI nE1 All.'*. Nan~ TVD *N;-S+ I-]]-W Nc~hing I~ Shape MPG-Jcthm O. 4206.00 394331 -3347.70 6OLR367.65 553779.59 I'oinl MPG-Jellu'u134201.00 5376.62 -2941.gl 6OI9g03.69 554174.44 Poin! MPG-Jctl~o tlc 419g.00 325637 -3537.92 6017679.63 553494.(~ Poinl MPG.Jethnl Polygon 4198.0~ 5596.64 -3204.18 6020021.66 553910.41 SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W DLeg TFace VSec Target 31.50 0.00 0.00 31.50 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 700.00 4.00 303.50 699.68 7.70 -I 1.64 1.00 303.50 12.34 1000.0010.00 303.50 997.30 27.87 -42.1 I 2.00 0.00 44.67 1800.0034.00 303.50 1733.64 192.07 -290.19 3.00 360.00 307.80 2060.9834.00 303.50 1950.00 272.62 -411.89 0.00 0.00 436.88 2764.8062.15 303.50 2415.53 558.78 -844.17 4.00 0.01 895.42 5706.9062.15 303.50 3789.84 1994.77 -3013.31 0.00 0.00 3196.43 7216.4589.33 7.00 4198.00 3256.87 -3537.92 4.40 77.52 4555.43MPG-Jethro tlc 0 7478.2489.33 17.47 4201.07 3512.34 -3482.52 4.00 90.06 4752.95 11 7870.2989.33 17.47 4205.65 3886.28 -3364.81 0.00 0.00 5024.47 12 7930.0390.00 15.81 4206.00 3943.51 -3347.70 3.00 -68.07 5066.47 MPG-Jethro t2 13 7936.4690.19 15.81 4205.99 3949.70 -3345.95 3.00 1.01 5071.06 14 9419.5290.19 15.81 4201.00 5376.62 -2941.81 0.00 0.00 6128.81 MPG-Jethrot3 ANNOTATIONS No. TVD MD Annotation I 300.00 300.00 Start Dir I?/100': 300' MD, 300'TVD 2 699.68 700.00 Start Dir 27/100': 700' MD, 699.68'TVD 3 997.30 1000.00Start Dir 37/100': 1000' MD, 997.YTVD 4 1733.64 1800.00End Dir : 1800' MD, 1733.64'TVD 5 1950.00 2060.98Start Dir 47/100': 2060.98' MD, 1950'TVD 6 2415.53 2764.80End Dir : 2764.8' MD, 2415.53' TVD 7 3789.84 5706.90Start Dir 4.47/100': 5706.9' MD, 3789.84'TVD 8 4198.00 7216.45Start Dir 47/100': 7216.45' MD, 4198'TVD 9 4201.07 7478.24End Dir : 7478.24' MD, 4201.07' TVD 10 4205.65 7870.29Start Dir 3'?/100': 7870.29' MD, 4205.65'TVD I 1 4205.99 7936.46End Dir: 7936.46' MD, 4205.99' TVD 12 4201.00 9419.5 Total Depth: 9419.52' MD, 4201' TVD FORMATION TOP DETAILS No. TVDPath MDPath Formation I 3475.00 5032.89Top Ugnu 2 3850.00 5838.64Top Ugnu M 3 3952.00 6081.01Schrader NA 4 3983.00 6161.79Schrader NB 5 4014.00 6247.41Schrader NC 6 4035.00 6308.87Schrader NE 7 4079.00 6450.06Schrader NF 8 4113.00 6576.28TSBD-OA 9 4144.00 6714.19TSBC {Base OA) 10 4183.00 6966.23TSBB-OB CASING DETAILS No. TVD MD Name I 4197.25 7177.457" 2 4201.00 9419.514 I/2" Size 7.000 4.500 2000 West(-)/East(+) [ 1000fl/in] BP Amoco Planning Report- Geographic Company: BP Amoco Date: 6/26/2001 Time: 11:34:07 Page: Field: Milne Point Co-ordinate(NE) Reference: Well: MPG-14, True North Site: M Pt (3 Pad Vertical (TVD) Reference: Plan MPG-Jethro 61.0' 61.0 Well: MPG-14 Section (VS) Reference: User (0.00N,0.00E,331.31Azi) Wellpath: MPG-Jethro Plan: MPG-Jethro wp02 Field: Milne Point ...................................... -~ North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic ModeL: BGGM2001 Site: M Pt G Pad TR-13-10 UNITED STATES: North Slope Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 ft Ground Level: 0.00 ft 6011726.58 ft Latitude: 70 26 33.685 N 556397.19 ft Longitude: 149 32 24.162 W North Reference: True Grid Convergence: 0.43 deg Well: MPG-14 MPG-14 Surface Position: +N/-S 2718.16 ft +E/-W 780.58 ft Position Uncertainty: 0.00 ft Reference Point: +N/-S 2718.16 ft +E/-W 780.58 ft Slot Name: 14 Northing: 6014450.30 ft Latitude: 70 27 0.417 N Easting: 557157.11 ft Longitude: 149 32 1.238 W Northing: 6014450.30 ft Latitude: 70 27 0.417 N Easting: 557157.11 ft Longitude: 149 32 1.238 W Measured Depth: 31.50 ft Inclination: 0.00 deg Vertical Depth: 31.50 ft Azimuth: 0.00 deg Wellpath: MPG-Jethro Drilled From: Well Ref. Point Tie-on Depth: 29.50 ft Current Datum: Plan MPG-Jethro 61.0' Height 61.00 ft Above System Datum: Mean Sea Level Magnetic Data: 6/25/2001 Declination: 26.25 deg Field Strength: 57457 nT Mag Dip Angle: 80.79 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ft ft ft deg 0.00 0.00 0.00 331.31 Plan: MPG-Jethro wp02 Date Composed: 6/25/2001 Version: 1 Principal: Yes Tied-to: From Well Ref. Point Plan Section Information MD Incl Azim TVD +N/-S +E/-W DLS Build Turn TFO Target ft deg deg ft ft ft deg/10Oft deg/100ft deg/100ft deg 31.50 0.00 0.00 31.50 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 0.00 700.00 4.00 303.50 699.68 7.70 -11.64 1.00 1.00 0.00 303.50 1000.00 10.00 303.50 997.30 27.87 -42.11 2.00 2.00 0.00 0.00 1800.00 34.00 303.50 1733.64 192.07 -290.19 3.00 3.00 0.00 360.00 2060.98 34.00 303.50 1950.00 272.62 -411.89 0.00 0.00 0.00 0.00 2764.80 62.15 303.50 2415.53 558.78 -844.17 4.00 4.00 0.00 0.01 5706.90 62.15 303.50 3789.84 1994.77 -3013.31 0.00 0.00 0.00 0.00 7216.45 89.33 7.00 4198.00 3256.87 -3537.92 4.40 1.80 4.21 77.52 7478.24 89.33 17.47 4201.07 3512.34 -3482.52 4.00 0.00 4.00 90.06 7870.29 89.33 17.47 4205.65 3886.28 -3364.81 0.00 0.00 0.00 0.00 7930.03 90.00 15.81 4206.00 3943.51 -3347.70 3.00 1.12 -2.78 -68.07 7936.46 90.19 15.81 4205.99 3949.70 -3345.95 3.00 3.00 0.05 1.01 9419.52 90.19 15.81 4201.00 5376.62 -2941.81 0.00 0.00 0.00 0.00 MPG-Jethro tlc MPG-Jethro t2 MPG-Jethro t3 Section 1 : Start MD. Inci Azim : TVD +N/-S +E/-W VS · .DLS .Build .Turn TFO . "ft ~ deg deg ft. ft . "ft' ft deg/100ft deg/100ft d'eg/100ft deg . 31.50 0.00 0.00 31.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 100.00 0.00 0.00 100.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 200.00 0.00 0.00 200.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 : ..................................................................................................................................................................................................... BP Amoco Planning Report- Geographic Company: BP Amoco Field: Milne Point Site: M Pt G Pad Well: MPG-14 Wellpath: MPG-Jethro Date: 6/26/2001 Time: 11:34:07 Co-ordinate(NE) Reference: Well: MPG-14, True North Vertical (TVD) Reference: Plan MPG-Jethm 61.0' 61.0 Section (VS) Reference: User (0.00N,0.00E,331.31Azi) Plan: MPG-Jethro wp02 Page: 2 Section 2: Start MD lncl Azim TVD ff deg deg 400.00 1.00 303.50 399.99 500.00 2.00 303.50 499.96 600.00 3.00 303.50 599.86 700.00 4.00 303.50 699.68 +NbS +E/-W VS DLS Build Turn TFO fl fl fl deg/100ftdeg/100ftdeg/100ft deg 0.48 -0.73 0.77 1.00 1.00 0.00 0.00 1.93 -2.91 3.09 1.00 1.00 0.00 0.00 4.33 -6.55 6.95 1.00 1.00 0.00 0.00 7.70 -11.64 12.34 1.00 1.00 0.00 0.00 Section 3: Start MD Incl Azim TVD +N/-S +E/-W VS DLS Build Turn TFO ~ ff deg deg ft ft ft ft deg!100ft deg/100ft deg/100ft deg 800.00 6.00 303.50 799.29 12.51 -18.91 20.05 2.00 2.00 0.00 0.00 900.00 8.00 303.50 898.54 19.24 -29.07 30.83 2.00 2.00 0.00 0.00 1000.00 10.00 303.50 997.30 27.87 -42.11 44.66 2.00 2.00 0.00 0.00 Section 4: Start : Incl: Azim +N/~S +E/~W VS : DLS BUlld Turn: ::=i TFO ~ :deg ft = ft.: : :deg/lOOffdeg/lOOftdeg/lOOft: : deg 1100.00 13.00 303.50 1095.28 38.87 -58.73 62.30 3.00 3.00 0.00 0.00 1200.00 16.00 303.50 1192.08 52.69 -79.61 84.44 3.00 3.00 0.00 0.00 1300.00 19.00 303.50 1287.45 69.29 -104.68 111.03 3.00 3.00 0,00 0.00 1400.00 22.00 303,50 1381.10 88.61 -133.88 142.00 3.00 3.00 0.00 0.00 1500.00 25.00 303.50 1472.80 110.62 -167.13 177.27 3.00 3.00 0.00 0.00 1600.00 28.00 303.50 1562.28 135.24 -204.33 216.73 3.00 3.00 0.00 0.00 1700.00 31.00 303.50 1649.31 162.42 -245.39 260.28 3.00 3.00 0.00 0.00 1800.00 34.00 303.50 1733.64 192.07 -290.19 307.80 3.00 3.00 0.00 0.00 Section 5: Start I~..::'MD" Incl· Azim .TVD +N/-S' +E/-W. VS DLS Build::· :: Turn TFO. :.ft . . deg deg .... ft ..'.ft ft' . ft .deg/lOOft.deg/lOOft.d.eg!lOOft" deg' . · . / -~0---~.00 34.00 303.50 1816.54 222.93 -336.82 357.26 0.00 0.00 0.00 0.00 / 2000.00 34.00 303.50 1899.45 253.80 -383.45 406.72 0.00 0.00 0.00 0.00 [ 2060.98 34.00 303.50 1950.00 272.62 -411.89 436.88 0.00 0.00 0.00 0.00 Section 6: Start · :i .'. :!: . ~D :. .... 'Incl:: AZim .' TVD +N/-S .+E/-W ' VS DLS ·Build: .. ·Turn . .TFO· " . .' i. ' ' ' deg deg' . :.'ft ft ' "ft '.. "ff deg/lOOff deg/1.0Oft..deg/!OOftl i:' deg ' · 2100.00 35.56 303.50 1982.05 284.90 2200.00 39.56 303.50 2061.30 318.55 2300.00 43.56 303.50 2136.11 355.16 2400.00 47.56 303.50 2206.11 394.56 2500.00 51.56 303.50 2270.96 436.56 2600.00 55.56 303.50 2330,35 480.96 2700.00 59.56 303.51 2383.98 527.54 2764.80 62.15 303.50 2415.53 558.78 -430.45 456.57 4.00 4.00 0.00 0.01 -481.27 510.47 4.00 4.00 0.00 0.01 -536.58 569.14 4.00 4.00 0.00 0.01 -596.11 632.28 4.00 4.00 0.00 0.01 -659.56 699.59 4.00 4.00 0.00 0.01 -726.63 770.73 4.00 4.00 0.00 0.01 -796.98 845.37 4.00 4.00 0.00 0.01, -844.17 895.43 4.00 4.00 -0.01 -0.10 Section 7: Start · = .i:'MD · .".InCi· · Azim 'TVD .+N/-S. +E/-W"' ..VS '.DLS : Build ' Tui:n TFO '.. ":.il.':ft. .'Oeo'.I' '.::'ideg' · ft '. ff'. ':'ft . fi:'., deg/iooff'deg/100ft deg!lOOft ' deg " " · '......... .::..: .. . . · .. · ..'. . ... : ..... .. :. . . . .. . . · . ... 2800.00 62.15 303.50 2431.97 575.96 -870.12 922.95 0.00 0,00 0.00 180.00 2900.00 62.15 303.50 2478.69 624.76 -943.85 1001.16 0.00 0.00 0.00 180.00 3000.00 62.15 303.50 2525.41 673.56 -1017.58 1079.36 0.00 0.00 0.00 180.00 3100.00 62.15 303.50 2572.12 722.36 -1091.31 1157.57 0.00 0.00 0.00 180.00 3200.00 62.15 303.50 2618.84 771.16 -1165.04 1235.77 0.00 0.00 0.00 180.00 3300.00 62.15 303.50 2665.55 819.96 -1238.77 1313.97 0.00 0.00 0.00 180.00 3400.00 62.15 303.50 2712.27 868.76 -1312.50 1392.18 0.00 0.00 0.00 180.00 3500.00 62,15 303.50 2758.98 917.56 -1386.23 1470.38 0.00 0.00 0.00 180.00 3600.00 62.15 303.50 2805.70 966.36 -1459.96 1548.59 0.00 0.00 0.00 180.00 3700.00 62.15 303.50 2852.42 1015.17 -1533.69 1626.79 0.00 0.00 0.00 180.00 3800.00 62.15 303.50 2899.13 1063.97 -1607.42 1704.99 0.00 0.00 0.00 180.00 3900.00 62.15 303.50 2945.85 1112.77 -1681.15 1783.20 0.00 0.00 0.00 180.00 4000 O0 62 15 303 50 2992 56 1161 57 -1754 88 1861 40 0 O0 0 O0 0 O0 180 O0 .... ~ ....... ""_ ....... ~ ................ ~ ................. £ ................ ~ .................. ~ ..................... : .............. ~ ............. : .......................... : .............................. BP Amoco Planning Report- Geographic Company: BP Amoco Field: Milne Point Site: M Pt G Pad Well: MPG-14 Wellpath: MPG-Jethro Date: 6/26/2001 Time: 11:34:07 Co-ordinate(NE) Reference: Well: MPG-14, True North Vertical (TVD) Reference: Plan MPG-Jethro 61.0' 61.0 Section (VS) Reference: User (0.00N,0.00E,331.31Azi) Plan: MPG-Jethro wp02 Page: 3 Section 7: Start MD Incl Azim TVD +N/-S +E/-W VS DLS Build Turn TFO ft deg deg ft ft ft ft deg/100ft deg/100ft deg/100ft deg 4100,00 62,15 303,50 3039,28 1210,37 -1828.61 1939.60 0,00 0,00 0,00 180,00 4200.00 62.15 303.50 3086.00 1259.17 -1902.34 2017.81 0.00 0.00 0.00 180..00 4300.00 62.15 303.50 3132.71 1307.97 -1976.07 2096.01 0.00 0.00 0.00 180.00 4400.00 62.15 303.50 3179.43 1356.77 -2049.80 2174.22 0.00 0.00 0.00 180.00 4500.00 62.15 303.50 3226.14 1405.57 -2123.53 2252.42 0.00 0.00 0.00 180.00 4600.00 62.15 303.50 3272.86 1454.37 -2197.26 2330.62 0.00 0.00 0.00 180.00 4700.00 62.15 303.50 3319.57 1503.17 -2270.99 2408.83 0.00 0.00 0.00 180.00 4800.00 62.15 303.50 3366.29 1551.97 -2344.72 2487.03 0.00 0.00 0.00 180.00 4900.00 62.15 303.50 3413.01 1600.77 -2418.45 2565.24 0.00 0.00 0.00 180.00 5000.00 62.15 303.50 3459.72 1649.58 -2492.18 2643.44 0.00 0.00 0.00 180.00 5100.00 62.15 303.50 3506.44 1698.38 -2565.91 2721.64 0.00 0.00 0.00 180.00 5200.00 62.15 303.50 3553.15 1747.18 -2639.64 2799.85 0.00 0.00 0.00 180.00 5300.00 62.15 303.50 3599.87 1795.98 -2713.37 2878.05 0.00 0.00 0.00 180.00 5400.00 62.15 303.50 3646.59 1844.78 -2787.10 2956.26 0.00 0.00 0.00 180.00 5500.00 62.15 303.50 3693.30 1893.58 -2860.83 3034.46 0.00 0.00 0.00 180.00 5600.00 62.15 303.50 3740.02 1942.38 -2934.56 3112.66 0.00 0.00 0.00 180.00 5706.90 62.15 303.50 3789.84 1994.77 -3013.31 3196.42 0.00 0.00 0.00 180.00 Section 8: Start TVD: +N!¢S:: :+Ei,W : VS ; ::i::;:DLS Build; TUrn ft : ;;f t: ::ff ft: :::d'egilooft:degllOOft;;dbgllOOft 5800.00 63.11 307.99 3832.66 2043.06 -3080.38 3270.98 4.40 1.03 4.82 77.52 5900.00 64.29 312.71 3876.99 2101.09 -3148.66 3354.67 4.40 1.18 4.73 75.46 , 6000.00 65.62 317.34 3919.33 2165.17 -3212.66 3441.61 4.40 1.33 4.63 73.36 6100.00 67.09 321.87 3959.45 2234.93 -3271.98 3531.28 4.40 1.47 4.53 71.40 6200.00 68.69 326.30 3997.10 2309.95 -3326.30 3623.16 4.40 1.60 4.43 69.58 6300.00 70.40 330.62 4032.07 2389.78 -3375.28 3716.71 4.40 1.71 4.33 67.92 6400.00 72.21 334.86 4064.13 2473.97 -3418.63 3811.37 4.40 1.81 4.23 66.40 6500.00 74.11 339.01 4093.12 2562.01 -3456.11 3906.59 4.40 1.90 4.15 65.05 6600.00 76.08 343.07 4118.85 2653.38 -3487.48 4001.81 4.40 1.98 4.07 63.84 6700.00 78.13 347.07 4141.18 2747.54 -3512.57 4096.46 4.40 2.04 4.00 62.80 6800.00 80.22 351.01 4159.96 2843.95 -3531.23 4189.98 4.40 2.10 3.94 61.90 6900.00 82.37 354.90 4175.10 2942.03 -3543.34 4281.84 4.40 2.14 3.89 61.16 7000.00 84.54 358.75 4186.50 3041.20 -3548.84 4371.47 4.40 2.18 3.85 60.58 7100.00 86.75 2.57 4194.10 3140.88 -3547.69 4458.36 4.40 2.20 3.82 60.14 7200.00 88.96 6.37 4197.85 3240.48 -3539.90 4542.00 4.40 2.22 3.80 59.85 7216.45 89.33 7.00 4198.00 3256.87 -3537.92 4555.43 4.43 2.24 3.82 59.57 Section 9: Start ri ..:...:MD.' ' Incl ' ' '..AZim '. TVDi .' '+N/-S +E/-W ' · VS'. .'"DES : ·Build·:: Turn ' : T'FO · ' .... ::... · · .:"ft'.' '. "deg/100ft deg/100ft'deg/100ft ..deg. ; .: ' ' : ' l"' ":"ft:' ... i deg.. · ' deg ..i ' "ft: ' . 'i .;ft.. :'.:.... 'ft · . ......... [- -'7-~-~ ~,'~-~- ..... -~ ~- ........ ~- ~ .-~---'-~-i'-~ ~-,~ ~-'-~-~ ~'~-,~-~'--"-~ ~ 525133 '----4-~-~ ~ ~-~ ....... ~ ~ ....... ~)~ ~}~ .......... -~ ~-'------~ '~ i-~ ..................... ~ 7400,00 89,33 14,34 4200,15 3437,11 -3503,96 4697,24 4,00 0,00 4,00 90,02 L 7478,24 89,33 17,47 4201,07 3512,34 -3482,52 4752,95 4,00 0,00 4,00 89,98 Section 10: Start .MD' .. Incl.. Azim. ...... .' TvD... '.'+N/-s:'. ' 5~E/~ ft .: ..... · deg..., deg..:: ..: ..'ft · .'ft' : ft' ft .. ........ ,, :: ...... DLS ' ' Build::: :Turn TFO :' ' ':. · 'd'egilooft 'deg/iO'oft dbgllOOft :'d~g. 7500.00 89.33 17.47 4201.32 3533.09 -3475.99 4768.02 0.00 0.00 0.00 0.00 7600.00 89.33 17.47 4202.49 3628.48 -3445.97 4837.28 0.00 0.00 0.00 0.00 7700.00 89.33 17.47 4203.66 3723.86 -3415.95 4906.54 0.00 0.00 0.00 0.00 7800.00 89.33 17.47 4204.83 3819.24 -3385.93 4975.80 0.00 0.00 0.00 0.00 7870.29 89.33 17.47 4205.65 3886.28 -3364.81 5024.48 0.00 0.00 0.00 0.00 Section 11 : Start ~;: :;;:::;Azim;:::::;: ;::-t-Ei~W;::: :; :! DLS : : Build ; TUrn ::T~0 : :. Z:dbg;, :::d:$g: ::.;;:; ::;;R] ]ff :::; ft: :deg/1;Ooft.deg~iO~::d~gilOOft 7930.03 90.00 15.81 4206.00 3943.51 -3347.70 5066.47 2.99 1.12 -2.77 -67.98 BP Amoco Planning Report - Geographic Company: BP Amoco Field: Milne Point Site: M Pt G Pad Well: MPG-14 Wellpath: MPG-Jethro Date: 6/26/2001 Time: 11:34:07 Co-ordinate(NE) Reference: Well: MPG-14, True North Vertical (TVD) Reference: Plan MPG-Jethro 61.0' 61.0 Section (VS) Reference: User (0.00N,O.00E,331.31Azi) Plan: MPG-Jethro wp02 Page: 4 Section 12: Start MD lncl Azim TVD +N/-S +E/-W VS DLS Build Turn TFO I ft deg deg ft ft ft ft deg/100ft deg/100ft deg/100ft deg '1 7936.46 90.19 15.81 4205.99 3949.70 -3345.95 5071.06 2.95 2.95 0.00 0.00 ' Section 13: Start MD Incl Azim TVD +N/-S +E/-W VS DLS Build Turn TFO ft deg deg ft ft ft ft deg/100ft deg/100ft deg/100ft deg 8000.00 90.19 15.81 4205.78 4010.84 -3328.64 5116.38 0.00 0.00 0.00 0.00 8100.00 90.19 15.81 4205.45 4107.05 -3301.39 5187.70 0.00 0.00 0.00 0.00 8200.00 90.19 15.81 4205.12 4203.27 -3274.15 5259.03 0.00 0.00 0.00 0.00 8300.00 90.19 15.81 4204.78 4299.49 -3246.90 5330.36 0.00 0.00 0.00 0.00 8400.00 90.19 15.81 4204.45 4395.70 -3219.66 5401.68 0.00 0.00 0.00 0.00 8500.00 90.19 15.81 4204.12 4491.92 -3192.42 5473.01 0.00 0.00 0.00 0.00 8600.00 90.19 15.81 4203.79 4588.14 -3165.17 5544.34 0.00 0.00 0.00 0.00 8700.00 90.19 15.81 4203.46 4684.35 -3137.93 5615.66 0.00 0.00 0.00 0.00 8800.00 90.19 15.81 4203.13 4780.57 -3110.68 5686.99 0.00 0.00 0.00 0.00 8900.00 90.19 15.81 4202.79 4876.78 -3083.44 5758.32 0.00 0.00 0.00 0.00 9000.00 90.19 15.81 4202.46 4973.00 -3056.19 5829.64 0.00 0.00 0.00 0.00 9100.00 90.19 15.81 4202.13 5069.22 -3028.95 5900.97 0.00 0.00 0.00 0.00 9200.00 90.19 15.81 4201.80 5165.43 -3001.70 5972.30 0.00 0.00 0.00 0.00 9300.00 90.19 15.81 4201.47 5261.65 -2974.46 6043.62 0.00 0.00 0.00 0.00 9400.00 90.19 15.81 4201.14 5357.87 -2947.21 6114.95 0.00 0.00 0.00 0.00 9419.52 90.19 15.81 4201.00 5376.62 -2941.81 6128.81 0.00 0.00 0.00 0.00 Survey : .. Map .. Map <-.-' ·Latitude --> < Longitude ---> MD lncl Azim TVD +N/-S +E/-W Northing Easting "Deg Min : Sec Deg Min Sec · ft deg deg ft ' .. ft.' ft ft' ' ft " .:' ' " 31.50 0.00 0.00 31.50 0.00 0.00 6014450.30 557157.11 70 27 0.417 N 149 32 1.238 W 100.00 0.00 0.00 100.00 0.00 0.00 6014450.30 557157.11 70 27 0.417 N 149 32 1.238 W 200.00 0.00 0.00 200.00 0.00 0.00 6014450.30 .557157.11 70 27 0.417 N 149 32 1.238 W 300.00 0.00 0.00 300.00 0.00 0.00 6014450.30 557157.11 70 27 0.417 N 149 32 1.238 W 400.00 1.00 303.50 399.99 0.48 -0.73 6014450.78 557156.38 70 27 0.422 N 149 32 1.259 W 500.00 2.00 303.50 499.96 1.93 -2.91 6014452.20 557154.19 70 27 0.436 N 149 32 1.323 W 600.00 3.00 303.50 599.86 4.33 -6.55 6014454.58 557150.53 70 27 0.460 N 149 32 1.430 W 700.00 4.00 303.50 699.68 7.70 -11.64 6014457.91 557145.42 70 27 0.493 N 149 32 1.580 W 800.00 6.00 303.50 799.29 12.51 -18.91 6014462.66 557138.11 70 27 0.541 N 149 32 1.793 W 900.00 8.00 303.50 898.54 19.24 -29.07 6014469.31 557127.90 70 27 0.607 N 149 32 2.092 W 1000.00 10.00 303.50 997.30 27.87 -42.11 6014477.84 557114.80 70 27 0.692 N 149 32 2.475w 1100.00 13.00 303.50 1095.28 38.87 -58.73 6014488.72 557098.09 70 27 0.800 N 149 32 2.963W 1200.00 16.00 303.50 1192.08 52.69 -79.61 6014502.37 557077.11 70 27 0.936 N 149 32 3.576W 1300.00 19.00 303.50 1287.45 69.29 -104.68 6014518.77 557051.91 70 27 1.099 N 149 32 4.312W 1400.00 22.00 303.50 1381.10 88.61 -133.88 6014537.87 557022.57 70 27 1.289 N 149 32 5.170W 1500.00 25.00 303.50 1472.80 110.62 -167.13 6014559.62 556989.16 70 27 1.505 N 149 32 6.146W 1600.00 28.00 303.50 1562.28 135.24 -204.33 6014583.96 556951.77 70 27 1.748 N 149 32 7.239W 1700.00 31.00 303.50 1649.31 162.42 -245.39 6014610.82 556910.51 70 27 2.015 N 149 32 8.445W 1800.00 34.00 303.50 1733.64 192.07 -290.19 6014640.12 556865.49 70 27 2.306 N 149 32 9.760W 1900.00 34.00 303.50 1816.54 222.93 -336.82 6014670.62 556818.63 70 27 2.610 N 149 32 11.130W 2000.00 34.00 303.50 1899.45 253.80 -383.45 6014701.13 556771.77 70 27 2.913 N 149 32 12.499W 2060.98 34.00 303.50 1950.00 272.62 -411.89 6014719.73 556743.18 70 27 3.099 N 149 32 13.335W 2100.00 35.56 303.50 1982.05 284.90 -430.45 6014731.87 556724.53 70 27 3.219 N 149 32 13.880W 2200.00 39.56 303.50 2061.30 318.55 -481.27 6014765.11 556673.46 70 27 3.550 N 149 32 15.373W 2300.00 43.56 303.50 2136.11 355.16 -536.58 6014801.30 556617.88 70 27 3.910 N 149 32 16.997W 2400.00 47.56 303.50 2206.11 394.56 -596.11 6014840.24 556558.06 70 27 4.298 N 149 32 18.745W 2500.00 51.56 303.50 2270.96 436.56 -659.56 6014881.75 556494.29 70 27 4.711N 149 32 20.609W 2600.00 55.56 303.50 2330.35 480.96 -726.63 6014925.63 556426.89 70 27 5.147 N 149 32 22.579W 2700.00 59.56 303.51 2383.98 527.54 -796.98 6014971.66 556356.18 70 27 5.605 N 149 32 24.645W 2764.80 62.15 303.50 2415.53 558.78 -844.17 6015002.54 556308.76 70 27 5.912 N 149 32 26.031 W BP Amoco Planning Report- Geographic Company: BP Amoco Date: 6/26/2001 Time: 11:34:07 Page: 5 Field: Milne Point Co-ordinate(NE) Reference: Well: MPG-14, True North Site: M Pt (3 Pad Vertical (TVD) Reference: Plan MPG-Jethro 61.0' 61.0 Well: MPG-14 Section (VS) Reference: User (0.00N,0.00E,331.31Azi) Wellpath: MPG-Jethro Plan: MPG-Jethro wp02 Survey Map Map <M Latitude ---> <-- Longitude --> MD Incl Azim TVD +N/-S +E/-W Northing Easting Deg Min Sec Deg Min Sec ft deg deg ft fi. ft ft ft 2800.00 62.15 303.50 2431.97 575.96 -870.12 6015019.51 556282.68 70 27 6.081 N 149 32 26.794W 2900.00 62.15 303,50 2478.69 624.76 -943.85 6015067.74 556208.59 70 27 6.561 N 149 32 28.959W 3000.00 62.15 303.50 2525.41 673.56 -1017.58 6015115.97 556134.49 70 27 7.041N 149 32 31.125W 3100.00 62.15 303.50 2572.12 722.36 -1091.31 6015164.20 556060.40 70 27 7.521 N 149 32 33.291 W 3200.00 62.15 303.50 2618.84 771.16 -1165.04 6015212.43 555986.30 70 27 8.001 N 149 32 35.456W 3300.00 62.15 303.50 2665.55 819.96 -1238.77 6015260.66 555912.21 70 27 8.481 N 149 32 37.622W 3400.00 62.15 303.50 2712.27 868.76 -1312.50 6015308.89 555838.11 70 27 8.960 N 149 32 39.788W 3500.00 62.15 303.50 2758.98 917.56 -1386.23 6015357.12 555764.02 70 27 9.440 N 149 32 41.954W 3600.00 62.15 303.50 2805.70 966.36 -1459.96 6015405.35 555689.92 70 27 9.920 N 149 32 44.119W 3700.00 62.15 303.50 2852.42 1015.17 -1533.69 6015453.58 555615.83 70 27 10.400 N 149 32 46.285W 3800.00 62.15 303.50 2899.13 1063.97 -1607.42 6015501.81 555541.73 70 27 10.880 N 149 32 48.451W 3900.00 62.15 303.50 2945.85 1112.77 -1681.15 6015550.03 555467.64 70 27 11.359 N 149 32 50,617W 4000.00 62.15 303.50 2992.56 1161.57 -1754.88 6015598.26 555393.54 70 27 11.839 N 149 32 52.783W 4100.00 62.15 303.50 3039.28 1210.37 -1828.61 6015646.49 555319.45 70 27 12.319 N 149 32 54.949W 4200.00 62.15 303.50 3086.00 1259.17 -1902.34 6015694.72 555245.35 70 27 12.799 N 149 32 57.115W 4300.00 62.15 303.50 3132.71 1307.97 -1976.07 6015742.95 555171.26 70 27 13.279 N 149 32 59.281 W 4400.00 62.15 303.50 3179.43 1356.77 -2049.80 6015791.18 555097.16 70 27 13.758 N 149 33 1.447W 4500.00 62.15 303.50 3226.14 1405.57 -2123.53 6015839.41 555023.07 70 27 14.238 N 149 33 3.613W 4600.00 62.15 303.50 3272.86 1454.37 -2197.26 6015887.64 554948.97 70 27 14.718 N 149 33 5.779W 4700.00 62.15 303.50 3319.57 1503.17 -2270.99 6015935.87 554874.88 70 27 15.197 N 149 33 7.946W 4800.00 62.15 303.50 3366.29 1551.97 -2344.72 6015984.10 554800.78 70 27 15.677 N 149 33 10.112W 4900.00 62.15 303.50 3413.01 1600.77 -2418.45 6016032.33 554726.69 70 27 16.157 N 149 33 12.278W 5000.00 62.15 303.50 3459.72 1649.58 -2492.18 6016080.56 554652.59 70 27 16.637 N 149 33 14.444W 5100.00 62.15 303.50 3506.44 1698.38 -2565.91 6016128.79 554578.50 70 27 17.116 N 149 33 16.610W 5200.00 62.15 303.50 3553.15 1747.18 -2639.64 6016177.01 554504.40 70 27 17.596 N 149 33 18.777W 5300.00 62.15 303.50 3599.87 1795.98 -2713.37 6016225.24 554430.31 70 27 18.076 N 149 33 20.943W 5400.00 62.15 303.50 3646.59 1844.78 -2787.10 6016273.47 554356.21 70 27 18.555 N 149 33 23.109W 5500.00 62.15 303.50 3693.30 1893.58 -2860.83 6016321.70 554282.12 70 27 19.035 N 149 33 25.276W 5600.00 62,15 303.50 3740.02 1942.38 -2934.56 6016369.93 554208.02 70 27 19.515 N 149 33 27.442W 5706.90 62.15 303.50 3789.84 1994.77 -3013.31 6016421.71 554128.88 70 27 20,030 N 149 33 29.756W 5800.00 63.11 307.99 3832.66 2043.06 -3080.38 6016469.48 554061.45 70 27 20.504 N 149 33 31.727W 5900.00 64.29 312.71 3876.99 2101.09 -3148.66 6016526.98 553992.73 70 27 21.075 N 149 33 33.733W 6000.00 65.62 317.34 3919.33 2165.17 -3212.66 6016590.56 553928.26 70 27 21.705 N 149 33 35.614W 6100.00 67.09 321.87 3959.45 2234.93 -3271.98 6016659.86 553868.40 70 27 22.390 N 149 33 37.358W 6200.00 68.69 326.30 3997.10 2309.95 -3326.30 6016734.45 553813.52 70 27 23.128 N 149 33 38.954W 6300.00 70.40 330.62 4032.07 2389.78 -3375.28 6016813.90 553763.93 70 27 23.913 N 149 33 40.394W 6400.00 72.21 334.86 4064.13 2473.97 -3418.63 6016897.74 553719.94 70 27 24.741 N 149 33 41.669W 6500.00 74.11 339.01 4093.12 2562.01 -3456.11 6016985.48 553681.80 70 27 25.606 N 149 33 42.771W 6600.00 76.08 343.07 4118.85 2653.38 -3487.48 6017076.60 553649.72 70 27 26.505 N 149 33 43.694W 6700.00 78.13 347.07 4141.18 2747.54 -3512.57 6017170.56 553623.92 70 27 27.431 N 149 33 44.432W 6800.00 80.22 351.01 4159.96 2843.95 -3531.23 6017266.81 553604.52 70 27 28.379 N 149 33 44.982W 6900.00 82.37 354.90 4175.10 2942.03 -3543.34 6017364.78 553591.66 70 27 29.343 N 149 33 45.339W 7000.00 84.54 358.75 4186.50 3041.20 -3548.84 6017463.90 553585.40 70 27 30.319 N 149 33 45.502W 7100.00 86.75 2.57 4194.10 3140.88 -3547.69 6017563.57 553585.78 70 27 31.299 N 149 33 45.470W 7200.00 88.96 6.37 4197.85 3240.48 -3539.90 6017663.22 553592.81 70 27 32.279 N 149 33 45.242W 7216.45 89.33 7.00 4198.00 3256.87 -3537.92 6017679.63 553594.66 70 27 32.440 N 149 33 45.184W 7300.00 89.33 10.34 4198.98 3339.45 -3525.33 6017762.29 553606.62 70 27 33.252 N 149 33 44.816W 7400.00 89.33 14.34 4200.15 3437.11 -3503.96 6017860.11 553627.24 70 27 34.213 N 149 33 44.189W 7478.24 89.33 17.47 4201.07 3512.34 -3482.52 6017935.49 553648.10 70 27 34.953 N 149 33 43,560W 7500.00 89.33 17.47 4201.32 3533.09 -3475.99 6017956.29 553654.47 70 27 35.157 N 149 33 43.369W 7600.00 89.33 17.47 4202.49 3628.48 -3445.97 6018051.89 553683.75 70 27 36.095 N 149 33 42.488W 7700.00 89.33 17.47 4203.66 3723.86 -3415.95 6018147.49 553713.03 70 27 37.033 N 149 33 41.607W 7800.00 89.33 17.47 4204.83 3819.24 -3385.93 6018243.09 553742.32 70 27 37.971 N 149 33 40.726W BP Amoco Planning Report- Geographic Company: BP Amoco Field: Milne Point Site: M Pt G Pad Well: MPG-14 Wellpath: MPG-Jethro Survey Date: 6/26/2001 Time: 11:34:07 Page: 6 Co-ordinate(NE) Reference: Well: MPG-14, True North Vertical (TVD) Reference: Plan MPG-Jethro 61.0' 61.0 Section (VS) Reference: User (0.00N,0.00E,331.31Azi) Plan: MPG-Jethro wp02 Map Map <-- Latitude ----> <- MD Incl Azim TVD +N/-S +E/-W Northing Easting Deg Min Sec Deg fl deg deg ft ft ft ft ft 7870.29 89.33 17.47 4205.65 3886.28 -3364.81 6018310.29 553762.92 70 27 38.631 N 149 7900.00 89.66 16.64 4205.91 3914.68 -3356.10 6018338.75 553771.42 70 27 38.910 N 149 7930.03 90.00 15.81 4206.00 3943.51 -3347.70 6018367.64 553779.59 70 27 39.194 N 149 7936.46 90.19 15.81 4205.99 3949.70 -3345.95 6018373.84 553781.29 70 27 39.255 N 149 8000.00 90.19 15.81 4205.78 4010.84 -3328.64 6018435.10 553798.13 70 27 39.856 N 149 8100.00 90.19 15.81 4205.45 4107.05 -3301.39 6018531.52 553824.64 70 27 40.802 N 149 8200.00 90.19 15.81 4205.12 4203.27 -3274.15 6018627.93 553851.14 70 27 41.749 N 149 8300.00 90.19 15.81 4204.78 4299.49 -3246.90 6018724.34 553877.64 70 27 42.695 N 149 8400.00 90.19 15.81 4204.45 4395.70 -3219.66 6018820.76 553904.15 70 27 43.641N 149 8500.00 90.19 15.81 4204.12 4491.92 -3192.42 6018917.17 553930.65 70 27 44.588 N 149 8600.00 90.19 15.81 4203.79 4588.14 -3165.17 6019013.58 553957.15 70 27 45.534 N 149 8700.00 90.19 15.81 4203.46 4684.35 -3137.93 6019110.00 553983.66 70 27 46.481N 149 8800.00 90.19 15.81 4203.13 4780.57 -3110.68 6019206.41 554010.16 70 27 47.427 N 149 8900.00 90.19 15.81 4202.79 4876.78 -3083.44 6019302.82 554036.66 70 27 48.373 N 149 9000.00 90.19 15.81 4202.46 4973.00 -3056.19 6019399.24 554063.17 70 27 49.320 N 149 9100.00 90.19 15.81 4202.13 5069.22 -3028.95 6019495.65 554089.67 70 27 50.266 N 149 9200.00 90.19 15.81 4201.80 5165.43 -3001.70 6019592.06 554116.17 70 27 51.212 N 149 9300.00 90.19 15.81 4201.47 5261.65 -2974.46 6019688.48 554142.68 70 27 52.159 N 149 9400.00 90.19 15.81 4201.14 5357.87 -2947.21 6019784.89 554169.18 70 27 53.105 N 149 9419.52 90.19 15.81 4201.00 5376.62 -2941.81 6019803.68 554174.44 70 27 53.290 N 149 Longitude Min Sec 33 40.107 W 33 39.851 W 33 39.605W 33 39.553W 33 39.045W 33 38.246W 33 37.447W 33 36.648W 33 35.848W 33 35.049W 33 34.249W 33 33.450W 33 32.651 W 33 31.851 W 33 31.052 W 33 30.252 W 33 29.453 W 33 28.653W 33 27.853W 33 27.695W BP Amoco Anticollision Report Company: BP Amoco Field: Milne Point Reference Site: M Pt G Pad Reference Well: MPG-14 Reference Wellpath: MPG-Jethro Date: 6/26/2001 Time: 08:31:01 Page: 1 Co-ordinate(NE) Reference: Well: MPG-14, True North Vertical (TVD) Reference: Plan MPG-Jethro 61.0' 61.0 Db: Oracle GLOBAL SCAN APPLIED: All wellpaths within 200'+ 100/1000 of reference Reference: Principal Plan & PLANNED PROGRAM Interpolation Method: MD Interval: 25.00 ft Error Model: ISCWSA Ellipse Depth Range: 31.50 to 9419.52 ft Scan Method: Trav Cylinder North Maximum Radius: 1138.80 ft Error Surface: Ellipse + Casing Date: 4/14/2000 Validated: No Version: 9 Planned From To Survey Toolcode Tool Name 31.50 500.00 Planned: MPG-Jethro wp02 Vl CB-GYRO-SS Camera based gyro single shots 500.00 9419.52 Planned: MPG-Jethro wp02 V1 MWD+IFR+MS MWD + IFR + Multi Station Casing Points _.i ........ .............. ,,_ ........................ !n_,.,, .... ..... 7177.45 4197.46 7.000 8.750 7" ,.` .9.4 !.9_;.5 ! .... 42.0_1_._2_9 .... 4...50.0- ........... 6_.??_ .... 4.1/2'- Summary ............................................................................................ ._..___~_ .............................. ,_-_._-. ................................................................................................................ <,-- Offset Wellpath ~ ReferenCe Offset Ctr-Ctr No-Go . Allowable Site Well WellPati~ MD MD Distance Area Deviation Warning ff ff , ff ft ........................................................ .-, ......................... ~., ~.-..--.; --------~.,-----~.--. ................. .- ...... ~ ..... L----~--..=.----_.;.,..~,.-.~_ ........ ~ ........ ~ ............................................................................ M Pt G Pad MPG-04 MPG-04 V1 409.02 400.00 217.81 11.51 206.30 Pass: Major Risk M Pt G Pad MPG-05 MPG-05 V1 403.91 400.00 92.04 10.94 81.10 Pass: Major Risk M Pt G Pad MPG-06 MPG-06 V1 395.66 400.00 32.20 9.58 22.62 Pass: Major Risk M Pt G Pad MPG-07 MPG-07 V1 570.59 575.00 30.68 14.31 16.37 Pass: Major Risk M Pt G Pad MPG-08A MPG-08A V1 538.37 525.00 89.65 10.68 78.97 Pass: Major Risk M Pt G Pad MPG-08 MPG-08 Vl 538.37 525.00 89.65 10.68 78.97 Pass: Major Risk M Pt G Pad MPG-10 MPG-10 V4 2387.10 2700.00 372.72 78.64 312.21 Pass: Major Risk M Pt G Pad MPG-12 MPG-12V5 1022.33 1050.00 247.54 17.59 230.53 Pass: Major Risk M Pt G Pad MPG-13 MPG-13 V3 742.69 775.00 63.49 12.39 51.13 Pass: Major Risk M Pt G Pad MPG-15 MPG-15 V4 501.82 500.00 61.58 9.00 52.59 Pass: Major Risk M Pt J Pad MPJ-02 MPJ-02 V1 4727.46 4850.00 189.89 147.75 43.29 Pass: Major Risk M Pt J Pad MPJ-05 MPJ-05 V1 5831.42 5525.00 339.93 166.49 214.87 Pass: Major Risk M Pt J Pad MPJ-10 MPJ-10 V1 6269.43 4825.00 673.92 144.78 534.69 Pass: Major Risk M Pt J Pad MPJ-13 MPJ-13 Vl 6938.21 5425.00 338.30 195.61 147.11 Pass: Major Risk M Pt J Pad Plan MPJ-Jethro Plan MPJ-Jethro L1 Vl 9409.81 8225.00 67.65 0.00 67.65 Pass: NOERRORS M Pt J Pad Plan MPJ-Jethro Plan MPJ-Jethro V5 Pla 9397.24 8225.00 7.01 No Reference Casings Site: M Pt G Pad Well: MPG-04 Rule Assigned: Major Risk Wellpath: MPG-04 V1 Inter-Site Error: 0.00 fl: :,:' Ctr~" NO:GO Allowable ........... ........................ .............. ..... : .............................. Casing/,DistanCe :Area Deviation MD TVD MD TVD 'Ref ' Offset:TFo+AZI TrOtHS Warning ff ff ff ' = ":deg" deg::'; in i.ft:..' ff 'ff 31.50 31.50 19.00 19.00 0.00 0.00 159.26 159.26 215.62 0.66 214.97 Pass 37.50 37.50 25.00 25.00 0.01 0.05 159.26 159.26 215.62 0.90 214.73 Pass 62.50 62.50 50.00 50.00 0.07 0.10 159.24 159.24 215.64 1.49 214.15 Pass 87.50 87.50 75.00 75.00 0.13 0.14 159.21 159.21 215.68 2.02 213.65 Pass 112.50 112.50 100.00 100.00 0.20 0.25 159.16 159.16 215.74 2.81 212.93 Pass 137.50 137.50 125.00 125.00 0.29 0.38 159.09 159.09 215.81 3.72 212.09 Pass 162.50 162.50 150.00 150.00 0.37 0.48 159.02 159.02 215.89 4.53 211.37 Pass 187.49 187.49 175.00 174.99 0.46 0.56 158.93 158.93 215.99 5.28 210.71 Pass 212.49 212.49 200.00 199.99 0.53 0.66 158.83 158.83 216.10 6.04 210.05 Pass 237.49 237.49 225.00 224.99 0.58 0.79 158.73 158.73 216.20 6.82 209.38 Pass 262.48 262.48 250.00 249.98 0.64 0.89 158.62 158.62 216.30 7.55 208.75 Pass 287.48 287.48 275.00 274.98 0.69 0.98 158.50 158.50 216.39 8.25 208.14 Pass 312.10 312.10 300.00 299.97 0.74 1.09 158.36 214.86 216.49 8.95 207.55 Pass 336.34 336.34 325.00 324.97 0.77 1.21 158.21 214.71 216.68 9.66 207.02 Pass 360.57 360.57 350.00 349.96 0.81 1.32 158.03 214.53 216.96 10.33 206.63 Pass 384.80 384.80 375.00 374.95 0.85 1.42 157.83 214.33 217.33 10.98 206.35 Pass o7/24/Ol T[~ 05:31 FAX 9O7 $64 4441 BP A],JISI~ IIlIILONII &WELLS 001/003 TO: Jane Williamson DATE: 7/20/01 COMPANY: Alaska Oil and Gas Conservation Commission FAX: 276-7542 PHONE: FROM' James Franks FAX: (907).564-4441 , i At~a:eh,ed t"e: this ewer sheet, are d~awings ~:'the aPG-i:~:and; MPi;,11. ,,, aswa[ antbcom tethelm.. ,, ,i ,, ; , ,, ~ , , :,', ~,,, ~' ,~, , Thanks!~, ,, ~ , ,, PHONE: (907)564,.'.. 4468 Multilateral w~l,ls i i , JUL 2 4 200 ~,, ~ uas Co.s. C~ ~nchorag~ Number of attachments not includinc,! fax cover: 2 07/24/01 TT.T~, 05:31 FAX 907 $64 4441 TREE'. FMC Horlzonta! 3-1/8" SM I-'f-~UI--'t.)~t-LJ ~,UlVll-'E~- I IUl~i WELLHEAD: FMC Hot'iz~3nt31' 1 1', 5M tbg. he' FMC tog, hanger, 'H' BPV profile 20" 92 lb/ft. H-40 Weldea ~002/003 KI~, ELEV = 61' Ccllar Box ELEV = 29.5' 2-7/6" x 1" Gas Lift Mandrel [ 1 $0' 2-7/8", 6.3 lb/fi, L-80, EUE-M Coupling OD: 3.5" Drift/ID' 2.347"/2.441" 2-718" x 1" Gas Lift Mandrel X Nipple 2.313" ID 7", 26#, L-80, BTC-M Casing Drift: 6,151" Casing ID: 6.276" Baker Hughes Hook Hanger system Window in 7" casing @ 6496' Well Inclination @ Window = 74 Degrees Baker Hughes Conventional Hanger 7" Casing Shoe @ 7018' Well inclination @ Shoe = 90 Degrees ,Centdlift Electric Submersible Pump [ 5650' Centrillff Pressure Gauge [ $700' ] ion, ! 6496' I OA Horizontal 6-1/8" DA Lateral TD [ 9430' 4-'1/2" Slotted Liner and Hook Hanger 6-1/8" OB Lateral TD J 94 4-1/2" Slotted Liner & Hanger DATE 712012001 .. REV. BY COMMENTS Jamea Franka L~v¢l 3 Multi-kataral, 2-718" ESP Cempletion Mllne Point Unit WELL: MPG-14 APl NO: BP Exploration (Alaska) TREE: FMC Horizontal 3-1/8" 5M WELLHEAD: FMC Horizontal 11", 5M tbg. headx, 11" x 3-1/2", EUE (btm) FMC tbg. hanger, 'H' BPV profile I 1 1 0' 20" 92 lb/ft. H-A0 Welded 7", 26#, L-80, BTC-M Casing Drift: 6.151" Casing ID: 6.276" Baker Hughes Hook Hanger system IWindow in 7" casing @ 6496' Well Inclination @ Window = 74 Degrees Baker Hughes Conventional Hanger 7" Casing Shoe @ 7177' Well Inclination @ Shoe = 90 Degrees PROPOSED COMPLETION ~i¢~'' MPG-14 & G-14 LI"- KB. ELEV = 61' Cellar Box ELEV = 29.5' 2-7/8", 6.3 Ib/ft, L-80, EUE-M Coupling OD: 3.5" Drift/ID' 2.347"/2.441" ction ] .649_.~6' OA Horizontal ~ 6-1/8" OA Lateral TD 4-1/2" Slotted Liner and Hook Hanger 9430' ~ ~,.,, OB Horizontal 6-1/8" OB Lateral TD I 9419' I 4-1/2" Slotted Liner & Hanger l II DATE REV. BY COMMENTS 6/2612001 James Franks Level 3 Multi-Lateral. 2-718" ESP Completion Milne Point Unit WELL: MPG-14 APl NO: BP Exploration (Alaska) TREE FMC Horizontal 3-1.~e' 5M PROPOSED COMPLETION ~,EL~E^o,.c. ...... .a.,,',..b0. h., MPG'14 & O'14 L1 11' x 3-152'. EUE (btm) ~ ~ ~. Cellar Box ELEV: 29 5' FMC lbg hanger. 'H' BPV profile I110' I 2o-921b,,...~OWe,Oe~ ~l , ' 2-7/8",6.3 lb/fl, L-80, EUE-M ' Coupling OD 3 5" I Drift/ID 2 347"/2.44 1" Il' ' 2'7/8" x 1" Gas Lift Mandrel 15600'1 I I i X Nipple 2.313" ID ~ Centrilill Electric Submersible Pump I 5650' Casing Drift: 6,151" Casing ID: 6.276" i i I M ulti-Late ral J un ctio n I .4o.'1 Baker Hughes Hook Hanger system < I Well Inclination ~ Window = 74 Degrees < OA Horizontal 8-1/8" OA Latera TD I 9430' I ~ 4-1/2" Slotted Liner and Hook Hanger i i Baker Hughes Conventional H ~ ~ Well Inclination @ Shoe = 90 Ufigrees I [ I ~ OB Horizontal ~ 6-118"OB LateralTD 4-1/2" Slotted Liner & Hanger I 9419' I DATE REV. BY COMMENTS nil: WELL: MPG-14 T/20Y2001 James Franks Level3 Multi.Lateral, 2.7/8" ESP Completion APl NO: BP Exploration (Alaska) RECEIVED JUL ~ 0 ?001 , Alaska Oil & Gas Cons. Commission Anchorage ORIGINAL I DATE I ~ CHECK NO. H 191152 VENDOR ALltSKAOILA O0 DATE INVOICE / CREDIT MEMO DESCRIPTION GROSS DISCOUNT NET )&0101 CKO6OIO1H lO0. O0 100. CO PYMT COMMENTS: PERMIT TO DRILL FEE HANDLINO INST: S/H - TERRIE HUBI~LE X4628 E ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. i Eli W!~ I ] 100. O0 1 O0 ._00 BP EXPLORATION, (ALASKA)INC; RO, BOX 196612 ANCHOFIAGE, ALASKA 99519-6612 :~AY Fo Th e ]RDER RRST NA~ONAL'' ~ANK OF ASHLAND AN AFFILIATE OF NATIONAL CITY BANK CLEVELAND, OHIO 56-389 412, ONE' ':"hUNDRED & OO/1.******************** 333 WEST 7TH AVENUE SUITE 100 ANCHORAGE AK V~501 C AL ACCOUNT 1 m:O h ;~ ~0 :iR ~ 5': CHECK 1 CHECK WHAT APPLIES STANDARD LETTER DEVELOPMENT / DEVELOPMENT REDRILL EXPLORATION INJECTION WELL INJECTION WELL REDRILL ADD-ONS (OPTIONS) MULTI LATERAL (If api number last two (2) digits are between 60-69) PILOT HOLE (PH) ANNULAR D~POSAL ( ~/~ NO ANNULAR DISPOSAL ( ) YES ANNULAR DISPOSAL THIS WELL DISPOSAL INTO OTHER ANNULUS ( ) YES + SPACING EXCEPTION "CLUE" The permit is for a new welibore segment of existing well , Permit No, ~ APl No. __. Production should continue to be reported as a function of the original APl number stated above. In accordance with 20 AAC 25.005(0, all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 -70/80) from records, data and logs acquired for well (name on permit). Annular disposal has not been requested... Annular Disposal of drilling wastes will not be approved... Annular Disposal of drilling wastes will not be approved... Please note that an disposal of fluids generated... Enclosed is the approved application for permit to drill the above referenced well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) will assume the liability of any protest to the spacing exception that may occur. Templates are located m drive\jody\templates WELL PERMIT CHECKLIST FIELD & POOL ~,~"?-~-'-/ ADMINISTRATION 1. 2. COMPANY , Permit fee attached ....................... Lease number appropriate.",~ ................. Unique well name and number .................. Well located in a defined pool .................. . 4. 5. Well located proper distance from ddlling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available' in ddlling unit ............ 8. If deviated, is wellbore plat included ..... : ....... · · · 9. Operator only affected party ............... · .... 10. Operator has appropriate bond in force .... · ......... 11. Permit can be issued without conservation order ........ 12. Permit can.be issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... PROGRAM:exp GEOLAREA dev ~/' reddl serv wellbore sag ann. disposal para req (~N UNIT# 0-0,~/_~.~~ ON/OFF SHORE 14. Conductor string.provided .................... 15. Surface casing protects all known USDWs ............ Y N ,~'~.e,~.L)-c,.-,~, ~ '~ O..~,~ '~'--~"~ ..- '-?. -. - 16. CUT vol adequate to circulate on conductor & surf csg. .... ~-'~N 17. CMTvol adequate to.tie-in long string tosurfcsg. (.~ N (. 18. CMTwillcoverallknownproductivehorizons. ' ' ~'-J~l 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. Y N 21. Ifare-drill, has a l0-403 for abandonment been approved. . . ' ~ ,~ ~ 22. Adequate wellbore separation proposed ....... : ...... 23. If diverter required, does it meet regulations .......... (~i ,~ ~_.~ ,~, , , ~ ~' 24. Drilling.fluid program schematic & equip list adequate.. ~ . . ~'~ 25. BOPEs, do they meet regulation . . . . .~ ~× ;. ........ .-._ II AIRPI~ DATF__/ 26. BOPE press rating appropriate; test to -'.'.'~C~ ~ c~ psig. (~, I1~ U~ 27. Choke manifold complies w/APl RP-53 (May 84) ..... Y I)J , fi ' IJ~., ~"~ ' 28. Work will occur without operation shutdown ..... ~ . .... Y II [;)-~ 2~. is presence of H2S gas probable ................. Y II~G"~'~'-- ~.. Permit can be issued wlo hydrogen sulfide measures ...... (~ N~''~'' ,_. '_~ ~ --~ /~4.o ,~.~-,,?_ /~-z~.4.~?:..,.,/~., ~..~"..- II 31. Data presented on potential overpressure zones ....... . ~ '] ~ ' 32. Seismic analysis of shallow gas zones... ......... .jv//~ Y N ~ . . I AP~R D_ATE / 33. seabed condition survey (if off-shore)..': ...... ~ Y N I /~ 7. ~/ 34. Contact name/phone for weekly progress reports [ex.oratory only] Y N ' ' ANNULAR DISPOS.A.L.35. With proper cementing records, this plan . -- (A) will contain waste in a suitable receiving zone; ..... "q,.L Y N '~(.,../~//...~ APPR DATE . (B) will not contaminate freShwater; or cause drilling waste...~"---~..Y.~ N "/ . to surface; , " ' ' ~ (C) will not impair mechanical integrity of the well used for disposal; Y' N (D) will not damage producing formation or impair recovery from a Y N ~ ' . pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N ~. GEOLOGY: ENGINEERING: ' UlClAnnular COMMISSION: Comments/Instructions: , Z ,-I -r c:Vnsoffice\wordian~diana\checklist (rev. 11101//00)