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Home My WebLink About196-070Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241205 Well API #PTD #Log Date Log Company Log Type AOGCC ESet AN 15(GRANITE PT ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24 MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Please include current contact information if different from above. T39808 T39809 T39810 T39810 T39811 T39812 T39813 T39813 T39814 T39815 T39816 T39817 T39818 T39819 T39820 T39820 T39821 T39822 T39823 T39823 T39823 T39823 T39824 T39825 T39826 T39827 MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.05 14:52:46 -09'00' 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 3,385'None Casing Collapse Conductor N/A Surface 3090 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: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 Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 Perforation Depth MD (ft): See Schematic See Schematic 5-1/2" (2) HES Versatrieve & HES BWD Sump and N/A 2,439 MD/ 2,137 TVD, 2,982 MD/ 2,547 TVD & 3,274 MD/ 2,812 TVD and N/A N/A 57502,885'3,363' 82' 20" 9-5/8"3,334' Length Size Proposed Pools: 112' 112' 17# / L-80 / Mod IBT TVD Burst 2,339' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 196-070 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22673-00-00 Hilcorp Alaska LLC N/A AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 10/15/2024 Water Source Well 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 F-02 MILNE POINT TERTIARY UNDEF WTRSP 2,903' 3,277' 2,815' 644 None No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:26 pm, Sep 23, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.09.23 11:37:05 - 08'00' Taylor Wellman (2143) 324-548 * BOPE pressure test to 2500 psi. MGR03OCT2024 10-404 DSR-9/27/24SFD 10/4/2024JLC 10/4/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.07 13:47:46 -08'00' 10/07/24 RBDMS JSB 100824 Well: MPF-02 PTD: 196-070 API: 50-029-22673-00-00 Well Name:MPF-02 API Number:50-029-22673-00-00 Current Status:Shut-in WSW Rig:ASR #1 Estimated Start Date:10/15/2024 Estimated Duration:4 days Regulatory Contact:Tom Fouts Permit to Drill Number:196-070 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 842 psi @ 1,982’ TVD 9/17/2017 | 8.2 EMW, 8.8 KWF Max Potential Surface Pressure: 644 psi Gas Column Gradient (0.1 psi/ft) Max Angle: 40° Sail Angle from 1,747’ MD Brief Well Summary: MPU F-02 was drilled in May 1996 and completed with a gravel pack in August 1996 as a Tertiary Prince Creek water source well. The well has had multiple ESPs installed: August 1996 (initial), October 1996, October 1997, January 1998, May 1998, February 2007, and November 2012 (hanger and penetrator only). The ESP has failed. Objectives: Pull failed ESP completion, run new ESP completion. Notes Regarding Wellbore Condition: - 7” casing test to 2,000 psi on 3/13/2016 at 2,360’ MD. Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,000psi high. 2. Drift and tag with sample bailer. 3. Caliper from 2,250’ MD to surface. 4. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 8.8# Brine down tubing, taking returns up casing to 500 barrel returns tank. Bullhead down tbg and IA taking returns to formation as needed to establish and maintain a full column of 8.8# Brine. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) Well: MPF-02 PTD: 196-070 API: 50-029-22673-00-00 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with 8.8# Brine prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,000 psi high. Test 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. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 3-1/2” test joint. e. Test 5-1/2” ram on 5-1/2” test joint. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with 8.8# Brine as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spoolers to handle ESP cable. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Hanger is 11”x 4.5” TCII top and btm. b. 2016 tubing PU weight on ASR #1 recorded as 45 kip. Slack off weight recorded as 32 kip. c. 5-1/2” 17# L-80 Mod IBT yield is 397 kip. MU torque was 7100ft-lbs 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 5-1/2”. a. Reuse all tubing based on Caliper results b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 59 ii. Protectolizers: 2 10. Lay Down ESP. If the ESP comes out clean, then go straight to the test packer run. 11. PU and RIH with 7” test packer to 2,360’ MD. 12. Test 7” casing to 1,500 psi for 30 minutes. 13. POOH with test packer. 14. RIH with used 5-1/2” 17# L-80 ESP completion to +/- 2,350’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per Baker, and cross coupling clamps every other joint Charted and recorded. - mgr Well: MPF-02 PTD: 196-070 API: 50-029-22673-00-00 Nom. Size Length Item Lb/ft Material Notes 8.5 2 Centralizer 4 7.25 34 Motor - 800HP 80 6.75 7 Lower Tandem Seal 38 6.75 7 Upper Tandem Seal 38 6.75 15 Pumps –52 6.75 15 Pumps –45 6.75 1 Ported Discharge Head 13 L-80 5-1/2” 2,200 5-1/2" Mod IBT 6.5 L-80 5-1/2” 10 Space out pup 6.5 L-80 5-1/2” 40 5-1/2" Mod IBT 6.5 L-80 5-1/2” 40 Tubing Hanger with XO 4.5” x 5.5” 6.5 L-80 15. Land tubing hanger. Use extra caution to not damage cable. 16. Lay down landing joint. 17. Set BPV. 18. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Triple BOPE Schematic _____________________________________________________________________________________ Revised By: PC 07/13/2018 SCHEMATIC Milne Point Unit Well: MPU F-02 Last Completed: 03/13/2016 PTD: 196-070 TD = 3,385’ (MD) / TD = 2,903’(TVD) 20” Orig. DF Elev.: 41.25 (N 22E)/ GL Elev.: 12.0’ RDF to 9-5/8” landing ring = 29.2’ 7 9 10 11 12 13 15 14 3 & 4 16 17 9-5/8” 5& 6 PBTD = 3,277’(MD) / PBTD = 2,815’(TVD) 8 r 1 2 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 91.1# / H-40 / N/A N/A Surf 113' 0.355 9-5/8" Surface 40# / L-80 / Btrc. 8.679 Surf 3,363’ 0.0759 TUBING DETAIL 5-1/2" Tubing 17# / L-80 / Mod Btrc 4.767” Surf 2,339’ 0.0233 JEWELRY DETAIL No Depth Item 1 2’ XO: 4.5” TCII Pin X 4.5” BTC Pin –Min ID= 3.958” 2 2,250’ Discharge Head: HPDIS/Attached-PMP 3 2,258’ Pump: 29HC12500 / HPHVMAR 4 2,272’ Pump w/ Integral Intake: 29HC12500 / HPHVLAR 5 2,287’ Upper Tandem Seal: HSB3DB UT M FER SB/SB PFSA 6 2,295’ Lower Tandem Seal: HSB3DB LT M FER SB/SB PFSA 7 2,302’ Motor CL5: HMI – 800HP/ 4,225V/ 114A 8 2,337’ Centralizer:Btm @ 2,339’ 9 2,439’ 9-5/8” HES Versatrieve pkr. 10 2,464’ 5-1/2”, 20 ppf, N-80, LTC blank pipe (ID = 4.778”) 11 2,560’ 5-1/2”, 0.012” Ga.Pre-pack screen (ID = 4.778”) 12 2,773’ 5-1/2”, 0.012” Ga. Screen (ID = 4.778”) 13 2,982’ 9-5/8” HES Versatrieve pkr. 14 2,999’ 5-1/2”, 20 ppf, N-80, LTC blank pipe (ID = 4.778”) 15 3,025’ 5-1/2”, 0.012” Ga.Pre-pack screen (ID = 4.778”) 16 3,180’ 5-1/2”, 0.012” Ga. Screen (ID = 4.778”) 17 3,274’ HES 9-5/8” ‘BWD’ sump pkr. PERFORATION DETAIL Ref log: GR/CCL 8/13/96 Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status Prince Creek “A” 2,574’ 2,624’ 2,246’ 2,287’ 49 Open Prince Creek “A” 2,704’ 2,764’ 2,351’ 2,399’ 60 Open Prince Creek “B” 2,780’ 2,894’ 2,415’ 2,503’ 114 Open Prince Creek “B/C” 2,914’ 2,964’ 2,519’ 2,560’ 50 Open Prince Creek “C” 3,034’ 3,149’ 2,616’ 2,710’ 115 Open Prince Creek “D” 3,234’ 3,264’ 2,779’ 2,804’ 30 Open 4.5” 12 SPF 26 gm. Jumbo Jet charges @ 135/45 deg. Phasing (w/0.74” EHD and 5.8” TTP) GENERAL WELL INFO API: 50-029-22673-00-00 Drilled and Cased by Nabors 22E - 5/11/1996 Gravel Pack Completion/ESP by Nabors 4ES – 8/96 ESP RWO w/ Nabors 4-ES – 10/96, 10/97, & 1/98 ESP RWO changeout ESP w/ Nabors 5S 5/98 ESP RWO changeout ESP by Nabors 3S Repair failed WH penetrator w/ Doyon 16 – 11/2012 ESP Changeout by ASR#1 – 3/13/2016 GRAVEL PACK SUMMARY Upper Zone – 8/16/96 – Est. 13,200 lbs. of 20-40 Carbolite Lower Zone – 8/14/96 – Est. 3,800 lbs. of 20-40 Carbolite Minimum gravel pack restriction = 2.97” safety shear sub @ 2,459’ & 2,995’ TREE & WELLHEAD Tree CIW 4-1/6” 5M ‘FLS’ Wellhead 11”x 12” 5M FMC Gen 6 Unibore w/ two 2” 5M valves on side ports 11” 5M x 4-1/8” 5M adapter and 11” x 4-1/2” Tbg Hgr 4.5” TC-II threads top and bottom and 4” CIW-H DEVIATION DETAIL KOP @ 200’ Max Hole Angle = 40° @ 1,750’ Hole Angle through perfs. = 36° DLS > 4°/100’ @ 710’ and 1,000’ OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I (Approx.) in 24” Hole 9-5/8" Cmt w/ 750 sks PF “E”, 500 sx Class “G”, 150 sx PF “E” in 12-1/4” _____________________________________________________________________________________ Revised By: TDF 9/20/2024 PROPOSED Milne Point Unit Well: MPU F-02 Last Completed: 03/13/2016 PTD: 196-070 TD =3,385’ (MD) / TD = 2,903’(TVD) 20” Orig. DFElev.:41.25 (N 22E)/ GL Elev.: 12.0’ RDF to 9-5/8” landing ring = 29.2’ 7 9 10 11 12 13 15 14 3 & 4 16 17 9-5/8” 5& 6 PBTD = 3,277’(MD) / PBTD =2,815’(TVD) 8 r 1 2 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 91.1# / H-40 / N/A N/A Surf 113' 0.355 9-5/8" Surface 40# / L-80 / Btrc. 8.679 Surf 3,363’ 0.0759 TUBING DETAIL 5-1/2" Tubing 17# / L-80 / Mod Btrc 4.767” Surf 2,339’ 0.0233 JEWELRY DETAIL No Depth Item 1 ±x’ XO: 4.5” TCII Pin X 4.5” BTC Pin – Min ID= 3.958” 2 ±X,XXX’ Discharge Head: 3 ±X,XXX’ Pump: 4 ±X,XXX’ Pump: 5 ±X,XXX’ Upper Tandem Seal: 6 ±X,XXX’ Lower Tandem Seal: 7 ±X,XXX’ Motor: 8 ±X,XXX’ Centralizer: Btm @ ±X,XXX’ 9 2,439’ 9-5/8” HES Versatrieve pkr. 10 2,464’ 5-1/2”, 20 ppf, N-80, LTC blank pipe (ID = 4.778”) 11 2,560’ 5-1/2”, 0.012” Ga.Pre-pack screen (ID = 4.778”) 12 2,773’ 5-1/2”, 0.012” Ga. Screen (ID = 4.778”) 13 2,982’ 9-5/8” HES Versatrieve pkr. 14 2,999’ 5-1/2”, 20 ppf, N-80, LTC blank pipe (ID = 4.778”) 15 3,025’ 5-1/2”, 0.012” Ga.Pre-pack screen (ID = 4.778”) 16 3,180’ 5-1/2”, 0.012” Ga. Screen (ID = 4.778”) 17 3,274’ HES 9-5/8” ‘BWD’ sump pkr. PERFORATION DETAIL Ref log: GR/CCL 8/13/96 Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status Prince Creek “A” 2,574’ 2,624’ 2,246’ 2,287’ 49 Open Prince Creek “A” 2,704’ 2,764’ 2,351’ 2,399’ 60 Open Prince Creek “B” 2,780’ 2,894’ 2,415’ 2,503’ 114 Open Prince Creek “B/C” 2,914’ 2,964’ 2,519’ 2,560’ 50 Open Prince Creek “C” 3,034’ 3,149’ 2,616’ 2,710’ 115 Open Prince Creek “D” 3,234’ 3,264’ 2,779’ 2,804’ 30 Open 4.5” 12 SPF 26 gm. Jumbo Jet charges @ 135/45 deg. Phasing (w/0.74” EHD and 5.8” TTP) GENERAL WELL INFO API: 50-029-22673-00-00 Drilled and Cased by Nabors 22E - 5/11/1996 Gravel Pack Completion/ESP by Nabors 4ES – 8/96 ESP RWO w/ Nabors 4-ES – 10/96, 10/97, & 1/98 ESP RWO changeout ESP w/ Nabors 5S 5/98 ESP RWO changeout ESP by Nabors 3S Repair failed WH penetrator w/ Doyon 16 – 11/2012 ESP Changeout by ASR#1 – 3/13/2016 GRAVEL PACK SUMMARY Upper Zone – 8/16/96 – Est. 13,200 lbs. of 20-40 Carbolite Lower Zone – 8/14/96 – Est. 3,800 lbs. of 20-40 Carbolite Minimum gravel pack restriction = 2.97” safety shear sub @ 2,459’ & 2,995’ TREE & WELLHEAD Tree CIW 4-1/6” 5M ‘FLS’ Wellhead 11”x 12” 5M FMC Gen 6 Unibore w/ two 2” 5M valves on side ports 11” 5M x 4-1/8” 5M adapter and 11” x 4-1/2” Tbg Hgr 4.5” TC-II threads top and bottom and 4” CIW-H DEVIATION DETAIL KOP @ 200’ Max Hole Angle = 40° @ 1,750’ Hole Angle through perfs. = 36° DLS > 4°/100’ @ 710’ and 1,000’ OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I (Approx.) in 24” Hole 9-5/8" Cmt w/ 750 sks PF “E”, 500 sx Class “G”, 150 sx PF “E” in 12-1/4” Updated 3/10/2020 11” BOPE INTEGRATED 11'͛-5000 INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind 11'͛- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManual 5-1/2" Pipe Ram Milne Point ASR 11” BOP w/ Jacks 05/17/2017 Milne Point ASR 11” BOP (Triple) 3/10/2020 STATE OF ALASKA ' ALA KA OIL AND GAS CONSERVATION COMAION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon Li Plug Perforations Fracture Stimulate Pull Tubing ✓I Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program E Plug for Redrill ❑ =rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 7 Other: ESP Change-out Q 2. Name: 4.Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska LLC Development ❑ Exploratory ❑ 196-070 3.Address: Stratigraphic❑ Service ❑✓ 6.API Number: !RECEIVED 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-22673-00-00 7, Property Designation(Lease Number): 8.Well Name and Number: APR 0 7 ZU16 ADL 025509 MILNE PT UNIT TER F-02 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): AOG V( N/A Milne Point Unit/Tertiary Undefined WTRSP w 11.Present Well Condition Summary: Total Depth measured 3,385 feet Plugs measured N/A feet true vertical 2,903 feet Junk measured N/A feet 2,439,2,982& Effective Depth measured 3,277 feet Packer measured 3,274 feet 2,137,2,574& true vertical 2,815 feet true vertical 2,812 feet Casing Length Size MD TVD Burst Collapse Conductor 82' 20" 112' 112' N/A N/A Surface 3,334' 9-5/8" 3,363' 2,885' 5,750psi 3,090psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 5-1/2" 17#/L-80/Mod Btrc 2,339' 2,057' (2)HES Versatrieve Packers and SSSV(type,measured and true vertical depth) HES BWD Sump N/A See Above N/A 12.Stimulation or cement squeeze summary: N/A 2 Intervals treated(measured): N/A 'j CANNED APR 0 2�y 16 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 10,800 60 2,416 Subsequent to operation: 0 0 10,000 0 2,115 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑ Exploratory❑ Development❑ ServiceL Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Li Gas) ( WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WTRSF0 WAGE] GIVJF SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A 'C.O. Exempt: u�.j , ----:3316-004&316-130 Contact Paul Chan \.. Email pchan(a�hilcorp.com Printed Name Bo York Ck,,..J I .,,,c, Title Operations Manager Signature i-liJ Phone 777-8345 Date 4/5/2016 LI-13`/x' Form 10-404 Revised 5/2015 A ` `3 /(�RBDMS U - APR 1 1 2016 Submit Original Only • • • Milne Point Unit SCHEMATIC Well: MPU F-02 • Last Completed: 11/24/2012 Haan")Alaska,LLC PTD: 196-070 Orig.DF Elev.:41.25(N 22E)/GL Elev.:12.0 TREE&WELLHEAD RDF to 9-5/8"landing ring= '.2' Tree CIW 4-1/6"5M'FLS' 41 r1 41 11"x 12"5M FMC Gen 6 Unibore w/two 2"5M valves on 0.f Wellhead side ports 11"5M x 4-1/8"5M adapter and 11"x 4-1/2" 20' v jo Tbg Hgr 4.5"TC-II threads top and bottom and 4"CIW-H ,Ad OPEN HOLE/CEMENT DETAIL 20" Cmt w/250 sks of Arcticset I(Approx.)in 24"Hole 9-5/8" Cmt w/750 sks PF"E",500 sx Class"G",150 sx PF"E"in 12-1/4" 4 CASING DETAIL ti" Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20" Conductor 91.14/H-40/N/A N/A Surf 113' 0.355 I 9-5/8" Surface 40#/L-80/Btrc. 8.679 Surf 3,363' 0.0759 TUBING DETAIL il 1 5-1/2" Tubing 174/L-80/Mod Btrc 4.767" Surf 2,339' 0.0233 s JEWELRY DETAIL DEVIATION DETAIL 1x y KOP @ 200' ; No Depth Item Max Hole Angle=40°@ 1,750' 11 rz 1 2' X0:4.5"TCII Pin X 4.5"BTC Pin-Min ID=3.958" Hole Angle through perfs.=36° ii 2 2,250' Discharge Head:HPDIS/Attached-PMP >4°/100'@ 710'and 1,000' 3 2,258' Pump:29HC12500/HPHVMAR DLS IA 4 2,272' Pump w/Integral Intake:29HC12500/HPHVLAR 5 2,287' Upper Tandem Seal:HSB3DB UT M FER SB/SB PFSA 6 2,295' Lower Tandem Seal:HSB3DB LT M FER SB/SB PFSA 7 2,302' Motor CL5:HMI-800HP/4,225V/114A 44 2 8 2,337 Centralizer:Btm @ 2,339' 9 2,439' 9-5/8"HES Versatrieve pkr. it 110 2,464' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") 11 2,560' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") t 12 2,773' 5-1/2",0.012"Ga.Screen(ID=4.778") ic,+ 2 =l 13 2,982' 9-5/8"HES Versatrieve pkr. 14 2,999' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") 1. 3&4 ' 15 3,025' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") 16 3,180' 5-1/2",0.012"Ga.Screen(ID=4.778") III ° 17 3,274' HES 9-5/8"'BWD'sump pkr. Ns grp 5&6 PERFORATION DETAIL Ref log:GR/CCL 8/13/96 1 vt Sands Top(MD) Btm(MD) Top(ND) Btm(ND) FT Status Prince Creek"A" 2,574' 2,624' 2,246' 2,287' 49 Open Prince Creek"A" 2,704' 2,764' 2,351' 2,399' 60 Open $ 8 Prince Creek"B" 2,780' 2,894' 2,415' 2,503' 114 Open 0 Prince Creek"B/C" 2,914' 2,964' 2,519' 2,560' 50 Open Prince Creek"C" 3,034' 3,149' 2,616' 2,710' 115 Open Prince Creek"D" 3,234' 3,264' 2,779' 2,804' 30 Open e "`:"' ' 9 4.5"12 SPF 26 gm.Jumbo Jet charges @ 135/45 deg.Phasing(w/0.74"EHD and 5.8"TTP) ss GRAVEL PACK SUMMARY Upper Zone-8/16/96-Est.13,200 lbs.of 20-40 Carbolite Lower Zone-8/14/96-Est.3,800 lbs.of 20-40 Carbolite 13 Minimum gravel pack restriction=2.97"safety shear sub @ 2,459'& 2,995' j :: GENERAL WELL INFO API:50-029-22673-00-00 11.: Drilled and Cased by Nabors 22E -5/11/1996 1.ir Gravel Pack Completion/ESP by Nabors 4ES-8/96 t _ 17 ESP RWO w/Nabors 4-ES-10/96,10/97,&1/98 4 '3 ESP RWO changeout ESP w/Nabors 5S 5/98 9-5/8 affeffatfttrAINefftftitta ESP RWO changeout ESP by Nabors 3S Repair failed WH penetrator w/Doyon 16-11/2012 TD=3,385'(MD)/TD=2,903'(TVD) ESP Changeout by ASR#1-3/13/2016 PBTD=3,277'(MD)/PBTD=2,815'(TVD) Revised By:TDF 3/16/2016 • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP F-02 ASR#1 50-029-22673-00-00 196-070 3/8/16 3/13/16 Daily Operations: 3/9/2015 -Wednesday Move Mud Pit module from A pad to MPF-02 and spot on well. Raise Derrick, Move Company Man Trailer& Crew change house & set in place. Rig up Generator for Well site trailer. Install Koomey lines and circulating lines to Rig and heat trace and insulate.Troubleshoot Proxy sensor on Derrick pins, sensor is showing a fault, Pinned Upper Section of Derrick. Continued Rigging up Rig Modules, Received 35 bbl Fresh Water for Testing. Rig up 5.5 Handling Equipment. Pull BPV Install TWC Valve. Function Test Bop Stack Close/Open Blind Rams, Install Test Joint Function Test pipe Rams &Annular, Check Accumulator Hydraulic Reservoir Level Prior to Testing. 3/10/2015-Thursday Continue Rigging up on MPF-02. Move in extra heaters to warm BOP house. Rig up For BOP Test.Test BOPs 250 psi. Low/2500 psi high,Test Annular to 250psi low/1,500psi high. Tested H2s & Methane alarms Jeff Jones AOGCC Rep. witnessed test. Blow down lines & Rig down Test equipment. Received 280 bbl. 8.7 ppg Filtered Brine in the Active System, P/U Tee Bar Open IA Valve Pulled TWC Valve. Closed Blind Rams Pump 1 Tbg Volume with a Pump Rate 190 stks @ 993psi with 52 bbl pump away, have returns at 10 bbls pumped. Blow Down lines. Pick up 2-7/8" Landing Joint & XO Sub RIH Screw into Hanger, BOLDS Open IA Psi=0 Pulled Hanger @ 50k Free Pull 46k Pulled Hanger to the Rig Floor Break out and Lay down Landing Joint and Hanger. Install TIW Valve in TBG. Hung Elephant Trunk &Sheave for ESP Cable, Waiting on ESP Spooler& Generator, Clean Organize Rig & Location. TOOH Laying Down 5.5 TBG and ESP, Currently @ 1,700'. 3/11/2015- Friday Service Rig & Check fluid levels on equipment. Continue to TOOH laying down 5.5" Production String. Lay down ESP Assembly. Removed 5.5 Production String From Pipe Racks, Clear& Clean Rig floor, Prep Equipment for 3.5" work string. Check Fluid levels on Rig equipment, Load &Tally 3.5" work string. Strap &Tally 9-5/8" Casing Scraper. Pick up 9-5/8" Casing Scraper Assembly with 8.5" Bladed Mill &XOs.TIH with 9-5/8" Casing Scraper& 3.5 CS Hydrill Pipe to 2,400 ft. Change out Hydraulic Filter on Rig Carrier Filter had a leaking 0-Ring, Retrieved New Filter From VMS Shop & Installed. Circulate Bottoms up X 1 Pump Rate 3BPM @ 70psi. POOH Lay down 3.5 CS HYDRILL Work string, currently @ 1,400'. 3/12/2015 -Saturday Service Rig & Check Fluid levels on Equipment. Continue to TOOH laying down 3.5" Work String. Break& lay down BHA. Make up Halliburton RTTS Packer with Circulating Valve. Trip in the Hole with Test Packer on 3.5" Work String to 2,360'. Set • RTTS per Halliburton Rep. Center of Element @ 2,356'. Fill wellbore with 8.7 Filtered brine. Close VBRs,Test casing to 2,000psi 30 min Charted(Good Test) Bleed Pressure off, open VBRs, Release RTTS per Halliburton Rep.TOOH, Lay down 3.5" Work string & Halliburton RTTS. Service Rig& Check Fluid levels on Equipment. Load ESP Pump & 5.5 Completion String onto Pipe Rack. Prejob Safety Meeting with Rig Crew, Cody Centrilift, CO,Man on Lifting Heavy ESP Pump Assembly to Rig Floor& Make up, ( Max Pump wt. 5,000Ibs use of a Hyd Tugger to Help Assist while Hoisting pump to the Rig Floor, Hazards Hand Placement, Pinch Points, Caught in between, Stay Clear and Dont Stand under over Head Loads. Make up & Service ESP Pump Assembly, (New Discharge Head had the wrong connection on the Pup joint for Discharge head, Removed Pup from old Assembly and made up to Discharge head), Tally & Pull Old Seal Rings From 5.5" Completion String. r S Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP F-02 ASR#1 50-029-22673-00-00 196-070 3/8/16 3/13/16 Daily Operations: 3/13/2015-Sunday Service Rig, Check Fluid levels on all Equipment.;Trip in the hole with ESP ASSY. & 5.5" IBT Production string Test Cable every 500'. Make up Hanger& Landing JT Installed Penetrator Connector. Service Rig, Check Fluid levels on all Equipment. Land Tbg Hanger, RILDS, Back out Landing Joint & Lay down. Install BPV in Hanger. Remove Power Tongs X-Box, Stairs, Disconnect Pits Lines, Kommey Lines all Handling Equipment From Rig Floor, Lower Derrick Removed Rig & Mud Boat. Nipple Down Bon Stark, Nipp.le_up Tree,Test Hanger void to 500psi low/ 5,000psi high, pull BPV. 3/14/2015 - Monday No activity to report. 3/15/2015-Tuesday No activity to report. of 7.4 • • e,`',1,/ ,. s, THE STATE Alaska Oil and Gas t-:=4" ---- :.,47-,,,, �, of j Conservation Commission _, ALAS��A ittitt �� 333 West Seventh Avenue 4`i: ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 wh Main: 907.279.1433 SFA +5 Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLCQ 2016 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Tertiary Undefined WTRSP Pool, MPU TER F-02 Permit to Drill Number: 196-070 Sundry Number: 316-130 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, la;et4Ve' Cathy . Foerster Chair DATED this ZJ day of February, 2016. RBDMS LL. Frd c 4 1016 riECEIVED • STATE OF ALASKA • FEB 1 7 201 • ALASKA OIL AND GAS CONSERVATION COMMISSION pTs z( 3 /(, APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program Q' Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: SSP 5 .-4f'zr 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑ 196-070 ` 3.Address: 6.API Number: Stratigraphic ❑ Service ❑✓ 3800 Centerpoint Drive,Suite 1400 Anchorage,AK 99503 50-029-22673-00-00 . 7. If perforating: 8,Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ ✓ MILNE PT UNIT TER F-02 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 025509 . Milne Point Unit/Tertiary Undefined WTRSP , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): , 3,385' . 2,903' . 3,277' .2,815' 100 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 82' 20" 112' 112' Surface 3,334' 9-5/8" 3,363' 2,885' 5750 3090 Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic ' See Attached Schematic 5-1/2" 17#/FT/L-80 2,340' Packers and SSSV Type: (2)9-5/8"HES Versatrieve Pkrs and a Packers and SSSV MD(ft)and TVD(ft): . 2,439'&2,982'. 2.137'&2,574' 9-5/8"BWD Sump Packer ,3,274'(MD) 2,812'(TVD) 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch E Exploratory ❑ Stratigraphic ❑ Development ❑ Service 0 ' 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 3/7/2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ ❑ SPLUG Commission Representative: Water Source Well ❑✓ t Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Paul Chan Email Pchan@hilcorp.com Printed Name Bo York Title Operations Manager Signature2, Phone 777-8345 Date S' $' 1,6 ` , COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance� �r ❑ Other: 7 s--0 a e S i I e' .r C (.SCt)�a 5- f l ti/e""`.-`.t-t 7L) Post Initial Injection MIT Req'd? Yes ❑ No ❑ e Spacing Exception Required? Yes El 2/ Subsequent Form Required: /0 --y0`1 RBDMS � k— FEB 1 4 2016 APPROVED BY ? // Approved by: /�� COMMISSIONER THE COMMISSION Date:2 -Z 3— lLO III��iii ry # {� {5 /t7�o Submit Form and Form 10-403 evised 11/2015i. ...icNn/S�v Id for 12 months from the date of approval. Attachments in Duplicate �- a.zZOPR 1 lG • Well Prognosis Well: MPU F-02 IIilcora Alaska.LL Date: 2/16/2015 Well Name: MPU F-02 API Number: 50-029-22673-00 Current Status: Water Source Well Pad: F-Pad [Failed ESP] Estimated Start Date: March 7th, 2016 Rig: ASR#1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 196-070 First Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Current Bottom Hole Pressure: 1,082 psi @ 2,500' TVD (SBHPS 07/30/2015/8.32 ppg EMW) Maximum Expected BHP: 1,082 psi @ 2,500' TVD (No new perfs being added) MPSP: 100 psi (SITP. Prince Creek water supply well with 0.433 psi/ft gradient) Hilcorp Alaska was unable to perform this ESP repair with Nordic 3 and is submitting a change program to perform the ESP repair with ASR#1. Sundry 316-0� 04 was approved on January 11, 2016. ' e1y'acv-✓ Brief Well Summary: MPU F-02 was drilled in May 1996 and completed with a gravel pack in August 1996 as a Tertiary Prince Creek water source well:i The well has had multiple ESPs installed: August 1996 (initial), October 1996, October 1997,January 1998, May 1998, February 2007, and November 2012 (hanger and penetrator only). The ESP has failed. Notes Regarding Wellbore Condition • Casing tested to 4,500 ps down to 3,277' PBTD on 8/13/1996 (prior to gravel pack operations). Objective: Pull failed ESP, pressure test casing, and run a new ESP. / Brief RWO Procedure: Pre-Rig Procedure: 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services and 500 bbl returns tank with choke manifold. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 8.7 ppg filtered NaCI brine/sea water down tubing, taking returns up casing to 500 bbl returns tank. 6. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 7. RD Little Red Services. 8. Set BPV. RU crane. ND Tree. NU 11" BOPE. RD Crane. 9. NU BOPE house. Spot mud boat. • • Well Prognosis Well: MPU F-02 Hilcorp Alaska,LLQ Date: 2/16/2015 WO Rig Procedure: 10. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 11. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ .7 ppg filtered NaCI brine/sea water prior to pulling BPV. Set TWC. 12. Test BOPE to 250 psi Low/2,5QtL.psi High, annular to 250 psi Low/ 1,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hrs in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 3-1/2" and 5-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 13. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/6i-corroded and BPV cannot be set with tree on.) 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 ��1 c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor r 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. 14. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.7 ppg filtered NaCl brine/sea water as needed. 15. MU landing joint or spear and 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. 16. POOH and lay down the 5-1/2" tubing. Tubing may be re-used. Lay down failed ESP. f. Thread protectors required to lay down the 5-1/2" mod-BTC tubing. g. Replace bad joints of tubing as necessary. 17. RIH with scraper assembly to 2,400' MD on 3-1/2" workstring. Circulate the well clean. If needed, spot sized salt pill to control losses. POOH. y, 18. PU test packer and RIH to 2,350' MD. Pressure test casing to 2,000 psi for 30 charted minutes. C!" POOH and LD test packer and workstring. 19. PU new ESP and RIH on 5-1/2" 17#/ft L-80 mod-BTC tubing. Set base of ESP at± 2,338' MD 20. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 21. Set BPV. • • Well Prognosis Well: MPU F-02 Hilcorp Alaska,LU Date: 2/16/2015 Post-Rig Procedure: 22. RD mud boat. RD BOPE house. 23. RU crane. ND BOPE. 24. NU existing 4-1/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 25. RD crane. Move 500 bbl returns tank and rig mats. 26. Replace gauge(s) if removed. 27. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic(No change) 2. Proposed Schematic (No change) 3. Existing Tree/Wellhead (No Change) 4. BOPE Schematic (Updated) 5. Choke Schematic (Updated) 6. Flow Diagram(s) (Updated) 7. Bleed to Pits Flow Diagram (New) 8. Blank RWO MOC Form (No change) • Milne Point Unit Well: MPU F-02 . Ili • SCHEMATIC Last Co196 p11/24/2012 m leted Jlilcorp Alaska,LLC 070 : Orig.DF Elev.:41.25(N 22E)/GL EIev.:12.0CASING DETAIL RDF to9-5/8"Iandingring=2 .2' Size Type Wt/Grade/Conn Drift ID Top Btm 20'1 l 20" Conductor 91.1#/H-40/N/A N/A Surf 113' �r, 9-5/8" Surface 404/L-80/Btrc. 8.679 Surf 3,363' TUBING DETAIL 3 5-1/2" Tubing 174/L-80/Mod Btrc 4.767" Surf 2,247' $a t' JEWELRY DETAIL /. No No Depth Item 1 2,254' Centrilift 35HC 12500 ESP LT SXD/SXD 70 Stg.(Two-35 Stg.) 2 2,289' Centrilift Seal Section HST3ILDBINVPFS 3 2,303' Centrilift Series,HMI 800 hp.Motor,4160/114 4 2,338' Centralizer 5 fin al 5 2,439' 9-5/8"HES Versatrieve pkr. , 4 6 2,464' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") 7 2,560' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") 8 2,773' 5-1/2",0.012"Ga.Screen(ID=4.778") T 9 2,982' 9-5/8"HES Versatrieve pkr. 10 2,999' 5-1/2",20 ppf,N-S0,LTC blank pipe(ID=4.778") 11 3,025' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") 12 3,180' 5-1/2",0.012"Ga.Screen(ID=4.778") 13 3,274' HES 9-5/8"'BWD'sump pkr. PERFORATION DETAIL Ref log:GR/CCL 8/13/96 / Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status i Prince Creek"A" 2,574' 2,624' 2,246' 2,287' 49 Open Prince Creek"A" 2,704' 2,764' 2,351' 2,399' 60 Open Prince Creek"B" 2,780' 2,894' 2,415' 2,503' 114 Open Prince Creek"B/C" 2,914' 2,964' 2,519' 2,560' 50 Open Prince Creek"C" 3,034' 3,149' 2,616' 2,710' 115 Open 1 Prince Creek"D" 3,234' 3,264' 2,779' 2,804' 30 Open 4.5"12 SPF 26 gm.Jumbo Jet charges @ 135/45 deg.Phasing(w/0.74"EHD and 5.8"TTP) .11:11: z DEVIATION INFO I OPEN HOLE/CEMENT DETAIL KOP @ 200' 20" Cmt w/250 sks of Arcticset I(Approx.)in 24"Hole Max Hole Angle=40°@ 1,750' 3 9-5/8" Cmt w/750 sks PF"E",500 sx Class"G",150 sx PF"E"in 12-1/4" Hole Angle through perfs.=36° , DLS>4°/100'@ 710'and 1,000' k' - 4 L TREE&WELLHEAD Tree CIW 4-1/6"5M'FLS' X 11"x 12"5M FMC Gen 6 Unibore w/two 2"5M valves on --. �_ 5 L k- Wellhead side ports 11"5M x 4-1/8"5M adapter and 11"x 4-1/2" 6 - 7rirl`r'`� Tbg Hgr 4.5"TC-II threads top and bottom and 4"CIW-H Li GRAVEL PACK SUMMARY 4.1 4Upper Zone-8/16/96-Est.13,200 lbs.of 20-40 Carbolite 31 g Lower Zone-8/14/96-Est.3,800 lbs.of 20-40 Carbolite Minimum gravel pack restriction=2.97"safety shear sub @ 2,459'& pop 2,995' =r GENERAL WELL INFO -` API:50-029-22673-00-00 i:•1 ..2 Drilled and Cased by Nabors 22E -5/11/1996 13 Gravel Pack Completion/ESP by Nabors 4ES-8/96 ESP RWO w/Nabors 4-ES-10/96,10/97,&1/98 9-5/s' \ ESP RWO changeout ESP w/Nabors 5S 5/98 ESP RWO changeout ESP/New ESP cable 2/2007 by Nabors 3S TD=3,385'(MD)/TD=2,903'(1VD) PBTD=3,277'(MD)/PBTD=2,815'(TVD) Created By:CJD 12/29/15 14 • PROPOSED • WellMilne PointPUF-02 Unit : M Last Completed: 11/24/2012 Hilcorp Alaska,LLC PTD: 196-070 Orig.DF Elev.:41.25(N 22E)/GL Elev.:12.0 CASING DETAIL' RDF to 9-5/8"landing ring=29.2' Size Type Wt/Grade/Conn Drift ID Top Btm A 1 ,) 20" Conductor 91.1#/H-40/N/A N/A Surf 113' 20' 1I lei 9-5/8" Surface 40#/L-80/Btrc. 8.679 Surf 3,363' TUBING DETAIL W 5-1/2" Tubing 17#/L-80/Mod Btrc 4.767" Surf 2,247' tt a '`i JEWELRY DETAIL No Depth Item 1 ±2,254' Centrilift Pump i : 2 ±2289' Centrilift Seal Section 3 ±2,303' Centrilift Motor fl 4 ±2,338' Centralizer 5 fin 5 2,439' 9-5/8"HES Versatrieve pkr. ,11 6 2,464' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") .- 7 2,560' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") L. " 8 2773' 5-1/2",0.012"Ga.Screen(ID=4.778") yy; 9 2,982' 9-5/8"HES Versatrieve pkr. 1 10 2,999' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") J". 11 3,025' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") t 4 12 3,180' 5-1/2",0.012"Ga.Screen(ID=4.778") I 13 3,274' HES 9-5/8"`BWD'sump pkr. I'Q rl PERFORATION DETAIL Ref log:GR/CCL 8/13/96 4a Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status k Prince Creek"A" 2,574' 2,624' 2,246' 2,287' 49 Open k° Nt. Prince Creek"A" 2704' 2764' 2351' 2399' 60 Open ('` Prince Creek"B" 2,780' 2,894' 2,415' 2,503' 114 Open Prince Creek"B/C" 2,914' 2,964' 2,519' 2,560' 50 Open i i. Prince Creek"C" 3,034' 3,149' 2616' 2,710' 115 Open 9 1 ) Prince Creek"D" 3,234' 3,264' 2,779' 2,804' 30 Open 'i 4.5"12 SPF 26 gm.Jumbo Jet charges @ 135/45 deg.Phasing(w/0.74"EHD and 5.8"TTP) iii 4 iiS2 DEVIATION INFO y e OPEN HOLE/CEMENT DETAIL KOP @ 200' ' 20" Cmt w/250 sks of Arcticset I(Approx.)in 24"Hole Max Hole Angle=40°@ 1,750' 3 9-5/8" Cmt w/750 sks PF"E",500 sx Class"G",150 sx PF"E"in 12-1/4" Hole Angle through perfs.=36° DLS>4°/100'@ 710'and 1,000' ti 1 4 to TREE&WELLHEAD and i, 4, Tree CIW 4-1/6"5M'FLS' it R 11"x 12"5M FMC Gen 6 Unibore w/two 2"5M valves on 4,...---.. =Mr' 5 Wellhead side ports 11"5M x 4-1/8"5M adapter and 11"x 4-1/2" m L. 6 t, Tbg Hgr 4.5"TC-II threads top and bottom and 4"CIW-H ii 74 k GRAVEL PACK SUMMARY Upper Zone-8/16/96-Est.13,200 lbs.of 20-40 Carbolite 1 11 L891:37 Lower Zone-8/14/96-Est.3,800 lbs.of 20-40Carbolite -w9 Minimum gravel pack restriction=2.97"safety shear sub @ 2,459'& 10 2,995' i i 111 GENERAL WELL INFO API:50-029-22673-00-00 " 11;:310 Drilled and Cased by Nabors 22E -5/11/1996 t ► 13Gravel Pack Completion/ESP by Nabors 4ES-8/96 3 ESP RWO w/Nabors 4-ES-10/96,10/97,&1/98 9-5/8° , 4..g t,x c ESP RWO changeout ESP w/Nabors 5S 5/98 ESP RWO changeout ESP/New ESP cable 2/2007 by Nabors 3S TD=3,385'(MD)/TD=2,903'(TVD) PBTD=3,277'(MD)/PBTD=2,815'(TVD) Created By:PC 12/29/15 01/07/1998 18:26.. *94277 . 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O a p. 0 2 g . To. \ Z U 2 g > a 2 /3 a) / f M X 0 o Cl) 2 k CO m ¢ E yOF Ti • • • �w��\I%i s THE STATE Alaska a it and Gas , ®fl-1 �1�J' Conservation Commission !!tom 333 West Seventh Avenue 1/41e. " GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ®ALAS' Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Area Operations Manager HilcorpAlaska, LLC _ 3800 enterpoint Drive, Suite 1400 SCANNED E x.11 Anchorage,AK 99503 Re: Milne Point Field, Tertiary Undefined WTRSP Pool, MPU TER F-02 Permit to Drill Number: 196-070 Sundry Number: 316-004 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. Foerster / Chair DATED this j1 / ay of January, 2016. IoM ‘AiaN �11S RECEIVED • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JAN p 2,016 APPLICATION FOR SUNDRY APPROVALS /i / 20 AAC 25.280 0 C 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well 11 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 Changeout_❑✓ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC • Exploratory ❑ Development ❑ 196-070 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: 3800 Centerpoint Drive,Suite 1400 Anchorage,AK 99503 50-029-22673-00-00 , 7. If perforating: 8 Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No Q I MILNE PT UNIT TER F-02. 9.Property Designation(Lease Number): 10. Field/Pool(s): _ I) c ` A4b ADL 025509 Milne Point Unit/Prince..-Greele r kra+f'l vndL[, kJ) &y P 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 3,385' . 2,903' ' ' 3,277' - 2,815' 100 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 82' 20" 112' 112' Surface 3,334' 9-5/8" 3,363' 2,885' 5750 3090 Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic . See Attached Schematic 5-1/2" 17#/FT/L-80 2,340' Packers and SSSV Type: (2)9-5/8"HES Versatrieve Pkrs and a Packers and SSSV MD(ft)and TVD(ft): 2,439'&2,982', 2,137'&2,574' 9-5/8"BWD Sump Packer 3,274'(MD) 2,812'(TVD) 12.Attachments: Proposal Summary 0 Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑✓ a 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations: 1/18/2015 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: k1l,'Rv '"''e J ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved b4-= herein will not be deviated from without prior written approval. Contact Paul Chan t,.--T' Email pchanna hilcorp.corn Printed Name Bo York Title Area Operations Manager Signature Phone 777-83457,47fr—V "2------ Date �I j i.„COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. / ��' 6ald Plug Integrity ❑ BOP Test le Mechanical Integrity Test ❑ Location Clearance ❑ Other: �S (3C� S C OI� • `•t' -- ( sD , S 4- .fin 1 .t (ms-IL- pMs40 AN 12. 0 Post Initial Injection MIT Req'd? Yes ❑ No ❑ RB Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: 10" 7 0 1 /�/D�,, / Approved by: R�� 219-C-alLigi;—hco COMMISSIONER THE COMMISSION Date: `(l � APPROVED BY (� n A Submit Form and Form 10-403 Revised 11/2015 Approved application FS}rafi�f*jr��t71nf fA 1 date of approval. , Attachments in Duplicate • • Well Prognosis Well: MPU F-02 Ililcor)Alaska,LLQ Date: 12/30/2015 Well Name: MPU F-02 API Number: 50-029-22673-00 Current Status: Water Source Well Pad: F-Pad [Failed ESP] Estimated Start Date: January 18th, 2016 Rig: Nordic 3 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 196-070 First Call Engineer: Paul Chan (907)777-8333 (0) (907)444-2881 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Current Bottom Hole Pressure: 1,082 psi @ 2,500' TVD (SBHPS 07/30/2015/8.32 ppg EMW) Maximum Expected BHP: 1,082 psi @ 2,500' TVD (No new perfs being added? - MPSP: 100 psi (SITP. Prince Creek water supply well with 0.433 psi/ft gradient) Brief Well Summary: MPU F-02 was drilled in May 1996 and completed with a gravel pack in August 1996 as a Tertiary Prince Creek water source well. The well has had multiple ESPs installed: August 1996 (initial), October 1996, October 1997,January 1998, May 1998, February 2007, and November 2012 (hanger and penetrator only). The ESP has failed. Notes Regarding Wellbore Condition • Casing tested to down to 3,277' PBTD on 8/13/1996 (prior to gravel pack operations). Objective: Pull failed ESP, pressure test casing, and run a new ESP. Brief RWO Procedure: 1. MIRU Nordic#3 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 2. Pull BPV. Circulate well clean with 8.7 ppg filtered NaCI brine/sea water. 3. Set BPV. ND Tree. NU 11" BOPE. Pull BPV and set TWC. 4. Test BOPE to 250 psi low/2,_500 psi high, annular to 250 psi low/ 1,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per Nordic 3 BOP Test Procedure. b. Notify AOGCC 24 hrs in advance of BOP test. c. Submit completed 10-424 BOPE test results within 5 days of completed test. d. Confirm test pressures per the Sundry Conditions of approval. e. Test rams and annular with 3-%2" and 5-%2" test joints. 5. Contingency: (If the tubing hanger won't pressure test due to eroded and/or corroded BPV profile and BPV cannot be set with tree on.) 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. • H • • Well Prognosis Well: MPU F-02 Ililcorp Alaska,LLQ Date: 12/30/2015 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. 6. Bleed any pressure off tubing and casing to 500 bbl returns tank. Pull TWC. Kill well w/8.7 ppg filtered NaCl brine/seawater as needed. 7. MU landing joint or spear and 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. 8. POOH and lay down the 5-1/2" tubing. Tubing may be re-used. Lay down failed ESP. a. Thread protectors required to lay down the 5-1/2" mod-BTC tubing. b. Replace bad joints of tubing as necessary. 9. RIH with scraper assembly to 2,400' MD. Circulate the well clean. If needed, spot sized salt pill to control losses. POOH. 10. PU test packer and RIH to"'2,350' MD. Pressure test casing to 2,000 psi for 30 charted minutes. POOH and LD test packer. 11. PU new ESP and RIH on 5-1/2" 17#/ft L-80 mod-BTC tubing. Set base of ESP at±2,338' MD 12. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 13. Set BPV. ND BOPE. NU existing 4-1/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 14. RU hot oil and freeze protect well to 2100' MD if needed. 15. RD Nordic#3 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 16. Turn well over to production. 17. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Choke Schematic 5. Existing Tree/Wellhead 6. Nordic#3 Flow Diagram 7. Blank RWO Changes Form H . Milne Point Unit • Well: MPU F-02 SCHEMATIC Last Completed: 11/24/2012 liilcorp Alaska,LLC PTD: 196-070 Orig.DFElev.:41.25(N22E)/GLEIev.:12.0 CASING DETAIL RDF to9-5/8' landing ring=2 3.2' Size Type Wt/Grade/Conn Drift ID Top Btm 4 -} 20" Conductor 91.1#/H-40/N/A N/A Surf 113' 20' �► 9-5/8" Surface 40#/L-80/Btrc. 8.679 Surf 3,363' TUBING DETAIL 5-1/2" Tubing 17#/L-80/Mod Btrc 4.767" Surf 2,247' $. JEWELRY DETAIL , 4 No Depth Item 1 2,254' Centrilift 35HC 12500 ESP LT SXD/SXD 70 Stg.(Two-35 Stg.) 2 2,289' Centrilift Seal Section HST3ILDBINVPFS 3 2,303' Centrilift Series,HMI 800 hp.Motor,4160/114 4 2,338' Centralizer 5 fin °' 5 2,439' 9-5/8"HES Versatrieve pkr. e 6 2,464' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") .� 7 2,560' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") . l+ 8 2,773' S-1/2",0.012"Ga.Screen(ID=4.778") 9 2,982' 9-5/8"HES Versatrieve pkr. r' 1 10 2,999' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") 11 3,025' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") � 12 3,180' 5-1/2",0.012"Ga.Screen(ID=4.778") 13 3,274' HES 9-5/8"'BWD'sump pkr. o PERFORATION DETAIL Ref log:GR/CCL 8/13/96 l.; Sands Top(MD) Btm(MD) Top(ND) Btm(ND) FT Status Prince Creek"A" 2,574' 2,624' 2,246' 2,287' 49 Open 44. ti Prince Creek"A" 2,704' 2,764' 2,351' 2,399' 60 Open Prince Creek"B" 2,780' 2,894' 2,415' 2,503' 114 Open 1 Prince Creek"B/C" 2,914' 2,964' 2,519' 2,560' 50 Open Prince Creek"C" 3,034' 3,149' 2,616' 2,710' 115 Open 1 Prince Creek"D" 3,234' 3,264' 2,779' 2,804' 30 Open 1. A 43 4.5"12 SPF 26 gm.Jumbo Jet charges @ 135/45 deg.Phasing(w/0.74"EHD and 5.8"TTP) el 2 DEVIATION INFO At 433 4 OPEN HOLE/CEMENT DETAIL KOP @ 200' fii' 20" Cmt w/250 sks of Arcticset I(Approx.)in 24"Hole Max Hole Angle=40°@ 1,750' 3 19-5/8' Cmt w/750 sks PF"E",500 sx Class"G",150 sx PF"E"in 12-1/4' Hole Angle through perfs.=36° 41 DLS>47100'@ 710'and 1,000' 4 TREE&WELLHEAD iTree CIW 4-1/6"5M'FLS' 11"x 12"5M FMC Gen 6 Unibore w/two 2"SM valves on i, . _-. 5 Wellhead side ports 11"5M x 4-1/8"5M adapter and 11"x 4-1/2" 6 kr Tbg Hgr 4.5"TC-Il threads top and bottom and 4"CIW-H #; 7 GRAVEL PACK SUMMARY A. Upper Zone-8/16/96-Est.13,200 lbs.of 20-40 Carbolite 8 It Lower Zone-8/14/96-Est.3,800 lbs.of 20-40 Carbolite ® 9 Minimum gravel pack restriction=2.97"safety shear sub @ 2,459'& 10 2,995' 11 GENERAL WELL INFO 12 API:50-029-22673-00-00 Li„ Drilled and Cased by Nabors 22E -5/11/1996 1 .1.- 13 Gravel Pack Completion/ESP by Nabors 4ES-8/96 ' ESP RWO w/Nabors 4-ES-10/96,10/97,&1/98 9-5/8" 4=,1 i% tlt ' i ESP RWO changeout ESP w/Nabors 5S 5/98 ESP RWO changeout ESP/New ESP cable 2/2007 by Nabors 3S TD=3,385'(MD)/TD=2,903'(TVD) PBTD=3,277'(MD)/PBTD=2,815'(TVD) Created By:CJD 12/29/15 . iii • • Milne Point Unit PROPOSED Well: MPU F-02 Last Completed: 11/24/2012 Ilileorp Alaska,LLC PTD: 196-070 Orig.DF Elev.:41.25(N 22E)/GL Elev.:12.0CASING DETAIL' RDF to9-5/8"landing ring=2,9.2' Size Type Wt/Grade/Conn Drift ID Top Btm I 20" Conductor 91.1#/H-40/N/A N/A Surf 113' 20� ) 9-5/8" Surface 40#/L-80/Btrc. 8.679 Surf 3,363' TUBING DETAIL r5-1/2" Tubing 17#/L-80/Mod Btrc 4.767" Surf 2,247' '5 j',, Art Ir JEWELRY DETAIL No Depth Item Ir. ? 1 ±2,254' Centrilift Pump i,,' 2 ±2,289' Centrilift Seal Section a P 3 ±2,303' Centrilift Motor ` 7 v 4 ±2,338' Centralizer 5 fin kgi ' f 5 2,439' 9-5/8"HES Versatrieve pkr. 6 2,464' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.7781 A 7 2,560' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.7781 8 2,773' 5-1/2",0.012"Ga.Screen(ID=4.778") 9 2,982' 9-5/8"HES Versatrieve pkr. i 10 2,999' 5-1/2",20 ppf,N-80,LTC blank pipe(ID=4.778") )4 11 3,025' 5-1/2",0.012"Ga.Pre-pack screen(ID=4.778") 12 3,180' 5-1/2",0.012"Ga.Screen(ID=4.7781 13 3,274' HES 9-5/8"'BWD'sump pkr. a+ t; u L. gPERFORATION DETAIL Ref log:GR/CCL 8/13/96 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status ►. Prince Creek"A" 2,574' 2,624' 2,246' 2,287' 49 Open Prince Creek"A" 2,704' 2,764' 2,351' 2,399' 60 Open Prince Creek"B" 2,780' 2,894' 2,415' 2,503' 114 Open s�� •t. Prince Creek"B/C" 2,914' 2,964' 2,519' 2,560' 50 Open Prince Creek"C" 3,034' 3,149' 2,616' 2,710' 115 Open 1 Prince Creek"D" 3,234' 3,264' 2,779' 2,804' 30 Open .,'" i 4.5"12 SPF 26 gm.Jumbo Jet charges @ 135/45 deg.Phasing(w/0.74"EHD and 5.8"TTP) III re Ls. 311, 2 DEVIATION INFO >16 ij OPEN HOLE/CEMENT DETAIL KOP @ 200' .' 20" Cmt w/250 sks of Arcticset I(Approx.)in 24"Hole Max Hole Angle=40°@ 1,750' 39-5/8" Cmt w/750 sks PF"E",500 sx Class"G",150 sx PF"E"in 12-1/4' Hole Angle through perfs.=36° DLS>4°/100'@ 710'and 1,000' , 4 0TREE&WELLHEAD Tree CIW 4-1/6"5M'FLS' ) w 11"x 12"5M FMC Gen 6 Unibore w/two 2"5M valves on .,.--.° Miii 5 Wellhead side ports 11"5M x 4-1/8"5M adapter and 11"x 4-1/2" 6 Tbg Hgr 4.5"TC-II threads top and bottom and 4"CIW-H 7 GRAVEL PACK SUMMARY Upper Zone-8/16/96-Est.13,200 lbs.of 20-40 Carbolite 11 8 Lower Zone-8/14/96-Est.3,800 lbs.of 20-40 Carbolite �-=®t` 9 Minimum gravel pack restriction=2.97"safety shear sub @ 2,459'& 10 2,995' i' ii 111 ,. GENERAL WELL INFO API:50-029-22673-00-00 12 F° Drilled and Cased by Nabors 22E -5/11/1996 - 13 Gravel Pack Completion/ESP by Nabors 4ES-8/96 ESP RWO w/Nabors 4-ES-10/96,10/97,&1/98 9-5/8"' L...,,;, f4;ag� „'arin ESP RWO changeout ESP w/Nabors 5S 5/98 ESP RWO changeout ESP/New ESP cable 2/2007 by Nabors 3S TD=3,385'(MD)/TD=2,903'(TVD) PBTD=3,277'(MD)/PBTD=2,815'(TVD) Created By:PC 12/29/15 H . MTrie Point • H Nordic#3 BOP T3 l- .p 11:14,to LTA. f 1 O O ' . it II \ / Hydril 11" 5M i di iiiiIII Shaffer aM( ( 0 -r*,e F. I)117f-al Pipe or VBR Rams li—� 11' 5M1---- -11—, ' Blinds qa 3 1/8 5M Kill Valves EW ' 3 1/8 5M Choke Valves Manual and HCR Manual and HCR 1,11-11k 1119119,1i 19,1i r1 ...��41 �Ii G ,�� J _ r��_yy _ A: o:I mai Hydril — 1..j.±11,_. 11" 5M 1=u Pipe Rams L �� _\ -` ® ' / J l) v fiv h h Av( 1.4 A VF A A vAvrS {2 ;A eY h A k F s k. F A A vF u pliplilld A vd 6. r a R rA a Fw .h c VF . 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They are available in the original file and viewable by direct inspection. / C/~-0~'0File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items - Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original - Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED [] Logs of various kinds [] Other COMMENTS: Scanned by: Bevedy ~incent Nathan Lowell [] TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: /si STATE OF ALASKA ' •SKA OIL AND GAS CONSERVATION •MISSION REPORT OF SUNDRY WELL OPERATIONS Water Source Well 1. Operations Performed: ❑ Abandon ® Repair Well ❑ Plug Perforations ❑ Perforate ❑ Enter Suspended Well I - __ per, ❑ Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver Oth� �'t """ ❑ Change Approved Program ❑ Operation Shutdown ❑ Stimulate - Other ❑ Time Extension 1^ ,-`^' �� {ei 2. Operator Name: 4. Well Class Before Work: C Permit To Drill Number: °' BP Exploration (Alaska) Inc. ❑ Exploratory ❑ Stratigraphic — 196 =70Q -- 070 3. Address: ❑ Development ® Service 6. API Numbe P.O. Box 196612, Anchorage, Alaska 99519 - 6612 ,-, 50 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 025509 - MPF -02 9. Logs (list logs and submit electronic and printed data per 20AAC25.071): 10. Field / Pool(s): Milne Point Unit / Prince Creek 11. Present well condition summary: Total depth: measured 3385 feet Plugs:(measured) None feet true vertical 2903 feet Junk: (measured) None feet Effective depth: measured 3277 feet Packer: (measured) 2439' & 2982', 3274' feet true vertical 2815 feet Packer: (true vertical) 2137' & 2574', 2812' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 82' 20" 112' 112' Surface 3334' 9 -5/8" 3363' 2885' 5750 3090 Intermediate Production Liner ECEIV " ;: .'`_ h... ED DEC 1 8 2012 DEC 1 , Perforation Depth: Measured Depth: 2574' - 3264' feet True Vertical Depth: 2246' - 2804' feet �� " '� Tubing (size, grade, measured and true vertical depth): 5 - 1/2 ", 17# L - 2340' 2058' Packers and SSSV (type, measured and true vertical depth): (2) 9 - 5/8" HES Versatrieve Packer and a 2439' & 2982', 2137' & 2574', 9 - 5/8" BWD Sump Packer 3274' 2812' 12. Stimulation or cement squeeze summary: Intervals treated (measured): SCANNED LIAR 18 2013. Treatment description including volumes used and final pressure: SCANNED Repair Tubing hanger and penetrator. 13 Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 14. Attachments: ❑Copies of Logs and Surveys run 15. Well Class after work: ❑ Exploratory ❑ Stratigraphic ❑ Development Service ® Daily Report of Well Operations 16. Well Status after work: `I✓Ak wok- ❑ 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: David Bjork, 564 -5683 N/A Email: David.Bjork @bp.com Printed am Jo L'�.�1 Title: Drilling Technologist I Signature: J - Phon 564 - Date: 11117 I Form 10-404 Re sed 10/2012 - Submit Original Only L _ c, 1 v/ v �' /Z•Lo• r Z— jyj1,eldg- • • °S22" F !F; = ✓.'� � 2i'oii'5'%r' ''f ..r _. 9'•� Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °30'25.764 "4 Long: 0149°39'32.541'W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 11/21/2012 00:00 - 03:30 3.50 MOB P PRE PJSM, SECURE TREE AND CELLAR. - SET TOP DRIVE IN TABLE. - R/U BRIDLE LINE. - PJSM. LID DERRICK 03:30 - 05:30 2.00 MOB P PRE PJSM FOR MOVING OFF WELL. - NOTIFY DSO. JACKUP RIG, PULL OFF WELL. - DROP OFF STACK. 05:30 - 09:00 3.50 MOB P PRE PJSM. MOVE RIG FROM L PAD TO F PAD. - POSITION RIG ON PAD, PICK UP BOPS. - N/D 13 3/8" X 11" FLANGE AND MAKE UP SPACER SPOOL. 09:00 - 12:00 3.00 MOB P PRE PJSM. SET BOP STAND IN CELLAR. - CLOSE CELLAR UP, N/U BOP TO TEST STAND. - PJSM. RAISE DERRICK. ACCEPT RIG @ 12:00 HRS, 11/21/2012. 12:00 - 17:00 5.00 RIGU P DECOMP PJSM. CONTINUE TO N/U BOPE. - R/U FLOOR EQUIPMENT. RIG. UP TEST EQUIPMENT. 17:00 - 23:00 6.00 BOPSUR P DECOMP PJSM FOR BOPE TEST. - STUMP TEST BOPE ACCORDING TO AOGCC REGULATIONS AND DOYON PROCEDURES. - TEST ANNULAR WITH 4" TEST JOINT TO / j 250/3500 PSI 5 MIN EA. - TEST UPPER AND LOWER 3 1/2" X 6" VBR WITH 4" AND 5 1/2" TEST JOINTS TO 250/3500 PSI 5 MIN EA. - TEST BLIND SHEAR RAMS, FLOOR VALVES, CHOKE MANIFOLD TO 250/3500 PSI. 5 MIN EA. - CHART RECORD ALL PRESSURE TESTS. - TEST WITH FRESH WATER. - PERFOM ACCUMULATOR DRAWDOWN TEST AFTER BOP WU ON WELL. - CHUCK SCHEVE AOGCC INSPECTOR WAIVED WITNESS TO BOP TEST 11/20/12 @ 19:30 HRS. - CLOSE OUT WELL WORK TRANSFER PERMIT FOR MPL -29 WITH DSO. 23:00 - 00:00 1.00 BOPSUR P DECOMP R/D TEST EQUIPMENT. BLOW DOWN LINES. - VAC OUT STACK. 11/22/2012 00:00 - 01:30 1.50 BOPSUR P DECOMP PJSM. R/D 13 3/8" TEST SPOOL ON BOP. - M /U 133/8 "X11" SPOOL. - SET BOP ON CELLAR STAND. 01:30 - 03:30 2.00 MOB P DECOMP PJSM FOR BACKING OVER WELL. - REVIEW DDI SOP FOR MOVING RIG OVER WELL. - NOTIFY DSO FOR BACKING OVER WELL. - POSITION RIG OVER WELL. - SHIM AND LEVEL RIG. Printed 12/10/2012 10:50:36AM n' i Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °30'25.764 "4 Long: 0149°39'32.541'W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:30 - 08:00 4.50 RIGU P DECOMP PJSM, REVIEW DDI SOP FOR R/U AND TESTING KILL MANIFOLD. - R/U KILL MANIFOLD AND LINES. - SET CUTTINGS BOX. - START OFFLOADING 8.9 PPG KWF TO PITS. - TEST HI LEVEL ALARM ON FLOWBACK —TANK. - PRESSURE TEST KILL MANIFOLD AND LINES TO 250/3500 PSI 5 MIN EA. CHARTED. 08:00 - 11:00 3.00 WHSUR P DECOMP PJSM. PICK UP LUBRICATOR. - TEST @ 250 PSI / 3500 PSI / 5 MIN EACH. - ATTEMPT TO PULL BPV, NOT ENOUGH LUBRICATOR EXTENSION. - MAKE UP MORE EXTENSION, RETEST LUBRICATOR. - PULL BPV. SITP = 300 PSI. I/A = 110 PSI. UD LUBRICATOR. 11:00 - 12:00 1.00 WHSUR P DECOMP RIG EVACUATION DRILL W/ DAY CREW. - SIREN SOUNDED, DRILL ANOUNCED. DRILL SITE OPERATOR NOTIFIED, MILNE PT BASE CAMP NOTIFIED. - GOOD RESPONSE. AAR CONDUCTED. -- SOME HANDS REPORTED TO SIGN IN SHACK DUE TO WIND DIRECTION. - HEAD COUNT MADE. ALL HANDS ACCOUNTED FOR. - TRUCK DRIVERS AND HANDS WORKING ON MPF -87 ACCOUNTED FOR. 12:00 - 13:00 1.00 WHSUR P _ DECOMP SERVICE RIG AND INSPECT EQUIPMENT. 13:00 - 13:30 0.50 WHSUR P DECOMP HOLD RIG EVACUATION DRILL W/ DAY CREW. - ALL HANDS REPORTED TO WELL SITE LEADER SHACK. - GOOD RESPONSE TIME, SIMULATED FIRE IN PIPE SHED. - DRILL SITE OPERATOR AND MILNE PT BASE CAMP NOTIFIED. - ALL 3RD PARTY HANDS ACCOUNTED FOR. SIREN HEARD BY ALL. - HEAD COUNT MADE, GOOD DISCUSSION. 13:30 - 14:00 0.50 KILLW P DECOMP PRE KILL MEETING HELD ON WELL KILL. - STRESSED GOOD COMMUNICATION TECHNIQUE. - FLUIDS MANAGEMENT AND INDIVIDUAL • RESPONSIBILITIES. Printed 12/10/2012 10:50:36AM Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °30'25.764 "4 Long: 0149 °39'32.541'W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 14:00 - 16:00 2.00 KILLW P DECOMP CHECK AND SIGN OFF ON VALVE ALIGNMENT. - NOTIFY MILNE PT OF INTENT TO BLEED GAS. - OPEN VA THRU CHOKE TO FLOW BACK TANK, FLUID RETURNS. - PUMP DOWN TUBING @ 5 BPM / HOLDING 50 PSI OVER SICP. PUMP PRESSURE = 1000 PSI, PUMP 60 BBLS OF 8.9 PPG HEATED BRINE. - SHUT IN CHOKE AND BULLHEAD 100 BBLS @ 5 BPM / 1400 PSI. OPEN CHOKE AND PUMP 50 BBLS, TAKING RETURNS TO FLOW BACK TANK. - SHUT DOWN PUMP AND SHUT IN CHOKE, STRAP FLOW BACK TANK. - 89 BBLS IN FLOW BACK TANK, 110 PUMPED, LOST 21 BBLS. StCP = 50. PSI, BRING ON PUMP @ 5 BPM HOLDING 100 PSI ON CHOKE. - PUMP 130 MORE BBLS DOWN TUBING, - TAKING RETURNS UP VA, THRU CHOKE TO FLOW BACK TANK. - 8.9 PPG BRINE COMING BACK. SHUT DOWN AND MONITOR WELL. - TUBING AND VA BOTH ON STRONG VACUUM. 16:00 - 17:00 1.00 KILLW P DECOMP BLOW DOWN LINES, RIG DOWN KILL MANIFOLD. - LINE UP ON VA AND CONTINUOUSLY FILL HOLE @ 20 - 25 BBLS / HR. 17:00 - 19:30 2.50 WHSUR P DECOMP PJSM. R/U LUBRICATOR. - PRESSURE TEST LUBRICATOR TO 250/3500 PSI 5 MIN EA. CHARTED. - INSTALL TWC. ATTEMPT TO PERFORM 10 MIN 500 PSI ROLLING TEST UNDER TWC. - PUMP 6 BPM 0 PSI INCREASING TO 100 PSI AFTER 5 MIN INTO TEST. - TEST ABOVE TWC TO 250/3500 PSI 5 MIN EA. CHART TESTS. - R/D LUBRICATOR. - BARRIERS IN PLACE, TESTED TWC, 8.9 PPG KWF AND HANGER SEALS. 19:30 - 22:00 2.50 WHSUR P DECOMP PJSM FOR N/D TREE AND N/U BOP.., - FMC BLEED TREE VOID. N/D TREE AND ADAPTOR FLANGE. - FMC INSPECT HANGER. SEAL SLEEVE - BOTH UPPER 0-RINGS DAMAGED. - 4 1/2" NSCT. 8 TURNS. - FUNCTION LDS. - USE CONTINUOUS HOLE FILL WITH 8.9 PPG KWF. 22:00 - 00:00 2.00 BOPSUR P DECOMP N/U 4 PREVENTER BOP WITH 13 3/8" X 11" ADAPTOR FLANGE. - USE CONTINUOUS HOLE FILL WITH 8.9 PPG KWF. - LOSSES TO WELL LAST 12 HRS= 170 BBLS 8.9 PPG KWF. Printed 12/10/2012 10:50:36AM err ' Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °30'25.764 "4 Long: 0149°39'32.541"W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 11/23/2012 00:00 - 00:30 0.50 BOPSUR P DECOMP PJSM. REVIEW DDI SOP FOR N/U. - CONTINUE N/U BOP. - CONTINUOUS HOLE FILL DOWN VA WITH 8.9 PPG KWF. 00:30 01:00 0.50 BOPSUR P DECOMP PJSM FOR TESTING BOP. - COMPLETE BOP TEST PER WELL PLAN. PERFORM ACCUMULATOR DRAW DOWN TEST. - CLOSE BLIND SHEAR RAM. - PERFORM 10 MIN ROLLING PRESSURE TEST. - PRESSURE UP TO 1000 PSI ON 13 3/8" X 11" SPOOL. - WITH TEST PUMP PERFORM 10 MIN ROLLING TEST. �1 - MONITOR SPOOL FLANGE IN CELLAR DURING TEST. - CHART RECORD TEST. A� - BLEED OFF PRESSURE THROUGH CHOKE. OPEN BLIND SHEAR RAM. CONTINUOUS HOLE FILL DOWN VA WITH 8.9 PPG KWF. 01:00 - 02:00 1.00 BOPSUR P DECOMP -PJSM, M/U DUTCH RISER AND LUBRICATOR. - COSE ANNULAR. PRESSURE TEST LUBRICATOR TO 250 PSI CHARTED. - NOTIFY ODE. INFORM THAT 3500 PSI TEST CANNOT BE ACHIEVED ON LUBRICATOR DUE TO COMMUNICATION ON HANGER PENETRATOR. 02:00 - 03:00 1.00 BOPSUR P DECOMP NOTIFY RWO FIELD SUPERINTENANT AND WTL. - DECISION MADE TO PERFORM 3500 PSI ROLLING TEST ON DUTCH RISER AND LUBRICATOR FOR 5 MIN. - VISUALY MONITOR FOR LEAKS. 03:00 - 03:30 0.50 BOPSUR P DECOMP PJSM FOR TESTING LUBRICATOR. - PRESSURE UP ON LUBRICATOR TO 3600 PSI WITH TEST PUMP. - OLD PRESSURE FOR 5 MIN CHARTED. 75 SI BLEED OFF TO 3525 PSI. - NO VISUAL LEAKS IN CELLAR OR ON LUBRICATOR. - VERIFY GOOD. NOTIFY WTL. - AUTHORIZED TO PROCEDE WITH WELL OPS. - PULL TWC. TBG ON VAC. R/D LUBRICATOR AND DUTCH RISER. 03:30 - 04:00 0.50 BOPSUR P DECOMP NOTIFY DOWN ODE. TUBING DECISION BEFORE MADE PULLING TO BULLHEAD HANGER TO ELIMINATE CLOSING ANNULAR ON ESP CABLE TO PREVENT DAMAGE. - CLOSE BLIND SHEAR RAM. - BULLHEAD 50 BBLS 8.9 PPG KWF DOWN TBG 5 BPM 1250 PSI . -SHUT DOWN PUMP. MONITOR LL FOR 10 MIN. ON STRONG VAC. M - OPEN BLIND SHEAR RAM. Printed 12/10/2012 10:50:36AM Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °30'25.764 "4 Long: 0149°39'32.541'W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) _ (ft) 04:00 - 04:30 0.50 BOPSUR P DECOMP PJSM, M/U 4" LANDING JT WITH XO AND FOSV. - FMC BOLDS. - UNSEAT TBG HANGER 85K. INCLUDES 40K TOP DRIVE WT. - CLOSE FOSV. - PULL TBG HANGER TO RIG FLOOR. - P/U WT= 85K. S/O WT= 80K. INCLUDES 40K TOP DRIVE WT. 04:30 - 06:00 1.50 BOPSUR P DECOMP USE CONTINUOUS HOLE FILL AT 20 BPH WITH 8.9 PPG KWF. - CENTRALIFT TROUBLESHOOT ELECTRICAL PROBLEM ON ESP CABLE. - MEGAR ESP CABLE. PASSED 06:00 - 08:00 2.00 BOPSUR P DECOMP PJSM. BREAK OUT AND LAY DOWN OLD HANGER. FMC EXPRESSING CONCERNS ABOUT OLD HANGER. - DECISION MADE TO CHANGE OUT HANGERS, ODE NOTIFIED. 08:00 - 09:00 1.00 BOPSUR P DECOMP WAILO ► • ►_ _ " IE..ROX CROSS OVER. NEW HANGER IS 4 1/2" TCII. DOYON 25 IS MOVING ACROSS BRIDGE. 09:00 - 09:30 0.50 BOPSUR P DECOMP PJSM. MAKE UP NEW HANGER W/ LANDING JT. - INSTALL PENETRATOR. 09:30 - 11:30 2.00 WHSUR P DECOMP PJSM. ATTACH FIELD CONNECTION. - PLUG IN TO PENETRATOR AND TEST, GOOD TEST. 11:30 - 12:00 • • WHSUR P DECOMP PJSM. LAND TUBING HANGER,, UD LANDING .1T. - RUN IN LOCK DOWN SCREWS. - FLUID LOST TO FORMATION LAST (12) HRS = 254 BBLS 8.9 PPG BRINE. 12:00 - 13:30 1.50 WHSUR P DECOMP PJSM. SET TWO WAY CHECK VALVE. - ATTEMPT TO GET ROLLING TEST FROM UNDERNEATH. - PUMPING DOWN VA @ 6 BPM / 200 PSI / 5 MIN, OK. - TEST FROM TOP, 250 PSI / 5 MIN / PASSED. - 3500 PSI ON TOP OF TWO WAY CHECK / TEST FAILED. - SIGNIFICANT LEAKAGE. 13:30 - 15:00 1.50 WHSUR N DFAL DECOMP PJSM. SUCK OUT STACK, INSPECT TWO WAY CHECK VALVE. - FLUSH AND OBSERVE NO TRASH OR ABNORMALITIES. - ATTEMPT TO RETEST FROM ABOVE, 3500 PSI, FAILED. 15:00 - 16:00 1.00 WHSUR N DFAL DECOMP PJSM. MAKE UP 4 1/2" TCII LANDING JT, ATTEMPT TO TEST THRU LANDING JT. - TEST FAILED, VERIFIED TWO WAY CHECK VALVE IS LEAKRG Printed 12/10/2012 10:50:36AM Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °30'25.764 "4 Long: 0149°39'32.541'W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 16:00 - 19:00 3.00 WHSUR N DFAL DECOMP PJSM. INSTALL DUTCH RISER. PICK UP OFF SET LUBRICATOR. - PRESSURE TEST @ 250 PSI. 35 PSI BLEED OFF IN 5 MIN. - WTL NOTIFIED OF TWC PRESSURE TEST NOT HOLDING. LINE UP KILL LINE. WITH RIG PUMP, SURGE TWC WITH 1000 PSI. CLEARING ANY TRASH STUCK IN TWC POPPET. - WITH TEST PUMP PRESSURE UP TO 3500 PSI FOR 5 MIN. - 20 PSI BLEED OFF IN 5 MIN, PASSING TEST. BLEED TO 0 PSI. PRESSURE UP TO 250 PSI FOR 5 MIN. - SOLID LOW PRESSURE TEST. - CHART RECORD TESTS. - NOTIFY WTL OF TEST RESULTS. - PASSING PRESSURE TEST ON INSTALLED T1NC. - R/D LUBRICATOR AND DUTCH RISER. CONTINUOUS HOLE FILL @ 20 BPH DURING ALL OPERATIONS. 19:00 - 21:00 2.00 WHSUR P DECOMP PJSM, REVIEW DDI SOP FOR N/D BOP, N/U TREE. - BARRIERS IN PLACE TESTED TWC, HANGER SEALS AND 8.9 PPG KWF. - VAC OUT STACK. N/D BOPE. CONTINUOUS HOLE FILL @ 20 BPH DURING ALL OPERATIONS. 21:00 - 00:00 3.00 WHSUR P DECOMP NLU I WADAPTOR_FLANGE• - PRSSEURE TEST TBG HEAD ADAPTOR TO 5000 PSI FOR 30 MIN PER FMC. - CLEAN PITS. CONTINUOUS HOLE FILL @ 20 BPH. - LOSSES TO WELL LAST 12 HRS= 191 BBLS 8.9 PPG BRINE. 11/24/2012 00:00 - 01:30 1.50 WHSUR P DECOMP PJSM. TEST TREE WITH DIESEL TO 250/5000 PSI 5 MI EA. - CHART RECORD TEST. - CENTRALIFT MAKE FINAL CHECKS ON ESP. - CONTINUE WITH HOLE FILL@ 20 BPH. 01:30 - 03:00 1.50 WHSUR P DECOMP PJSM, R/U LUBRICATOR. - TEST LUBRICATOR TO 250/3500 PSI 5 MIN EA. CHARTED. - TEST AGAINST CLOSED MASTER VALVE. OPEN MASTER. - OPEN MASTER, PULL TWC. TBG ON VAC. SHUT IN TREE. - UDTWC. Printed 12/10/2012 10:50:36AM Common Well Name: MPF -02 AFE No Event Type: WORKOVER (WO) Start Date: 11/21/2012 End Date: 11/24/2012 X4- 00WTF- E:DRILL (1,000,000.00 ) Project: Milne Point Site: M Pt F Pad Rig Name /No.: DOYON 16 Spud Date/Time: 5/9/1996 12:00:00AM Rig Release: 11/24/2012 Rig Contractor: DOYON DRILLING INC. UWI: / Lat: 070 °3025.764 "4 Long: 0149°39'32.541"W Active Datum: Kelly Bushing / Rotary Table @28.15ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:00 - 04:00 1.00 WHSUR P DECOMP M/U LUBRICATOR. - PRESSURE TEST TO 250/3500 PSI 5 MIN EA. CHARTED. - OPEN TREE VALVES. SET BPV. - ATTEMPT 10 MIN ROLLING TEST UNDER BPV. PUMP DOWN VA 5 BPM ACHIEVING ONLY 200 PSI. - SECURE TREE. R/D LUBRICATOR. 04:00 - 06:00 2.00 RIGD P DECOMP BLOW DOWN AND R/D LINES IN CELLAR. - CONTINUE TO VAC OUT PITS AND CUTTINGS BOX. SECURE WELL, RELEASE RIG @ 06:00 HRS, 11/24/2012. Printed 12/10/2012 10:50:36AM t Tree: CIW 4 1/16" 5M 'D MPU F -02 WSW Orig. Dilly. = 41.25' (N 22E) , Wellhead: 11" x 12" 5M FMC Gen 6 Orig. GL elev. = 12.0' Unibore w/ two 2" 5M valves on side / GG.' RDF To 9 5/8" landing ring = 29.2 ports 11" 5M x 4 1/8" 5M adapter and 0 11" x 4.5" Tbg Hgr 4.5" TC -II threads top and bottom and 4" CIW -H 20" 91.1 ppf, H -40 113' 0 , , N KOP @ 200' 0 Max. hole angle= 40 deg. f/ 1750' 0 0 Hole angle through perfs = 36 deg. 0 DLS > 4decq. /100' @ 710' and 1000' 5.5 ", 17 # / ft., L -80 Mod Btrc. 4.767" drift, 0 NOTE: 5.5" Tubing 4.892" ID, .0233 bpi 0 9 5/8 ", 40 ppf, L -80 Btrc. prod. csg 0 (cap. = 0.0758 bpf, 13.2 fpb.) D - Centrilift 35HC 12500 ESP LT SXD / SXD 0 � ,. 70 Stg. (Two - 35 Stg.) 2,254' 1980' TVD Centrilift Seal Section 2,289' 0 , HST3ILDBINVPFS 0 . Centrilift Series,HMI Gravel Pack Summary: 0 800 hp. motor, 4160/114 2,303' Upper zone - 8/16/96 - Est.. 13,200 lbs. of 20 -40 Carbolite , Lower zone - 8/14/96 - Est.. 3800 lbs. Centralizer 5 fin 2,338 of 20 -40 Carbolite. Minimum gravel pack restriction = 2.97" safety shear sub @ 2459' and 2995'. x f 9 5/8" HES Versatrieve pkr. 5 1/2", 20 ppf, N -80, LTC 2,439' T T blank pipe (ID = 4.778" 2,464' Perforation Summary: 5 1/2 ", 0.012" Ga. pre -pack Ref log: GR/CCL 8/13/96 - - - screen (ID = 4.778" 2.560' Size SPF Interval (TVD) -- 5 1/2 ", 0.012" Ga. screen 2,773' PrincD CreeK "A" Sand (ID = 4.778 ") 2,982, ZS 9 5/8" HES Versatrieve pkr. 4.5" 12 2574' - 2624' (2235' - 2276') 5 1/2", 20 ppf, N -80, LTC 2,999' 4.5" 12 2704' - 2764' (2340' - 2388) — — blank pipe (ID = 4.778") "B" Sand — 5 1/2", 0.012" Ga. pre -pack 4.5" 12 2780' - 2894' (2401' - 2492') 3'025' screen (ID = 4.778" _ _ "B /C" Sand 4.5" 12 2914' - 2964' (2507' - 2548') — • -- 5 1/2", 0.012" Ga. screen "C" Sand (ID = 4.778 ") 3,180' 4.5" 12 3034' - 3149' (2605' - 2699') HES 9 5/8" 'BWD' sump pkr. "D" Sand 3,274' s :; ; ;•' ;;;;;;';" ;;; 9.625" csg. shoe Float collar 3,277' 26 gm. Jumbo Jet charges @ 135/45 " " ';" " (PBTD) 3 ' 363' deg. phasing (w/ 0.74" EHD and 5.8" TTP), DATE REV. BY COMMENTS 05/11/96 JB Drilled and Cased by Nabors 22E MILNE POINT UNIT 1 01 / /098 MD8 ESP 2 (104ES ESP RWO 4ES WELL F -02 WSW 05/19/98 M.Linder ESP changeout 5 -S API NO: 50 -029 -22673 02/26/07 R. Handy ESP changeout/New ESP cable 11/24/12 L. Hulme Repair failed WH penetrator- Doyon 16 BP EXPLORATION (AK) • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 December 30, 2011 � ' FEB 1 7 ZOIL 191 61°7° Mr. Tom Maunder _ 0)- Alaska Oil and Gas Conservation Commission MI 333 West 7 Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of MPF -Pad Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from MPF -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 . • 1 1 1 BP Exploration (Alaska P � ) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top -off Report of Sundry Operations (10-404) MPF -Pad 10/29/2011 Corrosion Initial top of Final top of Cement top off Corrosion inhibitor/ Well Name P11) # API # cement Vol. of cement pumped cement date inhibitor sealant date ft bbls ft gal MPF -01 1950450 50029225520000 10.2 WA 10.2 N/A 122.4 8/7/2011 " ' MPF -02 1960700 50029226730000 4 N/A 4 N/A 35.7 8182011 MPF-05 1970740 50029227620000 1.3 N/A 1.3 N/A 13.6 8/9/2011 MPF-06 1960020 50029226390000 1.2 N/A 1.2 N/A 15.3 8/2/2011 MPF-09 1971040 50029227730000 5.0 N/A 5.0 N/A 54.4 8/9/2011 MPF -10 1960940 50029226790000 1.7 N/A 1.7 WA 20.4 8/22011 MPF -13 1950270 50029225490000 0.2 N/A 0.2 N/A 8.5 10/6/2011 MPF -14 1952120 50029226360000 0.1 WA 0.1 N/A 8.5 10/6/2011 MPF -17 1971960 50029228230000 4.1 N/A 4.1 N/A 37.4 8/6/2011 MPF -18 1961000 50029226810000 8.3 N/A 8.3 N/A 91.8 8/2/2011 MPF -21 1961350 50029226940000 1.8 N/A 1.8 N/A 15.3 8/6/2011 MPF -22 1952010 50029226320000 4 N/A 4 N/A 13.6 8/1/2011 MPF -25 1950160 50029225460000 0.3 N/A 0.3 N/A 6.8 10/29/2011 MPF -26 1970840 50029227670000 1.8 N/A 1.8 N/A 11.9 8/1/2011 MPF -29 1961170 50029226880000 6.7 N/A 6.7 N/A 56.1 8/9/2011 MPF -30 1951840 50029226230000 0.8 N/A 0.8 N/A 6.8 8/12011 MPF -33 2010620 50029226890000 23 Need top job MPF-34 1971970 50029228240000 4.1 N/A 4.1 N/A 13.6 8/1/2011 MPF-37 1950250 50029225480000 0.2 N/A 0.2 N/A 8.5 10/6/2011 MPF-38 1951680 50029226140000 0.3 N/A 0.3 N/A 6.8 10/5/2011 MPF -41 1970950 50029227700000 0.8 N/A 0.8 N/A 8.5 8/9/2011 MPF -42 1970200 50029227410000 1.8 N/A 1.8 N/A 13.6 8/1/2011 MPF-45 1950580 50029225560000 8 N/A 8 N/A 78.2 8/11/2011 MPF-46 1940270 50029224500000 Sealed Conductor N/A N/A N/A N/A N/A MPF -49 1970030 50029227320000 2.3 N/A 2.3 WA 18.7 8/112011 MPF -50 1970580 50029227560000 1.7 N/A 1.7 N/A 6.8 7/31/2011 MPF -53 1951080 50029225780000 2.8 N/A 2.8 N/A 11.9 9/19/2011 MPF -54 1961920 50029227260000 1.7 N/A 1.7 N/A 10.2 8/12011 MPF -57A 2031670 50029227470100 1.3 N/A 1.3 N/A 13.6 8/112011 MPF -58 1961560 50029227060000 1.7 N/A 1.7 N/A 13.6 7/31/2011 MPF-61 1951170 50029225820000 62 Need top job MPF-62 1951610 50029226090000 2.0 NA/ 2.0 N/A 13.6 9/1/2011 MPF-65 1970490 50029227520000 1.5 N/A 1.5 N/A 13.8 8/11/2011 MPF -66A 1961620 50029226970100 0.8 N/A 0.8 N/A 8.5 7/31/2011 MPF-69 1951250 50029225860000 0.8 N/A 0.8 N/A 8.5 8/4/2011 MPF -70 1951530 50029226030000 1.7 N/A 1.7 N/A 15.3 7/31/2011 MPF -73A 2001980 50029227440100 1.5 WA 1.5 N/A 13.6 8/11/2011 MPF -74 1961080 50029226820000 1.7 N/A 1.7 N/A 13.6 7/312011 MPF -77 1951360 50029225940000 0.2 N/A 0.2 N/A 6.8 10/5/2011 MPF -78 1951440 50029225990000 0.7 N/A 0.7 N/A 5.1 7/31/2011 MPF -79 1971800 50029228130000 0.6 N/A 0.6 N/A 6.8 8/3/2011 MPF-80 1982170 50029229280000 0.5 WA 0.5 N/A 3.4 8/3/2011 MPF -81 2000660 50029229590000 0.9 N/A 0.9 N/A 8.5 8/3/2011 MPF-82 2091350 50029229710000 1.7 N/A 1.7 N/A 15.3 8/3/2011 MPF-83 2000930 50029229630000 1.2 N/A 1.2 N/A 13.6 8/3/2011 MPF -84B 2001760 50029229310200 1.2 N/A 1.2 N/A 10.2 8/32011 MPF-85 1982500 50029229360000 0.1 N/A 0.1 WA 7.7 9/12011 MPF -86 2010870 50029230180000 0.8 N/A 0.8 N/A 6.8 8/122011 MPF -87A 2032130 50029231840100 1.3 N/A 1.3 N/A 11.9 8/132011 MPF -88 2031930 50029231850000 1.3 N/A 1.3 N/A 15.3 8132011 MPF -89 2050900 50029232680000 1.2 N/A 1.2 NIA 10.2 8/3/2011 MPF -90 2012110 50029230510000 1.8 N/A 1.8 N/A 18.7 8/3/2011 MPF -91 2051100 50029232710000 1.7 N/A 1.7 N/A 11.9 8/13/2011 MPF -92 1981930 50029229240000 0.8 N/A 0.8 N/A 5.1 8/13/2011 MPF -93 2050870 50029232660000 0.3 N/A 0.3 N/A 7.7 9/1/2011 MPF -94 2011700 50029230400000 1.8 N/A 1.8 N/A 13.6 8/13/2011 MPF -95 1981790 50029229180000 0.5 N/A 0.5 N/A 3.4 8/13/2011 MPF -96 2081860 50029234060000 0.1 N/A 0.1 N/A 6.0 9/1/2011 MPF -99 2061560 50029233320000 1.3 N/A 1.3 N/A 11.9 8/11/2011 . STATE OF ALASKA .""'V~: "2:; ~1 ALA Oil AND GAS CONSERVATION COM IM~R - ,; REPORT OF SUNDRY WELL OPEiftAl-QNS¡ Cons. Commission Anchorage Water Source Well 1. Operations Performed: o Abandon 181 Repair Well o Plug Perforations o Stimulate o Re-Enter Suspended Well o Alter Casing 181 Pull Tubing o Perforate New Pool o Waiver 181 Other o Change Approved Program o Operation Shutdown o Perforate o Time Extension ESP Changeout .-' ,,'¿nO? 2. Operator Name: 4. Well Class Before Work: 5. Permit To Drill Number: ~.f7 BP Exploration (Alaska) Inc. o Development o Exploratory 196-1'8Q. 17~ 3. Address: o Stratigraphic 181 Service / 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-29-22673-00-00 ( 7. KB Elevation (ft): 41 .25 / 9. Well Name and Number: MPF-02 / 8. Property Designation: 10. Field / Pool(s): ADL 025509 I Milne Point Unit / Prince Creek / 11. Present well condition summary ,~;~.f)1O -\ 3385 / 1 Total depth: measured feet , true vertical 2903 · feet Plugs (measured) None ~< Effective depth: measured 3277 feet Junk (measured) None true vertical 2815 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 82' 20" 112' 112' Surface 3334' 9-5/8" 3363' 2885' 5750 3090 Intermediate Production Liner sCANNED MAR 2 0 2007 Perforation Depth MD (ft): 2575' - 3264' Perforation Depth TVD (ft): 2247' - 2804' 5-1/2", 17# L-80 2340' Tubing Size (size. grade. and measured depth): Packers and SSSV (type and measured depth): (2) 9-5/8" HES Versatrieve Packer and a 9-5/8" BWD 2439' & 2982', 3274' Sump Packer 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment description including volumes used and final pressure: 13. Recresentative Dailv AveraQe Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Casino Pressure TubinQ Pressure Prior to well operation: Subsequent to operation: 14. Attachments: o Copies of Logs and Surveys run 15. Well Class after proposed work: 181 Daily Report of Well Operations o Exploratory o Development 181 Service 16. Well Status after proposed work: L0'ð--t-.Q.'("" -cÞ~""c..~· U>e.LG 181 Well Schematic Diagram o Oil o Gas o WAG OGINJ OWINJ o WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. .lsUndry Number or N/A if C.O. Exempt: Contact Bryan Mclellan, 564-5516 ¡;~hS Printed Name Sondra Stewman Title Technical Assistant J - r'f;- ...' Prepared By Name/Number: Sig",ure JtJ. ~p, ~.~, Phone 564-4750 Date '~ 11 0 7 Sandra Stewman, 564-4750 Form 10-404 Revised 04/2006 R G\ NAL RBDMS 8Ft MAR ] 9 2007 Submit Original Only .4þ j ./~.ø o 7 ~~ß'? Tree: CIW 41/16" 5M 'F~ Wellhead: 11" x 12" 5M FMC Gen 6 Unibore wI two 2" 5M valves on side ports 11" 5M x 4 1/8" 5M adapter and 11" x 4.5" tbg. hng. 4.5" NSCT threads top and bottom and 4" CIW-H 20" 91.1 ppf, H-40 I 113 KOP @ 200' Max. hole angle= 40 deg. fl 1750' Hole angle through perfs = 36 deg. DLS > 4deQ./100' @ 710' and 1000 5.5", 17 # / ft., L-80 Mod Btrc. 4.767" drift, 4.892" ID, .0233 bp 95/8",40 ppf, L-80 Btrc. prod. csg (cap. = 0.0758 bpf, 13.2 fpb.) Gravel Pack Summary: Upper zone - 8/16/96 - Est.. 13,200 Ibs. of 20-40 Carbolite Lower zone - 8/14/96 - Est.. 3800 Ibs. of 20-40 Carbolite. Minimum gravel pack restriction = 2.97" safety shear sub @ 2459' and 2995'. Peñoration Summary: Ref log: GRlCCL 8/13/96 Size SP Interval (TVD) Prin Cre k'A" Sand 4.5' 12 2574' - 2624' (2235' - 2276') 4.5" 12 2704' - 2764' (2340' . 23B8') "B" Sand 4.5" 12 2780' . 2894' (2401' - 2492') "B/C" Sand 4.5" 12 2914'·2964' (2507' . 2548') "C" Sand 4.5" 12 3034' - 3149' (2605' - 2699') "D" Sand 26 gm. Jumbo Jet charges @ 135/45 deg. phasing (wI 0.74" EHD and 5.8" TTP), II .... . II MPU F-02 Orig. D . = 41.25' (N 22E) Orig. GL elev. = 12.0' RDF To 9 5/8" landing ring = 29.~ NOTE: 5.5" Tubing Centrilift 35HC 12500 ESP L T SXD I SXD I 2.254' I 70 Stg. (Two - 35 Stg.) DATE REV. BY COMMENTS 05/11/96 JBF Drilled and Cased b Nabors 22E 10/24/96 MDO #1 / #2 (10/26/97) ESP RWO 4ES 01/07/98 MDO ESP RWO 4ES 05/19/98 M.Under ESP changeout 5'S 02/26/07 R. Handy ESP changeouUNew ESP cable Centrilift Seal Section HST31LDBINVPFS Centrilift Series,HMI 800 hp. motor, 4160/114 Centralizer 5 fin 95/8" HES Versatrieve pkr. 51/2",20 ppf, N-80, LTC blank pipe (ID = 4.778" 51/2",0.012" Ga. pre-pack screen (ID = 4.778" 51/2",0.012" Ga. screen (ID = 4.778") 9 5/8" HES Versatrieve pkr. 5 1/2", 20 ppf, N-80, LTC blank pipe (ID = 4.778") 51/2",0.012" Ga. pre-pack screen (ID = 4.778" 51/2",0.012" Ga. screen (ID = 4.778") HES 9 5/8" 'BWD' sump pkr. 9.625" csg. shoe Float collar (PBTD) MILNE POINT UNIT WELL F-02 WSW API NO: 50-029-22673 1980' TVD 2,289' I 2,303' I I 2,338' I 2,439' 2,464' 2,560' 2,773' 2.982' 2,999' 3,025' 3,180' 3274' 3277' 3,363' BP EXPLORATION AK . . Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPF-02 MPF-02 WORKOVER NABORS ALASKA DRILLING I NABORS 3S Start: 2/20/2007 Rig Release: 2/26/2007 Rig Number: N3S Spud Date: End: 2/26/2007 2/21/2007 00:00 - 06:00 6.00 RIGU P PRE Lay Herculite on location. Back Carrier over well with Pad Op present. Rig centered over well. Spot Pipe Shed and Pits. 06:00 - 14:00 8.00 RIGU P PRE Ambient temperature of -48 deg F. Wait on weather. 14:00 - 20:00 6.00 RIGU P PRE Temperature increase to warmer than ·40 deg F. Resume Rig Up operatons. Jack and level rig carrier. MU pipe shed and pit module. Continue RU. 20:00 - 00:00 4.00 RIGU P PRE Attempt to raise the Derrick. Not getting enough hydraulic pressure to lift Derrick. UD Derrick. Pressure Relief Valve Body is washed out on the Hydraulic Pump. Replace Body and Valve. 2/22/2007 00:00 - 01 :00 1.00 RIGU N PRE Continue repairing failed Hydraulic Pump. 01 :00 - 09:00 8.00 RIGU N PRE Accept rig @ 01 :00. Temperature of ·40 degrees F is too cold to raise Derrick per manufacturer's guidelines. Wait on weather. Install additional valve on IA. Lay wood in cellar. R/U on tree to kill well. R/U Berming, Tiger Tank, and Hardline. 09:00 - 13:00 4.00 RIGU N PRE Hold AAR (After Action Review) wI rig crew on rig move, spotting and rigging up rig. Ambient temperature @ -40 deg F. Wait on weather to raise and scope Derrick. 13:00 - 17:00 4.00 RIGU P PRE Raise and scope Derrick. Load pits wI 8.9 #/gal brine. Finish rig up for circulation well kill. 17:00 - 18:00 1.00 DHB P DECOMP PUMU lubricator. Pull BPV. TIIA = 120/200 psi. 18:00 - 23:30 5.50 KILL P DECOMP Pressure Test surface lines to 2500 psi. Push steam through hardline out to Tiger Tank. Begin circulating 55 Bbls of 8.9 ppg bine @ 3 BPM and 230 psi while taking returns through the Choke and to the Tiger Tank. Shut in and blowdown hardline. TIIA = 0/90 psi. Bullhead 65 Bbls of 8.9 ppg brine @ 3 BPM and 190 psi. TIIA = 0/120 psi. Circulate 245 Bbls of 8.9 ppg brine @ 4 BPM and 340 psi while taking returns through the Choke and to the Tiger Tank. Shut down. T/lA = vac/vac. Lost a total of 118 Bbls. 23:30 - 00:00 0.50 KILL P DECOMP Set TWC wI FMC hand on location. PIT to 3,500 psi and chart results. Did not PIT from below due to 3 BPM @ 190 psi bull heading pressure seen during well kill. 2/23/2007 00:00 - 02:00 2.00 WHSUR P DECOMP Drain Tree and break circulation lines. PJSM. N/D Tree. Cap on Penetrator along with an external sleeve had to be removed in order to lift Tree. Move Tree outside of cellar. M/U Opso Lopso XO onto Hanger - 6.5 turns. Break and UD XO. 02:00 - 06:00 4.00 WHSUR P DECOMP PJSM. N/U BOPE. 06:00 - 07:30 1.50 WHSUR N HMAN DECOMP Fish flashlight out of stack (was dropped down on top of TWC by roughneck). 07:30 - 12:00 4.50 WHSUR N RREP DECOMP Ambient temperature of -50 deg F. Begin function testing for BOPE testing. HCR frozen on stack. Apply tioga heater and steam to thaw. AOGCC witness of test waived by John Crisp. 12:00 - 18:00 6.00 WHSUR P DECOMP HCR thawed out. Swap hoses from Koomey unit to hook up extra set. Appears to be a problem with koomey hose connector or barksdale valve on Koomey Unit. Function HCR. Finish function testing of BOPE. Start BOPE pressure testing, 250 psi low I 3500 psi high I 3500 psi on annular preventer: 18:00 - 21 :30 3.50 PULL P DECOMP M/U XO on bottom of Opso Lopso. RIH and M/U Opso Lopso to Hanger. P/U and M/U Lubricator on top of Opso Lopso. Pull TWC. T/IA = 010 psi. POH wI TWC 1.5'. Break out Opso lopso from Hanger. POH and UD Lubricator and Opso lopso. 21 :30 - 22:30 1.00 PULL P DECOMP M/U 4-1/2" NSTC Landing joint (wI XO to the TIW valve) up to Printed: 2/2612007 1 :52:09 PM . . Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPF-02 MPF-02 WORKOVER NABORS ALASKA DRILLING I NABORS 3S Start: 2/20/2007 Rig Release: 2/26/2007 Rig Number: N3S Spud Date: End: 2/26/2007 2/23/2007 21 :30 - 22:30 1.00 PULL P DECOMP the Hanger. 22:30 - 23:30 1.00 PULL P DECOMP R/U 5-1/2" completion pulling equipment (Power Tongs). 23:30 - 00:00 0.50 PULL P DECOMP R/U Sheave and Elephant Trunk. 2/24/2007 00:00 - 04:00 4.00 PULL P DECOMP R/U Sheave and Elephant Trunk. After Action Review conducted to discuss performance of task. 04:00 - 06:30 2.50 PULL P DECOMP Pull Hanger to the Floor. P/U weight to unseat = 45k-lbs and 43k-lbs. free pull. T/IA = 0/0 psi. FMC redressed Hanger on the Floor. UD landing Joint and XO. UD Hanger into the Pipe Shed. Fill hole wI 113 Bbls 8.9 ppg brine. 06:30 - 12:30 6.00 PULL P DECOMP POOH to connect cable to spooling Unit. Shoot FL @ 750'. POOH laying down 5 1/2" Tbg. 40 jts OOH @ 1115-hrs. Found one bad Collar and one bad Pin out of the 55 jts pulled. 12:30 - 15:00 2.50 PULL P DECOMP Break and UD ESP into Pipe Shed. Test on Motor: 1.0 ohm balanced (phase to phase), 4.2/3.6/4.2 ohms (phase to ground). Test on Cable: 9.16/16.7/36.2 giga ohms (phase to phase), 16k112.2G/12.6G ohms (phase to ground). Cable is probable source of failure. 15:00 - 21 :30 6.50 RUNCO RUNCMP M/U ESP per Centrilift's recommendations. Pull new ESP cable from Spooler, through Elephant Trunk, over Sheave, and connect to ESP. 21 :30 - 22:00 0.50 RUNCO RUNCMP PJSM. RIH wI ESP and install 2-flatgaurds and 5-Protectorlizers. 22:00 - 23:00 1.00 RUNCO WAIT RUNCMP Wait on Centrilift to bring proper screw to install final Protectolizer. 23:00 - 00:00 1.00 RUNCO RUNCMP RIH wi ESP on 5-1/2" Tubing picked up from the Pipe Shed. Use Best of life 2000 Pipe Dope. Run 5-1/2" Cable Protectors on every full joint to surface. MU IBT-Mod connections to the mark. Filling hole wi 25 Bbls of 8.9 ppg brine wi Charge Pump every 10 joints RIH. 2/25/2007 00:00 - 07:00 7.00 RUNCO RUNCMP RIH wi ESP on 5-1/2" Tubing picked up from the Pipe Shed. Use Best of life 2000 Pipe Dope. Run 5-1/2" Cable Protectors on every full joint to surface. MU IBT-Mod connections to the mark. Filling hole w/10 Bbls of 8.9 ppg brine wI Charge Pump every 10 joints RIH. Replaced jts #50 and #51 (net loss of length = 2.82'). 10 jts in @ 0100-hrs. 20 jts @ 0200-hrs. 30 jts @ 0300-hrs. 35 jts @ 0400-hrs. 45 jts @ 0500-hrs. 07:00 - 08:00 RUNCMP 55 joints in hole. MU TIW valve and head pin. Load tubing with 20 bbls of 8.9# brine and flush with an additional 15 bbls. 3 BPM @ 340 psi. Change elevators, MU TIW and head pin on 4 1/2" landing joint. PU landing joint. 08:00 - 08:30 RUNCMP PUMU tubing hanger. 4 1/2" NSCT top and bottom of hanger. XO to 5 1/2" Mod Btc Tbg. MU to proper torque. Install penetrator. 08:30 - 10:00 RUNCMP Centrilift make splice for penetrator connector. Clean and clear rig floor while making splice. Prep for NO BOPE and NU tree. 56 Lasalle clamps, 5 protectolators, and 2 flat cable guards placed on tubing during ESP installation. Cable check of 1.4 balanced phase-phase I infinity phase-ground I 2.4 meg ohms 10:00 - 12:00 2.00 RNTBH P TUBHGR PU of 52K #'s, SO of 47K #'s. Orient and land tubing hanger. RILDS. Change out 2 packing glands on tubing hanger. Dry rod TWC. Tests from above to 3500 psi and chart for 10 minutes. Drain stack. 12:00 - 18:00 POST RD shieve, elephant trunk, ESP running equipment. Blow Printed: 2/26/2007 1 :52:09 PM .. . . legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPF-02 MPF-02 WORKOVER NABORS ALASKA DRilLING I NABORS 3S Start: 2/20/2007 Rig Release: 2/26/2007 Rig Number: N3S Spud Date: End: 2/26/2007 21:00 - 22:30 1.50 DHB P POST down choke and all manifolds. ND BOPE. N/U Tree and Adapter Flange. Test Tree and Adapter Flange to 5,000 psi and chart. Lost 0 psi in 10 minutes. Good test. Conduct final conductivity tests for the ESP Cable. Test is good. Wait on Wells Support to bring proper XO for Lubricator. . Pull TWC wI Lubricator and set BPV. TII = % psi. Secure Tree and Cellar. RDMO. Release rig @ OOOO-hrs 22:30 - 00:00 1.50 DHB P POST Printed: 2/26/2007 1 :52:09 PM RE: MPU Water Supply Wells • • Subject: RE: MPU Water Supply Wells From: "MPU, Well Operations Supervisor" < welloperationssupervisor @BP.com> Date: Fri, 02 Mar 2007 13:49:38 -0900 To: Thomas Maunder <torn maunder@admin .state.a ,us> Tom, I from what I know, they have always been ESPs. If you would like, I can dig back through the well files. Please let me know. *AWNED Thanks, APR 1 2 2011 John R. Cubbon MPU Well Operations Supervisor 1- 907 - 670 -3330 Original Message From: Thomas Maunder [mailto :tom maunder@admin. tate.ak.us] Sent: Friday, March 02, 2007 1:28 PM To: MPU, Well Operations Supervisor Subject: Re: MPU Water Supply Wells Thanks John. For the ESP wells, they have always been ESPs correct? Tom MPU, Well Operations Supervisor wrote, On 3/2/2007` ` 1:17 PM: ` i ! Hi Tom, i \S O 11) V �°- > ` S ! O \ o The information for these wells is as follows: F -02 ESP Completion Active Water Supply Well iC1(0- 0`A O A2A ESP Completion Active Water Supply Well tC6 S . ‘Cig 3-01 ESP Completion Non- Active Water Supply Well (has not been utilized since at least 2004, and likely much longer) C %©� dt F -21 ESP Completion Active Water Supply Well ‘S(4:)--\" F -58 ESP Completion Active Water Supply Well \S(0 F -77 ESP Completion Active Water Supply Well S -22 Jet Pump Completion in the UGNU. Has been SI since 2005 due to excessiv an production. S 90 Dr;lled as a hot Ivishak water supply well in 2006. We are evaluating completion options and trying to overcome potential a ©S - \ � c corrosion challenges due to the high CO2 content of the water. Tentative plan to put into service later in 2007. I hope this helps Tom. If you have any questions, or need any further details, please don't hesisitate to let me know. Thanks John R. Cubbon MPU Well Operations Supervisor 1- 907 - 670 -3330 1 of 2 3/2/2007 1:58 PM RE: MPU Water Supply Wells s • Original Message From: Thomas Maunder [ma.iito: tom maunder @admin. state.ac. _ s] Sent: Monday, February 26, 2007 3:13 PM To: Cubbon, John R Subject: MPU Water Supply Wells John, I see that MPF -02 was just worked over. In the course of checking a few things, I noticed in our production report that this well was reported to be a flowing completion and it appears to have been since completion in August 1996. I have checked our reports on your other wells and found the following: MPA -02A -- submersible, SI or no information to August 1995, then flowing or no information since. MPB- 01 - - -- submersible, SI or no information to January 1998, then flowing to September 2001 and SI since MPF- 21 - - -- flowing since completion June 1997 MPF- 58 - - -- flowing since completion November 1996 MPF- 77 - - -- flowing since completion April 1996 MPK- 34 - - -- flowing since completion December 1997 MPS- 22 - - -- hydraulic pump or flowing since completion in October 2003, SI mostly MPS- 90 - - - -no water production reported I think the production method for all the wells is ESP. Am I correct? I am not sure where the error might be coming from. When you confirm the production method, I will get with our stat techs here and see how we are receiving the information. Then I will get back to you and we can see what changes may be needed. Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC 2 of 2 3/2/2007 1:58 PM RE: Milne Point K-pad water supply well MPK-34 (PTD #1961690)... e e Subject: RE:Milne Point K-pad water supply well MPK-34 (PTD #1961690) and F-Pad water supply wells ~21, 58, and 77~wP#t~_~:i1I1961350, #1961560, and #1951360) From: "MPU ,. Well Operations'Supervi"sör":<:welloperationssupervisor@BP .com> Date: Thu,29 Dee 200507:05:21 -0900,,' To: Thomas Mau~d~J <tom _ maunder@admiil.statlak.us>' .... . Thanks Tom! JRC ~C^NNfL Z f From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Thursday, December 29, 2005 6:50 AM To: MPU, Well Operations Supervisor Cc: MPU, Operations Manager; Jim Regg Subject: Re: Milne Point K-pad water supply well MPK-34 (PTD #1961690) and f-Pad water supply wells MPf-02, 21, 58, and 77 (PTD #1960700, #1961350, #1961560, and #1951360) Hi John, I did some checking as well. Your understanding regarding a regulatory requirement for SSV s on water supply wells is correct. There is no requirement to employ SSV s on such wells. Thanks for checking. Tom Maunder, PE AOGCC MPU, Well Operations Supervisor wrote, On 12/28/2005 6:12 PM: Hi Tom, As per our conversation yesterday, I am curious if we are required to have a functioning SSV on our water supply wells here at Milne Point. These wells produce from the Prince Creek and Ugnu formations and are not hydrocarbon producing. From what I can gather reading through the regulations, I can't see where we are required to have a functioning SSV on these wells, but wanted to check with you to make sure. The wells were equipped with SSVs when they were drilled, but we would like to remove the panels and use them elsewhere if they are not required on our source water wells. Our source water wells are not capable of unassisted flow and are produced with Electrical Submersible Pumps. These wells are equipped with pilots that will shut down the ESP if the flowline pressure drops below 500 psi (i.e. we develop a leak). Thanks for your help on this Tom and please don't hesisitate to let me know if you need any further information. Best Regards. John R. Cubbon MPU Well Operations Supervisor 1-907 -670-3330 1 of 1 12/29/20057:10 AM Olq OR BgFO jANUARY 03 2001 C:LORlkN~'DOC PERMIT DATA ............. 96-070 GR/CCL (SET) 96-070 GR/CCL (PERF) 96-070 GR/CCL 96-070 GR/CCL - PERF 96-070 GRAVEL PACK 96-070 PERF RCD 96-070 DGR/RES-MD 96-070 DGR/RES-TVD 96-070 7903 10-407 AOGCC Individual Well Geological Materials Inventory DATA PLUS ~950-3252 ~40-3281 ~/2500-2975 ~286-3272 ~2100-2229 193-3385_ ~t~/1~91 _ 2903 RY GR/RES Page: 1 Date: 09/15/98 T / RUN RECVD D .............. 1 08/30/96 1 08/30/96 1 08/30/96 FINAL 09/11/96 FINAL 11/08/96 FINAL 11/08/96 FINAL 12/23/96 FINAL 12/23/96 1-3 02/12/97 PLETIO~ DATE /0 /~/~/ DAILY WELL OPS R Are dry ditch samples required? yes ~~d received? y~ Was the well cored? yes ~nalysis & description received? Are well tests required?_ ~yes ~Received? Well is in compliance Initial CO~ENTS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION C¢OMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: [] Pull Tubing [] Operation Shutdown [] Stimulate [] Plugging [] Perforate []Alter Casing [] Repair Well [] Other ESP Changeout 5. Type of well: 6. Datum Elevation (DF or KBE) [-1 Development KBE = 41' [] Exploratory [] Stratigraphic 7. Unit or Property Name [] Service Milne Point Unit 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1774' NSL, 2890' WEL, Sec. 6, T13N, R10E, UM At top of productive interval 1441' NSL, 3579' WEL, Sec. 6, T13N, R10E, UM At effective depth 1142' NSL, 4193' WEL, Sec. 6, T13N, R10E, UM At total depth 1111' NSL, 4302' WEL, Sec. 6, T13N, R10E, UM 8. Well Number MPF-02 9. Permit Number / Approval No. 96-70 10. APl Number 50° 029-22673 11. Field and Pool Milne Point/Prince Creek 12. Present well condition summary Total depth: measured 3385' feet Plugs (measured) true vertical 2903' feet Effective depth' measured 3277' feet Junk (measured) true vertical 2815' feet Casing Length Size Cemented Structural Conductor 82' 20" 250 sx Arcticset (approx) Surface 3363' 9 5/8" 750 sx PF 'E', 500 sx 'G' Intermediate 150 sx PF 'E' Production Liner MD TVD 112' 112' 3363' 2878' Perforation depth: measured 2575'-2624', 2704'-2764', 2780'-2894', 2914'-2964', 3034'-3149', 3234'-3264' true vertical 2246'-2287', 2351 '-2399', 2415'-2503', 2519'-2560', 2616'-2710', 2779'-2804' Tubing (size, grade, and measured depth) 5 1/2" 17# L-80 to 2247' Packers and SSV (type and measured depth) 9 5/8" HES Versatrieve Pkr @ 2439' & 2982'. HES 9 5/8" BWD Sump Pkr @ 3274' 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure ORIGINAL 14. Prior to well operation: Subsequent to operation: Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl 15. Attachments [] Copies of Logs and Surveys run [] Daily Report of Well Operations Casing Pressure Tubing Pressure 16. Status of well classifications as: [] Oil [] Gas [] Suspended Service Prince Creek Water Source 17. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed (~.¢¢~¢__~ C:~, ~?_.~.~L~ Title ~p.¢_/~ ate ~ :,/2- ,~ ~ ~ repared By Name/Number.'~ ~ 10-404 R v. 06/lS/ Su '% Du¢icat ~. Facility Date/Time 17 May 98 18 May 98 19 May 98 20 May 98 Progress Report M Pt F Pad Well MPF-02 Page 1 Rig Nabors 5S Date 21 May 98 06:00-06:15 06:15-07:30 07:30-08:00 08:00-20:00 20:00-00:00 00:00-01:30 O1:30-02:30 02:30-06:00 06:00-06:15 06:15-08:30 08:30-10:00 10:00-11:30 11:30-13:30 13:30-15:00 15:00-16:30 16:30-19:30 19:30-21:30 21:30-00:00 00:00-04:30 04:30-06:00 06:00-06:15 06:15-09:30 09:30-17:00 17:00-18:00 18:00-21:30 21:30-22:30 22:30-00:30 00:30-02:30 Duration 1/4 hr 1-1/4 hr 1/2hr 12 hr 4hr' 1-1/2 hr lhr 3-1/2 hr 1/4 hr 2-1/4 hr 1-1/2 hr 1-1/2 hr 2hr 1-1/2 hr 1-1/2 hr 3hr 2hr 2-1/2 hr 4-1/2 hr 1-1/2 hr 1/4 hr 3-1/4 hr 7-1/2 hr lhr 3-1/2 hr lhr 2hr 2hr Activity Held safety meeting Rigged down Travelling block Held safety meeting Rig moved 100.00 % Bleed down well Circulated at 2330.0 ft Removed Xmas tree Rigged up BOP stack Held safety meeting Tested BOP stack Removed Hanger plug Pulled Tubing on retrieval string to 2308.0 ft Removed Tubing hanger Laid down 200.0 ft of Tubing Rig waited: Materials Pulled Tubing in stands to 0.0 ft Rigged down sub-surface equipment - ESP Conducted slickline operations on Slickline equipment - Retrival run Functioned ESP Rigged up sub-surface equipment - ESP Held safety meeting Installed ESP Ran Tubing to 2330.0 ft (5-1/2in OD) Installed Tubing hanger Installed ESP Removed BOP stack Installed Xmas tree Displace treatment STATE OF ALASKA ALASK/-~ OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: []Operation Shutdown []Stimulate [] Plugging [] Perforate [] Pull Tubing []Alter Casing [] Repair Well [] Other ESP Replacement 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1774' NSL, 2890' WEL, Sec. 6, T13N, R10E, UM At top of productive interval 1441' NSL, 3579' WEL, Sec. 6, T13N, R10E, UM At effective depth 1142' NSL, 4193' WEL, Sec. 6, T13N, R10E, UM At total depth 1111' NSL, 4302' WEL, Sec. 6, T13N, R10E, UM 5. Type of well: [] Development [] Exploratory [] Stratigraphic [] Service 6. Datum Elevation (DF or KBE) KBE = 41' 7. Unit or Property Name Milne Point Unit 8. Well Number MPF-02 9. Permit Number / Approval No. 96-70 10. APl Number 50- 029-22673 11. Field and Pool Milne Point/Prince Creek 12. Present well condition summary Total depth: measured 3385' feet true vertical 2903' feet Effective depth: measured 3277' feet true vertical 2815' feet Casing Plugs (measured) Junk (measured) Length Size Cemented Structural Conductor 82' 20" 250 sx Arcticset (approx) Surface 3363' 9 5/8" 750 sx PF 'E', 500 sx 'G' Intermediate 150 sx PF 'E' Production Liner MD TVD 112' 112' 3363' 2878' Perforation depth: measured 2575'-2624', 2704'-2764', 2780'-2894', 2914'-2964', 3034'-3149', 3234'-3264' true vertical 2246'-2287', 2351'-2399', 2415'-2503', 2519'-2560', 2616'-2710', 2779'-280~~' ii~., !..., ~.~ ;:' _~:!i,~ ~_ ~ Tubing (size, grade, and measured depth) Packers and SSV (type and measured depth) 5 1/2" 17# L-80 to 2330' _ . 9 5/8" x 3 1/2 HES "RDH" @ 2211 ', 9 5/8" HES Versatrieve Pk¢@':;~9}~ 2982'. HES 9 5/8" BWD Sump Pkr @ 3274' 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure OEIG!NAL 14. Prior to well operation: Subsequent to operation: Representative Daily Average Production or In!ection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 15. Attachments [] Copies of Logs and Surveys run [] Daily Report of Well Operations 16. Status of well classifications as: [] Oil [] Gas [] Suspended Service Prince Creek Water Source 17. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Chip Alvord ,~~ ( (~ Title Engineering Supervisor Date .~ f2_,~ [,,~& Prepared By Name/Number: Mary Youngers 564-5242 Form 10-404 Rev. 06/15/88 Submit In Duplicate~ SUMMARY OF DALLY OPERATIONS SHARED SERVICES DRILLING - BPX/ARCO Well Name: MPF-02 Rig Name: N-4ES AFE# 339026 Accept Date: 10/22/96 Spud Date: . Release Date: 10/25/96 OCTOBER 23, 1996 ACCEPT RIG @ 1700 ON 10/22/96. TAKE ON 9.2 PPG BRINE, PULL BPV MONITOR WELL SITP 90 PSI, SICP 130 PSI RU LINES TO TREE & TIGER TANK TO KILL WELL. KILL WELL W/9.2 BRINE BY PUMPING DOWN TUBING TAKING RETURNS TO TIGER TANK THRU CHOKE, CIRCULATE TUBING VOLUME OF 33 BBLS BULL HEAD 28 BBLS INTO PERFS CIRCULATE OUT ANNULUS TO TIGER TANK ON CHOKE - MONITOR WELL, WELL DEAD FLUID LOSS 44 BBLS PER HR TO FORMATION. SET TWC VALVE, ND CIW 4 1/16 5000# TREE & ADAPTER SPOOL NU 13 5/8" BOP STACK, CHANGE PIPE RAMS TO 4 ~" CUT BRINE WT TO 9.0 PPG TEST BOP TEST ALL RAMS, LINES & VALVES TO 250 LOW & 5000 PSI HIGH TEST HYDRILL TO 250 & 3000 PSI TEST KELLY, UPPER & LOWER KELLY VALVES TIW & IBOP TO 250 & 5000 PSI WITNESS OF BOP TEST WAIVED BY MR. FOSTER OF AOGCC. PULL TWC FILL HOLE 15 BBLS TO FILL MU LANDING JT TO HANGER PULL ON TUNING AND SHEAR BAKER 9 5/8" ESP @ 135k, 95k OVER STRING WT - PULL TUBING HANGER TO RIG FLOOR. LD TUBING HANGER PERPARE TO POOH LD 4 ~" 12.6# L-80 IMP BTC TUBING FLUID LOSS TO FORMATION 44 BLS/HR TO FORMATION. OCTOBER 24, 1996 SERVICE RIG MONITOR WELL, FLUID LOSS 70 BBL/HR. SLIP DRILL LINE. POOH W/ESP LD 54 JTS 4 ~" 12.6# L-80 BIC MOD & BAKER CT-ESP PACKER INSPECT & LD ESP MOTOR BURNT TOP PUMP LOCKED UP, BOTTOM PUMP FREE FOUND SMALL PIECE OF METAL FROM FLAT BAND ON OUTSIDE OF SEAL SECTION - RECOVERED 116 PREFORMED BANDS & 14 FLAT BANDS LOST 5 FLAT BANDS IN HOLE RIG UP SCHLUMBERGER WIRELINE, RIH W/1 11/16" TDT GRAVEL PACK INSPECTION LOG TO 3262' WLTD - TOOL FAILED POOH. RIH W/BACKUP TDT LOG 3252' TO 2268' POOH. RIH W/8.5 GR/JB TO TOP OF GRAVEL PACK @ 2429' POOH RECOVERED ONE FLAT BAND, RERUN GR/JB, RECOVERED SECOND FLAT BAND, RERUN GR/JB, NO RECOVERY RD WL CHANGE RAMS TO 5 Y2" TEST RAMS TO 5000 PSI OK. MU & SERVICE ESP. MU HOWCO PACKER & INSTALL PENETRATOR. MAKE SPLICE ON ESP CABLE BELOW PACKER. CUT BRINE WT. 9.2 TO 8.6 PPG FLUID LOSS 12 BBLS/HR @ 0600 HRS W/8.6 NACI. OCTOBER 25, 1996 COMPLETE SPLICE OF ESP CABLE ABOVE & BELOW PACKER. RIH W/ESP ON 53 JTS 5 ~" 17.0# L-80 LMP BUTT TUBING MU TUBING HANGER & SPLICE CABLE @ HANGER. LAND TUBING SET TWC VALVE & TEST TO 2000 PSI. ND BOP STACK, NU 11 x 4 1/16 5000# ADAPTER SPOOL NU CIW 4 1/16 5000# TREE - TEST ADAPTER & TREE TO 5000 PSI. FINAL TEST ON ESP CABLE OK. FREEZE PROTECT WELL W/158 BBLS OF DIESEL BY PUMPING DOWN ANNULUS & Page 1 of 2 SUMMARY OF DALLY OPERATIONS TAKING RETURNS UP TUBING @ 3A BBL/MIN 80 PSI FREEZE PROTECTED ANNULUS & TUBING. DROP 1 5/6" BALL, PRESSURE UP TO 3500 PSI SET PACKER @ 2211' & TEST TUBING TEST ANNULUS TO 3500 PSI. ANNULUS BLED TO 3100 PSI IN 10 MINUTES - SET 4" BPV W/LUBRICATOR, RIG DOWN LINES SECURE WELL. RIG RELEASED @ 0400 HRS. Page 2 of 2 Facility M Pt F Pad Progress Report Well MPF-02 Page 1 Rig Nabors/55/-~/'~'53 Date 17 June 98 Date/Time 24 Oct 97 25 Oct 97 26 Oct 97 06:00-10:30 10:30-13:00 13:00-16:00 16:00-19:00 19:00-22:00 22:00-04:30 04:30-06:00 06:00-11:30 11:30-15:30 15:30-18:00 18:00-21:00 21:00-03:00 03:00-04:30 04:30-06:00 06:00-09:30 Duration 4-1/2 hr 2-1/2 hr 3hr 3hr 3hr 6-1/2 hr 1-1/2 hr 5-1/2 hr 4hr 2-1/2 hr 3hr 6hr 1-1/2 hr 1-1/2 hr 3-1/2 hr Activity Rig moved 100.00 % Removed Xmas tree Installed BOP stack Tested All rams Laid down 2275.0 ft of Tubing Laid down 2275.0 ft of Tubing Conducted slickline operations on Slickline equipment - Tool run Conducted slickline operations on Slickline equipment - Tool run Installed ESP Ran Tubing to 570.0 ft (5-1/2in OD) Ran Tubing to 2336.0 ft (5-1/2in OD) Ran Tubing to 2336.0 ft (5-1/2in OD) Rigged down BOP stack Installed Xmas tree Freeze protect well - 145.000 bbl of Diesel Facility M Pt F Pad Progress Report Well MPF-02 Page 1 Rig Nabors 4ES Date 17 February 98 Date/Time 04 Jan 98 05 Jan 98 06 Jan 98 07 Jan 98 10:00 18:00 00:30 02:30 03:30 06:00 06:30 10:00 16:00 00:30 01:30 06:00 06:30 13:30 22:00 01:30 06:00 06:30 09:30 12:00 12:30 13:30 14:30 15:00 16:00 19:00 20:00 Duration Activity Resumed operations At well location - Slot Equipment work completed Hole displaced with Brine - 100.00 % displaced Equipment work completed Stopped: To hold safety meeting Began precautionary measures Suspended function test, problems encountered Aborted equipment work Equipment work completed Function test completed satisfactorily Stopped: To hold safety meeting Began precautionary measures Equipment work completed Completed operations Completed run with Cleaning / Investigation tools from 0.0 ft to 3262.0 ft Stopped: To hold safety meeting Completed operations Stopped: To splice cable Equipment work completed Hanger landed Equipment work completed Equipment work completed Pressure test completed successfully - 5000.000 psi Equipment work completed Completed operations Equipment work completed CI I:t I I--I- I I~1 G S E I::! ~./I !~ ~: S WELL LOG TRANSMITTAL To: State of Alaska February 12, 1997 Alaska Oil and Gas Conservation Comm. Attn.: Loft Taylor 3001 Porcupine Dr. Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs - MPF-02 AK-MM-60522 The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of~ Jim Galvin, Sperry-Sun Drilling Services, 5631 Silverado Way, #G, Anchorage, AK 99518 1 LDWG formatted Disc with verification listing. API#: 50-029-22673-00 5631 Silverado Way, Suite G · Anchorage, Alaska 99518 · (907) 563-3256 · Fax (907) 563-7252 A Dresser Industries, Inc. Company "-" STATE OF ALASKA " ALASK~ OIL AND GAS CONSERVATION CO~viMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well [] Oil [] Gas [] Suspended [] Abandoned [] Service Prince Creek Water Source 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 96-70 ..... 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-22673 4. Location of well at surface ~ 9. Unit or Lease Name 1774' NSL, 2890' WEb, SEC. 6, T13N, R10Ei?'¢'~"¥~II Milne Point Unit At top of productive interval~.....,"~-r'~.,~.' ~ i 10. Well Number 1441' NSL, 3579' WEb, SEC. 6, T13N, R10E l~mN~("'~lt MPF-02 At total depth~ 11. Field and Pool 1111' NSL, 4302' WEb, SEC. 6, T13N, R10E Milne Point/Prince Creek 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. KBE = 41.25'I ADb 025509 12. Date Spudded05/09/96 I13' Date T'D' Reached I 14' Date C°mp" Susp" °r Abandl15' Water depth' if °ffsh°re I 16' N°' °f C°mpleti°ns05/10/96 10/25/96 N/A MSLI One 17. Total Depth (MD+TVD) 118. Plug Back Depth (MD+TVD)I19. Directional SurveyI20. Depth where SSSV set~l. Thickness of Permafrost 3385 2903 FTI 3277 2815 FT~ I~Yes LINc I N/A MD! 1800' (Approx.) 22. Type Electric or Other Logs Run MWD, LWD, GR/RES, GR/CCL, EMSS, TDT, GR/JB 23. CASING, LINER AND CEMENTING RECORD CASING SE'FrING DEPTH HOLE SIZE VVT. PER FT. GRADE TOP BO-FrOM SIZE CEMENTING RECORD AMOUNT PULLED 20" 91.1# H-40 30' 1 12' 24" 250 SX Arcticset I (Approx.) I 9-5/8" 40# L-80 29' 3363' 12-1/4" 1750 sx PF 'E', 500 sx 'G', 150 sx PF 'E' 24. Perforations open to Production (MD+TVD of Top and Bottom 25. TUBING RECORD and interval, size and number) SIzE DEPTH SET (MD) PACKER SET (MD) 4-1/2" Gun Diameter, 12 spf 5-1/2", 17#, L-80 2357' 2211' MD TVD MD -I-VD 2574'-2624' 2246'-2287' 2704'-2764' 2351 '-2399' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 2780'-2894' 2412'-2503' 2914'-2964' 2519'-2560' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 3034'-3149' 2616'-2710' Freeze protect w/158 bbls diesel 3234'-3264' 2779'-2804' GraveI-Pac, 2439'-2982' 132000# 20/40 Carbolite behind pipe Gravel-Pac, 2999'-3274' 3800# 20/40 Carbolite behind pipe 27. PRODUCTION TEST Date First Production IMethod of Operation (Flowing, gas lift, etc.) August 26, 1996 I Water Source Date of Test Hours Tested PRODUCTION FOR OIL-BBb GAS-MCF WATER-BBb CHOKE SIZE I GAS-OIL RATIO TEST PERIOD · I Flow Tubing Casing Pressure CALCULATED OIL-BBb 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. Anchorage Form 10-407 Rev. 07-01-80 Submit In Duplicate 29. Geologic Marke,.~ 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. (Subsea) Top Water Sands 2045' 1783' Base Water Sands 3140' 2661' 31. List of Attachments Summary of Daily Drilling Reports, Surveys 32. I hereby certify that the foregoing is tue and c rrect to the best of my knowledge TimSchofield /~¥) Title Senior Drilling Engineer Date 7 Prepared By Name/Number: Kathy Camlboardor, 564-5122 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage 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 Anchore~9 SUMMARY OF DAILY OPERATIONS SHARED SERVICES DRILLING - BPX / ARCO Well Name: M PF-02 Rig Name: N-22E AFE: 33701 2 Accept Date: 05/08/96 Spud Date: 05/09/96 Release Date: 05/1 2/96 May 8 1996 (1) RD high pressure lines. Rig moved 20%. Rig moved 40%. May 9 1996 (2) Held safety meeting. Rig moved 100%. Nabors rig #22E accepted 05/08/96 @ 1600 hrs. RU flowline. RU divertor. MU BHA #1. MU BHA#1. RU divertor. May 10 1996 (3) Held safety meeting. RU divertor. Drilled to 200 ft. MU BHA #1. Drilled to 2030 ft. Held drill (kick while drilling). May 11 1996 (4) Held safety meeting. Drilled to 2221 ft. Circulated at 2221 ft. POOH to 258 ft. RIH to 2221 ft. Drilled to 3385 ft. Circulated at 3385 ft. POOH to 1100 ft. RIH to 3385 ft. Circulated at 3385 ft. POOH to 258 ft. Downloaded MWD tool. Pulled BHA. Serviced casing handling equipment. May 12 1996 (5) Held safety meeting. Ran casing to 3362 ft (9.625" OD). Circulated at 3362 ft. Mixed and pumped slurry- 390 bbl. Tested casing. Mixed and pumped slurry- 58 bbl. RD divertor. Installed wellhead integral components. Installed Xmas tree. Freeze protect well- 70 bbl of diesel. Nabors rig #22E released 05/12/96 @ 0400 hrs. Skid rig. Page SUMMARY OF DALLY OPERATIONS SHARED SERVICES DRILLING - BPX ! ARCO Well Name: M P F-02 Rig Name: N - 4 E S AFE: 337012,339026 Accept Date: 08/12/96,10/22/96 Spud Date: Release Date: 08/18/96,10/25/96 Aug 12 1996 MIRU. Spot & berm. Raise & scope derrick & safe out same. Check PSI & ND tree. NU BOP's. Nabors rig #4ES accepted 08/12/96 @ 0400 hrs. Aug 13 1996 Cont NU BOP's. Rig floor & MU BHA #1. RIH with 4-1/2" tubing t/2460'. Displace diesel to TT. Cont RIH with BHA #1 t/3269'. Rec circ & displace seawater to TT with filtered brine. POOH with 4-1/2" tubing. Test 9-5/8" casing t/4500 psi, ok. ND flowline & NU shooting flange. Rig Atlas & test lub. RIH with GR/CCL t/3276' & log to surface. Aug 14 1996 Perf zones with Atlas #1, 3234'-3264'. Zone #2--4 gun runs, 3149'-3034'. Had one misrun with guns & run GR/JB 3 times. MU HES "BWD" Sump Packer & RIH on e-line & set @ 3274'. ND perf flange & NU flow nipple. MU HES gravel pack screens & 9-5/8" VTL packer assy. RIH with gravel pack assy on 4-1/2" tubing & space out same. Rig BJ valve & sting into sump packer. Drop setting ball & set packer. Aug 15 1996 Set packer @ 3000 psi & test annulus t/2500 psi. Release running G tool & rev circ setting ball. Rig BJ & test lines. Pump 12 bbl acid & reverse out. Estimate pressure rates & pump gravel pack 1800# (est) sand behind screen & screen out & re-stress with rig pump. Estimate rate. Mix & pump 10 bbl, 10 ppg sand & put 2000# behind screen before screen packed. Total of 3800#, restress with rig. RD B J, monitor well. Pump dry job. POOH & LD HES frac-pac tool. MU running tool & JP plug. TIH with 4-1/2" tubing. Tag packer & set JP plug @ 2959' (4ES KB) w/5K over down weight, verify latch in w/5K over. Release f/plug & test t/500 psi. Dump 6' sand on plug. TOH & LD tubing & running tool. NU shooting flange & Atlas & test lub. RIH with gun #1 & correlate to GR/CCL & perf @ 2944'-2964' Aug 16 1996 Cont perf for a total of 13 runs, had 3 re-runs. Perf intervals #1,2964'-2914'. #2, 2894'-2780'. #3, 2764'-2704'. #4, 2624'-2574'. RD shooting flange & NU flowline. MU JP plug retrieve tool & 9-5/8" casing scraper t/2551'. Pump 20 bbl zanvis pill. Cont RIH t/29653' with scraper & JP pulling tool. Rev out fill. Wash over plug & release plug. TOH & LD JP plug & scraper. PU & MU HES gravel pack screen assy. Page Aug 17 1996 MU HES gravel pack assy & RIH with same. RU frac head, drop 2" bali & set packer @ 2441' Bleed tubing & test annulus. Shear ball out. Rev circ & ball out. Rig BJ test lines. Perform step rates & cont with gravel pack. Pump 9200# sand in stages #1 & re-batch & pump 7100# & pack screen & rev out excess sand in tubing. Re-stress screen 2 times. RD frac equp & POOH & LD HES frac tool. Pull WR & rig floor to run ESP completion. MU ESP assy & maintenance inspect on same. Aug 18 1996 MU ESP assy & Baker 9-5/8" CT-ESP packer. Make splices at packer. RIH with ESP completion & MU hanger. Splice pig tail @ tubing hanger. Land tubing hanger. RILDS, install TVVC. ND BOP's & install 2-7/8" rams & NU prod tree. Test hanger & tree. Freeze protect annulus & tubing with 170 bbl diesel. Drop setting ball & set packer. Test annulus. RU lub & set BPV & secure well. Nabors rig #4ES released 08/18/96 @ 0100 hrs. Oct 23 1996 MIRU. Nabors rig #4ES accepted 10/22/96 @ 1700 hrs. Take on brine, pull BPV, monitor well. RU lines to tree & tiger tank to kill well. Kill well with brine by pumping down tubing, taking returns to tiger tank thru choke. Circulate tubing volume, bullhead 28 bbls into perfs. Circulate out annulus to tiger tank on choke. Monitor well, well dead, fluid loss to formation. Set TWC valve, ND CIW tree & adapter spool. Nipple up 13-5/8" BOP stack, change pipe rams to 4-1/2", cut brine weight. Test BOP, test all rams, lines & valves. Test hydril. Test kelly, upper & lower kelly valves. TIW & IBOP, witness of BOP test waived by Mr. Foster with AOGCC. Pull 'I-VVC, fill hole. MU landing jt to hanger. Pull on tubing & shear Baker 9-5/8" ESP. Pull tubing hanger to rig floor. LD tubing hanger, prepare to POOH. LD 4-1/2" tubing. Fluid loss to formation. Oct 24 1996 Monitor well. Slip drill line. POOH with ESP, LD 54 jts 4-1/2" & Baker CT-ESP packer. Inspect & LD ESP--motor burnt, top pump locked up, bottom pump free, found small piece of metal from flat band on outside of seal section. Recovered 116 preformed bands & 14 flat bands--lost 5 bands in hole. RU Schlumberger wireline, RIH with TDT gravel pack inspection Icg to 3262'. Tool failed, POOH. RIH with back up TDT--Iog 3252'-2266', POOH. RIH with GR/JB to top of gravel pack at 2429', POOH recovered 1 flat band. Re-run GR/JB, recovered second flat band. Re-run GR/JB, no recovery. RD WL. Change rams to 5-1/2" & test, ok. MU & service ESP. MU Halliburton packer & install penetrator. Make splice on ESP cable below packer. Cut brine wt, fluid loss. RECEIV!:D Page 2 FEB 3 1997 ~]~ska 0il & 6as Cons. Anchorage Oct 25 1996 Complete splice of ESP cable above & below packer. RIH with ESP on 53 jts, 5-1/2", 17#, L-80 Imp Butt tubing. MU tubing hanger & splice cable at hanger. Land tubing, set TWC valve & test. ND BOP stack, NU adapter spool, NU CIW tree. Test adapter & tree. Final test on ESP cable ok. Freeze protect well with 158 bbls diesel. Drop ball, pressure up, set packer at 2211' & test tubing. Test annulus. Set 4" BPV with lubricator, RD lines, secure well. Nabors rig #4ES released 10/25/96 @ 0400 hrs. RD & prepare to move. Page BP EXPLORATION (ALASKA) INC. Mine Point Unit TO: S. Rossberg FROM: J. Fox DATE: 08 /14 / 96 RE: MP F-02 Gravel Pack SERVICE CO'S.: BJ, Halliburton, Nabors, Peak JOB SUMMARY II INJECTIVITY TEST Design Rate, Bbls Max Rate, Final STP, NWB Treat grad, psi/ft BPM Pumped bpm psi friction, psi 5 25 5.0 550 none 0.76 GRAVEL PACK Sand pumped, Prop behind pipe, M# Design total (lbs) /size behind pipe, Job was (lbs.) Screened 12,300 1800 lbs. 20 / 40 Carbolite 12,300 out at MPT RE- PACK Sand pumped, Prop behind pipe, M# Design total (lbs) /size behind pipe, Job was (lbs.) Screened 2400 2000 lbs. 20 / 40 Carbolite 2400 out Operational considerations. - Mixing on the fly with the fmc blender (designed for 40 + bpm ) was difficult at the 5 bpm rates that were being pumped at. it took a relatively long time (7 bbls to go from 0 ppg to 5 ppg and 30 bbls before a full 10 ppg was seen) to get the sand concentration up to design. It would not be possible to mix on the fly at a rate of 2 or 3 bpm. If the slurry is just being circulated in, then a rate of 5 bpm is possible. If you are still mixing slurry at surface when the rate needs to be slowed down for an impending squeeze then the slurry will need to be batched. - In the future the sand c°ncentratiOn in the blender tub should be brought up to 10 ppg prior to the start of the start of the gravel pack pumping. - To conserve on gel displace slurry with brine. - Difficulties were encountered when trying to get a supply of brine from the rig charge pumps to the BJ pumps. 10/23/96 DATA FRAC & FRAC 11: 59 AM SENT VIA MICROSOFT MAIL I PSIG I ! PUMPING SUMMARY STAGE CUM COMMENTS BBL BBL - Gel was mixed in BJ s' yard in Deadhorse for ease and better conditions. If source water is not required seawater from PBU would be more convenient and less expensive if the gel is to be mixed in Deadhorse. - Rather than perform a separate injectivity test it was just incorporated into the initial 25 bbls flush stage at the beginning of the gravel pack. - Due to the small displacement volume and the desire to avoid tool movement / rate changes in the middle of sand displacement the initial gravel pacl was performed squeezing into the formation from the start. Comments An estimated 3800 lbs. of sand made it behind pipe. Due to the expectation that sand is running ahead of the fluid to some extent actual volumes are difficult to determine. The pack appeared to screen off on the first gravel pack attempt with only 1800 lbs of sand behind pipe. After reversing out the slurry in the tubing an attempt was made to re-stress the pack which yielded indications of an open screen. It is speculated that the MPT bridged off when the full 10 ppg slurry reached the crossover tool at a rate of 5 bpm. A slower pump rate may have prevented this screen out. An 8 bbl. batch of 10 ppg. slurry was made up and circulated to within 10 bbl. of the MPT and then squeezed in at 2 bpm. The screens pressured up with all but two bbls pumped behind pipe. After the sand was reversed out, the pack was restressed to the calculated screen out pressure of 1600 psi with very little volume pumped. With the choke open this pressure could be maintained at a rate of 3 bpm with almost full returns to surface. The 1300 psi down hole pressure drop indicated that all screens were covered. I DATE/TIME OPERATIONS SUMMARYII 08/14/96 AM Land gravel pack assembly, set pkr, rev. out ball, press, test pkr - ok. 0630 MIRU remainder of BJ frac fleet. 0845 Hold pre-job safety meeting. Pickle tb~l. 0907 prepare to pump acid. 0907.5 Start pumping acid by BJ - pump lost prime. 0914 Pumping re-established. Rate = 1.8 bpm. 0921 Switch to brine. Pump 7 bbl. 0924 Shut down BJ pump. 0931 Start reverse out to the slop tank. 0936 Acid back to surface. 0941 Clean returns - S/D pump. Gravel Pack 0950 Start pumping gel measuring Initial circulating pressures at 2 bpm. 0951 2 bpm ICP. 0953 3 bpm ICP. 1000 Start pumping gel prepad - measure injectivity. 1005 Start sand screws to bring sand into the blender tub. 1006 First sand entering the wellbore. 1007 Sand concentration slow to come up to desire~110 ppg concentration due to slow pumping speed. Staging slurry. 1014 10.0 ppg sand concentration finally achieved. 1016 First actual sand at MPT (calculated) 1018 Pump pressure quickly increased up to screen out pressure - shut down pumps, allow pressure to bleed off into the formation - open choke to dehydrate the pack. 1019 Pressure up to restress pack. - ok. Reverse out 1030 Attempt to test pack. Screen apparently not covered - prepare to repack. Repack 1247 Circulate 5 bbl. gel then 8 bbl. of batch mixed 10 ppg. 1252 Go to flush w/10 bbl. of gel followed by brine. 1257 With sand 10 bbl. from MPT slow rate down to 2 bpm and go to squeeze configuration. 1302 Sand at perf. (calc.). 1306 Screened out. 1307 Open choke and dehydrate pack. Pressure test the pack. Reverse out tubing and retest - ok. Prepare to POOH PUMPING SUMMARY PUMPING SUMMARY TIME RATE ANNP WHP STAGE CUM COMMENTS BPM PSIG PSIG BBL BBL I TIME RATE ANNP WHP STAGE CUM COMMENTS BPM PSIG PSIG BBL BBL 08/14/96 Pickle Tubin, DISPLACEMENT = 45.2 BBLS 0907 0 1 0 38 0 0 Prepare to pump acid. 0907.5 Start to pump acid but lost prime. 0914 1.8 1 9 59 3.3 3.3 Pumping acid 0915 1.8 1 9 53 5 5 0920.5 1.9 / 1.0 1 9 33 1 3 1 3 Slow down to I bpm. 0921 1.9 1 9 33 14.5 14.5 All acid pumped - switch to brine for displacement 0924.5 0 1 9 1 2 7 21.5 S/D pump and switch to rig for remainder of displacement. 0931. 5.9 526 192 25.2 32.2 Switch to reverse out w/rig pump. to slop tank. 0936 545 190 Acid to surface 0941 6/0 ;45 / 29 13 70+ Clean returns, S/D pumps. Gravel Pack 0949.5 0 1 9 23 0 0 MPT in sqz. position, bag closed, and choke open. 0950 2 29 227 1.3 1.3 Start pumping 60 ppt HEC gel at 2 bpm to determine ICP. 0951 2/3 39 213 2.6 2.6 Circulation pressure at 2 bpm stabilized at 210 psig. Increase rate to 3 bpm. 0953 3 49 333 7.3 7.3 Circulation pressure at 3 bpm stabilized at 330 psig. S/D pump. 1000 0 29 50 0 0 Close choke. Prepare to start injectivity test / flush. 1001 5.0 302 549 2.0 2.0 Target rate of 5 bpm established. 1003 5.0 438 736 10.0 10.0 1004 5.0 487 820 15 15 1005 5.0 506 885 20 20 Start sand screws to load sand in blender tub. 1006 5.0 25 25 First sand entering the wellbore. il 007 5.0 584 1006 32 / 0 32 Sand concentration slow to come up to desired 10 ppg concentration due to slow pumping speed. Staging slurry. 1010 4.8 594 976 12 44 sand concentration at 7.2 ppg and rising slowly. 1011 4.8 633 946 20 52 7.9 ppg 1014 4.9 672 933 30 62 10.0 ppg sand concentration finally achieved. 1015 4.9 672 937 35 67 Cut Sand King. Pump out blender tub 1016 4.9 682 967 38 70 First actual sand on perfs. 1016 5.1 721 981 44.8 76.2 Stage flush. 5 ppg slurry just reaching the MPT PUMPING SUMMARY TIME RATE ANNP WHP STAGE CUM COMMENTS BPM PSlG PSlG BBL BBL 1018 5.1 / 0 1 95 70 47.8 79.2 Pump pressure quickly increased up to screen out pressure - shut down pumps, allow pressure to bleed off into the formation - open choke to dehydrate the pack. 101 9 < 1 1 9 1600 3.2 80.1 Pressure back up on pack to screen out pressure. Pressured up w/3.2 bbl. and held. S/D pump and allow pressure to bleed off. .. Pressure up annulus to 500 psig. Shift tool into reverse position and turn over to rig to reverse out sand. 1030 3 0 500 With the MPT in the sqz. position and the choke open attempt to test / restress the gravel pack. Well circulating easily at 3 bpm and 500 psig indicating open screen. Prepare to repack screen. Re-Pack 1247 0 1 0 22 0 0 MPT in the rev. position and annulus open. An 8 bb110 ppg pre-mixed slurry batch ready in the blender tub. Prepare to pump 1248 5.2 1 9 217 0.7 0.7 Target rate established. 1250 5.2 1 0 183 5 5 Switch to slurry. 1252 5.2 1 9 215 8.0 / 0 8 Stage flush w/gel. 1254 5.3 1 0 1 20 10 / 0 1 8 Switch to brine for remaining displacement. 9.2 ppg brine from the rig charge pumps. Losing pump prime. 1255 5.3 19 294 3 21 1256 5.3 1 9 302 10 28 1257 5.3 1 9 264 17 35 With sand 10 bbls away from the MPT slow the rate down to 2 bpm, shift the MPT into the squeeze position and close in the annulus. 1258 2.1 389 530 17.9 35.9 Squeezing to the formation. 1259 2.1 448 563 20 . 38 1302 2.1 51 6 662 27 45 (Calc.) sand at MPT. 1304 2.1 565 704 30 48 1306 2.1 1640 33.9 52 Pressured up to screen out pressure. S/D pump and allow pressure to bleed off. 1307 1620 35 53 With the choke open restress the pack and verify, pack. Pack appears good. Pressure up the annulus to 500 psi and move the MPT into the reverse position. Reverse out sand to the slop tank. With choke in the closed position pressure up on the pack - quickly pressures up and bleed PUMPING SUMMARY TIME RATE ANNP WHP STAGE CUM " COMMENTS BPM PSIG PSIG BBL BBL off slowly. Pressure up with the choke open - getting almost full returns w/a pump rate of 3 bpm and pressure of 1600 psig. During the last few seconds the pressure dropped to 1300 at a constant rate for reasons unknown. With 1300 psi of pressure drop screens are covered. Pack complete - prepare to POOH. BP EXPLORATION (ALASKA) INC. Mine Point Unit TO: S. Rossberg FROM' J. Fox DATE: 08 /16 / 96 RE- MP F-02 Upper Gravel Pack SERVICE CO'S.: BJ, Halliburton, Nabors, Peak i INJECTIVITY TEST Design Rate, Bbls Max Rate, Final STP, NWB Treat grad, psi/ft BPM Pumped bpm psi friction, psi 5 I 5 5.1 848 0 0.85* not corr. for friction GRAVEL PACK- Batch I Sand pumped, Prop behind pipe, M# Design total (lbs) /size behind pipe, Job was (lbs.) No Screen 9200 lbs. 9200 LBS. OF 20 / 40 8100 out Carbolite GRAVEL PACK - Batch 2 Sand pumped, Prop behind pipe, M# Design total (lbs) /size behind pipe, Job was (lbs.) Screened unknown Est. 4000 lbs. of 20 / 40 6500 out Carbolite Operational considerations. - Mixing on the fly with the frac blender (designed for 40 + bpm ) was difficult at the 5 bpm rates that were being pumped at. It would not be possible to mix on the fly at a rate of 2 or 3 bpm. If the slurry is just being circulated in, then a rate of 5 bpm is possible. If you are still mixing slurry at surface when the rate needs to be slowed down for an impending squeeze then the slurry will need to be batched. In order to accommodate the 2 bpm squeeze rate and the need to shift the MPT 10 bbls before the sand reaches the MPT, the max. volume of slurry that can be pumped is the tbg. vol. minus 10 bbls. which in this case was 27 bbl. If needed the remainder of the blender could also be pumped hover in this case the sand volume would be too close to the expected screen out volume. The fear was reaching screen out just before the tail end of the sand reached the top of the sand pack and not getting a reserve of sand across the blank pipe. The first batch was just to partially cover the screen- a screen out was not anticipated. 10/23/96 DATA FRAC & FRAC 12:24 PM SENT VIA MICROSOFT MAIL PUMP,NG SUMMARY - During the previous gravel pack of the lower sand it took a long time to bring the sand concentration up to 10 ppg. when starting mixing slurry as the slurry was pumped. In this gravel pack the blender tub was pre- mixed to 10 ppg. so when the slurry stage started it immediately went to 10 ppg. There was still some fluctuation in sand concentration as the proper sand screw speed had to be determined pretty much by trial and error. - Batch mixing the entire vol. of slurry required and pumping it in one batch would probably be the best way to go in the future. It was considered for this procedure but the paddle mixer was not in working condition or cleaned up. - During the second batch the densiometer quit working and the sand concentration could not be monitored. It was felt that the sand concentration stayed at approx. 10 ppg because by that point the speed of the sand screws were fine tuned and constant. There was however no way to measure the amount of sand pumped. - Problems were encountered shifting the tool into the squeeze position when the slurry was 10 bbls away from the tool. The benefits of circulating the slurry into the wellbore may be out weighed by the risk taken of not getting into the squeeze position in time. On the second batch it took 10 min. to get stung in. During this time the sand was falling on it's own. When the tool did go into sqz. and the pumps brought back on the sand bridged off and it took 1300 psi to break it free. Consideration should be given to just start out in the squeeze position and not try to circulate it part way in. - Gel was mixed in BJ s' yard in Deadhorse for ease and better conditions. If source water is not required seawater from PBU would be more convenient and less expensive if the gel is to be mixed in Deadhorse. - Rather than perform a separate injectivity test it was just incorporated into the initial 15 bbls flush stage at the beginning of the gravel pack. - Request that BJ record annulus pressure during the next gravel pack job in order to review what BHP was doing. Comments The exact volume of sand that was put behind the screen is unknown. It is pretty clear that 9200 lbs of sand made it behind the screen on the first batch but on the second batch not only did the densiometer quit working in the middle of pumping sand but the pumping was stopped for 10 min. while trying to get the MPT in position - all the time which the sand must have been falling on it's own. The screen outs and re-stresses clearly indicated a good pack. DATE/TIME OPERATIONS SUMMARY 08/16/96 PM Land gravel pack assembly, set pkr, rev. out ball, press, test pkr- ok. 1500 MIRU remainder of BJ frac fleet. -- 1700 Pressure test surface lines to 4500 psig. 1715 Hold pre-job safety meeting. Gravel Pack- First batch 1728 Prepare to start ICP test. 1740.5 Start pumping gel measuring Initial circulating pressures at 2 bpm. 1742 2 bpm ICP. 1743.5 3 bpm ICP. 1745.5 Start pumping gel prepad - measure injectivity. 1755.5 Stage 10 ppg slurry 1 801 Shift tool to sqz. position 1805 First actual sand at MPT (calculated) 1820 Slurry completely displaced. Turnover to rig to reverse out. Batch up another blender tub full of 10 ppg slurry. Gravel Pack- Second Batch !1901.5 Circulate 10 bbl. gel " 1904 Switch to 10 ppg slurry. 1909 Sand King out of sand. Go to flush w/of gel. Reduce rate. Attempt to gat MPT into sqz. position. 1911 Shut down pump. 1 918 Finally worked tool down into squeeze position, 1 923 Switch to brine for add'l displacement. 1925 Screened out to 1600 psig. Open choke and re-stress. Go to reverse position and reverse out tbg. Restress pack twice to 1600 - confirms good pack. Sting out of packer. Reverse out hole w/left over gel. POOH. PUMPING SUMMARY BPM IPS~G IPS~GI BBL BBL 08/16/96 Gravel Pack - First batch DISPLACEMENT = 45.2 BBLS 1728 0 0 74 0 0 MPT in sqz. position, bag closed, and choke open. P.repare to determine initial circulating pressures. 1731 2 1 9 85 0.5 Pumping brine at 2 bpm. 1738 2/0 301 367 13.9 13. 9 Took several bbis to catch fluid level. Annulus pressuring up. S/D pump. Check valves. HCR valve inadvertently left closed - open HCR. 1740.5 2 39 137 16.2 16.2 Start 2 bpm ICP again. PUMPING SUMMARY TIME RATE ANNP WHP STAGE CUM COMMENTS BPM PSIG PSIG BBL BBL 1742 2 / 3 49 139 / 17.1 17.1 Circulating pressure at 2 bpm is constant - increase rate to 3 BPM. 1742.5 3 58 255 18.5 18.5 1743.5 3 / 0 55 260 20 20 Circ.pressure at 3 bpm stabilized. Shut down pump. Close choke. Switch to 60 ppt linear HEC gel. 1745.5 0 / 5 29 1 5 20.9 / 0 20.9 Start injection test. Unable to maintain prime to pump. 1748 5.0 282 416 4.9 26.6 5 bpm rate established. 1750 5.1 515 870 10 32.2 1751 5.1 / 0 848 15.5 37.2 End inje.ctivity test. S/D pump. Shift MPT to rev. position. Begin circ. of lead gel into tubing. 1753 0 / 5 78 392 2.8 39 1755 4.9 97 520 9.0 45 1755.5 5.0 97 544 10/0 46 Switch to pre-mixed 10.5 ppg slurry in the blender hopper and start pumping down hole. 1757 5.1 107 449 10 57 1758 5.1 107 444 15 62 Sand concentrations up to 12.6 ppg. 1759 5.1 107 422 20 67 1800 5.2 107 390 25 72 1801 2.0 58 101 27 / 0 74 Shift tool to sqz. position - having some problem getting stung in. 1803 2.0 58 133 5 79 MPT finally stung in. 1805 2.0 389 502 10 / 0 84 Switch from gel to 9.2 ppg brine. Sand theoretically at the MPT. 1808 2.0 520 674 5 89.6 1810 2.0 564 713 10 94 1814 2.0 744 748 18 105 .. 1815.5 2.0 603 743 20 104.8 1818 2.0 613 732 25 109.8 1820 2.0 / 0 705 613 30 114.8 Slurry completely squeezed off behind screen. No indication of screen out seen (or expected). S/D pump. Pick MPT into reverse position. Turn over to reverse circulate tubing while batching up another tub of 10 ppg slurry. Gravel Pack - Second batch 1901 0 010 17 0 114.8 MPT in the rev. position and annulus open. An 8 bb110 ppg pre-mixed slurry batch ready in the blender tub. Prepare to pump lead gel. 1902.5 5 97 308 5.0 115.3 Rate established. Pumping linear gel. PUMPING SUMMARY TIME RATE ANNP WHP STAGE CUM COMMENTS BPM PSIG PSlG BBL BBL 1904 5.0 107 325 10/0 124.8 Switch to slurry pre-mixed to 10.2 ppg. 1906 5.1 117 357 10 134.8 Densiometer no Ion~ler working. 1907 5.1 107 364 20 144.8 1908 5.1 107 364 20 144.8 1909 5.1 / 2 21.6 / 0 149.7 Sand King out of sand. Stage flush w/linear gel. Slow down pump to shift tool and start squeeze. 1 911 0 1 9 711 2.6 151.0 S/d pump to help get tool into squeeze position. 1918 0 / 2.0 1 9 1350 Finally in squeeze position - re-establish injection - tubing pressured up to 1300 psi before an apparent bridge released. 1919 2.0 457 568 5 153.2 1923 2.0 535 647 10 / 0 148.2 Switch to 9.2 ppg brine. 1925 2.0 / 1.0 1600 4.6 163.2 Pressured up to screen out pressure - S/d pumps, open choke and allow pressure to bleed off. 1926.5 0.1 1600 5.1 163.5 Restress with choke open. Pressured up quickly and bled off slowly. Pack appears to be good. Pressure up annulus to 500 psi, Pick MPT into the reverse position and turn over to the rig to reverse out tubing. Once reversed out place the MPT in the sqz. position and pressure up on the pack w/'the choke open to 1600. Pressured up quickly and bled off slowly. Repeated - Pack determined to be good. RID. Reverse circulate hole w/remaining gel and POOH. SPERR JUN DRILLING SERVICES ANCHORAGE ALASKA PAGE BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051096 MWD SURVEY JOB NUMBER: AK-MM-960522 KELLY BUSHING ELEV. = 41.25 OPERATOR: BP EXPLORATION FT. TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH .00 .00 -41.25 195.01 195.00 153.75 259.46 259.44 218.19 348.49 348.35 307.10 442.18 441.61 400.36 COURS INCLN DG MN 0 0 0 51 1 26 4 16 6 24 COURSE DLS TOTAL DIRECTION RECTANGULAR COORDINATES DEGREES DG/100 NORTH/SOUTH EAST/WEST N .00 E .00 .00N .00E S 68.45 W .44 .54S 1.36W S 57.63 W .96 1.15S 2.50W S 51.36 W 3.19 3.82S 6.03W S 53.70 W 2.30 9.09S 12.97W VERT. SECT. .00 1.46 2,75 7.09 15.65 531.16 529.79 488.54 623.03 620.19 578.94 714.33 708.81 667.56 804.29 794.93 753.68 894.59 880.54 839.29 8 49 11 36 16 6 17 29 19 31 S 54.44 W 2.72 16.00S 22.53W S 53.37 W 3.02 25.62S 35.68W S 55.04 W 4.96 38.36S 53.44W S 56.55 W 1.61 52.96S 74.94W S 58.88 W 2.40 68.24S 99.19W 27.28 43.32 64.87 90.61 119.11 986.34 965.84 924.59 1080.57 1050.78 1009.53 1175.35 1134.21 1092.96 1270.78 1216.49 1175.24 1366.45 1295.77 1254.52 23 38 S 63.60 W 4.87 84.36S 128.81W 27 38 S 66.85 W 4.50 101.37S 165.86W 28 59 S 66.37 W 1.43 119.22S 207.13W 31 50 S 66.80 W 3.00 138.41S 251.46W 36 12 S 66.23 W 4.57 159.75S 300.53W 152.81 193.56 238.47 286.72 340.18 1462.77 1372.38 1331.13 1556.82 1446.61 1405.36 1652.59 1521.64 1480.39 1747.84 1594.67 1553.42 1843.83 1668.05 1626.80 38 24 S 66.83 W 2.32 182.98S 354.07W 37 20 S 66.71 W 1.12 205.76S 407.12W 39 28 S 65.14 W 2.44 230.04S 461.43W 40 24 S 65.14 W .99 255.74S 516.91W 39 52 S 65.40 W .59 281.63S 573.11W 398.47 456.13 515.58 576.71 638.57 1938.33 1740.99 1699.74 2036.59 1817.73 1776.48 2131.30 1892.36 1851.11 2228.71 1969.48 1928.23 2319.98 2042.03 2000.78 39 4 38 13 37 45 37 32 37 9 S 65.67 W .86 306.51S 627.79W S 66.59 W 1.04 331.35S 683.91W S 66.16 W .57 354.72S 737.33W S 66.17 W .21 378.76S 791.76W S 65.73 W .52 401.33S 842.33W 698.62 759.95 818.19 877.65 932.99 2417.34 2119.91 2078.66 2513.81 2197.60 2156.35 2612.08 2277.15 2235.90 2703.23 2350.57 2309.32 2798.93 2426.99 2385.74 36 35 36 8 35 45 36 54 37 7 S 65.26 W .65 425.56S 895.49W S 65.52 W .49 449.38S 947.50W S 65.63 W .39 473.24S 1000.03W S 65.27 W 1.28 495.68S 1049.15W S 65.11 W .24 519.85S 1101.44W 991.39 1048.57 1106.23 1160.22 1217.81 2893.73 2502.94 2461.69 2989.22 2580.04 2538.79 3083.53 2656.49 2615.24 3175.87 2731.67 2690.42 3271.80 2810.24 2768.99 36 22 35 56 35 44 35 15 34 45 S 65.44 W .81 543.58S 1152.96W S 64.99 W .54 567.20S 1204.11W S 65.29 W .28 590.41S 1254.22W S 65.56 W .55 612.71S 1302.98W S 65.08 W .6~~~,.~5~$"% 1352.98W 1274.52 1330.84 1386.05 1439.65 1494.66 FEB 1997 ~aska Oil & Gas Cons. Commissiorl ^ncho~ags SPERRY FN DRILLING SERVICES aNCHORAGE ALASKA PAGE 2 BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051096 MWD SURVEY JOB NUMBER: AK-MM-960522 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION TRUE SUB-SEA COURS COURSE DLS TOTAL MEASD VERTICAL VERTICAL INCLN DIRECTION RECTANGULAR COORDINATES VERT. DEPTH . DEPTH DEPTH DG MN DEGREES DG/100 NORTH/SOUTH EAST/WEST SECT. 3299.15 2832.72 2791.47 34 42 S 65.43 W .74 3385.00 2903.29 2862.04 34 42 S 65.43 W .00 642.21S 1367.14W 1510.24 662.54S 1411.59W 1559.10 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. HORIZONTAL DISPLACEMENT = 1559.34 FEET AT SOUTH 64 DEG. 51 MIN. WEST AT MD = 3385 VERTICAL SECTION RELATIVE TO WELL HEAD VERTICAL SECTION COMPUTED ALONG 243.85 DEG. SPERR~ 3N DRILLING SERVICES ANCHORAGE ALASKA PAGE BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051096 JOB NUMBER: AK-MM-960522 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION .00 .00 -41.25 .00 N .00 E .00 1000.00 978.33 937.08 86.80 S 133.79 W 21.67 21.67 2000.00 1788.98 1747.73 322.36 S 663.14 W 211.02 189.35 3000.00 2588.77 2547.52 569.87 S 1209.85 W 411.23 200.22 3385.00 2903.29 2862.04 662.54 S 1411.59 W 481.71 70.47 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. SPERR% JN DRILLING SERVICES ANCHORAGE ALASKA PAGE BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5 / 22 / 96 DATE OF SURVEY: 051096 JOB NUMBER: AK-MM-960522 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION .00 .00 -41.25 .00 N .00 E .00 41.25 41.25 .00 .00 N .00 E .00 .00 141.26 141.25 100.00 .24 S .61 W .01 .01 241.27 241.25 200.00 .90 S 2.11 W .02 .01 341.38 341.25 300.00 3.50 S 5.63 W .13 .11 441.81 441.25 400.00 9.07 S 12.94 W .56 .44 542.77 541.25 500.00 17.07 S 24.01 W 1.52 .95 644.58 641.25 600.00 28.32 S 39.35 W 3.33 1.81 748.09 741.25 700.00 43.73 S 61.12 W 6.84 3.52 852.94 841.25 800.00 61.07 S 87.38 W 11.69 4.84 959.61 941.25 900.00 79.61 S 119.50 W 18.36 6.68 1069.86 1041.25 1000.00 99.42 S 161.37 W 28.61 10.24 1183.42 1141.25 1100.00 120.80 S 210.74 W 42.17 13.56 1300.14 1241.25 1200.00 144.65 S 265.95 W 58.89 16.72 1423.05 1341.25 1300.00 173.28 S 331.38 W 81.80 22.92 1550.07 1441.25 1400.00 204.14 S 403.37 W 108.82 27.02 1677.99 1541.25 1500.00 236.83 S 476.08 W 136.74 27.91 1808.91 1641.25 1600.00 272.31 S 552.76 W 167.66 30.92 1938.66 1741.25 1700.00 306.60 S 627.98 W 197.41 29.75 2066.54 1841.25 1800.00 338.72 S 700.92 W 225.29 27.88 2193.10 1941.25 1900.00 370.00 S 771.91 W 251.85 26.56 2319.00 2041.25 2000.00 401.09 S 841.79 W 277.75 25.90 2443.91 2141.25 2100.00 432.19 S 909.88 W 302.66 24.91 2567.83 2241.25 2200.00 462.56 S 976.46 W 326.58 23.92 2691.57 2341.25 2300.00 492.75 S 1042.79 W 350.32 23.74 2816.82 2441.25 2400.00 524.40 S 1111.24 W 375.57 25.25 2941.30 2541.25 2500.00 555.31 S 1178.62 W 400.05 24.48 3064.75 2641.25 2600.00 585.83 S 1244.25 W 423.50 23.45 3187.61 2741.25 2700.00 615.52 S 1309.15 W 446.36 22.85 3309.53 2841.25 2800.00 644.67 S 1372.51 W 468.28 21.92 3385.00 2903.29 2862.04 662.54 S 1411.59 W 481.71 13.43 THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN THE NEAREST 20 FOOT MD (FROM MINIMUM CURVATURE) POINTS SP;--IY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE 1 BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051196 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-60049 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH COURS INCLN DG MN COURSE DLS TOTAL DIRECTION RECTANGULAR COORDI DEGREES DG/100 NORTH/SOUTH EAST/ NATES VERT. WEST SECT. .00 .00 -41.25 132.20 132.20 90.95 223.58 223.57 182.32 314.38 314.30 273.05 405.56 405.20 363.95 0 0 N .00 E .00 .00N 0 16 N 75.82 W .21 .08N 1 3 S 79.08 W .89 .03S 1 3 3 S 56.60 W 2.35 1.52S 4 5 33 S 55.02 W 2.73 5.39S 9 .00E .00 .31W .24 .34W 1.21 .18W 4.43 .83W 11.20 495.72 494.74 453.49 586.84 584.73 543.48 677.77 673.57 632.32 768.35 760.73 719.48 858.55 846.63 805.38 7 '45 S 55.63 W 2.44 11.33S 18 10 8 S 54.37 W 2.63 19.47S 30 14 22 S 53.17 W 4.66 30.90S 45 17 8 S 54.45 W 3.09 45.41S 65 18 21 S 57.40 W 1.67 60.79S 88 .43W 21.53 .02W 35.53 .56W 54.52 .43W 78.75 .22W 105.98 948.85 931.14 889.89 1044.67 1018.19 976.94 1139.95 1102.71 1061.46 1235.38 1185.47 1144.22 1330.73 1265.36 1224.11 22 51 S 62.12 W 5.31 76.66S 115 26 30 S 65.88 W 4.15 94.11S 151 28 27 S 66.12 W 2.05 111.99S 191 31 15 S 66.85 W 2.96 130.93S 235 34 52 S 66.43 W 3.81 151.57S 283 .72W 137.66 .70W 177.65 .86W 221.58 .42W 269.03 .17W 320.99 1365.36 1293.50 1252.25 1426.36 1341.77 1300.52 1521.61 1416.61 1375.36 1617.18 1491.89 1450.64 1712.46 1565.09 1523.84 36 24 S 66.55 W 4.41 159.62S 301 38 55 S 66.70 W 4.14 174.40S 335 37 28 S 66.21 W 1.55 197.93S 389 38 34 S 66.18 W 1.14 221.70S 443 41 0 S 64.94 W 2.68 246.94S 499 .67W 341.14 .88W 378.37 .89W 437.21 .75W 496.04 .24W 556.97 1807.98 1637.68 1596.43 1903.69 1710.96 1669.71 1998.99 1784.69 1743.44 2094.75 1859.44 1818.19 2190.07 1934.21 1892.96 40 3 S 65.37 W 1.02 273.02S 555 40 0 S 66.00 W .43 298.37S 611 38 38 S 66.79 W 1.53 322.56S 666 38 43 S 67.21 W .29 345.94S 722 37 56 S 67.40 W .84 368.75S 776 .57W 619.03 .67W 680.56 .99W 740.88 .09W 800.64 .63W 859.65 2285.62 2009.82 1968.57 2381.22 2085.85 2044.60 2416.36 2113.89 2072.64 2476.90 2162.40 2121.15 2572.45 2239.26 2198.01 37 25 S 66.99 W .60 391.39S 830 37 13 S 65.45 W 1.00 414.76S 883 36 53 S 65.85 W 1.17 423.49S 902 36 36 S 66.16 W .54 438.22S 935 36 16 S 66.43 W .40 461.04S 987 .47W 917.96 .51W 975.87 .80W 997.03 .89W 1033.23 .86W 1089.94 2668.16 2316.63 2275.38 2763.56 2393.09 2351.84 2858.07 2468.30 2427.05 2953.17 2544.55 2503.30 3047.17 2620.32 2579.07 35 51 S 66.50 W .44 483.53S 37 35 S 65.44 W 1.94 506.77S 36 57 S 65.60 W .67 530.49S 36 25 S 65.76 W .58 553.89S 36 9 S 65.36 W .39 576.90S 1039.51W 1091.60W 1143.69W 1195.47W 1246.12W 1146.22 1203.21 1260.43 1317.22 1372.82 SPideRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE 2 BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051196 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-60049 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION TRUE SUB-SEA COURS COURSE DLS TOTAL MEASD VERTICAL VERTICAL INCLN DIRECTION RECTANGULAR COORDINATES VERT. DEPTH DEPTH DEPTH DG MN DEGREES DG/100 NORTH/SOUTH EAST/WEST SECT. 3141.20 2696.51 2655.26 35 36 S 65.67 W .60 3236.79 2774.44 2733.19 35 9 S 65.35 W .51 3261.36 2794.54 2753.29 35 2 S 65.55 W .70 3385.00 2895.77 2854.52 35 2 S 65.55 W .00 599.75S 1296.27W 1427.91 622.70S 1346.65W 1483.24 628.57S 1359.50W 1497.37 657.95S 1424.12W 1568.33 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. HORIZONTAL DISPLACEMENT = 1568.76 FEET AT SOUTH 65 DEG. 12 MIN. WEST AT MD = 3385 VERTICAL SECTION RELATIVE TO WELL HEAD VERTICAL SECTION COMPUTED ALONG 243.85 DEG. SPideRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051196 JOB NUMBER: AK-EI-60049 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATE S NORTH/SOUTH EAST/WEST MD-TVD DIFFERENCE VERTICAL CORRECTION .00 .00 -41.25 .00 N .00 E .0 1000.00 977.93 936.68 85.97 S 134.16 W 22.0 2000.00 1785.48 1744.23 322.80 S 667.57 W 214.5 3000.00 2582.24 2540.99 565.30 S 1220.82 W 417.7 3385.00 2895.77 2854.52 657.95 S 1424.12 W 489.2 22.07 192.45 203.24 71.47 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. RECEIVED FEB ;5 19,97 Alaska Oil &. (?as Cons. Commission Anchorage, · , PAGE 4 SP=~RY-SUN DRILLING SERVICES ANCHORAGE ALASKA BP EXPLORATION MILNE PT/MPF-02 500292267300 NORTH SLOPE BOROUGH COMPUTATION DATE: 5/22/96 DATE OF SURVEY: 051196 JOB NUMBER: AK-EI-60049 KELLY BUSHING ELEV. = 41.25 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION .00 .00 -41.25 .00 N .00 E .00 41.25 41.25 .00 .00 N .00 E .00 .00 141.25 141.25 100.00 .09 N .35 W .00 .00 241.26 241.25 200.00 .09 S 1.66 W .01 .01 341.37 341.25 300.00 2.32 S 5.39 W .12 .11 441.78 441.25 400.00 7.42 S 12.73 W .53 .41 542.68 541.25 500.00 14.97 S 23.74 W 1.43 .90 644.53 641.25 600.00 26.25 S 39.32 W 3.28 1.85 748.00 741.25 700.00 41.98 S 60.67 W 6.75 3.47 852.88 841.25 800.00 59.83 S 86.71 W 11.63 4.88 959.84 941.25 900.00 78.66 S 119.53 W 18.59 6.96 1070.43 1041.25 1000.00 98.81 S 162.19 W 29.18 10.59 1184.07 1141.25 1100.00 120.62 S 211.52 W 42.82 13.63 1301.54 1241.25 1200.00 145.01 S 268.08 W 60.29 17.47 1425.69 1341.25 1300.00 174.24 S 335.49 W 84.44 24.15 1552.66 1441.25 1400.00 205.55 S 407.17 W 111.41 26.97 1680.87 1541.25 1500.00 238.16 S 480.47 W 139.62 28.22 1812.64 1641.25 1600.00 274.27 S 558.30 W 171.39 31.77 1943.20 1741.25 1700.00 308.68 S 634.85 W 201.95 30.55 2071.43 1841.25 1800.00 340.29 S 708.64 W 230.18 28.24 2199.00 1941.25 1900.00 370.86 S 781.70 W 257.75 27.57 2325.19 2041.25 2000.00 400.81 S 852.59 W 283.94 26.19 2450.54 2141.25 2100.00 431.85 S 921.51 W 309.29 25.35 2574.91 2241.25 2200.00 461.62 S 989.20 W 333.66 24.37 2698.53 2341.25 2300.00 490.63 S 1055.83 W 357.28 23.61 2824.22 2441.25 2400.00 522.08 S 1125.16 W 382.97 25.69 2949.06 2541.25 2500.00 552.89 S 1193.25 W 407.81 24.84 3073.08 2641.25 2600.00 583.28 S 1260.01 W 431.83 24.02 3196.18 2741.25 2700.00 612.94 S 1325.38 W 454.93 23.10 3318.41 2841.25 2800.00 642.12 S 1389.32 W 477.16 22.23 3340.00 2858.93 2817.68 647.25 S 1400.60 W 481.07 3.91 THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN THE NEAREST 20 FOOT MD (FROM MINIMUM CURVATURE) POINTS C] I~! I I_1_ I IM ES S ~:: F! ~/I ~-' ~: S WEI,I, LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Cormn. Atm.: Howard Okland 3001 Porcupine Dr. Alaska 99501 ~ [_o"' O''~ 0 Anchorage, MWD Formation Evaluation Logs - MPF-02, AK-MM-60522 December 20, 1996 The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of~ Jan Galvin, Sperry-Sun Drilling Services, 5631 Silverado Way, #G, Anchorage, AK 99518 2" x 5" MD Resistivity and Gamma Ray Logs: 2" x 5" TVD Resistivity and Gamma Ray Logs: 1 Blueline 1 Rev. Folded Sepia 1 Blueline 1 Rev. Folded Sepia 5631 Silverado Way, Suite G · Anchorage, Alaska 99518 · (9.07) 563-3256 ° Fax (907) 563-7252 A Dresser Industries, Inc. Company FtECEIVED S£P 'l~ 1996 '~m Oil & ~s Cons. Commis~n HOWARD OKLAND Attn. ALASKA OIL + GAS CONSERVATION 3001 PORCUPINE DRIVE ANCHORAGE A_K, 99501. Date: 4 September 1996 RE: Transmittal of Data Sent by: HAND CARRY Dear Sir/Madam, Enclosed, please find the data as described below: WELL # DESCRIPTION 1 PFC/PERF FINAL BL+RF ~o-- 1~3 MPF-33 1 PLS FINAL BL+RF 1 PFC/PERF FINAL BL+RF ~ ~--O70 MPF-02 MPF- 29 .~. 1 PFC/PERF FINAL BL+RF 1 GR/CCL FINAL BL+RF 1 PFC/PERF FINAL BL+RF ECC No. Run # 1 6479.02 Run # 1 Run # 1 6766.01 Run # 1 6774.01 Run # 1 Run # 1 6776.00 Please sign and return to: Attn. Rodney D. Paulson Western Atlas Logging Services 5600 B Street Suite 201 ~-' ' A~chorage, AK 99518 Or FAX to (907) 563-7803 Received by: Date: HOWARD OKLAND Attn. ALASKA OIL + GAS CONSERVATION 3001 PORCUPINE DRI~-E ANCHOP~AGE A_K, 99501. Date: 22 August 1996 RE: Transmittal of Data Sent by: HAND CARRY Dear Sir/Madam, Enclosed, please find the data as described below: WELL MPK-38 ~-~ MPK-17 ~-0~ MPK-37 {%-~7~ MPF-21 MPF-21 MPF-02 ~' ~ 0 DESCRIPTION /PFC/PERF FINAL BL+RF ,,.~P~C/PER~ ~IN~ ~L+R~ PLS FINAL BL+RF ~/PFC/PERF FINAL BL+RF -I~//TEMP FINAL BL+RF ~SBT FINAL B~+R~ GR/CCL FIN~ BL+RF PFC/PERF FIN~ BL+RF GR/CCL FIN~ BL+RF ECC No. Run # 1 6638.03 Run # 1 6639.02 Run # 1 Run # 1 6729.01 Run # 1 6773.00 Run # I 6773.01 Run # 1 Run # 1 Run # 1 6774.00 Please sign and return to: Attn. Rodney D. Paulson Western Atlas Logging Services 5600 B Street Suite 201 Anchorage, AK 99518 563-7803 Received by: Or FA~ to (907) AUG ;50 ]996 Anch, or~ MEMORANDUM TO: THRU' Blair Wondzell, ~"', ~;~,~! ~ P. i. Supervisor FROM: Lou Grimaidi,'~-o ~'- Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE' May 9, 1996 FILE NO: EWOJEIDD.DOC SUBJECT: Diverter inspection Nabors rig #22E BPX well #MPF-02 MPU Kuparuk River Field PTD 96-70 Thursday, May 9, 1996' I traveled to F Pad in the Milne Point Unit to inspect the Diverter equipment on Nabors rig #22E which was drilling surface hole on BPX well #MPF-02. I had previously been in contact with Leonard Schiilaer (Nabors toolpusher) who had informed me of the upcoming test of the Diverter system. We had discussed the difficult layout he was looking at and I informed him I was tied up on a BOP test and would be there as soon as possible. When I arrived the rig had drilled nearly to the conductor shoe and was making slow footage. i found the following problems with the vent lines. The 10" vent line emerged from the rig and had to drop down below a existing flow line. This was approximately a 20" change in height and was accomplished with a misaligned flange on the end of a section of 10". In itself this was not too bad but immediately after the vent line crossed under the flow line it rose to its original level. I was concerned since the ambient temperature was still below freezing the possibility of a ice bridge in the vent line existed. Another part of the layout that was bad was the bifurcated leg of the vent line was pointed at the pads manifold building. The line terminated approximately 25 feet from the manifold building. I spoke with Leonard and Jimmy Pyron (BPX rep.), drilling was halted and the vent lines were rerouted. ! suggest that more attention be paid to existing structures and flowlines in future wells ~ r programs. ~.~~ ?~~~..-~ SUMMARY: I witnessed the Diverter function test on Doyon rig #9. Two failures'noted. Attachments' Page 2 (diagram) ,cc: SCott Sigurdsen/Tom Horten (Prudhoe Bay drilling) Vent Line Manifold Building I AS FOUND Rig Well Houses Vent Line ~. Manifold Building I I I'- AS LEFT Rig Well Houses ~I~$1~ OIL AND GAS TONY KNOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 April 17, 1996 Tim Schofield, Senior Drilling Enb4neer BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 . Milne Point MPF-02 BP Exploration (Alaska), Inc. Permit No 96-70 Sm-fLoc 1774'NSL, 2890'WEL, Sec. 6, T13N, R10E, UM Btmhole Loc 1095'NSL, 4276'WEL, Sec. 6, T13N, R10E, LTM Dear Mr. Schofield: Enclosed is the approved application for permit to 4fill 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. The blowout prevention equipment (BOPE) mug be tested in accordance with 20 AAC 25.035; and the mechanical integrity (MI) ofinjection wells must be demonstrated under 20 AAC 25.412 and 25.030(g)(3). Sufficient notice (approximately 24 hours) ofthe MI test before operation, and of the BOPE test performed before drilling below the surface casing shoe, must be given so that' a representative of the Commission may witness the tests. Notice may be given by contacting the Commission's petroleum field inspector on the North Slope pager at 659-3607: SO BY ORDEK OF THE COM/VIISSION c: Dept ofFish & Game, Habitat Sect- w/o encl Dept of Environmentai Conservation- w/o encl STATE OF ALASKA REVISED 04/09/96 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill [] Redrill Ullb. Type of well. Exploratoryl-] Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenI-11 Service [] Development Gas [] Single Zone [] Multiple Zone [] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exp/oration (A/aska) /nc. P/an RTE = 41.5 f e et Mi/ne Point / Prince Creek 3. Address 6. Property Designation P. 0. Box 196612, Anchorage, A/aska 99519-6612 ADL 025509 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 1774' NSL, 2890' WEL, SEC. 6, T13N, RIOE Mi/ne Point Unit At top of productive interval '8. Well number Number 1398' NSL, 3659' WEL, SEC. 6, T13N, RIOE MPF-02 2S100302630-277 At total depth 9. Approximate spud date Amount 1095'NSL, 4276' WEL, SEC. 6, T13N, RIOE 04/14/96 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD andTVD) property line ADL 355023, 886 feet No Close Approach feet 2533 3352'MD/2881' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth 200 feet Maximum hole angle3z, o5 o Maximum surface 3301 psig At total depth (TVD) 7000'/3998 psig 18. Casing program Setting Depth s~ze Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 24" 20" 91.1# H-40 Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 3321' 31' 31' 3352' 2881' 726 sx PF 'E', 474sx 'G', 150 sx PF 'E' 19. TO be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural Conductor RECEIVED Surface Intermediate Production APR 0 9 1996 Liner Perforation depth: measured Alaska 0il & (~as Cons. Commission true vertical Anchorage 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling programFx-I Drilling fluid program [] Time vs depth plot [] Refraction analysis [] Seabed report[] 20 AAC 25.050 requirementsCI 21. I hereby certi~ tha~hejl=or~g~? is true and correct to the best of my knowledgeC~,,+~,c~' ~'r~¥n~-: ~T,r. un~.S' Signed ~""~ ~'/~--~" 'i_ ~ -5~2-/,¢ Title Senior gdllin~l Engineer Date /,r,//~, Commission Use Only Permit Number~:',~' - Yd~::) [APl number O~.E. ~' -' 2_ 2.. ~' ~"~I 1 IApp~,~al date See cover letter 150- - //~'-/;'~ for other requirements Conditi~'~s of approval Samples required [] Yes ~ No Mud log required []Yes ,J~ No Hydrogen sulfide measures [] Yes ~ No Directional survey required ~ Yes [] NO Required working pressure for BOPE []2M; 1-13M; []5M; I-I10M; []15M; Other: Original Signed By by order of Approved by David W. Johnston Commissioner me comm.ssion Dateo~ Form 10-401 Rev. 12-1-85 Submit in triplicate CASING SIZE: MP F-02 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON 9-5/8" CIRC. TEMP 60 deg F at 2840' TVDSS. SPACER: 75 bbls fresh water. LEAD CEMENT TYPE: ADDITIVES: Retarder WEIGHT: 12.0 ppg APPROX NO SACKS: 726 Type E Permafrost YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE:, Premium G ADDITIVES: 0.2% CFR-3,0.2% HALAD-344, 2.0% CaCI2 WEIGHT: 15.8 ppg APPROX #SACKS: 474 FLUID LOSS: 100-150 cc YIELD:1.15 ft3/sx MIX WATER: 5.0 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. FREE WATER: 0 TOP JOB CEMENT TYPE: Permafrost E NOTE: TOP JOB WILL BE PUMPED IF THE CEMENT TOP FALLS BELOW SURFACE AFTER THE PUMPS ARE SHUT DOWN. ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/sk APPROX NO SACKS: 150 CENTRALIZER PLACEMENT: 1. I Bowspring centralizer per joint of 9-5/8" casing on bottom 15 joints of casing (15 required). 2. Place all centralizers in middle of joints using stop collars. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 - 15 bpm. Mix slurry on the fly -- batch mixing is not necessary. CEMENT VOLUME: 1. The Tail Slurry volume is calculated to cover to the base of the Permafrost with 30% excess. 2. The Lead Slurry volume is calculated to cover from the top of the Tail Slurry to surface with 150% excess. 3. 80'md 9-5/8", 40# capacity for float joints. 4. Top Job Cement Volume is 150 sacks. It will be pumped if necessary to provide support to the wellhead. RECEIVED APR 0 9 199 Alaska Oil & Gas Cons. C;omrnission Anchora..qe Shared Services Drilling Contact: James E. Robertson I Well Name: IMP F-02 Well Plan Summary 564-5159 IType of Well (producer or injector)' Prince Creek Source Water Producer Surface Location: 1774 NSL 2891 WEL Sec 06 T13N R10E UM., AK Target Location: 1398 NSL 3659 WEL Sec 06 T13N R10E UM., AK Bottom Hole 1095 NSL 4276 WEL Sec 06 T13N R10E UM., AK Location' IAFE Number: 1337012 I IEstimated Start 114APR96 Date' I Rig: I Nabors 22-E TVD: IOperating days to 15 complete: 2,881 ' KBE: bkb 42' IWell Design (conventional, slimhole, etc.)' Milne Point Ultra Slimhole MONOBORE: 9-5/8", 40# CASING TO TD Formation Markers: Formation Tops MD TVD (bkb) base permafrost 2 01 2 1 81 2 Prince Creek 'A' 2 42 6 21 42 Prince Creek 'B' 2 62 6 2 302 Prince Creek 'C' 2 78 9 2 43 2 Prince Creek 'D' 2 91 4 253 2 Total Depth 3 35 2 2 8 81 Casinq/Tubing Pro!;lram: Hole Csg/ Wt/Ft Grade Conn Length Top Btm Size Tbg O.D. MD/TVD MD/TVD 24" 20" 91.1# H-40 Weld 80 32/32 1 12/1 12 12 1/4" 9-5/8" 40# L-80 btrc 3321 31/31 3352/2881 Internal yield pressure of the 9-5/8", 40# casing is 5750 psi. Worst case surface pressure would occur with a full column of gas from TD, assuming a normal pressure gradient of 8.6 ppg. Maximum anticipated surface pressure in this case would be 1009 psi, well below the internal yield pressure rating of the 9-5/8" casing. Logging Program: Open Hole Logs: Surface MWD Directional. LWD GR/RES Intermediate N/A Final N/A N/A Cased Hole Logs: Mudloggers are NOT required for this well. APR 0,3 0ii & ~r~, Cons, Co!'~n'~iasioll Anchorage Mud Program: J Special design None-SPUD MUD considerations Surface Mud Properties: I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel ~lel Loss 8.6 100 15 8 10 9 8 to to to to to to to 9.0 50 35 1 5 30 1 0 1 5 Intermediate Mud Pro3erties- N/A I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Production Mud Properties' I LSND freshwater mud Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss N/A N/A N/A N/A N/A N/A N/A to to to to to to to N/A N/A N/A N/A N/A N/A N/A Well Control' Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Directional' I KOP.' 1200' IMaximum Hole Angle: Close Approach Well- 137'°5° (No Shut Ins) Disposal- Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A. The Milne Point reserve pit can be opened in emergencies by notifying Karen Thomas (564-4305) with request. Request to AOGCC for Annular Pumping Approval for approved wells on Milne Pt F pad: (THERE WILL BE NO ANNULAR INJECTION ASSOCIATED WITH MP F-02) 1. Approval is requested for Annular Pumping into any well on the pad/drillsite previously permitted for disposal activities by AOGCC. 2. The base of the Permafrost for all wells located in the Milne Point Unit is _+1,850' TVD. Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. There are no domestic or industrial use water wells located within one mile of the project area. 3. There are _+16 wells on Milne Pt. 'F' Pad. There may be additional unidentified wells within one quarter mile distance from the subject well. There are no domestic or industrial water use wells located within one mile of the project area. 4. The wastes to be disposed of during drilling operations can be defined as "DRILLING WASTES". 5. The cement design for this well ensures that annular pumping into hydrocarbon zones will not occur. ANNULAR INJECTION: THE FOLLOWING MILNE PT. 'F' PAD WELLS HAVE BEEN PERMITTED FOR ANNULAR INJECTION FOR 1996 AREA WELL PREV VOL PERMITTED PERMITTED INJECTED VOL DATES (BBLS) (BBLS) Milne Point F-06 0 35000 1/25/96 to 1/25/97 Milne Point F-14 4250 35000 12/26/95 to 12/26/96 Milne Point F-22 6536 35000 12/12/95 to 12/12/96 Milne Point F-38 0 35000 10/26/95 to 10/26/96 Milne Point F-62 0 35000 10/13/95 to 10/13/96 Milne Point F-69 9740 35000 8/31/95 to 8/31/96 Milne Point F-70 6799 35000 9/28/95 to 9/28/96 Milne Point F-78 8053 35000 9/12/95 to 9/12/96 DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS. MAXIMUM EXPECTED FLUID DENSITY IS 17.0 PPG BURTST PRESSURE 9-5/8" 40# L-80 CASING: COLLAPSE 7", 26#, L-80 CASING: 5750 PSI 5410 PSI MAXIMUM ALLOWABLE INJECTION PRESSURE 2000 PSI AT ANY PPG EST HYDROSTATIC MAXIMUM ALLOWABLE PRESSURE AT SURFACE 7" COLLAPSE ANNULAR INJECTION FLUID DENSITY CASING SHOE DEPTH PRESSURE (80%) SURFACE PRESSURE (PPG) (PSI) (PSI) (PSI) 8 1918.18 4328 2000 9 2157.95 4328 2000 1 0 2397.72 4328 1 930 1 1 2637.49 4328 1 691 1 2 2877.26 4328 1451 1 3 3117.04 4328 1211 1 4 3356.81 4328 971 1 5 3596.58 4328 731 1 6 3836.35 4328 492 1 7 4076.12 4328 252 o . . . . . . . MP F-02 Proposed Summary of Operations Drill and Set 20" Conductor. Weld a starting head and top job nipple on conductor. Prepare location for rig move. MIRU Nabors 22E drilling rig. NU and test 20" Diverter system. Build Spud Mud. Drill a 12-1/4" surface/production hole as per directional plan. Run Directional MWD from surface to TD and run Gamma Ray/Res LWD from surface to TD. Run and cement 9-5/8" casing. Test casing to 3500 psig. ND diverter, NU and Test Tree. RDMO Nabors 22E drilling rig to drill next well. DRILLING HAZARDS AND RISKS: See both the updated Milne Point F-Pad Data Sheet prepared by Pete Van Dusen for information on the No Point#1 (F-46), and review recent wells drilled on F Pad. Most of the trouble time on recent wells has been due to equipment mechanical problems with the surface equipment, rather than formation drilling problems. The MPU PE group MAY be perforating, hydraulic fracturing and cleaning out wells shortly after the rig drills and completes them. This will make the near rig area congested and as a result potentially hazardous. Ensure personnel use caution moving around adjacent production activities. Close Approach: There are no close approaches associated with the drilling of MP F-02. Lost Circulation: There has not been any appreciable amount of lost circulation in surface hole on any of the F Pad wellls to date, Stuck Pipe Potential: Well MPF-53 was stuck coming out on the short trip at surface casing point. Proir to this incident there was only minor indications that the gravel and coal were present. It appears that we dragged the gravel up into the bottom of the curve and reduced our ability to move up or down. Then we lost the ability to circulate when the hole collapsed. Subsequent fishing operations were not successful and a very expensive BHA was lost in the hole from 2516 - 3342. Formation Pressure: The maximum expected pore pressure for this well is 8.6 ppg EMW (1288 psi @ 2881' TVD). There has been no injection in this region, therefore the reservoir pressure should not exceed this estimate. CASING SIZE: MP F-02 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON 9-5/8" CIRC. TEMP 60 deg F at 2840' TVDSS. SPACER: 75 bbls fresh water. LEAD CEMENT TYPE: Type E Permafrost ADDITIVES: Retarder WEIGHT: 12.0 ppg APPROX #610 SACKS: TAIL CEMENT TYPE: YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/ski /' / THICKENING TIME: Greater than 4 hrs at 50 / / / Premium G ADDITIVES: 0.2% CFR-3,0.2% HALAD-344, 2.0% CaCI2 WEIGHT: 15.8 ppg YIELD:1.15 ft3/sx MIX WATEI 5.0 gal/sk APPROX #SACKS: 330 THICKENING TIME: Greater th~ 4 hrs at 50° F. FLUID LOSS: 100-150 cc FREEWATER: 0 TOP JOB CEMENT TYPE: Permafrost E ADDITIVES: Retarder WEIGHT: 12.0 ppg APPROX NO SACKS: 150 YIELD:2.17 ft3/sx MIX WATER' 11.63 gal/sk CENTRALIZER PLACEMENT: 1. 1 Bowspring centralizer per joint of 9-,~ required). 2. Place all centralizers in middle of join casing on bottom 15 joints of casing (15 using stop collars. OTHER CONSIDERATIONS: Perform ensure compatibility prior to pumping to pumping job requirement. Dis mixing is not necessary. tests on mixed cement/spacer/mud program and Ensure thickening times are adequate relative at 12 - 15 bpm. Mix slurry on the fly -- batch CEMENT VOLUME: 1. The Tail Slurry volume is with 30% excess. The Lead Slurry volume md with 30% excess and 80'md 9-5/8", 40# ca Top Job Cement Volume . . to cover 618' md above the 9-5/8" Casing Shoe to cover from the top of the Tail Slurry to 1500' md to surface with 100% excess. oat joints. Ii i -" N 10800:00 -F -NI- l \ N 9800.00 Or- --J-- + + F PAD I · 78 · 77 · 70 · 69 -~-62 · 61 · 53 'JF · 48 · 45 -~ 38 · 37 -~30 + · 25 ~ I ~ 6 · 1 + LEGEND AS-BUILT CONDUCTOR · EXISTING WELL -'1- N 10800.00 II .oi.. J S, MPSON , NO POINT I ' m~s SURly _~,_ VICINITY MAP N.T.S. -I- -F SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO. PRA¢ TI CI~,.~AND:~SU R V~ YIN G.~II~¢~? :?:<..: .:.:. THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF SEPTEMBER 24, 1995. NOTES 1, DATE OF SURVEY: SEPTEMBER 24, 1995. 2. REFERENCE FIELD BOOK: MP95-15 (pgs. 26-,3`3). ,3. ALASKA STATE PLANE COORDINATES ARE ZONE 4, NAD 27. 4. GEODETIC COORDINATES ARE NAD 1927. 5. PAD SCALE FACTOR IS 0.99990199, 6. HORIZONTAL/VERTICAL CONTROL IS BASED ON MONUMENTS L-1 NORTH AND L-2 SOUTH. 0 /25~.9 O~I~INAL AS-BUiLT !SSUE INo.] DATE: J REV~,ON LOCATED WITHIN PROTRACTED SEC. 06 T. 13 N., R. 10 E., UMIAT MERIDIAN ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC CELLAR SECTION NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) BOX ELEV. OFFSETS IY=6,055,225.66 N= 9,999.45 70'30'25.764" 70.5071567' 1,774' FSL 2 IX= 541,674.60 E= 5,000.15 149'39'32.541" 149.6590389' 12.0' 2,890' FEL Y= 6,035,250.31 N=10,029.64 70'30'26.006" 70.50722.39' 1,799' FSL 6 X= 541,692.02 E= 5,000.11 149'59'`32.024" 149.6588955' 12.0' 2,873' FEL Y=6,035,299.27 N=10,090.17 70'30'26.486" 70.5073572' 12.2' 1,848' FSL 14 X= 541,727.60 ;E= 5,000.83 149'39'30.967" 149.6586019' 12,837' FEL 22 Y=6,035,348.`30 N=10,149.82 70'`30'26.966" 70.5074906' 1,897' FSL X= 541,761.56 E= 5,000.19 .149'39'29.959" 149.6583219' 12.0' 2,802' FEL Y=6,035,397.06 N=10,209.44 70'30'27.444" 70.5076233' 1,945' FSL 30 X= 541,795,86 E= 4,999.98 149'`39'28.941" 149.6580`392' 12.0' 2,767' FEL 38 Y=6,035,446.44 N=10,270.26 70'30'27.927" 70.5077575' 1,994' FSL X= 541,831.37 E= 5,000.41 149'39'27.887" 149.6577464' 12.2' 2,731' FEL Y=6,035,593.36 N=10,449.88 70'30'29.367" 70.5081575' 2,141' FSL 62 !X= 541,934.66 E=4,999.74 149',39'24.820" 149.6568944' 12.0' 2,627' FEL DRA~: JACO(~S CHECKED: FERAUDO DAPZ: 9/25/95 DRA~MNG: MPU-F-AB NO: SC^L~: 1"=200' L BP EXPLORATION MILNE POINT UNIT F-PAD CONDUCTOR AS-BUILT WELLS NO. 2,6,14,22,30,38 &: 62 ISHEETi 0¢ 1 L "_ .... _.S._.HARED SERV_ZC_ES BR~LLIN6' ._.~._'_., ',, I i i i i ii i II ii i A) KB 0 0 0 0.00 ~ ~o~/~u=~/,oo ~oo ~oo -o o.oo VERTICAL SECTION VIEW D) TARGET- ~813 ~97J 854 37.05 E) 9-5/8" CASING POINT 3352 288J S54~ 37.05 SBctioA at' 243.85 F) TO 3352 288~ ~54~ 37.05 TVO Scale.' 1 inch = 400 feet Dep Scale,' ~ inch = 400 feel <KB> o - A I Brawn ..... · 03/25/96 I 200 ..... B ................... , ~nadri]] Schlumberger ii i i 400--- I : ~ ANAE~RILL AKA-DI~ ~oo-~.. · .~ ................................... ~~ROVED .... ~ ' F'OR I~ERM, ITTING ~oo~ ,: ,~ i''" . .......... ONI,Y ,,, ,o, oo: ........ :""~ ~"~c~__. ........ ~ .... ' ........... ."' ~'~ ~': ':'"' ~:='::~::'" -" ,oo ............ I ..........__X .............. . .............................-----..-~ . -~ ~t':tzt;[s'~i/s"~'~" ,,, moo- i , APR 0;3 !~ - : ~ ~ ~ ~ska ( i! & G~ ( :ohs. Corrl'mission -~r~'~¢~---~ ','-~---,.-~.~.-~.~ =~.,~=~-.~,..~- .-- . ~ ~ ........... ~l[r r ~ ~ ~ '~T41 ..................... ~ ................. , ' " 2200 .............................. ~ ............. ~ .~ ' ' ' -~,,~,,=-,,~ ........... ~ ........... ,,,-x- ....... , ...... ~4oo ,.: ' '--% ' '¢~ r ~ ~$ ~ ~- '2l~ ' ' ' ~ .................... ~ ~-- ......... - iU~[T $ ~0 ~ ~¢ 1~31,' ................. ~ .... ~ i I~ ~I ! .. ...... m ~oo-' ........... : ........................ _ .... ~ ..... ' .... r ....... ....... , ., ....... .. .. 2800- , ~ E ; 3000 .......................................... ........................ .... , ... 3200- , , , 0 2o0 400 600 8o0 ~000 ~200 ~400 ~600 ~800 2000 2200 2400 2600 Section Departure madn i 11 UPF-02 PLAN VIE~ CLOSURE · ]54] feet: at Azimuth 243.85 ' SHARED "SERVICES .... BR_I'L~'TN6 .... DECLINATION.: +28.008 '[E) J ..................... ; ....... DRAWN.. i ....: 03/25/96 Marker Identification MD .' N/S E/~i A} KB 0 O N 0 E . ..i ": 8} KOP/BUILD 3/~00 200 0 N 0 E TARGEI . 22t3 376 S 767 W Fl TO 3352 679 S 1383 ........ ~iT. TiNE -, .. ..... , '.-_ ~ ~-' .~ .... . i ~::,. , , . m .~. ' ~ ~ .... .. ~ .~ , ~ o~ '~ ;4.,,= ................. ~ ~ i . 1700 ~$00 t~0 fao0 ~0 ~00 1 ~0~ ~0 ~00 ~ 700 ~00 500 ~00 3~0 800 100 0 ~00 WELL PERMIT CHECKLIST F~.~,D ~ Po0~, ~2J /~ O PROGRAM: exp [] ., dev [] redrll [] serv/~ wellbore seg [] ON/OFF SHORE ~ ADMINISTRATION Permit fee attached ................... [y~ N Lease number appropriate ................ I~l N Unique well name and number ............... y~/ N Well located in a defined pool .............. Y ~ 1. 2. 3. 4. 5. Well located proper distance from drlg unit boundary. 6. Well located proper distance from other wells ...... 7. Sufficient acreage available in drilling unit ..... - --.....included iiiiiiii 8. If deviated, is wellbore plat ..... 9. Operator only affected party. 10. Operator has appropriate bond in'f°rCe' ' ' ' ' 11. Permit can be issued without conservation order. 12. Permit can be issued without administrative approval. 13. Can permit be approved before 15-day wait ....... ENGINEERING REMARKS 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs ........ ~ N 16. CMT vol adequate to circulate on conductor & surf csg..~ N~~ ~' ~--3~~~ 17. CMT vol adequate to tie-in long string to surf csg . . . Y N (__ _~F~:t~,_:~ 18. CMT will cover all known productive horizons.. .... ~ N -- - /~d~:: ~ 19. Casing designs adequate for C, T, B & permafrost .... ~ N ' 20. Adequate tankage or reserve pit ............ ~ N 21. If a re-drill, has a 10-403 for abndnmnt been approved..~~ 22. Adequate wellbore separation proposed ......... -C~ N 23. If diverter required, is it adequate .......... '~ N 24. Drilling fluid program schematic & equip list adequate N n '~~ 25. BOPEs adequate ..................... y N ~- ~ 26. BOPE press rating adequate; test to psig. Y N 27. Choke manifold complies w/API RP-53 (May 84) ....... ~-----N-~ ~ 28. Work will occur without operation shutdown ....... ~ N 29. Is presence of H2s gas probable ............. Y ~ GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures .... Y 31. Data presented on potential overpressure zones ..... Y 32. Seismic analysis of shallow gas zones .......... Y 33. Seabed condition survey (if off-shore) ........ 34. Contact name/phone for weekly progress reports .... /. Y N [ exploratory only] // GEOLOGY: ENGIN~:~RING: COMMISSION: Comments/Instructions' HOW/ljb - A:tFORMS\cheklist rev 11195 L..__. ..... Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special'effort has been made to chronologically organize this category of information. ~HOD~H ~NIS~D ~M .00'EI :qHA~ CINiIOH~ ~E'I~ :HO0~ HDIHH~ :ONIHS~ A~q~DI. (0 ~S~ ~OH~ i~)NOIi~A~ :qM~ 068~ ~0I :~©N-k~ ~£I :dlHSN/40~ 9 :NOI&D~S £ Nfl%I tIM/4 L6-~-£0 S~DIA~SS 9~I~I~ 'DN! (+fStS~) ~O!l+f~Oq~X5 00££9EE6E00S o Lo NOMAd EES09-~4-Hlf I Nfl%I CIM~ - :@clA~ sT E sIT~qns 0'S8££ 0SE'EI ©NIH&S NOIIDQ~OH6 ~NIHiS (aZ) Hmd~ (NI) ~ZIS (NI) ZZIS SH~qlHG DNIS~D ~qOH Naa0 FILE HEADER FILE NUMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH GR 142.0 RP 132.0 $ BASELINE CURVE FOR SHIFTS: GR CURVE SHIFT DATA (MEASURED DEPTH) BASELINE DEPTH GR 142.0 131.0 149.5 138.5 152.5 140.0 153.5 141.0 181.5 171.5 209.5 199.5 212.5 202.0 237.5 233.0 242.5 234.5 262.0 246.5 267.0 250.5 269.0 251.5 273.0 253.5 280.0 261.5 282.5 262.5 286.5 264.5 288.0 266.5 304.0 288.0 313.0 300.5 315.5 303.0 317.0 306.5 323.5 310.5 326.0 312.0 327.5 313.0 330.5 316.5 332.5 318.5 333.5 320.0 334.5 321.5 337.5 325.0 344.5 331.5 346.5 333.0 351.0 336.0 354.5 341.0 356.5 343.0 383.5 378.0 386.5 381.0 476.0 461.0 478.5 463.0 497.5 483.0 666.0 653.0 674.0 658.5 682.5 671.0 686.0 672.5 all bit runs merged. STOP DEPTH 3339.0 3332.0 EQUIVALENT UNSHIFTED DEPTH 688.0 722.0 724.0 728.0 828.5 829.5 833 .5 836.0 881.5 884.5 887.0 891.5 1004.0 1006.0 1008.5 1191.5 1195.0 1235.0 1236.5 1264.0 1286.5 1288.0 1302.0 1303.5 1307.0 1308.5 1313.0 1316.5 1320.0 1323.0 1499.5 1501.0 1502.0 1553.0 1557.0 1559.0 1694.5 1699.0 1702.5 1731.5 1734.0 1921.5 1924.0 1948.5 1952.0 1975.0 1977.5 2017.5 2039.5 2042.0 2051.0 2052.5 2114.5 2129.5 2187.5 2192.0 2479.0 2533.5 2536.0 2568.0 6 ,5 708.5 710.0 714.5 816.5 818.5 825.5 828.5 867.5 869.5 871.0 873.0 991.0 992.5 994.5 1176.5 1181.5 1220.0 1221.0 1249.0 1274.0 1275.0 1290.0 1292.0 1293.5 1294.0 1299.0 1302.0 1306.5 1307.5 1485.5 1491.0 1492.0 1542.5 1544.0 1545.0 1682.0 1685.0 1688.0 1717.5 1719.5 1905.5 1908.5 1932.0 1936.5 1951.5 1953.5 1997.0 2021.0 2025.5 2034.0 2039.0 2099.0 2115.5 2169.0 2170.0 2468.5 2521.0 2522.5 2555.5 (~9 #.~dA.T,) CIHOD.~H ,T,~OZ ~ ~¢S~I~ : i~ZS ~dOqS H~ON : NiiOD &NIOd ZN~IN : N~ E0-~dN : NM NOI~¥~O~dX~ ~ : NO ,T,nO ' .T,.~ IHS & 6 / 'E~ HLIM GZL~IHS Z~ZM SZA%K/D 'SS~d NI~ 0'S8££ 0'£6I I 0'S8££ S'6IE£ S'S8I£ S'6CI£ 0'£~6~ 0'5~6E S'9165 S'016~ 0'£68E S'988E 0'~88~ S'9£8~ O'E18~ 0'~8~ S'~8£~ 0'~8£~ S'~8£~ S'~8£~ 0'08£~ S'8££~ 0'0££~ S'09£~ 0'~0£~ S'£69~ S'~S9~ 0'~S9~ S'0S9~ S'£~9~ O'oE~9~ C 9SE : S~¢%5Z-MZE ZGOD ~IO0,T, fled ZD%IflOS %f,T,~f~ ~Z~ZN S'I0~E S'05~£ 0'~£E£ 0'66I£ 0'ASI£ 0 ' 8~I£ S'I96E 0'6S6E 0'L£6E 0'I£6E 0'LI6E S'SO6E S'668E S'~68~ 0'068~ 0'£E8E S'818E 0'£I8~ S'~08E S'EO8E 0'66£~ S'L6LE O'S6LE S'£6L~ O'S8L~ 0'S££E S'£I£E 0'EILE S'IL9E S'L99E 0'999~ 0'~99E S'ES9E S'~£S~ 7 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 GR MWD 68 1 AAPI 4 2 RPX MWD 68 1 OHMM 4 3 RPS MWD 68 1 OHMM 4 4 RPM MWD 68 1 OHMM 4 5 RPD MWD 68 1 OHMM 4 6 FET MWD 68 1 HR 4 7 ROP MWD 68 1 FPHR 4 4 90 310 01 1 4 90 995 99 1 4 90 640 99 1 4 90 995 99 i 4 90 995 99 1 4 90 995 99 1 4 90 995 99 1 28 * DATA RECORD (TYPE# 0) 998 BYTES * Total Data Records: 215 Tape File Start Depth = 3430.000000 Tape File End Depth = 100.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 53289 datums Tape Subfile: 2 434 records... Minimum record length: 62 bytes Maximum record length: 998 bytes Tape Subfile 3 is type: LIS FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NO: 1 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 131.0 EWR4 122.0 $ LOG HEADER DATA DATE LOGGED.: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERS ION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG) 'MINIMUM ANGLE: MAXIMUM ANGLE: STOP DEPTH 3323.0 3315.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE EWR4 ELECTROMAG. RESIS. 4 GR DUAL GAMMA, RAY $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER' S CASING DEPTH (FT) : BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TEMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): Il-MAY-96 ISC 2.11 MWD 3.94 MEMORY 3385.0 193.0 3385.0 0 .9 40.4 TOOL NUMBER P0488CRG8 P0488CRG8 12.250 .0 SPUD 8.70 80.0 9.5 9000 9.0 1.150 1.080 1.000 1.700 70.0 75.0 70.0 70.0 .00 .000 .0 0 REMARKS: CN WN FN COUN STAT : BP EXPLORATION (ALASKA) : MPF- 02 : MILNE POINT : NORTH SLOPE : ALASKA * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 7 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod ! GR MWD 68 1 AAPI 4 2 RPX MWD 68 1 OHMM 4 3 RPS MWD 68 1 OHMM 4 4 RPM MWD 68 1 OHMM 4 5 RPD MWD 68 1 OHMM 4 6 FET MWD 68 1 HR 4 7 ROP MWD 68 1 FPHR 4 4 90 995 99 1 4 90 995 99 1 4 90 640 99 1 4 90 995 99 1 4 90 995 99 1 4 90 995 99 1 4 90 995 99 1 28 * DATA RECORD (TYPE# 0) 998 BYTES * Total Data Records: 215 Tape File Start Depth = 3430.000000 Tape File End Depth = 100.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 53289 datums Tape Subfile: 3 280 records... Minimum record length: Maximum record length: 62 bytes 998 bytes 0 = ~OD Nllfl£~ X~ISXS · spuoo~s S£'E = ~mT~ noT~nosx~ p~sd~I~ d5S:£ L6 ~ £ uo~ :uoy~no~x~ ~o pu~ s~Xq E£T :q~Bu~I p~oo~ mnm~x~ ss~Aq E£T :q~Bu~I p~om~ mnmyu7~ '''sp~oo~ E ~ :~I~qns sd~l I0 £ /~ /L6 I0