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Home My WebLink About204-0981. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Fill Cleanout w/ N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,235 feet N/A feet true vertical 3,723 feet N/A feet Effective Depth measured 9,253 feet feet true vertical 3,723 feet feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4.5" 12.6 / L-80 / TXP BTC 4,633' 3,817' Tripoint Packer "HRD" ZXPN LTP Packers and SSSV (type, measured and true vertical depth)(3) Baker ZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: Production 5,775' 7-5/8" 5,775' 3,867' 6,890psi 4,790psi OA Liner 4,353' 4-1/2" 9,188' 3,730' N/A N/A 4,005, 4,667, 4,805, 4,991 & 5,213 3,523, 3,828, 3,875, 3,933 & 3,968 Surface 129' 10-3/4" 2,378' 2,339' 5,210psi 2,470psi 324-001 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Brian Glasheen Brian.Glasheen@hilcorp.com 907-564-5277 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 204 Gas-Mcf MD 112' 100 Size 112' 161' 1280 3386168 0 2640 321 measured TVD 4-1/2" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 204-098 50-029-23212-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025517 & ADL0025906 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT I-17 Plugs Junk measured Length NB Liner 4,239' 4,019' Casing Conductor 3,726' 3,725' 9,230' 9,232' 2,088' 161'Surface Surface OB Liner 20" 10-3/4" 10-3/4" 112' 161' N/A N/A 5,210psi 3,580psi N/A N/A 2,249' 2,213' Burst N/A Collapse N/A 2,470psi 2,090psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 9:13 am, Feb 29, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.02.27 16:19:29 - 09'00' Taylor Wellman (2143) DSR-3/4/24 RBDMS JSB 022924 WCB 2024-07-08 _____________________________________________________________________________________ Revised By: TDF 2/23/2024 SCHEMATIC Milne Point Unit Well: MP I-17 Last Completed: 8/1/2022 PTD: 204-098 6-1/8” Hole- TD@ 9,225’ HES ‘V’ Float Shoe 9,188’ Cleanout NB lateral to 8,726’ CTM 9/02/2016 6-1/8” Hole- TD@ 9,260’ Btm Baker Float Shoe 9,230’ 6-1/8” Hole- TD@ 9,253’ Btm Baker 4-1/2”‘V’ Float Shoe 9,232’ 4-1/2” Slotted Liner 4,862’ to 9,144’- Rat Hole 37’ 4-1/2” Slotted Liner 5,116’ to 9,190’- Rat Hole 30’ 4” Med Excluder Screen 6,245’ to 9,190’- Rat Hole 20’ TD=9,253’ (MD) / TD = 3,723’(TVD) 20” Retrievable Extended Patch Top @ 4,618’ MD Btm @ 4,816’ MD 7-5/8” 19 20 10-3/4” 13 21 “OB” Lateral “NB” Lateral 14 15 Orig. KB Elev.: 69.3’/ Orig. GL Elev.: 30.4’ RKB – Hanger: 30.4’ (Doyon 14) 13 “OA” Lateral 23 12 13 16 17 18 22 24& 25 4 2 1 5 7 9 10 11Leaking Lower Liner Top Packer 8 3 6 JEWELRY DETAIL No Depth Item (All depths to Orig RKB) ID 1 3,842’Sliding Sleeve - 2 3,905’ BHPG - 3 3,969’ Baker Seal Assembly 4 4,005’ Tripoint Packer 5 4,030’ X Nipple w/ RHC 6 4,091’’ X Nipple w/ RHC - 7 4,117’ 250 Micon Screens – Btm @ 4,616’ - 8 4,623’ 5.75” Bullet Seal Assembly - 9 4,667’ "HRD" ZXPN Liner Top Packer 4.800” 10 4,683’ "DG" Flex-Lock Liner Hanger 4.790” 11 4,780 5.5" 17# 9Cr F/M II BxP "XN" Nipple (4.455 no-go) 4.562” 12 4.789’ Bullet Seal Locating assembly –Btm @ 4,802’4.790” 13 4,794’ OA Tie Back Sleeve 14 4,805’ OA ZXP Liner Top Packer 15 4,828’ OA OA 4-1/2” Hook Hanger ‘LEM’ Above Hanger 16 4,835’ OA 4-1/2” Hook Hanger ‘LEM’ Inside Hanger 17 4,835’ OA Hook Wall, Hanger Inside 7-5/8” Casing 18 4,852’ OA Hook Wall, Hanger Outside (Hook Point) 19 4,991’ OB Lateral ZXP Liner Top Packer 20 5,038’ OB OA 4-1/2” Hook Hanger ‘LEM’ Above Hanger 21 5,048’ OB 4-1/2” Hook Hanger ‘LEM’ Inside Hanger 22 5,048’ OB Hook Wall, Hanger Inside 7-5/8” Window 23 5,065’ NB Hook Wall, Hanger Outside (Hook Point) 24 5,213’ NB ZXP Liner Top Packer 25 5,231’ NB Lateral 7-5/8” x 5” HMC Liner Hanger GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14 – 8/1/2004 CTU Clean-out and Kill String Install, ASR#1 – 2/5/2019 ESP Completion / Casing Repair – ASR#1 6/4/2019 Jet Pump Completion by ASR – 8/1/2022 Install Extended Patch w/ SL – 9/17/2022 LATERAL WINDOW DETAIL “OA” Window f/ 4,840’ MD to 4,852’ MD; Angle @ window 70° “OB” Window f/ 5,053’ MD to 5,065’ MD; Angle @ window 78° TREE & WELLHEAD Tree 2-9/16” – 5M FMC Wellhead 11” x 7-*1/16” 5M FMC Gen 5A w/ 2-7/8” FMC Tbg Hgr, 3” LH me on Top and 2-7/8” EU 8rd on Btm, 2.5” CIW BPV Profile OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 42” Hole 10-3/4" Cmt w/ 396 sx AS Lite, 257 sx Class “G” in 13-1/2” Hole 7-5/8” Cmt w/ 765 sx Class “G” in 9-7/8” Hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm Cap 20" Conductor 215 / A-53 / Welded N/A Surface 112' N/A 10-3/4” Surface 55.5 / L-80 / BTC-M 9.950 Surface 161’ .0962 10-3/4” Surface 45.5 / K-55 / BTC 9.950 161’ 2,249’ .0962 10-3/4” Surface 55.5 / L-80 / BTC-M 9.950 2,249’ 2,378’ .0962 7-5/8" Production 29.7 / L-80 / BTC-M 6.875 Surface 5,775' .0459 5-1/2” Prod. Liner 17 / L-80 / Flush II 4.892 4,735’ 4,805’ 0.0232 4-1/2” Liner “OA” 12.6 / L-80 / IBT 3.958 4,835’ 9,188’ N/A 4-1/2” Liner “OB” 12.6 / L-80 / IBT 3.958 4,991’ 9,230’ N/A 4-1/2” Liner “NB” 12.6 / L-80 / IBT-M 3.958 5,213’ 9,232’ N/A TUBING DETAIL 4-1/2” Tubing 12.4 / L-80 / TXP BTC 3.958 Surface 4,633’.0152 WELL INCLINATION DETAIL KOP @ 450’ MD 50°+ from 3,200’ Max Wellbore Angle = 70° @ +4,696’ PERFORATION DETAIL Schrader Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status N Sands 4,414’ 4,458 3,737’ 3,754’ 44 3-3/8” 7/18/22 Open 4,485’ 4,543’ 3,763’ 3,784’ 58 3-3/8” 7/18/22 Open 4,569’ 4,637’ 3,794’ 3,818’ 68 3-3/8” 7/18/22 Open Ref Log: 9/14/2004 MPT, GR, EWR4, ABI, ROP Well Name Rig API Number Well Permit Number Start Date End Date MP I-17 Slickline 50-029-23212-00-00 204-098 1/6/2024 1/29/2024 1/5/2024 - Friday No operations to report. 1/3/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/4/2024 - Thursday No operations to report. No operations to report. WELL SHUT-IN ON ARRIVAL. RIG-UP .125 CARBON WIRE. TS = 1.75" RS, 8' x 1-7/8" ROLLER STEM (2.60" whls), KJT 5' x 1-7/8" ROLLER STEM (2.60" whls), OJ, KJT LSS. STACK PCE AND TAKE CONTROL OF WIRE. PULL TREE CAP AND STAB ONTO WELLHEAD. PT PCE 350L / 3500H (Good). PULL 4-1/2" JETPUMP (ratio: 12B) W/ SPARTEK GAUGE FROM XD-SS AT 3,842' MD (No data recovered). TAG FILL AT 4,190' SLM W/ 2.0" CENT, 1-3/4" SAMPLE BAILER (sample of sand). SHIFT XD-SS CLOSED AT 3,842' MD W/ 4-1/2" 42BO. PRESSURE UP IA TO 500psi TO CONFIRM SLEEVE IS CLOSED. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 1/6/2024 - Saturday No operations to report. 1/9/2024 - Tuesday 1/7/2024 - Sunday No operations to report. 1/8/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP I-17 Slickline 50-029-23212-00-00 204-098 1/6/2024 1/29/2024 RU & Pressure test, Continue to 1/17/24 WSR No operations to report. 1/13/2024 - Saturday LRS Test Unit # 1, Begin WSR, IL I-17, OL I-27, Fill Clean out with CTU 9, RU & Pressure test, Continue to 1/16/24 WSR 1/16/2024 - Tuesday 1/14/2024 - Sunday No operations to report. 1/15/2024 - Monday 1/12/2024 - Friday No operations to report. 1/10/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/11/2024 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP I-17 Slickline 50-029-23212-00-00 204-098 1/6/2024 1/29/2024 1/19/2024 - Friday WELL S/I ON ARRIVAL. PT W/ NITROGEN, 200 PSI, PT/ W TRIPLEX TO 2500 PSI. BRUSH SLIDING SLEEVE @ 3,842' MD. 1/17/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary LRS Test Unit # 1, Continued from 1/16/24 WSR, IL I-17, OL I-27, Fill Clean out with CTU 9, Spot in FB Tank, Complete RU, PT, Assist CTU, RDMO, Continue WSR on 1/18/24.MIRU, Wait on wind 33mph. Raise mast, change packoffs. Perform weekly BOP test, Diesel down CT for CTC PT. low 300, high 4,000. M/U SLB slim BHA. RIH dry tag at 4,171. need to re-rig tanks for current wind direction and testers would be flowing into well currently online, unable to shut in. Rigging PTS down because return tanks will be too close for N2 returns to tanks. Pressure test all iron on RU with Tanks re-positioned. RIH again, same Slim BHA. N2 exposure drill with Crew, Man Down. 1/18/2024 - Thursday RIH again, same Slim BHA. Tag Fill same place, 4175', CTM. PUH to establish pump parameters. Begin FCO w/N2, 600 scf/min. Clean out down to 5,250' and chase up hole for bottoms up. FP coil, dry drift down to 7,289' CTMD until lock up. Discuss with OE, good on depth. FP well 38 bbls 60/40. POOH RDMO No operations to report. WSR CONT FROM 1/19/24. OPEN SLIDING SLEEVE @3842' MD. SET JET PUMP IN SLIDING SLEEVE @3842' MD. WELL LEFT S/I, PAD OP NOTIFIED. 1/20/2024 - Saturday No operations to report. 1/23/2024 - Tuesday 1/21/2024 - Sunday No operations to report. 1/22/2024 - Monday RIH again, same Slim BHA. Tag Fill same place, 4175', CTM. PUH to establish pump parameters. Begin FCO w/N2, 600 scf/min. Clean out down to 5,250' and chase up hole for bottoms up. FP coil, dry drift down to 7,289' CTMD until lock up. Discuss with OE, good on depth. FP well 38 bbls 60/40. POOH RDMO Well Name Rig API Number Well Permit Number Start Date End Date MP I-17 Slickline 50-029-23212-00-00 204-098 1/6/2024 1/29/2024 1/26/2024 - Friday No operations to report. 1/24/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/25/2024 - Thursday No operations to report. No operations to report. No operations to report. 1/27/2024 - Saturday WELL FLOWING ON ARRIVAL. RIG-UP .125 CARBON WIRE. TS = 1.75" RS, 8' x 1-7/8" ROLLER STEM (2.60" whls), KJT 5' x 1-7/8" ROLLER STEM (2.60" whls), OJ, KJT LSS. STACK PCE AND TAKE CONTROL OF WIRE. PULL TREE CAP AND STAB ONTO WELLHEAD. PT PCE 350L / 3500H (Good). PULL 4-1/2" JETPUMP (ratio: 12B)W/ SPARTEK GAUGE (Good data) FROM XD-SS AT 3,842' MD. BRUSH TUBING FROM SURFACE TO 4,100' SLM W/ 4-1/2" BRUSH, 3.50" GAUGE RING (No issues). SET 4-1/2" JETPUMP, SHOCK ABSORBER, SPARTEK GAUGE (ratio: 12B, oal - 120") IN XD-SS AT 3,842' MD. *** WELL FLOWING ON DEPARTURE, PAD OP NOTIFIED. 1/30/2024 - Tuesday 1/28/2024 - Sunday No operations to report. 1/29/2024 - Monday 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: Fill Cleanout w/ N2 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: Milne Point Schrader Bluff Oil N/A 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,253'N/A Casing Collapse Conductor N/A Surface 2,470psi Surface 2,090psi Surface 2,470psi Production 4,790psi OA Liner N/A OB Liner N/A NB Liner N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Brian Glasheen Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 5,775' 7-5/8" 5,775' 3,867' 6,890psi 4,353' 4-1/2" 9,188' 3,730' N/A 3,725' Brian.Glasheen@hilcorp.com 907-564-5277 9,230' Perforation Depth MD (ft): Tripoint Pchr, HRD ZXPN LTP, (3) Baker ZXP Liner Top Packers and N/A 4,005MD/ 3,523TVD, 4,667MD/ 3,828TVD, 4,805MD/ 3,875TVD, 4,991MD/ 3,933TVD & 5,213MD/ 3,968TVD and N/A 2,378' See Schematic 4,239' 4-1/2" See Schematic 9,232'4,019' 4-1/2" 3,726'4-1/2" 112' 20" 10-3/4" 10-3/4" 161' 10-3/4"129' 2,088' MD N/A 5,210psi 5,210psi 3,580psi 161' 2,213' 2,339' 161' 2,249' Length Size Proposed Pools: 112' 112' 12.6# / L-80 / EUE TVD Burst 4,633' N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025517 & ADL0025906 204-098 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23212-00-00 Hilcorp Alaska LLC AOGCC USE ONLY N/A Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 1/5/2024 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT I-17 3,723' 9,253' 3,723' 715 N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.01.03 15:12:29 - 09'00' Taylor Wellman (2143) 324-001 By Grace Christianson at 3:18 pm, Jan 03, 2024 10-404 MGR03JAN2024 SFD 1/11/2024JLC 1/16/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.01.17 09:19:21 -09'00'01/17/24 RBDMS JSB 011724 Coil N2 FCO Well: MPI-17 PTD: 204098 API:50-029-23212-00-00 Well Name:MPI-17 API Number:50-029-23212-00-00 Current Status:JP producer Rig:Coil Estimated Start Date:01/15/2024 Estimated Duration:3 days Reg.Approval Req’d? Yes Date Reg. Approval Rec’vd:TBD Regulatory Contact:Tom Fouts Permit to Drill Number:204098 First Call Engineer:Brian Glasheen 907-545-1144 (M) Second Call Engineer:Taylor Wellman 907-947-9533 AFE Number:TBD Current Bottom Hole Pressure: 1095 psi @ 3805’ TVD BHPG reading 10/30/20 Maximum Expected BHP:1095 psi @ 3805’ TVD 5.6 PPGE Max. Anticipated Surface Pressure:715 psi Gas Column Gradient (0.1 psi/ft) Min ID:2.31” @ 4810’ MD Seal Assembly Brief Well Summary The Milne Point I-17 well was drilled as a Schrader Bluff development well dual lateral with Doyon 14 in July 2004. The well was initially completed with an ESP that ran for thirteen years up to November 2017. The ESP was pulled in April 2018, but the 7-5/8” production casing failed to pressure test. A kill string of 4-1/2” tubing was ran and the well was left shut-in to order long-lead items for the casing repair. Subsequent leak-detect logs suggest a liner top packer leak @ 4,805’ MD. In addition, a coiled tubing cleanout of each of the three laterals was performed in Q1 2019. June 2019 ASR repaired the casing leak and installed a ESP completion. 6/28/22 the ESP failed and was unable to restart. July 2022 ASR pulled the ESP and converted the well to a JP producer. N sands were added and straddled with screens. A follow up coil procedure was completed to set an extended patch between OA and the N sand screens. Recent tests December 2023 indicated decrease in flow rate, JP CO was completed and memory gauges were reviewed. Memory gauges indicated a sanding event and FBHP suddenly dropped from 600-100 psi indicating loss of total fluid. Objective The primary objective is to clean the well out to TD using N2. This will allow full contribution from all lateral. Notes Regarding Wellbore Condition • 7-5/8’’ Casing passed to 4000 psi 8/1/22 • Operations could not back flush December 2023 Slickline 1. MIRU. 2. Pull JP leave sleeve open for possible PF circulation during FCO.. Coiled Tubing 3. MIRU 1.5”/1.75’’ Coiled Tubing Unit and spot ancillary equipment. 4. Pressure test BOPE to 3,000 psi Hi 250 Low, 10 min Hi, 5 min Low each test. 5. RIH with 1.5-1.75”JSN and GR/CCL and perform a FCO using 1% KCL and N2 to 9,190’ MD taking returns to tanks or portable separator. a. Note MIN ID of 2.31” in the extended patch. b. Target 500-1000 TGLR with N2 while performing FCO c. Pump 10 barrel of powervis for every 1bbl of fill removed Coil N2 FCO Well: MPI-17 PTD: 204098 API:50-029-23212-00-00 d. Lifting more than a 1bbl bite from the liner at any one time is not recommended. e. Follow best practices document for FCO in PE manual 6. PU to 2,500’ and freeze protect well down the coil x tubing annulus. POOH w/ coil. 7. RD Coiled Tubing and ancillary equipment Slickline 1. Spot Slickline unit and RU. 2. Pressure test lubricator to 300psi low and 2,800psi high. 3. Set 12B Jet pump in Sliding sleeve. Attachments: 1. Wellbore Schematic 2. Coil Tubing BOPE Schematic 3. Coiled Tubing Nitrogen Diagram 4. Standard Nitrogen Operations _____________________________________________________________________________________ Revised By: TDF 10/4/2022 SCHEMATIC Milne Point Unit Well: MP I-17 Last Completed: 8/1/2022 PTD: 204-098 6-1/8” Hole- TD@ 9,225’ HES ‘V’ Float Shoe 9,188’ Cleanout NB lateral to 8,726’ CTM 9/02/2016 6-1/8” Hole- TD@ 9,260’ Btm Baker Float Shoe 9,230’ 6-1/8” Hole- TD@ 9,253’ Btm Baker 4-1/2”‘V’ Float Shoe 9,232’ 4-1/2” Slotted Liner 4,862’ to 9,144’- Rat Hole 37’ 4-1/2” Slotted Liner 5,116’ to 9,190’- Rat Hole 30’ 4” Med Excluder Screen 6,245’ to 9,190’- Rat Hole 20’ TD=9,253’ (MD) / TD = 3,723’(TVD) 20” Retrievable Extended Patch Top @ 4,618’ MD Btm @ 4,816’ MD 7-5/8” 19 20 10-3/4” 13 21 “OB” Lateral “NB” Lateral 14 15 Orig. KB Elev.: 69.3’/ Orig. GL Elev.: 30.4’ RKB – Hanger: 30.4’ (Doyon 14) 13 “OA” Lateral 23 12 13 16 17 18 22 24& 25 4 2 1 5 7 9 10 11Leaking Lower Liner Top Packer 8 3 6 JEWELRY DETAIL No Depth Item (All depths to Orig RKB) ID 1 3,842’Sliding Sleeve - 2 3,905’ BHPG - 3 3,969’ Baker Seal Assembly 4 4,005’ Tripoint Packer 5 4,030’ X Nipple w/ RHC 6 4,091’’ X Nipple w/ RHC - 7 4,117’ 250 Micon Screens – Btm @ 4,616’ - 8 4,623’ 5.75” Bullet Seal Assembly - 9 4,667’ "HRD" ZXPN Liner Top Packer 4.800” 10 4,683’ "DG" Flex-Lock Liner Hanger 4.790” 11 4,780 5.5" 17# 9Cr F/M II BxP "XN" Nipple (4.455 no-go) 4.562” 12 4.789’ Bullet Seal Locating assembly –Btm @ 4,802’4.790” 13 4,794’ OA Tie Back Sleeve 14 4,805’ OA ZXP Liner Top Packer 15 4,828’ OA OA 4-1/2” Hook Hanger ‘LEM’ Above Hanger 16 4,835’ OA 4-1/2” Hook Hanger ‘LEM’ Inside Hanger 17 4,835’ OA Hook Wall, Hanger Inside 7-5/8” Casing 18 4,852’ OA Hook Wall, Hanger Outside (Hook Point) 19 4,991’ OB Lateral ZXP Liner Top Packer 20 5,038’ OB OA 4-1/2” Hook Hanger ‘LEM’ Above Hanger 21 5,048’ OB 4-1/2” Hook Hanger ‘LEM’ Inside Hanger 22 5,048’ OB Hook Wall, Hanger Inside 7-5/8” Window 23 5,065’ NB Hook Wall, Hanger Outside (Hook Point) 24 5,213’ NB ZXP Liner Top Packer 25 5,231’ NB Lateral 7-5/8” x 5” HMC Liner Hanger GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14 – 8/1/2004 CTU Clean-out and Kill String Install, ASR#1 – 2/5/2019 ESP Completion / Casing Repair – ASR#1 6/4/2019 Jet Pump Completion by ASR – 8/1/2022 Install Extended Patch w/ SL – 9/17/2022 LATERAL WINDOW DETAIL “OA” Window f/ 4,840’ MD to 4,852’ MD; Angle @ window 70° “OB” Window f/ 5,053’ MD to 5,065’ MD; Angle @ window 78° TREE & WELLHEAD Tree 2-9/16” – 5M FMC Wellhead 11” x 7-*1/16” 5M FMC Gen 5A w/ 2-7/8” FMC Tbg Hgr, 3” LH me on Top and 2-7/8” EU 8rd on Btm, 2.5” CIW BPV Profile OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 42” Hole 10-3/4" Cmt w/ 396 sx AS Lite, 257 sx Class “G” in 13-1/2” Hole 7-5/8” Cmt w/ 765 sx Class “G” in 9-7/8” Hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm Cap 20" Conductor 215 / A-53 / Welded N/A Surface 112' N/A 10-3/4” Surface 55.5 / L-80 / BTC-M 9.950 Surface 161’ .0962 10-3/4” Surface 45.5 / K-55 / BTC 9.950 161’ 2,249’ .0962 10-3/4” Surface 55.5 / L-80 / BTC-M 9.950 2,249’ 2,378’ .0962 7-5/8" Production 29.7 / L-80 / BTC-M 6.875 Surface 5,775' .0459 5-1/2” Prod. Liner 17 / L-80 / Flush II 4.892 4,735’ 4,805’ 0.0232 4-1/2” Liner “OA” 12.6 / L-80 / IBT 3.958 4,835’ 9,188’ N/A 4-1/2” Liner “OB” 12.6 / L-80 / IBT 3.958 4,991’ 9,230’ N/A 4-1/2” Liner “NB” 12.6 / L-80 / IBT-M 3.958 5,213’ 9,232’ N/A TUBING DETAIL 4-1/2” Tubing 12.4 / L-80 / TXP BTC 3.958 Surface 4,633’.0152 WELL INCLINATION DETAIL KOP @ 450’ MD 50°+ from 3,200’ Max Wellbore Angle = 70° @ +4,696’ PERFORATION DETAIL Schrader Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status N Sands 4,414’ 4,458 3,737’ 3,754’ 44 3-3/8” 7/18/22 Open 4,485’ 4,543’ 3,763’ 3,784’ 58 3-3/8” 7/18/22 Open 4,569’ 4,637’ 3,794’ 3,818’ 68 3-3/8” 7/18/22 Open Ref Log: 9/14/2004 MPT, GR, EWR4, ABI, ROP Coil N2 FCO Well: MPI-17 PTD: 204098 API:50-029-23212-00-00 Coiled Tubing BOPs Coil N2 FCO Well: MPI-17 PTD: 204098 API:50-029-23212-00-00 Coiled Tubing Nitrogen Diagram STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Fill Cleanout w/ N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,235 feet N/A feet true vertical 3,723 feet N/A feet Effective Depth measured 9,253 feet feet true vertical 3,723 feet feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4.5" 12.6 / L-80 / TXP BTC 4,633' 3,817' Tripoint Packer "HRD" ZXPN LTP Packers and SSSV (type, measured and true vertical depth)(3) Baker ZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: SCHRADER BLUFF OIL 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: Burst N/A Collapse N/A 2,470psi 4,790psi OB Liner NB Liner 4,353' 4,239' 4,019' Casing Conductor 3,730' 3,726' 4-1/2" 9,188' 9,230' 9,232' 3,725' 5,775' 161'Surface Production OA Liner 20" 10-3/4" 7-5/8" 112' 161' measured TVD 4-1/2" N/A 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 204-098 50-029-23212-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025517 & ADL0025906 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT I-17 Plugs Junk measured Length 161' 647 3,390108 0 00 318 N/A N/A 5,210psi 6,890psi N/A N/A 5,775' 3,867' 322-657 Sr Pet Eng: N/A Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Brian Glasheen Brian.Glasheen@hilcorp.com 907-564-5277 Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 351 Gas-Mcf 0 Surface 129' 10-3/4" 2,378' 2,339' 5,210psi 2,470psi 4,005, 4,667, 4,805, 4,991 & 5,213 3,523, 3,828, 3,875, 3,933 & 3,968 Surface 2,088' 10-3/4" 2,249' 2,213' 3,580psi 2,090psi measured true vertical Packer MD 112' Size 112' PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Anne Prysunka at 11:04 am, Dec 13, 2022 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.12.13 10:44:54 -09'00' David Haakinson (3533) RBDMS JSB 121322 WCB 12-2-2024 DSR-12/13/22 _____________________________________________________________________________________ Revised By: TDF 10/4/2022 SCHEMATIC Milne Point Unit Well: MP I-17 Last Completed: 8/1/2022 PTD: 204-098 6-1/8” Hole- TD@ 9,225’ HES ‘V’ Float Shoe 9,188’ Cleanout NB lateral to 8,726’ CTM 9/02/2016 6-1/8” Hole- TD@ 9,260’ Btm Baker Float Shoe 9,230’ 6-1/8” Hole- TD@ 9,253’ Btm Baker 4-1/2”‘V’ Float Shoe 9,232’ 4-1/2” Slotted Liner 4,862’ to 9,144’- Rat Hole 37’ 4-1/2” Slotted Liner 5,116’ to 9,190’- Rat Hole 30’ 4” Med Excluder Screen 6,245’ to 9,190’- Rat Hole 20’ TD=9,253’ (MD) / TD = 3,723’(TVD) 20” Retrievable Extended Patch Top @ 4,618’ MD Btm @ 4,816’ MD 7-5/8” 19 20 10-3/4” 13 21 “OB” Lateral “NB” Lateral 14 15 Orig. KB Elev.: 69.3’/ Orig. GL Elev.: 30.4’ RKB – Hanger: 30.4’ (Doyon 14) 13 “OA” Lateral 23 12 13 16 17 18 22 24& 25 4 2 1 5 7 9 10 11Leaking Lower Liner Top Packer 8 3 6 JEWELRY DETAIL No Depth Item (All depths to Orig RKB) ID 1 3,842’Sliding Sleeve - 2 3,905’ BHPG - 3 3,969’ Baker Seal Assembly 4 4,005’ Tripoint Packer 5 4,030’ X Nipple w/ RHC 6 4,091’’ X Nipple w/ RHC - 7 4,117’ 250 Micon Screens – Btm @ 4,616’ - 8 4,623’ 5.75” Bullet Seal Assembly - 9 4,667’ "HRD" ZXPN Liner Top Packer 4.800” 10 4,683’ "DG" Flex-Lock Liner Hanger 4.790” 11 4,780 5.5" 17# 9Cr F/M II BxP "XN" Nipple (4.455 no-go) 4.562” 12 4.789’ Bullet Seal Locating assembly –Btm @ 4,802’4.790” 13 4,794’ OA Tie Back Sleeve 14 4,805’ OA ZXP Liner Top Packer 15 4,828’ OA OA 4-1/2” Hook Hanger ‘LEM’ Above Hanger 16 4,835’ OA 4-1/2” Hook Hanger ‘LEM’ Inside Hanger 17 4,835’ OA Hook Wall, Hanger Inside 7-5/8” Casing 18 4,852’ OA Hook Wall, Hanger Outside (Hook Point) 19 4,991’ OB Lateral ZXP Liner Top Packer 20 5,038’ OB OA 4-1/2” Hook Hanger ‘LEM’ Above Hanger 21 5,048’ OB 4-1/2” Hook Hanger ‘LEM’ Inside Hanger 22 5,048’ OB Hook Wall, Hanger Inside 7-5/8” Window 23 5,065’ NB Hook Wall, Hanger Outside (Hook Point) 24 5,213’ NB ZXP Liner Top Packer 25 5,231’ NB Lateral 7-5/8” x 5” HMC Liner Hanger GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14 – 8/1/2004 CTU Clean-out and Kill String Install, ASR#1 – 2/5/2019 ESP Completion / Casing Repair – ASR#1 6/4/2019 Jet Pump Completion by ASR – 8/1/2022 Install Extended Patch w/ SL – 9/17/2022 LATERAL WINDOW DETAIL “OA” Window f/ 4,840’ MD to 4,852’ MD; Angle @ window 70° “OB” Window f/ 5,053’ MD to 5,065’ MD; Angle @ window 78° TREE & WELLHEAD Tree 2-9/16” – 5M FMC Wellhead 11” x 7-*1/16” 5M FMC Gen 5A w/ 2-7/8” FMC Tbg Hgr, 3” LH me on Top and 2-7/8” EU 8rd on Btm, 2.5” CIW BPV Profile OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 42” Hole 10-3/4" Cmt w/ 396 sx AS Lite, 257 sx Class “G” in 13-1/2” Hole 7-5/8” Cmt w/ 765 sx Class “G” in 9-7/8” Hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm Cap 20" Conductor 215 / A-53 / Welded N/A Surface 112' N/A 10-3/4” Surface 55.5 / L-80 / BTC-M 9.950 Surface 161’ .0962 10-3/4” Surface 45.5 / K-55 / BTC 9.950 161’ 2,249’ .0962 10-3/4” Surface 55.5 / L-80 / BTC-M 9.950 2,249’ 2,378’ .0962 7-5/8" Production 29.7 / L-80 / BTC-M 6.875 Surface 5,775' .0459 5-1/2” Prod. Liner 17 / L-80 / Flush II 4.892 4,735’ 4,805’ 0.0232 4-1/2” Liner “OA” 12.6 / L-80 / IBT 3.958 4,835’ 9,188’ N/A 4-1/2” Liner “OB” 12.6 / L-80 / IBT 3.958 4,991’ 9,230’ N/A 4-1/2” Liner “NB” 12.6 / L-80 / IBT-M 3.958 5,213’ 9,232’ N/A TUBING DETAIL 4-1/2” Tubing 12.4 / L-80 / TXP BTC 3.958 Surface 4,633’.0152 WELL INCLINATION DETAIL KOP @ 450’ MD 50°+ from 3,200’ Max Wellbore Angle = 70° @ +4,696’ PERFORATION DETAIL Schrader Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status N Sands 4,414’ 4,458 3,737’ 3,754’ 44 3-3/8” 7/18/22 Open 4,485’ 4,543’ 3,763’ 3,784’ 58 3-3/8” 7/18/22 Open 4,569’ 4,637’ 3,794’ 3,818’ 68 3-3/8” 7/18/22 Open Ref Log: 9/14/2004 MPT, GR, EWR4, ABI, ROP Well Name Rig API Number Well Permit Number Start Date End Date MP I-17 CTU #9 50-029-23212-00-00 204-098 11/21/2022 11/25/2022 Continue FCO w/N2 to 5100' and sweep to surface. Shutdown and dry drift to 8055' CTM before lockup. Call OE to discuss and decide to call it good. POOH. FP well. RDMO. No operations to report. 11/19/2022 - Saturday Travel to location, spot in, RU, function test BOP. Stab on, line up for pressure test, 300# low/4200# high, RIH w/ slim 1.75" JSN to attempt FCO. Tag fill @ 4,034, start FCO. Job In Progress. 11/22/2022 - Tuesday 11/20/2022 - Sunday No operations to report. 11/21/2022 - Monday 11/18/2022 - Friday No operations to report. 11/16/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 11/17/2022 - Thursday No operations to report. Continue FCO w/N2 to 5100' and sweep to surface. Shutdown and dry drift to 8055' CTM before lockup. Call OE to discuss and decide to call it good. POOH RIH w/ slim 1.75" JSN to attempt FCO. Tag fill @ 4,034, start FCO Well Name Rig API Number Well Permit Number Start Date End Date MP I-17 CTU #9 50-029-23212-00-00 204-098 11/21/2022 11/25/2022 11/25/2022 - Friday WELL SHUT-IN ARRIVAL. SHIFT XD-SS W/ 4-1/2" 42BO AT 3,842' MD (Appears open). SET, 3" JETPUMP, SHOCK ABSORBER, DUAL SPARTEK GAUGES (serial# - HC-00029, ratio: 12B, screen, oal -160") IN XD-SS AT 3,842' MD. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 11/23/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 11/24/2022 - Thursday WELL SHUT-IN ON ARRIVAL. RAN DUAL SWORF MAGNETS TO 4,315' SLM (Unable to pass). WELL SHUT-IN ON DEPARTURE, NOTIFIED PAD OP. No operations to report. No operations to report. 11/26/2022 - Saturday No operations to report. 11/29/2022 - Tuesday 11/27/2022 - Sunday No operations to report. 11/28/2022 - Monday SET, 3" JETPUMP, SHOCK ABSORBER, DUAL SPARTEK GAUGES Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/22/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221122-1 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# SRU 213-15 50133206520000 215100 6/24/2022 Yellowjacket PERF KBU 33-06X 50133205290000 203183 6/26/2022 Yellowjacket PERF BCU 7A 50133202840100 214060 6/28/2022 Yellowjacket GPT-PERF END 3-17F 50029219460600 203216 7/2/2022 Yellowjacket PERF-RETAINER KBU 32-08 50133206240000 214014 7/12/2022 Yellowjacket PERF BCU 7A 50133202840100 214060 7/15/2022 Yellowjacket GPT-PERF SRU 213-15 50133206520000 215100 7/19/2022 Yellowjacket GPT-PLUG MPU I-17 50029232120000 204098 7/19/2022 Yellowjacket TUBING CUT CLU 05RD 50133204740100 215160 7/21/2022 Yellowjacket PLUG CLU 10 50133205530000 205106 7/21/2022 Yellowjacket RCT-JET CUT SRU 213-15 50133206520000 215100 7/22/2022 Yellowjacket PERF Please include current contact information if different from above. 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Chmielowski Digitally signed by Jessie L. 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ϭϭ͟ǆϳͲΎϭͬϭϲ͟ϱD&D'ĞŶϱǁͬϮͲϳͬϴ͟&DdďŐ,Őƌ͕ϯ͟>, ŵĞŽŶdŽƉĂŶĚϮͲϳͬϴ͟hϴƌĚŽŶƚŵ͕Ϯ͘ϱ͟/tWsWƌŽĨŝůĞ KWE,K>ͬDEdd/> ϮϬΗ ŵƚǁͬϮϲϬƐǆŽĨƌĐƚŝĐƐĞƚ/ŝŶϰϮ͟,ŽůĞ ϭϬͲϯͬϰΗ ŵƚǁͬϯϵϲƐǆ^>ŝƚĞ͕ϮϱϳƐǆůĂƐƐ͞'͟ŝŶϭϯͲϭͬϮ͟,ŽůĞ ϳͲϱͬϴ͟ ŵƚǁͬϳϲϱƐǆůĂƐƐ͞'͟ŝŶϵͲϳͬϴ͟,ŽůĞ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ĂƉ ϮϬΗ ŽŶĚƵĐƚŽƌ ϮϭϱͬͲϱϯͬtĞůĚĞĚ Eͬ ^ƵƌĨĂĐĞ ϭϭϮΖ Eͬ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ ^ƵƌĨĂĐĞ ϭϲϭ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϰϱ͘ϱͬ<Ͳϱϱͬd ϵ͘ϵϱϬ ϭϲϭ͛ Ϯ͕Ϯϰϵ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ Ϯ͕Ϯϰϵ͛ Ϯ͕ϯϳϴ͛ ͘ϬϵϲϮ ϳͲϱͬϴΗ WƌŽĚƵĐƚŝŽŶ Ϯϵ͘ϳͬ>ͲϴϬͬdͲD ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϱ͕ϳϳϱΖ ͘Ϭϰϱϵ ϱͲϭͬϮ͟ WƌŽĚ͘>ŝŶĞƌ ϭϳͬ>ͲϴϬ ͬ&ůƵƐŚ// ϰ͘ϴϵϮ ϰ͕ϳϯϱ͛ ϰ͕ϴϬϱ͛ Ϭ͘ϬϮϯϮ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ ϭϮ͘ϲͬ>ͲϴϬͬ/d ϯ͘ϵϱϴ ϰ͕ϴϯϱ͛ ϵ͕ϭϴϴ͛ Eͬ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ ϭϮ͘ϲͬ>ͲϴϬͬ/d ϯ͘ϵϱϴ ϰ͕ϵϵϭ͛ ϵ͕ϮϯϬ͛ Eͬ ϰͲϭͬϮ͟ >ŝŶĞƌ͞E͟ ϭϮ͘ϲͬ>ͲϴϬͬ/dͲD ϯ͘ϵϱϴ ϱ͕Ϯϭϯ͛ ϵ͕ϮϯϮ͛ Eͬ dh/E'd/> ϰͲϭͬϮ͟ dƵďŝŶŐ ϭϮ͘ϰͬ>ͲϴϬͬdyWd ϯ͘ϵϱϴ ^ƵƌĨĂĐĞ ϰ͕ϲϯϯ͛͘ϬϭϱϮ t>>/E>/Ed/KEd/> <KWΛϰϱϬ͛D ϱϬΣнĨƌŽŵϯ͕ϮϬϬ͛ DĂǆ tĞůůďŽƌĞŶŐůĞсϳϬΣΛнϰ͕ϲϵϲ͛ WZ&KZd/KEd/> ^ĐŚƌĂĚĞƌ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ^ŝǌĞ ĂƚĞ ^ƚĂƚƵƐ E^ĂŶĚƐ ϰ͕ϰϭϰ͛ ϰ͕ϰϱϴ ϯ͕ϳϯϳ͛ ϯ͕ϳϱϰ͛ ϰϰ ϯͲϯͬϴ͟ 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EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϴͬϮϮͬϮϬϮϮͲDŽŶĚĂǇ tĞůůEĂŵĞ ZŝŐ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ DW/Ͳϭϳ ^Zηϭ ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ϮϬϰͲϬϵϴ ϴͬϭϵͬϮϬϮϮ ϵͬϭϳͬϮϬϮϮ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϴͬϮϳͬϮϬϮϮͲ^ĂƚƵƌĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϴͬϯϬͬϮϬϮϮͲdƵĞƐĚĂǇ ϴͬϮϴͬϮϬϮϮͲ^ƵŶĚĂǇ t>>^,hdͲ/EKEZZ/s>͕WdWϯϬϬ>ͬϯϱϬϬ,͘ZEϭϬΖǆϯ͘ϳϬΗhDDzt,/W^dK<dKϰ͕ϬϱϯΖ^>D;hŶĂďůĞƚŽƉĂƐƐͿ͘ZE ϯ͘ϳϬΗZ>>^^D>zdKϰ͕ϬϱϳΖ^>Dd,E&>>dKϰ͕ϴϮϱΖ^>D;ƐŚĞĂƌĞĚŐƌͿ͘Wh>>ϯ͘ϳϬΗZ>>^^D>z&ZKD ϰ͕ϴϮϱΖ^>D͘tKZ<W^d^WKddϰ͕ϬϱϯΖ^>D;ĂƉƉĞĂƌƐŵƵĐŚďĞƚƚĞƌͿ͘ZEϮ͘ϱϬΗZ>>^^D>zdKϰ͕ϵϮϱΖ^>D;EŽ ŝƐƐƵĞƐͿ͘ZEϭϬΖǆϯ͘ϳϬΗhDDzt,/W^dK<dKϰ͕ϴϮϱΖ^>D;^ĞĞůŽŐͿ͘WZdt/Zdϰ͕ϬϱϬΖ^>D;ƉƉĞĂƌƚŽŚĂǀĞ ƌĞĐŽǀĞƌĞĚĂůůǁŝƌĞͿ͘t>>^,hdͲ/EKEWZdhZ͕EKd/&/WKW͘>&d/E,K>͗ϭ͘ϳϱΗZ^͕ϭϬΖϭͲϳͬϴΗZK>>Z͕<:dϱΖǆϭͲ ϳͬϴΗZK>>Z͕ϭͲϯͬϰΗK:͕<:dϭͲϳͬϴΗ>^^͕ϰͲϭͬϮΗ'Z͕ϭϬΖǆDzt,/W^dK<;K>ͲϰϱΖͿ͘ ϴͬϮϵͬϮϬϮϮͲDŽŶĚĂǇ ϴͬϮϲͬϮϬϮϮͲ&ƌŝĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϴͬϮϰͬϮϬϮϮͲtĞĚŶĞƐĚĂǇ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϴͬϮϱͬϮϬϮϮͲdŚƵƌƐĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ tĞůůEĂŵĞ ZŝŐ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ DW/Ͳϭϳ ^ůŝĐŬůŝŶĞ ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ϮϬϰͲϬϵϴ ϴͬϭϵͬϮϬϮϮ ϵͬϭϳͬϮϬϮϮ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϯͬϮϬϮϮͲ^ĂƚƵƌĚĂǇ t>>^ͬ/KEZZ/s>͕WdWϯϬϬ>ͬϮϴϬϬ,͘;:K^KW͗^d>KtZW<ZΛZ/,tͬ,͕Ϯ͘ϳϱΖΖ'hE'DD͕<Z ηϭϬ͕<Z>KtZW<Z͘>dKdKWD/>DEdсϭϵΖ>^dKWWd,͕dKK>^dh<dϰϴϮϬ͘ϳΖtKZ</E'd,>/EdK dZ/'d&ZWh>>DydE^/KEϯϬϬϬ>^Kh>EΖd'd&Z͘t/dE'&ZKDdKtE͕D</^/KE^dd,>KtZ ^^D>zdϰϴϭϲΖ͘:KKDW>dt>>^ͬ/KEWZdhZ͘ ϵͬϲͬϮϬϮϮͲdƵĞƐĚĂǇ ϵͬϰͬϮϬϮϮͲ^ƵŶĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϱͬϮϬϮϮͲDŽŶĚĂǇ ϵͬϮͬϮϬϮϮͲ&ƌŝĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϴͬϯϭͬϮϬϮϮͲtĞĚŶĞƐĚĂǇ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ t>>^,hdͲ/EKEZZ/s>͕WdWϯϬϬ>ͬϯϱϬϬ,͘ZEϯ͘ϱϬΗΗ>/dKdKK>^dZ/E'dϰ͕ϳϲϲΖ^>D;ŝŵƉƌĞƐƐŝŽŶŽĨƉĂƌƚŝĂůƌŽƉĞ ƐŽĐŬĞƚͿ͘DϮddDWd^dKWh>>dKK>^dZ/E'&ZKDϰ͕ϳϲϲΖ^>D;hŶƐƵĐĐĞƐƐĨƵůͿ͘ZKsZdKK>^dZ/E'&ZKDϰ͕ϳϲϲΖ ^>D͘^d/>>>&d/E,K>͗ϭϬΖǆϯ͘ϳϬΗΗhDDzt,/W^dK<͘ ϵͬϭͬϮϬϮϮͲdŚƵƌƐĚĂǇ WdWϯϬϬ>ͬϯϱϬϬ,͘ZKsZϭϬΖǆϯ͘ϳϬΗΗhDDzt,/W^dK<&ZKDϰ͕ϴϬϬΖ^>D͘ZEϯ͘ϴϬΗΗ^t'Ed'>Dd ϰ͕ϴϬϯΖ^>D͘tKZ<d/',d^WKd^dϴϮϱΖ͕ϰ͕ϬϱϯΖ͕ϰ͕ϲϯϴΖ^>D;^ŵĂůůŝŵƉƌŽǀĞŵĞŶƚͿ͘d'>Ddϰ͕ϴϬϯΖ^>DϭϬΖǆϯ͘ϳϬΗΗ hDDzt,/W^dK<͘d/',d^WKd^dϰ͕ϬϱϯΖ͕ϰ͕ϲϯϴΖ^>DZDh,^/ZdKK>W^d͘t>>^,hdͲ/EKE WZdhZ͕EKd/&/WKW͘ tĞůůEĂŵĞ ZŝŐ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ DW/Ͳϭϳ Žŝůͬ^> ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ϮϬϰͲϬϵϴ ϴͬϭϵͬϮϬϮϮ ϵͬϭϳͬϮϬϮϮ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ t>>^ͬ/KEZZ/s>͘ZEϯͲϭͬϮZZZd,D'EdϰϲϭϴΖ^>D͕ZKsZ^D>>DKhEdDd>^,s/E'^͘ KWE^>sΛϲϱϭϬΖ^>DͬϲϱϭϬΖD͘^dtͬϯΗ:dWhDW;ƐĞƌŝĂůη,ͲϬϬϬϮϮ͕ƌĂƚŝŽ͗ϭϮ͕ƐĐƌĞĞŶ͕ƐĞĐ͘ůŽĐ͕͘K>сϲϵΗͿ/E^^y ΛϯϴϱϬΖ^>DͬϯϴϰϮΖD͘t>>&>Kt/E'KEWZdhZ͘ ϵͬϭϳͬϮϬϮϮͲ^ĂƚƵƌĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϮϬͬϮϬϮϮͲdƵĞƐĚĂǇ ϵͬϭϴͬϮϬϮϮͲ^ƵŶĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϭϵͬϮϬϮϮͲDŽŶĚĂǇ ϵͬϭϲͬϮϬϮϮͲ&ƌŝĚĂǇ D/Zh&ƵŶĐƚŝŽŶƚĞƐƚKWWdсϮϱϬ>ͬϯϱϬϬ,͘WĞƌĨŽƌŵďƵŵƉƚĞƐƚŽŶ>>ͬ,Ϯ^ŵŽŶŝƚŽƌƐ͘ŽŶƚŝŶƵĂůůǇƉƵŵƉĂĐƌŽƐƐDh^ĞĂůƐƐǇ͕ ƐƉĂĐŝŶŐũŶƚ͕ϲũŶƚƐϮͲϳͬϴΗ^d>dďŐ͕ϰϱ<WŬƌ͕^ĞƚƚŝŶŐ^ůĞĞǀĞ͕ηϭϬ:Ͳ,ǇĚ͕yK͕D,͕ĐƚĐ͘Z/,ƐƚŝŶŐŝŶƚŽƚŵWŬƌ͕ƉƵŵƉďĂůůĂƌŽƵŶĚ ΘƐĞƚƵƉƉĞƌWŬƌ͕ϰϲϭϴΖDƚŽƉŽĨƚŚĞƉĂĐŬĞƌ͘WKK,͕&WtĞůů͕ZDKdhηϵ ϵͬϭϰͬϮϬϮϮͲtĞĚŶĞƐĚĂǇ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϭϱͬϮϬϮϮͲdŚƵƌƐĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/3/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220930 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU I-17 500292321200 204098 3-Aug-22 READ CaliperSurvey MPU B-24 500292264200 196009 7/19/2022 READ CaliperSurvey MPU F-38 500292261400 195168 9/19/2022 READ CaliperSurvey MPU F-73A 500292274401 200198 7/31/2022 READ CaliperSurvey MPU I-01 500292206500 190090 8/31/2022 READ CaliperSurvey MPU I-30 500292371000 222023 7/12/2022 READ Inj_Profile MPU J-27 500292355700 215153 8/11/2022 READ CaliperSurvey MPU L-47 500292355000 215117 7/23/2022 READ CaliperSurvey Please include current contact information if different from above. T37121 T37122 T37123 T37124 T37125 T37126 T37127 T37128 MPU I-17 500292321200 204098 3-Aug-22 READ CaliperSurvey Kayla Junke Digitally signed by Kayla Junke Date: 2022.10.05 13:20:28 -08'00' David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/29/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220929 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# TBU G-01RD 507332003701 191139 6/24/2022 AK E-Line Depth MPU I-17 500292321200 204098 7/17/2022 AK E-Line Perf Please include current contact information if different from above. T37079 T37080MPU I-17 500292321200 204098 7/17/2022 AK E-Line Perf Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.30 13:12:11 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/02/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220902 Well API #PTD #Log Date Log Company Log Type Notes AOGCC Eset # END 3-11 50029218480000 188087 8/1/2022 Halliburton CALIPER + Report KALOTSA 4 50133206650000 217063 7/18/2022 Halliburton PPROF + Processing KBU 22-06Y 50133206500000 215044 7/14/2022 Halliburton PPROF + Processing KTU 24-06H 50133204900000 199073 7/21/2022 Halliburton PPROF + Processing KU 24-05B 50133206830000 219072 7/20/2022 Halliburton PPROF + Processing MPU C-24A 50029230200100 209134 7/28/2022 Halliburton COIL FLAG MPU I-17 50029232120000 204098 7/19/2022 Halliburton FREEPOINT NS-10 50029229850000 200182 7/23/2022 Halliburton CALIPER + Report NS-32 50029231790000 203158 7/24/2022 Halliburton CALIPER + Report PBU 18-02C 50029207620300 213009 7/14/2022 Halliburton CAST/CBL PBU C-10B 50029203710200 211092 7/15/2022 Halliburton PPROF + Processing PBU L5-03 50029236230000 219033 7/25/2022 Halliburton PPROF + Processing Please include current contact information if different from above. T36973 T36974 T36975 T36976 T36977 T36978 T36979 T36980 T36981 T36982 T36983 T36984 MPU I-17 50029232120000 204098 7/19/2022 Halliburton FREEPOINT Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.07 11:00:16 -08'00' By Samantha Carlisle at 12:46 pm, Aug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y Samantha Carlisle at 11:56 am, Aug 05, 2022 'LJLWDOO\VLJQHGE\'DYLG +DDNLQVRQ '1FQ 'DYLG+DDNLQVRQ RX 8VHUV 'DWH 'DYLG+DDNLQVRQ 0*5$8* 6)''65 GWV -/& Jeremy Price Digitally signed by Jeremy Price Date: 2022.08.10 14:02:07 -08'00' RBDMS JSB 081122 WĂƚĐŚ tĞůů͗DW/Ͳϭϳ Wd͗ϮϬϰϬϵϴ W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ tĞůůEĂŵĞ͗DW/Ͳϭϳ W/EƵŵďĞƌ͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗:WƉƌŽĚƵĐĞƌ ZŝŐ͗ůŝŶĞ͕Žŝů ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ϬϴͬϭϬͬϮϬϮϮ ƐƚŝŵĂƚĞĚƵƌĂƚŝŽŶ͗ϱĚĂǇƐ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍zĞƐ ĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗d ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗dŽŵ&ŽƵƚƐ WĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗ƌŝĂŶ'ůĂƐŚĞĞŶ ϵϬϳͲϱϰϱͲϭϭϰϰ ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗dĂǇůŽƌtĞůůŵĂŶ ϵϬϳͲϵϰϳͲϵϱϯϯ &EƵŵďĞƌ͗ &XUUHQW%RWWRP+ROH3UHVVXUH SVL#¶79' %+3*UHDGLQJ 0D[LPXP([SHFWHG%+3SVL#¶79' 33*( 0D[$QWLFLSDWHG6XUIDFH3UHVVXUHSVL *DV&ROXPQ*UDGLHQWSVLIW 0LQ,'´#¶ ;11LSSOH %ULHI:HOO6XPPDU\ 7KH0LOQH3RLQW,ZHOOZDVGULOOHGDVD6FKUDGHU%OXIIGHYHORSPHQWZHOOGXDOODWHUDOZLWK'R\RQLQ -XO\7KHZHOOZDVLQLWLDOO\FRPSOHWHGZLWKDQ(63WKDWUDQIRUWKLUWHHQ\HDUVXSWR1RYHPEHU7KH(63 ZDVSXOOHGLQ$SULOEXWWKH´SURGXFWLRQFDVLQJIDLOHGWRSUHVVXUHWHVW$NLOOVWULQJRI´WXELQJZDV UDQDQGWKHZHOOZDVOHIWVKXWLQWRRUGHUORQJOHDGLWHPVIRUWKHFDVLQJUHSDLU6XEVHTXHQWOHDNGHWHFWORJVVXJJHVWD OLQHUWRSSDFNHUOHDN#¶0',QDGGLWLRQDFRLOHGWXELQJFOHDQRXWRIHDFKRIWKHWKUHHODWHUDOVZDVSHUIRUPHG LQ4-XQH$65UHSDLUHGWKHFDVLQJOHDNDQGLQVWDOOHGD(63FRPSOHWLRQWKH(63IDLOHGDQGZDV XQDEOHWRUHVWDUW-XO\$65SXOOHGWKH(63DQGFRQYHUWHGWKHZHOOWRD-3SURGXFHU1VDQGVZHUHDGGHGDQG VWUDGGOHGZLWKVFUHHQV 2EMHFWLYH 7KHSULPDU\REMHFWLYHRIWKHSRVW5:2ZRUNLVWRVHWD¶SDWFKWRLVRODWHEHWZHHQWKH/73DQGEXOOHW VHDOVWKDWZHUHQRWVWXQJLQGXULQJWKH5:2RSHUDWLRQDQGOHIWµDERYHWKHVHDODVVHPEO\3DWFKZLOO QRWEHXVHGIRULQWHJULW\SXUSRVHVEXWZLOOIRUFHDOOIORZIURPWKH1VDQGVWRIORZWKURXJKWKHVFUHHQV DERYHDQGQRWVDQGRIIWKHZHOOGXULQJSURGXFWLRQ 1RWHV5HJDUGLQJ:HOOERUH&RQGLWLRQ ¶¶&DVLQJSDVVHGWRSVL 3RVW5LJ:RUN (OLQH 6SRWXQLWDQG58 3UHVVXUHWHVWOXEULFDWRUWRSVLORZDQGSVLKLJK 5,+ZLWK.%SDFNHUZLWKVHDODVVHPEO\ 7LHLQWRWXELQJWDOO\EHORZDQGVHW.%DW¶0' 3XOOMHZHOU\ORJXSWR¶0'ZKLOH322+IRUXSSHUSDFNHUVSDFHRXW WĂƚĐŚ tĞůů͗DW/Ͳϭϳ Wd͗ϮϬϰϬϵϴ W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ WĂƚĐŚ tĞůů͗DW/Ͳϭϳ Wd͗ϮϬϰϬϵϴ W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ &RLOHG7XELQJ Notes: x Due to the necessary open hole deployment of Extended BHA jobs, 24-hour crew and WSS coverage is required. x The well will be killed and monitored before making up the initial BHA. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. %XOOKHDGEEOV&7YRORI33*VHDZDWHURU.&/ D :HOOERUHYROXPHWRWRS2$ EEOV $IWHU080+$DQGSXOOWHVWLQJWKH&7&WDJXSRQWKH&7VWULSSHUWRHQVXUH%+$FDQQRWSXOO WKURXJKWKHEUDVVXSRQ322+ZLWK%+$ $WVXUIDFHSUHSDUHIRUGHSOR\PHQWRIa¶SDWFK &RQILUPZHOOLVGHDG:HOOVKRXOGEHGHDGDVVXPLQJLWSDVVHGSUHVVXUHWHVWDERYH+RZHYHU LISUHVVXUHLVREVHUYHGEOHHGDQ\SUHVVXUHRIIWRUHWXUQWDQN.LOOZHOOZ.:)SSJ .&ORUSSJDVQHHGHG0DLQWDLQKROHILOOWDNLQJUHWXUQVWRWDQNXQWLOOXEULFDWRUFRQQHFWLRQ LVUHHVWDEOLVKHG)OXLGVPDQZDWFKPXVWEHSHUIRUPHGZKLOHGHSOR\LQJ%+$WRHQVXUHWKH ZHOOUHPDLQVNLOOHGDQGWKHUHLVQRH[FHVVIORZ 5.*Perform drill by picking up safety joint with TIW valve and space out before MU BHA. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of BHA. 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Η'Η&ůĞǆͲ>ŽĐŬ>ŝŶĞƌ,ĂŶŐĞƌ ϰ͘ϳϵϬ͟ ϭϭ ϰ͕ϳϴϬ ϱ͘ϱΗϭϳηϵƌ&ͬD//ǆWΗyEΗEŝƉƉůĞ;ϰ͘ϰϱϱŶŽͲŐŽͿ ϰ͘ϱϲϮ͟ ϭϮ ϰ͘ϳϴϵ͛ ƵůůĞƚ^ĞĂů>ŽĐĂƚŝŶŐĂƐƐĞŵďůǇ ʹ ƚŵΛϰ͕ϴϬϮ͛ϰ͘ϳϵϬ͟ ϭϯ ϰ͕ϳϵϰ͛ KdŝĞĂĐŬ^ůĞĞǀĞ ϭϰ ϰ͕ϴϬϱ͛ KyW>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϱ ϰ͕ϴϮϴ͛ KKϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛ďŽǀĞ,ĂŶŐĞƌ ϭϲ ϰ͕ϴϯϱ͛ KϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛/ŶƐŝĚĞ,ĂŶŐĞƌ ϭϳ ϰ͕ϴϯϱ͛ K,ŽŽŬtĂůů͕,ĂŶŐĞƌ/ŶƐŝĚĞϳͲϱͬϴ͟ĂƐŝŶŐ ϭϴ ϰ͕ϴϱϮ͛ K,ŽŽŬtĂůů͕,ĂŶŐĞƌKƵƚƐŝĚĞ;,ŽŽŬWŽŝŶƚͿ ϭϵ ϰ͕ϵϵϭ͛ K>ĂƚĞƌĂůyW>ŝŶĞƌ dŽƉWĂĐŬĞƌ ϮϬ ϱ͕Ϭϯϴ͛ KKϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛ďŽǀĞ,ĂŶŐĞƌ Ϯϭ ϱ͕Ϭϰϴ͛ KϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛/ŶƐŝĚĞ,ĂŶŐĞƌ ϮϮ ϱ͕Ϭϰϴ͛ K,ŽŽŬtĂůů͕,ĂŶŐĞƌ/ŶƐŝĚĞϳͲϱͬϴ͟tŝŶĚŽǁ Ϯϯ ϱ͕Ϭϲϱ͛ E,ŽŽŬtĂůů͕,ĂŶŐĞƌKƵƚƐŝĚĞ;,ŽŽŬWŽŝŶƚͿ Ϯϰ ϱ͕Ϯϭϯ͛ EyW>ŝŶĞƌdŽƉWĂĐŬĞƌ Ϯϱ ϱ͕Ϯϯϭ͛ E>ĂƚĞƌĂůϳͲϱͬϴ͟ǆϱ͟,D>ŝŶĞƌ,ĂŶŐĞƌ 'EZ>t>>/E&K W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ƌŝůůĞĚĂŶĚŽŵƉůĞƚĞĚďǇŽǇŽŶϭϰʹϴͬϭͬϮϬϬϰ dhůĞĂŶͲŽƵƚĂŶĚ<ŝůů^ƚƌŝŶŐ/ŶƐƚĂůů͕^ZηϭʹϮͬϱͬϮϬϭϵ ^WŽŵƉůĞƚŝŽŶͬĂƐŝŶŐZĞƉĂŝƌʹ^ZηϭϲͬϰͬϮϬϭϵ :ĞƚWƵŵƉŽŵƉůĞƚŝŽŶďǇ^ZʹϴͬϭͬϮϬϮϮ >dZ>t/EKtd/> ͞K͟tŝŶĚŽǁĨͬϰ͕ϴϰϬ͛DƚŽϰ͕ϴϱϮ͛D͖ŶŐůĞΛǁŝŶĚŽǁϳϬΣ ͞K͟tŝŶĚŽǁĨͬϱ͕Ϭϱϯ͛DƚŽϱ͕Ϭϲϱ͛D͖ŶŐůĞΛǁŝŶĚŽǁϳϴΣ dZΘt>>, dƌĞĞ ϮͲϵͬϭϲ͟ʹϱD&D tĞůůŚĞĂĚ ϭϭ͟ǆϳͲΎϭͬϭϲ͟ϱD&D'ĞŶϱǁͬϮͲϳͬϴ͟&DdďŐ,Őƌ͕ϯ͟>, ŵĞŽŶdŽƉĂŶĚϮͲϳͬϴ͟hϴƌĚŽŶƚŵ͕Ϯ͘ϱ͟/tWsWƌŽĨŝůĞ KWE,K>ͬDEdd/> ϮϬΗ ŵƚǁͬϮϲϬƐǆŽĨƌĐƚŝĐƐĞƚ/ŝŶϰϮ͟,ŽůĞ ϭϬͲϯͬϰΗ ŵƚǁͬϯϵϲƐǆ^>ŝƚĞ͕ϮϱϳƐǆůĂƐƐ͞'͟ŝŶϭϯͲϭͬϮ͟,ŽůĞ ϳͲϱͬϴ͟ ŵƚǁͬϳϲϱƐǆůĂƐƐ͞'͟ŝŶϵͲϳͬϴ͟,ŽůĞ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ĂƉ ϮϬΗ ŽŶĚƵĐƚŽƌ ϮϭϱͬͲϱϯͬtĞůĚĞĚ Eͬ ^ƵƌĨĂĐĞ ϭϭϮΖ Eͬ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ ^ƵƌĨĂĐĞ ϭϲϭ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϰϱ͘ϱͬ<Ͳϱϱͬd ϵ͘ϵϱϬ ϭϲϭ͛ Ϯ͕Ϯϰϵ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ Ϯ͕Ϯϰϵ͛ Ϯ͕ϯϳϴ͛ ͘ϬϵϲϮ ϳͲϱͬϴΗ WƌŽĚƵĐƚŝŽŶ Ϯϵ͘ϳͬ>ͲϴϬͬdͲD ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϱ͕ϳϳϱΖ ͘Ϭϰϱϵ ϱͲϭͬϮ͟ WƌŽĚ͘>ŝŶĞƌ ϭϳͬ>ͲϴϬ ͬ&ůƵƐŚ// ϰ͘ϴϵϮ ϰ͕ϳϯϱ͛ ϰ͕ϴϬϱ͛ Ϭ͘ϬϮϯϮ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ ϭϮ͘ϲͬ>ͲϴϬͬ/d ϯ͘ϵϱϴ ϰ͕ϴϯϱ͛ ϵ͕ϭϴϴ͛ Eͬ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ ϭϮ͘ϲͬ>ͲϴϬͬ/d ϯ͘ϵϱϴ ϰ͕ϵϵϭ͛ ϵ͕ϮϯϬ͛ Eͬ ϰͲϭͬϮ͟ >ŝŶĞƌ͞E͟ ϭϮ͘ϲͬ>ͲϴϬͬ/dͲD ϯ͘ϵϱϴ ϱ͕Ϯϭϯ͛ ϵ͕ϮϯϮ͛ Eͬ dh/E'd/> ϰͲϭͬϮ͟ dƵďŝŶŐ ϭϮ͘ϰͬ>ͲϴϬͬdyWd ϯ͘ϵϱϴ ^ƵƌĨĂĐĞ ϰ͕ϲϯϯ͛͘ϬϭϱϮ t>>/E>/Ed/KEd/> <KWΛϰϱϬ͛D ϱϬΣнĨƌŽŵϯ͕ϮϬϬ͛ DĂǆ tĞůůďŽƌĞŶŐůĞсϳϬΣΛнϰ͕ϲϵϲ͛ WZ&KZd/KEd/> ^ĐŚƌĂĚĞƌ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ^ŝǌĞ ĂƚĞ ^ƚĂƚƵƐ E^ĂŶĚƐ ϰ͕ϰϭϰ͛ ϰ͕ϰϱϴ ϯ͕ϳϯϳ͛ ϯ͕ϳϱϰ͛ ϰϰ ϯͲϯͬϴ͟ ϳͬϭϴͬϮϮ KƉĞŶ ϰ͕ϰϴϱ͛ ϰ͕ϱϰϯ͛ ϯ͕ϳϲϯ͛ ϯ͕ϳϴϰ͛ ϱϴ ϯͲϯͬϴ͟ ϳͬϭϴͬϮϮ KƉĞŶ ϰ͕ϱϲϵ͛ ϰ͕ϲϯϳ͛ ϯ͕ϳϵϰ͛ ϯ͕ϴϭϴ͛ ϲϴ ϯͲϯͬϴ͟ ϳͬϭϴͬϮϮ KƉĞŶ ZĞĨ>ŽŐ͗ ϵͬϭϰͬϮϬϬϰDWd͕ 'Z͕tZϰ͕/͕ZKW WĂƚĐŚ tĞůů͗DW/Ͳϭϳ Wd͗ϮϬϰϬϵϴ W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ &RLOHG7XELQJ%23V 6WDQGLQJ2UGHUVIRU2SHQ+ROH:HOO&RQWUROGXULQJ3HUI*XQ'HSOR\PHQW WĂƚĐŚ tĞůů͗DW/Ͳϭϳ Wd͗ϮϬϰϬϵϴ W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ WĂƚĐŚ tĞůů͗DW/Ͳϭϳ Wd͗ϮϬϰϬϵϴ W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ (TXLSPHQW/D\RXW'LDJUDP 5HJJ-DPHV%2*& )URP$ODVND16$65:HOO6LWH0DQDJHUV$ODVND16$65:HOO6LWH0DQDJHUV#KLOFRUSFRP! 6HQW7XHVGD\$XJXVW$0 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& 6XEMHFW038LZHHNO\%23(WHVWUHSRUW $WWDFKPHQWV+LOFRUS$65[OV[ dŚĂŶŬǇŽƵ͘ Regards, Russell Gallen ASR DSM, Mobile: 907-529-7202 Office: 907-685-1266 russell.gallen@hilcorp.com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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:ASR 1 DATE: 7/29/22 Rig Rep.: Rig Phone: 685-1266 Operator: Op. Phone:685-1266 Rep.: E-Mail Well Name: PTD #22040980 Sundry #322-399 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: X Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:715 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1FP Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 2 1/16"P Inside Reel valves 0NA HCR Valves 1 2 1/16"P Kill Line Valves 2 2 1/16"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3050 P CHOKE MANIFOLD:Pressure After Closure (psi)1650 P Quantity Test Result 200 psi Attained (sec)10 P No. Valves 16 P Full Pressure Attained (sec)53 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4X 2200 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:1 Test Time:10.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 7/27/22 19:00 Waived By Test Start Date/Time:7/28/2022 21:30 (date) (time)Witness Test Finish Date/Time:7/29/2022 8:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Guy Cook Hilcorp Chart shows test #4 attempt to work upper kelly valve, for two tests. Fail. Line up test #4 without upper kelly valve. Pass. Change out to new & retest kelly valve on test #9 Pass. Tested with both 2.875" and 4.5" test joints . Annular closing time = 27 sec D. Schulze / J. Haberthur Hilcorp Alaska A. Haberthur/ R. Gallen MPU I-17 Test Pressure (psi): skaNS-ASR-Well Site Managers@hilcorp.c Form 10-424 (Revised 02/2022) 2022-0729_BOP_Hilcorp_ASR1_MPU_I-17 9 9 9 9 9 9 9 9 9 9 9 9 9 9 -5HJJ FP work upper kelly valve, for two tests. Annular closing time = 27 sec 5HJJ-DPHV%2*& )URP$ODVND16$65:HOO6LWH0DQDJHUV$ODVND16$65:HOO6LWH0DQDJHUV#KLOFRUSFRP! 6HQW6XQGD\-XO\30 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& 6XEMHFW038LZHHNO\WHVW:RUNRYHU $WWDFKPHQWV+LOFRUS$65[OV[ dŚĂŶŬǇŽƵ͘ Regards, Russell Gallen ASR DSM, Mobile: 907-529-7202 Office: 907-685-1266 russell.gallen@hilcorp.com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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:ASR 1 DATE: 7/21/22 Rig Rep.: Rig Phone: 685-1266 Operator: Op. Phone:685-1266 Rep.: E-Mail Well Name: PTD #22040980 Sundry #322-399 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: X Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:715 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 2 1/16"P Inside Reel valves 0NA HCR Valves 1 2 1/16"P Kill Line Valves 2 2 1/16"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3050 P CHOKE MANIFOLD:Pressure After Closure (psi)1700 P Quantity Test Result 200 psi Attained (sec)15 P No. Valves 16 P Full Pressure Attained (sec)58 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4x2125 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:13.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 7/20/22 10:19 Waived By Test Start Date/Time:7/20/2022 23:30 (date) (time)Witness Test Finish Date/Time:7/21/2022 13:00 PM BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Lou Laubenstein Hilcorp Chart shows test #2 lost significant fluid & introduced air in system from bad line up. Open up & fill again. Retest- Pass. No issues with equipment. Tested with both 2.875" and 4.5" test joints . Annular closing time = 27 sec D. Schulze / J. Haberthur Hilcorp Alaska C. Huntington/ R. Gallen MPU I-17 Test Pressure (psi): skaNS-ASR-Well Site Managers@hilcorp.c Form 10-424 (Revised 02/2022) 2022-0721_BOP_Hilcorp_ASR1_MPU_I-17 9 9 9 9 9 999 9 9 9 9 9 -5HJJ Annular closing time = 27 sec Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/18/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes AOGCC Eset # BRU 212-24 50283200370000 172015 7/27/2022 AK E-Line CIBP BRU 233-27 50283100260000 163002 7/2/2022 AK E-Line PERF HVA B-16 50231200400000 212133 6/23/2022 AK E-Line PLUG/CEMENT KBU 11-08Z 50133206290000 214044 6/22/2022 AK E-Line PERF KBU 33-06X 50133205290000 203183 6/18/2022 AK E-Line PLUG/CEMENT/PUNCH MPU I-17 50029232120000 204098 7/9/2022 Read CALIPER SRU 32A-33 50133101640100 191014 6/20/2022 Halliburton TMD3D-WFL + Report Please include current contact information if different from above. T36794 T36795 T36796 T36797 T36798 T36799 T36800 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.19 09:04:04 -08'00' From: Rixse, Melvin G (OGC) Sent: Sunday, July 17, 2022 10:10 AM To: Brian Glasheen <Brian.Glasheen@hilcorp.com> Cc: David Haakinson <dhaakinson@hilcorp.com> Subject: RE: [EXTERNAL] RE: MP I-17 AOGCC 10-403 Submittal, PTD: 204-098 Brian, Hilcorp is approved to set the production packer at 4090’ MD. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell From: Brian Glasheen <Brian.Glasheen@hilcorp.com> Sent: Saturday, July 16, 2022 11:05 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: David Haakinson <dhaakinson@hilcorp.com> Subject: Re: [EXTERNAL] RE: MP I-17 AOGCC 10-403 Submittal, PTD: 204-098 Good evening Mel, HC would like to request moving the production packer up to ~4090’Md on MPI-17 At my original target depth was ~4261. When testing below 4090’ we were getting a very small bleed off that was barley failing our MIT criteria at 3800 psi. Thanks, Brian Glasheen On Jul 15, 2022, at 1:59 PM, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Brian, AOGCC will decline to witness the pressure test on your TIW valve. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell From: Brian Glasheen <Brian.Glasheen@hilcorp.com> Sent: Friday, July 15, 2022 1:33 PM To: David Haakinson <dhaakinson@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com> Subject: Re: MP I-17 AOGCC 10-403 Submittal, PTD: 204-098 Mel, As a follow up. Would you like the TIW state witnessed? Please advise. Thanks, Brian Glasheen On Jul 15, 2022, at 10:04 AM, David Haakinson <dhaakinson@hilcorp.com> wrote: Mel, As a follow up to our conversation and after investigation of the incident on ASR yesterday, below are further details of the event: • At 1330 hours on 7/14, ASR operations was attempting a second pressure test of the 7-5/8” annulus with the work-string and bullet seals stabbed into the liner top packer. • A TIW valve was pre-emptively made up in the work-string on the rig floor and in place during the annulus testing. • The variable pipe rams were closed on the annulus during the testing and at the time of the event. • ASR operations was 25 minutes into a 30 minute test when approximately 1.5 gallons of crude/water mixture came out of the work-string on surface. • The TIW valve was in the open position when the release occurred and was immediately closed. • The pump pressure on the annulus was relieved and shut in. The annulus remained at zero psi during the entire event. • A Kelly hose was installed and tied into the work-string above the TIW valve. A shut in tubing (work-string) pressure of 300 psi was measured. • At 1600 hours, 100 bbls of 8.4 source water was bullheaded to formation, killing the well. Both tubing (work-string) and annulus pressures remained at zero post well kill. After reviewing the incident last night into this morning, we have classified this incident as a kick due to under-balancing of the tubing (work-string) side. Our initial investigation found that ASR operations was not maintaining proper hole fill in the work-string, allowing for the well to slowly underbalance as the fluid level fell. Brian and myself were personally on location for the well kill and subsequent follow up investigation and mandate of requiring proper hole fill during the operation. Further discussions regarding our wellsite supervisors is in progress. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. As discussed, we will pressure test the TIW valve to 2500 psi today when we are on surface. Please let us know if you need any additional information. We will be travelling back to Anchorage today and out of phone service from ~1030 to 1245. David Haakinson Operations Manager | Milne Point | Hilcorp Alaska, LLC Office: (907) 777-8343 | Cell: (307) 660-4999 dhaakinson@hilcorp.com From: Brian Glasheen <Brian.Glasheen@hilcorp.com> Sent: Thursday, July 14, 2022 5:13 PM To: melvin.rixse@alaska.gov Cc: David Haakinson <dhaakinson@hilcorp.com> Subject: MP I-17 AOGCC 10-403 Submittal, PTD: 204-098 Mel, Per phone discussion today. During step 17b we were stung in to the LTP and pressure testing the 7-5/8’’ to 3700 psi. After a hour of pressure testing the work string burped up a gallon of fluid. We had the TIW already in place and closed it. We pumped down the work string and re killed the well. Well is confirmed dead and we are maintaining hole fill in the work sting going forward. Once out of hole, plan forward is to move to step 22, rig up the shooting flange and pressure test. Thanks Brian Glasheen Operations Engineer 907-545-1144 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT I-17 JBR 08/18/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 7/12/22. 2 7/8" and 4.5" test joints used for testing. Annular failed initial tests and the element was changed out. I left location and returned the next morning to continue testing. Test #3 was bled off and air was purged out of the system. Retested good. Test #5 was retested due to the driller pressuring up to the high without having a solid passing 5 minutes on the low. The BOP control system response times were checked and were as follows: Annular - 22.9 seconds, UPR - 6 seconds, Blinds (simulated with the UPR) - 5 seconds, HCR choke - 2 seconds. All the charge bottles pre-charges were checked and all 12 bottles were at 975 to 1100 psi. Test Results TEST DATA Rig Rep:Chris GrubbOperator:Hilcorp Alaska, LLC Operator Rep:Charlie Huntington Rig Owner/Rig No.:Hilcorp ASR 1 PTD#:2040980 DATE:7/13/2022 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopGDC220711103850 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 9 MASP: 715 Sundry No: 322-399 CLOSURE TIME (sec) Time/Pressure P/F Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 1 P Lower Kelly 0 NA Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11" 5000 FP #1 Rams 1 2 7/8"x5"VB P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" 5000 P HCR Valves 1 2 1/16" 5000 P Kill Line Valves 2 2 1/16" 5000 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P1800 200 PSI Attained P14.7 Full Pressure Attained P62 Blind Switch Covers:PAll Stations Nitgn Btls# &psi (avg)P4@2350 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA 9 9 9 9 9 9 9 9 9 9 FP Annular failed initial tests BOP control system response times were checked and were as follows: Annular - 22.9 seconds, UPR - 6 seconds, Blinds (simulated with the UPR) - 5 seconds, HCR choke - 2 seconds. 7\SHRI5HTXHVW $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 5HSDLU:HOO 2SHUDWLRQVVKXWGRZQ 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH 3XOO7XELQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HHQWHU6XVS:HOO $OWHU&DVLQJ 2WKHU&RQYHUWWR-HW3XPS 2SHUDWRU1DPH &XUUHQW:HOO&ODVV3HUPLWWR'ULOO1XPEHU ([SORUDWRU\ 'HYHORSPHQW $GGUHVV6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU ,ISHUIRUDWLQJ:HOO1DPHDQG1XPEHU :KDW5HJXODWLRQRU&RQVHUYDWLRQ2UGHUJRYHUQVZHOOVSDFLQJLQWKLVSRRO" :LOOSODQQHGSHUIRUDWLRQVUHTXLUHDVSDFLQJH[FHSWLRQ" <HV 1R 3URSHUW\'HVLJQDWLRQ/HDVH1XPEHU)LHOG3RROV 7RWDO'HSWK0'IW 7RWDO'HSWK79'IW (IIHFWLYH'HSWK0' (IIHFWLYH'HSWK79' 0363SVL 3OXJV0' -XQN0' 1$ &DVLQJ &ROODSVH &RQGXFWRU 1$ 6XUIDFH SVL 6XUIDFH SVL 6XUIDFH SVL 3URGXFWLRQ SVL 2$/LQHU 1$ 2%/LQHU 1$ 1%/LQHU 1$ 3DFNHUVDQG66697\SH 3DFNHUVDQG66690'IWDQG79'IW $WWDFKPHQWV 3URSRVDO6XPPDU\ :HOOERUHVFKHPDWLF :HOO&ODVVDIWHUSURSRVHGZRUN 'HWDLOHG2SHUDWLRQV3URJUDP %236NHWFK ([SORUDWRU\ 6WUDWLJUDSKLF 'HYHORSPHQW 6HUYLFH (VWLPDWHG'DWHIRU :HOO6WDWXVDIWHUSURSRVHGZRUN &RPPHQFLQJ2SHUDWLRQV 2,/ :,1- :'63/6XVSHQGHG 9HUEDO$SSURYDO 'DWH *$6 :$* *6725 63/8* $2*&&5HSUHVHQWDWLYH*,1-2S6KXWGRZQ $EDQGRQHG &RQWDFW1DPH &RQWDFW(PDLO &RQWDFW3KRQH $XWKRUL]HG7LWOH &RQGLWLRQVRIDSSURYDO1RWLI\$2*&&VRWKDWDUHSUHVHQWDWLYHPD\ZLWQHVV 6XQGU\1XPEHU 3OXJ,QWHJULW\ %237HVW 0HFKDQLFDO,QWHJULW\7HVW /RFDWLRQ&OHDUDQFH 2WKHU 3RVW,QLWLDO,QMHFWLRQ0,75HT G"<HV 1R 6SDFLQJ([FHSWLRQ5HTXLUHG"<HV 1R 6XEVHTXHQW)RUP5HTXLUHG $33529('%< $SSURYHGE\ &200,66,21(5 7+($2*&& 'DWH &RPP &RPP 6U3HW(QJ 6U3HW*HR 6U5HV(QJ 6HH6FKHPDWLF 6HH6FKHPDWLF %DNHU=;3/LQHU7RS3DFNHUVDQG1$ 0'79'0'79' 0'79'DQG1$ 1$ 3HUIRUDWLRQ'HSWK0'IW /HQJWK 6L]H /(8( 79' %XUVW 1$ 0' 1$ SVL SVL SVL 35(6(17:(//&21',7,216800$5< 67$7(2)$/$6.$ $/$6.$2,/$1'*$6&216(59$7,21&200,66,21 $33/,&$7,21)25681'5<$33529$/6 $$& $'/ $'/ &HQWHUSRLQW'U6XLWH$QFKRUDJH$. +LOFRUS$ODVND//& 0,/1(3781,7, 0,/1(32,176&+5$'(5%/8))2,/ &2 7XELQJ*UDGH 7XELQJ0'IW3HUIRUDWLRQ'HSWK79'IW 7XELQJ6L]H ,KHUHE\FHUWLI\WKDWWKHIRUHJRLQJLVWUXHDQGWKHSURFHGXUHDSSURYHGKHUHLQZLOOQRWEHGHYLDWHGIURPZLWKRXWSULRUZULWWHQDSSURYDO $XWKRUL]HG1DPHDQG 'LJLWDO6LJQDWXUHZLWK'DWH $2*&&86(21/< %ULDQ*ODVKHHQ#KLOFRUSFRP 2SHUDWLRQV0DQDJHU %ULDQ*ODVKHHQ 1$ SVL 1$ U\ 6WDWX )RUP5HYLVHG$SSURYHGDSSOLFDWLRQLVYDOLGIRUPRQWKVIURPWKHGDWHRIDSSURYDO By Meredith Guhl at 10:04 am, Jul 06, 2022 'LJLWDOO\VLJQHGE\'DYLG +DDNLQVRQ '1FQ 'DYLG+DDNLQVRQ RX 8VHUV 'DWH 'DYLG+DDNLQVRQ $SSURYHGIRUUHYHUVHFLUFXODWLQJMHWSXPS 669RQ,$SRZHUIOXLGKLJKSUHVVXUHWULSQRWWRH[FHHGSVL0,7,$RU&0,7,$WRSVL&KDUWHG 5HFRUGHG,$ORZ SUHVVXUHWULSWREHSVL669RQSURGXFWLRQWXELQJORZSUHVVXUHWULSVHWDWSVL669FORVXUH,$ZLOOLQLWLDWHLPPHGLDWHFORVXUH RQ669RQWXELQJDQGYLVDYHUVD4XDGUHQQLDO0,7,$WRSVL%23(WHVWWRSVL '/%0*5-8/'65 ; 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E,ŽŽŬtĂůů͕,ĂŶŐĞƌKƵƚƐŝĚĞ;,ŽŽŬWŽŝŶƚͿ Ϯϳ ϱ͕Ϯϭϯ͛ EyW>ŝŶĞƌdŽƉWĂĐŬĞƌ Ϯϴ ϱ͕Ϯϯϭ͛ E>ĂƚĞƌĂůϳͲϱͬϴ͟ǆϱ͟,D>ŝŶĞƌ,ĂŶŐĞƌ 'EZ>t>>/E&K W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ƌŝůůĞĚĂŶĚŽŵƉůĞƚĞĚďǇŽǇŽŶϭϰʹϴͬϭͬϮϬϬϰ dhůĞĂŶͲŽƵƚĂŶĚ<ŝůů^ƚƌŝŶŐ/ŶƐƚĂůů͕^ZηϭʹϮͬϱͬϮϬϭϵ ^WŽŵƉůĞƚŝŽŶͬĂƐŝŶŐZĞƉĂŝƌʹ^ZηϭϲͬϰͬϮϬϭϵ >dZ>t/EKtd/> ͞K͟tŝŶĚŽǁĨͬϰ͕ϴϰϬ͛DƚŽϰ͕ϴϱϮ͛D͖ŶŐůĞΛǁŝŶĚŽǁϳϬΣ ͞K͟tŝŶĚŽǁĨͬϱ͕Ϭϱϯ͛DƚŽϱ͕Ϭϲϱ͛D͖ŶŐůĞΛǁŝŶĚŽǁϳϴΣ dZΘt>>, dƌĞĞ ϮͲϵͬϭϲ͟ʹϱD&D tĞůůŚĞĂĚ ϭϭ͟ǆϳͲΎϭͬϭϲ͟ϱD&D'ĞŶϱǁͬϮͲϳͬϴ͟&DdďŐ,Őƌ͕ϯ͟>, ŵĞŽŶdŽƉĂŶĚϮͲϳͬϴ͟hϴƌĚŽŶƚŵ͕Ϯ͘ϱ͟/tWsWƌŽĨŝůĞ KWE,K>ͬDEdd/> ϮϬΗ ŵƚǁͬϮϲϬƐǆŽĨƌĐƚŝĐƐĞƚ/ŝŶϰϮ͟,ŽůĞ ϭϬͲϯͬϰΗ ŵƚǁͬϯϵϲƐǆ^>ŝƚĞ͕ϮϱϳƐǆůĂƐƐ͞'͟ŝŶϭϯͲϭͬϮ͟,ŽůĞ ϳͲϱͬϴ͟ ŵƚǁͬϳϲϱƐǆůĂƐƐ͞'͟ŝŶϵͲϳͬϴ͟,ŽůĞ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ĂƉ ϮϬΗ ŽŶĚƵĐƚŽƌ ϮϭϱͬͲϱϯͬtĞůĚĞĚ Eͬ ^ƵƌĨĂĐĞ ϭϭϮΖ Eͬ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ ^ƵƌĨĂĐĞ ϭϲϭ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϰϱ͘ϱͬ<Ͳϱϱͬd ϵ͘ϵϱϬ ϭϲϭ͛ Ϯ͕Ϯϰϵ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ Ϯ͕Ϯϰϵ͛ Ϯ͕ϯϳϴ͛ ͘ϬϵϲϮ ϳͲϱͬϴΗ WƌŽĚƵĐƚŝŽŶ Ϯϵ͘ϳͬ>ͲϴϬͬdͲD ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϱ͕ϳϳϱΖ ͘Ϭϰϱϵ ϱͲϭͬϮ͟ WƌŽĚ͘>ŝŶĞƌ ϭϳͬ>ͲϴϬ ͬ&ůƵƐŚ// ϰ͘ϴϵϮ ϰ͕ϳϯϱ͛ ϰ͕ϴϬϱ͛ Ϭ͘ϬϮϯϮ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ 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цϰ͕Ϯϲϭ͛ dƌŝƉŽŝŶƚWĂĐŬĞƌ ϰ цy͕yyy͛ yEŝƉƉůĞ ǁͬZ,Ͳ ϱ цy͕yyy͛ ϮϱϬDŝĐŽŶ^ĐƌĞĞŶƐ ʹ ϯϮϬ͛Ͳ ϲ цy͕yyy͛ ϱ͘ϳϱ͟ƵůůĞƚ^ĞĂůƐƐĞŵďůǇ Ͳ ϳ ϰ͕ϲϲϳ͛ Η,ZΗyWE>ŝŶĞƌdŽƉWĂĐŬĞƌ ϰ͘ϴϬϬ͟ ϴ ϰ͕ϲϴϯ͛ Η'Η&ůĞǆͲ>ŽĐŬ>ŝŶĞƌ,ĂŶŐĞƌ ϰ͘ϳϵϬ͟ ϵ ϰ͕ϳϴϬ ϱ͘ϱΗϭϳηϵƌ&ͬD//ǆWΗyEΗEŝƉƉůĞ;ϰ͘ϰϱϱŶŽͲŐŽͿ ϰ͘ϱϲϮ͟ ϭϬ ϰ͘ϳϴϵ͛ ƵůůĞƚ^ĞĂů>ŽĐĂƚŝŶŐĂƐƐĞŵďůǇʹ ƚŵΛϰ͕ϴϬϮ͛ϰ͘ϳϵϬ͟ ϭϭ ϰ͕ϳϵϰ͛ KdŝĞĂĐŬ^ůĞĞǀĞ ϭϮ ϰ͕ϴϬϱ͛ KyW>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϯ ϰ͕ϴϮϴ͛ KKϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛ďŽǀĞ,ĂŶŐĞƌ ϭϰ ϰ͕ϴϯϱ͛ KϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛/ŶƐŝĚĞ,ĂŶŐĞƌ ϭϱ ϰ͕ϴϯϱ͛ K,ŽŽŬtĂůů͕,ĂŶŐĞƌ/ŶƐŝĚĞϳͲϱͬϴ͟ĂƐŝŶŐ ϭϲ ϰ͕ϴϱϮ͛ K,ŽŽŬtĂůů͕,ĂŶŐĞƌKƵƚƐŝĚĞ;,ŽŽŬWŽŝŶƚͿ ϭϳ ϰ͕ϵϵϭ͛ K>ĂƚĞƌĂůyW>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϴ ϱ͕Ϭϯϴ͛ KKϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛ďŽǀĞ,ĂŶŐĞƌ ϭϵ ϱ͕Ϭϰϴ͛ KϰͲϭͬϮ͟,ŽŽŬ,ĂŶŐĞƌ͚>D͛/ŶƐŝĚĞ,ĂŶŐĞƌ ϮϬ ϱ͕Ϭϰϴ͛ K,ŽŽŬtĂůů͕,ĂŶŐĞƌ/ŶƐŝĚĞϳͲϱͬϴ͟tŝŶĚŽǁ Ϯϭ ϱ͕Ϭϲϱ͛ E,ŽŽŬtĂůů͕,ĂŶŐĞƌKƵƚƐŝĚĞ;,ŽŽŬWŽŝŶƚͿ ϮϮ ϱ͕Ϯϭϯ͛ EyW>ŝŶĞƌdŽƉWĂĐŬĞƌ Ϯϯ ϱ͕Ϯϯϭ͛ E>ĂƚĞƌĂůϳͲϱͬϴ͟ǆϱ͟,D>ŝŶĞƌ,ĂŶŐĞƌ 'EZ>t>>/E&K W/͗ϱϬͲϬϮϵͲϮϯϮϭϮͲϬϬͲϬϬ ƌŝůůĞĚĂŶĚŽŵƉůĞƚĞĚďǇŽǇŽŶϭϰʹϴͬϭͬϮϬϬϰ dhůĞĂŶͲŽƵƚĂŶĚ<ŝůů^ƚƌŝŶŐ/ŶƐƚĂůů͕^ZηϭʹϮͬϱͬϮϬϭϵ ^WŽŵƉůĞƚŝŽŶͬĂƐŝŶŐZĞƉĂŝƌʹ^ZηϭϲͬϰͬϮϬϭϵ >dZ>t/EKtd/> ͞K͟tŝŶĚŽǁĨͬϰ͕ϴϰϬ͛DƚŽϰ͕ϴϱϮ͛D͖ŶŐůĞΛǁŝŶĚŽǁϳϬΣ ͞K͟tŝŶĚŽǁĨͬϱ͕Ϭϱϯ͛DƚŽϱ͕Ϭϲϱ͛D͖ŶŐůĞΛǁŝŶĚŽǁϳϴΣ dZΘt>>, dƌĞĞ ϮͲϵͬϭϲ͟ʹϱD&D tĞůůŚĞĂĚ ϭϭ͟ǆϳͲΎϭͬϭϲ͟ϱD&D'ĞŶϱǁͬϮͲϳͬϴ͟&DdďŐ,Őƌ͕ϯ͟>, ŵĞŽŶdŽƉĂŶĚϮͲϳͬϴ͟hϴƌĚŽŶƚŵ͕Ϯ͘ϱ͟/tWsWƌŽĨŝůĞ KWE,K>ͬDEdd/> ϮϬΗ ŵƚǁͬϮϲϬƐǆŽĨƌĐƚŝĐƐĞƚ/ŝŶϰϮ͟,ŽůĞ ϭϬͲϯͬϰΗ ŵƚǁͬϯϵϲƐǆ^>ŝƚĞ͕ϮϱϳƐǆůĂƐƐ͞'͟ŝŶϭϯͲϭͬϮ͟,ŽůĞ ϳͲϱͬϴ͟ ŵƚǁͬϳϲϱƐǆůĂƐƐ͞'͟ŝŶϵͲϳͬϴ͟,ŽůĞ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ĂƉ ϮϬΗ ŽŶĚƵĐƚŽƌ ϮϭϱͬͲϱϯͬtĞůĚĞĚ Eͬ ^ƵƌĨĂĐĞ ϭϭϮΖ Eͬ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ ^ƵƌĨĂĐĞ ϭϲϭ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϰϱ͘ϱͬ<Ͳϱϱͬd ϵ͘ϵϱϬ ϭϲϭ͛ Ϯ͕Ϯϰϵ͛ ͘ϬϵϲϮ ϭϬͲϯͬϰ͟ ^ƵƌĨĂĐĞ ϱϱ͘ϱͬ>ͲϴϬͬdͲD ϵ͘ϵϱϬ Ϯ͕Ϯϰϵ͛ Ϯ͕ϯϳϴ͛ ͘ϬϵϲϮ ϳͲϱͬϴΗ WƌŽĚƵĐƚŝŽŶ Ϯϵ͘ϳͬ>ͲϴϬͬdͲD ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϱ͕ϳϳϱΖ ͘Ϭϰϱϵ ϱͲϭͬϮ͟ WƌŽĚ͘>ŝŶĞƌ ϭϳͬ>ͲϴϬ ͬ&ůƵƐŚ// ϰ͘ϴϵϮ ϰ͕ϳϯϱ͛ ϰ͕ϴϬϱ͛ Ϭ͘ϬϮϯϮ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ ϭϮ͘ϲͬ>ͲϴϬͬ/d ϯ͘ϵϱϴ ϰ͕ϴϯϱ͛ ϵ͕ϭϴϴ͛ Eͬ ϰͲϭͬϮ͟ >ŝŶĞƌ͞K͟ ϭϮ͘ϲͬ>ͲϴϬͬ/d ϯ͘ϵϱϴ ϰ͕ϵϵϭ͛ ϵ͕ϮϯϬ͛ Eͬ ϰͲϭͬϮ͟ >ŝŶĞƌ͞E͟ ϭϮ͘ϲͬ>ͲϴϬͬ/dͲD ϯ͘ϵϱϴ ϱ͕Ϯϭϯ͛ ϵ͕ϮϯϮ͛ Eͬ dh/E'd/> ϰͲϭͬϮ͟ dƵďŝŶŐ ϭϮ͘ϰͬ>ͲϴϬͬhϴƌĚ ϯ͘ϵϱϴ ^ƵƌĨĂĐĞ цy͕yyy͛͘ϬϭϱϮ t>>/E>/Ed/KEd/> <KWΛϰϱϬ͛D ϱϬΣнĨƌŽŵϯ͕ϮϬϬ͛ DĂǆ tĞůůďŽƌĞŶŐůĞсϳϬΣΛнϰ͕ϲϵϲ͛ WZ&KZd/KEd/> ^ĐŚƌĂĚĞƌ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ^ŝǌĞ ĂƚĞ ^ƚĂƚƵƐ E^ĂŶĚƐ цϰ͕ϰϭϰ͛ цϰ͕ϰϱϴ цϯ͕ϳϯϳ͛ цϯ͕ϳϱϰ͛ цϰϰ ϯͲϯͬϴ͟ &ƵƚƵƌĞ &ƵƚƵƌĞ цϰ͕ϰϴϱ͛ цϰ͕ϱϰϯ͛ цϯ͕ϳϲϯ͛ цϯ͕ϳϴϰ͛ цϱϴ ϯͲϯͬϴ͟ &ƵƚƵƌĞ &ƵƚƵƌĞ цϰ͕ϱϲϵ͛ цϰ͕ϲϯϳ͛ цϯ͕ϳϵϰ͛ цϯ͕ϴϭϴ͛ цϲϴ ϯͲϯͬϴ͟ &ƵƚƵƌĞ &ƵƚƵƌĞ ZĞĨ>ŽŐ͗ ϵͬϭϰͬϮϬϬϰDWd͕ 'Z͕tZϰ͕/͕ZKW DŝůŶĞWŽŝŶƚ ^ZZŝŐϭKW %23( Εϰ͘ϰϴΖ Εϰ͘ϱϰΖ Ϯ͘ϬϬΖ ϱϬϬϬη ϮͲϳͬϴΗǆϱΗsZ ϱϬϬϬη ůŝŶĚ ^͕ϭϭϱDyϳϭͬϭϲϱD;/ĨEĞĞĚĞĚͿ ϮϭͬϭϲϱD<ŝůů>ŝŶĞsĂůǀĞƐ ϮϭͬϭϲϱDŚŽŬĞ>ŝŶĞsĂůǀĞƐ ,ZDĂŶƵĂůDĂŶƵĂůDĂŶƵĂů ^ƚƌŝƉƉŝŶŐ,ĞĂĚ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS =b HE �E��m 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing ✓ Operations shutdownLi Performed: Suspend ❑ Perforate ❑ Other Stimulate❑ Alter Casing ❑ CTU FC( i-VN2 0 Plug for Redrill ❑ srforate New Pool ❑ Repair Well❑ Repair Casing ❑ Other: ESP Change -out ❑✓ 2. Operator 4. Well Class Before Work: 5. Permil to Drill Number. Name: Hilcorp Alaska LLC Development ❑✓ Stratigraphic ❑ Exploratory ❑1 Service ❑ 204-098 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23212-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025517 / ADL0025906 MILNE PT UNIT 1-17 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A MILNE POINT / SCHRADER BLUFF OIL 11. Present Well Condition Summary: Total Depth measured 9,253 feet Plugs measured N/A feet true vertical 3,723 feet Junk measured N/A feet Effective Depth measured 9,253 feet Packer measured N/A feet true vertical 3,726 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Conductor 112' 20" 112' 112' N/A N/A Intermediate 161' 10-3/4" 161' 161' 5,210psi 2,470psi Intermediate 2,088' 10-3/4" 2,249' 2,213' 3,580psi 2,090psi Intermediate 290' 10-3/4" 2,378' 2,339' 5,210psi 2,470psi Production 5,775' 7-5/8" 5,775' 3,867' 6,890psi 4,790psi Prod. Liner 135' 5-1/2" 4,802' 3,874' 7,740psi 6,390psi OA Liner 4,353' 4-1/2" 9,188' 3,730' N/A N/A OB Liner 4,239' 4-1/2" 9,230' 3,726' N/A N/A NB Liner 4,019' 4-1/2" 9,232' 3,725' N/A N/A Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feel Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 / EUE 4,633' 3,817' 4,805MD/ 3,875TVD, 4,991MD/3,933ND8 Packers and SSSV (type, measured and true vertical depth) (3) Baker ZXP LTP N/A 5.213MD/3,%8TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 1,000 1 0 Subsequent to operation: 478 302 2,438 300 1 238 14. Attachments (required Per 20 AAC 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations ❑✓ Exploratory❑ Development ❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby Certify that the foregoing IS true and correct t0 the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-205 Authorized Name: Chad Helgeson Contact Name: David Haakinson Authorized Title: Operations Manager Contact Email: dhaakinson(a)hilcorp.cor l Authorized Signature: oe Date 6/18/2019 Contact Phone: 777-8343 Form 10-404 Revised 4/2017 //1y ,.. 40 7'�- 4- -y, 7 S7 IBDMS.- JUN 2 0 2019 Submit Original Only K Aileorp Alaska. LLC Orig. KB Elev.: 593/ Orig. GL Elev.: 30.4' RKB-Hanger. 30.4' (Doyon 14) 103/d 7-5/8' Z7 F 2 . s 485 0 7 A&9 -9 110 Jl it 121 13 14 15i SCHEMATIC Milne Point Unit Well: MP 1-17 Last Completed: 6/4/2019 PTD: 204-098 TREE & WELLHEAD Tree 2 -9/16" -SM FMC Wellhead 11" x 7 -*1/16" 5M FMC Gen 5A w/ 2-7/8" FMC Tbg Hgr, 3" LH Top e on Top and 2-7/8" EU 8rd on Btm, 2.5" CIW BPV Profile OPEN HOLE/ CEMENT DETAIL P20" Cmt w/ 260 sx of Arcticset I in 42" Hole 10-3/4" Crit w/ 396 sx AS Lite, 257 sx Class "G" in 13-1/2" Hole 7-5/8" 1 Cmt w/ 765 sx Class "G" in 9-7/8" Hole CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm Cap 20" Conductor 215/A-53/Welded N/A Surface 112' N/A 10-3/4" Surface 55.5 / L-80 / BTC -M 9.950 Surface 161' .0962 10-3/4" Surface 45.5/K-55/BTC 9.950 161' 2,249' .0962 10-3/4" Surface 55.5 / L-80 / BTC -M 9.950 2,249' .2,378' .0962 7-5/8" Production 29.7 / L-80 / BTC -M 6.875 Surface 5,775' .0459 5-1/2" Prod. Liner 17/ L-80/ Flush II 4.892 4,735' 4,805' 0.0232 4-1/2" Liner "OA" 12.6 / L-80 / IBT 3.958 4,835' 9,188' N/A 4-1/2" Liner"OB" 12.6 / L-80 / IBT 3.958 4,991' 9,230' N/A 4-1/2" 1 Liner"NB" 12.6/L-80/IBT-M 3.958 5,213' 1 ,232' I N/A TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE 8RD 1 2.441 Surface 1 4,633' .0152 WELL INCLINATION DETAIL KOP @ 450' MD3,20 50'+from 0' Max Wellbore Angle = 70° @ +4,696' JEWELRY DETAIL 6-1/8" Hole- TD@ 9,225' HES'V' Float Shoe 9.188' "OA" Laeal 4-1/2" Slotted Liner 4,862' to 9.144'- Rat Hole 37' No Depth Item (All depths to Drig RKB) ID 1 136' STA 2: GLM 2-7/8 1" Pocket Orifice Valve 2 4,473' Sta 1: GLM 2-7/8 1" Pocket Dummy Valve 3 4,530' XN Nipple 2-7/8" 2.313 pack 2.205 no-go 4 4,581' Discharge Head: 513 PMP- Bolton 5 4,582' Ported Discharge Head 6 4,583' Pump: 538 PMSXD / 73FLEX47 - 7 4,600' Gas Separator: 538 GRS - 8 4,603' Upper Tandem Seal: - 9 4,610' Lower Tandem Seal: 30 4,617' 1 Motor: 562XP- 150Hp/ 2,420V/ 38A 11 4,628' Motor Gauge w/ Centralizer: Zenith- St. @ 4,633' 12 4,667' "HRD" ZXPN Liner Top Packer 4.800" 13 4,683' "DG"Flex-Lock Liner Hanger 4.790" 14 4,780 5.5" 17# 9Cr F/M II BxP "XN" Nipple (4.455 no-go) 4.562" 15 4.789' Bullet Seal Locating assembly - Bon, @4,802' 4.790" 16 4,794' OA Tie Back Sleeve 17 4,805' OA ZXP Liner Top Packer 18 4,828' OA OA 4-1/2" Hook Hanger'LEM' Above Hanger 19 4,835' OA 4-1/2" Hook Hanger'LEM' Inside Hanger 20 4,835' OA Hook Wall, Hanger Inside 7-5/8" Casing 21 4,852' OA Hook Wall, Hanger Outside (Hook Point) 22 4,991' OB Lateral ZXP Liner Top Packer 23 5,038' OB OA 4-1/2" Hook Hanger'LEW Above Hanger 24 5,048' 084-1/2" Hook Hanger'LEM' Inside Hanger 25 5,048' OB Hook Wall, Hanger Inside 7-5/8" Window 26 5,065' NO Hook Wall, Hanger Outside (Hook Point) 27 5,213' NB ZXP Liner Top Packer 28 5,231' NB Lateral 7-5/8" x 5" HMC Liner Hanger 6-1/8" Hale- TD@ 9.260' Btm Baker Float Shoe 9,230' Loom 4-1/2" Slotted Liner 5,116' to 9,190'- Rat Hole 30' LATERAL WINDOW DETAIL "OA" Window f/ 4,840' MD to 4,852' MD; Angle @ window 70° "OB" Window f/ 5,053' MD to 5,065' MD; Angle @ window 78° GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14 - 8/1/2004 6-1/8" Hole- TD@ 9,253' Btm Baker 4-1/2"'V' Float Shoe 9,232' CTU Clean-out and Kill String Install, ASR#1 - 2/5/2019 ESP Completion/ Casing Repair- ASR#16/4/2019 ��•NB' laera 4" Med Excluder Screen 6,245'to 9,190' -Lasa 4" Med Excluder Screen 6,245'to 9,190'- Rat Hole 20' ■ TD=9,253'(IVID)/TD=3,723'(TVD) Cleanout NB lateral to PBTD=9,253'(MD)/PBTD=3,723'(TVD) 8,726'CTM 9/02/2016 Revised By: TDF 6/18/2019 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 1-17 ASR 41 50-029-23212-00-00 204-098 5/30/2019 6/5/2019 Daily Operations. 5/29/2019- Wednesday No operations to report. 5/30/2019 - Thursday ND Well head. Make up the test p[lug and test to 3,OOOpsi good. Cont. with crane operations, NU 11" BOPE (speed head, mud cross, double gate, spacer, single gate, Annular) Spot well but and work floor spot in rig heaters. lay down containment. Cont, RU all pump lines and torque up BOPE, Spot in the new HPH. RU flow spool and Flow line to pits, set rack pins in derrick, RU tbg tongs. Install new fittings on Single gate and run lines to accumulator, get bottle pressures and pressure up accumulator. Function test all BOPE equipment. Cont. to work towards BOPE shell test . 5/31/2019 - Friday Crew swaps and fluid checks on equipment, Function tested BOP's, Greased Choke and Kill Manifold, Install spacer spool and flow spool. Removed and repaired stairway, handrails busted at welds during rig move and re -welded. Re -install repaired handrails. New catwalk / pipe handler installed and trouble -shoot unit tripping breaker. Electrician found breaker on tool - push trailer not large enough. Remove new pipe handler and replace with old catwalk. Start shell test on BOP's, tested low 250 and 2,500 high for 5 minutes. Witnessed by Adam Earl for AOGCC inspector. Continue BOP testing as per Sundry and testing procedure. 5.5" rams tested with 5.5" test mandrel to 250/2,500psi for high and low test 2-7/8 -5" VBR's tested with 4.5" test mandrel and 2-7/8" test mandrel for 250 low and 2,500psi high all for good test. Annular, drawdown, choke tests remaining @ 1800 hrs. Crew Change, Continue to conduct BOPE test, Lock in and back out the pipe rams, open rams to allow fluid by but not test mandrill. Good test on the low but a small bleed off on the high. Chase leak to in-between the Spacer spool and Single gate Shaffer rams. Tighten with hammer wrench. try to retest Still no test on high. had to Get high torque out and torque to 3,800FT/lbs. Re -test. Good test, cont. to conduct test. Test Finished with 2 Fail/Pass. Blow down all lines not need to pump kill to pull BPV. Pull Test Plug with well head hand. Service rig and equipment.[ Check ASR Rig Oil, Radiator Level, DEF, Transmission, Namco(drop box),Durst(pump drive), Triplex Lube tank], 300K Genset(Engine oil and radiator level), 100K Genset(Engine oil and radiator level), Rig Jet Heaters 1&2 Oil level. Inspect all Tbg Equip. Function all ESDs]. pump 74 BBLS of 8.3# source water 2BPM@ 100psi, Bleed off TBG on a Vac. Pull BPV close Blind rams open to pits through super choke to Gas buster. Pick up landing, torque up X -overs to landing int. Before open Blinds to stab into the hanger noticed that we had flow at gas buster at about 1.5-2BPM steadily increase to 4 BPM shut in at super choke and monitor well. 35 Bbl of returns back. Pressure level off at 400psi . Open tbg to outside flow back tank and bleed of pressure to Opsi and monitor. tbg start to bring fluid back again. RU to pump tbg kill. TBG pressure at 150psi. Pump 100 Bbls of 8.3# source water down the tbg @ 4 BPM @ 150psi. Tbg on a Vac. shut in to let fluid drop and monitor pressure 30 min. TBG still on a vac. open well stab into Hanger with landing joint and make up Hydrill 521 threads 5 turns. BOLDS. Unland tbg off seat @53k, broke over @ 56k, up string wt 52K. Lay down TBG Hanger RU to Bullhead 220Bb1s down the I.A. Bullhead 220 BBLs Down the I.A. of 8.3# source water 4BPM @ 115psi, CSG on a vac. Change Elevators to 4-1/2" Slip type, Start out of the hole with 4.5" #12.6 L-80 EZGO TBG 30 jnts total out of hole @ 06:00, Pumping double displacement of 4.3Bbls every 15 jnts laid down. total fluid pumped in well 400 bbls of 8.3# source water. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPI -17 ASR #1 50-029-23212-00-00 204-098 5/30/2019 6/5/2019 Daily Operations. 6/1/2019 -Saturday Crew swaps, fluid checks in equipment, pumped 40 bbls down well while performing fluid checks - well remaining static with small intermittent gas blows,. Start POOH w/ 4.5" 12.6# L-80 EZ GO tubige laving down, pumping double displacement every 15 joints plus 20 bbl slugs every 30 joints, Laid down 115 its (3450') since 0700. Swap out tong dies and back-ups to break out seal assembly, break out and lay down seal assembly, pumping 5 bbls every 20 mins. Moved out 4.5" EZ -GO tubing. Reset pipe racks, move in 3.5" tubing, swap lifting gear, tally work -string, make up BHA - BHA consisting of 5.250" tri - cone bit ( 0.48' long), 7-5/8" casing scraper (7.063 OD -1.5" ID, 2.68' long), x -over 3.5" reg box to 2-7/8" reg pin (1.250" ID - 4.250" OD, 1.50' length), X -over 2-7/8" reg box to 2-7/8" IF box ( 4.125" OD -1.875" ID, 1.98' long). Total length BHA = 6.64'. Hydraulic elevators broke a hydraulic connection and a spring for latch close. Attempt to repair elevators - replace broke elevators with slip type elevators and repair offline. Start RIH w/ bit and scraper BHA on 3.5" work -string (10.4 # w/ 2-7/8 IF connections ), Jt 50 in hole @ 1800 hrs (2000'). Crew swaps, fluid checks in equipment Service rig and equipment.[ Check ASR Rig Oil, Radiator Level, DEF, Transmission, Namco(drop box),Durst(pump drive), Triplex Lube tank, 300K Genset(Engine oil and radiator level), 100K Genset(Engine oil and radiator level), Rig Jet Heaters 1&2 Oil level. Inspect all Tbg E , pumped 40 bbls down well while performing fluid checks - well remaining static with small intermittent gas blows. RIH w/ bit and scraper BHA on 3.5" work -string (10.4 # w/ 2-7/8 IF connections ) to 4780' reciprocate from 4700'-4760' down wt. @29K up wt. @ 47K flush CSG 25 Bbls of 8.3# source water. POOH/w bit and scraper BHA on 3.5" work -string (10.4 # w/ 2-7/8 IF connections ) 13 Jnts. pumping double displacement every 15 joints. Elevator door latch repaired swap out elevators pump 20 bbls 8.3# source water during down time. Cont. POOH/w bit and scraper BHA on 3.5" work -string (10.4 # w/ 2-7/8 IF connections ) pumping double displacement every 15 joints. Break out Bit and scraper, Pick up 7-5/8" test PKR, When Functioning and Inspecting the PKR found A Stripped out allen head Bolt on drag block section of the PKR. Call Baker Completions for new 7-5/8" Test PKR Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 1-17 ASR #1 50-029-23212-00-00 204-098 5/30/2019 6/5/2019 Daily Operations. 6/2/2019-Sunday Crew swaps, fluid checks on equipment, continue stand by for test packer arrival. Test packer arrive location. Tally and pick up test packer (OD at compression rings 6.64", drifted with 1.9" drift, 15.53' total length and 11.64' to element) and 1 X- over : 2-7/8 IF Box to 3-1/2 IF pin (1.67' long - 1.900" ID), Total BHA length = 17.2' and total length to element = 11.64' . Pick up RIH on 3.5" 10.4# work-string. RIH w/ test packer assembly on 3.5" 10.4# work-string pumping 5 bbis displacement every 15 joints. Well static with small gas shows. 85 joints in hole @ 12:30 hours (850 ft/hr). perform well control drill - high LEL in cellar. Closed in well - not simulated. 2 minute and 57 seconds response time. Rotated guys for lunch and swapped out hydraulic return filter on rig. Continue RIH w/ 3.5" work string and test packer assembly to 4778'. Element on test packer @ 4,778'. Set packer with 30K down weight as per Baker packer hand request. Pump 23 bbls down backside with packer element set @ 4,778' to load backside. fluid level at 676' Pressure up to 300psi and hold for 5 mins and bleed off to purge air. Pressure back up to 1665psi as per sundry and chart test. 35 minute chart and pressure falloff was to 1628psi for a passing test. Pick up and allow test packer to equalize, lay down 1 joint. Pump 25 bbl Barra-clean pill down tubing to clean off heavy oil inside work-string and start POOH with Test packer and 3.5" 10.4 # work-string. Pumping 5 bbis every 15 joints for hole fill. C/C Service rig and equipment.[ Check ASR Rig Oil, Radiator Level, DEF, Transmission, Namco(drop box),Durst(pump drive), Triplex Lube tank, 300K Genset(Engine oil and radiator level), 100K Genset(Engine oil and radiator level), Rig Jet Heaters 1&2 Oil level. Inspect all Tbg Equip. Function all ESDs] Derick inspection. Found a broken back up head in the tbg tongs. Change out Backup head in the Tbg Tongs. POOH with Test packer and 3.5" 10.4 # work-string. Pumping 5 bbis every 15 joints for hole fill. Break out and lay Down 7-5/8" test PKR start filling the hole 5Bbls every 15 min with 8.3# source water while prep to RIH with Scab liner assembly. rotate out for lunch while C/O to 5.5" tbg handling equip. Load and tally BHA ( Bullet Tie back Seal assembly,5.5" 17# P110 FlushMax II B x H521 P,5.5" 17# 9Cr FlushMax II BxP "XN" Nipple,5.5" 17# P110 FlushMax 11 Pup joint, 2 jnts5.5" 17# L-80 FlushMax 11,5.5" H563 B x FMII P Liner Cross Over Pup Joint, "DG" Flex-Lock Liner Hanger,5.5" Coupling 17# L80 H563,"HRD" ZXPN Liner Top Packer,Hydraulic Settting tool). Start Picking up the BHA filling the hole 5Bbls every 15 min with 8.3# source water 440 BBIs total pumped today Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPI-17 ASR #1 50-029-23212-00-00 104-098 5/30/2019 6/5/2019 Daily Operations. 6/3/2019 - Monday C/C Service rig and equipment.[ Check ASR Rig Oil, Radiator Level, DEF, Transmission, Namco(drop box),Durst(pump drive), Triplex Lube tank, 300K Genset(Engine oil and radiator level), 100K Genset(Engine oil and radiator level), Rig Jet Heaters 1&2 Oil level. Inspect all Tbg Equip. Function all ESDsj Derrick inspection. Start RIH with lower seal assembly, 2 jts 5.5" 17# L-80 liner, Baker Liner Hanger / Packer assembly on 3.5", 10.4# work-string, RIH running low speed. RIH w/ total of 50 joints 3.5" 10.4 # work-string. Move in 4-3/4" drill collars and prep to P/U 4-3/4" drill collars. Start P/U and RIH w/ drill collars. O-over from 2-7/8" IF pin to 3-1/2" IF box ( 1.0' long and 2.00" ID). P/U and RIH w/ 13 4-3/4" drill collars and X-over from 3-1/2" IF pin to 3-1/2" RTS8 box and a 3-1/2" RTS8 pin to 2-7/8" IF Box. Continue to RIH with 3.5" 10.4 # work-string. Continue RIH w/ 3.5" 10.4# work-string from 2,214' to surface. P/U 20' 3.5" IF pup joint with a 3-1/2" box and 2-7/8" IF pin (1.0' long and 2.00"ID), Stop 1 joint high @ +- 4,765' Get up weight of 57K and Down weight of 38K. Continue RIH to 4,805' and seal friction fall to 36 K. Pull up to 59K and weight fall to 57K as seals exit seal bore. RIH with 38 down and see weight fall to 36 K when seals enter seal bore. Continue Down 10' and Find NO-GO @ 4,805'. Rig up chicksan and low torque valve to tubing stump. R/U Little Red. Continue R/U Little Red, pressure test lines to 5K. Prep to pump and set liner hanger. Pump 20 Bbls DSL 2.5 BPM @ 7psi, Drop 29/32" ball chase ball 2.5 BPM for 20 Bbls, slow rate down to 1 BPM taking 26 total Bbls after dropping ball to bump. pressure up to 1,650psi set PKR, Eased up to 2,700psi to Neutrilize pusher tool, then shear off ball seats at 4,650psi. Try to get MIT on the Liner top PKR but having surface problems getting primed to the Mud Pump. after trouble shooting the problem found the Kerr pressure side needed maintenance. continued to use high pressure test pump for the M IT. MIT on liner top PKR 1,650psi for 30 min test good. PU out of liner top assembly 58K, blow out pump lines and prep to POOH/w 3.5", 10.4# work-string 56 jntsfilling every 15 jnts double displacement. Lay down 13- 4.75" 47# 3.5"IF Drill Collars. Lay down 50 more jnts of 3.5", 10.4# work-string filling every 15 jnts double displacement. Brake down and lay down Liner running tool assembly found CONSIDERABLE amount of RUST and SCALE from inside work string trapped in ball seat of running setting tool indicating a " near miss" failure in setting tool operation. Pipe was rung hard on deck before running. total Bbls pumped for the day 273Bbls Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPI -17 ASR #1 50-029-23212-00-00 204-098 5/30/2019 6/5/2019 Daily Operations. 6/4/2019 -Tuesday C/C Service rig and equipment.[ Check ASR Rig Oil, Radiator Level, DEF, Transmission, Namco(drop box),Durst(pump drive), Triplex Lube tank, 300K Genset(Engine oil and radiator level), 100K Genset(Engine oil and radiator level), Rig Jet Heaters 1&2 Oil level. Inspect all Tbg Equip. Function all ESDs] Derrick inspection. SIMOPS start spotting in Centrilift equipment and sheaves with Centrilift personnel. MIRU Centrilift, hang sheaves, thread power cable, spot pumps and motors on catwalk, SIMOPS - move in tubing and Tally, load out Baker Completions equipment on Jacobs truck and send off,. Start P/U ESP Components, Service ESP motor, Continue P/U: 150hp ESP Motor, Upper and Lower Tandem Seals, Gas Separator, Flex 47 Pump, Ported Discharge Head, and Discharge head. Make motor splice and test. Installing Protectolizers, flat guards, and start RIH as making up. Pump assembly in hole @ 15:30. Start P/U 2-7/8" 6.5# L-80 EUE tubing, place XN Nipple (2.313 ID - 2- 205 no-go) 1 joint above ESP pup joint, place GLM w/ dummy Valve 1 joint above XN Nipple, and Continue RIH w/ 2-7/8 tubing clamping every collar for 10 joints then every other collar. 30 joints in hole @ 1800 hrs. (400' per hour). BEFORE test cable. Test Cable, Good Test, Crw/change, Service rig and equipment.[ Check ASR Rig Oil, Radiator Level, DEF, Transmission, Namco(drop box),Durst(pump drive), Triplex Lube tank, 300K Genset(Engine oil and radiator level), 100K Genset(Engine oil and radiator level), Rig Jet Heaters 1&2 Oil level. Inspect all Tbg Equip. Function all ESDsj, Rig Needs full service during the rig move. Continue RIH w/ 2-7/8 EUE 6.5# tubing clamping every collar for 10 joints then every other collar. Pumping single displacement every 15 jnts 8.3# source water. 63 jnts @ 2,014' Test cable test good pump 20 bbls source water 8.3#. 21:18hrs Continue RIH w/ 2-7/8 EUE 6.5# tubing clamping every collar for 10 joints then every other collar. Pumping single displacement every 15 jnts 8.3# source water. 96 jnts in @ 3,018' Test cable test good, pump 20 bbls source water 8.3#. Continue RIH w/ 2-7/8 EUE 6.5# tubing clamping every collar for 10 joints then every other collar. Pumping single displacement every 15 jnts 8.3# source water. 129 jnts in @ 4,018' Test cable test good, pump 20 bbls source water 8.3#. Continue RIH w/ 2-7/8 EUE 6.5# tubing clamping every collar for 10 joints then every other collar. Pumping single displacement every 15 jnts 8.3# source water. 145 jnts in @ 4,507' Rig Hydraulic hose broke on tool carrier had to go build hose at VMS and replace. finish in the with RIH w/ 2-7/8 EUE 6.5# tubing and ESP prep hanger to pick up. Pick up and Make up FMC TBG hanger 2 7/8" EUE threads on top and bottom 2.5" CIW BPV Profile. Make ESP Cable splice. Total Bbls Pumped for the day 284 Bbls Calm count: 82 Cross Collar,2 motor Clamps,3 seal clamps, 3 Pump Clamps Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 1-17 ASR k1 50-029-23212-00-00 204-098 5/30/2019 1 6/5/2019 Daily Operations. 6/5/2019- Wednesday P/U Hanger, Make Hanger Splice, Make up Hanger penetrator and found bad o -ring. Get new o -ring and remake penetrator and install. (4 -man crew) Attempt land hanger and found liner hanger top with ESP Centralizer, Pull up throw out 2 joints re -splice hanger splice, install penetrator and land hanger @ 0830. ESP Centralizer @ 4633'. Install Back Pressure Valve. RILDS - Test ESP Cable for Good Test. 6/6/2019 -Thursday No operations to report. 6/7/2019-friday No operations to report. 6/8/2019 -Saturday No operations to report. 6/9/2019 -Sunday No operations to report. 6/10/2019- Monday No operations to report. 6/11/2019 -Tuesday No operations to report. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-17 Permit to Drill Number: 204-098 Sundry Number: 319-205 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 471-� Daniel T. Seamount, Jr. Commissioner DATED thisZ5 day of April, 2019. RBDMS.6/ APR 2 6 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS APR 19 2019 END 1. Type of Request: Abandon ❑ Plug Perforations GJ.LV V -- ❑ Fracture Stimulate ❑ Repair Well ❑ra ons shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0 MIT -IA ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Repair Casing 0 Other: ESP Change -out ❑� 2. Operator Name: 4. Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory 13 Development 0 204-098 Stratigraphic ❑ Service El 6. API Number: 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 50-029-23212-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No r MILNE PT UNIT 1-17 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0025517 / ADL0025906 MILNE POINT/ SCHRADER BLUFF OIL r 11. PRESENT WELL CONDITION SUMMARY Total th TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): ,723' 9,253' 3,723' 995 N/A N/A engthSize MD TVD Burst Collapse ff 112' 20° 112' 112' N/AN/A 161' 10-3/4" 161' 161'S,210psi 2,470psi ,088' 10-3/4" 2,249' 2,213' 3,580psi 2,090psi Surface 129'10-3/4' 2,378' 2,339' 5,210psi 2,470psi Production 5,775 7-5/8" 5,775' 3,867' 6,890psi 4,790P si OA Liner 4.353• 4-1/2" 9,188' 3,730' N/A N/A OB Liner 4,239 4-1/2" 9,230' 3,726' N/A N/A NB Liner 4,019' 4-1/2" 9,232' 3,725' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4-1/2" 12.6# / L-80 / EZGO 4,807' Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): (3) Baker ZXP Liner Top Packers and N/A 4,805MD/ 3,875TVD, 4,991 MD/ 3.933TVD 8 5,213MD/ 3,968TVD and N/A 12. Attachments: Proposal Summary Q Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 5/9/2019 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: David Haakinson YrA Authorized Title: Operations Manager Contact Email: dhaaklnson hileor .Corn Contact Phone: 777-8343 Authorized Signature: Date: 4/18/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 205 �(/ Plug Integrity 11 BOP Test 6C.1 Mechanical Integri/tyy Test ❑ Location Clearance ❑ Other: ;e cZ.- SLS 5 . Post Initial Injection MIT Req'd? Yes ❑ No ❑ I (APR 16 2019 ,RBp�s Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /O -_ 4 / 041 APPROVED BY Approved by: THE COMMISSION Date: 2-;J oCppllfvy5,${pNE@ FQn 3 r'i �J/O fivl ,t r ?ppr.— app K I (V� I N .he date of approval. Anaohe,ent� in ni nii gra V .(- • / -f-trf 7 1 4F iy�'r i•4.1'41Zz114 U Hileom A6aka, Lb RWO— Install ESP Well: MPU 1-17 Date: 04/15/2019 me: MPU 1-17 r: 50-029-23212-00 Status: SI Oil Well [Kill String] I -Pad d Start Date: May 9th, 2019 ASR 1roval Req'd? pSecondCall Yes pproval Rec'vd:ry NIM Contact: Tom Fouts rill Number: 204-098 Engineer: David Haakinson 43 (0) (307) 660-4999 (M)all Engineer: ber: Stan Porhola 12 (0) Job Type: (907) 331-8228 (M) ESP Install Current Bottom Hole Pressure: 1,385 psi @ 3,900' TVD (SBHPS 3/2/19 16.83 ppg EMW) Maximum Expected BHP: 1,385 psi @ 3,900' TVD (No new perfs being added) MPSP: 995 psi (0.1 psi/ft gas gradient) Max Inc. (Within Work Interval): 70° @ 4,696' MD Max DLS: 7.3°/100 ft @ 2,776' MD Brief Well Summary: The Milne Point 1-17 well was drilled as a Schrader Bluff development well dual lateral with Doyon 14 in July 2004. The well was initially completed with an ESP that ran for thirteen years up to November 2017. The ESP was pulled in April 2018, but the 7-5/8" production casing failed to pressure test. A kill string of 4-1/2" tubing was ran and the well was left shut-in to order long -lead items for the casing repair. Subsequent leak -detect logs suggest a liner top packer leak @ 4,805' MD. In addition, a coiled tubing cleanout of each of the three laterals was performed in Q12019. Notes Regarding Wellbore Condition • 4-1/2" 12.6# L-80 tubing stabbed into tieback sleeve down to 4,807' MD. 6� • 7-5/8" Production casing tested to 2,000 psi down to 5,688' MD (Above Float Collar) on 7/18/2004. • Leak detect log completed on 4/4/19 indicates liner top packer leak @ 4,805' MD o Note that additional smaller leaks may exist up -hole. o Leak rate (seawater gradient) of 2 BPM @ 650 psig Objective: 1) Pull kill string 2) Confirm leak point in 7-5/8" production casing. 3) Install 5-1/2" scab liner with packer and verify casing integrity with MIT -IA 4) Run new ESP completion with 2-7/8" tubing Pre -Rig Procedure: A-sk j- 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 bbl returns tank. 4. Pressure test lines to 3,000 psi. 5. Pum 1.5x wellbore volume 111 bbls with 8.3 P ( ) ppg source -water down tubing. a. Note that there is no circulation point to the IA. U Hilcorp Alaska, Lb RWO— Install ESP Well: MPU 1-17 Date: 04/15/2019 6. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 7. RD Little Red Services and reverse out skid. 8. RU crane. Remove well -house. Set BPV. ND Tree. 9. NU 11" BOPE. Spot mud boat. 10. Rig -down the crane. Brief RWO Procedure:�A 11. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. ,. L 12. Pull BPV after confirming zero surface wellhead pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.3 ppg source -water prior to pulling BPV. Set TWC. 1A 13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. IJP 1 a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. 1� 5 b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Rig up triple stack (5-1/2" VBR) on the BOP stack. In the event that a production casing leak is found up -hole, it may be require more than the 70' planned 5-1/2" Scab liner length. e. Test VBR ram on 2-7/8", 4-3/4", and 5-1/2" test joints. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or 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 q to send an inspector to witness test. 1 / 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 W the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 15. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. 16. MU landing joint or spear and PU on the tubing hanger a. Working weights during 2018 Kill String install were: i. Pick-up: 52 k -lbs ii. Slack -off: 36 k -lbs b. Original RKB: Doyon 14 @ 30.4' R WO — Install ESP Well: MPU 1-17 F I.PAlaska,Lb Date: 04/15/2019 c. If needed, circulate pill (forward or reverse) with 8.3 ppg source -water with cleaning surfactant prior to laying down the tubing hanger. i. Note that there is no circulation point for TxIA without unseating from seal-borp. 17. Recover the tubing hanger. Wk) "'`T +4 6 r4-`- 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. 18. POOH and lay down the 4-1/2" L-80 tubing. PAY' a. Number all joints. Fb� b. Send tubing to G&I for cleaning and inspection. c. Tubing will be reused for future kill -string completions. d. Save Seal Assembly for re -dressing for future RWO. 19. MU 7-5/8" scraper BHA and TIH w/ 3-1/2" work -string to ±4,780' md. a. Reciprocate across 4,750' to 4,700' interval and circulate wellbore clean. 20. POOH and LD scraper BHA. 21. PU 7-5/8" test packer and RIH on work -string to ±4,780' MD. T. °a` C_ 71qO �t 22. Set test packer and pressure test 7-5/8" casing to 1,500 psig for 30 min. 'lylLg� a. Contingency: If pressure test fails, move up -hole as necessary to 4,000' MD until a passing a casing test is achieved. b. Previous fluid levels were found in 4,100' to 4,300' range. 23. Unseat test packer and POOH while laying down the work -string. 24. PU the +/- 70' casing tie -back completion and run in hole: T a. Baker ZXP Packer Assembly i. Set for 40,000 lbs downward setting force tIL~ b. 5.5" Crossover: VAM HT Box to H563 Pin c. Baker Flex -Lock Liner Hanger 5`wb i. Set for 1,287 psi shear setting force d. 5.5" Crossover: H563 Box to Flushmax II Pin e. 5.5" 17# Flushmax II thread Casing f. 5.5" XN Nipple g. 5.5" 17# Flushmax II thread Casing h. 5.5" Crossover: Flushmaxx II Box to H521 Pin i. 5.5" Baker Bullet Locating Seal Assembly 25. PU setting tool BHA and drill collar BHA a. PU thirteen (^'520') 4-3/4" x 2" ID drill collars b. Targeting 50 k -lbs at 4,700' in 8.3 ppg fluid in the event the packer does not set and requires setting with the dog sub. c. Up to 10 k -lbs of snubbing force maybe necessary. 26. RIH with 3-1/2" work -string pumping down IA as needed to maintain fluid level. 27. Obtain Pick -Up and slack -off weights —50' above the Tie -back sleeve @ 4,794'. 28. Space out seal assembly in 5-3/4" Seal Bore, setting down with locator. RWO — Install ESP Well: MPU 1-17 11ilrory Alaska, LV Date: 04/15/2019 29. PU and reverse circulate (or pump to formation) 30 bbls of 1% CRW (or equivalent corrosion inhibitor) source water, chased by 132 bbls of untreated source water down IA to spot corrosion inhibited fluid behind 5-1/2" liner. a. Attempt to catch fluid on IA for upcoming 7-5/8" casing pressure test. 30. Set back down in the 5-3/4" Seal Bore. 31. Set liner hanger as per Baker procedure. M &y f 32. Pressure test (IA) 7-5/8" casing to 1,500 psig for 30 minutes (charted). 33. POOH L/D 3-1/2" work -string & BHA. 34. PU new ESP and RIH on 2-7/8" 6.5# L-80 tubing. Set base of ESP assembly at 4,700' MD. a. Upper 2-7/8"x 1" Side -pocket GLM @ ± 200' MD with 7/16" DPOV b. 2-7/8" tubing c. Lower 2-7/8"x 1" Side -pocket GLM with Dummy GLV d. 3 joints of 2-7/8" tubing e. 2-7/8" XN (2.205" No -Go) Nipple f. 1 joint of 2-7/8" tubing g. Downhole gauge for discharge temperature and pressure. L Connected with a jumper from the lower sensor. Does not require a separate tech - wire. h. 73 -stage Flex 47 ESP i. Gas Separator j. 150 HP Motor k. Motor gauge I. Base of ESP centralizer @ ±4,700' MD 35. Land tubing hanger. RILDS. Note Slack -off weight on tally. Avoid PU (if possible) to prevent stretch on ESP cable/clamps. 36. Lay down landing joint. 37. Set BPV. 38. Rig down ASR. Post -Rig Procedure: 39. RD mud boat. RD BOPE house. Move to next well location. �\ �v 40. RU crane. ND BOPE. �( 41. NU existing 2-9/16" 5,000# tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. 42. Pull BPV. 43. RD crane. Move 500 bbl returns tank and rig mats to next well location. 44. Replace gauge(s) if removed. 45. Turn well over to production. RU well house and flowlines. Attachments: 1. As -built Schematic ely935, H Ifilcurp M.A., LL, 2. Proposed Schematic 3. BOP Schematic 4. Blank RWO MOC Form RWO — Install ESP Well: MPU 1-17 Date: 04/15/2019 0 carp Alaska, LLC Orig. KB Elm: 69.37 Orig. GL Elev.: 30.4' RKB-Hanger: 30.4' (Doyon 14) SO -3/4" L01-1 Line -Top Packer Leak 9 N v 1,2,3&4 5 6 7 6-1/8" Hole- TD@ 9,225' HES'V' Float Shoe 9,188' Milne Point Unit Well: MP 1-17 SCHEMATIC Last Completed: 2/5/2019 PTD: 204-098 TREE & WELLHEAD Tree 2 -9/16" -SM FMC Wellhead 11" x 7 -*1/16" SM FMC Gen 5A w/ 2-7/8" FMC Tbg Hgr, 3" LH Top12,378' e on Top and 2-7/8" EU 8rd on Btm, 2.5" CIW BPV Profile OPEN HOLE / CEMENT DETAIL 20" Cunt w/ 260 sx of Arcticset I in 42" Hale 10-3/4" 1 Cmt w/ 396 sx AS Lite, 2575x Class "G" in 13-1/2" Hole 7-5/8" 1 Cmt w/ 765 sx Class "G" in 9-7/8" Hole CASING DETAIL TUBING DETAIL 4-1/2" Tubing 12.6/L-80/EZGO 3.958 Surface 4,807' .0152 WELL INCLINATION DETAIL KOP @ 450' MD 50'+from 3,200' Max Wellbore Angle = 69' @ +4,460' JEWELRY DETAIL No Type de/Conn ID Top12,378' m Cap 4,794' nductor /Welded N/A Surface12' 34,802' N/A Seals urface 0/BTC-M 9.950 Surface1' 4,805' .0962 6 urface KL1ne, 55 / BTC WIBT3.958 9.950 161' 49' .0962 4,835.38' Surface 0 / BTC -M 9.950 2,249' 10 .0962oduction OB Lateral Z%P Liner Top Packer 11 0/BTC-M 6.875 Surface75' 5,048' .0459ner"DA" 13 5,048' 80/IBT 3.958 4,835' 88' N/A 5,213' ner"OB" 80/IBT 3.958 4,991' 9,230' N/A 4-1/2" 1 iner"NB" 12.6/L-80/IBT-M 1 3.958 15,213' 9,232' 1 N/A TUBING DETAIL 4-1/2" Tubing 12.6/L-80/EZGO 3.958 Surface 4,807' .0152 WELL INCLINATION DETAIL KOP @ 450' MD 50'+from 3,200' Max Wellbore Angle = 69' @ +4,460' JEWELRY DETAIL No Depth Item (All depths to Orig RKB) GLM DETAIL: CAMCO KBMM 2-7/8" x 1" 1 4,794' OA Tie Back Sleeve 2 4,796' Seal Body Assy. 34,802' Seals 4 4,804' Bullnose Shoe 5 4,805' OA UP Liner Top Packer 6 4,828' OA OA 4-1/2" Hook Hanger I PM' Above Hanger 7 4,835.34' OA 4-1/2" Hook Hanger'LEM' Inside Hanger 8 4,835.38' OA Hook Wall, Hanger Inside 7-5/8" Casing 9 4,852' OA Hook Wall, Hanger Outside (Hook Point) 10 4,991' OB Lateral Z%P Liner Top Packer 11 5,038' OB OA 4-1/2" Hook Hanger" "" Above Hanger 12 5,048' OB 4-1/2" Hook Hanger'LEM' Inside Hanger 13 5,048' OB Hook Wall, --------Window 14 5,065' NB Hook Wall, Hanger Outside (Hook Point) 15 5,213' NB Z%P Liner Top Packer 16 5,231' NB Lateral 7-5/8" x 5" HMC Liner Hanger -OA, Lateral 4-1/2" Slotted Liner 4,862'to 9,144'- Rat Hole 37' ^1 s 110 .11 12 6-1/8" Hole- TD@ 9,260' Btm Baker Float Shoe 9.230' 'OB' Laterzl4-1/2" Slotted Liner 5,116'to 9,: 14 15 6 6-1/8" Hole -TD@ 9,253' Btm Baker 'NEF Lateral 4" Med F.Hnrlpr 5rrppn 6 ?AC' r Rat Hole 30' 'Float Shoe 9,232' Rat Hole 20' 1 LATERAL WINDOW DETAIL "OA" Window f/ 4,840' MD to 4,852' MD; Angle @ window 70' "OB" Window f/ 5,053' MD to 5,065' MD; Angle @ window 78' GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14-8/1/2004 CTU Clean-out and Kill String Install, ASR#1 - 2/5/2019 TD= 9,253'(MD) /TD = 3,723'(TVD) Cleanout NB lateral to PBTD= 9,2531(NO)/ PBTD=3,723'(TVD) 8.726'CFM 9/02/2016 Revised By: TDF 2/28/2019 n Hilcoro Aluelre, LLC Orifi. KB Elev.: 69.3'/ Orifi. GL Elev.: 30.4' RKB—Hanger: 30.4' (Doyon 14) I 13 3 4 5 6 B 10 Liner Top 11 Parker Leak - ,1a PROPOSED Milne Point Unit Well: MP 1-17 Last Completed: 2/5/2019 PTD: 204-098 TREE & WELLHEAD Tree 2-9/16"-5M FMC Wellhead 11"x7 -*1/16"5M FMC Gen 5Aw/2-7/8"FMCTbg Hgr, 3" LH Top e on Top and 2-7/8" EU 8rd on Btm, 2.5" CIW BPV Profile OPEN HOLE / CEMENT DETAIL 20" Cmt W/ 260 sx of Arcticset I in 42" Hole 10-3/4" Cmt w/ 396 sx AS Lite, 257 sx Class "G" in 13-1/2" Hole 7-5/8" Cmt w/ 765 sx Class "G" in 9-7/8" Hole CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm I Cap 20" Conductor 215/A-53/Welded N/A Surface 112' N/A 30-3/4" Surface 55.5/L-80/BTC-M 9.950 Surface 161' .0962 10-3/4" Surface 45.5 / K-55 / BTC 9.950 161' 2,249' .0962 10-3/4" Surface 55.5 / L-80 / BTC -M 9.950 2,249' 2,378' .0962 7-5/8" Production 29.7/L-80/8TC-M 6.875 Surface 5,775' .0459 5-1/2" Prod. Liner 17 / L-80 / Flush It 4.892 24,735' 14,805' 4-1/2" Liner "OA' 12.6 / L-80 / IBT 3.958 4,835' 9,188' N/A 4-1/2" Liner "08" 12.6 / L-80 / IBT 3.958 4,991' 9,230' N/A 4-1/2" Liner"NB" 12.6/L-80/IBT-M 3.958 5,213' 9,232' N/A TUBING DETAIL 2-7/8" Tubing 6.7/L-80/EZGO 2.491 Surtace 4,700' .0152 WELL INCLINATION DETAIL KOP @ 450' MD 50°+from 3,200' Max Wellbore Angle= JEWELRY DETAIL No Depth Item (All depths to Ong RKB) ID 15 6-1/8" Hole -TD@ 9,225' 23 16 H ESV Float Shoe 9,188' 24 'CALAMI 4-1/2" Slotted Liner 4,862'to 9.144'- Rat Hole 37' X18 `1s 2p 21 6-1/8" Hole- TD@ 9,260' Btm Baker Float Shoe 9,230' ? '( ^OB' L aeeal 4-1/2" Slotted Liner 5,116' to 9,190'- Rat Hole 30' LATERAL WINDOW DETAIL "OA" Window f/ 4,840' MD to 4,852' MD; Angle @ window 70° "OB"Window f/ 5,053' MD to 5,065' MD; Angle @window 78° GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14-8/1/2004 CTU Clean-out and Kill String Install, ASR#1— 2/5/2019 7-5/9' 233K V�_ 6-1/8" Hole -TD@ 9,253' Btm Baker 4-1/2"'V' Float Shoe 9,232' "FIB' Lateral 4" Med Excluder Screen 6,245' to 9,190'- Rat Hole 20' TD=9,253'(MD)/TE) =3,723'(TVD) Cleanout NB lateral to PBTD = 9,253'(MD) / PBT) = 3,723'DW) 81726'CfM 9/02/2016 Revised By: TDF 4/15/2019 Milne Point ASR 11" BOP (Triple) 06/21/2018 Nikr..' Ala.k�, I.IA: 11" BOPE Updated 6/21/18 UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: April 18", 2019 Subject: Changes to Approved Sundry Procedure for Well MPU 1-17 Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call" engineer. AOGCC written approval of the change is required before implementing the change. HAK Step Page Date Procedure Change Prepared B Initials HAK Approved B Initials AOGCC Written Approval Received Person and Date Approval: Prepared: . .. .. ...o. oy� Date N�....�� Ijvillavl Date I"SMACI V IZLi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION FEB 2 6 2019 REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations Ll Fracture Stimulate77 Pull Tubing ✓ own LJ Performed: Suspend ❑ Perforate ❑ Other Stimulate❑ Alter Casing ❑ CTU FCO w/N2 El Plug for Redrill ❑ arforate New Pool ❑ Repair Well❑ Re-enter Susp Well ❑ Other: 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development 0 Stratigmphic❑ Exploratory ❑ Service ❑ 204-098 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23212-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025517 /ADL0025906 MILNE PT UNIT 1-17 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A MILNE POINT/ SCHRADER BLUFF OIL 11. Present Well Condition Summary: Total Depth measured 9,253 feet Plugs measured N/A feet true vertical 3,723 feet Junk measured NIA feet Effective Depth measured 9,253 feet Packer measured N/A feet true vertical 3,726 feet true vertical N/A feet Casing Length Size MP TVD Burst Collapse Conductor 112' 20" 112 112' NIA NIA Intermediate 161' 10-3/4" 161' 161' 5,210psi 2,470psi Intermediate 2,088' 10-3/4" 2,249' 2,213' 3,580psi 2,090psi Intermediate 290' 10-3/4" 2,378' 2,339' 5,210psi 2,470psi Production 5,775' 7-5/8" 5,775' 3,867' 6,890psi 4,790psi OA Liner 4,353' 4-1/2" 9,188' 3,730' N/A N/A OB Liner 4,239' 4-1/2" 9,230' 3,726' N/A�,,DI/A NB Liner 4,019' 4-1/2" 9,232' 3,725' NIA N/A Perforation depth Measured depth See Schematic feet G True Vertical depth See Schematic feet Q N 1" Tubing (size, grade, measured and true vertical depth) b'f_1-3,876' 4-1/2" 12.6# / L -80I EZGO 4,807' 4,805MD/3,875TVD, 4,991 MD/ 3,933TVD 8 Packers and SSSV (type, measured and true vertical depth) (3) Baker ZXP LTP NIA 5,213MD/ 3,968TVD N/A 12. Stimulation or cement squeeze summary: NIA Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 1,100 0 Subsequent to operation: 0 0 0 1,140 0 14. Attachments (required per 20 MC 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations ❑✓ Exploratory[] Development ❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas WDSPL LJ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 318-005 SO Authorized Name: Chad Helgeson ."MAR 0 61019 Contact Name: Stan Porhola Authorized Title: Operations Manager Contact Email: sporhola@hilcorp.cOm Authorize Sin ur Cti.-( orlwpm Date 2/28/2019 Contact Phone: 777-8412 U W- 3-717 K sora M.A. LI.0 Orig. KB Elea.: 69.3/ Orig. GL Elev.: 30.4' RKB-Hanger: 3" (Doyon 14) 103/4" C'11� f/ 0Y 644.& f a 61:75 1,23&4 5 6 7 a 6-1/8" Hole- Milne Point Unit Well: MP 1-17 SCHEMATIC Last Completed: 2/5/2019 PTD: 204-098 TREE & WELLHEAD Tree 2A/16' -SM FMC Wellhead 11"x7-•1/16'SM FMC Gen SA w/2-7/8'FMC Tbg Hgr, 3' LH Top on Top and 2-7/8' EU 8rd on Btm, 2.5' CIW BPV Profile OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 42" Hole 103/4' Cmtw/396 sx AS Lite, 257 sxclass"G'in 13-1/2'Hole 7-5/8' Cmtw/ 765 sx Class 'G' in 9-7/8" Hole CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm Cap 20" Conductor 215/A-53/Welded N/A Surface 112' N/A 10-3/4" Surface 45.5/L-W/BTC-M 9.950 Surface 161' .0962 10-3/4' Surface 45-S / K-55 / BTC -M 9.950 161' 2,249' .0962 10-3/4" Surface 45.5/L-80/BTC-M 9.950 2,249' 2,378' .0962 7-5/8" Production 29.7/L-SO/BTC-M 6.875 Surface 5,775' .0459 4-1/2" Uner'OA" 12.6/L-80/187 3.958 4,835' 9,188' N/A 4-1/2' Uner "Or 12.6/L-80/IBT 3.958 4,991' 9,230' N/A 4-1/2" Uner'NB' 12.6/L-80/IBT-M 3.958 5,213' 9,232' N/A TUBING DETAIL 4-117 I Tubing 12.6/L-80/FIGO 1 3.958 1 Surface 1 4,807' .0152 WELL INCLINATION DETAIL KOP @ 450' MD 50'+from 3,200' Max Wellbore Angle = 69' @ 44,460' JEWELRY DETAIL No Depth Item (All depths to Orig RKB) GLM DETAIL: CAMCO KBMM 2-7/8" x 1" 1 4,794' OA Tie Back Sleeve 2 4,796' Seal Body Assy. 3 4,802' Seals 4 4,8W' Bullnose Since -Btm@4,807' 5 4,805' OA ZXP Liner Top Packer 6 4,828' OA OA 4-1/2" Hook Hanger'LEM'Above Hanger 7 4,835.34' OA 4-1/2' Hook Hanger YEM' Inside Hanger 8 4,835.38' OAHook Wall, Hanger Inside 7-5/8' Casing 9 4,852' OAHook Wall, Hanger Outside (Hook Point) 10 4,991' 1 OB Lateral ZXP Liner Top Packer 11 S,038' 080A 4-1/2'Hook Ha er'LEM'Above Hanger 12 5,048' 084-1/2' Hook Hanger'LEM'Inside Hanger 13 5,048' OB Hook Wall, Hanger Inside 7-5/8" Window 14 5,065' NB Hods Wall, Hanger Outside (Hook Point) 15 5,213' NB ZXP Uner Top Packer 16 5,231' NB Lateral 7-5/8' x 5' HMC Uner Hanger HES'V' Float Shce 9.198' -O'1-Lalee1 4-1/2" Slotted Uner 4,862'to 9,144'- Rat Hole 37' c, 1to 41 " 6-1/8" Hole -TD@ 9,260' Btm Baker Float Shoe 9,230' -0g-Laara4-1/2" Slotted Liner 5,116' to 9,190'- Rat Hole 30' 7-S/r tM 6-1/8" Hole- TD@ 9,253' Btm Baker 58A \ 1w�g 4" Med Excluder een 97 �4t Float Shoe 9,232' Rat Hole 20' LATERAL WINDOW DETAIL 'OA"Window f/4,840' MDto4,852'MD; An le@window 70' 'OB'Window f/5,053'MDto 5,065'MD; Angle P window 78' GENERAL WELL INFO API: 50-029-23212-00-00 Drilled and Completed by Doyon 14-8/1/2004 CTU Cleanout and Kill String Install, ASR#1-2/5/2019 TD=9,253'(W)/To=3,723'(IW) 8,726'CTM 9/02/2016 Revised By: TDF 2/28/2019 PBTD =9,253' (MD) / PBTD= 3,723TIVD) Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date MP 1-17 ASR #1 50-029-23212-00-00 204-098 4/9/18 2/5/19 Daily Operations: 4/4/2018 - Wednesday No activity to report. 4/5/2018 -Thursday No activity to report. 4/6/2018 - Friday No activity to report. 4/7/2018-Saturday No activity to report. 4/8/2018-Sunday No activity to report. 4/9/2018 - Monday T/1/0=1200/1200/140 Well Kill (ASR RWO) Bleed WHPs to tank. Bullhead 30 bbls seawater down tbg. Bullhead 30 bbls Seawater/1 drum Baraklean & 200 bbls seawater down IA. FWHPs=vac/vac/350. 4/10/2018-Tuesday R/D well kill circulation skid and lines. Verify no pressure on well. 200psi on IA. Bleed down to Opsi via flow back tank (all gas). N/D tree, inspect TBG hanger lifting threads, M/U blanking plug, and function LDS. N/U BOPE on well 1-17. Spot mud boat into position followed by the well house. Spot catwalk into position to ensure rig floor will be properly aligned for well work. Remove catwalk to allow R/U to continue. SIMOPS: Begin R/D on well J-09A, removing pipe racks connex buildings, and any loose equipment not needed for the remainder of well J-09A. Continue to R/D on J-09A and R/U on 1-17. Set rig floor in place, spot TP trailer into position to R/U accumulator. N/D BOPE on well J-09A and N/U production tree. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number I Start Date End Date MPI -17 ASR 41 50-029-23212-00-00 204-098 4/9/18 2/5/19 Daily Operations: 4/11/2018- Wednesday Continue to N/U production tree on J -09A and R/U on 1-17. Back rig carrier into position on mudboat, spot rig pit trailer into position beside rig carrier, spot jet heaters along side of well house, set up rig side staircase. SIMOPS: Spot spare well house on L -Pad in prep for the next well. Continue to R/U on well 1-17. Raise mast, pull out hydraulic lines and level rig, set catwalk into position, L/D containment for pipe racks, begin to R/U Certek unit. Haul dog house and tool pushes trailer from J -pad and spot in position on I -pad. Run power from pit trailer to company man trailer. Continue to R/U fluid lines/ glycol lines/hydraulic lines. Take on ambient temp water for testing BOPE. Hang ESP sheave. Fill stack and purge of air. Perform shell test on stack (good test). Wait for AOGCC rep to arrive on location. 4/12/2018 -Thursday Crew change, service rig. Crews prep for AOGCC inspector, roll fluids throughout pits and test all level indicators/alarm sensors. Function rams and ensure all air is out of the system. Test BOPE as per Sundry and IWS procedure. Test BOPE to 250psi low f/ 5 charted mins, 2,500psi high f/5 charted mins. AOGCC rep Guy Cook on location to witness testing. Had 3-F/P on valves K-3, K-4 K-6, rebuilt K-6 & retested good, replaced valves K-3 & 4, retested good,. Blow down lines, r/d test eq. After opening pipe rams noticed pumps cycling, troubleshoot accumulator & BOPE stack, diagnosed that there was a leak coming from pipe ram BOPE in open position. Spoke with Weatherford rep of findings, & arranged for parts & mechanic to be mobed out in AM, open doors & pull rams prepping for repair work. cont. re -racking pipe on location, perform maint. work & inventory. 4/13/2018 - Friday Continue to prep for Weatherford BOPE mechanic. Spot 6" flow line piping on rig carrier. Attach all accessories and mark out the spacing on flow line supports in prep to be adjusted by welders. Continue to perform rig maintenance. Weatherford BOPE rep on location to swap out sealing elements on ram body actuating pistons. Crews continue to perform maintenance on rig. Swap out piston seals on the choke side and function rams. Hydraulic leak decreased but was still present. Decision made to swap out seals on kill side ram body. Swap out seals and function rams. Good Test. Bleed down system, re -install 2- 7/8" x 5" variable rams, close doors, pressure system, M/U T1s, flood stack, shell test t/250 /2,500 had leak on door, retighten, re -test good, test pipe rams 250/2,500, w/4-1/2" & 2-7/8" Us good. I/d test jts, blow down lines, m/u 1t & pull blanking sub, pull BPV, Pump 2 tubing volumes @ 2.2 BPM, 45 psi. B/o L/D pins, pull hanger t/ floor, hanger came free @ 38k, leveled out @ 37k, pump 10 bbls down annulus, I/d hanger, walk through bare pipe shut in drill. POOH I/d 2-7/8" tubing t/ 1,496'. 4/14/2018 -Saturday Continue to POOH f/ 1,400'md to ESP pump @-50'md. TBG pulled wet after the last GLM. L/D ESP pump and swap over pipe handling equipment from 2-7/8" to 3-1/2". P/U and M/U Baker polished mill BHA, verify all ID's, OD's and lengths prior to RIH. RIH w/ Polished mill BHA on 3.5" work string down to jnt 118 (-4700'md) PUW = 44KIbs, SOW = 28klbs. Continue to RIH down to 4,806'md and stack out 5klbs on No -Go. Pick up and verify tag depth once more. (4,806'md) P/U 15' and M/U to power swivel. ROT DWN WT = 35klbs @ 25RPM. Work down to no-go at 4,806'md, set down 2klbs and allow mill to polish tieback. Work pipe in 15' strokes to cover the entire tieback. Shut down swivel, break out connection, L/D joint, pump 10bbls down IA, POOH. Cont. POOH, I/d 3 1/2" wk string, L/D polish mill BHA. C/O handling eq. t/4-1/2", load pipe rack & tall 4-1/2" 12.6# L-80, EZGO tubing. P/U seal assy. & make up, RIH u 4-1/2" 12.6# L-80 EZGO tubing t/1,292. P�" Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig I AN Number Well Permit Number Start Date End Date MP 1-17 ASR #1 1 50-029-23212-00-00 204-098 4/9/18 2/5/19 Daily Operations: 4/15/2018 -Sunday Continue to RIH w/ Baker seal assembly on 4.5" 12.6ppf L-80 Ez-Go TBG f/ 1,292'md to 4,787'md. PUW = 52kibs, SOW = 36klbs. Ease down 13' into joint 146 (4,799'md ORKB) and see weight drop by 6klbs to 30klbs, before giving 2-3klbs weight back on the weight indicator. Continue into the hole 8' and to 4,807'md (21' in on jnt 146). Stack 10klbs with no movement. No-go. SIMOPS: perform well kill on MPU L-11. Pump 580bbls down TBG taking returns out IA. R/U to fill IA and test to 1,750psi f/ 30 charted mins, as per Sundry. Watch down hole until fluid level reaches BOP stack. Close VBR's and test IA. Walk pumps up slowly to 2BPM w/ 50psi, fluid continuing to pump away. Squat down on seal assembly gradually until 30klbs stacked on tieback. No change in fluid loss rate/pressure. P/U and pull seal assembly out of tieback. 68klbs needed to pull tieback loose, weight leveled off at 58klbs while pulling out of tieback, Once 8' above No-go, hook load dropped to 52klbs, indicating seal assembly had pulled out of tieback. Contact Ops Engineer for plan forward. L/D jnts 146, 145 and 144. Replace jnts 144 and 145 w/ shorter joints. Wellhead reps on location. M/U hanger. Landing joint too long w/ pups below hanger to M/U to hanger. Locate x -over for 2-7/8" TBG, change out handling equipment to 2-7/8". M/U x -over and joint of 2 7/8" TBG and RIH w/ TBG hanger. Land TBG hanger and RILDS. Close blinds and line up to circulate down TBG. Pump @ 4.1BPM, caught pressure after 17bbls w/ pressure rising up to 644psi after 35bbls away. Pressure quickly dropped off after that, working down to 120psi @ 4.113PM. IA on a blow when pumping down TBG, Blow seemed to diminish as more fluid was pumped (gauge broke on IA so wasn't able to record pressure). Shut down and swap over to pump down IA. Pump down IA @ 4.1BPM w/ 940psi, pressure quickly began to fall off down to 300psi and held there. No signs of pressure on the TBG while pumping down IA. Shut down pumps and set BPV. R/D and M/0. Cont. r/d & start mobbing eq. t/L-pad, Unhook lines, suck out & prep pits, roll up accumulator lines, r/d pipe rack, prep & I/d derrick 4/16/2018 - Monday No activity to report. 4/17/2018 -Tuesday No activity to report. Cf • 7 JV\ 5 c Asa. tgS/D f,0 Hilcorp Alaska, LLC Weekly Operations Summary Hil�rorp Alaska. LLC Well Name Rig API Number Well Permit Number Start Date End Date MPI -17 CTU #6 50-029-23212-00-00 1 204-098 4/9/2018 1 2/5/2019 Daily Operations: 1/30/19 - Wednesday SLB CTU crew on location. Start up equipment and warm up. M/U BHA #1: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 2.13" Rupture sub, 2.13" Tempress screen sub, 2.13" Tempress Hydropull, 2" xo, 2.2" SJN. Fluid pack and pressure test CT and PCE. Low/ Hi 247/4000 psi. Open well. WHP 870/1245/136. RIH w/ BHA #1. R/U HES N2 and hardline. P/T to 250 psi low and 4,500 psi high. Bleed tubing pressure from 870 psi to 200 psi. Begin pumping N2 at 500 scf/min and 1% slk KCL at 1.4 BPM. Equivalent rate is 2.15 BPM. Begin cleaning out from 4,800' to end of NB lateral at 1.4 BPM and 700 scf/min at 2400 psi circulation pressure and 200-300 psi tubing pressure. Cleanout to 9,195'. Send 15 bbl gel sweep and POH while chasing sweep to surface. Cut N2 at 2,500'. POH and FP coil , tree, and well from 500' with 60/40 McOH. At surface. Secure well. SDFN. 1/31/19 - Thursday CTU #6: SLB CTU crew on location. Start up equipment and warm up. Wait on Baker due to rig move. M/U BHA #1: 2.0" CTC, 2.13" DBPV, 2.13" Jar, 2.13" TJ Hydraulic Disconnect, 2" xo, 3.5" GS Spear. (DAL = 11.43'). Fluid pack and pressure test CT and PCE. Low/ Hi 247/4000 psi. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =150/1217/104. RIH w/ BHA #1 to latch isolation sleeve in OA lateral. P/U weight at 4,700' is 11k -lbs. Tag OA isolation sleeve at 4830' . P/U and see 5k overpull before isolation sleeve comes free. Tubing pressure went from 185 psi to 160 psi. POH to surface with OA isolation sleeve. At surface. Close swab valve. Break and stand back injector. Break and L/D OA isolation sleeve. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =120/1217/104. RIH w/ 2.0" CTC, 2.13" DBPV, 2.13" Jar, 2.13" TJ Hydraulic Disconnect, 2" xo, 3.5" GS Spear. (DAL= 11.43'). P/U weight at 4,700' is 8k -lbs. Tag OB isolation sleeve at 5049'. Flag pipe (EDP is 5036'). P/U and see 35k overpull before isolation sleeve comes free. Tubing pressure stayed constant. POH to surface with OB isolation sleeve. At surface. FP well with 60/40 McOH to 2,500'. Close swab valve. Break and stand back injector. Break and L/D OB isolation sleeve. M/U BHA for tomorrow's IBP run. SDFN. 2/1/19 - Friday SLB CTU crew on location. Start up equipment and warm up. M/U BHA #1: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 2.10" xo, 2.13" Inflate Valve, 2.13; Screen sub, 2.13" Hydraulic running tool, 3" IBP. (OAL = 20.27'). Fluid pack and pressure test CT and PCE. Low/ Hi 247/4000 psi. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =135/1217/104. RIH w/ BHA #1 to set IBP. P/U at 4,700' is 11,800 -lbs. At flag correct depth to 5,052'. RIH and tag at 5,076'. Bring on pumps and pump 1 BPM down coil x tubing annulus. RIH to 5320'. P/U 11,800'. Pump fluid from upright to flowback tank directly until 90 degree fluid is seen at the micro motion. Pump 8 bbls of 90 degree 1% KCL. Drop 1/2" ball. Pump 6 alas of 90 degree 1% KCL. Ball on seat after pumping 35 bbls. Wait 2.5 hours for temperature to equalize prior to inflation. Begin inflating IBP. Increase coil pressure to 800 psi. Wait 10 minutes. Increase pressure to 1,300 psi. Wait 10 minutes. Set down 3k -lbs on IBP. Increase pressure 1,800 psi. Wait 10 minutes. Increase pressure to 2,300 psi. Shears at 2,100 psi. Set 6k-Ibs on IBP. IBP is set. POH to surface. At surface. Close swab valve. Break and stand back injector. Break and L/D BHA #1. M/U BHA #2: 2.0" CFC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 3.11" xo, 2.95" xo, 2.88" Hipp Tripper, 3.12" xo, 3.5" GS spear, 3.66" Diverter. (DAL = 29.59') Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =110/1225/97. RIH w/ BHA #1 to set diverter in OB lateral. P/U weight at 4,700' is 7k -lbs. Tag OB LEM and hammer down with Hipp Tripper at 5,069' . Diverter set. Pump off Diverter. POH to surface. At surface. Close swab valve. Break and stand back injector. M/U OA isolation sleeve. Move injector to well and makeup to BOP. P/T connection to 250 low/3500 high. Open wel I. T/I/O =104/1222/95. RIH w/ BHA #3: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 3.11" xo, 2.95' xo, 2.88" Hipp Tripper, 3.12" xo, 3.5" GS spear, 3.66" Isolation Sleeve. (DAL = 29.87'). P/U weight at 4,700' is 8k -lbs. Tag OA LEM at 4,852'. Set isolation sleeve with Hipp Tripper. POH to surface with OB isolation sleeve. At surface. Close swab valve. Break and stand back injector. Break and L/D GS Spear BHA. M/U BHA (nozzle) for tomorrow's clearout run. f,0 nHilcorp Alaska, LLC Hikwrp Alanka, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPI-17 CTU #6 50-029-23212-00-00 204-098 4/9/2018 1 2/5/2019 2/2/19-Saturday CTU #6 w/ 14,814' of 2" coil. SLB CTU crew on location. Start up equipment and warm up. M/U BHA #1: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 2" xo, 2 x 2" weight bars, 2.2" SJN. (OAL is 11.3'). Fluid pack and pressure test CT and PCE. Low/ Hi 247/4000 psi. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =90/1229/100. RIH w/ BHA #1 attempt to tag IBP and verify it is in NB lateral. P/U weight at 4,700' is 7k-lbs. RIH in OB lateral to 5,320' to see if IBP is set in OB lateral. Unable to pass through diverter at 5,048'. Attempt to pump down backside and still unable to pass through diverter. POH to surface. At surface. Close swab valve. Break and stand back injector. M/U 2 additional weight bars in order to lengthen BHA to attempt to enter diverter. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =104/1222/95. RIH BHA #2: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 2" xo, 2 x 2" weight bars, 2 x 1.75" weight bars, 2." SJN. (OAL is 19.3'). Drift to 5,400'. No IBP. POH to 5,100'. R/U N2 and cool down. Begin circulating N2 at 700 scf/min and 120 degree 1% KCL at 1.5 BPM. Cleanout from 5,100' to 9,079' (tag hard) while circulating N2 at 700 scf/min and 120 degree 1% KCL at 1.5 BPM. Send gel sweeps as necessary. Circulate BU volume and 15 bbl gel sweep. POH while chasing gel sweep to surface. Cut N2 at 500'. Switch to 60/40 McOH at 200'. FP coil and 500' from surface and tree. At surface. Stand back injector. Break and L/D BHA,C/O Packoffs. SDFN. f1l._,=day SLB CTU crew on location. Start up equipment and warm up. Wait on Baker due to Rig move. M/U BHA #1: 2.0" CTC, 2.13" DBPV, 2.13" Jar, 2.13" TJ Hydraulic Disconnect, 2" xo, 3.5" GS Spear. (DAL = 11.43'). Fluid pack and pressure test CT. Low/ Hi 247/4000 psi. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =83/1206/130. RIH w/ BHA #1 to latch isolation sleeve in DA lateral. P/U weight at 4,700' is 12k-lbs. Tag OA isolation sleeve at 4,818'. P/U and see 5k overpull before isolation sleeve comes free. POH to surface with OA isolation sleeve. At surface. Close swab valve. Break and stand back injector. Break and L/D OA isolation sleeve. Freeze protect well to 2,500'. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =120/1217/104. RIH w/ 2.0" CTC, 2.13" DBPV, 2.13" Jar, 2.13" TJ Hydraulic Disconnect, 2" xo, 3.5" GS Spear. (DAL = 11.43'). P/U weight at 4,700' is 8k-lbs. Tag OB diverter at 5049'. P/U and see 6k overpull before diverter comes free. POH to surface with OB diverter. At surface. Close swab valve. Break and stand back injector. Break and L/D OB diverter. M/U BHA #3: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 3.11" xo, 2.95" xo, 2.88" Hipp Tripper, 3.12" xo, 3.5" GS spear, 3.66" isolation sleeve. (DAL = 29.87'). Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =45/1225/97. RIH w/ BHA #1 to set isolation sleeve in OB lateral. P/U weight at 4,700' is 9k-lbs. Tag OB LEM and hammer down with Hipp Tripper at 5,069'. Isolation sleeve set. Pump off sleeve. POH to surface. At surface. Close swab valve. Break and stand back injector. M/U OA diverter. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =40/1222/95. RIH w/ BHA #3: 2.0" CTC, 2.13" DBPV, 2.13" TJ Hydraulic Disconnect, 3.11" xo, 2.95" xo, 3.5" GS spear, 3.66" Diverter. (OAL = 29.59'). P/U weight at 4,700' is 8k-lbs. Tag OA LEM at 4,853'. Set diverter at 4,853' and pump GS off at 1.5 BPM. POH to surface. At surface. Close swab valve. Break and stand back injector. Break and L/D GS Spear BHA. M/U BHA (nozzle) for tomorrow's cleanout run. SDFN. 2/4/19 - Monday SLB CTU crew on location. Start up equipment and warm up. M/U BHA #1: 2.0" CTC, 2.13" DBPV, 2.13" Tl Hydraulic Disconnect, 2" xo, 2 x 2" weight bars, 2.2" S.N. (CAL is 11.3'). Fluid pack and pressure test CT and PCE. Low/ Hi 247/4000 psi. Move injector to well and make up to BOP. P/T connection to 250 low/3500 high. Open well. T/I/O =30/1209/110. RIH w/ BHA #1 attempt to tag IBP and verify it is in NB lateral. P/U weight at 4,700' is 7k-lbs. RIH in OA lateral to 4,902' to ensure nozzle will pass into lateral. No issues getting into lateral. R/U N2 and cool down. P/T N2 lines to 500 psi low and 4,500 psi high. Begin circulating N2 at 700 scf/min and 120 degree 1% KCL at 1.5 BPM. RIH to 5,100'. POH to 4,900'. Keep coil moving while waiting for N2 at surface. See N, Cleanout from 5,100' to 9,045' (hard tag) while pumping 1.5 BPM of 1% KCL and 700 scf/min of N2. Send frequent gel sweeps. Returns range from 85%-125%. POH while chasing returns to surface. Cut N2 at 500'. FP with 60/40 McOH to 2,500' by pumping down the backside. FP coil while POH from 500'. At surface. Stand back injector. Break and L/D BHA. SDFN. 2/5/19 - Tuesday CT crew on site. PJSM. Check equipment. Start BOP test at 0800. Full BOP test to 300 psi / 4800 psi. End BOP test at 1130 with no failures. Record test on form 10-424,MU BHA - 2" OD CTC, 2.13" OD DBPV, Jars, TJ disconnect(5/8" ball), 3.11" OD X0, 3.50' OD 4" GS spear - OAL = 11.43' with diverter will be 30.36'. Stab on well. PT to 300 psi / 4000 psi. RIH with 4" GS. Latch and pull diverter from OA LEM at 4,828' md. POOH. L/D Recovered diverter. Back on well with same BHA - 4" GS. PT to 300/2500 psi. RBIH and pull isolation sleeve from OB LEM at 5,048' md. POOH. L/D recovered isolation sleeve. L/D GS and MU hydraulic overshot with 1.375" grapple,Stab back on well. PT to 300/2500 psi RIH with overshot. Set down at 5,320' ctmd equalize IBP. PU with 12k overpull and IBP released. Wait 20 minutes for IBP element to relax. POOH. At surface. IBP recovered with no missing elements. L/D all tools. RDMO. Job Complete. M - 7 PThimago Regg, James B (DOA) From: Harold Soule - (C) <hsoule@hilcorp.com> Sent: Friday, April 13, 2018 11:28 PM To: Cook, Guy D (DOA) Feet � 411 ' Cc: Regg,James B (DOA); Cody Rymut - (C) Subject: RE: ASR BOPE Attachments: 4-13-18 pipe ram test I-17.pdf '" a,04.-012, Hello 141,1-C Tp Repairs have been completed, function tested good, re-tested pipe rams good, preformed accumulator draw down test. Pressure 3000 Draw down pressure 1500 200 psi time 15 sec. - Full pressure 64 sec. CiN Harold From: Cook, Guy D (DOA) [mailto:guy.cook@alaska.gov] Sent: Friday, April 13, 2018 3:57 PM To: Harold Soule - (C) Cc: Regg, James B (DOA) Subject: Re: ASR BOPE Harold, Your plan forward sounds fine, but you will need to test the ram in question as well to ensure it is operating correctly. Please send test results and pics of the test recorder chart when you are done. Thank you, Guy Cook AOGCC Sent from my iPhone On Apr 13, 2018, at 6:21 AM, Harold Soule- (C)<hsoule@hilcorp.com>wrote: Hello Guy After you left we were rigging down test equipment, after opening the pipe rams the accumulator pumps started cycling. After investigating &troubleshooting we have concluded we have a bad seal either in the door hinge or on the ram plunger. We have not pulled the BPV at this point and the well is still secure. We have a mechanic& parts coming from Kenai this morning for repair.After repair we plan to function & shell test as well as preform a new accumulator test prior to moving forward. Please advise if this will suffice. Harold Soule 1 //// ////, / . :.7._„/...........,,, 1:/ ,..\\: ,''oiN >.-.1.11, jo -- S ' ----- ----- 40001 -----.. --------....._ .-----. ,, ,.. -----„,...----- .___----- ..„.,--- _.,..-------__.,......---, ___,3500 - j_... / / ,.,'" ,-- „---- -----3°a°. „,,„ — \\\ /---„,,,----„,„`N„, ''N. ' \ '. 17-;- . 1 // /1 /// `-,, '.-- ..------1_,_-- - ----- — ---.. -------- , 'N.,'-- \'s \ , \ / - - '00 7---------- -- >----- ” / ---- 4.D I a wee / ' 1 / ,g / / / x \ \ \ ' \ \\\ , \ i N a -.4 , // / \ \ \ \ / a ' 8 I ( ,Ur. Comk 1 Wi /6 '\ \-L 0 77- ' i'-' c? i CHART NO. MC MP-500 -1HR METER ---i-- .I,. ,•,' '. 1. ,', i '' I \ \ \ m iou —,0_ , ni , i ._:-,';•if:: .:.:!' j -,. • ' CMAR i P.I'T f, 14)16 AA'4t i 1 1 'j' ' ''''' i , / \ >K. ..>, , --- \ , - - \ \\ ,04).\\\°°.0, . irionso 0 alliga .„.„.„-- , , / ,• , -..,,....- 2., ' \ 0 --.. 0 .. 0- . .4\ N. ,-, __ • -..... __----:,-\ \ ,. \ „.„,. ,.., -._ --- ,... _ _., co, .,..- ..., 0 .,, ,,,, ,„, .,,,,, -."..4'--- -..„, . - :2= ._ -, -,--___, ---,-,-4 -- --- x' ,' • ----,, .,_„.„ ,,____.— i• o, \ 4\ , NN `-- -../ --- = A g-1 t=-- ' • . • NN '^ ' '")4- ----— — -_-- -..'.'-----'""1:..":--- ' \ ,,/ , . -__ -- ' ,...`, ,:',,,,,,>•„,,,,._.:_,-.---___. ---------____________ - -7:_-_,:777::, -----_____ ..-----1,,,, ', -"1,, ''• '''' -' .7 ' .-. - ----------:--- - - ir•Oi"----------___--'-' ,,----.' ,,,' . ',.,,,,,,,, '-"---,_ --------_, ---------__. = --- -_--------- — .------.' -_, „- •94" ''-- ------_, ----- - ----- --- -------- oosr-- ----- ,,,-- -- . - ._: 02 , I I , , 1 1 I , •y OF 7•4,w1" ► /// THE STATE Alaska Oil and Gas e��\\I/ice � =a 47,0 o f® LAS�<:A Conservation Commission 1Z 333 West Seventh Avenue r, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 *h_ O Q. • Main: 907.279.1433 ALA6� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager JAN 1 9 2018 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-17 Permit to Drill Number: 204-098 Sundry Number: 318-005 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, Hollis S. French .�L Chair DATED this (d day of January, 2018. RBDMS &'- J;'', 1 1 1 2",;18 RECEIVED • • STATE OF ALASKA JAN 0 3 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION J:1115 l v ( (el APPLICATION FOR SUNDRY APPROVALS OGGC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑✓ . CTU FCO w/N2 Q Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Change-out Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC ' Exploratory ❑ Development ❑✓ . 204-098 3.Address: 3800 Centerpoint Dr,Suite 14000 6.API Number: Stratigraphic ❑ Service Anchorage Alaska 99503 50-029-23212-00-00 , 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 t Will planned perforations require a spacing exception? Yes ❑ No LI / MILNE PT UNIT I-17 ' 9.Property Designation(Lease 10.Field/Pool(s): Y 9 Number): ADL0025517/ADL0025906 . MILNE POINT/SCHRADER BLUFF OIL ' 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): 9,253', 3,723', 9,253' # 3,723'. 937 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 112' 20" 112' 112' N/A N/A Intermediate 161' 10-3/4" 161' 161' 3,580psi 2,090psi Intermediate 2,088' 10-3/4" 2,249' 2,213' 3,580psi 2,090psi Intermediate 290' 10-3/4" 2,378' 2,339' 3,580psi 2,090psi Production 5,775' 7-5/8" 5,775' 3,867' 6,890psi 4,790psi OA Liner 4,353' 4-1/2" 9,188' 3,730' N/A N/A OB Liner 4,239' 4-1/2" 9,230' 3,726' N/A N/A NB Liner 4,019' 4-1/2" 9,232' 3,725' N/A N/A Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic i See Schematic 2-7/8" 6.5#/1-80/EUE 8rd 4,738' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): (3)Baker ZXP Liner Top Packers and N/A 4,805MD/3,875TVD,4,991 MD/3,933TVD&5,213MD/3,968TVD and N/A 12.Attachments: Proposal Summary ❑I Wellbore schematic Q 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: 1/16/2018 Commencing Operations: OIL ❑✓ . WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ 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. S rp Authorized Name: Bo York Contact Name: Stan Porhola Authorized Title: Operations Manager Contact Email: sporholaahilcorp.com Contact Phone: 777-8412 Authorized Signature: 70Date: 1/2/2018 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: AsI( 1 / 3Ii. OC/ Plug Integrity El BOP Test �i Mechanical Integrity Test ❑ Location Clearance ❑ Other: 2.5 61 p$ L AL n I s I Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No E Subsequent Form Required: /0 CD RBDMS J.",N 1 1 2.18 APPROVED BY Approved by: 6C2Qr—\ COMMISSIONNER THE COMMISSION Date: I ION I g �., f16fNtfOf Fo10-403 Reve /2017 Appro dapplication is va d pry` approval. Attachments in Duplicate r-r Is, • , n e Well Prognosis Well: MPU 1-17 Hilcorp Alaska,LLI Date: 1/02/2018 Well Name: MPU 1-17 API Number: 50-029-23212-00 Current Status: SI Oil Well [Failed ESP] Pad: I-Pad Estimated Start Date: January 16th, 2018 Rig: ASR 1/Coil Tubing Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 204-098 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) AFE Number z a Job Type: ''''''3- $P Repair/Coil CO P 1/02/2018/6.43EM W Pr sure: 1 337psi 4 000' TVD (SBHPS Bottom Hole es Current ) @ ( ppg Maximum Expected BHP: 1,337 psi @ 4,000' TVD (No new perfs being added)/ MPSP: 937 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point 1-17 well was drilled as a Schrader Bluff development well dual lateral with Doyon 14 in July 2004. The well was initially completed with an ESP (same ESP that is in the well today). The current ESP completion has failed as of November 2017 and is a known solids producer.The ESP and toIn (g will be replaced. 4J . Notes Regarding Wellbore Condition )...---- • Casing tested to 2,000 psi down to 5,688' MD (Above Float Collar) on 7/18/2004. '-...„ , • .r.. I^ H • Max angle 79.0° @ 5,065' in the 7-5/8" casing. Max angle 107.9 @ 5,722' in the laterals. • Deviation at ESP is 70.4°and dogleg of 2.00°/100 ft. • Min ID is 2.25"thru XN profile above ESP. • CO 390A: Hilcorp Alaska respectfully requests that a packer not be required on this ESP completion as the reservoir pressure is less than 8.55 ppg EMW. t„,.. LG t, deir %-.---% Objective: '��6 p� SThe purpose of this work is to pull the failed ESP, run a kill string, rig down the ASR rig, RU coil and cleanout the t� ) L� lateral, rig up the ASR rig, pull the kill string and run new tubing and a new ESP. v I,,- Boit: rc it/ // -i .>t / " c`� 3-feI .21 ai Pre-Rig Procedure: a ge‘ l 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 bbl returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 8.5 ppg seawater 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 and reverse out skid. 8. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 9. NU BOPE house. Spot mud boat. • • Well Prognosis Well: MPU 1-17 Hawn)Alaska,LLI Date:1/02/2018 Brief RWO 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/8.5 ppg seawater prior to pulling BPV. Set TWC. 12. Test BOPE to 250 psi Low/2,500 psi High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" and 4-1/2" 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/or 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. 1.(i b. With stack out of the test path, test choke manifold per standard procedure Aft' 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. 14. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.5 ppg seawater as needed. Pump cleaning pill w/heated seawater to flush tubing of residual oil. 15. MU landing joint or spear and PU on the tubing hanger. a. The PU weight during the 2004 ESP install was 82K lbs (block weight of 40k) b. If needed, circulate pill (forward or reverse) with cleaning surfactant prior to laying down the tubing hanger. 16. 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. 17. POOH and lay down the 2-7/8" tubing. Number all joints. Tubing will be junked. Lay down failed ESP. a. Junk all joints of tubing. b. Note any sand or scale inside or on the outside of the ESP on the morning report. c. Look for over-torqued connections from initial tubing run. 18. RIH with 7-5/8" 29.7#scraper assembly to—4,794' MD (top of ZXP Liner Top Packer) on 3-1/2" workstring. Circulate the well clean with 8.5 ppg seawater. • • • Well Prognosis Well: MPU 1-17 ililcorp Alaska,LL Date: 1/02/2018 19. POOH and LD 3-1/2" workstring and scraper assembly. 20. PU seal assembly and RIH on 4-1/2" tubing. 21. Tag up and space out above the ZXP Liner Top Packer at±4,794' MD. Circ inhibited packer fluid and freeze protect fluid. 22. Set seals below top of ZXP Liner Top Packer at±4,794' MD. 23. Land tubing hanger. RILDS. Note PU (Pick Up) and SO (Slack Off) weights on tally. �0 24. Pressure test annulus to 1,750 psi for 30 min and chart (test casing from surface to the ZXP packer). L� / Contingency(If casing test fails): PU 7-5/8" RTTS and RIH on 3-1/2" workstring and test casing I to 1,750 psi looking for possible leak. Notify town engineer of results to decide plan forward. 25. Lay down landing joint. 26. Set BPV. Rig down ASR. Post-Rig Procedure: 27. RD mud boat. RD BOPE house. Move to next well location. 28. RU crane. ND BOPE. 29. NU new 4-1/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 30. RD crane. Move 500 bbl returns tank and rig mats to next well location. 31. Replace gauge(s) if removed. 32. Turn well over to production. RU well house and flowlines. Coiled Tubing Procedure: 33. MIRU Coiled Tubing Unit and spot ancillary equipment. Fill source tank w/8.5 ppg 1% KCI. 34. Pressure test BOPE to 3,500 psi Hi 250 Low, 5 min Low/10 min Hi each test. a. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. 35. RIH w/2.00" coil w/2.0" to 3.25" max OD wash nozzle and extended reach cleanout BHA and cleanout to PBTD at+/-9,230' MD in the NB lateral (bottom lateral). POOH. ts'sk`? a. Circulate out fill using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen (see Nitrogen procedure and diagram). Utilize defoamer for returns in Kill Tank. b. Contingency: If unable to wash down with nozzle, RIH w/2.0"to 3.25" mill and extended reach cleanout BHA and cleanout to PBTD at+/-9,230' MD using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen. POOH. 36. RIH w/2.00" coil w/diverter sleeve and set in OA LEM rof' (Lateral Entry Module) at 4,835'. POOH. 37. RIH w/2.00" coil w/2.0"to 3.25" max OD wash nozzle and extended reach cleanout BHA and (:)/ cleanout to PBTD at+/-9,186' MD in the OA lateral (top lateral). POOH. a. Circulate out fill using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen (see Nitrogen procedure and diagram). Utilize defoamer for returns in Kill Tank. • • Well Prognosis Well: MPU 1-17 Ililcorp Alaska,LL Date: 1/02/2018 b. Contingency: If unable to wash down with nozzle, RIH w/2.0"to 3.25" mill and extended reach cleanout BHA and cleanout to PBTD at+/-9,186' MD using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen. POOH. 38. RIH w/2.00" coil w/4" GS spear retrieval tool and recover diverter sleeve set in OA LEM profile (Lateral Entry Module) at 4,835'. POOH. 39. PU to 2,500' and freeze protect well down the coil x tubing annulus. POOH w/coil. 40. RD Coiled Tubing and ancillary equipment. 41. Turn well over to production. Pre-Rig Procedure: 42. Clear and level pad area in front of well. Spot rig mats and containment. 43. RD well house and flowlines. Clear and level area around well. 44. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 45. Pressure test lines to 3,000 psi. 46. Circulate at least one wellbore volume with 8.5 ppg seawater down tubing,taking returns up casing to 500 bbl returns tank. 47. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 48. RD Little Red Services and reverse out skid. 49. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 50. NU BOPE house. Spot mud boat. Brief RWO Procedure: ; ''K 51. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 52. 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/8.5 ppg seawater prior to pulling BPV. Set TWC. 53. Test BOPE to 250 psi Low/2,500 psi High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" and 4-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 54. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or 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 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. • . H • • Well Prognosis Well: MPU 1-17 Ililcuru Alaska,LL Date:1/02/2018 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. 55. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.5 ppg seawater as needed. 56. MU landing joint or spear and PU on the tubing hanger. a. The PU weight is estimated to be 60k. 57. 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. 58. Pull seals out of ZXP packer. Circ out inhibited packer fluid and freeze protect fluid using 8.5 ppg seawater. ..21,1-:11-51(.-POOH and lay down the 4-1/2" tubing and seal assembly. ' 0)-9' 60. PU new ESP and RIH on 2-7/8" tubing. Set base of ESP at±4,600' MD. (� id° a. Upper GLM @ ± 140' MD w/SO b. Lower GLM @ ±4,350' MD w/DGLV c. 2-7/8" XN (2.205" No-Go) @ ±4,500' MD ot-k �r d. Base of ESP centralizer @ ±4,600' MD e. Run heat trace from ±3,500' MD to surface. 1.4).{ 61. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off)weights on tally. 62. Set BPV. Rig down ASR. Post-Rig Procedure: 63. RD mud boat. RD BOPE house. Move to next well location. 64. RU crane. ND BOPE. 65. NU previous 2-9/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 66. RD crane. Move 500 bbl returns tank and rig mats to next well location. 67. Replace gauge(s) if removed. 68. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Existing Tree/Wellhead 5. Temporary Tree/Wellhead 6. Blank RWO MOC Form 7. Coil BOPE Schematic • Well Prognosis Well: MPU 1-17 Ilileorp Alaska,LL Date: 1/02/2018 8. Nitrogen Operations Procedure 9. Nitrogen & Foam Flow Diagram . II . • Mime Poin MPt Unit We SCHEMATIC Last Completed:8/1/2004 Hileorp Alaska.LLC PTD: 204-098 TREE&WELLHEAD Tree 2-9/16"-5M FMC Wellhead 11"x 7-*1/16"5M FMC Gen 5A w/2-7/8"FMC Tbg Hgr,3"LH Orig.KB Elev.:69.3'/Orig.GL Elev.:30.4' me on Top and 2-7/8"EU 8rd on Btm,2.5"CIW BPV Profile RKB-Hanger:30.4'(Doyon 14) OPEN HOLE/CEMENT DETAIL a� k „:1, 20" Cmt w/260 sx of Arcticset I in 42"Hole 20'' * 1 10-3/4" Cmt w/396 sx AS Lite,257 sx Class"G"in 13-1/2"Hole 17-5/8" Cmt w/765 sx Class"G"in 9-7/8"Hole I4 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm Cap 20" Conductor 215/A-53/Welded N/A Surface 112' N/A 4 10-3/4" Surface 45.5/L-80/BTC-M 9.950 Surface 161' .0962 10-3/4" Surface 45.5/K-55/BTC-M 9.950 161' 2,249' .0962 10-3/4"".I 2 10-3/4" Surface 45.5/L-80/BTC-M 9.950 2,249' 2,378' .0962 7-5/8" Production 29.7/L-80/BTC-M 6.875 Surface 5,775' .0459 4-1/2" Liner"OA" 12.6/L-80/IBT 3.958 4,835' 9,188' N/A 4-1/2" Liner"OB" 12.6/L-80/IBT 3.958 4,991' 9,230' N/A 4-1/2" Liner"N B" 12.6/L-80/IBT-M 3.958 5,213' 9,232' N/A TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.4Surface 4,738' .0059 WELL INCLINATION DETAIL KOP @ 450'MD 50°+from 3,200' Max Wellbore Angle=69°@+4,460' 3 JEWELRY DETAIL Nin ID=2.250 No Depth Item(All depths to Orig RKB) @4,626--III.I 4 GLM DETAIL:CAMCO KBMM 2-7/8"x 1" � 6 1 146' STA 3:Dual Origice Valve,10=2.371" 2 2,022' STA 2:DV,SBK-2C Latch,ID=2.371" V. 6 3 4,470' STA 1:DV,56K-2C Latch,I0=2.371" 4 4,626' HES 2.313"XN Nipple-2.25"NoGo illi 7 5 4,669' Discharge Head:GPDIS-2-7/5"EUE 8rd irs 6 4,679' Pump:Type 122 Stage GC2200 S/N 01687871 sw ME 8sow 7 4,680' Tandem Gas Seperator:Nodel-GRSTX BAR H6 8 4,700' Seal Section:GSB#DB UT&LT H6ABHSN 9 4,719' KMH Motor:152hp/2,325V/40A-S/N 21K68181 9 10 4,733 Pump Mate&Centralizer-Btm @ 4,738' OS 11 4,794' OA Tie Back Sleeve l 10 12 4,805' OA ZXP Liner Top Packer 13 4,828' OA OA 4-1/2"Hook Hanger'LEM'Above Hanger .1j%" 11 14 4,835.34' OA 4-1/2"Hook Hanger'LEM'Inside Hanger 1 12 11c 15 4,835.38' OA Hook Wall,Hanger Inside 7-5/8"Casing at 13 16 4,852' OA Hook Wall,Hanger Outside(Hook Point) 14 17 4,991' OB Lateral ZXP Liner Top Packer • A 15 6-1/8"Hole-TD@ 9,225' HES'V'Float Shoe 9.188' 18 5,038' OB OA 4-1/2"Hook Hanger'LEM'Above Hanger 16 Ir( 1 -, r f/) 19 5,048' OB 4-1/2"Hook Hanger'LEM'Inside Hanger 33 ;: "OA'Lateral 4-1/2"Slotted Liner 4,862'to 9,144'-Rat Hole 37 20 5,048' OB Hook Wall,Hanger Inside 7-5/8"Window ,,t,,,,,.,, - 21 5,065' NB Hook Wall,Hanger Outside(Hook Point) 22 5,213' NB ZXP Liner Top Packer 17 23 5,231' NB Lateral 7-5/8"x 5"HMC Liner Hanger 18 LATERAL WINDOW DETAIL 19 6-1/8"Hole-TD@ 9,260'Btm Baker Float Shoe 9.230' "OA"Window f/4,840'MD to 4,852'MD;Angle @ window 70° 20 ii � "OB"Window f/5,053'MD to 5,065'MD;Angle @ window 78° 3( II "OB"Lateral Slotted Liner 5,116'to 9,190'-Rat Hole 30' GENERAL WELL INFO 21 ..'14.4. 1 4o API:50-029-23212-00-00 7-5/8" 22 6-1/8"Hole-TD@ 9,253' Btm Baker 4-1/2"`V'Float Shoe 9,232' Drilled and Completed by Doyon 14-8/1/2004 4 "NB"Lateral 4"Med Excluder Screen 6,245'to 9,190'-Rat Hole 20' TD=9,253'(MD)/TD=3,723'(TVD) Cleanout NB lateral to PBTD=9,253'(MD)/PBTD=3,723'(1VD) 8,726'CTM 9/02/2016 Revised By:TDF 9/6/2017 . • Mime PointMP Unit1-17 . II We PROPOSED Last Completed: Proposed Hilcorp Alaska,LLC PTD: 204-098 TREE&WELLHEAD Tree 2-9/16"-5M FMC Wellhead 11"x 7-*1/16"5M FMC Gen 5A w/2-7/8"FMC Tbg Hgr,3"LH Orig.KB Elev.:69.3'/Orig.GL Elev.:30.4' ne on Top and 2-7/8"EU 8rd on Btm,2.5"CIW BPV Profile RKB-Hanger:30.4'(Doyon 14) OPEN HOLE/CEMENT DETAIL 1.,,, f,..:,, 420" Cmt w/260 sx of Arcticset I in 42"Hole 20" t 1 10-3/4" Cmt w/396 sx AS Lite,257 sx Class"G"in 13-1/2"Hole 7-5/8" Cmt w/765 sx Class"G"in 9-7/8"Hole it CASING DETAIL o° 4 Size Type Wt/Grade/Conn ID Top Btm cap 20" Conductor 215/A-53/Welded N/A Surface 112' N/Ao .- 10-3/4" Surface 45.5/L-80/BTC-M 9.950 Surface 161' .0962 10-3/4" Surface 45.5/K-55/BTC-M 9.950 161' 2,249' .0962 10-3/4" Surface 45.5/L-80/BTC-M 9.950 2,249' 2,378' .0962 10-3/4"a a' 7-5/8" Production 29.7/L-80/BTC-M 6.875 Surface 5,775' .0459 4-1/2" Liner"OA" 12.6/L-80/IBT 3.958 4,835' 9,188' N/A 4-1/2" Liner"OB" 12.6/L-80/IBT 3.958 4,991' 9,230' N/A 4-1/2" Liner"NB" 12.6/L-80/IBT-M 3.958 5,213' 9,232' N/A TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 4,600' .0059 WELL INCLINATION DETAIL KOP @ 450'MD 50°+from 3,200' Max Wellbore Angle=69°@+4,460' 2 JEWELRY DETAIL Mn ID=2 25 No Depth Item(All depths to Orig RKB) @4,50(2---..-11.i. 3 GLM DETAIL:SPMO-1.OM 2-7/8"x 1" 1 140' STA 3:Dual Orifice Valve,ID=2.371" AO 4 2 4,350' STA 1:DV,SBK-2C Latch,ID=2.371" 5 3 4,500' HES 2.313"XN Nipple-2.25"NoGo 4 4,615' Discharge Head IaII 6 5 4,635' Pump ist 6 4,640' Gas Seperator • 7 7 4,660' Seal Section mar tor 8 4,575' ESP Motor 9 4,595' Gauge&Centralizer-Btm @ 4,600' 8 10 4,794' OA Tie Back Sleeve 11 4,805' OA ZXP Liner Top Packer 9 12 4,828' OA OA 4-1/2"Hook Hanger'LEM'Above Hanger 13 4,835.34' OA 4-1/2"Hook Hanger'LEM'Inside Hanger 14 4,835.38' OA Hook Wall,Hanger Inside 7-5/8"Casing • 10 15 4,852' OA Hook Wall,Hanger Outside(Hook Point) Mil 1111 1111 12 16 4,991' OB Lateral ZXP Liner Top Packer ! 13 17 5,038' OB OA 4-1/2"Hook Hanger'LEM'Above Hanger x • : ;' 0 14 6-1/8"Hole-TD(c@ 9,225' HES'V'Float Shoe 9,188' 18 5,048' OB 4-1/2"Hook Hanger'LEM'Inside Hanger 1541( ! '`'" r 19 5,048' OB Hook Wall,Hanger Inside 7-5/8"Window 3# _ "OA"Lateral 4-1/2"Slotted Liner 4,862'to 9,144'-Rat Hole 37' 20 5,065' NB Hook Wall,Hanger Outside(Hook Point) P. • , f'"� 21 5,213' NB ZXP Liner Top Packer 22 5,231' NB Lateral 7-5/8"x 5"HMC Liner Hanger Illa 16 !'f 17 LATERAL WINDOW DETAIL 19--,. -4111111, . 18 6-1/8"Hole-TD@ 9,260'Btm Baker Float Shoe 9,230' "OA"Window f/4,840'MD to 4,852'MD;Angle @ window 70° ij „ I- "OB"Window f/5,053'MD to 5,065'MD;Angle @ window 78° li i 'OB"Lateral 4-1/2"Slotted Liner 5,116'to 9,190'-Rat Hole 30' 20 it. swr is GENERAL WELL INFO 4§K..... API:50-029-23212-00-00 7-5/8" 21 " 6-1/8"Hole-TD@ 9,253' Btm Baker 4-1/2"'V'Float Shoe 9,232' Drilled and Completed by Doyon 14-8/1/2004 4 "NB'Lateral 4"Med Excluder Screen 6,245'to 9,190'-Rat Hole 20' TD=9,253'(MD)/TD=3,723'(TVD) Cleanout NB lateral to PBTD=9,253'(MD)/PBTD=3,723'(TVD) 8,726'CTM 9/02/2016 Revised By:STP 1/02/2018 • • Milne Point ASR Rig 1 BOPE flikorp %Lo ,1.111, 2017 11" BOPE Stripping Head Lilismirmr—\ 1 4.48' r 'V Pliydril GIP 11" - 5000 lil li ll lllll III-ill It! ill NI I 4.54' Mil.I11111 ® IMU VBR or Pipe Rams 1r :SIE Willi 11"- 5000 tai mow m, - Blind lit ILIAIJIII Ili! 2 1/16 5M Kill Line Valves M 2 1/16 5M Choke Line Valves 111'1 PI I'I!I'lilli 2.00' LIi: . I• ' ! „t& 4;,,, e fei . , ''.: Manual Manual Manual HCR Updated 11/20/2017 • H • • M -17 EXISTING TREE/WELLHEAD Wellhead/T/Tree H Al _LLC Milne Point Unit aska Tree Cap 1.11 ,-, BS 411111,, 77> Tree Valve 2-9/16" 5M r' o 1®6—,1®1 rO w, Tree Cross 2-9/16" 5M iI(o)o l Tree Valve 2-9/16" 5M Ib,,Y... "'91lt1 - SSV 2-9/16" 5M itIto 0 Tree Valve 2-9/16" 5M o,. Ihllug,II, ESP Cable "' "' Tubing Adapter II I , _ .... . 1 ,, r 1,7=-D Tubing Head uti .. �–.- I FE 11"5MTop x 11" 5M Btm ' mr !MI �/t , D6 11111 I I / 111 ■-i.,{ 01111111 ,i. Casing Head 11" 5MTop x11"5MBtm il 1110 ) IIIIIiiiip25011-1.; i,' '.'''l :. if ..,,v„,,,..\,. _„..._ _ . _ , _f . . MPU I-17 TEMPORARY TREE/WELLHEAD Wellhead/Tree x;ica>�,Alaska,LLC Milne Point Unit Gs Tree Cap tit lia tat itiWili tat Tree Valve 4-1/16" 5M dc' (21°'''4' tft W tat '/4"1/17, .O Tree Cross 4-1/16" 5M oo�0 Tree Valve 4-1/16" 5M i 0'ri Tree Valve 4-1/16" 5M '' ° oo® t#t NMI tat !Fkt(L tat OO Tree Valve 4-1/16" 5M 1 o�.), oQ'D` 1t1.. ..t11 III III Tubing Adapter _ �,-- r. '� Tubing Head #.. Eli 11" 5M Top x 11" 5M Btm _I '''' ", Cinit # all ''', , r ft! 1 III Casing Head .4i III id- 11" 5M Top x11" 5MBtm i 1 ) ifiniiii%%Stiki.. 11111 I / J • • 0 § kms a) = 5c 0 JJ $ / / 0 > o U qk ( 2 / « tea EE S c m % 2 2 E Y t $ 2 m < 2 •E / \ _ �— 7 e m W 5 \ � � _0 § k 22 RS k / 27 �f aS % .") < co ■ a) \ / I a a o Cif CO / - i » / 2 CD / § O CL k eL L. \ \\_ a 0 2 - * -o 0 \ \ � 2 L k E9 S L. § 2 = j m a O 2 \ ' 1... I- 22 a 0 \/ g 8 a) C � ƒ us a j0 C I a) \ \ % C 2 § i 12g a) 474 1-4 0 .- 0. Dm e o Lin o « a) 0 # cs ( � ca E % cn f * _� � w ■ coCI / \ / ■ co 0 © / cc 2 it co 0 'EsG ti \ Ea) .0 E 0 a § as O e M 0 a $ k k 0 o_ • COIL BOPS MILNE POINT UNIT MPU 1-17 Hi corp Alaska,LLC 12/29/2017 MPU 1-17 20 X 10% X 7% X 4'/2 Coil Tubing BOP 1 Lubricator to injection head i o i 71 1 2.00"Single Stripper I J 1 ( 1/16100110 Bind/Shea,.' -_ Blind/Shear 'C_ _- •I,', Blind/Shear M-Blind/Shear,L - iniNil l• 5111111111111 iNiMii J511111 11115 0® 0.111111 Slip = Slip ®'®I.t =_—__ Pipe Ems Pipe ,I,I•I ti IND ii Crossover spool 4 1/16 10M X 4 1/16 5M i Pump In Sub �; 4 1/16 5M 1502 Union :i: Manual Gate Manual Gate Mr Valve,Swab,WKM-M, t• • 2 1/8 5M 2 1/8 5M 4 1/16 5M FE &I �\O r, N- N12' N' III Valve,Upper Master,Baker, 4 1/16 5M FE,w/Hydraulic Valve,Lower Master,WKM-M, fft--o-", 4 1/16 5M FE 1111\ � Tubing Adapter,4 1/16 5M 1 • STANDARD WELL PROCEDURE Hileorp Alaska,LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 r • • era a I § $ °r �e • •.. a v a v > o Y ce W O v Y W z u _ F R p \2 K F \2 K P .... w > m O] t. o3ao „ o `o3aouo t � ° E t 3 o LL Z 4uXZzo n a RZ 0 W - - .fir a a °' a .Q a a u �;4., J Z y.., N > (7 =•'- E v ;,� �,� t•• z 3...•.',a w > C7 W U o. 41 3r . •o -. z m 41m _, I g O Y 0 r u ` , A i -- ' 0. pla D A A LL C7 o,k% _, k �,, or i lir- aP 1,_, p , `,l ' 11 maws*1 i; , .+''''' ' ® {. ` 111 ys r o • •__>.• MN 61/11/11 M . 0000 i O p O W Y d N Z t .- -- ,._ W Q c H d a v v LL � o z u+ a P- 8 Z-(>-- W W Q Q 3 3 o Y 2 VI 0 /- Y I m m Ea. o a C11 Ca 0 0 e • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 II I December 30, 2011 FEB 1 7 ZO1L Mr. Tom Maunder ca� Alaska Oil and Gas Conservation Commission � n (4 — 0 9, 333 West 7 Avenue Anchorage, Alaska 99501 p(-17 Subject: Corrosion Inhibitor Treatments of MPI -Pad Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from MPI -Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir BPXA, Well Integrity Coordinator • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top -off Report of Sundry Operations (10 -404) MPI -Pad 10/9/2011 Corrosion Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # Initial top of cement pumped cement date inhibitor sealant date ft bbls ft gal MPI -01 1900900 50029220650000 0.1 NA 0.1 NA 8.5 9/5/2011 MPI -02 1900910 50029220660000 Sealed coductor NA NA NA NA NA MPI-03 1900920 50029220670000 Sealed coductor NA NA NA NA NA MPI-04A 2010920 50029220680100 Sealed coductor NA NA NA NA NA MPI -05 1951200 50029225830000 2.7 NA 2.7 NA 27.2 11/2/2009 MPI-06 1971950 50029228220000 Open Flutes - Treated NA NA MPI -07 1951510 50029226020000 1.7 NA 1.7 NA 16.2 8/21/2011 MPI-08 1971920 50029228210000 1.3 NA 1.3 NA 15.3 11/2/2009 MPI-09 2001030 50029229640000 1.3 NA 1.3 NA 13.6 11/1/2009 MPI -10 2001090 50029229660000 Open Flutes - Treated NA NA MPI -11 2011370 50029230330000 1.3 NA 1.3 NA 10.2 8/19/2011 MPI -12 2011630 50029230380000 0.2 NA 0.2 NA 7.7 10/9/2011 MPI -13 2010750 50029230120000 0.85 NA 0.85 NA 8.5 9/5/2011 MPI -14 2041190 50029232140000 1.9 NA 1.9 NA 16.2 8/23/2011 MPI -15 2021520 50029231060000 1 NA 1 NA 9.4 8/19/2011 MPI -16 2041580 50029232210000 1.75 NA 1.75 NA 17.0 8/19/2011 -- ---05* MPI -17 2040980 50029232120000 1.75 NA 1.75 NA 13.6 8/23/2011 MPI -19 2041350 50029232180000 1.4 NA 1.4 NA 10.2 8/19/2011 • • -~,,. 1/ ~ • t 03!01/2008 DO NOT PLACE ~ ~..,,. ~;~~ , ~r .~;~ - '" :. ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_Inserts\Microfilm Marker.doc I~ DATA SUBMITTAL COMPLIANCE REPORT 9/11/2006 Permit to Drill 2040980 Well Name/No. MILNE PT UNIT sa 1-17 MD 9253 ----~~----~. ---_.._~----- TVD 3723 Completion Date 8/1/2004 ._~-,~ REQUIRED INFORMATION Mud Log No Samples No - DATA INFORMATION Types Electric or Other Logs Run: MWD, GR, RES, IFR/CASANDRA, ASI, GYRO Well Log Information: Log/ Data Digital ,~ Med/Frmt I HI C Lis I~ D Asc ~Dt vlo D Asc 4 ø D Lis l~~__ Electr Dataset Number Name -~- 13526 Induction/Resistivity Directional Survey Directional Survey Directional Survey Directional Survey 12770 Induction/Resistivity 12770 LIS Verification Well Cores/Samples Information: Name Interval Start Stop ADDITIONAL INFORMATION Well Cored? Y Gi::> Chips Received? '( I ~J Analysis Received? ~ Comments: ---"--~ ~-----~~~~ Operator SP EXPLORATION (ALASKA) INC API No. 50-029-23212-00-00 Completion Status 1-01L Current Status 1-01L UIC N --- Directional Survey Yes (data taken from Logs Portion of Master Well Data Maint Log Log Run Interval OH/ Scale Media No Start Stop CH Received Comments 114 9253 Open 2/22/2006 ROP DGR EWR plus Graphics 0 9253 9/3/2004 MWD SURVEY 0 9253 9/3/2004 MWD SURVEY 0 9253 9/3/2004 IIFR SURVEY- 0 9253 9/3/2004 IIFR SURVEY 267 9195 9/14/2004 MPT, GR, EWR4, ASI, ROP 267 9195 9/14/2004 MPT, GR, EWR4, ASI, ROP ---"- Sample Set Sent Received Number Comments . . Daily History Received? C:!)N çVN Formation Tops - Permit to Drill 2040980 MD 9253 TVD Compliance Reviewed By: DATA SUBMITTAL COMPLIANCE REPORT 9/11/2006 Well Name/No. MILNE PT UNIT SB 1-17 Operator SP EXPLORATION (ALASKA) INC 3723 Completion Status 1-01L Current Status 1-01L Date: ---Ll API No. 50-029-23212-00-00 J/-~~ . . . . WELL LOG TRANSMITTAL ¡!)04--0Qß To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West ih Ave., Suite 100 Anchorage, Alaska 99501 Febmary 16,2006 t ys~(¡ RE: MWD Fonnation Evaluation Logs MPI-17, The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rob Kalish, Sperry Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 907-273-3500 MPI-17: LAS Data & Digital Log Images: 50-029-23212-00 1 CD Rom (0{i~-h ~I :fPðIO(o . ~oi'-«) ?-8' . WELL LOG TRANSMlTIAL To: State of Alaska Alaska Oil and Gas Conservation Corom. Attn,: Robin Deason 333 West 7th Avenue, Suite 100 Anchorage,AJaska 99501 September 07,2004 RE: MWD Formation Evaluation Logs MPI-17, AK-MW-3171003 1 LIS formatted Disc with verification listing, API#: 50-029-23212-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING A COPY OF THE TRANSMITTAL LETTER TO THE ATIENTION OF: Sperry-Sun Attn: Rob Kalish 6900 Arctic Blvd, Anchorage, AJaska 99518 BP Exploration (Alaska) Inc. Petro-technical Data Center LR2-1 900 E. Benson Blvd. Anchorage, AJaska 99649-6812 Date(~ff RECEIVED SEP 24 200Ll Alaska Oil & Gas Cons. Commi83ion An~ . STATE OF ALASKA e ALASKA~IL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a, Well Status: a Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25,105 20AAC 25,110 o GINJ 0 WINJ 0 WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a, Location of Well (Governmental Section): Surface: 2323' NSL, 3581' WEL, SEC. 33, T13N, R10E, UM Top of Productive Horizon: 3096' NSL, 3432' WEL, SEC. 32, T13N, R10E, UM (NB) Total Depth: 3267' NSL, 4362' WEL, SEC. 32, T13N, R10E, UM (NB) 4b, Location of Well ~tate Base Plane Coordinates): Surface: x- 551790' y- 6009440 J Zone- ASP4 I , TPI: x- 546652 y- 6010178 Zone- ASP4 Total Depth: x- 545715' y- 6010~ JZone- ASP4 18. Directional Survey a Yes 0 No 21, Logs Run: MWD , GR , RES, IFRlCASANDRA , ABI , GYRO CASING, LINER AND CEMENTING RECORD SETtII\lßDsÞ1i'fMD SETT"I\IG DEÞTli"tVO HOLE I of> BOT'1;OM Top BOTTOM SIZE 34' 112' 34' 112' 42" 35' 2378' 35' 2339' 13-1/2" 33' 5775' 33' 3867' 9-718" 5213' 9231' 3970' 3726' 6-3/4" . 22, CASING SIZE WT.PER FT; 92# 45.5# 29.7# 12,6# 19,5# H-40 L-80 L-80 L-80 20" 10-3/4" 7-518" 4"x5" 23, Perforations open to Production (MD + TVD of To,e and Bottom Interval, Size and Number; if none, state' none"): 4" x 5 " Excluder Screens MD TVD MD 6244' - 9190' 3763' - 3730' 26. Date First Production: August20,2004 Date of Test Hours Tested PRODUCTION FOR 8/19/2004 I~ TEST PERIOD + Flow Tubing Casing Pressure CALCULATED + Press. 24-HoUR RATE One Other 5. Date Comp., Susp., or Aband. 8/1/2004 ,¡ 6, Date Spudded 7/11/2004 .I 7, Date T.o, Reached 7/20/2004 J 8. KB Elevation (ft): KBE = 68.35' 9. Plug Back Depth (MD+ TVD) j 9253 + 3723 ~ Ft 10, Total Depth (MD+ TVD) 9253 + 3723 'Ft 11, Depth where SSSV set N/A MD 19. Water depth, if offshore N/A MSL 1b. Well Class: a Development 0 Exploratory o Stratigraphic 0 Service 12, Permit to Drill Number 204-098 13, API Number 50-029-23212-00-00 14, Well Name and Number: MPI-17 15. Field 1 Pool(s): Milne Point Unit 1 Schrader Bluff 16. Property Designation: ADL 025517 17, Land Use Permit: 20, Thickness of Permafrost 1800' (Approx.) 260 sx Arctic Set (Approx.) 396 sx AS Lite, 257 sx Class 'G' 765 sx Class 'G' Baker Excluder Screen Liner 24. TUBING ReøÓRP SIZE DEPTH SET (MD) 2-7/8",6.5# x 12.6#, L-80 4738' TVD 25. DEPTH INTERVAL (MD) PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc,): Electric Submersible Pump OIL-BeL GAs-McF WATER-BeL 1177 227 0 CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). NO:ubmit core chips; if none, state "none" RBOMS Bfl SEP 2 1 ~(: C E' VE 0 SEP 1 6 2004 Alaska Oìl & Gas Cons. Commission l1 ,- Anchorage OIL-BeL 2354 27. GAs-MCF 454 WATER-BeL o V[?¡f~tÛ -~- 0 R ! G 1 Form 10-407 Revised 12/2003 I~L CONTINUED ON REVERSE SIDE PACKER SET (MD) AMOUNT & KIND OF MATERIAL USED I GAS-OIL RATIO 193 OIL GRAVITY-API (CORR) CHOKE SIZE 28. e 29. e GEOLOGIC MARKERS FORMATION TESTS Include and briefly summarize test results. List intervals tested, NAME MD TVD and attach detailed supporting data as necessary. If no tests were conducted, state "None". SBF2 4410' 3735' SBF21 4429' 3743' None SBF24-MF 4469' 3758' SBF1-NB 4486' 3764' SBF12 4545' 3785' SBE4-NC 4569' 3794' SBE41 4581' 3798' SBE3-ND 4591' 3802' SBE2-NE 4616' 3811' SBE1-NF 4744' 3855' TSBD-OA 4845' 3889' TSBC 4943' 3920' TSBB-OB 5069' 3950' SBA5 5173' 3966' SBA5 5389' 3963' TSBB-OB 5520' 3941' TSBC 5634' 3910' TSBD-OA 5743' 3877' SBE1-NF 5863' 3841' SBE2-NE 6043' 3791' SBE3-ND 6077' 3784' SBE41 6109' 3779' SBE4-NC 6154' 3773' SBF12 6265' 3762' SBF12 8300' 3763' SBF12 8462' 3761' SBF1-NB 9172' 3732' 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys and a Leak-Off Test Summary. 31, I hereby certify that the foregoing is true and correct to the best of my knowtedge, Signed Title Technical Assistant Date (j1-1 3 -Oci MPI-17 Well Number Prepared By Name/Number: Drilling Engineer: Sondra Stewman, 564-4750 Skip Coyner, 564-4395 204-098 Permit No. I Approval No. INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated, Each segregated pool is a completion, ITEM 4b: TPI (Top of Producing Interval). ITEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments, ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness, ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval), ITEM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain), ITEM 27: If no cores taken, indicate "None", ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 ( " lJ S I\~/~ L Submit Original Only Tree: 2-9/16" - SM FMC A_ Wellhead: 11" x 7-1/16" SM~ Gen SA, w 2-7/8" FMC Tbg. Hgr,. 3" LH Acme on top and 2-7/8" EU 8rd on bottom, 2,5" CIW BPV Profile .... 20" x 34" insulated, 215 lIft A-53 o:EJ 103/4" 45,5 ppf K-55 BTRC (Drift ID = 9,794, cap, = ,0961 bpf) 103/4" Howco Float Shoe 12378' I .111111111 75/8" 29.7 ppf, L-80, BTRC-mod casing (Drift ID = 6.750", cap = 0,0459 bpf) (Cap w/ tbg = ,0379 bpf) 2-7/8" 6.5 ppf, L-80 8rd eue tbg, ( drift id = 2,347" cap = .00592 bpf ) KOP @ 450' 50+ degree from 3200' Max hole angle = 69 degrees @ +4460' Window in 75/8" Casing @ 4840' - 4852' Well Angle @ window = 70" Baker Tie Back Sleeve 4794' Baker ZXP Liner Top Packer 4805' Baker Hook Hanger LEM 4828' - 4860' Baker Hook Wall Hanger inside 7-5/8" Window 4835' Baker Hook Wall Hanger outside 7-5/8" Window 4852' Window in 7-5/8" Casing @ 5053' - 5065' Well Angle @ window = 78" Baker Tie Back Sleeve 4991 ' Baker ZXP Liner Top Packer 5002' Baker Hook Hanger LEM 5038' - 5073' Baker Hook Wall Hanger inside 7-5/8" Window 5048' Baker Hook Wall Hanger outside 7-5/8" Window 5071' Baker Tie Back Sleeve 5213' Baker ZXP Liner Top Packer 5224' Baker 7-5/8" x 5" HMC Liner Hanger 5231' ~ ~5 /~ 7 -5/8" Weatherford Float Collar 5688' 7-5/8" Weatherford Float Shoe 5775' MPI-17 .. KB elev, = 69.30' (Doyon 14) GL elev,= 30.40' (Doyon 14) L C,moo '-'/8" ,'" KBMM Gas lift mandrel 146' Cameo 2-7/8" x1" KBMM Gas lift mandrel 2022' ~ Cameo 2-7/8" x1" KBMM Gas lift mandrel 4470' HES XN-Nipple (2.250" id) 4626' Tandem Pump, 122 stg. GCnOO GPMTAR 1:1 4679' Tandem Intake - Gas Separator Model - GRSTXBARH6 Tandem Seal Section, Series 513 GSB3 DB UT/L T IL H6 PFS AFLAS IHSN 4700' 4705' Motor, 152 KMH 2325 volt I 40 amp, 4719' PumpMate w/6 fin centralizer 4733' L 61/8" Hole td @ 9225' HES "V" Float shoe 9188' 'V""""J .. OA Lateral 102 jts, - 4 1/2" Slotted Liner Rat Hole 12,6# L-80 IBT ('-') 37' fSSSSSS" 1""""'1 OB Lateral '- 1./ ./ ./ ./ ./ ./ ./ ./ ./ I 98 jts, - 4 1/2" Slotted Liner 12,6# L-80 IBT (5116'-9190') rssSSSS"1 I""""" 6 1/8" Hole td @ 9260' Btm Baker Float Shoe 9230' .. Rat Hole 30' ~ 'Æ" Hol, W @9253' 8m ..., "" "V" """ "'"' ,,,,' ~ r//.>'///////N"//////ff//////ß/~' Rat Hole' NB Lateral 47 jts, - 4", 9,5# L-80, IBT Blanks and 20' 39 jts Baker Med Excluder Screen (6245' - 9190') I'/#////NN//////#//N//////J ~ DATE 0812104 REV, BY Lee Hulme COMMENTS Drilled & Completed Doyon 14 MILNE POINT UNIT WELL 1-17 API NO: 50-029-23212-00 BP EXPLORATION (AK) Legal Name: MPI-17 Common Name: MPI-17 TêStD8tê . 7/14/2004 FIT 7/15/2004 FIT 7/18/2004 FIT 2,378.0 (ft) 2,378.0 (ft) 5,774.0 (ft) Test.pépth··nVD) 2,339,0 (ft) 2,339.0 (ft) 3,867.0 (ft) 9.30 (ppg) 9.30 (ppg) 9.60 (ppg) 120 (psi) 170 (psi) 480 (psi) 1,250 (psi) 1,300 (psi) 2,408 (psi) EMW 10.29 (ppg) 10.70 (ppg) 11,99 (ppg) - e Printed: 8/3/2004 9: 14:42 AM - . BP Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 7/10/2004 From -To Code NPT 00:00 - 01 :00 1.00 MOB P PRE 01 :00 - 02:00 1,00 MOB P PRE 02:00 - 05:30 3,50 MOB P PRE 05:30 - 08:30 3,00 MOB P PRE 08:30 - 09:30 1,00 MOB P PRE 09:30 - 11 :00 1,50 MOB P PRE 11 :00 - 15:00 4,00 MOB P PRE 15:00 - 18:00 3,00 MOB P PRE 18:00 - 19:30 1.50 MOB P PRE 19:30 - 20:00 0,50 MOB P PRE 20:00 - 21 :00 1,00 MOB P PRE 21 :00 - 22:00 1,00 MOB P PRE 22:00 - 00:00 2,00 MOB P PRE 00:00 - 01 :00 1,00 MOB P PRE 7/11/2004 01 :00 - 02:00 1.00 MOB P PRE 02:00 - 03:00 1.00 MOB P PRE 03:00 - 05:00 2.00 RIGU P PRE 05:00 - 08:30 3.50 RIGU P PRE 08:30 - 17:30 9.00 DRILL P SURF 17:30 - 18:30 1.00 DRILL P SURF 18:30 - 19:30 1,00 DRILL P SURF 19:30 - 20:00 0,50 BOPSUF P SURF 20:00 - 20:30 0,50 DRILL P SURF 20:30 - 22:30 2,00 DRILL P SURF 22:30 - 00:00 1.50 DRILL P SURF 7/12/2004 00:00 - 06:00 6,00 DRILL P SURF 06:00 - 07:30 1.50 DRILL P SURF 07:30 - 19:30 12.00 DRILL P SURF 19:30 - 20:30 20:30 - 21 :30 21 :30 - 22:00 22:00 - 00:00 1,00 DRILL P 1.00 DRILL P 0.50 DRILL P 2.00 DRILL P SURF SURF SURF SURF Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: Description of Op Get floor ready to skid for move Skid rig floor from drtg position to move position Drillers side front steering rams not moving to 90 degree angle - Mechanic diagnose problem Move rig off well MPJ-25 Install back boosters Pick up matting boards and herculite around well MPJ-25 Front boosters will only turn one way - Electrican diagnose problem Move rig from J-Pad to I-Pad Remove Front boosters Finish laying rig mats Move rig on mats to other side of I-Pad Pick up double mats Lay herculite and mats for well MPI -17 Spot Rig Over Well - Accept Rig For Well Work At 00:01 hrs On 7/11/04 - Time Moved Back 3 Hours Due To Time Spent Removing Double Matting Boards - Laying Herculite And Single Matting Boards Because Of Poor Pad Conditions. Skid rig floor from move position to drtg position Rig up rig floor - Spot rock washer and berm - spot tiger tank and hook up Nipple up Divertor Install Divertor line - Mix spud mud - Load pipe shed Pick up 4" dp - Stand back in derrick - Pick up 5" HWT I Jars - Stand back in derrick Pick up BHA to rig floor - Perform Derrick Inspection Make up bit - motor - Stand HWT - Rig up HOWCO slickline for gyro runs Function Test Divertor / Knife Valve - Perform Accumulator test - Gas Monitor Test - Witness of test waived by Chuck Sheave with AOGCC Pre Spud meeting with all personnel on rig - Check mud system - Check surface lines for leaks - Fill Riser check for leaks - Spud in well - Directional Drill from 114' to 314' - WOB 20- RPM 70 - TO on 2 - off 2 - GPM 395 - PP on 1250 - off 1050- PU 80 - SO 80 - ROT 80 POH - Make up MWD - Flex De's - Orient - RIH to 314' Directional Drill from 314' to 728' - woe 20 - RPM 70 - TO on 2 - off 2 - GPM 395 - PP on 1250 - off 1050 - PU 80 - SO 80- ROT 80 Circ and reciprocate pipe while conference call to town on Directional Work - GPM 150 - PP 260 Directional Drill from 728' to 1972' - WOB 3.0 - RPM 80 - TO on 4.5 - off 2 - GPM 500 - PP on 2030 - off 1870 - PU 97 - SO 90- ROT 93 - Hydrates encountered @ 1780' to 1950' mud cut from 9.4 to 8.7+ CBU 3 X - GPM 500 - PP 1950 Pump out to HWT - From 1972' to 444' - (No Problems) RIH from 444' to 1972' - Hole good Directional Drill from 1972' to 2262' - WOB 15 to 30 - RPM 80 - TO on 5 - off 2 - GPM 500 - PP on 1950 - off 1980 - PU 103 - Printed: 8f3I2OO4 9:14:56 AM e e legal Well Name: MPI-17 Common Well Name: MPI-17 Spud Date: 7/11/2004 Event Name: DRlll+COMPlETE Start: 7/11/2004 End: Contractor Name: DOYON DRilLING INC. Rig Release: 8/1/2004 Rig Name: DOYON 14 Rig Number: Date 7/12/2004 22:00 - 00:00 2,00 DRILL P SURF SO 92 - ROT 95 7/13/2004 00:00 - 02:30 2,50 DRILL P SURF Directional Drill From 2262' to 2388' - T.D. 13 1/2" hole - WOB 15 to 30 - RPM 80 - TO on 5 - off 3 - GPM 500 - PP 2050 on - 1780 off - PU 105 - SO 93 - ROT 96 02:30 - 04:00 1,50 DRILL P SURF CBU 3 X - GPM 500 - PP 2000 - RPM 80 - TO 2 04:00 - 06:00 2,00 DRILL P SURF Flow Check - Pump out to HWT - From 2388' to 444' @ drilling rate 500 gpm - No Problems 06:00 - 06:30 0.50 CASE P SURF Flow Check - RIH tag bridge @ 851' 06:30 - 07:00 0.50 CASE P SURF Work through bridge from 851 to 855' 07:00 - 08:00 1.00 CASE P SURF RIH from 855' to 2388' - Hit soft bridges @ 1550',1814', and 2085' 08:00 - 10:00 2,00 CASE P SURF CBU 3 X - 80 RPM TO 2K - GPM 500 - PP 1830 10:00 - 11 :30 1.50 CASE P SURF Pump out from 2388' to HWT @ 444' - No problems 11 :30 - 13:00 1.50 CASE P SURF Lay down BHA - 13:00 - 13:30 0,50 CASE P SURF Clear rig floor 13:30 - 15:00 1.50 CASE P SURF Rig up to run 103/4" casing - PJSM 15:00 - 17:30 2.50 CASE P SURF Run 6 Joints L-80 45.5# BTC casing and 50 joints K-55 45.5" BTc casing total 56 jts 45,5# BTC 103/4" ran - Bridge at 852' - Beat casing through bridge - taking weigth from 2050' to 2343' - Break circ and circulate last joint down - Pick up landing joint / casg hanger - Make up RIH from 2343' to 2378' land. 17:30 - 18:00 0,50 CASE P SURF Lay down Franks fill up tool - Make up Dowell Schlumberger cementing head - cement lines 18:00 - 20:00 2.00 CASE P SURF Circulate and condition for cement job - stage up from 3 bpm to 8 bpm @ 340 psi 20:00 - 22:00 2.00 CEMT P SURF Give to Dowell - Pump 5 bbls water - Test lines to 3500 psi - Pump 25 bbls water (one gallon dye in first 5 bbls pumped) 5 bpm @ 170 psi- Swap to rig pumps flush with 20 bbls treated water 5 bpm 170 psi - Swap to Dowell pump 20 bbls CW-100 5 bpm @ 200 psi- Pump 75 bbls Mud Push mixed at 10,3 ppg 5 bpm @ 200 psi- Drop Top plug last 5 bbls pumped Pump 313 bbls Type "ASL" yield 4.44 cflsx mixed @ 10.7 ppg 6,5 bpm @ 350 psi - Dye back after pumping 296 bbls Lead - Switch to Class "G" after 313 bbls pumped Pump 53.5 bbls Class "G" yield 1,17 cflsx mixed @ 15.8 ppg 5.5 bpm @ 500 psi - Kick out Bottom plug with 20 bbls water with Dowell 5 bpm @ 450 psi - Give to Rig - Displace with 190 bbls mud 8 bpm @ 500 psi - Bump plug with 1500 psi 1000 psi over Hold pressure for 2 mins - Bleed off - Floats holding - 87 bbls good cement to surface Cement in place 22:00 hrs 22:00 - 23:30 1.50 CASE P SURF Rig down Cementing Head / Cementing lines - Clear rig floor - Flush Divertor - Lay down landing joint - Lay down Casing tools 23:30 - 00:00 0.50 CASE P SURF ND Divertor 7/14/2004 00:00 - 00:30 0.50 CASE P SURF Nipple Down Divertor 00:30 - 01 :00 0.50 CASE P SURF Install Tubing I Casing heads - Test to 1000 psi for 10 mins 01 :00 - 03:00 2.00 CASE P SURF Nipple up BOP's 03:00 - 03:30 0.50 CASE P SURF Rig up to test BOP's - Install test plug - Open annulus valve Printed: 81312004 9:14:56 AM e e BP Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 Date From ..To Hours Task Code NPT 7/14/2004 03:30 - 07:00 3,50 CASE P SURF 07:00 - 07:30 0,50 CASE P SURF 07:30 - 09:30 2,00 CASE P SURF 09:30 - 10:30 1.00 CASE P SURF 10:30 - 11 :00 0.50 CASE P SURF 11 :00 - 12:30 1,50 DRILL P SURF 12:30 - 13:00 0.50 DRILL P SURF 13:00 - 13:30 0,50 DRILL P INT1 13:30 - 15:00 1.50 DRILL P INT1 15:00 - 15:30 0.50 DRILL N DPRB INT1 15:30 - 00:00 8,50 DRILL P INT1 7/15/2004 00:00 - 01:00 1,00 DRILL P INT1 01 :00 - 02:00 1.00 DRILL P INT1 02:00 - 03:00 1.00 DRILL P INT1 03:00 - 03:30 0,50 DRILL N DPRB INT1 03:30 - 05:00 1,50 DRILL P INT1 05:00 - 05:30 0,50 DRILL P INT1 05:30 - 12:00 6.50 DRILL P INT1 12:00 - 13:30 1.50 DRILL N DFAL INT1 13:30 - 14:30 1.00 DRILL N DFAL INT1 14:30 - 15:00 0,50 DRILL N DFAL INT1 15:00 - 15:30 0.50 DRILL N DFAL INT1 15:30 - 18:00 2.50 DRILL N DFAL INT1 18:00 - 20:00 2.00 DRILL N DFAL INT1 20:00 - 22:00 2.00 DRILL P INT1 22:00 - 23:30 1.50 DRILL P INT1 Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: Test BOP's, Annular 250 low 2500 high for 5 mins each test- Pipe rams - Blind rams - Choke manifold - HCR Kill I Choke - Manual Kill / Choke - Upper IBOP / Lower IBOP - Floor safety valves to 250 low 3500 high for 5 mis each test - Perform Accumulator test - Witness of BOP test waived by Lou Grimaldi with AOGCC. Pull test plug - Install wear ring - Close annulus valve Make up BHA - Surface test MWD 402 gpm @ 1540 psi RIH to 2265' - Break circulation - Rig up testing equipment Test 10.75' casing to 2000 psi for 30 mins - Test good Drill float collar @ 2290' - Float shoe 2376' - Clean out to 2388' - Drill from 2388' to 2408' - Circ hole clean FIT - Mud weight 9,2 ppg - surface pressure 340 psi - Pressure bleed off to 110 psi EMW = 10,2 ppg Drill from 2408' to 2438' Circulate and condition hole for FIT FIT - Mud weight 9,3 ppg - surface pressure 340 psi - Pressure bleed off to 120 psi EMW = 10.3 ppg Directional Drill from 2438' to 3416' - WOB 15 to 25 - RPM 80- TO on 5k - off 3k - GPM 460 - PP on 2740 - off 2500 - PU 120- so 90 - ROT 106 CBU 2 X - GPM 453 - PP 2440 - RPM 84 - TO 5K Pump out to shoe - from 3416' to 2350' at drfg rate CBU 1 X - GPM 453 - PP - RPM 40 - TO 3k GPM 168 to 450- PP 600 to 1700 - Clay balls· Plugging flow line - augar line FIT - Mud weight 9,3 ppg - MD 2378' - TVD 2339' - Surface pressure 250 bled to 150 in 10 mins EMW = 10.53 - Bump up pressure from 150 to 270 psi - bled to 170 in 10 mins EMW = 10.69 Cut Drfg line - Top Drive Service - Rig Service RIH From 2350' to 3416' Directional Drill from 3416' to 4183' - woe 15 to 25 - RPM 80- TO on 5 to 10 - off 4 - GPM 500 - PP on 2740· off 2500· PU 130 - SO 90 - ROT 106 - POH due to lost signal from pulsar CBU 3 X - GPM 500 - PP 2500 - RPM 80 -TO 5 Pump out ot shoe from 4183' to 2370' CBU 1 X - Flow check well - Well static - Pump dry job POH to HWT from 2370' to 445' BHA stand back HWT - Flex DC's - Down load MWD Check out problem of not getting signal - Found clay and two fairfy large pieces of shale on top of pulsar· change out pulsar - Install smaller screens in suction pods - Circulated across shaker screens while gunning up suction pit - Make up bit - BHA - MWD - Surface test MWD - Install 5' DP screen in 5' HWT while surface test MWD to see if any more shale I clay is captured in screen· Pull DP screen out of 5' HWT RIH from 445' to 4100' - filling pipe every 25 std- Precauctionary wash from 4100' to 4183' Direcrtional Drill from 4183' to 4375' - WOB 15 to 25 - RPM 80 - TO on 5 to 10 - off 4 - GPM 500 - PP on 2540 - off 2300 - PU 130 - SO 94 - ROT 106 Circulate hole clean on top N-sands - GPM 500 - RPM 80 - PP 2300 Printed: 81312004 9: 1 4:56 AM e BP Operations Su Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 e ary Report Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: From - To Hours Ta$k Description 7/15/2004 23:30 - 00:00 0.50 DRILL P 7/16/2004 00:00 - 17:00 17,00 DRILL P 17:00 - 19:00 2,00 CASE P INT1 19:00 - 20:30 1,50 CASE P INT1 20:30 - 21 :30 1,00 CASE P INT1 21 :30 - 00:00 2,50 CASE P INT1 7/17/2004 00:00 - 03:00 3,00 CASE P INT1 03:00 - 04:00 1,00 CASE P INT1 04:00 - 04:30 0,50 CASE P INT1 04:30 - 06:00 1,50 CASE P INT1 06:00 - 07:00 1,00 CASE P INT1 07:00 - 08:30 1.50 CASE P INT1 08:30 - 11 :30 3,00 CASE P INT1 11 :30 - 12:00 0,50 CASE P INT1 12:00 - 16:00 4,00 CASE P INT1 16:00 - 16:30 0.50 CASE P INT1 16:30 - 18:30 2.00 CASE P INT1 18:30 - 21:00 2.50 CEMT P INT1 INT1 INT1 Directional Drill from 4375' to 4445' - WOB 15 to 25 - RPM 80 - TO on 5 to 10 - off 4 - GPM 500 - PP on 2550 - off 2300 - PU 150 - SO 90 - ROT 110 - (Top NA 4414' MD) Directional Drill from 4445' to 5785' T.D. 97/8" hole - (NB top sand 4475')(OA Sand Top 4848')(OB Sand Top 5066') - WOB 15 to 25 - RPM 80 - TO on 7 - off 5 - GPM 500 - PP on 2650- off 2540 - PU 125 - SO 85 - ROT 100 CBU 2 X - RPM 100 - TO 5k - GPM 460 - PP 2070 Flow check - Pump out to 4100' - Pump @ drilling rate - Hole good no problems - Flow check well RIH from 4100' to 5725' - Wash from 5725' to 5785' - No Problems CBU 3 X - RPM 100 - TO 5k - GPM 500 - PP 2519 - Heavy thick mud back while circulating bottoms up - 10.2 ppg Vis 130 with lots of cuttings - Dump 40 bbls heavy mud Flow Check - Pump out to shoe from 5785' to 2360' - Pump at drlg rate - No Problems CBU 2 X - Lots cuttings - Circulate hole clean - GPM 500 - PP 1900 - RPM 60 - TO 3k Flow check - Pump dry job - POH from 2360' to 444' Stand 1 HWT back in derrick - Lay down 9 7/8" BHA Pull wear ring - Install test plug - Change rams to 7 5/8" - Test door seal to 1500 psi Rig up 7 5/8" casing equipment Pick up and run 58 jts of 7 5/8" L-80 BTC-M 29,7# casing to shoe @ 2370' Circulate one casing volume Staging up from 2 bpm @ 250 psi to 6 bpm @ 380 psi PJSM - Con't RIH with 7 5/8" L-80 BTC-M 29.7# casing to 5739' - Total joints ran 140 plus two pup joints - Make up hanger and landing joint - RIH land casing on hanger @ 5774' - On trip in with casing break Circulation @ 3481',4502',5739'- (Shoe 5774.87' - Float collar 5688.37') Lay down Franks fill up tool - Make up Schlumberger Dowell cementing head - cementing lines Circulate two casing volumes - Condition mud for cement job - 6 bpm @ 350 psi - Reciprocate 15 foot strokes 1 stroke per min - PU 195 - SO 115 Give to Schlumberger Dowell - Pump 5 bbls CW-100 2 bpm @ 200 psi Test lines to 4000 psi Pump 20 bbls CW-100 3.5 bpm @ 300 psi Pump 35 bbls Mud push 3,5 bpm @ 280 psi Drop Bottom Plug Pump 158 bbls Class "G" cement mixed at 15.8 yield 1.16 cuftlsx - 760 sxs 6.2 bpm @ 750 psi Drop Top Plug Displace with Oil base mud - 6.4 bpm 1150 psi - Slow last 15 bbls to 2 bpm @ 825 psi - Bumped plug with 1825 psi - Pumped 262.5 bbls - Hold pressure for 5 mins - Bleed off - Floats holding - Reciprocated string while cementing and 165 bbls of displacement - String taking weight PU 220 - SO 100 - at 165 bbls displacement string taking weight down to 85 - set Printed: 81312004 9: 14:56 AM e e BP Operations Summary Report of Legal Well Name: MPI-17 Common Well Name: MPI-17 Spud Date: 7/11/2004 Event Name: DRILL+COMPLETE Start: 7/11/2004 End: Contractor Name: DOYON DRILLING INC. Rig Release: 8/1/2004 Rig Name: DOYON 14 Rig Number: From - To Hours Task Code NPT DescriptionofOpørål 7/17/2004 18:30 - 21 :00 2.50 CEMT P INT1 on hanger for rest of displacement 21 :00 - 21 :30 0.50 CASE P INT1 Flush Cement line with 15 bbl water - Blow back to Schlumberger - Rig down cement lines - Cementing head 21 :30 - 22:30 1.00 CASE P INT1 Lay casing / cementing equipment down beaver slide 22:30 - 23:00 0.50 CASE P INT1 Rig up to void casg of Oil base mud to 60' - Void casg - Rig down same 23:00 - 23:30 0,50 CASE P INT1 Back out landing joint - Lay down same - Change out long bails - Change out to 5" elevators 23:30 - 00:00 0.50 CASE P INT1 Pick up 1 stand 5" HWT - Install 10 3/4" X 7 5/8" packoff as per FMC Tech - Lay down 1 stand 5" HWT 7/18/2004 00:00 - 00:30 0.50 CASE P INT1 Con't to install 1 0 3/4" X 7 5/8" packoff and test to 5000 psi for 10 mins - test good 00:30 - 01 :00 0,50 CASE P INT1 Inject 20 bbls water in outer annulus - 3 bpm @ 1050 ICP injection rate - FCP injection 900 psi 01 :00 - 02:00 1.00 CASE P INT1 Change casg rams to Drill Pipe Rams 2 7/8" X 5" - Change drill pipe saver sub on top drive 02:00 - 02:30 0.50 CASE P INT1 Test rams 2 7/8" X 5" rams to 250 low 3500 high 5 mins each test 02:30 - 03:00 0,50 CASE P INT1 Pull test plug - Install wear ring - Lay down test joint - Close annulus valves 03:00 - 05:30 2,50 CASE P INT1 Make up 6 3/4" BHA - Surface test MWD - GPM 276 @ 1960 psi 05:30 - 07:00 1.50 CASE P INT1 RIH to 5644' 07:00 - 08:00 1.00 CASE P INT1 Cut - drlg line - Top drive service 08:00 - 10:00 2.00 CASE P INT1 Test 7 5/8" casing to 2500 for 30 mins leaked off 100 psi 10:00 - 10:30 0,50 CASE P INT1 CBU - GPM 276 @ 2850 - RPM 40 - TO 2K 10:30 - 11 :30 1.00 CASE P INT1 Test 7 5/8" casing to 2500 for 60 mins lost 150 psi 11 :30 - 13:00 1.50 DRILL P INT1 Drill FIC @ 5688' - Shoe tract - FIS - Clean out 10' rathole from 5775' to 5785' - 20' new hole from 5785' to 5805' 13:00 - 14:00 1.00 CASE P INT1 CBU - Condition mud for FIT - GPM 300 - @ 2600 psi - RPM 40 - TO 2K 14:00 - 15:00 1.00 EVAL P INT1 Rig up testing equipment for FIT - MD 5775' - TVD 3867' - Mud weight 9.6 - Surface pressure 480 psi = EMW 12.0 ppg - Rig down testing equipment 15:00 - 00:00 9.00 DRILL P PROD1 Directional Drill from 5805' to 6749' - WOB 2 to 5 - RPM 85- TO on 4,5k - off 2.5k - GPM 300 - PP on 3250 - off 3130 - PU 115 - SO - 80 - ROT 100 7/19/2004 00:00 - 08:30 8.50 DRill P PROD1 Directional Drill from 6749' to 7656' - WOB 5 - RPM 80 - TO on 4.5 - off 3.5 - GPM 275 - PP on 3200 - off 3100 - PU 120 - SO 82 - ROT 103 08:30 - 10:00 1.50 DRILL P PROD1 CBU 3 X - GPM 275 - PP 2770 - RPM 80 - TO 3K - Flow check - Well static 10:00 - 12:00 2,00 DRILL P PROD1 Pump out at drlg rate from 7656' to 7276' - Back ream out from 7276' to 5741' (Shoe at 5775') 12:00 - 12:30 0.50 DRILL P PROD1 CBU - RPM 40 - TO 3K - GPM 330 - PP 3500 - Did not see any excessive cuttings on bottoms up 12:30 - 13:00 0.50 DRILL P PROD1 Rig service - Top Drive service 13:00 - 14:00 1.00 DRILL P PROD1 RIH from 5741' to 7563' - Precauctionary wash from 7563' to 7656' - Hole in good shape - No Problems 14:00 - 00:00 10.00 DRILL P PROD1 Drill From 7656' to 8617 - WOB 5 - RPM 80 - TO on 5.5 - off 4.5· GPM 275 - PP on 3090 - off 2910 - PU 130 - SO 75- ROT 105 712012004 00:00 - 06:00 6.00 DRILL P PROD1 Directional Drill from 8617 to 9253' with 275 GPM, 3100 psi, Printed: 81312004 9:14:56 AM e e Page BP Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Datè MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 7/20/2004 Hours 00:00 - 06:00 6.00 DRILL P PROD1 06:00 - 08:00 2,00 CASE P LNR1 08:00 - 11 :00 3,00 CASE P LNR1 11 :00 - 11 :30 0.50 CASE P LNR1 11 :30 - 13:30 2,00 CASE P LNR1 13:30 - 15:30 2,00 CASE P LNR1 15:30 - 16:30 1.00 CASE P LNR1 16:30 - 19:30 3.00 CASE P LNR1 19:30 - 20:00 0.50 CASE P LNR1 20:00 - 22:30 2.50 CASE P LNR1 22:30 - 00:00 1.50 CASE P LNR1 00:00 - 01 :00 1,00 CASE P LNR1 01 :00 - 06:00 5.00 CASE P LNR1 06:00 - 10:00 4.00 CASE P LNR1 10:00 - 11 :00 1,00 CASE P LNR1 7/21/2004 11:00-12:00 1.00 CASE P LNR1 12:00 - 14:30 2.50 CASE P LNR1 14:30 - 15:00 0,50 CASE P LNR1 15:00 - 16:00 1.00 CASE P LNR1 16:00 - 17:30 1.50 CASE N SFAL LNR1 17:30 - 21 :00 3,50 CASE P LNR1 21 :00 - 23:00 2.00 STWHIP P PROD2 23:00 - 00:00 1,00 STWHIP P PROD2 7/22/2004 00:00 - 00:30 0,50 STWHIP P PROD2 00:30 - 03:30 3.00 STWHIP P PROD2 03:30 - 05:30 2.00 STWHIP P PROD2 05:30 - 06:00 0.50 STWHIP P PROD2 06:00 - 10:30 4.50 STWHIP P PROD2 10:30 - 11:30 1.00 STWHIP P PROD2 Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: Description of Operations 80 RPMs, 5K bit wt. Circ, Three bottoms up, with 100 RPMs, 315 GPM, 3900 psi Pumping out to 7276, Back ream from 7276' to shoe 5,774, at full drilling rate, Hole in good condition, No packoff or drags, Circ bottoms up from csg shoe 5774, with 315 Gpm 3100 psi, 50 rpms. No increase in cutting with bottoms up, Trip to bottom 9253', wash last stand to bottom Circ Three bottoms up with 100 rpms, 297 GPM, 3500 psi, Displace well with Excluder screen 9.60BM Pumping out of hole 9253 to 5775 with full drilling rate Circ bottoms up from csg shoe 5775 with 300 GPM, 2800 psi, 40 rpms Tripping out to BHA Lay down 3,5 hwdp, Jars Mwd,Mud motor Rig up to pickup 4" screen liner, PJSM Picking up 4" screen and 4" blank liner with 4-1/2" space out tubing. Made up Baker Seal Bore Extension, Baker 7-5/8" liner hanger and ZXP liner top packer. Run in hole slowly with screen liner on 4" drill pipe. No problems. Tagged bottom at 9253' and pick up to set liner shoe at 9232', PU weight 130K Slack off weight 78K. Dropped 29/32" ball and pumped down at 3 bpm at 500 psi. Ball on seat - pressure up to 2200 psi to set liner hanger. Set down 20K to ensure hanger was set. Pressured up to 3500 psi to set ZXP packer. Bled off pressure. Closed annular preventer and attempted to test ZXP packer - would not test. Pressured up on drill pipe to 4000 psi. Closed annular preventer and tested ZXP packer to 1500 psi. Rotated 12 rounds to the right and released from liner. PU weight 115K, Displaced out new OBM out of hole with old OBM at 70 spm @ 1220 psi. Flow check - negative. Pulled out of hole with 4" drill pipe and liner setting tool. Clear floor, pull wear ring Rig up and testing BOPS and manifold 250-3500 psi 5 min per test, Hydril 250-2500 psi 5 min, per test, the right to witness test was wavier by John Crisp AOGCC., #3 valve leaking on choke manifold Repair # 3 Valve on Choke manifold Finish testing BOPS and manifold 250-3500 psi 5 min per test, Hydril 250-2500 psi 5 min. per test, the right to witness test was wavier by John Crisp AOGCC, install wear ring Picking up 4 3/4 dc and 3,5 hwdp and stand in derrick Slip and cut drilling line, service top drive Finish cutting Drill line Picking up Whipstock BHA and space out 3.5 pipe, test MWD Tripping in with Whipstock to 5000' Orient Whipstock 15 degrees to the right and set anchor with 10K down. Picked 8K over pickup weight to assure anchor was set. Set down 38K and shear running bolt on whipstock. Milled window from 5053' to 5065' with 100 RPM 270 GPM and 1700 psi. Continued with mills to 5077'. Pumped sweep and circulated 2 bottoms up 100 RPM 340 Printed: 81312004 9: 14:56 AM e e BP Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: Hours Task Code NPT 7/22/2004 10:30 - 11 :30 1.00 STWHIP P PROD2 11 :30 - 13:30 13:30 - 14:30 14:30 - 15:30 15:30 - 16:30 2.00 STWHIP P 1.00 STWHIP P 1.00 STWHIP P 1.00 STWHIP P PROD2 PROD2 PROD2 PROD2 16:30 - 18:30 2.00 STWHIP P PROD2 18:30 - 19:00 0.50 STWHIP P PROD2 19:00 - 19:30 0.50 STWHIP P PROD2 19:30 - 00:00 4.50 DRILL P PROD2 7/23/2004 00:00 - 18:30 18,50 DRILL P PROD2 18:30 - 19:00 0,50 DRILL N DPRB PROD2 19:00 - 19:30 0,50 DRILL N DPRB PROD2 19:30 - 20:00 0,50 DRILL N DPRB PROD2 20:00 - 21 :30 1,50 DRILL N DPRB PROD2 21 :30 - 00:00 2,50 DRILL P PROD2 7/24/2004 00:00 - 11 :30 11.50 DRILL P PROD2 11 :30 - 13:00 1.50 DRILL P PROD2 13:00 - 15:00 2.00 DRILL P PROD2 15:00 - 16:00 1.00 DRILL P PROD2 16:00 - 16:30 0,50 DRILL P PROD2 16:30 - 19:00 2,50 DRILL P PROD2 19:00 - 23:30 4.50 CASE P PROD2 23:30 - 00:00 0.50 CASE P PROD2 7/25/2004 00:00 - 00:30 0.50 CASE P PROD2 00:30 - 02:00 1.50 CASE P PROD2 02:00 - 03:00 1.00 CASE P PROD2 03:00 - 03:30 0,50 CASE P PROD2 03:30 - 04:00 0.50 CASE P PROD2 04:00 - 05:00 1.00 CASE P PROD2 05:00 - 06:30 1.50 CASE P PROD2 GPM 2710 PSI and 4K torque, Good cutting circulated out with sweep. Monitor well - negative, Pulled out of hole with 4' drill pipe, Standing back 3.5 hwdp,and 4 3/4 DC,Laying down mills Clear floor, picked up stack flusher, flush Bop stack Picking up BHA # 6, 6 3/4 DS146H bit wI 6- 10 jets, 4 3/4 motor with 1,5 bend,float sub,stab,Mwd,3 flex dc,jars,2 3,5 Hwdp Test MWD tool, Trip in to 4966' Service top drive Orient to 15 degrees to right of high side, Slide thru window @ 5053 to 5064 Directional Drill 5077' to 5540' with 80 rpms, 275 GPM, 2900 psi, AST .76, ART 2,34, TO 3K, P/U 115K, S/o 88K.RIT 102K Directional Drill 5540' to 7746' with 80 rpms, 275 GPM, 3000 psi, out of sand @ 7746, AST 2.5, Art 7,27 Circ bottoms up Pumped out to 7450 Working lowside trought to side track well, side track well @ 7462 Time Drill from 7462 to 7555' Directional Drill 7555' to 7842' with 80 rpms, 275 GPM, 3000 ps, AST 1.54, ART 1,31, TO 3500, P/u 11 OK. S/o 80K, RIt 100K Directional Drill 7842' to 9260' with 80 rpms, 275 GPM, 3200 psi, hole taking mud slow Circ and Reciprocate, with 310 gpm 3840 psi, 80 Rpms, treating mud, lower YP Flow check, well breathing gave back 13 bbls in 10 min., pump out of well from 9260 to 7450 with 200 gpm Worked side track, orient motor to high side, attempt to slide in to side track, went into old hole,worked in to new hole, orient to high side and back ream thru side track Trip back to bottom, no problems Circ three bottoms up with 297 gpm, 3270 psi, 80 Rpms, hole not taking any mud Flow check, well breathing small stream of mud, Pumping out with 200 gpm, orient to high side @ side track and back ream side track @ 7462, small packoff @ 7400, Pumping out to window, @ 5053, pull thru window with out pumping, flow check @ window well static Circ bottom up @ 5030, with 297 gpm 2770 psi, 40 rpms Finish, Circ bottom up @ 5030, with 297 gpm 2770 psi, 40 rpms Tripping out to BHA Std back HWdp, Jars, flex dc, lay down MWD and Motor Clear rig floor, moblize whipstock Bha Service top drive Picking up whipstock retrival BHA, Hook, 1 jt drlg pipe,float sub, MWD,bumper sub, jars,11 dc, 15 hwclp, xo surface test MWD Trip in with whipstock hook to 5020 filling drillpipe every 25 stands Printed: 81312004 9:14:56 AM e e Page 8 of 10 BP Operations Summary Report Oreint 15 degrees to the right and latch whipstock. Pulled free with 190K (70K overpull). Observed well. Hole took fluid to BOP stack. Monitor well. Well stable. Circulated bottoms up Pulled out of hole from 5080' at controlled speed Stand back HWDP, DCs and MWD. Laid down whipstock and seal assembly. Clear floor, rig up to pickup 4.5 slotted liner, PJSM Pickup 98- 4.512.6# L-80 slotted liner and 2 -4.5 12,6# 1-80 blank its, Baker Hook wall hanger Trip in with liner, went out window on first try, went in to 9229 with no problems, pickup wt 124k, slack off wt 87K, block wt, 50 K Hook liner after Three trys,@ 5065, shoe @ 9229' top liner 5048' Drop ball, pumped down @ 3 bbls min. 630 psi, pressure to 4250 to shear, and release liner, pull one stand to 4969' Slip and cut drilling line, service rig Tripping out with running tools, lay down same Clear rig floor, Rig up to pickup LEM tools,PJSM Picking up Seals, 3 its 4,512,6# L-80, Baker LEM tool and ZXP liner top packer Tripping in with LEM tool Trying to work LEM tool thru O-B hook wall hanger, going to 5078' Tripping out with LEM and lay down same, found scarring on mule shoe Pull wear ring, rig up, Test BOPS and manifold 250-35OOpsi 5 min. per test, Hydril 25D-2500psi 5 min per test, the right to witness test was wavier by Jeff Jones AOOGC, install wear ring Waiting on New LEM tools, taking off Csg Swivel, putting bend in seal it. Mobilize New LEM to pipe shed Pickup LEM and ZXP packer Tripping in to 5050 Tag up @ 5078, pickup and turn 1/2 tum,tag same spot,pickup and turn 1/4 tum, tag same spot, pickup and turn 1/4 tum, tag same spot, pickup tum 1/4 turn went in to Latch point, Pick up wt. 11 OK, slack off 95K PROD2 Rig up pup it and pump in subs, Latched in collet in O-B hook hanger, pull to 125K, slacked off with 25k on hanger, Seals @ 5246, Lem 5073 to 5037, Csg seal bore 5010, ZXP packer 4991' Drop ball, pumped to seat with rig pump @ 3 bbls min. 650 psi, pump with First Energy and set packer with 3500 psi, Release from LEM with 3800 psi Bleed drill pipe pressure to 500 psi, rig and test annulus to 2500 psi to test packer Attempt to shear ball with First Energy put 5100 psi on ball, 5 times wouldn't shear, rig down pump in sub and First Energy Tripping out wet with running tools, Laying down same Pickup up space out jts,whipstock,MWD,Orient same 11 dC,13 hwdp, surface test MWD Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 Hours Task Code NPT Phase 7/25/2004 06:30 - 07:00 0,50 CASE P PROD2 07:00 - 07:30 0.50 CASE P PROD2 07:30 - 09:30 2,00 CASE P PROD2 09:30 - 11 :30 2,00 CASE P PROD2 11 :30 - 13:00 1.50 CASE P PROD2 13:00 - 16:30 3,50 CASE P PROD2 16:30 - 19:30 3,00 CASE P PROD2 19:30 - 20:00 0,50 CASE P PROD2 20:00 - 20:30 0.50 CASE P PROD2 20:30 - 22:00 1,50 CASE P PROD2 22:00 - 00:00 2,00 CASE P PROD2 7/26/2004 00:00 - 01 :00 1.00 CASE P PROD2 01 :00 - 02:00 1,00 CASE P PROD2 02:00 - 05:00 3,00 CASE P PROD2 05:00 - 06:30 1,50 CASE N DPRB PROD2 06:30 - 10:30 4,00 CASE N DPRB PROD2 10:30 - 15:30 5,00 CASE P PROD2 15:30 - 19:00 3,50 CASE N DPRB PROD2 19:00 - 19:30 0.50 CASE N DPRB PROD2 19:30 - 20:30 1,00 CASE N DPRB PROD2 20:30 - 23:30 3.00 CASE N DPRB PROD2 23:30 - 00:00 0,50 CASE P PROD2 7/27/2004 00:00 - 00:30 0,50 CASE P 00:30 - 01:00 0,50 CASE P PROD2 01:00 - 02:00 1.00 CASE P PROD2 02:00 - 03:00 1.00 CASE P PROD2 03:00 - 05:30 2,50 CASE P PROD2 05:30 - 08:00 2,50 STWHIP P PROD3 Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: of Operations Printed: 81312004 9:14:56 AM e e BP Operations Summary Report Page 9 of 10 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 Start: 7/11/2004 Rig Release: 8/1/2004 Rig Number: Spud Date: 7/11/2004 End: Hoûrs Task Code NPT Phase 7/27/2004 08:00 - 10:00 2.00 STWHIP P PROD3 Trip in with whipstock 10:00 - 10:30 0,50 STWHIP P PROD3 Orient 17 degree to left of high side, set whipstock trip anchor w/22K, shear off 35K 10:30 - 15:30 5.00 STWHIP P PROD3 Mill window with 3-5K 65-100 rpms, 300 gpm, 2100 psi, Top of window 4840', Bottom window 4852', Drill to 4866' 15:30 - 16:30 1,00 STWHIP P PROD3 Pump sweep, Circ 1.5 bottoms up, work window 16:30 - 18:00 1,50 STWHIP P PROD3 Trip out to BHA 18:00 - 19:00 1.00 STWHIP P PROD3 Stand back DC and Hwdp, Lay down mills, mills full gauge 19:00 - 19:30 0.50 STWHIP P PROD3 Pickup Johnny Wacker, flush BOP stack 19:30 - 21:30 2.00 STWHIP P PROD3 Clear floor, Pick up BHA #9 6 3/4 Bit with 6X10s, 5" sperry drii w/1.5 bend,float sub,stab,4 3/4 HCIMlRES/GR,4 3/4 DM,4 3/4 TM, 3 flex dc,jars,2 hwdp 21 :30 - 23:00 1.50 STWHIP P PROD3 Tripping in to 4774 23:00 - 00:00 1.00 STWHIP P PROD3 Slip and cut drilling line, service top drive 7/28/2004 00:00 - 00:30 0.50 DRILL P PROD3 Orient and slide thru window 00:30 - 20:30 20.00 DRILL P PROD3 Drilling 4856' to 6979' with 280 gpm, 2900 psi, 90 rpms, 3-10K bit wt., P/U wt 120K, Slo 85K, RIt 100K, TQ 4K, Control drill, max 200 ft. per hr" AST 3.39, ART 8,53 20:30 - 22:00 1.50 DRILL P PROD3 Circ, three bottoms up,with 280 gpm, 2800 psi, 90 rpms 22:00 - 00:00 2.00 DRILL P PROD3 Pumping out to window @ 4869' with full drilling rate, pull thru window @ 4840-4852 with out pumping, pull to 4473, with out problems 7/29/2004 00:00 - 00:30 0,50 DRILL P PROD3 Circ bottoms up @ 4773 00:30 - 01 :00 0,50 DRILL P PROD3 Service top drive 01 :00 - 02:00 1.00 DRILL P PROD3 Trip to bottom, wash last stand to bottom 02:00 - 22:30 20,50 DRILL P PROD3 Drilling 6979' to 9225' with 280 gpm, 3200 psi, 90 rpms, 3-1 OK bit wt., Control drill, max 200 ft. per hr, Drilled out of the top of the OA sand at 9155'. At 8700', the hole started taking mud 5- 8 bbls hr. 22:30 - 00:00 1.50 CASE P PROD3 Circ, three bottoms up with, 280 gpm, 3000 psi, 100 rpms 7/30/2004 00:00 - 01 :00 1,00 CASE P PROD3 Finish Circ three bottoms up with, 280 gpm, 3000 psi, 100 rpms 01 :00 - 04:30 3,50 CASE P PROD3 Pumping out to Window @ 4840-4852 with full drilling rate, pull thru window with out pumping, no problems 04:30 - 05:30 1.00 CASE P PROD3 Monitor well, Circ bottoms up, @ 4735 05:30 - 07:00 1.50 CASE P PROD3 POH 07:00 - 09:00 2.00 CASE P PROD3 Stand back BHA, Download MWD 09:00 - 10:00 1.00 CASE P PROD3 Pickup whipstock Hook and mwd BHA, orient same, surface test MWD 10:00 - 11:00 1.00 CASE P PROD3 Rih with whipstock hook to 4780 11 :00 - 12:00 1.00 CASE P PROD3 Orient Hook and latch on to whipstock, pulled free 12:00 - 12:30 0,50 CASE P PROD3 Circ bottoms up 250gpm, 1700 psi 12:30 - 16:00 3.50 CASE P PROD3 Tripping out with whipstock, lay down same 16:00 - 17:00 1.00 CASE P PROD3 Clean floor, rig up to run slotted Iiner,PJSM 17:00 - 21:00 4.00 CASE P PROD3 Picking up 4.5 Slotted liner, 102Jts, 4.5,12.6#, L-80, Slotted, 2 jts 4.5 12.6# L-80 Blanks jts, baker hook wall hanger, P/U wt. 97K, SIO 85K 21 :00 - 00:00 3.00 CASE P PROD3 Tripping in with liner, went thru window on first try,P/U 130K, Slo 80K, hooked window on on fourth try, Shoe 9188', top of hook wall hanger 4835' 7/31/2004 00:00 - 01 :30 1.50 CASE P PROD3 Pumped ball down 3 bbls min. pressure up, release from liner, pressure to 4,000 with rig pump couldn't shear ball, pull one stand rigged up test pump, shear ball with 4500 psi, P/U wt Printed: 81312004 9:14:56 AM e e BP Summary Report 1 0 of 1 0 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 7/31/2004 8/1/2004 MPI-17 MPI-17 DRILL+COMPLETE DOYON DRILLING INC. DOYON 14 7/11/2004 8/1/2004 Spud Date: 7/11/2004 End: Start: Rig Release: Rig Number: From - To NPT Phase 00:00 - 01 :30 1.50 CASE P PROD3 115K 01 :30 - 03:30 2,00 CASE P PROD3 POH with running tools, lay down same 03:30 - 04:00 0.50 CASE P PROD3 Rig up to pickup LEM, PJSM 04:00 - 05:00 1,00 CASE P PROD3 Picking up LEM, Seal it., 3 its 4.5 12,6# L-80 tubing, LEM, CSG swivel,ZXP packer 05:00 - 07:30 2.50 CASE P PROD3 RIH with LEM, Landed on Hgr. 4835, seals @ 5024 07:30 - 08:00 0.50 CASE P PROD3 Drop ball, pump to seat @ 3 bbls min., 550 psi,pressure up to 2800psi for pusher tool, 3200 psi to set ZXP packer 08:00 - 09:00 1.00 CASE P PROD3 RIU First Engergy, shear ball with 5200 psi 09:00 - 11 :30 2.50 CASE P PROD3 Poh, lay down running tools 11 :30 - 13:00 1.50 CASE P PROD3 Pick up Johnny Wacker, Trip in to 4762' 13:00 - 15:00 2,00 CASE P PROD3 Displace well with 40 bbls LVT, 25 bbls HiV spacer, 40 bbls Safesurf, 25 bbls HIV spacer,9.6 brine inhibiter treated 15:00 - 16:00 1.00 CASE P PROD3 Slip and cut drill line 16:00 - 23:30 7.50 CASE P PROD3 Laying down drill pipe 23:30 - 00:00 0.50 CASE P PROD3 Clear rig floor, pull wear ring 00:00 - 01:00 1.00 RUNCOM=> RUNCMP Change saver sub on topdrive 01 :00 - 03:00 2.00 RUNCOM=> RUNCMP Moblize tubing to pipe shed, rig up to run tubing, PJSM, (waiting on ESP sheave, oil for motor) 03:00 - 08:00 5.00 RUNCOM=> RUNCMP Picking up ESP assy, fill with oil, found broken wire on the end of motor, Repair same 08:00 - 14:00 6,00 RUNCOM=> RUNCMP Picking up 2 7/8 1-80 IBT tbg" check conductivity and circ ever 1500', pickup total 144 its, 14:00 - 16:30 2.50 RUNCOM=> RUNCMP make up to hanger, P/U 82K,S/0 72, 82 lesalle clamps run 16:30 - 17:00 0.50 RUNCOM=> RUNCMP Land tubing with TWC in place,test twc to 1000 psi,End of pump 4736, Top of pump 4678,XN 4626,GLM 4470,GLM 2022, GLM 145 17:00 - 18:00 1.00 RUNCOM=> RUNCMP Nipple down BOPS, 18:00 - 21 :00 3.00 RUNCOM=> RUNCMP Nipple up 11" x 2 9/16 ESP adapter flange (had to change out dummy Penetrator) and CIW 2 9/16 5K tree, test both to 5000 psi, ./ 21 :00 - 22:00 1.00 RUNCOM=> RUNCMP Pull TWC and Set CIW 2112 type H BPV, pump out cellar, secure well, Rig release for rig move @ 2200 hrs 8/1/2004 Printed: 81312004 9:14:56 AM e e ....;l ~1.st;:,lt) '7 9' (2 ç., '(3- 17 -Aug-04 AOGCC Robin Deason 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 Re: Distribution of Survey Data for Well MPI-17 Dear Dear Sir/Madam: Enclosed are two survey hard copies and one disk with the *.PTT and *.PDF files. Tie-on Survey: Window / Kickoff Survey: Projected Survey: 0.00' MD 0.00' MD 9,253.00' MD (if applicable) PLEASE ACKNOWLEDGE RECEIPT BY SENDING AN EMAIL TO CARL.ULRICH@HALLlBURTON.COM OR SIGNING AND RETURNING A COpy OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Carl Ulrich 6900 Arctic Blvd. dt Anchorage, AK 99518 Date '1 (J lof . YUtu~ ~ Please call me at 273-3545 if you have Regards, William T. Allen Survey Manager RECEIVED SEP 0 3 2004 Alaska Oil & Gas Cons. Cornmisaion Anchorage AUachment(s) · DEFINITIVE Halliburton Sperry-Sun Milne Point Unit BPXA Milne Point MPI MPI-17 e Job No. AKZZ3171003, Surveyed: 20 July, 2004 Survey Report 13 August, 2004 Your Ref: API 500292321200 Sutface Coordinates: 6009439.29 N, 551789.57 E (70· 26'11.5176" N, 149· 34' 39.9045" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 e Sutface Coordinates relative to Project H Reference: 1009439.29 N, 51789.57 E (Grid) Sutface Coordinates relative to Structure Reference: 350.50 S, 388.52 W (True) Kelly Bushing Elevation: 68.35ft above Mean Sea Level Kelly Bushing Elevation: 68.35ft above Project V Reference Kelly Bushing Elevation: 68.35ft above Structure Reference sper"r"Y-su:1'1 CFULLING SERVIC:ES A Halliburton Company Survey Ref: svy1432 ~ Halliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 Your Ref: API 500292321200 Job No. AKZZ3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 0,00 0,000 0.000 -68.35 0.00 0,00 N 0,00 E 6009439.29 N 551789,57 E . 0,00 Tolerable Gyro - CB-SS-Gyro 170.00 0.700 54.000 101.65 170,00 0,61 N 0,84 E 6009439,91 N 551790.41 E 0.412 -0,74 262.00 0.900 60.000 193.64 261,99 1,30 N 1,92 E 6009440,61 N 551791.48 E 0.235 -1.70 356,00 0,500 317,000 287,63 355,98 1,97 N 2.28 E 6009441,28 N 551791,84 E 1,195 -1,95 450.00 2,000 254,000 381,61 449.96 1.82 N 0.42 E 6009441,11 N 551789,98 E 1.945 -0,14 AK-6 BP JFR-AK - MWD-IIFIS 574,09 5.450 218,720 505.43 573,78 3,38 S 5,35W 6009435.88 N 551784.25 E 3,214 4,76 669,91 7.050 206,960 600,68 669,03 12,17 S 10.86 W 6009427,04 N 551778.80 E 2.130 8.86 765.95 8,140 194,640 695.89 764,24 24,00 S 15,25 W 6009415,18 N 551774.49 E 2,034 11.38 862.60 11 .450 164,230 791.17 859,52 39.87 S 14.37 W 6009399,32 N 551775.48 E 6,240 8,08 958.41 13.270 162.230 884,76 953,11 59,50 S 8.43 W 6009379.74 N 551781.55 E 1.951 -0,80 1054.47 12.490 167.050 978.41 1046,76 80,12 S 2,74W 6009359,15 N 551787,39 E 1.381 -9.59 1149,00 12.730 170.630 1070,66 1139,01 100,36 S 1,25 E 6009338,94 N 551791,52 E 0,865 -16.64 1244.40 13,120 183,170 1163,66 1232,01 121,54 S 2,36E 6009317,77 N 551792,78 E 2,963 -20.99 1341,08 13,070 195,180 1257,84 1326.19 143,05 S 1,11 W 6009296,23 N 551789.46 E 2,810 -20,86 1437,22 12,260 189.970 1351.64 1419,99 163.60 S 5,72W 6009275.66 N 551784.98 E 1 .456 -19.46 1532,03 12.070 188.110 1444.33 1512,68 183,33 S 8,86W 6009255,91 N 551781.98 E 0.459 -19.38 1627,39 11,930 187.410 1537.60 1605,95 202,97 S 11,54 W 6009236,24 N 551779.44 E 0.212 -19.75 1721,93 11,940 189,670 1630,10 1698.45 222.30 S 14.44 W 6009216,89 N 551776,67 E 0.494 -19,85 1818,36 11,840 190,290 1724.46 1792,81 241.87 S 17.89 W 6009197,30 N 551773.36 E 0,168 -19.45 1914,55 11.950 188.910 1818,58 1886,93 261.42 S 21,19 W 6009177.73 N 551770.19 E 0.317 -19.19 2009,81 12,140 189,210 1911,75 1980.10 281.05 S 24.32 W 6009158.08 N 551767,20 E 0,210 -19,11 2106.17 12.450 201.620 2005.91 2074.26 300,71 S 29.77 W 6009138,38 N 551761.89 E 2.756 -16.74 e 2203,06 13,270 219.210 2100.41 2168,76 319,04 S 40,65 W 6009119.97 N 551751,13 E 4,112 -8,80 2299,30 13.760 237,640 2194,03 2262,38 333.73 S 57.31 W 6009105,17 N 551734,58 E 4.485 5.40 2329,03 13,660 242,580 2222,91 2291.26 337.24 S 63.42 W 6009101.62 N 551728,50 E 3.951 10.90 2395,04 13.640 248.190 2287.06 2355.41 343.72 S 77.56 W 6009095,04 N 551714.40 E 2,005 23,88 2491,79 14,310 264.320 2380,98 2449,33 349,15 S 100,06 W 6009089.46 N 551691,94 E 4,072 45,28 2587.39 16,020 276,200 2473,27 2541,62 348.89 S 124.94 W 6009089,54 N 551667.06 E 3,701 69,90 2637,60 17,350 284.460 2521,37 2589,72 346.27 S 139,08 W 6009092,06 N 551652.90 E 5.409 84,28 2680,52 18.500 289,670 2562,21 2630,56 342,38 S 151,69W 6009095,86 N 551640,26 E 4,595 97,33 2775.96 25.370 292.590 2650,69 2719,04 329.42 S 184,87 W 6009108,60 N 551607,00 E 7,286 132,11 2871,30 31,650 287,920 2734.44 2802,79 313,86 S 227.57 W 6009123,86 N 551564,18 E 6.985 176.70 2922,96 33,530 284,560 2777,97 2846.32 306.10 S 254.28 W 6009131.43 N 551537.42 E 5.050 204.28 3015,35 39,190 280,670 2852.35 2920.70 294,27 S 307,72 W 6009142,89 N 551483,91 E 6.613 258,90 3114.35 45.530 277.440 2925.47 2993.82 283,89 S 373,56 W 6009152,81 N 551418,00 E 6,769 325.55 13 August, 2004 - 8:18 Page 2 of 6 DrillQuest 3.03.06.006 Halliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 Your Ref: API 500292321200 Job No. AKZZ3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) ("/100ft) 3160,34 46,760 277,650 2957.34 3025,69 279.54 S 406.43 W 6009156,94 N 551385,09 E 2,695 358.70 3256,52 51,990 277,620 3019.94 3088.29 269.84 S 478,76 W 6009166.13 N 551312,70 E 5.438 431.66 3351,70 53,820 279,700 3077,35 3145.70 258.39 S 553,80 W 6009177,06 N 551237.58 E 2.595 507.57 3449,07 54.570 277,590 3134,32 3202,67 246,53 S 631.86 W 6009188,38 N 551159.43 E 1.919 586,53 3541,68 54.480 277.540 3188,06 3256.41 236,60 S 706,62 W 6009197,79 N 551084,61 E 0,107 661,93 e 3639,93 54,860 277,530 3244,88 3313.23 226.09 S 786,09 W 6009207.74 N 551005.07 E 0.387 742,07 3736.91 55.390 279,290 3300,33 3368,68 214.45 S 864.79 W 6009218,84 N 550926,29 E 1.586 821,62 3833,58 54.800 281,840 3355,65 3424,00 199,93 S 942,71 W 6009232,82 N 550848,27 E 2,248 900.85 3928,21 54.470 281.860 3410.42 3478,77 184,08 S 1018,24 W 6009248,14 N 550772.63 E 0,349 977.91 4023,17 55,270 284,370 3465.07 3533.42 166.45 S 1093.86 W 6009265.25 N 550696,89 E 2,320 1055,35 4106,70 54,610 286,180 3513,06 3581.41 148.44 S 1159.82 W 6009282,80 N 550630,81 E 1.942 1123,29 4169.74 54.660 287,200 3549.55 3617,90 133,68 S 1209,06 W 6009297,22 N 550581.47 E 1.322 1174.21 4215,26 56,510 287.760 3575,27 3643,62 122.40 S 1244,88 W 6009308,25 N 550545,57 E 4,189 1211.33 4311.29 61,890 286.700 3624.43 3692,78 98,00 S 1323,63 W 6009332,11 N 550466.65 E 5,682 1292,90 4407.65 66,620 288,830 3666.27 3734.62 71.49 S 1406,25 W 6009358.03 N 550383.85 E 5.297 1378,61 4466,62 69,190 288,910 3688.45 3756,80 53,82 S 1457.95 W 6009375,35 N 550332,03 E 4.360 1432,41 4556,25 68.450 289,070 3720,84 3789,19 26.63 S 1536,98 W 6009401,99 N 550252,82 E 0,842 1514,67 4599,85 68,940 289.170 3736,68 3805,03 13,32 S 1575,36 W 6009415.03 N 550214,35 E 1,144 1554,64 4696,00 70.440 287,610 3770,05 3838.40 15,12 N 1660,92 W 6009442.87 N 550128.59 E 2.179 1643,55 4791,87 70,040 286,510 3802.46 3870,81 41.59 N 1747.17W 6009468.75 N 550042.15 E 1.158 1732,85 4888.44 70,560 284.560 3835,02 3903,37 65,94 N 1834,76 W 6009492.48 N 549954,39 E 1.976 1823,14 4984,60 75.470 285.100 3863,10 3931.45 89.47 N 1923,64 W 6009515.40 N 549865.36 E 5.134 1914.57 e 5080,72 79,380 284,910 3884.02 3952.37 113,76 N 2014.23 W 6009539.06 N 549774,59 E 4,072 2007,82 5177,33 83.820 286,100 3898,14 3966.49 139.30 N 2106,30 W 6009563,96 N 549682,35 E 4,755 2102,72 5273,62 90.680 287,380 3902,75 3971,10 166,99 N 2198,35 W 6009591.01 N 549590.11 E 7.247 2197,93 5369.54 95,880 287.880 3897.27 3965,62 195,98 N 2289.58 W 6009619.37 N 549498,68 E 5.446 2292,53 5464,89 99,990 284,280 3884.10 3952.45 222.14 N 2380.29 W 6009644,90 N 549407,80 E 5,706 2386.17 5561,50 106,010 281,240 3862.37 3930,72 242.95 N 2472,03 W 6009665,07 N 549315,91 E 6.944 2480.03 5657,04 107.440 281.280 3834,88 3903.23 260,82 N 2561,77 W 6009682.31 N 549226.05 E 1.497 2571.44 5721.90 107.890 281,970 3815.20 3883,55 273.27 N 2622.30 W 6009694,35 N 549165.43 E 1.228 2633.17 5815,39 107,610 281,690 3786.70 3855,05 291,53 N 2709.45 W 6009711,99 N 549078.16 E 0.414 2722.09 5860.65 107.540 281.430 3773,03 3841,38 300,17 N 2751,72 W 6009720,35 N 549035.83 E 0.569 2765.19 5912.24 107,240 281.480 3757,61 3825.96 309,95 N 2799,97 W 6009729,79 N 548987,51 E 0,589 2814,37 5956.69 106,940 281.730 3744.55 3812,90 318,50 N 2841.59 W 6009738,05 N 548945,83 E 0,863 2856,80 6006,32 103,660 280,530 3731.45 3799,80 327.73 N 2888,56 W 6009746,95 N 548898.81 E 7.008 2904.63 13 August, 2004 - 8:18 Page 3 of 6 Dri/lQuest 3.03.06.006 · Halliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 Your Ref: API 500292321200 Job No. AKZZ3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 6052,70 102,780 280,050 3720,85 3789,20 335.80 N 2932,98 W 6009754,71 N 548854,33 E 2,148 2949.77 6103,81 98,870 279,340 3711.25 3779.60 344,25 N 2982.45 W 6009762,82 N 548804.80 E 7.771 2999.95 6149,08 96.750 278,660 3705,10 3773.45 351.26 N 3026,75 W 6009769,52 N 548760.45 E 4,914 3044.80 6200.08 96,120 278,080 3699,38 3767.73 358,64 N 3076,89 W 6009776.55 N 548710,27 E 1,674 3095.47 6245,02 95,190 277.850 3694,95 3763,30 364,84 N 3121,18 W 6009782.44 N 548665.93 E 2,131 3140,19 e 6295,50 92,100 278.860 3691.75 3760,10 372,16 N 3171.01 W 6009789.42 N 548616.05 E 6.439 3190,56 6341,06 90,000 279,590 3690,91 3759.26 379.46 N 3215,97 W 6009796.41 N 548571,04 E 4,880 3236,11 6392,00 90,740 280.950 3690.58 3758,93 388,54 N 3266,10 W 6009805,14 N 548520.85 E 3,039 3287.03 6437.47 89.260 281.490 3690,58 3758.93 397.39 N 3310,70 W 6009813,68 N 548476,19 E 3.465 3332.46 6488,17 93,460 281,780 3689.38 3757,73 407.61 N 3360.33 W 6009823,55 N 548426.49 E 8.304 3383.07 6532.72 91,970 282,640 3687.27 3755.62 417,02 N 3403.82 W 6009832.66 N 548382.94 E 3.861 3427.49 6582,52 93.400 282,880 3684,94 3753,29 428,00 N 3452,34 W 6009843,31 N 548334.35 E 2,912 3477.12 6628,86 91,360 282,900 3683.01 3751.36 438,33 N 3497.47 W 6009853,32 N 548289,14 E 4.402 3523.30 6679,05 89.570 282,920 3682,60 3750,95 449.54 N 3546,38 W 6009864,20 N 548240,15 E 3,567 3573,36 6725.22 90,680 281,340 3682.50 3750.85 459,25 N 3591.52 W 6009873.58 N 548194.95 E 4.182 3619.45 6774.87 89,570 280,860 3682.40 3750.75 468,80 N 3640.24 W 6009882,80 N 548146.16 E 2.436 3669,06 6819,35 88.020 281.340 3683,33 3751,68 477.37 N 3683,88 W 6009891.06 N 548102.47 E 3,648 3713.49 6868.67 88.140 281.590 3684.98 3753.33 487.16 N 3732.19 W 6009900.52 N 548054,09 E 0.562 3762.73 6915,83 89.570 281,840 3685,93 3754,28 496.74 N 3778,35 W 6009909,78 N 548007.86 E 3,078 3809.82 6964,17 88,080 282.000 3686.92 3755.27 506,72 N 3825,64 W 6009919.43 N 547960,50 E 3,100 3858,08 7011.17 90,990 281,100 3687.30 3755.65 516,13N 3871,68 W 6009928,52 N 547914.40 E 6.481 3905.02 7057,36 90.430 280,730 3686.73 3755.08 524,87 N 3917.03 W 6009936,95 N 547868,99 E 1 .453 3951.18 e 7106,53 89,320 280,580 3686,83 3755.18 533.96 N 3965,35 W 6009945,71 N 547820.60 E 2.278 4000.32 7154,28 91.480 280.240 3686.50 3754.85 542,59 N 4012.31 W 6009954,01 N 547773,59 E 4,579 4048.05 7203,66 90.430 280,680 3685,68 3754,03 551.56 N 4060,87 W 6009962,63 N 547724,97 E 2,305 4097.40 7246,93 92.100 280.150 3684,72 3753.07 559.38 N 4103.41 W 6009970,16 N 547682,37 E 4.049 4140,64 7299.75 90.990 279,030 3683,30 3751.65 568.17 N 4155.47 W 6009978,59 N 547630.25 E 2.985 4193.44 7346.43 90,560 278.700 3682,67 3751,02 575.36 N 4201.59 W 6009985.46 N 547584,09 E 1.161 4240,11 7395,81 90,060 280,000 3682.40 3750,75 583.39 N 4250.31 W 6009993,15 N 547535,31 E 2.821 4289.49 7440,07 87,900 280,760 3683.19 3751.54 591.36 N 4293,84 W 6010000,82 N 547491.73 E 5.173 4333,72 7489.19 87.340 280.740 3685,23 3753,58 600.51 N 4342,05 W 6010009,64 N 547443.45 E 1.141 4382,77 7534,63 86,850 280.950 3687,53 3755,88 609.05 N 4386,62 W 6010017.87 N 547398,82 E 1.173 4428.13 7582.00 86.360 279,850 3690.33 3758.68 617.59 N 4433,13 W 6010026,08 N 547352,25 E 2,538 4475,39 7637.40 86,720 280.460 3693.68 3762.03 627,34 N 4487.57 W 6010035.45 N 547297.76 E 1.277 4530,68 7682.60 87.470 281.410 3695,97 3764,32 635.90 N 4531.89 W 6010043.71 N 547253.38 E 2,676 4575.79 13 August, 2004 - 8:18 Page 4 of6 DrillQuest 3.03.06.006 · Halliburton Sperry-Sun Survey Report for Milne Point MPI - MPI-17 Your Ref: API 500292321200 Job No. AKZZ3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0'100ft) 7733.41 88,760 280,050 3697.64 3765.99 645.36 N 4581,78 W 6010052,81 N 547203.42 E 3,688 4626,54 7779,08 91,240 277,850 3697.64 3765.99 652.46 N 4626.89 W 6010059.60 N 547158,26 E 7.259 4672.21 7829.89 90,190 278,020 3697,01 3765,36 659.47 N 4677,21 W 6010066,27 N 547107.90 E 2.093 4723,00 7875,21 91.300 282.950 3696.42 3764.77 667.72 N 4721.75 W 6010074.20 N 547063.30 E 11.149 4768,29 7925.71 90.430 283,850 3695,65 3764,00 679.42 N 4770,87 W 6010085,56 N 547014,10 E 2.479 4818.62 e 7970.98 90,740 285.170 3695.19 3763,54 690,76 N 4814.69 W 6010096,60 N 546970,20 E 2.995 4863.66 8021.27 89.200 286,650 3695,22 3763.57 704.54 N 4863,05 W 6010110,05N 546921.74 E 4.247 4913.57 8066,23 90,680 284.620 3695.27 3763,62 716,66 N 4906.35 W 6010121,86 N 546878,36 E 5.588 4958,21 8116,78 90,560 286,200 3694,72 3763,07 730,09 N 4955,08 W 6010134,96 N 546829.54 E 3,134 5008.42 8164,14 90.740 285,680 3694,18 3762.53 743.10 N 5000,61 W 6010147.64 N 546783,92 E 1.162 5055.41 8214,35 90.250 282,200 3693,75 3762.10 755.19 N 5049.33 W 6010159.40 N 546735.11 E 6.999 5105.41 8260,36 89.750 281.240 3693.75 3762.1 0 764.54 N 5094,38 W 6010168.43 N 546690,00 E 2.353 5151,36 8307.70 88,770 280.660 3694.36 3762.71 773,53 N 5140.86 W 6010177.10 N 546643.47 E 2.405 5198.67 8355.67 90,060 279,500 3694.85 3763,20 781,92 N 5188.08 W 6010185,17 N 546596.18 E 3,616 5246.62 8405,75 91.480 279.460 3694,18 3762.53 790.17 N 5237.47 W 6010193,07 N 546546,74 E 2.837 5296,69 8451.25 92,100 278.770 3692.75 3761,10 797.38 N 5282.38 W 6010199,96 N 546501,79 E 2,038 5342.17 8500,93 91.670 278,800 3691,12 3759.47 804,96 N 5331,45 W 6010207.21 N 546452,66 E 0.868 5391.82 8548.00 91.420 279.280 3689,85 3758.20 812.35 N 5377,91 W 6010214.28 N 546406.14 E 1.149 5438.87 8594.82 90,680 279,690 3688,99 3757,34 820,07 N 5424.09 W 6010221,67 N 546359,92 E 1.807 5485,68 8640,20 91.480 281.410 3688,14 3756.49 828.37 N 5468,69 W 6010229.67 N 546315.26 E 4,179 5531.03 8684,57 90.370 281,350 3687.42 3755.77 837.13N 5512.18 W 6010238.12 N 546271,71 E 2,505 5575.35 8737,64 91 .480 280.860 3686.56 3754,91 847,35 N 5564.25 W 6010247,98 N 546219.57 E 2.286 5628,37 e 8788,82 90.250 280,930 3685,79 3754.14 857.02 N 5614,50 W 6010257.30 N 546169.25 E 2.407 5679.51 8833,75 92,720 280.760 3684,63 3752,98 865,47 N 5658,61 W 6010265.44 N 546125,09 E 5,510 5724.40 8878.72 91,610 280,980 3682,93 3751.28 873,94 N 5702,74 W 6010273.61 N 546080,90 E 2.516 5769.30 8929.75 90,000 281,120 3682.21 3750,56 883,72 N 5752.82 W 6010283,04 N 546030,76 E 3,167 5820,29 8978,14 90.870 281,170 3681,84 3750.19 893.08 N 5800,29 W 6010292.07 N 545983.22 E 1,801 5868.64 9026,81 93,830 281,900 3679,85 3748,20 902.80 N 5847.93 W 6010301.46 N 545935.51 E 6,264 5917,21 9072.69 97,070 281,880 3675.49 3743,84 912,21 N 5892.62 W 6010310,56 N 545890,76 E 7.062 5962.81 9121,54 96.620 281,190 3669.67 3738.02 921.91 N 5940.14 W 6010319.92 N 545843,17 E 1.678 6011.26 9182.44 96,490 281,070 3662,72 3731.07 933,58 N 5999,51 W 6010331,19 N 545783.73 E 0,290 6071.71 ,J 9253,00 96.490 281.070 3654,74 3723.09 " 947.05 N 6068.31 W 6010344,17 N 545714,83 E 0.000 6141.76 Projected Survey All data is in Feet (US Survey) unless otherwise stated. Directions and coordinates are relative to True North, Vertical depths are relative to Well. Northings and Eastin9s are relative to Well. Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4, 13 August, 2004 - 8:18 Page 50f6 DrillQuest 3.03.06.006 .. Héllliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 Your Ref: API 500292321200 Job No. AKZZ3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit The Dogleg Severity is in Degrees per 100 feet (US Survey), Vertical Section is from Well and calculated along an Azimuth of 278.830° (True), Based upon Minimum Curvature type calculations, at a Measured Depth of 9253.00ft" The Bottom Hole Displacement is 6141 ,76ft., in the Direction of 278,870° (True), Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) e Comment 9253,00 3723,09 947.05 N 6068,31 W Projected Survey Survey tool program for MPI-17 From Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth Survey Tool Description (ft) (ft) 0,00 450,00 0.00 449,96 450,00 9253.00 449.96 Tolerable Gyro - CB-SS-Gyro 3723.09 AK-6 BP _'FR-AK - MWD-IIFR-MS e 13 August, 2004 - 8:18 Page 60f6 Dri/lQuest 3.03.06.006 - RECE\\lEO SEP 0 :) ZQOL\ O\\&.Gascon&.c~ AOGCC ~ ~ -R-ob,jrl.Qo3son 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 e 17 -Aug-04 Re: Distribution of Survey Data for Well MPI-17 MWD Dear Dear Sir/Madam: Enclosed are two survey hard copies and one disk with the *.PTT and *.PDF files. Tie-on Survey: Window / Kickoff Survey: Projected Survey: 0.00' MD 0.00' MD 9,253.00' MD (if applicable) PLEASE ACKNOWLEDGE RECEIPT BY SENDING AN EMAIL TO CARL.ULRICH@HALLlBURTON.COM OR SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Carl Ulrich 6900 Arctic Blvd. Anchorage, AK 99518 Date '1 f /ðf Please call me at 273-3545 if you have any questions or concerns. Regards, William T. Allen Survey Manager Attachment(s) :<,o'f -:_~T7 1/ ~,,/'-- - ,) Halliburton Sperry-Sun Milne Point Unit BPXA Milne Point MPI MPI-17 MWD e Job No. AKMW3171003, Surveyed: 20 July, 2004 Survey Report 17 August. 2004 Your Ref: API 500292321200 Surface Coordinates: 6009439.29 N, 551789.57 E (70026'11.5176" N, 149034' 39.9045" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 e Surface Coordinates relative to Project H Reference: 1009439.29 N, 51789.57 E (Grid) Surface Coordinates relative to Structure Reference: 350.50 S, 388.52 W (True) Kelly Bushing Elevation: 68.35ft above Mean Sea Level Kelly Bushing Elevation: 68.35ft above Project V Reference Kelly Bushing Elevation: 68.35ft above Structure Reference !5pe............y-!5ul! DRILLING SE~VIC:ES A Halliburton Company Survey Ref: svy1448 Halliburton Sperry-Sun Survey Report for Milne Point MPI - MPI-17 MWD Your Ref: API 500292321200 Job No. AKMW3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 0,00 0,000 0,000 -68,35 0,00 0,00 N 0,00 E 6009439,29 N 551789,57 E 0,00 Tolerable Gyro - CB-SS-Gyro 170,00 0,700 54,000 101,65 170,00 0.61 N 0,84 E 6009439,91 N 551790,41 E 0.412 -0,74 262,00 0,900 60,000 193,64 261,99 1,30 N 1,92 E 6009440,61 N 551791.48 E 0,235 -1,70 356,00 0,500 317,000 287,63 355,98 1.97 N 2.28 E 6009441 ,28 N 551791,84 E 1.195 -1,95 450,00 2,000 254,000 381,61 449,96 1,82 N 0.42 E 6009441 ,11 N 551789,98 E 1,945 -0,14 MWD Magnetic e 574,09 5.450 219,320 505.43 573.78 3,34 S 5,39W 6009435,91 N 551784.20 E 3,200 4.82 669,91 7,050 207,320 600,68 669,03 12,08 S 10,98 W 6009427.13 N 551778,68 E 2.147 8,99 765,95 8,140 194,360 695,89 764,24 23,91 S 15,37 W 6009415,28 N 551774,37 E 2,107 11,52 862,60 11 .450 163.940 791.17 859,52 39.77 S 14.41 W 6009399.42 N 551775.44 E 6,242 8,14 958.41 13,270 161,870 884,76 953.11 59.36 S 8.36W 6009379,87 N 551781,62 E 1,955 -0,85 1054.47 12.490 167,300 978.41 1046,76 79,97 S 2,64W 6009359,30 N 551787.48 E 1 .498 -9,66 1149,00 12.730 170,520 1070.66 1139,01 100,22 S 1,32 E 6009339,08 N 551791,59 E 0.786 -16.69 1244.40 13,120 183,310 1163.66 1232,01 121.40 S 2,43 E 6009317,91 N 551792.84 E 3.020 -21,03 1341.08 13,070 195,140 1257,84 1326,19 142,91 S 1,06W 6009296.38 N 551789,50 E 2,768 -20,89 1437,22 12.260 189,630 1351,65 1420,00 163.47 S 5,61 W 6009275.79 N 551785,09 E 1,512 -19.55 1532,03 12,070 187.550 1444,33 1512,68 183,22 S 8,60W 6009256,01 N 551782.25 E 0,504 -19.63 1627,39 11 ,930 187,150 1537,60 1605,95 202.88 S 11.13 W 6009236,33 N 551779.85 E 0,171 -20,14 1721.93 11,940 189,620 1630,10 1698.45 222,22 S 13,98 W 6009216,98 N 551777.13 E 0,540 -20,29 1818,36 11,840 190,290 1724.46 1792,81 241,79S 17,42 W 6009197,39 N 551773.83 E 0,177 -19,90 1914,55 11,950 188,830 1818,59 1886.94 261,34 S 20,71 W 6009177.81 N 551770.68 E 0,333 -19,65 2009.81 12,140 189,890 1911,75 1980.10 280,95 S 23,94 W 6009158,18 N 551767.58 E 0,306 -19.47 2106,17 12.450 202,180 2005.92 2074,27 300,56 S 29,61 W 6009138,54 N 551762,05 E 2,730 -16,88 e 2203,06 13,270 219.430 2100.41 2168.76 318,82 S 40,62 W 6009120,19 N 551751,17 E 4,036 -8,81 2299,30 13.760 237,780 2194,03 2262,38 333.46 S 57,32 W 6009105.44 N 551734,56 E 4.466 5.46 2329,03 13,660 242,790 2222.91 2291,26 336,95 S 63.44 W 6009101,90 N 551728.47 E 4.007 10,96 2395,04 13.640 248,190 2287,06 2355.41 343.41 S 77.60 W 6009095.35 N 551714.36 E 1,930 23,96 2491,79 14,310 264,530 2380,98 2449,33 348,79 S 100.10W 6009089,81 N 551691,90 E 4,123 45,37 2587.39 16,020 276.430 2473.27 2541,62 348.44 S 124.97 W 6009089,99 N 551667,02 E 3,706 70.01 2637.60 17,350 284,660 2521,37 2589.72 345,77 S 139,11 W 6009092,56 N 551652.87 E 5.394 84,38 2680,52 18,500 289,900 2562,21 2630,56 341,83 S 151,70 W 6009096.41 N 551640.25 E 4,612 97.43 2775.96 25,370 292,830 2650,69 2719.04 328,73 S 184,82 W 6009109,29 N 551607,03 E 7,287 132,17 2871,30 31,650 288,140 2734.44 2802,79 313,00 S 227.47 W 6009124.72 N 551564,28 E 6,988 176,72 2922,96 33.530 284,730 2777,97 2846,32 305.15 S 254.15 W 6009132,38 N 551537,54 E 5.086 204.30 3015,35 39.190 280,970 2852,35 2920,70 293,09 S 307,54 W 6009144,07 N 551484.08 E 6,582 258,90 3114,35 45,530 277,620 2925.48 2993,83 282.45 S 373,33 W 6009154,26 N 551418,21 E 6,796 325,55 17 August, 2004 - 10:16 Page 2 of6 DrillQuest 3.03.06.006 Halliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 MWD Your Ref: API 500292321200 Job No. AKMW3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (a/100ft) 3160,34 46.760 278.020 2957,34 3025,69 277,93 S 406,18 W 6009158.54 N 551385,33 E 2,747 358,71 3256.52 51,990 277,730 3019,94 3088,29 267,94 S 478.47 W 6009168,03 N 551312,97 E 5.443 431.67 3351,70 53,820 279.900 3077,35 3145,70 256,29 S 553.48 W 6009179,16 N 551237,88 E 2,646 507,58 3449.07 54,570 277.190 3134,32 3202,67 244,57 S 631,56 W 6009190,34 N 551159,72E 2,385 586,53 3541,68 54.480 277,260 3188,07 3256.42 235,08 S 706,38 W 6009199,31 N 551084,84 E 0,115 661.92 e 3639.93 54,860 277,220 3244,88 3313,23 224,98 S 785,90 W 6009208,86 N 551005,25 E 0,388 742,05 3736,91 55,390 278,770 3300,34 3368,69 213,91 S 864,68 W 6009219,38 N 550926.40 E 1.421 821,60 3833,58 54,800 281.480 3355,66 3424,01 199,99 S 942,71 W 6009232.76 N 550848,27 E 2,379 900.84 3928,21 54.470 281.770 3410.43 3478.78 184.44 S 1018,30 W 6009247,79 N 550772.58 E 0.429 977.92 4023.17 55,270 284,350 3465,08 3533.43 166,88 S 1093,94 W 6009264,82 N 550696.81 E 2,376 1055,36 4106,70 54,610 286,050 3513,06 3581.41 148,96 S 1159,92 W 6009282,28 N 550630,71 E 1,844 1123,31 4169,74 54.660 286,780 3549,55 3617,90 134.43 S 1209.23 W 6009296.47 N 550581,30 E 0,948 1174,26 4215.26 56,510 287,750 3575.28 3643,63 123,28 S 1245,09 W 6009307,36 N 550545,37 E 4.428 1211.41 4311.29 61,890 286,240 3624.43 3692,78 99,21 S 1323,95 W 6009330,89 N 550466,34 E 5,763 1293,03 4407,65 66,620 289.430 3666,28 3734,63 72,60 S 1406,52 W 6009356,93 N 550383,59 E 5.743 1378,71 4466,62 69,190 289,500 3688.46 3756,81 54,39 S 1458,03 W 6009374,78 N 550331,95 E 4,360 1432.40 4556,25 68.450 290,050 3720,85 3789,20 26,11 S 1536,68 W 6009402,50 N 550253,11 E 1,005 1514.46 4599,85 68,940 290,950 3736,69 3805,04 11,89 S 1574.73 W 6009416.47 N 550214.97 E 2,227 1554,24 4696,00 70.440 287.940 3770.07 3838.42 18.11 N 1659,74 W 6009445.88 N 550129,74 E 3,325 1642,85 4791,87 70,040 286,180 3802.48 3870.83 44,58 N 1745,99 W 6009471,75 N 550043,31 E 1,777 1732,14 4888.44 70,560 284,760 3835,04 3903,39 68,83 N 1833,61 W 6009495,39 N 549955,52 E 1 .485 1822.45 4984,60 75.470 284,620 3863.12 3931.47 92,14 N 1922,55 W 6009518.08 N 549866,43 E 5,108 1913,91 e 5080,72 79,380 283.080 3884,04 3952,39 114,59 N 2013,62 W 6009539,89 N 549775,21 E 4,358 2007,34 5177,33 83.820 282,140 3898,15 3966,50 135.44 N 2106,86 W 6009560,10 N 549681.82 E 4,695 2102.68 5273,62 90.680 280,670 3902,77 3971.12 154.45 N 2201,08 W 6009578.45 N 549587,47 E 7.285 2198,70 5369,54 95,880 282.660 3897,28 3965,63 173.80 N 2294,83 W 6009597,15 N 549493.59 E 5,803 2294,31 5464,89 99,990 280,030 3884,12 3952,47 192,38 N 2387.39 W 6009615.09 N 549400,90 E 5,103 2388,63 5561 ,50 106,010 280,010 3862.40 3930,75 208,75 N 2480,05 W 6009630,81 N 549308.13 E 6,231 2482.70 5657,04 107.440 280,800 3834.90 3903,25 225.27 N 2570,04 W 6009646,71 N 549218,03 E 1,693 2574,16 5721,90 107.890 278,050 3815.22 3883,57 235,39 N 2631,00 W 6009656,41 N 549157,00 E 4,099 2635.95 5815,39 107,610 278,770 3786,72 3855,07 248.42 N 2719,08 W 6009668,82 N 549068,83 E 0,792 2724.99 5860,65 107,540 281,540 3773,05 3841 .40 256.02 N 2761.55 W 6009676,13 N 549026,31 E 5.837 2768,12 5912,24 107,240 281,520 3757,63 3825,98 265,86 N 2809,78 W 6009685,64 N 548978.01 E 0,583 2817.29 5956,69 106,940 281,820 3744,57 3812,92 274.46 N 2851,39 W 6009693,94 N 548936,34 E 0.934 2859,73 6006,32 103,660 280,650 3731.47 3799,82 283,78 N 2898,34 W 6009702,94 N 548889.33 E 6,989 2907,55 17 August, 2004· 10:16 Page 3 of6 DrillQuest 3.03.06.006 Halliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 MWD Your Ref: API 500292321200 Job No. AKMW3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/1 DOft) 6052,70 102,780 280,160 3720,86 3789,21 291,93 N 2942,75 W 6009710,78 N 548844,87 E 2,158 2952.68 6103,81 98,870 279,500 3711.27 3779,62 300,50 N 2992,20 W 6009719,00 N 548795,35 E 7,755 3002,87 6149,08 96,750 278,760 3705,12 3773.47 307,62 N 3036.48 W 6009725,81 N 548751,03 E 4,955 3047,71 6200,08 96,120 278,160 3699.40 3767.75 315.D7N 3086,61 W 6009732,92 N 548700,85 E 1,701 3098.39 6245,02 95.190 277,760 3694,97 3763,32 321,26 N 3130,90 W 6009738,80 N 548656,52 E 2,251 3143,11 e 6295,50 92,100 279.400 3691,76 3760,11 328.78 N 3180,70 W 6009745.97 N 548606,66 E 6,927 3193.48 6341,06 90,000 280,250 3690,93 3759,28 336,55 N 3225,59 W 6009753.44 N 548561,72 E 4,972 3239,02 6392,00 90,740 281,580 3690,60 3758,95 346,20 N 3275.60 W 6009762,73 N 548511,64 E 2,988 3289.92 6437.47 89,260 282,090 3690,60 3758,95 355,52 N 3320,10 W 6009771,75 N 548467,08 E 3.443 3335,33 6488,17 93.460 282,320 3689.40 3757,75 366,24 N 3369,63 W 6009782.12 N 548417.48 E 8,296 3385,91 6532,72 91,970 282,700 3687,29 3755,64 375.87 N 3413,07 W 6009791.45 N 548373,97 E 3.451 3430.32 6582.52 93.400 282,630 3684,95 3753.30 386,78 N 3461,61 W 6009802,02 N 548325,36 E 2,875 3479.95 6628,86 91,360 282,500 3683.03 3751,38 396,85 N 3506,80 W 6009811,78 N 548280,10 E 4.411 3526,15 6679,05 89,570 282.920 3682,62 3750,97 407,89 N 3555,75 W 6009822.48 N 548231,07 E 3,663 3576,22 6725,22 90,680 281,780 3682,52 3750,87 417,77 N 3600,85 W 6009832,04 N 548185,90 E 3.446 3622,31 6774.87 89.570 281.960 3682.41 3750,76 427,98 N 3649.44 W 6009841.92 N 548137,24 E 2,265 3671,89 6819,35 88,020 282,600 3683,35 3751,70 437.44 N 3692,89 W 6009851,08 N 548093,73 E 3,770 3716,27 6868,67 88,140 282.400 3685,00 3753.35 448.11 N 3741,02 W 6009861.41 N 548045,53 E 0,473 3765.46 6915,83 89,570 282,740 3685,94 3754.29 458,37 N 3787,04 W 6009871,35 N 547999.44 E 3,117 3812,51 6964,17 88,080 281.750 3686,93 3755,28 468,62 N 3834,26 W 6009881,27 N 547952,14 E 3.700 3860,76 7011,17 90.990 281.070 3687,31 3755,66 477.92 N 3880,33 W 6009890,25 N 547906,02 E 6,358 3907,70 7057,36 90.430 280.410 3686,74 3755,09 486.52 N 3925,71 W 6009898.54 N 547860.58 E 1,874 3953,86 e 7106.53 89,320 280.450 3686,85 3755.20 495.42 N 3974,06 W 6009907,11 N 547812,16 E 2,259 4003,01 7154.28 91.480 280.290 3686.52 3754.87 504,02 N 4021,03 W 6009915,37 N 547765,14 E 4.536 4050,74 7203,66 90.430 280.480 3685.69 3754,04 512,92 N 4069,59 W 6009923.94 N 547716,51 E 2.161 4100,09 7246,93 92,100 280.450 3684,74 3753,09 520.78 N 4112,13 W 6009931,50 N 547673.92 E 3,860 4143.33 7299,75 90.990 279,550 3683,31 3751.66 529,94 N 4164,13 W 6009940.31 N 547621,86 E 2.705 4196,12 7346.43 90,560 279,200 3682,68 3751.03 537,55 N 4210,18 W 6009947.59 N 547575,76 E 1,188 4242,80 7395,81 90,060 280,130 3682.42 3750,77 545,84 N 4258.86 W 6009955,54 N 547527.03 E 2,138 4292,17 7440,07 87,900 280,390 3683.20 3751,55 553,72 N 4302,40 W 6009963,12 N 547483.43 E 4.915 4336.41 7489,19 87,340 279,920 3685,24 3753,59 562,37 N 4350,71 W 6009971.44 N 547435,06 E 1.488 4385.47 7534,63 86,850 279.600 3687,55 3755,90 570,07 N 4395.43 W 6009978,82 N 547390,28 E 1,287 4430,85 7582,00 86,360 279,720 3690,35 3758.70 578,00 N 4442,05 W 6009986.43 N 547343.61 E 1,065 4478,13 7637.40 86,720 279,870 3693,69 3762,04 587.41 N 4496,54 W 6009995,46 N 547289,06 E 0.704 4533.42 7682,60 87.470 281,250 3695,99 3764,34 595.68 N 4540,92 W 6010003.42 N 547244,63 E 3.471 4578.54 17 August, 2004 - 10:16 Page 4 of6 DrillQuest 3.03.06.006 Halliburton Sperry-Sun Survey Report for Milne Point MPI- MPI-17 MWD Your Ref: API 500292321200 Job No. AKMW3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 7733.41 88,760 280,000 3697,66 3766.01 605,04 N 4590,83 W 6010012.44 N 547194,65 E 3,534 4629,29 7779,08 91,240 277,800 3697,66 3766,01 612,11 N 4635.94 W 6010019,19 N 547149.49 E 7,259 4674,96 7829,89 90,190 278,280 3697,02 3765,37 619,21 N 4686,25 W 6010025.95 N 547099,14 E 2,272 4725,76 7875,21 91,300 282,990 3696.43 3764,78 627,57 N 4730,77 W 6010034,00 N 547054,55 E 10.676 4771,04 7925,71 90.430 284,090 3695,67 3764,02 639.40 N 4779,86 W 6010045.48 N 547005,38 E 2,777 4821,36 e 7970,98 90,740 285.370 3695,21 3763,56 650,91 N 4823.64 W 6010056,68 N 546961,53 E 2,909 4866,39 8021.27 89.200 286,820 3695.23 3763,58 664,85 N 4871.96 W 6010070.29 N 546913,11 E 4.206 4916,27 8066,23 90,680 284,830 3695,28 3763,63 677,11 N 4915,21 W 6010082.25 N 546869,78 E 5,516 4960,89 8116,78 90,560 286,340 3694,73 3763,08 690,69 N 4963,90 W 6010095.49 N 546821,00 E 2,996 5011,09 8164,14 90,740 285,840 3694,20 3762,55 703,81 N 5009.40 W 6010108,30 N 546775.41 E 1,122 5058,06 8214,35 90,250 282.480 3693,76 3762,11 716,09 N 5058,07 W 6010120,24 N 546726,65 E 6,762 5108.05 8260,36 89,750 281.450 3693,76 3762,11 725,63 N 5103.08 W 6010129.47 N 546681,57 E 2.488 5153,99 8307,70 88,770 280,780 3694,37 3762,72 734.76 N 5149,53 W 6010138,27 N 546635,06 E 2.508 5201.29 8355.67 90.060 279,850 3694,86 3763,21 743,34 N 5196,72 W 6010146.53 N 546587,81 E 3,315 5249,24 8405,75 91.480 279,680 3694,19 3762.54 751,84 N 5246,07 W 6010154,68 N 546538.41 E 2,856 5299,30 8451,25 92,1 00 278.870 3692,77 3761.12 759,17 N 5290,95 W 6010161,70 N 546493.47 E 2,241 5344,78 8500,93 91.670 278,780 3691,14 3759.49 766,78 N 5340,02 W 6010168,97 N 546444,36 E 0,884 5394.43 8548,00 91 .420 279,280 3689,87 3758.22 774,17 N 5386.49 W 6010176.04 N 546397.84 E 1.187 5441.48 8594,82 90,680 279,760 3689,01 3757,36 781,91 N 5432,65 W 6010183.46 N 546351,62 E 1,884 5488.29 8640.20 91.480 281.470 3688,15 3756,50 790,27 N 5477.25 W 6010191,51 N 546306,97 E 4,160 5533,64 8684,57 90,370 281,360 3687.44 3755,79 799.05 N 5520,73 W 6010199,98 N 546263.42 E 2.514 5577,96 8737.64 91.480 280.870 3686,58 3754,93 809,28 N 5572,80 W 6010209.85 N 546211,28 E 2.286 5630.98 e 8788,82 90.250 281.060 3685,81 3754.16 819,01 N 5623,04 W 6010219.24 N 546160,98 E 2.432 5682,12 8833,75 92.720 280.850 3684.64 3752,99 827,55 N 5667,13 W 6010227.46 N 546116,83 E 5,517 5727,00 8878,72 91,610 281.240 3682,94 3751,29 836,16 N 5711,24 W 6010235,77 N 546072,66 E 2,616 5771,90 8929,75 90.000 281,280 3682,23 3750,58 846.12 N 5761,28 W 6010245,38 N 546022,56 E 3,156 5822,88 8978,14 90,870 281.470 3681,86 3750.21 855.66 N 5808,72 W 6010254,60 N 545975.05 E 1.840 5871.22 9026,81 93,830 282,380 3679,87 3748,22 865.71 N 5856,29 W 6010264,31 N 545927.41 E 6,362 5919,77 9072,69 97,070 282,220 3675,51 3743,86 875.44 N 5900,91 W 6010273,73 N 545882,73 E 7,070 5965,35 9121,54 96.620 281,190 3669,69 3738,04 885.28 N 5948.40 W 6010283.24 N 545835.17 E 2,287 6013.79 9182.44 96.490 281.100 3662,73 3731.08 896,97 N 6007.76 W 6010294.52 N 545775.72 E 0,259 6074.25 ..... 9253,00 96.490 281,100 3654,76 3723,11 910.47 N 6076,56 W 6010307,54 N 545706,84 E Projected Survey 0,000 6144,30 All data is in Feet (US Survey) unless otherwise stated, Directions and coordinates are relative to True North, Vertical depths are relative to Well. Northings and Eastings are relative to Well, Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4, 17 August, 2004 - 10:16 Page 50f6 DrillQuest 3.03.06.006 Halliburton Sperry-Sun Survey Report for Milne Point MPI - MPI-17 MWD Your Ref: API 500292321200 Job No. AKMW3171003, Surveyed: 20 July, 2004 BPXA Milne Point Unit The Dogleg Severity is in Degrees per 100 feet (US Survey), Vertical Section is from Well and calculated along an Azimuth of 278,8300 (True), Based upon Minimum Curvature type calculations, at a Measured Depth of 9253,00fl., The Bottom Hole Displacement is 6144,39fl., in the Direction of 278,521 0 (True). Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) e Comment 9253,00 3723,11 910.47 N 6076.56 W Projected Survey Survey tool proøram for MPI-17 MWD Fro m Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth Survey Tool Description (ft) (ft) 0,00 450,00 0.00 449,96 450,00 9253,00 449,96 Tolerable Gyro - CB-SS-Gyro 3723.11 MWD Magnetic e 17 August, 2004 - 10:16 Page 60f6 DrillQuest 3.03.06.006 Winton, Please use this one instead. Pat Archey Sr. Drilling Engr. Wk.-564-5803 Cell 240-8035 -----Original Message---- From: Archey, Pat Sent: Monday, September 20, 2004 11 :00 AM To: Winton Aubert (E-mail) Subject: Surface Casing Grade correction for Milne Point Wells 14, 16, 17 & 19 a ~~ A-I\-l oA.\ ~o '/¡ This update is to correct the surface casing grade used in Milne Point I-Pad wells MPI-14, MPI-16, MPI-17, MPI-19. There were 3 joints of L-80 casing run at surface and K-55 from that point to TO. Change was as follows: 'Z o6.y~ç Well Hole Size Casing Size Weight Grade Coupling Winton, MPI-14 13-1/2" 10-3/4" 45.5# K-55 & L-80 BTC-M MPI-16 12-1/4" 9-5/8" 40# K-55 & L-80 BTC-M MPI-17 13-1/2" 10-3/4" 45.5# K-55 & L-80 BTC-M MPI-19 13-1/2" 10-3/4" 45.5# K-55 & L-80 BTC-M Please let me know if you need anything else. Pat Archey Sr. Drilling Engr. Wk.-564-5803 Cell 240-8035 Content-Type: application/ms-tnef Content-Encoding: base64 - STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Diverter Systems Inspection Report Submitto: Urn re<:¡Q~admìn.5t:::i0..ak.us aùgccnPudl1oe...bay@admin.state.a1<.us bob.. f:E:ckensÎE;in@:~drn¡n siatø. ak, us Date: 11-Jul-04 Development X Exploratory: PTD # 204-098 Rig Ph, # 670-3268 Drlg Contractor: Doyon Operator: BP Exploration FieldlUnit & Well No,: MP 1-17 Location: Sec. 33 T. 13N MISC. INSPECTIONS: Location Gen,: Pass Housekeeping: Pass Reserve Pit: NIA Well Sign: (Gen,) Drlg. Rig: Flare Pit: Yes Pass NIA DIVERTER SYSTEM INSPECTION: Diverter Size: 21 1/4" in. Divert Valve(s) Full Opening: Yes Valve(s) Auto & Simultaneous: Yes Vent Line(s) Size: 16 in, Vent Line(s) Length: 77 ft, Line(s) Bifurcated: No Line(s) Down Wind: No Line(s) Anchored: Yes Turns Targeted I Long Radius: No e R. Operation: Rig No. Oper, Rep.: Rig Rep.: 10E Green I Brown Eghlom I Gouchenauer Merdian UM 14 ACCUMULATOR SYSTEM: Systems Pressure: 3150 psig Pressure After Closure: 2000 psig 200 psi Attained After Closure:_ min ~ sec. Systems Pressure Attained: 3 mim 20 sec, Nitrogen Bottles: 4 @ 2250 psi psig MUD SYSTEM INSPECTION: Trip Tank: Mud Pits: Flow Monitor: Light P P P Alarm P P P GAS DETECTORS: Methane Hydrogen Sulfide: Lig ht P P Alarm P P Doyon 14 ...................................:........... ·:.:..·:.....:.:...·....................·þl'\fE:R@g:$¢8$.MAT'P.......·..··.·.····::::::·:·········· . North .- Non Compliance Items _ Repair Items Within Remarks: c=J Day (5) And contact the Inspector @ 659-3607 OPERATOR REP.: Green I Brown AOGCC REP.: Waived by Chuck Sheave Diverter Test (for rigs) BFL 05/29/03 Diverter Doyon 14 7-11-2004,xls 14 day BOP test intervaI--Doyon 14 , . e ... Subject: 14 day BOP test interval--Doyon 14 From: Thomas Maunder <tom_maunder@admin.state.ak.us> '0 U / ~f"\ C~ (1// Date: Thu, 08 Jul 2004 11 :39:32 -0800 C7 - ~ ~ U - 'v Õ To: Walter Quay <QuayWD@BP.com> cc: Skip Coyner <Skip.Coyner@asrcenergy.com>, Pat Archey <archeypj@bp.com>, Jim Regg <jimJegg@admin.state.ak.us>, AOGCC North Slope Office <aogcc -yrudhoe _ bay@admin.state.ak.us> Walter, et al: I have received your letter requesting a 14-day BOP test interval on Doyon 14 at Milne Point. In your letter, you note that Doyon 14 has been operating for some time at Milne and that 21 BOP tests have been performed in past 6 months. In that time, 1 major item (annular) failed during testing on 1 occasion and 4 "auxiliary equipment items" failed on 3 occasions. No failures were experienced on the remaining 17 (81%) of the tests. Any failed item was promptly repaired/replaced and successfully passed a new test. I concur that the BOP test record for 14-day interval would be employed beginning with the next well According to Skip the You have approval to adopt the 14-day interval on Doyon 14. Please note that as worded, the new regulation says the testing interval is ".. .not to exceed..." 14 days. As I understand, requests to exceed 14 days are unlikely to be granted. Please call with any questions. Tom Maunder, PE AOGCC '-.c... "Yo '{ Ð '"" \ '-\ \" '\ ~ ~'\ \ «:. \ ~. Od 1 of 1 7/8/2004 11 :40 AM ~ -- e 06 July 2004 Tom Maunder Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Request for a maximum 14-day BOPE test frequency for Doyon 14 Dear Tom: BP Exploration (Alaska) Inc. ("BP") would like to request an exception to 20 AAC 25.035(e)(10)(A) per 20 AAC 25.035(h)(1) for a maximuml4-day BOPE test frequency for the Doyon 14 drilling rig. In the first 6 months 2004, Doyon 14 performed 21 successful BOPE tests. In these 21 tests, other auxiliary equipment failed on three occasions. On 30 J an, the upper IBOP failed and was repaired. On 26 Mar, a gas detector and a floor valve failed and were repaired. On 18 May, the mop valve failed and was repaired. On 01 June, the Annular Preventer failed and was repaired. The BOPE test reports are available if required. The BOPE test record for Doyon 14 is thus good. If you have any questions or require any additional information, please contact the undersigned at 564-5581 Sincerely, ¿J,¡'ler{)~"7 by fSÆJ...y Walter Quay / Drilling Engineer BP Exploration (Alaska) Inc. ¡:F'~~p~\, ~: ~'t. ~ ~ .¡~. ~..'=. ~¿ ·U'li n (,i 7004 J LV() Oiì ty . . FRANK H. MURKOWSKI, GOVERNOR A 1,~tiliA OIL AND GAS CONSERVATION COMMISSION 333 W, 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Pat Archey Senior Drilling Engineer BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska 99519-6612 Re: Milne Point MPI-17 BP Exploration (Alaska) Inc. Permit No: 204-098 Surface Location: 2323' NSL, 3581' WEL, SEC. 33, T13N, RlOE, UM Bottomhole Location: 3306' NSL, 4361' WEL, SEC. 32, T13N, R10E, UM Dear Mr. Archey: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659 ager). S' c J Chair BY ORDER OF 'tHE COMMISSION DA TED thìs~11iay of June, 2004 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. II Drill 0 Redrill 1 a, Type of work 0 Re-Entry 2, Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O, Box 196612, Anchorage, Alaska 99519-6612 4a, Location of Well (Governmental Section): Surface: 2323' NSL, 3581' WEL, SEC, 33, T13N, R10E, UM ,/ Top of Productive Horizon: 2720' NSL, 1610' WEL, SEC. 32, T13N, R10E, UM j Total Depth: 3306' NSL, 4361' WEL, SEC. 32, T13N, R10E, UM ,j 4b. Location of Well (State Base Plane Coordinates): Surface: X-551790 ,j y-6009440 if Zone-ASP4 .I 16, Deviated Wells: Kickoff Depth 1ß.Oasing Program Size CasinQ 20" 10-3/4" 7-5/8" I STATE OF ALASKA . ALASKA IL AND GAS CONSERVATION COMMISSIßtr, b~'¢~_ 4<>""'-" PERMIT TO DRILL ..- 20 MC 25.005 N o:~ ¿004 1b. Current Well Class 0 Exploratory. II Dev~I.?pm91tOjl, ..0 Muijip~,~ o Stratigraphic Test 0 Service )!\Jã:~i.pmenU3as'EJ Slhgl'é zðí\~' 5. Bond: a Blanket 0 Single Well 11, Well ~J8nUfNumber: Bond No. 2S100302630-277 MPI-17 6. Proposed Depth: j 12, Field / Pool(s): MD 9237' j TVD 3734" Milne Point Unit I Schrader Bluff 7. Property Designation: ."th_ D25"~b; Z>< ADL 025517 . Ai.¡;~::..cf. 8, Land Use Permit: 13, Approximate Spud Date: June 30, 2004 ~ Hì 9, Acres in Property: 2560 14. Distance to Nearest Property: 2030' 4"x5" Length 80' 2320' 5950' 3962' 10, KB Elevation 15. Distance to Nearest Well Within Pool (Height above GL): Plan 69 feet MPI-10 is 1050' away 17, Maximum Anticipated Pressures in psig (see 20 AAC 25,035) Downhole: 1875./ psig Surface: 1478 ,/ psig Se~¡ng Depth Top .... ... 'i,iBottolTl MD TVD MD TVD 34' 34' 114' 114' 30" 30' 2350' 2319' 30' 30' 5980' 3880' 5275' 3989' 9237' 3734' Hole 42" 13-1/2" 9-7/8" 6-3/4" 300 ft Maximum Hole Angle 1080 Specifrcations Grade CouplinQ H-40 Weld L-80 BTC-M L-80 BTC-M L-80 4" IBT Weight 92# 45.5# 29,7# (including staQe data) 260 sx Arctic Set (Approx.) 417 sx AS Lite, 273 sx Class 'G' 762 sx Class 'G' Screen Assembly 19. PRESENTWE;I..L OONDITIQN SUMMAßY(To b~CQmpl~teØ.for~eØriU ,A.NPREt~nfJ'yOpe.r~tio!\$) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Depth TVD Junk (measured): Structural Conductor Surface Intermediate Production liner 20, Attachments a $100 Filing Fee 0 BOP Sketch a Property Plat 0 Diverter Sketch perfOration Depth TVD (ft): a Drilling Program 0 Time vs Depth Plot o Seabed Report a Drilling Fluid Program o Shallow Hazard Analysis a 20 AAC 25,050 Requirements Date: Perforation Depth MD (ft): 21. Verbal Approval: Commission Representative: 22, I hereby certify that the foregoing is true and correct to the best of my knowledge, Printed Name Pat Archey Title Senior Drilling Engineer Phone 564-5803 Date fb -. 2 -0 Y Contact Skip Coyner, 564-4395 Prepared By Name/Number: Terrie Hubble, 564-4628 Other: DYes ,.ø)'Jo DYes .,gJ No Date: Mud Directional Survey Required See CQver letter for other requirements D Yes .~o ~Yes D No Permit To Drill 1/ API Number: Number: 2£.J'-{'-Cf78 50- L)2-cl- 2-,3.2/2 ~CÚ Conditions of Approval: Samples Required Hydrogen Sulfide Measures V"'-ð~ ~\? '~k- Approved Bv: Form 10-401 Revised 12i~3 BY ORDER OF ~ ! rd/\ THE COMMISSION (ì Q \ i ¡ 1 \ r"\ L Date ~t"'4c/ V ~;;:: t o':p{¡cate . . - bp I Well Name: I MPI-17 Primary Wellbore / NB Lateral Drill and Complete Plan Summary I Type of Well (service I producer I injector): 1 Schrader Bluff Tri-Lateral Producer Surface Location: (As Staked) Target Location: Top NB Target Location: BHL NB Lateral 9,237' 2,323' FSL, 3,581' FEL, SEC. 33, T13N, R10E E = 551,790' N = 6,009,440' 2,720' FSL, 1,610' FEL, SEC. 32, T13N, R10E E = 548,477' N = 6,009,814' Z = 3,779' TVD 3,306' FSL, 4,361' FEL, SEC. 32 , T13N, R10E E = 545,721' N = 6,010,382' Z = 3,954' TVD v " Distance to Property line 2030' Distance to nearest pool 1037' from MPI-10 I AFE Number: I Estimated Start Date: 110 June 04 Rig: 1 Doyon 14 Rig days to complete: 121 MD: \9237' 1 1 TVD: 13734' 1 1 Max Inc: 11 080 1 I KOP: 1300' I I KBE: 169 Well Design (conventional, slim hole, etc.): I Tri-Lateral Producer Objective: I Schrader Bluff NB, OB & OA 1 Mud Program: 13-1/2" Suñace Hole !øQbª¡~;{(PQ§ 9.0 - 9.3 10 - 20 9-7/8" Intermediate Hole Density (ppg 9.4 - 9.6 10 - 20 . . LSND API Filtrate LG Solids 25 - 30 10 - 11 9.0 - 9.5 < 6 < 15 - 5980'): . yp. HTHP 25 - 30 10 - 11 LSND API Filtrate LG Solids 9.0 - 9.5 < 6 < 15 - 9237'): ·HTHP 10 - 11 9.0 - 9.5 MOBM / <6 <15 LCM Restrictions: No Organic LCM products in the Schrader Bluff formation Waste Disposal: NO ANNULAR INJECTION. Drill Cuttings taken to DS-4 disposal site Call the Pad 4 waste disposal site prior to truck leaving location so the site can be ready to unload waste. Exempt liquid wastes can be taken to DS-4 or Phillips KRU 1 R. 10-3/4", 45.5#, L-80, BTC Surface Casing at 2,350' MD Excess from B/Permafrost to Surface = 175% over gauge hole. Use 40% excess below the B/Permafrost. Tail cement = 500' MD. Total Cement 10 bbl water Volume: 387 bbl Wash 25 bbl CW 100 75 bbl of MudPush 330 bbl, 417 sx of Arctic Set Lite: 10.7 ppg and 4.44 fe/sx 57 bbl, 273 sx "G" mixed at 15.8Ib/gal & 1.17 fr3/sx Casing Point BHST 450 F (estimated by Dowell) 7 -5/8", 29.7#, L-80, BTC-M Intermediate Casing at 5,980' MD Top of cement to be 500' MD above Ugnu sands: 40% excess. Shoe Joint = 85 ft. 5-bbl water 25 bbl CW 100 40 bbl of MudPush 158 bbl, 762 sx "G" mixed at 15.8 Ib/gal & 1.16 ft,j/sx BHST =80°F from SOR Cement Program: Casing Size Basis Spacer Lead Tail Temp Casing Size Basis Total Cement Volume: 158 bbl Wash Spacer Tail Temp 2 '\ . Evaluation Program: 13-1/2" Section Open Hole: . Cased Hole: MWD/GR IFRlCASANDRA Sperry InSite N/A 9-7/8" Section Open Hole: MWD/GRlRES IFRlCASANDRA Sperry InSite Cased Hole: N/A 6-3/4" Section Open Hole: MWD/GRlRES/ABI IFRlCASANDRA Sperry InSite Cased Hole: N/A Formation Markers: Formation Tops MD TVD (ft) Pore Pressure (ft) (psi) BPRF 1,809 1,789 TUZC 3,600 3,294 1400 Ugnu-MA 3,982 3,522 1499 Ugnu-MB1 4,000 3,533 1504 Ugnu-MB2 4,071 3,575 1522 Ugnu-MC 4,310 3,700 1577 SBF2-NA 4,421 3,746 1768 SBF1-NB 4,468 3,763 1776 SBE4-NC 4,561 3,795 1791 SBE2-NE 4,617 3,814 1800 SBE1-NF 4,760 3,863 1824 TSBD-Top OA 4,877 3,903 1843 TSBC-Base OA 4,984 3,936 1859 TSBB-Top OB 5,125 3,969 1875 SBA5-Base OB 5,248 3,987 1884 TSBB-Top OB Upgoing 5,730 3,954 1868 TSBC-Base OA Upgoing 5,850 3,919 1851 TSBD-Top OA Upgoing 5,970 3,882 1833 SBEI-NF Upgoing 6,110 3,842 1814 SBE1-NE Upgoing 6,295 3,796 1792 SBE4-NC Upgoing 6,420 3,779 1783 SBFI2-Base NB Sand Upgoing 6,565 3,771 1779 NB owe 4,163 OA owe 4,189 OBowe 4,167 3 EMW (Ib/gal)* 8.2 8.2 8.2 8.2 8.2 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 v 9.1 9.1 9.1 9.1 9.1 9.1 9.1 . . CasinglTubing Program Hole Size Csg/·· . wtIFt· ;Grade . Conn Length· . 'TOp . Tbg O.D. ..; MD I TVD 42-in 20-in* 92# H-40 Welded 80' 34' 114' 1114' 13.5 in 10.75-in 45.5# L-80 BTC-M 2,320' 30' 2,350' 12,319' 9.875 in 7.625-in 29.7# L-80 BTC-M 5,950' 30' 5,980' 1 3,880' 6.75 in 4" X 5" Screens L-80 4" IBT 3,962' 5,275' 1 3,989' 9,237' 1 3,734' NB and 4" Blanks 6.75 in 4.5-in 12.6# L-80 BTC 4,090' 5,015' 13,944' 9,215' 13,Q54' OB Slotted 6.75 in 4.5-in 12.6# L-80 BTC 4,340' 4,750' 1 3,899' 9,205' 1 3,879' OA Slotted Recommended Bit Program: BHAHole Size . Depth (MD) ; Footage 1 13.50 in Surf - 2,350' 2,320' 2 9.875 in 2,350' - 5,980' 3,630' 3NB 6.750 in 5,980' - 9,237' 3,257' 30e 6.750 in 5,125' - 9,215' 4,090' 30A 6.750 in 4,865' - 9,205' 4,340' Well Control: Intermediate/Production hole: · Maximum anticipated BHP: · Maximum surface pressure: · Planned BOP test pressure: · Integrity tests: Kick tolerance: · Planned completion fluid: Bit Type MXC1 PDC PDC PDC PDC TFA .85 - 1.0 .60 - .85 .35 - .50 .35 - .50 .35 - .50 ..··GPM.· 450 - 650 500 - 600 275 - 325 275 - 325 275 - 325 1,875 psi at 3,969' TVD (Top of the OB sand) ý' 1,478 psi at (Based on a full column of gas at 0.1 psi/ft) / 3,000 psi FIT to 12.0 Ib/gal 20' below the 10-3/4" shoe. 38-bbl with 9.3 Ib/gal mud at below the 10-3/4" shoe. MOBM in Laterals with 9.8 ppg Brine and Diesel above. Drilling Hazards & Contingencies: · Hydrates have been encountered on I-Pad wells between 1,700' and 2,300' TVD. · Tight hole and packing off due to clays and poor hole cleaning has occurred on I Pad wells. · Sloughing 1 caving coal beds have been encountered on I Pad. · Over-Pressured sands have been encountered on I Pad due to offset injection wells. 4 Lost Circulation · We do not expect losses while drilling this well. · Offset wells have not reported losses while drilling. However if seepage and/or losses occur, follow the LOST CIRCULATION DECISION MATRIX in the well plan. Break circulation slowly in all instances and get up to recommended circulating rate slowly prior to cementing. . . Expected Pressures · The Schrader Bluff sands were over-pressured from offset injection wells while drilling 1-12 & v 1-13. That situation has since been rectified. v Pad Data Sheet · Please Read the I-Pad Data Sheet thoroughly. Breathing · Not expected or predicted. Hydrocarbons · Hydrocarbons will be encountered in the Ugnu through the Schrader Bluff. / Faults · Three faults are mapped in the intermediate hole section: one near the top of the Ugnu at :!:. 3608' MD, one near the BINB at:!:. 4414' MD, and one near the BlOB at:!:. 5500' MD. · Three faults are mapped that intersect the "NB" lateral: one at:!:. 6410' MD, one at:!:. 8450' MD, and the final fault at :!:. 8715' MD. Hydrogen Sulfide · MPI Pad is not designated as an H2S Pad.'; Anti-collision Issues · MPI-17 passes the Major Risk Criteria in the Mother Bore and all laterals. Gyro surveys will be required for close approach issues and magnetic interference down to:!:. 1200 ft MD. Distance to Nearest Property · MPI-17 is 2,030 ft from the nearest Milne Point property line. ¡ Distance to Nearest Well Within Pool · MPI-17 is 1,050 ft from the nearest Schrader Bluff NB sand penetration in MPI-10. .J 5 · . DRILL & COMPLETION PROCEDURE Pre-Ria Operations 1. The 20" conductor will be installed pre-rig. Drillina 1. MIRT and NU Diverter 2. Function Test Diverter, PU 4" DP and BHA. 3. Drill 13.5" surface hole. 4. Run and cement 10.75" surface casing. 5. NO diverter, install wellhead and NUlTest BOP. 6. Drill 9.875" intermediate hole. 7. Run and cement 7-5/8" intermediate casing. 8. Displace to MOBM. Drill 6-3/4" NB horizontal production hole. 9. Run 4" x 5" sand-control screens and blank combination liner. 10. Run whipstock and mill window for OB lateral. 11. Drill 6-3/4" OB horizontal production hole. 12. Retrieve whipstock. 13. Run 4.5" slotted liner and hang off in 7.625" casing 14. Run whipstock and mill window for OA lateral. 15. Drill 6-3/4" OA horizontal production hole. 16. Retrieve whipstock. 17. Run 4.5" slotted liner and hang off in 7.625" casing 18. Displace MOBM with Brine 19. RU and Run 2.875" ESP Completion. 20. NO BOP/NU Tree 21. Freeze Protect. 22. RDMO Doyon 14. 6 . \J I ASP GRID",\ - Z - 2'34'41" I I-PAD PLANT) Ç^Å--T--T--T--Á-Á--Á~ I I ¡-< I I I I-< 1 I ¡-< 1 I k 1 I I r' I 1 I-< I 1 :~ I I k I 1 I r' 1 I k I I 1 ¡-< I 1 r I ¡ ~ ¡ I I >-I I I J I 1 >-i I I I ~I 1 I >-I I I J I I I >-I I I ;.J 1 I I 'l I , >-i I I I >-1 I I ! ¡ : , , ~: , : , , ~ ! , o.-i : , I f-- -'L - - - - 'i _ - - __ L_ __ J _ _ _ _ _1_ ___ _ _l_) . NOTES 1. ALASKA STATE PLANE COORDINATES ARE ZONE 4, ALASKA, NAD 27. 2. PAD SCALE FACTOR IS 0.9999031 3, HORIZONTAL & VERTICAL CONTROL IS BASED ON MPU I-PAD MONUMENTS 1-1 AND 1-2. 4. DATE OF SURVEY: MAY 9, 2004. 5. REFERENCE FIELD BOOK: MP04-03 PAGES 58-59. .14 .13 .12 .11 .8 · 7 .4 .6 · 3 · 5 · 2 · 9 .1 .10 .15 +1-16 +1-17 ",' ~ \ N,T.S. LEGEND + AS-STAKED CONDUCTOR . EXISTING CONDUCTOR o EXISTING AS-STAKED CONDUCTOR LOCATION 018 019 ¡ ¡-< MPU I-PAD LOCATED WITHIN PROTRACTED SEC. 33, T. 13 N., R. 10 E" UMIAT MERIDIAN, ALASKA v WELL A.S.P. PLANT GEODETIC GEODETIC PAD SECTION NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D,DD) ELEVATION OFFSETS I 16 Y= 6,009,440,87 N 1,120.00 70'26'11.535" 70.4365375' 34.7' 2,324' FSL - X= 551,759.58 E 1,465.00 149'34'40.784" 149.5779956' 3,611' FEL I 17 Y= 6,009,439.52 N 1,120.00 70'26'11.520" 70.4365333' 34.7' 2,323' FSL J - X= 551,789.55 E 1,495.00 149'34'39.905" 149.5777514' 3,581' FEL v ~ ~~., DRAWN: ObP JACOBS CHECKED: ALUSON DAlE: 5/10/04 DRAWING: MilNE POINT UNIT I-PAD SHEET; FRB04 MPI 02-00 1 ffi1E~[I)(~o Joe NO: SCALE: AS-STAKED CONDUCTORS o 5/10/04 .SSUED FOR 'NFORMAllON JJ RF'A ENGINŒRSN«Il...IHDM~ WELLS MPI-16 & MPI-17 1 OF 1 1IDI'IiIEST FlRE'/IEEtI LAlU¿ 1'=150' NO, DAl< REVISION BY CHK ANC!4ORAGE, ALASKA teo3 11II MPI..17 Mother II bore And uN Lateral ..4 ~ 10~3/4", MPI..17 Inverted Tri-lateral NB, OA & OB Producer l~80. BTC at 2350' MD 9-7/8" Hole with lSND Mud NB Sand: 3730' ~ 3780' TVD 6~3/4" Hole with MOBM 9237' MD 5890' MD 7 ~5/8" 1 08° S REFERENCE INFORM.'\. nON SURVEY PROGRAM Plan; MPr~17 wpl2 (plan MPr~ 17 Thor/Plan MPl~ t 7 Depth Fm Depth To SurveylPlan Too' Created By: Troy ltdœ.büs:ky Date: 4/17/2004 6930 !200.00 45 CB-G,,¡ Cheeked; Date;~ 69Jû '.200.00 9236.92 45 MWD" Revîewed; Date:_ WELL DETAILS TARGET DET.ftJLS Nmw +NJ-S +EJ-W - - Latitude Longitude Slot """" TVD ~NJ-S ~E!-W Northí!1ß Ea5ring Sbape Plan MPI·17 Thor 104L19 1550.92 6009439.52 55!7ß9.55 70"26'll.520N [49"34'39.9Q5W NlA SECTION DETAILS COMPANY DETAILS BPAIJIDCO ",- y¥~ ! ;ï"'2 ¡fo~ I :~' 2 IS' ¡:: 3 :~ I 4 ,""" 5 6 :~¡ 1Jt 4 i ; 7 .. FORMATION TOI' DETAILS 8 :fJ :: j ! 9 ;;- \ No. TVDl'afu MDl'ath Formation 10 -' J! < : /' I ~! 12 -~' I 2 13- MI'I-17 TU 1 3 14 : 4 ~~: :i 15 ¡I' MPI-17 Casing 1 ',~ I 5 16 : 6 17 j I 7 18 ::~ MI'I-17 T2.2 /' S 19 , 9 2() ~ :~ ¡'!òC !() 21 MI'I-17 n.2 ¡¡ 22 ~ -5 ¡g ~ 12 1 23 9, -6 MI'I-17 T4.2 13 i . 14 ; ¡~:: ;.n IS 1 1 Iii, ¡. i CASING DETAILS I I . '!I I i I I J I No, TVD MD Name Size . .. . i : ßfR i.~,I,~ i ¡ I ./' 2 I 3 U) <'HI I.. . I ..... T '.. , , I , , I ¡ " j , 1 ....... + iiL I ! ~~. ~~ ~IJM, T' j I iàh J I I I I" f , I ,'''' i I··f ,_,_, \1 ~~ ....; ; I ; , .... I Ill", I ...... '\11 I I , ¡¡ , ~ I "T I ; ~"" 'jIQ-1b _, ìl ~--=- '" .- , , , j 1 ¡ J i , , , , , I , , , , , I , , , , , , , , , , I , , , I ! ¡ I ! ! , , , \ j \ Target VSec TFace DLeg +EI-W +NI-S TliD Azi !nc MD See 24()()- 320()- 4()0()- ';;¡' ;j;i '" '" !S t ¡:J -æ " E '" > ~ I 7200 6400 5600 4S()0 2400 3200 4000 Vertical 1600 800 o . . Current Datum: Magnetic Data: Field Strength: Vertical Section: 69,3 RKB(34.3 + 35} 3/11/2004 57552 nT Depth From (TVD) ft 69.30 BP Planning Report Principal: Yes Date: 4/1912004 Time: 09:02:11 Refereaee: Well: Plan MPI-17 Thor, T ereace: 69.3 RKB(34.3 + 35) 69. Section Dee: Well (O.OON,0.OOE.278 Survey Calculatioø Method: Minimum Curvature Date Composed: Version: Tied-to: Compauy: Field: Site: Well: Wellpath: Plan: BP Amoco Milne Point MPtIPad Plan MPI-17 Thor Plan MPI-17 MPI-17 wp12 Field: Milne Point North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Site: M pt I Pad TR-13-10 UNITED STATES: North Slope Site Position: NorthiDg: 6008388.01 ft From: Map Easting: 550245,83 ft Position Uncertainty: 0,00 ft Ground Level: 0.00 ft Well: Plan MPI-17 Thor Well Position: +N/-S 1041.19 ft +E/-W 1550.92 ft Position Uncertainty: 0,00 ft Northing: 6009439 52 Easting: ~~ft H~ <)~/-S :::>~ .., 0, 0 La' de: L gitude: Drilled From: ~ Tie-on Depth: Above System J)Q Declination: Mag Dip Angle: ~ +E/-W ft 0.00 £:\/ Well Ref. Point , . 69,30 ft Mean Sea Level 24,94 deg 80,85 deg Direction deg 278.83 Wellpath: Plan MPI-17 Casing Points MD TVD Diameter ft ft in 2349,94 2319.30 10,750 103/4" 5980.00 3879.51 7.625 7 5/8" 9236.00 3734.34 4,500 5" Screens Formations MD TV» Lithology Dip Angle Dip DireetiOD ft ft deg deg 1809,08 1789,30 BPRF 0,00 0,00 3600,26 3294,30 TUZ 0,00 0,00 3981,98 3522.30 U u-MA 0,00 0,00 4000,39 3533.30 nu-MB1 0.00 0.00 4070.77 3575.30 gnu-MB2 0.00 0.00 4310.45 3700.30 Ugnu-MC 0,00 0.00 4421.37 3746,30 SBF2-NA 0,00 0.00 4468.02 3763,3 SBF1-NB 0,00 0.00 4561.46 3795 SBE4-NC 0,00 0.00 4617,01 381 ,30 SBE2-NE 0,00 0.00 4760,28 3 3,30 SBE1-NF 0.00 0,00 4877,23 903,30 TSBD-Top OA 0,00 0,00 4984,09 3936.30 TSBC-Base OA 0.00 0,00 5125.40 3969.30 TSBB-Top OB 0.00 0,00 5248. 3987,30 SBAS-Base OB 0.00 0.00 . . BP Planning Report Company: BP Amoco Date: 4/19/2004 Time: 09:02:11 Field: Milne Point Co-ordinate(NE) Referenee: Well: Plan MPI-17 Site: MptlPad Vertieal (TVD) Rererenee: 69.3 RKB(34.3 + WeD: Plan MPI-17 Thor Seetion (VS) Rererenee: Well (O.CON,O. .278.83Azi) WeDpath: Plan MPI-17 Survey Calculation Method: Minimum Cu lUre Db: Oracle Targets Map <- Longitude· ~ Name Description TV» +N/-8 +EI-W Northing Beg Min See Dip. Dir. ft ft ft ft MPI-17 T4,2 3734.30 942,74 -6068.74 6010340,01 70 26 20.767 N 149 37 38,034 W MPI-17 T3.2 3764.30 782,38 -5299.76 70 26 19,196 N 149 37 15,460 W MPI-17 T2.2 3779,30 373.53 -3312,36 70 26 15,186 N 149 36 17,122 W MPI-17 Poly 3779,30 114.90 600954 . 0 549715.00 70 26 12,647 N 149 35 40.774 W -Polygon 1 3779,30 1123.02 6010 ,00 545676,00 70 26 22,540 N 149 37 39.147 W -Polygon 2 3779,30 766.71 601 63.00 545573.00 70 26 19,035 N 149 37 42.234 W -Polygon 3 3779,30 154,62 6 9574.00 548891,00 70 26 13.035 N 149 36 4.953 W -Polygon 4 3779,30 -128,50 09299.00 550058.00 70 26 10.254 N 149 35 30.754 W -Polygon 5 3779,30 129,92 6009558.00 550144.00 70 26 12.796 N 149 35 28.179 W -Polygon 6 3779.30 483,82 6009904,00 549010,00 70 26 16.273 N 149 36 1,397 W MPI-17 Casing T 3874.30 290.71 6009710,00 548880,00 70 26 14,373 N 149 36 5,250 W MPI-17 T1 ,2 3969,30 114.90 6009540,00 549715,00 70 26 12,647 N 149 35 40,774 W Plan Section Information MD Incl Azim TV» +N/-S +EI-W DLS Build Tum TFO Target ft deg deg ft ft ft deg/100ft deg/100ft deg/100ft deg 69,30 0,00 0.00 69,30 O. 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0,00 300,00 0 0.00 0.00 0.00 0,00 0,00 500.00 3.00 180,00 499,91 .23 0.00 1.50 1.50 0,00 180,00 800.00 9.00 180,00 798,13 6.58 0.00 2.00 2.00 0.00 0,00 1000.00 11.00 180,00 995.08 -71.31 0.00 1.00 1.00 0,00 0,00 1972.79 11.00 180,00 1950.00 -256.92 0.00 0.00 0,00 0,00 0,00 3275,99 49,00 282,07 3097.38 -280,06 -517.07 4,00 2,92 7.83 110.78 3385,00 53,32 282,80 3165.72 -261.77 -599,96 4,00 3,97 0.67 7,73 4059,58 53,32 282.80 3568. -141,92 -1127,55 0,00 0,00 0,00 0,00 4479,28 70,00 285.00 3767 9 -52,96 -1484,70 4,00 3,97 0.52 7.18 4779,28 70,00 285.00 38 .80 20,00 -1757,00 0,00 0,00 0.00 0.00 4874,85 70,00 285.00 3 2,49 43.24 -1843,75 0,00 0,00 0,00 0.00 5125.40 79.05 289.47 69,30 114,90 -2074,00 4.00 3,61 1.79 26,10 MPI-17 T1.2 5827.26 107,97 276.60 3926,63 272,15 -2747,58 4,50 4,12 -1.83 -23.86 5996.91 107,97 276,60 3874,30 290.71 -2907.88 0.00 0.00 0,00 0,00 MPI-17 Casing T 6172.28 104.16 283. 3825,73 320.02 -3073.70 4.30 -2.17 3,86 119,31 6212.92 104.16 283, 3815,78 329.14 -3112.03 0.00 0.00 0,00 0,00 6421.51 96.00 28 ,62 3779,30 373.53 -3312.36 4.00 -3.91 -0,84 -167,86 MPI-17 T2.2 6566.67 90.19 2 1,62 3771.46 402.72 -3454,27 4.00 -4.00 0,00 -179,98 8403,01 90.19 81,62 3765,26 772.68 -5252.94 0.00 0.00 0,00 0,00 8450,83 92.10 281,78 3764,30 782.38 -5299.76 4.00 3.99 0.33 4.69 MPI-17 T3,2 8453,01 92.19 281,78 3764.22 782,82 -5301.89 4,00 4,00 0,00 0.00 9236,92 92,19 281,78 3734.30 942,74 -6068,74 0,00 0,00 0.00 0.00 MPI-17 T4,2 . . BP Planning Report Survey 69,30 0.00 0.00 0,00 0.00 0.00 -1550.92 -1041,19 CB-GYRO-MS 100.00 0.00 0.00 30,70 0.00 0,00 -1550.92 -1041.19 CB-GYRO-MS 200.00 0.00 0.00 130,70 0.00 0,00 -1550,92 -1041.19 CB-GYRO-MS 300.00 . 0.00 0.00 230,70 0.00 0,00 -1550.92 -1041,19 CB-GYRO-MS 400.00 1.50 180,00 330,69 -1.31 0,00 -1550,92 -1039,88 CB-GYRO- 500.00 3.00 180,00 430,61 -5.23 0,00 -1550,92 -1035.95 600.00 5.00 180.00 530,36 -12.21 0,00 -1550,92 -1028.98 700.00 7.00 180.00 629,81 -22.66 0,00 -1550.92 -1018.53 800.00 9.00 180,00 728,83 -36.58 0,00 -1550,92 -1004,61 900.00 10.00 180.00 827.46 -53.08 0,00 -1550,92 -988.10 1000.00 11,00 180.00 925,78 -71.31 0,00 -1550,92 CB-GYRO-MS 1100.00 11,00 180.00 1023,94 -90.39 0,00 -1550,92 CB-GYRO-MS 1200.00 11,00 180.00 1122,11 -109.47 0,00 -1550.92 MWD+IFR+MS 1300.00 11.00 180.00 1220,27 -128.55 0,00 -1550,92 MWD+IFR+MS 1400,00 11.00 180.00 1318.43 -147.63 0,00 -1550,92 MWD+IFR+MS 1500.00 11,00 180.00 1416,59 -166.71 0,00 MWD+IFR+MS 1600.00 11,00 180.00 1514,76 -185.79 0,00 MWD+IFR+MS 1700,00 11,00 180.00 1612,92 -204.87 0,00 MWD+IFR+MS 1800,00 11,00 180.00 1711,08 -223.95 0,00 MWD+IFR+MS 1809,08 11,00 180.00 1720,00 -225.69 0,00 BPRF 1900,00 11,00 180.00 1809,24 -243.03 -798.15 MWD+IFR+MS 1972.79 11,00 180.00 1880.70 -256.92 -784.26 MWD+IFR+MS 2000,00 10,66 185.51 1907.42 -262.03 -779.16 MWD+IFR+MS 2100,00 10,34 207.52 2005.79 -279,20 -761.99 MWD+IFR+MS 2200,00 11,48 227.91 2104,02 -293.83 -747.36 MWD+IFR+MS 2300,00 13,72 243.19 2201,63 -1516.13 -735.33 MWD+IFR+MS 2349,94 15,11 248.96 2250,00 -1504,76 -730.32 10 3/4" 2400,00 16,63 253.76 2298,15 -1491,80 -725.98 MWD+IFR+MS 2500,00 19,91 261.09 2393,11 -1461,23 -719.33 MWD+IFR+MS 2600,00 23.40 266.37 2486,05 -1424,57 -715.44 MWD+IFR+MS 2700,00 27,04 270.32 -168,91 -1382,01 -714.31 MWD+IFR+MS 2800,00 30,75 273.39 -217,18 -1333,74 -715.95 MWD+IFR+MS 2900.00 34,53 275.85 -270,91 -1280,01 -720.36 MWD+IFR+MS 3000,00 38,34 277.88 -329,85 -1221,07 -727.51 MWD+IFR+MS 3100,00 42,18 279.60 -393,71 -1157,21 -737.36 MWD+IFR+MS 3200,00 46,05 -291,31 -462,17 -1088,75 -749.88 MWD+IFR+MS 3275,99 49,00 -280,06 -517,07 -1033,85 -761.13 MWD+IFR+MS 3300,00 49,95 -276,22 -534,91 -1016,01 -764.97 MWD+IFR+MS 3385,00 53,32 -261,77 -599,96 -950,96 -779.42 MWD+IFR+MS 3400,00 53,32 -259,10 -611,69 -939,23 -782.08 MWD+IFR+MS 3500,00 3165,11 -241.34 -689,90 -861,02 -799.85 MWD+IFR+MS 3600,00 3224,84 -223,57 -768,11 -782,81 -817.62 MWD+IFR+MS 3600,26 3225,00 -223.53 -768,32 -782,60 -817.66 TUZC .- 3700,00 3284,57 -205.81 -846,32 -704,60 -835.38 MWD+IFR+MS 3800,00 3344,30 -188.04 -924,53 -626,39 -853.15 MWD+IFR+MS 3900,00 282.80 3404,03 -170.27 -1002,74 -548,18 -870.92 MWD+IFR+MS 3981,98 282.80 3453,00 -155,71 -1066,85 -484,07 -885.48 Ugnu-MA 4000,00 282.80 3463.77 -152.51 -1080,95 -469,97 -888.68 MWD+IFR+MS 4000,39 282.80 3464,00 -152,44 -1081,25 -469,67 -888.75 Ugnu-MB1 4059,58 282.80 3499.36 -141.92 -1127,55 -423,37 -899.27 MWD+IFR+MS 53,77 282.87 3506,00 -139,92 -1136,32 -414,60 -901.27 Ugnu-MB2 54,93 283,05 3523.04 -134,60 -1159.46 -391 .46 -906.59 MWD+IFR+MS 58,90 283,62 3577,62 -115,27 -1240,97 -309,95 -925.92 MWD+IFR+MS . . BP Planning Report Survey 4300,00 -1325.77 -225.15 -946,88 4310.45 -1334.80 -216.12 -949.16 4400,00 66.85 284,63 3668.74 -71,82 -1413.43 -137.49 D+IFR+MS 4421,37 67.70 284,73 3677.00 -66,82 -1432.50 -118.42 BF2-NA 4468,02 69.55 284,95 3694,00 -55,69 -1474.49 -76.43 SBF1-NB 4479.28 70.00 285,00 3697.89 -52,96 -1484,70 -66.22 MWD+IFR+MS 4500,00 70.00 285,00 3704,98 -47,92 -1503.50 -47,41 MWD+IFR+MS 4514,68 70,00 285,00 3710,00 -44,35 -1516.83 MPI-17 Poly 4561.46 70,00 285,00 3726.00 -32,98 -1559.29 SBE4-NC 4600.00 70,00 285,00 3739.18 -23,60 -1594.27 MWD+IFR+MS 4617,01 70,00 285.00 3745,00 -19.47 -1609.71 SBE2-NE 4700.00 70.00 285,00 3773.38 0.72 -1685.04 MWD+IFR+MS 4760,28/' 70.00 285,00 :3794,00 15.38 -1056,57 SBE1-NF 4779,28 70.00 285,00 3800.50 20.00 -1061,19 MWD+IFR+MS 4800,00 70.00 285,00 3807.59 25.04 -1066,23 MWD+IFR+MS 4874,85 70.00 285,00 3833.19 43.24 -1084,43 MWD+IFR+MS 4877,23 70.09 285,04 3834.00 43,82 -1085,01 TSBD-Top OA 4900.00 70.90 285.47 3841,60 49,47 315.69 -1090,66 MWD+IFR+MS 4984.09 73.93 287,00 3867.00 71,89 392.65 -1113,08 TSBC-Base OA 5000.00 74.51 287,28 3871,33 76.40 407.28 -1117,59 MWD+IFR+MS 5100.00 78.13 289,04 3894.97 106.69 499.58 -1147,87 MWD+IFR+MS 5125.40 79,05 289.47 3900.00 114,90 523.08 -1156,09 MPI-17T1,2 5200,00 82.12 288,10 3912.20 -2143,67 592.75 -1179,78 MWD+IFR+MS 5248,44 84,12 287,22 3918.00 -2189.48 638,56 -1194.37 SBA5-Base OB 5300,00 86,25 286,30 3922.33 -2238,68 687,76 -1209.18 MWD+IFR+MS 5400,00 90,38 284,51 3925.27 -2335.02 784,10 -1235,72 MWD+IFR+MS 5500,00 94,51 282,72 3921.01 -2432,10 881,18 -1259,23 MWD+IFR+MS 5600,00 98,63 280.90 238,38 -2529,31 978,39 -1279.56 MWD+IFR+MS 5700,00 102,75 279.05 255,41 -2626,06 1075,15 -1296,60 MWD+IFR+MS 5800,00 106,85 277.14 269,04 -2721,76 1170,84 -1310.22 MWD+IFR+MS 5827,26 107,97 276.60 272.15 -2747,58 1196,66 -1313.34 MWD+IFR+MS 5900,00 107,97 276.60 280,11 -2816,31 1265.40 -1321.30 MWD+IFR+MS 5980,00 107,97 288.86 -2891,91 1340,99 -1330.05 75/8" 5996,91 107,97 290.71 -2907,88 1356,96 -1331.90 MPI-17 Casing T 6000,00 107,90 291.05 -2910,81 1359,89 -1332.24 MWD+IFR+MS 6100,00 105,76 305.50 -3005,40 1454,48 -1346.69 MWD+IFR+MS 6172.28 104,16 320.02 -3073,70 1522,78 -1361.21 MWD+IFR+MS 6200,00 104,16 3749,65 326.24 -3099,84 1548,92 -1367.43 MWD+IFR+MS 6212,92 104.16 3746.48 329.14 -3112,03 1561,11 -1370.33 MWD+IFR+MS 6300,00 100,76 3727,70 348.28 -3194.86 1643,94 -1389.47 MWD+IFR+MS 6400,00 96,84 3712.41 369.19 -3291.43 1740,51 -1410.38 MWD+IFR+MS 6421,51 96,00 3710,00 373.53 -3312.36 1761,44 -1414.72 MPI-17 T2,2 6500,00 281.62 3703,94 389.29 -3389.00 1838.08 -1430.48 MWD+IFR+MS 6566,67 281.62 3702,16 402.72 -3454,27 1903.35 -1443.91 MWD+IFR+MS 6600.00 281.62 3702,05 409.44 -3486.92 1936.00 -1450,62 MWD+IFR+MS 6700,00 281.62 3701,71 429.58 -3584,87 2033,95 -1470.77 MWD+IFR+MS 6800,00 281.62 3701,37 449.73 -3682,82 2131,90 -1490.92 MWD+IFR+MS 6900,00 281.62 3701,04 469.88 -3780,77 2229,85 -1511.06 MWD+IFR+MS 7000.00 281.62 3700,70 490.02 -3878.71 2327.80 -1531,21 MWD+IFR+MS 7100,00 281,62 3700,36 510.17 -3976.66 2425,74 -1551,36 MWD+IFR+MS 7200.00 281,62 3700,02 530.32 -4074,61 2523.69 -1571,50 MWD+IFR+MS 7300,00 281.62 3699,68 550.46 -4172.56 2621,64 -1591,65 MWD+IFR+MS . . BP Planning Report Survey 7400,00 90.19 281.62 3699,35 570.61 -4270,51 MWD+IFR+MS 7500.00 90.19 281,62 3699,01 590.76 -4368.46 MWD+IFR+MS 7600.00 90.19 281.62 3698,67 610.90 -4466.41 MWD+IFR+MS 7700.00 90.19 281,62 3698,33 631.05 -4564,36 MWD+IFR+MS 7800.00 90.19 281.62 3697,99 651.20 -4662,31 MWD+IFR+MS 7900.00 90.19 281.62 3697,66 671.34 -4760,25 -1712.53 MWD+IFR+MS 8000.00 90,19 281,62 3697,32 691.49 -4858,20 -1732.68 MWD+IFR+MS 8100.00 90.19 281.62 3696,98 711,64 -4956,15 -1752.83 MWD+IFR+MS 8200.00 90,19 281.62 3696,64 731.78 -5054,10 -1772,97 MWD+IFR+MS 8300.00 90,19 281,62 3696,31 751.93 -5152,05 -1793.12 MWD+IFR+MS 8403.01 90,19 281.62 3695,96 772,68 3702,03 -1813,87 MWD+IFR+MS 8450.83 92,10 281.78 3695.00 782,38 3748.84 -1823,57 MPI-17 T3,2 8453,01 92,19 281.78 3694.92 782,82 3750.97 -1824,01 MWD+IFR+MS 8500,00 92,19 281,78 3693.12 792.41 3796,94 -1833,60 MWD+IFR+MS 8600,00 92,19 281.78 3689.31 812,81 3894.77 -1854,00 MWD+IFR+MS 8700,00 92,19 281,78 3685.49 3992.59 -1874.40 MWD+IFR+MS 8800,00 92,19 281,78 3681.68 4090.41 -1894,80 MWD+IFR+MS 8900,00 92.19 281.78 3677.86 4188.23 -1915,20 MWD+IFR+MS 9000,00 92,19 281,78 3674.04 4286.06 -1935,60 MWD+IFR+MS 9100,00 92.19 281,78 3670.23 4383.88 -1956,00 MWD+IFR+MS 9200,00 92.19 281,78 3666.41 -6032.62 4481.70 -1976,39 MWD+IFR+MS 9236,00 92,19 281,78 3665.04 -6067.84 4516,92 -1983,74 5" Screens 9236,92 92.19 281,78 3665.00 -6068.74../ 4517.82 -1983,93 MPI-17 T4,2 · Halliburton Company. Anticollision Report GLOBAL SCAN APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval: 25,00 ft Depth Range: 69,30 to 9236,92 ft Maximnm Radins: 1116,76 ft Reference: Error Model: Scan Method: Error Snrface: Plan: MPI-17 wp12 & NOT PLANNED PROGRA ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Casing Points 2349,94 2319,30 10.750 13,500 10 3/4" 5980,00 3879,51 7,625 9,875 75/8" 9236,00 3734,34 4,500 6,125 51/2" Plan: MPI-17 wp12 Principal: Yes Summary Date Composed: Version: Tied-to: 3/11/2004 145 From Well Ref, Point M pt H Pad Plan Trinity Trinity V1 Plan: Trini 4648,74 10750,00 335,87 267,60 68,27 Pass: Major Risk M pt I Pad MPI-01 MPI-01 V1 1116,73 1150,00 49.47 31,11 18,35 Pass: Major Risk M pt I Pad MPI-01 Plan MPI-01A VO Plan: 1117.15 1125,00 49.47 31.08 18,39 Pass: Major Risk M PtI Pad MPI-01 Plan MPI-01AL 1 VO Plan 1117,15 1125,00 49.47 31,17 18,30 Pass: Major Risk M PtI Pad MPI-02 MPI-02 V1 986,29 1025,00 157,86 24.87 132.99 Pass: Major Risk M pt I Pad MPI-03 MPI-03 V1 1395,39 1400,00 151,73 40.73 111,00 Pass: Major Risk M pt I Pad MPI-05 MPI-05 V1 1595,86 1625,00 192,72 31,08 161 ,64 Pass: Major Risk M pt I Pad MPI-06 MPI-06 V1 0 677,89 675,00 268,04 15.01 253.02 Pass: Major Risk M pt I Pad MPI-07 MPI-07 V1 845,77 850.00 321,95 25,40 296,55 Pass: Major Risk M pt I Pad MPI-09 MPI-09 V12 626,82 625,00 139,97 11,88 128,09 Pass: Major Risk M pt Pad MPI-10 MPI-10 V8 505,93 500,00 79,67 9,32 70,35 Pass: Major Risk M pt Pad MPI-10 MPI-10A V1 505.93 500.00 79,67 9.48 70,19 Pass: Major Risk M pt Pad MPI-12 MPI-12 V10 529,18 525,00 411,87 8,66 403,21 Pass: Major Risk M pt Pad MPI-12 MPI-12L1 V11 529,18 525,00 411,87 8,55 403,31 Pass: Major Risk M pt Pad MPI-12 MPI-12PB1 V4 529,18 525,00 411,87 8,66 403,21 Pass: Major Risk M pt Pad MPI-12 Plan MPI-12 A (Thor T 5997,65 4950,00 181,98 165.81 16.17 Pass: Major Risk M pt Pad MPI-13 MPI-13 V6 354,79 350.00 444.45 7,81 436,64 Pass: Major Risk M pt Pad MPI-15 MPI-15 V6 1074,74 1075.00 34,44 21,61 12,83 Pass: Major Risk M pt Pad MPI-15 MPI-15L 1 V2 1074,74 1075,00 34,44 21.40 13.04 Pass: Major Risk M pt Pad MPI-15 MPI-15PB1 V5 1074,74 1075,00 34,44 21,66 12,78 Pass: Major Risk M pt Pad Plan MPI-14 Odin MPI-14 L 1 VO Plan: MPI 7667,15 6100,00 252,99 170,61 82,38 Pass: Major Risk M pt Pad Plan MPI-14 Odin Plan MPI-14 PB1 V10 PI 7667,15 6100.00 252,99 170,07 82,92 Pass: Major Risk M PI Pad Plan MPI-17 Thor Plan MPI-17 L 1 VO Plan 3300,00 3300.00 0.00 0,00 0,00 FAIL: NOERRORS M PI Pad Plan MPI-17 Thor Plan MPI-17 L2 VO Plan 3300,00 3300,00 0,00 0,00 0,00 FAIL: NOERRORS M PI Pad Plan MPI-Freya Plan MPI-Freya VO Plan 9194.46 7575.00 365,72 143,04 222,68 Pass: Major Risk MPt Pad Plan MPI-LlNK Plan MPI-LlNK VO Plan: 375,25 375,00 61,03 10,03 51.01 Pass: Major Risk M PI Pad Plan MPI-Tank Plan MPI-Tank VO Plan: 350,62 350,00 264,36 9,41 254,95 Pass: Major Risk MPt Pad Plan MPI-Uller Plan MPI-Uller V1 Plan 450,26 450,00 264,18 10,14 254,05 Pass: Major Risk M PI Pad Plan MPI-Valhalla Plan MPI-Valhalla VO P 450,03 450,00 264,55 10,89 253,65 Pass: Major Risk Site: M pt H Pad Well: Plan Trinity Rule Assigned: Major Risk Wellpath: Trinity V1 Plan: Trinily Wp 1 V5 Inter-Site Error: 0,00 ft 4780,94 3870.37 9850,00 4059,23 13,27 98.25 25.24 100,24 6,000 1114,30 392,06 722,24 Pass 4777,27 3869,11 9875,00 4059,67 13,25 98,22 25,56 100.56 6,000 1090.37 391,53 698,83 Pass 4773,59 3867,85 9900,00 4060,11 13,22 98.20 25,90 100,90 6,000 1066.47 390,98 675,49 Pass 4769,92 3866,60 9925,00 4060,56 13.20 98,17 26.26 101,26 6,000 1042.62 390.40 652.22 Pass 4766,25 3865,34 9950,00 4061,00 13.18 98,14 26,63 101.63 6.000 1018.80 389.78 629.02 Pass 4762.58 3864,09 9975,00 4061.44 13,15 98.12 27.02 102,02 6,000 995,03 389,12 605,91 Pass 4758,90 3862,83 10000.00 4061.88 13.13 98,09 27.42 102.42 6,000 971,31 388.43 582.88 Pass 4755,23 3861,57 10025,00 4062,33 13,11 98,06 27.85 102,85 6,000 947,64 387,68 559.96 Pass WELL DFI"AILS CQMI'ANY DETAll,$ N(f!)¡,: 1N.'-S Nm1!Üug 60094J9.51 E¡I,~ting 5517g<)55 j~tit!.lde Longìl:ud<.' Slot 70"26:j L520N 149''34'39.905W N/A 25.00 9236.92 Plan: MPf-17 \"'pl2 m' Amocu lntc:rpolatioll Method:MD Depth Range From: 69.30 MaximwnRangc: 1116.76 P!all MPI-J7 Thor 104L!9 J55(j{)2 -205 -171 -136 -102 -68 -34 0 27 -34 -68 -102 -136 -171 -205 -218 TraveJ!ing CyJinder Azimuth (TFO+AZI) [deg] vs Centre to Centre Separation eft] From Colour o o 500 1000 1500 2000 2500 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 s~", MD ¡U~ 3 J 5 " 7 , " ,I) " !2 1.1 " t5 '" 17 t8 !9 20 2t 22 23 SURVEY PR(XiRAM Depth Fm Depth To Survey/Plan Too] ToMD o 500 1000 1500 2000 2500 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 WELLPATJ-] DETAILS Plan MPI,17 niUw DOO (jOO U)JO SECTION DETAILS rVD VScc Türg"¡ MPI-17T12 MPI.17Cusìnf.'-l MI'I-I7T22 MP!·17Tl2 MP¡-I7T42 Halliburton Sperry-Sun Proposal Report 11 June, 2004 Surface Coordinates: 6009439.52 N, 551789.55 E (70026' 11.5199° N, 149034' 39.9051° W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Kelly Bushing Elevation: 69.30ft above Mean Sea Level .. DAU..I..IN. ..fltVU~::.. AHa~~ . e Proposal Ref: pr01422 Halliburton Sperry-Sun Proposal Report for MPI-17 Wp 12.0 Revised: 11 June, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Comment (ft) (ft) (ft) (ft) (ft) (ft) 0,00 0.000 0,000 -69.30 0,00 O,OON 0,00 E 0,00 69,30 0.000 0,000 0,00 69,30 O,OON 0,00 E 0.000 0,00 100,00 0,000 0,000 30,70 100,00 O,OON 0,00 E 0.000 0,00 200,00 0,000 0,000 130,70 200.00 0,00 N O.OOE 0,000 0,00 . 300,00 0.000 0,000 230,70 300,00 O,OON 0,00 E 0,000 0.00 Kick-Off at 300,00ft 400,00 1,500 180,000 330,69 399,99 43 ' 1 N 551789,56 E 1,500 -0,20 500,00 3,000 180,000 430,61 499,91 6 34,29 N 551789,59 E 1,500 -0,80 Continue Build/Turn at 500.00ft 600,00 5,000 180,000 530,36 599.66 6009427,31 N 551789,63 E 2.000 -1,87 700,00 7,000 180,000 629,81 699,11 6009416,86 N 551789,71 E 2,000 -3.48 800,00 9,000 180,000 728,83 798,13 6009402,94 N 551789,80 E 2,000 -5,61 Continue Build at 800,00ft 900,00 10,000 180,000 6009386,44 N 551789,92 E 1,000 -8,15 1000,00 11,000 180,000 6009368,21 N 551790,05 E 1,000 -10,94 End of Build at 1 OOO,OOft 1100,00 11,000 180,000 6009349,1 3 N 551790,18 E 0,000 -13,87 1200,00 11,000 180,000 6009330,05 N 551790,31 E 0,000 -16,80 1300,00 11,000 180,000 6009310,97 N 551790.44 E 0,000 -19,73 1400,00 147,63 S 0,00 E 6009291,89 N 551790,58 E 0,000 -22,66 1500,00 1 66,71 S 0.00 E 6009272.81 N 551 790,71 E 0,000 -25,59 1600,00 185,79 S 0,00 E 6009253,73 N 551790,84 E 0.000 -28.52 1700,00 204,87 S 0,00 E 6009234,65 N 551790,97 E 0.000 -31 .44 1800,00 223,95 S 0,00 E 6009215,57 N 551791,11 E 0,000 -34,37 1809,08 1720,00 1789,30 225,69 S 0,00 E 6009213,84 N 551791 ,1 2 E 0.000 -34,64 BPRF 1900,00 1809,24 1878,54 243,03 S 0,00 E 60091 96.49 N 551791,24 E 0,000 -37,30 e 1 972. 79 1880,70 1950,00 256,92 S 0,00 E 6009182,60 N 551791,33 E 0.000 -39.43 Start Build/Turn at 1972, 79ft 2000,00 1907.42 1976,72 262,03 S 0,24W 6009177.50 N 551 791 ,13 E 4,000 -39,98 2100,00 2005,79 2075,09 279,20 S 5,28W 6009160,29 N 551786,21 E 4,000 -37,64 2200,00 11.479 227,910 2104,02 2173,32 293,83 S 16,81 W 6009145,58 N 551774,78 E 4,000 -28.48 2300,00 13,722 243,1 94 2201,63 2270,93 305,86 S 34,79 W 60091 33.43 N 551756.88 E 4,000 -12,56 2400,00 16,628 253,758 2298,15 2367.45 315,21 S 59,1 2 W 6009123,91 N 551732,62 E 4,000 10,04 2500,00 19,907 261,096 2393,11 2462.41 321,85 S 89,69 W 6009117,06 N 551702,10 E 4,000 39,23 2600,00 23.405 266.375 2486,05 2555,35 325,74 S 126,35 W 6009112,91 N 551665.47 E 4,000 74.86 2700,00 27,035 270,327 2576,51 2645,81 326,87 S 168,91 W 6009111.49 N 551622,91 E 4,000 116,74 2800,00 30,751 273,396 2664,05 2733,35 325,22 S 217.18 W 6009112,80 N 551574,63 E 4,000 164,69 2900,00 34,525 275,857 2748,24 2817,54 320,82 S 270,91 W 6009116,83 N 551520,87 E 4,000 218.46 3000,00 38,340 277,886 2828.69 2897,99 313,67 S 329,85 W 6009123,57 N 551461,89 E 4,000 277,80 3100,00 42,184 279.598 2904,99 2974,29 303,81 S 393.71 W 6009132.98 N 551397,96 E 4,000 342.41 11 June, 2004 - 8:35 Page 20f7 Dri/IQuest 3.03.06.002 , . Halliburton Sperry-Sun Proposal Report for MPI-17 Wp 12.0 Revised: 11 June, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Comment (ft) (ft) (ft) (ft) (ft) (ft) 3200,00 46,051 281,072 2976,77 3046,07 291,29 S 462,17 W 411,98 3275,99 49,000 282,070 3028,07 3097,37 280,04 S 517,07 W 467,96 Continue BuildfTurn at 3275,99ft 3300,00 49.951 282,239 3043,67 3112,97 276,20 S 534,91 W 486.18 3385.00 53.320 282,800 3096,42 31 65,72 261,75 S 599,96 W 552,68 End of BuildfTurn at 3385,00ft . 3400,00 53,320 282.800 3105,38 3174,68 259,08 S 611,69W 564,68 3500,00 53,320 282.800 3165,12 3234.42 9, N 551101.35 E 0,000 644,68 3600,00 53,320 282,800 3224,85 3294,1 5 6 10,65 N 551023,02 E 0,000 724,69 3600,25 53,320 282,800 3225.00 3294,30 6009210,69 N 551022,83 E 0,000 724,89 ruzc 3700,00 53,320 282,800 3284,59 3353,89 6009227,87 N 550944.69 E 0,000 804.70 3800,00 53,320 282,800 3344,32 3413.62 6009245,10 N 550866,37 E 0,000 884,70 3900,00 53,320 282,800 3404,06 6009262,32 N 550788,04 E 0.000 964,71 3981 ,94 53,320 282,800 3453,00 6009276.43 N 550723,86 E 0.000 1030,26 Ugnu-MA 4000,00 53,320 282,800 3463,79 6009279,54 N 550709,71 E 0,000 1 044,71 4000.35 53,320 282,800 3464,00 6009279,60 N 550709,44 E 0,000 1044,99 Ugnu-MB1 4059,58 53,320 282,800 ,38 6009289,81 N 550663,05 E 0,000 1092,38 Start BuildfTurn at 4059,58ft 4070,72 139,90 S 1136,25 W 6009291.74 N 550654,30 E 4,001 1101.32 Ugnu-MB2 4100,00 134,56 S 1159.44 W 6009296,91 N 550631,08 E 4,001 1125,05 4200,00 115.24 S 1240,94 W 6009315,67 N 550549.44 E 4,001 1208,55 4300.00 94,27 S 1325,73 W 6009336,04 N 550464,50 E 4,001 1295,56 4310.38 92,01 S 1334,71 W 6009338,24 N 550455,51 E 4,001 1 304,77 Ugnu-MC 4400,00 3668,78 3738.08 71 ,78 S 1413.40 W 6009357,93 N 550376,68 E 4,001 1385,64 4421,28 3677,00 3746,30 66,80 S 1432,39 W 6009362,77 N 550357,66 E 4,001 1405.16 SBF2-NA . 4467,91 3694,00 3763,30 55,68 S 1474,36 W 6009373,60 N 550315,61 E 4,001 1448,34 SBF1-NB '''-10-'''''<:. ~~ 4479,28 3697,93 3767,23 52,93 S 1484,67 W 6009376,29 N 550305,29 E 4,001 1458,95 End of BuildfTurn at 4479, 28ft ... 4500,00 3705,02 3774,32 47,89 S 1503.47 W 6009381 ,19 N 550286.45 E 0,000 1478,31 4561,35 70,000 285,000 3726,00 3795,30 32,97 S 1559,1 6 W 6009395,73 N 550230,66 E 0,000 1535,63 SBE4-NC 4600,00 70,000 285,000 3739,22 3808,52 23,57 S 1594,24W 6009404,88 N 550195,51 E 0,000 1571,73 4616,90 70,000 285,000 3745,00 3814,30 19.46 S 1609,58 W 6009408,89 N 550180,14 E 0,000 1587,52 SBE2-NE 4700.00 70,000 285,000 3773,42 3842.72 0,76 N 1685,01 W 6009428,57 N 550104,58 E 0.000 1665,16 4760,17 70,000 285,000 3794.00 3863,30 15.39 N 1739,62 W 6009442,83 N 550049,86 E 0,000 1721,37 SBE1-NF 4779,28 70.000 285,000 3800,54 3869,84 20,04 N 1756,97 W 6009447,36 N 550032.49 E 0,000 1739,23 4800,00 70,000 285,000 3807.62 3876,92 25,08 N 1775,77 W 6009452,26 N 550013,64 E 0,000 1758.58 4874,85 70,000 285,000 3833,22 3902,52 43,28 N 1843,71 W 6009470,00 N 549945,58 E 0.000 1828,51 Start BuildfTurn at 4874. 85ft 4877.13 70,082 285,043 3834,00 3903,30 43,84 N 1845,78 W 6009470,54 N 549943,51 E 3,999 1830,64 TSBD-Top OA 4900,00 70,904 285.468 3841,64 3910,94 49,51 N 1866.58 W 6009476,07 N 549922,67 E 3,999 1852,06 11 June, 2004·8:35 Page 3 of7 DrillQuest 3.03.06,002 ,- Halliburton Sperry-Sun Proposal Report for MPI-17 Wp 12.0 Revised: 11 June, 2004 BPXA Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastin9s Comment (ft) (ft) (ft) (ft) (ft) (ft) 4983,96 73,930 286,996 3867,00 3936,30 71,89 N 1943.41 W 1931 .42 TSBC-Base OA 5000,00 74,509 287,282 3871,36 3940,66 76.43 N 1 958.1 6 W 1946,69 5100,00 78,129 289.033 3895,01 3964,31 106,72 N 2050.47 W 2042,55 5125,21 79.043 289.467 3900,00 3969,30 114,87N 2073,79 W 2066,85 TSBB-TopOB . 51 25.40 79,050 289.470 3900,04 3969,34 114,93 N 2073,97 W 2067,04 Continue BuildfTurn at 5125.40f 5200,00 82,1 23 288,1 00 3912,24 3981,54 5 N 549645.00 E 4,501 2139,51 5300,00 86,250 286,293 3922,36 3991,66 6 91,99 N 549549,78 E 4.501 2237,92 5400,00 90,380 284,503 3925,30 3994,60 6009617,85 N 549453,26 E 4,501 2337,19 5500,00 94,509 282,712 3921,04 3990,34 6009640,68 N 549356,02 E 4,501 2436,73 5600,00 98,635 280,900 3909,60 3978,90 6009660,33 N 549258,66 E 4,501 2535,91 5700,00 102,751 279,048 3891,04 6009676,68 N 549161,80 E 4,501 2634,13 5800,00 106,854 277.135 3865,50 6009689,64 N 549066,01 E 4,501 2730,78 5827,26 107,970 276,600 3857,34 6009692,57 N 549040,17 E 4.501 2756,77 End of BuildfTurn at 5827,26ft 5900,00 107,970 276.600 3834,90 6009700,05 N 548971.38 E 0,000 2825,91 5996,91 107,970 276,600 5,00 6009710,01 N 548879,74 E 0,000 2918.02 Start DropfTurn at 5996,91 ft 6000,00 291,03 N 2910,78 W 6009710,33 N 548876,82 E 4,303 2920,96 6100,00 305.47 N 3005,37 W 6009724,11 N 548782,1 3 E 4,303 3016,65 6172.28 319,99 N 3073,67 W 6009738,1 6 N 54871 3,73 E 4,303 3086,36 End of DropfTurn at 6172,28ft 6200,00 326,21 N 3099.82 W 6009744,19 N 548687,54 E 0,000 3113,16 6212,92 329,11 N 3112,00 W 6009747,01 N 548675,34 E 0,000 3125,64 Start DropfTurn at 6212, 92ft 6300.00 3727,70 3797,00 348,24 N 3194,84 W 6009765,56 N 548592,37 E 3,999 321 0.44 6400,00 3712.41 3781,71 369,1 4 N 3291.41 W 6009785,80 N 548495,66 E 3,999 3309,07 e 6421,51 3710,00 3779,30 373,48 N 3312,34 W 6009789,99 N 548474,70 E 3,999 3330.41 Continue Drop at 6421 ,51 ft 6500,00 3703,94 3773,24 389,24 N 3388,98 W 6009805,22 N 548397,95 E 4,002 3408,57 6566.67 3702,17 3771.47 402,66 N 3454,25 W 6009818,19 N 548332,58 E 4,002 3475,13 End of Drop at 6566,67ft 6600,00 90,190 281,620 3702,06 3771,36 409,38 N 3486,90 W 6009824,67 N 548299,89 E 0,000 3508.42 6700,00 90,190 281,620 3701,73 3771,03 429,52 N 3584,85 W 6009844,1 3 N 548201,80 E 0,000 3608,30 6800,00 90,190 281,620 3701.40 3770,70 449,66 N 3682,80 W 6009863,59 N 548103,72 E 0,000 3708,18 6900.00 90,190 281,620 3701,07 3770,37 469,80 N 3780,75 W 6009883,06 N 548005,63 E 0,000 3808,06 7000,00 90,190 281.620 3700,73 3770,03 489,94 N 3878,70 W 6009902,52 N 547907,54 E 0,000 3907,94 71 00,00 90,190 281,620 3700,40 3769,70 510,08 N 3976,65 W 6009921,98 N 547809.45 E 0,000 4007.82 7200,00 90,190 281 ,62o 3700,07 3769,37 530,23 N 4074,60 W 6009941 ,44 N 547711,37 E 0,000 4107,70 7300,00 90,190 281,620 3699,74 3769,04 550,37 N 4172.55 W 6009960,90 N 547613,28 E 0,000 4207.58 7400,00 90.190 281,620 3699.41 3768,71 570.51 N 4270,50 W 6009980.36 N 547515,19 E 0,000 4307.46 7500,00 90,190 281 ,620 3699,08 3768,38 590,65 N 4368.45 W 6009999,82 N 547417,10 E 0,000 4407,35 11 June, 2004·8:35 Page 4 of7 DrillQuest 3.03,06.002 Halliburton Sperry-Sun Proposal Report for MPI-17 Wp 12.0 Revised: 11 June, 2004 " Milne Point Unit Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings (ft) (ft) (ft) (ft) (ft) (ft) 7600,00 90,190 281,620 3698,74 3768,04 610,79 N 4466.40 W 7700,00 90.190 281,620 3698.41 3767,71 630,94 N 4564,35 W 7800,00 90,190 281 ,620 3698,08 3767,38 651,08 N 4662,30 W 7900,00 90,190 281 ,620 3697,75 3767,05 671,22 N 4760,25 W 8000,00 90,190 281,620 3697.42 3766,72 691,36 N 4858,20 W 8100.00 90,190 281,620 3697,09 3766,39 11 , 9 N 546828,58 E 8200,00 90,190 281,620 3696,75 3766,05 6 36,05 N 546730,49 E 8300,00 90,190 .281,620 3696.42 3765,72 6010155,51 N 546632.40 E 8400.00 90,190 281 ,62o 3696,09 3765.39 6010174,97 N 546534.32 E 8403.01 90,190 281,620 3696,08 3765,38 6010175,56 N 546531.36 E 8450,83 92,100 281,780 3695,13 601 01 84,93 N 546484.48 E 8453,01 92,190 281,780 3695,04 6010185,36 N 546482.35 E 8500,00 92,1 90 281,780 3693,25 6010194.63 N 546436,31 E 8600.00 92,190 281 ,780 3689.43 6010214,35 N 546338,35 E 8700,00 92,190 281 ,780 5,61 6010234,07 N 546240,39 E 8800,00 853.46 N 5641,33 W 601 0253,79 N 546142.43 E 8900.00 873,86 N 5739,15 W 6010273,51 N 546044.47 E 9000,00 894,26 N 5836.97 W 6010293,23 N 545946.51 E 9100,00 914,66 N 5934,80 W 6010312,95 N 545848,54 E 9200,00 935,06 N 6032,62 W 6010332,67 N 545750,58 E 9236,92 3665.09 3734,39 942,60 N 6068,74 W 6010339.95 N 545714,42 E All data is in Feet (US Survey) unless otherlJlÄse stated, Directions and coordinates are relative to True North, Vertical depths are relative to Well, Northings and Eastings are relative to Well, Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4, The Dogleg Severity is in Degrees per 1 00 feet (US Survey), Vertical Section is from Well and calculated along an Azimuth of 278,829° (True), Based upon Minimum Curvature type calculations, at a Measured Depth of 9236,92ft, The Bottom Hole Displacement is 6141.50ft, in the Direction of 278,829° (True), The Along Hole Displacement is 6497,7 4ft The Total Accumulated Dogleg is 149,589° The Planned Tortuosity is 2.325° 11 OOft The Directional Difficulty Index is 6,0, 11 June, 2004 - 8:35 Page 5 0'7 BPXA Comment 4507,23 4607,11 4706,99 4806,87 . 4906,75 0,000 5006.63 0,000 5106,51 0,000 5206,39 0,000 5306,27 0.000 5309.28 Start Buildrrurn at 8403,01 ft 4,008 5357,03 Continue Buildrrurn at 8450. 83ft 4,128 5359,20 End of Build at 8453,01 ft 0,000 5406,1 0 0.000 5505,89 0,000 5605,69 0,000 5705.48 0,000 5805,27 0,000 5905,07 0,000 6004,86 0,000 6104,66 0,000 6141,50 Total Depth at 9236,92ft . DrillQuest 3.03.06.002 Halliburton Sperry-Sun Proposal Report for MPI-17 Wp 12.0 Revised: 11 June, 2004 Milne Point Unit Comments Measured Station Coordinates Depth TVD Northings Eastings Comment (ft) (ft) (ft) (ft) 300,00 300,00 O,OON 0,00 E Kick-Qff at 300,00ft 500,00 499,91 5,23 S 0,00 E Continue BuildlTum at 500, 800,00 798,13 36,58 S O,OOE Continue Build at OOft 1000,00 995,08 71 ,31 S O,OOE End ofB 1 972. 79 1950,00 256,92 S 0,00 E S 9ft 3275,99 3097.37 280,04 S 275,99ft 3385,00 3165,72 261,75 S 5,00ft 4059,58 3568.68 141,89 S um at 4059,58ft 4479,28 3767,23 52,93 S End uildlTurn at 4479,28ft 4874,85 3902,52 43,28 N Start BuildlTurn at 4874,85ft 51 25.40 Continue BuildlTurn at 5125,40ft 5827,26 End of BuildlTurn at 5827,26ft 5996,91 Start DroplTurn at 5996,91 ft 6172,28 End of DroplTurn at 6172,28ft 6212,92 Start DroplTurn at 6212,92ft 6421,51 373.48 N 3312,34 W Continue Drop at 6421 ,51 ft 6566,67 402,66 N 3454,25 W End of Drop at 6566,67ft 8403,01 772. 54 N 5252.95 W Start BuildlTurn at 8403.01 ft 8450,83 782,23 N 5299,76 W Continue BuildlTurn at 8450.83ft 8453.01 782,67 N 5301,90 W End of Build at 8453,01 ft i/ 9236,92 3734,39 942,60 N 6068,74 W Total Depth at 9236,92ft 11 June, 2004 - 8:35 Page 60f7 " BPXA . . DrillQuest 3.03.06.002 1720,00 0.000 0.000 1809,08 1789,30 3225,00 0,000 0,000 3600,25 ' 3294,30 3453,00 0,000 0,000 3981,94 3522,30 3464,00 0,000 0,000 4000,35 3533,30 3506,00 0.000 0,000 4070,72 3575,30 3631,00 0,000 0,000 1334,71 W Ugnu-MC 3677.00 0,000 0,000 1432.39 W SBF2-NA 3694,00 0,000 0,000 1474,36 W SBF1-NB 3726,00 0.000 0,000 1559,1 6 W SBE4-NC 3745.00 0,000 0,000 1609,58 W SBE2-NE 3794,00 3794,00 15,39 N 1739,62 W SBE1-NF 3834,00 3834,00 43,84 N 1845,78 W TSBD-Top OA 3867,00 v 3867,00 71,89 N 1943.41 W TSBC-Base OA 3900,00 3900,00 114,87 N 2073,79 W TSBB-Top OB 3918,00 SBAS-Base OB Milne Point Unit Formation Tops Formati on Plane (Below Well Origin) Sub-Sea Dip Up-Dip (ft) Angle Dirn. Profile Measured Vertical Depth Depth (ft) (ft) 11 June, 2004 - 8:35 Halliburton Sperry-Sun Proposal Report for MPI-17 Wp 12.0 Revised: 11 June, 2004 Northings (ft) Penetration Point Sub-Sea Depth (ft) Page 70f7 ... . . BPXA . . DrillQuest 3.03,06.002 1 VI 1 w D 204-098 6/9/2004 MPU 1-13: Never Completed z MPU 1-06: Perf. ! o - I I Subject: MPI-17 MotherbOrellti-COllision From: "Coyner, Skip (NATCHIQ)" <coynsO@BP.com> Date: Thu, 17 Jun 2004 11: 14:35 -0800 To: tom _maunder@admin.state.ak.us . See attached summary report and travelling cylinders for all three wellbores. «MPI-17 Mother Bore Anti-Collision Report.pdt» «Mother bore & NB Travelling Cylinders.pdf» «OA Lateral Travelling Cylinders.pdt» «OB Lateral Travelling Cylinders.pdf» Skjp Coy1l£r ~~_~~i Energy s-ICIIII 907-564-4395 BPXA 907-748-3689 cell Content-Type: Content-Encoding: MPI-17 Mother Bore Content-Description: Anti-Collision Report.pdf application/octet -stream base64 ¡MPI-17 Mother Bore Anti-Collision .. Mother bore & NB Content-Descnptlon: T 11' C 1· d df , rave Illg y III ers.p Mother bore & NB Travelling Cylinders.pdf C t t T 1· t· n/ t t tr " on en - ype: app lca 10 oc e -s eam Content-Encoding: base64 Lateral Travelling C t t D . t· . OA Lateral Travelling on en - escnp Ion. C 1· d df y III ers.p application/octet-stream base64 Content-Type: Content-Encoding: Lateral Travelling Content-Description: OB Lateral Travelling Cylinders.pdf Content-Type: application/octet-stream Content-Encoding: base64 1 of 1 6/17/200412:16 PM RE: MPI-17 Multi-Lateral APD's . . Subject: RE: MPI-17 Multi-Lateral APD's From: "Coyner, Skip (NATCHIQ)" <coynsO@BP.com> Date: Wed, 16 Jun 2004 17:17:11 -0800 To: Thomas Maunder <tom_maunder@admin.state.ak.us> Since everybody (including me) likes seeing the ASP's, it would be best to replace the originals with the "ASP" versions don't you think? Please make the switch, S!¿jp Coyner 907-564-4395 BPXA 907-748-3689 cell -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Wednesday, June 16, 2004 4:49 PM To: Coyner, Skip (NATCHIQ) Subject: Re: MPI-17 Multi-Lateral APD's Skip, I am getting back to the 1-17 family. Should these directional plans be substituted for those that were included in the original applications?? Tom Coyner, Skip (NATCHIQ) wrote: OK, we have the various Sperry well plans sorted out and converted to ASP's. For somr reason, the common BHL (ASP's) moved 42.5 ft and all three lateral "entry points" moved a little as well. It seems like there was a minute azimuth change somewhere in the Compass program, but again, we're all on the same page now. I have attached all three well plans along with the front (data) sheet from the program. The revised data sheet has all necessary corrections on it: a) entry points, b) common BHL and c) TVD of the NB lateral. Let me know if you need anything else. «L2 asps.pdf» «1-17 asps.pdf» «L 1 asps.pdf» «MPI-17 Data Sheet revised.ZIP» S!¿jp Coyner ~~~c~~; Energy S.vICBII 907-564-4395 BPXA 907-748-3689 cell lofl 6/17/20047:10 AM Rb: MPl-lI, ApphcatlOn tor Permit to Unll . . Subject: RE: MPI-17, Application for Pennit to Drill From: "Coyner, Skip (NATCHIQ)" <coynsO@BP.com> Date: Thu, 10 Jun 2004 16:03:01 -0800 To: Thomas Maunder <tom_maunder@admin.state.ak.us> Roger. that. Skip Coyner 907-564-4395 BPXA 907-748-3689 cell -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Thursday, June 10, 2004 3:59 PM To: Coyner, Skip (NATCHIQ) Subject: Re: MPI-17, Application for Permit to Drill Thanks Skip. I am glad you place. Whole Tom I will await the new zips. are aware of I-10. You'll at least have a stack in lot more options. Coyner, Skip (NATCHIQ) wrote: First, I found a bunch of bugs in the Sperry wellplans with asp's that I sent you. So, throw them away. We're working on getting everyone on the same page. I'll re-send them when they are correct. Things just aren't the same since Ken Alan switched jobs. MPI-17 etal will be in hydraulic unit 3 along with the dreaded MPI-10. Since MPI-10 killed us a few years back, MPU has reduced their injection rates and pressures. Furthermore, I-10 will not be injecting while we're drilling. I was still here at BP when Steve Shultz took the kick a couple of years ago. So I am familiar with the incident. We believe that the fault block (hydraulic unit) is no longer over pressured - although we do list pore pressures at 9.1 ppg. We will be at > 9.4 ppg and drilling carefully. Skip Coyner 907-564-4395 BPXA 907-748-3689 cell 1 of 1 6/17/200410:18 AM Re: MPI-l!, ApplIcation for Permit to Drill . . Subject: Re: MPI-17, Application for Pennit to Drill From: Thomas Maunder <tomßaunder@admin.state.ak.us> Date: Thu, 10 Jun 2004 14:22:36 -0800 To: "Coyner, Skip (NATCHIQ)" <coynsO@BP.com> Well, I did ask for it all. Aren't zip files grand?? On the possible communication from 1-10 to 1-13, I realize the path is tortuous, but in the information I remember seeing on the pressure fall-off test there was a doubling of the derivative slope that indicated communication to something with a large porosity. The speculation was a fault and all that was needed to confirm it was allowing to pressure to continue to decline to some calculated value. There was even a time prediction of when the pressure would be reached. What HU(s) are the proposed 1-17 family in?? Tom Coyner, Skip (NATCHIQ) wrote: Here you go. Question: .... is there any plan to cover these faults?? Answer: Yes, the planned TOC will be 500' above TUCZ - ± 3100'MD Question: You state that the pressure situation has been rectified, how has this been done?? Answer All surrounding injectors in adjacent Hydraulic Units will be shut-in while drilling. Question: Do the reservoir engineers and geologists see communication between the various wells (1-11, I-11L1, 1-10 and 1-08) in the area or are they compartmentalized?? Answer: MPI-12, MPI-11, and MPI-13 are geologically isolated from MPI-08 and MPI-10i ("i" denotes an injector). MPI-12, MPI-11, and MPI-13i are in Hydraulic Unit 13, MPI-10i in HU 3, and MPI-08 in HU 2. This isolation is determined by two large faults (-100-300' displacement) traveling North-South and East-West. This also confirmed with different oil API between HU 13 and HU 3. In addition, pressure transient analysis in MPI-12 have determined that this well is in a very small compartment and not communicating to even to MPH-13. This has explained the poor performance of MPI-12. Finally, we have not seen any pressure indication in MPI-12 or MPI-08 since MPI-10i was put back on injection. Question: Close approach issues. please submit the data. A traveling cylinder plot would be appreciated as part of this. Answer: See attachments. Question: I remember some pressure fall-off tests being done on possibly MPI-10 that may have indicated that the water was communicating via a fault. Was a report ever issued on that testing?? Answer: There was no formal report written on that PTA, but the test did indicate fracture a of 408' right after a high injection period (-3000 bwpd). This fracture was reduced to 75' after a period of lower injection (-1000 bwpd). This lower injection rate has been continued since then. Even during the high injection, it is highly unlikely that MPI-10i was communicating to MPI-12 due to the 2000' feet of tortuous lof2 6/17/2004 10:18 AM Ke: MPl-l /, ApplIcatIOn lOr PermIt to Vrill distance between wells~ . Question: In the directional planning information, the positions (x,y) of the formation tops and casing points are not given. Would you please supply complete listings?? Answer: See attachments: Skip Coyner 907-564-4395 BPXA 907-748-3689 cell 20f2 6/17/2004 10: 18 AM TERRIE L HUBBLE BP EXPLORATION AK INC PO BOX 196612 MB 7-5 ANCHORAGE, AK 99519-6612 89-6/1252 109 "Mastercard Check" . ~~~J~cJFHE.. ~,JL ()~/AŒ;Cc . ~~ ~,lo ~MoóJ~ <Þ/Í Ol) First National Bank Alaska Anchorage, AK 99501 MEMO \y\ Ç), - \ 1 DA TE tf...n -fß -03 $ 100.00 DOLLARS ~~_ >f ~ -: ~ 2 5 2000 b 0 -: Ii Ii ~ l. III b 2 2 7 II' ;I. 5 5 b II- 0 ~ 0 Ii . . . TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/P ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER /' Development Service N\.o\-~£~~ cÃ- ~ ~\\~("(J.. \ CHECK WBA T ADD-ONS APPLIES (OPTIONS) MULTI LATERAL WELL NAME PTD# (If API number last two (2) digits are between 60-69) ;??//t{ II'? '-. "" /1· /'; CJ <:/ ¿_úL -u 70 Exploration Stratigraphic "CLUE" Tbe permit is for a new wellbore segment of existing weD Permit No, API No. productionsbould continue to be reported as a function' of tbe original API number. stated above. HOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for tbe pilot bole must be dearly differentiated in both name (name on permit plus PH) and API Dumber (50 70/80) from records, data and logs acquired for we)) (name on permit). Pn..OT (PH) .. SPACING EXCEPTION DRY DITCH SAMPLE Tbe permit is approved subject ·to full compliance with 20 AAC 25.05S~ Approval to perforate and produce is contingent upon issuance of ;t conservation order approving a spacing e:xception. (Companv Name) assumes tbe liability of any protest to tbe spacing . exception tbat may occur. An dry ditcb sample sets submitted to tbe Commission must be in no greater ·tban 30' sample intervals from below tbe permafrost or from wbere samples are first caugbt and 10' sample intervals tbrough target zones. PT5 Engineering Date: Commissioner: C;/¡ 111-- Geologic Commissioner: Date Public Commissioner Date 35 36 37 38 39 Conta_cll1amelphol1eJorweßlsly prpgressreports [expIQratPJ:Y 9nly] Yes Yes NA_ NA NA See_ Qrllltng Haz;ard_s _& Contin~encies_ s~çtion of appljcalion, Appr SFD Date 6/9/2004 _SeabedcPl1djtjpl1 survey (if Qff-shore) sands du_eJQ Qffsßtil1jectQrs have beenJeduced to _normal pressure l::Iydratesmay_b~enco_untered between_170Q & 2300' NO. P~(rl)it _D_atapresel1ted QI1 pote_ntial oveJRressure _ZOl1e$ .S~ts01ic_analysjs_ of shaJlow gas_zones BE',_6/9J04; NoH2SknQwnjn SchJad_er Expected reservojr ~re$Sl!.re iJ>_9.1 Bluff reservoirs at ppg EMW; wJII_bedrilled with 9,4 1:f3ad : 9,6 ppg mud, O.verpressure_d_ JS._CoyneJ,_ßP~ 6-9:04), Geology Date TEM 6/17/2004 ,At~ 1M ~(,.l\'1 Appr 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 can be issued w/o hydrogen s.ulfide O1eas_ures Js_ presenœ_ of Mecba_nicaLcondiUon Of H2S gas_ prQQablß weUs withil1 ~OR verified (f pr_ s_ervjce we QnM _C_hokemanifQld compJies w/API RP-53 (May 84) Work will PCc.ur withputoperatJon_shutdown Rdjvert _Drilling ',_,\,0 r--' ~",-," OJ ~"" BOPEs, do Jhey meet reguJation .BOPE_pres$ raiil1g ap~ropriate; Jest to.(puJ psig tn _comments) ",,:'" nrnnr~m ~~hematic_&. eCl-uipJistadequate .Adequate wellbore_ separatjo-" _pro~Osed it meet reguJa_tions_ .Adequatetank<lge_ OJ RaJe-¡j(ilt has a_ 10:403 for abandonment been apprQved re.serve pit _C_asing de_signs ad_equaie for knQwn-p[o.ductive horizQns C,_T~ B& permafrost .S_urfacecasing.pJQtects alLknQwn USOWs .CMT vol adeQl!.ate. to çirc.ulate.o_ncond.uctor CMT vol adeQ uate. to .CMT will co.ver all tie-in Jong string to surf çsg 8. su.rfcsg Yes NA Yes No No_ Yes Yes NA .Yes Yes Y~s Yes Yes Yes Y~s No_ NA Skip CQyner, Maximum PQten.tiaIJQrmatio.n.pressure 9.:1 _EMW,. MWpJa.nned 9, Noted jn potentiaJ hazards secliol1, Planne_d_ßQP. test (continue.d .from .abOlo'e) ßM$P calculated at 1478~si. pressure 3000 psi. 1 pp~, o.ver.pressure via fa_ult PQsJ>ible. I?rpJJ:imity analysis pertorme.d, Trayeling Cylinder provided, .Gyros avail<lble, Rig jsequippe.d_with J>teelpjts, No reserve.pjt~lanned. Wasle.tQ an ap~roYed disp.osal well. tntermedjaie_ cernentwill any cov_er bYdroçarbQn.~ones, $cree_ned compJeiiOI1 planned, All aqJJifers eJtempted 40 CFR 47.,102(b)(3). Engineering Conductor stril1gprovided . Appr 6/8/2004 Date Administration Well Jocated withil1 area and_sirata .authQrized by Injectipn Order # (Put 10# AJI wells_within .1l4.mile.are.a.of revißW identified (For servjcewell ooly). . . Pre-prpduced injector; .duration_of pre-productioo les~ than_ 3 mOl1tbs. (For. serytce well onJy) Jfdevia il1clu.ded _O~er.atl 11y qffected Pqrty. . _ _ .O~eratl ~s.appr9priate.b.ond tn.fQrce P~rmit. Permit c_an Can permit be approved before 15-day wait in_ comm.ents) (FQr. cao be iS$ued without ço_n$ervajiOI1 order be iSSl!.ed wjtbout ªd.ministrati\(e.a~provaJ js. weJlbore plat .Suffiçieot acreª~e.ayqilable indrilliog unjt n.a[1l~.and oumb.er Well .located ina d.efil1ed j)oQI WellJQcated prpper .distance. from driJling ul1itb.oUl1d.ary. Well JQcated pr_oper _distance_ from other wells 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 We drilled from exisiing pad .~ )ore. fQr.a tri-JateJql; will I der ßluff .Oil P.ool; CO A77. $1 ¡ties.only J O-acre spa_cing CQnJorming to_ 1tal.qtr-.qtr-.qtr secjiQl1sand more.tbaJ1_500' from the e rior bound~ry of the ~ffeçtec! area of.C_Q i ~on(orl1)s_ to the$e requiremeots,. . I~"" welll:1.3.has never been pertora.ted -it.", I,~, "",,,,,jo the PQol.Tbe Qther nearQyoffset 1-10~ 1-11. 8.1-11.L1 are not Qpen to io theNBsand, the pool J'.Jearbyoff~ð' I-Q6, -Q8, :~ n,.... nnon weiJs_ .U.nique well. Permit. fee attaçhe_d .Lease _number _appropriate_ LASK8 MILNE POINT, SCHRADER BLFF OIL - 525140 7 ACMP. Fïl1ding.of Con.siJ>tel1cy.ha$ bee.nissued_ for thi$ project INC Initial ClasslType Ye$ Yes .Yes Yes Yes Yes Y~s .Yes Y~s .Yes Yes .Y~s Yes NA NA. NA NA Primary well Surfaçe Ipcajioo in ADL025906;lop prod.uçtive injervaJ al1dlD_ il1 ADL OZ5517. ~ Well Name: MILNE PT UNIT SB DEV I PEND GeoArea ß9Q op.el1 NB-sOlod_ of -1J Unit Program DEV 11328 On/Off Shore go.verned_ byCQ4]7, On Well bore seg _ Annular Disposal o o e e Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding infonnation, 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. . Sperry-Sun Drilling Services LIS Scan Utility . /;0 f--()?g (;2.170 $Revision: 3 $ LisLib $Revision: 4 $ Fri Sep 03 14:51:28 2004 Reel Header Service name.......... ...LISTPE Date. . . . . . . . . . . . . . . . . . . . .04/09/03 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name.............. ..UNKNOWN Continuation Number... ...01 Previous Reel Name..... ..UNKNOWN Comments............. ....STS LIS Writing Library. Scientific Technical Services Tape Header Service name........... ..LISTPE Date. . . . . . . . . . . . . . . . . . . . .04/09/03 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name.............. ..UNKNOWN Continuation Number.... ..01 Previous Tape Name... ....UNKNOWN Comments............ .....STS LIS Writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER Milne Point MWD/MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA MPI-17 500292321200 B.P. Exploration (Alaska) Inc. Sperry-Sun Drilling Services 03-SEP-04 JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 1 MW0003171003 T. MCGUIRE D. GREEN MWD RUN 2 MW0003171003 C.A. DEMOSKI E. VAUGHN MWD RUN 3 MW0003171003 C.A. DEMOSKI E. VAUGHN JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 4 MW0003171003 C.A. DEMOSKI E. VAUGHN # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: 33 13N 10E 2323 3581 68.35 34.60 RECEIVED # WELL CASING RECORD OPEN HOLE CASING DRILLERS SEP! 2004 l\¡aska Oil & Gas Cons. Comm.øn Anøhorage 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING . BIT SIZE (IN) 13.500 9.875 6.750 SIZE (IN) 20.000 10.750 7.625 DEPTH (FT) 114.0 2378.0 5775.0 . # REMARKS: 1. ALL DEPTHS ARE MEASURED DEPTH (MD) UNLESS OTHERWISE NOTED. THESE DEPTHS ARE BIT DEPTHS. 2. ALL VERTICAL DEPTHS ARE TRUE VERTICAL DEPTH (TVD). 3. MWD RUN 1 COMPRISED DIRECTIONAL WITH DUAL GAMMA RAY (DGR) UTILIZING GEIGER-MUELLER TUBE DETECTORS. 4. MWD RUNS 2 - 4 COMPRISED DIRECTIONAL WITH DGR AND ELECTROMAGNETIC WAVE RESISTIVITY PHASE-4 (EWR4). RUN 4 ALSO INCLUDED AT-BIT INCLINATION (ABI). 5. DEPTH SHIFTING/CORRECTION OF MWD DATA WAS WAIVED PER E-MAIL FROM K. COONEY (SIS/BP), DATED 8/24/04, QUOTING AUTHORIZATION FROM MIKIE SMITH (BP GEOLOGIST). MWD DATA ARE CONSIDERED PDC. 6. MWD RUNS 1 - 4 REPRESENT WELL MPI-17 WITH API#: 50-029-23212-00. THIS WELL REACHED A TOTAL DEPTH (TD) OF 9253'MD/3723'TVD. SROP SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC SMOOTHED GAMMA RAY COMBINED. SEXP SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA SHALLOW SPACING) . SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (SHALLOW SPACING) . SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM SPACING) . SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP SPACING) . SFXE = SMOOTHED FORMATION EXPOSURE TIME (SEDP). SLIDE = NON-ROTATED INTERVALS. $ File Header Service name............ .STSLIB.001 Service Sub Level Name... Version Number... ....... .1.0.0 Date of Generation...... .04/09/03 Maximum Physical Record. .65535 File Type.......... ......LO Previous File Name..... ..STSLIB.OOO Comment Record FILE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE GR ROP FET 1 and clipped curves; all bit runs merged. .5000 START DEPTH 267.0 312.0 2343.5 STOP DEPTH 9195.0 9253.0 9202.0 RPD RPM RPS RPX $ . 2343.5 2343.5 2343.5 2343.5 9202.0 9202.0 9202.0 9202.0 . # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH $ # MERGED DATA SOURCE PBU TOOL CODE MWD MWD MWD MWD $ BIT RUN NO 1 2 3 4 MERGE TOP 267.0 2388.0 4183.0 5785.0 MERGE BASE 2388.0 4183.0 5785.0 9253.0 # REMARKS: MERGED MAIN PASS. $ # Data Format Specification Record Data Record Type..................O Data Specification Block Type... ..0 Logging Direction.. .... ......... ..Down Optical log depth units..... ......Feet Data Reference Point............. . Undefined Frame Spacing.. .................. .60 .1IN Max frames per record.. .......... .Undefined Absent value........... ......... ..-999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Name Service Order units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 RPX MWD OHMM 4 1 68 12 4 RPS MWD OHMM 4 1 68 16 5 RPM MWD OHMM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 FET MWD HOUR 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 267 9253 4760 17973 267 9253 ROP MWD FT/H 0.55 1068.52 205.416 17883 312 9253 GR MWD API 10.62 125.5 64.1955 17857 267 9195 RPX MWD OHMM 0.09 2000 115.919 13718 2343.5 9202 RPS MWD OHMM 1.68 2000 188.715 13718 2343.5 9202 RPM MWD OHMM 0.26 2000 276.846 13718 2343.5 9202 RPD MWD OHMM 0.25 2000 323.133 13718 2343.5 9202 FET MWD HOUR 0.09 46.48 1. 1776 13718 2343.5 9202 First Reading For Entire File.... ..... .267 Last Reading For Entire File...... .... .9253 File Trailer Service name............ .STSLIB.001 Service Sub Level Name... Version Number......... ..1.0.0 Date of Generation.... ...04/09/03 . Maximum Physical Record. .65535 File Type........ ...... ..LO Next File Name.......... .STSLIB.002 Physical EOF File Header Service name........... ..STSLIB.002 Service Sub Level Name... Version Number...... .....1.0.0 Date of Generation...... .04/09/03 Maximum Physical Record..65535 File Type.............. ..LO Previous File Name...... .STSLIB.001 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE GR ROP $ 2 . header data for each bit run in separate files. 1 .5000 START DEPTH 267.0 312.0 STOP DEPTH 2388.0 2388.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR $ BOTTOM) TOOL TYPE 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 TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL 13 -JUL- 04 Insite 66.37 Memory 2388.0 312.0 2388.0 5.5 13.8 TOOL NUMBER 61497 13.500 .0 SPUD MUD 9.30 75.0 8.5 500 10.8 .000 .000 .000 .000 .0 77.0 .0 .0 . . MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type....... ...........0 Data Specification Block Type.....O Logging Direction............... ..Down Optical log depth units....... ....Feet Data Reference Point.......... ....Undefined Frame Spacing................ .....60 .1IN Max frames per record........... ..Undefined Absent value............... ..... ..-999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Service Order Units FT FT/H API Size 4 4 4 Nsam 1 1 1 Code Offset o 4 8 Channel 1 2 3 Name DEPT ROP GR MWD010 MWD010 Rep 68 68 68 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 267 2388 1327.5 4243 267 2388 ROP MWD010 FT/H 0.55 892.46 181.728 4153 312 2388 GR MWD010 API 24.32 118.92 65.8669 4243 267 2388 First Reading For Entire File......... .267 Last Reading For Entire File.......... .2388 File Trailer Service name............ .STSLIB.002 Service Sub Level Name... Version Number.... .... ...1.0.0 Date of Generation... ....04/09/03 Maximum Physical Record. .65535 File Type............... .LO Next File Name.......... .STSLIB.003 Physical EOF File Header Service name............ .STSLIB.003 Service Sub Level Name... Version Number... ....... .1.0.0 Date of Generation...... .04/09/03 Maximum Physical Record. .65535 File Type............... .LO Previous File Name.. .... .STSLIB.002 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: 3 header data for each bit run in separate files. 2 . DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE RPM RPD RPS RPX FET GR ROP $ .5000 START DEPTH 2343.5 2343.5 2343.5 2343.5 2343.5 2388.5 2388.5 STOP DEPTH 4138.5 4138.5 4138.5 4138.5 4138.5 4146.0 4183.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 $ BOTTOM) TOOL TYPE DUAL GAMMA RAY ELECTROMAG. RES IS. 4 # 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 TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type....... ...... .....0 Data Specification Block Type.....O Logging Direction. . . . . . . . . . . . . . . . . Down Optical log depth units......... ..Feet Data Reference Point............. . Undefined Frame Spacing............. ....... .60 .1IN . 15-JUL-04 Insite 66.37 Memory 4183.0 2388.0 4183.0 13.6 55.4 TOOL NUMBER 053519 134758 9.875 2378.0 LSND 9.40 51. 0 9.5 640 6.6 2.600 1.800 2.200 3.000 65.0 97.0 65.0 65.0 . . Max frames per record............ . Undefined Absent value..................... .-999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 RPX MWD020 OHMM 4 1 68 12 4 RPS MWD020 OHMM 4 1 68 16 5 RPM MWD020 OHMM 4 1 68 20 6 RPD MWD020 OHMM 4 1 68 24 7 FET MWD020 HOUR 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 2343.5 4183 3263.25 3680 2343.5 4183 ROP MWD020 FT/H 19.35 1068.52 250.923 3590 2388.5 4183 GR MWD020 API 10.62 U8.89 65.0636 3516 2388.5 4146 RPX MWD020 OHMM 2.04 673.71 14.4059 3591 2343.5 4138.5 RPS MWD020 OHMM 2.24 678.65 15.3905 3591 2343.5 4138.5 RPM MWD020 OHMM 2.07 2000 18.132 3591 2343.5 4138.5 RPD MWD020 OHMM 0.25 2000 32.6395 3591 2343.5 4138.5 FET MWD020 HOUR 0.09 35.88 1.46318 3591 2343.5 4138.5 First Reading For Entire File......... .2343.5 Last Reading For Entire File.......... .4183 File Trailer Service name. ........... .STSLIB.003 Service Sub Level Name... Version Number......... ..1.0.0 Date of Generation...... .04/09/03 Maximum Physical Record. .65535 File Type........ ...... ..LO Next File Name........ ...STSLIB.004 Physical EOF File Header Service name............ .STSLIB.004 Service Sub Level Name... Version Number......... ..1.0.0 Date of Generation...... .04/09/03 Maximum Physical Record..65535 File Type............. ...LO Previous File Name..... ..STSLIB.003 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE FET RPD RPM 4 header data for each bit run in separate files. 3 .5000 START DEPTH 4139.0 4139.0 4139.0 STOP DEPTH 5740.0 5740.0 5740.0 . RPS RPX GR ROP $ 4139.0 4139.0 4146.5 4183.5 5740.0 5740.0 5747.5 5785.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 $ BOTTOM) TOOL TYPE DUAL GAMMA RAY ELECTROMAG. RES IS. 4 # 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 TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type. .................0 Data Specification Block Type.....O Logging Direction............... ..Down Optical log depth units. ......... .Feet Data Reference Point............. . Undefined Frame Spacing.. .................. .60 .1IN Max frames per record.. ...... .....Undefined Absent value....... ........ ...... .-999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O . 16-JUL-04 Insite 66.37 Memory 5785.0 4183.0 5785.0 56.5 107.9 TOOL NUMBER 053519 134758 9.875 2378.0 LSND 9.50 57.0 9.5 600 5.8 3.800 2.320 3.500 4.000 62.0 105.8 62.0 62.0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 . . ROP MWD030 FT/H 4 1 68 4 2 GR MWD030 API 4 1 68 8 3 RPX MWD030 OHMM 4 1 68 12 4 RPS MWD030 OHMM 4 1 68 16 5 RPM MWD030 OHMM 4 1 68 20 6 RPD MWD030 OHMM 4 1 68 24 7 FET MWD030 HOUR 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 4139 5785 4962 3293 4139 5785 ROP MWD030 FT/H 3.35 354.88 148.095 3204 4183.5 5785 GR MWD030 API 32.47 117.76 79.8539 3203 4146.5 5747.5 RPX MWD030 OHMM 1. 71 145.69 14.8897 3203 4139 5740 RPS MWD030 OHMM 1. 68 167.99 15.5932 3203 4139 5740 RPM MWD030 OHMM 1. 89 230.55 16.8816 3203 4139 5740 RPD MWD030 OHMM 3.14 198.17 17.3534 3203 4139 5740 FET MWD030 HOUR 0.24 9.26 0.837449 3203 4139 5740 First Reading For Entire File......... .4139 Last Reading For Entire File.......... .5785 File Trailer Service name..... ...... ..STSLIB.004 Service Sub Level Name... Version Number......... ..1.0.0 Date of Generation...... .04/09/03 Maximum Physical Record. .65535 File Type.......... .... ..LO Next File Name......... ..STSLIB.005 Physical EOF File Header Service name........ .....STSLIB.005 Service Sub Level Name... Version Number.. ........ .1.0.0 Date of Generation..... ..04/09/03 Maximum Physical Record..65535 File Type............... .LO Previous File Name..... ..STSLIB.004 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE RPD RPM RPS RPX FET GR ROP $ 5 header data for each bit run in separate files. 4 .5000 START DEPTH 5740.5 5740.5 5740.5 5740.5 5740.5 5748.0 5785.5 STOP DEPTH 9202.0 9202.0 9202.0 9202.0 9202.0 9195.0 9253.0 # LOG HEADER DATA . DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 $ BOTTOM) TOOL TYPE DUAL GAMMA RAY Electromag Resis. 4 # 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 TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type........... .......0 Data Specification Block Type.....O Logging Direction................ . Down Optical log depth units.......... .Feet Data Reference Point............. . Undefined Frame Spacing...... .... .......... .60 .1IN Max frames per record.......... ...Undefined Absent value..................... .-999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O 20-JUL-04 . Insite 66.37 Memory 9253.0 5785.0 9253.0 86.4 107.6 TOOL NUMBER 129046 162742 6.750 5775.0 Oil Based 9.50 63.0 .0 35000 .0 .000 .000 .000 .000 .0 108.9 .0 .0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD040 FT/H 4 1 68 4 2 GR MWD040 API 4 1 68 8 3 RPX MWD040 OHMM 4 1 68 12 4 RPS MWD040 OHMM 4 1 68 16 5 RPM MWD040 OHMM 4 1 68 20 6 RPD MWD040 OHMM 4 1 68 24 7 FET MWD040 HOUR 4 1 68 28 8 . . First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 5740.5 9253 7496.75 7026 5740.5 9253 ROP MWD040 FT/H 30.68 480.77 222.523 6936 5785.5 9253 GR MWD040 API 20 125.5 55.4503 6895 5748 9195 RPX MWD040 OHMM 0.09 2000 215.302 6924 5740.5 9202 RPS MWD040 OHMM 4.73 2000 358.691 6924 5740.5 9202 RPM MWD040 OHMM 0.26 2000 531.281 6924 5740.5 9202 RPD MWD040 OHMM 0.64 2000 615.244 6924 5740.5 9202 FET MWD040 HOUR 0.2 46.48 1.18684 6924 5740.5 9202 First Reading For Entire File......... .5740.5 Last Reading For Entire File....... ....9253 File Trailer Service name. ........... .STSLIB.005 Service Sub Level Name. . . Version Number.......... .1.0.0 Date of Generation... ... .04/09/03 Maximum Physical Record. .65535 File Type............... .LO Next File Name... ..... ...STSLIB.006 Physical EOF Tape Trailer Service name...... ...... .LISTPE Date. . . . . . . . . . . . . . . . . . . . .04/09/03 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name. .............. . UNKNOWN Continuation Number..... .01 Next Tape Name.......... . UNKNOWN Comments................ .STS LIS Writing Library. Scientific Technical Services Reel Trailer Service name..... ....... .LISTPE Date. . . . . . . . . . . . . . . . . . . . .04/09/03 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name. .............. . UNKNOWN Continuation Number..... .01 Next Reel Name....... ... . UNKNOWN Comments............ .....STS LIS Writing Library. Scientific Technical Services Physical EOF Physical EOF End Of LIS File