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Home My WebLink About197-0671. 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 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,643 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi Production 7,020psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10/30/2025 2-7/8" Baker FH & TE-5 4,206 (MD) 3,837 (TVD) & 332 (MD) 332 (TVD) 7,642' Perforation Depth MD (ft): 3,427' 4,356 - 6,342 7,642' 3,970 - 5,721 6,607'7" 13-3/8" 9-5/8"3,427' 1,075' MD 6,330psi 3,090psi1,062' 3,142' 1,075' Length Size Proposed Pools: L-80 TVD Burst 4,269 8,160psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018731 197-067 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20043-02-00 Hilcorp Alaska, LLC Trading Bay St A-08RD2 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager 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 Other: CTCO, N2 CO 93B Trading Bay Hemlock Oil, Middle Kenai C,D&E Oil Same 6,609 4,450 4,053 909psi 6,850 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:27 am, Oct 07, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.10.07 05:49:00 - 08'00' Dan Marlowe (1267) 325-608 DSR-10/15/25 CT BOP test to 3000 psi A.Dewhurst 14OCT25 X 10-404 BJM 10/15/25 10/16/2025 TBU A-08RD2 Fill Clean Out and Perforate Page 1 of 2 Well Name:TBU A-08RD2 API Number:50-733-20043-02-00 Current Status:Online, producer Permit to Drill Number:197-067 Estimated Start Date:10/30/25 Rig:Fox Coil Unit 9, Eline Regulatory Contact:Juanita Lovett Estimated Duration:7 days First Call Engineer:Eric Dickerman Cell Number:307-250-4013 Second Call Engineer:Casey Morse Cell Number:603-205-3780 Current Bottom Hole Pressure:1,314 psi at 4,048 TVD. June 2025 SBHPS. Max. Potential Surface Pressure:909 psi (Based on 0.1 psi/ft. gas gradient) Last Shut-in WHP:340 psi Min. ID:2.313 2-7/8 X nipple Max. Deviation:50 at 6,800 Field:Trading Bay Pools:Hemlock, Middle Kenai C, D, E. No pool change during operation. Brief Well Summary: Trading Bay State A-08 was completed on 11/11/1967 as a Hemlock, Kenai E, and Kenai D producer. The well was sidetracked to A-08RD and completed on 8/8/1998 as a Hemlock producer with Kenai C and D perforations added later. The well was redrilled and converted to a Hemlock injector in 1997, before being recompleted as a Kenai C and D producer in 2015. Slickline tagged top of fill at 4,469 on 6/9/2025, indicating that only the top two Kenai C intervals are above fill. Fluid rates have fallen below 25 bpd making production marginal. Objective: Coiled tubing fill cleanout down to ± 6,700. Eline perforate Middle Kenai E. TBU A-08RD2 Fill Clean Out and Perforate Page 2 of 2 Coiled Tubing Procedure: 1. MIRU Fox Energy offshore Coiled Tubing #9 and pressure control equipment. 2. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr BOP test witness notification. 3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out down to ± 6,700. a. Working fluid will be 3% KCl in Filtered Inlet Water (8.5 ppg). b. Take returns to surface up the CT x tubing annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 4. RDMO CT. Eline Procedure: 5. MIRU. Pressure test PCE to 250 psi low / 2,000 psi high. 6. Perforate the target Middle Kenai E sand intervals between a top at 6,451 MD / 5,812 TVD and a bottom at 6,586 MD / 5,918 TVD. a. All perforations in the Trading Bay Field Middle Kenai E Oil Pool. b. All runs will be fully lubricated. 7. RDMO Eline. Attachments: 1. Wellbore Schematic Current 2. Wellbore Schematic - Proposed 3. CT BOP schematic (Fox Energy) 4. Standard nitrogen procedure Updated: 03/10/25 by JLL Trading Bay Unit Monopod Platform Well # A-08RD2 Completed: 03/01/15 PTD: 197-067 API: 50-733-20043-02 SCHEMATIC PBTD = 6,850 TD = 7,643 MAX. HOLE ANGLE = 52 RKB to TBG Head = 38.52 6 4,450 SLM Tag fill 9/29/22 3 1 HB C 4 7 2 5 13-3/8 8 D X 9 9-5/8 7 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8 61# J-55 12.515 Surf 1,075 9-5/8 43.5# J-55 / N-80 8.755 Surf 3,415 (KOP) Window cut in 9-5/8 Casing 3,415 3,427 7 29# L-80 Butt 6.184 Surf 7,642 Tubing: 2-7/8 6.5# L-80 8rd EUE 2.441 Surf 4,269 JEWELRY DETAIL NO.Depth MD Depth TVD ID OD Item Hanger 1 332 332 2.312 4.620 TE-5 Safety Valve w/ BX Profile 2 2,257 2,107 2.441 GLM 2-7/8 SPM-1, IPOR-1/IPOC-1/PPOR-1 3 3,404 3,121 2.441 GLM 2-7/8 SPM-1, IPOR-1/IPOC-1/PPOR-1 4 4,016 3,670 2.441 GLM 2-7/8 SPM-1, Orifice-1 5 4,157 3,794 2.441 3.000 Chemical Injection Mandrel 6 4,206 3,837 2.441 5.940 Baker FH Retrievable Packer 7 4,256 3,881 2.312 3.227 X Nipple 8 4,269 3,893 2.441 3.690 WLEG 9 6,850 6,099 CIBP Perforation Details Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Accum SPF Last Perf Date Present Condition C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Isolated HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Isolated HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Isolated Cement Details: 13-3/8 Cmt w/1200 sks Class G to surface. Cement noted in riser confirming returns to surface (10/14/67) 9-5/8 Cmt w/800 sks (11/3/67). CBL logged cement top at 1,135 MD (7/8/89) 7 CBL logged TOC at 1,420 (7/4/97) Cmt w/ 175 bbl, 12.9 PPG lead, 60 bbl, 15.8 PPG tail. Updated: 10/02/25 by EPD Trading Bay Unit Monopod Platform Well # A-08RD2 Completed: 03/01/15 PTD: 197-067 API: 50-733-20043-02 PROPOSED SCHEMATIC PBTD = 6,850 TD = 7,643 MAX. HOLE ANGLE = 52 RKB to TBG Head = 38.52 6 4,450 SLM Tag fill 9/29/22 3 1 HB C 4 7 2 5 13-3/8 8 D E X 9 9-5/8 7 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8 61# J-55 12.515 Surf 1,075 9-5/8 43.5# J-55 / N-80 8.755 Surf 3,415 (KOP) Window cut in 9-5/8 Casing 3,415 3,427 7 29# L-80 Butt 6.184 Surf 7,642 Tubing: 2-7/8 6.5# L-80 8rd EUE 2.441 Surf 4,269 JEWELRY DETAIL NO.Depth MD Depth TVD ID OD Item Hanger 1 332 332 2.312 4.620 TE-5 Safety Valve w/ BX Profile 2 2,257 2,107 2.441 GLM 2-7/8 SPM-1, IPOR-1/IPOC-1/PPOR-1 3 3,404 3,121 2.441 GLM 2-7/8 SPM-1, IPOR-1/IPOC-1/PPOR-1 4 4,016 3,670 2.441 GLM 2-7/8 SPM-1, Orifice-1 5 4,157 3,794 2.441 3.000 Chemical Injection Mandrel 6 4,206 3,837 2.441 5.940 Baker FH Retrievable Packer 7 4,256 3,881 2.312 3.227 X Nipple 8 4,269 3,893 2.441 3.690 WLEG 9 6,850 6,099 CIBP Perforation Details Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Accum SPF Last Perf Date Present Condition C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open E 6,451 6,464 5,812 5,823 13 6 TBD E 6,522 6,586 5,869 5,918 64 6 TBD HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Isolated HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Isolated HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Isolated Cement Details: 13-3/8 Cmt w/1200 sks Class G to surface. Cement noted in riser confirming returns to surface (10/14/67) 9-5/8 Cmt w/800 sks (11/3/67). CBL logged cement top at 1,135 MD (7/8/89) 7 CBL logged TOC at 1,420 (7/4/97) Cmt w/ 175 bbl, 12.9 PPG lead, 60 bbl, 15.8 PPG tail. STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier 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 Tank. 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 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,643 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi Production 7,020psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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 3/25/2025 2-7/8" Baker FH & TE-5 4,206 (MD) 3,837 (TVD) & 332 (MD) 332 (TVD) 7,642' Perforation Depth MD (ft): 3,427' 4,356 - 6,342 7,642' 3,970 - 5,721 6,607'7" 13-3/8" 9-5/8"3,427' 1,075' MD 6,330psi 3,090psi1,062' 3,142' 1,075' Length Size Proposed Pools: L-80 TVD Burst 4,269 8,160psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018731 197-067 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20043-02-00 Hilcorp Alaska, LLC Trading Bay St A-08RD2 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager 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 Other: Cleanout / Run GL Completion CO 93B Trading Bay Hemlock Oil, Middle Kenai C,D&E Oil Middle Kenai B Oil & Hemlock Oil, Middle Kenai C,D&E Oil 6,609 6,850 6,099 898psi 6,850 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:35 pm, Mar 11, 2025 325-138 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.03.11 10:53:58 - 08'00' Dan Marlowe (1267) 10-404 DSR-3/24/25A.Dewhurst 13MAR25 Middle Kenai B Oil MGR13MAR2025 Perforate New Pool * BOPE test to 3000 psi. Annular to 2500 psi. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.26 08:30:47 -08'00'03/26/25 RBDMS JSB 032725 Trading Bay State A-08RD2 RWO for FCO Re-run completion Well Name:A-08RD2 API Number:50-733-20043-02-00 Current Status:Online, Producer Leg:Monopod Regulatory Contact:Juanita Lovett Permit to Drill Number:197-067 First Call Engineer:Eric Dickerman 307-250-4013 Second Call Engineer:Casey Morse 907-777-8322 Maximum Expected BHP:1,375 psi at 4,770’ tvd – A-13 ESP pressure gauge (2/23/25) - (5.6 ppg KWF) Max. Potential Surface Pressure:898 psi - Using 0.1 psi/ft to surface Applicable Frac Gradient:0.87 psi/ft, EMW 16.8 ppg, A-08RD2 LOT on 6/24/1997 at 9-5/8” window (3,415’ md) Shallowest Allowable Perf TVD:MPSP/(0.87 – 0.1 psi/ft) = 898 psi / 0.77 psi/ft = 1,166’ tvd Top of Applicable Pool:3,124’ md / 2,867’ tvd – Top of Middle Kenai B Oil Pool Well Summary: Trading Bay State A-08 was completed on 11/11/1967 as a Hemlock, Kenai E, and Kenai D producer. The well was sidetracked to A-08RD and completed on 8/8/1998 as a Hemlock producer with Kenai C and D perforations added later. The well was redrilled and converted to a Hemlock injector in 1997, before being recompleted as a Kenai C and D producer in 2015. Slickline tagged top of fill at 4,451’ on 9/29/2022, indicating that only the top two Kenai C intervals are above fill. Fluid rates have fallen below 25 bpd making production marginal. Objective: Rig workover to pull existing gas lift completion, clean out the 7” production casing, perforate the target Middle Kenai intervals, then run a gas lift completion. Notes on Wellbore condition: - Most recent casing test: Passed 1,500 psi on 3/1/2015. - The 2015 workover utilized 3% KCl (8.6ppg) as the completion fluid. - Slickline tagged top of fill at 4,451’ on 9/29/2022. Trading Bay State A-08RD2 RWO for FCO Re-run completion RWO Procedure: 1. Skid Monopod Rig 56 in to position over A-08RD2. 2. RU eline with lubricator. PT PCE to 250 psi low / 2,500 psi high. Punch tubing below packer ± 4,220’ md. Punch tubing above packer ± 4,145’ md. RD eline. 3. Perform well kill: a. KWF will be 8.6 ppg 3% KCl. b. Ensure any wellbore fluids are fully displaced with KWF either via circulation or bullheading. c. Total WBV = 247 bbl. i. 2-7/8” tubing volume to 4,269’ = 25 bbl. ii. 7” x 2-7/8” IA volume to 4,206’ = 123 bbl. iii. 7” Production casing volume from 4,206’ – 6,850’ = 99 bbl. 4. Set BPV/TWC, ND tree, NU Hilcorp BOP stack (see attached). a. Notify AOGCC 48 hours in advance for witness. b. Test BOPE to 250psi Low / 3,000psi High / 2,500psi Annular. c. BOPE will be used as needed to circulate the well. d. 3-1/2” workstring planned. 5. Pull BPV/TWC. 6. Pull hanger to floor, then lay down existing 2-7/8” completion. Expected PUW 29k #. 7. Set 7” test packer at ± 3,950’ and perform casing test to 1,500 psi for a charted 30 minute test. 8. MU cleanout BHA and clean out down to ± 6,750’. 9. MU TCP guns on workstring per RE and GEO perforating table. Perforate target intervals with eline GR/CCL correlation. a. New perforations, Kenai B target intervals, ± 3,890’ to ± 3,952’ md. b. New perforations, Kenai E target intervals, ± 6,451’ – 6,464’ and ± 6,522’ – 6,586’ md. c. Re-perf existing Kenai C and Kenai D intervals based on clean out results, 4,356’ – 6,342’ md. d. Deepest proposed perf = 6,586’ md / 5,917’ tvd. e. Shallowest proposed perf = 3,890’ md / 3,558’ tvd. 10. Circulate well clean, ensure no flow, POOH and lay down TCP guns. 11. Run new 2-7/8” gas lifted upper completion. a. Target packer at ± 3,840’ md (3,514’ tvd). b. Tubing retrievable subsurface safety valve planned at ± 330’ md (330’ tvd). c. Completion to be ran with live GLVs. 12. Land completion and set production packer. 13. MIT-T to 1,500 psi for a charted 30 minute test. 14. CMIT-TxIA to 1,500 psi for a charted 30 minute test. 15. Set BPV/TWC, ND BOP. 16. NU tree and test, pull BPV/TWC. 17. RDMO RWO crew and equipment. 18. Slickline to pull packer setting equipment as needed. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current Wellhead Diagram (No Change) 4. BOP Drawing 5. Fluid/Flow Diagram 6. RWO Sundry Change Form Updated: 03/10/25 by JLL Trading Bay Unit Monopod Platform Well # A-08RD2 Completed: 03/01/15 PTD: 197-067 API: 50-733-20043-02 SCHEMATIC PBTD = 6,850’ TD = 7,643’ MAX. HOLE ANGLE = 52q RKB to TBG Head = 38.52’ 6 4,450’ SLM Tag fill 9/29/22 3 1 HB C 4 7 2 5 13-3/8” 8 D X 9 9-5/8” 7” CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8” 61# J-55 12.515 Surf 1,075’ 9-5/8” 43.5# J-55 / N-80 8.755 Surf 3,415’ (KOP) Window cut in 9-5/8” Casing 3,415’ 3,427’ 7” 29# L-80 Butt 6.184 Surf 7,642’ Tubing: 2-7/8” 6.5# L-80 8rd EUE 2.441 Surf 4,269’ JEWELRY DETAIL NO.Depth MD Depth TVD ID OD Item Hanger 1 332’ 332’ 2.312” 4.620” TE-5 Safety Valve w/ BX Profile 2 2,257’ 2,107’ 2.441” GLM – 2-7/8” SPM-1, IPOR-1/IPOC-1/PPOR-1 3 3,404’ 3,121’ 2.441” GLM – 2-7/8” SPM-1, IPOR-1/IPOC-1/PPOR-1 4 4,016’ 3,670’ 2.441” GLM – 2-7/8” SPM-1, Orifice-1 5 4,157’ 3,794’ 2.441” 3.000” Chemical Injection Mandrel 6 4,206’ 3,837’ 2.441” 5.940” Baker FH Retrievable Packer 7 4,256’ 3,881’ 2.312” 3.227” X Nipple 8 4,269’ 3,893’ 2.441” 3.690” WLEG 9 6,850’ 6,099’ CIBP Perforation Details Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Accum SPF Last Perf Date Present Condition C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Isolated HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Isolated HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Isolated Cement Details: 13-3/8” Cmt w/1200 sks Class G to surface. Cement noted in riser confirming returns to surface (10/14/67) 9-5/8” Cmt w/800 sks (11/3/67). CBL logged cement top at 1,135’ MD (7/8/89) 7” CBL logged TOC at 1,420’ (7/4/97) Cmt w/ 175 bbl, 12.9 PPG lead, 60 bbl, 15.8 PPG tail. Updated: 03/10/2025 EPD Trading Bay Unit Monopod Platform Well # A-08RD2 Completed: Proposed PTD: 197-067 API: 50-733-20043-02 PROPOSED PBTD = 6,850’ TD = 7,643’ MAX. HOLE ANGLE = 52q RKB to TBG Head = 38.52’ 6 3 1 HB C 4 7 2 8 D E X 9 13-3/8” 9-5/8” 7” B CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8” 61# J-55 12.515 Surf 1,075’ 9-5/8” 43.5# J-55 / N-80 8.755 Surf 3,415’ (KOP) Window cut in 9-5/8” Casing 3,415’ 3,427’ 7” 29# L-80 Butt 6.184 Surf 7,642’ Tubing: 2-7/8” 2.441 Surf ±3,890’ JEWELRY DETAIL NO.Depth MD Depth TVD ID OD Item Hanger 1 ±330’ ±330’ 2.312” TRSV 2 ±2,000’ ±1,882’ 2.441” GLM 3 ±3,038’ ±2,790’ 2.441” GLM 4 ±3,790’ ±3,470’ 2.441” GLM 6 ±3,840’ ±3,514’ 2.441” Packer 7 ±3,860’ ±3,532’ 2.25” 3.227” XN Nipple 8 ±3,890’ ±3,558’ 2.441” 3.690” WLEG 9 6,850’ 6,099’ CIBP Perforation Details Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Accum SPF Last Perf Date Present Condition B ±3,890 ±3,952’ ±3,558’ ±3,613’ ±62’ Proposed C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open E ±6,451’ ±6,464’ ±5,812’ ±5,822’ ±13’ Proposed E ±6,522’ ±6,586’ ±5,868’ ±5,917’ ±64’ Proposed HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Isolated HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Isolated HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Isolated Cement Details: 13-3/8” Cmt w/1200 sks Class G to surface. Cement noted in riser confirming returns to surface (10/14/67) 9-5/8” Cmt w/800 sks (11/3/67). CBL logged cement top at 1,135’ MD (7/8/89) 7” CBL logged TOC at 1,420’ (7/4/97) Cmt w/ 175 bbl, 12.9 PPG lead, 60 bbl, 15.8 PPG tail. Monopod Platform A-8RD2 Current 02/10/2015 Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M EFO, X-bottom prep w/ 1 ½ VR profile Valve, Foster Dual-Seal, 2 1/16 5M FE, HWO, AA Monopod A-8RD2 13 3/8 X 9 5/8 X 7 X 3 1/2 2'’LP plug valve Casing head, Shaffer-KD, 13 5/8 3M X 13'’ SOW bottom, w/ 2'’ LPO Casing spool, CIW-WF, 13 5/8 3M X 13 5/8 3M, w/ 2- 2 1/16 5M SSO Valve, WKM-M, 2 1/16 5M FE, HWO, AA Tubing hanger, CIW-DCB, 11 X 3 1/2 8rd EUE lift and 3 ½ DSS-HTC susp, w/ 3'’ type H BPV profile, 6 ¼'’ EN, 2-¼’’ CCL , 1- 3/8'’ CCL, 410 SS material Adapter, Cameron, 11 5M Stdd X 3 1/8 5M stdd, prepped for 6 ¼ neck, 3- ½ cont control line exit Valve, Swab, WKM-M, 3 1/8 5M FE, HWO, DD trim BHTA, Bowen, 3 1/8 5M X 2.5 Bowen quick union Valve, Wing, WKM-M, 3 1/8 5M FE, w/ 15'’ OMNI operator, DD trim Valve, Master, WKM-M, 3 1/8 5M FE, HWO, DD trim Monopod Platform 2025 BOP 01/22/2025 Drill deck 1.76' Riser 13 5/8 5M FE X 13 5/8 5M FE 14.20'’ UOCD 1911 13 5/8 5M Shaffer Shaffer SL Mud Cross 13 5/8 5M FE X FE w/ 3 1/8 5M EFO w/ 2 1/16 5M manual and HCR valves for choke and kill lines 3.74' 13 5/8 5M Rig Floor 16'’ Pipe 2 7/8-5.5 Variables Blind 26.25' Bottom of air boot flange 5' below rig floor 2.83' Spool 13 5/8 5M X 11 5M1.00' 14.20' Hilcorp Monopod Rig 56 Flow Diagram LEGEND: Fluids Pumped Fluids Returned Valve Open Valve Closed Gate Valve Ball Valve Butterfly Valve Lo Torq Valve Automatic Choke Manual Choke Pressure Gauge Knife Valve MUD PUMP 4.30' PIT SYSTEM CHOKE MANIFOLD Choke Line Panic Line C12 C13 C15 C14 C16 AB C4 C5 C6 C7C2 C10 C9 C11 C8 C3 P HCR1 Open ClosedClosedOpen Open Open OpenAnnular VBR BLIND SucƟon MUD PUMP SHAKERSHAKERKill Line Trip Tank P P C1 C GAS BUSTER HCR2 4” Demco kill line Flow line P P Hilcorp Monopod Rig 56 Flow Diagram Reverse Circulating 4” Demco kill line LEGEND: Fluids Pumped Fluids Returned Valve Open Valve Closed Gate Valve Ball Valve Butterfly Valve Lo Torq Valve Automatic Choke Manual Choke Pressure Gauge Knife Valve MUD PUMP 4.30' PIT SYSTEM CHOKE MANIFOLD Choke Line Panic Line C12 C13 C15 C14 C16 AB C4 C5 C6 C7C2 C10 C9 C11 C8 C3 P HCR1 Open ClosedOpenOpen Open Open ClosedAnnular VBR BLIND SucƟon MUD PUMP SHAKERSHAKERKill Line Trip Tank P P C1 C GAS BUSTER HCR2 Flow line P P 4 11 C To Gas Buster White Normally Open 3-6-7-15 Black Normally Closed 1-2-4-5-8-9-10 11-12-13-14-16 From BOP 1413 10 12 3 2 8 1 B 5 6 7 A 9 16 15 D To Panic Line To Sending Unit Monopod Rig 51 Choke Manifold Item 3 & 5 4, 13, 15, 16 1-2, 6-12, 14 A B-C D ĞƐĐƌŝƉƟŽŶ 3 1/8 5M Vetco 2200T Gate Valve 4 1/16 5M Cameron Gate Valve 3 1/8 5M Cameron Gate Valve Swaco 2 9/16 10M Super Choke 3 1/8 5M Cameron H2 Manual Choke 3 1/8 5M Cameron H2 PosiƟve Choke Install 4 1/16 5M API instrument Ňange below panic line w/ ½ npt drain ports Monpopod Valve Alignment –Long Way Valve PosiƟon (O- Open/ C- Closed Monpopod Valve Alignment –Reverse Valve PosiƟon (O- Open/ C-Closed Annular O Annular C VBR O VBR O Blind O Blind O C1 C C1 C C2 C C2 C C3 O C3 O C4 C C4 C C5 C C5 C C6 O C6 O C7 O C7 O C8 C C8 C C9 C C9 C C10 C C10 C C11 C C11 C C12 C C12 C C13 C C13 C C14 C C14 C C15 O C15 O C16 C C16 C HCR1 C HCR1 C Wing1 (W1) O Wing1 (W1) O HCR2 C HCR2 C Wing2 (W2) O Wing2 (W2) O Demco4”KillLine C Demco4”KillLine O Stand Pipe Valve (SP1) O Stand Pipe Valve (SP1) C Cement Line (CL1) C Cement Line (CL1) C Trip Tank 1 (TT1) C Trip Tank 1 (TT1) C Reverse Line (RV1) C Reverse Line (RV1) O Mud Pump 1 (MP1) O Mud Pump 1 (MP1) O Mud Pump 2 (MP2) O Mud Pump 2 (MP2) O Mud Pump 3 (MP3) O Mud Pump 3 (MP3) O Mud Pump 4 (MP4) O Mud Pump 4 (MP4) O Pit Outlet 1 (PO1) O Pit Outlet 1 (PO1) O Pit Outlet 2 (PO2) C Pit Outlet 2 (PO2) C Pit Outlet 3(PO3) C Pit Outlet 3(PO3) C MP3 SP1 PO3PO2 MP4 MP1MP2 MP3MP4MP1MP2 W2 W1 W2 CEMENT LINE W1 TT1 TT1 RV1 RV1 CL1 PO1 PO3PO2PO1 Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well: Trading Bay St A-08RD2 (PTD 197-067) 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. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date • . Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday,August 16,2016 8:55 AM To: 'Juanita Lovett' Cc: Trudi Hallett; Dan Marlowe;samantha.carlisle@alaska.gov Subject: RE:Withdraw Sundry#315-575 PTD: 197-067 -Well:Trading Bay St A-08RD2 Juanita, The AOGCC will withdraw sundry 315-575 as per your request below. Regards, Guy Schwartz Sr. Petroleum Engineer ,. AOGCC �E� � � L.�j 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). From: Juanita Lovett fmailto:llavett@hilcorp.com] Sent: Monday, August 15, 2016 12:48 PM To: Schwartz, Guy L(DOA) Cc: Trudi Hallett; Dan Marlowe Subject: Withdraw Sundry # 315-575 PTD: 197-067 -Well: Trading Bay St A-08RD2 Guy, Please withdraw the above mentioned sundry. The project will not be completed at this time. Scope of work was to add perforations. Thank you Juanita Lovett Operations/Regulatory Tech Hilcorp Alaska,LLC 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Office: (907)777-8332 Email: ilovett@hilcorp.com 1 RBDMS L‘, AUG 2 5 2016 OF Tgp THE STATE Alaska Oil and Gas ' - Of T Conservation Commission , sKA _ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OFALAS' Fax: 907.276.7542 www.aogcc.alaska.gov Trudi Hallett iCANNED N O V 1 2 2015 Operations Engineer -.O 67 Hilcorp Alaska, LLCq7 3800 Centerpoint Drive, Suite Su tc 1400 Anchorage, AK 99503 Re: Trading Bay Field, Middle Kenai C, Middle Kenai D, Middle Kenai E, and Hemlock Oil Pools, Trading Bay St A-08RD2 Sundry Number: 315-575 Dear Ms. Hallett: 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, 3aAc6- 1,cars2A._. gs\(- Cathy P. Foerster r Chair DATED thid7 day of September, 2015 RBDMCS SEP 2 5 2015 Encl. III •• RECEIVED STATE OF ALASKA 'E P 18 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Suspend❑ Perforate 2 - Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrii El Perforate New Pool El Repair Well ❑ Re-enter Susp Well ❑ Other: El 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC ' Exploratory ❑ Development [J' 197-067 , 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20043-02 , 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 938 Will planned perforations require a spacing exception? Yes ❑ No CI/ Trading Bay St A-08RD2 , 9.Property Designation(Lease Number): 10.Field/Pool(s): M t I 144) ADL0018731 I Ifl Trading Bay Field/Middle Kenai C&Middle Kenai D Oil Pools t IE.�C,:G` OJL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 7,643 - 6,608 - 7,410 • 6,458 6,850 N/A Casing Length Size MD ND Burst Collapse Structural Conductor Surface 1,075' 13-3/8" 1,075' 1,062' 3,090 psi 1,540 psi Intermediate 7,082' 9-5/8" 7,082' 6,247' 6,330 psi 3,810 psi Production 7,642' 7" 7,642' 6,607' 8,160 psi 7,020 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic See Schematic 2-7/8" 6.5#/L-80 4,269 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Baker FH Ret.Pkr&TE-5 SSSV - 4,206'(MD)3,837'(TVD)&332'(MD)332'(TVD) 12.Attachments: Description Summary of Proposal ❑, 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ svelopment 0, Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 10/2/2015 OIL 0 ' WINJ ❑ WDSF❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTO❑ SPLUG ❑ Commission Representative: GIN,' ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Trudi Hallett Email thallettehilcorp.com Printed Name ��/�� Trudi Hallett Title Operations Engineer Signature '2I "U-OL �� Phone (907)777-8323 Date 9/18/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: I - G/6 G,7 G Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ElLocation Clearance ❑ Other: Spacing Exception Required? Yes ❑ No Subsequent Form Required: /e) — /0 41 �+ ` aitp�I (t C,/�, t Qi n APPROVED SI � 1 epi// 16 Approved by: o IJ'U�}/.,w' .�(Sv�" MMISSIONER THE COMMISSION Date: 1 1 ilkf�5 �fzZ• i> -'CCSc N .--\-s ORIGINAL � 2<�� , � RBDMS EP 2 5 2015 q/ `� Submit Form and Form 10-403 Revised 5/2015 Approved application is valid for 12 months from t e date of approval. Attachments in Duplicate 14 • • Well Work Prognosis Well: A-08RD2 Hilcorp Alaska,LLC Date: 9/18/2015 Well Name: Monopod A-08RD2 API Number: 50-733-20043-02 Current Status: Producer Leg: N/A Estimated Start Date: October 2, 2015 Rig: Moncla 404 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 197-067 First Call Engineer: Trudi Hallett (907)777-8323 (0) (907) 301-6657 (M) Second Call Engineer: Ted Kramer (907)777-8420(0) (985)867-0665 (M) Current BHP: 2069 psi @ 3970'TVD/4356' MD Max. Exp'd BHP: 2069 psi @ 3970'TVD/4356' MD Max Anticipated Surface Pressure(MASP): 1672 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary Well A-08RD2 is a gas-lift producer completed in the Trading Bay Field Middle Kenai C and D Oil Pools. This project will add ±50' of Middle Kenai E Oil Pool sands to increase productivity in the main II-A Fault Block. Procedure: • 1. MIRU E-line unit. — p•1- 2. Correlate on depth. 3. Add perforations per perforation request: Zone Bench Top, MD Btm, MD Total Ft E 58-1 ±6,452' ±6,460' ±8 E 58-7 ±6,528' ±6,570' ±42 4. Rig down E-Line. 5. Return well to production. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic • . 11 SCHEMATIC Monopod Platform • Well #A-08RD2 Completed: 3/1/15 API # 50-733-20043-02 API#50-733-20043-02 CASING AND TUBING DETAIL RKB to TBG Head=38.52' SIZE WT GRADE CONN ID TOP BTM. i IIIMiii 1L 13-3/8" 61# J 55 12.515 Surf 1,075' 9-5/8" 43.5# J-55/N-80 8.755 Surf 3,415' (KOP) Window cut in 9-5/8"Casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' 2 Tubing: 2-7/8" 6.5# L-80 8rd EUE Surf 4,269' 3 JEWELRY DETAIL - - NO. Depth ID Item 4 Hanger 1 332' 2.292 TE-5 Safety Valve 5 6 2 2,257' 2.441 GLM-2-7/8"SPM-1,IPOR-1/IPOC-1/PPOR-1 OM 7 3 3,404' 2.441 GLM-2-7/8"SPM-1,IPOR-1/IPOC-1/PPOR-1 am 4 4,016' 2.441 GLM-2-7/8"SPM-1,Orifice-1 8 5 4,157' 2.441 Chemical Injection Mandrel 6 4,206' 2.441 Baker FH Retrievable Packer 7 4,256' 2.310 X Nipple 8 4,269' 2.441 WLEG 9 6,850' CIBP C Perforation Details Top Btm Top Accum Last Present Zone (MD) (MD) (TVD) Btm(TVD) Amt SPF Perf Date Condition C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open 1.D C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open -"E''''..' _ -- 9 C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open - D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open HB D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open = HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Open HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Open HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Open J PBTD=7,555' TD=7,643' MAX.HOLE ANGLE =52° Updated: 04/01/15 by JLL • PROPOSED Monopod Platform Well #A-08RD2 Completed: 3/1/15 API # 50-733-20043-02 API#50-733-20043-02 CASING AND TUBING DETAIL RKB to TBG Head=38.52' SIZE WT GRADE CONN ID TOP BTM. L. 13-3/8" 61# 1-55 12.515 Surf 1,075' ....1 p-vi 9-5/8" 43.5# J-55/N-80 8.755 Surf 3,415' (KOP) Window cutin 9-S/8"Casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' )2 Tubing: 2-7/8" 6.5# L-80 8rd EUE Surf 4,269' 3 JEWELRY DETAIL 4 - NO. Depth ID Item 4 Hanger MB i 5 1 332' 2.292 TE-5 Safety Valve 6 2 2,257' 2.441 GLM-2-7/8"SPM-1,IPOR-1/IPOC-1/PPOR-1 INIt 7 3 3,404' 2.441 GLM-2-7/8"SPM-1,IPOR-1/IPOC-1/PPOR-1 AIM 4 4,016' 2.441 GLM-2-7/8"SPM-1,Orifice-1 8 5 4,157' 2.441 Chemical Injection Mandrel 6 7 8 9 4,206' 2.441 Baker FH Retrievable Packer 4,256' 2.310 X Nipple 4,269' 2.441 WLEG 6,850' CIBP C Perforation Details Top Btm Top Accum Last Present Zone (MD) (MD) (TVD) Btm(TVD) Amt SPF Perf Date Condition C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open D C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open E ✓ C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open 9 C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open -_ D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open - D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open HB D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open = E 58-1 ±6,452' ±6,460' ±5,813' ±5,819' ±8' Future E 58-7 ±6,528' ±6,570' ±5,873' ±5,905' ±42 Future HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Open HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Open HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Open PBTD=7,555' TD=7,643' MAX.HOLE ANGLE =52° Updated: 09/01/15 by JLL RECFIVED STATE OF ALASKA ALS. ,A OIL AND GAS CONSERVATION COME .,ION APR 01 2 2G;,) REPORT OF SUNDRY WELL OPERATIONS _ 1.Operations Abandon El Repair Well ❑ Plug Perforations El Perforate❑ Other�' I I Es WConvert Performed: to Producer Alter Casing ❑ Pull Tubing Stimulate-Frac ElStimulate ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development❑ Exploratory❑ 197-067 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service 2 6.API Number: Anchorage,AK 99503 50-733-20043-02 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018731 Trading Bay St A-08RD2 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Trading Bay Field/Middle Kenai C&Middle Kenai D Oil Pools 11.Present Well Condition Summary: Total Depth measured 7,643 feet Plugs measured 6,850 feet true vertical 6,608 feet Junk measured N/A feet Effective Depth measured 7,410 feet Packer measured 4,206 feet true vertical 6,458 feet true vertical 3,837 feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,075' 13-3/8" 1,075' 1,062' 3,090 psi 1,540 psi Intermediate 7,082' 9-5/8" 7,082' 6,247' 6,330 psi 3,810 psi Production 7,642' 7" 7,642' 6,607' 8,160 psi 7,020 psi Liner Perforation depth Measured depth See Schematic feet t a P 2 2.015 SCANNED True Vertical depth See Schematic feet Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5#/L-80 4,269'(MD) 3,893'(ND) 4,206'(MD) 332'(MD) Packers and SSSV(type,measured and true vertical depth) Baker FH Ret.Pkr 3,837'(ND) TE-5 SSSV 332'(ND) 12.Stimulation or cement squeeze summary: 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 0 250 260 100 Subsequent to operation: 375 367 1719 926 118 14.Attachments: 15.Well Class after work. Copies of Logs and Surveys Run Exploratory❑ Development[] Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil El Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-062 Contact Trudi Hallett Email thallettCc�hilcorp.com Printed Name Trudi Hallett Title Operations Engineer Signaturei1jU Phone (907)777-8323 Date 4/1/2015 Form 10-404 Revised 10/2012 4-Zj-I� Subrvi9riginal Only :; N1/1r Jam' RBDMSAPR 6 2015 . Trading Bay Unit SCHEMATIC Monopod Platform Well #A-08RD2 Completed: 3/1/15 API # 50-733-20043-02 API#50-733-20043-02 CASING AND TUBING DETAIL RKB to TBG Head=38.52' SIZE WT GRADE CONN ID TOP BTM. i i 13-3/8" 61# J-55 12.515 Surf 1,075' 9-5/8" 43.5# J-55/N-80 8.755 Surf 3,415' (KOP) Window cut in 9-5/8"Casing 3,415' 3,427' II. 2 7" 29# L-80 Butt 6.184 Surf 7,642' Tubing: 2-7/8" 6.5# L-80 8rd EUE Surf 4,269' )3 JEWELRY DETAIL NO. Depth ID Item 4 Hanger 5 • 1 332' 2.292 TE-5 Safety Valve 6 LI 1--`;& 2 2,257' 2.441 GLM-2-7/8"SPM-1,IPOR-1/1POC-1/PPOR-1 MK 7 3 3,404' 2.441 GLM-2-7/8"SPM-1,IPOR-1/IPOC-1/PPOR-1 4 4,016' 2.441 GLM-2-7/8"SPM-1,Orifice-1 AMR 8 5 4,157' 2.441 Chemical Injection Mandrel 6 4,206' 2.441 Baker FH Retrievable Packer 7 4,256' 2.310 X Nipple 8 4,269' 2.441 WLEG 9 6,850' CIBP C Perforation Details Top Btm Top Accum Last Present Zone (MD) (MD) (TVD) Btm(TVD) Amt SPF Perf Date Condition C-2 4,356' 4,392' 3,970' 4,002' 36' 5 02/28/15 Open C-3 4,438' 4,462' 4,042' 4,063' 24' 5 02/28/15 Open C CZNS6 4,500' 4,520' 4,097' 4,115' 20' 5 02/28/15 Open C-4 4,544' 4,558' 4,136' 4,148' 14' 5 02/28/15 Open C-5 4,634' 4,642' 4,215' 4,222' 8' 5 02/28/15 Open 1.D C-5 4,648' 4,659' 4,228' 4,237' 11' 5 02/28/15 Open C-6 4,754' 4,766' 4,321' 4,332' 12' 5 02/28/15 Open C-7 4,826' 4,938' 4,385' 4,484' 112' 5 02/28/15 Open C 47-5 5,058' 5,076' 4,590' 4,605' 18' 5 02/28/15 Open C 47-5 5,094' 5,106' 4,621' 4,632' 12' 5 02/28/15 Open C 49-4 5,330' 5,342' 4,830' 4,840' 12' 5 02/28/15 Open C 50-0 5,391' 5,413' 4,884' 4,903' 22' 5 02/28/15 Open 9 C 50-6 5,540' 5,566' 5,015' 5,038' 26' 5 02/28/15 Open _ C 51-6 5,616' 5,622' 5,082' 5,088' 6' 5 02/28/15 Open D DZNS2 5,897' 5,908' 5,330' 5,340' 11' 5 02/28/15 Open D 53-8 5,922' 5,984' 5,414' 5,407' 62' 5 02/28/15 Open HB D 55-7 6,126' 6,132' 5,533' 5,538' 6' 5 02/28/15 Open z D 57-2 6,316' 6,342' 5,699' 5,721' 26' 5 02/28/15 Open -- HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Open -- HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Open HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Open 4 PBTD=7,555' TD=7,643' MAX.HOLE ANGLE =520 Updated: 04/01/15 by.ILL Hilcorp Alaska, LLC Hilcorp Alaska,LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A-08RD2 50-733-20043-02 197-067 2/22/2015 3/2/2015 Daily Operations: 02/22/15-Sunday Set BPV. Nipple down tree.Tubing hanger lift threads extremely corroded and ineffective(more than 4" ID). BPV profile diminished and BPV is actually set 8"deeper into the tubing but is functional as a well control barrier.Tubing hanger will need to be speared to be pulled off seat and there are not enough threads for test plug to work. Install riser. Nipple up BOPE. 02/23/15-Monday Nipple up BOPE. Finish getting everything hooked up. Work on getting everything picked up and put away from skid and nipple up. Pull BPV. Prep to perform_rolling test.Close blind rams and circ across stack and through choke.Close choke slowly to get a 250 psi increase on stack. Had a leak on the unibolt on the kill line.Shut down and tighten unibolt.Circ again shutting choke until we had 250 psi. Hold for 5 min.Good test.Close choke until we had 1500 psi.Held for 5 min.Good test with no leaks.Lost 4 bbls to formation. Rig up to test choke manifold.Test choke manifold to 250 and 3000 psi.Change out saver sub on TD to 3 1/2 IF. MU spear and run in on 3 1/2 DP. Engage hanger. PU pulling hanger off seat at 70k. PU to 100k and wait about 1 min. PU to 130 and stop.About 10 seconds went by and packer came free. Pull up and lay down DP,hanger,3 tbg pups,and 2 jts of tbg. [76.26'tbg] MU XO to tbg and PU RTTS and storm valve. RIH and.set center of packer rubbers 65'from surface. Release from storm valve and POOH. MU test and PU test plug. Purge air out of system. Test BOPE on 3 1 2"at 250 L300 H_ jty / / .Test upper and lower pipe rams on 2 7/8". Unable to get a test with 2 7/8"on annular preventer.All other tests good.We received a verbal notification from Jim Regg to proceed with the rolling BOP test and the proposed solution for having a hanger with bad profile and threads. Lay down test joint assembly. Remove tools from derrick. RIH and retrieve storm packer and lay down same. Circulate well at 4 BPM/1550 psi.High gas 360 units at bottoms up,tapering off to 10 units. Pumped a total of 260 bbls to aid in cleaning tubing. Blow down top drive. POOH laying down completion string.Tubing ID is coated with approximately 3/8"grayish crud. 02/24/15-Tuesday POOH laying down completion string. Had a full recovery down to the mule shoe below the packer. Ended up laying do 121 jts 3 1/2, plus packer,seal assem,and mule shoe. Clean rig floor and clear floor of tools. Install wear bushing. Strap and caliper BHA. PU BHA#1. Bit,Csg scraper,2 Boot baskets, Bit sub,string magnet, Bumper sub,Oil jars,six 4 3/4 DCs.=228.50'. RIH strapping and picking up 3 1/2 DP to 4,400'. RU to circ. Pipe pressured up.Attempt to surge pipe to free blockage.Couldn't get circ back. Pull two stands and blow down TD. POOH wet. Found BHA packed off with marble sized chunks of oily scale from top of jars to the bit. Break down and clean debris out of BHA components from jars to the bit. No metal in boot baskets.Very little metal on the string magnet. PU BHA to the jars. Pressure wash and clean rig floor from wet trip. Continue RIH with BHA#2. Bit, Bit Sub w/float,double pin sub,Csg scraper,2 Boot baskets, Bit sub,string magnet, Bumper sub,Oil jars,six 4 3/4 DCs.=232.49'. RIH strapping and picking up 3 1/2 DP from 232'to 2,070'. Fill Pipe and blow down Top Drive. Continue RIH strapping and picking up 3 1/2 DP from 2,070'to 3,060'.Continue RIH with 3 1/2" DP in derrick to 3,788'. Daily fluid loss=0 bbls 8.5 FIW.Total Fluid Loss to Well=256 bbls 8.5 FIW. Average Daily Loss Rate=0 BPH.Sized Salt Pill=0 bbls.Total Sized salt=0 bbls.Annulus Pressures:20"= 30 psi, 13 3/8"=0 psi, 9 5/8"'=10 psi. MU Top Drive,fill pipe,circulate hole volume @ 10 bpm with 1720 psi.82K Up Wt,651( Dn Wt. Hilcorp Alaska, LLC Hilearp Alaska,LL(: Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A-08RD2 50-733-20043-02 197-067 2/22/2015 3/2/2015 02/25/15-Wednesday Circ hole clean at 3,800'.Very little cuttings back. RIH to 4,400'and circ bottoms up. Loaded shakers w/black fines for about 2 min on bottoms up. Kept staging in the hole a couple stands at a time and cir down to 5,018'. Decided to run 5 stds in.Were packing off when we started to circ.Stood 1 stand back.Cir at 5,366'until it cleaned up getting a lot of black fines across shakers. Wash and ream f/5,366 t/6,900'. Pumping 10 BPM at 2500 psi.55 rpm.Recovered about 12 bbls of black scale. Circ hole clean. Blow dn TD and POOH standing back 3 1/2 DP.Continue POOH w/clean out assembly to surface. Lay down BHA.Clean Magnet with 8.5 lbs meal.Clean boot baskets with 26 lbs mostly scale. PU BHA#4 RTTS for 7"casing. TIH to 4,454'@ 2 min stand. PU 12' Up Wt 90K, Dn Wt 74K.Set RTTS 2 turns to Right,Set down 20K, RTTS Set @ 4,442'. Close top Pipe Ram and test casing to 2500 psi and chart for 30 minutes.Test good. Release RTTS. TOH with RTTS from 4,442'. Lay down RTTS. PJSM.Slip and cut Drill Line. Daily fluid loss=0 bbls 8.5 FIW.Total Fluid Loss to Well=256 bbls 8.5 FIW. Average Daily Loss Rate=0 BPH.Sized Salt Pill=0 bbls.Total Sized salt=0 bbls.Annulus Pressures:20"=30 psi, 13 3/8"=0 psi, 9 5/8"'=10 psi.Valve Drill(38 Sec).Check Crown Saver. 02/26/15-Thursday RU e-line. RIH w/CIBP and set it at 6,850'WLM. POOH running a GR log up to 3,500'.Sent logs to town at 1015 hrs. RD e-line. Test csg and CIBP to 1000 psi for 15 min on a chart.Good Test. Start doing prep work to change out Hydril element.Change TD saver sub back to 41/2 IF. Drain stack below Hydril.Close blind rams then bleed dn accumulator. Remove hyd lines.Remove flow nipple and bottom of drip pan. PU potato masher from cellar and pull up through rotary.Set slips on potato masher and MU 10'pup jt in it. Lower dn on Hydril and bolt dn. Back out line up screw in top of Hydril. Screw TD into potato masher.Back out Hydril cap using TD, picking up slightly as it backs out to keep TD wt off Hydril cap.Raised cap up out of the way.Pulled old element out of Hydril. Cleaned and inspected seals. Installed new Hydril element and reversed process to get Hydril back together. Pull Wear Bushing. MU Stack jetting tool(Jonny Wacker). Flush stack. Lay down jetting tool. MU 2 7/8"Test joint assembly. Land Test Plug. Function Test Annular.Trouble shoot Koomey.Annular regulator continually by passing. Pull Test joint and Test Plug.Close Blind Rams. Rig mechanic changed out Regulator and regulator solenoid. Bring on Accumulator with all good.Open Blind Rams. Land test plug with 2 7/8"Test Joint. Function test Annular Preventer with no issues. Test Annular Preventer to 250/3000 psi against Choke/Kill HCR's. Pull Test plug.Set Wear Busing, lay down test joint and Wear bushing running tool. Rig up Weatherford 2 7/8" Handling equipment. RIH picking up 2 7/8"6.5#, L-80 EUE 8rd Tubing to 1,800'. Daily fluid loss=0 bbls 8.5 FIW.Total Fluid Loss to Well= 256 bbls 8.5 FIW. Average Daily Loss Rate=0 BPH.Sized Salt Pill=0 bbls.Total Sized salt=0 bbls.Annulus Pressures:20"=30 psi, 13 3/8"=0 psi, 9 5/8"'=10 psi.Spill Drill @ Koomey Drill(40 Sec). Hilcorp Alaska, LLC Hile,orNAlaska,LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A-08RD2 50-733-20043-02 197-067 2/22/2015 3/2/2015 02/27/15-Friday RIH picking up 2 7/8 tbg to 4,050'. MU XO to 3 1/2 IF and continue RIH to BP at 6,850'. PU a couple feet to 6,847'. [Shipping dirty fluid to production w/#1 pump and cleaning trip tank while RIH]. RU to circ. Displace well with clean 3%KCL while shipping dirty fluid to production room shipping suction. Ended up pumping 400 bbls 3%KCL before fluid clean up enough to keep returns. Flush all lines and choke manifold w/clean fluid.Blow down TD. Displaced well with 400 bbls 3%KCL.Shipped 744 bbls to Trading Bay. POOH standing back DP on off drillers side and tbg back on rack next to driller. Service rig. Reposition Tesco 24 volt, 16 pin Top Drive connection. PJSM on handling perf guns.Rig up to run perf guns. MU safety joint. RIH picking up 4 1/2",5 SPF, 135 deg phasing, RDX perf guns from surface to 161'. Suspend gun running operations to allow crane crew to work the boat. Continue to pick up perf guns from 161'to 391'. Rig electrician change out Link Tilt control switch. Continue to RIH picking up 4 1/2",5 SPF, 135 deg phasing,RDX perf guns from 391'to 1,997'(93 guns total). MU Mechanical firing head/flow sub/RA Marker assembly crossed over to 3 1/2"Drill Pipe.Total length of Gun BHA=2,097.97'. RA marker to Top Shot=104.75'. TIH with perf guns on 3 1/2'drill pipe from 2,097'to 6,150'.(44 stands and a double). 110K Up Wt,90K Dn Wt. Rig E-Line to log guns on depth. RIH with GR/CCL. Locate RA marker @ 4,256'.Make-6'correction to 4,250'. Need to move up hole 10'to 4,240' RA depth, placing top shot @ 4,346'.Send logs to town and W/O Geo to concur with PUH 10'and fire guns. Daily fluid loss=0 bbls 8.5 FIW.Total Fluid Loss to Well=256 bbls 8.5 FIW. Average Daily Loss Rate=0 BPH.Sized Salt Pill=0 bbls.Total Sized salt=0 bbls.Annulus Pressures:20" =30 psi, 13 3/8"=0 psi, 9 5/8"'=10 psi.Spill Drill @ Koomey Drill(40 Sec). 02/28/15-Saturday 1"6 l RD e-line. MU bar drop circ assem. PU 10'to put guns on depth.Top shot at 4,346'and bottom shot at 6,337'.Close annular.Drop ' bar and fire guns. Move pipe down hole 10'. Monitor well.Circ down through DP taking returns through choke. Pumped 45 bbls before getting returns.Circ 2 bottoms up at the ported sub.Gas peaked at 240 units then fell back.Shut dn and monitor well. Start cir again. Pump 31 bbls before seeing returns.Continue pumping and seen a high of 300 units of gas,w/a loss rate of 93 BPH while circ.Spot a 12 bbl SSP.Shut pump down and open Hydril.Attempt to move pipe.Guns appear to be sanded in. Circ through ported sub on top of guns and work pipe from 90k dn to 225k up,which is 115k over up wt. Hole taking 10 BPH. Continue circ and working pipe pulling up to 115k while waiting on personnel and equip. Hole taking 6 BPH. Boat arrived w/e-line hands and their tools.Also brought fishing tool hand and his tools. Unload boat. Hole taking 5 BPH. RU e-line and RIH w/1 1/4 overshot to retrieve bar off firing head.Didn't get the bar. RIH w/1".IDC and try to latch the bar.Still didn't get the bar. Decided to RD e-line and make a manual back off in the guns.Hole taking 3 BPH. RU to back off guns.Decided to pull up to 225k one more time and when we did the guns came free.PU 30'with all our wt back.Looks like we were not sanded in,we were differentially stuck and as the losses went down during the day it allowed us to pull free.When we pulled free it took a quick 10 bbl drink,then went back dn to about 5BPH. Circ bottoms up while keeping pipe moving. Didn't see any gas on bottoms up. Blow dn TD. POOH standing back 3 1/2" Drill pipe.Change over to 2 7/8"handling equipment. Lay down 3 jts 2 7/8'tubing,RA sub, ported sub,and firing head. Install 5" Drill pipe elevators. POOH laying down perf guns from 1,991'to surface. Rig down E-line and clear tools from rig floor. Break down and lay down safety joint. Daily fluid loss=304 bbls 8.6 KCL.Total Fluid Loss to Well=256 bbls 8.5 FIW/304 bbls 8.6 KCL. Average Daily Loss Rate=20 BPH.Sized Salt Pill=12 bbls.Total Sized salt=12 bbls.Annulus Pressures:20"=30 psi, 13 3/8" =0 psi, 9 5/8"'=14 psi. Fire Drill @ weld shop(1 min Response time). Pull wear bushing. Clean up and pressure wash rig floor from laying down guns. Rig up to run completion. • Hilcorp Alaska, LLC Hilcorp.tIa.ka.LL: Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A-08RD2 50-733-20043-02 197-067 2/22/2015 3/2/2015 03/01/15-Sunday RU equip to run gas lift completion. Work on rig projects while waiting on weather to get better for chopper or boat to bring out hands and tools. Finish derrick inspection issues.Clean pit#3 and sand trap. Hold PJSM. Boat showed up with hands and tools at 1300 hrs. PU Gas lift completion and RIH on 2 7/8 tbg out of derrick to 3,920'. MU and test and lock open SSSV. Continue to RIH with completion from 3,920'to 4,219'. Pick up tubing hanger and landing joint.Terminate control lines through hanger. Drain stack,land tubing hanger. RILDS, Packoff tubing hanger seals. Up Wt 56K, Dn Wt 52K,(TD&Block Wt=34K).Total cannon clamps =66.SS Bands=8. MU bar drop assembly. Drop bar. Pump down tubing and pressure up to 3500 psi. Hold pressure for 30 min. Bleed down tubing and Test casing to top of packer to 1500 psi and chart for 30 minutes.Test good. Packer Set @ 4,206'placing EOP/WLEG @ 4,269'.(Top perforation @ 4,346'.)Rig down bar drop assembly and landing joint.Close SSSV. Rig down control line. PU T-Bar and set BPV. Nipple down BOP. Bleed down Koomey. Install pick up slings,vac out flow box&riser. Break lower and upper riser bolts. Remove bell nipple,bell nipple flange and air boot flange. Rig up Bridge crane. N/D and set BOP aside.Pull and lay down Drill Riser. Land an M/U Tree. NU/Wing section.Test tubing head adapter to 5000 psi. Pull BPV,set TWC,Test Tree to 5000 psi.Test good. Pull TWC. Dress and mark control lines. Pump SSSV Open and hold 4500 psi. Rig up Slick Line. Land Lubricator Riser to Rig Floor. MU 1 1/2"tool string with 5'weight bar,5'weight Bar,knuckle joint,oil jar,spang jar,2.30"JDC.Stab on and Test lubricator. RIH with JDC Latch and retrieve Drop Bar. Daily fluid loss=44 bbls 8.6 KCL.Total Fluid Loss to Well=256 bbls 8.5 FIW,348 bbls 8.6 KCL.Average Daily Loss Rate=2 BPH.Sized Salt Pill=0 bbls.Total Sized salt=12 bbls.Annulus Pressures:20"= 30 psi, 13 3/8"=0 psi, 9 5/8"'=14 psi. Kick While Tripping Drill(28 sec Response time). 03/02/15-Monday Slickline Run#2. RIH to pull dummy valve out of chemical injection mandrel at 4,157'. Run#3. RIH and pull dummy valve out of GLM at 4,016'. Run#4. RIH and pull dummy valve out of GLM at 3,403'. Run#5. RIH and pull dummy valve out of GLM at 2,257'. Run#6. RIH and set live valve in GLM at 2,257'. Run#7. RIH and attempt to set live valve in GLM at 3,403',didn't set. Run#8. RIH and set live valve in GLM at 3,403'. Run#9. RIH and set live valve in GLM at 4,016'.Run#10. RIH and set live valve in Chemical Injection mandrel at 4,157'. Run#11.RIH and pull RHC plug.RD slickline.Turn well over to production. vt_ -08 P.I) Z Lqi0 76 Regg; James B (DOA) From: Brooks, Phoebe L (DOA) Sent: Tuesday, February 24, 2015 3:03 PM ! z� yrs To: Marvin Rogers - (C) Cc: Regg,James B (DOA) Subject: RE: Monopod BOP test on A-8RD2 Attachments: Kuukpik 56 02-23-15.xlsx Attached is a revised report changing the No. Valves test result to "FP" based on the remarks. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks SCANNED Statistical Technician II ''7 Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Marvin Rogers - (C) [mailto:mrogers@hilcorp.com] Sent: Tuesday, February 24, 2015 8:14 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Juanita Lovett; Ted Kramer Subject: Monopod BOP test on A-8RD2 UHilcorp Alaska, LLC DSM Monopod Platform [907] 776-6675 E-Mail: mrogers@hilcorp.com 1 STATE OF ALASKA • OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: jim.regq(aialaska.gov AOGCC.Inspectors alaska.gov phoebe.brooksCa)alaska.qov Contractor: Kuukpik Rig No.: 56 DATE: 2/23/15 Rig Rep.: Davidson/Borgen Rig Phone: 776-6675 Operator: Hilcorp Alaska Op. Phone: 776-6675 Rep.: Rogers/Brumley E-Mail mrogers@hilcorp.com Well Name: TBU A-08RD2 PTD# 1970670 Sundry# 315-062 Operation: Drilling: Workover: X Explor.. Test: Initial: X Weekly Bi-Weekly: Test Pressure(psi): Rams. 250/3000 Annular: 250/3000 Valves: 250/3000 -MASP. 1478 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen. P Well Sign P Upper Kelly 1 P Housekeeping P Rig P Lower Kelly 1 P PTD On Location P . Hazard Sec. P . Ball Type 1 P • Standing Order Posted P Misc. NA Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13 3/8"5M F / Pit Level Indicators P P #1 Rams 1 2 7/8 x 5 VBR P Flow Indicator P P_ #2 Rams 1 13 3/8"Blind P Meth Gas Detector P P #3 Rams 1 2 7/8 x 5 VBR P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln.Valves 1 3 1/8"5M FP Inside Reel valves 0 NA HCR Valves 2 1/16x31/8"E P Kill Line Valves 1 2 1/16"5M P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure(psi) 3000 P CHOKE MANIFOLD: Pressure After Closure(psi) 1300 P Quantity Test Result 200 psi Attained(sec) 31 P No.Valves 14 FP Full Pressure Attained(sec) 182 P Manual Chokes 2 P Blind Switch Covers: All stations Yes Hydraulic Chokes 1 P Nitgn. Bottles Avg. (#and psi): 6 @ 2200 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 3 Test Time: 5.5 Hours Repair or replacement of equipment will be made within 4 days. Notify the AOGCC of repairs with written confirmation to:AOGCC.Inspectors@alaska gov Remarks Performed rolling test to 250 and 1600 psi. Had one F/P on choke line unibolt while doing rolling test. Tightened and tested good. One F/P on CMV#6. Grease and retest okay. Fail on annular_Dreventer,with 2 7/8"tibular. Plan to retest-F it and red- - element if necessary before runnin• 2 7/8"com•letion string. All other tests good. 1 Tactarf H7S and mathana alarms with nn failurac AOGCC Inspection 24 hr Notice Yes Date/Time 2/22/2015 6:20 �� Z�is- Test Waived By Jim Regg % iS Test Start Date/Time: 2/23/2015 18:30:00 PM (date) (time) Witness Test Finish Date/Time: 2/23/2015 24:00:00 PM Form 10-424(Revised 06/2014) 2015-0223_BOP_Kuukpik56_TBU_A-08RD2.xlsx r(xt•O‘pik..- n / . • PlNkoitzt "\ Fr ietioei • 2. „ . ..., ,,, . ,,, ., • s, \ \ \ , \.. . . \ , „ \ \ ' ''. '• -- ..... -- -- -- . . . .. . \. , . . . , ..........„ , \ , i2—z --15-- r: .. .(2.-; • \ .(8.- . .0 -0 ,, ,, "cfli,k• r“-• . _ .., -- •, .... . ;•, t • , - . ..... ,..,_.4, •••••HAPT. f•-ki 3 ON • qfif 0 0 1)//° • - • - 1 d A-8 I?P ,' - - - ' • ', 1---1-. f' i t - . . 8 i . . , , .. , . • „et •- ..: ,,, ...• • .. ,,,, / ., / 1 941414' , ,,' , ... , / - ,,,.. ,, 1 . , ;• ,. ,, ,,„ „, ,, , / 1 1 • ,,.__,------,.--- . , , . _ • / . ...._ . \ \\ ' ‘- '• - -• N , . L , , .. . . \.. '-.• '., '''''\ '•,• , : \___••••\--:.- , .... s, . , '' • -', - . ' ' ' / / y` _ . . . _ , ., , ,• - - - - - • , • , . ... .... _ . N • ,• ,,• , \ •., ' , ,„ • . -, - ` ---- ', • .., . - . - •-'-' ,,'• , ••' - ''' ' ,.. , _ ,•:-, - ---• . , ' `., / . . ---- 4 -- . _•,',.. . . .. , •,,,. ,- ..----..' --- .-.--- --- ---- --- __-------- 11:111 HILCORP m�� .C.' 2_ BOP TEST SHEET DATE: FEB,23 2015 RIG CONTRACTOR Kuukpik RIG # 56 TIME: -mart=-03" WELL NAME: A-01-8RD .4--06, -h2- TYPE hz.TYPE OF OPERATION - (DRILLING /WORKOVER/OTHER): WORKOVER HILCORP REP: ROGERS/BRUMLEY RIG SUPERVISOR: DAVIDSON/BORGEN SUPERINTENDENT: TESTING COMPANY: KUUKPIK DP SIZES: BOP SIZE& RATING: 13 5/8" 5000 Test# Components Tested Minutes Held Low PSI High PSI Pass/ (Low/High) Fail 1 ROLLING TEST 250 FAIL 2 ROLLING TEST ALL FLANGES THAT WHERE BROKEN 250 1600 PASS 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Accumulator Manifold Annular Preventer Type Closing Time Initial Pressure Shaffer 13 5/8" Final Pressure Re-charge Time Hilcorp Representative Signature: Rig Supervisor Signature: Contract Testing Representative Signature: I EXPLANTATION OF TE 3 ON NEXT PAGE. ATTACH BOP , ) MANIFOLD SCHEMATIC. BOP TEST NOTES #1 UNI BOLT ON KILL LINE FAIL; TIGHTEN SAME; PASS #2 PASS A---0 R-1) 11-7D6-7c Regg, James B (DOA) From: Regg,James B (DOA) Sent: Monday, February 23, 2015 1:13 PM ef l'1711 5_ To: 'Ted Kramer'; Marvin Rogers - (C) Cc: Trudi Hallett; Rick Brumley - (C);Juanita Lovett Subject: RE:A-08RD2 Tubing Hanger Thank you for background info, photos, planned actions, and for documenting our conversation. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 SCANNED , -, ' t 907-793-1236 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Monday, February 23, 2015 9:20 AM To: Marvin Rogers - (C); Regg, James B (DOA) Cc: Trudi Hallett; Rick Brumley - (C); Juanita Lovett Subject: RE: A-08RD2 Tubing Hanger Marvin, I just spoke with Jim Regg at the AOGCC. Jim gave verbal approval to proceed with our Rolling BOP test. We need to do the following: 1.) Send a copy of the test charts for the rolling BOP test in to AOGCC with the test documents. 2.) Keep track of all failure/ pass events on the surface tests. After the hanger is pulled and the test plug inserted and the full test conducted, we will need to combine the test for AOGCC statistics. Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 1 From: Marvin Rogers - (C) Sent: Monday, February 23, 2015 7:11 AM To: Regg, James B (DOA) (jim.regg@alaska.gov) Cc: Ted Kramer; Trudi Hallett; Rick Brumley - (C) Subject: FW: A-08RD2 Tubing Hanger Mr. Reggs The e-mail below explains what position we are in and also describes what we have proposed. If this proposal is excepted we would like to test our choke manifold, and gas alarms while we are waiting for tools. We do realize that the test was not waived and we are still waiting on the reply. Thank you riHilcorp Alaska, LLC MG7vi,/ ��vs DSM Monopod Platform [907] 776-6675 E-Mail: mrogers@hilcorp.com From: Rick Brumley - (C) Sent: Monday, February 23, 2015 6:42 AM To: Marvin Rogers - (C) Subject: RE: A-08RD2 Tubing Hanger Mr. Regg, This past 12 hours we were able to make a tubing punch above the packer at 3725'—3728'. We then circulated the well with FIW surface to surface, plus an additional 60 bbls to insure the well bore was clean. We had clean returns immediately upon circulating with some 'dirty' fluid at bottoms up (no hydrocarbons, oil or gas). The well is stable. We then tapped out the BPV profile and set the BPV without issue. Upon removing the tree it was discovered that the tubing hanger lift threads were non-existent and the BPV had actually haen t 8" lowerin the hanger profile. See attached photos. We have almost finished installing the BOPE at this time. Due to the fact that we will not be able to make use of a normal plug/BPV/TWC in this hanger and knowing that the tubing ID is questionable, what we propose to do, with your approval is as follows: 1) Ensure the tubing and annulus are stable. 2) Pull BPV. 3) Perform a rolling test against the blind rams and well bore at 1600 psi to verify all BOP flanges are good. (We were able to inject at 1500 psi at % BPM previously). 4) Spear the tubing hanger, pull it off seat and lay down two joints of tubing. 5) Make up storm packer and set string down below tubing spool. 6) Pick up test joint with test plug and test BOPE as per sundry. From: Rick Brumley - (C) Sent: Monday, February 23, 2015 3:25 AM To: Marvin Rogers - (C); Shane Hauck; Eric Holland - (C); Clint Chanley; Ted Kramer; Dan Marlowe; Paul Mazzolini; Luke Keller; Trudi Hallett; Reed, Jeffrey; 'jeffrey.carter2@bakerhughes.com'; James Lott - (C) Subject: A-08RD2 Tubing Hanger Gents and Lady, 2 Attached are photos of the A-08RD2 tubing hanger. Clint Chanley tapped out the profile before setting the BPV (which turned out to be in the pup below the hanger).This could only be verified after nippling down the tree.The BPV is set approximately 8" deeper than should be, but.still effective for well control.The 3 W' 8rd EUE hanger lift threads are pretty much gone and the ID is 4".This will require a spear to pull the tubing hanger off seat and the normal plug/BPV/TWC for BOP test is not an option. We are presently nippling up the BOP and will discuss our test options this AM.There are additional photos in o-drive. Cheers, Rick Brumley Hilcorp DSM Monopod Platform 776-6875 Office 232-5709 Cell 3 '' ,f,"` , e' *'.'4. 4' 4:fr 4 + N *I .*« +:y . ' !� •. 4. ir t�a« . . 40, k Iiiiiki s t - . , .. . Vr"� � rtti'�" .y E '. 1 .4. .. �*' x s I • k rvy j •r • " � �v 4 * ' • k , * ,.*' . \ k* r*? '$..., 4 k . e' ':' *: * . ' _. , •, . t .!‘,. II n a .' 4. n k . , .I.4 — • _.„ Ln-.. a — _ . • . . — — . — . .. .. ? - *"\,,,, _ — \ ' i . •..... . #,, ..._ t .., - - I . '.... "Illga... ___ ___ .5. ,ii t.. . lie _ . . — ,, :4 ...• . , •‘,4.' a . . •.,. a. 1, .4,.., . - It • r • . , . . . :40 4,' a , — . C . e.• , ,------- I _ ......Cyl 4 .._.: --- 8..._. 1 . tlik k • ;:,. ,..,44-_ . . . ...-- - :7- 4 — .. . .. . ,. 4410 ' ,. * ' . — . ' ..- .5 .' — gieFt. ---...- . , ,,_ . . . . , 44, . . .,-.., ,..• .. .. _ , ....•P - W - ... 'J. . - :.'..'0,,.'7vi,4.444;. -. .4 1,''. • . ''''''.:41.f i f'‘.%'4 .. ........... 111. ' '''' ‘ t . ,,,,,,, 7 At.,',I.,,., -4-`'7,-......1c;,ir41•1* ' '.41.1fii.. .1.:::.' ' .. ''''-'''.. ;.;.,.,,,..' 1*-•.' — -- - ll -' - . ., 1 , 4-IP ri t 4 4. • ''.4-, • . 1 ..4. ' . ' , .' ....,„. , .. . . . • /. •1, , .,I. v. . S . , . . I . ., . . .,. ... . • 0.-,:„. ...., . • ' ' r .,2-e.#',,y •,z;". • : 4 vik, , ,:..., ., ? 4.9i...:; , V•vv.a,:-,'a •: ' ,',1'1:- -,,•,...I.C'4.,., '4.,.,f!.: • *I:4V likk..,,.''.4*-1'. , . i'*•.. 7 . . • .14;4*U , . . . . ' 11014H . ' . . . .-V, ' -:• '• . 1 •:,..,..' ' , • . 1 , „•...4 --0.: .'_ . . . . . oF TSF evw j; �� • THE STATE Alaska Oil and Gas fALAS�o Conservation Commission '4r - 2__^_,f:_ 333 West Seventh Avenue GOVERNOR BHA WALKER Anchorage, Alaska 99501-3572 04t, Main: 907.279.1433 LAS*P. Fax: 907.276 7542 www.aogcc.alaska.gov Trudi Hallett Operations Engineer 7-- O Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Trading Bay Field, Hemlock Oil Pool, Trading Bay ST A-08RD2 Sundry Number: 315-062 Dear Ms. Hallett: 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, Cat y P. F erste Chair DATED this /-/ da of February, 2015 Encl. RECEIVED STATE OF ALASKA FEB 0 6 2x15 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 2OAAC 28.280 1.Type of Request: Abandon El Plug for Redrill El Perforate New Pod 0 Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations 0 Perforate 0 Pull Tubing El Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ After Casing❑ Other. Install ESP/Convert to Producer0 2.Operator Name: 4 Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC• Exploratory ❑ Development ❑ 197-067 3.Address. 3800 Centerpoint Drive,Suite 1400Stratigraphic ❑ Service 0 ' 6.API Number. Anchorage,AK 99503 50-733-20043-02 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO93B I Will planned perforations require a spacing exception? Yes ❑ No 0 J Trading Bay ST A-08RD2' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018731 ' Trading Bay Field/Hemlock Oil Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 7,643 - 6,608 ' 7,410 • 6,458 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,075' 13-3/8" 1,075' 1,062' 3,090 psi 1,540 psi Intermediate 7,082' 9-5/8" 7,082' 6,247' 6,330 psi 3,810 psi Production 7,642' 7" 7,642' 6,607' 8,160 psi 7,020 psi • Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size. Tubing Grade: Tubing MD(ft): See Schematic , See Schematic 3-1/2" See Schematic 3,849 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): HES PHL Packer&N/A • 3,778'(MD)3,459'(ND)and N/A 12.Attachments. Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 0• Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 3/10/2015 Oil 0• Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date. WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Trudi Hallett Email thalletthilcorp.com Printed Name/ Trudi Hallett Title Operations Engineer Signature IlGit“..OU fiptigLitPhone (907)777-8323 Date 2/6/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: \5 .. cpl Plug Integrity ❑ BOP Test V Mechanical Integrity Test ❑ Location Clearance ❑ `� L_ Other: 0.. 3 %o5:. 80e / i?f- ( Ait.A5, ` I i 7 6 jo5.,.) Spacing Exception Required? Yes ❑ No E Subsequent Form Required: / a- '/ o LI APPROVED BY _ Approved by: P COMMISSIONER THE COMMISSION Date: Z—/ —/ TM �►�t�'r ap .z -� -�S— M "-i9-'5 d a JpQ IoN �"-- Submit Form and Form 10-403(Revised 10/2012) A roe a i al 1 nths from the date of approval. ?Rfachments in Duplicate RBDMS,.& FEB 1 3 2015 7-(iP�ff Well Work Prognosis Well: A-08RD2 Hilcorp Alaska,Ilk Date: 2/05/2015 Well Name: Monopod A-08RD2 API Number: 50-733-20043-02 Current Status: Water Injector Leg: N/A Estimated Start Date: March 10, 2015 Rig: Monopod Platform Rig#56 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 197-067 First Call Engineer: Trudi Hallett (907)777-8323 (0) (907) 301-6657 (M) Second Call Engineer: Ted Kramer (907)777-8420(0) (985) 867-0665 (M) AFE Number: Current BHP: 3194 psi @ 6131'TVD/6900' MD Max. Exp'd BHP: 3194 psi @ 6131'TVD/6900' MD Max. Possible SP: 397 psi Using 0.1 psi/ft gradient per 20 AAC 25.280(b)(4) Brief Well Summary A-08RD2 is a Hemlock only injector last completed in 1997.This workover will be converting the well from Hemlock water injector to Middle Kenai producer. Will pull the current completion and run new,F&F/ completion w/gas lift mandrels arecl4aigh=setwirelter. lAS L4F'r Procedure: 1. Skid rig and RU over A-08RD2. 2. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines and Hilcorp ROPE testing procedures to 250psi LOW and 3,000psi HIGH. 3. RU E-line. Cut tubing above packer at 3,778'. POOH 4. Pull hanger up to floor height, CBU. POOH laying down tubing. 5. Mill and retrieve packer at 3,778'441 6. RIH and clean out to PBTD @)1555f-and circulate clean. alt 7. PU 7" test packer and RIH to 4350'. Set packer, test backside to 2,500 psi to confirm casing integrity. Hold for 30 minutes, record with a chart recorder. ZSat. 8. PU storm packer, RIH and set same t 200' and hang off string. Pressure test to psi and chart. 9. Release from storm packer, POOH. Replace tO ing head. 10. Test all flange breaks to 2,500 psi and chart.V — - the 11. RIH, engage storm packer, release same, POOH, LD storm packer. 12. RIH w/CIPB and set+/- 6850' to isolate Hemlock. PU, release and test CIPB to 1000 psi charting for 15 min. a‘,l• ebvi 13. RIH with TCP guns and erforrate per program. 14. PU and RIH witb.SP• iot production tubing string w nd hang off same. est to 1500 psi charting for 30 min. 15. ND BOPE, NU wellhead and test. M 1�r 16. Turn well over to production. L Attachments: CCMG ul 14y e�( 1. Current Well Schematic 70 J�,�,ecr COMO//4 'c�"rt 3. Current W2. Proposedellhead Diagram I r, eell Schematic • ; `-' pw c der l �O 4. Proposed Wellhead Diagram rit QA wl Of Ffe r O vt�7'/�Id 5. BOP Stack TE'do//e / e6 4% prod SGC,' 14c �-ell to 4 //'r i4 oWd q //c) w pt imp( D vt a /t2COvee),-- II Monopod Well No. A-8RD2 (Inj.) As Completed 7-10-97 API#50-733-20043-02 RKB to TBG Head=38.52' 1 la 2 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8" 61# J-55 12.515 Surf 1,075' 9-5/8" 43.5# J-55/N-80 8.755 Surf 7,082' Section Mill 9-5/8"casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' L , Tubing: 3-1/2" 9.2# L-80 BTC(SCC) 2.992 Surf 1,572' 3-1/2" 12.95# L-80 PH-6 2.750 1,572' 3,778' 3-1/2" 9.23 L-80 BTC(SCC) 2.992 3,784' 3,849' 3 JEWELRY DETAIL NO. Depth ID Item 1 38.52' 2.875" CIW 11" 5M DCB 3-1/2"EUE Hanger. 2 39.27' 2.992" 3-1/2"EUE X 3-1/2"Butt Crossover 3 1,572' 2.750" 3-1/2"Butt X 3-1/2"PH-6(12.95#)Crossover 4 3,778' 2.750" 3-1/2"PH-6(12.95#)X 3-1/2"EUE Crossover 5 3,778' 2.885" HES 7"X 3-1/2"PHL Packer 6 3,784' 2.992" 3-1/2"EUE X 3-1/2"Butt Tubing Pup 4 ii=i 7 3,817' 2.562" 3-1/2" HES `R'Landing Nipple G ' 8 3.850' 2.750" Wireline Re-entry Guide 6 NOTE: Set 20,000#on Packer 7 R 8 Slickline/Fish/Fill Information: 7/18/07: Ran 2"Gauge Ring to7,410' &tagged. 5/1/01: Ran 2.25"Gauge Ring to 7,530'. Ran 1.5"bailer to 7,530'. Recovered scale- like solids&thick fluid. ad ___h._ PERFORATION DATA HB Accum Last Zone Top Btm Amt SPF Pert Date Present Condition HB 6,892' 7,040' 148 6 7/7/1997 Open HB HB 7,061' 7,334' 273 6 7/7/1997 Open HB 7,356' 7,456' 100 6 7/7/1997 Open HB / PBTD=7,555' TD=7,643' MAX.HOLE ANGLE =52' Updated: 02/05/15 by JLL PROPOSED '� Monopod Platform S v� � Trading Bay Unit � Well #A-08RD2 1`-�/9 do� (.f Completed: FUTURE API # 50-733-20043-02 V API#50-733-200743-02 CASING AND TUBING DETAIL RKB to TBG Head=38.52' SIZE WT GRADE CONN ID TOP BTM. 1 13-3/8" 61# J-55 12.515 Surf 1,075' ...] 9-5/8" 43.5# J-55/N-80 8.755 Surf 3,415' (KOP) Window cut in 9-5/8"Casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' )2 Tubing: �i 2-7/8 I 6.5* I L4,240' 11. 3 )'l°2 dZA-) JEWELRY DETAIL �`)IS I) NO. Depth ID Item 7 4 Hanger 1 P 5 ±300' SSSV 77:11111111111 6 2 ±2,250' GLM X 7 3 ±3,382' GLM 4 ±3,995' GLM 8 5 ±4,170' Chemical Injection Mandrel -., 6 ±4,200' Packer 7 ±4,230' X Nipple 8 ±4,240' WLEG 9 ±6,850' CIBP 7" To C. e rc400 . }ci Perforation Details Top Accum last Present Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Amt SPF Perf Date Condition ±4,356' 114,392' ±3,970' ±4,002' ±36' Future i C-3 ^438' t4,462' ±4,042' ±4,063' ±24' Future C CZN56 500' -4,520' ±4,097' ±4,115' ±20' Future C-4 ±4,544' r4,558' ±4,136' ±4,148' ±14' Future C-5 ±4,634' ±4,642' ±4,215' ±4,222' ±8' Future C-5 ±4,648' +4,659' ±4,228' ±4,237' ±11' Future D C-6 ±4,754' ,66' ±4,321' ±4,332' ±12' '!ture C-7 ±4,826' .+38' ±4,385' ±4,484' ±112' uture C 47-5 ±5,058' -5,076' ±4,590' ±4,605' ±18' Future C 47-5 ±5,094' ±5,106' ±4,621' ±4,632' ±12' Future C 49-4 ±5,330' ±5,342' ±4,830' ±4,840' ±12' Future E C 50-0 ±5,3' ±5,413' ±4,884' ±4,903' ±22' Future C 50-6 ±5,540 ±5,566' ±5,015' ±5,038' ±26' Future 111111 9 C 51-6 ±5,616' ±5,622' ±5,082' ±5,088' ±6' Future D DZNS2 ±5,897' ±5,908' ±5,330' ±5,340' ±11' Future I D 53-8 ±5,922' p5,984' ±5,414' +5,407' ±62' Future D 55-7 ±6,126' ±6,132' ±5,533' _38' ±6' Future HB D 57-2 ±6,316' ±6,342' ±5,699' ±5,721' ±26' Future E 58-7 ±6,534' ±6,582' ±5,878' ±5,914' +48' Future E 61-1 ±6,812' ±6,836' ±6,075' ±6,090' Future l HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Open HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Open -M'ili) HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Open lA PBTD=7,555' TD=7,643' MAX. HOLE ANGLE =52° Updated: 02/10/15 by JLL Trading Bay Unit PROPOSED Monopod Platform . Well #A-08RD2 Completed: FUTURE API # 50-733-20043-02 CASING AND TUBING DETAIL API#50-733-20043-02 RKB to TBG Head=38.52' SIZE WT GRADE CONN ID TOP BTM. 13-3/8" 61# J-55 12.515 Surf 1,075' _ 9-5/8" 43.58 J-55/N-80 8.755 Surf 7,082' L Section Mill 9-5/8"casing r✓/t4)9614) 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' Tubing: ) 2-7/8" 6.58 L-80 8rd EUE I Surf ±4,200' I r X JEWELRY DET' I. V NO. Depth ID Item H Hanger 1 ±300' SSSV 2 ±350 Pac. •r w/Vent valve 3 ±2,100' M 4 ±3,500' GLM 5 ±4,000 GLM ±4,050' X Nipple I 7 ±4,250' Bottom of ESP -T 8 6. ±6,850' CIBP _T q C / T 1 Perforation Details Top Btm To. Accum Last Present Zone (MD) (MD) (TVD) Btm(TVD) Amt SPF Perf Date Condition C-2 ±4,356' ±4,392' ±3,970' ±4,002' ±36' Future C-3 ±4,438' ±4,462' ±4,042' +4,063' ±24' Future D C CZNS6 ±4,500' ±4,520' ±4,097' ± 115' ±20' Future / C-4 ±4,544' ±4,558' ±4,136' ±4, .8' ±14' Future ', C-5 ±4,634' ±4,642' ±4,215' ±4,22 ±8' Future j C-5 ±4,648' ±4,659' ±4,228' ±4,237' ±11' Future C-6 ±4,754' ±4,766' ±4,321' ±4,332' +12' Future ' 1 C-7 ±4,826' ±4,938' ±4,385' ±4,484' ± 2' Future E C 47-5 ±5,058' ±5,076' ±4,590' ±4,605' ±1: Future C 47-5 ±5,094' ±5,106' ±4,621' ±4,632' ±12' Future --1 i C 49-4 ±5,330' ±5,342' ±4,830' ±4,840' ±12' Future Vim,' JIM C 50-0 ±5,391' ±5,413' ±4,884' ±4,903' ±22' Future A 4 C 50-6 ±5,540' ±5,566' ±5,015' ±5,038' ±26' Future C 51-6 ±5,616' ±5,622' ±5,082' ±5,088' ±6' Future - HB D DZNS2 ±5,897' ±5,908' ±5,330' ±5,340' ±11' Future D 53-8 ±5,922' ±5,984' ±5,414' ±5,407' ±62' .Future D 55-7 ±6,126' ±6,132' ±5,533' ±5,538' ±6' ture D 57-2 ±6,316' ±6,342' ±5,699' ±5,721' ±26' F re = E 58-7 ±6,534' ±6,582' ±5,878' ±5,914' ±48' Fut e E 61-1 ±6,812' ±6,836' ±6,075' ±6,090' ±24' Futur• HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Open HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Open PBTD=7,555' TD=7,643' HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Open MAX. HOLE ANGLE =52' Updated: 02/05/15 by JLL . 4 II Monopod Platform A-8RD2 Current 02/05/2015 Hilrarp Ua+ka.1.1.1 Monopod cubing hanger,CIW-DCB, A-8RD2 11 X 3 1/2 EUE lift and 133/8X95/8X7X31/2 3 1/2 IBT susp,w/3" type H BPV profile, 6'A"EN ei0e; b Arp Tree,Block,CIW-F,11 5M FE • X 3 1/8 5M,double master IF 4.41 rI and 2 1/16 5M wing,6/< VI pocket prepped for control O• line exit,EE trim KO i. `10' 1 In 1 Tubing head,CIW-DCB, i. Valve,Foster Dual-Seal, 13 5/8 3M X 11 5M,w/2- lil in 21/16SMFE,HWO,AA 2 1/16 5M EFO,X-bottom Ih' Joh prep w/1 A VR profile 81111Co/�o\',I • - 'I: Valve,WKM-M,2 1/16 5M _ Casing spool,ClW-WF, 1I1 ' iii FE,HWO,AA 13 5/8 3M X 13 5/8 3M, o', w/2-2 1/16 5M SSO I11IIII110o :1111 li iii ___. 1111# i. Casing head,Shaffer-KD, .i. 135/83MX13' SOW Iii ' 111 bottom,w/2"LPO it w lui, �- 2"LP plug valve IM� III_�-�:. air • Monopod Platform A-8RD2 Proposed 02/05/2015 Hihorp Alaska,I.L( Monopod Tubing hanger,FMC-TC- A-8RD2 B-EC,11 X 3'A TC-2 lift 133/8X95/8X7X27/8 and susp,w/3"type H BPV profile,300-1 pocket,4-''A"continuous control line BHTA,Bowen,3 1/8 5M X 2.5 Bowen quick union V • 111 Valve,Swab,WKM-M, •' 00' " 3 1/8 5M FE,HWO,DD trim oit' _ 0 ,0' Valve,Wing,WKM-M, 0 3 1/8 5M FE,w/15" ••' OMNI operator,DD trim 0 II S 30111 I. 0 Valve,Master,WKM-M, •t 3 1/8 5M FE,HWO,DD trim 0 0 ui X4 ' ni P'') Tubing head,CW, Valve,WKM-M,2 1/16 SM 135/83Mx115M,w/2- �S� "�' ■ urn FE,HWO,AA +_` 2 1/16 SM SSO,w/HPS Y•� ! It1II bottom,w/121/165M �— ■1'" �• �o� Mi r.I L Casing spool,CIW-WF, Ill I 'II oil, Valve,WKM-M,2 1/16 5M 13 5/8 3M X 13 5/8 3M, I - ; E,HWO,AA w/2-21/165MEFO iII1 1 #1.�I�I I.. l. 1111, !v. Casing head,Shaffer-KD, ai 1.1)' 13 5/8 3M X 13"SOW bottom,w/2"LPO III _ 1 Iii 1 �0mil l 2"LP plug valve Monopod Platform 2013 BOP Stack Hikurp:%lis ka.L.Id: 03/12/2013 Rig Floor 1111111111. Bottom of air boot flange 5'below rig floor 16" 14.72y_50' Pipe •III'III!I11 ti • O in in irt alni 3.74' Shaffer 135/85M d fit rftritut1 26.25' Shaffer LOT 2 7/8-5 Variables 2.50' 13 5/8 5M 4111111k Blind �.IITU _I I11_ '�1 • 1.76 1�:110�11: 11 ►� i` 110:11.1 Mud Cross Iii 111 ill III mil V 135/85MFEX FE w/3 1/8 5M EFO w/2 1/16 5M Choke and Kill valves w/Unbolt end III I I U 111 III connections for lines 2.83' — Dual Cameron Flex rams Ili XIi Ill ili Ili jims 70' 111 11111 111 I I Drill deck 14.20" UOCD 1911 Riser 14.20' 135/85M FE X 135/8SM FE III ill litll' !I'1 kip -. Spacer spool 13 5/8 SM FE X 11 3M 1 I' Wellhead @ 15.00' • Schwartz, Guy L (DOA) From: Roby, David S (DOA) Sent Thursday, February 19, 2015 9:24 AM To: thallett@hilcorp.com Cc: Schwartz, Guy L(DOA); Bettis, Patricia K(DOA) Subject: FW:Sundry application for Trading Bay St.A-08RD2 (PTD 197-067) Trudi, Sorry for the delay on this. I goofed up your email address in my initial email below but for some reason never got a message that it was undeliverable. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Dave Roby at(907)793-1232 or dave.roby@alaska.gov. From: Roby, David S(DOA) Sent: Monday, February 09, 2015 3:02 PM To: 'thallet@hilcorp.com' Subject: Sundry application for Trading Bay St. A-08RD2 (PTD 197-067) Trudi, I'm reviewing your application to convert the subject well from a Hemlock injector to a Middle Kenai producer and have some questions related to possible reserves implications. The well is still injecting a couple hundred bbls a day of water into the Hemlock formation,which leads to the following questions: 1) What is the status of the offset producers supported by this injector? 2) Are there any other injectors in this portion of the pool that will make up this loss of injection? 3) Is continued injection in this portion of the pool beneficial to ultimate recovery? Thanks in advance. Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907) 793-1232 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Dave Robyat 907 793-1232 or dave.rob @alaska. ov. ( 1 v g 1 • Schwartz, Guy L (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Thursday, February 19, 2015 1:12 PM To: Roby, David S (DOA) Cc: Schwartz,Guy L(DOA); Bettis, Patricia K(DOA) Subject: RE:Sundry application for Trading Bay St.A-08RD2 (PTD 197-067) Hi Dave The answers to your questions are in red below. Please feel free to call me if you need any clarifications whatsoever. I appreciate it! Thanks- Truoli. Trudi Hallett Operations Engineer Cook Inlet Offhhore Asset I earn ' l life rp ala,l.a. 1_L(' Hilcorp A Company Built on Energy thallett@hilcorp.com 0. 90^ —.8323 90-.301.66;- From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent:Thursday, February 19, 2015 9:24 AM To: Trudi Hallett Cc: Schwartz, Guy L(DOA); Bettis, Patricia K(DOA) Subject: FW: Sundry application for Trading Bay St. A-08RD2 (PTD 197-067) Trudi, Sorry for the delay on this. I goofed up your email address in my initial email below but for some reason never got a message that it was undeliverable. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s) It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Dave Roby at(907)793-1232 or dave.roby@alaska.gov. From: Roby, David S(DOA) Sent: Monday, February 09, 2015 3:02 PM To: 'thallet@hilcorp.com' Subject: Sundry application for Trading Bay St. A-08RD2 (PTD 197-067) 1 • Trudi, I'm reviewing your application to convert the subject well from a Hemlock injector to a Middle Kenai producer and have some questions related to possible reserves implications. The well is still injecting a couple hundred bbls a day of water into the Hemlock formation, which leads to the following questions: 1) What is the status of the offset producers supported by this injector? We were only injecting treated effluent into the wellbore of A-08RD2 since May 2014 due to the direct communication of A-08RD2 with A-13. This was the only offset producer with direct support other Hemlock producers are further up structure.The other direct offset wells are either abandoned &redrilled to another location or shut-in. de, 2Z1. 11 • $ 1147 51-15 A-16 -C 3 RD A-08RD2 73 s/s1 • a` A-08RD A-10 Int 175 p A-13 348 EI 2011. 1323 t iii 781 r- 1801 2) Are there any other injectors in this portion of the pool that will make up this loss of injection? We recently worked over A-12RD2 to support C-Zone injection and to take the treated effluent.We currently do not have any injection into the Hemlock Pool. At this time,we are working a reservoir management study to create the II-A FB waterflood development program which includes converting poor performing producers to injectors and/or deepening wells to support the peripheral of the block of all productive pools. With that being said,we can also make a strong case showing aquifer influx that additionally helps support the producers in the II-A FB in the Hemlock and thus reducing the need for the A-08RD2 injection. Regardless if we converted A-08RD2 to an uphole producer,we still would not utilize this well for waterflood support in the Hemlock due to the damaging effects it has on A-13 -4 and with most of the water going to A- 13 alone, it is most likely not adding any additional rate/reserves. 3) Is continued injection in this portion of the pool beneficial to ultimate recovery? Yes injection overall will be beneficial, however we have not seen any decline in reservoir pressures especially with A-08RD2 having such a reduced injection rate in the Hemlock.This could be a factor of comingling multiple zones—which again we plan to mitigate by injecting in all zones from the Hemlock up to the B-Zone in the II-A FB.This along with aquifer support will be a benefit in recovery. *When full Hemlock waterflood support was online we were injecting—15oo to 2000 bwipd @a 2150 psi tbg pressure,with treated effluent we were injecting--zoo bwipd 100 psi. Thanks in advance. Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907) 793-1232 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged 2 Schwartz, Guy L (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Thursday, February 19, 2015 12:54 PM To: Schwartz, Guy L(DOA) Cc: Bettis, Patricia K(DOA); Roby, David S (DOA); Dan Marlowe Subject: RE:TBU A-08RD2 RWO (PTD 197-067) Attachments: A-08RD2 Proposed GL Comp Revised 2015-02-16.pdf Guy, The new calculated MASP considering the new zones:1478 psi The current BHP for the new zones at Mid perf is--1875 psi tea 4600'TVD. Also,given the Cement Bond Log from 7/14/1997: Cement Top in 7" casing @ 1420' See attached proposed schematic for reference of corrected cartoon, as well. Please let me know if I can answer any more questions or address any concerns. Thanks- Trudi Hallett i Opc'ra1iom L ngim'c'r Cook InIct Ofllhorc \ssel Icam I lilcorh \lahkd. I I C Hilcorp A Company Built on Energy thal lett@hilcorp.com 0. 90-.---.N323 C: 90-301.665-- From: 01.66 -- From: Trudi Hallett Sent:Thursday, February 19, 2015 10:28 AM To: 'Schwartz, Guy L(DOA)' Cc: Bettis, Patricia K(DOA); Roby, David S(DOA); Dan Marlowe Subject: RE: TBU A-08RD2 RWO (PTD 197-067) Guy- Sure- I used the 0.1 psi/ft gradient back to surface from the newest top perforation in C-Zone @a 397o'ND anticipating worst case scenario of being all gas to surface once we perforate(which I should have noted).The current Hemlock zone open is water flooded and we don't anticipate gas to surface here which was my logic used. Noted-will change the pressure test in step 8 to 2500 psi. Thanks- 1 Truol i From: Schwartz, Guy L(DOA) [mailto:guy.schwartz©alaska.gov] Sent:Thursday, February 19, 2015 9:52 AM To: Trudi Hallett Cc: Bettis, Patricia K(DOA); Roby, David S(DOA) Subject: TBU A-08RD2 RWO (PTD 197-067) Trudi, I noticed the MASP for well is 397 psi. Can you show me the calculations? The .1 psi ft gradient back to surface as shown is not correct. This would also be a variance as allowed by 20 AAC 25.280(b)(4)but I need to know how you got it. Also,to test the lower flange (step 10)on the new tubing head you will be pressuring against the Storm packer. Should test Storm Packer to 2500 psi in step 8 to verify set. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz©alaska.gov). 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday, February 10, 2015 4:15 PM To: 'Trudi Hallett' Cc: Ted Kramer; Dan Marlowe;Juanita Lovett Subject: RE:Trading Bay ST A-08RD2, PBT# 197-067 Trudi, We haven't processed the sundry yet so I will update the application with the new information and drawings. Well will now be completed as an Gas lift well vs ESP. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALfIY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Trudi Hallett [mailto:thallett©hilcorp.com] Sent:Tuesday, February 10, 2015 2:38 PM To: Schwartz, Guy L(DOA) Cc: Ted Kramer; Dan Marlowe; Juanita Lovett Subject: Trading Bay ST A-08RD2, PBT # 197-067 Hello,Guy- Last week Hilcorp submitted the sundry request for the above mentioned well. Due to operational constraints,we have decided to utilize the available power capacity for additional ESP's on future wells. With that being said,we have changed the proposed completion design from ESP with high set packer to a gas lift completion.Attached is the updated proposed schematic and wellhead drawing. I have also included the updated procedure for your review. Please advise if you would like Hilcorp to submit a new sundry application for the proposed changes. I apologize for any inconveniences.Thank you for your time. Thanks- Trudi. Trudi Hallett Operations Engineer Cook Inlet Offshore.\ssel I cam I lileorp.11.tska. 1 1 C Hilcorp A Company Built on Energy thallett@hilcorp.com 0: 91)-. 8323 1 Y• Well Work Prognosis Well: A-08RD2 ❑ileorp [I,C Date: 2/10/2015 Alaska, Well Name: Monopod A-08RD2 API Number: 50-733-20043-02 Current Status: Water Injector Leg: N/A Estimated Start Date: Feb 20, 2015 Rig: Monopod Platform Rig#56 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 197-067 First Call Engineer: Trudi Hallett (907)777-8323 (0) (907) 301-6657 (M) Second Call Engineer: Ted Kramer (907)777-8420(0) (985) 867-0665 (M) AFE Number: Current BHP: 3194 psi @ 6131' TVD/6900' MD Max. Exp'd BHP: 3194 psi @ 6131' TVD/6900' MD Max. Possible SP: 397 psi Using 0.1 psi/ft gradient per 20 AAC 25.280(b)(4) Brief Well Summary A-08RD2 is a Hemlock only injector last completed in 1997.This workover will be converting the well from Hemlock water injector to Middle Kenai producer. Will pull the current completion and run new gas lift Jmpietio: . ESP completion w/gas lift mandrels and high set packer. Procedure: 1. Skid rig and RU over A-08RD2. 2. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines and Hilcorp BOPE testing procedures to 250psi LOW and 3,000psi HIGH. 3. RU E-line. Cut tubing above packer at 3,778'. POOH 4. Pull hanger up to floor height,CBU. POOH laying down tubing. 5. Mill and retrieve packer at 3,778'. 6. RIH and clean out to 3,890'PBTD @ 7,555'and circulate clean. 7. PU 7" test packer and RIH to 4350'. Set packer, test backside to 2,500 psi to confirm casing integrity. Hold for 30 minutes, record with a chart recorder. 8. PU storm packer, RIH and set same at 200' and hang off string. Pressure test to 1,500 psi and chart. 9. Release from storm packer, POOH. Replace tubing head. 10. Test all flange breaks to 2,500 psi and chart. 11. RIH,engage storm packer, release same, POOH, LD storm packer. 12. RIH w/CIPB and set+/- 6850'to isolate Hemlock. PU, release and test CIPB to 1000 psi charting for 15 min. 13. RIH with TCP guns and perforate per program. 14. PU and RIH with ;as lift completic ESP completion production tubing string w/ high set packer @ +/- 350' 1-420(, and hang off same. Pump set depth @ + 1^rc�.Test to 1500 psi charting for 30 min. 15. ND BOPE, NU wellhead and test. 16. Turn well over to production. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Current Wellhead Diagram 4. Proposed Wellhead Diagram 5. BOP Stack ' Trading Bay Unit II PROPOSED Monopod Platform Well #A-08RD2 Completed: FUTURE API # 50-733-20043-02 API#50-733 20043-02 CASING AND TUBING DETAIL RKBto 78G Head=38.52' SIZE WT GRADE CONN ID TOP BTM. ' 13-3/8" 61# J-55 12.515 Surf 1,075' ...i I-1 9-5/8" 43.5# J-55/N-80 8.755 Surf 7,082' Section Mill 9-5/8"casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' Tubing: )2 2-7/8 6.5# 18rd EUE I Surf ±4,240' )3 JEWELRY DETAIL NO. Depth ID Item 4 Hanger 5 ±300' SSV ±2,250' GLM IIIIIMI MIN 6 X 7 ±3,382' GLM 4 ±3,995' GLM t 8 5 ±4,170' Chemical Injection Mandrel 6 ±4,200' Packer 7 .'30' X Nipple ±4,240' WLEG ±6,850' CIBP __mi=} C Perforation Details Top Btm Top Accum Last Present Zone (MD) (MD) (ND) Btm(ND) Amt SPF Perf Date Condition C-2 ±4,356' ±4,392' ±3,970' ±4,002' Future C-3 ±4,438' ±4,462' ±4,041' ±4,063' ±24Future NI C CZNS6 ±4,500' ±4,520' ±4,1 ±4,115' ±20' Future ±4,544' ±4,558' ±4, ±14' Future _ C-5 ±4,634' ±4,642' ±4,215 -14,222' ±8' Future . D C-5 ±4,648' ±4,659' ±4,228' ±4,237' ±11' Future C-6 ±4,754' ±4,766' ±4,321' ±4,332' ±12' 'ure . C-7 ±4,826' ±4,938' ±4,38°,' ±4,484' ±112' Future C 47-5 ±5,058' ±5,076' ±4,5 ±4,605' ±18' Future III C 47-5 ±5,094' ±5,106' ±4,621' 532' _ ±12' Future IN.I C 49-4 ±5,330' ±5,342' ±4,830' 340' ±12' Future E C 50-0 ±5,391' ±5,413' ±4,884' 303' ±22' Future C 50-6 ±5,540' ±5,566' ±5,015' )38' ±26' - 'ture _ -,w,.= C 51-6 ±5,616' ±5,622' ±5,082' - +6' ure x,088' UN D DZNS2 ±5,897' ±5,908' ±5,330' ±5,340' ±11' ,u re A D 53-8 ±5,922' ±5,984' ±5,414' ±5,407' ±62' Future HB D 55-7 ±6,126' ±6,132' ±5,533' ±5,538' ±6' Future , D 57-2 ±6,316' ±6,342' ±5,699' ±5,721' ±26' Future E 58-7 ±6,534' ±6,582' 1- ° ±5,914' ±48' Future E 61-1 ±6,812' ±6,836' ±6,090' ±24' Future HB 6,892' 7,040' 6,126' 6,221' 148 6 7/7/1997 Open HB 7,061' 7,334' 6,235' 6,410' 273 6 7/7/1997 Open HB 7,356' 7,456' 6,424' 6,489' 100 6 7/7/1997 Open PB1D=7,555' 7D=7,643' MAX_HOLEANGLE =52" Updated: 02/10/15 by JLL .i. _ . * II Monopod Platform A-8RD2 Proposed IlYhwh tl:,.h:,.Lf.c 02/10/2015 Monopod Tubing hanger,CIW-DCB, A-8RD2 11 X 3 1/2 8rd EUE lift 13 3/8 X 9 5/8 X 7 X 3 1/2 and 3 c DSS-HTC susp, w/3"type H BPV profile, 6W'EN,2-Y."CCL, 1-3/8"CCL,410 55 material BHTA,Bowen,3 1/8 5M X 2.5 Bowen quick union iii Valve,Swab,WKM-M, "'^ 3 1/85M FE,HWO,DD p. trim '�';r #' _ — Valve,Wing,WKM-M, 31/85MFE,w/1S" mo OMNI operator,DD trim 1111 1: o Valve,Master,WKM-M, ..pm ` 31/85MFE,HWO,DD g. _ trim Adapter,Cameron, 115M Stdd X 3 1/8 5M ,,imil _ „ \ stdd,prepped for 6 Y. �.` /„,i1 ` ' neck,3-Y cont control line exit _ 1._ Tubing head,CIW-DCB, ,• 'sir �1 , Ili Valve,Foster Dual-Seal, 135/83MX115M,w/2- 21/165MFE,HWO,AA 2 1/16 5M EFO,X-bottom ,_ prep w/1%VR profile US 7i_I.I i 11 ni . n. 4.I'. Valve,WKM-M,21/16 5M IliFE,HWO,AA S: _ '2% Casing spool,CIW-WF, u, a 13 5/8 3M X 13 5/8 3M, 1��fl' � 1111 w/2-21/165MS50 : - n. Casing head,Shaffer-KD, . .if' 1 13 5/8 3M X 13”SOW III I III bottom,w/2"LPO • 10�'il�� j 2"LP plug valve Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. File Number of Well History File PAGES TO DELETE Complete RESCAN ~ Color items - Pages: [] GraYScale, halftones, pictures, graphs, charts - Pages: [] Poor Quality Odginal- Pages: [] Other- Pages: DIGITAL DATA Diskettes, No. a Other, No/Type 'OVERSIZED n ,Logs of various kinds Other COMMENTS: Scanned by: ~ver~ M~red. D',r~m, ~ TO RE-SCAN Notes: Re-Scanned by: Beverly Mildred Daretha~n Lowell Date: i~ "3 2011 May's Waivered Injection Well Report Page 1 of 1 • • Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Tuesday, June 07, 2011 3:53 PM To: Cc: Martin, J. Thomas E Lambert, Steve A; Hallett, Tr �� ? Ul t Subject: 2011 May's Waivered Injection Well Report Attachments: Master Well List TIO Report 2011 06 01.xls Hi Tom & Jim, Here is May's monthly report for all the active monitored injection wells. With G -27 shut -in due to the inability to complete the MIT compliance temperature survey (parted tubing), this well will be moving to the LTSI report starting next month. The attached plot for that well shows no indication of any integrity issues for the injected water. The A -08RD2 well successfully passed its MIT last month and the backside pressure was bled down to -500 #. Otherwise the monitored wells are responding as expected to ups and downs in injection volumes without any other pressure or rate anomalies observed. Bottom line, I don't see any indication that any of these wells are losing control of the injected fluids downhole. Larry «Master Well List TIO Report 2011 06 01.xis» 6/8/2011 Plot Pressure & Rate vs Time - Well A -08RD2 • - .—_,, - 2000 1800 2000 A � Ti -- I -- l ' J 1 `'o lsoo 1400 li 1500 1, _ i I I 1200 N I 1 1001 E m a 1000 _ .. _ - 800 mi - 600 500 7 .. I 400 •9 5/8" ifi 13 3/8" •Tubing 200 • Vol A - /� 0 2...,.. 0 0 _ _ _ 0 0 0 O M M O M M M Date 7" 95/8 133/8" 20" Tubing 'Vol AZT TIO Report 06/01/11 590 19 32 0 1950 440 05/31/11 570 19 32 5 1950 1293 Data Sheet 05/30/11 500 17' 32 5 1930 693 05/29/11 500 35 33 5 1950 1338 05/28/11 500 35 33 5 1950 614 A -08RD2 05/27/11 500 35 33 5 1950 1350 05/26/11 500 35' 33 5 1950 539 05/25/11 500 13 33 4 1950 1243 INJECTION 05/24/11 500 13' 33 4 1950 927 05/23/11 500 13 33 4 1950 235 05/22/11 500 13; 33 4 1950 1329 Permit # 1970670 05/21 /11 450 1'E- 34 4 1950 983 05/20/11 450 11 34 4 1950 886 05/19/11 400 10r 32 4 1950 1173 API # 50- 733 - 20043 -02 05/18/11 1550 1 U 34 15 1950 1060 05/17/11 1120 10 34 15 1950 1055 05/16/11 1100 10 34 15 1980 1322 12/01/2010 to 06/01/2011 05/15/11 1100 10 34 15 1980 484 05/14/11 1060 10 34 15 1980 692 05/13/11 1060 10k 34 15 1980 1328 � 05/12/11 1050 10 24 15 1930 828 05/11/11 1050 10 24 15 1930 998 05/10/11 1050 10 24 15 2200 1302 05/09/11 950 14,E 35 20 2000 558 05/08/11 950 10 35 20 2000 1396 05/07/11 1100 10 35 20 1950 952 05/06/11 1100 10 35 20 1950 917 05/05/11 1050 1e 34 20 1930 1292 05/04/11 1100 10 34 20 1910 474 05/03/11 1000 10 35 20 1950 1388 05/02/11 1130 10 34 19 1950 526 05/01/11 1130 10 34 19 1950 1084 04/30/11 1000 10 35 20 2000 652 04/29/11 1000 10 35 20 2000 562 04/28/11 1020 10 35 19 1950 768 04/27/11 1010 12 35 20 1925 1366 6/8/2011 9:33 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 06 01 (3).xls A -08RD2 • MEMORANDUM • State of Alaska Alaska Oil and Gas Conservation Commission • DATE: Thursday, May 19, 2011 TO: Jim Regg Re 51714, P.I. Supervisor SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA A -08RD2 FROM: Lou Grimaldi TRADING BAY ST A -08RD2 Petroleum Inspector Src: Inspector Reviewed B P.I. SuprvJ NON - CONFIDENTIAL Comm Well Name: TRADING BAY ST A - 08RD2 API Well Number: 50 733 - 20043 - 02 - 00 Inspector Name: Lou Grimaldi Insp Num: mitLGl 10518091310 Permit Number: 197 - 067 - Inspection Date: 5/18/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1 A -o8RD2 ` Type Inj. TVD 3459 IA 1560 1560 - 1555 r 1555 _ 820 820 P.T.D 1970670 ' TypeTest SPT Test psi 1500 - OA 10 10 10 1 10 i 10 10 Interval 4YRTST p/F P T I 1950 1880 1885 — 1885 1885 1885 Notes: IA pressured up when I arrived. Observed this condition for 30 min's w /minimal change. Depressured IA to 820 psi and observed for 15 min's w /no change. OOA remained at v34 psi throughout test. e rr• fYl AV w - , Qi ., l Thursday, May 19, 2011 Page 1 of 1 • Page 1 of 1 - 1/13/2010&u • McMains, Stephen E (DOA) From: Kanyer, Christopher V [Chris.Kanyer@chevron.com] Sent: Wednesday, January 13, 2010 1:10 PM To: McMains, Stephen E (DOA); Aubert, Winton G (DOA) Cc: Brandenburg, Tim C; Bonnett, Nigel (Nigel.Bonnett); Tyler, Steve L Subject: Cancellation of open sundries/permits _p After reviewing the following open permits to drill (form 10-401)/sundries (form 10-403) for Union Oil Company of California, it has been determined these open AOGCC permits/sundries should be cancelled: PTD Sundry API Well Name/Number 209-011 N/A 50-233-20025-00 Panthers 21-6-9 208-207 N/A 50-287-20026-00 Stegodon 24-6-8 209-058 N/A 50-733-20586-00 Trading Bay Unit M-08 201-117 308-260-733-20254-01 195-083 308-268 50-733-20097-04 208-184 309-198 50-283-20130-00 Please let me know if you have any. questions. Trading Bay Unit K-18 Trading Bay Unit K-26RD Ivan River Unit (IRU) 11-06 Thanks, Chris Kanyer ~• Technical Assistant Wellbore Maintenance Team Office: (907) 263-7831 Cell: (907) 250-0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 1/13/2010 • SARAH PAL/N, GOVERNOR ALASSA OII, A1~TD rzA,S 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQATI011T COMAIIS5IOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 Timothy Brandenburg Drilling Manager UNOCAL PO Box 196247 ~~, Anchorage, AK 99519 Q ~ ''" ~. _ 1 Re: Trading Bay Field, Hemlock/Middle Kenai E Oil Pool, A-08RD2 Sundry Number: 308-252 Dear Mr. Brandenburg: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may ffie with the Commission an application for rehearing. A request for rehearing 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. ~I~ JUL ~' ~ 2008 DATED this ~ day of July, 2008 Encl. Sincerely - - g, ~~ A ~(~'av STATE OF ALASKA j~~ ° I' /I 6 J U ~._ +~ 1/ ALA OIL AND GAS CONSERVATION COM ION ~~ APPLICATION FOR SUNDRY APPROVAL~3~~~~~ ~'a ~n aar ~~ ~Rn zoos J'"'~tS. ~5:~37'ta99aS(~il"I ,,~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^~ Waiver ^ Other ^ Alter casing^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Adding Tyonek Change approved program^ Pull Tubing ^ Perforate New Pool^ ~ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development ^ Exploratory ^ 197-067 3. Address: Stratigraphic ^ Service Q, 6. API Number: PO Box 196247, Anchorage, AK 99519 50-733-20043-02 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ~ A-08RD2 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): / ADL0018731 Mono od Plt 38.52' , Tradin Ba Field/Hemlock Oil A'/~~K~~-~ 12. PRESENT WELL CONDITION SUMMARY ~• ZZ• Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7,643' ~ 6,608' ' 7,410' 6,458' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,075' 13-3/8" 1,075' 1,062' 3090 psi 1540 psi Intermediate 7,082' 9-5/8" 7,082' 6,247' 6330 psi 3810 psi Production 7,642' 7" 7,642' 6,607' 8160 psi 7020 psi Liner N/A N/A N/A N/A N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" See Attached Schematic 3,849' Packers and SSSV Type: Packers and SSSV MD (ft): HES PHL Packer and N/A 3,778' and N/A 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^ Service Q 15. Estimated Date for 8/1/2008 16. Well Status after proposed work: Commencing Operations: Oil ^ Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ Q WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 276-7600 Date 7/16/2008 ~s COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: - a,5 Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ +~ I Other: 'VV C,,\\ C~:<.~~C\'~-~is i ~? --r~~~~' ~ ~. C~..C cr:,c'~~., ~~ 1 ~ ~ ~~~. ~ ~ . ~~ 1 Subsequent Form Required: ~ ~ (.1 APPROVED BY A roved b : OMMISSIONER THE COMMISSION Date: ~~5~' tJ p pp y i~ ~0 ~ I C~~P'CCA~ n ~ ~~~ ~ ~0~8 ~ ~ Z2. Form 10-403 Revised 06/200 ~i,~t.. f Subn}j~p c t Chevron • • Monopod Well No. A-8RD2 (Inj.) As Completed 7-10-97 API # 50-733-20043-02 RKB to TBG Head = 38.52' 5 HB HB HB SIZE CASING AND TUBING DETAIL WT GRADE CONN ID TOP BTM. 13-3/8" 61# J-55 12.515 Surf 1,075' 9-5/8" 43.5# J-55 / N-80 8.755 Surf 7,082' Section Mi119-5/8" casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' Tubing: 3-1/2" 9.2# L-80 BTC (SCC) 2.992 Surf 1,572' 3-1/2" 12.95# L-80 PH-6 2.750 1,572' 3,778' 3-1/2" 9.23 L-80 BTC (SCC) 2.992 3,784' 3,849' NO. Depth ID JEWELRY DETAIL Item 1 38.52' 2.875" CIW 11" 5M DCB 3-1/2" EUE Hanger. 2 39.27' 2.992" 3-1/2" EUE X 3-1/2" Butt Crossover 3 1,572' 2.750" 3-1/2" Butt X 3-1/2" PH-6 (12.95#) Crossover 4 3,778' 2.750" 3-1/2" PH-6 (12.95#) X 3-1/2" EUE Crossover 5 3,778' 2.885" HES 7" X 3-1/2" PHL Packer 6 3,784' 2.992" 3-1/2" EUE X 3-1/2" Butt Tubing Pup 7 3,817' 2.562" 3-1/2" HES `R' Landing Nipple 8 3.850' 2.750" Wireline Re-entry Guide NOTE: Set 20,000# on Packer Slickline/Fish/Fill Information: 7/18/07: Ran 2" Gauge Ring to7,410' & tagged. 5/1/O1: Ran 2.25" Gauge Ring to 7,530'. Ran 1.5" bailer to 7,530'. Recovered scale- like solids & thick fluid. PERFORATION DATA Accum last Zone Top Btm Amt SPF PerF Date Pn~ent Condition HB 6,892' 7,040' 148 6 7/7/1997 Open HB 7,061' 7,334' 273 6 7/7/1997 .Open HB 7,356' 7,456' 100 6 7/7/1997 Open PBTD = 7,555' TD = 7,643' MAX. HOLE ANGLE = 52° SCHEMATICS_RD2 A8RD2Actua10797.doc DATE: 7/7/08 By: CVK Chevron Monopod Proposed Well No. A-8RD2 (Inj.) API # 50-733-20043-02 KB to TBG Head = 38.52' 5 58-0 58-7 60-0 HB HB HB SIZE CASING AND TUBING DETAIL WT GRADE CONN ID TOP BTM. 13-3/8" 61# J-55 12.515 Surf 1,075' 9-5/8" 43.5# J-55 / N-80 8.755 Surf 7,082' Section Mi119-5/8" casing 3,415' 3,427' 7" 29# L-80 Butt 6.184 Surf 7,642' Tubing: 3-1/2" 9.2# L-80 BTC (SCC) 2.992 Surf 1,572' 3-1/2" 12.95# L-80 PH-6 2.750 1,572' 3,778' 3-1/2" 9.23 L-80 BTC (SCC) 2.992 3,784' 3,849' NO. Death ID JEWELRY DETAIL Item 1 38.52' 2.875" CIW 11" SM DCB 3-1/2" EUE Hanger. 2 39.27' 2.992" 3-1/2" EUE X 3-1/2" Butt Crossover 3 1,572' 2.750" 3-1/2" Butt X 3-1/2" PH-6 (12.95#) Crossover 4 3,778' 2.750" 3-1/2" PH-6 (12.95#) X 3-1/2" EUE Crossover 5 3,778' 2.885" HES 7" X 3-1/2" PHL Packer 6 3,784' 2.992" 3-1/2" EUE X 3-1/2" Butt Tubing Pup 7 3,817' 2.562" 3-1/2" HES `R' Landing Nipple 8 3.850' 2.750" Wireline Re-entry Guide NOTE: Set 20,000# on Packer Slickline/Fish/Fill Information: 7/18/07: Ran 2" Gauge Ring to7,410' & tagged. 5/1/O1: Ran 2.25" Gauge Ring to 7,530'. Ran 1.5" bailer to 7,530'. Recovered scale- like solids & thick fluid. PERFORATION DATA At;cum Last Zone Top Btm Amt SPF PerF ate Present Cond'Ition 58-0 6,453' 6,498' 45 4 proposed proposed 58-7 6,534' 6,590 66 4 proposed proposed 60-0 6,6'95 6,730' 34 4 proposed proposed HB 6,892' 7,040' 148 6 7/7/1997 Open HB 7,061' 7,334' 273 6 7/7/1997 Open HB 7,355 7,455 100 6 7/7/1997 Open PBTD = 7,555' TD = 7,643' MAX. HOLE ANGLE = 52° SCHEMATICS_RD2 A8RD2_Proposed_7.16.08.doc DATE: 7/16/08 By: CVK Chevron ~ ~ Trading Bay Unit Well # A-081tD2 7/16/08 OBJECTIVE: • Perforate 58-0, 58-7 and 60-0 Zones PROCEDURE SUMMARY: 1 Slickline Pelimnary work 2 MUSpot and RU Eline. Test BOPE's 3 RIH Perforate 58-0 Zone from 6,453' to 6,498' (+/-) 5 RIH Perforate 58-7 Zone from 6,534' to 6,590' (+/-) 6 RIH Perforate 60-0 Zone from 6,696' to 6,730' (+/-) 7 RD Eline Unit. Package for Demobe A-08RD2 REVISED BY: BCA 7-16-08 MEMORANDUM . State of Alaska . Alaska Oil and Gas Conservation Commission TO: J ¡m Regg <""'D P.I. Supervisor f\è11 b{7/0 7 DATE: Thursday, June 07, 2007 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA A-08RD2 TRADING BAY 5T A-08RD2 Src: Inspector /\ ~ 0{01 . C\ 1 \ Reviewed By: P.I. Suprv.:::fß(Z- Comm FROM: JeffJones Petroleum Inspector NON-CONFIDENTIAL Well Name: TRADING BAY ST A-08RD2 API Well Number: 50-733-20043-02-00 Inspector Name: Jeff Jones Insp Num: mitlJ070606184359 Permit Number: 197-067-0 Inspection Date: 5/31/2007 /' Rei Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well A-08RD2 Type Inj. w TVD 3458 IA 1780 1520 1520 1520 I P.T.D 1970670 TypeTest 5PT Test psi 1500 OA 0 0 0 0 I Interval 4YRTST P/F P v Tubing 1800 2100 2120 2120 I Notes: The tubing injection pressure was increased and the IA pressure was decreased prior to the test to achieve a differential pressure. The platform appeared clean, orderly and in good condition. ;/ SCANNED JUN 2 0 2007 Thursday, June 07, 2007 Page 1 of 1 Re: MIT _ Monopod A-8RD2 _05-31-07 e e Subject: Re: MIT_Monopod A-8RD2_05-31-07 From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Mon, 11 Jun 2007 10:25:31 -0800 To: "Greenstein, Larry pI' <Greensteinlp@chevron.com> cc: "Lambert, Steve A" <salambert@chevron.com>, Jim Regg <jim_regg@admin.state.ak.us> \ c;. '\ -0<"0 ~ Thanks Larry, The plot shows that the differential has been maintained. This is good. I know what you mean about not being able to troubleshoot when the pressures are too close. Tom Greenstein, Larry P wrote, On 6/11/2007 10:22 AM: An update Tom and I'll be glad to add this well to the monitoring report. We bled the casing down to 900# to create a pressure differential from the tubing on Thursday last week. This differential has held through the weekend as you can see by the attached TIO plot. Still don't know why these two pressures were so close to each other when we started the MIT. Normally we don't like them there either...too tough to monitor for MIT failure. Hope this satisfies your curiosity, for now? Larry s~mED JUN 1 1 2007 From: Thomas Maunder [mailto:tom maunder@admin.state.ak.usl Sent: Monday, June 11, 2007 9:42 AM To: Greenstein, Larry P Cc: Lambert, Steve A; Jim Regg Subject: Re: MIT_Monopod A-8RD2_05-31-07 Larry, In order to keep an eye on this well, would you please add it to the monitoring report. Call or message with any questions. Thanks, Tom Maunder, PE AOGCC Greenstein, Larry P wrote, On 6/7/20074:21 PM: Allright Tom, here is what I found out. The TIO plot shows a couple of instances of the casing pressure climbing up to the tubing pressure after the injection line repair. Inbetween, after the MIT, a clear separation of the pressures was maintained for several days. Talked with Lambert and the field about possible causes and none were offered, besides the MIT test itself, to explain the fluctuations in the casing pressure. Just today we bleed off -1000# from the casing to creat a delta pressure that we can monitor. Because the well passed the MIT on 5/31, it is interesting to note the casing pressure climb from just a couple days ago. The operators know that if the casing and tubing pressures lof2 6/11/2007 11 :49 AM Re: MIT _ Monopod A-8RD2 _05-31-07 e e equalize, the well has to be shut-in and you guys have to be notified. Thanks Tom and we will be watching this one closely. Larry -----Origina1 Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Thursday, June 07, 2007 7:56 AM To: Greenstein, Larry P Subject: Re: MIT_Monopod A-8RD2 05-31-07 Hi Larry, I was looking worked over. nearly equal well? Thanks, Tom at the MIT. I understand that the well was recently It is interesting that the tubing and IA pressures are at the start of the MIT. Do you have a TIO plot for the Greenstein, Larry P wrote, On 6/1/2007 7:40 AM: Gentlemen, Here is the report for the MIT on Monopod well A-8RD2. Thanks. Larry «MIT Monopod A-8RD2 05-31-07.xls» > 2 of2 6/11/2007 11 :49 AM . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us;Tom_Maunder@admin.state.ak.us OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Unocal Alaska Trading Bay Field / Monopod platform 05/31/07 Geller/Dorman Jeff Jones \<\1" 0101 Packer Depth Pretest Initial 15 Min. 30 Min. Weill A-8RD2 I Type Inj. I W TVD I 3,458' Tubing 1,800 2,100 2,120 2,120 Intervail 4 p.T.D.11970670 I Typetest I P Test psil 1500 Casing 1,780 1,520 1,520 1,520 P/FI P Notes: Incresed injection rate to pressure up tubing. OA 0 0 0 0 Bled off pressure from annulus to demonstrate tbg/csg pressure isolation. Weill I Type Inj. I I TVD I Tubing Interval 0 p.T.D.1 I Type test I I Test psil Casing P/FI Notes: OA . Weill I Type Inj.1 I TVD I Tubing Interval I P.T.D.I I Type test I I Test psil Casing P/FI Notes: OA Weill I Type Inj.1 I TVD Tubing Intervall p.T.D.1 I Type test! I Test psi I Casinq P/F Notes: OA Weill I Type Inj.1 I TVD I Tubing I nterval P.T.D.I I Type test I I Test psi! Casing P/FI Notes: OA TYPE INJ Codes D = Drilling Waist G = Gas I = Industrial Waistewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= Other (describe in notes) SCANNE.D JUL 1· () Z007 MIT Report Form BFL 9/1/05 MIT Monopod A-8RD2 05-31-07.xls Re: Monopod well A-8RD2 (197-067) . . Thanks Steve. Please keep Jim Regg informed regarding when the MIT is scheduled again. Please also note that according to our records, A-8 (167-053) was P&Aed in 1989 and A-8RD (189-048) was P&Aed in 1997. Tom Maunder, PE AOGCC Lambert, Steve A wrote, On 4/19/20077:23 AM: Tom we had planned to perform an MIT on injection well A-8 yesterday while the inspector was at the Monopod, but there was an issue with the flow line and the well has been shut-in. We have ordered the parts to repair the failure and we will reschedule the MIT when the well has returned to stablized injection following the repair. ~i~ APR 1 9 2007 1 of 1 4/19/2007 11 :57 AM MEMORANDUM State of Alaska Al, ~ J. ~ _Alaska Oil and Gas Conservation Commission TO: Randy Ruedrich ~.3~,¢~ : , ATE April 4 2003 Commissioner t.\~.~,~ {:,~ SU BJ ECT: Mechanical Integrity Tests THRU: Maunder/Regg~ ~ UNOCAL Petroleum Engineer's Monopod platform A-19RD, A-SRD2 FROM: Lou Grimaldi Trading Bay Field Petroleum Inspector Trading Bay Unit NON- CONFIDENTIAL Packer Depth Pretest Initial 15 Min. 30 Min. Well] A-08 RD2 ]Type InJ. I I I I I I I I I,nter a,I4 P.T.D.I 197-067 I Type testI P I Testpsil 4500 I Casingll,85011,20011,20011,200I P/F I P Notes: We,I A-*9 RD I Type,nj.I S I T.V.D. I ~ ITu~'"~ I~,~°° I',°°° I',°°° I~,°°° I'nterva'l P.T.D.I 188-001 I TypetestI P I Testpsil 1500 I Casingl 85 I ~,6oo1~,58Ol ~,58Ol P/F I Well a/ready pressured up above test pressure, observed in this state for thirty minutes. Lowered IA Notes: to 1200 psi and observed for an additional Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS INJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey D= Differential Temperature Test Test's Details Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover O= Other (describe in notes) I witnessed mechanical Integrity tests on A-08 RD2 and A-19 RD aboard the Monopod platform, both wells passed their tests A-08 RD2 already had annulus pressure above required test pressure, I observed this for thirty minutes with no change. The annulus pressure was dropped 650 psi and observed for an additional thirty minutes with no change. M.I.T.'s performed: _2 Attachments: None Number of Failures: None Total Time during tests: 3 hours ,cc: Gary Smith (Monopod) SCANNED JUN _1 9 2003 MIT report form 5/12/00 L.G. 2003-0404_MIT_TBF_Monopod_A-08RD2_lg.xls 5~8/2003 Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7651 Fax: (907) 263-7828 E-mail: hamsonb~unocal.com UNOCAL Beverly Harrison Business Ventures Assistant May 30, 2002 To: Lisa Weepie AOGCC 333 W. 7th Ave. Anchorage, AK 99501 DATA TRANSMITTAL- Alaska / Offshore / Monopod Platform Dry Samples A-3RD 2 3492'-4890' 4890'-6210' 6210'-7262' Box 1 of 3 Box 2 of 3 Box 3 of 3 [5q7 A-3RD 3 A-8RD A-27RD 5980'-7240' 7240'-8350' 8350'-8525' 3440'-4510' 4510'-5590' 5590'-6850' 6880'-7641' 8460'-9600' 9600'-10710' 10710'-11640' 11640'-12660' 12700'-12900' Box 1 of 3 Box 2 of 3 Box 3 of 3 Box 1 of 4 Box 2 of 4 Box 3 of 4 Box 4 of 4 Box 1 of 5 Box 2 of 5 Box 3 of 5 Box 4 of 5 Box 5 of 5 Dry anu v'B'-W~, c Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. TD PERMIT AOGCC Individual Well Geological Materials Inventory DATA T DATA PLUS Page: 1 Date: 07/19/99 RUN RECVD ---- 97-067 BHe/SL 36-7svs 1 97-067 PIL-SFL ~36-7592 1 97-067 CN/LDT ~436-7547 1 97-067 97-067 DEPTH DET. ~.~500-6830 1 97-067 CBT ~1400-7560 1 97-067 7818 /sCHLUM DITE/SDL/LDT/CNL 1 97-067 SR~ C~C ~ 3415.3-7643. 08/28/97 08/28/97 O8/28/97 08/28/97 08/28/97 08/28/97 09/16/97 10/23/97 10-407 '~/CO~PLETION D~TE @ 7/~ /~/ D~I~Y WE~ OP8 R @ ~/~/~?/ TO 7 //0/~/ Are dry ditch samples required? yes ~/knd received? Was the well cored? yes ~L~ ..Analysis & description received? Are well tests required? o~s .~.. Received? Well is in compliance Initial COMMENTS o/O 1~73 lq ?1 ye g~--ne~ ...... BOX Ju ,i2, i999 9'40AM UNOCAL CORP, .- 1'4o,bUU' F, ' Unocal Corporation Agricultural Products 909 West 9u' Avenue, P.O, Box 196247 Anchorage, Alaska 99519.6247 Telephone (907) 263-7830 UNOCAL 7/9/99 Blair Wondzel State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re; Monopod A-SRD2. Dear Blair: This letter is to document your awareness that we observed and verbally notified you, on 5/17/99, of a pressure increase of 200 psi on the easing over a 30 day period, indicating a possible breach in the tubing. We have since pressure tested the wellhead and found no problems, The well is still on injection and we request your permission to continue injection while we conduct slickline diagnostic work to identify the problem. Please sign and send a copy of this letter to my fax at 263-7884 otherwise call me at 263-7636. ChristolSh6r g,. Ruff "" ';i,.: Senior Reservoir Engineer .~ ,~..._ · Cook Inlet Waterflood Management Please return a signed and dated copy of this letter to document your agreement with this operation for our records. Blair Wondzel /~ AOC. CC ~ Date Aogcc A-SRD Leak Aeknowledgmem 7/9/99 13:52 UNOO.thL ASSET Offs GRP FP, X NO, EJU/;.'U~t.H~4 ~', uz/u~ Unocal Corporation 909 West 9'~ Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 UNOCAL March 27, 1998 Wendy Mehan Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Status of LTnocal's Cook Inlet Injector Work Dear Wendy, This letter is to provide you with an update of the work conducted since our January 23, 1998 letter which Blair signed granting time extensions for ,various wells. Testing or work was completed on the following wells and the results of this work is listed: Anna 29-42: Well head inspection completed (no leaks), Variance granted on 3/3/98. Baker 4: ~ passed on 2/15/98 by Leu Gnmaldi Bruce 31-42: Coil Tubing operation completed to repair leaking cement plug. Pressure test completed. GP 33-14RD: SI MIT successfully completed on 2/11/98. GP 22-13RD2: Variance granted on 3/17/98, MIT completed on 12/15/97. Grayling 16: Workover ~mpleted on 3/26/98. ~ Passed. --- Monopod A-8RD2: IVllT passed on 1/28/98 by Lou Grimaldi Testing or work was atto_ _rrmtcd on thc following shut-in wells and a time extension until June 30, 1998 is requestee~ t_o complete further work and testing. Anna 1942: Scale cleanout of tubing completed, further testing scheduled to prove casing integrity. Anna 27-42: Scale cleanout of tubing completed, further testing scheduled to prove casing integrity. Anna 4642: Temp Survey mn on 2/17/98, survey should prove no flow and allow SI status. Baker 9: MIT attempted on 2/15/98, further wireline testing scheduled to prove casing integrity.. Monopod A-12RD2: SI MIT attempted, Temp Survey scheduled to prove no flow. Monopod A-29 : SI Mrr scheduled to prove no flow/casing integrity King 4RD : WFL indicates possible casing leak, well shutin, further testing and workover scheduled. King 15RD: WFL indicates possible casing leak, well shutm, further testing scheduled. King 22RD: WFL indicates possible casing leak, well shul/n, further testing scheduled. Grayling 5 : Workover/Redrill scheduled in current drilling schedule. Grayling 22 : Workover/RedfiI1 scheduled in current drilling schedule. Grayling 28 : Workover/Redrill scheduled in current drilling schedule. Grayling 36DPN : Workover/Redrill scheduled in current drilling schedule. Grayling 40 : Workover/Redrill scheduled in current drilling schedule. Unocal respectfully requests a time-extension until June 30, 1998 to complete the work on the above listed Anna, Baker and Monopod wells. The Grayling and King work will be executed per our current drilling schedule. J~l~ilsc call me if you have any questions or clarification on these issues. ~ ~ i... ~ i \1 ~ t..,/ Senior Reservoir Engineer Cook Inlet Waterflood Mana~~':'i & t~;a~ dor~s. :L,3mrn~ss~or) Please acknowledge the approval of the time extension and >'our receipt of this letter by faxing back a signed copy of this letter to Christopher Ruff at 263-7874 (fax). ~Vendy~hd~han' Dat~ '! AOGCC Unocal AlasKa Resource~ ~Jnoca~ Coroora[~on 909 West 9th Avenue. P.O. Box: 96247 ,C. ncnoraae, AlasKa 995! 9-6247 Teleonone ~907'~ 27~-763'0 lINC)CAi. January 23, 1998 Blair Wondzell State of Alaska Alaska Oil and Gas Consen/ation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Status and Plans for MIT testing of Cook Inlet Injection Wells Dear Blair: Thank you for your assistance in helping us complete our mechanical integrity testing of water injectors in the Cook Inlet Area. The following is a status of our efforts to date. We also request a time extension for a group of wells listed below to allow us to complete testing work. We request a time extension for completing MIT testing on the following wells until the end of March 1998' Currently shut-in wells Granite Point Field Anna 19-42 Anna 27°42 Anna 46-42 ~'"~';*" ~'";"* Platfcm~, '*'-" ........ , ..... ,, ~l~ 33-14RD Middle Ground Shoal Field Baker #4 Baker #9 Currently injecting wells Tradinq Bay Field Monopod Platform A-8RD2 Wells Needing Repair The shut-in MIT on Bruce Platform Well. # 31-42 indicated a problem with the temporary abandonment which was completed on 10/7/88. We will develop and send to you a procedure for repairing or permanently abandoning this well. An MIT on shut-in Granite Point Platform Well, # 33-14 indicated a mechanical problem with this well. We will develop and send to you a procedure for repairing or permanently abandoning this well. We also want to confirm your receipt and approval of the following shut-in MIT tests. For our records, please sign and return a copy of the following shut-in MIT tests: Baker #8 Baker #12 Monopod A-5R Monopod A-12R2 Monopod A-26 Monopod A-29 Please indicate your approval of the shut-in tests and the time extension requested by signing and returning a copy of this letter. Thanks again for your help in this matter. Sincerely, etanka Reservoir Engineer Agreed to by: Blair Wondzell ~/' ' Petroleum Engineer AOGCC STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: SUSPENDED: ABANDONED: SERVICE: X Water Injector 2. Name of Operator 7. Permit Number Unocal r'-~.~-- ,: T' ~:~.?"?'-~ 97-67 3. Address i ' ' ' '. .... "; 8. APl Number P.O. Box 196247 Anchorage, AK 99519 ~ "7/~ ~i3 ,~ !: 50- 7=-20043-02 4. Location of well at surface Conductor # 12 ~ 'i ~ '~"~. ". '... ~ i' ~T~%~-.~; 9. Unit or Lease Name 1612' NSL & 577' WEL SEC. 4, TgN, R13W, SM : · .-.. ...... r Trading Bay State At Top Producing Interval @ 6888' MD / 6100' TVD/-5999' S .'-; .......... ~. 10. Well Number 1330' N & 3501' W From SE Cor SEC. 4, TgN, R13W, SM A-SRD2 At Total Depth 11. Field and Pool 1240' N & 4087' W From SE Cot SEC. 4, TgN, R13W, SM Hemlock 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 101 MSLI ADL 18731 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. I 15. Water Depth, if offshore 16. No. of Completions 6/21/1997 7/2/97 7/10/97I 62' feet MSL None 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey 20. Depth where SSSV set I 21. Thickness of Permafrost 7643' MD / 6566' TVD 7556' MD / 6516' TVD Yes: X No: N/A feet MDI N/A 22. Type Electric or Other Logs Run DIL\ LDT\ CNL\ Sonic\ GR & Mudlog 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 45 225' Driven 13-3/8" 61# J-55 45 1075' 18-5/8" Cmt'd to surface. 9-5/8" 43.5# ,S-95 45 3412' 12-1/4" Cmt'd to surface. 7" 29# L-80 45 7642' 8-1/2" 850 (sx) 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3 1/2", 9.2#, L-80 3850' 3779' 6,892 - 7,04¢; 7,061 - 7,334'; 7,356- 7,456' MD (6SPF) 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 6,130 - 6,250'; 6,266 - 6,480'; 6,497 - 6,554' TVD DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) N/AI Water Injection Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO I TEST PERIOD => Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 24-HOUR RATE => 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. - ...... ~;' O?'T 1997 Form 1 0-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. ' 30. -~.~_. p.. GEOLOGIC MARKERS , FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Hemlock Fm 6888' 6100' (Injection zone) 6,892' 6,130.' to to 7,456' 6,554' 31. LIST OF ATTACHMENTS Daily/Operations Summary, Wellbore Diagram 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Dale A. Haines ~~/~l ~ Drilling Manager 'October 16, 1997 Signed¢,- Title Date INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report an;:l log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 MONOPOD PLATFORM WELL HISTORICAL SUMMARY 50-733-200~3-02 WELL A-8RD2 1997 6/22-25 6/26-30 7/2 7/3-6 DAY 1-4 OPERATIONS COMMENCED ON A-8RD2 AT 1500 HRS 22 JUNE 1997. PREPARE RIG FOR OPERATIONS. N/D TREE AND NFLI BOP'S. MAKE UP LANDING JOINT AND RETRIEVE KILL STRING. MAKE UP 9-5/8" EZSV AND RIH ON DRILLPIPE AND SET AT 3641 '. RIG LIP TO CEMENT SQUEEZE ABANDON PERFORATIONS BELOW. ESTABLISH INJECTION RATE AND SQUEEZE AWAY 500 SX. CLASS G AT 15.8 PPG. POOH WITH CEMENT STINGER. FINAL SQUEEZE PRESSURE OF 2800 PSI AT 1BPM. REVERSE OUT CEMENT AND TEST 9-5/8" ANNULUS TO 1500 PSI. POOH WITH RUNNING TOOL. N/D BOP'S AND DCB SPOOL FROM WELLHEAD. INSTALL NEW "WF" CASING SPOOL. TEST CASING SPOOL TO 2000 PSI. NFLI BOP'S AND TEST TO 300/3000 PSI. MAKE UP SMITH WHIPSTOCK, AND MWD. RIH TO 3436 (WLM) ORIENT WHIPSTOCK AND SET PACKER. COM'IVIENGE MILLING OPERATIONS. MILLED WINDOW FROM 3415'rr~Q 3427 ,..~RILLED NEW HOLE TO 3441'. PULL MILLING ASSEMBLY THROUGHWH~PS~TOCK. CONDUCT LOT TO 16.8PPG. POOH AND LAY DOWN MILLING ASSEMBLY. MAKE UP DIRECTIONAL BHA WITH XL MOTOR AND ANDERGAUGE ADJUSTABLE STABILIZER. CONTINUE RIH WITH DIRECTIONAL BHA WITH XL MOTOR AND ANDERGAUGE ADJUSTABLE STABILIZER ASSEMBLY. DIRECTIONALLY DRILLED 8-1/2" HOLE FROM 3441' TO 3988'. ENCOUNTERING DIFFICULTIES SLIDING. POOH TO CHECK BIT CONDITION. DAY 5-8 CONTINUE POOH. FOUND BIT BADLY DAMAGED WITH CASING DEBRIS. M/U INSERT BIT ON MOTOR WITH ADJUSTABLE GAGE STABILIZER AND RIH. DIRECTIONALLY DRILL AHEAD FROM 3988' TO 5215'. POOH FOR PDC BIT. CONTINUE POOH. M/U PDC BIT ON DIRECTIONAL ASSEMBLY AND RIH. DRILL 8-1/2" HOLE FROM 5215' TO 6231'. POOH FOR BIT. MAKE UP SECURITY 2941 PDC BIT AND RIH. DRILL FROM 6231-6307'. UNABLE TO STEER EFFICIENTLY. POOH FOR INSERT BIT. RIH AND DRILL AHEAD FROM 6307'-7022'. POOH FOR BIT AND WEEKLY BOP TEST. DAY 10 CONTINUE DRILLING 8-1/2" HOLE TO WELL TD AT 7643'MD/6453'TVD.PERFORM WIPER TRIP AND POOH TO LOG. R/U SCHLUMBERGER AND COMMENCE DITE/SDT/LDTD/CNTH/GR/AMS LOGGING RUN FROM 7,600'. LOG DITE/SDT/LDTD/CNTH/GR/AMS FROM 7600' TO KOP AT 3412'. R/D SCHLUMBERGER. INSTALL 7" CASING RAMS AND TEST BOP'S. R/U AND RUN 7" CASING TO 7642'. CIRCULATE CASING VOLUME AND CEMENT CASING WITH 175 BBLS 12.9PPG LEAD SLURRY FOLLOW-ED BY 60 BBLS 15.8PPG TAIL SLURRY. DISPLACE WITH 297 BBLS FIW. DID NOT BUMP PLUG. CIP AT 23:45 HRS. DAY 11-15 N/D BOP'S. SET CASING SLIPS WITH 40K TENSION. MAKE CUTS AND INSTALL DCB SPOOL. TEST SPOOL TO 3000 PSI. N/U BOP'S AND TEST TO 250/5000 PSI. LAY DOWN 5" DRILLPIPE AND PICK LIP 3-1/2" DRILL PIPE. RIH WITH 6" BIT AND SCRAPER ASSEMBLY. TAG CEMENT PLUG AT 7474'. CLEAN OUT CEMENT TO 7555' AND CIRCULATE HOLE CLEAN. POOH AND TCP GUN ASSEMBLY. (RIH WITH 521' OF 4-5/8", 6SPF, 60 DEG TUBING CONVEYED PERFORATING GUNS.) R/U SCHLUMBERGER AND RUN GR/CCL FOR SPACE OUT. DROP BAR TO DETONATE GUNS. (NO STRONG SIGN OF 7/7 7/8-10 INFLUX) OPEN PACKER BY-PASS AND CIRCULATE OUT. POOH WITH TCP ASSEMBLY. GUNS HAD NOT FIRED. DE-ARM GUNS AND RE-RUN TCP ASSEMBLY WITH ANNULAR PRESSURE FIRE SYSTEM. R/U SCHLUMBERGER AND RUN GR/CCL FOR SPACE OUT. PRESSURE UP ANNULUS AND FIRE GUNS (GOOD INDICATION OF GUNS FIRING). OPEN BY-PASS AND CIRCULATE OUT. POOH WITH GUN ASSEMBLY (ALL GUNS FIRED). R/U TO RUN 3-1/2" COMPLETION ASSEMBLY. DAY 16 CLEAN LIP 3-1/2" PH-6 TUBING PRIOR TO RUNNING COMPLETION ASSEMBLY. RIG UP TO RUN COMPLETION. MAKE UP HOWCO 7" PHL PACKER ASSEMBLY AND RIH WITH 3-1/2" TUBING. (70 JTS 12.95 LB/bT PH-6 L-80 TUBING AND 49 JTS 9.2 LB/bT BUTt L-80 TUBING) LAND HANGAR AND PICKUP 12" ABOVE TUBING SPOOL. DROP BALL AND LAND ON "RHC" PLUG. DISPLACE ANNULUS WITH 1% TRETOLITE CRW-132 INHIBITOR. PRESSURE UP AND SET "PHL" PACKER. LAND TUBING AND PRESSURE TEST ANNULUS TO 1500 PSI.. RIH WITH SLICKLINE AND RECOVER PLUG. SET BPV AND N/D BOP'S. NIPPLE LIP TREE AND TEST TO 5000 PSI. TURN WELL OVER TO PRODUCTION AT 24:00 HRS. DAY 17-18 PRODUCTION STARTED INJECTION ON A-8RD2 AT 1430 HRS. CONTINUED INJECTION ON WELL A-8RD2. R/U BLOCK/HOOK ASSEMBLY. FABRICATE AND INSTALL CAGING ON BUMPER BLOCK. CONTINUED INJECTION ON WELL A-8RD2. P/U KELLY AND SWIVEL. PREPARE FOR RIG MOVE TO A-9RD (WO). RIG RELEASED FROM A-8RD AT 0800 HRS 10 JULY 1997. 50-73~-2004~-02 Monopod Platform Conductor 12 TBS A-SRD2 Trading B_ay Stat:e Trading Hay Field RKB E ev. 101 FT. MSL Tbg Head FI.q Depth 57.4-0 Ft. Mid--PerT Deviation 50 40.0 - 1075.0' 15 5/8" OD 61.00#/f[ J-55 SURF CSO 1075.0 - 1075.0' SHOE 40.0 - ,5412.0'9 5/8" OD 45.50#/f~ J-SS/N-80 PROD CSG 5410.0 - 5412.0' SHOE 58.5 - 7642.0' 7" OD 6.184" ID 29.00#/fi N-80 LINER ,58.5 - 1572.1' 5.500" OD 2.992" ID 9.20#/fi L-80 TBG 7/8/97 38.5 - 39.3' HANGER 61W DCB Hgr. ...., 1572.1 - 1572.8' 1572.8 - 5777.7' 1572.8 - ,5774.0' 5774.0 - 5777.7' 5777.7 - 5778.5' 5785.7 - 5849.4' CROSSOVER 5-1/2" BUTT x PH-6 BXP 5.500" OD 2.750"1D 12.95#/ft L-8OTBG 7/8/97 5.50" OB 2.750"10 JOINTPH-6 4.56" 00 2.687"IDJOINTPH-6 PUP CROSSOVER ,5-1/2" PH-6 x 5-1/2" EUE BXP 5.500" OB 2.992"10 9.20#/f~ b-80 TaG 7/8/97 `5778.5 - 5785.7' 5.970" OD 2.885" ID REI-RV. PACKER HES "PHL" Pkr. 38~ " l~ ,,n ' 7.u - 5818.5' 2.562" i0 u-,NuING NIPPLE HES ,5849.4 - ,5850.0' 2.750" ID REENTRY JOINT WL Entry Guide 7556.0 - 7645.0' CEMENT PLUG 7556.1 - 7557.5' FLCOLLAR KB ELEV: I01' PBTD: 7555' TD: 7645' 6892.0 - 7040.0' PERFS HB, 7/6/97, 6HPF, 148', 4-5/8" TCP Guns, 60 Phase 7061.0 - 7554.0' PERFS HD, 7/6/97, 6HPF, 275', 4-5/8" TCP Guns, 60 Phase 7556.0 - 7456.0' PERFS HB, 7/6/97, 6HPF, 100', 4-5/8" TCP Guns, 60 Phase Water Injector Redrilled & Completed 7/8/97 Lasl Perf'd 7/6/97 50-735-2004-3-02 Monopod Plat:form Conductor 12 TBS A-8RD2 Trading B_ay Stclte Trading Hay Field RKB Elev. 101 FT. MSL Tbg Head FI.q Depth 57.40 Ft. Mid--Perf Deviation 50 4-0.0 - 1075.0' 1,5 5/8" OD 61.00#/f[ J-55 SURF CSG 1075.0 - 1075.0' SHOE~ 40.0 - 5412.0' 9 5/8II OD 45,50#/f[ J-55/N-80 PROD CSt 54-10.0 - 54.12.0' SHOE'~ 58.5 - 7642.0' 7" OD 6.184-'l ID 29.00#/fl: N-80 LINER 58.5 - 1572.1' 5.500" OD 2.992" ID 9.20#/f[ L-80 TBG 7/8/97 58.5 - 39.5' HANGER 61W DOB Hgr. 1572.1 - 1572.8' CROSSOVER `5-1/2" BUTT x PH-6 BXP 1572.8 - 5777.7' 5.500" OD 2.750" lB 12.95#/ft L-80 TBG 7/8/97 1572.8 - `5774.0' 5.50" OD 2.750" ID JOINT PH-6 5774.0 - 5777.7' 4.56" OD 2.687" ID JOINT Pm-6 PUP 5777.7 - 5778.5' CROSSOVER 5-1/2" PH-Gx 5-1/2" EUE BXP 5785.7 - 5849.4' 5.500" OD 2.992" ID 9.20#/fl, L-80 ]'BO 7/8/97 ,5778.5 - `5785.7' 5.970" OD 2.885" ID RE]'RV. PACKER HES "PHL" Pkr. 38i 7.0 - 38~8.3~ 2.562': ID LANDING NIPPLE HES 584-9.4 - 5850.0' 2.750" ID REENTRY JOINT WL En[ry Guide 7556.0 - 7645.0' CEMENT PLUG 7556.1 - 7557.5' FLCOLLAR I KB ELEV: 101' PBTD: 7555' TD: 76451 6892.0 - 7040.0' PERFS HB, 7/6/97, 6HPF, 148', 4-5/8" TCP Guns, 60 Phase 7061.0 - 7554.0' PERFS HD, 7/6/97, 6HPF, 275', 4-5/8" TCP Guns, 60 Phose 7556.0 - 7456.0' PERFS HB, 7/6/97, 6HPF, 100', 4-5/8" TCP Guns, 60 Phase Wrier Inject:or Redrilled & Complet:ed 7/8/97 Last PerfId 7/6/97 50-75,3-20043-02 lonopod Platform onductor 12 40,0 - 1075.0' 13 3/8" OD 61,00#/[t J-55 SURF CS{; 1075.0 - 1075.0' SHOE 40.0 - 3¢12.C' 9 5/8II OD 43.50#/ft J--55/N--80 PROD CSG 5410.0 - ,3412.0' SHOE .~8.5 - 7642.0' 7" OD 6.184" ID 29.00J/f[ N-80 LINER TBS A-SRD2 Trading B_ay Slate Trading Bay Field RKB Elev. 101 FF. MSL l'bg Heed Fig Depth ,$7.40 Ft. Mid--Perf Deviation 50 38.5 - 39.`$' HANGER ClW DCB Hgr. 38.5 - 1572.1' 3.500" OD 2.992" ID 9.20#/fi L-80 TBG 7/8/97 1572.8 - .$777.7' 3.500" OD 2.750" ID 12.95#/fl L-80 TBG 7/8/97 378,$.7 - 3849.4' 3.500" OD 2.992" ID 9.20#/ft L-80 YBG 7/8/97 1572.1 - 1572.8' CROSSOVER 5-1/2" BUI-F × PH-6 BXP 1572.8 - ,$774.0' ,$.50" OD 2.750" ID JOIN]' PH-6 ,5774.0 - ,$777.7' 4.36" OD 2.687" ID JOINT PH-6 PUP ,~777.7 - ,$778.5' CROSSOVER `3-1/2" PH-6 x 3-I/2" EUE BXP 3778.5 - 5785.7' 5.§70'l OD 2.885" ID R~RV. PACKER HES "PHL" Pkr. 3817.0 - 3818]' 2,562" I0 ~DING NIPPLE HES 'IR" 3849.4 - 3850.0' 2.750" ID REENT~ JOINT WL Ent~ Guide CZ: 7556.0 - 76¢3.0' CEMENT PLUG 7556.1 - 7557.5' FLCOLLAR KB ELEV: 101' PBTD: 7555' TI): 764Y 6892.0 - 7040.0' PERFS HB, 7/6/§7, 6HPF, 148', 4-5/8" ]'CP Guns, 60 Phase 7061.0 - 73.$¢.0' PERFS HO, 7/6/97, 6HPF, 27,$', 4-5/8" I'CP Guns, 60 Phase 7~t56.0 - 7456.0' PERFS HB, 7/6/97, 6HPF, 100', 4-5/8" TCP Guns, 60 Ph(]se Water Injector Redrilled & Compleled 7/8/97 Lost Ped'd 7/6/97 ...... ', CALL; -II(JN N FIELD WORKSHE Job No. 0450-86423 Sidetrack No. 2 Page 1 of 2 1[, [4 11 =[,----~ Company UNOCAL Rig Contractor & U°. POOL ARTIC ALASKA- #56 Field T_.R~_..D_!_N._G.__B_A_Y__U,.N_!T__- 7 ' · __ Well Name & No. MONOPOD PLATFORM/A-8RD #2 Survey Section Name Definitive Survey BHI Rep. MILLER, YOUNG WELL DATA ~rget TVD (F~ Target Coord. N/S Slot Coord. N/S 1612.00 Grid Correction 0,000 Depths Measured From: RKB ~] MSL~] SS~ ~rget Description Target Coord. E/W Slot Coord. E/W 577.00., Magn. Declination '21.980 Calculation Method MINIMUM CURVATURE ,, arget Direction (OD) Build\Walk\DL per: 100ft[~ 30m0 10mf-] Vert, Sec. Azim. 258.00 Magn. to Map Corr. 21.980 Map North to: OTHER i i ii i i ii i iii SURVEY DATA Survey Survey !ncl, Hole Course Vertical Total Coordinate Build Rate Walk Rate Date Tool Depth Angle Direction Length TVD Section N(+) / S(-) E(+) / W(-) DL Build (+) Right (+) Comment Type IF1') (DO) (DO) {Fl') _ IF'ri , (FT) .... (FT) ...... (Pe.r, !O0 .FT)Drop, (;) Left (-) GMS 3415.30 24.36 280.64 3130,93 1170,54 32,15 -1203,14 TIE IN POINT S-JUN-97 MWD 4044,00 29,10 270,73 628,70 3692.57 1439,24 58,07 -1483,74 1,03 0,75 -1,58 S-JUN-97 MWD 4137,00 29,20 266,93 93,00 3773,79 1483,71 57,14 -1529.01 1,99 0,11 -4.09 ~-JUN-97 MWD 4230,00 28,50 261,48 93,00 3855,26 1528,28 52,64 -1573.61 2,93 -0,75 -5.86 3-JUN-97 MWD 4320,00 28,90 258,87 90.00 3934,21 1571,46 45,26 -1616.19 1,46 0,44 -2,90 .... 3-JUN-97 MWD 4415,00 28,90 258,80 95,00 4017,38 1617,37 36.37 -1661.23 0,04 0,00 -0,07 ~-JUN-97 MWD 4506.00 29,00 256,09 91.00 4097.01 1661,40 26,79 -1704.21 1,45 0.11 -2,98 ~-JUN-97 MWD 4601,00 28,70 258,06 95,00 4180.22 1707.23 16,54 -1748.89 1,05 -0,32 2,07 ,. , ~-JUN-97 MWD 4695,00 28,90 253,50 94.00 4282.61 1752,45 5.41 -1792,75 2.35 0,21 -4,85 S-JUN-97 MWD 4880.00 28.20 254.71 93.00 4425.15 1840.61 -18.47 -1877.80 0.34 -0.32 0,19 . ~-JUN-97 MWD 4974.00 28.10 256.59 94.00 4508.03 1884.91 -29.46 -1920.76 0.95 -0.11 2.00 ~-JUN-97 MWD 5066.00 27.20 257.40 92.00 4589.53 1927.60 -39.07 -1962.36 1.06 -0.98 0.88 ' · ~-J UN-97 MWD 5159.00 27.80 255.60 93.00 4672.02 1970.52 -49.10 -2004.11 1.1 0 0.65 -1.94 ~-JUN-97 MWD 5252.00 28.30 253.90 93.00 4754.10 2014.18 -60.61 -2046.29 1.01 0.54 -1.83 .., 7-JUN-97 MWD 5347,00 28.50 253.95 95.00 4837.66 2059.25 -73.12 -2089.71 0.21 0.21 0.05 .,~'~' ?-JUN-97 MWD 5442.00 28.40 253.61 95.00 4921.19 2104.38 -85.76 -2133.17 0.20 -0.11 -0.36 ,. , '~,~-~ 7-JUN-97 MWD 5534.00 28,50 253.83 92.00 5002.08 2148.09 -98.05 -2175.24 O. 16 0.11 0.24 7-JUN-97 MWD 5628,00 28,70 254.53 94.00 5084,61 2192,99 -110.31 -2218,53 0,42 0,21 0,74 !~. ~. ?-JUN-97 MWD 5722.00 28.60 254.35 94.00 5167.10 2237.97 -122.40 -2261.95 0.14 -0.11 -0.19 .................. i~ - '~' ~'"' '; 7-JUN-97 MWD 5816.00 28.70 253.33 94.00 5249,59 2282.92 -134.95 -2305.23 0,53 0,11 -1,09 .~ 7-JUN-97 MWD 5908.00 29.00 253.62 92.00 5330.17 2327.17 -147,57 -2347.79 0.36 0,33 0.32 7-JUN-07 MWD 6002.00 29.10 253.58 94.00 5412.35 2372.68 -160.46 -2391.58 0.11 0.11 -0.04 .~. _, '.7-JUN-97 ;' MWD -'1~095.00 29.20 252.51 93.00 5493.57 2417.81 -173.67 -2434.91 ---0157 0.11 -1.15 i ____ .. .. __ ,, ~,.~,~,~.~.~, ,,--_L~ Job No. 0450-86423 Sidetrack No. 2 Page 2 of 2' Well Name & No. MONOPOD PLATFORM/A-8RD #2 Survey Section Name Definitive Survey BHI Rep. MILLER, YOUNG WELL DATA ~rget TVD (FT) Target Coord. N/S Slot Coord. N/S __1612'00 Grid Correction 0.000__ Depths Measured From: RKB ~] MSL~ SS[-] ,rget Description Target Coord. E/W Slot Coord. E/W 577.00 . Magn. Declination .21.980 Calculation Method MINIMUM CURVATURE ~rget Direction (DD) Bulld\Walk\DL per: lO0ft~ 30mr'l lomr~ Vert. Sec. Azim. 258.00 Magn. to Map Corr. 21.980 Map North to: OTHER SURVEY DATA Survey Survey Incl. Hole Course Vertical Total Coordinate Build Rate Walk Rate Date Tool Depth Angle Direction Length TVD Section N(+) / S(-) E(+) / W(-) DL Build (+) Right (+) Comment Type (F-r) (DP) (DD) (FTI (FT) , (F'r) (FT) (Per lOO FT) Drop (-) Left (-) E~-JUN-97 MWD 6176.00 29.30 252.54 81.00 5564.24 2457.21 -185.56 -2472.66 0.12 0.12 0.04 8-JUN-97 MWD 6252.00 30.30 253.26 76.00 5630.19 2494.83 -196.66 -2508.76 1.40 1.32 0.95 9-JUN-97 MWD 6280.00 30.80 254.63 28.00 5654.31 o 2509.02 -200.59 -2522.44 3.06 1.79 4.89 ................... 9-JUN-97 MWD 6373.00 35.20 257.29 93.00 5732.29 2559.62 -212.81 -2571.57 4.98 4.73 2.86 9-JUN-97 MWD 6464.00 39.30 258.03 91.00 5804.71 2614.69 -224.56 -2625.37 4.53 4.51 0.81 :9-JUN-97 MWD 6556.00 42.40 258.33 92.00 5874.29 2674.86 -236.88 -2684.26 3.38 3.37 0.33 , , 19-JUN-97 MWD 6651.00 45.60 258.84 95.00 5942.62 2740.84 -249.93 -2748.94 3.39 3.37 0.54 !9-JUN-97 MWD 6744.00 48.60 259.24 93.00 6005.92 2808.94 -262.88 -2815.82 3.24 3.23 0.43 !9-JUN-97 MWD 6838.00 49.50 259.81 94.00 6067.53 2879.91 -275.78 -2885.63 1.06 0.96 0.61 .)9-JUN-97 MWD 6932.00 50.50 260.37 94.00 6127.95 2951.87 -288.17 -2956.57 1.16 1.06 0.60 30-JUN-97 MWD 7025.00 51.10 260.48 93.00 6186.73 3023.88 -300.16 -3027.63 0.65 0.65 0.12 30-JUN-97 MWD 7117.00 51.60 261.32 92.00 6244.19 3095.63 -311.52 -3098.58 0.90 0.54 0.91 30-JUN-97 MWD 7211.00 51.80 260.72 94.00 6302.45 3169.30 -323.03 -3171.44 0.54 0.21 -0.64. .... 30-JUN-97 MWD 7399.00 52.40 261.54 188.00 6417.93 3317.42 -345.90 -3318.01 0.47 0.32 0.44 01 -J UL-97 MWD 7492.00 52.60 261.77 93.00 6474.55 3391.05 -356.61 -3391.01 0.29 0.22 0.25 01-JUL-97 MWD 7588.00 52.50 262.90 96.00 6532.92 3467.05 -366.78 -3466.54 0.94 -0.10 1.18 01-JUL-97 MWD 7643.00 52.50 263.40 55.00 6566.41 3510.50 -371.98 -3509.86 0.72 0.00 0.91 Projected Data - NO SURVEY TONY KNOWLE$, GOVEF~NOI~ ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 April 17, 1997 Dale Haines Drilling Manager Union Oil Company of California P O Box 196247 Anchorage, AK 99519-6247 Re: Trading Bay State A-8RD UNOCAL Permit No. 97-67 Sur. Loc. 1612'FSL & 577'FEL, Sec. 4, T9N, R13W, SM Btmnhole Loc. 1208'FSL & 1244'FWL, Sec 4, T9N, R13W, SM Dear Mr. Haines: Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given at 279-1433. Chair~~ ~ BY ORDER OF THE COMMISSION dlffEnclosures cc: Department of Fish & Game, Habitat Section ~v/o encl. Department of Environmental Conservation w/o encl. " STATE OF ALASKA ALASKA O,-AND GAS CONSERVATION PERMIT TO DRILL 20 AAC 25.005 _.OMMISSION la. Type of work Drill: Redrill: x I lb. Type of well Exploratory: Stratigraphic Test: Devek)pment Oil: Re-Enb'~'.. Deepen:I Service: Injector Developement Gas: Single Zone: Multiple Zone: 2. Name of Operator Union Oil Company of California (UNOCAL) 3. Address P.O. Box 196247 Anchorage, AK 99519-6247 4. Locat]on of well at surface Conductor #12 1612' FSL & 577' FEL Sec. 4, T9N, R13W SM At top of productive interval {~ 6800' MD / 6067' TVD 134Z FSL & 1875' FWL, Sec. 4, T9N, R13W SM At total depth ~ 7643' MD / 6609' TVD 1208' FSL& 1244' FWL Sec. 4, T9N, R13W SM 12. Distance to nearest property line ~_, 7643' MD FSL of Sec. 9 6488' feet 13. Distance to nearest well Monopod A-16rd 1479' ~ 6067' TVD feet 16. To be completed for aeviated wells Kickoff depth: 3500 feet Maximum hole angle: 50 18. Casing program size Hole J Casing EXISTING ! 13~3/8" EXISTING t~5/8" 8-1/2" Specifications 5. Datum Elevation (DF or KB) KB 101 feet 6. Property Designation ADL 18731 7. Unit or property Name TRADING BAY STATE 10. Field and Pool TRADING BAY FIELD/ HEMLOCK 11. Type Bond (r, ee 20 AAC ~5.025) AK STATEWIDE OIL & GAS BOND Number U62-9269 8. Well number A-8RD2 9. Approximate spud date 6/1/97 14. Number of acres in property 384O Amount $200,000 15. Proposed depth (MD ~ 'i'VD) 7643' MD / 6609' TVD 17. Anticipated pressure (see 2o AAC 25.035 (e)(2)) Maximum surface 408 psig At total depU~ ('rVD) Setting Depth Top feet 2887 psig Quantity of cement Weight Grade Coupling Lencn MD TVD MD (include stage data) 61 J-55 BTC 1030' 45' 075' cemented to surface 451 34~5! J-55/N-80 3500'(KOP) Bottom 10~2 13208' ,,-,:,,ORIGINAL Junk (measured) L-80 cemented to surface ' :': see attached sche~ll~ BTC BTC 7596' Present well condition summary Total depth: measured true vertical 19. To be completed for Reddll, Re-entry, and Deepen Operations. 7403' feet 6554' feet Effective depth: measured 7340' feet true vertical 6485' feet Casing Length Size Cemented Measured depth True vertical depth Structural Conductor Surface 1030' 13-3/8" cemented to surface 1075' 106Z intermediate Production 3941' 9-5/8" cemented to surface 3986' 3208' Liner 3718' 7" 700 sx f/3684' - 7403' f/3376' - 6537' Perforation depth: measured see attached schematic true vertical see attached schematic 20. Attachments: Filing fee: x Property Plat: x BOP Sketch: x Diverter Sketch: Ddlling program: x Ddlling fluid program: x Time vs. depth plot: x Refraction analysis: Seabed report: 20 AAC 25.050 requirements: x 21. I herby certify that the foregoing is true and correct to the best of my knowledge: Signed: ;,~/'(~_c. (~i t r d:;: .... T'~le: Ddlling Manager Date: Commission Use Only Permit Number 77-d7 Conditions of approval Samples required: [ ] Yes .~ No Mud log required: [ ] Yes ~ No Hydrogen sulfide measures '~ Yes [ ] No Directional survey required ~)~J'Yes [ ] No Required working pressure forBOPE [ ]2M; [~[3M; [ ]5M; [ ] 10M; [ ] 15M Other: by order of I~rJgitl~! ,~l.q~'!(%~ ~, Commissioner the Commission Approved by David ~[L J~t,,tstot; , Form 10-401 Rev. 12-1-85 I APl number i ~ff See cover letter 50-7,~3- .2. o0 ~- ~_. '" //~ "- for other requirements Unocal Corporation Agricultural Products 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL( April 8, 1997 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 ORIGINAL Trading Bay Field Permit To Drill and Request for Administrative Approval Dear Chairman Johnston: Union Oil Company of California (Unocal), as Operator of the Monopod Platform, requests your approval to drill A-8rd2 and further requests Administrative Approval, pursuant to Rule 9, Conservation Order No. 93. In triplicate, is our application for Permit to Drill ADL 18731- A-8rd-2 (form 10- 401) pursuant to 20 AAC 25.005 and our check No. 2002315 in the amount of $100.00 as required under 20 AAC 25.005 (c)(1). Unocal intends to drill the ADL 18731-8rd-2 well from the Monopod Platform into the Hemlock Oil Pool of the Trading Bay Field for injection and pressure maintenance. The specific location, interval and depth are as follows: 1. Surface Location: 1612'FSL & 577'FEL, Sec. 4, T9N-R13W, SM. 2. Top of Prod. Interval: 1342'FSL & 1875'FWL, Sec. 4, T9N-R13W, SM. 3. Total Depth' 1208'FSL & 1244'FWL, Sec. 4, T9N-R13W, SM. If you require additional information, Please contact undersigned at (907) 263- 7600 or, Pat Ryan Drilling Dept. at 263-7864. Alaska Oil & Gas Cons. .6o.m_ft3'tsst~' Anch0rag~ q/truly yours, UNOCAL ) KB = 101' RKB from MSL Note Az Top offisl @ 3664' by tag. Tubing corroded & twisted w/multilxl~ strings side by side. Note B: Lost in hole 1/14/96. Gauge ring/spang/oil jam/stem/rope socket (22' operff21' closed). No wire lost in hole. Recovered 5' sinker bar & spangjars during 3/97 fishing job. I ?>,, / x 16/ 2~ 0', 8 ~0o 13 PBTD=7340' TD = 7439' Note C: Top of fill in robing ~ 6357' tagged 5/92 Note D: "PX" plug stuck '~x?' nipple @ 6773', unable to recover so left in place. Fish in place prong/pulling tooUspang/j arPoar/bar/rope socket. (17.75') TOF ~ 6790' sim. Note E: Fish in Plug/Running Tools/Spang/Bar/Rope Socket/Wire Grab/Ro Socket (23') TOF ~ 70' or wire in hole. Note F: Fill lagged ~ 7241' wlm in 10/91. MAX HOLE ANGLE = 40° W:\WORD60XMONOPODXMA8DIG4.DOC MONOPOD PLATFORM WELL # A-8RD PROPOSED PRE-REDRILL CONDITION 3/13/97 CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 61 J-55 0 1,075 9-5/8" 43.5 J-55/N-80 0 7,082 Section mill 9-5/8" 3,986 4,066 7" 29 N-80 BTC 3,684 7,403 2-7/8" 6.4 N-80 BTC 3664 JEWELRY DETAIL NO. DEPTH ITEM 6,803 2 3653' 3 4 3668' 5 4131' 6 4166' 7 4201' 8 4203' 9 4209' 10 4248' 11 6053' 12 6730' 13 6733' 14 6737' 15. 6773' 9-5/8"casing tested to 1500 psi. f/0 - 3653'. 9-5/8" EZSV Cement Retainer 450 sx cement plug f/3653' - 6053' 2-7/8" PSI-DSO GLM w/4.5" ecc. OD 2-7/8" PSI-DSO GLM w/4.5" ecc. OD Otis "XA" SSD Sleeve 3.75" x 2.313" Otis Strt Sit Locr w/11' 3.25" x 2.44" seal assby Otis "VST" Packer w/3.25" bore Otis 4.25" x 3.25" seal bore extension Otis "XA" SSD Sleeve 3.75" x 2.313" (closed Otis "XA" SSD Sleeve 3.75" x 2.313" (open) Otis Strt Slt Locr w/9' 4.00" x 2.44" seal assby Otis "BHW" Packer 4.00" bore ~ 6720' DIL Otis 5" x 4" seal bore extension Otis "32' landing nipple 3.25" x 2.313" 16 6803'-6804' Otis muleshoe re-entry guide Minimum ID = 2.313"; Otis X-nipples Note: All tubing & pups have 3.26" special clearence couplings PERFORATION DATA TOP BTM ZONE TOP 4400 4420 C-3 5300 4457 4480 C-6 5382 4500 4516 C-4 5792 4598 4612 C-5 5939 4698 4723 C-6 4792 4834 C-7 6855 5020 5040 47-5 5052 5073 47-5 5140 5150 48-5 5184 5200 48-7 BTM ZONE 5318 49-4 5387 C-2A 5798 C-5 6005 53-8 7318 HEMLOCK DRAWN BY: PAR 3/24/97 PERFORATION DATA SHEET PRIOR TO ABANDONMENT ADL 18731 MONOPOD A-8RD 1/20/97 TYONEK C & D MEASURED DEPTH (FEET) 4400-4420 4457-448O 4500-4516 4598-4612 4698-4723 4792-4834 5020-5040 5052-5073 5140-5150 5184-5200 5300-5318 5382-5387 5792-5798 5939-6005 TRUE VERTICAL DEPTH (FEET) 4032-4050 4084-4104 4122-4137 4209-4221 4297-4318 4377-4413 4571-4589 4599-4617 4675-4683 4713-4727 4814-4830 4885-4890 5232-5237 5351-5405 HEMLOCK MEASURED DEPTH (FEET) TRUE VERTICAL DEPTH (FEET) 6855-7318 6101-6467 MONOPOD PLATFORM A8 RD2 PROPOSED COMPLETION R.T. = 101' MSL 1. 3-1/2" 12.95# L-80 PH-6 TBG 0 - 6700'. 2. HES "XU" SLIDING SLEEVE ~ 6600'. 3. tIES "PHL" PACKER 6630'. 4. 3-1/2" 2.813" HES "X" NIPPLE ~ 6669'. 5.3-1/2" WLREG ~ 6700'. X 13-3/8" 61#j-55 CASING ~ 1075' 9-5/8" 43.5# J-55/N-80 CASING ~ 3500' KOP PBTD 6,592' TD 7,560' PROPOSED HEMLOCK PERFORATIONS 6800'-7443' 7" 29# L-80 CASING F/7,643' - SURF. FISH IN HOLE 6513 '-6592'. UNOCAL ) Trading Bay Field Well # A-8rd2 Depth vs. Time Summary 30OO I ~AFE -'-'Actual Optimum _ 4OOO 5000 6000 7000 8000 0 5 10 15 20 25 Time (Days) A8DRLAFE.XLS 3124/97/3:59 PM Unocal Alaska Business Unit Monopod Platform Well #A-8rd2 AFE # Prepared by: Pat Ryan Date:3/16/97 Revision #1 Estimate for P&A and Re-Drill UNOCAL ) No. Preliminary Procedure CUM Time (Days) 1 CIRC TO PROD & EST INJ RATE & PRES 0.1 2 SKID RIG F/A-27RD TO A-SRD 0.3 3 SET BPV 0.3 4 ND TREE 0.4 5 NU & TEST BOP 0.8 6 POOH LD 2870' KILL STRING 0.9 7 RIH W/RET. & SET ~ 3650' ON 5" DP 1.1 8 TEST ANNULUS TO 1500 PSI 1.1 9 SQZ PERFS 4400' - 6005' W/450 SX CMT 1.3 10 UNSTING & CLEAR DP 1.3 11 CHANGE WELL OVER TO MUD 1.5 12 POOH 1.5 13 WELL P&A'D AWAITING REDRILL 1.5 14 ND BOP 1.7 15 ND TBG SPOOL, NU CSG SPOOL 1.9 16 NU & TEST BOP 2.1 17 RIH W/WHIPSTOCK & SET ~ 3500' 2.5 18 MILL WINDOW ~ 3500' 3.5 19 POOH 3.5 20 RIH W/8-1/2" DRILLING ASSBY 3.7 21 DRILL 8-1/2" HOLE F/3500'-4000' 4.9 22 POOH F/BIT 5.0 23 RIH W/8-1/2" DRILLING ASSBY 5.1 24 DRILL 8-1/2" HOLE F/4000'-4500' 6.4 25 POOH F/BIT 6.5 26 RIH W/8-1/2" DRILLING ASSBY 6.6 27 DRILL 8-1/2" HOLE F/4500'-5000' 7.8 28 POOHF/BIT 8.0 29 RIH W/8-1/2" DRILLING ASSBY 8.1 30 DRILL 8-1/2" HOLE F/5000'-5500' 9.3 31 POOH F/BIT 9.5 32 RIH W/8-1/2" DRILLING ASSBY 9.6 33 DRILL 8-1/2" HOLE F/5500'-6000' 10.9 34 POOHF/BIT 11.0 35 RIH W/8-1/2" DRILLING ASSBY 11.2 36 DRILL 8-1/2" HOLE F/6000'-6500' 12.5 37 POOHF/BIT 12.6 38 RIH W/8-1/2" DRILLING ASSBY 12.8 39 DRILL 8-1/2" HOLE F/6500'-7000' 14.0 A8DRLAFE.XLS Page 1 of 2 3~24~97 Unocal Alaska Business Unit Monopod Platform Well #A-8rd2 AFE # Prepared by: Pat Ryan Date:3/16/97 Revision #1 Estimate for P&A and Re-Drill UNOCAL ) No. Preliminary Procedure CUM Time (Days) 40 POOH F/BIT 14.2 41 RIH W/8-1/2" DRILLING ASSBY 14.4 42 DRILL 8-1/2" HOLE F/7000'-7643' 16.1 43 POOH F/LOGS 16.3 44 RU WIRELINE 16.4 45 RUN TRIPLE COMBO F/7643' - 5945' 16.7 46 RD WIRELINE 16.8 47 RIH W/CLEANOUT ASSBY 17.0 48 CCH 17.0 49 POOH 17.2 50 RU CSG CREW 17.3 51 RIHW/7" CSGF/7643'- SURF 17.7 52 CCH 17.8 53 CMT7" CSGW/850 SX "G" CMT (425SXLEAD F/B 425 SXTAI 18.1 54 ND BOP 18.2 55 CUT CSG&NUTBG SPOOL 18.3 56 NU& TESTBOP 18.4 57 KIHW/B&S PU3-1/2" DP & CO TO ETD 18.7 58 TURN WELL OVER TO 3% KCL 19.0 59 POOH 19.2 60 RU WL & RUN CBL F/ETD - 3500' 19.4 61 RIH PU TCP GUNS & RTTS ON 5" DP 19.7 62 SPACEOUT GUNS ON DEPTH 19.8 63 FIRE GUNS & FLOW WELL 19.8 64 iREVERSE CIRC ENTRY 19.9 65 POOH LD TCP GUNS 20.3 66 RIH W/7" PKR PU 3-1/2" INJ STRING 20.8 67 CIRC PACKER FLUID 20.9 68 LAND TUBING 21.0 69 DROP BALL & SET & TEST PACKER 21.0 70 INSTALL BPV & ND BOP 21.2 71 NU & TEST TREE 21.4 72 PERFORM MIT AS PERAOGCC 21.5 A8DRLAFE.XLS Page 2 of 2 3/24/97 MONOPOD A-8RD2 BOP SCHEMATIC 3000 PSI WORKING PRESSURE ANNULAR BOP 13-5/8" 5000 PSI PIPE RAMS 13-5/8" 5000 PSI ,, CHOKE LINE TO MONOPOD CHOKE MANIFOLD HCR 5000 PSI MANUAL 5M GATE VALVE BLIND RAMS 13-5/8" 5000 PSI MUD CROSS MANUAL 5M GATE PIPE RAMS 13-5/8" 5000 PSI MANUAL 5M GATE VALVE 2,~ KILL LINE RISER 13-5/8" 5000 PSI FROM MUD PUMP & CEMENT UNIT DSA 13-5/8" 5M TO 13-5/8" 3M CIW 13-5/8" 3M CASING SPOOL ! .... TO 10" GAS 'BUSTER SHAKER c.u._o_F ~1 TO CHOKE PANEL 1101E: SWACO CIIOKES EACH HYDRAULICALLY ACTUATED VIA REMOTE. [-~1 ()W 1.13 - I MAI',IUAI_ TO BOPE SWACO CHOKE CHOKE MANIFOI. Unocal ?i,~'I'I;'OR~ RII 4-~/~" ~ :]-~/,", ,~, ~ RESERVE I~1'!' 480 BBl.. s I SHAKER,i TRIP TANK 20 BI3Ls TO MUD PITS MIXING PIT 50 BBl. s MIXING PIT IS A ONE LEVEL BELOW TIlE ACTIVE SYSIEM 1OO 13Bis 1OO BBl. i DESlL'I'EI'~ I SUCIION I'11' 100 BBI.s NOTE: TIlE SYSTEbl WILL BE EQUIPPED WlfII A DRILLING PiT LEVEL INDI£ATOR Wlfl l AUDIO & VISUAL WARNING DEVICES. EQUIPMENT LIST 1) RESERVE PII' 2) DEGASSER 3) (2) SI~AKE~S 4) PIT LEVEL INDICATOR (VISUAl. & AUDIO) 5) FLUID FLOW SENSOR 6) TRIP TANK 7) PIT AGITATORS B) DESILTER 9) MIXING PI'f IINOCAI. MONOPOD MUD Pl'r SCI'IEMATIC DRAWN: CLL APP'D: GSB" SCALE: NONE DATE: 04- 17-90 Monopod Platform Well # A-Srd2 Pressure Calculations Monopod Platform Well # A-8rd2 Trading Bay Field March 24, 1997 Hole Section 1 Depth Interval: 3500'-7643' 8-1/2" hole size 9-5/8" casing to 3500' Mud weight: Shoe depth (Top Sqz'd Perf): Est. fracture gradient of 9-5/8" shoe: Depth of next hole section (8-1/2"): BHP gradient: Gas gradient (assume worst case): 9.6 ppg=0.50 psi/fi 3500' MD/3208' TVD 0.80 psi/fi at KOP 7643' MD/6608' TVD 0.437 psi/ft 0.0 psi/fl Gas kick situation in wellbore. Assume 3/4 mud & 1/4 gas. MSP=BHP - Hydrostatic Pressure MSP=BHP - (3/4 mud + 1/4 gas) MSP=(6608'x.437 psi/fl) - ((.75(6608'x0.50 psi/fi)) + (.25(6608'x0.0 psi/fi))) MSP= 408 psi Therefore, the hydrostatic pressure at the 9-5/8" shoe (Hpsh) is the greatest when the gas (kick) bubble reaches the 9-5/8" shoe, if a constant BHP is applied. A conservative estimate would be the MSP plus the hydrostatic pressure at the 9-5/8" casing depth (Hpcsg). Hpsh= MSP + Hpcsg Hpsh= 408 + (3208'x0.50 psi/fi) HPsh= 2012 psi This (Hpsh = 2012 psi) is less than the fracture pressure at the same shoe (Fpsh) and thus adequate to handle the well kick scenario. Hpsh = 2012 psi < Fpsh = 0.80 psi/ft x 3208' = 2566 psi. The maximum surface at TD (MSPtd)pressure is calculated based on a normal pressure gradient to total depth (6608' TVD) and the hole full of gas (estimated 1 ppg gas density). MSPtd = (8.4ppgx.052x6608') - (lppgx.052x6608') = 2,543 psi File name: aSrd2cal.doc Well # Date Baker Platform Ba 28 10-10-93 Ba 30 10-24-93 Ba 30 10-28-93 Ba 28 11-17-93 Ba 29 12-17-94 Ba 29 12-29-93 Ba 30 01-27-94 Ba 28 03-01-94 Ba31 03-04-96 Ba31 03-09-96 Ba31 03-15-96 Grayling Platform G-40 01-24-90 G-40 Monopod Platform A-lrd 04-04-91 A-8rd 07-01-89 A-20rd 03-30-90 A-20rd 04-13-90 A-28rd 11-20-89 A-28rd 11-27-89 Granite Point Platform 11-13rd 02-14-92 51 08-07-92 51 07-28-92 51 08-25-92 50 05-27-92 50 06-04-92 50 06-27-92 Dillon Platform Leak Off Test (LOT) Data Cook Inlet, Alaska Revised March 15, 1996 Unocal Energy Resources Alaska Csg Size Shoe Depth Frac Grad. (TVD) (psi/tr.) EMW 24" 802' 0.94 18.10 24" 803' 0.83 15.90 18-5/8" 2011' 0.94 18.10 18-5/8" 2135' 0.75 14.50 18-5/8" 2054' 0.76 14.61 13-3/8" 5869' 0.85 16.33 13-3/8" 5467' 0.93 17.96 13-3/8" 3509' 0.75 14.40 18-5/8" 801' 0.82 15.68 13-3/8" 2076' 0.80 15.40 9-5/8" 5937' 1.02 19.70 (FIT) 16" 1926' 0.96 18.46 13-3/8" 4977' O. 86 16.54 9-5/8" 1132' 1.07 20.57 9-5/8" 3760' 1.02 19.61 13-3/8" 755' O. 95 18.20 9-5/8" 1931' 0.85 16.30 20" 240' 0.75 14.42 13-3/8" 1140' 0.97 18.65 9-5/8" 9966' 0.96 18.40 13-3/8" 3803' 1.00 19.20 18-5/8" 1010' 0.87 16.80 9-5/8" 9592' 1.05 20.20 18-5/8" 982' 0.91 17.50 13-3/8" 4208' 0.84 16.20 9-5/8" 9877' 0.93 17.90 1.12 0.82 NA 1.01 0.83 NA 1.02 0.80 16 04-22-94 18-5/8" 1131' 16 06-16-94 13-3/8" 3640' 16 07-04-94 9-5/8" 9469' 17 04-27-94 18-5/8" 1142' 17 05-01-94 13-3/8" 3560' 17 05- 9-5/8" 9213' 18 07-26-94 18-5/8" 1132' 18 08-01-94 13-3/8" 3988' 21.72 15.80 14.2 (FIT) 19.47 15.90 16.5 (FIT) 19.63 15.3 Leak Off Test (LOT) Data Page 2 Anna Platform 1 lrd 10-23-94 13-3/8" 2976' 1 lrd 11-11-94 9-5/8" 8750' 3rd 12/10/94 9-5/8" 7839' 50 2/8/95 18-5/8" 1160' 50 2/13/95 13-3/8" 4251 50 3/8/95 9-5/8" 9844' 51 1/29/95 18-5/8" 1130' 51 5/15/95 13-3/8" 3796' 51 6/3/95 9-5/8" 9842' 52 2/3/95 18-5/8" 1153' 52 3/27/95 13-3/8" 3940' 52 4/15/95 9-5/8" 9470' 7rd2 8/25/95 9-5/8" 4439' Notes: All fracture gradients reported have been corrected for air and water gaps. (FIT)-Formation Integrity Test 0.89 0.92 0.75 1.38 1.01 .86 1.36 .71 .88 1.41 .84 .91 .96 17.2 17.7 (FiT) 14.5 26.6 19.5 16.5 26.2 13.6 17.0 (FIT) 27.0 16.15 17.6 (FIT) 18.5 Filename Lotdata. doc WELL: MONOPOD A-8RD2 FIELD: MUD WT. I 9.6 PPG MUD WT. II 0 PPG MUD WT. III 0 PPG INTERVAL CASING DESIGN TRADING BAY FIELD CASING SIZE BOTTOM TO..__~P LENGTH WT..___~ I 7" 7643 45 7598 29 TVD 6609 45 DATE: 19-Jan-97 DESIGN BY: P.A. RYAN M.S.P. TENSION MINIMUM WEIGHT TOP OF STRENGTH DESCRIPTION W/O BF SECTION TENSION GRADE THREAD LBS LB._.~S 1000 LBS L-80 BTC 220342 220342 676 408 psi psi 0 psi TDF 3.07 COLLAPSE COLLAPSE PRESS @ RESIST. BOTTOM TENSION PSI_._~* PS~I 1890 7020 CD__EF 3.71 BURST MINIMUM PRESSURE YIELD PSI** PS~I 1487 8160 BDF 5.49 * Collapse pressure is calculated; Difference between two cement slurries (i.e. Avg of a 15,8 ppg (tail) & 14.2 ppg (lead) = 15 ppg, subtract a mud of 9.5 ppg = 5,5 ppg - .286 psi/ff gradient x'rVD of the casing string). ** Burst pressure is calculated; (BHP @ depth next csg X TVD next csg) X (0.5 half evacuated). File name: A3rd2csg.xls UNOCAL MONOPOD PLATFORM WELL #A-8RD2 DEPTH +/-7643' CASING SIZE HOLE SIZE 8-1/2" MUD TYPE F.I.W./GENERIC MUD #2 (with PHPA) ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels Fluid Loss API HPHT Fluid Loss 9.4 - 9.6 ppg 40 - 60 sec/qt 10 - 15 cps 10 - 25 # / 100 ft2 4- 12 8 20 File name: A8rd2mud.doc MONOPOD PLATFORM WELL # A-8RD 2 TRADING BAY FIELD ROTARY KELLY BUSHING (RKB) Elev. 101' DRILL DECK LEVEL Elev. 75' PRODUCTION DECK LEVEL Elev. 56' SEA LEVEL (MLW) Elev. 0' MUD LINE Elev. -62' 13-3/8" 61# J-55 BTC Surface Casing ~ 1075' 9-5/8" 43.5# J-55/N80 BTC Intermediate Casing ~ 3500' (KOP) 7" 29# L-80 BTC Production Casing ~ 7643' UNOCAL 50% I"IARATH ON ~,0% ADL 1759~ \\ xx UNOCAL 50% FORCENERG¥ ADL 18731 IONO?OD TRADING BAY FIELD UNOC.AL Structure : MONOPOD Platform Well : A-SRO #2 Field : Trading Bay Field Location : TBU, Cook Inlet, Alaska UNOCALe 2700- _ 3000- 3300- 3600 3900 -+- ~=~ 4200 c~ 4500 4800 5100 5400 I V 5700 6000 6300 6600 6900 25.04 25.98 27.20 KOP - Sidetrack Pt DLS: 3.00 dog per 100 ft EOC TARGET ANGLE 50 DEG <- West (feet) 3600 3450 3300 3150 3000 2850 2700 2550 2400 2250 2100 1950 1800 1650 1500 1350 1200 1050 I II II tI II II II tI II II II [ I I I I I I I I I I I I ~ ~/ 258 ,Azimuth // 3468' (To TD) ***Plane of Proposal*** AVERAGE ANGLE 28.01 DEG Begin Final Build 32.00 56.00 DLS: 4.00 deg per 100 fl 40.00 44.00 TARGET - T/ Hemlock (EOB) 48.00 A-SRd#2 Tgt# 1 21-Mar-97 TD i t t i i [ [ i i i t i i i i I i i i i l 900 1200 1500 1800 21 O0 2400 2700 3000 3300 3600 3900 Verficol Secfion (feet) -> Azimuth 258.00 with roference 0.00 N, 0.00 E from slot#12 30O WELL PROFILE DATA 150 0 0 150 "~ -..4- 300 I ¥ 45O 600 End at 8uitd/lurn 3856.63 28.01 258.00 3528.83 35.31 -1392.14 1354.36 End of Hold 6250.42 28.01 258.00 5642.31 -198.47 -2491.58 2478.38 Target A-SRd~2 Tgt#l 2 6800.2850.00 258.00 6067.00 -270.00 -2828.00 2822.32 End of Hold 7¢73.91 50.00 258,00 6500.00 -577,32 -3332.75 5338,34 ..... Point ..... MD Inc Oir I'VO North East V. Sect Dog/lO0 KOP 5500.00 24.40 280.98 3208.08 38.70 -1237.47 1202,57 0,00 3.00 O.O0 4.00 0.00 I.D. & End al Hold 7643.03 50.00 258.00 6608.71 -404.27-3459.47 3487.90 0.00 Created by jones For: Pat Ryan Date plotted : 25-kior-97 Created by jones Date ptotted : 25-Mar-97 Plot Reference is A-SRd#2 Version #1. Coordinates are in feet reference slot /~12.{ True VerticOt Depths ore reference wellhead.I I --- Boker Hughes NTEO --- I UNOCAL Slruclure : MONOPOD Plolform Well : ASRd2 Field : Trading Bay Field Location : TBU, Cook Inlet, Alaska UNOCAL ) 200 160 120 ¢0 :3 40 0 I 8O <- West (feet) 2040 2000 1960 1920 1880 1840 1BO0 1760 1720 1680 1640 1600 1560 1520 1480 1440 1400 1360 1320 )280 1240 1200 1160 iI i i i i i i i i i t t i i J L i i t t II ! i. I i i i i i J I ! ! l ~ i ! i ! t 200 160 120 4O 160 ~o00 160 200 200 8o I V 240 ~00 240 280 280 2040 2000 1960 1920 1880 1840 1800 1760 1720 1680 1640 1600 1.560 1520 1480 1440 1400 1360 1320 1280 1240 1200 1150 <- West (feet) Created by jones Dote plotted : 25-Mar-97 Plot Reference is A-8Rd#2 Version ~1. Coordinates ore in feet reference slot ~12.~ True Vertical Depths ore reference wellhead./ / --- Baker Hughes INTEQ --- / UNOCAL Structure: MONOPOD PlatformWell : A8Rd2 Field : Trading Bay Field Location : TBU, Cook Inlel, Alaska UNOCAL ) <- Wesf (feel) ~o ~o ~o ~oo 2~o ~o ~o ~o ~oo 2~o ~o ~8o ~o ~oo ~o ~o ~o~o ~o~o ~ooo ~o ~o ~o 160 [ I I I I I I I I I I I I I I I I I I [ I I I I I I I [ I I I I I I I I I I I I I I I 120 160 120 80 40 40 0 C' 160 80? 120 ~ I 160 ............. '"~0 200 200 ....... 0¥00 O0 240 ~0° 240 280 280 ,~20 520 ~ i ~ i i 2720 2680 2640 2600 2560 2520 2480 2440 2400 2560 2520 2280 2240 2200 2160 2120 2080 2040 2000 1960 1920 1880 18,40 <- Wesf (feet) Created by jones Dote plotted : 25-Mar-g7 Plat Reference is A-SRdJ~2 Version Jr1. ICoordinates are in feet reference stat ~12. I True Vertical Depths are reference wellhead. ---- Baker Hughes INTEQ --- UNOCAL Slruclure : MONOPOD Platform Well : ASRd2 Field: Trading Bay Field Location: TBU, Cook Inlet, Alaska UNOCAL ) 40 80 120 16O 200 C" 240 0 (-/') 280 I ¥ 320 360 400 440 480 <- West (feet) 3480 3440 3400 3360 3320 3280 3240 3200 3160 3120 3080 3040 3000 2960 2920 2880 2840 2800 2760 2720 2680 2640 I II II II II II II II [[ II II [I I[ II II 3480 3440 5400 3360 3320 3280 3240 3200 3160 3120 3080 3040 3000 2960 2920 2880 2840 2800 2760 2720 2680 2640 <- West (feet) 40 120 160 20O 0 240 280 v 32O 360 400 440 480 UNOCAL MONOPOD Platform A-SRD slot #12 Trading Bay Field TBU, Cook Inlet, Alaska PROPOSAL LISTING INCLUDING POSITION UNCERTAINTIES by Baker Hughes INTEQ Your ref : A-SRd#2 Version #1 Our ref : prop2137 License : Date printed : 25-Mar-97 Date created : 21-Mar-97 Last revised : 25-Mar-97 Field is centred on n60 53 32.779,w151 34 32.077 Structure is centred on n60 53 32.779,w151 34 32.077 Slot location is n60 53 48.653,w151 34 43.740 Slot Grid coordinates are N 2523125.883, E 218859.619 Slot local coordinates are 1612.00 N 577.00 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North UNOCAL MONOPOD Platform,A-8RD Trading Bay Field,TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : A-8Rd#2 Version #1 Last revised : 25-Mar-97 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOft Sect 3500.00 24.40 280.98 3208.08 38.70 N 1237.47 W 0.00 1202.37 KOP - Sidetrack Pt 3600.00 25.04 273.97 3298.94 44.10 N 1278.87 W 3.00 1241.73 3700.00 25.98 267.35 3389.21 44.55 N 1321.87 ~ 3.00 1283.70 3800.00 27.20 261.23 3478.65 40.05 N 13~.35 W 3.00 1328.14 3856.63 28.01 258.00 3528.83 35.31N 1392.14 ~ 3.00 1354.36 EOC 4000.00 28.01 258.00 3655.41 21.31 N 1457.99 W 0.00 1421.68 4500.00 28.01 258.00 4096.87 27.52 S 1687.64 W 0.00 1656.46 5000.00 28.01 258.00 4538.32 76.35 S 1917.28 W 0.00 1891.24 5500.00 28.01 258.00 4979.77 125.18 S 2146.92 W 0.00 2126.01 6000.00 28.01 258.00 5421.22 174.01 S 2376.57 ~ 0.00 2360.79 6250.42 28.01 258.00 5642.31 198.47 S 2491.58 W 0.00 2478.38 6350.28 32.00 258.00 5728.78 208.85 S 2540.42 W 4.00 2528.30 6450.28 36.00 258.00 5811.66 220.48 S 2595.10 W 4.00 2584.21 6550.28 40.00 258.00 5890.45 233.28 S 2655.31 W 4.00 2645.76 ~50.28 44.00 258.00 5964.75 247.19 S 2720.74 ~ 4.00 2712.66 6750.28 48.00 258.00 6034.20 262.15 S 2791.09 W 4.00 2784.58 (3800.28 50.00 258.00 6067.00 270.00 S 2828.00 W 4.00 2822.32 6800.29 50.00 258.00 6067.01 270.00 S 2828.01 ~ 0.00 2822.32 7000.00 50.00 258.00 6195.38 301.82 S 2977.65 W 0.00 2975.31 7473.91 50.00 258.00 6500.00 377.32 S 3332.75 ~ 0.00 3338.34 7500.00 50.00 258.00 6516.77 381.48 S 3352.30 ~ 0.00 3358.33 7643.03 50.00 258.00 6608.71 404.27 S 3459.47 ~ 0.00 3467.90 TD Begin Final Build A-SRd#2 Tgt#1 21-Mar-97 TARGET - T/ Hemlock (EOB) All data is in feet unless otherwise stated. Coordinates from slot #12 and TVD from wellhead (101.00 Ft above mean sea level). Bottom hole distance is 3483.01 on azimuth 263.33 degrees from wellhead. Total Dogleg for wellpath is 32.69 degrees. Vertical section is from wellhead on azimuth 258.00 degrees. Calculation uses the minin~Jm curvature method. Presented by Baker Hughes INTEQ UNOCAL MONOPOD Platform,A-SRD Trading Bay Field, TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : A-8Rd~2 Version #1 Last revised : 25-Mar-97 Comments in wetlpath MD TVD RectanguLar Coords. Comment 3500.00 3208.08 38.70 N 1237.47 W KOP - Sidetrack Pt 3856.63 3528.83 35.31N 1392.14 W EOC 6250.42 56Y,2.31 198.47 S 2491.58 W Begin Final Build 6800.28 6067.00 270.00 S 2828.00 W A-SRd#2 Tgt#1 21-Mar-97 6~)00.29 6067.01 270.00 S 2828.01W TARGET - T/ Hemlock (EOB) 7643.03 6608.71 404.27 S 3459.47 ~ TD Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing n/a 3208.08 38.70N 1237.471~ 3500.00 3208.08 38.70N 1237.47W 9 5/8" Casing n/a 3208.08 38.70N 1237.47t~ 7643.03 ~08.71 404.27S 3459.47W 7" Casing Targets associated with this wellpath Target nam~ Geographic Location T.V.D. Rectangular Coordinates Revised A-SRd#2 Tgt#1 21-Mar 6067.00 270.00S 2828.00W 21-Mar-97 UNOCAL MONOPO0 Platform,A-SRD Trading Bay Field,TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : A-8Rd#2 Version #1 Last revised : 25-Mar-97 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOft Sect 3500.00 24.40 280.98 3208.08 1650.70 N 1814.47 W 0.00 1202.37 KOP - Sidetrack Pt 3600.00 25.04 273.97 3298.94 1656.10 N 1855.87 W 3.00 1241.73 3700.00 25.98 267.35 3389.21 1656.55 N 1898.87 W 3.00 1283.70 3800,00 27.20 261.23 3478.65 1652.05 N 1943.35 W 3.00 1328.14 3856.63 28.01 258.00 3528.83 1647.31N 1969.14 W 3.00 1354.36 EOC 4000.00 28.01 258.00 3655.41 1633.31 N 2034.99 W 0.00 1421.68 4500.00 28.01 258.00 4096.87 1584.48 N 2264.64 W 0.00 1656.46 5000.00 28.01 258.00 4538.32 1535.65 N 2494.28 W 0.00 1891.24 5500.00 28.01 258.00 4979.77 1486.82 N 2723.92 W 0.00 2126.01 6000.00 28.01 258.00 5421.22 1437.9(2 N 2953.57 W 0.00 2360.79 6250.42 28.01 258.00 5642.31 1413.53 N 3068.58 W 0.00 2478.38 6350.28 32.00 258.00 5728.78 1403.15 N 3117.42 W 4.00 2528.30 6450.28 36.00 258.00 5811.66 1391.52 N 3172.10 W 4.00 2584.21 6550.28 40.00 258.00 5890.45 1378.72 N 3232.31 W 4.00 2645.76 6650.28 44.00 258.00 5964.75 1364.81 N 3297.74 W 4.00 2712.66 6750.28 48.00 258.00 6034.20 1349.85 N 3368.09 W 4.00 2784.58 6800.28 50.00 258.00 6067.00 1342.00 N 3405.00 W 4.00 2822.32 6800.29 50.00 258.00 6067.01 1342.00 N 3405.01 W 0.00 2822.32 7000.00 50.00 258.00 6195.38 1310.18 N 3554.65 W 0.00 2975.31 7473.91 50.00 258.00 6500.00 1234.68 N 3909.75 W 0.00 3338.34 7500.00 50.00 258.00 6516.77 1230.52 N 3929.30 W 0.00 3358.33 7643.03 50.00 258.00 6608.71 1207.73 N 4036.47 W 0.00 3467.90 TD Begin Final Build A-8Rd#2 Tgt#1 21-Mar-97 TARGET - T/ Hemlock (EOB) All data is in feet unless otherwise stated. Coordinates from SE Corner of Sec. 4, T9N, R13W and TVD from wellhead (101.00 Ft above mean sea level). Bottom hole distance is 3483.01 on azimuth 263.33 degrees from wellhead. Total Dogleg for wellpath is 32,69 degrees. Vertical section is from wellhead on azimuth 258.00 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL MONOPO0 P[atform,A-8RD Trading Bay Field,TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : A-SRd#2 Version #1 Last revised : 25-Mar-97 Comments in wellpath MD TVD Rectangular Coords. Coe~nent 3500.00 3208.08 1650.70 N 1814.47 ~ KOP - Sidetrack Pt 3856.63 3528.83 1647.31N 1969.14 ~ EOC 6250.42 5642.31 1413.53 N 3068.58 ~ Begin Final Build 6800.28 6067.00 1342.00 N 3405.00 g A-SRd~2 Tgt#1 21-Mar-97 6800.29 6067.01 1342.00 N 3405.01 ~ TARGET - T/ Hemlock (EOB) 7643.03 6608.71 1207.73 N 4036.47 ~ TD Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing n/a 3208.08 1650.70N 1814.4714 3500,00 3208.08 1650,70N 1814.4714 9 5/8" Casing n/a 3208.08 1650.70N 1814.4714 7643,03 6608.71 1207.73N 4036.4714 7" Casing Targets associated with this wellpath Target name Geographic Location T.V.D. Rectangular Coordinates Revised A-SRd~2 Tgt#1 21-Mar 6067.00 1342,00N 3405.00W 21-Mar-97 UNOCAL MONOPOD Platform, A-8RD Trading Bay Field,TBU, Cook Inlet, Alaska Measured Inclin. Azimuth True Vert R E C T Depth Degrees Degrees Depth C 0 0 R 3500.00 24.40 280.98 3208.08 38.70 N 3600.00 25.04 273.97 3298.94 44.10 N 3700,00 25.98 267.35 3389.21 44.55 N 3800,00 27.20 261.23 3478.65 40.05 N 3856,63 28.01 258.00 3528.83 35.31 N 4000,00 28.01 258.00 3655.41 21.31 N 4500,00 28.01 258.00 4096.87 27.52 S 5000,00 28.01 258.00 4538.32 76.35 S 5500,00 28.01 258.00 4979.77' 125.18 S 6000.00 28.01 258.00 5421,22 174.01 S 6250.42 28.01 258.00 5642.31 198.47 S 6350.28 32.00 258.00 5728.78 208.85 S 6450.28 36.00 258.00 5811.66 220.48 S 6550.28 40.00 258.00 5890.45 233.28 S 6650.28 44.00 258.00 5964.75 247.19 S 6750.28 48.00 258.00 6034.20 262.15 S 6800,28 50.00 258.00 6067.00 270.00 S 6800.29 50.00 258.00 6067.01 270.00 S 7000,00 50.00 258.00 6195.38 301.82 S 7473.91 50.00 258.00 6500.00 377.32 S 7500,00 50.00 258.00 6516.77 381.48 S 7643,03 50.00 258.00 6608.71 404.27 S ANG DIN ULAR ATES 1237.47 1278.87 1321.87 1366.35 1392.14 PROPOSAL LISTING Page 1 Your ref : A-SRd#2 Version #1 Last revised : 25-Mar-97 Vert Sect Ellipse Semi Axes Minor Major Minor Vert. Azi. 1202.37 36.80 16.58 8.95 272.01 1241.73 36.82 16.58 8.95 272.01 1283.70 36.86 16.59 8.96 272.01 1328.14 36.93 16.62 8.98 271.98 1354.36 36.99 16.64 9.00 271.95 1457.99 W 1421.68 37.17 16.71 9.05 271.83 1687.64 W 1656.46 38.32 17.18 9.35 271,05 1917.28 W 1891.24 40.20 17.92 9.85 269.87 2146.92 W 2126.01 42.71 18.88 10.50 260.50 2376.57 W 2360.79 45.77 20.01 11.28 267.12 2491.58 2540.42 2595.10 2655.31 2720.74 W 2478.38 47.48 20.63 11.72 2~.47 W 2528.30 48.32 20.90 11.92 266.17 W 2584.21 49.34 21.18 12.14 265.82 W 2645.76 50.56 21.47 12.39 265.42 W 2712.66 52.00 21.77 12.67 264.99 2791.09 W 2784.58 53.72 22.07 12.98 264,52 2828.00 W 2822.32 54.66 22.22 13.14 264.28 2828.01 W 2822.32 54.66 22.22 13.14 264.28 2977.65 W 2975.31 58.59 22.82 13.81 263.41 3332.75 W 3338.34 68.75 24.25 15.53 261.87 3352.30 W 3358.33 69.34 24.33 15.63 261.80 3459.47 W 3467.90 72.59 24.76 16.17 261.46 POSITION UNCERTAINTY SUMMARY Depth Position Uncertainty From To Survey Tool Error Model Major Minor Vert. 0 3500 Level Rotor Gyro INTEQ 36.80 16.58 8.95 3500 7643 NaviTrak (DAS) Mag Corrected INTEQ 72.59 24.76 16.17 1. Ellipse dimensions are half axis. 2. Casing dimensions are not included. 3. Ellipses are calculated on 2.00 standard deviations. 4. Uncer.tainty calculations start at drill depth zero. 5. Surface position uncertainty is not included. 6. Where two surveys are tied together the errors of one are considered to have a random relationship to the corresponding errors of the other. 7. Detailed description of the INTEQ error models can be found in the Ec*Trak manual, All data is in feet unless otherwise stated. Coordinates from slot #12 and TVD from wellhead (101.00 Ft above mean sea level). Bottom hole distance is 3483,01 on azimuth 263.33 degrees from wellhead. Vertical section is from wellhead on azimuth 258.00 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL MONOPOD Platform,A-8RD Trading Bay Field,TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : A-SRd#2 Version #1 Last revised : 25-Mar-97 Comments in wellpath MD TVD Rectangular Coords. Comment 3500.00 3208.08 38.70 N 1237.47 W KOP - Sidetrack Pt 3856.63 3528.83 35.31N 1392.14 W EOC 6250.42 5642.31 198.47 $ 2491.58 ~ Begin Final Build 6800.28 6067.00 270.00 $ 2828.00 ~ A-SRd#2 Tgt#1 21-Mar-97 6800.29 6067.01 270.00 $ 2828.01 ~ TARGET - T/ Hemlock (EOB) 7643.03 6608.71 404.27 S 3459.47 ~ TD Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing n/a 3208.08 38.70N 1237.47~ 3500.00 3208.08 38.70N 1237.47~ 9 5/8" Casing n/a 3208.08 38.70N 1237.47~ 7643.03 6608.71 404.27S 3459.47~ 7" Casing Targets associated with this wellpath Target name Geographic Location T.V.D. Rectangular Coordinates Revised A-SRd~2 Tgt#1 21-Mar 6067.00 270.00S 2828.00W 21-Mar-97 Tradi Measured Depth 3500.00 3600.00 3700.00 3800.00 3856.63 4000.00 4500.00 5000.00 5500.O0 6000.00 6250.42 6350.28 6450.28 6550.28 6650.28 6750.28 6800.28 6800.29 7000.00 7473.91 7500.00 7643.03 UNOCAL MONOPOD Platform,A-SRD ng Bay Field,TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : A-SRd#2 Version #1 Last revised : 25-Mar-97 Inclin Azimuth True Vert R E C T A N G U L A R Dogleg Vert G R I D C 0 0 R D S Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOft Sect Easting Northing 24.40 280.98 3208.08 38.70N 1237.47~ 0.00 1202.37 217623.44 2523194.30 25.04 273.9? 3298.94 44.10N 1278.87~ 3.00 1241.73 217582.19 2523200.69 25.98 267.35 3389.21 44.55N 1321.87~ 3.00 1283.70 217539.22 2523202.18 27.20 261.23 3478.65 40.05N 1366.35W 3.00 1328.14 217494.64 2523198.75 28.01 258.00 3528.83 35.31N 1392.14W 3.00 1354.36 217468.74 2523194.63 28.01 258.00 3655.41 21.31N 1457.99~ 0.00 1421.68 217402.57 2523182.21 28.01 258.00 4096.87 27.52S 1687.64~ 0.00 1656.46 217171.83 2523138.92 28.01 258.00 4538.32 76.35S 1917.28~ 0.00 1891.24 216941.08 2523095.62 28.01 258.00 4979.77 125.18S 2146.92W 0.00 2126.01 216710.33 2523052.32 28.01 258.00 5421.22 174.01S 2376.57~ 0.00 2360.79 216479.58 2523009.02 28.01 258.00 5642.31 198.47S 2491.58~ 0.00 2478.38 216364.01 2522987.34 32.00 258.00 5728.78 208.85S 2540.42W 4.00 2528.30 216314.95 2522978.13 36.00 258.00 5811.66 220.48S 2595.10~ 4.00 2584.21 216260.00 2522967.82 40.00 258.00 5890.45 233.28S 2655.31~ 4.00 2645.76 216199.50 2522956.47 44.00 258.00 5964.75 247.19S 2720.74~ 4.00 2712.66 216133.75 2522944.13 48.00 258.00 6034.20 262.15S 2791.09~ 4.00 2784.58 216063.06 2522930.87 50.00 258.00 6067.00 270.00S 2828,00W 4.00 2822.32 216025.98 2522923.91 50.00 258.00 6067.01 270.00S 2828,01~ 0.00 2822.32 216025.97 2522923.90 50.00 258.00 6195.38 301.82S 2977.65~ 0.00 2975.31 215875.61 2522895.69 50.00 258.00 6500.00 377.32S 3332,75~ 0.00 3338.34 215518.81 2522828.74 50.00 258.00 6516.77 381.485 3352.30~ 0.00 3358.33 215499.16 2522825.05 50.00 258.00 6608.71 404.27S 3459.47~ 0.00 3467.90 215391.47 2522804.85 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #12 and TVD from wellhead (101.00 Ft above mean sea level). Bottom hole distance is 3483.01 on azimuth 263.33 degrees from wellhead. Total Dogle9 for wellpath is 32.69 degrees. Vertical section is from wellhead on azimuth 258.00 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ UNOCAL MONOPO0 Platform,A-SRD Trading Bay Field,TBU, Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : A-8Rd#2 Version #1 Last revised : 25-Mar-97 Comments in weLlpath MD TVD Rectangular Coords. Corm~ent 3500.00 3208.08 38.?0N 1237.47g KOP - Sidetrack Pt 3856.63 3528.83 35.31N 1392.14W EOC 6250.42 5642.31 198.47S 2491.58W Begin Final Build 6800.28 6067.00 270.00S 2828.00~ A-SRd~2 Tgt#1 21-Mar-97 6800.29 6067.01 270.00S 2828.01~ TARGET - T/ Hemlock (EOB) 7643.03 6608.71 404.27S 3459.47~ TD Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD 8ot TVD Rectangular Coords. Casing n/a 3208.08 38.?0N 1237.47~ 3500.00 3208.08 38.70N 1237.47~1 9 5/8" Casing n/a 3208.08 38.70N 1237.47~ 7643.03 6608.71 404.27S 3459.47~ 7" Casing Targets associated with this wellpath Target name Geographic Location T.V.D. Rectangular Coordinates Revised A-SRd~2 Tgt#1 21-Mar 6067.00 270.00S 2828.00~ 21-Mar-97 UNOCAL MONOPO0 Platform A8Rd2 slot #12 Trading Bay Field TBU, Cook Inlet, Alaska 3-D M I N I M U M D I S T A N C E C L E A R A N C E R E P O R T by Baker Hughes INTEQ Your ref : A-8Rd#2 Version #1 Our ref : prop2137 License : Date printed : 25-Mar-97 Date created : 21-Mar-97 Last revised : 25-Mar-97 Fietd is centred on n60 53 32.779,w151 34 32.07/ Structure is centred on n60 53 32.779,w151 34 32.077 Slot location is n60 53 48.653,w151 34 43.740 Slot Grid coordinates are N 2523125.883, E 218859.619 Slot local coordinates are 1612.00 N 57/.00 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North Report is limited to clearances less than 200 feet DECREASING CLEARANCES of tess than 1000 feet are indicated by an asterisk, e.g. 487.4* Object we[[path Closest approach with 3-D Minimum Distance method Last revised Distance M.D. )r-94 2259.8 350D.0 )r-94 2244.6 3500.0 )r-94 529.5 3500.0 )r-94 1460.7 3500.0 )r-94 2063.0 3500.0 )r-94 1085.6 3500.0 Dr-94 1085.6 3500.0 ~r-94 1085.6 3500.0 ~r-94 1213.6 3500.0 ~r-94 1065.5 3500.0 ~r-94 1065.5 3500.0 )r-94 1~.6 3500.0 )r-94 1730.3 3500.0 )r-94 965.0 3500.0 )r-94 103.4 3500.0 )r-94 411.1 3500.0 )r-94 994.7 3500.0 )r-94 1545.0 3500.0 )r-94 1545.0 3500.0 )r-94 1239.7 3500.0 ~r-94 918.7 3500.0 ar-94 1127.1 3500.0 ar-94 1116.4 3500.0 ar-94 1484.0 3500.0 ~r-94 303.2 7338.0 GMS/MSS <O-1600-7224'>,,A-3RD,MONOPOD Ptatform 21-A MSS <486-11637'>,,A-3,MONOPOD Platform 21-A PGM$/MSS <O-900-?073'>,,A-lO,MONOPOD Platform 21-A MSS <0-8795'>,,A-26,MONOPO0 Platform 21-A MSS <0-11000'>,,A-18,MONOPO0 Platform 21-A MSS <5544-7101'>,,A-5 RD#2,MONOPO0 Platform 21-A GMS/MSS <0-1650-7646'>,,A-5,MONOPOD Platform 21-A MSS <6106-7506'>~,A-5 RD#1,MONOPOD Platform 21-A GMS/MSS <0-4750-7530'>,,A-23,MONOPOD Platform 21-A A-29 RD <GMS 0-~00'>,,A-29 Rd,MONOPOD P[atfor 21-A A-29 Orig. <MSS 5398-85~7'>,,A-29,MONOPO0 Plat 21-A PMS$ <147'2-6120'>~,A-20 RD#2,MONOPOO Platform 21-A GMS <0-11926'>~,A-20,MONOPO0 Platform 21-A GMS <0-7360'>,,A-30,MONOPO0 Platform 21-A PGMS/MSS <0-4000-7460'>,,A-16,MONOPOD Platform 21-A GSS/PMSS <1030-1932-6844'>~,A-16RD,MONOPO0 Pla 21-A MSS <O-6498'>,,A-6,MONOPO0 Platform 21-A! MSS <O-8310'>,,A-21~MONOPO0 Platform 21-A MSS <7259-8431'>,,A-21RD,MONOPOD Platform 21-A GMS/MSS <O-4900-9066'>,,A-22,MONOPOD Platform 21-A GMS/MSS cO-6500-8070'>,,A-14,MONOPO0 Platform 21-A GMS <O-5450'>,,A-24RD,MONOPOD Platform 21-A MSS <479-9150'>,,A-24,MONOPO0 Platform 21-A MSS <0-6340'>,,A~15,MONOPO0 Platform 21-A MSS <0-7292'>,,A-13,MONOPOD Platform 21-A Diverging from M.D. 3500.0 3500.0 5652.0 3500.0 3500.0 3500.0 6108.0 3500.0 7419.0 7643.0 3500.0 4683.0 3500.0 7239.0 7000.0 3500.0 3500.0 3500.0 7643.0 7643.0 7643.0 3500.0 7643.0 3500.0 7338.0 MSS <O-10180'>,0A-11,MONOP, .,latform GMS <O-3300'>,,A-4,MONOPO0 Platform MSS <O-6407'>,,A-7,MONOPOD Platform PGSS/PMSS <1100-1273-6592'>,,A-1Rd,MONOPO0 P[ A-1Comp.<PGM$/MSS O-6509'>,,A-1,MONOPOD Platf MSS <395-6896'>,,A-9,MOgOPO0 Platform GMS <O-7000'>,,A-9RD,MOflOPOD Platform MSS <1030-7358'>,,A-12,MONOPOD Platform PGMS/M$S <O-lO00-8473'>,,A-12RD,MONOPOD Platfo PGMS <O-7350'>,,A-19RD,MONOPO0 Platform MSS <4379-9259'>,,A-19,MONOPO0 Platform GMS <O-6750'>,,A-32,MONOPOD Platform GMS <O-5100'>,,A-17RD,MONOPO0 Platform MSS <2656-8535'>,,A-17,MONOPO0 P[atform PGMS <O-8650'>,,A-25RD,MONOPOD Platform MSS <1415-7796'>,,A-25,MONOPOD Platform MSS <O-6669'>,,A-2,MONOPO0 Platform GMS <250-6432'>,,A-28,MONOPOD Platform PGMS <O-9784'>,,A-28RD,MONOPO0 Platform GMS <O-8825'>,,A-27,MONOPO0 Platform PGMS <O~4498'>,0A-8,MONOPOD Platform PGSS/PMSS <3945-4164-?430'>,,A-8RD,MONOPOD Pla 21-A ~r-94 21-A ~r-94 21-A ~r-94 21-A ~r-94 21 -Apr-94 21 -A~r-94 21 -Aar-94 21 -Aar-94 21 -Aar-94 21 -A ar-94 21-Aar-94 21-Aar-94 21-Aar-94 21-A~r-94 21-A~r-94 21 -A ~r-94 21-A~r-94 21 -A ~r-94 21 -A!~r-94 20- J un- 96 21 -Mar-97 21 -Mar-97 984.3 1743.5 1317.8 1334.2 1483.4 1649.4 627.1 374.8 648.9 607.7 607.7 754.2 1050.2 1068.1 682.5 718.6 516.2 1962.7 2079.6 1852.0 0.0 0.0 3500. 3500.0 3500.0 3500.0 3500.0 3500.0 5493.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 3500.0 5493.0 3500.0 7643.0 7383.0 7643.0 3500.0 3500.0 7629.0 7643.0 7643.0 3500.0 3500.0 3500.0 3500.0 3500.0 5100.0 UNOCAL MONOPOD Platform,A8Rd2 Trading Bay Field,TBU, Cook Inlet, Alaska CLEARANCE LISTING Page 2 Your ref : A-SRd#2 Version #1 Last revised : 25-Mar-97 Reference we[lpath Object wellpath : PGMS/MSS <O-4000-7460'>,,A-16,MONOPO0 Platform M.D.T.V.D. Horiz Min'm TCyl Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 3610.0 3720.9 38~3.1 3946.3 4059.6 3308.0 3408.0 3508.0 3608.0 3708.0 44.4N 1283.1W 3604.5 3244.8 21.4N 1379.5W 256.6 117.5 118.7 44.0N 1331.1W 3709.8 3332.5 16.4N 1437.714 255.5 133.6 135.1 37.5N 1381.4~ 3817.2 3419.9 11.5N 1499.8g 257.6 149.9 151.6 26.6N 1433.3~ 3924.4 3505.4 6.3N 1564.3W 261.2 167.6 170.3 15.5N 1485.3W 4031.9 3589.4 0.SN 1631.2W 264.2 188.5 192.1 All data is in fee~ unless otherwise stated. Casing dimensions are not included. Coordinates from slot #12 and TVD frea~wellheacl ¢~01.00 Ft above mean sea [eve[). Total Dogleg for we[[path is 0.00 degrees. Vertical section is from we[lheeel~n azimuth 258.00 degrees. Calculation uses the minimua curvature method. Presented by Baker Hughes [NTEQ UNOCAL MONOPO0 P[atform,ABRd2 Trading Bay FieLd,TBU, Cook Inlet, ALaska CLEARANCE LISTING Page 3 Your ref : A-BRet#2 Version #1 Last revised : 25-Mar-97 Reference we[tpath Object we[lpath : PGMS <O-4498'>,,A-8,MONOPO0 Platform M.D. T.V.D. Horiz Min'm TCyL Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 3610.0 3308.0 3720.9 3408.0 3833.1 3508.0 3946.3 3608.0 4059.6 3708.0 44.4N 128~.1W 3609.9 3308.1 47.5N 1282.2W 16.3 3.3 3.3 44.0N 1331.1g 3720.4 3408.7 56.8N 1326.9~ 18.1 13.4 13,5 37.5N 1381.4~ 3831.0 3509.4 66.4N 1371.4~ 18.9 30.6 31.2 26.6N 1433.3W 3941.6 3610.5 76.9N 1415.4~ 19.6 53.5 54,6 15.5N 1485.3~ 4052.4 3711.8 87.5N 1458.9~ 20.1 76.8 78.5 4172.8 3808.0 4286.1 3908.0 4399.3 4008.0 4512.6 4108.0 4.4N 1537.4W 4162.9 3813.0 98.2N 1502.1W 20.6 100.3 102.6 6.6S 1589.4W 4273.3 3914.0 109.1N 1545.0~ 21.0 124.1 127.0 17.?S 1641.4~ 4383.2 4014.8 120.5N 1587.4~ 21.4 148.5 152.1 28.8S 1693.4W 4493.9 4116.3 132.1N 1630.2~ 21.5 173.0 All data is in feet unless otherwise stated. Casing dimensions are not included, Coordinates from slot #12 and TVD from wellhead (101.00 Ft above mean sea level). Total Dogleg for we[lpath is 0.00 degrees. Vertical section is from wellhead on azimuth 258.00 degrees. Calculation uses the minimL~n curvature method. Presented by Baker Hughes INTEQ UNOCAL HONOPO0 Ptatform,A8Rd2 Trading Bay Fietd,TBU, Cook Inlet, Alaska CLEARANCE LISTING Page 4 Your ref : A-8Rd#2 Version #1 Last revised : 25-Hat-97 Reference we[[path Object weLLpath : PGSS/PHSS <3945-4164-7430'>,,A-8RD,HONOPO0 Platform M.D. T.V.D. Rect Coordinates Horiz Hin'm TCyt H.D. T.V.D. Rect Coordinates Bearing Dist Dist 3610.0 3308.0 44.4N 1283.1W 3720.9 3408.0 44.0N 1331.1W 3833.1 3508.0 37.5N 1381.4W 3946.3 3608.0 26.6N 1433.3~ 4059.6 3708.0 15.5N 1485.3W 3609.9 3308.1 47.5N 1282.2~ 16.3 3.3 3.3 3720.4 3408.7 56.8N 1326.914 18.1 13.4 13.5 3831.0 3509.4 66.4N 1371.4~ 18.9 30.6 31.2 3941.6 3610.5 76.9N 1415.4W 19.6 53.5 54.6 4053.5 3713.0 87.0N 1459.1W 20.2 76.3 77.8 4172.8 3808.0 4286.1 3908,0 4399.3 4008.0 4512.6 4108.0 4625.9 4208,0 4.4N 1537.4~ 6.6S 1589.4~ 17.7S 1641.4~ 28.8S 1693.4W 39.85 1745.4W 4169.6 3819.9 93.2N 1503.714 20.7 95.7 96.7 4286.7 3928.2 93.6N 1548.3~ 22.3 110.2 110.8 4406.7 4037.9 87.9N 1596.6~ 23.0 118.6 118.7 4525.1 4144.2 76.6N 1647.4~ 23.6 120.6 120,6 4645.0 4249.8 59.7N 1701.714 23.7 116.5' 116.7' 4739.1 4308,0 4852.4 4408.0 4965.7 4508.0 5078.9 4608.0 5192.2 4708,0 50.9S 1797.5~ 4764.4 4353.0 36.2N 1756.8W 25.0 106.1' 106.8' 61.95 1849.5W 4879.6 4451.9 6.5N 1807.914 31.3 91.4' 92,3* 73.05 1901.5~ 4991.7 4547.2 27.95 1855.714 45.5 75.3* 75.9* 84.1S 1~53.5~ 5100.1 4640.4 63.85 1898.0~ 70.0 67.4* 67.4* 95.15 2005.6~ 5210.0 4735.5 98.9S 1940,3~ 93.3 71.0 71,2 5305.5 4808,0 5418.7 4908,0 5532.0 5008,0 5645.2 5108,0 5758.5 5208.0 106.2S 2057.6~ 5320.1 4831.5 132.7S 1982,4W 109.4 83.1 83.9 117.25 2109.6~ 5432.4 4929.0 167.0S 2026.3W 120.8 99.3 100.4 128.35 2161,6~ 5545.2 5025.7 201.55 2072.9W 129.5 116.4 117.8 139.45 2213.6~ 5657.9 5121.0 236.45 2122.1W 136.7 134.1 135,7 150.45 2265,7t4 5770,7 5214.6 271.55 2174,2W 142.9 151.9 153,9 5871.8 5308.0 5985.0 5408.0 161.5S 2317.714 5879.2 5302.6 306.5S 2227.2~ 148.1 171.0 174.3 172.5S 2369.714 5983.0 5386.6 342.0S 2276.6~ 151.2 194.5 200.3 ALt data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot #12 and TVD from wellhead (101.00 Ft above mean sea [eve[). Total Dogleg for we[[path is 0.00 degrees. Vertical section is from wellhead on azimuth 258.00 degrees. Calculation uses the minimc~n curvature method. Presented by Baker Hughes INTEQ Monopod A-8rd2 Drilling Hazards March 24, 1997 Drillin~ Hazards: Lost Circulation: While no known zone of lost circulation exists, it is likely that fluid could be lost in the Tyonek and Hemlock due to depleted pressure. Standard LCM will be kept on hand to combat losses. Low Pressure: It is likely that the Tyonek and Hemlock will be sub normal pressure due to historic withdrawl. Adequate mud properties will be maintained to build a mud cake to control losses. Over Pressure: None. Shallow Gas: As seen in the Monopod A-lrd workover, a gas cap exists in the Tyonek "E" zone at +/- 6400' MD / 5770' TVD. While this gas is not expected to be pressure, standard drilling practices will need to be followed to ensure correct and adequate hole fill. ADMINISTRATION 1. Permit fee attached .................. 2. Lease number appropriate ............... 3. Unique well name and number .............. 4. Well located in a defined pool ............. 5. Well located proper distance from drlg unit boundary.~ 6. Well located proper distance from other wells.....~.. 7. Sufficient acreage available in drilling unit 8. If deviated, is wellbore plat included ........ 9. Operator only affected party .............. 10. Operator has appropriate bond in force ......... 11. Permit can be issued without conservation order .... 12. Permit can be issued without administrative approval. 13. Can permit be approved before 15-day wait ....... ENGINEERING REMARKS " ,/ ! 1/ N ' '- // -' N "' ~ t ' '' '" ~PR 15. Surface casing protects all known USDWs ......... Y N 16. CMT vol adequate to circulate on conductor & surf csg. . Y 17. CMT vol adequate to tie-in long string to surf csg . . . y. 18. CMT will cover all known productive horizons 19. Casing designs adequate for C, T, B & permafrost .... 20. Adequate tankage or reserve pit ............ . _~ N 21. If a re-drill, has a 10-403 for abndnmnt been approved.~ N 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate .......... 24. Drilling fluid program schematic & equip list adequate . N 25. BOPEs adequate .................... N 26. BOPE press rating adequate; test to ~~ pslg N 27. Choke manifold complies w/API RP-53 (May 84) ...... N 28. Work will occur without operation shutdown ....... N 29. Is presence of H2S gas probable ............ N GEOLOGY / 30. Permit can be issued w/o hydrogen sulfide measures .... Y N/ 31. Data presented on potential overpressure zones ..... ¥ /A~ ~/ ~ 32. Seismic analysis of shallow gas zones .......... V N ~ 33. Seabed condition survey (if off-shore) ........ ~/Y N 34. Contact name/phone for weekly progress reports . . . /. Y N [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: Comments/Instructions: Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. * ALASKA COMPUTING CENTER * . * ****************************** . ............................ . * ....... SCHLUMBERGER ....... * Rt=CEIVED 8EP 16 i99;F .............................. .............................. COMPANY NAFiE : UNOCAL WELL NAME : TRADING BAY UNIT A-8 RD 2 FIELD NAlVlE : TRADING BAY BOROUGH : KENAI STATE : ALASKA API NUFiBER : 50-733-20043-02 REFERF~CE NO : 97388 L'IS Tape 'Verification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PA GE: **** REEL HEADER **** SERVICE NAME : EDIT DATE : 97/08/27 ORIGIN : FLIC REEL NAME : 97388 CONTINUATION # PREVIOUS REEL : COI~4ENT : UNOCAL, TRADING BAY, TRADING BAY UNIT A-8 RD 2,50-733-20043-02 **** TAPE HEADER **** SERVICE NAFiE .. EDIT DATE : 97/08/27 ORIGIN : FLIC TAPE NAME : 97388 CONTINUATION # : 1 PREVIOUS TAPE : COf4P~_~IT : UNOCAL, TRADING BAY, TRADING BAY UNIT A-8 RD 2,50-733-20043-02 **** FILE HEADER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01AiO DATE · 97/08/27 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : ******************************************************************************* ******************************************************************************* ** ** ** ** ** SCHLUFiBERGER WELL SERVICES ** ** ** ** ** ******************************************************************************* ******************************************************************************* COMPANY NAME: UNOCAL WELL: TRADING BAY UNIT A-8 RD 2 FIELD: TRADING BAY BOROUGH: KENAI STATE: ALASKA API NUA~ER: 50-733-20043-02 LOCATION: 1612' FSL & 577' FEL SECTION: 4 TOWNSHIP: 9N RANGE: 13W SM PERMANENT DA~: MSL ELEVATION: O' LOG MEASUREDFROMKB 101' ABOVE PERMANENTDATUM L~IS Tape .Verification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PAGE: ELEVATIONS KB: 101' DF: 100' GL: DATE LOGGED: 1-JUL-97 RUN NUM~ER: ONE TDDRILLER: 7643' TD LOGGER: 7610' CASING 1: 9.625" 43.5 LB @ DRILLER DEPTH OF 3426' AND LOGGER DEPTH OF 3436' BIT SIZE 1: 8.5" TYPE FLUID IN HOLE: POLY-PLUS G DENSITY: 10.3 VISCOSITY: 67 PH: 9 FLUID LOSS: 6 MUD RESISTIVITY: O. 95 @ 70 DEGF FILTRATE RESISTIVITY: 2.75 @ 68 DEGF MUD CAKE RESISTIVITY: O. 65 @ 69 DEGF TIME CIRCULATION ENDED: 13:30 1-JULY-1997 TIME LOGGER ON BOTTOM: 21:19 1-JULY-1997 MAXIMUM TEMP RECORDED: 161 DEGF LOGGING DISTRICT: KENAI LOGGING ENGINEER: BILL MOTHERWELL WITNESS: LEE BAILEY TOOL~ERS: DIS HC 421 DICCA 418 DRS C 485 NSC E 930 PDH L 2808 PGD G 3747 GSR H 1935 CNCRA 289 CNH NSR FA 1177 CNB AB 3200 SGC SA 64 FIELD REMARKS: PHASOR RUN IN COFfl~INATION WITH LDT-D, CNT-H, BHC-SONIC, AND GR. THREE 1.5" STANDOFFS RUN ON PHASOR. FIVE1.5" STANDOFFS RUN ON SONIC. FLEX JOINTS RUN BETWEEN SONIC AND LDT/CNT. FLEX JOINTS RUN BETWEEN LDT/CNT AND GARfl~A-RAY. MAXIMUM DEVIATION 52.6 DEGREES. UP HOLE REPEAT SECTION RUN TO VERIFY TOOL RESPONCE NEXT TO OLD CASING LOGS DEPTH OFFSET 10' AT CLIENTREQUEST TO TIE INTO OLD HOLE. DATE JOB STARTED: 27-AUG-97 JOB REFERENCE NO: 97388 LDP/ANA: R. KRUWELL ****************************************************************************** , * FILE -EDIT. O01 , * UNOCAL * TRADING BAY ~,IS Tape, Verification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PAGE: TRADING BAY UNIT A-8 RD 2 50-733-20043-02 "MAIN LOG FILE" DATA SAMPLED EVERY -.5000 FEET DATA INCLUDED - TOOL EXTENSION TOOL TYPE USED NAM~ DIT-E .DTE PHASOR DUAL INDUCTION SFL SDT . SDT ARRAY SONIC LDT . LDT LITHO DENSITY CNT-A/D/H . CArL COMPENSATED NEUTRON ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE .............................. t 66 0 2 66 0 3 73 216 4 66 1 5 66 6 73 7 65 8 68 O. 5 9 65 FT 11 66 4 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAM~ SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 539722 O0 000 O0 0 1 1 1 4 68 0000000000 CIDP DTE Fi~HO 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IDPH DTE OH~ 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LIS Tape ~/erification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PAGE: 4 NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) CIMP DTE ~4PLqO 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IMPH DTE 0H~539722 O0 000 O0 0 1 1 1 4 68 0000000000 CILDDTE f~4HO 539722 O0 000 O0 0 1 1 1 4 68 0000000000 ILD DTE 0H~4539722 O0 000 O0 0 1 1 1 4 68 0000000000 CILMDTE M~40 539722 O0 000 O0 0 1 1 1 4 68 0000000000 ILM DTE OH~M539722 O0 000 O0 0 1 1 1 4 68 0000000000 IFREDTE HZ 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IDQF DTE 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IMQF DTE 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IIRDDTE ~0 539722 O0 000 O0 0 1 1 1 4 68 0000000000 II3fDDTE ~vi~O 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IIRMDTE ~HO 539722 O0 000 O0 0 1 1 1 4 68 0000000000 IIX~DTE M~HO 539722 O0 000 O0 0 1 1 1 4 68 0000000000 SFLU DTE 0PH~4539722 O0 000 O0 0 1 1 1 4 68 0000000000 SP DTE MV 539722 O0 000 O0 0 1 1 1 4 68 0000000000 GR DTE GAPI 539722 O0 000 O0 0 1 1 1 4 68 0000000000 TENS DTE LB 539722 O0 000 O0 0 1 1 1 4 68 0000000000 MTENDTE DEGF 539722 O0 000 O0 0 1 1 1 4 68 0000000000 AfRES DTE OP~V~539722 O0 000 O0 0 1 1 1 4 68 0000000000 HTENDTE LB 539722 O0 000 O0 0 1 1 1 4 68 0000000000 DT SDT US/F 539722 O0 000 O0 0 1 1 1 4 68 0000000000 TT1 SDT US 539722 O0 000 O0 0 1 1 1 4 68 0000000000 TT2 SDT US 539722 O0 000 O0 0 1 1 1 4 68 0000000000 TT3 SDT US 539722 O0 000 O0 0 1 1 i 4 68 0000000000 TT4 SDT US 539722 O0 000 O0 0 1 1 1 4 68 0000000000 RHOB LDT G/C3 539722 O0 000 O0 0 1 1 1 4 68 0000000000 DRHO LDT G/C3 539722 O0 000 O0 0 1 1 1 4 68 0000000000 PEF LDT 539722 O0 000 O0 0 1 1 1 4 68 0000000000 QLS LDT 539722 O0 000 O0 0 1 1 1 4 68 0000000000 QSS LDT 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LS LDT CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LU LDT CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LL LDT CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LITHLDT CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 SSi LDT CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 SS2 LDT CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LSHVLDT V 539722 O0 000 O0 0 1 1 1 4 68 0000000000 SSHVLDT V 539722 O0 000 O0 0 1 1 1 4 68 0000000000 S1RHLDT G/C3 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LSRHLDT G/C3 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LURHLDT G/C3 539722 O0 000 O0 0 1 1 1 4 68 0000000000 CALI LDT IN 539722 O0 000 O0 0 1 1 1 4 68 0000000000 NPHI CNL PU 539722 O0 000 O0 0 1 1 1 4 68 0000000000 RTNR CNL 539722 O0 000 O0 0 1 1 1 4 68 0000000000 TNPH CNL PU 539722 O0 000 O0 0 1 1 1 4 68 0000000000 TNRA CNL 539722 O0 000 O0 0 1 1 1 4 68 0000000000 NPOR CNL PU 539722 O0 000 O0 0 1 1 1 4 68 0000000000 RCNT CNL CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 RCFT CArL CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 CNTC CNL CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 CFTC CArL CPS 539722 O0 000 O0 0 1 1 1 4 68 0000000000 LIS Tape .Verification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PAGE: ** DATA ** DEPT. 7254.500 CIDP.DTE 95.500 IDPH.DTE 10. 469 CIMP.DTE IMPH.DTE 14.633 CILD.DTE 97.813 ILD.DTE 10.219 CILM.DTE ILM. DTE 14. 289 IFRE.DTE 20. 000 IDQF.DTE 3. 000 IMQF.DTE IIRD.DTE 87.125 IIXD.DTE 4.785 IIRM. DTE 66.313 II3q~.DTE SFLU. DTE 13. 453 SP.DTE -45. 563 GR.DTE 60. 156 TENS.DTE MTEM. DTE 142.981 F~qES.DTE 0.206 HTEN. DTE 629. 000 DT. SDT TT1. SDT 506.800 TT2 . SDT 345.200 TT3 . SDT 521.200 TT4 . SDT RHOB.LDT 2. 426 DRHO.LDT O. 000 PEF. LDT 3. 090 QLS.LDT QSS.LDT -0.003 LS.LDT 312.500 LU. LDT 296.750 LL.LDT LITH. LDT 87.125 SS1.LDT 223.750 SS2.LDT 327.250 LSHV. LDT SSHV. LDT 1424.000 S1RH. LDT 2.424 LSRH. LDT 2.424 LURH. LDT CALI.LDT 8.500 NPHI.CNL 25.525 RTNR.CNL 2.227 TNPH. CNL TNRA. CNL 2.103 NPOR.CNL 20.837 RCNT. CNL 4074.134 RCFT. CNL CNTC. CNL 3955.438 CFTC. CArL 1898.396 DEPT. 3309.500 CIDP.DTE IMPH.DTE 1950. 000 CILD.DTE ILM. DTE 1950. 000 IFRE.DTE IIRD. DTE 61.656 II~D. DTE SFLU. DTE 4.199 SP . DTE MTE~. DTE 121. 887 F~RES. DTE TT1. SDT 439. 600 TT2. SDT RHOB . LDT 2. 122 DRHO. LDT QSS.LDT -0.088 LS.LDT LITH. LDT 20.063 SS1.LDT SSHV. LDT 1419.000 S1RH. LDT CALI.LDT 3.141 NPHI. ClFL TNRA. CNL 3.846 NPOR.CNL CNTC. CNL 1592.373 CFTC. CNL 67 063 68 438 20 000 -400 000 -120 000 0 230 297.600 -0.574 187.625 90.813 3.941 55.728 45.481 432.901 IDPH.DTE 14. 906 CIMP.DTE ILD. DTE 14. 602 CILM. DTE IDQF.DTE O. 000 IMQF.DTE IIRM. DTE -434. 250 IIX~.DTE GR. DTE 58.156 TENS. DTE HTEN. DTE 1320. 000 DT. SDT TT3. SDT 444. 400 TT4. SDT PEF. LDT 19. 703 QLS.LDT LU. LDT 182. 750 LL.LDT SS2. LDT 150. 125 LSHV. LDT LSRH. LDT 2. 693 LURH. LDT R TNR . CNL 3. 778 TNPH. CArL RCNT. CAUL 1645. 605 RCFT. CNL 68.313 69.938 2.000 5.398 3530.000 0.000 360. 400 -0. 021 164.250 1461.000 2.424 20.837 1798.168 -453.250 -441.500 0.000 1411.000 3370.000 71.200 302.800 0.005 96.250 1452.000 2.734 45.648 407.559 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01AIO DATE : 97/08/27 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : ._LIS Tape. verification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PA GE: **** FILE HEADER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION : O01AiO DATE : 97/08/27 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE -EDIT. O02 UNOCAL TRADING BAY TRADING BAY UNIT A-8 RD 2 50-733-20043-02 "BOTTOM REPEAT FILE" DATA SAMPLED EVERY -.5000 FEET DATA INCLUDED - TOOL EXTENSION TOOL TYPE USED NAME DIT-E .DTi PHASOR DUAL INDUCTION SFL SDT o SD1 ARRAY SONIC LDT . LDi LITHO DENSITY * CNT-A/D/H . CN1 COMPENSATED NEUTRON . ****************************************************************************** ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** .............................. TYPE REPR CODE VALUE .............................. I 66 0 2 66 0 3 73 216 4 66 1 5 66 LIS Tape V~_=fication Listing Schlumberger Alaska Computing Center 27-AUG-1997 1~.~7 PAGE: TYPE REPR CODE VALUE 6 73 7 65 8 68 0.5 9 65 FT 11 66 4 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUFiB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD ~ SAMP ELEM CODE (HEX) DEPT FT 539722 O0 000 O0 0 2 1 1 4 68 0000000000 CIDP DT1 MMHO 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IDPH DT1 0H~4539722 O0 000 O0 0 2 1 1 4 68 0000000000 CIMP DT1 14~HO 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IMPH DT1 0~539722 O0 000 O0 0 2 1 1 4 68 0000000000 CILDDT1 14FIHO 539722 O0 000 O0 0 2 1 1 4 68 0000000000 ILD DT1 Oh%N~$539722 O0 000 O0 0 2 1 1 4 68 0000000000 CILMDT1 14FIHO 539722 O0 000 O0 0 2 1 1 4 68 0000000000 ILM DT1 0H~539722 O0 000 O0 0 2 1 1 4 68 0000000000 IFREDT1 HZ 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IDQF DT1 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IMQF DT1 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IIRDDT1 14Ffl~O 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IIXDDT1 14FiHO539722 O0 000 O0 0 2 1 1 4 68 0000000000 IIRMDT1 14FiHO539722 O0 000 O0 0 2 1 1 4 68 0000000000 II3C~DT1 I4P~fO539722 O0 000 O0 0 2 1 1 4 68 0000000000 SFLU DT1 0~539722 O0 000 O0 0 2 1 1 4 68 0000000000 SP DT1 MV 539722 O0 000 O0 0 2 1 1 4 68 0000000000 GR DT1 GAPI 539722 O0 000 O0 0 2 1 1 4 68 0000000000 TENS DT1 LB 539722 O0 000 O0 0 2 1 1 4 68 0000000000 MTEMDT1 DEGF 539722 O0 000 O0 0 2 1 1 4 68 0000000000 IZiRES DT1 0H~$539722 00 000 O0 0 2 1 1 4 68 0000000000 HTENDT1 LB 539722 O0 000 O0 0 2 1 1 4 68 0000000000 DT SD1 US~F539722 O0 000 O0 0 2 1 1 4 68 0000000000 TT1 SD1 US 539722 O0 000 O0 0 2 1 1 4 68 0000000000 TT2 SD1 US 539722 O0 000 O0 0 2 1 1 4 68 0000000000 TT3 SD1 US 539722 O0 000 O0 0 2 1 1 4 68 0000000000 TT4 SD1 US 539722 O0 000 O0 0 2 1 1 4 68 0000000000 RHOB LD1 G/C3 539722 O0 000 O0 0 2 1 1 4 68 0000000000 DRHO LD1 G/C3 539722 O0 000 O0 0 2 1 1 4 68 0000000000 PEF LD1 539722 O0 000 O0 0 2 1 1 4 68 0000000000 QLS LD1 539722 O0 000 O0 0 2 1 1 4 68 0000000000 QSS LD1 539722 O0 000 O0 0 2 1 1 4 68 0000000000 LS LD1 CPS 539722 O0 000 O0 0 2 1 1 4 68 0000000000 LIS Tape ~ __ification Listing ~chlumbe~ger Alaska Computing Center 27-AUG-1997 ~ :57 PAGE: NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUM~ SAMP ELEM CODE (HEX) O0 000 O0 0 2 1 1 4 68 0000000000 LU LD1 CPS 539722 LL LD1 CPS 539722 LITHLD1 CPS 539722 SSI LD1 CPS 539722 SS2 LD1 CPS 539722 LSHVLD1 V 539722 SSHVLD1 V 539722 S1RHLD1 G/C3 539722 LSRHLDi G/C3 539722 LURHLD1 G/C3 539722 CALI LD1 IN 539722 NPHI CN1 PU 539722 RTNR CN1 539722 TNPH CN1 PU 539722 TNRA CN1 539722 NPOR CN1 PU 539722 RCNTCN1 CPS 539722 RCFT CN1 CPS 539722 CNTC CN1 CPS 539722 CFTC CN1 CPS 539722 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 00 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 00 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 O0 000 O0 0 2 1 1 4 68 0000000000 ** DATA ** DEPT. 7643 . 000 CIDP.DT1 227. 875 IDPH. DT1 IMPH.DT1 4.266 CILD.DTI 229. 625 ILD.DT1 ILM. DT1 4.230 IFRE.DT1 20. 000 IDQF. DT1 IIRD.DT1 197.125 IIXD.DTi 26. 703 IIRM. DT1 SFLU. DT1 3 . 820 SP.DT1 17. 734 GR. DT1 MTEM. DT1 143.994 FiRES.DTi 0.211 HTEN. DT1 TT1 . SD1 526. 800 TT2. SD1 371 . 200 TT3. SD1 RHOB.LD1 2. 436 DRHO.LD1 O. 022 PEF. LD1 QSS. LD1 0 . 012 LS. LD1 321 . 250 LU. LD1 LITH. LD1 96. 438 SSi .LD1 236. 000 SS2. LD1 SSHV. LD1 1422. 000 S1RH. LD1 2.338 LSRH. LD1 CALI.LD1 8.500 NPHI.CN1 35.560 RTNR.CN1 TNRA. CN1 2.745 NPOR. CN1 30.360 RCNT. CN1 CNTC. CN1 2792 . 001 CFTC. CN1 1029. 209 DEPT. 6897. 000 CIDP.DT1 83. 813 IDPH.DT1 IMPH.DT1 8. 859 CILD.DTI 87. 375 ILD.DT1 ILM. DT1 9.102 IFRE.DT1 20. 000 IDQF.DT1 IIRD.DT1 79. 938 IIXD.DT1 7. 531 IIRM. DT1 SFLU. DT1 9.531 SP. DT1 -16. 953 GR. DT1 MTE~. DT1 142. 756 f4RES.DT1 O. 207 HTEN. DT1 TT1 . SD1 328. 800 TT2 . SD1 364 . 800 TT3. SD1 RHOB.LD1 2. 419 DRHO.LD1 O. 038 PEF. LD1 QSS. LD1 O. 032 LS. LD1 339. 750 LU. LDI LITH. LD1 99 . 938 SSi . LD1 242. 750 SS2. LD1 SSHV. LD1 1424.000 S1RH.LD1 2.277 LSRH. LD1 4 387 4 352 3 000 221 625 113 563 1134 000 532 000 2.852 300.500 338.000 2.410 2.906 2875.785 11.922 11.438 0.000 103.875 64.813 1199.000 523.200 3.115 318.750 339.750 2.379 CIMP.DT1 CILM. DT1 IMQF.DT1 IIX~.DT1 TENS.DT1 DT. SD1 TT4.SD1 QLS.LD1 LL. LD1 LSHV. LD1 L URH . LD1 TNPH. CN1 RCFT. CN1 CIMP.DT1 CILM. DT1 IMQF. DT1 I IXM. D T1 TENS. DT1 DT. SD1 TT4. SD1 QLS. LD1 LL. LD1 LSHV. LD1 LURH. LD1 234.125 236.250 2. 000 16.234 5495. 000 O. 000 373. 200 -0. 002 170. 875 1460. 000 2.416 30.360 974. 870 112. 750 109. 750 O. 000 6. 492 5130. 000 86. 800 382. 400 -0. 011 180.500 1461. 000 2. 381 LIS Tape ~Verificati°n Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 PAGE: CALI.LD1 8.422 NPHI. CN1 TNRA.CN1 2.575 NPOR.CN1 CNTC. CN1 3293.817 CFTC. CN1 27.628 RTNR. CN1 29.671 RCNT. CN1 1298.881 2.825 TNPH. CN1 3210.523 RCFT. CN1 27.648 1148.622 ** END OF DATA ** **** FILE TRAILER **** FILE NA~iE : EDIT .002 SERVICE : FLIC VERSION : O01AIO DATE : 97/08/27 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAM~ : EDIT .003 SERVICE : FLIC VERSION : O01AiO DATE : 97/08/27 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : ****************************************************************************** FILE -EDIT. O03 UNOCAL TRADING BAY TRADING BAY UNIT A-8 RD 2 50-733-20043-02 "UPPER REPEAT FILE" DATA SAMPLED EVERY -.5000 FEET DATA INCLUDED - TOOL EXTENSION TOOL TYPE USED NAME DIT-E .DT2 SDT .SD2 LDT .LD2 PHASOR DUAL INDUCTION SFL ARRAY SONIC LITHO DENSITY LIS Tape P~£ification Listing Schlumberger Alaska Computing Center 27-AUG-1997 13:57 * CNT-A/D/H . CN2 COMPENSATED NEUTRON . ****************************************************************************** PAGE: 10 ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** .............................. TYPE REPR CODE VALUE .............................. 1 66 0 2 66 0 3 73 216 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 4 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NA~E SERV UNIT SERVICE API API API API FILE NUMB NUM~ SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUmB SAMP ELE~ CODE (HEX) DEPT FT 539722 O0 000 O0 0 3 1 1 4 68 0000000000 CIDP DT2 F~4~O 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IDPH DT2 0H~539722 O0 000 O0 0 3 1 1 4 68 0000000000 CIMP DT2 F~IHO 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IMPH DT2 0H~539722 O0 000 O0 0 3 1 1 4 68 0000000000 CILDDT2 F~O 539722 O0 000 O0 0 3 1 1 4 68 0000000000 ILD DT2 OHF~f539722 O0 000 O0 0 3 1 1 4 68 0000000000 CILMDT2 F~4HO 539722 O0 000 O0 0 3 1 1 4 68 0000000000 ILM DT2 0P~539722 O0 000 O0 0 3 1 I 4 68 0000000000 IFREDT2 HZ 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IDQF DT2 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IMQF DT2 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IIRDDT2 F~4~O 539722 O0 000 O0 0 3 1 I 4 68 0000000000 IIXDDT2 Fk4~O 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IIRMDT2 f4~O 539722 O0 000 O0 0 3 1 1 4 68 0000000000 IIX~DT2 F~4~O 539722 O0 000 O0 0 3 1 1 4 68 0000000000 SFLU DT2 0H~2~539722 O0 000 O0 0 3 1 1 4 68 0000000000 SP DT2 MV 539722 O0 000 O0 0 3 1 1 4 68 0000000000 LIS Tape ~ ~fication Listing ~ch~umberger Alaska Computing Center 27-AUG-1997 13:57 PAGE: 11 NAME SERVUNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELE~ CODE (HEX) GR DT2 GAPI 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TENS DT2 LB 539722 00 000 O0 0 3 1 1 4 68 0000000000 MTEMDT2 DEGF 539722 00 000 O0 0 3 1 1 4 68 0000000000 I~cES DT2 OHP~f539722 O0 000 O0 O. 3 1 1 4 68 0000000000 HTENDT2 LB 539722 O0 000 O0 0 3 1 1 4 68 0000000000 DT SD2 US/F 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TT1 SD2 US 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TT2 SD2 US 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TT3 SD2 US 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TT4 SD2 US 539722 O0 000 O0 0 3 1 1 4 68 0000000000 RHOBLD2 G/C3 539722 O0 000 O0 0 3 1 1 4 68 0000000000 DRHOLD2 G/C3 539722 O0 000 O0 0 3 1 1 4 68 0000000000 PEF LD2 539722 O0 000 O0 0 3 1 1 4 68 0000000000 QLS LD2 539722 O0 000 O0 0 3 1 1 4 68 0000000000 QSS LD2 539722 O0 000 O0 0 3 1 1 4 68 0000000000 LS LD2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 LU LD2 CPS 539722 00 000 O0 0 3 1 1 4 68 0000000000 LL LD2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 LITHLD2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 SSi LD2 CPS 539722 O0 000 O0 0 3 1 i 4 68 0000000000 SS2 LD2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 LSHVLD2 V 539722 O0 000 O0 0 3 1 1 4 68 0000000000 SSHVLD2 V 539722 O0 000 O0 0 3 1 1 4 68 0000000000 S1RHLD2 G/C3 539722 00 000 O0 0 3 1 1 4 68 0000000000 LSRHLD2 G/C3 539722 O0 000 O0 0 3 1 1 4 68 0000000000 LURHLD2 G/C3 539722 O0 000 O0 0 3 1 1 4 68 0000000000 CALI LD2 IN 539722 O0 000 O0 0 3 1 1 4 68 0000000000 NPHI CN2 PU 539722 O0 000 O0 0 3 1 1 4 68 0000000000 RTNR CN2 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TNPHCN2 PU 539722 O0 000 O0 0 3 1 1 4 68 0000000000 TNRA CN2 539722 O0 000 00 0 3 1 1 4 68 0000000000 NPOR CN2 PU 539722 O0 000 O0 0 3 1 1 4 68 0000000000 RCNTCN2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 RCFTCN2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 CNTC CN2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 CFTC CN2 CPS 539722 O0 000 O0 0 3 1 1 4 68 0000000000 ** DATA ** DEPT. 4206. 000 CIDP.DT2 239. 500 IDPH. DT2 4.172 CIMP. DT2 IMPH. DT2 3. 771 CILD.DT2 241. 625 ILD.DT2 4.137 CILM. DT2 ILM. DT2 3. 742 IFRE.DT2 20. 000 IDQF. DT2 3. 000 IMQF. DT2 IIRD. DT2 206. 750 IIXD.DT2 25. 063 IIRM. DT2 250. 000 IIXM. DT2 SFLU. DT2 3.223 SP.DT2 -96.000 GR.DT2 78.875 TENS.DT2 14TESf. DT2 124.531 I4RES.DT2 O. 229 HTEN. DT2 952. 000 DT. SD2 TT1.SD2 663.600 TT2.SD2 453.200 TT3.SD2 663.200 TT4.SD2 RHOB.LD2 2.337 DRHO.LD2 0.045 PEF. LD2 18.703 QLS.LD2 QSS. LD2 0 . 054 LS. LD2 398. 000 LU. LD2 371. 750 LL. LD2 LITH. LD2 115. 813 SSi .LD2 251. 000 SS2.LD2 347. 000 LSHV. LD2 265. 000 267. 000 2. 000 18. 875 2870. 000 O. 000 454. 800 -0. 017 212.250 1450. 000 LIS Tape _fication Listing $~chlumberger Alaska Computing Center 27-AUG-1997 ~_ .57 PAGE: 12 SSHV. LD2 1414.000 S1RH. LD2 CALI.LD2 8.500 NPHI. CN2 TNRA. CN2 5.159 NPOR. CN2 CATTC. CN2 1273 . 222 CFTC. CN2 DEPT. 3386. 000 CIDP.DT2 IMPH.DT2 1950. 000 CILD.DT2 ILM. DT2 1950. 000 IFRE.DT2 IIRD. DT2 57. 500 IIXD. DT2 SFLU. DT2 5. 734 SP. DT2 MT~. DT2 122 . 281 $~JES . DT2 TT1 . SD2 411 . 200 TT2 . SD2 RHOB. LD2 1.521 DRHO. LD2 QSS. LD2 - 0 . 116 LS . LD2 LITH. LD2 35 . 813 SSI . LD2 SSHV. LD2 1418.000 S1RH. LD2 CALI.LD2 3.141 NPHI.CN2 TNRA. CN2 4. 848 NPOR. CN2 CNTC. CN2 1136. 725 CFTC. CN2 2.180 LSRH.LD2 79.766 RTArR.CN2 89.843 RCNT. CN2 251.250 62.563 IDPH. DT2 63.563 ILD. DT2 20. 000 IDQF.DT2 -400. 500 IIRM. DT2 -162.625 GR.DT2 0.229 HTEN. DT2 295.600 TT3.SD2 -0.827 PEF. LD2 336.250 LU. LD2 74.188 SS2.LD2 4.090 LSRH. LD2 74.073 RTNR.CN2 72.492 RCNT. CN2 238.751 2.289 LURH.LD2 5.462 TNPH. CN2 1311.429 RCFT. CN2 15.977 CIMP.DT2 15. 719 CILM. DT2 O. 000 IMQF. DT2 -462.250 II3~4. DT2 57. 094 TENS. DT2 1312. 000 DT. SD2 413.600 TT4.SD2 19 . 031 QL$. LD2 303. 500 LL. LD2 137. 625 LSHV. LD2 2. 348 L URH . L D 2 5.538 TNPH. CN2 1198. 671 RCFT. CN2 2.293 89.843 237.985 -477.500 -469.000 0.000 1473.000 3465.0OO 57.000 302.000 0.165 184.625 1452.000 2.410 74.215 236.757 ** ENI) OF DATA ** **** FILE TRAILER **** FILE NAIVE : EDIT .003 SERVICE : FLIC VERSION : O01AiO DATE : 97/08/27 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** TAPE TRAILER **** SERVICE NAME : EDIT DATE : 97/08/27 ORIGIN : FLIC TAPE NAME : 97388 CONTINUATION # : 1 PREVIOUS TAPE : COMFIENT : UNOCAL, TRADING BAY, TRADING BAY UNIT A-8 RD 2,50-733-20043-02 **** REEL TRAILER **** SERVICE NA~E : EDIT DATE : 97/08/27 ORIGIN : FLIC REEL NAFIE : 97388 CONTINUATION # : PREVIOUS REEL : COf4FiENT : UNOCAL, TRADING BAY, TRADING BAY UNIT A-8 RD 2,50-733-20043-02