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Home My WebLink About211-1141. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,161 feet N/A feet true vertical 2,776 feet N/A feet Effective Depth measured 4,160 feet 2,530 & 2,576 feet true vertical 2,780 feet 2,435 & 2,468 feet Perforation depth Measured depth 3,031 - 4,154 feet True Vertical depth 2,673 - 2,779 feet Tubing (size, grade, measured and true vertical depth) See schematic Packers and SSSV (type, measured and true vertical depth) See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Middle Kenai Gas 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 4,760psi 5,020psi 6,870psi 1,402 1,388 Burst Collapse 2,260psi Production Liner 3,076 1,110 Casing Structural 2,683 4" 3,076 4,171 2,781 490 1,402 490Conductor Surface Intermediate 32" 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 211-114 50-733-20598-00-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0018730 McArthur River / Middle Kenai Gas Trading Bay Unit M-21 Plugs Junk measured Length measured TVD true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD N/A 22 Size 490 83 778484 0 80 13-3/8" Other: Install AVE GL System 10 324-331 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Ryan Rupert Ryan.Rupert@hilcorp.com 907 777-8503Operations Manager N/A measured Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 1:34 pm, Aug 01, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.08.01 12:05:26 - 08'00' Dan Marlowe (1267) _____________________________________________________________________________________ Updated By: RR 07/31/24 SCHEMATIC Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PBTD: 4,160 MD TD: 4,161 MD MAX HOLE ANGLE = 85.0° @ 3,076 4,194 MD A 32 RKB to TBG Head = 78 6-3/4 Open Hole 3-4 5 6 7 13-3/8 9-5/8 1 2 C B X 6 7 ECP Stage Collar @ 411 SIZE WT GRADE CONN ID TOP BTM (MD) 32 X-56 Welded 30 Surf 490 13-3/8 68 L-80 BTC 12.415 Surf 1,402 9 5/8 47 L-80 DWC 8.681 Surf 3,076 Tubing / Liner / Insert AVE Detail 5-1/2 17.0 L-80 TC-II 4.892 Surf 2,592 4-1/2 12.75 Blank TC-II 3.958 2,614 3,031 4 15.2 Excluder 2000 Screen SLHT 3.54 3,031 3,219 4 9.5 Bkrweld 140 Screen 8 ga. SHLT 3.46 3,219 4,160 2-7/8 6.5 L-80 EUE 8RD 2.441 Surf 2,598' 2-3/8 4.6 L-80 SUPERMAX SCC 1.995 2,598' 4,113' OPENHOLE DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Horizontal screened completion in A2 Sand A2 3,031 4,154 2,673 2,779 Open TUBING / LINER JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description 73.24 73.24 4.90 13.375 Hanger Vetco CWC-T 1 444 444 4.562 7.69 Halliburton SP-TRSV 2 2,554 2,452 4.562 5.937 X-Nipple 3 2,572 2,465 3.43 6.000 S-22 Snap Latch seal assembly w/ ratcheting muleshoe 4 2,576 2,468 4.750 8.43 Baker SC-1R Gravel Packer 2,581 2,471' 4.88 6.65 X-Over6-58 SLHT Box X 5-1/2: SLHT PIN 2,582 2,472' 4.75 6.3 Seal Bore Extension 5-1/2 SLHT Pin X Pin 5 2,604 2,485 3.40 5.810 Fluid Loss Control Valve (Baker)Milled out as of 1/31/24 6 4,154 2,779 1.88 4.510 O-Ring Seal Sub for Slick Stinger 7 4,160 2,780 NA 4.49 GP Wash Down Shoe INSERT AVE JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description A 418' 418' 2.312 4.609 Baker TE-5 TRSSSV B 2,525' 2,431' 2.21" 4.50 On/OFF Tool (left hand release). XN-profile in stringer (2.312 ID). Stinger necks down to 2.21 below X-profile. C 2,530' 2,435' n/a 4.50 2.8" x 5.5" ASI-X mechanical set Packer (right hand release) w/ concentric IAV Injection Tube: no passthrough. Packer is derated due to higher expansion dimensions GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,463 1,445 4.892 SFO-2 Mandrel 16 Dome 873 11/06/2011 2 2,485 2,401 4.892 SFO-2 Mandrel 20 Orifice 11/06/2011 3 4,041' 2,769' 1.995" Internal Mount Fixed 24 Orifice 07/04/2024 Well Name:MRF M-21 API #:50733205980000 Field:McArthur River Start Date:6/26/2024 Permit #:211114 Sundry #:324-331 End Date:7/8/2024 6/26/2024 6/27/2024 6/28/2024 6/29/2024 6/30/2024 7/1/2024 Well Operations Summary PJSM, IFO, Remove wireline bridge, Nipple down 7-1/16 blind flange from tbg spool, stack bops on same , continue to put BOP together on deck and stacking on well, torque all bolts with hyd wrench, Install wireline bridge, run and hook up koomey hoses, run hook up coflex hoses ( choke and kill hoses. prep and stand up work window & set in place and tighten PJ SM /PTW, IFO , Finish rigging up work window, change out co-flex hose, stand unit and stab same, rig up snubing basket, gin pole tongs, guy wires, make up 2-3/8 test joint, fluid pack lines and bope with TSI pump, attempt shell test, chase leak, and tighten same, shell test to 5000 psi for 5 minutes with TSI pump, bleed off test pressure, make up TIW valve and side pump in sub to test with test pump Crews arrive on Steelhead, orientate, and held PJSM, prep the deck for equipment arrival, unloading Snubbing equipment off the boat, setting snubbing unit equipment in place. SITP 0psi, cycled and closed master valve all good, N/d Tree and N/u 7-1/16" Tbg Head on top of master valve. Reposition Wire line bridge and close gaps in on deck, build mounts for gas detection system continue prep snubbing equipment, boat was unable to make call out at dock due to weather, made up blind flange on tbg head, nipple up same, tested gas detection (all good), test 7-1/16 tbg spool to 5000 psi for 15 minutes, offloading work boat, empty and sort baskets, Rigging up pump and stacking 7-1/16" BOPE. TEST bops and related surface equipment to Hilcorp and AOGCC specs to 250 psi 5000 psi high, Bob Noble with AOGCC witness bop test had two fail pass choke manifold valves 5,6,8 . Test for 2-3/8" and 2-7/8" pipe. Prep deck to run pipe and arrange the 2-3/8 super max on deck as pre tally , pick up 2-3/8 super max with bull plug, close stripper annular, open well "0" psi well on vacuum, continue snubbing in hole to 2617 ft at rot time prep to run 2-7/8 tbg. Daily Operations: Picked up packer and snub in hole, tagging up at 2084 EOT with packer tagging in 5-1/2 safety valve at 444 ft., snub out of hole lay of 5- 1/2 packer, had small of scale in slips, clean same pick up packer snub in hole tagging up at same 2084 ft packer in 5-1/2 SSSV, working same, pump diesel down back side, and let soak, snub 5k down over string wt for 4 ft pipe free. continue in hole tagging up 2117 taking 5k snubbing down on tbg. continue in hole at 2278 ft tagging up , Continue in hole taking 2k 5k adn 10k down each joint tagging up at 4117 ft md. verify elevation, and checking tally. Page 1 of 2 Well Name:MRF M-21 API #:50733205980000 Field:McArthur River Start Date:6/26/2024 Permit #:211114 Sundry #:324-331 End Date:7/8/2024 7/2/2024 7/3/2024 7/4/2024 7/7/2024 7/8/2024 Well Operations Summary Daily Operations: PJSM, PTW, XO tags 3.43" ratcheting muleshoe at 2591' placing EOT @ 4117', P/U install safety valve. Set packer with EOT at @ 4115'. Monitor well: static. Release from on/off tool above packer. wk on space out numbers getting on & off packer measurements, POOH t/ pick up TRSSV. RIH with upper completion and reengage on/off tool. Make up same lower work window, make up control line, fill with fluid, function valve, opened up at 1800 psi pressured up to 5000 psi for 5 minutes, (good test). Release from packer, pooh for space out and hanger, Mob out space out pups, inspect same found the pup that was needed was damaged. Will need to move packer to make existing space out pups work. Pooh lay down TRSSV, run back in the hole, close stripper, latch on/off tool, pickup and unseat packer. Moniter well while letting elements relax PT PCE to 2500psi. PASS. RIH w/ 2.30 gauge ring to 2512' kb, tag. RIH w/ 1" x 16" prong to 2513' kb to equalize plug. RIH w/ 2 1/2" GR to 2512' kb, pull plug. PJSM, PTW, Make 3 attempts to set packer, Set @ 4113', release from packer, check tubing static/no pressure build, open Equalizer line, monitor well while POOH l,d 14 jts 2 7/8" 6.5# L-80 EUE completion tubing. open stripper monitor well static, p/u TRSSV, m/u control line, test same good, RIH latch packer assembly @ 2524', make 2 space out runs. RIh with TRSV, pick up hanger, land same, latching the on/off tool pull test to 35k, land hanger and run in lock downs, Rig up and pressure test tbg against TTP in On/Off stinger with Gas to 900 psi, shut down gas , pressure at 890 psi, Held 890 for 15 minutes with no bleed off. IA for the 2-7/8 x 5-1/2 open and static during test. Bleed off test pressure, Close TRSSV, set BPV held PJSM with Crane crew & TSI crew for rigging down , Rigging down unit work basket, pump lines, choke manifold lines, spot skid on deck, Wait on weather wind 30 mph gusting at 35 mph, winds decreased to 25 mph made heavy lift on unit and set in skid and secure same Rig down work window, removed wire line bridge, nipple down 7-1/16 bope and risers, pick up and disassemble on deck and load in baskets, install tree and nipple up same , test void to 5k, tested tree t/ 5k good. Page 2 of 2 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________TRADING BAY UNIT M-21 JBR 07/26/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:3 Choke valves 5, 6, 8, F/P. serviced and passed retest. Very slow test. Took about 24 hours to get a shell test. Test Results TEST DATA Rig Rep:MunozOperator:Hilcorp Alaska, LLC Operator Rep:Hodgens Rig Owner/Rig No.:Team Snubbing TSI 102 PTD#:2111140 DATE:6/30/2024 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopRCN240703142404 Inspector Bob Noble Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 13 MASP: 0 Sundry No: 324-331 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.NA Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 9 FPNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 1 7 1/16 5K P Annular Preventer 1 7 1/16 5K P #1 Rams 1 2 3/8 5K P #2 Rams 1 2 3/8 x 2 7/8 V P #3 Rams 1 2 3/8 5K P #4 Rams 1 Blind/Shear P #5 Rams 1 2 3/8 stripper P #6 Rams 0 none NA Choke Ln. Valves 1 3 1/8 P HCR Valves 2 3 1/8 P Kill Line Valves 3 3 1/8 P Check Valve 0 none NA BOP Misc 0 none NA System Pressure P3000 Pressure After Closure P2150 200 PSI Attained P133 Full Pressure Attained P235 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P3 x 2300 ACC Misc NA0 NA NATrip Tank NA NAPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P7 #1 Rams P3 #2 Rams P3 #3 Rams P3 #4 Rams P3 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9 9 9999 9 9 9 9Choke valves 5, 6, 8, F/P FP TSI-102 HWO Unit at Trading Bay Steelhead Platform TBU M-21 (PTD 2111140) AOGCC Insp Rpt # bopRCN240703142404 Photo by AOGCC Inspector B. Noble 6/30/2024 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): 4,161 N/A Casing Collapse Structural Conductor Surface 2,260psi Intermediate Production 4,760psi Screen 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: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone: 907-777-8503 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 Other: Install AVE GL System SC-1R & SP-TRSV 2,576 (MD) 2,468 (TVD) & 444 (MD) 444 (TVD) N/A 3,076' Perforation Depth MD (ft): 3,031 - 4,154 3,076' 4" 1,402' 2,673 - 2,779 4,171'1,110' 5-1/2" 2,683'9-5/8" 2,781' 490' 1,402' 32" 13-3/8" 490' 5,020psi 490' 1,388' Size Proposed Pools: L-80 TVD Burst 2,700 6,870psi MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 211-114 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20598-00-00 Hilcorp Alaska, LLC Trading Bay Unit M-21 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 6/18/2024 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Operations Manager McArthur River Middle Kenai Gas Same 2,776 4,160 2,780 0psi N/A Length No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.06.05 09:25:06 - 08'00' Dan Marlowe (1267) By Grace Christianson at 3:51 pm, Jun 05, 2024 10-407 DSR-6/7/24 X See attached conditions of approval SFD 6/6/2024BJM 6/19/24*&:JLC 6/19/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.19 10:54:05 -08'00'06/19/24 RBDMS JSB 062024 TBU M-21 (PTD 211-114) Sundry 324-331 ^ŶƵďďŝŶŐŽƉĞƌĂƟŽŶ ŽŶĚŝƟŽŶƐŽĨƉƉƌŽǀĂů 1. BOP test to 2500 psi. Shear rams capable of shearing 2-7/8" tubing must be included in BOP stack. 2. WƌŽǀŝĚĞϰϴŚƌƐŶŽƟĐĞƚŽK'ĨŽƌKWƚĞƐƚ ĂŶĚŵĞƌŐĞŶĐǇŐƌĞƐƐƐǇƐƚĞŵŝŶƐƉĞĐƟŽŶ. 3. ^ŶƵďďŝŶŐĞƋƵŝƉŵĞŶƚ͕ƉĞƌƐŽŶŶĞůĂŶĚŽƉĞƌĂƟŽŶƚŽďĞĐŽŵƉůŝĂŶƚǁŝƚŚĂŶĂĚŝĂŶ/ZWϭϱ͘ ůů “must” and “shall͟ƐƚĂƚĞŵĞŶƚƐĂƐĚĞƐĐƌŝďĞĚŝŶ/ZWϭϱ͘Ϭ͘ϳƐŚĂůůďĞĂĚŚĞƌĞĚƚŽƵŶůĞƐƐĂƉƉƌŽǀĂůŝƐ ŽďƚĂŝŶĞĚĨƌŽŵK'ƚŽĚĞǀŝĂƚĞĨƌŽŵƚŚĞƐĞƐƚĂƚĞŵĞŶƚƐ͘/ĨƚŚĞƌƵůĞƐŝŶ/ZWϭϱĐŽŶŇŝĐƚǁŝƚŚ K'ƌĞŐƵůĂƟŽŶƐ͕K'ƌĞŐƵůĂƟŽŶƐǁŝůůĂƉƉůǇƵŶůĞƐƐK'ǀĂƌŝĂŶĐĞŽƌǁĂŝǀĞƌŝƐŐƌĂŶƚĞĚ. 4. tĞůůĐŽŶƚƌŽůƌĞŐƵůĂƟŽŶƐϮϬϮϱ͘ϮϴϱĨŽƌƌŽƚĂƌǇĚƌŝůůŝŶŐƌŝŐŽƉĞƌĂƟŽŶƐĂƉƉůǇ͘ 5. /ĨŶŽƚǁŽƌŬŝŶŐŽŶϮϰ-ŚŽƵƌĐŽŶƟŶƵŽƵƐŽƉĞƌĂƟŽŶĂůƐĐŚĞĚƵůĞ͕ƐŶƵďďŝŶŐƐƚƌŝŶŐŵƵƐƚďĞƌĞŵŽǀĞĚ ĨƌŽŵƚŚĞŚŽůĞŽƌŚƵŶŐŽīin a pipe-ŚĞĂǀǇĐŽŶĚŝƟŽŶ͕ǁŝƚŚƚƌĞĞǀĂůǀĞĂŶĚďůŝŶĚƌĂŵƐĐůŽƐĞĚďĞĨŽƌĞ ƐŚƵƫŶŐĚŽǁŶĨŽƌƚŚĞŶŝŐŚƚ͘ ŶŝŐŚƚǁĂƚĐŚŵĂŶƐŚĂůůďĞŽŶůŽĐĂƟŽŶƚŽŵŽŶŝƚŽƌƚŚĞǁĞůů͘ 6. Well site supervisors shall have ĂĐůĞĂƌƵŶĚĞƌƐƚĂŶĚŝŶŐŽĨƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ/ZWϭϱ͘ϱ͘Ϯ͕ĂŶĚ have an ĂǁĂƌĞŶĞƐƐ of the requirements of /ZWϭϱ͘ ŽĐƵŵĞŶƚĞĚĐŽŶĮƌŵĂƟŽŶŽĨƵŶĚĞƌƐƚĂŶĚŝŶŐ ĂŶĚĂǁĂƌĞŶĞƐƐ to be available upon request. 7. Prior to ƌŝŐŐŝŶŐƵƉŽŶƚŚĞǁĞůů, provide evidence ƚŽK' of: a. WĞůůŚĞĂĚΘƐŶƵďďŝŶŐƐƚĂĐŬƐƚĂďŝůŝǌĂƟŽŶĚĞƐŝŐŶƉĞƌ/ZWϭϱ͘ϰ͘ϭ͘ϮƉƌŝŽƌƚŽƌŝŐŐŝŶŐƵƉŽŶƚŚĞ ǁĞůů͘ Provided 6/19/24 – ĂƩĂĐŚĞĚƚŽƚŚŝƐƐƵŶĚƌǇ͘-bjm b. Well-ƐƉĞĐŝĮĐ,ĂǌĂƌĚƐƐĞƐƐŵĞŶƚƉĞƌ/ZWϭϱ͘ϲ. 8. WƌŝŽƌƚŽĞŶƚĞƌŝŶŐƚŚĞǁĞůůƚŽƉĞƌĨŽƌŵƐŶƵďďŝŶŐŽƉĞƌĂƟŽŶƐ͕ƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞŽĨEmergency Egress System in place ƉĞƌ/ZWϭϱ͘ϴ͘ϯ. Snub in Deep GL insert (AVE) Well: Steelhead M-21 Well Name:M-21 API Number:50-733-20598-00-00 Current Status:Offline Gas Producer Leg:B-2 (NE Corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:211-114 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Jake Flora (720) 988-5375 (c) Maximum Expected BHP:254 psi @ 2,776’ TVD PT gauge on CT at 4120’ MD (2/1/24) Max. Potential Surface Pressure: 0 psi Using 0.1 psi/ft (also observed, passing NFT) Brief Well Summary Steelhead well M-21 was D&C in 2011 as a single A-2 sand gas producer. The well had a static reservoir pressure of only 375psi upon completion. Over the next 9+ years that pressure was slowly depleted to the 254psi measured today. Several BCF of gas were extracted in this time speaking to the very large size of the A- 2 tank. Even a slight lowering of the reservoir pressure in this sand can increase ultimate recovery by large amounts of gas. The well did start cutting water in 2018, but gas rates combined with gas lift was enough to lift the water and sustain 1MM+ of production. In late 2020 the well started falling off, and quickly stopped flowing. Static BHP surveys confirmed that the reservoir pressure now could not support a fluid column up to the deepest GLM. Thus, existing gas lift no longer could help lift the water. The proposed Annular Velocity Enhancement (AVE) System has been primarily used in other basins to dewater gas wells with long perforation intervals. Prime candidates have the need to get gas lift far below the production packer (SPE paper #130256). M-21 should be a great application for this technology by lowering the lift point down to the bottom of the completion.In an effort to avoid loading the well, the completion will be snubbed in. The goal of this project is to lower the lift point via an AVE gas lift system and return M-21 to production Snubbing Specifics: x Operations to be compliant with Canadian DACC IRP 15 x All Must and Shall statements within IRP 15 will be adhered to unless approval obtained from AOGCC to deviate x In the event of conflicting regulations, AOGCC regulations will supersede IRP 15 x Well control regulations per 20 AAC 25.285 for rotary drilling rig operations will apply (BOP stack to include shear / fixed pipe / annular) x Operations shall be 24-hr continuous Snub in Deep GL insert (AVE) Well: Steelhead M-21 Pertinent wellbore information: - Inclination: o Goes beyond 70 degrees at 2950’ MD o 85 degrees throughout screened completion to TD - SSSV o Has 5-1/2” TRSSSV at 444’ MD (out of service) o NFT passed 12/20/20 - Nov-2011 o New drill well o 9-5/8” casing MIT to 3000psi (PASS) o FLCV appears to never have been locked open o FLCV shear disk likely blown, so can inject and not an impedance to production o Live GLV’s installed (plan to leave them installed during this RWO) - Jan-2024 o CT milled out FLCV at 2604’ with 3.40” junk mill and 3.40” string mill o Had some overpulls from 2600’ – 3000’ MD with 3.40” milling BHA afterwards o 2.70” burn shoe and venturi dry drifted to PBTD (4133’ CTMD) with no issues o Performed a pumping / venturi run from top screens to PBTD (same tag depth of 4133’ CTMD) o Venturi only recovered ½ gallon of shavings, sand, and asphaltenes - Feb-2024 o 4.75” gauge ring drifted freely to 5-1/2” SSSV at 444’ MD o 4.52” gauge ring drifted to crossover at 2596’ MD. Had to work through SSSV and X-nipple, but made it o 2.80” gauge ring drifted to 3079’ MD (deviated out) o CMIT-TxIA SL set TTP in X-nipple at 2554’ MD Loaded well with 171 bbls 6% KCL down IA CMIT-TxIA to 1750psi PASSED x Initial T/I: 1760 / 1785 x 15 mins: 1740 / 1740 x 30 mins: 1750 / 1760 (thermal from hot fluid) SSSV Variance Request: Given the passing NFT from 12/20/20, an SSSV shouldn’t be required in this new 2- 7/8” completion string. That being said, Hilcorp is electing to install an SSSV in case well conditions change in the future. The OD of our planned 2-7/8” SSSV is 4.61”. The ID of the existing 5-1/2” SSSV is 4.562”.Given this, Hilcorp request a variance to set a new 2-7/8” SSSV at 420’ MD (±75’ below the mudline). See below for exact depths. Reference KB: 0’ MD / 0’ TVD Mean Sea Level: 160’ MD / 160’ TVD Mudline: 345’ MD / 345’ TVD Existing 5-1/2” SSSV top: 444’ MD / 444’ TVD Variance approved. -bjm Snub in Deep GL insert (AVE) Well: Steelhead M-21 Pre-rig 1. Close lower master valve 2. ND tree leaving the lower master valve. (Will remain as a bottom to test against) 3. NU additional tubing spool to receive 2-7/8” hanger Snubbing Procedure: 1. Prep a. Review sundry b. Review all COA’s c. Review IRP 15, specifically all must and shall statements 2. MIRU PESI snubbing unit (Snubbing International, Alberta, CA: DBA PESI) 3. NU BOP’s a. Notify AOGCC 48 hours in advance for witness b. Will mate directly to new tubing spool c. Remaining lower master valve will act as bottom instead of TWC d. BOP’s will be closed as needed to circulate the well e. Rams needed to handle 2-3/8” and 2-7/8” pipe f. Primary well control BOP’s (below Snubbing BOP’s) will have a shear ram, pipe ram, and annular 4. Test primary and snubbing BOP’s to 250 low / 1500psi high 5. Close Blind rams 6. PU first joint of 2-3/8” with bullnose on bottom (full 30’ joint) 7. Run first joint in to just above closed blind rams, and close stripping annular on 2-3/8” pipe 8. MU and stab a full opening safety valve in the open position 9. Open blind rams and confirm no flow 10. Remove full opening safety valve 11. Snub in 2-3/8” lower completion through stripping annular per below: a. SITP should be 0psi (no flow well) b. Completion to be run with a closed bottom (bull plug) c. GLM will be an internal mount / fixed type with check d. Packer bypass assembly is fixed and cannot be removed (no mechanical passthrough) e. Packer and packer bypass assembly are integral, and will be RIH together f. All depths below are approximate Depth Item ±2,520’ MD On/Off stinger (on top of packer)with 2-7/8” plug installed ±2,525’ MD Packer bypass assembly with mechanical set packer ±4,040’ MD Internal mount fixed GLM with check ±4,100’ MD Bullplug at bottom of insert assembly 12. PU 2-7/8” upper completion per below and snub in hole with On/Off sealing overshot mated to on/off stinger Snub in Deep GL insert (AVE) Well: Steelhead M-21 13. Land on depth per above 14. Set packer (mechanical set) targeting 5-1/2” section between 2546 – 2504’ MD (~58’ window) a. Barriers are now 5-1/2” x 9-5/8” packer, 2-7/8” x 5-1/2” packer, and 2-7/8” tubing plug b. Reservoir is now mechanically isolated c. Snubbing through the stripping annular is no longer required (Plan to not snub through closed stripping BOP’s due to SSSV control line ) 15. Confirm no flow/pressure from 2-7/8” tubing 16. Open stripping annular and confirm no flow/pressure from 2-7/8” x 5-1/2” annulus 17. Release the on/off tool and POOH with 2-7/8” pipe 18. Make up SSSV and control line, and RIH with final 2-7/8” upper completion Depth Item ±420’ MD SSSV ±2,520’ MD On/Off Sealing Overshot 19. Reengage lower completion with on/off overshot 20. Land upper completion, and RILDS 21. ND BOP, NU tree and test 22. Demob snubbing unit and crew Post-rig 1. MIRU SL 2. PT to 250 low / 1500 high 3. RIH and pull plug from 2-7/8” XN profile in top of on/off tool stinger at ±2,520’ MD 4. RDMO SL Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current Wellhead Diagram 4. Proposed Wellhead Diagram 5. Snubbing BOP Drawing 6. IRP15 compliance matrix 7. M-21_AVE_Diagram(2024) 8. RWO Sundry Change Form _____________________________________________________________________________________ Updated By: JLL 02/14/2024 SCHEMATIC Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PBTD: 4,160‘ MD TD: 4,161’ MD MAX HOLE ANGLE = 85.0° @ 3,076 – 4,194’ MD 32” RKB to TBG Head = 78’ 6-3/4” Open Hole 5 3-4 6 7 13-3/8” 9-5/8” 1 2 X 6 7 ECP Stage Collar @ 411 SIZE WT GRADE CONN MIN ID TOP BTM (MD) 32” X-56 Welded 30” Surf 490’ 13-3/8” 68 L-80 BTC 12.415 Surf 1402’ 9 5/8” 47 L-80 DWC 8.681 Surf 3076’ Tubing / Liner Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surf 2,592’ 4-1/2” 12.75 Blank TC-II 3.958” 2,614’ 3,031’ 4” 15.2 Excluder 2000 Screen SLHT 3.54” 3,031’ 3,219’ 4” 9.5 Bakerweld 140 Screen 8 ga. SHLT 3.46” 3,219’ 4,160’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Horizontal screened completion in A2 Sand A2 3,031 4,154 2,673 2,779 Open JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 2,554’ 2,452’ 4.562” 5.937” X-Nipple 3 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 4 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,581’ 2,471' 4.88” 6.65” X-Over6-5’8” SLHT Box X 5-1/2: SLHT PIN 2,582’ 2,472' 4.75” 6.3” Seal Bore Extension 5-1/2” SLHT Pin X Pin 5 2,604’ 2,485’ 3.40" 5.810” Fluid Loss Control Valve (Baker) Flapper milled out to 3.40" 1/30/24 6 4,154’ 2,779’ 1.88” 4.510” O-Ring Seal Sub for Slick Stinger 7 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,463’ 1,445’ 4.892” SFO-2 Mandrel 16 Dome 873 11/06/2011 2 2,485’ 2,401’ 4.892” SFO-2 Mandrel 20 Orifice 11/06/2011 _____________________________________________________________________________________ Updated By: CRR 2/22/24 PROPOSED SCHEMATIC Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PBTD: 4,160‘ MD TD: 4,161’ MD MAX HOLE ANGLE = 85.0° @ 3,076 – 4,194’ MD A 32” RKB to TBG Head = 78’ 6-3/4” Open Hole 3-4 5 6 7 13-3/8” 9-5/8” 1 2 C B X 6 7 ECP Stage Collar @ 411 SIZE WT GRADE CONN ID TOP BTM (MD) 32” X-56 Welded 30” Surf 490’ 13-3/8” 68 L-80 BTC 12.415 Surf 1,402’ 9 5/8” 47 L-80 DWC 8.681 Surf 3,076’ Tubing / Liner / Insert AVE Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surf 2,592’ 4-1/2” 12.75 Blank TC-II 3.958” 2,614’ 3,031’ 4” 15.2 Excluder 2000 Screen SLHT 3.54” 3,031’ 3,219’ 4” 9.5 Bkrweld 140 Screen 8 ga. SHLT 3.46” 3,219’ 4,160’ 2-7/8” 6.5 L-80 EUE 8RD 2.441” Surf ±2,585’ 2-3/8” 4.6 L-80 SUPERMAX SCC 1.995” ±2,585’ ±4,100’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Horizontal screened completion in A2 Sand A2 3,031 4,154 2,673 2,779 Open TUBING / LINER JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 2,554’ 2,452’ 4.562” 5.937” X-Nipple 3 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 4 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,581’ 2,471' 4.88” 6.65” X-Over6-5’8” SLHT Box X 5-1/2: SLHT PIN 2,582’ 2,472' 4.75” 6.3” Seal Bore Extension 5-1/2” SLHT Pin X Pin 5 2,604’ 2,485’ 3.40” 5.810” Fluid Loss Control Valve (Baker)Milled out as of 1/31/24 6 4,154’ 2,779’ 1.88” 4.510” O-Ring Seal Sub for Slick Stinger 7 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe INSERT AVE JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description A ±420’ ±420' 2.312” 4.61” SSSV B ±2,520’ ±2,427' 2.205” 4.50” On / Off Tool (has 2-7/8” XN profile in stinger) C ±2,525’ ±2,431' n/a 4.50” Packer bypass assembly with mechanical set packer GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,463’ 1,445’ 4.892” SFO-2 Mandrel 16 Dome 873 11/06/2011 2 2,485’ 2,401’ 4.892” SFO-2 Mandrel 20 Orifice 11/06/2011 3 ±4,040’ ±2,769' n/a Internal Mount Fixed 24 Orifice Future Steelhead Platform M-21 Current 02/14/2024 Valve, Master, WKM-M, 5 1/8 5M FE, HWO, EE trim Valve, Upper master, SSV, WKM-M, 5 1/8 5M FE, HWO, w/ 18'’ operator, EE trim Valve, Swab, WKM-M 5 1/8 5M FE, HWO, EE trim BHTA, Otis, 5 1/8 5M FE x 9.5'’ Otis quick union top Valve, Wing, SSV, WKM-M, 5 1/8 5M FE, w/ 18'' operator 13 3/8'’ 9 5/8'’ 5 ½’’ Steelhead Platform M-21 28 x 13 3/8 x 9 5/8 x 5 1/2 Tubing hanger, Vetco-MB 242, 13 5/8 5M x 5 ½ TC-2 susp x 5.790 MCA lift, w/ 5'’ type H BPV profile, 2- ½ npt control line ports Starting head, Vetco MB-246, 20 ¾ 3M NT-2 top x 28'’ BW bottom, w/ 2- 3'’ LPO and 6'’ ANSI 600 outlets Multibowl system, Vetco MB-242, 13 5/8 5M Flanged top x 20 ¾ 3M NT-2 bottom, Steelhead Platform M-21 Proposed 05/30/2024 13 3/8'’ 9 5/8'’ 5 ½’’ Steelhead Platform M-21 28 x 13 3/8 x 9 5/8 x 5 ½ x 2 7/8 Tubing hanger-Lower, Vetco-MB 242, 13 5/8 5M x 5 ½ TC-2 susp x 5.790 MCA lift, w/5'’ type H BPV profile, 2- ½ npt control line ports Starting head, Vetco MB-246, 20 ¾ 3M NT-2 top x 28'’ BW bottom, w/ 2-3'’ LPO and6'’ ANSI 600 outlets Multibowl system, Vetco MB-242, 13 5/8 5M Flanged top x 20 ¾ 3M NT-2 bottom, Attachment spool, Cactus- TCM, 7 1/16 5M FE top x 5 1/8 5M FE bottom, w/2- 2 1/16 5M SSO, no bottom prep Adapter, Cactus-EN-CCL, 7 1/16 5M Stdd x 3 1/8 5M prepped for 5 ½ extended neck hanger 2 7/8'’ Tubing hanger-upper, Cactus TC-EN-CL, 7 x 3 1/2 EUE 8rd lift and susp, w/ 3'’ type H BPV- 1 non cont control line port 3 1/8 5M production tree assy IRP Chapter / Component Compliance Requirement IRP 15.01.07 BHA components fit in snubbing stack Stack heigth between gate valve & snubbing annular >> Longest BHA to be snubbed (12'). Minnium one plug in tubing GLV has check and prevent inflow. Bottom of assembly will be a bullplug. On/off tool stinger will have a plug pre-installed. IRP 15.01.08 Snubbing forces calculated on site Will be done on site, Hilcorp responsibility with TSI input Tubing buckling calculations Will be done on site, Hilcorp responsibility with TSI input Pipe heavy calculations done for MPSP No flow well, with SITP = 0psi, so should be pipe heavy the whole time. SITP to be verified by site supervisor, and pipe calcs redone. Tubing hanger calculations Will be done on site, Hilcorp responsibility with TSI input Rotary torque calculations Will be done on site, Hilcorp responsibility with TSI input IRP 15.01.08.02 Prejob calculations Will be done on site, Hilcorp responsibility with TSI input IRP 15.01.09.01 Explosive mixture in casing Equalize to bleed line to purge the stack IRP 15.01.12 Supervisory control Hilcorp Wellsite Manager (WSM) IRP 15.02.01 Plugs shall be tested to 1.3x BHP (1.3 x 254 psi = 330psi). Bull plug, GLM, and TTP in on/off stinger will be tested to 1500psi before RIH. IRP 15.03.01 Regulatory requirements must be followed for all primary BOP equipment AOGCC Regulation/BOP test Install shear ram as the lowest primary BOP Blind shear ram in lowermost position planned per sundry Minimum of one hole volume on site Hilcorp will have TSI's pump, and unlimited filtered inlet water on location IRP 15.06.01 Hazard Assesments PJSM will review hazard assesments per TSI JSA / SOP for Tripping Pipe Into Wellbore IRP 15.06.02 Hazards PJSM will review IRP 15.06.02 Table 8 Hazard Register IRP 15.07.2 Joint Safety Meetings Hilcorp WSM will hold JSM prior to performing work with all vendors on site. Agenda will include a risk assesment, specific safety requirements, supervisory control, well shut in procedures, responsibllities, egress, and SIMOPS. IRP 15.08.02 Pre-job calculations Will be done on site, Hilcorp responsibility with TSI input IRP 15.08.04 Primary BOPE tested per regulations AOGCC witnessed BOP test IRP 15.08.05 Contingency Practices PJSM will review different failure mechanisms and the corrective action to then take place as detailed in IRP 15.8.5 IRP 15.08.09 Setting Jack Pressure Follow steps 1-11 in IRP 15.8.9 to set hydraulic jack pressure IRP 15.08.13 Landing tubing hanger Hilcorp WSM & TSI supervisor will ensure tubing hanger lock down screws are fully engaged & pull test is completed prior to bleeding off stack pressure above Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: Trading Bay Unit M-21 (PTD 211-114)Sundry #: xxx-xxxAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date (1(5*<6(59,&(6,&21ϬΗ<,/',dEKd͗/E^d>>>dKDK>ϭϰϬϵϭϬd/KtE>h'^^D>z͘dzWYdzϰEKd͗h^KD'hzt/ZE,KZWK/Ed^ϯϴΖϬΗϯϴΖϬΗ'hz'hz'hz&'hz'hz'hz''hz,'hzEKd͗Z&ZdKKD^W^&KZ'/EWK>'hzt/ZZYh/ZDEd^EKd͗^hZdK:<ͲhWD^t/d,DK>ϭϮϳϱϮϮE,KZ͘dzWYdzϰy'hz>/E^W^yWd>KdE^/KE^KEW/t/EWZK&/>^Λϭϰϱ&dKstdZEϭ͕ϬϬϬ>&WZͲdE^/KE͘h^ϯͬϰ/tZ/W^ϲyϭϵt/ZZKWKZYh/s>Ed'hzt/ZWWZKy/Dd>E'd,^d/DdW<dE^/KEϰϬ&dϳ͕ϭϬϬ>&ϰϬ&dϳ͕ϯϬϬ>&ϰϬ&dϲ͕ϮϱϬ>&ϰϬ&dϲ͕ϭϬϬ>&Ϯϲ&dϭϬ͕ϮϬϬ>&&Ϯϲ&dϵ͕ϲϬϬ>&'Ϯϲ&dϵ͕ϱϬϬ>&,Ϯϲ&dϵ͕ϱϬϬ>&6'a2))6+25(B*8</,1(6ϭK&ϭZs͗%ZtE͗,<͗WWZKs͗d͗^,d^/͗WZK:d/KE͗ͲͲͲͲͲͲ&/>͗d/d>͗^,dd/d>͗^>^t't'η͗ϮϬϮϰͲϬϲͲϭϴd,/E&KZDd/KE/E>h/Ed,/^KhDEd/^WZKWZ/dZzE^,>>EKdZWZKh͕dZE^&ZZ͕KZ/^>K^dKKd,Z^͕&KZEzWhZWK^t,d^KsZ͕t/d,Khdd,tZ/ddEhd,KZ/d/KEK&/KEEZ'z^Zs/^͘Ϯϯϱϱϭ͘ϬϮϱ>td͗d^ͲϭϬϮDK<ͲhWϮϭϰϳϬ^,d͗ 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,161 feet N/A feet true vertical 2,776 feet N/A feet Effective Depth measured 4,160 feet 2,576 feet true vertical 2,780 feet 2,468 feet Perforation depth Measured depth 3,031 - 4,154 feet True Vertical depth 2,673 - 2,779 feet Tubing (size, grade, measured and true vertical depth) 5-1/2" L-80 2,700 (MD) 2,543 (TVD) 2,576 (MD) 444 (MD) Packers and SSSV (type, measured and true vertical depth) SC-1R 2,468 (TVD) SP-TRSV 444 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Middle Kenai Gas 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: Other: N2 Operations 88 323-651 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Ryan Rupert Ryan.Rupert@hilcorp.com 907 777-8503Operations Manager N/A measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD N/A 0 Size 490 0480 0 220 13-3/8" 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 211-114 50-733-20598-00-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0018730 McArthur River / Middle Kenai Gas Trading Bay Unit M-21 Plugs Junk measured Length measured TVD Production Liner 3,076 1,110 Casing Structural 2,683 4" 3,076 4,171 2,781 490 1,402 490Conductor Surface Intermediate 32" 4,760psi 5,020psi 6,870psi 1,402 1,388 Burst Collapse 2,260psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Kayla Junke at 1:35 pm, Feb 15, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.02.14 15:56:21 - 09'00' Dan Marlowe (1267) DSR-2/15/24 RBDMS JSB 022824 _____________________________________________________________________________________ Updated By: JLL 02/14/2024 SCHEMATIC Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PBTD: 4,160‘ MD TD: 4,161’ MD MAX HOLE ANGLE = 85.0° @ 3,076 – 4,194’ MD 32” RKB to TBG Head = 78’ 6-3/4” Open Hole 5 3-4 6 7 13-3/8” 9-5/8” 1 2 X 6 7 ECP Stage Collar @ 411 SIZE WT GRADE CONN MIN ID TOP BTM (MD) 32” X-56 Welded 30” Surf 490’ 13-3/8” 68 L-80 BTC 12.415 Surf 1402’ 9 5/8” 47 L-80 DWC 8.681 Surf 3076’ Tubing / Liner Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surf 2,592’ 4-1/2” 12.75 Blank TC-II 3.958” 2,614’ 3,031’ 4” 15.2 Excluder 2000 Screen SLHT 3.54” 3,031’ 3,219’ 4” 9.5 Bakerweld 140 Screen 8 ga. SHLT 3.46” 3,219’ 4,160’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Horizontal screened completion in A2 Sand A2 3,031 4,154 2,673 2,779 Open JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 2,554’ 2,452’ 4.562” 5.937” X-Nipple 3 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 4 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,581’ 2,471' 4.88” 6.65” X-Over6-5’8” SLHT Box X 5-1/2: SLHT PIN 2,582’ 2,472' 4.75” 6.3” Seal Bore Extension 5-1/2” SLHT Pin X Pin 5 2,604’ 2,485’ 3.40" 5.810” Fluid Loss Control Valve (Baker) Flapper milled out to 3.40" 1/30/24 6 4,154’ 2,779’ 1.88” 4.510” O-Ring Seal Sub for Slick Stinger 7 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,463’ 1,445’ 4.892” SFO-2 Mandrel 16 Dome 873 11/06/2011 2 2,485’ 2,401’ 4.892” SFO-2 Mandrel 20 Orifice 11/06/2011 Well Name:MRF M-21 API #:50733205980000 Field:McArthur River Start Date:1/26/2024 Permit #:211114 Sundry #:323-651 End Date:2/3/2024 1/26/2024 1/27/2024 1/28/2024 1/29/2024 1/30/2024 1/31/2024 Activity Report Complete PTW & PJSM w/rig crew. Completed BOPE test as per sundry 250 psi low / 2500 psi high. AOGCC waived witness (Kam StJohn 1/27/24 17:00 pm). P/U 32' of 4-1/6" flanged riser and transfer to rig floor w/crane. N/D tree cap flange and N/U riser to wellhead. P/U BOPE and transfer to rig cellar w/crane and rig cellar bridge cranes. N/U BOPE in rig cellar to riser on WH. R/U high pressure kelly hose from choke to P-sub in cellar. P/U 33' of 4-1/16" riser and transfer to rig floor using crane and rig tugger. Install riser on BOPE stack through rig floor. SDFN. Complete PTW & PJSM w/rig crew. M/U injector hoses and reel extensions to injector head. Function test injector head. Stab pipe. P/U injector head w/crane and transfer to rig floor. Take control of injector head w/top drive and release crane. M/U Baker CTC and pull test 20k. Stab on well & secure. SDFN. Continue RDMO SLB CTU #1 off M-20. R/D all 2" 1502 surface lines and high pressure kelly hoses. N/D BOPE stack. Move SLB CTU #1 and support equipment to M-21 utilizing crane. SDFN. Continue MIRU SLB CTU #1. Spot BOPE, choke skid, and N2 tanks w/crane. Prep to BOPE test. Troubleshoot SLB generator and change out fuel pump w/mechanic assistance. Troubleshoot SLB pump. AOGCC Kam StJohn waived witness 17:00 pm and left platform due to SLB equipment issues. SLB 8 hrs NPT. SDFN. Complete PTW & PJSM. PT MHA, PCE, IRV, and DBPV. M/U and RIH w/Baker milling BHA = 3.40" string mill & 3.40" junk mill. Milled through FLCV @ 2,577' ctm (top sub, flapper, and bottom sub). Dry drift FLCV multiple times w/no issues. Dry drift in hole and tag/stall at 2,703' ctm, 2,750' ctm, and 2,830' ctm. Appear to be pushing debris in hole. Over pull 10k and pull free. Running low on water in rig pits, Pooh w/BHA. Wrap reel and install heaters. SDFN. Daily Operations: Complete PTW / PJSM. B/D Baker milling BHA. M/U & RIH w/Baker Venturi w/2.70" burn shoe. Dry tag PBTD w/no issues @ 4,133' CTM / 4,160' MD. PUW off bottom 11k. PUH to 2500' ctm, establish venturi baseline parameters. Work venturi down to PBTD 4,133' CTM / 4,160' MD. Pooh w/BHA. On surface w/venturi, recovered 1/2 gallon of shavings, sand, and asphaltines. Stab on well w/N2 BHA w/Pollard tandem Pressure/Temperature gauges. Blow down reel w/N2. SDFN. Page 1 of 2 Well Name:MRF M-21 API #:50733205980000 Field:McArthur River Start Date:1/26/2024 Permit #:211114 Sundry #:323-651 End Date:2/3/2024 2/1/2024 2/2/2024 2/3/2024 Activity Report Daily Operations: Complete PTW & PJSM. RIH w/checks, stinger, ported sub and Pollard 1.75" bailer w/tandem Press/Temp gauges. Reciprocate pipe 4,115' - 4,075'. Online w/N2 down coil @ 350 scfm. SLB troubleshooting N2 pump, unable to keep pump running. Decision to Pooh w/BHA and secure well. SLB mechanic scheduled to come out on the morning chopper. SDFN. Complete PTW & PJSM. SLB mechanic arrived on location and assessed N2 pump, decision made by SLB not to proceed w/N2 pump. Begin RDMO SLB CTU # 1. B/D BHA. R/D surface 2" 1502 lines. SDFN. SLB Zero Rate for the day. Complete PTW & PJSM w/rig. RDMO SLB CTU #1. Pick injector head w/top drive and transfer to crane, lay down injector on deck. Pull risers & BOPE from rig using platform crane. Unstab pipe from injector head. R/D injector head hose extensions and hoses. N/U tree cap flange to WH. SLB CTU rig down complete. SDFN. Page 2 of 2 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Eli Wilson - (C) To:Regg, James B (OGC) Cc:Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay Subject:MRF M-21 Coil Tubing 10-424 Form, 1/30/24 Date:Tuesday, January 30, 2024 9:44:37 PM Attachments:image001.png SLB CTU #1 Coil BOPE Test Form 1-30-24.xlsx Some people who received this message don't often get email from eli.wilson@hilcorp.com. Learn why this is important All, See attached SLB CTU # 1 Coiled Tubing BOPE test form for MRF M-21 completed on 1/30/24. Thanks, Eli Wilson Wellsite Supervisor, GPB / CIO / KEN Hilcorp Wells Group Cell: 907-342-9840 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 7UDGLQJ%D\81LW0 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:1 DATE: 1/30/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #22111140 Sundry #323651 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:N/A Valves:250/2500 MASP:976 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.NA Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Water Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75" Top Load P Trip Tank NA NA Annular Preventer 0NAPit Level Indicators NA NA #1 Rams 1 1.75" Blind/Shear P Flow Indicator NA NA #2 Rams 1 1.75" Pipe/Slip P Meth Gas Detector NA NA #3 Rams 0NAH2S Gas Detector NA NA #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2" 2x2 FMC P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)2900 P Kill Line Valves 2 2" 2x2 FMC P Pressure After Closure (psi)2250 P Check Valve 1 2" FMC P 200 psi Attained (sec)29 P BOP Misc 2 EQ Ports P Full Pressure Attained (sec)86 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6 @ 1400 psi NA No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer NA #1 Rams 27 P Coiled Tubing Only:#2 Rams 23 P Inside Reel valves 1P #3 Rams NA #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:0 Test Time:5.5 HCR Choke NA Repair or replacement of equipment will be made within days. HCR Kill NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/25/24 (16:16pm) Waived By Test Start Date/Time:1/28/2024 8:00 (date) (time)Witness Test Finish Date/Time:1/30/2024 11:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Kam StJohn SLB 6 bottles @ 1400 psi pre charge. Started BOPE test on 1/28/24 on test stand 08:00am - 12:00pm. Rigged up to well on the drilling rig 1/29/24. Completed remaining BOPE tests (Stripper / IRV / Checks) on the well 1/30/24. 5.5 hrs of total test time. Bryson Lowe Hilcorp Alaska LLC Eli Wilson TBU M-21 Test Pressure (psi): Blowe2@slb.com eli.wilson@hilcorp.com Form 10-424 (Revised 08/2022)2024-0130_BOP_SLB1_TBU_M-21 9 9 9 99 9 9 9 9 9 -5HJJ 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): 4,161 N/A Casing Collapse Structural Conductor Surface 2,260psi Intermediate Production 4,760psi Screen 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: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone: 907-777-8503 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 Other: CT Operations / N2 SC-1R & SP-TRSV 2,576 (MD) 2,468 (TVD) & 444 (MD) 444 (TVD) CO 228A 3,076' Perforation Depth MD (ft): 3,031 - 4,154 3,076' 4" 2,673 - 2,779 4,171'1,110' 5-1/2" 2,683'9-5/8" 2,781' 32" 13-3/8" 490' 1,402' MD 5,020psi 490' 1,388' 490' 1,402' Length Size Proposed Pools: L-80 TVD Burst 2,700 6,870psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 211-114 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20598-00-00 Hilcorp Alaska, LLC Trading Bay Unit M-21 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 12/20/2023 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 McArthur River Middle Kenai Gas Same 2,776 4,160 2,780 976psi N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2023.12.06 15:54:57 - 09'00' Dan Marlowe (1267) 323-651 By Grace Christianson at 7:46 am, Dec 07, 2023 X CT BOP test to 2500 psi SFD 12/11/2023BJM 12/11/23 DSR-12/8/23 10-404 *&:JLC 12/11/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.12.11 15:47:42 -09'00'12/11/23 RBDMS JSB 121223 CT Mill out + Perfs Well: Steelhead M-21 Well Name:M-21 API Number:50-733-20598-00-00 Current Status:Offline Gas Producer Leg:Leg B2 (NE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:211-114 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:1,254 psi @ 2,786’ TVD 0.45psi/ft to deepest TVD Max. Potential Surface Pressure: 976 psi Using 0.1 psi/ft Brief Well Summary Gas producer M-21 has been offline since 2021 due to declining reservoir pressure and water production. Earlier in 2023 a perforation sundry was approved to try and add sands above the screens and restore the well to production. Initial SL drifts were unsuccessful and indicated that the FLCV was in fact not locked out as thought. This valve not being locked out allowed it to free float, so it could be produced through, but prevented downhole mechanical access. The proposed scope of work below aims to fill out the FLCV flapper, and opportunistically perform a deep nitrogen lift production test. If successful, an insert artificial lift may be pursued in the future and would be the subject of a subsequent sundry. The scope below included an EL step to perforate unshot zones after the FLCV mill out is complete. All proposed perforations below are within the Middle Kenai Gas Pool. The goal of this project is to restore liner access, perform a deep lift production test with nitrogen, and perforate unshot uphole sands. Pertinent wellbore information: - TRSSSV installed - Live GLV’s currently installed -FLCV installed at 2604’ MD - Pertinent wellwork o 9/22/23 SL drifts SL makes it down with a 20’ x 2-7/8” dummy gun assembly Deviates out at 2851’ MD Hangs up around FLCV on way out of hole Multiple additional drift attempts, and can’t fall past 2626’ SLMD o 10/24/23: SL LIB tag SL drifts with LIB Tags at 2627’ SLMD Clear impression of FLCV flapper (closed) o Nov-2023: Attempted to fluid load wellbore and lockout FLCV Pumped >600bbls into well, and couldn’t get a seal WBV above flapper is <175bbls FLCV flapper is either not sealing, or shear port has been failed Concur. SFD All proposed perforations below are within the Middle Kenai Gas Pool. o perforate unshot zones a CT Mill out + Perfs Well: Steelhead M-21 Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 1500psi high 3. MU Millout BHA 4. RIH to 2604’ MD and mill out FLCV a. Working fluid will be water (8.33ppg or greater) b. FLCV flapper closes downward c. Even when closed, FLCV does not hold pressure (shear disk likely blown) d. Mill per Baker recommendations e. Can use GL to assist with hole cleaning 5. MU screened liner cleanout assembly 6. RIH with BHA and mill / cleanout screened liner as deep as practical (target depth 4150’ MD) 7. MU nitrogen BHA and run to PBTD a. Initiate production test pumping N2 down the CT b. Take returns up the CT x Tubing annulus c. Pump at varying n2 rates per OE, and collect production rate data 8. RDMO CT E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 1500psi high 3. RIH and perforate Middle Kenai gas Pool sands from ±2,600 – ±3,076 MD (±2,481 – ±2,690 TVD) per RE/Geo 4. RDMO EL Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOP Drawing 4. Nitrogen procedure Test BOPs to 2500 psi. -bjm _____________________________________________________________________________________ Updated By: JLL 12-06-23 SCHEMATIC Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PBTD: 4,160‘ MD TD: 4,161’ MD MAX HOLE ANGLE = 85.0° @ 3,076 – 4,194’ MD 32” RKB to TBG Head = 78’ 6-3/4” Open Hole 3-4 5 6 7 13-3/8” 9-5/8” 1 2 X 6 7 ECP Stage Collar @ 411 SIZE WT GRADE CONN MIN ID TOP BTM (MD) 32” X-56 Welded 30” Surf 490’ 13-3/8” 68 L-80 BTC 12.415 Surf 1402’ 9 5/8” 47 L-80 DWC 8.681 Surf 3076’ Tubing / Liner Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surf 2,592’ 4-1/2” 12.75 Blank TC-II 3.958” 2,614’ 3,031’ 4” 15.2 Excluder 2000 Screen SLHT 3.54” 3,031’ 3,219’ 4” 9.5 Bakerweld 140 Screen 8 ga. SHLT 3.46” 3,219’ 4,160’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Horizontal screened completion in A2 Sand A2 3,031 4,154 2,673 2,779 Open JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 2,554’ 2,452’ 4.562” 5.937” X-Nipple 3 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 4 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,581’ 4.88” 6.65” X-Over6-5’8” SLHT Box X 5-1/2: SLHT PIN 2,582’ 4.75” 6.3” Seal Bore Extension 5-1/2” SLHT Pin X Pin 5 2,604’ 2,485’ 3.31” 5.810” Fluid Loss Control Valve (Baker) 6 4,154’ 2,779’ 1.88” 4.510” O-Ring Seal Sub for Slick Stinger 7 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,463’ 1,445’ 4.892” SFO-2 Mandrel 16 Dome 873 11/06/2011 2 2,485’ 2,401’ 4.892” SFO-2 Mandrel 20 Orifice 11/06/2011 _____________________________________________________________________________________ Updated By: JLL 12/06/23 PROPOSED SCHEMATIC Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PBTD: 4,160‘ MD TD: 4,161’ MD MAX HOLE ANGLE = 85.0° @ 3,076 – 4,194’ MD 32” RKB to TBG Head = 78’ 6-3/4” Open Hole 5 3-4 6 7 13-3/8” 9-5/8” 1 2 X 6 7 ECP Stage Collar @ 411 SIZE WT GRADE CONN MIN ID TOP BTM (MD) 32” X-56 Welded 30” Surf 490’ 13-3/8” 68 L-80 BTC 12.415 Surf 1402’ 9 5/8” 47 L-80 DWC 8.681 Surf 3076’ Tubing / Liner Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surf 2,592’ 4-1/2” 12.75 Blank TC-II 3.958” 2,614’ 3,031’ 4” 15.2 Excluder 2000 Screen SLHT 3.54” 3,031’ 3,219’ 4” 9.5 Bakerweld 140 Screen 8 ga. SHLT 3.46” 3,219’ 4,160’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Horizontal screened completion in A2 Sand SZ – A1 ±2,600 ±3,076 ±2,481 ±2,690 ±476 Future Proposed A2 3,031 4,154 2,673 2,779 Open JEWELRY DETAIL Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 2,554’ 2,452’ 4.562” 5.937” X-Nipple 3 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 4 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,581’ 4.88” 6.65” X-Over6-5’8” SLHT Box X 5-1/2: SLHT PIN 2,582’ 4.75” 6.3” Seal Bore Extension 5-1/2” SLHT Pin X Pin 5 2,604’ 2,485’ >3.70” 5.810” Fluid Loss Control Valve (Baker)To be milled out 6 4,154’ 2,779’ 1.88” 4.510” O-Ring Seal Sub for Slick Stinger 7 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,463’ 1,445’ 4.892” SFO-2 Mandrel 16 Dome 873 11/06/2011 2 2,485’ 2,401’ 4.892” SFO-2 Mandrel 20 Orifice 11/06/2011 SLB Stack Drawing Not Drawn To Scale--- For Reference Only 2 1/16 10M Flanged Plug Valve (Manual) from KP Well Floor HR 580 Injector Head with 72" Gooseneck 4.06" 10K Conventional Stripper – 1.75" C062 Pin Connection Manual 2 1/16 10M Provided by client Blind/Shear Pipe/Slip 4 1/16 10M Combi BOP Lubricator to Injector Head 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. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Christianson, Grace K (OGC) To:Brooks, James S (OGC) Subject:FW: Withdraw Sundry # 323-518 - Trading Bay Unit M-21 / PTD: 211-114 Date:Friday, November 17, 2023 7:42:51 AM FYI From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, November 16, 2023 3:24 PM To: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Subject: Fwd: Withdraw Sundry # 323-518 - Trading Bay Unit M-21 / PTD: 211-114 Grace, see below request Bryan Sent from my iPhone Begin forwarded message: From: Juanita Lovett <jlovett@hilcorp.com> Date: November 16, 2023 at 3:38:35 PM PST To: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov>, Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: Withdraw Sundry # 323-518 - Trading Bay Unit M-21 / PTD: 211-114 Bryan, Please withdraw the above-mentioned sundry. The work will not be performed at this time. The scope of work was to add perforations. Thank you, Juanita L Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 | Anchorage | AK | 99503 (907) 777-8332 | jlovett@hilcorp.com 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9.Property Designation (Lease Number):10.Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 4,161 N/A Casing Collapse Structural Conductor Surface 2,260psi Intermediate Production 4,760psi Screen 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: Karson Kozub Contact Email:kkozub@hilcorp.com Contact Phone: 907-570-1801 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 McArthur River Middle Kenai Gas Same 2,776 4,160 2,780 946psi N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 9/25/2023 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 211-114 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20598-00-00 Hilcorp Alaska, LLC Trading Bay Unit M-21 Length Size Proposed Pools: L-80 TVD Burst 2,700 6,870psi MD 5,020psi 490' 1,388' 490' 1,402' 32" 13-3/8" 490' 1,402' 2,673 - 2,779 4,171'1,110' 5-1/2" 2,683'9-5/8" 2,781' SC-1R & SP-TRSV 2,576 (MD) 2,468 (TVD) & 444 (MD) 444 (TVD) CO 228A 3,076' Perforation Depth MD (ft): 3,031 - 4,154 3,076' 4" No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:22 am, Sep 12, 2023 323-51 8 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2023.09.11 13:53:08 - 08'00' Dan Marlowe (1267) SFD 9/13/2023 10-404 DSR-9/12/23BJM 9/14/23*&:JLC 9/14/2023 09/15/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.15 07:46:37 -08'00' RBDMS JSB 091523 Perf add Well: M-21 Well Name:M-21 API Number:50-733-20598-00-00 Current Status:SI Gas Producer Permit to Drill Number:211-114 First Call Engineer:Karson Kozub (907) 570-1801 (c)Leg B-2 (NE corner) Second Call Engineer:Ryan Rupert (907) 301-1736 (c) Maximum Expected BHP:1224 psi @ 2,780’ TVD 0.44psi/ft to deepest open pay Max. Potential Surface Pressure: 946 psi Using 0.1 psi/ft Brief Well Summary M-21 on the Steelhead platform is a shut in Middle Kenai Gas Pool Producer open in the A2 sand. Production died off in early 2021 and the well has be SI since. The goal of this project is to add perfs to return the well to production. All proposed perfs remain within the Middle Kenai Gas Pool Pertinent wellbore information: - SSSV: Tubing retrievable (functional) - Inclination: o Goes >70 degrees at ~3000’ MD o Goes >80 degrees at ~3100’ MD o Goes >85 degrees at ~3273’ MD o - 10/13/2017 o Slickline unable to fall deeper than 2,625’ Pre-Sundry work 1. Slickline runs as needed to evaluate wellbore E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 1500psi high 3. RIH and perforate SZ & A1 sands from ±2,576 – ±3,076 MD (±2,468 – ±2,690 TVD) per RE/Geo a. * other E-line logs may be run as needed to evaluate wellbore 4.RDMO EL Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic All proposed perfs remain within the Middle Kenai Gas Pool Updated by: JLL 09-09-23 Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 SCHEMATIC MAX HOLE ANGLE = 85.0q @ 3,076’ – 4,194’ MD PBTD: 4,160’ MD (2,780’ TVD) TD: 4,161’ MD (2,780’ TVD) 1 Reservoir Information Screened completion from 3,031 – 4,154’ MD (2,673’ – 2,779’ TVD) Horizontal in A2 Sand Completion Equipment Information Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 1,463’ 1,445’ 4.892” 8/6.125” SFO-2 Mandrel 2,485’ 2,401’ 4.892” 8/6.125” SFO-2 Mandrel 3 2,554’ 2,452’ 5.937” 4.562” X-Nipple 4 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,585’ 2,473’ 4.750” 6.3” Seal Bore Extension 5 2,604’ 2,485’ 3.31” 5.810” Fluid Loss Control Valve (Baker)Supposed to be locked open as of 2011 2,614’ 2,492’ 3.958” 4.52” 4.5”,12.75 lb/ft TC-II Blank Pipe 3,031’ 2,673’ 3.48” 4.74” 4” Excluder ( Medium) Screen 3,219’ 2,701’ 3.54” 4.52” 4” BakerWeld 140 Screen 8 gauge 4,154’ 2,779’ 1.88” 4.510” Pack Off Sub for Slick Stinger 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe Casing Detail SIZE WT GRADE CONN MIN ID TOP BTM (MD) BTM (TVD) 32” X-56 Welded 30” Surface 490’ 490’ 13-3/8” 68 L-80 BTC 12.415 Surface 1402’ 1377’ 9 5/8” 47 L-80 DWC 8.681 Surface 3076’ 2690’ 4” 15.2 screen SLHT 3.54 3061’ 4171’ 2774’ Tubing Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surface 2700’ 2565’ ECP Stage Collar @ 411 32” Conductor 13 3/8” in 17 ½” Hole 9 5/8” Casing SC-1R Packer 4.0” Excluder Screen 4.0” BakerWeld Screen RKB to TBG Head = 78’ GP Shoe Pack Off Sub FLCV Valve 6 3/4” Open Hole X Updated by: JLL 09-09-23 Steelhead Platform Well M-21 Completed: 11/06/2011 PTD: 211-114 API: 50-733-20598-00 PROPOSED MAX HOLE ANGLE = 85.0q @ 3,076’ – 4,194’ MD PBTD: 4,160’ MD (2,780’ TVD) TD: 4,161’ MD (2,780’ TVD) 1 Reservoir Information Screened completion from 3,031 – 4,154’ MD (2,673’ – 2,779’ TVD) Horizontal in A2 Sand Completion Equipment Information Item Depth MD Depth TVD ID OD Description 73.24’ 73.24’ 4.90” 13.375” Hanger – Vetco CWC-T 1 444’ 444’ 4.562” 7.69” Halliburton SP-TRSV 2 1,463’ 1,445’ 4.892” 8/6.125” SFO-2 Mandrel 2,485’ 2,401’ 4.892” 8/6.125” SFO-2 Mandrel 3 2,554’ 2,452’ 5.937” 4.562” X-Nipple 4 2,572’ 2,465’ 3.43” 6.000” S-22 Snap Latch seal assembly w/ ratcheting muleshoe 2,576’ 2,468’ 4.750” 8.43” Baker SC-1R Gravel Packer 2,585’ 2,473’ 4.750” 6.3” Seal Bore Extension 5 2,604’ 2,485’ 3.31” 5.810” Fluid Loss Control Valve (Baker)Supposed to be locked open as of 2011 2,614’ 2,492’ 3.958” 4.52” 4.5”,12.75 lb/ft TC-II Blank Pipe 3,031’ 2,673’ 3.48” 4.74” 4” Excluder ( Medium) Screen 3,219’ 2,701’ 3.54” 4.52” 4” BakerWeld 140 Screen 8 gauge 4,154’ 2,779’ 1.88” 4.510” Pack Off Sub for Slick Stinger 4,160’ 2,780’ NA 4.49” GP Wash Down Shoe Casing Detail SIZE WT GRADE CONN MIN ID TOP BTM (MD) BTM (TVD) 32” X-56 Welded 30” Surface 490’ 490’ 13-3/8” 68 L-80 BTC 12.415 Surface 1402’ 1377’ 9 5/8” 47 L-80 DWC 8.681 Surface 3076’ 2690’ 4” 15.2 screen SLHT 3.54 3061’ 4171’ 2774’ Tubing Detail 5-1/2” 17.0 L-80 TC-II 4.892” Surface 2700’ 2565’ ECP Stage Collar @ 411 32” Conductor 13 3/8” in 17 ½” Hole 9 5/8” Casing SC-1R Packer 4.0” Excluder Screen 4.0” BakerWeld Screen RKB to TBG Head = 78’ GP Shoe Pack Off Sub FLCV Valve 6 3/4” Open Hole X PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status SZ Thru A-1 ±2,576’ ±3,076' ±2,468’ ±2,690' ±500' Future Proposed THE STATE 01AI.As� GOVERNOR MIKE DUNITAVY December 23, 2020 Mr. Dan Marlowe Operations Manager — Cl Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No -Flow Verification Trading Bay Unit M-21 PTD 2111140 Dear Mr. Marlowe: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov On December 20, 2020 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no -flow test of Trading Bay Unit M-21 located on the Steelhead Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10- 004 — was rigged up on Trading Bay Unit M-21 prior to the test. The well performance was monitored for approximately 3 hours consisting of flow rate checks each preceded by 1 -hour pressure build up periods. Gas flow rates were unmeasurable once the well was open to flow through the test equipment. There was no liquid flow to surface during the no -flow test. Trading Bay Unit M-21 may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit M-21 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a new no -flow test. Please retain a copy of this letter on the Steelhead Platform. Sincerely, James B. Regg0 Digitally signed James B. Regg Date: 2020.12.23 07:50:13 -09'00' James B. Regg Petroleum Inspection Supervisor ecc: Eric Boudreaux, Hilcorp (eboudreauxkhilcorp.com) P. Brooks AOGCC Inspectors Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov December 23, 2020 Mr. Dan Marlowe Operations Manager – CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Trading Bay Unit M-21 PTD 2111140 Dear Mr. Marlowe: On December 20, 2020 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit M-21 located on the Steelhead Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment – as outlined in AOGCC Industry Guidance Bulletin 10- 004 – was rigged up on Trading Bay Unit M-21 prior to the test. The well performance was monitored for approximately 3 hours consisting of flow rate checks each preceded by 1-hour pressure build up periods. Gas flow rates were unmeasurable once the well was open to flow through the test equipment. There was no liquid flow to surface during the no-flow test. Trading Bay Unit M-21 may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit M-21 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a new no-flow test. Please retain a copy of this letter on the Steelhead Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: Eric Boudreaux, Hilcorp (eboudreaux@hilcorp.com) P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2020.12.23 07:50:13 -09'00' I 51/L u-zi M zt(ii40 Regg, James B (CED) From: Regg, James B (CED) Sent: Tuesday, December 22, 2020 1:13 PM �Z�ZZ' ccszU To: Eric Boudreaux Subject: RE: Steelhead M-21 I did a quick review of the Inspector's report showing a passing No -Flow Test; you can put the well back online. Since you are injecting gas back to get the well to flow make sure the pilot set point for the well meets our requirements for an injector (not less than 50% of injection pressure). Jim Regg Supervisor, Inspections AOGCC 333 W. 71' Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Eric Boudreaux <eboudreaux@hilcorp.com> Sent: Tuesday, December 22, 2020 8:35 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: Steelhead M-21 Mr. Regg, We recently passed a no flow test on M-21 on the Steelhead. I was writing to ask you if there is a possibility we could get permission to get this well BOL prior to formal notification from you. This will include us having to inject back some. Thank you for your consideration. Eric Boudreaux Hilcorp Alaska, LLC Production Foreman Steelhead Platform Office 907-776-6836 Office 907-776-6830 Cell 907-252-3485 ebouoreaux@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg �`� (V 2v DATE: P. I. Supervisor FROM: Austin McLeod SUBJECT: Petroleum Inspector 12/21/2020 No Flow Test Trading Bay Unit M-21 Hilcorp Alaska LLC - PTD 2111140 - 12/20/2020: 1 traveled to the Steelhead platform and met with operator Garrett McLean to witness the No -Flow Test on well M-21. Garrett informed me artificial lift was shut in on 12/11/2020 and the well was bled for one day. In house No -Flow Tests were done since then, other than that the well had remained shut in. I verified the SCSSV control line was pressured up, calibrations on test equipment were current and that the Fluid Loss Control Valve (FLCV) was "locked open". Garrett told me the FLCV had been open for some time. Water flood well M- 30 was online and moving 11,000 barrels per day. The tubing and inner annulus were not in communication as the well is not capable of flow up the tubing -annulus. The hose in use to the pressure gauge and meter was half-inch with it necked up to 3/ -inch at the inlet and outlet of the meter. Photos of test equipment are attached. We recorded pressures every 15 minutes and opened to the meter on the hour 3 times each for 2 minutes. The following table shows test details: Time Pressures' (psi) Flow Rate Gas — scf/hr Liquid — al/hr Remarks 11:15 0/10/0 11:30 0/10/0 11:45 0.01/10/0 12:00 0/10/0 12:15 0/10/0 0 0 Did not register on meter 12:30 0/10/0 12:45 0/10/0 13:00 0/10/0 13:15 0/10/0 0 0 Did not register on meter 13:30 0/10/0 13:45 0/10/0 14:00 0/10/0 14:15 0/10/0 0 0 Did not register on meter. ' Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr I found the well not capable of unassisted flow, passing the No -Flow Test. Attachments: Photos (2) 2020-1220—No-Flow Test TBU M-21_am.docx Page 1 of 2 040*11" log LL i 0 k - j- + 9 0 ) m — m a « 2• ku) o z 0 ° 9 _ )» A 0 m a = , o� 4 " 5 0 2 0 2 k © E k ) 20 �� a a) ) § J § 0a . Z ° ° 2 / c[0 a \ II f 0 ,- ,- - 0 0 ] 3 0 0 2 ) 0 N. N N 9 a ■ § _ ' • .4 ) _ / \ c. E 2 c °° 0 0 0 0 a Ce S . . ° § � � 2 a s 2 « z z a. v 3 ) m (2 t § e el LIJ -J , ' z a I R S 8 8 CC n n• n g W 0 m a \ 2 Z 8 \ 0 § } E ) 2 � , o 4 k ICC 1-ii \ . ) / Om \ 2� j / ; ¢ \ ® § � ■ . co _ 0 o # , ri N k 2� 2 0 E � m co J ° Q _ 0_ / f G E 3 § To § S § Ca < / 5 2 m = 2 0 ) 3 R ® Q 2o iii $ # e Z ' » » 6ICC CI o. 0 o 0- k k k ��' CO = § } k } - 2 -2 —2 — • co e § \ ) ) C N J z § 2 2 � @ & \ 0 8 / f § 7 { q £ § • § \ w co 2 � ; & 0 . } ■ ° £ $ § i - c z s a ; CO . 0 -I ; cc \ \ S § k 0 , k 0 ) ) g k k ■ � � � 0 P tO , . E § ix .$ JTi } § Ce • / d \k / f § § 0 0 /} k 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil❑ Gas Q • SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑Q • Exploratory❑ GINJ ❑ WINJ ❑ WAG❑ WDSPL❑ No.of Completions: Service ❑ Stratigraphic Test❑ 2.Operator Name: 5. Date Comp.,Susp.,or 12.Permit to Drill Number: Union Oil Company of California Aband.: 11/14/2011 211-114 3.Address: 6. Date Spudded: 13.API Number: PO Box 196247,Anchorage,Alaska,99519 10/12/2011 507332059800• 4a. Location of Well(Governmental Section): 7. Date TD Reached: 14.Well Name and Number: Surface: 1,042'FNL,598'FWL,Sec.33,T9N, R13W,S 10/30/2011 Trading Bay Unit M-21• Top of Productive Horizon: 8. KB(ft above MSL): 160• 15.Field/Pool(s): 941'FNL,618'FWL,Sec 33,T9N,R13W,S GL Ground(ft MSL): McArthur River Field• Total Depth: 9. Plug Back Depth(MD+TVD): Middle Kenai Gas Pool 2577'FNL,594'FWL,Sec 33,T9N, R13W,S 4,161'(MD),2,779'(TVD) 4b. Location of Well(State Base Plane Coordinates, NAD 27): 10.Total Depth(MD+TVD): 16.Property Designation: Surface: - x- 214214 y-2499458 Zone- 4 • 4,161'(MD),2,779'(TVD) ADL-18730(Steelhead Platform) TPI: x- 214237 y-2499558 Zone- 4 11.SSSV Depth(MD+ND): 17.Land Use Permit: Total Depth: x- 214176 y-2497923 Zone- 4 444'(MD),443'(TVD) - N/A 18.Directional Survey: Yes U , No U 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) 185 (ft MSL)• N/A 21.Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): ,22.Re-drill/Lateral Top Window MD/TVD: gMWD,GR/RES,Triple Combo/PWD N/A 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH ND AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 28"-32" X-56 Surface 493' Surface 493' Driven 13-3/8" 68 L-80 Surface 1,375' Surface 1,362' 17-1/2" 2 Stage w/ECP 9-5/8" 47 L-80 Surface 3,126' Surface 2,691' 12-1/4" Single Stage 4" 15.2 L-80 2,576' 4,160' 2,467' 2,779' 6-3/4" N/A 24.Open to production or injection? YesL No❑ If Yes,list each 25. TUBING RECORD interval open(MD+TVD of Top&Bottom; Perforation Size and Number): SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Open hole completion 3,126'-4,161'MD;2,691'-2,779'(TVD) 5-1/2" 2,576' 2,576'(MD)/2,467'(TVD) 26. ACID, FRACTURE,CEMENT SQUEEZE, ETC. f;:v1. 1-16 j DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 1 ;' Pgri Ii N/A N/A ;S 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 11/14/2011 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 12/2/2011 24 •Test Period N/A 9,903 0 N/A N/A Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 297 26 24-Hour Rate . N/A 9,903 0 N/A 28. CORE DATA Conventional Core(s)Acquired? Yes❑ No❑., Sidewall Cores Acquired? Yes❑ No 0 If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. RECEIVED DEC 2 0 2011 ioa�ensCommission RBDMS DEC 212011 �p Form 10-407 Revised 12/2009 CONTINUED ON REVERSE Alaska(5'11'at nci<9tSubmit original only,..,) /� l 1` � /4'�j .,``�'' 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD ND Well tested? ❑, Yes U No If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form, if Permafrost-Top needed,and submit detailed test information per 20 AAC 25.071. Permafrost-Base See attached Formation Top Info. See Open Flow Potetial Report Attached Formation at total depth: 31. List of Attachments: Operations Summary, Directional Survey,Wellbore Schematic,Mud Weight Report and Formation Topos Summary _ 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: David Ross 263-7696 Printed Name: Timothy C. Brandenburg Title: Drilling Manager Signature: Phone: 276-7600 Date: 12/19/2011 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 Steelhead M-21 Formation Tops Chevron API No: 50-733-20598-00 - E APD: 211-1140 %O. Well Surface ft MDbrf ft TVDbrf ft TVDss M-21 SZOCT 802 802 -642 M-21 SZ2CT 949 948 -788 M-21 SZ4CT 1048 1045 -885 M-21 SZ6CT 1182 1176 -1016 M-21 SZ8CT 1302 1293 -1133 M-21 SZ9CT 1362 1350 -1190 M-21 SZ1OCT 1439 1423 -1263 M-21 SZ11ST 1450 1433 -1273 M-21 SZ11CT 1622 1591 -1431 M-21 SZ12ST 1654 1620 -1460 M-21 SZ12CT 1705 1668 -1508 M-21 SZ13ST 1741 1703 -1543 M-21 SZ13CT 1784 1745 -1585 M-21 SZ14ST 1796 1758 -1598 M-21 SZ14CT 1845 1807 -1647 M-21 SZ15ST 1879 1840 -1680 M-21 SZ15CT 1909 1869 -1709 M-21 SZ16ST 1915 1875 -1715 M-21 SZ16CT 2062 2021 -1861 M-21 SZ17ST 2101 2059 -1899 M-21 SZ17CT 2159 2115 -1955 M-21 SZ18ST 2177 2132 -1972 M-21 SZ18CT 2272 2222 -2062 M-21 SZ19ST 2295 2243 -2083 M-21 SZ19CT 2368 2306 -2146 M-21 SZ2OST 2400 2333 -2173 M-21 SZ2OCT 2418 2347 -2187 M-21 SZ21ST 2442 2367 -2207 M-21 SZ21CT 2517 2425 -2265 M-21 SZ22ST 2561 2456 -2296 M-21 SZ22CT 2596 2481 -2321 M-21 SZ23ST 2619 2495 -2335 M-21 SZ23CT 2637 2506 -2346 M-21 ACT 2725 2555 -2395 M-21 SZ23BCT 2847 2611 -2451 M-21 A1ST 2931 2642 -2482 M-21 A1CT 3012 2668 -2508 M-21 A2ST 3074 2683 -2523 Page 1 of 2 Chevron' Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB(ft) Water Depth(ft) M-21 TRADING BAY UNIT M-21 ADL018730 5073320598 NC7890 160.00 Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Drill and Complete Drill and 10/3/2011 Complete Primary Wellbore Affected Wellbore UWI 1Well Permit Number M-21 507332059800 2111140 Daily Operations 10/3/2011 00:00-10/4/2011 00:00 Operations Summary Rig start-up operations 10/4/2011 00:00-10/5/2011 00:00 Operations Summary Rig start-up operations 10/5/2011 00:00-10/6/2011 00:00 Operations Summary Rig start-up operations 10/6/2011 00:00-10/7/2011 00:00 Operations Summary Rig start-up operations,function test diverter,swap fittings on north diverter valve,retest diverter from all remote stations,(all good tests) 10/7/2011 00:00-10/8/2011 00:00 Operations Summary 129 start-up operations,24 hr notice given to AOGCC on upcoming diverter test. 10/8/2011 00:00-10/9/2011 00:00 Operations Summary Rig start-up operations, hydo test diverter stack. 10/9/2011 00:00-10/10/2011 00:00 Operations Summary Rig start-up operations,Test diverter-17 sec knife valve open 38 sec annular close, 139 sec to full recharge.AOGCC was notified of test but did not send an inspector. 10/10/2011 00:00-10/11/2011 00:00 Operations Summary P/U 17.5"bit assembly and TIH to clean out conductor,encountered metal scrap at 403'. Cleaned out from 403'to 448',worked several times between 411'and 447'w/o rotation. POOH and picked up magnet and TIH to 447', POOH with metal and rock shavings. 10/11/2011 00:00-10/12/2011 00:00 Operations Summary M/U and re-run 17-1/2"bit and TIH,wash and ream to 481'.Attempt to clean out junk.TOH and add string magnet to BHA TIH and wash down to 481', continue to wash and ream to 500',attempt to clean out junk w/o success.TOH and P/U 14"magnet and string magnet, make 3 runs to 500', recovered bearings and pieces of an unknown 17-1/2"bit with metal shavings and debris. R/U to pull wear bushing. 10/12/2011 00:00-10/13/2011 00:00 Operations Summary P/U BHA#7 w/14"magnet,stabilizer,bit sub and string magnet,TIH and work magnet,TOH w/no recovery. L/D BHA and P/U directional drilling BHA. TIH and riirectj nally drill from 498'to 879'.Conductor shoe depth @ 493',MW 9.15ppg. 10/13/2011 00:00-10/14/2011 00:00 Operations Summary POOH with BHA#8 and download ARC tool,TIH. Directionally drill from 879'to 1,370'taking surveys every 30'.CBU and drill from 1370'to 1381.', circulate and condition hole, MW 9.45ppg. 10/14/2011 00:00-10/15/2011 00:00 Operations Summary Continue to circulate and condition hole,pump out of hole and UD drilling BHA. Pull wear bushing and P/U conductor wash tool and TIH to 474',wash conductor from 474'to 374',TOH and UD wash tool.Prepare to run 13-3/8"casing,M/U shoe track and test floats.RIH casing to 252',MW 9.5ppg. Jim Regg with AOGCC given notice of upcoming BOP test. 10/15/2011 00:00-10/16/2011 00:00 Operations Summary Continue to run 13-3/8"68#/K-55 casing to 1,375',condition hole.UD drive sub and extra joint of casing and M/U hanger and landing joint. Test hanger seal to 2,000 psi for 30 mins.R/U cement lines.Pump 1st stage cement job w/10.5 ppg mud push, 180 bbls of 13 ppg lead and 118 bbls of 14 ppq tail, class G cement w/full returns.Displaced w/182 bbls of 9.5 ppg mud and bumped plug w/300 psi.Tested floats. Inflated ECP at depth.Launched opening art and ciculated clean mud.Pumped 2nd stage 10.5 ppg mud push,and 280 bbls 15.3 ppg cement.Displaced with 57 bbls 9.5 ppg mud, bumped plug and closed ports w/900 psi.Good cement returns at surface.Test casing to 1500 psi for 5 mins,MW 9.05ppg 10/16/2011 00:00-10/17/2011 00:00 Operations Summary R/D cementing equipment.UD landing joint.N/D diverter system.Prepare to N/U wellhead riser and BOP stack. 10/17/2011 00:00-10/18/2011 00:00 Operations Summary M/U NT-2 connection and test multi-bowl neck seals to 250/5000 psi for 30 min,Tested 20 3/4"3M starting head to 13-3/8"5M multi-bowl seals to 250/3000 psi for 30 min. Install annulus valves and begin to,N/U BORE.Notified AOGCC of upcoming BOP test. Chevron' %.11 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB(ft) Water Depth(ft) M-21 TRADING BAY UNIT M-21 ADL018730 5073320598 NC7890 160.00 Daily Operations 10/18/2011 00:00-10/19/2011 00:00 Operations Summary --- Contiue R/U BOP stack. Energize accumulator and function test stack. Install test plug and M/U safety valves and test equipment.Test Annular to 250psi low/1200psi high for 5 min,Test 5"upper rams and 9-5/8"lower rams to 250psi low/3000psi high, AOGCC rep.Bob Noble waived witness of the BOP test. ----- ---- 10/19/2011 00:00-10/20/2011 00:00 Operations Summary - Continue to test BOPE to 250psi low/3,000psi high, Perform accumulator test,start 3,100psi, after closure 1,400psi, 200psi build in 42 sec,full build 189 sec.8 N2 bottles with average pressure of 2,650psi. Pull test stand and test blind shears, Pull test plug, install wear bushing, M/U BHA#11 with a 12-1/4" bit,TIH and tag cement at 402'drill out stage collar. P/T casing to 1,500psi for 30 min and chart same.TIH and tag cement at 1,242',drill float equipment and cement to 1,376'and cleanout rat hole to 1,381'.drill formation from 1,381'-1,401'. Perform FIT to 12.5.ppg eq.uiyelant..Displace wellbore wT8:9 ppg GEM mud w/2%KCI.TOH. 10/20/2011 00:00-10/21/2011 00:00 Operations Summary Continue to TOH, L/D BHA and M/U BHA#12 w/12-1/4"Bit,TIH to 1,390',orient and test tools. Drill from 1,401'to 1,550'attempt to get quality surveys w/o success. R/U e-line and RIH w/1.8"gyro survey, POOH. Decision made to drill ahead. Drilled w/motor to 1,696'. R/U e-line and RIH w/gyro survey, POOH. Drill ahead to to 1,795'. Mud weight at 9.05 ppg. 10/21/2011 00:00-10/22/2011 00:00 Operations Summary Continue to directionally drill to 2 073'. Pump out of hole w/o rotation,TIH w/BHA#13 w/12-1/4"bit to 1,380', break circulation and TIH to 2,058', grectionally drill to 2,180'while taking surveys. Mud weight at 9.10 ppg. 10/22/2011 00:00-10/23/2011 00:00 Operations Summary Directionally drill to 2,221', unable to get WOB,work tight hole. Directionally drill while sliding to 2,396', Pump Hi-Vis sweep followed by a LCM pill.TOH and L/D BHA and M/U BHA#14 w/12-1/4"bit.TIH and break circulation at 1,450',TIH to 2,070'to perform MAD pass from 2,070'-2,130'and set down. Bring pumps on and work through tight spot. shut down pumps and continue MAD pass to 2,397'. Directionally drill from 2,397'to 2.458'.Mud weight at 9.2 ppg. 10/23/2011 00:00-10/24/2011 00:00 Operations Summary Directionally drill to_2 680'. Pump Hi-Vis sweep and wipe hole from 2,680' to 2,462'. Ream out tight spots and TIH. Ream from 2,655'to 2,680'.Orient BHA and directionally drill to 3,027'while back reaming and cleaning hole to permit slides. Mud weight 9.1 ppg. 10/24/2011 00:00-10/25/2011 00:00 Operations Summary Continue to directional drill to TD©3,090'.CBU twice, pump a sweep and CBU. Performed a short trip to shoe pumping out of hole and back reaming through tight spots.TIH from csg.shoe @ 1,375',set down at obstructions @ 2,133',2,580',2,804'and 2,921'.worked through by rotating. Continue TIH and tag TD @ 3,090'w/no fill indicated. Conditioned wellbore with sweeps and LCM pills.TOH,wiped tight spots at 2,560'and 2,130', remainder of hole pulled clean.Continue TOH and L/D BHA. Mud weight 9.25 ppg. 10/25/2011 00:00-10/26/2011 00:00 Operations Summary - - — Continue to L/D BHA, Pull wear bushing and R/U to run 9-5/8"csg. Shut down operations due to high winds. Decision made to perform cleanout trip. R/D casing tongs and install wear bushing. M/U BHA#15 w/8-1/2"bit and stabilizer,TIH with cleanout assembly from 617'to casing shoe at 1,375'. CBU and TIH to 3,075',tag bottom @ 3,090'w/no fill. Rotate and reciprocate pipe staging pumps up, pumped sweep with no significant returns.TOH from 3,090'to 2,229'w/no drag. Mud Weight 9.3 ppg. 10/26/2011 00:00-10/27/2011 00:00 Operations Summary TOH to 2,150', CBU twice,TOH to shoe @ 1,375' and flow check well,TOH and stand back BHA, Pull wear bushing and R/U casing equipment. P/U and RIH w/9 5/8"47#, L-80 casing. Install RA tags @ 2,486'and 1,599'. M/U hanger jt. and install plug set. M/U running tool.Wash down to 3,126'and land hanger.M/U cementing head and continue circulating. AOGCC was given notice of the upcoming BOP test. Mud weight 9.3ppg 10/27/2011 00:00-10/28/2011 00:00 Operations Summary Continue conditioning hole. P/T cement lines to 4,000 psi, pump 10.5 ppg mud push, launch bottom plug,pump 185 bbls of 13 ppg lead class G cement, 50 bbls of 14 ppg tail class G cement, launch top plug and displace with 9.2 ppg mud. Bumped plug at calculated value up to 2000 psi and held for 5 mins. Bled back 2 bbls,floats holding. P/T casing to 3,000 psi and charted for 30 mins. R/D cementing equipment,wash hanger and install pack-off. RILDS and test void to 5,000 psi for 30 mins. Install 13 5/8"x 7"spacer. Prepare for BOP test. Test BOPs w/5"test jt. annular test 250 psi low/1,200 psi high and the remainder of equipment to 250 psi low/3,000 psi high, lower top drive valve failed test. Pull 5"test jt and M/U 5 1/2"x 3 1/2"test joint. Lou Grimaldi with the AOGCC witnessed the BOP test. Mud weight 9.2ppg. 10/28/2011 00:00-10/29/2011 00:00 Operations Summary M/U 3 1/2"x 5"test jt and land same. Test annular with 3 1/2"pipe on 2nd attempt to 250 psi low/1200 psi high. Test 2 7/8"x 5"variable,TIW and IBOP on 3 1/2"test jt to 250 psi low/3,000 psi high. Replace lower top drive valve and test same to 250 psi/3,000 psi. M/U BHA#16 with 8 1/2"bit and clean out tools.TIH to 2,856'wash down and tag cement plug at 2,998'while circulating. Drill out wiper plugs. Chevron Chevron - Alaska Daily Operations Summary Wet Name Legal Well Name Lease Surface UWI ChevNo Original RKB(ft) Water Depth(ft) M-21 TRADING BAY UNIT M-21 ADL018730 5073320598 NC7890 160.00 Daily Operations 10/29/2011 00:00-10/30/2011 00:00 Operations Summary Continue to drill cement plugs to 3,000',TOH.M/U BHA#17 with 8 1/2"mill tooth bit and TIH to 2,910', drill out plugs and shoe track to 3,083'.Drillout float shoe and cleanout rat hole to 3,090'. CBU,pump a viscous pill and displace wellbore to filtered inlet water while reciprocating and rotating.Flow check well,TOH and L/D BHA. R/U E-line and prepare to RIH with cement evaluation log.Mud weight 8.9ppg. 10/30/2011 00:00-10/31/2011 00:00 Operations Summary RIH w/cement evaluation log to 2,8.60'and log out of hole to surface.R/D E-line. M/U directional BHA#18 w/6 3/4"mill tooth bit and TIH to 3,090'. Dace wellbore wT8 9 ppg drill in fluid. Perform MAD pass from 3,025'to 3,090'. Drill to 3,110'and perform FIT to 12.6 ma EMW. Driil to 3,191'and lost MWD signal. TOH due to BHA failure and L/D BHA. 10/31/2011 00:00-11/1/2011 00:00 Operations Summary M/U directional BHA#19 and TIH to 3,160'.Wash to 3,190'and directionally drill to TD of 4,161'while pumping sweeps to control ECD. CBU,pump hi-vis sweep with increased cuttings at surface. CBU w/clean returns.Mud weight 8.9ppg. 11/1/2011 00:00-11/2/2011 00:00 Operations Summary Continue circulating hole clean,pump out of the hole @ 5 BPM. Back ream out of hole to 3,012'.CBU @ shoe. Continue cleaning pits and building wash train.TIH w/o rotation to TD @ 4,161' No fill @ TD.Condition wellbore while reciprocating and rotating from 4,161'to 4,120'.Hole clean w/minimal solids.TOH to shoe,monitor well and continue cleaning pits.Mud weight 9.0ppg. 11/2/2011 00:00-11/3/2011 00:00 Operations Summary Continue to clean pits and R/U filtration equipment. Build and filter 6%KCL.Mud weight 9.0ppg. _ 11/3/2011 00:00-11/4/2011 00:00 Operations Summary TIH from shoe @ 3,082'to 4,161', pump Baradril-N to place in open hole.TOH from 4,161'to the shoe and continue cleaning pits. Pumped casing wash train,2 ppb caustic, 5%Baraklean,hi-vis and displaced w/filtered 6%KCL.Continue circulating and filtering returns from 3,082'.Mud weight 8.75ppg 11/4/2011 00:00-11/5/2011 00:00 Operations Summary Continue to circulate well and filter completion brine.TOH from shoe and L/D BHA. Pull wear bushing. Prepare floor for running screens and R/U handling equipment. M/U and TIH w/4"screen assembly. M/U and run inside the screen assembly with 27 jts of 2-7/8"concentric wash pipe. Mud weight 8.8ppg 11/5/2011 00:00-11/6/2011 00:00 Operations Summary Continue M/U screen assembly and 9 5/8"production packer.TIH on 5"DP and run screens to bottom. P/U off bottom and place packer @ 2,576'. Circulate completion brine to displace loosedrill in fluid in the open hole. R/U cement pump and pressure test lines to 500 psi low/4,500 psi high. Drop setting ball and displace with Oil Safe AR. Set packer and verify set. Close annular and pressure test backside to 1,000 psi for 5 mins. Pressure annulus to 2,000 psi to release setting tool. Pull free from packer and pressure up DP to 2,900 psi to shear ball seat. Pump remaining Oil Safe AR and displace with brine. Dump acid in open hole while TOH. Confirm fluid loss control valve(FLCV) closed and circulate 2 hole volumes. TOH,stand back workstring and LD packer setting tool. LID 2 7/8"wash pipe.TIH w/5 1/2"completion string. Mud weight 8.75ppg. 11/6/2011 00:00-11/7/2011 00:00 Operations Summary Continue to run 5 1/2"17#/L-80 completion string.Snap in and out of the packer @ 2,576'and space out to land hanger.Pull 3 stds and M/U control line to TRSSV,TIH,M/U hanger and splice control line.R/U slick-line,M/U lubricator and P/T to 250 psi low/3,000 psi high.RIH with PX prong and set in X-nipple @ 2,554'.P/T tubing.to 200 psi to verify prong is in place.POOH and R/D slick-line.M/U 2nd landing jt.to hanger,TIH and stab 1st seal.The completion floated in 16' unassisted by the blocks and the hanger landed.RILDS and P/T hanger seals to 250 psi lo and 5,000 psi high. Set BPV and prepare to N/D BOPE. 11/7/2011 00:00-11/8/2011 00:00 Operations Summary Continue N/D BOPE Test tubing hanger to 250 psi low/5,000 psi high, Begin N/U tree. 11/14/2011 00:00-11/15/2011 00:00 Operations Summary Unload well with gaslift. RU Slickline pressure test to 250 psi low/3,000 psi high.RIH pull PX prong plug body,RD Slickline 2 LA ,.; { 1 0 2 N CO r-1 a-, Ol . (0 On a-+ v an UA C v) roU N lD e-I N M CO CO } 0 4J N 2a) COco cu v 'O S cu N ai C N M ■ 01 Jo ii/II ■ 1 00 f 00 00 0 0 0 0 0 0 0 iz 0 Ln Or�-1 ON N m M Tr Chevron ;teelhead Platform %. Well M-21 As Built 11-17-2011 , %. RKB to TBG Head =78' Casing &Tubing Detail SIZE WT GRADE CONN MIN ID TOP BTM BTM (MD) (TVD) 32" X-56 Welded 30" Surface 493' 493' ECP/Stage Collar (c,401'-432' 13-3/8" 68 L-80 BTC 12.415 Surface 1375' 1362' 32"Conductor 9 5/8" 47 L-80 DWC 8.681 Surface 3126' 2691' 4.0 15.2 screen SLHT 3.54 3030' 4160' 2779' 51/2 17.0 L-80 TC-II Surface 2576" 2467' Logging Detail Hole LWD/MWD Mud Logging Notes Section gg g 17'/2 gMWD, GR/RES Gas On Site Geologist L 13 3/8"in 171/2"Hole Triple Combo/ 12.25 PWD Mudlog On Site Geologist 6 3/4" TripIPWDmbo Mudlog On Site Geologist Completion Equipment Information Item Depth MD Depth TVD OD ID 5'/2"SP TRSSV 444' 443' 7.690" 4.562" 5'/2'SFO-2 Mandrel 1463' 1445' 8.015" 4.892" SC-1R Packer 5''A"SFO-2 Mandrel 2485' 2401' 8.015" 4.892" 111 X Nipple 2554' 2439' 8.015" 4.892" FLCV Valve 9 5/8"SC-1 R Production Packer 2576' 2467' 8.430" 4.750" Seal Bore Extension 2582' 2471' 6.300" 4.750" _A 02 9 5/8"Casing Fluid Loss Control Valve 2604' 2485' 5.810" 3.315" op; 4.5",12.6 lb/ft TC-Il Blank Pipe 2614' 2491' 4.520" 3.958" i 041 4.0"Excluder Screen Ceiy 4"Excluder(Medium)Screen 3031' 2672' 4.740" 3.548" , �,� 4"BakerWeld 8 G Screen 3219' 2700' 4.520" 3.548" 4.0"BakerWeld Screen Pack Off Sub for Slick Stinger 4154' 2778' 4.510" 1.880" GP Wash Down Shoe 4158' 2779' 4.490" NA 6 3/4" ■ Open Hole Cementing Information Pack Off Sub Description Volume Density Yield(ft3/sx) Notes (bbls) (ppg) TD 4,161'MD Surface 1st stg 180/118 13.0/14.0 1.97/1.61 Full Returns, Bumped Plug MAX HOLE ANGLE = 86.6°@ 3747' MD, Surface 2od stg 286 15.3 1.38 Good Returns, Bumped Plug 2744' TVD ' Production 1s`stg 185/50 13.0/14.0 1.97/1.61 Bumped Plug Well Detail BY DR 11/17/2011 N 0004 M 000 00 M Om0C COO 0mN m O40C C U 0000 N O° 0mO?N MNOT M.N.-NZ + cN000,11 0Mpp pM 00 .- _ M 0N V0N'! 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MN0 W(00MON NNoMMMMM Q000 VV o C O O O N n o •m u N r2 q d E'' O 0 C y W 1 0 m D1 E (�07 TT O CC 10 NO 0 4TE OF ALASKA ALASKA OIL AND LAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a.Test: U Initial H Annual H Special lb.Type Test: U Stabilized U Non Stabilized U Multipoint ❑Constant Time ❑ Isochronal ❑Other: 2.Operator Name: 5.Date Completed: 11. Permit to Drill Number: Union Oil Company of California November 13,2011 211-114 3.Address: 6.Date TD Reached: 12.API Number: PO Box 196247,Anchorage,AK 99519 October 31,2011 50- 733-20598 4a. Location of Well(Governmental Section): 7.KB Elevation above MSL(feet): 13.Well Name and Number: Surface: 1042'FNL,598'FWL,Sec 33,T9N,R13W,SM 160' Trading Bay Unit M-21 Top of Productive Horizon: 8.Plug Back Depth(MD+TVD): 14. Field/Pool(s): 878'FNL,626'FWL,Sec 33,T9N,R13W,SM(from 401) 4,160'MD/2,700'TVD McArthur River Field Total Depth: 9.Total Depth(MD+ND): Grayling Gas Sands 2581'FSL,583'FWL,Sec 33,T9N,R13W,SM(from 401) 4,161'MD/2,700'ND 4b.Location of Well(State Base Plane Coordinates NAD 27): 10.Land Use Permit: 15.Property Designation: Surface: x- y- Zone- N/A ADL-17594,ADL-18730 TPI: x- y- Zone- 16.Type of Completion(Describe): Total Depth: x- y- Zone- 4"8-gauge screen across open-hole,near-horizontal interval 17.Casing Size Weight per foot, lb. I.D.in inches Set at ft. 19. Perforations: From To 9-5/8" 47 8.681 3,085 4"9.5 lb/ft 8-gauge screen 18.Tubing Size Weight per foot, lb. I.D.in inches Set at ft. across -horizontal section 5-1/2" 17 4.892 2576 (3,220' -4,155' MD) 20.Packer set at ft: 21.GOR cf/bbl: 22.API Liquid Hydrocardbons: 23.Specific Gravity Flowing Fluid(G): 2,576 0.56 24a. Producing through: 24b.Reservoir Temp: 24c.Reservoir Pressure: 24d. Barometric Pressure(Pa): ❑✓ Tubing ❑ Casing 74 F° 375 psia©Datum 2700 TVDSS psia 25.Length of Flow Channel(L): Vertical Depth(H): Gg: %CO2: %N2: %H2S: Prover: Meter Run: Taps: 3220 2701 0.56 0 0 0 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size(in.) Size(in.) psig Hw F° psig F° psig F° Hr. 1. X 343.1 74 343.1 4.0 2. X 342.0 74 342.0 4.0 3. X 339.7 74 339.7 _ 4.0 4. . X 337.9 74 337.9 4.0 5. X ' Basic Coefficient Flow Temp. Super Comp. No. (24-Hour) h Pressure Factor Gravity Factor Factor Rate of Flow Fb or Fp Pm Ft Fg Fpv1. 0.56 O� Mcfd 2. 0.56 �ECEIVED 4490 5060 3. 0.56 W[I V 2 9 20l l 5530 4. 0.56 6030 5. Alaska Oil&Gas Cans. Commission Temperature A Pilir 5e Orator for Flowing No. PrT Tr z Gas Fluid Gg G 1. 534 0.56 2. 534 0.56 3. 534 Critical Pressure 0.56 4. 534 Critical Temperature 0.56 5. NOV2 Form 10-421 Rev. 7/2''1`DMS N8 sigte-4,REVERSE SIDE Submit in Duplicate Pc 354.6 Pc2 125741 Pf 3,_ pf2 140625 No. Pt Pte Pc2-Pt2 Pw Pw2 Pc2-Pw2 Ps Ps2 Pf2-Ps2 1. 343.1 117718 8024 366 133956 6669 2. 342.0 116964 8777 365 133225 7400 3. 339.7 115396 10345 364 132496 8129 4. 337.9 114176 11565 363 131769 8856 5. 25. AOF (Mcfd) 105,380 n 1.0337 Remarks: I hereby(certify that the foregoing is true and correct to the best of my knowledge. '� Signed � ,, Title 4r Ier.,,‘ �,) ,"ear Date 11 /2Z/1 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ 4 hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas(air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet(TVD) L Length of flow channel, feet(MD) n Exponent(slope)of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back-Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. 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U >, aQ a -1 Chevron Debra Oudean Chevron North America Exploration and Production Technical Assistant 909 W. 9th Avenue Anchorage, AK 99501 Tele: 907 263 7889 Fax: 907 263 7828 E-mail: oudeand@chevron.com DATE Nov. 14, 2011 To: AOGCC Mahnken, Christine R 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTA WELL LOG TYPE LOG DATE INTERVAL B-LINE CD LOGGED M-21 VISION SERVICE and NOV.01,2011 380-4161.33 FT X X M-21 VISION SERVICE TVDSS NOV. 01,2011 380-4161.33 FT X X 380-2619.7 tvdss Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 263 7828. Received By: Date: (77 � r , Eslv r F5 IIf �l , Z C lv t p FLl i i �L /a` f¢ Ed 6 N v�` 4 b ` °�- 1-.A Ah ` 7 SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMIISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Timothy C. Brandenburg Drilling Manager Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519 Re: McArthur River Field, Middle Kenai Gas Pool, Trading Bay Unit M-21 Union Oil Company of California Permit No: 211-114 Surface Location: 1042' FNL, 598' FWL, SEC. 33, T9N, R13W, S Bottomhole Location: 2581' FSL, 583' FWL, SEC. 33, T9N, R13W, S Dear Mr. Brandenburg: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Si a-- a•, der 4 41 an WO •- ssio .-r DATED this /-day of September, 2011. cc: Department of Fish 86 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA RECEIVE AL)-_ A OIL AND GAS CONSERVATION COM. SION AUG 3 1 2011 PERMIT TO DRILL 20 AAC 25.005 A4iaeka OH&Gag Cum_Gomnission la.Type of Work: lb.Current Well Class: Exploratory ❑ Development Oil ❑ 1 c.Specify if well is proposed f Drill ❑✓ . Redrill ❑ Stratigraphic Test ❑ Service El Development Gas .Q Coalbed Methane ❑ "O ates ❑ Re-entry ❑ Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ ill.Well Name and Number: Union Oil Company of California Bond No. 086S103515406BCM . Tradng Bay Unit M-21 - 3.Address: 6.Proposed Depth: 12. Field/Pool(s): PO Box 196247,Anchorage,AK 99519 MD: 4194' • TVD: 2780' McArthur River Field 4a. Location of Well(Governmental Section): 7.Property Designation: r,4.,// Grayling Gas 9afxls / Surface: 1042 FNL,598'FWL,Sec 33,T9N, R13W,S A ADL 18730` `41 i /C itr) , i5 / Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Da •P A% 878'FNL,626'FWL,Sec 33,T9N, R13W,S NA L./29 011 Total Depth: 9.Acres in Property: 14.Distance to Nea -s 2581'FSL,583'FWL,Sec 33,T9N, R13W,S 5116,3840 Property: >6000' 4b.Location of Well(State Base Plane Coordinates): 10.KB Elevation 15. Distance to Nearest Well Surface:x- 214214 • y- 2499458 ' Zone- 4 (Height above GL): 160 AMSL feet Within Pool: 2290' M-09 16. Deviated wells: Kickoff depth: . 600 feet 17.Maximum Anticipated Pressures in psig(see 2 C 5.035) Maximum Hole Angle: 85 degrees Downhole: 4330 i' `' Surface: 1156 Ms 18.Casing Program: Specifications Tap--=Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 32 X-56 Weld 390 Surface Surface 490 490 Driven 17 1/2" 13 3/8" 68 L-80 BTC 1425 Surface Surface 1425. 1420 3141 ft3 in 2 stages /" 12 1/4" 9 5/8" 47 L-80 DWC 3076 Surface Surface 3076 2690 1718 ft3 in 1 stages K 6 3/4" 4" 9.5 screen Butt 1319 2876 2644 4194' 2780' 5.5 15.3 L-80 TC-11 2876 Surface Surface 2876 2644 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural 401.00 28-32 Driven 470 470 Surface Intermediate Production Liner Perforation Depth MD(ft): NA Perforation Depth ND(ft): NA 20. Attachments: Filing Fee ❑ BOP Sketch Q Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Property Plat 0 Diverter Sketch Q Seabed Report ❑ Drilling Fluid Program❑✓ 20 AAC 25.050 requirements ❑., 21. Verbal Approval: Commission Representative: Date 8/12/2011 22. I hereby certify that the foregoing is true and correct. Contact Tim Flynn, 907-263-7824 Printed Name Timothy Brandenburg Title Drilling Manager Signature — ( ! Phone Date –c-?>1–i/ Ale Commission Use Only Permit to Drill / /Z API Num. - / Permit Appr v I See cover letter for other Number: 50-7 Z�)2--Or) ) �'J �ate: /��-111 ( requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales:[ Other: Samples req'd: Yes❑/No© Mud log req'd: Yes❑; No[/]� H25 measures: Yes Non Directional svy req'd: Yes© Non Test 00." Je4r EoPE to hZoo ioc ; t'e t va 30PE *to ' °° Ptti . puvsuawt fir, 20i4i4C zS. 03 - (h)CZ), dt,vt✓ter vert* ' • ' v4r'441' i$ 41.1)rOve-4 . APPROVED BY THE COMMISSION DATE: 9''''�� // Afi. ,COMMISSIONER Form 10-401 Revised 12/2005 0R g j A Submit in Duplicate /,,i)ic_ I i Chevron Timothy C Brandenburg Union Oil Company of California Drilling Manager P.O. Box 196427 AK AK 99519-6247 Tel 907 263 7657 Fax 907 263 78888 4 Email brandenburgt@chevron.com 08/12/11 RECEIVED AUG 31 2011 Commissioner Alaska Oil &Gas Conservation Commission *aka Off& Gas C 333 W. 7'h Avenue Commission Anchorage, Alaska 99501 Anchor Re: Steelhead Platform, Trading Bay Unit M-21 Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Trading Bay Unit M-21 well from the Steelhead Platform. Drilling operations are expected to commence approximately September 29, 2011 depending on the progress of other ongoing projects. Per Conservation Order 228, Trading Bay Unit requires 10 acre spacing. There are no wells producing or capable of production from the target strata of TBU within 745' of the planned wellpath of TBU M-21. Therefore, a spacing exemption is not required to drill or produce TBU M-21. In accordance with 20 MC 25.005(c)(4)(A-C)... (A) MASP calculations are attached for review. (B) The Grayling Gas Sands are potentially gas bearing throughout the section. Potential target reservoirs and their predicted pore pressures are indicated in the attached M-21 v Well Design Summary. (C) Due to ongoing production operations in this field, sub-normally pressured sands occur in multiple places. Lost circulation and differential sticking are potential problems. Conventional solutions such as LCM and good drilling practice are intended to ameliorate the problems. An exception to 20 MC 25.035(c)(1)(B) is requested. The diverter system at Steelhead includes two 6' diameter diverter lines. The surface hole x section of M-21 is planned to be drilled with a 1 A" bit. a n Q \a r Union Oil Company of California/A Chevron Company Page 1 of 2 An exception to 20 AAC 25.005(c)(4)(A)is requested. Based on empirical Cook Inlet production data, the gas gradient to determine MASP for M-21 is .024 psi/ft. Union Oil Company, requests that this gradient is used for a more accurate expectation of the expected maximum surface pressure during a well control incident. Supporting documentation is attached in the PTD backup documents. Pursuant to 20 AAC 25.005(c)(14)... Qualified drilling waste will be discharged in accordance with NPDES permit AKG-31-5000 which became effective 7/2/2007 and expires 7/2/2012. At this time, Union Oil Company does not intend to apply for annular disposal approval. The remaining requirements of 20 AAC 25.005 are attached for review or currently on file with the Commission. If you have any questions, please don't hesitate to contact myself or Tim Flynn at 907-263-7824. Sincerely, • Timothy C. Brandenburg Drilling Manager Attachments: Form 10-401 in Duplicate M-21 Cementing Calculations M-21 Well Design Summary M-21 Casing Design M-21 Summary Drilling Procedure M-21 MASP Calculations M-21 Summary Mud Program M-21 FIT/LOT Procedure M-21 Planned Well Sketch M-21 Spider Plots M-21 Planned Well Trajectory M-21 BOP/Diverter Schematic M-21 Drilling Hazards Notice M-21 Choke Manifold Schematic M-21 Plat Cc: File Union Oil Company of California/A Chevron Company Page 2 of 2 Chevron Steelhead Platform Well M-21 Well Design Summary M-21 Well Design Summary Steelhead M-21 is a development well drilled in a South direction from Leg B2 slot 04. The well penetrates multiple primary and secondary Grayling Gas Sand targets from the SZl 1 to TD horizontal in the A-2 sand. M-21 is designed as a horizontal shaped, well reaching 88 degrees inclination in the A-2 tangent section and reaching a total depth of 4200' MD, 2780' TVD. Basic Well Information Platform: Steelhead Well Name: M-21 Estimated Spud Date: 09/29/2011 Field: McArthur River Productive Horizon: Grayling Gas Sands PTD: TBD Total Depth: 4200' MD, 2780' TVD Slot: Slot B2-04, NE Leg Surface Location: 1042 FNL, 598' FWL, Sec 33, T9N, R13W, S X=214214.9, Y=2499458.1, NAD27, ASP, Zone 4 Planned BHL: 2581' FSL, 583' FWL, Sec 33, T9N, R13W, S Original KB Elevation: 160' AMSL KB to THF: TBD Casing and Tubing Program TuTop Btm Hole D Weight Grade Conn Length MD/TVD MD/TVD Size (in) (in) (lbs / ft) (ft) (ft) (ft) Driven 28-32 X-56 Weld 390 BF 470 17 1/2 13 3/8 68 L-80 BTC 1425 BF 1425/1420 121/4 9 5/8 47 L-80 DWC 3076 BF 3076/2690 6 3/4 4" 9.5 L-80 BTC 1319 2876/2644 4194/2780 TBG 51/2 15.3 L-80 TC-II TBD THF TBD 8/11/2011 Page 1 of 3 Chevron Steelhead Platform Well M-21 Well Design Summary Well Control Summary Hole Section Equipment Test Pressure (psi) 17 '/2" 21 1/4 2M Diverter c/w 2 ea 16" 600 psi Diverter Function Valves* ' 13 5/8" Srinnular, 13 5/8(Double Gate, '/4 12 " 13 5/8 Mud Cross, 13 5/8(5 Single Gate 250/3000 3 1/8 5M Choke Manifold* (Annular 1200 psi) 13 5/8" 5M Annular, 13 5/8 5M Double Gate, 250/3000 6 3/4" 13 5/8" Mud Cross, 13 5/8 5M Single Gate 3 1/8 5M Choke Manifold* (Annular 1200 psi) *Schematics of the well control equipment are attached for reference Anti-Collision Evaluation Summary There are 3 close approach wells in the surface section of M-21 . Collision risk will be mitigated procedurally by monitoring annular pressures of adjacent wellbores and placing an observer in the wellhead room to listen for indications of a collision. A Gyro MWD tool will be used to accurately survey the wellbore in the surface hole while drilling. Close Approach M-21 Path Center to Center Diverging From Well (MD ft) Separation (ft) (ft) M-03 513-645 3.06 ' 500 M-02 590-615 5.31 615 M-05 995 9.87 1010 8/11/2011 Page 2 of 3 Chevron %.1 Steelhead Platform Well M-21 %. Well Design Summary Formation Integrity Testing Test Point, 20' Projected Projected Test Projected Below... Depth Test Type (EMW ppg) Casing Test (TVD) (PSI) 13 3/8" Csg Shoe 1410 FIT 12.5 1500 9 5/8" Shoe 2600 FIT 12.5 3000 5 4" screen NA Mud Program Summary Depth Density Viscosity Section (MD ft) Mud Type (pp (sec) PV YP API FL 17 '/2" Surf. 0-1425 Pre-Hyd Gel 9.0 ' 60-85 10-28 25-35 <12 121/4" Interm. 1425-3076 KCL/GEM/Pmr 9.1-9.3 40-53 6-15 13-20 _6 8 1/2" Prod. 3076-4194 KCL/BaraDrilIN 8.8 -9.0 40-53 11-18 18-25 _6 r Cementing Summary See Attachments Formation Markers Zone Top Depth Ft Depth Ft Pore Pressure EMW Requirement Measured RKB TVDsubsea psia (ppg RKB) Tyonek SZ11 1442 -1267 597 8.83 -� Tyonek SZ12 1637 -1454 470 6.21 Tyonek SZ17 2092 -1900 255 2.58 I Tyonek A2 3038 -2525 510 3.88 . 8/11/2011 Page 3 of 3 Chevron Steelhead Platform Well M-21 Preliminary Drilling Procedure M-21 Preliminary Drilling Procedure 1. RU Steelhead rig over slot B2-04. 2. Install A section wellhead and test. 3. Install 21 1/4 2M diverter and dual 16" diverter lines. Function test diverter per AOGCC requirements. 4. MU 17 1/2" bit and clean out conductor to 480'. 5. MU 171/2" directional BHA and drill to 1420 MD' taking gyro surveys as necessary. • 6. MU jet wash tool and wash out conductor to 470'. 7. Run and cement 13 3/8" casing to surface in 2 stages utilizing an ECP stage collar. 8. N/D 21 1/4 2M Diverter Install 13 5/8 multi bowl wellhead system. 9. NU 13 5/8" 5M BOP stack. Test 9 5/8" rams. Test stack to 250/1200/3000. 10. MU directional BHA w/ 12.25" bit, TIH Test casing to 1500 psi. 11. Drill out shoe track and perform FIT to 12.5 ppg EMW 12. Directionally drill to 3076'MD. 13. POOH L/D Drilling tools 14. Run and cement 9 5/8" casing from target sand up to ML. 15. Bump plug, Pressure test casing to 1500 psi, Install and test packoff 16. Redress BOP's w/ 5" rams and test 250/1200/3000 psi. Have kick stand available in derrick. 17. RIH with 6 3/4" PDC, TIH 18. Drill shoe track and drill 20' of new hole, perform FIT test to 12.5 ppg. 19. Change over mud to 8.8 ppg Bara Drill-N fluid 20. Directionally drill to section TD (Geo-Steer) to 4200'MD. • 21. Short trip to shoe, TIH swap drilling fluid over to 6% KCL w/ Aldacide, POOH 22. TIH w/screen assembly, set packer and FCLV, POOH 23. Run 5 1/2 tubing (GLM's,SSSV). Space out and land tubing. Test hanger void. 24. Install BPV and ND BOP. 25. NU tree and test tree to 5000 psi. Retrieve BPV 26. RDMO 8/11/2011 Page 1 of 1 • Chevron • Schlumberger WELL FIELD STRUCTURE M-21 (P3) Trading Bay Unit Steelhead Map.Panmetets Surface Location N6132761aWa State Plane,Zone 04,U5 Feet Misallaneoua Abdel: 600.12010 DIP: 73.664' Date: October 17,2011 Lei: N 60 49 54.548 Northing. 2499466 14 MUS Grid Cons:-139833100' Slol: leg 02 Not 4 TVD Ref: Rotary Tab6(160I1 above Mean Sea Love!) Map Dec: 17.762' FS'. 55517 1, Lon. W 151 36 5.916 Fasting: 214214.S7 MUS Sob Fad:096698294 Plan: 16-21(P3) Sew Date:May 17,2011 -400 0 400 800 1200 1600 0 RtE 0 MSL I 400 400 28"Conductor KOP Cry 1.5/100 Cry 5)100 800 800 1200 ... End Cry 1200 4 I 0 18418"Cs C II vt 0) 1600 1600 N 0 Co 8/100 2000 r 2000 2400 2400 2800 A30 M '•aAAehazgt 2800 TO -400 0 400 800 1200 1600 Vertical Section(ft)Azim=180.458°,Scale=1(in):400(ft) Origin=0 N/-S,0 E/-V Chevron Schlumberger WELL FIELD STRUCTURE M-21 (P3) Trading Bay Unit Steelhead Magneto Panmelen SurNce location NAD27 Alaska Stale Plane,Zune 04,US Feel Miscelhreous Week BOOM 2010 Dip: 73884 Dale: October 17.30 11 N 604954.546 Northing: 2499458.14 SUS Gni Cony'.-1.3988310W 5M'. Ng E12 slot TVO Ref'. Ralary Table(1S011abwe Mean Sea Level) Mag Dec: 11782' FS: 55517.1nT Lon: W 15136 5.918 E89k9'. 21421487 ItUS Scale Fact'.099999294 Plan: M-21(P3) Srvy Dale'.May 17.2011 -500 -250 0 250 500 250Cry 81100; 250 13318"Cs P Oki End Cry 0 .4 0 / . RTE Cry 51100 KOP Cry 1.51100 28"Conductor -250 -250 A2(P3)Heel TQt A .. A A 9518"Cs9 A -500 -500 S 0 I0 N C II To -750 -750 U) to V V V -1000 -1000 -1250 -1250 • -1500 -1500 TD -21(P3) -500 -250 0 250 500 c<< W Scale=1(in):250(ft) E >>> Steelhead M-21 Summary of Drilling Hazards POST THIS NOTICE IN THE DOGHOUSE 17-1/2" Hole Section • Shallow gas sands will be encountered that have the potential to flow and cause a loss of well 1 control. All operations shall proceed with the necessary precautions to prevent a kick. Special attention is required in the following areas: 1 . Monitor trip tank on each trip into and out of the hole. 2. Carefully monitor PVT for gain / loss. 3. Have LCM material onboard and ready for use in the event significant losses occur. 4. Minimize surge and swab pressures while tripping. 5. Review cement spacers and washes to ensure the well is not under balanced at any point during cementing operations. 6. Perform diverter drills until the crews are familiar with the procedure. • M-05, M-02 and M-03, are critical close approach wells. Record annulus pressures on these wells prior to spud and monitor during the drilling of the surface and 1st intermediate hole sections. 12-1/4" Hole Sections • Shallow gas sands will be encountered that have the potential to flow and cause a loss of well r control. All operations shall proceed with the necessary precautions to prevent a kick. Special attention is required in the following areas: 1. Monitor trip tank on each trip into and out of the hole. 2. Carefully monitor PVT for gain / loss. 3. Have LCM material onboard and ready for use in the event significant losses occur. 4. Minimize surge and swab pressures while tripping. 5. Review cement spacers and washes to ensure the well is not under balanced at any point during cementing operations. 6. Numerous coals will be drilled through. Unocal coal drilling strategy; limiting the amount of coal drilled (<10') prior to back reaming should be followed. 6 3/4" Hole Section • Significantly under pressured reservoir sands will be encountered A heightened awareness of kick detection, pre-job planning and trip tank calibration will be essential while drilling/trip ping the intermediate interval. • Loss circulation is considered to be a major risk due to the depleted reservoir sands which will be encountered. Loss circulation materials will be readily available for adding to the mud system should significant losses be encountered. Consult the Lost Circulation Decision Tree regarding LCM treatments and procedures • Differential sticking is a considerable risk while drilling these depleted sands. Keep the drill string moving whenever possible. HYDROGEN SULFIDE - H2S ' • Steelhead is/designated as an H2S drill site. Standard Operating Procedures for H2S precautions should be followed at all times. Version 1.0 Rigsite Hazards and Contingencies SOo9N013W SWAM 3W S009NO13W M-21,SZ12ST ASP 4 NAD 1927 X,Y=214246.5,2499621 878'FNL,626'FWL,Sec 33,T9N,R13W,S M-21,Surface ASP 4 NAD 1927 X,Y=214214.87,2499458.14 M-21 1042'FNL,598'FWL,Sec 33,T9N,R13W,S M-21,TD ASP 4 NAD 1927 X,Y=214165,2497920 2581'FNL,583'FWL,Sec 33,T9N,R13W,S S00811013W 50094013W 5009N013W 5000N0 13W 5008N073W S008NO 13W , - '5 C a) E N U a) 0) 0 o N O i U O 0) U Q -0 E �' O O ED 4 U 0 0 N 1— ,o C E T5 D O N O NN 0 O II a } N E 2 �) N. 0 N N D ._a. r 0 * M U s 3 rn a) N CO p U N C 0) a.. N o U 3 0 a o H uJ O N 15 O O v) a O N _c 0 Q ' Q Ti 0 + 0 > O X - o, _ } N N II Q a_ N O 0 N N II 0 O w II �' .0 N LO -O a) N. I� + co a) 0 Q 0 v) 0 O 0 N 2 N O) a) * N 0) _ 0 co O c U pop II C N *p II > = p C a) I I a) O O O O a U o 0 a) E u — 11 E > > N � o o E 1/4., 2 oL a L 3 — — a) > > U N o U �- N o o o c . ° .� > ° a L E a a a) a a o 1)) ac� co is 3 U) +- a) E a) U 0 U) N o r) r N 0) r Q O N Q a dN i- — OM 0'5 0 * O Cl.) II o a) d 0) v) O s3 0) N N c c . •- vn 0 a) o*�p = O ,0 y O \ O 00 II C ...o (1) N11 N 11 CO Q) C N. OM i Lri F cn � } II O O (1) 0 N O M = U 0 U 0 0 0it C U O o a) a 11 0 CN N. 0 c a) 3 > a� c 0 c .- E u D o E U - ) a a o - > '1 U a E > a) o o a) U O ° z E co t to 0: s✓ o, §c --- re 4. 2u) . � 2]\§ ( >� ® �/ <a. \ \§ � / § u \ . i_de ■ - - 20® ® V 0 " }Lk_ o jS�/§ K. SIS 7 i �fR= w 20. \2(/G ® sr E /xo o� � §§ « u■� o - oz uotoU, §U. - o � k 2&zm 22222 R LO 2 ƒES S see \eo \ZLz) % ; §0[\} } k = eR$ c € . 2 C § - \o®° / o to / -0f j $$�\ \ k� srv.Pi 06 Lii a z & 3 _ _ /2 ƒ: % o 0 ) d . \{ \ §\ 2 2 § L. ))) U) I222 § cn 000 §2 v R 2 ^ , _ a I(§ ;_ \\\ Ta§ }/oo = � _k\\\ z -- - § oo , o \ _ � \ [ 7%R& ' § LO NJ 2,- a- * 0 § & Li - oG - .. � � r zN-O O Q ( )/k \� 4 / 4 ■ 0 § k k §� cst a §CO\ 40-- • Chevron Maximum Anticipated Surface Pressure Calculation Steelhead Platform Well M-21 Cook Inlet,Alaska Assumptions: 1. Based on offset drilling &well test data,the pore pressure gradient is predicted to be a 0.440 psi/ft gradient(8.7 EMW) from surface to planned total depth at 3300'TVD BRT. It is understood that the Grayling Gas Sands have been substantially produced resulting in severly depleted sands. 2.The 17'/2"surface hole will be drilled to approximately 1450'/1410' MD/TVD under an existing structural pile conductor and will use a diverter system for well control. The diverter system is not designed to shut the well in and contain pressure. Therefore, MASP is 0 psig for this hole section. 3.The M.A.S.P.during drilling operations will be governed by pore pressure at TD. The calculations take into account a gas gradient to surface of.024 psi/ft.See attached supporting documentation on the derivation of this gas gradient for Cook Inlet Alaska. 4.The M.A.S.P.during production operations will be the estimated SIBHP minus the gas hydrostatic pressure between TD &the surface. 17.5"Hole Fracture Pressure Conductor(470 TVD): Max. Est. Frac pressure at KOP= 470 ft. x 0.000 psi/ft = 0 psi M.A.S.P.from pore pressure: Max. pore pressure at T.D. = 1,410 ft. x 0.440 psi/ft = 620 psi M.A.S.P. (tbg leak at surface) = 550 psi -( �24ftisi/ft* 1410 ft)= = 516 psi 12.25"hole Fracture Pressure at Casing Shoe(1230'TVD) Max. Est. Frac pressure at 13 3/8"shoe= 1410 ft. x 0.866 psi/ft = 1221 psi M.A.S.P.from pore pressure: Max. pore pressure at T.D. = 2,690 ft. x 0.440 psi/ft = 1184 psi M.A.S.P.(tbg leak at surface) = 1184 psi -(0.024 psi/ft*2690 ft)= = 1119 psi 6 3/4"Hole Fracture Pressure at Casing Shoe(2690'TVD) Max. Est. Frac pressure at 9 5/8"shoe= 2690 ft. x 0.866 psi/ft = 2330 psi M.A.S.P.from pore pressure: Max. pore pressure at T.D. = 2,780 ft. x 0.440 psi/ft = 1223 psi M.A.S.P. (tbg leak at surface) = 1223 psi -(0.024psi/ft*2780 ft)= = 6,59) psi Petrospec Technologies—Na*---a1 Gas Density Worksheet Page 1 of 2 xl Petrospec Technologies Natural Gas Density Worksheet RHOG=p *Mg/zg *R *T Constants Constant Name Value Pressure(psis) 1150 Temperature(deg F) 100 Constituent Values Constituent Mole Percent (%) Methane-Cl 98.5 Ethane-C2 1.5 Propane-C3 0 Butane-nC4 0 iso-Butane-iC4 0 Pentane-nC5 0 iso-Pentane-iC5 0 Hexanes-C6 0 Total 100 Natural Gas Characteristics Natural Gas Characteristic Value Compressibility Factor"Z" 0.89022 Specific Gravity(air= 1.0) 0.56112 Density(g/cc) 0.05597 Pressure Gradient(psi/ft) 0.024265 o K Print Page Reset Form Clear Form Calculate Natural Gas Density ©Copyright, 2011.All Rights Reserved. Petrospec Technologies Conroe, Texas file://\\anc3 80ntdfs l.anc3 80.chevrontexaco.net\share\NAU\MCBU\Alaska\Depts\Drilling\U... 8/4/2011 Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Note that the terms used in the procedures and the spreadsheet of FIT/LOT results are defined as follows: • Formation Integrity Test (FIT) - Formation is tested to a pre-determined equivalent mud weight. • Leak-Off Test (LOT) - Pressure is exerted against the formation until fluid begins to discernibly pump away. Pressure at which this first occurs is the leak-off point. • LOT Limit - 16.0 ppg EMW for all surface casing shoe tests; determined from previous experience with formation breakdown problems by attempting higher leak-offs. • Open Hole LOTs (OH LOTs)- Leak-off tests performed with open hole from the casing shoe to some point above the target reservoir. Generally done when leak-off is required but could not be achieved just below the casing shoe; or where weaker formations are suspected above the target reservoir but below the casing shoe, and assurance is required of being able to achieve estimated mud weight. Procedure for FIT: 1 . Drill 20' of new hole below the casing shoe. 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drillpipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Formation integrity tests are conducted on all casingshoes with the exception of some g Y P surface casing situations. Where annular pumping will be done on a well, the formation below the surface shoe is taken to leak-off. This ensures that future disposal fluids can pumped away without risk of damage to the surface shoe. If two attempts at establishing leak-off at the shoe are unsuccessful (using 16.0 ppg EMW LOT limit per definition above), then an open-hole LOT is performed. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Chevron . %. . %. Schlumberger "E" Plan M-21 (P3) I FIELD Trading Bay Unit ISTRUCTURE Steelhead Mepnetlo PerertMen Sodeu Loutlon NADI]Adds Slate Plane.Z .04,US Feet Mltnllaneoas Model: MGM 2010 Dip: 73.554• Dale: October 17,2011 Lab N 5049 54.545 Northing: 2499455.14 BUS Grid Cam:-1395431001 Slot leg B2 slot 4 P10 Rel: Rotary Tab2(1505 above Mem Sea Level) Map Dov:1].]52• FS: 55517.1 nT Lon: W 15136 5915 Fading: 214214.57 ItUS Scale Fad:0.99999294 Plan: M-412(P3) Srvy Data:APrl 01.2011 -500 -250 0 250 q 500 750 200, b 19RD 2000 •I f`: f' ...44, l e� M-03 250 250 - f ;� OPo�o / N , 411100 tis ` �A i,,14., it4ll4;1141. °°b A •l :Inti :;,,,4,ilk M-2011.10111111F- m1 g 4.41111 .11‘ 4, • _ 0 fir .?n, t .• \0 2• e`1y411/4 ° D -250 otv' >ti -250 X01 • M-13 • won, ksi64TVD• A •2500 Tvo C'''')n , Z -500 -500 Z o M-05 CD •.•� D�' • 1991 N •25Po •3r11 Ti, 300 �p 111)TV1 -750 -- 0) _..-._... —_.. • -750 Q1 U71,0 U) • . 35'1 C/) 2 9 V • V • V -1000 ! -. 1A91 l'It' -1000 -10PB1 1250 •2500 Za -- -1250 0 10, -10 4' wi D -1500 ��z ' -1500 1llsyjD(P3) ., M-02 -14RD M-15 M-17 -500 -250 0 250 500 750 «< W Scale= 1(in):250(ft) E >>> Chevron %. %. . Schlumberger "•L` Plan M-21 (P3) F1EL0 Trading Bay Unit S7RUO7URE Steelhead Magnetic Parameters Surface Local. N60276069.Elate Plana,Zane 04,US Foal Miscellaneous Monet: SCUM 2010 Dip: 73.66' Dale: Odober 17,2011 Let'. N 60 99 59.506 Nr61594: 2999956.19 BUS Orld Caw,39653100' SM: 189 62 MN 9 TO)Rel: Ratery Teble(1606 above Mwn Sw Levef) Mag Dec:17.762' FS: 55517.lpr Lon'. W 151 36 5916 E..1 g'. 211219.674US Swla Fec1'.0.9996YI6 Plen: M-P2(P3) SrvY Dale:RpI 01,2011 M-16RD M-31PB1 M-26 M-32PB1 M-01 ST M-01 M-14 —150 M-1210 31 L1 —50 M-321413250 M-06 10o M_04 150 �VI-1 E - M-32 M-2 250 l M�—I I l /1 t74-1/4',//11-1S ' �r I �'1� � /�•/ _. .. ��_ __ 250 -32 I 32RDP• ii At *� 6o��a j -27 200 —1 �� 200 /1)/// / •' /// p� -18 • / f ,/ M-09 150 / / 150 1500 TVI • 4 •1. ', ,,• 15081V9 • {{ ,,f A A 100 4/4 -16RD5oo0 ilrierAtIl 5o gi.19RD � IIIAI 'eloefWell 1 II 7' Arr / 51/1 � 806TVD •4 •1 �/ �To -j /cn �%V 1 `=• 't:- 1111111111111111116. V °''y r 0 g„ IR 1 g A \ k-. 1 •,- ,,,. %'_19 -eliefWell 2 —50 e�� —50 • 111 � APO -05 DOD • ,5001" —100 — —100 —150 M-17 M- 0P6'dI-14RD —02 M-21(P') M-08 (P l -150 —150 —100 —50 0 50 10 15b «< W Scale= 1(in):50(ft) E >>> r1� Steethead Platform 2011 New Drill-Diverter 07/06/2011 Mar Bottom of flow box Need a 25' stick of 22 22" pipe to cover gap for aii 22.84' Pipe boot flanges Trim at rig for proper fit -116 Hydril 4.22' M o MSP 21 1/4-2000 �( O #17 Clamp` O l Ot ! O 20 3/3M 3.00' Diverter Tees J 1 75.43' ti.;)eliceoet21) 52.59' 20 3/3M Riser 35.92' 47.06' I- 203/3M 4.75' Spacer Mirtwftrflurr .92' 20 3/Vetoi MB-246 3.78' Wellhead Room Floor Steelhead Platform 2011 Workover and New Drill 07/7/2011 A Rig floor Bottom of drip pan i 6.75' A 22" X 16" for air boot sleeve, 19' in length At Tuboscope 10.92' 26.23' Moon pool deck to rig floor II :i: II;l illit •4.54' v v 111111111L___ to 111111 lit iii J 4.67' Booster bon.-is on bottom mIll . .St. Top of Moonpool £ Moonpool deck top @ 55.95' " ''' ' ' • deck 55.38' 9.60' Total BOP assembly 0 }II : II 'IIQ 2.26' •iii.ti r II. noir I II 2.83' pi, I i..I ri, 1.25' It 3.86'flange above rig sub grating V A Rig sub grating Upper Wellhead Room to Rig Sub Grating 23.47' 5.08'clamp above floor V Upper wellhead room floor A Wellhead floor to Upper Wellhead Room 22.88' t: ni V A Top of Vetco wellhead @ 9.13' a ei I ______ / . 41i4i)illrallWfv. . ? \ d C MINIM N • m m • titik. I • 7. 1 j :Alli:. e.j.? v)[1--- I D �',f�i um:um duispi".‘,. ....... 3 < •Air O x _._1 esr..4pls P._\ I Flilio 1p _.74.. 21 o z < n ✓\ D • m 1 rn '� xf 44.}4) I x o _, 1}`cam s. t D 4-- N +•?�• • 1J I z r,/ O m 1/ O m o iuv I •I . o 0 N cil ___-___.1 1 1_____.----- -- "Mr©1 g �� Y In O o A 41 m D O DI D N -4 • r, 14 • -0---- SMI m n OM. , • • 1 HALLIBURTON Chevron M-21 ver. 1.1 ®aroid Cook Inlet AK/U.S.A. 1.0 Program Briefing M-21 will be spudded utilizing a freshwater AQUAGEL based spud mud.The 17-1/2"surface interval will be drilled to a depth of 1,208' MD,where 13-3/8"surface casing will be ran and cemented.The 12-1/4"Intermediate hole section will be drilled to a depth of 3,076' MD,where 9-5/8"Intermediate casing will be ran and cemented. A 2%KCl/CLAYSEAL/GEM GP mud system will b 'lized to drill this intermediate hole section.Then the 6- 3/4"Production interval will be drilled to a TD of 20 where 4"wire wrap screens will be run.This interval will utilize Baroid's BARADRILn mud designed ecifically for this application. 1.0.1 Well Data Operator Chevron Well No. M-21 Field/Block Cook Inlet/Steelhead Platform Location Alaska/U.S.A Well Type Grassroots Max. Well Deviation 85 .-. Maximum Expected Mud Density '9.5 ••g Estimated Days 24 Days Anticipated BHST at Total Depth of well 210°Fahrenheit 1.0.2 Reservoir Data Primary Target#1 Grayling Gas Sands Zone A2 Primary Target#1 Depth 4,200' MD 2,779' TVD Estimated Mud Weight for Target#1 8.8 ppg 5 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. 1.0.4 Potential Problems and Solutions Pgm. Exp. Potential Depth Mud Type Mud Fracture Drilling Baroid Solutions Weight Gradient Hazard Shallow gas ' Constant pit monitoring for 490'— increase in pit volume Freshwater/ 9.0;9.5 : kick/ 1,280' AQUAGEL spud mud pP N/A Loss • Maintain 10 ppb background MD circulation LCM,utilizing BARACARBs, STEELSEALs,&BAROFIBRE ■ Maintain 10 ppb background 1,280'— 2% 9.0-9.3 Loss LCM,utilizing BARACARBs, 3,076' KCUCLAYSEAL/GEM 12.8 ppg circulation/ STEELSEALs, &BAROFIBRE MD GP ppg Pack off • Utilize sweeps as necessary and maintain LCM for coal-sealing Differntial • Maintain BARCARBs to seal off 3,076' – Sticking/ sands and to bridge formation 8.8-9.0 Communicate with drillingteam 4,200' 2%KCUBARADRIL-N 12.5 ppg Loss MD ppg Circulation to minimize surge and swab pressures 1.0.5 Baroid Project Support Team Baroid Support Team Title Name Cell Number Office Number Email address Technical Professional Casey Guidry (907)315-4641 (907)275-2612 Casey.Guidry@,Halliburton.com Operations Leader David Higbie (907)242-7105 (907)275-2631 David.Higbie@Halliburton.com Lead Mud Eng. Jess Richardson (907)659-5847 hockeypuck6@hotmail.com Lead Mud Eng. Derek Rader (907)659-5847 Derek.Rader@Halliburton.com Stock-point Manager Charles Roney (907)690-0128 (907)776-3930 Charles.Roney@Halliburton.com 7 • HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AKU.S.A. 2.0.1 Casing Design Hole Size Casing Tops Bottom Fluid Frac Grad Size Density 17-1/2" 13-3/8" 0' MD/0' TVD 1,280' MD/1,270'TVD 9.0-9.5 PPG N/A 12-1/4" 9-5/8"40# 0' MD/0' TVD 3,076' MD/2,681' TVD 9.0-9.3 PPG 12.8 PPG 6-3/4" 4-1/2"9.5#screens 3,076' MD/2,681' TVD 4,200' MD/2,779' TVD 8.8-9.0 PPG 12.5 PPG 2.0.2 Drilling Fluid Properties Pre-hydrated AQUAGEL/freshwater spud mud MD weight Viscosity PV YP API FL pH 480'-1,280' 9.0-9.5 60-85 10-28 25-35 <8 8.5-9.0 Spud the well with a freshwater AQUAGEL spud mud at 9.0 ppg. The mud weight will be held in the 9.0 to 9.3 ppg mud weight range to the surface hole TD unless hole conditions dictate otherwise. Our primary focus for surface hole drilling 7 cementing the surface casing,ensure the mud weight is 9.5 ppg. LCM will be added to help strengthen the wellbore. Intermediate Hole 2% KCIICLAYSEAL/GEM GP Target Properties MD Weight Viscosity PV YP API FL pH 1,280'-3,076' 9.0-9.3 40-53 6-15 13-20 <6 8.5-9.5 A 2%KCl/CLAYSEAL/GEM GP mud will be maintained through the 12-1/4"interval. This mud offers good LCM responses if losses are encountered. Special emphasis should be placed on maintaining low ECD's and surge/swab pressures to minimize the potential for lost circulation and disturbing the coal beds. This mud is formulated with three mechanisms to provide waste minimization and effective wellbore stabilization: glycol(GEM GP),ionic inhibition (KC1),and polymer encapsulation(CLAYSEAL). BAROTROL PLUS can be used to help stabilize the coal seams. The filtrate will be tightened in the lower section of the interval. Background LCM will be added to help seal and strengthen the wellbore. Production Hole BARADRIL-N Target Properties MD weght Viscosity PV YP API FL MBT pH 3,076'-4,200' 8.8-9.0 40-53 11-18 18-25 <6 <3 8.5-9.5 The production interval will utilize an 8.8 ppg 2%KCl BARADRIL-N system built from freshwater. BARACARB The mud weight will be maintained to TD. 9 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. 2.0.3 Drilling Fluid Objectives Primary Objective: Drill the well safely,both with respect to personnel and the environment. 1) Well Control 2) Provide borehole stability 3) Optimize Hole Cleaning through the use of DFG Hydraulics 4) Prevent Differentially Stuck Pipe 5) Prevent Balling on Drilling Assembly 3.0 Interval Discussion Surface Interval 3.0.1 Surface Interval Depths: 480'—1,280' MD/1,270' TVD 3.0.2 Surface Interval Goals • Provide Borehole Stability • Prevent loss circulation • Weight up to 9.5 ppg prior to cementing 3.0.3 Primary Products PRODUCTS Product Description Product Function ALDACIDE G Glutaraldehyde solution Microbiocide AQUAGEL Treated sodium montmorillonite Primary Viscosifier BARCARB Sized calcium carbonate Bridging Material BARAZAN D+ Dispersion enhanced xantham gum Secondary Viscosifier BAROFIBRE Fibrous cellulosic material Loss circulation material BAROID 41 Ground barium sulfate Weighting agent Caustic soda Sodium hydroxide Alkalinity control CON DET PRE-MIX Blend of water soluble anionic surfactants Prevent bit balling DEXTRID LT Modified potato starch Filtration control agent PAC-L Polyanionic cellulose Filtration control agent Soda ash Sodium carbonate Treat out hardness STEELSEAL Resilient,angular,dual-composition carbon- Lost circulation material based material X-TEND II Polyacrylate/polyacrylamide copolymer Bentonite extender 3.0.4 Mud Maintenance and Discussion Mud Type: Pre-hydrated AQUAGEL/freshwater spud mud MD Weight Viscosity PV YP API FL pH 0-1,280' 9.0-9.5 60-85 10-28 25-35 <8 8.5-9.0 10 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. System formulation: Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 12-15 ppb caustic soda 0.1 ppb (9 pH) BARAZAN D+ as needed BAROID 41 as required for weight PAC-L/DEXTRID LT if required for<8 FL ALDACIDE G 0.1 ppb X-TEND II 0.02 ppb 1. Mud weight: Maintain the 9.0—9.3 ppg density or as directed. At TD the MW will be increased to 9.5 ppg. 2. Rheology: Maintain a YP between 25-35 or as needed to achieve adequate hole cleaning. 3. Filtrate control: Maintain the filtrate <8 using DEXTRID LT and/or PAC-L. Additions of CON DET PRE-MIX may be required to control screen blinding/BHA balling. Losses in this interval can be controlled with additions of 3 ppb BAROFIBRE and 3 ppb of BARACARB 50 or by dedicated LCM pills. Operations Summary: Mix a—50 bbl LCM pill prior to drilling out. The pill formulation will be:45 bbls base mud, 15 ppb BAROFIBRE,and 15 ppb of BARACARB 50. Pre-hydrated AQUAGEL should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Should sweeps be required,a high viscosity sweep is recommended. Run DFG (Drilling Fluid Graphics)to confirm hole cleaning efficiency based on current rheology,flow rates,angle and cuttings size. Sweep Formulation: 65 bbl of mud with—1 ppb of BARAZAN D+added. AQUAGEL and BARAZAN D+should be used to maintain rehology. X-TEND II should be used to enhance the AQUAGEL. DEXTRID and/or PAC L should be used for filtrate control. Background LCM(10 ppb total) BARACARBsBAROFIBRE/STEELSEALs should be maintained in the system while drilling the surface interval to prevent losses and strengthen the wellbore. While drilling,monitor the torque and drag to determine if liquid lubricant is required. If so,approval from town will be required prior to additions of lubricants. Additions of CON DET PRE-MIX are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high-clay content sections. Maintain the pH in the 8.5—9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 should be made to control bacterial action. At TD,a Wallnut"flag"(30 bbl pill with 5 ppb of WALLNUT M)or carbide pill should be pumped to gauge hole washout and to calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. The mud weight will be increased to 9.5 ppg before running surface casing and cementing. Losses have historically occurred in this interval. Ensure that the mud weight is maintained in the 9.0-9.3 ppg range through this area. Maintaining background LCM concentrations at 10 ppb total (BARACARBsBAROFIBRE/STEELSEALs)has proven successful on M-11,M-17,M-18,M-06,and M-20. Stress slow pipe movement to the drillers to reduce surge/swab on the zone. Stage pumps on slowly after connections and begin rotation prior to pumping(this will break the gels and reduce the pressure required to break the gels). 11 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. Run casing carefully to minimize surge and swab pressures.Reduce the system rheology with BARATHIN or CARBONOX once the casing is landed to a YP<20(check with the cementers to see what yp value they have targeted). Consider spotting a STEELSEAL 400 LCM pill prior to running the 13-3/8"casing if losses have been seen in this interval. The plug will be bumped with mud on the well. This well is a large borehole. Modeling shows that it will become much more difficult to clean if flowrates drop below 800 gpm. Maintain a minimum 25 YP at all times. Be prepared to increase the YP if hole cleaning becomes an issue. Run DFG(Drilling Fluid Graphics)to confirm hole cleaning efficiency based on current rheology,flow rates and cuttings size. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM. 600 800 1000 80 rpm 48 64 87 100 rpm 52 74 95 Baroid recommends a flowrate in the 800 gpm range to maximize hole cleaning efficiencies at these higher penetration rates. However if losses occur,the flow rate can be reduced in conjunction with a slower penetration rate which would reduce the ECD/losses. Hazards/Concerns—Surface Interval: • Optimize solids control equipment to maintain density and sand content. • Maintain YP between 25-35 to optimize hole cleaning and to control ECD. • Pump high viscosity sweeps to enhance hole-cleaning efforts. • Monitor sweep effectiveness. • Successfully land and cement casing. Intermediate Interval 3.1.1 Intermediate Interval Depths: 1,280'—3,076' MD/2,681' TVD 3.1.2 Intermediate Interval Goals • Well Control • Provide Borehole Stability • Prevent balling on drilling assembly • Efficient hole cleaning • Prevent differentially stuck pipe 3.1.3 Primary Products PRODUCTS Product Description Product Function ALDACIDE G Glutaraldehyde solution Microbiocide BARAZAN D PLUS Xanthan Gum Polymer Primary Viscosifier BAROTROL PLUS Sulfonated Asphalt Shale Inhibitor BDF-515 Modified Lignin Shale Inhibitor • CAUSTIC SODA Sodium Hydroxide pH Source CLAYSEAL Low molecular weight amphoteric material Shale stabilizer 12 HALLIBUATON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. DEXTRID Modified Starch Filtration Control Agent GEM GP Polyalkylene glycol Shale stabilizer KC1 Potassium Chloride Shale Inhibitor/Weighting agent PAC L Cellulose Derivative Filtration Control Agent STEELSEAL Resilient,angular,dual-composition carbon- Loss circulation material based material X-CIDE 207 Microbiocide Biocide 3.1.4 Mud Maintenance and Discussion Mud Type: 9.0-9.3 ppg 2% KCUCLAYSEAL/GEM GP MD weight Viscosity PV YP API FL pH 1,280'-3,076' 9.0.9.3 40-53 6-15 13-20 <6 8.5-9.5 System Formulation: 2%KC1,CLAYSEAL,GEM GP Product Concentration Water 0.905 bbl KC1 7 ppb caustic soda 0.2 ppb (9 pH) BARAZAN D+ 0.75 ppb (as required 18 YP) DEXTRID LT 1-2 ppb PAC-L 1 ppb CLAYSEAL 4 ppb (initial 1.5 ppb) ALDACIDE G 0.1 ppb GEM GP 1.5%by volume (5.2 ppb) BAROID 41 as needed for 9.0 ppg Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimize fisheyes. Intermediate Interval (12-1/4"hole, 9-5/8"casing to 3,076' MD) Mud Type: 9.0 ppg KCl/Clayseal/GEM System. 1.Mud weight: Maintain the density at 9.0 ppg or as needed;use solids control and whole mud dilution. Increase density as required for hole stability/coal sloughing. Maximize solids control usage. 2. Rheology: Maintain a YP between 13 and 20. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology, RPM, and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation(ideally> 100 RPM). 3. Other issues: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to minimize the chances for losses and differential sticking. LCM(BARACARBs 5/25/50, STEELSEAL 50/100/400,BAROFIBRE)should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. 13 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. Operations Summary: Mix a—50 bbl LCM pill prior to drilling out. The pill formulation will be the 50 ppb pill from the Payzone LCM tree. Mix the recommended LCM material in thinned back base mud. Drill out the cement/casing with the existing mud system. Soda ash and citric acid should be used to pretreat for any negative effects of the cement. After obtaining a leak off,begin drilling ahead displacing to the KC1 based fluid. BARACARB 5,25 and/or 50 should be maintained at 5 ppb and BAROFIBRE\STEELSEAL 50/100/400 should be maintained at 5 ppb for a total of 10 ppb LCM. The CLAYSEAL concentration should be 1.5 ppb in the initial mix. As the mud shears,slowly raise the CLAYSEAL concentration to its full 4 ppb concentration. GEM GP should be maintained at 1.5%v/v(5.2 ppb). BARAZAN-D+should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Should sweeps be required,a high viscosity sweep is recommended. Sweep Formulation: 50 bbl of mud with—1 ppb of BARAZAN D+added. DEXTRID LT and PAC-L should be used for filtrate control(6cc range). 4 ppb BAROTROL PLUS should be added to so, approval from town will be required prior to additions of lubricants. Additions of CON DET PRE-MIX are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high-clay content sections. Maintain the pH in the 8.5—9.5 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 should be made to control bacterial action. Maintain Cl-with 2%KCl. The GEM GP can be raised above the 1.5%level to help reduce torque. Do not exceed 3%v/v of GEM GP. Reduce system YP as required for running casing(do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP< 15 (check with the cementers to see what YP value they have targeted). Consider spotting a STEELSEAL LCM pill (20 ppb of the different sizes of STEELSEAL)prior to running the casing if losses have been seen in this interval. Suggested Drilling Parameters Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue in this interval. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM. 500 600 700 60 rpm 62 82 102 80 rpm 118 144 175 100 rpm 146 173 208 Rotary speed is the most critical factor in cleaning this highly deviated wellbore. Maximize rpms at all times. ROPs above these levels or with no rotation (sliding) or low rpm will require an increased frequency of the following remedial hole cleaning practices: • extended periods of circulation(with maximum pipe rpm,targeting> 100 rpm) • hole cleaning sweeps(change flow regime of base mud by using fibers,density or rheology for carrying capacity) • connection practices-employing extended gpm,rpm and back reaming during the connection 14 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. Production Interval 3.2.1 Production Interval Depths: 3,076' MD—4,200' MD/2,779' TVD • Drill 6-3/4"hole to 4,200' MD/2,779' TVD • Set 4-1/2"Production screens 3.2.2 Production Interval Goals • Well Control • Provide Borehole Stability • Efficient hole cleaning • Prevent differentially stuck pipe • Land screens on bottom 3.2.3 Primary Products PRODUCTS Product Description Product Function ALDACIDE G Gluturaldahyde Biocide BARACARBs Sized calcium carbonate Bridging agent Caustic soda Sodium hydroxide Alkalinity Source GEM GP Polyalkylene glycol Shale stabilizer KCl Potassium Chloride Shale Inhibitor/Weighting agent N-DRIL HT Specially processed, stabilized nonionic starch Filtration Control Agent derivation N-VIS Clarified Xanthan Gum Polymer Primary Viscosifier 3.2.4 Mud Maintenance and Discussion Production Hole BARADRILn Target Properties MD Weight Viscosity PV YP API FL MBT pH 3,076'-4,200' 8.8-9.0 40-53 11-18 18-25 <6 <3 8.5-9.5 System Formulation: 2% KCI BARADRILn Product Concentration Freshwater 0.943 bbl KC1 7 ppb Caustic 0.2 ppb (9 pH) N-VIS 1.5 ppb (as required 20 YP) N-DRIL HT+ 4 ppb ALDACIDE G 0.1 ppb GEM GP 1.5%by volume (5.2 ppb) BARACARB 5 7 ppb BARACARB 25 7 ppb BARACARB 50 7 ppb Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimize fisheyes. 15 HALLIBU�ATON Chevron M-21 ver. 1.1 Garold Cook Inlet AK/U.S.A. Production Horizontal Interval (6-3/4"hole. 4-1/2"Screens 4,200' MD) Mud Type: 8.8—9.0 ppg 2%KC1 BARADRILn 1.Mud weight: Maintain the density at 8.8 — 9.0 ppg or as needed with BARACARBs; use solids control and whole mud dilution to maintain a clean fluid. Maximize solids control usage. 2. Rheology: Maintain a YP between 18 and 25. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology, RPM,and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation(ideally>80 RPM). 3. Other issues: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to minimize the chances for losses and differential sticking. BARACARBs should be maintained in the system for sealing of the production sands. Operations Summary: Drill out the cement/casing with the existing mud system. Soda ash and citric acid should be used to pretreat for any negative effects of the cement. After obtaining a leak off,begin drilling ahead displacing to the 2%KCl BARADRILn system. A spacer(15 bbls 2%KC1 BARADRILn plus 1 ppb N-VIS)should be pumped when displacing the system to allow for a clean displacement. This low solids mud system is designed to reduce damage to production sands and precaution should be taken to keep the system clean. Barite will not be used in this system. If a weight up becomes necessary,BARACARBs should be utilized. GEM GP should be maintained at 1.5%v/v(5.2 ppb). N-VIS should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Maintain the MBT of the fluid below a 3. Whole mud dilutions may be necessary to maintain a clean fluid. Should sweeps be required,a high viscosity sweep is recommended. Sweep Formulation: 10 bbl of mud with—1 ppb of N-VIS added. N-DRIL HT+should be used for filtrate control (<6). While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. Maintain the pH in the 8.5 —9.5 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 should be made to control bacterial action. Maintain Cl- with 2% KC1. The GEM GP can be raised above the 1.5% level to help reduce torque. Do not exceed 3%v/v of GEM GP. This interval will have a wire-wrapped screen, open hole completion ran. Based on the final completion design, it will be necessary to displace the open hole volume at TD before pulling out of the hole to run the screens. Breakers will be used to treat the mud left in the open hole. Suggested Drilling Parameters Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue in this interval. Maximum Acceptable ROP in fah at Specified GPM and RPM GPM• 175 200 225 60 rpm 50 60 81 80 rpm 70 80 90 100 rpm 95 110 130 16 II HALLIBURTDN Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. • Rotary speed is the most critical factor in cleaning this highly deviated wellbore. Maximize rpms at all times. ROPs hole cleaning practices: • extended periods of circulation(with maximum pipe rpm,targeting> 100 rpm) • hole cleaning sweeps(change flow regime of base mud by using fibers,density or rheology for carrying capacity) • connection practices-employing extended gpm,rpm and back reaming during the connection • Completion 3.3.1 Completion Interval Depths: 0'MD-4,200' MD/2,779' TVD 3.3.2 Completion Interval Goals • Not exceeding the maximum allowable concentration of any product • Monitoring all discharges • Zero fluid related HSE incidents • Maintain an acceptable clarity of the brine • Lost circulation mitigation/control • Achieve minimal formation damage 3.3.3 Primary Products PRODUCTS Product Description Product Function ALDACIDE G Glutaraldehyde solution Microbiocide BARAKLEAN FL Blend of selected surfactants Casing wash BARAZAN D PLUS Xanthan Gum Polymer Primary Viscosifier CAUSTIC SODA Sodium Hydroxide pH Source KC1 Potassium Chloride Shale Inhibitor/Weighting agent System Formulation: 6%KC1 treated w/ALDACIDE G Product Concentration Water .972 bbl KCl 22.0 lb/bbl ALDACIDE G 0.25 lb/bbl 3.3.4 Discussion Completion Mud Type: 6%KC1 brine treated w/ALDACIDE G 1.Mud weight: Maintain a 6%KC1 concentration Operations Summary: Once TD is reached and prior to POOH to run screens,we will displace the open hole with new 2%KC1 BARADRIL-N mud.Then,when we get inside the 9-5/8"casing,we will displace the 2%KC1 BARADRIL-N mud to FIW and eventually circulate the casing wash train followed by 6%KC1 treated with ALDACIDE.The pits,all high pressure,and low pressure surface lines will be cleaned and flushed utilizing a Caustic Wash and a BARAKLEAN FL flush prior to running screens. This fluid needs to be contained,as it cannot be discharged. The pit clean-up flushes will be captured 17 HALLIBURTDN Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. and sent to production for processing. Ensure all personnel utilize correct PPE while handling caustic wash and a Pre job Safety Meeting is held with all personnel involved. Ensure the caustic wash is sufficiently neutralized with citric acid before disposal. Once the BARAKLEAN FL/Caustic washes have been pumped fluid,overboarding needs to be stopped. All remaining fluid will need to be collected and sent to production. Pit Cleaning Formulations: Caustic Flush 250 bbls FIW 2 ppb Caustic Soda **Ensure Proper PPE for handling caustic wash,and if necessary neutralize caustic wash when it returns to surface. BARAKLEAN FL Wash: 250 bbls FIW 5%v/v BARAKLEAN FL(10 drms) Once pits are cleaned,the 6%KC1 completion fluid will be built. Ensure a sample of FIW from the source to the pits is captured before mixing KC1. This sample will need an NTU ran on it and saved for the remainder of well as a control sample. Obtain a second control sample of the KC1 fluid. This sample as with the FIW will need an NTU ran,and saved as control samples until the end well. Once the 6%KC1 brine has been mixed,treat the system with 0.25 ppb ALDACIDE G. Collect a fourth control sample with NTU to be saved for the remainder of the well. The well is currently loaded with 2%KCl/CLAYSEAL/GEM GP mud. As operations begin,the well will be flushed with FIW until the fluid is clean. Once that has been achieved,the well will be displaced to a 6%KC1 brine using casing washes before displacement. The following casing wash train will be utilized to clean the wellbore before displacement. Caustic washes,BARAKLEAN FL washes,and 6%KC1 cannot be discharged. This fluid will need to be segregated and sent to production for disposal. Below is the sequence of casing wash train. 1. 40 bbls Caustic Wash 2. 40 bbls BARAKLEAN FL Wash 3. 40 bbls BARAZAN D+ Caustic Wash 40 bbls FIW 2 ppb Caustic Soda **Ensure Proper PPE for handling caustic wash,and if necessary neutralize caustic wash when it returns to surface. BARAKLEAN FL Wash 40 bbls FIW 5%v/v BARAKLEAN FL(2 drums) BARAZAN D+Hi-Vis Spacer 40 bbls FIW 3 ppb BARAZAN D+ Once the returned FIW is clean,the well will be displaced to a 6%KCI brine with a 40 bbl caustic wash,followed by the 40 bbl BARAKLEAN FL casing wash,and then followed by a 40 bbl Hi-vis spacer. Discard the 3 spacers on return.The 18 • HALLIBURTON Chevverron1. .1 M-21 Baroid Cook Inlet AK/U.S.A. 5.0 Appendixes 5.0.1 DFG Hydraulics Surface Interval Jpaak.Chen Irked 17.5Silage: ADUAGELSpud Mud 2996%Cul7giial WeM2l flow Rale.900gaUmo POP=100 NM 3.114MI*E11 Cul6gs lsnaspal Avenge Hak ECD Mud WigM=9.2hal Ci6gDia=25n Load,X Ell a42 V,Nan Aagk WIR.ls@100Rm1�}ElD)9HD104o3man 1C / 3.14 I1 Vo CiJ Lw/Ci 5,�d'6•.'B:Uti 250 — 27n , 3.97 ' 1 1010(430 0111 9231/9.609 Ngd 175i X3.20 90901799 010 5x3.x9kON 9249/9.672 WO 1000 L 4 _. 175m C ® 1280.0112700)8 9.261/9.651 b/gal 8.75x3 x930 NJ I I 1370.0 5 10 15 20 25 0 50 100 0 43 85 30 60 90 910 960 10.10 .6hall lire 21 HALLIBURTON Chevron M-21 ver. 1.1 8aroict Cook Inlet AK/U.S.A. • Intermediate Interval calor Chevron IrdeNak 12•1141nlenaeiale: 2%KC1/CLAYSEAUGEM GP 2708%Cutting idd ift21 flow Rale.500ga1am ROP=B0111M 2481%CuttingEll Cuttings import Average Hole ECD Mud Weight=9.2Ngd CulligDia=.15n Load,Z EH avg% V,R/n0 Angle b/gal 0.1 s@ 8011h80 pm/K.100 ipmr3m!C=3m 1 1.65 l w/o C� 7 4 [ 4151 7Q900(��'3Ifl 23 9.293/9.499 NO 12415n 1.94 8000( IN — &295I9.536 WO 1000- - 12415n 81 1290.0)12'0 1)R ! NI 5 x d.276 x 2491 O111 92E/9537 Ngd l l 123n 240 I I I 950 IN - — 2000— 9298/ 5/gal 230 2390.0P59 — 3Ifl --- 503 9.298/9.546 b/gd 1513 12250 7.80 Air 93D1/9.605 Ngd 87 I 5.>3.6473.0RI 3000 1230 r fl ( 30760106E111 . 23 s 1120N i i i 131EV 9312/9.622 Ngd 5 10 15 20 25 0 50 100 0 51 107 30 60 90 9l0 060 1010 .8h• OJ1Hr 22 { 1 HALLIBURTON Chevron M-21 ver. 1.1 Baroid Cook Inlet AK/U.S.A. Production Interval 3peater Device Inleval675Hoezenlal: 26KOBARADRiLn 2998%Culling idal elM08 FIA 1ale:200gimi RCP=BOO/Ix 2157%Culling Ell Cul Uanspod Avenge Hole ECD Mai:MI:9.86/gal CuigDia.=]5n Load,X EI avg% V,fl/nn Angle 6/gal R l s@ 8011 h•3J rpm/K.1009991/C=39/ -w/Ci _ 1\S_ 8681 n 50 1 18001410.018 1- 9973/9.154 b/gal 9681n 11.39 X0.0177990)0 — – 1910/9.156 NO 1N0 910 1146.0)1':3)0 --- - 66 991019.154 b)ga — _ -H35x274x3325.081 - 3.681 in 173 190001 it — — 2D00 8972116/gal i 3661 19 5.13' 24003( i9 — — 8.973/ lb/gal HI. , '\ \ / \ .' 8831r J9�• 1 116.0( )11 8.9941 Ib/gal )5) i do- NIi I 615 r x20�ix6260N] ii 91870119.465)ll 14 \135 475 x 225 x 243061 i i i i i I 14375.3 5 10 15 20 25 0 50 100 0 107 213 10 60 80 8,80 9.30 980 1.6HMI Hee 23 0 _NryMd O n N N N N N mh To�O nnyD ;Ig h Om0 WNNNNN NNNNd ddNd NNNNN NNNdN dddVd a NNNN N N N N N N N N N N N N N N N N N N N N N N N N N N a ?g ,,,1,1,,,! 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These materials may be found in the original hard file or check the parent folder to view it in digital format. 4111/ TRANSMITTAL LETTER CHECKLIST WELL NAME` G ( PTD# 2-1/ Vi Development Service Exploratory Stratigraphic Test Non-Conventional Well / FIELD: /0///(C /e/4 r SPOOL: / J J// 47,-(a 7 2 Circle Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. _ assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 I m -D 0 0 $ m2. SIll om O0 0 3 y ° = o ° 7 I* r r (7 p (0 --s CO. 0) p p 0) O -p' A 5 0 N 0 N 0 Ni 0 3 0 7 O S O cr, co N CD O C) W W co w CO w GO CO CO CO N N N N N N N N N3 N- CO CO V O CT A w N -, 3 (0 00 V CO (A A CO N 0 CO CO V 0) 01 A w N 0 CO O V C) 01 A CO CJ -, O •O m 0 O cn cn 0 0 v, * c) 0) co 0 '—, > > C) C) 'c) C) 'cn C z v > '* 0 -0 -1300 -.' 'C ',* '* 'g C " m , o UUt s m x p(- 1 3. < .00 -' a . - -I v o_ 0 a 3 3 w < m o m s 3 7 'CD * o CO:. fO 0- co a '0 a" g 'O 'O D n 7 'O y ,zO('';� (1. .7: 0: 0. 0 O .0. 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