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Home My WebLink About208-1841. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address: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 10,060 feet See Schematic feet true vertical 8,270 feet See Schematic feet Effective Depth measured 6,225 feet 5,825 feet true vertical 5,069 feet 4,792 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 9,492 MD 7,792 TVD 5,825 MD Packers and SSSV (type, measured and true vertical depth)Baker ZXP 4,792 TVD SSSV: N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 3,090psi 5,410psi 5,020psi 5,750psi 7,240psi 1,016'1,016' Burst Collapse 2,670psi Production Liner 6,015' 4,195' Casing Structural 4,920' 8,238' 6,015' 10,020' 171'Conductor Surface Intermediate 20" 13-3/8" 171' 1,016' measured TVD 9-5/8" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 208-184 50-283-20130-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0032930 Ivan River / Undefined Gas Ivan River Unit (IRU) 11-06 Plugs Junk measured Length 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 0 Size 171' 0 02076 0 630 1316 Chad Helgeson, Operations Engineer 324-541 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. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 p k ft t Fra O s 6. A G L PG , 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 3:44 pm, May 16, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.16 13:41:59 - 08'00' Noel Nocas (4361) RBDMS JSB 052125 BJM 8/12/25 DSR-6/3/25 Page 1/4 Well Name: IRU 011-06 Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20130-00-00 Field Name:Ivan River State/Province:ALASKA Permit to Drill (PTD) #:208-184 Sundry #:324-541 Rig Name/No: Jobs Actual Start Date:10/3/2024 End Date: Report Number 1 Report Start Date 10/3/2024 Report End Date 10/4/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up equipment, Nipple up BOPE, Pressure test BOPE-250/3000-pass, (No failures), Witness waived by Jim Regg. Perform accumulator draw down-pass, Batch mix 250 bbl 6% KCL, Lay down lubricator & injection head, Secure well for the night. Report Number 2 Report Start Date 10/4/2024 Report End Date 10/5/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up injector & lube, Load & pressure test 250/3000-good, Run in hole with 2.13" x 1" ID nozzle & check, Run in hole to tag @ 6315', Pull up to 6200', Kick in pumps & wash down (no weight lose) to 6666', Wash up/Wash down 6000' to 6666' x 3 times, Pull out of hole, Lay down injector & lube, Spot in & rig up AK Eline, Pick up lube & plug with GR/CCL, Pressure test 250/3000-good, Run in hole while pumping N2. pressured up tbg to 1100 psi W/ 47,000 SCF. SD @ 6242' W/ 3.71"CIBP unable to pass. Ran junk basket W/ 3.75" gauge ring & SD @ 6242' unable to work past. Ran junk basket W/ 3.40" G-ring SD 6242', unable to pass, tool string detained, work tools free over 1hr period. SDFN Report Number 3 Report Start Date 10/5/2024 Report End Date 10/6/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up CT injector & lube, Make up 3.494" nozzle, Run in hole to tag @ 6300'. Pick up to 6000', Kick in pumps, record off bottom psi, Run in hole & wash F/6300'-T/6577' with returns, (make several attempts unable to work deeper), Pull up to 5500', Standby for 1 hr, Kick in pump & pump 14 bbls for returns, Kick out pumps, Run in hole for dry tag @ 6577' (bottom of open perfs), Pull out of hole, top off hole with fluid, Lay down injector & lube. Recevied variance approval from Bryan McLellan (AOGCC) to set plug shallower than revised procedure depth @ 2:55 PM. Rig up AK eline. RIH w/ 3.50" CIBP. Set plug 2' above top of perfs @ 6546'. Dump 10 gallons of cement on CIBP (leaving 1-2 ft below bottom of new perf interval). Report Number 4 Report Start Date 10/6/2024 Report End Date 10/7/2024 Last 24hr Summary PTW/PJSM, Rig up AK-Eline. Tag TOC @ 6527'. Rig down AK eline & pick up Fox Coil. PJSM, Pick up injector & lube, Make up 2.13" wash nozzle(no check), Stab onto well & blow reel dry, Run in the hole with 2.13" nozzle, Kick in N2 & unload hole, recovered 15 bbls of fluid, Pressure up to test injectivity pressure built to 1280 psi with N2 and held, Pull out of hole & rig down coil tubing, Spot in & rig up eline, Pick up lube & tool string (GPT), Run in hole to find fluid @ 6050, Pull out of hole & rig down AK eline for the night. Report Number 5 Report Start Date 10/7/2024 Report End Date 10/8/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tool string (CCL/GR/GUN), Pressure test 250/3000 psi-good, Tubing pressure 300 psi to start. Run in hole with 2.75" x10' HC guns & tag @ 6525', Pressure up to 800 psi with pad gas, Get on depth to shoot C1 6515-6525, Pull out of hole with well building pressure to max of 1480 psi. Flow well, Pick up & make up CCL/GR/GPT, Run in hole, No fluid top, Pull out of hole & rig down for the night Report Number 6 Report Start Date 10/8/2024 Report End Date 10/9/2024 Last 24hr Summary PTW/PJSM. Ran GPT, gradient change at 6270, but not a liquid gradient. POOH. Wait on approval for new perfs to Sundry. SDFN. Received approval at 9:25 PM from Mel Rixse (AOGCC). Report Number 7 Report Start Date 10/9/2024 Report End Date 10/10/2024 Last 24hr Summary PTW/PJSM. FTP 382 psi. SI well and pressure up with pipeline gas. Perforate B2 Lower Sand f/ 6,381' - 6,397'. Init SITP: 506 psi. 5/10/15 min SITP: 590/630/642 psi. Perforate B2 Upper Sand f/ 6,362' - 6,374'. Init SITP: 653 psi. 5/10/15 min SITP: 649/647/646 psi. Perforate B1 Sand f/ 6,333' - 6,349' with well SI. Init SITP: 630 psi. 5 min SITP: 630 psi. Turn well over to Production. RDMO AK E-line. Report Number 8 Report Start Date 10/20/2024 Report End Date 10/21/2024 Last 24hr Summary MIRU SL, PT 250/2500, passed. Tag fill w/ 2.5 x 5' DD Bailer at 6420' kb, 1/2 bailer of dark grey sand. Run tandem gauges, as per procedure. RDMO. Report Number 9 Report Start Date 11/6/2024 Report End Date 11/7/2024 Last 24hr Summary SL MIRU, PT 250/2500 psi good. Bailed fill from 3900' to 3957'kb Report Number 10 Report Start Date 11/7/2024 Report End Date 11/8/2024 Last 24hr Summary SL Bailed from 3868' to 3982'kb Report Number 11 Report Start Date 1/24/2025 Report End Date 1/25/2025 Last 24hr Summary SL MIRU, PT 2500psi, passed. Using 2.5" pump bailer, bailed from 3896'kb to 3962'kb (9 runs) Report Number 12 Report Start Date 1/25/2025 Report End Date 1/26/2025 Last 24hr Summary Bail from 3,966' KB to 4,033' on 24hr ops with (14 runs). Closed swab on wire, lost tools. Fished toolstring at 4004'. Rig down. perfs @ 6546'. Dump 10 gallons of cement ), p g Get on depth to shoot C1 6515-6525, ,pppp down injector & lube. Recevied,pp, yg@( pp), ,p ,y j variance approval from Bryan McLellan (AOGCC) to set plug shallower than revised procedure depth @ 2:55 PM. Rig up AK eline. RIH w/ 3.50" CIBP. Set plug 2'y()pp above top of Page 2/4 Well Name: IRU 011-06 Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 13 Report Start Date 1/28/2025 Report End Date 1/29/2025 Last 24hr Summary MIRU SL, PT to 2500 psi, Bail to 4,025'KB Report Number 14 Report Start Date 1/29/2025 Report End Date 1/30/2025 Last 24hr Summary Bailed From 4028'kb to 4068'kb Report Number 15 Report Start Date 1/30/2025 Report End Date 1/31/2025 Last 24hr Summary Bail from 4,074' KB to 4,551'. Report Number 16 Report Start Date 1/31/2025 Report End Date 2/1/2025 Last 24hr Summary Bailed from 4554'kb to 4618'kb Report Number 17 Report Start Date 2/1/2025 Report End Date 2/2/2025 Last 24hr Summary Bailed from 4621'kb to 4701'kb Report Number 18 Report Start Date 2/2/2025 Report End Date 2/3/2025 Last 24hr Summary Bail with 24hr ops from 4355-4767'. Report Number 19 Report Start Date 2/3/2025 Report End Date 2/4/2025 Last 24hr Summary Bailed from 4774'kb to 5814'kb Report Number 20 Report Start Date 2/4/2025 Report End Date 2/5/2025 Last 24hr Summary Bail from 5774'KB to 5789'KB Report Number 21 Report Start Date 2/5/2025 Report End Date 2/6/2025 Last 24hr Summary Bailing 24hr ops, progress from 5814-6247' with 2.5" bailer. Report Number 22 Report Start Date 2/6/2025 Report End Date 2/7/2025 Last 24hr Summary Bailing w/ 12hr ops, Brush runs to clear restrictions in tubing. Bailed from 6255'KB end at 6287'KB. Report Number 23 Report Start Date 2/7/2025 Report End Date 2/8/2025 Last 24hr Summary Bailing on 12hr ops, started with 2.5" x 11' bailer at 6282'KB ending at 6301' KB. While running in hole wire parts at 5500'KB. Approx 2070' of wire left in hole according to counter, changeout crew, get other unit spotted. Report Number 24 Report Start Date 2/8/2025 Report End Date 2/9/2025 Last 24hr Summary RIH w/ 2-7/8" GR & bait sub, RIH to 4142' andball up wire and latch wire. Shear form GR. RIH with GS and unable to latch bait sub, oil jars not working, POOH and rebuild OJ. Report Number 25 Report Start Date 2/9/2025 Report End Date 2/10/2025 Last 24hr Summary Fished wire ooh W/ toolstring still attached, make multiple attempts to strip wire to tie back to unit- Unsuccessful. Secure Well, leave wire/toolstring hanging from wireline valves. Wait on additonal tools to arrive. Report Number 26 Report Start Date 2/10/2025 Report End Date 2/11/2025 Last 24hr Summary Maintinence on unit and crew changeout, new clamps arrived and able to secure and recover 2000' wire & tool string to surface - with approx. 6'' wire above wireline valves. Secured well, RDMO Report Number 27 Report Start Date 2/11/2025 Report End Date 2/12/2025 Last 24hr Summary Clean & organize both wireline units-park snap on truck on D-pad. Stand by for flight Report Number 28 Report Start Date 2/19/2025 Report End Date 2/20/2025 Last 24hr Summary SL Returned to well, Completed PJSM, initiate permits, repack stuffing box, PT PCE to 250/2500. Bailed fill from 5968'KB to 6061'KB. Report Number 29 Report Start Date 2/20/2025 Report End Date 2/21/2025 Last 24hr Summary SL Bailed from 5990'kb to 6110'kb. Page 3/4 Well Name: IRU 011-06 Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 30 Report Start Date 2/21/2025 Report End Date 2/22/2025 Last 24hr Summary SL Bailed from 6039'kb to 6235'kb Report Number 31 Report Start Date 2/22/2025 Report End Date 2/23/2025 Last 24hr Summary SL Bailed from 6085'kb to 6342'kb Report Number 32 Report Start Date 2/23/2025 Report End Date 2/24/2025 Last 24hr Summary SL Bailed from 6221'kb to 6390'kb, ran 4-1/2'' blb & 3.76'' g-ring worked from 6214'kb to 6335'kb. Report Number 33 Report Start Date 2/24/2025 Report End Date 2/25/2025 Last 24hr Summary SL Bailed from 6147'kb to 6347'kb, redressed counter head, bailed from 6234'kb(corrected depth)to 6255'kb(metal marks) cut 1900' of damaged wire. Report Number 34 Report Start Date 2/25/2025 Report End Date 2/26/2025 Last 24hr Summary Bailed from 6245' to 6255, Worked thru restriction @ 6255 w/ 2" DD bailer to 6265', Picked up 2.5" PB, Pressure up to 790 psi & packing leaking, Pull out of hole, Change packing & cut 200' line (flat spots), Run back in hole with 2.5" PB, Bail f/ 6275' to 6284', Pull out, Pick up 4.5" brb & 3.76 GR run in hole & tag @ 6280', Pull out of hole, Secure well. Report Number 35 Report Start Date 2/26/2025 Report End Date 2/27/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & 2.5" PD bailer, Run in hole & bail f/ 6075'-t/ 6276' (4 runs), Pull out of hole, Lay down, Spot in & rig up AK eline, Pick up lube & tool string (CCL/GR/GR 3.76"), Pressure test 250/3000-good, Run in hole, Tag @ 5986, Correlate, Secure well, Lay down for the night. Report Number 36 Report Start Date 2/27/2025 Report End Date 2/28/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tool string (1-11/16" CCL/GR), Run in hole, Tag @ 5978', Pull out of hole, Rig down AK eline, Rig up Pollard slick line, Pick up lube & tool (2" DD bailer), Run in hole copying eline speeds, Tag 6075' (+97 to eline), Bail f/6075'-t/6216'. Secure well & rig down for the night. Report Number 37 Report Start Date 2/28/2025 Report End Date 3/1/2025 Last 24hr Summary Bail F/ 6074'-t/6103', Cut 700 ft of wire, Bail f/6103-t/6214' Report Number 38 Report Start Date 3/1/2025 Report End Date 3/2/2025 Last 24hr Summary Bail f/6059-t/6113', Lay down & cut 300', Bail f/6113-t/6227, Lay down & cut 600', Secure well for the night. Report Number 39 Report Start Date 3/2/2025 Report End Date 3/2/2025 Last 24hr Summary Bail f/6167-t/6273', Cut 200' & test line, Caliper counter wheel & recalculate counter, Bail f/ 6173'-t/6190', Cut 1000' line, Report Number 40 Report Start Date 3/3/2025 Report End Date 3/3/2025 Last 24hr Summary Bail f/6174'-t/6197', Repack stuffing box & cut 200', Bail f/6205'-t/6210', Repack stuffing box & cut 100', Bail f/6202-t/6247 Report Number 41 Report Start Date 3/4/2025 Report End Date 3/4/2025 Last 24hr Summary Cut 140' wire, Bail f/6247-t/6337, Cut 700' wire & recaliper wheel, Tag & bail f/6167'-6234', Cut 450' wire Report Number 42 Report Start Date 3/5/2025 Report End Date 3/5/2025 Last 24hr Summary Cut 500' wire, Bail f/6080-t/5800', Lay down & secure well, Ops flow 241-1, Pick up & bail f/6139-t/6219', Freeze off in packing, Pump methanol & soak, Pull out of hole, Cut 100' & rehead Report Number 43 Report Start Date 3/6/2025 Report End Date 3/6/2025 Last 24hr Summary Cut 450' wire, Bail f/6202-t/6222, Cut 2000' line, Bail f/6133-t/6237, Loading well with fluid 64 bbls total, Fighting icing issues at surface, Tag ice plug @ 870, Work thru hydrates Report Number 44 Report Start Date 3/7/2025 Report End Date 3/7/2025 Last 24hr Summary PJSM, Clear ice from surface with methanol, Run in hole to tag @ 737, Bleed off well from 1300 to 0 psi, Bail f/6157-t/6302, Cut 500' of wire Report Number 45 Report Start Date 3/8/2025 Report End Date 3/8/2025 Last 24hr Summary PJSM, Bail f/, PJSM with eline, Spot in & rig, Pick up lube & tool string (CCL/GR, Firing head, Plug 3.50"), Pressure test 250/3000-good, Run in the hole, Correlate, Set plug @ 6257.7', Tag & log off, Pull out of the hole, Rig down & release AK eline, Spot in & rig up Pollard slickline to swab, Pick up lube & tools, Pressure test 250/3000-good, Swab well (Recovered 68 of 72 calculated). Continue swabbing at time of report. Page 4/4 Well Name: IRU 011-06 Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 46 Report Start Date 3/9/2025 Report End Date 3/9/2025 Last 24hr Summary PJSM, Continue to swab fluid f/3500'-t/6030, Drift run with 2" bailer to 6185' KB, Rig down & release. Report Number 47 Report Start Date 3/10/2025 Report End Date 3/11/2025 Last 24hr Summary PJSM, EL Crew mob to location, Spot in & rig up equipment. Report Number 48 Report Start Date 3/11/2025 Report End Date 3/12/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tool string (2 x wt bars 1-11/16", 1 x 1-11/16" CCL/GR, 1 x SS 1-11/16", 1 x 2" x 2' gun loaded 9 shots), Pressure test 250/2500-good, Run in hole with run #1, Correlate, Perf the A4 f/6249.5-t/6252, Pull out of hole, Pick up & make up run #2 (1 x 2-3/4" CCL/GR, 1 x SS 1-2-3/4", 1 x 2-3/4" x 13' gun), Tag @ 6169', Multiple attempts to pass-no go), Pull out of hole, Pick up & make run #3 (2 x 1-11/16 wt. bars, 1 x 1- 11/16" CCL, 1 x spangs, 1 x 2-1/4" bailer), Run in hole, Tag @ 6188 work string to 6256 (10 bailer runs), Pick up run #4 (1 x 2-3/4" CCL/GR, 1 x SS 1-2-3/4", 1 x 2- 3/4" x 13' gun), Run in hole tag @ 6179', Work to 6200' (300 lbs. over pull), Pull out of hole, Secure well & rig down for the night. Report Number 49 Report Start Date 3/12/2025 Report End Date 3/13/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tool string (2 x 1-11/16 wt. bars, 1 x 1-11/16" CCL, 1 x spangs, 1 x 2-1/4" bailer), Pressure test 250/2500-good, Run in the hole, Tag @ 6234, Work tools last tag 6229, Pull out of hole to empty bailer, Pick up & run in hole with BHA #1, Tag @ 6230 & work to 6234', Pull out of hole, Make up 3" Bailer, Run in hole, Tag @ 6194 & work down to 6237', Pull out of hole, Rig down & release AK Eline. Report Number 50 Report Start Date 3/13/2025 Report End Date 3/14/2025 Last 24hr Summary PJSM, Crew mob to equipment, Spot in & rig up, Pick up lube & tool string (3" dd bailer), Pressure test 250/2500-good, Run in hole & bail f/ 6242-t/6265, Pull out of hole, Secure well & lay down for the night. Report Number 51 Report Start Date 3/14/2025 Report End Date 3/15/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tool (3" dd bailer), Pressure test 250/2500-good, Run in hole Bail f/ 6256-t/6265 (4 runs), Rig down slick line, Spot in & rig up AK eline, Pick up lube & tools (1 x 2-3/4" CCL/GR, 1 x SS, 1 x 2-3/4" gun 13 ft), Pressure test 250/2500-good, Run in hole, Tag @ 6217', Pull out of the hole to 778', (tight spot), Trouble shoot & discover broken strand on eline, Bleed down well, Repair strand, Pull out of hole, Secure well & rig down for the night Report Number 52 Report Start Date 3/15/2025 Report End Date 3/16/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Rehead and test line-good, Pick up lube & tool string (3" DD), Pressure test 250/2500-good, Tag @ 5300', Change out counter wheels, Run in hole & adjust wear factor, Cut 700' line, Bail f/ 6224-6242' Report Number 53 Report Start Date 3/19/2025 Report End Date 3/20/2025 Last 24hr Summary PJSM, Crew mob to location, Spot in & rig up, Pick up lube & tool string (GPT/GR 2.72"), Pressure test 250/2500-good, Run in hole, Correlate, Tag @ 6257, Pull out of hole, Pick up run #2 ( 1 x CCL/GR, 1 x SS, 1 X 2-3/4" x 13' gun), Run in the hole, Tag @ 6258, Correlate, Perf A4 6243-6256, Pull out of hole, Secure well, Rig down for the night. Report Number 54 Report Start Date 3/20/2025 Report End Date 3/21/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tools (1 x GPT, 1 x spangs, 1 x GR 2.72"), Pressure test 250/2500-good, Run in hole, Tag @ 6179, Fluid @ 5990, Pull out to 5950, Bleed down well from 758 psi to 500 psi, Run in hole from 5959' with GPT to tag @ 6078, Pull out of hole, Secure well & rig down. Report Number 55 Report Start Date 3/28/2025 Report End Date 3/29/2025 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string (3"DD), Pressure test 250/2500-good, Run in hole, Bail f/ 5500-t/5593, Cut wire 100', Bail f/Pick up (2.5" DD), Run in hole, Bail f/5595-t/5623', Secure well, Rig down for the night. Report Number 56 Report Start Date 3/29/2025 Report End Date 3/30/2025 Last 24hr Summary PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tools (2.5" DD), Pressure test 250/2500-good, Run in hole, Bail f/5567-t/5652, Check wire, Cut 40', Bail f/5656-5675, Secure well & rig down for the night. Report Number 57 Report Start Date 3/30/2025 Report End Date 3/31/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tools (2.5" DD), Pressure test 250/2500-good, Bail f/ 5539-t/5664', Cut 100' wire, Bail f/5664-5665'. Secure well & rig down for the night. Report Number 58 Report Start Date 3/31/2025 Report End Date 4/1/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tools (2.5" PB), Pressure test 250/2500-good, Run ing the hole, Bail F/5583'-t/5660', Pull out of hole, Secure well, Rig down & release Pollard slickline. Page 1/1 Well Name: IRU 011-06 Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20130-00-00 Field Name:Ivan River State/Province:ALASKA Permit to Drill (PTD) #:208-184 Sundry #:325-541 Rig Name/No: Jobs Actual Start Date:4/4/2025 End Date: Report Number 1 Report Start Date 4/13/2025 Report End Date 4/14/2025 Last 24hr Summary PJSM, Crew travel to G-pad, Rig down lines, Mob equipment to IRU 11-06, Spot in & rig up, rig up pump & lines, Nipple up BOPE, Secure well & equipment for the night. Report Number 2 Report Start Date 4/14/2025 Report End Date 4/15/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up injector & lube, make up check & nozzle, Stab onto well head, Load lube & wellhead, Pressure test coil BOPE 250-low/3000- high, Witness waived by Jim Regg, Swab valve leaking, Fluid pack well & flow check-static, Close upper and lower master, Replace swab valve with new 4-1/16" valve, Continue pressure testing BOPE 250/3000-all pass, Unstab make up BHA (1 x 2.175" nozzle with x ports, 1 x 5' x 2.13" wt bar, 1 x check valve), (Trouble shoot encoder for footage & pressure), Secure well & shut down for the night.. Report Number 3 Report Start Date 4/15/2025 Report End Date 4/16/2025 Last 24hr Summary PJSM, Crew travel to location, Open well & flow check-static, Nipple down bope, Install BPV, Nipple down tree, Nipple up lower & upper master valves, Nipple back up BOPE & shell test 250/3000-good, (Work on Coil unit head counter), Pick up injector & lube, Make up BHA (1 x 2.175" nozzle with x ports, 1 x 5' x 2.13" wt bar, 1 x check valve), Shell test 250/3000-good, Run in the hole pumping .38 bbls/min, No tag, Run in hole to 5750, Pick up to 5700', Get pump rates, Pump @ 2.5 BPM, wash f/5700-6269 CTM, Circulate 2 bottoms up @ 2.5 BPM, Washing up & down from 6100-6269, Pull out of hole @ 75 fpm, Washing @ 2.5 bpm, Secure well, Break down BHA, Lay down lube & injector Report Number 4 Report Start Date 4/16/2025 Report End Date 4/17/2025 Last 24hr Summary PJSM, Crew mob to IRU, Spot in & rig up, Pick up lube & tool string ( 1 x 2-3/4 GR/CCL, 1 x junk basket, 1 x GR 3.55"), Pressure test 250/3000-good, Run in hole to 6166, Multiple attempts to pass @ different speeds, Pull out of hole, Pick up & make up run #2 ( 1 x 2-1/8 ccl, 1 x 2" wt bar, 1 x spangs, 1 x 2.2 GR) Run in the hole, Tag @ 6166', Pull out of the hole, Lay down lube & tools, Install night cap, Line up to inject, Pressure up to 3000 psi @ .5 bbl/min, Monitor pressure 3000 psi to 2500 psi, Pick up injector & lube, Make up 2.175"nozzle & bha, Shell test to 3000 psi-good, Run in hole & tag @ 6195', Pick up check rates 2, 2.5, 3 bbl/min, Wash f/6185-t/6270, Circulate bottoms up, Pump 45 bbls hi vis, Circulate bottoms up, Short trip to 2500' pumping 3 bbls/min, Kick out pumps & dry tag @ 6255, Pull out of hole pumping 3 bpm, Perform choke drills with crew, Lay down injector & lube, Secure well for the night. Report Number 5 Report Start Date 4/17/2025 Report End Date 4/18/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tool string (1 x CCL/GR, 1 x Junk basket, 1 x 3.55" GR), Pressure test 250/3000-good, Run in hole to 6250', Pull out of hole, Pick up run #2, (1 x CCL/GR, 1 x Setting tool. 1 x plug 3.50"), Tag @ 6250', Correlate, Set plug @ 6225', Tag & log off-good, Pull out of hole, Check valve line up & pressure test plug to 2500-psi-good, Pick up injector & lube, Make up BHA reverse nozzle, Run in hole, Reverse out 131 bbls @ 500 scfs/min, Trap 1700 psi on wellhead, Rig down Fox coil form tree. Rig up AK E-line. RIH w/ 2-3/4"x20' perf gun, bleed tubing down to 1500psi, correlate and perf A3 sands from 6167'- 6187'. Tubing pressure after 5/10/15 min.=1490/1450/1445psi. POOH, secure well. RDMO e-line to G pad. Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' -11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681"10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285"8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276"8.310" 5 4-1/2" CIBP (4/17/25) 6,225' - - - 6 4-1/2" CIBP (3/8/25) 6,258' - - - 7 Permanent Casing Patch Drift = 5.392 6270' - 6299'- 5.518" - 8 4-1/2" CIBP w/ 15.6' cement (10/5/24)6,546' - - - 7" TOC (USIT Log)9 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 6,082' MD 10 4-1/2' CIPB (9/1/21) 8,896' - - - 11 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 12 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 13 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A3 6,167 6,187 5,027 5,041 20 04/17/25 Open A4 6,243 6,256 5,083 5,092 13 03/19/25 Isolated A4 6,278' 6,291' 5,109' 5,118' 08/01/22 Isolated B1 6,333' 6,349' 16 10/09/24 Isolated B2U 6,362' 6,374' 12 10/09/24 Isolated B2 6,381' 6,397' 16 10/09/24 Isolated C1 6,515' 6,525' 5,295' 5,304' 10 10/07/24 Isolated C2 6,548' 6,565' 5,322' 5,336' 04/21/22 Isolated Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Isolated D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg Updated by DMA 05-13-25 Spud Date: 3698 psi @ 10,060' MD Description Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 13 MUD 10.1 ppg TB12 SCHEMATIC SA4 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299'ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 9 10 11 SC2 ~6595'' top of sand/fill cleanout 7 8 6 SA3 SB SC1 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/08/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250508 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 241-26 50283201970000 224068 4/15/2025 AK E-LINE Perf BRU 244-27 50283201850000 222038 4/19/2025 AK E-LINE Perf IRU 11-06 50283201300000 208184 4/14/2025 AK E-LINE CIBP PBU S-22B 50029221190200 197051 4/15/2025 AK E-LINE IPROF SRU 231-33 50133101630100 223008 4/13/2025 AK E-LINE CIBP PBU 14-33B 50029210020200 223067 1/22/2025 BAKER MRPM END 1-65A 50029226270100 203312 4/15/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON LDL END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON MFC40 MPU R-105 50029238150000 225017 4/20/2025 HALLIBURTON CAST-CBL NS-19 50029231220000 202207 4/12/2025 HALLIBURTON RBT PBU 06-12B 50029204560200 211115 3/22/2025 HALLIBURTON RBT PBU 07-22A 50029209250200 212085 3/31/2025 HALLIBURTON RBT PBU B-30B 50029215420100 201105 4/9/2025 HALLIBURTON RBT-COILFLAG PBU H-17A 50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU H-29B 50029218130200 225005 5/1/2025 HALLIBURTON RBT PBU J-10B 50029204440200 215112 4/15/2025 HALLIBURTON RBT PBU M-207 50029238070000 224141 4/21/2025 HALLIBURTON IPROF PBU Z-25 50029219020000 188159 4/23/2025 HALLIBURTON IPROF PBU Z-31 50029218710000 188112 4/25/2025 HALLIBURTON IPROF Please include current contact information if different from above. T40372 T40373 T40374 T40375 T40376 T40377 T40378 T40379 T40379 T40380 T40381 T40382 T40383 T40384 T40385 T40386 T40387 T40388 T40389 T40390 IRU 11-06 50283201300000 208184 4/14/2025 AK E-LINE CIBP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.08 12:42:44 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40256 T40256 T40257 T40257 T40258 T40259 T40260 T40261 T40262 T40263 T40264 T40265 T40266 T40267 T40268 T40269 T40270 T40271 T40272 IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.02 12:55:27 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250318 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-51 50733204640000 195004 3/1/2025 READ CAliperSurvey AN-51 50733204640000 195004 3/1/2025 READ CaliperSurvey/SBHPS BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF BRU 241-34S 50283201980000 224077 3/1/2025 AK E-LINE PPROF IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper MRU A-12RD 50733200760100 171029 3/7/2025 AK E-LINE Correlation MRU A-13 (REVISED)50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-32RD2 50733204620200 217091 3/4/2025 AK E-LINE Correlation PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT PBU 16-24A 50029215360100 224158 2/23/2025 HALLIBURTON RBT-COILFLAG PBU F-21 50029219490000 189056 2/25/2025 READ CaliperSurvey SD37-DSP01 50629234510000 211089 2/28/2025 HALLIBURTON WFL-TMD3D Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40221 T40221 T40222 T40222 T40223 T40224 T40225 T40226 T40226 T40227 T40228 T40229 T40230 T40231 T40232 T40233 T40234 IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.18 15:55:41 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241030 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch Please include current contact information if different from above. T39726 T39727 T39728 T39732 T39733 T39734 T39735 T39736 T39737 T39738 T39739 T39739 T39740 T39741 T39742 T39742 T39743 T39744 T39744 T39745 IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.01 13:27:33 -08'00' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Rixse, Melvin G (OGC) To:Chad Helgeson Cc:McLellan, Bryan J (OGC); Donna Ambruz; Trevor Willms - (C) Subject:RE: [EXTERNAL] FW: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes Date:Tuesday, October 8, 2024 9:21:29 PM Chad, Additional perforations described in your email below are approved. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, October 8, 2024 1:28 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Trevor Willms - (C) <Trevor.Willms@hilcorp.com> Subject: RE: [EXTERNAL] FW: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes Thanks Mel, Do you think this is something that will be answered today, or should we plan for an answer back in a few days? Chad From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, October 8, 2024 10:54 AM To: Chad Helgeson <chelgeson@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Trevor Willms - (C) <Trevor.Willms@hilcorp.com> Subject: Re: [EXTERNAL] FW: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes I should have Steve Davies or Andy Dewhurst review. I will pass along to them. Mel Rixse On Oct 8, 2024, at 11:42 AM, Chad Helgeson <chelgeson@hilcorp.com> wrote: Mel, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. We are currently working on an Ivan River well, IRU 11-06 with some perf adds. The well is in the Ivan River Unit, which is an undefined gas pool. We would like to add some additional perfs in between the existing sands and the proposed additional sands. Our current sundry has the following sands approved to perforate. We would like to add 3 additional sands that are in the middle of these proposed perfs (red font). Sand Name Top MD Bottom MD Top TVD Bottom TVD Total MD Comments A2 ±6,113'±6,133'±4,988'±5,003'±20' A3 ±6,167'±6,187'±5,027'±5,041'±20' A4 ±6,243'±6,257'±5,083'±5,093'±14' A5 L ±6,299'±6,315'±5,124'±5,137'±16' B1 ±6,333’±6,349’±5,151’±5,163’±16'New perfs B2 Upper ±6,362’±6,374’±5,173’±5,183’±12'New perfs B2 Lower ±6,381’±6,397’±5,188’±5,201’±16'New perfs C1 ±6,515'±6,525'±5,295'±5,304'±10'Perfed yesterday Please let us know if we can have approval to add these new perfs to this list. Chad Helgeson From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, October 4, 2024 3:12 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] FW: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes Chad, not Sean… Apologies for the mix up. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Friday, October 4, 2024 2:53 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes 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. Sean, This change to the sundry is conditionally approved. The goal is to place a P&A plug per 20 AAC 25.112(c)(1)(E) between the Beluga and Sterling formations. A good effort should be made to clean out deep enough to achieve this, however if multiple attempts at access prove unsuccessful, AOGCC will consider a variance to place cement higher. If unable to get a plug between the Sterling and Beluga pools, notify AOGCC and obtain approval before placing a shallower plug. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, October 4, 2024 1:13 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes Bryan Per our conversation on the phone we will make the following changes to the approved sundry # 324- 541. If the well cleanout goes well and we can clean out below the Sterling C2 sand (deepest open Sterling sand), we will set a plug as deep as possible to allow us to put 25ft of cement on the plug, so a proposed depth of ~6590’, which we will put 25ft of cement on the plug. However, if we have trouble getting to that depth, we will set a plug below the Sterling C1 sand and place cement to the bottom of the C1 perfs. Once cement is placed on the plug, we will set another CIBP at ~6540, which will not have any cement placed on the plug (as added by you in the approved sundry). Attached is a revised proposed schematic. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual orentity named above. 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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 ortelephone 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 onwardtransmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by thecompany in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. 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From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Joshua Stephenson - (C); Donna Ambruz; Rixse, Melvin G (OGC); Davies, Stephen F (OGC) Subject:RE: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes Date:Friday, October 4, 2024 2:52:00 PM Attachments:IRU 11-06 PROPOSED Rev1 Schematic 10-4-24.pdf Sean, This change to the sundry is conditionally approved. The goal is to place a P&A plug per 20 AAC 25.112(c)(1)(E) between the Beluga and Sterling formations. A good effort should be made to clean out deep enough to achieve this, however if multiple attempts at access prove unsuccessful, AOGCC will consider a variance to place cement higher. If unable to get a plug between the Sterling and Beluga pools, notify AOGCC and obtain approval before placing a shallower plug. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, October 4, 2024 1:13 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: IRU 11-06 (PTD# 208-184) Sundry # 324-541 changes Bryan Per our conversation on the phone we will make the following changes to the approved sundry # 324-541. If the well cleanout goes well and we can clean out below the Sterling C2 sand (deepest open Sterling sand), we will set a plug as deep as possible to allow us to put 25ft of cement on the plug, so a proposed depth of ~6590’, which we will put 25ft of cement on the plug. However, if we have trouble getting to that depth, we will set a plug below the Sterling C1 sand and place cement to the bottom of the C1 perfs. Once cement is placed on the plug, we will set another CIBP at ~6540, which will not have any cement placed on the plug (as added by you in the approved sundry). Attached is a revised proposed schematic. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis 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. Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' -11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681"10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285"8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276"8.310" 5 Permanent Casing Patch Drift = 5.392 6270' - 6299'- 5.518" - 5A 4-1/2" CIBP 6540'--- 5B 4-1/2" CIBP w/25' cement TOC @ 6565' 6590'--- 6 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 7" TOC (USIT Log)7 4-1/2' CIPB (9/1/21) 8,896' - - - 6,082' MD 8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 10 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A3 ±6,167' ±6,187' ±5,027' ±5,041' ±20' TBD Proposed A4 ±6,243' ±6,257' ±5,083' ±5,093' ±14' TBD Proposed A4 6,278' 6,291' 5,109' 5,118' 08/01/22 Open A5L ±6,299' ±6,315' ±5,124' ±5,137' ±16' TBD Proposed C1 ±6,515' ±6,525' ±5,295' ±5,304' ±10' TBD Proposed C2 6,548' 6,565' 5,322' 5,336' 04/21/22 Isolated Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Isolated D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Updated by CAH 09-19-24 Spud Date: 3698 psi @ 10,060' MD Description Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 PROPOSED SCHEMATIC Rev 1 SA4 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299'ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 6 7 8 SC2 ~6595'' top of sand/fill cleanout 5A 5B 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: CTCO, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,060'See Schematic Casing Collapse Structural Conductor Surface 2,670psi Intermediate 3,090psi Production 5,410psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 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 Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0032930 208-184 50-283-20130-00-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 9,492' 7,240psi 1,016' Size 171' 9-5/8"6,015' 1,016' MD See Attached Schematic 5,750psi 5,020psi 171' 4,920' 171' 1,016' October 4, 2024 4-1/2" 10,020' Perforation Depth MD (ft): 6,015' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 11-06CO 614 Same 8,238'7" ~1803psi 4,195' See Schematic Length Baker ZXP Packer & N/A 5,825 (MD) 4,792 (TVD) & N/A 8,270'6,665'5,419' Ivan River Undefined Gas 20" 13-3/8" See Attached Schematic m n P s t 2 N 66 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 11:57 am, Sep 20, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.09.20 11:15:24 - 08'00' Noel Nocas (4361) 324-541 DSR-9/27/24 Perforate SFD 9/23/2024 CT BOP test to 3000 psi X BJM 9/30/24 10-404 Dump bail 25' of cement on top of CIBP at 6540' MD. . *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.01 11:39:44 -08'00'10/01/24 RBDMS JSB 100224 Well Prognosis Well Name: IRU 11-06 API Number: 50-283-20130-00-00 Current Status: Gas Producer Permit to Drill Number: 208-184 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (M) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 2333 psi @ 5304’ TVD (Based on 0.44 psi/ft gradient)) Max. Potential Surface Pressure: 1803 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.70 psi/ft using 13.6 ppg EMW FIT at the 9-5/8” casing shoe 1/19/09 Shallowest Potential Perf TVD: MPSP/(0.70-0.1) = 1803 psi / 0.60 = 3005‘ TVD Top of Pools per CO 614: Ivan River Undefined Gas Pool Well Status: SI Producer with open Sands: Beluga D & Sterling C2) Brief Well Summary IRU 11-06 was completed in 2009. The well has produced 8.0 BCF from various sands ranging from Tyonek to Sterling. Most of the production has come from Tyonek L which produced between 2009-2020 when it depleted to 200mscfd at 30 psi. In 2020 the Tyonek was shut off and the Sterling A5 was perforated. The Sterling A5 was very productive at 7.5 mmscfd @ 1800 psi and produced until July 2021 when the A5 sands were isolated with a casing patch at 3.0 mmscfd and 650psi. A workover was completed installing a 4-1/2” monobore and cemented to isolate the A5 sands and access deeper production. The well tested a variety of Beluga sands without success when the last perforation into the Beluga D4L brought in sand. A coil cleanout was performed, and a plug was set over the Beluga D4L. The Beluga D was then perforated bringing the well into production with the Sterling C2 added a year later. The objective of this sundry is perform a coil cleanout, plug Beluga D sands and add perforations to the Sterling A and C sands. Notes Regarding Wellbore Condition: - SL tagged fill at 6332 8/27/24 (no fluid level in well) - Max Inclination holds ~47 degrees from 3500’ – 6000’ MD - TOC @ 6084’ based on USIT (2/8/09) Procedure 1. MIRU Fox #8 Coil Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high a. Provide AOGCC 48hr notice for BOP test 3. RIH & clean out wellbore to ~6,550’ with water & N2 a. Working fluid will be 6% KCl (~8.4 ppg) b. If necessary, add foam and nitrogen for the cleanout 4. MIRU E-line on Coil BOPs PT lubricator to 3000 psi 5. PU 4-1/2” CIBP and RIH to set at ~6,540’ (Above C2 Perfs @ 6548’) 6. RD Eline 7. Coil RIH and tag CIBP and blow well dry with N2, trapping 1000 psi on wellbore 8. RDMO coil tubing 9. RU E-line, PT lubricator to 2500 psi , equivalent to about 3,240' MD SFD Dump bail 25' of cement on top of CIBP. Set CIBP deeper as needed to accommodate cement below new perfs -bjm Well Prognosis 10. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 11. Perforate the below intervals: Sand Name Top MD Bottom MD Top TVD Bottom TVD Total MD A2 ±6,113' ±6,133' ±4,988' ±5,003' ±20' A3 ±6,167' ±6,187' ±5,027' ±5,041' ±20' A4 ±6,243' ±6,257' ±5,083' ±5,093' ±14' A5 L ±6,299' ±6,315' ±5,124' ±5,137' ±16' C1 ±6,515' ±6,525' ±5,295' ±5,304' ±10' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. a. Above perfs are in the Ivan River Undefined Gas Pool. b. Pending well production, all perf intervals may not be completed 12. RDMO 13. Turn well over to production & flow test well 14. Test SVS as necessary once well has reached stable flow rates (if not tested on last 6 month cycle) a. Notify state 48hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 2. Provide AOGCC 24hrs notice of BOP test 3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 4. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 5. RDMO coil tubing Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' -11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681"10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285"8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276"8.310" 5 Permanent Casing Patch Drift = 5.392 6270' - 6299'- 5.518" - 6 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 7 4-1/2' CIPB (9/1/21) 8,896' - - - 8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 7" TOC (USIT Log)9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 6,082' MD 10 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A4 6,278' 6,291' 5,109' 5,118' 08/01/22 Open C2 6,548' 6,565' 5,322' 5,336' 04/21/22 Open Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Open D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Updated by CAH 09-19-24 Spud Date: 3698 psi @ 10,060' MD Description PBTD - Top of 7" Float equipment (Tagged 2/6/09) Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 44444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 SCHEMATIC SA4 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299'ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 6 7 8 SC2 ~6332' top of sand/fill 8/27/24 Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' -11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681"10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285"8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276"8.310" 5 Permanent Casing Patch Drift = 5.392 6270' - 6299'- 5.518" - 5A 4-1/2" CIBP 6540'--- 6 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 7 4-1/2' CIPB (9/1/21) 8,896' - - - 7" TOC (USIT Log)8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 6,082' MD 9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 10 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A3 ±6,167' ±6,187' ±5,027' ±5,041' ±20' TBD Proposed A4 ±6,243' ±6,257' ±5,083' ±5,093' ±14' TBD Proposed A4 6,278' 6,291' 5,109' 5,118' 08/01/22 Open A5L ±6,299' ±6,315' ±5,124' ±5,137' ±16' TBD Proposed C1 ±6,515' ±6,525' ±5,295' ±5,304' ±10' TBD Proposed C2 6,548' 6,565' 5,322' 5,336' 04/21/22 Isolated Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Isolated D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg Updated by CAH 09-19-24 Spud Date: 3698 psi @ 10,060' MD Description Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 PBTD - Top of 7" Float equipment (Tagged 2/6/09) API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 44444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 PROPOSED SCHEMATIC SA4 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299'ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 6 7 8 SC2 ~6550' top of sand/fill 8/27/24 5A STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 18RD 50133205840100 222033 9/6/2023 YELLOW JACKET GPT-PERF BCU 18RD 50133205840100 222033 8/24/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 8/28/2023 YELLOW JACKET PLUG-PERF BCU 18RD 50133205840100 222033 9/9/2023 YELLOW JACKET PLU-GPT-PERF BCU 18RD 50133205840100 222033 9/4/2023 YELLOW JACKET SCBL BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf KTU 43-6XRD2 50133203280200 205117 9/4/2023 YELLOW JACKET CALIPER KU 42-12 50133206890000 220045 8/31/2023 YELLOW JACKET GPT-PERF KU 42-12 50133206890000 220045 8/20/2023 YELLOW JACKET SCBL MPU E-23 50029225700000 195094 8/18/2023 YELLOW JACKET CBL-PLUG MPU E-23 50029225700000 195094 8/20/2023 YELLOW JACKET PERF Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf PBU L-240 50029237030000 221086 8/30/2023 READ IPROF Please include current contact information if different from above. T37983 T37983 T37983 T37983 T37983 T37984 T37984 T37984 T37985 T37986 T37987 T37988 T37989 T37989 T37990 T37990 T37991 T37991 T37992 9/13/2023 IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.13 10:28:30 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory 3. Address: 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 10,060 feet See schematic feet true vertical 8,270 feet See schematic feet Effective Depth measured 6,665 feet 5,825 feet true vertical 5,419 feet 4,792 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 9,492 MD 7,792 TVD 5,825 MD Packers and SSSV (type, measured and true vertical depth)Baker ZXP 4,792 TVD SSSV: N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Jake Flora, Operations Engineer 323-393 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1451 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 jake.flora@hilcorp.com 907-777-8442 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 0 Size 171' 0 01585 0 1330 798 measured TVD 9-5/8" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 208-184 50-283-20130-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0032930 Ivan River / Undefined Gas Ivan River Unit (IRU) 11-06 Plugs Junk measured Length Production Liner 6,015' 4,195' Casing Structural 4,920' 8,238' 6,015' 10,020' 171'Conductor Surface Intermediate 20" 13-3/8" 171' 1,016' 3,090psi 5,410psi 5,020psi 5,750psi 7,240psi 1,016' 1,016' Burst Collapse 2,670psi p k ft t Fra O s O 6. A G L PG , 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 7:50 am, Aug 03, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.02 16:44:16 - 08'00' Noel Nocas (4361) Rig Start Date End Date E-Line 8/1/23 8/1/23 08/01/2023 - Tuesday PSJM and PTW, SIMOPS with production. Drive to location SITP 300psi. R/U E-line Bullhead well with sales gas up to 425psi, pressure broke over. M/U 2ft 2"OD geodynamics perf gun, 6.5gm (CCL to top shot 7.6ft) Stab on lubricator. Pressure test to 250psi/2500psi - Test Good. RIH, pull correlation log. Send to town, on depth. Pull on depth and perforate the Sterling A5 sands from 6,288-6,290' @ 11:40hrs POOH, Bull plug damp, gun has a little sand on it SITP 0M - 375psi 5M - 622psi 10M - 738psi 15M - 719psi. M/U 13ft 2-3/4"OD 6spf, geodynamics perf gun, 15gm (CCL to top shot 10.0ft) RIH, pull correlation log. Send to town, on depth. Pull on depth and perforate the Sterling A5 sands from 6,278-6,291' @ 13:30hrs POOH, Bull plug damp, gun has a little sand on it SITP 0M - 780psi 5M - 880psi 10M - 908psi 15M - 922psi. Secure well RD AK E-line SDFN Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' - 11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" 7" TOC (USIT Log)5 Permanent Casing Patch Drift = 5.392 6270' - 6299'- 5.518" - 6,118' MD 6 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 4,992' TVD 7 4-1/2' CIPB (9/1/21) 8,896' - - - 8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 10 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A5 6,278' 6,291' 5,109' 5,118' 08/01/22 Open C2 6,548' 6,565' 5,322' 5,336' 04/21/22 Open Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Open D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Updated by JMF 08-02-23 Spud Date: 3698 psi @ 10,060' MD Description PBTD - Top of 7" Float equipment (Tagged 2/6/09) Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 SCHEMATIC SA5 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299'ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665 MD / 5,419 TVD TD = 10,060 MD / 8,270 TVD 2 F1 F3 F2 6 7 8 SC2 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): 10,060'See Schematic Casing Collapse Structural Conductor Surface 2,670psi Intermediate 3,090psi Production 5,410psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker ZXP Packer & N/A 5,825 (MD) 4,792 (TVD) & N/A 8,270'6,665'5,419' Ivan River Undefined Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 11-06CO 614 Sterling A5 8,238'7" ~2242psi 4,195' See Schematic Length July 25, 2023 4-1/2" 10,020' Perforation Depth MD (ft): 6,015' See Attached Schematic 5,750psi 5,020psi 171' 4,920' 171' 1,016' Size 171' 9-5/8"6,015' 1,016' MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 9,492' 7,240psi 1,016' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0032930 208-184 50-283-20130-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 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: m n P s 66 t _ N 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 8:48 am, Jul 13, 2023 323-393 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.07.13 07:50:24 - 08'00' Noel Nocas (4361) BJM 7/17/23 DSR-7/13/23MDG 7/18/2023 Undefined Gas GCW 07/19/2023 JLC 7/19/2023 07/20/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.07.20 00:08:46 -05'00' RBDMS JSB 072023 Well Prognosis Well Name:IRU 11-06 API Number:50-283-20130-00-00 Current Status:Gas Producer Permit to Drill Number:208-184 First Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (M) Second Call Engineer:Chad Helgeson (907) 777-8420 (O)(907) 229-4824 (M) Maximum Expected BHP: ~2901 psi @ 6595’ TVD (0.44 psi/ft gradient to bottom perf) Max. Potential Surface Pressure: ~2242 psi (Max expected BHP - gas to surface) Well Status: Online Producer making 1000 mcfd at 145 psi FTP with 2 bw (Open Sands: Beluga D & Sterling C2) Brief Well Summary IRU 11-06 was completed in 2009. The well has produced 8.0 BCF from various sands ranging from Tyonek to Sterling. Most of the production has come from Tyonek L which produced between 200-2020 when it depleted to 200mscfd at 30 psi. In 2020 the Tyonek was shut off and the Sterling A5 was perforated. The Sterling A5 was very productive at 7.5 mmscfd @ 1800 psi and produced until July 2021 when the A5 sands were isolated with a casing patch at 3.0 mmscfd and 650psi. During the workover a 4-1/2” monobore was run and cemented to isolate the A5 sands and access deeper production. The well tested a variety of Beluga sands without success when the last perforation into the Beluga D4L brought in sand. A coil cleanout was performed, and a plug was set over the Beluga D4L. The Beluga D was then perforated bringing the well into production with the Sterling C2 added a year later. The objective of this sundry is to add perforations to the Sterling A5 which was originally produced in this well bore but shut-in at 3.0 mmscfd and 650psi. Notes Regarding Wellbore Condition: 4-21-22 Perforated Sterling C2 6548-65’ w 2-7/8” gun Procedure 1. RU E-line, PT lubricator to 2500 psi 2. Perforate the below interval: Sand Name Top MD Bottom MD Total MD Top TVD Bottom TVD Sterling A5 6278 6291 13 5109 5118 a) If the zone produces sand and/or water or needs isolated, RIH and set patch across the perforations. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic Ivan River Undefined Gas pool encompasses: Tyonek, Beluga, and Sterling. add perforations to the Sterling A5 which was originally produced Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' -11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681"10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285"8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276"8.310" 7" TOC (USIT Log)5 Permanent Casing Patch Drift = 5.392 6270' - 6299'-5.518"- 6,118' MD 6 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 4,992' TVD 7 4-1/2' CIPB (9/1/21) 8,896' - - - 8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 10 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A5 6,279' 6,292' 5,110' 5,119' 07/13/20 (Isolated behind patch & 4-1/2" lin C2 6,548' 6,565' 5,322' 5,336' 4/21/2022 Open C2 6,555' 6,557' 5,328' 5,330' 4/21/2022 Open Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Open D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg Spud Date: 3698 psi @ 10,060' MD Description PBTD - Top of 7" Float equipment (Tagged 2/6/09) Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 SCHEMATIC SA5 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299' ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 6 7 8 SC2 Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' -11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681"10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285"8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276"8.310" 7" TOC (USIT Log)5 Permanent Casing Patch Drift = 5.392 6270' - 6299'-5.518"- 6,118' MD 6 4-1/2" CIBP w/25' cement TOC @ 6665' (9/19/21) 6,690' - - - 4,992' TVD 7 4-1/2' CIPB (9/1/21) 8,896' - - - 8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 10 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A5 6,278' 6,291' 5,109' 5,118' Proposed A5 6,279' 6,292' 5,110' 5,119' 07/13/20 (Isolated behind patch & 4-1/2" lin C2 6,548' 6,565' 5,322' 5,336' 4/21/2022 Open C2 6,555' 6,557' 5,328' 5,330' 4/21/2022 Open Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Open D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Spud Date: 3698 psi @ 10,060' MD Description PBTD - Top of 7" Float equipment (Tagged 2/6/09) Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 PROPOSED SCHEMATIC SA5 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299'ID = 5.518Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 6 7 8 SC2 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/09/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL IRU 11-06 (PTD 208-184) PERF 04/21/2022 Please include current contact information if different from above. 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Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL IRU 11-06 (PTD 208-184) Standby 09/23/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/09/2021 By Abby Bell at 8:46 am, Nov 09, 2021 MEMORANDUM TO: Jim Regg I2y� (2c;7,1 P.I. Supervisor FROM: Lou Laubenstein Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, November 8, 2021 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC 11-06 IVAN RIVER UNIT 11-06 Sre: Inspector Reviewed B+�' P.I. Supry `,JP Comm Well Name IVAN RIVER UNIT 11-06 API Well Number 50-283-20130-00-00 Inspector Name: Lou Laubenstein Permit Number: 208-184-0 Inspection Date: 10/26/2021 Insp Num: mitLOL211030102844 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 11-06 'Type Inj N TVD Tubing 1124 1124 _ 1124. 1124 - 1124 1124 PTD 20818.40 'Type Test SPT Test psi 2000 IA 224 2205 - 2154 - 2115 2080 - 2048 ' BBL Pumped: 0s ' BBL Returned: 0.8 OA o 0 0 o a o Interval OTHER P/F P � Notes: MIT -IA to 2000psi per Sundry #321-305 1 S N&tCQ r— Monday, November 8, 2021 Page 1 of 1 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL IRU 11-06 (PTD 208-184) PERF 08/29/2021 Please include current contact information if different from above. 10/26/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Coil Cleanout 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: 6690, 8896, Total Depth measured 10,060 feet 9512, 9666 feet true vertical 8,270 feet See Schematic feet Effective Depth measured 6,665 feet 5825; 5915 feet true vertical 5,419 feet 4792; 4852 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 9,492' MD 7,792' TVD Baker ZXP Pkr; 5,825' MD 4,792' TVD Packers and SSSV (type, measured and true vertical depth)Baker SC-2; N/A 5,915' MD 4,852' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Contact Phone: 321-305 & 321-468 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 2,799 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 1,320 Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442Dan Marlowe, ASC Team Operations Manager, 907-283-1329 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 04,465 0 651 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 171' 1,016' 8 Structural TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 208-184 50-283-20130-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 032930 Ivan River / Undefined Gas Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Ivan River Unit (IRU) 11-06 measuredPlugs Junk measured Length 171' 1,016' Size Conductor Surface Intermediate 20" 13-3/8" 9-5/8" Production Liner 6,015' 4,195' Casing 171' 1,016' 4,920' 8,238' 6,015' 10,020'7" 3,090psi 5,410psi 5,020psi 5,750psi 7,240psi Burst Collapse 2,670psi t Fra O 6. A PG , R Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 8:13 am, Oct 20, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.19 14:08:42 -08'00' Dan Marlowe (1267) SFD 10/20/2021 RBDMS JSB 113023 DSR-10/20/21 Rig Start Date End Date 7/21/21 9/25/21 07/24/2021 - Saturday Offload barge and truck equipment to rigsite, stage on pad. Conduct Pre-Spud with crew on upcoming well intervention. Move Pollard boom truck to location. Instrument tech removing instrumentation, shut off glycol supply. Use Vac truck to evacuate lines of glycol. RD flow line and heater line valving. Stage grating and flow lines off to side. Prep pad, lay out herculite. Stage in base beam and Carrier, raise derrick. Stage in pits unit. Send in Witness Notification for BOP Test to AOGCC, request witness for 0700 hrs Monday July 26. PJSM with crew regarding continuing rig up. Emphasis on staging in equipment with trucking, handling high pressure hoses, wildlife awareness. Stage high pressure hose basket, begin laying out hoses. Trucking on location. Stage in mud pump, choke house. Pick and stage in Accumulator skid. Offload workboxes for wellhead prep. RU circulation lines, prep tree for bullhead kill. Take on fluid, mix KWF of 6% KCL 8.5+ ppg water. Open to well, 830 psi on tubing. Bullhead kill well with 165 bbls of 8.5+ ppg water a 4.2 bpm 400 psi initial, catch fluid pressure increase to 2980 psi, lower rate to maintain 2,800-2,900 psi. Shut down, monitor well, on slight vac. Secure location for evening. Water drawn from supply well 257 bbls. 07/25/2021 - Sunday Safety meeting with crew, discuss diesel leak at another location and busy truck traffic on tight roads. Open to well, ~500 psi on tubing. Bleed off quickly to 0 psi. Agitate mix fluid, ensure 8.5 ppg, fill well - took 39 bbls. Function all lockdowns in preparation for pulling tomorrow. Layout handling equipment and begin to service in prep for pulling pipe tomorrow. Install BPV. ND tree and set to side. NU drilling spool adapter. NU 13-5/8" BOP stack: Mud cross with manual Kill side and HCR Choke, Shear rams, 2-7/8" x 5" Variable rams, 2-3/8" fixed rams, 13-5/8" annular element. Install hydraulic and Choke / Kill lines. Install Rig Floor and stairs. Record BOP measurements. Function test BOP. Secure location for evening. Water drawn from supply well 140 bbls, cumulative 397 bbls. 07/21/2021 - Wednesday Move equipment from 401 storage at Rig Tenders to staging at OSK Dock. Re-arrange trailers to tighten up loads, send unnecessary equipment back to storage. 07/22/2021 - Thursday Re-arrange and load trailers, stage at loading ramp. Load out barge. 07/23/2021- Friday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Bullhead kill well with 165 bbls of 8.5+ ppg water a 4.2 bpm 400 psi initial Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 PJSM with crew, emphasis on tripping operations, handling pipe, congested pad. Open to well, 15 psi that bled immediately. Fill well, took 40 bbls of 8.5 ppg KCL. POH with 2-3/8" 4.6# L-80 IBT heater string. Recovered 111 jts. Swap out handling equipment from 2-3/8" to 3-1/2". Pull 3-1/2" completion from Seal Assembly with landing jt, pull hanger to floor, circulate down tubing to flush tubing and backside (took 15 bbls to catch returns). LD hanger. POH with 3-1/2" 9.3# L-80 IBT tubing string from Packer / Seal Assembly at 5,920' and LD. 3,430' out of hole. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 204 bbls, cumulative total 707 bbls. 07/26/2021 - Monday Safety Meeting with crew, emphasis on pressure control, working at heights. Inspect equipment that arrived on last nights barge. Pull crossovers and test joints off trailers that arrived last night. Build 2-3/8" test joint. Test 13-5/8" BOP equipment per AAO and AOGCC requirements. Conduct shell test. Test with 2-3/8" test joint for upper fixed rams, 2-7/8" and 4-1/2" test joints for lower 2-7/8" x 5" variable rams. Test to 250 psi low / 2,500 psi high for all tests for 5 minutes. Test witness waived by Jim Regg. Test alarms, conduct Accumulator drawdown test. Clear and clean floor of pressure test equipment. RU for pulling TWC / BPV, pull. Well on vac, fill well. Took 33 bbls 8.5+ ppg KCL fluid to catch returns. RU equipment to pull 2-3/8" heater string and lay down. Find improper equipment on location, make calls to have XO sent over. While waiting, RU in attempt to free 3-1/2" string. MU landing joint, BOLDS, pull free at 60k with 9' of free travel at 55k. Set back down and RILDS. Downtime - waiting on XO to pull heater string (cannot proceed since it is dual-string completion and no way to de-complete dual or ensure well control with both strings hanging). MU XO to landing jt, stab in and MU to 2-3/8" heater string. BOLDS, lift until string weight, back off to "J" out of hanger. String is free. Attempt to POH with 2-3/8" heater string laying down, Farr tongs (new to rig) not working properly, swap out to Fosters and RU. Fill well with 9 more bbls 8.5 ppg KCL. Hang off and secure well for evening. Water drawn from source well today 106 bbls, cumulative total 503 bbls. 07/27/2021 - Tuesday 07/28/2021 - Wednesday Safety Meeting with crew, emphasis on tripping operations, opening to well, handling BHA. Open to well, on significant vacuum. Fill with 96 bbls 8.5 ppg KCL while inspecting equipment, changing out dies in tongs. POH with 3-1/2" 9.3# L-80 IBT tubing string and lay down. 186 joints, 2 pups and the Seal Assembly recovered. Clear and clean rig floor. MU packer retrieval BHA: Baker SC-1 Retrieving tool, XOs, Cobalt Bumper Sub, Cobalt Jars, 4 each 4-3/4" Drill Collars, XO sub - OAL 155.81'. Swap out handling equipment from 3-1/2" to 2-7/8". RIH with packer retrieval BHA on 2-7/8" PH6 workstring. Tag up on depth at 5,921', engage with SC-1 tool. While picking up, jars fired and string free. Break circulation at 4 bpm while packer elements are relaxing. CBU 392 bbls of 8.5 ppg KCL. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 104 bbls, cumulative total 811 bbls. POH with 2-3/8" 4.6# L-80 IBT heater string. Recovered 111 jts. Downtime - waiting on XO to pull heater string (cannot proceed since it is dual-string completion and no way to de-complete dual or ensure well control with both strings hanging Test to 250 psi low / 2,500 psi high MU packer retrieval BHA POH with 3-1/2" 9.3# L-80 IBT tubing string from Packer / Seal Assembly at 5,920' and LD. 3,430' out of hole Pull 3-1/2" completion from Seal Assembly with landing j POH with 3-1/2" 9.3# L-80 IBT tubing string and lay down. 186 joints, 2 pups and the Seal Assembly recovered 13-5/8" BOP equipment per AAO and AOGCC requirements Test witness waived by Jim Regg Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Safety meeting with crew, Baker Fishing Rep, and Hilcorp Safety Rep, emphasis on monitoring laydown machine, inspecting fall arrest equipment, handling odd size BHA. Open to well, no pressure, took 37 bbls of 8.5 ppg KCL to fill. RIH with Milling BHA #1 on 2-7/8" workstring: 6.151" OD 5-blade junk mill, 7" scraper, 6.151" OD String Mill, bumper sub and jars, 2 each drill collars, OAL 95.91'. Stage in and RU Power Swivel, swap out handling equipment. RU Power Swivel unit. Make connection, bring on pumps and rotate through from 6230' to 6350' with mill and scraper BHA. Nothing remarkable first 60'. Increase in rotation torque at 6248' through 6283' with up to 5k torque. (Reamed through with 3 passes). Once through, all clean. Stand back Power Swivel. Pick up remaining 2-7/8" off of rack and RIH to make stands. No issues running in or change in Slack Off Weight. POH with BHA #1 on 2-7/8" workstring standing back. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 0 bbls, cumulative total 914 bbls. 07/31/2021 - Saturday PJSM with crew, Baker Rep, Hilcorp safety rep, emphasis on overhead loads, handling BHA, transferring fluids. Open to well, no pressure and well on slight vacuum, 22 bbls to fill with 8.5 ppg KCL. POH with Milling BHA #2 standing back 2- 7/8" workstring. Change out elevators. Stand back jar and bumper sub. LD String Mill / Scraper BHA. Stage in BHA #3 of Mohawk ReLine HYD 5-1/2" x 7" casing patch with RA PIP tag in collar of pup joint. OAL of patch 35.92'. Top seal is 1.96', bottom seal is 3.51'. RIH with patch BHA on 2-7/8" workstring. E-line on location, stage unit in while RIH. Stage RA Tag of patch on depth at 6243'. RU E-line, RIH with CCL and GR tools. Log across ZXP liner top and liner hanger, poor CCL info but GR info good. make correction, re-log. Send log to town for correlation, no correction. POH with E-line, begin RD. RIH, set bottom of patch on depth at 6,303', covering interval with seals from 6,270'-6,299'. Ensure well is fluid packed while pumping ball down to seat. With ball on seat, close in Annular and pressure up to 2,600 psi to initiate setting process, simultaneously picking up on workstring to pull Mandrel through patch. initial PUW 35k, PUW pulling Mandrel 36k with pump. Pop out of patch, test to 500 psi, no bleed. Break off pups, change out handling equipment. POH with BHA #3 on 2-7/8" workstring standing back. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 6 bbls, cumulative total 920 bbls. 07/29/2021 - Thursday Safety meeting with crew and with Baker Fishing rep, emphasis on opening to well with pressure on it, handling large BHA, monitoring hole fill. Well has 30 psi on backside. Took 37 bbls 8.5 ppg KCL to fill. POH with 2-7/8" workstring standing back. Tight pull with Packer / Sealbore Assembly through 6.276" ID ZXP Packer at 5,844'. No further issues POH. Swap out handling gear for BHA. LD two drill collars, stand back two drill collars, lay down rest of retrieval BHA. POH and lay down Packer and Sealbore assembly and lower 3-1/2" tubing string. Chain broke on lay down machine. Repair chain. (Still maintaining POH using loader and strap). Continue to POH with lower 3-1/2" tubing string using lay down machine again. Recover 111 full jts, ported fill disk assembly and auto-fire pup jt. Swap out handling equipment for picking up BHA. MU String mill / Scraper BHA with bumper sub and jars, OAL 95.91'. Swap back to 2-7/8" handling equipment. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 103 bbls, cumulative total 914 bbls. 07/30/2021- Friday RIH with patch BHA on 2-7/8" workstring set bottom of patch on depth at 6,303', covering interval with seals from 6,270'-6,299 RIH with Milling BHA #1 on 2-7/8" workstring lay down Packer and Sealbore assembly and lower 3-1/2" tubing string Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 08/01/2021 - Sunday Safety Meeting with crew, Baker Rep, Hilcorp Safety Rep, emphasis on loader operation, opening to well, tripping operations. Open to well, 0 psi (cased hole now with tested patch in). POH with Patch running tool BHA #3. LD BHA, clear and clean rig floor, swap out handling equipment. MU BHA #4 Shoe Milling BHA: mill with 5.393" OD with jar and bumper sub and 2 each 4-3/4" drill collars. OAL 88.12'. RIH with BHA #4 on 2-7/8" workstring, tag up on depth at 6,303'. MU to Power Swivel. Break circulation at 1.5 bpm, slack off to begin to mill shoe out of Mohawk Casing Patch. Vary SOW at 1.4 - 4.0k down, circ rate 1.5-1.6 bpm, 2.5-4.0k ft/lbs torque during milling. Once through, conduct several ream passes, clean pass through with no pump or rotation. RD from Power Swivel. PU 2-7/8" singles off of rack and RIH to make stands. Change out dies for breakout. POH with BHA #4 standing back workstring. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 140 bbls, cumulative total 1,060 bbls. 08/02/2021 - Monday Safety Meeting with crew and Baker rep, emphasis on tripping operations and LD of BHA. Open to well, static. POH standing back workstring. LD Milling BHA #4 and clear floor. Swap out handling equipment to lay down drill collars, bumper sub and jar. Swap out handling equipment. MU cleanout BHA #5 with 2-3/8" Muleshoe, 3 joints of 2-3/8" tubing. RIH with BHA #5 on 2-7/8" workstring. Bottom of pipe at 9,507'. Line up to reverse circulate off bottom. Reverse circ at 43.5-4.0 bpm, 900-1,200 psi. No metal, plenty of sand returns to surface, total volume 77 bbls reversed. RU to hang off with string from Test Plug. Test 13-5/8" BOP equipment per AAO and AOGCC requirements, AOGCC Rep Austin McLeod on location to witness. Conduct shell test. Test with 2-7/8" and 4-1/2" test joints for lower 2-7/8" x 5" variable rams. Test to 250 psi low / 2,500 psi high for all tests for 5 minutes. Conduct Accumulator drawdown test, test gas alarms. LD test equipment, swap out handling equipment. POH with Cleanout BHA #5 standing back with 2-7/8" workstring. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 69 bbls, cumulative total 1,129 bbls. 08/03/2021 - Tuesday Safety meeting with crew and Baker rep, emphasis on tripping operations. Open to well, POH with 2-7/8" workstring standing back. Break off, LD 3 jts 2-3/8" tubing and Muleshoe. Change out handling equipment, line out circulation for filling completion tubing, stage in tubing. RIH with 4-1/2" 12.6# L-80 IBT-M completion per running tally: Float Shoe, 2 jts, Float Collar, jts 3-165 (centralizers on even jts 102-164). Average MU torque used 2,650 ft/lbs. Complete filling pipe, assist cementers with RU. Hang string off, secure well for evening with Floor valve. Water drawn from source well today 84 bbls, cumulative total 1,213 bbls. Test 13-5/8" BOP equipment per AAO and AOGCC requirements, AOGCC Rep Austin McLeod on location to witness MU BHA #4 Shoe Milling BHA MU cleanout BHA #5 with 2-3/8" Muleshoe RIH with 4-1/2" 12.6# L-80 IBT-M completion per running tally Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Safety Meeting with crew, emphasis on tripping operations and high pressure pumping during cement job. Inspect equipment. RIH with 4-1/2" 12.6# L-80 IBT-M tubing from jt 166 to 293 (centralizers on even jts 102-202). Tag at 9,502' with jt 294. Pick-up, LD jt 294, space out with 10.20' of pups and land string with hanger. SIMOPS: stage in and RU for cement job. Complete RU. PT lines to 4,500 psi. Mix 228 bbls of 15.3 ppg cement, pump 220 bbls away at 4 bpm, 300- 370 psi. Drop wiper plug, displace with fresh water at initial rate of 3 bpm, 670 psi, max 6.7 bpm at 1700, final rate 3 bpm, 2,050 psi. Reciprocate with 120 bbls away, land out for last 14 bbls. Down on pump at 144.25 bbls, hold 2,500 psi. Bleed pressure and check floats, no flow. CIP 1525 hrs. Clean up and RD cementers. RILDS, test hanger void to 5,000 psi, good test. Change out handling equipment. MU Cleanout BHA #5: 3.75" Mill, 4-1/2" scraper with XO to 2-7/8" workstring, OAL 7.73'. SIMOPS: cleaning Halliburton cementing units, separating out rental tools. RIH with Cleanout BHA #5 on 2-7/8" workstring. SIMOPS: cleaning out pits. Hang off and secure well for evening. No water drawn from source well today. 08/05/2021 - Thursday Safety meeting with crew, emphasis on tripping ops, pressure testing, overhead loads when ND BOP. Inspect equipment, open to well. RIH with Cleanout BHA #5: 3.75" Mill, 4-1/2" scraper with XO on 2-7/8" workstring. Tag PBTD at 9,420' (Float collar set at 9,423'). Pick up off bottom with Cleanout BHA. RU to circulate, circ down workstring at 4.0 bpm, 2,900 psi. CBU with 100 bbls fresh water, mixed dirty and cement residue returns, cleaned up with last 10 bbls. Line up to test, conduct MIT-IA of 4-1/2" x 9-5/8" to 2,000 psi for 30 min on chart. start 2,150 psi, end 2,040 psi, good test. Bleed, line up to test 4-1/2" tubing to 2,100 psi for 10 min, 0 bleed, good test. Bleed pressure. POH with 2-7/8" workstring laying down singles. SIMOPS: clean pits, begin moving equipment off location. Lay down BHA, close in well to Blinds. Well is filled with clean 8.34 ppg fresh water. RD Rig floor, prep for ND BHA. Location secure for evening. 08/06/2021- Friday Safety meeting with crew, emphasis on heavy loads, loader activity. ND BOP. NU Tree. Test against K-neck seal (isolation from tubing hanger adapter) failed, body test against tree good. Pull BPV. Continue with rigging down and moving trailers to barge location. Rig release at 1530, make final sweep to clean area. Mobilize crew to airstrip. Wait on plane, fly crew back to Kenai and release. 08/04/2021 - Wednesday 08/18/2021 - Wednesday Morning Meeting- JSA-Permit- Depart to pad. Arrive to pad- gather broken parts - depart for metal shop. Send parts specs to town- begin standby. Receive parts from town- depart for pad. Arrive at pad- begin preliminary repair work. Depart for camp and arrived at 21:20. 15.3 ppg cement, pump 220 bbls away at 4 bpm, 300- 370 psi. Drop wiper plug, displace with fresh water Bleed, line up to test 4-1/2" tubing to 2,100 psi for 10 min, 0 bleed, good test conduct MIT-IA of 4-1/2" x 9-5/8" to 2,000 psi for 30 min on chart. start 2,150 psi, end 2,040 psi, good test. CBL log run 8/14/21. Approval to proceed with perfs granted on 8/17/21. See attached emails. bjm Tag PBTD at 9,420' (Float collar set at 9,423') Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 05:30 Morning Meeting- Perform JSA - Gain permit approval- Depart for pad. Arrive at pad - pull bind up to 3,400# from 6,740' KB - standby for fluid bypass. RIH to 9,372' KB - Tag Bottom. Drop 3' centralized cutter - Allow 8 minutes & work string - No cut indications -drop 5' 1.75 cutter- Allow 8 minutes & pull up to 3,400# Not cut indication - Drop 4'10" 2.7 centralized cutter bar- Allow 8 minutes & work string - No cut indication - Standby for Kinley Cutters. Safety Meeting- Drop Kinley cutters - Cut on impact- Standby for charge to det. POOH slowly - POOH stubigging boc @ 2,823' KB. Begin R/D - Secure well & equipment for the evening. Depart for camp & arrived at camp. 08/21/2021 - Saturday Morning Meeting - Perform JSA - Gain permit approval - Depart for pad. Begin R/U. RIH W/3.75" LIB to 3,708' KB - sit down - POOH W/Wire indications. Begin standby for tools. Gather tools - depart for pad. Add Lubricator - Prep overshot. RIH W/ 4-1/2 GR" W/ 3.75" Baitsub W/ 3.75" Bell overshot to 3,726' KB- W/T - Pull up w/50# extra- come up 30' & lose weight - RIH and fall to 3,750' KB - POOH. RIH W/3.75" LIB to 3,890' KB - sit & fall to 4,270' KB - sit &fall to 4,536' KB - Tag - POOH W/ wire indication. RIH W/ 4-1/2" GR W/3.75" Baitsub W/ 3.75" Bell overshot to 4,536' KB & fall slowly to 5,000' KB- POOH. Begin laydown - secure well & equipment for the evening. Depart for camp. 08/22/2021 - Sunday Morning Meeting - Perform JSA - Gain permit approval - Depart for Dad. Begin R/U. RIH W/3.75" LIB 6,429' KB - W/T - POOH W/wire impression on face & wire impression on side of block. Standby. RIH w/ 3.75" Centrilizer W/3.75" Magnet to 6,414' KB - SIT-POOH slow w/ no return *Lose chatter 3,300'. RIH w/3.75" Mag to 3,310'-POOH- No return. RIH W/same to 6,430'KB - POOH slow- no return. RIH w/3.75" LIB to 74'KB- Sit down-POOH - no return. RIH W/3.75" Magnet to 75' KB- POOH - no return. RIH w/3.75" LIB to 482'KB- sit down - POOH W/faint wire mark. RIH w/ Braided line brush W/centralizer to 725'KB 0 W/T - POOH w/no return RIH w/3.7" Magnet w/ 3.7 centralizer to 931' - POOH w/ no return. RIH w/wirebrush w/3.75" centralizer to 6,437'KB - POOH slow w/no return. RIH w/3" LIB to 9,436' KB W/T - POOH W/Kinley neck impression. Begin lay down - secure well & equipment for the evening - depart for cam 08/19/2021 - Thursday Mobilize AK E-line and Fox Energy N2 to West Side. Standby while slick repairs unit. Slick Line. 5:30 Morning Meeting. 6:45 Arrive at pad- begin affecting repairs. 10:50 Take control of wire- begin POOH- Sprocket shear at 3,200# - remove parts. 11:30 Depart for weld shop- have modifications applied to sprocket - depart for pad. 13:40 Begin repairs. 16:10 take control of wire - Begin POOH from 6,740' - Overly heavy fluid load - pull up to 3,400#- allow for fluid to bypass-when weight dropped to 2,900# pull up till 3,400#- repeat once more and secure wire with clam & wireline valves- secure well & equipment for evening. Ended at 6,680'KB. 21:30 - Depart for camp. 08/20/2021- Friday Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 08/29/2021 - Sunday Conduct JSA and approve PTW. MIRU AK E-line and Fox N2 equipment. Move wellhouse over well. Finish rigging up equipment. MU GPT and stab onto wireline valves. PT to 250 psi low / 3,000 psi high. Open swab and RIH. Find fluid at 6,340' MD, 5,156' TVD. POOH. Pressure well to 1,050 psi with Nitrogen. MU 3-3/8" x 9' gun with 25 gram charges. GR/CCL to top shot = 10.0'. Open well and RIH. Log from 9,210' to ,8800'. Send correlation data to Geo. Shift log up 3'. Log up and stop GR/CCL at 9115'. Perforate 9,125' - 9,134'. Initial whp = 1,050 psi. 5 min = 1,050 psi. 10 min = 1,050 psi. 15 min = 1,050 psi. POOH with perf gun. Laydown gun and Confirmed shots fired. Laydown lubricator and install night cap. LDFN. 08/30/2021 - Monday Troubleshoot and repair Pollard Crane. MU and RIH with 3-3/8" x 20' gun and 25 gram charges. GR/CCL distance to top shot = 9.0'. Log up from 9,200' to 8,800' to correlate and send data to Geo. Confirm on depth. Perforate 9,030' - 9,050'. Initial WHP = 1,045 psi. 5 min = 1,052 psi. 10 min = 1,054 psi. 15 min = 1,056 psi. Confirm all shots fired at surface. MU and RIH with 3-3/8" x 10' gun and 25 gram charges. GR/CCL distance to top shot = 9.0'. Log up from 9,200' to 8,800' to correlate and send data to Geo. Confirm on depth. Perforate 9,020' - 9,030'. Initial WHP = 1,100 psi. 5 min = 1,102 psi. 10 min = 1,102 psi. 15 min = 1,104 psi. Confirm all shots fired at surface. MU and RIH with 3-3/8" x 14' gun and 25 gram charges. GR/CCL distance to top shot = 9.0'. Log up from 9,200' to 8,800' to correlate and send data to Geo. Shift log 1' down. Perforate 8,946' - 8,960'. Initial WHP = 1,134 psi. 5 min = 1,142 psi. 10 min = 1,144 psi. 15 min = 1,144 psi. Laydown lubricator and gun. Confirm all shots fired at surface. Install night cap. LDFN. Perforate 9,020' - 9,030 Perforate 9,125' - 9,134 Perforate 9,030' - 9,050 Perforate 8,946' - 8,960 Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Conduct JSA and approve PTW. Travel to location and MU GPT. RIH with GPT. Fluid level = 6,080'. POOH. Install weight bars on GPT toolstring. Jumper gas from 44-36 and pressure up tubing to 1,100 psi. Pump N2 and pressure up tubing to 2,900 psi. Fluid level = 6,200'. Increase tubing pressure to 3,500 psi with N2. Fluid level = 6,250'. Monitor for another 30 minutes, fluid level = 6,270'. POOH. Trap 3,400 psi of Nitrogen on well. Close swab and install night cap. Laydown lubricator and GPT toolstring. LDFN. 09/01/2021 - Wednesday Conduct JSA and approve PTW. Arrive on location. Tubing pressure = 3, 300 psi. RIH with GPT, find fluid level at 6,400' and tubing pressure = 3,300 psi. Fluid moved ~ 120' downhole with 3,300 psi tubing pressure last 12 hrs. RIH with 4-1/2" CIBP. Log up from from 8,900 - 8,700' and send data to RE/GEO. On depth. Set plug at 8,896'. Tag plug to ensure set. MU and RIH with 3-3/8" x 20' gun loaded with 22.7 gram charges. GR/CCL to Top Shot = 9.0'. Log up from 8,500' - 8,240' and send correlation data to RE/GEO. Shift up 2.5'. Perforate Beluga H10 from 8,409' - 8,429'. Initial pressure = 996 psi. 5 min press = 1,027 psi. 10 min press = 1,054 psi. 15 min press = 1,076 psi. Laydown lubricator and gun. Handover well to production. LDFN. 08/31/2021 - Tuesday Perforate Beluga H10 from 8,409' - 8,429 Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/02/2021 - Thursday Conduct JSA and approve PTW. Travel to location. Change out flow tubes on grease injection head. PT lubricator to 250 psi low/ 3,000 psi high. MU and RIH with GPT. Fluid level = 6,200'. Download 12' gun to 9' gun. MU and RIH with 3-3/8" x 12' (9' of 25 gram charges). GR/CCL to Top Shot = 14.0'. Send correlation data to RE/GEO. Shift up 3'. Perforate Beluga H8 from 8,293' - 8,302'. Well flowing at 1,000 psi. POOH. Laydown lubricator and gun. Install night cap. Handover well to Ops to flow. 09/03/2021- Friday MU & RIH with 3-3/8" x 10' with 22.7 gram charges. GR/CCL to Top Shot = 9.0'. Send correlation data to RE/GEO. shift down 1.5'. Perforate Beluga H3 8,095' - 8,105' (10'). MU & RIH with 3-3/8" x 6' with 22.7 gram charges. GR/CCL to Top Shot = 9.0'. Send correlation data to RE/GEO. shift down 1.0'. Perforate Beluga H 8,000' - 8,006' (6'). MU & RIH with 3-3/8" x 6' with 22.7 gram charges. GR/CCL to Top Shot = 9.0'. Send correlation data to RE/GEO. shift down 3.0'. Perforate Beluga G 7,627' - 7,633' (6). MU & RIH with 3-3/8" x 13' with 22.7 gram charges. GR/CCL to Top Shot = 9.0'. Send correlation data to RE/GEO. shift down 3.0'. Perforate Beluga F4 7,362' - 7,375' (13'). Laydown lubricator. Install night cap. Handover well to Ops to flow test. Flow test well. MU & RIH with 3-3/8" x 20' (15' loaded) gun with 22.7 gram charges. Perforate Beluga H3 8,095' - 8,105' Perforate Beluga F4 7,362' - 7,375 Perforate Beluga G 7,627' - 7,633 Perforate Beluga H 8,000' - 8,006 Perforate Beluga H8 from 8,293' - 8,302 Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Attempt to bleed down lubricator. Attempt to work wire uphole and downhole by hand. Unable to get wire to move in either direction. E-line wire still appears to be stuck in flow tubes. Cut E-line wire with lower master valve. Bleed off lubricator and pull out remaining wire. ***Fish left in Hole*** ***cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1-11/16" x 8.6') Total length = 21.6'. ***Estimated E-line length = 0.25" x 45'. **Total fish = 45 + 21.6' = 66.6'. RDMO. Hand well over to production. 09/09/2021 - Thursday Rih w/ 4-1/2'' wire finder baited w/ 4'' GS to 758'SLM w/tool to 764' pooh redress LIB. Rih w/ 3.66'' Lib to 743'slm sit bobble thru to 750' would not sit pooh no marks. Rih w/ 3.75'' magnet baited w/ 4-1/2'' GS while pumping diesel to 743'slm w/ tool falling slow make several passes to 950' pooh magnet had metal shaving only stand by for diesel. Rih w/ 4-1/2'' wire finder baited w/ 4'' GS to 758'SLM w/tool to 789' w/ tool would not fall pull up 50' will not fall pooh finger on wire finder bent preventing tools to fall. Rih w/ 3.75'' magnet baited w/ 4-1/2'' GS while pumping diesel falling slow from 670' to 1026'slm w/ tool would not fall pooh GR sheared leaving magnet & bait sub in hole. Rih w/ 4-1/2'' GS to 1,028' slm w/ tool would not latch pooh pin not sheared. Rih w/ same to same w/ tool beat down several times latch pull up to 800# jar lick came free pooh w/ magnet. LDFN 09/04/2021 - Saturday Send correlation data to RE/GEO, add 4' to log. Perforate Beluga D4L from 6,727' - 6,742' (15'). Confirm shots fired at surface. Sand in Bull Plug of gun. Handover well to Ops and flow test. MU and RIH with GPT toolstring. Log down from surface to 7,340' and set down weight. Pick up E-line and attempt to RIH at faster speed, set down at 7,432'. Pick up E-line and attempt to RIH faster, cannot fall deeper. Deepest depth reached was 7,432' (uncorrected). POOH with wireline. Have kinked or stranded wire in the flow tubes at surface. Close wireline valves and attempt to bleed off pressure in lubricator. Continued on next day. 09/05/2021 - Sunday Perforate Beluga D4L from 6,727' - 6,742' Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/10/2021- Friday MIRU. Rih w/ 3' stem w/ braided line brush from 700' to 1,200' make several passes cont. to 2,500' w/ no obstruction pooh. Rih w/ 3.7'' LIB baited w/ 4-1/2'' GR to 880' tag fluid continue to 3,478'slm w/ tool would not pass - looks like sand on low side of hole. POOH. Rih w/ 3' stem w/ blb to 3505'slm sit w/ tool would not fall pooh. Rih w/ 2.5'' x 6' dd bailer to 3500'slm sit w/ tool to 3,514' pooh full dry sand. Rih w/ same to 3,507'slm w/ tool to 3,521' pooh full same. Rih w/ same to 3,511'slm w/ tool to 3,523'slm pooh full same. LDFN MIRU. Rih w/ 3' stem w/ 4-1/2'' braided line brush to 5,538'slm . Rih w/ 3''x9' dd bailer to 5,534'slm w/ tool to 5,555' pooh full thick mud Rih w/ same to 5,556'slm w/ tool to 5,564' pooh full sand discuss plan forward. RDMO. 09/14/2021 - Tuesday Offload coil equipment from Barge. Mobilize equipment from barge landing to Ivan River. Spot equipment on location. LDFN. 09/11/2021 - Saturday MIRU. Rih w/ 3'' x 9' dd bailer to 3,800'slm no obstructions did not sit down pooh full slurry. Rih w/ 3.7'' lib baited w/ 4-1/2'' gs fluid level 660' cont. to 3,779'slm w/ tool down to 3,786' pooh. Rih w/ 2.5'' x 6' dd bailer to 3,900'slm no obstructions did not sit down pooh full slurry. Rih w/ 3' stem w/ braided line brush to 3,700'slm slow down to 100fpm to 3,800' pull up 50' repeat process to 5,635'slm. Rih w/ 3.7'' lib to 570' tag fluid cont. to 5,618'slm w/ tool pooh no marks on lib. Rih w/ 2.5'' x 6' dd bailer to 5,619'slm w/ tool to 5,626' pooh full sand. Rih w/ same to 5,622'slm w/ tool 5,630' pooh full sand. LDFN. 09/12/2021 - Sunday MIRU. Rih w/ 3'' x 9' dd bailer to 5,549'slm sit w/ tool to 5,560' pooh full sand. Rih w/ same to 5,553'slm w/ tool to 5,565' pooh half full solids slurry on top. Rih w/ 2.5'' x 6' dd bailer to 5,560'slm w/ tool to 5,570' pooh full same. Rih w/ same to 5,565'slm w/ tool to 5,570' pooh full same. Rih w/ same to 5,563'slm w/ tool to 5,575' pooh full same. Rih w/ 3' 'x 9' dd bailer to 5,555'slm w/ tool 5,575' pooh full same. Rih w/ same to 5,560'slm w/ tool to 5,577' pooh full same. Rih w/ same to 5,568'slm w/ tool to 5,581' pooh full same. Rih w/ same to 5,565'slm w/ tool to 5,583' pooh full same. Rih w/ same to 5,574'slm w/ tool to 5,583' pooh full same. LDFN. 09/13/2021 - Monday Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/15/2021 - Wednesday Conduct JSA and approve PTW. layout pit liner, spot tanks, berm in place. Spot pump truck, pick lubricator, iron racks, and BOP from float. RU to choke manifold and return tank. Function test BOP rams. Drawdown test on accumulator. Pressure test BOPE for 1.75" pipe to 250 psi low / 4,000 psi high. AOGCC waived witness per Jim Regg. Stab 1.75" coil through injector. Install night cap on BOP's. LDFN. 09/16/2021 - Thursday Conduct JSA and approve PTW. MU 1.90" CTC and pull test to 12k. MU 1.75" dual check valves and PT. MU 1.75" stinger and 1.75" JSN PT stack to 250/4,000 psi. Open well and RIH. WHP = 420 psi. Well pressured up while RIH, crack choke and hold ~ 100 psi. Wt check at 2,000' = 2,600#. Wt check at 4,200' = 8,200#. Start taking weight at 5510' ctmd, up wt = 12,000#. Online with pump at 1.5 bpm, ctp = 3,180 psi, hold choke ~ 100 psi. Mix up gel pill. Take bite to 5,700' and wiper trip uphole. Take bite to 5,900' and wiper trip uphole. Take bit to 6,100' and wiper trip uphole. Getting sand at surface. Take bite to 6,300', gel at nozzle. Pull uphole cleaning ~ 1,500'. RIH and take bite to 6,500' and wiper trip uphole. Send another gel pill and take 100' to 6,600'. Getting 1:1 returns. Clean across perf interval 6,727' - 6,742', did not see change in pressures. Cleanout to 6,800' ctmd with final gel sweep at nozzle. Mechanical counter = 6826' ctmd. Chase sand to surface. Close swab with 300 psi on wellhead. Laydown lubricator above coil BOP's. MIRU AK E-line. MU lubricator on top of coil BOP's. PT 250/2000 psi. RIH with CCL/junk basket and 3.75" gauge ring. Set down at ~ 6,650' (uncorrelated). Try to pick up and overpull. Work wire and appear to have 'lost' weight at 6,619' (uncorrelated). POOH with toolstring. Junk basket had sand, metal shavings, and black sponge material inside. Discuss plan forward with OE. Laydown wireline lubricator for night. Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/17/2021- Friday Conduct JSA and approve PTW. MU nozzle drift BHA. 1.90" CTC, 1.70" DFCV, 1.75" stinger, XO, 2.75" ball drop nozzle. PT stack to 250/4,000 psi. RIH with 2.75" nozzle. Pickup at 6,500' was 14k. Set down at 6,696' ctmd. Pull 5k over. Slack off weight and pickup again. Pull 5k over. Slack off weight and pull 10k over, not moving uphole. Slack off weight and bring pump online down coil taking returns to tank. Pick up and no overpull. POOH. No noticeable marks on BHA. Laydown lubricator and set injector on back deck. Discuss options with OE. AK E-line on location. MU drift BHA (cable head, weight bar, CCL, spangs, and 3.80" gauge ring. MU lubricator on top of coil BOPs. PT lubricator. RIH with 3.80" gauge ring BHA. Set down at 3530' (uncorrected). Pick ups are clean. Attempt to RIH at different speeds, pickup different depths, unable to get past 3,530'. POOH. Laydown toolstring, lubricator and wireline valves. Install night cap on coil BOPs. LDFN. Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Conduct JSA and approve PTW. Drift YellowJacket BHA with 3/4" ball, confirm ball seats on disco. MU 2.88" CTC, 2.88" DFCV, 2.88" Bi-Di Jars, 2.88" Disco, XO, XO, 3.80" gauge ring. Go to the well and PT stack. RIH. Wt check at 6500' ctmd = 15,500#. Set down at 6,655' ctmd, overpull 5k, online with pump and come free. Set down again at 6,655', overpull 7k, online with pump and come free. Paint flag at 6,650' (e), 6654' (m). POOH pumping down coil to keep hole full. No obvious marks on gauge ring on outside or inside. laydown lubricator and set injector on back deck. RU E-line wireline valves on top of coil BOP's. MU drift run with CCL, impact jars, spangs, and 3.80" gauge ring. RIH and cannot pass 3,530'. POOH. Change out gauge ring to a 3.75". RIH and tag at 6,570' (corrected). Try RIH faster, tag at same depth, no overpull. Flag wire at 6,425'. POOH. Laydown lubricator and wireline valve. LDFN. 09/18/2021 - Saturday Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/19/2021 - Sunday Conduct JSA and approve PTW. MU Coil Cleanout BHA. 2.88" CTC, 2.88" DFCV, 2.88" Bi-Di Jars, 2.88" Disco, XO, XO, 2.75" ball drop nozzle. Go to the well and PT stack 250/3,500 psi. Hold 100 psi on choke while RIH. wt check at 5,400' = 11,700#. Set down at 6,545' ctmd, pull and get overpull of 10k. Online with pump at 1.7 bpm, 3,250 psi pumping water. Hold 150 psi on choke. Take bite to 6,700' then wiper trip uphole. Cleanout to 6,800', pump 10 bbl gel pill, chase uphole once gel pill at nozzle, holding choke at 150 psi. Coil at surface. Laydown cleanout BHA. MU YellowJacket CIBP BHA. 2.88" CTC, 2.88" DFCV, 2.88" Disco, XO, 3.52" FH hydraulic setting tool, 3.59" adaptor sleeve, 3.59" FX CIBP (OAL = 14.74"). RIH at < 100 fpm. Run past setting depth, PUH and get weight back and position CIBP at 6,670'. Drop 5/8" ball, and circulate around until seats. Pressure up to 2,500 psi and shear to set. CIBP set at 6,670' ctmd. Set down 7k to ensure it doesn't move downhole. Shear off and park above CIBP ~ 2 '. Pump N2 down coil taking returns to surface to blowdown well. Pull out of hole pumping N2. At surface. Close swab. Laydown lubricator and set injector on back deck. RU E-line wireline valves on top of coil BOPs. MU drift run with GR/CCL and 3.75" gauge ring. MU lubricator and PT. GR/CCL to bottom of gauge ring = 24.3'. RIH and tag top of plug at 6,665' GR/CCL depth. No fluid in wellbore. Send data to RE/GEO. Add +1'. Offset = 24.3'. Top of plug: 6,666 + 24.3 = 6,690.3'. MU 30' of 3" dump bailer and mix 16 gallons of cement. Load 30' x 3' bailer with 9.2 gallons of cement and RIH and place on top of plug. Load 30' x 3' bailer with 6.8 gallons of cement and RIH and place on previous cement. Top of Cement = 6,665'. Laydown lubricator and toolstring. Remove wireline valves and install night cap on coil BOPs. LDFN. Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/20/2021 - Monday Conduct JSA and approve PTW. Cool down N2 unit. Pressure tubing to 1,500 psi with N2. Standby for approval to shoot Beluga D sand. MU Perf BHA: Rope socket (1' x 1.4"), gun gamm/ccl (6.3' x 3.125"), quick change (1.5' x 3.125"), sub (0.4' x 3.125"), blast sleeve (1.5' x 3.125"), sub (0.4' x 3.375"), Gun 15' (12 loaded) x 3.375", bull nose (0.4' x 3.375"). OAL = 26.5'. Loaded with 22.7 gram charges. GR/CCL to top shot = 10.5'. Install wireline valves above coil BOPs. MU lubricator and PT 250 psi low / 3,000 psi high. RIH with perf gun and log up from 6,630' - 6,300'. Send correlation data to RE/GEO. Add 2'. Pull into position and perforate 6,595' - 6,607'. Initial tubing pressure = 1,500 psi. Gun blown up hole. Wireline weight went from 1,100# to 400# after perforating. Tubing pressure increased from 1,500 psi to 2,070 psi instantly. Work wire increasing pull in 100# increments. Full free and start to POOH. Wireline stuck in flowtubes with ~ 250' of wire left in hole. Unable to move wire up or down. Cut wireline with lower master valve and bleed off wellhead pressure. Pull wire from tree. Close master valve and swab valve. ***Fish left in hole*** ***~ 250' of 0.25" wireline*** ***3-3/8" spent perf gun BHA. OAL = 26.5'***. Lay down lubricator. Remove wireline valves and install night cap on coil BOPs. LDFN. 09/21/2021 - Tuesday Conduct JSA and approve PTW. Travel to location. Monitor wind speeds. Wind speed gusts ~ 40 mph. Did not attempt to lift injector with crane. Standby. Haul water to supply tank. Transfer N2 from transport to pump truck. Wind gust ~ 40 mph. Continue to standby. Did not raise crane mast to lift coil injector due to wind speed gusting > 40 mph. Standby. LDFN. perforate 6,595' - 6,607 Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 Conduct JSA and approve PTW. Mobilize KCl, supply tank, and lubricator sections to location. Spot tank and start mixing 6% KCl with batchmixer. Mix 150 bbls of 6% KCl. Mix 150 bbls of 14% KCl as Kill Weight Fluid. SG = 9.12 ppg. Pump 10 bbls of 6% KCl down well to establish injectivity rate. Pump rate = 4.5 bpm, pump pressure = 2,240 psi, WHP = 2,100 psi. Spot crane to pickup extra lubricator. Measure and confirm BHA. LDFN. 09/22/2021 - Wednesday Conduct JSA and approve PTW. Weekly test of coil BOPE. Witness waived by AOGCC (Jim Regg) Function test all rams. Full body test, test all rams to 250 psi low / 4,000 psi high. MU CTC and pull test to 25K. MU 2.88" DFCV, 2,88" Bi-Di Jars, 2.88" disco, 2.88" circ sub and PT. MU 3.80" gauge ring with sucker rod connection. OAL = 13.5'. Open well. Tubing pressure = 2,100 psi. Snub into well at -11k lbs. Tag at 42'. Set down -15k. Clean pickup. Increase set down weights. Max set down of -33k lbs. No downward movement. Tag depth = 42'. Pump 2 bbls of methanol down tubing. RIH and tag at 42'. POOH. MU 3.88" LIB. RIH and tag at 42'. Set down ~ 9k and fish started moving downhole. stopped moving at 73'. Set down 10k and no movement. POOH. Wire marks on bottom and side of LIB. Close LMV, UMV, Swab and install night cap on coil BOPs. LDFN. 09/23/2021 - Thursday Rig Start Date End Date 7/21/21 9/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 09/24/2021- Friday Conduct JSA and approve PTW. MU lubricator and fishing spear for wireline BHA. BHA: 2.88" CTC, 2.88" DFCV, 2.88" Disco, 2.70" GS Spear, 2.88" GS Bait sub, 3.05" bit sub, 3.75" canfield bushing, 3.90" shoe, XO, 1.75" wireline grab. OAL = 15.62'. PT stack down backside to 250 psi low/ 3,500 psi high. Zero counters at bottom of lubricator. Open well and RIH. WHP = 2,010 psi. RIH and Tag at 77'. Set down -4k. POOH and cut wire with UMV and recover 70' of wire. RIH and Tag at 35'. Work wire up/down to 45'. POOH and cut wire with UMV and recover 65' of wire. RIH and Tag at 23'. Work wire up/down to 76'. POOH and no wire at UMV. Recover 85'' of wire. Identify end of wire was pulled from rope socket. Recover total of 220' of wire. MU and RIH with 3.88" LIB. Tag at 6,611' ctmd. Previous correlation vs. E-line indicated a 20' correction. Estimated corrected tag = 6,631' MD. POOH. LIB indicated impression of rope socket with no wire. Laydown BHA and blowdown coil with N2. Install night cap on coil BOPs and handover to Ops. LDFN. 09/25/2021 - Saturday RDMO. De-mob SLB Coil and Cruz Construction to Barge Landing. Field: RKB-GL 16.80' X: ASP4 Y: ASP4 Well Status: Operator: 171'Csg Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 3.958" 9,492' 0' 9,492' 3,000' * 4-1/2 cemented with 228 bbls 15.3 ppg cement, centralizers on even jts 102-202 (8/4/21) Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx Jewelry & Fish Description Depth Length ID OD 1 13-5/8" Tbg Hanger, 4-1/2" IBT-M Susp 17' 0.49' - 11.000" 2 9-5/8" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" 4 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" 7" TOC (USIT Log)5 Permanent Casing Patch Drift = 5.392 6270' - 6299'- 5.518" - 6,118' MD 6 4-1/2" CIBP w/25' cement TOC @ 5419' (9/19/21) 6,690' - - - 4,992' TVD 7 4-1/2' CIPB (9/1/21) 8,896' - - - 8 7" CIBP w 28' cement TOC @ 9487' (7/13/20) 9,512' 13.1' - - 9 CIBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - - 10 9,926' - - - Perforations (post 4-1/2 cemented tubing) Zone Top MD Btm MD Top TVD Btm TVD Date Sterling A5 6,279' 6,292' 5,110' 5,119' 07/13/20 (Isolated behind patch & 4-1/2" lin Beluga D 6,595' 6,607' 5,361' 5,371' 09/20/21 Open D4U 6,727' 6,742' 5,470' 5,482' 09/04/21 Isolated F4 7,362' 7,375' 6,001' 6,012' 09/03/21 Isolated G 7,627' 7,633' 6,224' 6,229' 09/03/21 Isolated H 8,000' 8,006' 6,535' 6,540' 09/03/21 Isolated H3 8,095' 8,105' 6,614' 6,623' 09/03/21 Isolated H8 8,293' 8,302' 6,779' 6,787' 09/02/21 Isolated H10 8,409' 8,429' 6,877' 6,893' 09/01/21 Isolated I5 8,946' 8,960' 7,330' 7,342' 08/30/21 Isolated I8 9,020' 9,030' 7,392' 7,401' 08/30/21 Isolated I8 9,030' 9,050' 7,401' 7,418' 08/30/21 Isolated I10 9,125' 9,134' 7,557' 7,488' 08/30/21 Isolated 10,020' Csg Updated by DMA 10-19-21 2,646,275 Producing 12/22/08 2:00 PM 134° @ 10,060' MD Hilcorp Alaska, LLC 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: 10,060' 359,785 API#: Hilcorp Alaska, LLC Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 4-1/2, 12.6# / L-80 IBT-Mod 6,665' Spud Date: 3698 psi @ 10,060' MD Description PBTD - Top of 7" Float equipment (Tagged 2/6/09) Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 IRU 11-06 Ivan River Unit Permit to Drill#: 208-184Lease & Serial#: ADL-032930 1 TA 2 3 4 4 3 5 4444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 10 MUD 10.1 ppg TB9 SCHEMATIC SA5 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299' ID = 5.518 Drift = 5.392 Beluga I5 - I10 F3 - Fish left in Hole at ~7400' - 9/5/21 cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1- 11/16" x 8.6') Total length = 21.6'. Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO F2 -Fish left in Hole at ~9400' - SL Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) F1 - Fish left in Hole at ~9716' - Haslliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) Beluga D4U - H-10' ~6800' top of sand/fill Beluga D PBTD = 6,665’ MD / 5,419’ TVD TD = 10,060’ MD / 8,270’ TVD 2 F1 F3 F2 6 7 8 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By:Date: DATE: 10/12/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL IRU 11-06 (PTD 208-184) Cast-M/CBL-M Cement Inspection 08/14/2021 Advanced Cement Evaluation 08/16/2021 Please include current contact information if different from above. Received By: 10/12/2021 37' (6HW 1 Guhl, Meredith D (CED) From:Davies, Stephen F (CED) Sent:Monday, September 20, 2021 1:01 PM To:AOGCC Records (CED sponsored) Subject:FW: Request to Perforate Beluga D in IRU 11-06 (PTD 2081840; Sundry 321-305) Please file. Thanks! From: Davies, Stephen F (CED) Sent: Monday, September 20, 2021 12:24 PM To: Anthony McConkey <amcconkey@hilcorp.com> Subject: RE: Request to Perforate Beluga D in IRU 11‐06 (PTD 2081840; Sundry 321‐305) Thank you Anthony. I appreciate your thoughts and excellent documentation. Bryan and I are discussing this. Thanks again and stay safe, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Anthony McConkey <amcconkey@hilcorp.com> Sent: Monday, September 20, 2021 11:33 AM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Brad Gathman ‐ (C) <Brad.Gathman@hilcorp.com> Subject: Request to Perforate Beluga D in IRU 11‐06 Hey Steve, The wellbore is currently plugged back over the Beluga D4 with a CIBP at 6690’ with 25’ of cement on top. We are requesting the ability to perforate the Beluga D sand (sundry interval: 6588’ – 6608’), and if wet set a plug over it without cement, and move uphole to the Sterling C2 (sundry interval: 6544’ ‐ 6567’). These sands were crossed out in Sundry 321‐305 (see attached, refer to Step 31 – line ‘h’), to provide room for a plug w/ 25’ of cement. We are asking for permission to still perforate this sand. With that being said, there is not a specific lithologic marker that separates the Beluga and Sterling. There appears to a ‘transitional’ region in lithology from Beluga to Sterling as you move shallower in the well. Despite the name “Beluga D” given to the interval, it can easily be argued that the sand is actually a Sterling sand. The logs suggest high porosity/permeability (same as Sterling A through C), as well as suppressed resistivities, which is something characteristic of Sterling. 2 Furthermore, Matt Petrowsky has researched drilling cuttings between the Beluga D and Sterling A‐C from IRU 11‐06 and has not seen any discernable difference in lithology between the sands. Now there is a point/depth where we certainly are in the Beluga. The perforations below the Beluga D4 (Beluga F4, G, H10, etc) are most likely ‘Beluga’ sands from a geologic perspective. The Beluga D4 is likely in that lithology ‘transition’ zone between Beluga and Sterling. All of these zones are currently plugged back with a CIBP and 25’ of cement. I believe the ‘Beluga D’ interval is closer to a ‘Sterling‐type’ sand, than a Beluga sand. Reasons for that statement are attributed to the similarities in sonic/NPHI crossover, lower resistivities, and high mudlog shows in comparison to the Sterling A‐C sands. Refer to the log attached. All in all, I think we’re walking away from potentially a high value/rate adding sand due to seemingly arbitrary nomenclatures. With your permission, we’d like to still perforate the Beluga D (6,590’ – 6,608’ MD) and still maintain the opportunity to perforate the Sterling C3 & C2 in the future. Which could be challenging if we have to set another plug with 25’ cement. Attached – Sundry 321‐305 & IRU 11‐06 Log. Please do not hesitate to contact myself [ 907‐529‐6199 (C), 907‐777‐8460 (O)], Matthew Petrowsky (Geo) [mpetrowsky@hilcorp.com, 814‐421‐6753 (C), 907‐777‐8404], or Jake Flora (OE) [Jake.Flora@hilcorp.com, 720‐988‐5375 (C), 907‐777‐8442] I respect your decision on the matter and appreciate you time, Thank you very much 3 4 Anthony McConkey Reservoir Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907‐777‐8460 (c) 907‐529‐6199 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. 1 Guhl, Meredith D (CED) From:McLellan, Bryan J (CED) Sent:Monday, September 20, 2021 12:49 PM To:Anthony McConkey; Davies, Stephen F (CED) Cc:Jacob Flora; Matthew Petrowsky; Taylor Wellman; Brad Gathman - (C) Subject:RE: Request to Perforate Beluga D in IRU 11-06 Anthony and Jake, Steve Davies is in agreement with your assessment that the Beluga D4 is in the transition between Beluga and Sterling and was probably arbitrarily labeled as part of the Beluga. We can include the Beluga D4 in this well as part of the Sterling sand, and thus there is no need to set a plug between the proposed perfs currently labelled Beluga D4 and Sterling C3 in Sundry 321‐305. It is not in anyone’s interest to leave pay behind in this well due to an arbitrarily assigned label. The remaining perforated intervals in the Beluga have already been isolated with a CIBP and 25’ cement cap. Hilcorp has AOGCC approval to perforate the interval labeled in Sundry 321‐305 as the Beluga D4 (6588‐6608’ MD), recognizing that they were originally stricken from this Sundry. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Anthony McConkey <amcconkey@hilcorp.com> Sent: Monday, September 20, 2021 11:33 AM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Jacob Flora <Jake.Flora@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Brad Gathman ‐ (C) <Brad.Gathman@hilcorp.com> Subject: Request to Perforate Beluga D in IRU 11‐06 Hey Steve, The wellbore is currently plugged back over the Beluga D4 with a CIBP at 6690’ with 25’ of cement on top. We are requesting the ability to perforate the Beluga D sand (sundry interval: 6588’ – 6608’), and if wet set a plug over it without cement, and move uphole to the Sterling C2 (sundry interval: 6544’ ‐ 6567’). These sands were crossed out in Sundry 321‐305 (see attached, refer to Step 31 – line ‘h’), to provide room for a plug w/ 25’ of cement. We are asking for permission to still perforate this sand. With that being said, there is not a specific lithologic marker that separates the Beluga and Sterling. There appears to a ‘transitional’ region in lithology from Beluga to Sterling as you move shallower in the well. Despite the name “Beluga D” 2 given to the interval, it can easily be argued that the sand is actually a Sterling sand. The logs suggest high porosity/permeability (same as Sterling A through C), as well as suppressed resistivities, which is something characteristic of Sterling. Furthermore, Matt Petrowsky has researched drilling cuttings between the Beluga D and Sterling A‐C from IRU 11‐06 and has not seen any discernable difference in lithology between the sands. Now there is a point/depth where we certainly are in the Beluga. The perforations below the Beluga D4 (Beluga F4, G, H10, etc) are most likely ‘Beluga’ sands from a geologic perspective. The Beluga D4 is likely in that lithology ‘transition’ zone between Beluga and Sterling. All of these zones are currently plugged back with a CIBP and 25’ of cement. I believe the ‘Beluga D’ interval is closer to a ‘Sterling‐type’ sand, than a Beluga sand. Reasons for that statement are attributed to the similarities in sonic/NPHI crossover, lower resistivities, and high mudlog shows in comparison to the Sterling A‐C sands. Refer to the log attached. All in all, I think we’re walking away from potentially a high value/rate adding sand due to seemingly arbitrary nomenclatures. With your permission, we’d like to still perforate the Beluga D (6,590’ – 6,608’ MD) and still maintain the opportunity to perforate the Sterling C3 & C2 in the future. Which could be challenging if we have to set another plug with 25’ cement. Attached – Sundry 321‐305 & IRU 11‐06 Log. Please do not hesitate to contact myself [ 907‐529‐6199 (C), 907‐777‐8460 (O)], Matthew Petrowsky (Geo) [mpetrowsky@hilcorp.com, 814‐421‐6753 (C), 907‐777‐8404], or Jake Flora (OE) [Jake.Flora@hilcorp.com, 720‐988‐5375 (C), 907‐777‐8442] I respect your decision on the matter and appreciate you time, Thank you very much 3 4 Anthony McConkey Reservoir Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907‐777‐8460 (c) 907‐529‐6199 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. 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 Coil Cleanout: 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,420'N/A Casing Collapse Structural Conductor Surface 2,670 psi Intermediate 3,090 psi Production 5,410 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng jake.flora@hilcorp.com 7,765'8896'7,330'1,916 8896', 9666' Baker ZXP Pkr, Baker SC-2 Retrievable Pkr; N/A 5,825' MD / 4,792' TVD, 5,915' MD / 4,852' TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 032930 208-184 50-283-20130-00-00 Ivan River Unit (IRU) 11-06 Ivan River / Undefined Gas Length Size CO 614 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# / L-80 (prod) TVD Burst 9420' 7,240 psi MD 5,750 psi 5,020 psi 171' 1,016' 4,920' 171' 1,016' 8,238'7" 20" 13-3/8" 171' 9-5/8"6,015' 1,016' 10,020' Perforation Depth MD (ft): 6,015' See Attached Schematic 4,195' Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: Tuesday, September 14, 2021 4-1/2" (cemented monobore) Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 12:41 pm, Sep 13, 2021 321-468 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.13 11:53:16 -08'00' Dan Marlowe (1267) SFD 9/13/2021 8,270 10-404 DSR-9/13/21BJM 9/13/21 SFD 9/13/2021 10,060' CT BOP test to 4000 psi. X Tuesday, September 14, 2021 dts 9/14/2021 JLC 9/14/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.14 11:17:30 -08'00' RBDMS HEW 9/14/2021 Well Prognosis Well: IRU 11-06 Date: 9-13-2021 Well Name: IRU 11-06 API Number: 50-283-20130-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 9/14/21 Rig: Coil Tubing Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 208-184 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (985) 632-4113 (C) AFE Number: Max. Expected BHP: ~ 2,484 psi @ 5,680’ TVD (Based on 0.437 pressure gradient) Max. Potential Surface Pressure: ~ 1,916 psi (Based on expected BHP and gas gradient to surface (0.1 psi/ft)) Well Status IRU 11-06 is currently SI with ~1000’ of sand over the uppermost perforations. Brief Well Summary IRU 11-06 was worked over in August of 2021 when the producing Sterling perfs were patched over, and a 4-1/2” monobore was cemented in place to provide a monobore to test Beluga sands below. While swabbing the wellbore dry to perforate, the slickline unit broke down leaving the swabbing toolstring at TD which was cut and left there. Four Beluga sands were perforated, deemed wet, and plugged over with a CIBP at 8896’. Seven additional sands were then perforated, which sanded off the wellbore while attempting to test the zones. The objective of this sundry is to use coil tubing to clean out to the top set of open perfs, set a CIBP, blwo down the well with Nitrogen, and continue testing zones per the original sundry. Procedure 1. MIRU Coiled Tubing, Provide AOGCC 24hrs notice. PT BOPE to 4,000 psi Hi 250 Low. 2. MU cleanout BHA, trip in to top of fill, clean out well to ~6800’, keep pressure on well. 3. RU E-line over the coil BOPE, PT lubricator to 2500 psi, Set CIBP at ~6710’ above the open perfs at 6721’ – 6742’. RD E-line. 4. RIH w/ nozzle to 6700’. MIT CIBP to 1500 psi. 5. RU Nitrogen, blow well down trapping 1500 psi of pressure. 6. RU E-line, PT lubricator to 2500 psi. 7. Perforate below sands from the bottom up: 8. Turn Well over to Production. Attachments 1. Actual Schematic 2. Proposed Schematic 3. BOP Schematic 4. Standard Well Procedure – N2 Operations SFD 9/13/2021 The objective of this sundry is to use coil tubing to clean out to the top set of open perfs, set a CIBP, blwo down the well with Nitrogen, and continue testing zones per the original sundry. (No. 321-305) Per Sundry No. 321-305 in accordance with AOGCC's requirements specified in that Sundry. SFD 9/13/2021 Field: RKB-GL X: ASP4 16.80'Y: ASP4 RKB-MSL Well Status: 46.80'Operator: GL-MSL: 171'Csg RKB-MSL: Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 2.992" ~9,500 0' ~9,500 ~3,000' Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx * - SCC (Special Clearance Couplings) Jewelry & Fish Description Depth Length ID OD Tbg Hanger, Dual 3-1/2"x2-3/8" Vetco CWC 13-5/8" 5M 17' 0.49' - 11.000" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" 7" TOC (USIT Log)Baker Model "SC-2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 6,118' MD Baker Model 80-40 Sealbore w/ GBH-22 Seal Ass 5,920' 9.02' 4.000" 5.000" 4,992' TVD Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" Halliburton WLEG w/ TCP Auto-Release 9,483' 12.02' 2.992" 4.250" 7" Plug w/ 28' of cmt - TOC @ 9,512' 7/13/20 9,540' IBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - HES 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - Perforations (post 4-1/2 cemented tubing) Depths, MD Date 6727'6742' 9/4/21 7362'7375' 9/3/21 7627'7633' 9/3/21 8000'8006' 9/3/21 8095'8105' 9/3/21 8293'8302' 9/2/21 8409'8429' 9/1/21 8946'8960' 8/30/21 9020'9030' 8/30/21 9030'9050' 8/30/21 9125'9134' 8/30/21 10,020' Csg 10,060' TD Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 Spud Date: 46.80' 3698 psi @ 10,060' MD Description Schematic API#: Union Oil Company of California 100% (1) 7" Baker Model "SC-2" Mechanical Set Pkr Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 3-½", 9.2#, L-80, IBT-Mod Updated By: DMA 06-16-21 Ivan River Unit CASING & TUBING Ownership: Total Depth: Tubing: Tubing:2-Ǫ", 4.6#, L-80, IBT(SCC) 10,060' Prod Pkrs: 9,926' 359,785 2,646,275 Shut-In 12/22/08 2:00 PM 134° @ 10,060' MD UOCC 30.00' 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: IRU 11-06 Ivan River Unit ORIGINAL RIG ELEVATIONS Permit to Drill#: 208-184 Lease & Serial#: ADL- 1 TA 2 3 4 6 5 7 13 12 MUD 10.1 ppg TB 11 CURRENT WBD 9/13/21 SA5 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299' ID = 5.518 Drift = 5.392 Beluga 8946' - 9134' 8896' CIBP (9/1/21) Fish left in Hole cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1-11/16" x 8.6') Total length = 21.6' Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO Beluga Perfs 6727' - 8429' ~9400' Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) ~7400' Fish: 45' cable + 21' e- line 1-11/16 TS ~5600' top of sand/fill Field: RKB-GL X: ASP4 16.80'Y: ASP4 RKB-MSL Well Status: 46.80'Operator: GL-MSL: 171'Csg RKB-MSL: Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' DV Collar 3,487' MD Tubing 4 1/2" 12.6# L-80 IBT-Mod* 2.992" ~9,500 0' ~9,500 ~3,000' Cmt below DV 4,100'-6,120' 12.0 ppg 397 sx * - SCC (Special Clearance Couplings) Jewelry & Fish Description Depth Length ID OD Tbg Hanger, Dual 3-1/2"x2-3/8" Vetco CWC 13-5/8" 5M 17' 0.49' - 11.000" Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" 7" TOC (USIT Log)Baker Model "SC-2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 6,118' MD Baker Model 80-40 Sealbore w/ GBH-22 Seal Ass 5,920' 9.02' 4.000" 5.000" 4,992' TVD Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" Halliburton WLEG w/ TCP Auto-Release 9,483' 12.02' 2.992" 4.250" 7" Plug w/ 28' of cmt - TOC @ 9,512' 7/13/20 9,540' IBP (tagged 36' deeper than setting depth 7/15/09) 9,666' 13.1' - HES 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - Perforations (post 4-1/2 cemented tubing) Depths, MD Date 6727'6742' 9/4/21 7362'7375' 9/3/21 7627'7633' 9/3/21 8000'8006' 9/3/21 8095'8105' 9/3/21 8293'8302' 9/2/21 8409'8429' 9/1/21 8946'8960' 8/30/21 9020'9030' 8/30/21 9030'9050' 8/30/21 9125'9134' 8/30/21 10,020' Csg 10,060' TD 359,785 2,646,275 Shut-In 12/22/08 2:00 PM 134° @ 10,060' MD UOCC 30.00' 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: Total Depth: Tubing: Tubing:2-Ǫ", 4.6#, L-80, IBT(SCC) 10,060' Prod Pkrs: 9,926' Updated By: DMA 06-16-21 Ivan River Unit CASING & TUBING Ownership: API#: Union Oil Company of California 100% (1) 7" Baker Model "SC-2" Mechanical Set Pkr Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 3-½", 9.2#, L-80, IBT-Mod Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 Spud Date: 46.80' 3698 psi @ 10,060' MD Description Schematic IRU 11-06 Ivan River Unit ORIGINAL RIG ELEVATIONS Permit to Drill#: 208-184 Lease & Serial#: ADL- 1 TA 2 3 4 6 5 7 13 12 MUD 10.1 ppg TB 11 PROPOSED WBD 9/13/21 SA5 4-1/2" Tubing TOC @ 3,000' (8/14/21 CBL) Csg Patch 6,270' to 6,299' ID = 5.518 Drift = 5.392 Beluga 8946' - 9134' 8896' CIBP (9/1/21) Fish left in Hole cable head (1.4" x 1'), weight bar (1-11/16" x 7'), weight bar (1-11/16" x 5'), GPT (1-11/16" x 8.6') Total length = 21.6' Estimated E-line length = 0.25" x 45'. Total fish = 45' + 21.6' = 66.6';RDMO Continue Perforating Per Sundry 321-305 ~9400' Fish: (2) cutter bar(s) 25' slickline TS (swab cups, mandrel, spangs) ~7400' Fish: 45' cable + 21' e- line 1-11/16 TS ~5600' top of sand/fill Clean out to below open perfs Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Swanson River Field SRU 34A-33 10/20/2020 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/25/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: IRU 11-06 (PTD 208-184) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW eceived By: 08/25/2021 By Abby Bell at 3:29 pm, Aug 25, 2021 From:McLellan, Bryan J (CED) To:Jake Flora - (C); Brad Gathman - (C) Subject:RE: CBL - IRU 11-06 AOGCC 10-403 321-305 PTD 208-184 Approved 07-06-21 Date:Tuesday, August 17, 2021 3:41:00 PM Attachments:image001.png Jake, It looks like there are sections of good cement throughout the proposed perf interval, with good solid cement from 3000-3200’ MD, so you have authorization to proceed with perforating according to Sundry 321-305. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent: Monday, August 16, 2021 12:52 PM To: Brad Gathman - (C) <Brad.Gathman@hilcorp.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: CBL - IRU 11-06 AOGCC 10-403 321-305 PTD 208-184 Approved 07-06-21 Hello Bryan, Please find attached the CBL ran after cementing 4 ½” inside of 7” liner and 9 5/8”. The TOC is fairly clear at the planned 3000’. We are planning on starting perforating Wednesday of this week. Please advise if we are good to proceed. Thank you, Jake Flora From: Ted Kramer <tkramer@hilcorp.com> Sent: Monday, August 16, 2021 12:23 PM To: Jake Flora - (C) <Jake.Flora@hilcorp.com> Subject: FW: [EXTERNAL] IRU 11-06 ACE result Jake, Here is the CBL for 11-06. Ted Kramer Sr. Operations Engineer Hilcorp-Alaska LLC Office – 907-777-8420 Cell – 985-867-0665 From: Fanny Haroun <Fanny.Haroun@halliburton.com> Sent: Monday, August 16, 2021 12:20 PM To: Ted Kramer <tkramer@hilcorp.com> Cc: Chris Gullett <Christopher.Gullett@halliburton.com>; Reuben Butteri <Reuben.Butteri@halliburton.com> Subject: [EXTERNAL] IRU 11-06 ACE result Hi Ted, Please find attached the advanced cement evaluation result for IRU 11-06. The TOC appears to be at depth ~3000 ft MD. There is a good cement isolation from 3000-3200 ft MD, and below that there are some patchy and good cement to the bottom of the log interval. Regards, Fanny Haroun Log Analyst 6900 Arctic Blvd Anchorage, AK 99518-2146 Email: fanny.haroun@halliburton.com Office: +1 907-275-2605 Mobile: +1 907-342-5550 This e-mail, including any attached files, may contain confidential and privileged information for the sole use of the intended recipient. Any review, use, distribution, or disclosure by others is strictly prohibited. If you are not the intended recipient (or authorized to receive information for the intended recipient), please contact the sender by reply e-mail and delete all copies of this message. From:Jake Flora - (C) To:McLellan, Bryan J (CED); Brad Gathman - (C) Subject:FW: [EXTERNAL] IRU 11-06 CBL Date:Tuesday, August 17, 2021 9:56:24 AM Bryan, Below is Halliburton’s response. The well hits 47 degrees which they address in point #1 with the pipe laying low side. Channeling doesn’t concern me due to every 40’ we will have standoff from the collars and cement coverage all the way around. Thanks, Jake From: Chris Gullett <Christopher.Gullett@halliburton.com> Sent: Tuesday, August 17, 2021 9:29 AM To: Reuben Butteri <Reuben.Butteri@halliburton.com>; Jake Flora - (C) <Jake.Flora@hilcorp.com> Cc: Fanny Haroun <Fanny.Haroun@halliburton.com> Subject: RE: [EXTERNAL] IRU 11-06 Ticket Jake, There are two things I’d like to point out with this log. 1. I’m not sure what kind of centralization was used on the new tubing string, but it does look like the tubing is laying lowside against the casing. This creates a situation where the cement on the low side is much thinner than it is on the top side. If the cement is less then ~3/4” thick it will produce a less than optimal signal. This doesn’t mean that no cement exits, but rather makes the impedance from the CAST a bit more speculative. 2. There is a possible micro-annulus in this well. The CAST signal does not really reach past the interface of the casing OD and cement. Whereas the CBL amplitude and VDL can get signal as far out as the formation (or second casing in this case). What we could be seeing is a very good cement-to-outer casing bond with a less then ideal cement-to-tubing bond. The ACE analysis does not really have much wiggle room for parameter adjustment. The operating environment was clean freshwater and standard weight cement. Altering the parameters to adjust the log would give a false sense of what is really going on. We could run the data through a PACE model which dissects the annular space into four sections based on radial distance between the inner and outer pipe. PACE only applies to CBL waveforms however and the CBL already shows decent cement. The benefit would be to show that any channeling that is seen on the CAST may only be present immediately adjacent to the tubing and not a complete void between the two pipes. Please let me know if you have any other questions/concerns or if you see there is any added value in performing the PACE analysis. Thanks, Chris STATE OF ALASKA Reviewed By: JEE— OIL AND GAS CONSERVATION COMMISSION P.1. Supry N(Z 7021 BOPE Test Report for: IVAN RIVER UNIT 11-06 Comm Contractor/Rig No.: Hilcorp 401 PTD#: 2081840 DATE: 8/2/2021 Inspector Austin McLeod - Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Rob O'neal Rig Rep: Chris Hannevold Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopSAM210804105138 Rams: Annular: Valves: MASP: Type Test: WKLY 321-305 250/2500 - 250/2500 - 250/2500 ' 1916 Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: CHOKE MANIFOLD: P/F P/F Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank NA- _NA System Pressure -3000 P Housekeeping: P Pit Level Indicators P P Pressure After Closure 2000 P PTD On Location P Flow Indicator NA NA 200 PSI Attained 23 P Standing Order Posted P Meth Gas Detector - P P Full Pressure Attained 95 P Well Sign P H2S Gas Detector P -P Blind Switch Covers: All stations- P ' Drl. Rig P MS Misc NA _ NA Nitgn. Bottles (avg): 6(x)2350- P " Hazard Sec. NA #4 Rams 0 ACC Misc 0 NA Misc NA #5 Rams -_ -- 0 NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 0 - NA- Stripper 0 NA No. Valves 8 - P_ Lower Kelly 0 NA • Annular Preventer 1 13-5/8 P Manual Chokes 2 P - Ball Type 1 P_ #1 Rams 1 2-3/8 NT Hydraulic Chokes 0 NA Inside BOP l _ P #2 Rams 1 2-7/8x5-1/2_ P CH Misc 0 NA FSV Misc 0 NA #3 Rams I Blinds P #4 Rams 0 NA #5 Rams -_ -- 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 4-1/16 P Quantity P/F HCR Valves 1 4-1/16 - P - Inside Reel Valves 0 NA Kill Line Valves 3. 4-1/16_/2_-_1/1. 6 P Check Valve 0 _ NA BOP Misc 0 NA Number of Failures: 0 Test Results Test Time 3.5 Remarks: 2-7/8" & 4-1/2" joints. Annular on 2-7/8". No 2-3/8" in use or planned for well work. 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? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,060'N/A Casing Collapse Structural Conductor Surface 2,670 psi Intermediate 3,090 psi Production 5,410 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 5-Jul-21 3-1/2" (prod); 2-3/8" (heater) 10,020' Perforation Depth MD (ft): 6,015' See Attached Schematic 4,195'8,238'7" 20" 13-3/8" 171' 9-5/8"6,015' 1,016'5,020 psi 171' 1,016' 4,920' 171' 1,016' 9.2# / L-80 (prod); 4.6# / L-80 (heat) TVD Burst 9,495' (prod); 3,501' (heat) 7,240 psi MD 5,750 psi Length Size CO 614 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 032930 208-184 50-283-20130-00-00 Ivan River Unit (IRU) 11-06 Ivan River / Undefined Gas COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic tkramer@hilcorp.com 8,270'9,926'8,159'1,916 9,666' Baker ZXP Pkr, Baker SC-2 Retrievable Pkr; N/A 5,825' MD / 4,792' TVD, 5,915' MD / 4,852' TVD; N/A Perforation Depth TVD (ft):Tubing Size: m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 12:57 pm, Jun 22, 2021 321-305 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.06.22 12:14:30 -08'00' Taylor Wellman (2143) SFD 6/22/2021 SFD 6/22/2021 XX 10-404 DSR-6/24/21 BOP test to 2500 psi. MITIA and MITT to 2000 psi. Centralizers required on casing to ensure quality cement packer. BJM 7/2/21 Post Perf MITIA to 2000 psi required within 10 days of return to production. Provide 24 hrs notice for AOGCC witness. CBL required of 4-1/2" casing/tubing. Results to be reviewed by AOGCC before perforating. dts 7/6/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.06 12:13:51 -08'00' RBDMS HEW 7/7/2021 Well Prognosis Well: IRU 11-06 Date: 6-16-2021 Well Name: IRU 11-06 API Number: 50-283-20130-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: July 5th, 2021 Rig: 401 Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 208-184 First Call Engineer: Ted Kramer (907) 777-8420 (O)(985) 867-0665 (M) Second Call Engineer: Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (M) AFE Number: Max. Expected BHP: ~ 2,484 psi @ 5,680’ TVD (Based on 0.437 pressure gradient) Max. Potential Surface Pressure: ~ 1,916 psi (Based on expected BHP and gas gradient to surface (0.1 psi/ft)) Brief Well Summary IRU 11-06 was drilled and completed in late 2008 /early 2009. Three intervals were perforated in the Tyonek sands. An Inflatable Bridge Plug was set over the lower part of the Tyonek B interval to isolate water and the upper two intervals were re-perforated. In July of 2011 a RWO abandoned the lower completion by cementing off the Tyonek B perforations at 9,648 to 9,698’. The Tyonek A was then perforated on 4/2009. The well was operated like this until July of 2020 when the Sterling A5 was added. The Sterling A5 came in at over 4 MMscfd at 800 psi. The purpose of this sundry/work is to pull the existing completion, isolate the A-5, run a 4-1/2” casing tie back string from 9,500’ (+/-) to surface and cement it in place. Perforate and test the sand intervals in the attached table. Note: Hilcorp has checked this well for a 660’ radius and determined that it does not need a SSSV. Notes Regarding Wellbore Condition x Well is currently producing 4.3 MMscfd x Last tag at 9,512’ KB (ELM) w/ 2-3/8” perf gun on 7/14/2020 Safety Concerns x Advise crew of proper escape routes and muster points. x When appropriate, discuss nitrogen asphyxiation concerns and identify new areas where nitrogen could collect, and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job). x Ensure all crews are aware of stop job authority. Well is currently producing 4.3 MMscfd Well Prognosis Well: IRU 11-06 Date: 6-16-2021 E-line Procedure 1. RU E-line. Pressure test Lubricator to 3,000 psi. 2. PU RIH with GR, CCL and pipe cutter. Locate top of packer. PU 5’ and cut 3-1/2” tubing. POOH W/ E- line. 3. RDMO E-line. Rig 401 Procedure 1. MIRU 401 Work over rig. 2. Kill Well with 6% KCL. 3. Ensure well is dead. Set back Pressure Valve. 4. ND wellhead, NU BOP and test to 250 psi low & 2,500 psi high, annular to 250 psi low & 2,000 psi high. Record accumulator pre-charge pressures and chart tests. a. Perform Test. b. Test rams on 4-1/2”, 2-7/8” and 2-3/8” test joints. BOP Stack has 2-3/8” rams in top, 2-7/8” to 5” variables in second position, Blinds in bottom. c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 5. Pull Back Pressure Valve. 6. Ensure well is dead, pump more 6% KCL KWF, if needed. 7. RU on 2-3/8” Heater String. Screw in landing Joint and pull heater string from well, Laying down same. 8. Screw in landing joint for 3-1/2” tubing. PU tubing hanger to floor. Lay down same. 9. POOH W/ 3-1/2” tubing laying down same. 10. PU wash pipe and burn shoe on 2-7/8” WS. RIH and tag up on Packer. PU, establish parameters, burn over Baker packer until free. POOH. 11. PU OS. RIH and overshot tubing stub. RIH W/ pipe and reverse out fill down to TOC (9512’). Pull and packer from well laying down same. 12. PU Watermelon mill, RIH to 6,260’. 13. PU Power swivel, MU Pipe and rotate mill from 6,260’ to 6,322’. CIRC hole clean, POOH. 14. RU E-line. 15. PU Patch and pup joint with RA tag installed. Measure length from RA tag to patch element for space out. RIH to 6,307’ (+/-)’ and land tubing. 16. RIH with E-line and determine space out requirement. POOH and stand back E-line. a. Contingncy: If an RA tag is not available E-line may set a CBP to land the casing patch on for depth control. 17. Space out and stroke patch mandrel through patch by pumping fluid according to manufacturer’s procedure to set patch across SA5 Perforations from 6279’ – 6292’. POOH with Mandrel. 18. PU Junk Mill, RIH and Mill out plug in bottom of casing patch (and CBP if applicable). CBU. Continue in hole with bit and WS to 9,500’. CBU. POOH W/bit. 19. PU 4-1/2” Shoe and Float collar, on 4-1/2” casing Tie back string. RIH to 9,500’. 20. RU Cementers. Pressure test lines. Cement 4-1/2” tieback liner to 3,000 ft. on backside. 21. RD cementers. WOC. 22. PU, RIH W/ bit and scraper on WS. C/O cement stringers to 9,400’. CBU. 23. MITIA 4-1/2” casing backside to 1500 psi on chart for 30 min. Release pressure. Pressure test 4-1/2” casing to 1,500 psi. for 10 min. Install Centralizers on 4.5" casing from top of casing patch to desired TOC. Install centralizers below the patch if feasible. MITIA and MITT to 2000 psi. bjm Well Prognosis Well: IRU 11-06 Date: 6-16-2021 24. POOH W/ Bit and scraper laying down WS. 25. RDMO Rig 401. Slickline Procedure 26. MIRU SL. Pressure test Lubricator to 2,000 psi. (no open perforations) 27. PU Swab cups for 4-1/2” casing. Swab fluid out of casing to 9,350’ (or as deep as possible). RDMO SL. E-Line Procedure 28. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 29. RIH with GPT tool and find fluid level. If fluid level is over the depth of the new perfs, discuss with operations engineer. 30. RU Nitrogen Truck. Pressure up well to 2,500 psi. 31. PU Perf Guns. RIH W/guns and perforate the intervals listed in the table below: Sand Perf. Top Perf Bottom Perf. Top Perf. Bottom Total Footage (MD) (MD) (TVD) (TVD) (MD) ST_A1 ±6,051’ ±6,057’ ±4,945’ ±4,949’ 6‘ ST_A2 ±6,114’ ±6,134’ ±4,989’ ±5,004’ 20‘ ST_A3 ±6,171’ ±6,185’ ±5,030’ ±5,040’ 14‘ ST_A4 ±6,243’ ±6,257’ ±5,083’ ±5,093’ 14‘ ST_A5 ±6,279’ ±6,292’ ±5,109’ ±5,119’ 13‘ ST_A6 ±6,297’ ±6,316’ ±5123’ ±5,138’ 19‘ ST_B1 ±6,333’ ±6,349’ ±5,151’ ±5,163’ 16‘ ST_B2 ±6,361’ ±6,411’ ±5,173’ ±5,212’ 50‘ ST_C1 ±6,513’ ±6,526’ ±5,294’ ±5,305’ 13‘ ST_C2 ±6,544’ ±6,567’ ±5,319’ ±5,338’ 23‘ ST_C3 ±6,576’ ±6,582’ ±5,345’ ±5,350’ 6‘ Set Plug 6,584’. BEL_D ±6,588’ ±6,608’ ±5,355’ ±5,372’ 20‘ BEL_D1 ±6,651’ ±6,676’ ±5,407’ ±5,428’ 25‘ BEL_D4u ±6,707’ ±6,716’ ±5,454’ ±5,461’ 9‘ BEL_D4L ±6,726’ ±6,753’ ±5,469’ ±5,491’ 27‘ BEL_D5 ±6,763’ ±6,776’ ±5,499’ ±5,511’ 13‘ BEL_Eu ±6,804’ ±6,829’ ±5,534’ ±5,554’ 25‘ BEL_EL ±6,839’ ±6,858’ ±5,563’ ±5,579’ 19‘ BEL_E2u ±6,911’ ±6,936’ ±5,623’ ±5,644’ 25‘ Cement log required for the 4-1/2" casing. Send log to AOGCC for review before perforating. The perfs 6588-6608' MD will not be shot to ensure a proper abandonment of the Beluga pool with 25' of cement placed on top of a plug set above the perfs at 6651'. The waiver request in step 31.h is therefore not needed. Well Prognosis Well: IRU 11-06 Date: 6-16-2021 BEL_E2L ±6,952’ ±6,961’ ±5,657’ ±5,665’ 9‘ BEL_E4u ±7,034’ ±7,037’ ±5,726’ ±5,728’ 3‘ BEL_E4L ±7,050’ ±7,058’ ±5,739’ ±5,747’ 8‘ BEL_E5u ±7,103’ ±7,109’ ±5,784’ ±5,789’ 6‘ BEL_E5L ±7,144’ ±7,167’ ±5,818’ ±5,838’ 23‘ BEL_F1 ±7,234’ ±7,239’ ±5,894’ ±5,898’ 5‘ BEL_F4 ±7,361’ ±7,375’ ±6,000’ ±6,012’ 14‘ BEL_G ±7,624’ ±7,633’ ±6,221’ ±6,228’ 9‘ BEL_G9 ±7,915’ ±7,920’ ±6,464’ ±6,469’ 5‘ BEL_H ±8,000’ ±8,010’ ±6,535’ ±6,543’ 10‘ BEL_H2 ±8,060’ ±8,067’ ±6,585’ ±6,591’ 7‘ BEL_H3 ±8,095’ ±8,111’ ±6,615’ ±6,628’ 16‘ BEL_H4 ±8,175’ ±8,181’ ±6,681’ ±6,685’ 6‘ BEL_H8 ±8,279’ ±8,310’ ±6,768’ ±6,793’ 31‘ BEL_H10 ±8,406’ ±8,431’ ±6,874’ ±6,895’ 25‘ BEL_H11 ±8,454’ ±8,458’ ±6,914’ ±6,917’ 4‘ BEL_H12 ±8,478’ ±8,483’ ±6,934’ ±6,939’ 5‘ BEL_H16 ±8,658’ ±8,703’ ±7,087’ ±7,125’ 45‘ BEL_I ±8,801’ ±8,803’ ±7,208’ ±7,210’ 2‘ BEL_I5 ±8,946’ ±8,964’ ±7,330’ ±7,345’ 18‘ BEL_I8 ±9,020’ ±9,051’ ±7,393’ ±7,419’ 31‘ BEL_I10 ±9,126’ ±9,142’ ±7,482’ ±7,495’ 16‘ BEL_I14u ±9,243’ ±9,247’ ±7,581’ ±7,584’ 4‘ BEL_I14L ±9,269’ ±9,283’ ±7,603’ ±7,614’ 14‘ BEL_I15 ±9,342’ ±9,344’ ±7,665’ ±7,667’ 2‘ a. Depending on well conditions, the well may be shot flowing or the tubing pressure may be increased W/nitrogen prior to shooting. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. Record 5, 10 and 15 minute tubing pressure after firing. h. All perforations in the table above are located in the Ivan River Field Unidentified Gas Pools. A spacing exception has been filed - Conservation Order 614. In accordance with statewide undefined pool rules, a plug will be set over the Beluga sands at 6,584’ before the Sterling Sands are perforated. A waiver is requested for this plug as there will not be room for 25’ of cement on top of the plug. Alternatively, if minor production is coming from the Beluga Waiver to 20AAC25.112(c)(1)(E) is declined. The perfs from 6588-6608' MD will not be allowed under this Sundry so that a plug can be set above the perf at 6651' md, leaving enough room for the required 25' of cement below the Sterling pool bottom perf at 6582' MD. Hilcorp may submit another Sundry with variance request to perf the Beluga from 6588-6608, but will still need a plug and 25' of cement between the Beluga perfs at 6608' & 6651'MD to ensure that the vast majority of the Beluga is plugged per regulation. bjm a plug will be set over the Beluga sands at 6,584’ before the Sterling Sands are perforated. Waiver request declined. A waiver is requested for this plug as there will not be room for 25’ of cement on top of the plug. Well Prognosis Well: IRU 11-06 Date: 6-16-2021 sands, a comingling application may be filed with he AOGCC prior to perfing the Sterling sands so that production can be comingled. i. Contingency – If a zone is producing too much water or sand or both, Hilcorp may set a plug or patch to eliminate the influx from the affected interval. If a plug is used, cement will be placed on top of the plug in accordance with 20 AAC 25.112(c)(E). If there is not room for a full 25’ of cement, then a waiver will be requested. 32. POOH. RD E-line. 33. Turn Well over to Production. Attachments 1. Actual Schematic 2. Proposed Schematic 3. BOP Schematic 4. Current Wellhead Drawing 5. Proposed Wellhead Drawing 6. Standard Well Procedure – N2 Operations Additional MITIAs may be required after adding additional perfs in the future. Cement bond log results will help to inform future MITI A requirements. MITIA to 2000 psi lines required within 10 days after returning to production post perf. Field: RKB-GL X: ASP4 16.80'Y: ASP4 RKB-MSL Well Status: 46.80'Operator: GL-MSL: 171'Csg RKB-MSL: Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC Rotate Hrs 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900'163.5 hrs 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118'0.0 hrs DV Collar 3,487' MD Cmt below DV 4,100'-6,120'Tubing 3 1/2" 9.2# L-80 IBT-Mod* 2.992" 9,495' 0' 9,495' 12.0 ppg 397 sx 2 3/8" 4.6# L-80 IBT* 1.995" 3,501' 0' 3,501' * - SCC (Special Clearance Couplings) Depth Length ID OD 1 17' 0.49' -11.000" 2 3,487' 2.80' 8.681"10.625" 3 5,825' 18.53' 6.285"8.310" 4 5,844' 9.69' 6.276"8.310" 5 5,915' 5.45' 4.000"5.960" 6 5,920' 9.02' 4.000"5.000" 6,015' Csg 7 5,970' 4.54' 2.813"4.500" 8 9,418' 0.69' 2.992"4.187" 9 9,483' 12.02' 2.992"4.250" TOC (USIT Log)10 9,540' 6,118' MD 11 9,666' 13.1' - 4,992' TVD 12 9,716' 204.00' -4.625" 12.0 ppg 432 sx 13 9,926' - - - a 3,501' - - - Zone Top Btm Amt Gun Size SPF Phase Status Sterling A5 6,279' 6,292' 13' 2-3/8" 5 60 Open Tyonek A 9,545' 9,576' 31' 4-5/8" 6 60 Isolated Tyonek A 9,582' 9,609' 27' 4-5/8" 6 60 Isolated Tyonek B 9,648' 9,698' 50' 4-5/8" 6 60 Isolated 10,020' Csg 10,060' TD Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 Spud Date: Baker Model 80-40 Sealbore w/ GBH-22 Seal Assembly 46.80' 3698 psi @ 10,060' MD 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) Halliburton Type 'H' ES DV Collar (Closed 1/16/09) Description Tubing Hanger, Dual 3-1/2"x2-3/8" Vetco CWC 13-5/8" 5M Baker Model "SC-2" Retrievable Packer (set 2/10/09) PBTD - Top of 7" Float equipment (Tagged 2/6/09) Jewelry & Fish Halliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 7" Plug w/ 28' of cement on top of plug - TOC @ 9,512' 7/13/20 Halliburton WLEG w/ TCP Auto-Release Inflatable BP (tagged 36' deeper than setting depth 7/15/09) 9-5/8" Baker ZXP packer (set 2/4/09) Halliburton Ported Sub w/ Glass Disk Description (Heat String) Date Perforations 4/4/2009 4/4/2009, Re-Perf 5/10/2009 Schematic Mule shoe cut on joint, 2-3/8" Tubing Sterling/Beluga/Tyonek 4/4/2009, Re-Perf 5/10/2009 API#: Union Oil Company of California 100% (1) 7" Baker Model "SC-2" Mechanical Set Pkr Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 3-½", 9.2#, L-80, IBT-Mod Prod Pkrs: 9,926' Updated By:DMA 08-07-20 Ivan River Unit 7/13/2020 CASING & TUBING Description Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) Ownership: Total Depth: Tubing: Tubing:2-Ǫ", 4.6#, L-80, IBT(SCC) 10,060' 359,785 2,646,275 Shut-In 12/22/08 2:00 PM 134° @ 10,060' MD UOCC 30.00' 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: IRU 11-06 Ivan River Unit ORIGINAL RIG ELEVATIONS Permit to Drill#: 208-184 Lease & Serial#: ADL-032930 1 TA 2 3 4 6 5 7 8 13 12 a 9 MUD 10.1 ppg TB 11 10 SCHEMATIC SA5 Field: RKB-GL X: ASP4 16.80'Y: ASP4 RKB-MSL Well Status: 46.80'Operator: GL-MSL: 171'Csg RKB-MSL: Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC Rotate Hrs 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar 3,487' MD Cmt below DV 4,100'-6,120'Tubing 4 1/2" 12.6#L-80 IBT-Mod* 2.992"~9,500 0'~9,500 ~3,000' 12.0 ppg 397 sx * - SCC (Special Clearance Couplings) Depth Length ID OD 1 17' 0.49' - 11.000" 2 3,487' 2.80' 8.681" 10.625" 3 5,825' 18.53' 6.285" 8.310" 4 5,844' 9.69' 6.276" 8.310" 5 5,915' 5.45' 4.000" 5.960" 6 5,920' 9.02' 4.000" 5.000" 6,015' Csg 7 5,970' 4.54' 2.813" 4.500" 8 9,418' 0.69' 2.992" 4.187" 9 9,483' 12.02' 2.992" 4.250" TOC (USIT Log)10 9,540' 6,118' MD 11 9,666' 13.1' - 4,992' TVD 12 9,716' 204.00' - 4.625" 12.0 ppg 432 sx 13 9,926' - - - --- Zone Top MD Btm MD Top TVD Btm TVD Amt Phase Date ST_A1 ±6,051’ ±6,057’ ±4,945’ ±4,949’ ±6‘60 Proposed ST_A2 ±6,114’ ±6,134’ ±4,989’ ±5,004’ ±20‘60 Proposed ST_A3 ±6,171’ ±6,185’ ±5,030’ ±5,040’ ±14‘60 Proposed ST_A4 ±6,243’ ±6,257’ ±5,083’ ±5,093’ ±14‘60 Proposed ST_A5 ±6,279’ ±6,292’ ±5,109’ ±5,119’ ±13‘60 Proposed ST_A6 ±6,297’ ±6,316’ ±5123’ ±5,138’ ±19‘60 Proposed ST_B1 ±6,333’ ±6,349’ ±5,151’ ±5,163’ ±16‘60 Proposed ST_B2 ±6,361’ ±6,411’ ±5,173’ ±5,212’ ±50‘60 Proposed ST_C1 ±6,513’ ±6,526’ ±5,294’ ±5,305’ ±13‘60 Proposed ST_C2 ±6,544’ ±6,567’ ±5,319’ ±5,338’ ±23‘60 Proposed ST_C3 ±6,576’ ±6,582’ ±5,345’ ±5,350’ ±6‘60 Proposed BEL_D ±6,588’ ±6,608’ ±5,355’ ±5,372’ ±20‘60 Proposed BEL_D1 ±6,651’ ±6,676’ ±5,407’ ±5,428’ ±25‘60 Proposed BEL_D4u ±6,707’ ±6,716’ ±5,454’ ±5,461’ ±9‘60 Proposed BEL_D4L ±6,726’ ±6,753’ ±5,469’ ±5,491’ ±27‘60 Proposed BEL_D5 ±6,763’ ±6,776’ ±5,499’ ±5,511’ ±13‘60 Proposed BEL_Eu ±6,804’ ±6,829’ ±5,534’ ±5,554’ ±25‘60 Proposed BEL_EL ±6,839’ ±6,858’ ±5,563’ ±5,579’ ±19‘60 Proposed BEL_E2u ±6,911’ ±6,936’ ±5,623’ ±5,644’ ±25‘60 Proposed BEL_E2L ±6,952’ ±6,961’ ±5,657’ ±5,665’ ±9‘60 Proposed BEL_E4u ±7,034’ ±7,037’ ±5,726’ ±5,728’ ±3‘60 Proposed BEL_E4L ±7,050’ ±7,058’ ±5,739’ ±5,747’ ±8‘60 Proposed BEL_E5u ±7,103’ ±7,109’ ±5,784’ ±5,789’ ±6‘60 Proposed BEL_E5L ±7,144’ ±7,167’ ±5,818’ ±5,838’ ±23‘60 Proposed BEL_F1 ±7,234’ ±7,239’ ±5,894’ ±5,898’ ±5‘60 Proposed 10,020' Csg BEL_F4 ±7,361’ ±7,375’ ±6,000’ ±6,012’ ±14‘60 Proposed 10,060' TD BEL_G ±7,624’ ±7,633’ ±6,221’ ±6,228’ ±9‘60 Proposed Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 Spud Date: Baker Model 80-40 Sealbore w/ GBH-22 Seal Assembly 46.80' 3698 psi @ 10,060' MD 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) Halliburton Type 'H' ES DV Collar (Closed 1/16/09) Description Tubing Hanger, Dual 3-1/2"x2-3/8" Vetco CWC 13-5/8" 5M Baker Model "SC-2" Retrievable Packer (set 2/10/09) PBTD - Top of 7" Float equipment (Tagged 2/6/09) Jewelry & Fish Halliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 7" Plug w/ 28' of cement on top of plug - TOC @ 9,512' 7/13/20 Halliburton WLEG w/ TCP Auto-Release Inflatable BP (tagged 36' deeper than setting depth 7/15/09) 9-5/8" Baker ZXP packer (set 2/4/09) Halliburton Ported Sub w/ Glass Disk Comments Perforations TBD TBD TBD TBD Schematic Sterling/Beluga/Tyonek TBD TBD API#: Union Oil Company of California 100% (1) 7" Baker Model "SC-2" Mechanical Set Pkr Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 3-½", 9.2#, L-80, IBT-Mod Prod Pkrs: 9,926' Updated By: TBD TBD TBD DMA 06-16-21 TBD TBD TBD TBD Ivan River Unit TBD CASING & TUBING Description Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) Ownership: Total Depth: Tubing: Tubing:2-Ǫ", 4.6#, L-80, IBT(SCC) 10,060' 359,785 2,646,275 Shut-In 12/22/08 2:00 PM 134° @ 10,060' MD TBD TBD TBD TBD UOCC 30.00' 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: TBD TBD TBD Cont'd on Page 2 TBD TBD TBD TBD TBD TBD IRU 11-06 Ivan River Unit ORIGINAL RIG ELEVATIONS Permit to Drill#: 208-184 Lease & Serial#: ADL-032930 1 TA 2 3 4 6 5 7 8 13 12 9 MUD 10.1 ppg TB 11 10 PROPOSED SCHEMATIC SA5 TOC ~3,000' Csg Patch ±6,279' to±6,292' ID = 5.518 Drift = 5.392 Zone Top MD Btm MD Top TVD Btm TVD Amt Phase Date BEL_G9 ±7,915’ ±7,920’ ±6,464’ ±6,469’ ±5‘60 Proposed BEL_H ±8,000’ ±8,010’ ±6,535’ ±6,543’ ±10‘60 Proposed BEL_H2 ±8,060’ ±8,067’ ±6,585’ ±6,591’ ±7‘60 Proposed BEL_H3 ±8,095’ ±8,111’ ±6,615’ ±6,628’ ±16‘60 Proposed BEL_H4 ±8,175’ ±8,181’ ±6,681’ ±6,685’ ±6‘60 Proposed BEL_H8 ±8,279’ ±8,310’ ±6,768’ ±6,793’ ±31‘60 Proposed BEL_H10 ±8,406’ ±8,431’ ±6,874’ ±6,895’ ±25‘60 Proposed BEL_H11 ±8,454’ ±8,458’ ±6,914’ ±6,917’ ±4‘60 Proposed BEL_H12 ±8,478’ ±8,483’ ±6,934’ ±6,939’ ±5‘60 Proposed BEL_H16 ±8,658’ ±8,703’ ±7,087’ ±7,125’ ±45‘60 Proposed BEL_I ±8,801’ ±8,803’ ±7,208’ ±7,210’ ±2‘60 Proposed BEL_I5 ±8,946’ ±8,964’ ±7,330’ ±7,345’ ±18‘60 Proposed BEL_I8 ±9,020’ ±9,051’ ±7,393’ ±7,419’ ±31‘60 Proposed BEL_I10 ±9,126’ ±9,142’ ±7,482’ ±7,495’ ±16‘60 Proposed BEL_I14u ±9,243’ ±9,247’ ±7,581’ ±7,584’ ±4‘60 Proposed BEL_I14L ±9,269’ ±9,283’ ±7,603’ ±7,614’ ±14‘60 Proposed BEL_I15 ±9,342’ ±9,344’ ±7,665’ ±7,667’ ±2‘60 Proposed Zone Top Btm Amt Gun Size SPF Phase Status Sterling A5 6,279' 6,292' 13' 2-3/8" 5 60 Isolated Tyonek A 9,545' 9,576' 31' 4-5/8" 6 60 Isolated Tyonek A 9,582' 9,609' 27' 4-5/8" 6 60 Isolated Tyonek B 9,648' 9,698' 50' 4-5/8" 6 60 Isolated Page 2 Perforations Comments Sterling/Beluga/Tyonek TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD Date Updated By: DMA 06-16-21 4/4/2009, Re-Perf 5/10/2009 7/13/2020 4/4/2009, Re-Perf 5/10/2009 4/4/2009 IRU 11-06 Ivan River Unit Permit to Drill#: 208-184 Lease & Serial#: ADL-032930PROPOSEDSCHEMATIC 13-5/8" 5M RAMS (PER CAVITY) 5.5 5.8 4-1/16" 5M HCR 0.61 0.52 OPEN AND CLOSE DATA OPEN CLOSE 13-5/8" 5M ANNULAR 17.41 23.58 ϭϯͲϱͬϴΗ/^&KZ'EEh>Z ϭϯͲϱͬϴϱDDZKEKh>dzWhKW sZZD^dKWϮͲϳͬϴΗdKϱΗ >/EZD^KddKD ϭϯͲϱͬϴΗϱDKW ^d< tͬ^/E'> ϭϯͲϱͬϴϱDDZKE^/E'> dzWhKW ϮͲϯͬϴΗ^dZ/',dW/WZD^ ,K<^/ ϰͲϭͬϭϲΗϱDDEh>/E^/ ϰͲϭͬϭϲΗϱD,ZKhd^/ ϰͲϭͬϭϲΗyϮͲϭͬϭϲΗϱD^Khd^/ </>> ^/ ϰͲϭͬϭϲΗϱDDEh>/E^/ ϰͲϭͬϭϲΗϱDDEh>Khd^/ ϰͲϭͬϭϲΗyϮͲϭͬϭϲΗϱD^Khd^/ ϭϯͲϱͬϴΗϱDZ/>>/E'^WKK> tͬϰͲϭͬϭϲΗϱD^/Khd>d^ Current Well Head Drawing IRU 11-06 Ivan River Unit IR 11-06 Proposed 06/16/2021 Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Upper master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Swab, WKM-M 4 1/16 5M FE, HWO, EE trim BHTA, Otis, 4 1/16 5M FE x 7'’ Bowen quick union top Valve, Wing, SSV, WKM-M, 3 1/8 5M FE, w/ 15'' operator 13 3/8'’ 9 5/8'’ 4 ½’’ Ivan River 11-06 20 x 13 3/8 x 9 5/8 x 4 1/2 Tubing hanger, Vetco-MB 242, 13 5/8 5M x 4 ½ IBT susp x 4.909 MCA lift, w/ 4'’ type H BPV profile, 2- ½ npt control line ports Multibowl system, Vetco MB-242, 13 5/8 5M Flanged top x 13 3/8 quick connect bottom STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1 Carlisle, Samantha J (CED) From:Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent:Thursday, July 1, 2021 12:18 PM To:McLellan, Bryan J (CED); Ted Kramer Cc:Donna Ambruz; Taylor Wellman Subject:RE: [EXTERNAL] RE: IRU 11-06 (PTD 208-184) Waiver request BryanͲ HilcorpproposesthatwepleasestrikeouttheproposedBELͲDperfsfrom6588–6608’MDinthecurrentIRU11Ͳ06 sundry.Thisshouldallowenoughroomforaplug+25’ofdumpbailedcementtobeplacedbetweentheBelugaand SterlingperfsetsbeforeanySterlingsandsareopeneddowntheroad. IfHilcorpultimatelywishestoperfboththeBELͲDandSterlingC3intervals(only4’MDseparation),thatwouldbea separatefuturerequesttotheAOGCC. Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From:McLellan,BryanJ(CED)[mailto:bryan.mclellan@alaska.gov] Sent:Thursday,July1,202111:06AM To:TedKramer<tkramer@hilcorp.com> Cc:RyanRupert<Ryan.Rupert@hilcorp.com> Subject:[EXTERNAL]RE:IRU11Ͳ06(PTD208Ͳ184)Waiverrequest Ted, I’mheadingoutoftownfortwoweeksonvacationstartingFridayevening.Wouldyouliketodiscussthevariance requestinmyemailbelow? I’mhopingtogetthisSundryissuedbeforeIgosoyouguysarenotheldup.IcopiedRyanRupertincaseyouareoutof theofficethisweek. Regards BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 2 From:McLellan,BryanJ(CED) Sent:Monday,June28,20214:46PM To:TedKramer<tkramer@hilcorp.com> Subject:IRU11Ͳ06(PTD208Ͳ184)Waiverrequest Ted, WewouldacceptavariancerequestfortheisolationplugbetweenBelugaandSterling,butnotawaiver. Therearedifferentoptionsyoucouldpursue: 1. Varianceto20AAC25.112(c)(1)(D),wherethecementretainerissetonly4’abovetopperfinsteadof50’ minimum. 2. Varianceto20AAC25.112(c)(1)(E)ontheconditionthataplugissetat6634'with50'ofcementontopplaced withadumpbailer(TOCtarget6584').ThiswillisolatemostoftheBelugaperregulation,andthetopperfswill beisolatedbyonly4’ofcement. 3. Opentoothersuggestions. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 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. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool * Repair Well Re-enter Susp Well Other: N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,060 feet 9,666 feet true vertical 8,270 feet N/A feet Effective Depth measured 9,926 feet 5825; 5915 feet true vertical 8,159 feet 4792; 4852 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 3-1/2" Prod 9.2# / L-80 9,495' MD 7,795' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" Heater 4.6# / 80 3,501' MD 3,185' TVD Baker ZXP Pkr; 5,825' MD 4,792' TVD Packers and SSSV (type, measured and true vertical depth)Baker SC-2; N/A 5,915' MD 4,852' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 7,240psi 171' 1,016' 5,750psi 5,020psi Collapse 2,670psi 3,090psi 5,410psi Casing Structural 20" 13-3/8" 9-5/8" Length 171' 1,016' 6,015' 4,195' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 8 Casing Pressure Liner 4,201 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-266 1,723 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 17 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 208-184 50-283-20130-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 20 Ivan River Unit (IRU) 11-06 N/A ADL 032930 6,015' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ivan River / Undefined Gas*N/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 7"10,020' 4,920' 8,238' WINJ WAG 185 Water-Bbl MD 171' 1,016' 0 From Sundry Application from State. Not a new pool, see note below. *Note: Undefined Pool includes Sterling, Beluga, and Tyonek sands. All gas zones are co-mingled in Gas Pool #1 PA formed in 2000. t Fra O 6. A G L PG , R 2 Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:20 am, Aug 10, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.08.07 16:37:52 -08'00' Taylor Wellman RBDMS HEW 8/10/2020 SFD 8/10/2020 From Sundry Application from State. Not a new pool, see note below. *Note: Undefined Pool includes Sterling, Beluga, and Tyonek sands. All gas zones are co-mingled in Gas Pool #1 PA formed in 2000. Perforate New Pool * DSR-8/10/2020gls 9/18/20 Rig Start Date End Date E-Line 6/24/20 7/13/20 07/06/2020 - Monday Arrive Beluga, Orientate, gather Eq. & materals, Mobe to Ivan River. R/U E-line ,lubricator, 30' 2 1/2" Bailer & CCL, fill with 6/12 ceramic shot, PT 250/3,000 good RIH tag @ 9,542', P/U dump shot, Tag POOH, Mix & load bailer w/6 gal, 17ppg cmt. RIH, tag @ 9,539', p/u Dump cmt POOH, L/D lubricator, secure well. SDFN. 07/07/2020 - Tuesday RIH w/ 30' 2-1/2" mt bailer, tag @ 9,538', was sticky on btm. POOH, found wet cmt on bailer, called town discussed findings, pulling off well & letting cmt set longer. Rig Down & de-mobe eq. from Ivan river & back to Beluga for work on 212-24T. 06/24/2020 - Wednesday PTSM, travel to location, spot Eq. & r/u, m/n GRT tool & test good, c/o tree adaptor flange. Stab lubricator, PT 250/3,000 (had one O ring leak, c/o good test. RIH w/GPT tool, tag @ 9,605'. Log up t/ 5,940', cont. POOH t/surface. RU, RIH w/spiral plug GR, CCL, t/9,605', log & send to town to correlate, made 3' adjustment as per Res Engineer, pulled into place, set plug @ 9,540'. POOH. C/O tool string to cmt dump bailer fill bailer w/17.1ppg, cmt. RIH tag plug, P/U & dump bailer #1 of cmt on plug @ 9,540'. POOH, verify bailer dumped, re-fill bailer. RIH w/Bailer #2 cmt. 06/30/2020 - Tuesday R/U e-line, m/u 2.5" bailer while waiting on direction from town. Decission made to dump 5' of sand on plug, travel to Beluga & p/u sand. P/T lubricator 250/3,000 good, bailer loaded with sand. RIH t/tag at 9,540', p/u 4' t/9,536' break disk to dump bailer work bailer. POOH. OOH with bailer, disk broke but bailer only dropped 10% of sand, call engineer with findings, discuss & research options, decision made to to order recomended ceramic shot to place on top of plug. R/D e- line. 06/27/2020 - Saturday 06/29/2020 - Monday Spot Eq. on well, r/u e-line, m/u tools, GR,CCL, spinner, P/T 250/3,000 good RIH w/tool string t/5,600' spinner stopped working, POOH clean same & nsurface test. RIH w/spinner GR, CCL, t/9,330', started having issues with spinner unable to get working again, tagged btm @9,540', POOH. Clean up spinner & test good, add centrilizers to string, RIH w/spinner GR, CCL, t/9,533', r/u & attempted to put well on line to flow but not enough movement to get reading. R/U N2 & cool down, PT lines /2,500 good. Pressure up well with N2 t/185 psi while monitoring spinner tool, observe flow down hole past tool, s/d, N2 pump, cont. monitor flow down hole. Discuss findings with ops engineer. POOH, r/d e-line, secure well. Move out, spot E-line eq. stand by for gun barrels from Kenai Load 2-3/8" 5 spf, 6' gun, & m/u, w/GR, CCL, stab lubricator, test 250/3,000 good. RIH t/6,550', log up t/6,000' send logs to town for correlation Cont. RIH t/tag cmt @ 9,516', POOH t/6,500' adjust correlation as per Geo. log up t/6,000' verify correlation good, Start pressuring up well from 100psi w/Nitrogen, pressured up t/350 psi and pressure stopped increasing, (target 1,800psi) s/d pump monitored well lost 83 psi in 5 min, discussed options w/town, Decision made to run Diagnostics for leak, POOH, r/d move off. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 RIH w/GPT tool, tag @ 9,605'. Log up t/ 5,940', cont.POOH t/surface. plug at 9540 ft.. cap with cement set plug @ 9,540'. POOH. with 6/12 ceramic shot, PT Dump cmt POOH, Rig Start Date End Date E-Line 6/24/20 7/13/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name IRU 11-06 50-283-20130-00-00 208-184 R/U e-line, p/u 13'gun, GR, CCL WT bar, M/U lubricator, P/T lubricator, repair o ring leak, retest 250/3,000 good. RIH tag TOC @ 9,512' x2, POOH log up from 6,400'-6,000', send to town engineering for correlation, make adjustment as directed, resend for verification good, R/U N2 pressure test lines good, Pressure up well with N2 t/1,530 psi, Log gun into position, placing top shot @ 6,279', btm shot @ 6,292', fire 2-3/8" 5 SPF 60 deg phasing gun, good indication gun fired. Pressure built t/1,800 in first 3 min, cont. build 1,820 5 min, 1,834 10 min, 1,835 15 min. POOH R/D l/d gun, all shots fired, cap was dry. cont. RDMO, turn well over to production. 07/13/2020 - Monday 07/09/2020 - Thursday Mobe to Ivan River from Beluga, spot eq., r/u lubricator & m/u 30' bailer 2-1/2", pt 250/3,000 good. RIH tag @ 9,538', POOH, secure well for night. 07/10/2020 - Friday P/U 30' 2.1/2" bailer, mix & fill same with 17ppg cmt, P/T good, equalize lubricator to well pressure, RIH tag & p/u t/ 9,532' dump bailer POOH. Mix & fill bailer with 17ppg cmt, equalize lubricator to well pressure, RIH, p/u t/ 9,527' dump bailer POOH. Mix & fill bailer with 17ppg cmt, equalize lubricator to well pressure, RIH, p/u t/ 9,523' dump bailer POOH. Mix & fill bailer with 17ppg cmt, equalize lubricator to well pressure, RIH, p/u t/ 9,518' dump bailer POOH. Mix & fill bailer with 17ppg cmt, equalize lubricator to well pressure, RIH, p/u t/ 9,514' dump bailer POOH. Mix & fill bailer with 17ppg cmt, equalize lubricator to well pressure, RIH, p/u t/ 9,507' dump bailer POOH. Mix & fill bailer with 17ppg cmt, equalize lubricator to well pressure, RIH, p/u t/ 9,502' dump bailer POOH, ( Dumped total of 42 gal 17ppg cmt for day). RDMO, secure well. , placing top shot @ 6,279', btm shot @ 6,292', Field: RKB-GL X: ASP4 16.80'Y: ASP4 RKB-MSL Well Status: 46.80'Operator: GL-MSL: 171'Csg RKB-MSL: Other: Top Job BHP: 15.8 ppg 187 sx BHT: Primary Cmt 13.0 ppg 552 sx Weight Grade Conn ID Length Top Btm TOC Rotate Hrs 1,016'Csg Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV Surface 13 3/8" 68.0# L-80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900'-3,487'Intermediate 9 5/8" 40.0# L-80 BTC 8.681" 6,015' 0' 6,015' 900'163.5 hrs 12.5 ppg 642 sx Production 7" 26.0# L-80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118'0.0 hrs DV Collar 3,487' MD Cmt below DV 4,100'-6,120'Tubing 3 1/2" 9.2# L-80 IBT-Mod* 2.992" 9,495' 0' 9,495' 12.0 ppg 397 sx 2 3/8" 4.6# L-80 IBT* 1.995" 3,501' 0' 3,501' * - SCC (Special Clearance Couplings) Depth Length ID OD 1 17' 0.49' -11.000" 2 3,487' 2.80' 8.681"10.625" 3 5,825' 18.53' 6.285"8.310" 4 5,844' 9.69' 6.276"8.310" 5 5,915' 5.45' 4.000"5.960" 6 5,920' 9.02' 4.000"5.000" 6,015' Csg 7 5,970' 4.54' 2.813"4.500" 8 9,418' 0.69' 2.992"4.187" 9 9,483' 12.02' 2.992"4.250" TOC (USIT Log)10 9,540' 6,118' MD 11 9,666' 13.1' - 4,992' TVD 12 9,716' 204.00' -4.625" 12.0 ppg 432 sx 13 9,926' - - - a 3,501' - - - Zone Top Btm Amt Gun Size SPF Phase Status Sterling A5 6,279' 6,292' 13' 2-3/8" 5 60 Open Tyonek A 9,545' 9,576' 31' 4-5/8" 6 60 Isolated Tyonek A 9,582' 9,609' 27' 4-5/8" 6 60 Isolated Tyonek B 9,648' 9,698' 50' 4-5/8" 6 60 Isolated 10,020' Csg 10,060' TD Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Slickline Apr 2008 Spud Date: Baker Model 80-40 Sealbore w/ GBH-22 Seal Assembly 46.80' 3698 psi @ 10,060' MD 9-5/8"x7" Baker Flex-Lock III liner hanger (set 2/4/09) Halliburton Type 'H' ES DV Collar (Closed 1/16/09) Description Tubing Hanger, Dual 3-1/2"x2-3/8" Vetco CWC 13-5/8" 5M Baker Model "SC-2" Retrievable Packer (set 2/10/09) PBTD - Top of 7" Float equipment (Tagged 2/6/09) Jewelry & Fish Halliburton 4-5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 7" Plug w/ 28' of cement on top of plug - TOC @ 9,512' 7/13/20 Halliburton WLEG w/ TCP Auto-Release Inflatable BP (tagged 36' deeper than setting depth 7/15/09) 9-5/8" Baker ZXP packer (set 2/4/09) Halliburton Ported Sub w/ Glass Disk Description (Heat String) Date Perforations 4/4/2009 4/4/2009, Re-Perf 5/10/2009 Schematic Mule shoe cut on joint, 2-3/8" Tubing Sterling/Beluga/Tyonek 4/4/2009, Re-Perf 5/10/2009 API#: Union Oil Company of California 100% (1) 7" Baker Model "SC-2" Mechanical Set Pkr Well Classificaton: 50-283-20130-00 PBTD: Development Gas Well 3-½", 9.2#, L-80, IBT-Mod Prod Pkrs: 9,926' Updated By:DMA 08-07-20 Ivan River Unit 7/13/2020 CASING & TUBING Description Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) Ownership: Total Depth: Tubing: Tubing:2-Ǫ", 4.6#, L-80, IBT(SCC) 10,060' 359,785 2,646,275 Shut-In 12/22/08 2:00 PM 134° @ 10,060' MD UOCC 30.00' 585' FSL & 630' FEL Sec 1,T13N,R9W,SM Surface Location: IRU 11-06 Ivan River Unit ORIGINAL RIG ELEVATIONS Permit to Drill#: 208-184 Lease & Serial#: ADL-032930 1 TA 2 3 4 6 5 7 8 13 12 a 9 MUD 10.1 ppg TB 11 10 SCHEMATIC SA5 7/13/2020Open602-3/8" 5Sterling A5 6,279' 6,292' 13' sterling sand 9540 ft plug By Samantha Carlisle at 1:21 pm, Jun 16, 2020 320-266 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.16 10:52:20 -08'00' Taylor Wellman All gas zones are co-mingled in Gas Pool #1 PA formed in 2000. DLB Note: Undefined Pool includes Sterling, Beluga, and Tyonek sands. Not a new pool, see note below. gls 6/17/20 DLB 06/17/2020 DSR-6/16/2020 10-404 XDSR X 6/19/2020 dts 6/18/2020 JLC 6/18/2020 RBDMS HEW 6/19/2020 Perforating new pool. Plugging existing Tyonek perfortions also. packer 5915' Sterling A5 perfs expandable plug with cement cap DATA SUBMITTAL COMPLIANCE REPORT 2/9/2011 Permit to Drill 2081840 Well Name /No. IVAN RIVER UNIT 11 -06 Operator UNION OIL CO OF CALIFORNIA API No. 50- 283 - 20130 -00 -00 MD 10060 TVD 8270 Completion Date 4/4/2009 Completion Status 1 -GAS Current Status 1 -GAS UIC N REQUIRED INFORMATION / Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: LWD(GR -RES) OPEN HOLE(GR -RES, DEN, NEU, SON) Cased(gr -ne (data taken from Logs Portion of Master Well Data Maint Well Log Information: III Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med /Frmt Number me Scale Media No Start Stop CH Received Comments C Las 17631 ' nduction /Resistivity 5652 6063 Open 3/2/2009 GR, HCAL, HMNO, ITT, 1 Tens, SPHI AHF t Sonic 5 Col 5800 6040 Open 3/2/2009 FE, Platform Express, Dipole Sonic, DSI, CNL, TLD, MCFL, Cali, GR 1- Feb -2009 Log Sonic 5 Col 5800 6000 Open 3/2/2009 FE, Dipole Sonic, DSI, GR 1- Feb -2009 D C Pds 17632 `'ionic 5800 6000 Open 3/2/2009 FE, Dipole Sonic, DSI, GR 1- Feb -2009 PDS Image File Only: g Sonic 5 Col 5650 9900 Open 3/2/2009 Dipole Sonic, 9- Feb -2009 ✓4D C Las 17633—tonic 5650 9900 Open 3/2/2009 DSI GR, Tens, VPVS 1- /' Feb -2009 • 'Rpt Report: Final Well R 0 0 Open 3/19/2009 Final Well Report, Tab of Cont, Well Details, Geo Data, Drilling Data, Daily Reps / 't=D C 17726` Report: Final Well R 0 0 Open 3/19/2009 Final Well Report, Tab of Cont, Well Details, Geo Data, Drilling Data, Daily Reps 4-Cog Mud Log 2 Col 3800 10060 Open 3/19/2009 MD Formation Log i og Mud Log 2 Col 3800 10060 Open 3/19/2009 TVD Formation Log DATA SUBMITTAL COMPLIANCE REPORT 2/9/2011 Permit to Drill 2081840 Well Name /No. IVAN RIVER UNIT 11 -06 Operator UNION OIL CO OF CALIFORNIA API No. 50- 283 - 20130 -00 -00 MD 10060 TVD 8270 Completion Date 4/4/2009 Completion Status 1 -GAS Current Status 1 -GAS UIC N Log Mud Log 2 CoI 3800 10060 Open 3/19/2009 MD LWD Combo Log Log Mud Log 2 Col 3800 10060 Open 3/19/2009 TVD LWD Combo Log Log Mud Log 2 Col 3800 10060 Open 3/19/2009 MD Drilling Dynamics Log Mud Log 2 Col 3800 10060 Open 3/19/2009 TVD Drilling Dynamics og See Notes 2 Col 1 - 4 835 10026 Open 4/6/2009 Drilling and Process • Mechanics (Depth) Log 29- Jan -2009 D C Pds 17773 "see Notes 835 10026 Open 4/6/2009 DRL Log 29- Jan -2009 og See Notes Col 1 0 0 Open 4/6/2009 Drilling and Process Mechanics (Time) Log 30 Dec - 2008 -10 Jan -2009 Log See Notes Col 2 0 0 Open 4/6/2009 Drilling and Process Mechanics (Depth) Log 11 Jan -13- Jan -2009 •g See Notes CoI 3 0 0 Open 4/6/2009 Drilling and Process Mechanics (Depth) Log 18 Jan -22- Jan -2009 Log See Notes Col 4 0 0 Open 4/6/2009 Drilling and Process Mechanics (Depth) Log 23 Jan -30- Jan -2009 og Induction /Resistivity 2 Col 835 10026 Open 4/6/2009 TVD Vision Resisitivity 29- Jan -2009 Log Induction /Resistivity 2 Col 835 10026 Open 4/6/2009 MD Vision Resisitivity 29- Jan -2009 • Log Pressure 5 Blu 4700 9719 Case 4/20/2009 Press Temp Log, GR, CCL VD C Pds 17865 /Pressure 4700 9719 Case 4/20/2009 Press Temp Log, GR, CCL ,.,.ED C Las 17909 /Cement Evaluation 4953 9899 Case 4/23/2009 USIT CCL, GR, Cali, Tens - DLIS, PDS Log Cement Evaluation 5 Col 5900 9900 Case 4/23/2009 USIT, CEL 8- Feb -2009 D C Las 18393 Gamma Ray 9383 9681 Case 8/5/2009 FLOWMETER GR, CCL, Temp, Tens Log Gamma Ray 5 Blu 4700 9719 Case 8/5/2009 FLOWMETER, GR, CCL 15 -Jul -2009 I DATA SUBMITTAL COMPLIANCE REPORT 2/9/2011 Permit to Drill 2081840 Well Name /No. IVAN RIVER UNIT 11 -06 Operator UNION OIL CO OF CALIFORNIA API No. 50- 283 - 20130 -00 -00 MD 10060 TVD 8270 Completion Date 4/4/2009 Completion Status 1 -GAS Current Status 1 -GAS UIC N Casing collar locator 5 Blu 4700 9670 Case 8/5/2009 Baker Inflatable Bridge Plug, CCL ,i/E C Pds 18394 Casing collar locator 4700 9670 Case 8/5/2009 Baker Inflatable Bridge Plug, CCL 29- Apr -2009 Well Cores /Samples Information: Sample Interval Set • Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION �A Well Cored? YCO Daily History Received? / N 1`1 Chips Received? `'1�T Formation Tops l.Y) N Analysis ``114 Received? Comments: I Date: Pc- �t Compliance Reviewed By: _ III 1 1 1 Page 1 of 1 - 1/13/2010 &u McMains, Stephen E (DOA) )...0 8 - ' 8 Li From: Kanyer, Christopher [Chris.Kanyer @chevron.com] Sent: Wednesday, January 13, 2010 1:10 PM To: McMains, Stephen E (DOA); Aubert, Winton G (DOA) Cc: Brandenburg, Tim C; Bonnett, Nigel (Nigel.Bonnett); Tyler, Steve L Subject: Cancellation of open sundries /permits After reviewing the following open permits to drill (form 10 -401) /sundries (form 10 -403) for Union Oil Company of Califomia, it has been determined these open AOGCC permits /sundries should be cancelled: PTD Sundry API Well Name /Number 209 -011 N/A 50- 233 - 20025 -00 Panthera 21-6 -9 208 -207 N/A 50- 287 - 20026 -00 Stegodon 24-6 -8 209 -058 N/A 50- 733 - 20586 -00 Trading Bay Unit M -08 197 -067 308 -252 50- 733 - 20043 -02 A -08RD2 201 -117 308 -269 50- 733 - 20254 -01 Trading Bay Unit K -18 195 -083 308 -268 50 -733- 20097 -04 Trading Bay Unit K -26RD 208 -184 309 -198 50- 283 - 20130 -00 Ivan River Unit (IRU) 11 -06 Please let me know if you have any questions. Thanks, Chris Kanyer •• Technical Assistant Wellbore Maintenance Team Office: (907) 263 -7831 Cell: (907) 250 -0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 1/13/2010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSTGN GAS WELL OPEN FLOW POTENTIAL TEST REPO i, 1 a. Test: L] Initial Li Annual U Special 1 b. Type Test: ❑- Stabilized ❑ ; Nan StabOzed Lei 'Multipoirtt ❑ Constant Time ❑ Isochronal ❑ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Union Oil Company of California 7/08/09 (hydrocarbon flow) 208 -184 3. Address: 6. Date TD Reached: 12. API Number: PO Box 196247, Anchorage, AK 99519 January 21, 2009 50- 283 - 20130 -00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 585' FSL, 630' FEL, Sec 01, T13N, R9W, SM 46.8' Ivan River Unit 11 -06 Top of Productive Horizon: 8. Plug Back Depth(MD +TVD): 14. Field /Pool(s): 1777' FNL, 1006' FEL, Sec 01, T13N, R9W, SM 9637'MD/ 7917'TVD Ivan River Unit Total Depth: 9. Total Depth (MD + TVD): Undefined Gas 200' FNL, 366' FWL, Sec 06, T13N, R8W, SM 10,060'md /8270'TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 359785 y- 2646275 Zone- 4 N/A ADL- 032930 TPI: x- 359444 y- 2649197 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 360835 y- 2650757 Zone- 4 perforated casing 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 7" 26 6.276 5825-10,020' 9545' - 9576' 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 9582' - 9609' 3 -1/2" 9.2 2.992 9483' 9648' -9698' (isolated /partial) 20. Packer set at ft: 21. GOR cf /bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 5915' NA NA NA 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): El Tubing ❑ Casing 130 F° 750 psia @ Datum 6790' TVDSS 14.7 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO % N2: % H2S: Prover: Meter Run: Taps: NA NA 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 psig Hw F psig F psig F Hr. Size (in.) Size (in.) 1. X 704 70 0 NA 0 2. X 426 83 0 NA 2 3. X 371 87 0 NA 2 4. X 320 90 0 NA 2 5. X 255 92 0 NA 2 Basic Coefficient Flow Temp. Super Comp. 24 -Hour Pressure Gravity Factor Rate of Flow No. ( ) -v hwPm Factor Factor O Mcfd Fb or Fp Pm Ft Fg Fpv 1, 0 2 2784 3 3123 4 3405 5. 3691 Temperature for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1. 563 1.54269 0.9091 2. 1.361069837 563 1.580916 0.9143 3. 1.335809807 563 1.619497 0.9193 Critical Pressure 673 4. 1.29717682 563 1.658078 0.9241 Critical Temperature 346 5. 1.254086181 563 1.696665 0.9286 Form 10 -421 Revised 1/2004 CONTINUED ON REVERSE SIDE IS 8 ( � S bmit Anptuplic I 154 • Pc 683 pct 466489 Pf 793 p{ 628849 No. Pt pt2 Pc -Pt Pw Pw Pc Ps Ps Pf 1. 2. 441 194481 272008 75 5625 460864 516 266256 362593 3. 386 148996 317493 65 4225 462264 451 203401 423448 4. 334 111556 354933 56 3136 463353 390 152100 476749 5. 270 72900 393589 45 2025 464464 315 99225 529624 25. AOF (Mcfd) 4,200 n 0.8188 Remarks: I hereby certify that the foregoing is true and correct to the best of my knowledge. 1 , Signed : i n ' " Title Petroleum Engineer Date 9/11/2009 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. Form 10 -421 Revised 1/2004 Side 2 • vr - on ,:;zrainzi3e.o aasAlcr.r.c,: NDrth Ad ProcNctiron , Technical Asslstan:: 3300 ..:2enterpoint Dr, Suite 100 Anchorage AK 99503 Tele: 907 263 7844 Fax: 907 263 7828 E-mail: fcbn@chevron.com DATE August 4, 2009 To AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Corrected copy of log previously submitted and returned. = •, it0,15tpt.4.3te. DLIS, PDS, 4 9 /IA LAS TBU G-25 RST - GR - CCL 5" 13Jan09 1500-10493 1 1 1 WELL L0GTYPE SCALE LODATE . AdtptP"%- LAS, ti LA IRU 11-06 FLOWMETER LOG GR/CCL 15-Jul-09 1 4700-9716 1 1 DLIS, PDS u e5 f p ,i sa I ..5c IRU 11-06 BRIDGE PLUG CCL LOG 5" 29-Apr-09 1 4700-9670 1 1 PDS ( CL- br5 PDS, LAS, IRU 41-01 RST SIGMA LOG 5" 1 7-Jul-09 1 5000-8634 1 1 DLIS Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 263 7828. Received By: ( Date: . 1 t,7 1 g l p t r t �a� F� n a r 6 (, �' t t 9 p F t A 4 d C b.\ R ' SARAH PALIN, GOVERNOR LL—„1,173 t a po ALASKA OIL AND GAS 333 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION r ANCHORAGE, ALASKA 99501 -3539 is►7�I • PHONE (907) 279 -1433 Timothy Brandenburg FAX (907) 276 -7542 Drilling Manager Unocal PO Box 196247 Anchorage AK 99519 Re: Ivan River Unit, Undefined Gas, IRU 11 -06 Sundry Number: 309 -198 Dear Mr. Brandenburg: g Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, 4 ,, Daniel T. Seamount, Jr. Chair DATED this / 7 da y of June, 2009 Encl. tt) — (t C1 "' STATE OF ALASKA Mk 411712007 (,'t ALAS OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate 0 • Waiver ❑ Other Alter casing ❑ Repair well ❑ Plug Perforations 0 . Stimulate ❑ Time Extension ❑ • Cut tubing Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re -enter Suspended Well ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development 0 Exploratory ❑ 208 -184 ' 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: PO Box 196247, Anchorage, AK 99519 50- 283 - 20130 -00 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No A /r iv,zot Ivan River Unit (IRU) 11 -06 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field / Pool(s): ADL032930 [Ivan River Unit] 46.8 MSL Ivan River Unit / Undefined Gas • 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 10,660 8,270 9,630 7,911 9,630' (IBP) 9,716' (TCP guns) Casing Length Size MD TVD Burst Collapse Structural Conductor 171' 20" 171' 171' Surface 1,016' 13 -3/8" 1,016' 1,016' 5,020 psi 2,670 psi Intermediate 6,015' 9 -5/8" 6,015' 4,920' 5,750 psi 3,090 psi Production 4,195' 7" 10,020' 8,238' 7,240 psi 5,410 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3 -1/2 "(prod) & 2 -3/8 "(heater) 9.2 #L- 80(prod) & 4.6 #L- 80(heat) 9,483'(prod) & 3,501'(heat) Packers and SSSV Type: Packers and SSSV MD (ft): Baker SC -2 Retrievable Packer and N/A 5,915' and N/A 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development El Service ❑ 15. Estimated Date for 6/18/2009 16. Well Status after proposed work: Commencing Operations: Oil ❑ Gas El Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Kanyer 263 -7831 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature C P 7600 Date 6/10/2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: loci' . /9s, Plug Integrity V BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ RECEIVED Other: Per 20 /C 25. 1 , Z t; ) / mike f( pill p/R,Con.ef vccrl etn c e / s 0 fp 1-1) L , UN 1 2 2005 Alaska Oil & Gas Cans. Commission Subsequent Form Required: 10 _ (40 0 T Anchorage i ` / �' / APPROVED BY Approved by: �'/ J COMMISSIONER THE COMMISSION Date: d , AP 00 ))1 . , /7. Form 10 -403 Revised 06/2006 ORIGINAL Submit in Duplicate Chevron 11, 1110 Ivan River Unit /41110 Well # IRU 11 -06 6/10/09 OBJECTIVE: • Pull Inflatable BP, cut tubing, plug back open perfs, and perforate Beluga sands. PROCEDURE SUMMARY: 1 RU Slickline lubricator and pressure test to 250 psi low /2500 psi high. 2 Equalize & retrieve IBP at 9,630' RKB ( + / -). 3 RIH with GR and tag top of TCP perf guns at 9,716'( + / -). 4 RD Slickline. 5 RU Eline lubricator and pressure test to 250 psi low /2500 psi high. 6 RIH with GR/CCL and 3.5" PowerCutter and tie -in. Cut tubing at 8,275' ( + / -) RKB. Verify tubing has been cut. 7 RIH with GR and tag tubing at 8,496' ( + / -). Shoot fluid level. 8 RIH w/ 7" PosiSet plug above top of tubing at 8,496' ( + / -) RKB. Set same at ,49 ' ( + / -) RKB. MU & tag plug with dump bailer at 8,493' ( + / -) RKB. Begin Dump bailin 0' cement�� 9 on top of plug (6 runs). RD Eline. 10 WOC trapping 770psi ( + / -) on well. Shoot fluid level. 11 Bleed surface pressure off to 200 psi for 12 hour negative test. Test will be charted. /. 12 Pressure well with nitrogen to 2300psi ( + / -) surface pressure for 12 hour positive test. Test will be charted. 13 RU Eline lubricator and pressure test to 250 psi low /3000 psi high. RIH with GR/CCL and perf gun, tie -in, and tag top of cement Bleed pressure down 14 for 20% underbalance. Perforate Beluga sand at 8,410' ( + / -) - 8,435' ( + / -). Contingency: Perforate Beluga sand at 8,290' ( + / -) - 8,310' ( + / -). 15 Rig down Eline. Turn well over to production. IRU 11 -06 REVISED BY: CVK 6 -10 -09 Chevron 11 -06 Ivan River Unit Permit to Drill #: 208 -184 Lease &Serial #: ADL- 032930 ORIGINAL RIG Field: . 1 Ivan River Unit API #: 50 -283- 20130 -00 ELEVATIONS Surface Location: Well Classificaton: Development Gas Well 585' FSL & 630' FEL Total Depth" 10,060' Sec 1,T13N,R9W,SM PBTD 9,926' RKB -GL X: ASP4 359,785 Tubing: 3 - % ", 9.2 #, L -80, IBT -Mod 16.80' Y: ASP4 2,646,275 Tubing: 2-%", 4.6 #, L -80, IBT(SCC) RKB -MSL - - - Well Status: Shut -In Prod Pkrs: (1) 7" Baker Model "SC -2" Mechanical Set Pkr 46.80' II Operator: UOCC Ownership: Union Oil Company of California 100% I GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM 171' Csg RKB -MSL: 46.80' Other Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Top Job • BHP: 3698 psi @ 10,060' MD Slickline Apr 2008 15.8 ppg 187 sx BHT: 134° @ 10,060' MD - Primary Cmt CASING & TUBING Rotate 13.O ppg 552sx -41 I, Description Weight Grade Conn ID Length Top Btm TOC Ws 1,016' Csg Structural 20" 129.08 X -56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV Surface 13 3/8" 68.08 L -80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900' - 3,487' Intermediate 9 5/8" 40.08 L -80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs 12.5 ppg 642 sx • Production 7" 26.08 L -80 BTC -Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar ' 3,487' MD 3 Cmt below DV 4,100' - 6,120' Tubing 31/2" 9.2# L -80 IBT -Mad* 2.992" 9,495' 0' 9,495' 12.0 ppg 397 sx , 2 3/8" 4.68 L -80 IBT' 1.995" 3,501' 0' 3,501' -k. IG © `- SCC (Special Clearance Couplings) Jewelry & Fish D escription Depth Length ID OD till 1 Tubing Hanger, 3 -1/2" NSCO Unihead 11" SM, 3" Type H BPV 17' 0.49' 3.000" 11.000" -t - - � - -I -.V . 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" ' ] 3 9 -5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" l {i. 4 9-5/8"07" Baker Flex -Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" t —i J 5 Baker Model "SC -2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 6 Baker Model 80 -40 Sealbore w/ GBH -22 Seal Assembly 5,920' 9.02' 4.000" 5.000" 6,015' Csg 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" 8 Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" 9 Halliburton WLEG w/ TCP Auto - Release 9,483' 12.02' 2.992" 4.250" TOC (USIT Log) 10 Inflatable Bridge Plug 9,630' 13.1' 6,118' MD 11 Halliburton 4 -5/8" TCP Assembly (Pert 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" 4,992' TVD 12 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 12.0 ppg 432 sx Description (Heat String) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' - - - Perforations Zone I Top I Btm I Amt I Gun Size I SPF I Phase 1Statua I Date Sterling /Belu,a /Tyonek A Tyonek 9,545' 9,576' 31' 4 -5/8" 6 60 Open 4/4/09 Reperf 5/10/09 A Tyonek 9,582' 9,609' 27' 4 -5/8" 6 60 Open 4/4/09 Reperf 5/10/09 B Tyonek 9,648' 9,698' 50' 4 -5/8" 6 60 Open 4/4/09 Isolated ' E lit . Q e1 li ii 10 i t[ - 10,020' Csg 10,060' TD MUD 10.1 ppg Current Well Schematic 5 -6 -09 Prepared By: Chris Kanyer 0 Chevron PROPOSED L ermitto Drill# 208 -184 IRU 11 -06 Ivan River Unit Lease 8 Serial #: ADL- 032930 ORIGINAL RIG Field: I Ivan River Unit API #: 50- 283 - 20130 -00 ELEVATIONS Surface Location: Well Classificaton: Development Gas Well 585' FSL 8 630' FEL Total Depth: 10,060' Sec 1,T13N,R9W,SM PBTD: 9,926' RKB -GL X: ASP4 359,785 Tubing: 3 -15 ", 9 2#, L -80, IBT -Mod 16.80' Y: ASP4 2,646,275 Tubing: 2-%", 4.6 #, L -80, IBT(SCC) RKB -MSL — — Well Status. Shut -In Prod Pkrs: (1) 7" Baker Model "SC-2" Mechanical Set Pkr 46 80' :� Operator UOCC Ownership. Union Oil Company of California 100% GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM • 171' Csg RKB -MSL: 46.80' Other Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Top Job BHP'. 3698 psi @ 10,060' MD Slickline Apr 2008 15.8 ppg 187 se BHT. 134` @ 10,060' MD Primary Cmt ' CASING & TUBING I Rotate 13.0 ppg 552 sx - 41.' Description Weight Grade Conn i0 Length Top Btm TOC tits 1,016' Csg Structural 20" 129.0# X -56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV - { Surface 13 3/8" 68.08 L -80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900' -3,48T Intermediate 9 5/8" 40.0# L -80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs 12.5 ppg 642 sx t I Production 7" 26.0# L -80 BTC -Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar ' ? 1 3,487' MD Cmt below DV . 4,100-6,120' Tubing 31/2" 9.2# L -80 IBT -Mod` 2.992" 9,495' 0' 9,495' 12.0 ppg 397 sx 2 3/8" 4.6# L -80 IBT' 1.995" 3,501' 0' 3,501' © ' - SCC (Special Clearance Couplings) -. 2 Jewelry & Fish Description Depth Length ID OD © 1 Tubing Hanger, 3 -1/2" NSCO Unihead 11" 5M, 3" Type H BPV 17' 0.49' 3.000" 11.000" 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" - II 3 9 -5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" 4 9- 5/8 "x7" Baker Flex -Lock Ill liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" 5 Baker Model "SC -2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 6 Baker Model 80 -40 Sealbore w/ GBH-22 Seal Assembly 5,920' 9.02' 4.000" 5.000" 6,015' Csg L I1 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" • 8 Tubing Tail w/ SLB PowerCutter 8,275'( + / -) 2.992" - 9 7" PosiSet BP w/ 10' cement on top 8,493'( + / -) 48.25" - - TOC (USIT Log) 10 Cut tubing Fish (see detail below) 8,496' 1,220' 2.992" - 6,118' MD 1 , 11 Halliburton 4 -5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" 4,992' TVD , 12 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 12.0 ppg 432 sx Description (Heat String) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' - - - Description (Cut tubing) 3 -1/2" 9.2# L -80 IBT -Mod tubing 8,496' 1,220' 2.992" 3.500" Halliburton Ported Sub w/ Glass Disk 9,639' 0.69' 2.992" 4.187" • • Halliburton WLEG w/ TCP Auto - Release 9,704' 12.02' 2.992" 4.250" rations Zone Top Btm Amt Gun Size SPF I Phase 'Status I Date A Beluga I�8,290'( + / -) 8,310'( + / -) 20'( + / -) 2" or 2.5" 6 60 Contingency Proposed B Beluga 8,4101+1 -) 8,435'( + / -) 25'( + / -) 2" or 2.5" 6 60 Proposed Tyonek 9,545' 9,576' 31' 4 -5/8" 6 60 Open 4/4/09 Reperf 5/10/09 Tyonek 9,582' 9,609' 27' 4 -5/8" 6 60 Open 4/4/09 Reperf 5 /10/09 Tyonek 9,648' 9,698' 50' 4 -5/8" 6 60 Open 4/4/2009 giii 10 � ' i • ' • I11 • 10,020' Csg � _- 12 10,060' TD MUD 10.1 ppg PROPOSED Well Schematic 5 -27 -09 Prepared By: Chris Kanyer • Page 1 of 1 Aubert, Winton G (DOA) From: Kanyer, Christopher V [Chris.Kanyerrchevron.com] Sent: Wednesday, June 17, 2009 11:42 AM To: Aubert. Winton G (DOA) Subject: IRU 11 -06 Winton, With regards to our discussion of the proposed plugging back of the Tyonek zone in IRU 11 -06, I request a variance to AOGCC Regulation 20AAC25.112(1). The future recompletion in IRU 11- 06 will require the maximum rat hole available in order to access Beluga gas sands. For this reason I ask for the variance for less than the 25' of dump bailed cement required by regulation. Please contact me if you have any questions. Thanks, Chris Kanyer Technical Assistant Welibore Maintenance Team Office: (907) 263 -7831 Cell: (907) 250 -0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 6/17/2009 A6/ (%'/ U i /2-00i STATE OF ALASKA ALA, OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon L] Repair Well 11 Plug Perforations U Stimulate U Other U Set IBP & CT Unload . Performed: Alter Casing ❑ Pull Tubing❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. ShutdownE Perforate ❑ Re -enter Suspended Well ❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: ( . 5. Permit to Drill Number: Name: Development E 1 Exploratory 208 -184 . 3. Address: P.O. Box 196247, Anchorage, AK 99519 Stratigraphic❑ Service ❑ 6. API Number: 50- 283 - 20130 -00 • 7. KB Elevation (ft): 9. Well Name and Number: 46.38 MSL • Ivan River Unit (IRU) 11 -06 • 8. Property Designation: 10. Field /Pool(s): ADL032930 [Ivan River Unit] • Ivan River Unit / Undefined Gas . 11. Present Well Condition Summary: Total Depth measured 10,060 • feet Plugs (measured) 9,630' (IBP) true vertical 8,270 • feet Junk (measured) 9,716' (TCP guns) Effective Depth measured 9,630 feet true vertical 7,911 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 171' 20" 171' 171' Surface 1,016' 13 -3/8" 1,016' 1,016' 5,020 psi 2,670 psi Intermediate 6,015' 9 -5/8" 6,015' 4,920' 50 psi 3,090 psi Production 4,195' 7" 10,020' CENE 0 psi 5,410 psi Liner V Perforation depth: Measured depth: See Attached Schematic MAY 2 8 2009 $$1011 True Vertical depth: See Attached Schematic Alaska Oil &Gas Coroage ns• Comm i .2# Tubing: (size, grade, and measured depth) 3 -1/2" 9.2# L -80 9,495' (prod) / 2 -3/8" 4.6# L -890 3,501' (heater) Packers and SSSV (type and measured depth) Baker SC -2 Retr. Packer / N/A 5,915' / N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 - 0 0 0 psi 0 psi Subsequent to operation: 0 0 0 0 psi 670 psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development Service ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas El - WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 309 -149 Contact Marcus Barbee 263 -7605 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature y Phone 276 -7600 Date 5/28/2009 Form 10 -404 Revised 04/2006 � J U ,, L N 0 1. 70 \ 2 ‘ . " ° II " ° L Submit Original Only • 0 + 0. Chevron Permit to Drill #: 208 -184 IRU 11 -06 Ivan River Unit Lease 8 Serial #: ADL- 032930 ORIGINAL RIG Field: I Ivan River Unit API #: 50- 283 - 20130 -00 ELEVATIONS Surface Location: Well Classificaton: Development Gas Well 585' FSL 8 630' FEL Total Depth: 10,060' Sec 1,T13N,R9W,SM PBTD: 9,926' RKB -GL X: ASP4 359,785 Tubing: 3 -V: ", 9.2 #, L -80, IBT -Mod T 16.80' + T r Y: ASP4 2,646,275 Tubing: 2 - % ", 4.68, L -80, IBT(SCC) RKB -MSL - - - Well Status. Shut -In Prod Pkrs: (1) 7" Baker Model "SC -2" Mechanical Set Pkr 46.80' II Operator: UOCC Ownership: Union Oil Company of California 100% GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM 171' Csg RKB -MSL: 46.80' Other. Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; • Top Job BHP: 3698 psi @ 10,060' MD Slickline Apr 2008 15.8 ppg 187 so BHT: 134° @ 10,060' MD Primary Cmt CASING & TUBING - Rotate 13.0 ppg 552 ss -'+ ii- Description Weight Grade Conn ID Length Top Btm TOC Hrs 1,016' Csg Structural 20" 129.08 X -56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV _ Surface 13 3/8" 68.0# L -80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900'- 3,487' _ Intermediate 9 5/8" 40.08 L -80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs 12.5 ppg 642 sx . Production 7" 26.0# L -80 BTC -Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar I \ I 3,487' MD Cmt below DV 4,100' - 6,120' Tubing 3 1/2" 9.2# L -80 IBT -Mod` 2.992" 9,495' 0' 9,495' 12.0 ppg 397 sx , . 1 2 3/8" 4.6# L -80 !BP 1.995" 3,501' 0' 3,501' © ' - SCC (Special Clearance Couplings) -' Jewelry & Fish Description Depth Length ID OD I I i l l © 1 Tubing Hanger, 3 -1/2" NSCO Unihead 11" 5M, 3" Type H BPV 17' 0.49' 3.000" 11.000" ' _f =! =[= 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" r 3 9 -5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" 4 9- 5/8 "x7" Baker Flex -Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" ;—f. © 5 Baker Model "SC -2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 6 Baker Model 80 -40 Sealbore w/ GBH -22 Seal Assembly 5,920' 9.02' 4.000" 5.000" - 6,015' Csg A_ ik 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" 8 Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" _ 9 Halliburton WLEG w/ TCP Auto - Release 9,483' 12.02' 2.992" 4.250" TOC (USIT Log) 10 Inflatable Bridge Plug 9,630' 13.1' 6,118' MD _ 11 Halliburton 4 -5/8" TCP Assembly (Pert 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625", 4,992' TVD 12 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 12.0 ppg 432 sx Description (Heat String) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' - - - Perforations Zone I Top I Btm I Amt I Gun Size I SPF I Phase (Status I Date Sterling/Beluga/Tyonek A Tyonek 9,545' 9,576' 31' 4 -5/8" 6 60 Open 4/4/09 Reperf 5/10/09 A Tyonek 9,582' 9,609' 27' 4 -5/8" 6 60 Open 4/4/09 Reperf 5/10/09 B Tyonek 9,648' 9,698' 50' 4 -5/8" 6 60 Open 4/4/09 Isolated 7 j III II 110 -_ 111 12 10,020' Csg -_ 10,060' TD MUD 10.1 ppg Current Well Schematic 5 -6 -09 Prepared By Chris Kanyer Chevron • I WO Chevron-Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UM ChevNo Original RKB (ft) Water Depth (ft) IRU 11-06 IVAN RIVER UNIT 11-06 ADL032930 5028320130 LK9485 46.80 bS -** Primary Job Type Job Category Objective Actual Start Date Actual End Date Stimulation Well 4/24/2009 Services Primary VVellbore Affected VVellbore UWI Well Permit Number IRU 11-06 5028320130-00 2081840 —1. ' : ' ! '13:Srif: : ?;:711M111111/1111SL:, ; 27i l l Y tt ; t 4: ' ,%. ;5 :tf 4/24/2009 00:00- 412512000 00:00 Operations Summary Prepare location for Coil Tubing & E - Line Operstions 4125/2009 0000 - 4/26/2009 00:00 Operations Summary Prepare location for Coil Tubing & E - Line Operations 4/26/2009 0 Operations Summary Haul E - Line equipment to location 413778000 00:00 - 4/28/200000:00 Operations Summary MIRU E - Line unit, build 2-1/2" inflatable bridge plug, pick up tools and test same (good), stab on PT 250psi-2,500psi (good), RIH and make corelation passes, position center of element @ 9,637', begin setting sequence, (2hrs) unable to set IBP, POOH. Tools checked out good on surface, setting tools did not. Send for another IBP. SDFN 4/211/206000:00 - 4/29/2609 00:00 Operations Sumrnary Waiting on IBP equipment. No work on IRU 11-06 today. r 009 00:00 - 4/30/2009 00:00 ;11 Operations Summary RU E - Line and pressure test lubricator to 250psi low/ 2000psi high. Set IBP with center of element © 9,637'. RD E - Line and prep for coil tubing operations. 4 3 1 4 0 0 9 , 0 0 : 0 0 - 5/1/20000000, Operations Summary MIRU CTU and test BOPE 250psi low/4000psi high, witness waived by AOGCC Bob Noble. -51112009 00:00 00:00 Operations Summary Unload well with nitrogen to open top tank holding 300 psi back pressure. Recovered 66 Bbls total of formation fluid and residual completion fluids (6% KCI & diesel). POOH and begin to inject nitrogen into zone. 58K injected @ 2,000 psi, then shut down due to injector problems. , 5/2/2009 00:005i312009 00:00 ' Operations Sunmary POOH with injured injector head. OOH & inject 98K scf of nitrogen @ 1,425 psi. RD on 11-06 and RU on 14-31 to inject fluid recovered from 11-06. Inject all fluid & RD. 51342009 00:00 - 5/4/2009 00:00 Operations Summary Unload nitrogen to atmosphere & bring the well on line to production 2009 00:00 - 6/6/2009 Operations Summary Demobe. 515/2000 00:00 ...V: ," .00A:00 Operations Summary Demobe. *012009 0(100,...,5/7/2009 00:00 Operations Summary Demobe. 5/7/2009,00:00 - 6/8/206000(00 Operations Summary Demobe. 083/2009 00004/012009 Operations Summary Took fluid level shot w/ ecometer. Formation fluid in 3-1/2" tubing at 7,510' (+/-). *: 84000 00:00 .5/10/2009 00:00 Operations Sumniary Mobe Eline equipment to Westside & RU on well... 5110/ w 00:00 - 5/11/2009 00:00 Operations Summary Pressure well up using field gas to 700psi & trapped on well for 2 hours. RU Eline unit & pressure test lubricator to 250psi low/2500psi high. Bled tubing pressure to 400psi. RIH w/ 20' 2.5" PJ Omega 6spf 60 deg guns and perferorated 9,588-9608' and 9,552-9,572' (2 runs). RD eline unit. Turn well over to production. Chevron Chevron - Alaska %. Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 5/11/2009 00:0k , 4412/2009 5!12/2009 00:00 ' Operations Summary Demobe. Page 1 of 1 • Aubert, Winton G (DOA) From: Aubert, Wnton G (DOA) Sent Thursday, May 28, 2009 4:04 PM • To: 'Kanyer, Christopher V' • Subject: RE: IRU 11-06 Chris, f+ 1OGCC hereby approves pulling the B?. from 9637' in IRU 11-06 (P i C 238- 884), described below. Please submit appropriate vecumentat en as required. 'Million A AOGCC 793 -1231 From: Kanyer, Christopher V [mailto:Chris.Kanyer @Chevron.com] Sent: Thursday, May 28, 2009 3:27 PM To: Maunder, Thomas E (DOA); Aubert, Winton G (DOA) Subject: IRU 11-06 Sundry 309 -149 Tom and Wnton, I would like to request permission to pull the inflatable bridge plug from IRU 11 -06 that was set on 4/29 /09, while we currently evaluate our plan forward on this welt. I will be submitting a 10-404 for the completion of these operations (Sundry 309 -149) by tomorrow. The well is currently not able to produce despite our isolation of the lower zone by the IBP. We currently have equipment and crews on the Westside of the Inlet and would like to do this work as soon as possible while we have crews and also for cost savings purposes. Please let me know if you have any questions. Thanks, Chris Kanyer •• - Technical Assistant Wellbore Maintenance Team Office: (907) 263 -7831 Cell: (907) 250 -0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 Page 1 of 2 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, May 27, 2009 10:12 AM To: 'Kanyer, Christopher V' Cc: Aubert, Winton G (DOA) Subject: RE: IRU 11 -06 Sundry 309 -149 Chris, It is probably best to have all the activities described in the sundry application. If it is desired to pull the IBP "early ", then that request should be made then. Please also note that Cook Inlet activities are now being handled by Winton Aubert. I have copied him n this reply. Tom Maunder, PE AOGCC From: Kanyer, Christopher V [mailto:Chris.Kanyer @chevron.com] Sent: Wednesday, May 27, 2009 8:51 AM To: Maunder, Thomas E (DOA) Subject: RE: IRU 11 -06 Sundry 309 -149 Thank you for the clarification. I will be submitting a new 10-403 with this 10-404 to cut tubing to move up hole and pert a new zone. The inflatable BP will need to be retrieved before these operations. Does the retrieval of the IBP need to be submitted with the 10-403 for State approval or can it be retrieved before the 10-403 is submitted? Thanks, Chris Kanyer •s Technical Assistant Wellbore Maintenance Team Office: (907) 263 -7831 Cell: (907) 250 -0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, May 27, 2009 8:36 AM To: Kanyer, Christopher V Subject: RE: IRU 11 -06 Sundry 309 -149 Chris, If the 407 has been submitted, then the operations for 309 -149 should be reported using a 404. At the time 309 -149 was processed, I was not aware that the 407 had been submitted. Call or message with any questions. Tom Maunder, PE AOGCC 5/28/2009 Page 2 of 2 • • From: Kanyer, Christopher V [ mailto :Chris.Kanyer @chevron.com] Sent: Wednesday, May 27, 2009 8:09 AM To: Maunder, Thomas E (DOA) Subject: IRU 11 -06 Sundry 309 -149 Tom, On April 23, 2009 a 10 -407 (Permit to Drill 208 -184) & 10-403 (approved sundry 309 -149) were submitted. Operations proposed on sundry 309 -149 have been completed. Upon further review of this sundry, subsequent forms required state: "none this approval, include operations on 407." I would like to clarify if an additional 10-407 is required for these operations, or if a 10-404 should be submitted instead. 1 appreciate matter. Please call if have any questions. reciate you helping clarifying this atte ease ca you ve pP Y P g Y Y q Chris Kanyer • • Technical Assistant Wellbore Maintenance Team Office: (907) 263 -7831 CeII: (907) 250 -0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 5/28/2009 • • Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, May 06, 2009 4:47 PM To: 'Kanyer, Christopher V' Subject: RE: IRU 11 -06 (208 -184) Sundry 309 -149 Chris, It is not necessary to submit another sundry. I will place a copy of this message in the file. Tom Maunder, PE AOGCC From: Kanyer, Christopher V [mailto:Chris.Kanyer @chevron.com] Sent: Wednesday, May 06, 2009 4:37 PM To: Maunder, Thomas E (DOA) Subject: IRU 11 -06 Sundry 309 -149 Tom, IRU 11 -06 coil tubing operations have been completed for Sundry 309 -149, as noted in the weekly operations summary sent today. We are curently producing about 500 MCF of gas. The plan forward is to reperf 20' of each of the two upper tyonek zones that are currently producing soon. This was not part of the submitted plans in Sundry 309 -149. Will an additional sundry be needed to reperf these zones? Please let me know if you have any questions. Thanks, Chris Kanyer • • Technical Assistant Wellbore Maintenance Team Office: (907) 263 -7831 Cell: (907) 250 -0374 Chevron North America Exploration and Production Midcontinent/Alaska SBU 3800 Centerpoint Dr, Suite 100 Anchorage, AK 99503 5/6/2009 i Ali 111, 0 4'. Chevron IRU 11 -06 Ivan River Unit Permit to Drill #: 208 -184 Lease & Serial #: ADL- 032930 ORIGINAL RIG Field: 1 Ivan River Unit API #: 50 -283- 20130 -00 ELEVATIONS Surface Location: Well Classificaton: Development Gas Well 585' FSL & 630' FEL Total Depth: 10,060' Sec 1,T13N,R9W,SM PBTD: 9,926' RKB -GL X: ASP4 359,785 Tubing: 3 -% ", 9.28, L -80, IBT -Mod 16.80' 4 Y: ASP4 2,646,275 Tubing: 2 - % ", 4.6#, L -80, IBT(SCC) RKB -MSL - Well Status: Shut -In Prod Pkrs: (1) 7" Baker Model "SC -2" Mechanical Set Pkr 46.80' Operator: UOCC Ownership: Union Oil Company of California 100% GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM 171' Csg RKB -MSL: 46.80' Other: Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Top Job I • BHP: 3698 psi @ 10,060' MD Slickline Apr 2008 15 .8 ppg 187 s> 1 BHT: 134° 10,060' MD Primary Cmt orate 13.0 ppg 552 sx L Description Weight Grade Conn ID Length Top Btm TOC Mrs 1,016' Csg , , ; _ Structural 20" 129.08 X -56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV Surface 13 3/8" 68.0# L -80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900'- 3,487' Intermediate 9 5/8" 40.08 L -80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs 12.5 ppg 642 sx Production 7" 26.08 L -80 BTC -Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar I 3,487' MD — Cmt below DV 4,100'- 6,120' Tubing 31/2" 9.28 L -80 IBT -Mod" 2.992" 9,483' 0' 9,483' 12.0 ppg 397 sx 2 3/8" 4.6# L -80 IBT" 1.995" 3,501' 0' 3,501' 3 " - SCC Special Clearance Couplin.$) i I¢ v" AI © Description Depth Length ID OD I IALI" ® 1 Tubing Hanger, 3 -1/2" NSCO Unihead 11" 5M, 3" Type H BPV 17' 0.49' 3.000" 11.000" 1<= 8°4. 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" ' ] 3 9 -5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" .. 4 9- 5/8 "x7" Baker Flex -Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" 5 Baker Model "SC -2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 'X' 6 Baker Model 80 -40 Sealbore w/ GBH -22 Seal Assembly 5,920' 9.02' 4.000" 5.000" 6,015' Csg 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" 8 Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" 9 Halliburton WLEG w/ TCP Auto - Release 9,483' - 2.992" 4.250" TOC (USIT Log) 10 Inflatable Bridge Plug 9,630' 13.1' 6,118' MD 11 Halliburton 4 -5/8" TCP Assembly (Pert 4/4/09, Tagged 4/6/09) 9.716' 204.00' - 4.625" 4,992' TVD 1 12 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 12.0 ppg 432 sx Description (Heat String) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' Zone Top Btm Amt Gun Size SPF Phase Status Date Ste rlin g/B el u9a/Tyon ek s A Tyonek 9,545' 9,576' 31' 4 -5/8" 6 60 Open 4/4/2009 A Tyonek 9,582' 9,609' 27' 4 -5/8" 6 60 Open 4/4/2009 B Tyonek 9,648' 9,698' 50' 4 -5/8" 6 60 Open 4/4/09 Isolated ill WI r it v lil C 1121 O 10 x 10,020' Csg ► 10,060' TD MUD .... 10.1 ppg - Current Well Schematic 5-6-09 Prepared By: Chris Kanyer VY ` /� 40/` gl (" o� STATE OF ALASKA � oOg d( ALA OIL AND GAS CONSERVATION COMMI N s • APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ,. .',.ii s Cons. Commission 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ❑ Ai, , "` ?t] Other Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension ❑ Set IBP & CT UnloaC Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re -enter Suspended Well ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development El Exploratory ❑ 208 -184 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: PO Box 196247, Anchorage, AK 99519 50- 283 - 20130 -00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No El Ivan River Unit (IRU) 11 -06 9. Property Designation: 10. KB Elevation (ft): 11. Field / Pool(s): ADL032930 [Ivan River Unit] 46.8 MSL Ivan River Unit / Undefined Gas 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 10,060 8,270 9,931 8,164' N/A 9,716' (TCP guns) Casing Length Size MD TVD Burst Collapse Structural Conductor 171' 20" 171' 171' Surface 1,016' 13 -3/8" 1,016' 1,016' 5,020 psi 2,670 psi Intermediate 6,015' 9 -5/8" 6,015' 4,920' 5,750 psi 3,090 psi Production 4,195' 7" 10,020' 8,238' 7,240 psi 5,410 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A 3 -1/2 "(prod) & 2 -3/8 "(heater) 9.2 #L- 80(prod) & 4.6 #L- 80(heat) 9,483'(prod) & 3,501'(heat) Packers and SSSV Type: Packers and SSSV MD (ft): Baker SC -2 Retrievable Packer and N/A 5,915' and N/A 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch El Exploratory ❑ Development El Service ❑ 15. Estimated Date for 4/28/2009 16. Well Status after proposed work: Commencing Operations: Oil ❑ Gas 0 Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: ‘k0.( 0 WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: c v... \ x-- h 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Marcus Barbee 263 -7605 Printed Name "( Timothy C. Brandenburg Title Drilling Manager Signature Phone 276 -7600 Date 4/23/2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Zoq Aq 9 Plug Integrity ❑ BOP Test 114 Mechanical Integrity Test ❑ Location Clearance ❑ ` Other: .` 0� A SVC� �S00 k M� k 4—....3 O r Q°F � `v �� L Subsequent Form Required: 11O - "A S Q i"O N. QV' O -\ i i ' �.N ( c. 0 he)- b o`n Nrkt."/ APPROVED BY Approved b � COMMISSIONER THE COMMISSION Date: 4 X./ Form 10-403 evised 06/2006 , ' Submit in Du licate �� ` A 2 Chevron 1 • Ivan River Unit Well # IRU 11 -06 4/21/09 OBJECTIVE: • Isolate water from lower Tyonek zone. • Blow down well with nitrogen. PROCEDURE SUMMARY: 1 MIRU E — Line & set an IBP @ 9,640' ( + -) 2 RD E - Line 3 MIRU Coil tubing. Pressure test CT BOP. 4 RIH w/ CT and blow well dry with nitrogen. 5 RD Coil tubing. 6 Turn well over to production. IRU 11 -06 REVISED BY: CVK 4/21/09 Chevron 0 Ivan River Unit %10.1 Well # IRU 11 -06 4/21/09 OBJECTIVE: • Isolate water from lower onek zone. PROCEDURE SUMMA : 1 RU Coil tubing. Pressure test CT : • P. 2 RIH and set Inflatable bridge plug at ' 640' ( + / -). 3 RIH w/ CT and blow well dry with nitr, .,en. 4 RD Coil tubing. 5 Turn well over to production. UPS; 4 e _i i_ h 9 4 . __ hu f i IRU 11 -06 REVISED BY: CVK 4/21/09 limo Chevron , ; IRU 20 River Unit ' - Permit o Lease & SeriaMt: ADL- 032930 Pit t Drill #: 8 -184 Ivan River Unit . „ ORIGINAL RIG Field: 1 Ivan River Unit API #: 50- 283 - 20130 -00 ElEVA71ONS Location: Well e:caton: Development Gas Well 585 FS & 630 585' FSL & 630' EEL Total Depth: Depthpth 10,06 : 10,060' Sec 1,T13N,R9W,SM PBTD: 9,926' RKB-GL X: ASP4 359,785 Tubing: 3-h ", 9.2#, L -80, IBT -Mod 16.80' Y: ASP4 2,646,275 Tubing: 2 ?V.. ", 4.64, L -80, IBT(SCC) RKB -MSL l Well Status: Shut -In Prod Pkrs: (1) 7" Baker Model "SC-2" Mechanical Set Pkr 46.80' 1 4' .`. Operator. UOCC Ownership: Union Oil Company of California 100% GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM 171' Csg i RKB -MSL: 46.80' Omer. Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Top Job lF" I BHP: 3698 psi @ 10,060' MD Slickline Apr 2008 15,8 ppg 187 sx 1 n ' • I BHT: 134° 10,060' MD Primary Cmt f , ' IV 13.0 ppg 552 sx i r '` ,ag ° . Description Weight Grade Conn ID Length Top Btm TOC Hr. 1,016' Csg`., I Structural 20" 129.0# X-56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV t ; , ' S . Surface 133!8" 68.08 L -80 BTC _12.415" 1,016' 0' 1,016' Surf 91.0 hrs 900' -3,487' '' ' r. Intermediate 9 5/8" 40.0# L -80 BTC 8.681" 6,015' 0' 6,015' 900' 183.5 hrs 12.5 ppg 636 sx d ' & Production 7" 26.0# L-80 BTC -Mod 6.276" 4,195' 5,825' 10,020' 8,118' 0.0 hrs DV Collar 1 3,487' MD [r` i Cmt below DV § , v 4,100'46,120 i Tubing 3 1/2" 9.24 L-80 IBT -Mod• 2.992" 9,494' 0' 9,494' 12.0 ppg 399 sx - I, 23/8" 4.6# L-80 IBT" 1,995" 3,501' 0' 3,501' ' it' 1 ® • - SCC S ecial Clearance Couplings) y I I a Description Depth Length ID OD d Is l 1 i ' 1 Tubing Hanger, 3-1/2" NSCO Unihead 11" 5M, 3" Type H BPV 17' 0.49' 3.000" 11.000" t ( 6,. '51'0 ? 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.881" 10.625" .i j; 1 _ a 3 9-5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" f x' ' 4 9-5/8"x7" Baker Flex -Lock III liner hanger (set 2/4/09) 5,844' 9.69' 8.278" 8.310" fil t� e j. .' 5 Baker Model "SC-2" Retrievable Packer (set 2/10/09) 5,915' 5,45' 4.000" 5.960" p i 6 Baker Model 80-40 Sealbore w/ GBH -22 Seal Assembly 5,920' _ 9.02' _ 4.000" 5.000" 6,015' Csg . . 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" 8 Halliburton Ported Sub w/ Glass Disk 9,418' _ 0.69' 2.992" 4.187" 9 Halliburton WLEG w/ TCP Auto - Release _ - _ 2.992" 4.250" TOC (USIT Log) 10 Halliburton 4 -5/8" TCP Assembly (Perf 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" 6,118' MD 11 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 4,992' TVD 12.0 ppg 432 sx 0 iM , Description (Heat String) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' - - - IS k6 4 ut ic Zone Top Btm Amt Gun Size SPF Phase Status Date I V Sterling/Beluga/Tyonek NI A Tyonek 9,545' 9,698' 153' 4.5/8" 6 60 Open 4/4/2009 ra vt 1 ■ - II- -: _ - __ r r 1O f r $ 4 10,020' Csg " ►� . Eil 10,060' TD MUD 10.1 ppg Current Sketch Post Slickline on 4/6/09 Prepared By: Stan Portrola . ., •. PROPOSED Permk to Dn# #. 208-184 Chevron IRU 11 - Ivan River Unit - Lease & Serial #: ADL -032930 ORIGINAL RIG field: I Ivan River Unit API #: 50-283-20130-00 ELEVATIONS Surface Location: Well Classificaton: Development Gas Well 585' FSL & 630' FEL Total Depth: 10,060' Sec 1,T13N,R9W,SM PBTD: 9,926' RKB-GL X: ASP4 359,785 Tubing: 3-W, 9.2 #, L-80, IBT -Mod 16.80' Y: ASP4 2,646,275 Tubing: 2 -W, 4.6#, L -80, IBT(SCC) RKB -MSL Well Status: Shut -In Prod Pkrs: (1) 7" Baker Model "SC-2" Mechanical Set Pkr 46.80' i- M ) Operator. UOCC Ownership: Union Oil Company of California 100% iA ., d '; GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM 171' Csg RKB -MSL: 46.80' Other Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Top Job , l BHP: 3698 psi i 10,060' MD Slickline Apr 2008 r . 15.8 ppg 187sx M ; , 'Hi BHT: 134° 10,060' MD Primary Cmt „ ' p MMMM ii 13.0 ppg 552 sx ,+ ' , rG Description Weight Grade Conn ID Length Top Btm TOC Ws 1,016' Csg ` IF ' Structural 20" 129.0# X -56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV c Surface 13 3/8" 68.0# L -80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs q r', I ; 4 900 3, 87 ' Intermediate 9 5/8" 40.0# L -80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs � a,:.. I ;. 12.5 ppg 842 sx � : ' "rJ Production 7" 26.0# L -80 BTC-Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar 3,487' MD t 0 Cmt below DV i 4,100' -6,120 i" a _ Tubing 3 1/2" 9.2# L -80 IBT -Mod" 2.992" 9,494' 0' 9,494' 12.0 ppg 397 sx 2 3/8" 4.64 L -80 IBT• 1.995" 3,501' 0' 3,501' "1 i� °j is ; "- SCC S ecial Clearance Cou lin s ? = 1 I Description Depth Length ID OD ' I ` r 1 Tubing Hanger, 3-1/2" NSCO Unihead 11" 5M, 3" Type H BPV 17' 0.49' 3.000" 11.000" t 1 ' • I s % 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487', 2.80' 8.681" 10.625" _ I. I I 3 3 9-5/8" Baker ZAP packer (set 2/4/09) 5,825' 18 53' 6.285" 8.310" ) 4 9- 5/8 "x7" Baker Flex -Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" _p t P":,' 5 Baker Model "SC-2" Retrievable Packer (set 2/10/09) 5,915' 5,45' 4.000" 5.960" . 8 Baker Model 80-40 Sealbore w/ GBH -22 Seal Assembly 5,920' 9.02' 4.000" 5.000" 6,015' Csg ;ii, I .. „ I 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813” 4.500" 8 Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" Z 9 Halliburton WLEG w/ TCP Auto-Release 9,483' - 2.992" 4.250" TOC (USIT Log) 10 Halliburton 4 -5/8" TCP Assembly (Pert 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" 6,118' MD a 11 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 4,992' ND • 12 Proposed: Inflatable Bridge Plug 9,640( + / -; 12.0 ppg 432 sx 10 1 Description (Heat String) ' ) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' - - - rat Zone Top Btm Amt Gun Size l SPF Phase Status Date Sterling /Belu9a/Tyonek il A Tyonek 9,545' 9,576' 31' 4-5/8" 6 60 Open 4/4/2009 A Tyonek 9,582' 9,609' 27' 4-5/8" 6 60 Open 4/4/2009 B Tyonek 9,648' 9,698' 50' 4 -5/8" 6 60 Open 4/4/09 Proposed Isolate rti K I J . e1 4i - _ 0 r- 10,020' Csg .�� 10,060' TD MUD 10.1 ppg Proposed Well Schematic Prepared By: Stan Porhola . ., • 0 L i Chevron i IWO" Chevron IRU 11 -06 Well Head Rig Up Reverse Circulation v lk 44 it I .../ rk- 1, r rg .. aiie: Alai d la - ::7 �'� • I SS -800L Injector Head I ��. r,1C1 J Oa 4 1/16" 10M Stripper 1 a 4 1/16" 10M Flanged Lubricator - I , � „ 4 1/16" 10M Combi BOP i id• — ..0 4,-- Blind Ram /Shear Ram (41 'r 4 Slip Ram /Pipe Ram � . 4 I 4 1/16" 10M Flow Cross . • PA\ f \\"0 SARAH PALIN, GOVERNOR ALASKA OII, AND GAS / 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION r ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy Brandenburg Drilling Manager Unocal PO Box 196247 Anchorage AK 99519 Re: Ivan River Unit, Undefined Gas, IRU 11 -06 Sundry Number: 309 -149 Dear Mr. Brandenburg: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. pz Chair DATED this %ay of April, 2009 Encl. APR 2 3 ZUU9 STATE OF ALASKA ALA KA OIL AND GAS CONSERVATION COMM 011 Cans:, Commission WELL COMPLETION OR RECOMPLETION REPORT AND L't fags 1a. Well Status: Oil ❑ Gas Ei Plugged ❑ Abandoned ❑ Suspended ❑ 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development El Exploratory❑ GINJ❑ WINJ ❑ WDSPL ❑ WAG ❑ Other❑ No. of Completions: 1 Service ❑ Stratigraphic Test❑ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: Union Oil Company of California Aband.: 4/4/2009 - 208 -184 3. Address: 6. Date Spudded: 13. API Number: PO Box 196247, Anchorage, Alaska, 99519 12/22/2008 - 50- 283 - 20130 -00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 585' FSL, 630' FEL, Sec 01, T13N, R9W, SM ` 1/29/2009 Ivan River Unit (IRU) 11 -06 Top of Productive Horizon: 8. KB (ft above MSL): 46.8' ' 15. Field /Pool(s): 1777' FNL, 1006' FEL, Sec 01, T13N, R9W, SM Ground (ft MSL): 30' • Ivan River Unit Total Depth: 9. Plug Back Depth(MD +TVD): Undefined Gas 200' FNL, 366' FWL, Sec 06, T13N, R8W, SM 9,926' MD (8159' TVD) 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 359785 - y- 2646275 - Zone- 4 • 10,060' MD (8,270' TVD) - ADL- 032930 [Ivan River Unit] TPI: x- 359444 y- 2649197 Zone- 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- 360835 - y- 2650757 ' Zone- 4 N/A N/A 18. Directional Survey: Yes 0 No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost (TVD): (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): LWD [12 -1/4" GR -Res, 8 -1/2" GR -Res]; Open Hole [GR -Res, Den, Neu, Son]; Cased Hole [GR- Neu -Son, USIT, Temp] 22. CASING, LINER AND CEMENTING RECORD M. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 129# X -56 0 171 0 171 Driven N/A 0 180 bbl 13.0 ppg / 13 -3/8" 68# L -80 0 1,016' 0 1,016' 16" 0 38 bbl 15.4 ppg 161 bbl 12.0 ppg / 9 -5/8" 40# L -80 0 6,015' 0 4,920' 12 -1/4" 0 229 bbl 12.0 ppg 7" 26# L -80 5,825' 10,020' 4,792' 8,238' 8 -1/2" 172 bbl 12.0ppg 0 1 `k�J: -t 1 L . +•e c- Ce+ � �aw� iC -o S 23. Open to production or injection? Yes is No ❑ If Yes, list each 24. TUBING RECORD interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) 9545' -9576' (7837' -7864' TVD), 5 SPF 3 -1/2" 9,483' 5,915' 9582' -9609' (7869' -7892' TVD), 5 SPF 2 -3/8" (Heater String) 3,501' N/A 9648' -9698' (7925' -7967' TVD), 5 SPF 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED N/A N/A 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 4/5/2009 5 Test Period —♦ 0 0 0 32/64 0 Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 0 0 24 -Hour Rate — 0 0 0 27. CORE DATA Conventional Core(s) Acquired? Yes ❑ No 0 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. . 1 N 4 VE 6ED abfk5 (-[ 'XS 'Oq F Form 10-407 Revised 2/2007 CONTINUED ON REVERSE 4 7,4 7 r. • • 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? 151 Yes ❑ No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Top N/A N/A needed, and submit detailed test information per 20 AAC 25.071. Permafrost - Base N/A N/A 9545' -9576' Tyonek IRGS Upper Lobe, No fluids to surface Sterling Disposal Zone Upper 3,053' 2,869' 9582' -9609' Tyonek IRGS Middle Lobe, No fluids to surface Sterling Disposal Zone - Lower 5,088' 4,283' 9648' -9698' Tyonek IRGS Lower Lobe, No fluids to surface Beluga Coal 5,912' 4,854' Lower Sterling 5,980' 4,897' Sterling 58 -4T 6,125' 4,997' Beluga - Top 6,427' 5,225' Beluga 71 -3ST 6,514' 5,294' Beluga 83 -0ST 8,405' 6,874' Tyonek IRGS Upper Lobe 9,545' 7,837' Tyonek IRGS Middle Lobe 9,582' 7,869' Tyonek IRGS Lower Lobe 9,648' 7,925' Formation at total depth: Tyonek 10,060 8,270' 30. List of Attachments: Operations Summary, Directional Survey, Mud Weight vs. Depth Chart, Wellbore Schematic 31. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Stan Porhola 263 -7640 Printed Name: Timothy C. Brandenburg Title: Drilling Manager Signature: . ` Phone: 276 -7600 Date: 4/23/2009 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 a: 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 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 27: 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 29: 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 2/2007 Chevron • 1 %0 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 Objective Primary Job Type Job Category Date Actual End Date Drill • Complete Drill and Drill to access attic position reserves in the Sterling, Beluga, and 11: Complete Tyonek. Primary Wellbore Affected Wellbore UWI Well Permit Number IRU 16 5028320130-00 2081840 on 12/131200800 :00.12 /14/2008 00:00 Operations Summary R/D for rig move to IRU 11 -06. 12/14/2008 00:00 12/15/2008 00:00 ` t '; Operations Summary Rig move to IRU 11 -06. 12/15/2008 00:00 - 12/1612.008 00:00_ Operations Summary R/U Nabors 129. 12/16/2008 00 :00 - 12/11/2008 00:00 Operations Summary R/U Nabors 129. 12/17/200800:00 . 12118/2008 00:00 ..... r � levy t ,.. Operations Summary R/U Nabors 129. 12/18/2008 00 :00 - 12/19/2008 00:00 'w, i•.. . Operations Summary R/U Nabors 129. Install starting head. Test to 300 psi for 15 min - test OK. N/U diverter stack. Notify AOGCC of diverter function test. 12/19/2008 00:00 - 12/20/2008 00:00 ”4"-' 17' Operations Summary R/U Nabors 129. Install flow line and knife valve on diverter. N/U diverer line. Contact Jim Regg w/ AOGCC. Waived witness for diverter function test. 1212012008 00:00 - 12123/21108 00:00 Operations S ummary R/U Nabors 129. Mix spud mud. 12/2.02000- 00:00 - 12/22/2008 00,00 Operations Summary R/U Nabors 129. Mixing spud mud. Function test diverter. Test run 13 -3/8" casing hanger. Function test top drive - test OK. P/U 5" drillpipe. 12/22/2008 00:00 - 12/23/2008 00:00 "., : Operations Summary P/U 5" HWDP and 6 -1/2" Jars. P/U 16" BHA. RIH and tag fill inside conductor at 115' MD. Break circ and fill conductor. RIH washing down f/ 115' t/174'. MW = 8.7 ppg. P/U and run 8" DCs (3 ea). RIH and drill f/174'1/837'. MW = 9.0+ ppg. � 12/234048.00:00 - 12124/2008 0000 7 , � x . Operations Summary Drill f/837'1/1028'. MW = 9.0 ppg. Circ and cond hole. Mix and pump 25 bbl pill w/ 10 ppb nut plug for fluid caliper. PiII channeled and returned 47 bbl early. POOH back reaming f/1028' 1/289' MD. Mud pumps down. POOH f/289' t/surface w/ no pumps. Rack back BHA. Service rig and change lower mud saver valve on top drive. Lay down bit, stabilizer and XO. Rack back DCs. R/U to run 13 -3/8" casing. Change out rotary bowl w/ casing spider slips. Run casing 1/ 247' MD. Tight spot. UD casing joint. MW = 9.0 ppg. 1i/241200800:00 - 12/25/20(400.00 Operations Summary Run 13 -3/8" casing to 1018'. R/D casing running equipment. Attempt to back out landing joint from hanger - no joy. Laydown hanger and pup joints. R/U circ swedge. Break circ. P/U joint and tag bottom at 1027'. P/U and UD 2 joints w/ 1 pup. * •- X0:60 - 12/26/2008 00:00 ,.• Operations Summary R/U circ swedge. Circ and clean hole. Drain stack and clean cellar. Land casing on emergency slips. R/U false bowl and elevators. P/U stab -in adapter and pup w/ centralizer. RIH on 5" drillpipe. Space out and stab into float collar. Circ and cond hole. Mix spacer and R/U cement lines. Pump 20 bbl un- weighted spacer. Mix and pump 180 bbl 13.0 ppg cement. No cement to surface. Saw spacer at 132 bbl away. Returns diminished thru job. Unsting and P/U 90'. Circ casing clean. POOH w/ 5" drillpipe. N/D diverter system. „.061i068 : 0dio 4 12/27/2008 : 00' 7w t „ ,. Operations Summary Continue N/D diverter system. Make rough cut on 13 -3/8" above emergency slips. Move beaver slide and catwalk. Complete R/D of diverter system. Make final cut on 13 -3/8" above emergency slips. Install multi -bowl wellhead and test to 1800 psi for 10 min - test OK. Cut slot in 20" conductor for top job. Run 1/2" and 3/4" conduit pipe into annulus thru slot. Dropped 6 jts of 1/2" into annulus. Make 2nd cut in 20" conductor on opposite side. Run 3/4" in 10' sections. Give AOGCC (Bob Noble) 24 hours notice to witness BOPE test. 12/27/2008 Oil ', >" 408 00:00 Operations Summary Run 3/4" into annulus to 200'. POOH. Bottom jts of 3/4" bent. Enlarge cut slot to retrieve bent jts of 3/4 ". Run back w/ 3/4 ". Attempt to circ - no joy. POOH. Found bottom 2 jts plugged. Run back to 200'. R/U cement lines. Break circ. Circ 2 bpm @ 1950 psi. Mix and pump 15.4 ppg cement w/ 2% CaCl2. Pumped 38 bbls. Saw cement to surface at 30 bbls away (Calculated annulus volume = 34.7 bbl w/ 100% OH excess). Chevron • • 1 %. Chevron - Alaska 1 010 Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11-06 x a IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 11. 5-i 0 k � � :. y „ ,� „q;G 1 /2128/2008 00:00 ., ,'2/28/2000 00:00 ,.. Operations Summary POOH w/ 3/4" from annulus. Flush 3/4" and clean out cellar. Tag cement 3' below ground level. Top job complete. N/U BOPE. 9/2008 00:00:4040/2008 00:00 Operations Summary Complete N/U of BOPE and function test. Test BOPE to 250/3000 psi. Test annular to 250/2500 psi - test OK. Thaw dart valve and TIW valve - test OK. Test plug leaking. Pull plug and test casing to 2000 psi for 10 min - test OK. Rerun test plug - no leaks. HCR valve on kill line failed. Replace w/ manual valve and test OK. Choke manifold valve #7 failed. Replace w/ new bonnet and test OK. Remaining BOPE - test OK. AOGCC inspector Bob Noble witness onsite. Pull test plug and set wear bushing. 12/30/2008 00:00r-12/3112000 0000 Operations Summary P/U cleanout BHA. RIH. Tag cement at 928'. Cleanout to 956'. POOH to P/U gyro. Place gyro tool in totco ring at bottom of BHA. RIH taking gyro survey each connection. POOH taking gyro survey each connection. Recover gyro. P/U additional drillpipe. POOH standing back drillpipe. L/D cleanout BHA. P/U directional BHA. 12/31/2008 00:00.1/1/2009 00:00 Operations Summary Calibrate and test directional tools. Tag cement. Drill shoe track. Drill new hole f/1028' :/1055'. Circ and cond hole. R/U and perform leak -off test. LOT at 11.8 ppg EMW. Circ and cond hole. Build new mud system. MW = 9.0 ppg. 111/2009 00:00 = 1/2/2009 00:00 Operations Summary Change out spud mud for 6% KCI polymer mud. P/U to casing shoe. Repair top drive gripper dies. RIH to bottom. Directionally drill f/1055' 1/1270'. Service top drive PLC controls. P/U to casing shoe. Repair top drive PLC. MW = 9.0 ppg. 1a/2009 00:00 - . 1/3/2009 00 :00' : t , ar . ; Operations Summary Continue repair on the top drive PLC. Drift 9 -5/8" casing off-site at Pretty Creek pad. 1412009 00:00 - 1/412009 00:00 Operations Summary Complete repair of top drive. RIH t/ 1176'. Ream and wash f/1176' 111270'. Directionally drill f/1270' 111555'. TOOH t/ 13 -3/8" shoe to work multiple issues w/ mud pumps, pits, and shaker screens. MW = 9.0 ppg. 1/412009 00:00 - 1/5/2009 00 :00 a ' Operations Summary ° Change shaker screens, clean suction pit and jet lines. Change out lower kelly valve. Repair hydraulic leak on top drive brake. Move mud across new screens staging mud pumps up to 700 gpm. RIH f/ shoe t/ 1555'. Drill f/1555':/1741'. Change out shaker screens, clean possum belly, sand trap, and suction lines. Drill f/1741' 1/2121'. Cease drilling. G &I down and unable to process cuttings. Decision made to P/U additional drillpipe off the catwalk while waiting for G &I. MW = 9.0 ppg. 1/5/2009 00:00.1 0S 00 :00 � Operations Summary Shutdown, assist G &I w/ injection. Repairing water well on pad. Service mud pumps. P/U additional 5" drillpipe. Ream and wash f/2041' 1/2121'. Drill f/2121' 1/2663', control drilling section to allow G &I to keep up. MW = 9.0 ppg. 1/812009 00 :00 - . 1#/2009. 00x0 Operations Summary Drill f/2663' 1/2730', control drilling section to allow G &I to keep up. Excess solids building in mud pits. P/U and circ working pipe. Change out shaker screens. Clean out suction valves on #2 mud pump. Assist G &I w/ cuttings handling. P/U to 990' inside shoe and stab up TIW while assisting G &I. Clean cellar and BOP stack. Change additional shaker screens. Remove TIW and P/U to HWDP. TIH P/U additional 5" drillpipe. Break circ at 1740'. Trip back to shoe. Clean around rig while assisting G &I w/ cuttings handling. MW = 9.1 ppg. 4/7/2009'ooto0 - 118/2oo9 00:00 Operations Summary Assist w/ G &I on cuttings handling. R/U new tank inside tent. Service top drive. Thawing lines for injection. TIH. No hole problems. 1/8/2009,00:00 -1/9/2009 o000 Operations Summary Drill f/2730' t/3120'. P/U 1/2988'. Repair top drive throttle. Run back to bottom. Drill f/3120' 113368'. Service top drive circuit breaker. Drill f/3368':/3777'. MW = 9.1 ppg. 1/9/2009 00 :00'- 1/10/2009 00:00 Operations Summary Drill f/3777' t/5267'. MW = 9.4 ppg. v1oi200() O 1'/1112009 00 :00 Operations Summary Drill (/5267' 1/5778'. High torque. Decide to pull for bit change. Mix dry job. Circ btms up. Trip out 5 stands. Good hole conditions. Pump dry job. POOH. Tight f/4195' 1/4170', work thru w/ 20k overpull. POOH to BHA. L/D BHA and bit. Bit 5/16" out of gauge. Top stabilizer 1/16" out of gauge. Mud motor stabilizer lower 1/3 out of gauge. Download MWD /LWD data. Notify AOGCC of upcoming bi- weekly BOPE test. Waived witness by Lou Grimaldi. MW = 9.5 ppg. :61/2009 00 :00 - 111.2/2009 00:00 ' 1 Operations Summary Pull wear bushing. Set test plug and perform BOPE test to 250/3000 psi - test OK. Run wear bushing. P/U BHA w/ new bit. TIH 1/2798'. Break circ and test MWD - test OK. TIH 1/5622' w/ tight hole (/5065' 1/5083'. Kelly up and safety wash and ream (/5622' 1/5742'. MW = 9.2+ ppg. Chevron • 1 %0 1 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (fl) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 00:00 1/13/2009 00 :00 ''`, _ ra ' Operations Summary Safety wash and ream f/5742' t/5778'. Drill f/5778' t/5835'. Lose oil pressure on top drive. POOH to shoe to service top drive. Lube oil pump bad. Fly in replacement pump from North Slope. Change out pump and gear box oil. TIH. Safety wash and ream f/5742' t15835'. Drill f/5835' t15959'. MW = 9.4 ppg. . 1/1312tji09'00i0tOti/1�4/2009 00:00 Operations Summary Drill f/5959' t/6023'. Circ btms up w/ coal returns from thick coal near TD. Gas = 410 API units. Flow check - no flow. Wiper trip f/6023' t/5459'. No tight spots. Wiper trip f/5459' t/6023'. No fill on btm. Mix and pump 20 bbl hi -vis sweep. Small increase in cuttings. Returned 84 bbls late. Estimate OH excess = 30 %. Flow check - no flow. Pump dry job. POOH. UD BHA and download MWD /LWD data. Pull wear bushing. Notified AOGCC on 1/10/09 (Lou Grimaldi) of change to 9 -5/8" casing rams. P/U test joint. Install and test 9 -5/8" rams in upper ram cavity. Troubleshoot leaks. Clean out ram cavities and re- install. Test rams to 250/3000 psi for 5 min - test OK. UD test joint. R/U to run casing. MW = 9.5 ppg. 1 /t4 OO900:00. 1/15/200900:00 1 ,.. Operations Summary Clean and clear rig floor. Monitor losses - 9 bbl /hr. R/U to run casing. P/U shoe track, test floats - test OK. RIH t/364'. Monitor losses - 7 bbl /hr. Continue RIH w/ 9 -5/8" casing t/1005'. High winds - safety standown. Monitor losses - 5 bbl /hr. Winds dying down, resume running casing. RIH t/ 4330'. MW = 9.4 PPg• 1115I ® 00 000 4/116/2009 00 :00 � y: Operations Summary RIH w/ casing t/5922'. Monitor losses - 2 bbl /hr. Set down and tag bridge at 5922' w/ 15k. R/U and break circ. Wash down to casing set depth, pumping at 5 bpm. M/U landing joint and casing hanger. Land hanger and break circ. Circ at 5 bpm thru hanger flutes, no pressure /pack off observed. Circ 2 x btms up at 5 bpm. No excess cuttings seen at shaker. Stop circ and R/U cement head and cement lines. Circ and cond hole. Pump 4.5 bbls water. Test lines to 4100 psi for 5 min - test OK. Drop by -pass plug and chase w/ 0.5 bbl water. Shutdown and load shutoff plug. Mix and pump 20 bbl 11.0 ppg spacer, 156 bbl 12.0 ppg cement. Shutdown and drop shutoff plug and chase w/ 5 bbl cement. Displace w/ 444 bbl 9.4+ ppg mud. Slow pumps to 3 bpm at 475 psi. Bump plug at 1475 psi. Bleed off and check floats - test OK. Pressure up to 2710 psi and shift open DV collar. Total losses during job = 7 bbl. Circ btms up thru DV collar at 6 bpm. Note increased pH in returns. Spacer and contaminated cement returns seen at surface. Continue circ thru DV collar at 4 bpm while R/U to pump 2nd stage cement job. Monitor losses - 3 bbl /hr, reduced to 0 bbl /hr. 1/16/2009 00:00 - 1/17/200$ 00:00;44,7 ' 4 = a _ 444 Operations Summary R/U for 2nd stage cement job. Load shut -off plug in cement head. Hook up and test cement lines 1/ 2500 psi - test OK. Mix and pump 20 bbl 11.0 ppg spacer, 224 bbl 12.5 ppg cement. Drop plug. Pump 5 bbl 12.5 ppg cement and displace to 262 bbl 9.5 ppg mud. Land plug and close DV collar w/ 1200 psi over final circ pressure of 600 psi (1800 psi). No cement returns but did see increase in pH in mud returns as seen in 1st stage after circ thru DV collar. R/D cement lines. UD landing joint. Flush and clean out BOP stack. P/U packoff and running tool. Install packoff and test to 250/5000 psi for 30 min - test OK. UD packofff running tool. Set test plug. Change out upper rams from 9 -5/8" rams to 2 -7/8" x 5 -1/2" VBRs. R/U and test VBRs to 250/3000 psi for 5 min - test OK. R/D test equipment. Run wear bushing. Change out bails and UD 8" drill collars. P/U 6 -1/2" drill collars and 5" HWDP. MW = 9.5 ppg. 1/17/2009 00:00 - 1/1812009 00:00 1 " { Operations Summary P/U 8.5" cleanout BHA. TIH P/U 5" drillpipe 1/3385'. Break circ and test csg t/1500 psi for 10 min - test OK. Clean out cement t/3454', drill cement and DV collar f/3454' t/3489'. Drill cement strings f/3489' t/3509'. CBU. Test csg t/1500 psi for 10 min - test OK. Wash and ream cement f/3509' t/4794'. 1/18120000:00 =11 80009 :00 ,.�. 74 Operations Summary Wash and ream cement f/4794' t/5560'. Circ and cond mud. Test csg 1/3000 psi for 10 min - test OK. Tag up at 5575'. Drill cement, shut -off plug, shut -off baffle, and clean -out to float collar at 5930'. Circ and clean hole. Test csg 1/3000 psi for 10 min - test OK. Drill float collar, float shoe and rathole cement 1/6023'. Drill new formation f/6023' 1/6045'. Circ and cond hole. Perform FIT to 13.6 ppg EMW (9.2+ ppg mud, 4930' TVD, 1115 psi) test OK. POOH w/ cleanout BHA. Pull wear bushing. Test BOPE to 250/3000 psi w/ AOGCC witness Lou Grimaldi. 1 1 I20O00:00' :a " 1/20/2009 00:00 Operations Summary Continue BOPE test. Gas alarm test OK. Reset and gas alarm down. Troubleshoot gas alarm. R/D test equipment. AOGCC inspector Lou Grimaldi onsite, gave notice that we could proceed ahead but could not drill until gas alarms working properly and audible alarms for H2S and CH4 had separate tones. P/U directional BHA. TIH w/ directional BHA, test MWD - test OK. RIH 1/5600'. MW = 9.3 ppg. '1/ 2012009 00 :00. 1/21/2009 00:00 .,. Operations Summary Nabors gas alarms replaced w/ Total Safety. Test alarms - test OK. RIH f/5600' 1/5947'. Break circ. Ream 1/6045'. Drill f/6045' 1/6548'. MW = 9.5 ppg. CBU. Drill f/6548' 1/6962'. MW = 9.8 ppg. 1/21/2009 00:00 - 1/2240! 00x! !... " . Operations Summary Drill f/6962' 1/7024'. Standpipe pressure increase, diagnose plugged nozzles. Pumped 2ea 30 nut plug sweeps and lea 10 bbl drill -n -slide sweep. Lost 150 psi following sweeps. Service rig and top drive. Drill f/7024' t/7040'. Lost hydraulic power to top drive. Circ and reciprocate pipe while troubleshooting top drive failure. Break out connection and pull to shoe. Replace wires on PLC card and test run top drive. Electrical failure on PLC. Continue troubleshoot top drive. Change pump liners in mud pumps to 5.5" liners. MW = 9.9 ppg. 1/22/200 00 :00 t12312009 00 :00 4 14 3 , ak Operations Summary Continue to troubleshoot top drive. POOH w/o hydraulics on top drive. Lay down 2ea NMDC. Inspect 8 -1/2" bit. Found 2 nozzles plugged, 1 blade packed off w/ solids. No wear and in gauge. Download MWD tools. Continue repairs on top drive. Monitor well - no losses. MW = 9.9 ppg. Chevron • Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 = fi��r20ps oo - 1r24/2009 00:00 Operations Summary Continue repairs on top drive. Complete repairs. P/U BHA. 11 200900 :00 - 1125/2009 00:00 35 _ 4.. . Operations Summary TIH. Wash out of shoe at 6015'. Ream and work tight spots at 6050'- 6061', 6140'- 6160', 6420'- 6460', 6530'- 6550'. Continue ream to 7040' w/o problems. Drill f/7040' t/7504'. MW = 9.9 ppg. 1125/2009,00:00 - 1/26/2009 00 :00 .'' Operations Summary Drill f/7504' t17978'. Drill f/7978' t/8012'. MW = 10.5 ppg. 1 4W2009 , 00 :00 -1/27/2009 00:00, Operations Summary Drill f/8012' t/8359'. MW = 10.1+ ppg. Drill f/8359' t/8736'. MW = 10.0 ppg. .4/2712009 00:00 .1/2812009 00:00 . �'' 3 ,.. Operations Summary Drill f/8736' t/9115'. MW = 10.1 ppg. Drill f/9115' t/9461'. MW = 10.0 ppg. U28j20 .09.00:00, - 1/29/2009 00:00 _ Operations Summary Drill f/9461' t/9750'. MW = 10.0+ ppg. Drill (/9750' t/10,038'. MW = 10.0 ppg. 1/29/2009 00 :00: ` 1/30/2009 00:00 � Operations Summary Drill f/10,038' t/10,060' TD. MW = 10.2 ppg. CBU x 3. No gas. Check for swabbing - OK. Attempt POOH - no joy. Back ream (/9880' t/6020' working pipe and vaned flow rate to prevent packing off. CBU below casing shoe (6015'). Work pipe f /6060' t16020'. RIH (/6060' t17117'. Took weight at 7015'. Pick up and went thru. POOH f/7117' t/5993'. Tight hole at 6145' and 6165'. Work back down and pulled slicked. MW = 10.0 ppg. Contacted AOGCC inspector Bob Noble by phone for upcoming BOPE test. Plan to call AOGCC engineer Jim Regg next a.m. to discuss testing before required bi- weekly due date of 2/2/09. 1/30/200900:00 -1/31/2009 00 :00 Operations Summary POOH. L/D BHA. R/U to run wireline logs. RIH and tag up at 6038' WLM. Attempt to work down - no joy. POOH and remove bow spring centralizers. RIH and tag up at 6038' WLM. No overpull. Appears to be bridge. POOH. R/D wireline. R/U to test BOPE. Witness waived by AOGCC, Jim Regg. Change 5" rams to 7" casing rams - no joy. 7" casing rams wrong ram bodies. Change back to 5" rams. Order new 7" casing rams. MW = 10.0 ppg. 1/31/2009 00;00 - `2/1/2009 00:00 Operations Summary Continue w/ BOPE test. Test BOPE 250/3000 psi - test OK. P/U cleanout BHA. RIH and tag up at 6125'. Set down w/ 25k, unable to work thru. Wash and ream 3' and worked thru. Pull thru w/o overpull. RIH t/10,028'. Safety wash to 10,060'. CBU. MW = 10.0 ppg. 2/1/2009 00:00 '212/2009 00:00 Operations Summary Circ clean. Pump carbide, inconclusive. Pump hi -visc walnut sweep. Returned 76 bbls late. Calculated 83% OH excess. POOH. UD cleanout BHA. R/U wireline. RIH w/ Quad combo logs. RIH and tag up at 6038' WLM. Attempt to work down - no joy. POOH and remove dipole sonic and resistivity. RIH and tag up at 6038' WLM. No overpull. Run caliper log into casing. Caliper showing large washout ( >20 "). POOH. R/D wireline. Pull wear bushing. Run test plug. Change 5" pipe rams to 7" casing rams. Test rams to 250/3000 psi for 5 min - test OK. MW = 10.0 ppg. 212/2009 00:00 - 2/3/200000:00 Operations Summary L/D test joint and test plug. R/U to run 7" liner. M/U liner hanger assembly and UD. P/U reamer shoe. RIH w/ 7" 26# liner w/ centralizers. P/U liner hanger and RIH. CBU (/4200'. R/U to RIH on 5" HWDP and 5" drillpipe. MW = 10.0 ppg. ~ 2/3/2009 00:00 - 2/4/20093001W � , ,... . Operations Summary RIH on 5" drillpipe 1/5885'. UD jars. M/U cement head and L /D. Steam ice plugs in drillpipe. RIH on 5" drillpipe 1/8830'. Steam ice plugs in drillpipe. RIH on 5" drillpipe t/9991'. Wash and ream liner (/9991 1/10,002'. Circ 12.5 ppg sweep followed by red dye fluid caliper at 180 gpm, 600 psi. Unable to gauge hole (did not see at surface). Wash and ream liner f/10,002' t/10,012'. MW = 10.1 ppg. 0 00:00- 2/5/2009 00:00:9 . �, , Operations Summary Wash and ream liner (/10,012':/10,024'. P/U to 10,020'. R/U cement head. Lost pipe movement (possible differential sticking). Still able to circ. Drop liner setting ball. Land on seat and pressure up to 2800 psi to set liner hanger. Pump 31 bbl 11.0 ppg spacer, 172 bbl 12.0 ppg cement (75% OH excess). Bump plug and pressure up to 2500 psi for 10 min. P/U liner hanger tool and set ZXP packer. Reverse circ above liner top. Saw increase in pH and spacer at surface, no cement. Lost 12 bbl during job. RIH w/ liner tool to btm of liner seal bore. Reverse circ. R/D cement lines. Pump dry job. POOH. L/D 66 jts 5" drillpipe. MW = 10.1 ppg. 2/5/2009 00:00 2/6/2009 00 :00 33 9 Operations Summary POOH. L/D 5" HWDP. UD drill collars. Pull wear bushing. Run test plug. Change 7" casing rams to 3 -1/2" tubing rams. Test rams to 250/3000 psi for 5 min - test OK. Pull test plug. Run wear bushing. R/U wireline. RIH w/ Son /Neu /GR/USIT logging tools. Stopped at 5910' WLM. POOH. Found mud packed off in USIT spinner. Drop out USIT log. RIH w/ Son /Neu /GR. Stopped at 5910' WLM. POOH. R/D wireline. Move 3 -1/2" tubing to pipe racks. MW = 10.1 PPg• Chevron • 11 %. Chevron Alaska 1 Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 Dal •' >,. 2/6/2009 00:09- 2 009 00:00 '40140 .. Operations Summary Continue moving 3 -1/2" tubing to pipe racks. R/U tubing running tools. P/U muleshoe scraper, 3 -1/2" tubing. RIH. Crossover to 5" drillpipe. RIH t/7750'. Break circ and CBU. RIH t/9371'. P/U 18 joints 5" drillpipe. Tag landing collar at 9926'. R/U to reverse circ. MW = 10.1 ppg. 2/7/2009 00:00 - 2/8/2009 00:00 '' . Operations Summary Reverse out mud to fresh water at 250 gpm. Service rig. POOH t/4147'. UD 2 jts of 3 -1/2" tubing. P/U stop sub and XO to tubing. RIH f/4086' t19900'. Tag liner top w/ stop sub at 5825'. Reverse out dirt magnet and displace w/ fresh water at 170 gpm. R/U to test casing and liner. Test 9 -5/8" and 7" liner t/ 2500 psi for 30 min - test OK. Water = 8.4 ppg. 2/8/2009 00:00 - 2/9/2009 00:00 Operations Summary Mix 380 bbl 6% KCI in pits. Reverse out fresh water to 6% KCI at 210 gpm. POOH L/D upper scraper and XO's. Rack back drillpipe. POOH L/D btm scraper and mule shoe. Rack back 3 -1/2" tubing. R/U wireline. RIH w/ USIT (cement evaluation) to 9900' WLM. Log 7" liner cement f/9900' t/5900' WLM. Cement coverage poor to good. TOC at 6143' WLM. POOH w/ USIT. 6% KCI = 8.6 ppg. 2/9 /2009 00:00 2/1012009 00:00 Operations Summary RIH w/ Neu /Son /GR logging tools. Log 7" liner to liner top. Service rig. Staging and strap completion equipment. RIH w/ TCP guns, 3 -1/2" tubing (IBT -Mod SCC). M/U SC -2 packer w/ setting tool. RIH on 3 jts of 3 -1/2" tubing (IBT -Mod SCC), 8 -1/4" stop sub crossed over to 5" drillpipe. Tag top of liner w/ stop sub at 5825'. P/U and space out. TCP guns placed f/9698' t/9545'. Packer at 5915'. Drop setting ball and perform setting procedure w/ test pump. KCI = 8.6 ppg. 2110/200900:00 - 2/11/2009 00:00 Operations Summary Continue setting procedure for SC -2 packer. Test annulus to 500 psi for 5 min to confirm packer set - test OK. Pull and push 20k on packer to confirm set. Test annulus to 2500 psi for 30 min - test OK. Setting tool released. POOH. UD 5" drillpipe and packer setting tool. Stand back 1 stand 3 -1/2" tubing. Pull wear bushing. Install spacer sleeve bushing across 7" casing spool. Test seals to 5000 psi for 15 min - test OK. UD bushing setting tool. P/U seal assembly. RIH w/ seal assembly on 3 -1/2" tubing (IBT -Mod SCC) 9.2# L -80. Drift tubing to 2.867" ID. KCI = 8.6 ppg. 2/111200900 :00.2/12/2009 00:00 Operations Summary RIH w/ 3 -1/2" tubing (IBT -Mod SCC). Tag top of packer at 5915' RKB. Enter seal assembly and land out locator on top of packer. End of seal assembly at 5928' RKB. Close annular, pressure test to 500 psi, no returns up tubing, confirm seals in sealbore. Bleed off pressure. P/U out of sealbore t15889'. Displace 6% KCI in annulus to fresh water. Space out and M/U parent hanger. Land hanger and run lock down screws. Test hanger seals to 5000 psi for 15 min - test OK. Pressure test down tubing to 2500 psi for 30 min - test OK. R/D test equipment. UD landing joint. R/U to run 2 -3/8" heater string. RIH w/ 2 -3/8" heater string w/ mule shoe cut on end of bottom joint, and landed same at 3,501' RKB. Drift heater string to 1.875 ". M/U mandrel and land in parent hanger and 1/4 turn to right to j -lock. Pull test to verify locked. UD landing joint. Install TWC in both strings. Fill BOPE w/ water. Close blind rams. Open annulus. Test 2 -3/8" mandrel seals to 2500 psi for 15 min - test OK. N/D BOPE. Fresh water = 8.4 ppg. 6% KCI = 8.6 ppg. 2i1212009 00:00- 2/13/2009 00:00 Operations Summary N/D BOPE. N/U tree. Test adapter seals 250/5000 psi for 30 min - test OK. Test tree valves on both strings to 250/5000 psi for 30 min - test OK. Freeze protect long string. Displace water w/ diesel. Displace heater string and annulus top to diesel w/ 7 bbl diesel. Prep for rig move to Stump Lake sidetrack (SLU 41- 33RD). 2113/2009 00:00 - 2/14/2009 00 :00 •' G �` = � 4,.> , Operations Summary ' 1 ` t ( 6 R/D for rig move to SLU 41 -33RD. ** *Final Rig Report for IRU 11- 06 * * *. � 2/18/2009 00:00 - 2/19/2009 00:00 Operations Summary R/U Pollard Wireline to shift "Durasieeve" Sliding sleeve at 5,970' to open position. R/D wireline. 3/261200900:00, - 3/271200900 :00 Operations Summary Mobe BJ Coil Tubing crews to Westside. 3/27/2009 00:00 - 3/28/200900:00 Operations Summary Mobe BJ Coil Tubing out to Ivan River pad. R/U coil. 3/28/2009 00:00 - 3/29/2000 00.00 "0 Operations Summary Finish R/U Coil - Second Herc in with N2. Notice given to AOGCC of upcoming CT BOP test. 200900 :00' - 3/30/2009 00:00 Operations Summary Surface system test. BOP Test 250/4000 psi, witness waived by AOGCC Jeff Jones. 3/30/2009 00:00.3/3112009 00:097 n, . ..: Operations Summary N2 short circulated through Diversion tool. Shut down N2 pumping. 3/31/2009 00:00- 4/1 /200900:00 Operations Summary Wait on direction from town. Chevron • 1 %0 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 41112009 00:00 4/2/2009 00:00 Operations Summary Perform PJSM w/ BJ Coil crews. Redress SSD isolation tool, 2.82" OD. M/U SSD isolation tool. Stab on injector head. Test to 250/4000 psi - test OK. Break circ thru coil. Open well, 1300 psi on well. RIH bleeding nitrogen. Pump water down coil, no returns to surface. Leave 200 psi on coil x tubing annulus. RIH w/ SSD isolation tool into sliding sleeve at 5976' CTM. Set down w/ 2000 lb compression on coil, coil at 5977' CTM. P/U and set down, no indication of seals entering top seal bore. R/U to pump diesel down coil x tubing annulus to surface tank. Fluid to surface at 5 bbls away. Pump at 1 bpm, partial diesel returns at 33 - 34 bbls, full diesel returns at 39 bbl. Discuss plan forward w/ town. Attempt to re -seat SSD isolation tool, making 3 attempts - no joy. POOH. 4/2/200900:00 - 4/21200000::00 Operations Summary POOH. L/D SSD isolation tool. Stand back injector head. Secure well. SDFN. Rest crews. MIRU slickline. M/U lubricator and test to 1500 psi - test OK. RIH w/ 2.8" GR, set down at 5973' RKB. P/U and run tools thru spot 3 times w/o any issue. RIH to 9000' RKB. POOH. M/U 42B0 shifting tool. RIH to 5972' RKB. P/U and run tools thru spot 3 times w/o any issue. POOH. R/D slickline. Secure well. R/U BJ Coil. M/U 2.1" reverse jetting nozzle. Stab up injector head. Shell test riser and BOP to 250/4000 psi - test OK. RIH t/ 5970' CTM. Displace coil w/ water. Trap 310 psi on coil x tubing annulus. RIH to 7500' CTM. Pump 16 bbl diesel down coil x tubing annulus, taking retums up coil. Pump nitrogen down coil x tubing annulus at 1000 CFM. Taking returns up coil at 1 bpm. 4/312009 00:00. - 4/4/2009 00 :00 Operations Summary At 25 bbl retumed, RIH to 8500' CTM pumping nitrogen at 1000 CFM. At 57 bbls returned, RIH to 9200' CTM pumping nitrogen at 1000 CFM. Continue to pump until nitrogen to surface. POOH w/ coil, continue to pump nitrogen. Total fluid recovered = 188 blJJ. Continue to POOH. Total nitrogen pumped =—"' 30,000 CF. i on tubin POOH. L/D reverse nozzle. R/D coil. Secure well. SDFN. MIRU slickline. M/U and test lubricator to 1500 psi - test OK. RIH w/ 42B0 shifting tool to 59'3' RKB. Shift sleeve up to close. Pass thru sleeve to confirm closed. POOH. Check shifting tool - indicates sleeve closed. R/D slickline. R/U BJ coil crews. R/D coil tubing BOP and equipment. Hook up lines to heater string and casing annulus. Pump glycol down heater string, displacing water from casing annulus. 441412009 00:00 - 4/5/2009 00:00 Operations Summary M/U 12' wireline lubricator w/ 10' x 1.25" drop bar. Circ glycol in annulus to warm fluids. Vent nitrogen on well from 1500 si to 404 psi. R/U Halliburton listening device. Drop bar. Guns fired 82 se . • - • - • • . • • ■ - • ' • • - ■ - • • • •' = .B. R/D lubricator. Pressure increased from 404 to 427 psi. Turn well over to production. Unable to flow well, oas compressor down. Troubleshoot gas compressor. 4/5/2009 00:00 - 46/2009 00:00 Operations Summary Continue to troubleshoot gas compressor. Flow well thru gas compressor, nitrogen causing compressor to shutdown. MIRU T -Pack to Ivan River. Flow well to tank thru choke to unload water. Start at 119 psi. Well went to 0 psi. Used compressor to bring well up to 510 psi. Flow thru T -Pack. Unable to flow _well. Pressure bled to 0 psi. Shut -in well and monitor. 44/6/2009 00:00 - 4/7/2009 00:00 k�> Operations Summary Pressure increase of 1 psi over 5 hours. Wait -on- weather for slickline crews. MIRU slickline. M/U lubricator and test to 1000 psi - test OK. RIH w/ 2.75" GR. Set down at 9716' RKB. Tagged top of auto - released TCP guns. POOH. Worked thru WLEG /EOT at 9483' RKB. POOH. Apparent fluid level of 4614' WLM. POOH. ±/2009 00:00 418/200900:00 Operations Summary RIH w/ press -temp survey to 9700' RKB. Fluid level at 4730' RKR RHP = 1690 psi at 13n deg. POOH. Download tools. L/D lubricator and secure well. R/D slickline. MIRU E -line. M/U lubricator and test to 3000 psi - test OK. RIH w/ GR/CCL. Correlate w/ USIT log dated 2 -9 -09. RIH to 9720' RKB. BHP = 1700 psi at 131 deg. Correlate pert depths. POOH. R/D E -line. SDFN. 4/8/20 00 00' 4/9/2009 00:00 Operations Summary R/U slickline. M/U lubricator and test to 500 psi - test OK. RIH w/ 1 -1/2" Kuster sample bailer to 5050', 6900', 8600', 9700' RKB. Collect samples. POOH. 4/912009 00:00,-4/10/2009 00 :00 #t { Operations Summary R/D lubricator. and secure well. R/D slickline. SDFN. 4/10/2009 00:00 - 4/11/2009 00:00 = r :K Operations Summary SIMOPS w/ production. R/U to circulate glycol down heater string. Run hardline from test pack, choke skid, and flow back tank. SDFN. 4/11112009 00:00.4/12/2009 00 :00 " g 44 4 ry Operations Summary SIMOPS w/ production. Tubing pressure on 3 -1/2" = 0 psi. Open bleeder valve on tree cap, well venting nitrogen. Vent for 1 hour - well static, no gas detected w/ multi- meter. Secure well. SDFN. 0 0 Chevron Iva 11 -0 6nit Lease&Senal #: ADL- 032930 ORIGINAL RIG Field: I Ivan River Unit API #: 50- 283 - 20130 -00 ELEVATIONS Surface Location: Well Classifcaton: Development Gas Well 585' FSL & 630' FEL Total Depth: 10,060' Sec 1,T13N,R9W,SM PBTD: 9,926' RKB -GL T X. ASP4 359,785 Tubing: 3 -% ", 9.2 #, L -80, IBT -Mod 16.80' y Y: ASP4 2,646,275 Tubing: 2 - % ", 4.6#, L -80, IBT(SCC) RKB -MSL - - Well Status: Shut -In Prod Pkrs: (1) 7" Baker Model "SC -2" Mechanical Set Pkr 46.80' �.- Operator UOCC Ownership: Union Oil Company of California 100% I GL -MSL: 30.00' Spud Date: 12/22/08 2:00 PM 171' Csg RKB -MSL: 46.80' Other. Spud Dec 2008; Rig Release Feb 2009; Coil Tubing Mar 2008; Top Job BHP' 3698 psi (et7 10,060' MD Slickline Apr 2008 15.8 ppg 187 sx BHT. 134° @ 10,060' MD Pnmary Cmt CASING & TUBING Rotate 13.0 ppg 552 sx J ~ Descry:,tion Weight Grade Conn ID Length Top Btm TOC Hrs 1,016' Csg Structural 20" 129.0# X -56 Weld 19.124" 171' 0' 171' Driven 16.5 hrs Cmt above DV Surface 13 3/8" 68.0# L -80 BTC 12.415" 1,016' 0' 1,016' Surf 91.0 hrs - 900'- 3,487' Intermediate 9 5/8" 40.08 L -80 BTC 8.681" 6,015' 0' 6,015' 900' 163.5 hrs 12.5 ppg 636 sx Production 7" 26.08 L -80 BTC -Mod 6.276" 4,195' 5,825' 10,020' 6,118' 0.0 hrs DV Collar I ' I gi 3,487' MD Cmt below DV 4,100' - 6,120' Tubing 3 1/2" 9.2# L -80 IBT -Mod` 2.992" 9,494' 0' 9,494' 12.0 ppg 399 sx 2 3/8" 4.6# L -80 IBT* 1.995" 3,501' 0' 3,501' © ` - SCC (Special Clearance Couplings) ii Jewelry & Fish _7 Description Depth Length ID 00 T� I I I ` 71 © 1 Tubing Hanger, 3 -1/2" NSCO Unihead 11" 5M, 3" Type H BPV 17' 0.49' 3.000" 11.000" =}af- - -;-- 2 Halliburton Type 'H' ES DV Collar (Closed 1/16/09) 3,487' 2.80' 8.681" 10.625" LI 3 9 -5/8" Baker ZXP packer (set 2/4/09) 5,825' 18.53' 6.285" 8.310" I 4 9- 5/8 "x7" Baker Flex -Lock III liner hanger (set 2/4/09) 5,844' 9.69' 6.276" 8.310" u O 5 Baker Model "SC -2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.000" 5.960" 6 Baker Model 80 -40 Sealbore w/ GBH -22 Seal Assembly 5,920' 9.02' 4.000" 5.000" 6,015' Csg L 7 Halliburton DuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970' 4.54' 2.813" 4.500" 8 Halliburton Ported Sub w/ Glass Disk 9,418' 0.69' 2.992" 4.187" _ �_ 9 Halliburton WLEG w/ TCP Auto - Release 9,483' - 2.992" 4.250" TOC (USIT Log) 10 Halliburton 4 -5/8" TCP Assembly (Pert 4/4/09, Tagged 4/6/09) 9,716' 204.00' - 4.625" 6,118' MD 11 PBTD - Top of 7" Float equipment (Tagged 2/6/09) 9,926' - - - 4,992' TVD 12.0 ppg 432 sx Description (Heat String) a Mule shoe cut on joint, 2 -3/8" Tubing 3,501' - - - Perforations Zone I Top I Btm I Amt I Gun Size I SPF I Phase (Status I Date Sterling /Beluga / Tyonek A Tyonek 9,545' 9,698' 153' 4 -5/8" 6 60 Open 4/4/2009 El O L , .,.__ T .. . j 10,020' Csg .4 ------ `; 10,060' TD MUD 10.1 ppg Current Sketch Post Slickline on 4/6/09 Prepared By Stan Porhola Chevron %. %0 IRU 11 -06 Survey Report Scblumberger Report Date: 3- Feb -09 Survey I DLS Computation Method: Minimum Curvature / Lubinski Client: Chevron Vertical Section Azimuth: 11.950° Field: Ivan River Unit Vertical Section origin: N 0.000 ft, E 0.000 ft Structure 1 Slot: Ivan River Unit / 11 -06 TVD Reference Datum: Rotary Table Well: IRU 11 -06 TVD Reference Elevation: 46.40 ft relative to MSL Borehole: IRU 11 -06 Sea Bed 1 Ground Level Elevation: 30.00 ft relative to MSL UWIIAPI#: 502832013000 Magnetic Declination: 19.052 Survey Name I Date: IRU 11 -06 / January 29, 2009 Total Field Strength: 55741.171 nT Tort 'AHD I DDI I ERD ratio: 114.316 / 5133.93 ft / 5.854 / 0.621 Magnetic Dip: 74.052° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: January 05, 2009 Location LaULong: N 61.24065367, W 150.79595737 Magnetic Declination Model: BGGM 2008 • Location Grid NIE YIx: N 2646275.020 ftUS, E 359784.660 ftUS North Reference: True North Grid Convergence Angle: - 0.69778510 Total Corr Mag North -> True North: +19.052 Grid Scale Factor: 0.99992237 Local Coordinates Referenced To: Well Head Comments Measured Inclination Azimuth Sub -Sea TVD TVD Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure (ft ) (deg) (deg) (ft ) (ft ) (ft ) (ft ) (ft ) (ft ) (ft ) (deg /100ft ) (ftUS) (ftUS) RTE 0.00 0.00 0.00 -46.40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2646275.02 359784.66 N 61.24065367 W 150.79595737 NSG SS 95.00 0.13 15.35 48.60 95.00 0.11 0.11 0.11 0.10 0.03 0.14 2646275.12 359784.69 N 61.24065396 W 150.79595721 190.00 0.16 90.77 143.60 190.00 0.24 0.32 0.28 0.21 0.19 0.19 2646275.22 359784.85 N 61.24065424 W 150.79595629 285.00 0.28 134.76 238.60 285.00 0.14 0.66 0.49 0.04 0.49 0.21 2646275.05 359785.15 N 61.24065378 W 150.79595460 380.00 0.12 141.65 333.60 380.00 -0.05 1.00 0.74 -0.20 0.71 0.17 2646274.81 359785.37 N 61.24065312 W 150.79595332 475.00 0.26 185.65 428.60 475.00 -0.33 1.30 0.90 -0.49 0.75 0.20 2646274.52 359785.41 N 61.24065232 W 150.79595309 570.00 0.29 211.79 523.60 570.00 -0.77 1.75 1.10 -0.91 0.61 0.13 2646274.10 359785.26 N 61.24065118 W 150.79595393 665.00 0.22 207.33 618.60 665.00 -1.17 2.17 1.34 -1.28 0.40 0.08 2646273.74 359785.04 N 61.24065018 W 150.79595512 760.00 0.34 208.73 713.59 759.99 -1.61 2.63 1.70 -1.69 0.18 0.13 2646273.33 359784.82 N 61.24064906 W 150.79595636 855.00 0.47 220.62 808.59 854.99 -2.23 3.30 2.24 -2.23 -0.21 0.16 2646272.79 359784.42 N 61.24064757 W 150.79595857 13 -3/8" (c) 1 O17'md 950.00 0.48 220.89 903.59 949.99 -2.92 4.09 2.92 -2.83 -0.73 0.01 2646272.20 359783.90 N 61.24064594 W 150.795961 MV VD DMAG 1045.32 0.71 275.41 998.90 1045.30 -3.33 5.01 3.45 -3.07 -1.58 0.61 2646271.97 359783.05 N 61.24064527 W 150.79596 1093.82 0.76 288.16 1047.40 1093.80 -3.33 5.63 3.66 -2.94 -2.18 0.35 2646272.10 359782.44 N 61.24064562 W 150.795969 1187.45 2.26 346.69 1141.00 1187.40 -1.60 7.93 3.34 -0.95 -3.20 2.11 2646274.10 359781.45 N 61.24065106 W 150.79597551 1282.47 5.95 355.96 1235.76 1282.16 4.84 14.72 7.02 5.78 -3.97 3.93 2646280.85 359780.76 N 61.24066949 W 150.79597993 1378.47 8.91 356.53 1330.94 1377.34 16.79 27.13 18.79 18.17 -4.78 3.08 2646293.25 359780.11 N 61.24070337 W 150.79598447 1470.37 11.49 0.24 1421.38 1467.78 32.61 43.40 34.82 34.43 -5.17 2.90 2646309.51 359779.91 N 61.24074785 W 150.79598670 1567.88 13.14 0.17 1516.65 1563.05 52.98 64.20 55.46 55.23 -5.09 1.69 2646330.30 359780.24 N 61.24080473 W 150.79598628 1660.38 14.87 2.58 1606.40 1652.80 74.98 86.58 77.73 77.60 -4.53 1.97 2646352.66 359781.08 N 61.24086592 W 150.79598307 1757.81 17.44 4.51 1699.97 1746.37 101.80 113.68 104.69 104.65 -2.82 2.69 2646379.69 359783.12 N 61.24093991 W 150.79597336 1851.65 18.25 3.80 1789.30 1835.70 130.29 142.44 133.33 133.33 -0.74 0.89 2646408.34 359785.55 N 61.24101836 W 150.79596155 1946.15 20.73 3.55 1878.37 1924.77 161.48 173.97 164.80 164.79 1.28 2.63 2646439.77 359787.95 N 61.24110441 W 150.79595011 2042.50 23.12 1.34 1967.75 2014.15 196.95 209.93 200.75 200.73 2.78 2.62 2646475.68 359789.88 N 61.24120271 W 150.79594160 2053.26 23.28 1.33 1977.64 2024.04 201.12 214.17 204.99 204.97 2.88 1.49 2646479.92 359790.03 N 61.24121430 W 150.79594104 SurveyEditor Ver SP 2.1 Bld( doc40x_100 ) 11 -06 \IRU 11-06\ IRU 11 -06 \IRU 11 -06 Generated 4/21/2009 8:42 AM Page 1 of 4 • Measured Vertical Along Hole Comments Inclination Azimuth Sub -Sea TVC TVD Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure _ (ft ) (deg) (deg) (ft) (ft ) (ft) (ft) (ft) (ft ) (ft ) (deg/100ft ) (ftUS) (ftUS) 2147.58 24.82 0.06 2063.77 2110.17 238.81 252.61 243.42 243.40 3.33 1.72 2646518.34 359790.95 N 61.24131942 W 150.79593847 2246.01 26.36 359.24 2152.54 2198.94 280.35 295.12 285.93 285.91 3.06 1.61 2646560.85 359791.20 N 61.24143570 W 150.79593999 2339.98 28.01 358.05 2236.13 2282.53 322.12 338.05 328.83 328.83 2.03 1.85 2646603.77 359790.70 N 61.24155308 W 150.79594582 2436.61 30.52 356.28 2320.42 2366.82 367.78 385.28 376.00 376.00 -0.33 2.75 2646650.96 359788.91 N 61.24168210 W 150.79595925 2528.91 31.54 355.43 2399.51 2445.91 413.49 432.86 423.47 423.45 -3.78 1.20 2646698.45 359786.04 N 61.24181189 W 150.79597880 2624.30 33.52 353.47 2479.94 2526.34 462.40 484.15 474.57 474.49 -8.76 2.35 2646749.55 359781.68 N 61.24195151 W 150.79600708 2715.07 34.11 354.26 2555.35 2601.75 510.41 534.66 524.91 524.72 -14.15 0.81 2646799.83 359776.90 N 61.24208888 W 150.79603771 2811.55 35.67 353.59 2634.49 2680.89 562.89 589.85 579.94 579.59 -20.00 1.66 2646854.76 359771.72 N 61.24223898 W 150.79607090 2906.31 38.34 352.86 2710.15 2756.55 616.90 646.88 636.78 636.22 -26.74 2.86 2646911.47 359765.67 N 61.24239387 W 150.79610915 2999.35 40.02 352.94 2782.27 2828.67 672.45 705.65 695.38 694.55 -34.00 1.81 2646969.87 359759.12 N 61.24255340 W 150.79615039 3095.82 42.45 352.42 2854.81 2901.21 732.47 769.24 758.78 757.61 -42.11 2.54 2647033.03 359751.78 N 61.24272589 W 150.796196 3193.15 44.64 351.17 2925.36 2971.76 795.41 836.2 825.59 823.97 -51.70 2.42 2647099.49 359743.01 N 61.24290740 W 150.79625 3289.69 45.89 350.24 2993.31 3039.71 859.32 904.86 893.85 891.64 -62.78 1.46 2647167.29 359732.75 N 61.24309250 W 150.79631372 3382.11 46.88 348.95 3057.06 3103.46 921.20 971.77 960.37 957.45 -74.87 1.47 2647233.23 359721.46 N 61.24327250 W 150.79638235 3476.86 47.11 348.60 3121.68 3168.08 984.90 1041.06 1029.21 1025.41 -88.36 0.36 2647301.35 359708.80 N 61.24345839 W 150.79645892 3570.84 47.34 348.81 3185.51 3231.91 1048.28 1110.04 1097.80 1093.06 - 101.87 0.29 2647369.15 359696.12 N 61.24364342 W 150.79653562 3665.40 47.32 349.22 3249.60 3296.00 1112.31 1179.57 1167.00 1161.31 - 115.12 0.32 2647437.56 359683.70 N 61.24383011 W 150.79661083 3760.30 47.37 349.00 3313.90 3360.30 1176.63 1249.37 1236.52 1229.85 - 128.30 0.18 2647506.24 359671.35 N 61.24401757 W 150.79668568 3854.44 45.75 348.84 3378.63 3425.03 1239.54 1317.72 1304.62 1296.93 - 141.44 1.73 2647573.47 359659.04 N 61.24420104 W 150.79676025 3949.23 45.55 348.89 3444.89 3491.29 1301.89 1385.50 1372.16 1363.44 - 154.53 0.21 2647640.13 359646.76 N 61.24438295 W 150.79683456 4044.43 45.43 348.56 3511.63 3558.03 1364.28 1453.39 1439.83 1430.01 - 167.80 0.28 2647706.86 359634.30 N 61.24456506 W 150.79690992 4138.41 45.24 348.72 3577.69 3624.09 1425.67 1520.23 1506.46 1495.55 - 180.97 0.24 2647772.54 359621.93 N 61.24474430 W 150.79698466 4233.34 45.12 349.82 3644.61 3691.01 1487.79 1587.57 1573.65 1561.70 - 193.50 0.83 2647838.84 359610.20 N 61.24492526 W 150.79705584 4328.90 46.85 350.87 3711.01 3757.41 1551.69 1656.29 1642.30 1629.45 - 205.02 1.98 2647906.72 359599.52 N 61.24511056 W 150.79712122 4423.13 46.61 351.34 3775.60 3822.00 1615.81 1724.90 1710.88 1697.24 - 215.63 0.44 2647974.62 359589.73 N 61.24529596 W 150.79718146 4519.30 46.27 351.69 3841.87 3888.27 1681.11 1794.59 1780.55 1766.16 - 225.91 0.44 2648043.66 359580.29 N 61.24548449 W 150.79723984 4613.33 46.11 351.87 3906.96 3953.36 1744.80 1862.44 1848.40 1833.32 - 235.61 0.22 2648110.93 359571.41 N 61.24566819 W 150.79729492 4710.09 46.00 351.98 3974.11 4020.51 1810.26 1932.11 1918.06 1902.30 - 245.40 0.14 2648180.01 359562.46 N 61.24585685 W 150.79735049 4807.74 46.01 351.60 4041.94 4088.34 1876.21 2002.36 1988.30 1971.83 - 255.43 0.28 2648249.65 359553.28 N 61.24604703 W 150.797407 4901.62 46.18 352.25 4107.04 4153.44 1939.76 2070.00 2055.94 2038.80 - 264.93 0.53 2648316.73 359544.60 N 61.24623020 W 150.79746 4996.46 46.10 352.17 4172.75 4219.15 2004.12 2138.38 2124.32 2106.55 - 274.20 0.10 2648384.58 359536.15 N 61.24641551 W 150.79751402 5092.87 46.26 352.10 4239.51 4285.91 2069.56 2207.94 2193.88 2175.45 - 283.72 0.17 2648453.59 359527.48 N 61.24660399 W 150.79756807 5186.87 46.09 352.25 4304.60 4351.00 2133.38 2275.76 2261.69 2242.64 - 292.95 0.21 2648520.88 359519.06 N 61.24678776 W 150.79762050 5281.35 46.16 352.39 4370.08 4416.48 2197.53 2343.87 2329.80 2310.14 - 302.05 0.13 2648588.48 359510.78 N 61.24697237 W 150.79767218 5374.85 46.10 351.82 4434.88 4481.28 2260.93 2411.27 2397.20 2376.90 - 311.31 0.44 2648655.35 359502.34 N 61.24715499 W 150.79772475 5468.27 46.13 351.92 4499.64 4546.04 2324.17 2478.60 2464.53 2443.56 - 320.83 0.08 2648722.11 359493.63 N 61.24733730 W 150.79777882 5563.02 46.18 352.52 4565.28 4611.68 2388.49 2546.94 2532.86 2511.26 - 330.09 0.46 2648789.91 359485.21 N 61.24752249 W 150.79783134 5657.57 46.22 352.67 4630.72 4677.12 2452.88 2615.18 2601.10 2578.93 - 338.88 0.12 2648857.68 359477.24 N 61.24770759 W 150.79788129 5755.02 46.76 352.93 4697.81 4744.21 2519.64 2685.86 2671.78 2649.05 - 347.74 0.59 2648927.90 359469.23 N 61.24789938 W 150.79793159 5844.70 46.96 352.85 4759.13 4805.53 2581.49 2751.29 2737.22 2713.99 - 355.84 0.23 2648992.92 359461.93 N 61.24807699 W 150.79797758 5942.36 47.95 353.49 4825.17 4871.57 2649.61 2823.24 2809.16 2785.43 - 364.39 1.12 2649064.46 359454.24 N 61.24827238 W 150.79802616 SurveyEditor Ver SP 2.1 Bld( doc40x_100) 11 -06 \IRU 11 -06 \IRU 11 -06 \IRU 11 -06 Generated 4/21/2009 8:42 AM Page 2 of 4 Comments Measured Inclination Azimuth Sub -Sea TVC TVD Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure _ (ft) (deg) (deg) (ft ) (ft ) (ft) (ft) (ft) (ft) (ft) (deg/100ft ) (ftUS) (ftUS) 6007.27 47.71 354.53 4868.74 4915.14 2695.38 2871.35 2857.25 2833.27 - 369.41 1.24 2649112.35 359449.81 N 61.24840325 W 150.79805467 9 -5/8" @ 6014'md 6103.47 45.68 356.03 4934.72 4981.12 2762.43 2941.35 2927.17 2903.03 - 375.19 2.40 2649182.17 359444.88 N 61.24859406 W 150.79808747 6200.11 42.45 359.77 5004.17 5050.57 2827.58 3008.54 2994.08 2970.16 - 377.71 4.29 2649249.32 359443.17 N 61.24877767 W 150.79810182 6296.09 41.09 2.87 5075.76 5122.16 2890.40 3072.47 3057.30 3034.06 - 376.26 2.58 2649313.20 359445.40 N 61.24895246 W 150.79809361 6390.90 38.17 8.43 5148.79 5195.19 2950.44 3132.90 3116.28 3094.19 - 370.40 4.84 2649373.25 359451.99 N 61.24911692 W 150.79806036 6486.80 35.90 13.22 5225.36 5271.76 3008.15 3190.64 3171.35 3150.90 - 359.63 3.83 2649429.81 359463.46 N 61.24927202 W 150.79799918 6581.92 34.82 15.51 5302.93 5349.33 3063.14 3245.68 3222.84 3204.22 - 345.99 1.80 2649482.96 359477.75 N 61.24941786 W 150.79792174 6677.95 33.86 18.20 5382.23 5428.63 3117.10 3299.85 3272.76 3256.05 - 330.30 1.87 2649534.59 359494.06 N 61.24955965 W 150.79783268 6772.41 33.54 22.01 5460.82 5507.22 3168.96 3352.24 3319.97 3305.25 - 312.30 2.26 2649583.56 359512.66 N 61.24969422 W 150.79773048 6868.18 33.48 25.93 5540.69 5587.09 3220.65 3405.10 3366.13 3353.54 - 290.83 2.26 2649631.59 359534.71 N 61.24982630 W 150.79760860 6962.10 33.50 28.93 5619.02 5665.42 3270.58 3456.92 3409.99 3399.53 - 266.96 1.76 2649677.27 359559.14 N 61.24995208 W 150.797473 7055.90 33.36 31.88 5697.31 5743.71 3319.58 3508.59 3452.49 3444.08 - 240.82 1.74 2649721.51 359585.82 N 61.25007396 W 150.79732 7155.35 32.83 39.50 5780.66 5827.06 3369.21 3562.83 3494.39 3488.13 - 209.21 4.22 2649765.16 359617.96 N 61.25019442 W 150.79714 7250.94 32.92 44.69 5860.96 5907.36 3414.05 3614.69 3530.91 3526.59 - 174.46 2.95 2649803.20 359653.17 N 61.25029964 W 150.79694790 7347.19 32.82 49.81 5941.81 5988.21 3456.65 3666.91 3564.63 3562.03 - 136.13 2.89 2649838.16 359691.93 N 61.25039656 W 150.79673029 7442.91 32.88 53.11 6022.23 6068.63 3496.69 3718.82 3595.64 3594.37 -95.53 1.87 2649870.00 359732.91 N 61.25048502 W 150.79649978 7537.34 32.72 52.95 6101.61 6148.01 3535.25 3769.97 3625.54 3625.13 -54.66 0.19 2649900.26 359774.15 N 61.25056916 W 150.79626773 7633.41 32.88 52.50 6182.36 6228.76 3574.66 3822.01 3656.67 3656.65 -13.25 0.30 2649931.27 359815.94 N 61.25065538 W 150.79603261 7729.08 32.97 52.64 6262.67 6309.07 3614.13 3874.02 3688.36 3688.25 28.04 0.12 2649962.37 359857.61 N 61.25074182 W 150.79579815 7823.85 33.27 52.22 6342.04 6388.44 3653.52 3925.80 3720.47 3719.83 69.09 0.40 2649993.43 359899.03 N 61.25082818 W 150.79556512 7918.04 33.86 51.79 6420.52 6466.92 3693.38 3977.87 3753.50 3751.89 110.12 0.68 2650024.99 359940.45 N 61.25091587 W 150.79533211 8015.24 33.88 51.13 6501.23 6547.63 3735.17 4032.04 3788.71 3785.64 152.49 0.38 2650058.22 359983.23 N 61.25100818 W 150.79509154 8110.45 33.92 49.24 6580.26 6626.66 3776.88 4085.14 3824.52 3819.64 193.28 1.11 2650091.71 360024.42 N 61.25110118 W 150.79485997 8204.40 33.71 48.84 6658.31 6704.71 3818.59 4137.43 3860.93 3853.91 232.76 0.33 2650125.50 360064.32 N 61.25119492 W 150.79463578 8297.78 33.20 48.70 6736.22 6782.62 3859.79 4188.90 3897.30 3887.84 271.48 0.55 2650158.95 360103.44 N 61.25128772 W 150.79441595 8391.84 32.72 48.52 6815.14 6861.54 3900.85 4240.08 3933.90 3921.67 309.87 0.52 2650192.32 360142.24 N 61.25138026 W 150.79419796 8486.22 32.31 49.17 6894.73 6941.13 3941.42 4290.81 3970.35 3955.06 348.06 0.57 2650225.23 360180.83 N 61.25147158 W 150.79398109 8580.33 32.40 50.17 6974.23 7020.63 3981.25 4341.17 4006.34 3987.65 386.46 0.58 2650257.35 360219.62 N 61.25156073 W 150.79376308 8673.62 32.24 50.95 7053.07 7099.47 4020.23 4391.05 4041.74 4019.34 424.98 0.48 2650288.56 360258.52 N 61.25164739 W 150.79354437 8770.95 32.36 50.98 7135.34 7181.74 4060.64 4443.06 4078.73 4052.09 465.38 0.12 2650320.82 360299.31 N 61.25173697 W 150.793314. 8866.00 32.36 51.05 7215.62 7262.02 4100.14 4493.93 4115.19 4084.10 504.92 0.04 2650352.34 360339.24 N 61.25182451 W 150.79309044 8960.33 32.63 51.19 7295.19 7341.59 4139.43 4544.61 4151.75 4115.91 544.37 0.30 2650383.67 360379.07 N 61.25191151 W 150.79286643 9054.71 32.75 50.91 7374.62 7421.02 4178.98 4595.58 4188.86 4147.95 584.01 0.20 2650415.22 360419.09 N 61.25199916 W 150.79264133 9149.38 32.45 50.19 7454.37 7500.77 4218.85 4646.59 4226.59 4180.36 623.40 0.52 2650447.15 360458.87 N 61.25208779 W 150.79241769 9243.71 32.15 49.34 7534.11 7580.51 4258.66 4696.99 4264.59 4212.92 661.88 0.58 2650479.23 360497.74 N 61.25217683 W 150.79219919 9339.76 31.68 48.33 7615.64 7662.04 4299.27 4747.77 4303.66 4246.34 700.10 0.74 2650512.18 360536.37 N 61.25226824 W 150.79198212 9434.93 31.62 48.42 7696.65 7743.05 4339.46 4797.71 4342.58 4279.51 737.43 0.08 2650544.89 360574.09 N 61.25235896 W 150.79177015 9530.67 31.74 48.61 7778.13 7824.53 4379.84 4847.99 4381.91 4312.81 775.10 0.16 2650577.73 360612.16 N 61.25245006 W 150.79155627 9627.54 31.92 48.88 7860.43 7906.83 4420.75 4899.08 4421.98 4346.50 813.51 0.24 2650610.95 360650.97 N 61.25254220 W 150.79133817 9722.74 32.39 50.01 7941.03 7987.43 4460.95 4949.74 4461.55 4379.44 852.00 0.80 2650643.41 360689.86 N 61.25263228 W 150.79111957 9818.00 32.80 50.77 8021.28 8067.68 4501.14 5001.06 4501.33 4412.16 891.54 0.61 2650675.64 360729.79 N 61.25272176 W 150.79089507 9914.34 33.19 51.26 8102.08 8148.48 4541.87 5053.52 4541.88 4445.16 932.32 0.49 2650708.14 360770.97 N 61.25281202 W 150.79066349 SurveyEditor Ver SP 2.1 Bld( doc40x_100 ) 11 -06 \IRU 11 -06 \IRU 11 -06 \IRU 11 -06 Generated 4/21/2009 8:42 AM Page 3 of 4 Comments Measured Inclination Azimuth Sub•Sea TVC TVD Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure (ft ) (deg) (deg) (ft) (ft ) (ft ) (ft ) (ft) (ft ) (ft ) (deg1100ft ) (ftUS) (ftUS) Last Survey 9995.72 33.63 52.42 8170.02 8216.42 4576.25 5098.33 4576.30 4472.84 967.55 0.95 2650735.39 360806.53 N 61.25288773 W 150.79046342 TD (Projected) 10060.00 33.63 52.42 8223.54 8269.94 , 4603.33 5133.93 4603.54 4494.56 995.77 0.00 2650756.76 360835.01 N 61.25294711 W 150.79030321 Survey Type: Definitive Survey NOTES: NSG +SSHOT - ( NorthSeeking Gyro Singleshots -- Northseeking gyro in gyrocompassing or stationing mode with larger misalignment errors as a result of landing in a UBHO sub. Not to be run above 70 degrees inclination. ) MWD +DMAG - ( MWD + BGGM referenced multistation interference correction -- Standard SLB MWD error model where the surveys have been corrected using the SLB multistation DMAG (DeMAGnetization) correction process to correct for drillstring magnetic interference. This model contains improved azimuth accuracy as a result of applying DMAG as published in SPE 87977. ) Legal Description: Northing (Y) fftUS] Eastina (X) fftUS] Surface : 584 FSL 628 FEL S1 T13N R9W SM 2646275.02 359784.66 BHL : 5079 FSL 4826 FEL S6 T13N R8W SM ' 2650756.76 360835.01 • • SurveyEditor Ver SP 2.1 Bld( doc40x_100) 11 -06 \IRU 11 -06 \IRU 11 -06 \IRU 11 -06 Generated 4/21/2009 8:42 AM Page 4 of 4 • • Ivan River Unit 11 -06 Mud Weight -vs- Depth PTD 208 -184 Mud Weight (ppg) 8 8.2 8.4 8.6 8.8 9 9.2 9.4 9.6 9.8 10 10.2 10.4 10.6 10.8 11 0 Measured Depth True Vertical Depth 2000 TD 16" Hole @ 1028' MD I • 4111 4000 a 6000 TD 12 -1/4" Hole @ 6023' MD PFL w , � a j 8000 �' �w 10000 TD 8 -1/2" Hole @ 10,060' MD __- 11 I 12000 • Chevron Timothy C Brandenburg Union Oil Company of California 411.1 Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 Fax 907 263 7884 April 23, 2009 RECEIVED APR ?009 Commissioner Alaska Oil & Gas Conservation Commission 404 Oi & GR8s COi :o9mm1��ig0 333 W. 7 Avenue Anchorage, Alaska 99501 Ancharo0e Re: Well Completion Report and Log (Form 10 -407) Ivan River Unit, IRU 11 -06 (PTD 208 -184) Dear Commissioner: Enclosed for your review is the Well Completion Report (form 10 -407) for the Ivan River Unit IRU 11 -06 Gas Development Well. The well is currently perforated but has not been able to produce. A subsequent pressure /temperature log indicates a fluid influx that is preventing the low- pressure Tyonek IRGS sands from producing. We are currently evaluating our options for intervention to bring the well on production. Approval for this work will be submitted in a separate sundry (Form 10 -403). If additional information is required, please contact either myself or Mr. Stan Porhola at 263 -7640. Sincerely, !f Timothy C. Brandenburg Drilling Manager TCB: stp Attachments: Form 10 -407 Operations Summary Directional Survey Mud Weight vs. Depth Chart Wellbore Schematic Cc: Well File Union Oil Company of California / A Chevron Company http: / /www.chevron.com 1 • • Chevron Francisco Castro Chevron North America Exploration and Production Technical Assistant 3800 Centerpoint Dr. Suite 100 ` Anchorage, AK 99503 Tele: 907 263 7844 Fax: 907 263 7828 E -mail: fcbn @chevron.com DATE April 23, 2009 To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste #100 Anchorage, AK 99501 DATA TRANSMITTAL `' hkV /EL ". 100Typ t } , II,SC�A *t kwTA �L c LlI1E l �y � e k ► � PDS, LAS, IRU 11 -06 USIT 5' 08- Feb -09 5900' -9900' 1 1 1 DLIS SLU 41- LWD GR DEPTH SHIFT PDS, LAS, 33RD QC PLOT 2' 20- Apr -09 5414' -9038' 1 1 1 DLIS < 00t — it 1q96 " 0(D 11 Please acknowled4D, receipt by signing and -turning one copy of this transmittal or FAX to 907 263 7828. Received 8 : Date: 3 • Chevron Francisco Castro Chevron North America Exploration and Production Technical Assistant 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tele: 907 263 7844 Fax: 907 263 7828 E -mail: fcbn @chevron.com DATE April 14, 2009 To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste #100 Anchorage, AK 99501 DATA TRANSMITTAL IRU 11 - PRESS TEMP - GR CCL 5' 07- Apr -09 4700' -9719' 1 1 1 PDS Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 263 7828. ' 1 3 Received By Date: Chevron •cisco Castro Chevron North Aleica Exploration and Production ••=0, Technical Assistant 3800 Centerpoint Dr. Suite 100 .:-...' Anchorage, AK 99503 *Oil Tele: 907 263 7844 Fax: 907 263 7828 E-mail: fcastro@chevron.com DATE April 1, 2009 To: AOGCC Mahnken, Christine R 333 W. rh Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL - - , A , a. +- -"APT,' ',...;,- z --.;.--- ,?.,. 4: .4-.a,A, .,_. -*A., AZIV, A' h?,. ,,, ' A r it gi■W. , , g, 3 ' ',A: 1 ' _4,01.,. ' ' ' ,; „ 1:,, , ,,it t eit; ;"-;,-., ' ., 4 : ' ,4,1%,, „prf;r2Z4` " r `,,...= MO ` 3 . ''-cV,P , .-- ;:t4}._ ,f lex..,ip_- ' , -, -,;,e , ,,,Ik i ,t,T , ..4=4",4f-',41 - , ';‘,ir-• N'..:,,.. . VP: fl *:;.!.. t' 'f; ' ° , ." '''"' 0 ' 1 ' ';':';t:',;,' .:; 4. LI, LAS, PDF, MEASURED DEPTH LOG 31-Dec-08 - XLS, DOC, IRU 11-06 RECORDED MODE 2" 29-Jan-09 835-10026 1 1 1 TXT, FMA LAS, PDF, TRUE VERTICAL DEPTH 31-Dec-08 - XLS, DOC, IRU 11-06 LOG RECORDED MODE 2" 29-Jan-09 835'-10026' 1 1 1 TXT, FMA DRILLING AND LAS, PDF, PROCESS MECHANICS 31-Dec-08 - XLS, DOG, IRU 11-06 (DEPTH) LOG REALTIME 2" 29-Jan-09 835-10026' 1-4 1 1 TXT, FMA DRILLING AND LAS, PDF, PROCESS MECHANICS 30-Dec-08 - SURFACE- XLS, DOC, IRU 11-06 (TIME) LOG REALTIME 10-Jan-09 SURFACE 1 1 1 TXT, FMA DRILLING AND LAS, PDF, PROCESS MECHANICS 11-Jan-09 - SURFACE- XLS, DOC, IRU 11-06 (TIME) LOG REALTIME 13-Jan-09 SURFACE 2 1 1 TXT, FMA DRILLING AND LAS, PDF, PROCESS MECHANICS 18-Jan-09 - SURFACE- XLS, DOC, IRU 11-06 (TIME) LOG REALTIME 22-Jan-09 SURFACE 3 1 1 TXT, FMA DRILLING AND LAS, PDF, PROCESS MECHANICS 23-Jan-09 - SURFACE- XLS, DOC, IRU 11-06 (TIME) LOG REALTIME 30-Jan-09 SURFACE 4 1 1 TXT, FMA Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 90 263 7828. /) Received By Date: — , : i , • Chevron Francisco Castro Chevron North America Exploration and Production .; - Technical Assistant 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tele: 907 263 7844 Fax: 907 263 7828 E -mail: fcbn @chevron.com DATE March 16, 2009 To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste #100 Anchorage, AK 99501 DATA TRANSMITTAL OS 4,1 46 - Ati t ,i t v. H LAS, PDF, DML, DOC, IRU 11 -06 Final Mud Logging Report 2" 29- Jan -09 3800 -10060 1 1 1 TXT Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 263 7828. Received By: Date: Clk q � ∎: ' 1 STATE OF ALASKA �' , ° 0 ALASKA OIL AND GAS CONSERVATION COMMISSION J APPLICATION FOR SUNDRY APPROVALS' MAR Q .t t19 20 AAC 25.280 Sg. �,�ZrPt188 ��SB�a 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ❑ 1 fiv MI * COI' C Other Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension WohotIO CT Unload Change approved program IS Pull Tubing ❑ Perforate New Pool 0 . Re -enter Suspended Well ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development 0 _ Exploratory ❑ 208 -184 - 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: PO Box 196247, Anchorage, AK 99519 50- 283 - 20130 -00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No El Ivan River Unit (IRU) 11 -06 9. Property Designation: 10. KB Elevation (ft): 11. Field /Pool(s): ADL032930 [Ivan River Unit] ° 46.4 MSL' Ivan River Unit / Undefined Gas pocA 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): 10,060 8,270 9,931 8,164' N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 170' 20" 107' 170' Surface 1,016' 13 -3/8" 1,016' 1,016' 5,020 psi 2,670 psi Intermediate 6,015' 9 -5/8" 6,015' 4,921' 5,750 psi 3,090 psi Production 4,195' 7" 10,020' 8,239' 7,240 psi 5,410 psi Liner Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A 3 -1/2 "(prod) & 2 -3/8 "(heater) 9.2 #L- 80(prod) & 4.6 #L- 80(heat) 9,494'(prod) & 3,500'(heat) Packers and SSSV Type: Packers and SSSV MD (ft): Baker SC -2 Retrievable Packer and N/A 5,915' and N/A 13. Attachments: Description Summary of Proposal El 14. Well Class after proposed work: Detailed Operations Program p BOP Sketch IS Exploratory ❑ Development El - Service ❑ 15. Estimated Date for 3/10/2009 16. Well Status after proposed work: Commencing Operations: Oil ❑ Gas 0 - Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Marcus Barbee 263 -7605 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 276-7600 Date 3/4/2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 1/4309 — p 'Y Plug Integrity ❑ BOP Test K Mechanical Integrity Test ❑ Location Clearance ❑ Other: Ica © `, (�k A r-,_a) C.7 ZI 4. --, - Subsequent Form Required: "ft 0 ' 4 v-.43T GA G -c ‘\ APPROVED BY Approved by � COMMISSIONER THE COMMISSION Dater 7® Form 10 -403 Revised 06/2006 -- , . ' ' ‘ " Submit in Duplicate Chevron Well Name: IRU 11 -06 Field: Ivan River Completion: Actual 2 -13 -09 Driven I L Conductor: 20 ", 129 ppf, X -56 Plain End to 171' 16" Hole I A , Surface Casing: 13%", 68 ppf, L -80, BTC to 1,016' Surface Casing Cement 13.0 ppg Lead cmt from 200' - 1,016' 180 bbl (130% OH Excess) Disposal Zone (Upper): 15.8 ppg Top job cmt from 0' - 200' 38 bbl (218% OH Excess) Top Inj - 3053' MD / 2869' TVD y;�?ir�±1 Btm lnj - 3358' MD / 3087' TVD 12 -1/4" Hole I _1 Intermediate Casing: 9% ", 40 ppf, L -80, BTC to 6,015' Intermediate Casing Cement DV Collar at 3,487' 12.0 ppg Lead cmt from 4,100' - 6,018' 162 bbl (40% OH Excess) 1st Stage Disposal Zone (Lower): 12.0 ppg Lead cmt from 900' 3,487' ryr 227 bbl (40% OH Excess) 2nd Stage ;ttM1ci.;. Top Inj - 5088' MD / 4283' TVD Btm Inj - 5684' MD / 4695' TVD 8 -1/2" Hole I X X Production Liner Casing Cement SS 12.0 ppg Lead cmt from 5,820' - 10,024' 172 bbl (75% OH Excess) Fracture Gradients: LOT @ 1,016' MD (1,016' TVD) = 11.8 ppg FIT @ 6,015' MD (4,920' TVD) = 13.6 ppg Production Tubing: 3 9.2 ppf, L -80, IBT -Mod to 9,494' Perfs (Proposed): 00 Tyonek 9,545' - 9,698' (153' TCP) Heater String Tubing: 2 ", 4.6 ppf, L -80, IBT(SCC) to 3,500' / %8 0 Tyonek Completion: - Retrievable Packer at 5,915' 0 Production Liner. - Durasleeve Sliding Sleeve at 5,970' 7 ", 26 ppf, L -80, BTC -Mod w/ Torque Rings from - Ported Sub at 9,418' 5,825' to 10,020' MD (4,792' to 8238' TVD) - WLEG at 9,494' 9 -5/8" x 7" Rotatable FlexLock liner hanger w/ ZXP - 4 -5/8" TCP Guns 9,545' to 9698' Packer & Tieback sleeve at 5,825' PBTD = 9,931' MD TD = 10,060' MD WBD IRU 11 -06 Actual 2- 13- 09.xls Feb 16, 2009 Drawn by: STP Chevron • l Ivan River Unit %1101 Well # IRU 11 -06 3/4/09 OBJECTIVE: • Dry out well bore utilizing coil tubing & perforate Tyonek zone. PROCEDURE SUMMARY: 1 Slick line — RIH and open the sliding sleeve below the production packer@ 5,970'. 2 Coil Tubing — RIH and sting into the sliding sleeve with custom locator seal assembly. 3 Nitrogen — Pump nitrogen down the 3-1/2" production tubing x coil tubing annulus through the sliding sleeve, down the 7" x 3 -1/2" annulus below the production packer, through the ported sub above the perforation guns, up the 31/2" production tubing, into the 1 -3/4" coil tubing back to surface. 4 Coil Tubing — POOH leaving 500 psi ( + / -) on the production tubing that is dry to the ported sub above the perforation guns. 5 Slick line — RIH and close the sliding sleeve below the production packer & bleed WHP to 334 psi ( + / -). 6 Slick line — Load firing drop bar on master valve, MU drop bar retrieval tool and lubricate, stab lubricator over drop bar and onto the well head. 7 Slick line — Drop the firing bar and wait for indication of firing, once guns fire RIH with drop bar retrieval tool and verify guns have released from tubing tail. If guns have released POOH, if guns have not released retrieve the drop bar and POOH. 8 Turn well over to production. Contingency: 9 Wire line — If guns did not release, RIH with tubing cutter / radial torch and cut the tubing tail off. IRU 11 -06 REVISED BY: CVK 3 -4 -09 S • Lj Chevron Chevron IRU 11 -06 IWO Well Head Rig Up Reverse Circulation 4 r1 .►/ r� - •1. i /% T rk � \ .i iii. Alilr It :; air ` SS -800L Injector Head • • I Y 1 , • 4 1/16" 10M Stripper • 4 1/16" 10M Flanged Lubricator • • 4 1/16" 10M Combi BOP Ii,. ak.(I 4 Blind Ram /Shear Ram (I' ';) a Slip Ram /Pipe Ram dtliZIEXC 1031 11 C :; i i . ;:; II 01 4 4 1/16" 10M Flow Cross • 4 1. Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 IVAN RIVER UNIT 11 ADL032930 5028320130 LK9485 46.80 Primary Job Type Job Category Objective Actual Start Date Actual End Date Drill and Complete Drill and Drill to access attic position reserves in the Sterling, Beluga, and 12/13/2008 Complete Tyonek. Primary Wellbore Affected Wellbore UWI Well Permit Number IRU 11 - 5028320130 -00 2081840 12/131200 H00 00 12/1412008` .. x Operations Summary R/D for rig move to IRU 11 -06. 12/1412008 00:00 - 12115/2008 00:00 Operations Summary r ,.k„ Rig move to IRU 11 -06. 12/15/200800:00' - 12118/200800:00 ?.';" ,4 14-4-," , , Operations Summary R/U Nabors 129. Set rig mats. Spot substructure over well. Set mud pumps, boiler, and pits. 12/16/2008 00:00 - 12/17/2008 00:00 < . , ` ' Operations Summary R/U Nabors 129. Set generator and dog house. Hook up steam and electric. Perform "Man Down" drill. Pin derrick to sub base. Spool on new drilling line. Start up boiler and transfer fuel to rig. 12117/2008 '00 t' -12/1 2008 00:00 '.11 ., :..., Operations Summary Spool new drilling line. Prep to raise derrick. Start boiler and circ steam thru rig. Stage Top Drive. Stage welding shop. Fill water tank. String blocks and attach to drawworks. Raise derrick and secure. R/U on rig floor. Is is 00:00 - 1211912008 00.E Operations Summary Setup containment berms around rig. Continue R/U on rig floor. Spot cement silo. Prep and cut conductor for diverter nipple up. Weld on 4" outlets. Conduct pre - spud meeting w/ service hands and rig crews. Spot cuttings tank, gas buster, top drive cable tray. Change mud pump pop - offs. Install starting head. Test to 300 psi for 15 min - test OK. N/U diverter stack. Notify AOGCC of diverter function test. 12/ 19/2008:00140 - 12/20/200800:00° x` ' Operations Summary Fill pits w/ water. Install 4" ball valves on conductor outlets. Install flow line and knife valve on diverter. N/U diverer line. Contact Jim Regg w/ AOGCC. Waived witness for diverter function test. P/U torque tube and top drive. Set cat walk. Function test mud pumps. 12/2012008 00:00' -12121/2008 00:00 ? Operations Summary Hook top drive to blocks. Install flowlines from conductor outlets. Mix spud mud. R/U on rig floor. R/U windwalls. Set mud and mudlogging shacks. Troubleshoot electrical problem w/ top drive. Set secondary water tank w/ crane. Move 540 sx "Class G" into silo next to rig. R/U centrifuge. Install shaker screens. Re -spot welding shop. Set up pipe racks for tubulars and BHA. 12/21/20400 :00 - 12/22/2008; 00:00 Operations Summary Continue trouble shoot top drive electrical and mixing spud mud. Function test diverter. Test run 13 - 3/8" casing hanger. Install kelly hose to top drive. Set pipe racks and strap 5" drillpipe. Find top drive electrical problem repaired. Function test top drive - test OK. P/U 5" drillpipe. 1� . ; .�.2/2 ':'2/200, od800.0 «� .0 0:00 �,.;,.. �` �' .44 .1 Operations Summary P/U 5" HWDP and 6 -1/2" Jars. P/U 16" BHA. RIH and tag fill inside conductor at 115' MD. Break circ and fill conductor. Found leak in knife valve and 4" ball valves. Change ball valve and tum knife valve to face o..osite directi.n. Test for leaks - n. leaks, RIH washing down f/ 115' t/174'. MW = 8.7 ppg. P/U and run 8" DCs (3 ea). RIH and drill f/174' t1837'. MW = 9.0+ ppg. 1212312 T,.', 00 00f ;,12/24/2.00, c 0100 Operations Summary Drill f/837' t11028'. MW = 9.0 ppg. Circ and cond hole. Mix and pump 25 bbl pill w/ 10 ppb nut plug for fluid caliper. Pill channeled and retumed 47 bbl early. POOH back reaming f/1028' t/289' MD. Mud pumps down. POOH f/289' t/surface w/ no pumps. Rack back BHA. Service rig and change lower mud saver valve on top drive. Lay down bit, stabilizer and XO. Rack back DCs. R/U to run 13 -3/8" casing. Change out rotary bowl w/ casing spider slips. Run casing t/ 247' MD. Tight spot. UD casing joint. MW = 9.0 ppg. 1. 7r Oa 00:00 - 1212512.. l ;� '`;t , . ry ` Operations Summary Run 13 -3/8" casing to 1018'. R/D casing running equipment. Attempt to back out landing joint from hanger - no joy. Laydown hanger and pup joints. R/U circ swedge. Break circ. P/U joint and tag bottom at 1027'. P/U and UD 2 joints w/ 1 pup. 12/2512008 00:00`= 12/26/2008 00:06 Operations Summary Clean threads and pup and full joint. Clean threads and torque. R/U circ swedge. Circ and clean hole. Drain stack and clean cellar. Land casing on emergency silos. R/U false bowl and elevators. P/U stab -in adapter and pup w/ centralizer. RIH on 5" drillpipe. $Dace out and stab in to float collar. Circ and cond hole. Mix spacer and R/U cement lines. Pump 20 bbl un- weighted spacer. Mix and pump 190 bbl 13.0 ppg cement. No cement to surface. Saw spacer at 132 bbl away. Returns diminished thru job. Unsting and P/U 90'. Circ casing clean. POOH w/ 5" drillpipe. N/D diverter system. • Chevron IOW Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 - 06 IVAN RIVER UNIT 11 - 06 ADL032930 5028320130 LK9485 46.80 Est 2/2612008 00 :00 - 12127/2008 00:00 Operations Summary Continue N/D diverter system. Make rough cut on 13 -3/8" above emergency slips. Move rig beaver slide and catwalk. Complete R/D of diverter system. Make final cut on 13 -3/8" above emergency slips. Install multi -bowl wellhead and test to 1800 psi for 10 min - test OK. Cut slot in 20" conductor for top lob. Run 1/2" and 3/4" conduit pipe into annulus thru slot. Dropped 6 jts of 1/2" into annulus. Make 2nd cut in 20" conductor on opposite side. Run 3/4" in 10' sections. Give AOGCC (Bob Noble) 24 hours notice to witness BOPE test. 12 /27/2008 00:00 - "12128/20800 :00 , Operations Summary Run 3/4" into annulus to 200'. POOH. Bottom jts of 3/4" bent. Enlarge cut slot to retrieve bent jts of 3/4 ". Run back w/ 3/4 ". Attempt to circ - no joy. POOH. Found bottom 2 jts plugged. Run back to 200'. R/U cement lines. Break circ. Circ 2 bpm @ 1950 psi. Mix and Dumo 15.4 Dpg. cement w/ 2% ( r.12 Pumped 38 bbls. Saw cement to surface at 30 bbls away (calculated annulus volume = 34.7 hhl w/ 10()% OH excess). 12/28/2008 00x:00 12/29/2008 00 :00 Operations Summary POOH w/ 3/4" from annulus. Flush 3/4" and clean out cellar. Tag cement 3' below ground level. Top job complete. N/U BOPE. 12/29/ 2008 00:00.-12/30 /2008 00:00w "o,; Operations Summary Complete N/U of BOPE and function test. Test BOPE to 250/3000 psi. Test annular to 250/2500 psi - test OK. Thaw dart valve and TIW valve - test OK. Test plug leaking. Pull plug and test casing to 2000 psi for 10 min - test OK. Rerun test plug - no leaks. HCR valve on kill line failed. Replace w/ manual valve and test OK. Choke manifold valve #7 failed. Replace w/ new bonnet and test OK. Remaining BOPE - test OK. AOGCC inspector Bob Noble witness onsite. Pull test plug and set wear bushing. Unbolt drilling nipple and silicone API ring. Reset fill up line and bolt down drilling nipple. 12/30/200800 :00 = 12/31/2008'.00 :00 Operations Summary P/U cleanout BHA. RIH. Tag cement at 928'. Cleanout to 956'. POOH to P/U gyro. Place gyro tool in totco ring at bottom of BHA. RIH taking gyro survey each connection. POOH taking gyro survey each connection. Recover gyro. P/U additional drillpipe. POOH standing back drillpipe. L/D cleanout BHA. P/U directional BHA. 12/3112008 - .111/201 Operations Summary Calibrate and test directional tools. Tag cement. Drill shoe track. Drill new hole f/1028' 1/1055'. Circ and cond hole. R/U and perform leak -off test. LOT at 11.8 ppg EMW. Circ and cond hole. Build new mud system. MW = 9.0 ppg. 111 00 00i °A''00:00 Operations Summary Change out spud mud for 6% KCI polymer mud. P/U to casing shoe. Repair top drive gripper dies. RIH to bottom. Directionally drill f/1055' 1/1270'. Service top drive PLC controls. P/U to casing shoe. Repair top drive PLC. MW = 9.0 ppg. i'9`'x1 ' 1 '00 :00 Operations Summary Continue repair on the top drive PLC. Drift 9 -5/8" casing off -site at Pretty Creek pad. ,1/3/2009 00:00 -1/4/2009 :04 •, ; Operations Summary Complete repair of top drive. RIH 1/ 1176'. Ream and wash f/1176' 1/1270'. Directionally drill f/1270' 1/1555'. TOOH 1/13 -3/8" shoe to work multiple issues w/ mud pumps, pits, and shaker screens. MW = 9.0 ppg. 1/4/2009 00:00 1/5/2009 00 :00:. • t 1' Operations Summary Change shaker screens, clean suction pit and jet lines. Change out lower kelly valve. Repair hydraulic leak on top drive brake. Move mud across new screens staging mud pumps up to 700 gpm. RIH f/ shoe 1/1555'. Drill f/1555' 1/1741'. Change out shaker screens, clean possum belly, sand trap, and suction lines. Drill f/1741' 1/2121'. Cease drilling. G &I down and unable to process cuttings. Decision made to P/U additional drillpipe off the catwalk while waiting for G &I. MW = 9.0 ppg. 1/5/2009 00100 % 110%2000`00:00 Operations Summary Shutdown. assist G &I w/ injecting. Repairing water well on pad. Service mud pumps. P/U additional 5" drillpipe. Ream and wash f/2041' 1/2121'. Drill f/2121' 1/2663', control drilling section to allow G &I to keep up. MW = 9.0 ppg. i'110/2009 00 :00 -117/2009 r I ` Operations Summary Drill f/2663' 1/2730', control drilling section to allow G &I to keep up. Excess solids building in mud pits. P/U and circ working pipe. Change out shaker screens. Clean out suction valves on #2 mud pump. Assist G &I w/ cuttings handling. P /IJ to 990' inside shoe and stab up TIW while assisting G &I. Clean cellar and BOP stack. Change additional shaker screens. Remove TIW and P/U to HWDP. TIH P/U additional 5" drillpipe. Break circ at 1740'. Trip back to shoe. Clean around rig while assisting G &I w/ cuttings handling. MW = 9.1 ppg. 1/7/2009 00:`' ' :1i 2009 00:00 z Operations Summary Assist w/ G &I on cuttings handling. R/U new tank inside tent. Service top drive. Thawing lines for injection. TIH. No hole problems. 04009 0600=1'19 "° 0:00 . Operations Summary Drill f/2730' 1/3120'. P/U 1/2988'. Repair top drive throttle. Run back to bottom. Drill f/312D' 1/3368'. Service top drive circuit breaker. Drill f/3368' 1/3777'. MW = 9.1 ppg. Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 - 06 IVAN RIVER UNIT 11 - 06 ADL032930 5028320130 LK9485 46.80 0 o perk one gam, 1/912009 00:00 - 7/10/200900;00 - Operations Summary Drill f/3777' t/5267'. MW = 9.4 ppg. •11012009 00 :00 - 1111/2009 00:00 Operations Summary Drill f/5267' t15778'. High torque. Decide to pull for bit change. Mix dry job. Circ btms up. Trip out 5 stands. Good hole conditions. Pump dry job. POOH. Tight f/4195' 1/4170', work thru w/ 20k overpull. POOH to BHA. UD BHA and bit. Bit 5/16" out of gauge. Top stabilizer 1/16" out of gauge. Mud motor stabilizer lower 1/3 out of gauge. Download MWD /LWD data. Notify AOGCC of upcoming bi- weekly BOPE test. Waived witness by Lou Grimaldi. MW = 9.5 ppg. 1/11/2009 00:00 -1/1212009 00:00` Operations Summary Pull wear bushing. Set test plug and perform BOPE test to 250/3000 psi - test OK. Run wear bushing. P/U BHA w/ new bit. TIH t/2798'. Break circ and test MWD - test OK. TIH 1/5622' w/ tight hole f/5065' t15083'. Kelly up and safety wash and roam f/5622' t/5742'. MW = 9.2+ ppg. 1/1=12009 -1 ;12` i �; t �, Operations Summary Safety wash and ream f/5742' 1/5778'. Drill f/5778' t15835'. Lose oil pressure on top drive. POOH to shoe to service top drive. Lube oil pump bad. Fly in replacement pump from North Slope. Change out pump and gear box oil. TIH. Safety wash and ream f/5742' t/5835'. Drill f/5835' t/5959'. MW = 9.4 ppg. 11 : _ i t ; 1 , 1 : 1 0.-1/14/200! >00:00 Operations Summary Drill f/5959' t16023'. Circ btms up w/ coal returns from thick coal near TD. Gas = 410 API units. Flow check - no flow. Wiper trip f/6023' t/5459'. No tight spots. Wiper trip f/5459' t16023'. No fill on btm. Mix and pump 20 bbl hi -vis sweep. Small increase in cuttings. Retumed 84 bbls late. Estimate OH excess = 30 %. Flow check - no flow. Pump dry job. POOH. UD BHA and download MWD /LWD data. Pull wear bushing. Notified AOGCC on 1/10/09 (Lou Grimaldi) of change to 9 -5/8" casing rams. P/U test joint. Install and test 9 -5/8" rams in upper ram cavity. Troubleshoot leaks. Clean out ram cavities and re- install. Test rams to 250 / 3000 psi for 5 min - test OK. UD test joint. R/U to run casing. MW = 9.5 ppg. 1/14/2009 00:0041115/20o9 '~ � vim. 4 Operations Summary Clean and clear rig floor. Monitor losses - 9 bbl /hr. R/U to run casing. P/U shoe track, test floats - test OK. RIH t/364'. Monitor losses - 7 bbl /hr. Kelly hose caught dead line and broke safety cable dropping shackle from derrick - safety standown. Remove load cell on dead line and inspect derrick. Continue RIH w/ 9 -5/8" casing t/1005'. High winds - safety standown. Monitor losses - 5 bbl /hr. Winds dying down, resume running casing. RIH 1/4330'. MW = 9.4 PPg• 5120 ; rev, i .0 -111612009 00:00 Operations Summary RIH w/ casing t15922'. Monitor losses - 2 bbl /hr. Set down and tag bridge at 5922' vy/ 15k. R/U and break circ. Wash down to casing set depth, pumping at 5 bpm. M/U landing joint and casing hanger. Land hanger and break circ. Circ at 5 bpm thru hanger flutes, no pressure /pack off observed. Circ 2 x btms up at 5 bpm. No excess cuttings seen at shaker. Stop circ and R/U cement head and cement lines. Circ and cond hole. Pump 4.5 bbls water. Test lines to 4100 psi for 5 min - test OK. Drop by -pass plug and chase w/ 0.5 bbl water. Shutdown and load shutoff plug. Mix and pump 20 bbl 11.0 ppg spacer, 156 bbl 12.0 ppg cement. Shutdown and drop shutoff plug and chase w/ 5 bbl cement. Disp ace w/ 444 bbl 9.4+ ppg mud. Slow pumps to 3 bpm at 475 psi. Bump plug at 1475 psi. Bleed off and check floats - test OK. Pressure up to 2710 psi arid shift open DV collar. Total losses during job = 7 bbl. Circ btms up thru DV collar at 6 bpm. Note increased pH in returns. Spacer and contaminated cement returns seen at surface Continue circ thru DV collar at 4 bpm while R/U to pump 2nd stage cement job. Monitor losses - 3 bbl/hr, reduced to 0 bbl /hr. 1116/200900:00 -1/17/2009 00:00 Operations Summary R/U for 2nd stage cement job. Load shut -off plug in cement head. Hook up and test cement lines 1/2500 psi - test OK. Mix and pump 20 bbl 11.0 ppg spacer, 224 bbl 12.5 ppg cement. Drop plug. Pump 5 bbl 12.5 ppg cement and displace. to 262 bbl 9.5 ppg mud. Land plug and close DV collar w/ 1200 psi over final circ pressure of 600 psi (1800 psi). No cement returns but did see increase in pH in mud retums as seen in 1st stage after circ thru DV collar. R/D cement lines. UD landing joint. Flush and clean out BOP stack. P/U packoff and running tool. Install packoff and test to 250/5000 psi for 30 min - test OK. UD packofff running tool. Set test plug. Change out upper rams from 9 -5/8" rams to 2 -7/8" x 5 -1/2" VBRs. R/U and test VBRs to 250/3000 psi for 5 min - test OK. R/D test equipment. Run wear bushing. Change out bails and UD 8" drill collars. P/U 6 -1/2" drill collars and 5" HWDP. Repair cable for driller's side tugger actuator. MW = 9.5 ppg. 11,1 . 0!0100/1812609 00;00 Operations Summary P/U 8.5" cleanout BHA. TIH P/U 5" drillpipe 1/3385'. Break circ and test csq 1/1500 psi for 10 min - test OK. Repair control cable to driller's side hoist. Clean out cement 1/3454', drill cement and DV collar f/3454' 1/3489'. Drill cement strings f/3489' 1/3509'. CBU. Test csg 1/1500 psi for 10 min - test OK. Service rig and change out top drive grabbers. Wash and ream cement f/3509' 1/4794'. 1/18/2009 00A0 y , !„ r Operations Summary Wash and ream cement f/4794' 1/5560' (cleaning cement that channeled below DV coll<Ir and swapped out w/ mud in 47 deg inclination hole). Circ and cond mud. Test csg 1/3000 psi for 10 min - test OK. Tag up at 5575'. Drill cement, shut -off plug, shut -off baffle, and clean -out to float collar at 5930'. Circ and clean hole Tegt r90 t /inns psi fnr 10 min - test QS. Drill float collar, float shoe and rathole cement 1/6023'. Drill new formation f/6023' 1/6045'. Circ and cond hole. Perform FIT to 13.6 . . • EMW 9.2+ ... mud • 0' i i psi) - test OK. POOH w/ cleanout BHA. Pull wear bushing. Test BOPE to 250/3000 psi w/ AOGCC witness Lou Grimaldi. Chevron %10 Chevron-Alaska I WO Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11-06 IVAN RIVER UNIT 11-06 ADL032930 5028320130 LK9485 46.80 3.11 1/1912 1 ..00100:A1/20/2009 00:00 , Operations Summary Continue BOPE test. Gas alarm test OK. Reset and gas alarm down. Troubleshoot gas alarm. R/D test equipment. AOGCC inspector Lou Grimaldi onsite, gave notice that we could proceed ahead but could not drill until gas alarms working properly and audible alarms for H2S and CH4 had separate tones. P/U directional BHA. Safety stand down. Dropped pipe spinners from snub line. Investigate and repair. TIH w/ directional BHA, test MWD - test OK. RIH. Service rig. RIH t/ 5600. MW = 9.3 ppg. 1/20/2009 0000 , '1121/2009 00:00 Operations Summary Nabors gas alarms replaced w/ Total Safety. Test alarms - test OK. RIH f/5600 t/5947. Break circ. Ream t/6045. Drill f/6045' t16548'. MW = 9.5 ppg. CBU. Calibrated gas alarms at shakers. Drill f/6548' 116962. MW = 9.8 ppg. 1121/2009 00:00 - 1/22/2009 00:00 Operations Summary Drill f/6962' t/7024. Standpipe pressure increase, diagnose plugged nozzles. Pumped 2ea 30 nut plug sweeps and lea 10 bbl dril-n-slide sweep. Lost 150 psi following sweeeps. Service rig and top drive. Drill f/7024' t17040. Lost hydraulic power to top drive. Circ and reciprocate pipe while troubleshooting top drive failure. Break out connection and pull to shoe. Replace wires on PLC card and test run top drive. Electrical failure on PLC. Continue troubleshoot top drive. Change pump liners in mud pumps to 5.5" liners. MW = 9.9 ppg. 1/2212009 00:00 -1/23/2009 00:00 "AV Operations Summary Continue to troubleshoot top drive. POOH w/o hydraulics on top drive. Lay down 2ea NMDC. Inspect 8-1/2 ' bit. Found 2 nozzles plugged, 1 blade packed off w/ solids. No wear and in gauge. Download MWD tools. Continue repairs on top drive. Monitor well - no losses. MW = 9.9 ppg. 1/23/2009 00:00 - 1/24/2009 00:00 Operations Sunimary Continue repairs on top drive. Complete repairs. P/U BHA. 112412009 00:00 .1/25/2009 00:00 Operations Sunimary TIH. Wash out of shoe at 6015'. Ream and work tight spots at 6050-6061, 6140-6160', 6420-6460', 6530-6550'. Continue ream to 7040' w/o problems. Drill f/7040' t/7504'. MW = 9.9 ppg. 112812009 00:00 - 1/26/2009400* Operations Summary Drill f/7504' t/7978'. Safety stand down. While reaming stand, ran link tilt into derrick board, bending derrick board and 2 fingers. Inspect and repair. Changed 2 seats and valves on #1 mud pump. Drill f/7978' 1/8012'. MW = 10.5 ppg. ,112012009 00100 `00:00 Operations Summary Drill f/8012' 1/8359'. MW = 10.1+ ppg. Drill f/8359' 1/8736'. MW = 10.0 ppg. 1/A7110:4 00:00 Operations Summary Drill f/8736' 1/9115'. MW = 10.1 ppg. Drill f/9115' 1/9461'. MW = 10.0 ppg. 1/28/2009 00:00 - 1129/2009 00:00 Operations Summary Drill f/9461' 1/9750'. MW = 10.0+ ppg. Drill f/9750' 1/10,038'. MW = 10.0 ppg. 1/29/2009 00:00 - 1/30/2009 00:00 Operations Summary Drill 1110,0381/10,060' TD. MW = 10.2 ppg. CBU x 3. No gas. Check for swabbing - OK Attempt POOH - no joy. Back ream f/9880' 1/6020' working pipe and varied flow rate to prevent packing off. CBU below casing shoe (6015'). Work pipe 1(60601/6020'. RIH f/6060' 117117'. Took weight at 7015'. Pick up and went thru. POOH f/7117' 115993'. Tight hole at 6145' and 6165'. Work back down and pulled slicked. MW = 10.0 ppg. Contacted AOGCC inspector Bob Noble by phone for upcoming BOPE test. Plan to call AOGCC engineer Jim Regg next a.m. to discuss testing before required semi-weekly due date of 2/2/09. 1/30/2009 00:00 - 1/31009 Operations Summary POOH. UD BHA. R/U to run wireline logs. RIH and tag up at 6038' WLM. Attempt to work down - no joy. POOH and remove bow spring centralizers. RIH and tag up at 6038' WLM. No overpull. Appears to be bridge. POOH. R/D wireline. R/U . .o test BOPE. Test waived by Jim Regg. Change 5" rams to 7" casing rams - no joy. 7" casing rams wrong ram bodies. Change back to 5" rams. Order new 7" casing rams. MW = 10.0 ppg. 1/31/2009 00;00 - 2/14000.00�057 ' Operations Summary Continue w/ BOPE test. Test BOPE 250/3000 psi - test OK. P/U cleanout BHA. RIH one tag up at 6125'. Set down w/ 25k, unable to work thru. Wash and ream 3' and worked thru. Pull thru w/o overpull. RIH 1/10,028'. Safety wash to 10,060'. CBU. MW = 10.0 ppg. •? +I, 109 0000 - „ „ 4 WA Operations Summary Circ clean. Pump carbide, inconclusive. Pump hi-visc walnut sweep. Returned 76 bbls late. Calculated 83% OH excess. POOH. UD cleanout BHA. R/U wireline. RIH w/ Quad combo logs. RIH and tag up at 6038 WLM. Attempt to work down - no joy. POOH and remove dipole sonic and resistivity. RIH and tag up at 6038' WLM. No overpull. Run caliper log into casing. Caliper showing large washout (>20"). POOH. R/D wireline. Pull wear bushing. Run test plug. Change 5" pipe rams to 7" casing rams. Test rams 10 250/3000 psi for 5 min - test OK. MW = 10.0 ppg. Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11 -06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 2/2/200900:00 2/3/2009 00:00 Operations Summary UD test joint and test plug. Change load sensor on top drive pipe handler. R/U to run 7" liner. M/U liner hanger assembly and UD. P/U reamer shoe. RIH w/ 7" 26# liner w/ centralizers. P/U liner hanger and RIH. CBU f/4200'. R/U to RIH on 5" HWDP and 5" drillpipe. MW = 10.0 ppg. 2/3/2009 00:<00 =- 2/412009 00:00 Operations Summary RIH on 5" drillpipe t/5885'. UD jars. M/U cement head and UD. Steam ice plugs in drillp pe. Service top drive brake actuator cylinder. Replace same but unable to repair completely. RIH on 5" drillpipe t18830'. Steam ice plugs in drillpipe. RIH on 5" drillpipe t/9991'. Wash and ream liner f/9991 t/10,002'. Circ 12.5 ppg sweep followed by red dye fluid caliper at 180 gpm, 600 psi. Unable to gauge hole (did not see at surface). Wash and ream liner f/10,002' 010,012'. MW = 10.1 ppg. 2/4/2009 00 :00 - '2/5/2009 00 :003 4, Operations Summary Wash and ream liner f/10,012'1/10,024 P/U to 10,020'. R/U cement head. Lost pipe movement (possible differential sticking). Still able to circ. Drop liner setting ball. Land on seat and pressure up to 2800 psi to set liner hanger. Pump 31 bbl '11.0 ppg spacer, 172 bbl 12.0 ppg cement (75% OH excess). Bump plug and pressure up to 2500 psi for 10 min. P/U liner hanger tool and set ZXP packer. Reverse circ above liner top. Saw increase in pH and spacer at surface, no cement. Lost 12 bbl d ring iob, RIH w/ liner tool to btm of liner seal bore. Reverse circ. R/D cement lines. Pump dry job. POOH. UD 66 jts 5" drillpipe. Service rig. MW = 10.1 ppg. 2)5/2009 00 :00 - 2/6/2009 00 :00 Operations Summary POOH. UD 5" HWDP. UD drill collars. Pull wear bushing. Run test plug. Change 7" casing rams to 3 -1/2" tubing rams. Test rams to 250/3000 psi for 5 min - test OK. Pull test plug. Run wear bushing. R/U wireline. RIH w/ Son /Neu /GR/USIT logging tools. Stopped at 5910' WLM. POOH. Found mud packed off in USIT spinner. Drop out USIT log. RIH w/ Son /Neu /GR. Stopped at 5910' WLM. POOH. R/D wireline. Move 3 -1/2" tubing to pipe racks. MW = 10.1 Peg. 2/6/2009 00:00 - 217/2009 00:00 Operations Summary Continue moving 3 -1/2" tubing to pipe racks. R/U tubing running tools. P/U muleshoe scraper. 3 -1/2" tubing. RIH. Crossover to 5" drillpipe. RIH t/7750'. Break circ and CBU. RIH 09371'. P/U 18 joints 5" drillpipe. Tag landing collar at 9931'. FUU to reverse circ. MW = 10.1 ppg. 2/7/2009 - 2/81200900:0 . z,, "` Operations Summary Reverse out mud to fresh water at 250 gpm. Service rig. POOH t/4147'. UD 2 jts of 3 -1/2" tubing. P/U stop sub and XO to tubing. RIH f/4086' t/9900'. Tag liner top w/ stop sub at 5825'. Clean and empty pits #4, #5, and #6. Haul fluids to G&I. Reverse out dirt magnet and displace w/ fresh water at 170 gpm. R/U to test casing and liner. Test 9 -5/8" and 7" liner U 2500 psi for 30 min - test OK. Clean pits #1, #2, #3 for displacing well. Water = 8.4 ppg. 2/8/2009 00 :00 - 2194009 00:00 Operations Summary Continue cleaning pits. Mix 380 bbl 6% KCI in pits #4, #5, and #6. Reverse out fresh water to 6% KCI at 210 gpm. Service rig. POOH UD upper scraper and XO's. Rack back drillpipe. POOH UD btm scraper and mule shoe. Rack back 3 -1/2" tubing. R/U wireline. RIH w/ USIT (cement evaluation) to 9900; WLM. Log 7" liner cement f/9900' t/5900' WLM. Cement coverage poor to good. TOC at6143' WLM. POOH w/ USIT. 6% KCI = 8.6 ppg. lifOrios 00:oo - 2/10/2009 00:00 34 n „ Operations Summary RIH w/ Neu /Son /GR logging tools. Log 7" liner to liner top. Service rig. Staging and strap completion equipment. RIH w/ TCP guns, 3 -1/2" tubing. M/U SC -2 packer w/ setting tool. RIH on 3 jts of 3 -1/2" tubing, 8 -1/4" stop sub crossed over to 5" drillpipe. Tag top of liner w/ stop sub at 5825'. P/U and space out. TCP guns placed f/9698' t/9545'. Packer at 5914'. Drop setting ball and perform setting procedure w/ test pump. KCI = 8.6 ppg. 2/10/2009 00:00 - 2/114009 . �. M •... ;' :. � Operations Summary Continue setting procedure for SC -2 packer. Test annulus to 500 psi for 5 min to confirm packer set - test OK. Pull and push 20k on packer to confirm set. Test annulus to 2500 psi for 30 min - test OK. Setting tool released. POOH. UD 5" drillpipe and packer setting tool. Stand back 1 stand 3 -1/2" tubing. Pull wear bushing. Install spacer sleeve bushing across 7" casing spool. Test seals to 5000 psi for 15 min - test OK. UD bushing setting tool. P/U seal assembly. RIH w/ seal assembly on 3 -1/2" IBT -Mod 9.2# L -80 tubing. Drift tubing to 2.8137" ID. KCI = 8.6 ppg. 01112009 40:00 - 2/12/200990:00 ` ;'' ' " 1%13 Operations Summary RIH w/ 3 -1/2" tubing. Tag top of packer at 5915' RKB. Enter seal assembly and land out locator on top of packer. Fnd of seal assemhly at 592R' RKR Close annular, pressure test to 500 psi, no returns up tubing, confirm seals in sealbore. Bleed off pressure. P/U out of sealbore t15889'. Displace 6% KCI to fresh water. Space out and M/U parent hanger. Land hanger and run lock down screws. Test hanger seals to 5000 psi for 15 min - test OK. Pressure test down tubing to 2500 psi for 30 min - test OK. R/D test equipment. UD landing joint. R/U to run 2 -3/8" heater string RIH w/ 2 -3/8" heater string w/ mule shoe cut on end of bottom joint. Drift heater string to 1.875 ". M/U mandrel and land in parent hanger and 1/4 turn to right to j -lock. Pull test to verify locked. UD landing joint. In stall TWC in both strings. Fill BOPE w/ water. Close blind rams. Open annulus. Test 2 -3/8" mandrel seals to 2500 nsi for 15iin - test OK Start cleaning pits and cuttings tank. Clean and clear rig floor. N/D BOPE. Lift threads are 3.725" MCA and 3.160" MCA. BPV profiles are 3" H -BPV and 2" H -BPV. Fresh water = 8.4 ppg. 6% KCI = 8.6 ppg. 2/12/2009 00.00.2%13/2009 00:00 , T . `_ . Operations Summary N/D BOPE. N/U tree. Test adapter seals 250/5000 psi for 30 min - test OK. Test tree valves on both strings to 250/5000 psi for 30 min - test OK. Freeze protect long string. Displace water w/ diesel. Displace heater string and annulus too to diesel w/ 7 hbl diesel. Prep for rig move to Stump Lake sidetrack (SLU 41- 33RD). • • Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) IRU 11-06 IVAN RIVER UNIT 11 -06 ADL032930 5028320130 LK9485 46.80 . . {. ? 2/13/2009 0000 2/14/2009 Operat ons Summary R/D for rig move to SLU 41 -33RD. ***Final Report for IRU 11 -06 "'. 2/18/2009 00:00 - 2/18/2009,00 :00 Operations Summary R/U Pollard Wireline to shift "Durasleeve" Sliding sleeve at 5,970' to open position. RD wireline. 1,q1111I :T A-LIMEA SARAH PALIN, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy Brandenburg Drilling Manager Unocal PO Box 196247 Anchorage AK 99519 Re: Ivan River Field, Undefined Gas Pool, IRU 11 -06 Sundry Number: 309 -090 Dear Mr. Brandenburg: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, „S '/ Daniel T. Seamount, Jr. Chair DATED this / day of March, 2009 Encl. Chevron Francisco Castro Chevron North America Exploration and Production Technical Assistant 3800 Centerpoint Dr. Suite 100 41.0 Anchorage, AK 99503 Tele: 907 263 7844 Fax: Fax: 907 263 7828 E -mail: fcbn @chevron.com ' y ` DATE February 26, 2009 t To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste #100 _ • Anchorage, AK 99501 t1 4 1' DATA TRANSMITTAL it FORMATION EVALUATION DIPOLE IRU 11 -06 SONIC DSI -GR 5" 1- Feb -09 5800 -6000 ES -1 1 1 LAS, PDS PLATFORM EXPRESS DLIS, LAS, IRU 11 -06 DIPOLE SONIC 5" 1- Feb -09 5800 -6040 1 1 1 PDS PROCESSED DIPOLE 1- Feb -09 - IRU 11 -06 SONIC 2" 8- Feb -09 5650 -9900 1 1 1 LAS, PDS 101r - it L i I'9 6 / X633 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 263 7828. Received 8y: f ;' Date: Ivan River Unit IRU 11 -06 (P1208 -184) Logging Program Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, February 04, 2009 2:07 PM To: 'PORHOLA, STAN T' Subject: RE: Ivan River Unit IRU 11 -06 (PTD 208 -184) Logging Program You had mentioned this morning about the difficulties being encountered. That is a pretty big washout below the shoe. It would appear that you have some open hole information from the LWD and that you will gather additional information cased hole. I will place a copy of this message in the file. Nothing further is needed. Tom Maunder, PE AOGCC From: PORHOLA, STAN T [ mailto :stan.porhola ©chevron.com] Sent: Wednesday, February 04, 2009 1:37 PM To: Maunder, Thomas E (DOA) Subject: Ivan River Unit IRU 11 -06 (PTD 208 -184) Logging Program Tom, We were unable to get our open hole logging tools below 6038' WLM (approximately 25' below the 9 -5/8" casing shoe at 6018' MD). We did gather log data above this point and into the casing. The caliper showed a large washout below the casing shoe as large as 28" (8 -1/2" hole drilled). We were unable to procure logging tools for running on drillpipe (Weatherford's Compact Shuttle) before making the decision to run the 7" liner. Our current plan forward is to run the same open hole logging tools in casing in combination with our USIT cement log. We hope to gather useable Neutron, Sonic and Gamma Ray data thru casing from the logging tools. The interval was drilled w/ LWD Gamma Ray and Resistivity. Stan Porholas Drilling Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 Cell 907 229 1769 stan.porhola @chevron.com mad C . onficlentiai hooter Privileged /Confidential information may be contained in, or attached to, this message. If you are not the addressee indicated in this message (or responsible for delivery of the message to such person), you may not copy, forward, disclose, deliver, or otherwise use this message or any part of it in any form whatsoever, If you receive the message in error, you should destroy this message after notifying me immediately by replying to the message or contacting me at (907) 263 - 7640. 2/9/2009 Changes to 9 -5/8" Cement Prm Ivan River IRU 11 -06 (PTD: 208) Page 1 of Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, January 14, 2009 2:16 PM To: 'PORHOLA, STAN T' Cc: Bonnett, Nigel (Nigel.Bonnett); Harness, Evan Subject: RE: Changes to 9 -5/8" Cement Program Ivan River IRU 11 -06 (PTD: 208 -184) Stan, et al, Thanks for the updated information. You all know better how the cement jobs should be optimized. From the information in your attachment, it appears that you are incorporating the information gathered and experienced while drilling the intermediate section. That in my assessment is being a prudent operator. Good luck with the operations. Tom Maunder, PE AOGCC From: PORHOLA, STAN T [mailto:stan.porhola @chevron.com] Sent: Wednesday, January 14, 2009 1:56 PM To: Maunder, Thomas E (DOA) Cc: Bonnett, Nigel (Nigel.Bonnett); Harness, Evan Subject: Changes to 9 -5/8" Cement Program Ivan River IRU 11 -06 (PTD: 208 -184) Tom, Attached are proposed changes to our 9 -5/8" cement program for Ivan River IRU 11 -06 (PTD: 208 -184). The significant changes were to the volumes and slurry design of the 2nd stage. The 2nd stage cement slurry is the same as the 1st, except it has less mix water and CaCl2 added as an accelerator. We are currently running casing w/ static losses from 7 to 9 bbl /hr. The top of the lower Sterling disposal zone (permitted for Class II well IRU 13 -31 PTD: 192 -088) is at about 5080' MD / 4277' TVD (about 5' deeper than prognosis). «9 Cement Program 11 -06 rev2.doc» «Int Casing Cmt Job Schematic v2.xls» Stan Porhola•• Drilling Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 Cell 907 229 1769 stan.porhola@chevron.com Mail Confidential Footer 1/14/2009 • • Chevron Ivan River Unit %10 IRU 11 -06 Gas Well Cement Program 9 -5/8" Casing (12 -1/4" Hole to 6,023' MD): 1 Stage Changes from previous submittal: 1.) Depths corrected to actual, hole TD is 6023'MD, plan to land casing at 6016' MD. 2.) Shoetrack length increased from 80' to 126' w/ 5 bbl cement left on top (66' above top of shoe track). 3.) Top of cement changed from 4600' MD to 4100' MD to increase chances of isolating the lower Sterling disposal zone. The top of the zone is at 5080' MD. We are currently seeing losses from 7 — 9 bbl /hr. 4.) Changes to yield, mix water required, and thickening time. The estimated total volume is as follows: Ratehole: 7' X 0.8185 cuft/ft (12 -1/4" x 9 -5/8 ") X 1.4 = 8 cuft = 4 sxs (2.27 yield) OH: 1916' X 0.3132 cuft/ft (12 -1/4" x 9 -5/8 ") X 1.4 = 840 cuft = 370 sxs (2.27 yield) Shoe track: 192' X 0.4257 cuft/ft = 82 cuft = 36 sxs (2.27 yield) TOTAL: 8 + 840 + 82 = 930 cuft or 410 sxs 2" Stage Changes from previous submittal: 1.) Shoetrack length increased from 20' to 100' w/ 10 bbl cement left on top (132' cement left above DV collar in the 9- 5/8 ") 2.) Increased the amount for openhole excess from 40% to 50% for the shallower depths. 3.) Cement slurry density changed from 12.0 ppg to 12.5 ppg. 4.) Changes to density, yield, mix water required, thickening time, and added CaCl 5.) Previous casing string (13 -3/8 ") at 1016' MD. The estimated total volume is as follows: OH: 2484' X 0.3132 cuft/ft (12 -1/4" x 9 -5/8 ") X 1.5 = 1167 cuft = 583 sxs (2.00 yield) Csg x Csg: 116' X 0.3354 cuft/ft (12 -1/4" x 9 -5/8 ") = 39 cuft = 20 sxs (2.00 yield) Shoe track: 132' X 0.4257 cuft/ft = 56 cuft = 28 sxs (2.00 yield) TOTAL: 1167 + 58 + 56 = 1262 cuft or 631 sxs 9 Cement Program 11 -06 rev2.doc 1 1/14/2009 • • Chevron Ivan River Unit %100 1%0 IRU 11 -06 Gas Well Cement Program Cement Type and Design: Intermediate Casing, 9 -5/8 ", 1 Stage Cement Type: Class G Density: 12.0 ppg Cement: 410 sx Yield: 2.27 ft /sx Mix Water: 9.84 gal /sx Slurry Volume: 166 bbl Thickening Time (70 Bc): 4:32 hrs Additives: BA -90 15.000% BWOC Silica Static Free 0.500% BWOC Anti - Static FL -63 1.200% BWOC Fluid Loss Additive CD -32 1.000% BWOC Dispersant FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 0.300% BWOC Accelerator LW -7 -6 10.000% BWOC Light- weight additive Intermediate Casing, 9 -5/8 ", 2 Stage Cement Type: Class G Density: 12.5 ppg Cement: 631 sx Yield: 2.00 ft /sx Mix Water: 7.80 gal /sx Slurry Volume: 225 bbl Thickening Time (70Bc): 4:18 hrs Additives: BA -90 15.000% BWOC Silica Static Free 0.500% BWOC Anti - Static FL -63 1.200% BWOC Fluid Loss Additive CD -32 1.000% BWOC Dispersant FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 0.300% BWOC Accelerator LW -7 -6 10.000% BWOC Light- weight additive CaCl 2.000% BWOC (Pre- hydrated) 9 Cement Program 11 -06 rev2.doc 2 1/14/2009 • • IRU 11 -06 Chevron Intermediate Casing 2 -Stage Cement Job 13.375 in Csg 68.00 IbrrVft 1016 ft TOC - Tail 900 ft Ll 12.250 in 50% Excess 3500 ft Yield = 2.00 ft /sx Density = 12.5 ppg Cement = 631 sx 1 TOC DV 3368 ft Tail DV Collar 224.76 bb! 3500 ft 12.250 in 40% Excess --- II II 6023 ft TOC - Lead Yield = 2.27 ft 4100 ft Density = 12.0 ppg Cement = 410 sx / / Lead , --- 165.60 bbl al TOC 9 -518" / 5824 ft 1 9.625 in Csg 40.00 bin/ft 6016 ft / Ivan River IRU 11 -06 (PTD 2.184) Revised Kick Tolerance • Page 1 of 1 Maunder, Thomas E (DOA) From: PORHOLA, STAN T [stan.porhola @chevron.com] Sent: Wednesday, December 31, 2008 11:14 PM To: Davies, Stephen F (DOA); Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: Santos, Ronilo; Rasch, Brad J; Farrell, Robert [Alaska Pipe Recovery]; Bonnett, Nigel (Nigel.Bonnett); Bowe, Satch [F G C Safety & Logistics]; Brandenburg, Tim C; Bush, Dean A [Peak]; Dunn, Tom [ASRC]; Harness, Evan; Leslie, Mike; Menapace, Michael Sam; Schadle, alva G. [Peak Oilfield Services] Subject: Ivan River IRU 11 -06 (PTD 208 -184) Revised Kick Tolerance Attachments: IRU 11 -06 KT 11.8 & 13.6LOT.xls Gentlemen, — \ a We've drilled out our 13 -3/8" surface casing shoe and performed a LOT /FIT test for IRU 11 -06 (PTD 208 -184). The results of the test was a leak -off at 11.8 ppg EMW at a shoe depth of 1016' MD/TVD. Offset Ivan River wells have Teak -off tests at depths of +/- 900' TVD of 11.3, 23.5, and 26.0 ppg EMW. In the approved PTD, the LOT /FIT was estimated to be a 12.8 ppg EMW, giving a 10 bbl kick tolerance. With a 11.8 ppg EMW LOT, our kick tolerance will be down to 5.9 bbl. The kick tolerance calculations assume a swabbed gas kick w/ a kick intensity equal to the planned mud weight of 10.0 ppg. Our anticipated maximum pore pressure in this interval is 8.7 ppg EMW. We believe that our calculations are fairly conservative and a 10.0 ppg intensity kick is highly unlikely.Therefore, the interval can be drilled safely with a kick tolerance of 5.9 bbl. Please see the attached kick tolerance calculations. If you have any questions, please feel free to use the contact info below. «IRU 11 -06 KT 11.8 & 13.6LOT.xls» Stan Porhola• • Drilling Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 Cell 907 229 1769 stan.porhola@chevron.com Mail Confidential Footer Privileged /Confidential information may be contained in, or attached to, this message. If you are not the addressee indicated in this message (or responsible for delivery of the message to such person), you may not copy, forward, disclose, deliver, or otherwise use this message or any part of it in any form whatsoever. .11 you receive the message in error, you should destroy this message after notifying me immediately by replying to the message or contacting me at (907) 263 - 7640. 1/5/2009 • UNOC.AL T '`< GENERAL INPUT DATA Field Ivan River Well Name 11 -06 RT -MSL 16.8 ft Water Depth 0 ft Sea Water Gradient 0.447 psi /ft Casing Size to be Designed 9 -5/8 inch Hole Size Drilled for This Casing 12 -1/4 inch DESIGN METHOD 1: From TD up to find the shallowest allowable shoe depth Hole Size Below the Shoe 8 -1/2 inch Next Section Total Vertical Depth 8,168 ft TVD RKB Next Section Total Vertical Depth 8,151 ft TVD BML Next Section Gas Gradient (first approximation: 0.075) 0.100 psi /ft Kick Intensity (Swab kick = 0.0 ppg intensity) 0.5 PPG Mud Weight 10.6 PPG Estimated Formation Pressure at Next Section TD 11.1 PPG EMW Fracture Gradient 0.71 psi /ft Kick Tolerance 20.0 bbl Drill Pipe Outside Diameter 5 inch 'Calculation results acceptable. Minimum shoe depth = 3,713 ft TVD RKB 1 DESIGN METHOD 2: From upper casing shoe down to find the deepest t hole which can be drilled without S PP 9 P fracturing the upper casing shoe Upper Casing Size 13 -3/8 inch Upper Casing Shoe Depth 1,016 ft TVD RKB Upper Casing Shoe Depth 999 ft TVD BML Upper Gas Gradient (first approximation: 0.008) 0.100 psi /ft Hole Size below the Upper Casing Shoe 12 -1/4 inch Kick Intensity (Swab kick = 0.0 ppg intensity) 0.0 PPG Mud Weight 10.0 PPG Estimated Formation Pressure 10.0 PPG EMW Fracture Gradient 0.61 psi /ft Kick Tolerance 5.9 bbl Drill Pipe Outside Diameter 5 inch 'Calculation results acceptable. Maximum shoe depth = 4,991 ft TVD RKB 1 mdb /03jan01 • Ivan River 11 -06 UINIOCAL 573 9-5/8" SHOE DESIGN SUMMARY & SKETCH METHOD 2: METHOD 1: • RT - MSL = 16.8 ft • WD = 0 ft with 0.447 PSI /FT Gradient DESIGN DOWN: 13 -3/8" shoe MW = 10 PPG 999 ft BML, Pform = 10 PPG EMW 13 -3/8" shoe, (1,016 ft TVD) \ KT = 5.9 BBLS at O PPG / FG = 0.6136 PSI /FT \ Gas Gradient = 0.1 PSI /FT / Drill Pipe = 5 INCH 12 -1/4" Hole / / The shallowest 9-5/8" shoe depth = 3,696 ft BML or 3,713 ft TVD / \ \ / / \ \ / The deepest 12 -1/4 in hole that can be drilled = / 4,974 ft BML or 4,991 ft TVD \ DESIGN UP: / MW = 10.6 PPG Pform = 11.1 PPG EMW 8 -1/2" Hole _ / KT = 20 BBLS at 0.5 PPG \ FG = 0.707 PSI /FT / Gas Gradient = 0.1 PSI /FT \ Drill Pipe = 5 INCH TD = 8,151 ft BML or8,168ft 'TVD / mdb /01 dec00 CASING DESIGN CALCULATION GENERAL DATA: Field Name Ivan River Well Name 11 -06 Casing Size to be Designed 9 -5/8 in Water Depth 0 ft RT -MSL 16.8 ft Gas Gradient 0.1 psi /ft Sea Water Gradient 0.447 psi /ft METHOD 1. FROM TD UP To calculate the shallowest casing shoe depth. 1.A. DATA Hole Size Drilled Below the Shoe 8 -1/2 in Total Vertical Depth 8168 ftTVD Estimated Formation Pressure at TD 11.1 ppg Mud Weight 10.6 ppg Fracture Gradient 0.707 psi /ft Kick Tolerance 20 bbls Drill Pipe Outside Diameter 5 in 1.B. BOTTOM HOLE PRESSURE = 0.052 *Pform *TVD = 0.052 * Pform * (TVD) = 0.052 * 11.1 * (8168) =I 4715 'psi 1.C. FRACTURE PRESSURE AT SHOE = (FG * Shoe Depth) + (SW Grad * WD) = (0.707 * Shoe Depth) + (0.447 * 0) But shoe depth is unknown (it is the one to be calculated), so the iteration calculation begin: First try: Shoe Depth = 3690.9 ft BML Calculation continued: (0.707 3690.89205501852 + 0.447 0) =I 2609 'psi 1.D. GAS VOLUME WHEN IT REACHES THE SHOE Kick Volume at TD = 20 bbls P1 V1 = P2 V2 Pshoe Vshoe = Ptd Vtd Vshoe = Ptd Vtd Pshoe Since we don't want to fracture the shoe, the design criteria should be: Pfluid at shoe < Pfrac The shallower the shoe depth (the farther away from TD), the more gas expansion volume at the shoe from the kick at TD, and the more chance to frac the shoe because Pfluid at shoe is higher and getting closer to Pfrac. • • Therefore, the shallowest shoe depth is calculated at the limit condition when Pfluid at shoe = Pfrac. Thus: Vshoe = Ptd Vtd where Pressures are in psia Pfrac _ (4715 + 14.7) * 20 (2609 + 14.7) =1 36 I bbls 1.E. ANNULAR CAPACITY = Dh ^2 - Dp ^2 1029.4 = 8.5 1 %2 - 5 ^2 1029.4 =1 0.0459 I bbl /ft 1.F. CALCULATE % GAS VOLUME AT SHOE = Vol Gas in DP annular at shoe Total Annular Vol below shoe Vshoe (TVD -Shoe Depth BML -WD -RT to MSL) * Annular Capacity 36 (8168 - 3690.89205501852 - 0 - 16.8) * 0.0459 =I 17.58% I 1.G. FLUID GRADIENT = (% Gas * Gas Gradient) + (% Mud * Mud Gradient) = (% Gas * Gas Gradient) + [(1 - % Gas) * MW * 0.052] = (0.1758 * 0.1) + [(1 - 0.1758) * 10.6 * 0.052] =1 0.4719 I psi /ft 1.H. CALCULATE THE SHALLOWEST SHOE DEPTH Design Criteria: Pfluid at shoe =< Pfrac To calculate the shallowest/minimum shoe depth as discussed in 1.D: Pfluid at shoe = Pfrac BHP - Fluid Hydrostatic = FG * Shoe ftBML + SW Grad * WD BHP - Fluid Grad(TVD - Shoe ftBML - WD - RT to MSL) = FG * Shoe ftBML + SW Grad * WD BHP -FI Grad *TVD +FI Grad *Shoe ftBML +FI Grad *WD +FI Grad *RT to MSL = FG * Shoe ftBML + SW Grad * WD BHP -FI Grad *TVD +FI Grad *WD +FI Grad *RT to MSL -SW Grad *WD = FG *Shoe ftBML - FI Grad *Shoe ftBML BHP -FI Grad(TVD-WD-RT to MSL) -SW Grad *WD = (FG - FI Grad) Shoe ftBML Shoe ftBML = BHP -FI Grad * (TVD -WD -RT to MSL) -SW Grad * WD FG - Fluid Grad = 4715 - 0.4719 * (8168 - 0 - 16.8) - 0.447 * 0 0.707 - 0.4719 =13694 IftBML 1.J. ITERATION CALCULATION: Since the first trial shoe that we input (3690.89205501852 ftBML) is not the same as the output shoe (3694 ftBML), we try the same calculation again until both numbers are very close, and the results are presented in the table below: • • SHOE 3691 3694 3695 3696 P fracture 2609 2612 2612 2613 Gas Volume 36 36 36 36 % Gas 17.61 17.61 17.60 17.60 Fluid Gradient .4718 .4718 .4718 .4718 SHOE 3697 3696 3696 3696 Average 3694 3695 3696 3696 3696 0 0 0 3696.1 0 0 0 0 0 0 0 Thus, the 9 -5/8" casing shoe can be set minimum at 3696 ftBML. This is the shallowest shoe depth at which we still can contain 20 bbls kick volume at TD of 8168 ftTVD without fracturing the shoe. • . METHOD 2. FROM THE PRESET UPPER CASING SHOE DOWN To calculate the deepest casing shoe depth. 2.A. DATA Casing Size to be Designed 9.625 in Hole Size Drilled for This Casing 12.25 in Estimated Formation Pressure 10 ppg Mud Weight 10 ppg Fracture Gradient 0.6136 psi /ft Kick Tolerance 5.9 bbl Upper Casing Size above This Hole 13.375 in Upper Casing Shoe Depth 1016 ftVD = 999.2 ft BML Drill Pipe Outside Diameter 5 in 2.B. FRACTURE PRESSURE AT UPPER SHOE = FG * Shoe Depth BML + SW_Grad * WD = 0.6136 * 999.2 + 0.447 * 0 =1 613 'psi 2.C. BOTTOM HOLE PRESSURE AT SHOE DEPTH = 0.052 * Pform * SSD = 0.052 * Pform * (TVD ) But the TVD is unknown (it is the one to be calculated), so the iteration calculation begin: First try: TVD = 5250 ft Calculation continued: = 0.052 * Pform * (TVD ) = 0.052 * 10 * (5250) _' 2730 psi 2.D. GAS VOLUME WHEN IT REACHES THE UPPER SHOE Kick Volume at TD = 5.9 bbls P1 V1 = P2 V2 Pshoe Vshoe = Ptd Vtd Vshoe = Ptd Vtd Pshoe Since we don't want to fracture the upper shoe, the design criteria should be: Pfluid at upper shoe =< Pfrac The deeper the hole drilled below the shoe (the farther away the TD from the shoe), the more gas expansion volume at shoe from the kick at TD, and the more chance to frac the formation below the shoe because Pfluid at shoe is higher and getting closer to Pfrac. Therefore, the deepest hole can be drilled below the upper shoe is calculated at the limit condition when: Pfluid at upper shoe = Pfrac. • • Thus: Vshoe = Ptd Vtd , where Pressures are in psia Pfrac = (2730 + 14.7) *5.9 (613 + 14.7) =I 26 Ibbls 2.E. ANNULAR CAPACITY = Dh ^2 - Dp ^2 1029.4 = 12.25 ^2 - 5 1 '2 1029.4 =I 0.1215 Ibbl/ft 2.F. CALCULATE % GAS VOLUME AT SHOE = Vol Gas in DP annular at shoe Total Annular Vol Below Shoe Vshoe (TVD -Shoe Depth BML -WD -RT to MSL) * Annular Capacity 26 (5250 - 999.2 - 0 - 16.8)* 0.1215 =I 5.01% 2.G. FLUID GRADIENT _ (% Gas * Upper Gas Gradient) + (% Mud * Mud Gradient) = (% Gas * Upper Gas Gradient) + [(1 - % Gas) * MW * 0.052] = (0.0501 * 0.1) + [(1 - 0.0501) * 10 * 0.052] =1 0.4990 psi /ft 2.H. CALCULATE THE DEEPEST CASING DEPTH Design Criteria: Pfluid at shoe < Pfrac To calculate the deepest hole can be drilled below the upper shoe as discussed in 2.D: (which will become the deepest casing shoe depth we want to find) Pfluid at shoe = Pfrac BHP - Fluid Hydrostatic = Pfrac BHP -Fluid Grad(TVD -Shoe BML -WD -RT to MSL) = Pfrac 0.052 * Pform*TVD -FI Grad *TVD +FI Grad *Shoe BML +FI Grad *WD +FI Grad *RT to MSL = Pfrac 0.052 * Pform*(TVD) -FI Grad *TVD +FI Grad(Shoe BML +WD +RT to MSL) = Pfrac 0.052 * Pform*TVD -FI Grad *TVD +FI Grad(Shoe BML +WD +RT to MSL) = Pfrac TVD(0.052 *Pform -FI Grad) = Pfrac -FI Grad(Shoe BML +WD +RT to MSL) TVD = Pfrac - FI Grad(Shoe BML +WD +RT to MSL) 0.052 *Pform - FI Grad = 613 - 0.49896 * (999.2 + 0 + 16.8) 0.052 * 10 - 0.49896 =1 5461 1 ft • • 2.J. ITERATION CALCULATION: Since the first trial TVD that we input (5250 ftBML) is not the same as the output TVD (5461 ftBML), we try the same calculation again until both numbers are very close, and the results are presented in the table below: TVD 5250 5042 5002 4993 4991 BHP 2730 2622 2601 2596 2596 Gas Volume 26 25 25 25 25 % Gas 5.01 5.07 5.08 5.08 5.08 % Gas 5.01 5.07 5.08 5.08 5.08 Fluid Gradient .4989 .4987 .4987 .4987 .4987 TVD 5042 5002 4993 4991 4991 4991 0 0 0 0 4991.1 0 0 0 0 0 0 0 The deepest shoe depth =14991 (ft VD = 4991 - WD - RT to MSL = 4991 - 0 - 16.8 = 4974.2 Ift BML Thus, the 9 -5/8" casing shoe can be set maximum at 4974.2 ftBML. This is the deepest shoe depth at which we still can contain 20 bbls kick volume at this depth and can circulate the kick out without fracturing the upper casing shoe at 999.2 ftBML. 3. CONCLUSION From Method 1 and 2, it can be concluded that 9 -5/8" casing shoe can be set anywhere from minimum 3696 ft BML to maximum 4974.2 ft BML. (or from minimum 3712.8 ft VD to maximum 4991 ft VD) IRU 11 -06 PTD 208 -184 Top Cement Job Page 1 of 1 • • Regg, James B (DOA) p - im_ From: Harness, Evan [eharness @chevron.com] Sent: Sunday, December 28, 2008 8:28 AM l q i Z (Z`i iZeO To: Regg, James B (DOA); aogcc _prudhoe_bay @admin.state.ak.us; Fleckenstein, Robert J (DOA) Cc: PORHOLA, STAN T; Bonnett, Nigel (Nigel.Bonnett); Brandenburg, Tim C Subject: IRU 11 -06 PTD 208 -184 Top Cement Job Took us a while - Ran in16" by 13 3/8" annulus with 3/4" pipe had a good tag - Tripped out to check for indications of cement - We did not have a cement core in the end of pipe - Did have a few joints bent on btm from spudding - Re -ran 3/4" pipe (note had to trip out ounce due to getting 3/4" pipe plugged - Ran to 200' rkb in 16" by 13 3/8" annulus - Another good tag - Cemented with 38bBI class "G" with 3% KCL - Had cement back to surface with 30BbI pumped (Cal vol =28.7) - POH with 3/4" = Cement fell a total of 3' below cellar btm - Start nipple up of BOP Evan K. Harness Drilling Superintendent Chevron Anchorage Office 907 263 7932 Cell 907 229 3592 Home 907 333 2228 Email eharness @Chevron.com 12/29/2008 1 s irfaasEA SARAH PALIN, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 COMMISSION CONSERVATION ANCHORAGE, ALASKA 99501 -3539 CONSERVATION V ►7 PHONE (907) 279 -1433 Tim Brandenburg FAx (907) 276 -7542 Drilling Manager Unocal PO Box 196247 Anchorage AK 99519 Re: Ivan River Unit, Undefined Gas, IRU 11 -06 Unocal Permit No: 208 -184 Surface Location: 585' FSL, 630' FEL, SEC. 01, T13N, R9W, SM Bottomhole Location: 240' FNL, 402' FWL, SEC. 06, T13N, R8W, SM Dear Mr. Brandenburg: Enclosed is the approved application for permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Unocal assumes the liability of any protest to the spacing exception that may occur. 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. When providing notice for a representative of the Commission to witness any required test, contact the Commissions petroleum field inspector at (907) 659 -3607 (pager). Sincerely, 4111 p- ,v Daniel T. Seamount, Jr. Chair DATED this � day of December, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. • '. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMI SION PERMIT TO DRILL 4,a ( 20 AAC 25.005 la. Type of Work: lb. Current Well Class: Exploratory ❑ Development Oil ❑ lc. Specify if well is proposed for: Drill isi . Redrill ❑ Stratigraphic Test ❑ Service ❑ Development Gas • 0 Coalbed Methane ❑ Gas Hydrates ❑ Re -entry ❑ Multiple Zone ❑ Single Zone • El Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket El Single Well ❑ 11. Well Name and Number: Chevron (Union Oil Company of California) Bond No. 61S10 CM j>ep$163S'• IRU 11 -06 • 3. Address: 6. Propose epth: 15 12. Field /Pool(s): PO Box 196247, Anchorage, Alaska, 99519 MD: 9951 TVD: 8168 Ivan River Unit 4a. Location of Well (Governmental Section): 7. Property Designation: Undefined Gas Surface: 585 FSL, 630' FEL, Sec 01, T13N, R9W, SM • ADL- 032930 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1853 FNL, 993' FEL, Sec 01, T13N, R9W, SM N/A • 12/17/2008 Total Depth: 9. Acres in Property: 14. Distance to Nepreet 240 FNL, 402' FWL, Sec 06, T13N, R8W, SM • 1278 Property 3 / 1.9722E d4 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 4s46 • V f 013 L- 15. Distance to Nearest.WeIf •t Surface: x- 359,785 y- 2,646,275 • Zone- ASP 4 (Height above GL): 16.4 feet Within Pool: 510 /1'2' 16. Deviated wells: Kickoff depth: 1100 feet ' 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 46 degrees • Downhole: 3594 ' Surface: 2984 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20 133 H -40 Weld 173 0 0 173 173 Driven (not cemented) 16 13 -3/8 68 L -80 BTC 1000 0 0 • 1000 1000 165 bbls (100% excess) 12 -1/4 9 -5/8 40 L -80 BTC 6018 0 0 • 6018 4916 180 bbls (40% excess) w/ DV 8 -1/2 7 26 L -80 BTC -Mod 4083 5868 4812 ' 9951 8168 127 bbls (35% excess) 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor /Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ❑ BOP Sketch 0 Drilling Program El Time v. Depth Plot is Shallow Hazard Analysis ❑ Property Plat El Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program Ell 20 AAC 25.050 requirements ID 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Stan Porhola Printed Name Tim Brandenburg Title Drilling Manager Signature 5Phone 263 -7640 Date 11/26/2008 Commission Use Only Permit to Drill -- ZQ J API Number: 2 � _ P rmi App oval See cover letter for other Number: 8 / 50- 2.�.,,) � te: 1 • 1 0 To requirements. If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:[✓ Conditions of approval : Samples req'd: YesE No 121 Mud log req'd: Yes No[' 3000 iz,, L v-0_,....\-e.-,A- H measures: Yes❑ No l2r Directional svy req'd: Yes[ No❑ Other: APPROVED BY THE COMMISSION / D DATE: '�� , COMMISSIONER Fo 10 401 Revised 12/2005 ! + D Submit in plicate r 1 • Chevron Timothy C Brandenburg Union Oil Company of California 4101 Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 %O. Tel 907 263 7657 Email brandenburgt @chevron.com November 26, 2008 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7 Avenue Anchorage, Alaska 99501 L Re: Permit to Drill 10 -401 Ivan River Unit, IRU 11 -06 Gas Development Well Dear Commissioner: Enclosed for your approval is a completed Permit to Drill (form 10 -401) for the Ivan River Unit IRU 11 -06 Gas Development Well. We would like to request a variance from requirements of 20 AAC 25.035(e)(1)(A), requiring BOPs for each size of — tubing to be run in the well. We are planning to run a 4 preventer stackup. From top to bottom, we will run an annular preventer, variable rams, blind rams, pipe rams. The long string will be 3 -1/2" and the heater string will be 2 -3/8 ". The heater string will be run after the 3 -1/2" long string is run, the packer set and the annulus isolated from the well below. The liner will not be perforated prior to this point and the annular preventer would be able to close in on the 2 -3/8" if necessary. Therefore, running of the heater string separately w/o a 2 -3/8" pipe ram should not present a risk to well control. There are several wells on the Ivan River pad. Based on our proposed wellpath, our closest approach will be to the Ivan River IRU 44 -01. We are planning to utilize MWD w/ inclination and azimuth to steer our well away from this offset vertical well. Other wells also show close approaches but only come as close as 180' as in the IRU 14 -31 well. . Schlumbergers proximity reports show that based on the uncertainities of the offset directional survey, the well path may not exactly be located as indicated. However, we will take several precautions while drilling near these close approaches including watching returns for cement and/or metal and monitoring offset well pressures in case of collision. We plan to use Rotary Steerable BHAs w/ MWD for our directional hole sections, therefore the risk of collision should be minimal. We are targeting a spud date of December 17 Therefore, your earliest attention to this application will be greatly appreciated. If additional information is required, please contact either myself or Mr. Stan Porhola at 263 -7640. Sincerely, / 1011" ./1 —....... Timothy C. Brandenburg Drilling Manager TCB: stp Attachments: PTD Package Cc: Well File Engineer File – Stan Porhola Environmental – Rich Vicente i i , \ Union Oil Company of California / A Chevron Company http: / /www.chevron.com • • Chevron Ivan River Unit IRU 11 -06 Gas Well Drilling Procedure Summary 1. Prepare location. Drill and drive 20" conductor casing to +/- 173' MD w/ Kraxberger truck rig. Set cellar. 2. MIRU Nabors #129 drilling rig. 3. NU and function test Diverter. 4. PU 5" drillpipe and 16" bit and straight -hole BHA. 5. RIH and clean -out 20" conductor. 6. Drill 16" hole with 8.7 -9.3 ppg water -based spud mud to casing point at +/- 1000'. Utilize multi -shot directional survey. 7. Condition hole and POOH. Laydown bit and BHA. 8. RU and run 13 -3/8" casing. 9. RIH w/ 5" drillipipe for Stab -in cement job. Circulate and cement casing bringing cement to surface. Plan to pump 100% excess but will cut short if cement returns are seen before pumping 100% excess. Drop drillpipe wiper plug and displace. Test floats. 10. ND diverter system, NU multi -bowl wellhead and test to 5000 psi. NU BOPE equipment. Test BOPE to 250 psi /3000 psi. 11. Test casing to 2000 psi from surface at end of BOP test. 12. PU 5" drillpipe and 12 -1/4" bit and directional BHA. 13. RIH. Drill out float equipment, and 20' of new formation. Pull back into the casing and conduct a leak -off test or FIT test to 12.8 ppg EMW. 14. Drill 12 -1/4" hole with 9.1 -10.0 ppg water -based spud mud to casing point at +/- 6018'. Utilize BHA w/ MWD, GR, and Res. Plan for 2 bit runs. 15. Condition hole and POOH. Laydown bit and BHA. 16. RU and run 9 -5/8" casing. 17. MU and test cement lines. Circulate and pump 1 stage cement job around shoe. Pump 2 stage cement job thru DV collar bringing cement up 100' inside of the 13 -3/8" shoe. Bump top plug and test casing to 3000 psi. 18. PU 4" drillpipe and 8 -1/2" bit and directional BHA. 19. RIH. Drill out float equipment, and 20' of new formation. Pull back into the casing and conduct a leak -off test or FIT test to 13.6 ppg EMW. 20. Directionally drill 8 -1/2" hole to TD at +/- 9,952' MD / 8,168' TVD with 10.0 -10.6 ppg water -based mud. Utilize BHA w/ MWD, GR and Res. Plan for 2 bit runs. 21. Condition hole and POOH. Laydown bit and BHA. 3 Drilling Procedure Summary IRU 11 -06 rev1.doc 1 12/04/2008 • ! Chevron %1101 Ivan River Unit %110 IRU 11 -06 Gas Well Drilling Procedure Summary 1. Prepare location. Drill and drive 20" conductor casing to +/- 173' • D w/ Kraxberger truck rig. Set cellar. 2. - U Nabors #129 drilling rig. SUPERSEDED 3. NU nd function test Diverter. \ 4. PU 5 • rillpipe and 16" bit and straight -hole BHA. 5. RIH an. clean -out 20" conductor. 6. Drill 16" •le with 8.7 -9.3 ppg water -based spud mud to casing point at +/- 000'. Utilize multi -shot directional survey. 7. Condition ho - and POOH. Laydown bit and BHA. 8. RU and run 13 -' 8" casing. 9. RIH w/ 5" drillipi. - for Stab -in cement job. Circulate and cement casing bringing ce ent to surface. Plan to pump 100% excess but will cut short if ce -nt returns are seen before pumping 100% excess. Drop drillpipe ' •er plug and displace. Test floats. 10. ND diverter system, NU ulti -bowl wellhead and test to 5000 psi. NU BOPE equipment. Tes :OPE to 250 psi /3000 psi. 11. Test casing to 2000 psi from urface at end of BOP test. 12. PU 5" drillpipe and 12 -1/4" bit . d directional BHA. 13. RIH. Drill out float equipment, a • 20' of new formation. Pull back into the casing and conduct a lea -off test or FIT test to 12.8 ppg EMW. 14. Drill 12 -1/4" hole with 9.1 -10.0 pp• water -based spud mud to - casing point at +/- 6018'. Utilize BHA w WD, GR, and Res. Plan • for 2 bit runs. 15. Condition hole and POOH. Laydown bit an • ' HA. 16. RU and run 9 -5/8" casing. 1 . _ - • • test cement lines. Circulate - • : • mi. 1 stage cement job around s oe. ' • • s a • e cement jo • thru DV collar bringing c - . - - - •ove upper disposa z• -. • • slug and - asing to 3000 psi. 18. PU 4" drillpipe and 8 -1/2" bit and directional BHA. 19. RIH. Drill out float equipment, and 20' of new formation. 'ull back into the casing and conduct a leak -off test or FIT test to ' .6 ppg EMW. 20. Directionally drill 8 -1/2" hole to TD at +/- 9,952' MD / 8,168' VD with 10.0 -10.6 ppg water -based mud. Utilize BHA w/ MWD, GR a • Res. Plan for 2 bit runs. 21. Condition hole and POOH. Laydown bit and BHA. 3 Drilling Procedure Summary IRU 11- 06.doc 1 11/26/2008 Chevron Ivan River Unit %110 IRU 11 -06 Gas Well Drilling Procedure Summary 22. RU and run open hole logging suite (Quad Combo: GR -Res, Den, - Neu, Son) from TD to 9 -5/8" shoe. Run FMI (Formation Micro Imager) from 7575' MD to 9 -5/8" shoe. 23. RU and run 7" liner. 24. MU and test cement lines. Circulate and cement casing bringing cement to liner top. Bump plug and test liner to 3000 psi. 25. RIH w/ cleanout assembly and displace mud to 6% KCI brine. POOH. 26. RIH w/ retrievable packer, 3 -1/2" tubing and TCP perf guns. Correlate to place on depth. 27. RIH w/ PX plug. Set in X profile. Pressure up and set packer. Test tubing to 5000 psi. Pull PX plug. 28. Test tubing x casing annulus to 1500 psi. 29. RU slickline. Open sliding sleeve and circ glycol packer fluid. Close sliding sleeve. 30. Space out and land tubing. Set tubing hanger. Test packoff. 31. RIH w/ 2 -3/8" heater string and set in tubing hanger. 32. ND BOPE. NU Tree and test to 5000 psi 33. RD and Release Rig. 34. Drop bar and fire TCP guns w/ auto -gun release to drop to bottom. 35. Turn well over to production for testing. Flowline will connect well from 11 -06 to Ivan River production facilities. 3 Drilling Procedure Summary IRU 11- 06.doc 2 11/26/2008 . Chevron Well Name: IRU 11 -06 imoi • Ivan fe Field River . a Completion: Proposed v 9.0 Driven / ° ■ Conductor: 20 ", 133 ppf. PE to 173' 16" Hole Surface Casing: 13%", 68 ppf, L -80, BTC to 1,000' Surface Casing Cement: 13.0 ppg Lead cmt from 0' - 1,000' 165 bbl (100% OH Excess) . ' xcess) ' ; ° # Disposal Zone (Upper): Top Inj - 3015' MD /2821' TVD r:r:r:r 12 -1/4" Hole ' f .7... ' Btm Ivry - 3328' MD / 3040' TVD k 1.1.1. -.-. Intermediate Casing Cement 1 - _ 1 Intermediate Casing: 12.0 ppg Lead cmt from 4,600' - 6,018' ,,' 9 % ", 40 ppf, L -80, BTC to 6,018' 117 bbl (40% OH Excess) 1st Stage DV Collar at 3,500' 12.0 ppg Lead cmt from 900' - 3,500' 205 bbl (40% OH Excess) 2nd Stage t M ;� ;?1r Disposal Zone (Lower): r1 r y r y r. r } } }. Top Inj -5094' MD /4272' TVD 8 -1/2" Hole Btm Inj - 5680' MD / 4681' TVD ss x j,; , Production Liner Casing Cement: 12.0 ppg Lead cmt from 5,868' - 9,951' 127 bbl (35% OH Excess) Perfs (Proposed): Tyonek 9,551' - 9,676' (125' TCP) -, Fracture Gradients: Shoe @ 1,000' MD (1,000' TVD) = 15.0 ppg Shoe @ 6,018' MD (4,916' TVD) = 15.0 ppg TD @ 9,951' MD (8,168' TVD) = 15.0 ppg p Production Tubing: ' 47. 3/A', 9.2 ppf, L -80, IBT -Mod to 9,551' '' =, Heater String Tubing: / 2%", 4.6 ppf, L -80, IBT(SCC) to 3,500' _ _ Tyonek Completbn: - CMU Sliding Sleeve at 6,000' • Production Liner - Retrievable Packer at 6,010' • 7 ", 26 ppf, L -80, BTC -Mod w/ Torque Rings from X Profile at 9,506' • 5,868' to 9,951' MD (4,812' to 8168' TVD) - WLEG at 9,551' • 4 -5/8" TCP Guns (Auto- Released) at 9,741' • 9 -5/8" x 7" Rotatable FlexLock liner hanger w/ ZXP - Packer & Tieback sleeve at 5,868' PBTD = 9,866' MD TD = 9,951' MD 4 \A/BD IRU 11 -06 Proposed v9.0.xls Dec 4, 2008 Drawn by: STP • evron Well Name: IRU 11 -06 Field: Ivan River Completion: Proposed v8.0 Driven , Conductor: 20 ", 133 ppf, PE to 173' 16" Hole Surface Casing: 13'/8 ", 68 ppf, L -80, BTC to 1,000' Surface Casing Cement _ 13.0 ppg Lead cmt from 0' - 1,000' 165 bbl (100% OH Excess) Disposal Zone (Upper): r:r� };: Top Inj - 3015' MD / 2821' TVD 112 -1/4" Hole �i�.:rr {. Btm Inj - 3328' MD / 3040' TVD Intermediate Casing Cement 12.0 ppg Lead cmt from 4,600' - 6,018' J L 9%", Casing: 9%, 117 bbl (40% OH Excess) 1st Stage 9/e 40 ppf, L -80, BTC to 6,018' DV Collar at 3,500' 12.0 ppg Lead cmt from 2,700' - 3,500' 63 bbl (40% OH Excess) 2nd Sta Disposal Zone (Lower): yrtir r� ?r?L Top Inj - 5094' MD / 4272' TVD 18 -1/2" Hole Btm Inj - 5680' MD / 4681' TVD Production Liner Casing Cement ∎ 1W l i J iP ED L 12.0 ppg Lead cmt from 5,868' - 9,951' A 127 bbl (35% OH Excess) &q/) Perfs (Proposed): Tyonek 9,551' - 9,676' (125' TCP) Fracture Gradients: hoe @ 1,000' MD (1,000' TVD) = 15.0 ppg .e @ 6,018' MD (4,916' TVD) = 15.0 ppg TD ' ' 9,951' MD (8,168' TVD) = 15.0 ppg • Production Tubing: 3W, 9.2 ppf, L -80, IBT -Mod to 9,551' x Heater String Tubing: / 2%", 4.6 ppf, L -80, IBT(SCC) to 3,500' Tyonek Completion: - CMU Sliding Sleeve at 6,000' 0 Production Liner. - Retrievable Packer at 6,010' 0 7 ", 26 ppf, L -80, BTC -Mod w/ argue Rings from - X Profile at 9,506' 0 5,868' to 9,951' MD (4,812' to 8 8' TVD) WLEG at 9,551' - 4 -5/8" TCP Guns (Auto - Released) at 9,741' 0 9 -5/8" x 7" Rotatable FlexLock lin= hanger w/ ZXP Packer & Tieback sleeve at 5,868' PBTD = 9,866' MD TD = 9,951' MD 4 WBD IRU 11 -06 Proposed v8.0.xls Nov 17, 2008 Drawn by: STP Ivan River Chevron IRU 11 -06 , Depth vs. Time AFE Time Updated: Nov 26, 2008 0- 1000 / \ MIRU Nabors 129 • 2000 s 16" Hole 12 -1/4" Hole 3000 13 -3/8" Casing 4000 /I Bit/BHA w Change ,; 5000 A 6000 /v 9 -5/8" Casing 7000 8 -1/2" Hole 3 -1/2" TCP 7" Liner Completion 8000 Bit/BHA O pen Hole Logs DeMobe Change Nabors 129 9000 1 / i 10000 0 5 10 15 20 25 30 35 40 45 50 55 60 Time (Days) Chevron %✓ %. Schlumberger IRU 11 -06 (P8) Proposal Report Date: 1- Dec-08 I Survey / DLS Computation Method: Minimum Curvature / Lubinski Client: Chevron 1 I , Vertical Section Azimuth: 11.950° Field: Ivan River Unit Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure / Slot: Ivan River Unit / 11 -06 /�'O � 'ND Reference Datum: Rotary Table Well: Plan IRU 11 -06 7 TVD Reference Elevation: 46.40 ft relative to MSL Borehole: Plan IRU 11 -06 rOV Sea Bed / Ground Level Elevation: 30.00 ft relative to MSL UWVAPI /: 50283xxxxx00 � Magnetic Declination: 19.071° Survey Name / Date: IRU 11 -06 (P8) / November 14, 2008 Total Field Strength: 55740.455 nT Tort / AHD / DDI I ERD ratio: 84.285° / 5062.03 ft / 5.716 /0.620 Magnetic Dip: 74.052° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: December 15, 2008 Location Lat/Long: N 61.24065367, W 150.79595737 Magnetic Declination Model: BGGM 2008 Location Grid WE Y/X: N 2646275.020 ftUS, E 359784.660 ftUS North Reference: True North Grid Convergence Angle: - 0.69778510° Total Corr Mag North -> True North: +19.071° Grid Scale Factor: 0.99992237 Local Coordinates Referenced To: Well Head I Measured Vertical Mag / Gray Directional Comments Measured Azimuth Sub-Sea TVD TVD NS EW DLS Northing Easting Latitude Longitude Depth Section Tool Face Difficulty fty (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (deg) I (deg/100ft ) Index I (ftUS) (ftUS) RTE 0.00 0.00 0.00 -46.40 0.00 0.00 0.00 0.00 - 0.00 0.00 2646275.02 359784.66 N 61.24065367 W 150.79595737 20" Conductor 160.00 0.00 0.00 113.60 160.00 0.00 0.00 0.00 - 0.00 0.00 2646275.02 359784.66 N 61.24065367 W 150.79595737 13-3/8" Csg 1000.00 0.00 0.00 953.60 1000.00 0.00 0.00 0.00 - 0.00 0.00 2646275.02 359784.66 N 61.24065367 W 150.79595737 KOP Bld 1/100 1100.00 0.00 0.00 1053.60 1100.00 0.00 0.00 0.00 0.00M 0.00 0.00 2646275.02 359784.66 N 61.24065367 W 150.79595737 KOP BId 2.5/100 1200.00 1.00 ' 0.00 1153.59 1199.99 0.85 0.87 0.00 0.00M 1.00 0.00 2646275.89 359784.67 N 61.24065606 W 150.79595737 1300.00 3.50 0.00 1253.51 1299.91 4.69 4.80 0.00 0.00M 2.50 1.23 2646279.82 359784.72 N 61.24066680 W 150.79595737 1400.00 6.00 0.00 1353.16 1399.56 12.80 13.08 0.00 HS 2.50 1.89 2646288.10 359784.82 N 61.24068944 W 150.79595737 1500.00 8.50 0.00 1452.35 1498.75 25.14 25.70 0.00 HS 2.50 2.34 2646300.71 359784.97 N 61.24072396 W 150.79595737 1600.00 11.00 0.00 1550.90 1597.30 41.71 42.63 0.00 HS 2.50 2.67 2646317.64 359785.18 N 61.24077028 W 150.79595737 1700.00 13.50 0.00 1648.61 1695.01 62.46 63.85 0.00 HS 2.50 2.94 2646338.86 359785.44 N 61.24082831 W 150.79595737 1800.00 16.00 0.00 1745.31 1791.71 87.37 89.31 0.00 HS 2.50 3.16 2646364.31 359785.75 N 61.24089794 W 150.79595737 0 1900.00 18.50 0.00 1840.81 1887.21 116.38 118.96 0.00 HS 2.50 3.35 2646393.96 359786.11 N 61.24097905 W 150.79595737 2000.00 21.00 0.00 1934.92 1981.32 149.44 152.75 0.00 HS 2.50 3.51 2646427.74 359786.52 N 61.24107147 W 150.79595737 2100.00 23.50 0.00 2027.46 2073.86 186.48 190.61 0.00 HS 2.50 3.66 2646465.60 359786.98 N 61.24117503 W 150.79595737 Cry 2.5/100 2160.00 25.00 0.00 2082.17 2128.57 210.59 215.25 0.00 16.90L 2.50 3.74 2646490.24 359787.28 N 61.24124243 W 150.79595737 2200.00 25.96 359.34 2118.28 2164.68 227.40 232.46 -0.10 16.30L 2.50 3.79 2646507.44 359787.39 N 61.24128949 W 150.79595794 2300.00 28.37 357.86 2207.24 2253.64 271.80 278.09 -1.24 14.99L 2.50 3.91 2646553.08 359786.80 N 61.24141430 W 150.79596442 2400.00 30.79 356.60 2294.21 2340.61 319.53 327.38 -3.65 13.89L 2.50 4.02 2646602.39 359785.00 N 61.24154913 W 150.79597808 2500.00 33.22 355.50 2379.00 2425.40 370.49 380.24 -7.32 12.96L 2.50 4.12 2646655.29 359781.97 N 61.24169372 W 150.79599891 2600.00 35.66 354.54 2461.47 2507.87 424.58 436.58 -12.24 12.17L 2.50 4.21 2646711.68 359777.74 N 61.24184780 W 150.79602685 2700.00 38.11 353.69 2541.45 2587.85 481.70 496.27 -18.41 11.48L 2.50 4.30 2646771.44 359772.30 N 61.24201108 W 150.79606186 2800.00 40.56 352.92 2618.79 2665.19 541.75 559.21 -25.81 10.89L 2.50 4.38 2646834.46 359765.66 N 61.24218324 W 150.79610387 WellDesign Ver SP 2.1 Bld(doc40x 100) 14-31X \Plan IRU 14 -31X \Plan IRU 14 -31X \IRU 14 -31X (P8) Generated 12/1/2008 9:27 AM Page 1 of 2 I Measured Vertical Mao I Gray Directional Comments Inclination Azimuth Sub Sea ND ND NS EW DLS Northing Easting Latitude Longitude De Depth Section Tool Face Difficulty tY (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (deg) (deglt00ft ) Index (ftUS) (ftUS) Latitude 2900.00 43.02 352.23 2693.35 2739.75 604.60 625.28 -34.43 10.38L 2.50 4.46 2646900.63 359757.85 N 61.24236395 W 150.79615280 3000.00 45.48 351.60 2764.98 2811.38 670.15 694.36 -44.25 9.92L 2.50 4.53 2646969.81 359748.87 N 61.24255288 W 150.79620856 End Cry 3011.77 45.77 351.53 2773.21 2819.61 678.03 702.68 -45.49 - 2.50 4.54 2646978.14 359747.74 N 61.24257564 W 150.79621557 9-5/8" Csg 5707.34 45.77 351.53 4653.60 4700.00 2488.01 2612.98 - 330.07 - 0.00 5.17 2648891.62 359486.46 N 61.24780071 W 150.79783129 Tgt 1 /Cry 3/100 6031.89 45.77 351.53 4880.00 4926.40 2705.93 2842.98 - 364.34 131.28R 0.00 5.21 2649122.00 359455.00 N 61.24842981 W 150.79802586 6100.00 44.44 353.72 4928.08 4974.48 2751.45 2890.82 - 370.54 129.73R 3.00 5.24 2649169.91 359449.38 N 61.24856066 W 150.79806109 6200.00 42.57 357.13 5000.62 5047.02 2817.42 2959.42 - 376.06 127.26R 3.00 5.27 2649238.56 359444.69 N 61.24874829 W 150.79809246 6300.00 40.81 0.79 5075.30 5121.70 2882.19 3025.89 - 377.31 124.53R 3.00 5.31 2649305.04 359444.26 N 61.24893011 W 150.79809955 6400.00 39.18 4.70 5151.92 5198.32 2945.60 3090.06 - 374.27 121.53R 3.00 5.34 2649369.16 359448.07 N 61.24910562 W 150.79808233 6500.00 37.68 8.88 5230.27 5276.67 3007.46 3151.75 - 366.96 118.25R 3.00 5.37 2649430.75 359456.13 N 61.24927435 W 150.79804084 6600.00 36.34 13.35 5310.14 5356.54 3067.62 3210.79 - 355.40 114.69R 3.00 5.40 2649489.64 359468.41 N 61.24943584 W 150.79797520 6700.00 35.18 18.08 5391.30 5437.70 3125.89 3267.02 - 339.62 110.84R 3.00 5.43 2649545.67 359484.88 N 61.24958963 W 150.79788560 6800.00 34.21 23.07 5473.53 5519.93 3182.13 3320.28 - 319.66 106.74R 3.00 5.46 2649598.68 359505.48 N 61.24973532 W 150.79777227 6900.00 33.46 28.29 5556.61 5603.01 3236.19 3370.43 - 295.57 102.40R 3.00 5.48 2649648.53 359530.18 N 61.24987249 W 150.79763553 7000.00 32.93 33.68 5640.31 5686.71 3287.90 3417.33 - 267.43 97.89R 3.00 5.51 2649695.08 359558.89 N 61.25000078 W 150.79747575 I 7100.00 32.64 39.20 5724.40 5770.80 3337.13 3460.85 - 235.31 93.25R 3.00 5.53 2649738.21 359591.53 N 61.25011983 W 150.79729337 7200.00 32.59 44.77 5808.66 5855.06 3383.75 3500.88 - 199.29 88.56R 3.00 5.55 2649777.79 359628.03 N 61.25022931 W 150.79708889 End Cry 7298.24 32.78 50.21 5891.36 5937.76 3426.88 3536.69 - 160.21 -- 3.00 5.57 2649813.12 359667.54 N 61.25032727 W 150.79686702 Tgt 2 9550.59 32.78 50.21 7785.00 7831.40 4384.40 4317.10 776.89 - 0.00 5.70 2650582.00 360614.00 N 61.25246178 W 150.79154610 9950.36 32.78 50.21 8121.10 8167.50 4554.35 4455.61 943.22 - 0.00 5.72 2650718.46 360781.99 N 61.25284061 W 150.79060162 TD / 7" Csg 9950.59 - 32.78 50.21 8121.30 8167.70 • 4554.45 4455.69 943.31 - 0.00 5.72 2650718.54 360782.09 N 61.25284083 W 150.79060107 Survey Error Model: SLB ISCWSA version 24*** 3 -D 95.00% Confidence 2.7955 sigma Surveying Proq: MD From (ft) MD To (ft) EOU Freq Survey Tool Type Borehole -> Survey 0.00 16.40 1/100.00 SLB_NSG+SSHOTAA1 -Depth Only Plan IRU 11 -06 -> IRU 11-06 (P8) 16.40 1000.00 1/100.00 SLB_NSG +SSHOTAA1 Plan IRU 11 -06 -> IRU 11 -06 (P8) 1000.00 5707.34 1/100.00 SLB_MVVD- STDAA1 Plan IRU 11 -06 -> IRU 11 -06 (P8) 5707.34 9950.59 1/100.00 SLB MWDSTDAA2 Plan IRU 11 -06 -> IRU 11 -06 (P8) Legal Description: Northing (Y) fftUSl Eastinq (X) fftUSl Surface : 584 FSL 628 FEL S1 T13N R9W SM • 2646275.02 • 359784.66 • Tgt 1 : 3427 FSL 993 FEL S1 T13N R9W SM 2649122.00 359455.00 Tgt 2 : 4901 FSL 5045 FEL S6 T13N R8W SM 2650582.00 360614.00 BHL : 5040 FSL 4878 FEL S6 T13N R8W SM . 2650718.54 360782.09 WellDesign Ver SP 2.1 Bld( doc40x_100) 14 -31X \Plan IRU 14 -31X \Plan IRU 14 -31X \IRU 14 -31X (P8) Generated 12/1/2008 9:27 AM Page 2 of 2 M Chevron Schlumherger WELL FIELD STRUCTURE IRU 11 -06 (P8) I Ivan River Unit I Ivan River Unit Magnetic Parameters Surface Locatnn NA027 SeMa State Planes, Zone 04. US Feet imeIlene°. Model: 6GGM 2006 e 74 052' Date: December 15, 2008 Let' N61 14 26.353 Northing 2646275 02 WS Cod Como -0.69778510• Slot: TVD Ref: Rotary Table (46.40 ft above MSL) Meg Dec: v19071• FS: 55740.5 nT Lon: W150 47 45.447 E6Aln9: 359 784 66 (WS Scab Fact' 09999223697 Plan: IRU 11-06 (P8) Si, Dale: November 14, 2008 0 1000 2000 3000 4000 5000 • 0 RTE 0 20" Conductor 1000 A 133/8" Csg 1000 KOP Bld 1/100 KOP Bid 2.5/100 Cry 2.5/100 4 2000 2000 Ettd Cry 3000 3000 0 0 0 c 4000 4000 20 U 93/8" Csg 0 Tgt1 / Cry 3/100 5000 0 - 1 .11.-Ab.Tst. 1 .1.vWer.§Vivg 7 5000 End Cry 6000 a 6000 7000 7000 Tgt 2 'U 11 -06 Tgt 2 Tyonek 8000 8000 TOI 7" Cs. e ' .RU 11 -06 (P6) 0 1000 2000 3000 4000 5000 Vertical Section (ft) Azim = 11.95 °, Scale = 1(in):1000(ft) Origin = 0 N / -S, 0 E / -V • • Chevron s er chlumber %. g WELL IRU 11 -06 (P8) I FIELD STRUCTURE Ivan River Unit I Ivan River Unit I Magneto Ponnetem I Surface Looelion N002T Pbsba Slate Planes. Zoo. M, US Feet I Mrecelbrreooa I MoEd: eGGM]008 Dip: 74053' Dvle: December 15, 2008 Let: 951 14 26 333 Northing: 2546275.02 SUS GM Cony: -00778510' Std: TW Ref: Rotary Table (08.407 above MSL) Meg Dec v18071' FS: 55700.5 nT Lon: W1504745.447 Easing: 359784 fib 5U8 Scale Fed: 0.98082230 Ran: IRU 11J)8 (PS) Snry Delo: November 14.2005 -1200 -600 0 600 1200 1800 TD/ 7" Cs. Tgt .,,IL U 11 -06 (14) 111 0'.RU 11 r • Tgt 2 Tyonnk 4200 4200 End Ctv 3600 3600 N Ate/ ®s /10 3000 0. 3000 Al A Tgt 1/ Cry 3/10. r c Tgt 1 Lawer Sterling A ,. Z D 9516" Csg 1 O ° m 2400 a 2400 c II a) C N cn v 1800 1800 v 1200 1200 End Cry 600 600 Cry 2. &100 KOP Bld 2.61100 13-316" Csg KOP Bld 11100 20" Conductor 0 0 RTE -1200 -600 0 600 1200 1800 c« W Scale = 1(in):600(ft) E »> • • ANTICOLLISION SUMMARY REPORT Client: - Chevron Slot: 14 -31X Field: Ivan River Unit Well: Plan 1RU 11 -06 Structure: Ivan River Unit Borehole: Plan IRU 11 -06 Subject Trajectorj: 1RU 11 -06 (P8) (DEF PLN) Rpt Date. December 01, 2008 Analysis Method: Normal Plane Depth Interval: Every 5.00ft MD ECU Type: Oriented EOU used. Min Pts: All local minima indicated. • ProbColMax: 1:25959 Mag Model: BGGM 2008 Offset Trajectory Sep. Allow Sep. Subject Trajectory Separation Factor Alert Status Ct -Ct (ft)_ Dev. (ft) Fact. MD (ft) 1 TVD (ft) Alert 1 Minor 1 Major IRU 13-31 (DEF SVY) PASS 116.07 107.46 27.87 760.28 760.28 MinPt -CtCt 116.40 106.20 22.19 935.27 935.27 MinPt -0-ADP 140.74 127.10 EllirlEn 1493.88 1492.69 MinPt -O -SF 144.17 130.24 18.59 1530.47 1528.85 MinPt -O -SF 304.84 275.71 =Ma 2641.63 2541.48 MinPt -0-SF 576.72 501.57 5796.18 4761.97 MinPt -0-SF 1474.47 1377.68 MOM 8154.20 6657.40 MinPt -0-SF 1981.47 1857.95 24.53 9921.15 8142.95 MinPt -O -SF 1989.68 1865.68 24.53 9949.79 8167.02 TD IRU 14 -31 (DEF SVY) FAIL MINOR 11 197.2011 181.09 21.46 475.40 475.40 MinPt -CtCt 197.9411 180.42i1 19.52 520.39 520.39 MinPt -0-ADP 312.86 217.02 4.99 3415.91 3101.54 5.00 Enter Alen 186.36 -0.72 1.49 4570.23 3906.77 1.50 Enter Minor 185.72 -14.30 1.39 4623.36 3943.83 MinPt -CtCt 209.11 -65.64 1.14 4950.95 4172.35 MinPt -O -SF 219.26 IIMMI 1.15 5018.25 4219.30 MinPt -O -ADP 341.49 -0.73 1.50 5507.19 4560.38 1.50 Exit Minor 531.02 101.6811 1.86i1 8212.66 6706.55 MinPt -0-SF 528.2611 101.4011 1.86 8281.22 6764.19 MinPt -O -ADP 1 523.521 107.51 1.89 8516.36 6961.88 MinPt -CtCt 1 523.111 135.09 2.03 8987.62 7358.09 MinPt -CtCt 634.67 294.62 2.81 9949.37 8166.67 TD IRU 23 -12 (DEF SVY) PASS 1 94.7211 92.2211 19876.63i1 0.81 0.81 MinPts 1 94.471 83.60 16.48 425.80 425.80 MinPt -CtCt 94.47 83.601 16.471 430.80 430.80 MinPts 94.45 84.33 18.10 490.79 49079 MinPt -CtCt 94.851 85.311 19.67 615.44 615.44 MinPt -O -ADP 153.49 129.86 11 10.72 1149.94 1149.94 MinPt-0-SF 9017.52 8707.121 43.921 4358.77 3759.26 MinPt -O -SF IRU 41 -1 (DEF SVY) PASS 172.72 170.21 36685.92 0.40 0.40 MinPts 173.47 169.74 209.03 175.37 175.37 MinPt -0-ADP 17425 169.91 140.21 270.32 270.32 ' MinPt -O -ADP 175.12 ion 99.59 400.29 400.29 MinPt -O -ADP MEE 167.61 42.48 885.21 885.21 MinPt -CtCt 176.72 MOM 37.36 1000.20 1000.20 MinPt -0-ADP 129.45 114.24 14.98 2118.23 2090.55 MinPt -CtCt 124.18 98.81 7.98 2613.16 2518.54 MinPt -CtCt 124.46 98.27 7.72 2657.88 2554.48 MinPt -O -ADP 127.92 100.46 MBE 2744.05 2622.25 MinPt -O -SF 499.83 441.70 ® 4499.70 3857.57 MinPt -0-SF 11 953.6311 850.58 14.19 7868.09 6416.86 MinPt -CtCt 955441 848.8111 13.73 7990.87 6520.08 MinPt -O -ADP 1119.76 979.4011 12 -16i1 9037.54 7400.06 MinPt -O -SF 1196.07 1047.33 12.24 9311.80 7630.64 TD Version DO 4.0 ( doc4ox_100 ) SP 2.1 - ANTICOLLISION SUMMARY REPORT Generated 12/1/2008 10:07 AM Page 1 of 2 • • fiffsef. ! r a j e c t j . j . i r i a w ' 3 S ! , S i . d a 'a .e �, Sept � Vier,: Fac a _ Vy A:.',Pf Ski { ct- (MI Dew ; fly' =ad.. 1 MOM I ? a �`t I, A.iet? Knox t;Aa r_? :1 =.[.F 1 6EF , 3 VY) F _..1),%1315 is .1 62.' 35 ':'i 440 tii 1,1 Y . 38 481 77,04 44 1001 40 1f 1 ; 45 1 i ii _t- Se 77 77.07. 14.07 1093 'i0s33 3, 141tn(`i.0- 4'S.{`. 68.78 77 011 14.06; 1 41 1101 41 MinP 0 F 45 13 ` 33 55 7 04 1753 12 1746 . as Rrr:Pi -C Ct 45 141 33.5311 7 02 1757 95 175'i 12 VittP.3- C-ADf 45 73 3..3 9111 11732 02 7 7 41 h P1 -13 -SF 2386.37 1654 94 4.97 4449.97 3822 88 5.00 Ewer Alert 4001.29 - 2.00 1.50 6023.02 4920.21 1.50 Enter 66r:or 411059 - 2056.32 1.00 8107 34 6618 00 - 1 CO Eider Major 5056.321 - 5009.60 MIIIIMI 9948.56 8165.99 MinP£s IRU 44 -36 (DEF SVY) PASS 217.51 165.91 300 38 300.38 Mint -CtCt 222 05'MB:a 157.99 320.38 320.38 W4inPt -fl ADP 304.51 292.49011Ml 1102.37 1102.37 11/1 66nPt. -0-SF MEM 530.84 2024 3588.35 3221.83 MinPt -CtCt 578.83 MIN 17.53 3906.49 3443.75 Min4't -O -ADP 590.26 ® 14.17 4463.72 3832.47 MinPt -O -ADP 636.85 538.96 9.98 5708.49 4700.81 MinP1-O -ADP 662.51 553.57 9.30 ` 6280.98 5107.34 MinP1-0-SF 1292.57 1161.77 15.08 8153 60 6656.89 TO Version DO 4.0 ( doc40x_100) SP 2.1 - .ANT.ICOLLISION SUMMARY REPORT Generated 12/1/2008 10 :07 AM Page 2 of 2 I • , , scidankeilier Travehng r-,_,—yllinder Pot :,,,,,:,,,..i.:4,,i7 PLOT Struct ore, Ivan River Uoit NeCro Regoort Et31,., s insed 011. 211; 4' VC 4 E0t11Iimeustou 2008 b 14, Date: ... Nekret-te*N1 Aill. ir,44111isxon rote used: — _ aid MitWir Risk - Separstiou Factor Novemer Legend 7 1 tRU t 3-31 urs North RU 14-31 IRU 14-31 350 True North 0 10 1 I 20 I RU 14 - 3 1 340 "F:;'bibalgir:;:itiPrll:Vttikit •,. 30 IRU 23-12 IRU I3-31 _ ,,,,,rox i t.,4, 74 1 ilateak . 114.,, , rillk I tt IRU 41-1 IRU 44-36 331 ..„..,c,',1"40x, ,,,;--/Aripsrmaip, .41111:4 lit" . 40 AU 44-1 irt 7411 • 2110.4241/4 Tot G r i dm C c o a og r r e l: :: (0 7 + 61997 07 0 1; 7 )1 1 0 7 IRU 44-36 !!*-110,411 ' / 10 t A ilf 14601844114 320411t4bitirliGW/04'1.%arioritririliPit P410" ‘ 4 \- so Trioii';'7..74•-•lpf, 11 . At ALA 0 r W.44iL*4 11 0: 4 1 X 10?..,V,,, a / A 1 EV flidr,44. 4rat k \ :1A-A*Vii'.1tic,,-"irlitiAtt0A04‘, V 4 310 '. A IV ? 1 4& 4 r, .,,, N. ■ N 80 ' e'''• filakv0 2 441, 40Ik 1 / - ilr''',11-4.Eptil, 46 ■%:',, It . ' 4 is 1 110:ititUA;;:-.4):40614:.42.114.51/4171,"„& V 440., '''''s 417° W,/ga741.7,,, -ezi,LVitgarattfoirriWws v .fr#N1 1 290 40 ),,,. -. IF:2 Altim„ =,,,,wito.441114r - 416.,,yeil' - 80 ' tiajall; : \i: *14414 Ott in ae lk ‘. 1 R U 1 - 11 ii , A 111 90 l lit 16 , up XI Vit . : „.finom ., 15stii 0,,.. .z.. ' in ,,.. F4 AID? 1 ., , 7A -, Nyi.V .' ' ii: -4 -V117 -."‘r ..1=',.. . - loo wanz I .,g..t:t7_,,-3. iiiiv..,k_.JAragiitivi is ingweirrAltiiWNVAtill, 1.P*1414jp"440ifi N W . IR 1 Sliii‘ -11a741Ar ,N,4110*** - 4.. „ , Wilkiiik..4,44* ler no ittiek et, ..Lioac,c, tiptipiiim ‘,.. -,c..'f,* . 4, 1 7 / 110 man I 11 Il lill, 240 ige vo+ , la p - , ., 1,0 \ fr. 220 AI* OF, ' ii- :110 150 200 4111 111141111m i UR 190 IRU 44-1 Ro IRU 14411 160 Well Ticks Type: MD on IRU 11-06 (P8) Calculation Method: 20.00 ft Plane Ring Interval: Azimuth Interval: 10.0 deg Scale: 1 INCH = 100.0011 • • ki•o' Chevron Maximum Anticipated Surface Pressure Calculation Ivan River Unit IRU 11 -06 Kenai Peninsula, Alaska Assumptions: 1. Based on offset drilling & well test data, the pore pressure gradient is predicted to be a 0.440 psi /ft gradient from surface to planned total depth at 8,168' TVD BRT. 2. The M.A.S.P. during drilling operations will be governed by the 9 -5/8" shoe frac gradient, and is calculated based on a full column of gas between the 9 -5/8" shoe and the surface. The shoe f or IRU 11 -06 at 4,916' TVD will be between the shoe depths of offset wells on the Ivan River and Stump Lake pad, ranging from 2943' to 8677' TVD. Leak -off or formation integrity tests ranged from 14.7 ppg to 20.2 ppg (0.764 psi /ft and 1.050 psi /ft). This offset LOT /FIT data from Ivan River and Stump Lake is useful for relatively accurate kick tolerance & MASP calculations. 3. The M.A.S.P. during production operations will be the estimated SIBHP minus the gas hydrostatic pressure between TD & the surface. M.A.S.P. During Production Life: Max. pore pressure at T.D. = 8,168 ft. x 0.440 psi /ft = 3594 psi M.A.S.P. (tbg leak at surface) = 3594 psi - (0.1 psi /ft * 8,168 ft) = = 2777 psi M.A.S.P. While Drilling 8 -1/2" hole at 8,168' TVD: vprf.S.1/4W Max. Est. Frac pressure at 9 -5/8" shoe = 4916 ft. x 0.707 psi /ft = 3476 psi �� M.A.S.P. during drilling = 3476 psi - (0.1 psi /ft x 4916 ft.) _ - 2984 psi ` A'AW. M.A.S.P. While Drilling 12 -1/4" hole at 4,916' TVD: ‘\'\ Cr Max. Est. Frac pressure at 13 -3/8" shoe = 1000 ft. x 0.665 psi /ft = 665 psi M.A.S.P. during drilling = 665 psi - (0.1 psi /ft x 1000 ft.) = = 565 psi `aC, Calculation & Casing Design Factors 4 40 C hevron Ivan River Unit IRU 11-06 Kenai Peninsula, Alaska WELL: IRU 11 -06 FIELD: Ivan River Unit DATE: 26- Nov -08 DESIGN BY: Stan Porhola Sect. 1 16" hole MUD WT. 9.3 PPG MASP= 565 psi ** Sect. 2 12 1/4" hole MUD WT. 10.0 PPG MASP= 2,984 psi Sect. 3 8 1/2" hole MUD WT. 10.6 PPG MASP= 2,777 psi Production Mode TENSION MINIMUM COLLAPSE COLLAPSE WEIGHT TOP OF STRENGTH PRESS @ RESIST. MINIMUM DESCRIPTION W/O BF SECTION TENSION WORST CASE BOTTOM w/o TENSION WORST CASE MASP YIELD WORST CASE • SECTION CASING BOTTOM TOP LENGTH WT. GRADE THREAD LBS LBS 1000 LBS SF TENSION PSI* PSI SF COLL. PSI ** PSI SF BURST 1 13 - 3/8" 1,000 0 1000 68 L - 80 BTC 68,000 68,000 1556 22.88 452 2,260 5.00 565 5,020 8.88 TVD 1,000 0 2 9 - 5/8" 6,018 0 6018 40 L - 80 BTC 240,720 240,720 916 3.81 2,222 3,090 1.39 2,984 5,750 1.93 TVD 4,916 0 3 7" 9,951 0 9951 26 L -80 BTC -Mod 258,726 258,726 604 2.33 3,692 5,410 1.47 2,777 7,240 2.61 TVD 8,168 0 * Collapse pressure is calculated; Normal Pressure Fluid Gradient for external stress (.440 psi/ft) and the casing evacuated for the internal stress (0 psi/ft) ** See attached sheet for calculation of MASP • • • Chevron Ivan River Unit %1110 IRU 11 -06 Gas Well %110 Cement Program 20" Casing (Driven to +/ -173') Note: This string is only for structural support of the wellhead and diverter system. 13 -3/8" Casing (16" Hole to 1,000' MD): Cement volume based on annular volume plus 100% open hole excess and shoe joint(s). The job will involve a stab -in adapter into the float collar and consist of a lead only and cement will be brought to surface. The estimated total volume is as follows: Lead: 1,000' X 0.4206 cuft/ft (16" x 13 -3/8 ") X 2.0 = 841 cuft = 462 sxs (1.82 yield) 80' shoe joint X 0.8406 cuft/ft = 67 cuft = 37 sxs (1.82 yield) TOTAL: 841 + 67 = 908 cuft or 499 sxs 9 -5/8" Casing (12 -1/4" Hole to 6,018' MD): Cement volume based on annular volume plus 40% open hole excess and shoe joint(s) The job will consist of a 1 Stage at the shoe to cover the lower disposal zone and a 2nd Stage thru a DV collar to cover the upper disposal zone and cement will be brought up to 100' inside of the surface casing shoe. The estimated total volume is as follows: 1 Stage: 1418' X 0.3132 cuft/ft (12 -1/4" x 9 -5/8 ") X 1.4 = 622 cuft = 278 sxs (2.24 yield) 2 Stage: 2600' X 0.3132 cuft/ft (12 -1/4" x 9 -5/8 ") X 1.4 = 1140 cuft = 509 sxs (2.24 yield) 1 Stage 80' shoe joint X 0.4257cuft/ft = 34 cuft = 15 sxs (2.24 yield) 2 Stage 20' shoe joint X 0.4257cuft/ft = 9 cuft = 4 sxs (2.24 yield) TOTAL: 622 + 1140 + 34 + 9 = 1805 cuft or 806 sxs 7" Casing (8 -1/2" Hole to 9,951' MD): Cement volume based on annular volume plus 35% open hole excess and shoe joint(s). The job will consist of a lead only and cement will be brought to 2,DeA�IID (Pr? i u,,s shoe). The estimated total volume is as follows: S 5cog ` Lead: 4,083' X 0.1268 cuft/ft (8 -1/2" x 7 ") X 1.35 = 699 cuft = 312 sxs (2.24 yield) �3(c 80' shoe joint X 0.2148 cuft/ft = 17 cuft = 8 sxs (2.24 yield) TOTAL: 699 + 17 = 716 cuft or 320 sxs 9 Cement Program 11 -06 rev1.doc 1 12/04/2008 • Chevron Ivan River Unit IRU 11 -06 Gas Well Cement Program Cement Type and Design: Surface Casing, 13 -3/8 ", Lead Cement Type: Type 1 Density: 13.0 ppg Cement: 499 sx Yield: 1.82 ft /sx Mix Water: 7.58 gal /sx Slurry Volume: 165 bbl Additives: Static Free 0.050% BWOC Anti - Static Calcium Chloride 1.000% BWOC Accelerator LW -6 12.000% BWOC Light- weight additive FL -63 0.1000% BWOC Fluid Loss Additive • CD -32 0.6000% BWOC Dispersant FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 1.000% BWOC Accelerator BA -10A 0.9000% BWOC Matrix Flow Control MPA -1 5.000% BWOC Pozzolan Intermediate Casing, 9 -5/8 ", 1 Stage Cement Type: Class G Density: 12.0 ppg Cement: 293 sx Yield: 2.24 ft /sx Mix Water: 9.71 gal /sx Slurry Volume: 117 bbl Additives: BA -90 15.000% BWOC Silica Static Free 0.500% BWOC Anti - Static FL -63 1.200% BWOC Fluid Loss Additive CD -32 1.000% BWOC Dispersant FP -6L l gal /100 sx Anti -Foam Sodium Metasilicate 0.300% BWOC Accelerator LW -7 -6 10.000% BWOC Light- weight additive Intermediate Casing, 9 -5/8 ", 2 Stage Cement Type: Class G Density: 12.0 ppg Cement: 509 sx Yield: 2.24 ft /sx Mix Water: 9.71 gal /sx Slurry Volume: 203 bbl Additives: BA -90 15.000% BWOC Silica Static Free 0.500% BWOC Anti - Static 9 Cement Program 11 -06 rev1.doc 2 12/04/2008 • Chevron Ivan River Unit IRU 11 -06 Gas Well Cement Program 20" Cas o (Driven to +/ -173') Note: This - ing is only for structural support of the wellhead and diverter system. 13 -3/8" Casing 6" Hole to 1,000' MD): Cement volume b. ed on annular volume plus 100% open hole excess and shoe joint(s). The job will involve • stab -in adapter into the float collar and consist of a lead only and cement will be brough to surface. The estimated total volume is as follows: Lead: 1,000' X 0.4 16 cuft/ft (16" x 13 -3/8 ") X 2.0 = 841 cuft = 462 sxs (1.82 yield) 80' shoe joint X 0.84∎ • cuft/ft = 67 cuft = 37 sxs (1.82 yield) TOTAL: 841 + 67 - • 08 cuft or 499 sxs SUPERSEDEV ID f 9 -5/8" Casing (12 -1/4" Hole to 6,01: D): g Cement volume based on annular vol e plus 40% open hole excess and shoe joint(s). The job will consist of a 1 Stage at the • , oe and a 2 Stage thru a DV collar to cover the current tail and cement will be brought to s ace. The estimated total volume is as follows: 1 Stage: 1418' X 0.3132 cuft/ft (12 -1/4" x • •/8 ") X 1.4 = 622 cuft = 278 sxs (2.24 yield) 2nd Stage: 800' X 0.3132 cuft/ft (12 -1/4" x 9 -5/: X 1.4 = 351 cuft = 157 sxs (2.24 yield) 1 Stage 80' shoe joint X 0.4257cuft/ft = 34 cuft = 15 sxs (2.24 yield) 2nd Stage 20' shoe joint X 0.4257cuft/ft = 9 cuft = 4 sxs (2.24 yield) TOTAL: 622 + 351 + 34 + 9 = 1016 cuft or 45' xs 7" Casing (8 -1/2" Hole to 9,951' MD): Cement volume based on annular volume plus 35% open hole -xcess and shoe joint(s). The job will consist of a lead only and cement will be brought to 2,0 '0' MD (Previous shoe). The estimated total volume is as follows: Lead: 4,083' X 0.1268 cuft/ft (8 -1/2" x 7 ") X 1.35 = 699 cuft = 31 xs (2.24 yield) 80' shoe joint X 0.2148 cuft/ft = 17 cuft = 8 sxs ' .24 yield) TOTAL: 699 + 17 = 716 cuft or 320 sxs 9 Cement Program 11- 06.doc 1 11/26/2008 • • Chevron Ivan River Unit IRU 11 -06 Gas Well Cement Program Cement ' ype and Design: Surface Casi ' , 13 -3/8 ", Lead Cement Type: Type 1 Density: 13.0 pp• Cement: 499 sx Yield: 1.82 ft /sx Mix Water: 7.58 gal /s Slurry Volume: 165 bbl Additives: Static Free 0.050% BWO Anti- Static Calcium Chloride 1.000% . OC Accelerator SUPERSEDED LW -6 12.000% BWOC Light , eight additive FL -63 0.1000% BWOC Fluid L 'ss Additive CD -32 0.6000% BWOC Disper- nt FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 1.000% BWO Accelerator BA -10A 0.9000% BWOC Matrix Flo Control MPA -1 5.000% BWOC Pozzolan Intermediate Casing, 9 -5/8 ", 1st Stage Ce ent Type: Class G Density: 12.0 ppg Cement: 293 sx Yield: 2.24 ft /sx Mix Water: 9.71 gal /sx Slurry Volume: 117 bbl Additives: BA -90 15.000% BWOC Silica Static Free 0.500% BWOC Anti - Static FL -63 1.200% BWOC Fluid Loss Additive CD -32 1.000% BWOC Dispersant FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 0.300% BWOC Accelerator LW -7 -6 10.000% BWOC Light- weight additive Intermediate Casing, 9 -5/8 ", 2 "d Stage Cement Type: Class G Density: 15.8 ppg Cement: 159 sx Yield: 2.24 ft /sx Mix Water: 9.71 gal /sx Slurry Volume: 63 bbl Additives: BA -90 15.000% BWOC Silica Static Free 0.500% BWOC Anti - Static 9 Cement Program 11- 06.doc 2 11/26/200. • • Chevron Ivan River Unit IRU 11 -06 Gas Well Cement Program FL -63 1.200% BWOC Fluid Loss Additive CD -32 1.000% BWOC Dispersant FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 0.300% BWOC Accelerator LW -7 -6 10.000% BWOC Light- weight additive Production Casing, 7 ", Lead Cement Type: Class G Density: 12.0 ppg Cement: 320 sx Yield: 2.24 ft /sx Mix Water: 9.70 gal /sx Slurry Volume: 127 bbl Additives: BA -90 15.000% BWOC Silica Static Free 0.050% BWOC Anti - Static FL -63 1.200% BWOC Fluid Loss Additive CD -32 1.000% BWOC Dispersant FP -6L 1 gal /100 sx Anti -Foam Sodium Metasilicate 0.300% BWOC Accelerator LW -7 -6 10.000% BWOC Light- weight additive R -3 0.350% BWOC Retarder 9 Cement Program 11- 06.doc 3 11/26/2008 • Chevron %111.1 Ivan River Unit IRU 11 -06 Gas Well Mud Program Surface Hole Recommendations Mud Type: Spud Mud (Water- based) Properties: Depth Densi Viscosity Plastic Viscosity Yield Point API FL 10 S. Gel 0 - 1000' 8.7 -9.3 250 - 150 10 - 30 35 - 40 unrestricted 10 - 15 System Formulation: Spud Mud (Water- based) Product Concentration Fresh Water 0.95 bbl Aquagel 25 ppb (35 -40 YP) X -Tend 11 0.1 ppb Caustic Soda 0.2 ppb (9.0 pH) Soda Ash 0.2 Intermediate Hole Recommendations Mud Type: 6% KCI, EZ Mud (Water- based) Properties: Depth Density Viscosi Plastic Viscosity Yield Point API FL pli 1000 - 6018' 9.1 -10.0 • 40 - 50 8- 25 20- 28 < 5 8.5 -9.5 System Formulation: 6 %KCI, Clayseal Product Concentration Water 0.905 bbl KCI 19.8 ppb (30K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.25 ppb (as required 35 YP) PAC L 1 ppb Dextrid 1 ppb Clayseal 0.6 gal (.2 initially) X -Cide 0.015 ppb (1 can per 400 bbl) Baracor 700 1 ppb Barascav D 0.5 ppb (maintain per dilution rate) Baroid As required Production Hole Recommendations Mud Type: 6% KCI, EZ Mud (Water- based) Properties: Depth Density Viscosity PV YP API FL pH 6018 - TD 10.0 —10.6 ' 40 - 50 6 -15 18 -25 <5 8.5 — 9.5 10 Mud Program 11- 06.doc 1 11/26/2008 1 Chevron Ivan River Unit IRU 11 -06 Gas Well Mud Program System Formulation: 6% KCI, Clayseal Product Concentration Water 0.905 bbl KCI 19.8 ppb (30K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.25 ppb (as required 35 YP) PAC L 1 ppb Dextrid 1 ppb Clayseal 0.6 gal (0.2 initially) X -Cide 207 0.015 ppb Baracor 700 1 ppb Barascav D 0.5 ppb (maintain per dilution rate) Baroid As required* *There will be an adequate stock of Barite on location to increase mud weight by 1.5 ppg for entire mud system Monitoring Equipment to be used on the circulating system: • Flow Show — Gauge for returns • Pit Volume Totalizer System • Mud /Gas Detection System for Methane and H • 10 Mud Program 11- 06.doc 2 11/26/2008 Chevron %1110 Ivan River Unit IRU 11 -06 Gas Well Drilling Waste Plan Drilling Waste Plan The drilling operations will utilize water -base mud for all drilling: Approved Class II wastes such as cuttings, liquids and used mud will be hauled by Super Sucker or Vacuum Truck from the IRU 11 -06 well location to the Grind & Inject unit set up on the Ivan River pad. The Grind & Inject unit will utilize IRU 14 -31 (PTD No.175 -008), a currently active Class II Disposal well. If permitting and technical work is completed, IRU 13 -31 (PTD No. 192 -088) will be used as the primary Class II Disposal well during drilling operations at Ivan River. 11 Drilling Waste Plan.doc 1 11/25/2008 1 • Chevron Ivan River Unit IRU 11 -06 Gas Well Log /Core /Test Programs LOGGING Surface Hole, 16" 0' - 1,000' MD: BHA: Straight Hole Assembly (No Motor) MWD: None (Directional Surveys will be made w/ a multi -shot survey) LWD: None Open Hole: None Cased Hole: None Intermediate Hole, 12 -1/4" 1,000' - 6,018' MD: BHA: Rotary Steerable 9" rY ( ) MWD: Directional LWD: Gamma Ray, Resistivity Open Hole: None Cased Hole: None Production Hole, 8 -1/2" 6,018' - 9,951' MD: BHA: Rotary Steerable (6 -3/4 ") MWD: Directional LWD: Gamma Ray, Resistivity Open Hole: Gamma Ray, Resistivity, Density, Neutron, Sonic Open Hole: FMI (6018' — 7575') Cased Hole: None CORING None Planned TESTING Following rig demobilization, flowing testing of the well will be from the well tree thru buried flowline from the well location to the Ivan River production facilities. All fluid volumes will be metered. 12 Log- Core -Test Programs 11- 06.doc 1 11/26/2008 • 0 la Chevron ESTIMATED GEOLOGIC TOPS AND CORRELATIONS IRU 11 -06 Elevation 30.0 RKB 16.4 Zone / Pore Depths ( +/- 50') Marker Lithology Fluid Target* Press (ppg) MD TVD TVDSS � Upper Disposal Sand Water IRU 14 -31 Inj 8.7 3015 2821 -2774 Lower Disposal Sand Water IRU 13 -31 Inj 8.7 5094 4272 -4225 Beluga Coal Coal Gas/Water N/A 8.5 5761 4838 -4791 Sterling Lower Sand Gas/Water Secondary 8,5 5822 4885 -4838 58 -4T Sand Gas/Water Secondary 4.4 5946 4980 -4934 59 -6T Sand Gas/Water Secondary 8.5 6064 5072 -5026 60 -2T Sand Gas/Water Secondary 6.0 6119 5115 -5069 Beluga Sand Gas/Water Secondary 5.8 6254 5221 -5175 71 -3ST Sand Gas/Water Secondary 2.5 6343 5292 -5245 73 -2ST Sand Gas/Water Secondary 8.5 6479 5401 -5355 74 -8ST Sand Gas/Water Secondary 8.5 6594 5493 -5447 75 -3ST Sand Gas/Water Secondary 8.5 6646 5536 -5489 75 -7ST Sand Gas/Water Secondary 8.5 6679 5563 -5516 Tyonek Coal Gas/Water N/A 8.5 9392 7831 -7785 IRGSTop Sand Gas/Water Primary 1.7 - 4.8 . 9407 7843 -7797 IRGSBase Sand Gas/Water Primary 1.7 - 4.8 , 9573 7983 -7936 TD Siltstone Water Well TD 8.5 9951 8168 -8121 *Current Cement Design will isolate all fresh water and hydrocarbon zones. IV 13 -3/8" Casing Cement to Surface 9 -5/8" Casing Cement coverage of both Disposal Injection intervals 7" Liner Cement to 9 -5/8" shoe @ 6018' MD / 4916' TVD UNOCAL GENERAL INPUT DATA Field Ivan River Well Name 11 -06 RT -MSL 16.7 ft Water Depth 0 ft Sea Water Gradient 0.447 psi /ft Casing Size to be Designed 9 -5/8 inch Hole Size Drilled for This Casing 12 -1/4 inch DESIGN METHOD 1: From TD up to find the shallowest allowable shoe depth Hole Size Below the Shoe 8 -1/2 inch Next Section Total Vertical Depth 8,168 ft TVD RKB Next Section Total Vertical Depth 8,151 ft TVD BML Next Section Gas Gradient (first approximation: 0.075) 0.100 psi /ft Kick Intensity (Swab kick = 0.0 ppg intensity) 0.5 PPG Mud Weight 10.6 PPG Estimated Formation Pressure at Next Section TD 11.1 PPG EMW Fracture Gradient 0.71 psi /ft Kick Tolerance 20.0 bbl Drill Pipe Outside Diameter 5 inch (Calculation results acceptable. Minimum shoe depth = 3,713 ft TVD RKB 1 DESIGN METHOD 2: From upper casing shoe down to find the deepest hole which can be drilled without fracturing the upper casing shoe Upper Casing Size 13 -3/8 inch Upper Casing Shoe Depth 1,000 ft TVD RKB Upper Casing Shoe Depth 983 ft TVD BML Upper Gas Gradient (first approximation: 0.008) 0.100 psi /ft Hole Size below the Upper Casing Shoe 12 -1/4 inch Kick Intensity (Swab kick = 0.0 ppg intensity) 0.0 PPG Mud Weight 10.0 PPG Estimated Formation Pressure 10.0 PPG EMW Fracture Gradient 0.67 psi /ft Kick Tolerance 10.0 bbl Drill Pipe Outside Diameter 5 inch (Calculation results acceptable. Maximum shoe depth = 4,978 ft TVD RKB 1 mdb /03jan01 Chevron %110 LEAK OFF TEST PROCEDURE 1. Clean out the rathole below the shoe, and drill 20' of new hole. Circulate and condition mud. 2. Pull the drill string into the shoe. Rig up to observe annulus pressures. 3. Close the pipe rams and pump down the drillpipe at a slow rate (1/4 - 1/3 BPM) if exposed formation is permeable. A non - permeable formation should be step tested to a predetermined pressure. 4. Measure the volume pumped and plot annulus pressure -vs- cumulative volume pumped. Compare annulus pressure to drill pipe pressure and confirm both are the same. Record and plot pressure versus volume pumped. The pumps should be shut down immediately upon indication of leak -off. Record the inital, shut down pressure and the pressure after 1, 2, and 3 minutes. 5. Release pressure and record the volume of fluid recovered in the trip tank. The point "B" shown in the attached graph at which the plot of drillpipe pressure stops increasing equally as the volume is pumped is called the P.I.T. limit, Leak Off, or pressure integrity test limit. The leak -off pressure is calculated as follows: Leak -off (EMW) = Mud weight in hole + P.I.T. (PSI) (0.052) X (shoe depth in TVD ft.) This equivalent mud weight should be made known to all drilling personnel to ensure it is not exceeded. See the drilling procedure for guidelines on expected LOT's or pressure integrity test limits for each casing shoe. B SURFACE PRESS. TYPICAL PIT PLOT (psi) A VOLUME PUMPED SHUT -IN -TIME (BBLS) (MIN) NOTES: Point "A" will have some variance until the system begins to pressure up. Point "B" is the leak off and is abbreviated LOT. Point "C" is known as the injection pressure and is usually dependent on rate. Point "D" is known as the fracture closure pressure and may not stabilize if permeable formations are exposed. 0 _41i) FND BRASS CAP N 28 E 380463.181 © e •. 4P 7 1b i ,'° SEC 1 T13N R9W SM AK 4. Po C t oo, , • ( :. 7 *• . ,?ts POND ELEV. 21' Water V., ete L, � Bldg. Well Has n 1 Scrubbx rl► 44 • f O Well Nee. ' :* �, ref 14 - 3 1 O W Hse �,. `.. 41 1 O Generator 44 • •44.Ahedg. 13 Well Hse. N: 2848434.171 w/ E:359829.223 A g l � Qf°t � r � i E:359 LATITUDE: 611417.902" \ ` J. ♦ 4 WIeN HI" _'v` o LONGITUDE: — 1504Y48.882' �. GI Compresaor 44-1 wear ww 2 \ �o/ ` K LO 2646418.845 ` 23 11(6 J = $ LATITUDE: 61427.753 IVAN RIVER PAD 1- s LONGITUDE: — 150'47'48.239" A • 41 - 1 b N: 2646404.136 ` ‘NN\\\ 11 ' `.. Q v , . r ae.. ' ; �� f Z L1nNDE 611417.611 ` ��S, OF Az , Ili • waar ^" '" 630 FEL LONGITUDE: — 150 13 — b; wJ%:919. �P ' nr � oly 44„1 ; ^,;.g'�`,<- tom- \ , R U 11-06 E 'AS— STAKED un 1UOE 8114'27.105• 0 ' _ SCOT M . . J LONGITUDE: — 150 I (/) N: 2646275.023 "I `51, ' I{ 49� S ` -• E: 59784.661 3 I �� g ia++� `' `� oo LA : 61 14 26.353 N� I LONG:150 45.446 W k l‘V%A.S% SECTION ma NOT To SOME NAD27ASP ZONE 4 , I • SURVEY NOTES ELEV. 30' MSL . 12 7 1. COORDINATE DATUM IS NAD 27 ALASKA STATE ___ 630' FEL PLANE ZONE 4. 585' FSL ' PUTED POs. 2. ASLS 75 -70 P.I. WERE RECOVERED AND USED FOR E 3604 1 HORIZONTAL CONTROL. N R TH 3. VERTICAL DATUM IS REFERENCED TO THE .�I►4.;,- NAVD88, AND IS BASED ON THE GPS DERIVED OPUS 0 SCALE To SOLUTION AT CP -1 (GEODO6 APPROX. MSL HEIGHTS). I 100 I I IRU 11 -06 hevron AS- STAKED SURFACE LOCATION IVAN RIVER UNIT, BELUGA AK LOCATION: SECTION 1, TOWNSHIP 13 NORTH, fil ENGINEERING - TESTING RANGE 9 WEST, SEWARD MERIDIAN ALASKA SURVEYING - MAPPING P.O. BOX 468 NAD27 DATUM _Y+__ SOLDOTNA, AK. 99669 JOB NO. 083083 VOICE: (907) 283 -4218 FAX: (907) 283 -3265 DWG. Consulting Inc WWW.MCLANECG.COM 083083_NAD27 I Date: 11/19/08 FIGURE: 1 0 • Legend ; - - -- - - - - - -- IRU 11 -06 Track I 1500 ft Buffer ! T 1 3000 ft Buffer j • Bottom Holes i ADL t 6058 Wel Tracks i ADL302284 STUMP LAKE UNIT - - I ---- - - - r PA: GAS POOL #1 jam; Unit Boundary !!J i Leases IVAN RIVER UNIT DL058792ADL058791 Roads j I ' IVAN R 13 -31 Co I J o r /a, �, �.,� IVAN R 14 -31 <4 • • IVAN R 44 -36 r \ IVAN R 41 -01 ',, ,1L) - IRU 11 -06 Bottom Location X 360,782 �� Y 2,650,719 � �,„ ADL058795 IRU 11 -06 Target Location X 359,455 , , IVAN 244 - 01 i Y 2,649,122 IM � -� ' IRU 11 -06 Surface Location ' L03372 i — X 359,785 _j -- Y 2,646,275 ', /._,, 1___________- j 1 ADL390571 IVAN R 23 -12 Cook Inlet • 0 N , A Chevron 0 1,500 3,000 Wellpath IRU 11 -06 Feet Top Target t & TD Radius Alaska State Plane Zone 4, NAD27 p g November 19, 2008 NM 1. MUTER ANNIAAR NORIIYLY OPEN. 2 RN-VALVE NORIM LY CLOSED. _ IN A�aA40M I 21 2 115P • aa6< 2aDaPS ._.. —� -- ANNULAR ■imom II ■I I FAOY ASIMIARW ONERIER SPO01. API 21 1/4 - 2000PS1 FIANCES ! I • . _t Il II . �J� • �E!I r, ._ X12 ' T s -- -- I 1111W OMB LK II II ..1 . � E _ : _ .. �1� y n _ — — — — RAY-VALVE s• 50 FLUMES VALVE ICES F I II DIVERTER CONFIGURATION 1 II I y • �o ; — •111. -LC-' :.::,,,1� _ ...4. ' - �,�.. II �, ':: = 1► r1i P:. • =• & -,; II l.i - - - WE a:� __, _,....... ,.� II II II II • NABORS ALASKA RIG 129E 111 , I I GENERAL ARRANGEMENT BAsm w 1R01P is gaitlagenkan e WICWI w ili NPbP '''' 0.* ho. Nabors Maths � N�r 911503-2639 aNA6es�wRl.ow 60Y- PPO= MOORS ALASKA RIG 129 '" GENERAL. ARRANGEMENT SEP 06 b JA MY MOM CIfUIF HOUSE 12• DNERTER SYSTEM 240190.7 A JA P.S. ICBM SAVIOR (16• Iii[ 21 -I/4' IMAM) 6016 mu Ram If/ NM SI - PALM. 5161N WV. 6 WE i le 7,"197. =PIM N/A 3/26/03 0 129_0001 w t of 1 SCALE DM • IRU 11 -06 BOP Stack Diagram - w/ Nabors 129 Underside of Rotary Table Driu Pan / Planned Test Pressure 250/3000 psi 13 -5/8" Shaffer Annular 5M J 13 -5/8" Shaffer 5M Dbl Gate I 24/8" x 5 -1/2" VBR Pipe Rams l 13 -5/8" Shaffer 5M Blind Rams ° To choke manifold From kill fine — (3 7 1/7' 3� Sm 13 - /8" 5M 31/8" 31/8" a' HCR 5m Mud Cross 5m 5m ■:"• 13 -5/8" Shaffer 5M Single BOP I I 4" or 5" pipe rams 1 1 Ground Level Rig Mats 7" outlet I. 13 -5/8" 5M MB -242 Wellhead 9 5/8" outlet ?) 3/8" outlet 1 r 20" Conductor (driven) Well Cellar 1 NI 4 c�Rs - �.k L. 1i RIG 29E Material List Item Descristion 10 - 11 4-1/16" 10M Gate Valve 3, 4, 7, 8, 9 3-1/8" 5M Gate Valve 1, 2, 5, 6, 12 3-1/16" 10M Manual Choke Valves T 0. Ga' A 2- 9/16" 10M SWACO Su • er Choke - _ C�u lc B 3- 1/16" 10M Manual Choke '-� 0 = 0 p A ' co e X10 l Legend �"°' Whig F Iarxile Valve. Normally Open l ► Red Handle Valves � .� ,.�e . � � �,. ,� oro.�_ ,4_ . � �: =_ � x ,� , -�,�� , �,,.�� <.,�� • IF Normally Closed Date: 12 -23 -05 Rev. 3 Inl t ` I !O JIM m1 m WO . 3nac 1414e11300 42,a 25 ar'l 6m 9031 m /8 QM03iM /8 031910 /8 NOM - Wld lOb 6L1 ON 3191 6711 ON ypgy ICK -COU6 M1M� '011 � 91 41 M10 0 M 91 A AZIASN INA AI ME Y9111 — .01 -.Z .9-.► .ItAL .4;' IlleMFArk .p .$1-0 `L l�� l.. -...1 � .9-.► IJ Ilip irilliiii.1-§ 11 1 _I �.,' . v 111 = ��1111111111 � �� itilMVIITIVIVIIMMIN 111111I1 11 • °7 l+"i _ -. =' ) A - � ��I_IIIIIII �� - [] [7 [] '� _ i�. : 1 • _= r4 ti cl t. a A-A .e - S9 AS6 A'1901 FW: Schematic as requested Aw Page 1 of A Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, December 09, 2008 10:37 AM To: 'Bonnett, Nigel (Nigel.Bonnett)' Cc: PORHOLA, STAN T; Santos, Ronilo; Harness, Evan Subject: RE: Ivan River Unit well 11 -06 Diverter System Thanks Nigel. My question is answered. Tom From: Bonnett, Nigel (Nigel.Bonnett) [mailto:Nigel.Bonnett @chevron.com] Sent: Tuesday, December 09, 2008 10:34 AM To: Maunder, Thomas E (DOA) Cc: PORHOLA, STAN T; Santos, Ronilo; Harness, Evan Subject: RE: Ivan River Unit well 11 -06 Diverter System Morning Tom, We have interfaced with Nabors Rig 129 currently working the 13 -31 conversion work -over and can confirm that for Ivan River Unit well 11 -06, we will utilise :- - 21 -1/4 H Y dril 2M Annular with 16" Diverter Valve - 16" Diverter line for drilling the 16" surface hole section and running 13 -3/8" surface casing. Refering to Attachment 17 in the Permit to Drill, the Diverter System Diagram is mistitled " 12" Diverter System ". The actual schematic detail is labelled correctly as outlined above. I hope the above is satisfactory. Regards, Nigel From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Monday, December 08, 2008 5:33 PM To: Bonnett, Nigel (Nigel.Bonnett) Cc: PORHOLA, STAN T; Santos, Ronilo; Nash, R Scott Subject: RE: Ivan River Unit well 11 -06 Updated 9 -5/8" Casing Cement Programme Importance: High Nigel, On my last review of the packet, I noticed that the diverter drawing for Rig 129 says it is a "12" system ". 16" surface hole is planned. I do not find any request for a waiver to drill 16" hole with a 12" diverter line, however that is a waiver that would not be granted. 12 -1/4" hole is the largest that has been allowed with a 12" diverter line. Would you or one of your engineers please look into this? If the diverter line is indeed 12 ", the largest hole size that will be authorized is 12 -1/4 ". I look forward to your reply. Tom Maunder, PE AOGCC From: Bonnett, Nigel (Nigel.Bonnett) [ mailto:Nigel.Bonnett@chevron.com] Sent: Monday, December 08, 2008 4:52 PM To: Maunder, Thomas E (DOA) Cc: PORHOLA, STAN T; Santos, Ronilo; Nash, R Scott 12/9/2008 FW: Schematic as requested Page 1 of$ Maunder, Thomas E (DOA) From: Bonnett, Nigel (Nigel.Bonnett) [Nigel.Bonnett@chevron.com] Sent: Monday, December 08, 2008 4:52 PM To: Maunder, Thomas E (DOA) Cc: PORHOLA, STAN T; Santos, Ronilo; Nash, R Scott Subject: RE: Ivan River Unit well 11 -06 Updated 9 -5/8" Casing Cement Programme Attachments: IRU 11 -06 (P8) report.pdf Tom, Apologies for ommission. Please find complete Directional Report for well 111 -06. Rgds, \� �S�o t. Qc2.( . S C J ` C) ` - cam �c�, s 4_2_7111 ta( From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, December 08, 2008 1:39 PM To: Bonnett, Nigel (Nigel.Bonnett) Cc: PORHOLA, STAN T; Santos, Ronilo; Nash, R Scott Subject: RE: Ivan River Unit well 11 -06 Updated 9 -5/8" Casing Cement Programme Gentlemen, I was finalizing the permit application for IRU 11 -06 and I noticed one item still missing. I am unable to find a copy of the request, however I had requested some proximity information on the proposed well and close approaches. The text of my message on 12/3 at 13:14 was, 1 !$B!HI (BAlthough close approach issues are mentioned in the cover letter, I done I$B!GI I(Bt find any documentation about the proximity analysis in the packed. Could you provide a traveling cylinder plot and a listing showing the close approaches ?I !$B!li l(B This may have gotten lost in the concerns about the cement height on the intermediate casing. II I$B!GI (Bd appreciate receiving the information. Thanks in advance. Call or message with any questions. Tom Maunder, PE Fro :onnett, Nigel (Nigel.Bonnett) [mailto:Nigel.Bonnett@chevron.com] Sent: Thu ,.. December 04, 2008 1:10 PM To: Maunder, Tho - DOA) Cc: PORHOLA, STAN T; Sa Ronilo Subject: Ivan River Unit well 11 -1 • - •ated 9 -5/8" Casing Cement Program • - Tom, To address non exempt aquifers on the planned I . ' fiver Unit we 16, we propose to increase the cement pumped on the 2nd stage of the 9 -5/8" cas • = ement job to 205 bbls of 12. I . • • slurry. Assuming 40% open hole excess, this will bring the 2nd s - = - OC to 900 ft MD, 100 ft inside the 13 -3/: . • ,ce casing. I enclose updated - Drilling Proce• . - Summary - Propo -: ell Schematic 12/8/2008 FW: Schematic as requested Page 1 of • • Maunder, Thomas E (DOA) From: Bonnett, Nigel (Nigel.Bonnett) [Nigel.Bonnett©chevron.com] Sent: Thursday, December 04, 2008 1:10 PM To: Maunder, Thomas E (DOA) Cc: PORHOLA, STAN T; Santos, Ronilo Subject: Ivan River Unit well 11 -06 Updated 9 -5/8" Casing Cement Programme Attachments: 4 WBD IRU 11-06 Proposed v9.0.pdf; 9 Cement Program 11 -06 revl.doc; 3 Drilling Procedure Summary IRU 11-06 revl.doc Tom, To address non exempt aquifers on the planned Ivan River Unit well 11 -06, we propose to increase the cement pumped on the 2nd stage of the 9 -5/8" casing cement job to 205 bbls of 12.0 ppg slurry. Assuming 40% open hole excess, this will bring the 2nd stage TOC to 900 ft MD, 100 ft inside the 13 -3/8" surface casing. I enclose updated - Drilling Procedure Summary - Proposed Well Schematic - Cement Programme Thanks for identifying this oversight. Regards, Nigel From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednesday, December 03, 2008 6:15 PM To: Bonnett, Nigel (Nigel.Bonnett) Subject: RE: Schematic as requested Nigel, I have spoken with Commissioner Foerster and apprised her of you request. She has given her oral approval for you to proceed. I will look for the sundry tomorrow. Call or message with any questions. Tom Maunder, PE AOGCC From: Bonnett, Nigel (Nigel.Bonnett) [ mailto :Nigel.Bonnett @chevron.com] Sent: Wed 12/3/2008 4:48 PM To: Maunder, Thomas E (DOA) Subject: FW: Schematic as requested Tom, Please refer to attached P &A schematic for SRU well 211 -33. What we propose to do is set 4 cement plugs on top of each other from TD (4760' MD) to 4160 'MD. This will isolate all permeable porous zones in the well. 12/8/2008 • Page 1of2` Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, December 03, 2008 3 :25 PM To: 'PORHOLA, STAN T' Cc: 'Bonnett, Nigel (Nigel.Bonnett); Regg, James B (DOA) Subject: RE: IRU 11 -06 -- CRITICAL ISSUE Importance: High Nigel, In the last message, I misquoted a depth in the last sentence. It should read ... Unocal /Chevron should make plans to isolate the non - exempted intervals between - 2306' tvd and the 13 -3/8" casing shoe. Sorry about that. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Wednesday, December 03, 2008 2:55 PM To: 'PORHOLA, STAN T Cc: Bonnett, Nigel (Nigel.Bonnett); Regg, James B (DOA) Subject: RE: IRU 11 -06 -- CRITICAL ISSUE Importance: High Stan, Further examination of the application has revealed a critical issue. The Commission issued Aquifer Exemption Order (AEO) 6 July 23, 2001. That order exempted all aquifers for a % mile radius of IRU 14 -31 between the depths of 2500' - 3420' and (- 2306' - 3000' tvd). I believe IRU 11 -06 lies within that radius. In IRU 11 -06 13 -3/8" surface casing is planned at 1000' and /tvd and 9 -5/8" intermediate casing at 6018' md/4916' tvd. The surface casing will be cemented to surface while the intermediate casing will be cemented in 2 stage operation back to 3800' and (- 3331' tvd). Unocal /Chevron should make plans to isolate the non - exempted intervals between - 3000' tvd and the 13 -3/8" casing shoe. Call or message with any questions. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Wednesday, December 03, 2008 1:41 PM To: ' PORHOLA, STAN T' Subject: RE: IRU 11 -06 -- AGAIN Stan, Although close approach issues are mentioned in the cover letter, I don't find any documentation about the proximity analysis in the packet. Could you provide a traveling cylinder plot and a listing showing the close approaches? Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) 12/3/2008 • • Page 2 of 2 Sent: Wednesday, December 03, 2008 1:33 PM To: 'PORHOLA, STAN T' Subject: IRU 11 - 06 Stan, I am reviewing the permit application for this well. Would you have a look at the 7" cementing design? In the cementing section, the string is listed as a long string rather than a liner and the planned TOC is well above the planned liner top. Also, is spud still anticipated for about the 17t? Thanks in advance. Call or message with any questions. 12/3/2008 i 1 TRANSMITTAL LETTER CHECKLIST WELL NAME — L---/a-rt vex /7-04 PTD# 2- CS /05 Development Service Exploratory Stratigraphic Test Non- Conventional Well Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD -ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) 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(0, all records, data and togs 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 pl ce with 20 AAC / EXCEPTION 25.055. Approval to perforate an ► rodu / t is contingent V upon issuanc� ,of c rvation orde , �jjourg a spacing exception.. lit$ its" Of f / f» the liability of any protest to the s aci eption 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. Please note the following special condition of this permit: Non - Conventional production or production testing of coal bed methane is not allowed Well 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: 7/13/2007 Gcri g. y t ' r�4444 rK tit • ,G�- yrrV 4 � e %/ . eit frig - �' g ,27 ft WELL PERMIT CHECKLIST Field & Pool IVAN RIVER, UNDEFINED GAS - 360500 Well Name: IVAN RIVER UNIT 11 -06 Program DEV Well bore seg ❑ PTD#: 2081840 Company UNION OIL CO OF CALIFORNIA Initial Class/Type DEV / PEND GeoArea 820 _ Unit 10970 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA ,2 Lease number appropriate Yes Entire well will lie within ADL 32930 3 Unique well name and number Yes 4 Well located in a defined pool No IVAN RIVER, UNDEFINED GAS - 360500 5 Well located proper distance from drilling unit boundary Yes 6 Well located proper distance from other wells No SPACING EXCEPTION REQUIRED: application received from operator on 11/24/2008; notice scheduled 7 Sufficient acreage available in drilling unit No for publication on 11/26/2008. 8 lf_deviated, is_wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has_ appropriate bond in force Yes 11 Permit can be issued without conservation order No Appr Date 12 Permit can be issued without administrative approval Yes SFD 12/2/2008 13 Can permit be approved before 15 -day wait Yes • 14 Welllocated within area and_strata authorized by Injection Order # (put 10# in comments) (For NA 1 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre - produced injector: duration of pre production less than 3 months_ (For service well only) NA 17 Nonconven, gas conforms to AS31,05A30(1.1.A),(j,2.A -D) NA 18 Conductor string provided _ - - - -- - -- Yes - - - - -- -- - - - - -- -- - - - - -- - - - -- - - - - -- Engineering 119 Surface casing protects all known ttSDWs No Surface casing set shallow. Intermediate cement will provide isolation of Non - exempt intervals. 1 20 CMT vol adequate to circulate on conductor & surf csg Yes 21 CMT_v_ol_ adequate to tie -in long string to surf csg Yes 22 CMT_will coverall known_ productive horizons Yes 23 Casing designs adequate for C, T_, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig equipped with steel pits. No reserve pit planned. All waste to approved disposal well(s). 25 If a re- drill, has a 10 -403 for abandonment been approved NA 26 Adequate wellbore separation-proposed Yes Proximity analysis performed. Traveling cylinder path calculated. 27 If diverter required, does it meet regulations Yes Appr Date 28 Drilling fluid program schematic_$ equip list adequate Yes Maximum expected formation pressure 8.7 EMW. MW planned up to 10.6 ppg. TEM 12/9/2008 29 PEs, -do theymeet reg ulation Yes 4 ............. _ 30 BOPS -press rating appropriate; test to -(put psig in comments) Yes MASP calculates at 2777 psi. 3000- psi _ BOP test p lanned, • 31 Choke_rnanifold complies w /API_RP -53 May 8 4) Yes 32 Work will occur without oper ation shutdown Yes 33 is presence of H2S gas probable No H2S is not reported in CI gas production. 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 _Permit_ can be issued w/o hydrogensuifide me asures Yes Geology 36 Data_presented on potential overpressure zones Yes Reservoir pressures are expected to range from 1.7 to 8.7 ppg EMW. Will be drilled with 8.7 Appr Date 37 Seismic analysis of shallow gas_z_ones NA to 10.6ppg mud. SFD 12/2/2008 38 Seabed condition survey (if off - shore) NA 39 Contact name /phone for weekiy_progress reports [exploratory only] NA Geologic Engineering Publi SPACING EXCEPTION REQUIRED because well will be 2650' from another well capable of producing gas from the same undefined pool. Well will lie Commissioner Date: Comm ssioner: Date Co t$ r Date about 3000' from the nearest boundary of the Ivan River Unit, which is owned entirely by Unocal. Spacing exception application received 11/24/2008, and �j'` notice was scheduled for publication on 11/26/2008. The public hearing is scheduled for 1/7/2009. Correlative rights are not an issue here, so I recommend /2 - g ; �� 0 8 -4 approval of permit to drill prior to granting the spacing exceptions. SFD • Well History File APPENDIX Information of detailed nature that is not • particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically • organize this category of information. • Chevron I OW Chevron North America E &P, Inc. IRU 11 -06 Ivan River Unit Kenai Borough, Alaska Section 1- T13N -RO9W, SM Cook Inlet, Alaska • January 29, 2009 FINAL WELL REPORT Harry Bleys — Sr. Logging Geologist Zachary Beekman — Logging Geologist Jeff McBeth — Logging Geologist Justin VanDerberg — Logging Geologist El EPOCH O TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT AND CREW 3 1.1. EQUIPMENT SUMMARY 3 1.2. PERSONNEL 3 2. GENERAL WELL DETAILS 4 2.1. OBJECTIVES 4 2.2. WELL RESUME 4 2.3. HOLE DATA 4 3. GEOLOGICAL DATA 5 3.1. LITHOLOGY AND REMARKS 5 3.2. MUDLOG SUMMARY 6 3.3. SAMPLING PROGRAM AND DISTRIBUTION 13 4. DRILLING DATA 14 4.1. DAILY ACTIVITY SUMMARY 14 • 4.2. SURVEY RECORD 18 4.3. MUD RECORD 22 4.4. BIT RECORD 24 5. DAILY REPORTS 25 Enclosures: Formation Log 2" = 100' MD /TVD LWD Combo Log 2" = 100' M D /TVD Drilling Dynamics Log 2" = 100' MD/TVD Final Data CD • [I EPOCH 2 • Chevron CHEVRON — IRU 11 -06 1 MUDLOGGING EQUIPMENT AND CREW 1.1. EQUIPMENT SUMMARY Parameter Equipment Type And Position Total Comments Downtime Electric Driven QGM Gas Trap Ditch Gas Mounted In Possum Belly; FID Total 9h 10m Hydrocarbon Analyzer And Chromatograph Rate of Penetration (ROP) Primary Draw works Belt Driven 0 Encoder On Drum Shaft (Rigwatch) Pump stroke counter Externally Mounted Magnetic Proximity 0 Sensor (Rigwatch) Hook load / Weight on bit (WOB) Proximity Crown Encoder (Rigwatch) 12h Wind snapped sensor cable Drill string torque Digital Signal From Top Drive 0 (Rigwatch ) Top drive rotary (RPM) Digital Signal From Top Drive 0 (Rigwatch) Standpipe Pressure Hydraulic Pressure Cell (Rigwatch) 0 Casing Pressure Hydraulic Pressure Cell (Rigwatch) 0 Mud flow in / out (MFI / MFO) MFI Derived From SPM / MFO From 0 110 Flow Paddle (Rigwatch) Pit volumes Ball Float Pit Sensors In All Pits Except 0 pits 2 &b 3. Driller's work station Explosion Proof Touch Screen 0 Casing Pressure Hydraulic Pressure Cell Company man's work station Rigwatch 8 12h Due to network interruption to Tool pusher's work station Rigwatch 8 12h Due inter r n ruption Geologist's work station None on location 0 Pit's work station Explosion Proof Touch Screen 0 1.2. PERSONNEL Unit Number: ML012 Mudloggers Asa Days Technician Days Sample Catchers Days Zach Beekman 180 Steve Forrest James Patterson 5 Jeff McBeth 180 Allen Williams Noah Bodin 60 Justin VanderBerg 180 Christina Medlyn 1 Harry Bleys 4 • El EPOCH • 2. GENERAL WELL DETAILS 2.1. OBJECTIVES Ivan River IRU 11 -06 intends to drill 9950' through two zones of interest. The primary zone of interest is the IRGS. It is expected at 9406'. This well will test the productivity of the IRGS. The secondary zone of interest is the Lower Sterling at 5822' and will test feasibility of possibly producing this formation in the future. If Lower Sterling proves successful, future wells maybe be drilled to this formation. 2.2. WELL RESUME Operator: Chevron Well Name: IRU 11 -06 Field and Pool: IVAN RIVER UNIT State and Borough Kenai Borough Alaska Company Representatives: Sam Menapace / Bob Farrell Location: SEC 01, T13N, RO9W Elevation: — Ground, — RKB KB 46.4' Classification: Development Gas API #: 50- 283 - 20130 -00 Permit #: 208 -184 AFE #: UWEAKB8007DRL Rig Name / Type: Nabors 129 Primary Target: Ivan River Tyonek & Beluga Gas Sands Primary Target Depth: 9391' MD / -7785' SS TVD Spud Date : -> Finish Date : -> 12/22/08 to 1/29/09 Total Depth: 10,060' MD Total Depth Formation: IRGS Base, below Tyonek Mudlogging Company Epoch Well Services, Inc. (Canrig Drilling Technology Ltd.) MWD Company: Schlumberger Tools Run: Directional, On Trak, Litho Trak, Mag Trak, Tes Trak, GR /Density Azimuthal image logs Directional Drilling: Schlumberger Drilling Fluids Company: Halliburton 2.3. HOLE DATA Maximum Depth T.D. Mud Deviation Shoe Depth Hole g Casing F.I.T. Section MD TVDSS Formation PPg)t ( ° inc) MD TVDSS 8.5" 13076' - 10072.4 C -7D 9.8 91.88 9 5/8" 9088' -7513 14.0 6" 15381' - 10092.9 C -7D 9.5 89.61 7" 13078' -10072 - ID El EPOCH 4 3. GEOLOGICAL DATA 3.1. LITHOLOGY AND REMARKS LWD tops refer to provisional picks by the well site geologist. ACTUAL FORMATION MD SSTVD (ft) (ft) Beluga Coal 5760.61 - 4791.23 Sterling Lower 5822.19 - 4838.47 58-4T 5945.94 - 4933.88 59 -6T 6064.46 - 5026.03 60 -2T 6119.16 - 5068.80 Beluga 6253.59 - 5174.67 71 -35T 6342.73 - 5245.39 73 -2ST 6479.37 - 5354.59 74 -85T 6593.55 - 5446.57 • 75 -3ST 6645.99 - 5489.11 75 -75T 6679.28 - 5516.13 Tyonek 9391.97 - 7796.94 I RGSTop 9406.68 - 7796.94 I RGS Base 9572.83 - 7936.29 TD (pick) 9950.59 - 8121.30 Actual TD 10060.10 - 8273.28 • El EPOCH 5 3.2. MUDLOG SUMMARY BELUGA COAL 5760' MD, -4791' SSTVD D rill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 93 22 58 10 3 7 Coal = 10 — 20 %, black to very dusky red, hard and angular with brittle and blocky fracture, shiny luster, matte texture, medium sized fragments with some smaller cuttings, strong degassing present 1 hour after extraction. Tuffaceous Claystone = 10 -20 %, medium light grey to reddish orange, texture is firm, resistant to crumbling with earthy fracture and luster, has light brown streak. Sand = up to 50 %, ranging in color from white to greenish grey to moderate reddish brown, size ranges coarse to fine, hard with some evidence of weathering, subang ular to subrou nded, reddish brown grains are fine and rounded, greenish grey grains are medium coarse and subrounded. Peaks Depth TG C1 C2 C3 C4l C4N C5l C5N 5761 10 2100 • STERLING LOWER 5822'MD, - 4838'SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 140 27 82 193 03 98 Coal = 20 — 30 %, color is black to blackish red, very hard and brittle with crumbly blocky fracture, medium sized fragments, strong evidence of degassing present 1 hour after cutting extraction. Sand /sandstone = 50% sand and very poorly consolidated sandstone, light grey, light brown, translucent and reddish orange brown grains, very poorly sorted with a wide range of color, mostly subrounded, texturally mature medium -fine grained in size, pale yellowish orange grains are translucent, hard and subangular, some greenstone and trace pyrite, up to 20% silty matrix light grey in color, poor integrity, easily friable. Peaks Depth TG C1 C2 C3 C4l C4N C5I C5N 5945 193 38561 • €i EPOCH 6 58 -4T 5949'MD, -4933' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 120 27 74 408 16 212 Coal = black with some dark reddish brown, large to small size fragments, angular to subangular, vitreous, hard and b rittle, friable with striations, irregular fracture. Claystone = greenish grey, firm, moderate induration, touch, bladed, silty, dull, stiff, some tuff present, light grey in color. Sandstone = 0 -10% loose unconsolidated sandstone grayish yellow to medium grey, fine - medium size, subrounded, contains trace am ounts of greenstone with very light grey claystone. Peaks Depth TG C1 C2 C3 C4I C4N C51 C5N 5977 408 82778 59 -6T 6064' MD, -5026' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 137 16 77 71 9 40 Siltstone = dark grey, dense, blocky, waxy dull luster, silty texture. Sandstone = light grey, very fine to fine, moderate sphericity, moderate rounding, friable to poorly consolidated. Shale = brownish grey to brownish black, easily friable under slight pressure, poorly indurated, sample is very brittle, with platy fracture, clayey texture, waxy appearance, cohesive, stiff, often interbedded with claystone and siltstone. Peaks Depth TG C1 C2 C3 C4I C4N C51 C5N 6117 71 13830 60 -2T 6119' MD, -5068' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 262 7 135 549 22 285 El EPOCH 7 • Sand = color ranges from clear and translucent to white and very light grey, grain size is fine to very fine, sample is well sorted, angular to subangular with moderate sphericity, moderate hardness, well indurated, sample exhibits some consolidation of very fine grains, and traces of silica cement, color variations include light grey and light greenish grey , Claystone = color is very light grey, texture is very soft especially when hydrated, exhibits poor induration, massive cutting habit, dull luster, adhesive and somewhat mushy. Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 6180 549 106828 BELUGA 6253' MD, -5174' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 170 10 90 524 55 290 Tuffaceous Claystone = very light grey to light bluish grey claystone containing specs of light grey tuffs throughout, very cohesive, moderate induration, massive, dull, some shale interbedded, silty -ash texture. Sand = mostly clear but ranging to light grey, very fine, subangular, well sorted. Coal = black, small fragments, subangular to angular, vitreous and hard. Peaks Depth TG C1 C2 C3 C41 C4N C51 C5N 6337 524 263030 20765 71 -3ST 6342' MD, -5245' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 204 24 114 946 50 498 Tuffaceous Claystone = light bluish grey to light grey, a moderate degree of induration, texture tends towards crumbly with massive cutting habit, silty -ashy, moderately hard to firmly friable, it has a dull to earthy luster and is cohesive, tuffs are light brownish grey to light grey with a dull to earthy luster, clay has a smooth texture, non - calcareous, no n- carbonaceous. Sand = color varies from clear to white, grain size is fine to very fine, sample is well sorted and is angular to subangular with moderate sphericity. 411 Ii EPOCH 8 Coal = black, dusky to brownish black, earthy to vitreous luster, subangular, firm friable to moderately hard, well indurated, stiff, blocky fracture, crumbly, elongated to wedge -like cutting habit. Peaks Depth TG C1 C2 C3 C41 C4N C51 C5N 6381 946 442800 58591 71 -2ST 6479' MD, -5354' SS TVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 152 49 100 373 55 214 Claystone = light bluish grey to light grey, firmly friable to friable, moderate degree of induration, flexible to crumbly, elongated cutting habit, dull to earthy luster, cohesive. Sand = very light grey, fine to very fine, subrounded to rounded, well sorted. Peaks Depth TG C1 C2 C3 C41 C4N C5I C5N 6590 373 12996 3 74 -8ST 6593' MD, -5446' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 132 25 78 480 44 262 Shale = pale yellowish brown, firm friable, well indurated, tough, platy, silty - gritty, very earthy luster. Claystone = color is light grey to grayish brown, hardness is very soft to firm, moderate to well induration, very malleable, buttercurl cutting habit, exhibits a waxy to dull luster, clayey to silty texture, some evidence of tuffaceous claystone, very hydrophilic reacting quickly in the presence of water. Coal = color has little variation from black to brownish black, hardness ranges from firm to hard, sample exhibits blocky to platy cuttings with resinous and earthy luster, texture is silty to abrasive, interbedded with shales of medium light grey to medium grey. Sand = color is translucent to light grey to brownish grey, upper very fine to very fine, subangular to subrounded with moderate sphericity, poor to moderate sorting, 50 °A) quartz with some greenstone, loose unconsolidated. 411 g Li EPOCH • Peaks Depth TG C1 C2 C3 C4I C4N C51 C5N 6597 480 122283 42 75 -3ST 6645' MD, -5489' SSTVD Drill Rate (ft/hr Total Gas (units) Maximum Minimum Average Maximum Minimum Average 87 25 56 95 46 81 Claystone and tuffaceous claystone = light grey to medium light grey with few pale yellowish greens, very soft, malleable, slightly tuffaceous with earth luster to slight resinous, silty to gritty texture fining up sequence, tuff is light grey. Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 6677 95 21075 9 75 -7ST 6679' MD, -5516' SSTVD • Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 201 4 103 332 3 165 Tuffaceous Claystone = Light gray to medium gray to few pale yellowish greens, becoming grayish blue with depth; very soft, malleable; slightly tuffaceous with earthy luster to slightly resinous; silty to gritty texture fining upward; liquidy when hydrated and slow to desiccate; common butter - curling habit on cuttings; poor to moderate induration. Sand = Translucent to medium light gray; loose, unconsolidated quartz dominates with some greenstone and other lithics present; upper fine to lower coarse; subangular to rounded; low to moderate sphericity; poor sorting overall with occasional fair sorting; igneous and metamorphic lithic fragments mixed with sand grains indicating possible conglomeritic source. Sandstone = Generally medium gray overall; silica cementing of grains with occasional local calcareous content; low to moderate visible permeability and porosity; generally friable, occasionally firm to hard; composed of upper very fine to lower fine, sub- to rounded grains; poor sorting and consolidation; matrix supported. Peaks Depth TG C1 C2 C3 C4I C4N C51 C5N 8425 332 99598 • El EPOCH 10 TYONEK 9391' MD to -7796' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 71 12 42 15 5 10 0 Coal = accounts for nearly 30% of the sample at this depth, the coal i s dominantly black with slight dark reddish brown, it is very hard and angular with blocky and crumbly fracture, vitreous to resinous luster. Sand = comprises around 40% of this section, medium grey to white in color, size ranges from medium to fine, subangular to subrou nded increased rounding in quartz grains, overall the sand is loose and unconsolidated, also present is some ash, medium light grey, firm to hard, tough and fine grained, smooth to silty to slightly sucrosic texture, waxy to slightly frosted luster. Peaks Depth TG C1 C2 C3 C4I C4N C51 C5N 9395 10 10302 IRGS TOP 9406' MD, -7796' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 108 18 63 90 4 46 Claystone = most common in this layer is claystone though occasional tuffaceous clay /ash is present, generally light grey to medium light grey, very soft to soft, brittle with little or no induration present, mostly mushy to pasty consistency, massive cuttings habit, waxy to earthy to slight sparkling luster depending on tuff content, clayey to silty to matte texture, predominately structureless. Sand /Sandstone = light grey overall, lower very fine to upper fine grained, moderate sphericity, subangular to subrounded, unconsolidated sands to friable sandstones fining upward in sequence, contains some grayish orange pink to moderate yellowish brown claystones that are friable with thin coal laminae interbedded. Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9536 90 36601 40 [I EPOCH 11 • IRGS BASE 9572' MD, -7936' SSTVD Drill Rate (ft/hr Total Gas (units Maximum Minimum Average Maximum Minimum Average 180 8 94 221 0 111 Coal = approx. 50 %, black with brownish black hues, crumbly and brittle to frequently hard and dense, hackly to irregular fracture, medium to large fragments, blocky to subnodular cuttings habit, shiny to matte finish, dully luster, smooth flat texture on flat sides but finely layered on cross view, thinly laminated structure with occasional thicker bedding, strong degassing present for up to an hour after extraction. Sand = approx. 20 %, light grey overall with white and clear colorless quartz along with some greenstone present, lower to fine to upper medium size, well sorted with moderate sphericity, subangular to subrounded, loose unconsolidated, some etching of quartz is present composition is 60 -80% quartz with hard subangular m afic fragments dark reddish brown to pale yellowish orange. Claystone = light bluish grey to light brownish grey, fairly firm, mushy to crumbly, clayey to silty texture, massive and sometimes nodular cutting habit, dull to earthy luster, fairly cohesive with some inclusions, increased friability with hydration. Shale = olive grey to olive black to light olive grey, friable to moderately hard, fissile, crumbly, silty to gritty, finely laminated, dull luster. Peaks Depth TG C1 C2 C3 C41 C4N C5I C5N 9871 221 57940 • El EPOCH 12 � 3.3. SAMPLING PROGRAM AND DISTRIBUTION Set Type and Purpose Interval Frequency Distribution Chevron 3800' to 9750' 30' 909 West 9 Avenue A Washed Samples 9750' to 9780' 10' Anchorage, AK 99501 Attn: Debra Oudean and Francisco Castro Chevron 9780' to 909 West 9 Avenue A Washed Samples 10050' 30' Anchorage, AK 99501 10050' to 10' Attn: Debra Oudean and 10060' Francisco Castro Chevron 3800' to 9750' 30' 909 West 9 Avenue B Washed Sam 9750' to 9780' 10' Anchorage, AK 99501 Attn: Debra Oudean and Francisco Castro Chevron 9780' to 909 West 9 Avenue 10050' 30' B Washed Samples 10050' to 10' Anchorage, AK 99501 10060' Attn: Debra Oudean and Francisco Castro Ii EPOCH 13 • 4. DRILLING DATA 4.1. DAILY ACTIVITY SUMMARY December 22, 2008: Spud and commence drilling. Drilled to 834'. December 23, 2008: Drilled to 1028', circulated bottoms up. Back reamed hole from 1028' to 289'. Began running casing. December 24, 2008: Running casing down hole stopped to lay down 6 to 7 joints of bad collars; continued to run casing after bad collars. Picked up and made up a landing joint. Broke -out and redressed threads of pipe; while circulating 3.8 bbls per minute at five strokes and 15 psi and land hanger. Rigged down casing equipment and circulated hose. Landing joint would not back out. Drained stack and checked rotation. Rigged up GB R and broke off landing joint, hanger and laid both dow n. Rigged up to await orders, while made -up 42 joints and ran in hole to tag bottom. Pulled out and laid down 42 joints and 5 ' pup joint. December 25, 2008: Made up 19' and 42' casing j oints. Circulated head, hose and rigged down casing equipment. Rigged down circulating hose, swedge, drain stack, pumped out cellar and set emergency slips; while rigged up false bowls and elevators to run in hole with 5" drill pipe. Made up stabilizer, sub, and 5 ft. pup joint. Run in hole with drill pipe to 974 ft. Rigged up BJ cementing, and circulated through secondary kill line, while circulating and waiting on cement. Finally pumped cement to 979', followed by spud mud, then pumped 165bbIs of cement and 13.5bbls of spud mud. Did not see cement return to surface. Picked up and racked back one stand of drill pipe while circulating mud in hole. Started to pull out of hole with 5 inch drill pipe, and commenced to cutting casing for the top job; while cleaning pits. December 26, 2008:. Nippled dow n spacer tools and cut flow line and risers, then nippl ed down diverter, and knife valve. Installed lifting cable on blocks, and removed high pressure hose from conductor. Commenced to loosen Blow Out Preventer bolts. Then picked up and inspected Emergency Slip, then cut 13 3/8 " casing and pulled out of hole. The crew laid over beaver slide, and broke down surface stack and rinsed it down. Installed well heads and made final cut. Cut 13 3/8" casing above emergency slips, than installed multi -head well head. Cut hole in 20" conductor casing and ran in hole with pipe to do top job. December 27, 2008: Continued rigging 3 /4" pipe to do top job. Currently doing top job. December28, 2008: Finished setting surface casing. Prepared and built system mud. Nippled up and tested BOP's. Measured and began to setup BHA. December 29, 2008: Finish nipple and test BOP's. Found Teaks and frozen lines that were fixed and completed tests. Flowed and tested all well control lines. Tested surface casing to 2000 psi. Tripped into hole to clean casing and pick up drill pipe. December 30, 2008: Tripped into hole with bit to clean casing. Tagged at 926', cleaned and reamed to 956'. Pulled out of hole. Picked up drill pipe and ran Giro. Pulled out of hole, racked drill pipe on derrick and picked up directional BHA. Tripped back in hole, tagged, and circulated. Getting ready to drill out cement. December 31, 2008: Circulate to get even mud weight. Wait for G &I and clean hole. Drilled to 1055'. Rigged up BJ Services to make Formation Integrity Test. Formation only holding 10.2 EMW. Moved mud and pre -post flush to G &I. Cleaned lines to weld on the pits. Li EPOCH 14 January 1, 2009: Circulated active system and built pre -post flush mud for G &I. Drilled from 1055' to 1260'. Pulled back to the shoe to service top drive. January 2, 2009: Down to troubleshoot top drive on the rig. Mechanics are working on repair. Built active system mud and built pre and post flush fluid for G &I. Waiting on top drive to resume drilling. January 3, 2009: Troubleshot the top drive on the r ig. After fixing the top drive, tripped back to bottom. Drilled from 1260' to 1555'. Having probl ems controlling through the shakers. Changed the shaker screens and continued to see the same issue. Cuttings were noticed in the active system due to a torn screen and stopped drilling. Pulled up to shoe and cleaned pumps and shakers of all cuttings. Built 120 bbls of 6% KCI to make up for lost mud. All cuttings have been sent to G &I for process and disposal. January 4, 2009: Finish cleani ng all the solids from the suction lines and put back the shaker screens. Began to circulate mud within the active pits. Changed the saver sub on the drill pipe. Tripped back to bottom and continued drilling. Drilled from 1555' to 2125'. Stopped drilling to allow G &I to inject and make room for more cuttings. Tripped back to shoe and picked up more drill pipe while waiting. January 5, 2009: Had to stop drilling to let G& I displace there slurry. Stopped drilling and pulled out to shoe. Water well froze and had to fix before going back to drilling. Picked up drill pipe. G &I pumped and displaced successfully. Water was fixed and then tripped back to bottom, broke circulation and continued drilling and sliding from 2125' to 2670'. Flow has been kept around 550 gallons per minute to prevent m ud from going over the shakers. January 6, 2009: Stopped drilling at 2670' due to excessive solids in the mud. Circulated and changed out the shaker screens and also changed the bottom seals. Waiting for G &I to create and pump slurry. Picked up 30 joints of drill pipe. Made another 120 bbls to make more volume in the active system. Circulating to reduce solids. January 7, 2009: Waiting for G &I to process the cuttings and inj ect them to make room for more. Started to go in the hole at 2200 hours. G &I pumping slurring down the hole. January 8, 2009: Tripped back to bottom, broke circulation, no fill. Back to drilling from 2750' to 3082'. And rotary drilling from 3082' to 3750'. Added LCM to system to prevent losses. Left mud weight at 9.1 ppg and are running solids control equipment. Lowered water loss on active system. January 9, 2009: Continued drill ing and sliding from 3750' to 5260'. Adding LCM to the system to prevent losses. Changed the screens on #1 s haker to have pyramid all around. Drilling at current time. January 10, 2009: Continued drilli ng from 5260' to 5781'. Was determined bit was getting out of gauge so tripped out of the hole to check the bit. Made BOP test and got ready to go back in the hole with the new bit. January 11, 2009: Finished tripping out of the hole. Broke down the MWD and directional drilling tools and checked them. Made a BOP test and tested all well control equipment. Picked new bit and put together the new BHA. Tripped back in the hole. Tight spot at 5300'; worked the pipe through it and continued tripping to the bottom. 4110 El EPOCH 15 • January 12, 2009: Continued tripping to bottom , tagged and began to circulate to get bottoms up and to make sure the hole is clean and has no gas. Continued to drill from 5778' to 5836'. The top drive began to have issues with the oil pump, it was determined that it had to be changed before further damage done. Stopped drilling to pull back to the shoe. The top drive was repaired and tested. Tripped back to bottom and circulated to clean the hole. Continued drilling from 5836' to 5970'. January 13, 2009: Continued drilli ng from 5837' to 6024'. Drilled past coal seam and called TD for intermediate casing at 6024'. Started running casing. January 14, 2009: Continued drilling from 5970' to 6024'. Intermediate TD. Made a bottom's up and made a 5 stand trip. Went back to bottom and pumped a high viscosity sweep to clean the hole. Circulated all the way out and slugged. Tripped out of the hole and layed down the BHA. Changed the rams and rigged up the casing crew. Currently running casing. January 15, 2009: Finished running casing. Circulated to get past 3 j oints to bottom. Circulated the hole and rigged cement crew. Ran cement job and displacement. Sent waste mud and excess active system mud to G &I for processing. Got everything ready for second stage of cement job. January 16, 2009: Ran the second cem ent stage. Dumped contaminated mud. Emptied the BOP stack and changed the rams back to 5 inch drill pipe. Setup the new BHA, running bit and collars only, motor is not in due to weather issues. Tripping in the hole, picking up drill pipe. January 17, 2009: Picking up drill pipe and tripping in the hole. Stopped at 3000' to test casing to 1500 psi. Drilled out the plug at 3200'. Continued reaming and cleaning the hole to 5500'. Dumped all cement contaminated mud and made fresh mud to keep up the volume. January 18, 2009: Made the casing test at 5560' to 5500 psi. Went to bottom and continued reaming to get to the bottom of casing. Drilled out at 6024'. Got all contaminated mud to G &I for processing. Continued dril ling to 6045', circulated to get even mud and to clean the hole. Made FIT to 13.6 EMW. Got a good test and began to trip out of the hole. Made BOP as tripping out to pick up the BHA. January 19, 2009: Put together the directional drilli ng equipment and began to trip in the hole. Stopped at 5700' to cut drill line and work on the alarm system to ensure in good working order. Circulated mud to get even mud weight all around and worked on dropping water loss to drill. Tripping in the hole to TD. January 20, 2009: Circulated at botto m and began to drill. Drilled from 6045' to 6430' and began to get gas back. Stopped drilling to circulate and to raise mud weight to 9.7 ppg. Conti nued to circulate to get gas out. Continued to drill from 6043' to 6970' increasing mud weight to 9.8 ppg. Drilling at report time. January 21, 2009: Continue drill ing from 6960' to 7040', cleaned the bit to prevent balling. At 7000' looked like a nozzle got plugged. Pum ped wall nut sweeps to clean the bit, was able to clean the nozzle and continue drilling. Top drive began to have problems and had to pull back to the intermediate shoe to fix. Changed the pump liners from 5" to 5.5" to get max GPM. Finished testing gas alarms. Cleaned pits 1 and 2 to keep mud weight down. January 22, 2009: Top drive on the rig is down, trying to get parts in to repair. Decided to pull out of the hole to clean the BHA. Cleaned 2 jets on the bit and checked other BHA components. • Parts have arrived and crew working to get the top drive repa ired. El EPOCH 16 • January 23, 2009: Continue to work on top drive. After repair was complete, tested and verified everything work fine before begin to put togethe r BHA and tripping back to bottom. Tripping at report time. January 24, 2009: Continued tripping in hole f filling up every 20 stands. Broke connection at 6015' to get complete circulation and to test top d rive. Continued reaming to bottom. Tight spot at 6040' to 6050', tight spot at 6420' to 6450', and again at 6 530' to 6550'. Adding lubricant to avoid sticking through clays. Began to drill at 7040' to 7545' . Drilling at report time. January 25, 2009: Continued drilli ng to 7978' and stopped due to damage to monkey boards. Haulted drilling to repair. Repaired the monkey boards and continued drilling to 8058'. January 26, 2009: Continued drilli ng from 8169' to 8765'. Rotary torque has been climbing, so put additives in mud system to try and reduce torque. Drilling ahead. January 27, 2009: Continue drill ing from 8765' to 9400'. Added 2 pounds per bbl of steelseal, torque -trim 2, and drill -n -slide and it has brought the torque down about 1200 to 2000 ft Ib. Continuing to drill toward TD at midnight. January 28, 2009: Continue dril ling. RigWatch Master computer crashed at 2121 hrs and was restored at 2257 hrs. Still drilling ahead at midnight. January 29, 2009: Reached T D of 10060' MD at 0058 hrs. Circulate and condition hole; CB U; pull up to 9880' on elevators; CBU. Tripped up to 7120'; worked tight spots at 7015', 6145', and 6165'. Pulled up to shoe; CBU; begin pulling out of hole. At midnight the bit depth was 5993'. • January 30, 2009: Finish POOH and lay down BHA. RIH with wireline logging tools to 6200'; they could not get any further. Pull out wireline tools and begin testing BOP s. January 31, 2009: Continue with BOP testing; total of 8.5 hrs. RIH to ream and clean out well to re -run wireline. Circulated at 5900'; run to 609 5' and washed through bridge to 61 27'. RIH to 10028' and begin first CBU. February 1, 2009: Continue with first CBU; begin second CBU after dropping carbide marker followed by a high -visc sweep. Pull out drill pipe and re -run wireline. Wireline encountered a bridge at 6039'; POOH. Began testing 7" rams. February 2, 2009: Ran 102 stands of 7" liner. Cleaned out m ud pits; pits have 20 -30 bbls of solids and mud at the bottom. February 3, 2009: RIH to 9991' to work /ream a tight spot from 9991' to 10002'. At 10002', pumped a 25 -bbl, 12-lb pill followed with a dye tracer using 540 -745 psi with 60 -65 spm. Dye tracer did not come back. Continuing to work pipe down at midnight. February 4, 2009: Run casing to 10024'. Install cement lines and drop ball; ball seated @ 2800 psi. Pumped 172 bbls cement with 40 bbls of spacers; bumped collar with 258 bbls. Once it was verified that the ZXP packer was set, pressure was brought up to 2500 psi. Ci rculated cement from drill pipe and dumped cement returns. Circulated drill pipe and ZXP packer clean. Stood six stands back and circulated mixed dry job, then began to POOH. Continuing to POOH at midnight. • II EPOCH 17 0 • • Chevron CHEVRON - IRU 11 -06 4.2. SURVEY RECORD Measured Vertical Course Depth Inclination Azimuth TVD Section +NS- +EW- INCR VS Length DLS (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft ) (ft) (deg /100ft ) 95.00 0.13 15.35 95.00 0.11 0.10 0.03 0.11 95.00 0.14 190.00 0.16 90.77 190.00 0.24 0.21 0.19 0.28 95.00 0.19 285.00 0.28 134.76 285.00 0.14 0.04 0.49 0.49 95.00 0.21 380.00 0.12 141.65 380.00 -0.05 -0.20 0.71 0.74 95.00 0.17 475.00 0.26 185.65 475.00 -0.33 -0.49 0.75 0.90 95.00 0.20 570.00 0.29 211.79 570.00 -0.77 -0.91 0.61 1.10 95.00 0.13 665.00 0.22 207.33 665.00 -1.17 -1.28 0.40 1.34 95.00 0.08 760.00 0.34 208.73 759.99 -1.61 -1.69 0.18 1.70 95.00 0.13 855.00 0.47 220.62 854.99 -2.23 -2.23 -0.21 2.24 95.00 0.16 950.00 0.48 220.89 949.99 -2.92 -2.83 -0.73 2.92 95.00 0.01 1045.32 0.71 275.41 1045.30 -3.33 -3.07 -1.58 3.45 95.32 0.61 1093.82 0.76 288.16 1093.80 -3.33 -2.94 -2.18 3.66 48.50 0.35 1187.45 2.26 346.69 1187.40 -1.60 -0.95 -3.20 3.34 93.63 2.11 1282.47 5.95 355.96 1282.16 4.84 5.78 -3.97 7.02 95.02 3.93 1378.47 8.91 356.53 1377.34 16.79 18.17 -4.78 18.79 96.00 3.08 1470.37 11.49 0.24 1467.78 32.61 34.43 -5.17 34.82 91.90 2.90 1567.88 13.14 0.17 1563.05 52.98 55.23 -5.09 55.46 97.51 1.69 1660.37 14.87 2.58 1652.78 74.98 77.60 -4.53 77.73 92.49 1.97 1757.81 17.44 4.51 1746.37 101.80 104.65 -2.82 104.69 97.44 2.69 1851.65 18.25 3.80 1835.69 130.29 133.33 -0.74 133.33 93.84 0.89 1946.15 20.73 3.55 1924.77 161.49 164.79 1.28 164.80 94.50 2.63 2042.50 23.12 1.34 2014.15 196.95 200.73 2.78 200.75 96.35 2.62 2053.26 23.28 1.33 2024.04 201.12 204.97 2.88 204.99 10.76 1.49 2147.58 24.82 0.06 2110.17 238.81 243.40 3.33 243.42 94.32 1.72 2246.01 26.36 359.24 2198.94 280.35 285.91 3.06 285.93 98.43 1.61 E1 EPOCH . • . Measured Vertical Course Depth Inclination Azimuth TVD Section +NS- +EW- INCR VS Length DLS 2339.98 28.01 358.05 2282.53 322.12 328.83 2.03 328.83 93.97 1.85 2436.61 30.52 356.28 2366.82 367.78 376.00 -0.33 376.00 96.63 2.75 2528.91 31.54 355.43 2445.91 413.49 423.45 -3.77 423.47 92.30 1.20 2624.31 33.52 353.47 2526.34 462.40 474.50 -8.76 474.58 95.40 2.35 2715.07 34.11 354.26 2601.75 510.41 524.72 -14.15 524.91 90.76 0.81 2811.55 35.67 353.59 2680.89 562.89 579.59 -20.00 579.94 96.48 1.66 2906.31 38.34 352.86 2756.55 616.90 636.22 -26.74 636.78 94.76 2.86 2999.35 40.02 352.94 2828.67 672.45 694.55 -34.00 695.38 93.04 1.81 3095.82 42.45 352.42 2901.21 732.47 757.61 -42.11 758.78 96.47 2.54 3193.15 44.64 351.17 2971.76 795.41 823.97 -51.70 825.59 97.33 2.42 3289.69 45.89 350.24 3039.71 859.32 891.64 -62.78 893.85 96.54 1.46 3382.11 46.88 348.95 3103.46 921.20 957.45 -74.87 960.37 92.42 1.47 3476.86 47.11 348.60 3168.08 984.90 1025.41 -88.36 1029.21 94.75 0.36 3570.84 47.34 348.81 3231.91 1048.28 1093.06 - 101.87 1097.80 93.98 0.29 3665.40 47.32 349.22 3296.00 1112.31 1161.31 - 115.12 1167.00 94.56 0.32 3760.30 47.37 349.00 3360.30 1176.63 1229.85 - 128.30 1236.52 94.90 0.18 3854.44 45.75 348.84 3425.03 1239.54 1296.93 - 141.44 1304.62 94.14 1.73 3949.23 45.55 348.89 3491.29 1301.89 1363.44 - 154.53 1372.16 94.79 0.21 4044.43 45.43 348.56 3558.03 1364.28 1430.01 - 167.80 1439.83 95.20 0.28 4138.41 45.24 348.72 3624.09 1425.67 1495.55 - 180.97 1506.46 93.98 0.24 4233.34 45.12 349.82 3691.01 1487.79 1561.70 - 193.50 1573.64 94.93 0.83 4328.90 46.85 350.87 3757.41 1551.69 1629.45 - 205.02 1642.30 95.56 1.98 4423.13 46.61 351.34 3822.00 1615.81 1697.24 - 215.63 1710.88 94.23 0.44 4519.30 46.27 351.69 3888.27 1681.11 1766.16 - 225.91 1780.55 96.17 0.44 4613.33 46.11 351.87 3953.36 1744.80 1833.32 - 235.61 1848.40 94.03 0.22 4710.09 46.00 351.98 4020.51 1810.26 1902.30 - 245.40 1918.06 96.76 0.14 4807.74 46.01 351.60 4088.34 1876.21 1971.83 - 255.43 1988.30 97.65 0.28 4901.62 46.18 352.25 4153.44 1939.76 2038.80 - 264.93 2055.94 93.88 0.53 4996.46 46.10 352.17 4219.15 2004.12 2106.55 - 274.20 2124.32 94.84 0.10 ELI EPOCH 19 • • • Measured Inclination Azimuth TVD Vertical +NS- +EW- INCR VS Course DLS Depth Section Length 5092.87 46.26 352.10 4285.91 2069.56 2175.45 - 283.72 2193.88 96.41 0.17 5186.87 46.09 352.25 4351.00 2133.38 2242.64 - 292.95 2261.69 94.00 0.21 5281.35 46.16 352.39 4416.48 2197.53 2310.14 - 302.05 2329.80 94.48 0.13 5374.85 46.10 351.82 4481.28 2260.93 2376.90 - 311.31 2397.20 93.50 0.44 5468.27 46.13 351.92 4546.04 2324.17 2443.56 - 320.83 2464.53 93.42 0.08 5563.02 46.18 352.52 4611.67 2388.49 2511.26 - 330.08 2532.86 94.75 0.46 5657.57 46.22 352.67 4677.12 2452.88 2578.93 - 338.88 2601.10 94.55 0.12 5755.02 46.76 352.93 4744.21 2519.64 2649.05 - 347.74 2671.78 97.45 0.59 5844.70 46.96 352.85 4805.53 2581.49 2713.99 - 355.84 2737.22 89.68 0.23 5942.36 47.95 353.49 4871.56 2649.61 2785.43 - 364.39 2809.16 97.66 1.12 6007.27 47.71 354.53 4915.14 2695.38 2833.27 - 369.41 2857.25 64.91 1.24 6103.47 45.68 356.03 4981.12 2762.43 2903.03 - 375.19 2927.17 96.20 2.40 6200.11 42.45 359.77 5050.57 2827.58 2970.16 - 377.71 2994.08 96.64 4.29 6296.09 41.09 2.87 5122.16 2890.40 3034.06 - 376.26 3057.30 95.98 2.58 6390.90 38.17 8.43 5195.19 2950.44 3094.19 - 370.40 3116.28 94.81 4.84 6486.80 35.90 13.22 5271.76 3008.15 3150.90 - 359.63 3171.35 95.90 3.83 6581.92 34.82 15.51 5349.33 3063.14 3204.22 - 345.99 3222.84 95.12 1.80 6677.95 33.86 18.20 5428.63 3117.10 3256.05 - 330.30 3272.76 96.03 1.87 6772.41 33.54 22.01 5507.22 3168.96 3305.25 - 312.30 3319.97 94.46 2.26 6868.18 33.48 25.93 5587.09 3220.65 3353.54 - 290.83 3366.13 95.77 2.26 6962.10 33.50 28.93 5665.42 3270.58 3399.53 - 266.96 3409.99 93.92 1.76 7055.90 33.36 31.88 5743.71 3319.58 3444.08 - 240.82 3452.49 93.80 1.74 7155.35 32.83 39.50 5827.06 3369.21 3488.13 - 209.21 3494.39 99.45 4.22 7250.94 32.92 44.69 5907.36 3414.04 3526.59 - 174.46 3530.91 95.59 2.95 7347.19 32.82 49.81 5988.21 3456.65 3562.03 - 136.13 3564.63 96.25 2.89 7442.91 32.88 53.11 6068.63 3496.69 3594.37 -95.53 3595.63 95.72 1.87 7537.34 32.72 52.95 6148.01 3535.25 3625.13 -54.66 3625.54 94.43 0.19 7633.41 32.88 52.50 6228.76 3574.66 3656.65 -13.25 3656.67 96.07 0.30 7729.08 32.97 52.64 6309.06 3614.13 3688.25 28.04 3688.36 95.67 0.12 7823.85 33.27 52.22 6388.44 3653.52 3719.83 69.09 3720.47 94.77 0.40 7918.04 33.86 51.79 6466.92 3693.38 3751.88 110.12 3753.50 94.19 0.68 El EPOCH 20 • • • Measured Inclination Azimuth TVD Vertical +NS- +EW- INCR VS Course DLS Depth Section Length 8015.24 33.88 51.13 6547.63 3735.17 3785.64 152.49 3788.71 97.2 0.38 8110.45 33.92 49.24 6626.65 3776.88 3819.64 193.28 3824.52 95.21 1.11 8204.40 33.71 48.84 6704.71 3818.58 3853.91 232.76 3860.93 93.95 0.33 8297.78 33.20 48.70 6782.62 3859.79 3887.84 271.48 3897.30 93.38 0.55 8391.84 32.72 48.52 6861.54 3900.84 3921.67 309.87 3933.89 94.06 0.52 8486.22 32.31 49.17 6941.13 3941.42 3955.06 348.07 3970.34 94.38 0.57 8580.33 32.40 50.17 7020.63 3981.25 3987.65 386.46 4006.33 94.11 0.58 8673.62 32.24 50.95 7099.46 4020.23 4019.34 424.98 4041.74 93.29 0.48 8770.95 32.36 50.98 7181.73 4060.64 4052.09 465.38 4078.73 97.33 0.12 8866.00 32.36 51.05 7262.02 4100.14 4084.10 504.92 4115.19 95.05 0.04 8960.33 32.63 51.19 7341.58 4139.43 4115.91 544.37 4151.75 94.33 0.3 9054.71 32.75 50.91 7421.01 4178.98 4147.95 584.01 4188.86 94.38 0.2 9149.38 32.45 50.19 7500.77 4218.84 4180.36 623.40 4226.59 94.67 0.52 9243.71 32.15 49.34 7580.50 4258.66 4212.92 661.88 4264.59 94.33 0.58 9339.76 31.68 48.33 7662.03 4299.27 4246.34 700.10 4303.66 96.05 0.74 9434.93 31.62 48.42 7743.05 4339.46 4279.51 737.43 4342.58 95.17 0.08 9530.67 31.74 48.61 7824.52 4379.84 4312.81 775.10 4381.91 95.74 0.16 9627.54 31.92 48.88 7906.83 4420.75 4346.50 813.51 4421.98 96.87 0.24 9722.74 32.39 50.01 7987.42 4460.95 4379.44 852.00 4461.55 95.2 0.8 9818.00 32.80 50.77 8067.68 4501.14 4412.16 891.54 4501.33 95.26 0.61 9914.34 33.19 51.26 8148.48 4541.87 4445.16 932.32 4541.88 96.34 0.49 9995.72 33.63 52.42 8216.42 4576.25 4472.84 967.55 4576.30 81.38 0.95 10060.00 33.63 52.42 8269.94 4603.33 4494.55 995.77 4603.54 64.28 0 El EPOCH 21 • • • 4.3. MUD RECORD Contractor: Baroid Mud Type: LSND Mud DATE DEPTH MW VIS PV YP GELS HTHP AP SOLIDS OIL/WATER SAND MBT pH Chl Ca 12/23/08 1028' 9.00 76 16 29 23/34/0 0 3/- 4.9 -/94.8 1.0 10.0 8.5 900 20 12/24/08 1028' 9.10 96 20 32 32/60/0 0 3/- 5.7 -/94.0 0.50 15.0 8.50 800 20 12/25/08 1028' 9.10 62 27 14 4/6/- 0 3/- 5.7 -/94.0 1.50 10.0 8.40 750 40 12/26/08 1028' 0 0 0 0 -1 -1- 0 -1- 0 0 0 0 0 0 0 12/27/08 1028' 8.80 37 06 05 2/3/0 0 2/- 3.4 -/96.3 0 0 8.80 800 20 12/28/08 1028' 9.10 39.0 7 13 4/14/19 0 2/- 3.8 -/96.0 0 0 9.20 5 7 12/29/08 1028' 9.00 50 9 21 4/5/22 0 1/- 1.7 -/96.0 0 0 10.10 27000 240 12/30/08 1028' 8.90 48 8 11 4/ -/- 0 1/- 1.9 -/96.0 0 0 9.80 25000 120 12/31/08 1055' 9.00 49 7 10 3/4/23 0 1/- 1.9 -/96.0 0 0 10.00 25000 120 1/01/09 1260' 9.00 55 11 18 5/6/23 0 1/- 1.7 -/96.0 0 0 10.10 27000 120 1/02/09 1260' 9.00 55 10 25 7/8/27 0 1/- 1.8 -/96.0 0 0 9.40 26000 240 1/03/09 1560' 9.00 58 8 20 9/10/- 0 1/- 2.2 -/96.0 0 0 9.20 21000 200 1/04/09 2120' 9.00 62 9 26 8/12/- 0 1/- 1.8 -/96.0 1.20 7.5 8.80 26000 240 1/05/09 2670' 9.00 58 10 21 9/12/- 0 1/- 1.8 -/96.0 1.20 7.5 8.90 26000 240 1/06/09 2670' 9.10 52 9 19 8/11/- 0 1/- 3.0 -/95.0 1.20 0 8.90 24000 240 1/07/09 2670' 9.10 52 9 19 8/11/- 0 1/- 2.9 -/95.0 1.10 0 8.90 25000 280 1/08/09 3750' 9.10 47 7 22 8/10/- 0 1/- 1.9 -/96.0 0 0 8.90 25000 360 1E111 EPOCH 22 • • 0 DATE DEPTH MW VIS PV YP GELS HTHP AP SOLIDS OIL/WATER SAND MBT pH ChI Ca 1/09/09 5260' 9.40 45 9 21 8/11/- 0 1/- 3.9 -/94.0 0.90 10.0 8.80 26000 240 1/10/09 5778' 9.50 44 9 26 12/14/- 0 1/- 3.9 -/94.0 0.75 0 8.90 26000 480 1/11/09 5778' 9.25 42 6 18 8/11/- 0 1/- 2.9 -/95.0 0.70 0 8.90 25000 240 1/12/09 5970' 9.40 47 9 23 9/14/- 0 1/- 4.0 -/94.0 0.70 10.0 8.80 24000 240 1/13/09 6024' 9.40 42 10 21 9/11/- 0 1/- 3.9 -/94.0 0.70 10.0 8.80 25000 240 1/14/09 6024' 9.50 47 9 23 8/11/- 0 1/- 4.0 -/94.0 0.70 10.0 8.90 24000 240 1/15/09 6024' 9.50 48 11 20 9/14/- 0 1/- 4.0 -/94.0 0.70 10.0 9.40 24000 240 1/16/09 6024' 9.50 47 9 16 8/13/- 0 1/- 4.0 -/94.0 0.50 0 9.80 24000 320 1/17/09 6024' 9.40 47 9 17 8/13/- 0 1/- 3.9 -/94.0 0.60 0 9.70 25000 280 1/18/09 6045 9.30 50 8 12 5/6/- 0 2/- 3.2 -/95.0 0 0 9.80 22000 280 1/19/09 6045' 9.30 46 7 13 6/8/- 0 2/- 2.9 -/95.0 0.60 7.5 11.50 25000 200 1/20/09 6970' 9.80 52 13 24 9/14/- 0 1/- 5.9 -/92.0 0.50 10.0 9.80 26000 240 1/21/09 7040' 9.90 46 13 22 7/10/- 0 1/- 6.7 0.2/91.0 0.25 10.0 9.40 27000 280 1/22/09 7040' 9.90 50 9 23 7/11/- 0 1/- 5.6 0.2/92.0 0.50 10.0 9.10 27000 240 1/23/09 7040' 9.90 52 12 12 8/12/- 0 1/- 5.8 0.2/92.0 0.50 10.0 9.00 25000 240 1/24/09 7460' 9.90 47 13 19 7/11/- 0 1/- 5.7 0.2/92.0 0.50 10.0 9.30 26000 240 1/25/09 8020' 10.5 47 16 19 5/14/- 0 1/- 7.6 0.2/90.0 0.25 7.5 8.40 28000 440 1/26/09 8740' 10.0 45 15 18 7/10/15 0 1/- 9.6 2.3/86.0 0.23 12.5 8.20 28000 480 1/27/09 9745' 10.0 51 17 18 6/9/13 0 1/- 9.4 2.1/86.5 0.12 13.0 8.50 27000 400 1/28/09 10040' 10.0 48 19 19 7/9/13 0 1/- 9.5 2.0/86.2 0.15 12.0 8.40 30000 480 1/29/09 10060' 10.0 49 12 17 4/10/13 0 1/- 9.8 2.0/86.2 0.15 11.0 8.50 26000 400 1/30/09 10060' 10.0 56 14 17 4/8/11 0 1/- 10.2 1.0/87.0 0.15 11.2 8.40 24000 440 El EPOCH 23 • • • DATE DEPTH MW VIS PV YP GELS HTHP AP SOLIDS OIL/WATER SAND MBT pH LIME Ca 1/31/09 10060' 10.0 59 11 16 5/7/11 0 1/- 9.1 1.0/88.0 0.15 11.2 8.40 25000 440 2/1/09 10060' 10.0 55 13 18 6/8/12 0 1/- 9.9 1.1/87.0 0.13 11.5 8.50 26000 480 2/2/09 10060' 10.0 78 14 18 7/10/15 0 1/- 10.4 1.8/86.0 0.12 14.0 8.40 24000 480 2/3/09 10060' 10.1 60 15 18 10/26/32 0 1/- 10.8 1.0/86.5 0.20 14.5 7.80 23000 600 2/4/09 10060' 10.1 63 17 20 13/28/33 0 1/- 10.9 1.5/86.0 0.10 14.0 7.90 21000 480 4.4. BIT RECORD BIT AVE NO SIZE MAKE TYPE S/N JETS/TFA IN OUT FEET HOURS ROP WOB CONDITION 1 12.25" STC XR+ PJ4606 3x14,1x13 1028' 5781' 4753' 45.5 104.5 7 5 - 7 - WT A - E - 5 /16 - RG - PR 2 12.25" SMITH XR +T PJ4606 3x14,1x13 1028' 5781' 4753' 45.5 104.5 7 5 - 7 - WT A - E - 5 /16 - RG - PR 3 12.25" STC F27DL KC5433 3X16 5781 6023 181' 3.6 87 8 N/A 4 8.5" STC ROCK BIT PG1561 3X14 6023 6045 27' 2 54 5 N/A 5 8.5" HYC PDC 123276 9X11 6023 7504 1419' 12.3 94 11 N/A 6 8.5" HCC PDC 123278 9X11 7504 10060 3019' 74.4 52 16 N/A Li EPOCH 24 Daily Report Chevron USA • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE Jan 10, 2009 DEPTH 5260.00000 PRESENT OPERATION Drilling TIME 00:31:09 YESTERDAY 3750.00000 24 HOUR FOOTAGE 1510.00000 CASING 20.00" 13.375" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 12.250" Smith Tri -cone XR -t 3x14/1x13 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 0.0 @ 0 @ 0.0 FT /HR SURFACE TORQUE 0 @ 0 @ 0.0 AMPS WEIGHT ON BIT 0 @ 0 @ 0.0 KLBS OTARY RPM 0 @ 0 @ 0.0 RPM MP PRESSURE 0 @ 0 @ 0.0 PSI DRILLING MUD REPORT DEPTH 5260' MW 9.4 VIS 45 PV 9 YP 21 FL 7 Gels 9/12/- CL- 26000 FC 1/- SOL 3.9 SD .9 OIL -/94 MBL 10 pH 8.8 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 0 @ 0 @ 0.0 TRIP GAS CUTTING GAS 0 @ 0 @ 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 0 @ 0 @ 0.0 CONNECTION GAS HIGH 138 ETHANE (C -2) 0 @ 0 @ 0.0 AVG 31 PROPANE (C -3) 0 @ 0 @ 0.0 CURRENT 0 BUTANE (C -4) 0 @ 0 @ 0.0 CURRENT BACKGROUND /AVG 0 PENTANE (C -5) 0 @ 0 @ 0.0 HYDROCARBON SHOWS a TERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /C]/Documents and Settings/RigUser /My Documents/My Wells /Chevron/20090110.htm (1 of 2)1/10/2009 1:37:39 AM Daily Report LITHOLOGY PRESENT Sand 40 %, Siltstone 30 %, Sandstone 20 %, Claystone THOLOGY 10% ILY ACTIVITY Continued drilling and sliding from 3750 feet to 5260 feet. LCM was added to the system to prevent SUMMARY losses. The screens on shaker #1 were changed. Drilling at the current time. EPOCH PERSONNEL ON Harry Bleys, Zachary Beekman, Justin Vandeberg, Jeff DAILY $3990.00 BOARD McBeth COST REPORT BY Zachary Beekman • file: / / /Cl/Documents and Settings/RigUser/My Documents /My Wells /Chevron/20090110.htm (2 of 2)1/10/2009 1:37:39 AM Daily Report Chevron USA DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE , 01/10/09 DEPTH 5781.00000 PRESENT OPERATION Testing BOP TIME 3:00 AM YESTERDAY 5518.00000 24 HOUR FOOTAGE 263 CASING 20" 13.375" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 3 12.25" STC PJ4606 3x14/1x13 4753 45.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 163.8 @ 5706.00000 21.0 @ 5533.00000 76.3 23.95700 FT /HR SURFACE TORQUE 20822 @ 5692.00000 7809 @ 5546.00000 12535.8 AMPS WEIGHT ON BIT 10 @ 5566.00000 0 @ 5698.00000 4.9 3.18200 KLBS OTARY RPM 69 @ 5771.00000 52 @ 5704.00000 60.1 RPM MP PRESSURE 2284 @ 5676.00000 1574 @ 5754.00000 2013.4 PSI DRILLING MUD REPORT DEPTH MW 9.5 VIS 44 PV 9 YP 26 FL 7 Gels 12/14/- CL- 26000 FC 1/- SOL 3.9 SD .75 OIL -/94 MBL - pH 8.9 Ca+ 480 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 16 @ 5522.00000 2 @ 5550.00000 8.3 TRIP GAS CUTTING GAS 0 @ 5781.00000 0 @ 5781.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 3723 @ 5522.00000 443 @ 5550.00000 1798.0 CONNECTION GAS HIGH 22 ETHANE (C -2) 0 @ 5781.00000 0 @ 5781.00000 0.0 AVG 16 PROPANE (C -3) 0 @ 5781.00000 0 @ 5781.00000 0.0 CURRENT 0 BUTANE (C -4) 0 @ 5781.00000 0 @ 5781.00000 0.0 CURRENT BACKGROUND /AVG 0 PENTANE (C -5) 0 @ 5781.00000 0 @ 5781.00000 0.0 HYDROCARBON SHOWS TERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /C[/Documents and Settings/RigUser /My Documents/My Wells /Chevron/20090111.htm (1 of 2)1/11/2009 1:43:45 AM Daily Report LITHOLOGY PRESENT SAND 80 %, TUFFACEOUS CLAYSTONE THOLOGY 20% ILY ACTIVITY Continued drilling from 5260' to 5781'. Bit was getting out of gauge so tripped out of the hole to check SUMMARY the bit. Make BOP test and got ready to go back in the hole with a new bit. EPOCH PERSONNEL ON Harry Bleys, Zach Beekman, Justin Vandeberg, Jeff DAILY $4790.00 BOARD McBeth COST REPORT BY Zach Beekman • • file: / / /Cl/Documents and Settings/RigUser /My Documents/My Wells /Chevron/20090111.htm (2 of 2)1/11/2009 1:43:45 AM Daily Report CHEVRON USA 0 DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE , 01/11/2009 DEPTH 5781.00000 PRESENT OPERATION Tripping to bottom TIME 1:05 YESTERDAY 5781.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 3 12.25 STC -insert bit F27D 3x16 0 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 163.8 @ 5706.00000 21.0 @ 5533.00000 76.3 23.95700 FT /HR SURFACE TORQUE 20822 @ 5692.00000 7809 @ 5546.00000 12535.8 AMPS WEIGHT ON BIT 10 @ 5566.00000 0 @ 5698.00000 4.9 3.18200 KLBS ROTARY RPM 69 @ 5771.00000 52 @ 5704.00000 60.1 RPM •UMP PRESSURE 2284 @ 5676.00000 1574 @ 5754.00000 2013.4 PSI DRILLING MUD REPORT DEPTH MW 9.25 VIS 42 PV 6 YP 18 FL 7.6 Gels 8/11/- CL- 25000 FC 1/- SOL 2.9 SD .70 OIL -/95 MBL - pH 8.9 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 16 @ 5522.00000 2 @ 5550.00000 8.3 TRIP GAS CUTTING GAS 0 @ 5781.00000 0 @ 5781.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 3723 @ 5522.00000 443 @ 5550.00000 1796.4 CONNECTION GAS HIGH 0 ETHANE (C -2) 0 @ 5781.00000 0 @ 5781.00000 0.0 AVG 0 PROPANE (C -3) 0 @ 5781.00000 0 @ 5781.00000 0.0 CURRENT 0 BUTANE (C -4) 0 @ 5781.00000 0 @ 5781.00000 0.0 CURRENT BACKGROUND /AVG 0 PENTANE (C -5) 0 @ 5781.00000 0 @ 5781.00000 0.0 HYDROCARBON SHOWS /INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/Documents and Settings/RigUser /My Documents /My Wells /Chevron/20090112.htm (1 of 2)1/12/2009 1:17:30 AM Daily Report LITHOLOGY PRESENT SAND 80 %, TUFFACEOUS CLAYSTONE T HOLOGY 20% MV VD ACTIVITY Finished tripping out of the hole. Broke down the MD and directional drilling tools. Made a BOP test SUMMARY and tested all well control equipment. Picked new bit and put together the BHA. Tripped back to bottom. Tight spot at 5300', but worked pipe through to continue tripping to bottom. EPOCH PERSONNEL ON Harry Bleys, Zach Beekman, Justin Vandeberg, Jeff DAILY $4790.00 BOARD McBeth COST REPORT BY Zach Beekman III • file: / / /C[/Documents and Settings/RigUser /My Documents/My Wells /Chevron/20090112.htm (2 of 2)1/12/2009 1:17:30 AM Daily Report O CHEVRON USA IIIIIIIIIIIIIIIIIIIIIIII DAILY WELLSITE REPORT EPOCH IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE , 01/12/2009 DEPTH 5970.00000 PRESENT OPERATION Tripping J TIME 3:00 AM YESTERDAY 5781.00000 24 HOUR FOOTAGE 189 aING INFORMATION 20.00" IIIIIIIIIIIII DEPTH INCLINATION AZIMUTH VERTICAL DEPTH M SURVEY DATA 11.111111. MEE MIIIEE MM. mom BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 1111 EIS MIMI F27D 3x16 189 NE Mil EMI 11.1 111111 mum NE 1111. Eill NE NEI 1111 11111 Ell • 1 f3 1/13/2009 3:04:59 AM file: / / /C�/DML2000 /DailyReport.htm ( o ) Daily Report DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 163.8 @ 5706.00000 21.0 @ 5533.00000 76.3 23.95700 FT /HR lik URFACE TORQUE 20822 © 5692.00000 7809 @ 5546.00000 12535.8 AMPS WEIGHT ON BIT 10 @ 5566.00000 0 @ 5698.00000 4.9 3.18200 KLBS ROTARY RPM 69 @ 5771.00000 1111= © 5704.00000 60.1 RPM PUMP PRESSURE 111E111 @ 5676.00000 @ 5754.00000 2013.4 Mil PSI DRILLING MUD REPORT DEPTH 5970 MW 9.4 _ VIS 011 PV 9 YP FL MI Gels 9/14/ - CL- 24000 FC 11111 SOL 4 SD .70 OIL -/94 MBL 10 pH 8.8 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 16 ME @ 5550.0 ; TRIP GAS @ 55 22.0 . NM CUTTING GAS 0 @ 5781.07 0 @ 5781.07 0.0 , WIPER GAS im I I I CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) IIMMI @ 5522.0 +4 443 @ 5550.0 + 1798.0 CONNECTION GAS HIGH 20 ETHANE (C -2) 0 @ 5781.0 +; 0 @ 5781.0+ 0.0 AVG MR PROPANE (C -3) 0 @ 5781_0 +'. 0 @ 5781.0 + 0.0 CURRENT 40 BUTANE (C -4) 0 @ 5781.0 F. 0 @ 5781.07 0.0 CURRENT BACKGROUND /AVG 20 PENTANE (C -5) 0 @ 5781.0 +; 0 @ 5781.0 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION LITHOLOGY O RESENT THOLOGY Coal 90 %, Claystone 10% file: / / /q/DML2000 /DailyReport.htm (2 of 3)1/13/2009 3:04:59 AM Daily Report DAILY ACTIVITY SUMMARY !Continued tripping back to bottom, tagged and began to circulate to get bottoms up and VIA EPOCH PERSONNEL ON DAILY • LOCATION _Continued drilling from 5836' to + COST 1=W REPORT BY $4790.00 V • • file: / / /CI /DML2000/DailyReport.htm (3 of 3)1/13/2009 3:04:59 AM Daily Report CHEVRON USA 0 DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Brad DATE , 01/13/2009 DEPTH 6024.00000 PRESENT OPERATION Casing TIME 3:00 AM YESTERDAY 5837.00000 24 HOUR FOOTAGE 187 CASING 20.00" 13.375" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 3 12.25" STC -Insert Bit F27D 3x16 187 1.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 393.2 @ 5837.00000 50.0 @ 6001.00000 127.4 60.21500 FT /HR SURFACE TORQUE 12425 @ 5847.00000 9446 @ 5935.00000 10929.6 AMPS WEIGHT ON BIT 13 @ 5847.00000 1 @ 5840.00000 8.9 8.75100 KLBS ROTARY RPM 65 @ 5946.00000 57 @ 5936.00000 61.7 RPM *MP PRESSURE 2310 @ 5885.00000 1996 @ 5837.00000 2215.5 PSI DRILLING MUD REPORT DEPTH 6024' MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 408 @ 5977.00000 1 @ 5844.00000 142.6 TRIP GAS 170/90 CUTTING GAS 0 @ 6024.00000 0 @ 6024.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 82778 @ 5977.00000 322 @ 5844.00000 28672.3 CONNECTION GAS HIGH 20 ETHANE (C -2) 73 @ 5942.00000 0 @ 5972.00000 6.2 AVG 8 PROPANE (C -3) 0 @ 6024.00000 0 @ 6024.00000 0.0 CURRENT 0 BUTANE (C -4) 0 @ 6024.00000 0 @ 6024.00000 0.0 CURRENT BACKGROUND /AVG 0 PENTANE (C -5) 0 @ 6024.00000 0 @ 6024.00000 0.0 HYDROCARBON SHOWS O TERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /g/Documents and Settings/RigUser/My Documents /My Wells /CHEVRON /20090114.htm (1 of 2)1/14/2009 3:34:47 AM Daily Report LITHOLOGY PRESENT Coal 50 %, Sandstone 30 %, Claystone 10 %, Sand THOLOGY 10% AILY ACTIVITY Continued drilling from 5837' to 6024'. Drilled past coal seam and called TD at 6024'. Started running SUMMARY casing. EPOCH PERSONNEL ON Harry Bleys, Zach Beekman, Justin Vandeberg, Jeff DAILY $4790.00 BOARD McBeth COST REPORT BY Zach Beekman • • file: / / /q/Documents and Settings/RigUser/My Documents /My Wells /CHEVRON /20090114.htm (2 of 2)1/14/2009 3:34:47 AM Daily Report CHEVRON USA • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE , 1/14/2009 DEPTH 6024.00000 PRESENT OPERATION Casing TIME 3:00 AM YESTERDAY 6024.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 3 12.25" STC- Insert Bit F27D 3x16 187 1.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS Ei TARY RPM @ @ RPM MP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6024' MW 9.5 VIS 47 PV 9 YP 23 FL 6.5 Gels 8/11/- CL- 24000 FC 1/- SOL 4 SD .70 OIL -/94 MBL 10 pH 8.9 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 0 CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH 0 ETHANE (C -2) @ @ AVG 0 PROPANE (C -3) @ @ CURRENT 0 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 0 PENTANE (C -5) @ @ HYDROCARBON SHOWS •ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /g/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090114.htm (1 of 2)1/14/2009 9:05:43 PM Daily Report LITHOLOGY PRESENT Coal 50 %, Sanstone 30 %, Sand 10 %, Claystone I THOLOGY 10% DAILY ACTIVITY Continued drilling from 5970' to 6024'. Intermediate TD. Made a bottom's up and made a 5 stand trip. SUMMARY Went back to bottom and pumped a high viscosity sweep to clean the hole. Circulated all the way out and slugged. Tripped out of the hole and layed do EPOCH PERSONNEL ON wn the BHA. Changed the rams and DAILY Harry Bleys, Zach Beekman, Justin BOARD rigged up the casing crew. Currently COST Vandeberg, Jeff McBeth running casing. REPORT BY $4790.00 • file: / / /O/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090114.htm (2 of 2)1/14/2009 9:05:43 PM Daily Report 116 CHEVRON USA DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE , 01/15/2009 DEPTH 6024.00000 PRESENT OPERATION Cementing TIME 3:00 AM YESTERDAY 6024.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 3 12.25" STC -Insert Bit F27D 3x16 187 1.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS OTARY RPM @ @ RPM MP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6024' MW 9.5 VIS 48 PV 11 YP 20 FL 7.8 Gels 9/14/- CL- 24000 FC 1/- SOL 4 SD .7 OIL -/94 MBL 10 pH 9.4 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT 7.6 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 5 PENTANE (C -5) @ @ HYDROCARBON SHOWS 0 - ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090116.htm (1 of 2)1/16/2009 1:26:03 AM Daily Report LITHOLOGY PRESENT Coal 50 %, Sandstone 30 %, Sand 10 %, Claystone THOLOGY 10% DAILY ACTIVITY Finished running casing. Circulated to get past 3 joints to bottom. Circulated the hole and rigged cement crew. Ran cement job and displacement. Sent waste mud and excess active system mud to SUMMARY G &I for processing. Got everything ready for second stage of cement job. EPOCH PERSONNEL ON Zach Beekman, Justin Vandeberg, Jeff McBeth, Noah DAILY $4790.00 BOARD Bodin COST REPORT BY Zach Beekman S file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090116.htm (2 of 2)1/16/2009 1:26:03 AM Daily Report CHEVRON USA S DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Bob Farrell DATE , 01/16/2009 DEPTH 6024.00000 PRESENT OPERATION Running back in hole TIME 3:00 AM YESTERDAY 6024.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM D UMP PRESSURE @ @ PSI RILLING MUD REPORT DEPTH 6024' MW 9.5 VIS 47 PV 9 YP 16 FL 8 Gels 8/13/- CL- 24000 FC 1/- SOL 4.0 SD .50 OIL -/94 MBL 0 pH 9.80 Ca+ 320 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 0 CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) @ @ CONNECTION GAS HIGH 0 ETHANE (C -2) @ @ AVG 0 PROPANE (C -3) @ @ CURRENT 0 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 0 PENTANE (C -5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /CVDOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090117.htm (1 of 2)1/17/2009 1:29:29 AM Daily Report LITHOLOGY PRESENT Coal 50 %, Sandstone 30 %, Claystone 10 %, Sand 1 0 0 THOLOGY 10% AILY ACTIVITY Ran the second cement stage. Dumped contaminated mud. Emptied the BOP stack and changed the SUMMARY rams back to 5 inch drill pipe. Setup the new BHA, running bit and collars only, motor is not in due to weather issues. Tripping in the hole, picking up drill pipe. EPOCH PERSONNEL ON Zach Beekman, Justin Vandeberg, Jeff McBeth, Noah DAILY $4790.00 BOARD Bodin COST REPORT BY Zach Beekman S fa file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090117.htm (2 of 2)1/17/2009 1:29:29 AM Daily Report iiki CHEVRON lir DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Brad Rasch DATE , 1/17/2009 DEPTH 6024.00000 PRESENT OPERATION Tripping in hole TIME 3:00 AM YESTERDAY 6024.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 4 8.5 STC- Insert Bit PG1561 3x14 0 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS al•TARY RPM @ @ RPM lIpMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6024' MW 9.40 VIS 47 PV 9 YP 17 FL 8.7 Gels 8/13/- CL- 25000 FC 1/- SOL 3.9 SD .60 OIL -/94 MBL 0 pH 9.70 Ca+ 280 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 0 CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) @ @ CONNECTION GAS HIGH 0 ETHANE (C -2) @ @ AVG 0 PROPANE (C -3) @ @ CURRENT 0 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 0 PENTANE (C -5) @ @ HYDROCARBON SHOWS iv ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090118.htm (1 of 2)1/18/2009 1:38:59 AM Daily Report LITHOLOGY PRESENT Coal 50 %, Sandstone 30 %, Claystone 10 %, Sand . ITHOLOGY 10% DAILY ACTIVITY Picking up drill pipe and tripping in the hole. Stopped at 3000' to test casing to 1500 psi. Drilled out the SUMMARY plug at 3200'. Continued reaming and cleaning the hole to 5500'. Dumped all cement contaminated mud and made fresh mud to keep up the volume. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman S file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090118.htm (2 of 2)1/18/2009 1:38:59 AM Daily Report CHEVRON III DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Brad Rasch DATE Jan 18, 2009 DEPTH 6045.00000 PRESENT OPERATION Testing BOP TIME 3:00 AM YESTERDAY 6025.00000 24 HOUR FOOTAGE 20 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 4 8.5" STC -Insert Bit PG1561 3x14 20' 1 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 70.1 @ 6026.00000 27.1 @ 6025.00000 52.1 59.06190 FT /HR SURFACE TORQUE 10650 @ 6045.00000 9183 @ 6027.00000 10356.9 10650.22656 AMPS WEIGHT ON BIT 24 @ 6037.00000 4 @ 6025.00000 19.1 21.60175 KLBS OTARY RPM 76 @ 6029.00000 62 @ 6028.00000 76.0 74.72043 RPM MP PRESSURE 1147 @ 6038.00000 900 @ 6045.00000 1041.2 900.45392 PSI DRILLING MUD REPORT DEPTH 6045' MW 9.30 VIS 50 PV 8 YP 12 FL 9.6 Gels 5/6/- CL- 22000 FC 2/- SOL 3.2 SD 0 OIL -/95 MBL 0 pH 9.80 Ca+ 280 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 5 @ 6035.00000 4 @ 6045.00000 5.0 TRIP GAS 0 CUTTING GAS 0 @ 6045.00000 0 @ 6045.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) 0 @ 6045.00000 0 @ 6045.00000 0.0 CONNECTION GAS HIGH 0 ETHANE (C -2) 0 @ 6045.00000 0 @ 6045.00000 0.0 AVG 0 PROPANE (C -3) 0 @ 6045.00000 0 @ 6045.00000 0.0 CURRENT 0 BUTANE (C -4) 0 @ 6045.00000 0 @ 6045.00000 0.0 CURRENT BACKGROUND /AVG 0 PENTANE (C -5) 0 © 6045.00000 0 @ 6045.00000 0.0 HYDROCARBON SHOWS • TERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090118.htm (1 of 2)1/19/2009 3:02:38 AM Daily Report LITHOLOGY PRESENT Tuffaceous CIay60 %, Claystone30 %, Sand HOLOGY 10% Made the casing test at 5560' to 5500 psi. Went to bottom and continued reaming to get to the bottom DAILY ACTIVITY of casing. Drilled out at 6024'. Got all contaminated mud to G &I for processing. Continued drilling to SUMMARY 6045', circulated to get even mud and to clean the hole. Made FIT to 13.6 EMW. Got a good test and began to trip out of the hole. Made BOP as tripping out to pick up the BHA. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman 410 S file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS/MY WELLS /CHEVRON /20090118.htm (2 of 2)1/19/2009 3:02:38 AM Daily Report CHEVRON • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Brad Rasch DATE Jan 19, 2009 DEPTH 6045.00000 PRESENT OPERATION Tripping to bottom TIME 3:00 AM YESTERDAY 6045.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 4 8.5 HYC- RSX616M -A1 123276 9x11 0 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS 'OTARY RPM @ @ RPM JMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6045' MW 9.30 VIS 46 PV 7 YP 13 FL 9.0 Gels 6/8/- CL- 25000 FC 2/- SOL 2.9 SD .60 OIL -/95 MBL 7.5 pH 11.50 Ca+ 200 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 0 CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) @ @ CONNECTION GAS HIGH 0 ETHANE (C -2) @ @ AVG 0 PROPANE (C -3) @ @ CURRENT 0 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 0 PENTANE (C -5) @ @ HYDROCARBON SHOWS •TERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090118.htm (1 of 2)1/20/2009 2:17:06 AM Daily Report LITHOLOGY PRESENT Tuffaceous Clay 60 %, Claystone 30 %, Sand THOLOGY 10% AILY ACTIVITY Put together the directional drilling equipment and began to trip in the hole. Stopped at 5700' to cut drill SUMMARY line and work on the alarm system to ensure in good working order. Circulated mud to get even mud weight all around and worked on dropping water loss to drill. Tripping in the hole to TD. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman 0 II I file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090118.htm (2 of 2)1/20/2009 2:17:06 AM Daily Report 41110 CHEVRON DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Brad Rasch DATE Jan 20, 2009 DEPTH 6960.00000 PRESENT OPERATION Drilling TIME 3:00 AM YESTERDAY 6142.00000 24 HOUR FOOTAGE 818 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5 8.5" HYC- RSX616M -A1 123276 9x11 818 24 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 262.7 @ 6153.00000 7.2 @ 6958.00000 88.1 19.27804 FT /HR SURFACE TORQUE 18352 @ 6772.00000 6358 @ 6250.00000 12006.9 15991.14258 AMPS WEIGHT ON BIT 24 @ 6956.00000 0 @ 6528.00000 5.9 15.81835 KLBS OTARY RPM 129 @ 6291.00000 82 @ 6813.00000 106.2 119.08098 RPM J MP PRESSURE 2351 @ 6960.00000 1368 @ 6741.00000 1760.4 2351.62012 PSI DRILLING MUD REPORT DEPTH 6970 MW 9.80 VIS 52 PV 13 YP 24 FL 5.0 Gels 9/14/- CL- 26000 FC 1/- SOL 5.9 SD .50 OIL -/92.0 MBL 10 pH 9.80 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 946 @ 6381.00000 4 @ 6897.00000 145.4 TRIP GAS 0 CUTTING GAS 0 @ 6960.00000 0 @ 6960.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) 442800 © 6381.00000 1 @ 6720.00000 48269.6 CONNECTION GAS HIGH 525 ETHANE (C -2) 62433 @ 6389.00000 @ 6720.00000 3651.9 AVG 464.5 PROPANE (C -3) 0 @ 6960.00000 1 @ 6720.00000 -0.1 CURRENT 5 BUTANE (C -4) 0 @ 6960.00000 2 @ 6720.00000 -0.1 CURRENT BACKGROUND /AVG 3 O NTANE (C -5) 0 @ 6960.00000 2 @ 6720.00000 -0.1 file: / / /Cl/Documents and Settings /RigUser/Desktop /20090121.htm (1 of 2)1/21/2009 2:35:30 AM Daily Report HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION HOLOGY PRESENT Claystone 70 %, Sand 20 %, Volcanic Ash 10% LITHOLOGY 4 lior DAILY ACTIVITY Circulated at bottom and began to drill. Drilled from 6045' to 6430' and began to get gas back. Stopped SUMMARY drilling to circulate and to raise mud weight to 9.7 ppg. Continued to circulate to get gas out. Continued to drill from 6043' to 6970' increasing mud weight to 9.8 ppg. Drilling at report time. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman • file: / / /C/Documents and Settings/RigUser /Desktop /20090121.htm (2 of 2)1/21/2009 2:35:30 AM Daily Report ill CHEVRON DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Mike Leslie /Brad Rasch DATE Jan 21, 2009 DEPTH 7040.00000 PRESENT OPERATION Servicing top drive TIME 08:46:30 YESTERDAY 6960.00000 24 HOUR FOOTAGE 80 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5 8.5" HYC- RSX616M -A1 123276 9x11 1020 14 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 83.7 @ 7009.00000 3.7 @ 7027.00000 20.9 16.13214 FT /HR SURFACE TORQUE 16840 @ 7006.00000 9832 @ 7031.00000 13228.8 10789.15234 AMPS WEIGHT ON BIT 23 @ 6963.00000 7 @ 7029.00000 15.7 13.15281 KLBS OTARY RPM 121 @ 7006.00000 71 @ 7039.00000 99.9 71.07182 RPM MP PRESSURE 2444 @ 6972.00000 1873 @ 6982.00000 2075.9 2084.02905 PSI DRILLING MUD REPORT DEPTH 7040' MW 9.90 VIS 46 PV 13 YP 22 FL 4.5 Gels 7/10/- CL- 27000 FC 1/- SOL 6.7 SD .25 OIL .2/91.0 MBL 10 pH 9.40 Ca+ 280 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 12 @ 7028.00000 1 @ 7030.00000 5.1 TRIP GAS 0 CUTTING GAS 0 @ 7040.00000 0 @ 7040.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) 1697 @ 6998.00000 188 @ 6970.00000 436.2 CONNECTION GAS HIGH 5 ETHANE (C -2) 0 © 7040.00000 0 @ 7040.00000 0.0 AVG 3 PROPANE (C -3) 0 @ 7040.00000 0 @ 7040.00000 0.0 CURRENT 0 BUTANE (C -4) 0 @ 7040.00000 0 @ 7040.00000 0.0 CURRENT BACKGROUND /AVG 0 PENTANE (C -5) 0 @ 7040.00000 0 @ 7040.00000 0.0 HYDROCARBON SHOWS •TERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090121.htm (1 of 2)1/22/2009 3:39:06 AM Daily Report LITHOLOGY PRESENT Claystone 40 %, Volcanic ash 20 %, Coal 10 %, Sand 10 %, Shale 10 %, Siltstone i iITHOLOGY 10% Continue drilling from 6960' to 7040', cleaned the bit to prevent balling. At 7000' looked like a nozzle got DAILY ACTIVITY plugged. Pumped wall nut sweeps to clean the bit, was able to clean the nozzle and continue drilling. SUMMARY Top drive began to have problems and had to pull back to the intermediate shoe to fix. Changed the pump liners from 5" to 5.5" to get max GPM. Finished testing gas alarms. Cleaned pits 1 and 2 to keep mud weight down. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY 4790.00 BOARD Patterson COST REPORT BY Zach Beekman • file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090121.htm (2 of 2)1/22/2009 3:39:06 AM Daily Report CHEVRON • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Sam Menapace /Brad Rasch DATE Jan 22, 2009 DEPTH 7040.00000 PRESENT OPERATION Servicing top drive TIME 3:00AM YESTERDAY 7040.00000 24 HOUR FOOTAGE 0 CASING 20.00" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5 8.5" HYC- RSX616M -A1 123276 9x11 1000 24 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS 4t IGHT ON BIT @ @ KLBS TARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7040' MW 9.90 VIS 50 PV 9 YP 23 FL 4.6 Gels 7/11/- CL- 27000 FC 1/- SOL 5.6 SD .50 OIL .2/92.00 MBL 10 pH 9.10 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 0 CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) @ @ CONNECTION GAS HIGH 0 ETHANE (C -2) @ @ AVG 0 PROPANE (C -3) @ @ CURRENT 0 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 0 • PENTANE (C -5) @ @ file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090121.htm (1 of 2)1/23/2009 4:26:36 AM Daily Report HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION •ITHOLOGY PRESENT Claystone 40 %, Volcanic Ash 20 %, Coal 10 %, Sand10 %, Shale 10 %, Siltstone LITHOLOGY 10% DAILY ACTIVITY Top drive on the rig is down, trying to get parts in to repair. Decided to pull out of the hole to clean the SUMMARY BHA. Cleaned 2 jets on the bit and checked other BHA components. Parts have arrived and crew working to get the top drive repaired. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman • • file: / / /G/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS/MY WELLS /CHEVRON /20090121.htm (2 of 2)1/23/2009 4:26:36 AM Daily Report CHEVRON • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Sam Menapace /Brad Rasch DATE Jan 21, 2009 DEPTH 7040.00000 PRESENT OPERATION Tripping in hole TIME 08:46:30 YESTERDAY 7040.00000 24 HOUR FOOTAGE 0 CASING 20" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5 8.5" PDC 123276 9x11 1000 24 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS 4111 ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW 9.90 VIS 52 PV 12 YP 19 FL 5. Gels 8/12/- CL- 25000 FC 1/- SOL 5.8 SD .5 OIL .2/92.0 MBL 10 pH 9 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 0 CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C -1) @ @ CONNECTION GAS HIGH 0 ETHANE (C -2) @ @ AVG 0 PROPANE (C -3) @ @ CURRENT 0 BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG 0 PENTANE (C -5) @ @ file:/ / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS/MY WELLS /CHEVRON /20090121.htm (1 of 2)1/24/2009 2:49:19 AM Daily Report HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION HOLOGY PRESENT Claystone 40% Volcanic Ash 20% Coal 10% Sand 10% Shale 10% Siltstone LITHOLOGY 10% DAILY ACTIVITY Continue to work on top drive. After repair was complete, tested and verified everything work fine SUMMARY before begin to put together BHA and tripping back to bottom. Tripping at report time. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY 4790. BOARD Patterson COST REPORT BY Zach Beekman • file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS/MY WELLS /CHEVRON /20090121.htm (2 of 2)1/24/2009 2:49:19 AM Daily Report CHEVRON • DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Brad Rasch DATE Jan 24, 2009 DEPTH 7545.00000 PRESENT OPERATION Drilling TIME 3:00 AM YESTERDAY 7041.00000 24 HOUR FOOTAGE 504 CASING 20" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5RR 8.5" PDC 123276 9x11 1500 30 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 260.5 @ 7524.00000 11.1 @ 7181.00000 75.5 71.19971 FT /HR SURFACE TORQUE 18939 @ 7508.00000 10989 @ 7042.00000 14134.8 17473.01563 AMPS IGHT ON BIT 13 @ 7330.00000 0 @ 7523.00000 7.4 0.56237 KLBS O TARY RPM 123 @ 7352.00000 89 @ 7373.00000 113.7 114.16747 RPM PUMP PRESSURE 2562 @ 7180.00000 1785 @ 7216.00000 2387.2 2392.78784 PSI DRILLING MUD REPORT DEPTH 7460' MW 9.90 VIS 47 PV 13 YP 19 FL 5.0 Gels 7/11/- CL- 26000 FC 1/- SOL 5.7 SD .50 OIL .2/92.0 MBL 10.0 pH 9.30 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 252 @ 7372.00000 0 @ 7290.00000 35.1 TRIP GAS 54 CUTTING GAS 0 @ 7545.00000 0 @ 7545.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 15922 @ 7077.00000 1694 @ 7121.00000 1695.0 CONNECTION GAS HIGH 161 ETHANE (C -2) 0 @ 7545.00000 0 @ 7545.00000 0.0 AVG 40 PROPANE (C -3) 0 @ 7545.00000 0 @ 7545.00000 0.0 CURRENT 18 BUTANE (C -4) 0 @ 7545.00000 0 @ 7545.00000 0.0 CURRENT BACKGROUND /AVG 12/9 PE NTANE (C -5) 0 @ 7545.00000 0 @ 7545.00000 0.0 file:///C/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090125.htm (1 of 2)1/25/2009 3:26:47 AM Daily Report HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION THOLOGY PRESENT Sand 40 %, Sandstone 40 %, Conglomerate LITHOLOGY 20% Continued tripping in hole filling up every 20 stands. Broke connection at 6015' to get complete DAILY ACTIVITY circulation and to test top drive. Continued reaming to bottom. Tight spot at 6040' to 6050', tight spot at SUMMARY 6420' to 6450', and again at 6530' to 6550'. Adding lubricant to avoid sticking through clays. Began to drill at 7040' to 7545'. Drilling at report time. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman file: / / /G/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090125.htm (2 of 2)1/25/2009 3:26:47 AM Daily Report CHEVRON • DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Brad Rasch DATE Jan 25, 2009 DEPTH 8058.00000 PRESENT OPERATION Drilling TIME 3:00 AM YESTERDAY 7671.00000 24 HOUR FOOTAGE 387 CASING 20" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5RR 8.5" PDC 123276 9x11 1800 35 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 133.8 @ 8033.00000 7.0 @ 7749.00000 63.8 79.75719 FT /HR SURFACE TORQUE 20282 @ 7707.00000 12409 @ 7727.00000 16181.6 15728.72754 AMPS fO IGHT ON BIT 17 @ 7738.00000 0 @ 7986.00000 8.6 12.78018 KLBS TARY RPM 105 @ 7701.00000 82 @ 7731.00000 94.9 101.61111 RPM PUMP PRESSURE 2747 @ 8032.00000 2433 @ 7702.00000 2596.4 2737.56836 PSI DRILLING MUD REPORT DEPTH 8020' MW 10.50 VIS 47 PV 16 YP 19 FL 5.5 Gels 5/14/- CL- 28000 FC 1/- SOL 7.6 SD .25 OIL .2/90.0 MBL 7.5 pH 8.40 Ca+ 440 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 204 @ 8003.00000 6 @ 7979.00000 36.4 TRIP GAS CUTTING GAS 0 @ 8058.00000 0 @ 8058.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 0 @ 8058.00000 0 @ 8058.00000 0.0 CONNECTION GAS HIGH 115 ETHANE (C -2) 0 © 8058.00000 0 @ 8058.00000 0.0 AVG 50 PROPANE (C -3) 0 @ 8058.00000 0 @ 8058.00000 0.0 CURRENT 15 BUTANE (C -4) 0 @ 8058.00000 0 @ 8058.00000 0.0 CURRENT BACKGROUND /AVG 15/12 PE NTANE (C -5) 0 @ 8058.00000 0 @ 8058.00000 0.0 file: / / /C] /DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS/MY WELLS /CHEVRON /20090126.htm (1 of 2)1/26/2009 1:51:00 AM Daily Report o HYDROCARBON SHOWS I NTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION HOLOGY PRESENT Claystone 50 %, Sand 40 %, Volcanic Ash LITHOLOGY 10% DAILY ACTIVITY Continued drilling to 7978' and stopped due to damage to monkey boards. Haulted drilling to repair. SUMMARY Repaired the monkey boards and continued drilling to 8058'. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman 110 • file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090126.htm (2 of 2)1/26/2009 1:51:00 AM Daily Report Y P CHEVRON • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Sam Menapace /Brad Rasch DATE Jan 27, 2009 DEPTH 8765.00000 PRESENT OPERATION Drilling TIME 01:40:25 YESTERDAY 8169.00000 24 HOUR FOOTAGE 596 CASING 20" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5RR 8.5" PDC 123276 9x11 2400 55 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 209.0 @ 8343.00000 10.3 @ 8293.00000 47.8 30.12880 FT /HR SURFACE TORQUE 21934 @ 8591.00000 12842 @ 8506.00000 18052.1 17395.83398 AMPS •IGHT ON BIT 23 @ 8343.00000 0 @ 8315.00000 8.1 12.09105 KLBS ROTARY RPM 107 @ 8427.00000 79 @ 8516.00000 91.8 100.05048 RPM PUMP PRESSURE 3000 @ 8718.00000 2006 @ 8657.00000 2825.4 2989.72144 PSI DRILLING MUD REPORT DEPTH 8740' MW 10.0 VIS 45 PV 15 YP 18 FL 5.2 Gels 7/10/15 CL- 28000 FC 1/- SOL 9.6 SD .23 OIL 2.3/86.0 MBL 12.5 pH 8.20 Ca+ 480 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 332 @ 8425.00000 2 @ 8725.00000 32.2 TRIP GAS CUTTING GAS 0 @ 8765.00000 0 @ 8765.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 99598 @ 8425.00000 1385 @ 8169.00000 7079.2 CONNECTION GAS HIGH 147 ETHANE (C -2) 0 @ 8765.00000 0 @ 8765.00000 0.0 AVG 70 PROPANE (C -3) 0 @ 8765.00000 0 @ 8765.00000 0.0 CURRENT 12 BUTANE (C -4) 0 @ 8765.00000 0 @ 8765.00000 0.0 CURRENT BACKGROUND /AVG 12/9 ENTANE (C -5) 0 @ 8765.00000 0 @ 8765.00000 0.0 file: / / /G/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090127.htm (1 of 2)1/27/2009 2:13:44 AM Daily Report ilo. HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION HOLOGY PRESENT Coal 40 %, Sand 20 %, Claystone 20 %, Volcanic Ash 10 %, Limestone LITHOLOGY 10% DAILY ACTIVITY Continued drilling from 8169' to 8765'. Rotary torque has been climbing, so put additives in mud system SUMMARY to try and reduce torque. Drilling currently at report time. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman • S file: / / /CVDOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090127.htm (2 of 2)1/27/2009 2:13:44 AM Daily Report CHEVRON DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Jan 27, 2009 DEPTH 9400.00000 PRESENT OPERATION Drilling TIME 3:00 AM YESTERDAY 8765.00000 24 HOUR FOOTAGE 635 CASING 20" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5RR 8.5" PDC 123276 9x11 2800 70 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 112.8 @ 9020.00000 8.1 @ 9389.00000 45.3 56.99900 FT /HR SURFACE TORQUE 22103 @ 9167.00000 12981 @ 9082.00000 17232.1 18399.18555 AMPS IGHT ON BIT 17 @ 9094.00000 0 @ 9151.00000 9.9 1.68712 KLBS OTARY RPM 109 @ 9162.00000 83 @ 9078.00000 100.7 107.38689 RPM PUMP PRESSURE 3056 @ 9214.00000 2819 @ 9148.00000 2945.2 2881.65576 PSI DRILLING MUD REPORT DEPTH 9400' MW 10.0 VIS 51 PV 17 YP 18 FL 0 Gels 6/9/13 CL- 27000 FC 1/- SOL 9.4 SD .12 OIL 2.1/86.5 MBL 13.0 pH 8.50 Ca+ 400 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 112 @ 9030.00000 4 @ 9331.00000 22.7 TRIP GAS CUTTING GAS 0 @ 9400.00000 0 @ 9400.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 38835 @ 9397.00000 1065 @ 8914.00000 7146.3 CONNECTION GAS HIGH 107 ETHANE (C -2) 0 @ 9400.00000 0 @ 9400.00000 0.0 AVG 70 PROPANE (C -3) 0 @ 9400.00000 0 @ 9400.00000 0.0 CURRENT 8 BUTANE (C -4) 0 @ 9400.00000 0 @ 9400.00000 0.0 CURRENT BACKGROUND /AVG 12/9 PENTANE (C -5) 0 @ 9400.00000 0 @ 9400.00000 0.0 file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090127.htm (1 of 2)1/28/2009 1:34:14 AM Daily Report 0. HYDROCARBON SHOWS I NTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION HOLOGY PRESENT Claystone 30 %, Sand 30 %, Sandstone 30 %, Volcanic Ash LITHOLOGY 10% DAILY ACTIVITY Continue drilling from 8765 to 9400'. Added 2 pounds per bbl of steelseal, torque -trim 2, and drill -n- SUMMARY slide and it has brought the torque down about 1200 to 2000 ft lb. Continueing to drill toward TD. Drilling at report time. EPOCH PERSONNEL ON Zach Beekman, Jeff McBeth, Noah Bodin, James DAILY $4790.00 BOARD Patterson COST REPORT BY Zach Beekman 110 • file: / / /C]/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090127.htm (2 of 2)1/28/2009 1:34:14 AM Daily Report CHEVRON 0 DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Jan 28, 2009 DEPTH 10060.00000 PRESENT OPERATION Back Reaming TIME 5:45 AM YESTERDAY 9610.00000 i 24 HOUR FOOTAGE 450 CASING 20" 13.375" 9.625" INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED 5RR 8.5" PDC 123276 9x11 2850 72 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 179.2 @ 9689.00000 7.4 @ 9697.00000 29.7 12.56800 FT /HR SURFACE TORQUE 22767 @ 9688.00000 14864 @ 9635.00000 16197.0 AMPS IGHT ON BIT 25 @ 9690.00000 0 @ 9721.00000 8.1 13.64500 KLBS ROTARY RPM 121 @ 9923.00000 78 @ 9633.00000 85.4 RPM PUMP PRESSURE 3097 @ 9687.00000 2871 @ 9997.00000 2571.4 PSI DRILLING MUD REPORT DEPTH MW 10.00 VIS 48 PV 19 YP 19 FL 4.8 Gels 7/9/13 CL- 30000 FC 1/- SOL 9.5 SD .15 OIL 2.0/86.2 MBL 12.0 pH 8.40 Ca+ 480 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 221 @ 9871.00000 0 @ 9734.00000 24.4 TRIP GAS CUTTING GAS 0 @ 10060.00000 0 @ 10060.00000 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) 107928 @ 9788.00000 110 @ 9734.00000 7100.2 CONNECTION GAS HIGH 237 ETHANE (C -2) 0 @ 10060.00000 0 @ 10060.00000 0.0 AVG 35 PROPANE (C -3) 0 @ 10060.00000 0 @ 10060.00000 0.0 CURRENT 7 BUTANE (C -4) 0 @ 10060.00000 0 @ 10060.00000 0.0 CURRENT BACKGROUND /AVG 8/6 PE NTANE (C -5) 0 @ 10060.00000 0 @ 10060.00000 0.0 file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090129.htm (1 of 2)1/29/2009 7:13:31 AM Daily Report HYDROCARBON SHOWS INTERVAL LITHOLOGY /REMARKS GAS DESCRIPTION THOLOGY RESENT Claystone 80 %, Coal 10 %, Sand 10 LITHOLOGY DAILY ACTIVITY TD of 10060' reached, back SUMMARY reaming EPOCH PERSONNEL ON Jeff McBeth, Noah Bodin, James Patterson, Christina DAILY $4790.00 BOARD Medlyn COST REPORT BY Jeff McBeth I • file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090129.htm (2 of 2)1/29/2009 7:13:31 AM Daily Report Chevron • DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Jan. 29, 2009 DEPTH 10060' PRESENT OPERATION POOH to run wireline TIME 05:OOam YESTERDAY 10060' 24 HOUR FOOTAGE 0 CASING 20" @ 13.375" @ 9.625" @ INFORMATION 173' 1017' 6015' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS •TARYRPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG PENTANE (C -5) @ @ Mr DROCARBON SHOWS ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION I file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (1 of 2)2/5/2009 9:38:28 AM Daily Report LITHOLOGY PRESENT HOLOGY ILY ACTIVITY TD'd at 10060'; CBU and condition hole; back -ream f/ 9880' to 6035'; CBU; SUMMARY POOH EPOCH PERSONNEL ON 4 DAILY $4970 BOARD COST REPORT BY Medlyn • file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (2 of 2)2/5/2009 9:38:28 AM Daily Report Chevron • DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Jan. 30, 2009 DEPTH 10060' PRESENT OPERATION Testing BOP TIME 05:OOam YESTERDAY 10060' 24 HOUR FOOTAGE 0 CASING INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS •TARYRPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG PENTANE (C -5) @ @ DROCARBON SHOWS -ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (1 of 2)2/5/2009 9:42:45 AM Daily Report LITHOLOGY PRESENT � HOLOGY ILY ACTIVITY POOH; L/D BHA; RIH w/ Wireline; blocked by bridge at 6200'; POOH; test BOP for 7" SUMMARY casing EPOCH PERSONNEL ON DAILY 4 $4970 BOARD COST REPORT BY Medlyn • • file: / / /G/DOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (2 of 2)2/5/2009 9:42:45 AM Daily Report Chevron • DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Jan. 31, 2009 DEPTH 10060' PRESENT OPERATION Wash to bottom, CBU TIME 05:OOam YESTERDAY 10060' 24 HOUR FOOTAGE 0 CASING 20" @ 13.375" @ 9.625" @ INFORMATION 173' 1017' 6015' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS TARY RPM @ @ RPM UMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG PENTANE (C -5) @ @ AITDROCARBON SHOWS fERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /CVDOCUMENTS AND SETTINGS/RIGUSER/MY DOCUMENTS/MY WELLS /CHEVRON /20090205.htm (1 of 2)2/5/2009 9:48:46 AM Daily Report LITHOLOGY PRESENT THOLOGY ILY ACTIVITY Complete BOP testing; RIH to 5900; TIH to 6095' and wash through bridge to 6127'; RIH to 10028; SUMMARY CBU; POOH EPOCH PERSONNEL ON DAILY 2 $3990 BOARD COST REPORT BY Medlyn • file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (2 of 2)2/5/2009 9:48:46 AM Daily Report Chevron DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Feb. 1, 2009 DEPTH 10060' PRESENT OPERATION Testing 7" BOP for liner TIME 05:OOam YESTERDAY 10060' 24 HOUR FOOTAGE 0 CASING INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS EIGHT ON BIT @ @ KLBS TARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG PENTANE (C -5) @ @ VDROCARBON SHOWS ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (1 of 2)2/5/2009 9:53:36 AM Daily Report LITHOLOGY PRESENT THOLOGY AILY ACTIVITY RTB; CBU; Circ carbide and high visc sweep; POOH; L/D BHA; begin testing 7" rams in SUMMARY BOP. EPOCH PERSONNEL ON 2 DAILY $3990 BOARD COST REPORT BY Medlyn file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (2 of 2)2/5/2009 9:53:36 AM Daily Report Chevron O DAILY WELLSITE REPORT EPOCH LOGO IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Feb. 2, 2009 DEPTH 10060' PRESENT OPERATION RIH w/ 102 stands of 7" liner TIME 05:00 YESTERDAY 10060' 24 HOUR FOOTAGE 0 CASING 20" @ 13.375" @ 9.625" @ INFORMATION 173' 1017' 6015' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS •TARYRPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG PENTANE (C -5) @ © at DROCARBON SHOWS ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (1 of 2)2/5/2009 9:58:09 AM Daily Report LITHOLOGY li PRESENT THOLOGY AILY ACTIVITY Complete testing 7" rams; RIH w/ 102 stands of 7" SUMMARY liner EPOCH PERSONNEL ON 2 DAILY $3990 BOARD COST REPORT BY Medlyn • IIII file: / / /G/DOCUMENTS AND SETTINGS/RIGUSER /MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (2 of 2)2/5/2009 9:58:09 AM Daily Report 1110 Chevron DAILY WELLSITE EPOCH LOGO REPORT IRU 11 -06 REPORT FOR Sam Menapace /Bob Farrell DATE Feb. 3, 2009 DEPTH 10060' PRESENT OPERATION Working pipe to bottom; CBU TIME 05:OOam YESTERDAY 10060' 24 HOUR FOOTAGE 0 CASING 20" @ 13.375" @ 9.625" @ INFORMATION 173' 1017' 6015' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T /B /C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT /HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS •TARYRPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C -1) @ @ CONNECTION GAS HIGH ETHANE (C -2) @ @ AVG PROPANE (C -3) @ @ CURRENT BUTANE (C -4) @ @ CURRENT BACKGROUND /AVG PENTANE (C -5) @ @ gliDROCARBON SHOWS lip-ERVAL LITHOLOGY /REMARKS GAS DESCRIPTION file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (1 of 2)2/5/2009 10:02:20 AM Daily Report LITHOLOGY i iiTHOLOGY 1 11FAILY ACTIVITY RIH w/ 102 stands of 7" liner; Working pipe SUMMARY down EPOCH PERSONNEL ON 2 DAILY $3990 BOARD COST C. REPORT BY Medlyn 411 • file: / / /Cl/DOCUMENTS AND SETTINGS /RIGUSER/MY DOCUMENTS /MY WELLS /CHEVRON /20090205.htm (2 of 2)2/5/2009 10:02:20 AM