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169-018
1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _0 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): North Cook Inlet Field GL: N/A BF: N/A Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 30" - 390' 16" H-40 576' 10-3/4" J-55 2,264' 7" J-55 2,572' (TOW) 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate April 8, 1969 March 19, 1969 ADL017589 N/A N/A 2,810' MD / 2,572' TVD99 N/A 7,656' MD / 6,421' TVD N/A Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A Water-Bbl: PRODUCTION TEST N/A Date of Test: Flow Tubing - 65# 390' Surface 2,410' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 45.5 & 51# 2,810' (TOW) Surface Surface DEPTH SET (MD) PACKER SET (MD/TVD) Surface CASING WT. PER FT.GRADE 26 & 23# 333750 334780 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 2584001 BOTTOM TOP 15" Surface 22" HOLE SIZE AMOUNT PULLED 50-883-20023-00-00 NCIU A-04 332108 2586718 2539' FNL, 2279' FEL, Sec 6, T11N, R9W, SM, AK CEMENTING RECORD 2585415 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 8/20/2021 1259' FNL, 1086' FWL, Sec 6, T11N, R9W, SM, AK 3896' FNL, 3744' FWL, Sec 6, T11N, R9W, SM, AK 169-018 / 321-155 Tertiary Gas Pool 126.6' 2,810' MD / 2,572' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas - Surface 576' 545 sx Driven 1000 sx Surface N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 1252 sx9-5/8" TUBING RECORD WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 9:09 am, Nov 12, 2021 RBDMS HEW 11/16/2021 Abandonment Date 8/20/2021 HEW xG DLB 11/17/2021BJM 12/1/21 DSR-12/1/21 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A Top of Productive Interval N/A Beluga R 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange 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. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: Wellbore Schematic, Decomplete Reports. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS 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. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME This form and the required attachments provide a complete and concise record for each well drilled 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. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 11.12.2021Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.11.12 08:06:23 -09'00' Monty M Myers _____________________________________________________________________________________ Updated By: CJD11/10/21 SCHEMATIC Tyonek Platform Well: NCI A-04 P&A’d: 8/20/2021 PTD:169-018 API: 50-883-20023-00-00 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Conductor Welded 29”41’390’ 16”65 H-40 Welded 15.25”41’576’ 10-3/4”51/45.5 J-55 BTC 9.794”41’2,410’ 7”26/23 J-55 BTC 6.366”39’7,618’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43”3.428”4,447’4,701’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 8 4,120’3,586’Top of cement plug 4,402’3,810’6.366”Plug EZSV Cement retainer 9 4,447.1’3,845.9’4.000”PACKER, Baker SC-1 GP packer 10 4,451.8’3,849.7’4.892”UPPER EXTENSION 11 4,455.6’3,852.7’4.000”SLEEVE, Baker GP sliding sleeve 12 4,458.2’3,854.8’4.000”SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’4.276”5.000”LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’3,868.5’3.428”5.500”XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’3,869.7’3.000”KOIV, Baker KOIV 4” flapper 16 4,478.5’3,871.1’3.428”SOS, Baker Shear out safety sub 17 4,513.5’3,899.3’’3.428”5.43”SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’4,049.2’0.000”BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’4,154.3’0.000”PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’0.000”PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’4,576.4’0.000”PLUG, EZSV Cement Retainer (8/28/94 run date) SCHEMATIC Tyonek Platform Well: NCI A-04 P&A’d: 8/20/21 PTD: 169-018 API: 50-883-20023-00-00 __________________ Updated By: CJD 11/10/21 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 06/05/21 Isolate CI-2.0 4,620’ 4,690’ 3,984.9’ 4,048.9’ 80’ 06/05/21 Isolate CI-2.0 4,690’ 4,700’ 4,042’ 4,050’ 10’ 08/03/2020 Isolated CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 08/03/2020 Isolated CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 08/03/2020 Isolated CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Activity Date Ops Summary 5/11/2021 MORNING MEETING JSA PERMIT STAND BY FOR PLAN FORWARD,P/U LUB. STAB ON RISER P/T 250/1500PSI GOOD TEST,RIH W/ 3.76'' G-RING TO 4184'KB SIT W/ TOOL FELL TO 4212'KB W/ TOOL WOULD NOT FALL , POOH,RIH W/ 3.75'' SWEDGE TO 4216'KB SIT W/ TOOL LOSE SPANGS. JAR LICK FREE- POOH,RIH W/ 3"X6' DD BAILER TO 4217'KB W/ TOOL VERY STICKY POOH EMPTY FLAPPER STUCK OPEN W/ CLAY LIKE SAND AROUND FLAPPER,RIH W/ 2.25X4 DD BAILER TO 4500'KB DID NOT SIT DOWN NO OBSTRUCTION POOH STAND BY FOR CRANE,RIH W/ 2.5''X5' DD BAILER TO 4500'KB NO OBSTRUCTION POOH RIH W/ 3'' LIB TO 4218'KB W/ TOOL POOH W/ IMPRESSION OF POSSIBLE DAMAGED TUBING,RIH W/ 2.8'' SWEDGE TO 4219'KB ABLE TO BOBBLE THROUGH WITH SOME SPEED PULLING OUT HAD OVER PULL BUT WENT THROUGH - POOH,RD 5/21/2021 Rig up on well. Pressure test at 250psi L/1500psi H.,RIH with 1 9/16" tubing puncher. Punch at 4500'. POOH. All shots fired.,RIH with 1 9/16" tubing punch. Punch at 4418'. POOH. All shots fired. Rig down. 5/30/2021 Move rig from NCI B2 to NCI A-04. {circ A-04, pump 90 bbl no returns, pump 150 bbl total, returns clean, 0 psi tubing and IA) set drilling spool on mast, set mast load beam, set mast on deck,, remove draw works, and A-Leg. Boat unable to come in to assist due to winds. 5/31/2021 Continue r/d carrier, stairs & roll up lines to tie off, spread walkways, & remove from beam package, break down beam package, Re arrange deck, spot base beam & mat.,Finish spot and assemble beam package, stack up rig carrier, install draworks, driveline A-leg, pin landings, install ODS carrier stairs, spot accumulator & choke manifold. set electric panel power up rig, slide in carrier walkways, install carrier stairs. Spot derrick and pin on carrier A-leg.,Spot racking beam, weld stairs for beaver slide, set bang board and dog house. prepare riser spools for installation..,Install BPV, Remove production line to tree and blind line, nipple down tree, back out lock down screws and remove hanger lock down plate, clean and dress flanges, install blanking sub for BOP test, install 11" tubing spool, adapter spool, spacer spool, cross over spool and riser, install Grey Lock clamp, set in deck plate. 6/1/2021 Cont. N/U BOPE, stack up flow cross, double gate, annular & tq flanges, N/U choke & kil line, arrange decks,Prep & raise mast, secure same, string up tuggers & man rider, r/u accumulator lines,Scope mast up, secure same, string up draworks, check accumulator bottle pressure, run circulating lines from pits to pump, & standpipe manifold. c/o shifting solenoid on rig carrier. r/u rig floor, install hand rails & stairs to same.,Finished Rig Assembly, Tested Gas Detection, Built 3-1/2" and 4-1/2" Test Jts.,PU/MU 3-1/2" Test Joint and Flooded Stack. Tried to Shell Test and found 4 lockdowns pins leaking at 800psi. Drained Stack and to make repairs to Lockdowns. 3 out of 4 LDP had the Allen Head Packing Screws stripped out. Fly out replacement LDP.,Install 3 New Lockdown Pins and Repacked 1.,Shell tested to 2,500psi with a leak-off. Could not find a visual leak on the BOPE or Wellhead. Started troubleshooting leak, double blocked Kill and Choke Lines with the Bag closed, pressured up and narrowed it down to the Hanger leaking.,Contacted Wellhead Sup to find a Test Plug for the New Tubing Spool to Test BOP's. Discussed plan forward with the town engineer.,Preformed an Inhouse rolling test (250-2500psi) to ensure LDP and Tubing Spool Break wasn't leaking. 4 mins into the high @ 2500psi, 1 LDP started leaking. Working on LDP at report time. 6/2/2021 Test choke manifold at 250 L/2500 H. Perform 'rolling test' on tubing hanger with 3 1/2" test joint and annular preventer.,Pull blanking sub and 3 1/2" test joint. Make up x-overs and test plug for upper tubing hanger (Cactus-EN-CCL 11 x 4 1/2"). Fluid pack BOPE.,Cont Testing BOPE per Sundry as following: Annular 250- 2500psi, Rams 250-2500psi, Valves 250-2500psi. 1 f/p was recorded on the HCR Choke, Function and Cycled Valve, subsequent test was good. Performed the Koomey drawdown test. 3-1/2" and 4-1/2" Test Joints were used. Witness was waived by Jim Regg on 6/1/21 @ 10:39am,L/D BOP Testing equipment, Pulled BPV, Monitored Well static, MU 4-1/2" Landing Jt.,PU on Completion String, Unseated Hanger @ 40k, Pipe travel @ 55k. PU 20' putting the seal assembly anchor assembly 4' above the Baker SC-1 GP Packer.,Lined up valves, Circulated STS volume pumping @ 3bpm/150psi. SD pump monitored well, IA/Tbg on Vac. 14 bbl losses while circulating.,RU Power Tongs and prepared to POH L/D 4-1/2" Completion String.,POOH, L/D Tubing Hanger, 7 joints of 4-1/2 IBT and SSSV.,C/O Handling tool to 3-1/2". PU/MU 7" Storm Packer, RIH on 3-1/2" PH6 Workstring and set Storm Packer @ 90'.,Filled IA and stack, Closed Bag and lined up to pump down Kill line. PT the orginal Tbg Hanger and New Tbg Spool Adapter to 250psi L/2500psi H and charted test for 5mins. Good Test. Monitored OA pressure at 0psi while Testing. BOP test charts will be sent to the State via Email.,Release Storm Prk, POOH L/D 4jt of 3-1/2" WS. BO/LD Storm Pkr. PU 4-1/2" Handling Tools.,POOH, L/D 4- 1/2" Completion String. Pumping single displacement every 10jts out. 47 joint L/D at report time.,Daily Fluid Lost to Formation= 24 bbls Contractor AFE #: AFE $: Job Name: Spud Date: Well Name: Field: County/State: NCIU A-04 North Cook Inlet Hilcorp Energy Company Composite Report , Alaska n (LAT/LONG): evation (RKB): API #: PT the orginal Tbg Hanger and New Tbg Spool Adapter to 250psi L/2500psi H and charted test for 5mins. Good Test. pppp g g gpp L/D Tubing Hanger, 7 joints of 4-1/2 IBT and SSSV.,C/O Handling tool to 3-1/2". PU/MU 7" Storm Packer, RIH on 3-1/2" pg PH6 Workstring and set Storm Packer @ 90'.g@ Perform 'rolling test' on tubing hanger with 3 1/2" test joint and annular preventer., ,Release Storm Prk, POOH L/D 4jt of 3-1/2" WS. Witness was waived by Jim Regg on 6/1/21 L/D 4- 1/2" Completion String. 6/3/2021 POOH laying down 4 1/2" completion from 2836' to 1796'.,Work boat. Wait on tide. Housekeeping and rig maintenance.,Cont inue laying down completion tubing from 1796' to surface'. Recovered seal assembly. The bottom 228ft of pipe had cement inside with a coil tubing hole bored through the cement. Calculated displacement 16.5 bbls. Actual displacement 21.9 bbls.,Rig up Pollard e-line. RIH with 5.70 gauge ring/junk basket to 4450' WLM. Pick up ESSV. RIH and correlate on depth and set at 4,440'. Tagged EZSV to confirm set. POOH. and L/D Setting Tool.,Rig down E-line, Picked up 3-1/2" handling tools, prep rig floor to RIH w/Stinger Tool.,PU/MU EZSV Stinger Tool, TIH on 3-1/2" PH6 Work string f/surface t/445'md.,Work boat arrived, assist crane with boat. Offload and stage HAL cementing equipment. Loaded boat with 4-1/2" Completion Tubing and Jewelry. Greased crown and service rig as needed.,Backups not biting on the Gill Tongs. Troubleshoot. Cleaned and serviced Tong and resumed ops.,Continued TIH w/Stinger Tool on 3-1/2" PH6 Work string f/445'md t/2177'md.,Daily Fluid Lost to Formation= 24 bbls 6/4/2021 RIH with cement stinger picking up PH6 work string from 2177' to 4400'. Tag retainer at 4402'. Set down 20K. P/U 47K, S/O 40K. 20.5 bbls calc/20.5 actual displacement.,Space out. Make circulating lines. Sting into retainer with 250 psi noted increase in pump pressure. Set down 22K on retainer.,Finish rigging up Halliburton. Wait on computer cable for electronics.,Hold PJSM. Test lines at 4500 psi. Attempt to obtain injection rate at 2500 to 3000 psi several times with no success. Consult with engineer. Obtain permission from AOGCC to proceed with balanced plug above retainer.,Unsting from EZSV retainer. Pump 10 bbls Type 1-2 cement balanced plug. Cement in place at 1335 hrs.,Pull slowly and stand back 6 stands from 4402' to 4040'. TOC at +-4140'.,Drop pipe wiper ball and circulate at 3 BPM/280 psi STS.,POOH f/4040' standing back +-2800' (46 Stands) of PH6 work string. L/D remaining joints. L/D Stinger Tool.,Organized rig floor. PU/MU 6" Tricone Bit and 7" Csg Scraper,TIH w/Cleanout BHA f/surface t/2850'. Reciprocated Csg scraper from f/2,700' t/2800'.,R /U circulating lines. Rev circulated @ 3bpm/190psi, monitored returns clean. R/D circulating lines.,POOH, L/D 3-1/2" Workstring f/2800' t/surface. L/D Cleanout BHA.,Clean and clear rig floor, prepared testing equipment and aligned valves to Pressure Test the IA.,Pressure test IA against cement plug to 1,500 psi and chart for 30 minutes, good test. Chart in folder for viewing.,Assist crane, arrange deck for room to spot the S-line unit. C/O handling tool to 4-1/2" and C/O Tongs. Load 4jts of 4-1/2" IBT in beaver slide. Began R/D and organizing equipment not needed to complete the WO operation. 6/5/2021 Spot Pollard unit. Rig maintenance and prepare equipment for rig move. Wait on helicopter for slick line and well head personnel.,Rig up Pollard slick line. RIH with 2 5" x 6' drive down baler. Tag TOC at 4120' WLM. POOH. R/D slick line.,Pick up 4 1/2", 12.6#, J-55, BTC-M work string. with muleshoe collar to 130' (4 joints). Make up and land tubing hanger (installed BPV at floor). Run in lock down screws. Lay down landing joint.,Clear rig floor of tools and equipment. Remove rig floor. R/D accumulator and prep for transport. Prepare and scope down mast. Lay mast over. N/D BOPE and set out.,Pulled riser, skid rig back, Prep Wellhead, N/U Dry HoleTree, test void t/5k f/15min good. END of well work on A-04,This will be final report on this AFE. pg g yg The bottom 228ft of pipe had cement inside with a coil tubing hole bored through the cement. pp j Obtain permission from AOGCC to proceed with balanced plug above retainer. g ,Pressure test IA against cement plug to 1,500 psi and chart for 30 minutes, gy g ,Continued TIH w/Stinger Tool on 3-1/2" PH6 Work string f Pump 10 bbls Type gp p pg g 1-2 cement balanced plug. Cement in place at 1335 hrs.,Pull slowly and stand back 6 stands from 4402' to 4040'. TOC at +-4140'., pppg Tag retainer at 4402'. p pgp ,Pick up 4 1/2", 12.6#, J-55, BTC-M work string. with muleshoe collar to 130' g Make up and land tubing hanger (installed BPV at floor). pp qp Tag TOC at 4120' WLM. g Pick up ESSV. RIH p and correlate on depth and set at 4,440'. Activity Date Ops Summary 7/16/2021 NCIU St 17589 1A P&A acitivity. Rig down and move off well. Rig released from well at 19:00, see NCIU St 17589 1A P&A report for details. Moving off well on slack tide at 18:42.;Maintain station with tugs Anna T, Bering Wind, Glacier Wind and Stellar Wind while raising legs to 45' over the sea floor. Begin moving west then north west, crossed pipeline with 37' clearance at 19:41. Start lowering legs at 19:46 and were 12' off bottom at 19:57.;The synthetic winch line from Stellar Wind to port stern broke at 20:02. Current was picking up and pushing the rig further NNE. Began raising legs at 20:12 to lessen effect from current and were 45' off bottom at 20:42.;Rig was out of the surveyed area and could not lower legs to pin and the incoming current was picking up. Stellar Wind connected to port stern with another winch line. Decision was made to hold rig in position with tugs.;Maintain position as best as possible with approximately 80% power from all tugs. Started at 2100' from the Tyonek and got within 500' as current lessened. Reduce power and maintain position while waiting on 00:36 slack high.;Begin lowering legs at 23:15 to 10’ above sea floor at 23:47. Orient rig at 323* heading and move in toward the Tyonek platform. High tide at 23:59.;Lower legs and tag bottom at 00:13. Commence final positioning at 00:29. Slack tide at 00:36. Pin stern and lower bow at 00:49. Continue to position and had to reposition the Glacier Wind from port to starboard bow at 1:30.;Fight 2 knot current attempting to position. Current increased to 4 knots and actually moved further away. The decision was made to continue final positioning at 06:40 low tide. Tyonek operations moved ESD out of the way on handrail.;Lower legs and pin rig. Unhooked tow lines from two up current tugs and two down current tugs remained attached. Wait on slack tide. 7/17/2021 Hooked up tugs, jacked the rig and was floating at 6:55. Low tide at 6:40 and slack at 7:59. Spartan 151 hard pinned at 8:30 with 1’ air gap at 8:45. Verify position, slight skew to rig of 1.18° = 13” lateral movement over 53’ of skid out - good. Release tugs at 9:30.;Offloaded PSOs to the Masco Endeavour. Jack rig up to 1' of air gap. Maintain 1' air gap until high tide is reached. Calculate pre-load. Lower deep well.;Perform Mesotech MS-1000 side scan sonar image of spud cans at 12:27 high tide (13:37 slack) – looked good. eTrac technicians rigged down equipment and departed on afternoon chopper.;Began filling ballast tanks with preload - fill P-01 and P-02.;Pull blind flanges on remaining pre-load tanks. Install wing decks on port side. Perform general rig maintenance while waiting on tide to come back to resume pre-load sequence.;Sand blasting personnel and equipment arrived on the Tyonek platform and were transferred to Spartan 151. Rig manager Donnie Durham and the driller toured Tyonek for electrical cable layout.;Filled pre-load tanks P-10-5 & P-10-6, bow pre-load complete. Hold pre-load for one hour - good.;Transfer ballast water from P-01 & P-02 to P-19-1 & P-19-2. 7/18/2021 Continue to transfer water from pre-load tanks P-01 and P-02 to P-19-1 and P-19-2.;Wait on high tide to pre-load stern legs. Cover all equipment under the rig floor to protect from sandblast dust. Move pump and lines to prepare for pre-load on stern legs. Install wing deck on starboard side of the rig. Scaffolding crew mobilizing and start building scaffolding to work on sub beams;Rig crew performed man overboard rescue drill with rescue boat.;Fill stern leg pre-load tanks 10-5 and 10-6. Continue to build scaffolding - (scaffold builders end of shift at 18:00). Disconnect hydraulic lines from skid unit to allow full access to sandblast beams. Connect 2" high pressure hose to mud pump. Cover shaker motors to protect from sandblast sand.;Rig crew performed man overboard rescue drill with rescue boat - both crews understand roles and responsibilities.;Pre-load completed at 00:15, hold for one hour to 01:15 - good. Release rig mover and marine surveyor. Rinse mud pits with ballast water. Continue general rig maintenance and clean main deck 7/19/2021 Continue rig maintenance. Utilize Tyonek crane to install gangplank between Spartan 151 and the Tyonek. Scaffolding crew and sandblasting crew resumed erecting scaffolding and installing tarps. Received 3 additional scaffolding crew for a total of 5.;Utilize Tyonek crane to install 2" high pressure hose from Spartan 151 sub to Tyonek well head room.;Verify pump stroke counters work - good. Flood lines to Tyonek injection well. Pressure test lines to 650 PSI low / 3300 PSI high - good. Begin injecting pit cleaning water at 0.7 BPM, 250 PSI. Increase rate and saw break over at 550 PSI. Continue up to 2.4 BPM, 2000 PSI.;Max rate for injection well is 2.4 BPM and 2500 PSI. Pressure began to climb to 2200, slowed to 1.7 BPM, 1900 PSI then increase to 2.0 BPM, 2050 PSI. After pumping 272 bbls, increased back to 2.4 BPM, 2200 PSI.;Held meeting with DSM, Tyonek foreman & lead, rig manager, OIM, Enterprise safety rep and medic to discuss emergency muster procedures while the Spartan rig is on the platform.;Scaffolding crew end of shift at 18:00 - 70% complete.;Continue to inject pit cleaning water at 2.4 BPM, 2150 PSI - 1915 bbls injected at 24:00. Perform general rig maintenance and housekeeping.;Continue to inject pit cleaning water at 2.4 BPM, 2150 PSI. 2775 total bbls injected at 06:00. Perform general rig maintenance and housekeeping. 7/20/2021 Continue to inject pit cleaning water at 2.4 BPM = 2150 psi. 3525 total bbls injected at 12:00. Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping.;Continue to inject pit cleaning water at 2.4 BPM = 2150 psi. 5252 total bbls injected at 12:00. Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping.;Shut down the pumps with 1,500 psi on the line and monitor pressure. Pressure bled to 0 psi in 30 minutes.;Begin stripping the pre-load tanks. Pump all excess water into the pits. Perform general rig maintenance and housekeeping. 7/21/2021 Finish stripping the pre-load tanks pumping all excess water into the pits. Inject 167 bbls water at 2.4 BPM = 2100 psi. Total water injected = 5419 bbls. Perform general rig maintenance and housekeeping. Continue to build scaffolding for sand blasters.;Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping;Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping. NU the BOP stack single, double and Tee in the rotating sub.;Jack up the rig 5' due to upcoming high tide.;Continue to NU up the BOP stack installing blind flanges. Perform general rig maintenance and housekeeping.;Perform general rig maintenance and housekeeping. Prep to NU the annular 7/22/2021 NU the annular. Perform general rig maintenance and housekeeping. Wrap equipment under the rig floor to protect from sandblasting.;Spot and RU sandblasting equipment. Perform general rig maintenance and housekeeping.;Continue to RU sandblasting equipment. Perform general rig maintenance and housekeeping.;Sandblast substructure in preparation for welding. Perform general rig maintenance and housekeeping.;Change out the actuator rollers on the top drive. Check pressures on the accumulator bottles. Perform general rig maintenance and housekeeping. 7/23/2021 Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Perform general housekeeping and maintenance. Change oilers on the mud pumps. Contractor AFE #: AFE $: Spartan 151 Job Name: Spud Date: Well Name: Field: County/State: NCIU A-04 North Cook Inlet Hilcorp Energy Company Composite Report , Alaska n (LAT/LONG): evation (RKB): API #: 7/24/2021 Continue to sandblast the substructure in preparation for welding. Rain was getting into the sand hopper. Call over scaffolder's to build hooch over sandblasting equipment. Continue to sandblast. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance. Grease the choke manifold, draw works, crown and top drive. Function all the valves in the pump room and mud pits.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance. Finished sandblasting the substructure at midnight.;Perform general housekeeping and maintenance. Perform PM's on the mud pumps. 7/25/2021 Review sandblasted areas with welding supervisor and determine it is sufficient for welding. Perform general housekeeping and maintenance.;Cleanup sandblasting debris. RD scaffolding. Perform general housekeeping and maintenance. Install new hydraulic skid lines.;Cleanup sandblasting debris. RD scaffolding. Perform general housekeeping and maintenance.;Cleanup sandblasting debris. RD scaffolding and sandblasting equipment. Perform general housekeeping and maintenance. Sandblaster's left the platform at midnight.;Cleanup sandblasting debris. Perform general housekeeping and maintenance. Prep for jacking the rig. PJSM for jacking up the rig. 7/26/2021 Jack up the rig to the Tyonek Platform.;PJSM. Skid the rig over the rotating sub on the Tyonek Platform. Install walkway from the rig to the platform.;RU scaffolding for the welders. Prep and mark area for welding. Install handrails and stairs where needed.;RU scaffolding for the welders. Prep and mark area for welding. Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/27/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance. RU deep well.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Fill up bow and port leg hydraulic jacking units with hydraulic fluid.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. RU black water hose to the Tyonek platform.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/28/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Relocate the walkway between the platform and rig for easier welder access.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Assist with craning in plate steel for the welders.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Install bulk cement vent line.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/29/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/30/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/31/2021 Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Offload supplies and equipment from the work boat.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Cut threads in 2" schedule 40 pipe for rig air line and MU hammer unions. 8/1/2021 Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Unpin the cable rack from the rig and secure to the upper pipe rack. Remove the electric cables from the cable rack.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Continue to remove the electric cables from the cable rack.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Run 3" fuel hose from the rig to the Tyonek platform.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. RU the 3" fuel hose to the Tyonek platform. 8/2/2021 Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Continue to remove the electric cables from the cable rack.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Remove the cable rack from the port leg. Unpin the two sections and set down on the main deck. Move all electric cables down to the main deck.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping.;Perform general rig maintenance and housekeeping. 8/3/2021 R/D scaffolding;Prep to skid the rig and align with the rotating sub. Cleanup welding debris.;Transverse 6’ to starboard and pickup BOP’s. Unbolt rotating sub and transverse 1’ to port. Set down BOPs and secure. Transverse rig floor back to center.;Cantilever rig floor into fully stowed position.;Lower jack up 30" on bow, 26" on starboard & 28" on port. Welders secured rotating sub after traversing and prepared top of rotating sub beam for welding to rig floor package.;Cantilever rig floor package out over rotating sub, too high. Cantilever back into stowed position. Lower jack up an additional 3" on bow, 4" on starboard & 1" on port. Cantilever out over rotating sub, transverse rotating sub to fine tune position. Drill new holes and secure rotating sub.;Raise rotating sub and install 2" of shims. Install 3" of shims on rotating sub jacks. Raise rotating sub and contact rig floor package. Transvers e rig floor package centered over rotating sub and secure.;Welding and construction crews houred out. Perform general maintenance and housekeeping. Chip paint on starboard tow bits, paint handrails on shaker house. Install gangway between Spartan 151 and the Tyonek. 8/4/2021 Shim gap between gussets and rotating sub extension as required. Erect scaffolding and build tarp enclosures to provide work platform for welders.;Weld rig floor module gussets to rotating sub extension: 7/8" PJP and 1" fillet welds. 60% complete. Welders houred out and will resume at 06:00. Remove electrical wires from wire tray on port side leg tower.;Paint yellow area on starboard aft main deck. Begin installing skid off access window in flow line trough. Perform general rig maintenance and housekeeping. 8/5/2021 Resumed welding rig floor module gussets to the rotating sub extension: 7/8" PJP and 1" fillet welds. Completed everything which was accessible.;Allow welds to cool prior to Magnetic Particle Inspection. Perform MPI - good. R/D scaffolding. Rig welder fabricate hand rails for upper pipe deck opening after rig floor is skidded off.;Total Safety mounted outdoor alarms in mud pits & at shakers and indoor alarm in the galley. Rigged up secondary H2S/LEL monitor in the control room. Installed 2 outdoor monitor antennas above control room. 30% of gas system installation complete.;PJSM. Jack up rotating sub. Remove bolts securing rig floor package to the cantilever beams. Raise rig floor package up off cantilever beams, remove guide bars and retract cantilever beams clear of the platform. Suspend BOP stack with bridge cranes.;Skid rig floor package / rotating sub assembly 16' south off leg #1 to allow access for welders to finish welding remaining gussets.;Install scaffolding. Finish 7/8" PJP and 1" fillet welds on last two gussets to rotating sub extension.;Allow welds to cool prior to final Magnetic Particle Inspection. 8/6/2021 Waiting on gussets welds to cool. While waiting skid rig cantilever beams back over platform so crane can have more deck space on Jack up. Also installed handrails on cement unit roof and installed walkway to the platform. Checked measurements for turning the rig on leg 3.;Found out that the drilling line spool hung down 2'8" to much to clear the oil cooling building on the platform. Made plans to remove the 3' top section of the oil cooler before turning the rig.;MPI gusset welds and remove scaffolding. Move equip from east side of the rig in prep for moving. Cut off old trolley rails.;Jack rig about 38' to the east and run into an issue with a cross beam only partially beveled. Push rig back a few inches, and swap jacks to the west side. While moving ja cks have welders bevel the beam. Jack rig to about 6' from east side.;Welders attempted to install new landings on east side skid extension. The landing didn't fit right so they had to make changes in the beams to make them fit. Welders finished landings at 19:30. Skid rig 4', 2' short of completely over leg #2.;Total Safety 40% complete on gas detection installation. Installed 7 conductor cable from control room to pump room and mud pits. Relocated mud pit alarm.;Bevel last skid beam prior to skidding last 2' east. Welders preparing to remove louvers and top 3' from oil cooler and removed spark arrestor lines and cut turbine exhaust stair frame down to clear rig. Welders houred out at 21:30.;Drop plumb bob off crane to check for interference with rig. Found that 800 crane walkway will interfere with rig. Call Brian Wilkes and discuss options. Decision made to cut 24" off crane walkway. Discuss with Tyonek Lead about cutting landing and agreed it was the best way to proceed.;Remove handrails from crane walkway.;Crane transformer also need to be removed to clear the rig. Wake up platform electrician and formulate plan. LO/TO power to crane, disconnect and remove transformer. Will reinstall after rig moves past crane.;Cut 24" off crane walkway to provide clearance for the rig.;Skid rig module east to leg #2 and align on N/S skid rails. Move jacking cylinders to north side of rig. Remove all tools and equipment from Tyonek crane. Install chainfall hoist on crane cab jib boom to facilitate re-installation of the walkway. 8/7/2021 Welders welding pad eyes on sub for guide pins and installing pad eyes on the oil cooler roof. Get sub squared up on skids. Move jacks so we can pull the rig toward leg 3. Pull roof off oil cooler.;Jack rig from leg 2 past the crane with only 1" of clearance at times. Total safety is continuing to rig up his gas alarm system.;Move jacks to other side of sub by crane. Install 2 earthquake clamps for safety. Jack upper section up and attempt to rotate the sub. Trouble shoot rotating system. Finally found 2 hoses that were crossed and got it working.;Rotate sub around into position. Had to move it ahead several times while rotating due to interference with production mud room and the crane. Set upper section back down in it's clamp down position.;Remove earthquake clamps and jack sub up next to production over leg 3. Had to bevel the last beam in order to get on it.;Total Safety installed 7 conductor cable from mud pit alarm to shaker alarm. Tie-in wire and relays to shaker, mud pit and outdoor alarms to control room. Planning for platform installation. 50% complete on rig up.;Install c-plates to hold down rotating sub - lower pre-drilled holes did not fit, had to torch cut to size. Cut off hand rails and clearance I-beam. Unload rig equipment from the Sovereign.;Skid rig last 2' over leg #3 and align with transverse skid beam. Move jacking cylinders to lateral beam. Transverse rig module 2.5' in line with A-04A. Skid rig package on rotating sub 1' back toward leg #2 to center on A-04A.;Remove jacking cylinders from lateral beams. Re-drill rotating sub hold down bolt holds and secure. Install two outboard earthquake / hurricane clamps.;Clear the platform deck to provide working room. Set rig mat, 1/2" x 12" x 10' flat bar and shaker tank. Set two 50' HAK pipe rack riser beams. Had to utilize two cranes to set beam nearest to 800 crane since it could not boom up enough. 8/8/2021 Finish installing 28.5' HAK pipe rack riser beams. Have scaffold builders build hutches for the welders. [rain and high winds] Welders welding down 50' X 5'6" beams for raising HAK racks. Install hand rails and put up roof supports on shaker pit. Remove old pipe stop off 428 slide.;Pi n earthquake clamps to rotating sub. Welders will need to make plates to bolt them down. Remove the hyd hoses used for moving rig to clear area for service lines. Got a couple picks off the boat and weather got a lot worse, so the boat headed for calmer waters to wait it out.;Set slide from jackup to platform for running service lines. Help production RU pumps to remove rain water off platform deck. Start running HP mud line from jackup. Have scaffold builders build scaffold so we can weld a flange on the flow line. Set shaker landing and shakers. Power drk lights.;Set up service line piping stands. Run and clamp dn 4" high press mud line up to rig. Clean and prep 16" flowline for welding. Weld on 16" flange. Bolt adaptors from 16" to 10" together for the flow line. Welders building bottom plate for Earthquake clamps.;Total Safety worked with platform electrician to install primary monitor & tie into platform system. Install wellhead room and shaker pit sensors & alarms. 70% complete for installation;Run 4" mud return line, two 3" seawater lines and 2" air lines on service line piping stands. Connect mud line to the rig floor. Remove scaffolding. Unload Sperry and mud shacks, shaker pit roof and rig pieces from the Sovereign. Welders begin building 10" flow line.;Install shaker tank suction manifold and secondary transfer pump. Finish install 3" seawater and 2" air lines on piping stands. Install shaker tank roof. W eld pad eyes on cuttings chute and install on shaker discharge. Clear platform deck for electrical cable tray installation. 8/9/2021 Have welders building the flowline to the shakers. Run the ramp they used at the dock for a cable tray to the platform. Have derrick hand replacing the rubber at the end of the shakers and working on other shaker issues. Start tying in service lines. Got Pason, 2 MWD, and Baroid hand in.;Work on cable trays and cables.;Have orientation meeting with both crews and service hands in galley of the Tyonek platform.;Move light above shakers for flowline access. Weld down center section of pipe rack beams. Production electricians wiring in shaker pit pump, pit lights, and shakers. Put cable tray on stand under pipe racks. string electric cables. Hang flowline . Put knee braces on shaker landings.;Welders continue to weld knee braces on shaker landings and secure shaker landing to shaker tank. Install kick plates on shaker landing. Install rubber guard on shaker dump. Remove 1 joint of 4" line and plumb shaker tank to 4" mud return line.;Finish installing rig utility lines between jack up and rig sub. Finished installing flow line. Total Safety 75% complete on gas system installation.;Welders continue to weld knee braces on shaker landings and secure shaker landing to shaker tank. Weld mud return transfer pump base to deck skid rail. Blow air through 2" hard air line to ensure clear. Secure flaps on shaker tank roof.;Plumb drill water from platform to rig floor. Building hand rail for shaker tank. Install 60 mesh screens on Derrick shakers. Install rubber splash guard on possum belly. Install double 8" king nipple to join two 8" shaker dump lines. 8/10/2021 Lay out wire trays. Pick first bundle of wires from jackup side and lay out on wire trays on the Tyonek. Get 2nd bundle and lay out the same. Production electrician wiring shaker pits. Welders getting water cleaned up and welding down the service line stands.;Have scaffold builders building temporary walkways across service lines. Rig welder modifying piping for mud shipping manifold.;Weld down shakers to the shaker tray. Finish welding service line stands to the Tyonek deck. Lay out 100' electrical cable extension on the deck and prepare for installation. Band cable extensions to cable tray;Hoist cable tray and cables with both Tyonek cranes. Hang cable tray off cable house and attempt to connect cables - 3' too short. Lay down cables and cable tray. The M/V Sovereign offloaded 217 bbls of drill water to the Spartan.;Unload two freestanding sections of the HAK pipe rack from the M/V Sovereign. Masco Endeavour unloading freight to the Spartan. Set 1st section of HAK pipe rack on extension beams and square up. Weld first pass on the four support columns. Release crane. Layout electrical cables for reinstallation.;Move rig vac and hoses from inside HAK rack sub extension. Unload center HAK pipe rack section from the Masco Endeavour. Verify measurements on center section and perform layout for setting 2nd HAK pipe rack section.;Set 2nd HAK pipe rack section, square up on extension beams and tack weld 1" on all corners of the four support columns. Test fit center section of HAK pipe rack - good fit. Continue to layout electrical cables.;Masco Endeavour continued to unload freight, 226 bbls drill water & 156 bbls potable water.;Welded first pass on 2nd HAK pipe rack support columns. Started welding the cap on all HAK pipe rack support columns. 8/11/2021 Finish welding HAK pipe rack support columns. Weld center 10' HAK pipe rack deck to outer sections - 6" skip weld every 48" across both side of 48' deck. Pull 100' electrical line extensions and hook up in cable house.;Finish welding HAK pipe rack deck. Continue to pull 100' electrical line extensions and hook up in cable house. Mix 400 bbls of 9.5 ppg LSND mud as per mud man.;Hold pre-spud meeting with both rig crews, Tyonek personnel, service personnel and drilling engineer.;Modify and install beaverslide from the Steelhead on Spartan 151. Install walkway and stairs from HAK pipe rack deck to the sub. Install stairs from HAK rack to Tyonek deck. Install stairs from HAK rack to Tyonek mud room roof. Cut & grind old stanchions from HAK rack deck.;Connect 100' cable extension to Spartan 151 cables. Udelhoven welders swaps to days. Rig welder building walkway for rig floor stairs to HAK rack walkway.;Install shaker mud chute guards. Install cat walk on HAK pipe rack. Install discharge hose on secondary shaker pit pump to shaker pit manifold. Measure HAK deck hand rail pockets. Pickup extra equipment and materials from construction. Perform cleaning up Tyonek deck and substructure.;Install walkway from Tyonek fin fan building to rig BOP deck. 8/12/2021 Continue hooking up electrical cables to rig and testing same (all good except troubleshoot & repair a blower mtr and rotary table cable to short (sourcing cable and plug for an extension) / Continue installing walk ways, landings, stairs and hand rails / continue build 9.5# WBM system / Work;Boat cargo and take on water / UOSS welders finished supports of shaker landing and stairs from drill deck to HAK pip rack cleanup and pack up tools / with access to rig floor total safety and pason continued r/up of equipment / No crew change today do to possible COVID of hand of on coming crew;Complete Crew taking PCR test and quarantining at hotel. Total Safety run and tie in cables to rig floor, cellar, shaker pit and well head room - total installation 95% complete. Pason installation 55% complete.;Install stair walkways over cable trays for access and protection. Remove excess equipment and materials from the Tyonek and store on Spartan 151. Spot vac unit on mud room roof. Mobilize Hawk Jaw and drill pipe handling equipment to the rig floor. Set cable trays & plywood over cable trays on deck.;Install king nipple and flange on 8" overboard line. Hang overboard line from shaker cuttings chute. Move electrical bang board to clear walkway. Spot Hawk Jaw power unit and run lines to rig floor. Unload MV Sovereign freight to Tyonek deck. 8/13/2021 Flush HP mud line to platform shaker pit / wire in back up centrifugal transfer pump, Hawk jaw HPU and check rotation and power mud lab / Continue r/up total safety and pason equipment / fabricate walk way and steps for pump end of platform shaker tank;Work boat and take on water / chk all pressures on A- 04A = 30" x 16" = 7.5 psi / 16" x 10-3/4" = 28 psi / 10-3/4" x 7" = 11 psi 7" x 4-1/2" tbg = zero / Tbg zero w/ visual fluid level +-20' down / Install TWC / production welder on board start re-purpose used hand rails to fit Hak pipe rack;Stage 10k choke and kill assy in cellar / house clean work areas / continue build 2nd batch of 9.5# WBM / continue flushing lines and prep test HP mud line / continue work crew over and and short handed / finished building 400 bbls mud - 800 bbls total built.;Pressure test high pressure mud line, leak at 2000 PSI. Repair 2" Demco valve. Pressure test to 5000 PSI - good test. Fill shaker tank to Spartan mud pit return line hose - pin hole leak. Replace hose. Circulate from shaker tank back to mud pits with primary pump - good. Test secondary transfer pump;Pump worked correctly, but starter sticking. Electrician will troubleshoot starter. R/U 110' of 2" Yellow Jacket cement hard line in piping support stands on the Tyonek deck. Test seawater cooling lines, found minor leaks on feed line threaded connections. Tighten connections and circulate good.;Production welder continue to work on HAK pipe rack hand rails and pipe stanchions. Testing Total Safety gas alarms. Pason 85% complete in installation, calibration and training. Install 140 screens on mud cleaner #1. Mobilize wear bushing, running tool & blanking sub to the rig floor. 8/14/2021 Electricians work on start /stop station of back up platform shaker tank transfer pump / work boat of cargo and some drill pipe / production welders continue to re-purpose used hand rails to fit HAK pipe rack / test and cal total safety gas system and continue pason r/up;Nip/dn dry hole tree and store in well room / install 13-5/8" 5k riser with XO spool / start to install stairs and walk way from jack up pipe rack to top of platform weld shop / continue w/ handrails and station of HAK pipe rack / work on platform gai-tronic for rig / attempt stab stack;Annular interference with sub beams need about 2" to center up ( sub not centered with well ) attempt pull riser over no/go / r/up jacks and loosen clamps / rig up hydraulic unit ,/ cut welds for stairs to HAK deck / disconnect flow line dresser sleeve;Skid rotating sub 3" outboard on transverse skid rail to center annular in rotating sub beams. Transverse rig package 4" inboard to center rotary table over BOPs. Remove jacking cylinders, R/D hydraulic unit and re-install earthquake clamps. Reconnect flowline dresser sleeve.;Weld stairs back to HAK. Production welders continue to work on HAK rack handrails.;Tighten adapter flange and riser bolts in the wellbay. N/U BOP stack and tighten BOP to riser. Remove upper BOP stack from mud cross. Rotate mud cross 90°. Remove 5K to 10K DSAs from mud cross. Install rotating 90°s. Install longer studs on5K to 10K DSAs and dress flange bolt holes on DSA.;Install DSAs on rotating 90°s. Set BOP stack on mud cross and hammer up bolts. N/U choke and kill line assemblies. 8/15/2021 Continue N/U choke and kill line assemblies / Open doors and inspect door seals and rams 2-7/" x 5" vbr's in btm blinds middle & install 4-1/2" hard rams in top / Plumb in and hook up koomey lines / Electrician's working on platform gai-tronic to Rig floor, pipe rack & shakers run cat 5;Cable to mud lab / production welders continue with Hand rail install on HAK pipe rack / rig welder work on stairs and landing / Held muster and abandon platform drill w/ both Toynek platform and jack up and held debriefing and go over issues;Continue nip/up / continue hand rail, walkway and stairs install continue wiring in communications / calibrate pason / hook up koomey lines / clean cellar / Prep to function test bope and build test jt;M/U blanking sub, XO, five foot 4.5" pup joint, full 4.5" joint, fifteen foot 4.5" pup joint for test joint assembly. M/U pump in sub, FOSV #1, FOSV #2 and top drive to test joint. R/U test pump. Attempt shell test, lower pipe ram body blind flanges leaking - tighten bolts.;Pressure up again, choke valve #15 leaking - function valve. Pressure up again, grease fitting on choke valve #16 leaking - replace fitting. Pressure up again, packing gland leaking on tubing hanger - tighten gland nut.;Obtain 250 PSI low / 2500 PSI high body test against annular, choke valves #13, 14, 15 & FOSV #1. Obtain 250 PSI low / 4500 PSI high body test against 4-1/2" upper pipe rams, choke valves #13, 14, 15 & FOSV #1.;Perform preliminary BOP test. All test performed with fresh water, against a blanking sub installed in the 4.5" hanger with a 4.5" test joint. Test performed to 250 PSI low / 5000 PSI high and held for 5 min each.;1) Lower 2-7/8"x5" VBR on 4.5" test joint 2) Upper 4-1/2" pipe rams on 4.5" test joint, FOSV #1, manual choke & kill 3) Upper 4-1/2" pipe rams on 4.5" test joint, FOSV #2, HCR choke & kill 4) Upper 4-1/2" pipe rams on 4.5" test joint, lower IBOP, valves #1, 17 & 18 (fail/pass - tighten choke flange);5) Upper 4-1/2" pipe rams on 4.5" test joint, upper IBOP, valves #3, 4 & 7 6) Upper 4-1/2" pipe rams on 4.5" test joint, FOSV #1, valves 2, 6, 11, 8 & 16 BOP testing continues into next report period;Load and strap 189 joints of 4-1/2" drill pipe on the pipe rack. 8/16/2021 Continue and finish Pre-Bope test as per regulations 250L/5000H 5/5 notified state Mr Jim Regg of good pre-test / discussed timing of state witnessed with Inspector Adam Earl planned for 8-17 -21 @ 09:30 / to finish r/up and p/up DP;Work boat / Continue weld extensions on 22" flow nipple w/ production welders 3 welds / re-tigten bolts on complete stack / calibrated Sperry block Hight and installed sensor on stand pipe goose neck / enterprise working through issues with 2nd attempt w/ crew change;Install backstop on beaverslide. Install bails and 4-1/2" elevators. Install new saddle on beaversli de mounting plate. Change top drive grabber dies from 5" to 4-1/2". Install sheave at derrick board to position tugger to pickup drill pipe.;Pick up drill pipe, make up stands in the rotary table and rack back in the derrick. Torque 4-1/2" CDS40 pipe to 20,800 ft/lbs torque with Hawk Jaw. 114 joints / 38 stands total.;Perform accumulator drawdown pre- test. 3075 system pressure, 1650 after closure, 21 seconds 200 PSI recovery, 130 second full recovery.;Pick up drill pipe, make up stands in the rotary table and rack back in the derrick. Torque 4-1/2" CDS40 pipe to 20,800 ft/lbs torque with Hawk Jaw. 123 joints / 41 stands total. 8/17/2021 P/up and install flow nipple / production welders working on re-install of back landing of south crane to a bolt on connection / Install 4-1/2" test jt / Adem Earl w/ AOGCC on board / orientation and tour of rig and fluid flow paths / test gas alarms / start testing BOPE;Test pump unable to get above 4950 psi with out pop- off bypassing re-plum pop-off / Continue testing Bopes as per regulations 250L/5000H 5/5. Perform accumulator draw down. Test Kelly hose & swivel packing to 4000 psi 250 5 min. Attempt high test swivel packing leaking.;Draw down- 3100 PSI Start, 1800 psi after shut in, 200 PSI increase 19 sec, Full charge 115 sec. 16 BTLS @ 2400 psi.;Change valve and gauge on test pump. Service swivel packing. Retest Kelley hose and swivel packing. Good. Break down TIW, Dart & L/D same. Back out test Joint. Test blinds to 250/ 5000 psi 5 min X 5 min. Good. RIH with Test joint & M/U same. Function BOPs from remote station. Good.;R/U to Pull hanger with 4 1/2 DP. M/U TD. PJSM, BOLD. Pull hanger free.;POOH L/D Pups & DP. L/D hanger and break out running tools. Pull 4 joints of IBT 4 1/2 tubing. Monitor for oil cap. Verified oil cap.;R/U line and 2'' pump from cellar to vac tote. R/U Pump and line from rig floor to pump off cap from well to vac tote. Lay out Dc. Strap tally and get FN. notified state Mr Jim Regg of good pre-test Adem Earl w/ p AOGCC on board / Pull 4 joints of IBT 4 1/2 tubing. gpg / Continue testing Bopes as per regulations 250L/5000H 8/18/2021 Continue skim dirty water w/ diesel sheen off top of well to cuttings box / R/up to pump from annulus to production injection tank to skim diesel sheen off top of well / Production welders continue retro fitting back landing of south crane landing to Bolt on connection / finish working boat;Finish laying out and strapping HWDP and collars / Rih set wear ring;RIH open end two std and Pump dirty sheen water from annulus t/ production / pump clean water dn dp and re fill stack test and sheen test fluid repeat this 4 times w/ total 75 bbls pump and two passing sheen test / welders and elections continue repairs on south crane;Secure stack / remove catch tank from jack up for catch tank for rig floor drains / continue run 1502 cmt line to SLB unit / rig welder repairing hand rails on 151 sub / Production electricians hooking up transformer on south crane .;Production electricians continue hooking up transformer on south crane & Test same. Good. Spot rig floor drain tank and hook up lines. Transfer skimmer water from vac tote to production header. 12 bbl.;R/U lines and pump in wellhead room to suck out stack. Put away transfer lines and store.;PJSM, with production crane crew and drill crew. P/U WIS full gauge window mills as per WIS. 6 1/8 OD mills. M/U bit sub, 9- 4 3/4 DC & 21 4 1/2 HWDP T/ 930'. Take returns to TT.P/U 4.5 DP & RIH with clean out BHA to 2878'. 63 joints. RIH with stands from derrick to 3985'.;PJSM for first circulation and fluid transfer. Walk down lines and system with crew. Break circ and stage up pumps to 5 BPM at 300 psi with drill water. Test transfer from transfer pits to rig pits. Good. 8/19/2021 Continue circ at 5 BPM at 300 psi with drill water. Total 100 bbls circ around / dn pumps and flow chk (ok);Pooh w/ proper hole fill chk mills (ok) l/dn same;PJSM p/up sperry MWD and test same (ok) / p/up WBI 7" track master whip stock assy w/ expandable anchor Bha #2 / Rih slow w/ collars;Continue Rih slow w/ hwdp and DP t/2769';Fill pipe w/ drill water;Continue rih t/ 2829.52' btm of whip stock / Kelly up and pressure cycle #1 shoot tool face @ 128L Orentate to 153L. Work pipe and verify 153L. Perform 5 cycles on depth. TOW at 2810'. 300 GPM 1050 PSi. UP/DN 108/102;Perform the 6th cycle and saw pressure increasing to 3200 psi. Hold pressure while shutting in stand pipe. Set down to 85K. P/U to 125 twice. Set down to 75K and saw bolt shear. P/U and saw 5K over pull and pressure drop. P/U 5'. Open stand pipe and ROT at 60 RPM 175 GPM. Rot down at 2200 psi.;Saw pressure drop from 2500 si to 1050 psi when plug drilled up. P/U 5' above TOW. to 2805'. Prep for displacement and mud treatment.;Displace to 9.5 PPG 6% KCL mud. Cut mud back to 2% KCL with water and bring wt and properties back to 9.5 PPG. 260 GPM, 1527 psi. Current MW in and out 9.+. 8/20/2021 Continue circ and weight up system and properties back spec. 260 GPM, 1527 psi. Current MW in and out 9.3 PPG;Held platform/ Jack up joint drill / platform high gas alarm that turned into abandon Platform / drill crew dn pump and secured well and mustered @ there safe briefing area along with Jack up / then went to bucker and head count (had one drill hand went to wrong platform brucker );Chk pressure open well / Resume circ and weight up system and properties back spec. 260 GPM, 1527 psi. Current MW in and out 9.4+ PPG;Shut down finish hit list before window milling. Change bleeder needle valve on accumulator, Install fire water line to Sparten 151 from platform fire water. Test. Good. Prep shakers for mill cuttings.;Establish milling permeators. Take slow pump rates with #1 & #3 pump. #1 @ 20/30/40 110, 182, 284psi. #2 20/30/40 112/180/281 psi. Choke panel has 15K Gauges. Take readings from Totco.;Mill window ast 80 RPM, 3-5 K TQ, 200 GPm, 942 PSI. F/ 2810' T/ 2820'. 62# Metal back. MW 9.5 in and out. 44 vis.;Drill 20' New hole F/ 2820' T/ 2840'. 200 GPM, 1028 PSi 80 RPM, 6K TQ WOB 0-3;Ream through window at 100 RPM three times & Slid through to btm twice. Good. Pump 25 bbl HV sweep around.;Monitor well, 10 Min. R/U for FIT to 12 PPG. Perform FIT to 12.1 PPG, Monitored pressure for 10 Min. Good FIT. Bleed off pressure & R/D testing equipment. Prep for TOOH.;POOH F/ 2805' T/ 1396'. pp Perform FIT to 12.1 PPG, ;Drill 20' New hole F/ 2820' T/ 2840'MW 9.5 in and out. pp ;Mill window ast pp @ p 80 RPM, 3-5 K TQ, 200 GPm, 942 PSI. F/ 2810' T/ 2820' Good FIT. From:McLellan, Bryan J (OGC) To:Karson Kozub - (C) Cc:Juanita Lovett; Katherine O"connor Subject:RE: NCIU A-04 (PTD 169-018) P&A and sidetrack prep Date:Friday, June 4, 2021 5:54:00 PM Karson You are good to go with the plan below. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Friday, June 4, 2021 1:03 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Katherine O'connor <Katherine.Oconnor@hilcorp.com> Subject: NCIU A-04 (PTD 169-018) P&A and sidetrack prep Bryan, Per our phone conversation on step 9 of the sundry we are not able to inject into the formation through our EZS. We will not be able to perform the hesitation squeeze outlined in step 10. Our new plan will be to place 10 BBL (~254’) of cement on top of the EZSZ for zone abandonment. TOC will be +/-4,186’ after cement is pumped. We will then continue with sundry 321-155 step 12. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:Karson Kozub - (C) To:McLellan, Bryan J (OGC); Regg, James B (OGC) Cc:Rick Brumley - (C); Wade Hudgens - (C); Juanita Lovett; Harold Soule - (C) Subject:NCIU A-04 (PTD 169-018) Sundry P&A and Sidetrack Prep Date:Wednesday, June 2, 2021 8:39:51 AM Attachments:NCIU A-04 Wellhead Diagram 2020-06-02 Proposed Rolling BOPE test.pdf NCIU A-04 Wellhead Diagram 2020-03-09 Current.pdf All, We are currently BOPE testing on NCIU A-04 (PTD 169-018) Sundry (321-155). We are unable to get a BOPE test due to a leaking hanger. We will proceed with a rolling BOPE test as outlined in the sundry. The gentlemen on the rig contacted Mr. Regg this morning to notify him of the change to a rolling BOPE test. We will send the rolling BOPE test charts in when completed. We installed an adapter for a new tubing hanger (see proposed and current wellhead diagrams attached). This will allow us to place a test plug in the new adapter to test the BOPE against, then only one rolling test will be needed to test the flange where the adapter mates to the old wellhead. The remainder of the BOPE components will be tested per the standard procedure. The steps will be a follows: 1. Test the choke manifold with the BOPE out of the test path 2. Do a rolling test on the old tubing hanger with 3-1/2” test joint 3. Pull 3 ½” test joint and blanking sub. 4. Run new tubing hanger test plug in our adapter and test fully BOPE (non-rolling) on both 3 ½” and 4 ½”. 5. Unseat hanger, POOH and lay down +-3 joints of completion tubing. 6. RIH with storm packer to +-80’. 7. Test original tubing hanger and new adapter with 3 ½”. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com 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 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. Current Wellhead 3/04/2020 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'’ LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'’ Starting head, OCT, 30 ½ 1M X 28'’ BW, w/ 2- 4'’ 1M EFO Tbg hanger, FMC-UH-A-EN, 6'’ X 4 ½ EUE 8rd lift and 4 ½ IBT susp, w/ 4'’ Type IS BPV profile, 1- ¼ non cont control line port Hanger is nested in pack-off and held down by lock plate Lock-plate needs to be removed before nipple up of BOPE Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 4 1/2 Tree assy, 4 1/16 3M Adapter, 16 ¾ 5M clamp hub x 4 1/16 3M stdd top, prepped f/ 1- non cont control line port 16'’ 10 ¾’’ 7'’ 4 ½’’ David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address: 3800 Centerpoint Drive, Suite 1400 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): North Cook Inlet Field / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD): Junk (MD): 7,656'4,685' Casing Collapse Structural Conductor 630 psi Surface 2,090 psi Intermediate Production 3,270 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 Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 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 See schematic 12.6 / J-55 N Cook Inlet Unit A-04 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size Hilcorp Alaska, LLC N/A Other: PB for Sidetrack COMMISSION USE ONLY Authorized Name: 3,580 psi2,264' 576' 2,410' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-018 50-883-20023-00-00Anchorage, AK 99503 390' 576' TVD Burst 4,448' 4,360 psi Tubing Size: MD 1,640 psi 7,618' Perforation Depth MD (ft): 7,618' 390'390' 30" 16" 10-3/4" 576' Perforation Depth TVD (ft): 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. 4/15/2021 4-1/2" Daniel E. Marlowe See Schematic 4,520 - 4,690 6,412' 4,685' 4,083' See Schematic Tubing Grade:Tubing MD (ft): 3,904 - 4,048 1,380 psi 6,391'7" 2,410' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:03 pm, Mar 30, 2021 321-155 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.03.30 14:13:52 -08'00' Dan Marlowe (1267) SFD 4/1/2021 DLB6,421' See changes in main procedure and BOP test procedure. BOP test pressure 2500 psi. BJM 4/13/21 10-407 DLB 03/30/2021 X DSR 3/30/21 X Comm. Required? Yes 4/13/21 dts 4/13/2021 JLC 4/13/2021 RBDMS HEW 4/13/2021 Well Work Prognosis Well Name:NCIU A-04 API Number: 50-883-20023-00 Current Status:Producer –Shut in Leg:Leg #3 SE Corner Estimated Start Date:4/15/2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-018 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure: 1,794 psi @ 4,143’ TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,794 psi @ 4,143’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,380psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-04 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. The well was first worked over in 1994, during which time a partial collapse of the 7” casing was identified at 5,184’ MD. A cement plug was placed at 5130’ MD and a cast iron bridge plug was set at 4,828’ MD during this workover to isolate the lower part of the wellbore and produce the upper Cook Inlet Sands. In 2007 the existing completion was pulled and a gravel pack completion was installed to produce the Cook Inlet 1, 2, 3, and 4 sands. Water breakthrough occurred in 2017 and the well was shut in. In 2020 cement was bullheaded through the gravel in an attempt to isolate the water breakthrough and was unsuccessful at shutting off the water. The work proposed will isolate the current wellbore and set up for a sidetrack. Last Casing Test: Tested IA 1/15/2008 to 2,400 psi @ 4,447’ (new test to be performed in Step #13 below) Wellbore Notes: x Inflatable packer left in well @ 4,685’FT on 08/03/2020 Procedure: 1. RU Slickline pressure test lubricator to 250psi low/1,500psi high a. Pull SSSV b. Open sliding sleeve at 4,455’ i. Contingent tubing punch at ±4,452’ c. Set plug in X-nipple at 4,425’ i. Pressure test tubing with gas lift to ~500 psi for 15 minutes (plug test) d. Pull GLV at ±4,412’ for circulation, RD Slickline e. Fluid pack well and pressure test to 1,500psi for 30min charted f. Pull plug in X-nipple at 4,425’ g. RD Slickline 2. MIRU HAK 404 3. Circulate well with brine 4. Test BOP’s to 250psi low/2,500psi high /2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. Workover fluid will be brine. BOP’s will be closed as needed to circulate the well. 6. Pull upper completion fishing tubing and cleaning out as needed to ±4,447’. 7. RIH and set EZSV ±4,415’. POOH and RD E-Line 8. RIH, sting into EZSV. 9. Conduct injectivity test. 10. Perform Hesitation Squeeze with ±20 BBL of cement through EZSV. 3.a Install BPV 3.b ND Tree 3.c NU BOP 3.d Pull BPV, Set TWC 4. Test BOP 4.a Pull TWC 4.b Circ KWF The work proposed will isolate the current wellbore and set up for a sidetrack. Well Work Prognosis 11. Un-sting from EZSV and place 25ft (~1 BBL)of cement on top of EZSV x Depending upon squeeze. Can place up to 16 BBL on top of retainer. Note: Max TOC is 4,000Ft for a 3,750’ whipstock x Circulate clean. POOH. 12. Wait on cement, RIH and tag TOC 13. Test IA to 1,500 psi and chart for 30 minutes. 14. Land hanger with bottom of tubing at ±120’. 15. ND BOPE and NU wellhead, test same. 16. RD HAK 404 and move off location 17. Suspended operations until drilling rig moves on location ***Remaining Procedure to be included on the Permit to Drill for the sidetrack*** Phase II General sequence of operations pertaining to drilling procedure: (informational only) 1. Resume operations with drilling rig. 2. MIRU drilling rig. 3. Monitor well to ensure it is static. 4. ND Wellhead, NU BOP and test to 250psi low/3,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. PU Sidetrack BHA and RIH to TOC. 6. Swap well to drilling fluid. 7. Kick off cement plug into new formation. 8. Drill per directional plan. 9. Run/Cement/ and cleanout 4.5” casing. 10.Swap to completion sundry. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic 4. BOP Drawing – HAK 404 5. Fluid Flow Diagrams –HAK 404 6. Rolling BOP Test Procedure 7. Sundry Revision Change Form NU and test tree. Ensure IA test pressure is greater than MPSP, 721 psi, for drilling ops. bjm Place minimum of 75 ft of cement on top of EZSV - bjm. _____________________________________________________________________________________ Updated By: JLL 08/24/20 SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 TD: 7,656‘MD TVD: 6,412’ 16” RKB to TBG Head – 64.4’ 7” 2 3 4 5 6 78 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 130” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 X X TOC 4,690’ CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 BTC-M 3.958” 64.4’ 4,447.9’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 290’ 290’ 3.813” NIPPLE, 4.5” XXO SVLN 3.813” HES FXE WRDP ON X-Lock (5/16/13 Install) 2 1,409.8’ 1,399.4’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 860 psi (1/27/08 run date) 3 2,579.9’ 2,394.3’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 910 psi (1/27/08 run date) 4 3,655.3’ 3,226.8’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 900 psi (1/27/08 run date) 5 4,412.0’ 3,817.9’ GLM, 1” OV, CAMCO KBG-2-1R, BK LATCH, 0.313” PORT, 0 psi (1/27/08 run date) 6 4,425.7’ 3,828.8’ 3.813” NIPPLE, 4.5” HES X landing nipple 7 4,433.7’ 3,835.2’ 3.992” PBR, Baker 80-40 w/ 3.5” EUE 8 4,447.1’ 3,845.9’ 2.992” SEAL ASSY, Baker 80-40 “K” Anchor assembly 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) Fish: 4,685’ Cement Sqz Packer 08/03/2020 SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 __________________ Updated By: JLL 08/24/20 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,620’ 4,690’ 3,984.9’ 4,048.9’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,690’ 4,700’ 4,042’ 4,050’ 10’ 08/03/2020 Isolated CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 08/03/2020 Isolated CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 08/03/2020 Isolated CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Base of perf interval is 4690'. Cement volume sufficient to fill wellbore 100' below base perf to EZSV = 15 bbls cement assuming no tbg or gravel pack in the well. 4,690’ _____________________________________________________________________________________ Updated By: KDK 03/25/21 PROPOSED Tyonek Platform Well: NCI A-04 Last Completed: Future PTD: 169-018 API: 50-883-20023-00 TD: 7,656 ‘MD TVD:6,412’ 16” RKB to TBG Head – 64.4’ 7” 8 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 30” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 TOC ±4,390’ Inflatable packer left @ 4,685’ RKB. (08/03/20) TOC 7” 2,600Ft CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 IBT-M Surf ±120’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item ±120’ ±120’ Kill String 8 ±4,390’ ±3,800’ Top of cement plug ±4,415’ ±3,820’ 6.366” Plug EZSV Cement retainer 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) PROPOSED Tyonek Platform Well: NCI A-04 Last Completed: Future PTD: 169-018 API: 50-883-20023-00 __________________ Updated By: KDK 03/25/21 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 8/22/1994 Isolate CI-2.0 4,620’ 4,690’ 3,984.9’ 4,048.9’ 80’ 8/22/1994 Isolate CI-2.0 4,690’ 4,700’ 4,042’ 4,050’ 10’ 08/03/2020 Isolated CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 08/03/2020 Isolated CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 08/03/2020 Isolated CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Current Wellhead 3/04/2020 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tbg hanger, FMC-UH-A-EN, 6'͛X 4 ½ EUE 8rd lift and 4 ½ IBT susp, w/ 4'͛Type IS BPV profile, 1- ¼ non cont control line port Hanger is nested in pack-off and held down by lock plate Lock-plate needs to be removed before nipple up of BOPE Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 4 1/2 Tree assy, 4 1/16 3M Adapter, 16 ¾ 5M clamp hub x 4 1/16 3M stdd top, prepped f/ 1- non cont control line port 16'͛ 10 ¾͛͛ 7'͛ 4 ½͛͛ Proposed Wellhead 03/04/2020 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tubing hanger, Cactus-EN- CCL, 11 x 3 ½ EUE 8rd lift and susp, w/ 3'͛type H BPV, 2- ¼ cont control line ports Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 3 1/2 16'͛ 10 ¾͛͛ 7'͛ 3 ½͛͛ Tubing head attachment, Cactus, 11 5M FE X 16 3/4 5M BX-161 hub bottom Valve, Master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim BHTA, Bowen, 3 1/8 5M FE x 2.5 bowen quick union top Adapter, Cactus-EN-CCL, 11 5M stdd x 3 1/8 5M, w/ 2- 1'͛npt control line exits Valve, Master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim Valve, Swab, CIW-FLS, 3 1/8 5M FE, HWO, EE trim Superseded BOP Stack Rig 404 Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) OPumpManifold3(PM3) CPumpManifold4(PM4) OPumpManifold5(PM5) CMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve OMissing Choke Bypassline.Panic Line goes straight up.Asked them to route it in asafe direction.Hilcorp is putting together a properchoke skid. Waiting on as-builtdrawing. Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) CPumpManifold3(PM3) OPumpManifold4(PM4) CPumpManifold5(PM5) OMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve OSee updated choke diagrams. Waiting on as-builtwith bypass line. BJM Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. x Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Bryan McLellan (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) Set a plug in the tubing before ND tree with no BPV. - bjm Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold, close valves 1, 2, 10 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross, open 1st valve of standpipe, close valves 3, 4 & 9 on choke manifold, open valves 1 & 2 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve / open outside valve on kill side of mud cross, close valves 5 & 6 / open valves 3 & 4 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke / open valves 5 & 6 on choke manifold. Pressure up to ~ 1200 psi and bleed off 200 – 300 #s recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. f) Close HCR (outside valve on choke side of mud cross), open manual & super choke. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close inside valve / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold, close valve 7 & 8 / open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-04 (PTD 169-018)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date Proposed Wellhead 04/01/2021 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'’ LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'’ Starting head, OCT, 30 ½ 1M X 28'’ BW, w/ 2- 4'’ 1M EFO Tubing hanger, Cactus-EN- CCL, 11 x 4 ½ EUE 8rd lift and susp, w/ 4'’ type H BPV, 2- ¼ cont control line ports Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 4 1/2 16'’ 10 ¾’’ 7'’ 4 ½’’ Tubing head attachment, Cactus, 11 5M FE X 16 3/4 5M BX-161 hub bottom Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim BHTA, Otis, 4 1/16 5M FE x 7.5 Otis quick union top Adapter, Cactus-EN-CCL, 11 5M stdd x 4 1/16 5M, w/ 2- 1'’ npt control line exits Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Valve, Swab, CIW-FLS, 4 1/16 5M FE, HWO, EE trim 1MBOOFEEJBHSBN"T CVJMUXJMMCFTFOUCFGPSF PQFSBUJPOCFHJOTCKN 1MBOOFEEJBHSBN"TCVJMUXJMMCFTFOUCFGPSFPQFSBUJPOCFHJOTCKN 1 Guhl, Meredith D (CED) From:Karson Kozub - (C) <kkozub@hilcorp.com> Sent:Tuesday, April 13, 2021 11:27 AM To:McLellan, Bryan J (CED) Cc:Juanita Lovett Subject:RE: [EXTERNAL] NCIU A-04 (PTD 169-018) Sundry questions Attachments:Choke Manifold(2).pdf; Choke manifold.JPG Bryan, Attachedisapictureandadrawingofthechokeweplantouse.Dependingonhowtheinspectionandtestinggoafew thingsmaychange.IwillsendoveranasͲbuiltwhenwehaveit. PleasenotetheSuperchokeandmanualchokeareindifferentlocationsonthedrawingandpicture.Itwillbeupdated oncewehaveourchokecomplete. I’mgladyouaregettingavacationin.DoyouhaveacontactattheAOGCCforwhenyouwillbegone?Idon’tanticipate needinganythingbutwewillberunningthe404rigandthingsmaycomeupdependingonhowthewellworkgoes. Regards, KarsonKozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,April13,20219:14AM To:KarsonKozubͲ(C)<kkozub@hilcorp.com> Cc:JuanitaLovett<jlovett@hilcorp.com> Subject:RE:[EXTERNAL]NCIUAͲ04(PTD169Ͳ018)Sundryquestions Thanksforfollowingup,Karson. IfyousendmeadrawingofyourplannedChokeskiddesign,IwillattachittotheSundryandapproveitbeforeIleave forvacationthisThursday.ThensendtheasͲbuiltwhenyouhaveit. IfyouarenotinahurrytogettheSundryapproved,thenwecanwaituntilthechokeskidiscompleteandyousendme anasͲbuilt. Bryan BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:KarsonKozubͲ(C)<kkozub@hilcorp.com> Sent:Monday,April12,202112:07PM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> 2 Cc:JuanitaLovett<jlovett@hilcorp.com> Subject:RE:[EXTERNAL]NCIUAͲ04(PTD169Ͳ018)Sundryquestions Bryan, Thankyoufortakingmycallthismorning.Wewillbechangingthechokeskidandusingthechokefromthe301.This willtakeafewweekstogetthechokegonethroughandcheckedout.OnceIhaveanupdateddrawingIwillpassityour direction. Onthechokepaniclineweplacethechokehouseinthebestpossiblelocationtoensureitisnotnearignitionsources anditwouldnotendangerpersonnelifitisused. Forthecasingpressuretest.Thehighestreservoirpressureexpectedis1213psiintheBelugaEsand(4919'TVDss). MASPis721psiwith0.1psi/ftgasinthewellbore. Regards, KarsonKozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com From:KarsonKozubͲ(C) Sent:Thursday,April8,20215:24PM To:'McLellan,BryanJ(CED)'<bryan.mclellan@alaska.gov> Cc:JuanitaLovett<jlovett@hilcorp.com> Subject:RE:[EXTERNAL]NCIUAͲ04(PTD169Ͳ018)Sundryquestions HelloBryan, Iwillsendoverachokeskiddrawinghopefullytomorrow,ouremployeewhodrawsthemishookedupoffshore currently.Thepaniclineofthechokeskidcomesoutthetopandispointedstraightup. Youarecorrectontheproposedwellheaddiagramhavingtheincorrecthanger.Attachedisanupdatedwellhead drawingforthe4.5”tubing. ThedrillingguysareworkingontheirMASPIwillupdatethatwhentheyhavetheGeoprogdialedin. MybestguessforastartdateondrillingisJuly18th.TheSpartan151willbecompletingaP&Afirst,ourschedulewill shiftdependinghowtheP&Agoes. Regards, KarsonKozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com From:McLellan,BryanJ(CED)[mailto:bryan.mclellan@alaska.gov] Sent:Thursday,April8,202112:41PM To:KarsonKozubͲ(C)<kkozub@hilcorp.com> Subject:[EXTERNAL]NCIUAͲ04(PTD169Ͳ018)Sundryquestions HiKarson 3 I’mreviewingyourNCIUAͲ04Sundryapplicationforpluggingandpullingtubingandhaveacouplequestions. 1. Doyouhaveachokeskiddiagramyoucansend?Thefluidflowdiagramisn’tdetailedenough. 2. WhereisthePaniclinedirectedontheFluidflowdiagram. 3. Whattubingsizedoyouplantorun.TheproposedWellborediagramandproposedWellheaddiagramshow differenttubingsizes. Thankyou 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. 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. Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 09/24/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCIU A-04 (169-018) GASSAT3D ANALYSIS with TMD3D 03/01/2020 ANALYSIS FIELD DATA Please include current contact information if different from above. Received by the AOGCC 09/25/2020 PTD: 1690180 E-Set: 33986 Abby Bell 09/25/2020 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: CT w/N2 Operations 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 7,656 feet See schematic feet true vertical 6,412 feet 4,685 feet Effective Depth measured 4,685 feet See schematic feet true vertical 4,038 feet See schematic feet Perforation depth Measured depth 4,520 - 4,690 feet True Vertical depth 3,904 - 4,042 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / J-55 4,448 MD 3,847 TVD Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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: Authorized Title: Contact Email: Contact Phone: TVD 390 measured true vertical Packer 7" 30" 7,618 MD 390 576 2,410 measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 700 Casing Pressure STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 169-018 50-883-20023-00-00 Plugs ADL0017589 N Cook Inlet Unit A-04 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-297 324 Authorized Signature with date: Authorized Name: 0 WINJ WAG 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 86 N/A Oil-Bbl 0 Water-Bbl Intermediate N/A Junk 5. Permit to Drill Number: 78 North Cook Inlet Unit / Tertiary Gas PoolN/A measured 7,618 Size 432 Production Casing Structural Liner Length 390 576 2,140 Conductor Surface 3,270psi 16" 10-3/4" 907 777-8384 4,360psi 576 2,264 6,391 Collapse 630psi Karson Kozub kkozub@hilcorp.com Tubing Pressure 2,090psi 1,640psi 3,580psi Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 2:33 pm, Aug 26, 2020 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2020.08.26 14:18:47 -08'00' Dan Marlowe (1267) CT w/N2 Operations RBDMS HEW 8/27/2020 DSR-8/27/2020gls 9/21/20 SFD 8/28/2020 _____________________________________________________________________________________ Updated By: JLL 08/24/20 SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 TD: 7,656‘MD TVD: 6,412’ 16” RKB to TBG Head – 64.4’ 7” 2 3 4 5 6 78 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 130” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 X X TOC 4,690’ CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 BTC-M 3.958” 64.4’ 4,447.9’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 290’ 290’ 3.813” NIPPLE, 4.5” XXO SVLN 3.813” HES FXE WRDP ON X-Lock (5/16/13 Install) 2 1,409.8’ 1,399.4’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 860 psi (1/27/08 run date) 3 2,579.9’ 2,394.3’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 910 psi (1/27/08 run date) 4 3,655.3’ 3,226.8’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 900 psi (1/27/08 run date) 5 4,412.0’ 3,817.9’ GLM, 1” OV, CAMCO KBG-2-1R, BK LATCH, 0.313” PORT, 0 psi (1/27/08 run date) 6 4,425.7’ 3,828.8’ 3.813” NIPPLE, 4.5” HES X landing nipple 7 4,433.7’ 3,835.2’ 3.992” PBR, Baker 80-40 w/ 3.5” EUE 8 4,447.1’ 3,845.9’ 2.992” SEAL ASSY, Baker 80-40 “K” Anchor assembly 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) Fish: 4,685’ Cement Sqz Packer 08/03/20204,685’Cement Sqz Packer 08/03/2020 sqz packer SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 __________________ Updated By: JLL 08/24/20 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,620’ 4,690’ 3,984.9’ 4,048.9’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,690’ 4,700’ 4,042’ 4,050’ 10’ 08/03/2020 Isolated CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 08/03/2020 Isolated CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 08/03/2020 Isolated CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf ISO perfs. -2.0 4,690’4,700’4,042’4,050’10’08/03/2020 Isolated CI-3.0 4,732’4,742’4,075.3’4083.5’10’08/03/2020 Isolated CI-4.0 4,764'4,814’4,101.7’4,142.8’50’08/03/2020 Isolated Rig Start Date End Date CTU / Slickline 7/31/20 8/5/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit A-04 50-883-20023-00-00 169-018 07/31/20 - Friday SL crews arrive platform. PJSM & permits. RU SLU. PT WLV & Lub = 1500. RIH w/ 3" DD Bailer to 4453' KB tag. Work tool, sticky. POOH. Metal marks on bailer sides appear to be from wedging. RBIH w/ 2.85" G ring to 4480' KB tag, work tool & fall to 4500'. Unable to pass 4500'. POOH. Deep metal marks on face of 2.85" G ring. RBIH w/ 2" DD bailer to 4720' KB w/o resistance. POOH w/ bailer full of mud. RBIH w/ 2.30" G Ring to 4480' KB, work tool & fall to 4500' KB. Work tool & fall to 4720' KB. OOH w/ slight metal marks on G ring. RBIH w/ 2.33" swedge to 4720' KB, no resistance. POOH. RBIH w/ 2.70" Blind Box to 4500' KB set down, work tool & fall to 4720' KB. POOH. RBIH w/ 2.80" swedge to 4720" KB w/o resistance. POOH. Platform Gas, Fire & Abandon Platform Drill. RIH w/ 3" swedge to 4453' kb tag. Work tools & get detained in place. 4 jar licks to pull free. POOH. RBIH w/ 4-1/2" AD-2 Stop, w/o slips, & 3.75" G ring to 3591' KB tag. Unable to pass. POOH. RBIH w/ 4- 1/2" Daniels KOT w/ JK RT & 1" Oriface Valve (Camco KBG-2-1R, BK LATCH< 0.3125 PORT, 0 psi)) to 4437' KB (SLM). Work tools & set valve @ 4412' RKB GLM. All SLM WSR reco rded KB depths appear to be 25' deep. RD SLU. Fly crew to beach. Job in Progress No operations to report 08/01/20 - Saturday PJSM & permits. Test BOPE as per Hilcorp & AOGCC requirements, witnessed waived 8/01/2020 by AOGCC Inspections Supervisor Jim Regg, 250/3000. Make up cc, pull tes t 35k, Pt, Low 250, High 3500. Stab on well, PT lubricator. Blow reel down per TAM International tool rep with N2 before running in hole. Pop of well, make up ICR. Stab back on well. PT Low/High 250/2500. Stabbed on wel l, WHP 50, IA 75, OA 35. RIH, WT CK 4650'= 6K. lightly tag Bullnose at 4700' for depth correction. PU to strin g wt plus 5'= 4685'. Launch .5" steel ball. WHP 52, IA 75, OA 35. Ball on seat @ 29 bbls away. Pressure up 500 psi, Hold for 5 min, bring up to 1,000 psi to inflate and set packer. Stack 8k down to confirm packer is set. Do inje ction test 1bpm for 10 min, CTP 1,000 psi, WHP 52, IA 75, OA 35. Batch up 15.8 ppg Cement. Come online with 5 bbls D/W ahead followed by 6 bbls 15.8ppg cement followed by 5 bbls D/W. HES offline. Displace cement with produced water at .75 bpm, CTP 1750, WHP 25, IA 75, OA 35. At 2 bbls Cement out of coil, CTP increased to 2750 then broke back to 550, kept pumping at .75 bpm, 3 bbls away CTP came back up to 2450 psi an d broke back to 1000 psi. Squeeze final bbl of cement at 1,000 psi, total bbls of cement squeezed was 6 bbls, 15.8 ppg. PU hole 5K over string wt to release packer, packer does not release, continue pulling up hole to 36k, 29k over string wt. Weight falls back to 6k string wt. Continue POOH. No overpulls or additional drag observed while continuing out of hole. Popped off well. Squeeze packer left in hole. SDFN, secure drill deck. Job in progress. 08/02/20 - Sunday No operations to report 08/03/20 - Monday CTU Squeeze packer left in hole. 0 psi, Hold for 5 min, bring up to 1,000 psi to inflate and set packer. Stack 8k down to c packer does not release, RBIH w/ 4-1/2" AD-2 Stop, w/o slips, & 3.75" G ring to 3591' K B tag. . Do injection test 1bpm for 10 min, CTP 1,000 psi, WHPconfirm packer is set. 52, IA 75, OA 35. Batch up 15.8 ppg Cement. total bbls of cement squeezed was 6 bbls, 15.8 ppg. PU hole PU to string wt plus 5'= 4685'. Rig Start Date End Date CTU / Slickline 7/31/20 8/5/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit A-04 50-883-20023-00-00 169-018 08/05/20 - Wednesday PJSM & Permit. RDMO CTU. Fly CTU crew to beach. Job Complete. Attend morning ops meeting. Stand by for plan forward. Got the green light to rig coil up, go in for tag and possibly mill cement. Wait on Production change out for crane operator. Pu injector, 20' Lubricator make up tools. (CTC 2" X .23') ( DFCV 2.13" X 1.70') ( BI-DI JAR 2.13" X 5.18') ( TJ DISCONNECT 2.13" X 1.58') ( CIRC SUB 2.13" X 1.17') (TITAN STD PDM 2.13" X 11.60') ( JUNK MILL 2.80" X .96') TOL= 22.42'. Stab on well, Pt Lubricator and hardline, low/high 250/2500. Open well, swab 20, WHP 5, IA 330, OA 35. RIH, Tag at 4198', 4229', 4446', 4481',4492', no motor work just min rate through these spots. CRIH tag hard at 4609' bring pump rate up to 1.4 bpm. CTP 2350 psi, WHP 120, IA 320, OA 35. Mill down to 4660' C TMD. ROP was 4-8 fpm. Make wiper trip up to 4200'. Pump bottoms up (60 bbls produced water) before shuttin g pumps down. Shut pump down, RIH for dry tag. Tagged at 4690' RKB stacked down, PU wt 7k, PU Depth 4687' RKB. Wait on production to complete flowline to facility before bringing well online and trying to lift it. Drop .5" ball to open Circ sub. Blow reel and well dry, bring well online to production while pulling coil out of hole. Leave well online. Tagged up, swab shut, bleed down, blow down. Pop off well. Break tool string down. .5" ball recovered. SDCFN. Job in progress. 08/04/20 - Tuesday Mill down to 4660' CRIH tag hard at 4609' bring pump 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address: 3800 Centerpoint Drive, Suite 1400 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): North Cook Inlet Field / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD): Junk (MD): 7,656'N/A Casing Collapse Structural Conductor 630 psi Surface 2,090 psi Intermediate Production 3,270 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 Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 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 Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size See schematic Other: CT w/ N2 Operations COMMISSION USE ONLY Authorized Name: 3,580 psi2,264' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-018 50-883-20023-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N/A N Cook Inlet Unit A-04 12.6 / J-55 TVD Burst 4,448' 4,360 psi Tubing Size: MD 1,640 psi576' 2,410' 390'390' 30" 16" 10-3/4" 576' 390' 576' 2,410' 7,618' Perforation Depth MD (ft): 7,618' See Schematic Tubing Grade:Tubing MD (ft): 3,904 - 4,142 Perforation Depth TVD (ft): 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. 7/28/2020 4-1/2" Daniel E. Marlowe See Schematic 4,520 - 4,814 6,412' 4,700' 4,050' 1,380 psi 6,391'7" s Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Jody Colombie at 1:55 pm, Jul 23, 2020 320-297 Daniel Marlowe I am approving this document 2020.07.14 09:57:02 -08'00' Daniel Marlowe 10-404 BOP test to 3000 psig SFD 7/23/2020 X DSR-7/23/2020VTL 7/24/20 X Comm. 7/24/2020 dts 7/25/2020 JLC 7/24/2020 RBDMS HEW 7/24/2020 Well Work Prognosis Well Name:NCIU A-04 API Number: 50-883-20023-00 Current Status:Producer –Shut in Leg:Leg #3 SE Corner Estimated Start Date:7/28/2020 Rig:Coil Tubing Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-018 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (907) 214-7400 (M) Current Bottom Hole Pressure: 1,794 psi @ 4,143’ TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,794 psi @ 4,143’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,380psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-04 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. The well was first worked over in 1994, during which time a partial collapse of the 7” casing was identified at 5,184’ MD. A cement plug was placed at 5130’ MD and a cast iron bridge plug was set at 4,828’ MD during this workover to isolate the lower part of the wellbore and produce the upper Cook Inlet Sands. In 2007 the existing completion was pulled and a gravel pack completion was installed to produce the Cook Inlet 1, 2, 3, and 4 sands. Water breakthrough occurred in 2017 and the well was shut in. This work is proposed to isolate the Cook Inlet 3, and 4 sands by bull heading cement through the gravel pack. Then producing the Cook Inlet 1 and 2 sands through the existing completion. Safety Concerns: x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting methane and Nitrogen during this job) x Ensure all crews are aware of stop job authority (Review Standard Well Procedure – Nitrogen Operations) Wellbore Notes: x Slickline will remove the SSSV and perform drift runs x 3.70” gauge ring ran to ~4,410’ on 4/15/2020 x 3” bailer ran to ~4,715’ on 2/3/2020 Procedure: 1. MIRU Coil tubing unit x Perform BOPE pressure test 3,500psi/250psi (Note: Notify AOGCC 48hrs in advance to allow them to witness) x R/U and RIH to ±4,685’ x Establish injection rates i. Contingency of injection rates aren’t desirable ii. MIRU E-line. PT lubricator to 1,500psi/250 psi iii. RIH with tubing punches to ±4,700’, punch screens. Consult Engineer prior to punching screens iv. POOH, RD E-line x Set inflatable squeeze packer at ±4,685’ x Establish injection rates 2. R/U Cement unit x Pressure test cement lines 4500psi/250psi 3. Pump ±5 bbl 15.8# cement to isolate the CI 3&4 perforations TOC ±4,685’ VTL 7/24/203000psig Well Work Prognosis x Displace cement to inflatable squeeze packer with water x Deflate squeeze packer x Circulate as necessary until pipe is clean 4. POOH w/coil tubing x Wait on cement 5. RIH with coil tubing and nitrogen lift the well dry taking returns to the production header x POOH w/ coil tubing and R/D 6. Turn well over to production, Test flow well 7. R/U Slickline and set SSSV 8. Test SVS per regulations Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic 4. Coil Tubing BOP Drawing 5. Standard Well Procedure – Nitrogen Operations 6. Fluid Flow Diagrams 7. Coil Layout drawing 8. Sundry Revision Change Form _____________________________________________________________________________________ Page 1 of 2 Updated By: PJR 06/24/17 SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 TD: 7,656‘MD TVD:6,412’ 16” RKB to TBG Head – 64.4’ 7” 2 3 4 5 6 78 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 130” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 X X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 BTC-M 3.958” 64.4’ 4,447.9’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 290’ 290’ 3.813” NIPPLE, 4.5” XXO SVLN 3.813” HES FXE WRDP ON X-Lock (5/16/13 Install) 2 1,409.8’ 1,399.4’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 860 psi (1/27/08 run date) 3 2,579.9’ 2,394.3’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 910 psi (1/27/08 run date) 4 3,655.3’ 3,226.8’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 900 psi (1/27/08 run date) 5 4,412.0’ 3,817.9’ GLM, 1” OV, CAMCO KBG-2-1R, BK LATCH, 0.313” PORT, 0 psi (1/27/08 run date) 6 4,425.7’ 3,828.8’ 3.813” NIPPLE, 4.5” HES X landing nipple 7 4,433.7’ 3,835.2’ 3.992” PBR, Baker 80-40 w/ 3.5” EUE 8 4,447.1’ 3,845.9’ 2.992” SEAL ASSY, Baker 80-40 “K” Anchor assembly 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 __________________ Page 2 of 2 Updated By: PJR 06/24/17 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,620’ 4,700’ 3,984.9’ 4,048.9’ 80’ 8/22/1994 Open RPERF 12 spf CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 8/22/1994 Open RPERF 12 spf CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 8/22/1994 Open RPERF 12 spf CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf _____________________________________________________________________________________ Updated By: JLL 07/13/20 PROPOSED Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 TD: 7,656‘MD TVD:6,412’ 16” RKB to TBG Head – 64.4’ 7” 2 3 4 5 6 78 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 130” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 X X Est. TOC ±4,685’ Punch Screen ±4,700’ CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 BTC-M 3.958” 64.4’ 4,447.9’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 290’ 290’ 3.813” NIPPLE, 4.5” XXO SVLN 3.813” HES FXE WRDP ON X-Lock (5/16/13 Install) 2 1,409.8’ 1,399.4’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 860 psi (1/27/08 run date) 3 2,579.9’ 2,394.3’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 910 psi (1/27/08 run date) 4 3,655.3’ 3,226.8’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 900 psi (1/27/08 run date) 5 4,412.0’ 3,817.9’ GLM, 1” OV, CAMCO KBG-2-1R, BK LATCH, 0.313” PORT, 0 psi (1/27/08 run date) 6 4,425.7’ 3,828.8’ 3.813” NIPPLE, 4.5” HES X landing nipple 7 4,433.7’ 3,835.2’ 3.992” PBR, Baker 80-40 w/ 3.5” EUE 8 4,447.1’ 3,845.9’ 2.992” SEAL ASSY, Baker 80-40 “K” Anchor assembly 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) PROPOSED Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 __________________ Updated By: JLL 07/13/20 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,620’ 4,700’ 3,984.9’ 4,048.9’ 80’ 8/22/1994 Open RPERF 12 spf CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 8/22/1994 Isolate CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 8/22/1994 Isolate CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Current Wellhead 3/04/2020 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tbg hanger, FMC-UH-A-EN, 6'͛X 4 ½ EUE 8rd lift and 4 ½ IBT susp, w/ 4'͛Type IS BPV profile, 1- ¼ non cont control line port Hanger is nested in pack-off and held down by lock plate Lock-plate needs to be removed before nipple up of BOPE Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 4 1/2 Tree assy, 4 1/16 3M Adapter, 16 ¾ 5M clamp hub x 4 1/16 3M stdd top, prepped f/ 1- non cont control line port 16'͛ 10 ¾͛͛ 7'͛ 4 ½͛͛ Coiled Tubing BOP 07/13/2020 SWAB VALVE MASTER VALVE STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. HilcorpMonopod Rig 56Flow Diagram Fluids Pumped Fluids ReturnedValve Open Valve ClosedGate Valve Ball ValveButterfly Valve Lo Torq ValveAutomatic Choke Manual ChokePressure Gauge Knife ValveChoke LineP PIT SYSTEM SucƟon SHAKER SHAKER CHOKE MANIFOLDGAS BUSTER Panic LineC12 C13 C15 C14 C16 A B C4 C5 C6 C7 C2 C10 C9 C11 C8 C3 P C1 C 1110K PSI Fluid PumpNitrogen PumpCirc PSIInjector HeadHR-580GooseneckCT StringSuction Hose To Source Tank Coiled Tubing Treating Equipment Layout Dart CVNitrogen Tank2,000 Gallons ea.N2 Bleed StackChoke ManifoldReturn Line To TankSLB Flow Cross4.06"10K Quad BOPTreating Line Bleed Stack Dart CVCustomer ValveWH PSI4.06" 10K Riser From WH To DeckCO62 5K LubricatorTop Load StripperBackside CVPump CV1502 Treating Iron 2"1502 Flowback Iron 2" 1502 Nitrogen Iron 1.5" LP Suction Hoses 3"Plug Valve 2"x2"Check ValveLP ValvePressure SensorNote: Exact stack drawing and equipment layout with equipment dimensions will be provided following a site visitPump PSI Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-04 (PTD 169-018)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date From:Karson Kozub - (C) To:Loepp, Victoria T (CED) Cc:Juanita Lovett; Dan Marlowe Subject:N Cook Inlet Unit A-04 Date:Thursday, July 23, 2020 10:35:09 AM Attachments:10-403 N Cook Inlet Unit A-04 PTD 169-018 - 2020-07-13.pdf Victoria, On July 14th Hilcorp submitted the attached Application for Sundry Approvals to AOGCC. I had requested a 3,500 psi BOPE test but I need to change to a 3,000 psi BOPE test due to the well having a 3,000 psi tree installed on it. Please let me know if you would like a sundry revision change form submitted. Regards, Karson Kozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 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): North Cook Inlet Field / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,656'N/A Casing Collapse Structural Conductor 630 psi Surface 2,090 psi Intermediate Production 3,270 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 Contact Name: Contact Email:jkaiser@hilcorp.com Contact Phone: (907) 777-8393 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 6,412' 4,828' 4,154' 1,380 psi 6,391'7" 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. 5/1/2020 4-1/2" Daniel E. Marlowe See Schematic 4,520 - 4,814 7,618' See Schematic Tubing Grade:Tubing MD (ft): 3,904 - 4,142 Perforation Depth TVD (ft): 2,410' 7,618' Perforation Depth MD (ft): 576' 2,410' 390'390' 30" 16" 10-3/4" 576' N Cook Inlet Unit A-04 12.6 / J-55 TVD Burst 4,448' 4,360 psi Tubing Size: MD 1,640 psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-018 50-883-20023-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC CO 68 390' COMMISSION USE ONLY Authorized Name: 3,580 psi 576' 2,264' Other: G/L Completion Authorized Signature: Operations Manager Joe Kaiser PRESENT WELL CONDITION SUMMARY Length Size See schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Daniel Marlowe I am approving this document 2020.04.08 09:45:08 -08'00' Daniel Marlowe By Samantha Carlisle at 11:07 am, Apr 08, 2020 320-157 gls 4/10/20 DSR-4/8/2020 X * 2500 psi BOPE test * Alternate placement of SSV approved per 20 AAC 25.265(o)(1) 10-404 DLB 4/8/2020 XRequired? Yes No Com m. X 4/10/2020 dts 4/10/20 JLC 4/10/2020 Well Work Prognosis Well Name:NCIU A-04 API Number: 50-883-20023-00 Current Status:Producer –Shut in Leg:Leg #3 SE Corner Estimated Start Date:May 1 st, 2020 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-018 First Call Engineer:Joe Kaiser (907) 777-8393 (O) (907) 952-8897 (M) Second Call Engineer:Dan Marlowe (907) 283-1329 (O) (907) 398-9904 (M) Current Bottom Hole Pressure:1,794 psi @ 4,143’ TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,794 psi @ 4,143’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure:1,380psi 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-04 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. The well was first worked over in 1994, during which time a partial collapse of the 7” casing was identified at 5,184’ MD. A cement plug was placed at 5130’ MD and a cast iron bridge plug was set at 4,828’ MD during this workover to isolate the lower part of the wellbore and produce the upper Cook Inlet Sands. In 2007 the existing completion was pulled and a gravel pack completion was installed to produce the Cook Inlet 1, 2, 3, and 4 sands. Water breakthrough occurred in 2017 and the well was shut in. It is proposed to isolate the Cook Inlet 1, 2, 3, and 4 sands by placing a cast iron bridge plug at ±4,440’MD. Then produce the Cook Inlet A, and Stray 3 sands through a single string completion with production packers set at (±4,209’, ±3,931’, and ±3,753’ MD). Waiver Request: Hilcorp requests waiver to 20AAC25.265(c)(1). We request locating the SSV on the tree wing allowing the SSV to remain in the production stream while providing concurrent well bore access. Additionally, a SSSV will be installed. Wellbore Notes: x Slickline will remove the SSSV Procedure: 1. MIRU HAK 404 2. Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 3. Workover fluid will be brine. BOP’s will be closed as needed to circulate the well. 4. Pull upper completion, fishing tubing and cleaning out as needed to ±4,447’. Lay down 4- 1/2” tubing completion. Contingency -If unable to pull completion from seal bore assembly: x Rig up E-line. RIH with tubing cutter. Cut tubing at ±4,415’. RD E-line. *Note depths of steps below will shift shallower. 5. RIH with casing scraper to Baker SC-1 Packer ±4,447’. Circulate clean. POOH. 6. RU E-line CBL Logging tool. RIH with tool. Log ±4,445’ to TOC. POOH – Send logs to AOGCC 7. RIH with 7” CIBP and set at ±4,440’ 8. Dump bail 10’ of cement on CIBP. RD E-line. 9. RIH with 3-1/2” Gas Lift completion (live valves) and packer assembly. See proposed schematic for detail and set depths. 10. Set Packers / Pressure test completion: o isolate the Cook Inlet 1, 2, 3, and 4 sands by (also pull #5 GLM valve @4412' for circulating KWF ) gls produce the Cook Inlet A, and Stray 3 sands t - Test casing to 1500 psi /30 min Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. Well Work Prognosis x Pressure up and set packers x Test tubing against plug in X nipple to >2,500psig and chart for 30 minutes. x Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). x Pull prong and plug in X-Nipple. 11. Set BPV. NU tree, test same. 12. RU E-line, PT lubricator to 2,500 psi, and perforate per program. RD E-line. Note: Deepest zone will be perforated first and tested. Contingency: If zone is unproductive, a CIBP w/cement will be placed in the tubing above the open zone. E-line will perforate the next shallowest zone. This will be repeated until a productive zone is achieved. 13. RD HAK 404 14. Turn over to production. 15. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Proposed 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form - within 5 days of production -----> Retest tubing to verify lower packer integrity. gls _____________________________________________________________________________________ Page 1 of 2 Updated By: PJR 06/24/17 SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 TD: 7,618 ‘MD TVD: 6390.8’ 16” RKB to TBG Head – 64.4’ 7” 2 3 4 5 6 78 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 130” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 X X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 BTC-M 3.958” 64.4’ 4,447.9’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 290’ 290’ 3.813” NIPPLE, 4.5” XXO SVLN 3.813” HES FXE WRDP ON X-Lock (5/16/13 Install) 2 1,409.8’ 1,399.4’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 860 psi (1/27/08 run date) 3 2,579.9’ 2,394.3’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 910 psi (1/27/08 run date) 4 3,655.3’ 3,226.8’ GLM, 1” GLV, CAMCO KBG-2-1R, BK LATCH, 900 psi (1/27/08 run date) 5 4,412.0’ 3,817.9’ GLM, 1” OV, CAMCO KBG-2-1R, BK LATCH, 0.313” PORT, 0 psi (1/27/08 run date) 6 4,425.7’ 3,828.8’ 3.813” NIPPLE, 4.5” HES X landing nipple 7 4,433.7’ 3,835.2’ 3.992” PBR, Baker 80-40 w/ 3.5” EUE 8 4,447.1’ 3,845.9’ 2.992” SEAL ASSY, Baker 80-40 “K” Anchor assembly 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 01/12/2008 PTD: 169-018 API: 50-8833-20023-00 __________________ Page 2 of 2 Updated By: PJR 06/24/17 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 8/22/1994 Open RPERF 12 spf CI-2.0 4,620’ 4,700’ 3,984.9’ 4,048.9’ 80’ 8/22/1994 Open RPERF 12 spf CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 8/22/1994 Open RPERF 12 spf CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 8/22/1994 Open RPERF 12 spf CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf _____________________________________________________________________________________ Updated By: JLL 2020-04-03 PROPOSED Tyonek Platform Well: NCI A-04 Last Completed: FUTURE PTD: 169-018 API: 50-8833-20023-00 TD:7,618‘MD TVD: 6390.8’ 7 16” RKB to TBG Head – 64.4’ 7” 8 9 2 34 6 5 DE F Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 130” Sterling A G H I J Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08)K L M N O P Collapsed Casing @ 4,702 CI Stray 3 C X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT 2.992” Surf ±4,225’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item Hanger 1 ±350’ ±350’ SSSV – 3.5” 2 ±1,410’ ±1,400’ 2.867” 5.313” GLM - SPM ±2,580’ ±2,394’ 2.867” 5.313” GLM - SPM ±3,600’ ±3,182’ 2.867” 5.313” GLM - SPM 3 ±3,650’ ±3,300’ 2.867” 5.313” Chemical Injection Mandrel 4 ±3,753’ ±3,300’ 3.000” 6.000” Hydraulic Packer 5 ±3,931’ ±3,438’ 3.000” 6.000” Hydraulic Packer 6 ±4,209’ ±3,656’ 3.000” 6.000” Hydraulic Packer 7 ±4,219’ ±3,654’ 2.813” 3.750” Profile X-Nipple 8 ±4,225’ ±3,669’ 2.992” 3.750” WLEG 9 ±4,440’ ±3,840’ CIBP w/ 10’ Cement A 4,425.7’ 3,828.8’ 3.813” NIPPLE, 4.5” HES X landing nipple B 4,433.7’ 3,835.2’ 3.992” PBR, Baker 80-40 w/ 3.5” EUE C 4,447.1’ 3,845.9’ 2.992” SEAL ASSY, Baker 80-40 “K” Anchor assembly D 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer E 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION F 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve G 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore H 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. I 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin J 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper K 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub L 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens M 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug N 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) O 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) P 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) NOTE: no perforations between packers initially. gls ___________________________________ Updated By: JLL 2020-04-03 PROPOSED Tyonek Platform Well: NCI A-04 Last Completed: FUTURE PTD: 169-018 API: 50-8833-20023-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI Stray 3 ±4,189’ ±4,194’ ±3,640’ ±3,644’ ±5’ Future Proposed Sterling A ±4,227’ ±4,260’ ±3,670’ ±3,697’ ±33’ Future Proposed CI-1.0 4,520’ 4,600’ 3,904’ 3,969’ 80’ 8/22/1994 Isolated CI-2.0 4,620’ 4,700’ 3,985’ 4,049’ 80’ 8/22/1994 Isolated CI-3.0 4,732’ 4,742’ 4,075’ 4083’ 10’ 8/22/1994 Isolated CI-4.0 4,764' 4,814’ 4,1012’ 4,143’ 50’ 8/22/1994 Open RPERF 12 spf CI-5.0 4,865’ 4,895’ 4,185’ 4,209’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,220’ 4,228' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,253’ 4,265’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273’ 4,279’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445’ 4,457’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,503’ 4,527’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616’ 4,626’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,764’ 4,769’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822’ 4,826’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,886’ 4,899’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162’ 5,170’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,228’ 5,236’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,283’ 5,306’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312’ 5,316’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389’ 5,409’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432 5,444’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,606’ 5,614’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308' 6,240’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Current Wellhead 3/04/2020 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tbg hanger, FMC-UH-A-EN, 6'͛X 4 ½ EUE 8rd lift and 4 ½ IBT susp, w/ 4'͛Type IS BPV profile, 1- ¼ non cont control line port Hanger is nested in pack-off and held down by lock plate Lock-plate needs to be removed before nipple up of BOPE Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 4 1/2 Tree assy, 4 1/16 3M Adapter, 16 ¾ 5M clamp hub x 4 1/16 3M stdd top, prepped f/ 1- non cont control line port 16'͛ 10 ¾͛͛ 7'͛ 4 ½͛͛ Proposed Wellhead 03/04/2020 NCIU A-04 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tubing hanger, Cactus-EN- CCL, 11 x 3 ½ EUE 8rd lift and susp, w/ 3'͛type H BPV, 2- ¼ cont control line ports Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 3 1/2 16'͛ 10 ¾͛͛ 7'͛ 3 ½͛͛ Tubing head attachment, Cactus, 11 5M FE X 16 3/4 5M BX-161 hub bottom Valve, Master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim BHTA, Bowen, 3 1/8 5M FE x 2.5 bowen quick union top Adapter, Cactus-EN-CCL, 11 5M stdd x 3 1/8 5M, w/ 2- 1'͛npt control line exits Valve, Master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim Valve, Swab, CIW-FLS, 3 1/8 5M FE, HWO, EE trim Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-04 (PTD 169-018)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Joe Kaiser <jkaiser@hilcorp.com> Sent:Friday, April 10, 2020 9:38 AM To:Schwartz, Guy L (CED) Cc:Dan Marlowe; Juanita Lovett; Karson Kozub - (C) Subject:RE: [EXTERNAL] A-04 RWO sundry (PTD 169-018) Mr, Schwartz, We will be pulling a GLV with slickline prior to rigging up Rig 404 on the well. This will be the same for A‐7 and A‐16. I mis‐read the HLB Redbook table, my mistake. For 3.5” 9.3# L‐80 tubing the collapse resistance is 15,540 psi and the internal burst pressure is 10,160 psi. These are significantly higher than the expected thermal pressures. Good catch! For packer isolation, very good suggestion. We will do that. Thank you, Joe Kaiser CIO Operations Engineer Hilcorp Alaska, LLC O: 907‐777‐8393 M: 907‐952‐8897 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Friday, April 10, 2020 9:27 AM To: Joe Kaiser <jkaiser@hilcorp.com> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub ‐ (C) <kkozub@hilcorp.com> Subject: RE: [EXTERNAL] A‐04 RWO sundry (PTD 169‐018) Joe, One other item… are you planning on pulling lower GLV for circulating? I couldn’t tell if the completion had a circulation point open at this time. You are rigging up slickline already to pull SSSV before rig gets there already. You are likely right on the expansion of fluid in annulus. The downhole temperature swing will be minor since you are close to surface. The only comment I have the 3.5” tubing will see collapse pressure vs burst. You won’t be able to test the all packers either. The CMIT only tests the upper packer in step 10. You could test the bottom packer if you retest (pressure up tubing) after pulling the plug/prong in the X nipple before perforating. The middle packer can’t be tested at all…. But this would at least show you don’t have a one way packer(s) leak to the IA. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 2 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Joe Kaiser <jkaiser@hilcorp.com> Sent: Thursday, April 9, 2020 1:50 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub ‐ (C) <kkozub@hilcorp.com> Subject: RE: [EXTERNAL] A‐04 RWO sundry (PTD 169‐018) Mr. Schwartz: My response to your questions are below. 1) In Cook Inlet we prefer the SSV in the flowline adjacent to the tree. Reason being: Easier for well maintenance, parts availability, consistency and standardization. 2) We are installing packers to isolate particular zones, especially zones known to have water. These are placed in a manner to produce the sterling A sands, the Stray (1, 2, & 3) sands, and a couple other gas zones revealed on a recent PNL. These will be added to pool rule currently being amended (which I believe is close to AOGCC approval). We will utilize a bottom up approach. We plan to perf the A zone and produce until unproductive. Then we will set a CIBP in the tubing and perf through tubing/casing. Once each zone between the packer is perforated, we will set a CIBP and come up hole. We are moving away from Sliding Sleeve/Packer approach typical at Tyonek and Beluga River. These designs allow too much comingling behind pipe (while not producing to surface) with no isolation. Hilcorp is finding the sleeves in these completions are eroded out to the point they don’t isolate. Further causing isolation and cross flow issues down hole. Additionally we don’t have open zones while having completion fluid circulating. We have a theory this can damages the reservoirs and breaks down the sands near the wellbore. I performed a volume expansion calculation on the area between the packers. The reservoir is shallow with a 101F temperature. Assuming we pump down fluids at 40F (conservative) that is a 61F differential temp. The pressure on the IA in the event of a pressure increase would be approximately 2,284 psi. Taking into account the head pressure from when the packer would be set ( Brine fluid gradient to 3,654’ TVD) of 1,644 psig. Total pressure would be 3,928 psi. This is significantly less than the burst pressure of the 3.5” tubing of 10,160 psig and the packer design pressure rating of 7,500 psig. Any tubing internal pressure reduces this differential pressure. Playing around with the sensitivities of the differential temperature, we do not see a pressure concern until approximately 150F differential. We are significantly below that. Additionally, I don’t feel we will have much expansion of fluid. The fluid will be full while running the completion. As we RIH the fluid temperature will equalize at or near reservoir temp of 101F. As we produce the gas, I feel we will see a reduction in temperature due to the JT effect across the perforations. This further reduces pressure effects from thermal changes. To conclude, Hilcorp feels the tubing and packer ratings are sufficient for the thermal expansion. If you have any further questions regard this sundry, please feel free to reach me on my cell phone or email. Thank you, 3 Joe Kaiser CIO Operations Engineer Hilcorp Alaska, LLC O: 907‐777‐8393 M: 907‐952‐8897 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Thursday, April 09, 2020 10:29 AM To: Joe Kaiser <jkaiser@hilcorp.com> Subject: [EXTERNAL] A‐04 RWO sundry (PTD 169‐018) Joe, What is the reasoning for taking out the SSV ? There are 2 now .. why not leave the SSV in the vertical run and remove the wing SSV? Also the schematic shows the CI stray 3 sands behind pipe (between straddle packers) . Assume you will leave this unperfed till later and have to punch through tubing to access. What is the third packer for? Also . you will have trapped pressure between the packers until you perf. Could have pressure/tubing collapse issues. Guy Schwartz Sr. Petroleum Engineer AOGCC 907‐301‐4533 cell 907‐793‐1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). ~rv~,N~~ ~~~ RECEIVED STATE OF ALASKA MAR 0 7 2008 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERAT,~ ~ G~ r.~ r~,„„,,~;~„ 1. Operations Performed: Abandon ^ Repair Well ^ Plug Pertorations ^ Stimulate ~,~ OD~ft~~101'~ Alter Casing ^ Pull Tubing [i~ q (p@tfp~te New Pool ^ ~~ ~~ ~~ .Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown^ /~;;((~~ Perforate ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: ConocoPhillips Alaska, InC. Development 0 Exploratory ^ `` 169-018 / " 3. Address: Strati ra hic g p ^ Service 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 ~ 50-883-20023-00 7. KB Elevation (ft): 9. Well Name and Number: RKB 40', 105' MSL ~ " NCI A-04 ` 8. Property Designation: ,10. Field/Pool(s): ADL 17589 • ~ '` ' North Cook Inlet, Tertiary Gas 11. Present Well Condition Summary: Total Depth measured 7656'- feet true vertical 6421'- feet Plugs (measured) 4826' Effective Depth measured 4826' feet Junk (measured) 5184' true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 576' 16" 576' Intermediate 2410' 10.75" 2410' Production 7618' 7" 7618' Perforation depth: Measured depth: 4520'-5285', 5392'-7542' ~~~y~E.® APR ~ ~ 2008 true vertical depth: Tubing (size, grade, and measured depth) 4.5", J-55, 4420' MD. Packers & SSSV (type & measured depth) Baker'SC' pkr @ 44as' XXO' SVLN @ 290' 12. Stimulation or cement squeeze summary: Intervals treated (measured) gravel pack CI 1 &2 4520'-4700' Treatment descriptions including volumes used and final pressure: gravel packed w/ 4800# 20/40 Accupack behind screens 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation 8 mmcfd -- 150 Subsequent to operation 0.8 mmcfd -- 140 14. Attachments 15. Well Class after work: Copies of Logs and Surveys run _ Exploratory ^ Development ^~ Service ^ Daily Report of Well Operations _X 16. Well Status after work: Oil^ GasO 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: 307-313 Contact Ji Ennis @ 265-1544 Printed Name ~ ~1'1nIS Signature `~,/J/ ' Title Phone: 265-1544 Wells Group Engineer ,, Date S 7 ~ p ~J Pre aced b ha Allsu -Drak 263-4612. Form 10-404 evised 04/2006 Submit Original Only ConoeoPhillips NCIU A Completion Diagram WATER DEPTN: 16" @ 576' API# 508832002300 41it" 7.;67 ~: ae.~. 11.75k J85 ~: ~s 4730 49F0 131 No. Top L engt h Description ID OD PRODUCTION TUBING STRING & JEWELRY 10 314" @ 2410' Item Description Jts OD ID Wt Grade Len Top Hanger 1 0.7 64.4 TOC @ 2600' CBL 4.5' 12.6# IBT-Mod tubing pup 1 4 1/2 3.992 12.6 J-55 10.15 65.1 4.5" 12.6# IBT-Mod tubing 7 4 1/2 3.992 12.6 L-80 214.82 75.2 4.5 HES XXO SVLN' 1 5.56 3.813 2.35 290 "X" 3.81 3"'7C nipple @4426' KB a.5" 12.6# IBT-Mod tubing 36 4 v2 3.992 12.6 L-80 111 161 292.a 4.5' 12.6# IBT Mod pup 1 4 1/2 3.95 12.6 L-80 5.77 1,404.00 KBG-2-1R GLM, t valve BK latch 1 5.984 3.86 12.6 6.89 1,409.80 Baker'SC' packer @ 4448' KB a.5" 12.6# IBT Mod pup 1 4 1!2 3.95 12.6 L-80 7.12 1,416.70 4.5' 12.6# IBT-Mod tubing 9 4 1/2 3.992 12.6 L-80 276.1 1,423.80 4.5' 12.6# IBT-Mod tbg stantls 3 4 1/2 3.992 12.75 J-55 187.64 1,699.90 Cook Inlet Sands EUE 8rd Mod xIBT-Mod Xover 1 4 1/2 3.992 12.75 J-55 62.68 1,887.50 Baker 4' Excluder Screens 4513-4700' KB 4.5, 12.75# EUE-Mod stand tubing' 10 4 1/2 3.992 12.75 J-55 623.79 1,950.20 4520 - 4600 CI-1.0 4.5' IBT-Mod x EUE 8rd Mod pup 1 4 t/2 3.992 12.75 L-80 5.93 2,574.00 KBG-2-1 R GLM, 1 valve BK latch' 1 5.984 3.86 6.9 2,579.90 4620 - 4700 CI-2.0 4.5' IBT-Mod x EUE 8rd Mod pup 1 4 t!2 3.992 12.75 L-80 5.67 2,586.80 opsed s~~ <= 1702' 4.5, 1275# EUE-Mod stand tubing' 17 4 112 3.992 12.75 J-55 1,056.89 2,592.50 4732 - 4742 CI-3.0 4.5' IBT-Mod z EUE 8rd Mod pup 1 4 1/2 3.992 12.75 L-80 5.95 3,649.40 _ KBG-2-1 R GLM, 1 valve BK latch' 1 5.98a 3.86 6.9 3,655.30 - 4764 - 4814 CI-4.0 4.5' IBT-Mod x EUE 8rtl Mod pup 1 4 1/2 3.992 12.75 L-80 5.67 3,662.20 BP C 8' 4.5, 12.75# EUE-Mod stantl tubing' t th d t t f ll k D 12 1 4 1!2 3.992 12.75 J-55 750.05 -11 91 3.667.90 4 418 00 @482 I er) a jus men or a y (pac ep 4.5' tBT-Mod x EUE 8rd Motl pup 1 4 1!2 3.992 L-BO . 5.94 , . 4,406.00 4865 -4895 CI-5.0 KBG-2-1R GLM, 1 valve BK latch' 1 5.984 3.86 6.87 4,412.00 7oc g asao 4908 - 4918 CI--5.1 4.5' IBT-Motl x EUE 8rd Motl pup 1 4 112 3.992 L-80 5.71 4,418.90 4.5' 12.75# EUE SRD pup 1 4 1/2 3.992 1.15 4,424.60 4948 - 4963 CI-6.0 4.5 HES "X' landing nipple" 1 4 1/2 3.813 1.2 4,425.70 zso~ ce~»er,i n 4973 - 4980 CI-6.1 4.5' 12.75# EUE 8RD pup 1 4 1/2 3.992 6.08 4,426.90 4.5 x 3.5' EUE reducer X-over' 1 5 9/16 2.992 0.75 4,433.00 ¢sv ®513o Baker 80-40 PBR w/ 3.5 EUE' 1 5.61 3.992 13.4 4,433.70 Baker 80-40 K' Anchor assembly' 1 5 2.992 0.75 4,447.10 L S , ~ _ ~%LLAPSED CASING 5184 - 5198 CI-9.0 1 ~ ~; F1SV @ 5220 I. ~ szss-seas c1-11_o We//History R April 1969 -Original Completion - CI 1.0,2.0,3.0,4.0,5.0,5.1,6.0,6.1,9.0,11.0, Beluga Sands and Beluga c-1 thru q-4 Commingled 4'X3-1 /2- tubing Set at 4761' with packers at 4722' and 4426' with CI t-2 Sleeve open II F2SV @ 5346 August 1994 Workover -Well completed in CI 1-4 i Reperforate/Perforate Beluga 5392'-6425' t2 SPF. (* Reperforate CI 4520'-5285' 12 SPF except CI 5.1 ~! ' 5392 - 5405 a-7 s DS7 3 CI 6.0 & 6.1 tested 200 MCFD and 960 BW PD (3200 Cq '. ' 5578 - 5584 b-7 w October 99 -Top of Fill 4745' ', 5650 -5655 c-1 w June 4, 2001 -Tag fill @ 4698 W LM 5728 - 5735 c-3 w May 13, 2002 - Tag f II @4688 W LM 5740 - 5745 c-3 a May 12, 2005 - Tag f II @4555' RKB during SBHP Survey June 2006 - Tag fll @ 4596' RKB. CCT FCO l0 4808' CTMD. Sept 14, 2006 -Tag fill @4736' RKB for SBHP survey. 6070 -6080 a-9 ~ May 11, 2007 - Tag f II @ 4682' RKB for SBHP @ 4600' (281 psi). 6152 - 6162 f-4 January 2008 - RWO found collapsed csg @ 4702' KB. Installed 4' Excluder screens & GF"d w/ 4800tt 20/40 Accupack sand. 6220 - 6250 f-8 & g-1 6257 - 6262 g-2 6355 - 6380 h-1 & h-1.1 6410-6425 h-0 6630 - 6640 i-7 7515-7542 q-4 ".,'_!i~ 7" @ 7618' PBTD: 4,826' TD = 7sss• well: North Cook Inlet Unit No. A-04 ILOCation: Lower Cook Inlet. Alaska Unn n • Corto+~oPhillips Time Log Summary WeUv7eia Web ReAaKfng Well Name: NCI A-04 Job Type: RECOMPLETION Time Logs __ Date From To Dur _ S. De th E,_De~th Phase __ Code 5ubcode T _ COM ____ __ 12/25/2007 12:01 16:00 3.99 MIRU MOVE MOB P Skid CUDD #136 unit over NCI A-04. Shut in well. 16:00 17:00 1.00 MIRU RPCOh SLKL P Rig-up Pollard W/L 17:00 17:45 0.75 MIRU RPCOh SLKL P RIH w/ 4.5" GS to 225'WLM. Latch & ull HES SSSV. POOH ., 17:45 18:30 0.75 MIRU RPCOh SLKL P RIH w/ 3.808" G-ring to 2807'WLM, tag to of XN ni le, POOH. 18:30 19:30 1.00 MIRU RPCO SLKL P RIH w/ 3.70" G-ring to 4682'WLM tag fill, POOH. 19:30 23:00 3.50 MIRU RPCOh SLKL P Rig Down Pollard W/L. Stage e ui ment for load out. 23:00 00:00 1.00 COMPZ WELC CIRC P Paint line on tree, tbg adapter, and tbg head. Take photo of tree position. Pre for well kill. 12/26/2007 00:00 05:00 5.00 COMPZ WELCT CIRC P Complete prep work for well kill. Fou ht MI lines bein froze. 05:00 07:30 2.50 COMPZ WELCT CIRC P Pump total of 144 bbls of 6% KCL water down tubing @ 2.7 BPM. Initial tubing pressure 200 psi. Shut down and montitor well for flow. Had MI batch up another 100 bbls of filtered KCL water. 07:30 09:30 2.00 COMPZ WELCT CIRC P Wellhead showing 25 psi. Decide to pump additional 50 bbls of 6% KCL water. 09:30 10:30 1.00 COMPZ WELCT OWFF P Montior well for flow. Pressure build up to 25 si. in 30 mins. 10:30 15:30 5.00 COMPZ WELC CIRC P Pump another 100 bbls @ slower rate of 1 BPM. Total volume pump down tubin 300 bbls. 15:30 18:00 2.50 COMPZ WELC OWFF P Will monitor well over next two hours. While pumping class two fluids out of pits to A-12 injection well @ .5 bpm 1400 si. 18:00 22:30 4.50 COMPZ WELC OWFF P Mixing up another 300 bbls of 6% filtered KCL water. Injected 140 bbls of class II fluid from A-3 into A-12, while waiting on Filtered KCL. Frozen pump/lines coming from pits, cleared and continue um in . 22:30 00:00 1.50 COMPZ WELCT OWFF P Start pumping -initial presure 140 psi, dropped to zero pressure after 10bbls awa , 3 BPM. ~A_._.__..~..W.y.. P~~e 1 of 1d Time Logs _ _ Date From To Dur S. tl~ E. De th Pha e Code Subcode T COM 12/27/2007 00:00 03:00 3.00 COMPZ WELCT OWFF P Pumped 100 bbls of 6% KCL & 1% Flo-Visc, Annulus on Vac, shut down for 10 min. to switch pits. Well increased to 40 psi. Continue pumping additional 230 bbls of filtered 6% KCL. 03:00 03:45 0.75 COMPZ WELC CIRC P Total pumped 340 bbls, well currently on vac monitor for 30 min. WHP increased to 15 psi. Continue mixing another 100 bbl KCL ill. 03:45 04:45 1.00 COMPZ WELCT WOW P WHP 15 psi, pump another 100bb1s @ 3 BPM. 04:45 06:15 1.50 COMPZ WELCT OWFF P Shut in for 30 min, 5 psi, bleed down slight gas head, no pressure increase "0" monitor well for another 30 min, Burin shift chan e. 06:15 11:15 5.00 COMPZ WELCT OWFF P Tubing pressure up to 10 psi. Spent next four hours attempting to bleed small amount gas out of tubing. Tubing pressure continues to build-up to around 5-10 si each time. 11:15 13:15 2.00 COMPZ WELC CIRC P Batch another 100 bbls of 6 %KCL. Pump 10 barrel 1% FLO-VIS pill follwed by 100 bbls KCL water down tubin 2 BPM, shut down um . 13:15 14:00 0.75 COMPZ WELCT OWFF P Tubing pressure at 0 psi. Pull off ressure au a well on vac. Monitor well 30 mins. Well still on vac. 14:00 16:00 2.00 COMPZ WELC NUND P Set BPV. Production shut in two wells beside A-04. Break loose flow line. Continue pumping class two fluid down injection A-12. Pumping com lete. 16:00 18:00 2.00 COMPZ WELCT NUND P ND tree. Set blanking plug. 18:00 00:00 6.00 COMPZ WELCT NUND P Start NUBOP stack with 4.5" i e rams. 12/28/2007 00:00 02:00 2.00 COMPZ WELCT NUND P Continue rigging up BOPS. Hooking up hyd. hoses and fluid lines to stack. Mixed up 500 bbl of 6% KCL and stored in platform pits. Wind speeds around 30 MPH. 02:00 04:00 2.00 COMPZ WELCT NUND P Function test all Bop components including HCR & Annular. Start to rig up PTS iron to A-3 while rig is cycling BOP's. 04:00 06:00 2.00 COMPZ WELCT NUND P Pick up pressure test subs and joints for BOP test. 06:00 08:30 2.50 COMPZ WELCT BOPE P Fill BOP stack. attempt shell test to 2500 psi, leaking at hanger pins, bleed off, reti hten han er ins. 08:30 12:00 3.50 COMPZ WELCT BOPE P Made several more attempts at shell test to 2500 psi. Had leaks at the kelly basket and hammer union on manifold, make repairs. Shell test still leakin off with no visible leaks. ~ - Pepe ~ ~s~` 1& a Time Logs _ _ Date From To Dur S De th E. De th Phase Code Subcode T COM 12/28/2007 12:00 15:00 3.00 C OMPZ WELCT BOPE P~ Discovered blankin plug is leaking' retrieve blanking plug. Inspect threads and grease ball & seat. Reset blanking plug. Shell test to 2500 psi, holdin now. 15:00 19:30 4.50 COMPZ WELC BOPE P All BOP rams and com ents tested 250/250_ 0 psi. PTS lines tested and flowin back from A-3. 19:30 19:54 0.40 COMPZ WELCT BOPE P Pull blanking plug, make up tubing to upland tubing hanger prior to pulling BPV. 19:54 21:54 2.00 COMPZ WELCT BOPE P Checked pressure under BPV. Gas bubbles detected in fluid. Close blinds and pump 10 bbl 1 % flow visc pill followed by 100 bbl 6°loKCL pill. Pressured up to 80 psi 30 min. monitoring leaking through BPV. Pum rate 3b m 21:54 23:54 2.00 COMPZ WELCT BOPE P Still light gas flow, pump an additional 90 bbls. Monitor with light gas detected. Pressured up to 40 psi. Mix up 6 bbl pill (FRW-14) followed by 100 bbls 6% KCI fluid. PBV sealed this time, very light gas flow (25 psi an um anel. 12/29/2007 00:00 01:30 1.50 COMPZ WELC CIRC P Pump 8 bbl 1% heavy FRW-14 followed by 105 bbl 6%KCL. Well very light blow of gas throughPBV, 10-15 si. Mix u another ill. 01:30 03:30 2.00 COMPZ WELCT CIRC P 15 psi when started pumping 200 bbl @ 3bpm pill. Monitor for 10 min. slight as under BPV. 03:30 05:30 2.00 COMPZ WELCT OWFF P Still seeing gas pressure from under BPV, mix up more KCL fluid and monitor well and pressures. Arrange for more Flo-vis to ship offshore to wei h u ills. 05:30 11:00 5.50 COMPZ WELC WOSP NP Stand By for boat arrival with more KCL and FIO-VIS. Pump returns from A-03 flowback to A-12 inj. well. Batch u remainin KCL on board. 11:00 13:30 2.50 COMPZ WELC KLWL P Offload Champion. Batch up additional KCL. Mix 30 barrel FLO-VIS pill at 5 allons er 10 bbls KCL water. 13:30 16:30 3.00 COMPZ WELCT CIRC P Start pumping 250 bbls of KCL water @ 2 BPM. Initial pressure 0 psi. Increased pump rate to 3.3 BPM when pressure dropped to 0 psi. Had to drop pump rate to 2.5 BPM, MI Swaco unable to push fluid to CUDD quick enough @ 3 BPM. Will follow water with 30 bbls of FLO-VIS pill. Followed by 80 bbls of KCL water to get pill to to of erfs. 16:30 17:00 0.50 COMPZ WELCT OTHR P Pull BPV .~~._ I~~~~ 3 0~ 1A i Time Logs Date From To Dur S De th E. De th Phase Code Subcode T COM 12/29/2007 17:00 19:00 2.00 COMPZ RPCO RURD P _ _ Make-up landing joint/ Crew change 19:00 20:00 1.00 COMPZ RPCO RCST P Pulled 54, 000#, weight dropped to 44,00#. P/U additional 40' to ensure clear of PBR assembl . 20:00 22:30 2.50 COMPZ RPCOh CIRC P Start pumping 200 bbls of 6% filtered KCL, did not have any returns to surface. 22:30 00:00 1.50 COMPZ RPCOf~ RCST P Monitor well, begin POOH with 4.5" tubing. Noticed slight weight gain with SSSV coming into stack. Pulled up slowly and a birdsnest of control line was wra ed around SSSV. Control line still intact, total of 3 plastic bands recovered. 12/30!2007 00:00 03:30 3.50 COMPZ RPCO CIRC P Pull 4.5" tubing from well. Stop and tally every 10 stands and pump 5 bbl down the backside. Well stayed dead no indication of fluid level. 03:30 05:30 2.00 COMPZ RPCO RURD P Close blinds, secure the well. Start changing Dies/slips to 2-7/8". Set up to inject Class II fluid down A-12 from A-3 PTS). 05:30 06:30 1.00 COMPZ RPCO SFTY P Perform Abandon Platform Test (Muster). Weft/ secured and all personnel accounted. Discussed Safety topics with both crews on board. 06:30 09:30 3.00 COMPZ RPCO SFEQ P Install test plug, Change pipe rams from 4.5" to 2 7/8". 09:30 13:30 4.00 COMPZ RPCO SFEO P Test i e rams 250/2500 psi. Had several leaks that prolonged test. Eventual! of ood test 250!2500 si. 13:30 14:30 1.00 COMPZ RPCO RURD P Lay down test plug. Make up HES PBR retrieval tool and crossover to workstrin . 14:30 18:30 4.00 COMPZ RPCOh TRIP P RIH w/ HES BHA on 2 7/8" work string to 2800'MD. P/U weight off bottom 30,000# En a ed PBR. Stand 46 in. 18:30 21:30 3.00 COMPZ RPCOh RURD P Hook up addtional hydraulic hoses for rotary table. Hydraulic system function tested to man basket. 21:30 00:00 2.50 COMPZ RPCOb TRIP P Turned fishing BHA 29 turns to the right. P/U weight 34,000#. Flag stand, POOH stoooina every 10 stands to um 5 bbls down the backside. 12/31/2007 00:00 01:30 1.50 COMPZ RPCO CIRC P Stand back 2-7/8" tubing with PBR fish. 01:30 03:00 1.50 COMPZ RPCOh PULD P Lay down first fishing string. 03:00 07:00 4.00 COMPZ RPCO PULD P P/U Second fishing run BHA (HES). 07:00 08:00 1.00 COMPZ RPCOh TRIP NP Start in hole with HES BHA on work string. Trouble with hydraulic system. Close annular, secure well. 08:00 09:30 1.50 COMPZ RPCOh WOEO NP Troubleshoot hydraulic system from CUDD ower ack. €~<~~e ~ caf 1~ r~ Time Logs _ _ _ _ Date From To Dur S. Depth E. Depth Phase Code Subcode T COM 12/31/2007 09:30 14:30 5.00 COMPZ RPCOh WOEQ NP Make repairs to main hydraulic pump at CUDD ower ack. 14:30 16:30 2.00 COMPZ RPCOti TRIP P Continue in hole with HES BHA on work strip 16:30 18:00 1.50 COMPZ RPCOh CIRC P Sit one stand above packer and circulate 50 bbls down backside and 50 bbls down workstring prior to latchin acker assembl . 18:00 19:00 1.00 COMPZ RPCO CIRC P Latched down on fish 43 stands plus 5' pup. Latched in, set down 5M#, P/U 10M# over, Set down 20M#, P/U 15M over packer released total PJU weight 50,000#, relax rubbers for 30 min prior to POOH. Pump 20 bbls down backside. No as detected. 19:00 22:30 3.50 COMPZ RPCO TRIP P POOH, stand back WS, pump 5 bbls eve 10 stands. No indication of as. 22:30 00:00 1.50 COMPZ RPCO6 PULD P Lay down BHA with complete packer assembl .Prepare to P/U 3.5" Calvins BHA. 01/01/2008 00:00 02:00 2.00 COMPZ RPCOh PULD P Finish laying down HES VSR packer assembl & drill collars. 02:00 04:00 2.00 COMPZ RPCO PULD P P/U equipment for 3.5" Cavins tubing run. Change dies in Work basket to 3.5" 04:00 07:00 3.00 COMPZ RPCOh PULD P P/U Cavins BHA for first sand cleaning run. 07:00 08:30 1.50 COMPZ RPCOh TRIP P RIH w/ Cavins BHA to 2700'MD. 08:30 10:30 2.00 COMPZ RPCOh PULD P Install TIW valve. Back load Champion to make access to remaining 2 7/8" PH-6. 10:30 14:00 3.50 COMPZ RPCOh TRIP P Continue in hole with clean-out BHA. Stand back remaining 16 singles for a total of 75 stands racked back. 14:00 16:00 2.00 COMPZ RPCOh FCO P Tag fill @ 4662'MD, start cleaning out casing. Couple of tight spots, sand bridges. But for the most part making hole rather easily. Stopped making hole 4747'MD. Made approximately 85' of hole. Up/down weight off bottom 50k/32k. Suspect BHA assembly is 16:00 20:00 4.00 COMPZ RPCOh TRIP P POOH w/ Cavins BHA assembly, Pumping down backside every 20 stands. 20:00 00:00 4.00 COMPZ RPCO PULD P BHA @ surface, no sand inside BHA. Inspect tools, no indication of any sand, slight scarring on side of BHA, make back u . 01/02/2008 00:00 00:30 0.50 COMPZ RPCOh SFTY P Safety Meeting discussing communication in the work basket. 00:30 04:30 4.00 COMPZ RPCOh FCO P RIH with 3.5" Cavins sand pump ~~ii~L ~ cf "I$ r~ Time Logs - _ Date From To Dur S. De th E _D~th Ph se_ Code Subcode T COM 01/02/2008 04:30 07:00 2.50 COMPZ RPCOh CIRC T Fun ti ht s of a ain on 72 stands in 4650' .Need to push 15M# down to get through and P/U weight is 10M# over-pull. Discuss pumping down backside and try to RIH. If that does not work then rotate in and see if we can make any hole without hanging u. 07:00 09:00 2.00 COMPZ RPCOh FCO P PUH to 4625' MD. Pump down backside @ 26PM while working BHA through restriction, unable to make hole, also tried rotating pipe while pumping down backside with same results, tools sticking somewhat. Decide to POOH. 09:00 12:00 3.00 COMPZ RPCO TRIP P POOH w/ Cavins BHA 12:00 13:00 1.00 COMPZ RPCOh PULD P Change out dies to 3.5" for 3.5" BHA. 13:00 14:00 1.00 COMPZ RPCO PULD P Lay down Cavins equipment and 3.5" single above Cavins pump. everal metal marks alon side of 3.5" tubin and on the pump assembly. Couple of the marks 18" in length and 1/4" wide were sufficient. Pictures were taken and sent to town Engineer. Nothing in BHA assembl . 14:00 17:00 3.00 COMPZ RPCOA WOEQ T Stand by for Champion arrival with new BHA equipment. Mix another 200 bbls of KCL water to top off pits. CUDD crew spent stand by time pulling maintenance on unit. 17:00 18:00 1.00 COMPZ RPCO OTHR P Offload Champion. 18:00 21:30 3.50 COMPZ RPCO PULD P Make up Baker BHA for 6.0"junk mill, 5.50" string mill, Bumper sub, OJ, 6 - 4.5" DC, X-over to 2-7/8". Pump 20 bbls rior to RIH. 21:30 00:00 2.50 COMPZ RPCOh CIRC P Current depth @ midnight 34 stands 2350' .Continue to RIH. 01/03/2008 00:00 03:00 3.00 COMPZ FISH MILL T Trip in hole.Tagged on stand 71 (1ft in) 4560' .BHA 6"junk mill, 5.80" string mill above, OJ & 6 DC. tagged within 5' of tight spot from previous 4.5" run. Total of all erferated sections 4520-4814'. 03:00 06:00 3.00 COMPZ FISH MILL T P/U weight 56,000# & DW 20,000#. Start pumping down WS @ 1.5 BPM. Bit work detected, keep rotating slowl ,made 3' in 2 hours. F~~y~ ~ of 14 Time Logs ~ Date From T_o Dur S. De th E De th Phase Code Subco d e T COM 01/03/2008 06:00 14:00 8.00 COMPZ FISH _ __ MILL T Continue to work flat bottom mill down hole @ 1'-1.5' FPM. Torque with 10K down weight 2500- 5000 lbs. P/U weight 50K and down weight 30K. Reduce pump rate down work string to .5 BPM. Made 13' total since coming on tour 06:00 and 16' total since mill o erations started. 14:00 16:00 2.00 COMPZ FISH WOEL T Pick-up hole one single. Shut down pump and milling operation. Try several attempts to get more RPM's to rota ,but onl able to et 25 RPM's. 16:00 18:00 2.00 COMPZ FISH MILL T Continue milling operations and return um rate to .5 BPM. 18:00 00:00 6.00 COMPZ FISH MILL T Continue Milling total hole made in 18 hours 20' 4580'MD .Numerous tries to increase pump rates, shutting down pumps etc. Addtional PP supply to arrive tonight to rotate TS faster for better ROP. Continue milling at current rate. 01/04/2008 00:00 02:00 2.00 COMPZ FISH MILL P Continue Milling with 6.0"Junk mill pumping .5 bpm. Estimated 22 rpm, torque is 2500-5000# with 10K down. Rou hl made 1ft in ast hour. 02:00 04:00 2.00 COMPZ FISH MILL P Boat arrived, offload power pack for rotary head. Inspect dies and tongs while swa in ower acks. 04:00 06:00 2.00 COMPZ FISH MILL P Start Milling again, getting roughly 43rpm, mark pipe to measure gain. Current DW 10K torque 2500-5000#. Sitting on ticlht spot only made 8" in past 1.5 hrs. Cycling pipe, increasing um seed to 1 b m. 06:00 09:30 3.50 COMPZ FISH MILL T Crew change. Continue milling at tight spot @ 4578'M, more torque now. Still getting 45 rpm's, reduce pump rate to .5 b m. 09:30 10:30 1.00 COMPZ FISH MILL T Worked thru tight spot. Over last hour made another two feet to 4580'MD. C/P Engineer made call to POOH to check BHA. 10:30 17:00 6.50 COMPZ FISH TRIP T POOH w/ Baker BHA standing back work strip . 17:00 18:00 1.00 COMPZ FISH PULD P Stand back drill collars, lay down Baker BHA. 18:00 19:00 1.00 COMPZ FISH PULD P Inspect Bit, definate wearing from a flat bottom junk mill to a tapered mill near the top and outside edges. Bottom center of mill had no scaring, and string mill had very little scarring. Si ns ma look like colla se or deformed casin . 19:00 20:00 1.00 COMPZ WELCT BOPE P Start making up BHA for BOP test, state test witnessed b Chuck Scheve Pays 7 of 4~ Time L©s _ Date From To Dur S. De th E. De th Phase Code Subcode T CO M 01/04/2008 20:00 22:30 2.50 COMPZ WELCT BOPE P _ Install test plug and start testing lower pipe rams 250/2500 psi. Complete tests 1 through 6 which include both pipe rams, annular and WC valves on stack and manifold 250/2500 si. 22:30 00:00 1.50 COMPZ WELC BOPE P Pull 2-7/8" tubing from BOP and test Blind rams. 250/2500psi. passed. test Kummi unit, all tests passed and witnessed b Chuck Scheve. 01/05!2008 00:00 04:00 4.00 COMPZ FISH PULL P Making up Milling BHA which consists of 5" tapered mill, junk basket„ BS, OJ, FS, 6 - 4.5" DC back to 2-7/8" work strin . 04:00 08:30 4.50 COMPZ FISH TRIP P Trip in hole. Getup P/U weight @ 3,318'MD 46K down wei ht 26K. 08:30 10:30 2.00 COMPZ FISH TRIP P No problems through restriction @ 4560'MD. P/U weight thru restriction 56K down 24K. Continue in hole, tag with 10K over @ 10' in on stand #73 (4693'MD) Attempt to work thru obstruction with out rotating pipe. P/U hole start rotating pipe @ 25 rpm's, TIH to tag depth. Called town Engineer, decide not to rotate at this oint. 10:30 16:00 5.50 COMPZ FISH TRIP P POOH w/ tapered mill BHA standing back work strip .Stand back D/C's. 16:00 18:00 2.00 COMPZ FISH PULD P Lay down tapered mill BHA, check junk basket, two small pieces of scale in junk basket, add 5.80" string mill to BHA. 18:00 22:00 4.00 COMPZ FISH TRIP P Trip in hole with 5.5" tapered mill, 5.75" string mill, Pump out sub, 4.75" bum er sub & OJ, 6 - 4.75" DC. 22:00 23:00 1.00 COMPZ FISH MILL P Tagged up on top restriction 4580' MD with 5.75" string mill. P/U weights 56K, down 22K. Start rotating and um down backside .5 b m. 23:00 00:00 1.00 COMPZ FISH MILL P Made roughly 3' of hole since tagging. All weights look good, continue with millin o erations. 01/06/2008 00:00 02:00 2.00 COMPZ FISH MILL P Continue milling, most likely all work being done on string mill in tighter restriction @ 4580' MD. Made 10' since startin . 02:00 03:30 1.50 COMPZ FISH MILL P Made roughly 30' past hour, depth 4620'MD. Continue pumping down backside .5b m. 03:30 04:30 1.00 COMPZ FISH MILL P Still going in smooth, some areas need a little work while slowly lowering down. P/U weight 59K, down 21 K, current de th 4651' MD. Pumping .5b m down backside. Pagz 8 cf 1A r~ • Time Logs __ __ __ Date From To Dur S Depth E De th Phase Code Subcode T COM _ _ 01/06/2008 04:30 06:30 2.00 COMPZ FISH MILL P Current depth 4695' MD, slowly working in hole. Stopped rotating until tag. Weights still look good. Tagged. up slightly @ 4723' MD, rotated bit and pumped.5 bpm. kept working string down to 4740' MD. Stopped pumping, check weights again. P/U 58K, 22K down. Continue milling @ .5 b m. 06:30 07:00 0.50 COMPZ FISH MILL P 4741' MD, heavy P/U 82K, increase pump rate to 1.5bpm, Pull free. POOH to change BHA assembly back to Sand Pum . 07:00 11:00 4.00 COMPZ FISH TRIP P Trip out of hole. 11:00 13:00 2.00 COMPZ FISH PULD P Stand back D/C. Lay down tapered mill BHA and inspect. Bottom 3" of carbide on tapered mill worn off with three stress cracks on tip. OD of mill reduced from 5" to 4.90". String mill OD reduced from 5.80" to 5.75". Decide to run Cavins um assembl . 13:00 16:00 3.00 COMPZ FISH PULD P Make up Cavins BHA. 16:00 20:00 4.00 COMPZ FISH TRIP P RIH w/ Cavins pump assembly on work strin . 20:00 22:00 2.00 COMPZ FISH CIRC P Cavins pump on bottom, 72 stands in hard to (7440'MD .Same depth as previous mill run. Cycle pump numerous times. Continue hard tagging, pumped 30 bbls down backside, cylce two more times and POOH. 22:00 00:00 2.00 COMPZ FISH TRIP P Trip out of hole counting stands to double check proper depth. 3 Stands in basket rior to POOH. 01/07/2008 00:00 03:30 3.50 COMPZ FISH TRIP P Trip out of hole from 4702' RKB 03:30 08:30 5.00 COMPZ FISH PULD P Total of 75 total stands @ surface. Pipe tally correct. Begin breaking down and laying out 3.5" Cavins Sand pump assembly. Fluid detected in right above pump assembly. Break out stands below check valves and catch all fluid/sand in holding tank. Total volume of solids obtained 1/2 oof a 5 gallons bucket. Mostly formation sand, small amount of rubber, also trace of metal fines. 08:30 11:30 3.00 COMPZ FISH WOOR T Stand by for decision to made from town. 11:30 18:30 7.00 COMPZ RPCOh PULD P Start loading boat with Gravel pack equipment at the beach. Breaking down all BHA on deck to ship back to town. P~g~5c~f14 r~ Time Lomas +Date From To Dur S. De th E. De th Phase Code Subcode T COM 01/07/2008 18:30 00:00 5.50 COMPZ RPCOh WOLG P Boat loaded, waiting on low tide and heavy ice to move out. Boat captian requested departure time @ midnight with tide. Pulled maintance on Power pack, and tongs. Cleaned up deck s ace and cleaned deck/ latform. 01/08/2008 00:00 01:30 1.50 COMPZ RPCO PULD P Lay down 3.5" tubing. 01:30 07:30 6.00 COMPZ RPCOh RURD P Offload gravel pack equipment, and load u millin /fishin BHA on boat. 07:30 09:30 2.00 COMPZ RPCOh PULD P Lay out BHA and prepare to P/U ravel ack BHA. 09:30 00:00 14.50 COMPZ RPCOR SFTY T Screen dropped from elevators and fell to upper deck. Suspend operations while doin a Ta Root investi ation. 01/09/2008 00:00 01:00 1.00 COMPZ RPCOh SFTY P Hold PJSM and do plan forward for assemblin screen assembl . 01:00 08:00 7.00 COMPZ RPCOti GRVL P Make u GP screen assembly and acker. 08:00 10:00 2.00 COMPZ RPCOh GRVL P PU wash string 10:00 16:30 6.50 COMPZ RPCOh TRIP P RIH with GP assembly on 2 7/8" work strip 16:30 18:00 1.50 COMPZ RPCOh PACK P Tag fill at 4698', 56000 up weight, 30000 down. Drop ball, wait on it for 1 hour. 18:00 21:00 3.00 COMPZ RPCO P Set acker by pressuring tubing up in intervals and bleeding off pressure between pressure cycles. First pressure interval to 1900 psi on tubing string for 5 minutes, second was 2500 psi for 5 minutes, third was 3100 psi for 5 minutes. 21:00 23:00 2.00 COMPZ RPCO P Com lete acker set by pressuring up on backside to 2500 psi for 5 minutes. Performed pull test on packer of 20k over, all indications are that packer is set. 23:00 00:00 1.00 COMPZ RPCO P Verified tubing was released from acker b PUH 9'. 01/10/2008 00:00 02:00 2.00 COMPZ RPCOh CIRC P Reverse circulate packer set ball back to surface. Blow down lines and freeze rotect surface a ui ment. 02:00 10:00 8.00 COMPZ RPCO CIRC P Make up fluids for gravel pack and load tanks. 10:00 10:30 0.50 COMPZ RPCOti GRVL P Hold PJSM for Acid pickle 10:30 11:00 0.50 COMPZ RPCOM1 GRVL P Wait on MI to mix fluids. 11:00 11:15 0.25 COMPZ RPCOh GRVL P PT BJ surface lines. 11:15 12:00 0.75 COMPZ RPCOh GRVL P Load well @ 3 bpm with 36 bbls of 2 micron filtered 6% HCL with FRW friction reducer. 12:00 12:15 0.25 COMPZ RPCO GRVL P Pump 10 bbls of Flo-Vis PacJe 1D of 14 • Time Logs __ Date From To Dur S De th E. Depth Phase Code Subcode T COM _ _ ~ 01/10/2008 12:15 12:30 0.25 COMPZ RPCOti GRVL P , Pump 12 bbls of Safe-solve 12:30 12:45 0.25 COMPZ RPCOb GRVL P Pump 7.8 bbls of 10% HCL 12:45 13:00 0.25 COMPZ RPCOh GRVL P Displaced acid w/ 14.1 bbls of 6% KCL 13:00 13:30 0.50 COMPZ RPCOb GRVL P Reverse circulate out w/ 40 bbls of 6% KCL while um in 2 b m. 13:30 15:00 1.50 COMPZ RPCOh GRVL P Wait on MI to make up fluids. 15:00 15:15 0.25 COMPZ RPCOh GRVL P Begin Step rate test, pumped 30 bbls KCI into well @ 8 9 pb mat 40 psi to fluid ack well. 15:15 15:30 0.25 COMPZ RPCOh GRVL P Decreased pump rate to 6 bpm @ 60 si. 15:30 15:39 0.15 COMPZ RPCOh GRVL P Increased pump rate to 8 bpm @ 536 si. 15:39 15:48 0.15 COMPZ RPCOh GRVL P Increased pump rate to 10 bpm @ 900 si. 15:48 16:00 0.20 COMPZ RPCO GRVL P Increased pump rate to 11 bpm @ 1150 psi. rSD pumps w/ 174 bbls awa ISIP was 100 si. 16:00 17:45 1.75 COMPZ RPCO GRVL P Wait on MI to load tanks with 2 micron filtered 6% KCL with FRW friction reducer: 17:45 18:45 1.00 COMPZ RPCOh GRVL P Hold PJSM for gravel pack. 18:45 18:54 0.15 COMPZ RPCOh GRVL P Load well @ 9.5 bpm with 30 bbls of 2 micron filtered 6% KCI 40 si. 18:54 19:03 0.15 COMPZ RPCOh GRVL P Start in with .5 PPG 20/40 Accupack sand 8 b m with 440 si 19:03 19:12 0.15 COMPZ RPCO GRVL P Increase to 1 PPG sand while pumping 8 bpm @ 550 psi. (Light returns startin from annulus . 19:12 19:21 0.15 COMPZ RPCO GRVL P Screen out at 1500 psi, with 4800# of sand to formation. Pressure up slow to 2200 si to veri ravel ack. 19:21 19:51 0.50 COMPZ RPCOh GRVL P Pressured back side up to 500 psi, PU tubing 10' to reverse circulate, 50 bbls @ 4 bpm to clean out tubing. PU tubing an additional 11' then set back down. COMPZ RPCOh GRVL P Begin rigging down BJ pump e ui ment. 01/11/2008 00:00 01:00 1.00 COMPZ RPCOh PULD P l pad well with 48 bbls of 6% KCI to load test KOIV, wait for 1 hour to check fluid level. 01:00 03:30 2.50 COMPZ RPCO PULD P After 1 hour, fluid still @ surface. Continue to move BJ surface e ui ment for backhaul. 03:30 10:30 7.00 COMPZ RPCOh PULD P Start pulling work string. 10:30 12:30 2.00 COMPZ RPCOti TRIP P Lay down Baker BHA 12:30 16:00 3.50 COMPZ RPCOh OTHR P Chan a out BOP rams to 4 1/2". Off load BJ um in a ui ment. ~~~~ 11 ~~ 14 Time Logs _ _ Date From To Dur S Depth E. De th Phase Code Subcode T COM 01/11/2008 16:00 20:00 4.00 COMPZ RPCOh WOEL NP Unit crane broke down 20:00 00:00 4.00 COMPZ RPCO Stage equipment for BOP test 01/12/2008 00:00 04:00 4.00 COMPZ RPCOh OTHR P Stage equipment for BOP test 04:00 16:00 12.00 COMPZ RPCO OTHR P Perform BOP test 16:00 20:00 4.00 COMPZ RPCO OTHR P Unload Champoin, strap completion e ui ment. 20:00 00:00 4.00 COMPZ RPCO OTHR P Inject Class II fluids down the disposal well. 01/13/2008 00:00 02:00 2.00 COMPZ RPCOh HOSO P Start running completion. 02:00 05:00 3.00 COMPZ RPCO HOSO NP Change out and repair broken pin in sli s. 05:00 00:00 19.00 COMPZ RPCO HOSO P Continue running completion string. 01/14/2008 00:00 03:00 3.00 COMPZ RPCOfv HOSO P Continue running completion. 03:00 03:30 0.50 COMPZ RPCO HOSO P one joint abouve packer performed wei ht check of 64k u . 03:30 04:00 0.50 COMPZ RPCOh HOSO P Stung into packer w/ baker PBR anchor assembly. Pulled 20 K over to veri set. 04:00 04:30 0.50 COMPZ RPCO HOSO P Pulled 100k to shear PBR, pulled up one joint and installed Kelly for circulatin . 04:30 07:30 3.00 COMPZ RPCO CIRC P Start circulating out well. 07:30 09:30 2.00 COMPZ RPCO CIRC P Thaw out inhibitor fluid 09:30 10:30 1.00 COMPZ RPCO CIRC P Spot inhibited fluid in backside at aaker, 40 Bbls with 25 al MI 10:30 15:30 5.00 COMPZ RPCO HOSO P Land tubing and tubing hanger with control line attached. 15:30 16:30 1.00 COMPZ RPCOh HOSO P Set BPV 16:30 00:00 7.50 COMPZ RPCO NUND P ND BOP's 01/15/2008 00:00 08:00 8.00 COMPZ RPCOti NUND P Continue ND BOP's 08:00 14:00 6.00 COMPZ RPCOh NUND P NU Tree Pull BPV set test Plug 14:00 16:00 2.00 COMPZ RPCO SIPB P Test Tree to 2400 psi Good test. Pull Test lu 16:00 18:00 2.00 COMPZ RPCOh SIPB P Test IA to 2400 psi hold for 30 min MITIA. Good Test 18:00 21:00 3.00 COMPZ RPCO NUND P Prep rig to skid over A-05, stage Pollard a ui ment. 21:00 00:00 3.00 COMPZ RPCO NUND P Skid rig over to A-05, RU pollard. 01/16/2008 00:00 00:00 24.00 COMPZ RPCO OTHR P Start rigging down CUDD equipment, load MI Swaco BOP equipment, and CUDD mud um onto the Cham ion. ~~~e 12 cif 94 ~~ r~ Time Lo s Date From To Dur S. De th E. De th Phi e Code Subcode T COM____ ___ 01/17/2008 00:00 17:00 17.00 COMPZ RPCO OTHR P Prep next mainline crane picks and organize deck. Wait on boat to return for load out. 17:00 20:00 3.00 COMPZ RPCO Load equipment onto Champion for backhaul to OSK dock. 20:00 00:00 4.00 COMPZ RPCOh Prep rig to skid 01/18/2008 00:00 00:00 24.00 COMPZ RPCO Skid unit, RD mast, ladder and work basket. Load onto Champion for backhaul 01/19/2008 00:00 00:00 24.00 COMPZ RPCO Disassemble CUDD rig, back load it onto the Champion. Continue to clean and or anize for next load. 01/20/2008 00:00 00:00 24.00 COMPZ RPCOti Prep for next Champion load, clean decks and remove plywood wind walls around drill deck. 01/21/2008 00:00 16:00 16.00 COMPZ RPCOh OTHR Continue to organize equipment, and load out on Cham ion 16:00 00:00 8.00 COMPZ RPCO MIRU PWS, pulled 4.5"dummy SSSV. Attempt to RIH w/ 4.5" PX plug body w/ no packing as a catcher sub. Unable to make past 3604' KB. SD due to high winds, will resume in the mornin . 01/22/2008 00:00 00:00 24.00 COMPZ RPCO Load various small items onto the Champion, start pressure washing deck areas. 01/23/2008 00:00 00:00 24.00 DEMOB MOVE DMOB P Continue Demob of workover equipment. Stage remaining equipment on work deck for offload to Champion. Pressure wash work deck. Pre lafform for u load/offload. 01/24/2008 00:00 00:00 24.00 DEMOB MOVE Continue demob operations. 01/25/2008 00:00 00:00 24.00 DEMOB MOVE Continue DEMOB. Post workover S/L work. 01/26/2008 00:00 00:00 24.00 DEMOB MOVE Continue DEMOB. Post workover S/L work. 01/27/2008 00:00 00:00 24.00 DEMOB MOVE Continue demob. Complete post workover S/L work. 01/28/2008 00:00 00:00 24.00 DEMOB MOVE RIG-UP PTS FLOWBACK EQUIPMENT TO NCI# A-04. START FLOWBACK. SHUT DOWN FLOWBACK AT 19:00 DO LACK OF MAN POWER. NO CHOPPER ALL DAY DO TO WEATHER. 01/29/2008 00:00 00:00 24.00 DEMOB MOVE Complete platform clean up. Start 24 hour flowback o erations. 01/30/2008 00:00 00:00 24.00 DEMOB MOVE Continue flowback on NCI # A-04 01/31!2008 00:00 00:00 24.00 DEMOB MOVE Flowback suspended. Unable to get W/L crew on chopper due weather. Pollard needed to break KOIV flapper valve above GP assembl . 02/01/2008 00:00 12:00 12.00 DEMOB MOVE Stand by for chopper with Pollard w/I crew. Page 13 r~F 1A l I Time Logs Da e _ From _To Dur _ S Depth E. De~~th Pha e Code Subcode T COM _ __ 02/01/2008 12:00 15:00 3.00 DEMOB MOVE MIRU Pollard equipment 15:00 17:00 2.00 DEMOB MOVE RIH w/ 1.75" DD bailer (chisel btm to _ Baker KOIV flapper valve @ 4477'kb. Jar down and brake flapper, continue in hole tag .bull nose of GP assembly 4701'kb. POOH. 17:00 00:00 7.00 DEMOB MOVE Rig-up PTS equipment. Continue with flowback o erations. ----- - --- f~~ga't4of'f4 Well Name Pre 2008 Survey Location NAD27 ASP 4 Northing Easting Post 2008 Survey Location NAD27 ASP4 Northing Easting Distance Moved A-01 NCI 2,586,726.69 332,100.19 2,586,726.40 _ 332,102.26 2.09 _ NCI A-02 _ 2,586,722.85 332,108.29 _ 2,586,721.16 332,111.27 3.43 NCI A-03 2,586,728.60 332,106.22 2,586,728.31 332,109.43 _ _ 3.22 NCI A-04 2,586,719.62 _ 332,105.09 _ 2,586,718.58 332,108.09 3.18 --- NCI A-05 2,586,725.55 332,110.17 2,586,725.14 332,111.79 1.67 NCI A-06 2,586,719.66 332,102.09 2,586,719.22 332,104.19 2.15 NCI A-07 2,586,727.79 332,103.73 2,586,728.78 332,105.40 . 1.94 NCI A-08 2,586,720.56 332,098.31 2,586,722.44 332,101.65 : 3.83 NCI A-09 2,586,666.58 332,039.08 2,586,667.35 332,040.44 1.56 NCI A-10 2,586,670.21 332,040.91 2,586,673.71 332,044.17 __ 4.78 NCI A-10A - 2,586,670.21 - -- 332,040.91 - 2,586,673.71 332,044.17 __ 4.78 __ _ NCI A-11 2,586,670.23 _ 332,039.14 2,586,677.01 332,041.75 7.27 NCI A-12 2,586,722.73 331,947.80 2,586,723.59 331,994.15 _ 46.36 NCI A-13 _ 2,586,734.88 _ __ 331,993.50 2,586,733.15 331,995.48 2.63 NCI B-01 2,586,730.03 331,999.80 2,586,723.04 331,998.16 7.18 NCI B-01A 2,586,730.03 331,999.80 2,586,723.04 331,998.16 7.18 NCI B-02 2,586,731.14 331,999.29 2,586,729.60 332,001.86 3.00 NCI B-03 2,586,731.69 331,986.37 2,586,726.81 331,991.70 7.23 NCI B-03PB1 2,586,731.69 331,986.37 2,586,726.81 331,991.70 7.23 ~~~~ APB a ~ zoos ~~ ~ ~ ~ • . r~ REV DATE BY CK APP ESCRIPTION REV DATE BY C P DESCRIPTION I 2/29/08 SAS KW,[a MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADO MUD LINE ELEV., SHT.3 ~ ~ 36 31 g' T 12 IU ~ ~ ~ a 31 32 '~2 ~~ 1 6 T 11 N 6 5 N ,.. Ao g. KMS' SLC. 6 1206' SCALE: !"-1320' ' ~ ~ o ~ ~ 6 6 5 12 7 7 8 GENERAL NOTES: .~~~~ 0~ ,q~ ~~~/ ~ I. SEE SHEET 3 FOR COORDINATE TABLE •''•~S/r-~1 i '~P '' ~ ~•~'• '. ' ~ 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND ~ ~ 9 ~ ~~ ~ . ~ ~ VERTICAL SURVEY DATA : ~j 49th d ~ 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED ~"'°`""""""""""""""""""4""'~ VALUES. / ....................................... ... ..~ . ~ KENNETH W. AYERS ~~ ~• <~"~ '~ • ~1 ; ~ Es 8535 ~ • SURVEYOR'S CERTIFICATE • ~ ~op•• .• .•~o ~ , I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND ,~~~~~~ ~=~~~~~~ LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DONE BY LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF & assoclATES, INC. FEBRUARY 28, 2008. SURVEYORS ENGINEERS PLANNERS 907 ~ PHONE 272 5451 J : f - ~~ AREA: MODULE: UNIT: ConocoPhilli s NORTH C°OK ~N~ET p TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUNT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 ~g-~~5 /-~S BU~L_T 1 of 3 1 r~ REV DATE BY CK APP SCRIPTION REV DATE BY CK P DESCRIPTION I 2/29/08 SAS K WA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 9 ~ ,~r ~ ~ a4; ~ ~ 9 yOS~ ~ RR g .wl "° so s. te'a' ~aS scc a ~~ ~~ ~ o o '~~ SCALE: 1"-30' a9 aQ. 0 ESD 600 -50 ESD 600-51 O A13 • I p •B2 B3• AB A•A• p5 • • • A3• AB AI BI : •A5 • A4 A2 WELL HOUSE 2 Op• zp A1Op LEGEND: 5 p • 3 A • WELL p WELL CONDUCTOR 0 ESD (EMERGENCY SHUT OFF VAL VEJ GENERAL NOTES: I. SEE SHEET 3 FOR COORDINATE TABLE 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND VERTICAL SURVEY DATA LOUNSBURY 3. NO WELLS EXIST IN WELL HOUSE N0. 4, AND IT WAS NOT & nssoclnTES, )rrc. AS BUILT SURVEYORS ENGINEERS PLANNERS ~ ~ PHONE: /907/ 272-5451 ~.~ AREA: MODULE: UNIT: ConocoPhilli s NORT" C°OK INLET p TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 ~8-~~5 AS BURET 2 GF 3 1 1 12/29/OBI SAS I KWA I I MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 ASP ZONE 4, NAD83, FEET NAD63 GE OGRAPHIC MLLW DESCRIPTION (POINT NO.) NORTHING FASTING LATITUDE LONpTUDE ELEVATION NqU WELL TAG NO. WELL HOUSE N0.1 1001 2586492 1472018 61 04 34.38 150 57 03.71 72.0 Conductor 1 1002 2586489 1472017 61 04 34.34 150 57 03.72 73.9 B3 1003 2586485 1472019 61 04 34.31 150 57 03.67 74.1 A12 1004 2586485 1472023 61 04 34.31 150 57 03.59 73.8 B1 1005 2586487 1472027 61 04 34.33 150 57 03.52 72.0 Conductor 5 1006 2586491 1472027 61 04 34.37 150 57 03.52 73.7 B2 1007 2586495 1472025 61 04 34.41 150 57 03.57 72.1 Conductor 7 1008 2586495 1472021 61 04 34.41 150 57 03.65 73:7 A13 WELL HOUSE N0.2 2001 2586437 1472060 61 04 33.84 150 57 02.83 71.9 Conductor 1 2002 2586433 1472059 61 04 03.38 150 57 02.84 71.9 Conductor 2 2003 2586430 1472062 61 04 33.77 150 57 02.79 71.8 Conductor 3 2004 2586429 1472066 61 04 33.77 150 57 02.71 73.4 A9 2005 2586431 1472069 61 04 33.79 150 57 02.65 71.9 Conductor 5 2006 2586435 1472069 61 04 33.83 150 57 02.64 73.3 A10 2007 2586439 1472067 61 04 33.86 150 57 02.69 73.3 A11 2008 2586439 1472063 61 04 33.87 150 57 02.77 71.9 Conductor 8 WELL HOUSE N0.3 3001 2586488 1472128 61 04 34.36 150 57 01.47 73.0 Al 3002 2586484 1472127 61 04 34.32 150 57 01.48 73.1 A8 3003 2586481 1472130 61 04 34.29 150 57 01.43 73.1 A6 3004 2586480 1472133 61 04 34.28 150 57 01.35 73.0 A4 3005 2586483 1472137 61 04 34.31 150 57 01.29 73.0 A2 3006 2586487 1472137 61 04 34.34 150 57 01.28 73.0 A5 3007 2586490 1472135 61 04 34.38 150 57 01.33 73.0 A3 3008 2586490 1472131 61 04 34.38 150 57 01.41 73.3 A7 50 2586540 1472069 61 04 34.86 150 57 02.69 72.7 ESD Valve 600-50 51 2586501 1472011 61 04 34.46 150 57 03.86 72.6 ESD Valve 600-51 100 2586572 1472123 61 04 35.18 150 57 01.58 115.3 Top center helipad -101' MUD LINE SURVEY NOTES: 1. ALL COORDINATES ARE ASP ZONE 4, NAD83, US SURVEY FEET. GEOGRAPHIC COORDINATES ARE NAD83. 2. ELEVATIONS ARE IN FEET, BASED ON MLLW, REFERENCED TO DRAWING N0. MPD- TY04-2021, SHEET I OF 1, REV. 2 3. ALL AS BUILTS ARE TO THE CENTER OF EXISTING STRUCTURE. 4. WELL CONDUCTOR ARE VERTICALLY AS BUILT TD THE TOP OF A 1/4" STEEL LID, TACK WELDED TO THE TOP OF THE CONDUCTOR. 5. WELLS ARE VERTICALLY AS BUILT TO THE TOP OF THE LOUNSBURY LOWEST HORIZONTAL FLANGE ON THE WELL. & ASSOCIATES, Irrc. SURVEYORS ENGINEERS PLANNERS ~ ~ PHONE: (9071 272-5451 y,.~ AREA: MODULE: UNIT: ConocoPhillips NORTH COOK INLET TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 ~~~~5 AS BU~~T 3 of 3 1 A-4 ~ Page 1 of 1 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, February 29, 2008 7:54 AM To: 'Braden, John C' Cc: Tyonek Supervisor, 'AOGCC North Slope Office' Subject: RE: NCIU R-04 (169-018) John, It would seem that you are conducting well work with personnel in attendance. That is allowed as I understand the guidelines. If continued problems are experienced, keep us informed. A request, please include the permit number when referring to wells. It helps with the filing, etc. Call or message with any questions. Tom Maunder, PE AOGCC .._. __ _........,_~..... From: Braden, John C [mailto:John.C.Braden@conocophillips.com] Sent: Friday, February 29, 2008 7:41 AM To: Maunder, Thomas E (DOA) Cc: Tyonek Supervisor subject: A-4 ,~~~'~ FEB 2 ~ ZDO~ Tom- We are working on getting NCIU A-4 back on line after a through tubing gravel pack. It looks like the SSSV may not be opening fatly. Can we flow the test the well without the valve for a day without AOGCC approval or do we need to request a variance? John Braden 2/29/2008 STATE OF ALASKA ""~~07 QIL AND GAS CONSERVATION CO-MM1SStON ROPE Test Report Submit to: Contractor: Cudd R~ No.: 136 DATE: 1/5/2008 Rig Rep.: BrowNGreen Rig Phone: 776-2081 Rig Fax: 776-2044 Operator: CPAI Op. Phone: 776084 Op. Fax: 776-2044 Rep.: Shotenski/Freebom Field/Unit & Well No.: NCIU A-04 PTD ~# 169-018 Operation: Drlg: Workover: X Explor.: Test: initial: Weekly: X Bi-Weeic~r Test Pressure: Rams: 2502500 Anr~ar. 250125t}t? Valves: TEST DATA MISC. INSPECTIONS: Test Result Test Resultf Location Gen.: P WeN Sign P Housekeeping: Drt. Rig P PTD On Location P Hazard Sec. P Standing Order Pasted P BOP STACK: Quantity Size Test Resat Annular Preventer 1 7" 5M F Pipe Rams 1 2-7/8" P Lower Pipe Rams 1 2-718" P Blind Rams 1 7" 5M F Choke Ln. Valves 1 3-1f8" P HCR Valves 1 3-i/8" P Kil! Line Valves 2 3-~l8" P Check Valve 0 NA FLOOR SAFETY VALVES: Quantity Test Re Upper Ketiy 0 NA Lower Kerr _ 0 NA Bati Type 2 P Inside BOP t P CHOKE MANIFOLD: Quantity Test Result No. Values 11 P Manual Chokes 1 NT Hydraulic Chokes 1 NT ACCUMULATOR SYSTEM: Tme/Pressure Test Result System Pressure 3000 P Pressure After Ck-s~e 2250 P MUD SYSTEM: Visual Test Alarm Test 200 psi Atta~ed 12 sec P Trip Tank F F Futi Pressure Attained 43 sec P Pit Level Indicators P P B~ Switch Covers: AA stations P Flow indicator P P Niter. E3ottles (avg}: 2400 Meth Gas Detector P P H2S Gas Detector P P Test Results Number of Failures: 0 Test Ttm~e: 9 Hots Componer~ tested 22 Repair or replacement of ement vaN be maw ~ Notify the North Slope Inspector 659-3607, foMovr with written cor~matiorr to Superv~er at: Remarks: YES X NO Date 01/03108 Time 19:00 start 11412008 Fu~h BOP Test (for rigs} ~, ~~,N ~~ '~ ~~~~ BFL 11/28/07 By Witness Chuck Scheve 'a _.. Cudd 136 1-5-08 ptd 169-018.x1s ~ ,f ~~ "-fir .~.,~. . *P, • • d ~ ~ SARAH PALlN GOVERNOR _~..1 ' 1~T ~1~~t7~SA ~ui ~ i7rt>•1sa7T 333 W. 71hAVENUE, SUITE 100 C0111SERQ~~'IOl~ CO~~'IISSI~l~. ANCHORAGE, ALASKA 99501-3539 e PHONE (907) 279-1433 ` FAX (9D7) 276-7542 Jim Ennis Wells Group Engineer ConocoPhillips Alaska, Inc PO Box 100360 ~,r+,~,~, ~? N 0 V $ 2Q07 Anchorage, AK 99510 Re: North Cook Inlet Field, Tertiary Gas Pool, NCI A-04 Sundry Number: 307-313 , z .._ _ . . _. . Dear Mr. Ennis: ~b~-oil 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. DATED this day of October, 2007 Encl. Sincerely, • ConocoPhillips October 9, 2007 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Application for Sundry Approval NCI A-04 Dear Commissioner: • Jim Ennis Wells Group Engineer Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1544 ConocoPhillips Alaska, Inc. submits the attached Application for Sundry Approval for the upcoming workover on the Tyonek Platform well NCI A-04. If you have any questions regarding this matter, please contact me at 265-1544. J. nnis We s Group Engineer CPAI Drilling and Wells JElskad • SID D~ I° 30~ ~ ~~ ,~~,. `•R~.~'~° STATE OF A SKA ~~ ~W ~,~.q. ALASKA OIL AND GAS CONSERVATION COMMISSION ~~ I°•; r~ ~~ `iz '~~ ~ ~~~ ~.~ ~a . APPLICATION FOR SUNDRY APPROVAL ~, .;: ~~ ~.,~ 20 AAC 25.280 1. Type of Request: Abandon ^ Suspend ^ Operational Shutdown ^ Perforate ^ Waiver ^ Other ^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Change approved program ~ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development Q -' Exploratory ^ 169-018 3. Address: Stratigraphic ^ Service ~ 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-883-20023-00 ~ 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership o r landownership changes: Spacing Exception Requires? Y2S NO Q NCI A-04 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL 17589 ~ RKB 40' /OS'~ I~.S~ // •O~ North Cook Inlet /~{~c ~ts~/' Q5 n 12. PRESENT WELL C NDITION SUMMARY /o•i~- Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ff): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7656' 6421' 4826' 4826' 5184' Casing Length Size MD TVD Burst Collapse Conductor 576' 16" 576' Intermediate 2410' 10.75" 2410' Production 7618' 7" 7618' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 4520'-5285', 5392'-7542' 3895'-4523', 4.5" J-55 2850' Packers and SSSV Type: Packers and SSSV MD (ft) Halliburton VSR pkr @ 2810' HES'FXE' SSSV 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^~ Exploratory ^ Development Q Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operat November 20, 2007 Oil ^ Gas ~ ` Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ~ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the ®~ g is true and correct to the best of my knowledge. Contact: Jim Ennis @ 265-1544 Printed Name I Title: Wells Group Engine r ," Signature ~~ Phone 265-1544 Date / ~ ~~ (y~ Commission Use Onl Sundry Number: Conditions of approval: Notify Commission so that a representative may witness Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ Other. .~5000~i\ P~~ ~C"`i~ 4 I oZ `~SO~ C'C~~..~,5''VDr-CcC,.C.^ei e~. ~~~ ~f`'rJ~`~ ~~ F ~W 4 Subsequent Form Required: 't~~ ~; APPROVED BY / ~/( ^ ~ Approved by: C MMISSIONER THE COMMISSION ~/'~ ~ I/ Datef~ >7 Form 10-403 Revised 06/2006 ~ s Submit in Duplicate • NCIU A #4 Gravel Pack CI 1-4 Sands Workover FELT Procedure Pre-rlg 1. MIRU Pollazd slickline. Pull HES `FXE' SSSV. Tag fill w/ 3" bailer. RD slickline. 2. PT IA 2500 psi w/ water. a~~,S~~~~ a ~-~5 ~~~.~.s 3. Set BPV . ~ c~c" ~. ~ ~'` ~ p t 'a'~ ~ ~~ ~ s~eo~\ ~J ~4 ~ Q'r''*e~p~C ~~ _.:.~ ac, 1. MIR.U Cudd hydraulic unit. NDWH. NU 7" BOP stack {see attached diagram} w/ 4. " & 2.875" pipe rams. Notify AOGCC 24 hours prior to BOP testing. PT BOP's 2SO12S00 psi. MASP is {281 psi}-{3969' TVD}{0.01 psilft}= 241 psi based on SBHP obtained on S/11107. Remove BPV. 2. Upland & POOH w/ 4-112" production tbg and PBR seal stem. 3. Single in w/ HES retrieving tool, jars & nine 4.75" DC's on 2.875" WTS-6 workstring. Engage HES `VSR' packer & release. POOH w/packer. 4. RIH w/ Cavins tbg pump & clean out to CIBP @ 4828' MD. S. RIH w/ Baker gravel pack BHA and set `SC' pkr. Pump gravel pack & circ clean. POOH laying down workstring & GP tools/washpipe. 6. Single in w/ Baker anchor, PBR, 3.813" `X' nipple, 4-112" production tbg, 3 GLM's & 3.813" SSSV landing nipple {--400' MD). Land tbg & install BPV. NDBOP ~ NUWH. PT IA to IS00 psi. Set BPV. 7. RDMO Cudd. Pull BPV. Past-Ris 1. RU slickline &PTS. Install GLV's to unload water from well. Install `FXE' SSSV. RD slickline. Unload well to PTS separator for cleanup. Jim Ennis Page 1 10!2612007 • NCIU A #4 Gravel P;~ck CI 1-4 Sands Workover FELL Procedure Pre_ri~ 1. MIRU P lard slickline. Pull HES `FXE' SSSV. Tag fill w/ 3" bailer. RD slickline. 2. PT IA 2500 i w/ water. 3. Set BPV. p ~~~~ 1. MIRU Cudd hydraulic a it. NDWH. NU 7" BOP stack (see at ched diagram) w/ 4.5" & 2.875" pipe rams. Notify OGCC 24 hours prior to BOP tes ~ g. PT BOP's 250/2500 psi. MASP is (281 psi)-(3969' D)(0.01 psifft)= 241 psi base on SBHP obtained on 5/11/07. Remove BPV. 2. Unland & POOH w/ 4-112" produd~ion tbg and PBR~eal stem. 3. Single in w/ HES retrieving tool, jars nine 4.7 'DC's on 3.5" WTS-6 workstring. Engage HES `VSR' packer & release. POOH pac r. 4. RIH w/ Cavins tbg pump & clean out to @ 4828' MD. 5. RIH w/ Baker gravel pack BHA down workstring & GP toolslwa 6. Single in w/Baker anchor, SSSV landing nipple (~40( psi. Set BPV. ~ 7. RDMO Cudd. Pull `SC' pl~ Pump gravel pack & circ clean. POOH laying 3.813" `X' nipple, /2" production tbg, 3 GLM's & 3.813" ). Land tbg & install V. NDBOP & NUWH. PT IA to 1500 Post-Rig 1. RU slicklin &PTS. Install GLV's to unload water from well. slickline. nload well to PTS separator for cleanup. `FXE' SSSV. RD Jim Ennis Page 1 10/9/2007 IE 390' 16" @ 676' 19 18 39.40 40.10 0 71 Hanger 10.15 4 12" BTC -Mod Pup Jt 10 3/4" @ 2410' 4.500 17 TOC 2600' CBL 9 "X" 2767' 4.500 s Single Comp. I:I: Halliburton VSR packer @ 2810' 4112" Brd X 4112" BT&C 3 "xN" 2848' 40.13 Annulus Fluid: Cook Inlet Sands 4.500 4520 - 4600 CI -1.0 70.74 RKB-SL: 116.9 4620 - 4700 CI -2.0 13 r: Tag fill @ 4682' KB' (5/11107) 2.46 Halliburton "XXO" SVLN 4732-4742 CI -3.0 5.660 4764-4814 CI -4.0 iBAttom ::::::::::::N[T::i:i:i:i:i CIBP 4828' isisisl:isl:i�,orui:::::::::::::::Bieiidrii:i: 4.500 4865-4895 CI -5.0 TOC @ 4880 Z 4908-4918 CI --5.1 NA 5.560 10 4948 -4963 CI -6.0 250' cement 4973-4980 CI -6.1 30 " 41' EZSV @ 5130 2767.38 :.:.'r;`:''"''�':::.... ::.:. COLLAPSED CASING X. 5184- 5198 CI -9.0 16" 41' EZSV@ 5220 H-40 4.500 5255-5285 CI -11.0 600 Beluga Sands 10 314" 41' EZSV @ 5346 J-66 ST&C " 5392 - 5405 a-7 1970 5578 - 5584 b-7 7" 39' 5650-5655 c-1 J-55 5728-5735 o-3 4660 5740-5745 o-3 327 6070-6080 a-9 7129' 23# 6152 -6162 f-4 BT&C 6220-6250 f-8 & 9-1 3080 6257-6262 g-2 7•• 7127' 6355 - 63BO h-1 & h-1.1 J-55 6410-6425 h-4 4660 6630 - 6640 i-7 327 7515 - 7542 q-4 PBTD 4aZa' J-55 Mod BT&C 7" @ 7618' TD -7,666' 135 19 18 39.40 40.10 0 71 Hanger 10.15 4 12" BTC -Mod Pup Jt 3.992 4.500 17 50.25 C X)Cii3 li1111PS NCIU WELL A Gas Producer FMC OCT mpletion Diagram 4.500 API* 508832002300 RKB-Drill Deck: Single Comp. FMC 4112" Brd X 4112" BT&C 4.500 RKB-THF: 40.13 Annulus Fluid: 70130 KCL methanol fluid 4.500 14 70.74 RKB-SL: 116.9 TOC: 2600' from CBL dated 04/12/69 13 WATER DEPTH: 120' 2.46 Halliburton "XXO" SVLN RKB-ML: 5.660 OD:l:l:i is :i:l:Ta i:l:i:i iBAttom ::::::::::::N[T::i:i:i:i:i i:i:Giad'e:i:i isisisl:isl:i�,orui:::::::::::::::Bieiidrii:i: 4.500 11 292.91 CASING & TUBING NA 5.560 10 293.74 2473.64 4 1/2" 12.75 lb EU -Mod Tubing 3.992 30 " 41' 390' 2767.38 1.45 Halliburton "X" Nipple 3.813 6.560 8 16" 41' 576' 66# H-40 4.500 1640 600 293 10 314" 41' 2410' 46.6# & 61# J-66 ST&C 3350 1970 531 7" 39' 79' 26# J-55 BTBC 4660 4080 327 7" 79' 7129' 23# J-55 BT&C 4080 3080 288 7•• 7127' 7618' 26# J-55 BTBC 4660 4080 40E 327 4 112" 39' 293.74' 12.6# J-55 Mod BT&C 4730 4980 135 4 112 " 293.74' ..: 2850' 12.75# J-55 Mod EVE era 4730 4980 ::ID:::: 134 19 18 39.40 40.10 0 71 Hanger 10.15 4 12" BTC -Mod Pup Jt 3.992 4.500 17 50.25 8.15 4 12" BTC -Mod Pup Jt 3.992 4.500 16 58.40 8.22 4 12" BTC -Mod Pup Jt 3.992 4.500 15 66.62 4.12 4 12" BTC -Mod Pup Jt 3.992 4.500 14 70.74 188.37 4 1/2" 12.75 lb BTC -Mod Tubing 3.992 4.500 13 269.11 2.46 Halliburton "XXO" SVLN 3.813 5.660 12 261.56 31.35 4 1/2" 12.75 Ib BTC -Mod Tubing 3.992 4.500 11 292.91 0.83 X -Over 4 12" EU -Mod (box) x 4 1/2" BTC -Mod (box) NA 5.560 10 293.74 2473.64 4 1/2" 12.75 lb EU -Mod Tubing 3.992 4.500 9 2767.38 1.45 Halliburton "X" Nipple 3.813 6.560 8 276883 31 40 4 112" 12 75 Ib EU -Mod Tubing 3 992 4.500 7 2800.23 8.65 Upper "PBR" Assembly 3.950 5.750 6 280888 2.61 Ratch Latch Seal Unit 3.950 5.560 5 2810.00 6.48 Halliburton VSR Packer - 3.880 6.870 4 2816.48 31.41 4 12" 12.75 Ib EU Tubing 3 992 4.500 3 2847.891.51 Halliburton "XN" Nipple 3.726 6.660 2 2849 40 0.66 Re-entry Guide 3 951 5562 1 2850081 1 End of Tubing Well History April 1969 - Original Completion - Cl 1.0,2.0,3.0,4.0,5.0,5.1,6.0,6.1,9.0,11.0, and Beluga o-1 thru q-4 Commingled 4"X3-1/2" tubing set at 4761' with packers at 4722' and 4426' with Cl 1-2 sleeve open August 1994 Workover- Well completed in Cl 1-4 Reperforate/Perforate Beluga 5392'-6425' 12 SPF, Reperforate Cl 4520'-5285' 12 SPF except Cl 5.1 DST 3 Cl 6.0 & 6.1 tested 200 MCFD and 960 BWPD (3200 Cl) October 99 - Top of Fill 4745' June 4, 2001 - Tag fill @ 4698 WLM May 13, 2002 - Tag fill @4688 WLM May 12, 2006 - Tag fill @4555' RKB during SBHP Survey June 2006 - Tag fill (8 4596 RKB. CCT FCO to 4808' CTMD. Sept 14, 2006 - Tag fill @4736' RKB for SBHP survey. May 11, 2007 - Tag fill @ 4682' RKB for SBHP @ 4600'(281 psi). Updated : 9/2512007 By: Jim Ennis PBTD: 4,826' Well: North Cook Inlet Unit No. A-04 Location: Lower Cook Inlet, Alaska NCIU WELL A~Froposea Completion API# 508832002300 TOC ~ 4880 390' 16" ~ 576' 10314"@2410' TOC @ 2600' CBL 3.813"'X' nipple 'SC' packer ~ -4420' Cook Inlet Sands Excluder Screens 4520 - 4600 CI-1.0 4620 - 4700 CI-2.0 4732 - 4742 CI-3.0 4764 - 4814 CI-4.0 CIBP ~ 4828' 4865 - 4895 CI-5.0 4908 - 4918 CI--5.1 4948 - 4963 CI-6.0 4973 - 4980 CI~.1 ezsv ~ s1 so COLLAPSED CASING 5184 - 5198 CI-9.0 EZSV @ 5220 5255 - 5285 CI-11.0 Beluga Sands EZSV ~ 5346 5392 - 5405 a-7 5578 - 5584 b-7 5650-5655 c-1 5728 - 5735 c-3 5740 - 5745 c-3 6070 - 6080 a-9 6152 - 6162 f-4 6220 - 6250 f-8 8 g-1 6257 - 6262 g-2 6355 - 6380 h-1 8 h-1.1 6410-6425 h-0 6630 - 6640 i-7 7515-7542 q-4 LADa111V Or I 30 " VOanu 41' 390' 16 " 41' 576' 65# H-40 1540 600 293 10 314 " 41' 2410' 45.b# 8 51 # J-55 BT&C 3350 1970 531 7 ~~ 3g• 79' 26# J-55 BT&C 4650 4080 33~ 7 " 79' 7129' 23# J-55 BTBC 4080 3050 2"~: 7" 7127 7618' 26# J-55 BT&C 4660 4080 32- j~ 400 12.6# J-55 PJlod BT&C 4730 4980 13 7 4.4"'0 12.75# J-55 ~ ~r aid 4730 4980 1~, N0:' ;:709 I'E-Cil fh .., .: i : : 1005cri oh. ,:.., ' ' 14 f1D April 1969 -Original Completion - CI 1.0,2.0,3.0,4.0,5.0,5.1,6.0,6.1,9.0,11.0, and Beluga c-1 thru q-4 Commingled 4"X3-1/2" tubing set at 4761' vrith packers at 4722' and 4426' with CI 1-2 sleeve open August 1994 Workover -Well completed in CI 1-4 Reper`orate/Perforate Beluga 5392'-6425' 12 SPF, Reperorate CI 4520'-5285' 12 SPF except CI 5.1 DST 3 CI 6.0 & 6.1 tested 200 MCFD and 960 BWPD (3200 CI) October 99 -Top of Fill 4745' June 4, 2001 -Tag fill @ 4698 WLM May 13, 2002 -Tag fill X4688 WLM May 12, 2005 -Tag fill @4555' RKB during SBHP Survey June 2006 - Tag f 11 @ 4596' RKB. CCT FCO to 4808' CTMD. Sept 14, 2006 -Tag fill @4736' RKB for SBHP survey. May 11, 2007 -Tag fill @ 4682' RKB for SBHP @ 4600' (281 psi). ---;.~ 7" @ 76'. 8' PBTD: 4 826' I TD 7sss' rWell: North Cook Inlet Unit No. • • ~L ~~ iii +~' -~'~ "~~ ~-1;' « 'fie ~. ~~~ ~ ~~ C Maunder, Thomas E (DOA) From: Ennis, J J (J.J.Ennfs@conocophillips.com] Sent: Monday, Octot~r 22, 2007 7:20 AM To: Maunder, Thomas E (DQA) Cc: AHsup-Drake, Sharon K Subject: Emaiting: NCtU A #4 t=EL1 Procedure 1d-22-07.doc Attachments: NCtU A #4 FEt_1 Procedure 10-22-07.doc NCIU A #4 FEL1 Praedure 10-22... «NCIU A #4 FELL Procedure 10-22-07,doc» Good morning Tom, You are correct, there is a typo in the A #4 procedure submitted. Workstring will be 2.875" so that we don't have to clean up another workstring after finishing A #3. Corrected copy of procedure attached. Sorry for the confusion. Jim Ennis j.j.ennis@conocophillips.com (907)265-1544 (W) (907)632-7281 (C) 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1 Operations performed' Operat,on Shutdown__ Stimulate Plugging __ Pull Tub,ng .X. Alter Casmng Repair Well 2 Name of Operator' 5. Type of Well Phdhps Petroleum Co Development X 3 Address Exploratory 6330 W Loop South Stratlgraphmc Bellmre, Texas 77401 Serwce 4 Location of well at surface: Leg 3, Slot 4 PPCo Tyonek Platform 1259' FNL & 1086' FWL Sec6-TllN-R9W North Cooklnlet, Ak. At top of productive interval 4520' MD 3895' TVD 2539' FNL & 2280' FWL Sec6-TllN- Rgw At effective depth 4520' MD 2539' FNL & 2280' FWL Sec6- T11N- R9W At total depth 4828' MD 2739' FNL & 2611' FWL Sec6-TllN-R9W 3895' TVD 4147' TVD Perforate x Other 6. Datum elevation (DF or RKB) RKB 116 Feet 7 Unit or Property Name North Cook Inlet Unit 8. Well Number A-04 9 Permit Number / Approval Number 69-18 94-176 10 APl Number 50-883-20023 11. Field / Pool Cook Inlet / Beluga 12 Present well condition summary Total Depth measured 7,656 feet true vertical 6,412 feet Effective Depth measured 4,520 feet true vertical 3,895 feet Plugs (measured) Junk (measured) "= ORIGIN/ W, rehne tools @ 5,172' Casing: Structural Conductor Surface Intermediate Production L~ner Length S~ze Cemented Measured Depth 30 " Driven 390 16 " 545 sx CI "G" 576 10 3/4" 900 sx CI "G" 2,410 7" 1252 sx CI "G 7,618 True Vertical Depth 39O 576 2,253 6,381 Perforation Depth' measured 4520' - 7542' true vertical 3895' - 6320' Tubing (s~ze, grade and measured depth) Packers and SSSV ( type and measured depth) 13 Stimulation or cement squeeze summary: Intervals treated (measured). Treatment descrlphon ~ncludlng volumes used and f,nal pressure 4 1/2" 12 6 Ib/ft J-55 Mod BT&C Tubmg 4 1/2" 12.75 Ib/ft J-55 Mod EUE 8rd Tubmg Halhburton "XXO" SVLN at 259'. Halliburton "VST" packer at 2810' 39-294' 294-2850' RECEIVED JAN 2 7 1995 ~)il & Gas Cons. Commission '""-~. Anch0r~ 14 Representahve Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Prior to well operation: 0 9400 Subsequent to operation O 14900 Water-Bbl Casing Pressure 33.78 25 0.6 0 Tubing Pressure 923 06/10/94 967 11/O3/94 15 Attachments' Copies of Logs and Surveys Run __ Dady Report of Well Operations 16 Status of Well Classlhcatmn as' X Od Gas X Suspended Service 15 I hereby certify that the foregoing is true and correct to the best of my knowledge: Signed /~Z.,~** f~ 2~_.~j~..t_ Title Principle Eng,neer Form 10-404 Rev 06/15/88 Date 19-Jan-95 SUBMIT IN DUPLICATE L PHILLIPS PETROLE~ DAILY REPORT SUMMARY PAGE:I WELL:North Cook Inlet Unit No. A-4 FIELD:COOK INLET NORTH CNTY/STATE:TYONEK OFFSHORE/ALASKA RIG:Pool Arctic Alaska/Pool Arctic Alaska AFE#:P-V195 AUTH COST:$1,496,300 DATE DEPTH RPT NO I~ OPERATIOffS SUH4ARY DAILY CC)ST GUN COST EVENT TYPE: Workov®r 08/18/94~ 7,618 1 8.5 SKID RIG TO NClU A-&.CHANSE TREE CAP & R/U RISER & TEST. S28,550 S28,550 PULL SCSSV.GAUGE RING RUN TO 5155.AHERADA BOMB RUN TO 5155 KILL bELL.INSTALL BARRIERS.Nfl) TREE & N/U RISERS & BOPS. 08/19/94 '"?,618 2 8.5 INITIAL BOP TEST.CIRC DM TBG.PULL BPV.PULL PLUG FROM SCSSV $66,007 S?`6,558 ' NIPPLE 8 287.RELEASE PER & SEAL ASSEHBLY.CBU.C)BSERVE.PULL TBG.hiELL SblABBING.CBU.PULL & L/D TUBING.P/U PKR HILLING ASS. TIH.CBU.HILL UP I~ PKR.CBU.TOff. FULL RECOVERY.P/U 6N SHOE & 08/20/9~ 7,618 '3 8.5 $62,381 $1t'6,939 UASHPIPE TO RECOVER STRIP GUN 8 5172.TIN.NO SUCCESS.TOff.SH(E SHOOTH.TOff.PU HILL.TIN.HILL TOS201.LOOSE.TIH TO 6601.CBU.TOff 08/21/94 7,618 ' `6 8.5 TOH.TIH hi/BIT & SCRAPER.CBU.TOff.CUT LINE.P/U NILL.TIH.REAN S50,065 $167,,00~ TITE SPOT 0 5200.TIH.CBU.TOff.REAH TITE SPOT 05200.TOfl. SAFETY HTG.PU `6 5/8 TCP GUNS.TIH.CORR.TOP SHOTG5392.RU&TEST.PLJflP H2 08/22/W. 7,618 5 8.5 PERF BELUGA SANDS (5392-6~25).FLC~ FOIl CLEANUP.SHUT IN. KILL $56,870 ' S223,87& ' ~LL.TOff WGUNS & TCX:)LS.CLEANOUT RUN b//6 1/8 BIT & HILL TO 6601.CBU.TOff.P/U EZSV.TIH TO 53~0 & SET.TOH.P/U TCP GUNS. 08/23/9`6 7,618 6 8.5 TIH hi/TCP GUNS.CORRELATE DEPTH hi/IdL.R/U TEST EQUIP & TEST. S2`63,892 $667~76D -- SAFETY HTG.PERF Cl SANDS.SURGE & FLOU.S/I & KILL IdELL.TOH.L/ D GUNS.BIT & SCRAPER TO 5340.P/U TEST TOOLS.TIH.TEST C-11. 08/2`6/91, 7,618 7' 8.6 DST #3(CI-11/5255-5285).KILL hiELL.L/D SURFACE EOUlP.TIH.TAG $68,280 $516,~ EZSY ~5~O.CBU.TOH.L/D TEST TOOLS.P/U EZSV.TIH & SET 85220. TOH.P/U TEST TOOLS.TIH.SET PKRO5167.OPEN ~LL.RU COILED TBG. 08/25/9`6 7,618 8 8.6 RU i 3/,6" COILED TBG UNIT.TEST ALL LINES,BOPS & COIL.JET ON $68,686 $56~,730 hiELL.DID NOT FLOId. FILL TUBING ld/&5 BBLS.STRING CLEAR.RIH.,JET ON C/ELL.DID NOT KICK 0FF.75.`6 BBLS REC.KILL klELL.TOH hi/TOOLS 08/26/94 7,618 9 '" 8.6 TOff/L/D TEST TOOLS.TIH/hi BIT & SCRAPER.hiASH & RENd 5i50-5220 $106,239 $670,969 CIRC & COMD HUD.TOfl. TIH & SET EZSV 0 5030.TOH.hiEEKLY BOP TEST.P/U TEST TOOLS F/DST 5(`6948-`6980)TIH.SET PKR~5036.TEST. 08/27/94 ?,618 10 8.6 DST '#SCCI-6).KILL klELL.TOff. L/D TOOLS/P/U BIT & JUNK BASKETS. $61,672" $71'2,640 TIH.DRILL EZSV ~5030. RIH TO 5179 TAG FILL CLEAN OUT TO EZSV 8 5220 DRILL OM SAHE.CAHE LOOSE.CHASING DOUN HOLE g 5270t. 08/2~/94 7,618 11 8.6 CHASE EZSV TO 5376.DID NOT TAG EZSV a ~340.SidEEP & CBU.TOH. $37,249 $749,889 NO HARKS ON TOOLS.TIH k//NEhi BIT.DRILL TO 54`61 SUSPECT OF DRILLING OPEN HOLE. POH TO 5150. CIRC, hiAITING OH SIgS TOOLS. b~/29/9`6' 7,618 12 8.6 RIH hiITH CET LOG hiENT OUT OF CSG AT 5180'.RUN BIT & SCRAPER S9`6,511 S8`6~,399 TO 5170. SET EZSV a 5130. PUHP 4.5 BBLS CEHENT BELOU EZSV PUflP 9 BBLS CEHENT ABOVE EZSY TO `6880. 08/30/94 7,618 13 8.6 HADE UP BIT & SCR RIH TO '4880 POH RIH hi/ CIBP SET g 4834 POH S58,319 S902,718' RIH hi/ VST PKR ATTEHPT TO SET PACKER HAD SUSPECT OF COIdEING OFF DP hiHEN SETTING.HADE UP RETRIEVING TOOL RIH.POH hi/ PKR. 08/31/94 7,618 14 8~6 SET PRO0 PKR/POOH hi/SETTING TOOL/TIH hi/4.5" TBG/DISP ANNULUS $26~,254 $1,166,972 hi/PKR FLUID/SET BPV/ND BOP-RISER/MU TREE & FLOIgLINE/RU COIL TBG/TIH hi/COIL JETTING hi/NITROGEN ~REPORT TIHE 09/01/94 7,618 15 8.6 JET IN hiELL/FLOId FOR CLEANUP/TURN OVER OT PROOUCTION/RELEASE S106,313 $1,27i,286 RIG 1200 8/31/94. PREPARE SKID TO A-6 DAYSUH.RP1 ~2/07/94 RECEIVED JAN 2 7 1995 ~))1 & Gas Cons. Commi~sip~ FINAL WELL TOC O 4880 39O 576 10 3/4" {~ 2410 260(r Halhburton VST 281o' Cook Inlet Sands 4520 - 4600 C1-1 4620 - 470O Cl-2 4732 - 4742 CI-3 4764 - 4814 CI-4 ClBP {~ 4828' 48~5 - 4895 CI-5 4908 - 4918 4948-4963 4973. 4980 EZSV 0 5130 Cl-6 5184 ~ 5198 CI-9 EZSV ¢~ 5220 5255 - 5285 Beluga Sands EZSV ¢~ 5346 C1-11 BPV(MaU~T~In, OD) COMPLETIOM--XMAG~M FMC OCT FMC 4 1/2" 8rd X 4 1/2" BT&C 70 1 30 KC[, methanol fluid Annulm Fluid: 2600' from CBL dated 04/12/69 Production Cming: 41 576 65 lb/it 41 2,410145.5 & 51 lb/fi] 39 791 26 lb/it 79 7,1291 23 lb/it 7,127 7,6181 26 lb/it WATER DEPTH: 120 ' 39 294 .. H.40 .I-55 BT&C J-55 BT&C J-$ 5 BT&C J-55 BT&C 294 2,850 12.6 lb/it I J-55 I Mod BT&C 12.75 lb/it J-55 Mod GUI= PRODUCTION TUBING STRING 4730J 49801 135 47301 4980 J 134 , ~ l, OD 0.00 39.40 39.40 0.70 40.10 10 15 50 25 8.15 58.40 8.22 66.6; 70.74 4 12 188.37 259.11 2 45 261.56 31.35 292.91 0 83 293.74 2473,64 2767.38; 1.45 2768.83 31.40 2800 23 8.65 Elcvatton Han~cr 4 1/2" BTC-Mod Pup Jt 4 1/2" BTC-Mod Pup Jt 4 1/2" BTC-Mod Pup Jt 4 1/2" BTC-Mod Pup Jt 4 1/2" 12.75 lb BTC-Mod Tubm$ Halliburton "XXO" SVLN 4 1/2" 12.75 lb BTC-Mod Tubing X-Over 4 1/2" EU-Mod (box) x 4 1/2" BTC-Mod (box) 4 1/2" 12.75 lb EU-Mod Tubing Haihburton "X" Nipple 4 1/2" 12.75 lb EU-Mod Tubin8 Upper "PBR" Assembly 3.992 3992 3.992 3.992, 3.992 3.813 3.813 4 1/2" 12.75 lb EU Tubing 3.950 2808.88 2.61 Ratch Latoh Seal Umt 3.950 2810.00 6 48 Halliburton VSR Packer 3 880 2816.48 31 41 3.992 1.51 0.68 2847.89 2849.40 2850.08 Halliburton "XN" Nipple Re-entry Guide End of Tubing 3.725 3.951 5728 - 5735 57~.5745 7515 - 7542 "~ 7818 PRODUCTION PERFORATION INTERVAI~ COOK INLET SANDS BELUGA SANDS C1-1 4520. 4600 "Upper' 5392 - 54~ ** Cl-2 4620 - 4700 5578 - 5584 ** CI-3 4732 - 4742 5550 - 5655 Cl-4 4764. 4814 5728 - 5735 5740 - 5745 "Middle" 6070 - 8080 NOTE: All perf8 below shut off ~nth CIBP o152 - 8162 CI-5 4865 - 4895 6257 - 62~2 4908. 4918 8355. 6380 Cl-6 4948 . 4963 6410 - 6425 4973 - 4980 6830 - 8640 CI-9 5164 - 5198 C1-11 5255 - 5285 7515 - 7542 ** New Perfs PBTD: 4,826' ]$upv: ITbl~ Wt. 4 1/2" - 12.6 and 12.75 Ib/R Well: North Cook Inlet Unit No. A-04 I Location. Lower Cook Inlet, Alaska F~eid' Cook Inlet Unit November 15, 1994 MPG RECEIVED Gas Cons. Commissien PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 EXPLORATION AND PRODUCTION GROUP COMPANY BELLAIRE TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING June 28, 1994 North Cook Inlet Unit "A-04" Phillips Tyonek Platform "A" North Cook Inlet, Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: North Cook Inlet Unit A-4 Workover Program Attached are three copies of the Application for Sundry Approvals, form 10-403, and three copies of the tentative workover program for the workover of the A-04 well on the North Cook Inlet Unit. Included in the program are the BOP schematic and the well control policy for the workover. If you have any questions concerning this workover or need any additional information please contact Paul R. Dean at (713) 669-3502. D. C. Gill, Manager Drilling and Production Engineering CC: V. R. Chamberlain M. L. Jones (r) P.,E~I~. Dean J.F. Mitchell Central files RECEIVED JUN 3 0 !994 A~sk~ 0d & (~as Cons. Commission Anch0ra~e APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend Operation Shutdown. Reenter Suspended Well Alter Casing __Repair Well .. Plugging Time Extension Stimulate Chan~e Approved Program Pull Tubin~ X Variance Perforate X Other ~ (add perf.) 2. Name of Operator: phillips Petroleum Co. 3. Address: 6330 W. Loop South Bellaire~ Texas ,77,401 4. Location of well at surface: 1259' FNL & 1086' FWL At top of productive interval: 2539' FNL & 2280' FWL At effective depth: 2539' FNL & 2280' FWL At total depth: 3896' FNL & 3744' FWL Sec 6 - T11N - 12. Present well condition summary: Total Depth: Leg 3, Sec 6 - T11N - 4520' Sec 6 - T11N - 4520' Sec 6 - T11N - 7656' 5. Type of Well Development Exploratory Stratigraphic Sen/ice Slot 4 PPCo. Tyonek Platform Rgw North Cook Inlet, Ak. MD 3895' TVD RgW MD 3895' TVD R9W MD 6412' TVD Rgw 6. Datum elevation (DF or RKB) RKB 116 Feet 7. Unit or Property Name North Cook Inlet Unit 8. Well Number A-04 9. Permit Number / Approval Number 10. APl Number 50-883-20023 ii 11. Field / Pool Cook Inlet / Beluga measured true vertical 7,656 feet Plugs (measured) 6,412 feet PBTD: 7,575' Effective Depth: measured true vertical 4,520 feet Junk (measured) 3,895 feet Wireline tools @ 5,172' Casing: Structural Conductor Surface Intermediate Production Liner Length Perforation Depth: measured Size Cemented Measured Depth True Vertical Depth 30" Driven 390 390 16" 545 sx CI "G" 576 576 10 3/4" 900 sx CI "G" 2,410 2,253 true vertical 7" 1252 sx CI "G" 7,618 4520'- 7542' OR'! IXAL 3895' - 6320' R 'EIVED jdN 50 1994 Alaska Od & Gas Cons. Commissior~ Anchor_age Tubing (size, grade and measured depth) 4" 10.9 Ib/ft J-55 BT&C & 3 1/2" 9.2 Ib/ft J-55 BT&C set at 4,761 '. Packers and SSSV ( type and measured depth) Otis "RH" retr. packer @ 4,426'; Otis "WB" permanent packer @ 4722'. Otis Wireline Retrievable SSSV @ 287.88'. , 13. Attachments: Description Summary of Proposal X Detailed Operations Program __ BOP Sketoh X 14. Estimated Date for Commencing Operations: , Jul}, 20r 1994 16. If Proposal was Verbally Approved: Oil Gas Name of Approver Date Approved Sen/ice ,,, 17.1 hereby c~~g is true and correct to the best of my knowledge: Signed/~'~_ D.C. Gill ,,Title Drip. & Prod. En~r. Manager FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so Representative may witness Plug Integrity .. BOP Test Location Clearance Mechanical Integrity Test Subsequent Form Required 10 - 15. Status of Well Classification as: Suspended Date ~/'~¢ Approved b}, Order of the Commission Form 10-403 Rev. 06/15/88 ORIGINAL SIGNED BY RUSSELL A. DOUGLA~I~ Approved Copy Returned ..... Commissioner , Date'7-/- ~ ~r SUBMIT IN TRIPLICATE June 28, 1994 Houston, Texas North Cook Inlet Unit "A-4" North Cook Inlet Unit Tyonek County, Alaska Tentative Procedure lo ~ · · · · · · Kill well with 8.5 lb/gal KCl water / XanVis polymer. Fill tubing and annulus with 2 % kcl water. Bleed off pressures and monitor same. Close SSSV. Skid rig over No. 4 slot in Leg 3. Install BPV, remove XMAS tree, NU and test 13 5/8" 10M BOP equipment. Utilize a 16 3/4" 5M x 13 5/8" 10M DSA (FMC Unihead with 16 3/4" 5M BX Clamp Hub). Test the BOP equipment as per the attached "Well Control" program. Rig up to pull tubing. Release Otis "RH" packer (4,426'). Pull 4" tubing, SSSV and retrievable packer with tailpipe and seal assembly from the "WB" packer at 4,722'. Circulate out any gas from below the packer. Inspect all tubulars for "NORM" contamination. TIH with packer milling assembly. Mill over packer slips and recover Otis "WB" permanent packer. POOH. TIH with 6 1/8" bit and casing scraper for 7 "23 and 26 lb/ft casing. Clean out casing to PBTD of 7575'. Circulate hole clean and POOH. Make up and TIH with tubing conveyed perforating assembly to reperforate the existing and new Beluga Sands as follows: ** 5392' - 5405' ** 5578' - 5584' 5650' - 5655' 5728' - 5735' 5740' - 5745' 6070' - 6080' 6152' - 6162' 6220' - 6250' 6257' - 6262' 6355' - 6380' 6410' - 6425' 6630' - 6640' ** 6766' - 6776' ** 6874' - 6878' ** 6983' - 6986' ** 6995' - 6998' ** 7110' - 7118' ** 7138' - 7144' ** 7155' - 7157' ** 7429' - 7446' 7515' - 7542' New perforations RECEIVED d ~J i'4 ,,% 0 1994 ~t~.ska h~t & Gas Cons. Commission Anchorage Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. Unload well and flow for initial clean-up. 9. Kill well and POOH with perforating assembly. 10. TIH with bit and( scraper and clean out well(~o PBTD. gas until well is stable. Circulate out 11. If significant volumes of water and/or sand is produced during Step No. 8, TIH with DST tools and isolate intervals to check for water production. 12. Make up and TIH with tubing conveyed perforating assembly to reperforate the existing Cook Inlet Sands as follows: 4520' - 4600' 4620' - 4700' 4732' - 4742' 4764' - 4814' 4865' - 4895' 4908' - 4918' 4948' - 4963' 4973' - 4980' 5184' - 5198' 5255' - 5285' 13. Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. 14. Unload well and flow for initial clean-up. 15. Kill well and POOH with perforating assembly. 16. TIH with bit and scraper and clean out well to PBTD. Circulate out gas until well is stable. 17. If significant volumes of water and/or sand is produced during Step No. 14, TIH with DST tools and isolate intervals to check for water production. 18. TIH with Halliburton 7" retrievable "VSR" packer with 4 1/2" tailpipe equipped as per the proposed wellbore schematic. Set packer at 4,400' with sliding sleeves at 4,700' and 6,000'. 19. Make up Halliburton packer seal assembly onto the 4 1/2" tubing. TIH with 4 1/2" tubing and SCSSV landing nipple. Land seal assembly into packer seal bore. Test annulus, then pull out of seal assembly and circulate 70/30 KCl / methanol packer fluid into annulus. Space out tubing. 20. Close SCSSV, install BPV, ND BOP equipment and NU and test 7 1/16" x 4 1/2" Xmas Tree. Remove BPV's. 21. Use coiled tubing (if necessary) and nitrogen to lower fluid level and get well kicked off. Unload well and allow clean up through the production testing equipment. Release workover rig to next well. NOTE: BHP at 3891 TVD is approx 1400 psi (7.0 lb/gal equivalent), somewhat less than the 8.5 lb/gal equivalent which will be used to kill the well during the recompletion phase. JUN 1994 0~1 & Gas Cons. Commismon Anchorage SECTION WELL CONTROL PROCEDURES This well is a category 3 well, as defined in Phillips Completion Workover and Well Control Policy. As such two barriers must be in place during nipple up and nipple down operations. For all other operations, two barriers, e.g. the BOP's, fluid column, etc. must be in place in order to conduct simultaneous operations. The BOP equipment is 10000 psi WP Class 4 as per Phillips Well Control manual. The bottom set of rams should be 5" pipe rams, the middle set will be blind rams and the top set should be variable rams. Although the BOP is rated to 10000 psi, the riser and the wellhead are rated to 5000 psi. The BOP and choke manifold should be stump tested to 3000 psi. The BOP should be tested to 3000 psi upon nipple up and to 1500 psi on a weekly basis. The Alaska Oil and Gas Conservation Commission (AOGCC) should be notified prior to conducting BOP tests. The notification to AOGCC should be made early enough for them to witness the test if they desire. The maximum surface pressure for the well is 1036 psi. This pressure was obtained during the Bottom Hole Pressure Test of May 20, 1994. The well can be killed and stability maintained with 8.5 lb/gal fluid. Well control drills are to be conducted with each crew as per Phillips well control manual. Drills should be reported on the IADC daily drilling report and on Phillips Daily Drilling Report. This well produces from a series of very permeable sands. A small decrease in pressure at the perforations can result in very large flowrates. It is vital that good well control practices be followed during the course of this workover. Trip speed while POOH should be kept relatively slow to avoid any tendency to swab. Before any trip is made swab and surge calculations should be made based on the properties of the fluid in the hole. DO NOT exceed the running speed determined by the calculations. A detailed trip book comparing measured fill up requirements to the calculated requirements should be maintained for each trip. The cause for any discrepency between the actual and required fill up volume must be determined before continuing with the trip. MAINTAINING CONTROL OF THE WELL IB OF THE UPMOBT IMPORT~,NCE, TRIP ~PEED I~ ~ECOND~RY. Two perforated intervals are isolated between the Otis "RH" retrievable and the "WD" permanent packer, and there are 19 different intervals below the "WD" that are effectively commingled at the present time and cannot be isolated. Ail of the zones presently perforated in this well can be killed with water. As a precautionary measure, a line should be ran from the annulus valves on the tubing head to supply workover fluid, drillwater, or seawater. This line can be used to supply workover fluid as discussed above or as a last resort can be used to kill the well with drillwater or seawater. Pumping drillwater or seawater through the annulus valves should be considered only in an emergency situation as these fluids could result in formation damage. RECEIVED JUN 3 0 i994 ¢)Jl & Gas Cons, Commission NClU A- RISER AND BOP ARRANGEMENT . I SM ANNULAR PREVENTER 10M VARIABLE BORE PIPE RAMS 1OM BLIND RAM8 DRILLING 8POOL 3 1/2" 1OM PIPE RAMS RISER 13 6/8" 1OM X 13 6/8" 6M ADAPTER 13 6/8" 6M X 16 3/4" 6M CLAMP RISER 16 3/4" 6M X 16 3/4" 6M UNIHEAD 16" 8RD X 16 3/4" 6M CLAMP HUB RECEIVED JUN 3 0 19g¢ A~$~. OJi & Gas Co~s. Anchorage Top of Fish @ 5,172' PBTD 7575' 576 10 3/4' @ 2410 TOC@ 26~0' Cook Inle~ Sands 4520-4800 4620 - 4700 Otis WB packer @ 4722' 4732 - 4742 4764 - 4814 4865-4895 4908-4818 4948-4963 4973 - 4980 5164 - 5198 ** 5187 - 5197 5255 - 5285 Beluga 8ands 5650 - 5655 5728 - 5735 5740 - 5745 6070 - 6080 6152-8152 6257 - 6262 6410 - 6425 7515 - 7542 7" @ 7618 EXISTING WELL COMPLETION DIAGI '.,TypqOD) FMC OCT RKB-Drill Deck: 4 .,T&C RKB-TI-~ Annnlu Fluid: Salt Water with 3 bbl Methanol RKB-SL: 115.90 TOC: 2600' from CBL dated WATER DEPTH: RKB-ML: Bot~ WT Ond~ J~ ~..:t Bm, st ~ott Production C. asi~.. 41 39O 41 576 65 lb/ft H-40 60O 41 45.5 & 51 J-55 39 79 26 lb/R J-55 Tnbb 39 23 lb/ft J-55 26 ro/R J-55 BT&C BT&C 1970 9.3 lb/ft J-55 BT&C 5700 6440 PRODUCTION TUBING STRING 0.00 40.13 Elevation 40.13 41.13 291.79 296.79 441739 4418.17 4425.72 4433.72 4704.85 4707.85 4721.18 4727.09 4737.50 4749.30 4759.35 4760.65 1.00 246.75 3.91 4120.30 1.08 271.13 3.00 13.33 5.91 10.41 10.80 10.05 1.30 FMC / OCT 8' 3M 4 1/2' 8rd x4" BT&C Tubing Hanger 4" 10.9 lb/ft J-55 BT&C Tubing Otis 3 1/2" NO Ball Valve N~pple and SCSSV CAMCO 3 1/2" GLM 4" 10.9 lb/ft J-55 BT&C Tubing 4" BT&C x 3 1/2" X-OVER Camco KBM 3 1/2" GLM Otis 7" x 3" "RIP Hydraulic Set Retrievable Packer 3 1/2" 9.3 Ib/ft J-55 BT&C Tubing Otis 3 1/2" ")CO" Sliding Sleeve 3 1/2" 9.3 lb/ft J-55 BT&C Tubing Otis 3 1/2" "X" Nipple & straight slot locator Otis 7" x 4" "WB" Permanent Packer 3 1/2" 9.31b/ft J-55BT&C Tubing Otis 3 1/2" "X" Nipple 3 1/2" 9.3 lbflt J-55BT&C Tubing Otis 3 1/2" "Q" Nipple End of Tubing 3.958 3.476 2.760 2.991 3.476 2.992 2.991 2.900 2.992 2.750 2.992 3.000 2.992 2.750 2.992 2.625 NOTE: 1-11/16" Wireline Perforating Tools (42.5') leR in well at 5,172'. 8-01-88 after perforating 5,184' - 5,198'. PRODUCTION PERFORATION INTERVALS COOK INLET SANDS Gl- 1 4520 - 4600 CI-2 4820 - 4700 CI-3 4732 - 4742 Cl-4 4764 - 4814 Cl-5 4865 - 4895 4908 - 491.8 CI-6 4948 - 4963 4973 - 4980 perftflru-tub,ng ~n 1988 5184 - 5198 Cl-9 5187 - 5197 CI- 11 5255 - 5285 ] Sap~. [ Tb~ wu Well: North Cook Inlet Unit No. A-04 BELUGA SANDS 'Upper' 5650 - 5655 5728 - 5735 5740- 5745 'Middle* 6070 - 6080 6152- 6162 6220 - 6250 6257 - 6262 6355 - 6380 5410 - 5425 6630-6640 7515 - 7542 4" - 10.9 lb/ft 3 1/2" - 9.3 lb/ft ] June 09, 1994 PBTD 7575' 576 10 3/4' @ 2410 TOC @ 2600' Hallibmton VST @ 4400' Cook Inlet Sands 4732 - 4742 4764 - 4814 4865-4895 4908 - 4918 4948-4963 4973 - 4980 5164 - 5196 5255 - 5285 Beluga Sands 5392 - 5405 ** 5578 - 5584 ** 5650 - 5655 5728 - 5735 5740 - 5745 6070 - 8080 6152 - 6162 6220 - 6250 6257 - 6262 6410 - 6425 8766 - 6776 ** 6874 - 6878 ** 8983-6988 ** 8995-8998 ** 7110 - 7118 ** 7138 - 7144 ** 7155 - 7157 ** 7429 - 7446 ** 7515 - 7542 7" (~ 7618 PROPOSED WELL COMPLETIOI~'"~'IIAGRAM .kc,Type,OD) FMC OCT ~. IR[B--D_r!ll Deck: FMC 4 1/2" 8rd X 4 1/2" BT&C I R~CB- .'r~_ 4o.]3 Annulus Fluid: 70 / 30 KCL methanol fluid I RKB-SL: 115.90 TOC: 2600' from CBL dated 04/12/69 WATER DEPTH: 120]RKB-ML: Bettem [ 'WI' [ C~ade I Cona. ]. ]~uts~t ~ Colt Prodlctiol ~lJil ~: 41 390 41 576 65 ib/ft 41 45.5 & 51 lb/f~ 39 79 26 lb/ft 23 lb/ft 26 lb/ft J-55 BT&C 1540 3350 J-55 BT&C 4660 J-55 BT&C 4O8O 3-55 BT&C 466O [ Mod BT&CI 4730 39 387 12.6 lb/ft 387 12.75 lb/ft PRODUCTION TUBING STRING 0.00 40.13 Elevation 3.476 40.13 41.13 303.00 333.00 334.00 4389.00 4700.00 5303.00 7539.00 7540.00 1.00 258.87 30.00 4054.00 1.00 11.00 289.00 600.00 1.00 FMC / OCT 6' 31VI 4 1/2' 8rd x 4' BT&C Tubing Hanger 4 1/2" 12.75 lb/ft J-55 ModBT&C Tubing Halliburton 4 1/2" "XXO" SSSV Nipple and SCSSV 4 1/2" 12.75 lb/ft J-55 Mod BT&C Tubing 3.958 3.813 4 1/2" Mod BT&C x 4 1/2" Mod EUE X- OVER 3.955 4 1/2" 12.75 lb/ft J-55 Mod EUE 8rd Tubing 3.958 Halliburton 4 1/2" "X" Nipple 3.813 Halliburton Ratch-Latch Seal Adapter & Seal Bore 3.937 Howco 7' x 4 1/2 · "VST' Hydraulic Set Retrievable Packer 3.8~0 4 1/2" 12.75 lb/ft J-55 Mod EUE 8rd Tubing 3.958 Halliburton 4 1/2" "XD" Sliding Sleeve 4 1/2" 12.75 lb/ft J-55 Mod EUE 8rd Tubing Halliburton 4 1/2" "XA" Sliding Sleew 4 1/2" 12.75 lb/ft J-55 Mod EUE 8rd Tubing Halliburton 41/2" "XN" Nipple End of Tubing PRODUC~ :ION PERFORATION INTERVALS 3.813 3.958 3.813 3.958 3.725 COOK INLET SANDS BELUGA SANDS C1-1 4520 - 4600 CI-2 4820 - 4700 Cl-3 4732 - 4742 CI-4 4764 - 4814 CI-5 4885 - 4895 4908 - 4818 C1-6 4948 - 4963 4873 - 4980 C1-8 5164 - 5168 el- 11 5255 - 5285 BELUGA SANDS "Upper" 5392 - 5405 ** 5578 - 5584 ** 5650-5655 5728 - 5735 5740 - 5745 'M,ddle" 6070 - 6080 6152 - 6162 6220 - 5250 6257 - 6262 6355-6,380 6410 - 8425 6630-6640 6768 - 6776 6874 - 6878 'Lower' 7110 - 7118 7138 - 7144 7155 - 7157 7429 - 7446 7515 - 7542 ** New Perfs Well: I Supv. I Tbg Wt: 4 1/2" - 12.6 and 12.75 lb/ft North Cook Inlet Unit No. A-04 I June 28 ~ 1994 TD 656' Location: Field: Cook Inlet Umt PHILLIPS PETROLEUM KENAI, ALASKA 9961'1 P O DRAWER 66 EXPLORATION AND PRODUCTION DEPARTMENT File: P-JFS-340-77 October 20, 1977 COMPANY Alaska Oil & Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99501 Attention: Mr. Harold Hawkins Dear Sir: This is to confirm our Mr. Porter's conversation with you on October 19, 1977, relative to our having m~_~de .~th~ repairs to the high/low pilot o~CIU~ ~urface safety valve which did not'~fu~ction '~-~orrectIy~--d~ring your recent inspection. The valve is ready for re-inspection at your convenience. Sincerely, / ~. Settl~ JFS/NEP/eml ,/ Form 10-403 REV. 1-10~73 Submit "1 ntentions" In Triplicate & "Subsequent Reports" in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT---" for such proposals.) 5. APl NUMERICAl- CODE 50-283-20023 6. LEASE DESIGNATION ANO SERIAL NO. ADL-17589 7. IF INDIAN, ALLOTTEE OR TRIBE NAME WELL I..AJ OTHER 2. NAME OF OPERATOR 8. UNIT, FARM OR LEASE NAME Phillips Petroleum Company NCIU 3. ADDRESS OF OPERATOR 9. WELL NO. P.O. Drawer 66 / Kenai, Alaska 99611 A-4 4. LOCATION OF WELL Atsurface Leg 3, Slot 4, 1259' FNL, 1086.8' FWL, Sec. 6, TllN, Rgw, S.M. BHL 3896' FNL, 3744' FWL, Sec. 6, TllN, Rgw, S.M. 13- ELEVATIONS (Show whether DF, RT, GR, etc.) RKB 116' from MLLW 14. Check Appropriate Box To Indicate Nature of Notice, Re 10. FIELD AND POOL, OR WILDCAT North Cook Inlet 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See Item 4 BHL 12. PERMIT NO. 69-18 )ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF FRACTURE TREAT SHOOT OR AClDIZE REPAIR WELL (Other) ~'1 PULL OR ALTER CASING MULTI PLE COMPLETE ABANDON* CHANGE PLANS SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form,) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. 1. Rig up. Kill well with 10.0 ppg mud. Remove tree. Install 12"-3000# WP riser and 12"-3000# WP Double gate preventor and Hydril. Test BOP and riser. 2. Pull 4" tbg and retrievable packer. 3. Cleanout to 7575 PBTD. . Run combination 4 'x 3 1/2" tubing string with Otis subsurface safety valve set about 288' RKB and Otis retrievable packer set about 4470' MD RKB, and tubing set 7546' MD RKB. 5. Install tree and displace mud with water. 6. Clean up well and conduct 4 point BPT. Set hydraulic packer. Test packoff. 7. Utilize as a producer commingled in Cook Inlet and Beluga pays. Estimated start of operations is 8/16/75. 16. I hereby certify that the f~o,4'egolng Is true and correct SIGNED/ / (~'-"Y ,/" / 11. ~,'. Yorter (Thi~space for State office use) _ DATE 7115175 APPROVED BY CONDITIONS OF APPROVAL, IF ANY: T IT LE DATE See Instructions On Reverse Side PHILLIPS PETROLEUM ANCHORAGE, ALASKA 99501 ~ 515 °'D'" STREET EXPLORATION AND PRODUCTION DEPARTMENT COMPANY June 26, 1969 Mr. T. R. Mzrshall, Jr. Division of Mines & Minerals Department of Natural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska Gentlemen: As per your request, please find copies of blue line Electrical Logs for NCIU #A-l, #A-2, #A-3 and #A-~. If at all possible, these blue lines will be furnished with ~.ion Reports, in the future. Yours tr ~y, JBG: jo Attachment HILLIPS PETROLEU[~[ ' . . .. District Office Manager Ferm No P--4 REV 9-30-6? TRM ~5 API ATUA'IEF, iCAi., CODE KLV , .L~V . API 50-283-20023 HWK. I& -- STATE OF ALASKA suB.~rr LN DEPLICATE O~L AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS ADL-17589 OIL ~ GA8 WELL '~ WELL~ OTHER 2 NAME OF OPERATOR 8 LrNIT,F.~LM OR LEASE ...... Phillips Pe~ole~ Com~n7 No~h Oook Inleg Unig ADDRESS OF OPERATOR 515 "D" Street~ Anchorage, Alaska 99501 LOCATION OF WJ~LL Surface: 1259' FNL, 1086.8' FWL, Sec. 6, TI]N, R9W, S.M. Top of Pay: 2539.3' FNL, 2280.3' FWL, Sec. 6, T!qN, R9W, S.M. 9 %VELL NO 16 FIELD A2qD POOL OR WILDCAT North C9ok Inlet i1 SEC, T. R, M (BOI'TOM HOI_,E O~~ Sec. 6~ TllN~ R9W, S.M. PERMIT NO 69-18 13 REPORT TOTAL DEPTH AT END OF MONTH, CHA-NGES IN HOLE SI~E. CASING AND CEMENTING JOBS INCLUDING DEPTH SET A_l%TD VOLU/VIES USED, PERFORATIONS, ~TS ~ ~SULTS FISHING JO~,,J~K ~ HO~ ~D SIDE-~CKED HOLE ~ ~Y O~R SIGNIFIC~T ~Gm m HO~ ~ITIONS J i,~J .- /.,.-1/9.-.69 l,.-10..-69 -ll/13--69 Drilled 9-5/8" hole to 7656'. JUN 71969 Ran IES, Density and SNP Logs. DIVISION OF D:L AND GA3 ANCflO£~G5 Ran 7" casing, set @ 7618.10'. Cemented 1st stage w/517 sx Class "G" cement mixed w/lO% Diacel 'D' + 2% cc. Avg slurry wt 13.2#. Circ out 30 bbls cement. Cemented 2nd stage w/735 sx Class "G" cement w/2% cc mixed w/88 bbls FW w/15#/bbl cc. Avg slurry wt 15.6~/gal. Drilled cement 517~' - 520~' and DV Collar @ 520~'. ~-14-69 Perforate as IES & SNP Meas as follows w/4" no plug gun, ~ shots/ft., .50" holes: 75h2'-7515', 66&0'-6630', 6~25'-6410', 6380'-6355', 6262'- 6257', 6250'-6220', 6162'-6152', 6080'-6070', 57&5'-57~0', 5735'-5728', 5655'-5650', 5285'-5255', 5197'-5187', &980'-~973', ~963'-~9&8', 4918'-~908', &895'-~865', ~81~'-&76&', &7&2'-&732', ~700'-~620' & ~600'-4+520'. &-15/16-69 Ran comb &" & 3½" tubing. Set @ ~728.07'. Ran ~ pt. test on perf's ~732'-75~2'. #1 Test - Flowed 1-1/2 hrs on 3/4" choke, FTP 1592 PSI, Temp 62°F, FARO 24.5~MMCFD. #2 Test - Flowed l-l/2 hrs on 5/8" choke, FTP 1791 PSIG, Temp 65~F, FARO 19.1 MMCFD. #3 Test - Flowed 1/~ hr on 1/2" choke, FTP 1891 PSIG, Temp 65°F, FA_~O 12.6 MMCFD. i hr SIP 1987 PSIG, AOF ~l MMCFD. BHT @ ~725' RXB=91°F. Set #2 packer ~426'. ~-19-69 Ran & pt. test on perf's &520'-&700'. #1 Test - Flowed 3-1 h, hr'~- ~n ~/;.,, PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99501 ~ 515 -D" STREET EXPLORATION AND PRODUCTION DEPARTMENT June ~, 1969 Re: NCIU Well #A-~ Division of Mines and Minerals Department of Natural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska Attention: Mr. T. R. Marshall, Jr. Gentlemen: Attached please find Sepia Induction Electric Log for NCIU Well #A-~. ?orm P-7, Well Completion or Recompletion Report, was previsouly furnished your office without this Sepia. Yours truly, PHILLIPS PETROLEUM COMPANY //.~o~ B. o~.'~so~,~ /District Office Manager JBG: Jo Attachment JUN ~ ~969 DIVISION OF 01l AND GAS AN CI-'.OI~.GE PHILLIPS PETROLEUM ANCHORAGE, ALASKA 99501 ~ 515 "D" STREET EXPLORATION AND PRODUCTION DEPARTMENT COMPANY May 26, 3.969 Divisien ef Mines and Minerals Dept. ef Eatural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska Attention: ~entle~en: ~r. T. R. Marshall, Jr. I've been holding this until I get the copy of the final print of the log, but I still don't have it. I theaght I would go ahead and send this te you and then forward the leg when I receive it. Yours truly, JB~: Je Attac?~ent PS PETROLEUM CONP~IY DIVISION OF OIL AND ANCHORAGE PHILLIPS PETROLEUM COi~iPkNY N. C. !. Unit #A-4 North Cook Inlet Field Cook Inlet, Alaska 2600- 3060 3060 - 3800 3800- 3900 3900- 4225 4225 4455 - 4500 4500- 5275 5275 - 6195 6195 - 6360 6360- 7090 7090 - 7656 SAMPLE DESCRIPTION Sand; dk .6Y, m-cg, poorly sorted, quartz and abundant dark rock fra~mments; scattered claystone and coal beds. Sand; med gy, mg, poorly sorted, quartz and black, brown, green, and yellow grains; with some gy silty claystone and thin coal beds. sample returns. Sand; med gv, mg, poorly sorted, subangular to subround, abdnt black, brown, and green grains; with some gray, silty claystone and thin coal beds. Sand; dk guy, f-mg, mod sorted, subangular to subround, abdnt black, brown, green, and yellow grains. Claystone; gy, silty; with thin coal beds. Sand; dk gy, m-cg, mod srtd, subangular to subround, abdnt black, brown, and green grains; with some gray and brown silty, carbonaceous claystone and thin coal beds. Claystone; gy, silty, micaceous, soft; and claystone- tan, hd; with scattered thin sand and sandstone beds; and thin coal beds. Sand; it gy, f-cg, subangular to subround, abdnt gy, smoky euartz grains, some black grains, tr green, brown, and pink grains; with tan, calcareous siltstone, and gy silty claystone. Claystone; gy, sli slty, soft to mod hd; with scattered thin beds of sand, sandstone, coal and siltstone. Siltstone; med gy, hd, calcareous; with thin beds of claystone, coal, and gray, calcareous sandstone. May 6, 1969 Clyde R. Seewald RECEIVED MAY 2 ? 1969 DIVISION OF OIL AND GAS ANCHOI~.GE Form P--7 , SUBMIT IN DUPLICATE* STATE OF ALASKA '~See other in- AttrAct Ions on OIL AND GAS CONSERVA11ON COMMITTEE WELL COMPLETION OR RECOMPLETION/REPORT AND LOG* iE. TYPE OF WELL. OZl,wELL b. TYPE OF COMPLETION: NEW 5a WOnK ~ VEEP' ~ACK W~LL 2. NAME OF OFBRAT0g 8. A~RgS8 O~OPEIATOI - -- DRY E]~ Other vzrr.n~.svR '[~ Othe~ ~l~ "I)" Street~ ~uchora~e. Alaska 4. LOCATION Oi WELL -(-Report IOC~tio~ clearly ~nd t~ ~ccord~ce *tsu~ace~59' F~, 1086.8' ~, Sec.' 6;,- ~l]W, At top prod int~rw~ report~ below '/. IF INDIAI~, AL,L~ OR TlR/BE NAME '8. UNIT,FAI~ OR LF, ASE NA1V~ North fi~ok Inlet Unit 10.- FIEI,D A/iD 'POOL, OR ~T N~rth C®ok Ir~et '11. SEC., T., R., M., (BiYI'TOM HOY~ OBJECTIVE) Sec. 6, TllN, R9W, S.M. 3896' FNL & 37/g+' FWL, Sec. 6, TllN,'R9W, S.M. ' '', ...... ,,, ,,,,,'~,, , ,,, , ,m ,v, , ~ ,, ,, ~ ,'mm,, ']lTl' r ~ $ I' ~ l~' ~ *,~1 m 1~. DATE SPUDDED !14. DATE T.D. P,~ACHED 115. DATE COMP,$USP, O~ A~%.N"D. l'" ~VATXOI~S ?)F, RKB fi' ' ! ?A~A, ~ / ' 7979' ~ I Single i ~ ~.',~ODU~G mV~(S), OF ~ ~~Z~~, ~M, N~E (~'~ ~)* ' Bel~a ~ds; 5288' ~ {~521' ~) to 7656' ~ (d~, T~) ~4. ~E ~c ~D OT~ ~S ~ ~ ~. · CASING I{~3ORD (Report all strings set in w~,ll) i CA.~T~G SIZE WEIGHT, DFZ~TH S~T (MD) 16" SIZE t 69-18 t -INTERvALs 'bRfLLED BY CABLE TOOLS ........ ?'~.'wAS mRrC~oN~u, SURVEY Yes T~I Ill mill i m i ~~O ~CO~J) A/V~ObA4'T PU ~ED LINER , ~. ~ TUBING TOP (MD)~ BOTTOM (MD) SACKS CEMENt* SCREEN (1VID) ~IZE DEPTK S~ri" (M~D) PACKER SET (MD) OP~A~T TO (Interval, size and number) See perforating and squeeze record attached.. -~ ~: I PRODUCTION - ' DATE FIRST P~ODUCTION ~ .~ODUC~ON ME'IHOD (~own~, g~ hi.t, pump~g--~ze and type of p~P) Not P~d~ced ~et~ I Flo~ ~ ~,' : DATE OF TruST, ]HO~S T~ , ~OXE SIZE ~OD'N ~R O~ ' ~KF. , wArn~-~at.. ]OAS-O/t, t I FLOW TUBING ]C~SI. NG PRESSUR~ [C~~ O~BBL. G~M~. WA~B~ [OIL G~V~Y-~ (C~) m~ ': I ' 1~-~ ~ -2h,,t. Tn I 33 I hereb~ ce the forego attached information ts complete and correct as determined from all-available records - INSTRUCTIONS General: This form is des,gnedJ~or subm,tt,ng a complete and correct well complehdn report and log all types of lands and Jeases ~n Alaska Itm: 16: Indicate wh,ch eleva~on is used as reference (white not othe~se show4~for de~ measur~ ments given ~n cther s~aces on ~s form and ~n any attachments. ~-'~ I ~ ~ ~ ' ; Items 20, n~d 22:: If th~s w~ll ~s completed for separate produchon from more the6, one ~nterval zone (muFf,pie complehon), so state ~n ~tem 20~ and' ,n dem 22 show the prcJuc~ng interval, '~ ~nterval~ 'top(s); bottom(s) and name (s) Of any) for~gn~ 'the ~nterval reported ~n ~tem 30 Sub~rt a sep.arat~ re~,(t (page) on th~s form, adequatel~ident,f,eG'~ J&ach adrift,anal interval to ~'sepere~ly prod~,;'~ho~ mg the a~tional data perhn~m to such interval, o ' Item26: "~cks Cement": Attached supplemental records for th~s well should show the details of any mul- tiple stage cementing and the location of~t~ ~menting t~l. I~m 28: Submit a separate com~pletion r~r~ ~h this {orm {or each interval to ~ separately produ~. (~ instruction for items 20 and 22 abo~).c~ ' ' / · · i i, i , i1 ~ i ,, · , ~ ' WA~ AND' MUD ' J ~ ........... ~ '~ ~0 "l ...... " , .~ ~'~ ,'~ ~ . ~ ~ , ,,n .... ' (-' .gppe~ aoJ~ Z~e~ Baa ~2~~ ~660~ ~ ATTA~D CHRONO~GIC~ ~ HISTORY ', ~2 Cook ,I~et ~e bsa' 3891' ' -~- ~ ~Bel~a ~. ~, 5288' ~' l' ~ - '' , t / ii i i i i i i i = ,, ,,, , i ~8 CO~E DATA. A~qll n~F D~C~IPI~ON~]OF LITttOLOOY. POROSITY,' ~AC~~. AP~T DIPs -- ~ ~ AND DETECt'El) SILO.S OF OIL. G~ O~ WA~ _ _ , , , , ...... ? ..... , , ,_ - ~ , ~ ~ - , ')- ,'- ,) S~ ATT~C~D, S~~ ~~PTION ,, , (.--' .. -~ ,, , ,, :' "~' ' .... S ~' ' ':~ 3-19-69 3-20/21-69 3-22/2~-~9 3-25/29-69 5-30/31-69 ~-14-69 ,-15/16-69 ,-I?/18-69 -19-69 CHRONOLOGICAL ~,~LL HISTORY Spud 15" hole .D 9:30 PM, 3-19-69 & drilled to 607' & reamed to 22". Set 16" casing @ 575.87' & cemented w/420 sx Class "G" cement .mixed w/200 bbls prehydrated Gel wtr ~f~/bbl followed w/125 sx Neat cement mixed w/15 bbls CaC12. Repairing drawworks. Drilled 15" hole to 2585'. Ran 10-3/~" casing, stuck at 2~09.67'. Cemented w/775 sx Class "G" cement w/8#/bbl prehydrated Gel, followed w/125 sx Class "G" cement w/2% CaC12. WOC & nippled up. Drilled 9-5/8" hole to 7656'. Ran IES, Density and SNP logs. Ran 7" casing, set @ 7618.10'. Cemented let stage w/517 sx Class "G" cement mixed w/lO% Diacel 'D' + 2% cc. Avg slurry wt 13.2#. Circ out 30 bbls cement. Cemented 2nd stage w/735 sx Class "G" cement w/2% cc mixed w/88 bbls M.~ w/15#/bbl cc. Avg slurry wt 15.6#/gal. Drilled cement 517~' - 520d' and DV Collar ~ 520~'. Perforate as IES & SNP Meas as follows w/~" no plug gun, ~ shots/ ft., .50" holes: 75~2'-7515', 66~0'-6630', 6%25'-6~10', 6380'- 6355', 6262'-6257', 6250'-6220', 6162'-6152', 6080'-6070', 57~5'- 57~0', 5735'-5728', 5655'-5650', 5285'-5255', 5197'-5187', ~980'- ~973', ~96~'-d9~8', ~918'-~908', %895'-~865', d814'-~76~', ~742'- d732', ~700'-~620' & d6OO'-~520'. Ran comb ~" & 3½" tubing. Set ~ ~728.07'. Ran d pt. test on perf's ~732' - 75~2'. #1 Test - Flowed 1-1/2 hfs on 3/~" choke, FTP 1592 PSI, Temp 62°F, FARO 2~.5 MMCFD. #2 Test- Flowed l-l/2 hrs on 5/8" choke, FTP 1791 PSIG, Temp 65OF, FARO 19.1 MMCFD. #3 Test - Flowed 1/~ hr on 1/2" choke, FTP 1891 PSIG, Temp 65°F, FARO 12.6 N~CFD. I hr SIP 1987 PSIG, AOF &l ~,~CFD. BHT @ d725' RKB=gl°F. Set #2 packer 4~26'. Ran 4 pt. test on perf's 4520'-~700'. #1 Test - Flowed 3-1/~ hrs on 3/~" choke, FTP 1280 PSI, Temp 65°F, FARO 19.9 MMCFD. #2 Test - Flowed 1-1/4 hrs on 5/8" choke, FTP 1397 PSI, Temp 63°F, FARO 14.95 ~CFD. #3 Test - Flowed I hr on 1/2" choke, FTP 1476 PSI, Temp 63°F FARO 9.9 ~CFD. #~ Test - Flowed I hr on 3/8" choke, FTP 151~ PSI, Temp 6d°F, FARO 5.5 M~CFD. AOF=36 ~DICFD. SI i hr. SITP 1538 PSIG, BHT 88°F. Completed as gas well. RECEIVEO MAY 2 ? 'i969 DIVISION OF OIL AND OAS ANCHO$.GE PERFORATIN~ AND S~UEEZE RECORD Well Dale Size of Casting Perforating From Feet Perforated 2?1 ~0' 10' 10' ?' 30' 10' ?' 1~' 10' 30' ~3' 10' 80' ~0' Holes Size of Holes # # ~f ~r Gun D;amefer # Jf # # Gun II II It II II 11 II * I II II II II tl It Perforating Company Form ~To. G-1 RE:VISED ' ,lAN I, 196~ STATE OF ALASKA 'OIL AND GAS CONSERVATION COMMI~EE SUBMIT ltKCE 2 I969 DIVISION OF OIL AND G~ GAS WELL OPEN FLOW POTENT[AL TEST REPORT 4-POINT TEST Test In it lal [2~ Annual U Special Set @ Pipelinm--C~nectlon ~ jTypeTaps ~ --!.--),~ ~ ....... ~C~.~.,^,'~ k~t L,~T ~--'1~,~,.¢. MulUple CompleUon (Dual or Triple) J Type production from each zone I · , 11 ii 111 , , ,, ,,, i , , ,1 , ,11111 , ,, - OBSERVED DATA Flow Data ' Time (~) (~ , Press. Diff. Tubing Casing Flowing .~o. of Flow (Line) (Orifice) h Press. Press. Temp. Hours Size Size psig w pslg pslg *F s, ,4 2 7-'~ ................. . ...1 cf4 ~ ........ ~,,.-.,.~_ (~ . 2 I ~. I'A q 6,7 XOa,-I ~! ........ ~7¢ ,,, FLO%V CALCULATIONS Coeffl- : - Flow Temp. Gravity Compress. lhlo. cient ---~/h p Pressure Factor Factor Factor Rate of Flow (24 Hr.)V w m psla Pt Fg Ypv O ~iCr/D ~.. .... ~ .~4 5 CaS, U ,...eSe 7, . ~ ~, oa~- ......... I~, 0,¢0 ...................... , aZ~a PRESSVIIE CALCULATIONS Absolute Potentml j n , , '' , , i , t , ,, , , - _ (company), and that I am authorized by said company to make this report; and that this report was pre- pared under my supervision and direction and that the ,acts state true. 7rrec; ?V the best of mir knowledge. Si~atUre - . ~ 3 -i 3 4 6 · !!I!~l 2 I969 6 7 8 910 2 3 4. 5 6 7 8 910C~ 2 3 4 910 C SYMBOL OF SERVICE REPORT of SUB-SURFACE DIRECTIONAL SURVEY PHILLIPS PETROLEUM COMPANY PLATFORM COMPANY "A" A-4 WELL NAME NORTH CO OK INLET LOCATION JOB NUMBER AMS- 869 TYPE OF SURVEY SINGLE SHOT DATE MARCH- APRIL 1969 SURVEY IY ANCHORAGE OFFICE Ollm D-3~ Il& LIT~O gY' EASTCO tN U S A L L C O M P L E T I O N R E P O R T COMPANY A-4 LEG 3 SLOT 4 ION .... C 0 U R ON AMOUNT V.DEPTH LATITUDE PREPARED FOR S E DEPARTURE TVD = 363.98, LATITUDE = -2.88, 0.72 82,99 0.53 N 0.48 W 0,21 31,99 0,21 S 0.05 W 0,27 30,99 0,19 N 0,19 W O,~+l 31,99 0.36 N 0.19 W 0.26 29.99 0.18 N 0.18 W 0.28 32,99 0.16 N 0.23 W 18,99 217,17 16,28 S 9.18 E 6.96 63.6! 6.03 S 3.48 E 11,28 95.33 10,22 S 4.76 E 13.08 93.08 12.63 S 3.38 E 17.01 96.51 15.16 S 7.12 E 5.98 29.39 5.07 S 3,16 E 6.70 30.26 5.21 S 4.22 E 9.35 36.83 6.3? S 6.84 E 16.83 60.70 10.82 S 12.89 E 26.60 8?.02 17.10 S 20.38 E 29.95 86.98 18.84 S 23.27 E 34.83 86.22 22.39 S 26.68 E 39,04 87,70 25.09 S 2').91 F ~.1,85 83,04 26.90 S 32.06 E 4.5,57 82.21 29,89 S 34.39 E 48,02 76.1! 3[,50 S 36.24 E 54.71 78.87 36,61 S 40.66 E 55.04 73,71 37,54 S 40,25 E 38'.17 48.85 26,03 S 27.91 E 66.34 82.66 44.39 S 49.30 E 78.65 94.56 52.62 S 58.44 E 78.72 90.56 54.68 S 56.63 E 45.26 52.07 31.44 S 32.56 E 4]..77 48.48 28.49 S 30.55 E 59.13 70.47 40,33 S 43.24 E PAGE EASTMAN 4/9/69 TANGENTIAL METIq.9O & · T 0 T A L V,DEPTH LAT[TUDE DEPARTURE DEPARTURE = 0.00 4'+6.97 2.34 S 0.48 W 478.91 2.61 S 0.54 W 509.97 2.42 S 0.73 W 54[.97 2.05 S 0.93 W 571.97 1.86 S l.lt ~ 604.96 l. ?0 S 1.35 822.13 17.98 S 8.43 E 885,75 24.02 S' 11,91 E 981.09 34.25 S 16.68 E 10;'4.17 46.88 S 20.07 E 1170.69 62.04 S 2 I, 79 E [200.08 67.12 S 30.96 E 1230.35 72.33 S 35.19 E 1267,18 78.7I S 42,03 E 1327.89 89.53 S 54.92 E 1414.91 106.63 S ~ 75.30 E 1501.90 125.48 S 98.58 E 1588.13 147.88 S 125.27 E 1675.83 172.98 S 155.18 E 1758.87 199.88 S 187.25 E 1841.09 229.78 S 22t.64 E 1917.20 261.29 S 257.89 ,"'"% 1996.08 297.90 S 298.55 L 2069.80 335.44 S 338.81 E 2118.65 361.48 S ~' 366.73 E 2201.32 405,87 S 416.03 E 2295.89 458.50 S 474.48 E 2386.45 513.19 S 531.11 E 2438.53 544.63 S-< 563.6? E 2487.01 573.13 S 594.23 E 2557.49 613.46 S 637.48 £ NELL COMPLETION REPORT PAGE PHILLIPS PETROLEUH COMPANY A-4 LEG 3 SLOT 4 PREPARED FOR EASTMAN 4/q/6g TANGENTIAL MET~D MEASURED COURSE - - D E V ! A T I 0 N .... C 0 U R S E DEPTH LENGTH ANGLE DIRECTION AMOUNT V.DEPTH LATITUDE DEPARTURE T 0 T A L V.DEPTH LATITUDE DEPARTURE 2937. 127. 39 O' S 47 E 79.92 98.69 54.50 S 58.45 E 3092, 155, 39 O' S 46 E 97.54 120.45 67.76 S 70.16 E 32?8, 186, 39 O' S 65 E 117.05 166.54 82.76 S 82.76 E 3463° ~85, 39 O* S 65 E 116.62 143.77 82.32 S 82.32 E 365~. 189o 39 15' S 46 E 119,58 146.36 83°06 S 86.01E 3800, 148. 39 45' S 45 E 94.63 113,T8 66,91 S 66.91 E 3931, 131. 38 65* S 46 E 81.99 102.16 56.95 S 58.98 E 4088. 157° 38 15' S 47 E 97.19 123.29 66.28 S 71.08 E 4242. ~[54. 37 15' S 46 E 93.2! 122o58 64.75 S 67.05 E 44Z8o 186. 37 O' S 46 E 111.93 148.56 77,75 5 80.52 E 4644. 216. 36 O* S 45 E 126,96 174.76 89.77 5 89.77 E 4827. 183. 34 45' 5 45 E 104.30 150.36 ~3.75 S 73.75 E 4984. ~57o 35 O* 5 65 E 90.05 128.60 63,67 S 63.67 E 5~72o 188° 35 45' 5 45 E 109.83 152.57 77.66 S 77.66 E 5387, 215, 36 15' S 44 E 127.13 173.38 91.45 S 88.31E 5605, ~18, 36 O* S 45 E 128.13 176.36 90.60 S 90.60 E 5'731, 126, 35 15' S 45 E 72.72 ~02.89 51.42 S 51.42 E 5~50, 219, 36 15' S 46 E 129.49 176.61 89.95 S 93,15 E 6~66. 216, 37 O* S 46 E 129.99 172.50 90.30 S 93.b0 E 6383, 2~7. 38 O' S 45 E 133.59 170.99 94.46 S 94.46 E 6476, 93° 38 O* $ 46 E 57.25 73.28 39.77 S 41.18 E 666Z. ~86, 38 O* S 45 E 114.5! L66.57 80.97 S 80.97 E 68?7° 215. 38 0* S 45 E 132°36 169.42 93°59 S 93.59 E 7097. 220° 37 15' S 43 E ~33.16 175.12 97.39 S ~0.81E 7312. 215o 37 15' S 42 E 130.13 171.14 06.71S 8?.07 E 7529. 217. 36 45' S 41E 129.83 173.87 97.98 S 85.18 E 7656° ~27o 36 0* S 41 E 74°64 102.76 56.33 S 48.97 E 2656.19 667.96 S 695.q3 F 2776.65 735.72 S 766.10 E 2921.19 818.49 S ~ 848.87 E 3064.97 900.82 S q~l.lg E 3211.33 983.89 S 1017.21 E ~325.12 1050.80 S 1084.13 E ' 3427,28 1107.76 S 1143.11E ~550.57 1174.05 5 1214.20 E 367~.16 1238.81 S ~1281.25 E 3821.71 1316.56 S 1361.77 E 3906.45 1406,34 S 1451.55 E 41~6.81 1480.10 S × 1525.3! E 42F5.42 1543,77 5 1588.98 E 4428.00 1621.44 S 1666,65 E 4601.38 1712,89 S ~ 1754.96 E 4777.75 1803.50 S 1845.57 E 4880.65 1854.92 S 1896.99 E 5057.26 1944.88 S 1990.14 E 5229.76 2035.18 S ~ 2083.65 E 5400.?6 2129.6~ S 2178,12 E 5474.05 2169.42 S 2219.31 E 5620.62 2250.39 S 2300.28 E ~ 5790.04 2343,99 S ~2393.88 E 5965.16 2441.38 S 2484,70 E 6136.30 2538.09 S 2571.78 E 6310.17 2636.08 S 2656,96 E 6412,92 2692.42 S ~2705.q3 E LDSURE 3817.22 S 45- 9' E VE~ ¥I~/~ EECTIL]N '"i l e' I-+' Form No P--4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMI~EE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS 1 OIL [] GA8 [] WELL WELL OTHER 2 NAME OF OP~m,.ATOR Phillips Pe%releum CemImn~ 3 ADDRESS OF OPERATOR 515 "D" Street. Anch®ra~e. Alaska 9q501 4 LOCATZON OF ~ ' -- - S~rface: 1259' lq~, 1086.8' lq~, Sec. 6, T33~I, Rgw, S.M. Tep ef Pay: 2539.3' YIn, 2280.3' F'w'L, Sec. 6, TllN, Rgb, S.M. AP1 NUAIERICAL CODE API 50-283-~0023 6 LEASE DESiGI~Aki'ION AXD SEHIAL NO ADL-17589 ? IF INDIA)~, ALOTTEE 0}{ TRIBE NAME 8 L.'/%'IT,F.~=IM OR LEASE NA_ME Ner~h Ceek Inlet Unit 9 WELL NO 10 FTI~.T~I~ AND POOL OR WILDCAT Nerth Ceek Inlet 11 SEC . T, R , M (BO/'rOM HOLE Sec. 6, T31~, RgW, S.M. SUBMIT IN DUPLICATE 12 PERMIT NO 13 REPORT TOTAL DEPTH AT END OF MONTH, CH-A~NGES IN HOLE SIZE, CASING AND CEMENTING JOBS INCLUDING DEPTH SET A_N'D VOLUiViES USED, PERFORATIONS. TESTS A.N'D RESULTS. FISHING JOB~, JUNK LN HOLE AND SIDE-TRACKED HOLE AND ANY OTI-~.J~ SIGNIFICANT CI.-LA. NG~ IN HOL~ CONDITIONS 3-31-69 TD 2585' WOO & nipple up. / 3-19-69 Spud 15" hele 9:30 PM, 3-19-69 & drill te 607' & ream te 22". 3-20/21-69 Set 16" casing at 575.87' & cemented w/420 ex Class "G" cement mixed w/200 bbls prehydrated Gel wtr 8~/bbl fellewed w/125 ax Neat cement mixed w/15 bbls CCC12. P~p~iz~ng Drill 15" hele te 2585'. 3-3o/3 -69 Ran 10-3/~" casing, stuck at 2409.67'. Cemented w/775 ,x Clazs "G" cement w/.8~/bbl prehydrated Gel, fellewed w/125 sx Class "G" cement w/2% Ca¢l2. WOC & nipple up. RECEIVED APR 9 ! DIVISION OF OIL AND GAS ,ANCHOrAgE 14 I hereby e forego~ ~s true~_._ ~ rrect ) s,~. ,"/-k'~/~d:~/'2"~*'-~- _ ./~-. ~. / District. . Office Manager DA~ April 8, 1969 ,., _ 0TE--Report on this form m requ~rred for each calendar month, regardless of the status of operaUons, ancl must be f,le~ m duplicate w~t~ the D~wsmn of M~nes & Minerals by the 15th of the succeeding month, unless otherwise d~rected l~z~h ~ .1.969 Rot Sp~ New ~ _ ~ ~x~ ~AR 2 & f969 DIVISION OF OiL AND GAS ANCi':C;,, gE Form P--3 REV 9-30-67 Submit "Intentions" in Triplicate [ & "Subsequent Reports" m Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use thru form for proposals to drill or to deepen or plug back to a d~fflerent reservoir Use "APPLICATION FOR PEP,~IT--" for such proposals ) TRM WELL WELL OTHER 2 NAME OF OPEP,~TOR (~K[.~ 13 ELEVATIONS (Show whether DF, RT, GR, etc 5 AP1 N~CAL CODE API 50-283-20023 $ I_,EAS~. DESIGNATION A.ND ~l~'tlAL NO ~, IF INDIA.N, A.I_,LO'i-i'~:~: OR TRIBE NA.M~ ~ umr, F.~ o~ LEASE 9. W~L NO ,, 10 F~ ~ P~L, OR W~T ~ No~h Cook 11 SF~ , T , R, M , (BOTTOM HOI.~ OBJ~VE) Sec. 6, TllN, RgW, S.M. '12 PERMIT NO ~ ~ q F,, From ],4"r.T~ ] 6~-18 14 Check Appropriate Box To [ndi'cate Nlat'ure of N~ogce, Report, or Other Data NOTICE OF INTENTION TO : TEST WATER SHUT-OFF I [ PULL OR ALTER CASINO FRACTURE TREAT [ [ MULTIPLE COMPI,ETE SHOOT OR ACIDIZE ~ ARANDON* REPAIR WELL CHANGE PLANS (Other) SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASINO SHOOTING OR ACIDIZINO ABANDONMEBiTs (Other) NOTE: Report results of multiple completion on Well ompletion or Recompletion Report and Log form.) "15 DESCRIBE pROposED OR COMPLETED OPERATIONS (Clea~ly state all pertinent details, and give perttn~ent dates, Including estimated date of starting an) proposed work. This is to inferm of our intention to change surface location from Leg 3, Slot 3 to: Leg 3, Slot &, 1259' FNL, 1086.8' F~L, Sec. 6, T_llN, R$~, S.N. and Tep of"l~_y.to: 2539.3' FNL, 2280.3' F~L, Sec. 6, TllN, Rgb, $.N. and BHL to: 1095.2' FSL,1~b5.2' FEL, ~ec. 6, TllN, RgW, S.M. See corrected slot location plat attached. D tot40~ o~t A~O GAS 16. I hereby c~tify~hat~the foregoing i~r~ue and correct CONDITIONS OF APPROVAL, IF A~: District Office Nanager DATE March 11, 1969 See l~nstrucfions On Reverse Side / / i LeE/ I No N.C.I. , N.C.I. Un.A-2 ~ RECEIVED MAR 1:8 .~o~o PHIlLiPs PETROLEUM CCJ.,~ANY 515 "O' STREET A~',CHORAG~- ,~.ASKA NORTH ~"' ~.u~,~ INLET TYONEK PLAT¢ORM ~ , POOK ~NLET~ ALASK~ NOTE~ Using PLATFORM NORTH, S,4. furthest plotform North slot i~ p~atform west quodront of er~y leg; Slots ore Ifhru8 in o counfer-clock-w~sc d~rec;' 'DRW~, N, ~-FF;~,D-' -- |NOT .TO SCALr. ..... . ::- ; ........ ::: -: - FORM SA lB MEMORANDUM TO: J-- lmlus~al ~ lmpeclm' FROM: llmlr L. Ii'lin11 State of Alaska DIVISION Of OZL AND SUBJECT= Coo& lolet Ullt BO. A*4 Pb1111pl Pltre~ Clqam~, FORM SA lB MEMORANDUM State of Alaska i~t~ililAt Of:' I~TtI~ ~ DIVISIOII OF OIL Aim FROM: limit L. IIITe11 Mrect~ DATE SUBJECT= Nlrth Cook lolet Uafl mo. A-4 EBcles~ .'e tin dqqN'wed appltcattee for pemft to drill. · leratSoi pier, i a clck 1. t~ emmmt of / ~ filing fee. DIVISION OF OIL AND GAS ~rch 4, 1969 North Cook Inlet Untt go. A-4 Phtlltps Petroleum Cempany, Mr. 3ohn B. Gtpson Otstrtct Offtce Phtllfps Petrot(mm Company 516 D Street Anchorage, Alaska Dear Str: Enclosed please ftnd the approved application for pemlt t~ drill the referenced well. ide11 samples and core chtps are not required. Please note the requtrnmnt as shown on the permit that the 7-1nth and 10 3/4-tnch castng s.lmuld be tted tn ~th cement. Very truly your~, HLB:Iqy Enclosure . , Hmer L. Burrell Otrector H.EV 9-30-67 STATE OF ALASKA OIL AND GAS CONSERVATION ,COMMITTEE' HLB rd7 / , ~i TRM "" J reverse side) "w 3- oo 3 APPLICATION FOR PERMIT TO DRILL, DEEPEN, OR PLUG BACK TYPE OF WORK DRILL [] DEEPEN [] PLUG BACK [-J b. TYPE OF WELL O,L F-I °" Iii WELL WELL OTHER ZONE ZO N E NAME OF OPERATOR Phillips Petroleum Company ADDRESS O~ OI-'I~-~.TOR 515 "D" Sgreet, Anchorage, A~,k~ 99501 LOCATION~OF WI~eL At sur~ace'eg >, Slot 3, North 0ook Inlet, Platfo~ "Tyonek" 1259t ~ 1083! I~L, Sec. 6, TIIN, R~I, S.l~. At proposed pro~ zone 2539' FNL. 2276.' ~f~, Sec. 6, T~_, R~, S.~. DISTANCE IN MIl-ES AND DIRECTION ~2OM NEAREST TOWN OR POST OFFICE* lo.~ ~ile East of ~ek, Alaa~a BOND INFORMATION M-M~-IV gate ~i~e Bon~ BI-1 TYPE Suret~ and/or No i5OO2 lg PROPOSED DEPTH 8230 ~ 7OOO ~ 16 NO. OF ACRES IN LEASE 15 DISTANCE FROM PROPOSED* LOCATION TO NEAREST PROPERTY OR LEASE LIN~; 1~i'' (Also to nearest drag, umt, if any) i~ DISTANCE FROM PROPOSED LOCATIOn* ' TO NEAREST WELL DI:LILLING, COMPLETED, OR APPLIED FOR, FT 2000' . 6 l.l~.a ~ r~'~t~GNATiON AND SERIAL NO r;'.E IF INDIAN, ALLOi-A-ifiifi OR Tlm, J_BE 8 UNIT~FARM OR LEASE NAME North Cook Inlet Unit 9 w~:,~L NO ~A-~ 10 ~IELD AND POOL, OR WILDCAT North Oook Inlet I~SEC , T , R, M, (BOTTOM HOLE OBJECTIVE) sec. 6, TllN, Rgb, S.M. A~nount 17 NO ACRES ASSIGNED TO THiS WELL 20 ROTARY OR CABLE TOOLS L~otary 21 ELEVATIONS (Show whether DF, RT, CR, etc ) ~ APPROX DATE WORK WILL START* 23 I~OPOSED CASING ~ID CEMENTA~G PROGRAM SIZE OF HOLE SIZE OF C~SIN WEIGHT PER FOOT GI~AI)E SETTING DEPTH qUANTiT~ OF CEMEN~ 22. IA,, 65 H-&~0 600 Circulate to surface 15,, 10-3/~, A5.5 & 51 . J-55 2._A~0 ~iron~te t~ surface 9-5/8. 7,,'.. ...., 26 & 23 _ J-55 _~._30 F-~'~ 1 u~. ,to, ~00! above pay zone __ 1. Deviation required to reach ~ from permanent platform. 2. There are no e.ffected operators. 3. BOP Specifications attaohed.' ~. Intervals of interest will be perforated and may be stimulated. FEB 2 ? 19¢,-] DIVISION OF C,L AND GA3 ANC} ' ,,.DE * Refer to State of Alaska, Alaska Oil & Gas Conservation Cammittee, Conservation Order #~, dated 6-8-67 a~d #68, dated ]2-7-68. J SANIPLES AND CORE CHIPS It.F~UIRE~ [] YES ~ ATO DIRECTIONAL SURVEY YES [] NO IN ABOVE/g~ACE DESCRIBE PROPOSED PHOGRA2Vi If proposal is to deepen or plug back, give data on present productive zone and proposed rite ~v/ productive zone. If pro,posal L~ to drill or deepen d~rect_onally, gxve pertmen+~ data on s~bsurface locatmns and measure~i and 24 I hereby/~erlJ4y tJlat the Foregom~t,~12rue and Correct SIGNED DATE . ebruary 26, 1~6~ ~L~ District Office Mgr. (This spac~or State office use) ~ CONDI~ONS OF APPROVAL. IF ANY. t°~a~aamuau~N~SThe 7" and 10 3/4" casing shouldt be t~ed ~n with cement. A P I NU1VIERICAL OODE March 4, 1969 DATE 18755 i2 7 18 5 PROPCS --S B.H.L, N.C.I. Un, (1096'F81. 8, I4,89'FF..:.L of $,~¢.8-:~, · .~ . ,/,.) ' ANSI' PHILLIPS '-,_-;*~,OLEUM COMPANY 515 'D" 8TR,T. ET ~NCHO~AC~. ,ALASKA NOR':'H CC'" NLET UNIT 7/ONEJ~ ~ ,-,TFO~M HOOF, UP FOR DOUBLE PREVENTERS N,C.I.U. PLATFORM CHOKE MANIFOLD I.J_ ~.. Q 4" SERIES 1500 VALVE G 2_" SERIES 1500 VALVE 2" MUD PRESSURE GAUGE ON 4"X ~'X~' SERIES 1500 STEEL TEE SERIES 1500 X 2" SERIES 1,500 STEEL CROSS 2"SERIES 1500 POSITIVE CHOKE 2" SERIES 15OO ADJUSTABLE CHOKE h~OTE: Double Preventers are used with flanged side outlets for choke manifold · and fillup line connec,%ions. i PHILLiPS P~:. 1 [',OLE,.,~,~ PRODUCTION DF_-PART M ENT 5000 PSl \qORKING,-r',~'"'~'e°'~-_...o~,,-,c'~- BLOWOUT PREVF_N'FERI-,O0,~-U' " '~'r (SERIES 1500 FL. ANG~'S,:_ OR...['c"~Tr-'-'), , ._., REV j/'l I/aB SC}lEI)Ut E E N KC, i, Un.A-2 */ DIVISION OF C · /', ,; C;',3 PHILLIPS PETROLFU,,! CO:',PANY NORTH CO~,, t LE'F,~ ~,, TYONEK PLATFORM COOK INLETt ,:~ASKA . 'NOTE: Using PLATFORM NORTH, Slot No.~ will DC t furthest platform North ,slot m platform west quadrant of an~ leg;Slots dre numbcruc I thru 8 in a counter-clock-wise d~rection. PLAT~- O,~M LOCATION' 6 975' I 6 12 7 LEG Ng. LAT. Gl° 04' 3G ~8" LONG 150° 56' 55 65" Y= 2,586,751 X: $51,995 ' FROM N.W COR 1~250' SOUTH l& 975' EAST. LEG Ng. 4 LAT 61° 04' 3689" LONG 150° 56' 54 25" Y= 2~586,781 X:' 332,063 FROM N W. CON. 1,198' SOUTH & 1,045' EAST. ' SCALE I": 1,000' LEG N.9,. 2 LAT 61° 04' $585" LONG 150° 56' 5477" Y= 2,586,674 X: 332,056 FROM N W. COR 1~305' SOUTH & 1,018' EAST T 12 N $1 [ TIIN 6 · ' $ 5 LEGNa $ , , , LAT 61u 04' 36 $4" LONG Y: 2,586,72 4 x: FEB 2 ? 1969 FROM N~ COR i,254' SaSH I, O85' EAST. , ANCH~kGE . NOTE The location of the platform legs was accomplished by using triangulation stations BELUGA,TERRACE,and TYONEK which are all U.S.C.I~G.S. stations. AIl coordinates are Alaska State Plane, Zone 4. pLAT OF" ' " NORTH COOK I NlaE.,T UNIT PLATFORM A FOR PHILLIPS PETROLEUM CO DATE. 21 JUNE 68 F.M , , SCALE I": IOOO' .' Lond&. Hydr<~grOphic~ FB. II374 Pp 11-15 ' S~v~s JHG i, 1374 J CERTIFICATE OF SURVEYOR I hereby certify that lam properly registered and licensed to practice land sur.veying in the State of Alaska (~nd that this plat represents a location su~ey made by me or under my supervision and that all dimenstons and correct. - / DA~E
