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168-099
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 Unit 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" - 384' 16" H-40 612' 10-3/4" J-55 2,329' 7" J-55 2,918'(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 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, 515 sx9-5/8" TUBING RECORD N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 1245 sx Surface - Surface 612' 735 sx Driven STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 9/2/2021 1250' FNL, 1090' FWL, Sec 6, T11N, R9W, SM, AK 1454' FNL, 2449' FEL, Sec 1, T11N, R10W, SM, AK 168-099 / 321-160 Tertiary System GP / Sterling Undef GP 126.6' 3,209' MD / 2,918' TVD HOLE SIZE AMOUNT PULLED 50-883-20020-00-00 NCIU A-03 332109 2586728 1578' FNL, 363' FEL, Sec 1 T11N, R10W, SM, AK CEMENTING RECORD 2585415 SETTING DEPTH TVD 2586552 BOTTOM TOP 15" Surface 22"Surface CASING WT. PER FT.GRADE 23-26# 330651 328554 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information 45.5-51# 3,209' (TOW) Surface Surface DEPTH SET (MD) PACKER SET (MD/TVD) - 65# 384' Surface 2,519' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST N/A Date of Test: Flow Tubing 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 N/A Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: March 2, 1968 November 2, 1968 ADL017589 / ADL037831 N/A N/A 3,209' MD / 2,918' TVD101 N/A 7,480' MD / 6,392' TVD WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Abandonment Date 9/2/2021 HEW RBDMS HEW 11/10/2021 By Meredith Guhl at 1:27 pm, Nov 10, 2021 xGDSR-11/10/21DLB 11/10/2021BJM 11/30/21 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval Beluga S 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, P&A 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 11.4.2021Digitally 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: 2021.11.04 15:03:26 -08'00' Monty M Myers ____________________________________________________________________________________ Updated by: CJD 11/4/21 P&A SCHEMATIC North Cook Inlet Well: NCI A-03 Abandoned: 9/2/21 PTD: 168-099 API: 50-883-20020-00-00 PBTD: 3,981’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A A B C D E G TOC 3,260’ 7” Stage Collar 5,114” 10-3/4”10-3/4 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ 3,908’– 3,911’ 13 Tubing Patches 3,788’- 3,809’ + 3,870’ – 3,882’ ID 1.875” X Tubing cut @ 3,754’ 6 TOW @ 3,209’MD BOW @ 3,222’MD F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Conductor 29.000 Surf 384’ 16”65 H-40 15.250 Surf 612’ 10-3/4”45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366”79’6,818’ 26 J-55 BTC 6.276”6,818’7,475’ TUBING DETAIL 3-1/2”9.2 L-80 IBT 2.992 Surf 166’ 2-7/8”6.5 L-80 EUE 8 rnd 2.441 3,754 3,962’ 4-1/2”12.60 J-55 EUE Mod 3.958 4,003’6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 6 3,228’2,935’7” Mechanical Bridge Plug 3,265’2,966’16 BBL Cement placed on top of packer –TOC @ 3,265’ 3,754’3,395’Tubing cut 7 3,759’3,399’2.440”5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 8 3,872 3,496’2.310”3.180”Sliding Sleeve -PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’3,509’2.313”3.670”X-Nipple 10 3,900’3,519’2.440”5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310”3.180”Sliding Sleeve -PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’3,548’2.313”3.670”X-Nipple 13 3,939’3,552’Tubing plug w/ top AA stop 14 3,954’3,564’2.440”5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’3,570’2.205”3.670”XN Nipple 16 3,962’3,571’2.450”3.700”WLEG 17 3,988’3,592’EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’3,713'2.500 Baker 40A-25 SC-1 GP Packer 4,139’3,716'2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’3,722'2.992 16 Ft Lower Extension 4,193’3,760'2.441 2-7/8” Excluder 2000 Screen – Med (337’) B 4,198’3,764'3.990 5.560 No Go Seal Assembly C 4,199’3,764'4.000 5.870 Halliburton TWR Packer D 4,501’4,007'3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’4,026'3.990 5.560 No Go Seal Assembly F 4,526’4,027'N/A 2.875” Bull Plug G 4,527’4,028'4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’4,074'3.813 5.560 Halliburton XD Sliding Sleeve – Closed (w/PX Plug) I 4,594’4,081'3.990 5.560 No Go Seal Assembly J 4,595’4,081'4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’4,131'3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’4,139'3.990 5.560 No Go Seal Assembly M 4,669’4,140'4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’4,199'3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’4,203'3.990 5.560 No Go Seal Assembly P 4,751’4,204'4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’4,262'3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’4,267'3.990 5.560 No Go Seal Assembly S 4,832’4,267'4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’4,309'3.990 5.560 No Go Seal Assembly U 4,886’4,310'4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’4,343'3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’4,348'3.990 5.560 No Go Seal Assembly X 4,936’4,349'4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’4,435'3.813 5.560 Halliburton XD Sliding Sleeve – Open 12/13/2001 Z 5,105’4,481'N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’4,487'3.990 5.560 No Go Seal Assembly BB 5,114’4,488'4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’4,898'3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’5,424'3.725 5.560 Halliburton XN Landing Nipple EE 6,289’5,425'3.980 Wireline Re-Entry Guide Notes: 12/07/2007 –Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 –9.98’ difference in elevation is due to being set on Electric Log Depths ____________________________________________________________________________________ Updated By: JLL 06/25/21 SCHEMATIC North Cook Inlet Well: NCI A-03 Last Completed: 06/08/21 PTD: 168-099 API: 50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 06/07/21 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 06/07/21 Isolated CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 06/07/21 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 06/07/21 Isolated CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 06/07/21 Isolated CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 06/07/21 Isolated CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Isolated CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Activity Date Ops Summary 5/10/2021 RIG UP SLICKLINE P/T LUB. 250/1500PSI GOOD TEST RIH W/ 3 1/2'' GS W/ PRONG TO 368'KB W/ TOOL LATCH HAVE PROD. DROP CONTROL LINE PRESSURE W/ TOOL POOH W/ SSSV STAND BY TO EQUALIZE WELL RIH W/ 2 7/8'' OK-5 KOT W/ 1.25'' JDS TO 3668'KB LOCATE - LATCH W/ TOOL 3 JAR LICKS CAME FREE POOH W/ VALVE STAND BY FOR CRANE LAY DOWN LUB P/U RISER STAB ON A-4 6/6/2021 Skid rig over A-03 and assemble beam package. R/U circulating lines to tree (A-03) and installed lubricator. Circulated well @ 3bpm/200psi, returns were 1/1 and clean, pump a total of 157bbls. SD pump monitored well, Tbg/IA is static. R/D Circulating lines, Removed flowline from tree and blinded off line. Continue R/U miscellaneous equipment. Remove flow line spool from tree. Nipple down actuator and pull to drill deck.,Set BPV. Remove landing and stairs in wellhead room for riser clearance..,Nipple down tree. Work boat. Remove tree and set on drill deck. Verify lifting threads to be 3 1/2" EUE.,Dress hanger/prepare for nipple up. Make up accumulator lines.,Install riser. N/U mud cross, double gate and annular preventer. Nipple up choke and kill lines.,Tor que all BOP bolts to specs. Nipple up choke house to choke manifold.,Raise and scope up derrick. Secure guy lines. Slide doghouse in and secure. Nipple up kill li ne to stand pipe. Install rig floor and stairs. Install beaver slide and weld to stand. Test precharge on Koomey bottles. Hook up umbilical to Koomey remote in doghouse.,Built 2-7/8" and 3-1/2" Test Joint. Function tested BOP's, Kill HCR would not close open from the remote panel. Changed over 4 way and functioned properly.,R/U BOPE Testing equipment and M/U 2-7/8" Test Joint. Flooded stack and surface lines, preformed shell test, chased leak on annular, increased annular pressure and function bag and shell tested to 2500psi- good test.,Tested BOPE per Sundry as following: Annular 250-2500psi, Rams 250-3000psi, Valves 250-3000psi. 1 f/p recorded on the HCR Choke, Serviced and Cycled Valve, subsequent test was good. Performed the Koomey drawdown test. 2-7/8" and 3-1/2" Test Joints were used. Witness was waived by Matt Herrera by phone on 6/6/21 @ 14:00hrs,L/D BOP Testing equipment, Pulled test sub and BPV, monitored well static.,M/U 3-1/2" Landing Jt, and circulating lines. Attempt an injection test with no success, pumped away 2.1bbls and pressure climb to 2146psi, SD the pump and monitored pressure for 10mins and bleed off to 0psi. R/D circulating lines. ISIP=2146psi 5min=2076psi 10min=2072psi,BOLDS, Pulled hanger off seat @ 21k, picked up on completion string 10k in tension and set in slips. R/U E-line to make cut. 6/7/2021 Rig up Pollard e-line. RIH with 2.062 jet cutter. Correlate on depth. Make tubing cut at 3754' WLM. POOH and R/D e-line. Pick up on string to 32K with free travel.,Rig up and circulate well at 3 BPM/300 psi. No losses.,Pull tubing hanger to rig floor. Disconnect chemical injection and SSSV lines. Lay down tubing hanger. Make up safety valve.,POOH laying down 3 1/2" IBT completion to 3349'. Spool up chemical injection mandrel and SSSV control lines.,Change out handling equipment. POOH laying down 2 7/8" completion. Spool up chemical injection control lines.,Clean and cleared rig floor of clamps and control line spools, C/O Handling tools to 3-1/2". Tallied 1st row of 3-1/2" Work-string,M/U Cementing Stinger, RIH w/same picking up 3-1/2" 12.95# PH6 Work-string. Tagged Top of Cut Joint @ 3,725'RKB. Picked up 15' and M/U Head Pin and circulating lines. Broke circulation with rig pump.,R/U HAL Cement Equipment, PT lines to 2,500psi. Pump 16 bbls 15.3ppg Primary cement balanced plug. Cement in place at 05:20 hrs.,R/D HAL Cement. Slowly POOH and standing back 10 stands from 3705' to 3090'. Calculated TOC at 3318’. Drop wiper ball and R/U to circulate clean at report time. 6/8/2021 Finish circulating wiper ball at 3 BPM/230 psi.,POOH standing back 2800' of PH6 work string.,POOH laying down remainder of PH6 work string.,Make up 7" casing scraper assembly. RIH with same to +-2700'. Work 100' area for whip stock.,Rig up to reverse circulate.,Reverse circulate at 3.25 BPM/200 psi.,POOH laying down 3 1/2" PH6 work string.,Rig up and test casing/cement plug at 2950 psi on chart for 30 minutes. Good test.,Rig up Pollard slick line. RIH with 2.25 x 5' baler. Tagged TOC 2x @ 3265'slm. Sample of cement recovered.,R/D Pollard SL,C/O Tongs' tallied 3-1/2 Kill String and set in beaver slide. RIH w/4jts (127') of 3-1/2 9.2# L-80 IBT and EOT Cut Muleshoe. PU/MU landing joint and tubing hanger with BPV installed. Landed completion and ran in lock down screws. Drained stack,Clear rig floor of tools and equipment. Removed beaver slide, stairs, handrails and rig floor. Disconnected koomey hoses from stack and umbilical cord from the remote panel. Secure remote panel in doghouse for transport. Removed hoses from mud pump and pits.,Scope down mast. Removed block, Spooled off drill line. Lay mast over. Preparing 404 and auxiliary equipment for rig move Grayling,N/D BOP Stack and Riser, Prep Wellhead to N/U Dry Hole Tree. 6/9/2021 Nipple up tree. Test void at 5K. Continue with general rig down miscellaneous.,Prepare mast for removal. Continue with general rig down miscellaneous.,Continue rigging down and preparing loads for the boat. Crew scrub decks, derrick, etc. Organize and inventory Conex's Boat arrival ETA @ 07:00hrs. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NCIU A-03A North Cook Inlet Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name: Spud Date: g Tagged TOC 2x @ 3265'slm. pgg ,POOH laying down 3 1/2" IBT completion to 3349' @p Pump 16 bbls 15.3ppg Primary cement balanced plug. Make tubing cut at 3754' WLM. Calculated TOC at 3318’ ppg y pgp ,Rig up and test casing/cement plug at 2950 psi on chart for 30 minutes. Good test. p p ,Tested BOPE per Sundry as following: Annular 250-2500psi, Rams 250-3000psi, Valves 250-3000psi. Witness was waived by Matt Herrera RIH w/4jts (127') of gg @ p 3-1/2 9.2# L-80 IBT and EOT Cut Muleshoe. gg @ Activity Date Ops Summary 8/29/2021 Welders extending landings and install same. Skid top section of the rig and center over A-03A wellhead. [Had wellhead hand install TWC in A-03A, then released him.] Install 2" jumper hose in air line. Break bolts on A-03A dry hole tree. Install landings.;Skid upper sub over toward A-03A . Ran out of jacking room w/ 3' to go. Turn jacks around for pushing the sub and finish skidding rig in place over A-03A.;Rig dn hyd jacking hoses. Set earthquake clamps on bottom sub. Clamps hit on the rails where you cant get the bottom clamps on so we welded them down. Drill holes in upper section and bolt sub down. Install stairs on landing f/ HAK rack to rig.;Set slide and install landing next to slide. Hook up Mud, salt water, water, air, low press mud, and cmt lines.;Production Removing obstruction around wellhead. Finish nippling down dry hole tree and removing it from the cellar. Install blanking sub in hanger. Welder finished building fl ow line so its ready to install.;Set in and nipple up riser. Set BOPS on and nipple up to Riser. Role 90s on mud cross Roustabout crew Painting Upper sub beam stiffeners with Primer from previous welding.;Install Choke and kill valves on mud cross and tighten same. Roustabout crew Painting Upper sub beam stiffeners with Primer from previous welding.;Install Bell nipple on BOPs. Continue securing lines. Work on rig acceptance check list.;Wellhead Pressures- Tubing & IA- 0 PSI 8/30/2021 Finish working on rig acceptance check list. Finish hooking up flow nipple. Install mouse hole. LD PU slings. RU Hawkjaw.;PU and MU BOP test jt assem. Had issues with blanking sub and had to re-install. Also had a blockage in the choke line that finally got blown out.;Made one good test and the swivel flange connection on the kill line started leaking. Had to remove kill line hose and valves to replace ring gasket on mud X. Replaced gasket and got kill line back together.;Attempted to test again and the adaptor spool above the well head started leaking. Re-tighten bolts on the spool and do a shell test. tested good.;Test BOPs as per AOGCC to 250/3500 psi. Test annular to 250/2500 psi. Test Annular and pipe rams with 4.5 Test Joint. All Test performed against Blanking sub in hanger. Install flow line and stands.;Accumulator Draw down- 3100 PSI Starting Pressure 1980 PSI After Shut in 200 PSI Increase 22 sec Full Pressure 132 N2- 16 BTLS @ 2278 PSI Average;R/D Testing equipment. Prep for pulling the hanger. Run Lines in cellar to production header to pump to production.;Troubleshoot drillers console communication failure. Unable to use draw works/MP/TD. Lay out one bundle of DP & Strap for clean out run 8/31/2021 Continue working on power issues with drillers console. Found wire that had been stretched tight from the rig move. R epaired wire and made sure we had slack in all the wires.;Break out test equip and MU jt for pulling hanger [Waiting on Production to get gas to test alarms] Working on flow meter to make it more sensitive.;Production tested gas alarms. PU 9 jts of DP with air tuggers MU stands and stand them back in the derrick.;Back out LDS and pull hanger. Break out LD landing as we pull hanger. Pull hanger to the floor. Break out all the XOs and the hanger. LD 4 jts 3 1/2 tbg. Clear floor and prep wash tool.;With wash tool on the bottom of the stand wash down through stack while pumping from ann valve to production low press header. After getting washed to wellhead break off wash tool and run in about 15' in liner washing.;Pumped about 40 bbls taking it to production low pressure header. Mud man taking samples until we passed the sheen test.;M/U running tool and set 9" I.D. wear ring and mobilize clean out BHA tools to the rig floor. M/U CDS-40 to 3-1/2" IF XO, 6.151" O.D. upper mill, flex joint, bit sub and 6.125" Kymera bit to 19'. RIH w/ stand of 4.5" drill pipe and took weight at 55.8' - top of 26# 7" casing.;P/U and inspect bit - good. RIH and take weight again at 55.8', rotate string with chain tongs and bit rolled into 7" casing. TIH with stands and tag top of cement at 3282' with 8K WOB. Rack back stand to 3275'.;PJSM. Perform displacement from water to 9.5 ppg 2% KCl LSND mud. 255 GPM, 475 PSI ICP, 715 PSI FCP. Overboarded 127 bbls of water then take interface and mud back to shaker tanks. Pumped additional 210 bbls to fill shaker tanks. Perform flow check - static. Pump 15 bbls dry job.;POOH from 3275' racking back 4.5" drill pipe to 19'. L/D bit sub and bit. Bit graded 0-0-NO-A-X-I-NO-BHA.;M/U 6.125" window mill, 6.00" lower mill, flex joint, 6.151" upper mill, XO sub, one 4.5" HWDP, XO sub, whipstock valve (verified open), MWD DM & TM collar (measure MWD offset to whipstock highside 120.51°), XO sub to 86' then M/U stand of 4.5" drill pipe.;Dump cold mud from shaker tank then transfer mud from platform pits to provide room to pump. Pulse test MWD tools with 250 GPM, 710 PSI - good test. POOH and M/U whipstock and hydraulic anchor assembly n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NCIU A-03 North Cook Inlet Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Spartan 151 Job Name: Spud Date: LD 4 jts 3 1/2 tbg. gg g Perform displacement from water to 9.5 ppg 2% KCl LSND mud. gpg BOPs as per AOGCC to 250/3500 psi. gp gpg TIH with stands and tag top of cement at 3282' with 8K WOB. ;M/U 6.125" window mill, 9/1/2021 Orientate to whipstock. RIH through wellhead w/ no issues.;RIH w/ whipstock filling pipe w/ fill up hose at about 1800' & continue RIH to 3143'.;Orientate tool to 26° left. Attempt to set whipstock w/ bottom of window at 3223' and top at 3208'. Made several attempts with no success. Baker consulted with his people in town and decided something on the tool was faulted.;Pump dry job and POH. Stand back BHA down to MWD tools. PU and remove whipstock. Lay down TM and DM collars. Break and LD window mill. Layout the rest of the mill assem together. Looks like the reason the whipstock wouldn't set is because;The whipstock valve didn't shift .;M/U Baker 7" mechanical set 3BB bridge plug and 3-1/2" IF x 4-1/2" CDS40 XO . TIH on 4-1/2" drill pipe to 3228'. Filled pipe once at 20 stands.;Place bridge plug on depth at 3228', 85K PU / 82K SO. Apply 11 rounds right hand turns & slack off - did not set. Continue to work string up to 15' high slacking off fast to work torque down and applying more right turns. Worked pipe 26 times and applied up to 50 right revolutions.;Fill pipe, caug ht pressure and pressure built and did not drop off. Bleed pressure off. Slack off, plug not set. P/U to 100K (pipe full now). Slack off to 60K, bridge plug set. P/U and set down to 60K twice more to verify set. P/U observe travel at 90K stop at 110K then S/O to 105K.;Apply right turn, saw release at 3 revolutions, but continued to 10 total turns. P/U with 95K free travel - verified release.;POOH with bridge plug running tool from 3226' and laydown running tool;M/U 6.125" window mill, 6.0" lower mill, flex joint, 6.151" upper mill, XO, one joint of 4.5" HWDP, XO, MWD DM and TM collars. Perform MWD to whipstock highside offset measurement - 268.66°. Shallow pulse test MWD w/ 235 GPM, 530 PSI - good test.;P/U bottom trip anchor and 7" whipstock assembly. Remove shipping screw and one anchor set screw. 5 remaining sets screws in anchor = 18K set. M/U mills to whipstock with 35K shear bolt.;Trip in hole with whipstock / milling assembly on none 4.75" drill collars, eighteen 4.5" HWDP and 4.5" drill pipe at 90'/min running speed to 2402'. 9/2/2021 Finish RIH to 3148'. Bring pump on and stage up to 250 GPM. orientate whipstock to 35°L, Slack off and tag at 3226', Set dn 18k and anchor set, PU to 10k k over up wt, Slack off to 60k but seen pin shear at 40k, PU 10' and slack back off setting dn 5k.;PU 5' and get rotating parameters. At 60 rpm we had 5k torque, 260 GPM, 950 psi. Start milling window at 3209', Mill reached bottom of window at 3222'.;Dressing window with upper mill and drilling new hole f/3222' t/3244'. [Pumped high vis sweep at 3226' and 3244'];Circ hole clean with mud wt even all the way around. Also worked tools through window to ensure window is clean. 65# metal recovered during milling and circulating.;Pump through choke and kill lines and rig up to perform FIT to 14.7 ppg MWE . Pressure up to 795 psi taking pressures every stk.for 13 stks at full pressure. Monitor press every min for 13 min. Total pumped 1.17 bbls, got back .71 bbls. Sent press charts to town.;Blow dn lines and pump dry job.;POH racking back drill pipe, HWDP and drill collars. L/D Baker milling assembly. Normal wear on all mi lls and upper mill in gauge 6.16". Clean and clear rig floor.;Pull wear bushing. M/U Johnny Wacker on a stand of drill pipe and flush stack with 5 BPM. L/D Johnny Wacker and rack back stand. Re-install wear bushing. Recovered 5# metal after flushing stack = 70# total.;M/U BHA #3: 6-1/8" Kymera K5M323 bit, 4-3/4" mud motor, float sub, MWD DM & TM collars, XO, 2 jts HWDP and jars to 210'. TIH w/ stands of HWDP from the derrick to 487'.;Single in the hole with 4-1/2" CDS-40 drill pipe f/ 487' t/ 3086'. g to 14.7 ppg MWE . pg Start milling window at 3209', Mill reached bottom of window at 3222'.;D ;M/U 6.125" window mill, ;RIH w/ whipstock Pressure up to 795 psi taking gg gpg gpp pressures every stk.for 13 stks at full pressure. Monitor press every min for 13 min. Total pumped 1.17 bbls, got back .71 bbls. ppg bridge plug on depth at 3228', ;Place y ;M/U Baker 7" mechanical set 3BB bridge plug perform FIT p From:Karson Kozub - (C) To:McLellan, Bryan J (OGC); Katherine O"connor Cc:Juanita Lovett Subject:RE: [EXTERNAL] RE: NCI A-03 PTD 168-099 Rig Prep Sundry Date:Friday, June 25, 2021 7:57:59 AM Attachments:N Cook Inlet Unit A-03 PTD 168-099 - Approved Sundry_321-160_050621.pdf Good Morning Bryan, On A-03 P&A there is a slight change from the email below. Since we were unable to inject into formation we did not run the EZSV (cement retainer), we placed cement right on top of the packer at 3,759’. We pumped 16BBL of cement and tagged TOC at 3,265’ ~ 494’ above the packer. The plug was then pressure tested to 2,875psi a held for 30 min. I wanted to let you know of the changes to the below email. Attached is the approved sundry for reference. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Monday, June 7, 2021 11:08 AM To: Katherine O'connor <Katherine.Oconnor@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub - (C) <kkozub@hilcorp.com> Subject: [EXTERNAL] RE: NCI A-03 PTD 168-099 Rig Prep Sundry Sounds good Katherine. Your plan is approved. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent: Monday, June 7, 2021 11:04 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub - (C) <kkozub@hilcorp.com> Subject: NCI A-03 PTD 168-099 Rig Prep Sundry Hi Bryan Following up on our phone conversation, we were not able to inject into the formation down the tubing into the CI stray perfs. This is believed to be due to perfs sanding out. Our new plan will be to place 10 BBL (~254’) of cement on top of the EZSZ for zone abandonment. TOC will be +/-3,396’ after cement is pumped. We will then continue on with step 12 of sundry 321-160. Thank you! Katherine O’Connor CIO Operations Engineer Katherine.oconnor@hilcorp.com W: (907) 777-8376 C: (214) 684-7400 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 deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 Unit / Tertiary System Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,480'N/A Casing Collapse Structural Conductor Surface 630 psi Intermediate 2,090 psi Production 4,320 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 Other: PB for Sidetrack N/A PRESENT WELL CONDITION SUMMARY Length Size 3,580 psi COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 168-099 50-883-20020-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-03 See schematic6,392' 3,939' 3,552' 1,142 psi 9.2 L-80 / 6.5 L-80 / 12.6 J-55 TVD Burst 406' / 3,962' /6,289' 4,980 psi MD 1,640 psi 384' 612' 2,329' 384' 612' 30" 16" 384' 10-3/4"2,519' 612' 7,475' Perforation Depth MD (ft): 2,519' 3,915 - 3,979 7,475' See schematic & 367 (MD) 367 (TVD) Tubing Grade:Tubing MD (ft): 3,532 - 3,585 Perforation Depth TVD (ft): Tubing Size: 6,388'7" 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. 4/20/2021 3-1/2" / 2-7/8" / 4-1/2" Daniel E. Marlowe See schematic & WLRSV / SLVN-XXO Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:58 am, Apr 01, 2021 321-160 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.04.01 10:04:43 -08'00' Dan Marlowe (1267) DSR-4/1/21 SFD 4/1/2021 Sterling Undefined Gas Pool SFD 4/1/2021 SFD 4/1/2021 X Pressure test 7" casing to a minimum of 2875 psi after P&A cement plug is in place (this is MPSP for the planned NCI A-03A sidetrack). 10-407 BOP test pressure 3000 psi. Annular test pressure to 2500 psi. BJM 5/6/21 Comm ption Required? Yes 5/6/21 dts 5/6/2021 JLC 5/6/2021 RBDMS HEW 5/7/2021 Well Work Prognosis Well Name:NCIU A-03 API Number: 50-883-20020-00-00 Current Status:SI Producer Leg:Leg #3 SE Corner Estimated Start Date:April 20, 2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:168-099 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8387 (O) (214) 684-7400 (M) Current Bottom Hole Pressure: 1,484 psi @ 3,427’ TVD 0.433 lbs/ft gradient to surface Maximum Expected BHP:1,484 psi @ 3,427’ TVD 0.433 lbs/ft gradient to surface Maximum Potential Surface Pressure: 1,142 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary A-03 is currently a watered out gas producer. The well was worked over in 2019 and produced from the A Sand. Later a tubing plug was set to isolate the A and produce the X-sand. Coil tubing was used to clean out the well, isolate the CI-X sands, and produce the stray sands in 2020. The well has since watered out. The work proposed will isolate the current wellbore and set up for a sidetrack. Wellbore Notes: x Tubing plug set at 3,939’ WLM. *Top AA stop not installed due to sand inflow during SL operations x Coil clean out to 3,939’ on 8/1/2020 x Tubing punch 3,908’-3,911’ x Tubing patches at 3,788’-3,809’ & 3,870-3,882’ ID 1.875” x MIT-IA passed 11/16/2019 – 1,600psi charted 30 min x MIT-T passed 11/16/2019 – 4,000psi charted 30 min Procedure: 1. RU Slickline pressure test lubricator to 250psi low/1,500psi high a. Pull SSSV b. Pull GLV at 3,654’ for circulation, 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. RU E-line. RIH and cut tubing at ±3,750’ 7. Pull upper completion fishing tubing and cleaning out as needed to ±3,750’. 8. RIH and set EZSV ±3,680’. POOH and RD E-Line 9. RIH, sting into EZSV. 10. Conduct injectivity test. 11. Perform Hesitation Squeeze with ±20 BBL of cement through EZSV. 12. Un-sting from EZSV and place 25ft (~1 BBL)of cement on top of EZSV x Depending upon squeeze. Can place up to 18 BBL on top of retainer. Note: Max TOC is 3,200’ for a 2,950’ whipstock x Circulate clean. POOH. 13. Wait on cement, RIH and tag TOC 14. Test IA to 1,500 psi and chart for 30 minutes. 15. Land hanger with bottom of tubing at ±120’ 16. ND BOPE and NU tree, test same. 17. RD HAK 404 and move off location 18. Suspended operations until drilling rig moves on location Test IA to minimum 2875, which is the MPSP for NCI A-03A. BJM Planned brine is SW or produced water. Wellbore volume from EZSV to Plug back TD at 3988' is approximately 7-8 bbls. Well Work Prognosis ***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 4a. Plan to Set whipstock at +/-2600' MD. ____________________________________________________________________________________ Updated by: JLL 08/24/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PBTD:3,981’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A 3 4 5 6 A B C D E G TOC 3,260’ 7” Stage Collar 5,114” , 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 1 2 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ 3,908’ – 3,911’ 13 Tubing Patches 3,788’- 3,809’ + 3,870’ – 3,882’ ID 1.875” F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT Mod 2.992” Surf 406’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441” 406’ 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 37.65 37.65 Hanger – 3-1/2” EUE 8rd lift & suspend, 3” type “H” BPV profile 1 367’ 367’ 2.813” 4.420” WLRSV / SLVN-XXO 2 406’ 406’ 2.375” 4.250” 3-1/2” x 2-7/8” Crossover 3 1,799’ 1,738’ 2.441” 4.750” GLM #1 - SFO-1 4 2,820’ 2,581’ 2.441” 4.750” GLM #2 – SFO-1 5 3,654’ 3,308’ 2.441” 4.750” GLM #3 – SFO-1 6 3,706’ 3,353’ 2.347” 4.748” Chemical Injection Mandrel 7 3,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 8 3,872 3,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing plug w/ top AA stop 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve- Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths TOC below csg shoe ____________________________________________________________________________________ Updated By: JLL 08/24/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 07/30/20 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Open CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Open CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Open CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Open CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) ____________________________________________________________________________________ Updated by: JLL 03/08/21 PROPOSED North Cook Inlet Well:NCI A-03 Last Completed: FUTURE PTD:168-099 API:50-883-20020-00 PBTD: 3,981’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A A B C D E G TOC 3,260’ 7” Stage Collar 5,114” , 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ 3,908’ – 3,911’ 13 Tubing Patches 3,788’- 3,809’ + 3,870’ – 3,882’ ID 1.875” EZSV @ ±3,680 w/ 25’ cement – TOC ± 3,655’ Tubing cut ± 3,750’ F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 2-7/8” 6.5 L-80 EUE 8 rnd 2.441”Surf ±120 2-7/8” 6.5 L-80 EUE 8 rnd 2.441”±3,750 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item ±3,680’ ±3,330’ EZSV W/ 25’ cement (TOC ± 3,655’) ±3,750’ ±3,391’ Tubing cut 73,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 83,8723,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing plug w/ top AA stop 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths TOC below csg shoe ____________________________________________________________________________________ Updated By: JLL 03/08/21 PROPOSED North Cook Inlet Well:NCI A-03 Last Completed: FUTURE PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 07/30/20 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Isolated CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Isolated CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Isolated CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Isolated CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Isolated CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Wellhead - NCIU A-03 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-03 28 X 16 X 10 3/4 X 7 x 3 1/2 16'’ 10 ¾’’ 7'’ 3 ½’’ 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 BOP Stack Rig 404 SwacoSuperchokeBlooey LineTo Gas BusterInlet 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 OChoke manifold drawing has been superseded.See attached choke manifold diagram. 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 OChoke manifold drawing has been superseded.See attached choke manifold diagram. 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.) 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-03 (PTD 168-099)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 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: 10/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI A-03 (PTD 168-099) Memory Multi Finger Caliper Log 08/02/2020 Please include current contact information if different from above. PTD: 1680990 E-Set:34112 Received by the AOGCC 10/16/2020 Abby Bell 10/20/2020 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 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 7,480 feet See schematic feet true vertical 6,392 feet N/A feet Effective Depth measured 3,939 feet See schematic feet true vertical 3,552 feet See schematic feet Perforation depth Measured depth 3,915 -3,979 feet True Vertical depth 3,532 - 3,585 feet Tubing (size, grade, measured and true vertical depth)3-1/2"/2-7/8"/ 4- 1/2" 9.2 L-80/6.5 L80/ 12.6 J-55 406/3,962/6,289 (MD) 406/3,571/5,425 (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: Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst kkozub@hilcorp.com Tubing Pressure 630psi 2,090psi 1,640psi 3,580psi 907 777-8384 4,980psi 384 612 2,329 6,388 Karson Kozub 384 612 Conductor Surface 4,320psi 30" 16" 10-3/4" 2,519 7,475 Size 722 Production Casing Structural Liner Length Intermediate N/A Junk 5. Permit to Drill Number: 1,832 North Cook Inlet Unit / Tertiary System Gas PoolN/A measured 2,519 0 Gas-Mcf 448 N/A Oil-Bbl 0 Water-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-308 797 Authorized Signature with date: Authorized Name: 2 WINJ WAG STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 168-099 50-883-20020-00-00 Plugs ADL0017589 / ADL0037831 N Cook Inlet Unit A-03 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 2240 Casing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 7" 7,475 MD 384 612 TVD measured true vertical Packer Other: CTCO / Tubing Punch/Patch measured Collapse Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 12:00 pm, Aug 26, 2020 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2020.08.26 09:16:02 -08'00' Dan Marlowe (1267) RBDMS HEW 8/27/2020 CTCO / Tubing Punch/Patch Plug Perforations SFD 8/28/2020DSR-8/27/2020gls 9/21/20 ____________________________________________________________________________________ Updated by: JLL 08/24/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PBTD:3,981’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A 3 4 5 6 A B C D E G TOC 3,260’ 7” Stage Collar 5,114” , 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 1 2 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ 3,908’ – 3,911’ 13 Tubing Patches 3,788’- 3,809’ + 3,870’ – 3,882’ ID 1.875” F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT Mod 2.992” Surf 406’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441” 406’ 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 37.65 37.65 Hanger – 3-1/2” EUE 8rd lift & suspend, 3” type “H” BPV profile 1 367’ 367’ 2.813” 4.420” WLRSV / SLVN-XXO 2 406’ 406’ 2.375” 4.250” 3-1/2” x 2-7/8” Crossover 3 1,799’ 1,738’ 2.441” 4.750” GLM #1 - SFO-1 4 2,820’ 2,581’ 2.441” 4.750” GLM #2 – SFO-1 5 3,654’ 3,308’ 2.441” 4.750” GLM #3 – SFO-1 6 3,706’ 3,353’ 2.347” 4.748” Chemical Injection Mandrel 7 3,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 8 3,872 3,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing plug w/ top AA stop 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve- Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths 12 I- Say CI- -Stray 3 Say Stray 1-S ____________________________________________________________________________________ Updated By: JLL 08/24/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 07/30/20 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Open CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Open CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Open CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Open CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) IsolatedCI-X 3,790’3,806’3,427’3,439’16’6 07/30/20 Rig Start Date End Date CTU/EL/SL 7/27/20 8/7/20 07/27/20 - Monday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit A-03 50-883-20020-00-00 168-099 07/29/20 - Wednesday Morning meeting, PJSM, Get permit signed. Standby for Rig 169 to release HES cementers. HES Cementers arrive on Tyonek from Beluga. Job in Progress. PJSM & permits. Continue MIRU CTU. Test BOPE as per Hilcorp & AOGCC requirements, witnessed waived 7/26/2020 by AOGCC Inspections Supervisor Jim Regg, 250/3500. BOP test done. Change packoffs, rig up rest of hardline, hoses to return tanks and filter pod. Hook up all hoses to injector head, function test reel and injector. SDFN Arrive at Heliport, get checked in, standby for delayed helicopter. Arrive on Tyonek. Get checked in, get orientation for two SLB guys. MIRU CTU. Prep and get ready for an AM start for a BOP test. 07/28/20 - Tuesday 07/30/20 - Thursday PJSM & permits. RU CTU. Move injector to WHA. PT = 250/4300. Op en well, swab 19 turns, WHP 560, IA 700, OA 0. RIH. WT CK 2000'=0 lbs. CTRIH. Tag @ 3827' RKB. PU 200' start bleeding off WHP (560 psi) to the tank. Getting back all gas. WHP @ Zero not getting any fluid returns. Come online with Coil pump to FCO. FCO from 3827' to 3900', do four bottoms up jetting out formation f ines (sand) till clean returns are seen back at the tank. Shut down pump. Line up to do injection test. @ .5 bpm WHP 171, IA 700, OA 0. @ 1 bpm, WHP 452, IA 700, OA 0. Shut down coil pump, start batching up 15.8 ppg Cement. Parked at 3800' RKB, HES online down coil pumped 11.6 bbls 15.8 ppg cement. Swap to DW displaci ng CMT to nozzle. CMT at nozzle 29.6 bbls, WHP 442, IA 700, OA 0. Squeeze 11 bbls 15.8 cement in th e Sterling X Sands. WHP 963, IA 720, OA 0. HES offline, WHP 912, IA 700, OA 0. POOH keeping hole full @.4bpm. WHP 210, IA 700, OA 0, CTP 280, Tagged up, WHP 50, IA 700, OA 0. Swab shut 19 turns, bleed dow n, blow down, pop off well. Let cement set up for 18-24 hrs. SBFN 07/31/20 - Friday Open swab. Roll C-pump, WHP = 100 psi instantly w/ no injectiv ity. SD C-pump, WHP falls to 0 psi. Roll triplex pump, WHP = 600 psi instantly w/ no injectivity. Initi al WHP = 600 5 min WHP = 544 10 min WHP = 438 psi Shut in well. SDFN. Job in Progress Squeeze 11 bbls 15.8 cement in the Sterling X Sands. RU CTU. Move injector to WHA. Rig Start Date End Date CTU/EL/SL 7/27/20 8/7/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit A-03 50-883-20020-00-00 168-099 08/01/20 - Saturday PJSM & Permits. Pick up injector head, 18' lubricator, Make up CTC, pull test 35k, make up milling bha, pt low 250, high 3500. BHA1: CTC(2" x 0.23'), DFCV(2.13" X 1.70'), BI-DI JAR(2.13" x 5.18'), DISCO(2.13" X 1.58'), CIRC SUB(2.13" X 1.17'), MOTOR(2.13" X 11.60'), JUNK MILL(2.25" X 0.96') OAL = 22.42'. DISCO BALL = 9/16' CIRC SUB BALL = 1/2" w/ 5K RUPTURE DISC. RIH w/ Motor & Mill BHA to cement top tag @ 3790'. Bring on pump @ 1.25 BPM. Mill hard cement to 3909' w/ 1:1 returns @ 0.50 FPM penetration rate. 3909' break thru bottom of cement column into sand fill. Circ bottoms up and hol e clean. POOH. LD motor & mill. MU BHA2: CTC(2" x 0.23'), DFCV(2.13" X 1.70'), BI-DI JAR(2.13" x 5.18'), DISCO(2.13" X 1.58'), CIRC SUB(2.13" X 1.17'), DJN(1.75" x 0.58') OAL = 10.44'. DISCO BALL = 9/16'. CIRC SUB BALL = 1/2" w/ 5K RUPTURE DISC. Move to well. PT WHA & Lub = 250/2500. Open swab. Roll pump to establis h injection rate & well pressures up to 200 psi instantly, unable to establish injection rate to well. RIH to tag at 3909'. Wash down to top of Packoff Plug Assy @ 3939' RKB, pumping 1.50 BPM fluid w/ 1:1 re turns. Circ bottoms up & hole clean. Attempt to inject to well, NO GO. POOH. RD & stand back CTU. Ni pple down BOP & WH stack. Normal up tree & prep for ELU. SDFN. Job in Progress. 08/02/20 - Sunday PJSM & permits. RU ELU. MU caliper log tool suite. Move to well . PT WLV & Lub = 250/2500. Fix leaks on Lub. Open well, Swab 19 turns. RIH W/ Reed Caliper logging tool . WHP 0, IA 700, OA 0. RIH, tag tubing stop at 3939' RKB, Caliper log up to 3650'. Download data, send to Engineers for verification on setting depths for patches. Make up 11.5' 2.25" OD X 1.875" ID patch, stab on well, open swab, 19 turns. RIH, set down at X Nipple 3888' rkb, pu getting on depth. Make .5' correction. Pul l up to CCL depth 3860.5', CCL top element 9.5', CCL bottom element 21'. Set patch @ 3870-3881.5' RKB. POO H. Tagged up, swab shut, bleed down, pop off well. Redress setting tool. Setting tool redressed. Mak e up 21.5' X 2.25" OD X 1.875" ID patch. Stab on well. Open Swab 19 turns. WHP 0, IA 700, OA 0. RIH to 3820', log up getting on depth, .5' correction. Pull into CCL depth 3778.5'. CCL to top element 9.5', CCL to bottom element 31'. Set patch at 3788-3809.5' RKB. POOH, Tagged up, swab shut, bleed down, pop off well. RD ELU. Turn well over to production to gas lift fluid off well for upcoming tubing punch. Job in progress. 08/03/20 - Monday No operations to report 08/04/20 - Tuesday No operations to report . Set patch at 3788-3809.5' Rig Start Date End Date CTU/EL/SL 7/27/20 8/7/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit A-03 50-883-20020-00-00 168-099 SLU crew arrives platform. PJSM & permits. Waiting while crane backloads CTU equipment package to MV Sovereign. T/IA = 700/698 Min ID = 1.75" drift patches @ 3788' - 3809' KB & 3870' - 3881.5' KB. RU SLU & MU toolstring: 1-1/4" RS w/ 1-1/2" WB, OJ, LSSJ & 1.50" X 6' DD Bailer w/ chisel bottom. Move to well. PT WLV & LUB = 250/1500. Open swab, T/IA = 750/698. RIH to top of fill @ 3906' KB. Work tools. POOH. OOH w/ full bailer of formation sand. Change out to 1-3/4" X 6'DD Bailer w/ chisel bottom. RBIH w/ 1.75" DD bailer to 3907' KB set down depth. W/T. POOH. Pass thru 2-7/8" patches, d own & up, w/o restriction. OOH w/ full bailer of sand. Add 3' extension, for total of 9' bailer tube, to 1.75" DD Bailer. RBIH to 3909' KB set down depth. W/T. OOH w/ 2/3 full bailer of sand. Standby while crane works MV Titan backloading remaining 14 picks of CTU package. RBIH w/ 1.75" DD bailer w/ flapper bottom to 3912' KB. W/T. POOH. OOH w/ 1/4 full bailer of sand. RBIH w/ same w/ chisel bottom to 3913' KB. W/T. OOH w/ full bailer of sand. Drop off 1.75" DD bailer. MU BL Brush. RIH w/ BLB to 3915' KB. W/T 3881' - 3815' KB. POOH. Drop off BLB & MU 1.75" X 9' DD Bailer w/ chisel bottom. RBIH w/ 1.75" DD bailer to 3915'. W/T to 3918' KB. OOH w/ full bailer of sand. RD SLU. RU ELU. MU CCL/Firing Head tool suite. Surface test CCL & FH. PU Tubing Punch Gun: 1-9/16" x 3', 6spf(total shots = 19), 0* phase, 3.0 gm HMX explosive for 0.39" dia. perf hole per shot. Move to well, PT WLV & LUB = 250/1500. T/IA = 660/658 CCL-to-Top Shot = 3.8' CCL-to-Bottom Shot = 6.8'. Production tops off WHP w/ production gas T/IA = 760/698. ELU RIH w/ 1-9/16" x 3' Tubing Punch Gun to 3909.5' CCL. Log up to 3587' CCL for correlation to 11/16/19 Tubing Tally. Correct + 2.3'. RBIH to 3909.5' CCL. Log up to 3904.7' CCL to place shots on depth (3904.7' + 3.8' = 3908.5' Top Shot). Fi re Tubing Punch Gun to punch 2-7/8", 6.5# tubing w/ 19 perf holes @ 0.39" dia. per perf hole (2.26 sq. inches of flow area) across Stray Sands #1, 2 & 3 from 3908.5' - 3911.5' KB. T/IA = 760/698. Log up 200' & POOH. OOH w/ all shots fired. T/IA = 840/698. Close Swab. RD ELU. Secure well & turn over to Production to bring online. SDFN. Job in Progress. 08/05/20 - Wednesday ELU crew arrives on platform. PJSM & Permit. RU ELU. MU CCL logging tool suite & firing head. Surface test CCL. Fire check firing head. MU 6' tandem Tubing Punch perf gun: 1-9/16" OD X 7.1', 6spf, 0* phase, 3 gm HMX Explosive for 0.31 ID perf holes. Tandem punch gun is confi gured for upper gun w/ 3' of shots (total shots = 19), 2' blank spacer & lower gun w/ 3' of shots (total shots = 19). Move to well. PT WLV & LUB = 250/1500. T/IA = 700/700,CCL-to-Top Shot = 3.75' CCL-to-2' Blan k = 7.75' CCL-to-Bottom Shot = 11.75' CCL-to- Bottom of Gun = 13.25'. Open swab. Production increases WHP = 730. ELU RIH w/ 6' tandem Tubing Punch Perf Gun to 3893' CCL tag depth. Work tool suite in hole, unabl e to pass 3893' CCL Depth + 13.25' = 3906.25' KB tag depth. Set down at tags feel solid but are not sticky. POOH. OOH. No marks on tool. LD perf gun. MU jar, weight bar & 1.36" OD sedge. RIH to tag @ same = 3906' KB. Work tools. Appear to be making hole when beating down & lose it after pickup. Able to beat down to ~ 3911' KB but lose hole each time PU tool off bottom. Pick ups are not sticky. Appear to be beating thru soft & fluffed fill. POOH. Check tools for damage or sand . None found. Call for SLU crew to bring bailers & tools. RD ELU for night. Will resume in morning bailing fill w/ SLU. Job in Progress 08/06/20 - Thursday Rig Start Date End Date CTU/EL/SL 7/27/20 8/7/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit A-03 50-883-20020-00-00 168-099 08/07/20 - Friday PJSM & permit. RU SLU w/ 1.75" TS. PT = 250/1500. Redress SSSV packing. RIH w/ 3.50" X-line running tool & SSSV to 370' KB. Hand Spang to set SSSV, pump to control line to stroke valve _ failed. POOH, missed run. Redress packing. RBIH to same, unable to set SSSV. POOH, missed run. Redress SSSV w. 2.85" over-sized packing. RBIH to 370' KB. Hand spang & fall to 371' KB. Test @ control panel, SSSV pressures up & strokes open. Shear off SSSV & POOH. Perform SSSV closure test - PASS. RDMO SLU. Turn over well to Production. Fly crew to beach. Job complete. 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 System Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,480'N/A Casing Collapse Structural Conductor Surface 630 psi Intermediate 2,090 psi Production 4,320 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) 777-8384 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 6,388'7" 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. 8/3/2020 3-1/2" / 2-7/8" / 4-1/2" Daniel E. Marlowe See schematic & WLRSV / SLVN-XXO 3,790 - 3,979 7,475' See schematic & 367 (MD) 367 (TVD) Tubing Grade:Tubing MD (ft): 3,427 - 3 585 Perforation Depth TVD (ft): Tubing Size: 10-3/4"2,519' 612' 7,475' Perforation Depth MD (ft): 2,519' 384' 612' 2,329' 384' 612' 30" 16" 384' 9.2 L-80 / 6.5 L-80 / 12.6 J-55 TVD Burst 406' / 3,962' /6,289' 4,980 psi MD 1,640 psi 168-099 50-883-20020-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-03 See schematic6,392' 3,939' 3,552' 1,177 psi COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 Authorized Signature: Operations Manager Karson Kozub Other: CTCO / Tubing Punch & Tubing Patch CO 68A PRESENT WELL CONDITION SUMMARY Length Size 3,580 psi Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Jody Colombie at 4:02 pm, Jul 20, 2020 320-308 Daniel Marlowe I am approving this document 2020.07.20 15:48:42 -08'00' Daniel Marlowe BOP test to 3500 psig DSR-7/20/2020 X X DLB 07/20/2020 VTL 7/23/20 X 10-404 On behalf of dtseamount dts 7/23/2020 JLC 7/23/2020 alf of dtseamounComm.Com m.e t JLC 7/23/2020 RBDMS HEW 7/24/2020 Well Work Prognosis Well Name:NCIU A-03 API Number: 50-883-20020-00 Current Status:SI Producer Leg:Leg #3 SE Corner Estimated Start Date:August 3, 2020 Rig:Coil, E-line, Slickline Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:168-099 First Call Engineer:Karson Kozub (907) 777-8384 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8387 (O) (907) 214-7400 (M) Current Bottom Hole Pressure: 1,520 psi @ 3,427’ TVD 0.444 lbs/ft (8.53 ppg) Maximum Expected BHP:1,520 psi @ 3,427’ TVD 0.444 lbs/ft (8.53 ppg) Maximum Potential Surface Pressure: 1,177 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary A-03 is currently a watered out gas producer. The well was worked over in 2019 and produced from the A Sand. Later a tubing plug was set to isolate the A and produce the X-sand. This well recently watered out. Slickline was able to move the tubing plug down to 3,939’ WLM. The sleeve to the x-sand is confirmed to leak and fill comes in the tubing. This fill prevents the Stray (1, 2, 3) Sleeve from opening. We have been unable to remove the fill from A-03 with slickline. This sundry will use coil tubing to clean out the well, isolate the CI-X sands with cement and tubing patches, then produce the CI stray sands through a tubing punch. Wellbore Notes: x Tubing plug set at 3,939’ WLM. *Top AA stop not installed due to sand inflow during SL operations x Sleeve at 3,872’ is confirmed to leak. x SSSV is currently removed. x MIT-IA passed 11/16/2019 – 1,600psi charted 30 min x MIT-T passed 11/16/2019 – 4,000psi charted 30 min 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 CTCO fluid will be drill water 2. R/U Cement unit x Pressure test cement lines to 4,500psi/500psi 3. R/U and RIH with coil tubing cleaning out to ±3,888’ 4. POOH to ±3,790’ x Establish injection rates 5. Pump ±10 bbls of cement down coil x Placing cement in the tubing from ±3,888’ to ±3,790’ and squeezing of the Sterling X sands x Hold backpressure on tubing at surface to ensure cement enters the formation x Displace cement to end of tubing x Circulate until clean x POOH with Coil, wait on cement 6. RIH and clean out 2-7/8” tubing to ±3,939’ x Mill up cement and fill to ±3,939’, POOH 7. R/U Slickline. PT lubricator to 1,500psi/250 psi x Place top AA stop on plug at ±3,939’ x Pull and replace plug if necessary 8. R/U E-line. PT lubricator to 1,500 psi/250 psi x Run caliper log from ±3,872’ to ±3,759’ x RIH set E-line patch over sleeve at ±3,872’ Well Work Prognosis x Contingent set additional tubing patch between ±3,872’ to ±3,759’ based on caliper log x * MIT not required, zone isolation only 9. Unload well fluid with gas lift to the production header 10. R/U and RIH with tubing punch to ±3,907’ x Send correlation log to engineer prior to punch. x Punch tubing x Record tubing pressures pressure before and after punch 11. POOH. RD E-line 12. Turn well over to production 13. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic - Current 2. Well Schematic - Proposed 3. Wellhead Diagram - Current 4. Coil Tubing BOP Drawing 5. Coil Layout drawing 6. Sundry Revision Change Form ____________________________________________________________________________________ Updated By: JLL 04/16/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PBTD: 6,380’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A 3 4 5 6 A B C D E G TOC 3,260’ 7” Stage Collar 5,114” 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 1 2 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 13 F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT Mod 2.992” Surf 406’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441” 406’ 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 37.65 37.65 Hanger – 3-1/2” EUE 8rd lift & suspend, 3” type “H” BPV profile 1 367’ 367’ 2.813” 4.420” WLRSV / SLVN-XXO 2 406’ 406’ 2.375” 4.250” 3-1/2” x 2-7/8” Crossover 3 1,799’ 1,738’ 2.441” 4.750” GLM #1 - SFO-1 4 2,820’ 2,581’ 2.441” 4.750” GLM #2 – SFO-1 5 3,654’ 3,308’ 2.441” 4.750” GLM #3 – SFO-1 6 3,706’ 3,353’ 2.347” 4.748” Chemical Injection Mandrel 73,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 83,8723,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing Plug 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths ____________________________________________________________________________________ Updated By: JLL 04/16/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: FUTURE PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 11/15/19 Open CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Open CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Open CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Open CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Open CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) ____________________________________________________________________________________ Updated By: KDK 07/14/20 PROPOSED North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PBTD:6,380’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A 3 4 5 6 A B C D E G TOC 3,260’ 7” Stage Collar 5,114” , 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 1 2 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ ±3,907’13 + 13A 1313A Tbi Tubing Patch @ ±3,872’ F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT Mod 2.992” Surf 406’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441” 406’ 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 37.65 37.65 Hanger – 3-1/2” EUE 8rd lift & suspend, 3” type “H” BPV profile 1 367’ 367’ 2.813” 4.420” WLRSV / SLVN-XXO 2 406’ 406’ 2.375” 4.250” 3-1/2” x 2-7/8” Crossover 3 1,799’ 1,738’ 2.441” 4.750” GLM #1 - SFO-1 4 2,820’ 2,581’ 2.441” 4.750” GLM #2 – SFO-1 5 3,654’ 3,308’ 2.441” 4.750” GLM #3 – SFO-1 6 3,706’ 3,353’ 2.347” 4.748” Chemical Injection Mandrel 73,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 83,8723,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 ±3,938’ ±3,551’ - 2.441 CIBP 13 a 3,939’ 3,552’ Tubing plug w/o top AA stop 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths ____________________________________________________________________________________ Updated By: KDK 07/14/20 PROPOSED North Cook Inlet Well:NCI A-03 Last Completed: FUTURE PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 11/15/19 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Open CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Open CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Open CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Open CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Wellhead - NCIU A-03 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-03 28 X 16 X 10 3/4 X 7 x 3 1/2 16'’ 10 ¾’’ 7'’ 3 ½’’ 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 Coiled Tubing BOP 07/13/2020 SWAB VALVE MASTER VALVE 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-03 (PTD 168-099)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. 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, Sterling Undef Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,480'N/A Casing Collapse Structural Conductor Surface 630 psi Intermediate 2,090 psi Production 4,320 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 Authorized Signature: Operations Manager Joe Kaiser Other: Tubing Punch & Tubing Patch CO 779 PRESENT WELL CONDITION SUMMARY Length Size 3,580 psi COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 168-099 50-883-20020-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-03 See schematic 9.2 L-80 / 6.5 L-80 / 12.6 J-55 TVD Burst 406' / 3,962' /6,289' 4,980 psi MD 1,640 psi 384' 612' 2,329' 384' 612' 30" 16" 384' 10-3/4"2,519' 612' 7,475' Perforation Depth MD (ft): 2,519' 3,790 - 3,979 7,475' See schematic & 367 (MD) 367 (TVD) Tubing Grade: Tubing MD (ft): 3,427 - 3 585 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. 4/27/2020 3-1/2" / 2-7/8" / 4-1/2" Daniel E. Marlowe See schematic & WLRSV / SLVN-XXO Tubing Size: 6,392' 3,939' 3,552' 1,177 psi 6,388'7" 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 2020.04.17 11:04:27 -08'00' Daniel Marlowe By Jody Colombie at 2:09 pm, Apr 17, 2020 320-169 gls 4/17/20 X DLB 4/17/2020 DSR-4/17/2020 gls 10-404 Comm on Required? Yes 4/20/2020 dts 4/20/2020 JLC 4/20/2020 Well Work Prognosis Well Name:NCIU A-03 API Number: 50-883-20020-00 Current Status:Producer Leg:Leg #3 SE Corner Estimated Start Date:April 27th, 2020 Rig:E-line Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:168-099 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: 1,520 psi @ 3,427’ TVD 0.444 lbs/ft (8.53 ppg) Maximum Expected BHP:1,520 psi @ 3,427’ TVD 0.444 lbs/ft (8.53 ppg) Maximum Potential Surface Pressure: 1,177 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary A-03 is currently a watered out gas producer. The well was worked over in 2019 and produced from the A Sand. Later a tubing plug was set to isolate the A and produce the X-sand. This well recently watered out. Slickline was able to move the tubing plug down to 3,939’ WLM. The sleeve to the x-sand is confirmed to leak and fill comes in the tubing. This fill prevents the Stray (1, 2, 3) Sleeve from opening. This sundry will punch the tubing in the Sterling stray sand zone to produce the Sterling Stray sands. A tubing patch will be placed over the CI-X sand sleeve at 3,872’ to isolate this sand. Wellbore Notes: x Tubing plug set at 3,939’ WLM. x Sleeve at 3,872’ is confirmed to leak. x Slickline to bail down prior to E-line rig up. x SSSV is currently removed. Procedure: 1. MIRU E-line. PT lubricator to 1,500 psig Hi, 250 psi low. 2. RU tubing punch. RIH with tubing punch to ~3,907’. x Send correlation log to Engineer prior to punch. x Gas lift pressure on well (~850 psi) x Punch tubing x Record pressure before and after punch. 3. POOH. RD E-line. 4. RU slickline. PT lubricator to 1,500 psig Hi, 250 psi low. 5. RU tubing patch. RIH set patch over sleeve at ~3,872’. 6. RU SSV running tool and SSV. Set SSV in profile at ~367’. 7. RD Slickline 8. Turn well over to production 9. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed (patch is below packer) This sundry will punch the tubing in the Sterling stray sand zone to produce the Sterling Stray sands. A tubing patch will be placed over the CI-X sand sleeve at 3,872’ to isolate this sand. ____________________________________________________________________________________ Updated By: JLL 04/16/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PBTD: 6,380’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A 3 4 5 6 A B C D E G TOC 3,260’ 7” Stage Collar 5,114” 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 1 2 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 13 F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT Mod 2.992” Surf 406’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441” 406’ 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 37.65 37.65 Hanger – 3-1/2” EUE 8rd lift & suspend, 3” type “H” BPV profile 1 367’ 367’ 2.813” 4.420” WLRSV / SLVN-XXO 2 406’ 406’ 2.375” 4.250” 3-1/2” x 2-7/8” Crossover 3 1,799’ 1,738’ 2.441” 4.750” GLM #1 - SFO-1 4 2,820’ 2,581’ 2.441” 4.750” GLM #2 – SFO-1 5 3,654’ 3,308’ 2.441” 4.750” GLM #3 – SFO-1 6 3,706’ 3,353’ 2.347” 4.748” Chemical Injection Mandrel 73,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 83,8723,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing Plug 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) Prior to pulling tubing plug or opening any other sleeves refer to Conservation Order 779 A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths open close ____________________________________________________________________________________ Updated By: JLL 04/16/20 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: FUTURE PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 11/15/19 Open CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Open CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Open CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Open CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Open CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) ____________________________________________________________________________________ Updated By: JLL 04/16/20 PROPOSED North Cook Inlet Well:NCI A-03 Last Completed: 11/17/2019 PTD:168-099 API:50-883-20020-00 PBTD: 6,380’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A 3 4 5 6 A B C D E G TOC 3,260’ 7” Stage Collar 5,114” , 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 1 2 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ ±3,907’13 Tubing Patch @ ±3,872’ F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT Mod 2.992” Surf 406’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441” 406’ 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 37.65 37.65 Hanger – 3-1/2” EUE 8rd lift & suspend, 3” type “H” BPV profile 1 367’ 367’ 2.813” 4.420” WLRSV / SLVN-XXO 2 406’ 406’ 2.375” 4.250” 3-1/2” x 2-7/8” Crossover 3 1,799’ 1,738’ 2.441” 4.750” GLM #1 - SFO-1 4 2,820’ 2,581’ 2.441” 4.750” GLM #2 – SFO-1 5 3,654’ 3,308’ 2.441” 4.750” GLM #3 – SFO-1 6 3,706’ 3,353’ 2.347” 4.748” Chemical Injection Mandrel 73,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 83,8723,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing Plug 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) Prior to pulling tubing plug or opening any other sleeves refer to Conservation Order 779 A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen –Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve –Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths ____________________________________________________________________________________ Updated By: JLL 04/06/20 PROPOSED North Cook Inlet Well:NCI A-03 Last Completed: FUTURE PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 11/15/19 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 11/15/19 Open CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 11/15/19 Open CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 11/15/19 Open CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 11/15/19 Open CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS REE V17 -151I ED DEC 12 2019 1. Operations Abandon Plug Perforations 4 Fracture Stimulate Pull Tubing shutdownLl Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plu for Redrill � g ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: G/L Completion ❑� 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑� Exploratory ❑ Stratigraphic ❑ Service ❑ 168-099 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-883-20020-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0017589 / ADL0037831 N Cook Inlet Unit A-03 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A North Cook Inlet Field / Tertiary Gas Pool, Sterling Undef Gas Pool 11. Present Well Condition Summary: Total Depth measured 7,480 feet Plugs measured 3,897; 3,988; feet 4,526;4,586; 5,105 true vertical 6,392 feet Junk measured N/A feet Effective Depth measured 3,897 feet Packer measured See Schematic feet true vertical 3,517 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Structural Conductor 384' 30" 384' 384' Surface 612' 16" 612' 612' 1,640 psi 630 psi Intermediate 2,519' 10-3/4" 2,519' 2,329' 3,580 psi 2,090 psi Production 7,475' 7" 7,475' 6,388' 4,980 psi 4,320 psi Liner Perforation depth Measured depth 3,790 - 3,979 feet True Vertical depth 3,427 - 3,585 feet 3-1/2" 9.2 / L-80 406' (MD) 406' (TVD) Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5 / L-80 3,962' (MD) 3,571' (TVD) 4-1/2" 12.6 / J-55 6,289' (MD) 5,425' (TVD) Packers and SSSV (type, measured and true vertical depth) See Schematic WLRSV / SLVN-XXO 367' (MD) 367 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation:1 0 509 628 925 356 Subsequent to operation: 0 3179 3 977 1240 14. Attachments (required per 20 n C 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations Exploratory ❑ Development Service ❑ Stratigmphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas ❑✓ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby Certify that the foregoing Is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-405 Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title:Manager Contact Email: dmarlowe(CDhilcoro.com —/—Opyerations Authorized Signature: 12' I Z I ZC) )91 Date: Contact Phone: (907) 283-1329 Form 10-404 Revised 4/2017 / f� Submit Original Only A V� �2,3.� 3BDMSrI- DEC 1 3 2019 n eom Alaska. LLC RKB: 39', RKB to MSL: 115.9' RKB to Mudline: 235.9' rim I 2 0 3 16" 4 5 10-3/4" 4 wt Grade L H o 7 I Burn e cI-s.o TOC y 29.000 3,260' 10 a. 111 L K o 12 CI -Stray 1 Surf 13 CI-Stray2 45.50&51 J-55 CI -Stray 3 N p p CI -7.0 14 O 15 XN P BTC BTC BTC 16 CI -A 17 GLM rig -SFO -1 5 Top of A 2.441" tubing GLM#3-SFO-1 S 4,003' 3,353' CI -B T B 7 C 3,399' ULt 5.970" Packer- MFH Hydraulic Retrievable straight pull release 30K shear CI -1.0 v 470 D CI -2.0 W E CI -3.1 3,8' 88 3,509' CI -0.0 G` wt Grade p H o I Top I Burn I cI-s.o J EUE 8 rod 29.000 ?' 384' 16, L K o CI -6.0 15.250 Surf 612' M 45.50&51 J-55 f N p p CI -7.0 2,519' O CI -7.1 P BTC BTC BTC 6.276 6.366" 6.276" t, 79' 6,818' 7,475' GLM rig -SFO -1 5 0 0 CI -8.0 2.441" R GLM#3-SFO-1 S 3,706' 3,353' J� T CI -8.2 7 3,759' 3,399' ULt 5.970" Packer- MFH Hydraulic Retrievable straight pull release 30K shear 8 v 470 CI -9.0 2.310" W CI -10.0 s 3,8' 88 3,509' X 3.670" X -Nipple ]"Stage y 0 CI -01.0 Collar Z Tubing Plug 5,114" AA 3,519' BB 5.970" Packer- MFH Hydraulic Retrievable straight pull release 30K shear W CC 0 B-6 i 3.180" C-3 13 DD XN D-4 2.313" 3.670" F-1, F-2, F-4 14 EE G-1, G-5 2.440" 5.970" H-1, H-9 y 3,961' -3 2.205" 3.670" J-2 16 3,962' K-4 2.450" 3.700" N-5 17 3,988' 0-4 7" Q3. Q4 Notes: PBTD: 6,380' TD: 7,480' 12/07/2007 -Set TTGP on Top of fill @4,532' (Tagged 15' high) 01/20/2011- 9.98' difference in elevation is due to being set on Electric Log Depths 2.500 SCHEMATIC North Cook Inlet Well: NCI A-03 Last Completed: 11/17/2019 PTD: 168-099 API: 50-883-20020-00 Size wt Grade Cann I ID I Top I Burn 30" 6.5 conduct., EUE 8 rod 29.000 Surf 384' 16, 65 H-40 EUE Mod 15.250 Surf 612' 10-3/4" 45.50&51 J-55 BTC 9.794 Surf 2,519' 7" 26 23 26 1-55 1-55 1-55 BTC BTC BTC 6.276 6.366" 6.276" Surf 79' 6,818' 79' 6,818' 7,475' 3-1/2" 9.2 L-80 IBTMod 2.992" Surf 406' 2-7/8" 6.5 L-80 EUE 8 rod 2.441" 406' 3,962' 4-1/2" 1 12.60 1-55 EUE Mod 3.958 4,003' 6,289' 2-7/8" Gravel Pack Liner 1 6.40 L-80 SLHT 1 2.441 4,135' 4,527' IFWFI RV nFTAll No Depth (MD) Depth (TVD) ID OD Item 37.65 37.65 large r-3-1/2"EUE End lift & s u spen d, 3" type "H" BPV profile 1 367' 367' 2.813" 4.420" W1-XXO 2 406' 406' 2.375" 4.250" 3-1/2" x 2-7/8" Crossover 3 1,799' 1,738' 2.441" 4.750" GUM #1 -SFO -1 4 2,820' 2,581' 2.441" 4.750" GLM rig -SFO -1 5 3,654' 3,308' 2.441" 4.750" GLM#3-SFO-1 6 3,706' 3,353' 2.347" 4.748" Chemical Injection Mandrel 7 3,759' 3,399' 2.440" 5.970" Packer- MFH Hydraulic Retrievable straight pull release 30K shear 8 3,872 3,496' 2.310" 3.180" Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) OPEN 9 3,8' 88 3,509' 2.313" 3.670" X -Nipple 10 3,897' 3,517' Tubing Plug 11 3,900' 3,519' 2.440" 5.970" Packer- MFH Hydraulic Retrievable straight pull release 30K shear 12 3,919' 3,535' 2.310" 3.180" Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) SLEEVE CLOSED 13 3,935' 3,548' 2.313" 3.670" X -Nipple 14 3,954' 3,564' 2.440" 5.970" Packer - MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961' 3,57(Y 2.205" 3.670" XN Nipple 16 3,962' 3,571' 2.450" 3.700" WLEG 17 3,988' 3,592' EZSV w/ 7' of cement on top (TOC 3,981') 4,135' 3)13' 2.500 Baker 40A-25 SC -1 GP Packer A 4,139' 3,716 2.500 20-25 Mod 5 Gravel Pack Ext w/Sliding Sleeve 4,146 3,722' 2.992 16 Ft Lower Extension 4,193' 3,760' 2.441 2-7/8" Excluder 2000 screen -Med (337') B 4,198' 3,71, 3.990 5.560 No Go seal Assembly C 4,199' 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501' 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve -Closed E 4,525' 4,026 3.990 5.560 N.Go seal Assembly F 4,526 4,027' N/A I 2.875"Bull Plug ' G I 4,521 4,028' 4.000 5.870 Halliburton 1 N Packer& Millout Extension H 4,586' 4,074' 3.813 5.560 HalliburtoaXDsliding Sleeve-Closed(w/PX Plug) 94' 4,081' 3.990 5.560 No Go Seal Assembly 95' 4,081' 4.0005.8]0 Halliburton MR Packer& Millout Extension58' 4,131' 3.813 5.5fi0 Hall iburton XO Slid ing Sleeve-Closed68' 4,139' 3.990 5.560 NoG.Sealpseir ly69' 4,140' 4.000 5.870 HalliburtonP RPacker& Millout Extension4' jT4,S85' 4,199' 3.813 5.560 Halliburton Xo Sliding Sleeve-Closed0' 4,203' 3.990 5.560 NOGG Sea1' 4,204' 4.000 5.870 HaIllbu H.nTWR Packer& Millout Extension25' 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve-Closed1' 4,267' 3.990 5.560 No Go Seal Assembly 2' 4267 4000 5.8]0 lout Bxtension 5' 4,309' 3.990 5.560 No Go seal Assembly 4,310' 4.000 5.870 Halliburton TWR Packer& Millout Extension 4,929' 4,343' 3.813 5.560 Halliburton XD 5l id ing Sleeve -Closed 4,935' 4,34.' 3.990 5.560 NO Go Seal Assembly 4,939 4,349' 4.000 5.870 Halliburton TWR Packer&Millout Extension dBB4,886' 5,046' 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve -Open 12/13/2001 5,105' 4,481' N/q 4.500 Set 4.5- My Britlge Plug 5111T 4,48]' 3.990 5.560 No Go Seal Assembly 5,114' 4,488' 4.000 5.8]0 Halliburton TWR Packer& Millout Etension 5,626' 4,898' 3.813 S.NoHalliburton XA Sliding Sleeve -Closed 6,288' 5,424' 3.]25 S.560 Halliburton XN Landing Nipple EE 6,289' 5,425' 3.980 1 1 Wireline Re -Entry Gulde Updated By: JILL 12/10/2019 North Cook Inlet Well: NCI A-03 Last Com SCHEMATIC PTD: 168P099d: FUTURE LLC API: Updated By: JILL 12/10/2019 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI -X 3,790' 3,806'427 3,439' 16' 6 11/15/19 Open CI -Stray 1 3,915' 3,921' 3,532' 3,537' 6' 6 11/15/19 Open CI -A 3,930' -3,933' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sgz CI -Stray 2 3,937' 3,547' 3,550' 4' 6 11/15/19 Open CI-Stray3 3,946' 3,951' 3,557' 3,562' 5' 6 11/15/19 Open CI -A 3,964' 3,979' 3,572' 3,585' 15' 6 11/15/19 Open CI -A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI -B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI -B 4,055' 41070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI -B 4,100' 4,101' 3,684' 3,685' V 4 3/14/1969 CmtSgz CI -e 1 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI -1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI -1.0 4,210' 4,280' 3,773' 3,83U 70' 12 9/1/1994 Isolated CI -1.0 4,281' 4,299' 3,831' 1,845' 18' 4 11/7/2007 Isolated CI -2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI -2.0 4,376' 4,401 3,907' 3,927' 25' 1 11/7/2007 Isolated CI -3.1 4,401' 4,427' 3,927 3,948' 26' 1 11/7/2007 Isolated CI -3.1 4,428' 41440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI -3.1 4,441 4,453 3,959 3,969' 12' 1 11/6/2007 Isolated CI -4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI -4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI -4.0 4,495' 4,520' 4,002' 41022' 25' 1 11/4/2007 Isolated CI -5.0 4,552' 4,582' 4,047' ' 12 9/1/1994 Isolated CI -6.0 4,630' 4,640' 4,109' ' 12 9/1/1994 Isolated CI -7.0 4,692' 4,697' 4,158' 12 9/1/1994 Isolated CI -7.1 4,730' 4,737' 4,188' S4,3011125pp 12 9/1/1994 Isolated CI -S.0 4,778' 4,788' 4,225' 12 9/1/1994 Isolated CI -8.2 4,810' 4,820' 4,250' ' 12 9/1/1994 Isolated CI -9.0 4,850' 4,875' 4,281' 12 9/1/1994 Isolated CI -10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI -11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,87T 4,879' T 12 9/1/1994 isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' .5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 30' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 30' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 1 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227 6,252 5,375' 5,395' 25' 12 9/1/1994 Isolated(EZSV Bridge Plug) -3 6,284' 6,289' 5,421' 5,425' S' 12 9/1/1994 Isolated (EZSV Bridge Plug) 1-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' SO' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 1 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) 7,212' 7,237' 6,172' 1 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Updated By: JILL 12/10/2019 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 50-883-20020-00-00 168-099 10/28/19 11/17/19 Daily Operations: 10/28/19 - Monday DEPART FOR PLATFORM. ARRIVE ON BOARD, CHECK-IN, ORIENTATION, TALK W/PROD SUPERVISOR. PERMIT/JSA AND WIRELINE SAFETY MEETING. SPOT EQUIPMENT. RU SLICKLINE, PT LUB TO 2500 PSI. CHANGE O-RING, RETEST, PASS. RIH W/4.5 GS W/PRONG TO 381KB. LATCH SSSV, DUMP PRESSURE, POOH W/VALVE. RIH W/3.5" LIB TO 3930 KB, POOH W/NO FISHING NECK MARKS. MARKS ALL AROUND EDGES. RIH W/3" PUMP BAILER TO 3930KB WT 3933KB. POOH, FULL DRY FLUFFY SAND. RIH W/SAME TO 3936KB WT 3936KB POOH, 1/2 FULL SAND. RIH W/SAME TO 3937KB WT 3939KB POOH, 1/2 FULL SAND. RIH W/SAME TO 3940KB WT 3942KB POOH, 1/2 FULL SAND AND FISH NECK MARKS IN BAILER BTM. RIH W/SAME TO 394VKB W/T. POOH, EMPTY AND FISH NECK MARKS IN BAILER BTM. RIH W/2.5" JD W/2.91 BELL GUIDE TO 3941KB, LATCH PRONG, PULL UP TO 1400#, CAME FREE. POOH W/PRONG. RIH W/2.25" PUMP BAILER TO 3944KB WT, POOH, 1/2 FULL SAND AND MARKS ON BAILER BTM. RIH W/4.5" OK -5 TO 3857KB, LATCH VALVE, SPANG UP 4x, ONE 14004 JAR LICK, CAME FREE. POOH W/VALVE. RIH W/4.5 GS TO 3935KB, WT, PULL UP 1300# JAR LICK, CAME FREE, HANG UP MULTIPLE TIMES @ 3894KB, CAME FREE, POOH, NO PLUG. POSSIBLY HUNG UP IN SAND. RIH W/3.74 G - RING TO 3894KB, SET DOWN, WT AND FALL TO 3930KB, CANNOT PASS. POOH, LAY DOWN FOR NIGHT. 10/29/19 -Tuesday ATTEND MORNING MEETING, PERMIT/JSA. CUT WIRE, REREAD. CHECK TOOLSTRING FOR TIGHTNESS. STAND UP LUB. RIH W/3" PUMP BAILER TO 3930KB, WT 3931KB. POOH, FULL SAND. RIH W/SAME TO 3934KB, WT 3939KB. POOH, FULL SAND. RIH W/ SAME TO 3931KB WT3940KB. POOH, FULL SAND. RIH W/SAME TO 3939KB WT 3943KB. POOH, FULL SAND. RIH W/SAME TO 3943KB WT 3944K. POOH, FULL SAND. RIH W/SAME TO 3943KB WT 3944KB. 1/3 FULL SAND. RIH W/SAME TO SAME, WT. POOH, 1/4 FULL SAND. MARKS ON BAILER BTM. LAY DOWN LUB. RE -TIE ROPE SOCKET AND STANDBY FOR CRANE TO OFFLOAD BOAT. UNLOAD BOAT W/SUB FRAME FOR 404, DRAWORKS, MIX TANK, "A"- LEG, & E - LINE UNIT. PICK UP TOP SHEAVE. STAND UP LUBRICATOR. RIH W/3.74 G -RING TO 3944KB. MAKE MULTIPLE PASSES FROM 3750 TO 3944KB, POOH. RIH W/3" PUMP BAILER TO 3944KB, WT. POOH WITH 1/4 FULL SAND. RIH W/4.5" GS TO 3944KB. LATCH PLUG, 40x SPANG LICKS AND 10x JAR LICKS, WONT COME FREE. SHEAR OFF AND POOH. HANG UP AT 3900KB, WT MULTIPLE TIMES, 1400# JAR LICK, SLACK OFF AND COME THROUGH. OOH, LAY DOWN LUB. NITE CAP WELL. REST CREWS & MOBE OUT TOOLS FROM BEACH. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 50-883-20020-00-00 168-099 10/28/19 11/17/19 Daily Operations: 10/30/19 - Wednesday MORNING MEETING. PERMIT/1SA. CUT SOFT WIRE, CHECK TOOLSTRING, REHEAD. STANDBY FOR CHOPPER AND CRANE TO REFUEL. CHECK TOOLS UPON ARRIVAL. RAISE TOP SHEAVE AND STAND UP LUBRICATOR. RIH W/3" PUMP BAILER TO 3944KB, WT, POOH. FULL FLUID NO SAND. RIH W/2.25" PUMP BAILER TO 3944KB, WT, POOH. FULL FLUID NO SAND. RIH W/1.75" PUMP BAILER TO 3945KB, WT, POOH. FULL FLUID NO SAND, MARKS FROM PLUG BODY. RIH W/1.75 HYDROSTATIC BAILER TO SAME, WT TO SHEAR PIN. POOH, NO SAND. RIH W/4.5" PR TO 3945KB, LATCH PLUG, GIVE 3x 1600# JAR LICKS, CAME FREE. POOH, HANG UP IN SSSV PROFILE. HAND SPANG FREE. CONTINUE OOH W/PLUG. RIH W/3.74 G -RING, DRIFT TUBING TO 4015KB, SET DOWN, WT, CANNOT PASS, STICKY, POOH. RD SLICKLINE. PREP DECKS FOR E -LINE. UNLOAD & BACKLOAD BOAT. PJSM W/E-LINE HANDS. SPOT UNIT & R/U E/LINE. RE -HEAD & MOBE OUT GR TOOLS. M/U GR, CCL & 3 1/2" JET CUTTER. RIH W/JET CUTTER T/4005' LOG UP T/3500'. RIH PLACE CUTTER @ 3997' FIRE CUTTER, GOOD INDICATION CUTTER FIRED, POOH. SECURE WELL. R/D E -LINE. 10/31/19 - Thursday Spot rig beam package & assemble same over well center A-03. Mobilize rig crews to Tyonek Platform. Hold orientation with crews on Tyonek. Clean and organize change room and prepare for arrival of work boat. Continue organizing and prepping drill deck for rig. Boat arrives at platform. Off load work boat and begin setting rig components. 11/01/19 - Friday PTSM. Repair bolt on carrier for Drawworks. Install drawworks, pin derrick to A -leg, finish arrange decks & spot mud pump & tool conex. Spot electrical panel. Mix tank parts conex. Install drillers controls. Pin raising rams to lower mast. R/u air manifold. R/u d/w air, housekeeping. Rig up lights to parts conex's. Rig up hoses to drill water and air. Position 1502 hoses to connect to rig. Offload work boat. Clean threads on chiksans and lo -torque valves. Reposition mud pump. Begin rigging up hoses to tree for well kill. Continue with miscellaneous rig up projects. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 50-883-20020-00-00 168-099 10/28/19 11/17/19 Daily Operations: 11/02/19 - Saturday R/D annulus line on well head. R/u circulating lines from pump & mix tank to wellhead. Mix 6% KCL in mix tank, run mud pump & check rod wash & stroke counter, good. PJSM, walk lines verify valve alignment. Pump 127 bbls 6% KCL down tubing @ 3BPM, no returns at surface. Shut dawn & monitor well. Monitor well, prep BOPE for install, housekeeping. Locate and verify all BOP components. Clean ends of choke and kill lines. Plug in lower mast lights. Begin building mud cross. General housekeeping. Finish building mud cross. Off load work boat. Unable to mobilize personnel and equipment to obtain fluid level in well bore. Tubing/annulus still on vacuum. Decision was made to set BPV and nipple down. Rig down circulating equipment from tree. Set BPV. Nipple down tree in sections. Remove stairs to tree landing. Remove hub flange section of tree. Verify lift threads to be 4 1/2" 8rd. Install blanking sub. Off load work boat. Nipple up riser and spools. Set mud cross and double gate. 11/03/19 - Sunday PTSM. Cont. stack up BOPE, tq connections @ tubing spool & riser. Re -spot accumulator, run accumulator lines. Cont. tq. flanges on BOPE. R/U Quadco Rig Sence system. Calibrate gauges & chart recorders. Start prepping backload for boat. Cont. tq. flange bolts on BOP eq. Run & install accumulator remote control line. Install Gas alarms. Unload & back load boat. Spot DS stairs to carrier, welders modify same to fit configuration. Organize decks while back loading boat. Prep to stand Derrick. Finish gas alarm system install & tie in to quarters, test same, good. Work boat. Back load equipment. Move mud tanks. R/U hose from choke manifold to mud tanks. R/U poor boy stack. N/U choke and kill hoses. Set rig floor on racking board. Organize drill deck. Hold PJSM. Raise mast. Set doghouse. Secure lower mast. Arrange guy lines. Slip on additional drill line. Scope mast out. Secure guy lines. 11/04/19 - Monday PTSM. Install rig floor & secure. Install hand rails. R/u remote accumulator panel. R/u kill line to standpipe manifold. Continue work on ODS stairs to carrier. Install ODS stairs to rig floor from carrier. Install reverse circulating hose. M/U 4 1/2" test jt. Work on modifications for beaver slide. Check pre -charge on accumulator bottles, pressure up accumulator. R/U super choke. Skirt BOP stack with plastic to retain heat. Rig up test pump. Finish making up 4 1/2" testjoint, IBOP and floor valves for test. Rig up test hoses. Fill pits with water for testing. Assist welders with stair modifications. Work boat. Rig up to test. Fluid pack stack, choke. etc. Shell test at 250 L/2500 H. Perform accumulator draw down test. Bring tool board and tools to rig floor. Build 25 bbl sized salt pill. Rig up floor wind walls. Stage handling equipment on rig floor. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 1 50-883-20020-00-00 1 168-099 10/28/19 11/17/19 Daily Operations: 11/05/19 -Tuesday Locate and rig up lighting for rig floor. Touch up sized salt pill. Test BOPE on 4 1/2" and 2 7/8" test joints at 250 L/2500 H. AOGCC (Jim Regg) waived witness at 0805 hours on 11-5. Rig down test equipment. Line choke manifold up for well work. Abandon platform drill with muster and after action review. Slip on additional drill line and install new drawworks dog knot clamp. Build 6% KCL volume. R/U return line from annulus to choke manifold. Back out blanking plug and lay down 2 7/8" test joint. Stack fluid went down hole. Pull BPV. Install 4 1/2" landingjoint. Break head pin off of testjoint and make up on landingjoint. Make up circulating hoses. Fill lines and test at 500 psi. Pump 5 bbls 6% KCL, 54 bbls sized salt pill and chase with 45 bbls 6% KCL. 0 psi during pumping on tubing and annulus. Pill in place at 0240 hrs. Allow pill to soak while rigging up power tongs. Build 6% KCL volume. Pump 48 bbls. 6% KCL at 3.5 BPM with 0 psi. Shut down. Monitor well while building volume. 11/06/19 - Wednesday R/U handling tools for 4 1/2" tubulars. Filled pits with 6%KCL. Adjust rig to center elevators over hole, make adjustments to A -leg. Pump 28 bbls with no returns, caught fluid @ 9 bbls. Welders finish modifications to stairs. R/U pump 20 bbls down annulus. Pull hanger off seat @ 20k, cont. pull t/98k, string started moving (freeing packer @ 3908') work string down. POOH laying down 31 joints of 4 1/2" tubing. Recovered 11 SS bands. Install protectors on box and pins. Continue POOH laying down 4 1/2" tubing. Recovered 3 GLM's, 119 joints of tubing and seal assembly. Halliburton VSR packer was NOT retrieved. Clear rig floor. Chang out power tongs. Change out slip inserts. Repair hydraulic leak on power tongs Adjust brakes. Make up BHA (casing scraper assembly). RIH picking up 3 1/2" PH6 work string. 11/07/19 - Thursday RIH w/ scraper & bit p/u 3 1/2" PH -6 wk string, t/1857'. POOH standing back work string in derrick. Pump 20 bbls down tubing w/no returns, while unloading tools from boat. Stage handling equipment on rig floor. Change out elevators and slips. Make up fishing BHA #1. RIH with BHA #1 with stands out of derrick to 2011'. RIH with BHA #1 picking up 3 1/2" PH6 work string to +-3850'. 44 K P/U, 36 K S/0. Establish parameters. Make up head pin and valve. Locate TOF at 3898' and engage same. Jar on fish at 75 K 5 times. Pick up to 5 K over weight. Rotate 14 rounds right and PBR released. �jjr Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 50-883-20020-00-00 1 168-099 10/28/19 11/17/19 Daily Operations: 11/08/19 - Friday POOH t/ 3882', L/D single r/u pump 47 bbls SS pill, chase w/ 18 bbls 6% KCL. POOH t/3846', hung up, worked through, cont POOH hanging @ every casing collar working through. Work BHA, recover ratch latch assy. Make up mud motor BHA #2:pilot mill, 4 3/4" mud motor, sub, boot basket, bit sub, string magnet, BS/OJ's, 6 ea. 4 3/4" DC's. accelerator jars, XO = 264.50. Test mud motor (good). RIH with BHA #2 to +-3887'. P/U 43 K, S/0 35 K. Tag TOF at 3892'. Lay down joint. Rig up circulating lines. Pump 32 bbls sized salt pill at 3 BPM. Shut in annular and squeeze with 30 bbls (pipe volume) 3% KCL at 3 BPM. Last 8 bbls pumped had up to 210 psi. Rig down circulating equipment. Rig up power swivel. Build 3% KCL volume. Free up stiff arm roller assembly for swivel. Make up 10' pup joint for milling. pL,� 11/09/19-Saturday Cont. R/U Power swivel & circulating system for milling operations. Get parameters & milling measurements, Up wt 42k, do wt 39k, pump 4.3 BPM, rot 16-20 RPM, tq off 400, on 800-1200, differential pressure 200-400. Milled —30" of 46.6", (no returns while milling, mixing 3% KCL during operations). Pump 30 bbl SS pill & let soak while unloading boat. Service rig. Wait on boat to offload drill water. Production had issues priming water pump. Build 3% KCL volume. Continue milling on packer with previous parameters for a total of 43". MP #1 began to hammer violently. Shut down. Go through MP #1 fluid end.-Re-prime pump. Finish milling on packer. Fluid losses: SS pill 208 bbls, 6% KCL 362bbis, 3% KCL 2318 bbls. 11/10/19-Sunday Cont. drill off, take measurements & verify. Cont. Milling operations, measure & verify milled —49.5". R/D power swivel & circulating lines, prep t/POOH. POOH t/ BHA #2. L/D BHA, mill wore — 75%. Make up BHA #3 spear assembly- Spear w/ext & stop sub, dressed w/ 3.947 Grapple, xo, Bumper sub, oil jar, 6-4 3/4" DC, acc. jar xo sub= 228.44'. RIH with BHA #3 to 3882'. Had returns beginning at 858' but lost returns again at +-3700'. M/U safety valve. Engage fish at 3891'. Wash through with full extension at 3 BPM/200 psi. Set down several times by working through with right hand rotation. No returns throughout fishing process. No jarring necessary. Rig down circulating hose. POOH with BHA #3 slowly with several over pulls. Work BHA and stand back drill collars. Lay down spear and fish. Photos in o-drive well file. Fluid losses: Daily: 250 bbls 3% KCL. Totals: SS pill 208 bbls, 6% KCL 362bbls, 3% KCL 2568 bbls. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 50-883-20020-00-00 1 168-099 10/28/19 11/17/19 Daily Operations: 11/11/19 - Monday L/D Fish. Recover - packer, 2 full jts 4 1/2" tubing, X -nipple, one cut jt- total 95.8'. M/U BHA #4, 6 1/8" mil tooth bit, 7" csg scraper, bit sub, bumper sub, oil jar, 6-4 3/4" DC, xo = 208.62. Troubleshoot & adjust DW brakes. TIH with cleanout assy. t/3987' up wt 43k, do wt 35k. R/U & wash down t/ 4001' pipe measurement, tag btm, pump 3.6 BPM, 350 psi. P/U 10' shut down pump, monitor, rih tag same, r/d circulating lines. POOH standing back 3 1/2" wk string. L/D BHA. Finish laying down BHA #4. Clear rig floor. N/D circulating head. Work boat N/U shooting flange and pack -off. R/U sheaves and wire line. Make up tools and RIH with 3 3/8" perf gun to +-4000' WLM. Log up and send logs to town. Correlate on depth with engineer. Shoot squeeze holes from 4000' to 4003', 6 SPF/60 degree phase, .74 hole. POOH with wire line. Took 7.5 bbls to fill hole. P/U 7" EZSV and RIH with same. Correlate and set at 3992' POOH with e -line and rig down. Fluid losses: Daily: 75 bbls 3% KCL. Totals: SS pill 208 bbls, 6% KCL 362 bbls, 3% KCL 2643 bbls. q 30� U 11/12/19 -Tuesday R/D edine. R/U t/ test BOPE. M/u 2-7/8" test jt, install & flood surface eq w/test fluid, shell test 250/2500 good. Test BOPE as per Hilcorp & AOGCC expectations, test witnessed by Inspector Guy Cook, tested w/2-7/8" & 3-1/2" testjoints, tested gas alarms & PVT good. Unload CMT eq. & fill CMT silo w/5 pods while breaking down test eq. Make up cement stinger. RIH with same to +-3967'. Picked up 3 joints. Tagged top of EZSV at 3978' DPM. Halliburton circulate at 1 BPM (with drill water) while stinging into retainer. Pressure increased to 800 psi and then fell off to 50 psi when stung in. Set 18 K down on EZSV. Establish injection rates: 1 BPM/50 psi, 2 BPM/80 psi, 3 BPM/220 psi, 4 BPM/400 psi, 5 BPM/800 psi. Consult with engineer about high set of EZSV. Mobilize wire line crew to verify retainer depth. Un -sting from retainer and rig up hoses to allow string to u -tube due to under balance. Space out and sting into EZSV with 15K set down. Rig up a -line. RIH with wire line. Verify top of EZSV to be 3989' WLM. Consult with engineer. Decision made to cement. POOH and rig down a -line. Rig up for cement job. Hold PJSM. Fluid losses: Daily: 7 bbls 6% KCL. Totals: SS pill 208 bbls, 6% KCL 362 bbls, 3% KCL 2650 bbls. 11/13/19 - Wednesday Cont. Prep f/ cmt job. PJSM with all involved. Pump CMT job as per Procedure, fill lines 5 bbls water while monitoring annulus, static. PT lines t/1200psi & 4600psi, good. Mix & pump 158 bbls 15.8ppg cmt @ 5bpm 600 psi. Displace tubing w/6%kcl @4bpm icp 400 psi, fcp 850—PSI. Un -sting from retainer, drop wiper ball, circulate hole volume w/6%kcl @ 2.5 bpm, 180 psi. Mix & pump dry job. Clear rig floor breaking down circulating lines. POOH I/d 3 1/2" wk string f/3989' & I/d cmt stinger assy. Hole fill 18bbls as calculated. Nipple down circulating head. Nipple up shooting flange. Spot e -line unit. Rig up a -line and make up tool string. RIH with CBL. Tag at 3988'. Log to surface. Send logs and consult with engineer. Make up and RIH with cement baler. Dump 12.2 gallons. Work boat unable to get up to the dock due to high winds. Wait on boat. Housekeeping and organizing. Fluid losses: Daily: 0 bbls 6% KCL. Totals: SS pill 208 bbls, 6% KCL 362 bbls, 3% KCL 2650 bbls. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 50-883-20020-00-00 168-099 10/28/19 11/17/19 Daily Operations: 11/14/19-Thursday Housekeeping and maintenance while waiting on boat with completion string. Unload boat. Layout 2 7/8" tubing & strap same. P/U 2 7/8" 6.5# L-80 EUE 8rd tubing. POOH standing back 2 7/8" completion tubing. Clear rig floor. N/D stripper head and nipple up shooting flange. Rig up a-line. Load and prep perf guns. Fluid losses: Daily: 0 bbls 6% KCL. Totals: 55 pill 208 bbls, 6% KCL 362 bbls, 3% KCL 2650 bbls. 11/15/19 - Friday Cont. R/U e-line. P/U gun found wire fouled, re-head & P/U gun #1, loaded w/15', 6 SPF, 60deg Phasing. RIH t/3980', log strip & send to town for correlation. Make V adjustment as per Res. Eng. re-log strip & send in for verification, fire gun on depth perforating f/3964'-3979', good indication gun fired, well static. POOH I/d gun #1 all shots fired. P/U gun #2 loaded w/16',6 SPF, 60deg Phasing, log & send correlation logs to town for verification, good, fire gun perforating L/3790'-3806', good indication guns fired, well static. POOH 1/d gun #2 all shots fired. P/U gun #3 loaded w/5',6 SPF, 60deg Phasing, had tech issues with firing panel, send for new one from beach, log & send correlation logs to town for verification, good. Attempt to fire no joy, continue trouble shoot find DC voltage low. R/U alternate power & fire gun perforating f/3946-3951', good indication gun fired. POOH 1/d gun #3 all shots fired. P/U gun #4 loaded w/4', 6 SPF, 60deg Phasing. RIH w/gun #4, log & send correlation logs to town for verification, good. Fire gun perforating f/3933'- 3937', good indication guns fired, well static. POOH I/d gun #4 all shots fired. P/U gun #5 loaded w/6', 6 SPF, 60deg Phasing, log & send correlation logs to town for verification, good. Fire gun perforating f/3915'-3921', good indication guns fired, well static. POOH I/d gun #5 all shots fired. R/D edine. Rig up to run completion assembly. Hold PJSM. Hole is full and static. RIH with completion assembly to 2000'. Fluid losses: Daily: 0 bbls 6% KCL. Totals: 55 pill 208 bbls, 6% KCL 362 bbls, 3% KCL 2650 bbls. 11/16/19-Saturday Cont. TIH w/GL completion- 2 7/8" 6.5# L-80 EUE 8rd as per program t/3956' up wt 25k, do wt 21k. R/U e-line, rih t/354' pull blanking sleeve from SSSV. C/o tools t/2.9" GR, CCI & GR tools. RIH t/3938', log up t/3590', to correlate space out pup. POOH I/d 2 jts, p/u 8' pup. M/U full joint pup & hanger w/landingjt, drain stack & land placing tubing tail @ 3964' pipe measurement. R/U a-line. RIH w/CCL/GR tools to verify packer correlation, good. POOH r/d a-line. Pressure up to 4000 psi to set packers and test tubing on chart for 30 minutes. R/U and test annulus at 1600 psi on chart for 30 minutes. All good tests. Rig down test equipment. R/U Pollard slick line unit. RIH with 2.8" drift to 75'. Run #1: 2 7/8" OKI with 11/4" JDC to 3952'. Retreive prong. Run #2: 2 7/8" kickover tool to 3706'. Pull chemical injection valve. Run #3: 2 7/8" JK kickover tool to 3706' with chemical injection valve. Run #4: RIH to 3959'. Pull RHCP plug. Run #5: Set SSSV. Tested at 5000 psi. Drain pits to production. Flush lines with drill water while slick lining. Rig down Pollard slick line unit. Pull and lay down landingjoint. Set BPV. Demob accumulator lines. Rig down wind walls. Flush Kelly hose. Prepare to rig down floor. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date N Cook Inlet Unit A-03 Slickline 1 50-883-20020-00-00 168-099 10/28/19 11/17/19 Daily Operations: 11/17/19 -Sunday Cont clear floor & prep to take off. Pull slide & stairs. R/d accumulator lines, remove dog house, remove rig floor. Prep derrick & scope down. Break bolts on BOPE. Unsp000l tuggers, manrider, hang blocks & un spool DW. L/d derrick, prep t/pull off. Drain pits to production. N/D BOPE annular, double gate & mud cross, pump out riser & prep to pick. R/d PVT sustem. R/d total safety gas alarm system. Pull riser, prep wellhead. N/u tree, test void t/500/5000, good. Tested tree 500/5000, good. REPEAT SECTION Database File tionek a3 -db Dataset Pathname cbl/pass2 Presentation Format cdnrad Dataset Creation Wed Nov 13 22:49:20 2019 Charted by Depth in Feet scaled 1:240 650 T T (usec) 150 -54 CCL 6 0 GR (GAP 1) 150 0 RAD MAX 150 0 _ ._ CCL AMP (mV) 100 0 RAD AVG 1150J200 VDL (usec) 120011 AMP (mV)20 0 RAD MAX 150 0 RAD MIN 150 AD MIN ' RAD AVG - - -- I VAD r 650 -54 T T (usec)_ CCL 150 6 0 AMP (mV) 0 AMP (mV) --------------------------------- 100 20 0 RAD AVG 150i200 VDL (usec) 12001 VAD S 0 RAD MAX 0 RAD MIN 150 150 0 GR (GAPI) 150 Company HILCORP ALASKA, LLC • Well A-03 Field NORTH COOK INLET County KBP State ALASKA Country THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Stan W. Golis Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: North Cook Inlet Field, Tertiary Gas and Sterling Undefined Gas Pools, NCIU A-03 Permit to Drill Number: 168-099 Sundry Number: 319-405 Dear Mr. Golis: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Jerem M. ice Chair DATED this-* day of October, 2019. RBDMSL OCT 2 5 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1•ItRCTWWX'LI:TrI D7:5 f5 1. Type of Request: Abandon ❑ Plug Perforations 0 . Fracture Stimulate ❑ Repair Well ❑ Operations shutdown[--] Suspend ❑ Perforate ❑� - Other Stimulate ❑ Pull Tubing ❑Q - Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool 0 , Re-enter Susp Well ❑ Alter Casing ❑ Other: G/L Completion Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q . Stratigraphic ❑ Service ❑ 168-099 - 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-883-20020-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055(a)(4) & CO 68 Will planned perforations require a spacing exception? YesO ✓ No ❑ IN Cook Inlet Unit A-03 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0017589 / ADL0037831 North Cook Inlet Field / Tertiary Gas Pool _` GY (�✓ (C.O �PF t!j4-j 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,480 • 6,392 3,946 3,557 1,177 psi 3,946; 4,526; 4,586 & WA 5,105 Casing Length size MD TVD Burst Collapse Structural Conductor 384' 30" 384' 384' Surface 612' 16" 612' 612' 1,640 psi 630 psi Intermediate 2,519' 10-3/4" 2,519' 2,329' 1 3,580 psiff(ft): 90 psi Production 7,475' 7" 7,475' 6,388' 4,980 psi20 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing 3,964 - 4,070 3,572 - 3,660 4-1/2" & 2-7/8" 12.75# J-55; 12.60# J-55; 6.4# L-80 3,898; 6,289; 4,527 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Packers (x11) see schematic & SVLN Packers - see schematic & SVLN 286 (MD) 286 (TVD) 12. Attachments: Proposal Summary Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑� Exploratory ❑ Stratigraphic ❑ Development ❑✓ * Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 10/1/2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑� WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe@hilcorg.com p Contact Phone: (907) 283-1329 Authorized Signature: t.,) rL Date: COMMIS ION USE ONLY Conditions of approval: Notify Commission soat a representative may witness Sundry Number: ^ (� 406 O6 Plug Integrity ❑ Test [� Mechanical Integrity Test ❑ Location Clearance ❑ OBOP n I Other: -1250 s�� An .+� �t �� ,�t dhaa.✓1L /,5 Q l;-7fI- ou.�9 ZarF^L ZS'.,?" -(o Post Initial Injection MIT Req'd? Yes n, No P�y /o 2g.I Y , I �BD�SH�"'� OCT 2 51019 /�v _ Spacing Exception Required? Yes No Subsequent Form Required: r.1 O I I�f..(E: -04 Rrro w wr �R 3P"c'`JIVd *A V APPROVED BY ,I ^ \ Approved by: � COMMISSIONER THE COMMISSION 1J Date: I Q � 1 Submit Form and bbb,?h777 Fo 03 R etl /201 Approved application is va id or 1 moot s rpm the date of approval. AllQ////rchments in Duplicate %//./7^ H Hil.rp Alaska, LLC Well Work Prognosis Well Name: NCIU A-03 API Number: 50-883-20020-00 Current Status: Producer Leg: Leg #3 SE Corner Estimated Start Date: October 1, 2019 Rig: HAK 404 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 168-099 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Stan Golis (907) 777-8356 (0) (281) 450-3071 (M) Current Bottom Hole Pressure: 1,520 psi @ 3,427' TVD 0.444 lbs/ft (8.53 ppg) Maximum Expected BHP: 1,520 psi @ 3,427' TVD 0.444 lbs/ft (8.53 ppg) Maximum Potential Surface Pressure: 1,177 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary A-03 is currently a watered out gas producer. This workover will recomplete the well up -hole, isolating the CI -B sand water, re -perforating the CIA gas sands, and adding the CI -stray and CIA gas sands. q? T6 1 Last Casing Test: Tested IA 2007-12-01 to 2,500 psi @ 3,908' 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. (._J-7 Procedure: )( 1. Rig up slickline and pull the bottom GLV and the plug at 3,946'. RD slickline. 2. Rig up E -Line and cut the tubing at ±4,125'. RD E -Line 3. MIRUHAK404 .ySv' 4. Test BOP's to 250psi low/2,500psi high / si annular. (Note: Notify AOGCC 48 hours in advance - of test to allow them to witness test). S. 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 ±4,125'. M6 7. RIH and set EZSV ±3,990'. POOH and RD E -Line 8. RIH, sting into EZSV. 9. Conduct injectivity test.� j)b 06, 10. Perform Hesitation Squeeze with "'1,00 sacks of cement through EZSV. 11. Un -sting from EZSV and circulate clean. POOH. CAI_ 'q�4 12. Rig up E -line and run a CBL from EZSV to surface. 13. Dump ±10' of cement (±16 gallons) on top of EZSV. RD E -line. 14. PU and rack back completion tubing. 15. RU E -line and perforate per program. 16. RIH with Gas Lift completion (live valves). 17. Set Packer / Pressure test completion: • Pressure up and set packer • Test tubing against plug in XN nipple to >2,500# and chart for 30 minutes. • Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). • Pull prong and plug in XN-Nipple. 18. Set BPV. NU tree, test same. 19. Turnover to production. 20. Schedule SVS testing with AOGCC as per regulations. U I il.p Al..U. LLC 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 Well Work Prognosis K corn Alaska. LLC RKB: 39', RKB to MSL: 115.9' RKB to Mudline: 235.9' I 30' , Wt Grade I Conn ID 16., Btm 30" i Conductor 10-3/4" 3 Surf 384' 16" oC 4 Camco KBG-2 GLM 15.250 Surf 3700 10-3/4" 45.50 & 51 J-55 BTC s •'" Surf 2,519' 7" 26 23 26 •. n€=nnrn 6.276 6.366" 6.276" plug seen CI -A HES PBR Seal Stem 3 920 6 3,898' X -Nipple 3.992 5.880 3,9]1" 5 3,907' 3,525' 1 3.992 7 1 Ratch Latch Seal Assembly - 3,908' 3,525' 4.000 6.000 Halliburton VSR Packer ✓ CI -B 3,946' 8 3.813 5.562 Halliburton X Nipple (Plug Set) 4,135' 3,713' 2.500 Baker 40A-25 SC -1 GP Packer 4,139' 3,716' CI -1.0 L 10 00 4,146' c1-2.0 k, 2.992 11 16 Ft Lower Extension CI -3.1 3,760' 2.441 2-7/8" Excluder 2000 Screen - Med (337') Cl -4.0 4,198' 3,764' 12 5.560 No Go Seal Assembly 13=' 4,199' 3,764' 4.000 5.870 Halliburton TWR Packer 14 a 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 11 4,525' C15.0 3.990 5.560 No Go Seal Assembly 12 4,526' 16 :- N/A 2.875" Bull Plug 13 4,527' 17 0 5.870 CI -6.0 14 1a 4,074' 3.813 5.560 1e . 15 4,594' 4,081' 3.990 5.560 zo p p 4,595' CI -7.0 4.000 5.870 Halliburton TWR Packer& Millout Extension 17 CI -Z1 2z ;: 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 18 4,668' z3 ❑ o 5.560 CI -e.0 19 za 4,140' 4.000 5.870 25 20 4,744' 4,199' 3.813 5.560 28 21 4,750' 048.2 27 : 5.560 No Go Seal Assembly 22 4,751' 4,204' 28 0 Halliburton TWR Packer & Millout Extension 10I-9.0 4,825' pg 3.813 5.560 CI -10.0 30 4,831' 4,267' 3.990 5.560 p, Stage (: 31 O 4,267' CI -11.o Collar 32 26 4,885' 4,309' 5,114" 33 No Go Seal Assembly 27 4,886' .n 4.000 5.870 Halliburton TWR Packer & Millout Extension 28 3a = 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 29 35 O0 3.990 B6 V 30 4,936' 4,349' G3 }. 36 XN 5,046' D-4 3.813 5.560 Halliburton XD Sliding Sleeve - Open 12/13/2001 32 F-1, F-2. F-4 t, 37 4.500 Set 4.5" EZSV Bridge Plug G1, G5 5,113' 4,487' 3.990 5.560 H-1, H-9 34 5,114' 4,488' 4.000 1-3 Halliburton TWR Packer& Millout Extension 35 5,626' 4,898' J-2 t" Halliburton XA Sliding Sleeve - Closed 36 6,288' K4 3.725 5.560 Halliburton XN Landing Nipple 37 6,289' 5,425' 3.980 Wireline Re -Entry Guide N-5 0-4 7' f Q3. Q4 -i�a��1.�.as�S� c �'w• _ane PBTD: 6,380' TD: 7,480' North Cook Inlet Well: NCI A-03 Last SCHEMATIC PTD: 168-099Completed: TD168-099d: 11/29/2007 API: 50-883-20020-00 CA"ING nFTAII Size Wt Grade I Conn ID Top Btm 30" 4-1/2" 12.60 Conductor 3.958 3,898' 29.000 Surf 384' 16" 65 H-40 Camco KBG-2 GLM 15.250 Surf 612' 10-3/4" 45.50 & 51 J-55 BTC 9.794 Surf 2,519' 7" 26 23 26 J-55 J-55 1-55 BTC BTC BTC 6.276 6.366" 6.276" Surf 79' 6,818' 79' 6,818' 7,475' TUBING DETAIL 4-1/2" 12.75 J-55 EUNSdRD 3.992 Surf 3,898' OD Item 1 286' 4-1/2" 12.60 J-55 EUE Mod 3.958 3,898' 6,289' 2-7/8" Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135' 4,527' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 286' 286' 3.813 4.920 HES 3.813"SVLN Nipple 2 1,738' 1,686' 3.860 5.984 Camco KBG-2 GLM 3 3,013' 2,748' 3.860 5.984 Camco KBG-2 GLM 4 3,846' 3,473' 3.860 5.984 Camco KBG-2 (Orifice) 3,892' 3,512' 4.000 HES PBR Seal Stem 3,898' 3,517' 3.992 5.880 Halliburton Upper PBR 5 3,907' 3,525' 1 3.992 5.562 1 Ratch Latch Seal Assembly - 3,908' 3,525' 4.000 6.000 Halliburton VSR Packer ✓ 6 3,946' 3,557' 3.813 5.562 Halliburton X Nipple (Plug Set) 4,135' 3,713' 2.500 Baker 40A-25 SC -1 GP Packer 4,139' 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 7 4,146' 3,722' 2.992 16 Ft Lower Extension 4,193' 3,760' 2.441 2-7/8" Excluder 2000 Screen - Med (337') 8 4,198' 3,764' 3.990 5.560 No Go Seal Assembly 9 4,199' 3,764' 4.000 5.870 Halliburton TWR Packer 10 4,501' 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 11 4,525' 4,026' 3.990 5.560 No Go Seal Assembly 12 4,526' 4,027' N/A 2.875" Bull Plug 13 4,527' 4,028' 4.000 5.870 Halliburton TWR Packer& Millout Extension 14 4,586' 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed(w/PX Plug) 15 4,594' 4,081' 3.990 5.560 No Go Seal Assembly 16 4,595' 4,081' 4.000 5.870 Halliburton TWR Packer& Millout Extension 17 4,658' 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 18 4,668' 4,139' 3.990 5.560 No Go Seal Assembly 19 4,669' 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension 20 4,744' 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 21 4,750' 4,203' 3.990 5.560 No Go Seal Assembly 22 4,751' 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension 23 4,825' 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 24 4,831' 4,267' 3.990 5.560 No Go Seal Assembly 25 4,832' 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension 26 4,885' 4,309' 3.990 5.560 No Go Seal Assembly 27 4,886' 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension 28 4,929' 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed 29 4,935' 4,348' 3.990 5.560 No Go Seal Assembly 30 4,936' 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension 31 5,046' 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve - Open 12/13/2001 32 5,105' 4,481' N/A 4.500 Set 4.5" EZSV Bridge Plug 33 5,113' 4,487' 3.990 5.560 No Go Seal Assembly 34 5,114' 4,488' 4.000 5.870 Halliburton TWR Packer& Millout Extension 35 5,626' 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed 36 6,288' 5,424' 3.725 5.560 Halliburton XN Landing Nipple 37 6,289' 5,425' 3.980 Wireline Re -Entry Guide INotes: 12/07/2007 -Set TTGP on Top of fill @4,532' (Tagged 15' high) 01/20/2011-9.98' difference in elevation is due to beine set on Electric Loe Deoths Updated By: DEM 08/15/2019 R1 SCHEMATIC North Cook Inlet Well: NCI A-03 Last Completed: 11/29/2007 PTD: 168-099 API: 50-883-20020-00 Updated By: JUL 10/06/17 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI -A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI -A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI -B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Open CI -B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Open CI -B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI -B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI -1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI -1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI -1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI -2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI -2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI -3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI -3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI -3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI -4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI -4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI -4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI -5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI -6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI -7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI -7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI -8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI -8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI -9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI -10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI -11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 30' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 35' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 30' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) 1-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 30' 4 3/14/1969 Isolated (EZSV Bridge Plug) 0-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Updated By: JUL 10/06/17 n Mal Alaska, LLC RKB: 39', RKB to MSL: 115.9' RKB to Mudline: 235.9' VV5�, Top of tubing -4,125' S� Z- 7 7 31np CI -x 10 310" cl-stray, 1 c CI -stray 2 C1 -Stray 3 13 P Cl -A CI -B CI -1.0 CI -2.0 CI -3.1 CI -4.0 CI -8.0 CI -7.0 CI -7.1 CI -8.0 CI -8.2 CI -9.0 CI -10.0 CI -11.0 r CG B6 Grade C,3 N DD XN D-4 Btm F-1, F-4 1� EE G-5 G-1, G-5 a H-1. H-9 3 Surf J-2 16" K-4 H-40 N-5 15.250 0-4 612' 03,04 45.50 & 51 J-55 Notes: PBTD: 6,380' TD: 7,480' 12/07/2007 -Set TTGP on Top of fill @4,532' (Tagged 15' high) 01/20/2011- 9.98' difference in elevation is due to being set on Electric Log Depths J-55 J-55 1-55 North Cook Inlet Well: NO A-03 Last Completed: FUTURE PTD:168-099 API: 50-883-20020-00 CASING DETAIL Size Wt Grade Conn ID Top Btm 30" 6.5 Conductor EUE 8 rnd 29.000 Surf 384' 16" 65 H-40 EUE Mod 15.250 Surf 612' 10-3/4" 45.50 & 51 J-55 BTC 9.794 Surf 2,519' 7" 26 23 26 J-55 J-55 1-55 BTC BTC BTC 6.276 6.366" 6.276" Surf 79' 6,818' 79' 6,818' 7,475' TUBING DETAIL 3-1/2" 9.3 L-80 EUE Brnd 2.992" Surf ±330' 2-7/8" 6.5 L-80 EUE 8 rnd 2.441" ±330'±3,970' ±300' 4-1/2" 12.60 J-55 EUE Mod 3.958 ±4,125' 6,289' 2-7/8" Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135' 4,527 JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item Hanger 1 ±300' ±300' 2.813" 4.420" WLRSV/SLVN-XXO 2 ±330' ±330' 3-1/2" x 2-7/8" Crossover 3 ±1,813' ±1,750' 2.441" 4.750" GUM #1 -SFO -1 4 ±2,842' ±2,600' 2.441" 4.750" GLM#2-SFO-1 5 ±3,720' ±3,365' 2.441" 4.750" GLM#3-SFO-1 6 1 ±3,750' ±3,391' 1 Chemical Injection Mandrel 7 ±3775' ±3,413' 2.401" 5.968" Packer- Hydraulic Retrievable 8 ±3,790' ±3,425' 2.313" 3.188" Sliding Sleeve 9 ±3,800' ±3,434' X -Nipple 10 ±3,900' ±3,519' 2.401" 5.968" Packer- Hydraulic Retrievable 11 ±3,925' ±3,540' 2.205" 3.668" Sliding Sleeve 12 ±3,930' ±3,544' 2.441" 3.668" X -Nipple 13 ±3,955' ±3,565' Packer - Hydraulic Retrievable 14 ±3,965' ±3,573' 2.205" 3.668" XN Nipple 15 ±3,970' ±3,577' 2.441" 3.668" WLEG 16 ±3,998' ±3,601' EZSV w/ 10' of cement on top Zc)D 3Bc- �r 4,135' 3,713' 2.500 Baker 40A-25 SCA GP Packer 4,139' 3,716 2.500 20-25 Mad S Gravel Pack EM w/Sliding Sleeve A 0146' 3,722' 2.992 16 Ft Lower Extension 4,193' 3,760' 2,441 2-7/8" Excluder 2000 Screen -Med (331) 8 4,198' 3,764' 3.990 5.560 No Go Seal Assembly C 4,199' 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501' 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525' 4,026' 3.990 5.560 No Go Seal Assembly F 4,526 4,027' N/A 2.875- Bull Plug G 4,52T 4,028' 4.000 5.870 Hallibunon TNR Packer& Millout FAension H 4,5BV 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve -Closed (w/PX Plug) 1 4,594' 4,081' 3.990 5.560 No Go Seal Asaembly 1 4,595' 4,081' 4.000 5.870 Halliburton TWR Packer& Millout Extension K 4,658' 4,131' 3.813 5.560 Hallibunon XD Sliding Sleeve - Closed L 4,668' 4,139' 3.990 5.560 No Go Seal Assembly M 4,669' 4,140' 4.000 5.870 Halliburton TWR Packer& Millout Extension N 4744' 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750' 4,203' 3.990 5.560 No Go Seal Assembly P 4,751' 4,204' 4.000 5.870 Halliburton TWR Packer S, Millout Extension Q 4,825' 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831' 4,267' 3.990 5.560 No Go Seal Assembl S 4,832' 4,267' 4.000 1 5.870 Halliburton TNR Packer& Millout Extension T 4,885' 4,309' 3.990 5.560 No Go Seal Assembly u 4886' 4,310 4.000 5.870 Hallibunon TNR Packer& M lllout Extension V 4,929' 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935' 4,348' 3.990 5.560 No Go Seal Assembly X 4,936' 4,349' 4.000 5.870 Hallibunon TWR Packer& Millout Extension Y 5,046 4,435' 3.813 5.560 Halllburton XO Sliding Sleeve - Open 12/13/2001 Z 5,105' 4,481' N/A 4.500 Set 4.5 -MV Bid, Plug AA 5,113' 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114' 4,488' 4.000 5.870 Halliburton TWR Packer& Millout 6Hension CC S,fi26 4,898' 3.813 5.560 Hallibunon XA Sliding Sleeve - Closed DD 6,288' 5,424' 3.725 5.560 Halliburton %N Landing Ni le EE 6,289' 5,425' 3.980 Wireline Re -Entry Gulde Updated By: JLL09/04/2019 UJ North Cook Inlet Well: NO A-03 Last Completed: FUTURE PTD: 168-099 API: 50-883-20020-00 Updated By: ILL 09/04/2019 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI -X ±3,790' ±3,806' ±3,427' ±3,439' 18' Future Proposed CI-Stray1 ±3,915' ±3,921' ±3,532' ±3,537' 16' Future Proposed CIA 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI -Stray 2 ±3,933' ±3,937' ±3,547' ±3,550' ±4' Future Proposed CI -Stray 3 ±3,946' ±3,951' ±3,557' ±3,562' ±5' Future Proposed CI -A ±3,964' ±3,979' ±3,572' ±3,585' ±15' Future Proposed CI -A 3,964' 3,979' 3,572' 3,585, 15' 12 3/14/1969 0 en CI -B 41000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI -B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI -B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI -B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI -1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI -1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI -1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI -2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI -2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI -3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI -3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI -3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI -4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI -4.0 4,474' 4,494'. 3,986' 4,002' 20' 16 11/6/2007 Isolated CI -4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated 0-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI -6.0 4,630' 4,640' 4,109' 4,117' 1o' 12 9/1/1994 Isolated CI -7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI -7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI -8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI -8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI -9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI -10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI -11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 30' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) 1-3 6,284' 6,289' 5,421' 5,425' S. 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 30' 4 3/14/1969 Isolated (EZSV Bridge Plug) 0-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Updated By: ILL 09/04/2019 R 11111mrp AhAn. UA: Current Wellhead 8/26/2019 NCIU A-03 Tyonek Platform A-03 28 X 16 X 103/4 X 7 x41/2 Unihead, OCT type 3, 16 3/4 51 BX -161 hub top X 16" LTC rash bottom, w/ 2- 2 LPO on lower section, 2- 21/16 SM S50 on mi( section, 2- 2 1/16 5M SSO on up section, IP internal lockpin ass Starting head, OR, 30 % 1M X 28" BW, W/ 2- 4" 1M EFO Tbg hanger, FMC -UH A -EN, 6"X4%EUE find lift and 4Y IBT susp, w/ 4" Type 15 BPV profile, 1- H non cont control line port Hanger's nested in pack -off and held down by lock plate Lock -plate needs to be removed before nipple up of ROPE Tree assy, 41/16 3M 4 W' clamp hub old top, on cont port H nar„rn .a".. UA; Proposed Wellhead 8/26/2019 NCIU A-03 Tyonek Platform A-03 28 X 16 X 103/4 X] x 31/2 BHTA, Bowen, 31/8 5M FE x 2.5 bowen Quick union top Valve, Swab, CI W -FLS, 31/8 5M FE, HWO, EE trim Valve, Master, CI W -FLS, 31/8 SM FE, HWO, EE trim Valle, Master, CIW-FLS, 31/85M FE, HWO, EE trim Tubing head attachment, Cactus, 115M FE X 16 3/4 SM BX -161 hub bottom Un !head, OR type 3, 16 3/4 SM BX -161 hub cap %I6" LTC asirig bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSG on middle section, 2-21/16 SM SSO on upper section, IP internal lockpin assy Starting head, OCT, 30 IS IM X 28" BW, w/2-4" 1M EFO 3 VV' 6" tor„ Tubing hanger, Cactus -EN - CCL, 11 x 3 % EUE Erd lift and susp, w/ 3" type H BPV, 2. X cant control line ports 4� 0 lE E �oguf�aV °Go �aNe'�FE, V F �gS 3 Adapter, Cactus-EN{CL, 115M sold x 31/8 SM, w/ 2- 1" not control line exits 28" Nu.. 4 h} ff "`P H Hikrnrp Aljwka. IJA: BOP Stack Rig 404 5.5 An 9vv< 3v3a33333 A c o r mZpr mJ W o o n O n O o� � < G c � i � M:� r N n Z 0 0 Anm�x n D ;u 0 G) C ct) D D r 41 - iG)ODa C U 3 ❑ -z � C C ryr �O W mn Z zz Z z O m m > 0 mp/ �m V o p A p i ➢ �G iF` t C T1r TA 9 y Z2 mo m N a a DD J �D N O T!7T 9vv< 3v3a33333 o o n O n O o� � n X 0 z a � Z oz -n 0 w p p r pJ �z i1C / 2 Z � C M -n r C r r O oo O O N Z - :E z^ ; T1 /''� Ul S2 5 >� A Z > >0 3 El 2 GG G) D m� z C z z cn zZ O m m m W 1 � 1 Cl) y p P om r o 0 < nx r� <,ll m 09 aG ON 09 m m� a fJ zz M, T N OD J MO N O n _ <� 33333 33ne Onooo o0 0n o n p LEN. 0 Rig 404 BOP Test Procedure Hil.p Alaska, LLC Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program — Oil 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. • 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. NO Tree. NU BOP. 2) MU landingjoint. 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. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. 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.) H Hik.,p Aha ka, LLC 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 14` 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 2,500 psi 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 15t 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 3,000 psi 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 3,000 psi 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 3,000 psi 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 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. H Hil.p AI.Ak , LLC 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 3000 psi 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 3000 psi 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 2nd 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 and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. 0 m im v CD m Rq O� n o a C 3 (D 0 O fp N :E O o v 0 o v Ca a CD CL n ow c a N CD 7 (D n O N C <D 3 CD 09 Om G a 0 0 O� n :E v �a 0 v am v a o m d 0 O (D 3 W =ED M m D o N j (D d �v cv CD 'o nCD va 0 N O m a v m =_ m m 0 0 3 �3 CD s0 CL m o s CD N c Q n R n s d 7 N 0 D a v 0 m CL U) C 3 CL `G 0 O 0 CL C fD 0 z n 0 0 m C 7 :i D O W 9 v w 0 <n i. r n E\ N n N v m V n a c 'm n s d ID ID Z CD �cF zCD 0 CL C4 F:W o(D " > 4! C D _ D m v CL D� O 0 o O °- n CCS a0_ vL CD- 0 M —a O� n o a C 3 (D 0 O fp N :E O o v 0 o v Ca a CD CL n ow c a N CD 7 (D n O N C <D 3 CD 09 Om G a 0 0 O� n :E v �a 0 v am v a o m d 0 O (D 3 W =ED M m D o N j (D d �v cv CD 'o nCD va 0 N O m a v m =_ m m 0 0 3 �3 CD s0 CL m o s CD N c Q n R n s d 7 N 0 D a v 0 m CL U) C 3 CL `G 0 O 0 CL C fD 0 z n 0 0 m C 7 :i D O W 9 v w 0 <n i. r n E\ Davies, Stephen F (CED) From: Tommy Nenahlo <tnenahlo@hilcorp.com> Sent: Monday, September 9, 2019 2:40 PM To: Davies, Stephen F (CED) Cc: Michael Schoetz; Dan Marlowe Subject: RE: NCIU A-03 & A-09 Proposed Operations Steve — Michael Schoetz forwarded me your questions regarding the Tertiary Systems Gas Pool. Please see below for the answers to your questions: There are no wellbores currently open in the sands above the top of the Tertiary Systems Gas Pool. For the proposed NCI A-03 and A-09 workovers, we correlate the proposed perforations in the Sterling Stray 1 and Sterling X Sands as being above the Tertiary Systems Gas Pool. Of these two sands outside the Pool, the NCI A-09 will only perforate the Sterling X Sand as the Sterling Stray 1 Sand is shaled out. In the NCI A-03 we will perforate the Sterling Stray 1 and the Sterling X sands. Other Sterling Stray Sands and the Sterling A Sand that are within the Tertiary Systems Gas Pool will also be perforated during the NCI A-03 and A-09 workovers. The Sterling X Sand has never been perforated. The Sterling Stray 1 sand was perforated in the NCI A-11 and A-12 wells. The A-11 and A-12 wells both have cement plugs preventing the ability to produce these wells. NCI A-09 will be the first well perforated in the Sterling X sand. NCI A-03 will be the second well to perforate the Sterling X Sand and the third well to perforate the Sterling Stray 1 sand. L ."X�'° ,ttK' rh'r, Please let me know if you have any questions! .j Thanks, Tommy Nenahlo I Reservoir Engineer Cook Inlet Asset Team Hilcorp Alaska, LLC Office: +1 (907) 777-8424 Mobile: +1 (720) 273-2685 tm nn h_l.o iDhileci.4Lcom r 6r• e From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, September 5, 2019 3:44 PM To: Michael Schoetz <mschoetzPhilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Cc: Boyer, David L (CED) <david.bover20?alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Michael, Dan: Please confirm that no wells at NCIU are currently open within the sands above the top of the Tertiary System Gas Pool, and that A-09 will be the first well perforated in those sands. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or Steve day esPalaska.¢ov. From: Michael Schoetz <mschoetz@hilcorg.com> Sent: Thursday, September 5, 2019 9:00 AM To: Boyer, David L (CED) <d avid. bover2@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Thank you. I did not mention that we were planning to cite C068 for those operations that fall within the Tertiary Gas Systems Pool. Glad to know that I am interpreting the requirements correctly. Thank you very much for the quick response! Thank you, Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz(a hilcorp.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED)[mailto•david.boyer2@alaska.gov] Sent: Thursday, September 5, 2019 8:58 AM To: Michael Schoetz <mschoetz@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Michael, For the Tertiary System Gas Pool, C068 should be cited. For the undefined gas pool above the interval from 3500-6200' defined in C068, you are correct in citing the Alaska statewide regulation 20 AAC 25.055(a)(4) for both A-09 and A-03. If there are a number of spacing exceptions needed in the future for similar wells, it would be worth it for Hilcorp to formally apply for a new pool above 3500'. Best, Dave Boyer AOGCC From: Michael Schoetz <mschoetzCa@hilcorp.com> Sent: Thursday, September 5, 2019 8:38 AM To: Boyer, David L (CED) <d avid. bover2@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Dave, 2 Davies, Stephen F (CED) From: Boyer, David L (CED) Sent: Thursday, September 5, 2019 2:05 PM To: Davies, Stephen F (CED) Subject: FW: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations From: Michael Schoetz <mschoetz@hilcorp.com> Sent: Thursday, September 5, 2019 9:00 AM To: Boyer, David L (CED) <david.boyer2@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Thank you. I did not mention that we were planning to cite C068 for those operations that fall within the Tertiary Gas Systems Pool. Glad to know that I am interpreting the requirements correctly. Thank you very much for the quick response! Thank you, Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz(a_)hilcorp.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED)[mailto:david.bover2@alaska.gov] Sent: Thursday, September 5, 2019 8:58 AM To: Michael Schoetz <mschoetz@hilcoro.com> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Michael, For the Tertiary System Gas Pool, C068 should be cited. For the undefined gas pool above the interval from 3500-6200' defined in C068, you are correct in citing the Alaska statewide regulation 20 AAC 25.055(a)(4) for both A-09 and A-03. If there are a number of spacing exceptions needed in the future for similar wells, it would be worth it for Hilcorp to formally apply for a new pool above 3500'. Best, Dave Boyer AOGCC From: Michael Schoetz <mschoetz@hilcorp.com> Sent: Thursday, September 5, 2019 8:38 AM To: Boyer, David L (CED) <david.bover2@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations 'Dave, It appears that we will be drilling the A-09 well first and then submitting a spacing exception for the A-03. In filling out section 7 of the sundry for the A-03 Well, shown below, which regulation should we cite? Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes ❑ No For the A-09 Well, we will be citing 20 AAC 25.055(a)(4). Would it be the same for the A-03 and then check the "yes" box below that a spacing exception will be required? My apologies for all of the rapid questions on this. If you would prefer, please feel free to just give me a call. I just want to make sure that both of us only have to fill out/review these forms once. Thank you, Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz(a)hilcoru.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED) [mailto•david boyer2@alaska.eov] Sent: Tuesday, September 3, 2019 4:40 PM To: Michael Schoetz <mschoetz0hilcorp.com> Subject: [EXTERNAL] RE: NCIU A-03 & A-09 Proposed Operations Michael, I checked with one of our experts, and everything I told you on the phone is correct. Your plan of choosing the best candidate between NCIU A-03 or A-09 first to pert and then requesting a spacing exception for the 2nd choice works fine for the undefined pool. The whole process for the spacing exception including the 30 day wait period eats up 6 weeks. CO 68 only covers the defined Tertiary System Gas Pool, as discussed. Cheers, Dave Boyer From: Michael Schoetz <mschoetz(cahilcorp.com> Sent: Tuesday, September 3, 2019 3:26 PM To: Boyer, David L (CED) <david.bover2(aalaska.zov> Subject: NCIU A-03 & A-09 Proposed Operations 2 0413-01 t Thank you, ,t CI B-02 I I � \ , I \ I 1 1 ! 1 1 I 1 \ T11N-R10W Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz64hilcorN.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 NCI -A-03 NCI -A-03 - , ^ r . I rr rl I r J, NCI -R -g9 .-NCI-R-o9 7 �r s NCI -A -OS NCI -A-06 4 r r COOK NILEr !4 UNFT t • 5 NCI -A-12 `ACI ,s CIa.9-OtA : I NCt-A-O7 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. 3 Schwartz Guy L (CED) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Friday, September 13, 2019 8:53 AM To: Schwartz, Guy L (CED) Cc: Juanita Lovett Subject: RE: [EXTERNAL] NCI A-03 RWO (PTD 169-099) Well that's odd, it appears my normal step 3 is missing which would address nipple down of the tree and nipple up of the BOP's 1. The current spool holds a nested hanger design and this spool will stay in place. Procedure is as follows: • Set a BPV and nipple down the tree • Remove the hanger lock down ring • Install new spool on top of existing spool • NU BOP's and test • Then we will pull the existing hanger (shows up as the green inner portion of hanger on the diagram) up through the new spool. The new design does not require any additional nipple downs and will accept a new 11" hanger You are correct in the fact that the CI -A sands will still be open, our goal is to isolate the CI -B sands. We will also be reshooting 15' of the CI -A sands to insure they remain open From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Friday, September 13, 2019 8:38 AM To: Dan Marlowe <dmarlowe@hilcorp.com> Subject: [EXTERNAL] NCI A-03 RWO (PTD 169-099) Dan, Was looking at the procedure and saw that you are changing the tubing head adapter. I don't see that in the procedure ... I need some details on how you are going to replace this with the proper barriers in place. ( The EZSV is set below the Cl -A perfs so it appears there will be open perfs after cement is pumped to abandon the lower perfs so the well will not be isolated) Mike Quick also came over and we looked at the CBL logs from way back. They are the old SLB type with only an amplitude curve. The top log interval was 3500 ft and so wouldn't hurt to get a look at what is above that as per your step #12 . Cement doesn't look too bad after the block sqz work. 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). If may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. It 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 (Guv schwartz@alaska aov). Colombie, Jody J (CED) From: Michael Schoetz <mschoetz@hilcorp.com> Sent: Wednesday, October 23, 2019 9:41 AM To: Colombie, Jody J (CED) Cc: Kevin Tabler; Dan Marlowe; Juanita Lovett Subject: Withdrawal of Spacing Exception - NCI -A-03 Well Jody, Per our conversation this morning, Hilcorp Alaska, LLC (Hilcorp) plans to perform its proposed perforation and recompletion operations on the NCI -A-03 Wellnp 'or to its proposed operations on the NCI -A-09 Well. This will make the NCI -A-03 Well the first gas well in governmental Section 1, TI IN, RI OW, S.M. to be capable of producing, and thus, not require a spacing exception. Therefore, Hilcorp would like to withdraw its request for a spacing exception for the NCI -A- 03 Well, and respectfully requests that its submitted Application for Sundry Approval for said well be approved. As a result, a spacing exception will be required in accordance with 20 AAC 25.055(a)(4) should Hilcorp desire to perform its proposed operations on the NCI -A-09 Well, as it would then be the second gas well capable of producing in the above referenced governmental section. Should you require any additional information, or have any questions, please contact me at the information below. Thank you, Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz(a),bilcora.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. • STATE OF ALASKA • RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS r-, A :pit 1.Operations Abandon ❑ Plug Perforations CI Fracture Stimulate ❑ Pull Tubing 0 Operations shutdown 0 Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing 0 Change Approved Program ❑ Plug for Redrill 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Tubing Plug&Punch El 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development El Exploratory ❑ 168-099 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic El Service ❑ 6.API Number: Anchorage,AK 99503 50-883-20020-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0017589/ADL0037831 N Cook Inlet Unit A-03 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A North Cook Inlet Field/Tertiary Gas Pool 11.Present Well Condition Summary: Total Depth measured 7,480 feet Plugs measured 3,946;4,526; feet 4.586:5.105 true vertical 6,392 feet Junk measured N/A feet Effective Depth measured 3,946 feet Packer measured See Schematic feet true vertical 3,557 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Structural Conductor 384' 30" 384' 384' Surface 612' 16" 612' 612' 1,640 psi 630 psi Intermediate 2,519' 10-3/4" 2,519' 2,329' 3,580 psi 2,090 psi Production 7,475' 7" 7,475' 6,388' 4,980 psi 4,320 psi Liner SCAPM uA1' J. .' Perforation depth Measured depth 3,964-4,070 feet True Vertical depth 3,572-3,660 feet 4-1/2" 12.75#&12.60#/J-55 3,898&6,289 3,517&5,425 Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 4,527 4,028 Packers and SSSV(type,measured and true vertical depth) Pkrs(x11)See Schematic SVLN 286(MD)286(TVD) 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Md Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 380 221 Subsequent to operation: 0 7500 83 394 822 14.Attachments(required per 20 MC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 2 , Exploratory El Develo ment p ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil p Gas 9 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR El WINJ ❑ WAG El GINJ 0 SUSP❑ SPLUGO 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: 317-370 Authorized Name: Stan W.Golis Contact Name: Joe Kaiser Authorized Title: Operations Manager Contact Email: jkaiser@hilcorp.com Authorized Signature: LA-. Date: `°/ qI I Contact Phone: (907)777-8393 Form 10-404 Revised 4/2017 /� �//� / 4.,,;I7 ®""` //��7 !!! ��'�� ���''� �� �"s � 1 Submit Original Only • • North Cook Inlet II Well: NCI A-03 SCHEMATIC ompleted: 11/29/2007 PTD: 168-099 Hilcurp Alaska,LLC API: 50-883-20020-00 CASING DETAIL Size Wt Grade Conn ID Top Btm RKB:MSL=115.9' 30" Conductor 29.000 Surf 384' 16" 65 H-40 15.250 Surf 612' J , 10-3/4" 45.50 J-55 BTC 9.794 Surf 2,519' 1 7" 26 J-55 BTC 6.276 Surf 7,475' TUBING DETAIL 30 4-1/2" 12.75 1-55 E E 8dRD 3.992 Surf 3,898' 4-1/2"1 L 12.60 J-55 EUE Mod 3.958 3,898' 6,289' 16 2 2-7/8"Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135' 4,527' 10.3/4 3 ' `"1 JEWELRY DETAIL `' Depth Depth No ID Item 4 ,� (MD) (ND) 5 _ '( JAS 1 286' 286' 3.813 HES 3.813"SVLN Nipple(WRDP set in nipple) I �� 2 1,738' 1,686' Camco KBG-2 GLM(Dummy) 92Tbg P nch. Plugcet in-.=set 3,013' 2,748' Camco KBG-2 GLM(Dummy) 3,921' x-"'PP1e 4 3,846' 3,473' Camco KBG-2(Orifice) 7 ",1 7' 3,892' 3,512' 4.000 HES PBR Seal Stem Tr _ CI-B 5 3,898' 3,517' 3.992 Halliburton Upper PBR 3,907' 3,525' 3.992 Ratch Latch Seal Assembly 3,908' 3,525' 4.000 Halliburton VSR Packer 8 6 3,946' 3,557' 3.813 Halliburton X Nipple(Plug Set) 4,135' 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 9 ':::[ 4,139' 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/Sliding Sleeve CI-1.o 10 ' `.[ =CI-2.0 7 . 4,146' 3,722' 2.992 16 Ft Lower Extension 11 = CI-3.1 4,193' 3,760' 2.441 2-7/8"Excluder 2000 Screen-Med(337') 1 = 0-4.0 8 4,198' 3,764' 3.990 No Go Seal Assembly 13111 9 4,199' 3,764' 4.000 Halliburton TWR Packer 10 4,501' 4,007' 3.813 Halliburton XD Sliding Sleeve-Closed 14 i ■ = CI-5.0 11 4,525' 4,026' 3.990 No Go Seal Assembly _ 15 12 4,526' 4,027' 2.875"Bull Plug 16 13 4,527' 4,028' 4.000 Halliburton TWR Packer&Millout Extension 17 ■ , e = CI-6.0 14 4,586' 4,074' 3.813 Halliburton XD Sliding Sleeve-Closed(w/PX Plug) 18 15 4,594' 4,081' 3.990 No Go Seal Assembly 19 16 4,595' 4,081' 4.000 Halliburton TWR Packer&Millout Extension 20 ■ ■ a _ CI-7.0 17 4,658' 4,131' 3.813 Halliburton XD Sliding Sleeve-Closed 21 - CI-7.1 18 4,668' 4,139' 3.990 No Go Seal Assembly 22 4,669' 4,140' 4.000 Halliburton TWR Packer&Millout Extension 23 s ■ s = CI-8.0 20 4,744' 4,199' 3.813 Halliburton XD Sliding Sleeve-Closed 24 21 4,750' 4,203' 3.990 No Go Seal Assembly 2511, 22 4,751' 4,204' 4.000 Halliburton TWR Packer&Millout Extension 26 - CI-8.2 23 4,825' 4,262' 3.813 Halliburton XD Sliding Sleeve-Closed 27 24 4,831' 4,267' 3.990 No Go Seal Assembly 28 s a : -CI-9.0 25 4,832' 4,267' 4.000 Halliburton TWR Packer&Millout Extension 29 -CI-10.0 26 4,885' 4,309' 3.990 No Go Seal Assembly 30 27 4,886' 4,310' 4.000 Halliburton TWR Packer&Millout Extension 31 ■ a - 28 4,929' 4,343' 3.813 Halliburton XD Sliding Sleeve-Closed 32 I -CI-11.0 29 4,935' 4,348' 3.990 No Go Seal Assembly 33 - 30 4,936' 4,349' 4.000 Halliburton TWR Packer&Millout Extension 31 5,046' 4,435' 3.813 Halliburton XD Sliding Sleeve-Open 12/13/2001 34 B-s 32 5,105' 4,481' Set 4.5"EZSV Bridge Plug 35 Mt C-3 33 5,113' 4,487' 3.990 No Go Seal Assembly 36 IR - -4 F =F-1,F-2,F-4 34 5,114' 4,488' 4.000 Halliburton TWR Packer&Millout Extension 37 =0-1,0-5 35 5,626' 4,898' 3.813 Halliburton XA Sliding Sleeve-Closed =H-1,H-9 36 6,288' 5,424' 3.725 Halliburton XN LandingNipple =I-3 Pp J-2 37 6,289' 5,425' 3.980 Wireline Re-Entry Guide K-4 -N-5 =0-4 7„ Q3,Q4 Notes: ,.r.n 7 `i • 12/07/2007-Set TTGP on Top of fill @4,532'(Tagged 15'high) PBTD:6,380' TD:7,480' 01/20/2011-9.98'difference in elevation is due to being set on Electric Log Depths Updated By:JLL 10/06/17 • • • North Cook Inlet II Well: NCI A-03 SCHEMATIC LastCo pd: 11/29/2007 PTD: 8099 Hilcorp Alaska,LLC API: 50-883-20020-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT SPF Date Status CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Open CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Open CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Open CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated(EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' • 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated(EZSV Bridge Plug) F-1&F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated(EZSV Bridge Plug) 1-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated(EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated(EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated(EZSV Bridge Plug) 0-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated(EZSV Bridge Plug) Q-3&Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated(EZSV Bridge Plug) Updated By:JLL 10/06/17 • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date NCI A-03 S/L& E-Line 50-883-20020-00 168-099 9/14/17 9/15/17 Daily Operations: 09/14/2017-Thursday JSA, rig up unit pressure test to 2500, and start pressuring up on tubing pushing water away. Pull SSSV and continue pressuring up on tubing. Drift tubing with GR and braided brush making sure tubing clear for E-Line. Set plug in X- nipple at 3947 MD. Rig down and rig up E-Line. Rig up E-Line. MU 10 shot 1-11/16 puncher, continue pressure up on tubing. Shoot from 3919.5-3921, gained 510psi in less than 1 min. OOH, RD E-Line. 09/15/2017- Friday RIH with SSSV, set SSSV, Good Test. POOH, rig down slick line. Notified AOGCC of well return to production and requested SVS witness. They waived the witness. . y of Tit� • • gam_,,I//7:st THE STATE Alaska Oil and Gas —s �,�-1 � ,Il, Of \ L A Conservation Commission ,j014-=,---_,7_,;4_,--,.-_ 333 West Seventh Avenue .1F GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 VIIVIr Main: 907.279.1433 OF ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager _ SCANNED AOIL Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: North Cook Inlet Field, Tertiary Gas Pool,N Cook Inlet Unit A-03 Permit to Drill Number: 168-099 Sundry Number: 317-370 Dear Mr. Golis: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Pic-ftc—L Cathy . Foerster Commissioner DATED thisay of August, 2017. RBDMS (" AUG 1 4 2017 • • RECEIVED STATE OF ALASKA AUG U 7 247 ALASKA OIL AND GAS CONSERVATION COMMISSION Di ` V N 7 APPLICATION FOR SUNDRY APPROVALS �F 20 AAC 25.280 , 1.Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Tubing Plug&Punch 0• 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 0 , 168-099 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service EI 6.API Number: Anchorage,AK 99503 50-883-20020-00-00. 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 68 • Will planned perforations require a spacing exception? Yes ❑ No 0 i N Cook Inlet Unit A-03 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0017589/ADL0037831 • North Cook Inlet Field/Tertiary Gas Pool . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 7,480 • 6,392 . 4,526 • 4,027• 1,190 psi 4,526;4,586&5,105 N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 384' 30" 384' 384' Surface 612' 16" 612' 612' 1,640 psi 630 psi Intermediate 2,519' 10-3/4" 2,519' 2,329' 3,580 psi 2,090 psi Production 7,475' 7" 7,475' 6,388' 4,980 psi 4,320 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 3,964-4,995 . 3,572-4,395 4-1/2"&2-7/8" 12.75#J-55; 12.60#J-55;6.4#L-80 3,898;6,289;4,527 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Packers(x11)see schematic&SVLN Packers-see schematic&SVLN 286(MD)286(TVD) 1 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development D • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 8/21/2017 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 0 . WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W.Golis Contact Name: Joe Kaiser Authorized Title: Operations Manager Contact Email: jkaiser@hilcorp.com � ` Contact Phone: (907)777-8393 _- — Authorized Signature: ti L,..4J Date: Ibi 1 /l COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: _ 3 t-7- S-7 c) Plug Integrity ❑ BOP Test❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes 0 No ier Subsequent Form Required: /0-- Lio 1 / APPROVED BY Approved by: rj /).. ...e../.4t...._, COMMISSIONER THE COMMISSION Date: g i-_/7 9K. 8/g/o. .i'`org7 ,r1/7 RBDMS L`" 1-,.�.; 1 1 2017 O ❑ I Submit in Form and Form 10-403 Revised 4/2017 I�ip llpl i valid for 12 months from the date of approval. Attachments in Duplicate • • • Well Prognosis Well: Tyonek A-03 fIilcorp Alaska,LL Date:8/2/2017 Well Name: Tyonek A-03 API Number: 50-883-20020-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: August 21th, 2017 Rig: N/A Reg.Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 168-099 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (M) Second Call Engineer: Dan Marlowe (907) 283-1329 (0) (907)-398-9904 (M) AFE Number: Current Bottom Hole Pressure: 1,544 psi @ 3,557' TVD (Based on offset well data) Max. Potential Surface Pressure: 1,190 psi (Based on 0.1 psi/ft to surface) Brief Well Summary Tyonek A-3 was drilled and completed in March of 1969 in the Sterling and Beluga sands. A workover was performed in 1994 where the Beluga Q and N sands were isolated with a bridge plug and packers/sliding sleeves run across groups of Sterling intervals. The Sterling A, B, and 9 intervals were isolated with straddle sections. A leak was discovered across the Sterling 5 selective section in March 2002 at which time a plug was run to isolate the Sterling 5 and below. In November 2007 a through tubing gravel pack was run across the Sterling 1-4 intervals. The well has been SI since 2012. The purpose of this work/sundry is to install a tubing plug and punch to test the CI—A and B Sands in the Sterling Formation. 0. e° A �j 4„41,_,,p Notes Regarding Wellbore Condition • Prior to setting a plug, water in the tubing will be pushed away with gas lift and/or well swabbed down. Procedure: 1. MIRU wireline, PT lubricator to 2,000 psi Hi 250 Low. 2. RIH pull SSSV. POOH. LD SSSV 3. RIH with gauge ring and tag. POOH. 4. Set plug in X-nipple at 3,945'. ' Contingency: Utilize RU swab cubs. Remove as much fluid as possible from tubing. POOH 5. Keep gas lift pressure on tubing. (^'840 psig) 6. RU Tubing Punch. RIH and punch tubing at"'3,920'. Use gamma/CCL to correlate. Consult Engineer prior to punch. Punch tubing. POOH. 7. RIH w/SSSV and set in profile. 8. RD wireline 9. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic North Cook Inlet . 11 • • Well: NCI A-03 SCHEMATIC pd: 11/29/2007 PTD: 168099 Hilcorp Alaska,LLC API: 50-883-20020-00 CASING DETAIL Size Wt Grade Conn ID Top Btm RKB:MSL=115.9' 30" Conductor 29.000 Surf 384' 16" 65 H-40 15.250 Surf 612' J .1 10-3/4" 45.50 J-55 BTC 9.794 Surf 2,519' 1. 7" 26 1-55 BTC 6.276 Surf 7,475' TUBING DETAIL 30 4-1/2" 12.75 1-55 EUE 8RD 3.992 Surf 3,898' 1 LMod 4-1/2" 12.60 J-55 EUE Mod 3.958 3,898' 6,289' 16 2 2-7/8"Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135' 4,527' 10-3,° 3 ' JEWELRY DETAIL No Depth Depth ID Item 4 1 (MD) (TVD) 1 286' 286' 3.813 HES 3.813"SVLN Nipple(WRDP set in nipple) 5 2 1,738' 1,686' Camco KBG-2 GLM(Dummy) 6 1' X =CIA 3 3,013' 2,748' Camco KBG-2 GLM(Dummy) -CI B 4 3,846' 3,473' Camco KBG-2(Orifice) 7 `� f i 3,892' 3,512' 4.000 HES PBR Seal Stem po. - 5 3,898' 3,517' 3.992 Halliburton Upper PBR ci-to 3,907' 3,525' 3.992 Ratch Latch Seal Assembly 3,908' 3,525' 4.000 Halliburton VSR Packer 8lil - 6 3,946' 3,557' 3.813 Halliburton X Nipple 9 4,135' 3,713' 2.500 Baker 40A-25 SC-1 GP Packer • 4,139' 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/Sliding Sleeve 10 :. : . --=- C1-2.0 7 4,146' 3,722' 2.992 16 Ft Lower Extension 11 8 _ CI-3'1 4,193' 3,760' 2.441 2-7/8"Excluder 2000 Screen-Med(337') - CI-4.0.., 8 4,198' 3,764' 3.990 No Go Seal Assembly 13 12 9 4,199' 3,764' 4.000 Halliburton TWR Packer - 10 4,501' 4,007' 3.813 Halliburton XD Sliding Sleeve-Closed 14 {cps _- CI-5.0 11 4,525' 4,026' 3.990 No Go Seal Assembly 15 -;.`.. - 12 4,526' 4,027' 2.875"Bull Plug 16 13 4,527' 4,028' 4.000 Halliburton TWR Packer&Millout Extension 17 ■ ■ ■' = CI-6.o 14 4,586' 4,074' 3.813 Halliburton XD Sliding Sleeve-Closed(w/PX Plug) 1815 4,594' 4,081' 3.990 No Go Seal Assembly 19 ° 16 4,595' 4,081' 4.000 Halliburton TWR Packer&Millout Extension 20 j. . . CI-7,0 17 4,658' 4,131' 3.813 Halliburton XD Sliding Sleeve-Closed 21 - C1-7 1 18 4,668' 4,139' 3.990 No Go Seal Assembly 2219 4,669' 4,140' 4.000 Halliburton TWR Packer&Millout Extension 23 ' ' up = CI-8.o 20 4,744' 4,199' 3.813 Halliburton XD Sliding Sleeve-Closed 24 21 4,750' 4,203' 3.990 No Go Seal Assembly 25 22 4,751' 4,204' 4.000 Halliburton TWR Packer&Millout Extension 26 - CI-8.2 23 4,825' 4,262' 3.813 Halliburton XD Sliding Sleeve-Closed 27 24 4,831' 4,267' 3.990 No Go Seal Assembly 28 ;ia®. -CI-9.0 25 4,832' 4,267' 4.000 Halliburton TWR Packer&Millout Extension _ Y9 -Ci-10.0 26 4,885' 4,309' 3.990 No Go Seal Assembly 30 R. 27 4,886' 4,310' 4.000 Halliburton TWR Packer&Millout Extension 31 . a - 28 4,929' 4,343' 3.813 Halliburton XD Sliding Sleeve-Closed 32 - -Ci-1 to 29 4,935' 4,348' 3.990 No Go Seal Assembly 33 - 30 4,936' 4,349' 4.000 Halliburton TWR Packer&Millout Extension 34 31 5,046' 4,435' 3.813 Halliburton XD Sliding Sleeve-Open 12/13/2001 35 i. . s B-6 32 5,105' 4,481' Set 4.5"EZSV Bridge Plug C-3 33 5,113' 4,487' 3.990 No Go Seal Assembly 36 =D-4 =F-1,F-2,F-4 34 5,114' 4,488' 4.000 Halliburton TWR Packer&Millout Extension 37 ". :. _G-1,G-5 35 5,626' 4,898' 3.813 Halliburton XA Sliding Sleeve-Closed =H-1,H-9 36 6,288' 5,424' 3.725 Halliburton XN Landing Nipple =1-3 J-2 37 6,289' 5,425' 3.980 Wireline Re-Entry Guide -K-4 N-5 =0-4 7„ Q3,Q4 Notes: 4 „4.,'''4.:',.-.'", :.a „ _•1. 12/07/2007-Set TTGP on Top of fill @4,532'(Tagged 15'high) PBTD:6,380' TD:7,480' 01/20/2011-9.98'difference in elevation is due to being set on Electric Log Depths Updated By:1LL 07/20/17 North Cook Inlet .n le • Well: NCI A-03 SCHEMATIC d: 11/29/2007 PTD 168-099 Hilcorp Alaska,LLC API: 50-883-20020-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT SPF Date Status CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 C1-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated(EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated(EZSV Bridge Plug) F-1&F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated(EZSV Bridge Plug) 1-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated(EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated(EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated(EZSV Bridge Plug) 0-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated(EZSV Bridge Plug) Q-3&Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated(EZSV Bridge Plug) Updated By:JLL 07/20/17 North Cook Inlet . 'in H . Well: NCI A-03 PROPOSED Last Completed: 11/29/2007 PTD: 168-099 Hileorp Alaska,LLC API: 50-883-20020-00 CASING DETAIL Size Wt Grade Conn ID Top Btm RKB:MSL=115.9' 30" Conductor 29.000 Surf 384' 16" 65 H-40 15.250 Surf 612' t" 10-3/4" 45.50 J-55 BTC 9.794 Surf 2,519' 1J1 7" 26 J-55 BTC 6.276 Surf 7,475' TUBING DETAIL 30" II [ L 4-1/2" 12.75 J-55 EUE 8dRD 3.992 Surf 3,898' 4-1/2" 12.60 J 55 EUE Mod 3.958 3,898' 6,289' 16" 2 2-7/8"Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135' 4,527' I 10-3/4" 3 1 JEWELRY DETAIL 111 Depth Depth 4 No (MD) (ND) ID Item 1 286' 286' 3.813 HES 3.813"SVLN Nipple(WRDP set in nipple) 5 2 1,738' 1,686' Camco KBG-2 GLM(Dummy) Mg Punch Set Plug ink CI-A 3 3,013' 2,748' Camco KBG-2 GLM(Dummy) 13,920' 6 i x-Nipple @-`CI-B Mr ±3,946• 4 3,846' 3,473' Camco KBG-2(Orifice) 7 3,892' 3,512' 4.000 HES PBR Seal Stem � ' 5 3,898' 3,517' 3.992 Halliburton Upper PBR i ii ] =CI-1.0 3,907' 3,525' 3.992 Ratch Latch Seal Assembly . 3,908' 3,525' 4.000 Halliburton VSR Packer 8 6 3,946' 3,557' 3.813 Halliburton X Nipple(Set Plug) ii 4,135' 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 9 ii 4,139' 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/Sliding Sleeve 10 . = CI-2.0 7 4,146' 3,722' 2.992 16 Ft Lower Extension 1 •"" = CI-3.1 4,193' 3,760' 2.441 2-7/8"Excluder 2000 Screen-Med(337') 11 �[ ] CI 4.0 8 4,198' 3,764' 3.990 No Go Seal Assembly 13 9 4,199' 3,764' 4.000 Halliburton TWR Packer 10 4,501' 4,007' 3.813 Halliburton XD Sliding Sleeve-Closed 14 = • = CI-5.o 11 4,525' 4,026' 3.990 No Go Seal Assembly 15 - 12 4,526' 4,027' 2.875"Bull Plug 16 13 4,527' 4,028' 4.000 Halliburton TWR Packer&Millout Extension 17 E.a as = CI-6.0 14 4,586' 4,074' 3.813 Halliburton XD Sliding Sleeve-Closed(w/PX Plug) 1815 4,594' 4,081' 3.990 No Go Seal Assembly 19 16 4,595' 4,081' 4.000 Halliburton TWR Packer&Millout Extension 20 ■ a aE _ CI-7.0 17 4,658' 4,131' 3.813 Halliburton XD Sliding Sleeve-Closed 21 - CI-7.1 18 4,668' 4,139' 3.990 No Go Seal Assembly 22 19 4,669' 4,140' 4.000 Halliburton TWR Packer&Millout Extension 23 sIts = CI B.o20 4,744' 4,199' 3.813 Halliburton XD Sliding Sleeve-Closed 23 --7.:- cl-8.0 24 21 4,750' 4,203' 3.990 No Go Seal Assembly 25 in 22 4,751' 4,204' 4.000 Halliburton TWR Packer&Millout Extension 26 = CI-8.2 23 4,825' 4,262' 3.813 Halliburton XD Sliding Sleeve-Closed 27 24 4,831' 4,267' 3.990 No Go Seal Assembly 28 a . .„' -CI-9.0 25 4,832' 4,267' 4.000 Halliburton TWR Packer&Millout Extension 29 ._ -CI-10.0 26 4,885' 4,309' 3.990 No Go Seal Assembly 27 4,886' 4,310' 4.000 Halliburton TWR Packer&Millout Extension 30 31 ®. 28 4,929' 4,343' 3.813 Halliburton XD Sliding Sleeve-Closed 32 E'.--_CI-11.o 29 4,935' 4,348' 3.990 No Go Seal Assembly 33 30 4,936' 4,349' 4.000 Halliburton TWR Packer&Millout Extension 34 k 31 5,046' 4,435' 3.813 Halliburton XD Sliding Sleeve-Open 12/13/2001 35 . ■`, B-6 32 5,105' 4,481' Set 4.5"EZSV Bridge Plug =C-3 33 5,113' 4,487' 3.990 No Go Seal Assembly 36 =D-4 34 5,114' 4,488' 4.000 Halliburton TWR Packer&Millout Extension ffi =F-1,F-2,F-4 37 !G-1,G-5 35 5,626' 4,898' 3.813 Halliburton XA Sliding Sleeve-Closed H-1,H-9 36 6,288' 5,424' 3.725 Halliburton XN Landing Nipple =_-1-3 J-2 37 6,289' 5,425' 3.980 Wireline Re-Entry Guide -K-4 N-5 =0-4 Notes: 7" Q3,Q4 12/07/2007-Set"IMP on Top of fill @4,532'(Tagged 15'high) PBTD:6,380' TD:7,480' 01/20/2011-9.98'difference in elevation is due to being set on Electric Log Depths Updated By:111 07/20/17 North Cook Inlet n • • Well: NCI A-03 SCHEMATIC Last Completed: 11/29/2007 PTD: 168-099 Hilcorp Alaska,LLC API: 50-883-20020-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT SPF Date Status CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 3/14/1969 Cmt Sqz CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 CmtSqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 CmtSqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated(EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated(EZSV Bridge Plug) F-1&F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated(EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated(EZSV Bridge Plug) 1-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated(EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated(EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated(EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated(EZSV Bridge Plug) 0-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated(EZSV Bridge Plug) Q-3&Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated(EZSV Bridge Plug) Updated By:JLL 07/20/17 Well Name Pre 2008 Survey Location NAD27 ASP 4 Northing Easting Post 2008 Survey Location NAD27 ASP4 Northing Easting Distance Moved NCI A-01 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 ~~N~ APR 0 4 2008 • • /~ ~-0~~ REV DATE BY CK APP SCRIPTION REV DATE BY CK DESCRIPTION I 2/29/08 SAS 1(~/Q MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 o g ~ 36 31 T 12 N 31 32 ~; ~ :~' 1 s 9s T ll N s 5 N .~, Ro s. ~svs. SEC. 6 1206' SCALE: I"_1320' ----6 -- ~ ~ i o ~ ~ 1 6 6 5 12 7 ~ g \ GENERAL NOTES: \\/ q~ •~~~ ~F I. SEE SHEET 3 FOR COORDINATE TABLE • , • P.•'''~ ~ ; S ~~•• •••• ~ ~~ ~ 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND ~ ' • ~ ~j ~ ' ~ '~ ' VERTICAL SURVEY DATA 49th • ~~ ~ : 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED ~""''"""""""""""""""""""""j VALUES. ~ ....................................... ... ..~ . ~ ~• ~, ;• KENNETH W. AYERS ~: ~o r ~• J' ',• LS-8535 .•'••~,i SURVEYOR'S CERTIFICATE ~1~,, •ARO „•...•,,,~~'PN::•i I HEREBY CERTIFY THAT 1 AM PROPERLY REGISTERED F AND \\~l ; ~~~~~ 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 & nssoc[nTES, INC. FEBRUARY 28 2008 SURVEYORS ENGINEERS PLANNERS ~ ~~ , . PHONE: (907/ 272-5451 y.~ AREA: MODULE: UNIT: ConocoPhilli s NORTH COOK INLET p TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 0227/08 Og-~~5 AS BU~~T 1 OF 3 1 REV DATE BY CK APP SCRIPTION REV DATE BY CK P DESCRIPTION 1 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 ~r 9 ~ r W °ss ¢ ,~£' 9 ~n~ ~ AA9 rux ao 6' 0 s. nu. v~, scc e y~ ~~ ~~ SO s~, SCALE: 1"=30' a9 dp. O ESD 600 -50 ESD 600-51 e Ala 7 • I p •B2 A:A7 A8 • 83 : •p5 • A3• 46 A12 BI : •A5 ' A4 • A2 WELL HOUSE 2 B All I O• zp A1Op5 LEGEND: o~ , • WELL p WELL CONDUCTOR 0 ESD (EMERGENCY SHUT OFF VAL VEl 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 & ASSOCIATES, INC. AS BUILT SURVEYORS ENGINEERS PWNNERS O ~ PHONE: (907/ 272-5451 AREA: MODULE: UNIT: ConocoPhilli s NORTH C°OK 'MEET TYONEK PLATFORM Alaska, Inc. WEAL CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 08-005 AS BUNT 2 of 3 1 REV DATE BY CK APP `DESCRIPTION ~ 2/29/08 SAS ~(~/A MODIFY WELL HOUSE SCHEMATIC, SH T.2 ADD MUD LINE ELEV., SHT.3 DESCRIPTION ASP ZONE4, NAD83, FEET NAD83 GEOGRAPHIC MLLW DESCRIPTION (POINT NO.) NORTHING FASTING LATITUDE LONGITUDE ELEVATION NCIU W ELL 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 62 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 1 OF 1, REV. 2 3. ALL AS BUILTS ARE TO THE CENTER OF EXISTING STRUCTURE. 4. WELL CONDUCTOR ARE VERTICALLY AS BUILT TO 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. & nssoc[nTES, crrc. ConocoPhilli s p Alaska, Inc. CADD FILE N0. DRAWING N0: 8-005 AS BUILT 02/27/08 SURVEYORS ENGINEERS PLANNERS O ~ PHONE: 19071 272-5451 MODULE: UNIT: AREA: NORTH COOK INLET TYONEK PLATFORM WELL CONDUCTOR AS BUNT 08-005 AS BUNT PART: 3 of 3 REV: 1 s ~ Maunder, Thomas E (DOA) From: Ennis, J J [J.J.Ennis@conocophillips.com] Sent: Thursday, March 27, 2008 8:59 AM To: Maunder, Thomas E (DOA) Cc: Allsup-Drake, Sharon K Subject: RE: NCIU A-03 (168-099) Workover Attachments: NCI A-03 Cudd 136 summary.pdf Good morning Tom, Page 1 of 1 Non-truncated version of NCI A-03 rig summary attached. Sorry for the confusion, we hadn't noticed the Excel downloaded version chops off long comment sections. Sharon: I replaced our central fifes copy w/ this as well. Jim Ennis j j.ennis@conocophillips.com (907)265-1544 (IN) (907)632-7281 (C) hew E ~~ns~,~-J~ ~S S s /".~Y ~ <ah From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov) Sen#: Wednesday, March 26, 2008 12:04 PM To: Ennis, J J Subject: NCIU A-03 (168-099) Workover Jim, Finally getting things reviewed on this work. Some of the comment blocks are "cut off'. In particular, the summary for the early hours of 12/10 is incomplete. Is it possible to check the information blocks and send complete information? Thanks in advance. Tom Maunder, PE AOGCC `~~d MAR ~ '~ 200 . ~, 3/27/2008 • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION ~~~~ REPORT OF SUNDRY WELL OPERATION~ske o~c & Ins Gong. G~mmissi~r>7 t Operations Pertormed: Abandon ^ Repair Welt Q ' Plug Perforations ^ Stimulate ^ Other nC ~~8 Alter Casing ^ Pull Tubing Q Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ~ Operat. Shutdown^ Perforate Q Re-enter Suspended Well ^ 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: ConOCOPhillips Alaska, InC. Development ^ Exploratory ^ 168-099 / 3. Address: Strati raphic g ^ Service 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 <. 50-883-20020-00 . 7. KB Elevation (ft): 9. Well Name and Number: RKB 116' ~ NCI A-03 8. Property Designation: 10. Field/Pool(s): s Sn~ ADL 18755. North Cook Inlet Field / Tertiary~as Pool • 11. Present Well Condition Summary: 3`3•a~ Total Depth measured 7480' feet true vertical 6392' feet Plugs (measured) 5105' Effective Depth measured 6380' feet Junk (measured) true vertical feet Casing Length Size MD TVD Burst Collapse Structural Structural 384' 30" 384' 384' Conductor 612" 16" 612' 612' Surface 2519' 10.75" 2519' 2320' Production 7475' 7" 7475' 6385' Pertoration depth: Measured depth: 3930'-4995', 5254'-7237', CI A-B: 3964'-4070' (SI), C I 1-4: 4210'-4494' true vertical depth: Tubing (size, grade, and measured depth) 4.5", J-55, 6290' MD. Packers & SSSV (type & measured depth) packers @ 3908', 4135', 4199', 4526', 4595', 4669', 4751', 4832', 4886', 4936', 5114' Halliburton'XXO' SVLN @ 291' 12. Stimulation or cement squeeze summary: Intervals treated (measured) gravel pack CI 1-4 4210'-4494' Treatment descriptions including volumes used and final pressure: TTGP placed 6400# 20/40 Accu-Pack behind screens 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation 0 0 0 -- Subsequent to operation 0 1200 50 - 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^ Gas WAG^ GINJ^ WINJ ^ WDSPL^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NiA if C.O. Exempt: 307-314 Contact Jim Ennis @ 265-1544 Printed Name IS ~ Title Wells Group Engineer ~ ~ Signature Phone: 265-6471 Date ~~ '~ Pr ar Sh r n All u Drake 263-4612 Form 10-404 Revised 04/2006 R~-kls 3f~llz ,~ 3.3•ea Submit Origin Onl ~~.~~vS NCI A-03 Pre-Rig and Post-Rig Workover Su~ry DATE Summary 10/3/07 Tag fill @ 4579' KB 10/26!07 Pull 4.5" SSSV, drift tubing w/ 3.75" gauge ring down to 4490' KB. 11/3/07 BARGE AND SET UP SCHLUMBERGER E-LINE UNIT ON TYONEK PLATFORM FOR PERFORATIONS ON WELL A-3 IN A.M. 11/4/07 RIG-UP SLB E-LINE UNIT. SHOT PERF INTERVAL FROM 4495' TO 4520'MD IN 4.5" TUBING WITH 25' X 2.875" (ONE SPF) HC GUNS. WHILE POOH GOT STUCK @ 4375' ELM, PULL OUT OF WEAK POINT AT 5200#. POOH WITH CABLE, LAY DOWN SLB EQUIPMENT. JOB IN PROGRESS. 11/5/07 RIG-UP POLLARD W/L UNIT. FISH SLB 2.875" X 25' HC PERF GUNS @ 4478' WLM, FULL RECOVERY AND ALL SHOTS FIRED, RDMO POLLARD EQUIPMENT. PREP SLB EQUIPMENT FOR PERF RUN IN A.M. JOB IN PROGRESS. 11/6/07 RIG-UP SLB E-LINE UNIT. MADE FOUR PERF RUNS. FIRST INTERVAL WITH 3 3/8" GUNS (12 SPF) FROM 4,474' - 4,494' MD. SECOND PERF INTERVAL WITH 2 7/8" ' GUNS (1 SPF) FROM 4,453' - 4,473' MD. THIRD PERF INTERVAL WITH 2 7/8" GUNS (1 SPF) FROM 4,441' - 4,453' MD. FOURTH PERF INTERVAL WITH 3-3/8" GUNS (12 SPF) FROM 4428'-4440' MD. ALL SHOTS FIRED AND NOT PROBLEMS ENCOUNTERED. __ _ JOB IN PROGRESS. 11/7/07 Rig-up SLB E-Line unit. Made seven perf gun runs. First 26' x 2 7/8" (1spf) guns from . 4401'-4427'. Second 25' x 2 7/8" (1spf) guns from 4376' - 4401'. Runs three,four, five, and six were with 3 3/8" (12spf) guns from 4300' - 4375'. Seven 18' X 2 7/8" (1 spf) guns from 4281' - 4299'. No problems encountered. all shots fired. Job in progress. ~ 11/8/07 Continued perforating 4.5" tubing with 3 3/8" (12spf) HC guns from 4205' - 4280'MD. Rigged down SLB E-line and ready equipment for Demob. Rig-up Pollard S/L, drift tubing with 3.50" G-ring to 4500'wlm. Made four bailer runs with 2.5" bailer. bail metal and sand from 4500' to 4503' wlm. Job in progress. 11!10/07 Continue to ready platform deck for CUDD equipment. Pollard W/L continues to troubleshoot SSSV failure on A-05. Unable to spot up CUDD equipment till SSSV work is complete. Offload first boat load of CUDD equipment. 11/11/07 POLLARD W/L COMPLETED SSSV WORK ON NCI A-05. LAY DOWN POLLARD EQUIPMENT AND OFFLOAD ON OUT GONG BOAT. CONTINUE RIGGING UP CUDD WORKOVER UNIT. _ 1/24/08 MIRU POLLARD W/L. CHANGED OUT 3/16" OV WITH 3/8" OV @ 3846'RKB. INSTALLED 3.813" HES FXE SSSV @ 286'RKB. JOB COMPLETE. • ' >: ConocoPhillips NCIU Well A-3 Wellbore Diagram API#508832002000 Gas Producer FMC OCT RKB-Drill Deck: Single Comp. FMC 41/2" Brd X 4" BTBC RKB-THF: ~ 39.94 ~~ ss SSSV Annulus Fluid: 6 % KCL wtr wl corrosion inhibitor RKB-SL : 115.9 ~:~ 384 TOC: 3700' from CBL dated 03114169 WATER DEPTH: 120' RKB-ML s3 OD Tap:::::: BottcM WT Cxade GGrln. ::;Burst: i:i:Gnl[i 7en;rl:!i:': CASING & TUBING 16" @ 612' 30 " 41 384 16" 41 612 65# H-40 1540 600 293 10 J/4 " 41 2 519 45.5# 8 51# J-55 BTBC 3350 1970 531 61 7" 39 79 26# J-55 BTBC 4660 4080 327 7 " 79 6 818 23# J-55 BTBC 4080 3080 288 '~ 4.5" protl tbg w/ 3 GLM's 7 " 6 818 7 475 26# J-55 BTBC 4660 4080 327 4 1l2" 39 325 12.6# J-55 mod BTBC 4730 4380 134 4 1l2 " 325 6 285 12.6# J-55 mod Brd 4730 4980 134 55 NAi~!:!: :::!:;:Td~~i~i:!: :i~i~iEep fli~i~i~ ~i~i~i~i~i~i~i~i~i~i~`i~i~i~i~i~ iDasCN'tiorl~i~i ~i~i~i~i~i~i~i~i~ii~ ~ i~i~ID~i~i~i~ ~i~i~i~i~C1D~i~i~i~i PRODUCTION TUBING STRING & JEWELRY 5s 10 314" @ 2519' Note: 8.98 ft difference in elevation on 1994 tally is due to assembly being set on Electric Log Depths TOC @ 3700' CBL 68 0-00 39 94 Ori iris/ KO 3.958 U 000 58 ~`i Halliburton VSR packer @ 3908' 67 39.94 1 84 FMC / OCT G" 3M 4 tit" Brd x 4 1/2' BTC Tbc .Han er 3 958 6.000 66 41.78 244 39 4 1 i2" 12 6 Ib J-85 BTC Tubin S u s 3.992 4 S00 Cook Inlet Sands 65 28G 17 2.45 Halliburton "XXO" SVLN (FXE installed 1-2408) 3.813 4.920 3930 - 3931 sqz 64 288.62 1449 85 a 12" 12 75 Ib J-55 EUE Tubrn. 3 992 4.500 53 "x" 63 1738 47 5 8G Camco KBG-2 GLM GLV w, BK-2 latch Installed 12-12-0. 3.860 5.584 3964 - 3979 CI-A 62 1 i 45.33 1267.34 4 1,2" 12 6 Ib J-55 EUE Tubin 3 992 4.SOU 61 301267 6.83 Camco KBG-2 GLM GLV w/ BK-2 latch installed 12-12-07 3 860 5.984 4000 - 4025 CI-B 60 3019.50 826 60 4 1/Z" 12.6 Ib J-55 EUE Tubin 3.992 4.500 59 3846.10 6.88 Camco KBG-2 GLM 0.375" OV w/ BK-2 latch installed 1-24-OB 3.860 5.984 4055 - 4070 CI-B 58 3852.96 38.61 4 1!2" 12.6 Ib J-55 EUE Tubin 3.992 4500 57 3898 21 8.68 Halliburton U er "PBR" 3 992 G 880 hsc-1' Dkr 4135' 4100 - 01 sqz 56 3906.89 2 62 Retch Latch Seal Assembl 3.992 ~ bti2 4178 - 79 sqz 55 3909.51 6.48 Halliburton "VSR" Packer 4.000 6.000 54 3914.49 31 38 4 1/2" 12.61h J-22 EIJE Tubin 3.992 4500 3945.87 1.44 Halliburton "X" Ni le 3.813 5.562 =~> Halliburton TWR packer @ 4199' 2 3947.31 250.87 4 1.2" 12 r> Ib J-22 EUE Tubin 3 992 4500 s .'.~ 4.5" tUg DeRd 4205'-0520' (12 81 spry N..l 51 4198.18 2 62 No Go Seal ASSBmbI 3 990 5.56'J 4210 - 4280 CI-1.0 L~ ` 50 4200.80 10.68 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 i 20/40 ~ ~ 4300-4375 CI-2.0 ~\' ~ 49 4209.98 U6 Tubin Ada for 3990 6.560 ~i~i ACCU-Pack gravel i 1 I i 4428 -4440 CI-3.1 ~ , 4474 -4494 CI-4.0 ~ ` I 48 47 4210.58 4501.18 290 GO 4.22 4 V2' 12.6 Ib J-55 EUE-MOD Tubin & Pu ~ Jls. Halliburton "XD" Slidin Sleeve Closed O6I03I06 1992 3.813 4 SUO 5.560 46 4505.40 20.41 41/2" Pu Jts- 3.992 4.500 4r ~:~: XD Teaks 8 X pro/i/e bad (Jun 'O6J 45 4525.81 2 62 No Go Seal Assembly 3.990 5.560 `~ .~.~ 2.875" Excluder medium screens 4194'-0532' w' 44 4528.43 10.66 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 7 ~, 43 4537.59 0.6 Tubin Ada for 3.950 5.560 4a ` Halliburton TWR packer @ 4526' 42 4538.19 47 73 a 1/Z' 12 6 Ib J-55 EUE-MOD Tubin 8 Pu Jts. 3 992 4 500 "x0" :':~ TAG'd FILL @ 4579' RKB (10/3/07) 41 4585.92 8.3 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1/31/02 3.813 5.560 41 'PX'plu ~i~ 4552 - 4582 cbs-o 40 4594.22 2 6Z fdu Go Seal Assembly 3.990 5.560 cl~s~d 39 4596 84 10.65 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 38 4605.99 0.6 Tubin- Ada for 3.990 5.560 a9 iii Halliburton TWR packer @ 4595' 37 4606.59 51.60 4 162" 12 6 Ib J-55 EUE-MOD Tubin 8 Pu Jts. 3.992 4.500 36 4658.19 10.35 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1131/02 3.813 5.560 4630 - 4640 a-s.o 35 4668.54 2.62 No Go Seal Assembl 3.990 5-560 as °xn° Tbg leak @ 4658' (sleeve leak?) 34 4671.16 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 closed 33 4680.30 U G Tubin Ada for 3.990 5.560 32 466Q90 62 79 4 1/2" 126 Ib J-55 EUE-MOD Tubin 3.:192 4.500 31 4743.69 6.26 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1131102 3.813 5.560 30 4749.95 2 e,2 No Go Seal Assembl ~ 3.990 5 5ti0 sa i Halliburton TWR packer @ 4669' 29 475257 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 Tbg leak @ 4700' 28 4751. ~ 1 0 6 Tubin Ada for 3.990 5.560 91 °x0° 4692 -4697 CI-7.0 27 4762.31 62 62 4 1,2" 12 61b J-55 EUE-MOD Tubin 3 992 4.500 closed 4730 - 4737 CI-7.1 26 4825.13 6.26 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1/31/02 3.813 5.560 25 483141 2.62 No Go Seal Assembl 3.990 5.560 29 :i:i Halliburton TWR packer @ 4751' 24 41334.03 10.72 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 23 4843.25 0.6 Tubut. Ada [or 3.990 5.560 4778-4788 CI-8.0 22 4843.85 41.43 41/2" 1261b J-55 EUE-MOD Tubinc 3.992 4.500 zs °xo° 4793 - 94 sqz perfs 21 4885.26 2.62 No Go Seal Assembl 3.990 5.560 closed 4810 - 4820 CI-8.2 20 4887.90 10.7 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 19 4897.10 0.6 Tubin Ada for 3.990 5-560 z4 `S Halliburton TWR packer @ 4832' 18 4897.70 31 38 4 '1.2" 12.6 Ib 1-55 EUE-Iv10D Tubin 3.992 4 500 17 4929.08 6.28 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1/30/02 3.813 5.560 4850 - 4875 CI-9.0 16 4935.36 2.62 No Go Seal Assembl 3.990 5.560 15 4937.98 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 m iiii Halliburton TWR packer @ 4886' 14 4947. t2 0 6 Tubin Ada for 3 990 500 13 4947.72 98.27 4 1/2" 12 6 Ib J-55 EUE-MOD Tubin 3.992 4.500 4900-4925 CI-10.0 t2 -~99 4.22 Halliburton"XD"Slidin Sleeve CLOSED 3.813 5.560 n °xD" t I i 21 G2.67 4 V2" 12.6 Ib J-55 EUE-MOD Tubin 3.992 4 500 closed 10 5105.00 4 1/2" EZSV Brid a Plu 4.500 9 .;1 It.88 262 No Go Seal Assembl ~ 3.950 5.560 t8 iiii Halliburton TWR packer @ 4936' 8 5115.50 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 7 5124.64 05 Tubin Ada for 3.990 5.560 Tbg leak @ 4940' G 5123.24 501.1 4 1-Z' 12 G Ib J-55 EUE-MOD Tubin 3.992 4.500 ~.' on@499 ' 4950-4995 CI-11.0 ~ 5 5626.34 4.22 Halliburton"XA"Slidin Sleeve 3.813 5.560 1z °x0° ~ :: 4 563056 657.01 4 I%T 12 6 Ib J-55 EUE-MOD Tubin 3.992 4.600 to EZSV BP ;$10a'KB 3 6287.57 1.5 Halliburton "XN" Landin Ni le 3.725 5.560 8 ~ i~ Halliburton TWR packer @ 5114' 2 6289A7 U.6 Re-Entr Guide Beluga Sands I 62e9 s7 End ~r Ilibing 5254-5261 b-6 527s - 5z6a b-7 Well History •~xn~• ~ closes 1 ~•xnr• z ~ ro saeo~ 5418 -5423 c-3 5565 - 5570 d-3 5579 - 5584 d-3 5596 - 5603 d-4 5834 - 5844 f-1.18f-2 5870 - 5880 f-4 5961 - 5971 g-1 6043 - 6058 g-5 :; 6070 - 6080 h-1 6227 - 6252 h-9 6284 - 6289 i-3 F1SV @ 6380 6414 -6421 j-2 6514 - 6529 k-4.1 6696 - 6908 n-5 7033 - 7040 0-4 7212-7237 q-38q-4 March 1969 -Original Completion - CI A, B, 4.0,5.0,6.0,8.0,8.2,9.0,10.0,11.0, and Beluga b-6 thru q-4 Commingled July 1975 - CI 1.0, 2.0,7.0,87.1 Pertorated. September 1994 Workover -Well completed in Beluga b-6 thru i-3 Reperforate Beluga b-6 thru i-3 5254'-6289' 12 SPF Beluga j-2 thru q-4 abandoned without testing Reperforate CI 1.0 thru 11.0 from 4210'-4995' 12 SPF Also added CI 3.1 perforations October 1999 -Top of Fill 6342' Jun 4, 2001 -Tag fill @ 5625' Dec 2001 -Set EZSV BP @ 5105' RKB. Open XD Sleeves @ 5046' 8 4929' RKB. Jan 30, 2002 -Tag fill @ 5005' WLM, Closed sleeve @ 4878' WLM Jan 31, 2001 -Confirmed all sleeves above 5005' SLM closed, tested well @ 12MM , approx 300 BWPD, Ran SSSV March 2002 -Tag fill @ 4991' RKB, ran PDS caliper and production log, 3 tbg leaks identified, set'PX' plug @ 4586' RKB. May 14, 2002 -Tag fill @ 4530' WLM. Obtain BHP survey. May 15, 2003 -Tag fill @ 4560' RKB (4534' WLM). Obtain BHP survey. May 13, 2004- Tag fill @ 4566' RKB. Obtain BHP survey. May 14, 2005 -Tag fill Co? 4500' RKB. Obtain BHP survey. Jun 2006 -Bail fill to 4561' KB. Close XD @4501' KB, leaks. Can't locate X profile in same. Set WRP at 4481' KB, PT tbg OK. Sep 2006 -Tag fill @ 4579' RKB. Obtain BHP survey. Oct 2007 - Tag f ll @ 4579' RKB w/ 1.75" bailer. Tag w/ 3.75" GR @4490' RKB. Nov 2007 - Eline perfd 4.5" tbg 4205'-4520' w/ big hole 12 spf (adjacent to csg perfs) 8 1 spf (in between 12's) hollow carrier guns. Dec 2007 - RWO added GLM's to tbg 8 installed 2.875" TTGP w/ 6400# 20!40 placed behind Excluder medium screens. U dated :2/7/2008 B :Jim Ennis _ _ _ _ 7" @ 7475' PBTD: 6380' TD = 7,aeo' weu: North Cook Inlet Unit No. A-03 Location Lower Cook Inlet. Alaska Field: Cook Inlet Unit JJE Ah lime Logs _ Date From To _ Dur S. De th ___ E. De th Phase Code Subcode T COM 11/22/2007 03:00 12:00 9.00 MIRU MOVE Skid unit over well. Continue RU 12:00 13:30 1.50 MIRU MOVE Shut down crane due to high winds, 13:30 15:30 2.00 MIRU MOVE Clear hands from drill deck due to high winds, 45+ m h. 15:30 00:00 8.50 MIRU MOVE Winds dropped slightly, still not able to run crane. 11/23/2007 00:00 02:00 2.00 MIRU MOVE Standby for weather 02:00 08:00 6.00 MIRU MOVE Make up BOP stack, call for Cham ion to return. 08:00 13:00 5.00 MIRU MOVE Champion at platform, unloading 13:00 18:00 5.00 MIRU MOVE Hook up electrical to Kummy and MI e ui ment. 18:00 00:00 6.00 MIRU MOVE Set tongs in CUDD unit, and slip BOP back for function test. 11/24/2007 00:00 01:00 1.00 MIRU MOVE Well had 50 psi on tubing, bled to 0 psi, check TTP 8~ control line for pressures and bled to 0 si. 01:00 04:00 3.00 MIRU MOVE Install BPV, SI adjacent wells. 04:00 16:00 12.00 MIRU MOVE Nipple down tree. Install blanking lu .Threads were scaled up, cleaned with wire brush and solvent. Unload Champion and RU MI & PTS 16:00 00:00 8.00 MIRU MOVE Continue rigging up BOP's, removed riser section to rotate to accomidate 3" hose. 11/25/2007 00:00 02:00 2.00 MIRU MOVE Rotate choke manifold, had to shut down crane due to hi h winds. 02:00 07:00 5.00 MIRU MOVE Stanby for weather. 07:00 00:00 17.00 MIRU MOVE Continue with RU, spotting equipment. Tie in Kill and choke lines to BOP stack. 11/26/2007 00:00 01:00 1.00 MIRU MOVE Initial IA FL near surface, bled IA to 0 psi. Tie into platform tri-plex and start ressurin u on IA. 01:00 02:00 1.00 MIRU MOVE At 1800 psi pump pressure the IA broke back pressure rapidly. Upon investigation, found several LDS's leakin water. Also noticed all LDS's were backed out. BOP stack filled with fluid indicating that the tubing han er seals failed. 02:00 03:00 1.00 MIRU MOVE Bled well back down to 0 psi, called FMC about re lacement seals. 03:00 05:00 2.00 MIRU MOVE Standby for high winds and FMC. 05:00 11:00 6.00 MIRU MOVE Continue RU and placing containment mattin ,winds down to 14 m h. 11:00 15:00 4.00 MIRU MOVE FMC repaired leaking LDS's, unable to seat PO seals. BOP stack has direct communication with IA. Page 2 of 13 • 1 Time Logs Date From To _ Dur S. De th _ E. Depth Phase Code Subcode T COM 11/26/2007 15:00 19:00 4.00 MIRU MOVE Quadco & Tutka on location rigging up pit monitoring and gas detection s stems. 19:00 00:00 5.00 MIRU MOVE Perform Shell test on BOP' and surface pressure equipment. (All assed . 11127/2007 00:00 01:00 1.00 MIRU MOVE Make up XO for blanking plug, and attach to 4.5" x 2' pup with circ hole alon w/ 3 'oints of i e. 01:00 01:30 0.50 MIRU MOVE While making up last joint of pipe, employee swung tongs into hydraulic hose causing it to part at king bushin .Caused 2 allon s ill. 01:30 03:30 2.00 MIRU MOVE Clean up spill 03:30 07:30 4.00 MIRU MOVE RIH w/ pipe and tie into blanking plug by rotating left 9.75 turns. Test upper pi a rams to 2500 si 07:30 10:30 3.00 MIRU MOVE Finish RU of pit monitoring equipment and as detection a ui ment. 10:30 14:30 4.00 MIRU MOVE Back out blanking plug. Pull BPV. 14:30 17:30 3.00 MIRU MOVE Pull hanger. Never pull over 44k. Well started u-tubing after unseating the PBR. Circulate well with 145 bbls water. Monitor well 15 mins. Well static. 17:30 20:30 3.00 MIRU MOVE OTHR Lay down hanger, one 6' pup, and two 10' u s. 20:30 00:00 3.50 SURFA WELCT BOPE Install test plug. 11128/2007 00:00 02:00 2.00 SURFA WELC Finish installing test plug. 02:00 10:30 8.50 SURFA WELCT BOPE Start state witnessed BOPE function test to 250/2500 psi (AOGCC Bob Noble onsite 10:30 14:30 4.00 SURFA WELCT Pull test joint above hanger and test blind rams. 14:30 16:00 1.50 SURFA WELC TIH below bottom rams and test Koome .BOP test com lete. 16:00 18:00 2.00 SURFA WELCT OTHR Rig-up and test PTS surface e ui ment. 18:00 00:00 6.00 SURFA MOVE OTHR Finish installing last of plywood along outer railing. Continue moving equipment on work deck in prep for BJ equi ment in AM. 11/29/2007 00:00 01:00 1.00 SURFA MOVE Prep work deck for pulling 4.5" com letion. 01:00 02:30 1.50 COMPZ RPCO RCST P Start pulling 4.5" completion with SSSV control line to 290' MD. Weight off bottom 45K. La down SSSV. 02:30 11:30 9.00 COMPZ RPCOti RCST P Continue pulling 4.5" completion standin back tubin . Page 3 of 13 r ~ Time Logs _ ____ Date From To Dur S. De th E. De th Phase Code Subcode T COM 11/29/2007 11:30 13:30 2.00 COMPZ RIGMN RURD P Secure well, change seals on PBR assembly. Reposition equipment on deck to clear space for 500 bbl frac tank. Manitwok out of range for lift/spotting. Need to use Unit crane for frac tank. 13:30 18:30 5.00 COMPZ RIGMN Rih with 6 stands of pipe, secure well. Backload equipment to clear deck space to rig up fluid lines so we do not have to disconnect. Complete rigging up fluid system prior to tripping in hole. 18:30 20:30 2.00 0 120 COMPZ RPCO PULD P POOH w/ six stands. Redress and P/U HES PBR seal assembly, one single joint tubing, and GLM # 3 @ 3846'. 20:30 00:00 3.50 120 3,425 COMPZ RPCO RCST P Start in hole with 4.5" completion, drifting tubing as we run in hole. GLM #2 @ 3011'. Continue offloading equipment from champion. Baker e uipment, inhibitor, MI hoses, etc... 11/30/2007 00:00 01:00 1.00 3,425 1,730 COMPZ RPCOh RCST P Continue in hole with 4.5" completion. GLM #1 1736'. 01:00 06:00 5.00 1,730 0 COMPZ RPCOh RCST P Continue in hole with completion. 3.813" HES SVLN @ 282'. MI swaco mixing 1 % corrosion inhibited 6% KCL water. Will continue in hole with completion without C/L to confirm space-out depth. While waiting on confirmation about tubing hanger in Kenai. 06:00 14:00 8.00 0 COMPZ RPCO RCST P Complete RIH, noticed slight weight loss, flag pipe squat down to 32,000#. Made another 2.70 ft in hole. Roll pump and pressure up to 400 psi. Mark pipe, record measurements. POOH up to SSSV, install control line. 14:00 16:00 2.00 COMPZ RPCO RCST P Tubing hanger arrived on platform, begin RIH with tubing hanger and SSSV control line. 16:00 18:00 2.00 COMPZ RPCOh PULD P Reconfirm with pipe tally depth. 18:00 00:00 6.00 COMPZ RPCOh PULD P Made two attempts to confirm space-out depth. Before installing control line on hanger. Unable to see_ seal assembl en a e PBR, recheck i e tall . 12/01/2007 00:00 06:00 6.00 COMPZ RPCO HOSO P Continue space-out. Confirmed correct space out. Add four space out pups totaling 27.2'. New 4.5" completion with 3.813" HES SVLN @ 286'RKB, GLM #1 @ 1739' RKB, GLM # 2 @ 3013' RKB, GLM # 3 3846' RKB. 06:00 10:00 4.00 COMPZ RPCOh HOSO P Landed PBR seal assembly & Tubing hanger in correct position. test PBR to ,~-- 500 si for confirmation Page 4 of 13 • ~~ Time Logs __ Date From To Dur S. De th _ E. De th Phase Code Subcode T COM 12/01/2007 10:00 13:00 3.00 COMPZ RPCOR HOSO P P/U 10ff and pump 70 bbls of filtered/corrosion inhibited KCL water followed by 7 bbl/s of 60/40 freeze protect. 13:00 17:00 4.00 COMPZ RPCOh SLKL P P/U so tubing hanger is in the work window. Rig up SL to run a SSSV blanking sub & test the control line. RIH tag SSSV @ 250' WLMD set blanking plug, test control line to ___, 5 000 si for 15 min no loeak off. 17:00 18:00 1.00 COMPZ RPCO SLKL P POOH with SSSV blanking sub, rig down S.L. Crew chan e. 18:00 19:00 1.00 COMPZ RPCOh PULD P P/U perferated pump sub and install above tubing hanger and below top i e rams. 19:00 22:00 3.00 COMPZ RPCOh DHEQ P Make up landing joint above perforated pup, make up stand pipe hose. Land hanger. PT tubing 3000 psi (charted) 30 mins, ood test. Leave 3000 psi on tubin PT annulus to 2500 si (charted) for 30 mins, good test. Bleed annulus and tbg to zero. Lay down landin 'oint, pre for i e ram swa . 22:00 00:00 2.00 COMPZ RPCOh SFEO P Start pipe ram swap from 4 1/2" to 2 7/8" 12/02/2007 00:00 04:00 4.00 COMPZ RPCOA SFEO P Complete BOP pipe ram swap from 4 1/2"to 2 7/8" 04:00 06:00 2.00 COMPZ RPCO SFEO P Prep for pipe ram test. Make up test 'oint. 06:00 08:00 2.00 COMPZ RIGMN SVRG P Perform unit maintenance. 08:00 10:00 2.00 COMPZ WELC BOPE P Make up 2-7/8" tubing, Space out and start pressure testing BOP's and valves for weekly BOP test. Waived b Bob Noble. P-tested Both 2-7/8" Pipe rams 2500 si. 10:00 00:00 14.00 COMPZ WELC WOW P Stop testing due to high wind speeds. 35 to 50 MPH. 12/03/2007 00:00 01:00 1.00 COMPZ WELCT BOPE NP Stand by for high winds 35-45 MPH. 01:00 03:00 2.00 COMPZ WELC BOPE P Continue weekly BOP function test 250/2500 psi, tested OK. Test waived b AOGCC Bob Noble. 03:00 05:00 2.00 COMPZ WELC BOPE NP Wind picked back up to 40-50 MPH. Stand b . 05:00 06:00 1.00 COMPZ WELCT BOPE P Wind down to 30 MPH. Resume week) BOP test. 06:00 09:00 3.00 COMPZ WELCT BOPE P Completed Weekly BOP test consisted of 2-7/8" rams(2), Blinds,Annular, WC Valves, HCR, TIW 2 , IBOP all tested 250/2500. 09:00 12:00 3.00 COMPZ RPCO DHEQ P Change slips to adjust to 4.5", rig up tubin stand and X-overs for SL 12:00 14:00 2.00 COMPZ RPCO SLKL P Start rigging up SL for first run, 14:00 15:00 1.00 COMPZ RPCO SLKL P RIH w14"SB PT to 3952'KB, unable to make hole, POOH. Page 5 Qf 't 3 • 1 ~ Time Logs Date From To _ Dur S. De th E. De th Phase Code Subcode T COM 12/03/2007 15:00 16:00 1.00 COMPZ RPCO SLKL P RIH w/ 3" SB to 3952'KB, set down, beat down fell thru to 3982'KB, una_ blew ron ,POOH. 16:00 17:00 1.00 COMPZ RPCOA SLKL P RIH w/ 2.5" P bailer to 3952'KB, set down, work bailer, POOH w/ bailer, bailer had O-rin chucks and other debris two cu sin bailer. 17:00 18:00 1.00 COMPZ RPCO SLKL P RIH w/ 4" SB set down @ 3952'KB, work to 3962'KB, POOH. 18:00 19:00 1.00 COMPZ RPCO SLKL P RIH w/ 4.5" wire brush to 3952'KB work thru restriction to 3982'KB, POOH. 19:00 23:00 4.00 COMPZ RPCO SLKL P Make five more bailer runs with 2.5" P bailer to 3982'KB. More of the same in bailer, chucks of rubber seals, some sand. Last bailer run had nothing but liquid in bailer with metal marks on bailer btm. 23:00 00:00 1.00 COMPZ RPCO SLKL P RIH w/ 4" SB to 3982'KB, latch & pull, PX pron ,POOH w/ ron . 12/04!2007 00:00 01:00 1.00 COMPZ RPCOh SLKL P POOH w/ PX equalizing prong. 01:00 06:00 5.00 COMPZ RPCO SLKL P RIH w/ 4.5" GS to 3982'KB latch PX lu bod ,Jar on plug body one hour up to 1600# oil jar licks, no movement. Attempt to pressure upon tubing to 300 psi, lubricator o-ring leak, bleed off lubricator. Continue jarring up and down for next three hours, finally GS pt sheared, POOH. 06:00 08:00 2.00 COMPZ RPCO SLKL P SL BHA cannot POOH to surface, froze in the 4.5'° riser pipe above the Blinds. Stop operation and discuss Ian forward. 08:00 13:00 5.00 COMPZ RPCOti FRZP P Tarp in lubricator at surface and pump Glycol through entire fluid system at surface. 13:00 17:00 4.00 COMPZ RPCO WOEL P Lubricator still frozen, close blinds, cut slick line cable and lay down frozen iron with BHA. 17:00 21:00 4.00 COMPZ RPCOh SLKL P Rig-up Pollard S/L after unthawing lubricator and 4.5" tubin . 21:00 22:00 1.00 COMPZ RPCO SLKL P RIH w/ 1.75" hydrostatic bailer to 3982'KB set down, jar down with bailer in PX plug, POOH w/ bailer. No solids in bailer. 22:00 23:00 1.00 COMPZ RPCOh SLKL P RIH w/ 4.5" GS to 3982'KB set down and latch plug, jar up 1 hour @ 1900#, no movement in plug, shear off, POOH. 23:00 00:00 1.00 COMPZ RPCO SLKL P Before RIH with 4.5" GS we pressure up on tubing to 600 psi, pressure fell off, able to pump at min. rate down tubing. RIH w/ 4.5" GS to 4288'KB, found fluid lev 750'MD, plug no longer in nipple @ 3982'KB, latch & ull PX plu bod ,POOH w/ lu . Page 6 of 13 ~J l Time Logs _ Date From To Dur S. De th _ E. De th Phase Code Subcode T COM 12/05/2007 00:00 01:00 1.00 COMPZ RPCOh SLKL P RIH w/ 3.75" G-ring to 4320'MD, unable to make hole, POOH. 01:00 02:00 1.00 COMPZ RPCOh SLKL P RIH w/ 3.55" G-rin to 4555'MD, to fill. POOH 02:00 05:00 3.00 COMPZ RPCOh SLKL P Lay down Pollard equipment. Move e ui ment for load out. 05:00 06:30 1.50 COMPZ RPCOA GRVL P Crew change, discuss plan forward with BOT tools. Move 2-7/8" pipe over to i e deck 06:30 11:30 5.00 COMPZ RPCOh GRVL P P/U, Measure and layout Baker BHA for ravel pack run. 11:30 12:30 1.00 COMPZ RPCO SFTY P Safety Meeting, discuss picking up of BHA in order and good communication. 12:30 18:00 5.50 COMPZ RPCO GRVL P Make u Baker ravel ack assembly as per Baker rep. Bull nose, 337' of Excluder 2000 screens, Blank pipe, Lower extension, 20-25 Seal Bore, GP Sleeve, Upper Extension, Baker SC-1 GP Packer, Setting Tool, Crossover, 2.875" PH-6 pup. Total length if BHA 410.42'. 18:00 00:00 6.00 0 4,300 COMPZ RPCOh TRIP P RIH w/ Baker sand control system on PH-6 work strip . 12/06/2007 00:00 03:00 3.00 4,300 4,532 COMPZ RPCOA TRIP P Continue in hole with BOT sand control system on PH-6 work string. All PH-6 drifted with 2.23" rabbit. Tag fill at 5' in on sin le number 135 4532'RKB. Get Up/Down weights 52k up 18k down. 03:00 06:00 3.00 4,532 COMPZ RPCO WOEO P Continue to prep work deck for incoming BJ pump equipment @ 6:00-7:00 AM. 06:00 07:00 1.00 COMPZ RPCOh WOOR P Packer/gravel screens at depth. Discussion taking place with town staff. 07:00 13:00 6.00 COMPZ RPCOh WOEO P Continue moving equipment on deck, getting ready to bring BJ pumping equipment on board. 13:00 18:00 5.00 COMPZ RPCO RURD P Offload BJ pump equipment from Champion. Stage equipment on work deck. Start initial ri -u . 18:00 19:00 1.00 COMPZ RPCO SFTY P CUBE PJSM. Set up surface lines to set Baker SC-1 acker. 19:00 20:00 1,00 COMPZ RPCO RURD P Finish offloading BJ equipment, send Champion for second load of BJ equipment. Rage 7 0# 13 Time Logs Date From To Dur S. De th E. De th Phase Code Subcode T COM 12/06/2007 20:00 00:00 4.00 COMPZ RPCO PACK P Hold PJSM to set packer. Pump 5 bbls to clear lines and tubing, drop 7/8" ball. Pressure test lines to 5000 psi. Set packer with 900 psi, hold for 5 mins, bleed off. Pressure up 1200 psi, hold 5 mins, bleed off. Anchor test packer to 54K up weight, good test. Pressure up to 1500 psi, hold 5 mins, bleed off. Rig-up lines to pump down annulus, It took 12.5 bbls to fill annulus, test annulus to 1000 psi for 15 mins, ood test, attempt to release from packer pulled 62K up weight, applied 2000 psi on annulus, crossover tool free with 34k up weight. Pulled crossover tool to reverse osition 10'. Attempted to blow ball seat 5000 psi 5 times. Decide to wait on BJ pump equipment to take pressure higher. Crossover tool left in squeeze/ circulate position. Baker SC-1 packer set de th 4135'RKB to of ravel ack screen de th 4195'RKB bottom of rav screen 4232'RKB. 12/07/2007 00:00 05:00 5.00 COMPZ RPCO RURD P After setting packer freeze protector blow down all surface lines. 05:00 10:00 5.00 COMPZ RPCO WOEO P Continue to prep work deck for last of BJ equipment do in 7:00-8:00 AM. 10:00 18:00 8.00 COMPZ RPCOA KURD P Offload remaining BJ surface equipment, release Champion. Spot and ri -up BJ pum a ui ment. 18:00 20:00 2.00 COMPZ RPCO RURD P Rig-up BJ stand pipe line. Shut down due to increasing wind speed. Lay down BJ crew. 20:00 00:00 4.00 COMPZ RPCO WOW NP Stand by for high winds 35-40 MPH. 12/08/2007 00:00 02:00 2.00 COMPZ RPCO WOW NP Stand by for high winds. 02:00 04:00 2.00 COMPZ RPCO RURD P Rig-up BJ stand pipe. Off load two BJ diesel tanks and. one pallet of MI Swaco chemicals. 04:00 07:00 3.00 COMPZ RPCO RURD P Complete BJ rig up, flow line and iron. 07:00 08:00 1.00 COMPZ RPCO SFTY P Safety Meeting discussing pressure test (7500 psi), and ball shearing pressures/rates. Injected 40bbls of Cata o 2 fluid i to is o al well. 08:00 10:00 2.00 COMPZ RPCO CIRC P Start taking on fluid, purge all surface lines, test surface lines to Rig floor, and check for circulation to pits. Pressure test treatin line 1500/7500 SI. Page 8 of 13 r ~ Time Logs Date _ From To Dur S, De th E. De th Phase Code Subcode T COM 12/08/2007 10:00 11:00 1.00 COMPZ RPCOh DHEQ P Open up backside to pits. Close Annular. Set tools in reverse position. Pressure tbg to 5200 osi, saw break back. Pumped an addtional 4.2 bbls to break circulation to surface and establish circ @ 1 bpm & 2600 psi. Higher than expected circ pressure. Shut down. 11:00 15:00 4.00 COMPZ RPCOCV OTHR P Start mixing KCL &FRW-14 to 500 bbl surface tank, prep surface tanks for re-flush ills. 15:00 18:00 3.00 COMPZ RPCOA GRVL P Load sand silo w/ 24M# Accupack 20/40 from super sacks. Begin mixing acid fickle pills. 18:00 22:00 4.00 COMPZ RPCOh DHEQ P PJSM. With tools in reverse position and annular closed, attempt to establish circ rate. Pressure tbg to 6000 psi 4 times w/ slow bleed off. Throw valves and establish reverse circ @ 1 BPM & 150 psi indicating ball seat not sheared vet. Throw valves and ramp tbg pressure up to 6000 psi three times. Third time saw sharp pressure drop indicating ball seat now fully sheared. Tbg pressure dropped to zero. Establish circ @ 3 BPM & 950 psi w/ full returns. Open annular, move tools to test position. Close annular. Establish circ @ 0.5 BPM & 800 psi w/full returns. Open annular, move tools to reverse position. Close annular & backside valves. PT packer, seals & 4.5" tbg to 1000 psi OK. Bleed off pressure and open backside valve for circ. Leak in tool strip above xover tool. Suspect the Baker setting tool. Will pull tools following acid pickle. Machine shop making xover to allow removal of settin tool from strip . 22:00 00:00 2.00 COMPZ RPCOti CIRC P ,, ?erform acid fickle on 2.875" work strip to 'ust above ravel ck as per rocedure. Pump 10 bbls of Flo-vis pill @ 2 BPM 250 psi, 16 bbls of 6% KCL water with Safe Solv @ 2 BPM 250 psi, 11 bbls of 10% HCL w/inhibitor and citric acid @ 2 BPM 280 psi and 9 bbls of filtered 6% KCL water to displace acid to 2 bbls from crossover tool. SD pumps 8~ close backside. Throw valves 8~ reverse out @ 2 BPM @ 400 psi w/ 50 bbls filtered 6% KCL water w/ 0.1 %FRW-14. Returns clean. Pump returns to A-12 infection well. Page 9 of 13 • Time Logs Date From To Dur S. De th E. De th Phase Code Subcode T COM 12/09/2007 00:00 02:00 2.00 COMPZ RPCOCL RURD P Continue pumping class 2 returns from CUDD pits and trip tank to A-12 injection well. Break out and secure BJ standpipe assembly. Lay down 5' u 'oint. 02:00 06:00 4.00 COMPZ RPCOh TRIP T OOH standin ac 06:00 12:00 6.00 COMPZ RPCO RURD T LD Baker setting &xover tools. Baker had wrong xover made to remove setting tool from string. Fill setting tools w/ water and found leak in settin sleeves. Correct xover arrived. 12:00 18:00 6.00 COMPZ RPCOh TRIP T RIH w/ 1.66" washpipe & GP xover tool on workstring. BJ rolled 500 bbl tank of treatin fluid. 18:00 18:30 0.50 COMPZ RPCO SFTY P Held PJSM. Gravel pack plan forward. 18:30 20:30 2.00 COMPZ RPCOh GRVL P Confirm tool position, fill hole, close annular, close kill line, open choke line. Start getting returns @ 20 bbls away, started getting 1:1 returns @ 42 bbls away. Perform step rate test @ 2,4,6,8,10,and 12 BPM._Well screamin vacuum. Move tool in circulate/squeeze position, top off 500 barrel tank. Mix another 100 bbls of KCL water. 20:30 21:00 0.50 COMPZ RPCO SFTY P Held gravel pack PJSM. 21:00 00:00 3.00 COMPZ RPCOti GRVL P Start pumping down 2.875" work string @ 10 BPM till stable, crack open choke line. Tubing pressure up to 850psi. Decrease pump rate to 5 BPM @ 710 psi, pump 1/2 PPA 20/40 Accupack, Got approximately 25 bbls away or sand to packer, tubing pressure climbed to 2850 psi. Pressure backside to 1000 psi. Pull up to reverse position w/ 35M# overpull. Reversed tbg clean @ 5 _ BPM. Pulled up to dump seals. SD to discuss & troubleshoot roblems. Page 10 of 13 • r Time Logs Date From To Dur S. De th _ E. De th Phase Code Subcode T COM 12/10/2007 00:00 03:00 3.00 COMPZ RPCO GRVL P With seals dum ed unable to um into well @ 3000 psi down kill line (???). Stung seals back in and move down to circ position. Close annular. With choke line open, load tbg & ramp up to 8 BPM @ 625 psi. Drop rate to 6 BPM & 40 psi. Bump rate to 10 BPM & 1150 psi. No circ to surface whatsoever. Restock frac tank w/ fluid. Set returns choke to 1/4. Ramp up to 7 BPM & 430 psi. After 50 bbls away, begin 1/2 PPA 20/40 Accupack sand @ same rate. At sand on port, 7 BPM & 375 psi. Treating pressure increasing gradually. Got 0.3 BPM retums @ 900 psi TP, 5 psi annulus presure. Treating pressure increased slope and lost returns. At 1180 psi, pressure dropped and then rose sharply to 3500 psi for screenout SD. Closed choke. Throw valves and pressure backside to 1500 psi. Strip up to reverse position w/ 40M# overpull. Reverse tbg clean w/ 60 bbls @ 4 BPM. SD pumps & open annular. Pull up to dump"seals and then run back down to circ position. Broke off treating lines in work basket. Pumped total of 7065 Ibs sand with 6400 Ibs of sand thru gravel pack port. Pumped a total of 800 bbls of 2 micron filtered, 6% KCL, 0.1 % FRW-14 fluid toda . 03:00 08:00 5.00 COMPZ RPCOh TRIP P Pull six stands and rack back to free wash pipe from packer assembly. Lay down and rig down BJ equipment. Offload Champion before pulling out of hole PH-6 work string. Swap CUDD ower ack. 08:00 12:00 4.00 COMPZ RPCOh TRIP P Begin POOH with 2-7/8" work string. 12:00 14:00 2.00 COMPZ RPCOh PULD P Baker BHA layed on deck. Tools looked good, gravel pack port sand washed & 7/8" ball severely eroided. Appears ball was partially blocking lower third of gravel pack port. Erosion due to sand impingement in flow path. Did not effect 'ob. 14:00 18:00 4.00 COMPZ RPCO PULD P Empty 200 bbls of 6% KCL water from 500 barrel blue tank to Tyonek pits 2&3. Total of 300 bbls remain in pits 2&3. Ensure all service lines are blown down with air. Offload Baker equipment onto Champion. Prep work area for NDBOP. 18:00 19:00 1.00 COMPZ RPCOR SFTY P Daily operation meeting. CUDD PJSM/JSA. Page'! 1 of 13 • Time Logs Date From To _ __ Dur S. De th E. Ae th Phase Code Subcode T COM 12/10/2007 19:00 20:00 1.00 COMPZ RPCO SFEQ P Install FMC BPV. , 20:00 23:00 3.00 COMPZ RPCOh NUND P NDBOP 23:00 00:00 1.00 COMPZ RPCO NUND P Lay down risers below BOPS. 12/11/2007 00:00 15:00 15.00 COMPZ RPCOh NUND P NUWH and test to 3000 psi, connect all control lines and test. 15:00 17:00 2.00 COMPZ RPCO NUND P Back load and make space for SL e ui ment. 17:00 20:00 3.00 COMPZ RPCOh NUND P RU Slickline unit 20:00 21:00 1.00 COMPZ RPCO SLKL P RIH w/ 2" DD bailer to 4547' RKB, POOH w/ sam le of frac sand. 21:00 22:00 1.00 COMPZ RPCOh SLKL P RIH w/ 4" AD-2 stop down to 2407 RKB, sat down tool would not fall further. POOH before shearin tool. 22:00 23:30 1.50 COMPZ RPCO SLKL P RIH w/ 3.74" gauge ring to 4000' RKB to ensure tubing is clear. Started PUH, tool hung up at 3860' wlm had to tap lightly to work free. Continue to POOH. 23:30 00:00 0.50 COMPZ RPCOh SLKL P Perform crew change 12/12/2007 00:00 01:00 1.00 COMPZ RPCOA SLKL P RIH with 4" AD-2 catcher sub. Sat down @ 2430' RKB, unable to make an further. POOH. 01:00 02:00 1.00 COMPZ RPCOA SLKL P RIH w/ 4" GS to drift tubing down to 3960' RKB with no problems. POOH 02:00 04:30 2.50 COMPZ RPCO SLKL P RIH w/ 4.5" x-lock catcher sub down to 3984' RKB. POOH, P/U GLV pulling tools. 04:30 06:00 1.50 COMPZ RPCO SLKL P Located top, middle and bottom pockets. Could not latch bottom GLV (3844 RKB) ,multiple tries, PU to 3012' RKB located second valve POOH to inspect tool. Retrieved a dummy valve, spoke with operator he felt may be top one due to the weight he first tagged down on. Tool may have kicked out when lowering lubricator at surface. 06:00 06:18 0.30 COMPZ RPCOh SLKL P Pre tower safety meeting/crew change. Tool in lubricator waiting to bleed down to production. (40 psi on well). Slight gas pressure on Annulus, no pressure. 06:18 11:18 5.00 COMPZ RPCOh RIH latch number 3 GLV (3844' RKB) POOH. RIH for final GLV. Page 12 of 13 Time Logs Date .From To bur S. De th E. De th Phase Cade Subcode T COM 12/12/2007 11:18 23:00 11.70 COMPZ RPCOh Pulled catcher sub after setting 3 GLV. Ran SSSV, would not hold pressure. Changed out packing and rerun, still wont hold. Ran in selective configuration and it held pressure. After attempting to shear, lost pressure, came out with SSSV still attached. Changed out to new X-line and fiber ring in packing. Did not hold pressure. Ran with o-rings and reconfigured packing and in selective and set successful) . 23:00 00:00 1.00 COMPZ RPCOh Rig back Pollard. Well left SI NCI A-3 BOP test Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, November 27, 2007 9:02 AM To: 'Ennis, J J' • Cc: Tyonek Company Man,; 'aogcc_prudhoe_bay@admin.state.ak.us' Subject: RE: NCI A-3 (168-099) BOP test Page 1 of 2 Jim, Thanks for the information. Further to our call, FMC has indicated that it is possible to hang the tubing off on the test plug. While you are correct that the downhole environment out there is not harsh, repeated cycling of the production casing should be avoid if possible. The test conducted so far has proven the integrity of the upper pipe rams and the connections below them. This should allow the hanger to be pulled and replaced with the test plug. Good luck with the operations. Call or message with any questions. Also, please include the permit to drill number on any messages regarding wells. This helps referencing the files and filing any documents. Tom Maunder, PE AOGCC From: Ennis, J J [mailto:J.J.Ennis@conocophillips.com] Sent: Tuesday, November 27, 2007 8:56 AM To: Maunder, Thomas E (DOA) Cc: Tyonek Company Man, Subject: FW: NCI A-3 BOP test Tom, ~~ FEB ~ ~ 2D0~ The 0230 IA & BOP body test was indeed against the upper pipes. ~... Jim Ennis % j, ennis@conocophillips. com (907)265-1544 (lM (907)632-7281 (C) From: Tyonek Company Man, Sent: Tuesday, November 27, 2007 8:44 AM To: Ennis, J J Subject: FW: NCI A-3 BOP test From: Tyonek Company Man, Sent: Tuesday, November 27, 2007 8:30 AM To: 'Maunder, Thomas E (DOA)' Subject: RE: NCI A-3 BOP test 11 /27/2007 NCI A-3 BOP test ~ Page 2 of 2 Tom, The packer is at 3908', 4 1/2" production tubing in 7" casing. IA volume is 72.7 Bbls. The IA has been tested to 2500 PSI at 02:30 today. Thank you, Kai Starck Jared Brake From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, November 27, 2007 7:42 AM To: Tyonek Company Man, Subject: RE: NCI A-3 BOP test Jared, I just got your messages. Where is the "bottom" of the IA? What volume will be energized? When was the last time the IA was pressure tested and to what value? Tom Maunder, PE AOGCC From: Tyonek Company Man, [mailto:TyonekCompanyMan@conocophillips.com] Sent: Tuesday, November 27, 2007 12:31 AM To: Maunder, Thomas E (DOA) Subject: NCI A-3 BOP test Tom, We have encountered a unique situation on the Tyonek platform in regards to our workover on well NCI A- 3, API# 50-883-20020-00, PTD# 168-099. The problem we have is that our tubing hanger seals have failed giving the BOP stack direct communication with the Inner Annulus. There is currently a BPV and a blanking plug isolating the tubing, but in order for us to pressure up on the BOP stack to get a tes#, we have to also pressure up the Inner Annulus. We are still able to obtain the desired pressure of 2500 psi, and test the BOP's as normal The only change is the volume below the BOP stack that needs to be energized for the test. We have consulted with both Bob Noble and. Jeff Jones on the matter, and they have referred us to you for a decision whether we can proceed with the State witnessed BOP test.. Please advise us on any further requirements you may have so that we may proceed with our test. Sincerely, Jared M. Brake CPAI DrillingNVells supervisor Tyonek Alaska (907) 776-2081 11127/2007 SARAH PAUN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Jim Ennis Wells Group Engineer ConocoPhillips Alaska, Inc PO Box 100360 ~~:,~;g~~ NOV D $ 2007 Anchorage, AK 99510 Re: North Cook Inlet Field, Tertiary Gas Pool, NCI A 03~.., ~, f - ~ 1 Sundry Number: 307-314 + . ° . -~ _ ~ '~ ~ / ® ! Dear Mr. Ennis: 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 pro~~ded 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 atTected by it may file with the Commission an application for rehea~ng. 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 thiscil7 day of October, 2007 Encl. Sincerely, • ConocoPhillips October 10, 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-03 Dear Commissioner: Jim Ennis Wells Group Engineer Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1544 jug, ConocoPhillips Alaska, lnc. submits the attached Application for Sundry Approva{ for the upcoming workover on the Tyonek Platform well NCI A-03. This application is to change the approved program as outlined in sundry 306-229. If you have any questions regarding this matter, please contact me at 265-1544. Si er , ~.w .~, J. En is Wells Group Engineer CPAI Drilling and Wells JE/skad STATE OF ALASKA ~ ~ ~ 10I S 1'~ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 t,( _ ~,~t C.I!l( 1. Type of Request: Abandon ^ Suspend ^ Operational Shutdown ^ Perforate ^ Waiver ^ Other ^ Alter casing ^ Repair well ^ Plug Pertorations ^ Stimulate ^ Time Extension ^ Change approved program Q _ _ Pull Tubing ^ Perforate New Poo{ ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development Q Exploratory ^ 168-099 3. Address: Stratigraphic ^ Service ^ 6. API Number: P. O. Box 100360, Anchora e, Alaska 99510 50-883-20020-00 ` 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? YeS NO 0 NCI A-03 ` 9. Property Designation: ADL 18755 10. KB Elevation (ft): RKB 116' 11. Field/Pool(s): i-~rha,.• ~y,, Q~s North Cook Inlet Field / Bel ool ~o.l?.09 12. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): 7480' 6392' 6380' 5105' Casing Length Size MD TVD Burst Collapse Structural 384' 30" 384' 384' Conductor 612" 16" 612' 612' Surface 2519' 10.75" 2519' 2320' Production 7475' 7" 7475' 6385' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3930'-4995', 5254'-7237' 4.5" J-55 6290' Packers and SSSV Type: Packers and SSSV MD (ft) packers @ 3908', 4199', 4526', 4595', 4669', 4751', 4832', 4886', 4936', 5114' Halliburton 'XXO' SVLN @ 291' 13. Attachments: Description Summary of Proposal ~ 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch Q Exploratory ^ Development Q Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operat November 5, 2007 Oil ^ Gas 0° Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Jim Ennis @ 265-1544 Printed Name f1nIS- Title: Wells Group Engine r Signature Phone 265-1544 Date , ~ ~~ U Commission Use Onl Conditions of approval. Notify Commission so that a representative may witness Sundry Nu per: ~' 3' Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ ~(~ 'k'~s~' Other: ~ r3~ S~ 1Zs ~"S O~ C''C~r+~S ~F'e GC~ ~ S~ C` Sl2S~ `a~~J,~~~C ~1"V~~~~ p1 . Q . ~ c c ~ Subsequent Form Required: ~©y S ~~~~..OV~~ c~Up~C~~S 30~- a ~-5 APPROVED BY ~ Approved by: .... MMISSIONER vriJ (J~ ~~~~ THE COMMISSION Date: Form 10-403 Revised 06/2006 (1~~~~, ~ (~~ R t ~ ~ 1~;~~ Q~~ ~ ~DQ7 Submit in Duplj~ %o-/?-O~ • NCIU A #3 TTGP CI 1-4 Sands Workover Procedure Pre-ri L MIRU Pollard slickline. Pull HES `FXE' SSSV. Tag fill w/ 3"bailer. RD slickline. 2. PT IA 1500 psi. ``~~ 3. Set BPV. n-s c~Zsc~sSc~J~ ~ sc~~S O~- ~`1''~S c~ hoc ~`Ia`roc-~`~l~'`5~.~~c~h~.~w•p\ay~c1.~~ 1. MIRU Cudd hydraulic unit. NDWH. NU 7" BOP stack (see attached diagram) w/ 4.5" & 2.875" pipe rams. Notify AOGCC 24 hours prior to BOP testing. PT BOP's 250/2500 psi. MASP is (1000 psi)-(3573' TVD)(0.01 psi/ft)= 964 psi assuming CI A-B Sands have experienced little or no depletion since 1994 workover. Remove BPV. 2. Unland & POOH w/ 4-1/2" production tbg and PBR seal stem. 3. Single in w/ PBR seal stem, 3.813" `X' nipple, 4-1/2" production tbg, 3 KBG-2 GLM's & 3.813" SSSV landing nipple (400' MD). Land tbg. PT IA to 1500 psi. ry (~1 ~~« wai~~S~rir 4. RIH w/ Baker TTGP BHA and set `SC' pkr @ ~415~ RKB. Pump 20/40 gravel pack & circ clean. POOH laying down workstring & GP tools/washpipe. NDBOP & NUWH. Set BPV. 5. RDMO Cudd. Pull BPV. Post-Rig 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 1019/2007 • • NCIU Well A-3 Completion Diagram API#508632002000 FMC OCT RKB-Drill Deck: FMC 4112" Brd X 4" BT&C RKB-THF: 61 364 18" ~ 612' 10314"2519' TOC ~ 3700' CBL 55 ~:I: Halliburton VSR packer ~ 3908' Cook Inlet Sands 53 °x•• 3930 - 3931 sqz 3964 - 3979 CI-A 4000 - 4025 CI-B 4055 - 4070 CI-B 4100 - 01 sqz 4178 - 79 sqz 50 ~:~: Halliburton TWR packer LID 4199' 4210 - 4280 CI-1.0 4300 - 4375 CI-2.0 4428 - 4440 CI-3.1 4474-4494 CI4.0 a~ '•xD•' ~ XD leaks 8 X profile bad (Jun '06) closed a4 Halliburton TWR packer ~ 4526' "XD" ~i~i TAG'd FILL @ 4579' RKB (10/3/07) a1 'PX' plu ~~~ 4552 - 4582 c1-5.o Closed as Halliburton TWR packer ~ 4595' 4630 - 4640 cla.o as "x D" Tbg leak @ 4658' (sleeve leak7J Closed a4 Halliburton TWR packer ~ 4669' Tbg leak @ 4700' J1 •'xo•' 4692 - 4897 CI-7.0 nosed 4730 - 4737 CI-7.1 ze `I' Halliburton TWR packer ~ 4751' 4778 - 4788 CI-8.0 z6 •'xD'• 4793 - 94 sqz perts closed 4810-4820 CI-8.2 z4 ~:i~: Halliburton TWR packer ~ 4832' 4850 - 4875 CI-9.0 zo Halliburton TWR packer ~ 4886' 4900 - 4925 CI-10.0 n •xD° closed 15 '' Halliburton TWR packer ~ 4936' Tbg leak @ 4940' ~ 4sst 4950 - 4995 CI-110 12 XD" 10 EZSV BP :~ b105' KB 8 ~: Halliburton TWR packer ~ 5114' Beluga Sands 5254 - 5261 b-6 5279 - 5284 b-7 5418 -5423 c-3 5565-5570 d-3 5579-5584 d-3 5596-5603 d-4 b .~.. closed 5834 - 5844 f-1.1 &f-2 5670 - 5880 f-4 5961 - 5971 g-1 6043 - 6058 g-5 T 6070 - 6080 h-1 6227 - 6252 h-9 1 •'xN'• 6284 - 6289 i-3 2 I: EZSV @ 6380 6414 - 6421 j-2 6514 - 6529 k-0.1 T 6898-6908 n-5 7033-7040 0-4 F I', ro 639n' 7212 - 7237 q-3&q-4 /.. @ rns 1 i) = 7,480' 61 290.55 2.45 Halliburton "XXO" SVLN (SSSV pulled 6l2I06) 3.813 4.920 60 293 UO 31 .4 4 12' 17 0 Ib J-55 L?TC Tubin 3992 4 500 59 324 r4 0 8 X-Over FU box x BTC Bax 3.992 4 500 58 325 54 35i2. GI 4 112" 12.61b J-55 EUE Tubing 3.992 4.500 5'2 3N4,-.i1 2506. 41!Z' 12 [i lb .:-22 EUE Tuhln 3.992 4.b0U 51 41'-F ICa 2 62 No ;.; Seal ssembf 3.990 5.560 50 4199.30 10.68 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 45 4.09 J8 0 6 Tub~n[ ,Ada for 3.990 5 500 48 42"0 S6 ~9i] 50 4 1; 2" 12-Fi Ib J-55 BJE-MOD Tubin 8 Pup Jts. 3.992 4 500 47 4501.18 4.22 Halliburton "XD" Slidin Sleeve Closed 06103/06 3.813 5.560 46 450540 Pu~,-.~'s 3.992 4.500 45 4 ~5 81 ;~mbly 3.990 5 560 44 4526.93 10.66 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 43 453,- Sg 3.990 ',.560 42 4~ <F 15 I ~ ~ b5 E' -NGD T.I blrg S Puo Jts 3.992 4 SOG 41 4585.92 8 3 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1/31/02) 3.813 5.560 40 4594 22 IJa Oc a~~nl Assembly 3.990 5.560 39 4595.34 10.65 Halliburton "TWR" Packer &Millout Extension 4.000 5.870 3F 4sos 99 l ..i~,no ~,d~-l~r 3.990 S.seu 3- 4606 59 C I ~' I ' Ir) ,i-Sc f. _ s1OD Tubing ~ Pup Jls 3.552 aI 500 34 4669.66 I 29 ~ 4751.07 ~ 10.64~Halliburton "TWR" Packer 8 Millout Extension ~ 4.000 ~ 5.870 I 10 18 4897 70 i I t" 4 ~ 2" 7L ~3 Ib J-55 EUF-MOD Tubing 3.992 4 500 17 4929.08 6.28 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1130/02 3.813 5.560 16 4935 36 N:: ? eai Fssembl 3.990 5 560 15 4936.48 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 14 4947.12 o G I uUm9 svlaplur 3990 = 5G0 4 l_~o :>r> ~ ~ ; ~ -1 1~,"' r_ r, ln.~-ss ~In IVioD rr~t,ll,n 3.~9z asou 3 6287.57 ~ 1.5 Halliburton "XN" Landin Ni le 3.725 5.560 2 6289-07 0.6 Re-Entry Guide 1 b2s~ a; LI.Q -~r Ilioing Well Histo March 1969 -Original Completion - CI A, B, 4.0,5.0,6.0,8.0,8.2,9.0,10.0,11.0, and Beluga b-6 thru q-4 Commingled July 1975 - CI 1.0, 2.0,7.0,&7.1 Pertorated. September 1994 Workover -Well completed in Beluga b-6 thru i-3 Reperforate Beluga b-6 thru i-3 5254'-6289' 12 SPF Beluga j-2 thru q-4 abandoned without testing Reperforate CI 1.0 thru 11.0 from 4210'-4995' 12 SPF Also added CI 3.1 pertorations October 1999 -Top of Fill 6342' June 4, 2001 Tag fill @5625' Dec. 2001 Set F1SV BP @ 5105' RKB. Open XD Sleeves @ 5046' 8 4929' RKB, Jan 30, 2002 Tag fill @ 5005' WLM, Closed sleeve @ 4878' WLM Jan 31, 2002 Confirmed all sleeves above 5005' SLM closed, tested well @ 12MM , approx 300 BWPD, Ran SSSV March 2002 -Tag fill @ 4991' RKB, ran PDS caliper and production log, 3 tbg leaks identified, set'PX' plug @ 4586' RKB. May 14, 2002 -Tag fill @ 4530' WLM. Obtain BHP survey. May 15, 2003 -Tag fill @ 4560' RKB (4534' WLM). Obtain BHP survey. May 13, 2004 -Tag fill @ 4566' RKB. Obtain BHP survey. May 14, 2005 -Tag fill @ 4500' RKB. Obtain BHP survey. Jun 2006 -Bail fill to 4581' KB. Close XD @4501' KB, leaks. Can't locate X profile in same. Set WRP at 4481' KB, PT tbg OK. Sep 2006 -Tag fill @ 4579' RKB. Obtain BHP survey. Oct 2007 -Tag fill ~ 4579' RKB w/ 1.75" bailer. Undated :1 01912 0 0 7 Bv: Jim Ennis A-03 • • .- ConocoPhillips NCIU Well A-3 Proposed TTGP Diagram API#508832002000 Gas Producer FMC OCT RKB-Drill Deck: Single Comp. FMC 4 112" Brd X 4 "BTBC RKB-THF: ~ 39.94 st SSSV Annulus Fluid: Salt Water with 3 bbl Methanol RKB-SL : 115.9 ~: 304 TOC: 3700' from CBL dated 03114169 WATER DEPTH: 120' RKB-ML OD ToP'' 94tt6ip !i;.. yYi. !::. ;::Graq@...::: Cbrin ::::...::;gyFst CWI TehBr> ::: CASING & TUBING 16" ~ 612' 30 " 41 384 16" 41 612 65# H-40 1540 600 293 10 314 " 41 Z 519 45.5# 8 51# J-55 BTBC 3350 1970 531 7" 39 79 26# J-55 BTBC 4660 4080 327 7" 79 5,818 23# J-55 BTBC 4080 3080 288 ' 4.5" prod tbg w/ 3 GLM's 7 " 8,818 7,475 26# J-55 BTBC 4660 4080 327 a 1!2" 39 325 12.6# J-55 mod 6T8C 4730 4980 134 A 112" 325 :1,289 12.0# J-55 mod Brd 4730 4980 134 ::~:Nn;:~:~: ~:~:~:~:To :~ ~:~:~Leri ~ ~ :~: ~Desci llba:~ : ::::::::::::::::~:::~: ~:~:~:::~:::::~:~:~~ ~:~:~:~:ID:~:~:~: :~:~:~:~:OD~:~:~:~:~ PRODUCTION TUBING STRING & IEWELRY 10 314" @ 2519' Note: 8.98 ft difference in elevation is due to assembly being set on Electric Log Depths TOC @ 3700' CBL 3.558 F :;oo ss i'i Halliburton VSR packer @ 3908' ? 958 6 :)00 3-592 4500 Cook Inlet Sands 3.813 4.920 53 ^x^ 3930 - 3931 sqz 3.592 4500 3964 - 3979 CI-A 3.992 4.500 a000 - 4025 CI-B 3 992 a 500 4055 - 4070 CI-B 3 992 5 IIGG ?? 'SC-r pkr -4150' :i 4100 - 01 sqz 3 992 5 56Z 4178 - 79 sqz 55 3908.01 6.46 Halliburton "VSR" Packer 4.000 6.000 54 ~ 1 •~~- 31 38 ~ 12 ~ Ib.;-22 EUE Tul:nr 3.992 4 500 53 3945.87 1.44 Halliburton "X" Ni le 3.813 5.562 ~`i Halliburton TWR packer @ 4199' '~~~ 1 ;, I 250 6,' a ~ 12 S Ib ~-T2 EUE 1'ubmg 3-992 4 500 Tpg perfd4205'-0520' S1 411878 flu Seal nss:: rnhly 3.990 550 1 4210 - 4280 CI-1.0 50 4199.30 10.68 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 zo/ao I I 4300-4375 CI-2.0 a9 420998 06 n~b~nq ~~,daptcr 3-990 5.560 gravel ~ ~ :~:~ 4428 - 4440 CI-3.1 48 421 J 58 290 60 a vZ' 12 a Ib J-55 LGL-N,OD Tubing 3 Rip Jts 3 992 4 5G0 pack I I ~ 4474-4494 CI-4.0 47 4501.18 4.22 Halliburton"XD"Slidin Sleeve Closed 06/03/06) 3.813 5.560 46 4505 40 20.41 .~7 11Z' Pup Jts. 3 992 4 500 a7 I I ?! XD leaks 8 X profile bad (Jun 'O6) 45 4525 81 2 62 No So Seal Assembly 3-090 `, SBb `~ ~.~.2.875" Excluder screens 44 4526.93 10.66 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 43 4537 59 0.6 Tubvr~ Ada for 3.990 ~ SGO as ii' Halliburton TWR packer @ 4526' 42 4538 19 42 3 a v2" 12.6 Ib J-5S FUF-MOD Tubing & Pup Jts 3.992 4.500 "xo° i?>. TA G'd FILL @ 4579' RKB (10/3/07) 41 4585.92 8.3 Halliburton "XD" Slidin Sleeve 8 Pup Jt. Closed 1131102 3.813 5.560 41 'PX'pl ~~~: 4552 - 4582 cl-5.o 40 45da 22 2 (i2 No G<: Seal Assembly 3.990 5-560 closed 39 4595.34 10.65 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 38 4G.;'~99 O.fi lubnw 4Ja ~tor 3.990 5.560 3a i~ Halliburton TWR packer @ 4595' 37 4 > ,' as: 51 c0 ~ I ~) lu J-55 EUE nOD T ubing ~ Pup Jrs. 3-992 4-500 36 4658.19 10.35 Halfibu-ton "XD" Slidin Sleeve 8 Pu Jt. Closed 1131102 3.813 5.560 4630-4640 a~.o 35 Af1~ 64 ~ I,. ,;ssembl 3.990 5-560 3e ••x0•• Tbg leak @ 4658' (sleeve /eak7) 34 4669.66 10`64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 closed 33 .D 116 I~ihuw ~;cia for 3.990 560 32 ~ 5_ 4 ':;"' I "' d to J-56 E E bbjU TAIL in~ 3.992 4 :;CO 31 4-%s; GI! 6.26 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1131/02 3.813 5.560 30 aa: ssembl 3.990 560 as Halliburton TWR packer @ 4669' 29 4751.07 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 Tbg leak @ 4700' ~1; ~ 1 ~.;. ~ny Adaptor 3.990 5 560 at •'xD" 4692-4697 CI-7.0 Z7 h 62 b~ I'- I i5 E., -h<<~D Tibino 3.902 4 500 closed 4730-4737 CI-7.1 26 4825.13 6.28 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1131102 3.813 5.560 4831 a I 2 6~ PJ~ ~ Ga Seal Nssembly 3.990 5 560 ze :i:i Halliburton TWR packer ~ 4751' 24 4832.53 10.72 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 23 4Aa3 25 0 6 Tubm ~ AUa ~lor 3.990 5-560 4778-4788 CI-8.0 48a355 41.43 41/2" 1261b ~-55 EUE-iv10D Tubin 3.992 4.500 26 "x D" ~~ 4793 - 94 sqz parts 21 4S?5 28 2.62 No Go Seal Assembl 3 590 5 560 closea 4810-4820 CI-8.2 20 4886.40 10.7 Halliburton "TWR" Packer8 Millout Extension 4.000 5.870 '19 4F13 ~- 10 0 6 1 admu :adaptor 3 900 S 567 zs ~ Halliburton TWR packer @ 4832' 18 4P „ S 3I 38 .I ' , u, J-55 EUE-MOD Tubinu 3.992 <I 500 17 4929.08 6.28 Halliburton "XD" Slidin Sleeve 8 Pu Jt. Closed 1130102 3.813 5.560 4850-4875 CI-9.0 16 1?',r s3 ~,~I ASSembl 3.090 5560 15 4936.48 1064 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 zo 3> Halliburton TWR packer @ 4886' 14 404 ~ 12 0 !i I ubui Ada for 3.990 5.560 13 494F 72 98 27 4 1.2" 12 61b J ~5 EUE-MOD Tubin 3.592 4 SOG 4900-4925 CI-10.0 12 5045.99 4.22 Halliburton"XD"Slidin Sleeve CLOSED 3.813 5.560 n "x D" 11 ."~06u 71 Ge !~~ :' 6 Ib J-55 EUE-MOD Tubin 3.992 4 SUU closed 10 5105.00 4 112" EZSV Brid a Plu 4.500 9 `~1 I' 98 hL: ~nel Flssenibl 3.980 5 560 is :: Halliburton TWR packer @ 4936' 8 5114.00 10.64 Halliburton "TWR" Packer 8 Millout Extension 4.000 5.870 7 5124 64 0.6 Tubin A,da for 3.990 5 560 Tbg leak @ 4940' 6 5125 Z4 501 1 4 V7" 12 6 Ib ~-55 EUE-MOD Tubn'.4 3.992 4 500 :~:~ fill ~ 4991 4950 - 4995 CI-11.0 5 5626.34 4.22 Halliburton "XA" Slidin Sleeve 3.813 5.560 tz °x0° ~ 4 .L?U 60 657 01 4 Lam' i' 6 Ib J-55 CUE-MOD Tub~r~ 3.9)2 4.500 to ezsv ea :~stos•ICe 3 6287.57 1.5 Halliburton"XN"Landin Ni le 3.725 5.560 8 i': Halliburton TWR packer @ 5114' 2 6289.07 D.6 Re-Ent Guide Beluga Sands ~~'~ ~ ~,. L~r, or Tnbr,g ~~ ~~ 5254 - 5261 b-6 :. .. ~. ~ . 5z7s - 5zea a7 Well Histo ••xn•• closed •xrl•• ~ z -n eseo' _ 5418 -5423 c-3 5565 - 5570 d-3 5579 - 5584 d-3 5596 -5603 d-4 5834 - 5844 f-1.18f-2 5870 - 5880 f-4 5961 - 5971 g-1 6043-6058 g-5 6070 - 6080 h-1 ~.'~~:'~, 6227 - 6252 h-9 6284 - 6289 i-3 EZSV @ 6380 6414 - 6421 j-2 6514 - 6529 k-4.1 6898 - 8908 n-5 7033-7040 0-4 _ 7212-7237 q-38q-4 March 1969 -Original Completion - CI A, B, 4.0,5.0,6.0,8.0,8.2,9.0,10.0,11.0, and Beluga b-6 thru q-4 Commingled July 1975 - CI 1.0, 2 0,7.0,87.1 Perforated. September 1994 Workover -Well completed in Beluga b-8 thru i-3 Reperforate Beluga b-6 thru i-3 5254'289' 12 SPF Beluga j-2 thru q-4 abandoned without testing Reperforate CI 1.0 thru 11.0 from 4210'-4995' 12 SPF Also added CI 3.1 pertorations October 1999 -Top of Fill 6342' - June 4, 2001 Tag fill @ 5625' Dec. 2001 Set EZSV BP @ 5105' RKB. Open XD Sleeves @ 5046' 8 4929' RKB. Jan 30, 2002 Tag fill @ 5005' WLM, Closed sleeve @ 4878' WLM Jan 31, 2002 Confirmed all sleeves above 5005' SLM closed, tested well @ 12MM , approx 300 BWPD, Ran SSSV March 2002 -Tag fill @ 4991' RKB, ran PDS caliper and production log, 3 tbg leaks identified, set'PX' plug @ 4586' RKB. May 14, 2002 -Tag fill @ 4530' WLM. Obtain BHP survey. May 15, 2003 -Tag fill @ 4560' RKB (4534' WLM). Obtain BHP survey. May 13, 2004 -Tag fill @ 4566' RKB. Obtain BHP survey. May 14, 2005 -Tag fill @ 4500' RKB. Obtain BHP survey. Jun 2006 -Bail fill to 4581' KB. Close XD @4501' KB, leaks. Can't locate X profile in same. Set WRP at 4481' KB, PT tbg OK. Sep 2006 -Tag fill @ 4579' RKB. Obtain BHP survey. Oct 2007 -Tag fill @ 4579' RKB w/ 1.75" bailer. U dated :10/9/2007 B :Jim Ennis _... ~u: 7a75~ PBTD: 6380' rD = 7.aao wen: NoRh Cook Inlet Unit No. A-03 Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit JDB • • ~~~ ~~ L ~t~ ~~ +~`~" ~C'~ ip rs ~:: 1 ~f ~~ e e FRANK H. MURKOWSKI, GOVERNOR AJ1ASIiA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Jim Ennis Wells Group Engineer ConocoPhillips (Alaska), Inc. PO Box 100360 Anchorage, AK 99510 Re: North Cook Inlet Field, Tertiary Gas Pool, NCI A-03 Sundry Number: 306-229 - 1.., Dear Mr. Ennis: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, n . Chairman DATED this II day of July, 2006 Encl. I Co ~ -O'ì~ e e Review of Sundry Application 306-229 ConocoPhillips Alaska, Inc. Well NCI A-03 AOGCC Permit 168-099 Recommendation: I recommend approval of Sundry Application 306-229 to allow ConocoPhillips Alaska, Inc. ("CP AI") to install an expandable casing patch to seal off the Cook Inlet ("CI") A&B sands and re-perforate and install a gravel pack across the CI 1-4 sands in the subject well. Discussion: On June 26, 2006, the Commission received the subject Sundry application fÌ'om CP AI. They requested to re-perforate and install a gravel pack across the CI 1-4 sands and to install an expandable casing patch across the CI A&B perforations to prevent cross flow. Since some open perforations are going to be sealed (not squeezed in the traditional sense but still incapable of flowing) an analysis of potential impacts to reserves is required. On September 2, 1994, the Commission received an application fÌ'om Phillips Petroleum Co. to perform a workover on the subject well. One ofthe proposed activities was to squeeze the CI A&B sands. The Commission approved this application, sundry approval number 94-239, on September 6th. However, when the work was actually done the CI A&B sands were not squeezed, but were instead isolated from production by placing them behind tubing and isolating them with a packer set above and below the open perforations. The Commission's files do not contain any details as to why this change was made. I talked with MR. John Braden of CP AI about their proposed activity. Specifically I asked him if the CI A&B sands are capable of producing. He stated that they have attempted to flow these sands in other wells in the field recently, but the sands appear to be watered out and incapable of commercial production. Also, he was unaware of why the previous workover simply isolated the CI A&B sands perforations instead of squeezing them as had been proposed. In addition to the CI sands mentioned above the well is also currently perforated in several Beluga sands, however in March 2002 a plug was installed in the tubing above these sands and they are currently incapable of production. A review of the production data for this well shows no discernible changes in the production rate trend, shown in the figure below, after either the workover in 1994 that isolated the CI A&B sands, or the plug installation in 2002 that isolated the Beluga sands. Therefore it is apparent that the CI 1-4 sands is the dominant producing interval in the well and any potential contribution fÌ'om the other sands is negligible. Currently the subject well is producing about 7 to 8 mmscfpd. ~ . e e Conclusions: Based on my conversation with Mr. Braden and a review ofthe workover and production histories for this well I believe that the potential for loss of reserves fÌ'om the proposed operations is negligible. Th~e, I recommend approving CPAI' s Sundry Application. Prepared by: D.S. RobY~ Prepared on: July 7,2006 e Conoc6Phillips e Jim Ennis Wells Group Engineer Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1544 June 26, 2006 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West yth Avenue Suite 100 Anchorage, Alaska 99501 RECEIVED JUN 2 6 Z006 Alaska Oil & Gas Cons. Commission Anchorage Subject: Application for Sundry Approval NCI A-03 Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Application for Sundry Approval for the upcoming workover on the Tyonek Platform well NCI A-03. The attached procedure outlines steps to reperforate' and install a gravel pack across the Cook Inlet (CI) 1-4 sands. In order to accomplish this sand control installation, an expandable casing patch will be installed across the shallower CI A&B sands to prevent cross flow. If you have any questions regarding this matter, please contact me at 265-1544. since~ J. EnniS~--- Wells Group Engineer CPAI Drilling and Wells JE/skad OR\G\NAL 'l~ 1[rotfe ke /;/:27/06 {,p{1'Ú-' ÁflO t<~~~~"2:~ L!n. STATE OF ALASKA . . I lJ r ALASKA OIL AND GAS CONSERVATION COMMISSION .Alaska em (~{ CQns. CQIftmIsslOn APPLICATION FOR SUNDRY APPROVAl "nchorage 20 MC 25.280 1. Type of Request: Abandon 0 Suspend 0 Operational Shutdown 0 Perforate 0 Waiver 0 Other 0 Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Change approved program 0 Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development 0 Exploratory 0 168-099 . 3. Address: Stratigraphic 0 Service 0 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-883-20020-00 . 7. KB Elevation (ft): 9. Well Name and Number: RKB 116' NCI A-03 . 8. Property Designation: 10. Field/Pool(s): ~::10~1- ?~j ~ ADL 18755 .¥.Cook Inlet Field I' PJ.,zJ,O 11. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7480' 6392' Casing Length Size MD TVD Burst Collapse Structural 30" 384' 384' Conductor 16" 612' 612' Surface 10.75" 2519' 2320' Production 7" 7475' 6385' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3964'-7237' 3570'-6187' 4.5" J-55 6289' Packers and SSSV Type: Packers and SSSV MD (ft) Halliburton 'VSH' pkr @ 3908', Halliburton 'TWR' pkrs @ 4199',4526',4595',4669',4751',4832',4886',4936',5114' Halliburton 'XXO' SVLN @ 291' 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: August 1, 2006 Oil 0 Gas 0 Plugged 0 Abandoned 0 16. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Jim Ennis @ 265-1544 Printed Name JimEnnis Title: Wells Group E:9i7; Ii Signature /~ Phone Date Ç¡.,;¿ (p ð lo Commission Use Only f I Sundry Number: Conditions of approval: Notify Commission so that a representative may witness 3-::>/..." - ~~ Plug Integrity 0 BOP Test J8; Mechanical Integrity Test 0 Location Clearance 0 Other: ¿;)SOO,\,S~\ ~Ç>~c:.>\~o."" ~\o.'l'~ ) RBDMS 8Ft ,JUL ] 2 2006 s""",,,,,", F"m ""'"".., '-\0?íj ~C~~'~~N~ A L D're ?/t /,,6 ~t APPROVED BY Approved by: "-T-:; THE COMMISSION '--"'" C/ ~ _~b. t.- zB-o' Form 10-403 Revised 7/2005 Submit in Duplicate. ~ 77/c6 ,_o~,... aq.: .... e e NCIU A #3 Gravel Pack CI 1-4 Sands W orkover FELl Procedure Pre-rh! I. MIRU Pollard slickline. Pull HES 'FXE' SSSV. Tag fill wi 3" bailer. RD slickline. ~&SOO~\ ~~~"I/\v 2. MIRU BJ 2"xl" CCTD. Nipple up and test BOP as per SOP (see attached BOP diagram). Notify AOGCC 24 hours prior to BOP testing. 3. RIH wi 2.125" WellVac BHA to 4450' CTMD (last tag @ 4515' KB in Jun '06). Establish circ wi 2 micron filtered 6% KCL wtr containing I gaVI000 gal FRW-14. CO to 'PX' plug @ 4586' MD. Circ clean. POOH. RD CCT. 4. RU APRS Eline. Chemical cut tbg mid-joint above the 'TWR' packer @ 4526' & mid-joint above & below the 'TWR' packer @ 4199' MD. Set BPV. . ,- Rie 1. MIRU Cudd hydraulic unit. NDWH. NU II" BOP stack (see attached diagram) wi 4.5" & 3.5" pipe rams. Notify AOGCC 24 hours prior to BOP testing. PT BOP's 250/2500 psi. MASP is (1000 psi)-(3573' TVD)(O.OI psi/ft)= 964 psi assuming CI A-B Sands have experienced little or no depletion since 1994 workover. Remove BPV. 2. Unland & POOH wi 4-1/2" production tbg and PBR seal stem. . 3. Single in wi HES retrieving tool, jars & nine 4.75" DC's on 3.5" WTS-6 workstring. Engage RES 'VSR' packer & release. POOH wi packer & ~290' 4.5" tailpipe. 4. RIH wi packer plucker milling BHA on workstring & mill up 'TWR' packer @ 4199' MD. POOH wi packer. 5. RIH wi 350' 5.75" washpipe, boot baskets, jars & nine 4.75" DC's on workstring. Wash over tbg fish to top of 'TWR' packer @ 4526' MD. POOH. 6. RIH wi overshot, jars & DC's on workstring. Engage tbg fish & POOH. 7. RIH wi 6" Baker ExPatch assembly to isolate CI A-B & sqz perfs 3930'-4179' MD'. Expand patch as per SOP & POOH wi tools. 8. RIH wi TCP perf guns on workstring. Underbalance re-perfCI 1-4 sands 4210'-80', 4300'-75', 4428'-40' & 4474'-94', 12 SPF wi BH charges. POOH wi TCP guns. 9. RIH wi Baker 'MZ' gravel pack BHA and set 'SC' pkr above ExPatch. Pump gravel pack & circ clean. POOH laying down workstring & GP tools/washpipe. Jim Ennis Page I 6/2212006 e e 10. Single in wi PBR seal stem, 3.813" 'X' nipple, 4-1/2" production tbg, 3 KBG-2 GLM's & 3.813" SSSV landing nipple (~400' MD). Land tbg & install BPV. NDBOP & NUWH. PT IA to 1500 psi. Set BPV. 11. RDMO Cudd. Pull BPV. Post-Rit?: 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 2 6/22/2006 ~~~._~.~~ .....'~~~---S&S 800L Injector (80k pull capacity) .-~ ~~~~-~31/16"10K Side Door Stripper ~-~~- 41/16" 10K Lubricator 41/16" 10K Quad BOP Blind ... Shear Slip Pipe ... 41/16" 10K Flow Cross ... ~'--41116"10K Blind/Shear Ram .....~ ,~,--~-- Tree x 41116" Crossover .....---~-~~,~ Tree Swab Valve ConocoPhillips BJ Coiltech 5/4/2006 _.~....._--- Coiled Tubing Stack Drawing * 2" denotes annular capacity Combined: Wt/Ft = Total Wt: Capacity: 3.351 Ib/tt 33,091 Ibs 26.3 bbls ConocoPhillips 5/4/2006 Concentric Makeup Coiltech e e Weatherlord® Pressure Control Diagram Customer Name: Well Name/Number: Drawn On: Job Number: Location: Work Order Number: Conoco Phillips 2006 May 05 --"".._-~_..._.__.~~----~~,._-_._~._-_._~._._._-- Cook Inlet, Tyonek Platform Prepared For: Prepared By: J.D. Quartly Weathertord products and services are subject to Weatherford's standard terms and conditions. For more infonnation concerning the full line of Weathertord products and services, please contact your authorized Weatherford representative. Unless noted otherwise, trademarks and service marks noted herein are the property of Weatherford. Specifications are subject to change without notice. © 2005 Weatherford. All rights reserved. Page 1 of 3 e e " ConCK s Weatherlord® Sketch Page 2 of 3 o CD eatherford products and services are subject to Weatherford's standard terms and conditions. For more infonnation concerning the full I ne of Weatherford products and services, please contact your authorized Weatherford representative. Unless noted otherwise, ademarks and service marks noted herein are the property of Weatheñord. Specifications are subject to change without notice. Page 2 of 2005 Weatherford. An rights reserved. e e . Details Page 3 of 3 WeatherfordOÞ Item Description Comments 1 BOP (LWS Single) - 11 in, 5000 PSI "Shaffer Type LWS SGL Gate Studded Top and Bottom No OTL" Height: 19-112 in, Spool (Drilling) - 11 in, 5000 PSI, 11 in, 5000 PSI 2 Outlet1: 2 in, 5000 PSI "FLGD" Outlet2: 4 in, 5000 PSI Height: 24 in 3 BOP (LWS Double) - 11 in, 5000 PSI "Shaffer Type LWS DBL Gate Studded Top and Bottom No OTL" Height: 33 in, 4 BOP (Bolted) - 11 in, 5000 PSI "FLG B1M" Height: 48-7/16 in, Spool (Adapter) - 4 1/16 in, 5000 PSI 5 3 1/8 in, 5000PSI "Double Studded Adapte~' 6 Valve (gate) - 31/8 in, 5000 PSI "FLGD" 7 Valve (gate) - 3 1/8 in, 5000 PSI "Hydraulic Gate Valve FLGD" 8 Valve (gate) - 2 1/16 in, 5000 PSI "FLGD" 9 Valve (gate) - 2 1/16 in, 5000 PSI "FLGD" 10 Valve (Check) - 2 1/16 in, 5000 PSI "FLGD" Drawn On: Job Number: Work Order Number: 2006 May 05 ~:~~~~~h~~~c~~nu~sse~~e:e~~~,b~~:~ %~~~~~~~;~~~~~~: ~:~:e~~~~~~~~:~fa~~v~.o~en::~~o~::~~:~n~~g the full Page 3 of 3 trademarks and service marks noted herein are the property of Weatherford. Specifications are subject to change without notice. © 2005 Weatherford. All rights reserved. e e I~ Conocó'Phillips NCIU Well A-3 Completion Diagram API# 508832002000 Gas Producer FMC OCT RKB-Drill Deck: ~ Single Compo FMC 41/2" 8rd X 4" BT&C RKB- THF: ~ 39.94 ., Annulus Fluid: Salt Water with 3 bbl Methanol RKB-Sl : 3 115.9 ~ml TOC: 3700' from CBl dated 03/14/69 WATER DEPTH: 120 . RKB-Ml : OD'<'< roD' ; i ; BottÖlri; ;;;;;W'I';J;;';; ,; ';Grade; '<I' ;;; Tensn;; roBING 16"@612' 30 " 41 384 16 " 41 612 65# H-40 1540 600 293 103/4 " 41 2,519 45.5# & 51# J-55 BT&C 3350 1970 531 7" 39 79 26# J-55 BT&C 4660 4080 327 7" 79 6,818 23# J-55 BT&C 4080 3080 288 7" 6,818 7,475 26# J-55 BT&C 4660 4080 327 41/2" 39 325 12.6# J-55 mod BT&C 4730 4980 134 41/2 " 325 6.289 12.6# J-55 mod 8rd 4730 4980 134 No! 'JIop, lengm; ;;; ';;;eT;; :;'<: DD: PRODUCTTON TUBING STRING & JEWELRY 103/4" @ 2519' Note: 8.98 ft difference in elevation is due to assembly being set on Electric Log Depths TOC @ 37DD' CBL 64 0.00 48.92 Elevation 3.958 6.000 ><: 55 V5R packer @ 3908' 63 48.92 0.70 FMC .I OCT 6' 3M 4 1/2' 8rd x 4 1/2' BTC Tbg, Hanger 3.958 6.000 - 62 49.62 240.93 41/2' 12.61b J-55 BTC Tubing & Pup JIs. 3.992 4.500 [ Cook Inlet Sands 61 290.55 2.45 Halliburton "XXO" SVlN - reset SCSSV 1/31/02 3.813 4.920 53 -::;¡::- 3930 - 3931 sqz 60 293.00 31.74 4 1/2' 12.6 Ib J-55 BTC Tubing 3.992 4.500 --"- = 3964 - 3979 CI-A 59 324.74 0.8 X-Over EU Box x BTC Box 3.992 4.500 = 4000 - 4025 CI-B 58 325.54 3572.67 4 1/2' 12.6 Ib J-55 EUE Tubing. 3.992 4.500 = 4055 -4070 CI-B 57 3898.21 8.68 Halliburton Upper 'PBR' 3.992 5.880 = 4100- 01 sqz 56 3906.89 2.62 Ratch Latch Seal Assembly 3.992 5.562 4178 - 79 sqz 55 3908.01 6.48 Halliburton "VSR" Packer 4.000 6.000 54 3914.49 31.38 4 112" 12.6 Ib J-22 EUE Tubina 3.992 4.500 53 3945.87 1.44 Halliburton "X" Nipple 3.813 5.562 >< 50 TWR packer @ 4199' 52 3947.31 250.87 4112' 12.61b J-22 EUE Tubin9 3.992 4.500 - - 51 4198.18 2.62 No Go Seal Assembly 3'990 5,560 :~ 4210 - 4280 CI-1.0 50 4199.30 10.68 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 4300 - 4375 CI-2.0 49 4209.98 0.6 Tubing Adaptor 3.990 5.560 =i!' 4428 - 4440 CI-3.1 48 4210.58 290.60 41/2' 12.61b J-55 EUE-MOD Tubing & Pup JIs. 3,992 4.500 4474 - 4494 CI-4.0 47 4501.18 4.22 Halliburton nXD" Sliding Sleeve Open 3/21/02 3.813 5.560 = ~, 46 4505.40 20.41 4 112' Pup JIs. 3.992 4.500 4 ","" ~. ",",' "" ''''''' 5.560 ~.....- "" ",",. "'" 45 4525.81 2.62 No Go Seal Assembly 3.990 44 4526.93 10.66 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 43 4537.59 0.6 Tubing Adaptor 3.990 5.560 42 4538.19 47..73 4 1/2" 12.6 Ib J-55 EUE-MOD Tubing & Pup Jts 3.992 4.500 z "_____ 41 4585.92 8.3 Halliburtan "XD" Sliding Sleeve & Pup Jt. Closed (1/31/02) 3.813 5.560 41 'PX' p~g;, 4552 - 4582 CI-5,O 40 4594.22 2.62 No Go Seal Assembly 3.990 5.560 Closed 39 4595.34 10.65 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 38 4605.99 0.6 Tubing Adaptor 3.990 5.560 3. TWR packer @ 4595' 37 4606.59 51.60 4 1/2" 12.6 Ib J·55 EUE-MOD Tubing & Pup Jts. 3.992 4.500 - 36 4658.19 10.35 Halliburton "XD" Sliding Sleeve & Pup Jt. Clased 1/31/02 3.813 5.560 -::x¡;::- = 4630 - 4640 CI-6.0 35 4668.54 2.62 No Go Seal Assembly 3.990 5.560 36 Tbg leak@ 4658' (sleeve leak?) 34 4669.66 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 ~ 33 4680.30 0.6 TubinÇJ Adaptor 3.990 5.560 32 4680.90 62.79 41/2" 12.61b J-55 EUE-MOD Tubina 3.992 4.500 31 4743.69 6.26 Halliburton "XD" Slidina Sleeve & PUD Jt. Clased 1/31/02 3.813 5.560 30 4749.95 2.62 No Go Seal Assembly 3.990 5.560 34 TWR packer @ 4669' 29 4751.07 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 - Tbg leak@ 4700' 28 4761.71 0.6 Tubing Adaptor 3.990 5.560 31 "XD" = 4692 - 4697 CI-7.0 27 4762.31 62.82 4 112" 12.6 Ib J-55 EUE-MOD Tubing 3.992 4.500 ~ 4730 - 4737 CI-7.1 26 4825.13 6.28 Halliburton "XD" Sliding Sleeve & Pua Jt. Closed (1/31/02 3.813 5.560 25 4831.41 2.62 No Go Seal Assembly 3.990 5.560 2. TWRpacker@4751' 24 4832.53 10.72 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 - 23 4843.25 0.6 Tubing Adaptor 3.990 5.560 -::;¡¡;:;- ~ 4778 - 4788 CI-8.0 22 4843.85 41.43 4 112' 12.6 Ib J-55 EUE-MOD Tubing 3.992 4.500 2. 4793 - 94 sqz peñs 21 4885.28 2.62 No Go Seal Assembly 3.990 5.560 ~ 4810 - 4820 CI-8.2 20 4886.40 10.7 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 - 19 4897.10 0.6 Tubing Adaptor 3.990 5.560 24 :>< TWR packer @ 4832' 18 4897.70 31.38 4112' 12.61b J-55 EUE-MOD Tubing 3.992 4.500 - 17 4929.08 6.28 Halliburton "XD" Sliding Sleeve & PUD Jt. Closed 1/30/02 3.813 5.560 = 4850 - 4875 CI-9.0 16 4935.36 2.62 No Go Seal Assembly 3.990 5.560 - 15 4936.48 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 20 TWR packer @ 4886' 14 4947.12 0,6 Tubing Adaptor 3.990 5.560 13 4947,72 98.27 4112' 12,61b J-55 EUE-MOD Tubing 3.992 4.500 -::x¡;::- = 4900 - 4925 CI-10.0 12 5045.99 4.22 Halliburton "XD" Slidina Sleeve CLOSED 3.813 5.560 17 11 5050.21 62.67 41/2' 12.61b J-55 EUE-MOD Tubing 3.992 4.500 ~ 10 5105.00 41/2" EZSV BrldDe PIUD 4.500 81 Halliburton TWR packer @ 4936' 9 5112,88 2,62 No Go Seal Assembly 3.990 5.560 15 8 5114.00 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 7 5124.64 0.6 Tubing Adaptor 3.990 5.560 __ p, Tbg/eak@4940' 6 5125.24 501.1 4 1/2' 12.6 Ib J-55 EUE-MOD Tubing 3.992 4.500 1@4991' :::::::::::: 1; 4950 - 4995 CI-11.0 5 5626.34 4.22 Halliburton "){A" Sliding Sleeve 3.813 5.560 12 ~ "XD" ;H 4 5630.56 657.01 41/2' 12.61b J-55 EUE-MOD Tubing 3.992 4.500 10 EZSV BP-tt~5105' KB 3 6287.57 1.5 Halliburton "XN" Landing Nipple 3.725 5.560 >< 8 2S. ¡¡ Halliburton TWR packer @ 5114' 2 6289.07 0.6 Re·Entry Guide ~E Beluga Sands J 1 6289.67 End of Tubing -- 5254 - 5261 b-6 ,;C' ;:, 'X'C ;c, ~;:" ,,,,,;;;;:;:, ;:, ';c = 5279 - 5284 b-7 Well History = 5418" 5423 0-3 March 1969 - Original Camplelian - CI A, B, 4.0,5.0,6,0.8.0,8.2,9.0,10.0,11.0, = and Beluga b-6 thru q-4 Commingled 5565 - 5570 d-3 July 1975- CI1.0. 2.0,7.0.&7,1 Perforated. = 5579 - 5584 d-3 September 1994 Workover - Well completed in Beluga b-6 thru i-3 -:;¡¡::- = 5596 - 5603 d-4 Reperfarate Beluga b-6 thru i-3 5254'-6289' 12 SPF 5 Beluga j-2 thru q·4 abandoned without testihg ~ 5834 - 5844 1-1.1&1-2 Reperfarate C11.0 thru 11.0 Iram 4210'-4995' 12 SPF = 5870 - 5880 1-4 Also added CI 3.1 perforations = October 1999 - Tap 01 Fill 6342' 5961 - 5971 g-1 June 4, 2001 Tag fill @ 5625' = 6043 - 6058 g-5 = 6070 - 6080 h-1 = Dec. 2001 Set EZSV BP @ 5105' RKB. Open XD Sleeves @ 5046' & 4929' RKB. -::;¡¡¡:;- = 6227 - 6252 h-9 Jan 30, 2002 Tag fill @ 5005' WlM, Clased sleeve @ 4878' WLM 3 6284 - 6289 i-3 Jan 31, 2002 Confirmed all sleeves above 5005' SLM closed, tested well @ 12MM, approx 300 BWPD, Ran SSSV 2 ~ = March 2002 - Tag fit! @ 4991' RKB, ran PDS caliper and production log, 3 tbg leaks identified, set 'PX' plug @ 4586' RKB. ~ May 14, 2002 - Tag fill @ 4530' WlM. Obtain BHP survey. EZSV @ 6380 May 15, 2003 - Tag fill @ 4560' RKB (4534' WlM). Obtain BHP survey. = May 13, 2004 - Tag fill @ 4566' RKB. Obtain BHP survey. = m 6414 - 6421 j-2 May 14, 2005 - Tag liII ¡g¡ 4500' RKB. Oblain BHP survey. = m 6514 - 6529 k-4.1 = 0:' 6898 - 6908 n-5 = .~ = 7033 - 7040 0-4 PBrD 6380' 7212 - 7237 q-3&q-4 Updated: 3/7/2006 By: Jim Ennis I 7" @ 7475' PBTD: 6380' Fill Tag: 4460' WLM 5105 I TD = 7,480' Well: North Cook Inlet Unit No. A-03 Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit JDB e e ~J ~ ConocoPhillips NCIU Well A-3 Proposed Completion Diagram API# 508832002000 Gas Producer FMC OCT RKB-Drill Deck: ~ Single Comp. FMC 41/2" 8rd X 4" BT&C RKB- THF: ~ 39.94 61 Annulus Fluid: Salt Water with 3 bbl Methanol RKB-Sl : 3 115.9 I' ,. TOC: 3700' Irom CBl dated 03/14/69 WATER DEPTH: 120 ' RKB-Ml : '"~COD! ~ I'"'' 'WI ""urst; 'Coli"" lJ 16"@612' 30 " 41 384 16" 41 612 65# H·40 1540 600 293 10314 " 41 2,519 45.5# & 51# J·55 BT&C 3350 1970 531 W 7" 39 79 26# J-55 BT&C 4660 4080 327 7" 79 6,818 23# J·55 BT&C 4080 3080 288 7" 6,818 7,475 26# J-55 BT&C 4660 4080 327 41/2" 39 325 12.6# J-55 mod BT&C 4730 4980 134 41/2 " 325 ;28. 12.6# J-55 mod 8rd 4730 4980 134 ," U PRODUCTION TUBING STRING & JEWELRY ---:x:- 10314" @2519' Note: 8.98 ft difference in elevation is due to assembly being set on Electric Log Depths ---::...... TOC @ 3700' CBl >< 55 'SC' pkr @ -3900' - Cook Inlet Sands 53 3930 - 3931 sqz 3964 - 3979 CI-A 4000 - 4025 CI-B 4055 - 4070 CI-B 4100-01 sqz :8: 4178-79 sqz .,~ Iso Pkr in ExPatch = 4210 - 4280 CI-1.0 4300 - 4375 CI-2.0 = 4428 - 4440 CI-3.1 = 4474 - 4494 CI-4.0 = ¡ Baker Exclvder Screens 45 4525.81 2.62 No Go Seal Assembly 3.990 5.560 '-- 44 4526.93 10.66 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 43 4537.59 0.6 Tubing Adaptor 3.990 5.560 >< 44 TWR packer @ 4526' 42 4538.19 47.73 41/2' 12.61b J-55 EUE-MOD Tubing & Pup Jls. 3.992 4.500 "XD" - 41 4585.92 8.3 Halliburton "XO" Sliding Sleeve & Pup Jt. Closed (1/31/02) 3.813 5.560 41 1>< 'PX'p~ 4552 - 4582 CJ-5.0 40 4594.22 2.62 No Go Seal Assembly 3.990 5.560 I Closed 39 4595.34 10.65 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 38 4605.99 0.6 Tubing Adaptor 3.990 5.560 3. TWR packer @ 4595' 37 4606.59 51.60 4 1/2' 12.6 Ib J-55 EUE-MOD Tubin9 & Pup Jts. 3.992 4.500 - 36 4658.19 10.35 Halliburton "XO" Slidina Sleeve & PUD Jt. Closed (1/31/02 3.813 5.560 t-:xo:- = 4630 - 4640 CI-6.0 35 4668.54 2.62 No Go Seal Assembly 3.990 5.560 36 Tbg leak@ 4658' (sleeve leak?) 34 4669.66 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 Closed 33 4680.30 0.6 Tubina AdaDtor 3.990 5.560 32 4680.90 62.79 4 1/2" 12.6 Ib J-55 EUE-MOD Tubina 3.992 4.500 31 4743.69 6.26 Halliburton "XD" Slidino Sleeve & PuP Jt. Closed (1/31/02 3.813 5.560 30 4749.95 2.62 No Go Seal Assembly 3,990 5.560 34 TWR packer @ 4669' 29 4751.07 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 Tbg leak @ 4700' 28 4761.71 0.6 Tubing Adaptor 3.990 5.560 31 "XD" 4692 - 4697 CI-7.0 27 4762.31 62.82 41/2' 12.61b J-55 EUE-MOD Tubing 3.992 4.500 ~ 4730 - 4737 CI-7.1 26 4825.13 6.28 Halliburton "XD" Sliding Sleeve & PuP Jt. Closed (1/31102 3.813 5.560 I.....- 25 4831.41 2.62 No Go Seal Assembly 3.990 5.560 2. TWR packer @ 4751 ' 24 4832.53 10.72 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 - 23 4843.25 0.6 Tubing Adaptor 3.990 5.560 -;:;¡¡;:;- ~ 4778 - 4788 CI-8.0 22 4843.85 41.43 41/2' 12.61b J-55 EUE-MOD Tubing 3,992 4.500 26 4793 - 94 sqz peris 21 4885.28 2.62 No Go Seal Assembly 3.990 5.560 ~ ~ 4810 - 4820 CI-8.2 20 4886.40 10.7 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 I.....- 19 4897.10 0.6 Tubing Adaptor 3,990 5.560 24 TWR packer @ 4832' 18 4897.70 31.38 41/2" 12.61b J-55 EUE-MOD Tubing 3.992 4.500 ¡o- 17 4929.08 6.28 Halliburton "XO" Slidina Sleeve & PUD Jt. Closed (1/30102) 3.813 5.560 = 4850 - 4875 CI-9.0 16 4935.36 2.62 No Go Seal Assembly 3.990 5.560 I.....- 15 4936.48 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 2. TWR packer @ 4886' 14 4947.12 0.6 Tubing Adaptor 3.990 5.560 13 4947.72 98.27 4 1/2' 12.6 Ib J-55 EUE-MOD Tubing 3,992 4,500 --:x¡;:- = 4900 - 4925 CI-10.0 12 5045.99 4.22 Halliburton "XD" Sliding Sleeve CLOSED 3.813 5.560 17 11 5050.21 62.67 4 1/2' 12,61b J-55 EUE-MOD Tubing 3,992 4.500 ~ 10 5105.00 4112" EZSV Bridae Pluo 4.500 I.....- 9 5112.88 2.62 No Go Seal Assembly 3.990 5.560 15 I VYK packer @ 4936' 8 5114.00 10.64 Halliburton "TWR" Packer & Millout Extension 4.000 5.870 ¡o- 7 5124.64 0.6 Tubina Adaptor 3.990 5.560 ,_ --;;;-Tbgleak@4940' 6 5125.24 501.1 4 1/2" 12.6 Ib J-55 EUE-MOD Tubing 3.992 4.500 fill@4991' :::::::::::: 1 4950-4995 CI-".0 5 5626.34 4.22 Halliburton "XA" Sliding Sleeve 3.813 5.560 12 """><" "XD" '-'IT: 4 5630.56 657.01 4 1/2' 12.61b J-55 EUE-MOD Tubing 3.992 4.500 1. EZSV BP',£S10S' KB 3 6287.57 1.5 Halliburton "XN" Landino Nipple 3.725 5.560 8 ~ II Hallibvrton TWR packer @ 5114' 2 6289.07 0.6 Re-Entry Guide H Beluga Sands 1 6289.67 End of Tubing q 5254 - 5261 b-6 l'];'!I] ;';', ';' 1';,;,;':: ;'2:";'l' ""1' ;:1';1' ~ = 5279 - 5284 b-7 Well History = 5418 - 5423 c-3 March 1969 - Original Completion - CI A. B, 4.0,5.0,6.0,8.0.8.2.9.0.10.0.11.0. = and Beluga b-6 thru q-4 Commingled 5565 - 5570 d-3 July 1975- CI1.0, 2.0.7.0.&7.1 Perforated. = 5579 - 5584 d-3 September 1994 Workover - Well completed in Beluga b-6 thru i-3 ~ = 5596 - 5603 d-4 Reperforate Beluga b-6 thru i-3 5254'-6289' 12 SPF 5 Beluga j-2 thru q-4 abandoned without testing ~ 5834-5844 f-1.1&1-2 Reperforate C11.0 thru 11.0 from 4210'-4995' 12 SPF = 5870 - 5880 f-4 Also added CI 3.1 perforations October 1999 - Top of Fill 6342' = 5961 - 5971 g-1 June 4, 2001 Tag fill @ 5625' = 6043 - 6058 g-5 6070 - 6080 h-1 = .. Dec. 2001 Set EZSV BP @ 5105' RKB. Open XD Sleeves @ 5046' & 4929' RKB. -::x;¡:;- = 6227 - 6252 h-9 Jan 30, 2002 Tag fill @ 5005' WlM, Closed sleeve @ 4878' WLM 3 6284 - 6289 i-3 Jan 31, 2002 Confirmed all51eeves above 5005' SLM closed, tested well @ 12MM. approx 300 BWPD. Ran SSSV 2 ¡........;.;;;- = March 2002 - Tag fill @ 4991' RKB. ran PDS caliper and production log. 3 tbg leaks identified. set 'PX' plug @ 4586' RKB. '-- May 14, 2002 - Tag fill @ 4530' WLM. Obtàin BHP survey. EZSV @ 6380 May 15, 2003 - Tag fill @ 4560' RKB (4534' WlM). Obtain BHP survey. = May 13, 2004 - Tag fill @ 4566' RKB. Obtain BHP survey. = 6414 - 6421 j-2 May 14, 2005 - Tag fill @ 4500' RKB. Obtain BHP survey. = 6514 - 6529 k-4.1 = = 6898 - 6908 n-5 = 7033 - 7040 0-4 PBTD 6380' 7212 - 7237 q-3&q-4 Updated: 3/7/2006 By: Jim Ennis 7" @ 7475' PBTD: 6380' Fill Tag: 4460' WLM 5/05 TD = 7,480' Well: North Cook Inlet Unit No. A-03 I Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit JDB - .- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown ~ Stimulate Pull Tubing X Alter Casing 2. Name of Operator: Phillips Petroleum Co. 3. Address: P.O. Box 1967 Houston, Texas 77251-1967 4. Location of well at surface: 1250' FNL & 1087' FWL At top of productive interval: 1579' FNL & 363' FEL At effective depth: 1285' FNL & 510' FEL At total depth: 1550' FNL & 1828' FEL Plugging Repair Well 5. Type of Well Development X Exploratory Stratigraphic Service Leg 3, Slot 7 PPCo. Tyonek Platform Perforate x Other 6. Datum elevation (DF or RKB) RKB 116 Feet 7. Unit or Property Name North Cook Inlet Unit 8. Well Number Sec 6 - T11N - R9W North Cook Inlet, Ak. 3962' MD 3564' TVD Sec 1 - T11N - RIOW 4210' MD 3764' TVD Sec 1 -T11N- R10W 6380' MD 5488' TVD Sec 1 - T11N- R10W A-03 9. Permit Number / Approval Number 68-99 94-239 10. APl Number 50-883-20020 11. Field / Pool Cook Inlet / Beluga 12. Present well condition summary: Total Depth: measured 7,480 feet true vertical 6,387 feet Effective Depth: measured 4,210 feet true vertical 3,704 feet Plugs (measured) Junk (measured) PBTD: 6380' ORIginAL Casing: Structural Conductor Surface Intermediate Production Liner Length Size Cemented Measured Depth True Vertical Depth 30 " Driven 384 384 16 " 735 sx Cl "G 612 612 10 3/4" 1245 sx CI" 2,519 2,320 7ff 1050 sx CI"G 7,475 6,385 Perforation Depth: measured 3964' - 7237' true vertical 3570' - 6187' Tubing (size, grade and measured depth) Packers and SSSV ( type and measured depth) 13. Stimulation or cement squeeze summary: 4 1/2" 12.6 Ib/ft J-55 Mod BT&C Tubing 39' - 325' 4 1/2" 12.6 ib/ft J-55 Mod 8rd Tubing 325-6289' Halliburton "XXO" SVLN at 290', Halliburton "VSH" packer at 3908' Halliburton "TWR" packers at 4199', 4526', 4545', 4669', 4751', 4832, 4886', 4936', 5114' R F.,¢ F.. D Intervals treated (measured): Treatment description including volumes used and final pressure: 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Prior to well operation: 0 151 O0 0.86 190 Tubing Pressure 929 06/06/94 Subsequent to operation 0 12000 0.32 205 956 12/02/94 15. Attachments: 16. Status of Well Classification as: Copies of Logs and Surveys Run __ Daily Report of Well Operations X Oil __ Gas X Suspended ~_ 15. I hereby certify that the .foregoing is true and.correct to the best of my knowledge: Signed ~~_~', .~ ~'~~ Title Principle Engineer Form 10-404 Rev. 06/15/88 Service Date 19-Jan-95 SUBMIT IN DUPLICATE PHILLIPS PETROLEUM DAILY REPORT SUMMARY WELL:NOrth Cook Inlet Unit No. A-3 FIELD:COOK INLET NORTH CNTY/STATE:TYONEK OFFSHORE/ALASKA RIG:Pool Arctic Alaska/Pool Arctic Alaska AFE$:P-V128 AUTH COST:$1,795,000 DATE DEPTH RPT NO Ng OPERATIONS SUMMARY DALLY COST CU~ CO~T ~ENT TYPE; Workovo. r 09/12/94 7,,~80 1 8.5 SKIDDED RIG F/A-6 TO A3. KILLED WELL. RU PRECISION glRELINE $24,73~ $24,7'~ TO PULL D#SV FOR SETTING PLUG. 09/13/9~ 7,480 2 '8.5'PULL SSSV/RIH &'SET PLUG/ND TREE/IRI & TEST BOPIS/PULL PACKER " $~5,398 $70,132 FREE/CIRC HOLE CLEAN/LAY DOUN TUBING/RIH & BEGIN MILLING OVER PERMANENT PACKER ASSEMBLY 09/14/9~ 7,480 3 8.6 MILL UP PKR a 4115.CBIJ.TOfl.P/U CLEANOUT BHA.TIN & CLEAN OUT $~$,271 $115,403 TO6~O.CIRC.S~EEP.TON.P/U EZSV.TIH & SET a6380.CBU.TON.P/U 4 5/8 TCP GUNS TO PERF BELUGA INTERVAL 5254-6289.TI#. R/U g/L.CORRELATE.SPACE OUT.CORR.OK.OPEN TOOLS.PIPE FILLED 09/15/94 7,480 4 8.6 $~9,70Z $165,10~ g/I~JD.SHEAR IPO.CBU.TON,C/O TEST TOOLS.TIH.CORR.PERF & SURGE BELUGA.KILL gELL.TON.L/D TOOLS & GUNS.P/LI BIT & $CRAPER.TIH. ~'/16/9~ 7,480 5 ' 8.6 BIT & SCRAP TO 6380.CBU.TOII.P/U TCP GUNS TO PERF COOK INLET. S297,222 $~62,326 TIH.g/L CORRELATION.PERF 4210-4995(~4'NET).SURGE PERFS.KILL gELL.TOH.L/D SPENT GUNS.TIH U/BIT & SCRAPER.CIRC & COMO. ~/17/94 7,480' 6 8.6 TOH U/BIT & SCRAPER.TIH.DST ff~ ON BELUGA SANDS (5254-6289). $35,157 t~97,,ULt KILL NELL.CUT DRILL LINE.TO#.P/U TOOLS.TIH.R/U COILED TBS. JET ON NELL g/N2 TO START TEST ON C-1 THRU C-11. 09/19/94 7,480 $43,7~8 S643o146 1~9/18/94 7,480 7 8.6 JET IN U/COIL TBG.R/D TBG.R/U TEST TREE.DST ~ (Cl PERFS) $101,9~6 $599,429 4210-4995.KILL gELL.TOH.P/U EZSV.TIH.SET ~205.TOfl.P/U TOOLS TIH.DST#S (UPPER Cl A&B)396~-&OTO.KILL UELL.TOH.P/U DRLG ASS 8 8.6 TIH.DRILL EZSV ~205.TOH.P/U SCRAPER.TIH TO 6~80.ClRC,SUEEP. TOH.R/U & RUN PER ASS #1.PKR SET & STUCK g/TAILPIPE a PKR ~969.SNEAR OFF.CBU.TOfI.P/U PRT NILLING ASS.TIN.MILL ~KR 09/20/94 7,480 9 8.6 MILL PER iI~969.CBU.TON g/FISH.TIH U/BIT & 6" MILL.REAM 4969- $40,541 $683,687 4974.TIH TO 6380.SHEEP & CBU.TOH.RUN PKR ASS#1.CORRELATE.SET PKR #1 g5114.TOH.TIH & SET PKR #2 a 09/21/94 7,480 10 8.6 PER ASS #3.SET g4886.TOH.RUN PER ASS #~.SET ~832.TOH.RUN t~4,437 $728,124 RUN PKR ASS #S.SET ~TS1.TOH.RUN PKR ASS i~kS.SET ~669.TON. RUN PKR ASS #7.SET ~595.TOH.RUN PER ASS #8.SET a 4526.T0#. 09/22/94 7,480 11 8.6 TOH.RUN PER ASS #9.SET g~199.TOH.RUN PKR ASS #10.SET g3908. S95,276 S823,400 TOH.PULL klEAR BUSHG.RUN TBS TO 3908.SCSSV g2901.TEST ANNULUS SPACE OUT & HANG OFF.INSTALL BPV.#/O BOPS.N/U X-MAS TREE. 09/23/94 7,480 12 8.6 N/U & TEST 3M X-MAS TREE, PRODUCTION FLOULINE & MANUMATIC $~04,735 $1,228,135 VALVES.R/U RISER, COILEO TBS EGUIP & TEST.JET UELL IN AND TURN OVER TO PROOUCTION.R/O & PREPARE TO SKIO TO A-lO. 09/24/94 7,480 13 8.6 PREPARE SKID RIG/RELEASED RIG 1200 HRS 09/23/94. S54,878 Sl,283,013 10/29/94 7,480 14 8.6 TIH g/GUAGE RING & SHIFTING TOOL CHECKING XD SLEEVES.CLOSE $2,100 $1,285,113 ALL SLEEVES TO PROOUCE FROM BELUGA ZONES gBOTTOM. TURN NELL TO PRODUCTION FLOUING DAYSUM.RP1 12/07/94 RECEIVED JAN 2. 7 1995 Oil .& Gas Cons. Commissio~ Anchor~. ~ 612 PROPOSED WELL COMPLETIO FMC OCT FMC 4 If2" I~d X 4 ' BT&C Salt Water ~ith 3 bM Methanol 115.90 Production Cam;,, 315 J-55 WATER DEPTH: 120 ' RKB-ML: 1970 408O 3080 4080 49S0 TOG O 3700' PRODUCYION TUBING STRING i PBTD 7429' TD = 7 480' Otb V8H I~k~r 3~30 - 31 Iqz ~. 4055 - ~70 41~ - 01 I~ 4178 - 79 ~ packer@4200 '~ 4210 - 4280 Cl- 1 ~ 4300 - 4375 Cl-2 -"~*"**4428 - 4440 Cl-3 -~ 4474 - 4494 Cl-4 packer @ 4524 4552 - 4582 Cl-5 packer @ 4597 4630 - 4640 Cl-6 packer @ 4670 '-~ 4692 - 4~g7 Cl-7 -~. 47~) - 4737 packer @ 4753 4778 - 4788 Cl-8 4793 - 84 4810 - 462O packer @ 4832 ~ 4850 - 4875 CI-9 packer @ 4885 4~00 - 4~25 Cl- 10 4950 - 4995 C1-11 packer @ 5114 Beluga 8and~ 5279 - 5284 5418 - 5423 5565 - 5570 5579 - 5584 EZSV @ 6350 ~414 - 6514 - 6529 7033 - 7040 7212 - 7237 7" @ 7475 ToBe Squeezed 5.00 3549.10 3868_50 1_50 30.00 7.00 3907.00 290.00 4197.00 3.00 4200.00 10.00 4210.00 297.00 Elevation FMC I OCT ~' 8M 4 1/'2' ~rd x 4 1/2' BT&C J-55 mo{m Wi'&C Tubing H'buflon 4 I 12.6 IWfl J-55 -mod BT&C Tubing I/2" BT&C · 4 I/Z" EUE X-O~r 3.958 3.958 2.992 3.958 12.6 IWft J-55 mod EUE Tubing Halliburton 4 1/2" "X" Ninple J-55 mod EUE Tubin H'bnrton 7" · 3' %'SH' Hydraulic 12.6 IWft J-55 mod EUE Tnbint Halliburton 'No-Go' Sa~l Unit 3.958 3.813 3.958 3.958 4511.00 10.00 H'bnrton "AWR" Permanent Packer & ~ Ada$ 4 ~ 12.6 lb/fl J-55 mod EUE Tubint Halliburton 4 1/2" "XD" Sliding Sleeve 4 I/Z" 12.6 lb/fl J--55 mod EUE Tubing 3.813 3.958 4521.00 3.00 Halliburton "No-Go'.Seal Unit 3.900 4524.00 10.001 H'bmrton "AW'R" Permanent Packer & Tug. Adal~ 4.000 60.001 4 1/2" 12.6 lb/fl J-55 mod EUE Tubing / 3.958 3.00[ Halh'bnrton "No-Go" Seal Unit 3.900 H'burtoa "AWR" Permanent Packer & TI~ Adal~ 12.6 IWfl J-55 mod EUE Tubing / Halliburton 4 1/2 · 'XD" Sliding Sleeve J-55 mod EUE Tubin Halliburton "No-Go' Seal Unit 4:oooI 6.oooI 3.9581 4.500I 3.8131 s.sooI 3.9~1 4..s09. I 3.9oo1'4.oo~1 H'burtoa "AWR" Pernanent Packer & TI~ 4 I/2' 12.6 ib~fl J-55 mod EUE Tubint Halliburton "No-Go" Seal Unit 4.oooI 6.o00I 3.9581 4.500I 3.9001 4.0001 4763.00 !0.00I 60'001 H'burton "AWR" Permanent Packer & TI~ Ada$ 4 1/2' 12.6 IMf J-55 ~.o~. EUE Tubing Hall.burton 4 1/2 · 'XD Sliding Sleeve 4 I/2" 12.6 Ib/ft J-SS mod EUE Tubin8 Halliburton "No-Go" Seal Unit 4.0o01 6.000 I 3.~1. ~-~OOl 3~J~I 4.~0oI 3.9001 4..0~.,,, I IH'barton "AWR" Permneat Packer & ~ Ada1 4 1/'2" 12.6 Ib/ft J-55 mod EUE Tnbing Halliburton "No-Go" Seal Unit 4.oooI 6.o00I 3.958 [4~,,00I 3.9001 4.0001 H'burton "AWR" Permanent Packer & TI~. Adal~ 4 1/2' 12.6 IWft J--55 mod EUE Tubing / 3.8131 55oo 3.9581 4.5(~ 3.9oo I Halliburton 4 I/2 · 'XD" Sliding Sleeve 4 1/2' 12.6 lb/fl J-55 mod EUE Tubing Halliburton "No-Go' Seal Unit H'burton "AWR" Permanent Packer & ~ Ada 4 1/2' 12.6 lb/fl J-55 mod EUE Tubing Hall.burton 4 1/2 · 'XD" SLiding Sleeve 4 ~ 12.6 lb/fl J-55 mod EUE Tubing Halliburton 4 1/2" "XN" Nipple End of Tubing 4~0001 . 6.000 3.9581 4.soo 3.8131 s.soo 3.gssI 4.s(x) 3.7251 4.500 .,. COOK INLET SANDS BELUGA SANDS 4055 - 4O70 , 5418 - ~ · ~70 - ~ ~1 - ~71 ~70 - ~ ~7 - ~ ~14 - ~1 8514 - ~ UCI-A UCI-B UCI- B C1-1 CI-2 C~-3 Cl-4 Cl-5 Cl-e 463o - 4640 Cl-7 4692 - 4~97 4730 - 4737 Cl-8 4778 - 47~8 4810 - 48~ Cl-g 4850 - 4875 Gl- 10 490O - 4925 C1-11 4~50 ~ 4995 ~.owor' J Tbg Wt: 4" - 10.9 lb/ft I *** New Pe~orations PBTD: 7,429' [ Supv:. Well: Norlh Cook Inlet Unit No. A-03 ~:~.at, io~: ]~owerCgo, klnleh ~laska ~iel(~: C~ok Inlet U,it , 7033 - 7040 7212 - 7237 Not To Be Re -.Perfor ated 3 1/2" - 9.3 lb/fi August 31 ~ 1994 PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING September 01, 1994 North. Cook Inlet Unit "A-3" Phillips Tyonek Platform "A" North Cook Inlet, Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 ORIGINAL Re: North Cook Inlet Unit A-3 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-3 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. Regards, ~' D.~C. '-Gi~l, M~nager Drilling and Production Engineering cc (w/enc)' J.A. Landrum M. L. Jones (r) P. R. Dean J.F. Mitchell Central files RECEIVED SEP -2 1994 ~s_k~ .0il .& Gas Cons. Commission 1. Type of Request: Abandon ~ Suspend Alter Casing ___Repair Well ~ Chan~e Approved Pro,ram 2. Name of Operator: Phillips Petroleum Co. 3. Address: 6330 W. Loop South Bellairel Texas 77401 4. Location of well at surface: 1250'FNL & 1087'FWL Sec6-T11N - R9W At top of productive interval: 3962' MD 1579' FNL & 363' FEL Sec 1 - T11N - R10W At effective depth: 4209' MD 1285' FNL & 510' FEL Sec 1 - T11N - R10W At total depth: 7480' MD 1454' FNL & 2449' FEL Sec I - T11N - R10W 12. Present well condition summary: Total Depth: measured 7,480 feet true vertical 6,387 feet STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS Operation Shutdown Plugging _X__ Time Extension Pull Tubin~ X Variance 5. Type of Well Development X Exploratory Stratigraphic Service Leg 3, Slot 7 PPCo. Tyonek Platform North Cook Inlet, Ak. 3564' ']'VD 3764' TVD 6387' TVD Plugs (measured) Effective Depth: measured 4,209 feet true vertical 3,763 feet Junk (measured) Reenter Suspended Well ~ Stimulate Perforate X Other X {add perfs) 6. Datum elevation (DF or RKB) RKB 116 Feet 7. Unit or Property Name North Cook Inlet Unit 8. Well Number A-03 9. Permit Number / Approval Number 68-99 10. APl Number 50-883-20020 11. Field / Pool Cook Inlet / Beluc~a PBTD: 7,429' ORIGINA Casing: Structural Conductor Surface Intermediate Production Liner Length Size 30" 16" 10 3/4" Cemented Driven 735 sx CI "G" 1245 sx CI "G" 1050 sx CI "G" Measured Depth 384 612 2,519 7,475 True Vertical Depth 384 612 2,320 REEE IVED Perforation Depth: measured 3964' - 7237' SEP -2 1994 true vertical Tubing (size, grade and measured depth) packers and SSSV ( type and measured depth) 13. Attachments: 3570' - 6187' N__aS~3~ .0[! .& Gas Cons, .~_OlTI~i~J~ 4" 10.9 Ib/ff J-55 BT&C & 3 1/Z' 9.2 Ib/fl J-55 BT&C set at 4,154'. Otis "RH" retrievable packer @ 3,727'; Otis "WB" permanent packer @ 4,115'. Otis Type "AO" Wireline Retrievable SSSV ~ 288.02'. Description Summary of Proposal ~ Detailed Operations Program __ BOP Sketch ~. 14. Estimated Date for Commencing Operations: ~ September 10t 1994 I 16. If Proposal was Verbally Approved: Oil Gas ~L Name of Approver Date Approved Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge: Signe~/~~/ /~/~ D.C. Gill Title Drlg. & Prod. En,(:jr. Mana,cjer '~ FOR COMMISSION USE ONLY Conditions of ApProval: Notify Commission so Representative may witness Plug Integrity Mechanical Integrity Test Approved by Order of the Commission Form 10-403 Rev. 06/15/88 15. Status of Well Classification as: BOP Test Location Clearance Subsequent Form Required 10 - Original Signed By 0avid W. Johnston Suspended Commissioner Date SUBMIT IN~RIPLICA'I'E Approved Copy Returned September 1, 1994 Houston, Texas North Cook Inlet Unit "A"-3 North Cook Inlet Unit Tyonek County, Alaska Tentative Procedure le Skid rig over Well No. 3 slot in Leg 3. 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. · 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. · Pressure up the 4" x 7" annulus slowly to 1600 psi to test the casing prior to releasing the packer. · Rig up to pull tubing. Release Otis "RH" packer (3,727'). Pull 4" tubing, SSSV and retrievable packer with tailpipe and seal assembly from the "WB" packer at 4,115'. 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. ~1~ TIH with 6 1/8" bit and casing scraper for 7 "23 and 26 lb/ft casing. Clean out casing to a minimum of 6,400' (PBTD is 7,429'). Circulate hole clean and POOH. 7. TIH with EZSV drillable bridge plug. Set BP at 4,190'. · TIH with open ended drill pipe and spot 150 sx cement from 4,190 - 3,500'. Pull drill string above cement and squeeze Cook Inlet "A" and "B" perfs (3,964 - 4,070'). POOH with drill string. WOC 8 hours minimum. · TIH with bit and drill out cement. Test each perforated interval to 1500 psi. Resqueeze as necessary. When squeeze is obtained, TIH to 6400' and circulate hole clean. POOH. 10. TIH with EZSV cement retainer and set same at 6,350 to isolate the lower Beluga perforations (6,414' - 7,237'). 11. Make up and TIH with tubing conveyed perforating assembly to reperforate the existing and new Beluga Sands as follows: 5254' - 5261' 5279' - 5284' ~5418' - 5423' 5565' - 5570' 5579' - 5584' 5596' - 5603' 5834' - 5844' - RECEIVED 5961' - 5971' 6043' - 6058' SEP -~ ]994 6070' - 6080' 6227' - 6252' Al~$~U~l,&GasCons. Commission - . 6284' - 6289' '~.< ~ChOr~nn.:~.~ 12. Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. 13. 14. 15. Unload well and flow for initial clean-up. Kill well and POOH with perforating assembly. Make up and TIH with tubing conveyed perforating assembly to reperforate the existing Cook Inlet Sands as follows: 16. 17. 18. 19. 20. 21. 22. 23. 24. 4210' - 4280' 4300' - 4375' 4428' - 4440' 4474' - 4494' 4552' - 4582' 4630' - 4640' (CI-1) 4692' - 4697' (CI-7) (CI-2) 4730' - 4737' (CI-7) (CI-3) 4778' - 4788' (CI-8) (CI-4) 4810' - 4820' (CI-8) (CI-5) 4850' - 4875' (CI-9) (CI-6) 4900' - 4925' (CI-10) 4950' - 4995' (CI-11) New Perforations 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. Kill well and POOH with perforating assembly. TIH with bit and scraper and clean out well to PBTD. gas until well is stable. Circulate out If significant volumes of water and/or sand is produced during Step No. 13 or 17, TIH with DST tools and isolate intervals to check for water production. TIH with permanent packer assemblies as outlined on the "Proposed Well Completion Diagram" Set packer isolation assemblies at 5,114' 4,885', 4,832', 4,753', 4,670', 4,597', 4,524', and 4,200', Set Halliburton 7" retrievable "VSR" packer at 3,900'. 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 isolation packer. Test annulus, then pull out of seal assembly and circulate 70/30 methanol / KCl packer fluid into annulus. Space out tubing. Close SCSSV, install BPV, ND BOP equipment and NU and test 7 1/16" x 4 1/2" Xmas Tree. Remove BPV's. 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 3880 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. SECTION A 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 1064 psi. This pressure was obtained during the BHP test of May 21, 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 IS OF THE UPMOST IMPORTANCE, TRIP SPEED IS SECONDARY. Three perforated intervals are iSolated between the Otis "RH" retrievable and the "WD" permanent packer, and there are 30 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. NClU A- O3 RISER AND BOP ARRANGEMENT ! i _ i- i 6M ANNULAR PREVENTER 1OM 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 I UNIHEAD 16' 8RD X 16 3/4' 6M CLAMP HUB RECEIVED SEP -2 1994 Aie, sk~ O~i.& Gas Cons. Commiss!g~t ", ~,'~ FINAL WELL COMPLETION DIAG[ PBTD 6380' 384 612 10 3/4' 2519 TOC(~ 3700' Otis VSH pacimr 3930- 31 sqz 3964 o 3979 4000- 4025 4055- 4070 4100- 01 sqz 4178- 79 sqz packer ~ 4199 4210 - 4280 c1-1 43o0 - 4375 ci-2 4428 - 4440 ci-3 4474 - 4494 Cl-4 packer ~ 4526 4552 - 4582 ci-5 packer ~]~ 4595 4630 - 4640 c1..6 packer ~ 4669 4692 - 4697 Cl-7 4730 - 4737 packer ~ 4751 4778 - 4788 ' Cl-8 4793- 94 sqz 4810- 4820 packer ~]~ 4632 4850 - 4875 cl-9 packer ~ 4886 49o0- 4925 c~10 packer ~ 4936 4950 - 4995 c1-11 packer ~]~ 5114 5254 - 5261 5279- 5284 5418 - 5423 5565- 5570 5579 - 5584 5596 - 5603 5961 - 5971 6043 - 6058 6070 - 6080 6227 - 6252 6284 - 6289 EZSV ~ 6380 5414 - 5421 6514 - 6529 6898 - 69o8 7033 - 7040 7212- 7237 7" ~ 7475 FMC OCT RKB-DrII! De~k: FMC 4 1/2" 8rd X 4" BT&C RKB-THF: 39.94 Annulus Fluid: SaR Waler with 3 bbl Methanol RICB~L: 115.90 TOC: 3700' from CBL dated 03114/69 WATER DEPTH: 120 ' RICB-MI,: Production Casing: 41~ 41 !65 ib/R H-40 1540 45.5 & 51 lb/R 33501 26 lb/R 4660~ 23 lb/R 26 lb/R Tubing String: 325i 12.6 Ib/ft mod BT&C 6,289' 12.6 Ib/f~ mod 8rd PRODUCTION TUBING STRING Note: 8.98 ft. difference in elevation is due to assembly bein~l set on Electric 0.00 Elevation 48.92 FMC ./OCT 6" 3M4 I/2" 8rd x 4 1/2" BTC TI~ 49.62 4 1/2" 12.61bL55BTCTubin~&Pup Jts. 290.55 [ SVL_N 293.00 i/2" 12.6 lb $-55 BTC Tubin~ X-Over EU Box x BTC Box 4 1/2' 12.6 lb L55 EUE Tubing. Halliburton Upper "PBR" Ratch Latch S~al Assembly Halliburton "VSR" Packer 31.38:4 1/2" 12.6 lb $-22 EUE Tubin$ 1.44 Halliburton "X" Nipple 250.87[4 1/2" 12.6 lb $-22 EUE Tubin~ , Go Seal Assembly Halliburton "TWR" Packer & Miliout F. zaension 1/2' 12.6 lb $4 ) .Its, 4501.18 Halliburton "XD" Sliding Sleeve 4505.40 ) .Its. 4525.81 ) Go Seal Assembly 4526.93: 4749.95 4751.07 4761.71 4762.31 4825.13i 4936.48 4947.12 4947.72 5050.21l COOK INLET SANDS 3.990 4 1/2' 12.6 lb 1-55 EUE-MOD Tubing & Pup Jts. UCI-A 3964- 3979 UCI-B 4000 - 4025 UCI-B 4055 - 4070 C1-1 4210 - 4280 Cl-2 430O - 4375 C1=3 442C - 4440 Cl-4 4474 - 4494 CI-5 4552 - 4582 Ck6 4630 - 4640 CI-7 4692 - 4697 4730 - 4737 CI-8 4778 - 4788 4810 - 4820 CI-9 4850 - 4875' Ct-10 4900 - 4925 C1-11 4950 - 4995 *** New Perforations Halliburton 'XD" Sliding Sleeve & Pup JL Go Seal Assembly Halliburton "TWR" Packer & Millout Extension 51.60 4 i/2" 12.6 lb J-55 EUE-MOD Tubing & Pup Jts. 2.62: ~ Jr. Halliburton 'TWR" Packer & Millout Extension 1/2" 12.6 lb $-55 EUE-MOD Tubing Hallibmlon "XD' Sliding Sleeve & Pup Seal Assembly Halliburton "TWR" Packer & Millout Extension 4 1/2" 12.6 lb $~55 EUE-MOD Tubing Halliburton "XD" Sliding Sleeve & Pup Jt. Go Seal Assembly Halliburton "TWR" Packer & Millout Extension 4 1/2" 12.6 lb L55 ED'E-MOD Tubing Halliburton "TWR' Packer & Millout Extension 3.813 4.000i I/2" 12.6 lb L55 EUE-MOD Tubing Halliburton "XD' Slidin~ Sleeve & Pup St. Seal Assembly Halliburton "TWR" Packer & Millout Extension 4 1/2" 12.6 lb L55 EUE-MOD Tubin~ Halliburton "XD' Sliding Sleeve 4 1/2" 12.6 lb J.55 EUE-MOD Tubin~ Go Seal Assembly HallibuRon 'TWR' Packer & Millout Extension ~ Adaptor 4 1/2" 12.6 lb .L55 E-dE-MOD Tubin~ Halliburton "XA" Sliding Sleeve 3.992! 3.813; 1/2" Halliburton "XN" Landing Nipple ' Guide End of Tubing BELUGA SANDS "Upper' 5254-5261 5279-5284 5418-5423 "Middle' 5565-5570 5579-5584 5596-5603 5870-5880 5961-5971 6043-6058 6070-6080 6227-6252 6284-6289 "Lower' 6414 - 6421 6514 - 6529 6898-6908 7033-7040 7212-7237 Not To Be Re-Perfor at~d PBTD: 6380' [Supv: Well: North Cook Inlet Unit No. A-03 JTb~ Wt: 4"- 10.9 ib/ft 3 1/2' - 9.3 lb/R [ November i 7, 1994 TD = 480' Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit MPG PBTD 7429' TD,= ,7~480' 384 612 10 3/4' @ 2519 TOC 0 3700' Offs RH packet 0 3727' Sands 3930 - 31 sqz 3964 - 3979 4O55 - 4O7O 4100 - 01 sqz Otis WB packer 04115' 4178 - 79 sqz -~- 4210 - 4280 :~ 4300 - 4375 1. 4474 - 4494 ~ 4552 - 4582 ~ 4630 - 4640 ~.. 4692 - 4697 ~ 4793 - 94 sqz 4730 ' 4737 4778 - 4788 4810 - 482O 4850 - 4675 4~o - Beluga Sands 5254 - 5261 5279 - 5284 5418 - 5423 5565 - 5570 5579 - 5584 5870 - 588O ~ 5961 - 5071 1. 8O7O - 8O8O 6414 - 6421 6514 - 6529 7033 - 7040 7212 - 7237 7 · @ 7475 BP~ EXISTING WELL COMPLETION FMC OCT Deck: Annulus Fluid: FMC 4 1/2" 8rd X 4 "BT&C Salt Water with 3 bbl Methanol RKB-TH1~ 39.94 RKB-~: 115.90 TOC: 3700' from CBL dated WATER DEPTH: 120 RKB-ML: Production Casing: 41 384 41 612 41 45.5 & 51 79 Tubin J-55 J-55 J-55 J-55 BT&C BT&C BT&C BT&C 1540 6OO 335O 4O8O 3-55 I BTaCI 51So 9.3 ,b/ft 3-55I BTaCi 5310 ~:.':: ' ....... !:::~Oescriptionj:: ::ii' ::. ::: "::.::: '==:::!ii: 5730 644O PRODUCTION TUBING $TRING 0.00 39.94 Elevation 39.94 40.94 247.08 4.42 292.44 7.50 299.94 3418.91 3718,85 1.07 3719.92 1.00 FMC I OCT 6' 3M 4 1/2' 8rd x 4' BT&C Tubing Hanger J-55 BT&C Tubing AO Ball Valve Nipple and SCSSV Camco KBM 3 1/2" GLM 10.9 lb/it J-55 BT&C Tubing 4" BT&C x 3 1/2" X-OVER 3727.42 7,00 3734.42 337.91 Camco KBM 3 1/2" GLM Otis 7" x 3 .... RH" Hydraulic Set Retrievable Packer 3 1/2" 9.3 lb/it 3-55 BT&C Tubing & Blast Joints 4072.33 3.69 4076.62 6.00 4082.62 1.50 4083.52 31.20 4114.72 0.28 11.20 4126.20 15.00 4141.20 414Z70 4152.65 4153.93 "XO" Sliding Sleeve 3 1/2" 9.3 lb/it J-55 BT&C Tubing Otis 3 1/2" "X" Nipple 3 1/2" 9.3 lb/it J-55 BT&CTubing Otis Seal Assembly & Straight Slot Locator Otis 7" x 4" "WB" Permanent Packer 3 1/2" 9.3 lb/it J-55 BT&C Tubing 1.50 Otis 31/2" "X" Nipple 9.95 1/2" 9.3lb/ft J-55BT&CTubing 1.28 Otis 31/2" "Q" Nipple End of Tubing 3.958 3.476 2.760 2.991 3.476 2.992 2.991 2.750 2.750 2.992 2.750 4.00 2.992 2.750 2.992 2.625 PRODUCTION PERFORATION INTERVALS COOK INLET SANDS UCI-A 3964 - 3979 UCI-B 4000 - 4025 UCI-B 4055 - 4O70 C1-1 4210 - 4280 Cl-2 4300 - 4375 Cl-4 4474 - 4494 el-5 4552 - 4582 C1-6 4630 - 4640 el-7 4692 - 4697 4730 - 4737 Cl-8 4778 - 4788 4810 - 482O Cl-9 4650 - 4675 C1-i0 49OO - 4.W25 el- 11 4950 - 4995 PBTD: 7,429' J Supv: Well: North Cook Inlet Unit No. A-03 Location: Lower Cook lnlet~ Alaska BELUGA SANDS 'Upped 5279 - 5284 5418 - 5423 "Middle* 5585 - 5670 557g - 5584 5566 - 5803 'Lower' 5870 - 5880 5061 - 5071 0O*,3 - e058_ 8070 - 8080 6227 - 6252 5414 - 8421 6514 - 6529 8898 - 8906 7033 - 7040 7212 - 7237 { Tbg Wt: 4" - 10.9 lb/ft Field: Cook Inlet Unit 3 ]/2" - 9.3 lb/ft August 08, 1994 PRD PHILLIPS PETROLEUM KENAI, ALASKA 99611 P.O. DRAWER 66 EXPLORATION AND PRODUCTION DEPARTMENT Kenai Plant December 11, 1975 File: P-NEP-k4-75 COMPANY CONFEI4~ Dzv~szon of 0m± and Gas State of Alaska //~ /"' / 3001 Porcupine Drive cnora e, Reference is md~e to your letter of December ~ 1975 inq~~formed the proposed workover of oU~CIU A-3 well.~ This well was not worked over this We apologize for the inconvenience our oversight in not notifying you earlier may have caused. A new form 10-403 will be submitted when our workover program is reS~umed. N. E. Porter Sr. Petroleum Engineer NEP/eh Form 10-403 REV. 1-10~73 Submit "Intentions" 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.) WELL ~ OTHER 2. NAME OF OPERATOR Phillips Petroleum Company' '3. ADDRESS OF OPERATOR P. 0o Drawer 66, Kenai, Alaska ??611 4. LOCATION OF WELL At su~face Leg 3, Slot 7,1250' FNL, 1087' FWL, Sec. TllN, R9 W, S.M. BHL 1~54' FNL, 24~9' FELt Sec. 1, TllNt RlO W, S.M. 13. ELEVATIONS (Show whether DF, RT, GR, etc.) RKB 116' from Mr.LW 14. CheCk Appropriate Box To Indicate Nature of Notice, Re [5. APl NUMERICAL CODE 50-28.3-20020 !6. LEASE DESIGNATION AND SERIAL NO. ADL- 18755 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME 9. WELL NO. 10. FIELD AND POOL, OR WILDCAT North Cook Inlet 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See Item 4 BHL 12. PERMIT NO. 68-99 )ort, or Other Data NOTICE OF INTENTION TO.' I SHOOT OR ACIDIZE ~ ABANDON* REPAIR W~=LL J I CHANGE PLANS (Other) Clean out-/--P~rf. 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 10.5 ppg mud. Remove tree. Install 12'~3000~ WP riser and 12" 3000~ WP double gate preventor and F~dril. Test BOP and riser. 2~ Pull 4" tbg and retrievable packer. 3~· Perforate Cook Inlet 4000- 4788 MD RKB overall. Run combination 4" X 3~" tubing string with Obis subsurface safety valve set about 288' RKB and Obis retrievable packer set about 3930' MD RKB~ a~xi tubing set 6535' 6, Clean up well and conduct 4 point BPT. . 7. Ubilize as a producer commingled ia Cook Inlet and Beluga pays. ,tltl 1 1975 · . Estimated start of Operations is 7/12/75 ~,t/J;:~.t~.,~ {).[" OIL 16. I hereby going is true and correct (This space for State office use) CONDITIONS OF APPIR~AL, IF ANY= ~ved ~. Re~med ~e Instructions 0n Reveme Side PHILLIPS PETROLEUM ANCHORAGE, ALASKA 99501 ~ 515 "D" STREET EXPLORATION AND PRODUCTION DEPARTMENT COMPANY June 26, 1969 Mr. T. R. l~rshall, Jr. Division of Mines & Minerals Department of Natural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska Gent lemen: As per your request, please find copies of blue line Electrical Logs for NCIU #A-l~ #A-3 and #A-~. I~ at all possible, these blue lines will be ~hed with Completion Reports, in the future. · JBG: jo Attac~nent Yours truly, HILLIPS PETROLEUM COMPANY / / Jo~u B. Gip-9on~,~'~- -M / / D~trict Office ~n~ger PHILLIPS PETROLEUM COMPANy ANCHORAGE, ALASKA 99501 ~ 515 "D" STREET EXPLORATION AND PRODUCTION DEPARTMENT April 16, 1969 DiviSion of ~-ines & Minerals Department of Natural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska Attention: Gentlemen: Mr. T. R. M~arshall, Jr. Enclosed please fin ~o~ o~o~ ~ ~ ?~ct~ oo zurntshed yo'- ~,~n±et Unit We~l~Y~?f_Perlbratin~ ~_~ ~ ~'~ earlier. ~ ~a-3. Ple~o~ ~ ~u oqueeze Rec~ ~ Ges~roy the co Thank you for your COoperation. PY JBG: Jo Attachment Sincerely, PHILLIPS PETROLEUM COMPANy RECBVE?) APR 17 19~Q DIVISION OF OIL AND OA$ ANCHOitAO! ~' ' HLB i: SUBMI? Z~ ~V~mCxtZ* j OKG STATE OF ALASKA ]~ ~ ~ (Seeotherm-J ZlV 3 ": . - structions on- ~" ~' +~ ~ - ~ t reverse side) B. ~I N~~ CODE OIL AND GAS CONSERV~N~ COMMITTEE : i HW WEL. L.~.C.Q.... PLEI!ON. QLSECQ~.LE~O.N~.~~~T AND LOG- J ~x~ TYPE OF WELL: OIL ~ GA8 ~ ~ ~ h~ ~ ,; ~ .... - .... WELL ~- WELL ~ DRY ~ Ot~ ? f~ ~ ~. IF ~I~, ~~ OR~ WELL ~ OVER ~ EN ~ BACK ~ ' E~.~:~ Ot~ ~ " ~ I' ' 515 "O" Street. ~ehe~e. ~s~ 99~1 I i :, ~ ./ .:lXO. r~~V~L; oaw~~ At top prod. interval reported below ~O1 ~ ~- ~2~J ~ '" ~ ~ ~..J.: .~4~,~1" ~- ~Oe~ '~ .................................................... '-" - * :- ; ":' ':' '~ 8 ..A -' . -- · ; ~W~Y* ! i a0Tiae o s '- ' ~ CABLE TOOLS m.!PRODUCING m'r~VAL(S), 0r T~'.~~X~~, ~M. N~ (~'~':~)* . ~- ~ : .... I~.'W~ ~uee~ ~et - ~09~.~.(376k"_~)te ~'.~.~3~' ~). :- .. ~ I . F',r 0 ,. ~ . : CAS~G ~ (Re~ all strips set ~ will) .... . . ' .~,: irt .,, i ~. &s~ :: ;; ~ / a~ 16aa, .~a'. ! ~ "' " " " ....' n I : ' :", ~ i: PRODUCTION' I ,' "If - _ .i. l'l '~"" :,:I _ [ : - ICTION METHOD (Flowing, ~ lift, pmpin~--~lze and type oJ' p~p) ' DA.TE FIRST PRODI.I~I'ION DATE OF TEST. ~OLTRS TE~'rI'ED': F~21~l :. FLOW TUBING [ DISPOSITION OF GAS (~O~d) .... ~ . . '. net WA,THP,~BBL. -: LIST hereby eert~y tbs ?the !oreg0!ng anti--attached information la complete and eorrebt as determined from aZlV,V~l'iable ree&~-S '~ .... [, ; .r . / , · · ~ ~ *(~e I,,tructions and S~ces for Additidnal Data on Reverse Side) - INSTRUCTIONS ,z ,' - :. _ ] ".'t!~ ..... · . ~*~ ....... . ':: ' ~*m · ~' C,~enerah This form is designedl;~or submitting a c~lete and correct wel~ completion ~e~¢rt an~ Jog ..* . all types of lands and leases in ~'laska. '7' ~' ' '/~: ~--~ *~ It~: 16: Indicate which elevation is ~ed '~aS '-"-reference (w~ere n~t otherwise sho~n~gf~r .d~, _ measur~ merits given in other spaces on is form and in any attachments. -. -o c_a t-: o .~ .- ' Itemi:,20, ,nd 22:: If this well is comp(~ted f°'r ~eParatc production from mo,% t~an: 8~eOSi~rval zon~' (mu tiple completion), so state in item:.~O, and in item 22 show theprcduong' m~r~al,;~- oe° ~ntervals;' ':: ' ' a c:'~ ' ' "rEnu 'se~Lr~te~ 'top(s~ bottom(s) and name (s) {if any) fo~'~n[y 1he interval reported in .item 30. Sub~ ~' ~ ' · .. 0 t ~ '.T; ' . " ~U~!t-a--' on ~hi~ ~torm, a~uate'--'-'em'~'~'''~eq W-~ ~,! o~ ~'~rf~ach additional inte~ val. ~ -- '}'xh -.: ,-.¢ __ r:,~ . _ o ~ sepera~e~y proaoc~,~snow~ ing the a~itional data-perfin~ to sO~h'-i~6{al.' .... .o ';-- o .q" .,v : .... -: (?. , c.- I~m26: '~cks Cement": ~.ach~d suO~le~n*~l iecords for thi~>Well ~hould sh6W :i'~eiai~ o{ any tiple stage cementing and the 'location~of~ ~menting t~l. ,..;~ ~;. ·.,~ . 0 }-~ km M " .'~ Item 28: Submlt' a ~parate completion~r~rt Bh this form {pr._~ach intergol to ~ s~arately prod~. ' C~ 'C~ I -m >. · . .CF 34. SUMMAI~.Y O~ FOI~fATION Tlc'-~TS ~'I~CLUDIN(I INTERVAL ~D. P~~ ~A~ ~ '~OV~ ,0~ OIL'. O~. ': 0J : ,. " :' 71 ~.- ' N~ .' . ~..,, 1 ~.-: '.,3 : ' . ,.....;~? ~:O · · ~ O ', - · . , , ;., .. .... . -- 'l'J · : · * [.) -' ' : , '; ;. .; ?% ?:x :'(~:~ ~'~ ;n. U¢~r ~k'~ ~e¢ 3962 -)z-,"...~ !..9 ' ." ~'--.<'.-- ~.: ..... fi_~ ,; ' , i *'- 0 . ' ....... ' ' ' ." :"* 'th' -'/:-.l -- ' '~ i'--~ -~ , ' ' ~ ~ ' : c'" " ; . r i- : ~ .?-. 2.~ - :"0 b'-~ ~ . . . _' ~ .. T" .. ,":,'~.~ 't :--] ".'.','*: ~) ,'..~. c~..(3 , . · .. <~ .'(~ r'.','-.~ ~7. -.,3 i..~ , :.t 7,.: ' :~ ' ., ~ - · .... ~ , .. ' ':: ..... C; '' O ) ' '-' ,~ ,'O ,7 f ~ --'~ 0 : · 23 :-~ AND DETECt'ED.: SllOWS OF OIL, G~ OR' WA~.' - ~' ' ~.') - "9' ' ~ , ,, , .~ ! '~- ..-'~ 7 :_ . ' .. '~ f~ -: .. ' ' . 2: " ~- ~ ' ' ' ., , .- . . ... --.~ ) ,:_~ 0 . .:r C.., ' ~,) r) 'C.': / ,'3 -- ',: ~_,. ,.'..: . ,,,, .:: .... . ' ~0 ' - ' ..... ' '- ,'."~ 1 '~ ,'~ .-:. ,..~ .~ ..... ....... ., 12 .... :~ ..-_ ..... e~ ~-, ....- .. 5~ -.' ..... ¢,, .. ft.:."u'' ' C,,' ': '::~ 'j.Z · ':..~] .o .... z ......... . .--, : - · ' ~ ,. . .. ~ ... : ~ .. ~": I ~-.~ " ~ ~'.f,~.~ .: ~ 2.) · ~ · - ,,n~ -,. .... : ...... '~ . "~ F"~O,'.'. '~; . I ' .... ' ',..-~ .. I"~ .,t.~ f .. ~ ~ :. : ' O O '(7- . }-'~ ,"'~.~ .1:~ /':~ , '' " ':: ' ' "]"t 'J.(7 - ~ ~ ', ~ '~.;.- ' ~ t , Form 8~2 12-57 A 6012S PHnfed in U.S.A. North Cook Inlet Unit Lease ADL-17589 · ' RECEIVEi) APR 1 ? 1969 DIVISION OF OIL AND OAS PERFORATING AND SQUEEZE RECORD ANCHOi~.GE CORRECTED C~PY Well_ #A-3 Dale 3-16-69 3-(~ 69 11' Il Il !t ti Ii II Il 3-8-69 Size of Casting 11 Il II tl Il II Il Il II II Il l! Il II II Il tl Il II Il Il II Il Il To IES 72/2' 7033' 6898' 6513+' 64]4' 628~+' 6227' 6070' 60~+3' 5961' 5S7o' 5834' 5596' 5579' 5565' 5418' 5279' 5254' 4950' 4850' ASlO' 473o, Pentoraf;ng From Feet Perforated 4692, &552, &o55, &ooo, ;UREMEt~S 7237' 70~0 ' 6908,~ 6529'/ 6~%1, ~ 6289'/ 6252t ~ 6080,/ 6058' 5~i, 58~'w 5603 ' 5570,~ 5~3'~ 5261' &995'~ &925'~ ~5'~ ~0,/ ~737'~ 25' 7' l0t 15' 7, 25' 10' 15' 10' 10' 10' 7' 5' 5' 5' 5' 7' ~+582'/ &070'~ &025'* :LOt 51 10' 30' 20' 15' 25' THe ~-~-llowi~ ~i00' 3.9.30' 3979' ¥ g perf's we] 4794' &:L79' 4101' 3931' ]~5t ~ s~eeze 1' l' l' l' Holes 100 28 6O 28 2o 100 60 &O &O 28 2O 2O 2O 28. 180 100 I00 28 2O 120 100 · Size of Holes · 50 w/no plug shape charge Gun Diameter ~i~II II II II II l! II Il Il Il II II tl I1 I! I! Gun Type Carrier Per[orating Company Schlumberger Form 852 12-51 A 6012S P4nted in U.~. North Ceok !~et Le~se ,,ADL.i~589 APR 1 ~719~o DIVISION OF OIL AND GAl ANCttOCU'.GE PERFORATING AND S9UEEZE RECORD CORRECTED COPY Well_ #A-3 Date Size of Casting 3-16-69 Il oo It il II II II il ~" ,:. I! Il Il Il I! tl I! !I ti !! $1 ~-8~9' ti Il 11 It I1 I1 tl I1 . I! · · :. ~ i · I! 11 I! 11 PerForating i~S MEA~ 7212' 7033' 6898' 65]J+' 6~1/+' .- 628/+' 6227' 6070' 60~3 ' 5961' 5876' 5596' 5579' 5565' 5/+18' 5279' 525/+' ~810' ~692' /~630' ~552' /~055' The followi~ /+793' . ~178' /+100' 39~30' From UP~,~ENTS 7237' 7o~o, 6908, 6529' 6/+21' 6289' 6252' 6080' 6058' 5971' 5880' 5603' 558/+' 5570' 5~23' 528~' 5261' /+995' /~925' /~820' /+737' /~6&O' ~o?o, ~o25' 3979' perf~s ~79~'. ~179' ~101' 3931' Feet Perforated 25' 7' 10' 15' 7, 5' 25' 10' 15' 10~ 10' !0' 7' 5' 5' 5' 5' 7, ~5' 25' 25' 10' 7' 5' 10' 30' 20' 15' 25' squeeze 1' 1' Holes 100 28 6o 28 20 100 6O 28 2O 2O 2O 2O 28. 180 100 100 ~o 28 2o 12o 100 ~0 Size of Holes .._ .50 w/no. plug shape charge I! II I1 II . I! GUll Diameter II 11 II II Il II II Il II II II Il Il Il II II II II Il II Il Il Il Il Il Il II II ' Gull Type Carrier Il Il Per,~orafing Company __ Schlumberger Il II Il' PHILLIPS PETROLM~M COMPANY N.C.I.Unit #A-3 North Cook Inlet Field Cook Inlet, Alaska 27AO- 3250 3250- 37OO 37OO- &l~5 ~l&5 - ~200 &2CO- 5000 5000- 55&5 55&5 - 5600 56OO- 5885 5885 - 6O65 6065 - 67OO 67OO- 7O30 7O3O- 7195 7195 - 723© 7230- 7~80 SAMPLE DESCRIPTION Sand; med gy, cg, sctd pebbles, poorly srtd, ang-subang, w/sctd gy clyst and coal beds. No samples. · Sand; dk gy, f-rog, mod srtd, pred. qtz. w/some claystone and coal beds. Claystone; gy, slty, sli carb, med hd w/coal beds. Sand;' med gy, rog, subang-subround, 'mod srtd, prod qtz. w/abnt multi-colored grains w/gy claystone and w/sctd co al beds. Claystone; gy to bm, silty, soft to firm, w/thin sand, siltstone, and coal beds. Sand; mod gy, f-rog, subang-subround, poorly, srtd,~-pred. qtz. w/abnt gy smoky qtz. .... - Olaystone; gy, slty, soft; w/thin sand, siltstone and coal beds. Sand; it 'gy, fg, mod. srtd, pred. qtz. w/some interbedded claystone and siltstone. Claystone; gy, slty, soft w/interbedded sand. Claystone; tan, firm; w/interbedded sandstone, siltstone, and coal. Claystone; tan, firm; w/thin siltstone and. sandstone stringers. Sandstone; meal gy, fg, sli slty, calc, friable. Siltstone; gy, sli clayey, calc, mod hd to hd, w/sctd thin sandstone and coal beds. ~arch 25, 1969 C12de R. Seewald RECEIVED APR 10 1969 ~JVmION o~ om A~D OAS PHILLIPS PETROLETB~ COMPANY N.C.I.Unit #A-3 North Cook Inlet Field Cook Inlet, Alaska 27&0- 3250 3250- 3700 3700 - Al&5 &l&5 - &200 &200- 5000 SO00 - 55&5 55&5- 56OO 56OO- 5885 5885 - 6065 6065 - 6700 67oo- 7O3O 7030- 7195 7195 - 7230 723o- 7&8o SAMPLE DESCRIPTION Sand; reed gy, cg, sctd pebbles, poorly srtd, ang-subang, w/sctd gy clyst and coal beds. No samples. Sand; dk gy, f-rog, reed srtd, pred. qtz. w/some claystone and coal beds. Claystone; gy, slty, sli carb, mod hd w/coal beds. Sand; reed gy, rog, subang-subround, mod srtd, pred qtz. w/abnt mmlti-colored grains w/gy claystone and w/sctd coal beds. Claystone; gy to bm, silty, soft to firm, w/thin sand, siltstone, and coal beds. Sand; mod gy, f-rog, subang-subround, poorly srtd, pred. qtz. w/abnt gy smoky qtz. Claystone; gy, slty, soft; w/thin sand, siltstone and coal beds. Sand; It gy, fg, mod. srtd, pred. qtz. w/some interbedded claystone and siltstone. Claystone; gy, slty, soft w/interbedded sand. Claystone; tan, firm; w/interbedded sandstone, siltstone, and coal. Claystone; tan, firms~ w/thin siltstone and sandstone stringers. Sandstone; med gy, fg, sli slty, calc, friable. Siltstone; gy, sli clayey, calc, mod hd to hd, w/sctd thin sandstone and coal beds. March 25, 1969 Clyde R. Seewald RECEIVED APR 10 1969 ~I¥1SIOH OF OIL AND UHRONOIDGIQA,L ,,,WELL ~IST,OR~, RECEWED APR 10 1969 DIYIgON OF OIL AND GA~ Spudded from Surface. Drill 15" hole & ream to 22" to 630'. Set 16" casing at 612, and Cemented w/735 sacks cement. Suspended. Waiting on rig. Skid Rig on Slot and test BOP' s. Drill 15" hole to 2550'. Set lO-3/&" casing at 2518.90' and cemented w/l120 sx Type "G" cement mixed in 8#/bbl prehydrated zeogel and inlet water, tailed in w/125 sx Type "G" cement mixed in 15 bbls inlet water w/2% cc. Drill 9-5/8" hole to 5~20'. Drill 9-5/8" hole to 7&80'. Set 7" casing at 7~75' & cemented w/515 sx Class "G" cement mixed w/135 bbls prehydrated 10% Diacel "D" - 2% CaC12. Pumped plug to 7~29' w/2000~, held O.K. Dropped stage collar, opened bomb and attempted to establish 2nd stage circulation, could not. Set 7" Packoff. Tested to 5000#. O.K. Pushed top cement plug to stage collar at 5114' RKB & tested to 2250 PSI. O.K. Perforated 1', ~793'-&79&' IES, squeezed in 27 sx Class "G" cement. Perforated 1', ~178'-~179' IES, squeezed in ~6 sx Class "G" cement. Perforated 1', ~100'-~101' IES, squeezed in 15 sx Class "G" cement. Perforated 1', 3930'-3931' IES, squeezed in ~6 sx Class "G" cement. Tested perf's. Resqueezed perf's 3930'-3931' w/91 sx Class "G" cement. Resqueezed perf' s ~793 '-&79~' w/82 sx Class "G" cement. Resqueezed perf' s &178'-~179' w/92 sx Class "G" cement. Resqueezed perf's &793'-~79~' w/ 65 sx Class "G" cement. Ail perf's test to 2500 PSI, O.K. Perforated 7212'-7237', 7033' - 70&O', 6898' - 6908' IES Meas. & test. Flowed 6 hrs on 3/&" choke. FTP 250 PSI, FARO ~076 MCFD, flowed 6~ hrs on 3/8" choke, FTP 885 PSI, FARO 3392 MCFD, Flowed 1¼ hrs on ¼" choke, FTP 1575 PSI, FARO 2697 MCFD. Perforated IES Meas. as follows: 6514'-6529', 6~14'-6421', 628~'-6289', 6227'-6252', 6070'-6080', 60&3 '-6058' , 5961'-5971', 5870'-5880', 583~'- 5844', 5596'-5603', 5579'-558~', 5565'-5570', 5~18'-5~23', 5279'-5284', 525~'-5261', ~950'-~995', ~900'-~925',~850'-~875', ~810'-J+820', ~730'- ~737', ~692'-~697', ~630'-~6~0', ~552'-~582', ~47~'-449~', ~055'-~070', &000'-~025' & 3965'-3979'. Ran combination 3½" and ~" tubing string, Set &121' RKB. Test perf's &055'-~070', &OOO'-&025', 396&'-3.979'. Flowed 3 hfs on 3/&" choke, FTP 1225 PSI, FARO 19.O MMCFD. Flowed & hrs on &O/6&" choke, FTP 1336 PSI, FARO l~.3& MMCFD, Flowed ~ hfs on 32/6&" choke, FTP 2439 PSI, FARO $.66 MMCFD, Flowed 1 hr on 28/6~" Choke, FTP 1&46 PSI, FARO 7.3 MMCFD. Completed as NG well in Beluga Formation (SI) Lower Cook Inlet Sands (SI) Upper Cook Inlet Sands (open-perf's 4055'-~070', &000'-~O25' & 396&'- ~9~9' XE$ Meaa. DROP FRG~..E~_RT. . STATE OF ALASKA. OIL AND GAS CONSERVATION COMMITTEE GAS WELL OPEN FLOW POTENTIAL TEST.· REPORT SUBMIT ~ DUPLICATI~ , ' D ',' TBG. Size '~Vt/Ft. O.D. ;i.-':' _ Pip?~'onnectlon ~Jultlple Completion (Dual or Triple) · JType I~roduetion from each zone 'OBSERVED DATA i .' Flow Data ;i" Time (~t*e~-r~ . (~he4+~ 'Press. Diff. Tubing Casing Fiowinr .~o. of Flow (Line) (Orifice) h ' Press. Press. Temp. Hours Size Size pslg w. psl~ polk oF s,. _ ' ~...,~ _. . ' ..... ' . . ~ ~>,z~ ~.~L~", .... ~.g ~ ~,' / /b'~ ~ ~ ~... / .. . ~ ~/ ~~ //~ ~ .... 1~~ ..... ~ . . FLOXV CALCULATIONS Coeffi- - ..... . Flow Temp. Gravity Compress, lqO. cient ----~/h p Pressure Factor Factor Factor Rate ~f Flow (24 Hr.) VW m psla F F F (~ ~fCF/D t ~ pv ..',' ........ ,. ~,~7' .".'?:~,.~ "~?~. y ., c~:/~ ·/,~/ . /, o~- ,.. /~. ~ ...:-.: {...~,...~ ~ ~_~ ~ ~ ~ ~ ~, ~ ..... ~ . ,.~. ~ /~~, ~ ~ , ~.~~ . ~ . /,.~-,~pc, ~.=,,~:~.' :~.....:..- ,..' ·/ ~/y.~, 0 ~~, 7 , ?~ ~7 _../ .. _'../,.o_~ ..... ~' ~~. "-.::::' ,.' ~ ~2. ~ ' '/o~, -1 · ~~ -... _ ~ /, ~~. ~./~ .-.'" - P.~.s~?~ ca~u~.~,?~ ........... ..... ~:~. P P w ~aL w P (p. ln) ~ ~ Q (F Q)t (F Q)s X 1-·;m' ' ps ~ _ ~ p ,t e O e . W 0 W W t -. , , , ,, , , , , t t , ,, .... , ,, , , , ...... - ............... '- b:~?o. ~~ /. ~ , G~ ? 2 ......... , .... ...... ~ ~ . ~.: ........... ' . .............~Y /.S~ <~ ~ 7 , ~,.~ , .................... - ...... . ............. ~.5~. t' /_~ ~/~ 1~0~ , ~ //. Almolute Potential - j n · '.-... ~ (~p~), ~ ~at I am ~~ by smd ~p~y ~ m~ ~ ~ ~ ~at ~ ~ woe ~ :., ; - ... .. ." . ::.. ' . -~-~~ ................. . - . rm P--12 -~ .-'--' STiT~ OF ALASr, A OIL. D cO s RV, O . '~ & Date "~ "=' ~ Tested Z,~se ' ~. ...= P, ESERVOH~ PRESSURE REPORT · . ,.~ . ' .: ~A~dress ' [county ~.-~~,~,~ ,, Initial Completion® ~ Special* Bomb Test Data Shut-In - ' Test Tubin~ Observed (Bbls. per Day) Pressure Pressure ... CERTIFICATE: I, th~ undersigned, state that I am the ..... of the eSee Lnstmct/ons on ReverSe/~e ,. . (company), and th'at'I am authorized by said company, to make this reporti and that this report was Prepared under my supervision and direction and that the facts stated therein are true, correct and ~omplete to the best of my knowledKe. . · , :'.' .:~.- ,.'-,: ~:::!":'.?.~.': .": ' "'. '::[/' .,,ns,ute ; i · Oeneral Surveys ] D~tum Plane [ Gas GravltF i~onic Instrument Test Dat~ I Pressure Wt. of 1 Ca~ing at ! Pressure i Datum · ,.~ ~ OF SER1/ICE ~ REPORT o~ SUB-SURF,ACE DIRECTIONAL SU RV""~Y I~CB1/ED ; APR ~PHILLIPS PETROLEUM COMPANY NORTH. COOK INLET TY~ OF SU['~¥'~Y DA~,:" $1N(ILE SHOT FE:B',IaARCH · · ANCHORAGE ASURED DEP T H [Gl N 700. 748. 78O. ..812. 844. 887. 950. 1142. 1241. 1332. 1422.. 1521. 1614. 1707. ~'"" 1.8 01. 1863. _1967. 2092. ~ 2247. 2403. 2550. ~ 2686. .2841, 3009, 3141. _332.9, 3390, ._3451 ·. 3513. PHILLIPS COURSE - - D LENGTH ANGLE LOCaTEu AT MD =- 103. 1 15' 48. 3 15' 32. 4 15' 32. 5 45' 32. 7 15' 43. 8 30' 63. I'0 15' 96. 13 O' q6* 16 30' 99. 18 15' 91. 19 15' gO; 20 O' gq. 22 45' '73. 26 15' 93. 29 30' 94, 32 45' 62. 35 15' 104. 35 15' 125. 35 15' 15~. 35 O' 156. 34 15' 147. 34 30' 136. 33 O' 155. 31 15' 88. 29 15' 80. 29 45' 132. 31 45' 188. 27.%5'. 61, 27 45' 61. 28 15' 62. 28 30' w E t L C O M P L E T I .. PETROLEUM CORP. A'3 LEG 3 SLOT ON. REPORT 7 03/04/69 PREPARED BY SCS E V I & T I 0 N - C 0 U R DIRECTION AMOUNT V.DEPTH LATITUDE = 599.89, 2 · 18 99.97 2.72 47.92 2.37 31.91 3.20 31.83 4.03'31.74 6,35 42.52 11.21 61.99' 21,59 93,53 27.26 92.04 31.00 94.02 30.00 85.91 30.78 84.57 38.28 91.29 41.13 83.4O 45.79 80.94 50.85 79.05 35.78 50.63 60.02 84.93 72,14 102.08 88.90 126.96 87.79 128.94 83,'2.6 121,14 74,07 114.05 80,40 132,51 42.99 .76,77 59,69_ 69,45 69,4.6 112.24 TVD LATITU O. O, O. O, O, 1, 3, 7. 9. 10, 10. 10, 11. 12, 12. 14, 9, 18, 21, 21. 15, 16. 19, 11, 11, 23. 4, 4, 600.00, N 88 W S 87 W S 85 W S 84 W S 84 W S 78 W STOW STOW S ?0 w S 70 W S 70 W S 7I W S 72 W S 73 W S 74 W S 74 W S 74 W S 74W S 75w S 76 W S 76 W S 7.9 .W S 77 W S 76 W S 75 W S. 73 .W S 70 W S._81 S 81 S 82 S 82 W .......B7..53. 166.37 W 28.40' 53.98 W .... 28.87 53.73 W 29.58 54.48 PAGE 1 T'ANGEN'T I AL METH06 DE = 07 N 14 S 20 S 33 S 42 S 32 S 83 S 38 S 32 S 60 S 26 S 02 S 83 S 02 S 62 S 01 S 86 S 54 S 67 S 50 S 24 S 88 S 66 S 45 S 12 S 60'S 75 S 69 S 44 S 01 S 11 S S E - - - T DEPARTURE V.DEPTH 7,66, 2-18 W 2.71 W 2.36 W 3,18 W 4.01 W 6,21 W 10,53 w 20,29 W 25.62 W 29,13 W 28.19 W 29. IOW 36.41 W 39.33 W 44.02 w 48,88 W 34.39 W 57,69 W 69.68 W 86,26 W 85.18 W 81.73 W . 72,17 W 78,02 W 41,53 W 37,96 W -65.27 W 86.45 .W 28.05 W 28.59 W 29.29 W DEPARTURE = 699.86 747.78 779.70 811.54 843.28 885,81 947,80 1041.34 1133.39 1227.41 1313.32 1397.89 1489.19 1572,60 1653,54 1732,60 1783.23 1868.16 1970.24 2097.21 2226,16 2347.31 2461.37 2593,88 2670,66 2740,11 2852.36 ., .3018.74. 3072.72 3126.45 3180.94 0 T A t LATITUDE DEPARTURE -5.96 7.73 N 7.59 N 7.38 N 7.05 N 6.62 N 5.30 N 1.47 N ,5.91 S 15.23 S 25.84 S 36.10 S 46,12 S 57.95 S 69.98 S 82,60 S~- 96,61 S 106,48 S 123,02 S' 8,14 W 10,85 W '13,22 W 16,40 W 20.42 W 26,64 W 37.17 W 57,46 .W - 83.09 W 112,22 W ) 140,41 W 1.69'52 W 205,93 w 245.26 W 2Bg. 28 338,17 W. 372,56 W 430,26 W 141.69 S ~.,..499.94 W~ 163.20 S 586.21 W 184.44 S 671,40 W .... 200,33. S ~-753..13..~ 216.99 S 825.30 W 236,~5 ~ .. 903.32 247.57 S 944,86 W 259.18 S . 982.82 282.94 S 1048.09 W 296,63 .$ ..... 301,07 S 1162,60 W 305.09 S 1191,19 W 309,21 S 1220.49 W o. · W E L L C O M P L E T I ON R E POR'T PHILLIPS PETROLEUM CORP. A-3 LEG 3 SLOT 7 03/04/69 PREPARED BY SCS - ~PAGE 2 · TANGENTIAL METHO[~''''< EASURED COURSE - - D E V I A T I 0 N - C 0 U R S E DEPTH LENGTH ANGLE DIRECTION AMOUNT V. DEPTH LATITUDE DEPARTURE T 13 T A L .... V.DEPTH LATITUDE DEPARTURE 3606. 3728. 3884. 4008. 4146. 4344. 4487. 4641 · 4985. 5172. 5390. 5513. 5669, 5855. 5978. 6196. 6415. 6509. 6694. 6911. ?34 i'. ?48O. LOSU~t. 93. 28 30' S- 83 W ' 122. 29 45' S 85 W 156. 32 30' S 86 W I24. 35 O' S 87 W 137. 35 ~0' S 87 W 199.. 36 30' S 89 W 143. 37 30' S 89 W 154. 38 O' S 89 W 154. 38 45' S 89 W 190. 38 30' S 89 W 187. 38 O' S 90 W. 218. 36 15' N 87 W 123. 36 15' N 89 W 156. 37 O' N 89 W 186. 37 15' N 87 W 1£3. 37 45' N 86 W 218. 37 30' N 85 W 219. 36 30' N 84 W 94. 35 45' N 83 W 185. 36 O' N 82 W 21'1. 35 45' N 82' W 216. 35 30' N 81 W 2;'0. 34 46' N 80 W 133. 34 O' N 80 W. 354'~.68 .~'-' 86- 43' W · 44.37 81.72 60.53 105.92 83.81 131.56 71.12 101.57 79.55 111.53 i18.36.159.96 87.05 113.44. 94.81' 121.35 96.39 120.10 118,27 148.69 115.12 147.35 128.90 1.75.80 ,72.73 gg. Ig 93.88 124.5B I12.58 148.05 75.30 97.25 132.70 I72.g5 I30.26 176.04 54.91 76.28 108.74 149.66 126.78 176.11- 125.43 175.84 125.J9 180.76 74.37 110.26 5.40 S 44.04 W 5.27 S 60.30 W 5.84 S 83.61W 3.72 S 71.02 W 4.16 S 79.44 W 2.06 S 118.35 W 1.51S 87.03 W 1.65 S 94.79 W 1.68 S 96.37 W 2.06 S 118.25 W 0.00 S 115.12 W '6.?4 N 128.72 W 1.26 N 72.?2 W 1.63 N 93.86 W 5.89 N 112.43 W 5.25 N 75.11W I1,56'N I32.20 W I3.6I N 129.55 W 6.69 N 54.51W 15.13 N 107.68 W 17.64 N 125.54 W 19.62 N 1.23,B8 W 21.77 N I23.49 W 12.gl N 73.24 W 3262.67 3368.59 3500.16 3601.74 3713.27 3873.24 3986.69 4108.04 4228.14 43?6.84 4524.20 4700.00 4799.19 4923.78 '5071.84 314.62 S 1264.53 W -. 319.89 S 1324.84 W 325.74 S~ 1408.4'6 W ~" 329.46 S 1479.48 W 333.63 S 1558.93 W . 335.69 S 1677.28 W 337.21 S 1764.32 W 338.87 S 1859.12 WJ 340.'55 S 1955.50 ~' ~ . 342.61 S 2073'76 W 342.61.Sv 2188,88 W ~'~. 335.87 S 2317,61 W 334.60 S 2390.33 W 332.96~S 2484.20 W 327.07 S 2596.63 W 5169.09' 321.81 S 2671.75 W~ 5342.04 310.25 S 2803.96 W 5518.09 296.63 S 2933.51 W 5594.38 '289.94 S 298~.02 W 5?44.04 274.80 S 3095.70 Wv 5920.16 257.16 S 3221.25 W 6'096.00 237.54 S 3345.14 W 6276.7? 215.76 S 3468.63 W 6387.03 202.85 $ 3541.87 W . ''7 ,.. . . } ! '' : l~rm ~o, REV, STATE OF ALASKA OIL AND GAS CONSERVATION CONWII~EE MONTHLY REPORT OF DRILLING AND WOR'KOVER OPERATIONS KLV ............... 0IL [] GA8 W~LL WELL [~ O?~ER HWK ........ ~ 2. NAME OF OPERATOR Phillips Petroleum Company REL 31 ADDRESS OF OPEP..ATOR ....... ~1~ "D" S%ree%, ~cho~ge, A~ka ,~1~ , , ,~ ~. ~CA~ON OF w~LT. . - .... ' , , ~g 3, Slo~ 7' No~h Cook I~et P~tfo~ "~nek", ~50' ~, 10~' [5. APl NI.~EHICAL CODE 50-283~20020 6, LEASE DESIGNATION AXD SEI~IAL NO. ADL-!_~55 7. iF"INDIA]~, AL,OT~E~ O~ TRIBE NAME 8. U~'IT, FA3~{ OR LEASE NAME No~,~'h COOk In3-t Unit 9. WELL NO. i0. FIELD AND ~OOL. OR WILDCA. T _ North Cook Inlet n. s~.. ~., ~., ~., (~0~ ~o~Top of ~y ~~ 1500' F~, 665 ~, ~c. ~, 1~, S.M. ~:17~'~, "· ' 68-,99 REPORT 'TOTAL D~TH AT END O~ NION'£'~, CHA~NGES IN HOLE SIZE, CASING AJ~D CE3~ENTING JJBS INCLUDING DEPTH ~SET A_NI)Ajqy VOLUlViq~OTi. iER SIGNIFICA.NTUSED' PEP,~FOHATIONS,~GES I~TESTSHoL~ ~CONDITIONs.RESULTS' FISHING JOBS, JUIWK IN HOLE AND SIDE-TRACKED HOL~ 2-28 2.z5/16 2-17/21 2-22 2-23/28 TD 5~20'. Dri~ 9-5/8, hole. Skid Rig on Slot and test BOP, s. Drill 15" hole to 2550'. Set 10-3/4. ~s~ at 2518.~, a~ c~ented w/~0 sx ~ "G" cement ~d in ~bl preheated zeogel ~d ~let ~ter, tailed ~ r W/~5 sx ~ "G,, eememt ~ed ~ 15 bbls inlet ~ter w/2% cc. Drt~ 9-~/8, hole to 5~0'. PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99501 ~ 515 -D" STREET EXPLORATION AND PRODUCTION DEPARTMENT January 51, 1969 Mr. T.~,~. ~rshall, Jr. Division of Mines & ~nerals Department of Natural Resources State of Alaska 5OO1 Porcupine Drive Anchorage, Alaska 995Ol~ Gent lemen: Attached please find completed P-5 Form~, Sundry ~otices and Reports Cm Wells, covering a change in bottom hole location and top of proposed production zone 'for North Cook Inlet Unit Well #A-~,~ ~ originally~ approved by you a~_~ assigned Permit ~6~-99. This ~han~e~ was discussed ~th. Mr. Karl VonderAhe, your office, by telephone, January 50, 1969. Yours truly, JBG:jo Attachment oN o~ ot[ ANO OAS ~ F6rm P--3 Submit "Infentlons" ir~ Triplicate & "Subsequent Reports" in Duplicate STATE O,F ALASKA OIL AND GAS CONSERVATION, CO,MMI]'fEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill 6r to deepen or plug back to a diffierent reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) OIL [] OAS [] WELL OTHER 2 ~TAME OF OPERATOR Phil ]ips Petroleum_ Company '3. ADDRESS OF OPERATOR 515 "D" Street, Anchorage, Alaska $~ LOCATION. O,F WFJ-,L At surface Leg 3, Slot '7, North Cook Inlet Platform Ty~nek, 1250' FNL, 10~' F~ Sec. 6, 13. ELEVATIONS (Show whether DF, RT, GE, etc- !~KB ] ~6' from "~" Check ApPrOpriate B~x To I~n~i'~e Nlature NOTICE OF INTENTION TO: TEST WATER 8HUT-0FF FRACTURE TREAT SHOOT OR ACID!ZE REPAIR WELL PULL OR ALTER CASINO MULTIFLE COMPLETE ABANDONs CHANOE P~ANS (Other) 5. API NUiVIERICAL CODE ~;0-28,,;3-20020 ADL-187 ~, i '~ / ";, IF :ZN"DZAN, AL.tJO'r.t'.:w. OR T'RrRw. :N~' ~,,,, Ii. UNIT, FARM OR LEASE NAME 'North Cook Inlet Unit 9. VvqELL NO. #A-3 10. F,L,~a.~) AAW'I) POOL, OR WII.~CAT N~rth C~ok Inlet 11. SEC., T., R., o~w~ 1500 F~, 660~L*, Sec.!. ~I, lOW, S.M. B~: 1700 F~, 2850 12. ~T NO; ' ' ' SUBSEQUENT REPORT OF: WATER SHUT-OFF REPAIRING WELL FRACTURE TREATMENT ALTERING CASINO SHOOTING OR ACIDIZINO ABANDONMENT' (Other) NOTE: Report results of multiple completion on Well ompletion or Recompl~tion Report and L%g form.) 'IS.'D~S'CRIBE PROPOSED OR COMPLETED 0PERATIO~S (~learly state all pertinent details, and giv~ pertinent dates, including estimated date of starting an.y proposed work. We intend to change bottom_ hole location of. this well from-ADL-17589 BHL 2179' FSL, 3]3+7' F%~L, Sec. 31, T12N, R~g, S.M. to location as shown above. 16"'surface casing was set at 630' and cemented 11-5-68. We have not drilled cut from surface. 16. I hereby seXily/that :the fore.ins iq~_ue and correct (This sp~ for State o~ice,.use) COND~T]0N8 OF District Office ~nager January 31, 19~69 See 1,nstrucfions On ReVerse Side i i, · [ L I I ( I1 I III PHILLIPS PROPOSED ' B.H.L. N.C.I; Un. No. A~5,- - 2850 F'£L ef $1e.I*IIN-IOW $.M.) 12 1.3 ! i iii ii ii ii . . r i PROPOSED B.H.L. , ' /'"N.C;L Un. No. A-I ' · ~,,~ ( 89 FEI. & I, % % 6 ,i, · · iiiiiiiii ii ii i · , 18 \, /87,I1 GRID ORWN, N.J. Powell i i ii ii i i PHILLIPS PETROLEUM COMPANY 5lB #0" STREET ANCHORAGE ~ALASKA PLAT OF NORTH COOK INLET UNIT TYONEK PLATFORM ISC.~LE.' I'% 20'oo' O'~"f'l[: ,I-~1-69 HLEI OKG KLV HWK ~ - · ,' 5 No. P--4 STATE OF ALASKA SUBMFr lin DUPLICATE OIL AND GAS CONSERVATION COMMITTEE MONTHLY RE!PORT OF DRILLING AND WORKOVER OPERATIONS ~. NA/~E OF OPERATOR Phillips Petroleum Company 3. ADDRESS OF OPEI~TOR 515 "g" Street, 4. LOCATION OF W~-T-x- Leg 3, Slot 7 North Cook Inlet Platform Tyonek~ 1250' FNL and 1087' FWL Sec. 6~ TllN, R~I', S.M. AP1 NUMEKICAL CODE 50-283-20020 '6. LEASE DESIGNATION AND SEfilAL NO. ADL-17589 7, IF INDIA]q, ALOTTEE OR TRIBE NAME 8.UNIT,FARM OR LEASE NAJ~E North Cook Inlet Unit WELL No. 10. FIELD ~_ND POOL, OR %VILDCAT 11. SEC., T,, R., M,, (BO"'FI'OM HOLE oB,r~rn~ Sec, 6, TllN, R9W, 1~.. PERMIT NO. 68-99 13. REPORT TOTAL DEPTH AT END OF MONTH, CHANGES IN HOLE SIZE, CASING AN2D CEMENTING JOBS INCLUDING DEPTH SET AN~ VOLUiVIES USED, PEP~OI{ATIONS. TESTS ~ I~ESULTS, FISHING JOBS. JLrNK IN HOLE A_ND SIDE-TRACKED HOLE AND ANY OTHER SIGNIFICANT ~-~ES IN HOL~ CONDITIONS. Suspended -'Waiting on.,,Rig. :L::L/2 Spudded from surface. Drill 15" hole & ream to 22" to 630'. Set 16" casing at 612' and cemented w/735 sacks cement. SXGmm District Office ManaMer hATE December 6, 1968 l/' ' ' ' ' /// ' /~OTE--Report on this form is~eqUired for each calendar month, regardless of the status o! operations, and must be filed in duplicate with the Division of Mines & Minerals by the 15th of the succeeding month, unless otherwise directed. REC.EJV£D 1,~(,~v ? 1968 DIVISION OF MINES & MINERAL~ /~,4,CHORAGE ~ ~ t~ ~ this ~ ~tom:l&y to & bet,~ hole l~tiea of ~79' ~ ~1/~.?' I~L, ~. DIVISION OF OIL ANDGAS North Cook Inlet Un/t A-3 PhiLlips Petroleua Company, operator a.. ~oyce gale Fh/llips Petroleum Company ~~rage, ~~ 99~1 Dear Sir~ Enclosed please f~nd the approved application for pera~C co drill the referenced yell. ~ell samples and core chips are nsc required. Very Crul~ yours Thoaaa R. ltarshall, Jr. l'etroletm Superv~or ~nclosure FORM SA - i B. 125.5M 8/67 ME~M~ORANDUM State of Alaska DATE : SUBJECT: FORM SA - I B 125.5M 8/67 MEMORANDUM State of Alaska DX93;S~ OY OZL ~ g~ DATE : SUBJECT: Pp~wn P~I REV. 9'30-67 A. P..._~. 50-283-20020 · SUBMIT IN TR1 !ATE (Other instructions on reverse side) STATE OF ALASKA OIL AND GAS CONSERVATION ,COMMITTEE APPLICATION FOR PERMll TO DRILL, DEEPEN, OR PLUG BACK 1R. TYPE OF WORK DRILL [] DEEPEN [-] PLUG BACK [-] WELL WELL OTHER ZONE ZONE 8, UNIT~FARNI OR LEASE N~E 2. NAME OF OP~TOR North Cook Inlet Unit Phillips Petro!e~ Com~ny o. gL NO. 515 "D" Street, Anchorage, Alaska 99501 ~0. m~ *~ ~OOL, O~ ~. LOCATION O~ W~L ~surface ~g 3 Slot 7 No~h Cook Inlet, Platfo~ Tyonek No~h Cook Inlet 1250 ' FN~ aBd 1087 ' ~ Sec, 6-TI~-9W-S.M. ~*, HOLESEC" T.,OmECTIvE)R., M., (BOWO~ At pro.sea proa. zone 2179' FSL and 5~7' ~ Sec. ~I-T~N~s.M,~-/'-~ ":. Sec. 6 TllN Rgw S.M. 13. DIST~CE IN MILB AND D~ECTION F_%OM NEAREST TOWN OR'POST OFFICE* 12. !0.5 Mile E of ~onek,~ ~. :-.~:: : .; '-... - . . 14. BOND INFO~A~ON: M-}~-IV State Wide Bond B!-! -':- , TYPE Surety and/or No. 15. DISTANCE FROM PROPOSED*" . ~ -:::- ~ ' - . ~ j .' ..r-:; '~6. ~O. 0F:ACR~ IN-LE~SE 17. NO. ACR~ ASSIGN~ LOCATION TO NEAREST [ TO ~iS WELL PROP~TY OR LEASE LINE;' FT.*~ - *i~9 ~ ~i' ' . 1 (A~o to nearest drig, unit, if. a~y~, ~[y rb 5002 i8. DISTANCE FROM PROPOSED LOcA~'ON* ' [i9.' PROPOSED D~~ 20. ROTARY 0R CABLE TOOLS oRTO NEARESTAPPLiED FoR,WELLFT.DRILLINGr'~COMPLE~D'- .... ' ' ?f;" [- ' ----.--~]~0 1- '~--- , ~ 32~,2 Ft~ . · ~1 " 7~' TVD 'Rotary 2L ELEVATION~ ($how whether DF, RT, ~R, etc.) ~. APP~OX ,~E WORK WILL ~B 116 ft. from I~TJ?~ I November 5, 1968 ~3' - .... ~ ~OPOS~ CASING' ~D C~-E~NG PROGR~ ' - SIZE OF HOLE SIZE OF CKSINGt ':~E~HT pE~ FOoT` ' GRA~ :i [":" S'~'"[[i'[N~: DEpTH ~' : QUANTITY 0F C,MEN~ 22" 16" 65 H-40 600 Cir. to: sUrface 1~,, 10-3/4" , 45,5 &-~t ~. J-55-- .~2640 . Cir. to s~ace .9 5/~" 7, . -.~: 26.& 23 L ~J-55-... . .8150 . Fi]] up t~ 5O0,',above pay zon~ ~ r 2? i "_ [ /-' ~ ~ ~ ' ~ · ~' :. f ' ' ~ , , ~ .'.. , - ,, !. Deviation required to :reach-BHL from permanent platform. 2. There are no effected.~op~rators. - . 3. BOP Specifications attached. 4. Intervals of interest .will be perforated and may be stimulated _ .... .. · . . ! . . . ,. . ~. · ~'",, }~.~. e~a~dS~a~e6~_f_ _ Alaska, Alaska 0il & Gas Conservation Committee, Conservation Order IN ABOVE SpACE~ DESCRIBE PROPOSEI~ PROGRA.iV[: If proposal is to deepen or plug back, give data on presen'c productive zone and proposed~ new productiv~ zo~e. If Pr(~posal.~is to drill or deepen dire~tionally, give pertinent data on subsurface locations and measured and true vertidal.., depths. Give blowout preventer program. 24.1 herebqTf~.:,~,,i~!/,~o~:go~True and Correct Th f ta ffg ( is space or S te o ~ce use) .... ~x~?~ 10-.30-68 TIT~ 1,'~terial Supervisor SAMPLES AND CORE CroPS REQUIR]~D [] YES a NO DIRECTIONAL SURVEY REQUIRED YES [] NO CONDITIONS OF APPROVAL, IF ANY: ~ REQU~TS: A.P.I. NUMEEICAL CODE DATE · / / i, . i iiiiiJi i 12 7 LEG Ng. LEG N°. 4 LEG N°. 2 L/NIt 6 o 04' 56.38" LAT. 61° 04' 36.89" LAT.. 61© 04' 35.83" LONG.150o 56' 55.63" LONG. 150° 56' 54.25" LONG. 150° 56' 54.77" Y= 2,586,731 Y= 2~586,78 i Y= 2,586,674 X= 331,995 X=' ;532,063 X= 332,036 FROM N.W. COR. FROM N.W. COR. FROM N.W. COR. :'' 1,250' SOUTH & 1,198' SOUTH & 1,305' SOUTH & 975' EAST. - 1,043' EAST. · 1,018' EAST. : CERTIFICATE OF SURVEYOR I to practice land surveying in the State of Alaska and that this plat represents a location survey made by rrm 'or under my supei'vision and that all dimensions and ."other details are correct. ".. / DA~E SJR~YOR SCALE I = I,OO0" hereby certify that lam properly registered end licensed NOTE '"'"~. T 12 N 31 i TilN 6 mmm m mm m mm mm m 32 . 5 The location of the platform legs was accomplished by using triangulation stations BELUGA,TERRACE,and TYONEK which ' are all U.S.C.&G.S. stations. AIl coordinates are Alaska State Plane, Zone 4. 5 8 LEG N° 3 LAT. 61v 04' 36.34" LONG. 150° 56' 53.39" Y:2,586,724 X: 332,105 FROM N.W. COR. 1,254' SOUTH & 1,085' EAST. NOTE: Plet amended 7AUG.68' to show revised leg numbering. NORTH COOK INLET UNIT PLATFOR M~I[ 'I"Z ONEK Fo, PHILLIPS PETROLEUM CO ' . , DATE'. 21 JUNE 68 __.~F.M. LINDSEY ~ ASSOC. SCALEi I"=' I000'~ Lond & Hydrogrophic FB. II374 PP. !!-15 I Surveyors DRWN.' Ct'IKD. ..1¢.C'[ 250Z W. NORTHERNLIGI~'PS 8LVll JHG. i'1374 8PI[N&I~I), 80X4-081 ALASKA '56 12 I$ ,i i i i i i Ill] I . PROPOSED B.H.L. ' N.C,I. Un. No. A-I (85' FEI. & % · % 32 ,e~..~ PROPOSED B.H.L. / N.C. I~ Un. No. / (~IT'9'FSL & $147'FWL. of SIO.~I-12N-;W ~.M.) / / · / i PROPOSED BHL N.C.I, Un, No. ( 49~,.~'FNI. & ~4.~'FEI., ef .. 8 GRID PHILLIPS PETROLEUM COMPANY 515 "D" 8TRrET, , ,, ANCHORA6EB ,ALASKA PLAT OF' NORTH COOK INLET UNIT TYONEK PLATFORM DRWN. N, J, Leg 2 N,¢,I. Un.A-2 PHILLIPS PETROLEUM COMPANY 515 'l~' STREET ANCHORAGE,~ALASKA ~ ~ NORTH COOK INLET TYONEK PLATFORM COOK IN'LET, ALASKA ~l NOT, E: Using PLATFORM NORTH, Stot No.! will bethel furthest plotform North slot in plotform North- west quedront of ony leg; Slots are numbered I thru 8 in o counter-clock-wise direction. PLATFORM LOCAT ION.' Se~.&- II H-gW NOV, HOO!<UP FOR DOUBLE _ . _ PREVENTERS PLAT FO R M Double Preventers are use'd with flanged side outlets for choke manifold and fillup line connections. · BLOWOUT PREVEN'FER HOOK-UP (SERIES 1500 FLANGES OR~,,-,P'="~'"'~:,._R) . · , . REV, ~/l!/G,9 SCH~.DL~ ,'~ ~ E NOTE: t I N.C.I.U. _ ;~..__.~ ' . . ;- - . . 2 MUD PRESSURE GAUGE 0~,,I 4 X 4X~" . .'-= ' ..... ' SERIES 1500 STEEL TEE. ~.M.. .' . ~ 0% 4 SERIES ICROSS 50~0 X 2 SERIES t500 --k._ (BLIND RAMS') - ~---'"" 2: SERIES 15,00 POSITIVE CHOKE '. ~ '1 · ~LG. - ~ ' ' ' ' ' G " ' U i ' ' ' ' I I I!, ",' "' I ' ...:.::.,.. ';:.~: ~ · ~ .'~~. .. : .' .',~~''~. '.-~ - ," ' ~ . ~¢. . .,, ~ - ' k~ .' . '::'" PRODUCTION DEPARTMENT . ... ' '" . . 5000 PSi WORKING PRESSU,R,E
