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Home My WebLink About169-0851a. 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- 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" - 386' 16" H-40 631' 10-3/4" J-55 2,370' 7" J-55 3,388' 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 September 9, 1969 August 20, 1969 ADL 17589 / ADL 37831 N/A N/A 4,010' MD / 3,388' TVD99 N/A 8,022' MD / 6,147' TVD N/A Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary Water-Bbl: PRODUCTION TEST N/A Date of Test: Flow Tubing - 65# 386' Surface 2,587' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 45.5# 4,010' (TOW) Surface Surface DEPTH SET (MD) PACKER SET (MD/TVD) Surface CASING WT. PER FT.GRADE 26# N/A 328292 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 2583873 BOTTOM TOP 15" Surface 22" HOLE SIZE AMOUNT PULLED 50-883-20029-00-00 NCIU A-09 332040 2586667 N/A CEMENTING RECORD N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6/18/2022 1312' FNL, 1022' FWL, Sec 6, T11N, R9W, SM , AK 1132' FSL, 2692' FWL, Sec 1, T11N, R10W, SM, AK 169-085 / 322-128 Tertiary Gas, Sterling Undef GP 126.6' 4,010' MD / 3,388' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Cond Surface 631' 550 sx Driven 735 sx Surface N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 446 sx9-5/8" TUBING RECORD 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 By James Brooks at 8:34 am, Aug 31, 2022 Abandoned 6/18/2022 JSB RBDMS JSB 091622 xG NCIU A-09 As with NCIU A-10A, they were unable to get good cement behind the tubing and into the IA. So, they pulled the tubing and placed a CIBP and 25' of cement inside the 7-5/8" casing. -WCB Abandoned DSR-9/16/22 169-085 / 322-128 SFD 11/8/2022WCB 4/27/2023 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval N/A N/A Beluga 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 8.30.2022 Digitally 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: 2022.08.30 15:43:27 -08'00' Monty M Myers _____________________________________________________________________________________ Updated By: CJD 08/30/22 P&A SCHEMATIC Tyonek Platform Well: A-09 P&A: 6/18/22 PTD: 169-085 API: 50-883-20029-00-00 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Conductor Welded 28”Surf 386’ 16”65 H-40 BUTT 15.250”Surf 631’ 10-3/4”45.5 J-55 BUTT 9.950”Surf 2,587’ 7”26 J-55 BUTT 6.276”Surf’4,010’(TOW) JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 4,010’3,388’6.000 Whipstock 2 4,130’3,473’3.94 5.98 OTIS overshot TSD 4,142’3,482’3.94 5.63 OTIS Ratch Latch 4,143’3,482’3.880 6.000 Packer, Otis VSR A ±4,143’CIBP w 10’ of cement B ±4,202’CIBP w 25’ of cement 3 4,500’ 3,734’3” Magna Range Bridge Plug w/ 10’ cement (1/26/18) 4 4,547’3,767’4.000 5.880 Packer, Otis TW 5 4,563’3,779’3.880 6.000 Packer, Otis VSR (Not Set) 4,569’3,783’3.958 5.600 4-1/2 Blast Joints, 214.5’ TL 6 4,784’3,932’3.813 5.500 Sleeve, Otis XA SSD – Closed (Opens up) 7 4,791’3,937’4.000 5.880 Packer, Otis TW 4,796’3,941’3.950 5.600 4-1/2 Blast Joints, 25.79’ TL 4,796’3,941’3” Magna Range BP w/ 10’ cement (9/23/17) 8 4,821’3,958’3.810 5.520 Sleeve, Otis XO SSD – Closed (Opens down) 4,826’3,962’3.950 5.600 4-1/2 Blast Joints, 22.59’ TL 9 4,848’3,977’4.000 5.880 Packer, Otis BWH 10 4,860’3,985’2.990 5.890 XO, 4.5 X 3.5 4,861’3,986’2.990 4.550 3-1/2 Blast Joints, 248.68’ TL 11 5,110’4,159’2.750 4.280 Sleeve, Otis XA SSD – Closed (Opens up) 12 5,116’4,163’4.000 5.880 Packer, Otis BWH 5,128’4,171’2.992 4.550 3-1/2 Blast Joints, 71.54’ TL 13 5,200’4,221’2.750 4.280 Sleeve, Otis XO SSD – Closed (Opens down) 14 5,211’4,228’4.000 5.880 Packer, Otis BWH 15 5,223’4,237’2.440 5.030 XO, 3.5 X 2.875 5,224’4,237’2.440 3.310 2-7/8 Blast Joints, 253.93’ TL 5483’4,415’0.000 FISH: 4 Cutter Bars (1) 1.5” X 5’, (1) 1.75” X 5’, (2) 1.25” X 5’, 452’ of 0.125” Wire, 21’ SL Toolstring & 2.875” Packoff Plug 16 5,484’4,416’2.313 3.750 Sleeve, Otis XA SSD (Opens up) 0.875 2.250 FISH: AD-2 Stop 17 5,521’4,441’4.000 5.880 Packer, Otis BWH 5,756’4,602’2.440 3.310 2-7/8 Blast Joint, 9.85’ TL 6,141’4,864’2.440 3.310 2-7/8 Blast Joints, 49.3’ TL 6,274’4,955’2.440 3.310 2-7/8 Blast Joint, 9.85’ TL 6,385’5,030’2.440 3.310 2-7/8 Blast Joint, 29.55’ TL 6,456’5,078’2.440 3.310 2-7/8 Blast Joint, 19.70’ TL 18 6,508’5,114’2.313 3.750 Sleeve, Otis XO SSD – Open (Opens down) 19 6,522’5,123’3.250 5.087 Packer, Otis BWH 20 6,538’5,134’2.313 3.750 Sleeve, Otis XO SSD – Open (Opens down) 6,764’5,288’2.440 3.310 2-7/8 Blast Joints, 78.80’ TL 21 6,875’5,364’2.205 3.230 Nipple, Otis XN 22 6,886’5,371’2.440 4.500 Wireline Re-Entry Guide 7,057’5,488’0.000 CIBP, Baker 7,666 5,913’0.000 Cement Retainer, Baker K-1 7,691 5,930’0.00 FISH Activity Date Ops Summary 3/14/2022 Meet with ops and obtain permit, PJSM. Perform MIT-IA to 2200 psi for 30 minutes with drill water. Starting pressure: 2304 psi. 30 minute pressure: 2262 psi. Good test. Bleed down, secure well and SDFN. 3/17/2022 Rig up eline and pressure test lubricator to 250 psi low / 1000 psi high.,Arm and RIH with 4.5" CIBP (3.71" running OD). Tag at 220'. POOH and lay down tools. RIH with 1-11/16" drift assembly and sit down at 220'.,Dump 25 gallons of methanol down well and let soak. RIH with 2.20" gauge ring assembly and sit down at 220'. Hand spang and push obstruction down to 295'. POOH. Dump another 25 gallons of methanol and let soak. RIH with 2.20 gauge ring assembly and sit down at 295'. Unable to continue downhole. POOH.,Replace 2.20" gauge ring with 1-11/16" chisel bottom nose. RIH and get past obstruction at 295'. Attempt to POOH but unable to pull up past 312'. RIH to 4200' and make correlation pass for future plug set run. POOH and get hung up at 312' again. Hand spang tools through obstruction and POOH. Lay down tools and lubricator. Secure well and SDFN. 3/18/2022 AKEL crew assembles and attends morning safety meeting. Obtain permits and hold PJSM. Rig substructure crew re-scheduled to arrive at noon. Fire up eline equipment and rig up.,Dump 20 gallons methanol in well. RIH with 3-1/8" drift assembly and tag at 295'. Pump 15 gallons of methanol downhole while sitting on obstruction. Unable to pass through. POOH and RDMO for substructure crew. 3/19/2022 Ru Slickline PT 2500 psi. Pull SSSV at 295'. Gauge Ring run to 4,136'. RDMO well. 3/20/2022 AKEL crew assembles and attends morning safety meeting. Obtain permits and hold PJSM. Rig up eline equipment and pressure test lubricator to 250 psi low / 1500 psi high. Arm and RIH with 4.5" CIBP (3.72" running OD). Correlate to tubing tally and set plug at 4134'. POOH and inspect tools.,Arm and RIH with 3' of 2" OD tubing puncher. Fill tubing while RIH. Correlate to tubing tally and punch from 4127-4130'. Good indication that shots fired. POOH and lay down puncher.,Pump down tubing taking returns from IA and establish returns. Shut down and wait for well to stabilize and tubing pressure increases. Attempt to bleed down tubing and take approximately 4 bbls until flow stops. Pump down backside across tree until fluid packed and then taking returns from tubing attempting to circulate packer fluid into the tubing. Take 10 barrels of fluid into tubing and well is static.,Take an additional 5 barrels of fluid from IA into tubing. Arm and RIH with cement retainer. Correlate to tubing tally and set at 4125'. POOH and lay down tools. Monitor tubing flow to determine if retainer is holding but flow continues. Rig down off and secure A-09. Spot up on A-10. 3/21/2022 Rig up Yellowjacket triplex to pump drill water down tubing taking returns from the IA to platform produced water tank. Come online at 2 BPM and circulate wellbore volume down tubing and out IA. Initial circulating pressure: 575 psi. 20 bbls away: 550 psi. 40 bbls away: 500 psi. 60 bbls away: 430 psi. Final circulating pressure: 370 psi. 150 bbls total pumped. Check flow, tubing and IA are balanced.,Rig up eline equipment and begin to mix cement at 19:10. Make up 40' x 3.5" cement dump bailer and fill with 15 gallons of cement. RIH and tag retainer at 4125. Pick up to 4100 and dump cement. POOH. Mix second batch of cement at 20:30. Fill bailer with 15 gallons of cement. RIH and tag cement top at 4100. Pick up to 4075 and dump cement. POOH.,Mix third batch of cement at 21:20. Fill bailer with 15 gallons of cement. RIH and tag cement top at 4075. Pick up to 4050 and dump cement. POOH. Lay down dump bailer assembly and nightcap well. Pump down tubing with IA valve closed until fluid is caught. Open IA and take returns to trip tank while pumping down tubing.,Returns established at a trickle, nowhere close to 1:1. Initial treating pressure of 100 psi and steadily increasing. Come off pump and bleed off pressure once treating pressure at 500 psi. Attempt to establish circulation with no luck, bring pressure up to 1000, 1500, 2000 and 2500 psi while bleeding back to zero between attempts. Total of ~2 gallons returned. Unable to circulate cement, secure well and SDFN. 3/23/2022 AKEL crew assembles and attends morning safety meeting. Obtain permits and hold PJSM. Warm up eline equipment. Pressure test IA to 2000 psi for 10 minutes, good test.,Arm and RIH with 4.5" segmented jet cutter (3.5" running OD). Correlate to tubing tally and cut at 4040'. Good indication that cutter fired. POOH and lay down tools. Rig down and move over to A-10. 4/17/2022 Assist R/U w/l on A-02, housekeeping & r/u circulating lines while waiting on crane operator to free up from W/L,Organize deck for setting carrier on beam package, unload carrier from boat set on beam package to well center on A-09, secure same,Set Draworks, install driveline, "A" leg, cont. organize deck, unload mast from boat pin to carrier, backload boat, continue sharing crane op with w/l operations.,Production Isolate flow line from A-09, monitor well 30 min good, set BPV,N/D Tree, and Dress Hanger neck. Went to install the blanking sub for testing BOP's and sub was hitting the top of the BPV. Located a 4.5'' EUE pup and had it flown out for a spacer between the BPV and the blanking sub.,Set Koomy unit, choke manifold and Doghouse. MU drilling console to mast. removed drilling line spool from mast. Removed top foot from mast. Hook up Super Choke and lines. Run air and electrical lines for the carrier and mast.,Installed 4.5'' eue pup and blanking sub into the hanger. Installed the riser. Set the racking beam into place. Build the BOPE stack and torque studs. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NCIU A-09A North Cook Inlet Unit Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:221-00030 NCIU A-09A PreDrill Spud Date: (g) Correlate to tubing tally and punch from 4127-4130'. e test IA to 2000 psi for 10 minutes, good test. p gp qp Correlate to tubing tally and set plug at 4134'. gy gy g p pqp RIH with 4.5" segmented jet cutter (3.5" running OD). Correlate to tubing tally and cut at 4040'. G yp yp yp ,Rig up eline equipment and begin to mix cement at 19:10. Make up 40' x 3.5"pp pp g gpqpg p cement dump bailer and fill with 15 gallons of cement. RIH and tag retainer at 4125. Pick up to 4100 and dump cement. POOH. Mix second batch of cement atxpg g pp 20:30. Fill bailer with 15 gallons of cement. RIH and tag cement top at 4100. Pick up to 4075 and dump cement. POOH.,Mix third batch of cement at 21:20. Fill g gp p p bailer with 15 gallons of cement. RIH and tag cement top at 4075. Pick up to 4050 and dump cement. POOH. p ygp ,Returns established at a trickle,pg gp pppgg nowhere close to 1:1. Initial treating pressure of 100 psi and steadily increasing. Come off pump and bleed off pressure once treating pressure at 500 psi. Attemptgp p y g p p p gp p to establish circulation with no luck, bring pressure up to 1000, 1500, 2000 and 2500 psi while bleeding back to zero between attempts. Total of ~2 gallons returned. Unable to circulate cement, They were unable to circulate cement from the tubing into the IA. -WCB gpg Arm and RIH pg with cement retainer. Correlate to tubing tally and set at 4125'. Perform MIT-IA to 2200 psi for 30 minutes with drill water. Starting pressure: 2304 psi. 30 minute pressure: 2262 psi. Good test. Passing MIT-IA post cementing. Tbg jet cut. No MIT-T, no CBL, no tag of cement. -WCB CIBP set in tubing. Tubing punched. Returns established up IA. Cement retainer set. -WCB gp g ,Pump down tubing taking returns from IA and establish returns. gy p Rig down 4/18/2022 Set in misc equipment on racking mat, raised mast, stung up tuggers, man rider and drill line.,Scoped up derrick, secured guy wires, hooked up lights, inspected derrick.,Fly on and r/u work floor, installed winterization, spotted heaters and warmed stack, hooked up gas detection and bump tested same, Built 4-1/2" test joint.,P/u BOP testing eq.,Performed BOPE test per Sundry as following; Annular 250-2500psi, Rams 250-3000psi, Valves 250-3000psi, Tested gas detection and preformed Koomey drawdown test. AOGCC witnessed test Lou Laubenstein Done BOPE test by 00:00 SIMOP's MIT-IA A-12 to 2950 psi 30 min good test. MIT-IA B-03 to 2800 psi 30 min good test also witnessed test Lou Laubenstein.,Attempted to pull blanking sub and test jt backed out at XO. Screwed back into blanking sub retrieval tool and pulled out of hole. SIMOP's cont rigging up the rig floor for pulling 4.5'' tubing. Tightened the running tool XO's and backed out blanking sub out of the hanger. Pulled BPV MU landing JT with side entry sub and TIW valve.,Rigged up to circulate the well. Pumped a surface to surface volume, pumping down the kill and taking returns to production though the IA. 4/19/2022 Circ well STS @ 3bpm/200psi w/8.4ppg Drill Water in and out.,S/d pump well static, blow lines down, R/d circ eq.,M/u Landing Joint, BOLDS, Pulled hanger to rig floor PUW 45k, Cut and caped control line. L/d Tbg hanger and FOSV and XO's .,POOH f/4040' t/3746' L/d 4-1/2" completion tbg and 1/4" control lines, L/d SSSV and Otis XXO.,Continued POOH L/d 4-1/2" completion tbg f/3746' t/surface, L/d 126jts and 11' cut joint.,Crew assisted crane with work boat, Arranged deck for eline unit.,Spot and R/u AK EL SIMOP's Rigged up and circulated a surface to surface volume on A-10 see A-10 report for details,AK EL RIH with 7" CIBP Logged going in the hole and correlated on depth @ 4053' so after the cement is in place there will be 27' in-between the TOC and the next 7 5/8'' collar. Set 7'' CIBP at 4053' and verified location with a tag. POOH with E-line to change tools for cement run.,PU E-line tools set charge and loaded bailer with cement. 2 20gal 17ppg cement dump runs. Changed tool to a bobber bailer. Tagged TOC with a 50lb weight drop @ 4028' @ 04:00.,Pull WL out of hole and RD WL 4/20/2022 N/d stripper head, drained stack, R/d koomey control lines and kill/choke lines, removed rig floor, stairs,,Prep, scoped down and lay over derrick, N/u strong back BOP lifting beam,,Arranged deck, installed jacks and removed clamps and prep to skid rig,See A-10 report,N/U Dry Hole Tree on A-09. No official MIT was preformed on A-09 waiting on response from AOGCC prior to testing. 5/30/2022 Perform general maintenance and house keeping. Prepare rig for upcoming rig move. Test jacking system. Up with hull 3' to 25' air gap, Down with hull to 22' air gap above low tide. Continue to perform general maintenance and housekeeping. Prepare rig for rig move. Assist rig welder with welding project. Continue to dress out mud pumps. 7" CIBP set; cement dump bailed. TOC tagged @4028'. -WCB E-line to change tools for cement run.,PU E-line tools set charge and loaded bailer with cement. 2 20gal 17ppg cement dumpgg runs. Changed tool to a bobber bailer. Tagged TOC with a 50lb weight drop @ 4028' @ 04:00.,Pull WL out of hole and RD W L K EL RIH with 7" CIBP Logged going in the hole andgg p pgggg correlated on depth @ 4053' so after the cement is in place there will be 27' in-between the TOC and the next 7 5/8'' collar.Set 7'' CIBP at 4053' and verifiedpp location with a tag. g pp q gg L/d Tbg hanger and FOSV and XO's .,POOH f/4040' t/3746' L/d 4-1/2" completion tbg and 1/4" control lines, L/dpgg SSSV and Otis XXO.,Continued POOH L/d 4-1/2" completion tbg f/3746' t/surface, L/d 126jts and 11' cut joint. It appears that due to cement not being put behind the tubing on 3-21-2022, the plan was made to jump to the Contingency Plan for RWO A, detailed in Sundry 322-128. -WCB Tubing removed. -WCB R/u AK EL Activity Date Ops Summary 6/5/2022 Construction finish drilling holes In Rotary sub base. Remove planking. Work boat-receive bops & Misc. supplies. Start N/U BOPs inside rotary sub while waiting on crane rigging for the 800 crane removal.;Shut down N/U operations due to 800 crane removal. Still waiting on 800 crane body removal, Top landing pedestal, Lower landing R/D. Simop- replacing cables on spartan starboard crane.;Skid Rig out over rotary sub, jack and shim rotary sub for bolt up t/rig floor. Simop-c/o whip line on starboard crane.;Torque rotary sub bolts t/rig floor. Simop-c/o head block line on starboard crane. Un-bolt rig floor from cantilever.;Skid cantilever back and leave rig package on the platform. Jack rig up and remove shims from bolt up on rotary sub. 6/6/2022 Skid rig towards Leg 2 & set up scaffolding. Torque bolts on Rot sub & Continue to install C plates.;Work on safe out handrails on 151 pipe deck. Install cat walk from 151 to Tyonek platform; simop-Tyonek still Demob 800 crane landings.;Hook up drain lines on Spartan cantilever and fire fighting deluge system; simop- Tyonek still Demob 800 crane landings.;Skid rig toward leg #2, swap side with jacks to push and continue jacking over well A-09A. Work boat.;Secure rot. base, scope in rams and roll up hyd. unit. decision made to traverse rig package 4" north when rig is powered up.;Cont. working on fire fighting deluge, sea H2O systems on Spartan. Work boat-unload HAK rack base beams and spot same, unload Sperry unit. 6/7/2022 take on potable water and fuel. Install hurricane clamps on rot.sub base to deck. Bolt up Hak rack base t/spreaders w/C-clamp bolts.;Modify jack links t/fit Hak rack base and install jacks t/skid same. Change out head block on port crane. Pull blind flanges off mud pits on Spartan.;Install mud feed/return hoses from pits/pumps t/ beaver slide. Assist welders installing ST-80 socket for pedestal-firewatchs x3. Re-install new bolts on C-clamps on rot. sub used for Hak rack.;Install centrifuge feed pump under centrifuge unit. Build bracket and move satellite dish for internet in OIM office. Ready decks and back load for boat.;Unload Hak rack section from boat and set on deck, re-rig for 2 crane pick and set in place, while working boat w/Spartan crane.;Pick 2nd Hak rack section and set into place, secure both sections to Hak rack base section. Cont. working boat w/Spartan crane. 6/8/2022 Secure HAK rack end sections to base and skid HAK rack into place. Continue to work on ST-80 socket install.;Install service catwalk from 151 to Tyonek platform and lay down rubber matting. Install catwalk from 151 to HAK rack on Tyonek platform.;Work on handrails and landings to 151 pipe deck.;Unpack and layout gas alarm equipment with Tyonek electrician. Begin laying cables in service catwalk from 151 to platform.;Work boat- unload and set-middle Hak rack deck, 2ea. 8 x30ft mats for new shaker tank. Install hand rails on Hak deck. Unload shaker tank and set same.;Unload and set-stairs; unload the rest of equipment. Set centrifugal pumps x2 and headers.;M/u centrifugal pumps and headers t/shaker tank, simop-install service line brackets and install service lines. Set shaker roof. 6/9/2022 Work on gas alarm installation. Fabricate/install stairs, landings, and handrails around shaker tank and from HAK rack deck to 151. Coil, secure and plug in electrical service connections to rig from jack up.;cont. install ST-80 socket and fit beaver slide extension.;Cont. fabricate/install stairs, landings, and handrails around shaker tank and from HAK rack deck to 151. Coil, secure and plug in electrical service connections to rig from jack up.;Begin welding out beaver slide extension. Work boat-off load mud product, vacuum unit, spot mud shack and misc. equipment.;Cont. fabricate/install stairs, landings, and handrails around shaker tank and from HAK rack deck to 151. Coil, Secure and plug in electrical service connections to rig from jack up.;Welding out beaver slide extension. Pulling power cords from shaker tank t/bang board under Hak rack. Install cement line from rig t/Spartan. 6/10/2022 Continue to fabricate/install stairs, landings, and handrails. Continue hook up service lines. Continue hook up gas detection system . Power up rig and test same. Rig up overboard line from shakers. Rig up secondary BOPE panel and install 80gal accumulator bottle on rig.;Continue to fabricate/install stairs, landings, and handrails. Secure HAK rack green iron to deck with clamps. Offload boat, take on fuel and water. Weld flange on flow line. Install flow line to shakers. 6/11/2022 Continue to fabricate/install stairs, landings, and handrails. Continue and finish fabricate of flow line . Install ST-80 pipe handler and work on plumbing for same. Continue work on beaver slide sling access walk way. install test pump on rig floor. House cleaning;Continue install and test gas detection system. Start r/up of Pason rig watch system. Boat unable to Load pipe and needed equipment @ dock due to wind and seas;Set beaver slide w/ sling access walkway and catwalk in position. Finish installation of stairs over green iron on HAK rack base. Route service lines away from stair base and clear walkway. Clear decks for drill pipe.;Hold PJSM and stage tools and equipment in BOPE deck and cellar. ND dry hole tree and NU 11" 3M tubing spool.;Dress upper and lower rams with 2-7/8" x 5" VBRs. Dress middle rams with blind rams. NU high pressure riser. 6/12/2022 Continue nipple up Bopes . House clean all work areas and prep loads for boat . Still no boat or chopper weather in. Re-work beaver slide sling access . Continue r/ up Pason rig watch system . Finish testing gas detection system.;House clean all work areas and prep deck for boat. Straighten landings and stairs. Continue to rig up Pason system. Grease choke manifold valves.;Work Boat: Offload short high pressure riser, pipe bucket and pipe stanchions. Offload 250 jts of 4" DP, 14 jts of 4" HWDP, 9 DC, MWD tools, and mud product. Take on drill water from boat and transfer fuel from platform. Install short high-pressure riser. Nipple up BOPE stack. Torque bolts 6/13/2022 Continue to nipple up BOPE. Make up choke and kill lines to stack and XO to Spartan 15M equipment. Make up remainder of high-pressure mud line and route hoses over the top of the shaker tank.;Fill lines and tanks with water. Walk through lines and check connections for leaks. Verify operation of shakers and agitators on shaker tank. Repair leaks on feed pump lines on shaker tank transfer pumps. Calibrate tank volumes with Pason system. Install clamps and secure high pressure mud line.;Continue to fix leaks on transfer tank lines and Pit 1. Change saver sub and top drive dies from CDS40 to XT39. Build test joint assemblies. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NCIU A-09A North Cook Inlet Unit Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:221-00030 NCIU A-09A Drilling Spud Date: 6/14/2022 Continue and finish weld out of 3'x3' Patch on port side of Jack up Mud tank #1. Continue repair leaks on jack up tanks HP isolation valve , 10" and couple 8" butterfly butter fly valve & repair leaks on scalper tank transfer pump #1 suction line . Change out bell guide Held pre-spud meeting.;Welders continue and finished beaver slide pipe bucket re-work and install. Re flood test Jack up Pit # 1 Still leaking drain same and install 2nd 2' x2' patch.;Continue and finish 2nd patch on mud tank #1 and re flood test same good. Reassemble scalping tank transfer pump #1 Suctions line and flood test good and trouble shoot Pumps poor performance Impeller good motor wrong rpm for application chase new motor. Function test bopes install 4";test jt and exercise annular element flood stack and retighten riser and r/up test equipment and shell test Bope t/ 250/3000 psi on chart good.;Good shell test and test on tubing spool break - 250-3500 psi for 5/5 charted min. Pull lower test plug. Make up and install upper test plug with 4" test joint. Test with upper rams, flange between HCR and manual valve on Choke side leaking - tighten and re-test good.;Work Boat: Offload cement pods and air compressor. Transfer cement to silos on rig and backload pods. Take on fuel and water to platform.;Continue to test BOPE with 4" test joint. Work and re-test Choke HCR and Manual valves good. Perform drawdown test: 25 sec to 200 psi, 140 sec to full pressure. Annular closed in 24 sec. 6/15/2022 Still working two men short on one crew . Finish Pre- BOPE test with 4" test joint. 250L /3000H 5/5 on chart .R/dn test equipment. Install flow nipple and work on rig acceptance chk list. Flood test trip tank and flow nipple good. Flood test Jack up shaker tanks and lines and repair leaks.;Set test plug and r/up test equipment . Test Bop as per regulations 250L / 3000H 5/5 on chart witnessed by AOGCC inspector Austin McLeod;Work boat - Offload 3 cement pods and transfer 440 sks of tail cement to rig silo. Loadout empty pods and take on drill water.;Rig down test equipment, pull test plug. Secure stack in cellar. Re-Torque all bolts on BOP stack. Fabricate new mounting plate for transfer pump motor and install motor. Install mouse hole and 3-1/2" handling equipment.;Strap, pick up and make up nine 4-3/4" drill collars and rack back in the derrick. Verify ST-80 make up torque and rig tongs read the same on first connection running in. Change handling equipment for 4". 6/16/2022 Chg out crown -o- madic and test same. r/up test auto driller and set block height. install wear ring. PTSM Crew chg and short change New crew walk dn rig and Platform & orientation of both. flood test jack up shaker tanks and lines . Pump out stack and finish setting wear ring .;P/up rabbit and strap 14 jts of 4" HWDP. Cut and slip drill line and install directional drillers screen at drillers station.;Pick up, drift and strap 1100' of 4" Drill Pipe. Run power to directional driller screen at driller's station.;Work Boat: offload cement pod with weighted spacer, 4 iso's of fuel and 80' of 4" mud return hose. Install XT39 saver sub in top and verify function. Install 4" mud return line and commission primary mud return transfer pump (~16 bbl/min). Start building mud in pits. Check top drive make up torque.;Continue to pick up, drift and strap 4" drill pipe. Continue to build mud in pits. 6/17/2022 Running 2 men short. Continue to pick up, drift and strap 4" 14# S-135 XT39 drill pipe f/ 1533' t/ 2130' while monitoring well on trip tank for proper displacement. Continue to build LNSD WBM;Remove test pump from rig floor and install new cable for crown saver bell system and test same. Finish dressing #3 Mp. Continue to build LNSD WBM system;Resume p/up 4" 14# S-135 XT-39 DP f/ 2130' t/ t/ 2413' while monitoring well on trip tank for proper displacement . Continue to build LNSD WBM system;Pooh and rack back f/ 2413' t/ 430' P/up and m/up jars and rack back in derrick and Commission derrick and finish rig acceptance chk list and accept rig @ 1300 hrs;P/up Drift / c/out bha #1 = 6-1/8" bit + 7" scraper + Bit sub w/ float + 6-1/8" string mill + (9) 4-3/4" Dc's + XO + (2) jts HWDP + 4- 3/4" jars + (12) jts HWDP = 750.09'. Continue to build LNSD WBM system;Resume p/up 4" 14# S-135 XT-39 DP f/ 745' t/1781' while monitoring well on trip tank for proper displacement. Continue to build LNSD WBM system;Continue to build LNSD WBM system. Install tarps around scalper deck shakers. Re-install rubber under high pressure mud line over scalper roof and secure mud line. Clean cellar area around BOP stack. Re-route and secure drain from rig floor.;Continue to build LNSD WBM system. Resume p/up 4" 14# S-135 XT-39 DP f/ 1781' t/ 3764' while monitoring well on trip tank for proper displacement.;Continue to build LNSD WBM system. Pull and rack back DP f/ 3764' t/ 2637' while monitoring well on trip tank for proper displacement.;Continue to build LNSD WBM system. Resume p/up 4" 14# S-135 XT-39 DP f/ 2637' t/ 4022' while monitoring well on trip tank for proper displacement. Tag cement at 4022' w/ 10 Klbs. 6/18/2022 Drain sand traps to Pit #2 (short system water ) Rack back 3 std and p/up 9 more jts of dp for total 6700' of DP in derrick and on hook and re tag @ 4022' w/ 10k. Continue to build LNSD WBM system;Polish off cmt f/ 4022' t/ 4031' & circ btm/up. Continue to build LNSD WBM system;Prime and test and trouble shoot MP#3 power issue. Continue to build LNSD WBM system;Pooh rack back f/ 4031' t/ 787'. Continue to build LNSD WBM system;Joint Platform / Jack up drill gas alarm on platform, secured well all reported to proper muster area all accounted for. Then abandon platform all went to proper Brucker and Debriefing;Open well resume pooh f/ 787' inspect and l/dn Bha #1 (ok). Continue to build LNSD WBM system;P/up bha #2 w/ WIS 5-3/8" Whip stock assy shallow hole test MWD ok, P/up M/up. Continue to build LNSD WBM system;Trip in the hole with Whipstock and milling assembly at 120sec/std to 4010'. Monitoring well on trip tank.;Make up top drive and orient whipstock with MWD. Set whipstock at 55 deg ROH and shear off with top of whipstock at 4010'. Bolt sheared at 40 Klbs.;Transfer water from platform shaker tank to Pit #2 on jack-up and prep pits for displacement to LSND. Hold PJSM with rig crew and Mud Engineer.;Displace well to 8.9 ppg LSND at 205 gpm, 600 psi, taking all returns to scalper tank.;Discharge water in scalper tank overboard and rig up to pressure test casing.;Pressure test 7" casing to 2200 psi for 30 charted min. Good test.;Mill 7" window per WIS representative f/ 4010' t/ 4017' 113 rpm, 5-7 Kft-lbs Torque, 236 gpm, 685 psi Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/09/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI A-09 (PTD 169-085) CIBP 4/20/2022 Please include current contact information if different from above. PTD:169-085 T36568 Kayla Junke Digitally signed by Kayla Junke Date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tĞůůtŽƌŬWƌŽŐŶŽƐŝƐ tĞůů͗EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚͲϬϵ ĂƚĞ͗ϯͬϭϭͬϮϬϮϮ tĞůůEĂŵĞ͗E/hͲϬϵ;ZĞǀϯͿ W/EƵŵďĞƌ͗ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗^/WƌŽĚƵĐĞƌ>ĞŐ͗>ĞŐηϮ^tŽƌŶĞƌ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ϬϯͬϭϱͬϮϮ;ůŝŶĞǁŽƌŬͿZŝŐ͗^ƉĂƌƚĂŶϭϱϭ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍ϰϬϯĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗ŽŶŶĂŵďƌƵǌ;ϴϯϬϱͿWĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϭϲϵͲϬϴϱ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗ŚĂĚ,ĞůŐĞƐŽŶ;ϵϬϳͿͲϳϳϳͲϴϰϬϱ;KͿ;ϵϬϳͿϮϮϵͲϰϴϮϰ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗^ĞĂŶDĐůĂƵŐŚůŝŶ;ϵϬϳͿϮϮϯͲϲϳϴϰ;DͿ Current Bottom Hole Pressure: 1,520 psi @ 3,441’ TVD 0.442 lbs/ft (8.49 ppg) Maximum Expected BHP: 1,520 psi @ 3,441’ TVD 0.442 lbs/ft (8.49 ppg) Maximum Potential Surface Pressure: 1,176 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ƌŝĞĨtĞůů^ƵŵŵĂƌǇ dŚĞE/hͲϵǁĂƐŽƌŝŐŝŶĂůůǇĚƌŝůůĞĚŝŶϭϵϲϵ͘dŚĞǁĞůůǁĂƐĐŽŵƉůĞƚĞĚŝŶϭϵϳϱĂƐĂĞůƵŐĂƉƌŽĚƵĐŝŶŐǁĞůů͘ ǁŽƌŬŽǀĞƌǁĂƐĐŽŵƉůĞƚĞĚŝŶϭϵϵϮƚŚĂƚĂĚĚĞĚƉĞƌĨŽƌĂƚŝŽŶƐĂŶĚƌĂŶƐƚĂĐŬĞĚƉĂĐŬĞƌĐŽŵƉůĞƚŝŽŶ͘dŚĞ ƐůŝĚŝŶŐƐůĞĞǀĞƐĂƚϱ͕ϮϬϬ͛ĂŶĚϱ͕ϭϭϬ͛ĂƌĞĐůŽƐĞĚ͘/ŶϮϬϭϳΘϮϬϭϴďƌŝĚŐĞƉůƵŐƐǁĞƌĞƐĞƚŝŶƚŚĞƚƵďŝŶŐ͘dŚĞ ǁĞůůŚĂƐŶ͛ƚĨůŽǁĞĚƐŝŶĐĞDĂƌĐŚŽĨϮϬϭϴǁŚĞŶŝƚƐĂŶĚĞĚƵƉĂŶĚǁĂƚĞƌĞĚŽƵƚ͘ 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ϭϰ͘D/dͲdĂŶĚD/dͲ/ƚŽϭ͕ϱϬϬƉƐŝ͘;WƌŽǀŝĚĞϰϴŚƌƐŶŽƚŝĐĞĨŽƌK'ǁŝƚŶĞƐƐͲD/d͛ƐͿ ϭϱ͘Z/,ǁůŝŶĞĂŶĚƚĂŐdKŝŶƚƵďŝŶŐ;ĐŽƌƌĞůĂƚĞĚƚŽ>Ϳ ϭϲ͘Z/,ĂŶĚĐƵƚƚƵďŝŶŐΕϰ͕ϬϰϬ͛;ǀĞƌŝĨǇĚĞƉƚŚǁŝƚŚĞŶŐŝŶĞĞƌďĞĨŽƌĞĐƵƚƚŝŶŐƉĞŶĚŝŶŐŚŽǁŵƵĐŚ ĐĞŵĞŶƚǁĂƐƵƐĞĚƚŽƉůƵŐďĂĐŬĂŶĚǁŚŝƉƐƚŽĐŬǁŝůůďĞƐĞƚŽŶƚƵďŝŶŐƐƚƵď͘Ϳ ZŝŐϭϱϭWƌŽĐĞĚƵƌĞ͗ ϭ͘D/Zh^ƉĂƌƚĂŶϭϱϭ Ϯ͘/ŶƐƚĂůůdt͕EƚƌĞĞ͕EhKW ϯ͘dĞƐƚKW ¾dĞƐƚKWƚŽϮϱϬͬϯϬϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘dĞƐƚĂŶŶƵůĂƌƚŽϮϱϬͬϮϱϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘ ;EŽƚŝĨǇK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁƚŚĞŵƚŽǁŝƚŶĞƐƐƚĞƐƚͿ͘ ¾ŶƐƵƌĞƚŽůĞĂǀĞ͟͞ƐĞĐƚŝŽŶƐŝĚĞŽƵƚůĞƚǀĂůǀĞƐŽƉĞŶĚƵƌŝŶŐKWƚĞƐƚŝŶŐƐŽ ƉƌĞƐƐƵƌĞĚŽĞƐŶŽƚďƵŝůĚƵƉďĞŶĞĂƚŚƚŚĞdt͘ŽŶĨŝƌŵƚŚĞĐŽƌƌĞĐƚǀĂůǀĞƐĂƌĞ ŽƉĞŶĞĚ͊͊͊ ¾dĞƐƚsZƐŽŶϰ͘ϱ͟ƚĞƐƚũŽŝŶƚ;ϯϬϬϬƚĞƐƚŽŶůĂƌŐĞƐƚĂŶĚƐŵĂůůĞƐƚWͿ͕ ¾ŶƐƵƌĞŐĂƐŵŽŶŝƚŽƌƐĂƌĞĐĂůŝďƌĂƚĞĚĂŶĚƚĞƐƚĞĚŝŶĐŽŶũƵŶĐƚŝŽŶǁͬKW͘ ¾/ĨƚŚĞKWŝƐƵƐĞĚƚŽƐŚƵƚŝŶŽŶƚŚĞǁĞůůŝŶĂǁĞůůĐŽŶƚƌŽůƐŝƚƵĂƚŝŽŶŽƌŝĨKW ĞƋƵŝƉŵĞŶƚĐŽƵůĚďĞĐŽŵƉƌŽŵŝƐĞĚ͕>>KWĐŽŵƉŽŶĞŶƚƐƵƚŝůŝǌĞĚĨŽƌǁĞůůĐŽŶƚƌŽů ŽƌĐŽŵƉƌŽŵŝƐĞĚŵƵƐƚďĞƚĞƐƚĞĚƉƌŝŽƌƚŽƚŚĞŶĞǆƚƚƌŝƉŝŶƚŽƚŚĞǁĞůůďŽƌĞ͘ ϰ͘WƵůůdt ϱ͘WƵůůŚĂŶŐĞƌĂŶĚ>Εϰ͕ϬϰϬ͛ŽĨϰͲϭͬϮ͟ƚƵďŝŶŐ ¾ϮϵϰĨƚŽĨϰͲϭͬϮ͟hϴZ ¾^^^^s>ĂŶĚŝŶŐŶŝƉƉůĞΛϮϵϰ͛;ƌĞĐŽǀĞƌĂŶĚƐĞŶĚŝŶĨŽƌŝŶƐƉĞĐƚŝŽ ŶͿ 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ŽŶƚŝŶŐĞŶĐǇƉůĂŶĨŽƌZtK͕;ŝĨƵŶĂďůĞƚŽƉƌŽǀĞϮϱ͛ŽĨĐĞŵĞŶƚŽŶŽƵƚƐŝĚĞŽĨƚƵďŝŶŐͿ͗ ZŝŐWƌŽĐĞĚƵƌĞ;ŽŶƚŝŶŐĞŶĐǇZtKͿ͗ ŝ͘ZhůŝŶĞZ/,ĂŶĚĐƵƚƚƵďŝŶŐĂƚΕϰ͕Ϭϳϱ͛͘ ŝŝ͘ZůŝŶĞ ŝŝŝ͘D/ZhZŝŐϰϬϰ ŝǀ͘/ŶƐƚĂůůdt͕EƚƌĞĞ͕EhKW ǀ͘dĞƐƚKW ¾dĞƐƚKWƚŽϮϱϬͬϯϬϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘dĞƐƚĂŶŶƵůĂƌƚŽϮϱϬͬϮϱϬϬƉƐŝĨŽƌϱͬϱ ŵŝŶ͘;EŽƚŝĨǇK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁƚŚĞŵƚŽǁŝƚŶĞƐƐ ƚĞƐƚͿ͘ ¾/ĨƚŚĞKWŝƐƵƐĞĚƚŽƐŚƵƚŝŶŽŶƚŚĞǁĞůůŝŶĂǁĞůůĐŽŶƚƌŽůƐŝƚƵĂƚŝŽŶŽƌŝĨKW ĞƋƵŝƉŵĞŶƚĐŽƵůĚďĞĐŽŵƉƌŽŵŝƐĞĚ͕>>KWĐŽŵƉŽŶĞŶƚƐƵƚŝůŝǌĞĚĨŽƌǁĞůů ĐŽŶƚƌŽůŽƌĐŽŵƉƌŽŵŝƐĞĚŵƵƐƚďĞƚĞƐƚĞĚƉƌŝŽƌƚŽƚŚĞŶĞǆƚƚƌŝƉŝŶƚŽƚŚĞ ǁĞůůďŽƌĞ͘ ¾KWƐǁŝůůďĞĐůŽƐĞĚĂƐŶĞĞĚĞĚƚŽĐŝƌĐƵůĂƚĞƚŚĞǁĞůůĚƵƌŝŶŐƚŚŝƐǁŽƌŬŽǀĞƌ͘ ǀŝ͘WƵůůdt ǀŝŝ͘WƵůůŚĂŶŐĞƌĂŶĚƉƵůůƐĞĂůƐ ǀŝŝŝ͘ŝƌĐƵůĂƚĞǁĞůůǁŝƚŚǁĂƚĞƌ;ϴ͘ϰƉƉŐͿ ŝǆ͘WKK,ǁŝƚŚϰͲϭͬϮ͟hƚƵďŝŶŐ ǆ͘ZhůŝŶĞZ/,ĂŶĚƐĞƚϳ͟/WĂƚΕϰ͕Ϭϲϱ͛ĂŶĚĚƵŵƉϮϱĨƚŽĨĐĞŵĞŶƚŽŶƉůƵŐ ǆŝ͘ZůŝŶĞ ǆŝŝ͘WƌĞƐƐƵƌĞƚĞƐƚĐĂƐŝŶŐƚŽϮ͕ϱϬϬƉƐŝĂŶĚĐŚĂƌƚĨŽƌϯϬŵŝŶ ǆŝŝŝ͘EKWƐ͕EhĚƌǇŚŽůĞƚƌĞĞΘƚĞƐƚ ǆŝǀ͘ZDK,ŝůĐŽƌƉZŝŐϰϬϰ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘tĞůů^ĐŚĞŵĂƚŝĐƵƌƌĞŶƚ Ϯ͘tĞůů^ĐŚĞŵĂƚŝĐWƌŽƉŽƐĞĚ ϯ͘tĞůůŚĞĂĚ^ĐŚĞŵĂƚŝĐ ϰ͘KWƌĂǁŝŶŐʹ^ƉĂƌƚĂŶϭϱϭ ϱ͘ZtK^ƵŶĚƌǇŚĂŶŐĞ&Žƌŵ Ă͘tĞůů^ĐŚĞŵĂƚŝĐWƌŽƉŽƐĞĚ;ŽŶƚŝŶŐĞŶĐǇZtKͿ ď͘KWƌĂǁŝŶŐʹZŝŐϰϬϰ;ŽŶƚŝŶŐĞŶĐǇͿ Đ͘&ůƵŝĚͬ&ůŽǁŝĂŐƌĂŵƐʹZŝŐϰϬϰ;ŽŶƚŝŶŐĞŶĐǇͿ 3OXJ ZLOO EH PG DERYH WRS SHUI LQ WKLV FDVH EMP 3UHVVXUH WHVW FDVLQJ WR SVL DQG FKDUW IRU PLQXWHV EMP &LUFXODWH ZHOO ZLWK ZDWHU EHIRUH SXOOLQJ KDQJHU EMP BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚǇ͗,ϬϯͬϬϴͬϮϮ ^,Dd/ dǇŽŶĞŬWůĂƚĨŽƌŵ tĞůů͗ͲϬϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϴͬϭϰͬϭϵϵϮ Wd͗ϭϲϵͲϬϴϱ W/͗ ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ Wd͗ ϳ͕Ϭϱϳ͚ d͗ϴ͕ϬϮϮ͛ ϯϬ͟ Z<ƚŽd',ĞĂĚʹϱϰ͘Ϭϴ͛ ϳ͟ ϳ͕Ϭϱϳ͛/W ϳ͕ϲϲϲ͛ ĞŵĞŶƚZĞƚĂŝŶĞƌ ϳ͕ϲϵϭ͛&/^, ϭϲ͟ ϭϬͲϯͬϰ͟ dƵďŝŶŐ WƵŶĐŚ ϰ͕ϱϲϱ͛ dĂŐŐĞĚ&ŝůůΛ ϰ͕ϵϯϰ͛^>DŽŶ ϳͬϬϭͬϭϳ ϰ͕ϱϱϱ͛ʹϰ͕ϱϱϲ͛ ^ƋƵĞĞǌĞĚWĞƌĨƐ ϰ͕ϮϮϲ͛ʹϰ͕ϰϮϳ͛ ^ƋƵĞĞǌĞĚWĞƌĨƐ ¶),6+ ¶±¶ 6TXHH]HG3HUIV ¶),6+ ϯ͘ϱ͟/ ƌĞƐƚƌŝĐƚŝŽŶ ϰϭϱϬ͛ ϰ͕Ϯϱϳ͛ʹϰ͕ϯϭϵ͛ > dK Εϯ͕ϴϰϲ͛ dĂŐĨŝůůΛ ϰ͕ϮϬϮ͛ ϭϮͬϯϬͬϮϭ ; 1 ^/E'd/> ^ŝǌĞ tƚ 'ƌĂĚĞ ŽŶŶ / dŽƉ ƚŵ ϯϬ͟ ŽŶĚƵĐƚŽƌ tĞůĚĞĚ Ϯϴ͟ ^ƵƌĨ ϯϴϲ͛ ϭϲ͟ ϲϱ ,ͲϰϬ hdd ϭϱ͘ϮϱϬ͟ ^ƵƌĨ ϲϯϭ͛ ϭϬͲϯͬϰ͟ ϰϱ͘ϱ :Ͳϱϱ hdd ϵ͘ϵϱϬ͟ ^ƵƌĨ Ϯ͕ϱϴϳ͛ ϳ͟ Ϯϲ :Ͳϱϱ hdd ϲ͘Ϯϳϲ͟ ^ƵƌĨ͛ ϳ͕ϵϵϴ͛ dh/E'd/> ϰͲϭͬϮ͟ ϭϮ͘ϳϱ :Ͳϱϱ hϴƌĚ ϯ͘ϵϱϴ͟ ϱϰ͛ ϰ͕ϴϲϬ͛ ϯͲϭͬϮ͟ ϵ͘ϯ :Ͳϱϱ hϴƌĚ Ϯ͘ϵϵϮ͟ ϰ͕ϴϲϬ͛ ϱ͕ϮϮϯ͛ ϮͲϳͬϴ͟ ϲ͘ϱ :Ͳϱϱ hϴƌĚ Ϯ͘ϰϰϭ ϱ͕ϮϮϯ͛ ϲ͕ϴϴϲ͛ :t>Zzd/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϭ Ϯϵϰ͘ϱ͛ Ϯϵϰ͘ϱ͛ ϯ͘ϴϭϬ ϱ͘ϱϭϬ EŝƉƉůĞ͕KƚŝƐyyK͕ǁͬϯ͘ϴϭϯ͟&yϰͲϴtZW^^^s Ϯ ϰ͕ϭϯϬ͛ ϯ͕ϰϳϯ͛ ϯ͘ϵϰ ϱ͘ϵϴ Kd/^ŽǀĞƌƐŚŽƚd^ ϰ͕ϭϰϮ͛ ϯ͕ϰϴϮ͛ ϯ͘ϵϰ ϱ͘ϲϯ Kd/^ZĂƚĐŚ>ĂƚĐŚ ϰ͕ϭϰϯ͛ ϯ͕ϰϴϮ͛ ϯ͘ϴϴϬ ϲ͘ϬϬϬ WĂĐŬĞƌ͕KƚŝƐs^Z ϯϰ͕ϱϬϬ͛ϯ͕ϳϯϰ͛ ϯ͘ϵϱϴ ϯ͟DĂŐŶĂZĂŶŐĞƌŝĚŐĞWůƵŐǁͬϭϬ͛ĐĞŵĞŶƚ ;ϭͬϮϲͬϭϴͿ ϰ ϰ͕ϱϰϳ͛ ϯ͕ϳϲϳ͛ ϰ͘ϬϬϬ ϱ͘ϴϴϬ WĂĐŬĞƌ͕KƚŝƐdt ϱ ϰ͕ϱϲϯ͛ ϯ͕ϳϳϵ͛ ϯ͘ϴϴϬ ϲ͘ϬϬϬ WĂĐŬĞƌ͕KƚŝƐs^Z ;EŽƚ^ĞƚͿ ϰ͕ϱϲϵ͛ ϯ͕ϳϴϯ͛ ϯ͘ϵϱϴ ϱ͘ϲϬϬ ϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϭϰ͘ϱ͛d> ϲ ϰ͕ϳϴϰ͛ ϯ͕ϵϯϮ͛ ϯ͘ϴϭϯ ϱ͘ϱϬϬ ^ůĞĞǀĞ͕KƚŝƐy^^ʹůŽƐĞĚ;KƉĞŶƐƵƉͿ ϳ ϰ͕ϳϵϭ͛ ϯ͕ϵϯϳ͛ ϰ͘ϬϬϬ ϱ͘ϴϴϬ WĂĐŬĞƌ͕KƚŝƐdt ϰ͕ϳϵϲ͛ ϯ͕ϵϰϭ͛ ϯ͘ϵϱϬ ϱ͘ϲϬϬ ϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϱ͘ϳϵ͛d> ϰ͕ϳϵϲ͛ ϯ͕ϵϰϭ͛ ϯ͘ϵϱϴ ϯ͟DĂŐŶĂZĂŶŐĞWǁͬϭϬ͛ĐĞŵĞŶƚ;ϵͬϮϯͬϭϳͿ ϴ ϰ͕ϴϮϭ͛ ϯ͕ϵϱϴ͛ ϯ͘ϴϭϬ ϱ͘ϱϮϬ ^ůĞĞǀĞ͕KƚŝƐyK^^ʹůŽƐĞĚ;KƉĞŶƐĚŽǁŶͿ ϰ͕ϴϮϲ͛ ϯ͕ϵϲϮ͛ ϯ͘ϵϱϬ ϱ͘ϲϬϬ ϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕ϮϮ͘ϱϵ͛d> ϵ ϰ͕ϴϰϴ͛ ϯ͕ϵϳϳ͛ ϰ͘ϬϬϬ ϱ͘ϴϴϬ WĂĐŬĞƌ͕KƚŝƐt, ϭϬ ϰ͕ϴϲϬ͛ ϯ͕ϵϴϱ͛ Ϯ͘ϵϵϬ ϱ͘ϴϵϬ yK͕ϰ͘ϱyϯ͘ϱ ϰ͕ϴϲϭ͛ ϯ͕ϵϴϲ͛ Ϯ͘ϵϵϬ ϰ͘ϱϱϬ ϯͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϰϴ͘ϲϴ͛d> ϭϭ ϱ͕ϭϭϬ͛ ϰ͕ϭϱϵ͛ Ϯ͘ϳϱϬ ϰ͘ϮϴϬ ^ůĞĞǀĞ͕KƚŝƐy^^ʹůŽƐĞĚ;KƉĞŶƐƵƉͿ ϭϮ ϱ͕ϭϭϲ͛ ϰ͕ϭϲϯ͛ ϰ͘ϬϬϬ ϱ͘ϴϴϬ WĂĐŬĞƌ͕KƚŝƐt, ϱ͕ϭϮϴ͛ ϰ͕ϭϳϭ͛ Ϯ͘ϵϵϮ ϰ͘ϱϱϬ ϯͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕ϳϭ͘ϱϰ͛d> ϭϯ ϱ͕ϮϬϬ͛ ϰ͕ϮϮϭ͛ Ϯ͘ϳϱϬ ϰ͘ϮϴϬ ^ůĞĞǀĞ͕KƚŝƐyK^^ʹůŽƐĞĚ;KƉĞŶƐĚŽǁŶͿ ϭϰ ϱ͕Ϯϭϭ͛ ϰ͕ϮϮϴ͛ ϰ͘ϬϬϬ ϱ͘ϴϴϬ WĂĐŬĞƌ͕KƚŝƐt, ϭϱ ϱ͕ϮϮϯ͛ ϰ͕Ϯϯϳ͛ Ϯ͘ϰϰϬ ϱ͘ϬϯϬ yK͕ϯ͘ϱyϮ͘ϴϳϱ ϱ͕ϮϮϰ͛ ϰ͕Ϯϯϳ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕Ϯϱϯ͘ϵϯ͛d> ϱϰϴϯ͛ ϰ͕ϰϭϱ͛ Ϭ͘ϬϬϬ &/^,͗ϰƵƚƚĞƌĂƌƐ;ϭͿϭ͘ϱ͟yϱ͕͛;ϭͿϭ͘ϳϱ͟yϱ͕͛;ϮͿ ϭ͘Ϯϱ͟yϱ͕͛ϰϱϮ͛ŽĨϬ͘ϭϮϱ͟tŝƌĞ͕Ϯϭ͛^>dŽŽůƐƚƌŝŶŐΘ Ϯ͘ϴϳϱ͟WĂĐŬŽĨĨWůƵŐ ϭϲ ϱ͕ϰϴϰ͛ ϰ͕ϰϭϲ͛ Ϯ͘ϯϭϯ ϯ͘ϳϱϬ ^ůĞĞǀĞ͕KƚŝƐy^^;KƉĞŶƐƵƉͿ Ϭ͘ϴϳϱ Ϯ͘ϮϱϬ &/^,͗ͲϮ^ƚŽƉ ϭϳ ϱ͕ϱϮϭ͛ ϰ͕ϰϰϭ͛ ϰ͘ϬϬϬ ϱ͘ϴϴϬ WĂĐŬĞƌ͕KƚŝƐt, ϱ͕ϳϱϲ͛ ϰ͕ϲϬϮ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϵ͘ϴϱ͛d> ϲ͕ϭϰϭ͛ ϰ͕ϴϲϰ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕ϰϵ͘ϯ͛d> ϲ͕Ϯϳϰ͛ ϰ͕ϵϱϱ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϵ͘ϴϱ͛d> ϲ͕ϯϴϱ͛ ϱ͕ϬϯϬ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕Ϯϵ͘ϱϱ͛d> ϲ͕ϰϱϲ͛ ϱ͕Ϭϳϴ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϭϵ͘ϳϬ͛d> ϭϴ ϲ͕ϱϬϴ͛ ϱ͕ϭϭϰ͛ Ϯ͘ϯϭϯ ϯ͘ϳϱϬ ^ůĞĞǀĞ͕KƚŝƐyK^^ʹKƉĞŶ;KƉĞŶƐĚŽǁ ŶͿ ϭϵ ϲ͕ϱϮϮ͛ ϱ͕ϭϮϯ͛ ϯ͘ϮϱϬ ϱ͘Ϭϴϳ WĂĐŬĞƌ͕KƚŝƐt, ϮϬ ϲ͕ϱϯϴ͛ ϱ͕ϭϯϰ͛ Ϯ͘ϯϭϯ ϯ͘ϳϱϬ ^ůĞĞǀĞ͕KƚŝƐyK^^ʹKƉĞŶ;KƉĞŶƐĚŽǁ ŶͿ ϲ͕ϳϲϰ͛ ϱ͕Ϯϴϴ͛ Ϯ͘ϰϰϬ ϯ͘ϯϭϬ ϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕ϳϴ͘ϴϬ͛d> Ϯϭ ϲ͕ϴϳϱ͛ ϱ͕ϯϲϰ͛ Ϯ͘ϮϬϱ ϯ͘ϮϯϬ EŝƉƉůĞ͕KƚŝƐyE ϮϮ ϲ͕ϴϴϲ͛ ϱ͕ϯϳϭ͛ Ϯ͘ϰϰϬ ϰ͘ϱϬϬ tŝƌĞůŝŶĞZĞͲŶƚƌǇ'ƵŝĚĞ ϳ͕Ϭϱϳ͛ ϱ͕ϰϴϴ͛ Ϭ͘ϬϬϬ /W͕ĂŬĞƌ ϳ͕ϲϲϲ ϱ͕ϵϭϯ͛ Ϭ͘ϬϬϬ ĞŵĞŶƚZĞƚĂŝŶĞƌ͕ĂŬĞƌ<Ͳϭ ϳ͕ϲϵϭ ϱ͕ϵϯϬ͛ Ϭ͘ϬϬ &/^, hƉĚĂƚĞĚďǇ͗:>>ϬϮͬϬϵͬϭϴ ^,Dd/ dǇŽŶĞŬWůĂƚĨŽƌŵ tĞůů͗ͲϬϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϴͬϭϰͬϭϵϵϮ Wd͗ϭϲϵͲϬϴϱ W/͗ ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ WZ&KZd/KEd/> ŽŶĞ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ /Ͳ^ƚƌĂǇ ϰ͕ϮϮϲ͛ ϰ͕ϮϮϳ͛ ϯ͕ϱϰϰ͛ ϯ͕ϱϰϱ͛ ϭ͛ ϯͬϮϴͬϭϵϳϬ ^Y /Ͳ^ƚƌĂǇ ϰ͕Ϯϱϳ͛ ϰ͕Ϯϲϲ͛ ϯ͕ϱϲϰ͛ ϯ͕ϱϳϬ͛ ϵ͛ ϬϭͬϮϳͬϭϴ KWE /Ͳ ϰ͕Ϯϵϰ͛ ϰ͕ϯϭϵ͛ ϯ͕ϱϵϬ͛ ϯ͕ϲϬϳ͛ Ϯϱ͛ ϬϭͬϮϳͬϭϴ KWE /Ͳ^ƚƌĂǇ ϰ͕Ϯϰϳ͛ ϰ͕ϮϲϮ͛ ϯ͕ϱϱϵ͛ ϯ͕ϱϳϬ͛ ϭϱ͛ ϳͬϯϭͬϭϵϵϮ Dd^Y /Ͳ ϰ͕Ϯϴϰ͛ ϰ͕ϯϭϰ͛ ϯ͕ϱϴϱ͛ ϯ͕ϲϬϳ͛ ϮϬ͛ ϴͬϭͬϭϵϵϮ Dd^Y /Ͳ ϰ͕ϯϯϬ͛ ϰ͕ϰϬϬ͛ ϯ͕ϲϭϴΖ ϯ͕ϲϲϳ͛ ϳϬΖ ϴͬϭͬϭϵϵϮ Dd^Y /Ͳ ϰ͕ϰϮϲ͛ ϰ͕ϰϮϳ͛ ϯ͕ϲϴϲ͛ ϯ͕ϲϴϲΖ ϭΖ ϯͬϮϴͬϭϵϳϬ ^Y /Ͳ ϰ͕ϱϱϱ͛ ϰ͕ϱϱϲ͛ ϯ͕ϳϳϲ͛ ϯ͕ϳϳϳ͛ ϭ͛ ϯͬϮϴͬϭϵϳϬ ^Y /Ͳϭ͘Ϭ ϰ͕ϱϴϬ͛ ϰ͕ϱϵϬ͛ ϯ͕ϳϵϭ͛ ϯ͕ϳϵϴ͛ ϭϬ͛ ϬϵͬϮϱͬϭϳ /^K>d /Ͳϭ͘Ϭ ϰ͕ϱϴϰ͛ ϰ͕ϲϳϰ͛ ϯ͕ϳϵϲ͛ ϯ͕ϴϱϵ͛ ϵϬ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /ͲϮ͘Ϭ ϰ͕ϲϵϮ͛ ϰ͕ϳϴϮ͛ ϯ͕ϴϳϭ͛ ϯ͕ϵϯϰ͛ ϵϬ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϯ͘Ϭ ϰ͕ϴϬϰ͛ ϰ͕ϴϭϲ͛ ϯ͕ϵϰϵ͛ ϯ͕ϵϱϳ͛ ϭϮΖ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϯ͘ϭ ϰ͕ϴϯϯ͛ ϰ͕ϴϰϴ͛ ϯ͕ϵϲϵ͛ ϯ͕ϵϴϬ͛ ϭϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϰ͘Ϭ ϰ͕ϴϱϱ͛ ϰ͕ϵϮϬ͛ ϯ͕ϵϴϱ͛ ϰ͕ϬϯϬ͛ ϲϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϰ͘ϭ ϰ͕ϵϰϮ͛ ϰ͕ϵϱϮ͛ ϰ͕Ϭϰϱ͛ ϰ͕ϬϱϮ͛ ϭϬ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϱ͘Ϭ ϰ͕ϵϴϱ͛ ϱ͕ϬϮϬ͛ ϰ͕Ϭϳϱ͛ ϰ͕Ϭϵϵ͛ ϯϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϲ͘Ϭ ϱ͕ϬϲϬ͛ ϱ͕Ϭϴϱ͛ ϰ͕ϭϮϳ͛ ϰ͕ϭϰϰ͛ Ϯϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϳ͘Ϭ ϱ͕ϭϯϳ͛ ϱ͕ϭϳϮ͛ ϰϭϴϬ͛ ϰ͕ϮϬϰ͛ ϯϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϳ͘ϭ ϱ͕ϭϴϳ͛ ϱ͕ϭϵϯ͛ ϰ͕Ϯϭϱ͛ ϰϮϭϵ͛ ϲ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϴ͘Ϭ ϱ͕ϮϯϮ͛ ϱ͕ϮϰϮ͛ ϰ͕Ϯϰϲ͛ ϰ͕Ϯϱϯ͛ ϭϬ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϴ͘Ϯ ϱ͕Ϯϲϰ͛ ϱ͕Ϯϴϵ͛ ϰ͕Ϯϲϴ͛ ϰ͕Ϯϴϱ͛ Ϯϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϵ͘Ϭ ϱ͕ϯϯϮ͛ ϱ͕ϯϱϳ͛ ϰ͕ϯϭϱ͛ ϰ͕ϯϯϮ͛ Ϯϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /ͲϭϬ͘Ϭ ϱ͕ϯϴϬ͛ ϱ͕ϯϵϱ͛ ϰ͕ϯϰϴ͛ ϰ͕ϯϱϴ͛ ϭϱ͛ ϴͬϭϰͬϭϵϵϮ /^K>d /Ͳϭϭ ϱ͕ϰϭϲ͛ ϱ͕ϰϳϲ͛ ϰ͕ϯϳϮ͛ ϰ͕ϰϭϯ͛ ϲϬ͛ ϴͬϭϰͬϭϵϵϮ /^K>d ϱ͕ϰϴϳ͛ ϱ͕ϰϴϴ͛ ϰ͕ϰϮϭ͛ ϰ͕ϰϮϮ͛ ϭ͛ ϯͬϮϴͬϭϵϳϬ /^K>d Ͳϲ ϱ͕ϳϲϮ͛ ϱ͕ϳϲϴ͛ ϰ͕ϲϬϴ͛ ϰ͕ϲϭϯ͛ ϲ͛ ϴͬϮϵͬϭϵϵϮ /^K>d Ͳϯ ϲ͕ϭϰϵ͛ ϲ͕ϭϱϰ͛ ϰ͕ϴϳϮ͛ ϰ͕ϴϳϲ͛ ϱ͛ ϴͬϮϵͬϭϵϵϮ /^K>d Ͳϰ ϲ͕ϭϲϮ͛ ϲ͕ϭϴϳ͛ ϰ͕ϴϴϭ͛ ϰ͕ϴϵϴ͛ Ϯϱ͛ ϴͬϮϵͬϭϵϵϮ /^K>d Ͳϯ ϲ͕ϮϴϬ͛ ϲ͕Ϯϴϱ͛ ϰ͕ϵϲϮ͛ ϰ͕ϵϲϱ͛ ϱ͛ ϴͬϮϵͬϭϵϵϮ /^K>d Ͳϵ ϲ͕ϯϵϰ͛ ϲ͕ϰϭϰ͛ ϱ͕Ϭϯϵ͛ ϱ͕Ϭϱϯ͛ ϮϬ͛ ϴͬϮϵͬϭϵϵϮ /^K>d &ͲϮ ϲ͕ϰϲϯ͛ ϲ͕ϰϳϴ͛ ϱ͕Ϭϴϲ͛ ϱ͕Ϭϵϲ͛ ϭϱ͛ ϴͬϮϵͬϭϵϵϮ /^K>d ,ͲϮ ,Ͳϯ ,Ͳϰ ,Ͳϱ ϲ͕ϳϳϮ͛ ϲ͕ϴϰϮ͛ ϱ͕Ϯϵϳ͛ ϱ͕ϯϰϱ͛ ϲϵ͛ ϴͬϮϵͬϭϵϵϮ /^K>d :Ͳϴ ϳ͕Ϭϳϲ͛ ϳ͕Ϭϵϴ͛ ϱ͕ϱϬϭ͛ ϱ͕ϱϭϲ͛ ϮϮ͛ /^K>d :ͲϮ ϳ͕ϭϯϮ͛ ϳ͕ϭϰϮ͛ ϱ͕ϱϰϬ͛ ϱ͕ϱϰϳ͛ ϭϬ͛ /^K>d <ͲϰΘϰ͘ϭ ϳ͕ϮϰϬ͛ ϳ͕ϮϳϬ͛ ϱ͕ϲϭϱ͛ ϱ͕ϲϯϱ͛ ϯϬ͛ /^K>d /ͲϮΘ/Ͳϯ ϳ͕ϯϭϮ͛ ϳ͕ϯϯϳ͛ ϱ͕ϲϲϱ͛ ϱ͕ϲϴϮ͛ Ϯϱ͛ /^K>d DͲϮ ϳ͕ϯϳϵ͛ ϳ͕ϯϴϵ͛ ϱ͕ϳϭϮ͛ ϱ͕ϳϭϵ͛ ϭϬ͛ /^K>d DͲϵ ϳ͕ϱϯϵ͛ ϳ͕ϱϰϰ͛ ϱ͕ϴϮϰ͛ ϱ͕ϴϮϳ͛ ϱ͛ /^K>d DͲϭϭ ϳ͕ϱϴϭ͛ ϳ͕ϱϴϳ͛ ϱ͕ϴϱϯ͛ ϱ͕ϴϱϴ͛ ϲ͛ /^K>d EͲϯ ϳ͕ϲϵϭ͛ ϳ͕ϲϵϳ͛ ϱ͕ϵϯϬ͛ ϱ͕ϵϯϱ͛ ϲ͛ /^K>d EͲϰ ϳ͕ϳϮϰ͛ ϳ͕ϳϯϰ͛ ϱ͕ϵϱϰ͛ ϱ͕ϵϲϭ͛ ϭϬ͛ /^K>d BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚǇ͗,ϬϯͬϬϵͬϮϮ WZKWK^^,Dd/ dǇŽŶĞŬWůĂƚĨŽƌŵ tĞůů͗ͲϬϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϴͬϭϰͬϭϵϵϮ Wd͗ϭϲϵͲϬϴϱ W/͗ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ ^/E'd/> ^ŝǌĞtƚ'ƌĂĚĞŽŶŶ/dŽƉƚŵ ϯϬ͟ŽŶĚƵĐƚŽƌtĞůĚĞĚϮϴ͟^ƵƌĨϯϴϲ͛ ϭϲ͟ϲϱ,ͲϰϬhddϭϱ͘ϮϱϬ͟^ƵƌĨϲϯϭ͛ ϭϬͲϯͬϰ͟ϰϱ͘ϱ:Ͳϱϱhddϵ͘ϵϱϬ͟^ƵƌĨϮ͕ϱϴϳ͛ ϳ͟Ϯϲ:Ͳϱϱhddϲ͘Ϯϳϲ͟^ƵƌĨ͛ϳ͕ϵϵϴ͛ dh/E'd/> ϰͲϭͬϮ͟ϭϮ͘ϳϱ:ͲϱϱhϴƌĚϯ͘ϵϱϴ͟цϰ͕ϬϰϬ͛ϰ͕ϴϲϬ͛ ϯͲϭͬϮ͟ϵ͘ϯ:ͲϱϱhϴƌĚϮ͘ϵϵϮ͟ϰ͕ϴϲϬ͛ϱ͕ϮϮϯ͛ ϮͲϳͬϴ͟ϲ͘ϱ:ͲϱϱhϴƌĚϮ͘ϰϰϭϱ͕ϮϮϯ͛ϲ͕ϴϴϲ͛ :t>Zzd/> EŽĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ/K /ƚĞŵ ϭцϰ͕ϬϰϬ͛цϯ͕ϰϬϵ͛ϲ͘ϬϬϬtŚŝƉƐƚŽĐŬ цϰ͕ϭϯϵ͛цϯ͕ϰϴϬ͛ĞŵĞŶƚƌĞƚĂŝŶĞƌǁͬŵŝŶϮϱ͛ŽĨĐĞŵĞŶƚ цϰ͕ϭϰϯ͛цϯ͕ϰϴϮ͛/W Ϯ ϰ͕ϭϯϬ͛ϯ͕ϰϳϯ͛ϯ͘ϵϰϱ͘ϵϴKd/^ŽǀĞƌƐŚŽƚd^ ϰ͕ϭϰϮ͛ϯ͕ϰϴϮ͛ϯ͘ϵϰϱ͘ϲϯKd/^ZĂƚĐŚ>ĂƚĐŚ ϰ͕ϭϰϯ͛ϯ͕ϰϴϮ͛ϯ͘ϴϴϬϲ͘ϬϬϬWĂĐŬĞƌ͕KƚŝƐs^Z ϯϰ͕ϱϬϬ͛ϯ͕ϳϯϰ͛ϯ͟DĂŐŶĂZĂŶŐĞƌŝĚŐĞWůƵŐǁͬϭϬ͛ĐĞŵĞŶƚ ;ϭͬϮϲͬϭϴͿ ϰϰ͕ϱϰϳ͛ϯ͕ϳϲϳ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐdt ϱϰ͕ϱϲϯ͛ϯ͕ϳϳϵ͛ϯ͘ϴϴϬϲ͘ϬϬϬWĂĐŬĞƌ͕KƚŝƐs^Z;EŽƚ^ĞƚͿ ϰ͕ϱϲϵ͛ϯ͕ϳϴϯ͛ϯ͘ϵϱϴϱ͘ϲϬϬϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϭϰ͘ϱ͛d> ϲϰ͕ϳϴϰ͛ϯ͕ϵϯϮ͛ϯ͘ϴϭϯϱ͘ϱϬϬ^ůĞĞǀĞ͕KƚŝƐy^^ʹůŽƐĞĚ;KƉĞŶƐƵƉͿ ϳϰ͕ϳϵϭ͛ϯ͕ϵϯϳ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐdt ϰ͕ϳϵϲ͛ϯ͕ϵϰϭ͛ϯ͘ϵϱϬϱ͘ϲϬϬϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϱ͘ϳϵ͛d> ϰ͕ϳϵϲ͛ϯ͕ϵϰϭ͛ϯ͟DĂŐŶĂZĂŶŐĞWǁͬϭϬ͛ĐĞŵĞŶƚ;ϵͬϮϯͬϭϳͿ ϴϰ͕ϴϮϭ͛ϯ͕ϵϱϴ͛ϯ͘ϴϭϬϱ͘ϱϮϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹůŽƐĞĚ;KƉĞŶƐĚŽǁŶͿ ϰ͕ϴϮϲ͛ϯ͕ϵϲϮ͛ϯ͘ϵϱϬϱ͘ϲϬϬϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕ϮϮ͘ϱϵ͛d> ϵϰ͕ϴϰϴ͛ϯ͕ϵϳϳ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϭϬϰ͕ϴϲϬ͛ϯ͕ϵϴϱ͛Ϯ͘ϵϵϬϱ͘ϴϵϬyK͕ϰ͘ϱyϯ͘ϱ ϰ͕ϴϲϭ͛ϯ͕ϵϴϲ͛Ϯ͘ϵϵϬϰ͘ϱϱϬϯͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϰϴ͘ϲϴ͛d> ϭϭϱ͕ϭϭϬ͛ϰ͕ϭϱϵ͛Ϯ͘ϳϱϬϰ͘ϮϴϬ^ůĞĞǀĞ͕KƚŝƐy^^ʹůŽƐĞĚ;KƉĞŶƐƵƉͿ ϭϮϱ͕ϭϭϲ͛ϰ͕ϭϲϯ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϱ͕ϭϮϴ͛ϰ͕ϭϳϭ͛Ϯ͘ϵϵϮϰ͘ϱϱϬϯͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕ϳϭ͘ϱϰ͛d> ϭϯϱ͕ϮϬϬ͛ϰ͕ϮϮϭ͛Ϯ͘ϳϱϬϰ͘ϮϴϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹůŽƐĞĚ;KƉĞŶƐĚŽǁŶͿ ϭϰϱ͕Ϯϭϭ͛ϰ͕ϮϮϴ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϭϱϱ͕ϮϮϯ͛ϰ͕Ϯϯϳ͛Ϯ͘ϰϰϬϱ͘ϬϯϬyK͕ϯ͘ϱyϮ͘ϴϳϱ ϱ͕ϮϮϰ͛ϰ͕Ϯϯϳ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕Ϯϱϯ͘ϵϯ͛d> ϱϰϴϯ͛ϰ͕ϰϭϱ͛Ϭ͘ϬϬϬ&/^,͗ϰƵƚƚĞƌĂƌƐ;ϭͿϭ͘ϱ͟yϱ͕͛;ϭͿϭ͘ϳϱ͟yϱ͕͛;ϮͿ ϭ͘Ϯϱ͟yϱ͕͛ϰϱϮ͛ŽĨϬ͘ϭϮϱ͟tŝƌĞ͕Ϯϭ͛^>dŽŽůƐƚƌŝŶŐΘ Ϯ͘ϴϳϱ͟WĂĐŬŽĨĨWůƵŐ ϭϲϱ͕ϰϴϰ͛ϰ͕ϰϭϲ͛Ϯ͘ϯϭϯϯ͘ϳϱϬ^ůĞĞǀĞ͕KƚŝƐy^^;KƉĞŶƐƵƉͿ Ϭ͘ϴϳϱϮ͘ϮϱϬ&/^,͗ͲϮ^ƚŽƉ ϭϳϱ͕ϱϮϭ͛ϰ͕ϰϰϭ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϱ͕ϳϱϲ͛ϰ͕ϲϬϮ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϵ͘ϴϱ͛d> ϲ͕ϭϰϭ͛ϰ͕ϴϲϰ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕ϰϵ͘ϯ͛d> ϲ͕Ϯϳϰ͛ϰ͕ϵϱϱ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϵ͘ϴϱ͛d> ϲ͕ϯϴϱ͛ϱ͕ϬϯϬ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕Ϯϵ͘ϱϱ͛d> ϲ͕ϰϱϲ͛ϱ͕Ϭϳϴ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϭϵ͘ϳϬ͛d> ϭϴϲ͕ϱϬϴ͛ϱ͕ϭϭϰ͛Ϯ͘ϯϭϯϯ͘ϳϱϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹKƉĞŶ;KƉĞŶƐĚŽǁŶͿ ϭϵϲ͕ϱϮϮ͛ϱ͕ϭϮϯ͛ϯ͘ϮϱϬϱ͘ϬϴϳWĂĐŬĞƌ͕KƚŝƐt, ϮϬϲ͕ϱϯϴ͛ϱ͕ϭϯϰ͛Ϯ͘ϯϭϯϯ͘ϳϱϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹKƉĞŶ;KƉĞŶƐĚŽǁŶͿ ϲ͕ϳϲϰ͛ϱ͕Ϯϴϴ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕ϳϴ͘ϴϬ͛d> Ϯϭϲ͕ϴϳϱ͛ϱ͕ϯϲϰ͛Ϯ͘ϮϬϱϯ͘ϮϯϬEŝƉƉůĞ͕KƚŝƐyE ϮϮϲ͕ϴϴϲ͛ϱ͕ϯϳϭ͛Ϯ͘ϰϰϬϰ͘ϱϬϬtŝƌĞůŝŶĞZĞͲŶƚƌǇ'ƵŝĚĞ ϳ͕Ϭϱϳ͛ϱ͕ϰϴϴ͛Ϭ͘ϬϬϬ/W͕ĂŬĞƌ ϳ͕ϲϲϲϱ͕ϵϭϯ͛Ϭ͘ϬϬϬĞŵĞŶƚZĞƚĂŝŶĞƌ͕ĂŬĞƌ<Ͳϭ ϳ͕ϲϵϭϱ͕ϵϯϬ͛Ϭ͘ϬϬ&/^, hƉĚĂƚĞĚďǇ͗:>>ϬϮͬϬϵͬϭϴ WZKWK^^,Dd/ dǇŽŶĞŬWůĂƚĨŽƌŵ tĞůů͗ͲϬϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϴͬϭϰͬϭϵϵϮ Wd͗ϭϲϵͲϬϴϱ W/͗ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ WZ&KZd/KEd/> ŽŶĞdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&d ĂƚĞ ^ƚĂƚƵƐ /Ͳ^ƚƌĂǇϰ͕ϮϮϲ͛ϰ͕ϮϮϳ͛ϯ͕ϱϰϰ͛ ϯ͕ϱϰϱ͛ϭ͛ ϯͬϮϴͬϭϵϳϬ^Y /Ͳ^ƚƌĂǇϰ͕Ϯϱϳ͛ϰ͕Ϯϲϲ͛ϯ͕ϱϲϰ͛ ϯ͕ϱϳϬ͛ϵ͛ ϬϭͬϮϳͬϭϴKWE /Ͳϰ͕Ϯϵϰ͛ϰ͕ϯϭϵ͛ϯ͕ϱϵϬ͛ϯ͕ϲϬϳ͛Ϯϱ͛ϬϭͬϮϳͬϭϴKWE /Ͳ^ƚƌĂǇϰ͕Ϯϰϳ͛ϰ͕ϮϲϮ͛ϯ͕ϱϱϵ͛ϯ͕ϱϳϬ͛ϭϱ͛ϳͬϯϭͬϭϵϵϮDd^Y /Ͳϰ͕Ϯϴϰ͛ϰ͕ϯϭϰ͛ϯ͕ϱϴϱ͛ϯ͕ϲϬϳ͛ϮϬ͛ϴͬϭͬϭϵϵϮDd^Y /Ͳϰ͕ϯϯϬ͛ϰ͕ϰϬϬ͛ϯ͕ϲϭϴΖϯ͕ϲϲϳ͛ϳϬΖϴͬϭͬϭϵϵϮDd^Y /Ͳϰ͕ϰϮϲ͛ϰ͕ϰϮϳ͛ϯ͕ϲϴϲ͛ϯ͕ϲϴϲΖϭΖϯͬϮϴͬϭϵϳϬ^Y /Ͳ ϰ͕ϱϱϱ͛ϰ͕ϱϱϲ͛ϯ͕ϳϳϲ͛ ϯ͕ϳϳϳ͛ϭ͛ ϯͬϮϴͬϭϵϳϬ^Y /Ͳϭ͘Ϭϰ͕ϱϴϬ͛ϰ͕ϱϵϬ͛ϯ͕ϳϵϭ͛ ϯ͕ϳϵϴ͛ϭϬ͛ ϬϵͬϮϱͬϭϳ/^K>d /Ͳϭ͘Ϭϰ͕ϱϴϰ͛ϰ͕ϲϳϰ͛ϯ͕ϳϵϲ͛ϯ͕ϴϱϵ͛ϵϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d /ͲϮ͘Ϭϰ͕ϲϵϮ͛ϰ͕ϳϴϮ͛ϯ͕ϴϳϭ͛ϯ͕ϵϯϰ͛ϵϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϯ͘Ϭϰ͕ϴϬϰ͛ϰ͕ϴϭϲ͛ϯ͕ϵϰϵ͛ϯ͕ϵϱϳ͛ϭϮΖϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϯ͘ϭϰ͕ϴϯϯ͛ϰ͕ϴϰϴ͛ϯ͕ϵϲϵ͛ ϯ͕ϵϴϬ͛ϭϱ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϰ͘Ϭϰ͕ϴϱϱ͛ϰ͕ϵϮϬ͛ϯ͕ϵϴϱ͛ ϰ͕ϬϯϬ͛ϲϱ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϰ͘ϭϰ͕ϵϰϮ͛ϰ͕ϵϱϮ͛ϰ͕Ϭϰϱ͛ϰ͕ϬϱϮ͛ϭϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϱ͘Ϭϰ͕ϵϴϱ͛ϱ͕ϬϮϬ͛ϰ͕Ϭϳϱ͛ϰ͕Ϭϵϵ͛ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϲ͘Ϭϱ͕ϬϲϬ͛ϱ͕Ϭϴϱ͛ϰ͕ϭϮϳ͛ϰ͕ϭϰϰ͛Ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϳ͘Ϭϱ͕ϭϯϳ͛ϱ͕ϭϳϮ͛ϰϭϴϬ͛ϰ͕ϮϬϰ͛ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϳ͘ϭϱ͕ϭϴϳ͛ϱ͕ϭϵϯ͛ϰ͕Ϯϭϱ͛ ϰϮϭϵ͛ϲ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϴ͘Ϭϱ͕ϮϯϮ͛ϱ͕ϮϰϮ͛ϰ͕Ϯϰϲ͛ ϰ͕Ϯϱϯ͛ϭϬ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϴ͘Ϯϱ͕Ϯϲϰ͛ϱ͕Ϯϴϵ͛ϰ͕Ϯϲϴ͛ϰ͕Ϯϴϱ͛Ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϵ͘Ϭϱ͕ϯϯϮ͛ϱ͕ϯϱϳ͛ϰ͕ϯϭϱ͛ϰ͕ϯϯϮ͛Ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /ͲϭϬ͘Ϭϱ͕ϯϴϬ͛ϱ͕ϯϵϱ͛ϰ͕ϯϰϴ͛ϰ͕ϯϱϴ͛ϭϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϭϭϱ͕ϰϭϲ͛ϱ͕ϰϳϲ͛ϰ͕ϯϳϮ͛ϰ͕ϰϭϯ͛ϲϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d ϱ͕ϰϴϳ͛ϱ͕ϰϴϴ͛ϰ͕ϰϮϭ͛ ϰ͕ϰϮϮ͛ϭ͛ ϯͬϮϴͬϭϵϳϬ/^K>d Ͳϲϱ͕ϳϲϮ͛ϱ͕ϳϲϴ͛ϰ͕ϲϬϴ͛ ϰ͕ϲϭϯ͛ϲ͛ ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϯϲ͕ϭϰϵ͛ϲ͕ϭϱϰ͛ϰ͕ϴϳϮ͛ϰ͕ϴϳϲ͛ϱ͛ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϰϲ͕ϭϲϮ͛ϲ͕ϭϴϳ͛ϰ͕ϴϴϭ͛ϰ͕ϴϵϴ͛Ϯϱ͛ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϯϲ͕ϮϴϬ͛ϲ͕Ϯϴϱ͛ϰ͕ϵϲϮ͛ϰ͕ϵϲϱ͛ϱ͛ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϵϲ͕ϯϵϰ͛ϲ͕ϰϭϰ͛ϱ͕Ϭϯϵ͛ϱ͕Ϭϱϯ͛ϮϬ͛ϴͬϮϵͬϭϵϵϮ/^K>d &ͲϮϲ͕ϰϲϯ͛ϲ͕ϰϳϴ͛ϱ͕Ϭϴϲ͛ ϱ͕Ϭϵϲ͛ϭϱ͛ ϴͬϮϵͬϭϵϵϮ/^K>d ,ͲϮ ,Ͳϯ ,Ͳϰ ,Ͳϱ ϲ͕ϳϳϮ͛ϲ͕ϴϰϮ͛ϱ͕Ϯϵϳ͛ ϱ͕ϯϰϱ͛ϲϵ͛ ϴͬϮϵͬϭϵϵϮ /^K>d :Ͳϴϳ͕Ϭϳϲ͛ϳ͕Ϭϵϴ͛ϱ͕ϱϬϭ͛ϱ͕ϱϭϲ͛ϮϮ͛/^K>d :ͲϮϳ͕ϭϯϮ͛ϳ͕ϭϰϮ͛ϱ͕ϱϰϬ͛ ϱ͕ϱϰϳ͛ϭϬ͛ /^K>d <ͲϰΘϰ͘ϭϳ͕ϮϰϬ͛ϳ͕ϮϳϬ͛ϱ͕ϲϭϱ͛ ϱ͕ϲϯϱ͛ϯϬ͛ /^K>d /ͲϮΘ/Ͳϯϳ͕ϯϭϮ͛ϳ͕ϯϯϳ͛ϱ͕ϲϲϱ͛ϱ͕ϲϴϮ͛Ϯϱ͛/^K>d DͲϮϳ͕ϯϳϵ͛ϳ͕ϯϴϵ͛ϱ͕ϳϭϮ͛ϱ͕ϳϭϵ͛ϭϬ͛/^K>d DͲϵϳ͕ϱϯϵ͛ϳ͕ϱϰϰ͛ϱ͕ϴϮϰ͛ϱ͕ϴϮϳ͛ϱ͛/^K>d DͲϭϭϳ͕ϱϴϭ͛ϳ͕ϱϴϳ͛ϱ͕ϴϱϯ͛ϱ͕ϴϱϴ͛ϲ͛/^K>d EͲϯϳ͕ϲϵϭ͛ϳ͕ϲϵϳ͛ϱ͕ϵϯϬ͛ ϱ͕ϵϯϱ͛ϲ͛ /^K>d EͲϰϳ͕ϳϮϰ͛ϳ͕ϳϯϰ͛ϱ͕ϵϱϰ͛ ϱ͕ϵϲϭ͛ϭϬ͛ /^K>d 7\RQHN3ODWIRUP $&XUUHQW dƵďŝŶŐŚĞĂĚ͕&DͲdͲKK͕ ϭϭϯDǆϵϯD͕ǁͬϮͲ ϮϭͬϭϲϱD^^K sĂůǀĞ͕DĂƐƚĞƌ͕&DͲϭϮϬ͕ ϰϭͬϭϲϯD&͕,tK͕ ƚƌŝŵ sĂůǀĞ͕hƉƉĞƌŵĂƐƚĞƌ͕^^s &DͲϭϮϬ͕ϰϭͬϭϲϯD&͕ǁͬ &DWŽƉĞƌĂƚŽƌ͕ƚƌŝŵ sĂůǀĞ͕^ǁĂď͕&DͲϭϮϬ ϰϭͬϭϲϯD&͕,tK͕ ƚƌŝŵ ,d͕KƚŝƐ͕ϰϭͬϭϲϯD&ǆ ϳ͘ϱΖ͛KƚŝƐƋƵŝĐŬƵŶŝŽŶƚŽƉ ϭϲΖ͛ ϳΖ͛ ^ƚĂƌƚŝŶŐŚĞĂĚ͕KdͲϮϵͲ>͕ ϭϲΖ͛ϯDǆϭϲΖ͛^Kt͕ǁͬϮͲϮ ϭͬϭϲϱD&K ĂƐŝŶŐƐƉŽŽů͕KdͲͲϮϵ>ͲKK ϭϲΖ͛ϯDǆϭϭϯD͕ǁͬ ϮͲϮϭͬϭϲϱD&K dǇŽŶĞŬWůĂƚĨŽƌŵ ͲϬϵ ϭϲǆϭϬвǆϳǆϰЪ sĂůǀĞ͕tŝŶŐ͕^^s͕&DͲϭϮϬ͕ ϰϭͬϭϲϯD&͕ǁͬϭϱΖ͛ǆĞůƐŽŶ D,ŽƉĞƌĂƚŽƌ͕ƚƌŝŵ dƵďŝŶŐŚĂŶŐĞƌ͕&DͲdͲEͲ >͕ϵǆϰЪhϴƌĚůŝĨƚĂŶĚ ϰЪ/dƐƵƐƉ͕ǁͬϰΖ͛ƚǇƉĞ/^Ͳ WsƉƌŽĨŝůĞ͕ϭͲЬŶƉƚĐŽŶƚƌŽů ůŝŶĞƉŽƌƚ ĚĂƉƚĞƌ͕&DͲϱWͲ>͕ ϵΖ͛ϯD&ǆϰϭͬϭϲϯD ϰЪ͛͛ ϭϬв͛͛ E/Ͳϭϭ ϬϭͲϮϴͲϮϮ KW 6SDUWDQ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚǇ͗,ϬϯͬϬϵͬϮϮ WZKWK^^,Dd/ ŽŶƚŝŶŐĞŶĐǇZtK dǇŽŶĞŬWůĂƚĨŽƌŵ tĞůů͗ͲϬϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϴͬϭϰͬϭϵϵϮ Wd͗ϭϲϵͲϬϴϱ W/͗ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ ^/E'd/> ^ŝǌĞtƚ'ƌĂĚĞŽŶŶ/dŽƉƚŵ ϯϬ͟ŽŶĚƵĐƚŽƌtĞůĚĞĚϮϴ͟^ƵƌĨϯϴϲ͛ ϭϲ͟ϲϱ,ͲϰϬhddϭϱ͘ϮϱϬ͟^ƵƌĨϲϯϭ͛ ϭϬͲϯͬϰ͟ϰϱ͘ϱ:Ͳϱϱhddϵ͘ϵϱϬ͟^ƵƌĨϮ͕ϱϴϳ͛ ϳ͟Ϯϲ:Ͳϱϱhddϲ͘Ϯϳϲ͟^ƵƌĨ͛ϳ͕ϵϵϴ͛ dh/E'd/> ϰͲϭͬϮ͟ϭϮ͘ϳϱ:ͲϱϱhϴƌĚϯ͘ϵϱϴ͟цϰ͕ϬϳϬ͛ϰ͕ϴϲϬ͛ ϯͲϭͬϮ͟ϵ͘ϯ:ͲϱϱhϴƌĚϮ͘ϵϵϮ͟ϰ͕ϴϲϬ͛ϱ͕ϮϮϯ͛ ϮͲϳͬϴ͟ϲ͘ϱ:ͲϱϱhϴƌĚϮ͘ϰϰϭϱ͕ϮϮϯ͛ϲ͕ϴϴϲ͛ :t>Zzd/> EŽĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ/K /ƚĞŵ ϭцϰ͕ϬϰϬ͛цϯ͕ϰϬϵ͛ϲ͘ϬϬϬtŚŝƉƐƚŽĐŬ цϰ͕ϬϳϬ͛цϯ͕ϰϯϬ͛/WǁͬϮϱ͛ŽĨĐĞŵĞŶƚ цϰ͕ϭϯϵ͛цϯ͕ϰϴϬ͛ĞŵĞŶƚƌĞƚĂŝŶĞƌǁͬŵŝŶϮϱ͛ŽĨĐĞŵĞŶƚ цϰ͕ϭϰϯ͛цϯ͕ϰϴϮ͛/W Ϯ ϰ͕ϭϯϬ͛ϯ͕ϰϳϯ͛ϯ͘ϵϰϱ͘ϵϴKd/^ŽǀĞƌƐŚŽƚd^ ϰ͕ϭϰϮ͛ϯ͕ϰϴϮ͛ϯ͘ϵϰϱ͘ϲϯKd/^ZĂƚĐŚ>ĂƚĐŚ ϰ͕ϭϰϯ͛ϯ͕ϰϴϮ͛ϯ͘ϴϴϬϲ͘ϬϬϬWĂĐŬĞƌ͕KƚŝƐs^Z ϯϰ͕ϱϬϬ͛ϯ͕ϳϯϰ͛ϯ͟DĂŐŶĂZĂŶŐĞƌŝĚŐĞWůƵŐǁͬϭϬ͛ĐĞŵĞŶƚ ;ϭͬϮϲͬϭϴͿ ϰϰ͕ϱϰϳ͛ϯ͕ϳϲϳ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐdt ϱϰ͕ϱϲϯ͛ϯ͕ϳϳϵ͛ϯ͘ϴϴϬϲ͘ϬϬϬWĂĐŬĞƌ͕KƚŝƐs^Z;EŽƚ^ĞƚͿ ϰ͕ϱϲϵ͛ϯ͕ϳϴϯ͛ϯ͘ϵϱϴϱ͘ϲϬϬϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϭϰ͘ϱ͛d> ϲϰ͕ϳϴϰ͛ϯ͕ϵϯϮ͛ϯ͘ϴϭϯϱ͘ϱϬϬ^ůĞĞǀĞ͕KƚŝƐy^^ʹůŽƐĞĚ;KƉĞŶƐƵƉͿ ϳϰ͕ϳϵϭ͛ϯ͕ϵϯϳ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐdt ϰ͕ϳϵϲ͛ϯ͕ϵϰϭ͛ϯ͘ϵϱϬϱ͘ϲϬϬϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϱ͘ϳϵ͛d> ϰ͕ϳϵϲ͛ϯ͕ϵϰϭ͛ϯ͟DĂŐŶĂZĂŶŐĞWǁͬϭϬ͛ĐĞŵĞŶƚ;ϵͬϮϯͬϭϳͿ ϴϰ͕ϴϮϭ͛ϯ͕ϵϱϴ͛ϯ͘ϴϭϬϱ͘ϱϮϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹůŽƐĞĚ;KƉĞŶƐĚŽǁŶͿ ϰ͕ϴϮϲ͛ϯ͕ϵϲϮ͛ϯ͘ϵϱϬϱ͘ϲϬϬϰͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕ϮϮ͘ϱϵ͛d> ϵϰ͕ϴϰϴ͛ϯ͕ϵϳϳ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϭϬϰ͕ϴϲϬ͛ϯ͕ϵϴϱ͛Ϯ͘ϵϵϬϱ͘ϴϵϬyK͕ϰ͘ϱyϯ͘ϱ ϰ͕ϴϲϭ͛ϯ͕ϵϴϲ͛Ϯ͘ϵϵϬϰ͘ϱϱϬϯͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕Ϯϰϴ͘ϲϴ͛d> ϭϭϱ͕ϭϭϬ͛ϰ͕ϭϱϵ͛Ϯ͘ϳϱϬϰ͘ϮϴϬ^ůĞĞǀĞ͕KƚŝƐy^^ʹůŽƐĞĚ;KƉĞŶƐƵƉͿ ϭϮϱ͕ϭϭϲ͛ϰ͕ϭϲϯ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϱ͕ϭϮϴ͛ϰ͕ϭϳϭ͛Ϯ͘ϵϵϮϰ͘ϱϱϬϯͲϭͬϮůĂƐƚ:ŽŝŶƚƐ͕ϳϭ͘ϱϰ͛d> ϭϯϱ͕ϮϬϬ͛ϰ͕ϮϮϭ͛Ϯ͘ϳϱϬϰ͘ϮϴϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹůŽƐĞĚ;KƉĞŶƐĚŽǁŶͿ ϭϰϱ͕Ϯϭϭ͛ϰ͕ϮϮϴ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϭϱϱ͕ϮϮϯ͛ϰ͕Ϯϯϳ͛Ϯ͘ϰϰϬϱ͘ϬϯϬyK͕ϯ͘ϱyϮ͘ϴϳϱ ϱ͕ϮϮϰ͛ϰ͕Ϯϯϳ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕Ϯϱϯ͘ϵϯ͛d> ϱϰϴϯ͛ϰ͕ϰϭϱ͛Ϭ͘ϬϬϬ&/^,͗ϰƵƚƚĞƌĂƌƐ;ϭͿϭ͘ϱ͟yϱ͕͛;ϭͿϭ͘ϳϱ͟yϱ͕͛;ϮͿ ϭ͘Ϯϱ͟yϱ͕͛ϰϱϮ͛ŽĨϬ͘ϭϮϱ͟tŝƌĞ͕Ϯϭ͛^>dŽŽůƐƚƌŝŶŐΘ Ϯ͘ϴϳϱ͟WĂĐŬŽĨĨWůƵŐ ϭϲϱ͕ϰϴϰ͛ϰ͕ϰϭϲ͛Ϯ͘ϯϭϯϯ͘ϳϱϬ^ůĞĞǀĞ͕KƚŝƐy^^;KƉĞŶƐƵƉͿ Ϭ͘ϴϳϱϮ͘ϮϱϬ&/^,͗ͲϮ^ƚŽƉ ϭϳϱ͕ϱϮϭ͛ϰ͕ϰϰϭ͛ϰ͘ϬϬϬϱ͘ϴϴϬWĂĐŬĞƌ͕KƚŝƐt, ϱ͕ϳϱϲ͛ϰ͕ϲϬϮ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϵ͘ϴϱ͛d> ϲ͕ϭϰϭ͛ϰ͕ϴϲϰ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕ϰϵ͘ϯ͛d> ϲ͕Ϯϳϰ͛ϰ͕ϵϱϱ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϵ͘ϴϱ͛d> ϲ͕ϯϴϱ͛ϱ͕ϬϯϬ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕Ϯϵ͘ϱϱ͛d> ϲ͕ϰϱϲ͛ϱ͕Ϭϳϴ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚ͕ϭϵ͘ϳϬ͛d> ϭϴϲ͕ϱϬϴ͛ϱ͕ϭϭϰ͛Ϯ͘ϯϭϯϯ͘ϳϱϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹKƉĞŶ;KƉĞŶƐĚŽǁŶͿ ϭϵϲ͕ϱϮϮ͛ϱ͕ϭϮϯ͛ϯ͘ϮϱϬϱ͘ϬϴϳWĂĐŬĞƌ͕KƚŝƐt, ϮϬϲ͕ϱϯϴ͛ϱ͕ϭϯϰ͛Ϯ͘ϯϭϯϯ͘ϳϱϬ^ůĞĞǀĞ͕KƚŝƐyK^^ʹKƉĞŶ;KƉĞŶƐĚŽǁŶͿ ϲ͕ϳϲϰ͛ϱ͕Ϯϴϴ͛Ϯ͘ϰϰϬϯ͘ϯϭϬϮͲϳͬϴůĂƐƚ:ŽŝŶƚƐ͕ϳϴ͘ϴϬ͛d> Ϯϭϲ͕ϴϳϱ͛ϱ͕ϯϲϰ͛Ϯ͘ϮϬϱϯ͘ϮϯϬEŝƉƉůĞ͕KƚŝƐyE ϮϮϲ͕ϴϴϲ͛ϱ͕ϯϳϭ͛Ϯ͘ϰϰϬϰ͘ϱϬϬtŝƌĞůŝŶĞZĞͲŶƚƌǇ'ƵŝĚĞ ϳ͕Ϭϱϳ͛ϱ͕ϰϴϴ͛Ϭ͘ϬϬϬ/W͕ĂŬĞƌ ϳ͕ϲϲϲϱ͕ϵϭϯ͛Ϭ͘ϬϬϬĞŵĞŶƚZĞƚĂŝŶĞƌ͕ĂŬĞƌ<Ͳϭ ϳϲϵϭ ϱ ϵϯϬ͛ϬϬϬ &/^, hƉĚĂƚĞĚďǇ͗:>>ϬϮͬϬϵͬϭϴ WZKWK^^,Dd/ ŽŶƚŝŶŐĞŶĐǇZtK dǇŽŶĞŬWůĂƚĨŽƌŵ tĞůů͗ͲϬϵ >ĂƐƚŽŵƉůĞƚĞĚ͗ϴͬϭϰͬϭϵϵϮ Wd͗ϭϲϵͲϬϴϱ W/͗ϱϬͲϴϴϯͲϮϬϬϮϵͲϬϬͲϬϬ WZ&KZd/KEd/> ŽŶĞdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&d ĂƚĞ ^ƚĂƚƵƐ /Ͳ^ƚƌĂǇϰ͕ϮϮϲ͛ϰ͕ϮϮϳ͛ϯ͕ϱϰϰ͛ ϯ͕ϱϰϱ͛ϭ͛ ϯͬϮϴͬϭϵϳϬ^Y /Ͳ^ƚƌĂǇϰ͕Ϯϱϳ͛ϰ͕Ϯϲϲ͛ϯ͕ϱϲϰ͛ ϯ͕ϱϳϬ͛ϵ͛ ϬϭͬϮϳͬϭϴKWE /Ͳϰ͕Ϯϵϰ͛ϰ͕ϯϭϵ͛ϯ͕ϱϵϬ͛ϯ͕ϲϬϳ͛Ϯϱ͛ϬϭͬϮϳͬϭϴKWE /Ͳ^ƚƌĂǇϰ͕Ϯϰϳ͛ϰ͕ϮϲϮ͛ϯ͕ϱϱϵ͛ϯ͕ϱϳϬ͛ϭϱ͛ϳͬϯϭͬϭϵϵϮDd^Y /Ͳϰ͕Ϯϴϰ͛ϰ͕ϯϭϰ͛ϯ͕ϱϴϱ͛ϯ͕ϲϬϳ͛ϮϬ͛ϴͬϭͬϭϵϵϮDd^Y /Ͳϰ͕ϯϯϬ͛ϰ͕ϰϬϬ͛ϯ͕ϲϭϴΖϯ͕ϲϲϳ͛ϳϬΖϴͬϭͬϭϵϵϮDd^Y /Ͳϰ͕ϰϮϲ͛ϰ͕ϰϮϳ͛ϯ͕ϲϴϲ͛ϯ͕ϲϴϲΖϭΖϯͬϮϴͬϭϵϳϬ^Y /Ͳ ϰ͕ϱϱϱ͛ϰ͕ϱϱϲ͛ϯ͕ϳϳϲ͛ ϯ͕ϳϳϳ͛ϭ͛ ϯͬϮϴͬϭϵϳϬ^Y /Ͳϭ͘Ϭϰ͕ϱϴϬ͛ϰ͕ϱϵϬ͛ϯ͕ϳϵϭ͛ ϯ͕ϳϵϴ͛ϭϬ͛ ϬϵͬϮϱͬϭϳ/^K>d /Ͳϭ͘Ϭϰ͕ϱϴϰ͛ϰ͕ϲϳϰ͛ϯ͕ϳϵϲ͛ϯ͕ϴϱϵ͛ϵϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d /ͲϮ͘Ϭϰ͕ϲϵϮ͛ϰ͕ϳϴϮ͛ϯ͕ϴϳϭ͛ϯ͕ϵϯϰ͛ϵϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϯ͘Ϭϰ͕ϴϬϰ͛ϰ͕ϴϭϲ͛ϯ͕ϵϰϵ͛ϯ͕ϵϱϳ͛ϭϮΖϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϯ͘ϭϰ͕ϴϯϯ͛ϰ͕ϴϰϴ͛ϯ͕ϵϲϵ͛ ϯ͕ϵϴϬ͛ϭϱ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϰ͘Ϭϰ͕ϴϱϱ͛ϰ͕ϵϮϬ͛ϯ͕ϵϴϱ͛ ϰ͕ϬϯϬ͛ϲϱ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϰ͘ϭϰ͕ϵϰϮ͛ϰ͕ϵϱϮ͛ϰ͕Ϭϰϱ͛ϰ͕ϬϱϮ͛ϭϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϱ͘Ϭϰ͕ϵϴϱ͛ϱ͕ϬϮϬ͛ϰ͕Ϭϳϱ͛ϰ͕Ϭϵϵ͛ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϲ͘Ϭϱ͕ϬϲϬ͛ϱ͕Ϭϴϱ͛ϰ͕ϭϮϳ͛ϰ͕ϭϰϰ͛Ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϳ͘Ϭϱ͕ϭϯϳ͛ϱ͕ϭϳϮ͛ϰϭϴϬ͛ϰ͕ϮϬϰ͛ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϳ͘ϭϱ͕ϭϴϳ͛ϱ͕ϭϵϯ͛ϰ͕Ϯϭϱ͛ ϰϮϭϵ͛ϲ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϴ͘Ϭϱ͕ϮϯϮ͛ϱ͕ϮϰϮ͛ϰ͕Ϯϰϲ͛ ϰ͕Ϯϱϯ͛ϭϬ͛ ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϴ͘Ϯϱ͕Ϯϲϰ͛ϱ͕Ϯϴϵ͛ϰ͕Ϯϲϴ͛ϰ͕Ϯϴϱ͛Ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϵ͘Ϭϱ͕ϯϯϮ͛ϱ͕ϯϱϳ͛ϰ͕ϯϭϱ͛ϰ͕ϯϯϮ͛Ϯϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /ͲϭϬ͘Ϭϱ͕ϯϴϬ͛ϱ͕ϯϵϱ͛ϰ͕ϯϰϴ͛ϰ͕ϯϱϴ͛ϭϱ͛ϴͬϭϰͬϭϵϵϮ/^K>d /Ͳϭϭϱ͕ϰϭϲ͛ϱ͕ϰϳϲ͛ϰ͕ϯϳϮ͛ϰ͕ϰϭϯ͛ϲϬ͛ϴͬϭϰͬϭϵϵϮ/^K>d ϱ͕ϰϴϳ͛ϱ͕ϰϴϴ͛ϰ͕ϰϮϭ͛ ϰ͕ϰϮϮ͛ϭ͛ ϯͬϮϴͬϭϵϳϬ/^K>d Ͳϲϱ͕ϳϲϮ͛ϱ͕ϳϲϴ͛ϰ͕ϲϬϴ͛ ϰ͕ϲϭϯ͛ϲ͛ ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϯϲ͕ϭϰϵ͛ϲ͕ϭϱϰ͛ϰ͕ϴϳϮ͛ϰ͕ϴϳϲ͛ϱ͛ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϰϲ͕ϭϲϮ͛ϲ͕ϭϴϳ͛ϰ͕ϴϴϭ͛ϰ͕ϴϵϴ͛Ϯϱ͛ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϯϲ͕ϮϴϬ͛ϲ͕Ϯϴϱ͛ϰ͕ϵϲϮ͛ϰ͕ϵϲϱ͛ϱ͛ϴͬϮϵͬϭϵϵϮ/^K>d Ͳϵϲ͕ϯϵϰ͛ϲ͕ϰϭϰ͛ϱ͕Ϭϯϵ͛ϱ͕Ϭϱϯ͛ϮϬ͛ϴͬϮϵͬϭϵϵϮ/^K>d &ͲϮϲ͕ϰϲϯ͛ϲ͕ϰϳϴ͛ϱ͕Ϭϴϲ͛ ϱ͕Ϭϵϲ͛ϭϱ͛ ϴͬϮϵͬϭϵϵϮ/^K>d ,ͲϮ ,Ͳϯ ,Ͳϰ ,Ͳϱ ϲ͕ϳϳϮ͛ϲ͕ϴϰϮ͛ϱ͕Ϯϵϳ͛ ϱ͕ϯϰϱ͛ϲϵ͛ ϴͬϮϵͬϭϵϵϮ /^K>d :Ͳϴϳ͕Ϭϳϲ͛ϳ͕Ϭϵϴ͛ϱ͕ϱϬϭ͛ϱ͕ϱϭϲ͛ϮϮ͛/^K>d :ͲϮϳ͕ϭϯϮ͛ϳ͕ϭϰϮ͛ϱ͕ϱϰϬ͛ ϱ͕ϱϰϳ͛ϭϬ͛ /^K>d <ͲϰΘϰ͘ϭϳ͕ϮϰϬ͛ϳ͕ϮϳϬ͛ϱ͕ϲϭϱ͛ ϱ͕ϲϯϱ͛ϯϬ͛ /^K>d /ͲϮΘ/Ͳϯϳ͕ϯϭϮ͛ϳ͕ϯϯϳ͛ϱ͕ϲϲϱ͛ϱ͕ϲϴϮ͛Ϯϱ͛/^K>d DͲϮϳ͕ϯϳϵ͛ϳ͕ϯϴϵ͛ϱ͕ϳϭϮ͛ϱ͕ϳϭϵ͛ϭϬ͛/^K>d DͲϵϳ͕ϱϯϵ͛ϳ͕ϱϰϰ͛ϱ͕ϴϮϰ͛ϱ͕ϴϮϳ͛ϱ͛/^K>d DͲϭϭϳ͕ϱϴϭ͛ϳ͕ϱϴϳ͛ϱ͕ϴϱϯ͛ϱ͕ϴϱϴ͛ϲ͛/^K>d EͲϯϳ͕ϲϵϭ͛ϳ͕ϲϵϳ͛ϱ͕ϵϯϬ͛ ϱ͕ϵϯϱ͛ϲ͛ /^K>d EͲϰϳ͕ϳϮϰ͛ϳ͕ϳϯϰ͛ϱ͕ϵϱϰ͛ ϱ͕ϵϲϭ͛ϭϬ͛ /^K>d %236WDFN5LJ ^ŚĂĨĨĞƌ^> ϭϯϱͬϴϱD ϮϳͬϴͲϱ͘ϱ ǀĂƌŝĂďůĞƐ ůŝŶĚƐ Ϯ͘ϮϲΖ ZŝƐĞƌ ϭϯϱͬϴϱD&yϭϯϱͬϴϱD& ^ƉĂĐĞƌƐƉŽŽů ϭϯϱͬϴϱD&yϭϭϱD ϰ͘ϱϰΖ Ϯ͘ϴϯΖ ŚŽŬĞĂŶĚ<ŝůůǀĂůǀĞƐ ϮϭͬϭϲϱD 0XG&URVV 0()2 ϰ͘ϯϬΖ ,ǇĚƌŝů '<ϭϯϱͬϴͲϱϬϬϬ ^ϰyϮ^ϰyϮ^ƉĂĐĞƌƐƉŽŽů ϭϯϱͬϴϱDyϭϯϱͬϴϱD +,/&253$/$6.$//& 6ZDFR6XSHUFKRNH%ORRH\/LQH7R*DV%XVWHU/ŶůĞƚ +LOFRUS$ODVND//&+LOFRUS$ODVND//&Changes to Approved Rig Work Over Sundry Procedure6XEMHFW &KDQJHVWR$SSURYHG6XQGU\3URFHGXUHIRU:HOO1&RRN,QOHW8QLW$37'6XQGU\;;;;;;$Q\PRGLILFDWLRQVWRDQDSSURYHGVXQGU\ZLOOEHGRFXPHQWHGDQGDSSURYHGEHORZ&KDQJHVWRDQDSSURYHGVXQGU\ZLOOEHFRPPXQLFDWHGWRWKH$2*&&E\WKHULJZRUNRYHU5:2³ILUVWFDOO´HQJLQHHU$2*&&ZULWWHQDSSURYDORIWKHFKDQJHLVUHTXLUHGEHIRUHLPSOHPHQWLQJWKHFKDQJH6HF3DJH'DWH3URFHGXUH&KDQJH1HZ5HTXLUHG"<1+$.3UHSDUHG%\,QLWLDOV+$.$SSURYHG%\,QLWLDOV$2*&&:ULWWHQ$SSURYDO5HFHLYHG3HUVRQDQG'DWH$SSURYDO $VVHW7HDP2SHUDWLRQV0DQDJHU 'DWH 3UHSDUHG )LUVW&DOO2SHUDWLRQV(QJLQHHU 'DWH 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.aogcc.alaska.gov Re: North Cook Inlet Field, Tertiary Gas and Sterling Undefined Gas Pool, NCIU A-09 Permit to Drill Number: 169-085 Sundry Number: 319-406 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, Jessie L. Chmielowski Commissioner DATED this I � day of September, 2019. RBDMS±-/SEP 12 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS i� `VI„�,_,.,� ,a 1. Type of Request: Abandon El Plug Perforations ❑Q Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Other Stimulate ❑ Pull Tubing Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool Re-enter Sus p Well ❑ Alter Casing ❑ Other: G/L Completion ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 169-085 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-883-20029-00-00 ' 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? Yes❑ No N Cook Inlet Unit A-09 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0017589 / ADL0037831 North Cook Inlet / Tertiary Gas / ��Zr�tn «�:� ��j 11. PRESENT WELL CONDITION SUMMARY 9g, /'7 Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,022. 6,149 • 4,500 3,734 1,176 psi see schematic 5,483 & 7,691 Casing Length Size MD TVD Burst collapse Structural Conductor 386' 30" 386' 386' Surface 631' 16" 631' 631' 1,640 psi 630 psi Intermediate 2,587' 10-3/4" 2,587' 2,370' 1 3,580 psi 2,090 psi Production 7,998 7" 7,998' 6,146' 4,980 psi 4,320 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: ubing Grade: Tubing MD (ft): 4,257 - 4,319 3,564 - 3,607 4-1/2" / 3-1/2" 12-7/8" 1112.75J-5519.3J55/6.6J-55 6,886 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): See schematic See schematic 12. Attachments: Proposal Summary Q 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: 10/1/2018 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: garlovve hilCor .Com Contact Phone: (907) 283-1329 Authorized � Signature: Date: / COMMISSION USE ONLY Conditions of approval: Notify Commission sot t a representative may witness Sundry Number. Plug ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: {rc -.2, V00 5,;, %� ato sit— 55✓ �L.�Pr"oa�1 Z0AtLZS'Z-b.�Ca�LI� 7t"A14-ern. P�Ee.e,,,,,,_� /oeL Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No Subsequent RBDMS! SEP 1 11019 ❑ Form Required: �.. c� �t' ^ APPROVED BY d"�� Approved by: ✓ COMMISSIONER THE COMMISSION Date: 7-P-11, Re I G N A L S� R p(1,1 Submit Form and Form 10-403 Revised 4/2017 AppvpplicatioOn isitl for 12I on[hs from [he date of apppr al. Attachmem in Duplicate B I ilmrp Alaska, LLC Well Work Prognosis Well Name: NCIU A-09 API Number: 50-883-20029-00 Current Status: Sl Producer Leg: Leg #2 SW 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: 169-085 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: I Stan Golis (907) 777-8356 (0) (281) 450-3071 (M) Current Bottom Hole Pressure: 1,520 psi @ 3,441' TVD 0.442 lbs/ft (8.49 ppg) Maximum Expected BHP: 1,520 psi @ 3,441' TVD 0.442 lbs/ft (8.49 ppg) Maximum Potential Surface Pressure: 1,176 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary w:t� A-09 is currently a depleted / watered out gas producer. This workover complete the well up -hole to allow the addition of the CIA, Cl Stray 2, & CI -A gas sands. 1 C04cut /%6ly Last Casing Test: Tested IA 07-30-1992 to 2,000 psi @ 4195' 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. C" �I rn P Procedure: �,.f-b:� p4-b.Ci( 1. Rig up E -line and cut tubing at ±4,35W (Note: tubing has possible damage or part at 4,150') 2. Rig up wire and punch tubing at ±4,125' 3. MIRU HAK 4042__ju �o" 4. Test BOP's to 250psi low/2,500psi high /y"popsi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. Workover fluid will be brine. BOP'S will be closed as needed to circulate the well. 6. Pull upper completion fishing tubing arnMcleaning out as needed to ±4,400'. Pk+c yIR r 7. Rig up E -line and perforate top 2' of CI -B sands (±4,330'-4,332') with big hole casing guns. 8. RIH and s t EZSV±4,325'. POOH and RDE -Line 7" �s7ej iss✓ 9. RIH, sting into EZSV. 10. Conduct injectivity test. 11. Perform Hesitation Squeeze with 1,000 sacks of cement through EZSV. 12. Un -sting from EZSV and circulate clean. POOH. l ,/ 13. Rig up E -line and run a CBL from EZSV to surface. �� (w a h h v Cly 14. Dump ±10' of cement (±16 gallons) on top of EZSV. RD E -line. Gg (e 15. PU and rack back completion tubing. 16. RU E -line and perforate per program. 17. RIH with Gas Lift completion (live valves). 18. 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). C— Kc r • Pull prong and plug in XN-Nipple. 19. Set BPV. NU tree, test same. 20. Turnover to production. 21. Schedule SVS testing with AOGCC as per regulations. H Hil.p Alk., LLC Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current 4. Wellhead Schematic Proposed 5. BOP Drawing 6. Fluid Flow Diagrams 7. RWO Sundry Revision Change Form Well Work Prognosis ftilcorD Alaelru, I.I.0 RKB to TBG Head- 54.08' 301' fl) 16" atm 30"Conductor 10.3/4" 1 J-55 Welded EsiT[X . Surf 386' 3,2FA' ' 65 H-40 j, 15.250" Surf 631' 10-3/4" 45.5 stdctio BUTT 4,257-a,319' 4150 + 1 2,587' 4,22 C-4,427 26 J-55 BUTT Tu6in65 Surf I 7,998' Punch 5 1 :'.I Sgpw FErfs 4565' 6 090 7 .. MW 3,783' 8 000 9 6 o:r 3.813 5.500 Sleeve, Otis XA SSD- Closed (Opens up) 7 wed BII 3,937' 4.000 000: 4,934' SlM. Packer, Otis TW 7/01/17 14 15 ® w-� �1 S® � r 19 s• za DO 21 X N z2 f 7,1357 O8P 7,665 CenerR Reding 7,e31' FISH PBTD: 7,057' TD: 8,022' SCHEMATIC Tyonek Platform Well: A-09 Last Completed: 8/14/1992 PTD: 169-085 API: 50-883-20029-00 CASING DETAIL Size Wt Grade Conn fl) Top atm 30"Conductor 9.3 1 J-55 Welded 28" Surf 386' 16" 65 H-40 BUTT 15.250" Surf 631' 10-3/4" 45.5 J-55 BUTT 9.950" Surf 1 2,587' 7" 26 J-55 BUTT 6.276" Surf I 7,998' TUBING DETAIL 4-1/2" 1 12.75 J J-55 EUE8rd 3.958" 54' 4,8601 3-1/2" 9.3 1 J-55 EUE 8rd 2.992" 4,860' 5,223' 2-7/8" 6.5 1 1-55 I EUE 8rd 2.441 5,223' 6,886' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 294.5' 294.5' 3.810 5.510 Nipple, SSSV, Otis XXO 3.813" FXE 4-8 WRDP SSSV 2 4,143' 3,482' 3.880 6.000 Packer, Otis VSR 3 4,500' 3,734' 3" Magna Range Bridge Plug w/ 101 cement 4 4,547 3,767' 4.000 5.880 Packer, Otis TW 5 1 4,563' 3,779' 3.880 6.000 Packer, Otis VSR (Not Set) MW 3,783' 3.958 5.600 4-1/2 Blast Joints, 214.5' TL 6 3,932' 3.813 5.500 Sleeve, Otis XA SSD- Closed (Opens up) 7 4,791' 3,937' 4.000 5.880 Packer, Otis TW 4,796' 3,941' 3.950 5.600 4-1/2 Blast Joints, 25.79' T:(Opens 4,796' 3,941' 3" Magna Range BP w/ 10' 8 4,821' 3,958' 3.810 5.520 Sleeve, Otis XO SSD- Closeown)4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints, 22.59' T 9 1 4,848' 3,977' 4.000 5.880 Packer, Otis BWH 10 T 4,860' 3,985' 2.990 5.890 XO, 4.5 X 3.5 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints, 248.68'TL 11 5,110' 4,159' 2.750 4.280 Sleeve, Otis XA SSD- Closed (Opens up) 12 5,116' 4,163' 4.000 5.880 Packer, Otis BWH 5,128' 4,171' 2.992 4.550 3-1/2 Blast Joints, 71.54' TL 13 5,204 4,221' 2.750 4.280 Sleeve, Otis XO SSD- Closed (Opens down) 14 5,211' 4,228' 4.000 5.880 Packer, Otis BWH 15 5,223' 4,237' 2.440 5.030 XO, 3.5 X 2.875 5,224' 4,237' 2.440 3.310 2-7/8 Blast Joints, 253.93'TL 5483' 4,415' 0.000 FISH: 4 Cutter Bars (1) 1.5" X 5', (1) 1.75" X 5', (2) 1.25" X 5', 452' of 0.125" Wire, 21' SL Toolstring & 2.875" Packoff Plug 16 F 5,484' 4,416' 2.313 3.750 Sleeve, Otis XA SSD(Opens up) 0.875 2.250 FISH: AD -2 Stop 17 5,521' 4,441' 4.000 5.880 Packer, Otis BWH 5,756' 41602' 2.440 3.310 2-7/8 Blast Joint, 9.85'TL 6,141' 4,864' 3.310 2-7/8 Blast Joints, 49.3' TL 6,274' 4,955' 3.310 2-7/8 Blast Joint, 9.85' TL 6,385' 5,030' 3.310 2-7/8 Blastloint, 29.55' TL 6,456' 5,078' k2.313 3.310 2-7/8 Blast Joint, 19.70' TL 18 6,508' 5,114' 3.750 Sleeve, Otis XO SSD- Open (Opens down) 19 6,522' 5,123' 5.087 Packer, Otis BWH 20 6,538' 5,134' 3.750 Sleeve, Otis XO SSD -Open (Opens down) 6,764' 5,288' 3.310 2-7/8 Blast Joints, 78.80' TL 21 6,875' 5,364' 1 2.205 3.230 Nipple, Otis XN 22 6,886 5,371' 2.440 4.500 Wireline Re -Entry Guide 7,057' 5,488' 0.000 Cap, Baker 7,666 5,913' 0.000 Cement Retainer, Baker K-1 7,691 5,930' 0.00 FISH Updated By: JUL 02/09/18 B Hikwrp Almke, LLC SCHEMATIC Tyonek Platform Well: A-09 Last Completed: 8/14/1992 PTD: 169-085 API: 50-883-20029-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI -Stray 4,226' 4,227' 3,544' 3,545' 1' 3/28/1970 SQZ CI -Stray 4,257' 4,266' 3,564' 3,570' 9' 01/27/18 OPEN CI -A 4,294' 4,319' 3,590' 3,607' 25' 01/27/18 OPEN CI -Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMTSQZ CI -A 4,284' 4,314' 3,585' 3,607' 20' 8/1/1992 CMTSQZ CI -B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMTSQZ CI -B 4,426' 4,427' 3,686' 3,686' 1' 3/28/1970 SQZ CI -B 4,555' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ CI -1.0 4,580' 4,590' 3,791' 3,798' 10' 09/25/17 ISOLATED CI -1.0 4,584' 4,674' 3,796' 3,859' 90' 8/14/1992 ISOLATED CI -2.0 4,692' 4,782' 3,871' 3,934' 90' 8/14/1992 ISOLATED CI -3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 ISOLATED CI -3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 ISOLATED CI -4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 ISOLATED 0-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 ISOLATED CI -5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 ISOLATED CI -6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 ISOLATED CI -7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 ISOLATED CI -7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 ISOLATED CI -8.0 5,232' 5,242' 4,246' 4,253' 30' 8/14/1992 ISOLATED CI -8.2 5,264' 5,289' 4,268' 4,285'46W8/14/1992 /14/1992 ISOLATED CI -9.0 5,332' 5,357' 4,315' 4,332'/14/1992 ISOLATED CI -10.0 5,380' 5,395' 4,348' 4,358'/14/1992 ISOLATED CI -ii 5,416' 5,476' 4,372' 4,413' ISOLATED 5,487' 5,488' 4,421' 4,422'/28/1970 ISOLATED B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 ISOLATED D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 ISOLATED D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 ISOLATED E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 ISOLATED E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 ISOLATED F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 ISOLATED H-2 H-3 H-4 H-5 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 ISOLATED J-8 7,076' 7,098' 5,501' 5,516' 22' ISOLATED J-2 7,132' 7,142' 5,540' 5,547' 10' ISOLATED K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' ISOLATED 1-2 & 1-3 7,312' 7,337' 5,665' 5,682' 25' ISOLATED M-2 7,379' 7,389' 5,712' 5,719' 10' ISOLATED M-9 7,539' 7,544' 5,824' 5,827' 5' ISOLATED M-11 7,581' 7,587' 5,853' 5,858' 6' ISOLATED N-3 7,691' 7,697' 5,930' 5,935' 6' ISOLATED N-4 7,724' 7,734' 5,954' 5,961' 10' ISOLATED Updated by: JLL 02/09/18 Platform Well: A PROPOSED Well: A-09 A Last Completed: FUTURE Hilrnra Alaska, LLC PTD: S �/r.P� PTD: 169-085 API: 50-883-20029-00 CASING DETAIL RM bTtiGHMd: 54.09, Po®b MLW 1159, MLWb MAre: M 30' 1 2 ..r' 16" i Wt ✓:.✓ M .'b+ ID n t t- I A lD3/air 3 /s -Oz, �Sc Est TOC 28" -3,2&4 4 ;'TI 65 N 00 5,487-5,4E 15.250" 6 9p =- a -X 0 �„ �i 7 _! 417518:;x' P 0 { 4,226'-4,427 2,587' o0 Iq—ed Perls 1a �. saso-:y 427617 • 7,998' 12 XN —6A 3.5"ID1Q%:. 13 4,M7-4,319' ,bOQ ' stdction � _•'__ •T4,33d-34,332 4150 B iMs c.rti Tubing ; , ,55S'-4,556' Punch sw� 4,565' y:'. 00 E6 t• F 000 G ti b.. H �'• ;:<'.' Tamed Fll@ p , r._iDu 4,93451Mm 7/01/17 i' K d0 L ' Wt M .'b+ ID To Btm 30" 5,483 FISH 5 28" Surf 386' 16" 65 N 00 5,487-5,4E 15.250" Surf - SWeezed P. 0 �„ �i 45.5 ;5,535 FISH 1 2. P 0 Surf 7,m7 a6P 7,666' CrrreM RKainerH 7,691' RSH r PBTD: 7,057' TD: 8,022' Size Wt EUE 8 rnd ID To Btm 30" 28" Surf 386' 16" 65 !H-4E0BuTr 8rd 15.250" Surf 631' 3-1/2"EUE 45.5 8rd 9.950" Surf 2,587' 2-7/8"EUE 26 Brd 6.276" Surf 7,998' Waal, raea�.m 3-1/2"EE6.5J-55 EUE 8 rnd 2.992" Surf 1330' 2-7/8"EUEBrnd 2.441" 1330' 14,295' 4-1/2"EUE 8rd 3.958" 34,400' 4,860' 3-1/2"EUE 8rd 2.992" 4,860' 5,223' 2-7/8"EUE Brd 2.441" 5,223' 6,886' JEWELRY DETAIL Updated By: ILL 09/04/2019 xJJeorR nLaeka• lac PROPOSED Platform Well: A Well: A-09 Last Completed: FUTURE PTD: 169-085 API: 50-883-20029-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT DateaRe-perf CI-x ±4,089• ±4096' ±3,444' ±3,449' ±7' FutureCI-Stray 4,226' 4,227' 3,544' 3,545' 1'3/28/1970CI-Stray 2 ±4,254' ±4,262' ±3,562' ±3,567' ±8' FutureCI-A 4,294' 4,319' 3,590' 3,607' 25' 01/27/18 CI-Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMT SQZ CI-A ±4,286' ±4,308' ±3,584' ±3,599' ±22' Future Proposed CI-B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMTSQZ 0' 6' ±4,332' 4,427' ±3,615' 3,686' ±3,616' 3,686' ±2' 1' Future 3/28/1970 SQZ ce SQZ ' &CI-2.04,692' 5' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ ' 4,590' 3,791' 3,798' 10' 09/25/17 ISOLATED ' 4,674' 3,796' 3,859' 90' 8/14/1992 ISOLATED ' 4,782' 3,871' 3,934' 90' 8/14/1992 ISOLATED CI-3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 ISOLATED CI-3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 ISOLATED CI-4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 ISOLATED CI-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 ISOLATED CI-5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 ISOLATED CI-6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 ISOLATED CI-7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 ISOLATED CI-7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 ISOLATED CI-8.0 5,232' 5,242' 4,246' 4,253' 10' 8/14/1992 ISOLATED CI-8.2 5,264' 5,289' 4,268' 4,285' 25' 8/14/1992 ISOLATED CI-9.0 5,332' 5,357' 4,315' 4,332' 25' 8/14/1992 ISOLATED 0-10.0 5,380' 5,395' 4,348' 4,358' 15' 8/14/1992 ISOLATED 0-11 5,416' 5,476' 4,372' 4,413' 60' 8/14/1992 ISOLATED 5,487' 5,488' 4,421' 4,422' 1' 3/28/1970 ISOLATED B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 ISOLATED D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 ISOLATED D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 ISOLATED E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 ISOLATED E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 ISOLATED F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 ISOLATED 1-12-1-15 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 ISOLATED J-8 7,076' 7,098' 5,501' 5,516' 22' ISOLATED J-2 7,132' 7,142' 5,540' 5,547' 30' ISOLATED K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' ISOLATED 1-2 & I-3 7,312' 7,337' 5,665' 5,682' 25' ISOLATED M-2 7,379' 7,389' 5,712' 5,719' 10' ISOLATED M-9 7,539' 7,544' 5,824' 5,827' 5' ISOLATED M-11 7,581' 7,587' 5,853' 5,858' 6' ISOLATED N-3 7,691' 7,697' 5,930' 5,935' 6' ISOLATED N-4 7,724' 7,734' 5,954' 5,961' 10' ISOLATED Updated by: 1LL 09/04/2019 Tyonek Platform A-09 C A-09 Current ea , r� nia ►., t.u: 05/04/2018 Tyonek Platform A-09 16x10%x2 x4% BHTA, Oti% 41/16 3M FE x 7.5" Otis quick union top Valve, Swab, FMC -12( 41/16 3M FE, H W0, 00 trim Valve, Upper master, SSV FMC -120,4 1/163M FE, w/ FMC PA operator, EE trim Valve, Master, FMC420, 41/16 3M FE, HW 0, AA trim AL Tubing head, FMC -TC -00, 113Mx93M,w/2- 16 21/165M550 _j _ Casing spool, OCF- C -29L -OO 16"3M x113M, w/ 2-21/165M EFO Starting head, OCT -C29-4 16"3M x16"SOW, w/2-2 1/165M EFO 4 %" 10%11 Turing hanger, FMC -TC -EN - CL, 9 x 4 % EUE &d lift and 4 Y, IBT cusp, w/ 4" type IS- BPV profile, 1-%npt control line Port Valve, Wing, SSV, FMC -120, 41/16 3M FE, w/ 15" Axelson MHA operator, EE trim A' /'I 1 Adapter, FMC -A51, -CL, 9" 3M FE x41/16 3M Tyonek Platform A-9 Proposed 7/30/2019 Tyonek Platform Tubing hanger, FMC -TC -EN- A -09 CCL, 9 x 3 Y, EUE gird lift and 16 x 10 %x 7 x 335 cusp, w/ 3" type H-BPV profile, 2- Knot control line Port BHTA, Otis, 3 1/9 5M FE x 7.5" Otis quick union top Valve, Swab, CIW-FC 31/85M FE, HWO, Valve, Wing, SSV, WKM-M, EEtnm 31/85M FE, w/15"Axelson MHA operator, EE trim Valve, Master, CIW-FC, 31/8 5M FE, HWO, EE trim Valve, Master, CIW-FC, 3 1/8 5M FE, HWO, EE tr m Tubing head, FMC -TC -00, 113M x 93M, w/2- 2 1/16 5M SSO Casing spool, OCT- C-291--00 16"3M x 113M, w/ 2- 21/16 5M EFO Starting head, OCr-C29-L, 16"3Mx 16" SOW, w/2-2 1/165M EFO 3A" y10i„ 7" Adapter, FMC -ASP -CCL, 9 3M stdd x 31/8 5M, w/ 2-1" npt control line exits H Hil..,q. Ala.ka„ UA: BOP Stack Rig 404 Faroe. M Ul U. u u u u u u u 2 03 I z \ �® ) a - / - eco G$oap -o�zz\ ® « 7 = 3j) �0 if LL -1 j\� w ( » v !§ f _ < \ D O 0 0 o u o u o 0 o u o a v o u o u o u u o � u o m >' i E E E E E � "" a o 0 0 0 0 0 0 � _ z� `u `u i�'nF > u ui, N tD U a� pw io ¢w a zo NU 20 W K g W ) J LL n Irc\ Iw\ Y m H N W a a z Q � p Z Q ❑a mnz ❑ a Z U) Q o0OU} Q Q ? < O—�0wzc7 d Z p0?0 " 'k LL Q ~ W p g Z 2 O 7 N yW ay 4 LL Z p a a Wm z 0 ~ Z ° U af U 0 0 o u o u o 0 o u o a v o u o u o u u o � u o m >' i E E E E E � "" a o 0 0 0 0 0 0 � _ z� `u `u i�'nF > u ui, Rig 404 BOP Test Procedure 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. 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. 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 Iil.p M.A., 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 1't 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 1't 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. N Hflcorp Alaska, 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 30 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. HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well N Cook Inlet Unit A-09 (PTD 169-085) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date 10,000,000 1,000,000 Z C 0 a 100,000 LL v o cc 10,000 O W O n 1,000 V Z U M 100 7 O s 10 1 Jan -1975 Hilcorp Alaska LLC, N COOK INLET UNIT A-09 (169-085) NORTH COOK INLET, TERTIARY GAS Monthly Production Rates Jan -1980 Jan -1985 Jan -1990 I Produced Gas (MCFM) Jan -1995 Jan -2000 10,000,000 v 1,000,000 0 100,000 m 3 0 3 10,000 s l Jan -2005 Jan -2010 Jan -2015 Jan -2020 GOR Produced Water (BOPM) t Produced ON (BOPM) SP READSH EET_Prod-I nject_Cu"es_Well_Gas_V 120_20190718.xisx 9/5/2019 'war'1A'111►lirlM—=Ri—�17�C�"�—��1� 'iiiialiiii'i '°'"�"iir �cii �� ,ilii +,4�■�iiieh6�3l �i'1ii■��'I�I�Ilii�lf�l�lHfi�ll11' imb) , _0 ■■■■■■■■■■■■■■■■■il■ ■■■■■■■■■■■■■■ us■_■ ■■ u__■_■__■__■__■__■_■___■_■___■_■■■■___■_ —__ MENNEN _�■_■unnni■■u■■n■■ ■■■■■■■■■■■■N■It■■■■■■■■■■■■■■■ ■■��_�_�_�■_■■I !_■■_�_■_�■�■___�__R'I�■ ■■■■■tjIM N. ■I■■ www■■ i'�� ■■■■■■w■a■■'i —•--Irl—• � 4.�iI--.. NI Vlyl— --- Mai ■rri■ ■il■■■ ■ Jan -1980 Jan -1985 Jan -1990 I Produced Gas (MCFM) Jan -1995 Jan -2000 10,000,000 v 1,000,000 0 100,000 m 3 0 3 10,000 s l Jan -2005 Jan -2010 Jan -2015 Jan -2020 GOR Produced Water (BOPM) t Produced ON (BOPM) SP READSH EET_Prod-I nject_Cu"es_Well_Gas_V 120_20190718.xisx 9/5/2019 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.' Please let me know if you have any questions! Thanks, Tommy Nenahlo I Reservoir Engineer Cook trilet Asset Team Hilcorp Alaska, LLC Office: +1 (907) 777-8424 Nlobile: +1 (720) 273-2685 Lnenahl_o ialiilcor p.coin From: Davies, Stephen F (CED) [mailto:steve.davies@alaska gov] Sent: Thursday, September 5, 2019 3:44 PM To: Michael Schoetz <mschoetz@hilcorp.com>; Dan Marlowe <dmarlowephilcorp.com> Cc: Boyer, David L (CED) <david.bover2Cdalaska.eov> 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.daviesPalaska.gov. From: Michael Schoetz <mschoetz@hilcorp.com> Sent: Thursday, September 5, 2019 9:00 AM To: Boyer, David L (CED) <david.boyer2@alaska.eov> 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 1 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: mschoetzaAhilcorp.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED)[mailto:david.boyer2@a1aska.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 <mschoetz@hilcorp.com> Sent: Thursday, September 5, 2019 8:38 AM To: Boyer, David L (CED) <david. boye2@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 0 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: mschoetzAhilcorp.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED)[mailto:david.boyer2@alaska.gov] Sent: Tuesday, September 3, 2019 4:40 PM To: Michael Schoetz <mschoetz@hilcorp.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 perf 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@hilcorp.com> Sent: Tuesday, September 3, 2019 3:26 PM To: Boyer, David L (CED) <david. bover2@alaska.gov> Subject: NCIU A-03 & A-09 Proposed Operations 2 Thank you, `\ JCI 13-02 1 I I 1 1 \ I 1 \ I � � I � 1 f =a _- lTyonel rJC l -A-03 NCI -A-03 - / \t rf NORTH COOK IN LET UNIT t N -c T11N-R10W NCI-A-09«NCI-A-09 NCI -A-12. T jr• C189 -01A NC) -A -0e I / NCI -A-07 r 0140-01 r r Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: msehoetz(a)hilcorp.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. 4 Davies, Stephen F (CED) From: Davies, Stephen F (CED) Sent: Thursday, September 5, 2019 3:44 PM To: mschoetz@hilcorp.com; Dan Marlowe Cc: Boyer, David L (CED) 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.daviesldalaska.eov. From: Michael Schoetz <mschoetz@hilcorp.com> Sent: Thursday, September 5, 2019 9:00 AM To: Boyer, David L (CED) <david.bover2@alaska.eov> 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(ahilcorp.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED)[mailto:david.bover2@alaska.govl 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 inciting the Alaska statewide regulation 20 AAC 25.055(a)(4) for both A-09 and A-03. If 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,hilcorn.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@hilcorn.com> Sent: Thursday, September 5, 2019 8:38 AM To: Boyer, David L (CED) <david.boyer2@alaska.eov> 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(i hilcoro.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 From: Boyer, David L (CED) f mailto:david.bover2@alaska.aov] Sent: Tuesday, September 3, 2019 4:40 PM To: Michael Schoetz <mschoetz@hilcorp.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 2n1 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@hilcorp.com> Sent: Tuesday, September 3, 2019 3:26 PM To: Boyer, David L (CED) <david.bover2@alaska.i=_ov> Subject: NCIU A-03 & A-09 Proposed Operations 1,F + • � J 1 r +� NCI -A-03 MCI -F, 03 T. 1 r f T11Ni210W Ncl-A-o-9. IdCl-R-09 NCI -A-08 r r C140-01 +' r ; I Thank you, Michael W. Schoetz, CPL Hilcorp Alaska, LLC Senior Landman Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz(ahilcoro.com 3800 Centerpoint Dr., Suite 1400 1 Anchorage, Alaska 99503 l r J f 1 f `0.pti tTj/t)nel r li ,w t �5 / Jf � r r / I ! 1 /7 t r J t J NORTH tJ COOK INLET 4 UNIT t NCI -A-12 t cl.)k ,T Cta9-m • J NCI -A-07 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. RECEIVED STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMMI ION FEB 1 2 REPORT OF SUNDRY WELL OPERATIONS 2018 1.Operations Abandon 0 Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing 0 p r Q C El Performed: Suspend El Perforate CI Other Stimulate ❑ Alter Casing 0 Change Approved Program ❑ Plug for Redrill 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:Reperforate CI 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory El 169-085 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-883-20029-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0017589/ADL0037831 N Cook Inlet Unit A-09 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A North Cook Inlet/Tertiary Gas 11.Present Well Condition Summary: Total Depth measured 8,022 feet Plugs measured See Schematic feet true vertical 6,149 feet Junk measured 5,483&7,691 feet Effective Depth measured 4,490 feet Packer measured See Schematic feet true vertical 3,727 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Structural Conductor 386' 30" 386' 386' Surface 631' 16" 631' 631' 1,640 psi 630 psi Intermediate 2,587' 10-3/4" 2,587' 2,370' 3,580 psi 2,090 psi Production 7,998' 7" 7,998' 6,146' 4,980 psi 4,320 psi Liner Perforation depth Measured depth 4,257-4,319 feet True Vertical depth 3,564-3,607 feet 4-1/2" 12.75/J-55 4860'(MD) 3,985'(TVD) Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3/J-55 5,223'(MD) 4,237'(TVD) 2-7/8" 6.5/J-55 6,886'(MD) 5,371'(TVD) Packers and SSSV(type,measured and true vertical depth) See Schematic 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A w•� ' r i , Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 55 63 Subsequent to operation: 0 12536 7 134 1072 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations CI Exploratory ❑ Development0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas 2 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ El SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-599 Authorized Name: Stan W.Golis Contact Name: Michael Quick Authorized Title: Operations Manager P Contact Email: mquiCk@hiICOrp.Com Authorized Signature: .9-".......c D(f. Date: - 11I- I SSS Contact Phone: (907)777-8442 Form 10-404 Revised 4/2017 7/2_,„ � /_'/�RE E'?1` S 0-, E5 „/.zb` ,j F_� , �C18 Submit Original Only 11 • • Tyonekll: PlatformA-09 We SCHEMATIC Last Completed:8/14/1992 PTD: 169-085 Hilcorp Alaska,LLC API: 50-883-20029-00 RKBtoTBGHead-54.08' CASING DETAIL ®g .' ii Size Wt Grade Conn ID Top Btm 30 Conductor Welded 28" Surf 386' 30' 16" 65 H-40 BUTT 15.250" Surf 631' ` 10-3/4" 45.5 J-55 BUTT 9.950" Surf 2,587' ', 7" 26 J-55 BUTT 6.276" Surf' 7,998' ke-,1 TUBING DETAIL sr il'2' `" 4-1/2" 12.75 1-55 EUE 8rd 3.958" 54' 4,860' x . '` 3-1/2" 9.3 J-55 EUE 8rd 2.992" 4,860' 5,223' 2-7/8" 6.5 J-55 EUE 8rd 2.441 5,223' 6,886' 16" ..0 JEWELRY DETAIL No Depth Depth ID OD Item (MD) (TVD) 10-3/4"" +.,. 1 294.5' 294.5' 3.810 5.510 Nipple,SSSV,Otis XXO _ _ 3.813"FXE 4-8 WRDP SSSV 35"IDrestriction 2 • 1� irli , 2 4,143' 3,482' 3.880 6.000 Packer,Otis VSR ' 4,257-4,319' 4150' 4226-4427 3 4,500' 3,734' 3"Magna Range Bridge Plug w/10'cement 4 ' .41 t... ":squeezed Perfs 4 4,547' 3,767' 4.000 5.880 Packer,Otis TW Tubing s `2 -f '555'-4556' 5 4,563' 3,779' 3.880 6.000 Packer,Otis VSR(Not Set) Punch �_��Peds 4,569' 3,783' 3.958 5.600 4-1/2 Blast Joints,214.5'TL 4,565' ' 6'900 _ 6 4,784' 3,932' 3.813 5.500 Sleeve,Otis XA SSD-Closed(Opens up) 7 '4 ► " 7 4,791' 3,937' 4.000 5.880 Packer,Otis TW ' 4,796' 3,941' 3.950 5.600 4-1/2 Blast Joints,25.79'TL .8 to 4,796' 3,941' 3"Magna Range BP w/10'cement � s e Fr, 8 4,821' 3,958' 3.810 5.520 Sleeve,Otis XO SSD-Closed(Opens down) 10 . Tagged FII @ 4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints,22.59'TL ,LL ))(.; � .. 4,934'sLMon 9 4,848' 3,977 4.000 5.880 Packer,Otis BWH ."),...f V 7/0117 10 4,860' 3,985' 2.990 5.890 XO,4.5 X 3.5 12 7 ` ` 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints,248.68'TL ;' 11 5,110' 4,159' 2.750 4.280 Sleeve,Otis XA SSD-Closed(Opens up) B12 5, ' , ' . . a , Lao! 5,128116' 44,171163' 4 2.992000 45.550880 3P1/2ckerBlast Otis JointsBWH,71.54'TL 14 !32 13 5,200' 4,221' 2.750 4.280 Sleeve,Otis XO SSD-Closed(Opens down) 15 14 5,211' 4,228' 4.000 5.880 Packer,Otis BWH r , '-i' 5,483' FISH 15 5,223' 4,237 2.440 5.030 X0,35X2875 i 5,224' 4,237' 2.440 3.3102-7/8 Blast Joints,253.93'TL % FISH:4 Cutter Bars(1)1.5"X 5',(1)1.75"X 5',(2) .K 2F`5,487-5,488'iik ed Pals 5483' 4,415' 0.000 1.25"X 5',452'of 0.125"Wire,21'SL Toolstring& 17 AO r®-> 4 5,535'FISH 2.875"Packoff Plug 16 5,484' 4,416' 2.313 3.750 Sleeve,Otis XA SSD(Opens up) 18 tij 0.875 2.250 FISH:AD-2 Stop 17 5,521' 4,441' 4.000 5.880 Packer,Otis BWH 19 '.' �� 5,756' 4,602' 2.440 3.310 2-7/8 Blast Joint,9.85'TL • -t_ 6,141' 4,864' 2.440 3.310 2-7/8 Blast Joints,49.3'TL 20 iii 6,274' 4,955' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 6,385' 5,030' 2.440 3.310 2-7/8 Blast Joint,29.55'TL 21 1 6,456' 5,078' 2.440 3.310 2-7/8 Blast Joint,19.70'TL 18 6,508' 5,114' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 4 ® 19 6,522' 5,123' 3.250 5.087 Packer,Otis BWH ,.,` 22 a 20 6,538' 5,134' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 6,764' 5,288' 2.440 3.310 2-7/8 Blast Joints,78.80'TL " =-y 21 6,875' 5,364' 2.205 3.230 Nipple,Otis XN 7,057'DSP - 22 6,886' 5,371' 2.440 4.500 Wireline Re-Entry Guide 7,666' 4'' 7.4'-':'-, 7,057' 5,488' 0.000 CIBP,Baker Cement Retainer !1,- .""", 7,666 5,913' 0.000 Cement Retainer,Baker K-1 7,691'FISH a1. 7,691 5,930' 0.00 FISH PBTD:7,057' TD:8,022' Updated By:JLL 02/09/18 H . • Tyonek Platform Well:A-09 SCHEMATIC Last Completed:8/14/1992 PTD: 169-085 Ililcorp Alaska,LLC API: 50-883-20029-00 PERFORATION DETAIL Zone Top Btm Top Btm FT Date Status (MD) (MD) (ND) (TVD) CI-Stray 4,226' 4,227' 3,544' 3,545' 1' 3/28/1970 SQZ CI-Stray 4,257' 4,266' 3,564' 3,570' 9' 01/27/18 OPEN CI-Stray 4,294' 4,319' 3,590' 3,607' 25' 01/27/18 OPEN CI-Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMT SQZ CI-A 4,284' 4,314' 3,585' 3,607' 20' 8/1/1992 CMT SQZ CI-B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMT SQZ CI-B 4,426' 4,427' 3,686' 3,686' 1' 3/28/1970 SQZ CI-B 4,555' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ CI-1.0 4,580' 4,590' 3,791' 3,798' 10' 09/25/17 ISOLATED CI-1.0 4,584' 4,674' 3,796' 3,859' 90' 8/14/1992 ISOLATED CI-2.0 4,692' 4,782' 3,871' 3,934' 90' 8/14/1992 ISOLATED CI-3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 ISOLATED CI-3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 ISOLATED CI-4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 ISOLATED CI-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 ISOLATED CI-5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 ISOLATED CI-6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 ISOLATED CI-7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 ISOLATED CI-7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 ISOLATED CI-8.0 5,232' 5,242' 4,246' 4,253' 10' 8/14/1992 ISOLATED CI-8.2 5,264' 5,289' 4,268' 4,285' 25' 8/14/1992 ISOLATED CI-9.0 5,332' 5,357' 4,315' 4,332' 25' 8/14/1992 ISOLATED CI-10.0 5,380' 5,395' 4,348' 4,358' 15' 8/14/1992 ISOLATED CI-11 5,416' 5,476' 4,372' 4,413' 60' 8/14/1992 ISOLATED 5,487' 5,488' 4,421' 4,422' 1' 3/28/1970 ISOLATED B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 ISOLATED D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 ISOLATED D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 ISOLATED E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 ISOLATED E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 ISOLATED F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 ISOLATED H-2 ISOLATED H-3 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 H-4 H-5 J-8 7,076' 7,098' 5,501' 5,516' 22' ISOLATED J-2 7,132' 7,142' 5,540' 5,547' 10' ISOLATED K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' ISOLATED 1-2&1-3 7,312' 7,337' 5,665' 5,682' 25' ISOLATED M-2 7,379' 7,389' 5,712' 5,719' 10' ISOLATED M-9 7,539' 7,544' 5,824' 5,827' 5' ISOLATED M-11 7,581' 7,587' 5,853' 5,858' 6' ISOLATED N-3 7,691' 7,697' 5,930' 5,935' 6' ISOLATED N-4 7,724' 7,734' 5,954' 5,961' 10' ISOLATED Updated by:JLL 02/09/18 • '• Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date NCIU A-09 Eline/Slickline 50-883-20029-00 169-085 1/26/18 1/28/18 Daily Operations: + ` e s *UN , 01/26/2018—Friday DEPART OSK FOR TYONEK PLATFORM.SIGN-IN, DRESS-OUT AND HOLD SIM-OPS MEETING WITH PROD/E-LINE. SPOT EQUIPMENT. RU SLICKLINE. SET RISER AND WLV,STAND UP LUBRICATOR. PT LUB W/800 PSI GASLIFT PRESSURE. RIH W/3.5" GS AND 5'X 1.5" PRONG TO 300 KB. LATCH SSSV, DUMP CONTROL LINE PSI, HAND SPANG FREE. POOH W/VALVE. ADD OIL JARS AND KNUCKLE-JOINT. RIH W/3.49 LIB ON 5'X1.5"STEM TO 4600KB,SEE FLUID LEVEL @ 3950KB, POOH. LAY DOWN LUBRICATOR. REMOVE SLICKLINE WIRE AND TOOLS. HELP RIG UP E-LINE. MU GAMMA RAY/CCL W/2-1/8" MULTI STAGE SETTING TOOL,AND 3.00" MAGNA RANGE PLUG. MOVE TOOLS AND LUBRICATOR TO WELL. PT W/GAS TO 850 PSI. RIH (13' TO TOP OF PLUG).SET DOWN W/PLUG AT 4620'AND LOGGED GAMMA RAY UP HOLE. END PASS AT 4100'.SEND LOGS TO TOWN.CONFIRMED SETTING DEPTH AT 4500'. LOG INTO POSITION @ 4487'(CCL DEPTH)AND SET PLUG AT 4500'.TAG PLUG TO CONFIRM SET AND POOH. MU 2"X 20'CEMENT DUMP BAILER. MIX 3.25 GAL. CEMENT, FILL BAILER. RIH TAG PLUG AT 4500'AND DUMP CEMENT. POOH. REDRESS BOTTOM OF BAILER, MIX CEMENT AND FILL BAILER. RIH W/BAILER RUN#2. DUMP @ 4495'. POOH. DUMP BAILED 6.5 GALLONS OR 10'CAP OF CEMENT ON PLUG WITH 2 RUNS. 01/27/2018-Saturday ATTEND PLATFORM SAFETY MEETING. PRESSURE UP WELL W/GAS. RIG UP LUBRICATOR AND MAKE UP 10'STRIP GUN WITH GAMMA RAY/CCL AND E-LINE JARS. MOVE TOOLS AND LUBRICATOR TO WELL. PT W/FLUID TO 2500 PSI. RIH RUN CORRELATION STRIP FROM 4450'-4200'.SEND LOG TO RE FOR APPROVAL.ADJUSTED PERFS 4'. PULL INTO POSITION AT 4295.5' (CCL DEPTH -13.5'CCL TO TOP SHOT). 760 PSI. GUN RUN#1-(10') (4309'-19'), GUN#2-(10')(4299'-4309'),GUN#3- (5')(4294'-4299')TOTAL-25'.GUN#4-(9')(4257'-4266'). USED GAMMA RAY/CCL BASE LOG FROM 1-26-18 FOR CORRELATION. RAN 2.50"STRIP GUNS LOADED 4SPF/60 DEG. PHASED.TOOL STUCK AFTER FIRING,JARRED FREE. 1150 PSI. POOH. RD E-LINE AND RU SLICKLINE. DUMP"'1 BBL DIESEL DOWN WELL TO CLEAN TUBING. RIH W/4.5"X-LINE AND SSSV TO 325KB,SET VALVE, FUNCTION TEST AND CONTROL LINE PSI.WILL NOT BUILD OR HOLD OVER 1100 PSI,SHEAR OFF, POOH. RIH W/4.5 GS W/5'X1.5" PRONG TO SAME, LATCH SSSV, POOH W/SSSV. OOH, REDRESS VALVE W/3.85" OVERSIZE PACKING. DUMP"10 GAL DIESEL AND RIH W/BL-BRUSH. RIH W/SSSV TO 325KB,SET VALVE, FUNCTION TEST AND PASS @ 4000 PSI AND HOLDING.OOH,VALVE SET,TALK W/PRODUCTION TO PERFORM CLOSURE TEST.STANDBY FOR TEST. 01/28/2018-Sunday MORNING MEETING, PERMIT/JSA.TALK ABOUT PLAN FORWARD TO RETRIEVE AND RE-SET SSSV. CHECK WORK AREA FOR HOUSEKEEPING ISSUES, PREP TOOLS. RIH W/4.5" GS W/PRONG TO TUBING HANGER,SET DOWN 325KB, LATCH SSSV, POOH W/VALVE. INSPECT VALVE-PACKING AND LOCK APPEAR TO BE FINE,ALTHOUGH THE BOTTOM 6" OF FLOW TUBE IS BROKEN OFF OF THE REST OF THE TUBE AND IS FLOATING INSIDE. LOCATE SECONDARY VALVE ON BOARD AND REDRESS AND PART TOGETHER NEW VALVE.SET UP TO PUMP METHANOL WHILE BRUSHING. FILL LUB W/METH AND RIH W/BL- BRUSH WHILE PUMPING METHANOL THE WHOLE TIME. OOH W/BRUSH, PUT ON SSSV. RIH W/4.5"X-LINE AND SSSV WHILE PURGING CONTROL LINE TO 325KB.SET DOWN AND WT TO SET VALVE. PRESSURE UP CONTROL LINE TO 3900 PSI, SHEAR OFF, POOH, NO VALVE. RIH W/4.5" CHECK-SET TOOL TO SAME,WT POOH, PIN SHEARED.STANDBY TO FLOW WELL AND PERFORM CLOSURE TEST. BRING WELL UP TO 3 MCFD AND DUMP VALVE. DOES NOT HOLD PRESSURE, BRING WELL UP TO 5 MCFD AND DUMP VALVE AND THEN HOLDS PRESSURE, GOOD TEST. RD SLICKLINE, CLEAN WORK AREA(SWEEP AND MOP)TAG AND BAG TOOLS, FINISH TICKET.STANDBY FOR CHOPPER. OF T • • 0,1,\�X77 s9 THE STATE Alaska Oil and Gas -�— Conservation Commission of __ .'. ALASKA .;f= 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 0i `*h �� Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis 6 u i 6 `.`3' Operations Manager S Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: North Cook Inlet Field, Tertiary Gas Pool,N. Cook Inlet Unit A-09 Permit to Drill Number: 169-085 Sundry Number: 317-599 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, Hollis S. French Chair DATED this2 day of December, 2017. • • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑✓ , Fracture Stimulate ❑ Repair Well 0 Operations shutdown 0 Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Pull Tubing 0 Change Approved Program E Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other: Reoerforate ` ❑✓ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC • Exploratory 0 Development 2r, 169-085 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number: Anchorage,Alaska 99503 50-883-20029-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 68 N COOK INLET UNIT A-09 Will planned perforations require a spacing exception? Yes 0 No 12✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0017589/ADL0037831 . NORTH COOK INLET/TERTIARY GAS ° 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): 8,022' , 6,149' ` 4,934' ` 4,037 840 psi 4,796';7,057';7,666' 5,483'&7,691' Casing Length Size MD TVD Burst Collapse Structural Conductor 386' 30" 386' 386' Surface 631' 16" 631' 631' 1,640psi 630psi Intermediate 2,587' 10-3/4" 2,587' 2,370' 3,580psi 2,090P si Production 7,998' 7" 7,998' 6,146' 4,980psi 4,320psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size:4-1/2", Tubing Grade: 12.75#/J-55, Tubing MD(ft): 4,860'; 4,580-6,842 3,791 -5,345 3-1/2",2-7/8" 9.3#/J-55,6.5#/J-55 5,223';6,886' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Packers(x9)See Schematic&WRDP SSSV Packers(See Schematic)&SSSV 295'(MD)295'(TVD) 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory ❑ Stratigraphic 0 Development ❑✓ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: January 5,2018 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended 0 16.Verbal Approval: Date: GAS Q ' WAG 0 GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 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: Michael Quick Authorized Title: Operations Manager Contact Email:_maUICk(q hiICOrp.Com Contact Phone: (907)777-8442 Authorized Signature: Date: IZ 121 ((-4- COMMISSION .COMMISSION USE ONLY Conditions of approval: Notify Commission s that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test ❑ Location Clearance El V E Other: DEC 21 2a17 QT'S !2- 27/ t ? Post Initial Injection MIT Req'd? Yes 0 No ❑ Spacing Exception Required? Yes ElNo Er Subsequent Form Required: 0 __q 04-J A Ectal APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 011 -4 114 J\ \ !/a lz/ac.fI?- 7 6 vvvv uA �I,, y`/'//`/' [2 2 C 1 7submit Form and rm 10-403 Revised 4/2017 Approved applicati aR'dtot� r' date of appt+bval. Attachments in Duplicate • • Well Prognosis Well: Tyonek A-09 Hilcorp Alaska,LL Date: 12/21/2017 Well Name: Tyonek A-09 API Number: 50-883-20029-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: January 5, 2018 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 169-085 First Call Engineer: Michael Quick (907)777-8442 (0) (907) 317-2969 (M) Second Call Engineer: Joe Kaiser (907) 777-8393 (0) (907)952-8897 (M) AFE Number: Current Bottom Hole Pressure: 789 psi @ 4,040' TVD (PT Survey Data 7/1/17) Max. Potential Surface Pressure: 1370 psi (Based on A-3 shut in tubing pressure from A& B Sands) ---- Brief Brief Well Summary A-09 was drilled in August 1969 and left in suspended status until a later date when gas production was needed. It was then completed in July 1975 throughout the Beluga and Sterling intervals with a single packer and single string of tubing that was run to the bottom perforations. The well was worked over in 1992 in order to determine intervals of water entry. As a result of the workover the upper sterling sands were squeezed with cement, lower beluga intervals were isolated with a cast iron bridge plug, and remaining intervals were grouped and placed behind several selective sleeves. The well stopped producing in January 2015 when fill was found in the tubing. An attempt was made in January 2016 to flow the Sterling 3&4 sands and the Sterling 1&2 sands above the fill depth and proved unsuccessful. The CI 1.0 was re-perforated from 4580'to 4590' MD in September 2017 with no significant results. S+e .,..- ., The purpose of this sundry is to isolate the open perforations below and re-perforate the A Sand and the Stray, both within the Sterling formation. These sands were previously isolated with a cement squeeze. Notes Regarding Wellbore Condition • Through tubing bridge plug (3" Magna Range Plug) set at 4796' with 10' cement dump bailed on top (9/23/17). • Suspected tubing part/3.5"ID restriction in tubing at+/-4150' MD. Procedure: 1. MIRU wireline, PT lubricator to 2,000 psi High/250 Low. 2. RIH pull SSSV. POOH. LD SSSV 3. RIH with through tubing bridge plug to±4,500'. Use Gamma/CCL to correlate. Consult Engineer prior to setting.Set plug. POOH. Note: confirm water level. 4. Contingency: RU and RIH with swab cups. Remove as much fluid as possible from tubing. POOH 5. RU wireline perforating guns. 6. RIH and reperforate the following intervals: Zone Sands Top Btm (MD) FT SPF -4-1A-0''' (MD) x —(-b trSterling CI A ±4,274' ±4,325' 51' 6 / v Sterling CI Stray ±4,235' ±4,273' 38' 6 a. Proposed perf's shown on the proposed schematic in red font. • • Well Prognosis Well: Tyonek A-09 Hilcurp Alaska,lit Date: 12/21/2017 b. Final Perf tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL to correlate. Utilize Press/Temp tool if available. e. Record tubing pressures before and after each perforating run. 7. RIH w/SSSV and set in profile. 8. RD wireline 9. Turn well over to production. Contingency Procedures: 10. The Sterling A sand may be perforated and tested prior to adding the Sterling Stray sand perforations. 11. If the Sterling A sand produces water,a through tubing bridge plug maybe set to isolated the A sand prior to perforating the Stray sand. Attachments: 1. Actual Schematic 2. Proposed Schematic III • • Tyonek Platform Well:A-09 PROPOSED SCHEMATIC Last Completed:8/14/1992 PTD: 169-085 i3ilcorn Alaska,LLC API: 50-883-20029-00 RKBtoTBG Head-54.08' CASING DETAIL Size Wt Grade Conn ID Top Btm 30" Conductor Welded 28" Surf 386' 30 � . 16" 65 H-40 BUTT 15.250" Surf 631' 10-3/4" 45.5 J-55 BUTT 9.950" Surf 2,587' 7" 26 J-55 BUTT 6.276" Surf' 7,998' TUBING DETAIL 4-1/2" 12.75 J-55 EUE 8rd 3.958" 54' 4,860' 3-1/2" 9.3 J-55 EUE 8rd 2.992" 4,860' 5,223' 2-7/8" 6.5 J-55 EUE 8rd 2.441 5,223' 6,886' 16" 1 , a�y Alt.' JEWELRY DETAIL No Depth Depth ID OD Item (MD) (ND) 10-3/4" " 1 294.5' 294.5' 3.810 5.510 Nipple,SSSV,Otis XXO 3.5"ID � r< r . 3.813"FXE 4-8 WRDP SSSV 2 4. 4,245-4,315' 2 4,143' 3,482' 3.880 6.000 Packer,Otis VSR restricti0 •••"II... t New Perfs 4150' r'..'.1 4226'-4,427' 4,500' 3"Through tubing BP 3 .. - Squeezed Perfs 3 4,547' 3,767' 4.000 5.880 Packer,Otis TW ,,555'-4,556' 4 4,563' 3,779' 3.880 6.000 Packer,Otis VSR(Not Set) Tubing 4 .41 �Y Punch _" ' eezedPerfs 4,569' 3,783' 3.958 5.600 4-1/2 Blast Joints,214.5'TL 4,565' g i tis 5 4,784' 3,932' 3.813 5.500 Sleeve,Otis XA SSD-Closed(Opens up) 6 1 �� 6 4,791' 3,937 4.000 5.880 Packer,Otis TW Ir 4,796' 3,941' 3.950 5.600 4-1/2 Blast Joints,25.79'TL )00 ' 4,796' 3,941' X 3"Magna Range BP w/10'cement 8 _ or 7 4,821' 3,958' 3.810 5.520 Sleeve,Otis XO SSD-Closed(Opens down) 9 ■ Tagged Fill @ 4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints,22.59'TL VIII 4.9 strolon 8 4,848' 3,977' 4.000 5.880 Packer,Otis BWH 7/01/17 9 4,860' 3,985' 2.990 5.890 XO,4.5 X 3.5 11 01jk 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints,248.68'TL jil 10 5,110' 4,159' 2.750 4.280 Sleeve,Otis XA SSD-Closed(Opens up) 111 I11 1.111 5,116' 4,163' 4.000 5.880 Packer,Otis BWH 5,128' 4,171' 2.992 4.550 3-1/2 Blast Joints,71.54'TL 13 `"' *M'" 12 5,200' 4,221' 2.750 4.280 Sleeve,Otis XO SSD-Closed(Opens down) 14 = :f 13 5,211' 4,228' 4.000 5.880 Packer,Otis BWH T',483' FISH 14 5,223' 4,237' 2.440 5.030 XO,3.5 X 2.875 5,224' 4,237' 2.440 3.310 2-7/8 Blast Joints,253.93'TL III.. �`"` FISH:4 Cutter Bars(1)1.5"X 5',(1)1.75"X 5',(2) w Etta'5487'-5488' '4Squeezed Pert5483' 4,415' 0.000 1.25"X 5',452'of 0.125"Wire,21'SL Toolstring& 16 - 'I`�u' '5,535 FISH 2.875"Packoff Plug 15 5,484' 4,416' 2.313 3.750 Sleeve,Otis XA SSD(Opens up) 17 III 0.875 2.250 FISH:AD-2 Stop s 16 5,521' 4,441' 4.000 5.880 Packer,Otis BWH `. 18 , P/..4 *' 5,756' 4,602' 2.440 3.310 2-7/8 Blast Joint,9.85'TL ," ' 6,141' 4,864' 2.440 3.310 2-7/8 Blast Joints,49.3'TL 19 IIE 6,274' 4,955' 2.440 3.310 2-7/8 Blast Joint,9.85'TL ` I - 6,385' 5,030' 2.440 3.310 2-7/8 Blast Joint,29.55'TL '' 6,456' 5,078' 2.440 3.310 2-7/8 Blast Joint,19.70'TL 20® e. !►I 17 6,508' 5,114' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) '', _ 18 6,522' 5,123' 3.250 5.087 Packer,Otis BWH • 21 19 6,538' 5,134' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) _ 6,764' 5,288' 2.440 3.310 2-7/8 Blast Joints,78.80'IL °I:. 20 6,875' 5,364' 2.205 3.230 Nipple,Otis XN 7,057'GBP 21 6,886' 5,371' 2.440 4.500 Wireline Re-Entry Guide 7,666' 7,057' 5,488' 0.000 CIBP,Baker Cement Retainer 7,666 5,913' 0.000 Cement Retainer,Baker K-1 VIP 7,691 5,930' 0.00 FISH 7,691'FISH 7, PBTD:7,057' TD:8,022' Updated By:MJQ 12/21/17 H . • Tyonek Platform Well:A-09 SCHEMATIC Last Completed:8/14/1992 PTD: 169-085 Ililcurp Alaska,LLC API: 50-883-20029-00 RKB to TBG Head-54.08' CASING DETAIL j Size Wt Grade Conn ID Top 8tm 1 {' 30" Conductor Welded 28" Surf 386' 16" 65 H-40 BUTT 15.250" Surf 631' 10-3/4" 45.5 J-55 BUTT 9.950" Surf 2,587' 7" 26 J-55 BUTT 6.276" Surf' 7,998' '. TUBING DETAIL A 4-1/2" 12.75 J-55 EUE 8rd 3.958" 54' 4,860' 3-1/2" 9.3 J-55 EUE 8rd 2.992" 4,860' 5,223' 2-7/8" 6.5 J-55 EUE 8rd 2.441 5,223' 6,886' 16 A '" r JEWELRY DETAIL 0 (MD) ;�t' Depth Depth No ID OD Item (ND) 10-3/4" •• 1 294.5' 294.5' 3.810 5.510 Nipple,SSSV,Otis XXO 3.5"ID 2 _ " ''' 3.813"FXE 4-8 WRDP SSSV restriction �t �!t 2 4,143' 3,482' 3.880 6.000 Packer,Otis VSR 4150' _ _ 4,226-4,427' 3 4,547' 3,767' 4.000 5.880 Packer,Otis TW 3 =. - `: Squeezed Perfs : 4 4,563' 3,779' 3.880 6.000 Packer,Otis VSR(Not Set) Tubing 4 Sq � 4,569' 3,783' 3.958 5.600 4-1/2 Blast Joints,214.5'TL Punch � 1• 5 4,784' 3,932' 3.813 5.500 Sleeve,Otis XA SSD-Closed(Opens up) 4,565' ' S 000 -$ 6 4,791' 3,937' 4.000 5.880 Packer,Otis TW 6 0 III 1 4,796' 3,941' 3.950 5.600 4-1/2 Blast Joints,25.79'TL ' 7i4,796' 3,941' 3"Magna Range BP w/10'cement t!l i s 7 4,821' 3,958' 3.810 5.520 Sleeve,Otis XO SSD-Closed(Opens down) 8 4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints,22.59'TL 98 4,848' 3,977' 4.000 5.880 Packer,Otis BWH vim 1,-" Tagged Hil @ e ,, 4,934 Sinton 9 4,860' 3,985' 2.990 5.890 XO,4.5 X 3.5 ` 7/01/17 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints,248.68'TL 110• 10 5,110' 4,159' 2.750 4.280 Sleeve,Otis XA SSD-Closed(Opens up) '- 11 5,116' 4,163' 4.000 5.880 Packer,Otis BWH 1•l l l '_ 5,128' 4,171' 2.992 4.550 3-1/2 Blast Joints,71.54'TL 12 5,200' 4,221' 2.750 4.280 Sleeve,Otis XO SSD-Closed(Opens down) 13 2 =,i, 13 5,211' 4,228' 4.000 5.880 Packer,Otis BWH 14 ' ® 14 5,223' 4,237' 2.440 5.030 XO,3.5 X 2.875 ' i 1r 5,483' FISH 5,224' 4,237' 2.440 3.310 2-7/8 Blast Joints,253.93'TL FISH:4 Cutter Bars(1)1.5"X 5',(1)1.75"X 5',(2) 15Er5487-5488 5483' 4,415' 0.000 1.25"X 5',452'of 0.125"Wire,21'SLToolstring& Squeezed Pei1s 2.875"Packoff Plug 16 oXot .5,535'FISH 15 5,484' 4,416' 2.313 3.750 Sleeve,Otis XA SSD(Opens up) 0.875 2.250 FISH:AD-2 Stop 1' ` 17 0t q 16 5,521' 4,441' 4.000 5.880 Packer,Otis BWH 5,756' 4,602' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 18 g'`:. 6,141' 4,864' 2.440 3.310 2-7/8 Blast Joints,49.3'TL '4,1 6,274' 4,955' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 19 Hu 6,385' 5,030' 2.440 3.310 2-7/8 Blast Joint,29.55'TL 6,456' 5,078' 2.440 3.310 2-7/8 Blast Joint,19.70'TL 20 X r_' - 17 6,508' 5,114' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) N r.. 18 6,522' 5,123' 3.250 5.087 Packer,Otis BWH 19 6,538' 5,134' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 4 21 ti Inn ,.",': 6,764' 5,288' 2.440 3.310 2-7/8 Blast Joints,78.80'TL 20 6,875' 5,364' 2.205 3.230 Nipple,Otis XN 21 6,886' 5,371' 2.440 4.500 Wireline Re-Entry Guide 7,057'CIBP 7,057' 5,488' 0.000 CIBP,Baker 7,666' 7,666 5,913' 0.000 Cement Retainer,Baker K-1 Cement Retainer 7,691 5,930' 0.00 FISH 111 7,691'FISH 7" PBTD:7,057' TD:8,022' Updated By:JLL 10/09/17 U 0 • Tyonek Platform Well:A-09 SCHEMATIC Last Completed:8/14/1992 PTD: 169-085 Hilcorp Alaska,LLC API: 50-883-20029-00 PERFORATION DETAIL Zone Top Btm Top Btm FT (MD) (MD) (ND) (TVD) Date Status CI-Stray 4,226' 4,227' 3544' 3545' 1' 3/28/1970 SQZ CI-Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMTSQZ CI-A 4,284' 4,314' 3,585' 3,607' 20' 8/1/1992 CMTSQZ CI-B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMT SQZ CI-B 4,426' 4,427' 3,686' 3,686' 1' 3/28/1970 SQZ CI-B 4,555' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ CI-1.0 4,580' 4,590' 3,791' 3,798' 10' 09/25/17 OPEN CI-1.0 4,584' 4,674' 3,796' 3,859' 90' 8/14/1992 OPEN CI-2.0 4,692' 4,782' 3,871' 3,934' 90' 8/14/1992 OPEN CI-3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 ISOLATED CI-3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 ISOLATED CI-4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 ISOLATED CI-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 ISOLATED CI-5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 ISOLATED CI-6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 ISOLATED CI-7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 ISOLATED CI-7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 ISOLATED CI-8.0 5,232' 5,242' 4,246' 4,253' 10' 8/14/1992 ISOLATED CI-8.2 5,264' 5,289' 4,268' 4,285' 25' 8/14/1992 ISOLATED CI-9.0 5,332' 5,357' 4,315' 4,332' 25' 8/14/1992 ISOLATED CI-10.0 5,380' 5,395' 4,348' 4,358' 15' 8/14/1992 ISOLATED CI-11 5,416' 5,476' 4,372' 4,413' 60' 8/14/1992 ISOLATED 5,487' 5,488' 4,421' 4,422' 1' 3/28/1970 ISOLATED B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 ISOLATED D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 ISOLATED D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 ISOLATED E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 ISOLATED E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 ISOLATED F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 ISOLATED H-2 ISOLATED H-3 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 H-4 H-5 J-8 7,076' 7,098' 5,501' 5,516' 22' ISOLATED J-2 7,132' 7,142' 5,540' 5,547' 10' ISOLATED K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' ISOLATED 1-2&1-3 7,312' 7,337' 5,665' 5,682' 25' ISOLATED M-2 7,379' 7,389' 5,712' 5,719' 10' ISOLATED M-9 7,539' 7,544' 5,824' 5,827' 5' ISOLATED M-11 7,581' 7,587' 5,853' 5,858' 6' ISOLATED N-3 7,691' 7,697' 5,930' 5,935' 6' ISOLATED N-4 7,724' 7,734' 5,954' 5,961' 10' ISOLATED Updated by:JLL 10/09/17 RECEIVED • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION rim* I fl 2011 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Pull Tubing 0 A '7""t"tera�INII'Huteown ❑ Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing❑ Change Approved Program 0 Plug for Redrill 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:Reperforate 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory❑ 169-085 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-883-20029-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0017589/ADL0037831 N Cook Inlet Unit A-09 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A North Cook Inlet/Tertiary Gas Pool 11.Present Well Condition Summary: Total Depth measured 8,022 feet Plugs 4796;7,057; measured 7,666 feet true vertical 6,149 feet Junk measured 5,483&7,691 feet Effective Depth measured 4,786 feet Packer measured See Schematic feet true vertical 3,934 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Structural Conductor 386' 30" 386' 386' Surface 631' 16" 631' 631' 1,640 psi 630 psi Intermediate 2,587' 10-3/4" 2,587' 2,370' 3,580 psi 2,090 psi Production 7,998' 7" 7,998' 6,146' 4,980 psi 4,320 psi Liner • Perforation depth Measured depth 4,580-4,782 feet SCANWE A's, ,„, . True Vertical depth 3,791 -3,934 feet 4-1/2” 12.75#/J-55 4,860(MD) 3,985(TVD) Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/J-55 5,223(MD) 4,237(TVD) 2-7/8" 6.5#/J-55 6,886(MD) 5,371 (TVD) Packers and SSSV(type,measured and true vertical depth) Pkrs(x9)See Schematic SSSV 295(MD)295(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: 0 0 0 50 52 Subsequent to operation: 0 0 0 53 66 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory El Development0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ Cl WAG ❑ GINJ❑ 3USP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-325 Authorized Name: Stan W.Golis Contact Name: Joe Kaiser Authorized Title: Operations Manager Contact Email: jkaiser@hilcorp.com 5.L.Authorized Signature: � .,.. 4r/...... Date: 1a Pi 1 11- Contact Phone: (907)777-8393 ✓ //./G-17 Form 10-404 Revised 4/2017 /(/l RB_ 3 VV OCT 1 i L'17 Submit Original Only III • Tyonek Platform 11 Well:A-09 SCHEMATIC Completed:8/14/1992 PTD: 169-085 Iiilcarp Alaska,LLC API: 50-883-20029-00 RKBtoTBGHead-54.08' CASING DETAIL I :eft. Size Wt Grade Conn ID Top Btm I" 1 ' '4 30" Conductor Welded 28" Surf 386' 30" le 16" 65 H-40 BUTT 15.250" Surf 631' ,it, 10-3/4" 45.5 J-55 BUTT 9.950" Surf 2,587' to , 7" 26 J-55 BUTT 6.276" Surf' 7,998' I ( TUBING DETAIL 4-1/2" 12.75 J-55 EUE 8rd 3.958" 54' 4,860' 3-1/2" 9.3 J-55 EUE 8rd 2.992" 4,860' 5,223' E i .Y 2-7/8" 6.5 J-55 EUE 8rd 2.441 5,223' 6,886' 1b' I 16, JEWELRY DETAIL " No Depth Depth aID OD Item . (MD) (ND) 143/4" " a 1 294.5' 294.5' 3.810 5.510 Nipple,SSSV,Otis XXO II 2 3.813"FXE 4-8 WRDP SSSV 2 4,143' 3,482' 3.880 6.000 Packer,Otis VSR ` 4,226'-4.427 3 4,547 3,767' 4.000 5.880 Packer,Otis TW 7- Squeezed Perfs 4 4,563' 3,779' 3.880 6.000 Packer,Otis VSR(Not Set) ,555'-4,556' 4,569' 3,783' 3.958 5.600 4-1/2 Blast Joints,214.5'TL Tubing 4 �� • Squeezed Perfs Punch 5 4,784' 3,932' 3.813 5.500 Sleeve,OtisXASSD-Closed(Opensup) 4,565' 5:101I - °-- 6 4,791' 3,937' 4.000 5.880 Packer,Otis TW 6 �►/I ► F' C t e 4,796' _ 3,941' 3.950 5.600 4-1/2 Blast Joints,25.79'TL r 4,796' 3,941' CIBP w/10'cement 000 " 7 7 21' 3,958' 3.810 5.520 Sleeve,Otis XO SSD-Closed(Opens down) 8 A4, 4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints,22.59'TL 91 � TaggedFll@ 8 4,848' 3,977' 4.000 5.880 Packer,Otis BWH 1a _1 4,934 SLMon 9 4,860' 3,985' 2.990 5.890 XO,4.5 X 3.5 7/01/17 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints,248.68'TL 11 03 �." 10 5,110' 4,159' 2.750 4.280 Sleeve,OtisXASSD-Closed(Opens up) 11 5,116' 4,163' 4.000 5.880 Packer,Otis BWH 1-'Bpi 5,128' 4,171' 2.992 4.550 3-1/2 Blast Joints,71.54'TL 12 5,200' 4,221' 2.750 4.280 Sleeve,Otis XO SSD-Closed(Opens down) 1s 13 5,211' 4,228' 4.000 5.880 Packer,Otis BWH 14 IF-4 - 14 5,223' 4,237' 2.440 5.030 XO,3.5 X 2.875 i +5,483' FISH 5,224' 4,237' 2.440 3.310 2-7/8 Blast Joints,253.93'TL FISH:4 Cutter Bars(1)1.5"X 5',(1)1.75"X 5',(2) is RC - 5483' 4,415' 0.000 1.25"X 5',452'of 0.125"Wire,21'SLToolstring& 5 487-d' S 2.875"Packoff Plug 16 X `5,535'FISH 15 5,484' 4,416' 2.313 3.750 Sleeve,Otis XA SSD(Opens up) 0.875 2.250 FISH:AD-2 Stop 17'E16 5,521' 4,441' 4.000 5.880 Packer,Otis BWH 4" 5,756' 4,602' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 18 '.'t"J `':a 6,141' 4,864' 2.440 3.310 2-7/8 Blast Joints,49.3'TL 6,274' 4,955' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 19 006 6,385' 5,030' 2.440 3.310 2-7/8 Blast Joint,29.55'TL 6,456' 5,078' 2.440 3.310 2-7/8 Blast Joint,19.70'TL 20 X 17 6,508' 5,114' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) N18 6,522' 5,123' 3.250 5.087 Packer,Otis BWH 19 6,538' 5,134' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 21 1 6,764' 5,288' 2.440 3.310 2-7/8 Blast Joints,78.80'TL 1 20 6,875' 5,364' 2.205 3.230 Nipple,Otis XN -, 21 6,886' 5,371' 2.440 4.500 Wireline Re-Entry Guide 7,057 CIBP ,, 7,057' 5,488' 0.000 CIBP,Baker 7,666' 7,666 5,913' 0.000 Cement Retainer,Baker K-1 Cement Retainer 7,691 5,930' 0.00 FISH 7,691'FISH PBTD:7,057' TD:8,022' Updated By:JLL 10/09/17 • • Tyonek Platform Well:A-09 SCHEMATIC 169 Completed:8/14/1992 PTD: Hilcorp Alaska,LLC API: 50-883-20029-00 PERFORATION DETAIL Zone Top Btm Top Btm FT Date Status (MD) (MD) (ND) (TVD) CI-Stray 4,226' 4,227' 3544' 3545' 1' 3/28/1970 SQZ CI-Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMT SQZ CI-A 4,284' 4,314' 3,585' 3,607' 20' 8/1/1992 CMT SQZ CI-B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMT SQZ CI-B 4,426' 4,427' 3,686' 3,686' 1' 3/28/1970 SQZ CI-B 4,555' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ C1-1.0 4,580' 4,590' 3,791' 3,798' 10' 09/25/17 OPEN CI-1.0 4,584' 4,674' 3,796' 3,859' 90' 8/14/1992 OPEN CI-2.0 4,692' 4,782' 3,871' 3,934' 90' 8/14/1992 OPEN CI-3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 ISOLATED CI-3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 ISOLATED CI-4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 ISOLATED CI-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 ISOLATED CI-5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 ISOLATED CI-6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 ISOLATED CI-7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 ISOLATED CI-7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 ISOLATED CI-8.0 5,232' 5,242' 4,246' 4,253' 10' 8/14/1992 ISOLATED CI-8.2 5,264' 5,289' 4,268' 4,285' 25' 8/14/1992 ISOLATED CI-9.0 5,332' 5,357' 4,315' 4,332' 25' 8/14/1992 ISOLATED CI-10.0 5,380' 5,395' 4,348' 4,358' 15' 8/14/1992 ISOLATED CI-11 5,416' 5,476' 4,372' 4,413' 60' 8/14/1992 ISOLATED 5,487' 5,488' 4,421' 4,422' 1' 3/28/1970 ISOLATED B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 ISOLATED D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 ISOLATED D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 ISOLATED E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 ISOLATED E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 ISOLATED F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 ISOLATED H-2 ISOLATED H-3 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 H-4 H-5 J-8 7,076' 7,098' 5,501' 5,516' 22' ISOLATED J-2 7,132' 7,142' 5,540' 5,547' 10' ISOLATED K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' ISOLATED 1-2&1-3 7,312' 7,337' 5,665' 5,682' 25' ISOLATED M-2 7,379' 7,389' 5,712' 5,719' 10' ISOLATED M-9 7,539' 7,544' 5,824' 5,827' 5' ISOLATED M-11 7,581' 7,587' 5,853' 5,858' 6' ISOLATED N-3 7,691' 7,697' 5,930' 5,935' 6' ISOLATED N-4 7,724' 7,734' 5,954' 5,961' 10' ISOLATED Updated by:1LL 10/09/17 • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date NCI A-09 W/L& E/L 50-883-20029-00 169-085 9/13/17 9/25/17 Daily Operations: 09/13/2017 -Wednesday JSA/TGSM RIG UP P/T 2500PS1 (GOOD) OPEN SSSV. RIH W/4-1/2 GS W/PRONG TO 294KB LATCH SSSV. BLEED C- LINE W/T PULL SSSV. POOH. RIH W/3.5 G-RIG ON 3.59 SWEDGE TO (SEE FL @3930KB) 4807KB W/T FALL TO 4860KB. TAG DRIFT PAST 4807KB 5 TIMES. LOOKS CLEAR, PULL UP TO 4580KB. SEE TIGHT SPOT W/T ONLY SLIGHT OVER PULL, SIT DOWN IN MULTIPLE SPOTS BETWEEN 4575 -4580'KB. FALL THROUGH PULL BACK UP GET BLOWN UP HOLE 40' POOH SLOW. 09/14/2017-Thursday OOH RIG UP GAS TO TUB PRESSURE UP. RIH W/3" LIB TO 4150KB TAG HARD, POOH. SEE FL @2000KB WITH 780PS1 POOH. SEE POSSIBLE 2 7/8 G-FISHING NECK NOT CLEAR. RIG DOWN. 09/15/2017 - Friday NO OPERATIONS TO REPORT 09/16/2017-Saturday NO OPERATIONS TO REPORT 09/17/2017-Sunday RIG UP,JSA/TGSM (P/T 2500PS1 GOOD). PRESSURE UP TUBING WITH GAS LIFT TO 800PSI. RIH W/3" PUMP BAILER TO 4578KB W/T POOH EMPTY. RIH W/3" LIB TO 4150KB W/T, CAN'T PASS, POOH. IMPRESSION OF PARTED 4-1/2" TUBING BELOW PACKER AT 4,143', POOH. SDFN. 09/18/2017 - Monday CHECK TS RE HEAD CUT 100' OF WIRE. RIG UP, PRESSURE UP TUB TO 800PSI WITH GAS. RIH W/2.5 CEN ON 3.59 CEN 3' LONG TO 4856KB. OOH SEND FOR E-LINE CREW RIG DOWN W/L. SPOT UP E-LINE, JSA/TGSM. RU 3.5" CIBP. RIH. TAGGED 4578KB. UNABLE TO PASS RESTRICTION. POOH. LD TOOL STRING. RIG DOWN E-LINE. 09/19/2017-Tuesday NO OPERATIONS TO REPORT 09/20/2017 -Wednesday NO OPERATIONS TO REPORT 09/21/2017 -Thursday NO OPERATIONS TO REPORT 09/22/2017- Friday JSA. Rig up, PT lubricator and equipment to 1500p psi. Good test. SDFN. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date NCI A-09 W/L& E/L 50-883-20029-00 169-085 9/13/17 9/25/17 Daily Operations: 09/23/2017-Saturday JSA/TGSM. RIG UP. RIH WI 4-1/2 GS W/PRONG TO 295KB, LATCH. BLEED C-LINE. Si FREE, POOH. RIG DOWN WIRELINE. RIG UP E-LINE. PRESSURE TUBING UP W/GAS LIFT TO 800PSI. E-LINE RIH W/3-1/8" CCL DRIFT TO 4835KB, CLEAR. POOH E-LINE. RIH WI 3.0" CIBP TO 4796 KB, SET PLUG. POOH. RIH W/2" DUMP BAILER TO 4790KB, DUMP. POOH. E-LINE RIH W/2" BAILER & DUMP CEMENT. CEMENT TOTAL OF 10'. POOH. SDFN. 09/24/2017-Sunday JSA/TGSM. RIG UP W/L. RIH W/3.5 B-BOX TO 2,350KB TAG FL. POOH. OOH, BLEED DOWN WELL. RIG UP TANK AND 2" LINE TO SWAB. RIH W/SWAB MANDREL TO 2,350KB SWAB SHEET. SWABED WELL DOWN TO 4,060KB. LAY LUB DOWN. RIG UP E-LINE PRESSURE UP TUBING TO 800PSI W/GAS LIFT. E-LINE RIH W/TUB PUNCHER TO 4,565KB TO 4,575KB SHOOT, SEE NO CHANGE IN PRESSURE. POOH,TUBING PUNCH DID NOT SHOOT. RE-BUILT RIH W/SAME TO 4,565 KB AND SHOOT. POOH. ALL SHOTS FIRED. SDFN. 09/25/2017- Monday RU e-line, RIH with 10' of 2-7/8" HC gun.Tagged at 4550' (tubing restriction). POOH. RIH with 10' 6spf RTG gun (strip gun). Pressure up with with gas lift supply. Shoot gun from 4,580' -4,590', no pressure increase. POOH. RD E-line. LOF � • ,w\� 1yyy s THE STATE Alaska Oil and Gas �,,;.s�� of® T ® KA Conservation Commission ts fx 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 tel" ALAS" Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis 4� . Operations Manager S"* . Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: North Cook Inlet Field, Tertiary Gas Pool, A-09 Permit to Drill Number: 169-085 Sundry Number: 317-325 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, 10 0 Hollis S. French t Chair DATED this (6 day of July, 2017. RBDMS JUL 2 7 2017 0 • RECEIVED STATE OF ALASKA JUL 12 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 9 • Fracture Stimulate 0 Repair Well 0 Operations shutdown 0 Suspend ❑ Perforate 0• Other Stimulate 0 Pull Tubing 0 Change Approved Program❑ Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other: Reperforate E' 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska, LLC Exploratory 0 Development 0 • 169-085' 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic6_API Number 0 Service ❑ Anchorage,Alaska 99503 50-883-20029-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 68 • N COOK INLET UNIT A-09 Will planned perforations require a spacing exception? Yes 0 No 9 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0017589/ADL0037831 • NORTH COOK INLET/TERTIARY GAS • 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): 8,022' • 6,149' ' 4,934' 4,037' 840 psi 7,057'&7,666' 5,483'&7,691' Casing Length Size MD TVD Burst Collapse Structural Conductor 386' 30" 386' 386' Surface 631' 16" 631' 631' 1,64opsi 630psi Intermediate 2,587 10-3/4" 2,587' 2,370' 3,580psi 2,090psi Production 7,998' 7" 7,998' 6,146' 4,980psi 4,320psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size:4-1/2", Tubing Grade: 12.75#/J-55, Tubing MD(It): 4,860'; 4,584-6,842 3,796-5,345 3-1/2",2-7/8" 9.3#/J-55,6.5#I J-55 5,223';6,886' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Packers(x9)See Schematic&WRDP SSSV Packers(See Schematic)&SSSV 295'(MD)295'(TVD) 12.Attachments: Proposal Summary 9 Wellbore schematic 9 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development 0 • Service 0 14. Estimated Date for 15.Well Status after proposed work: CommencingOperations: July 26,2017 OILWINJWDSPL p 0 0 0 Suspended 0 16.Verbal Approval: Date: GAS 0 ' WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned 0 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: Oper tions Manager Contact Email: jkaiserahilcorp.com f.A,•i / Contact Phone: (907)777-8393 Authorized Signature. �a,�3 Date: 7 zcA COMMISSI N USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: I?_3 2.._� Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: Post Initial Injection MIT Req'd? Yes 0 No q q Spacing Exception Required? Yes 0 No Subsequent Form Required: /c9 �— j &( RBDMS I' JUL2 7 2017 lAt:kgr\. APPROVED BY I r I t Approved by: COMMISSIONER THE COMMISSION Date: 6. /(1.7`� ORIGINA Submit Form and "U Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. zns7 Attachments i Duplicate • • Well Prognosis Well: Tyonek A-09 Ililcorp Alaska,LL Date: 7/12/2017 Well Name: Tyonek A-09 API Number: 50-883-20029-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: July 26th, 2017 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 169-085 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: 789 psi @ 4,040' TVD (PT Survey Data 7/1/17) Max. Potential Surface Pressure: 840 psi (Based on gas lift supply pressure) Brief Well Summary A-09 was drilled in August 1969 and left in suspended status until a later date when gas production was needed. It was then completed in July 1975 throughout the Beluga and Sterling intervals with a single packer • and single string of tubing that was run to the bottom perforations. The well was worked over in 1992 in order to determine intervals of water entry. As a result of the workover the upper sterling sands were squeezed with cement,lower beluga intervals were isolated with a cast iron bridge plug, and remaining intervals were grouped and placed behind several selective sleeves. The well stopped producing in January 2015 when fill was • found in the tubing. An attempt was made in January 2016 to flow the Sterling 3&4 sands and the Sterling 1&2 sands above the fill depth and proved unsuccessful. The purpose of this work/sundry is to install a tubing plug,tubing punch, and potentially reperforate the C1.0 Sand in the Sterling formation. Notes Regarding Wellbore Condition • Tagged at 4,934' WLM on 7/1/17. • Tubing has restriction at 4,582' WLM.Tubing ID is approximately 3.65". • Prior to a setting a plug and perforating, water in the tubing will be pushed away with gas lift and/or well swabbed down. Procedure: 1. MIRU wireline, PT lubricator to 1,500 psi Hi 250 Low. 2. RIH pull SSSV. POOH. LD SSSV 3. RIH with 4.5" CIBP (3.5" ID)to ±4,797'. Use Gamma/CCL to correlate. Consult Engineer prior to setting. Set plug. POOH. Note: confirm water level. 4. RU dump bailer. RIH with bailer and cement. Dump bail 5' cement on top of plug. POOH. 5. Bleed down pressure to verify any communication with reservior(C1.0) through sleeve at 4,784'. Consult Engineer. 6. Utilize RU swab cubs. Remove as much fluid as possible from tubing. POOH 7. RU Tubing Punch. RIH and punch tubing at—4,572'. Use gamma/CCL to correlate. Consult Engineer prior to setting. Punch tubing. POOH. 5%. l. S-4.id ss�"` a\ 8. Wireline on standby while operations to tests well. (24 - XI 3.�5`' e.-C 9. If productive, RIH w/SSSV and set in profile. 10. RD wireline 11. Turn well over to production. • Well Prognosis Well: Tyonek A-09 IIilcorp Alaska,LU Date: 7/12/2017 Contingency Procedures: (if no gas production from tubing punch) 1. Utilze Gas lift supply to push water away. 2. Utilize RU swab cubs. Remove as much fluid as possible from tubing. POOH 3. RU 2-7/8" 6 spf wireline guns. 4. RIH and reperforate the following intervals: Zone Sands (Mp) Btm (MD) FT SPF Sterling Cl 1.0 ±4,580' ±4,610' 30' 6 a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL to correlate. Utilize Press/Temp tool if available. e. Install Crystal gauges. Record tubing pressures before and after each perforating run. 5. RIH w/SSSV and set in profile. 6. RD wireline 7. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic . H • H . Tyonek Platform Well:A-09 SCHEMATIC Last Completed:8/14/1992 PTD: 169-085 Hilcorp Alaska,LLC API: 50-883-20029-00 RKB to TBG Head-54.08' CASING DETAIL Size Wt Grade Conn ID Top Btm 1 30" Conductor Welded 28" Surf 386' 16" 65 H-40 BUTT 15.250" Surf 631' 10-3/4" 45.5 J-55 BUTT 9.950" Surf 2587' 7" 26 J-55 BUTT 6.276" Surf' 7,998' TUBING DETAIL 4-1/2" 12.75 J-55 EUE 8rd 3.958" 54' 4,860' 3-1/2" 9.3 J-55 EUE 8rd 2.992" 4,860' 5,223' 2-7/8" 6.5 J-55 EUE 8rd 2.441 5,223' 6,886' 16' 4 k JEWELRY DETAIL No Depth Depth ID OD Item (MD) (ND) 10-3/4' - 1 294.5' 294.5' 3.810 5.510 Nipple,SSSV,Otis XXO 3.813"FXE 4-8 WRDP SSSV 2 �1 2 4,143' 3,482' 3.880 6.000 Packer,Otis VSR 4'226'-4'427' 3 4,547' 3,767' 4.000 5.880 Packer,Otis TW Squeezed Perfs 4 4,563' 3,779' 3.880 6.000 Packer,Otis VSR(Not Set) 4,569' 3,783' 3.958 5.600 4-1/2 Blast Joints,214.5'TL 4 Z 4,555-4,556' Squeezed Perfs 4,784' 3,932' 3.813 5.500 Sleeve,Otis XA SSD-Closed(Opens up) ' 5 00E1 {✓i' 6 4,791' 3,937' 4.000 5.880 Packer,Otis TW 6 .. ► `M�� ' 0' 4,796' 3,941' 3.950 5.600 4-1/2 Blast Joints,25.79'TL �� 7 4,821' 3,958' 3.810 5.520 Sleeve,Otis XO SSD-Closed(Opens down) 7fir _. 4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints,22.59'TL 8 Jul h..- 8 4,848' 3,977' 4.000 5.880 Packer,Otis BWH 9 ' Ili - Tagged FII @ 9 4,860' 3,985' 2.990 5.890 XO,4.5 X 3.5 o�Q 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints,248.68'TL 1� 4,934 SLM on ` 7/01/17 10 5,110' 4,159' 2.750 4.280 Sleeve,Otis XA SSD-Closed(Opens up) 11 irjj r-'. 11 5416' 4,163' 4.000 5.880 Packer,Otis BWH 5,128' 4,171' 2.992 4.550 3-1/2 Blast Joints,71.54'TL 1.0E0 12 5,200' 4,221' 2.750 4.280 Sleeve,Otis XO SSD-Closed(Opens down) 13 5,211' 4,228' 4.000 5.880 Packer,Otis BWH 13 , 7,3 k, ,'•,. 14 5,223' 4,237' 2.440 5.030 XO,3.5 X 2.875 t4 5,224' 4,237' 2.440 3.310 2-7/8 Blast Joints,253.93'TL 775483 85,483 FISH FISH:4 Cutter Bars(1)1.5"X 5',(1)1.75"X 5',(2) ;r 5483' 4,415' 0.000 1.25"X 5',452'of 0.125"Wire,21'SL Toolstring& 15 RE ,„ 2.875"Packoff Plug =' 5.497 5'488 15 5,484' 4,416' 2.313 3.750 Sleeve,Otis XA SSD(Opens up) Squeezed Perfs 6 ' 5535'FISH 0.875 2.250 FISH:AD-2 Stop , ��++/ 16 5,521' 4,441' 4.000 5.880 Packer,Otis BWH 17 ��. -, 5,756' 4,602' 2.440 3.310 2-7/8 Blast Joint,9.85'TL �T6,141' 4,864' 2.440 3.310 2-7/8 Blast Joints,49.3'TL 18 ` z g 6,274' 4,955' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 6,385' 5,030' 2.440 3.310 2-7/8 Blast Joint,29.55'TL 19 Ilr 6,456' 5,078' 2.440 3.310 2-7/8 Blast Joint,19.70'TL 17 6,508' 5,114' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 20 X 18 6,522' 5,123' 3.250 5.087 Packer,Otis BWH N 19 6,538' 5,134' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 6,764' 5,288' 2.440 3.310 2-7/8 Blast Joints,78.80'TL 21 IJ-_ ' 20 6,875' 5,364' 2.205 3.230 Nipple,Otis XN 21 6,886' 5,371' 2.440 4.500 Wireline Re-Entry Guide " 7,057' 5,488' 0.000 CIBP,Baker 7,057'CIBP . �... 7,666 5,913' 0.000 Cement Retainer,Baker K-1 7,666' 7,691 5,930' 0.00 FISH Cement Retainer • -/ 7,691'FISH �y, DIV) 7" .r .:'.:A,..a:..,.:1 S. PBTD:7,057' TD:8,022' Updated By:ILL 7/12/2017 . . • Tyonek Platform Well:A-09 SCHEMATICCompleted:8/14/1992 PTD: 169-085 Hilcorp Alaska,LLC API: 50-883-20029-00 PERFORATION DETAIL Zone Top Btm Top Btm FT Date Status (MD) (MD) (TVD) (TVD) CI-Stray 4,226' 4,227' 3544' 3545' 1' 3/28/1970 SQZ CI-Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMT SQZ CI-A 4,284' 4,314' 3,585' 3,607' 20' 8/1/1992 CMT SQZ CI-B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMT SQZ CI-B 4,426' 4,427' 3,686' 3,686' 1' 3/28/1970 SQZ CI-B 4,555' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ CI-1.0 4,584' 4,674' 3,796' 3,859' 90' 8/14/1992 OPEN CI-2.0 4,692' 4,782' 3,871' 3,934' 90' 8/14/1992 OPEN CI-3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 OPEN CI-3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 OPEN C1-4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 OPEN CI-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 OPEN CI-5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 OPEN CI-6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 OPEN CI-7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 OPEN CI-7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 OPEN CI-8.0 5,232' 5,242' 4,246' 4,253' 10' 8/14/1992 OPEN CI-8.2 5,264' 5,289' 4,268' 4,285' 25' 8/14/1992 OPEN CI-9.0 5,332' 5,357' 4,315' 4,332' 25' 8/14/1992 OPEN CI-10.0 5,380' 5,395' 4,348' 4,358' 15' 8/14/1992 OPEN CI-11 5,416' 5,476' 4,372' 4,413' 60' 8/14/1992 OPEN 5,487' 5,488' 4,421' 4,422' 1' 3/28/1970 SQZ B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 OPEN D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 OPEN D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 OPEN E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 OPEN E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 OPEN F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 OPEN H-2 OPEN H-3 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 H-4 H-5 J-8 7,076' 7,098' 5,501' 5,516' 22' Isolated J-2 7,132' 7,142' 5,540' 5,547' 10' Isolated K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' Isolated 1-2&1-3 7,312' 7,337' 5,665' 5,682' 25' Isolated M-2 7,379' 7,389' 5,712' 5,719' 10' Isolated M-9 7,539' 7,544' 5,824' 5,827' 5' Isolated M-11 7,581' 7,587' 5,853' 5,858' 6' Isolated N-3 7,691' 7,697' 5,930' 5,935' 6' Isolated N-4 7,724' 7,734' 5,954' 5,961' 10' Isolated A-09 Schematic 2017-07-11 Page 2 of 2 07/12/17 JLL • H . • Tyonek Platform Well:A-09 PROPOSED Last Completed:8/14/1992 PTD: 169-085 Hilcorp Alaska,LLC API: 50-883-20029-00 RKBtoTBG Head-54.08' CASING DETAIL `•� Size Wt Grade Conn ID Top Btm 1 30" Conductor Welded 28" Surf 386' 3a' 16" 65 H-40 BUTT 15.250" Surf 631' 10-3/4" 45.5 J-55 BUTT 9.950" Surf 2,587' 7" 26 J-55 BUTT 6.276" Surf' 7,998' ' TUBING DETAIL 4-1/2" 12.75 J-55 EUE 8rd 3.958" 54' 4,860' 3-1/2" 9.3 J-55 EUE 8rd 2.992" 4,860' 5,223' 2-7/8" 6.5 J-55 EUE 8rd 2.441 5,223' 6,886' 16" 1j 1 I; JEWELRY DETAIL Depth Depth x' No ID OD Item (MD) (TVD) 10-3/4" ' „ 1 294.5' 294.5' 3.810 5.510 Nipple,SSSV,Otis XXO 3.813"FXE 4-8 WRDP SSSV 2 ,► 2 4,143' 3,482' 3.880 6.000 Packer,Otis VSR '■ 4,226'-4'427 3 4,547 3,767' 4.000 5.880 Packer,Otis TW s ®� Squeezed Perfs 4 4,563' 3,779' 3.880 6.000 Packer,Otis VSR(Not Set) y- = ,,555'-4,556' 4,569' 3,783' 3.958 5.600 4-1/2 Blast Joints,214.5'TL 4 % '�. ;:ol!"'".: .• Squeezed Perfs 5 4,784' 3,932' 3.813 5.500 Sleeve,Otis XA SSD-Closed(Opens up) ©Ili I 6 4,791' 3,937' 4.000 5.880 Packer,Otis TW 6 -,•'►7® >' + 4,796' 3,941' 3.950 5.600 4-1/2 Blast Joints,25.79'TL 1 (�'' t �._. ±4,797' ±3,941' CIBP w/5'cement 7 4,821' 3,958' 3.810 5.520 Sleeve,Otis XO SSD-Closed(Opens down) 8 `i .= 4,826' 3,962' 3.950 5.600 4-1/2 Blast Joints,22.59'TL 9 8 4,848' 3,977' 4.000 5.880 Packer,Otis BWH I Tagged All @ I MI9 4,860' 3,985' 2.990 5.890 XO,4.5 X 3.5 «,.� 4,934'SLMon 7/01/17 4,861' 3,986' 2.990 4.550 3-1/2 Blast Joints,248.68'TL 11 i 10 5,110' 4,159' 2.750 4.280 Sleeve,Otis XA SSD-Closed(Opens up) 11 5,116' 4,163' 4.000 5.880 Packer,Otis BWH I 0[]0', 5,128' 4,171' 2.992 4.550 3 1/2 Blast Joints,71.54'TL 12 5,200' 4,221' 2.750 4.280 Sleeve,Otis XO SSD-Closed(Opens down) 13 1 ` +,--t 13 5,211' 4,228' 4.000 5.880 Packer,Otis BWH 14 `` d 14 5,223' 4,237' 2.440 5.030 XO,3.5 X 2.875 ,5,483 FISH 5,224' 4,237' 2.440 3.310 2-7/8 Blast Joints,253.93'TL FISH:4 Cutter Bars(1)1.5"X 5',(1)1.75"X 5',(2) 15''Er54875,44385483' 4,415' 0.000 1.25"X 5',452'of 0.125"Wire,21'SL Toolstring& ed pis 2.875"Packoff Plug 16 q Z 5,535'FISH 15 5,484' 4,416' 2.313 3.750 Sleeve,Otis XA SSD(Opens up) 0.875 2.250 FISH:AD-2 Stop 17 iiil 16 5,521' 4,441' 4.000 5.880 Packer,Otis BWH 5,756' 4,602' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 18 'F 4 ��1., 6,141' 4,864' 2.440 3.310 2-7/8 Blast Joints,49.3'TL 6,274' 4,955' 2.440 3.310 2-7/8 Blast Joint,9.85'TL 19 02 6,385' 5,030' 2.440 3.310 2-7/8 Blast Joint,29.55'TL 6,456' 5,078' 2.440 3.310 2-7/8 Blast Joint,19.70'TL 20 117 6,508' 5,114' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) 18 6,522' 5,123' 3.250 5.087 Packer,Otis BWH a ' I 19 6,538' 5,134' 2.313 3.750 Sleeve,Otis XO SSD-Open(Opens down) `f"' 21 lin 6,764' 5,288' 2.440 3.310 2-7/8 Blast Joints,78.80'TL 2,., 20 6,875' 5,364' 2.205 3.230 Nipple,Otis XN .. . 21 6,886' 5,371' 2.440 4.500 Wireline Re-Entry Guide 7,057 CIBPT_ 7,057' 5,488' 0.000 CIBP,Baker 7,666' ' ..`2 7,666 5,913' 0.000 Cement Retainer,Baker K-1 Cement Retainer r4 o 7,691 5,930' 0.00 FISH 7,691'FISH 7, r_ „4 e>,q ttijii PBTD:7,057' TD:8,022' Updated By:JLL 07/12/17 Tyonek Platform .. Well:A-09 n 0 PROPOSED d:8/14/1992 PTD: 169-085 Ililcarp Alaska,LLC API: 50-883-20029-00 PERFORATION DETAIL Zone Top Btm Top Btm FF Date Status (MD) (MD) (TVD) (TVD) CI-Stray 4,226' 4,227' 3544' 3545' 1' 3/28/1970 SQZ CI-Stray 4,247' 4,262' 3,559' 3,570' 15' 7/31/1992 CMT SQZ CI-A 4,284' 4,314' 3,585' 3,607' 20' 8/1/1992 CMT SQZ CI-B 4,330' 4,400' 3,618' 3,667' 70' 8/1/1992 CMT SQZ CI-B 4,426' 4,427' 3,686' 3,686' 1' 3/28/1970 SQZ CI-B 4,555' 4,556' 3,776' 3,777' 1' 3/28/1970 SQZ /�� T CI-1.0 ±4,580' ±4610' �„_w6��-L'±3,791' ±3,812' ±30' FUTURE _ PROPOSED / CI-1.0 4,584' 4,674' 3,796' 3,859' 90' 8/14/1992 OPEN CI-2.0 4,692' 4,782' 3,871' 3,934' 90' 8/14/1992 OPEN CI-3.0 4,804' 4,816' 3,949' 3,957' 12' 8/14/1992 ISOLATED CI-3.1 4,833' 4,848' 3,969' 3,980' 15' 8/14/1992 ISOLATED CI-4.0 4,855' 4,920' 3,985' 4,030' 65' 8/14/1992 ISOLATED CI-4.1 4,942' 4,952' 4,045' 4,052' 10' 8/14/1992 ISOLATED CI-5.0 4,985' 5,020' 4,075' 4,099' 35' 8/14/1992 ISOLATED CI-6.0 5,060' 5,085' 4,127' 4,144' 25' 8/14/1992 ISOLATED CI-7.0 5,137' 5,172' 4180' 4,204' 35' 8/14/1992 ISOLATED CI-7.1 5,187' 5,193' 4,215' 4219' 6' 8/14/1992 ISOLATED CI-8.0 5,232' 5,242' 4,246' 4,253' 10' 8/14/1992 ISOLATED CI-8.2 5,264' 5,289' 4,268' 4,285' 25' 8/14/1992 ISOLATED CI-9.0 5,332' 5,357' 4,315' 4,332' 25' 8/14/1992 ISOLATED CI-10.0 5,380' 5,395' 4,348' 4,358' 15' 8/14/1992 ISOLATED CI-11 5,416' 5,476' 4,372' 4,413' 60' 8/14/1992 ISOLATED 5,487' 5,488' 4,421' 4,422' 1' 3/28/1970 ISOLATED B-6 5,762' 5,768' 4,608' 4,613' 6' 8/29/1992 ISOLATED D-3 6,149' 6,154' 4,872' 4,876' 5' 8/29/1992 ISOLATED D-4 6,162' 6,187' 4,881' 4,898' 25' 8/29/1992 ISOLATED E-3 6,280' 6,285' 4,962' 4,965' 5' 8/29/1992 ISOLATED E-9 6,394' 6,414' 5,039' 5,053' 20' 8/29/1992 ISOLATED F-2 6,463' 6,478' 5,086' 5,096' 15' 8/29/1992 ISOLATED H-2 ISOLATED H-3 6,772' 6,842' 5,297' 5,345' 69' 8/29/1992 H-4 H-5 J-8 7,076' 7,098' 5,501' 5,516' 22' ISOLATED J-2 7,132' 7,142' 5,540' 5,547' 10' ISOLATED K-4&4.1 7,240' 7,270' 5,615' 5,635' 30' ISOLATED 1-2&1-3 7,312' 7,337' 5,665' 5,682' 25' ISOLATED M-2 7,379' 7,389' 5,712' 5,719' 10' ISOLATED M-9 7,539' 7,544' 5,824' 5,827' 5' ISOLATED M-11 7,581' 7,587' 5,853' 5,858' 6' ISOLATED N-3 7,691' 7,697' 5,930' 5,935' 6' ISOLATED N-4 7,724' 7,734' 5,954' 5,961' 10' ISOLATED A-09 Proposed 2017-07-12 Page 2 of 2 07/12/17 JLL 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-03P61 2,586,731.69 331,986.37 2,586,726.81 331,991.70 7.23 • ~~~Ep APR 0 ~ 200 J(o9 -C~~S~ REV DATE BY CK APP DESCRIPTION REV DATE BY CK P DESCRIPTION ~ 2/29/08 SA$ KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 o ~ ~ 36 31 T 12 N 31 32 ~f ~ ~~ ~a ~ 1 6 T II N e s N .w Ao N ,. ,o,s• ~ SEC. 6 1206' SCALE: I"-1320' -6- --- ~ ~ o ~ ~ 6 6 5 12 7 ~ 8 GENERAL NOTES: ~~~~ OF ,q~ ~\~, ~~~~~.~•~ 1. SEE SHEET 3 FOR COORDINATE TABLE i '`P:••''~~ ~~''gS~r~1 ~ • ' ~ • 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND ~ •° ~ ~j ~ ' ~ 'z • VERTICAL SURVEY DATA 49th ; ~j ~ ? 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED ~""''""""""""""""""""""6""' j VALUES. ~. ................................ .~ • ~• ~ '• KENNETH W. AYERS = moo; • t ~ ' ~ ~~ J' '.• LS-8535 •.' ~~= ~ SURVEYOR'S CERTIFICATE 1~,, A O ~ ~ ~~ „.....,,, R F ` P :. , I HEREBY CERTIFY THAT 1 AM PROPERLY REGISTERED AND 1~~~~ ~=~~~~ 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 & AssoctATES, INC. FEBRUARY 28, 2008. SURVEYORS ENGINEERS PWNNERS ~ PHONE: (907/ 272-5451 ~.~ AREA: MODULE: UNIT: ConocoPhilli s NORTH COOK INLET p TYONEK PLATFORM Alaska, Inc. WERE CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 ~g~~5 AS B~~T 1 of 3 1 REV DATE BY CK APP SCRIPTION REV DATE BY CK P DESCRIPTION 1 2/29/08 SAS K WA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 o & ~r T ~ ~s e ~ 9 ~ QQ9 Z~ '3 ? TYM R9 SO s. ro.u. `riS sca e y~ ~j ~O so `s SCALE: 1"=30' ga pp. O D 600 5 - ES 0 ESD 600-51 O •10 2 1 p • A8 A•A• B3 • •p5 A6• A3• AI2 BI b • • A4 • A2 WELL HOUSE 2 'p p • 2p A ~ LEGEND: ~ 3p AB • WELL p WELL CONDUCTOR 0 ESD (EMERGENCY SHUT OFF VAL VEJ GENERAL NOTES: 1. 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 ac assoctaTES, INC. AS BUILT SURVEYORS ENGINEERS PLANNERS V PHONE: 1907 272-5451 AREA: MODULE: UNIT: ConocoPhilli s NORTH C°OK 'NET TYONEK PLATFORM Alaska, Inc. WELD CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 08-005 P,S BUILT 2 of 3 1 1 ~ 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 ON ASP ZONE 4, NAD83, FEET NAD83 GE OGRAPHIC MLLW DESCRIPTION (POINT NO.) NORTHING FASTING LATITUDE LONGITUDE ELEVATION NqU WELL TAG NO. WELL HOUSE NO. 1 1001 2586492 1472018 61 04 34.38 150 57 03.71 72.0 Conductor 1 1002 2586489 1472017 61 04 34.34 150 57 03.72 73.9 B3 1003 2586485 1472019 61 04 34.31 150 57 03.67 74.1 A12 1004 2586485 1472023 61 04 34.31 150 57 03.59 73.8 B1 1005 2586487 1472027 61 04 34.33 150 57 03.52 72.0 Conductor 5 1006 2586491 1472027 61 04 34.37 150 57 03.52 73.7 B2 1007 2586495 1472025 61 04 34.41 150 57 03.57 72.1 Conductor 7 1008 2586495 1472021 61 04 34.41 150 57 03.65 73.7 A13 WELL HOUSE N0.2 2001 2586437 1472060 61 04 33.84 150 57 02.83 71.9 Conductor 1 2002 2586433 1472059 61 04 03.38 150 57 02.84 71.9 Conductor 2 2003 2586430 1472062 61 04 33.77 150 57 02.79 71.8 Conductor 3 2004 2586429 1472066 61 04 33.77 150 57 02.71 73.4 A9 2005 2586431 1472069 61 04 33.79 150 57 02.65 71.9 Conductor 5 2006 2586435 1472069 61 04 33.83 150 57 02.64 73.3 A10 2007 2586439 1472067 61 04 33.86 150 57 02.69 73.3 A11 2008 2586439 1472063 61 04 33.87 150 57 02.77 71.9 Conductor 8 WELL HOUSE N0.3 3001 2586488 1472128 61 04 34.36 150 57 01.47 73.0 Ai 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 NO. 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 I/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. & AssoclATES, Irrc. i ConocoPhilli s p Alaska, Inc. CADD FILE N0. DRAWING N0: 8-005 AS BUILT 02/27/08 AREA: SURVEYORS ENGINEERS PLANNERS ~ ~ PHONE: f907/ 272-5451 MODULE: UNIT: NORTH COOK INLET TYONEK PLATFORM WELL CONDUCTOR AS BUILT 08-005 AS BUNT PART: 3 OF 3 REV: 1 PHILLIPS PETROLEUM COMPANY KENAI, ALASKA 99611 DRAWER 66 PHONE: 907776-8166 NORTH AMERICA EXPLORATION AND PRODUCTION Kenai Area November 30, 1992 Ms. Leigh Griffin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Ms. Griffin: RE: North Cook Inlet Unit Well A-9 Post - Workover Sundry Report Form 10 - 404 Please find enclosed in duplicate the subject form, along with two copies each of the Daily Report Summary, thermal decay log prints, and thermal decay log sepias. Please direct any questions to our Mr. L. C. "Fritz" Krusen, Senior Production Engineering Specialist. Yours Sincerely, A.R. Lyons Kenai Region Manager ARL/LCK/dh Attachment RECEIVED DEC - 4 1992 Alaska Oil & Gas Cons. Comrnissio~ Anchorage ~ ? )A STATE OF ALASKA " AL, ..*, OILAND GAS CONSERVATION COMMI N REPORT OF SUNDRY WELL OPERATIONS 1. Operations peflormed: Operation shutdown __ Stimulate ~ Plugging __ edorate __ ~,~. Pulltubing ~ Alter casing __ Repair well ~ Other ~ ,r, 2. Name of Operator Phillips Petroleum Company 3. Address P. O. Box 1967,Houston, TX 77251-1967 5. Type of Well: Development __x Exploratory __ Stratigraphic __ Service __ 4. Location of well at surface Platform A Leg 1019.0 FWL Sec 6-TllN-R9W At top of productive interval 2624' FNL, 380' FEL Sec 1-11N-iOW At effective depth At total depth l132'FSL, 2692' FEL Sec 1-iiN-10W 2 Slot ~ 1310.6' FNL 6. Datum elevation (DF or KB) RKB 116 feet 7. Unit or Property name North Cook Inlet Unit J8. Wellnumber J~. Permit r~ber/approval number 50- 883-20029 11. Field/Pool 12. Present well cOndition summary Total depth: measured true vertical Effective depth: measured true vertical 8022 6148 feet Plugs(measured) Baker cast iron bridge plug @7057 feet Model K-1 retainer @7641 Bobcat Bridge Plug @7640 feet Junk(measured) feet 83' 3-1/2" tbg. @7666 Casing Length Size Cemented Measured depth True vertical depth Structural 30" Driven 386 386 Conductor 16" 14~sxSX tal±le~ 631 631 Surface 10-3/4" 610 sx lead 2587 2355 Intermediate 125 sx tail Production 7" 446 sx 7998 6131 Liner Perforation depth: measured 4247-7734 RECEIVED true vertical 3558-5963 DEC - 41992 Tubing (size. grade, and measured depth) 4-1/2" 12.75 PPF ,I-55 surface - 484~]aska OiJ & Gas Cons. 6om~ss~oi 3-vl//2~" 9.3 PPF J-55 4849-5215 Anchorage 2-.,,.," 6.5 PPF ,1-55 5215-6889 Packers and SSSV (type and measured depth) Ot±s BW'D_permanent packers at 6524, 5524, 5213, 5119, 4849. Otis TWR permanent packers@4791 & 4540; Otis VSR retrievable packers @4563 & ]3. Stimuiation or cement squeeze summary /41-5/; otis ball type SCSSV L~ZgU. Intervalstreated(measured) Cement squeezed 4247'-4400, acidized 7076-7581. 14. Treatment description including volumes used and final pressure Squeezed 4247-4400 w/350 sx class G to 2000psi. Acidized 7076-7587 w/2650 gal 7-1/2% HCl + 2650 ~al 7-1/2% HCl,0.5%HF, displaced w/nitr~ Representative Daily Average Produc~on or Injection Data gen, final pressure 2930. OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure - SI Prior to well operation 07-07-90 -- 17,200 14.1 685 1232 Subsequent to operation 10-02-92 -- 12,400 11.4 1231 1269 15. Attachments Copies of Logs and Surveys run Z.._ - TDT Daily Report of Well Operations 16. Status of well classification as: Oil __ Gas ~ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. SignedA.R. Lyons ~- ~ ~~---- Title Kenai Region Manager Form 10-404 Rev 06/15/88 Date /Z///'~2 3. SUBMIT IN DUPLICATE PHILLIPS PETROLEUM PAGE:i DAILYREPOR~ _SUMMARY FIELD:COOK INLET ~\L~-~v~ AFE#:P-V124 CNTY/STATE:TYONEKXAI~SI~ AUTH COST:$2,947,800 .o .. o. DEC - 4 1 92 E~TIONS SUMMARY DAILY COST CUM COST EVENT TYPE: Workover ~[~§~OFU~Sh~%~4~ Anchorage 07/17/92 8,022 1 8.4 RU FAA RIG 429 - DAYWORK OPERATIONS START 91200 07-i6-92 - $27,441 $27,441 RU OTIS & DOWELL - PULL DHSV - GUAGE RUNS - SET XX PLUG - PREPARE TEST PLUG 07/18/92 8,022 2 8.4 TEST XX PLUG & DHSV - SET BPV ND TREE SET BLANKING PLUG- $33,748 $61,189 NU RISERS & BOPE - LO~ER TEST SUB INTO HEAD - SUB BACKED OFF DRILLPIPE - ATTEMPT TO SCREW INTO SUB 07/19/92 8,022 3 PU STACK & RETRIEVE SUB - NU BOP STACK - ATTEMPT PRESSURE $29,808 $90,997 TEST - REPAIRING LEAKS & TESTING - 07/20/92 8,022 4 8.4 TEST BOPE - REPAIR HCR VALVE & TEST OK - ABANDON PLATFORM $43,343 $134,341 & BOP DRILLS - PULL BPV - OTIS PULL DHSV & XX PLUG - PU ON TBG. REL. PKR. W/TBG. STUCK BELOW PKR. - RU DIALOG TO FR. PT 07/21/92 8,022 5 8.4 PUMP PILL TO CONTROL FLUID LOSSES - CIRC. WELL - RU DIALOG $45,049 $179,390 RUN GR. - FREE PT. - MONITOR FLUID LOSSES ; PUMP PILL DOWN ANNULUS ; WELL STATIC - RUN STRING SHOT - RUN CHEM. CUTTER 07/22/92 8,022 6 8.4 CUT TBG AT 7208', UNABLE TO PULL CHEMICAL CUTTER, RU CUT & $36,158 $215,547 STRIP WIRE, PULL TBG, LOST WIRE THROUGH CLAMP, FELL IN TBG, LOST 35' TOOLS & 7160' WIRE IN WELL, POH W/ TBG 07/23/92 8,022' 7 8.4 FINISH LAY DOWN TBG / RUN SPEAR AND RECOVER WIRELINE AND $37,512 $253,059 TOOLS FROH WELL / PICK UP WASHPIPE, BHA AND DRILLPIPE 07/24/92 8,022 8 8.4 TRIP IN W / WASHPIPE TO 7200' - CIRC BOTT UP ' WASH OVER $44,022 $297,081 FISH TO 7484' ' CIRC BOTT UP - TRIP OUT WITH WASHPIPE 07/25/92 8,022 9 8.4 TOH W/WASHOVER PIPE'PICK UP OVERSHOT,JARS AND ACCEL'TIH'JAR $30,690 $327,771 ON FISH-MOVED 20' UPHOLE AND STUCK-UNLATCH FROH FISH-POOH- P/U AND M/U OUTSIDE CUTTER'TIH 07/26/92 8,022 10 8.4 FINISH TIH W/OUTSIDE CUTTER/CUT TUBING AT 7452.41'/POOH AND $27,175 $354,946 LAY DOWN FISH (RECOVERED 253') - PULL WEAR BUSHING - SET TEST PLUG - TEST BOPS AND RELATED EQUIPMENT PER PPCO SPECS 07/27/92 8,022 11 8.4 TEST BOPE, RIH W/ WP, WASH OVER FISH 7452 - 7694', POH $28,699 $383,645 TO PU/NEW WASH OVER SHOE / BEGIN WASHING OVER TAILPIPE AT 7694' 07/28/92 8,022 12 8.4 NO PROGRESS AT 7694', POH PU OUTSIDE CUTTER, TRIP IN $66,897 $450,542 AND CUT 3 1/2" TBG AT 7666', POH, LAY DOWN 214' FISH, PICK UP BIT AND SCRAPER, TIH 07/29/92 8,022 13 8.4 TIH W/BHA # 8 TO 7666'/ CIRCULATE BOTT UP AND SWEEP HOLE/ $65,366 $515,908 POOH /W BHA # 8 / RIG UP SWS FOR "E" LOGS / GAUGE RING RUN/ ULTRASONIC IMAGING LOG / SET K1 RETAINER AT 7641'/TIH W/BP 14 8.4 TIH/SET BP AT 4195'/TEST CSG TO 2000PSI/OK/TIH/SET BP AT 07/30/92 8,022 $33,776 $549,684 4521'/DROP SAND/POOH/PU 25 JTS TBG/TIH TO 4430'/SQUEEZE PERFS W/IOOSX W/ADDITIVES/WOC/POOH/TIH W/MILL/CMT TOP94210' 07/31/92 8,022 15 8.7 DRILL CHT TO 4270'/TEST SQUEEZE/NO TEST/RE-SQUEEZE PERFS AT $49,942 $599,626 4247' TO 4262' W/50 SX CLASS G W/ADDITIVES/WOC/POOH/TIH W/ MILL/TAG HARD CEMENT AT 3995'/DRILL CEMENT TO 4005' 08/01/92 8,022 16 8.5 DRILL CMT TO 4270'/CIRC & TEST PERFS'OK/DRILL CMT TO 4320' $31,740 $631,366 TEST PERFS AT 4284'-BROKE DOWN/DRILL CMT TO 4410'/CIRC/POOH SQUEEZE OPEN PERFORATIONS 4247' TO 4400'-WAIT ON CEMENT 08/02/92 8,022 17 8.6 WOC/POOH/TIH/DRILL CEMENT TO 4270'/TEST PERFS OK/DRILL CMT $53,903 $685,269 TO 4320'/TEST PERFS OK/DRILL TO 4410'/CIRC HOLE CLEAN 08/03/92 8,022 18 8.4 CIR/TEST PERFS/NO TEST/POOH/WEEKLY BOP TEST/TIH/SQUEEZE $36,857 $722,126 PERFS W/lO0 SX CLASS "G" W/AODITIVES/WOC/POOH W/ TAILPIPE/ CUT DRILL LINE/TIH W/ MILL/CMT AT 3943'/DRILL TO 3963'/WOC 08/04/92 8,022 19 8.4 DRILL OUT CMT TO 4507'/TEST SQUEEZED PERFS-OK/DISPLACE HOLE $29,153 $751,279 W/ SEA WATER/POOH/LAY DOWN 2.875" TBG & HNDLG EQUIP/PU AND MU RET TOOL FOR BOBCAT RET BP AND TIH 08/05/92 8,022 20 8.4 DISP. MUD SYSTEM W/2% KCL WTR.' SET RBP 95627'- PU DST TOOLS $46,403 $797,682 FAIL TO GO PAST 4340'- POOH CMT. ON PKR. - TIH W/MILL & CSG SCRAPPER WASH 4221'4545'-TIH TO RBP95627' CBU9 REPORT TIME 08/06/92 8,022 21 8.4 POOH W/MILL/TIH W/DST TOOLS FAIL TO GO PAST 4323-POOH & LD $45,476 $843,158 TIH W/6.2"MILL CLEAN CMT.4331-4424'/POOH/TIH W/DST TOOLS TO 4470/RU&TEST FLOW EQUIP./RU TO LOAD TBG. W/NITROGEN PHILLIPS PETROLEUM PAGE: 2 W~.L~.: ~orth Cook Inlet Unit No. ~%~~:~~COMPANY / 429 FIELD: COOK INLET AFE#: P-V124 CNTY/STATE:TYONEK~ALASKA DS0 - 4 ~ AUTH COST:$2,947,800 08/07/92 8,022 22 8.4 OPEN WELL TO FLOW TEST & EVALUA~I~i~i~LET SANDS/RU SCH- $31,160 $874,318 LUMBERGER & RUN PLT LOGS @ VARI130S"FLUg~RATES 08/08/92 8,022 23 8.4 SI WELL/RELEASE PKR. MOVE DOWNHOLE & RESET BELOW CI-1 /TO $65,164 $939,482 TEST CI-2 TO CI-11 /RU SCHLUMBERGER WL & RUN PLT LOG @ 3 FLOW RATES/ 08/09/92 8,022 24 8.4 RD WL LUB./RELEASE PKR. & LOWER TO RESET BELOW CI-2/SCHLUM $39,454 $978,935 WL RUN PLT LOGS a 3 FLOW RATES/SI FOR BUILDUP/POOH W/WL& RD RELEASE PKR./CIRC, OUT GAS/ 08/10/92 8,022 25 8.4 CIRC./RD TEST EQUIPMENT/TEST BOPE/UNLOAD 4.5" TBG. FROM $93,780 $1,072,715 WORKBOAT/TIH W/TEST TOOLS & 4.5"TBG./RU TEST EQUIP. & WIRE- LINE EQUIP. 08/11/92 8,022 26 8.4 TEST SURFACE EQUIP./SET PKR./FLOW TEST LOWER CI-4 TO CI-11 $77,512 $1,150,227 & LOG W/PLT /POOH CHG. TOOLS TO TDT LOG/ TIH & LOGGING REPORT TIME 08/12/92 8,022 27 8.4 TDT LOG- CI-1 TO CI-11/PU 2"PERF. GUN/REPERF. LOWER CI-8/ $63,747 $1,213,974 POOH W/GUN STUCK IN DST JARS/PULL OUT OF ROPESOCKET/RD WL & TESTERS/CBU/POOH W/TOOLS/PERF. GUN LOST IN HOLE/TIH W/DP 08/13/92 8,022 28 8.4 CBU @4970/POOH/TIH W/FISHING TOOLS/ENGAGE FISH/POOH W/TOTAL $39,143 $1,253,117 RECOVERY/RU WL TO REPERFORATE COOK INLET ZONES/PERFORATING/ 08/14/92 8,022 29 8.4 PERFORATING SELECTED COOK INLET ZONES W/WL CASING GUNS $67,322 $1,320,439 08/15/92 8,022 30 8.4 FINISH PERFORATING/RD WL/PU DST TOOLS,4.5" TBG.,& 3.5" DP/ $67,083 $1,387,522 RU TEST TREE,WL LUBRICATOR, & TEST MANIFOLD TEST TO 1500/ OPEN WELL TO TEST @REPORT TIME 08/16/92 8,022 31 8.4 OPEN WELL TO FLOW TEST & EVALUATE COOK INLET ZONES/ RUN PLT $64,137 $1,451,659 LOGS, RU COIL TBG UNIT, TEST COIL TBG./BOTH TIW VALVES LEAK ON TBG./ORDER NEW VALVES 08/17/92 8,022 32 8.4 KILL WELL, RU COIL TBG INJECTOR HEAD, JET WELL AND FLOW TEST $78,048 $1,529,708 SI WELL/TIH & JET WELL TO CHECK FL/POOH/RD & OFFLOAD COIL TBG./RU WL & TEST EQUIP./TIH W/PLT LOGGING TOOL/ 08/18/92 8,022 33 8.4 SCHLUMBERGER RUN PLT LOGS/POOH W/WL /MOVE PKR. BELOW ti-2/ $75,054 $1,604,762 OPEN WELL FOR CLEANUP/SI WELL/RU WL FOR PLT LOGS/ 08/19/92 8,022 34 8.4 SCHLUMBERGER gL RUN PLT LOGS @ 3 FLOW RATES/SI, POOH WI gL, $64,400 $1,669,161 MOVE PKR BELOW UPPER C-4, OPEN WELL FOR CLEANUP, SHUT IN, R/U LUB./RUN SHUT IN PLT/OPEN AND FLOW FOR STABILIZATION 08/20/92 8,022 35 8.4 PLT LOGS AND GAS RATES ON ZONES FROM 4942' TO 5476' - MOVE $65,196 $1,734,357 TEST STRING DOWN TO 5363' - PLT LOGS AND GAS RATES ON ZONES FROM 5380' TO 5476' 08/21/92 8,022 36 8.4 COMPLETE DST # 8 AND ASSOCIATED PLT LOGS - KILL WELL - POOH $44,202 $1,778,559 WITH TEST TOOLS - WEEKLY TEST OF BOPS AND ASSOCIATED EQUIPMENT 08/22/92 8,022 37 8.4 PU & MU RET TOOL/TIH TO 5823'/WASH TO 5834'/COULD NOT LATCH $43,426 $1,821,985 RBP/POOH/CHANGE BHA/TIH/WASH OUT BRIDGE/LATCH TOOL/TIH TO 7~'/CIRC BOTT UP/ATTEMPT TO POOH W/RBP-NO SUCCESS I 08/23/92 8,022 38 8.4 SET RBP @7640 /TOH/PICK UP TOOLS FOR DST # 9 (BELUGA SAND) $147,500 $1,969,485 I TIH W/SAME/SET AT 6039 /TESTING BELUGA SAND FROM 6149' TO 7587'/WELL STILL CLEANING UP 08/24/92 8,022 39 8.4 DST #9 ON BELUGA SAND - FLOW FOR CLEANUP - SHUT IN AND RUN $41,176 $2,010,661 PLT LOG PASSES - OPEN WELL ON 37.5/64" CHOKE (2ND FLOW) FOR PLT LOG - 08/25/92 8,022 40 8.4 COMPLETE DST # 9/PICK UP TUBING AND SET PKR AT ~96' TO TEST $44,814 $2,055,475 LOWER BELUGA ZONES/OPEN WELL AND BEGIN TEST OF BELUGA PERFS FROM 6772' TO 7587' 08/26/92 8,022 41 8.4 DST #10 ON BELUGA SAND - CLEANUP FLOW - R/U PLT LOGGING $51,522 $2,106,997 EQUIP AND LUB/RIH W/SAME ANO PLT LOGGING ON LOW RATE - MED RATE AND HIGH RATE FLOW/SHUT IN FOR BUILDUP 08/27/92 8,022 42 8.4 POOH W/WL TOOLS/CLOSE TOOLS/UNSEAT PKR AND MOVE TO 6978'/ $71,813 $2,178,809 DST # 11/KILL WELL/POOH W/TEST TOOLS/PICK UP BIT AND SCRAPER ANO TRIP IN HOLE ! 08/28/92 8,022 43 8.4 CLEAN OUT TO RBP AT 7639 /POOH/PU TBG CONVEYED GUNS AND TIH $49,009 $2,227,818 CORRELATE AND PLACE GUNS TO REPERFORATE BELUGA SAND/ADD 2% KCL H20 TO TUBING FOR A WATER CUSHION PHILLIPS PETROLEUM DAILY REPORT SUMMARY WELL: ~orth Cook Inlet Unit No. A-09 RIG:POOL COMPANY FIELD: COOK INLET CNTY/STATE: TYONEK%ALASKA PAGE:3 / 429 AFE#:P-V124 AUTH COST:$2,947,800 DATE DEPTH RPT NO MW OPERATIONS SUMMARY DAILY COST CUM COST 08/29/92 8,022 44 8.4 TEST LINES/PERFORATE BELUGA SAND/FLCR4 FOR CLEANUP/KILL WELL/ $175,861 $2,403,679 POOH/LD TEST TOOLS AND GUNS/WEEKLY BOP TEST/PU TEST TOOLS FOR DST # 12/CUT DRILL LINE/TRIP IN HOLE FOR DST # 12 08/30/92 8,022 45 8.4 TIH W/DST # 12 TOOLS/SET PKR AT 6985'/TEST LINES/DST # 12/ $29,845 $2,433,524 MOVE PACKER UPHOLE TO 557~'/TEST LINES/DST # 13/CLEAN UP RU WL/TEST LUB/RUN SHUT IN PLT PASSES 08/31/92 8,022 46 8.4 FINISH DST # 13 - MOVING PACKER TO 6696' FOR DST # 14 - $55,695 $2,489,219 EXCESSIVE GAS IN ANNULUS AT BOTTOMS UP-SHUT IN ANO DISPLACE GAS FROM ANNULUS 09/01/92 8,022 47 8.4 DISPLACE REMAINING GAS FROM ANNULUS - TIH - SET TEST $33,580 $2,522,799 PACKER AT 6702' - DST # 14 09/02/92 8,022 48 8.4 CLEANUP FLCR4/REPAIR TEST EQUIPMENT/RUN WL TOOLS TAG SAND $34,717 $2,557,516 FILL @7262'/POOH RD WL/REL. PKR./CIRC. OUT 'GAS/POOH W/DST TOOLS/TIH W/MILL & SCRAPPER TO CLEAN OUT FILL/ 09/03/92 8,022 49 8.4 TIH TO SAND FILL/WASH TO 7640'/CBU & DISPLACE HOLE W/CLEAN $101,493 $2,659,008 FLUID/POOH/TIH W/DST TOOLS/TEST LINES/SET PKR/ACIDIZE / ATTEMPT FLCR4 & FAIL/RU BJ PUMP NITROGEN/ATTEMPT FLOW TEST 09/04/92 8,022 50 8.4 ATTEMPT FLOW WELL/TIH W/WL DETERMINE FLUID & SAND LEVEL/RD $86,712 $2,745,720 WL/POOH W/DST TOOLS/WEEKLY BOPE TEST/TIH W/DST TOOLS 10 STDS DISCOVER FLUID IN TBG./POOH FIND MIRV OPEN/CLOSE TOOL & TIH 09/05/92 8,022 51 8.4 TIH & SET RBP/FAIL TO RELEASE OFF RBP/ RELEASE RBP & POOH/ $48,396 $2,794,116 TIH & SET RBP W/DP/POOH W/SETTING TOOL/TIH W/DST TOOLS/RU TEST EQUIP./SET PKR./CLEANUP FLOW LOWER CI4 TO CI-8/ 09/06/92 8,022 52 8.4 PLT LOG ti-4 TO CI-8/POOH & RD WL/CYCLE MFE CLOSED/RD TEST $61,263 $2,855,379 TREE & MANIFOLD/REL.PKR./LOWER PKR. TO TEST C1-7 TO CI-8/ OPEN MFE & FLOW FOR CLEANUP/ 09/07/92 8,022 53 8.4 FLOW TEST CI-7 TO CI-8/RUN PLT LOGS/POOH RD WL/RELEASE PKR. $68,367 $2,923,745 CIRC. WELL/POOH LD DST TOOLS/ TIH W/RET. TOOL/RELEASE RBP CIRC. OUT GAS/TIH TO 7045'/CBU, 09/08/92 8,022 54 8.4 CBU/POOH W/RBP/TIH W/CIBP & SET @7057'/CIRC. WELL g/NEW $82,837 $3,006,583 FLUID/POOH W/SETTING TOOL/RU TONGS/PU PROD. ASSY. & PKR./ TIH ON DP/RU SCHLUMBERGER TO CORRELATE PKR./SET PKR./POOH 09/09/92 8,022 55 8.4 POOH W/SETTING TOOL/PU ASSY. & PKR.#2/TIH &CORRELATE W/WL $50,858 $3,057,441 POOH W/WL/SET PKR/POOH W/SETTING TOOL/PU ASSY.& PKR.#3/TIH STING INTO PKR #2/SET PKR.#3/CUT DRLG. LINE/POOH/PU ASSY.#4 09/10/92 8,022 56 8.4 TIH W/ASSY.#4 & SET PKR./POOH W/SETTING TOOL/TIH W/ASSY.#5 $38,882 $3,096,323 CORRELATE PKR. SETTING/RD WL/SET PKR.#5/POOH W/SETTING TOOL/ TIH W/ASSY.#6 & SET PKR./POOH W/SETTING TOOL/ 09/11/92 8,022 57 8.4 POOH W/SETTING TOOL/TIH W/ASSY.#7/LATCH INTO PKR. #6 @4792' $38,910 $3,135,233 WELL CIRC. AFTER LATCHED IN/ATTEMPT TO RELEASE RATCHLATCH FAILED/POOH W/SETTOOL /ORDER PERM.PKR./TEST BOPE/TIH W/PKR. 09/12/92 8,022 58 8.5 STING INTO RET PKR & SET PERM. PKR. a4540/POOH/PU PKR.~9 $39,030 $3,174,262 STING IN PERM PKR@4540'& SET RET PKR@4137/POOH/PU SEAL ASSY. & 4.5"TBG./LAND TBG/SPACE OUT/REPAIR LOCKDOWN PINS/DISP. ANN 09/13/92 8,022 59 8.5 DISP. ANNULUS W/PKR.FLUID/PRES.TEST HGR.1500#/OTIS SET PLUG& $225,021 $3,399,283 SSSV/TEST PLUG & SSSV 1500#/RD WL/SET BPV/ND BOP & RISER/ NU XMAS TREE/TEST OK/PULL BPV/RU OTIS TO PULL SSSV & XX PLUG 09/14/92 8,022 60 PULL XX PLUG-SSSV-SET BLANKING SLEEVE/RU COIL TBG & NITROGEN $48,799 $3,448,082 TIH dET TO 5170/WELL FLC~/ING/POOH RD COIL TBG./FLC~/ WELL TO CLEAN UP/WELL MAKING DRLG. MUD IN SAMPLES/ 09/15/92 8,022 61 CLEANUP FLC~d WELL/SI WELL/RU OTIS PULL BLANKING SLEEVE/SET $34,415 $3,482,497 SSSV/TEST OK/RD OTIS WL/SI WELL/RELEASE RIG/SKID TO A-1 09/16/92 8,022 62 $113,802 $3,596,299 OAYSUM.RPl 10/29/92 ECEIVED DEC - 4 !992 A~aska Oil & Gas Co~'~s. Anchorage MEMORA I M stale of Alaska GAS CONSERVATION COMMISSION TO: .............. ~,-~Ila~ze. Johnston_z/.- Commiss loner-'~ THRU: Blair E Woddzell P.I. supervisor ~-T6u Grimaldi Petr Inspector DATE: FILE NO: TELEPHONE NO: SUBJECT: 8-9-1992 lg817-1, doc B,O.P, TEST, Tyonek Pool rig t~429 Phillips #A-9 N. C.I .U. workover FROM: Sunday 8-9-1992 I travelled to Phillip's Tyonek platform to witness the weekly B,O.P. test on Grace rig ~429 which is presently working over well %A-9 Ken Meyers (Phillips rep.) conducted a good B.O.P. test and all equipment I observed functioned good and held its pressure test. At Ken Meyer's request, I looked over the B.O.P.E. in anticipation of when the rig goes under 10,000 P.S.I. requirements, I found all equipment well constructed and of the proper pressure rating. The Tyonek.platform is small and with the Pool rig onboar~ access is diffic~t-but there was evidence of new walkways being constructed and I was assured that shortly these would be completed with some deck space being freed up when the welding crew is released. In summary, the B.O.P. test I witnessed on Pool rig 4~429 went well wit~ no failures observed. Attachment 02-00lA (]Rev. 6/89) 20/11/MEMO1.PM3 OPERATION: Drlg . Wkvr Operator / l P5 Drlg contrctr p csg set @ Location (general) Housekeeping (general STATE OF. ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION BOP Test Report TEST: Initial__ Rep /~ AJ~ ~t4v~/~ S ft Well sign Rig. MUD SYSTEMS: Vi~ Audio Trip tank ) ~---- Pit gauge ~ I ~ mo.i o I BOPE STACK: Annular preventer Pipe rams Blind rams Test Pressure Kill llne valves Check valve Weekly ~(~ Other Rig phone # Location: Sec ~ T ///t~ R 9~J M S/-~ ,, Rep ~>~~L~ (-__~.,~'~e~/ ACCUMULATOR SYSTEM: Full charge pressure \?C~(~ Press after closure // Pump incr clos press 200 psig Full charge press attained Controls: Master Remote&~>~ psig psig min ~0 sec Bin ~"C) sec psig ~-~ Blind switch cover KELLY AND FLOOR'SAFETY VALVES: Upper Kelly Lower Kelly Ball type Inside BOP Choke manifold Number valves Number flanges Adjustable chokes Hydraulically operated choke Test pressure Test pressure Test pressure Test pressure Test pressure ooc) TEST RESULTS: Failures ~[~ Test time ~// hfs Repair or replacement of failed equipment to be made within .. days. Notify the Inspector, and follow with written/FAXed [276-75~2] verification to Commission office. Di stri buti on: orig - AOGCC c - Operator c - Supervisor STATE WITNESS REQUIRED? I 24-HR NOTICE GIVEN? Waived by: C.004 (rev 03/92) May 12, 1992 PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 EXPLORATION AND PRODUCTION GROUP Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: North Cook Inlet Unit A-9 Workover Program COMPANY OR IGIN A BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING Attached are three copies of the Application for Sundry Approvals, form 10-403, and three copies of the detailed workover program for the workover of the A-9 well on the North Cook Inlet Unit. Included in the detailed program are BOP schematics and the workover fluid program. If you have any questions concerning this workover or need any additional information please contact Dennis Morgan at (713) 669-2173. Regards, D. C. Gill Drilling and Production Engineering Manager DCG:DRM/bcf CC: A. R. Lyons W. R. Gibson (r) D. R. Morgan Central files RECEIVED MAY 1 41992 Alaska 0il & Gas Cons. Com~tSs[o~ Anchorage AND GAS CONSERVATION COMM ION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend Time extension Change approved program 2. Name of Operator ....... phillips Petroleum CQmpany 3. Address P.0.Box 1967~ Houston~ TX 77251-1967 4. Location of well at surface Platform "A", Leg 2 Slot 4 1310.6' FNL, 1019.0 FWL Sec.6 - Operation Shutdown i ] Re-enter suspended well ~ Alter casing ~ Plugging ~ Stimulate :.] Pull tubing;~, Amend order .r Perforate E; Other 'f ~ 5, Datum elevation (DF or KB) RKB 116 6. Unit or Property name North Cook Inlet 7. Well number A-9 feet T ]A]t~ p~9oT~ p rod u ct ive interval 2624' FNL, 380' FEL Sec 1 - llN-10W At effective depth At total depth 1132' FSL, 2692' FEL Sec 1 -llN- 10W 8. Permit number 9. APl number 50-- ~83-20029 10. Pool 11. Present well condition summary Total depth: measured true vertical 8022 6148 feet Plugs (measured) feet Effective depth: measured true vertical feet Junk (measured) feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured Length true vertical Size 30" 16" 10-3/4" Cemented Driven 425 SKS lead,125 SKS Tail 610 SKS lead,125 SKS Tail 7" 446 SKS 4247'-7734' 3558'-5963' Measured depth 386' 631' 2587' ~ue Verticaldepth 386' 631' 2355' 7998' 6131' RECEIVEC Tubing (size, grade and measured depth) 4-1/2" 12.6 PPF 5-55 Surface - 1438' MAY 1 4 1992: 4" 10.9 PPF J-55 1438'-4165" Packers and SSSV (type and measured de~/2, 9.3 PPF J-55 4~65'-7749' Alaska 0il & Gas C0,$. Com~ Otis RH Packer @ 4203, Otis Ball Valve at 281' Anchorage 12.Attachments Description summary of proposal © Detailed operations program ~ BOP sketch 13. Estimated date for commencing operation June 15, 1992 14. If proposal was verbally approved Name of approver Date approved 15. I her,ep~/cer~)y thatjhe foregoing is true and correct to the best of my knowledge Signed~'~w~.~~;~_~~/~,.-~ Title D&P Engineering Manager Date Conditions of approval Approved by Commission Use Only Notify commission so representative may witness I Approval No. ~ Plug integrity [] BOP Test I~ Location clearanceI ,~,~--/,,~" ~pprovect Copy / 0 - .</z~ ~' /dd'~~ ~/~. ¢ 0 ORIGINAL SIGNED BY Returned LONNIE C. SMITH ~ by order of the commission Date Form 10-403 Rev 12-1-85 Submit in triplicate ~ PHILLIPS PETROi.RUM COMPANY NORTH AMERICA E & P DRILLING OPERATIONS THIS IS NOT A TIGHT HOLE WELL: NCIU A-9 COUNTY, STATE: Tyonek, Ak. FIELD: North Cook Inlet Unit AREA: Kenai SURFACE LOCATION: Leg 2 Slot 4 PROJECT SPONSOR: L.C. Krusen 1311' FNL, 1019' FWL Sec 6-T11N-RgW J.J. Voelker BoI'rOMHOLE LOCATION: 1132' FSL, 2692' FEL SEC 1-T11N-R10W AFE: P-V124 PARTNERS, W.I.: Phillips 100% BUDGET ITEM: 2C GROSS AUTHORIZATION: $1,706,300 OBJECTIVE: Shut off intervals producing water and/or sand, reperforate and/or stimulate unproductive intervals and isolate Cook Inlet and Beluga sands. Original (X) Supplement ( ) Revision ( ) APPROVED IN QUAUTY PLANNING COMMITTEE: ,,I;~nuarv 30. 1992 DRILLING ENGINEER DRILLING ENGINEERING DIRECTOR DRILUNG SUPERINTENDENT D & P ENGINEERING MANAGER DISTRIBUTION: M.L. Jones W.R. Gibson (r) C. A. Boykin W.I_ Carrico Development Supervisor (2) A.R. Lyons (r) L.C. Krusen D.R. Morgan D.C. Gill H.J. Robinson (r) J.J. Voelker J.E. Stark (r) B.W. Baird A.I_ Sorrels Central Files vcu MAY 1 4 1992_ Alaska Oil & 6as Cons. Commission Anchorage NCIU A-9 WORKOVER PROCEDURE A® Be Ce De Eo Fe G® He I · J· Ko L· M· N· O· INDEX OF PROCEDURES APPROVALS AND INDEX GENERAL COMMENTS, WORKOVER OBJECTIVES AND WELL HISTORY WORKOVER PROCEDURE A. ESTABLISH BARRIERS, INSTALL BOPS AND KILL WELL B. PULL EXISTING COMPLETION C. IDENTIFY AND SHUT OFF WATER PRODUCING INTERVALS D. TEST COOK INLET SANDS E. TEST BELUGA SANDS F. RUN NEW COMPLETION WELL CONTROL PROCEDURES WORKOVER/COMPLETION FLUID PROGRAM FISHING PROGRAM TEST PROCEDURES A. COOK INLET STRAY, A, AND B SANDS B. COOK INLET SANDS i THROUGH 11 C. BELUGA SANDS D. TEST TO DETERMINE SOURCE OF WATER PRODUCTION SQUEEZE PROCEDURES A. COOK INLET STRAY, A, AND B. B. ANY OTHER INTERVALS STIMULATION PROCEDURES COMPLETION PROCEDURE SIMULTANEOUS ACTIVITIES GUIDELINES DIRECTIONAL SURVEY CURRENT WELI2{EAD AND CHRISTMAS TREE DETAIL PROPOSED WELLHEAD AND CHRISTMAS TREE DETAIL CURRENT COMPLETION SCHEMATIC RECEIVED MAY I 4 199~ Alaska 0tt & Gas Cons. Commission Anchorage NCIU A-9 WORKOVER PROCEDURE Pe Q® PROPOSED COMPLETION SCHEMATICS PORE PRESSURE PLOTS BOP AND RISER HOOK UP S. VENDOR LISTS T. PHONE LISTS RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage ~LL H~STORY RECEIVED MAY 1 ~ 1992 Alaska Oil & Gas Cons. C~mmissio~ Anchorage GENERAL COMMENTS While the workover is in progress the Drilling Supervisor has overall responsibility for the workover activity. The Lead Operator has responsibility for the production activities and routine operation of the platform. The Drilling Supervisor and' Lead Operator are expected to maintain close communications. In the event of an emergency the Drilling Supervisor is designated "Person in Charge". Safety is the top priority in conducting this workover program. Production from the other 11 wells on the platform will continue throughout the course of the workover. This will result in simultaneous activites on the platform. These activities will be performed following the procedures found in the North Cook Inlet Unit, Platform A, Standard Procedure Guidelines for Simultaneous Activities. A copy of the Standard Procedure Guidelines for Simultaneous Activities is included as section K of this program. There may be occasions when the adjacent wells (10 and 11) will need to be shut in to continue with the workovers. This could occur for such activites as nippling up and down the X-mas tree and risers, or welding on the new flowline. This work can be planned for in advance so that the impact on production is minimal. When this situation arises, the wells should be shut in and the workover activity should proceed. However, if the wells are require4 to meet the deliverability requirements of the plant then the workover activity should wait until such time as the wells can be shut in. The deliver]~ requirements of the plant are more important than the workover. To minimize the potential for lost rig time due to conflicts with the production operations, close communication between the Phillips Drilling Supervisor and the Platform Lead Operator will be required. This workover is intended to shut off a water and sand producing interval and to answer several reservoir questions. The procedure, particularly with regard to restoring production from intervals that are not producing, will be subject to change based on the results observed. WORKOVER OBJECTIVES: 1. Identify and shut off intervals producing water and/or sand. R£C£1V£D Alaska Oil & Gas Cons. · · e · · · Test Cook Inlet sand to confirm all zones that should be producing are producing and to gather reservoir date to refine the reservoir model. Reperforate/Stimulate any Cook Inlet sands not producing. Test Beluga sands to confirm all zones that should be producing are producing and to gather reservoir date to refine the reservoir model. Reperforate/Stimulate Beluga intervals not producing. Run completion with multiple packers for proper zone isolation. Begin producing well, initially from Beluga adding Cook Inlet when needed. WELL HISTORY AND CURRENT CONDITION: The well was drilled in 1968 and completed as a commingled Cook Inlet and Beluga producer in 1975. The well was completed with an Otis RH retrievable packer set at 4203 and tailpipe extending to 7749'. A schematic drawing and detailed description of the current completion is shown in section O. All 14 of the Cook Inlet sands and 15 intervals in the Middle and Lower Beluga are perforated. A plot of the current pore pressure vs depth is shown in section Q. Note that the pressure gradient decreases from about 8.3 ppg in the Cook Inlet B sand to about 5.4 ppg in the Cook Inlet 11 sand and then increases to about 7.5 ppg in the Middle and Lower Beluga. There are three intervals in the Upper Beluga that have been identified as pay but have not been perforated. These intervals may be perforated during the course of this work·vet. These intervals may be at virgin reservoir conditions. Virgin reservoir pressure in the Beluga was 9.9 ppg EMW. The well is equipped with an FMC-OCT wellhead and X-mas tree. A drawing of the tree is shown in section M. Back pressure valves, test plugs, wear bushings and any required wellhead service will be supplied by FMC. This well began producing significant volumes of water and sand in 1990 and has been shut in as the result· The water and sand are believed to come from the Cook Inlet B sand· This interval will be abandoned during the course of the workover. Production logs have been run and have detected sand inside the tubing at 7450'· The top of sand outside the tubing is unknown. In the worst case it could be as high as the Cook Inlet B perforations· R E C E IV E D Alaska Oil & Gas Cons. Gom, mssior' The sands in this well are highly.permeable. A small reduction in the pressure at the perforations can result in very high flowrates. Be sure that all personnel are aware of this and understand the importance of following good well control practices. Crews should be alert for any indications of flow and prepared to shut in the well and circulate through, the choke at any time. RECEIVED MAY 1 z] 199~ Alaska Oil & Gas Cons. (jommissio~. Andmrage SECTION C WORKOVER PROCEDURE RECEIVED ~A¥ 1 ,~ 1992_ Alaska 0tl & {~as Cons. Commission Anchorage PROCEDURE Establish barriers, install BOPs and kill well= Wells are category three, 2 tested barriers are required to ND tree. Al. RU wireline lubricator and test to 1500 psi. A2. Run TDT log. A3. Pull DHSV. A4. Install plug in profile above XA sleeve at 4166'. A5. Bleed off pressure to test plug from below. A6. Load well with filtered KCL water, see workover fluid section E for kill fluid recipe. Note: The fluid column does not qualify as a second tested barrier. The density of the fluid cloumn is adequate, however the volume of fluid is insufficient to contain the well. The fluid column is needed to facilitate testing of the DHSV. A7. Install DHSV. AS. Test the DHSV using the volume measurement method as follows: A. With the valve DHSV open, pressure up on the tubing to 2000 psi. B. Bleed off the pressure carefully measuring the volume bled back. C. Pressure up the tubing to 2000 psi a second time, then close the DHSV while holding the pressure on the tubing. D. After the valve is closed, bleed off the pressure carefully measuring the volume. If the DHSV is holding, the volume bled back should be about 10% of the volume measured in step B. Contingency Plan: If the DHSV will not set or will not test a blanking plug can be set in the DHSV nipple. In this event remove the faulty DHSV then pressure up, bleed back and pressure up as outlined in steps A B and C. Then run the blanking plug in while holding the 2000 psi on the well. Set the plug in the nipp~l~,ap~%l~d back as in step D. KtttlVtU A9. Install BPV MAY 1 ~ 199~ Al0. Skid rig over'well. Ail. ND tree. Note: Tree should be sent to FMC for inspection, repair, and addition of a second master valve. Al2. NU and test riser and BOP to 3000 psi. See the well control section of this procedure for additional details concerning BOP tests and well control requirements. Al3. Retrieve BPV, DHSV, and deep plug. Al4. Kill well with kill fluid. Sized salt pills are recommended if needed for fluid loss control. Note: See attached workover/completion fluid, section E, for additional details and contingency plans for workover fluids. Al5. After well is dead and standing full of the workover fluid, attempt to open the XA sleeve at 4166'. After the sleeve is open circulate out the packer fluid and displace the annulus to workover fluid, then close the sleeve. Pull existinq completion, clean out to TD: B1. Screw DP into tubing hanger and pull on DP to release Otis RH packer. Limit pull to 170,000 lbs hookload. The Otis RH packer is a pull to release packer, rotation is not needed. Note: Be prepared for gas bubbles anytime, but especially when a packer is released or any perforations are exposed to the wellbore as sand is circulated out. B2. If pipe does not come free, see attached fishing program for additional details on fishing for packer and tailpipe. B3. If pipe does come free circulate at least one full hole volume before POOH. Be prepared to shut well in and circulate through choke as there may be significant volumes of gas trapped below the packer. B4. POOH w/tubing, packer and tailpipe. Pull slow to avoid any tendency to swab. Note: Tubing is to be checked for NORM contamination Note: A detailed description of the completion equipment presently in this well is found in section O. The tubing in the well includes 4 1/2", 4" and 3 1/2" as well as several blast joints and other tools. Have handling tools available to cover ~l~4~hF¥gC~zes of tubing in the well. 3 NIAY 1 j 1992 Alaska Oil & Gas Cons. commission Anchorage B5. After all tubing has been recovered, RIH w/ 6" bit and clean out to PBTD at 7950'. Note: Expect to circulate out significant volumes of sand. The sand can be disposed of overboard unless it contains oil or other contaminants that would violate the terms of the NPDES permit. Collect samples of the sand and check for any material that would prevent discharging the sand overboard. If the sand is contaminated then it will be collected and transported ashore for disposal. Identify and shut off water/sand producing zones. Test 1: Most likely water/sand source - Cook Inlet B sand Cl. Run cement evaluation and casing inspection logs. Note: These logs are to determine if behind pipe communication exists and to determine the condition of the casing. C2. RIH w/ Schlumberger Bobcat Retrievable Bridge Plug (RBP) and set at + 4100'. C3. Test casing to 2000 psi. C4. Move RBP to 4500'. The RBP should be between CI B sand and CI 1 sand. Dump sand on top of RBP. C5. Displace well w/ test fluid. C6. RIH w/ test tools and test CI Stray, A and B sands. See the detailed test procedures, section G. Note: The CI B sand is the zone believed to be the major water/sand producer in the well. This test is to confirm this belief. C7. POOH w/ test tools C8. RIH and squeeze perfs in CI Stray, A and B sands. See attached squeeze procedures, section H. Note: NCIU A-9: Stray, A & B, 153' gross, 105' net, C9. Drill out cement and test perfs to 2000 psi. Resqueeze as - necessary. RECEIVED 1 a 1992 Oil & Gas Cons. Gom~s~J~ Anchorage 'Test 2: Cook Inlet Interval D1. Move RBP to between Cook Inlet and Beluga, RBP should be set at + 5600'. D2. RIHw/ test tools. See the detailed test procedure, section G. D3. Test Cook Inlet interval. At least 2 flOwing passes will be made with PLT tools at different rates. One rate should be high enough to produce large enough drawdown for all CI sands to be producing. (Surface equipment will be designed for 20 MMCFD rates.) D4. If test produces significant volumes of water, the water source will be isolated and shut off. If test shows some intervals are not producing they will be reperforated and the test repeated. If the interval still does not produce it will be isolated and tested alone and stimulated if necessary. Beluga Test: performed last to minimize time spent with kill fluid across Beluga before production begins. El. Move RBP to below bottom Beluga perforation. Set RBP at ± 7900'. E2. RIH w/ test tools. See the detailed test procedure, section G. E3. Test Beluga interval. At least 2 flowing passes will be made with PLT tools at different rates. One rate should be high enough to produce large enough drawdown for all Beluga intervals to be producing. (Surface equipment will be designed for 20 MMCFD rates.) E4. If PLT shows fluid covering any Beluga perle. RIH w/ coiled tubing and use nitrogen lift water out of well. E5. If test produces significant volumes of water, the water source will be isolated and shut off. If test shows some intervals are not producing they will be reperforated and the test repeated. If an interval still does not produce it will be isolated and tested alone and stimulated if necessary. E6. After all work to restore Beluga production is complete, a single layer in the Beluga will be tested to provide deliverability data. The reservoir engineer on location will determine which interval to test. Kill the well and move the RBP to below the interval to be tested. E7. RIH w/ test tools to conduct buildup and drawdown tests of the Beluga interval. Test as required. R E C E IV E D MAY 1 4 1992 Alaska 011 & Gas Cons. Commission Anchorage ES. Kill well, displace to completion fluid and POOH with test tools and RBP. Run new completion - See detailed completion procedure, section J. Fl. RIH w/ subassembly 1, shown in section P, including 2 7/8,' tailpipe, profile nipples, blast joints, sliding sleeves and permanent packer. Set packer to isolate Beluga from CI. F2. Jet in Beluga to minimize time spent with any completion fluid across Beluga. F3. Set plug in .XN nipple in 2 7/8" tailpipe. Bleed off pressure and load well with completion fluid. F4. Run subassemblies 2 through 7 as per section J. Note: Final completion design is subject to change depending on results of CI tests and on cement quality, however preliminary design is shown in the schematics. Note that in order to obtain the desired zone isolation several packers are needed. Ail sliding sleeves to be run in the closed position. F5. Run subassembly 8. Prior to latching seal assembly into packer reverse circulate to displace well with packer fluid. F6. Set and test DHSV, set BPV. F7. ND BOP, NU tree. Connect flowlines. Since an extra master valve is being added, new flowlines will be needed. Note: Tested barriers will include the completion fluid currently in well and the DHSV. The plug in the XN nipple of the 2 7/8" also qualifies as a tested barrier for the Beluga interval. Untested barriers would include the closed sliding sleeves in combination with the production packers and the back pressure valve. FS. Retrieve BPV, and the DHSV. Fg. RIH w/ coiled tubing and displace completion fluid with nitrogen. Fl0. Recover plug from 2 7/8" tailpipe. If the plug cannot be retrieved the 2 7/8-" tailpipe will be perforated above the plug. Fll. Install and test DHSV. F12. Turn well to production, initially producing from Beluga. Production will open sliding sleeves to produce Cook Inlet sands as they feel necessary. RECEIVED 6 MAY I ~ 1992 Alaska Oil & Gas Cons. Commissior~ Anchorage SECTION D WELL CONTROL PROCEDURES RECEIVED MAY 1 ~ 1992 Ala~ka Otl& G~s Cons Commissiop- Anchmage Well Control This well is a category 3 well, as defined in Phillips Completion Workover and Well Control Policy. As such two testmd 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 3 1/2" 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 3000 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. 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. A large number of trips can be expected during the course of this workover. It is vital that good well control practices be followed during the course of these trips. 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. I~INTAINING CONTROL OF THE ~ELL IS OF THE UPMOST IMPORT~.NCEv TRIP SPEED IS SECOND~RY. - Ail of the producing sands, 29 different intervals between 3558' and 5963' TVD (4247' - 7734' MD), are commingled at the present time and cannot be isolated until the existing completion is removed. A plot of reservoir pressure, based on the RFT results from the Sunfish No. 1 and production logs ran in wells A-i, A-3 and A-7 is shown in section Q. Production logs have not been possible in A-9 due to its completion design. Note that the mud gradient varies from an 8.3 ppg equivalent in th~.C~o~9~B sand to a 5.4 ppg equivalent in the Cook Inlet 11 san ~et:~q~fl~sands will have a slightly higher pressure than the''C-ook Inlet sands 2 MAY ] ~ 1992 AlaskaOit&Gas~ns.(Am~missi°~ because of the water that has accumulated in the wellbore and inhibited flow from the Beluga. The variations in gradient will make it difficult to kill the well and could create well control problems throughout the workover, particularly if the lower pressured intervals are covere~ with sand. There is a probability that the lower pressured intervals will not support a fluid column adequate to control the higher pressured intervals without addition of a bridging agent to the workover fluid. A premixed pill designed to bridge off the lower pressured zones should be maintained in one of the mud pits until the well has been cleaned out to TD. If the well cannot be made to stand full, then well control can be maintained by constantly pumping workover fluid. Ail of the zones presently perforated in this well can be killed with water. As a precautionary measure, a line should be ran from the annulus valves on the tubing head to supply workover fluid, drillwater, or seawater. This line can be used to supply workover fluid as discussed above or as a last resort can be used to kill the well with drillwater or seawater. Pumping drillwater or seawater through the annulus valves should be considered only in an emergency situation as these fluids could result in formation damage. RECEIVED MAY 1,~ 1992 Oil & Oas Cons..Commissior Anchorage SECTION E WORKOVER FLUID PRO~I~ RECEIVED MAY 1 4 '!99~ Alaska Oil & Gas Cons. Commission Anchorage 'Workover Fluid Program The base fluid for the workover is a NaCl/KCL brine containing 3% KCL and a 1:1 ratio of Sodium to Potassium. Fluid density will be 8.65 - 8.7 ppg. Kill fluid: This fluid will be used for the initial kill operations and will be used while cleaning out the existing completion and circulating out the sand that has accumulated in the wellbore. The initial 600 barrel volume of kill fluid should be built by mixing 585 barrels of fresh water with 5538 lbs, approximately 70 sacks (80 lbs/sack) of NaCl and 7062 lbs, approximately 71 sacks (100 lbs/sack) of KCl. After mixing check for total hardness. If calcium is greater than 100 ppm treat with soda ash. Fluid Properties: Weight: 8.65 - 8.7 ppg Total hardness: less than 100 ppm KCl concentration: 11.77 ppb NaCl concentration: 9.23 ppb Fresh water mixed with KCL and NaC1 as above or filtered inlet water can be used as additional volume is required. To use inlet water measure the'chlorides to determine the concentration of NaCl, then add NaCl as necessary to achieve the desired concentration and mix 11.77 ppb KCl. After adding salt, treat makeup volume with soda ash to remove calcium and magnesium. - For additional fluid loss control use pills of workover fluid containing 3 ppb Xanvis (XC polymer). The polymer should be hydrated and sheared properly to obtain the maximum iow shear theology. If additional fluid loss is required LCMpills of Litesal XCP pill will be used, The volume of the pill and the amount of bridgeing agent to be used will be determined based on the rate of loss. Saturate the system with LiteSal (borate salts) and add 2 - 3 ppb Liteplug fine to the circulating system. Then spot the LCM pill across the thief zone. Should additonal fluid loss control be needed for seepage control while working with the thief zones open, add 15 ppb LiteSal XCP and 5 ppb pH-6. This will viscosify the system to suspend additional bridging agent. Then add 5 - 10 ppb Liteplug if needed. RECEIVED 2 MAY 1 ,~ 1992 Alaska Oil & Gas Cons. Commission Anchorage Sweeps containing 3 PPB Xanvis should be used' as needed for hole cleaning while circulating out the sand. Screens on the shaker should be as fine as possible without blinding. Sand that is circulated out should be sampled to insure it complies with the NPDES permit and ,diposed of overboard. If the sand cannot be disharged overboard it will-be collected in bins and sent to shore for disposition. Test Fluid: Cook Inlet Stray, & and B test Test fluid is to be clean workover fluid. After setting the RBP at 4500', build the required volume of clean base workover fluid as was used for the initial kill fluid. Displace the well with the clean fluid and store the kill fluid either in the girder tanks or in the mud pits. Conduct the test of the Cook Inlet Stray, A, and B as required. Kill the well with clean workover fluid. This gradient in this interVal is expected to be about 8 ppg so fluid loss control is not expected to be a problem. If fluid loss control is needed use Xanvis pills. After test is complete continue using the fluid in the well to squeeze the Cook Inlet Stray, A and B, and to drill out the cement. Test Fluid: Cook Inlet 1 through 11 test After the RBP has been moved to 5600' dump the cement contaminated system and build a clean fluid with same composition as above. Displace the well with the clean fluid. If Xanvis or Litesal was needed for fluid loss control previously a polymer breaker will be needed to obtain a valid test. If this is the case spot a pill containing sodium hypochlorite across the Cook Inlet interval to be tested, i.e. from 5600' to 4500'. The concentration of sodium hypochlorite will vary from 1-2 55 gallon drums per 50 bbls of workover fluid dependent on the volume and composition of fluid lost in the well. Let this pill soak while POOH with the drillpipe and RIH with test tools. The pill will act to break the polymer required for fluid loss control and will be produced during the test. After the test is complete, fluid loss control may be needed in the kill fluid. If so use the kill fluid previously stored. RECEIVED ~l~,~ka Oii& Ge$ Cons. commiss%or Test Fluid= Beluga test. After the RBP has been moved to TD displace the well with clean fluid with same composition as above. Fluid loss control should not be required for the Beluga so the polymer breaker will not be needed. Likewise fluid loss control should not be needed to kill the Beluga. Completion fluid Continue using the Beluga test fluid as the completion fluid. After setting subassembly 1 and installing the plug in the XN nipple, it may be desirable to spot another sodium hypochlorite pill across the Cook Inlet' 1 through 11. This would be advised if fluid loss control was needed to kill the Cook Inlet interval after the Cook Inlet test was complete. If this is required, spot the pill across the Cook Inlet perforations and let it soak for 1-2 hours. Then displace the well with clean workover fluid and run subassemblies 2 through 7. Packer fluid. After RIH with subassembly 8 reverse circulate with packer fluid containing corrosion inhibitor. Leave 4 barrels of glycol in the top of the tubing X casing annulus to act as freeze protection. 'RECEIVED MAY 1 4 1992 Alaska 011 & Gas Cons. Commissio~ An~horag~ 8ECTZON F FZ8HZNG PROGI~3~ RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage Fishing Program This well produces sand and water, presumably from the Cook Inlet B sand at 4330 - 4400. Production logging tools have confirmed the 9resence of sand inside the tubing at 7450'. The amount of sand in the annulus is unknown. The sand could have accumulated to the top of the CI B perforations. There is a high probablity that the tailpipe will be stuck in the sand. If the tailpipe is stuck it will need to be cut before the packer can be released. The following outlines the steps to cut and pull the packer and tailpipe. A detailed description of the completion equipment presently in this well is found in section O. The tubing in the well includes 4 1/2", 4" and 3 1/2" as well as several blast joints and other tools. Have handling tools and fishing tools available to cover all three sizes of tubing and the completion tools found in the well. Assuming the initial attempt to pull the packer in step B1 has failed, proceed as follows, adjusting the procedure as needed based on the fish to be recovered: · Make one attempt to open the XO sleeve at 6867' to provide access to the annulus for circulating sand. · RIH with a chemical cutter and cut the tailpipe in the center of a pup joint of tubing immediately below the upper XO sleeve. The upper XO sleeve is at 4217' so the cut should be made at about 4230'. Use a CCL to insure the cut is made near the center of the joint. · Pull on DP to release to release Otis RH packer. Limit pull to 170,000 lbs hookload. · If packer is still stuck, rotate the tubing to the right and pull. This should release the Otis Sleeve Release Seal Divider (on-off tool). If the on-off tool does not release make another chemical cut in the joint of tubing above the packer. The cut should be made at about 4180' and near the center of the joint· 5. POOH and LD tubing. Note: Tubing is to be checked for NORM contamination. · RIH w/ overshot and jars to jar out packer. Latch onto fish and jar packer out of hole. · RIHw/overshot and latch onto fish, Overshot should release by right hand rotation. Make an attempt to pull or jar fish out of the well. 0 Run freepoint. Run string shot and back off tubing i joint above stuck point. 9. POOH and LD fish. 10. RIH with screw in sub and screw into fish. 11. Attempt to break circulation and wash out the sand. Communication to the annulus is possible through the XO sleeve at 6867' (assuming the sleeve'was not pulled out in step 9) or through the end of the tubing. If it is impossible to break circulation then the tubing may be perforated at an intermediate point between the top of fish and the nearest circulation point cr the decision may be made to washover the remainder of the fish. 12. Run a free'point and back off in the first connection above the stuck point. 13. After determining that further attempts to circulate out the sand would not be the most cost effective fishing method, the remainder of the fish will be recovered by washing over. RIH w/washpipe and begin to washover remainder of fish. Note that the fish could include 3 1/2" tubing, blast joints, and other completion tools. Take the varying diameters into account in selecting washover shoes and determining how much washpipe to run on each trip. R£C£1VrcD MAY 1 ~ ~992 Almslm ~ & Gas C~)s SECTION TEST PROCEDURES RECEIVED M~Y 1 ~ 1992, Alaska Oil & Ga~ Cons bc,~~qm~' Anchorage DRILL STEM TEST PROCEDURES These tests will follow the guidelines for conducting drill stem tests on bottom supported marine rigs found in Phillips Drill Stem Testing Manual. Bottomhole pressure is anticipated to be 1200 psi for each test. The produced fluid will be dry gas and possibly water and/or sand. Rig up surface equipment as shown on the attached schematic. The preferred location for the surface equipment will be located on the drill deck between wellrooms i and 2. The flare boom should be located on the NW corner of the platform near the existing process flare. If this proves to be impossible due to the rig pipe rack then the test equipment can be located on the drilldeck between well room 2 and 3. The test manifold should be piped to permit gas to flow either to the rental separator or to the platform test separator. This will allow the gas to be flared during clean up flows but sold during extended flow tests. The exact routing of the line to the test separator will be determined. Ail surface equipment upstream of the separator is to be rigged up and hydrostatically tested to 1500 psi. After the hydrostatic test is complete and any leaks repaired, retest using nitrogen or helium to 1500 psi. All piping is to be securely snubbed down. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. RECEIVED Alaska Oil & ~as Cons. Cmmmission Anchorage ~V NCIU WELL TESTS SURFACE EQUIPMENT TO BURNER BOOM TO PRODUCTION TEST SEPARATOR SEPARATOR SCRUBBER IJ LINE HEATER COOK INLET STRAY, A, AND B DST BEGIN TEST, FLOW WELL I YES NO STIMULATE ZONES NOT PRODUCING i END TEST YES ARE ALL PERFORATED INTERVAL8 PRODUCING AS EXPECTED? YE8 PERFORATE ZONES NOT PRODUCING W/ THRU TUBING GUNS I ARE ALL PERFORATED IN TERra',L8 PRODUCING AS EXPECTED? RECEIVED MAY 1 4 1992 Alaska ~ & r~as.C0ns. COOK TNLET STI~Y· A· ~ B Test Objective: Verify interval produces water and sand Procedure: ® Displace well with test fluid, see workover fluid section E for test fluid recipe. · RIH w/ DST tools as shown on the attached schematic. The PCT valve should be run in the closed position so that the pipe is dry. · Set Bobcat Retrievable Bridge Plug Positrieve packer at ± 4200'. (RBP) at 4500' and · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. · Fill drillpipe with nitrogen and pressure up on drillpipe to 1100 psi. · Close the pipe rams, and pressure up on the annulus to open the PCT valve. Cycle the valve to the held open position. Open the choke at surface and permit the well to clean up through the separator. If the well does not flow at high enough flowrates to lift the water volume below the PCT valve,-use gas from the platform to kick the well off. If the well cannot be kicked off using gas from the platform then coiled tubing and nitrogen should be used to jet the well in. RECEIVED MAY t '4 ~992 {)ii .& ;~s.Cons. ,.Qommission · Continue flowing the well. Flow the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. Note the flowrate where sand production can be detected. The flowrates and lengths of the flow periods at each rate will be determined by the reservoir engineer on location. The well is to be flowed at a high enough rate to maximize the drawdownthereby insuring that all the intervals are producing. Production logs are planned during this test to determine the contribution from each of the sands and to determine the pressure in each sand. Production logs should be ran at flowrates lower than the flowrate that produces sand in order to avoid cutting the electric line with sand. 8. Close the tester valve and open the MIRV reversing valve. · Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 10. POOH w/ test tools and prepare to squeeze this interval. If this interval does not produce water and sand the zone will not be squeezed but will be isolated with packers during the final completion so that the remaining reserves in the Stray, A, and B can be produced. RECEIVED ~AY 1 ~ 1992 .k,14mska Oi~ & ,6a,~ Cons. Gomm. i~,~ DST TOOL STRING TEST 1 COOK INLET STRAY, A AND B TEST TREE 3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND 3 1/2' DRILLPIPE PCT VALVE W/ HOLD OPEN POSlTRIEVE PACKER MAY 1 a 1992. At~ka Oil & Gas Cons. COOK INLET I - 11 DST BEGIN TEST, FLOW WELL DOES WELL PRODUCE WATER? IEND TEST I RUN TEST TO DETERMINE INTERVAL(S) PRODUCING WATER I I SHOULD WATER ZONE(S) BE SQUEEZED? ISQUEEZE INTERVAL(S) PRODUCING WATER RETEST CI 1-11 ADDITIONAL STIMULATION PROCEDURE TO BE DETERMINED RECEIVED MAY 1 4 1992 YES ~ NO IEND TEST YES Alaska 0ii & Gas Cons. Commission Anchorage ARE ALL PERFORATED INTERVALS P RODU Cl NG AS EXPECTED? NO PERFORATE ZONES NOT PRODUCING W/ THRU TUBING GUNS I ARE ALL PERFORATED INTERVALS PRODUCING AS EXPECTED? YES STIMULATE ZONES NOT PRODUCING ARE ALL PERFORATED INTERVALS PRODUCING AS EXPECTED*? COOK INLET S~'DS 1 THROUGH 11 Test Objective: Verify all perforated intervals are producing as expected, reperforate or stimulate any zones not producing, identify any zones producing water and or sand, and gather reservoir data to update the reservoir model. Procedure: le Displace well with test fluid, see workover fluid section E for test fluid recipe. · RIH w/ DST tools as shown on the attached schematic. The PCT valve should be run in the closed position so that the pipe is dry. Note: If the Cook Inlet Stray, A, and B have not been squeezed use the DST tools that will-be used for the Beluga test with the MFE valve instead of the PCT valve. 3. Set packer at ± 4500'. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. · Fill drillpipe with nitrogen and pressure up on drillpipe to 1100 psi. e Close the pipe rams, and pressure up on the annulus to open the PCT valve. Cycle the PCT valve to the held open position. Open the choke at surface and permit the well to clean up through the separator. If the well does not flow at high enough flowrates to lift the water volume below the PCT valve, use gas from the platform to kick the well off. _ If the well cannot be kicked off using gas from the platform then coiled tubing and nitrogen should be used to jet the well in. · Continue flowing the well. Flow the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. The flowrates and lengths of the flow periods at each rate will be determined by the reservoir engineer on location. The well-is to be flowed at a high enough rate to maximize the drawdown thereby insuring that all the intervals are producing. Production logs are planned during this test to determine the contribution from each of the sands and to determine the pressure in each sand. If the production logs show workover fluid covering the lower zones, RIHw/ coiled tubing and use nitrogen to liftthe water out, then continue testing. · If water production was observed during the test, review the production log results to determine which zone appears to be the most likely source of the water, and continue with steps 9 through 12. If the test did not produce water skip to step 13. 9. Close the PCT valve and open the MIRV reversing valve. 10. Reverse circulate taking returns through the separator until the tubing if full of kill fluid and well is dead. 11. RIH and latch onto RBP. Move RBP to just below the highest zone identified as a possible source of the water from the production logs· 12. POOH w/ annulus pressure operated test tools. Skip to test procedure entitled "Test to determine source of water. production", page 20. 13. If the production logs show any interval to be non productive, perforate the non productive interval with 4 spf using 2 1/8" hollow steel carrier thru tubing perforating guns and deep penetrating charges. 14. After perforating, open the choke at surface and resume flowing the well through the separator. Flow the well and rerun the production logs as in step 6 above. If flow from the interval has resumed continue with test procedure. If interval is still not productive then the interval will be stimulated. Refer to the appropriate stimulation procedure in section I. 15. Close the PCT valv9 and open the MIRV reversing valve. 16. Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 17. POOH with test tools. RECEIVED DST TOOL STRING TEST 2 COOK INLET I THROUGH 11 TEST TREE 3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING ~,LVE I STAND 3 1/2' DRILLPIPE PCT VALVE W/ HOLD OPEN HYDROSTATIC REFERENCE TOOL POSlTRIEVE PACKER RECEIVED BELUGA DST BEGIN TEST, FLOW WELL I I LL PRODUCE WATER? DOES WE I YES ~ NO END TEST RUN TEST TO DETERMINE INTERVAL(S) PRODUCING WATER I ENDTEST I I SHOULD WATERZONE(S) I BE SQUEEZED? IDENTIFY INTERVALS NOT PRODUCING AS EXPECTED? I END TEST I I ISQUEEZE INTERVAL(S) PRODUCING WATER ADDITIONAL STIMULATION PROCEDURE TO BE DETERMINED PERFORATE ZONES NOT PRODUCING W/ TCP GUNS IRETEST I YE8 ARE ALL PERFORATED CONDUCT BUILDUP/DRAWDOWN TEST ON ONE SAND INTERVALS PRODUCING A8 EXPECTED? YE8 END TEST ~,,,, ~ STIMULATE ZONES NO ARE ALL PERFORATED INTERVALS PRODUCING MAY 1 ~ t992 Alaska 0ii & Gas Cons, ,~e~missior BELUGA TEST PROCEDURE Test Objective: Verify all perforated intervals are producing as expected, reperforate or stimulate any zones not producing, identify any zones producing water and or sand, and gather reservoir data to update the reservoir model. Procedure: Displace well with-test fluid, see workover fluid section E for test fluid recipe. · RIH w/ DST tools as shown on the attached schematic. The MFE valve should be run in the closed position so that the pipe is dry. · Set packer at ± 5600'. Close pipe rams. Note: The mechanically operated DST tools needed for this test are operated by manipulating the drillpipe. Space out the drillsting to insure that the drillpipe can be manipulated as needed to operate the tools with the pipe rams closed. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. Se Fill drillpipe with nitrogen and pressure up on drillpipe to 1100 psi. · Close the pipe rams, and slack off on the drillstring to open the MFE valve. Cycle the MFE valve to the held open position. Open the choke at surface and permit the well to clean up through the separator. · Rig up coiled tubing unit on top of the test tree, open the choke at surface and begin RIH with the coiled tubing and use nitrogen to lift water from below the packer. · Run the coiled tubing to 7850' and continue jetting with nitrogen to lift water off of all perforated intervals. "s MAY ] ~ 199z · Continue flowing the well..Flow the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. The flowrates and lengths of the flow periods at each rate will be determined by the reservoir engineer on location. The well is to be flowed at a high enough rate to maximize the drawdown-thereby insuring that all the intervals are producing. Production logs are planned during this test to determine the contribution from each of the sands and to determine the pressure in each sand. 8. Close the MFE tester valve and open the MIRV reversing valve. · Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 10. If water production was observed during the test, review the production log results to determine which zone appears to be the most likely source of the water, and continue with steps 11 and 12. If the test did not produce water skip to step 13. 11. RIH and latch onto RBP. Move RBP to just below the highest zone identified as a potential source of the water water from the production logs. 12. POOH with test tools. Skip to test procedure entitled "Test to determine source of water production", page 20. 13. RIH w/ tubing conveyed perforating guns and DST tools per attached schematic to reperforate any non productive intervals. 14. Run correlation log to locate TCP guns to perforate desired intervals and set packer. 15. Close the pipe rams, and slack off on the drillstring to open the MFE valve. Rerun the correlation log to verify the guns are on depth. Note that a RA tag is included below the packer for the second correlation log. This is to verify that the drillpipe movement needed to set the packer'did not affect the gun setting depth. 14 RECEIVED 1992 16. Fill the drillpipe with nitrogen and fire guns by pressuring up on the drillpipe-to the required pressure then bleeding off to the pressure needed for 500 psi underbalance. Bottomhole pressure data for determining underbalance will be determined from the production logs ran in step 7. After perforating, open the choke at surface and permit the well to clean up through the separator. Flow until well has cleaned up. 17. Close the MFE tester valve and open the MIRV reversing valve. 18. Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 19. POOH with TCP guns, check guns to verify all shots fired. 20. Repeat steps 2 thrOugh 13. If production logs show an interval is still not productive it will be stimulated. Refer to the appropriate stimulation procedure in section I. 21. The reservoir engineer will select a zone in the Beluga for drawdown and buildup testing. Move the RBP to below the zone to be tested. 22. RIH w/ DST assembly for buildup and drawdown tests per attached schematic. Run MFE valve in the closed position so that pipe is dry. Set packer above zone to be tested. The final configuration of the tool string below the packer will be dependent on the space available between the packer and RBP. 23. Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. 24. Fill drillpipe with nitogen and pressure up to the reservoir pressure measured in step 7. 25. Close the pipe rams and slack off on the drillpipe to open the MFE valve. Open the choke at surface and permit the well to clean up through the separator. 26. Conduct drawdown and buildup tests well as directed by reservoir enginee~ on location. Surface readout pressure gauges will be used. 'R.EC E IV E D 27. Close the MFE valve and open the MIRV reverszng valve. MAY 1 ,~ t992 Alaska Oil & Gas Cons. 15 28. 29. 29. 30. Reverse circulate taking returns through the separator until the tubing if full of kill fluid and well is dead. POOH w/ test tools. RIH and latch RBP. RIH to TD and displace well with filtered KCL water for final completion, see workover fluid section E for completion fluid recipe. POOH w/ RBP and prepare for final completion of well. 16 RECEIVED MAY 1 ,~ 1992 Alaska Oil & Gas Cons. C~mm, is$iOr., DST TOOL STRING TEST 3 BELUGA TEST TREE 3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND 3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN 1 STAND ;3 1/2' DRILLPIPE JAR8 SAFETY JOINT POSiTRIEVE PACKER RECEIVED MAY 1 ~ 1992 Alaska 0il & Gas C'ons. ~;ommisr, ion TUBING CONVEYED PERFORATING TEST TREE ;3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING ~,LVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND 3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN I STAND 3 1/2' DRILLPIPE JARS SAFETY JOINT POSlTRIEVEPACKER 3 1/2' DRILLPIPE AND PUPS AS NEEDED TO SPACE OUT RADIOACTIVE MARKER PORTED SUB 3 1/2' DRILLPIPE AND PUPS AS NEEDED TO SPACE OUT FIRING HEAD- INTERAL PRESSURE PERFORATING GUNS RECEiVeD Alaska 0ii & ~s Co~s uo~.~s: Anch~ DST TOOL STRING TEST 5 BELUGA DRAWDOWN/BUILDUP TEST TEST TREE 3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND 3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN I STAND 3 1/2' DRILLPIPE JARS SAFETY JOINT PO$1TRIEVE PACKER BUNDLE CARRIERS TO BE DETERMINED RECEIVED MAY 1 ~ 1992 A/aska mi & ~ cons, ~ TEST TO DETEI~INE SOURCE OF WATER PRODUCTION Objective: Identify intervals producing water. ® RIH w/ DST tools per attached schematic. MFE valve should be run in closed position. 2. Set packer above uppermost zone expected to produce water. · '. 4o Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. Fill drillpipe with nitrogen and pressure up to reservoir pressure of interval being tested. · Close the pipe rams and slack off on the drillpipe to open the MFE valve. Open the choke at surface and permit the well to clean up through the separator. e Continue flowing the well. Flow' the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. ® After the test is complete, close the MFE valve and bleed off the gas inside the drillpipe. · If this interval does not produce water, RIH and lower the RBP to below the next zone that might produce water, reset the packer above that zone and repeat steps 3 through 8. If this interval does produce water and there are other intervals that may also produce water, lower the RBP to below the next zone suspected of water production and reset the packer above the zone and repeat steps 3 through 8. · After all zones.suspected of producing water have been tested, open the MIRV reversing valve and reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 10. POOH w/ test tools. 11. The intervals producing water may be squeezed per the appropriate squeeze procedure in section H or may be isolated by packers in the final completion. RECEIVED z o MAY 1 ~ t~2 Al~st~ 0il & Gas Cor~. ~[~mm~br~ DST TOOL STRING TEST 4 DETERMINE WATER SOURCE TEST TREE ;3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING ~LVE I STAND ;3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN I STAND 3 1/2' DRILLPIPE JARS SAFETY JOINT POSlTRIEVE PACKER RECEIVED U~Y 1 ~ ~992 SECTION H 8~UEEZE PROCEDUREs RECEIVED MAY 1 4 199L~ S~UEE~E PROCEDURE Send samples of cement, additives, and mix water to Dow. Il- Schlumberger for testing at least 4 days prior to squeeze job. Brad.nh. ad Squeeze Procedure for Cook Inlet Stray, &, and B sands. The interval to be squeezed is as follows: Cook Inlet Stray: Cook Inlet A: Cook Inlet B: 4247' - 4262' 4284' - 4314' 4330' - 4400' Static Temperature: 95 deg. . A Bobcat Retrievable Bridge Plug (RBP) will have been set below the Cook Inlet B sand. . RIH w/ 20 joints 2 7/8" tubing and 3 1/2" DP to +_ 4450' MD. Dump sand on top of the bridge plug. 3. Establish circulation then close annular preventer. 4. Establish injection rate then open annular preventer. Se Mix 20 BBLS of cement in batch mixer as follows: 100 sacks Class G cement 0.5 % D156 (fluid loss additive) 0.05 gal/sk D-47 (antifoam) 4.97 gal/sk fresh water Dens ity: Yield: Thickening Time: Fluid Loss: 15.8 ppg 1.15 cu ft/sack 4:30 hours 40 cc/30 min Note: D156 is a dry additive and should be pr.mixed in the mix water ® Pump a 20 barrel fresh water spacer then spot the 20 bbls of cement as a balanced plug. Pump a 5 bbl fresh water spacer behind the cement and displace with workover fluid. . POOH w/ 7 stands. . Close annular and squeeze cement into formation. Displace 7 bbls of cement in~o formation then slow pump rate down to hesitation squeeze the remainder of the cement. Limit pressure to 2000 psi. RECEIVED .. MAY '1 4 199 Alaska Oil & Gas Cons. Commission Anchorage · If the pressure does not increase overdisplace the cement and proceed to step 10. If pressure does increase permit the pressure to increase to 2000 psi and hold 2000 psi while WOC. Keep pipe moving in ± 25' long strokes (make strokes as long as possible without stripping a tool joint through the annular preventer) while WOC. If there are any indications that cement is remaining around the drillpipe, open the annular, circulate the well clean, POOH, and skip to step 12. 10. RIH to ± 4450 and circulate 2 hole volumes prior to repeating squeeze procedure. 11. Repeat steps 3 through 9 if needed. 12. After the squeeze is complete, RIH w/ 6" bit to drill cement. 13. Drill to 4270 and test Cook Inlet Stray perforations to 2000 psi. 14. Drill to 4320 and test Cook Inlet A perforations to 2000 psi. 15. Drill to 4410 and test Cook Inlet B perforations to 2000 psi. Note: If any of the perforations does not test, repeat the squeeze procedure before continuing. RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage Inlet B sand. If excessive water production occurs when testing either the Cook Inlet or Beluga the interwal producing the water will be identified and may be squeezed. In this event the zone producing the water will be isolated from below with a bridge plug and from above with a cement retainer. The setting depth of the bridge plug and the retainer may be critical due to the proximity of the adjacent sands. A Bobcat Retrievable Bridge Plug (RBP) will have been used in the testing program that identified the interval producing water. Depending on the spacing between the interval to be squeezed and the interval below either a retrievable bridge plug or a drillable bridge plug will be used for zone isolation. A drillable bridge plug should be ordered when it becomes apparent that a squeeze will be performed that may require its use. Squeeze Procedure le If spacing of bridge plug to isolate from below is critical, POOH with the Bobcat Retrievable Bridge Plug (RBP) used for testing. If spacing is not critical leave the RBP in the well and dump sand on top of the plug. If spacing of the bridge plug is critical, set a drillable bridge plug on wit·line at the appropriate depth. · Set a cement retainer on wit·line above the perforations to be squeezed. 4. RIH w/ cement stinger and st:ing into retainer. · Close the annular and establish injection rate. Note that there are several sets of open perforations above the retainer and there is a chance for communication through these perforations to the annulus. Observe the annulus for any indications of this_ before proceeding. e Mix the desired cement volume in the batch mixing tank· Final cement formulation will be determined based on the interval to be squeezed. Have Dowell- Schlumberger test cement formulations using bottomhole temperatures of the interval to be squeezed. RECEIVED MAY 14 1992: Alaska Oil & Gas Cons. Commission Anchorage · Pump a 5 barrel fresh water spacer and the cement followed by a 5 barrel fresh water spacer then displace with workover flUid. Hesitate during the squeeze as needed. Desired squeeze pressure is 2000 psi. If the interval does not squeeze overdisplace to facilitate another attempt. Observe the annulus for any indications of communication. Note: Communication is possible even if there is no indication of communication at surface. Cement could enter the wellbore through one set of perforations and displace the workover fluid out through another set of perforations. · Unsting from retainer and pick up to above the top set of open perforations. Do not attempt to reverse circulate until pipe is above all the open perforations. Steps 8 - 10 should be performed even if another squeeze will be attempted before drilling up the retainer due to the possibility of cement in the annulus. · Reverse circulate to insure the drillpipe and annulus are clear. 10. If an additional squeeze will not be required POOH. If an additional squeeze will be required WOC, then run back into hole, sting into the retainer and repeat squeeze procedure. 11. Drill out retainer and cement to past bottom perforation to be squeezed. If RBP was used, drill out all cement, if a drillable bridge plug was used then drill past the bottom perforation but do not drill up the bridge plug. 12. RIH w/ packer. 13. Test the squeezed perforations to 2000 psi. 14. If the perforations test, POOH w/ packer. If perforations do not test POOH w/packer and repeat squeeze procedure. 15. RIH w/ 6" bit and drill out bridge plug (if applicable) 'RECEIVED 1 4 1992 Alaska Oil & C~es Cons. ~ SECTION ~ ST~I. IUL~TION PROCEDURES RECEIVED MAY 1 4 199~ Alaska Oil & Gas Cons. Commission Anchorage STIMULATION PROCEDURE 1. Move RBP to below the highest interval to be stimulated. · RIH w/ packer and BHA per attached schematic. Set packer above interval to be stimulated. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 2000 psi. All lines between the separator and the burner boom should be tested to125 psi. All tests are to made using nitrogen or helium as the test fluid. · Close pipe rams, fill drillpipe, open MIRY reversing valve and spot stimulation fluid to near MIRY reversing valve. Composition of stimulation fluid has not been determined at the present time. The fluid will depend on the interval to be stimulated and the results of ongoing core analysis. ® Close MIRV reversing valve, open MFE valve valve and pump remainder of stimulation fluid. 6. Displace with nitrogen· · Flow back as directed. If interval cleans up and flows at an acceptable rate continue to step 8. If interval does not flow at an acceptable rate an alternative stimulation procedure will be developed by the reservoir engineer and the drilling engineer on site. · Close the MFE, open the MIRV reversing valve and reverse circuluate taking returns through the separator until the tubing is full of kill fluid and well is dead. · Move RBP to below the next zone to be stimulated. Set packer above zone and repeat steps 3 through 7. 10. After all intervals have been stimulated and are producing at acceptable rates, kill well and POOH w/ packer. RECE /ED ~k¥ 1 4 199Z Alaska Oil & Gas I~ons. Co,m~i°n Anchora~ TOOL STRING FOR STIMULATIONS [ TEST TREE ,3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING ~LVE I STAND 3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN I STAND 3 1/2' DRILLPIPE JARS SAFETY JOINT POSlTRIEVE PACKER RECEIVED MAY '~ 4 1992 Alaska Oil & Gas Cons. Commission Anchorage SECTION ~ COMPLETION PROCEDURE RECEIVED MAY 1 ~ 1992 Alaska Oil & Gas Cons L;O~m'llissior COMPLETION PROCEDURE Note: Detailed schematics of each subassembly are shown in section P. The final completion design is subject to change based on the results of the well testing. Other adjustments to the setting depths of the equipment will be made based on the actual length of the tools and the need f~r additional crossovers. Blast joints are to remain opposite each set of perforations and the packers should be set to isolate the intervals shown. The completion design includes 2 7/8", 3 1/2" and 4 1/2" tubing and a large number of blast joints and other tools. Have tools available to handle all tubulars. 1. Make up subassembly i as per attached schematic and RIH. Note: XA sleeve should be in the closed position while RIH. · Run a GR-CCL log to verify the depth of the top blast joint· Set packer so that the top blast joint is located opposite the Upper Beluga perfs. · Rig up test tree and RIH w/ coiled tubing. Jet well in and flow through test separator until well cleans up. · · Set a blanking plug in the XN nipple at the end of the 2 7/8" tubing. Bleed off pressure and load the well with completion fluid. 6. Release DP from packer and 'POOH. 7. Make up subassembly 2 and RIH. 8. Sting seal assembly into packer set on subassembly 1. · Run a GR-CCL log to verify depth of the top blast joint· Set packer so that the top blast joint is opposite the Cook Inlet 8 perforations. 10. Release DP from packer and POOH. 11. Make up subassembly 3 and RIH. 12. Sting seal assembly into packer set on subassembly 2. 13. Run a GR-CCL log to verify depth of the top blast joint· Set packer so that the top blast joint is opposite the Cook Inlet 7 perforations·_ R-ECEIVED 2 MAY 1 1992 Alaska Oil & Gas Cons, Cm[tmissioc Anchorage 14. Release DP from packer and POOH. 15. Make up subassembly 4 and RIH. 16. Sting seal assembly into packer set on subassembly 3. 17. Run a GR-CCL log to verify depth of the packer. Set packer so that the packer is set between the bottom perforation of the Cook Inlet 3 and the top perforation of the Cook Inlet 4. 18. Release DP from packer and POOH. 19. Make up subassembly 5 and RIH. 20. Sting seal assembl~ into packer set on subassembly 4. 21. Run a GR-CCL log to verify depth of the top blast joint. Set packer so that the top blast joint is opposite the Cook Inlet 3 perforations. 22. Release DP from packer and POOH. 23. Make up subassembly 6 and RIH. 24. Sting seal assembly into packer set on subassembly 5. 25. Run a .GR-CCL log to verify depth of the top blast joint. Set packer so that the top blast joint is opposite the Cook Inlet 1 perforations. 26. Release DP from packer and POOH. 27. Make up subassembly 7 and RIH. 28. Sting seal assembly into packer set on subassembly 6. 26. Release DP from packer and POOH LDDP. 27. Lay down any drillpipe stood back in the derrick. 28. Make up subassembly 8 and RIH. Note: This subassembly includes the SCSSV and the control line. 29. Prior to stinging into packer, reverse circulate to displace well with packer fluid. Leave 4 bbls of glycol in top of tubing x casing annulus for freeze protection. 30. Space out and latch into packer. Prepare to establish barriers, ND BOP and NU tree per step F6 of main procedure. RECEIVED MAY I 1992 ~la,~ka Oit & G~ Cons L;ol~'lrnissio' PHILLIPS PETROLEUM COMPANY NORTH COOK INLET UNIT PLATFORM A STANDARD PROCEDURES GUIDELINES FOR SIMULTANEOUS ACTIVITIES RECEIVED Anchorage 1.0 GENERAL 1.1 The following procedural guidelines will be used whenever simultaneous activities are in progress on North Cook Inlet Unit Platform A. There will be situations which do not fit the examples described in these guidelines. If any doubt exists about the correct action to be taken, consult the appropriate management personnel. RESPONSIBILTY While conducting simultaneous activities the Drilling Supervisor is responsible for Drilling, Completion and Workover activities. The platform Lead Operator is responsible for production activities and the routine operation of the platform. The Drilling Supervisor and the Lead Operator should assist each other in order to achieve the common objective of conducting simultaneous operations in a safe manner. Either the Drilling Supervisor or the Lead Operator has the authority to declare an emergency and shut in production when it is deemed unsafe to continue. In an emergency while drilling, completion, or workover activities are in progress the Drilling Supervisor will be the designated "Person In Charge". The "Person In Charge" will be responsible for the following: . . . . Assumes management responsibility for the safety of personnel and protection of property and equipment by activating the Emergency Plan and assuming operating direction. Evaluates the overall emergency situation based on the information at hand including information from the Toolpusher and the platform Lead Operator and makes decisions on actions to be taken. Initiates platform evacuation if necessary, and insures that all personnel are accounted for and evacuated. As soon as possible, contacts the Kenai Drilling Superintendent and the Kenai Plant Superintendent. These people will in turn activate the Phillips Emergency Communications Plan. 'RECEIVED MA'( 1 4 1992. Alaska 0ii & Bas .~rm. C~ 2.0 DEFINITIONS For the purpose of these guidelines the following definitions will apply. 2.1 SIMULTANEOUS ACTIVITIES Any of the following activities which are occurring simultaneously on the platform: Drilling, Workover/Hydraulic Workover, Concentric Tubing Workover, Production, Wireline Operations, Construction/Maintenance, 2.2 DRILLING Any work done on a well with the use of a drilling rig and related equipment, prior to the well being placed on production. 2.3 WORKOVER 2.4 2,5 Any work done on a well with the use of a drilling, workover, or hydraulic workover rig, after the well has been placed on production. CONCENTRIC TUBING WORKOVER Any work performed using a small string of tubing inside the production tubing or the drillpipe. The small tubing may be a small string of tubing run using the drilling rig or a snubbing unit, or the small tubing may be coiled tubing. PRODUCTION 2,6 Any work involving producing/injecting hydrocarbons or other fluids from/into a well. With the X-mas tree installed, stimulating is considered production. WIRELINE Any work which involves using a wireline or electric line to run tools/instruments into or out of a well. RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Cammi~i¢ 2.7 2.8 CONSTRUCTION/MAINTENANCE Any work requiring issuance of hot work permits or involving heavy lifts. RIG MOVING/SKIDDING Movement of the derrick from one leg to another or from one well slot to another. 2.9 BARRIER Any device, mechanical or fluid which prevents the uncontrolled flow of fluids from a well. 2.10 HEAVY LIFT Any lift which requires the use of the main block of the crane. 3.0 BASIC PHILOSOPHY . . . . . Safety is of the highest priority in any activity. Simultaneous activities will be performed with a minimum of two barriers on each well. If simultaneous activities are occurring and a well activity loses the minimum number of barriers, all wells within the wellroom of the offending well will be shut in. The Drilling Supervisor and Lead Operator will evaluate the situation and determine if production from the remaining wellrooms should also be shut in. All other simultaneous activity must cease until the required number of barriers is restored. More than two simultaneous activities can occur provided that at least two barriers are maintained for each well activity. Communication between all parties involved, onshore as well as offshore, is critical to the conduct of simultaneous activities. This communication begins during prejob planning, and should continue until the job is complete. RECEIVED MAY 1 4 1992 4.0 ACCEPTABLE BARRIERS Examples of acceptable tested barriers for each activity are as follows: 4.1 DRILLING . Stable fluid column of sufficient density to prevent flow from any formations open to the well. Fluid barriers should be tested by observing the well for an appropriate period, normally at least 30 minutes. 2. Blowout Preventer Stack tested to Phillips specifications 3. Tested casing 4. Bridge plUg 4.2 WORKOVER/HYDRAULIC WORKOVER . Stable fluid column of sufficient density to prevent flow from any formations open to the well. Fluid barriers should be tested by observing the well for an appropriate period, normally at' least 30 minutes. 2. Blowout Preventer Stack tested to Phillips specifications. 3. Downhole Safety Valve 4. Back Pressure Valve 5. Wireline plug set in the appropriate profile nipple 6. Bridge Plug 7. Hydraulic Workover Unit BOP RECEIVED MAY 1 4 1992 Alaska 0il & Gas Cons. Commissto~ Anchorage 4.3 CONCENTRIC TUBING WORKOVER 4.4 Stable fluid column of sufficient density to prevent flow from any formations open to the well. Fluid barriers should be tested by observing the well for an appropriate period, normally at least 30 minutes . Hydraulic Workover Unit BOP, drilling rig BOP, or coiled tubing unit BOP. PRODUCTION For production operations the tubing and the annuli must be considered as independent flowpaths. Each flowpath must have two barriers. 4.4.1 PRODUCTION TUBING 4.5 1. x-mas tree 2. Downhole safety valve 3. Wireline plug 4.4.2 ANNULUS WIRELINE 1. x-mas tree and wellhead including annulus valves 2. Packer and tubing with tested casing . Stable packer/completion fluid or mud of sufficient density to control formations potentially open to the well 1. X-mas tree 2. Wireline BOP 5.0 SPECIAL CONDITIONS AND PROCEDURES 5.1 SURVEILLANCE AND COMMUNICATIONS Performing the various activities simultaneously requires the coordinated efforts of all the groups involved. This coordination requires that proper communications be maintained between all the' groups. This is enhanced by the Hot Work Permit system and the surveillance of the Lead Operator, the Drilling Supervisor, and the conscious effort of all platform personnel to be aware of and adhere to the simultaneous activities guidelines. A safety meeting should be held prior to each critical operation, A critical operation is defined as any operation that could affect the security of a well. 5,2 5.3 DRILLING AREA EXCEEDING 60% LOWER EXPLOSIVE LIMIT Simultaneous activities shall cease in the event the gas level in the drilling area exceeds 60% of the lower explosive limit. The drilling area includes the rig floor, BOP deck, wellhead area, and mud pits. BOP DROP RADIUS The BOP handling system has been designed to eliminate the risk of the BOP stack falling while nippling up/down. Shutting in producing wells to nipple up/down the stack is not necessary provided that the stack is supported by the handling system. If the BOP cannot be supported by the BOP handling system, such as for · replacing the stack or a major component of the stack, all wells in the wellroom need to be shut in. The shut in should occur when the BOP is removed from the handling system. The wells should remain shut in until 4 studs, spaced around the flange, are in place securing the BOP to the riser. For nippling down, the shut in should occur when 4 studs remain securing the BOP to the riser and the wells should remain shut in until the BOP is secured in the handling system. Shut in of a well should be done using established procedures, confirming the DHSV is closed, bleeding off wellhead and ~;)~l~rre[3~l~~ to header pressure, bleeding off any annulus pressure, ark~t~~th~ster valve. MAY t ~ t992 Alaska 0il & Gas C~ns 5.4 HEAVY LIFTS The following procedures will apply for heavy lifts. . A flagman will-be present at all times during any lift. He will be in radio contact and, if possible, visual contact with the crane operator. . Prior to the lift, the crane driver and flagman will discuss relevant hazards and agree on proper action. . Every effort will be made to avoid making a heavy lift over any hazardous area. . Any time a heavy lift is made over the drill deck, any wells within the swing path should be shut in. . Loads should not be lifted any higher than necessary to clear obstructions in the swing path. . Loads will not be rotated above a hazardous area, including the wellrooms, unless it cannot be avoided. 7. Use tag lines on load to guide them into correct and safe position. 8. Visually inspect rigging (slings, hooks, shackles,' etc.) before use . The crane operator is responsible for seeing that all rules are followed before a lift is made. 5.5 HOT WORK Any welding, torch cutting, or other hot work in a wellroom or the drilling area shall be evaluated to determine what activities, if any, should cease, and which wells, if any, should be shut in. Appropriate procedures and hot work permits will be prepared and approved by the Drilling Supervisor and the Platform Lead Operator to insure hot work operations are conducted safely in conjunction with any other activities in progress. RECEIVED 5.6 5.7 EMERGENCY SHUT-DOWN sYSTEM (ESD) The ESD system must be capable of handling all activities in progress on the platform. Testing of the ESD system is to be carefully coordinated to prevent the loss of vital capabilities during simultaneous activities. DIRECTIONAL DRILLING In the event of a drilling operation taking place, a "safety zone" will be established around the drilling well. The safety zone is equal to the minimum wellhead spacing or 1.5 % of the measured depth of the current drilling depth below mudline, whichever is greater. If a producing well intersects the safety zone, then the producing well must be shut in by setting a plug below the potential point of intersection. Once the risk of collision is past the plug can be retrieved and production resume. A detailed analysis of the location of nearby production wells in relation to the proposed path of the drilling well will be included with the drilling program. In all cases, when a producing well is near the safety zone directional control will take priority over penetration rate. RECEIVED 9 MAY 1 4 199,! Aiasl~ 0il & sas 1:~. 6.0 EXAMPLE SITUATIONS The examples shown in this section are intended to clarify the simultaneous activities guidelines. These examples are not intended to cover every possible situation. For situations which are not covered by an example the appropriate management, normally the Drilling Supervisor, will evaluate the situation and determine the action to take. 6.1 DRILLING SITUATION 1. Well kick 2. Loss of circulation before 20" casin& has been set 3. Loss of circulation, able to keep hole full 4. Loss of circulation, unable to keep hole full but can pump seawater down annulus and pore pressure of formations open is less than a seawater 8radient. 5. Loss of circulation, unable to keep hole full but can monitor fluid level with echometer or other devices and determine that fluid colum~ is stable and of sufficient height to exceed pore pressure of any formation open 6. Loss of circulation, unable to keep hole full. Pore pressure of formation open exceeds a seawater &radient and fluid level cannot be monitored 7. Gas level exceeds 60Z LEL 8. BOP control failure - unable to close rams or annular preventer 9. Failure of a component of the BOP stack i.e. one of ~he pipe rams, the blind/shear ram, or the annular to function or hold pressure. At Least one of the components below the failed component will operate properly and will hold pressure 10. Leak in a flange or riser below ~he bottom component of the BOP which could be used to shut in ~he well 11. Stuck pipe, full circulation ACTION All other activities must cease until well is stable No action required, simultaneous activities can continue No action required, simultaneous activities can continue No action required simultaneous activities can continue No action required, simultaneous activities can continue AIl other activities must cease until the hole can be kept full Ail activities must cease ALI other activities must cease. Run test/abandonment plus into wellhead and lock down. O~her activities can ~hen be resumed. Simultaneous activities can continue. Run test/abandonment plu~ int~ wellhead and lock down. Make necessary repairs ~o BOP. Other activities must cease. Run test/abandonment plu~ into wellhead and lock do~n. Other activities can resume and repairs can be made. No action required, simultaneous activities can continue 10 REHARKS Loss of barrier No formations capable of flow have been penetrated therefore no barriers are lost No barrier lost No barrier lost as Ions as it is possible to pump seawater into annulus No barrier is lost as ions as fluid column is known to be sufficient to overbalance pore pressure. The fluid level does not need to be at surface but must be observable in some Loss of barrier No barrier lost but hazard condition exists Loss of barrier No barrier is lost Loss of barrier No barrier lost 12. Stuck pipe, reducing mud weight to free differentially stuck pipe 13. Unable to circulate due to plugged bit 14. Directional drilling well, safety zone will approach an active well. Potential point of intersection is above shoe of conductor casing of active well Directional drilling well, safety zone will approach an active well. Potential point of intersection is Below shoe of conductor casing of active well 16. NU/ND BOP 17. NIl/ND Riser or X-mas tree Notify Production, if well kick is induced inadvertently other activities must cease, see example 1. Otherwise, simultaneous activities can continue No action required, simultaneous activities can continue Other activities can continue, d~ii1 slowly and cautiously until past potential point of intersection. If there is any indication of collision stop drillin~ and plug Back in order to sidetrack Active well must be plugged below potential point of intersectionbefore the safety zone reaches the potential intersection point. A pump open plug is acceptable and can be opened as soon as the safety zone is past the potential point of intersection No action required, simultaneous activities can continue. Shut in all wells and flowlines in wellroom. Wells will re~ain shut in when leas than 4 studs are in place. Need to be aware for potential loss of barrier No barrier lost Since there a~e at least three casin~s aepaxatin~ the cl~illing well f~o~ the active well flo~stream a collision would be detected before the active well is damaged therefore a collision would not result in a loss of any barrier Collision might result in the loss of a barrier in either the drilling well or the active well unless the active well is plugged No barriers lost If the riser or X-mas tree were to fall the X-mas tree barrier on wells in the welLroamwould be jeapordized. 11 'RECEIVED MAY 1 4 1992 Alaska Oil & Gas Corm. Commis~ Anct~age 6.2 WORKOVER SITUATION 1. Well kick 2. Loss of circulation 3. BOP failure 4. ~llins plussed packer, may lose circulation when millins ACTION All other activity must cease until well is stable See ~rillins examples 2 - 6 See drilling examples 8 - 10 Notify production of situation and proceed per drillins examples 2 - 6 Loss of bazrier Same as for drillin~ examples Same as for drilling examples Need to be aware of potential for loss of barrier 12 'RECEIVED MAY 1 ~ 1992 Alaska ~1 & ~as Cons, Comaassjo.: 6.3 SNUBBING SITUATION 1. See concent=~c tub~n~ examples ACTION 13 RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage 6.4 CONCENTRIC TUBING WORKOVER SITUATION ACTION 1. Leak in shear seal BOP or hydraulic workover unit, rig or coiled tubing BOP. Concentric tubing is not in the well. 2. Leak in shear.seal BOP or hydraulic workover unit, rig or coiled tubing BOP. Concentric tubing is in well so masker valve cannot be closed Close master valve and make repairs. Other activities must cease unless do~nhole barrier exists. Other activities must cease. Pull concentric tubing out of hole and proceed as per example 1. RE~U~S Loss of barrier Loss of barrier 14 RECEIVED MAY !~ t99,~ uii & ~$ Cons ~m~;~i~,~ 6.5 WIRELINE SITUATION 1. Pulling/Running CIV/gas lift valve, hydrostatic column of fluid in annulus is greater than BHP 2. Pulling/running ClV/gas lift valve, hydrostatic colunm of fluid in annulus is less than BHP. 3. Leaking wireline riser ACTION No action required, simultaneous activities can continue No action required, simultaneous activities can continue Unless a downhole barrier is present so that the wireline riser is not the second barrier, all other activities must cease, and the well shut in at the X-mas tree (shear wireline if necessary) No barriers are lost Acceptable practice for this closely manned operation Loss of second barrier 4. Wireline tools, plugs, logging tool or other device stuck in X-mas tree preventing closure of master valve 5. Flowing well while production lo&ging, obtaining wirelins samples, or flowing trash off plugs, etc. without DHSV in place Unless a downhole barrier is present so that the X-mas tree is not the second barrier, all other activities must cease. No action required, simultaneous activities can continue Loss of second barrier Acceptable practice for this necessary and closely manned operation 15 RECEIVED Alaska Oit & G~s Co.s. C~~or' A~ra~ 6.6 MAJOR CONSTRUCTION 3. SITUATION Hot work in wellzoom no well activity in progress and no wells are on sas lift Hot work in wellroom, drilling or other well activity in progress Hot work in wellroom, wells are gas lifted. Hot work in drilling areas 5. Beav~ lift over skid deck 6. Hot work in wellhead area, some wells on platfomhave annulus pressure (see production examples) ACTION Hake safety evaluation to determine what wells (if any) to shut in. Remainder of wells can continue producing. Water injection can continue even in adjacent wells at the discretion of the Lead Operator Make safety evaluation to dete~nine what welle (if any) to shut in. If a well activity, i.e. drilling, workover etc. is in progress on a well that would have been shut in, then the well activity must also cease. If t/~e well would not have been shut in then the activity may be pemitted to continue. Make safety evaluation to detemine what wells (if any) to shut in. Make safety evaluation to detezmine what wells (if any) can continue to he gas lifted. Evaluation of gas lift should consider how far gas jet would reach if a annulus valve were to fail. Bleed off gas pressure in annulus on all wells where gas lift is stopped and close annulus valve Activity using drillins rig must cease. Other activities can continue as per examples 1 and 3 Shut in all wells, flowlines, and headers in swin~path Bleed off annulus' pressure and shut in annulus valve, other activities can continue as per e~amples 1 and 3. Ho barriers lost, but potential hazard for nearby wells No barriers lost, for this urpoee there is no practical ifferencewhether a well is producin~ or has another activity in progress. Should a annulus valve fail, a gas jet would be released in the wellhead area. Hot work should not be performed in areas where this jet could reach. Wells may continue producing but without gas lift assistance No barriers lost, but potential hazard exists for well activity using drilling ri8 If load were dropped it would jeopardize the X-mas tree as as barrier Situation is similar to gas lift 16 'RECEIVED MAY 1 4 1992 Alaska 0il & Sas Co~s ~;o;a~r 6.7 MULTIPLE WELL ACTIVITIES 1. 3. SITUATION Two well activities - i. e. drilling, workover, wireline, coiled tubing are planned to occur concurrently. Two well activities are planned to occur concurrently, at least one of the activities involves working in the reservoir More then two activities are planned to occur concurrently ACTION Evaluate planned activities for potential conflicts which would jeopardize a barrier on one of the activities. If no conflict exists both activities can continue. If conflict does exist, resolve conflict - i.e. perfom only one activity, or reschedule conflicting portion of activities, or other action as required. Same as example 1 Same as example 1, however as the number of well activities increases the possibility of conflicts occurring also increases. As Ions as there are no conflicts between activities then each activity can continue without arbitrary restrictions. Work in the reservoir is not si~nificently different nor n~re hazardous than workin~ elsewhere in a well 17 RECEIVED MAY 1 1992 Aleske Oil & G~s Cons. Commission Anchorage 6.8 PRODUCTION SITUATION 1. DHSV major leakase or DHSV DHSV fails open or is blown 2. DHSV minor leakase 3. DHSV fails closed but holds pressure ACTION Other activities must cease. Shut in the problem well and evaluate situation. Shut in other wells only if the overall operation is in jeopardy. DHSV must be replaced before other activities can resume. Other activities can. continue, Well can be kept on production but DHSV is to be retested at 7 day intervals until the valve is replaced. The valve should be replaced at the first opportunity. Other activities can continue, chanse DHSV at first chance. Loss of barrier DHSV is still considered a barrier. No barriers lost up the hole 4. DRSV fails closed but leaks Treat as per example 1 or 2 dependin~ on severity of leak 5. 6. 7. Annulus pressure, pressure can not be bled off with a 1/2" hose to below FTP of well indicatin&tubins - annulus communication Annulus pressure, pressure can be bled off with a 1/2' hose Annulus pressure, pressure can not be bled off with a 1/2" hose but can be bled off with a 2" chicksan. Annulus is not tubinsX casin~ annulus. Other activities must cease unless leak is determined to be above DHSV. Shut in well, as soon as possible well should be plussed with a deep plus or killed with fluid. No action required, simultaneous activities can continue Same as example 6 Loss of annulus barrier, In cases where annulus Tressure can be bled below P consult with the OPEs to determine the annulus pressure history of the well and for a determination of any action to be taken. Sustained flo~ cannot occur since pressure can be bled off therefore dmmhole barrier (fluid, etc) is still a barrier Annulus pressure, pressure can not be bled off with a 1/2" hose and produces at a stable rate through a 2" chicksan Other activities must cease. Evaluate situation to determine if well should be shut in and corrective actions to take. Production can continue on other wells. Loss of annular barrier 18 RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage 6.9 WATER INJECTION SITUATION See production examples ACTION 19 RECEIVED MAY 1 4 1BB~ Alaska Oil & G~s Cons. 13ommi$$io~ Anchorage DIRECTIOHflL SURVEY HETHODt RflDUIS OF CURVIqTURE b/ELL REFERENCE NOg E&P39945 OPERRTOR; PHILLIPS bJELL ~ big DRILL DEPTH 5529.B ~?l~.B 6899.9 6276.9 6463,9 6656.9 69BB.B ?BB4.B 7271.B ?523.9 COURSE LENGTH ______ IB4.B 366,B IB6,B IB?,B 186,B IB9,B IB?,B 187.9 256,9 184,B 252.B 49919 DRIFT fiNS -VERTICflL DEPTH-- DEC DEG COURSE TOTflL 46.99 127,8 4966.? 4?,99 251.4 4447.8 47,09 126.9 45?3,9 47,08 127.5 4ret,4 4?.88 126,9 4828.2 4?,BB 128,2 4956,4 4?,se 126,D 5e93,4 4r.ee 126.9 52te.3 47,98 178,5 5388.8 46,58 126,1 5586,9 .-46,88 129.3 5636,2 45.B9 176.6 5812.9 46~99. ~4917 6162i6 DRIFT D IR RE II'IlJTH 234 235 235 23;' 23;' 239 239 249 249 249 249 o. 244 DIqTE: 8/2:3/r6 · LERSE AND TRRCT: NC! ---COURSE DEPRRTLIRES--- H/S E/bJ -91,49 -104,39 -168.89 -212.45 -79.D9 -119,?4 -79,44 -112,93 -76.96 -112,?? -?4.89 -115.31 -73.r8 -115.8i -?1.75 -117.88 -92.88 -157.55 -67.91 -116.86 -67.54 -116.99 -99,97 - i55.66 -16F195 -314J iff I~ELL ~1,: ?. TOTfiL DEPflRTUREg N/'S E/ld -1658.78 -1912,79 -1893.42 -2139.81 -1972.42 -2241.55 -2958.86 -2353.59 -2126.93 -2466.35 -2281.81 -2581.67 -22?5.59 " -~697.48 -2347;34 -2814,55 -2440.14 -2972.18 .-2se?.15 -3988,16 -2574,69 = -=205.15 -2664.56 -3369.80 -~931d61 -$674~99 RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commisslon Anchorage i RECEIVED MAY 1 4 1992 Naska Oil & Gas Cons. Commission ,,.:. .. .. .,_._, .... _ .. ............ ._.._ ,. _ ......~c~o,rage . ~' _-T2.."-... -~2'~.~"' 1 .................... ~. "~ .........'J ~ .... :.' . ~.,.~ ................................ , ..... . . "i '. .... i .. · ' ~-:.-~. · . l'.' ..... ::I ........ 1 ...... i . ! .'-~. ..... - .... :,~ ........ ,__..: .._._.._. ~.. ! ....... ,f- ........... ,. .... · ,-.~-::!"'[':: ."!' ::: I-: .... ~t ....... ,- -- '~. '" t .... I' ; · ~, ., i . '~'t ' ' ; " ' ' ' .~' :~.~ . -- ............. ..~ ...... , . . 'l i '- I' I -~ - i :% I' North Cook Inlet Unit Wellhead Arrangement CURRENT 1. Hammer Union 2. 4' 3M Orbit Ball Valve 3. 4' 3M Studded Tee 4. 4' 3M FE Gate Valve with 'Fail Close' Pneumatic Actuator 5. 4' 3M Gate Valve . e 4' 3M x 8" 3M Studded Tubing Head Adapter, bored for Otis TSV Line 8" 3M x 10" 3M Tubing Head, equipped with OCT Type TC-1A-EN Tubing Hanger bored for Otis TSV Une (4-1/2' EU 8rd Hanger Lilt Thread) 8. 2' 3M FE Gate Valves 9. 10' 3M x 16' 3M Casing Spool 10. 16' 3M x 16' SOW Casing Head 'RECEIVED MAY I 4 1992 Alaska 0il & Gas Cons. Commission Anchorage North Cook Inlet Unit Wellhead Arrangement PROPOSED 1. 4' 3M Tree Cap with Needle Valve and Gauge 2. 4' 3M FE Gate Valve 3. 4" 3M Studded Tee 4. 4" 3M FE Gate Valve with "Fail Close" Pneumatic Actuator 5. 4" 3M x 8' 3M Studded Tubing Heed Adapter, bored for Otis TSV Une. 8' 3M x 10' 3M Tubing Head, equipped with OCT Type TC-IA-EN Tubing Hanger bored for Otis TSV Une (4-1/2" EUSrd Hanger Lift Thread) 7. 2' 3M FE Gate Valves 8. 10' 3M x 16' 3M Casing Spool 9. 16' 3M x 16' SOW Casing Head RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage DIRECTIONRL SURVEY t'IETHODI RI::IDUIS OF CURVRTURE bJELL REFERENCE NO,' E&P30045 OPERRTOR', PH ILL IPS DRILL COURSE DRIFT RING -VERTICRL DEPTH-- DEPTH LENGTH DEC DEC COURSE TOTRL ------------. --------.-- ~________ 445.8 445.8 · 25 445.8 445,8 587. B 62.8 · 25 62.8 587.8 578.8 63.8 .88 63.8 5?8.8 658,8 88.8 .88 88.8 658,8 715.8 65.8 .58 65.8 ?15.8 743.8 28.8 2,88 28.8 ?43.8 773.B 38.8 4.25 38.8 ??2.9 886.8 113.8 7.58 112,4 885.3 977,8 9t.8 9,25 90,8 9?5.4 1878.8 93.a 11.75 91.4 1866.8 1166,8 96.B 14.58 93,5 1168.3 1268,8 94.8 17.58 98.3 1258.6 1353.8 93.B 28.25 88.8 ]338.6 1587,8 154.8 19.75 144,? 1483,3 1683.8 96.8 21.25 89,9 1573,2 1697,8 94,8 24.25 86.? 1659.9 1798,8 93.8 26.25 B4, l 1744.8 1856.8 66.8 27.75 58.8 ]882.8 1975.8 119.8 32.88 183.2 1986.8 2866.e 91.8 35.58 ?5.7 l~el.? 2158.8 92.e 39.88 ?3.2 2854.9 2253.e 95,8 48.58 73.e 2127.9 2445.8 192.8 44.ee 142,1 22re.e 25]8.8 65.8 45.25 46.3 2316.3 2618.8 188.8 45.25 78.4 2386.? 2691.B 81.8 45.58 56.9 2443.6 2785.8 94.8 46.25 65.4 2589.8 28F?.8' 92.8 46,F5 63.3 25F2.3 2982,8 185.8 46.25 72.3 2644.6 3189.B 127,8 45,25 88.6 2733.2 3292.8 183.8 44.25 138,8 2863.2 34?9.8 ]87.8 43,25 ]35.1 2998.3 3635.6 156.6 42,25 114.6 3112.8 3?36.6 95,6 42.56 76.2 3183.8 3855.6 125.6 43.66 91.8 3274.8 4642.8 187.0 44.88 135.6 3418.5 4233.6 191.8 44.75 136.5 3547.8 4666.6 373.8 46.68 262.8 3889.6 4793.8 187.B 46.88 129,9 3938.9 'RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage klELLI DR IFT D IR RZIHUTH 165 I?B 166 180 175 199 217 226 22? 226 226 226 226 225 225 225 226 22? 22? 227 228 ' 228 228 22? 22? 228 228 228 22? 22? 226 225 226 226 22? 228 229 231 232 DRTE; 8,/23/'?'6 LERSE RI'II) TERCT; HC l ---COURSE DEPRRTURES--- H,'S E.,'U ---------- --------,~, -.96 ,26 -,26 ,66 -.14 -,29 .6i -,60 -,67 -1.44 -.76 -6,65 -?.66 -9.12 -'9.61 -11.67 -12.29 -15.14 -15,69 -18.68 -19.64 -28,96 -21.64 -36.92 -37.57 -23.?? -23.?? -25,78 -25.79 -2?.88 -29.29 -28.63 -21.73 -48.42 -43.34 -34.4? -$6.9? -37.61 -4i.85 -48.65 -45.14 -96.37 -95.92 -36.65 -33.66 -48.43 -51.94 -38.95 -42.56 -45.15 -56.14 -44.65 -49.59 -51,45 -56,15 -62.e4 -66.53 -88.68 -93.45 -98.64 -92.23 -74.22 -r5.53 -44.49 -46.06 -58.41 -61.55 -86.96 -94.98 -88.51 -IEI6.04 -178.63 -26~3.35 -83,74 -105.27 TOTFIL DEPRRTURES UELL ®: ~ H,,~ E,'~ .88 -.96 .26 -1.23 .32 -1.37 .33 -1.37 .33 -1.65 .34 -2.25 .27 -3.69 -.58 -12.35 -8.15 -21,47 -17.?? -33.13 -38.86 -48.29 -45,?4 -66.27 -64.3? -67.17 -86.81 -124.89 -123.58 -147.66 -147.35' -t73,56 -t73,85 -281.36 -281,35 -221,99 -223.88 -262.48 -266,42 -296.88 -383,39 -334.49 -344.44 -375.14 -389.58 -461.51 -485.58 -492.35 -548.79 -571.11 -579.?3 -613.61 -624.88 -663.75 -669.54 -713.34 -728.99 -?69.58 -783.83 -*836.83 -871.?1 -'929.48 -962.35 -1821.71 -1636.57 -1897.24 -1881.85 -1143.38 -1139,46 -1204,64 -1226,42 -1299.74 -1314,93 -1399,78 -1495.56 -1683.13 -1569,29 -1708.40 jj i iL. F_..Ai~,.~ i i1~1~1 ~JVlll./i ilVll Yvl i~1~,1 ~llv Ely ..... ~ TSVL BPV(M~e,T~,~ ~-~ ~: 24.5' , ~.H~.~e.T~): ~T TC-IA [ ~-~F: ~.9' ~ F~: INHI~DWA~R ~ ~ F~ F~ P~C~ . ~-~: 118 , , ] T~: ~-ML: ~ 8U~A~ ~ 1~ ~ ~1 ~.~ H~ ~ _ " , '~o~, SURF~ ~; ' 4S.~ ~-M , 41~~;, 1~4~ 12.~ , , ~ , B~ ~ E?~ 4' 1~ 41~ 10.~ J-~ ~ ~10 ~ , ~ I ~ Tc-iA~NQ H~ ~ I X-O~R ~ I~,B~ ~X X 4' ~i.~ ~X 3.476 I 41 ~ 41~BU~E~Q., 3.~ 4.~ ~ 1 X-~R 31~ ~ X4 t~B~ 2.~; ~ " ~1 3 O~N~P~ ~81,~ 4~' I ~ ~ ~ ~ ~e~ ~ ~.~ 4.~ ] ~ 1 X-~R4 I~B~X8 ~~' 2.~ ,~7 , x-~.~,~~x4,~~' , , ~.~ ~.~ I 1~ I X-~R4' B~ X S l~E~ ~ ~.~ 4.7~ 1~ ~ 4' BU~ ~mNG ~ATe 4.~ 41~ ! X&O~R~I~B~ii~'X4'~ '" Z~ 4.7~ ~ . , 4~ 4 O~~NG ~ ~.8~ 4.~ 4170 ~1 ~I~BU~E~NG, , '% ,, ~.~ ~.G : XO ~ ~ O~ ~ P~R 2.7~ ~ 9 3 I~UP ~NT 2.~ ~17 4 O~ XO ~NG ~. ,, 2.813 4~ ~1 ~ ~ 31~ puP ~N~ ~ ~BINQ ,,. 2.~ ,~.~ ~Y G7-~ ~S: ~ 3 I~B~T ~N~ 2.~ 4.~ 4~S 14 3 I~PUP~N~ 2.~ ~A ~-~14 ~ ~ ~,1~ ~T ~N~ ~.~ I ~ B ~-~ ~ ~ 3,1~T~N~ 2.~ 4.~ ~ 174 ~ I~E~HG ~D PUP~H~ I 2.~ ~ ~ 4~-~74 4579' 1~ 31~B~T~N~ 2.~ 4.~ CI 2 ~-~ ~7 1~ 81~ ~T ~N~ ~ 2.~ 4.~ 4787 ~ 14 31~ PUP ~N~ 2.~ , .. 3.~ ~ 3 ~-~16 ~1 ~ ~ 31~T~N~ 2.~ 4~ .... I . ~4 , ~ ~" 70 31~T~N~ 2.~ 4.~ ~ 4 4~ ~71 ~ 3 1~ B~T ~N~ ~ 4.~ ~e ~-~ ~7 ~ ~T~ am 4.~ G7 ~ ~ 1~ BU~E~NG MD PUP~N~ ~.~ 3.G ~7 S137-517~ 51~ ~ S 1~ B~T~N~ ~.~ 4.~ St7S 10 S l~PUp~ ,. . ~.~ S.G ~7 sleT-S1K 5t~ 10 ~ I~B~T ~N~. 2.~ 4.~ ~8 ~-~ ~ ~ ~I~B~T~N~. .~.~ .4.G ~S 16 a I~PUP~N~ ~.~ ~1 ~ ~ 1~ B~E~ ~NG ~D PUP ~N~ 2.~ ~ , 3.~ ~ 18 ~ 1~ B~E~NG ~D PUP~N~ 2.~ 3.~ ~111 M~e-MT6 ~ ?0 ~I~T~N~ ~.~ ,,, 4.~ ~ M7~ ~ 3 I~B~E~NG ~D PUP~H~ 2.~ M K~ 814G-mM 8147 10 3 1~ ~T ~ 2.m 4.~ 8167 2 ~ I~PUP~NT ~.~ MKL~ 81~-~87 etH ~ 81~B~T~ " ~.m , ~7 , 1~ 31~NG~D~N~ 2.~ 3.~ M~L~ ~ ~14 ~ ~ ~I~T~N~ 2.~' 4.G ~18 ~ ~ 1~ ~BING ~D PUP~N~ 2.~ 3.~,, , ~ KL~ K-~78 Kt ~ ~ I~T~N~ 2.~ 4.~ ~1 ~ ~I~NG~DP~N~, 2~.,, i ~7 ~ 31~ B~ ~BING ~D PUP ~ 2.~ ~.~ X~ ~7 4 ~ xo ~NG ~ 2.81~ 4.~' ~7t ~ ~ 1~ ~E~ ~NG ~D PUP ~N~ ~ 3.G I M KLU~ 7078-~ ~71 ~ 31~T~N~ 2.~ 4.~ 7101 ~ ~ 1~ ~NG ~D PUP ~N~ 2.~ 3.~ M KL~ 71~-~ 7t~ ~ ~I~T~N~ ~ 4.~ " 714S ~ 8 I~NG ~D P~N~ 2.~ 8.G MK~ ~-~ ~ ~ ~ 91~T~N~ 2tm 4.G ~s ~ s I~NG ~DPUP~ ,, 2.~ M KL~ 7812-~7 7~ ~ 31~ ~ ~N~ 2.~ 4.~ 7~ ~ ~ ~ 1~ ~G ~D.pUP ~N~, ~ ] 'LKL~ 7~-~ 7~7 10 ~I~T~N~ "' ~.~ 4.G i 7~7 ~ ~ !~mNG ~D PUP~ , .. ~.~ ~ 7~ 1~ ~ ~ 1~ ~mNG ~O PUP ~N~ ~ ~.G 7~ ~ S 1~ PUP ~N~ ~.~ S.G LKL~ ~ ~IG ,~ SI~T~Nm t.~ 4.G ~ 8 ~ 1~ PUP ~N~ 2.~ ........ Q ~ I O~ Q NIP~ ~.~ 4.G ~47 ~ S~E~ , ~.~ 4~ _ ~_ ~ , , PB~ ' - . ~ 47 ~G T~ ~ ~D ~MU~ IN~ ~NG W~ AT 74~' AT ~T ~~NT _J L_ EXISTING CONDITION SCHEMATIC NCIU A-g: PAGE 1 OF 5 ,,, BPV(Make,Type,OD) RKB- DRILL DECK: 24.5' )- - Tbg. Hgr.(Make,Type): OCT TC- lA RKB-THF: 38.9' Annulut Fluid: INHIBITED WATER WITH METHANOL FOR FREEZE PROTECTION flKB-SL: 116 TOC: RKB-ML: 30' ~JRFACE 386 , 1~' SURFACE 631 65.63 H-40 10 3/4' SURFACl 2507 45.50 J-65 7' SURFACr +/-70 26.00 J-65 BUTT 5~50 4330 415000 7' +1-7C _~-__'58 23.00 J-55 BUTT 4980 3270 385000; : 7' 6858 7998! 38.00 J-65 . BUTT 56~0 4330 415000 4 1/2' 40 1,438 12.50 J-55 BUTT 6820 5730 198000 ~1 4' 1438 4165 10.90 J-65 BUTT 7210 . ~0 169200 3 1/2 4165 7749 9.30 J-55 BUTT 7980 7400 142500 RECEIVED MAY 1 4 1992 Alaska Oil & Gas Cons. Commission Anchorage EXISTING CONDITION 'SCHEMATIC NCIU A-9: PAGE 2 OF 5 39~ 1 OCTTO-1ATUBING HANGER , , 40 I X-OVER 4 1/2" BUT1'FE88 BOX X 4' BL, Fl"TFE88 BOX 3.478 41 239 4 1/2' BUT~ TUBIN{3 :3.~58 4.500 280 1 X-OVER 3 1/2' BUTTFE~ X 4 1~2' BLITTFESS 2.~2 281 3 OTIS TSV NIPPLE 2.813 4.2B~ 285 I X-OVER41/2'BLFTll:E~X3 1/2"BUTrFE~ 2.9g2 286 1151 4 1/2' BUTTFE~ CASING 3.958 4.5(30 1437 1 X-OVER 3 1/2' EUE 8FID X 4 1/2' BU'ITFE~S 2.9g2 5.2(30 1438 5! CAMCO KBM ~L 2.813 4.5Q~ 1443 I X-OVER 4' BUTII:E~ X 3 1/2' EUE 8FE) 2.9~; 4,750 .... 1444 2721 4' BUTTFE~ TUBING 3.476 4.0~30 4165 I X-(3NER :3 1/2' BUTtl::E~ X4' BUTII:E~ 2.~g2 4.750 ....................... 4165 ! 4 ~ XA ~LIDING SLEEVE 2.813 4.280 , , 4170 ;31 3 1/2' BUI"rFE~TUBING 2.9g2 3.500 4201 2 o'ns SLEEVE FELEA~ SEAL DMOER (ON-OF TOOL) 2.7a:) 4203 5 OTIS P,H PACKER 2.780 4208 9 3 1/~Z' PUP JOINT Z9~2 .... 4217 4 OTISXOSUDING ~LEEVE 2.813 4.280 CI STRAY 4247-4282 4245 20 3 1/2' BLA, S'T JOINT8 2.~82 4.5~0 42e5 14~ 3 1/2" PUP JOINT~8 2.9~ 3.5~0 ~r.~ ~=~ CIA 4284-4314 4279 40 3 1/2' BLAST JCIN~ 2.882 4.500 ~ 431~I 5 31/2. PUP J~NT 2.~ I 3.~0 ~_ ,, CIB 4330-44Q3 4325 80 i 3 1/2" BLAST JCINTS 2.882 4.500 4405 174 3 1/2" BUTTFESS TUBING AND PUP JOINTS 2.gEe EXISTING CONDITION SCHEMATIC NCIU A-9: PAGE 3 OF 5 44Q5 174e 1/2' BUTTRESS TUBING AND PUP JOINT8 2.952 [SO0 Gl I 4584-4674 4579 100 I 8 1/2' BI..ABT JOINT8 2.~2 4.500 487G 8 I8 1~ PUP JOINTS Z~ Gl 2 4eG~-478~ 4887 I 100 ' 8 1)2' BI. AST JOINT8 2.8~. 4.S(X) 4737 14 :3 l~d' PUP ~OINT8 2.~G~ 3.S00 Gl 3 d1~04-4818 4801 ~0 8 1/~' Bi. ABTJOINT8 2.8&?. 4.S00 48S1 2 8 1~' PUP ,JOINT8 2.~ ~.SO0 Gl 4 dl8S~--4G~O 4858 70 8 1~' BLABT~OINT8 2.88~ 4.530 4G~3 14 :3 1/~' PUP JOINTB 2.~ Gl 4 dlG4~--4GS~ 4G~7 ~0 :3 1~' BLASTJOINTB 2.8~. 4.S00 4~7 ~ ~ :3 1/2' PUP JOINT8 2.~ Gl S 4G8S-S020 4gG~ 40 :3 1/2' BLA~TJOINT8 2.882. 4.SQO S023 ~4 :3 1/'Z' TUBING AND PUP JOINT~ 2.GG2 :3.SQO Gl :3 Soeo-soes ~7 ~0 :3 1/2' BLASTJOINT8 2.8~ 4.54X) S087 48 $1/2' BUTTREBB TUBING AND PUP ~OINTS 2.~ ~.BQO Gl 7 S1:37-S172 SI~S 40 :3 1?2' BlAST.JOINTS 2.~. 4.SQO S17S I 10 I :3 1/2' PUP JOINTS 2.GG2 $.S00 Gl 7 S187-5195 S18S 10::3 1/2' BLABTJOINT8 2.~2 4.SQO 5195 30 3 1/2' BUTTRE88 TUBING AND PUP JOINT8 2.882 3.SQ0 524~ 16 :3 IN' PUP JOINT8 2.982 C:~ 5291 ~8 :3 1/2' BUTTRE88 TUBING AND PUP JOINT8 2.~ ~.530 ~Gl 9 5332-5357 5329 30 3 1/2' Bi.A, ST JOINT8 2.~2 4.500 535~ 18 :3 1/2' BUTTRE88 TUBING AND PUP JOINT8 2.982 3.SO0 Gl 10 5380-S395 5377 20.$1/2" BLAST JOINT8 2.882 4.500 EXISTING CONDITION SCHEMATIC NCIU A-9: PAGE 4 OF 5 Cl 10 53e0-~ 5377 20 3 1~ B~T ~1~ 2~ 4~ ~7 12 3 1~ ~P ~1~ 2.~ i 3~ ~11 ~16-~76 ~ 70 3 1~ B~I~ 2,~i 4.~ ~79 ~ 3 1~ B~S~BING~D ~P ~IN~ 2.~ 3~ M B~U~ 81~-61~ 6147 10 3 1~ B~T ~1~8 2.~ 4.~ 6157: 2 3 1~ ~P ~INT ~ 3~ M B~U~ 61~-6187 61~ ~ : 3 1~ B~T ~1~ 2~ 4~ 61~ ~ 1 3 1~ B~S ~BING ~D ~P ~IN~ 2.~ 3.~ M B~U~ ~-~ ~ 10 3 1~ B~T ~IN~ 2.~ 4~ ~7 1~ 3 I~BING~D~P~I~ 2.~ 3.~ M B~U~ ~-~14 ~ ~ 3 1~ B~T ~1~ 2.~ 4.~ ) ~19 ~ I 3 1~ ~BING ~D ~P ~1~ 2.~ 3.~ M B~ ~-~78 ~1 ~ 3 1~ B~T ~IN~ 2.~ 4.~ ~1 ~ 3 1~ ~BING ~D ~P ~INT8 2.~ ~ 3~ M B~U~ ~-~ ~ ~ 3 1~ B~T ~1~ 2~ 4.~ ~7 ~ 3 1~ B~ ~BING ~D ~P ~IN~ 2~ 3~ XO ~ 4 O~ XO 8E~NG S~ ~13 4~ ~1 ~ 3 1~ B~ ~BING ~D ~P ~1~8 2.~ 3~ M B~U~ ~6-7~ ~1 ~ 3 1~ B~T ~S ~ 4~ ~ 7101 24 3 I~ ~ING ~D ~P ~ 2~ 3~ L~ ~ ~ ~ ~ ~ 71~ ffi 31~NG~D~I~ ~ 3~ ~ ~ == ~ ~ ~ ~ ~ 3 1~ ~ING ~D ~ ~I~S ~ 3~ ~ M B~U~ ~12-7~7 ~' ~ 3 1~ B~T ~1~ 2~ 4.~ EXISTING CONDITION SCHEMATIC NCIU A-9: PAGE 5 OF 5 Id BELUGA 7312-7337 7308 30 a 1/2' SLAST JOINTS 3~82 4.500 ~ ~4 a 1/2' 'I3JBING AND PUP JOINT~ ~.~g2 ~.500 7393 144 ;3 1/2' 'rUBING AND PUP JOINTS ~oge2 a.500 7547 32 ~ 1/2' TUBING AND PUP JOINTS ~.~2 ~.500 L BELUGA 7581-7587 7579 10 3 1.2= BLAST JOINTS ~.882 4.500 7589 100 ;3 1/'Z' TUBING AND PUP JOINTS 2~e2 3.500 L BELUGA 7691-76g7 7889 10 ;3 1/'Z' BLAST JOINTS ~.882 4.500 78~ 20 ;3 1/2' PUP JOINT~ ~.~2 ~.500 L BELUGA 17724-7734 7719 20 ~ 1/2· BLAST JOINTS ~.~82 4.500 ~) 7739 6 3 1/2' PUP JOINT~3 2.~2 3.500 7745 I 3 1/2' BUTTRE88 COLLAR 3.325 4.250 {~ 7746 1 OTIS Q NIPPLE 2.625 4.500 I 7747 I 3 1/2' Bu'rI'RESS COLLAR 3.325 4.250 7748 1 X-OVER3 1/2' EUESRDX3 1/2' BUTTRE88 2.982 3.500 7748 Oll8 SHEAR SUB - END OF TUBING ........ ;..o ..... . .... , R[CI IVI £ DEWTIO.,? OEG Alaska 011 & Gas ConS. Commission Anchorage ,) TOP OF SAND ACCUMULATION INSIDE TUBING WAS AT 7450' AT LAST MEASUFEMENT TOP OF SAND IN ANNULUS IS UNKNOWN AND COULD BE AS HiGH AS 4400' ,,. LL PLANNED (~OMPLEI IUN 5(..;HEMAIIL; N(~IU A--9 BPV(Mike,TYI:)e,O0): RKO-DRIlL DECK: 24.S' 'n)g.H~'.(Md(e,T~l)e): OCT TC-IA RKI3-THF: 38.9' Annulus Fluid: iNHiBITED WATER ~ G~.¥COL FOR FREEZE PIK)TECTION R~-~L: I t · TOC: ~ - ML: 3~ SURFACE le SURFACE ~1 M.0~ H-40 103(4 SURFACE 2~? 4S.B) J-66 7 SURFACE 4-/-7C :::! J-B5 BuTr .90 4330 416000 ' +/-7C 6W J-65 ,UTF 4980 3270 366000 7 6858 789~ 26.00 J-E6 BUTT 6690 4330 415000 4 $/2 40 284 12.~0 J-66 BUTT 6620 6730 4 I/2 284 ~ 12.75 J-66 EUE 6RD 6620 6?30 198000 3 t/2 4649 52tC 6.30 J-S5 EUE 6RD 7980 7400 142600 2 7/6 52t 0 77~0.60 J-66 EUE 0RD 8300 7660 99700 4o ~414 1/2' B~ ~Nd(~ ~.$r~ 4.60o 28t ~ OTI8 8~$V NN:'PLE ~.613 6.76O · 64 $ X-OVER 4 1/2' 6RD EUE PIN X 4 t/2' BI,rrT BOX 3.8~, 4.~0 ~ ~ 4 t/"~ EUE 6RDTUBING 3.~ 4167 $ 8EALAgSEMBLY ~.~8D ! 4182 0 UPPER SEAL BORE W/RATCH A LATCH SF. AB~ LO00 0.0~0 41~ 2 SEAL UNIT FOR RATCH A LATCH HEAD 3,RSO 4~00 7 OTIS 'TYPE VSR RETRIEVABLE PACKER 4.O0O Gl STRAY4247- 434~ SQUEEZED CIA 4264-43t4 SQUEEZED CI 8 4,33O-44OO SQUEEZED 4207 ! 36~4 IN" TUSN~G AND PUP JOHdT8 3.06~ 4.600 4646 ~, SEAL UNIT FOR RATCH A LATCH HEAD 6.000 0.000 4667 7 Ol18 TYPE VSR RETRIEVABLE PACKER 3.M0 0.000 4574 4 4 1~ pup J(NNT~ 3.968 4.g~0 ' CI 1 4684-4674 4573 1004 1~2' BLABTJOHfT~ 3.~6 4876 8 4 1/2' PUP J(NNT8 3.96~ 4.500 CI2 4892-47m) 4~64 t004 1/8' BLA~TJO~T8 3.8~6 4764 2 4 1/2' PUP JOWLS3 6.966 4.600 47M 3 XA SUDff~G SLEEVE 3.913 4488 2 4 f/2'PUPJO~rF8 3.~8 4.~0 470t 2 SEAL UNiT FOR RATCH A LATCH HEAD 3.~0 6.000 4701 2 RATCH A LATCH RECIEVING HEAD 6.0GO 3.0C0 4706 3 OTIS TYPE BWR PERMANENT PACKER 4.OQO 478~ 4 4 1/8" PUP J ,CINT8 6.958 CI3 4804-4816 4800 20 41/2' BLAST JOINT8 3.W 4820 4 4 I/2'PUPJCINT8 3.8~8 4,600 4824 3 XO SLIDING SLEEVE 3.613 6.r~3 4527 2 4 1/2' PUP JOINT9 3.968 4.r~o CI3 4063-4846 4629 20 4 IN' BLAST JOflfTS 3.866 6.663 4646 6 SEAL A,RSEMBLY 2.9~2 4.000 4849 3 O116 TYPE AWD PERMANENT PACKER 4.000 ~ 0 8EALBOR~ EXTENSION 4.0Go 6.0~2 CI4 4055-4220 4280 70 3 t/2' BLAST JOINTS 2.8~2 4.SOO 4830 7 $1/2' PUP JCINT~ 2.952 CI4 4842-48~2 48~7 20 3 1/2" BLAST JCINT8 2.W 4.5G0 4867 RS 3 1~2" PUP JOINT8 2.882 CI6 dlS~--EOgO 42S2 40 3 t/2' BLAST JOINT8 2.8~ S022 ~S 3 IA"'TUSIHGI AND PUP JOINT8 2.~ Cie S060-208S S067 30 3 1/2' BLAST JOINT8 2.~ 4.SGO 602? 4 3 IN' PUP JOINT8 2.9S2 Kel 3 XA 8UD~ SLEEVE 2.616 EGG4 3 3 1/8' PUP JC)IN19 2.~R 6.500 S097 6 ~SEAL ASSEUBLY 2.~ 4.O430 SOG? 3 OTIS TYPE AWD PERMANENT PACKER 4.0C0 6120 01 8F. AI. BOP. E EXTENsION 4.0QO 6.0,~ 610~ 27131/2P Pup ,J(X, NI'8 a~w CI7 6137-6172 6136 40!3 1/2' BLAST JO4NT8 2.~12 4.5~O 6t76 t0 3 tN' PUPJO~IT~ 2.9~2 6.600 ~7 6167-61~ 6106 10 3 1N' BLAST JOg4T8 2,~2 4.600 6106 4 3 IN' PUP JOWT8 2.992 3.600 ~1e9 3 xo 8UDiNG SLEEVE ~.613 4.K0 62O2 0 3 tj2' PUpjOINT8 2.e~ 3.6OO 6210 ~ SEAL AgSEMBLY 2.e~ 4.0e0 62~0 $ OTIS TYPE AWD PERMANENT PACKER 4.0(~ S213 0 SEALBOR~ EXTENBK~N 4.000 ~221 8 2 7/8" PUP JOINT8 2.441 S,675 Cie , r~2-6242 r~27 20 27/rBLA~TJOINT~ a. M2 6247 14 2 7/r PUp dOl~T~ 2.44~ 2.875 Cie 6264-s216 626t 20 27/rBLASTJOiNT8 · 2~62 ~26t ~i 2 7/8' TUel4G AND PUp JC)~ 2.441 2.075 Cl0 ~S3,~-r~S7 , 06~ ~0 27/rBLASTJOWTS 2.~ 0666 16 27/8~.TUSINGANO PUP JOINTS 2.441 2.i~ ¢110 6M6-S~ 52?7 20 2 ?/r BI~T JCINT8 2.~2 0667 14 2 T/8" PUP JCINT9 2.44t 2.6~ CItt 1 64t0,647~ 64tt 70 2 7/8' BLAST JCINT9 2~2. 64~1 0 27/r PUPJOg4T 2.441 2.875 5487 8, )CA 8UDINQ SLEEVE 2,3t3 3.e68 5490 t0 2 7/f' PUP JOINT 2.44t 2.875 K00 6 SEAL ASBEIH3LY 2.3~0 0.000 3500 S OTIS TYPE AWD PERMANENT PACKER 3.23) 0.000 SS03 0 GEALBORE EXTENsION 3.250 6.6Q0 661t 3t 1 JT27M"J-6SEUE 8RDTUB~4Q 2.441 2.875 6642 3 XO 8UD~4Q SLEEVE 2.313 3.669 6645 216 27/rTUB~4QAND PUPJO~fT8 2.441 2.075 6770 ' 676 2 7/8' TUB~Q AND PUP JOLT8 2.44t 2.075 M BELUGA6t49-6164 6148 10 27/rBLASTJOgfT8 2,M2 6166 3 27/8' PUpjo~rr 2.44t 2.675 M BELUGA01~2-01~ 0168 20 27~rSLASTJO~T8 0.~2 3tRS RS 27/rTUS~K~AND PUPJOMT8 2.44t 2.675 M BELUGA6RSO-~ 067? 10 2 7/r BLAST JO~IT8 2.3~2 ~2~? 10~2?/8'TUB~ANO PuPJo~rt8 2.441 2.075 M BELUGA&164-~4t4 e3ee 2027~"BLABTJOINT8 2.~2 6.M8 6419 4127~'TUBINGAND PUPJOeIT8 2.441 2.675 M BELUGA: 6483-~475 ~ 2027/rBLA~TJO~rs. 2.362 3.068 M BELUGA0772-~642 6707 062 7/r BLAST J(NNT8 2o3~2 ~M? 224 2 7/r TUB~4G~ND PUP JON4T9 2.441 2.675 M BELUGA7076-7008 707t . ~0 2 7/r BLAST JOgfT8 2.3~2 7for RS2 ?/r TU~Q ANO PUP JOWT8 2.44~ M BELUGA7t'32'7142 7127 202 7/r BLAST JO~r~ 2.3~2 7147 RS27/rTUB~QAND PUPJO~T~ 2.441 2.675 M BELUGA7240-7270 7236 402 ?/8' BLAST JO~fT8 2.362 7276 ~42 ?~P TUBg4Q AND PUp JO4NT8 2.441 2.075 M BELUGA7312-7337 720~ 202 I/r BLAST J .O4NT9 23~2 7339 RS2 7/8' TUB~ AND PUP JOMT8 2.441 2.675 L BELUGA7373-73~0 7374 RS2 7/8' BLAST JO~l~ 2.3~2 3.066 73~4 142 2 7/r TUBNdG ANO PUP JONfT8 2,44t LBELUGA 75M-7644 706~ 1027/rBLABTJO~T8 2342, 7642 ~327/rTUS~K~AND PUP JOlT8 2,441 2.675 L BELUGA7f41-7947 7678 102 7/r BLAST JOgfT8 2.~ ~49 100 27/rTUBINQAND PUPJ~ 2.441 2.075 L BELUGA788t-7887 78~9 fO;2 TM' BLAST JOINT~ 2.M2 768~ 202 7/8" PUP J(NNT~ 2.441 LBELUGA r724-7734 7710 20, 27/8' BLASTJO~T$ 23~2. 3~. 7726 611 JT 2 7(8' ~ TUBING 2.44~ 2.675 7770 I Or118 XN NIPPLE '~ ' 2.2~ 2.675 7771 10PUP JOINT ' ~ ~ i :~ 2.44t 2.675 7781 '1WIREUNE REENTRY GIUDE ~ 2.441 2.675 DRIU.ED IN 19~. COMPLETED IH 1076 DEVIATION 47 HIQHLIGI.~rE~ U INTERVALS DEKrlFIED M UPPER eELUOA PAY I~l I°6? FIESEFNCIR S'T1JOY BUT ~ NOT BEEN PERFORATED _~ I PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 1 ._ 5500 3 OTIS TYPE AWD PERMANENT PACKER 3.250 6.000 5503 8 SEAL BORE EXTENSION ' 3.250 5.500 " 5511 31 I JT 2 7/8" J-55 EUE 8RD TUBING 2.441 2.875 ~ ' 5542 3 XO SLIDING SLEEVE 2.313 3.668 5545 215 2 7/8°"'TUBING AND PUP JOINTS 2.441 2.875 ii~'"":'"i'"i?'::'":::':i~! ~:~:~::~:~:~:~:~:~i:i:i::~:~:~:~:~:~:~:~::i:~ii:i:i:i:iiii:i:i~:~::~:~:~:~:~:~i: ::::::::::::::::::::::::::::::: ,.!:':':::':':'":':i~i:'"':"i::'::"+"i'i ..-i~-.:.....:.:...;.:...: :i :i iiiiiiiiiiii ~i!iiiiii iii iiiiiiiii .... · ..~:~!~.L':.~ ........ ~6~.:.-:.!~!!! ........................ 5~.6~..:~ ::::::::::::::::::::::..O..:: I!:i.2.'i~61:::!B..'~:~!:!~i:i:!:~:i:i:!:!:!:~:!~!:!:~:~:!:!:! ........................... :,::;:,:i::,:i: 2,362 3.668 5770 376 ! 2 7/8" TUBING AND PUP JOINTS 2,441 2.875 M BELUGA 6149-6154 6146 10 !2 7/8" BLAST JOINTS 2,362 3,668 6156 3 i 2 7/8" PUP JOINT 2,441 2.875 M BELUGA 6162-6187 6159 30 !2 7/8" BLAST JOINTS 2,362 3,668 6189 88 i2 7/8" TUBING AND PUP JOINTS 2,441 2,875 M BELUGA 6280-6285 6277 10 i'2 7/8" BLAST JOINTS 2.362 3.668 6287 102 i2 7/8" TUBING AND PUP JOINTS 2,441 2,875 M BELUGA 6394-6414 6389 30 ;2 7/8" BLAST JOINTS 2.362 3,668 6419 41 ; 2 7/8" TUBING AND PUP JOINTS 2.441 ' 2.875 M BELUGA 6463-6478 6460 20~ 2 7/8" BLAST JOINTS 2.382 3.668 6480 287 '2 7/8" TUBING AND PUP JOINTS 2.441 2.875 M BELUGA 6772-6842 6767 80 2 7/8" BLAST JOINTS , 2.362 3.668 6847 224 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 M BELUGA 7076-7096 7071 30 2 7/8" BLAST JOINTS 2.362 3.668 7101 26 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 M BELUGA 7132-7142 7127 20 2 7/8" BLAST JOINTS 2.362 3.668 7147 88 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 M BELUGA 7240-7270 7235 40 2 7/~' BLAST JOINTS 2.362 3.668 7275 34 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 M BELUGA 7312-7337 7309 30 2 7/8=" BLAST JOINTS ' 2.362 3.668 7339 35 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 L BELUGA 7379-7389 7374 20 2 7/8" BLAST JOINTS 2.362 3.668 7394 142 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 L BELUGA 7539-7544 7536 10 2 7/8" BLAST JOINTS 2.362 3.668 7546 33 2 7/8' TUBING AND PUP JOINTS 2.441 2.875 L BELUGA 7581-7587 7579 10 2 7/8" BLAST JOINTS 2.362 3.668 7589 100 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 L BELUGA 7691-7697 7689 10 2 7/8" BLAST JOINTS 2.362 3:668 7699 20 2 7/8' PUP JOINTS 2.441 2.875 L BELUGA 7724-7734 7719 20 2 7/8" BLAST JOINTS 2.362 3.668 7739 31 I JT 2 7/8' 8RD TUBING 2.441 2.875 7770 1 OTIS XN NIPPLE 2.205 2.875 7771 10 PUP JOINT 2.441 2.875 7781 1 WlRELINE REENTRY GIUDE 2.441 2.875 7782 END OF TUBING 7950 PBTD R£E'£iV£D MAY 1 4 1992 Alaska 011 & [~a~ Oon~, Commissio. Anchorage PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 2 ::i::i::iiii:~:::~ii::i:::~ii::!ii::ii:~i:~::ii!::ii:.i:.::::i!:~!:~:::~i:~i:~iiiiiiiiiiii::ii~::~::~?:~i% :,i::ii!i!i:.~i!iiii ii:.::iiii~iiiii:: ::~i!i~::~i~iiiiii::iiiii!iiiiiii!i!i::~::ii~i~iii~iiiiii!iiiii?:~::i!iii::i::i::ii!ii~!~iiiii!iii!~i~i!i!i:.ii:.!~!iiii!~!!~!:.i::~::~i i! iii~ ~ ~13 8 S~ ~E ~SI~ 4.~ 5.~ ~1 6 2 7/8' PUP JOl~ 2.~1 2.875 CI 8 52~-~42 ~7 ~ 2 7/8' B~T~I~ 2.~ 3.~ 5247 14 2 7/8' PUP JOl~ 2.~1 2.875 CI 8 ~-~ ~1 ~ 2 7/8' ~T~I~ 2.~ 3.~ ~1 ~ 2 7/8' ~BING ~D PUP JOl~ 2.~1 2.875 Cl 9 ~-~7 ~ ~ 2 7/8' B~TJOI~ 2,~ 3.~8 ~ 18 2 7/8' ~BING ~D PUP ~1~ 2.~1 2.875 CI 10 ~-~5 ~ ~ 2 7/8" B~TJOI~ 2.~ 3.~ ~7 14 2 7~" PUP ~1~ 2.~1 2.875 Cl 11 ~16-~76 ~11 70 2 718' ~T~I~ 2.~ 3.~ ~1 6 2 7R' PUP ~1~ 2.~1 2.875 ~7 3 ~DING ~ 2.313 3.~ ~ 10 2 71g ~P ~1~ 2.~1 2.875 ~ 5 ~~~Y 2.~ 3.~ RECEIVED 8 ~ ~ ~~ 3.~ 5.~ Alaska 0tl & 9~ Cons. Oo~nmt~ton Anol~orage _~ L_ PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 3 :::~~.'~ ::~i~i~?i::ili::::iiil Iii!ii::?:i~?:i::?:!i !!i!ii~::i i:.i:.?:ili~i:.::ii::::::::::?:?:::i::i!:.i~ii:::.~i~:.~i~i~~ii!:: :: ?: i ::ii ii::ii:.::iiii!:: ?iii :::.:: i!iii !i::i?:iii?:iii::i?:::i::iiiii!iiiii::iii::i:: iiiii iiliii i iii:: i i ?: il i i :: i iD i i ii ii :: i i:: :: ii i iODi ii :~: i ~7 3 OTIS ~PE A~ PER~E~ PACER 4.~ 6.~ 51~ 8 S~ BO~ ~NS~N 4.~ 5.032 51~ 27 3 1~ PUP ~1~ 2.~ 3.500 CI 7 5137-5172 51~ ~ 3 lff B~T ~1~ 2.~ 4.500 5175 10 3 1~ PUP ~1~ 2.~ 3.500 Cl7 5187-51~ 51~ 10 3 1~ B~T~I~ 2.~ 4.5~ 51~ 4 3 1~ PUP ~1~ 2.~ 3.500 ~ XO 51~ 3 XO SLIDING ~ 2.813 4.5~ ~ 8 3 1~ PUP ~1~ 2.~ 3.~0 5210 5 ~ ~EMBLY 2.~ 4.~0 ~10 3 OT~ A~ PACER S~ ON ~B~EMBLY 2 4.~ 6.000 ~13 8 S~ BO~ ~NSION 4.~ 5.032 RECEIVED _J L PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 4 4~ 8 ~S~ ~RE ~NSION 4.~ 5.032 Cl 4 ~-49~ ~ 70 ; 3 1~ B~T ~1~ 2.~ 4.500 49~ 7 3 1~ PUP ~1~ 2.~ 3.5~ Cl 4 4~2-49~ 4937 ~ 3 1~ ~T ~1~ 2.~ 4.5~ 4957 25 ~3 1~ PUP ~1~ 2.~ 3.~0 CI 5 4~-~ 4~ ~ 3 1~ B~T ~1~ 2.~ 4.~0 ~ ~ ~3 1~ ~BINGAND PUP ~1~ 2.~ 3.~0 CI 6 ~-~ ~57 ~ 3 1/~ ~T ~1~ 2.~ 4.~0 ~7 4 3 1~ PUP ~1~ 2.~ 3.~ ~ ~1 3 ~ SLIDING ~ 2.813 4.~ ; i ~ 3 3 1~ PUP ~1~ 2.~ 3.~ ; , i ~7 5 S~ ~EM~Y 2.~ 4.~ ~ ~7 3 OT~ A~ PACER S~ ~ SU~EMBLY 3 4.~ 6.~ ; 51~ 8 ~ ~ ~~ 4.~ 5.~ ....... ~..~ nnme [ission Alaska UI! ~ u~o" ....... Anchorage m L. PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 5 4791 2 RATCH A LATCH RECIEVlNG HEAD 5.030 6.030 4793 3 OTIS TYPE BWR PERMANENT PACKER 4.030 6.000 4796 4 4 1/2' PUP JOINTS 3.958 4.500 CI 3 4804-4816 4800 20 4 1/2' BLAST JOINTS 3.865 5.563 4820 4 4 1/2' PUP JOINTS 3.958 4.500 XO 4824 3 XO SLIDING SLEEVE 3.813 5.563 4827 2 4 1/2- PUP JOINTS 3.958 4.500 Cl 3 4833-4848 4829 20 4 1/2' BLAST JOINTS 3.865 5.563 4849 5 SEAL ASSEMBLY 2.992 4.000 4849 3 OTIS AWD PACKER SET ON SUBASSEMBLY 4 4.000 6.000 I SEAL BORE EXTENSION 4.030 5.032 RECEIVE:D MAY 1 4 1992 Alaska Oil & Gas Cons. C~mmission AnChoral)e PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 6 OTIS TYPE VSR RETRIEVABLE PACKER 41/2' PUP JOINT~ 41/2' BLAST JOINTS 41/2' PUP JOINTS 41/2' BLAST JOINTS 41/2' PUP JOINTS XA SUDING SLEEVE 41/2' PUP J(~NTS SEAL UNIT FOR RATCH A LATCH HEAD (NO LATCH) RATCH A LATCH REClEV~IG HEAD SET ON SUBAS,~EMSLY 5 OTIS BWR PACKER SET ON SUBASSEMBLY 5 CI 1 CI 2 RECEIVED Ala~a Oil & Gas Coos, Co~tmiSs~r Anct~ra~e _J L_ PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 7 4200 7 OTIS TYPE VSi=I FIETRIEVA~LE PACKER 3.880 6.000 CI STRAY 4247-4262 SQUE;7~=n 4284-4314 Ct B 4330-4400 i SOU~=~'Tm3 4207 358 4 1/2' TUBING AND PUP JOINTS 3.958 4.500 4585 2 ~ UNIT FOR RATCH A LATCH HEAD 5.000 6.000 I I 4567 7 OTIS V~R PACKI~ ~ ON ,~dBAS~EMBLY 6 3.880 6.000 RECF_..IV ED 0il & Gas Cons. Commission __~ L PLANNED COMPLETION SCHEMATIC NCIU A-9: SUBASSEMBLY 8 _ _ ::i~~ ::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::: !::!::!~!i::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::: ::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::: 39 I TUBING HANGER 40 241 4 1/2' BU'ITRESS TUBING 3.958 4.500 SC;SSV 281 3 OTIS SCSSV NIPPLE W/1/4' SS CONTROL LINE 3.813 5.750 XOVER 284 5 X-OVER 4 1/2' 8RD EUE PIN X 4 1/2' BUT[' BOX 3.958 4.500 289 3898 4 1/2' EUE 8RD TUBING 3.958 4.500 4187 5 SEAL. ASSEMBLY 3.860 5.000 4192 6 UPPER SEAL BORE W/RATCH A LATCH SEALS 5.000 6.000 4198 2 SEAL UNIT FOR RATCH A LATCH HEAD 3.860 5.000 I I 4200 7 OTIS TYPE VSR RETRIEVABLE PACKER 4.000 6.000 'RECEIVED MAY 1 4 1992 Alaska 0tl & ~as Cons. (;ommissior Anchorage NCIU RESERVOIR PRESSURES BASED 'ON SUNFISH RFT DATA 8000 4OOO 5OOO 6OO0 TVD COOK INLET 8 ............................... .C...O....O....K....!..N...L..E...T...!.~, COOK INLET 11:'.. C..OOK INLET 7 oo~.~ ~N~ET * .. : .: UP:P ER BELUGA : : '. .. :.MIDDLE BEL~.GA : : : : I \1 0 500 1000 1500 2000 2500 RESERVOIR PRESSURE(PSI) 3000 NCIU RESERVOIR PRESSURES BASED ON A-1 PRODUCTION LOG 8000 4OOO 5OOO 6OOO 0 TVD ~¢ ',.¢ 5.0 '....o ......................................................... · ~ ........... ~. ........... .'., .......... :. ....................................................................................................... · .. ... '. .. · .. : -~ .. ; ", COOK INLET A, B, I AND 2 ............................... ~'~'~'~'"i"~'~'~'~'i"~ ..... 'f'il .......... ':i .......... :~':.: ..................... ~ ............................................................... COOK INLETX8 '~'~ "~.~. '"'\ -- '"'.. COOK INLET 10 ', ........................................................................... · .. .............. '.. .............. ~,. .............. ',. ........................................................................... -. · . : 500 1000 1500 2000 2500 8000 RESERVOIR PRESSURE(PSI) RECEIVED MAY 1 4 1997_. Alaska 0ii & Gas Cons. Commission Anchorage NCIU RESERVOIR PRESSURES BASED ON A-3 PRODUCTION LOG 3OOO 4OOO 5OOO 6OOO TVD '0 500 1000 1500 2000 2500 RESERVOIR PRESSURE(PS1) 3000 RECEIVED MAY 1 z~ 1992 Alaska Oil & Gas Cons, Commission Anchorage NCIU RESERVOIR PRESSURES BASED ON A-7 PRODUCTION LOG TVD 3000 4000 ~1~c°°'';'.~ '"~ s COOK INLE¥ 4 ~. '\. '\. COOK I N L E ~'-.,.. 8 "~.. I 6000 500 1000 1500 2000 2500 RESERVOIR PRESSURE(PSI) 3000 RECEIVED MAY 1 4 1992 Alaska 0ii & 6as Cons. Commission Anchorage NCIU A-9 RISER AND BOP ARRANGEMENT I I I I 6M ANNULAR PREVENTER 10M VARIABLE BORE PIPE RAMS 10M BLIND RAMS DRILLING SPOOL 3 1/2' 10M 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 ]ADAPTER 16 3/4' 6M CLAMP X 9' 3M TUBING HEAD 9' 3M X 11' 3M RECEIVED MAY 1 4 ~992 Alaska 0il & Gas Cons. Commission Anchorage NCIU A-9 WORKOVER PROCEDURE Vendor List Service Vendor Drilling Rig Pool Arctic Alaska Cement and Pumping Dowell-Schlumberger Services Workover Fluid M-I Drilling Fluids Well Testing Production Testing Equipment (surface) Service Schlumberger Drill Stem Test Tools (downhole) Nitrogen Pumping Service Wireline Logging Tubing Conveyed Perforating Wellhead Equipment and Service Rental and Fishing Tools DowelI-Sclumberger Schlumberger Vann Systems FMC Tri State Rental Tools* Homco Rental Tools* DSR Companies Coiled Tubing Service Arctic Recoil Helicopter Service Kenai Air Supply Boat Seacor "Mustang Island" PVT system and Totco service Contact Telephone Larry Ross (907) 276-5464 Jack Archer (907) 283-7165 Bob Haagensen (907) 274-5564 Robert Hoff (907) 258-2022 Lance Dunn (907) 562-2654 Jack Archer Lance Dunn Stan Weaver (907) 283-7165 (907) 562-2654 (907) 283-7812 (907) 563.3990 (907) 776-8791 (907) 522-3234 Alvan Walker (907) 283-1980 (907) 283-7561 (907) 562-7602 * Additional rental tool companies are listed to provide flexibility in the event Tri State is unable to provide all the tools required. RECEIVED MAY 1 z! 1992 Alaska 0il & G~ G~S. Cornmissi0r, NCIU A-9 WORKOVER PROCEDURE Telephone List Position Drilling & Production Engineering Manager Kenai Area Manager Drilling Supt. ,, Drilling Engineering Director Drilling Engineer Production Engineer Reservoir Engineer Materials Coordinator - Kenai Material Coordinator - Houston David Gill Roy Lyons Walt Carrico Wes Gibson Dennis Morgan Fritz Krusen Joe Voelker Jim Magee Mary Laws Office Number (713) 669-3519 (907) 776-8166 (907) 776-8166 (713) 669-2969 (713) 669-2173 (~07) ?~-~ (907) 776-8166 (713) 669-3712 Safety Specialist - Bob Wirtanen (907) 776-8166 Kenai Alaska Oil and Gas Lonnie Smith (907) 279-1433 Conservation Commission A{aska 0%% 8, Sas Gons. (3ommlssion REV. 1-10~73 Submit "Intentions" in Triplicate I & "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 I~ OTHER NAME OF OPERATOR Phillips Petroleum Company 5. APl NUMERICAL CODE 50-283-20029 6. LEASE DESIGNATION ANO SERIAL NO. ~DL- 37831 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8.1~~ FARM OR LEASE NAME 3. ADDRESS OF OPERATOR 9. WELL NO. P.O. Drawer 66- Kenai, AK 99611 A-9 10. FIELD AND POOL, OR WILDCAT 4. LOCATION OF WELL At surface Leg 2, Slot 4, 1310.6 FNL, 1019' FWL, Sec. 6 TllN, R9W, S.M. BHL 1132' FSL, 2692' FEL, Sec. i TllN, RiOW, S.M. 13. ELEVATIONS (Show whether DF, RT, GR, etc.) RKB 116' from MLLW 14. CheCk Appropriate Box To Indicate Nature of Notice, Re 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See It em 4 BHL 12. PERMIT NO. 69-85 )ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF l~ PULL OR ALTER CASING FRACTURE TREAT ~ MULTIPLE COMPLETE SHOOT OF{ AClDIZE ABANDON* REPAIR WELL CHANGE PLANS (Other) SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ FRACTURE TREATMENT SHOOTING OR /1CIDIZING (Other) Clean out & Perf REPAIRING WELL ALTERING CASING ABANDONMENT* (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCR IBEPROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work, SEE ATTACHED "DAILY REPORT DETAILED" 16. I hereby . . lng is true and cTect l~e J3~e ru.I.- u~r' TITLE ~:[', Petroleum EnEr-. DATE (This space for State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY: TITLE DATE See Instructions On Reverse Side DAILY REPORT DETAILED LEASE NC~U WELL NO. A-9 SHEET NO. 3 TOT AL ................ ~ *~ ............. .. ~U2,~ :20, .19~ 10 ~ r~~ ~ ~ sea water do~ ~~ of ~ ~9 t~ ~lieve ~ess~e on ......................... e~ before mo~ r~ .... aug~ 6, ~975 Present Operation: Prepare to pull tbg. Finish skidding rig from Well A-10 to A-9 and rig up. Circulate and kill well with ll.B mud install Otis BPV, Remove Christmas tree and nipple up BOP, Test BOP/Riser to 2500 PSI ~ 15 min. O.K. Prepare to pull tbg. August 7, 1975 Preseut Operation: Circulate end condition mud. Pulled up to remove ball valve, gas drop under same, circulate out, remove bell. valve. WIH, tag top of fish packer, had moved down hole 207'. Attempt to get through of seal divider to made sure dogs were in latching position, could not get Otis shifting tool through top half of Otis seal diw-lder. COOH, lay down tbg, GItt with L~7/8 Bowen spear, Jars and bumper sub B, h B/h inch drill collars on B 1/2 inch drill pipe latch spear in top of packer at hhl~, work tbg loose~ pull 60' pipe drag at 50,000 lbs, pull 60 more feet drag dropped to lO,O00 lbs. Circulate out through circulate sub above spear. ~.~ill now condition ~.ud. August 8, 1975 Pulling tbg. Laying down be~t tbg. Finished circ out above pkr. -Pulled drill pipe and standing derrick. Ld pkr. Slips worh out from dragging. Ld fishing tools. Otis made two trips with wire line to open XO sleeve at 6871. Ctrc out B 1/2 tbg. Circ gas out of hold and cond mud. Now pulling ~ 1/2 tbg and blast Jts. Ld crooked tbg. August 9, 1975 Circulating at 77B0, finished laying down bent tbg pups end blast Joint. Pick up 6" bit end Csg sc2aper on B 1/2" drill pipe, hit sand bridge at 77B0. August 10, 1975 GIH with production string, finish circulating out at 77B0 clean sand out of hole to 7950 plus "D". COH lay down drill pipe collar scraper and bit, start running production string. August 11, 1975 Present Operation: Prepare to flow well Fi~shed running production string install Oct BPV test ball valve, remove BOP NU Christmas tree remove BPV, displace mud in hole with water, pump 10.5 PH water behind packer. Now preparing to bring well in. August 12, 1975 Present Operation: Blowing water out of hole Opened OX sleeve at h211 flowed water out of tbg, opened sleeve at 6871 well flowed, well cleaned up. WIH, closed sleeve at h211, well loaded up and died. i~IH wit Otis to open sleeve at h211, b~oke off sinker bar, left 5 bar~, ~~. ~. ~ ~ ~ars and shifting tool. WIHwith over shop~ recovered sleeve leaving 3 ~ ~ars, recovered s~me with two runs with I 1/2" overshot. Open sleeve at ~211, flowed well - close sleeve end flowed well through sleeve at 6871, t~g ~OV ~ ~ 1~ '~'ioaded up and died, opened sleeve at 42hl, flow water out of tbg. end close ?-~. ' sleeve - flow well through sleeve at 6871, close sleeve, flow well through ~" "~"~;"'~,,~,~?'~'r-. :L. ~: ~:L:,!L AND ...... ~ttom of tbg Well loaded up 'with water aud died. Now will open sleeve ,4,.'~,,...?~OR,'-,'"" ~,~,_...~. back up at 6871. "~"'~// ~.,.~.z~.~--~, ~.--.,...~-/-'/"~-~--~ ~/~'~,.'~.--'~-~---~.~ ~,'~-"",~/~'..'=' Form 911 1-69 Printed in U,S,A. ,~ -',,., · ,' , Form No.' G-I RE¥1$ED : JAN. I, 1969 O STATE OF ALASKA IL AND GAS CONSERVATION COMMI~EE 1975 GAS WELL OPEN FLOW POTENTIAL TEST REPORT 4-POIX~ TEST Test · · Initial ~ Annual D Special /~,~/_?,,,, ~._ 7T,-.,,, ,,,..: ~?~-~.~z C' ':.'- -:~.'~"~ ~..n ?,.~,. :.. . >.-..z'.~/., //'2,': ;'~'~ ~-,','.,' "' ... ,//~, <, ~-, ~. " ..... ~';'~. ~ ~ -'.-' . Total Depth _ TBG.. [ CSG. Temp~ratur~ Temperature ~-, , }~ . ] , .._, Multiple Completion ~Dual or Triple) ~'. '" Type..pro~uc{~on from each zone OBSERVED DAT~k Flow Data ~';~(:~.: .... Press.:~i,: · ,,.,! Diff, Tubing Casing , l;'lowing ' NO. of Flow" ' ' .(Line)., ' ""(Orifice)', .' ' - .,, ' ' '. ~ 'h' ' 1 Press. Press. Temp. Hours ' . ' Size Size pstg ., w pslg pslg 'F , ..... ' /,.¢~,~ ' ST ', ' ' /0 ' ,. _ .--¥'.V..~ . ?,,Y~O /~.'o~ ': ~ /~ /~. ~q . :. / " . " / ~f .¢ ~'~ /_~q . ,,~ ~8 , ,, ,, //~ ~. /~ /5 .~ . ~. ~ 5. .,' , " //:~ ,~P /~~ , /~,,, ,~5 .. FLO~V CALCULATIONS · Coeffi- ..... -, Flow Temp. Gravity Compress. , ~o. clent ---~/h p Pressure .:' ·,Factor ' Factor Factor ' Rate of Flow (24 Hr.)ld w m psia ' , F "' ,. ' F , F .Q I~ICF/D t ' g .p¥ · , :.. . ~_~ c /.7) .//-. ' z ~:,~ ~'' " / ,~e;/ /~ .~ 72, · ' ' ~ ~' ~' ' ' · t · ,-~ , , . .. - PRESSURE CALCULATIONS .Absolute .:Potential / [ n · 69, ~<~,?- ~,~ci,'/r, · ~ I CERTIFICATE: I, the undersigned, state that I am the /~' (' ~t-';,,~ . . ~ o! the' '~':' ~ ~ "~ ~D'..5 :'-, ~, ,-.';~ ~ ....... (company), ~d ~at I am au~or~ed by said comply to make ~is report; and that th~ report was pre- , p~ed ~d~ my su~sion ~d direc~on ~d ~at ~e fac~ ~t~ed there~ are t~~~,~d complete to ' o ... ~ ~ ....... -r-,-r--'---~ --r -7' '"'TT"c~.~'- - ". !: · , ! ', ~ ! ' ' ; , ~: ~, .._'_, _: ,~.L_.I_:__:_5_~.~_..'..'.-'..i.L'..¢_.~ ....'..- Li . ~ ._' ..... ~ ~ ~ . ._, ...... .,4.._ ~..i---~. -~--~' ............... ' ............ ,r ....... 'f ......... ~ ........ "'""-,-X:T'r'::"-'-'T"7-,'7; ..... 7'-,,'-- -' [ - F ~ : , . r . I' ' ' '. ~ '5 I' I '. ! ~ '~ ' ' ~ "' ' - ...... 1 X. L-- _i..; ..:. ..... ;_.:,._._ i_L ':_._ .{ .. .......... l ........ i_','...:: ' ~ '-. ,. ! ..'r":--?-r:'::~ '"'r-I.. ~1. ::, .... : , i ..... '1 ; . = . ' ," ' ' ' '' i '!' i ~ ' ! ' '!' ~:" ' = ii~;' '::I: ! ,t I~ L ' ', ' .,--. ~:t-,4 ......... ;-.--:-I .............. -, ........... ! ...... 1 .......... ~ "'-::7': :-T'-,T'/ .: '..i ...... ; :.',-t i 'i.":! :: , '~ , ' :l'-i:';"<'l-:;'~: - ! ,:l.~i~ i/...c~:=....,,.,-; r.,:i.,.., , '~ 'T I ! iT ':';: I ' ~ ', , i '--' ~ )-t'~'-- ,t.,.$/ Ii ~',.,:"," . - ~ · ~ ....~ .... -- -'r -{ ............. · ....... , ....... ~1'" i-}'r- ~ ' :; ::'l ' , l:'l l'.ii' [:~ ! ~"~' .... ": ...... ' '" ..... : : 'I"~' vt · I ........ ~ I ; 1 ~' : , ' ' -" , · ' ; : i , · ! [ ! ~' ',:-5% ........ ": : .... __ . . """ · .7--- :.-.;.;-'4 , -. · I .-. ......... i- . .: ,. 'i' ,,i:::.:.,i ........... i"i ' ' , -' :' '~ :' 'i ':' i "'i ,' r '! -; !' ,'}":4 .... !,'ii:'i Form 10-403 Submit "Intentions" in Triplicate REV. 1-10~73 & "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 P£RMIT--" for such proposals.) 1. OW~LLB GAS [---~ OTHERWELL 2. NAME OF OPERATOR Phillips Petroleum Com~auy 3. ADDRESS OF OPERATOR P. 0. Drawer 66 / Kenai, Alaska 99611 4. LOCATION OF WELL Atsurface Leg 2, Slot 4, 1310.61 FEL, 1019' FWL, Sec. TllN, R9W, S.M. BHL 1132' FSL, 2692'FEL, Sec. i TllN, R10W, S.M. 13. ELEVATIONS (Show whether DF, RT, GR, etc.) RKB ll6 ' from M~3.W 14. CheCk Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 50-28~-20029 . 6. LEASE DESIGNATION AND SERIAL NO. ADL- 37831 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME ~C~U 9. WELL NO. A-9 10. FIELD AND POOL, OR WILDCAT 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See Item 4 BHL 12. PERMIT NO. 69-85 )ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF L-- FRACTURE TREAT SHOOT OR ACIDIZE REPAIR WELL (Other) PULL OR ALTER CASING L.._.J MULTIPLE COMPLETE ABANDON* CHANGE PLANS SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) ~lP_~.~m~+. ~, Perf (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. SEE ATTACHED "DAILY REPORT DETAILED" 16. by c rtify t h/~e~/~rego~g is/rue and correct / ./ 'N.~-~. Porter Sen~ow Petrnl~]m RnM~neer (Thiffpace for State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY: TITLE ,1111 1 197,,5 DIVISION OF OIL AND DATE DATE See Instructions On Reverse Side " EAS~: N~U WELL NO. ~'"9 · . SHEET NO. TOTAL D EP TH :-R :10.'5 Vis: h2 · ':-Perle ~s ;'follo~s: '" 5085 ~'~ ~0 ~ ~247 .- . -?:,.' :;.,. .. :..: ,:: .,., :' "' '::,:" (~l :perle '~po~ed,: DlL.meas~ement' ~D Schl. St~ed. r~ning. . 'comple~ion. . $~rin~7.. .. : h'.,.r~s ~ tstd to 2500' psi E~, ~ Schl G~ eo~elation'lo~. Correlated ~b~"at 7381. l~. Finished GE to fin~ ~b~ setting ??h9 ~ ~3 old ~ ~hich' is ?T~2 - R~ .8~87 tn place,: D~ded tbs. N~ $0~..~ NU ~. N~M ~Ps~ing to ~spla~e mud ~tth salt ~ater. . . . Note:;: ~M m~d~l in S~M in Pl.~ce.~o'~S000 psi , . , ~ev ~11 ~/s~l~ ~te~ ~til ~~s c~ea' S~ottea ~ 1/2 x ?" ~~ ~/es.~tt~ f~esh ~/~ .bbla ~t~ol .~ top, D~op~d 1:' h" '" ' ~ater .... 1/ ball, Had ~00 psi stan~ng p~sS~ on ~ 1/2" x ?" ~~us ~hile M~ting on b~l to d~op. ~et ~ ~/1~00 psi. ~essu.~d '~ :112 x 7" ,. , ~n~ to 800 ~s~, ~ va~ ae~, ~e~e~ ou~ :l~se ~a we~ flowed ~p tmnul~. Press~ed ~ ~nul~ to. ~O0 psi. No e~icaZion ~/tbg. %~stted 2 hours for g~ to work to s~face. Bled gas off ,~~ from 1~00 psi. Pkr ok. Bled off ~us p~ss~. Disc~ected lines to skid back to Well HN~ P~PORT. DAILYREPORT DETAILED .... ~ .- ,J - [ J I I .... IL "LEASE , NOIU WELL NO. A-9 SHEET NO. - TOTAL DATE DEPTH -- NATURE OF WORK PERFORMED ~d: 10.5 Vis: 20 Started skidding to well A-9 at 8: 30 a.m. Jlxly 5, 1975. Pumping on 1/4" line indicated no EO3SV or dumm~ in place, Zero pressure on tbg. Installed OCT. ~PV. NDt~?. flU BOP. Tstd to 3000 psi.. Pulled pkr loose. Removed. tbg hanger. Could not p~up down tbg, indicating 8CSSV was in place. ~hable to open $~tSV by pumping on 1/4" llne due to leak by packing SO3SV. RU Otis. Ran impression bloe3~, and.latched on to S~SV ~th pul!in~ tube. :-U~able to pull sa~e. Jarring apparentlY set packing on $~3SV. pressured up 1/1¢' and opened Sf~;SV.. Unable to release Otis pulling tool. ~irc out water w/ 10.5 #/gal mud. Mud: 10,5 Vis: 40. COOH. Stripped over.vire:.lime'end:LD h" tbg and Otis ~{ pkr. Landed test plug. TStd blind rams to 3000 psi - o.k. Changed to ~ 1/2 pipe rams and tsted'to BO00 ~ ~k. Pulled test plug. rJIH w/ 6 1/8 bit. Tagged brid~ at ~85~. Drld to 7~8~. Could COOH LD 3'1/2'~ DP. drill no deeper. C&C~. . Mud: 10.5 Tstd 'lubricator to I000 psi -- ok. Fer£ es follows with 4" l~vperJet With ~"i hol'es per ft. (Perforations reported ar~ DIL measurement) 772~- 773L' 7691 * 7697 758~ '. 7587 7379 - .7:389 7312 ' - 7337 72h0 - 7270 7132- 7142~ ~7076- 7096/ 6772 - 6842 6463 - 6478 639,..4 - 6hl~ 6280 - 6285 6162 -.6187~ 6!29 615I; 5~16 - 5476 5380 ~- 5395 53~ - 5357 526h - 5289 52~ ~ 52h2 5187 - 5193 513T - 5172 . Form 91] 1-69 Printed in U.S.A. STATE ) ALASKA Submit "Intentions" in Triplicate & "Subsequent Reports" in Duplicate OIL AND GAS CONSERVATIO, N~ COMMITTEE SUNDRY NOTICES AND. REPORTS O,N WELLS (Do not use this form for proposals to dz-itl or to deepen or plug back to a diffierent reservoir Use "APPLICATION FOg PERMIT--" for such proposals.) 1, W~LL W]~LY~ OTlq ER 2. NAZI~, OF OPEP~TOR Phillips Petroleum Compan~ . ADDt~E$$ OF OP~ATOR P. 0. Dra~ 66, .Ken~, ~~ 996~ -- ~19'. ~'~ ' *'~ ~g 2, ~ot S.~& B~'~32' F~--: 2692' 13. FJ~EVATIONS (Show whether DF, RT, GR, etc. · ?.' .' 14.. ~.'.':. :- 5. API ND~CA3, CODE LEASE DESIGNATION AND SEiRL~XL NO. DL- 3783- 7: IF IN~I'~T. AJ_~OT~ OR TR/BE Nk'SlE 8. UNIT, F.a~R.NI OR LF~SE NA~IE NCIU 9. WELL NO. ,. 10. FIELD ~ POOL. OR WILDCAT NOrth Cook. Inlet ll,..SEC., T.,' R., ~I.. (BO'i~OM HOI~ ".: .OBJECTIVE} _ ,. Check Appropriate Box To indi'cate Nmture of N~ti'ce, Report, or Other Data NOTICI~ OF INTENTION TO: FRACTCR~ TR~A~._ I~ . MULTIPL~ COMPLETE FRACTUR~ T'~ATM~ ~,::. (' '~, ALTERING ezsz~a . (O~her) Perf, (NOTZ :' Report'results of multi~le completion on Well Completion or Recompletlon Report and Log form,) , -, ~ ~..~:~c~/,',o~o~o o~ c~f~o o~oss (c~ea~.~ s~.t~ ~n ~o~ti.~,,t ~t~,,. and ~..~ V~t,=~.t a~t~s. ,.~lu~.s ~s~=~ted a~t~ o~ ~t~rtl~S ~n~- proposed work, ._ ~ " '~ V' "" ...... ~' ~ . , ,: ,: ;; .~ 1. ~g up. K~ ~ ~th 10.5 ppg md. ~mo~ t~e. '- ~ta]_!: ~'i'/~':"3~ ~ r~er ~ 12" ~ ~ double gage ~e~or ~d ~~; -Test ~P ~-~riser. . 2. Pull 4" tbg and retrievable packer. ~- 3. Perforate Cook Inlet & Beluga Ps~ 4247-7698 MD ~qKB-overall ' ). ~ 4. Run combination Z~" X 3~-" tubing string with Ogis subsurface safety valve set about 292' RKB and Otis retrievable packer set about 4160' MD RKB~and tubing set 7692' 5. Install tree and displace ~d with water. Set hydraulic packer.'i Test packoff. 7. b%ilize as a producer commingled in Cook Lulet and Beluga ~pa~s. Estimated start of Operations is 7/6/75 TITLE See Instructions On Reverse Side .. -- DW:S1ON OF OiL AND GAS . : ANCHOR,~GE PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99501 ~ 515"D" STREET EXPLORATION AND PRODUCTION DEPARTMENT August 21, 1970 Division of Mines & Minerals Department of Natural Resources State of Alaska 5001 Porcupine Drive Anchorage, Alaska 9950~ Attention: Mr. T. R. Marshall, Jr. Gentlemen: Attached, please find Form P-7, Well Completion or Recompletion Report and Log, Chronological Well History from date of re-entry to suspension, Perforating and Squeeze Record and Sample Description for NCIU Well #A-9. Yours truly, JBG: jo Attachments PHILLIPS PETROLEUM COMPANY /~/' District Office Manager SUBMIT IN DUPLICA',~-.'~! STATE OF ALASKA (See other'lni structions on · - . ! $. AP! N~CakL CODE COMMITTEE ~everse s:ae~ I OIL AND GAS CONSERVATION J ~ ~0-~-~00~ ._WELL cOMPLETION OR 'RECOMPLETION REPORT AND LOG. WELL OVER ~END~EP'~ACK ' gESVR. _ ~ · . 2. ~,M~ o~ o~o~ nV U ~ .......... North Cook Inle~ Un~ 9. W~L Phillips Petrole~ ~om~ny mv,~,o~ o~ o~ A~O 8. AnnamSS OP OPZaATOa AN~MO~AG~ A-9 515 ,'D" Street, Anchorale~ A~ska:, 99501 ~,.~~~o~w~r 4. LOCATION OF WELL (Report location clearly and in accordance with any State requirements)* North Cook Inlet ~t,ua~ ~g 2, Slo~ k, 1310.6~ F~, 1019.0~ ~, Sec. 6, n. src..~..~..'~..(~uo~ TI~, RgW, S.~., No~h Cook Inlet, Platform~"T~onek" omr~vz~ FSL. ~75~. ~L. Sec. ~, T,~ RiOW,FEL, Sec.S'~' 1, T~N, RIO~, S.~. Sec. 1, T~, ~OW, S.~. 12..P~IT NO. 8-20-69 I '9-9-69 ! 3-28-70 ! ~B' ~6' From ~ ~. I 73.' 18. T~_~H, .~ a TVD~9. PLUG. ~CK MD & ~D~. ~ ~LT~"CO~L., ~' '[ 21. "' 'i~RVALS 'bR[LLED BY 8022' ~ / '~ 79~9' P~ [ ~w ~. ' 1 ~o~, ~oo~s -- - / cx~ ~oo~,~ . ' ' ~ SURV~ ~DE NOT PE~0~D ~ Ye~ . J 24. TYPE ELECTRIC A_ND OTHER LOGS RUN IES~ S. NP &~,FDC ~. CASING R~CORD (Report all strings set in well) · CA~NO SIZE I WEIGHT,, LB/PT. I 'GHa~D1w' i DEPT~ ~T, (i~D) I ..... I '-i ~. LINER ~CO~ ,,, ,, ..... NOI~ i ~2,, ~'n s~ nl~. ,,n,' nmi-. "~ ~ n ' 1_5" I;~5 ~ n~.~ ,,n. n~+. ~ 'n .' ! (~D) (~) I I II II i i ii I I D~{ ~V~ (~) I ~O~T ~D ~ O,F ~~ US 56'-55' J, 875 Sx C~ss "G" Cmt ~27'.26' J 550 ~Sx C~ss "G" Cmt, ,. PRODUCTION DATE ~RST PKODUC~ON [ ~ODUCTION ME'I'HOD (Flowh~, gas lift, p~p~--~ and type of prop) ]W-ELL STA~S (~oduc~ or I sieur-m) Not ~rfo~ted or ~r~uc~ng ,._ J i Sus~nded DATI--OF TlST. [IHO~S T~_ I[~OXE-- SIZE [~'r P~D }.I~°=N DR O~BE~_ iIG~HCF'-- [WA~B~" -- .[ G~/O~_~O ~ow ~ma' ~G ~s~ [~~ 'O~L. I - r - TEST WITNESSED BY .. 32 LIST 0F A~ACHME~S ~ ...... . ~ , --. / /2~ Perfmting and ~eeze Rec~ and Chronological Well Histor7 ~13-I hereby ce~ffy/hat the foregoi~/nd at~ched information is complete and ~rreet as determined'{rom alUavailable'l~e~ords. SIGNED~ ~~~'~.~,~~ TITLE l DiStr~ct Ofc. ~r, I. DATE Augus~ *(Se· Instructions and Spaces for Additional Data on Reverse Side) · ~' , , .~ ,,, ~. -..j:,,..a, . :: .~,,; .. ....... ;,~ .. ,, ~, ., ........ .:~ " " ' :"~ ro'-~-'-"I .a .... r-' .... a F.'~Pno a~n,~'X ~, .... o~n,--, ~-~,?+r ' ~ ~? ,. qr . _,_ ,.. ., ,. ... . , , ... ..... "2. (ID_:. p o 0, _O_O O~_f .O_ , ... ,., .. ]..~-,(: t'.::.nO(. ~,. .,':, 0 ,~ .~':~ ' . .J ~'" C ." V," ':':': , ,"" ' ,' ;" .~': ~- , c,..,~ ....... ~ ~':,:::": · ,, S;:'":-' ~'-~ :2" ~ '," ' ' · NCIU WELL #A-9 8-20-69 8-21-69 8-27/31--69 9-1-69 9-10.69 9-11-69 2610' 8022 ' 5592' PBTD CHRONOLOGICA_L WELL HISTOR,,Y, Spudded 15" hele & drld te 630' & rind te 22". Ram 16" csg. Set · 632'. Cmtd w/~25 sx Type "G" mat mxd in 210 bbls prehydrated ~% Gel SW. Cmt circ. Tailed in w/125 sx Type "G" ~ mx~ in 15 bbls ~ w/2% cc SW. WOR. Drld 15" hele te 2610'. Ran lO-3/&" csg. Set @ 2687'. Cmtd w/610 sx Type "G" cmt mxd in 257 bbls 3% prehydrated Gel wtr. Tailed in w/125 sx Neat cmt mxd in 15 bbls 2% cc wtr. Drld 9-5/8" hele te 8022'. Ran IES, SNP & FDC Legs. Ran 7" csg. Set ~ 7~98'. Cmtd w/~46 sx Type "G" cmt mx~ in 107 bbls 10% prehydrated Diacel "D" w/2% cc wtr. Well temperarily suspended. This well has been legged and csg run. The tubing will net be run in this well and the well will net be perferated until seine later date when the well is needed. NCINJ I~LL ,~A-9 Corrected PBTD 79~9' CHRONOLOGICAL WELL HISTORY Ran Bond Log. Perforated 5287' - 5288' with g-½" shots. Squeezed 600 sx Type "G" cmt thru perfs, 3000# maximum & holding pressure. Perforated 2555' - 2556' with 2-½" shots. Squeezed 895 sx Type "G" cmt thru perfs. Perforated 2&26'- 2227' with ~-~' 1,, holes, 550 sx Type "G" cmt thru perfs. Perforated 2426' - 2227' with 2-~" holes. Squeezed 575 sx Ty/joe "G" cmt thru perfs. Tested all perfs to 2000#, all held except at 5287' - 5488', tested to ,, ~!,, tubing string, set at 2180' 2000~, O.K. Ran 2" and ~2 · Tested tubing to 200~,$, O.K. Well suspended. PlV.kSiON OF CUL AND GAS i , SYMBOL OF SERVICE nLl~ TRM OKO KLV HW~ REL FILE REPORT of SUB-SURFACE DIRECTIONAL SURVEY s~i, ~ ~1969 PI_YJ~-~LObl OF OIL AND GAS .~. PHILLIPS PETROLEUM COMPANY PLATFORM COMPANY "A", A-9 NORTH COOK WELL NAME INLET ALASKA LOCATION JOB NUMBER AM8- 2669 TYPE OF SURVEY SINGLE SHOT DATE.. AUG.- SEPT. 1969 SURVEY BY ANCHORAGE W E L L C O. M P' L E T I 0 N R E P 0 R'T PAGE PHILLIPS PETROLEUM COMPANY 'WE'LL A-9 PREPARED BY SCS 09/11/69 FOR EASTMAN TANGENTIAL;MET~tOD MEASURED O E V I A T I 0 N TOTAL COORDINATES C L 0 S U'R E'S DOG LEG SECT]DN DEPTH ANGLE DIRECTION TVD SUB SEA LATITUDE DEPARTURE DISTANCE ANGLE SEVERI'TY;DISTANCE -6.63, DEPARTURE = -0.58 ORIGIN LOCATED AT MD = 375.00s TVD = 374..98, LATITUDE : 445 0 15' S 1SE 444.97 444.97 6.92S 0.50W 6,94 S 4.13W 0.000 4.60 507 0 15' S IOE 506.97 506.97 7-19S 0.45W 7.20 S 3.61W 0-035 4'72 570 0 O' S OE 569.97 569.97 7,19S 0.45W 7.20 S 3.6IW 0.396 4.72 650 0 O' S OE 649.97 649.97 7.19S 0.45W 7.20 S 3.61W 0.000 4'72 715 0 30' S 5E 714.97 714.97 7.75S 0-4OW. 7.76 S 2o98W 0.769 5.03 743 2 O' S lgW 742'95 742'95 8.68S 0.72W 8.71S' 4.7.5W 5.559 5.84 773 4 15' S 37W 772.87 772.87 10-45S 2.06W 10.65 S ll.:I4W 8.092 7.98 825 5 45' S 43W 824.6I 824'61 14'26S 5.61W 15,33 S 2I.o47W 3.051 13.I2 886 7 30' S 46W 885-09 885.09 19.79S 11-34W 22.81S 29.80W 2.923 21,03 977 9 I5' S'47W 974.90 974,90 29.77S 22.03W 37.04 S 36.51W 1-929 35.59 I070 11 45' S 46W 1065.96 1065.96 42.92S 35.66W 55.80 S. 39o71W 2.695 54..40 I166 14 30' S 46W II58.90 1158.90 59.62S 52.95W 79.74 S'41'60W 2.864 78.28 1260 17 30' S 46W 1248.55 1248.55 79.26S 73.28W 107.95S 42'75W 3.191 106'36 1353 20 15' S'46W 1335.80 1335.80 101.62S 96'44W 140.og"s 43.50W 2,956 13&.33 1507 19 45t S 45W 1480.74 1480.74 138.41S 133.23W 192.12. S 43.90W 0-393 189-92 1603 21 15' S 45W 1570.21 1570.21 - 163.02S 157.84W 226.91S 44'07W 1.562 " 1697 24 15' S 45W 1655.92 1655.92 190.32S 185.14W 265.51'S 44.20W 3.191 262~.67 ~ 17gom' 26 15' S 46W 1739.33 1739.33 218.89S~ 214.72W~ 306'63 S 44.44W 2.198 303.53 1856 27 45t S 47W 1797.74 1797.74 239.85S 237-20W 337.33 S 64'68.W 2'374 334.I2 1975 32 O' S 47W 1898.66 1898.66 282'86S 283.32W 400.35 S 45-04W 3.571 396.88 2066 35 30~ S 47W 1972.74 1972'74 318.90S 321.97W 453.16 'S 45.27W 3~8.46 449.47 2158 39 01 S 48W 2044.24 2044'24 357.64S 364.99W 511-00 S 45.58W 3.860 507.18 2253 40 301 S 48W 2116.48 2116.'48 398-92S "~410'84WV 572.65 S 45o84W 1.578 568.68 2348 41 O' S 48W 2188.17 2188.17 440'62S 457-16W 634-94 S 46,05W 0.526 630-81 2443 44 O' S 48W 2256'5I 2256'5I 484o78S 506.20W 700'.90 S 46.23W 3-.157 69-6.59 2510 45 15t S 47W 2303.68 2303.68 517.23S 541.00W 748'.47 S 46'28W 2.'140 743.94 2610 45 15' S 47W 2374.08 2374.08 565.67S 592.94W 819.49 S 46.34W 0.000 81.4.62 2691 45 30' S 48W 2430.85 2430-85 604.32S 635'87W 877.24 S 46.45W 0.931 872.21 2785 46 15~ S 48W 2495.86 2495.86 649.76S~" 686.34W~ 945.12 S 46.56W 0.797 939.89 ' 2877 46____4~' S 48W 2558.89 2558.89 694.60S 736'13W 1012.11 S 46',66.W 0.5.43 1006.69 2982 46 151 S 47W 2631.50 2631.50 746.33S 791.61W I087.96' S 46:g:6.8.W 0,83.9 1082.17 W'E L L C 0 M P L E T I-O N R E P O-R T PAGE 2- · PHILLIPS PETROLEUM COMPANY WELL 'A-9 PREPARED BY SCS 09/11t69: FOR EASTMAN TANGENTIAL METHOD - MEASURED O E V I A T I 0 N TOTAL COORDINATES C L 0 S U R E S DOG LEG SECTION DEPTH ANGE~ DIRECTION TVD SUB SEA LATITUDE DEPARTURE DXSTANCE ANGLE SEVERXTY DISTANCE 3109 45 _15' S 47W 2720.91 ...... ~'--2720..91 807.84S-',/' 857,57W ~./'1178,15 S 46o71W 0,787 1171.94 3292 44- 15m S 46W 2852'00 2852.00 896.54S 949o43W 1305.84' S 46'64W 0.668 1298'79 3479. 43 15' S 45W 3635 ~ 42~_L5 m __S 46W 3730 42 _30 m S 46W 2988.20 2988.20 987.14S 1040o03W 1433,92 S'46,49W 0.650 1425.79 3103.67 3103.67 1060.01S~ 1115.48W V 1538.180 S'46'46'W 0.774 1529.99 3173.72 3173.72 1104.59S 1161.65Wi 1602.98 S 46.'44W 0-263 1593.74 3855 43 Om S 47W 3265.14 3265.14 1162.73S 1223.99W 1688.23 S 46.47W 0-674 1678.59 4042 _~f~ O' S 48W 4233F' 44 45' S 49W 3399.65 3399.65 I249'65S 1320-53W .? 1818.09' S 46,57W 3535.30 3535.30 1337.87S~' 1422.01WY~ 195.2'44 S 46'74W 0,649 1808'07 0.536 1942.27 4422' 45 15' S 50W 3668.36 3668.36 1424.15S 1524'83W 2086.46' S 46.95W 0-458 2076.36 · 4606 46 O' S 51W 3796.17 3796.17 t507.44S 1627,70W 2218,51 S 47'19W 0,563 2208,67 4793 _ 46 om S 52W 3926.07 3926.'07 1590.26S 1733o7.0W 2352'58 S 47.47W 0.384 2343.18 4977 4~ 0 ' S 52W 5163 46 !5' S 52W 4053.89 4053.89 1671.75S 1838.00W, 2484.55 S 47.71W 0.000 2475.53 4182.51 4182.51 1754o'47S~ 1943.87W'¥' 2618'55 S 47'o93W 0.134 2609..88 5529 47 O' S 54W 4432,12 4432'12 1911.80S 2160.43W 2884.87 S 48-49W 0-446 2877.48 5715 47 O' S 55W 5902 47 O' S 55W 4558.98 4558.98 1989.83S ~227t.86W 4686.5'1 4686'51 2068.27S 2383.89W 3020-06 S'48.78W 0-393 3013.39 3156.06 S 49.05W 0.000 3150-03 6088 47 O' S 57W 4813.36 4813.36 2142.36S 2497.97W 3290.84 S 49.38W 0.786 3285.66 6276 47 0 ' S 57W 6463~'~/ 47 S 58W 30' 6650 47 O' S 59W 4941.58 4941.58 2217.25S 2613.29W 3427.17 S 49~6'8W 0.000 3422'75 5067.91 5067.91 2290-31S'~27~0.2-IW.~ '3563'64'S 50oOOW 0.475 3560-.01 5195.45 5195.45 2360.75S 2847~44W 3698.79 S 50.33W 0-47.5 3695.92 6900 47 0m S 60W 5365.95 5365.95 2452.16S 3005.78W 3879.15 S-50.,79W 0,292 3877.23 7084 46 30' S 60W 5492.60 5492.60 2518'.90S 312t,37W 4010.96 $ 51..09W 0-271 4009-59 7271 46 O' S 60W 5622.50 .5622.50 2586.16S 3237.86W 4143-91 S-51.38~ 0,267 4I~2.98 7523 45 O' S 60W 5800,70 5800-70 2675.2'5S 3392.18W m.4320.17' S.51'73W 0'396 4319.69 7770 45 30' S 62W 8022 46 O' S 64W 5973.82 5973'82 6148'87 6148.87 2757-96S 3547'73W 4493'64'S 52'13W 2837.43S 3.710-66WW 467t.19: S 52°59W 10'6.09 4493.49 ~ 0~. 60.2 4671'19 C__L_QSURE 4671.'19 S 52- 36~ W W E L. L C O M P' L E T~I O N R'E P O R T INTERPOLATED VALUES FOR EVEN 1000 FEET ~OF MEASURED DEPTH~ PAGE PHILLIPS PETROLEUM COMPANY WELL A-9::PREPARED BY SCS 09/11/6g FOR EASTMAN TANGENTIAL METHOD MEASURED ___ TOTAL COORDINATES MD-TVD VERTICAL DEPTH TVD SUB SEA LATITUDE DEPARTURE DIFFERENCE CORRECTION 1000 997.00 997.00 -33.02S -25o40W 3 3 2000 1919o00 1919.00 -292.76S -293-94W 3000 __ 2644°00 2644.00 -755,05S -800'96W 4000 3969,00 3369.00 -1230-13S -1298'85W 81 78 356 275 631 275 5000 4069,00 4069°00 -1681'g8S -1851o09W 931 300 6000 4753.00 4753.00 7000 5434,00 5434,00 -2107o31S -2~44-00W 1247 316 -2488.43S -3068.60W 1566 319 80OO 6133.00 6133.00 -2830-49S -3696.43W 1867 301 W E L L C 0 N P L 'E T~I: 0 N R E P 0 iR T PAGE I INTERPOLATED VALUES FOR EVEN 100 FEET;OF SUB SEA DEPTH PHILLIPS'PETROLEUM COMPANY'WELL A'9 PREPARED BY'iSCS 09/I1/69 FOR EASTMAN TANGENTIAL~METHOD MEASURED TOTAL COORDINATES MD-TVD VERTICAL DEPTH TVD St)B SEA LATITUDE DEPARTURE DI!FFERENCE CORRECTION 500 500,00 500,00 -7.16S -0o4.5W 600 600.00 600.00 -7-19S' -0o45W 0 0¸ 0 O. _ 700 700,00 700-00 -7-62S -0.41W 0 0.' 800 800.00 800.00 -12,45S -3-92W 0 0 go1 900.00 go0.o0 -21-45S -13.1IW 1 1 1003 1000.00 1000.00 -33.39S -25,79W 3 2 1105 .....,~__ 1100.00 1100.00 -49.04S -41'99W 1209 1200.00 1200.00 -68'62S -62.27W 9 4 1315 1300.00 1300-00 -92'44S -86.93W 15 6 142] .___1400.00 1400.00 -117-91S -112.73W 21 6 1528 1500.00 1500.00 -143,71S -138:.53W 28 7 1636 ~600,00 1600.00 -172'50S -167'32W 1746 1700. 36 O0 1700.00 -205.42S -200!-77W 46 10 1859 1800.00 1800.00 -240-81S -238-23W 59 13 ~. 1900.00 -283.51S -284,02W 77 18 , 1977 1900,00 2101 _, 2___000.00 2000.00 -333'66S -338'37W 101 24 2231 2]00,00 2100.00 -389-50S _-400-38W 131 30 2364 __ ___2200,00 2200-00 -448.26S 2505 _ 2300.00 2300.00 -514-70S 26~7 2400.00 2400.00 -583.31S -465.64W 164 33 -538.28W 205 41 -612.54W 247 42 2791 2500.00 2500.00 -652.70S -689.6IW 2936 2600,00 2600.00 -723.88S -767.54W 291 44 336 45 3079 2700.00 2700-00 -793.45S -842.14W 379 43 3219 2800. 3358 ___ 2900, 3495 3000. O0 2800.00 -861.35S .-912"99W -928,47S -981.35W 419 40 458 39 O0 2900,00 O0 3000.00 -994'59S -1047,73W 495 37 3630' 3100.00 3100.00 -1057'695 -1[13.07W 530 35 3766 3200.00 3200.00 -1121.30S -II79o57W 566 36 603 3903 3300.00 3300.00 -1185.26S -1249-01W 37 4042 __~00.00 _ 3400.00 -1249.88S -1320,79W 642 39 W E L [ COMP INTERPOLATED VALUES 'FOR EVEN L:'E~ T I 0 N R E P 0 R.T PAGE 2 ~ IO0 FEET OF SUB SEA DEPTH PH[LLIP~ PETROLEUM COMPANY WELL=A-9 PREPARED BY SCS 09/II/69 FOR EASTMAN TANGENTIAL METHOD MEASURED TOTAL. COORDINATES MD-TVD VERTICAL DEPTH TVD SUB SEA LATITUDE DEPARTURE DIFFERENCE CORRECTION 4183 ~500.00 3500.00 -1314'91S -1395°60W 683 41 4325 3600,00 3600.00 -1379.82S -1472.01W 725 42 4468 _ 3700.00 3700.00 -1444'77S -1550.30W 768 43 4612 ~800,00 3800.00 -1509.88S -1630.82W 812 44 4756 ....... 3900.00 3900,00 -1573.63S -1712.42W 856 44 4899 __4000.00 4000,00 -1637..39S -1794.02W 899 43 5044 4]00.00 4100,00 -1701.40S -1875-95W 944 45 5189 4~00-00 4200.00 -1765.49S -1959.04W 989 45 5335 4300.00 4300-00 -1828.52S -2045.80W 1035 5482 4400,00 4400.00 -1891.55S -2132o55W 1082 47 5629__ 4.500.00 4500.00 -1953.55S -2220.05W 1129 47 5775 4600.00 4600.00 -2015.06S -2307.89W 1175 46 5922 4700.00 4700.00 -2076.15S -2396.02W 1222 47 6068 4800.00 4800,00- -2134'56S -2485.95W 1268 46 6215 ___ 4900.00 4900,00 -2192.96S -2575o89W. 1315 47 6362 ___5000,00 5000.00 -2251.03S -2667.35W 1362 47 6510 ~100,00 5100.00 -2308.03S -2759.70W 1410 48 6657__5200,00 5200.00 -2363.18S -2851.66W 1457 47 6803 _ 5300.00 5300.00 -2416.80S -2944.53W 15.03 46 6949 5400.00 5400.00 -2470.t0S --3036,85W 1549 7095 5500.00 5500.00 -2522°73S -3128.00W 1595 7239 5600.00 5600.00 -2574.50S -3217.68W 1639 44 7381 5700.00 5700.00 -2624.90S -3304-97W 1681 42 7522 5800.00 5800.00 -2674,90S -3391.57W 1722 41 7665 5900.00 5900.00 -2722'69S -3481.40W 1765 43 7808 6000.00 6000.00 -2769'84S -3572.09W 1808 43 7952 6100.00 6100.00 -2815.24S -3665.17W 1852 44 PHILLIPS PETROLEUM COMPANY #A-9 ~CI U~IT NORTH COOK INLET FIELD COOK INLET, ALASKA 0- 4OOO 4OO0- 4140 2140 - 4160 4160 - A175 4175 - 4200 4200- A215 4215 - 4235 423 5 - ~530 4530- 4590 4590 - 4895 4895 - 4975 4975- 5075 5075- 5255 5255 - 5285 5285- 5410 5410- 5475 5475- 5715 5715- 5725 5725- 5965 5965- 60OO 6000- 6145 6145 - 6175 6175 - 6490 6490- 656O 656O- 6755 6755 - 68OO 6800 - 70~5 70~5 - 7325 7325- 7565 7565- 7590 7590- 7835 7835 - 8022 Sample Description. Gravel and san& Sand -Med gy, f-mg, SA-SR. Clyst- Gy, soft, slty. Sand. Clys.t. Sand. Clyst. Sand -Med gy, f-rog, SA-SR. Clyst - Gy, mod hd w/interbedded coal and sand. Sand -Med gy, f-rog, SA-SR; w/interbedded coal and clyst. Clyst- Gy, soft, slty, carb. Sand - Meal gy, f-rog, SA-SR; w/interbedded coal & clyst. Clyst - Gy, soft, slty, carb; w/interbedded sltst, sand, & carb. sh. Sand - Med gy, f-mg, SA-SR. Clyst- Gy, soft, slty, carb; w/interbedded sand, coal, sltst, & carb. sh. Sand - Med gy, f-mg, S^-SR; w/interbedded clyst. Clyst - Gy, soft, bentonitic. Sand- Med. gy, mg, SA-SR. Clyst - Gy, soft, bentonitic; w/interbedded sand & sltst. Sand- Med. gy, fg, SA. Clyst - Gy, soft, bentonitic. Sand - Med gy, fg, SA. Clyst - Gy, soft, bentonitic; w/interbedded sand & sltst. Sand -Med gy, fg, SA. Clyst - Gy, soft, bentonitic; w/interbedded sand & sltst. Sand -Med gy, fg, SA Clyst - Gy, soft, bentonitic; w/interbedded sand & sltst. Sand - Med gy, f-mg, SA-SR; w/interbedded clyst & sltst. Clyst - Gy, soft, bentonitic; w/interbedded sand & sltst. Coal. Sltst - Gy & buff, sdy, mod hd; w/interbedded sand, sandstone, clyst, & coal. Sltst - Med. gy, hd, calc; w/some interbedded sand & sandstone. -. ' I " ' ' ~ 0 , ~'I! -' .. :~-1-70 . 7" :~,2_7o __-. _!:_>->' ~-.:::_ .... . ... _: .. . . 4556' '" - '- I'-- 4555' '4227, .~ ~ I..../4226,- . . :: Ned'-of ~:_ S~ze o1: -':.:- ::-Fee'l' -:i ~'i: No, Of ':- '~' Pefforafe/d "()): Holes' ''~: "' -Holes ' 'RECEIVED g G 2 4 !97 ) DIV~$ AN GAS . . . · . . _ Type .... Hyper Jet Hyper Jet Hyper Jet Hyper Jet Perforating Company Schlumberger Schlumberger Sch lumbe rge r Schlumberger PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99501 ~ 515"D" STREET EXPLORATION AND PRODUCTION DEPARTMENT April 27, 1970 Mr. Homer L. Burrell, Chairman Alaska Oil & Gas Conservation Comnmittee 5001 Porcupine Drive Anchorage, Alaska 9950~ Dear Sir: In response to Mour letter of April 2~, 1970, concerning installation of safety devices in flowing wells, please be advised we have installed hydraulically controlled ball valves in all our wells in North Cook Inlet with the exception of NCIUWell #A-9, which has not been perfora- ted. At such time as this well is perforated, a ball valve will be installed. Yours truly, PHILLIPS PETROLEUM CO]~A~f District Produc~gon Superintendent JBG:jo RECEIVED APR g8 I97C OtVI~IG'N OF C~L ~.ND GAS ANCHO~A~ Form 1~--3 REV. 9-30-67 STATE O,F ALASKA Submit "Intentions** in Triplicate & "Subsequent Reports" in Duplicate OIL AND GAS CONSERVATIO,N; ,CO,MMII'I'EE SUNDRY NOTICES AND REPORTS O',N WELLS (Do not use this form for proposals to drill or to deepen or plug back to a diffierent reservoir. Use "-~PPLICATION FOR-PER1VIIT~" for such proposals.) OIL ~-] OAS [] WELL WELL OTHER 2. NAME OF OPERATOR Phi ]l~ps Pet rolet~m C~moanv S. ADDRESS OF OPERATOR - - 51~ "D" S+,reet. Anchorage. i~ska 99501 At~u~ ~g 2, Slot ~, 1310.6' F~, !019.O' ~, Sec. 6, TI~, Rgw, S.M., North Cook Inlet, P~tform "Tyonek" Top.o? Pay: ~0' ~, 5750' T~, 2650' FSL, 675' F~, Sec. 1~ TllN, R10W~ S.M. ~2. ELEVATION~ (Show whether DF, RT, GR, ~B 116' From ~W 14. CODS F~ - 'OT~ OR ~ ~ UNZT, FXR~ OR LF~SE NA~II~ ~ North Cook Inlet Ur~t 9. WELL NO. f0. FIELD A~D POOL, OR WILDCAT .' N~r~h Cook Inlet .i1. SEC., T., R'.'2' .~., (BOTTOM HOLE OBJECTIVE) 12. P]~R/VIIT NO. ! ., ~. 69-85 Check Appropriate Box To I~nSi,cate NJat'ure of N~oti'c'e~, Report, or','Other 'Data NOTICE OF INTENTION TO : FRACTURE TREAT I~t MULTIPL$ COMPLETE SHOOT OR ACIDIZE ~ ABANDON$ REPAIR WELL CHANGE PLANS ~URSEQUENT REPORT OF: SHOOTING 0a ACiDIZING ~ 2 ] ABANDONMEKT* (Other) See BeloW (NOTE:Report' results/of multiple completion on Well (Other~ Completion,or Recompletion Report and Log form ) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertineut details, and give pertfiien't:i,dS[~es; including estima'~ted date of starting any proposed work. ~' , : 3-28-70 7%8' PBTD Ran Bond Icg. Perforated 5~87' -"5~88' "with: 4-~" shots Squeezed 200 sx Type "G" cmt~thru perf,, 3~0~ maximum & holding pressure. Perforated.~555' -."~556'~mith 4-~,, shots. Squeezed 935 sx Type ".'G'~ cmt' thru perfs. Perforated 4~26u ~27' with 4~" holes, 225 sx .~e "G" cmt thru perfs. Perforated 4426' -~.27' with4-~" h~le. Squeezed 753 sx Type "G" cmt thru perfs. Tested all per~s to 2000~, all held except at 5~87' - 5~88'. SqUeezed 380 sx Type "G" cmt' into perfs 5~87' - 5~88', tested~:.t~ 2ooO~, O.K. Ran ~" and 3½" tubing string, setat ~,180'. Tested tree and ball valve control with 5OO0~, O.K. Tested tubing t~ 2000#, O.K. Well suspended. ~7~at~ true and correct 16. I hereby ce .the forego (This sp$/ce ~or State office use¥ CONDITIONS OF APPROVAL, IF ANY: TITLE District Ofc. l~r. DATE April 21, 1970 See ')nstructlons On Reverse Side Approved Copy Returned OIL AND GAS CONSERVATION: ,CO,MMI'KrEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a diffierent reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) OIL 7q GAS [] WELL WELL OTHER 2. NAME OF OPERATOR Phillips Petroleum Company 31 ADDRESS OF OPERATOR 515 "D' Street, Anchorage, Alaska 99501 4, LOCATION. O,F W~t~L' Atsur~ace Leg 2, Slot ~, 1310.6' FNL, 1019.0' FW%, Sec. 6~ TllN, R9W, S.M., North Cook Inlet, Platform "Tyonek', ToR of, Pay: &800' MD, 3750' TVD, 2650' FSL, 675' FEL, Sec. l, TllN~ RIOW, S.M. 13. ELEVATIONS. (Show whether DF, RT, GE, etc. RKB ll6' From ~5LW 14. API 50-283-20029 6. LEASE DESIGNA~iOi~ AND SER][J~O. HWK ~ AD~37831 R~ ~. IF I~I~, ~OT~ OR ~IB~ N~~ North Coo~ I~et U~t 9. WI/ILL NO. IO. FIELD A~D POOL, OR WILDCAT 11. ~EO., T., ~., ~., (~ O~m~V~) "'sec,~ i~,T~N~ P&OW, S.M. 12. P~T NO. 69-85 Check Appropriate Box To I~nd:i,cate Nlat'ure of N~ti'ce, Re,port, or ,Other 'Dat~ NOTICE OF INTENTION TO: TEST WATER SHUT-OFF I t PULL OR ALTER CASING FRACTURE TREAT ] [ MULTIPLE COMPI,ETE SHOOT OR ACIDIZE [__~ ABANDONs REPAIR WELL CHANGE PLANS SUBSEQUENT REPORT OF: WATER SHUT-bFF~'~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING' S~OOTING OR ~CIDIZINO ARAND0~,~E~T' (Other) (NOT'El Report results.of multiple completion on Well (Other) Complet~p,n ,0'r Rec0mpletion R~port and I~g form ) 151 DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates,, including estimated date of starting any proposed work. Re-?nte~r Well #A-9. Run cst Bond. Log, perforate and squeeze any zones, where cement no gooa. Hun combination tubing string, shut-in and suSpe: n~..~ PrOductiVe z6~nes will not be perforated for producing until needed. Work to start~' on approximately 3-28-70. 16. I hereby the fore$~l~ ~l~e and correct ' (Thl~ sp~e for State o~ce~)/ ~ ~ ~ CONDITIONS OF APPROVAL, IF ~: District 0fc. Mgr. DAT~ April 21, 1970 i, See'~nstructions On Reverse Side Ratumed No.ember 19. ! 969 D! sir icl ~ff ice: ,~a:n~er ~:i I Itps PeSo/cum Company 515 "D' ~treet Aachorage, A I aska 9950 t Dear ~L~. 'g! pson: ~ have received y~r aaPri:als on tt~e ~tU ~etts ~s. ~. A-IO. ~-ll. "~ are I:e~e~ ~proved ~p I es of F~ P-3 ~ e~h of ~e ,~lis. Thee ~~v~ ~)'es of F~ P-3 ~e c~dl- :t'~on~ on ~e su:bm{ss{~ of' F~ be suspended. All of the fifes appear compte,~ exce~ for these ,Pro(~cf,:f;on, ~e, ~ou, ld apprec,ja~e ne~ P-7's $~I~ ~he l'~ttlal produc~lo~ dat~. very Petrol earn 'Oeolog ! st Enc! osu ~es PHILLIPS PETROLEUM ANCHORAGE, ALASKA 99501 ~ 515 ~'D" STREET EXPLORATION AND PRODUCTION DEPARTMENT COMPANY o~o KLV --- REL ~ FiLE ~ November 12, 1969 Division of Mines & Minerals Department of Natural Resources State of Alaska 3001 porcupine Drive Anchorage, AlaSka 9950~ Attention: Mr. T. R. Marshall, Jr. Gentlemen: Attached, please find original and two copies of Form P-3, Sundry Notices and Reports on Wells, Chronological Well History, Sepia and Blue Line IES ~og for NCIU Well #A-9. Yours truly, JBG: jo Attachments PHILLIPS PETROLEUM COMPANY ~~~~er 1969 Fo~m STATE OF ALASKA Sub'nit "Intentions" in Triplicate & "Subsequent Reports" in Duplicate OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a di£fierent reservoir. Use "APPLICATION FOR PEP~IT~" for such proposals.) OIL [~] OAS ~ WELL WELL OTHER 2. NAME OF OPERATOR Phi~ps Petreleum Cempan¥ 31 ADDRESS OF OPERATOR 515 "D" Street, Anchorage, Alaska 99501 4. LOCATION. O,F WELL At surface ~g 2, Slot &, 1310.6' FNL, 1019.O' FWL, Sec. 6, TllN, Rgw, S.M., North Cook Inlet, Platform "Tyenek" TeD of Pay: ~800, MD, 3750' .T MM), 2650' FSL,~.675' sec. 1~ TllN~ R10W~ S.M. 13. ELEVATIONS (Show whether DF, ET, GR, etc. RKB 116' Frem 14. ,Check Appropriate Box To I~nd',icate N!at'ure of N~oti'Ce, Re ~i API NUMER/CAL CODE API 50-283-20029 5. 'LE~SE DESIGNATION AND SERIAL NO. , ADL-37831 ?. IF II~Ui)I~, ~LLOTTEE OR TRIBE UNIT, FAR~ OR LEASE NAlVIE Ner%h C~k Inlet Unit WELL NO. 1~. FIELJ~ ~ND POOL, OR WILD~T North Cock 11, SEC~, T., R., ~.; (B~ ZO~ O~E~IVE) NOTICE OF INTENTION TO; SUBSEQUENT REPORT OF: FRACTURE TREAT ~ULT!pLE COMPI.ETE FRACTURE TREATMENT ALTERING CASING SHOOT OR ACIDIZE A~ANDON* SHOOTING OR ACIDIZ'NG ABANDONME~'Ts REPAIR WELL CHANO~ ~LA~S (Other) (No?~: Report results of multiple completion on Well (Other) ComPletion or ~Recompletion RepOrt and'Log form ) 15. DESCRIBE PROPOSED OR COMPLETED OPERAT~0N'S" (Clearly ~tate all pertinent details, and give pertinent dates, including estimated date of starting proposed work. This well has. been drilled to a TVD of 61~9', MD of 8~'. BHL: 1132' FSL, 2692' FEL, Sec. 1, TI_~N, RIOW, S.H. The well,,~as then logged .a~,.d ,easi~/,;was,.,~. (See Chrenelogical Well History attached). The well will net be perforated un~il some later date when the well is needed. (Est. ~&-5. years). Alse attached, please find Sepia and Blue Line IES L~g. 1969 16.SIGNED ~~~.~I hereby eer tha the fo egoing m i~ue and correct (T~,II ,p&~ State ofa;e'uL) -- /' TITLE Manager DATE N~vembar 12, 1969 CONDITIONS OF APPROVAL, IF AN~:' ' ~ - TITLE DATE See '~nstrucfions On Reverse Side Approved Copy Returned __ PorTo NO. NJEV. STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUBMIT IN DUPLICATE MONTHLY REPORT OF :DRILLING AND WORKOVER OPE;RATIONS 2. NAME OF OPEB,ATOR Phillips Pe~.r...eleum Company. 3. ADDRESS OF OPIERATOR .5.15 "D" Street, An.e, he. ra~e. ~ska 99501 Surface: Leg 2' Slot ~, 1310.6' ~, lO19.O' ~, Sec. 6 TllN' RgW, S.M., North Cook Inlet, Platform "Tyonek" T.ep.~f...Pay: ~' ~, 3750" TVD, 2650' FSL, 675' FEL, Sec. 1, TiL~, RIOW, S.M. _ 5. APl NUA~ERICAL CODE API 50-283-20029 LEASE DESIGNATION A%-D S~t~ NO.,i HLB , TRM OKG KLV ~ HWK .....~2 ,.. .ADLr,37831 ....... 7. IF INDIA]~, ALOY i ~:J~ 0]~ TI:{IBFIJ~I~E ' 8. TJ~'IT,F.~ OR LEASE NAME North Cook Inlet Unit WELL NO, #A-9 10. Fi~ AMD POOL, OR WILDCAT North Cook Inlet 11. SEC., T., R., M., (BO~Ol%{ HOLE OB~CTrV~ Sec.. 1~ Tll~.,,, RIOW~ $.M. 12. PEB/VIIT NO, 69-8~ REPORT TOTAL DEPTH AT END OF MONTH, CHA~N'GES IN HOLE SIZE, CASING AND CE2V[F~TING JOBS INCLUDING DEPTH SET ~ VOLUATF_~ USED. PEF, FO]R~%TIONS, TE~TS ~ PLESULTS, FISHING JOB,~. JTJi~K L~ HOLE AND SIDE~TRACKED HOLE A~ ~Y O~R SIGNIFIC~T ~~ ~ HO~ ~ITIONS, 9-30-69 80~, This well has been logged and csg ~. The tubing wi~ not be run in this well and the well will not be perforated until some later date when the well is needed. 9-1-69 Ran lO-3/&" csg. Set :$ 2587'. ~d w/610 sx Type "G" cmt mxd in 257 bbls 3% prehydrated Gel wtr. Tailed in w/125 sx Neat cmt mxd in 15 bbls 2% cc wtr. Drld 9-5/8" hole to 80~,. 9-10-69 Ran IES, SNP & FDC Legs. 9-11-69 Ran 7" esg. Set $ 7998'. Cmtd w/~46 sx Type "G" cmt, mxd in 107 bbls 10% prehydrated Diacel "D" w/2% cc wtr. Well temporarily suspended. ~lyl.~iOJ/OF OIL AND //f ~, ~ h~by ~Y ~t ~e fore~O~~ ~d ~ ......... sm~ ~~, ~~ ~' Ofc..~r.... DA~~to~r 15, ,1969 .... //- .- ~E--Repo~ on this form is required for each ~lendar month, regardless of the status of operations, and mu~ ~ filed in dupli~te with the Division of Mines & Minerals by the [Sth of the succeeding month, unless othe~ise ditched, lVorra No. REV. 9-S0-67 STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF :DRILLING AND WORKOVER OPE:RATIONS SUBMIT IN DUPLICATE 1. 2.NAME OF OPE/{ATOR Phillips Petroleum Compan7 ADbRESS 6F OPEPcATOR ., 515 "D" Street, Anchorage, Alaska 4. LOCATION O'F WmLL Surface: Leg 2, Slot 4, 1310.6' FNL, 1019.0' T~]N, RgW, S.M., North Oook Inlet, Platform "Tyonek" T_oD ®f Pay: ~800' F~], 3?50' TVD, 2650' FSL, 6?5' FEL, secl 1' R 0W, 'TRM KLV AP1 50-283-20029 .~.,.( $. LEASE DESIGNATION AND SERIAL NO. ADL-37831 IF INDIA]~, ALOI lJ~E OR TRIBE NAM]~' ,'iLE .... 8. LrNIT,FARA{ OR LEASE NA3~E North COok Inlet Unit g. WELL NO. ~A-9 10. FIELD A-ND POOL. OR WILDCAT North CoOk Inlet 11. SEC.. T.. R., M.. (BOTTOM HOLE Sec. 1, T!IN, RiOW, $.M. 12. PER~IT NO. 13. REPORT TOTAL D~J~"I'H AT END OF MONTH, CHA~N'GES IN HOLE SIZE, CASING ANT) CEMENTING JOBS INCLUDING DEPTH SET A/XrD VOLLrNIES USED. PEI~ORATIONS, TESTS AN-D iq~ESULTS. FISHING JOBS. JUNK IN HOLE AND SIDE-TR~CKED HOLE AND ANY OTHER SIGNIFICANT ~GES IN HOL~ CONDITIONS. 8-31-69 8-20-69 8-21-69 8-22/26-69 8-27/31-,,,,69 2610' 2610, Drilling 15" hole. Spudded 15" hole & drld to 630' & rind to 22". Ran 16" csg, set @ 632', emtd w/&25 sx Type "G" cmt mxd in 210 bbls prehydrated 4% Gel SM. Cmt circ. Tailed in w/125 sx Type "G" cmt mxd in 15 bbls FW w/2% cc SW. W0R. Drld 15" hole to 2610'. ~1¥1510N OF OIL AND GAS sm~u~ KJ--J,~,,_ZD ~'~,, . u~= District 0£¢, I,~uager ~^~t September 12~ 1969 ,,-7 .... f/ ......... -- (/l~OTE--Report on this form is required for each calendar month, regardless of the staL.s of operations, and mgst be file~l i, duplicat~ with the Division of Mines & Minerals by the 15th of the succeeding month, unless otherwise directed. DIVI$10N OF OILA~~ ANCHORAGE Mr. John B. Gipson District Office 14anager Phillips Petroleum Company 515 "D" Street Anchorage, Alaska 99501 ,I Dear l,,r, Gipson- Re: North Cook Inlet #A-9 Phillips Petroleum Co., Operator In reference to the subject off shore drill-site the following stipulations are requi' ' r~:sou,~ rea to protect fish and game'~ .... .~' No material foreign to the environment will be discharged from t.~s ~la~for, n, This inciudes ~.~rba.:~ trash, refuse petroleum and/or its products~ drilling mud~ and debris. e Drilling operations are not to interfere with cornmerciai fish ,ng. e The Habitat Biologist's O'f'fice~ 10t8 !'.lest i'= "-~"-' Airport Road Ancl~o~ ~.u': 99502~ ' '~ - ~a,',.~ Al~-u- v,,~ll ~ notified prior to abandon:tent ofu~s~ Iocation~ 'The fo~'~"n,-~nc~ urovisions do nnt 'reli:',',,~ t!".} lesse:~ and/oTM his contractors or assignees of anZ responsibilities or provisions requi:ed by law ,._~ulation of ~.'"~ State ~'? Alaska or the Federal Governm.~,nt RorCh Cook Inl~ ~&-9 Phillips P2~rolm ~o., op~r&~or ~11 oa or ~ ~ 21, 1969, from ~ a 1~t~ ia. Seettx,~ 6, ~~ 1~, aell mmp~ and eora chips ar~ uo~ 'requix~- t direct~l survey uill be require. The 10 3/&' and 7" cao~ must be ~ied in with cement. ~sch electric los, s~pia and print fixed pursuant ~o ~ 31.05.0~ a~ ~ ~1-~~ ~~~ a~il ~1~ ~ ~1:~~~ file ~ ~ ~~l ~ ~tt~ o~ all ~ ~s, ~th ~ ~ ~~ ~ lo~ m. ~ ~ ~1 $~all f~ ~ ~I~ (I) ~ of fl~ h ~ ~. (~ ~ h ~ ~ ~ ~~~ ~i~, (3) ~Xe c~, (4) the egeuC of mmpeusLou or abandommmt:, pl2as2 m~tLt~ this office ~tu~ely in edunce so Ch~ mm uny h~e a uttmss preoenz. Very truly yours, Homsr L. Burrell, Ch~lrmn cc: Dept. of Fish & Camm v[o eric. Dept. of Zmber v/o e~c. Form P--1 (Other instructions'r~n · reverse side) ' REV. 9-30-67 ,5. .. DiVi~01~I~~ONSER'VATIO'N ,CO,~,TTEE APPLI,,C~TION_:~ F~~Lt~IT TO ~RILL, DEEPEN, OR PLUG BACK la. TYPE OF W01~I~4 , DRILL [] DEEPEN [] PLUG BACK [-I b. TYPE OF WELL OIL [-~ Oa~l [] SINGLE[-"] MULTIPLE ~_~ WELL WELL OTHER ZONE ZONE 8. ~IT~FA~ OR LEASE N~E 2.NA~E OF OP~TOR No~h C~ok I~et ~t ~~ps Pet~le~ Cosy ~. ~L No. 515 "~" ~et, ~ehor~e~ ~ka, ~1 ~0. 4.LOCATION OF WELL ~tsurIace- ~g 2, Slot ~, 1310.6~ F~, 1019.0~ F~, See. 6, No~h ~ok I~et TI~, R~ g.H., No~h ~k ~et, P~tfo~ "~~k" ~opo~d~ro~.~o~ ~0~ ~, ~7~~ ~, 2650~ F8L,~. 675~ 13. DIST~CE IN MILES A~ ~E~Off F~O~ Ng~ T~RrpO.ST OFFICE* 14. BOND INFO~A~ON: N~~ State 'Wide ~nd ~-1 .... ~ ~ "~.' TYPE Surety and/or No. ~o~t (Ai~ to nearest drig, unit, if any) ~ ~ ' 18. DISTANCE FROM PROPOSED LOC~'O'N* ..... ciy - [i9. PROPOS~ D~ ROTARY ~0R 20. CABLE TOOLS TO NEAREST WELL D2ILLING, COMPLETED. 21. ELEVATIONS (Show whether DF, RT, OR, etc.) : ~. AP~ROX-D&TE WORK WILL ST~T* 23. ' PRoP0SD CA~.iNG AND C~EN~NG PROGR~ 6. LEASE DESIGNATION AND SERIA~ NO. ADL-37831 7. IF INDIAN. AJ~LOTTEE OR TllIBE NAJ~E 12. ~ T , ~ , , 1. De~ation re~d te reach B~L from' per~anent;, pla%fer~- 2. ~ere ~ no e. ffect~ 3. ~P 5~eifi~tion at~ehed. - &. Inte~s of ~terest ~ be ~rforate4 ~d ~y ~ * Refer to S~te of ~~a, ~a ~1 & ~s Cense~tion CO--tree, ~n~atien ~er ~0, dat~ 6~7 ~d ~68, ~ted ~-7~8. NOTE: ~tL: l~OO' FSL, 2500t FEL, ~e. 1, TllN, RlO~, S.N. IN ABOVE SPACE DESCRIBE PROPOSED PROGRA/VI: If proposal is to deepen or plug back, give data on present productive zone and proposed~a~;~ productive zor'~e. If proposal is to drill or deepen direct '_onally, give pertinent data on m~bsurface locations and measu~d and depths. Give blo t preventer program._______~ 24. I here~y cert~~ th~he For/~oing~T~e and Correct jDIRE~ON~ SURVEY YES [] NO · See Transmittal Letter J A.P.I. NU1VEEHICAL CODE APPROVAL DATE August: 20_ 1969 Alaska 0il & Gas Chairman TZTL~.Conservation CO~Illttt~)ATE At,~__ 90 ~ 1969 *See Inslvucti°ns On Reveme Side Di¥1~ION OFOILAt~ GAS -) · .' North Cook Inlet Unit A-5~,~.~ · : -, . ,.c.I. u~. ~~ . · ~.c.,.~-,/~.~, 'Leg 3' t.~ '~..--.~~N.Cl. Un. A-9 i PHILLIPS PETROLEUM COMPANY 515 "ii' STREET ANCHORASE,,,AL, ASKA NORTH COOK INLET TYONEK PLATFORM COOK INLET ~ ALASKA NOTE: Using PLATFORM NORTH, Slot No.~ ~':~i b~ The furthest platform North slot in p!ctform North- west quadrant of any leg; Slots ~r~ numbered I thru 8 in a counter-clock-wise PLATFORM LOCATION' Se¢.6-iIN-gW ~ ORWN. N.J. Po~,,li ...... DATE: 6-2o-G9 NOT TO SCALE ilECEiVED ~6 / . ~ ' ~. ~ ~A-I , ~~~~~, -~ ._~: -.: ......... C,,LL~S ~-... " · a '--.;~.~...-' . .. TOP . 2650 F.S.L;675'F ~ '/ ' ,~,A-e .. I - , ~t.~ I ~ . · .. Sec 1711 N- IOW S 1200 FS.L:2500'~ // X // ~L i iiiiiii i ~ i . i 12 ,~ '7 , ..... ~. , ~ , . 18 - " i i i ii i j ia ii ,. , 32 "' 5 8 GRID PHILLIPS PETROLEUM COMPANY 515 "D" STREET ANCHORAGE ,ALASKA ~LAT OF ' NORTH COOK INLET UNIT TYONEK PLATFORM b~WN. N. d. Powell lSCAL~:: HOOF, UP FOR DOUBLE PREVENTERS DIVi~IONOFOILA~tDGA$ [_j~~ E_RIE S 1500 CHOKE MANIFOLD N.C.I.U. PLATFORM ~- -F ' · · 1'----6EE'G ' LINE / ,,,,,, ~,~ , . .. ,, .. . -. · ~;~- ~~ .. . . N~E: Double Preventers are used ~th f~nged side outlets-for choke mnifo'ld .. and fillup line co~ectiOns. 4" SERIES 1500 VALVE 2" SERIES 1500 VALVE 2" MUD PRESSURE GAUGE ON 4"X ~'X~" SERIES 1500 STEEL TEE 4" SERIES 1500 X 2" SERIES 1500 STE'EL CROSS 2"SERIES 1500 poSITIVE CHOKE 2" SERIES 1500 ADJUSTABLE CHOKE Pi-'] ILLiPS Pc. ~ ,-~ _,Lc~u,,', CO~';: NY PRODUCTION DEPARTMENT 5000 PSi WORKING BLOWOUT PREVENTER HOOK-UP (SERIES 1500 FLANGES OR · REV. SCH~_L g,.~ E · 2~ · 4. CHECK LIST FOR NEW WELL PERMITS -' Yes No Remarks Is well to be located in a defined pool ................. Is a registered survey plat attached . ' ~ . :"i.. ~,:i Is we1, ,ocated proper distance from prOperty... Is well located proper distance from other wel Is sufficient undediCated acreage avaiiable" in 'thiS ~.:]7. ~. Is well to be deviated ..i _.i.~.;~. · ~8 Is operator the only affected Party .......... ',.;_-_~-. -.-,: ". '.. . . · .:; - .. ~:9,'.' .'.Can pemtt be approved before ten,day ~'_:.!0',':- o°es 'OPerator have' a bond :~'~Or~e . . i:'::13.: Will cement tie in sUrface and intermediate or :iOn strings ~.~ :~.;.:%'.:?::':i'!:'.':.'-,~:-' '~ ..... ',~- ' "- -.' :~ ~:''-'' ~-~ ~ ': ..... ' :::' ~-' :14,-- Will -C~ent 'CoVer-al'i:~"~O-SSible prodUcti, ..... . .:~..-.: ~- .:-.:: ~::- .:.~..: ~ -. ~_-. ~:.] -- ... _.~ ..... - .. _ . . .-. . 15. ~tll surface casing cover all fresh wa~er zones .... ~ ...-.-:....-', ~.. · .;~.. :-.. -.. - 16 ~tll surface csg. internal burs: equal .5 psi/ft. to next string . . . ;... · .'.... . : . . -.'~ _ _ .. _ . .~ ..' .- ; .' ; ~ *. . . 17.~tll al~castng give adequate safety in collapse and tension ." . * . ;~ ' . .... ~_ - .. .'.. ._ .~_.' ...."... _- ~ - ~ ' . _.. - ~..18..Does BOPE have sufficient pressure rating ..._.~.... : ) . -~/ ~ . . .. ~ : . ~ Additional Requirements: ~. .~ ~ ~..m~" ~' 7Y~ / . NOTICE The following well logs and oversized documents have been placed in offsite storage. If you would like to view the original documents, please contact the AOGCC librarian. AOGCC 3/4/2005 .. lenuC[Yf11TLI1 ICHLUMBERGER.�� 4.1'".'. _- 4: w COMPANY PHI �-L 1. PS PETROLEUM COMPANY o o t.,;, Z OZD J .L CD o - WELL - NORTH. COOK I NLET UNIT A} -I0 +►- >' ,:. o m � o FIELD NORTH COOK I NLET _ s .w CD a COUNTY KENAI BOROUGH STATE ALASKA � o Z Z Z y, location: LEG., 2 SLOT 6 -Other` Services: E.; Y O �- Z - PLATFORM TYONEK SNP , I ES 3�; _. r-- o 'p Z Q ° Uj W �_ 0 3 0 Sec. 6' 11.N R e._ 9W T W p•---,---- g Qz U U m G) M L LW Elev.: 0 Vev.: K.B._ 1_15..9' e V C - ,: , u Permanent Datum; Measured From K g` 1 1 59Ft. Above Perm. Datum j� D. F. 1 1 , � ) Z w �, ' Log G.L. Drilling Measured From K B a� Date 9/ 27/69 _ C W Run No: Q N E - o .00 a N T e to-----9250FDC-GR_ -- - - -a ' �' De th—Driller a - Dep—Loggerth _ - -- --- - ` -- a Bottom logged interval 2 - - - - --- - - ---- 0 Top logged interval _- — --- -- ----- o Type fluid in hole FRESH GEL . ___...-___--____-- Salinity, PPM Cl. 1900'Density - ----- -- E G Level - ------ __ ___ _---- Max rec. ternp., deg F. 116 --- -- - a Q _ O eratin' rigtime - - Recorded by CHAF F EY -DRAG E s Witnessed by S E EWA L D - - `- RECORD CASING RECORD To 0 RUN BORE -HOLE No. Bit - From, To Size W t. 82 0 1.0 3/ From SURFACE 2782 82 1 92 2 O Z - N C`