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Home My WebLink About181-1441. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ESP Completion Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,913 feet 9,238 (Fill)feet true vertical 7,917 feet N/A feet Effective Depth measured 9,320 feet 9,055 feet true vertical 7,439 feet 7,239 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 2-7/8' 6.5 / L-80 / EUE R2 9,019' 7,212' 3-1/2" 9.2 / L-80 / EUE 8rd 9,060' 7,242' Tubing (size, grade, measured and true vertical depth)4-1/2" 13.5 / L-80 / TSD 625 9,248' 7,348' Packers and SSSV (type, measured and true vertical depth)Baker Hyd. Set N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: Burst N/A Collapse N/A 2,670psi 7,020psi 5,380psi 6,870psi 8,160psi 8,455' 6,793' 4,760psi Conductor 7,904'9,900' 8,455' 2,300'Surface Production Liner 20" 13-3/8" 9-5/8" 110' 2,300' MILNE POINT / KUPARUK RIVER OIL MILNE PT UNIT D-01 Plugs Junk measured measured TVD 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 181-144 50-029-20664-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0047433 & ADL0047437 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 110' Size 110' 2,300' Length 1,802' Casing N/A Erik Nelson Erik.Nelson@hilcorp.com 907-564-5277 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 166 1,200 389 3,435347 0 00 243 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 324-559 & 324-658 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:39 pm, Jan 10, 2025 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.01.10 15:31:54 - 09'00' Taylor Wellman (2143) A.Dewhurst 06FEB25 DSR-1/16/25 RBDMS JSB 011525 JJL 2/7/25 _____________________________________________________________________________________ Revised By TDF: 1/10/2025 SCHEMATIC Milne Point Unit Well: MPU D-01 Last Completed: 12/7/2024 PTD: 181-144 TD =9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’ / Orig. GL Elev.: 9’ Parker #128 7” 9-5/8” 1 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) Kuparuk C 2 3 4 5 6 7 8 9 & 10 11 & 12 13 & 14 15 & 16 17 18 23 19 20 21 22 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRC 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRC 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRC 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE R2 2.441 Surface 9,019’ 3-1/2" Tubing 9.2 / L-80 / EUE 8rd 2.992 9,051’ 9,060’’ 4-1/2” Tubing 13.5 / L-80 / TSD 625 3.920 9,060’ 9,248’ JEWELRY DETAIL No Depth Item 1 172’ GLM #4: 2-7/8” x 1” Patco w/ BK-DGLV 2 2,112’ GLM #3: 2-7/8” x 1” Patco w/ BK-DGLV 3 2,177’ D&L 9-5/8” ESP Retrievable Packer w/ Single Vent Valve 4 2,235’ GLM #3: 2-7/8” x 1” Patco w/ BK-DGLV 5 2,294’ HES X-Nipple w/ RHC-M Installed 6 8,098’ Hyd. Liner Hanger 7 8,788’ GLM #1: 2-7/8” x 1” Patco w/ BK-DGLV 8 8,845’ HES XN-Nipple 2.313" Profile,2.205" No-Go 9 8,927.9’ Bolt on Discharge Head: 400X, 416 SS 10 8,9278’ Discharge Adaptor: Vigilant, 2 7/8'' SS 11 8,929’ Pump #2: 400,SF675,141S,15,INC,1:1,SHB,D7,TS3 12 8,951’ Pump #1: 400,SF675,141S,15,INC,1:1,SHB,D7,TS3 13 8,973’ Gas Separator: High Flow, Upper Tandem, 400X, Vortex 3 14 8,977’ Intake: Sub-Assy A/R, 400X, 416 SS, Inconel Shaft 15 8,978’ Upper Tandem Seal: 400 Series, BPBSL, Inconel Shaft 16 8,986’ Lower Tandem Seal: 400 Series, BPBSL, Inconel Shaft 17 8,994’ Motor: 456 Series, FMS2-HT, 126HP/2745V/32.2A, 12 Rotor 18 9,015’ Gauge & Centralizer: 2XPRES,2XTEMP,2XVIB –Btm@ 9,019’ 19 9,051’ 3-1/2” Baker Scoop Guide 20 9,055’ 3-1/2” Baker Hyd set Packer 40K shear 21 9,060’ 3-1/2” x 4-1/2” X-Over 22 9,247’ Bull Nose Shoe:Btm @ 9,248’ 23 9,383’EZSV Retainer PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,178’ 7,317’ 7,331 18 11/27/2024 Open 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,178’ 9,198’ 7,326’ 7,343’ 20 11/26/2024 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8"500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” HoleWELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 ESP Swap, Perf & Lower Screens Install by ASR – 12/7/2024 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite SCREEN DETAIL 4-1/2” Screen Pro Screen (250ђ) 4 1/2" TSH 625 BxP 3.849 9,086’ 9,209’ Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 CTU#1 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 Load tubing with hot brine, Pumped 22 bbls hot 9.9 brine down Tubing No operations to report. 11/2/2024 - Saturday Continue POOH pumping KWF taking returns out tubing and IA. Perform 30 min no flow test confirm well is dead. FP cap on Tubing and IA w/ 60/40. Perform 2nd 30min no flow test. Verify no flow. RDMO. 11/5/2024 - Tuesday 11/3/2024 - Sunday Continue rigging up. Function test BOPs 350 Low/ 4,300 High - Pass. RIH w/ 2.25" BDJSN. Tag ball catcher @ 8988' CTM. PUH and stand by for fluids. While waiting on fluids weather deteriorates, POOH until weather improves. Phase conditions reduced. RIH and tag ball catcher at 8982' CTMD. Begin circulating 9.8 brine at 0.9 bpm maintaining BHP. Circulate brine to surface up the IA and tubing. Once clean fluid returns begin chasing OOH taking returns out tubing and IA. 11/4/2024 - Monday 11/1/2024 - Friday No operations to report. 10/30/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/31/2024 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 CTU#1 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 Level out rig, Spot in tool trailer & connexs. Mobilize MP #2 unit from i-pad. Lay out koomie lines & install in BOPE. Spot in MP #2 unit. R/U fluid line & electrical. Personnel injured on site. Send to medic for evaluation. IP sent back to work. Stand mast up. Install rack pins. Continue working on rig acceptance checklist. Connect hydraulics to tongs, catwalk & test pump. Set alarm parameters for canrig pvt testing. Complete rig acceptance checklist. Rig accepted at 17:30 on 11-09-2024 Shell test prior to state witness. Test BOPE as per approve sundry. AOGCC rep Kam St. John witnessed all testing. Tested to 250 psi low & 3000 psi high f/ 5/5 charted mins. Perform accumulator draw down. 11/9/2024 - Saturday Cont. trip out of hole with 3.5" 9.3# dss-ht F/ 7,178' T/ 5,340'. ESP cable stopped coming up with pipe RIH w/ 2 joints, no cable movement. Pump friction reducer. Pump 186 BBLs w/ NSX lube down tubing taking returns up IA Pipe still free, ESP cable not moving w/ pipe begin alternating pull pipe 15' and pulling cable 15' with clamp on ESP cable using winch. Cont. POOH w/ 3.5" 9.3# dss-ht f/ 5,255' P/U wt = 39K. Pulling/stripping ESP cable up hole with clamps and tugger. T/ 4,493' P/U wt = 38K. 11/10/2024 - Sunday Completed testing BOPE with no failures. Load pits with 9.9 ppg NACL brine. P/U tee bar. Pull CTS & BPV. L/D tee bar. P/U landing joint. Engage landing joint into hanger. Open IA static. BOLDS. Attempt to pull hanger to floor. work up to 120K X5. Pump 70 BBLs down tubing taking returns though choke. Open annular. P/U. Work pipe to 126K PKR sheared. PUW now 78K. Close annular and pump BU to clear Packer gas. L/D Hanger. POOH w/ ESP pumping double displacement. L/D SSSV and ESP packer. Rig up to pump BU.Pump down tbg taking returns up IA. Returning 9.5 ppg send to tiger tank. Weighed up brine w/ NaCl in pits to 9.9ppg. Circ. until 9.9ppg returns observed.Cont. trip out of hole trip out of hole with 3.5" 9.3# dss-ht f/ 8,795' P/U wt = 74k T/ 7,178' P/U wt = 62K. Fill double displacement. 11/11/2024 - Monday 11/8/2024 - Friday Spot in mud boat. Spot in crane. Move pits to D-pad & spot. Fly on cellar. Begin removing production tree with wellhead rep. Removing bolts from well head requiring bolts to be cut off. Spot in pits. All bolts removed from tree. Mobilize crane to location. LRS fill well w/ 31 BBLs 9.9 brine. Wellhead rep. using flange wedges to unseat production tree. Spot in trailer with work floor. finish picking up containment on I-pad. while awaiting crane to arrive. Move pusher shack, crew quarters, and company man shack from e-pad to d-pad. Spot in crane. N/D & pick production tree. Install and test cts plug to 5000 psi. (good). Install bop stack on well head. Fly rig floor & set in place on top of cellar. Fly spacer & flow spools on top of BOPE. Connect choke and kill lines. Spot in rig on mud boat and lay out chains, boomers, matting boards, and guyed lines. lay out and connect all electrical and communication lines between pusher shack, rig, and pits. 11/6/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Well Warm Up and Load Pre RWO, Pumped 22 bbls warm 9.9 brine into tubing 11/7/2024 - Thursday N/U production tree with wellhead rep. Torque up studs. Perform void pressure test t/ 500 psi low 5000 psi high f/ 5/10 mins. (Good) Pull bpv. Secure well site. With crane fly cellar to trailer and secure, pick and fly all heaters from behind the well. Load out rig mats on i-pad transport to D-pad for rig layout. Pad uneven on D-pad. Pull rig mats & resurface pad around well. Finish spotting in rig mats on D-01. Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 CTU#1 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 Hilcorp Alaska, LLC Weekly Operations Summary Cont. POOH w/ 3.5" 9.3# dss-ht F/ 4,493' P/U wt = 38K. Fill with single displacement. Pulling/stripping ESP cable up hole with clamps and tugger. At 3,210' Spooler able to pull cable Cont. POOH w/ 3.5" 9.3# dss-ht F/ 3,210' - T/ 80'. B/O perforated joint, joint packed off with sand above XN. L/D pumps and motor. All equipment intact. Remove flat guards from pumps. ESP cable attached to motor. Recovered 350 bands & 2 flat guards. R/D ESP sheave and containment hose. Clean & clear rig floor. Extend time cleaning due to heavy crude on all tools, tongs, floor mats ect. 11/12/2024 - Tuesday Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 ASR#1 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 11/15/2024 - Friday POOH W/ 9-5/8" RCJB laying down singles of 3-1/2" G-105 NC-31 workstring F/ 6,830' - T/ 66' Well returning correct displacement. L/D RCJB BHA. Recovered 10 bands & 10 pounds of debris. Decision made to attempt to MIT well. Line up to test. Close blinds & fill lines. Pressure up well to 1,800 psi. Immediately bleeding to 1,600 psi & stabilizing. Final test pressure 1,590. Not achieving desired test pressure. Test PKR run still in scope. Down time change out swivel pipe packing & trouble shoot kerr. P/U & M/U 7" liner clean out BHA. RIH W/ 7" RCJB clean out 3-1/2" G-105 NC-31 workstring F/ 51' - T/ 3,053' Well returning correct displacement. Rig PTO kicked out. Down time. Trouble shoot PTO on rig. Run continuous hole fill. Well static. 11/13/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Spot in Slick line truck. R/U SL sheave & raise. Run continuous hole fill. Lossing 0 BPH. P/U & M/U 3.2" magnet with 3.72" centralizers. RIH w/ SL assy. to 4500' SD. work through. Decision made to POOH & check magnet. OOH w/ SL. recovered 2 bands. Install wire brush above magnet. RIH W/ SL T/4820'. POOH recovered 87 Bands with partial pieces. Observed medium chunks of scale on magnet & brushes. Change SL BHA to GR 8.38" & Junk basket. RIH. Tag w/ JB at 8,084' Recover 2 gallons of scale chunks & sludge recovered. Cont to RIH w/ GR& JB. 11/14/2024 - Thursday OOH w/ SL. Recovered 4 gallons of small pieces of scale. R/D SL. P/U & M/U 9-5/8" RCJB clean out BHA. 8" RCJB. 2 x 7" string magnets, 2 x 7" boot baskets & jars. RIH W/ 9-5/8" RCJB on 3-1/2" G-105 NC-31 workstring F/ 66' T/ 7,911' S/O wt = 47K Well returning correct displacement. Begin Washing down. Wash down w/ RCJB f/ 7,911' at 4 BPM w/ 700psi to tag TOL at 8,106' RKB corr. Set down 6K. Confirm tag. P/U off liner top 1'. Rotate & recip. F/ 8,105' T/ 8,031' Pump at 4.5 BPM w/ 1100 psi. Pump over a BTU for 623 bbls. No pressure change. Shut down pumps. Returns clean & 9.9+ PPG brine. POOH W/ 9-5/8" RCJB laying down singles of 3-1/2" G-105 NC-31 workstring F/ 8,105' T/ 6,830' Well returning correct displacement. P/U wt = 62K S/O = 42K. Cont. RIH W/ 7" RCJB clean out on 3-1/2" G-105 NC-31 workstring F/ 3,053' Well returning correct displacement. RIH to 8,090'. Attach kelly hose. Found kelly hose failure on sheath & exterior wrap. Replaced kelly hose. Remove from derrick & install new. Completed kelly hose install. Tag TOL at 8,106. ROT in liner at 30 RPM TQ = 1,340 ft/lbs. Cont. RIH in 7" casing. T/ 9,150'. Reverse circ to remove 9.3 ppg t brine from wellbore. Reverse circulated with bag closed at 2 BPM w/ 760 psi. Sent 25 bbls to tiger tank. Wash & ream down at 4.5 BPM w/ 1,350 psi. f/ 9,150' - t/9,210' Setting 6-8k work through tight spots & back reaming. At 9,250' set10K down in tight spot. Weight did not drill off. P/U to ream. S/O TQ increased to 7,200 ft/lb torque & stalling. P/U observing overpull. Attempt to free P/U to 100k f/ 19K over. Torque remains, Attempt to free setting dw to 15K & over pulling 25K. Remove torque from string to begin jarring operations. S/O to 48K cock jars and pulled to 120K . Jars fire. Make marks & continue jarring. 11/16/2024 - Saturday 11/17/2024 - Sunday Cont. to jar. Attempt to free, setting dw to 15K & over pulling up to 60K. Use varying weight in elevators & jar weights to free pipe. Pipe free. P/U wt = 79K Cont. POOH. Cont. POOH W/ 7" RCJB laying down singles of 3-1/2" G-105 NC-31 workstring F/ 9,266' - T/6,931'. Line up to perform well test. Hard shut in well. Pressure test to 1,750 psi on chart. Pressure bled down to 0 psi within 10 min. Test again to verify with same results. Completed test. Cont. POOH. After test losses = 1.5 BPH. Cont. POOH W/ 7" RCJB laying down singles of 3-1/2" G-105 NC-31 workstring T/1,211'. Pump double displacement P/U wt = 13K S/O wt= 11K. Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 ASR#1 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 Hilcorp Alaska, LLC Weekly Operations Summary OOH w/ SL. Metal shavings & 1 band on magnet. RIH w/ 3.25" magnet. Tag liner top at 8,099'. Change BHA. RIH w/ 2.3" magnet for entering liner top. RIH At 9,140' (just above perfs) w/ slick line. POOH OOH w/ SL. No recovery of tong die or ESP band. R/D slick line. M/U Dual scraper & 7" test PKR assy. M/U bull nose 25 jts, 7" scraper & 7" AS1-X Test PKR. T/ 6,721' Well returning correct displacement. No losses. At 6,721' P/U 9-5/8" scraper & pup. XO to WS. Cont. RIH. Cont running in the hole w/ Dual scraper & PKR Assy. on 3-1/2" G-105 NC-31 workstring T/ 8,070'. Line up to reverse circulate down. M/U Jt # 201 on tally. Close annular. Reverse at 3 BPM w/ 700 psi. Pump BTU at 1' above liner top. Wash down reversing at same rate to 8,160' P/U wt = 71K S/O wt = 43K with annular closed. Cont. POOH W/ 7" RCJB laying down singles of 3-1/2" G-105 NC-31 workstring f/1,211'. L/D RCJB & inspect. BHA intact. Clean out RCJB. Sending to shop for further disassembly & recovery. Pull wear ring & install test plug. Flood BOP stack with fresh water & flush. Purge air out of lines. Test BOPE as per approve sundry. AOGCC waived witness to testing. Test to 250 psi low & 3,000 PSI high f/ 5/5 charted mins. Completed BOPE testing & accumulator draw down with no failures. Install wear bushing. M/U BHA. Running dual scraper & test PKR assy. P/U mule shoe XO to work string. RIH w/ mule to 521' w/ 3-1/2" G- 105 NC-31 workstring. Tong die observed descending from tongs and falling into wellbore. POOH watching for over pull. None. Slick line on location. Spot & R/U unit. M/U 3.25" magnet & BHA tools. RIH w/ slick line BHA to 6,700' End of build. POOH. 11/19/2024 - Tuesday 11/18/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 ASR#1 & WH 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 WELL SHUT IN ON ARRIVAL.T/IA/OA=100/0/0. RIG UP AKE PCE FUNCTION TEST WLV'S. PT 250 L 3000 H. PERFORATE (9178- 9198) 20', 2 3/4", 6 SPF, 60 DEGREE PHASE, 15 GRAM CHARGES. CCL STOP DEPTH=9169.3 (CCL-TS=8.7'). T/IA/OA=100/0/0. JOB TO BE CONTINUED 27-NOV-2024. WELLSHUT IN ON DEPARTURE. WELLHEAD: M/U hanger to Landing joint then to string, landed hanger with BPV installed to RKB of 15.71' RILDS, S/B for RDMO, cleaned up hanger, replaced 4ea bad LDS, N/U tree/adapter, Tested void 500 low 5000 high 5/10 min good test, pulled BPV with Tbar, secured well. 11/23/2024 - Saturday WELL SHUT-IN ON ARRIVAL. TAG HARD BOTTOM AT 9,235' SLM W/ 20' x 3.70" DUMMY WHIPSTOCK (No issues). WELL SHUT- IN ON DEPARTURE, PAD OP NOTIFIED. 11/26/2024 - Tuesday 11/24/2024 - Sunday No operations to report. 11/25/2024 - Monday 11/22/2024 - Friday Continue RDMO from MPD-01. Perform mast inspection, service rig. ND BOPE, NU Tree, and test void 500/5000psi - good. Pull BPV. 11/20/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Cont running in the hole w/ Dual scraper & PKR Assy. on 3-1/2" G-105 NC-31 workstring f/ 8,160' Well returning correct displacement. At 9,140' Reverse at 3 BPM w/ 750 psi. Wash down reversing t/ 9,247' with annular closed. Pump BTU, send light fluid to tiger tank. Set 7" AS1X test packer with COE at 8,229'. Test CSG to 1750psi for 30 charted min. Good. POOH w/ BHA F/ 9,247' - T/ 1,076'. 11/21/2024 - Thursday POOH w/ BHA Dual scraper & PKR Assy. on 3-1/2" G-105 NC-31 workstring F/ 1,076'. Recover missing tong die from BOP cavity. Test VBR/Annular 250/3000psi - Good. (Witness waived). RIH w/ 4-1/2",12.6#,L, BTC kill string. Dispacement as calculated. Land hanger placing EOT at 4,007'. RILDS. RDMO Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 EL, FB 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 Test BOPE 250/3000psi as per sundry. AOGCC witness waived. Pull CTS/BPV. Displace MEOH freeze protect w/ 9.9ppg NaCl. Install landing joint, BOLDS. Pull 4-1/2",12.6#,L,BTC kill string from 4,007'. Load and process screen BHA/WS in pipe shed. Install 6.875" wear ring and RILDS. WELLHEAD: Set 4" CTS Bpv with T bar, pre RWO. Freeze Protect (RWO Rig Delayed), Pumped 14 bbls 60/40 down IA, Well pressureing up with TxIA communicatoin. 11/30/2024 - Saturday Continue mobilizing equipment to D-Pad and spotting in. N/D Tree, N/U BOP. Complete rig acceptance checklist (Accepted at 22:00). Begin testing BOP per Sundry/AOGCC. 12/3/2024 - Tuesday 12/1/2024 - Sunday No operations to report. 12/2/2024 - Monday 11/29/2024 - Friday No operations to report. 11/27/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL SHUT IN ON ARRIVAL. T/IA/OA=100/0/0. RIG UP AKE PCE. PT 250 L 3000 H. PERFORATE (9160-9178) 2 3/4" GUN, 6 SPF, 60 DEGREE PHASE, 15 GRAM CHARGES. CCL STOP DEPTH=9149.4 (CCL-TS=10.6'). T/IA/OA=100/0/0. JOB COMPLETE. WELL SHUT IN ON DEPARTURE. 11/28/2024 - Thursday Bleed off Tubing gas cap from 55 psi to 0 psi, no flow test for 30 min, shut in and monitor for 30 min with 0 psi gain, Pumped 8 bbls 60/40 down Tubing, Pumped 10.5 bbls 60/40 down IA pressured up TxIA to 500 psi, Leave pressure overnight. Well Name Rig API Number Well Permit Number Start Date End Date MP D-01 ASR & WH 50-029-20664-00-00 181-144 11/3/2024 12/10/2024 12/6/2024 - Friday Cont. RIH W/ ESP completion on 2-7/8" 6.5# L-80 EUE F/ 806' T / 6,700' Test ESP cable every 1000'. Well losing 1 BPH. Code 8. Planned downtime troubleshooting ongoing speed issues with rig. Replace Joystick base and joystick. Completed troubleshooting. RIH Cont. RIH W/ ESP completion on 2-7/8" 6.5# L-80 EUE T/ 6,835'. P/U ESP PKR. Perform ESP cable splice through PKR. Simops. Clean & completed maintenance tasks on rig. 12/4/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary P/U M/U sump PKR & /250 Micron screen assy. RIH Filling each jt on the fly and topping off every 15 jts. on 3-1/2" G105 NC- 31 WS T/ 9,210' ' Kelly up. Place PKR on depth. Pressure up to set PKR. Pressure up at 1,800 psi, observed shear. S/O 20K on PKR for 36K string wt. Cont. pressure up to 2,500 psi. Hold for 15 charted mins. A48 Line up & pressure test IA. Test PKR to 1,750 psi. good test. Line up & pump to shear burst disc. Disc sheared. Established injection rate at .5 BPM w/ 1600 psi. for a total of 5 bbls pumped. P/U to shear running tool out of scoop guide. P/U to 116K for 30K over. New P/U wt = 81K. S/O to ensure Sump PKR set/depth. Tag Top of scoop 1' deep. New depths; End of bull nose = 9,247' COE 9,056. Scoop guide = 9,051. B/D fluid lines. begin POOH f/ 9,051' . Cont, POOH w/ running tool. Laying dw to pipe shed 3-1/2" G105 NC-31 WS F/ 9,051' T/ 7,492' P/U = 68K. 12/5/2024 - Thursday Cont, POOH w/ running tool. Laying dw 3-1/2" G105 NC-31 WS to pipe shed F/ 7,492'. OOH, L/D running tool. Intact. Pull Wear ring. Load pipe shed W/ ESP equipment. Start P/U & service ESP equipment. P/U & service motor, Service tandem seals. Tie in motor lead. M/U pumps, discharge head & handling pup. Tie in control line to discharge. P/U one jt of 2.875" 6.5# l-80 eue. Test ESP (good). Cont. RIH W/ ESP completion on 2-7/8" 6.5# L-80 EUE F/ 132' - T/ 806'. DEPLOY BALL & ROD ASSY TO RHC BODY @ 2,294' MD. LRS CIRC'D IN 151 BBLS OF DIESEL THROUGH ST#2 FOR FREEZE PROTECT. PULLED BALL & ROD ASSY FROM RHC BODY @ 2,294' MD. PULLED BK-DGLV FROM ST#1 @ 171' MD. SET BEK- DPSOV IN ST#1 @ 171' MD. SET BK-DGLV IN ST#2 @ 2,112' MD. PULLED 2-7/8" RHC BODY FROM X-NIPPLE @ 2,294' MD. Completed PKR splice. Test ESP cable (good). Attach Cap line to PKR. Test & function vent valve. (good) RIH W/ ESP completion on 2-7/8" 6.5# L-80 EUE F/ 6,835' - T/ 7,790' Test ESP cable every 1000'. Well losing 1 BPH. Begin reel to reel splice Reel to reel splice completed. Cont. RIH W/ ESP completion on 2-7/8" 6.5# L-80 EUE T/ 9018'. P/U & M/U hanger. Test cable. good test. Begin hanger splice. Complete hanger splice. Test ESP cable (good) Run cap line through hanger. Test cap line to 5,000 psi. bleed to 500 psi for landing. Land & RILDS. Test cable. Good. End of ESP completion at 9,018.97' Drop ball & rod. Pressure up to set ESP PKR. Pressure up IA to test ESP PKR to 1550 psi. Hold for 30 charted mins. Good test. Bleed off B/D fluid lines. & remove landing joint. P/U tee bar. Install BPV. Simops. Remove pipe shed. Remove 9.9 ppg brine from pits & rig fluid lines. 12/7/2024 - Saturday PULLED BALL & ROD ASSY FROM 2-7/8" RHC BODY @ 2,294' MD. PULLED BK-DGLV FROM ST#2 @ 2,112' MD. 12/10/2024 - Tuesday 12/8/2024 - Sunday Welllhead: Land 2-7/8" EUE Tubing hanger P134137-0001, RILDS, rig set vent packer, set CTS BPV, Rig nipple down BOPs, Nipple up 2-9/16 tree and adapter, Tested adapter to 500/5000 PSI for 10 mins. All tests good. Pull BPV with dry rod. RDMO 12/9/2024 - Monday Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887 MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241205 Well API #PTD #Log Date Log Company Log Type AOGCC ESet AN 15(GRANITE PT ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24 MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Please include current contact information if different from above. T39808 T39809 T39810 T39810 T39811 T39812 T39813 T39813 T39814 T39815 T39816 T39817 T39818 T39819 T39820 T39820 T39821 T39822 T39823 T39823 T39823 T39823 T39824 T39825 T39826 T39827 MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.05 14:52:46 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Completion 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9.Property Designation (Lease Number):10.Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,913'N/A Casing Collapse Conductor N/A Surface 2,670psi Production 4,760psi Liner 7,020psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng KUPARUK RIVER OIL N/A 7,917' 9,320' 7,439' 2,710 9,238 (Fill) Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT D-01 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 11/26/2024 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047433 & ADL0047437 181-144 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-20664-00-00 Hilcorp Alaska LLC C.O. 432E Length Size Proposed Pools: 110' 110' 9.3# / L-80 / EUE 8rd TVD Burst 9,072' MILNE POINT MD N/A 8,160psi 5,380psi 6,870psi 2,300' 6,793' 7,904' 2,300' 8,455' 110' 20" 13-3/8" 9-5/8" 2,300' 7"1,802' 8,455' OTIS RDH and FMX TRSV 588 MD/ 588 TVD and 572 MD / 572 TVD Erik.Nelson@hilcorp.com 907-564-5277 Perforation Depth MD (ft): 9,900' See Schematic See Schematic 3-1/2" Erik Nelson No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:31 pm, Nov 20, 2024 Digitally signed by Scott Pessetto (9864) DN: cn=Scott Pessetto (9864) Date: 2024.11.20 13:36:55 - 09'00' Scott Pessetto (9864) 324-658 10-404 DSR-11/21/24 Witnessed BOP and Annular Test to 3000 psi. A.Dewhurst 21NOV24 X * Approved to operate with tested packer to 1500 psi. - Charted pressure test. MGR26NOV2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.26 11:39:19 -09'00'11/26/24 RBDMS JSB 112624 Well: MPU D-01 Scope: ESP Swap 20 November 2024 Well Name:MPU D-01 API Number:50-029-20664-00-00 Current Status:Producer [Shut in ESP]Pad:D-Pad Estimated Start Date:26 November 2024 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts Permit to Drill Number:181-144 First Call Engineer:Erik Q. Nelson (907) 564-5277 (O) (907) 903-7407 (M) Second Call Engineer:Taylor Wellman (907) 777-8343 (O) (307) 660-4999 (M) AFE Number:Job Type:ESP Swap Current Bottom Hole Pressure: 3567 psi @ 7438-ft TVD Downhole Gauge 08Sep24 |9.2 PPGE MPSP:2823 psi (0.1psi/ft gas gradient) Max Deviation:52° @ 4700 – 5000-ft MD Max Dogleg:6.5°/100-ft @ 2600-ft and 6600-ft MD Min ID:2.75” @ 602-ft MD 3-1/2” XN Nipple BPV Profile: 3” Type H Brief Well Summary: Well MPU D-01 was drilled by Parker #278 in 1982 and initially completed in the Kuparuk A sand which were found to be wet. A drill stem test of the Kuparuk C sand was completed with a ~500 BOPD rate. The well was plugged back and completed in the Kuparuk B and C sands in 1989. A mud acid stimulation and frac was completed in 1989. A cleanout was completed on the well and ESP ran in November 1989. The well operated for approximately one year until November 1990 when it appears the pump stopped working, possibly plugged up with solids. The well has remained shut in since 1990. A flow test was completed and confirmed approximately 9% max water cut, and thus the well is being progressed for a RWO. The productivity of the well during the one-year flow period showed rates ranging from 170-350 BOPD. Unfortunately, no flowing BHP data is available to determine PI ranges but given the SBHP after shutdown of ~2,500 psi, the range is estimated at 0.17 to 0.3 bbl/psi. Note that this well will run #4 ESP Cable (smaller than #2) and is uncommon at MPU. Please verify all clamps, penetrators, and cable is on location. This re-submittal will address the pause in our work on MPU D-01 and resumption of work after we finish work on MPU J-02. Objective: x Pull 3-1/2” ESP Completion x Perform 7” Scraper run and Tag Fill x Cleanout fill if necessary. x Run 7” Test packer. Test production casing x Run new 2-7/8” ESP Completion Notes Regarding the Well & Design x Circulating Sub @ 9,032’ MD is sheared x ESP Packer pinned for 30K over string weight x Offset Injector Support o No known injection support. Well: MPU D-01 Scope: ESP Swap 20 November 2024 o Aquifer support x 13-5/8” Wellhead. Will require a 13-5/8” x 11” crossover spool. x Passing MIT (1750 psi) of the 7” csg from 8200-ft MD, 7” x 9-5/8” lnr hgr, and 9-5/8” csg to surface on 20 Nov 2024. x Well is currently stable with 9.9 lb/gal fluid in the hole. We anticipate that this will continue to be the case when freeze protect is circulated in the kill string and inner annulus. x Well will be left with a 4-½” kill string hung off at ±4000-ft MD Pre-Rig Procedure Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500-barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Bleed down tubing and IA pressure to zero. 6. Reverse circulate at least one wellbore volume down annulus, taking returns up the circulation sub at 9,032’ MD (725 bbls) with 9.4 ppg brine down tubing, taking returns up casing to 500 barrel returns tank. a. Continue circulating until no gas is seen. 7. Bullhead down tbg for a volume of 87 bbls taking returns to formation: 8. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 9. RD Little Red Services and reverse out skid. 10. Set BPV and CTS plug. Brief RWO Procedure 1. MIRU ASR #1 Rig. 2. ND tree. NU BOPE. a. When ND tree, ensure that control line to the vent valves is pressured up and capped. Note and highlight to crew that cap-string will have pressure on it when recovering hanger. This will keep vent valve and SSSV open. 3. Test BOPE to 250psi Low/3,000psi High, annular to 250psi Low/3,000psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Perform Test per ASR #1 BOP test procedure. d. Test the 2-7/8” x 5” VBR’s with 2-7/8” and 3-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull CTS Plug. Check for pressure below the BPV. a. If indications show pressure underneath BPV, lubricate out BPV and re-kill as needed. 5. Call out Baker Hughes. Rig up spoolers for #4 cable and ¼” SS cap-string. 6. MU landing joint, BOLDS, PU on the tubing hanger. Well: MPU D-01 Scope: ESP Swap 20 November 2024 a. The current completion has an estimated dry string weight of 85 Klbs, and 73 Klbs with 9.4 ppg fluid. b. The ESP packer is pinned to shear release at 30k overpull. Estimated PUW to release packer is 103k – 115k. Work pipe up in 5 Klbs increments to 120k and contact OE for discussion before pulling higher. c. Prepare for packer gas. Close annular and forward circulate, taking gas returns up annulus. Circulate out one full wellbore volume of 9.4 ppge KWF. i. Note that the packer is very shallow. 7. Confirm hanger free, lay down tubing hanger. a. Bleed off pressure from control line prior to laying down hanger. 8. POOH and lay down the 3-1/2” tubing and ESP completion components. a. Clamps to be recovered, washed and saved for re-use if possible. 600 ESP Cable Clamps 25 SS Clamps 4 Flat Guards (Only shown on ESP invoice* from 1989) 9. Lay Down ESP. a. Note that there should be an 18’ 5.5” OD Motor Shroud that may need to be cold cut on surface. b. Document the condition of motor, seals, and pump. 10. PU 3-1/2” Work-string. 11. MU 7” rotatable casing scraper with bit on bottom on work-string and TIH to tag fill. Reverse circulate and clean out fill to 9,250’ MD. 12. POOH and LD casing scraper. 13. MU 7” test packer and TIH to 8200-ft MD 14. Test 7” x 9-5/8” production casing to 1750 psi for 30 minutes charted. a. Minimum required 6825’ TVD x 0.25 psi = 1706 psi. Above work has been done and is considered complete as of 20 November Below work is to be completed in order to pause our work on MPU D-01 15. TOOH w/ test pkr assy and lay down same 16. Test 2-7/8” x 5” VBRs with 4-½” test jt to 250psi Low/3,000psi High. Record accumulator pre- charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Perform Test per ASR #1 BOPE test procedure. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 17. MU and TIH w/ 4-½” kill string to ±4000-ft MD 18. PU and MU the 4-½” tbg hgr 19. Land tbg hgr. RILDS. Record PU and SO weights on tally and AWGRS. 20. Set BPV. ND the BOP stack. Set CTS Plug. 21. NU the tubing head adapter and tree Well: MPU D-01 Scope: ESP Swap 20 November 2024 22. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 23. Pull CTS plug and BPV 24. Replace gauge(s) if removed. Secure the tree and cellar. 25. RDMO ASR Post-Rig Procedure Pumping & Well Support 26. FP well w/ ±34 bbls down the tbg and ±118 bbls down the IA Below work is to be completed when ASR returns to MPU D-01. Screen assy (Steps #34 thru #41) was not part of the original Sundry Approval (324-559) but was approved via email on 15 November 2024 27. MIRU ASR 28. ND tree. NU BOPE. 29. Test BOPE to 250psi Low/3,000psi High,annular to 250psi Low/3,000psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test b. Confirm test pressures per the Sundry Conditions of approval c. Perform Test per ASR #1 BOPE test procedure d. Test the 2-7/8” x 5” VBR’s w/4-½” and 2-7/8” test jts e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test 30. Pull CTS Plug. Check for pressure below the BPV. a. If indications show pressure underneath BPV, lubricate out BPV and re-kill well as needed 31. MU landing joint, BOLDS, PU on the tubing hanger. 32. Confirm tbg hgr free, lay down same 33. POOH and lay down 4-½” tbg kill string 34. MU and TIH w/ Screen Assy: NOTE: Contact OE for fill schedule while TIH to avoid premature set of the pkr a. Bull Nose Shoe w/ 4-½”, 13.5# L80 TSH 625 Box (5.220-in OD) b. (1) jt 4-½”, 13.5# L80 TSH 625 B x P c. (3) jts R3 250ђ screens on 4-½”, 13.5# L80 TSH 625 B x P (5.100-in OD shroud) d. X-over sub 4-½”, 13.5# L80 TSH 625 P x 4 ½”, 12.6# JFE Bear B e. 4-½”, 12.6# L80 JFE Bear Glass Float Sub (4K psi shear) w/ 4-½”, 12.6# L80 JFE Bear handling pups f. X-over sub 4-½”, 12.6# JFE Bear P x 3-½”, 9.3# L80 EUE 8rd Box g. Hyd Set, STR retrievable pkr w/ 3-½”, 9.3# EUE 8rd B x P h. 3” Seal Bore w/ 3-½”, 9.3# EUE 8rd P x P i. Scoop Guide w/ 3-½”, 9.3# EUE 8rd B j. Scoop Guide Running Tool w/ 3” bonded seals and 2-3/8” Reg Box k. X-over back to ASR workstring 35. Obtain PU/SO weights prior to crossing the perfs with the screen assy 36. TIH to so Bull Nose Shoe is at ±9253 MD Well: MPU D-01 Scope: ESP Swap 20 November 2024 37. Set pkr per vendor procedures 38. Pressure up to 1750 psi on IA to ensure pkr is set. Bleed pressure off IA upon confirmation. 39. Blow burst disc 40. Shear off of Scoop Guide NOTE: Confirm PU weights so as to only shear off of the Scoop Guide and not the STR pkr 41. TOOH w/ workstring 42. Clean and clear rig floor for 2-7/8”, 6.5# L80 EUE 8rd ESP completion run 43. Call out Summit ESP to run Completion. 44. PU and MU new ESP assembly. Set base of ESP assembly at ±9,045-ft MD (will change from original Sundry Approval to accommodate approved Screen Assy). Check electrical integrity test every 1,000’. Install clamps on the first 15 joints then every other joint to surface. a. Motor centralizer b. Motor gauge unit c. ESP motor d. Lower tandem seal e. Upper tandem seal f. Gas separator g. Pump #1 h. Ported discharge head i. Bolt on discharge head with pup joint, 2-7/8”, 6.5#, L-80, EUE 8rd box up j. 2 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing k. Nipple, HES XN-Nipple (2.205”) with 10’ handling pups above and below. l. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing m. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below. n. Multiple joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing o. Nipple, HES X-Nipple (2.313”) with 10’ handling pups above and below.RHC plug body installed p. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing. q. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below r. Packer with crossover pups a. TriPoint 9-5/8” ESP retrievable with single vent valve (setting depth = ±2,200’ MD) 45. PU and MU the Tri-Point packer. Verify that there are 4 setting shear pins and confirm w/ OE number of release shear pins. a. Double check direction of packer slips and pinned settings. b. Run packer slow at >30 seconds per joint to prevent premature hydraulic setting. c. Shear pins will be dependent upon expected PUW of completion. Initial target is 20k overpull to release. d. Document packer with photos above and below all jewelry as installed on 2-7/8” tubing. e. Document on tubing tally that max pull on packer after set is 124,000 lb. Well: MPU D-01 Scope: ESP Swap 20 November 2024 46. Terminate the ESP cable and MU the ESP penetrator to the ESP cable. Ensure the 3/8” NPT control line feed thru port is dummied off. 47. MU the control line to the vent valve. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in AWGRS). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while RIH. 48. Continue to RIH with ESP completion. Check electrical integrity test every 1,000’. a. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing b. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±2,170’ MD) c. Multiple joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing d. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±175’ MD) e. 4 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing 49. PU and MU the 2-7/8” tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 50. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in AWGRS). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while landing the hanger. 51. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator, or control line. RILDS. Record PU and SO weights on tally and AWGRS. 52. Drop the ball & rod and allow time for it to gravitate to the ball seat. 53. Pressure up on the tubing to 2,000 psi and hold for 15 minutes to set the packer. Bleed the tubing pressure to 0 psi. Pressure back up to 2,000 psi and hold for 5 minutes then bleed to 0 psi. a. Note that packer is designed to begin setting at 1,247 psi of differential pressure. 54. Bleed the control line pressure to 0 psi to close the vent valves. 55. Slowly pressure up at 50 psi/min on the IA to 1,500 psi and hold for 30 minutes on chart recorder. a. Bleed pressure off in 50% increments per 30 minutes to prevent gas expansion and cable damage. 56. Set BPV. ND the BOP stack. Set CTS Plug. 57. NU the tubing head adapter and 2-9/16”, 5M tree. 58. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 59. Pull CTS plug and BPV. 60. Replace gauge(s) if removed. Secure the tree and cellar. 61. RDMO Post-Rig Procedure: 1. Turn well over to production via handover form. 2. RU well house and flowlines. 3. RU HES slickline. 4. Pull the ball and rod. 5. Pull DV from GLM at ±175’ and install 1/4" DP-OV. 6. Pull RHC plug body. 55. Slowly pressure up at 50 psi/min on the IA to 1,500 psi and hold for 30 minutes on chart recorder. Well: MPU D-01 Scope: ESP Swap 20 November 2024 7. RD HES slickline. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By TDF: 11/24/2024 SCHEMATIC Milne Point Unit Well: MPU D-01 Last Completed: 12/4/1989 PTD: 181-144 TD =9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’ / Orig. GL Elev.: 9’ Parker #128 7” 2 3 9-5/8” 1 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) Kuparuk C CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRC 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRC 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRC 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.958 Surface ±4,000’ JEWELRY DETAIL No Depth Item 1 ±4,000’ WLEG 2 8,098’ Hyd. Liner Hanger 3 9,383’ EZSV Retainer PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8" 500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite _____________________________________________________________________________________ Revised By TDF: 11/20/2024 PROPOSED Milne Point Unit Well: MPU D-01 Last Completed: 12/4/1989 PTD: 181-144 TD =9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’ / Orig. GL Elev.: 9’ Parker #128 7” 9-5/8” 1 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) Kuparuk C 2 3 4 5 6 7 8 9 & 10 11 12 13 & 14 15 16 & 17 22 18 19 20 21 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRC 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRC 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRC 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / DSS-HT 2.992 Surface 9,072’ 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992 ±X,XXX’ ±X,XXX’ 4-1/2”Tubing/ Screen 13.5 / L-80 / TSD 625 3.920 ±X,XXX’ ±X,XXX’ JEWELRY DETAIL No Depth Item 1 ±175 GLM 2-7/8” x 1” w/ DV Installed 2 ±2,170’ GLM 2-7/8” x 1” w/ DV Installed 3 ±2,200’ Tripoint 9-5/8” ESP Retrievable Packer w/ Single Vent Valve 4 ±X,XXX’ GLM 2-7/8” x 1” w/ DV Installed 5 ±X,XXX’ HES X-Nipple 6 8,098’ Hyd. Liner Hanger 7 ±X,XXX’ GLM 2-7/8” x 1” w/ DV Installed 8 ±X,XXX’ HES XN-Nipple 9 ±X,XXX’ Bolt on Discharge Head 10 ±X,XXX’ Ported Discharge Head 11 ±X,XXX’ Pump #1 12 ±X,XXX’ Gas Separator 13 ±X,XXX’ Upper Tandem Seal 14 ±X,XXX’ Lower Tandem Seal 15 ±X,XXX’ ESP Motor 16 ±X,XXX’ Motor Gauge Unit 17 ±X,XXX’ Motor Centralizer – Btm @ ±9,070’ 18 9,383’ EZSV Retainer 19 ±X,XXX’ 3-1/2” Scoop Guide 20 ±X,XXX’ 3-1/2” x 7’ STR Retrievable PAcker 21 ±X,XXX’ 3-1/2” x 4-1/2” X-Over 22 ±X,XXX’ Bull Nose Shoe: Btm @ ±9,253’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8" 500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30' Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR From:Rixse, Melvin G (OGC) To:Erik Nelson - (C) Cc:DOA AOGCC Prudhoe Bay Subject:20241119 1643 APPROVAL : MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Date:Tuesday, November 19, 2024 4:55:48 PM Erik, Consider this email an approval to pause work under approved sundry 324-559 as you have described below. Please submit another 10-403 for restarting the work on this well, as inspectors should have a formal paper trail for BOPE testing etc. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. AOGCC Inspectors From: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Sent: Tuesday, November 19, 2024 4:21 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Mel, As discussed on the phone, we’re currently tripping in the hole with our test packer. Our planned 1750 psi (30 min) test will confirm integrity of the 7” csg from the packer set point (8200-ft MD (6613-ft TVD)) to the 7” x 9-5/8” liner hanger (8098-ft MD (6543-ft TVD) and the 9- 5/8” csg to surface. When we get out of the hole with our test assembly we will run a kill string to 4000-ft MD. At that point, as mentioned, we’re going to RDMO from MPU D-01 to go knock out another RWO on J-Pad while we have the spacing available to us. When that other well is complete we’re planning on returning to finish up the remaining work to bring MPU D-01 back online as an ESP producer. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. I would like to inquire as to how you would like to proceed in regard to the Approved Sundry? Would this be considered a pause on the existing Sundry with work to re-commence after returning to the well and performing our BOPE test? Thank you for your time. Q From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, November 18, 2024 10:31 AM To: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Subject: RE: [EXTERNAL] RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Erik, MPSP on this well is 2823 psi. In my opinion IC could see pressures above the 0.25 X TVD on this over pressured reservoir with a shallow packer. I think you should, at a minimum, test IC to 1750 psi as described in the sundry and it should be charted. Are you asking for approval to accept an uncharted pressure test to 1600 psi when the casing would not hold 1800 psi and approval was 1750 psi? Regulations are not clear on producers except when casing is new that it should be tested to 50% of burst which would be 3435 psi for this IC . Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Sent: Sunday, November 17, 2024 8:27 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Mel, As mentioned in my other email chain regarding our request for a 24-hr extension on our weekly BOPE test, we managed to get our workstring free this morning. With a full recovery of our workstring and cleanout BHA I’m looking at our plan forward once we complete our weekly BOPE test early tomorrow morning, 18 Nov. In our approved procedure the next step after our cleanout run is to MU and TIH with a 7” test packer set it at ±8500-ft MD (±6825-ft TVD) in order to test the 7” csg above this point, the 7” x 9-5/8” lnr hgr, and the 9-5/8” csg to surface. However, we effectively performed an MIT after we got out of the hole with our 9-5/8” cleanout assembly on the afternoon of 15 November. For that test we secured the well and pressured up against the plugged formation from surface. We pressured up to 1800 psi and it settled back to 1600 psi and we held it for 30 mins. Over the 30 min test we lost ±50 psi. During the cleanout run in the 7” csg we starting tagging and washing through fill at 9150-ft MD (10-ft MD above top perfs at 9160-ft MD). We continued our cleanout washing fill through the perforations before we got hung up. The barrel of our RCJB was at 9266-ft MD (±72-ft MD below btm perfs at 9194-ft MD). As we worked the pipe we noticed that we had fluid losses while at our max circulation rate. After freeing ourselves, we TOOH back up into the 9-5/8” csg and performed a similar test pumping down the backside. We pressured up again to 1800 psi but the pressure fell back to ±300 psi within 3 mins. We attempted a second test with similar results. All this leads me to believe we have integrity in the 7” csg above the perforations, the 7” x 9- 5/8” lnr hgr, and the 9-5/8” csg to surface. I would like to ascertain whether or not the AOGCC views these tests as confirmation of that as well. Thank you for your time and consideration of my inquiry. Q From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Sent: Sunday, November 17, 2024 1:38 PM To: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Subject: RE: [EXTERNAL] RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Erik, Approved to reperforate 9160-9194’ MD. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Sent: Sunday, November 17, 2024 10:15 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Mel, As previously noted in a separate email this morning, we’ve run into some issues and are currently in pipe recovery mode on MPU D-01. During the course of our cleanout our BHA became stuck below the existing perforations. We’re currently making plans to cut in a crossover joint below the jars. A successful cut will leave us with TOF ±9234-ft MD giving us ±40-ft of rathole below the existing perforations (9160 - 9194-ft MD). We do not anticipate attempting any further efforts to recover the remaining BHA left in the well. Of note, we have not had any losses on this well since pulling the prior ESP completion even while swinging our pump rates while trying to work the pipe free. Given that information, once our pipe is free, we are planning to trip back up into the 9-5/8” csg and perform an injection test before continuing to trip out of hole and begin our weekly BOPE test (assuming we receive CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. approval for our request for a 24-hr extension). I believe it is highly likely that we will not get a satisfactory result when we perform the injection test. Therefore, I’m writing to request approval to re-perforate the existing perforated interval (9160 – 9194-ft MD) with E-Line before we run the lower screen completion followed by the upper ESP completion. Thank you for your time and consideration of my request. Q Erik Q. Nelson Milne Point OE (Contract) O (907) 564 - 5277 C (907) 903 – 7407 Erik.Nelson@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, November 15, 2024 4:37 PM To: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Subject: [EXTERNAL] RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Erik, Hilcorp is approved to run 3 joints of screens as described below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Sent: Friday, November 15, 2024 3:40 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Mel, As discussed on the phone, due to the discovery of prolific amounts of proppant and formations sand during out cleanout runs we’re planning on running (3) jts of screens across the Kuparuk perforations when we go back to re-complete MPU D-01. We’ll hang these screens from a production pkr set in the 7”, 26# csg then run the ESP with ESP above. There is no plan to change the set depth of the planned ESP packer. Please let us know if we need to include Mr. Jack Lau or Mr. David Roby in any and/or all of our communications moving forward. Thank you for your time and have a great weekend! Q Erik Q. Nelson Milne Point OE (Contract) O (907) 564 - 5277 C (907) 903 – 7407 Erik.Nelson@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:FW: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Date:Sunday, November 17, 2024 2:53:23 PM From: Rixse, Melvin G (OGC) Sent: Friday, November 15, 2024 4:37 PM To: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Subject: RE: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Erik, Hilcorp is approved to run 3 joints of screens as described below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Erik Nelson - (C) <Erik.Nelson@hilcorp.com> Sent: Friday, November 15, 2024 3:40 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU D-01 Re-completion communication (PTD 181 - 144) (Approved Sundry 324 - 559)... Mel, As discussed on the phone, due to the discovery of prolific amounts of proppant and formations sand during out cleanout runs we’re planning on running (3) jts of screens across the Kuparuk perforations when we go back to re-complete MPU D-01. We’ll hang these screens from a production pkr set in the 7”, 26# csg then run the ESP with ESP above. There is no plan to change the set depth of the planned ESP packer. Please let us know if we need to include Mr. Jack Lau or Mr. David Roby in any and/or all of our communications moving forward. Thank you for your time and have a great weekend! Q Erik Q. Nelson Milne Point OE (Contract) O (907) 564 - 5277 C (907) 903 – 7407 Erik.Nelson@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Completion 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,913'N/A Casing Collapse Conductor N/A Surface 2,670psi Production 4,760psi Liner 7,020psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng KUPARUK RIVER OIL N/A 7,917' 9,320' 7,439' 2,823 9,238 (Fill) Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT D-01 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 10/10/2024 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047433 & ADL0047437 181-144 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-20664-00-00 Hilcorp Alaska LLC C.O. 432E Length Size Proposed Pools: 110' 110' 9.3# / L-80 / EUE 8rd TVD Burst 9,072' MILNE POINT MD N/A 8,160psi 5,380psi 6,870psi 2,300' 6,793' 7,904' 2,300' 8,455' 110' 20" 13-3/8" 9-5/8" 2,300' 7"1,802' 8,455' OTIS RDH and FMX TRSV 588 MD/ 588 TVD and 572 MD / 572 TVD Erik.Nelson@hilcorp.com 907-564-5277 Perforation Depth MD (ft): 9,900' See Schematic See Schematic 3-1/2" Erik Nelson No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.09.27 09:53:54 - 08'00' Taylor Wellman (2143) 324-559 By Grace Christianson at 10:52 am, Sep 27, 2024 SFD 9/30/2024 DSR-9/27/24MGR03OCT2024 * BOPE pressure test to 3000 psi. Annular to 2500 psi. 10-404 JLC 10/3/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.07 13:16:43 -08'00' 10/07/24 RBDMS JSB 100824 Well: MPU D-01 Scope: ESP Swap Well Name:MPU D-01 API Number:50-029-20664-00-00 Current Status:Producer [Shut in ESP]Pad:D-Pad Estimated Start Date:October 10, 2024 Rig:ASR #1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts Permit to Drill Number:181-144 First Call Engineer:Erik Q. Nelson (907) 564-5277 (O) (907) 903-7407 (M) Second Call Engineer:Taylor Wellman (907) 777-8343 (O) (307) 660-4999 (M) AFE Number:Job Type:ESP Swap Current Bottom Hole Pressure: 3567 psi @ 7438-ft TVD Downhole Gauge 08Sep24 |9.2 PPGE MPSP:2823 psi (0.1psi/ft gas gradient) Max Deviation:52° @ 4700 – 5000-ft MD Max Dogleg:6.5°/100-ft @ 2600-ft and 6600-ft MD Min ID:2.75” @ 602-ft MD 3-1/2” XN Nipple BPV Profile: 3” Type H Brief Well Summary: Well MPU D-01 was drilled by Parker #278 in 1982 and initially completed in the Kuparuk A sand which were found to be wet. A drill stem test of the Kuparuk C sand was completed with a ~500 BOPD rate. The well was plugged back and completed in the Kuparuk B and C sands in 1989. A mud acid stimulation and frac was completed in 1989. A cleanout was completed on the well and ESP ran in November 1989. The well operated for approximately one year until November 1990 when it appears the pump stopped working, possibly plugged up with solids. The well has remained shut in since 1990. A flow test was completed and confirmed approximately 9% max water cut, and thus the well is being progressed for a RWO. The productivity of the well during the one-year flow period showed rates ranging from 170-350 BOPD. Unfortunately, no flowing BHP data is available to determine PI ranges but given the SBHP after shutdown of ~2,500 psi, the range is estimated at 0.17 to 0.3 bbl/psi. Note that this well will run #4 ESP Cable (smaller than #2) and is uncommon at MPU. Please verify all clamps, penetrators, and cable is on location. Objective: x Pull 3-1/2” ESP Completion x Perform 7” Scraper run and Tag Fill x Cleanout fill if necessary. x Run 7” Test packer. Test production casing x Run new 2-7/8” ESP Completion Notes Regarding the Well & Design x Circulating Sub @ 9,032’ MD is sheared x ESP Packer pinned for 30K over string weight x Offset Injector Support o No known injection support. o Aquifer support x 13-5/8” Wellhead. Will require a 13-5/8” x 11” crossover spool. Well: MPU D-01 Scope: ESP Swap Pre-Rig Procedure Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500-barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Bleed down tubing and IA pressure to zero. 6. Reverse circulate at least one wellbore volume down annulus, taking returns up the circulation sub at 9,032’ MD (725 bbls) with 9.4 ppg brine down tubing, taking returns up casing to 500 barrel returns tank. a. Continue circulating until no gas is seen. 7. Bullhead down tbg for a volume of 87 bbls taking returns to formation: 8. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 9. RD Little Red Services and reverse out skid. 10. Set BPV and CTS plug. Brief RWO Procedure 1. MIRU ASR #1 Rig. 2. ND tree. NU BOPE. a. When ND tree, ensure that control line to the vent valves is pressured up and capped. Note and highlight to crew that cap-string will have pressure on it when recovering hanger. This will keep vent valve and SSSV open. 3. Test BOPE to 250psi Low/3,000psi High, annular to 250psi Low/3,000psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Perform Test per ASR #1 BOP test procedure. d. Test the 2-7/8” x 5” VBR’s with 2-7/8” and 3-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull CTS Plug. Check for pressure below the BPV. a. If indications show pressure underneath BPV, lubricate out BPV and re-kill as needed. 5. Call out Baker Hughes. Rig up spoolers for #4 cable and ¼” SS cap-string. 6. MU landing joint, BOLDS, PU on the tubing hanger. a. The current completion has an estimated dry string weight of 85 Klbs, and 73 Klbs with 9.4 ppg fluid. b. The ESP packer is pinned to shear release at 30k overpull. Estimated PUW to release packer is 103k – 115k. Work pipe up in 5 Klbs increments to 120k and contact OE for discussion before pulling higher. Well: MPU D-01 Scope: ESP Swap c. Prepare for packer gas. Close annular and forward circulate, taking gas returns up annulus. Circulate out one full wellbore volume of 9.4 ppge KWF. i. Note that the packer is very shallow. 7. Confirm hanger free, lay down tubing hanger. a. Bleed off pressure from control line prior to laying down hanger. 8. POOH and lay down the 3-1/2” tubing and ESP completion components. a. Clamps to be recovered, washed and saved for re-use if possible. 600 ESP Cable Clamps 25 SS Clamps 4 Flat Guards (Only shown on ESP invoice* from 1989) 9. Lay Down ESP. a. Note that there should be an 18’ 5.5” OD Motor Shroud that may need to be cold cut on surface. b. Document the condition of motor, seals, and pump. 10. PU 3-1/2” Work-string. 11. MU 7” rotatable casing scraper with bit on bottom on work-string and TIH to tag fill. Reverse circulate and clean out fill to 9,250’ MD. 12. POOH and LD casing scraper. 13. MU 7” test packer and TIH to 8,500’ MD. 14. Test 7” x 9-5/8” production casing to 1750 psi for 30 minutes charted. a. Minimum required 6825’ TVD x 0.25 psi = 1706 psi. 15. Call out Summit ESP to run Completion. 16. POOH and LD test packer. 17. RU to run ESP completion. 18. PU and MU new ESP assembly. Set base of ESP assembly at ±9,070’ MD. Check electrical integrity test every 1,000’. Install clamps on the first 15 joints then every other joint to surface. a. Motor centralizer b. Motor gauge unit c. ESP motor d. Lower tandem seal e. Upper tandem seal f. Gas separator g. Pump #1 h. Ported discharge head i. Bolt on discharge head with pup joint, 2-7/8”, 6.5#, L-80, EUE 8rd box up j. 2 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing k. Nipple, HES XN-Nipple (2.205”) with 10’ handling pups above and below. l. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing m. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below. n. Multiple joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing Well: MPU D-01 Scope: ESP Swap o. Nipple, HES X-Nipple (2.313”) with 10’ handling pups above and below.RHC plug body installed p. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing. q. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below r. Packer with crossover pups a. TriPoint 9-5/8” ESP retrievable with single vent valve (setting depth = ±2,200’ MD) 19. PU and MU the Tri-Point packer. Verify that there are 4 setting shear pins and confirm w/ OE number of release shear pins. a. Double check direction of packer slips and pinned settings. b. Run packer slow at >30 seconds per joint to prevent premature hydraulic setting. c. Shear pins will be dependent upon expected PUW of completion. Initial target is 20k overpull to release. d. Document packer with photos above and below all jewelry as installed on 2-7/8” tubing. e. Document on tubing tally that max pull on packer after set is 124,000 lb. 20. Terminate the ESP cable and MU the ESP penetrator to the ESP cable. Ensure the 3/8” NPT control line feed thru port is dummied off. 21. MU the control line to the vent valve. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in AWGRS). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while RIH. 22. Continue to RIH with ESP completion. Check electrical integrity test every 1,000’. a. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing b. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±2,170’ MD) c. Multiple joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing d. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±175’ MD) e. 4 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing 23. PU and MU the 2-7/8” tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 24. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in AWGRS). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while landing the hanger. 25. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator, or control line. RILDS. Record PU and SO weights on tally and AWGRS. 26. Drop the ball & rod and allow time for it to gravitate to the ball seat. 27. Pressure up on the tubing to 2,000 psi and hold for 15 minutes to set the packer. Bleed the tubing pressure to 0 psi. Pressure back up to 2,000 psi and hold for 5 minutes then bleed to 0 psi. a. Note that packer is designed to begin setting at 1,247 psi of differential pressure. 28. Bleed the control line pressure to 0 psi to close the vent valves. 29. Slowly pressure up at 50 psi/min on the IA to 1,500 psi and hold for 30 minutes on chart recorder. a. Bleed pressure off in 50% increments per 30 minutes to prevent gas expansion and cable damage. Well: MPU D-01 Scope: ESP Swap 30. Set BPV. ND the BOP stack. Set CTS Plug. 31. NU the tubing head adapter and 2-9/16”, 5M tree. 32. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 33. Pull CTS plug and BPV. 34. Replace gauge(s) if removed. Secure the tree and cellar. 35. RDMO Post-Rig Procedure: 1. Turn well over to production via handover form. 2. RU well house and flowlines. 3. RU HES slickline. 4. Pull the ball and rod. 5. Pull DV from GLM at ±175’ and install 1/4" DP-OV. 6. Pull RHC plug body. 7. RD HES slickline. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic Well: MPU D-01 Scope: ESP Swap Date: 8/12/2023 Well Number: MPD-01 FMC FMC FMC FLG. FLG. FLG. 13 5/8” 5M 13 5/8” 5M 20“ 2M 13.00” 21.625” 13.00” 21.625” 21.625” 24.250” 26.00” 24.00” _____________________________________________________________________________________ Revised By TDF: 8/29/2023 SCHEMATIC Milne Point Unit Well: MPU D-01 Last Completed: 12/4/1989 PTD: 181-144 TD = 9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’/ Orig. GL Elev.:9’ Parker #128 7” 6 4 9 ¼” SS Control line 9-5/8” 1 5 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) 8 Kuparuk C 7 2 3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRS 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRS 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRS 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992 Surface 9,072’ JEWELRY DETAIL No Depth Item 1 572’ OTIS 3-1/2” FMX TRSV 2 588’ OTIS RDH Packer 3 602’ 3-1/2” OTIS XN Nipple -Min ID 2.813 4 8,098’ Hyd. Liner Hanger 5 8,999’ OTIS Ball Catcher 6 9,032’ X-O w/ Ball Circulating Sub 7 9,033’ Top of REDA ESP, DN 450, 191 Stage 8 9,072’ Bottom of ESP 9 9,383’ EZSV Retainer PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8" 500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite _____________________________________________________________________________________ Revised By TDF: 8/30/2023 PROPOSED Milne Point Unit Well: MPU D-01 Last Completed: 12/4/1989 PTD: 181-144 TD = 9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’/ Orig. GL Elev.:9’ Parker #128 7” 9-5/8” 1 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) Kuparuk C 2 3 4 5 6 7 8 9 & 10 11 12 13 & 14 15 16 17 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRS 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRS 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRS 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992 Surface 9,072’ JEWELRY DETAIL No Depth Item 1 ±175 GLM 2-7/8” x 1” w/ DV Installed 2 ±2,170’ GLM 2-7/8” x 1” w/ DV Installed 3 ±2,200’ Tripoint 9-5/8” ESP Retrievable Packer w/ Single Vent Valve 4 ±X,XXX’ GLM 2-7/8” x 1” w/ DV Installed 5 ±X,XXX’ HES X-Nipple 6 ±X,XXX’ GLM 2-7/8” x 1” w/ DV Installed 7 ±X,XXX’ HES XN-Nipple 8 ±X,XXX’ Bolt on Discharge Head 9 ±X,XXX’ Ported Discharge Head 10 ±X,XXX’ Pump #1 11 ±X,XXX’ Gas Separator 12 ±X,XXX’ Upper Tandem Seal 13 ±X,XXX’ Lower Tandem Seal 14 ±X,XXX’ ESP Motor 15 ±X,XXX’ Motor Gauge Unit 16 ±X,XXX’ Motor Centralizer – Btm @ ±9,070’ 17 9,383’ EZSV Retainer PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8" 500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite Well: MPU D-01 Scope: ESP Swap Date: 8/12/2023 Well Number: MPD-01 FMC FMC FMC FLG. FLG. FLG. 13 5/8” 5M 13 5/8” 5M 20“ 2M 13.00” 21.625” 13.00” 21.625” 21.625” 24.250” 26.00” 24.00” 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Completion 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,913'N/A Casing Collapse Conductor N/A Surface 2,670psi Production 4,760psi Liner 7,020psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng KUPARUK RIVER OIL N/A 7,917' 9,320' 7,439' 2,710 9,238 (Fill) Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT D-01 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 10/1/2023 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047437 181-144 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-20664-00-00 Hilcorp Alaska LLC C.O. 432E Length Size Proposed Pools: 110' 110' 9.3# / L-80 / EUE 8rd TVD Burst 9,072' MILNE POINT MD N/A 8,160psi 5,380psi 6,870psi 2,300' 6,793' 7,904' 2,300' 8,455' 110' 20" 13-3/8" 9-5/8" 2,300' 7"1,802' 8,455' OTIS RDH and FMX TRSV 588 MD/ 588 TVD and 572 MD / 572 TVD scott.pessetto@hilcorp.com 907-564-4373 Perforation Depth MD (ft): 9,900' See Schematic See Schematic 3-1/2" Scott Pessetto No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager By Grace Christianson at 9:01 am, Sep 01, 2023 323-499 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.08.31 14:07:04 - 08'00' Taylor Wellman (2143) DSR-9/1/23MGR01SEP23 10-404 SFD 9/14/2023 2,710 * BOPE test to 3000 psi. Annular to 2500 psi * Inner casing pressure integrity test with test packer to be performed. , ADL0047433 SFD *&:JLC 9/14/2023 09/15/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.15 07:45:14 -08'00' RBDMS JSB 091523 Well: MPU D-01 Scope: ESP Swap Well Name:MPU D-01 API Number:50-029-20664-00-00 Current Status:Producer [Shut in ESP]Pad:D-Pad Estimated Start Date:October 1, 2023 Rig:ASR #1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts Permit to Drill Number:181-144 First Call Engineer:Scott Pessetto (907) 564-4373 (O) (801) 822-2203 (M) Second Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) AFE Number:Job Type:ESP Swap Current Bottom Hole Pressure: 3,390psi @ 7,197’ TVD Downhole Gauge 8/8/2023 |9.1 PPGE Maximum Hole Pressure:3,430 psi @ 7,197’ TVD Reservoir Buildup |9.2 PPGE MPSP:2,710 psi (0.1psi/ft gas gradient) Max Deviation:52° @ 4,700’ – 5,000’ MD Max Dogleg:6.5°/100ft @ 2,600’ and 6,600’ MD Min ID:2.75” @ 602’ MD 3-1/2” XN Nipple BPV Profile: 3” Type H Brief Well Summary: Well MPU D-01 was drilled by Parker #278 in 1982 and initially completed in the Kuparuk A sand which were found to be wet. A drill stem test of the Kuparuk C sand was completed with a ~500 BOPD rate. The well was plugged back and completed in the Kuparuk B and C sands in 1989. A mud acid stimulation and frac was completed in 1989. A cleanout was completed on the well and ESP ran in November 1989. The well operated for approximately one year until November 1990 when it appears the pump stopped working, possibly plugged up with solids. The well has remained shut in since 1990. A flow test was completed and confirmed approximately 9% max water cut, and thus the well is being progressed for a RWO. The productivity of the well during the one-year flow period showed rates ranging from 170-350 BOPD. Unfortunately, no flowing BHP data is available to determine PI ranges but given the SBHP after shutdown of ~2,500 psi, the range is estimated at 0.17 to 0.3 bbl/psi. Note that this well will run #4 ESP Cable (smaller than #2) and is uncommon at MPU. Please verify all clamps, penetrators, and cable is on location. Objective: x Pull 3-1/2” ESP Completion x Perform 7” Scraper run and Tag Fill x Cleanout fill if necessary. x Run 7” Test packer. Test production casing x Run new 2-7/8” ESP Completion Notes Regarding the Well & Design x Circulating Sub @ 9,032’ MD is sheared x ESP Packer pinned for 30K over string weight x Offset Injector Support o No known injection support. o Aquifer support x 13-5/8” Wellhead. Will require a 13-5/8” x 11” crossover spool. Well: MPU D-01 Scope: ESP Swap Pre-Rig Procedure Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500-barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Bleed down tubing and IA pressure to zero. 6. Reverse circulate at least one wellbore volume down annulus, taking returns up the circulation sub at 9,032’ MD (725 bbls) with 9.4 ppg brine down tubing, taking returns up casing to 500 barrel returns tank. a. Continue circulating until no gas is seen. 7. Bullhead down tbg for a volume of 87 bbls taking returns to formation: 8. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 9. RD Little Red Services and reverse out skid. 10. Set BPV and CTS plug. Brief RWO Procedure 1. MIRU ASR #1 Rig. 2. ND tree. NU BOPE. a. When ND tree, ensure that control line to the vent valves is pressured up and capped. Note and highlight to crew that cap-string will have pressure on it when recovering hanger. This will keep vent valve and SSSV open. 3. Test BOPE to 250psi Low/3,000psi High, annular to 250psi Low/2,500psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Perform Test per ASR #1 BOP test procedure. d. Test the 2-7/8” x 5” VBR’s with 2-7/8” and 3-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull CTS Plug. Check for pressure below the BPV. a. If indications show pressure underneath BPV, lubricate out BPV and re-kill as needed. 5. Call out Baker Hughes. Rig up spoolers for #4 cable and ¼” SS cap-string. 6. MU landing joint, BOLDS, PU on the tubing hanger. a. The current completion has an estimated dry string weight of 85 Klbs, and 73 Klbs with 9.4 ppg fluid. b. The ESP packer is pinned to shear release at 30k overpull. Estimated PUW to release packer is 103k – 115k. Work pipe up in 5 Klbs increments to 120k and contact OE for discussion before pulling higher. Well: MPU D-01 Scope: ESP Swap c. Prepare for packer gas. Close annular and forward circulate, taking gas returns up annulus. Circulate out one full wellbore volume of 9.4 ppge KWF. i. Note that the packer is very shallow. 7. Confirm hanger free, lay down tubing hanger. a. Bleed off pressure from control line prior to laying down hanger. 8. POOH and lay down the 3-1/2” tubing and ESP completion components. a. Clamps to be recovered, washed and saved for re-use if possible. 600 ESP Cable Clamps 25 SS Clamps 4 Flat Guards (Only shown on ESP invoice* from 1989) 9. Lay Down ESP. a. Note that there should be an 18’ 5.5” OD Motor Shroud that may need to be cold cut on surface. b. Document the condition of motor, seals, and pump. 10. PU 3-1/2” Work-string. 11. MU 7” rotatable casing scraper with bit on bottom on work-string and TIH to tag fill. Reverse circulate and clean out fill to 9,250’ MD. 12. POOH and LD casing scraper. 13. MU 7” test packer and TIH to 8,500’ MD. 14. Test 7” x 9-5/8” production casing to 1750 psi for 30 minutes charted. a. Minimum required 6825’ TVD x 0.25 psi = 1706 psi. 15. Call out Summit ESP to run Completion. 16. POOH and LD test packer. 17. RU to run ESP completion. 18. PU and MU new ESP assembly. Set base of ESP assembly at ±9,070’ MD. Check electrical integrity test every 1,000’. Install clamps on the first 15 joints then every other joint to surface. a. Motor centralizer b. Motor gauge unit c. ESP motor d. Lower tandem seal e. Upper tandem seal f. Gas separator g. Pump #1 h. Ported discharge head i. Bolt on discharge head with pup joint, 2-7/8”, 6.5#, L-80, EUE 8rd box up j. 2 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing k. Nipple, HES XN-Nipple (2.205”) with 10’ handling pups above and below. l. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing m. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below. n. Multiple joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing Well: MPU D-01 Scope: ESP Swap o. Nipple, HES X-Nipple (2.313”) with 10’ handling pups above and below.RHC plug body installed p. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing. q. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below r. Packer with crossover pups a. TriPoint 9-5/8” ESP retrievable with single vent valve (setting depth = ±2,200’ MD) 19. PU and MU the Tri-Point packer. Verify that there are 4 setting shear pins and confirm w/ OE number of release shear pins. a. Double check direction of packer slips and pinned settings. b. Run packer slow at >30 seconds per joint to prevent premature hydraulic setting. c. Shear pins will be dependent upon expected PUW of completion. Initial target is 20k overpull to release. d. Document packer with photos above and below all jewelry as installed on 2-7/8” tubing. e. Document on tubing tally that max pull on packer after set is 124,000 lb. 20. Terminate the ESP cable and MU the ESP penetrator to the ESP cable. Ensure the 3/8” NPT control line feed thru port is dummied off. 21. MU the control line to the vent valve. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in AWGRS). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while RIH. 22. Continue to RIH with ESP completion. Check electrical integrity test every 1,000’. a. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing b. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±2,170’ MD) c. Multiple joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing d. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±175’ MD) e. 4 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing 23. PU and MU the 2-7/8” tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 24. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in AWGRS). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while landing the hanger. 25. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator, or control line. RILDS. Record PU and SO weights on tally and AWGRS. 26. Drop the ball & rod and allow time for it to gravitate to the ball seat. 27. Pressure up on the tubing to 2,000 psi and hold for 15 minutes to set the packer. Bleed the tubing pressure to 0 psi. Pressure back up to 2,000 psi and hold for 5 minutes then bleed to 0 psi. a. Note that packer is designed to begin setting at 1,247 psi of differential pressure. 28. Bleed the control line pressure to 0 psi to close the vent valves. 29. Slowly pressure up at 50 psi/min on the IA to 1,500 psi and hold for 30 minutes on chart recorder. a. Bleed pressure off in 50% increments per 30 minutes to prevent gas expansion and cable damage. Well: MPU D-01 Scope: ESP Swap 30. Set BPV. ND the BOP stack. Set CTS Plug. 31. NU the tubing head adapter and 2-9/16”, 5M tree. 32. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 33. Pull CTS plug and BPV. 34. Replace gauge(s) if removed. Secure the tree and cellar. 35. RDMO Post-Rig Procedure: 1. Turn well over to production via handover form. 2. RU well house and flowlines. 3. RU HES slickline. 4. Pull the ball and rod. 5. Pull DV from GLM at ±175’ and install 1/4" DP-OV. 6. Pull RHC plug body. 7. RD HES slickline. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By TDF: 8/29/2023 SCHEMATIC Milne Point Unit Well: MPU D-01 Last Completed: 12/4/1989 PTD: 181-144 TD = 9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’/ Orig. GL Elev.:9’ Parker #128 7” 6 4 9 ¼” SS Control line 9-5/8” 1 5 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) 8 Kuparuk C 7 2 3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRS 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRS 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRS 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992 Surface 9,072’ JEWELRY DETAIL No Depth Item 1 572’ OTIS 3-1/2” FMX TRSV 2 588’ OTIS RDH Packer 3 602’ 3-1/2” OTIS XN Nipple -Min ID 2.813 4 8,098’ Hyd. Liner Hanger 5 8,999’ OTIS Ball Catcher 6 9,032’ X-O w/ Ball Circulating Sub 7 9,033’ Top of REDA ESP, DN 450, 191 Stage 8 9,072’ Bottom of ESP 9 9,383’ EZSV Retainer PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8" 500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite _____________________________________________________________________________________ Revised By TDF: 8/30/2023 PROPOSED Milne Point Unit Well: MPU D-01 Last Completed: 12/4/1989 PTD: 181-144 TD = 9,913’ (MD) / TD = 7,917’(TVD) 20” Orig. KB Elev.: 32’/ Orig. GL Elev.:9’ Parker #128 7” 9-5/8” 1 PBTD =9,320’(MD) / PBTD = 7,439’(TVD) Kuparuk C 2 3 4 5 6 7 8 9 & 10 11 12 13 & 14 15 16 17 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20” Conductor 94# / H-40 / BTRS 19.124 Surface 110’ 13-3/8" Surface 72 / L-80 / BTRS 12.347 Surface 2,300' 9-5/8" Production 47 / L-80 / BTRS 8.835 Surface 8,455’ 7" Liner 29 / L-80 / BTRC 6.184 8,098’ 9,900’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992 Surface 9,072’ JEWELRY DETAIL No Depth Item 1 ±175 GLM 2-7/8” x 1” w/ DV Installed 2 ±2,170’ GLM 2-7/8” x 1” w/ DV Installed 3 ±2,200’ Tripoint 9-5/8” ESP Retrievable Packer w/ Single Vent Valve 4 ±X,XXX’ GLM 2-7/8” x 1” w/ DV Installed 5 ±X,XXX’ HES X-Nipple 6 ±X,XXX’ GLM 2-7/8” x 1” w/ DV Installed 7 ±X,XXX’ HES XN-Nipple 8 ±X,XXX’ Bolt on Discharge Head 9 ±X,XXX’ Ported Discharge Head 10 ±X,XXX’ Pump #1 11 ±X,XXX’ Gas Separator 12 ±X,XXX’ Upper Tandem Seal 13 ±X,XXX’ Lower Tandem Seal 14 ±X,XXX’ ESP Motor 15 ±X,XXX’ Motor Gauge Unit 16 ±X,XXX’ Motor Centralizer – Btm @ ±9,070’ 17 9,383’ EZSV Retainer PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C Sand 9,160’ 9,198’ 7,317’ 7,346’ 38 9/1989 Open 9,171’ 9,194’ 7,326’ 7,343’ 23 3/7/1982 Open 9,404’ 9,420’’ 7,504’ 7,516’ 16 3/4/1982 Squeezed 9,434’ 9,474’ 7,527’ 7,559’ 40 3/4/1982 Squeezed 2-1/8” 4 SPF 0 Deg Phasing Guns for Perfs @ 9,160’ to 9,198 // 12 SPF 90 Degree Phasing for Perfs 9,171’ to 9,194’ OPEN HOLE / CEMENT DETAIL 20” Cement to surface in a 26” Hole 13-3/8” 4,980 sks of Perma-Frost 17-1/2”” Hole 9-5/8" 500 sks Class ‘G’, 135 bbl of Arctic Pack in 12-1/4” Hole 7” 650 sks Class “G” in a 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 2,300’ Max Hole Angle = 52.5 deg. @ 4,800’ MD TREE & WELLHEAD Tree FMC 3-1/8” 5,000# w/ 3-1/2” 8rd TreeTop Connection Wellhead 13-5/8” x 11” 5k Gen. 1, w/ 2-7/8” x 11” FMC Tubing Hanger, w/ 3” FMC BPV GENERAL WELL INFO 50-029-20664-00-00 Drilled, Cased & Completed by Parker 128 - 3/20/1982 Temp Completion - 8/20/1989 ESP Completion – 11/26/1989 STIMULATION DETAIL Frac - 52,239# of 16/20 Carbolite Well: MPU D-01 Scope: ESP Swap Date: 8/12/2023 Well Number: MPD-01 FMC FMC FMC FLG. FLG. FLG. 13 5/8” 5M 13 5/8” 5M 20“ 2M 13.00” 21.625” 13.00” 21.625” 21.625” 24.250” 26.00” 24.00” Ima~°roject Well History File Cover ge XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. RESCAle- DIGITAL DATA OVERSIZED (Scannable) ~'"' Color items: ~/~'/~ ~' [] Diskettes, No. [] Maps: [] Grayscale items: [] Other, No/Type ~3 Other items scannable by large scanner D Poor Quality Originals: ~OV~°n'Scannable) Other: '"~ Logs of various kinds NOTES: r~ Other BY: BEVERLY ROBIN VINCE(~~ MARIA WINDY Project Proofing BY; ~OBIN Scanning Preparation x 30 = _ BY: VINCENT SHERYL MARIA WINDY DATE: /SI / / - Production Scanning Stage '1 PAGE COUNT FROM SCANNED FILE: PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND:/ ~ YES NO (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY. GRAYBCALE OR COLOR IMAGES) RESCANNEDBY; BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: IS~ General Notes or Comments about this file: Quality Checked 12/10/02Rev3NOTScanned,wpd , Milne Point 2001 Shut In Wells Date Reason for Future Utility Plans & Sw Name Shut-In Well Shut-In ~ Current Mechanical Condition of Well2 Possibilities3 Comments MPB-07 Jul-97 A No known problems I High GOR well, Facilities can not handle gas. Possible production after gas expansion project. MPB-08 May-94 E No known problems 3 Futher use as an injector not re~uired MPB-13 Jan-86 B GL well that was shut in due to high 3 Wellhouse and flowlines removed water cut. Possible channel into water zone, MPB-17 Jan-e6 E No mechanical problems. Quick 3 We#house and flowlines removed communication with producer MPB-19 Jul-91 B GL well. High water cut producer. 3 We#house and flowlines removed Possible frec into water zone MPC- 11 Feb-96 E No known problems 3 Further use as an injector not required while associated producer shut-in MPC-12/ Jan-O0 E Fish in hole, drilling problems 3 Suspended due to drilling problems. 12a MPC-16 Aug-93 A High' GOR well, parrs and completion 3 We#house and flowlines removed abandoned MPC-17 May-O0 D Leak in 9 5/8" casing to surface I Evaluating possible plans for solution to problem. MPC-20 Apr-O0 B High water cut well, no mechanical I Evaluating possible plans for solution to =roblems problem. MPC-21 Feb-02 D Problems with Jet Pump Completion I Evaluating possible plans for solution to problem. ~ Dec-90 C Dead ESP completion, no support to I Evaluating possible plans for solution to block problem. Possible alternative uses for we#bore MPD-02/ Aug-99 B Dead ESP completion, very high water I Evaluating possible plans. 02a cut well MPE-02 Jun-05 C No known problems 2 Recomplete to upper Kup zone MPE-19 Aug-99 C Failed ESP on tubing string 2 Well brought on line in 2002 MPL-01 Feb-00 B High water cut well, no mechanical I Evaluating possible plans ~roblems dead ESP in hole ~ MPL-IO Feb-09 E No proof that is supports other wells I Evaluating side track possibilities MPL-17 Apr-00 B No menchanical problems, dead ESP I Evaluating side track possibilities MPL-21 0ct-98 E ....... ~h3~e~m~ btock ~-5OOO-psi, "no I - Fossible-use-fortnjecttonwhenpressure support needed for producers lowers ~MPL-37a Nov-99 C Dead ESP, no other mechanical I Evaluating possible side track plans or issuses recompletions MPL-39 Jan-99 E Could not inject gas into well, no use I Evaluating possible side track plans or for it. recompletions *Note- Wells were shut in 100% during2001 Milne Pt Shut In Wells 2001.xls A~KA OIL AN D GAS CONSERVATION REPORT OF SUNDRY WELL N AL 1. Operations performed: Operation shutdown__ Pull tubing .__X Alter casing 2. Name of Operator CONOCO TNC. 3. Address 3201 C ST #200, ANCHORAGE, AK Stimulate __ Plugging __ Perforate __ Repair well __ Other __ 5. Type of Well: Development ..__X Exploratory __ Stratigraphic ~ 503 Service __ 4. Location of well at surface 964' FNL, 1233' FEL, At top of productive interval 3367' FSL, 1158' FEL, At effective depth At total depth 3636' FSLt 914' FELt Section 13, T13N, R10E, UM Section 12, T13N, R10E, UM Section 12, T13N, R10E, UM 12. Present well condition summary Total depth: measured true vertical 13 ' feet Plugs (measured) 17' · feet 6. Datum elevation (DF or KB) KB- 32 feet 7. Unit or Property name Milne Point Unit 8. Well number 9. Permit number/approval number 10. APl number 50-- 029-20664 11. Field/Pool Kuparuk River Field N/A Effective depth: measured true vertical N/~ feet Junk (measUred) feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured Length Size Cemented 20" 13-3/8" 9-5/8" 9171'-9194'; 9404'-9420'; Measured depth True vertical depth ,,,, RECEIV'E 2300~ DEC 181989 8455' 9 9 9 0, Alaska 0il & Gas Cons. Comn Anchorage 9434'-9474' true vertical 7325 ' - 7343 ' Tubing (size, grade, and measured depth) 3-1/2", 9.3#/Ft; L-80; DSS-HT Tubing Bottom of Motor 9060, MD Packers and SSSV (type and measured depth) 9-5/8" "RDH' Otis Packer at 580, MD, Otis 'FMX- 778~, SBSV ~ 565' MD 13. Stimulation or cement squeeze summary N/A Intervals treated (measured) N/A Treatment description including volumes used and final pressure N/A 14. Prior to well operation Subsequent to operation Representative Daily Average Production or Injection Data OiI-Bbl Gas-Md Water-Bbl Casing Pressure Waiting on Surfac'e Equipment Hook-up Tubing Pressure 15. Attachments Copies of Logs and Surveys run 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. Form 10-404 Rev 06/15/88 Title Senior Production Foreman Date12/04/8~j SUBMIT IN DUPLICATE .... ( RECEIVED DEC ! 81989 SUBMERSIBLE PUMP INSTALLATION PROCEDURE D-1 NELL Anchomge · MIRU ON D-I. PRE-MIX 10.2 PPG SODIUM BROMIDE/SODIUM CHLORIDE BRINE· TOTAL VOLUME OF 598 BBL'S PLUS AN ADDITIONAL 200 BBL'S DUE TO THE WEATHER CONDITIONS AND VACING OUT OF LINES. 2. PULL BACK PRESSURE VALVE OUT OF TUBING HANGER· RIH WITH SLICK LINE AND PULL G/L DUMMY VALVE FOR CIRCULATION OF KILL FLUID. WELL HAS 9.8 NACL ON ANNULUS AND WELL BORE FLUIDS IN TUBING· 50 BBL.'S DIESEL FOR FREEZE PROTECTION ON SURFACE. G/L MANDREL WILL BE'REMOVED FROM FINAL COMPLETION STRING. · PREPARE THE SPOOLING UNIT AND REDA CABLE PRIOR TO RIH WITH SUBMERSIBLE PUMP. PROCEED WITH CHECK OUT OF ALL REDA EQUIPMENT. · ALL FMC WELLHEAD EQUIPMENT IS LOCATED IN THE GARAGE FOR EASY VERIFICATION. FMC TO CONFIRM ALL EQUIPMENT IS ON LOCATION. · REVERSE CIRCULATE i0.2 BRINE AND TAKE RETURNS THROUGH THE TUBING UNTIL TOTAL TUBING AND ANNULUS HAVE BEEN DISPLACED. 7. CHECK TO MAKE SURE WELL HAS BEEN KILLED. 8. INSTALL BACK PRESSURE VALVE BACK IN.THE TUBING HANGER. ND TREE AND INSTALL BOP'S, CALL AOGCC FOR BOP PRESSURE TEST. 10. HOLD SAFETY MEETING PRIOR TO PULLING TUBING. ii. PULL BACK PRESSURE VALVE. 12. LOOSEN ALL LOCK DOWN BOLTS FROM HANGER· PICK UP TUBING HANGER AND PULL 20,000 LBS OVER STRING WEIGHT IN ORDER TO RELEASE CHAMP PACKER. 13. PULL 3 1/2" DSS-HT TUBING AND PACKER INTO THE 9 5/8" CASING. INSTALL 9 5/8 .... RTTS" RETRIEVABLE PACKER AND 6 1/8" STORM VALVE. SET 30' BELOW THE TUBING HANGER BY TURNING i/4 TURN TO THE RIGHT. MAKE SURE ALL CONNECTIONS ARE TIGHT ABOVE THE PACKER SO WHEN TUBING IS BACKED OFF OF PACKER BY TURNING TO LEFT THE RIGHT CONNECTION IS FREED. 14. BE SURE AND FILL HOLE PRIOR TO SETTING THE 9 5/8" PACKER. 15. PRESSURE TEST TO 1500 PSI AND CHECK FOR LEAKS. 16. ND BOP'S, AND INSTALL 13 5/8" X 11" DOUBLE STUDDED ADAPTER AND ii" BOP STACK. CALL AOGCC FOR BOP PRESSURE TEST. RIH WITH JNT OF TUBING AND LAND IN 9 5/8" PACKER. PULL UP ON THE TUBING TO RELEASE THE PACKER. PRESSURE WILL EQUALIZE ON ( ( RECEIVED DEC 1 81989 Aiaska 0il & Gas Cons. BOTH SIDES OF PACKER WHEN STINGING INTO THE PACKER THR0~~O8 THE STORM VALVE. 17. POOH WITH "RTTS" RETRIEVABLE PACKER AND THE HALLIBURTON CHAMP PACKER. 18. MAKE UP REDA PUMP ASSEMBLY AND OTIS "RDH" DUAL HYDRAULIC RETRIEVABLE PRODUCTION PACKER. SET UP SPOOLING UNIT FOR CABLE INSTALLATION. 19. SEE ATTACHED OTIS COMPLETION GUIDE OF PACKER AND PUMP. 20. WILL NEED TO SET UP OTIS TO ALSO RUN 1/4" CONTROL LINE FOR SSSV TO BE SET AT 500' PLUS. OTIS ANNULAR VENT VALVE AND "RDH" PACKER WILL BE SET JUST BELOW THE SSSV. CONTROL LINE WILL BE RUN CONNECTING BOTH THE SSSV AND THE ANNULAR VENT VALVE FOR OPERATION OF VALVES. 21. MAKE SURE REDA CABLE AND SPOOLING UNIT IS HEATED GREATER THAN 32 DEGREES PRIOR TO RIH. ALL BANDS WILL NEED TO BE INSTALLED ON BOTH SIDES OF EACH COLLAR JNT OF THE TUBING. 22. DO NOT RIH FASTER THAN 2 FT./SEC WITH SUBMERSIBLE PUMP AND MOTOR. TAKE EXTREME CAUTION WHEN RIH WITH THE SUBMERSIBLE PUMP ESPECIALLY WHEN ENTERING THE 7" LINER. WILL HAVE A SHROUD INSTALLED AROUND THE PUMP AND MOTOR FOR COOLING OF MOTOR WHILE IN OPERATION. MAXIUM OD OF PUMP ASSEMBLY IS THE SHROUD AT 5.5", THE ID OF THE 7" LINER IS 6.184". MAY LOOK AT MODIFYING THE SHROUD BY CUTTING A MULE SHOE FOR EASIER ENTRY INTO THE LINER. WILL DISCUSS FURTHER WITH REDA WHEN THEY ARRIVE. 23. WILL NEED TO HI-POT POWER CABLE PRIOR TO REMOVING FROM SPOOLING UNIT. 24. RIH WITH SUBMERSIBLE PUMP, PACKER, AND SSSV. SET BOTTOM OF SUBMERSIBLE PUMP MOTOR AT A DEPTH OF 905i' MD. THIS DEPTH DOES NOT INCLUDE KB MEASUREMENT. NEED TO INSTALL "XX" PLUG IN THE SELECTIVE "X" NIPPLE BEFORE RIH. THIS WILL ENABLE US TO PRESSURE UP ON TUBING AND SET PACKER. 25. ONCE THE PUMP MOTOR IS POSITIONED AT PROPER DEPTH, WILL NEED TO SPACE OUT TUBING SO WHEN HANGER IS SET IN PLACE THE PUMP MOTOR WILL CORRECTLY BE POSITIONED. MAY NEED TO INSTALL PUP JNT. ETC. 26. WILL NEED TO PRESSURE TEST 1/4" CONTROL LINE TO SSSV PRIOR TO SETTING HANGER IN PLACE. PRESSURE TEST TO 5000 PSI FOR FIVE MINUTES. 27. ONCE HANGER IS IN PLACE AND LOCK DOWN BOLTS HAVE BEEN ENGAGED, WILL NEED TO DISPLACE 10 BBL'S OF DIESEL IN ANNULUS AND 20 BBL'S IN THE TUBING PRIOR TO PRESSURING UP ON PACKER FOR FREEZE PROTECTION. PRESSURE UP ON THE TUBING TO 1200 PSI WHICH IS THE OTIS RECOMMENDED SETTING SETTING PRESSURE. WILL NOT BE ABLE TO PUT PRESSURE ON BACK SIDE AFTER PACKER IS SET DUE TO THE SLIDING SLEEVE FEATURE IN THE ANNULAR VENT VALVE. MAXIUM ALLOWABLE PRESSURE ON ANNULUS IS 500 PSI. WAITING ON OTIS RECOMMENDATIONS FOR MAKING SURE PACKER IS SET. 28. WILL NEED TO CHECK FOR SSSV INTEGRITY. AFTER PRESSURING UP TO SET PACKER, CLOSE SSSV AND BLEED PRESSURE TO ZERO. PRESSURE TUBING UP TO EQUALIZE ACROSS SSSV AND OPEN VALVE. BLEED REMAINING PRESSURE FROM TUBING. 28. INSTALL BPV IN TUBING HANGER. 29. ND BOP°S AND NU TREE. PRESSURE TEST THE SSSV CONTROL TO 5000 PSI AND CHECK FOR LEAKS. PRESSURE UP TREE TO 5000 PSI AND ALSO CHECK FOR LEAKS. 30. RDMO LOCATION. 31. RIH WITH SLICK LINE AND RETRIEVE THE "XX" PLUG IN THE "X" SELECTIVE NIPPLE. 52. WAIT FOR FURTHER SURFACE MODIFICATIONS BEFORE ATTEMPTING TO RUN SUBMERSIBLE PUMP. CASING: TUBING: SURFACE-13 5/8", 72#/FT.~ L-80 BTRS., SET AT 2,299'. INTERMEDIATE- 9 5/8"~ 47#/FT., L-80 BTRS., SET AT 8,455'. PRODUCTION- 7" LINER, 29#/FT., L-8O BTRS., SET FROM 8,089°-9,900. CAPACITY: 3.75 BBL/IO0° BURST PRESSURE: 7,240 PSIG 3 1/2", 9.2#/FT., L-80, DSS-HT @ 9171' CAPACITY: .8700 BBL/iO0' RE[£1V'ED DEC 1 81989 Alaska Oil & Gas Cons. GO~tlttSS[! Anchorage CAPACITY OF TUBING/CASING ANNULUS: 2.64 BBL/iO0' BURST PRESSURE: 10,160 PSIG (NO SAFETY FACTOR) RAT HOLE VOLUME: 24.5' BBL. (TO PBTD) PRESENT COMPLETION: MIDDLE KUPARUK 9,177'-9,194' PRESENT STATUS: KUPARUK PRODUCING WELL PENDING E.S.P. INST. 9 5/8" X 5 1/2" VOLUME- 496.4 BBL.'S 7" X 3 1/2" VOLUME- 2~.9 BBL.'S 1/2" TUBING VOLUME- 80.4 BBL.'S TOTAL DISPLACEMENT TO KILL WELL: 598.7 BBL.'S Z Dz U- 'r N ! t~ H --'% , ~ : i I ~ ~- ~EERING CORPORATION OEC-217-E A HALLIBURTON Company PREPAREO FOR COMPANY TELEPHONE DATE SIZE ;IZE WEIGHT , j~ THREAD DE$C RI PTI ON iTHREAD I [~NEW · COMPLET ION [~WORKOVER ESTI MATE OR DEPTH i) TOTAL ESTIMATE PREPARED BY iFFICE STATE OF ALASKA- ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 (907) 279-1433 TO: RE: Receipt of the following material which was transmitted via is hereby acknowledged: QUANT I TY' -- DESCRIPTION Copy sent to sender YES NO ~ - ST^T. o. n , ,SKAOILANDGASCONSERVATIONCOIV~' SION ""' '~ APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Alter casing __ Repair well Change approved program __ Operation shutdown __ Re-enter suspended well __ · Plugging __ Time extension __ Stimulate ~ Pull tubing x Variance __ Perforate __ Other __ 2. Name~Operator Conoco Inc. 3. Addmss P.O. Box 340045, Prudhoe Bay, AK 99734 4. location of well at sudace 964' FNL, 1233' FEL, Section 13, T13N, At top of productive interval 3367' FSL, 1158' FEL, Section 12, T13N, At effective depth N/A At total depth 3636' FSL, 914' FET,, Section 12, T13N, 5. Type of Well: V_._ Development Exploratory __ Stratigraphic Service ~ . R10E, UM R10E, UM R10E, UM 6. Datum elevation (DF or KB) KB-32 ' feet 7. Unit or Property name Milne Point Unit 8. Well number D-1 9. Permit number 81-144 10. APl number 50-- 029-20664 11. Field/Pool Kuparuk River Field 12. Present well condition summary Total depth: measured true vertical 9913 ' feet Plugs(measured) N/A 7917 ' feet Effective depth: measured true vertical N/A feet Junk(measured) N/A feet Casing Structural Conductor Sudace Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth 20" 113' 13-3/8" 2,300' measured 9-5/8" 8,455' 7" 9,990' 9171'-9194', 9404'-9420', 9434'-9474' true vertical 7 3 2 5 ' - 7 3 4 3 ' Tubing (size, grade, and measured depth) 3-1 / 2" True vertical depth AnChorage 9.3#/ft; L-80; DSS-HT Tubing (MD-9110') 13. Pac~rsandSSSV~ypeandmeasureddepth) Otis 7" Type WD Packer @ 9110' MD Camco 3-1/2" TRDP-1AE SSSV @ 2084' MD Attachmen~ Descri~ionsumma~pmposalx_~.._ De~iledoper~ionsprogram__ BOPs~h..;~ Well Completion Sketch; Choke Manifold Sketch 14. 16. Estimated date for commencing operation November 15, 1989 If proposal was verbally approved Name of approver Date approved 15. 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. Signed ~ ~. /~'~,3~~ Title Senior Production Foreman FOR COMMISSION USE ONLY Date /c,//'/~. Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test __ Location clearance Mechanical Integrity Test ~ Subsequent form required 10- ORIGINAL SIGNED BY LONNIE C. SMITH Approved by order of the Commission 404 Commissioner JApprovalNo.¢-,, Approved Copy Returned Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE j/ STIMULATION PROCEDURE Reperf & Frac Well D-1 Milne Point Unit ~ace Locat(on- g64' FNL, 1,231' FEL, Sec. 13, T13N, RIOE, UM l~.~h~: All depths are measured from KB datum. Cas_.~i~: Surface- 13 3/8", 72#/ft, L-80 btrs., set at 2,2gg'. Intermediate - 9 5/8",47#/ft., L-80 btrs., set at 8,455'. Production - 7" liner, 29#/ft, L-80, btrs., set from 8,089'-g,900'. Capacity: 3.75 bbl/]O0' Burst Pressure: 7,240 psig Tubinq: 3 l/2") 9.20#/ft, L-80, DSSIi e 8,g66' Capacity: 0.8700 bbl/]O0' Capacity of tubing/casing annulus: 2.64 bbl/lO0' Burst Pressure: 10,160 psi9 {no safety factor) PJcesent Como]eti_q~: Middle Kuparuk 9,]77'-9,194'. ~resentStatus: Kuparuk producing well pending E. S. P. installation. Ob.iective: Reperforate and fracture stimulate the Middle Kuparuk. Reclommend.ed ProCedurQ: 1) Hold a meeting with all contractors to discuss job requirements and safety prior to the job. The well contains a Camco TRDP $CSSV. Maintain sufficient control line pressure to keep the valve open throughout the job. '3) Rig up electric line company and wireline pressure control equipment. Run a GR/CCL from 9,250't~o, 8,9.25', Correlate with the attached DIL/GR dated 2/21/82. Perforate ~ne interval from 9,160'-9,198' with 4 SPF. Perf depths are based on the attached log dated 2/21/82 POOH and rig down perforating company. · PERORATION DETAIl. iNTERVAL FEET ~ T_QTAL SHOTS PHASING EHD ECP 9,160'-9,198' 38 4 15'~ - 0 0,~6" 7.-~--~2" Perforate with 2 1/8" semi-expendable guns With two runs of 19' each. The minimum recommended specs for EHD and ECP are listed above. Dist. TRP, PMS, JDC, MPU Sen(or Foreman OCT 1 1 ]98g Fracture MPU We . D-1 September 26, 1989 Page 2 4) Spot three 500 bbl frac tanks on location approximately 150' from the wellhead. Elevate the rear of the tanks approximately 8". Visually inspect the interior of the tanks for cleanliness (do not climb into the tanks). Fill each tank with 420 bbls. of clean MPU injection water. The water should be heated and maintained at 75-80 degrees F in order to insure proper hydration of the gelling agent. 5) Rig up tree saver and service company pump lines (use no threaded cross- overs, swedges or valves). Install two shut-off valves on the wellhead. Use two tn-line denstometers. Set up backup pumps for crosslinker and diesel. Rig up annulus pump to maintain 2,000 psig backside pressure. 6) Batch mix 1,960 bbl. (517,920 gal.) gelling agent at 40 lbs/lO00 gal. and additives as prescribed in the Material Detail (Attached). The pre-pad consists of non-crosslinked gel. Particulate fluid loss additive should be in the pad and pre-pad only. Diesel and crosslinker activator are the only additives that should be mixed on the fly. 7) Fill out the fluid report forms. Checl~ all additives against the attached material detail. Continuously roll the tanks until the viscosity is within the recommended limits {30 to 35 at 300 rpm on Fan 35 viscometer). Check samples from the top and bottom of the tank, values should correspond within 3 cps. 8) Hold a safety meeting with all personal on location. g) Pressure test the surface lines and tree saver to 7,000 psig and insure that there are no leaks. Set the pump trips at approximately 6,200 psig. Pressure up the annulus to 2,000 psig and maintain throughout the job. Note: O.V. stage collar in the 9 5/8" casing at approximately 2,000'. 10) Prepare to pump the frac Job as follows: A) Standby pumps (SOt,) are t'equired. These pumps must be manned and primed to immediately come on line if needed. A standby blender must be hooked up and ready to come on line in the case of primary blender failure. Pump the first $,000 gal of pre-pad on standby blender. Shut down and record the ISIP. Switch to main blender for the remainder of the job. B) Tank bottoms are Included in the volumes listed in Step 6. Leave 50 bbls tank bottom. C) Use the in-line densitometers during the job. Record rate and pressure on a strip chart. Send the charts to the Anchorage o~fice. D) Take samples of the crossllnked gel during the job. Place them in a water bath at 165 deg. F. Observe the samples and note when the gel breaks, Fracture MPU Well D-1 September ;?6, ]98g Page 3 E) Pre-Pad is not crosslinked and does not contain diesel oil. [he entire flush volume is diesel to prevent freezing. F) DO NOT OVER DISPLACE. Frac Rate: 25 BPil Maximum Allowable Surface Pressure: 6,000 psig 0 ~.5 BPM Anticipated SurFace Pressure- 4,500 psig to 5,000 psig Gel Diesel Cum Sand St-~-ge ~ ~g.al_J.. _p_p_g lbs. ~ Cum Fluid Pump Time ~ Minutes P-Pad 10,000 Pad ~g 800 ! 200 10,000 9.5 ' ' 34,000 3g.4 1 3,730 196 0.5 1,963 1,963 38,000 36.2 Z 2,65] 140 2.0 5,582 7,545 41,000 39.0 3 Z,479 130 4.0 110,437 17,982 44.000 41.9 4 2,3~8 122 6.0 14~698 32,680 47,000 44.8 5 2,193 115 8.0 18,468 S1,148 60,000 47.6 Flush 3,540 Totals 46,18! 5,443 51,148 51,148 53,540 51.0 Cum fluid--gel+diesel+sand Pre-Pad and Pad should contain 50#/lO00gal. fluid loss additive. Surfactant and non-emulsifier should be batch mixed with all fluid except flush. 11) Shut down. Allow the pressure to bleed off into the formation. Record the ISIP, 5 minute, 10 minute and 15 minute pressures. Close all surface valves and leave the well shut-in over night. Leave the SCSSV open. Have the service company monitor the break time of the last sample collected. Rig down the service company. 12) Allow the fracture to heal for a minimum of 24 hours. 13) Rig up slickline. Run in the hole and tag fill. If fill is present above 9,198' (bottom perf), rig up coil tubing and clean out to 9,900' PBTD. Rig down coil tubing. Engineering will provide a coil tubing procedure, if necessary. 14) Flow back the well to tanks very slowly. Begin with the choke set at 6/64" and increase the choke size by 4/64" every :~ hours to a maximum of 24/64". 15) Monitor for proppant returns. If after 300 bbls. of recovery, there is no proppant return and load recovery is less than ~0%, open the choke to 64/64" and obtain a stabilized post-frac flow test. Flow back a minimum of 500 bbls. 16) Shut-in the well pending E.S.P. installation and permanent flowline hookup Fracture MPU Well D-] September 26, 1989 Page 4 MATERIAL DETAIL Clean MPU injection water KCL (2%) Gelling Agent (40#/]O00gal Hydroxypropylguar) Nonionic Surfactant (2 gal./],O00 gal) Non-Emulsifier (2 gal/lOOOgal} Cross linker (3~/lO00gal) Anti-Foamer (Sgal/tank) B ioc i de (500 ppm) 52,920 gal. 8,916 lbs. 2,117 lbs. 106 gal. 106 gal. 110 lbs. 6 gal. 26 gal. FLA (50#/lO00gal Pad and Pre-Pad only) 1,640 lbs. Breaker As recommended by service company Diesel · 5,443 gal. ]6-20 Intermediate Strength Prop 51,148 lbs. TREATM~ Maximum Rate: 25 BPM Average Anticipated Pressure: 5,000 psig Estimated Hydraulic Horsepower: 3,064 hhp (An additional 50% hp capacity is required on location) Backside pump capable Of maintaining 2 000 psig static surface pressure is required. ' The following backup equipment is required: ]) 50% backup on primary injection pumps. 2) 100% blender backup. 3) 100% backup on diesel and crosslinking pumps. Prepared By: Approved By: "S~tS eve Rossbero Senior Production E~gineer ~upervising ProdUction Engin-~'F Fleld~ntenden-t DEPTH{RCB} MILNE POINT UNIT O No. I - ~ '~LETION DIAGRAM OPERATOR: CONOCO INC. SURFACE LOCATION' 964'FNL,12~,~)'FEL0 SEC 13,TI~)N, RIOE, U.M. BOTTOMHOLE LOCATION: 1564°FNL,914'FEL,SEC12,TI~)N, RIOE,U.M. 95/8", 47 LB/FT, L- 80, BTR$. CASING IO.825' 8.6SI= -- 31/2"~ g.$ LB/FT, L -80~ 0S$ --NT TU81NG .$.80' 2.$92" -- I/4`* SAFETY VALVE CONTROL LINE 0.25" -- CAMCO 31/2" TRDP -- 'I. AE SUBSURFACE $.93T" 2.812"' ~,,~ SAFETY VALVE 2202' 95/8"D.V. STAGE COLLAR eoge' ~ TOP OF 7# LINER 81OB' _i' 7~LINERBROWN HANGERMC HYORAULI¢ 8368' 95/8' FLOAT COLLAR B4SS' 95/8' FLOATSHOE 15.1 PPG EMW 7",29 LB/FT, L-80, BTRS. LINER 10-:31/2' CAMCO KBUG gAS LIFT MANDRELS SPACED OUT WITH ~1/~' 9.3 LB/FT, L-80, OSS-HT TUBING. ALL ~ANOR[LS HAVE I" TYPE 'E' DUMMY ~LYES INSTALLED. NO. I S.3l$" 2.87S" 2145' NO. 2 S. 3J3" 2.875" 3036' NO.3 5.313" 2.075" 3988' NO. 4 5.313" 2.675' 5067' NO.S 5.313" 2.87B' 6020' NO. 6 5.313" 2.075' 6788' NO.T 5.313" 2.875' 7423' NO.8 5.313' 2.875" 8000' NO.g S. 313" 2..875" 8573' NO.IO 5.313" 2.875' 8957' (8 PERFORATIONS) 9ISO'-- 9i32' g138' 917J* 9194' 9320' 9383' 9404*--9420* 9434' 9474' 9740' 9900' 9913' ~~. ,~,~,~ ._ · .... ~-~.. 4' +' - - ~-.-: 31/2' PUP JOINT 3 I/2'.OTIS"XN' NIP_PLE WITH 2.75" PROFiLe: ~iRELINE REEN~.T GUIDE PERFORATIONS (N~OO~E KUPARUK) EZSV RETAINER LEI PERFORATIONS (LOWER KUPARUK} LK2 T'LINER SHOE · TOTAL DEPTH ORIGINAL:JBF, 5-85 REVISIONS: S.S' 4.0' $.0' 3.90'* 2* .992 ' 2.75" 9138' 3.90" 2.992" 2.635' 9145' 5.7S' 3.00' FISH: DRESSER ATLAS 32" LINK CHARGE ALUMINUM STRIP pERFORATING GUN WAS STUCK IN THE'TUBING WITH THE TOP AT 9~32'. RECEIVED OCT 1 t98 Alaska 0il & 6~s Cons. Commission. MILNE Pl'. UNIT O NO. I CASING DIAGRAU OPERATOR' CONOCO, SURFACE LOCATION' 964' FtlL, 12~1' FEL, S!3, TI3H, BOTTOI~HOLE LOCATION: SPUD DATE: 1/19/82 RIOE, U. ~. 1564' FSL, 914' FEL, SI2, TISN, RIOE, U. ~. GROUND LEVEL EL.: 9' IASC DEPTH ~ t755' t ~LLY BUSHING EL.: $2' USL --B$~', ?~' Il/fi, L-~, MIS, esl. ~1 lC -~3~" f~O~ WLLU ~. F~ s~ M~}~ -t~/t" ~ 9404' } 1434' ~ , 4 e~ 94T4'~ .... ~ j I ~,.. z, u/,,. ~-u. ,,~. cst Casin$: 20", q4 lb/ft, H-40, BTRS, 0'-!110' 13-3/8", 72 lb/ft, L-80, BTRS, 0'-8455' 9-5/8", 47 lb/ft, L-80, BTRS, 0'-8455' 7", 29 lb/ft, L-80, BTRS, 8098'-9900' Cement: Primary 13-3/8" - 4900 sks. of Permafrost cement 9-5/8" - 500 sks. class G w/l% CFR-2, 0.3% Haled 9 32 Natl. Second stage - 135 sks. A~ctic Pack, 150 sks. Permafrost type C. ?" liner - 180 sks. class G w/l% CFR-2, 0.3% Haled 9, 3% KC1. Secondary Sqz. No. 1 - 180 sks. class G w/l% CFR-2, 0.1% HR-' below retainer and 20 sks. on top of the retainer. Perforations: Production 9404'-9420', 4 JSPF, Schlum. 4" Hollow Carrier 9434'-9474', 4 JSPF, Schlum. 4" Hollow Carrier 9171'-9194', 12 JSPF, Schlum. 4"'Hollow Carrier Well Test Results: Test Intv. BOPD No Date Form. (°APl) BWPD MCFPD Pwh Pwf Pe I 3/5/82 9404'-20' 0 1090 NA 0-50 3365 LK-1 9434'-74' LK-2 2 3/7/82 9171'-94' 230 0 86 50 2392 3652 1,04-2 (22°) Directional Highlights: The hole angle and direction at 9650' (deepest measurement) is 35.5°, N 34° g. A maximum hole angle of 52.5° was measured at 4800' ORIGINM.: dBF, 5/83 August 2, 1989 Conoco Inc. Milne Point Operations Center Pouch 340045 Prudhoe Bay, AK 99734 (907) 659-6300 Mr. M. T. Minder Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Minder: RE: Well D-1 Workover Operations This letter is to confirm that all items listed on the B.O.P.E. Inspection Report on 7/29/89 for the E.W.S. Rig # 94 conducted by Harold Hawkins have been repaired or replaced. If you should have any questions, plaese contact Bernie Barrilleaux or Henry Harrington at (907) 659-6322. Yours very truely, L Ro inson/D F. Rainwater Senior Production Foreman MEMORANDdM Stat(i of Alaska ALASKA OIL AND GAS CONSERVATION COmmISSION To: Lonnie C. Smit,~:~ DATE: August 7, 1989 : Co~issioner roLE NO: D. HRM. 055 TELEPHONE NO: THRU: Michael T. Minder ~~~ SUBJECT: Sr. Petroleum Engineer BOP Test Conoco MPU D-1 Kuparuk Rv Field FROM: Harold R. Hawkins Petroleum Inspector Wednesday.,._ July 26,_.1989,~ Conoco called me on the beeper and said they would be ready to test BOP's early pm on MPU Pad D-1. I arrived in the morning at Conoco's drill site and found that they were pUmping down the well to kill it. I started checking the rig and equipment and found serveral discrepancy. 1. I asked Henry Harrington, Conoco's Production Specialist if they had sent the Commission a sundry notice on the workover, they had not. 2. The choke manifold was. not to conformance, they have to build a new choke manifold complete. 3. The nitrogen6 back up was 2 bottles short and was not manifolded up to the accumulator. 4. There was no inside BOP on location. 5. No cover over blind remote control on floor. 6. No hydraulic valve on outsi~de choke on BOP. I went completely through the API RP 53 regu- lations and AOGCC regulations on workovers with Henry Harrington, Production Specialist, Jim Harford, owner and tool pusher for EWS-94, Doug Rainwater, Conoco's Supervisor, Dave Mountjoy another Supervisor for Conoco. Ail agreed to get BOP equipment into conformity and thanked me for the help. Saturday, J~ 2.9, 1989, I was called by Henry Harrington, Production ~peciali~'~'At ~.'0~0~7~'~hat they were ready for BOP tests. There were five failures, after 13 hours of testing. I filled out an AOGCC Field report which is attached. I also took pictures of rig 94 and compo- nen t s. Sunday, July 30, 1989, I returned and arrived back at BP Operations In summary, the BOP equipment was in satisfactory condition, when I left Milne Point, with the exception of two control valves on the master accumulator dripping hydraulic fluid. Conoco is to call AOGCC when repaired. Tuesday, August 1, 1989, I called Dave Mountjoy, Conoco Supervisor, they installed a flow nipple and flow lines to there pits. Attac~ent 02-001A (Rev. 8/8§) O&G 5184 Inspector STATE OF ALASKA ALASKA OIL & GAS CONSERVATION COMMISSION B.O.P.E. Inspection Report ~ Well .J Operator Location: Sec ~ T/~ Rt~ Drilling Contractor Mud Svstems Trip Tank Pit Gauge~ Flow Monitor Gas Detectors Representative~f~t~)z-%//~/~f~/~ff~~.~ Permit # /f~j Casing Set @ 27Z~ ft. Rig # ~M Representative Location, General ~]~ Well Sign.__ General Housekeeping ~ Rig ~ , Reserve Pit Visual z Audio ff £/f/f ffr'. ~ ACCUMULATOR SYSTEM Full Charge Pressure ~ ?~ ~-) Pressure After Closure Pump incr. clos. pres. 200 psig Full Charge Pressure Attained: psig psis/~fO ? min, JO sec. .~' min ~YO sec. q zTaT'?Zz 5 2 ('a psig, Controls: Master $/$~e~g~ ~0 ~ ,,~ ~ Remote O~ Blinds switch cover Kelly and Floor Safety Valves · BOPE Stack Annular Preventer Pipe Rams Blind Rams Choke Line Valves H. C.R. Valve Kill Line Valves Test Pressure Upper Kelly. Lower Kelly Ball Type Inside BOP Choke Manifold No. Valves ~ No. flanges / ~ Test Pressure Test Pressure Test Pressure Test Pressure ~.~we~ Test Pressure Check Valve , j¢/~/'¢ Adj us table Chokes Hydrauica!ly operated choke Test Results. Failures Test Time. /? hrs. Repair or Replacement of failed equipment to be made within y days and InspeCtor/ Commission office notified. Remarks: 62~'/~' ~ ~/ ~ ~ Z /~~ ~ ~~ ~ ~Z~' ~/~. ~ ~ ~ ~'~ - '~ J "a - . I ' ' orig. - AO&GCC cc - Operator cc - Supervisor Inspector, ~ ~r RIGIN STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ~1¢ ~'"~'~ APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Alter casing __ Repair well __ Change approved program __ Operation shutdown __ Re-enter suspended well __ Plugging __ Time extension __ Stimulate -z Pull tubing ~ Variance __ Perforate __ Other __ 2. Name of Operator Conoco Inc. 3. Address 99503 3201 C St., Suite 200 Anchorage, Ak. 4. Location of well at surface 964' FNL, 1233' FEL, Sec. 13, T13N, At top of productive interval 3367' FSL, 1158' FEL, Sec. 12, T13N, At effective depth N/A At total depth 3636' FSL, 914' FEL, Sec. 12, T13N, 5. Type of Well: Development Exploratory Stratigraphic Service R10E, UM R10E, UM R10E, UM 6. Datum elev~ion(DForKB) KB-32' Z UnitorPropertyname Milne Point Unit 8. Well number D-1 9. Permitnumber 81-144 10. APInumber 50-- 029-20664 11. Field/Pool Kuparuk River Field & feet 12. Present well condition summary Totaldepth: measured 9913' true vertical 7917 ' feet feet Plugs (measured) N/A Effective depth: measured N/A feet true vertical feet Junk(measured) N/A Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 20" 113 ' Surface 13 3/8" 2300' :~' :~ ...... ; Intermediate - . Production 9 5 / 8" 8455 ~1,~'~ "',,,~ ,I"'.:?(:.'~,,,¢~, Liner 7" 9900 ' Pedorationdepth: measured 9171' to 9194' 9404' to 9420', 9434' to truevertical 7325' to 7343' Tubing (size, grade, and measured depth) 3 1/2" 9.3#/Ft.; L-80; DSS-HT Tubing (MD-9110') 13. 14. 16. Packers and SSSV (type and measured depth) Otis 7" Type WD Packer @ 9110' MD Camco 3 1/2" TRDP-1AE SSSV ¢ 2084' MD Attachments Description summary of proposal .2L. Detailed operations program __ BOP sketch -x- Well Completion Sketch~ Choke Manifold Sketch Estimated date for commencing operation 15. Status of well classification as: 7/27/89 If proposal was verbally approved Yes 1625 Hr.s Oil..x_ Gas__ Suspended__ 7/26/89 Name of approver Lonnie Smith Date approved Service 17. , here~cer~fy that~foreg~and correct to the best of my knowledge. · Signed Title Senior Production Foreman FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test __ Location clearance __ Mechanical Integrity Test __ Subsequent form required 10- ORIGINAL SIGNED BY LONNIE C. SMITH Approved by order of the Commission Commissioner Date 7/27/89 I^ rova, o. Approved Copy Returned : ..... Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE ~MILNE POINT ....UN_lIT O No. I..-~'~ '°LETION. , ~ DIAGRAM.= . OPERATOR: CONOCO INC. SURFACE LOCATION' 964'FNL,1233'FELoSEC13,TI3N, RIOE, U.M. BO'[I'OMHOLE LOCATION: I$$O,'FNL,914'FEL,SECIZ,TI3N, RIOE,U.M. 1005'-- TUBING HANGER ~ ~'. ~9~" 19.70' OTIS 2. BO0' 'DW' T~G. PLUG 800' -'~ 1005'. ~,Oeq° 2202' sogs' · IIOS' IISI' 14SS' SilO* PERFORATIONS) S~)O'-- 9132' IISI' 9474' ,9740' 9900' 9913' ORIGINAL:JBF, 5-83 t~EVISIONS: $S/I",47LR/FT, L- I0, ITRS. CASING I0 .liS" t.lll' 31/~"", 1.3LB/trT, L-lO, OSS -NT TUBING 3.~0" a~.Bl2,' I~.?' I/4" SAFETY VALVE CONTROL LINE O.~S" ~ ~ · 31/Z' TRDP -- t. AE SUBSURFACE~_'"'"':! .' - CAMCO SAFETY VALVE 31/Z" CAMCO KBUG OAS LIFT S.SI3" MANDREL No.]. (FOR DETAILS lEE BELOW) IS/l'O.V. STAGE COLLAR SEE BELOW TOP OF 7" LINER 1"~ S~OWN MC HYORAULIC LINER NANGEI IS/l" FLOAT COLLAR SS/O' FLOAT S110[ IS. I PPG EMW ?;2:IILI/FT$ L-~O, ITII. LINtl NO.I t.31S" IIO. ;~' $. SIS' lO-SI/S" CAMCO IIUG 110.3 GAS LIFT MANDRELS 110.4 S.315, SPACED OUT WITH 31/~" NO.G S.3 LB/FT, L- I0, DSS- 11T NO.G 8.311" TUBING. ALL MANORELS NO.T 11AYE I' TYPE "E' DUMMY NO.I S.SI3 VALVES INSTALLED. NO.I S. 31S" OTIS STRAIGHT SLOT LOCAT011 SUe WITH .q.Tm _sr.~_ ~. U~T OTIS T T~PE WO" PACKER OTIS SEAL BORE EXTENSION WITH SI/Z'X S.S" ¢~0SS - OVER S.~O" 31/~" PEI~FORATED PUP JOINT ]I/S'"OTIS "X' NIPPLE WITH J~.I'S" PROFILE · $1/;~" PUP ,lOIN? 31/~" 0TIS'XN' NIPPLE WITH ~.75' ~.&~S"~O-G0 AND"PX-N" ~UG IN EZSV RETAINER PERFORATIONS { LOWER KuPARUK) 7'LIN£R SHOE TOTAL DEPTH I.ITS" .ITS" · .Om 3.0" 1.192" 2.&35" 9145' FISH: DRESSER ATLAS 32" LINK CHARGE ALUMINUM STRIP PERFORATING GUN WAS STUCK IN THE TUi~ING WITH THE TOP AT 9132: DESCRIPTION SUMMARY OF OPERATIONS le RU OTIS SLICKLINE, RIH AND PULL DUMMY VALVE C NO. 10 GAS LIFT MANDREL @ 8957' . 2. POOH AND RD SLICKLINE UNIT. 3. RU WORKOVER RIG. 4. CIRCULATE 9.8 PPG BRINE AND KILL WELL. 5. INSTALL BPV IN TUBING HANGER. 6. NU BOP STACK AND HYDRILL. 7. PU TUBING AND PULL OUT OF PACKER. 8. LD GAS LIFT MANDRELS WHILE POOH. 9. RIH WITH PACKER PLUCKER AND MILL OUT PACKER. 10. POOH WITH PACKER. IF X-NPLAND WIRELINE RE-ENTRY GUIDE ARE LEFT IN HOLE, PU OVERSHOT AND ATTEMPT TO FISH JUNK OUT OF HOLE. 11. ONCE ALL JUNK IS OUT OF HOLE RIH AND TAG FILL, REVERSE OUT AND CLEAN TO 9200'. POOH. 12. RIH WITH RE-ENTRY GUIDE, OTIS X-NPL, 3 1/2" PUP JNT. BELOW PACKER, HALLIBURTON CHAMP III PACKER AND TUBING. WILL LEAVE GAS LIFT MANDRIL ABOVE PACKER TO CIRCULATE. SET PACKER AT 9120'. 13. ND BOP AND NU TREE. MOVE RIG OFF LOCATION. 14. PROCEED WITH ACID STIMULATION PER ENGINEERING RECOMMENDATIONS. FLOW TEST WELL. John R. Kemp Manager of Alaskan Operations September 12, 1985 Conoco Inc. 3201 C Street Suite 200 Anchorage, AK 99503 (907) 564-7600 Harold Hedland Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hedland, Attached are completed 10-403 forms for Milne Point A-3, D-I, N-lB, L-I, M-IA and Gwydyr Bay State #2A. Ail of the above are classified as suspended wells. Conoco will contact oae of your representatives to conduct an inspection each year as long as the status of the wells is suspended. Please contact Jim Dosch at (907) 564-7649 if you should have any questions. Very truly yours, John R. eratlons Manager of AlaSka ' RECEIVED s£P 1 z Alaska 0il & Gas Cons, Commission Anchorage ( STATE OF ALASKA ( ALASKA OIL AND GAS CONSERVATION COMMISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL]t~I[ OTHER [] 2. Name of Operator Conoco Inc. 3. Address 3201 C Street, Suite 200, Anchorage, Alaska 99503 4. Location of Well 964' FNL, 1233' FEL, Section 13, T13N, R10E, U.M. 5. Elevation in feet (indicate KB, DF, etc.) GL=9 ' KB=32 ' 12. 6. Lease Designation and Serial No. ADL 47437 7. Permit No. 81-144 8. APl Number 5o- 029-20664 9. Unit or Lease Name Milne Point Unit 10. Well Number Milne Point D-1 11. Field and Pool Kuparuk River Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other [] Pull Tubing [] Other ~x~ Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105,170). Request one year extension for a suspended well. Conoco will contact one of your representatives to conduct an inspection each year as long as the status of the well is suspended. This wellbore will be utilized in Phase II development of the Milne Point Unit. Phase II is scheduled for production in 1988 and the well will be suspended until then. 14. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signe~~..~'-~~ ~ __ itle Manager of Alaskan Operations Date The space below for Commission use Conditions of APproval, if any: Approved by COMMISSIONER Approved Copy Returned By Order of the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate Conoco Inc. 2525 C Street Suite 100 Anchorage, Alaska 99503 November 6, 1984 Mr. Jim Trimble Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Trimble: Attached are completed 10-403 forms for Milne Point A-I, A-2, B-I, B-2, B-3, B-4A, B-5, C-I, C-2, C-3, D-l, L-I, M-IA, N-lB, and Gwydyr Bay State 2A. Ail of the above are classified suspended wells. Conoco will contact one of your representatives to conduct an inspection each year as long as the status of the wells are suspended. Please contact Jim Dosch at 279-0611 if you have any questions. Your_s very truly,/ Attachments RECEIVED NOV 0 9 Alaska Oil & Gas Cons. Commission Anchorage STATE OF ALASKA ALASI~ OIL AND GAS CONSERVATION'( ,MMISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL ~ OTHER [] 2. Name of Operator 7. Permit No. Conoco Inc. 81-144 3. Address 8. APl Number 2525 C Street, Suite 100, Anchorage, Alaska 99503 50- 029-20664 4. Location of Well 9. Unit or Lease Name Milne Point Unit 964' FNL, 1233' FEL, Setion 13, T13N, R10E, U.M. 5. Elevation in feet (indicate KB, DF, etc,) GL=9' KB=32' I 6 . Lease Designation and Serial No. ADL 47437 12. 10. Well Number Milne Point D-1 11. Field and Pool Kuparuk Field Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Wel~ [] Change Plans [] Repairs Made [] Other [] Pull Tubing [] Other [~X Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Request one year extension for a suspended well. Conoco will contact one of your representatives to conduct an inspection each year as long as the status of the well is suspended. This wellbore will be utilized in Phase II:~de~zelopment of the Milne Point Unit. Phase II is scheduled for production in 1988 and the well will be suspended until then. 14. I hereby ~~ the best of my knowledge. Manager of AlaSkan Operations Signed Title The space b~/~or Commission use C°nditior~'~ Approval, if any: _~pprovc~ Copy Date 9-26-84 Approved by By Order of COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate ' MEMOR, r' IDUM Sta e of Alaska ALASKA O L [~D GAS CONSERVATION COMMISSION TO: C.V. ~h~t~ton-- O^TE: August 22, 1984 Chairm~[j~ FILE NO: D.31.52 THRU: Lonnie C. Smith z/~5 Commis s loner TELEPHONE NO: FROM: Bobby Foster'~4o~.~ Petroleum Inspector SUBJECT: Inspect Suspended Wells and Locations at Conoco Sites. Thursday.,. August 16, 1984: I traveled this date to Prudhoe Bay and met with Jerry Fritch and Jim Dosch, Conoco representatives, to inspect the suspended drill sites and wells listed below. Gwyder Bay .2A Milne Point N-lB Milne Point M-IA Milne Point L-1 Milne Point Pad A (4 wells) Milne Point Pad C (4 wells) Milne Point Pad B Milne POint Pad D I recommend to the Commission that these wells and drill sites be accepted as suspended. PiCtures attached. 02-00IA(Rev. 10/79) . ~ Suspended Well and Location Report 20 AAC 25, ARTICLE 2 FILE INFORMAT!ON: /~ . %~-- ~)/CJO_~/ .~' _ Date Suspended ~-~-~'c_ Address '_~~5 d[ J~ ~~ ~[ ~~ ~ ' S~~ Location of Well ' Permit NO] ~r /~i .,~ - Ft. ~ ~ L, ~Ft. F ~ L API No. S00~:~,L&~q Sec.~, ~ ~, ~ &, ~. Unit or L~ase Name ~/~}~ ~F. ~ We~ No.l D: /1 2- ' - Field & Pool ~//~C-~F : / Condi ti on of Pi ts ~~/L/_ -I Well head - Ail outlets plugged Well sign - Attached to well head Attached to well guard Attached to Information correct No Ye s No '(~~ No No Cellar - Opened Ye s No Fi 1 led Ye s No Covered ~ No Capped Open WaterWell - Plugged off Rat Hole Open Yes No Fi 1 led Ye s No Covered ~ No Explanation Photographs taken to verify above conditions~ No Explanaton Work to be done to be acceptable This well and location is ~ (unacceptable) suspended for the period o~~ ;9~thru ~-/~ Inspected by Date: to be classified as 19~_. Revised 8/24/82 Suspended Well and Location Report 20 AAC 25, ARTICLE 2 FILE INFORMATION: /~ . ~-~a--~--. ..... ~ ~/6/_~3~_ ~_ . ~ . ~ _ ' Date Suspended Address ~'-~ ~7~_~'. ~-~~/D~ ~~'-~ Permit No~ ~[~O Sur~ce Location,of Well , _ /7 ~ Ft. F ~ L, ~Ft. F~ L API NO. 50~-~O.~DO-O) s~C.~, T~ ~' R/~~, ~ M. Unit or Lease Name~/~ ~_: Well No.','~L~[ ~ . Field & Pool ~/~.~~.~[[ ~ ~' Condition of Pad 0~-, .... Condition' of Pits Well head - Ail outlets plugged Well sign - Attached to well head Attached to well guard Attached to Information correct ~ No Ye s No No O No Cellar - opened Ye s Fil led Ye s Covered ~ WaterWell - Plugged off No No No Capped Ope n Rat Hole Open Yes N° Fil led Yes No Covered ~ No Explanation /~/~ · condi tions~ Photographs taken to verify above No , Explanaton Wor~ to be done to be acceptable This well and location is (~-~ptabI~ (unacceptable_) to, suspended for the period ofj Inspec ed by Da te: be classified as Revised 8124/82 ALASKA OIL AND CAS CONSERVATION COMMISSION DATE: TO: Permit No. ~/-- /~ Bill Sheffield Governor 3001 PORCUPINE DRIVE ANCHORAGE,ALASKA 99501;-3192 TELEPHONE(907) 279.-1433 We wish to bring to your attention that the Commission has not yet received the following required items on the subject well which our records indicated was completed ~--~2~r-~=P- Article 536(b) of Title 20, Chapter 25, Alaska Administrative Code, stipulates that this material shall be filed within 30 days after completion of a drilled well. Please submit the above missing material. Sincerely, C. V. Chat~ Chairman Conoco Inc. 2525 C Street Suite 100 Anchorage, Alaska 99503 January 19, 1984 Mr. C. V. Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Chatterton: RE: 'uest For Request For Mill Unit Registered Survey Plat (1/10/84) 2 Inclination Survey (1/10/84) Please find attached; a Registered Survey Plat for Milne Point Unit Well D No. 1, and a list of all Single Shot Surveys run in Milne Point Unit B No. 2, as requested by the referenced letters. We regret that this information was not submitted earlier, and we will strive to prevent such oversights in the future. Your~ ~ery truly, R. J. Francis Manager - Engineering JBF/km cc: Milne Point Unit D No. 1 Well File, w/EnCl. Milne Point Unit B No. 2 Well File, w/Encl. JAN2 o ]984 Oil & Gas Cons. Commisoion · ' CONF'"'nENTIAL INFORMATION ~ Ft~,nished By Conoco inc. O R T H ' LAGOON RESERVE ,.o.,,. ~/ .. ,%% PONDS P IT VICINITY MAP i,': 2 MILESt ' NOT_ E_'- I. STATE PLANE COORDINATES ARE ZONE 4. 2. ALL GEODETIC POSITIONS ARE BASED 'ON N. kD. 1927. $. OFFSETS TO SECTION LINES ARE COMPUTED BASED ON PROTRACTED VALUES OF THE SECTION CORNER POSITIONS. LOCATION IN SECTION STATE PLANE COORDS. 6EODETIC POSITION i I II 04 I 96,4,' I iz:31' 6,027,418.09 I 569,807.63 70°t9'06.90" 149o25,46i:3, ~124/83 I I - MADE BY ME OR UNDER MY SUPERVlSlON~ AND I ~,_ II THAT ALL DIMENSIONS AND OTHER DETAILS II P ~~ II ARE coR.~. ,~' ~ a~h ~ ~~11 i h.li' ii D PAD I ~%.,:: II~c.~."~ ~DUlLIWELL I _~"**u",_ !~. . . ..LOCATION '~~?""'":~'~' I! H. D. Haley Manager of Alaskan Operations Conoco Inc. 2525 C Street Suite 100 Anchorage, AK 99503 October 17, 1983 Mr. Jim Trimble Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Trimble: Attached are completed 10-403 forms for Milne Point A-i, A-2, B-i, B-2, B-3, B-4A, C-I, C-2, C-3, C-4,~i~l,~and Gwydyr Bay State #2A. Ail of the above are classified as suspended wells, and Conoco will be contacting one of your representatives to conduct an inspection of these wells each year as long as the wells remain under this status. Also attached is a completed 10-407 form requesting a change in status for Milne Point B-5 from plugged and abandoned to suspended. You will also find photographs enclosed covering the cleanup operations that took place subsequent to this year's inspection of Gwydyr Bay State #1 and #2A. Photographs are also included that show the new signs mounted on Milne Point C-4 and D-2A. Please contact J. T. Dosch if additional, information is necessary or if you should have any questions. H. D. Haley Manager of Alaskan Operations JTD/kp cc: A. E. Hastings, Anchorage SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL OTHER [] 2. Name of Operator Con.oco Inc. 3. Address 2525 C Street, Suite 100, Anchorage, Alaska 99503 4. Location of Well 964' FNL, 1233' FEL, Sec. 13, T13N, RIOE, U.M. 5. Elevation in feet (indicate KB, DF, etc.) GL=9' KB=32' 6. Lease Designation and Serial No. APL 47437 7. Permit No. 81-144 8. APl Number 50-029_20ti¢;4 9. Unit or Lease Name Milne Point Unit 10. Well Number Milne Point D-1 11. Field and Pool Kuparuk Field 12. (Submit in Triplicate) Perforate [] Alter Casing [] Perforations Stimulate [] Abandon [] Stimulation Repair Well [] Change Plans [] Repairs Made Pull Tubing [] Other X[X] Pulling Tubing (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Duplicate) [] Altering Casing [] Abandonment [] Other 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Request one year extension for a suspended well Conoco will contact one of your representatives to conduct an inspection each year until the well has a plugged and abandoned status. 14. I hereby~er~y t,t,~t the foregoing is true and correct to the best of my knowledge. Signed ~- ~~'~~'~/~' ~ T~t,eManager of Alaskan Operations The space-b~w fo'r Commission use H. D. Hal ey 10-19-83 Conditions of Approval, if any: . Approved by Form 10-403 Date ORIGINAL' SltllE! '-- B'Y I~ON~IE C. SMITI! Approved Copy Returned By Order of COMMISSIONER, the Commission Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate M EMORAN DUM State of Alaska /7- TO: C. VI. ~h~t~ton DATE: September 2, 1983 Chain~--~ TRRU'. Lonnie C. Smith ~%:/"/ 10SA:J3 FILE NO: ~~ ~O~ TELEPHONE NO: FROM: Harold R. Hawkins ..,?, ,~: SUBJECT: Petroleum Inspector ?'['~,?/. Cleanup Inspection for Extension of Suspended Status, Conoco, Milne Point D-i, Sec. 13, T13N,R10W,UM, Permit No. 82-1~ Wednesday, August 17, 1983: While I was inspecting other wells on the slope, I inspected Milne Point D-1 for Conoco for extension of suspension. I found the pad free of debris, well sign okay. I took a picture of the well sign and tree for verification. I filled out an A.O.C.C.C. report ~hich is attached. In summary, I inspected Conoco's Milne Point No. D-1 and found all requirements on our regulations were met. I feel .that Well No. D-1 should be approved for extension of suspension. Attachments 02-001A{ Rev. 10/791 Suspended Well and Location Report 20 LAC 25, ARTICLE 2 FILE INFORMATION: Operator L-_~. ~ ~.~ f~ Date Suspended Addre s s Surface Location of Well Permit No., ..... ,5~3~'/ Ft. F..//~A L, O~~___Ft. F ~-~'-~ L API No. 50 Sec. ;~, T/_~_ ../J, R/{3 ....~/_, _t/_M. Unit or Lease Name ./4¢ Wel 1 No. Field & Pool Condition of Pad ~ d)...~_/D Condition of Pits _ ~ rg~ Am-_ Well head - All outlets plugged Well sign -Attached to well head Attached to well guard Attached to Information correct No Cellar - Opened Yes No Fi 1 led Ye s No Covered ~~ No capped Ope n WaterWell - Plugged off Rat Hole Open Yes Fi 1 led Ye s No Covered ~' No PhOtographs taken to verify above conditions Yes No Explanaton , >~ >= c Work to be done to be a.cceptable This well and location is(~cce~ (unacceptable) to be classi~fied as suspended for the period of----. ----~ 191 .... thru .- 19..... ~ .- Inspected by: ...... Revised 8~24/82 Conoco Inc. 2525 C Street Suite 100 Anchorage, Alaska 99503 C. V. Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Chatterton: Please find enclosed one blue-line print and one sepia print of all logs from Milne Point Unit No. D-1. These logs are being sent to you in compliance with Article 6, Section 536 of the AOGCC Regulations. Ail other well data required under this section were previously submitted on April 20, 1982. ~ Please note that this data is considered "confidential" and should be handled accordingly. Attached isa list of all well logs submitted with this letter. Please sign the copy and return it to my attention at: Conoco, Inc. 2525 C Street, Suite 100 Anchorage, AK 99503 If you have any questions or comments, please call me at 279-061].. YoT~rs/~.w~./l~very~ t~~ Jim Fox Engineering Technician kp cc: Gary Merriman, w/Attachments Steve Berg, w/Attachments Well File, w/Attachments RECEIVED NOV 1 9 1982 Alaska 0il & Gas Cons. ComrnJssi0~ Anchorag~ To "'~ lecord of Shipment of Confidential Information F'lUnder Separate Cover [~iJ~Enclosed Via ~-~/~'l~'~) -'~E~.-I y(~__._G~E~;> Quantity Contents A,~ ' ....... ,i .... j ~_~.~T ....... ~ " ..... ~" j MGT ~ ~', J ~ B~-I~- ,,,, "~ ~,, J ~, qo~ ~~c6, ~ ~" [ : cbc- ~Cl i . Qx~~~o ~ I ~,, ......... ~/ Signed By ittal Approved By Date ~struction/~ease~~/~_e~ge rec~/la~~:tly b.~,~i~ing arid returning carbon copy. Received rcN~/~,'~_~',/~_...f,~¢~..~ lCf~/~~~~_ Date Remarks REtEIVEO NOV 1 9 i9-82 Alaska 0il & 6as Cnns. ~' Anchorage Transmittal Copy Only To 13-98 PCX1, 7-79 NORICK OKLA, CIT~' PRINTED IN U.$.Ao !~ ':"~cord of Shipment of 0 .;onfidential Information [] Under Separate Cover [] Enclosed Via fi'( ~ {"~'~ --~ ~_~(~1 W (~,~--~ '""~ Quantity Contents Tr~sm Signed By ittal Approved By Date ~nstruction,: Eleas.~k~ec~e receip'{~:~f.o~mptly.,b,C.~;~ing and r~.~,turning carbon copy. .Rede,yea ~y-' ~./.:'./CL/-":.,, -. ~.,.., ?/:.,~,' :...-.~.eW¢.~,_ Date Remarks ~[~ch_~s~ Comrnis~b.n: Transmittal Copy Only To 13-98 PCXt ,"7-79 NORICK OKLA. CiTY PRH~TED IN U.S.A. H. D. Haley Conoco Inc. Manager of Alaskan Operations 2525 C Street Suite 100 Anchorage, AK 99503 October 1, 1982 Mr. Jim Trimble Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Trimble: Attached are completed 10-403 forms for: Milne Roint A-l, B-l, B-2, B-3, B-4A, C-1, C-3'!!i!iiD?!, Kavearak Point 32-25; and Gwydyr Bay State #2A. All of the above are classified as suspended wells and Conoco will be contacting one of your representatives to conduct an inspection each year until the wells have a plugged and abandoned status. Also attached is a completed 10-407 form requesting a change in. status for Gwydyr Bay State #1 from suspended to plugged and abandoned. You will also find the photographs you requested concerning the recent i.nspections of Gwydyr Bay State #1, #2A, and Milne Point A-1. Please contact J. T. Dosch if additional information is necessary or if you should have any questions. Yours very truly, H. D. Ha ley Manager of Alaskan Operations JTD/tt cc- G. A. Merriman - w/o attachments A. E. Hastings - w/o attachments ALASKA ,LAND GAS CONSERVATION C ~IMISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL OTHER [] 2. Name of Operator 7. Permit No. Conoco Inc. 81-144 3. Address 8. APl Number 2525 C Street, Suite 100, Anchorage, Alaska 99503 5o-029-20664 4. Location of Well 964' FNL, 1233' FEL, Sec. 13, T13N, RIOE, UM 5. Elevation in feet (indicate KB, DF, etc.) GL=9' KB=32' 6. Lease Designation and Serial No. ADL 47437 9. Unit or Lease Name Milne Point Unit 10. Well Number Milne Point D-1 11. Field and Pool Kuparuk Field 12. (Submit in T[iplicate) Perforate [] Alter Casing [] Perforations Stimulate [] Abandon [] Stimulation Repair Well [] Change Plans [] Repairs Made Pull Tubing [] Other ~[~ Pulling Tubing (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Duplicate) [] Altering Casing [] Abandonment [] Other 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Request one year extension for a suspended well. Conoco will contact one of your representatives to conduct an inspection each year until the well has a plugged and abandoned status. 14. I hereby certify ~ t~ forego!,~ is true and correct to the best of my knowledge. Signed ..... ,~-- __~__ Title Manager of Alaskan Operations'Date 10-6-82_ The space below for Commission use ///" / Conditions of Approval, if any: An inspection will be necessary by August 1983. Approvedby. BY ~1~'~¥ ¥~:~' [U~[[~ COMMISSIONER Approved Copy Returned By O-7~-er 6f ~ the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate Conoco Inc. 2525 C Street Suite 100 Anchorage. Alaska 99503 April 27, 1982 Mr. Bill Van Alen Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Bill' Enclosed are the original Well Completion Report forms on MSq~ne' Poi~nt C-1 and~§~l'~'with original signatures.. If I can be of further assistance, please call me at 279-0611. Yours very truly, "'Gary 'A. Merriman Supervising Engineer kp cc: Correspondence file, Milne Point C-l, D-l Alaska Oil & G~s Car~s. C ~ 'Ancl'~;ago omlnissior~ ' ~'~ ''I~ STATE Of ALASKA {i'~ .... ALASK ~,''.''ANDGASCONSERVATION C '~;¢'AISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL [] GAS [] SUSPENDED [~ ABANDONED [] SERVICE [] '2. Name of Operator 7. Permit Number Conoco :Inc. 8]-]44 3. Address 8. APl Number 2525 C Street, Suite 100, Anchorage, AK 99503 5oj329-20664 ,. 4. Location of well at surface 9. Unit or Lease Name 964' FNL, 1233' FEL, Sec. 13, T13N, RIOE, UM ' Milne Point Unit At Top Producing Interval 10. Well Number 3367' FSL, 1158' FEL, Sec. 12, T13N, RIOE, UM Milne Point No. D-1 At Total Depth 11. Field and Pool 3636' FSL, 9]4' FEL, Sec. ]2, T]3N, R]0E, UM Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Kuparuk GL= 9' KB=32' ADL 47437 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 116. No. of Completions ]/]9/82 2/26/82 3/20/82 N/A feetMSLI One 17. l~otal Depth (MD+TVD) 18.Plug Back Depth (MD+I'VD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of PermafroSt 9913 (7917 TVD) 9320 (7362 TVD YES)~X NO[] 2084 feetMD 1800'+ · 22. Type Electric or Other Logs Run SP/GR/SFL/DIL/BHCS; NGT/FDC/CNL; HUT; 'RFT; SWC's 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLESIZE CEMENTING RECORD AMOUNT PULLED 20" 94#/ft H-40 0 113' 26" Cement to surface . 13 3/8" 72#/ft L-80 0 2300' '17~" 4980 sks perma-frosl O' · 9 5/8" 47#/ft L-80 ' '0 .8455' 12¼" 500 sks Class G. 13E O' ' bbl Arctic pack, continuation of casing Liner dat~ on page 2. 24. Perforations op.en to Production (MD+TVD of Top and Bottom ~and 25. TUBING RECORD interval, size and. nur~iber) ' ' SIZE ' ' DEPTH SET (MD) PACKER SET(I~ID) 9171 (7325 TVD) to 9194 (7343 TVD) 3½" (9.3#) 9110' 9110' 90° phasing ~ 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. See. page..2 - Test., perforations for DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED additional perf data. See page .2.. - Cement squeezes 27. PRODUCTION TEST Date First Production,,.,. 3' :-': :'U a~;'a~'tJ' Method of. Operation (Flowing, gas lift,.etc.) Date of Test Hours Tested ,PRODUCTION FOR OIL-BBL GAs-MCF WAT~:R-BBL CHOKE SIZE' i'GAS-OILRATIO , : ' . . . . TEST PERIOD ~ .... ,.~ ,: - Flow Tubing ~Casing Press, ure CA,LCOI_ATED-.. O. IL-BBL' GAS-MCF . .WATER:DeL OIL GRAVITY-APl (corr) ~Press.. ,. .... ,. 24-HouRRATE . ... 28. COP E DATA ' Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. '" " "' ' -"' RECEIVED None taken " '"" " " ' ' :' APR . 'Alaska Oil & Gas Cons. Comml~o~ '""' ' :¥ " Anchorage · Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. 30.' GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. W. Sak Sands 5145 (4566 TVD) (See page 3 for details) T/Middle Kup 9166 , (7322 TVD) DST # 2, Test #3 T/Lower Kup 9402 (7502 TVD) DST # 1 I 31. LIST OF ATTACHMENTS 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~~2~,¢~.~/ TitleSUpV. Prod. Eng. Date Apr'il 19,, 1 982 INSTRUCTIONS General' This form is designed for submitting a complete and correct well comple~ion report and log qn all types of lands and leases in Alaska. Item 1' Classification of Service Wells' Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5' Indicate which elevation is used as reference (where not otherwiseishown) for depth measurements given in other ~paces on this form and in any attachments. "~:. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing.intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23' Attached supplemental records for this well should show the details of any multiple stage cement- lng and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken', indicate' "none". ',Form 10.407 :)PERATOR_ CONOCO DATE,,, 2- ...... / zG L__I9 NELL NAME /1AI£NE PT D-I NO. SHOT 41 NO. RECOVERED ! TUN NO. -~ ......... TOTAL DEPTH c)~13 REMARKS D~ ~o e_~o,.~c ~.r~-o% %~F~ ~- ~ ~r~ 1~~.~. 'AMT PROB NO DF. PTH REC III 0 $ C F CF DESCRIPTION FORM , --' // , ~1- / · Z 9 ~o " - ~'F~, - - ~ ~-~/~, s~4, ~h-,,~,~. " , , ,14 e4o4 ~ ~' F " " ~-¢e ~ ~-.--' o, , ,u , r --' J / ~ / 1~ 939~ Ng - " - .... , , , lY~' ? ,, F -- a=$ " ~1. --' '' ' ' , ' pal ~ ' 5 ~" .... )PERATOR COl,JOC,.,..ODATE Z / ~ ~ ...... / I q ~ z NELL NAME ~I/-N~' pT' P-! NO. SHOT 41 NO. RECOVERED ,~.,~ ~UN NO._ ~ TOTAL DEPTH '~'51~ _REMARKS~5,-¢... ?..~.~,-. I ') AMT , PROB DESCRIPTION NO DEPTH REC FORM 0 S C F CF ,. .. .Z.C, c)jc)~., jy~." P .,;J~llck, vp ~ ~'-~; F icl,is ~k ~w t,~s. .... I+ l~,,-m~l b~-, ,c,,,,.~,.; ~:-v~,~,.-~17-~_.,=+=../ . _~-~r,. ,/~r+~t, ;,,¢/,~.~ ('&/,~,rb 1), ~h. Wl~. L J ~'/~ ~l ~ · · · / J ' u lY~~ ,, ,, ,,,1~ ¢i,.Is ~1.,. ~ ,aL. ,~,., .F~.hJ. ~,.,t,.,c,:,.-J.,IJ,. , c~l~. 1 I/).~ . . · ~ ~ ' ~ ' .~ 2- ,. ,,,.. ~',.,..,. ,~,,,/, g;,- - ~, It-,... ~;,.'. ,~ I/' ' / i , i-' : '~ : ! i: : -- ~1 ~' ' , k~. ~, ~ L.,- L~.: . / d · , / , ~7 ~17~, P .... v~ ~ c~ o,~, ~ ~ , , . .~ ' ' / ' '" ' · 3~ ~,4 ~" F " " " " " '~ .... ~ '' ~ ' ' ~ ' i,t,4'~ ,, ,, ~t' , 1,1,,, '/-I.a S:~, o ~ , ~ / / .// , ?J ...... , ,,:t.~/.~.. s~,,J~<.~..~,.;-~ ~,,'~,-~,. 40 9~7o - 4/ 9lr~, lY4" ~-G " r. ~,.+ , .... ~:~,.,,,,,o,~-,-Jk~,,,.,..c,.-,,.,,:/,~,,,,,,,'~ · _ ~ j . /, / I - -'"ClylCn ""27Co o ^ -- · _ _ CONT~IENTAL OIL COMPANY ' '' , , ~,~,-L,Li¥~,'U State_.__~ .4~,~ ~_Recor'~ed by..~o~/~.x Well ~~- ~- / .'__~ ~Z~ ~' Parish/C0un~Y ~)~ ~/o~"~ NO. . .DEPT!{. RECOVERY LITHOLOGY .......~ ,! PERM' i PROD.;.. _v_Is,,CUT FLUOR,.. ~ ..~ESS TEXTURE .C, OLO. R' ... REMARKS "(;~ '! ! - '";)'~ *'"~;" "' ·e_ ·..~I~-~. $/¥ ) b~4o~ Lo ...0'7. ' . Al~,~.. ./Fo~_. ... ~,;~ ~II Z~. ~X:S,o X~:.. s/~ ~,~r~ ! .... , _ _ , I I ] I ,,, ii ,, .. , ..... ' - ~', u , ~ , ] , , ~ , .. - - ..................... - .......... - - :-=--- -:-~-=- ........ ---~:~ ' ----~---"'--~--: ..... ~ ' ~ .... ' ...... ~ '~ , .'L~ ..... i ....... / ........ ,,1 ...... '-- i _ _ ~ __~ , ' .2 I1 ~I"TI. 7 ~,' - t~ .. .-,_. ' .~ ,,--: ~ ..... ;~ _%' --"F ,,% .... ~ ,, ~ uz-" ,;;,',:'r~,,, ':' ~ ~ ";.,~ ". '-:~ -:Z' .'~ ~, ~ .... ' ..... .._ __._., .... ., ....... _ ...... . .... _ . _ _~___.._ :_.~__ _...:..._._. _:_...., ...... ~_g . . ~~~ e//,~~,,. c ' '" ' ' . ' ,-: State LUttsnore} ~_ .~OHT~IENTAL OIL COMPANY Well ///?~Y- $.-/' r~,., ~Z .~ APR 2 1 1982 Paris~coUn~y ~. ~~ .... ..... ~' -- ... ~ ....... , L' ! m mi I t m i NO. DEPTH RECOVERY LITHOLOGY .. PERM, .. PRO. D, ~__!S.: CUT ' FLUOR. NESS. 'I:EXTURE COLOR REMARKS , m i ....... - '~'L.' '" ~ - ~ - ~ /_.4', ' ~,tif~,',.:i' ! ,', ..... l,~-. ,~,~:; .,~,~.,. y.~../,~ ~72o,.,., ..... , ~.., " ' ' '. "i ~-I C" I- ~~' ~',,~,-- I , ..., ' ~- ~~ ;--~: m~z~ / ,,I ~,~1 I .... q _ . n I.. _ - ,, . ..... .._,, ' · , i ..,'. I ., I ,, " ~,'F~-~ ~ i ..- ~ .,r ~ ~: ~Ne~ ~Z. ~Z~ I ~ ~~d__ .[ ~,'~4 ! ' . .] ............ " ~,~l ~W. o~ l. . ,,.. ........... +-vt Z~N-~. ~/1~-~,'~ ~~,~. . 7,~ ,, ..,~ .- ,I '~ . i ,~ I -'// - ,, - ! ~,~,~,~ ¢; ; .~~ ~'; ~~: ~ z ~ m~a5 / ,z · ~ i ,, ......... ~ ........... ~o~ ~,.~ , ........... . , "- ........ :~~-" ...... ~- - - ~/~ ' - ~ .. ~ . ,, ~oc: ~-~,'~ ~//~-~,/~ ........ ~ .......... · , mm,~ _ m " ........ ', I:';-_:1: ' ' .............. ' . "e~z~ ~1~ '.. - ......... - - ....... - .......,~,, ! ...... ',i"-' ...... ',, ~,~-..' .......... ~ .... . .-~ y~ ........ · /'/ .... _ 3~ SZZ; / " '-- ' ---' "~ ~ . . I'~ ' I -" -- ..... "' OIL COMPANY _ #~ State {uttsnore) //4: .. NO. _DEP_T!i ,_ RECOVERY LITHOLOGY PERM,_ i. PROD..J ViS. CUTJ. ' FLUOR. NESS TEXTURE COLOR REMARKS j i i , ]mu il i ~~ / Eastman / ~ ,Whipstockl)~ A PETROLANE COMPANY REPORT of SUB-SURFaCE DIRECTIONAL SUR CONOCO COMPANY Well Number: D-1 WELL NAME Milne Pt., North SloDe, Alaska LOCATION JOB NUMBER A0382G0409 SURVEY BY M Lund TYPE OF SURVEY Gyro Multi Shot ~'8" ,,'", Alaska DATE 03-Mar-82 ............. Eastman Whipstock APE TROLANE COMPANY P. O. Box 4-1970?Anchorage. Alaska 99509/(907) 349-4617 March 9, 1982 CONOCO 2525 C Street Anchorage, Alaska 99503 Well Number: D-1 Location: Milne Pt., North Slope, Alaska Type of Survey: Gyro Multi Shot Date: 03-Mar-82 Method of Computation: Radius of Curvature Surveyor: M Lund Job Number: A0382G0409 Attn: Terry Lucht Dear Mr. Lucht, We are enclosing the original and five copies of the Gyro Multi Shot Survey run on the above mentioned well. To date, the following distribution has been accomplished: A. ' ' 1 copy telecopied to E/W North Slope office for delivery to CONOCO field representives. B.' '5 copies delivered to drilling for in-house distribution. C. '3 copies for E/W permanent well files. We wish to take this opportunity to thank you for calling on our services and we trust that we may continue to serve your needs in the future. Sincerely, SHYA~ TALWAR District Operations Manager ST/bb cc: file enclosure Directional Drillers/Sub-Surface Surveyors/Instrument & Tool Rentals/Sales/Worldwide CONOCO. NORTH SLOPE~ ~I.~SK~ GMS, 0-9650 M~, SURVEYORI M LIIN[; ;.;ATE RUN; O~-MAR-82 90 DEG, A/LI NO; 1524 FORE'SIGHT'; N59W ................................................................................................. RECOR;~ OF SURVEY RADIUS OF CURVATURE METHO0 . L, UI~UL, U :MILNE PT, WELL NO: D-] 'NORTH'-SUOPE¥'--AIZASK'i~' ,JOB NO:' AOJ8200409 T~ME [,ATE TRUE ;MEASURED-DR~'FT ........ DR"I'FT .... COURSE---'VERTXCAlz"-VERTICAI ....... SLtBSEA .....R E C T A N G IJ [. A R C L 0 S tJR E DOGLEG DEPTH ANGLE DIRECTION LENGTH DEPTH SECTION TVD C 0 0 R D I N A '! E S DISTANCE DIRECTION SEVERIT'. FEET D M D M FEET FEET FEET FEET FEET FEET D M DG?100F? . O. 0 0 0 0 Oo 0.00 0o00 -32°00 0.00 0.00 0o00 0 0 100. 0 0 0 0 ~00. 100.00 0.00 68.00 0.00 0.00 0,00 0 0 200'~ .......... 0-"~0"N'"59 ......0----~ ........ i00~ .......... 200"c00 0°'22 1'68.00 ..... 0'~22'~N .................. 0-c37'-E ....... 0.44 N 59 0 E 300. 0 0 0 0 100. ~00.00 0.43 268.00 0.45 N 0.75 E 0.87 N 59 0 E 400. 0 0 0 0 100. 400.00 0.43 368.00 0.45 N 0.75 E 0.87 N ..,9 0 E 500. 0 ]~ .., N 30 0 W 100. 500.00 0.63 468.00 0.64 N 0.64 E 0.90 N 45 5 E 600. 0 30 S 88 0 W 100. 599.99 0.94 567.99 0.94 N 0.09 E 0.94 N 5 41E -' 700~ ......... 0 .......... 0 ................ 0 .......... 0 ................... t00-~ ................... 699s-99 ................... 0-~'9~ 667.99 ........ 0o-93'-N ................. 0~--34--W ...... 0~-99 N 20 ]9 W 800. 0 45 N 54 0 W 100. 799.99 1.3~ 767.99 900, 0 0 0 0 ]00. 899.99 ].72 867.99 1.31N 0.87 W 1.69 N 1.40 W ].69 N 1.40 W ].57 N 53 39 W 2.20 N 59 56 W 1000. 0 0 0 0100. ........ 999.99~. 1.72 967.99 2.20 N ~9 36 W 1100. 0 0 0 0 lOOJi~' 099.99";-'--~;' .] ...~,:.o :t067..99 1 · 69 N 1 040 W 20,_-':"0N 39 36 W ]200~- ....... 0--30---N---'1'-9 .......... O--W .!00i;'-~:i;1199o99,1-i~i~ i' .2,114 1167~99 --:2';.li~1_;;..N'77;:"~."i,54 W 2~6] N 36 ]~ W 1400 0 0 0 0 ~00 '~-13~,~ "2~55 1.67J~ ~"~9-':~:~' '~'Y~".~ W J.O~ N S~ 47 W 1500, 0 0 0 0 100, 14~~ 2 55 1467'~ - ~ '5~ N 1 6~ W J O~ N J5 47 W 1600. 0 ~0 N 82 0 W lO0. 159~.~8 ,_~.62 1567.~8 ~?.58 N 2.12. W 3.34 N S~ ~ W 1700'. ....... 0"'~0-'-N'"'65 ...... O"E .............. 1'00¥ ............ 1-6~9c~8 .......... J,27 1667-~8--- ~.2'3-N ...... 2~'21 ...... W' J.~1 N ~4 28 W ]800. 0 0 0 0 100. 1799.98 D.44 ]767.98 5.4] N 1.82 W D.86 N 28 4 W ]900. 0 0 0 0 100. ~899.98 3~44 ]867.98 3.41 N 1.82 W 3.86 N 28 4 W , ~'~ 2000. 0 0 0 0 100. 1999.98 ~.44 1967.98 3.41 N 1.82 W 3.86 N 28 4 W ('~0 2100. 0 0 0 0 100. 2099.98 ~.44 2067.98 ~.41 N ].82 W 3.86 N 28 4 W 0.00 : ~2200~ ...... 0'45 S'-'12 ........... O'--W ............... XO0-~ ........ 21-99~98 ..................... 2~8] ~ 2~67','98 ....... 2,'77-'N .............. 1~95-~W .... 3.~9 N 55 12 W ~ 0.75 2300. 0 30 N 80 0 E 100. 2299.97 2.13 2267.97 2.10 N 1.31 W 2.48 N 31 56 W 2400. 0 45 S 60 0 W 100. 2399.96 ].40 2367.96 1.38 N 1.05 W 1.74 N 37 12 W 2500. 5 0 N 15 0 W 100. 2499.82 3.].4 2'467.82 3.04 N 5.06 W 5.91 N 58 58 W 2600. 11 30 N 16 0 W 100. 2598.73 17.0~ 2566.7~ 16,86 N 8.89 W 19,06 N 27 48 W ......... 2700~ .... ~3'"-45N~'23 ......... O-'-W ......... :100; .......... 26'96'~30 .......... 37,-76 2664,30 .... 37¥45 N--: 16c].8-~'W 40,80 N 23 22 W 2800. 16 0 N 20 0 W 100. 2792.95 61,82 2760.95 61.~ N 25,59 W 66.46 N 22 39 W 2900. 18 0 N 2~ 0 W 100. 2888.57 89.22 2856.57 88.53 N ~6.~0 W 95.69 N 22 18 W 0.00 0.00 0.50 0.50 0.00 0.25 ¢. JO .... 0,75 0.75 0. O0 0.00 O, 50-.. 0.50 0.00 0.00 0.50 0.96 0.50 0.00 1.05 1.23 5.24 6.50 2.72 2.38 2.18 ~ONOCO ~tILNE PT, WELL NO: D-1 GMS ~ OR TH='-S E 0 PE-'~:'"--A f:~'S K~q- JoB NO: 'nO382G0409 TIME DATE ~1'~5-1'37 ...... O8~MAR-82 TRUE iE~S~ORE~F'~'RI'F~ ...... DRIFT ...... COURSE'-VERTI-CAIS'VERTICAli .... SUBSE~ ....... R'--'~-C--T--A-~-"G'-"U-'-~'"~--R ........ C £. 0 S U R E DOGLEG DEF'TH ANGLE DIRECTION LENGTH DEPTH SECTION TVD C 0 0 R D I N A T E $ DISTANCE DIRECTION SEOERI~Y FEET D H D H FEET FEET FEET FEET FEET FEET D H DG/~OOFT _ . 3000. 20 15 N 21 0 W 100. 2987o05 119.83 295J.05 118.91 N 48·58 W 128.45 N 22 13 W 3100· 2~ 45 N 21 0 W 100· 3075·75 155.05 3043.75 15~o87 N 62.00 W J65.8~ N 21 57 W '-~00; ....... 25'"-"-45-N""'~'~---O-'W ................. ]-00'; .......... ~'1"66,'56 .:94;-99" Z]--3~;56' .............. ~ ....~ ...................... 207,76 N 21 ..,] W 3300. 28 15 N 24 0 W 100. ~255~65 238.42 3223.65 234.61 N 95.08 W 253.14 N 22 4 W 3400. 30 30 N 24 0 W 100~ 3342~79 281.61 3310.79 279.42 N 115.03 W ~02.17 N 22 23 W 3500. 32 ~0 N 22 0 W 100. ~428~05 330.09 ~396.05 327.5] N 17~5.44 W 354.41 N 22 28 W 3800. 3~ 0 N 14 0 W 100~ 3512~15 381.81 3480.15 378.92 N ]52~]5 W 408~32 N 21 5S W ....... S7'00', ........... 34"'30'-N ..... 9 ........ O--W ......... 100~' ~595~'~0 '4~6+44- ~563-,30 ........... 433-~'4~N ......... 1-83-s-22--W .... 463.06 N 20 38 W 3800. 35 30 N 8 0 W 100. 3677~21 49~.32 3645.21 490.07 N ]7].70 W 519.27 N 19 18 W s~l W 3900. 38 15 N 7 0 W 100~ ~757.20 552.95 ~725.20 549~55 N ]79.53 W 578.13 N 18 ~ 4000. 41 30 N 7 0 W 4100· 45 0 N 7 0 W ~200-~ ........4'7-"~0'-N ......... 8 ...... O'"'W 4300, 50 45 N ? 0 W 4400. 51 0 N 8 0 W 100, 3833,93 100,: 3906,76 100,' 3975,?J 100, 4041,34 100~i .4104,44 100· 4187,37 616.71 3801.93 6].3.]8 N 187·34 W 684~'86 -387.-4:,'7&~:'-~:~~ 681 · 17 N 195.69 W 831 ,'&2 4007,34 :.. 827, ~o.: w ',~ 841.16 N 16 59 W 708.7~ N 16 2 W 780.23 N 15 15; W 855.38 N 14 S? W 932o53 N 14 8 W 2,34 2,04' 2.66 2,25 2,26 1.15 2o81 ~,25 3,50 2,60 3,34 0.82 4500· 51 0 N 8 0 W 985.71 4~35.3~<~-.:.~8~1:-,'2~*:'N 238.57 W ~009.83 N 13 40 W 0.00 4600. 51 15 N 8 0 W ~00. 4230.14 1063.00 4198.14 1058·34 N 249.4~ W 1087.33 N 13 16 W 0.25 ! -4700~ ....... 52 ......... O'"'-N .......... 8 ....... O-W ........... 1'00-, ....... 4292-.21 ' ~.~40.83 "4280;21 ......... 1-1"35-~-97'---N ......... 280-;'32--W---1185.41 N 12 54 W 0·75- 4800. 52 30 N 8 0 W 100. 43~3~..44 1219.32 4321.44 ~214.27-N 271.32 W 1244.91_ N 19.. 36 W 0.50 4900· 51 45 N 7 0 W 100· 4414.83 1297.77 4382.83 1292.52 N 281.83 W 1322.85 N 1'2 18 W .......... 5000. 52 0 N 5 0 W 100. 4476 57 1376 14 4444 .7 1370 75 N 289.85 W 1401.06 N 11 56 W 5100. 51 45 N 6 0 W 100· 4538.31 1454.57 4506.31 ~449.05 N 2?7.3? W 1479.25 N 11 36 W 0.83 5200~ .......... 50--'~'45-N .......... ~ ...... O-W ........... ~00'; .......... 4600-,'?0 ..... 1532';28'4568,90 ..... ~-526-;-6~ ...... N ......... 305','54-'W-'-~556.89 N 11 19 W -'1','00"- 5300. 51 0 N & 0 W 100 4664 00 ~609 ~8 4632 00 1603.77 N 313 65 W 1634 15 N 11 4 W 5400, 50 45 N 5 0 W 100, 4727,10 1686,93 4695·10 J680,97 N 321,08 W J7J1·38 N 10 49 W 5500. 51 0 N 6 0 W 100. 47?0.20 1764.28 4758.20 1758.21N 328.52 W 1788.84 N 10 35 W 5800. 51 0 N 6 0 W ~00· 4853.14 1841.71 4821.14 ~835.50 N 338.84 W 1888.11 N 10 24 W 5'700: .......5'1 ......... O-N ........... 6 ........... O"-W 100; ..... 49~6"~'07' 1919+14 4884.07 .... 1912~-Y9 N ....... 344~77 W- J943.61 N 10 13 W 5800. 51 0 N 5 0 W 100, 4979·00 1996o6~ 4947.00 J. 990·14 N 352·~J W ~0~1.07 N 10 2 W 5900+ 51 0 N 5 0 W 100. 5041.9~ 2074.J6 5009,93 2067.56 N ~58.99 W 2098·49 N 9 51W 0.82 0.82 0.00 0~00 0.78 0.00 !i~Oi~OCO COMF'tJ ! ~ILNE PT~ WELL NO; P-1 GMS JOB NO;~ AO~2G0409 T~ME DATE i N O'RTH--SL~ PE'~---AI~*A'S K~ ........................................................ TRLtE ~BA~SUR'E-~DR'I--F-T ....... DR--I-P-T ........... COURSE-VERT-ICAL VERTI"CAt: ............. SUBSEA ....... R' E--C-T-A-N-'-G-~L~-L· A-R C L 0 S U R E · DOGLE~'- 7.;EF'TH ANGLE DIRECTION LENGTH DEF'TH SECTION TV[; C 0 0 R D I N A T E S D~STANCE DIRECTION SEVERITY FEET D M D M FEET FEET FEET FEEl' FEET FEET D M DG/IOOFT ....... 6000. 50 45 N 5 0 W ]00. 5105.0~ 2151.57 507~.0~ 2144.84 N 7~65.75 W 2175.81 N ~ 41 W 0.25 6100. 51 0 N 4 0 W 100. 5~68.17 ~-~°~.0~ 51~6.1~ ~.~.=.=~.18 N ~71.84 W 225Z~.08 N ~ ~0 W 0.82 ....... 6200~ ........ 5'1' ........... O-"N ......... 4 ............ O-W ............ 100'~ 52S4'J ",'07 ....... 2~06~¥"62 .......... 51-9~¥'0'7 .... '2'2~'9-'~7-1--'N 6~00. 51 0 N 5 0 W 100. 52~4.00 2~84.20 5262.00 2~77.18 N 6400. 51 0 N 5 0 W ~00. 5~56.~ 2461.74 5~24.~ 2454~60 N ~0.1~ W 2485.41 N ~ 2 W 0.00 ~8.15 5~8~.~7 25~0.~ N ~2.1~ W 2561.18 N 8 48 W 5.80 6500. 48 45 N 2 0 E 100. 5421.~7 6600. 46 0 N 10 0 E 100. 548~.0~ 2611.10 5457.0~ 2604.10 N Z~84.44 W 26~2.~2 N 8 24 W ..... 6700"'~ ........ 45 ............ O-'N ....... 12 ........ O-E ......... 100~ 555~'.'18 ...... 2680'~8~ ........ 5527'¥'~i'8 ....... 2674'~--1'1 ...... N 6800. 44 45 N 12 0 E 100. 56~0.04 274~.54 55~8 04 274~.12 N ~56.17 W 2766.15 N 7 24 W 6~00. 44 0 N 12 0 E 100. 5701.52 2817.65 566~.~.,,. 2811.5~ N ~41.62 W 28~2.~1~ N 6 56 W 0.75 7000. 4~ 45 N 12 0 E 100. =.~77. 60 2885.15 5741.60 2879.~2 N ~27 ~ W o8~7 85 N 6 2~ W 0 25 7100. 44 0 N 12 0 E 100~ .5845. 2~47.1~ N ~12.8~ W 2~6~.67 N 6 4 W 0.25 00. ~17.~2~ ...... ~OI~;:~ 2~8.47~ W ~02~.4~ N 5 ~ W - 0.50 7700, 4~ 0 N 12 0 E ~08~ ;8,7& ~:~081,77.::N 284,18 W ~0~4,85 N 5 16 W 0,50 7400, 43 0 N 12 0 E ~1 l~48-~Y48:N~' 270,00 W ~1&0,04 N 4 54 W 0,00 7500, 4~ 45 N 12 0 E · 100, 61~6,58 ~220,0~ 61~4~,;58~:~<.:~.~25;5~.6-6....N 255,72 W ~225,81 N 4 ~ W 0,75 7600, 46 0 N 12 0 E JO0, 6207,44 ~288,74 6175,44 ~284.67 N 24J.,06 W ~2~7,50 N 4 12 W 2,25 ~.~0.,, 28 N ~ & W O, 75 7900. 48 0 N 14 0 E 100. 640~.78 ~503.17 6~77.78 ~500.13 N 18~ 8000. 47 45 N 14 0 E J00. 6476.85 3574~77 6444.85 ~572.10 N 172.02 W ~576.24 N 2 45 W (~5 8100. 47 0 N 1~ 0 E 100. 6544.57 ~645.~7 6512~57 ~64~64 N 154.84 W ~646.~3 N 2 26 W ~..05 ~-8200~- ....... 46-~I5""N ......I'~ ....... O"E i00'~ ........ 661'3~'-25 ........... ~716,-46 ..... 658't¥'25 ....... ~7'14~-'47"~N .... 138¥4~' W ' '~717.05 N 2 8 W ......0.75 8~00. 45 ~0 N J~ 0 E 100. 6682.87 ~786.07 6650.87 ~784.41 N 122.~4 W ~786.~9 N I 51 W 0.75 8400. 44 45 N 1~ 0 E 100. 675~.4~ ~854.80 6721.4~ ~85~46 N J06.40 W ~854.~ N I ~5 W 0.75 · '~ 04 N i ].~ W ] 65 8500. 43 15 N 14 0 E 100. 6825.~6 3922.01 6793.~6 ~921.00 N ~0 18 W 8600. 42 45 N 15 0 E 100. 6898.4~ ~87.70 6866.49 ~987.03 N 7~.11 W ~987.70 N I 3 W 0.85 ......... 8700~ ...... 42 ........... O'"~"N ....... I8 ......... O'"E 100, .... 69'72'~7 4051,~ ...... 6940,'~7 .... 4051'.'64 N 5~.'97 W 4052.00 N 0 46 W 2.16 8800. 42 0 N 21 0 E 100. 7046.68 4114.55 7014.68 4114.7] N ~1.6~ W 4114.8~ N 0 26 W 2.01 8~00~ 41 0 N 25 0 E 100. 7121.58 4175.01 7089.58 4175.6~ N 5.75 W 4~75.70 N 0 5 W 2.8~ lSONOCO HI[.NE. F.'T, WELL NO; ][;-1 GMS JOB NO;' AO382G0409 !N'OR'TH'-S IZO P E'~--"A I'~"A S K A : TIME DATE 1.6~35;37 .... 08~MA'R~82 TRUE ME~SURE~ DRIFT DRIFT COURSE VERTiCAl~ VERTICAl. SUBSEA R E C T A N G U l. A R C L 0 'S-"U"R-E- -DOGEEG- DEPTH ANGLE DIRECTION LENGTH DEF'TH SECTION TVD C 0 0 R D I N A T E S DISTANCE DIRECTION S~VERI~'Y FEET D M D M FEET FEET FEET FEET FEET 9000° 41 0 N 27 0 E 100. 7197o05 4233.40 7165,05 4234,66 N 9100, 41 30 N 29 0 E 100, 7272,23 4291,00 7240°23 4292,87 N 9300, 40 0 N 32 0 E JO0o 7422,88 4404.48 7390,88 4407.62 N ?400° ~8 30 N 32 0 E 100. 7500,32 4457.47 7468,32 4461,27 N 9500, 37 0 N 33 0 E 100, 7579,39 4508,45 7547°39 4512,90 N FEET D M DG/IOOFT 2~.0~ E 4234,72 N 0 19 E ~,3~ 53.~6 E 4293,21 N 0 43 E 1o41 85.58 E 4351~94 N ....I ..... 8--'E ....... 0'.-6'6"' J. 18.21 E 4409,20 N 1 32 E 3,0J ~51.74 E 446~,85 N I 57 E ~,50 184.63 E 4516,68 N 2 21 E 1,62 ! 9600, 36 0 N 34 0 E 100. 7659,77 4557,40 7627°77 4562,50 N 217.46 E 4567,68 N 2 44 E 1~6 i~-'~50'~ ........35'"'~30'-N'~'3'4 O"E ......... 50'~ 77'00Y-35 .......... 458I'~-30 ......... 7~6'8¥35 ............ 4586'-~72 N 233.79'E 4592~'-68~'N ..... 2~"55--'~E ........... 1. ?0 iF'ROJECTED TO TD 9720, 35 30 N 34 0 E 70° ~7757o34~-~.4614,55 7725,34 4620.42 N FINAL CLOSURE - DIRECTION°: i.:- N 3 I~EGS.i:~ i~.~.M~N~:40 SECS E 256.53 E 4627.54 N 3 11 E 0o00 CONOCO ' ........................ -~'IIZN£ F'~T, WEEIZ NO'. ....................... D-.] NORTH SLOPE, AI.ASKA GMS, 0-9650 MXI~ SIURVEYORI M LUND DATE RUN: 03-MAR-82 90 DEG. A/U NO: 1524 ............ PORESIGHTI N59W ........................................................................................................................................................................................ TRUE SUBSEA flE'~-$URE[i ....................... VERTICAl: ............. PID'z'TVD ...................... VER'I VERTICi~I, ....... R"E"C'T"A' N G"IJ-L A R -'C'L O' S U R E DEF'TH DE'i::'TH DIFF CORR I';EF'TH C 0 0 R ]FI I N A T E S DJ'STANCE DIRECT]'ON. FEET FEET FEET FEET FEET FEET FEET D Fi 32,00 32.00 0,0 0,0 0,00 0,00 . 0.00 0,00 0 0 132,00 132.00 0,0 0.0 :100,00 0.07 N 0.12 E 0,14 N 59 0 E -'59 0 E ........................ 2:32';"00 .... ,:.3~.. O0 0.0 -0-;-0 ............................. 20'O-TO0 ............. 0':~ 30"-' N 0,49' E ............. 0'~'58 ...... N 3:32,00 :332,00 0,0 0,0 :300,00 0,45 N 0.75 E 0,87 N 59 0 E 432.00 432.00 0.0 0.0 400.00 0.51 N 0.71 E 0.88 N ..... 54 27 E. 53;2.00 532.00 0.0 0.0 500.00 0.73 N 0.46 E 0.87 N 3;2 20 E 0.0 0.0 600.00 0.94 N 0.05 W 0.94 N 2 49 ~ 632.01 632.00 ........................ 7:3'2'~01 732~ O0 ...... 0', 0 ................................... 0-;0 .................. 70'0','00 ..... I,'05' N O-f51"'--W ............................... 1-';'1-7 ......... N-'26' 2 L 83;2.01 832.00 0.0 O.O 800.00 1.4:3 N 1.04 W 1.77 N :36 I W 9:32,01 932.00 0.0 0,0 900.00 :1.,69 N :1..40 W 2.20 N 39:36 W 10:32.01 103.°,00 O.:O .:~0,o0 1000.00 1.69 N .1..40 W 2,20 N :39:36 W ' ............. ~' 1.8:3 N 1.45 W 2.33 N 38 23 W ' ~" ;~!:' ........ ;; 0 :: ::0,24 N I 59 W ...... 2,'75' N 35 -')2 W 1-2:32'* 01 12:32 · O0 ':', :~;.0,,~'~.:.~;: ~,;:,~:l.;~ ~Oi~, O.' ' ~' ' ~" ' ") ~:' 3 03 N :33 47 14 1532.01 J5~2.00 0+0 0.0 ]500:;:O0':F':":: .:2.54-"N 1+82 W ~.1~ N 35 4] W ~'732702 17~2,00 ...... 0-,'0 ................................ 0-~'0 ................... ~700~00 ~,28' N 2~O~'W ........ ~.8~" N"~2-2~ W' 1832.02 18~2.00 0,0 0,0 J800,O0 ~.41 N 1.82 W ~.86 N 28 4 W 1~2,02 1~32,00 0 0 0,0 1~00,00 3,41 N 1,82 W ~,86 N 28 4 W 20~2,02 2032.00 0.0 0,0 2000.00 3.41 N 1.82 W 3.8& N 28 4 ~"~ 21~2.02 2132.00 0.0 0.0 2100,00 ~.20 N 1.86 W S.71 N SO ~ W ........... 22~2-~03 22~2,00 0"~"0- 0:'0 ............. 2200',-00 .......... 2+56'N 1.75"W ...................... ~IO'-'N ~4 22'W 24~2,08 24~2.00 0,1 O.J 2400.00 1.~2 N 2.~4 W S,02 N 50 3~ W 2532.54 2532.00 0.5 0.5 2500.00 7.54 N 6.31 14 9.83 N 39 55 W 2634.10 2632.00 2.1 1.6 2600.00 23.88 N 11.38 14 26.46 N 25 28 W ........... 2736'~'9'4 ................ 2732,00 4~9 ...................... 2~8 .................... 2700',00 46.27 N 19.66' W 50,28 N 23 1 W 2840.84 2832,00 8.8 3.9 2800.00 72.44 N 29.97 W 78.39 N 22 28 W 2~45.97 2932.00 14.0 5.1 2~00.00 102.49 N 41.95 W 110.75 N 22 15 W CONOCO iMILNE PT, WELL NO: D-1 GMS iNORTH-SEOPE¥'~-~I:'ASKA !_ TRUE SUBSEA ........ MEASURE'~ .......... VERTICAL ................MD'~TVD---------VERT ....................VERTICAl_ DEPTH DEPTH DIFF CORR DEPTH FEET FEET FEET FEET FEET 3052.81 3032.00 20.8 6,8 3000.00 3161.94 3132,00 29,9 9,1 3100,00 ............... S275v45 ............. 3252~00 ................. 4"1-~-5 .................... ]~-~'5 ............... $200.00' 3387,62 3332.00 55.6 14,2 3300.00 ~504,70 54~2,00 72.7 17,1 J400.00 3623,87 3532,00 91.9 19,2 3500,00 3744,80 3632.00 112.8 20,9 ~600,00 ............... ~868'~49 ......... 37~2v00 .................. 1--36~-5 ...................... 2'3'v7 ............. ~700~'00 3997,48 3832.00 ]65.5 29.0 3800.00 4136,50 J9~2.00 204.5 39,0 3900.00 4285,73 4032.00 4443,79 ............... 4603"~-'00 ....... 4232~'00 4764,99 4332.00 4927,81 44~2,00 5089.78 4532,00 557,8 62.0 4500;00 5249.29 4632.00 617.3 59.5 4600.00 5407'~76 .................. 4732"~-00 ...... 675-~'8 ..................... 58v5 ......... 4'700.00 5566,42 4832,00 7~4,4 58,7 4800,00 5725,32 4932,00 79~,~ 58.9 4900.00 L:UI"II"'UIRI IU~ r-HL~ ~,, ,JOB NO:. AO38~2G0409 TIME DATE I6',+ '39'; "15 ....08-M A R- 82 R E C T A N G"U' L--A'R ................... C'-I,--O'S-~LI R E C 0 0 R I) I N A T E $ DJ'STANCE DIRECTION. FEET FEET D M 137.37 N 55,66 W 148.°°-~ N~.°° 4 W 178.00 N 7],50 W 191,82 N 21 53 W 223.51 .... N .......... 90','37'-W ................ 24-1-,09'~N-"22 I W 273.87 N 112.56. W 296,10 N oo~,. 21 W 32~.72 N 136.23 W 35&.~4 N 22 2& W 391,91 458,75 530.81 611.57 707.31 816.89 N 214,70 W 937,99 N 232.49 W 1060,67. N .249,74 W 1186,85 N 2~7.i, 47 W J314.28 N 283,9] W 1441.05 1564.64 1686,98- 1809.54 1932.37 N 154.79 W 421,37 N 2] 33 W N 167.02 W 488.21 N 20 0 ~ -N ...... 1'7~06-W -'55'9-~56 .... N-i-8-27 ~ N 187,14 W 639,57 N 17 I W N ]99,13 W 734,81 N 15 43 W 844,&3 N 14 44 W 966,37 N 13 55 W d089..67-- N--13-15W 1.216,62 N 12 42 W 1344,59 N 12 11 W .. N 296,62 W 147].,26 N 11 38 W N 309.54 W 1594,97 N 11 11W N 321-,66-W ............ ~7i7~37 N---lO--48--W-~ N 333,91W 1840,09 N 10 27 W N 346.65 W ].963,22 N 10 10 W ~884.~ ,~03,.00 8~.~ ~8.9 ~000.00 ~0 ~. ~7.9, o o '~ '- ' · · · ~ 34 N 3 ~ W ~086.~7 N 9 .,3 :: 6042.74 5132,00 910,7 58,5 5100.00 2177.90 N 368.35 W 2208,83 N 9 36 W ............... 6201":'48 ........... 52~2~'00 ................. 969~'5 ....................... 58v7 .............5200'+00 ..... 2300,86 N 377,'35"W ................. 233t,60 ...... N ....9'19"W 6360,38 5332.00 1028.4 58,9 S. 300.O0 2423.93 N 387o44 W 2454.Y0 N 9 5 W 6515,69 5432,00 ]083,7 55.3 5400.00 2542,46 N 390,92 W 2572,34 N 8 44 W 6661,23 5532,00 1129o~? 45,5 5500,00 2646,96 N 376,11W 2673, 55 N 8 5 W 6802,74 5632,00 1170,7 41,5 5600,00 ~74~,.00 N 355,77 W 2767,96 N 7 23 W 694~.~9 ,)73~,00 ..... 1210'i-3 ......................... 39'v5 ................. 5700,00 2840,19'N 335.53'-'W ........ 2859.95 N '6 44- W 7081.01 5832,00 1249.0 38.7' 5800.00 2934.24 N 315,5;4 W 295].16 N 6 8 W 7219 32 5932 O0 1287 3 38.3 5900 O0 3027.70 N ~ = · · · · ,.9,~.68 W 3042.10 N 5 35 W ............ !~ONOCO iglLNE PT, WELL NO; D-1 GMS JOB NO:~ A0382G0409 i;qORTH "SI, OPE', AI:ASKA' TIME DATE 16~39'~15 ........ 08=M-AR~82 TRUE MEASUREI ........... VERTIC~IZ DEF'TH DEPTH DIFF FEET FEET FEET FEET FEET SLIBSEA gERT ...................... VER'TI'CAI~ R E C"-T"~A N~'G'U~L' A R ........... C ~--0 S II R E CORR DEPTH C 0 0 R D I N A T E S DISTANCE DIRECTION. FEET FEET D M 7356.39 6032.00 1324.4 37.] 6000.00 7493.69 6132.00 1361.7 37.3 6100.00 7635;67 .................6232700 ............ 1-4'0~T7 ~'2:"0 .............. 6200;00' 7783.08 6332.00 145].1 47,4 6700.00 7933.13 6432.00 150~.,1 50,1 6400.00 8081.44 6532.00 1549.4 48.3 6500.00 8226,93 6632.00 ]594.9 45.5 6600.00 8369;63 673'2'~00 ......... ]:'6-3-7¥'6 42¥7: .............. 6700-;00 8509.08 6832.00 1677.] 39.5 6800.00 8645.36 6932.00 1713.4 36.3 6900.00 7032 · O0 17 ~?~9 7000 · O0 '72~2,00 1 7332, O0 ~8 33,3: ~:::: .:7::~00<~ O0 7532 · O0 1908 · J 28 . 3 7500 ' 7632.00 1~33.5 25.4 7600,00 7732 ~'00 .................. I ~56-i9 ......... 23'V4 .......... 7700, O0 8780.24 8913.81 9046.49 9179.80 9311.78 9440.07 9565.45 9688i88 3119.39 N 276.19 W 3131.59 N 5 4 W ... oo 66 N 4 34 W 3211.42 N ~%6.63 W 3309~93"N 2~5,46 W 3318-~'29--N~ '4 4' W 3415.39 N 210.97 W 3421.90 N 3 32 W 3523.97 N 184.01W 3528.78 N 2 59 W 3630.36 N 158.03 W 3633.80 N 2 30 W 3733.30 N 134.]4 W 3735.7]. N 2 3 3832'~49-N ....... 1]I-'~24-W .................. ~834-~-'~0 .... N ~27o00 N 88,63 W 3~28,00 N 1 18 W 4016,34 N ~4,43 W 4016,85 N 0 55 W 4102.25 N 36.05 W 4102.41 N 0 30 W 4183.84 N 1.78 W 4183.84 N 0 1 W 426 o 7 1.7~.,N 3 ..40 E -426'Ii'88' N 0'30 E 4339.34: N ':,:::79:,19 E 4340.06 N 1 E 4413'94 N 122.16 E 4415.63 N 1 35 F.:: 4481,96: N 164.92 E 4484.99 N 2 6 E 4545.37 N 206.12-' E 4550.04 N 2 36 E 4605,44 N '246~42 E .... 4612.03' N . . ! ' Suggested form to -be inserted in each "Active" well folder tc check for tin~21y cc~.pliance wi~'~ our ro:julations. Otmrator, Well Name and Num~r ~q~.x)rts'.and Materials to be received Rc~]uired Date Received · Cc~p letio RePOrt Yes . . Wel 1- Hist0~ Yes ~ - ~) -- ~ ~ .,. , " · .. . __., ,. Core ~scription ',,.. ....... :: ........... ~. ...... ,,.. // ' ~ Inclination Su=ey .4/: -- -' --' '.. . Pr~,u~on-T~ .~ Rear ts ~s ~ / ,~ Yes Conoco Inc. 2525 C Street Suite 100 Anchorage, AK 99503 April 27, 1982 Ms. Elaine Johnson Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Ms. Johnson: SUBJECT: BOTTOMHOLE LOCATION CORRECTIONS~..T~ COMPLETION REPORTS FILED ON MILNE POINT NOS. C-1A~D-i_~ As you noted in our telephone conversation on March 22, 1982, location of the top of the producing zone and the bottomhole location for Milne Point C-1 should be as follows: Top of Producing Zone Location (@6959'MD) - 951' FSL, 2167' FEL Sec. 10, T13N, R10E, UM Bottomhole Location (@10,442' MD) - 913' FSL, 2168' FEL Sec. 10, T13N, R10E, UM As we also discussed, the bottomhole location for Milne Point D-1 should be as follows: 1564' FNL, 914' FEL Sec. 12, T13N, R10E, UM Thank you for bringing these errors to my attention and I apologize for any inconvenience. If you have any additional questions, please call me at 279-0611. Very truly yours, Supervising Engineer kr cc: A. E. Hastings, Production, Anchorage G. A. Merriman, Production, Anchorage Working Interest Owners Milne Point C-l, D-1 Well Files RECEIYED. Alaska 0il & G~ Com.';. Co~umJs$ion April 20, 1982 Cor~o~o 2525 C Street Suite 100 Anchorage, Alaska 99503 Mr. C. V. Chatterton, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE- Milne Point D-1 -API No. 50-029-20664 Well Completion Report Dear Mr. Chatterton' EnClosed are two copies of the Well Completion Report for Milne Point D-1. Also enclosed are two copies of a transmittal letter listing data and mat- erials being submitted to your office as per AOGCC regulation 20 ACC 25.070 and as outlined in the AOGCC Permit to Drill approval letter of September 25, ~1981. Upon receipt of these data and materials, please sign and return to this office one Copy of the transmittal letter. If you have any questions about the information you have received, please contact either Jim Fox or myself at 279-0611. Yours very truly, G. A. Merriman Supervising Production Engineer kp cc: Milne Point C-1 file, w/Attachments RECEIVED A/aska Oit & Gas Cons. Cornntls~iort ~chorage C~a STATE OF ALASKA NFIDENTIAL ALASKA ' AND GAS CONSERVATION COI~ .AISSlON WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL [] GAS L~ SUSPENDED ~-X ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number Conoco Inc. 81-144 3. Address 8. APl Number 2525 C Street, Suite 100, Anchorage, AK 99503 so-029-20664 4. Location of well at surface 9. Unit or Lease Name 964' FNL, 1233' FEL, Sec. 13, T13N, R10E, UM Milne Point Unit At Top Producing Interval 10. Well Number 3367' FSL, 1158' FEL, Sec. 12, T13N, R10E, UM Milne Point No. D-1 At Total Depth 11. Field and Pool 3636' FSL, 914' FEL, Sec. 12, TI3N, RI0E, UM Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Kuparuk River P0ol GL= 9' KB=32' ADL 47437 ,, 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 116. No. of Completions 1/19/82 2/26/82 3/20/82 N/A feetMSLI One 17. Total Depth (MD+TVD) 18.Plug Back Depth (MD+FVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of PermafroSt 9913 (7917 TVD) 9320 (7362 TVD YESK]( NO[:] 2084 feetMD 1800'+ 22. Type Electric or Other Logs Run SP/GR/SFL/DIL/BHCS; NGT/FDC/CNL; HUT; RFT; SWC's 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 94#/ft H-40 0 113' 26" Cement to surface 0' 13 3/8" 72#/ft L-80 0 2300' 17~" 4980 sks perma-frost 0' 9 5/8" 47#/ft L-80 0 .8455' 12¼" 500 sks Class G. 13E 0' bbl Arctic pack, - continuation of casin9 finer dat~ on page 2. 24. Perforations open to Production (MD+TVD of Top and Bottom .and 25. TUBING RECORD interval, size and number) ' SIZE DEPTH SET (MD) PACKER sET (MD) ' 9171 (7325 TVD) to 9194 (7343 TVD) 3""~ (9.3#) 9110' 9110' 90° phasing · 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. See, page 2 - Test. l~erforations for · DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED . additional perf. data. See page ,,,,2.. Cement Squeezes , . .. . 27. PRODUCTION TEST" Date First Production. · at]~ . See page 3 Test D Method of Operation (Fl. qwing, gas lift, etC..! . : 'Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF wATER-BBL CHOKE SIZE IGAS'OILRATIO . TEST PERIOD ~ .... I Flow Tubing Casing Pressure CALCULATED.. '1~ OIL-BBL GAS-MCF WATER-BBL Gl L GRAVITY-APl (corr) Press. 24-HOUR RATE.-7 28. CDR E DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. " .. RECEIVED .. None taken .. APR t i982 A~as~(a 0il & Gas Cons. Commission Anchorage Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gr, avity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. W. Sak Sands 5145 (4566 TVD) (See page 3 for details) T/Middle Kup 9166 (7322 TVD) DST Cf 2, Test #3 T/Lower Kup 9402 (7502 TVD) DST # 1 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ,- . ~~~~ - Title SUpV. Prod. Eng. Date April 1,9. 1982 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23' Attached supplemental records for this we!! should show the details of any multiple stage cement- lng and the location of the cementing tool. Item 27' Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Milne Point No. D-1 Well Completion Report and Log (continued) CONFIDENTIAL 23. Casing and Liner Data (continued) Casing Size wt/ft Grade Top(MD) Btm(MD) 9 5/8" 47#/ft L-80 0 8455' Hole Cementing Amount Si ze Record Pul 1 ed 12-~'' 150 sks O' Permafrost C. 7" 29#/ft L-80 8098' 9900' u2~-~" 650 sx, Class O' G w/l% CFR2, 0.3% Halad 9, 3% Kc1 (BWOW) 24. Test Perforations ~' Test # 1 - 9404' to 9420' (16') 4 spf at 90° phasing 9434' to 9474' (40')' Test # 2 9171' to 9194' (23'), 12 Spf ~t 90° phasing Test # 3 26. Cement Squeezes ....... - .... Squeeze #1 - Abandon perforations from 9404' to 9420' and 9434' to 9474'. Squeeze 180 sx Class "G" cement with 1% CFR2 and 0.1% HR-7 below retainer set at 938~3'. Spot 20 sx Class "G" on top of retainer. RECeiVED APR 2 1 1982 0{I & Gas Cons. Commissim~ Anchora~ Milne Point No. D-1 Well Completion Report and~J- g (continued) 27. Test Data Date of Test Method of Operation Hours Tested Test Number 3/5/82 Cased Hole DST 1 Oh, 30m Flowing Tubing Pressure, psig 0-50 Casing Pressure, psig Produced Oil, bbl Produced Gas, MCF Produced Water, bbl Choke Size GOR (MCF/BBL) Flowing BHP, psig Final Build-up pressure Maximum Rates: BOPD BWPD Gas, MCF/D Oil Gravity (°API) 0 0 NA 188 Ful 1 open (0.87") N/A 27]4-3365 37]9 0 1090 NA NA CONFiDEN AL 3/7/82 - 3/8/82 Cased Hole DST 23h~35m 12-160 0 175 NA 0 - Full open (0.87") NA 1741-2464 3552 586 0 NA 22° 3/16/82 - 3/17/82 F1 ow Test 23h~ 20m 0-16 0 92 23.2 0 Ful 1 open O. 252 2880-2392 3521 481 0 86 20° APR 2 1 I982 AJ~s~(a Oil & Gas Co~s. Commissim~ l-TELL HISTORY HILNE POINT NO. D-1 - CONOCO ET AL. API NO. 50-029-20664 Date Operations 1-4-82 to 1-18-82 1-18-82 1-19-82 to 1-21-82 1-22-82 to 1-24-82 1-25-82 to 1-27-82 1-28-82 to 1-29-82 1-30-82 to 2-4-82 2-5-82 to 2-7-82 2-8-82 to 2-10-82 2-11-82 to 2-12-82 2-13-82 to 2-16-82 2-17-82 to 2-18-82 Move in and rig up drilling rig and support facilities. Set conductor pipe (20", 94#/ft, H-40) at ll3'KB. Spud well at 2330 hours. Drill 17½" hole from conductor shoe (113') to 2300'. Run the following logs from 2314' to conductor shoe: SP/DIL/SFL; OR/BHCS. Run 13-3/8" 72#/ft L-80 Btrs casing to 2300' , -~ , · Sting drill pipe into casing collar at 2217', circulate, and pum~ 4980 sks. of Perma Frost cement (14.5 ppg.) back to surface. Full returns were seen during entire job. Drill and Dyna-drill 12¼" hole flrom 2300' to 4142' ?U~ding hole angle. Fish for and recover drill pipe twisted off at 973'. Drill 12¼" hole from 4142' to 6630'. Hole angle is N.7.3°W. at 49.9°. Drill and Dyna-drilI 12¼" hole from 6630' to 7455' dropping hole angle to 42° at N 7.8°E. Fish for and recover bottom hole assembly (pin on string stabilizer failed) at 7215'. Drill 12¼" hole from 7455' to 8480'. Hole angle building to 45.5°, N.11.7°E. Attempt to run SP/GR/DIL/BHCS log and can not get to bottom. Go back in hole with drilling assembly and wash and ream to bottom. Run the following logs from 8480' to 2300': GR/SP/DIL/SFL/BHC-Sonic No~ / FDC / CN~ HDT SWC - could not get core gun to bottom Run in hole with drilling assembly to wash and ream to bottom. Fish and recover bottom hole assembly. Run core gun in hole on wireline and attemgtm~~ll cores. 35 cores were recovered· KCt[~/V[~ U APR z t982 Ga~ Cons. Commissio~'t Anchorage Well History Milne Point D-1 Page 2 2-19-82 to 2-20-82 2-21-82 to 2-22-82 2-23-82 to 2-26-82 2-27-82 to 2-28-82 3-1-82 3-2-82 3-3-82 3-4-82 3-5-82 to 3-6-82 3-7-82 to 3-8-82 CONFIDENTIAL Run 9-5/8", 47#/ft., L-80, Butrs casing and set shoe at 8455'. Pump 500 sks. Class "G" (15.7 ppg.) around the shoe and displace casing with mud. Open D.V. tool, pump 110 bbl. water, 135 bbl. of Arctic Pack, 150 sks. of Perma Frost "C" cement (15.6 ppg.), displace with mud, and close D.V. tool. Drill out and test casing. Run a wireline gyro survey, drilling 8%" hole from 8490' to 8780', angle dropping to 41-3/4°, N 15°E. Drill and survey from 8780' to 9913', angle dropping to 33° N 38°E Run the following logs from 9905' to 8455': GR/SP/DIL/SFL/BHC-S onic NGT / CNL/FDC ~ NRD SWC's--41 a~tempted, 38 recovered. Test BOP's; RU and run 7", 29#/ft, L-80, butt. liner. Finish running 7" liner; liner shoe at 9900', TOL at 809~8'. Cement liner with 650 sks. Class "G" cement -~/1% CFR2, 0.3% Halad 9, and 3% KCl (BWOW). Displace cmt. and bump plug w/3000 psi. WOC. Tag cmt. at 7000'. Drill cement from 7000' to 8098' (TOL); test TOL to 2950 psi; drill cement to 9740'. Test liner to 2600 psi. Run GR/CBL/VDL/CCL from 9740' to 7940' w/1000 psi. Re-run log from 9740' to 9268' w/2000 psi; lubricator problems cause loss of pressure; log from 9268' to 8100' w/ 0 psi. Ran gyro-survey 9720' to 8455'. Rig up Schlumberger and perforate from 9404' to 9420' and 9434' to 9474' w/4 SPF. Pick up and RIH w/Howco APR testing assembly. Set packer at 9370' and DST perforated intervals. Set cement retainer at 9383'. Squeeze 180 sks. Class "G" cement w/l% CFR2 and 0.1% HR-7 into perfs and set 20 sks. of Class "G" on top of retainer. Test BOP's. Rig up Schlumberger, perforate from 9171' to 9194' w/4" guns at 12 SPF w/90° phasing. TIH w/ DST assembly and start DST #2. Open tool at 1610 on 3-7 and closed tool at 0315 on 3-8 for 11 hour buildup. Recovered 65 of 83 bbls. of diesel cushion. Re-open tool at 0835 on 3-8 and closed at 1235 on 3-8· Final flowing pressure 45 psig. Produced approx. 60 bbls. oil. ~ E ~ ~ ~ V ii~ ~ APR 2 1 82 Gao Cons. Commissio~ ~,nchorag~ Well History Milne Point D-1 Page 3 CONFIDENTIAL 3-9-82 to 3-10-82 3-11-82 3-12-82 3-13-82 to 3-15-82 3-16-82 3-17-82 3-18-82 3-19-82 to 3-20-82 Set Otis "1~" packer @ 9110'. Set PX-N plug in mandrel. Test casing, liner, packer, and plug to 3000 psi. TIH and reverse circulate fresh water displacing mud. Observe well and POOH. Run 287 joints of 3%", 9.3#, L-80 DSS HT tubing. Pump 122 bbls. diesel treated w/Arco HIB C-120. Pump 400 bbls., 9.6 ppg. NaCl water treated w/20 gal. biocide, 400# caustic, and 200# NOXYGEN. Pump 67 bbls. diesel treated w/Arco HIB C-120. Land tubing. Test head to 500 psi and annulus to 10,000 psi. Set back pressure valve, N/D BOP's and N/U tree. Test tree to 5000 psi. Rig up Otis slickline; bailing on top of PX-N plug. Retrieve PX-N plug. Fishing unsuccessfully for.X-N locking mandrel at 9145'. Rig down Otis. Rig up Dresser Atlas. Run in hole w/perf, gun, unable to get below 9132'. Pull out of hole, perf. gun lost in hole. Trip in hole ?~.~.j~et cutter, unable to get below 9132'. Pull out of hole. Run in hole w/perf, gun, perforate tubing from 9134' to 9136' w/4 SPF using 2-1/8" slim cone tubing punching charges w/5/8" O.D. Pull out and rig down Dresser. DST #3. Middle Kuparuk Formation. Open well at 1840' on 3-16-82 and shut in at 0236 on 3-17 for pressure build up. Open well at 0306 and flow to test separation. Obtain samples. Shut in at 1800. Shut well for pressure build up. Rig down Otis. Install back pressure valve in tubing hanger. Release Parker Rig #128 to rig down. Rig down Parker #128. RECEIVED' APR 0i~ & Gas Cons. Commissio~'e ~noco Inc. "] Under Separate Cover [~Enclosed · ;cord of Shipment of ' ' L;onfidential Information Date From GONOco INc. Signed By 'ransmittal Approved By G-A- ~P-¢1~~ Date ~structions: Please acknowledge receipt promptly by sigmng and returning carbon copy. eceived By Date emarks ransmitta Copy Only To 3-98 PCX1, 7-79 Alaska 0il & Gas Cons. Commission ~l~[~tl~-~N~lCtlCK OKLA. CITY r'tli~ll~/~,~ilNTED IN U.S.A. STATE OF ALASKA ALASKA-~' . AND GAS CONSERVATION C~"~ ~ISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS/ . 1, Drilling well [-~ Workover operation [] 2. Name of operator Conoco 7. Permit No. 81-144 4. Location of Well atsurface 964' FNL, 1233' FEL, Sec. 13, T13N, RIOE, UM Inc. 3. Address 8. APl Number 2525 C Street, Suite 100 Anchorage, AK 99503 5o- 029-20664 9. Unit or Lease Name Milne Point Unit 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. 45' KB ADL 47437 10. Well No. D-1 11. Field i~,nd Pool ~uparuk River Field Kuparuk River Pool For the Month of. March ,19 82 12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks TD - 9913' PBTD - 9320' Results of DST test to follow on final report. 13. Casing or liar run and quanti'ties of cement, results of pressu.r9 tests Squeezed 180 sks Class G cement below on top of tool· EZSV tool @ 9383' and spot 20 sks, cmt. 14. Coring resume and brief description None 15. Logs run and depth where run Logs: GR/CBL/VDL/CCL From 9740' 9740' 9268' To 7940' 9268' 8100' ,16. DST data ~erfo/,ating data,_sh_o_ws of H2S, miscellaneous data ' 'verts: SPF From To 4 9404' 9420' 4 9434' 9474' 12 9171 ' 9194' 4 9134' 9136' - Perforated tubing hung below the packer 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. SIGNED ~ ,~~' TITLE Supervising Prod. Eng DATE R~or ~ .... r~e NOTE-- t on is form is quired for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form10-404 AFE 1742 A0 & GCC (2) WI0 Submit in duplicate Rev. 7-1-80 ALASKA ~' STATE OF ALASKA ' '"~'~ ~ AND GAS CONSERVATION CO( IlSSION MONTHLY REPORTOF DRILLING AND WORKOVER OPERATIONS . Drilling well I-X] Workover operation [] 2. Name of operator 7. Permit No. Conoco Inc. 81-144 3. Address 8. APl Number 2525 C Street Suite 100, Anchorage, Alaska 99503 50-029-20664 9. Un.it 9r~ Lease Name .~/ne Point Unit 4. Location of Well atsurfaoe 964' FNL, 1233' FEL, Sec. 5. Elevation in feet (indicate KB, DF, etc.) 45' KB 13, T13N, RIOE, U.M. 6. Lease Designation and Serial No. ADL 47437 For the Month of. Febraury ,19 82 10. Well No. D-1 11. Field and Pool Kuparuk River Field Kuparuk River Pool '12. Depth at end of month, footage drilled, fishing lobs, directional drilling problems, spud date, remarks Depth on 2/28 - 9913'. Pin on stabilizer failed - lost 40,000# of string weight. Made full recovery of fish. Second fish job - lost stabilizer and two drill collars - made full recovery. Completion Gyro run' from 9650' to surface. Projected T. D. 9 9720' MD, 7757' TVD, 4620' N, 257' E. Closure is 4627.54' @ N 3° 10' 40" E. Seven inch liner was run on 2/28 and cemented on 3/1. 13. Casing or liner run and quantities of cement, results of pressur9 tests Casing' Size Wt. Grade From To 9 5/8" 47# L-80 O' 8455' Liner 7" 29# L-80 8098' 9900' Cement 500 sks. class "G" Arctic Pak & 150 sks. Permafrost "C". 650 sks. class "G" w/ 1% CFR .3% Hal ad 9 & 3% KCL 14. Coring resume and brief description Ran core gun. Fi red 45 shots - recovered 35, lost 6, 3 misfires & I empty. 15. Logs run and depth where run Logs- From To Logs- DIL-GR-Sonic 8480' 2300' DIL-BHC NGT-FDC-CNL NGT-FDC-CNL From To 9905' 8455' 6. DST data, perforating data, shows of H2S, miscellaneous data MAR 1 S/-9,92 41aska 0il &~.a_a. Cons. 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ""'ullOl'sge "'"tg'O.iSSJoi. NOTE--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Submit in duplicate Rev. 7-1-80 AFE 1742 AO&GCC (2) ' STATE OF ALASKA [ ALASKA: ,_ ,L AND GAS GONSERVATION G[~ MMISSION SUNDRY NOTICES AND REPORTS ON WELLS 2. Name of Operator Conoco Inc. 3. Address 2525 C Street, Suite lO0, Anchorage, AK 4. Location of Well 964' FNL, 1233' 5. Elevation in feet (indicate KB, DF, etc.) KB-32' 99503 FEL, SEC 13, T13N, RIOE, UM 6. Lease Designation and Serial No. ADL 47437 12. 7. Permit No. 81 - 144 8. APl Number 50-029-20664' 9. Unit or Lease Name Milne Point Unit 10. Well Number Milne Point D-1 11. Field and Pool Kuparuk River Field Kuparuk River Pool Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate ~-1 Alter Casing [] ~ Perforations [-] Altering Casing Stimulate I'"l Abandon [] Stimulation [] ' Abandonment Repair Well [] Change Plans [] Repairs Made [] Other Pull Tubing [] Other [] Pulling Tubing [], (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state ali pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). This notice is being submitted for the approval of perforating the Kuparuk River form- ation as described in the attached procedure. This wor, k will commence on March 4, 1982. Alaska 0il & Gas Cons. Anchorage 14. I hereby ce,~y that the foregoing is true and correct to the best of my knowledge. The space~;Iow for,-~ommission use Date March 2, 1982 Conditions of Approval, if any: Approved by Approved Copy R~tumed ...... Ely 'Order of COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate STATE OF ALASKA ' ALASKA . AND GAS CONSERVATION C MISSION MONTHLY REPORT~F DRILLING AND WOI~i~OVER OPERA 1. Drilling well IX] -.~ ,~ .~ Workover operation [] ...... ~ '~ '" '-~ ~';~ ~ ': ,"'~' '" 7. Permit No. 2. Name of operator Conoco Inc. 81~144 3. Address 8. APl ~umber 2525 C Street Suite 100, ~nchora~e, ~laska 99503 so~29-20664 4. Location of Well at surface 964' FNL, 1233' FEL, Sec. 13, T13N, RIOE, UM 9. Unit or Lease Name Milne Point Unit 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 45' KBI ADL 47437 10. Well No. D-1 1 1. Field and Pool Kuparuk River Field Kuparuk River Pool For the Month of. January ,19 82 '12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Spud date: 1/18/82 Depth on 1/31 - 4890'. Twisted off drill pipe & lost 118,000# of String weight. Made full recovery of fish. Cont'inue drilling. 13. Casing or liner run and quantities of cement, results of pressur9 tests Casing. Size Wt, Grade From To Cement 20" 94# H40 O' 80' To surface 13 3/8" 72# L80 O' 2304' 4980 sks.-Perma Frost 14. Coring resume and brief descriptmon NONE 15. Logs run and depth where run Logs SP-DI L-SFL,GR-BHCS From To 2314' O' .1 6. DST data, perforating data, shows of H2S, miscellaneous data NONE FEB 1 1982 0ii & Gas Cons. Commiss~or~ A~ch0rag~ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ~ ~~ Drilling Supervisor SIGNEDx~l~*~ /- '""-- V TITLE DATE NOTE--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 submit in duplicate Rev. 7-1-SO AFE 1742 AO&GCC (2) MILNE POINT D NO. 1 ~' KUPARUK RIVER FORMATION TEST PROCEDURE CO~~D~ 1) After running and cementing the 7" .29#, L-80, BTRS liner (toa TD of 9900 ), WOC, then RIH with an ~ bit and cleanout to the'top of the liner. Pressure test the liner lap to 3000 psig (note pressure must not drop more than 300 psi in 30 minutes)~ 2) POOH with the 8½" bit and RIH with a 6" bit and scraper to 9740'_+. 3) POOH with the 6" bit, and rig up a wireline.unit to run a GR-CBL-VDL- CCL and a gyro survey in the 7" liner. Run the bond log to at least 100' above the liner top under 1000 psig surface pressure. Overlap the gyro survey to tie-in with the previous run. 4) If the bond log shows that the zones of interest are isolated, prepare to-perforate. ., Lower Kuparuk Test Objectives: Primary - Clean sample of formation fluid Secondary - Productivity Information (Pi, Kh, Tf, Skin).~ 5) Perforate from 9404'-9420' and 9434'-9474' (MD-DIL) with 4" casing guns at 4 JSPF, 90° phasing. 6) RIH with a DST packer, downhole shut-in valve, and pressure and temper- ature gauges. Set the packer at 9360'_+ and fill the test string with a 6700' diesel cushion. 7) Open the downhole shut-in valve for 6 minutes of initial flow. 8) Close the downhole shut-in valve for 60 minutes of initial buildup. 9) Open the downhole shut-in valve for the final flow period. Flow the well for a minimum of 4 hours at a maximum rate. Obtain clean samples of formation fluid (at least 20 gallons). 10) Shut-in the downhole valve for a final buildup of 4 hours on the length of the final flow period, whichever is greater. l l) Reverse out the' test string and POOH with the test string. 12) RIH with a retainer and set at~'+_. Squeeze perforations with 150 sacks of cement. 'Lay a 50+' cement plug on top of the retainer prior '- to pul lin9 the work string out of the hole. Middle Kuparuk Test Objectives: Primary- Productivity (Pi, Kh, Tf, Skin) Secondary - Weathered crude samples. ~yI~~ ...... 13) Rig up a wireline unit and perforate from 9171'-9194' MD (DIE) with 4" casing guns at 12 JSPF, 90° phasing. 14) RIH with a DST packer, downhole shut-in valve, and pressure and temper- ature gauges. Set the packer at 9140'_+ and fill the test string with a 6400' diesel cushion. 15) Open the downhole shut-in valve for 6 minutes of initial flow. ~age 2 16) Close the downhole shut-in valve for 60 minutes of initial buildup. 17) Open the downhole shut-in valve for the final flow period. Flow the well until oil reaches the surface th'en shut-in the downhole shut-in valve for 2 hours or the length of the final flow period. 18) Reverse the test string. Obtain weathered crude samples and POOH with the test string. 19)·RIH with the packer and packer assembly on wireline and set the packer at 9110'_+. 20) RIH with the 3½" production tubing. Stab into the packer and space out. Nipple up the Xmas tree with master valves. Prepare to RDMO. March 2, 1982 Anchorage, Alaska ALASKA OIL AND GAS CONSERVATION COMMISSION THRU: Chat Chatter/o~~/ Chairman ~/&~-" Lonnie C. Smith ~ Commissioner Bobby Foste~~ ~ Petroleum Inspe tor January 26, 1982 Witness BOPE Test on Conoco's Milne Point D-1 Sec. 13, T13N, R10E UM Permit #81-144 Sunday,~ J..a.n.u. ary 24, .!982 - The BOPE test began at 2:00 a.m. and was concluded at 6:30 a.m. As the attached BOPE inspection report shows there were two failures. The manual valve on the choke line leaked. This valve 'was repaired and tested. A valve in the choke manifold leaked and this is to be repaired, tested and the A.O.G.C.C. office notified. The manifold on the accumulator bottles does not meet A.O.G.C.C. regulations and I informed Job~ Henderson, Conoco drilling foreman, that this would have to be corrected before the next BOPE test. In summa~-t I witnessed the BOPE test on Conoco's Milne Point D-1. Attachmenti I was notified by John Henderson on January 30, 1982 that the valve in the chOke manifold which failed had been repaired and tested. · O&G ,~4 ,;/80 (STATE OF A],ASKA ( ALASKA OIL & GAS CONSERVATION COMMISSION B.O.P.E. Inspection Report Inspector~~'' .--.,~--'~'~' "'~ ,~.:-1¢'~. ,,~ Operator ~ 'j ~j ~.~ . Well i'~"/1~/~ ~4' b' I Location:. S~c/~ }R ~ .... · /~ /~z ~,~ Drilling Contractor ~~~, .. . Rig ~,/~ ~cation, General ~/~' ', , Reserve pit Rig General H~ous eke.eping BOPE Stack · , Annular Preventer -- Pipe Rams '- Blind Rams. Choke Line Valves H.C.R. Valve Kill Line Valves Check Valve / Test Results: Failures Test Pressure Wel 1 /g)///~,£: ,5( Representative .j~"~,j //'/~e/j / ~" ~ C ~'~ ft. c?' '~Casing Set Representativ~ ~'~"7 ~, Full Charge Pressure~:~'~ ps ig Pressure Afte'r Closure ~/~ psig 200 psig Above Precharge Attained: - rain ~sec Full Charge Pressure Attained: ~ min ~ sec Controls: Master ~_. Remote ~ .. Blinds switch cover Kelly and Floor Safety Valves / Test ~ressure ~Q' 'oz~ Upper Kelly Lower Kelly Ball Type / Test Pressure / Test Pressure InSide BOP / Test Pressure Choke Manifold ~/¥~,~ Test Pressure~FD~ 't~'/ NO. Valves ./~ No. flanges ~ ~ Adjustable Chokes. / Hydrauically operated choke ............... :---/-4-I _~r~- Te~[- ~e ~ ~%s ..... Repair or Replacement of failed equipment to be made within ~. days and Inspector/Commission office notified. . ~ ~o ~ .~- , ..., ., .... ,. . , , ~ ~ ~ / . -,,., cc - Supervisor ' ' Inspector . ' . ~..~ ~ ' . ' 'January 18, 1952 Mr. Gary A, ~terriman 2525 C Street, Suite 100 Anchorage, Alaska 99503 Conoco et.al, bftlne Point [Inlt [~tlne Point Conoco Ins o Permit ~to. 81-144 Sur. Lee. 964'FNL, 1233VFHL, Sec 13, ?131~, I~IOE, UMo Bottomhole Loot 1411'l~L, 1328tFBL, See 12, TISN, RIOE, Dear ~. ~err tman ~ Enclosed is the approved revise~l application for per~.~it to drill the above referenced well. The provisions of the cover letter, dated Sept~ber 25, 1951, accompanying the original approved pemit are in effect for this revision. Very truly ~y~ours, /_ .... . ~ai ~n of Alaska Oil and Cas ~nae~stton C~issien Ene lo SUre ~epartment of Fish & Gangs, Itabitat Section w/o anal. D-epart~r~ent of Favi~o'~ntal Conservation w/o encl. A(' STATE OF ALASKA ALASK ,_ ,L AND GAS CONSERVATION C ~MlSSlON PERMIT TO DRILL 20 AAC 25.005 la. Type of work. DRILL I~ lb. Type of well EXPLORATORY [] SERVICE [] STRATIGRAPHIC [] REDRILL [] DEVELOPMENT OIL DEEPEN [] DEVELOPMENT GAS [] MULTIPLE ZONE [] 2. Name of operator 3. Address 4. Location of well at surface I ' 9. Unit or lease name ~'~, tzar' ~, ~ ~, T~,~,o~. ~o~.~., H,{~ P0~0~ At top of proposed producing interval 10. Well number At total depth 11. Field and pool 5. Elevation in feet (indicate KB, DF etc.) I 6. Lease designation and serial no. 45' ~I A~U 12. Bond information (see ~0 AAC 25,025) Type ~~ Surety and/or number ~~ - t~-~ Amount 13, Distance and direction from nearest town 14. Distance to nearest property or lease line 15. Distance to nearest drilling or completed ~~; ~~ ~Z miles L~55 ' feet well ~;~g ~ ~t ~ ~feet 16. Proposed depth (MD & TVD) 17. Number of acres in lease 18. Approximate spud date ~t ~b" ~l~ feet ~ ~e5 19. if deviated (see 20 AAC 25.050) ]20. Anticipated pressures ~Z~O~ psig~ O Surface KICK OFF POINT ~ feet. MAXIMUM HOLE ANGLE ~ o~ (see 20 AAC 25.035 (c) (2) ~ psig~~ft. TD (TVD) 21 Proposed Casing, Liner and Cementing Program SIZE CASING AND LINER SETTING DEPTH QUANTITY OF CEMEN~ Hole Casing Weight Grade Coupling Length MD TOP TVD MD BOTTOM TVD (include stage data) ~Z'~ 95/8" 4~ e b-~o ~ ~' o~ , O' ~0' ~'~ ~" ~9¢ C-~o ~ CZ~' qq~' ',~' ~' I ~ I 22. Describe proposed program: ~ ~~ ~0¢ ~~ JAN 1 5 1982 ~ o~: p~¢~.re~-er ~ ~o~ ~-~ ~ec Alas~0it&Gasc°ns'c0mmissi°n ~ch0rage . 23. I hereby cectify t~: t~e foregoing is true ~nd correc: :o :~e best of my knowledge The sPa/below~r Commis~use CONDITIONS OF APPROVAL Samples required Mud log required Directional Survey required APl number ~'YES ~NO ~YES eNO ~YES eNO 50- Approval~ate Permit number ~/--~¢ y ~ O~ /~*//~/ ~ SEE COVER LETTER FOR OTHER REQUIREMENTS bg order of the Commission / Form 10-401 / Submit in triplicate Rev. 7-1-80 Naska-O!! & _fi_as C.o~s~ Co..,n...,n.~k~ Anchorage 0t Z~oo' KCLI21VI-U JA-~'i 5 1982 ~aska Oii & Ga~ Cuns. Commi~:~ioD Anchorage IZ RECEIYEI) JR N 1 5 ]982 Alaska 0il & Gas Cons. Commissio, ~chorage , I000 JAN ! 5 ]982 Alask~ 0il & 6as Cons. Anchorags // September 25, 1981 Mr. Gary A. Merriman Supervising Engineer CO~OCO 2525 C Street, Suite 100 Anchorage, Alaska 99503 Re~ Milne Point Unit, Milne Point-D-1 Conoco Inc. Permit No. 81-144 Sur. Loc. z 535~FNL, 905'FEL, Sec 13, T13~, RIOE, UM. Bottomhole Loc.~ 2380'FSL, 2310'FEL, Sec 7, T13N, RllE, UM. Dear Mr. Merriman~ Enclosed is the approved application for permit to drill the above referenced well. Well samples and a mud log are required. A directional survey is required. If available, a tape containing the digitized log information shall be submitted on all logs for copying except experimental logs, velocity surveys and dip~ter surveys. Many rivers in Alaska and their drainage systems have been classified as important for the spawning or migration of anadromous fish. Operations in these areas are subject to AS 16.50.870 and the regulations promulgated thereunder (Title 5, Alaska Administrative Code ). Prior to commencing operations you may be contacted by the ~abitat Coordinator's office, Department of Fish and Game. Pollution of any waters of the State is prohibited by AS 4.6, Chapter 3, Article 7 and the regulations promulgated thereunder (Title 18, Alaska Administrative Code, Chapter 70) and by the Federal Water Pollution Control Act, as amended. Prior to Mr. Gary A. Merriman -2- Milne Point Unit, Milne Point D-1 September 25, 1981 commencing operations you may be contacted by a representative of the Department of Environmental Conservation. To aid us in scheduling field work, we would appreciate your notifying this office at lease 48 hours before the well is spudded. We would like to be notified so that a representative of the Comm/ssion may be present to inspect the diverter system before the conductor shoe is drilled and also to witness testing of blowout preventer equipment before surface casing shoe is dril led. In the event of suspension or abandonment,~ please give this office adequate advance notification so that we may have a witness present. Very truly yours, H. Hamilton Chairman'of BY ORDER OF THE Alaska Oil & Gas Conservation ~6~fl~bsion EncloSure cc~ Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o/encl. Conoco Inc. 3201 C Street Suite 403 Anchorage, AK 99503 September 18, 1981 Mr. Lonnie C. Smith, Commissioner Alaska Oil and Gas Conservation Commission 3001 Porcupine Dr. Anchorage, Alaska 99501 Dear Mr. Smith' Enclosed are the permit applications to drill Milne Point B-2, C-l, and D-l.~'These applications are being submitted in triplicate on form 10-401, revised 7-1,80. Please disregard any previous permit applications to drill the above mentiOned wells. If you have any questions, please call me at 279-0611. Sincerely, Supervising Engineer RECEIVED N~ska Oil & (:;as C:,,s. con'~n)ission Anchorag,.., STATE OF ALASKA ALASKA (~'"~- AND GAS CONSERVATION C(]~r MISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work. DRILL X~ lb. Type of well EXPLORATORY [] SERVICE [] STRATIGRAPHIC [] REDRILL [] DEVELOPMENT OIL [~ SINGLE ZONE [3{3 DEEPEN [] DEVELOPMENT GAS [] MULTIPLE ZONE [] 2. Name of operator Conoco Inc. 3. Address 2525 'C' St. Suite 100 Anchorage, Alaska 99503 4. Location of well at surface 9. Unit or leaSe name 535' FNL, 905' FEL, Sec 13, T13N, R10E, UM Conoco et al~ Milne Point Uni At top of proposed producing interval 10. Well number ~20~ FSL, 2580'FEL, Sec 7, T13N, RilE, OM Milne Point D-1 At tdtal depth 11. Field and pool 2380' FSL, 2310' FEL, Sec 7, T13N, RllE, UM Kuparuk River Field '5. Elevation in feet (indicate KB, DF etc.) I 6. Lease designation and serial no. 30' ground levelI ADL 47437 Kuparuk River Pool , 12. Bond information (see 20 AAC 25.025) Type blanket Surety and/or number 8086-15-54 Amount $200,000 13. Distance and direction from nearest town 14. Distance to nearest property or 'lease line 15. Distance to nearest drilling or completed D~_adhor.~e :Southeast 32 miles 905 feet well Milne Pt. 2/SE. 5300f~t 16. Proposed depth (MD & TVD) 17. Number of acres in lease 18. Approximate spud date 9620' MD:8000' ~VD feet 2560 Ac January 1, 1982 19. If deviated {see 20 AAC 25.050) I20. Anticipated pressures 32/0 ;psig@_ 0' .'Surface KICK OFF POINT2100' feet. MAXIMUM HOLE ANGLE 45 {see 20 AAC 25.035 {c) (2) 4000, psig@.]~~ft. TD (TVD) Proposed Casing, Liner and Cementing Program - "SIZE CASING AND LINER SETTING DEP'FH QU/~.NTITY OF CEMENT .......... Hole Casing Weight Grade Coupling Length MD TOP TVD MD BOTTOM TVD (include stage data) 26 '20" 94# H-40 BTRS 80 0 I 0 80'*l 80'* Cement to surface ' 17½ 13-3/8 72 N-80 BTRS 2000 0 t 0 ~ .~~-2~e0' 4200 CF (200% excess. ..... ' o .... 19Z a_~/~ 47 T.-RO. RmRR 9620 0 ' 0 962 00 lst:..;:8.60CF 2nd: 100C] 22. Describe proposed program: · Proposed surface and bottomhole location plat enclosed ~-~/' ~ ! As-built survey plat will be submitte~after setting conductor casing See attached Supplemental Data Shee~EtEiv~.D~ See attached wellhead BOP shetches S~p ] g ]~] *set 80' from ground level; all. othe] figures are based on KB elevation Alaska 0fl & (~as Cons. ~ of 20'. Anchorago Co~nt~is,lo~ ..... .... 23- I hereby ~.~..~~+~~~ certi that the foregoing is true and correct to the best of my knowledge ". SIGNED _ TITLE Supervising Engineer DATE Sept. 17, 198. The space/l~ow forffmmission u~ CONDITIONS OF APPROVAL Samples required Mud Icg required I Directional Survey required I APl number ~YES [-INO ~YES []NOt ~ES [--INOI 50-- O"L,$ '- '~ (o(= ~/ Permit number Approval date ~/- / ~( 09/25/81 t SEE COVER LETTER FOR OTHER REQUIREMENTS APPROVED BY ' "' ,COMMISSIONER DATE September 25, 1981 u' -/ ,- "' - by order of the Commission Form 10-401 Submit in triplicate Rev. 7-1-80 SUPPLEMENTAL DATA SHEET FOR APPLICATION FOR PERMIT TO DRILL CONOCO et al. MILNE POINT NO. D-1 CONOCO INC. 2525 "C" Street - Suite 100 Anchorage, Alaska 99503 I CEMENTING PROGRAM A. The 20" OD conductor casing will be cemented to the surface with perma- frost cement in 26" bucket drilled hole. B. The 13-3/8" OD casing will be cemented to the surface with permafrost cement through drillpip.e stinger stabbed into float collar and through fl oat shoe. C. The 9-~/8' OD casing will be cemented through plug container head, float shoe, and float collar with 860 CF of Class "G" cement. Isolation of the 13-3/8"-9-5/8" casing annulus @ the 13-3/8" casing shoe will be accomplished through multi-stage cementing collar run at the 13-3/8" casing shoe with lO_(] CF of permafrost cement. Non-freezing fluid will be placed in the 13-3/8"-9-5/8" casing annulus through the permafrost utilizing multi-stage cementing collar placed at the base of the permafrost. II ANTICIPATED GEOLOGY III O; - 4,600' 4,600' - 6,950' 6,950' - 7,800' 7,800'- 9,000' 9,000' - 9,100' 9,100' - 9,275' 9,275' -lO,O00' lO,O00' -10,360' Surface conglomerates, silt and sand sequences Estimated base of permafrost @1,800' FORMATION EVALUATION Siltstone, shales Kuparuk River formation Kingak formati on Sag River formation Shubl i k forma ti on Sadlerochi t formation Li sburne formation. A. Standard mud logging equipment will be installed while drilling interval 60' to total depth. ~' B. Full size cores may be taken as determined by on-site geologists. C. Wireline logs including: Dual Induction Laterolog; Borehole Compensated Sonic-Gamma Ray; Formation Compensated Density with CNL and GR-Caliper IV DRILLING FLUIDS Depth O' - 2,000' 2,000' - 5,500' 6,900' -10,000' Type Dens i ty Gel - Fresh Water 9.5'- 10.0 ppg Low Solids - Non Dispersed 9.5 - 10.0 ppg Low Solids - Lignosulfonate 10.0 - 10.5 ppg ?ROBABLE )F. SP !R!LLINO · · FROM . · I IIIL#J. PT. UNIT G~YDTR BAY MILNE PT. VICIN TY MAP UlLlS · . It " 6~ ~~'-/'0 ' "- PR ABLE N '.:' :. ". L -' .:' '. F.' ~ .,~~ '~!,~-, ',-. · ':..f -- .,' .. 0 ~PILL~GE FRO "' ' '" ' .".D~{I:SLING OF ~'"'1'~1~~ ,'.~'~PO-~D ',.. ~ ~: ':' ,' '"--'"' ' ~ --....-' ~ .-. '-:.. ~ : .,_.-.'..:;n_~, ~ :o e:, a~ 'e ON: "' "/-"-- ' "" -";- '<"' " " -' ,)- ~ ...... '.,/ .: --- . ..' / .--- .,. :iff 1~. "'~ '": ~;' ' /:" ~ 'j~ ': ' ' · · :' ~:.C.k.~."' "' '- ~' - /i"-': -':'; , · '%>-.,.-',; ~ -.., ) ~' ' · : :-" --' :T2.. '."-'~- ."'.?' ""' ' ': '" "' ':' i':'! '"' .. t t '..::; i I .' · ,,: *.'-- .. · '"' '' ' "' "" ' I ~ I .. \ ,. ..- ~..... . ,.'. , . .__ ... , , I . . - ;.",..: ,' :, ..: -,;,. o.-..-" . 28 Conoce Inc. Milne Pt. Unit Proposed Drilling Supplement to SPCC 1981 q~ 8 SEP ~ 8 ]~8] Gas Cons. Commission Anchorage CA. 5lMm. "~ 0 P '~"FAC..K I I 'x / i I l -"L~IV~~. CHOI~_ & KILL MANIFOLD FOR ....~, 3 /II Io ze ~9~'OD CASING BOP STACK ROM MUD PUMP . - KILL MANIFOLD · PRESSURE PUMP __ REMOTE PRESSURE GUAGE SENSOR DRILLING SPOOL - · HYDRAULIC CONTROLLED REMOTE OPERATED TO AT t.*OS PHE MUD/~ 5E NOTE: 1. 2. CHOKE MANIFOL.[ Stack Station Cu. trol Hanifold located remotci)' ~'ith B000 ~si Acc~utator ~ 160 EaL: Re~;ervoir S[~tion Control H~nifold p!u~ vari~bte Choke Control to be located on 2iE fJcor. Kiil& ~ok~ ~tanifolds to meet APl Class 5H c .... ~.r~- ~okc Y.a~;:'cld 5izc-;~t:ng 5"-SC00 TO SHALE S£p 1 8 198t ~aslOa Oil & Oas Cons J! ~,~I... ' ..... , ,v, ~ge C°m.~;S ~iort BOP ~.~Ar~tFOLD LAYOUT CO;:O~O,~ I,,"C. H. D. Hal®y Manager of Production Ventura Division Conoco Inc. 290 Maple Court Ventura. CA 93003 (805) 642-8154 September 2, 1981 Mr. L. C. Smith Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Smith' Permit Request Milne Point/Conoco Attached is a permit request for the authority to drill three oil wells on the Milne Point Unit of the Alaskan North Slope. These wells are designated as B-2, C-1, and D-l?the letter indicating the drilling site location and the number is the sequence in which the wells will be drilled from the respective location. A map of the area is attached which designates the location of these wells. A surveyed location will be provided once the well is staked. Also attached you should find our check in the amount of $300.00 which according to the Alaskan Administrative Code is the filing fee required. Your contact relative to the permitting of this well is Gary Merriman. Gary can be reached by dialing 279-0611. Very truly yours, H. D. Hal ey Division Manager of Production DLD-fes encs CC: Gary A. Merriman CHECK LIST FOR NEW WELL PE[LMITS Company Lease & Well No. ITEM APPROVE ....... DATE .. (2) Loc ......:~'~ ~:: 7 :'/~ j!? 2. ~2; thru 8') 3 ~./. 4. 5. 6. 7. 8. (3) Admin :h~(9 ~U ll)~']t/'/~/ 10.9' 11. (4) Casg (~ ~P--'Z~',~ / ~X2 ih~u 20) 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. Geology: Eng ine~eying: WVA - JAL ~ rev: 03/10/81 YES NO __ REMARKS Is the permit fee attached ................................. Is well to be located in a defined pool ................. Is well located proper distance from property line ..... Is well located proper distance from other wells ....... Is sufficient undedicated acreage available in this pool Is well to be deviated and is well bore plat included .. Is operator the only affected party ............ ........ Can permit be approved before ten-day wait .................. Does operator have a bond in force .................................. ~w_. Is a conservation order needed ...................................... ,, , Is administrative approval needed ................................... Is conductor string provided ..................................... Is enough cement used to circulate on conductor and surface'"''. WiLl cement tie in surface and intermediate or production s trings Will cement cover all known productive horizons ..., ....... Will surface casing protect fresh water zones ................. ;nd . . Will all casing give adequate safety in collapse, tenSion bUrs Is this well to be kicked off from an existing wellbore .......... eeo , ~ Is old wellbore abandonment procedure included on 10-403 ............ Is a equate well bOre separation proposed .......................... Is a'diverter system required ...................................... Are necessary diagrams of diverter and BOP equipment attached Does BOPE have sufficient pressure rating- Test to ,~~ Does the choke manifold c~ply w/AP1 RP-53 (Feb.78) .................. Additional requirements ************************************* Additional Remarks: /~; .... c~~ ~ ~ ~/~l/,,~/ INITIAL'' i' GEO- ' UNIT ON/OFF POOL CLASS STATUSI AREA NO.... SHORE ,, CHECK LIST FOR NEW WELL PERMITS Comp any Lease & Well No. IT~H APPROVE DATE u s) 1. Is the permit fee attached .......................................... 2. Is well to be located in a defined pool ............................ 3. Is well located proper distance from property line ................. 4. Is well located proper distance from other wells ................... 5. Is sufficient .undedicated acreage available in this pool ........... 6. Is well to be deviated and is well bore plat included . .............. 7. Is operator the only affected party ................................. 8. Can permit be approved before ten-day wait ..................... - .... 11) 10. 11. (4) casg~ &l~{~l~ (12 thru :~0)' 12. 13. 14. 15. 1'6. 17. 18. 19. 20. 21. 22. 23. 24. 25. (5) BOPE (21~thr~ (6) Add: YES NO REMARKS Does operator have a bond in force ................. . ,~/~-- ~. Is adm±n±strat±ve approval needed .. . '' '. 'i.'~ Is conductor str±ng prov±ded ........................................ Is enough cement used to c±rculate on conductor and surface ......... ~ .... W±ll cement t±e in surface and tntermediate or product±on strings . . Will cement cover all known productive hor±zons ..................... W±ll surface casing protect fresh water zones ....................... Will all cas±ng g±ve adequate safety ±n collapse, tension and burst., Is this well to be kicked off from an ex5sting wellbore ............. Is old wellbore abandonment procedure included on 10-403 ............ , , Is adequate well bore separation proposed ........................... Is a diverter system required ......................... , ............. Are necessary diagrams of diverter and BOP equipment attached ....... ----- ...... Does BOPE have sufficient pressure rating - Test. to .ff__o..o..o. psig Does the choke manifold comply w/AP1 RP-53 (Feb 78) ......... Additional requirements ............................................. Additional Remarks: Geolo~yfi Engin~%r.ij~g: .c's rev: 01/13/82 INITIAL GEO. UNIT oN/OFF POOL CLASS STATUS AREA NO. SHORE ,,. Well History File APPENDIX Information of detailed nature that is not padiculady germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this natUre is accumulated at the end of the file under APPENDIX. No Special'effort has been made to chronologically organize this category of information. CONfiDENTIAL LVP 0i0 F~(')I V~ ..... ~! . ,~ ~,,~IF!CATIO ~ISTING 6ERVIC7~ WAN~ ~SERVIC DATE :82/0~/ 3 ORiCl~>i :107o TAP~] NA~E :52675 CONTi~,~AT%Qh ~ :01 PREVIOUS TAPE : ** FibF, hEADER FIbE ~',~ A f~E :$ERVIC.O01 SERViC~ ~'~ A P, E DATE ~ MAXI~,,~ I,[(~t:~GTH : 1024 F I b E 'fY P E : PREVi O:~S FiLE CN : C[){~OCO INC. FN : KHP~,~RUK RIVER RANG: STAT: ALASKA CTRY: USA UNIT 000 0 00 000 000 000 000 000 000 000 TYPE O0 0 CAT~J 000 000 000 000 000 OOO 000 000 0 O0 C. ATE 000 012 004 0~I 4 O0 3 003 002 012 O04 SiZE O07 CODE 065 065 O65 065 065 065 065 065 CODE O65 CONFIDENTIAL 5VP Oi'~ }i01 ~]ERiFICA.,.]ON ISTING PAG~2 2 [ PACIFIC COAST COMPUTING CEF'[ER ~==~ ...................... ~--~_--~__--~== CO~PA~Y = CO~OCO INC. WELL = FiEb~ = EUPARUK RIVER CO~NT~ = MOR~"' ..H SLOPE STATE = AbASKA O0~ ~ i0707,62t~73 BOTTC~, LOG iNTERVAL TOP LOG INTERVAL CASI.~G-bOGGgR BIT SIZE TYP~ hi}bE DENSITY VISCOSITY PH : 2304. = 113 FT. : 20 IN. ~ 1!3 ~T. : i7.5 i~~f. = GEL/BEi,~XtSPUO =9.3 : 159 LVP oi~'~.~()i V~{IFICAT'i'Ob~ LISTING 16.~. C3 4.43 (a, 64 ~- 3.38 0 6.6 F 3.57 Ce .65 F 3.27 L~ 89 F j 6CHuUM6~R~ER i I PACIFIC COAST CO~PUTiN¢ CE~rER i COMPANY = CONOCO INC. WELL = D-1 FIELD = KUPAROK RIVER COUNTY = MGRTH SLOPE STAT~ = ADASKA JO.B ~ ~0707,62674 DIL RU~'~ ~2, LOGGED 15-FE~'82 8~76 F'T. 2086 FT. CONFIDE LVP Olo MOl VE~IFI~A%ION blSTiNG PAGE CAS I ~:.~-LOGGER = 20 BIT SIZE = 12,25 IN, TYP~ii ~F~LE. VISCOSITY . CO~%PAi'.~Y : COi',~OCO INC, FIEDD : KUPAR'(]K RIVER COUi'~'fY' : NORi'H SLOPE STAT;f : ALASKA LV~ Olo Hoi V~iFi~ATi©N hlSTi~G BOTT©s LOG iNT~CRVAL = 9897 FT. BIT 5IZ~ = 13.38 TYP~ dOhE FbUi{~ = bIGNOSUbFO~qATg DE~'~ITY = 10.4 PH = 11.0 FLUiL) bOSS = 4.5 C3 Rh ~ ~EAS. TE~P. : 1.44 ia 65 Ri~ ~ ~b]AS. TE~>~P. = 1.12 ~ 64 R~,C ~ ~5A5 TEacUP. ! 62 ~ 64 RM {,~ ~.~-{7~ = 0.544 ~ 170 f TYPE SIZ~ ~EPR CODE 4 1 56 8 4 73 9 4 05 ~NTRY ! 6O ,lin 0 CONFIDENTIAL LVP 010.HO1 VERIFICATION LISTING PAGE DATU~ ¢~PEC£f'ICAT!ON SLOCKS MNE~ ~ERVim~'' 8,~klICE u~l~ AP1 Aei 1D ORDER ~ bOG TYPE -DEPT FT 0 0 SFLU D!L OHMS4 7 0 ILM DiL 0;4i~ ~ 7 ILO OiL {J H ~ ~ 7 ~ 2 SP DiL ~4V 1 GR n!h GAO1 7 3 I NPHt FON PO 42 68 RHO,~ FOb} GIC'~ 42 CALl PO~ IN 42 28 SG~ ?p~:4 GAPi 42 o NRAT P 0'~-~ 42 42 NCNb ?0~ 42 34 FCi~b ?0~,~ 42 34 DT ~dC US/F 60 52 G R ~ ~ C ~,., A ~ 60 ,~ 1 SP ~C ~,~V 60 i URA~'~ ~t;T PP~ 0 0 THOR :~(;T PPM O 0 POTA ~GT PU 0 0 CGR "~GT GAPi 0 0 AP~ AMI FILE CLASS ~OO NO. 0 0 0 0 0 0 0 0 0 46 0 0 0 0 0 32 0 0 2 0 0 i O (] 0 0 0 3 0 0 0 0 0 i 0 0 9 2 0 0 93 0 0 32 0 0 32 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 SIZE. PROCESS LEVEL 4 0 1 4 n 4 0 1 q 0 i 4 n 1 4 0 4 n 4 0 1 4 0 4 0 1 4 0 ! 4 0 4 0 4 0 1 4 0 4 0 4 0 4 0 R~]PR CODE ~8 68 68 68 68 68 ..58 68 68 68 68 68 68 68 DEPT g933.5000 SFbU 8P 999 2500 ~ DRHO -i~3~.0000 CAbI NC~[~ -4932.0000 FCNL SP -999.2500 URA~ CGR -28.92~9 DEPT 9900. 0000 SF,GU SP -14.2i29 GR DRMO 0 2212 CALl NC~,} [., 2432: 0000 SP -999.2500 CGR 52,4297 DEPT 9-9{20 00 SP -14,9629 ,<.GA DRHO 0.0767 CAi~i NCi<i L 2590 , 00O0 FCNL SP 999.2500 UR., N CGR 83.46~8 DEP? 9100,0000 SFLU SP -14.8594 GA DRHO 0. 0372 CAUl NCi~L 2710. 7500 FCNL -999.2500 -999.2500 ~PHI 8.5000 SGR -1453.0000 PT -0.4873 THOR 3.0781 99.4375 7.5977 SGR 720.5000 DT 2.1145 THOR 3.0527 110.0781 8.7891 839.0000 DT 2.6157 THOR 3.0~ IL~ 103.71R8 ~P~i 9.2969 SOR 816.8750 0% 2.3662 TH6~ -999.2500 ILD 38.183~ -999,2500 -i,7910 POTA 2.5566 iLP 3~.2324 R~OB 68,7500 NRAT 93,7500 GR 7,3398 POTA 2.6699 iLD 32.7148 103.0000 90.1875 G~ i2.2578 POTA 3.1i72 32 . 5439 97.0000 ~.3750 -999.2500 -16384.0000 3.1152 -999.2500 -0.0039 1.9805 2.3984 3 387 0.0146 2.6230 2.4707 2.9453 110.0781 0.0244 3.023,~ 2.A813 2 9'140 ~o317~88 0.0220 LYP OlO,M()l YERIFICATIOM 79,7500 DEPT 9600,0000 SFL[; SP -15,6738 GR DRHO 0.0488 CAbi NCNt. 2776.000U FCNL SP -999.2500 DEAN CGR $2.8599 DEPT 9500.0000 SFLU SP -16,6250 GR DRHG 0,0186 CAbI NCNL 2528,0000 FCNL SP -999.2500 URAN CG.R 86,6077 DEPT 9400,0000 SFLU SP -22,3477 GR DRHO 0~0368 CALi NCNb 2857.0000 FCNb SP -999,2500 URAN CGR 65.9404 DMPT 9300,0000 8FbU SP -28,~961 GR DRHO 0.0196 CALi NCnb 3050,2500 FCNL SP -999,2500 URAN CGR 58,2969 DEPT 9200,0000 SFLU SP -24,8594 GR DR~{O 0 02!5 CALX NCNL 2948~0000 FCNL SP -999,2500 UkAN CGR 72,9844 DEPT 9100.0000 SFLU SP -21,0977 GR DAN© 0,0375 CALl NCNb 2322,1562 FCNb SP -999.2500 URAN CGR 97,1562 DEPT 9000.0000 SFLU SP -22.3867 GR DAMS 0.0414 CALl NCNL, 242~,6875 FC~L SP -~99,2500 CGR DEPT 8900.00~0 SFLU SP -17,50t0 DR~D 0.0321 CAb~ LISTING 2,5781 IbM 106,0469 MPHi 9,6563 MGR 844,0000 DT 2.~254 3 i523 IL~ !01.32~1 NPMI 9,~6~8 SG~ 737,0000 DT 1.5590 T~OR 4.~255 IL~ 87.0000 NPMI 9,16&1 SGR 937,5000 DT 3.0942 THOR 6.7969 ]:b~ 80.3594 NPHi 9,2525 SGR 1082,6250 OT 1.4153 THOR 5.3633 91.328t NPMI 9,8672 922,0000 DT 2.2456 THOR 2,1992 119.2500 11,2999 SGR 665,7500. DT 2.8608 T~OR 2,35~6 IBM 117.0000 NPMI 11,9050 686.5000 DT 2,~706 TdOR 2.0059 ILN 126.4531 NP~I I~.56~0 SGR 2,6895 IbP 3!,9336 AMOS 101,.~250 ~RA% 89,0000 (;R 11.i529 POTA 3,2773 IbP 37,!096 REOB 98,44t6 NRAT 94,0000 GR 13.7448 POTA &.3008 IbP 30,4199 RMOB 89,7070 NRAT 88,7500 GR 9,6401 POTA 5,664! IbP 27,1774 RhOS 79,5625 NRAT 85,7500 G~ 11,6074 POTA 5,5195 IbP 31,2988 RHDB 89 6875 NRAT 87~3750 GR ! 0,5918 POTA 2.0156 iLD 34. '2377 R H 0 b 119.1875 MRAT 0,750(;' GA I73.7207z iPOeA... 2.6074 31,1736 RMOB 123.0~25 NRAT 92.0000 GP 15.5918 1.8965 iI.D 125,2949 NRAT PAGE 2.5309 2.4941 2.9629 I06.0~69 0.0266 3.2148 2.4199 3,2246 101.3281 0,0231 2.4614 2 8203 87!0000 0 0195 5.7461 2.4832 2.6147 80.3594 0.0156 5.4375 2.4355 2.9395 91.3281 0.0215 2.0i56 2 ~4.3 311953 119 2500 0~0293 2.5273 2 4383 I~7.0000 0.0300 2.0137 2.3636 3,6060 CONfiDENTIAL bVP 0[0.HOt VERIFICATION blSTING PAGE NCaL 1998.3672 Sp -999.2500 CGR 102,7979 DE~T ~00.0000 SFBU SP -17.2461 GR DRHO 0,02~3 CADI NCN6 1878.3i25 FCNL Sp -999.2500 URAN CGR s6,7205 DEPT N700.0000 SFLO SP -22.5313 GA DRHP 0.020~ CALI NCnb 2066.4375 FCNL $~ -999.2500 URA~ CGR 99.2627 DEPT B6~O.O000 6F6U SP -23.~047 GR DRH~ 0,0225 u . NCP% 2094,0000 FCNb SD -999,2b00 U~AN CGR 87.3125 DEP'2 ~500.o000 SFLU Sp -23.2109 GR DR~9 0.02O0 CAb£ NCNb 2180.0000 FCNG 8P -g99,2500 QRA?! CGR ~0.6230 DEP? H400.OOO0 SFLU SP 27,2969 GR '-' ~.,376 CALl NC~f., 1757,0000 FCNb Sp -q99."2500 U'RAN CdR !12.9531 DEPT ~300,0000 SFLJ SP ~73.i250 GR NC4h 18~9.0000 FC~i, Sp -9~9.2500 URA~ CGR 97.9469 DEPT ~2uO 9000 DR~,~ 0.0i75 C~LI CGR D ...., 0.00 .~ 0 $ F L d 520.2773 DT 2.9570 %?iOR 1.~770 113.~906 ~PMi i0.2794 503.9062 DT 3.8574 THOR 2.1523 Ib~ 118.9531 ~PHI 10.55~0 553.6563 2.07¢)7 1.8535 203.~375 II.~766 519 000u 15,4707 2.4160 240.53!3 ii.7969 529.00~0 DT 19.5672 THOR 2000 0000 thai 93:3750 ~PF! -999.25O0 5GR 445.7500 DT 4.7852 ~8~R 2.2539 ib~ L0~,03!3 NPHi -999.2500 5GR 561,0000 DT 3.07R1 THOR 73.92!9 -999.25~0 614.5oo~) DT 2.~3A0 Ib~ 10i.1875 14.9838 1,7217 4i.3029 116,4863 107,1875 1t.0977 2.0820 39,7793 114.5859 i00,00OO 15.4276 1,7~39 44,4824 207,7500 108.7500 10,2754 2.1582 ~4.7754 230,6484 105.3750 8.1235 2000.000o 45 4590 . 14~.3750 55.7813 17.976~ 2.7168 36,718~ 119.8750 8,6719 5.1582 P,154:t 35.4/~92 84,4229 90.9219 10.0i97 3.4355 IbP R~OB ILD RHO~ NEAT GR POTA 1 LD FOTA IbP ~RAT POTA ~RAT gg PinTA POTA 126.4531 0.0286 I 747~ 3 5230 i~3'.8~o6 O.0293 1,9707 2.3934 3.4606 118,9531 0.0269 1,7051 2.4297 3.7559 203.4375 0.0317 2.0684 2.328i 3.7813 2qO 5313 olo o 6.1172 2 3594 3}8301 93 3750 0 0289 2.6133 2 3711 3i3438 108 03i3 0.028~ 1.9512 2.4082 3.2734 73 9219 o10155 3.1367 ~VP N C ~ b CGP~ D~© DEPT NCnb SP CG~ DEPT SP SP CGR DEPT SP DR~O NCbb SP CG~ SP NCNb SP CG~ DEPT SP NCi~i L SP DEPT SP NCN~ SP CGR VERiFiCATION 0,0305 CALl 2167,3008 FCN5 -;~R9,2500 URAi'q 87.953~ -58,6250 GR 0.015~ CALI 2!.74.0000 FCNL -999,2500 URAN 75.3643 7900.0000 SFbU -~2,3750 GR 0.0068 CALi 2338,4063 FCN~ -999,~500 URA~I ~1,2578 7~O0,OO00 SFLu -37,6563 GR 0,0i22 CALI 2522,0000 FCNL -999.2500 [.IRAN 74.9375 7700,0000 SFL[i -38.7~13 GR 0.0059 CAbl -~99.2500 UAAN b9,2457 7600,0000 SFLU -31,3906 GR 0,0039 CALl 2604 0000 -999:2500 ORAN 57,7422 7500.O000 SFLU -32,4063 GA 0,0t68 CALl 2539,u250 FCNI~ -999.2500 URA~ 68.~90b 7aO0,O000 SFLU -34,a437 GR 0 0195 CALi FCNb 2..46~0000 · -999.2500 ORAN 5S.3672 94,i2!9 ~PHi -999,2500 $GR 6!4,8437 DT 3.66Q9 THOR 2.2090 85.734~ NPHi -999,2500 SGR 630.0000 DT 2,3267 THUR 1.9922 ib~ 74,0000 NPN£ -999.2500 SGR 693,53!3 DT 2.~23~ THOR 2,7656 IL~ 67.67!9 NPHI -999,2500 SGR 778,5009 DT 2,11!3 ~HOR 2,4902 IbM 82,0156 ~PHi -999,25~0 SGR 673,50(.10 DT 3,12~0 THOR 2.6523 Ibi,'~ a 65,6406 ~PH! -999.2500 SGR 785,50o0 bT 2,2051 THOR 2.7070 ib~~ 71.6406 NPHI -99q.25OO SGR 765.~906 DT 2.529~ THOR 2.3359 ibm ~3.4~53 NPH~ -999.2500 SGR 777.5000 PT i.8359 T~OR 35.9436 RHOS 116.6875 ~RAT 87,5156 GR i3'4648 POTA 2,6797 ILO 35,6934 92.7813 GR 11.7830 P~TA 2,4102 33,0170 80,3750 NRAT 93,3750 GA 8,746! PO?A 3,3242 IbD 32,4707 RHOB 91,8125 SEAT 91,2344 GR 11.0430 POTA 3,0000 ILO 35,6445 R~OB 92.53~2 NRAT ~..3~25 GR 10,7734 PDTA 3.1973 IbP 32.2756 RHClB 75.1875 N~AT 89.I~75 G~ 8,3750 POTA 3,2578 ILO 32.5294 RHOB 88,0000 ~RAT 91,7~56 GR 9.8770 ~OTA 2.9297 iii. 6406 75,1~75 9~ .7S~3 GR 10,0645 POTA PAGC 2,4523 3,3015 94.~219 0,0236 2 525~ 2:t355 3,2871 85,2344 0,0203 2.2500 2.3962 7 0000 0.0182 3 1289 2i]770 3 1230 67.~719 0.0212 2.8496 2 i082 3i2852 82 0156 0.0188 3 0078 2~363'3 3 1113 65;6406 0.9167 3 052'~ 3.i289 71,b~06 0.0211 2.'74ql 2 3848 . 3,0703 63,4453 0,0126 COtlFtD .l 5VP ()~O.HOj VEMIFiCATIO~i DiSTING PAGE 10 DEPT 7300,0000 SFLU 2,1239 SP -30,3438 GR 69..~594 DRBO 0.0137 CAL~ -999.~500 SGR NCNL 2534,9000 FCN~ 773,0000 DT $~ -999 2500 URAN 2,0605 THOR CGR 62[7344 DEPY 7200,0000 SFLLI 2.4043 SP -29.0781 GR 62.t453 DR~O 0.0~66 CAbI -999,2500 NCNb 2652.0000 FCNL 793.5000 DT SP -999,2500 U~A~ 2,0~20 ThOR CGR 56.7S9! DEPT 7100.0000 S?'hU 2,734~ IL~ SP -~3,3750 GR 77,2056 NPHI DRHO 0,0278 CALI -999.2500 8GR NC~L 2772,0000 FC~L 818,5000 DT SP -999,~500 URAN 2.4346 THOf~ CGR 70.7314 DEPT 7000.~000 SFLU 2.3165 SP -33.0938 GR 73.3750 DRHO 0,0238 CALl -999,2500 ~N? 778,~12~ DT SP 999:2500 URA~ 2,250~ THOR CGR 63,1924 DEPT ~900,0000 8FLO 2,2773 ILN SP -12,~359 GR 75.~844 ~PHi DRHO 0,0221 CADI -999.2500 $G~ NCNL 2510,2500 FC~L 737,0469 DT SP -999.2500 U~A~ ~.t4~5 THOR CGR 68,703i DEPT 6800.0000 SFLO 2.6523 SP -11.6406 G~ 73,~0~i3 DRHO 0,0313 CALl -999.2500 NCNL ~490.0000 FCNL 7~2.5000 DT S~ -999,2500 U~ 2.4492 CGR 65.6~06 DEPT 6700.0000 SFLG 2.3125 IL~ SP -il.6094 GR 71,2813 DRMO 0.015~ CALl -999,2500 NCN~ 2~36,0000 FCNL 723.5000 DT SP -~9.2500"u (IRAN 2.31~5 TMOR CGR 64.9219 DEPT SP NC~[~ 'I6.3281 GR 75:7196 NP}~I 0,ul~7 CALl -999 2500 SGR 2312 ~1~5 FCNL 700.9570 DT 2,8594 ILD 39,5215 RHOB '7~,8750 NR~T 93,7656 G~ ~,9453 POTA 3.0547 ill) 32.8125 RMOB 71.1250 NRAT 95.0938 GR 9,6309 POTA 3.4395 34,2285 RMOB 89.3164 93,3125 GR 9,57t6 POTA 2,816~ ILD 33,t~51 RHOB 80.6621 NRAT 92,8594 GR i0.3972 POTA 2.9434 IbD 3~,204! RHOB 87,8750 FRAT 95,2656 GR 10.3~57 POTA 3.3125 lbo 31.4453 RHOB 85.8125 NRAT 95,0313 GR 10,6504 POTA 3.0098 34.9i21 RHOB 81.8125 NRAT 97,5~25 9.5176 3.I34~ '"" A ~ ~...) 34 . 9007 RHOB 90,1250 NRAT 99.718~ GR 2 5855 2!3672 3 2227 69,3594 0.0188 2.9258 2 3555 3:1~84 62.4453 0,0133 3.2539 23 4141 ~2051 77 2656 2,7051 2.4018 3.1699 '73,3750 0,0157 2 8281 2!3457 3 2t68 75 .~8~4 0:0190 3 2168 2i3477 3 0566 73.4063 0,0~67 I:8535 3574 3 2441 7ii281~ 0 0188 3.0025 2,3321 3.2~35 75.7158 LVP SP CGR SP CGR DEPT SP NC~L SP CGR DEPT SP DR~Q NCNb SP CGR DEPT SP DRHO NCNb SP CGR DEPT SP DRHO NCNb CGR DEPT SP DRH£) N C r~ I: CGR DEPT DRHO NCNL SP DEPT Ol~.HOi VE~IFICATID~ -999.2500 ORAN 66.8~37 6600 0000 SFLO -1818594 GR 0.0479 CA[,I 2290.0000 FCNh -999.2500 URAN 69,8367 ~O0.0000 -15.3438 GR -0,0015 2356.0000 -999.2500 64,1719 6300.0000 $F50 -21,1094 GR 0.0229 CA4I 2204,53i3 ~C,~ -999,2500 UR~N 80,2969 6200.0000 -25,5000 GR 0.0271 CALI 2170,0000 FC~b -9~.2500 6100.0000 SFbU -24.515~ GA 0,0244 CALI 21~6,0000 FC~L -999,2500 URA.~ 72,~375 5000,0000 SFL~ -25,8750 GR 0,0229 CADI 2280~0000 FCNL -999.2500 j~AN 72.1250 ~900,0000 SFLU -27.2813 GR 0.0i71 CASi i954.0313 FCNL -999,2500 73,2089 58o0,o000 SFLU -28,i094 GR 3,12!I THO~ 2.4668 74.71~ NPHi -999.2500 638.0000 DT 2,81~8 THOR 2.0898 67.7969 ~PHI -999,25o0 SGR 623.0000 DT 2,66~0 THOR 2.3926 78.9531 -999.2500 SGR 642.9219 2.4512 1,9189 IL~ 76.1406 NPMI -999.2500 SGR 579.6250 DT 3.0137 T~OR 1.5420 I4~ 72,3906 ~PHI -999.2500 SGR 520.0000 DT 1,8223 THOR 1.9805 Ib~ 71.0'625 NPHI -999.2500 SGR 606.00n0 PT 1,68~9 TMOR 1.97!7 75.6563 -999,2500 SGR 502,~063 DT 2.3547 THOR 1.6260 71.5000 NPHI 10.4~54 POTA 3.164t ILD 38,4766 90.4297 NRAT 102,4531 9.750~ POTA 2.8008 38.2813 84.0625 ~RAT I02,1719 GR 10.1055 POTA 2.9297 35,3241 98,1875 NRAT 104,42i9 GR 11.6465 POTA 2,42i9 40.0757 R~OS 94,0625 ~RAT I06,1094 GR 1!,7793 POTA 1.9023 iLO ~3 0176 86.1875 NRAT 107.9219 GR 12,0488 POTA 2,6~41 iLO 39.9902 RNOB ~3.6875 NRAT 110.0938 GR 11.2891 PGTA 2.5703 IbP 42.6472 R~[]B 9!.568~ NRAT i07,2187 GR 11.9450 POTA 2.3828 42.0410 RHOB PAGE 0.0186 3.0781 2.3066 3 4414 0.0225 2.6895 2.2988 3.43!6 67.7969 0.0173 2.7148 2.3505 3.2081 78 9531 0;0244 2 4063 2i3257 3 §322 76 1406 0.0194 1.8193 2.2871 3.6953 72.3906 0.0176 2.6348 2.2930 3.5254 71.0~25 0.0197 2 5098 3 674 75 6563 0'.0185 2.3633 2,2852 (;ONFII)ENTi.4L bVP 010.~i0i VERIFICATION D1STIMG PAGE 12 DRHO NCNb SP CGR DEPT SP DR~O NCN~ CGR DEPT SP DRH~ NCNb SP CGa DEPT SP DRHO NCNL SP CGR DEPT SP DRHO NCNb SP DEPT SP DRHO NC~L SP CGR DEPT SP D R H 0 NC~ L SP CGR DEPT SP SP CG~ 0.0361 CALl 2224,0000 FCNL -999,2500 5700.0000 SF~LU -30.5625 GR 0.O117 CADi 2306.0000 -999.2500 ~3.0583 5600.0000 SMLU -9,7969 GR 2202,0000 FCMb -999,2500 UEAa 68,42Q9 5500.0000 SFL~ -13,5938 G~ 0.0029 CALl 2250,0000 -999,2500 52,~135 5400.0000 SFbO -25,3438 GR 0,038~ CALl 2202 0000 FCML -q99:2500 URA~ 75.5730 5300.0000 SFhO -14.8516 GR 0.0337 CAUl 2054.0000 FCNL -999,2500 IJRAN ~6.7651 5200.0000 SFLU -26.5938 GR 0.0313 CAbI 2064.0000 FCN5 -999.2500 Oaa~ 64.0677 -18.3~38 GR 0. 0741 CALI 2250. bO00 FC~L -999.25oo -999.2500 SGM 574.0000 ~ 52V3 T~ 2.0430 71.71~8 NPHi -999,2500 8GR 647,5000 DT 1.7253 THOR 1.5537 IbM 71.3905 NPM! -999.25{~0 SG¢ 59~.0000 DT 2.3809 TMOR 1.9043 Ib~ 01.0469 NPHi '~. -999 ~500 635.0000 2,38!8 T~O~ 2,1621 IL~ 74,3281 -999.2500 SGR 618.0000 DT 3.29~4 THOR 1,97g5 Ii~$ 70.7031 NP~I -999.2500 SGR 545.5000 DT 2.40!4 THOR 2,3633 Ib~ 71.5313 NP8I -999,2500 SGR 595.0000 DT 2.6277 THOR 90.1875 107.734~ 11.8203 2.7363 37,5000 76.1187 104,4219 9,8O03 2.i484 40.7227 U5.8633 108.5313 10.6580 2.4551 38,8672 68.9805 1ii.5625 8.8370 2.7930 35.79i0 100.4i80 lo8.4688 10,9333 2.6250 39.7949 85,6563 108.5313 io.7~89 3.1d02 35.7188 U5.027~ i10.2344 9.6892 3,2480 36,7584 72.6875 6,7285 NRAT POTA ILD iqRAT G~ POTA ILD NRAT GR POTA ILL RhOB NEAT G~ POTa I L D GR POTA ILD NRAT GH POTA ILD RHOB NRAT GR POTA N~AT 3.6406 '11.5000 0.0i82 2 ~090 2i 813 3 3887 71.7188 0.0168 2.1543 2.2832 3 5684 7I:3906 O,OIBB 2.4~68 2 2q02 3:4648 6~ 0469 o:o .25 2,7988 2.3555 3.2930 7~ 3281 0:0227 2.7070 2.3066 3.5156 70 7031 o2o 7 3 2734 3 3438 0.0178 2!3223 3 3482 65.9219 0.01'17 L, VP DEPi' SP DRH[J NCNL CGR SP DRHO NCSL SP DEPT SF D R H O NC~ L SP CGR DEPT SP DRMO SP CGR DEPT SP DRHG NCNn SP CG~ DEPT SP NC~::L SP COa DEPT SP NCNL SP CGR DEPT SP DRgO SP 010.~{01 VErsIFICATiON 5000.0000 S~LO -o4.~125 GR 0.0272 2517,0000 FCNL -999.2b00 URAa 39,1016 4900.0000 SFL~ -26.0938 GR 0.0650 CALl 2156,4063 FCN& -999.2500 URAN 60.~950 4800.0U00 SFLO '76.3125 GR 0,0039 CALl 2518,0000 FCNL '999,2500 LIRAS 53.3203 q700.0000 SFLU -38.8125 GR 0.0029 CALI 21U4.0000 FCNL -999.2500 U~AN 54.2031 4600. 0000 SFLU -80.8125 0.0099 CALl 2534 3750 ~: CNb -999] 2500 35,0938 4500 ~' ' ,u000 SFDU -20.6094 GR 0.0260 CALl 2075.5000 FCNL -999.2500 URAN b7.2i63 6400.U000 8FLJ -61.8750 GR 0.0024 CALl 2406.0000 FCNL -999.2500 URAN 44.0586 4300 . 0000 SFLi3 -71,1250 GR 0. 0061 CALl 2447,2~13 FC~ -999. 2500 [.IRAA~ 5.5234 39.21~7 -999.2500 689.3438 OT 0,7754 THOR 2.8066 68.3594 -999.2500 ~GR 594.2500 DT 2,4875 THOR 4.9492 53.4219 -999.2500 SGR 685.5000 DT 1.1621 TMOR 3.0~79 55.5703 -999.2500 586.0000 DT 3,0430 T~OR 5,2617 35.6328 -999.2500 711.3750 DT 1.I680 TiiO~ 2,6934 Iba 67.2656 NPHI '999.2500 573,6~75 DT 2.7952 5.2148 49.8906 -999.2500 654.5000 DT 1.0918 4.4805 IL~ 38.9219 NPaI -999.2500 SGR 685.$$94 bT i.0798 TMOR 3.1602 37.6904 45.8437 N~AT 122.0313 6,4072 PGTA 3.6465 IbD 3~.4743 RHOB 80,2559 NRAT 109,7656 GR 9.6537 POTA 7441 R~OB 63. 3750 bRAT 121.578i GR 7.6230 POTA 41,7969 R~OB 7~.0000 bRAT 117.2813 GR 9.4629 POTA 1,9004 %4.593~ i~RAT 125.4688 GR 6,3311 POTA 2.9727 32,7474 77,2256 bRAT 115.5625 9.5632 POTA 2.8203 39.0i37 52.6563 bRAT 96.1250 GR 7.1831 POTA 2.2227 ILO 39, !113 R~OS 46.5273 bRAT 126.3750 GR 5. 3522 POTA PAGE 2.6309 2.1163 3 3982 39!2187 0 0100 3.7832 2.3107 3.4432 68.3594 0.0159 2.1270 3 4004 5314219 0.0164 5723 3.6270 55.5703 0.0126 ! ,4512 2~0891 3 i4215 35 6328 2.8379 2,2317 3.4580 67 2656 o:o 4 2.2813 2.1465 8906 0.0103 1.8457 23 0~80 :4v s 38.9219 0.0119 13 CONfiDENtiAL LVP Oiu.!ioi VERiFICATiON 5ISTING PAGE 14 CGR DEPT SP DRUID NCnb CGR DEPT SP DRHO NC~B SP CGR DEPT SP DRHO NCNL SP CGR DEPT SP DRhO NCNb SP Cge DEPT SP DRHU NCNL SP CGR DEPT SP DRHO NC;~L CGR DEPT SP DRHb NCNb SP CGR SP 4200.0000 SFb~ -82.3~25 GR -0.00~5 CALl 2560,0000 FCNL -999,~500 URA~ 26,7297 4100.0000 SFLO -34.6250 GR -0.0034 CALI 2372.0000 FC~b -999.2500 URAN 52.35Q3 4000.0000 SFLU -28.0469 GR 0,0042 CALl -999~2500 46.2407 3900.0000 SFLi3 -13.0547 GR 0.0241 CALl i~b8.1875 FCNL -999.2500 UR{N 53,9687 3800.0000 SFbU -24.07~1 GR 0.0047 CALl i821.7813 FCNL -999.~500 URA~ 5~.4014 3700.0000 SFLt] -37.5625 GR -0.0029 CALl 2216.0000 FCNh -999.2500 UR~N q1,~557 3600.00n0 SFL(; -21,a2al G~ -0,0394 CALl 1352.0469 FCNL -999,2500 URA~ 15.3500 3500.0000 SFL~ ~38.~I25 4.9414 ~'~ 29.5898 NPHI -999.2500 SGR 710.0000 DT 1..i326 T~OR 2.~250 IbM 48.2813 NPHi -999.2500 SGR 654,5000 DT 0.7754 THOR 2.7637 Iha 47.7422 NPHi -999.2500 6GR 588.8672 DT 1.6647 THOR 2.5371 Ib~ 71.5469 -999.2500 452.3906 DT 1,4i21 T~O~ 3,i973 1~ 64,57@1 -999,2500 421,6406 DT 2.7207 T~iOa 3.6855 IbM 48.8359 NPHI -999.2500 SGR 568,0000 DT 1.~2Q2 T~OR 21,7969 2.3,0781 ~ . 0~% -999 25u 251,9052 D~ i,2967 THOa 5.10Q4 Ii~ 45.7109 N~HI -999.2500 SGR 2,2324 ~bD 36,6211 RHOB 37,4023 NRAT i26,4689 GR 4,2431 POmA 2.382~ 1SD 41,5039 RaOB 58.2290 NRAT 124.018i GR 7.7622 POTA 2.7129 41.8232 RHOB 5B.6704 NRAT 122.3906 5.2088 POTA 3.4590 !bP 49.7772 R~OB 14,2500 NRAT i41.28.!3 GR 9.3320 POmA 3,9961 ILD 50.7080 RNOB 77.B691 NRAT 13'7.6250 GR 9,7120 POTA 4.3516 ILD a2.773~ 57.6760 NRAT 145,9062 GR 6.4055 POTA 14,2578 IhD 57.1i58 RHOB 25.9a05 NRAT .144.968'1 GR 1.8335 POTA 5.9375 ~5.8055 52.7500 1.8u57 2.0781 3.3398 29 5898 o:oo6 2.1445 2 1152 3!6094 48 28~3 0.0i49 2,5q49 2.i070 3.6296 47 7422 3,6211 2,1857 4.0690 5469 4.1094 2.1381 4.1210 64.5781 0.0146 4.0625 2 1016 3~6816 48 8359 o'.o116 14 9453 1~3879 5 0320 23~0781 0,0052 5.9844 2.0675 3.8507 NCNb SP CGR D~PT SP NCNb SP CGR DEP'[ SP DRHO NCmL SP CGR 19~1.2500 FC~L -999.2500 ORam ~6,0~25 3400.0000 SYLO -24,8125 GR -0,0054 CAb1 1921.3750 FCNL -999,2500 URAN 81.4219 3300.0000 SFLO -23,0625 GR 0,0054 CALi 1.817,0000 FCNL -999,2500 URA~ 58,1592 DEDT 3200,0000 SFL¢ SP -~7,3438 GR DR~iO -0,005'1 CALl NC~L 22!0 2969 FCNG SP -999:2500 URAN CGR 43,i265 DEPT DRHO NC~?~h CGR DEP~ SP DR~ NCNL SP CGR DEPT SP DR~O NC~L SP CGR DEP~ SP NCNL D£PT 3100,0000 SFLU -37,0938 GR -0,0053 CALl 1982,7500 FCNL -999,2500 URAN ~3.2109 3000.0000 SFbU -47.7500 GR -0.0068 CALl 2248,0000 PCND -999.2500 URAN 2~,35~5 2900.0000 SFLO -34,0625 G~ -0.0018 CALi 2014,~375 FCNb -999,2500 URAN 51,6274 2800.0000 SFLO -31.828i GR 0.0000 CALI 1946.0000 FCNL -999,2500 URA~ 47,6563 2700,0000 SFLO blSTING 487.78i3 D~ 0.8091 THOR 75.5156 NPHi -999.2500 SGR 453.2578 DT 2.3926 THOR ~.~258 7'4,~6~.8 -999.2500 430,0000 DT 3,4534 THOR 6,2578 l~h~ 46,2364 NPH! -999.2500 SG~ 587,0625 DT 1.2424 THOR 44,I71,9 NPHI -999,2500 SG~ 506,12~I DT 0.9463 THOR 5.558~ in~ 32,8047 ~!PHi -999,2500 SGR 571,0000 DT 1.6084 TMOR 5.9023 Ib~ 49.539~ NPHI -999.2500 SGR 500,1562 DT 1.4131 THOR 6,23O5 5~.4375 -999,2500 SGR 49~.0000 DT 2.6836 THOR 5.8203 iLM 151,9687 5.7832 5,9570 8,9917 9.i875 128,5i56 9,1035 5,8945 52,8809 84.7109 142,5313 9.2092 7,7188 ~2,2340 51.8291 169.5313 6,0007 7.0664 43.7866 5i,78t3 132,9062 6.0010 7,6563 43,8477 33,6563 169,9062 2,7896 7,3906 44,0750 62.3691 134,1250 9.2087 7,839U 43,3594 68,5525 131.2187 7.1504 7.i914 GR POmA NRAT POTA NR~T GR RHOB NR,~T GR PtJTA !LD RHOi~ NRRT GR POTA RHDB NR~T GR POTA NR~T GR POTA NR~T 46,7109 0.0154 6 0781 2:1707 4,0259 75 5156 0:0176 6,3672 2,1641 4.2422 4 4688 70~0151 8,2422 2,0332 3,6516 46 234~ o:o13 7 2383 3 369 44,i719 0,0133 8,5469 7~02 32,8047 0,0074 7.5234 2.1171 3.7539 49.5391 0.0105 8 2 1 3:7148 58.4375 0.0135 7.3398 15 CONFIDENTIAL VERIFICATION LISTING P~GE 16 DRHO NCNL SP SP NCNL SP CGR DEPT SP DRHO NCNb SP CGR -38.3125 GR 0.012i CAbI 1808.5313 FCNL -999.2500 URAN 5i.6505 26U0.0000 SFLU -36.2500 GR 0.0121 CALi 739.1953 FCNL 999.2500 ORAN 45.0172 2500.0000 SFLU -36.6250 GR -0.0015 CALI 1554.0000 FCN5 ~999.2500 URAN 42.5025 DEPT 2400,0000 S~bO SP -~9.0313 GR DRHO 0.0209 CALI NCNL 1468.4531 FCND SP -999.2500 URAN CGR ~2.5235 DEPT SP DRHO NCN~ SP C~ DEPT SP DRHO NCNL CGR DEPT SP CGR DEP~ SP NCN& SP CGR 2300.0000 5FLU -54.1875 Ga 0.0415 CALI !306.3438 FCN5 -64,I875 URAN 43.0391 ~200,0000 SFLU 132.5000 GR -0.6460 CALI 14~8.0000 FCNL -132,5000 URAN 28.5894 2100.0000 SFbU -126,8125 GR -0,7148 CA5i 1373,0000 FCNb -126,8125 URAN 36.9607 2000.0000 SFLU -108.9375 GR -999.2500 CALl -999.~500 FCNb -10~.9375 URAm -999.2500 55.3203 NPMI -999.2500 SGR 416.8437 O~ 1.5171 THOR 5.9062 lh~ 51.6797 NPHI -999.2500 SGR 402.3203 PT 1,0321 THOR 6,4727 60,8125 -999,2500 331,75n0 Df 4.4872 THOR 5.7656 ILM 44.71~ NPH£ -999.2500 346.5000 Df 1.9277 THOR 7.9648 !~a 45.7266 NPHi -999.2500 SGR 280.914i D'~ 1.454I THOR 8,3281 ibm 38,5625 NPHI -999.2500 SGR 3~4.7500 DT 0,7905 THQR !O,17~.g 45,6563 NPHI -999,2500 SGR 303,0000 DT 0.6960 5.5938 IbM 55.007g SPHl -999.2500 SGR -999.2500 DT -999,25o0 THOR 46.6890 RH~IO 64.26t7 N~AT 7.1 7 ~ 2 PD'rA 7,9336 InO 48.4962 RHOB 57.9771 NRAT 136,2500 GR 6,8443 POTA 7.5000 ISD 53.3691 RHOB 77.3i25 NRAT 144.0938 GR 6.794~ POTA ~.1094 1SD 50.34!8 ~HOB 57.3906 NRAT 145.0525 GR 6.9t42 POTA 8.0313 I~D 61.2259 R~[)B 54.31~5 NRAT 143,7500 GR 6'8086 POTA 8.1484 54.6387 33.4683 144,2813 3,4859 8.4922 57.3730 ~i.7i00 NRAT 146.4063 5.5235 POTA 6.4i80 -999.2500 -999,2500 r~RAT 152.9375 GR -999.2500 POTA 2.1353 3.8995 55.3203 0.0141 8.0000 2.1260 4.0000 0122 8 1797 1~5654 4.2695 60,8125 0.0110 8.5547 1.6801 4.1016 44.7188 0.0107 8.1875 2 0215 4~7053 45 726~ 0~0115 8.2187 2.0664 4 3398 38~5625 0,0096 8 8125 4.t883 45.b563 0.0110 6 5211 -999[2500 -999.2500 55.0078 -999.2500 LVP O'LO.HOi VERIFICATION DE?T 1900.0(!)00 SFLW SP -i49.0000 dR DR~{[) -999.2500 CALl NC~L -999.2500 FCNb SP -149.0000 URAN CGR -999,2500 DEP~f 1800.0000 SFLU SP -38.6563 GR DRNO -999.2500 CAbi NC~[. -999.2500 FCNL SP -38.6563 Ua~a CGR -999.2500 DEPT i700.0000 SFLU SP -51.%688 GR DRaB -999,2500 CALl' NC~L! -~99,2500 FCNL SP 51,468~ URAN CGR -999.2500 D~P~J -999.~500 CALl NCi~h -999, 500 FCNL SP -43.4063 URAN CGR -999,2500 DEPT 1500.0000 SFLU SP -55.3750 Gk DRHO -999.2500 CALl NCNL -999.2500 FCNL SP -55,3750 URAN CGR -999.2500 DEPT 1~0.0000 SFbO Sp 4~7500 GR DR~O :999.2500 CALl NCNb 999.2500 FCNL SP -64,7500 U'~ ~ CGR -999.2500 DEPT 1300.0000 SFLU SP -81.0625 GR DRi'{E! 999 2500 CALl NCi~i,., :999~2500 FC~b SP -81.0625 UR~N c~ -999.2500 DEPT 1200.0000 SFL~ SP -63.7500 GR DRNG -999.2500 CALl NCNL -999.2500 FCNL LISTING 7.0234 42.6641 -999.2500 -999.2500 -999.2500 THOR 9.7578 ISa 54.5075 SPFI -999.2500 SGR -999.2500 DT -999.2500 THOR 28,0781 i9.85u2 ~PHI =999.2500 -999,2500 DT -999.2500 THOR 9.5156 82.9844 -999.2500 SGR -999.2500 bT -999.2500 ~HOR 26.9062 62.1562 -999.2500 SGR -999.2500 -999.2500 36.7813 IL~ 51.5234 ~PMi -999.2500 -999.2500 DT -999.25n0 TMO~ 93.9375 40.17!9 aPMi -999.25o0 -999.25~)0 ST -999.25o0 T~OR z9.35:t Iaa 61.117~ NPHI -999.2500 SGR -999.2500 DT 6.8594 ILO -999.2500 RMOB -999.2500 NRAT .159,2187 GR 999.2500 PgTA 9.7578 -999.2500 RMOB -999,2500 NRAT 154.0625 GR -999.2500 POTA 26.359'4 IDP -999.2500 RHOB -999.2500 NRAT 133.53!3 GA -999.2500 POTA 9.6719 !bP -999.2500 RMOB -999.2500 NRAT 163.6875 GR -999.2500 POTA 28. 6094 ILD -9~ 2500 RMOB -9~ :25oo .~A'£ 111. 1406 GR -999.2500 POTA 36.5313 IbP -999.2500 RHOB -999,2500 NRAT 112.7813 GR -999,2500 POTA 43.5000 IbP -999.2500 RHOB -999.2500 N'RAT 94.2~13 GR -999.2500 POTA 29,5781 -999.2500 RHDB -999. 2500 1ii ,o313 PAGE 17 6.9219 -999.2500 -999.2500 42 6641 -999~2500 9.9609 -999.2500 -999.2500 54.5078 -999.2~00 30.3906 -999.2500 -999.2500 49.8672 -999.2500 10.0156 -999.2500 -999.2500 82.9844 -999.2500 32.2500 -999.2500 -999.2500 62.1562 -999.2500 51.5000 -999 2500 -999i2500 51 5234 -999.2500 82.6250 :_999i2500 999 2500 40 171.9 999 2500 42.9375 -999.2500 -999 2500 CONFIDENTIAL LVP O!O.MO1 V~RIFICATiGN LISTING PAGE 18 CGR DEPT NCnb SP CGR DEPT DR~O NCN[, SP DEPT NCNb $? S? NCNb CGR DEPT SP DRHO NC~b CGM DEPT SP DRhO NCML DEPT SP NC~L SP CG~ $? -63.7500 -999,2500 1100.0000 SFLU -82,1250 GR -999.2500 CALl -999,2500 FCNb -82,1250 URAN -999.2500 1000.0000 SFLO -81,5625 GR -999.2500 CALl -999.2500 FCLL -81.5625 gRAM -999.2500 9(;0,0000 SFbU -95,9375 GR -999'2500 CALl -9~9.~500~ F'CNb -95.9375 URAN -999.2500 800.0000 SFLO -i17.5625 GR '999.2500 CALl -999.2500 FCNL -117.5625 URAN -999.2500 700.0000 SFLU -99 2500 CALI -999.2500 FCNL -137,1250 URAN -999.2500 600.0000 SFLU -149.3750 GR -999.2500 CALI -999.2500 FCNL :Iq9.3750 U~AN 999.25O0 500.0000 2FbU -56,562~ GR -999,2500 CALl -999,2500 FCNb -999.2500 400.0000 SFLU. -14.~609 GR -999.2500 ~MOR 1008.5000 Ih~ 28,5820 ~eHi -999.2500 ~GR -999,2500 DT -999.2500 T~O~ I763.0000 Ib~ 34.0234 NP?il -999.2500 5GR -999.25a0 DT -999.25o0 ~'HOR 51.0000 56.8516 -999.2500 SGR -999,2500 DT -999.2500 THOR 255.00OO 44.5547 -999.2500 -999.2500 DT -999.2500 T~OR 11.1875 IbM 49.3i25 NP~i -999,2500 -999,2500 DT -999,2500 71.$750 IbM 28.2070 NP~¢I -999,2500 SGR -999.25O0 DT -999.2500 TMOR 16.0938 lba 42.6563 NPHi -999.2500 SGR -999,2500 O'r -999.2500 THOR 51.uO00 iL~ 43.1.~06 NPM! -999.2500 POTA 75.0000 IbP -999.2500 RHOB -999.2500 NRAT 82,7i88 GS -999.2500 POTA 84.3750 -999,2500 -999,2500 78,4375 GR -999.2500 POTA 45,2187 ILD -999.2500 RHOB -999.2500 NRAT 104.2656 GR -999,2500 POTA 66.6250 -999,250'0 RHOB -999.2500 ~RAT 90.2656 GR -999.2500 POTA 9.6250 -999.2500 -999.2500 NRAT 1i3.0313 -999.2500 POTA i9.8594 ILO -999,2500 RHOB '999.2~00 NRAT i58,8750 GR -999,2500 POTA 11.8984 ILD -999,2500 RhOB -999.2500 NRAT 147.8i25 -999.2500 P~TA 13,7734 -999.2500 RHOB -999.2500 487 7500 -999 2500 -999 2500 28 5820 -999 25OO 455 7500 -999[2500 -999,2500 ]4.0214 -999.2500 83.3750 -999,2500 -999.2500 56.8516 -999.2500 i'19.8750 -999 2500 -999~2500 44.554'1 -999.2500 13,7188 -999 2500 -999~2500 49.3125 -999.2500 68.6875 -999.2500 -999 2500 -999.2500 20 8594 -999~2500 -999.2500 42.65~3 -999.2500 25.2813 -999.2500 LVP 0i0.~01 VERIFICATION LISTING DRanO -999.2b00 CAbI NCNL -999.2500 FEN5 SP -14,460~ URAN CGR -999.2500 -999.2506 SGR -999.2500 -999.2500 THO~ DE?T 3gU.00~O SFL, U BP -13.4766 DRNO -9~9.2500 CALl NC~g5 -999.2500 SP -i3 4766 URAN CGR -999~2500 421,7500 Ib~ 37.5761 NP~i -999.2500 SGR -999.2500 DT -999.2500 THOR DEPT 200.0000 SFLU BP -55.1250 GR DRHO -999 2500 CALl NCNb -999:2500 FCNh SP -55.1250 URAN CGR -999.2500 36~,2b00 45,3203 -999.2500 -999.2500 DT -999,2500 DEPT 100.0000 SFLU SP ~8.6563 GR DRHO -999.2500 CAbI NCNb -999,2500 FC~L SP 48.6563 URA~ CGR -999.2500 21.5547 ~P~I -999.2500 -999.2500 DT DE..i' 80,5000 SFLU SP 36 6563 GR DR~O -999~2500 CAbI NCNL -999.2500 FCb~h SP ~6.6563 URA~ CGR -999.2500 23.2070 NPHI -999.2500 SGR -999.2500 DT -999.2500 THOR FIbS ~ A ~,~ E :SERVIC,001 SERVICE NA~E VERS!CIq D~TE : MAXIMUm4 b~]NGTH : 1024 FILE i~PE : NEXT FILE NAME ** 'rAPE tRAILER ** SERVICE NAME :$YRVIC DATE :82104/ 3 ORIGIN :1070 TAPE ~E :62675 CONTt~UATIO~ ~ NEXT ~APE NA~E : CO~E~TS :TAPE COM~ENTS -999.2b00 NRAT 142.6875 GR -999.2500 PL,~A 53.7500 IbP -999.2500 ~HOB -999.2500 NR~T 82,4688 GR -999.2500 POTA 75.9375 -999. 2500 RHOB -999. 2500 NR.AT 9519375 GR -999.2500 PLATA 2000.0000 -999.2500 -999.250'0 N~AT 49.4375 -999.2500 POTg 2000.0000 ILD -999.2500 RMOB -999.2500 N~AT 240.7813 G~ -999.2500 P[]TA PAGE -999.2500 43.I406 -999.2500 483 0000 -999:2500 -999.2500 37.5781 -999.2500 356.0000 -999.2500 -999 2500 45~3203 -999.2500 27 0156 992500 . 21. 5547 999.2500 27 8906 -999 2500 -999.2500 19 CONFIDENTIAL LVM OiO.HO1 VERIFICATION LISTING PAGE 20 DATE :~2/~;4/ 3 ORIGI~ : REEL nAME :REEL ID NEX~ RCEG t']A~E : COMmEnTS :REEL ********** gOF