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Home My WebLink About176-014David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: Hilcorp North Slope, LLC Date: 05/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well Name PTD Number API Number PBU NGI-05 176-014 50-029-20196-00-00 Definitive Directional Surveys (Composited) -Gyrodata Re-Survey 05/01/2025 Main Folder Contents: Please include current contact information if different from above. 176-014 T40431 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.19 14:37:58 -08'00' 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU NGI-05 Replace Production Csg & Tubing Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 176-014 50-029-20196-00-00 9404 Conductor Surface Production Tieback Liner 8623 81 2689 8391 1291 9313 20" 13-3/8" 9-5/8" 7" 8542 30 - 111 30 - 2719 27 - 8418 8108 - 9399 30 - 109 30 - 2719 27 - 7748 7475 - 8619 Unknown 520 2670 4760 7020 none 1530 5380 6870 8160 8807 - 9231 7-5/8" 29.7# x 7" 26# 22 - 7941 8092 - 8469 Structural 7" Baker SABL-3 7837 , 7989 / 7241 , 7372 Bo York Operations Manager David Bjork David.Bjork@hilcorp.com 907.564.4672 PRUDHOE BAY, PRUDHOE OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final 13.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: CBL ADL 0028302 7" Camco A-1 22 - 7330 2133 / 2133 9-5/8" x 13-3/8" IA Pump 175 bbls of 15.3 ppg cmt and displace with 155 bbls 9.8ppg brine. FCP = 1011 psi 321-618 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2021 Submit Within 30 days or Operations Sr Res Eng: 7837 , 7989 7241 , 7372 L-80 By Meredith Guhl at 2:22 pm, Jul 19, 2022 Digitally signed by Bo York (1248) DN: cn=Bo York (1248), ou=Users Date: 2022.07.19 12:57:53 -08'00' ACTIVITYDATE SUMMARY 12/19/2021 T/I/O = SSV/0+/vac. Temp = SI. PPPOT-T (PASS) (pre rig). PPPOT-T: Stung into test port (0+ psi), bled void to 0 psi. Function LDS, 3 LDS are stuck to the gland nuts 4,5,6:00 positions. The whole assembly will turn. Single port, unable to pump through void. Pressured void to 5000 psi for 30 min test, lost 150 psi in 15 min, lost 50 psi in second 15 min (PASS). Bled void to 0 psi. Phaze 2, will return later to cycle LDS on IC void. 12/20/2021 T/I/O = SSV/0+/vac. Temp = SI. Function LDS on casing hanger (pre rig). Stung into IC test void (0+ psi), bled to 0 psi. Function LDS on casing hanger, all functioned normally. Torqued LDS to 600 lb/ft, gland nuts to 450 lb/ft. Did not PT test void as per Kevin Krause. 2/11/2022 ***WELL S/I ON ARRIVAL*** HES 759 R/U ***CONT WSR ON 02/12/2022*** 2/12/2022 ***CONT WSR FROM 02/11/2022*** HES 759 WEATHER HOLD FOR -44* TEMPS ***CONT WEATHER HOLD ON 02/13/2022*** 2/13/2022 ***CONT HES 759 WEATHER HOLD FROM 02/12/2022*** HES 759 WEATHER HOLD ***CONT HES 759 WEATHER HOLD ON 02/14/2022*** 2/14/2022 ***CONT HES 759 WEATHER STANDBY FROM 02/13/2022*** HES 759 WEATHER HOLD FOR TEMPS ***CONT WEATHER HOLD ON 02/15/2022*** 2/15/2022 ***CONT HES 759 WEATHER STANDBY FROM 02/14/2022*** HES 759 WEATHER HOLD ***CONT WEATHER HOLD ON 02/16/2022*** 2/16/2022 ***CONT HES 759 WEATHER HOLD FROM 02/15/2022*** HES 759 WEATHER HOLD ***CONT WEATHER HOLD ON 02/17/2022*** 2/17/2022 ***CONT WEATHER HOLD FROM 02/16/2022***(pre-rwo) END WEATHER HOLD, R/U HES 759 DRIFT W/ 6.05" GAUGE RING TO 2,184' MD PULL 7" DB DSSSV (3 SETS OVER-SIZED PACKING) @ 2,184' MD (all packing recovered) DRIFT W/ 5.85" DUMMY WELLTECH TBG-CUTTER TO 8,024' MD ***WELL LEFT SI*** Daily Report of Well Operations PBU NGI-05 Daily Report of Well Operations PBU NGI-05 3/2/2022 ***WELL SHUT IN ON ARRIVAL*** (TUBING CUT) MIRU HES E-LINE RIH W/ WELLTEC TBG CUTTER BHA. CORRELATE TO TBG TALLY 6/9/99. ATTEMPT TO CUT TBG AT 7981' ( 3' BELOW TOP OF 10' PUP ABOVE PACKER) CCL-CUT=24.3', CCL STOP=7956.7' HAD LOTS OF STALLS TRYING TO CUT IN HIGH PRESSURE MODE. SWITCH TO LOW PRESSURE TO GET CUTTING PATTERN STARTED. SWITCH BACK TO HIGH PRESSURE MODE TO CUT. CURRENT EVENTUALLY ~ FLAT LINED LIKE IT WAS FREE-SPINNING AND NO LONGER CUTTING. ATTEMPT TO CUT TBG FOR ~ 3HRS WITH NO DOWNHOLE OR PRESSURE INDICATIONS. RELEASE ANCHORS & POOH. AT SURFACE TATTLE SHOWED KNIVES WENT OUT TO 7.286" AND DID NOT CUT ALL THE WAY THRU THE 7-5/8". 1-KNIVE WAS CHIPPED AND OTHER 2 WORN DOWN. RIG DOWN ELINE. WELLTEC WILL PERFORM A TOOL INSPECTION & RE- GROUP. ***JOB NOT COMPLETE / ELINE WILL RETURN TO CUT TBG*** 3/5/2022 Set 6" K BPV #607, would not pass LTT. Set test dart, LTT passed. Perform passing 500 psi low PT and failing 3500 psi high PT. Pull test dart and BPV. Set 6" K BPV #612, LTT BPV (Pass), set Test Dart, PT'd against Test dart 350/3500 PSI for 5 minutes (Pass). Pull test dart and BPV. RDMO. 4/18/2022 ***WELL S/I ON ARRIVAL, DSO NOTIFIED***(tubing cut) CUT TUBING AT 7983'. CCL TO CUTTER OFFSET: 23.8'. CCL STOP DEPTH: 7959.2'. CORRELATED TO TUBING TALLY RECORD DATED 9-JUN-1999. NO PRESSURE CHANGE AFTER CUT, POSSIBLE FILL ON THE BACKSIDE. PUH 1' AND FUNCTION CUTTER TO VERIFY THAT CUTTER DID NOT STALL. TATTLE TALE ON CUTTER INDICATED A MAX TRAVEL OF 7.94", WELLTEC CONFIRMED THAT CUT WAS SUCCESSFUL. ***WELL LEFT S/I, SECURED AND TURNED OVER TO DSO*** 5/18/2022 T/I/O=200/0/0 Set 6" K BPV. LTT [PASSED] 5/19/2022 T/I/O= BPV/0/0 ND Upper Tree. Install Second MV. Torque to API spec. Shell test 500 low, 5000 hi (Pass) ***RDMO*** 5/20/2022 Pull 6" K BPV. RDMO 5/24/2022 T/I/O = 220/0/0. Temp = SI. Bleed WHPs/B & C lines to 0 psi (Pre RWO). B-line = 300 psi. C-line = 300 psi. TBG FL @ near surface. Bled TP to BT from 220 psi to 0 psi in 4 hrs (gas/fluid mix, 4.5 bbls). SI TBG bleed and monitor for 30 min. TP increased 30 psi. Bled to 0 psi in <3 min. Final WHPs = 0/0/0. B & C lines = 0 psi. SV = C. MV = O. IA, OA = OTG. 5/24/2022 T/I/O = 300/10/10. Temp = SI. Bleed WHP's / C & B Lines to 0 psi ( Pre RWO ). C&B line pressure = 300 psi. Bled IAP to BT from 10 psi to 0 psi in < 5 min (gas). During bleed OAP decreased 10 psi. Will need drill scoffolding to bleed TBG. Dry hole tree installed. Final WHP's = 300/0/0. SV = C. SV = O. IA, OA = OTG. 12:45 Daily Report of Well Operations PBU NGI-05 5/25/2022 T/I/O = 60/0/0. Temp = SI. Bleed WHPs/C & B lines to 0 psi (Pre RWO). C & B lines = 50 psi. Bled TP to BT from 60 psi to 0 psi i <1 min. Maintained open bleed on TBG for 30 min. SI TBG bleed and bled C & B lines to 0 psi. Monitor for 30 min. TP increased 40 psi. Bled to 0 psi in <1 min. Held open bleed for an additional 1 hr. SI TBG bleed and monitor for 30 min. TP increased 30 psi. Bled o 0 psi in <1 min. Final WHPs = 0/0/0. SV = C. MV = O. IA, OA = OTG. 02:15 5/27/2022 T/I/O = 50/vac/vac. Temp = SI. Bleed WHPs/C & B lines to 0 psi (Pre RWO). C & B lines = 5 psi. Bled TP to BT from 50 psi to 10 psi in 5 min. Fluid came to surface and bled TP for another 20 min, would not bleed below 10 psi (returned .25 bbls). SI TBG bleed and bled C & B lines to 0 psi in <1 min. Monitor for 30 min. TP increased 30 psi. Final WHPs = 40/vac/vac. SV = C. MV = O. IA, OA = OTG. 16:00 5/29/2022 T/I/O = 55/vac/vac. Temp = SI. Bleed WHPs/C & B lines to 0 psi (Pre RWO). C & B lines = 3 psi. Bled TP to BT from 55 psi to 10 psi in < 30 min (SI when fluid came to surface). Would not bleed down past 10 psi. Bled C & B lines to 0 psi in <1 min. Monitor for 30 min. TP increased 30 psi Final WHPs = 40/vac/vac. SV = C. MV = O. IA, OA = OTG. 16:30 5/30/2022 T/I/O = 35/VAC/VAC. Temp = SI. Bleed TP (pre RWO). Wellhouse, scaffold, flooring removed. Dryhole tree & rig mats installed. T FL near surface. Bled TP to BT to 20 psi in 2 hrs (gas). No monitor. Final WHPs = 20/VAC/VAC. SV = C. MV = O. IA, OA = OTG. 22:30 5/30/2022 T/I/O = 49/VAC/VAC. Bleed TP (pre RWO). Wellhouse, scaffold, flooring removed. Dryhole tree & rig mats installed. T FL near surface. Bled TP to BT to 14 psi in 3 hrs (FTS). Continued bleeding TP until TP increased to 33 psi (0.1 bbl). SI to allow TP to stackout. Bled TP to 9 psi in 30 min (gas). No monitor. Final WHPs = 9/VAC/VAC. SV = C. MV = O. IA, OA = OTG. 05:00 5/31/2022 T/I/O = 20/0/0. Set 6" K BPV, Set Test Dart, PT against Test Dart 250/4000 PSI for 5 min (Pass). Test Dart left in BPV. RD SV, Installed Tree cap Assy. RDMO. 6/2/2022 Check void and SMR's for pressure. Remove SMR flanges, Install SMR plugs and blind flanges. N/D DHT. Clean void, inspect TBG HGR neck and verify lift threads w/ XO. Function all LDS. (4"out). Replace (3) LDS. Assist N/U BOP. S/B for BOP test. Wells Support attempt to pull "K" plug dart w/ lubricator failed. Travel to valve shop and pick up T-Bar adapter. Attempt to pull test dart, failed. drain stack, pull test dart. Lubricate out "K" plug. RIH w/ XO to drill pipe. M/U to TBG HGR. BOLDS. Pull TBG HGR to rig floor. Terminate (2) 1/4" control lines. Lay down TBG HGR. 6/3/2022 T/I/O=0/0/0 I-Rig Pull 6" K-plug and Dart. T-bar Dart out. RU Lubricator w/ 12' extentions. PT Lub w/ rig. RIH pull 6" K plug #612 at 155". POOH. while rigs tugger pulled up wedged plug in dutch riser. pulled dutch riser and lubricator. rigged down plug then set dutch riser down. ***RDMO*** 6/7/2022 *** Innovation RIG Support *** (CAST-M) Logged CAST-M from 7140'-7975' and surface to 3000'.' Estimated top of cement at 2616'. ***Job complete*** Daily Report of Well Operations PBU NGI-05 6/8/2022 RWO: Nipple down Grey Gen 2 tubing spool, remove 9-5/8 slips and packoff & install new tubing spool. Observed 9 5/8¿ csg was 5 ft. down in well and not engaged in the slips. Remove slips from casing head, nipple up new tubing head with BOP test plug installed, rig crew to nipple up and test BOP. RDMO. Tubing head LDS clear bowl at 5-1/2 in. GV center to LDS Center 12 in 6/13/2022 Verify CSG OD. Center 9 5/8" CSG in CSG HD. Wrap slips. Verify tension on CSG string. Set slips w/ 62k weight in slips. (well plan called for setting 100k weight in slips...unable to acheive due to CSG patch seal integrity). Mark cut off on CSG. S/B for welder to make cut and bevel. Prep stump for install of P/O, Grease P/O seals. Set P/O, S/B for BOP N/U. R/U test equipment and test P/O compression seal/flange connection 500/3800 for 10 min ea. Test P/O ID/OD seals to 500/3800 for 10 min ea. Good test R/D test equipment and bleed off pressure. Verify correct Upper test plug. 6/17/2022 Installed 6¿ J TWC #403 in hanger ahead of landing, dope 7¿ TC-II pin on X/O, M/U L/J to 7¿TC-II x 13-1/2¿ hanger 7-1/2 RH, M/U to string, Weatherford casing torqued up, mark IA verification on hanger body 12¿ below LDS ramp, RIH keeping centered in stack via tuggers, land on 21.35¿ RKB, look through IA valve, verify landed by seeing verification mark in C/L of IA, RILDS tag hanger, torque gland nuts 600 lb/ft, torque LDS 600 lb/ft, B/O L/J, test against blind rams 3500psi. ~ 5 min w/ IA valve open, good test, bleed off, S/B for rig crew to C/O rams & N/D stack, clean void, ring groove, & TWC profile, ensure that J plug R/T will M/U completely into profile, install new BX-160, fill void w/ hydr. fluid, P/U new THA, clean & inspect seal areas, land THA, install (16) new 1-5/8¿ studs & nuts, rig crew N/U THA, then install 7¿ dry hole tree on THA, rig crew hammered up, test void 500 psi/10 min. low & 5000 psi./10 min. high, good tests witnessed by company man Steve, bleed off, R/D, fill tree, rig tested 500 psi./10 min., 5000 psi./10 min., good tests, bleed off, pull tree cap, pull 6¿ J TWC #403 w/ T-bar, secure well, hand off to rig for circulating, etc. 6/18/2022 Freze protect tbg & IA with 140 bbls DSL 6/18/2022 T/I/O=0/0/0. Post I-Rig Reconnect. Installed 6" CIW upper tree with Baker acutator. Torqued flanges to API spec. Pressure test tree against MV to 300/5000 psi for 5 min ea. Passed. Reconnected flowline and blowdown lines and Torqued to ANSI spec. Installed tree work platforms and set wellhouse. ***Job Complete***. 6/18/2022 ***INOVATION RIG ON WELL***(rig assist) RAN 4.55" BELL GUIDE W/ 2" RS TO 7,871' SLM (rig currently preping to set packer) ***CONT WSR ON 6/19/22*** 6/19/2022 ***CONT WSR FROM 6/18/22*** (rig assist) PULLED B&R AND 7" PR-RHC FROM 7,872' MD (unable to pressure up) SET 7" PR-PLUG IN R-NIPPLE @ 7,872' MD SET 4.60" CENT PRONG IN PLUG @ 7872' MD. RIG PERFORMED PRESSURE TESTS. ***RIG ON WELL UPON DEPARTURE*** Daily Report of Well Operations PBU NGI-05 6/21/2022 ***WELL S/I UPON ARRIVAL*** (rwo expense) PULLED 7" PR-PLUG FROM R-NIPPLE @ 7872' MD. ATTEMPTED TO PULL PRONG FROM 7" PRN-PLUG, SD HIGH ON TUBING STUB @ 7,984' SLM MADE 2 RUNS W/ 10' x 3.0" PUMP BAILER TO 7,993' SLM (recovered ~1 band, 1/2 gal steel & aluminum pieces, f.neck) ATTEMPTED TO PULL PRONG FROM 7" PRN-PLUG @ 7,994' SLM (unable to latch) ***CONT WSR ON 6/22/22*** 6/22/2022 ***CONT WSR FROM 6/21/22*** (rwo expense) MADE 2 RUNS W/ 10' x 3.50" PUMP BAILER, 7,995' SLM (recovered 1/4gal fill, several metal pieces) MADE UNSUCCESSFUL ATTEMPT TO LATCH PRONG @ 8,000' SLM MADE 9 RUNS W/ 10' x 3.0" PUMP BAILER (inline 3.50" cent) FROM 7,995' SLM TO 7,999' SLM (recovered 6gal fill, metal banding & aluminium chunks) ***CONT WSR ON 6/23/22*** 6/23/2022 ***CONT WSR FROM 6/22/22*** (rwo expense) RAN 7" BRUSH, 3.75" 3 PRONG GRAB TO 7,999' SLM (no recovery, bent tips) RAN 5.14" CENT, 3.63" LIB TO 8,001' SLM (impression of possible debris) RAN MULTIPLE FISHING BHA'S FROM 8,001 TO 8,005' SLM (recovered multiple C/L bands and multiple pieces of C/L) ***CONT WSR ON 6/24/22*** 6/24/2022 ***CONT WSR FROM 6/23/22*** (rwo expense) MADE 11 RUNS W/ 3.0" AND 3.50" PUMP BAILERS FROM 8,003 TO 8,005' SLM (recovered multiple metal bands, C/L pieces, 8gal fill) MADE 2 RUNS W/ BARBELL SPEAR FROM 8,003 TO 8,008' SLM (recovered of C/L & bands) ***CONT WSR ON 6/25/22*** 6/25/2022 ***CONT WSR FROM 6/24/22*** (rwo expense) RAN 7" BRUSH, 4.54" GAUGE RING TO8,014' SLM MADE 12 RUNS W/ MULTIPLE BAILERS FROM 8,005' TO 8,023' SLM (recovered metal, c/l, c/l bands, 20.5gal fill/cement) RAN 7" BRUSH, 4.54" GAUGE RING TO 8,023' SLM ***CONT WSR ON 6/26/22*** 6/26/2022 ***CONT WSR FROM 6/25/22*** (rwo expense) MADE 4 RUNS W/ 10' x 3.50" PUMP BAILER TO 8,024' SLM (recovered 4gal fill, tt pins sheared) PULLED P-PRONG FROM PRN PLUG @ MADE 6 RUNS W/ 10' x 3.0" PUMP BAILER (3.50" inline cent) FROM 8,022' SLM TO 8,024' SLM (recovered 4gal fine fill) ***CONT WSR ON 6/27/22*** 6/27/2022 ***CONT WSR FROM 6/26/22*** (rwo expense) RAN 10' x 2.25" PUMP BAILER (3.50" inline m2m cent) TO PLUG BODY @ 8,024' SLM (slung shot and r/s clipped on tubing tail) FISHED COMPLETE 40' TOOLSTRING FROM 7,993' SLM MADE 7 RUNS W/ MULTIPLE BAILERS TO 8,025' SLM (recovered 2gal fill) ATTEMPTED TO PULL PLUG BODY @ 8,025' SLM (unable to latch) RAN 2.50" HYDROSTATIC BAILER TO 8,027' SLM (recovered 1/2gal scale flakes and fine fill) ***CONT WSR ON 6/28/22*** Daily Report of Well Operations PBU NGI-05 6/28/2022 ***CONT WSR FROM 6/27/22*** (rwo expense) ATTEMPTED TO PULL 7" PRN-PLUG FROM 8,024' MD (unable to latch) RAN BARBELL 5.12" CENT, 3.60" LIB TO 8,026' SLM (impression of fill) RAN 7" BRUSH TO PLUG BODY @ 8,026' SLM (binds) MADE 8 RUNS W/ VARIOUS BAILERS FROM 8,023' SLM TO 8,030' SLM (recovered 4gal of fill) JARRED ON PLUG BODY W/ 5 1/2" GR FOR 5min @ 8,028' SLM (sheared) ***CONT WSR ON 6/29/22*** 6/29/2022 ***CONT WSR FROM 6/28/22*** (rwo expense) PULLED 7" PR-PLUG BODY FROM 8,024' MD (missing center oring and 2 pieces of packing) ATTEMPTED TO SET 7" R-LOCK (5.962") A-1 INJECTION VALVE IN SSSV NIPPLE @ 2,133' MD RAN 7" BRUSH, 4.50" GAUGE RING TO 5.962" SSSV NIPPLE @ 2,133' MD SET 7" A-1 INJECTION VALVE IN SSSV NIP @ 2,133' MD ***CONT WSR ON 06/30/2022 6/30/2022 T/I/O = SSV/VAC/30. Temp = SI. OA cement top job. Bled OA to 0 psi in ~ 1 min. Monitored OAP for 1 hr. OAP increased 0+ psi. Removed Tapped Blind on OA CV on 6:00 side & blind/ VR plug on on 12:00 side. Mixed 2.5 gallons of Fine Cem concrete. Poored cement into OA until water was evacuated and cement overflowed and was consistant (2 gallons). Monitored for 30 min to verify cement did not fall out. Swabbed excess cement from CV & VR port. Re-installed blind on OA CV 6:00 side & VR plug/ blind on 12:00 side. Tourqued flanges to 543 ft lbs. Pressure tested to 4250 psi. Final WHPs = SSV/VAC/0. 16:00. 6/30/2022 ***CONT WSR FROM 06/29/2022*** CONT HES 759 R/D ***WELL LEFT S/I ON DEPARTURE, PSD OP NOTIFIED ON WELL STATUS*** 7/4/2022 T/I/O=3343/285/45 AOGCC MIT IA PASSED to 1843 psi ( Witnessed by Bob Noble ) Pump 1.6 bbls 150* diesel down IA to 2229 psi ***See log for results***. Bled back 2 bbls to FWHPs=3350/275/46 7/5/2022 ***WELL S/I ON ARRIVAL*** PULL 7" A1 INJECTION VALVE FROM SSSV NIPPLE @ 2,133' MD ***CONT WSR ON 07/06/2022*** 7/6/2022 ***CONT WSR FROM 07/05/2022*** SET 7" A1 INJECTION VALVE (HYS-426) IN SSSV NIP @ 2,133' MD ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED ON WELL STATUS*** 7/7/2022 State tested. passed following SSSV c/o Activity Date Ops Summary 6/1/2022 Blow down steam system and de-energize air system. Disconnect remaining interconnects. Prep all stairways, walkways and rooftops for move. Unplug and remove break shack. Remove cuttings tank. Jack up jeep mod and install jeep. Jack up pipe shed. Raise outriggers and stompers on sub base and turn.,NES trucks on location at 09:30. Split all rig modules. Begin walking sub base off AGI-03. Begin transporting pipe shed and cattle chute to NGI.,Cont. to move sub base off AGI-03. Turn sub and install rear tires. Install front tow bar. Transport all modules to NGI pad and stage. Spot sub base over NGI-05, shim and level.,Spot all remaining modules. Release NES trucks at 22:15. Connect interconnects. Turn on steam, air and water.,Work on rig acceptance checklist. Safe out walkways, stairways and rooftops. Install cellar grating. Spot and berm cuttings tank. Scope up derrick and bridal down. Secure and inspect derrick. Hang rig tongs. Sim Ops: dress shakers and prep pits for bringing on fluid begin loading 4" drill pipe. Rig Accepted at 03:00,Check pressures: IA/OA on vac. Tubing 0 psi. N/D tree: Bleed and terminate 2 control lines and install blind flanges. Break studs on tree flange. Install lifting cap on tree. Hook up tugger, attempt to lift tree unable to. Connect slings to TD and attempt to pull 20K over. Start heating flange and mobilizing flange splitter6/2/2022 Use flange spreader to pop tree loose. Pick up with top drive and set down. Attempt to remove studs, unable to due to rusted/seized. Cut and remove studs with Portaband. Check 7" BTC XO in hanger (9 turns). Check lockdown screws and change out 3.,N/U BOPE. Install DSA, move BOPE stack from pedestal and N/U on DSA. Install cross chains. Align stack and install flow riser. Install hole fill lines. Install accumulator lines. Begin torqueing DSA/BOP bolts. Obtain RKB's. SimOps: Move shop and pusher camp from AGI to NGI. Perform cross ehad inspection on MP #2. Cont. to load 4" DP.,Cont. torqueing choke/kill lines and BOP to DSA flange. SimOps:assist NC cat mechanic with generator repair. Assist NES welder with crack repair under shaker #2,C/O UPR's to 2.875" x 5.5" VBR's. Inspect ram door cavities. Sim Pops: take apart HCR kill and replace bonnet seal.,R/U to test BOPE's. M/U test joint, Locate rams on joints. Set 7-5/8" test joint in hole and M/U valves. Flood and purge lines. Shell test to 4,000 psi - good.,BOPE test 250/4000 psi on 4" and 7-5/8" test joints. AOGCC Austin Mcleod witnessed. Test gas alarms, PVT alarms and flow. F/P on annular, function and re-test good. Drawdown test: starting pressure 3050 psi, final 1500 psi. First 200 psi recharge 30 seconds, full recharge 101 seconds. (6) N2 at 2291 psi average.,R/D testing equipment. Roll up hoses. Break down valves and clearn rig floor. Remove ts sub from top drive. B/D top drive, choke and kill.,Service rig: grease blocks, crown, spinners and top drive. Check gear and rotary oil.,Rig up Weatherford casing tongs, bring slips, DC, elevators to rig floor. Bring spooling unit to rig floor.,Set dutch riser and lubricator. Attempt to lubricate test dart x 2 - unsucessful. Source T-bar adapter. L/D lubricator. Attempt to engage test dart with T-bar, unsuccessful. Bring hoses to rig floor and back in vac truck. Suck out stack M/U T-Bar Pull test dart Rig up lubricator Lubricate out BPV6/3/2022 Rig down lubricator and dutch riser. R/D wells group tools and lines. L/D BPV,M/U XO to 4" drill pipe, and M/U to hanger. Pick up staging up from 230K to 300K and observe hanger unseat at 290K. Pull up to 300K and observe cut free. PUW 255K.,Displace wellbore to 9.8 ppg brine. Pump 50 bbls soap pill followed by 9.8 ppg brine staging pumps up to 5 bpm. ICP 420, FCP520 psi. No losses. Shut in and close choke, no pressure build.,Pull hanger to rig floor. Wellhead rep remove control line from hanger. Back out landing joint XO and unscrew top drive. L/D hanger and landing joint. B/D top drive and choke. C/O elavators. Monitor well on trip tank 2bph loss rate.,POOH with 7-5/8" tbg from 7983' (cut) to 7778'. PUW 220K, SOW 175. Observe vibration/shuddering from drawworks gear box.,Service rig: grease crown, roughneck, check rotary table gear oil. Sim Ops: Inspect drawworks gear box.,Cont. to inspect drawworks gear box. Remove cover and pump oil out. Remove sample line and swedge lock fitting from gear box. Observe bent/cracked tooth on one gear, as well as minor scarring from debris. Dressed affected teeth as per manufacturer recommendation.,Cont. to POOH from 7,778' to 7,084 with 7-5/8", NT-80, 29.7#, SL-T tbg. Attempt to pull 1:1 with control line. Pulled 20K over at 7,130'. Work pipe x 2 free. Observe control line pull tight at 7,084'. Give slack in control line and slack off on pipe without control line moving, indicated slack downhole. Attempt to spool up slack in control line while moving pipe up/down and with tugger assist.,Only 2 SS bands recovered thus far from below the hanger.,Cont. to spool up slack in control lines. Observe control lines spooling freely. Spool up control line.,Cont. POOH with 7-5/8", 29.7#, SL-T tbg from 7,084' to 5660'. Pull 20K overpull at 5700', pipe chattering. Drain stack and observe rats nest of SS control line at wellhead. Continue to POOH to 5660' dragging pipe through SS control line with up to 80K drag, decreasing. 2 of 55 SS bands recovered.,Daily disposal to G&I: 580 bbls, total= 870 bbls Daily H2O from Lake 2: 120 bbls, total=360 bbls Daily Metal: 0 Total 0 Daily DH losses 12 bbls, total 12 bbls 6/4/2022 Cont. POOH with 7-5/8" NT-80, 29.7#, SL-T tubing from 5660' to 2381'. PUW 120K, SOW 95K. Calculated displacement.,Service rig: grease TD, blocks, crown. Check gear oil on TD. Inspect gears on drawworks.,Cont. POOH with 7-5/8" NT-80, 29.7#, SL-T tubing from 2381' to 2010'. PUW 95K, SOW 85K. Calculated displacement.,Cont. POOH with 7-5/8" NT-80, 29.7#, SL-T tubing from 2010' to surface. PUW 95K, SOW 85K. Calculated displacement.,Rig down Weatherford tongs. Change out pipe handling equipment. Send spooling unit off floor. Clean and clear rig floor.,M/U fishing BHA: crankshaft rope spear. RIH to 45' and 76' multiple times, 140' recovering 33 pieces of SS bands (~27 full bands) and pieces of Cap line totally ~70'. RIH to 326' with no recover.,RIH with rope spear drifting and picking up drill pipe to 2530'. PUW 64K, SOW 66K. Rotate and reciprocate 3x from 2530' to 2515' at 10 rpms, 1Kft- lbs.,POOH with rope spear racking back drill pipe from 2,530' to surface. no recovery.,RIH with rope spear from surface to 2497' from derrick. PUW 66K, SOW 62K. Calc displacement. Set down 10K at 2,357' and 15K at 2,397'. Pick up and rotate down at 15 rpms, 1000 ft-lbs, only observing a 1-2K bobble.,Daily disposal to G&I: 30 bbls, total= 900 bbls Daily H2O from Lake 2: 0 bbls, total=360 bbls Daily Metal: 0 Total 0 Daily DH losses 0 bbls total 12 bbls6/5/2022 Cont. to RIH with rope spear from 2,497' to 6,542', drifting and picking up drill pipe from shed. PUW 109K, SOW 106K. Calc displacement. Reduced running speed of 40 fpm due to drawworks gearbox.,Cont. to RIH with rope spear from 6,542' to 7,896'. Tag top of 7-5/8" stump with 4K down x 2. Drifting and picking up drill pipe from shed. PUW 127K, SOW 120K. Calc displacement. Reduced running speed of 40 fpm due to drawworks gearbox.,Service rig: grease and inspect crown sheaves, top drive and blocks. Check top drive gear oil. Swervice and inspect iron roughneck. Remove drawworks gearbox cover and inspect gear.,POOH with rope spear from 7986' to surface. 1/4 of a SS band recovered. L/D Rope spear. Reduced running speed of 40 fpm due to drawworks gearbox.,M/U RCJB and XO's. RIH from surface to 830'. PUW 50K, SOW 48K.,Cont. to RIH with RCJB from 830' to 7192' from derrick. PUW 120K, SOW 113K. Calculated displacement. Reduced running speed of 40 fpm due to drawworks gearbox.,Daily disposal to G&I: 0 bbls, total= 900 bbls Daily H2O from Lake 2: 120 bbls, total=480 bbls Daily Metal: 0 Total 0 Daily DH losses 0 bbls, total 18 bbls6/6/2022 Cont to RIH with RCJB from 7192' to 7986'. PUW 125K, SOW 120K. Cacl displacement.,Tag tubing stump at 7986'. Pick up to 7966'. Establish circulation with RCJB activated and stage pumps up from 3-8 bpm, 20 rpms, 3Kft-lbs. Wash and ream x 3 from 7966' to 7986',POOH with RCJB from 7986' to surface. Reduce trip speed to 50 fpm due to damaged gear in drawworks gear box. Calc displacement. L/D RCJB - no recovery.,Cut and slip 100' of drilling line.,Service rig. Perform monthly sheave wobble EAM. check top drive gear oil. Service and inspect top drive, drawworks and iron roughneck.,M/U tubing hanger, XO and landing joint. Set hanger, attempt to back out landing joint. Backing out above XO. Pull tubing hanger and tq XO. Set tubing hanger. RILDS. Set poor boy dutch riser and lubricator. Lubricate in BPV. Dry rod in plug. Rig down lubricator,Break bolts and open all ram doors and inspect cavaties. C/O top seal on UPRs. C/O blind ram rubber seals on both sides. Install 9-5/8" solid body rams in LPRs.,Rig up testing equipment. M/U test joints. Flood stack and purge air.,Test UPR's on 4" test joint 250/4000 psi. Multiple LDS leaking. tighten LDS. Good test. L/D test joint. P/U 9-5/8" test joint.,Daily disposal to G&I: 0 bbls, total= 900 bbls Daily H2O from Lake 2: 0 bbls, total=480 bbls Daily Metal: 0 Total 0 Daily DH losses 0 bbls total 18 bbls6/7/2022 Test LPR's with 9-5/8" test joint, test blind rams. 250/4000 psi.,Suck out stack. Dry rod out test dart. R/U dutch riser and lubricator and pull K-BPV.,M/U 4" x 7" BTC XO to landing joint. BOLDS. RIH and pull tubing hanger. L/D landing joint and hanger.,Spot in and Rig up E-Line. Secure sheave at bottom of slide and in elevators.,M/U CBL Logging tools. RIH with logging tools to 7975. Log up from 7975 to 7140. Log upper section from 3000 to surface. R/D E- line.,M/U retrievable bridge plug. RIH to set depth of 2,554' (top of plug 2542'). PUW 65K, SOW 68K,Set RBP as per Baker hand with top of plug at 2542'. POOH to 2466'. Dump 2200# (~50') of sand down drill pipe. Pause and reciprocate pipe after every 10 sacks.,Service rig: grease/inspect top drive and blocks. Check top drive gear oil, good. Service and inspect iron roughneck. Clean and clear rig floor.,POOH from 2466' to surface racking back drill pipe. Calc displacement. Clean and clear rig floor.,M/U Baker multistring cutter as per Baker: XO, pump out sub, stabilizer, XO, multistring cutter (MSC),RIH with MSC BHA from surface to 1830'. PUW 56K, SOW 59K,Daily disposal to G&I: 57 bbls, total= 957 bbls Daily H2O from Lake 2: 120 bbls, total=600 bbls Daily Metal: 0 Total 0 Daily DH losses 0 bbls, total 18 bbls 50-029-20196-00-00API #: Well Name: Field: PBE NGI-05 Prudhoe Bay East Hilcorp Energy Company Composite Report 6/2/2022 Job Name:215-03750 PBE NGI-05 RWO Spud Date: 6/8/2022 TIH F/ derrick W/ 4 D.P. F/ 1,830 to 2,460 MD. P/U 62k SLK 67. No losses.,Locate 9.625 collar at 2,454.5 MD. Set cutter at 2,460 MD. Make cut 80 rpm, 8- 12k Trq 7 bpm, 1,450 psi W/ 21% R/F. Saw erratic Trq and SLK off about ¼ increments till TD stalled at 12k. Shut annular and lined up to OA taking returns to flow back tank. Verified circulation at 1 bpm 225 psi.,R/U Circ manifold on D.P. stump W/ head pin and LoTrqs. M/U to cement line and PT to 2,000 psi, good. LRS started displacing 9.625 X 13.375 OA W/ 25 bbls 150° F Diesel at 1.5 bpm 600 psi spotted in 4 D.P. Close annular and take returns F/ OA to flow back tank. LRS Cont pumping 145 bbls Diesel at 2 bpm 690 psi. LRS shut down and use rig pumps to pump 30 bbls 9.8 ppg brine in D.P. Shut down and shut in OA.,Allow Diesel to soak in 9.625 X 13.375 OA foe 1 hr. R/D Blow down and LRS.,PJSM Open OA to flow back tank and line up on rig pumps. Pump 43 bbls 9.8 ppg Brine 2 bpm 30 psi, pump 40 bbls Con Det soap pill, 65 bbls 9.8 Brine, 30 bbls Baraklean pill and chase W/ 170 bbls 9.8 ppg brine staging pumps up to 6 bpm 1,300 psi. Shut down verify no pressure and open annular. Close OA and blow down lines to flow back tank. Circ hole volume 9.8 ppg brine at 6 bpm 1,180 psi R/F 33%.,PJSM Monitor well 10 min static. Blown down TD, kill & choke. POOH rack back 4 D.P. F/ 2,434 to surface at 50 fpm. L/D Baker mutli string cutter and per Baker rep onsite. All cutters returned to surface with wear on top of cutters. P/U 64k SLK 66k. Went on high line power at 16:00.,M/U Johnny Whacker and flush BOPE at 15 bpm and 30 rpm. L/D Johnny Whacker. Blow down TD.,PJSM Drain stack. N/D Choke and Kill lines. Pull bushing and remove riser. Break bolts top and bottom of tubing spool. Leave lower flange 4 bolted. BOLDS on upper pack off and attempt to separate, only getting about a ½ of play. BOLDS on lower pack off and was able to separate well head and tubing spool. Pack off was a single piece not two pieces. P/U BOPE with DSA and set back on pedestal.,PJSM P/U tubing spool and set back in cellar by rear tires. Observed 9 5/8 csg was 5 down in well and not is ES. Manual removed pack off and emergency slips as per Vault reps onsite. Clean up well head and prep for new tubing spool. Bring in new tubing spool though side door on cellar.,PJSM P/U and install 13.625 5k Vetco Grey tubing spool as per Vault rep onsite.,PJSM Install test plug into tubing spool as per Vault rep. Set BOP and DSA unto tubing spool and Trq bolts 3300 ft/lb, well head 2200 ft/lb. Install choke and kill lines. Install trip nipple and air up boots. Secure BOP W/ chain binders and remove bridge cranes.,R/U test Equip. M/U XT39 test sub to TD. M/U side entry, 4 XT39 TIW & 4 XT39 Dart and set aside.,Install 9.625 test jnt W/ donut and head pin. Test LPR 9.625 Solid Body Rams 250/ 4000 psi for 5 min on chart. R/D L/D 9.625 test jnt. Reflood stack and purge air from choke manifold.,Daily disposal to G&I: 290 bbls, total= 1247 bbls Daily H2O from Lake 2: 120 bbls, total=720 bbls Daily Metal: 0 Total 0 Daily DH losses 0 bbls, total 18 bbls 6/9/2022 Cont testing BOPE W/ 4 Test Jnt 250 psi low/ 4,000 psi high 5/10 min on chart. Test 4 TIW XT39, 4 Dart XT39, upper & lower IBOP, Annular, UPR (2 7/8 X 5 ½ VBR), Blinds, HCR/Manual Choke & Kill, Mezz Kill, Choke Manifold 1-15, Super & Manual Choke 1,600 psi. Koomey draw down: Initial Acc 3,000 psi, Man 1,500 psi, Ann 1,300 psi, Final Acc 1,400 psi, Man 1,400 psi, Ann 1,400 psi. 200 psi increase 29 sec, full charge,105 sec. 6 bottle NO2 Avg 2,300 psi. F/P Manual Choke had to rebuild valve. Test high- & low-level alarms, H2S 10-20 ppm, LEL 20-40%. Witnessed waived by AOGCC rep Matt Herrera.,R/D test Equipment and break down test jnt. Blow down surface Equip.,Clean and clear rig floor. P/U Weatherford power tongs. Stage 250T side door elevators and 9.625 handling Equip. Stage Baker 9.625 casing spear.,PJSM P/U 4 D.P. and M/U 9.625 Csg spear as per Baker rep onsite. RIH 34 MD and engage 9.625 spear. P/U to 168k and observe csg movement. Pull 9.625 Csg to rig floor. P/U 157k SLK 89k. Set slips and release spear as per Baker rep onsite. Beak out 9.625 Csg cut jnt (3.6) with steam and hammering connection to break free.,PJSM M/U 9.625 X/O and 1502 Equip. R/U HP lines to flow back tank. Close Annular and line up OA on flow back tank. LRS pumped 145° F 150 bbls Diesel at 1 bpm ICP 275 psi FCP 800 psi at 2 bpm. Release LRS. Swap to rig pumps. Pump 40 bbls 9.8 Brine W/ Con Det, 40 bbls 9.8 ppg Brine, 35 bbls 9.8 ppg Brine W/ BaraKleen and 321 bbls hot 9.8 ppg Brine. Staged pumps up to 4 bpm 65 psi. Shut down and let soak for 1 hour.,Circ out Diesel and soap pills to flow back tank 3 bpm 115 psi to flow back tank. Verify 9.8 ppg Brine in and out. Press test well head and tubing spool flange to 500 psi F/ 5 min, good. Open Annular and blow down all lines. R/D X/O, 1502 Equip and flow back tank lines.,PJSM POOH W/ 9.625 Csg F/ ~2,427 to 2,130 MD. Having to steam and hammer every connection to get them to break free. Seeing break out Trq 30-40k. Found 2 bow spring centralizers while pulling pipe. P/U 132k SLK 115k.,PJSM POOH W/ 9.625 Csg F/ 2,130 to 1,855 MD. Apply trq W/ power tings and work with hammer every connection to get them to break free. Seeing break out Trq 30-40k. Cont removing bow spring centralizers. Observed swabbing and clabbered up returns.. P/U 102k SLK 92k.,Pull stripping rubber and R/U X/O, head pin and HP hose to mud manifold. Broke Circ at 2 bpm W/ 110 psi falling to 20 psi after pumping 6 bbls. Stage up pumps to 7 bpm 130 psi Max Gas 159u. Observed large increase in oily/ greasy returns at BU. Cont circ until clean brine was seen at surface. R.D circ Equip and install stripping rubber.,Cont POOH 9.625 Csg F/ 1,855 to 1,380 MD. Applying Trq W/ power tongs and working connection with hammer. Connection breaking out at 30-35k. Removing bow spring centralizers, appears to be every 4-5 jnts.. P/U 89k SLK 85k.,Daily disposal to G&I: 637 bbls, total= 1884 bbls Daily H2O from Lake 2: 120 bbls, total=840 bbls Daily Metal: 0 Total 0 Daily DH losses 0 bbls, total 18 bbls 6/10/2022 Cont POOH 9.625 Csg F/ 1,380 to 133 MD. Applying Trq W/ power tongs and working connection with hammer. Connection breaking out at 30-35k. Removing bow spring centralizers., P/U 40k SLK 40k. At 133' observed overshot patch on jnts 59/60. R/U rig tong extensions and break out jnt on top of overshot.,L/D cut 9.625 casing. L/D overshot patch. 2 centralizers removed (14 total). Appears 9.625 Csg fell on top of cut jnt down hole. Very large split in retrieved casing cut. May have left some down hole. Discussed options.,Clean and clear floor. Stand aside Weatherford power tongs, C/O elevators to 4. Clean arctic-pack F/ tools and rig floor.,P/U M/U baker tools. Stage baker cutter assembly and spear assembly on rig floor. Check OD, ID, and lengths of tools.,M/U cutter and spear as per baker rep. C/O cutter blades as per Baker rep. M/U cutter assembly under stand #1, M/U spear assembly in between stand #1. Baker rep engaged spear in ready position and taped secure.,Trip in hole W/ 4 DP out of derrick f/surface to 2,460 MD. Soft tag top of cut Jnt, set down to 5k. Rotated at 10 rpm Trq 644# and 20 rpm Trq 750# attempting to roll cutter Assy into 9.625 Csg cut. Was unable to pass through cut. Decision made to POOH to P/U a tapered mill assembly. P/U 64k, SLK 68k.,Trip out of hole F/2,461 to surface. L/D cutter and spear assembly as per baker rep. Did see any visual marking on cutter to indicate wear from Csg cut. P/U 62k SLK 64k. Canrig lost connection, working on restoring Canrig.,M/U Milling BHA as per baker rep. M/U 8.5 tapered mill, 2 ea Boot Baskets, X/O, XT String Magnet, LBS & Jar total BHA 48.21.,Trip in hole w/ milling assembly W/ 4 DP out of derrick F/ Surface to 551 MD. P/U 45k, SLK 48k.,Cont RIH W/ milling assy W/ 4" D.P. F/ 551' to 2,441' MD. P/U 66k SLK 69k. No losses. Canrig working again at 03:00.,Wash down F/ 2,441' to 2,496' MD at 0.5 bpm 15 psi. Did not see any drag at top of cut at 2,460' MD. Wash down to top of sand at 2,496' to 2,497' W/ 3-4k. Cont washing down F/ 2,497' to 2,498' MD 4 bpm 125 psi and saw a hard 5k tag suspected collar. Rotated at 5 rpm Trq 600-800# and continued washing down to 2,505' MD with 2-4k with weight on mill, no issue. P/U Above cut and pass through no Rot, no issue.,Rot & Rec 2,505' to 2,440' MD 7 bpm 290 psi Pump 40 bbl 120 vis sweep R/F 38%. Max Gas spiked to 855u at BU. Sweep back on time W/ sand. Monitor well 10 min, static.,POOH Tapered Mill Assy racking back 4" D.P. F/ 2,505' to 1,748'' MD. P/U 59k SLK 63k. No losses.,Daily disposal to G&I: 114 bbls, total= 1998 bbls Daily H2O from Lake 2: 120 bbls, total=960 bbls Daily Metal: 2# Total 2# Daily DH losses 0 bbls, total 18 bbls 6/11/2022 Cont POOH W/ Tapered Mill Assy racking back 4" D.P. F/ 1,748' to surf.,PJSM L/D 8.5" Tapered Mill, X/O, Bumper Sub, String Magnets and Jars as per Baker rep onsite. Recovered ~45# metal shavings. Boot Baskets empty. Clean and clear rig floor.,PJSM P/U M/U 7.75" OD Bull Nose, Multistring Cutter, X/O, 8.5" OD Centralizer, Pump Out Sub and X/O 16.09'. RIH W/ 4" D.P to 1,901' MD. P/U 58k SLK 60k. No losses.,PJSM Service rig. Grease Crown, Blocks, TD, IBOP, Washpipe, Spinners, Iron Roughneck and Drawworks. Check TD oil. Check cradle, no cracks. Add 2 gallons to rotary table. Remove hatch and inspect gearbox on Drawworks, no change.,Cont RIH W/ Multistring BHA W/ 4" D.P. F/ 1,901' to 2,500' MD. No issue getting into top of 9.625" cut at 2,460' MD. P/U 64k SLK 67k.,PJSM Stage up pumps to 3 bpm 225 psi to engage blades. SLK and locate 9.625" collar at 2,494' MD. Set knives at 2,500' MD, Rot 80 rpm Trq 930#. Stage pumps to 6 bpm 900 psi R/F 37%. Observed pressure increase to 1,420 psi then dropping to 1,060 psi indicating successful cut.,POOH F/ 2,500' to 2,495' MD. CBU at 6 bpm 1,172 psi R/F 37%. Max Gas 529u. Monitor well 10 min, static.,PJSM Blow down. POOH F/ 2,495' to surface. P/U 52k SLK 55k. No losses.,PJSM L/D Cuter BHA. All blades on Multicutter W/ little wear. P/U M/U ITCO Spear (8.681" Grapple), 6.25" Bumper Sub, 6.25" Jar and X/O total 26.58'. Engaged spear and tape in ready position as per Baker rep onsite.,PJSM RIH Spear BHA on 4" D.P. to 2,460' MD tag up and set 14k down. P/U 64k SLK 67k. Picked up and re entered cut at 2,460' with out issue. Cont slack down to 2,469' MD inserting grapple 19' into cut jnt. Picked up to 73k indicating fish on. Let Jars bleed for 20 min, no fire.,PJSM POOH W/ 9.625" cut jnt F/ 2,500' to surface Pull speed 20 ft/min. P/U 66k no slacking down.,PJSM Selt 9.625" slips and dog collar on cut jnt. Ture grapple assy 1.5 turns to right to release grapple. Pull and set grapple BHA aside. Set 4" strap around dog collar and L/D 9.625" cut jnt to shed. 9.625" cut jnt overall length 40.30', Cut jnt W/ collar 7.10'. Retrieved 1 bow spring centralizer. Slight Gas breaking out of cut jnt Max Gas 229u.,Top cut was staggered and bottom cut looked good slightly flared out. Break off L/D Grapple Assy and keep LBS & Jar.,PJSM Stage Baker polish and scrapper tools on rig floor.,PJSM P/U M/U 12" OD Dress off shoe, 11.75" Wash Pipe, 10.375" Dress of Mill, 11.75" Boot Basket, X/O P X P, 13.375" Csg Scrapper, C/O B X B, Float Sub (Flapper Valve), 6.25" LBS, 6.25" Jar and X/O total length 47.02' as per Baker Rep onsite.,PJSM RIH Polish/ Scrapper Assy F/ 47' to 1,558' MD. CBU every 500' while running in hole, 9 bpm 185 psi R/F 36%. Max Gas 471u. P/U 55k SLK 55k. No losses.,Daily disposal to G&I: 114 bbls, total= 2112 bbls Daily H2O from Lake 2: 120 bbls, total=1080 bbls Daily Metal: 40# Total 42# Daily DH losses 0 bbls, total 18 bbls 6/12/2022 PJSM Cont RIH W/ polish mill/ scraper on 4" D.P. F/ 1,558' to 2,472' MD. CBU every 500' RIH 9 bpm 250 psi R/F 38%. Max Gas 929u. P/U 70k SLK 65k. No losses.,CBU at 2,472' MD at 9 bpm 285 psi R/F 40% Max Gas 1,440u. Heavy clabber greasy/ sand at BU. Circ hole clean and gas falling quickly BGG 80- 100u.,PJSM Wash down F/ 2,472' to top of cut at 2,500' MD. Saw 1-2k bobble washing over cut. Start rotary 60 rpm and cont wash down over cut to 2,508' MD. Milled 1' past hard tag (5K) at 2,507' MD 9 bpm 300 psi 60 rpm Trq 2.5-8k R/F 40%. WT on mill 2-7k, Max Gas 324u. P/U over cut and ream back over 2X W/O issue. Rot Rec F/ 2,498' to 2,460' MD 12 bpm 400 psi Pump 25 bbl 100 Vis sweep bring back heavy greasy/sand at shakers.,Dressed top of cut to 2,501' MD.,PJSM Monitor well for 10 min, static. Blow down TD. POOH rack back 4" D.P. F/ 2,498' to surface. No losses. P/U 59k SLK 62k.,PJSM L/D dress off BHA and components as per Baker rep onsite. Wash out Boot Basket and recovered 5" piece of metal band and other metal debris (20#). Clean and clear rig floor.,PJSM Remove 4" elevators and install 9.625" 250T side doors. R/U 9.625" Weatherford power tongs and Equip. Stage 30 solid body bow springs on rig floor.,PJSM P/U M/U 9.625" Overshot as per Baker Rep onsite. P/U M/U ES Cementer W/ 4 ea 1/2 pins set for ~1,800 psi and 9.625" 47# L-80 Vam21 Csg to 489' MD. Trq to 21k ft/lb TXP and 31.5k ft/lb Van21. P/U 51k SLK 54k.,Cont RIH W/ 9.625" 47# L-80 Vam21 Csg to 489' to 2,500' MD. Trq Van21 to 31.5K ft/lb. P/U 123k SLK 128k. 31 total solid body bow springs and 2 ea stop rings. Verify 1 Centralizer left and 13 jnts in pipe shed.,Slack off and observed 1-2k bobble at 2,501'ndicating overshot patch going over 9.625" cut. Cont slacking down and saw 5K drag as seals engaged. Set down (127k) 92k string weight to engage seals. P/U 22k over string weight (150k) to verify seals engaged. Set in slips W/ neutral WT 128k as per Baker rep onsite.,PJSM P/U M/U Volant tool, X/O and HP cement lines to top drive. HES rig up truck and Equip.,PJSM PT cement lines to 2,000 psi, good. Pump down 9.625" Csg through Volant at 3 bpm ES Cementer shifted open at 1,835 psi and had return flow. Increase to 6 bpm 275 psi.,Cont Circ 6 bpm 275 psi at BU Max Gas 173u.,PJSM, Perform cement job: Wet lines w/ 5 bbls H2O (HES) 990 psi low kick out, 3,930 psi high, good. HES pumped 35 bbls H2O 1.95 bpm 122psi. 5 bbls 10 ppg spacer, VariCem 175 bbls 15.3 ppg Lead cmt, 1.25 yld, (786 sx) 3.9 bpm, ICP 360/ FCP 532 psi. Release from CRT & drop closing plug. Displace w/ 20 bbls H2O (HES) 5.5 bpm 443 psi then turn over to rig. Rig disp actual 155.4 bbls Calc 159.3 bbls W/ 9.8 ppg Brine,,6 bpm ICP 183 psi FCP 948 psi, reduce rate 5 bpm 130 bbls away ICP 957 FCP 1,011 psi. Reduced rate last 10 bbls to 3 bpm, ICP 931 psi FCP 931 PSI. ES Cementer shifted shut at 1,870 PSI. Held 2,319 psi for 2 minutes, check plug - good. CIP 03:20 hrs. No losses. Dumped 32 bbls of green cement.,PJSM Drain stack and fill W/ black water 3X and work Annular until clean. Break down cement lines and hook up bleeder. Flush cement lines and flow line W/ black H2O. Set slips and break out CRT. R/D Volant and X/O from top drive. Install 9.625" 250T elevators.,PJSM Blow down lines and drain stack. Suck out 9.625" Csg below well head. Hook up bridge cranes and remove cross chains. Let air out of boots on riser and disconnect hole fill line. Break BOPE bolts wellhead and lift stack. Install Vault centering tool and align as per Vault rep.,Daily disposal to G&I: 171 bbls, total= 2283 bbls Daily H2O from Lake 2: 240 bbls, total=1320 bbls Daily Metal: 42# Total 84# Daily DH losses 0 bbls, total 18 bbls 6/13/2022 Cont. N/D to Set Slips. Slack off to 97K, Set Emergency slips on 9 5/8" casing with 62K on slips. Remove Riser from stack.,Open LPR Doors and change out from 9 5/8" Rams to 7 5/8" Rams, close and tighten Doors.,NES Welder cut 9 5/8" casing. L/D Cut Jt (12.02'). Clean and Bevel Cut. Set Packoff and seat using BOPE. RILDS, TQ Stack Bolts to Spec, Test Packoff upper and Lower seals to 500/3800 psi f/10 min. SIMOPS: Remove Weatherford casing elevators, install 4" Elevators, Remove casing equipment from rig floor, install riser, air boots and hole fill line. P/U single and M/U Jonnie Wacker,Flush and jet stack with black water, remove Jonnie Wacker, set test plug, L/D single.,R/U Test Equipment, M/U 7 5/8" Test Jt, Flood and purge system, Test 7 5/8" LPR's to 250/4000 psi. R/D Test Equipment. Pull Test Plug and L/D Jt.,M/U Running Tool and install 9" ID wear Bushing. (OD 13.375") RILDS (4) Back out and L/D Running Tool.,M/U 8.5" Cleanout Assy with w/8.5" Tri cone bit, string mill and 2 boot baskets, Bumper sub and Jars.,TIH with Clean Out assy on 4" DP from Derrick to 2,416' MD P/U 64k SLK 67k,Encountered cement stringers, Wash and ream F/ 2,416' to closing plug at 2,449' MD. 450 gpm 600 psi 50 rpm Trq 1k WOB 3-5k R/F 41% P/U 64k SLK 67k ROT 65k,Drill plug, & ES on depth at 2,451' MD Cont drilling to 2,454' MD chasing plug 400-450 gpm 600-750 psi 50 rpm Trq 1-3.5k WOB 2-9k R/F 41% P/U 64k SLK 67k ROT 65k.,Dress ES W/ string mill F/ 2,468' to 2,447' MD as per Baker rep. Ream though 2X W. slight 1k bobble on first pass. 2X without ROT out pumps, clean. 450 gpm 740 psi 70 rpm Trq 1k R/F 41% P/U 64k SLK 67k ROT 65k,Wash down tag top of sand W/ 3k at 2,504' MD. Wash and ream F/ 2,504' to 2,510' MD. Circ hole clean seeing sand/ greasy returns at shakers. BU Gas 403u. 500 gpm 900 psi 50 rpm Trq 600 ft/lb P/U 66k SLK 69k ROT 64k. Leaving top of sand at 2,510' MD, 32' above 9.625" RPB at 2,542' MD.,PJSM Monitor well 10 min, static. POOH rack back 4" D.P. F/ 2,504' to surface' MD, P/U 55k SLK 57k. No losses.,PJSM Break out boot baskets, X/O, string mill and LBS/Jar as per Baker rep onsite. No wear string mill and bit grade 1-1 same as went in. From boot baskets retrieved pieces of aluminum face from shut off plug, 4" piece of bow spring, light amount of metal shaving and 4 pieces of brass. L/D BHA. Stage RCJB BHA on rig floor.,PJSM P/U M/U 8.5" RCJB W/ 1" ball installed and finger baskets (16.03') as per Baker rep onsite.,PJSM RIH W/ RCJB Asy W/ 4" D.P. F/ 16' to 2,472' MD. P/U 65k SLK 70k,Pump at .5 bpm 45 psi and wash down F/ 2,472' to 2,513' MD and light tag top of sand W/ 3k. Cont washing sand at 252 gpm 1,140 psi F/ 2,513' to 2,542' top of plug. Initially get 1' increments of sand and P/U 3' and repeated 3X to try and capture misc metal. Increased to 5' of sand and P/U 15' at a time the rest of the way to plug. Max Gas 40u.,Daily disposal to G&I: 234 bbls, total= 2517 bbls Daily H2O from Lake 2: 240 bbls, total=1560 bbls Daily Metal: 20# Total 104# Daily DH losses 0 bbls, total 18 bbls 6/14/2022 Continue wash down through sand with RCJB to top of Plug @ 2542', wash down over Plug stem to 2547', hard tag top of plug w/4K down. P/U above plug and wash over again x2. Pump 30 bbls Hi Vis Sweep, chase sweep with clean 9.8 ppg Brine. See debris/heavy sands with sweep. POOH to 2500'.,R/U Head pin and 1502 Components. Flood/purge kill line and choke. PT Casing 4000 psi on chart for 30 min. Good Test. Pumped 2.23 bbls, Bled Back 2.2 bbls.,R/D Test Equipment, blow down choke and kill lines. Attempt to POOH from 2500' to 2479', observe 3-4K over/under when going up/down, with significant drag and pipe vibration, pulled 12K over @ 2479'. P/U 64K, SO 68K.,Wash down to 2479' over stem on top of RBP. See drag go away and getting clean up/down weights. Pump 25 bbls Hi Vis sweep and wash to top of plug x3 w/o issues. Sweep back with light amount of sand and no debris/junk. POOH from 2547 to 2467 w/o issues.,Service Rig: Grease Crown, Blocks, TD, Iron Roughneck, Drqwwprks Spline as per EAM. Check oil in TD. Check TD Cradle for cracks, all good.,POOH with RCJB from 2467' to Surface. P/U 52K, SO 54K,Break Down RCJB components. Recovered 6" piece of casing shaving, Multiple Metal fragments and large chunks of cement. Re-assemble RCJB and prep to re-run same.,PJSM . RIHG with RCJB F/Surface T/2535'. P/U Single and tag RGP @2547'. Set down 4k. P/U = 65k, S/O=68K. Calculated displacement Observed.,PJSM. Stage pumps up to 415 GPM=2450 PSI, Return flow @ 38%, RPM =10, Torque = 1.2K, P/U=64k, S/O=67k, Slacked off to 2546'MD (1' above RBP) and punmped thru the RCJB. R&R F/2546' T2535'.,PJSM/ LD Single, POOH on Elevators F/2535' T/Surface. Observed 7k Overpull @2500'MD. S/O observed no drag. Pull 10-15k overpull @2500' MD as per baker rep. S/O T2503' MD, weight fell off, rotate @ 10RPM w/free torque of 650-800 Ft/lbs. P/.U T/.2500' MD observed a 4k TQ Stall. S/O w/o Rotary. Pass through up and down with no issues F/2503' T/2497'.,Orient string to the left quarter turn, pass through up and down w/o issues F/2497' T/2503'. No overpull or Torque bobbles passing by 2500' MD. Shut off rotary and made another pass w/o issues F/2497' T/2503'. P/U 63k and S/O 68k.,PJSM for laying down Baker RCJB assembly per rep. Clean out junk basket and retrieved a 4"x3" piece of 9.625" Casing. Re-assemble the RCJB and removed from rig floor. P/U 9.625" RBP Retrievable head and RIH per Baker Rep.,RIH with Model L RBP retrieval tools on 4" XT-39 DP F/Surface T/ 821'.,RIH on 4" DP T/2546 and tag up on RBP.,Screwed into RBP and let the RBP equalize, monitor for 5 minutes - no flow. Rotate @ 20RPM TRQ 8-1200Ft/Lbs, Pickup T/70k Slack T/68kk.. Continue Rotating picked up and un- seated to 2541'. Slack off T/2551' to ensure packer was released, attempted to PU Pulled over 17K at 2532' MD. Suspected a collar RIH to 2533'. turn pumps on 205GPM to wash debris away from RBP. Slacked down to 2538' attempted to PU again, no joy.,Hung up again at 2532 w/9k overpull. wash down 3' rotate half turn in string and PU hung up again. Pulled over 16k again, slacked back down and rotated at 40RPM 580TQ. ROT 64K.Attempted to clean debris off of RBP. Kill Rotary, PU T/2532', pulled 19k over, Slack off, working string in 1-2k increments. Pulled passed 2532' MD.,POOH L/D 1 joint of DP, set slips @ 2523'. R/U To circulate, CBU.,R/U T/test Casing. PT to 4000 PSI, pumped 6.3 bbls - Good test; Bled back 5.5 bbls. Blowdown choke and lines. R/D testing equipment.,POOH w/4" DP on elevators F/ 2,523' T/ 2499' 5k overpull. Worked back down T/2504, S/O 67k. 1/4 turn to Right, pumps on at 3 BPM, 88 PSI, Pull up T/2498' (P/U=76k). Increased to 4BPM when reciprocating stacked out at 52K - Inadvertently set packer, 20RPM 6 turns to release. Pull up T/2498' MD with 84K (18k over). 1/4 Turn to R, Pulled up T/2497' and popped free with 20K over.,POOH F/2497' T/2451 P/U=68k, S/O=67K. Pulled into ES Cementer with RBP and observed a 10k overpull (77K). Pumps on 3BPM 40PSI, working thru ES cementer and observed 2-4k over bobble, working thru at time of report.,Daily disposal to G&I:97 bbls, total= 2611 bbls Daily H2O from Lake 2: 165 bbls, total=1725 bbls Daily Metal: 0# Total 104# Daily DH losses 0 bbls, total 18 bbls 6/15/2022 Continued POOH with the RBP on 4" DP. Incurred 2-4k overpull with each collar F/2429 T/2337'. POOH T/2296' (next collar) and observed no more overpulls at the collars. Continue POOH T/Surface w/o issue..,POOH T/Baker BHA, BHA at surface; observed slight scarring on metal collars above and below element. Closed Blind Rams and L/D BHA.,Pull Wear Ring. Single and M/U to wear ring running tool. Latch onto wear ring and BOLDS, L/D.,PJSM. Make up setting tool. RIH and set test plug. P/U M/U XO's to pump in sub, TIW and dart valve. R/U Test pump, flood and purge lines. Pressure up to 1200 PSI and work valves, bleed off and perform body test to 4,000 psi - good. Found Actuator valve on Super Choke not functioning properly.,PJSM Perform BOPE test W/ 4" & 7.625" to 250 PSI low and 4,000 PSI high for 5 Min. Tested Choke Manifold 1-15 (F/P #14), 4" Dart, 4" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and Kill, Manual to 1,600 PSI, Upper VBRs (2.875 X 5.5) and lower Rams (7.625") Blind Rams & Annular. Test H2S 10-20 ppm, LEL 20- 40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Koomey draw drown Initial System,3,050 PSI, Manifold 1,500 PSI, Annular 1,500 PSI, after System 1,350 PSI, Man 1,350 PSI, Annular 1,350 PSI. 200 PSI increase 31 Sec, full charge 119 sec. Nitrogen 6 bottle average 2,325 PSI. Witnessed Waived by AOGCC Adam Earl.,C/O Super Choke actuator and adjusted timing, C/O CMV #14 and continue testing. Tested Super Choke. 1,600 psi and CMV #14 250 / 4000 psi 5 min on chart. Good.,R/D Test equipment and Blowdown Top Drive, Kill and Choke Lines. Line up Choke Manifold, Install wear ring: OD=13.375", ID=9", Length = 15", RILDS. Remove Running tool and L/D Joint.,PJSM for P/U BHA. P/U 3.5" Mule shoe, Baker 9.625" Scraper, in Line Magnet, Boot Baskets, LBS & Jar and Appropriate XO's total 65.2'. and M/U per baker rep.,PJSM RIH with BHA on 4" XT-39 DP. F/ 65' to 317' MD. P/U = 47k, S/O = 47k,PJSM RIH with BHA on 4" XT-39 DP. F/ 317' to 6510' MD. P/U = 109k, S/O = 103k. No issues observed passing thru the ES Cementer or casing patch.,Daily disposal to G&I:57 bbls, total= 2671 bbls Daily H2O from Lake 2: 0 bbls, total=1725 bbls Daily Metal: 0# Total 112# Daily DH losses 0 bbls, total 18 bbls 6/16/2022 Continue RIH w/ 9.625" scraper assy F/ 6510' - T/ tag depth 7995' MD (7986' NoGo). Light tag w/ 2k dn. P/U 134k, S/O 121k. Calculated displacement for trip.,Service traveling equipment. Grease blocks, drawworks, TDS, Iron Roughneck and spinners. Check oil in TDS (Good). Inspect TDS cradle (good).,Circulate clean TOL F/ 7995' slowly pulling up to 7980' MD pumping @ max rate 550 gpm, 1715 psi, 43% flow out, max gas 67 units. Pumped 25 bbl hi vis sweep with minimal cuttings returned to surface (slight trace of sand). P/U 134k, S/O 121k. Circulated a total of 1x STS. Monitor well 10 min (static).,Pump dry job, POOH laying down 4" DP F/ 7980' - T/ 6589' MD. P/U 116k, S/O 109k.,PJSM CONT to L/D DP F/6589' T/1850' MD, P/U=59K, S/O=59k, Calculated Displacement observed.,PJSM CONT to L/D DP F/1850' T/65', P/U=49k, S/O=49K.,PJSM for L/D BHA per Baker Rep, Clean Junk Baskets; 6 pieces of stainless steel bands and 4 pieces of 9.625" casing retrieved. 15#'s of metal from string magnets.,PJSM BOLDS Remove Wear Ring.,PJSM for P/U WOTCO tools and R/U 7"/7.625" handling equipment for Upper completions run. P/U 7" 26# VAMTOP Mule shoe and perform dead stick test with tongs dumping to 12278 FT/Lbs.,PJSM with oncoming crew to RIH with 7" / 7-5/8" Upper Completions. Bring Mule shoe and baker locked to space out joint (TT 11,830 Ft/Lb) to floor and M/U. P/U 5.625 bore 7" R-Nipple Joint and observed an audible thud from skate - RHC-M fell out from the pin end and was caught in Thread Protector.,Made appropriate calls; Halliburton and Hilcorp Wireline Tool room on site to rebuild RHC in pipe shed. The wrong RHC was installed in the R-Nipple. Wireline Toolhouse verified and installed proper R-RHC catcher. SIMOPS: Rig Crews worked, swapped out spiral wrap, clean service loops, housekeeping and misc. projects.,RIH R-Nipple joint and M/U, Baker-Lok'ed TNT packer to R-Nipple joint. Verified TNT packer shear screws (4) are in place, setting PSI 2140. Continued RIH 7" 26.7# L-80 VAMTOP to 188' MD. Crossed over to 7-5/8" 29# L-80 VAMTOP, Cont and RIH 7.625" 29# L-80 VamTop F/ 188' T/695' MD. P/U = 50k S/O = 52k.,7" VamTop: Min Shoulder TQ = 420, Max Shoulder TQ = 5810, opt M/U TQ = 8300 ft/lb. 7.625" VamTop Min shoulder TQ = 730 ft/lb, Max Shoulder TQ = 10110 ft/lb, optimum M/U TQ = 14450 ft/lb,Daily disposal to G&I: 0 bbls, total= 2671 bbls Daily H2O from Lake 2: 0 bbls, total=1725 bbls Daily Metal: 15# Total 127# Daily DH losses 0 bbls, total 18 bbls 6/17/2022 RIH w/7-5/8 VAMTOP L-80 29.7# Tubing T/2080' P/U = 78k, S/O = 82k. Continue Running F/2080' T/4552' MD and M/U 7-5/8" VAMTOP x 7-5/8" H563 XO, P/U = 135k, S/O = 132k, Change out FOSV to 7-5/8" H563 .,Torque Turn values, 7" VAM = 11,830 FT/LBS, 7-5/8" VAM 14,450 FT/LBS, 7-5/8 H563 = 10,300 FT/LBS. P/U = 135k, S/O = 132K.,PJSM, RIH w/7-5/8" H563 29.7# Tubing F/4552' T/7857' MD. P/U 7-5/8" H563 x 7" VAMTOP XO joint, 7" R-Nipple joint w/ a 5.963" Packing bore, 7" VAMTOP x 7-5/8" H563 XO joint. P/U 212k, S/O = 194k. C/O Slips and elevators as required. H563,Change out Elevators for 7" VAMTOP, P/U 7-5/8" H563 x 7" VAMTOP XO Joint, followed by 19.82' 7" VAMTOP Pup joint. Followed with Hanger (8.88' pup joint), TWC was installed prior, torque turned to 11,830 FT/LBS. P/U = 212k and S/O = 194K. Hanger landed -159k string weight at 18:30, RILDS. Mule shoe bottom at 7941.45'. Test Hanger to 3500 PSI for 5 min.,Several gland nuts were observed to be leaking, loosened and retorqued per Vault Rep - good. SIMOPS, R/D Weatherford and clean rig floor of tools for running tubing.,PJSM, for Johnny Whacking the stack, Flush lines and surface equipment. B/D all lines and drain stack.,PJSM, C/O LPR's F/7-5/8" SBR's T/2-7/8 x 5-1/2" VBR's.,Bleed down Koomey system/lines, Disconnect Choke and Kill lines, Break BOP from Tubing spool/DSA and Rack back. SIMOPS Cont cleaning pits and grinding off roof plate for removing roof for Drawworks gear end swap.,PJSM, clean off wellhead and install tubing spool; test. Pull TWC... R/U tubing head and TQ bolts per Vault Rep. Test hanger void 500/5000 for 10 mins - good. Tested tree to 500 for 5 mins and 5000 for 10 mins - good. Vault pulled TWC. SIMOPS - Cleaning pits, flushing pumps and lines.,PJSM, R/U valve manifold for pumping down 9.8 ppg CI Brine and FP (LRS) Diesel on 9-5/8 x 7-5/8 IA, with a U-Tube line between Tubing and IA.,PJSM R/U LRS for FP the well with diesel. PT lines to 3,000 psi, good.,Daily disposal to G&I: 57 bbls, total= 2728 bbls Daily H2O from Lake 2: 145 bbls, total=1875 bbls Daily Metal: 0# Total 127# Daily DH losses 0 bbls, total 18 bbls 6/18/2022 PJSM R/U and pump CI brine and FP Diesel down IA... R/U, Lined up manifold accordingly and reversed in 100 bbls 9.8ppg CI Brine (Rig pumps, 3 BPM = 225 PSI) followed by 140 bbls of diesel down the 7-5/8" x 9-5/8" IA (LRS). LRS: ICP = 440 @ 2.5 BPM, FCP = 1460 @ 1.5BPM.,Disconnected LRS, R/U sensator, test pump and opened up manifold to U-tube (@08:45) IA and Tubing. SIMOPS: Rig crews cleaned up floor, Prepped roof for craning out gear box, remove excess 7-5/8" equipment, flush pumps, finish cleaning pits, remove bails F/top drive, R/D FP manifold.,PJSM, Dropped 1-7/8" Ball and rod,. Lineup on tubing and pump @ 2 BPM, pressure walked up to 540 psi and held psi with IA showing same - Ball not seating. Verify line up (good).,PJSM with new Crew. Psi up F/500 - T/ 1200 psi and dump IA attempting to seat ball and rod (no go).Lineup IA to take returns to cuttings box, Attempt to seat ball and rod @ 5 bpm, 500 psi with full returns throughout (no go). Pumped a total of 11.2 bbls. Consult with Engineer.,Line up and "U"-Tube for 15 min. Brought pumps on at 2 BPM to establish psi, increased to 500 psi at 7 BPM with pump rate reducing to 5 bpm, maintaining 600 psi, increase psi incrementally to 800 psi w/ 5 bpm (no change). Shut down. Observe tbg bleed to 140 psi. Pump a total of 17.5 bbls down tubing, without indication of ball seating.,Line up and "U-tube". Estimated FP depth @ 1780' MD Discuss options with David Bjork. Decision made to mobilize slickline for set and test.,Prep rig floor for slickline operations. Build 30 bbls 9.8 brine in pill pit. Build circulation manifold on rig floor.,PJSM w/ Halliburton Slickline. P/U 7" pop off sub, 7' x 7" Lubricator, 7" to 5" XO, 10' x 5" Lubricator, 5" pop off sub and lubricator. Hang Sheave F/ elevators. SL BHA: 24' OAL, RS, 2-5/8" x 5' weight Stem, 1-3/4" OJ, 1-7/8" LSS, 5.5" bell guide and 2" RS. PT lubricator T/4500 PSI. SIMOPS: Continue prep for RDMO.,PJSM for RIH w/SL, SL running speed 350fpm, SL observed latch of ball and rod (10# increase) P/U = 475#'s @ 7871' SLM, P/U 5' to reseat ball into RHC. Pumps on 1.5BPM, IA lined up to flow line seeing out of balance and flowing, ICP = 160 psi, increased to 300 psi. Pumps off @ 1.5 bbls pumped; psi bleeding off, had full returns shutting in IA immediately to prevent any more loss of FP. No indication of ball seating.,P/U SL 5', pumps on 3 BPM, pumped 1 bbl and simultaneously while pumping, SL S/O to seat ball - psi not building past 130 psi, 2.7 bbls pumped. Decision was made to POOH with SL and ball and rod.,SL POOH F/ 7,871' SLM to surface w/ Ball and rod. Bleed down lubricator. P/U lubricator W/ tuggers from pop off sub on tree. Lower ball and rod down F/ lubricator. L/D ball and rod. No visual signs of scaring on ball and rod looked good. C/O retrieval tools F/ 5.5" Bell Guide T/ 5.5" GS, RIH to retrieve RHC Plug. RIH 400 fpm, P/U = 480#'s @ 7700'. Latched onto RHC at 7,871' SL, P/U W/ 80# increase, P/U = 560#'s, POOH.,POOH F/7871' SLM T/ Surface. P/U lubricator from pop off sub on tree. Lower RHC plug F/ Lubricator. RHC Plug showed indication of ball on seat, but no evidence of debris. Slickline rebuilt current RHC with a PR plug body and guide.,RIH w/ PR Plug Body F/Surface T/ 7850' SLM 400 fpm, P/U = 535#. RIH T/7872' SLM, located PR plug body on nipple profile. Jarred down setting locks in nipple profile, P/U shearing brass pin leaving PR plug body in nipple profile @ 7872' SLM. Weight loss was 85# on SL, P/U = 450#. POOH 400 fpm,POOH F/7872' SLM T/Surface. Bleed back to flowback trailer. P/U Lubricator from pop off sub on tree, L/D plug body running tool. P/U Prong setting tool and M/U Lubricator. PT lines at time of reporting.,Daily disposal to G&I: 248 bbls, total= 2976 bbls Daily H2O from Lake 2: 200 bbls, total=2075 bbls Daily Metal: 0# Total 127# Daily DH losses 0 bbls, total 18 bbls 6/19/2022 PJSM w/oncoming HES Slickline. PT Lines, found faulty valve - added double block.,RIH w/Slickline F/Surface T/7700' SLM, 430 fpm, P/U = 485#'s. RIH T/7872' SLM landing prong setting tool, P/U = 500#'s. Pressured up Tubing T/530 psi with 50 psi on IA w/ prong stung in. Bleed off pressure to 0 psi on tubing. Pumped back up to 270 psi on tubing, holding pressure for SL. SL Jarred down on prong shearing pins, released from Prong and 500 psi remained in place - good. Bled off pressure and POOH with SL.,Slickline POOH F/ 7872' SLM T/Surface. Drained and laid down Lubricator and R/D HES SL tools.,PJSM and PT lines/manifold to 500 psi for 5 mins. Lined up on tubing to set packer while monitoring IA. TNT packer, 4 set screws (535 psi per), set pressure at 2140 psi.,Packer setting / MIT-T: Pump at 1.5 BPM down tubing, pumped a total of 4.6 bbls, packer shifted at 2190 psi. MIT-T for 30 mins at 4000 psi on chart - good test. MIT-IA: Bled tubing down to 1528 psi, lined up IA monitoring tubing. Pump at 0.5 BPM, pumped a total of 3.8 bbls. MIT-IA for 30 mins at 4000 psi on chart - good test.,R/D Test equipment, Clear rig floor of HES Slickline equipment. Remove Lubricator from Tree. Lower top drive, remove SL Sheave/slings, Remove SL BOPE, riser and pump in sub. Install tree cap: SIMOPS: Flush and blow down mud/charge pumps.,PJSM, Install Kelly bushing. P/U on derrick, retract derrick pins and scope down. Remove bridal lines from top drive. Set top drive down w/5' DP pup into slips. Slack off to block weight and hang blocks.,PJSM, Disconnect hydraulic lines F/draw works, tuggers, manrider. Disconnect electric power and control lines F/draw works, dog house, rig floor and Koomey. Spot crane and remove roof hatch for gearbox removal. Disconnect all interconnects. On cold start power at 17:00,PJSM Jack up and install jeeps under motor mod and mud mod to pull off. SIMOPS: Drain draw works and gear box, shim draw works. Pickup draw works and move aside.,Rig was Released @ 20:00. Jack up pipe shed and cat walk and move off well. Stomp sub 3' of well and install tow bars and steering arms. SIMOPS: Crane gear box out from draw works and crane in replacement gear box. Install roof cap. Continue R/U Gear box and draw works. Hook up to sub, Move off of wellhead. Convoy for movement across field, Security on site. Rig left location at 01:15 for L-Pad. Final Report,Daily disposal to G&I: 469 bbls, total= 3445 bbls Daily H2O from Lake 2: 0 bbls, total=2075 bbls Daily Metal: 0# Total 127# Daily DH losses 0 bbls, total 18 bbls 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW7KXUVGD\-XO\$0 7R3%:HOOV,QWHJULW\ &F5HJJ-DPHV%2*& 6XEMHFW5(>(;7(51$/@5(+LOFRUS3%8-XQH0,7)RUPV $WWDFKPHQWV0,73%8$*,5HYLVHG[OV[0,73%836,36,5HYLVHG[OV[0,73%8 $5HYLVHG[OV[0,73%8:$5HYLVHG[OV[0,73%81*,$1*, 5HYLVHG[OV[0,73%8$5HYLVHG[OV[0,73%81*,5HYLVHG[OV[ )ROORZ8S)ODJ)ROORZXS )ODJ6WDWXV)ODJJHG ,ŝZǇĂŶ͕ ƚƚĂĐŚĞĚĂƌĞƌĞǀŝƐĞĚƌĞƉŽƌƚƐĂƐĨŽůůŽǁƐ͗ x D/dWh'/ͲϬϯϬϱͲϯϭͲϮϮʹĚĚĞĚƚŚĞƌĞŵĂƌŬƐ͕͞dďŐůĞĨƚŽƉĞŶƚŽŵŽŶŝƚŽƌĨŽƌĨůŽǁĨƌŽŵƚŚĞƚƵďŝŶŐĚƵƌŝŶŐƚŚĞ ƚĞƐƚŽĨƚŚĞĐĂƐŝŶŐͬƉĂĐŬĞƌ͟ĂŶĚĚĞůĞƚĞĚƚŚĞǀĞƌďŝĂŐĞ͞ŽƉĞŶ͟ĨƌŽŵƚŚĞƚƵďŝŶŐĨŝĞůĚƐ͘ x D/dWhW^/ͲϬϴW^/ͲϭϬϬϲͲϬϰͲϮϮʹŚĂŶŐĞĚƚŚĞ>WƵŵƉƚŽϰ͘ϲĨŽƌW^/ͲϭϬ x D/dWhϬϰͲϭϵϬϲͲϬϰͲϮϮʹŚĂŶŐĞĚƚŚĞWĂĐŬĞƌdsƚŽϳϲϬϵ͛ĨŽƌϬϰͲϭϵ x D/dWhtͲϬϭϬϲͲϭϵͲϮϮʹŚĂŶŐĞĚƚŚĞWĂĐŬĞƌdsƚŽϴϰϱϭ͛ x D/dWhE'/ͲϬϳE'/ͲϭϰϬϲͲϮϬͲϮϮʹŚĂŶŐĞĚƚŚĞWĂĐŬĞƌdsƚŽϳϮϱϱ͛ x D/dWhϬϯͲϮϱϬϲͲϬϭͲϮϮʹŚĂŶŐĞĚƚŚĞ/ϭϱDŝŶ͘ƉƌĞƐƐƵƌĞĨŽƌϬϯͲϮϱƚŽϳϮϲĂŶĚ/ŶŝƚŝĂůdƵďŝŶŐƚŽϮϳϳϴĨŽƌ ϬϯͲϮϱďĂƐĞĚŽŶƚŚĞŝŶƐƉĞĐƚŽƌ͛ƐƌĞƉŽƌƚ x D/dWhE'/ͲϬϱϬϲͲϭϵͲϮϮʹDŽǀĞĚƚŚĞK'ZĞƉǁĂŝǀĞĚďǇǀĞƌďŝĂŐĞƚŽEŽƚĞƐ͕ĂĚĚĞĚĂĚĚŝƚŝŽŶĂůŶŽƚĞƐ ƌĞŐĂƌĚŝŶŐƚŚĞƐƵŶĚƌǇ͕ĂŶĚĐŚĂŶŐĞĚƚŚĞŝŶƚĞƌǀĂůƚŽ͞K͟ WůĞĂƐĞƵƉĚĂƚĞǇŽƵƌĐŽƉŝĞƐŽƌůĞƚŵĞŬŶŽǁŝĨǇŽƵĚŝƐĂŐƌĞĞ͘ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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). 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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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗WtĞůůƐ/ŶƚĞŐƌŝƚǇфWtĞůůƐ/ŶƚĞŐƌŝƚǇΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕:ƵůǇϳ͕ϮϬϮϮϱ͗ϰϱWD dŽ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗,ŝůĐŽƌƉ;WhͿ:ƵŶĞϮϬϮϮD/d&ŽƌŵƐ 3%81*, 37' D/dWhE'/ͲϬϱϬϲͲϭϵͲϮϮʹ ,ŝWŚŽĞďĞʹ/ĐŽŶƚĂĐƚĞĚƚŚĞƌŝŐ͘dŚĞĐƌĞǁƚŚĂƚĚŝĚƚŚĂƚƉĂƌƚŝĐƵůĂƌũŽďĂƌĞŶŽƚŽŶƚŚĞƐůŽƉĞĐƵƌƌĞŶƚůǇ͘,ŽǁĞǀĞƌ͕/ǁĂƐĂďůĞ ƚŽĐŽŶĨŝƌŵĨƌŽŵƚŚĞƚŽǁĞƌŶŽƚĞƐƚŚĂƚƚŚĞƚƵďŝŶŐǁĂƐůĞĨƚŽƉĞŶ͘^ƉĞĐƵůĂƚŝŽŶŽŶƚŚĞƉĂƌƚŽĨƚŚĞƌŝŐƚĞĂŵƚŚĂƚ/ƐƉŽŬĞǁŝƚŚ ƚŚĂƚƚŚŝƐŵĂǇŚĂǀĞďĞĞŶĚŽŶĞƚŽŵŽŶŝƚŽƌĨŽƌĨůŽǁĨƌŽŵƚŚĞƚƵďŝŶŐĚƵƌŝŶŐƚŚĞƚĞƐƚŽĨƚŚĞĐĂƐŝŶŐͬƉĂĐŬĞƌ͘ /ǁŽƵůĚďĞŚĂƉƉǇƚŽĞŝƚŚĞƌĐŚĂŶŐĞƚŚĞƉƌĞƐƐƵƌĞƚŽǌĞƌŽŝŶƚŚĞĨŽƌŵ͕ĂĚĚĂŶŽƚĞƚŽƚŚĞϭϬͲϰϮϲƐƚĂƚŝŶŐƚŚĂƚƚŚĞĐƌĞǁůĞĨƚ ƚŚĞƚƵďŝŶŐŽƉĞŶƚŽĐŚĞĐŬĨŽƌĨůŽǁĚƵƌŝŶŐƚŚĞƚĞƐƚŽƌŝŶǀĞƐƚŝŐĂƚĞĨƵƌƚŚĞƌƚŽŐĞƚĂŵŽƌĞĐŽŵƉůĞƚĞĞǆƉůĂŶĂƚŝŽŶŝĨƌĞƋƵŝƌĞĚ͘ dŚĂŶŬƐ͕ ZǇĂŶ,Žůƚ ,ŝůĐŽƌƉůĂƐŬĂ>> &ŝĞůĚtĞůů/ŶƚĞŐƌŝƚǇͬŽŵƉůŝĂŶĐĞ ZǇĂŶ͘,ŽůƚΛ,ŝůĐŽƌƉ͘ĐŽŵ W͗;ϵϬϳͿϲϱϵͲϱϭϬϮ D͗;ϵϬϳͿϮϯϮͲϭϬϬϱ &ƌŽŵ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕:ƵůǇϳ͕ϮϬϮϮϯ͗ϱϱWD dŽ͗WtĞůůƐ/ŶƚĞŐƌŝƚǇфWtĞůůƐ/ŶƚĞŐƌŝƚǇΛŚŝůĐŽƌƉ͘ĐŽŵх Đ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗΀ydZE>΁Z͗,ŝůĐŽƌƉ;WhͿ:ƵŶĞϮϬϮϮD/d&ŽƌŵƐ ,ŝZǇĂŶ͕ /ŚĂĚĂƋƵĞƐƚŝŽŶƌĞŐĂƌĚŝŶŐƚŚĞD/dĨŽƌ'/ͲϬϯϬϱͲϯϭͲϮϮ͖ƚŚĞD/dͲ/ŝŶĐůƵĚĞĚƌĞŵĂƌŬƐ͕͞KƉĞŶ͟ĨŽƌƚŚĞƚƵďŝŶŐ͕ďƵƚ/ĚŝĚ ŶŽƚƐĞĞĂŶǇƌĞŵĂƌŬƐŝŶĐůƵĚŝŶŐƚŚĞũƵƐƚŝĨŝĐĂƚŝŽŶĨŽƌůĞĂǀŝŶŐƚŚĞƚƵďŝŶŐŽƉĞŶ͍WůĞĂƐĞĂĚǀŝƐĞ͘ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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). 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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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗WtĞůůƐ/ŶƚĞŐƌŝƚǇфWtĞůůƐ/ŶƚĞŐƌŝƚǇΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗^ĂƚƵƌĚĂǇ͕:ƵůǇϮ͕ϮϬϮϮϭϮ͗ϰϬWD dŽ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KůŝǀĞƌ^ƚĞƌŶŝĐŬŝфKůŝǀĞƌ͘^ƚĞƌŶŝĐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗,ŝůĐŽƌƉ;WhͿ:ƵŶĞϮϬϮϮD/d&ŽƌŵƐ DƌƐ͘ƌŽŽŬƐ͕ ƚƚĂĐŚĞĚĂƌĞƚŚĞĐŽŵƉůĞƚĞĚK'D/dĨŽƌŵƐĨŽƌƚŚĞƚĞƐƚƐƉĞƌĨŽƌŵĞĚďǇ,ŝůĐŽƌƉŝŶ:ƵŶĞϮϬϮϮ͘ &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH tĞůů͗ Wd͗ EŽƚĞƐ͗ ϬϯͲϮϱ ϭϵϯϬϮϯϬ ϮͲǇĞĂƌD/dͲdΘD/dͲdǆ/ƉĞƌKϳϯϲ ϬϰͲϭϵ ϮϬϭϮϭϴϬ ϰͲǇĞĂƌD/dͲ/ ϭϯͲϬϱ ϭϴϭϭϬϯϬ EŽŶͲǁŝƚŶĞƐƐĞĚD/dͲdǆ/ƐƵƐƉĞŶĚĞĚǁĞůů ƚŽĚĞŵŽŶƐƚƌĂƚĞĐĂƐŝŶŐͬƉůƵŐŝŶƚĞŐƌŝƚǇ '/ͲϬϯ ϭϵϮϭϯϱϬ ZŝŐD/dͲdΘD/dͲ/ΎΎΎZŝŐƚĞƐƚƐǁĞƌĞ ƉĞƌĨŽƌŵĞĚŽŶϬϱͬϯϭŚŽǁĞǀĞƌĚĂƚĂǁĂƐ ŶŽƚƌĞǀŝĞǁĞĚƵŶƚŝůϬϲͬϬϲĂĨƚĞƌ/ŚĂĚ ĂůƌĞĂĚǇƐĞŶƚŽƵƚƚŚĞD/d͛ƐĨƌŽŵDĂǇ͘ '/ͲϬϳ ϮϬϲϬϱϮϬ ϰͲǇĞĂƌD/dͲ/ Ͳϭϯ ϮϭϬϬϯϵϬ ϰͲǇĞĂƌD/dͲ/ >ͲϮϮϮ ϮϬϵϭϭϵϬ ϰͲǇĞĂƌD/dͲ/ >'/ͲϬϴ ϭϴϲϬϱϳϬ EŽŶͲǁŝƚŶĞƐƐĞĚD/dͲdǆ/ƐƵƐƉĞŶĚĞĚǁĞůů ƚŽĚĞŵŽŶƐƚƌĂƚĞĐĂƐŝŶŐͬƉůƵŐŝŶƚĞŐƌŝƚǇ DͲϮϬϭ ϮϮϮϬϯϬϬ WŽƐƚŝŶŝƚŝĂůŝŶũĞĐƚŝŽŶ E'/ͲϬϱ ϭϳϲϬϭϰϬ ZŝŐD/dͲdΘD/dͲ/ E'/ͲϬϳ ϮϬϲϭϮϲϬ ϰͲǇĞĂƌD/dͲ/ E'/Ͳϭϰ ϭϳϴϬϵϮϬ ϰͲǇĞĂƌD/dͲ/ WϭͲϮϱ ϭϴϵϬϰϭϬ ϰͲǇĞĂƌD/dͲ/ W^/ͲϬϴ ϮϬϮϭϳϮϬ ϰͲǇĞĂƌD/dͲ/ W^/ͲϭϬ ϮϬϮϭϱϵϬ ϰͲǇĞĂƌD/dͲ/ ZͲϬϱ ϭϵϳϮϱϬϬ ϰͲǇĞĂƌD/dͲ/ ^ͲϭϮϬ ϮϬϯϭϵϴϬ ϮͲǇĞĂƌD/dͲ/ƉĞƌ/KϮϱ͘ϬϮϭ tͲϬϭ ϮϬϯϭϳϲϬ WŽƐƚƌŝŐǁŽƌŬŽǀĞƌD/dͲdΘD/dͲ/ƉĞƌ ƐƵŶĚƌǇϯϮϭͲϯϵϰΘŝŶŝƚŝĂůŽŶůŝŶĞD/dͲ/ ͲϮϴ ϭϴϴϭϮϳϬ ϰͲǇĞĂƌD/dͲ/ WůĞĂƐĞƌĞƉůǇǁŝƚŚƋƵĞƐƚŝŽŶƐŽƌĐŽŶĐĞƌŶƐ͘ ZǇĂŶ,Žůƚ ,ŝůĐŽƌƉůĂƐŬĂ>> &ŝĞůĚtĞůů/ŶƚĞŐƌŝƚǇͬŽŵƉůŝĂŶĐĞ ZǇĂŶ͘,ŽůƚΛ,ŝůĐŽƌƉ͘ĐŽŵ W͗;ϵϬϳͿϲϱϵͲϱϭϬϮ D͗;ϵϬϳͿϮϯϮͲϭϬϬϱ 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH Submit to: OOPERATOR: FIEL DD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1760140 Type Inj N Tubing 0 4146 4110 4085 Type Test P Packer TVD 7372 BBL Pump 4.5 IA 0 970 970 960 Interval O Test psi 4000 BBL Return 4.5 OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1760140 Type Inj N Tubing 1500 1500 2300 2300 Type Test P Packer TVD 7372 BBL Pump 3.8 IA 0 4296 4215 4180 Interval O Test psi 4000 BBL Return 3.8 OA 0000 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec hanicall Integrityy Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov NGI-05 Notes:Initial Rig MIT-IA to 4000 psi per sundry 321-618. OA cemented back to surface. Waived by Adam Earl. Notes: Hilcorp North Slope, LLC. Notes: Prudhoe Bay/ PBU/ NGI Pad Shane Barber 06/19/22 Notes:Initial Rig MIT-T to 4000 psi per sundry 321-618. Waived by Adam Earl Notes: Notes: Notes: NGI-05 Form 10-426 (Revised 01/2017)2022-0619_MIT_PBU_NGI-05_2tests 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 5(9,6(' MIT-T to 4000 psi MIT-IA to 4000 psi Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 21, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC NGI-05 PRUDHOE BAY UNIT NGI-05 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/21/2022 NGI-05 50-029-20196-00-00 176-014-0 G SPT 7372 1760140 1843 3343 3337 3340 3325 45 46 46 46 INITAL P Bob Noble 7/4/2022 Initial MIT-IA for post rig workover. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT NGI-05 Inspection Date: Tubing OA Packer Depth 285 2298 2283 2271IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN220704120345 BBL Pumped:1.6 BBL Returned:2 Thursday, July 21, 2022 Page 1 of 1          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:Brooks, Phoebe L (OGC) To:Shane Barber - (C) Cc:Regg, James B (OGC) Subject:RE: Innovation BOP test report Date:Friday, June 24, 2022 3:32:37 PM Attachments:Hilcorp Innovation 06-15-22 Revised.xlsx Shane, I changed the test type to Weekly. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Shane Barber - (C) <sbarber@hilcorp.com> Sent: Thursday, June 16, 2022 1:52 PM To: DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: David Bjork <David.Bjork@hilcorp.com>; Oliver Amend - (C) <oamend@hilcorp.com>; Steve Carter - (C) <scarter@hilcorp.com> Subject: Innovation BOP test report All, Please see attached BOP test report NGI-05. Thank you. Shane G. Barber | Drilling Foreman Hilcorp Alaska, LLC Rig “Innovation” Office: 907-670-3094 Mobile: 907-841-5208 3%81*, 37' Harmony: 1006 sbarber@hilcorp.com Alternate: James Lott The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:Innovation DATE: 6/15/22 Rig Rep.: Rig Phone: 907-3095 Operator: Op. Phone:9073094 Rep.: E-Mail Well Name: PTD #11760140 Sundry #321-618 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: x Bi-Weekly: Other: Rams:250/4000 Annular:250/4000 Valves:250/4000 MASP:2650 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 2P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8", 5K P Pit Level Indicators PP #1 Rams 1 2-7/8"x5-1/2"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 1 7 5/8"Solid Body P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8, 5K P Inside Reel valves 0NA HCR Valves 2 3-1/8, 5K P Kill Line Valves 2 3-1/8, 5K P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)3050 P CHOKE MANIFOLD:Pressure After Closure (psi)1350 P Quantity Test Result 200 psi Attained (sec)31 P No. Valves 15 FP Full Pressure Attained (sec)119 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1FP Nitgn. Bottles # & psi (Avg.): 6 @ 2325 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:2 Test Time:9.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/15, 02:46 Waived By Test Start Date/Time:6/15/2022 12:00 (date) (time)Witness Test Finish Date/Time:6/15/2022 21:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Hilcorp Test on 4" and 7 5/8" Pipe size. F/P on Hydraulic Choke. Replaced actuator and retested with Pass.F/P on Choke Manifold Valve #14. Replaced valve and retested with Pass. Tested early approved by Adam Earl via email. Matt Vanhoose Hilcorp Shane Barber PBU NGI-05 Test Pressure (psi): sbarber@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0615_BOP_Hilcorp_Innovation_PBU_NGI-05 9 9 9 999 9 9 9 9 9 9 9 9 -5HJJ FP FP F/P on Hydraulic Choke. .F/P on Choke Manifold Valve #14. 5HJJ-DPHV%2*& )URP5HJJ-DPHV%2*& 6HQW:HGQHVGD\-XQH30 7R-DPHV/RWW& &F%URRNV3KRHEH/2*& 6XEMHFW5(+LOFRUS,QQRYDWLRQ5DP&KDQJHWHVWUHSRUW /ŵŽǀĞĚƚŚĞ&WƚŽKWDŝƐĐŝŶƐƚĞĂĚŽĨƚŚĞsZŽŶŽƵƌĐŽƉǇ͘ :ŝŵZĞŐŐ ^ƵƉĞƌǀŝƐŽƌ͕/ŶƐƉĞĐƚŝŽŶƐ K' ϯϯϯt͘ϳƚŚǀĞ͕^ƵŝƚĞϭϬϬ ŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ ϵϬϳͲϳϵϯͲϭϮϯϲ &ƌŽŵ͗:ĂŵĞƐ>ŽƚƚͲ;ͿфũůŽƚƚΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗tĞĚŶĞƐĚĂǇ͕:ƵŶĞϴ͕ϮϬϮϮϲ͗ϬϵWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗ĂǀŝĚũŽƌŬфĂǀŝĚ͘ũŽƌŬΛŚŝůĐŽƌƉ͘ĐŽŵх͖KůŝǀĞƌŵĞŶĚͲ;ͿфŽĂŵĞŶĚΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗,ŝůĐŽƌƉ/ŶŶŽǀĂƚŝŽŶϲͲϳͲϮϮZĂŵŚĂŶŐĞƚĞƐƚƌĞƉŽƌƚ :ĂŵĞƐ>Žƚƚ ,/>KZWƌŝůůŝŶŐ&ŽƌĞŵĂŶ ,/>KZW/EEKsd/KEZŝŐ Wh͕EŽƌƚŚ^ůŽƉĞůĂƐŬĂ ϵϬϳͲϲϳϬͲϯϬϵϰ;KĨĨŝĐĞͿ ϵϬϳͲϯϵϴͲϵϬϲϵ;ĞůůͿ ,ĂƌŵŽŶǇϭϬϬϲ ũůŽƚƚΛŚŝůĐŽƌƉ͘ĐŽŵ ũĂŵĞƐůŽƚƚϯϱϮΛǇĂŚŽŽ͘ĐŽŵ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:Innovation DATE: 6/7/22 Rig Rep.: Rig Phone: 907-670-3095 Operator: Op. Phone:907-670-3094 Rep.: E-Mail Well Name: PTD #11760140 Sundry #321-618 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: Bi-Weekly: Other: x Rams:250/4000 Annular:NT Valves:NT MASP:2650 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1NT Housekeeping P Rig P Lower Kelly 1NT PTD On Location P Hazard Sec.P Ball Type 2NT Standing Order Posted P Misc.NA Inside BOP 1NT FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NT NT Annular Preventer 1 13-5/8", 5K P Pit Level Indicators NT NT #1 Rams 1 2-7/8"x5-1/2"P Flow Indicator NT NT #2 Rams 1 Blinds P Meth Gas Detector NT NT #3 Rams 1 9 5/8" Solid P H2S Gas Detector NT NT #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8, 5K NT Inside Reel valves 0NA HCR Valves 2 3-1/8, 5K NT Kill Line Valves 2 3-1/8, 5K NT Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 1 see remarks FP Time/Pressure Test Result System Pressure (psi)NT CHOKE MANIFOLD:Pressure After Closure (psi)NT Quantity Test Result 200 psi Attained (sec)NT No. Valves 15 NT Full Pressure Attained (sec)NT Manual Chokes 1NT Blind Switch Covers: All stations Yes Hydraulic Chokes 1NT Nitgn. Bottles # & psi (Avg.):NT CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:1 Test Time:3.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/6/22 @ 07:00 Waived By Test Start Date/Time:6/7/2022 16:00 (date) (time)Witness Test Finish Date/Time:6/7/2022 19:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Matt Herrera Hilcorp Purpose of test: Opened all doors to check for metal Debris and changed out LPR from 7 5/8" to 9 5/8". Tested on 4" and 9 5/8" Pipe Size. FP on UPR, gland nuts leaking on Tbg Head. Tighten Gland Nuts and retest Pass. Joel Sture Hilcorp James Lott PBU NGI-05 Test Pressure (psi): jlott@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0607_BOP_Hilcorp_Innovation_ram-change_PBU_NGI-05 9 99 9 9 9 9 +LOFRUS1RUWK6ORSH//& 9 9 9 9 -5HJJ FP on UPR, gland nuts leaking on Tbg Head. Tighten Gland Nuts and retest Pass. 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:Shane Barber - (C) To:Regg, James B (OGC);Brooks, Phoebe L (OGC);DOA AOGCC Prudhoe Bay;Wallace, Chris D (OGC) Cc:David Bjork;Oliver Amend - (C) Subject:MIT Date:Monday, June 20, 2022 5:16:29 PM Attachments:MIT PBU NGI-05 6-19-22.xlsx Please see attached MIT-T, MIT-IA for NGI-05. Thank you Shane G. Barber | Drilling Foreman Hilcorp Alaska, LLC Rig “Innovation” Office: 907-670-3094 Mobile: 907-841-5208 Harmony: 1006 sbarber@hilcorp.com Alternate: James Lott The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 3%81*, 37' Submit to: OOPERATOR: FIEL D / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 176-014 Type Inj N Tubing 0 4146 4110 4085 Type Test P Packer TVD 7241 BBL Pump 4.5 IA 0 970 970 960 Interval I Test psi 4000 BBL Return 4.5 OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 176-014 Type Inj N Tubing 1500 1500 2300 2300 Type Test P Packer TVD 7241 BBL Pump 3.8 IA 0 4296 4215 4180 Interval I Test psi 4000 BBL Return 3.8 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj N Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Hilcorp North Slope, LLC. Notes: Prudhoe Bay/ PBU/ NGI Pad Shane Barber 06/19/22 Notes:Initial Rig MIT-T; witness waived by AOGCC's Adam Earl Notes: Notes: Notes: NGI-05 NGI-05 Notes:Initial Rig MIT-IA/ OA cemented back to surface; witness waived by AOGCC's Adam Earl Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec hanical Integrity Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Form 10-426 (Revised 01/2017)2022-0619_MIT_PBU_NGI-05_2tests -5HJJ 9 9 9 9 9 9 9 9 9 9 9 9 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: Gas Injector NGI-05 (PTD #1760140) RWO complete Date:Thursday, June 23, 2022 8:17:43 AM Attachments:image001.png From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Wednesday, June 22, 2022 4:15 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; John Conrad <John.Conrad@hilcorp.com>; Bo York <byork@hilcorp.com> Subject: OPERABLE: Gas Injector NGI-05 (PTD #1760140) RWO complete Mr. Wallace, The RWO on Gas Injector NGI-05 (PTD #1760140) is complete. A passing MIT-T to 4085 psi and MIT-IA to 4180 psi was completed on 06/19/22 and proves two competent well barriers. The well will now be classified as OPERABLE. Once the well is on stable injection, an AOGCC witnessed MIT-IA will be performed. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Sunday, April 28, 2019 8:33 AM To: 'chris.wallace@alaska.gov' <chris.wallace@alaska.gov>; AK, OPS EOC Specialists <AKOPSEOCSpecialists@bp.com>; AK, OPS FS1 DS Ops Lead <AKOPSFS1DSOpsLead@bp.com>; Ak, OPS FS1 Facility PTL <akopsfs1facilityptl@bp.com>; Ak, OPS FS1 Field PTL <akopsfs1fieldptl@bp.com>; AK, OPS FS1 OSM <AKOPSFS1OSM@bp.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt2@bp.com>; AKOpsProdEOCTL <AKOPSPCCEOCTL@bp.com>; Brown, Don L. <browd2@BP.com>; G GPB FS1 Drillsites <ggpbfs1drillsites@BP.com>; Oestgaard, Finn <Finn.Oestgaard@bp.com>; Vandergon, Mark A <Mark.Vandergon@bp.com> Cc: 'Regg, James B (DOA) (jim.regg@alaska.gov)' <jim.regg@alaska.gov>; AK, GWO Completions Well Integrity <AKDCWLCompletionsSupt@bp.com>; AK, GWO DHD Well Integrity <AKD&CDHDWellIntegri@bp.com>; AK, GWO Projects Well Integrity <AKDCProjectsWellIntegrityEngineer@bp.com>; AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com>; AK, GWO Well Integrity Well Information <akgwowellintegritywe@bp.com>; AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com>; AKIMS App User <akimsuser.service@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; Dempsey, David G <David.Dempsey1@bp.com>; Dickerman, Eric <Eric.Dickerman@bp.com>; Hibbert, Michael <Michael.Hibbert@BP.com>; Janowski, Carrie <Carrie.Janowski@bp.com>; Montgomery, Travis J <Travis.Montgomery@bp.com>; Munk, Corey <Corey.Munk@bp.com>; Obrigewitch, Beau <BEAU.OBRIGEWITCH@bp.com>; O'connor, Katherine <Katherine.O'connor@bp.com>; Sternicki, Oliver R <Oliver.Sternicki@bp.com>; Tempel, Joshua <Joshua.Tempel@bp.com>; Worthington, Aras J <Aras.Worthington@bp.com> Subject: NOT OPERABLE: Injector NGI-05 (PTD #1760140) failed pre-AOGCC CMIT-TxIA with IAxOA communication All, Gas Injector NGI-05 (PTD #1760140) operates under Administrative Approval 4E.032 for TxIA communication. A condition of the AA requires a 2-year AOGCC witnessed MIT-IA. On 04/27/19 Slickline was preparing the well for the required 2-year MIT-IA when they set a TTP and performed a passing MIT-T to 2,511 psi. A subsequent CMIT-TxIA failed with rapid response on the OA pressure. The failing CMIT-TxIA and subsequent response in OA pressure indicates a failure of the secondary barrier. The well has been secured with a TTP and will now be classified as NOT OPERABLE. The town engineer will evaluate for a LDL. Please respond with any questions. Andrew Ogg Well Integrity Engineer BP Global Wells Organization – Alaska Office: 907-659-8110 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. 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No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considersappropriate. 5HJJ-DPHV%2*& )URP-DPHV/RWW&MORWW#KLOFRUSFRP! 6HQW7XHVGD\-XQH$0 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& &F2OLYHU$PHQG&6WHYH&DUWHU&'DYLG%MRUN 6XEMHFW+LOFRUS,QQRYDWLRQ/35&KDQJH7HVW5HSRUW $WWDFKPHQWV+LOFRUS,QQRYDWLRQ/35&KDQJH[OV[ :ĂŵĞƐ>Žƚƚ ,/>KZWƌŝůůŝŶŐ&ŽƌĞŵĂŶ ,/>KZW/EEKsd/KEZŝŐ Wh͕EŽƌƚŚ^ůŽƉĞůĂƐŬĂ ϵϬϳͲϲϳϬͲϯϬϵϰ;KĨĨŝĐĞͿ ϵϬϳͲϯϵϴͲϵϬϲϵ;ĞůůͿ ,ĂƌŵŽŶǇϭϬϬϲ ũůŽƚƚΛŚŝůĐŽƌƉ͘ĐŽŵ ũĂŵĞƐůŽƚƚϯϱϮΛǇĂŚŽŽ͘ĐŽŵ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:Innovation DATE: 6/13/22 Rig Rep.: Rig Phone: 907-670-3095 Operator: Op. Phone:907-670-3094 Rep.: E-Mail Well Name: PTD #11760140 Sundry #321-618 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: Bi-Weekly: Other: x Rams:250/4000 Annular:NT Valves:NT MASP:2650 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1NT Housekeeping P Rig P Lower Kelly 1NT PTD On Location P Hazard Sec.P Ball Type 2NT Standing Order Posted P Misc.P Inside BOP 1NT FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NT NT Annular Preventer 1 13-5/8", 5K NT Pit Level Indicators NT NT #1 Rams 1 2-7/8"x5-1/2"NT Flow Indicator NT NT #2 Rams 1 Blinds NT Meth Gas Detector NT NT #3 Rams 1 7 5/8" Solid P H2S Gas Detector NT NT #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8, 5K NT Inside Reel valves 0NA HCR Valves 2 3-1/8, 5K NT Kill Line Valves 2 3-1/8, 5K NT Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)NT CHOKE MANIFOLD:Pressure After Closure (psi)NT Quantity Test Result 200 psi Attained (sec)NT No. Valves 15 NT Full Pressure Attained (sec)NT Manual Chokes 1NT Blind Switch Covers: All stations Yes Hydraulic Chokes 1NT Nitgn. Bottles # & psi (Avg.):NT CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:1.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/12/22 @ 07:50 Waived By Test Start Date/Time:6/13/2022 12:00 (date) (time)Witness Test Finish Date/Time:6/13/2022 13:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Brian Bixby Hilcorp Purpose of test: Changed out LPR from 9 5/8" to 7 5/8". Tested 7 5/8" Pipe Size. Matt Vanhoose Hilcorp James Lott PBU NGI-05 Test Pressure (psi): jlott@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0613_BOP_Hilcorp_Innovation_LPR_PBU_NGI-05 +LOFRUS1RUWK6ORSH//& 9 9 9 9 9 9 9 9 9 -5HJJ Changed out LPR from 9 5/8" to 7 5/8". 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW0RQGD\-XQH30 7R-DPHV/RWW& &F5HJJ-DPHV%2*& 6XEMHFW5(+LOFRUS,QQRYDWLRQ%23(7HVW5HSRUW $WWDFKPHQWV+LOFRUS,QQRYDWLRQ5HYLVHG[OV[ )ROORZ8S)ODJ)ROORZXS )ODJ6WDWXV)ODJJHG ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚĐŚĂŶŐŝŶŐƚŚĞƚĞƐƚƚǇƉĞƚŽtĞĞŬůǇ͘WůĞĂƐĞƵƉĚĂƚĞǇŽƵƌĐŽƉǇŽƌůĞƚŵĞŬŶŽǁŝĨǇŽƵĚŝƐĂŐƌĞĞ͘ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗:ĂŵĞƐ>ŽƚƚͲ;ͿфũůŽƚƚΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗^ĂƚƵƌĚĂǇ͕:ƵŶĞϭϭ͕ϮϬϮϮϭϬ͗ϰϮD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗KůŝǀĞƌŵĞŶĚͲ;ͿфŽĂŵĞŶĚΛŚŝůĐŽƌƉ͘ĐŽŵх͖ĂǀŝĚũŽƌŬфĂǀŝĚ͘ũŽƌŬΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗,ŝůĐŽƌƉ/ŶŶŽǀĂƚŝŽŶϬϲͲϬϵͲϮϮKWdĞƐƚZĞƉŽƌƚ :ĂŵĞƐ>Žƚƚ ,/>KZWƌŝůůŝŶŐ&ŽƌĞŵĂŶ ,/>KZW/EEKsd/KEZŝŐ Wh͕EŽƌƚŚ^ůŽƉĞůĂƐŬĂ ϵϬϳͲϲϳϬͲϯϬϵϰ;KĨĨŝĐĞͿ ϵϬϳͲϯϵϴͲϵϬϲϵ;ĞůůͿ ,ĂƌŵŽŶǇϭϬϬϲ ũůŽƚƚΛŚŝůĐŽƌƉ͘ĐŽŵ ũĂŵĞƐůŽƚƚϯϱϮΛǇĂŚŽŽ͘ĐŽŵ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:Innovation DATE: 6/9/22 Rig Rep.: Rig Phone: 907-3095 Operator: Op. Phone:9073094 Rep.: E-Mail Well Name: PTD #11760140 Sundry #321-618 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: x Bi-Weekly: Other: Rams:250/4000 Annular:250/4000 Valves:250/4000 MASP:2650 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 2P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8", 5K P Pit Level Indicators PP #1 Rams 1 2-7/8"x5-1/2"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 1 9 5/8" Solid Body P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8, 5K FP Inside Reel valves 0NA HCR Valves 2 3-1/8, 5K P Kill Line Valves 2 3-1/8, 5K P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1400 P Quantity Test Result 200 psi Attained (sec)29 P No. Valves 15 P Full Pressure Attained (sec)105 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 6 @ 2300 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:1 Test Time:6.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/8, 15:00 Waived By Test Start Date/Time:6/9/2022 16:30 (date) (time)Witness Test Finish Date/Time:6/9/2022 23:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Matt Herrera Hilcorp Test on 4" and 9 5/8" Pipe size. F/P on Manual Choke line Valve. Rebuild Valve and Retest with Pass. Matt Vanhoose Hilcorp James Lott PBU NGI-05 Test Pressure (psi): jlott@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0609_BOP_Hilcorp_Innovation_PBU_NGI-05 9 +LOFRUS1RUWK6ORSH//& 9 9 9 9 9 99 9 9 9 9 -5HJJ +LOFRUS1RUWK6ORSH//&K FP F/P on Manual Choke line Valve. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT NGI-05 JBR 06/20/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Annular FP-function for pass. Annular 10 secs; Rams 9 secs; HCRs 1 sec. Test Results TEST DATA Rig Rep:Sture/LeslieOperator:Hilcorp North Slope, LLC Operator Rep:Lott/Montague Contractor/Rig No.:Hilcorp Innovation PTD#:1760140 DATE:6/2/2022 Type Operation:WRKOV Annular: 250/4000Type Test:INIT Valves: 250/4000 Rams: 250/4000 Test Pressures:Inspection No:bopSAM220602161456 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 2650 Sundry No: 321-618 Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8 FP #1 Rams 1 2-7/8x5-1/2 P #2 Rams 1 Blinds P #3 Rams 1 7-5/8 P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8 P HCR Valves 2 3-1/8 P Kill Line Valves 2 3-1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P1500 200 PSI Attained P30 Full Pressure Attained P101 Blind Switch Covers:PAll stations Nitgn. Bottles (avg):P6@2291 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA 99 9 999 9 99 9 9 FP Annular FP-Annular 10 secs; Rams 9 secs; HCRs 1 sec. 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: [EXTERNAL] PTD176-014, NGI-05, Sundry 321-618: Questions Date:Friday, December 10, 2021 4:28:03 PM From: David Bjork <David.Bjork@hilcorp.com> Sent: Friday, December 10, 2021 2:11 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] PTD176-014, NGI-05, Sundry 321-618: Questions Mel, Answers to your questions below. I will call you to discuss after you have had time to review. Regards, Dave From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, December 10, 2021 10:58 AM To: David Bjork <david.bjork@hilcorp.com> Subject: [EXTERNAL] PTD176-014, NGI-05, Sundry 321-618: Questions Dave, A few questions: 1. Is there a way to lubricate out the test plug for the tubing hanger? We will lubricate out the K plug after pulling the test dart with our standard 7” lubricator kit. 2. Do we have a CBL for TOC on the 9-5/8” casing shoe? No, The only CBL we have is the for the 7” liner logged 3/26/1976. 3. I want to be sure we have a significant length of cement/confining zone on the 9-5/8” casing above the new packer at 7838’ MD. Can you confirm? Using a 30% washout in the 12-1/4” hole, 750sks of neat G (153bbls) puts the cement top at a calculated 7,518ft. Cement job was noted to have 50% returns after the first 150bbls displaced and full returns at 250bbls displaced with a 616bbl casing capacity. 4. When you break the stack, do you monitor for flow for a set amount of time? The OA will be monitored and on a bleed during initial rig up. IAxOA will be in communication after the casing cut and during the Arctic-Pak circ-out. The wellbore will be loaded with 9.8ppg brine before POOH. The well will be monitored before coming off bottom and before pulling the BHA. It will also be continuously monitored while making up the Spear BHA. I can program 10minutes but in reality it will be longer while handling equipment. 5. On step 19, what is your expected cement volume? 175bbls (155bbls annular capacity +20bbls excess) if we get out both FOC’s. It may be less depending upon where the TOC is found on the original shoe down squeeze. Either way it will be fully cemented to surface. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 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. 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Wd͗ϭϳϲϬϭϰϬ WƌŽƉŽƐĞĚtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ WƌŽƉŽƐĞĚůƚĞƌŶĂƚŝǀĞtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐŝĨĂĚĞƋƵĂƚĞĐĞŵĞŶƚŝƐŽůĂƚŝŽŶŝƐŶŽƚĨŽƵŶĚ͘ ZtK E'/ͲϬϱ Wd͗ϭϳϲϬϭϰϬ /ŶŶŽǀĂƚŝŽŶZŝŐKWƐ ZtK E'/ͲϬϱ Wd͗ϭϳϲϬϭϰϬ /ŶŶŽǀĂƚŝŽŶZŝŐŚŽŬĞDĂŶŝĨŽůĚ ZtK E'/ͲϬϱ Wd͗ϭϳϲϬϭϰϬ Changes to Approved Sundry Procedure 'DWH 6XEMHFW 6XQGU\ $Q\PRGLILFDWLRQVWRDQDSSURYHGVXQGU\ZLOOEHGRFXPHQWHGDQGDSSURYHGEHORZ&KDQJHVWRDQDSSURYHG VXQGU\ZLOOEHFRPPXQLFDWHGWRWKH$2*&&E\WKH³ILUVWFDOO´HQJLQHHU$2*&&ZULWWHQDSSURYDORIWKHFKDQJH LVUHTXLUHGEHIRUHLPSOHPHQWLQJWKHFKDQJH 6WHS 3DJH 'DWH 3URFHGXUH&KDQJH +$. 3UHSDUHG %\ ,QLWLDOV +$. $SSURYH G %\ ,QLWLDOV $2*&&:ULWWHQ $SSURYDO 5HFHLYHG 3HUVRQDQG 'DWH $SSURYDO 2SHUDWLRQV0DQDJHU 'DWH 3UHSDUHG 2SHUDWLRQV(QJLQHHU 'DWH Carlisle, Samantha J (CED) From: Rixse, Melvin G (CED) Sent: Wednesday, July 3, 2019 8:29 AM To: Carlisle, Samantha 1 (CED) Subject: FW: Please withdraw Sundry #319-263 for NGI-05 (PTD #176-014) Sam, FYI. Let me know if I need anything else. Mel From: Lastufka, Joseph N <Joseph.Lastufka@bp.com> Sent: Tuesday, July 2, 2019 3:13 PM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Subject: Please withdraw Sundry #319-263 for NGI-05 (PTD #176-014) Mel, Please withdraw approved sundry #319-263 for NGI-05 (PTD #176-014). We will not be doing the approved work and will submit a new 10-403 when the revised work is ready. If you have any questions or need additional information, please let me know. Thanks! Thank you, Joe Lastufka SIM Specialist Cell: (907) 227-8496 1 Office: (907) 564-4091 N BP Exploration Alaska 900 E. Benson Blvd. I Room: 717B I Anchorage, AK RBDMSLFA^,'jUI 1 0 2019 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Travis Montgomery Intervention and Integrity Engineer BP Exploration (Alaska), Inc. PO Box 879194 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU NGI-05 Permit to Drill Number: 176-014 Sundry Number: 319-263 Dear Mr. Montgomery: Alaska Gil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279J 433 Fax: 907.276.7542 www.aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this 33 o day of May, 2019. 4BDMS16"/MAY 3 12019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 s -I r:k.0 &Z d V it MAY 2 2 ?nre 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown ❑ Suspend Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ ChangeApproved Program Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other Repair WH w/ Sealant 0 - 2. Operator Name: BP Exploration (Alaska), Inc 4. Current Well Class: Exploratory ❑ Development ❑ 5. Permit to Drill Number: 176-014 3. Address: P.O. Box 196612 Anchorage, AK 99519-6612Stratigrephic ❑ Service 0 S. API Number: 50-029-20196-00-00 ' 7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? S. Well Name and Number: Will planned perforations require a spacing exception? Yes ❑ No 0 PBU NGI-05 9. Property Designation (Lease Number): 10, Field/Pools: ADL 028302 • PRUDHOE BAY. PRUDHOE OIL ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD(ft) : Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9404 8623 8024 7402 8024 9170 Casing Length Size MD TVD Burst Collapse Structural Conductor 81 20" 29-109 29-109 1530 520 Surface 2688 13-3/8" 29-2719 29-2719 5380 2670 Intermediate 8391 9-5/8" 27-8418 27-7748 8150/6870 5080/4760 Production Liner 1290 7" 8109-9400 7476-8620 1 8160 7020 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8807-9152 8092 - 8398 7-5/8" 29.7# x 7" 26# NT -80 25-8038 Packers and SSSV Type: 7" Baker SABL-3 Packer Packers and SSSV MD (ft) and TVD (ft): 7991 / 7374 7 Camw WRDP-2 SSV (Out to perform MIT's) 2184/2184 12. Attachments: Proposal Summary 0 Wellbore Schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service 0 14. Estimated Date for Commencing Operations: May 31, 2019 15. Well Status after proposed work: Oil ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ 0 Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Montgomery, Travis J be deviated from without prior written approval. Contact Email: Travis.Montgomery@bp.com Authorized Name: Montgomery, Travis J Contact Phone: +1 907 564 4127 Authorized Title: Interventions & Integrity Engineer Authorized Signature: - 'Y✓/ Date: S22111 V COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: /✓� 1_A1h✓ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test lwll� Location Clearance ❑ Other. Post Initial Injection MIT Req'd? Yes ❑ No ❑J Spacing Exception Required? Yes ❑ No Id Subsequent Form Required: T APPROVED BYTHE fin Approved by: COMMISSIONER COMMISSION Date: 5( 1 6 f i q 1 Form 10-403 Revised 04/2017 ORIGINAL RB°Mst- MAY 3 12019 Submit Fonn an Approved application is valid for 12 months from the date of approval. Attachments in Duplicate NGI-05 repair wellhead with sealants Well Interventions Engineer: Travis Montgomery (907) 564-4127 Pad Engineer: Don Brown History / The well is a gas injector with a history of TxIA and IAxOA communication. After an acoustic LDL indicated a leak at the SSSV, the TxIA communication was mitigated with Freudenberg packing on the SSSV. A caliper showed that the tubing was in good to fair condition with maximum wall penetration of 26% at 6072' MD in 2014. A MIT -T Passed to 2511 psi on 4/28/19. The well operates under Administrative Approval 3E.032 for TxIA communication. A condition of the AA requires a 2 -year AOGCC-witnessed MIT -IA to the maximum anticipated injection pressure. On 4/27/19, Slickline was preparing the well for the required 2 -year MIT -IA when they set a TTP and performed a passing MIT -T to 2511 psi. A subsequent CMIT-TxIA failed with a LLR of 0.4 bpm @ 1500 psi with rapid response in OA pressure. The failing CMIT-TxIA and subsequent response in OA pressure indicates a failure of the secondary barrier. When loading the OA, IA pressure slowly increased. The well has been secured with a TTP. A temperature log from 3000' to surface indicated a large leak at the IC packoff and another anomaly at 1935' MD while the IA was loaded at 0.75 bpm with returns being taken from OA to open -top tank on 5/9/19. IAxOA communication has been evident since 2013. The secondary seals of the IC packoff were suspected to be bad when the IC void couldn't be pressurized above 850 psi in 2013. A LPE indicated that the secondary seals of the IC packoff were failing in 2016. The void pressure didn't change when the OA was pressurized with nitrogen. The IC void couldn't be pressurized above 500 psi. Objective Mitigate IAxOA communication by repairing wellhead with sealant. Procedural steps Wellhead 1. Repair wellhead with sealants. Fullbore 1. AOGCC-witnessed MIT -IA to target pressure of 3600 psi. Slickline 1. Pull plug from RN NIP. Set SSSV. TRff= 7-1/16'CIW WELLHEAD= GRAY ACTUATOR= BAKER KB. E.E7 = 47.0' BF. E -EV = 18.34' KOP= 3300' Max Angle = 33' @ 4300' Dulum MD = CWTP CORRECTIONS DatumTVD= 8800'99 t e s¢ 2-71 2-71 2-71 2-71 2-n 2-71 2-71 2-71 2-71 3-31 3-31 331 3-1 331 SAFETY NOTES: WELL REQUORESA SSSV. "35/8' N G I 0 5 CSG SET ON EMERGENCY SLIPS' WO PROGRAM IN RUE NOTED GRAY 6-3/8' K BPV PROFILE IN TBG HGR CAN'T AOCOMMOD4TEA TWCVALVP" DATE REV BY COMMENTS DATE REV BY COMMENTS 04/06!76 ORIGINAL COMPLETION 12/03/15 RCT/,]MD RILL® PLUG (1123/15) 06112198 RWO 12115/15 DLW WD SET PRN PLUG (12/13/15) 12/31/01 CWTP CORRECTIONS 02/16/16 RJK/JM] PALIDPRNPUIG(1221/15) 1022/07 DDK/PJC ACTUATOR CORRECTION 05/07/19 RCBUMD SET Dsssv & PLUG (04/28119) 02/11/11 MB/JAD ADDED SSSV SAFETY NOTE 0522119 JN /JMD ADDED BF E.EV 0126114 RCT/PJC SET PRN PLUG PRUDHOE BAY UNIT WELL NGF05 PERMIT No: 176-0140 AP No: 50-029-20196-00 SEC 12, T11 N, R14E 450' FNL & 1039' FWL BP Expbratwn (Alaska) Wallace, Chris D (DOA) From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Sunday, April 28, 2019 8:33 AM To: Wallace, Chris D (DOA); AK, OPS EOC Specialists; AK, OPS FS1 DS Ops Lead; Ak, OPS FS1 Facility PTL; Ak, OPS FS1 Field PTL; AK, OPS FS1 OSM; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; AKOpsProdEOCTL, Brown, Don L.; G GPB FS1 Drillsites; Oestgaard, Finn; Vandergon, Mark A Cc: Regg, James B (DOA); AK, GWO Completions Well Integrity; AK, GWO DHD Well Integrity, AK, GWO Projects Well Integrity; AK, GWO SUPT Well Integrity, AK, GWO Well Integrity Well Information; AK, OPS FF Well Ops Comp Rep; AKIMS App User; Cismoski, Doug A; Daniel, Ryan; Dempsey, David G; Dickerman, Eric, Hibbert, Michael; Janowski, Carrie; Montgomery, Travis J; Munk, Corey; Obrigewitch, Beau; O'connor, Katherine; Sternicki, Oliver R, Tempel, Joshua; Worthington, Aras J Subject: NOT OPERABLE: Injector NGI-05 (PTD #1760140) failed pre-AOGCC CMIT-TxIA with IAxOA communication Attachments: NGI-05.pdf All, Gas Injector NGI-05 (PTD #1760140) operates under Administrative Approval 4E.032 for TxIA communication. A condition of the AA requires a 2 -year AOGCC witnessed MIT -IA. On 04/27/19 Slickline was preparing the well for the required 2 -year MIT -IA when they set a TTP and performed a passing MIT -T to 2,511 psi. A subsequent CMIT-TxIA failed with rapid response on the OA pressure. The failing CMIT-TxIA and subsequent response in OA pressure indicates a failure of the secondary barrier. The well has been secured with a TTP and will now be classified as NOT OPERABLE. The town engineer will evaluate for a LDL. Please respond with any questions. Andrew Ogg Well Integrity Engineer BP Global Wells Organization - Alaska Office: 907-659-8110 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Wednesday,May 03,2017 P.I.Supervisor 2e* 51110 SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)INC. NGI-05 FROM: Lou Laubenstein PRUDHOE BAY UNIT NGI-05 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry je— NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UNIT NGI-05 API Well Number 50-029-20196-00-00 Inspector Name: Lou Laubenstein Permit Number: 176-014-0 Inspection Date: 4/25/2017 Insp Num: mitLOL170426070700 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well NGI-05 - Type Inj G 1TVD 7372 - Tubing 2693 2894 - 2924 _ 2952 PTD 1760140 - Type Test SPT Test psi 3800 IA 51 3992. 4000 71 4011 • BBL Pumped: Io.4 - BBL Returned: 4 - OA 0 0 0 0 Interval REQVAR P/F P Notes: AA 4E.032 for TxIA communication 4444 - � ti�., c;,a( VOLic frke pt,u,v1e.rjf rthvntee, SCANNED AUG 1 0 2017 Wednesday,May 03,2017 Page 1 of 1 • Regg, James B (DOA) From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Thursday, May 11, 2017 3:15 PM 1 1 id 17 To: Regg,James B (DOA) Subject: RE: PBU NGI-05 MIT 4-25-17 Mr. Regg, I checked the well service report records and verified that 10.4bbls were uummped and 4bbls returned,the final IA pressure after bleed back was 200psi. Our standard practice is to do a follow up bleed anytime we conduct pressure test on lAs due thermal expansion of the test fluids; we do not record the volumes for these bleeds so I'm not certain on the total amount of fluid that was returned once the well was placed back on injection and the IA temperature was stabilized. As far as the discrepancy between bbls pumped versus bbls returned I think there are several factors at play ' 4 than can explain the apparent void that was in the IA. 1. The well has known TxIA communication and operates under AIO 04E.000. The well is manageable by bleeds and the IA has been bleed off twice since the last MIT-IA. Gas migration from the TxIA comm. is most likely the biggest contributor to the void space in the IA. 2. On 7/5/16 a nitrogen cap was placed on the inner annulus as part of a diagnostic procedure to test the inner casing packoffs with gas. The pre and post bleeding of this operation most likely displaced some fluid out of the f inner annulus. 3. For the MIT-IA the tubing was loaded with 722_bbls 2% KCL water followed by 100bbIs for 30°F 50/50 methanol water for freeze protect. The flow line temperature on this well while injecting has been reported as high as 150°F. Given the delay between shutting in the well, loading the tubing, setting the standing valve and then performing the MIT-IA it is reasonable to assume that the fluid in the inner annulus cooled and volume was lost due to thermal contraction. The exact amount of volume loss due to thermal effects is hard to quantify so I only offer this as a possible explanation. Looking over the TIO plots I don't see any indications that lead me to believe the TxIA communication has increased since it was first reported in 2008. I would be glad to elaborate on any of the items above or answer additional questions. Thanks, Joshua Stephens Well Integrity Engineer Office: 907-659-8110 Cell: 907-341-9068 1 • • From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, May 11, 2017 12:07 PM To: AK, GWO Well Integrity Engineer Subject: PBU NGI-05 MIT 4-25-17 Test report indicates there were 10.4 bbls pumped for the test with only 4 bbls returned. Please clarify the discrepancy, including the final bleed back pressure following the MIT. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 orjim.regg@alaska.gov. 2 STATE OF ALASKA likASKA OIL AND GAS CONSERVATION COMMIS. REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Pull Tubing ❑ Operations shutdown ❑ Suspend 0 Perforate 0 Other Stimulate 13 Alter Casing 0 Change Approved Program ❑ Plug for Redrill 0 Perforate New Pool 0 Repair Well 0 Re-enter Susp Well 0 Other:Water Wash IZ 2. Operator Name: BP Exploration(Alaska),Inc 4. Well Class Before Work 5. Permit to Drill Number: 176-014 3. Address: P.O.Box 196612 Anchorage, Development El Exploratory 0 AK 99519-6612 Stratigraphic ❑ Service ® 6. API Number: 50-029-20196-00-00 7. Property Designation(Lease Number): ADL 0028302 8. Well Name and Number: PBU NGI-05 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pools: PRUDHOE BAY,PRUDHOE OIL 11.Present Well Condition Summary: RECEIVED Total Depth: measured 9404 feet Plugs measured feet true vertical 8623 feet Junk measured 9170 feet NOV 21 2015 Effective Depth: measured 9313 feet Packer measured 7991 feet true vertical 8542 feet Packer true vertical 7374 feet AOGCC Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 81 20"94#H-40 30-111 30-111 1530 520 Surface 2688 13-3/8"72#MN-80 30-2718 30-2718 5380 2670 Intermediate See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Production Liner 1290 7"29#MN-80 8109-9400 7476-8620 8160 7020 Perforation Depth: Measured depth: See Attachment feet SCANNED APR 13 2O 7 True vertical depth: See Attachment feet Tubing(size,grade,measured and true vertical depth) See Attachment See Attachment See Attachment Packers and SSSV(type,measured and 7"Baker SABL-3 Packer 7991 7374 true vertical depth) 7 Camco WRDP-2 SSV 2170 2170 12.Stimulation or cement squeeze summary: Intervals treated(measured): 8807'-8817',8820'-8876',8891'-8966',8981'-9042',9047'-9182',9211'-9231'. Treatment descriptions including volumes used and final pressure: 20 Bbls Methanol,200 Bbls 50/50 Diesel/Xylene,720 Bbls 1%KCL w/0.02%F-103 Surfactant,1423 psi. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 139930 300 3221 Subsequent to operation: 142964 320 3249 14.Attachments:(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ® Exploratory 0 Development 0 Service ® Stratigraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil ❑ Gas 0 WDSPL ❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ 0 WAG 0 GINJ 0 SUSP 0 SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-502 Contact Catron,Garry R(Wipro) Email Garry.Catron@bp.com Printed Name Catron,Garry R(Wipro) Title PDC Principal Engineer Signature Ac'-/_ 1_ Phone +1 907 564 4424 Date 11/21/16 Form 10-404 Revised 5/2015 : -,, :;f;7" ��®�� r2ot! 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" OTFS: WELL REQUIRES A '9-S/8" (WELLFEAD'= GRAY G' CSG N EMERGENCY SLIPS*WO PROGRAM N FILE ACTUATOR= BAKER -05 TW NOTED GRAY 6-3/8'K BR!PROFILE N TBG HGR CANT KB.ELEV= 47.0 ACCOMMODATE A WC VALVE*** BF.ELEV= NA KOP= 3300' Max Angle= 33 @ 4300' 2182' -I7-5/8"X 7"XO,D=6.151" Datum MD= —" Datum ND= 8800'SS I 1"-----------1 2184' H7"CAMCO BAL-O SSSV NP,D=5.937" 7-5/8"TBG-IPC,29.7#,NT-80, H 2182' / % t 2188' Hr X 7-5/8"XO,D=6.151" .0459 bpf,ID=6.875" 1 2356' -19-5/8"JOY/ARCO 0/S CSG PATCH,D=8.625"J Minimum ID = 5.50" @ 8024' — 7" HES RN NIPPLE — 2393' -{9-5/6'FOC -- — — — [_ 2671' H9-5/8"FOC [13-3/8"CSG,72#,MN-80,D=12.347" 1-{ 2719' H, ' 7-5/8"TBG-IPC,29.7#,NT-80, -{ 7987' \ ) 7988' -17-5/8"X 7"XO,D=6.250" -0459 bpf,ID=6.875" 7$$9' -19-5/8"X 7"BKR SABL-3 PKR,D=6.00" ' ' L 8024' I-I 7 HES RN NIP,D=5.50" 7"TBG-IPC?,26#,NT-80, H 8035' / \—1- 8038' H7"WLEG,D=6.276" .0383 bpf,D=6.276" HELM()TT NOT LOGGED $108' BOT TACK SLV,D=7.00" , r 8114' 1-19-5/8"X 7"BOT MC LNR HGR1 9-5/8"CSG,47#,MN-80,D=8.681 I-[ 8418' ' PERFORATION SUMW1RY REF LOG: BHCS ON 03/21/76 I ANGLE AT TOP FERE: 28 @ 8807' Note:Refer to Production DB for historical perf data I SIZE SFF NTERVAL Opn/Sgz SHOT SOZ 2-78" 4 8807-8817 0 10/03/77 2-7/8" 4 8841-8876 0 10/03/77 I 2-7/8" 4 8891-8921 0 10/03/77 2-7/8" 4 8936-8966 0 10/03/77 2-7/8" 4 8981-9011 0 10/03/77 I 2-7/8" 4 9047-9072 0 10/03/77 2-718" 4 9110-9130 0 10/03/77 I 2-7/8" 4 9152-9182 0 10/03/77 2-7/8' 4 9211-9231 0 10/03/77 3-318" 4 8820-8841 0 11/23/86 I 3-3/8' 4 8921-8936 0 11/23/86 3-3/8" 4 9011-9042 0 11/23/86Ilk ? -FISH-FLAPPER FINSPRING FROM WRDP 3-3/8' 4 9072-9110 0 11/23/86 (01/11/06) 3-3/8" 4 9130-9152 0 11/23/86 [PBTD 1-1 9313' I 11111111 7"LNR,29#,MN-80,.0371 bpf,D=6.184" -I 9398' X111/111111/1/11 16666444 DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 04/06/16 ORIGINAL COMPLETION 12/03/15 RCT/JMD PULLED PLUG(11/23/15) WELL NGI-05 06/12/99 RWO 12/15/15 DLFVJMD SET PRN PLUG(12/13/15) PERMT No: 176-0140 u 12/31/01 CFVTP CORRECTIONS 02/16/16 RJK/JIu) PULLED PRN PLUG(12/21/15) API No: 50-029-20196-00 10/22/07 DDK/PJC ACTUATOR CORRECTION SEC 12,T11 N,R14E 450'FNL&1039'FWL 02/11/11 MB/..1M0 ADDED SSSV SAFETY NOTE 01/26/14 RCT/PJC SET FRN PLUG BP Exploration(Alaska) • • `SOF T� ,,,, (//7,7. THE STATE Alaska Oil and Gas OfA T ® c TA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 A :SY` Fax: 907.276.7542 www.aogcc.alaska.gov Christopher Stone %WED Petroleum Engineer BP Exploration(Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU NGI-05 Permit to Drill Number: 176-014 Sundry Number: 316-502 Dear Mr. Stone: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ale Cathy P. Foerster Chair DATED this day of October, 2016. RBDMS LL- OCT 1 0 2016 STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COM ON APPLICATION FOR SUNDRY APPROVALS 20 MC 25.280 1. Type of Request: Abandon 0 Plug Perforations ❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 ' Pull Tubing 0 Change Approved Program ❑ Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other Water Wash ® • 2. Operator Name: BP Exploration(Alaska),Inc 4. Current Well Class: 5. Permit to Drill Number: 176-014• 3, Address: P.O.Box 196612 Anchorage,AK Exploratory 0 Development ❑ 99519-6612 Stratigraphic 0 Service 0. 6. API Number: 50-029-20196-00-00 - 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes 0 No Et _R 'P r 9. Property Designation(Lease Number): 10. Field/Pools: SEP 27 n U i ADL 0028302 • PRUDHOE BAY,PRUDHOE OIL' /0/6//C L 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): A9143 CC 9404 • 8623 • 9313 8542 9170 Casing Length Size MD TVD Burst Collapse Structural Conductor 81 20"94#H-40 30-111 30-111 1530 520 Surface 2688 13-3/8"72#MN-80 30-2718 30-2718 5380 2670 Intermediate See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Production Liner 1290 7"29#MN-80 8109-9400 7476-8620 8160 7020 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment See Attachment See Attachment See Attachment See Attachment Packers and SSSV Type: 7"Baker SABL-3 Packer Packers and SSSV MD(ft)and TVD(ft): 7991, 7374 7 Camco WRDP-2 SSSV 2170, 2170 12.Attachments: Proposal Summary 0 Wellbore Schematic 0 13.Well Class after proposed work: Detailed Operations Program ® BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development 0 Service 0• 14.Estimated Date for Commencing Operations: 15. Well Status after proposed work: Oil 0 WINJ 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS 0 WAG ❑ GSTOR 0 SPLUG ❑ Commission Representative: GINJ 0 • Op Shutdown 0 Abandoned 0 17.I hereby certify that the foregoing is true and the procedure approved herein will not Contact Stone,Christopher be deviated from without prior written approval. Email Christopher.Stone@bp.com Printed Name Stone,Christopher Title DS 2&18 PE Signature a---kfli —. Phone +1 907 564 5518 Date Cr/2t� COMMISSION USE ONLY /( Conditions of approval:Notify Commission so that a representative may witness Sundry Number: Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test 0 Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes 0 No 1" r Spacing Exception Required? Yes ID No GD/ Subsequent Form Required: /0 -- IT& 4 0V APPROVED BYTHE Approved by: , COMMISSIONER COMMISSION Date: /Q __/ // VYL /D/11-ii 11�P !Y RBDMS 0— OCT 1 0 2016 ORIGINAL Submit Form and Form 10-403 Revised 11/2015 Approved application is valid for 12 months from the date of approval. l / , Attachments in Duplicate IFFFaao/ c(- ',r • ALASKA WELL ACTIVITY STATEMENT OF REQUIREMENTS (V2.0,DBR,LHD,EAZ,BPG 10/12/15) General Information Well Name: NGI-05 Well Type: Natural Flow Producer API Number: 50-029-20196-00 Well Activity Conventional 4 Classification: Activity Description: Water Wash Cost Code/AFE: APBINJEC Field/Reservoir: PRUDHOE IVISHAK 12 Month Avg IOR, bopd: Job Type: TREAMENTS Estimated Cost, $K: AWGRS Job Scope: TUBING WASH/PICKLE Other regulatory None requirements? Sundry Form 10-403 Yes Required? Sundry Form 10-404 Required? Yes Primary Secondary Engineer: Chris Stone Contact numbers: (907) 564-5518 (907)440-4011 Well Intervention Engineer: Tyson Shriver Contact numbers: (907)659-5525 (406) 690-6385 Lead Engineer: Chris Stone Contact numbers: (907) 564-5518 (907)440-4011 Date Created: September 22, 2016 Revisions(date,who,what changed): Current Well Status Information Water Rate or Gas Rate or FTP or Injection Date Oil Rate Inj Rate Gas Injection GOR Choke Setting Gas Lift Rate Pressure (bopd) (bwpd)Water Rate (scf/stbo) (Mscf/Day) (psi) Cut(%) (Mscf/Day) 9/21/2016 0 0 130,360 0 0 0 3,218 Current Status: Operable Flowing Inclination>70°at Depth(ft) NA Recentppm) NA 0 Maximum Deviation (Angle and H2S (date, ppm Depth) 33° 4,300' MD _ Datum depth,ft TVDss 8,800' TVDss Dogleg Severity(Angle and Depth) 4° 2,900' MD Reservoir pressure(date, psig) No Data No Data Minimum ID and Depth 5.500" 8,024' MD Reservoir Temp,F 180° F Shut-in Wellhead Pressure 2,440 psi Known mech. integrity AA A10 4E.032 for slow TxIA comm- 12/23/13 problems(specifics) Last downhole operation (date, 12/21/2015 Pulled PRN plug, drifted, set 7"Al SSSV operation) Most recent TD tag(date,depth, 1/22/2014 8,082' MD 2' 1-7/8"Stem,4.50"Cent, TEL, 3"S-Bailer toolstring OD) Surface Kit Fit-for-Service? YES If No,Why? Comments,well history, NGI-05's most recent water wash was pumped in August 2010. During this water wash 10 bbls of 60/40 background information, McOH, 54 bbls of diesel/xylene and 762 bbls of 110 F KCI was pumped. This water wash resulted in an etc: increase of injection volume of-50.0 MMSCFPD under the same injection pressures. TxIA communication surfaced in late 2013,a LPE was conducted proving up the primary seals, a caliper log was run indicating gooa tui a memory LVL was run resoiung in inconclusive iEsuits. I ne weu remained of until late Lula when Fruedenberg seals were deployed on the SSSV. Setting these seals on the SSSV seems to have resolved the slow TxIA communications. The well has a AA for slow TxIA communication granted on 12/23/2013 under AIO 4E.032,which stipulates that the well can be safely managed with periodic bleeds. Since restoring the well to gas injection service the well has experienced reduced injectitivy. The diesel/xylene water was will restore the injectivity to pre-SI rates. • • Well Intervention Details Please contact the SOR author if: 1.There is a change in work scope to the approved SOR 2.For well work>$100M estimated total cost, as soon as it is reasonably anticipated that the actual cost will exceed the estimated cost by 20%. Suspected Well Problem: Reduced infectivity due to depositions. Specific Intervention or Well Objectives: by cleaning Pump diesel/xylene water wash to restore injectivity by cleaning perfs and tubing. 2 3 Key risks,critical issues: Mitigation plan: 1 Control of Work Follow CoW Protocol 2 High Pressure Pumping Use pressure cross check checklist 3 Summary Step# Service Line Activity 1 F Pump diesel/xylene water wash as per attached pumping template. 2 3 Detailed work scope(If no RP/SOP exists for the intervention type,a well-specific procedure is required in addition to the SOR): 1 2 3 Performance Expectations(may be NA if no change anticipated due to the intervention) BOPD: MMSCFD: BWPD: Expected Production Rates: FTP(psi): Choke setting: PI(bfpd/psi dp) Post job POP instructions: Post water wash return well to gas injection service. Attachments-include in separate excel worksheets Required attachments: Current wellbore schematic As needed: Perf form,logging form,well test chart,annotated mini log,annotated log section,tubing/casing tallies,Wellhead info,etc Approvals Management Approval: Date: Wells Approval: Date: . 0 • WELLHEAD_PRES vs. INJ_VOL_ALLOC • 3700 CO , 365D DO I'll 0,t 35 50 00 2016 Reduced injectivity r- • 350000 41 • • 3450 CO (,,i) • 4.7:17 • 4110 340000 : 41. . taw 33-00 00 • •W • 2 • 410 • • 330000 • IIIIP ' 325000 • ... 5 321k CO g315000 ;.--,,.., 310000 111P • ,.,,, • 0 IP 3050 00 3C00 CO • • 2950 00 290000 000 50000 00 1DCCC0CO 150CCO 00 2:0::)0( CC INJ_VOL_ALLOC • • Marking: IN Marking v Marker by: (None) v Color bar. YeaNLAST_ . le •2010 •2011 • • •41) • I S S •2012 � •2013 • •2014 p %OS • •2015 •41°b.) • •2016 Shave by • (None) 410 • All values Size by: (None) 250000.00 300000.00 350000.00 100000.00 U Q 0 0 0 0 0 0 0 o 0 0 RI N r, CO CO (0 N N (A CA — CO O O h O T- ct N. N. 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DATE REV BY COMMENTS PRUDHOE BAY UNIT 04/06/76 ORIGINAL COMPLETION 12/03/15 RCT/JM.) PULLED LUG(11/23/15) WELL: NGI-05 06/12/99 RWO 12/15/15 DLWJM) SET PRN PLUG(12/13/15) PERMIT No: 176-0140 12/31/01 CWTP CORRECTIONS 02/16/16 RJK/JM) PULL )PRN PLUG(12/21/15) API No: 50-029-20196-00 10/22/07 DDK/PJC ACTUATOR CORRECTION SEC 12,T11 N,R14E 450'FNL 8 1039'PAL 02/11/11 11/3/J4.0 ADDED SSSV SAFETY NOTE 01/26/14 RCT/PJC SET FRN PLUG BP Exploration(Alaska) l7b014 0 Regg, James B (DOA) From: AK, OPS FS1 DS Ops Lead <AKOPSFS1DSOpsLead@bp.com> c 511/ 1,0 t Sent: Wednesday, March 16, 2016 1:14 PM To: AK, OPS FF Well Ops Comp Rep; Regg, James B (DOA); Jones, Jeffery B (DOA) Cc: Cocklan-vendl, Mary E; Pomeroy, Glen; AK, OPS FS1 Field OTL; AK, OPS FS1 OSM; AK, OPS FS1 DS Ops Lead Subject: INFO- NGI-05 Blowdown line Deficiency Report Importance: High Lee, The NGI-05 blowdown spool was replaced today and has been pressure tested. This deficiency noted by the state has been repaired. Johnny(Dumont FS1 DS Lead Ops .Jf#5547/Phone 659-5394 Aft/Dave Demaris SCANNED SEP 2 12016 "If your presence doesn't make a&fference your words can never create e.ffect" From: AK, OPS FF Well Ops Comp Rep Sent: Saturday, February 13, 2016 8:40 AM To: Regg, James B (DOA); Jones, Jeffery B (DOA) Cc: Cocklan-vendl, Mary E; Pomeroy, Glen; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Field OTL; AK, OPS FS1 OSM Subject: RE: NGI-05 Blowdown line Deficiency Report Based on this email chain and the conversation I had with the FS1 Lead Tech, I would say that is a sound target date. From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Saturday, February 13, 2016 8:34 AM To: AK, OPS FF Well Ops Comp Rep; Jones, Jeffery B (DOA) Cc: Cocklan-vendl, Mary E; Pomeroy, Glen Subject: RE: NGI-05 Blowdown line Deficiency Report So completion of work by March 30? Sent from my Samsung Galaxy smartphone. Original message From: "AK, OPS FF Well Ops Comp'Rep" <AKOPSFFWellOpsCompRepnbp.com> Date: 02/13/2016 8:26 AM (GMT-09:00) i 19864-it,4T—Ocs PTOI7 i4c Regg, James B (DOA) From: Regg,James B (DOA) Sent: Saturday, February 13, 2016 9:24 AM Zll6'lW To: AK, OPS FF Well Ops Comp Rep;Jones,Jeffery B (DOA) Cc: Cocklan-vendl, Mary E; Pomeroy, Glen;AK, OPS FS1 DS Ops Lead;AK, OPS FS1 Field OIL;AK, OPS FS1 OSM Subject: RE: NGI-05 Blowdown line Deficiency Report Ok. As always let us know if the time line slips and we can discuss additional time to complete this work. ,./• Thank you. Sent from my Samsung Galaxy smartphone. SCANNED SEP. 2 32016 Original message From: "AK, OPS FF Well Ops Comp Rep" <AKOPSFFWellOpsCompRep@bp.com> Date: 02/13/2016 8:40 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov>, "Jones, Jeffery B (DOA)" <jef£jones@alaska.gov> Cc: "Cocklan-vendl, Mary E" <mary.cocklan-vendl@bp.com>, "Pomeroy, Glen" <G1en.Pomeroy@bp.com>, "AK, OPS FS1 DS Ops Lead" <AKOPSFSIDSOpsLead@bp.com>, "AK, OPS FS1 Field OTL" <AK_OPSFS1FieldOTL@bp.com>, "AK, OPS FS1 OSM" <AKOPSFS1OSM@bp.com> Subject: RE: NGI-05 Blowdown line Deficiency Report Based on this email chain and the conversation I had with the FSI Lead Tech, I would say that is a sound target date. From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Saturday, February 13, 2016 8:34 AM To: AK, OPS FF Well Ops Comp Rep; Jones, Jeffery B (DOA) Cc: Cocklan-vendl, Mary E; Pomeroy, Glen Subject: RE: NGI-05 Blowdown line Deficiency Report So completion of work by March 30? Sent from my Samsung Galaxy smartphone. Original message From: "AK, OPS FF Well Ops Comp Rep" <AKOPSFFWellOpsCompRep@bp.com> Date: 02/13/2016 8:26 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg alaska.gov>, "Jones, Jeffery B (DOA)" <jeff.jones@alaska.gov> Cc: "AK, OPS FF Well Ops Comp Rep" <AKOPSFFWellOpsCompRep@bp.com>, "Cocklan-vendl, Mary E" <mary.cocklan-vendl@bp.com>, "Pomeroy, Glen" <Glen.Pomeroy(aIbp.com> Subject: FW: NGI-05 Blowdown line Deficiency Report 1 S • Jim Below is the answer for the NGI-05 repair timing. Let me know if you have any questions or concerns. Lee Hulme FF Well Ops Compliance Advisor BP Exploration (Alaska) Inc. Office: (907) 659-5332 Cell: (907) 229-5795 Harmony — 7187 (Alternate: Vince Pokryfki) From: AK, OPS FS1 DS Ops Lead Sent: Saturday, February 13, 2016 8:11 AM To: AK, OPS FF Well Ops Comp Rep; AK, OPS FS1 Field OTL; AK, OPS FS1 OSM; AK, OPS FS1 Facility MTL; AK, OPS FS1 OSM; Ak, ops fs1 seawater maint planner Cc: Cocklan-vendl, Mary E; AK, OPS FS1 DS Ops Lead Subject: RE: NGI-05 Blowdown line Deficiency Report Material for this is on the slope. We are currently working on getting it fabricated at the fab shop. Once complete, scaffold will be built and install will be done. At this time scaffolding is scheduled for March 16th Johnny(Dumont FS1 DS Lead Ops ,7f#5547/Thane 659-5394 Aft/Dave(Demaris "�fyour presence doesn't make a reference your words can never create effect" From: AK, OPS FF Well Ops Comp Rep Sent: Friday, February 12, 2016 12:46 PM To: AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Field OTL; AK, OPS FS1 OSM Cc: AK, OPS FF Well Ops Comp Rep; Cocklan-vendl, Mary E Subject: FW: NGI-05 Blowdown line Deficiency Report Importance: High Can someone supply an answer for Jim? Thanks, Lee Hulme FF Well Ops Compliance Advisor BP Exploration (Alaska) Inc. Office: (907) 659-5332 Cell: (907) 229-5795 Harmony— 7187 (Alternate: Vince Pokryfki) 2 • • From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, February 12, 2016 12:28 PM To: AK, OPS FF Well Ops Comp Rep Cc: Cocklan-vendl, Mary E; Pomeroy, Glen; Jones, Jeffery B (DOA) Subject: RE: NGI-05 Blowdown line Deficiency Report My fault for not getting back to you in a more timely manner; that has essentially been a 50-day extension (so far). When will this be corrected? Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: AK, OPS FF Well Ops Comp Rep [mailto:AKOPSFFWellOpsCompRepAbp.com] Sent: Tuesday, December 22, 2015 1:16 PM To: Jones, Jeffery B (DOA); Regg, James B (DOA) Cc: AK, OPS FF Well Ops Comp Rep; Cocklan-vendl, Mary E; Pomeroy, Glen Subject: FW: NGI-05 Blowdown line Deficiency Report Jim and Jeff, Please see below note and attachments addressing the Deficiency notice that was sent in for NGI-05 Blow Down line. We are requesting an extension for corrective actions due to materials due dates and maintenance schedules. Call with any questions that you may have. Vince Vince Pokryfki Field Well Compliance Advisor BP Exploration (Alaska) Inc. PBOC - B103 Office: (907) 659-5332 Cell: (907)354-1352 Harmony-7187 Alternate: Lee Hulme From: AK, OPS FF Well Ops Comp Rep Sent: Tuesday, December 22, 2015 10:20 AM To: Cocklan-vendl, Mary E; Pomeroy, Glen Cc: AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer; Obrigewitch, Beau; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Field OTL; AK, OPS FS1 OSM; Daniel, Ryan; AK, OPS FF Well Ops Comp Rep Subject: NGI-05 Blowdown line Deficiency Report 3 • • Team, Enclosed is the signed AOGCC Deficiency Report that was submitted to BP on 12-18-15 during a State witnessed MIT-IA concerning the blowdown piping on NGI-05 being in a bind. Please note that this report from the State of Alaska is a new process that we will be dealing with in the future. Contained within the follow up instructions on the Deficiency Report it states that BP must reply within 7 days of receipt. Since we do not have a "correct date" established, we will be asking for an extension for the corrective action. The extension request instructions are defined within the "Follow up Instructions" on the bottom of the attached Deficiency report. Attached to this email is note from the FS1 Drill Site Lead Operator that provides a brief history and a repair plan for the blowdown piping. As stated,this line sits at 0 psi and is only exposed to slight pressure when used for blow down maintenance or used in an emergency, this piping is connected to a vented atmospheric pit. Repair Work Orders have been written and materials are on order to ultimately relieve the stress on the piping. Mary Cocklan-Vendl the Pipeline Compliance Manger will forward the attached Report and documentation to the AOGCC.The Full Field Well Compliance Advisor will work with Mary and FS1 Leadership to track progress until repairs have been made. Please call with any questions that you may have. Vince Vince Pokryfki Field Well Compliance Advisor BP Exploration (Alaska) Inc. PBOC - B103 Office: (907) 659-5332 Cell: (907)354-1352 Harmony- 7187 Alternate: Lee Hulme 4 L\14" • 3 2 State of Alaska Oil and Gas Conservation Commission Deficiency Report Location: PBF NG1-05 • Date: 12/18/15 PTD: 1760140 Operator: BPXA Type Inspection: MIT Operator Rep: Beau Obrigewitch Inspector: Jeff Jones - Position: Well Integrity Engineer Op.Phone: 659-5766 Correct by(date): Op.Email: BEAU.OBRIGEWITCH@bp.com Follow Up Required: Detailed Description of Deficiencies Date Corrected The outlet blow down line and the companion valve on top of this well head appear to be stressed to the point that the blowdown line is being bent, possibly due to subsidence. Team, Please reference the enclosed attachment for historical information and the repair plan for NG!-05 Blowdown line. Please call the BP Full Field Well Compliance Advisor at 659-5332 with any questions. The below Operator Rep signature is from the FS1 Field OTL. 659-8738 Operator Rep Signatures: 411.1" /c 1 /(S— AOGCC inspector *After signing,a copy oI ti4orm to be left with the operator. Follow-up Instructions Return a copy of this Deficiency Report to AOGCC(Attention:Inspection Supervisor)within 7 days of receipt. Include the "Date Corrected"and atta.h supporting documentation for each corrective action implemented to address the deficiencies. If a follow-up inspection w:s performed by AOGCC,include the date arid name of Inspector. Extensions for corrective actions taking longer than he"correct by"date must requested and accompanied by justification(Attention:Inspection Supervisor). Failure to provide the req red documentation of corrective actions constitutes a violation of 20 MC 25.300 and is subject to enforcement action un.-r 20 MC 25.535 Revised 3/9/2015 • • PBU NGI-05 (PTD 1760140) 81 wdown Line Attachment to Deficiency Report— 121815 Photo courtesy of BPXA 12/22/2015 i ¥ 1 0 ) /» ,t r , i \ \ „it \} . , . , 1 / » , » ° 2 . - y: 1 � . E , 1 f1 4, s i ,... 0 • c a) n?)P E 0 ° c .4 •-• a) o a a c 23 E L5 c o em ..- _9. s) ti .c a) a -al a 2 ti ; tvw 0 .s 25, ...., tr) til w O. C .--o rn 0 3; o -o 0 to 0 CI --__. (=> C',1 , Cl c c ao -ft t 0 iIi .c0 co gi .. :s 0 o CI, `i '6'a <7) -5, .4 .z F.. 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NGI-05 FROM: Jeff Jones PRUDHOE BAY UNIT NGI-05 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry Vgt--- NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UNIT NGI-05 API Well Number 50-029-20196-00-00 Inspector Name: Jeff Jones Permit Number: 176-014-0 Inspection Date: 12/18/2015 Insp Num: mitJJ151221075957 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min WellNGI-05 , Type Inj N, TVD 7372 r RTubing 198 2404 - 2387 - I 2375 -1 PTD 1760140 - iT e Test SPT Test psi 1843 IA 32 4272- 4241 — 4224 Interval OTHER P/F P OA o 0 0 o Notes: 1 well inspected,one exception noted;the companion valve and blow down line on the production tree appear to stressed to point of bending the steel piping,possibly due to subsidence.Deficiency report initiated. t SCANNED 2 1 U Friday,January 08,2016 Page 1 of 1 • fk ti 17 0 14o Rte, James B (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com> \(4 Iqz Sent: Tuesday, December 22, 2015 9:22 AM 7/S To: AK, OPS FS1 OSM; AK, OPS FS1 Facility OTL; AK, OPS FS1 Field OTL; AK, OPS FS1 DS Ops Lead; AK, OPS PCC EOC TL;AK, OPS PCC Ops Lead;AK, D&C Well Services Operations Superintendent; AK, D&C Wireline Operations Superintendent; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB West Wells Opt Engr;AK, RES GPB East Wells Opt Engr;AK, OPS EOC Specialists;AK, OPS Prod Controllers; AK, OPS FS1 GAS INJ OPERATOR; Morrison, Spencer; 'chris.wallace@alaska.gov' Cc: AK, D&C DHD Well Integrity Engineer;AK, D&C Well Integrity Coordinator;AK, D&C Projects Well Integrity Engineer;AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Sayers, Jessica; Dickerman, Eric; 'jim.regg@alaska.gov' Subject: OPOERABLE: Gas Injector NGI-05 (PTD #1760140)AOGCC MIT-IA Passed Post SSSV Changeout Attachments: Injector NGI-05 (PTD #1760140) TIO Plot.docx All, Injector NGI-05 (PTD#1760140) is no longer presenting signs of tubing by inner annulus communication following a subsurface safety valve changed out on November 24, 2015. An AOGCC witnessed MIT-IA passed on December 18, 2015 indicating two competent barriers in the wellbore. The well is reclassified as Operable and may remain online as needed. An updated TIO plot has been included for reference. Please call with any questions or concerns. Thank you, Kevin Parks '11t#1, SC ANNEX BP Alaska-Well Integrity Coordinator Global Wells Organizatlor Office: 907.659.5102 WIC Email:AKDCWellIntegritvCoordinatorPbp.com From: AK, D&C Well Integrity Coordinator Sent: Monday, November 23, 2015 9:43 AM To: AK, OPS FS1 OSM; AK, OPS FS1 Facility OTL; AK, OPS FS1 Field OTL; AK, OPS FS Ops Lead; AK, OPS PCC EOC TL; AK, D&C Well Services Operations Superintendent; AK, D&C Wireline Opera Superintendent; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells •. Engr; AK, OPS EOC Specialists; AK, OPS Prod Controllers; AK, OPS FS1 GAS INJ OPERATOR; Morrison, Spence • chris.wallace@alaska.gov' Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Well Integri 'oordinator; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Sayers, sica; Dickerman, Eric; AK, D&C Wells Slickline Coordinator; 'jim.regg@alaska.gov' Subject: UNDER EVALUATION: Gas Injector NGII-05,( D #1760140) Ready to be place on injection for Evaluation All, V 1 • 111 tt+-fl 0 • E 0 ap 0 3 ' 0 CD Z • U 4) r" wn 0F; ♦!S I76o/4-o Regg, James B (DOA) From: Regg, James B (DOA) � 12-17(1C Sent: Saturday, December 05, 2015 11:19 AM Z To: AK, D&C Well Integrity Coordinator Subject: RE: Permission for continued operations Injector NGI-05 (PTD #1760140)while prepping for upcoming compliance testing Request approved Sent from my Samsung Galaxy smartphone. Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Date: 12/05/2015 11:18 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov> Cc: "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov>, DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay(aialaska.gov>, "AK, D&C Well Integrity Coordinator" <AKDCWelllntegrityCoordinator@bp.com>, "AK, D&C Projects Well Integrity Engineer" <AKDCProjectsWellIntegrityEngineer(abp.com> Subject: RE: Permission for continued operations Injector NGI-05 (PTD #1760140) while prepping for upcoming compliance testing Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> bp.com> Date: 12/05/2015 11:18 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg(alaska.gov> Cc: "Wallace, Chris D (DOA)" <chris.wallac@alaska.gov>, DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.baynalaska.gov>, "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com>, "AK, D&C Projects Well Integrity Engineer" <AKDCProj ects WelllntegrityEngineer@bp.com> Subject: RE: Permission for continued operations Injector NGI-05 (PTD #1760140) while prepping for upcoming compliance testing Jim, SC. 4NEU The wellwork is tentatively scheduled for December 11`h, 2015.The well will be online for approximately a week give or take one or two days for any change in scheduling. Thank you, Whitney Pettus 1 • • • (dlternot e: Actin Pa,ks) BP Alaska-Well Integrity Coordinator Nal WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinatorPBP.com From: Regg, James B (DOA) [mailto:jim.reggftalaska.gov] Sent: Saturday, December 05, 2015 9:10 AM To: AK, D&C Well Integrity Coordinator Cc: Wallace, Chris D (DOA); DOA AOGCC Prudhoe Bay Subject: RE: Permission for continued operations Injector NGI-05 (PTD #1760140) while prepping for upcoming compliance testing What is the anticipatrd timing for installation of the tubing tail plug? Sent from my Samsung Galaxy smartphone. Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator cr bp.com> Date: 12/05/2015 6:25 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.reggalaska.gov> Cc: "Wallace, Chris D (DOA)" <chris.wallace(,,alaska.gov>, "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Subject: Permission for continued operations Injector NGI-05 (PTD #1760140) while prepping for upcoming compliance testing Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator(a�bp.com> Date: 12/05/2015 6:25 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov> Cc: "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov>, "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Subject: Permission for continued operations Injector NGI-05 (PTD #1760140) while prepping for upcoming compliance testing Jim, 2 • • . As per our discussion, Injector NGI-05 (PTD #1760140), gas injector operating under Administrative Approval Area Injector Order (AIO) 4E.032 for slow tubing by inner annulus communication, is due for upcoming AOGCC compliance testing. Due to the high pressure guidelines regarding obtaining a test to max anticipated injection pressure, BP will set a tubing tail plug in order to hold back pressure on the tubing while performing the required mechanical integrity test on the inner annulus. BP requests •ermission to leave the well on cont.. -• in'ection until the well is secured for the AOGCC MIT-IA. Plan Forward: 1. Operations: Leave well on injection 2. Slickline: Set tubing tail plug 3. Fullbore: Perform AOGCC MIT-IA while holding back pressure on the tubing A TIO plot has been included for reference. Thank you, Whitney Pettus �_11/erf�rafe� Ke 'in Pat I BP Alaska-Well Integrity Coordinator {=Pis WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator(a)BP.com 3 • • Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com> Sent: Saturday, December 05, 2015 11:19 AM To: Regg,James B (DOA) Cc: Wallace, Chris D (DOA); DOA AOGCC Prudhoe Bay;AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer Subject: RE: Permission for continued operations Injector NGI-05 (PTD#1760140)while prepping for upcoming compliance testing Jim, The wellwork is tentatively scheduled for December 11th, 2015.The well will be online for approximately a week give or take one or two days for any change in scheduling. Thank you, Whitney Pettus (Alternate:Kevin Parks) BP Alaska-Well Integrity Coordinator GW SCAMS APR 2 2016 WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator@BP.com From: Regg, James B (DOA) [mailto:jim.regg@ alaska.gov] Sent: Saturday, December 05, 2015 9:10 AM To: AK, D&C Well Integrity Coordinator Cc: Wallace, Chris D (DOA); DOA AOGCC Prudhoe Bay Subject: RE: Permission for continued operations Injector NGI-05 (PTD #1760140) while prepping for upcoming compliance testing What is the anticipatrd timing for installation of the tubing tail plug? Sent from my Samsung Galaxy smartphone. Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@,bp.com> Date: 12/05/2015 6:25 AM (GMT-09:00) To: "Regg, James B (DOA)" <iim.regg@alaska.gov> Cc: "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov>, "AK, D&C Well Integrity Coordinator" <AKD C W ell IntegrityCoordinator@bp.com> Subject: Permission for continued operations Injector NGI-05 (PTD #1760140)while prepping for upcoming compliance testing 1 • Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Date: 12/05/2015 6:25 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov> Cc: "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov>, "AK, D&C Well Integrity Coordinator" <AKDC W ell IntegrityCo ordinator@bp.com> Subject: Permission for continued operations Injector NGI-05 (PTD#1760140) while prepping for upcoming compliance testing Jim, As per our discussion, Injector NGI-05 (PTD #1760140), gas injector operating under Administrative Approval Area Injector Order (AIO) 4E.032 for slow tubing by inner annulus communication, is due for upcoming AOGCC compliance testing. Due to the high pressure guidelines regarding obtaining a test to max anticipated injection pressure, BP will set a tubing tail plug in order to hold back pressure on the tubing while performing the required mechanical integrity test on the inner annulus. BP requests permission to leave the well on continued injection until the well is secured for the AOGCC MIT-IA. Plan Forward: 1. Operations: Leave well on injection 2. Slickline: Set tubing tail plug 3. Fullbore: Perform AOGCC MIT-IA while holding back pressure on the tubing A TIO plot has been included for reference. Thank you, Whitney Pettus (Alternate:Kevin Parks) BP Alaska-Well Integrity Coordinator GV WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinatorABP.com 2 • S Wallace, Chris D (DOA) From: Regg,James B (DOA) Sent: Friday, November 20, 2015 11:30 PM To: AK, D&C Well Integrity Coordinator;Wallace, Chris D (DOA) Subject: RE: Upcoming well work for Injector NGI-05 (PTD#1760140) Put on injection for Evaluation As discussed. OK to place on injection. Sent from my Samsung Galaxy smartphone. SCOW MAY 1 12016 Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Date: 11/20/2015 6:07 PM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov>, "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov> Cc: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator(a bp.com> Subject: Upcoming well work for Injector NGI-05 (PTD #1760140)Put on injection for Evaluation Original message From: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Date: 11/20/2015 6:07 PM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg(aalaska.gov>, "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov> Cc: "AK, D&C Well Integrity Coordinator" <AKDCWellIntegrityCoordinator@bp.com> Subject: Upcoming well work for Injector NGI-05 (PTD #1760140) Put on injection for Evaluation Jim, Per your conversation with Ryan Daniel, BP would like to bring online Gas injector NGI-05 (PTD #1760140) which operates under Administrative Approval Area Injection Order(AIO) 4E.032 for tubing x inner annulus communication. The path forward will be to reset the downhole subsurface valve with extended swell packing and monitor the inner annulus pressure when the well is online to determine if it is an appropriate mitigation factor. The well will be monitored for pressure trends with the understanding if the inner annulus pressure approaches 2,500 psi (per AA) the well will be shut in and the AOGCC notified. When the well becomes stable an AOGCC MIT-IA will be performed. With your approval, we will initiate the necessary well work. Kevin Parks (Alternate: Whitney Pettus) BP Alaska-Well Integrity Coordinator GANGlobal Wells Organization 1 WELL LOG TRANSMITTAL II. PROACTIVE DIAGNOSTIC SERVICES, INC. To: AOGCC Makana Bender 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793-1225 \1-1 G- 012k 23Y 74{ RECEIVED f i 0 3 2014 DATA LOGGED Z�3 /2D14 OGCCM K BENDER RE: Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of : BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Sarah Gunkel LR2-1 900 Benson Blvd. Anchorage, AK 99508 and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 w � MAO 1) Leak PointTm Survey 23 -Jan -14 NGI-05 BL/ CD 2) Signed Print Name: Date 50-029-20196-00 PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGEPMEMORYLOG.COM WEBSITE: WWW.MEMORYLOG.COM D:\Archi ves\MasterTempl ateFi les\Templates\Di stribution\Transmittal S heets\BP_Transmit. docx Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator [AKDCWeIIlntegrityCoordinator@bp.com] Sent: Thursday, January 23, 2014 4:21 PM To: AK, OPS FS1 OSM; AK, OPS FS1 Facility OTL; AK, OPS FS1 DS Ops Lead; AK, OPS PCC EOC TL; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB West Wells Opt Engr; AK, RES GPB Wells ells Opt Engr; AK, OPS EOC Specialists; AK, OPS Prod Controllers; G GPB FS1 Drillsites: AK, OPS FS1 GAS INJ OPERATOR; Farinez. Javier; Wallace, Chris D (DOA) Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer, Regg, James B (DOA) Subject: NOT OPERABLE: Gas Injector NGI-05 (PTD #1760140) Sustained Outer Annulus Casing Pressure Above MOASP Attachments: Injector NGI-05 (PTD #1760140) TIO Plot.docx All, Injector (PTD #1760140) is a Not Operable gas injector that has known tubing x inner annulus communication. The outer annulus was found to have sustained casing pressure above MOASP on 01/22/2013. The pressures were tubing/inner annulus/outer annulus of 2540/1860/1050 psi. The outer annulus was bled down the same day. There is currently an intervention taking place on the well to diagnose the source of the tubing x inner annulus communication. A copy of the TIO plot is attached for reference. Please call with any questions. Jack Disbrow BP Alaska - Well Integrity Coordinator SCANNED GWGlobal Wells Organization Office: 907.659.5102 WIC Email: AKDCWeIIlntegrityCoordinator@bp.com From: AK, D&C Well Integrity Coordinator Sent: Monday, December 23, 2013 3:47 PM To: AK, OPS FS1 OSM; AK, OPS FS1 Facility OTL; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 DS5 Operator; AK, OPS PCC EOC TL; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Farinez, Javier; G GPB FS1 Drillsites; 'chris.wallace@alaska.gov'; Jim.regg@alaska.gov'; Derrick, Mackie; AK, OPS FF Well Ops Comp Rep Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer; Climer, Laurie A Subject: NOT OPERABLE: Gas Injector NGI-05 (PTD #1760140) not meeting AA requirements All, Gas Injector NGI-05 (PTD #1760140) has exhibited increased tubing by inner annulus communication, and as such does not meet the AA criteria set out by the AOGCC in AA 4E.032. At this time the well has been reclassified as Not Operable, and will be secured shortly. Future diagnostics will be ran to evaluate the wellbore condition. Supporting documentation has been included for reference. Please call with any questions. Thank you, Laurie Climer BP Alaska - Well Integrity Coordinator GSA j tas�tra'drB�ls �(�j WIC Office: 907.659.5102 WIC Email: AKDCWelllntegrityCoordinator@BP.com Injector NGI-05 (PTD #1760140) TIO Plot W." NGM 4.000 3.000 tTbg t 01 2.00D OA DOA 1.000 IUM13 11/0213 11/W13 11116113 112113 1VA13 12)07/13 121x13 11/21/13 12M13 OUDC14 01,11114 01118114 Wallace, Chris D (DOA From: AK, D&C Well Integrity Coordinator[AKDCWelllntegrityCoordinator@bp.com] Sent: Monday, December 23, 2013 3:47 PM To: AK, OPS FS1 OSM; AK, OPS FS1 Facility OTL; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 DS5 Operator; AK, OPS PCC EOC TL; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Farinez, Javier; G GPB FS1 Drillsites; Wallace, Chris D (DOA); Regg, James B (DOA); Derrick, Mackie; AK, OPS FF Well Ops Comp Rep Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer; Climer, Laurie A Subject: NOT OPERABLE: Gas Injector NGI-05 (PTD #1760140) not meeting AA requirements Attachments: NGI-05 Wellbore Schematic.pdf; NGI-05 AA 4E.032 06-09-08.pdf; NGI-05 90 day TIO and Inj Plot 12-23-13.docx; NGI-05 1 year TIO and Inj Plot 12-23-13.docx All, Gas Injector NGI-05 (PTD #1760140) has exhibited increased tubing by inner annulus communication, and as such does not meet the AA criteria set out by the AOGCC in AA 4E.032. At this time the well has been reclassified as Not Operable, and will be secured shortly. Future diagnostics will be ran to evaluate the wellbore condition. Supporting documentation has been included for reference. Please call with any questions. Thank you, Laurie Climer (Alternate: Jack Disbrow) BP Alaska - Well Integrity Coordinator Orgaft)8niZo" WIC Office: 907.659.5102 WIC Email: AKDCWelllntegrityCoordinator@BP.com SCAMM 61 "�umq • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg �� `. 4 I ¢ DATE: Tuesday, April 17, 2012 P.I. Supervisor � � t I ( SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC NGI -05 FROM: John Crisp PRUDHOE BAY UNIT NGI -05 Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry :7 NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UNIT NGI -05 API Well Number 50- 029 - 20196 -00 -00 Inspector Name: John Crisp Permit Number: 176 -014 -0 Inspection Date: 4/15/2012 Insp Num: mitJCr120416054248 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well NGI -05 ' Type Inj N I VD 7372 ' IA 988 4224 '' 4170 4153 PTD 1760140 " Type Test SPT Test psi 4200 ' OA 0 10 10 10 Interval RE P/F P ' Tubing 2576 - 3120 , 3104 3088 pumped for test. 2 year MITIA AA 4E.032. 3.1 bbls um Notes: Y p p \4 /k 4c. o -z.- JUN C I ZO12 Tuesday, April 17, 2012 Page 1 of 1 OPERABLE: NGI -05 (PTD #1760140) Confirmed Surface Casing Integrity Page 1 of /A Maunder, Thomas E (DOA) From: AK, D &C Well Integrity Coordinator [ AKDCWelllntegrityCoordinator @bp.com] Sent: Saturday, June 11, 2011 8:22 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS FS1 OSM; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Facility OTL; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Cismoski, Doug A; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead; Daniel, Ryan Cc: AK, D &C Well Integrity Coordinator; Chivvis, Robert; Walker, Greg (D &C) Subject: OPERABLE: NGI -05 (PTD #1760140) Confirmed Surface Casing Integrity Attachments: NGI -05 (PTD #1760140) TIO and Injection Plot.doc All, Injector NGI -05 (PTD #1760140) passed a 5 day Outer Annulus Repressurization Test (OART) from 6/5- 6/10/2011. The well has shown no signs of OA repressurization for 18 days since the arctic pack was flushed from the outer annulus surface equipment on 5/23/2011. The well is reclassified as Operable. A copy of the current TIO and injection plot are included for reference. «NGI -05 (PTD #1760140) TIO and Injection Plot.doc» Please call if you have any questions. Thank you, Gerald Murphy (alt. Mehreen Vazir) Well Integrity Coordinator Office (907) 659 -5102 Cell (907) 752 -0755 "�` - , l: c, Pager (907) 659 -5100 Ext. 1154 : AK, D &C Well Integrity Coordinator Sent May 20, 2011 12:43 PM To: 'Maunder, • .s E (DOA)'; 'Regg, James B (DOA); 'Schwartz, Guy L (DOA) ; AK, OPS FS1 OSM; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Facility OTL; AK, RES GPB Wells Opt Engr; Cismoski, Doug A; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead Cc: Chivvis, Robert; Walker, Greg (D &C) Subject: UNDER EVALUATION: NGI -05 (PTD #1760140 ained Casing Pressure on the OA All, Injector NGI -05 (PTD #1760140) is operating under Administrative Approva - 032 dated 06/09/08 for slow IA repressurization. The wellhead pressures were tubing /IA/OA equal to 3230/780/ • • •si on 05/19/2011. When the Operator bled off the OA pressure, arctic pack was returned from the annulus. The OA pressure is suspected to be a consequence of the arctic pack. The well has been reclassified as Under - -tion and placed on a 28 -day clock. The plan forward is to leave the well on injection and conduct the followin • : ' - . nostics: 1. D: Flush arctic pack from OA 6/13/2011 • • NGI -05 (PTD #1760140) TIO Plot Well: N61 -05 4.000 - 3,000 - Tbg —/-- IA 2,000 - —a— OA OOA - 000A 1,000 03/12/11 03/19/11 03/26/11 04/02/11 04/09/11 04/16/11 04/23/11 04/30/11 05/07/11 05/14/11 05/21/11 05/28/11 06/04/11 06/11/11 OART testing from 6/5 -6/10, 2011. Beginning IA pressure of OART was 1520 psi. NGI -05 (PTD #1760140) Injection Plot Well: N61.05 3,500 - 3,000r - 250,000 2500 - - 200000 — WHIP SW 2,000 - - 150,000 )1,500- - n -MI - 100,000 - n GI 1000 - - o Other 500 - - 50,000 • On • 03/12/11 03/26/11 04/09/11 04/23/11 05/67/11 05/21/11 06/04/11 • 110 • UNDER EVALUATION: NGI - 05eD #1760140) Sustained Casing Pressuon the OA Page 1 of 2 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Sunday, May 22, 2011 8:05 AM To: AK, D &C Well Integrity Coordinator Subject: RE: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained Casing Pressure on the OA Mehreen, You have answered my question by noting that it is the surface that will be cleared. That was not clear in your original message. Tom From: AK, D &C Well Integrity Coordinator [ mailto :AKDCWelllntegrityCoordinator @bp.com] Sent: Sat 5/21/2011 9:43 PM To: Maunder, Thomas E (DOA) Subject: RE: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained Casing Pressure on the OA Hi Tom, At the time when the OA pressure increased, there was an increase in the injection rate and temperature which appears to have caused an associated thermal response in the annuli. The arctic pack dump will be performed to clear the arctic pack in any surface equipment and near surface after which we will monitor OA repressurization. Previously an arctic pack dump was performed on NGI -05 on 12/1/2010 after which the OA pressure showed stabilization. There are two FOCs (2393' and 2671') in the 9 -5/8" casing above the surface casing shoe at 2719'. I will do some more research on how much cement was pumped and discuss with the drilling team on Monday to verify. It appears that the surface casing shoe has integrity because in the previous arctic pack dump we were able to pressure up with diesel to 1000 psi. An updated TIO and Injection Plot are attached for reference. Thank you, '' MA.Y 2 3 201' Mehreen From: Maunder, Thomas E (DOA) [mailto:tom.maunder©alaska.gov] Sent: Saturday, May 21, 2011 7:11 PM To: AK, D &C Well Integrity Coordinator; Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS FS1 OSM; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Facility OTL; AK, RES GPB East Wells Opt Engr; Cismoski, Doug A; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead Cc: Chiwis, Robert; Walker, Greg (D &C) Subject: RE: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained Casing Pressure on the OA Mehreen, et al, am curious about "flushing the arctic pak" from the annulus. I don't have access to the well files to answer this question, is the surface casing shoe open on this well? Thanks in advance, Tom Maunder, PE AOGCC 5/23/2011 UNDER EVALUATION: NGI -05eD #1760140) Sustained Casing Presson the OA Page 2 of 2 From: AK, D &C Well Integrity Coordinator [mailto :AKDCWeIllntegrityCoordinator @bp.com] Sent: Fri 5/20/2011 12:43 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS FS1 OSM; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Facility OTL; AK, RES GPB East Wells Opt Engr; Cismoski, Doug A; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead Cc: Chiwis, Robert; Walker, Greg (D &C) Subject: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained Casing Pressure on the OA All, Injector NGI -05 (PTD #1760140) is operating under Administrative Approval 4E.032 dated 06/09/08 for slow IA repressurization. The wellhead pressures were tubing /IA/OA equal to 3230/780/1120 psi on 05/19/2011. When the Operator bled off the OA pressure, arctic pack was returned from the annulus. The high OA pressure is suspected to be a consequence of the arctic pack. The well has been reclassified as Under Evaluation and placed on a 28 -day clock. The plan forward is to leave the well on injection and conduct the following diagnostics: 1. D: Flush arctic pack from OA 2. D: Monitor OA repressurization A TIO plot, wellbore schematic and copy of the AA have been included for reference. «NGI -05 TIO 05- 20- 11.doc» «NGI- 05.pdf» «NGI -05 AA 4E.032.pdf» Thank you, Mehreen Vazir (Alternate: Gerald Murphy) Well Integrity Coordinator BP Alaska Drilling & Wells Well Integrity Office: 907.659.5102 Email: AKDCWeIllntegrityCoordinator @BP.com 5/23/2011 • • Injector NGI -05 (PTD #1760140) TIO Plot W.t N6I-0 4900 1 3,000 Tbg -a— IA 2,000 006 + 000A On 1,000 02/26/11 03/05/11 03/12/11 03/19/11 03/26/11 04/02/11 04/09/11 04/16/11 04/23/11 04/33/11 05/07/11 05/14/11 0.5/21/11 Injector NGI -05 (PTD #1760140) Injection Plot wet NG145 300200 350000 i1 ' - + ' 340.000 330 0[0 3 1/ , 320 000 0 ' 310 000 3000 30,000 2,900 293 000 2,800 280 2 700 2.600 27000 zso 000 2 500 .,000m 2400 24000 2 300 230,006 2200 220,000 2,100 210,000 m _ WHIP '' -00 SW 200,000 £ _ SW 1,900 193,000 0 PW 3 1 800 19003 — NI 1,100 170,000 n — GI 1,600 160,00 — Oliva 1,500 150000 — On 1 400 140000 1 300 130 000 1,200 120 000 0100 110000 1,000 10000 900 90,000 800 80000 700 70,00 600 60 50 50.000 400 40,000 300 3000 200 20,00 100 10,000 02/26/11 03/05/11 03/12/11 03/19/11 03/26/11 04/02/11 04/09/11 04/16 /11 04/23/11 04/30 /11 05/07/11 0544/11 05/21/11 OPERABLE: NGI -05 (PTD #17600) Confirmed Production Casing Integrity Page 1 of J Maunder, Thomas E (DOA) From: AK, D &C Well Integrity Coordinator [ AKDCWellintegrityCoordinator @bp.com] Sent: Thursday, December 09, 2010 11:10 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS FS1 OSM; AK, OPS FS1 DS Ops Lead; AK, OPS FS1 Facility OTL; AK, RES GPB East Wells Opt Engr; Cismoski, Doug A; Engel, Harry R; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead Cc: Chivvis, Robert; AK, D &C Well Integrity Coordinator; King, Whitney; Quy, Tiffany Subject: OPERABLE: NGI -05 (PTD #1760140) Confirmed Production Casing Integrity Attachments: Injector NGI -05 (PTD #1760140) TIO and Injection Plot 12- 09- 2010.doc All, Injector NGI -05 (PTD #1760140) has been monitored for OA represurization after the OA was recorded above MOASP on 11/24/2010. An arctic pack flush was subsequently performed on the OA. After a 12 day monitor, the OA pressure has not increased concluding there is no IAxOA communication,. The well has been reclassified as Operable. A TIO plot has been included for reference. <<Injector NGI -05 (PTD #1760140) TIO and Injection Plot 12- 09- 2010.doc>> Thank you, Gerald Murphy (alt. Torin Roschinger) Well Integrity Coordinator Office (907) 659 -5102 Cell (907) 752- 0755�� Pager (907) 659 -5100 Ext. 1154 From: D &C Well Integrity Coordinator Sent: Thursda , ovember 25, 2010 10:07 AM To: 'Maunder, Thom (DOA)'; 'Regg, James B (DOA)'; 'Schwartz, Guy L (DOA)'; AK, OPS FS1 OSM; AK, OP 1 DS Ops Lead; AK, OPS FS1 Facility OTL; AK, RES GPB Ea ells Opt Engr; Cismoski, Doug A; Engel, Harry R; AK, D &C Wireline Opera' s Team Lead; AK, D &C Well Services Operations Team Lead Cc: Chiwis, Robert; AK, D &C Well Integrity Co inator; Janowski, Carrie; Holt, R (ASRC) Subject: UNDER EVALUATION: NGI -05 (PTD #17 0) Sustained Iasi ressure on the OA All, Injector NGI -05 (PTD #1760140) i erating under Administrativ proval 4E.032 dated 06/09/08 for slow IA repressurization. The wellhe pressures were tubing /IA/OA equal to 00/1550/1100 psi on 11/24/10. The operator attempted to b the OA pressure and the hose and jewelry plu d off with arctic pack. Therefore, the high OA press Is suspected to be a consequence of the arctic pack. The ll has been reclassified as Under Evalu i and placed on a 28 -day clock. The plan forward is to leave the we n injection and flush the arctic pa out of the OA with warm diesel. t A wellbore schematic and TIO plot has been included for reference. << File: NGI- 05.pdf >> << File: NGI -05 TIO Plot 10- 25- 10.doc >> 12/10/2010 0 0 Injector NGI -05 (PTD #1760140) TIO Plot Wen: 1461-05 Tbg —11I IA 2.Of_iCi a, —►— OA OOA —� OOOA On 1 "Un 09/11/ 1009 /18/ 1009 /25/ 1010 /021 1010 /09/1010116/1010 /23/1010/30/ 1011 /06/ 1011 /13/1011/20/1011 /27/1012/04/10 Injector NGI -05 (PTD 91760140) Injection Plot W.IF I 3.400 260,000 1200 240.000 3,000 220,000 2,800 2,600 200,000 2,400 -180,000 2.200 160000 m -WHIP 2000 . £ SW i 1.000 140.000 - pw s -NI 3 1.600 120.000 _ 01 - 7 400 oft. 100.000 On 1 ,200 1,000 00.000 B00 60 000 600 40,000 400 200 20,000 09/11/10 09/16 09/25/10 10/02/10 10/09/10 10/16/10 10/23/10 10/30/10 11 /OH10 11/13/10 1120/10 11i27i10T12104110 Page 1 of 1 Maunder, Thomas E (DOA) From: Barker, Elizabeth R (SAIC) [Elizabeth. Barker @bp.com] Sent: Wednesday, December 01, 2010 3:04 PM To: Maunder, Thomas E (DOA); Stewman, Sondra D Cc: Barker, Elizabeth R (SAIC) Subject: RE: NGI -05 (176 -014) Attachments: NGI -052IP Hello Tom, Enclosed is the Operation Summary Report for that same time period. Please confirm this will be sufficient to meet your requirements. Thank you, Liz Barker 4 -5674 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Friday, November 26, 2010 12:40 PM To: Stewman, Sondra D Cc: Barker, Elizabeth R (SAIC) Subject: NGI -05 (176 -014) Ladies, I have attached the 404 and operations report from an old (1999) workover on this well. The report style does not provide much detail regarding what was accomplished doing the work. Can you provide a report with greater detail? I know that the DEAP system employed through those years did have several "detail levels ". I'd appreciate a report with detail similar to what you presently are sending. Thanks in advance. Tom Maunder, PE AOGCC Thy t�a.,.�. i� o� c, zc� pc- •� Lam, V --� o cQ Z �c ck " 4 C 7 12/10/2010 • 0 North America - ALASKA - BP Page 1 of 9 Operation Summary Report Common Well Name: NGI -05 DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 6/3/1999 End Date: 6/12/1999 4.19104 (0.00) Project: Prudhoe Bay (various) Site: NGI Rig Name /No,: NABORS 7ES Spud Date/Time: 3/211976 12:00:OOAM Rig Release: 6/12/1999 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: / Lat: 070 °19'40,749 "9 Long: 0148 °28'52946 "W Active Datum: ORIG KELLY BU SHING @18.00ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations 6/3/1999 15:00 - 16:00 1.00 MOB P PREP Move rig Rigged down Drillfloor / Derrick Prep modules f/ move to NGI -05. 16:00 Equipment work completed 16:00 - 20:00 4.00 MOB N WAIT PREP Rig waited: Production facilities WO NGI-05 pad prep. Safety meeting w/ Peak, 20:00 Resumed 2p2rations 20:00 - -23:59 4.00 MOB P PREP Rig moved 100 % Moved camp, shop & pits to NGI -05. Move sub base, derrick up to NGI -05. Spread herculite & spot sub. Set mats & herculite & spot pits, shop, & camp. Berm up around rig. Accepted rig @ 0001 hrs on &/4/99. 6/4/1999 00:00 - 04:00 4,00 MOB P PREP Rig moved 100 % Moved camp, shop & pits to NGI -05. Move sub base, derrick up to N%05. Spread herculite & spot sub. Set mats & herculite & spot pits, shop, & camp. Berm up around rig, Accepted rig @ 0001 hrs on 6/4/99. 04:00 At well location - Cellar 04:00 - 06:15 2.25 FILTR P DE -COM Fluid system Fill pits with Brine Take on 9.4# NaCl brine. 06:15 Com leted operations 06:15 - 06_ :45 _ 0.50 FILTR P DE -COM Held safety meeting Pre -Spud with all personnel. 06:45 Com plete d oper 06:45 - 07:30 0.75 PULCOM P DE -COM Wellhead work Rigged down Hanger plug Pull BPV. 07:30 Work completed, equipment laid out 07:30 - 08:00 0.50 PULCOM P DE -COM Tested Chicksan lines 08:00 Pressure test completed successfully - 3500 psi 08:00 - 11:30 3.50 FILTR P DE -COM Fluid system Reverse circulated at 7797 ft Reverse 9.4 ppg NaCl brine through choke & gas buster @ 48 spur w/ 400 psi. At BU, increase to 85 sprn w/ 850 psi. No loss or gain Monitor well -OK. 11:30 Hole displaced with Brine - 120 °l° dis {aced 11:30 12:00 0.50 PULCOM P DE -COM Wellhead work Installed Hanger plug Set BPV. 12:00 Eqpt work completed, running tool retrieved 12:00 - 13:30 1.50 PULCOM P DE -COM Removed Xmas tree ND tree & adapter flange, 13 :30 Equipment work completed µ — 13:30 - 15:00 1.50 WCTRL P �DE-COM Nipple up BOP stack Rigged up BOP stack 15:00 Work completed- BOP stack in osition Printed 1211/2010 2:00:49PM • North America - ALASKA - BP Page 2 of 9' Operation Summary Report Common Well Name: NGI -05 DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 6/3/1999 End Date: 6/12/1999 4J9104 (0.00 ) Project: Prudhoe Bay (various) — Site: NGI —� Rig Name /No.: NABORS 7ES Spud DatelTime: 3/2/1976 12:00:OOAM Rig Release: 6112/1999 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: / Let: 070 °19'40.749 "9 Long: 0148 °28'52.946 "W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations hr) _ ft -- 15:00 - 18:00 3.00 FTEST P DE -COM Test well control equipment Tested BOP stack Test BOPE to 250/5000 psi; annular to 250/3500 psi. Witnessing waived by Chuck Sheve -AOGCC Field Inspector. 18:00 Pressure test completed successfully - _ 5000 psi 18:00 - 21:30 3.50 FTEST P DE -COM Retrieved Hanger plug R/U Lubricator. Trouble pulling BPV. Finally Sucessfui. R/D Lubricator. 21:30 Equipment work completed _ 21:30 - 23:00 1.50 — PULL P DE -COM Pull Single completion, 7 in O.D. Pulled Tubing on retrieval string to 7803 ft M/U spear and engage 7" tubing one joint below hanger. Pulled 400K to remove hanger. Pull hangerto floor and L/D. _ 23:00 Com leted operations 23:00 - 23:59 1.00 PULL P DE -COM Circulated at 7803 ft CBU with 9.4 Brine. 85 SPW300 psL 00 :00 Hole displaced with Brine -100 % displaced 6/5/1999 00.00 - 00:30 0.50 PULL P DE-COM Rigged down Fluid system R/D circulating equipment, LID spear. 00:30 Equipment work completed 00:30 - 02:00 1.50 PULL P DE -COM Laid down 160 ft of Tubing LID 4 jts, of 7" tubing. _ 02:00 Completed operations 02:00 - 04:00 2.00 WCTRL P DE -COM Nipple down BOP stack Installed Emergency hang off assembly Set storm packer. Test same to 1000psi. 04:00 Equipment work completed 04:00 - 05:00 1.00 WCTRL P DE -COM Rigged down BOP stack PJSM and WD BOP, 05:00 Equip wor completed 05:00 - 09:30 4.50 PULCOM P DE -COM Wellhead work Installed Tubing head spool Change out tubing spool and packoff to 13 -5/8" x 13 -5/8" Gray Gen 11 tubing head. [Jun 51999 6:00AMj (Jun 6 1999 6:00AM) Installed Tubing head spool Finish NU tbg spool & packoff. 09:30 Equipment work completed 09:30 - 10:30 1.00 WCTRL P DE-COM Nipple up BOP stack Rigged up BOP stack 10: Work completed - BOP stack in position 10:30 11:00 0.50 PULCOM P DE-COM Wellhead work Tested Seal assembly Attempt to test packoff. Fluid passing by top seal. 11:00 Suspended pressure test on Seal _ assembly, observed leak 11:00 - 12:00 1.00 PULCOM N FAIL DE-COM Rigged down BOP stack ND BOP stack & tbg spool, 12:00 Equipment work completed 12:00 13.30 1.50 PULCOM N FAIL DE -COM Rigged up Adapter spool Inspect packoff. MU tbg spool. Realign packoff. 13:30 Equipment work completed Printed 12/1/2010 2 :00:49PM North America - ALASKA - BP MV Page 3 of 9 Operation Summary Report Common Well Name: NGI- 05 _DIMS AFE No Event Type: COM- ONSHORE (CON) Start Data: 613/1999 I End Date: 6/12/1999 4.19104 (0,00 ) Project: Prudhoe Bay (various) Site: NGI Rig Name /No.: NABORS 7ES I Spud Daterrime: 3/2/1976 12:00:OOAM Rig Release: 6112/1999 Rig Contractor: NABORS ALA KA DRILLING INC. UWk 1 Let: 070"19'40.749 "9 Long: 0 148'28'52.946W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations hr __ ft 13:30 - 14:00 0.50 PULCOM N FAIL DE -COM Tested Seal assembly Test packoff -OK. 14:00 Pressure test completed successfully - 3500 psi 14:00 - 15:00 1.00 PULCOM N FAIL DE -COM Rigged up BOP stack 1 5:00 Work completed - BOP stack in position 15:00 - 15:15 0.25 PULCOM P DE -COM Installed BOP test plug assembly 15:15 Eqpt. work completed, running tool retrieved 15:15 - 15:45 0.50 FTEST P DE -COM Test well control equipment Tested BOP stack Test flange break & lower pipe rams to 250/5000 psi. 15:45 Pressure test completed successfully - 5000 psi 15:45 - 16:00 0.25 PULCOM P DE -COM Wellhead work Rigged down BOP test plug assembly Pull test plug & set wear ring. 16:00 E ui mend t work c ompleted 1600 - 17:00 1,00 PULCOM P DE -COM Removed Emergency hang off assembly Engage storm packer & release. Monitor well -OK. Pull to rig floor. LD packer & running toot 17:00 Equipment work completed 17:00 - 17:30 0.50 PULCOM P DE -COM Circulated at 7650 ft CBU 85 spm w/ 350 psL No loss or gain. Monitor well. Pump dry job. 17:30 Obtained bottoms up (100% annulus volume 17:30 - 18:00 0.50 PULL P DE -COM Pull Single completion, 7 in O.D. Rigged up Tubing handling equipment 18:00 Work completed - Tubing handling equipment in position 18:00 - 23:59 6.00 PULL P DE-COM Laid down 2600 ft of Tubing L/D 65 jts. of 7" tubing. Pulled SSSV. Recovered 57 control line bands. Control line brittle. 00:00 SCSSSV ni le a ssembly laid out 6/6/1999 00:00 - 07:00 7.00 PULL P DE-COM Laid down 4300 ft of Tubing Continue LID 7" tubing. [Jun 6 1999 6:00AMj (Jun 7 1999 6:OOAR Laid down 4300 ft of Tubing Finish LD tbg, Recovered 21.46' cutoff. Clean cut. 07:00 238 joints laid out 07:00 - 07:30 0.50 PULL P DE -COM Rigged down Completion string handling equipment 07:30 Work completed, equipment laid out 07:30 - 08:00 0.50 PULL P DE -COM Removed Wear bushing 08:00 Equip work c 08:00 - 08:30 0.50 PULL P DE -COM Rigged up BOP test plug assembly 08:30 Equipment work com pleted 08:30 - 09:45 1.25 PULL P DE -COM Rigged up Top ram Change top rams to 3.5!'x 6" variables. Changed rubbers on rams. 09:45 Equipment work comp leted _ _ 09:45 - 10:30 0.75 PULL P DE -COM Tested Top ram Test door seals. 10:30 Pressure test completed successfully - 3500 psi Printed 12/1/2010 2:00:49PM 0 go North America - ALASKA - BP 14W Page 4 of 9 Operation Summary Report — to - m Well Name: NGI- 05_DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 613/1999 End Date: 6/12/1999 4J9104 (0.00) Prajec Prudhoe Bay (various) Site. NdF Rig Name /No.: NABORS 7ES Spud Da me 3/2/1976 12:00:OOAM Rig Release: 6/12/1999 Rig Contractor: NABORS ALASKA DRILLING INC, I UWk / Let: 070 "19'40.749 "9 Long; 0148 "28 '52.946'W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations 10:•30 - 11:00 0.50 __ PULL P - DE-COM Rigged down BOP test plug assembly 11:00 Equipment work completed 11:00 - 12:00 1.00 PULCOM P DE -COM Wellhead work Rigged up Wear bushing Wear ring too short. Change for longer bushing. 12:00 Equipment work completed 12:00 - 12 :30 0.50 BHA P DE -COM BHA run no. 1 Serviced Top drive pipe handler 12:30 Equipment work completed 12:30 - 14:30 2.00 BHA P DE -COM Made up BHA no. 1 MU BHA. Overshot assembly. 14:30 BHA no. 1 made up 14:30 - 20:30 6.00 BHA P DE-COM RJ.H. to 7785 ft RIH to top of fish with DP singles. 20:30 At Top of fish; 7785 ft 20:30 - 21:00 0.50 BHA P DE -COM Fished at 7785 ft Tag fish at 7785'. Swallow fish at 7791 Jar 4 times at 350K: Fish free. 21:00 Fish came free 21:00 - 22:30 1.50 BHA P DE -COM Circulated at 7720 ft Unable to circulate through fish. Drop ball and open circulating sub. CBU. Pump Dry Job. Monitor well - OK. 22:30 Obtained bottoms up (100% annulus volume) 2230 - 23:59 1.50 BHA P DE -COM Pulled out of hole to 150 ft POOH slowl y to D C's. 6/7/1999 00:00 - 03:00 3.00 BHA P DE -COM Pulled out of hole to 150 ft POOH slowly to DC's. _ 03:00 At BHA 03:00 - 04:00 1.00 BHA P DE -COM Pulled BHA PJSM - chemical cutter handling. L/D BHA. 04:00 BHA Laid out 04:00 - 04:30 0,50 BHA P DE -COM Laid down fish R/U to handle 5,5" tubing and L/D same. 04:30 Complete fish recovered 04:30 - 06:00 1.50 BHA P DE -COM Laid down fish Removed Chemical Cutter. 06:00 Complete fish recovered 06:00 - 06:30 0.50 BHA P DE-COM Laid down fish Finish LID fish & clear floor. 06:30 Complete fish recovered 06:30 - 08:00 1.50 BHA P DE -COM BHA run no. 2 Made up BHA no. 2 MU burn shoe & washpipe assembly. 08 :00 BHA no. 2 made u p_ 08:00 - 12:00 4,00 BHA P DE -COM R.I.H. to 7000 ft RIH slow. Pipe overflowing, 12:00 Slopped To service drillin ui ment 12:00 - 13 :00 1,00 BHA P DE -COM Serviced Block line 1 3:00 Line slipped and cut 13 ;00 - 13:30 0.50 BHA P DE -COM Serviced Top drive pipe handier 13:30 Equipment work completed 13:30 - 14:00 0,50 BHA P DE -COM R.I.H, to 7844 ft Tagged up on PBR barrel. 14:00 At To of packer: 7844 It Printed 1211/2010 2:00:49PM • North America - ALASKA - BP Page 5 of 9 Operation Summary Report Common Well Name: NGI -05 DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 6/3/1999 End Date: 6/1211999 4J9104 (0.00 ) Project: Prudhoe Bay (various) Site: NGI Rig Name /No.: NABORS 7ES Spud Date/Time: 3/2/1976 12:00:OOAM Rig Release: 6/12/1999 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: / Let: 070 °19'40.749 "9 Long: 0148 °28'52.946 "W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level) Date From To Hrs Task Code NPT NPT Depth Phase Description of Operations hr ft 1400 - 20:30 6,50 BHA P DE -COM Milled Permanent packer at 7888 ft Mill over PBR barrel @ 7644'. Milled packer f/ 7886' -88', Packer dropped. 20.30 Completed o perati ons 20 :30 22:30 2.00 BHA P DE -COM Circulated at 7888 ft Circulated surface to surface with 30bbls HiVis sweep at 85SPIW600psi. Monitor well. Pump Dry Job, 22:30 Hole displaced with Brine - 100 % displaced �— 22:30 - 23:59 1.50 BHA P DE -COM Pulled out of hole to 200 ft PJSM. POOH to BHA, 6/8/1999 00:00 - 02:00 2.00 BHA P DE-COM Pulled out of hole to 200 ft PJSM. POOH to BHA. 02:00 At BHA 02:00 - 02:45 0.75 BHA P DE-COM Pulled BHA L/D washpipe and boot baskets. Recovered 4 gallons of metal in baskets including control lines. 02 :45 BHA Laid out 02:45 - 03:30 0.75 BHA P DE -COM BHA run no. 3 Made up BHA no. 3 P/U spear, extension, and stop ring. 03:30 BHA no. 3 made, 03:30 - 06:00 2.50 BHA P DE-COM R.I.H. to 6000 ft 06:30 - 08:00 1.50 BHA P DE -COM Circulated at 8100 ft No losses. 08:00 Obtained bottoms up (100% annulus _ volume 08:00 - 11:00 3.00 BHA P DE -COM Pulled out of hole to 309 ft 11:00 At BHA 11:00 - 12:00 1.00 BHA P DE-COM Pulled BHA Recovered 45.21' fish from K- anchor up. Left packer & tail pipe assembly in hole. 12:00 BHA Stood back 12:00 - 13:00 1.00 BHA P DE-COM BHA run no. 4 Made up BHA no. 4 PJSM - Redress spear to catch packer ID. 13:00 BHA no. 4 made up 13:00 - 15:30 2.50 BHA P DE -COM R.I.H, to 8082 ft 15:30 At Top of fish: 8082 ft _ 15:30 - 16:00 0,50 BHA P DE -COM Fished at 8082 ft Spear and pull packer free with 50k over. 16:00 Latched fish — —� 16:00 - 17:30 1.50 BHA P DE -COM Circulated at 8082 ft Circulate bottoms up - 85 spm(6 bpm) @ 720 psi. Minor gas on bttm up, no losses. Pump slug and monitor well 17:30 Obtained bottoms up (100% annulus volume ) 17:30 - 21:00 3.50 BHA P DE -COM Pulled out of hole to 305 ft POOH slow - packer hanging up. Fire Drill @ 20:15 hr - AMAS 1:10 min. 21:00 At BH 21:00 - 21:30 4.50 BHA P DE -COM Pulled BHA 21:30 BHA Stood back Printed 12/1/2010 2:00:49PM • go North America - ALASKA - BP MW Page 6 of 9 Operation Summary Report Common Well Name: NGI -05 DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 6/3/1999 End Date: 6/12/1999 4J9104 (0.00 ) 'Project: Prudhoe Bay (various) Site: NGI �! Rig Name /No.: NABORS 7ES Spud Date/Time: 312/1976 12:00:OOAM Rig Release: 6/12/1999 Rig Contractor: NABORS ALASKA DRILLING INC. UWt / Let: 070 °19'40.749 "9 Long: 0 148 °28'52,946 "W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations 21:30 - 22:00 0.50 _ BHA ._.....___ P ( - -- DE-COM _ Laid down fish Lay down packer and tail pipe assembly. 22:00 Complete fis recovered 22:00 - 22 :30 0.50 BHA P DE -COM Pulled BHA Break out and lay down Baker Fishing equipment. Clear rig floor. 22:30 BHA Laid out 22:30 23:59 1.50 BHA P DE -COM BHA run no. 5 Made up BHA no. 5 Make up 6" bit,1 joint of 4" drill pipe and 9 -5/8" scraper, 00:00 BHA no. 5 made up 6/911999 x 00:00 - 03:00 3.00 BHA u P - DE -COM R.I.H. to 8144 ft Bit @ 8144', scraper @ 8105', Pick up and position bit at 8105'. 03:00 At Top of liner: 8 108 ft 03:00 - 05:30 2.50 BHA P DE-COM Circulated at 8105 ft Circulate high vis sweep while working string - clean returns and no losses. Pump slug and monitor well. 80 spm(5.7 bpm) @ 465 psi. 05:30 Obtained clean returns - 150 % hole volume 05 :30 - 06 :00 0.50 BHA P DE -COM Pulled out of hole to 6750 ft 0 6:00 Began precautionary m easures _ 06:00 - 10:30 4.50 BHA P DE-COM Laid down 7800 ft of 4 in OD drill pipe D1 BOP Drill @ 07:30 Hr - AMAS 1:07 min. 10:30 248 joints laid out 10:30 - 12:30 2.00 BHA P DE -COM Pulled BHA 12:30 BHA Laid out 12:30 - 13:00 0.50 PULCOM P DE -COM Wellhead work Retrieved Bore protector Pull wear ring. 13.00 Eq uipment work completed 13:00 - 14:30 1.50 WCTRL P DE -COM Nipple up Top ram Rigged up Top ram Change top 3-1/2" x 6" variable ram to 7 -5/8 ". Spill Drill @ 14:25 Hr - AMAS 1 :15 min. 14:30 Equipment work completed 14:30 16:00 1.50 FTEST P DE -COM Test well control equipment Tested Top ram Test top door to 250 psi low and 3500 psi high. 16:00 Pressure test completed successfully - 3500 psi 16:00 - 17:30 IM RUN P DE -COM Run Single completion, 7.625 in O.D. Rigged up Tubing handling equipment Rig up 7 -5/8" tubing equipment with intergral tongs and computer analysis. 1 7:30 E work completed 17:30 - 23:59 6.50 RUN P _ DE-COM Ran Tubing to 4900 ft (7.625 in OD) Pre job safety meeting with crew and Jim Denny. Run 7 -5/8" 29.7# L -80 IPC STL completion. Torquing STL connections to 5600 ft/lb with computer analysis on make up and utilizing Teflon seal ring In modified threads. Printed 12/1/2010 2:00:49PM North America - ALASKA - BP Page 7 of 9 Operation Summary Report Common Well Name: NGI -05 - DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 6/3/1999 End Date: 6/12/1999 4.19104 (0.00 ) Project: Prudhoe Bay (various) Site: NGI Rig Name /No.: NABORS 7ES Spud Date/Time: 3/211976 12:00 :OOAM Rig Release: 6112/1998 Rig Contractor: NABORS ALASKA DRILLING INC. UWt / Lat: 070'19'40.749 "9 Long: 0148'26'52.946 -W Active Datum: ORIG KELLY BUSHING @I 8.00ft (above Mean Sea L Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations _..... _�hr)_-_ _ . _._ _ ._..._ —. ft 6/10/1999 00:00 - 06:00 6,00 RUN P DE -COM Ran Tubing to 4900 ft (7.625 in OD) Pre job safety meeting with crew and Jim Denny. Run 7 -5/8" 29.7# L -80 IPC STL completion. Torquing STL connections to 5600 ft/lb with computer analysis on make up and utilizing Teflon seal ring In modified threads. 06:00 Began precautionary measures Fire Drill 05:00 Hr - AMAS 0:45 min. 06:00 - 07 :30 1.50 RUN P DE -COM Installed SCSSSV nipple assembly Make up and test 7" Camco'Bal -O' SVLN and control lines. 07:30 Equi pment wor completed 07 :30 - 10:30 3.00 RUN P DE -COM Ran Tubing to 7100 ft (7 in OD) 10:30 Stop : To hold safe meeting 10:30 11:00 0.50 RUN P DE -COM Held safety meeting Meeting with Jim Denny discussing rigs future. __ 11:00 Compl d apera 11:00 13:30 2.50 RUN P DE -COM Ran Tubing to 8038 ft (7.625 in OD) Run a total of 195 joints of 7 -5/8" IPC 29.7# L -80 STL tubing. Tubing torqued to 5600 ftllbs and utilized API modified Best -O -Life 2000 thread compound with Teflon seal rings in STL box 13:30 Completed run with Tubing to 8038 ft 13:30 - 15:00 1,50 RUN P DE -COM Installed Hanger assembly Make up tubing hanger and control lines. Test control lines to 5000 psi. Ran a total of 55 stainless steel control line bands. Align hanger and land. PUW = 245k, SOW = 190K 15:00 E uipment work completed — 15:00 - 16:00 1.00 RUNCOM P DE -COM Wellhead work Installed Accessories Run in lock down screws with 500 fUlbs. Install and test through tubing spool control lines. Test metal- to-metal hanger seal to 1000 psi. 16:00 Equipment work completed 16 :00 - 17:00 1.00 RUNCOM P DE -COM Installed Hanger plug Back out landing joint and install BPV. 1 7:00 Equipment work completed 17:00 - 18:00 1.00 MAINT P DE -COM Planned maintenance Serviced Tubing handling equipment Rig down tubing equipment and clear rig floor, 18:00 Equipment work completed - 18 7 0 - 0 - - 19:00 1,00 WCTRL P DE -COM Nipple down BOP stack Held safety meeting Meeting with Fritz Gunkel & Jim Denny on rigs future. PJSM addressing nippling down operations, 19:00 Completed operations 19:00 - 23:59 5;00 WCTRL P DE -GOM Rigged down BOP stack Remove all rams. Flush and grease cavities/ bonnet bolts for cold stack, H2S Drill P 20:00 Hr - AMAS 2:15 min, Printed 12/1/2010 2:00:49PM • North America - ALASKA - BP l qw Page 8 of s Operation Summary Report Common Well Name: NGI -05 DIMS AFE No Event Type COM ONSHORE (CON) Start Date: 61311999 End Date: 6/12/1999 4,19104 (0.00 } Project: Prudhoe Bay (vanous) Site: NGI Rig Name /No.: NABORS 7ES Spud Date/Time: 3/2/1976 12:00:OOAM Rig Release: 6/1211999 Rig Contractor: NABORS ALASKA DRILLING INC. UWt 1 Let: 070 *19'40.749"9 Long: 0148 * 28'52.946W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) _ (ft 6/11/1999 00:00 - 04 :00 4.00 INCTRL P mm DE-COM Rigged down BOP stack Remove all rams. Flush and grease cavities/ bonnet bolts for cold stack. H2S Drill @ 20:00 Hr - AMAS 2:15 min. �_ 04:00 Equipment work comple 04:00 - 06:00 2.00 RUNCOM P DE-COM Wellhead work Installed Xmas tree Nipple up Gray adapter flange and tree. 06:00 Began precautionary measures 06:00 - 07:00 1,00 RUNCOM P DE -COM Retrieved Hanger plug Test tree to 5000 psi. Pull tree test plug and BPV with DSM lubricator. 07:0 Equipment work completed 07:00 - 09:00 2.00 RUNCOM P DE -COM Chemical treatment Displace treatment Displace annulus with clean inhibited 9.4# brine followed by 42 bbl diesel freeze protection. 42 spm(3 bpm) @ 425 psi. 09:00 Completed displacement at 425 psi and 42 bbl _._...__ 09:00 - 11:00 2.00 PTEST P DE -COM Perform integrity test Tested Tubing Attempt to set packer and test tubing. Ball not set due to full returns of diesel from annulus. Re -pump diesel down annulus and call out Halliburton slickline. 450 psi on annulus due to diesel, 11:00 Suspended test, observed returns from wellbore 20:00 - 21:00 1,00 PTEST P DE -COM Perform integrity test Tested Tubing Set packer and test 7 -5/8" x 7" tubing to 4000 psi for 30 minutes. 21:00 Pressure test completed successfully - 4000 psi 2100 - 22:00 1.00 PTEST P DE -COM Tested Casing Test 9-5/8" x 7 -5/8" annulus to 4000 psi for 30 minutes with 1500 psi on the tubing. 22:00 Pressure test completed successfully - 4000 psi 23:00 - 23:59 1.00 RUNCOM P DE -COM Wellhead work Installed Hanger plug Install BPV and secure tree. Empty pits of all excess fluids, *Rig released @01:00 hrs - 6/12/99 * 11:00 - 14:30 3.50 MISC N FAIL LL DE-COM Slickline wireline work Rigged up Slickline unit Rig up Halliburton slickline with full high pressure lubricator, wireline rams and packoff. Test lubricator to 3500 psi. 14:30 Equipment work completed 14:30 - 16:00 1.50 MISC N FAIL DE -COM Retrieved SCSSSV dummy pack off Retrieve dummy SSSV with 4.0" ID, 16:00 Completed operations Printed 12/1/2010 2:00:49PM 0 Ah North America - ALASKA - BP Page 9 of 9 Operation Summary Report Common Well Name: NGI- 05_DIMS AFE No Event Type: COM- ONSHORE (CON) Start Date: 6/3/1999 End Date: 6112/1999 4,19104 (0.00) Project: Prudhoe Bay (various) ite N I Rig Name /No.: NABORS 7ES Spud Datelrime: 3/2 /1976 12:00:OOAM Rig Release: 6/12/1999 Rig Contractor: NABORS ALASKA DRILLING INC. UWt / Lot 070 °19'40.749" 9 Long: 01 48 °28'52.946' W Active Datum: ORIG KELLY BUSHING @18.00ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth Phase Description of Operations ___f6 2 MISC N FAIL R _ DE COM Conducted slickline operations on Shckline equipment -Tool run Run 5.90" overshot with LIB inside. Slight resistance when running through packer. Tap down on ball to seat in RHC plug, Opened annulus and bled of 450 psi hydrostatic within 30 seconds - ball on seat. 18:00 Completed run with Slickline / braided cable from 0 ft to 8023 ft 18:00 - 19:30 1.50 MISC N FAIL DE -COM Installed SCSSSV plug Run and set dummy SSSV. 19:30 E ui ment work completed 19:30 - 20:00 0.50 MISC N FAIL DE -COM Rigged down Lubricator Rig asside Halliburton and rig up to test tubing. 20:00 Equipment work completed 22:00 - 23:00 1.00 MISC P DE -COM Slickline wireline work Rigged down Slickline unit Rig down Halliburton slickline and clear rig floor. 23:00 Eq work completed 6/12/1999 00:00 - 01:00 _ 1.00 RUNCOM P DE -COM Installed Hanger plug Install BPV and secure tree. Empty pits of all excess fluids. " Rig released @ 01:00 hrs - 6/12/99 " 01:00 Equipment work completed Printed 12/1/2010 2:00:49PM UNDER EVALUATION: NGI -05 WD #1760140) Sustained casing pressure on the OA Page 1 of 2 Maunder, Thomas E (DOA) From: AK, D &C Well Integrity Coordinator [ AKDCWellintegrityCoordinator @bp.com] Sent: Friday, November 26, 2010 4:23 PM To: Maunder, Thomas E (DOA); AK, D &C Well Integrity Coordinator Cc: Regg, James B (DOA) Subject: RE: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained casing pressure on the OA Attachments: NGI -05 TIO Plot 10- 26- 10.doc Tom, Though it appears that the IA and OA pressures are tracking on the TIO plot after the bleeds in November, they were actually both bled down together. The arctic pack will be flushed from the OA valves and upper OA by pumping hot diesel down the OA and bleeding it back. This will not remove all the arctic pack from the OA, but it will clear the valves and clean out the arctic pack near surface. This method has proven to be successful and yields the best chance to evaluate the source of high OA pressure. On 08/01/10, an arctic pack dump was performed on NGI -05 after the operator reported the jewelry plugged off. Due to the arctic pack dump, the OA pressure began to show stabilization over the next week. Once this intervention has been completed, you will be sent an updated 10 day TIO plot for reference. An updated TIO plot has been attached for reference. Thank you, Torin From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Friday, November 26, 2010 12:12 PM To: AK, D &C Well Integrity Coordinator Cc: Regg, James B (DOA) Subject: RE: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained casing pressure on the OA Torin, From the TIO plot, it appears that the IA pressure began to increase slowly in early October and the buildup rate has increased since about mid November. There is a time lag in the OA response which appears to start in the latter part of October and it also exhibits an increased buildup rate from about mid November on. It appears that the IA is responding to the OA bleeds in November. I am curious how you plan to flush the arctic pack out of the OA. The narrative provided with the 407 filed 5/6/76 indicates that there are to FO cementers (2393' and 2671') in the 9 -5/8" casing string above the 13 -3/8" shoe. The narrative states that 125 sx of cement was placed through the lower FO and then the OA was arctic packed through the upper FO. Due to identified leaks in the 9/5/8" casing it was necessary to pull and then cut and pull the 9 -5/8" casing from 2356' not unlike has been done on a number of wells recently. After tieing back the 9 -5/8 ", the well was again arctic packed. I do not believe the pressure communication you are seeing is a consequence of the arctic pack. I look forward to your reply. Tom Maunder, PE AOGCC From: AK, D &C Well Integrity Coordinator [ mailto: AKDCWellIntegrityCoordinator @bp.com] 12/10/2010 UNDER EVALUATION: NGI -050D #1760140) Sustained casing pressure on the OA Page 2 of 2 Sent: Thursday, November 25, 2010 10:07 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); AK, OPS FS1 OSM; AK, OPS FSi DS Ops Lead; AK, OPS FSi Facility OTL; AK, RES GPB East Wells Opt Engr; Cismoski, Doug A; Engel, Harry R; AK, D &C Wireline Operations Team Lead; AK, D &C Well Services Operations Team Lead Cc: Chivvis, Robert; AK, D &C Well Integrity Coordinator; Janowski, Carrie; Holt, Ryan P (ASRC) Subject: UNDER EVALUATION: NGI -05 (PTD #1760140) Sustained casing pressure on the OA All, Injector NGI -05 (PTD #1760140) is operating under Administrative Approval 4E.032 dated 06/09/08 for slow IA repressurization. The wellhead pressures were tubing /IA/OA equal to 3300/1550/1100 psi on 11124/10. The operator attempted to bleed the OA pressure and the hose and jewelry plugged off with arctic pack. Therefore, the high OA pressure is suspected to be a consequence of the arctic pack. The well has been reclassified as Under Evaluation and placed on a 28-day clock. The plan forward is to leave the well on injection and flush the arctic pack out of the OA with warm diesel. A wellbore schematic and TIO plot has been included for reference. «NGI- 05.pdf>> «NGI -05 TIO Plot 10- 25- 10.doc>> Thank you, Torin Roschinger (alt. Jerry Murphy) Well Integrity Coordinator Office (907) 659 -5102 Harmony Radio X2376 Cell (406) 570 -9630 Pager (907) 659 -5100 Ext. 1154 12/10/2010 Welk NG1405 9,000 3,000 — W - Tb9 t w ''. 2,000 Q4 ODA �- 000n o� 1.000 08/28!10 09/Od110 09111/10 09/18/10 09/25/10 10/02/10 10109/10 10/16/10 10/23/10 10/30/10 ll/W /10 11/13/10 11/20/10 MEMORANDUM To: Jim Regg ~ 5~ ~~ ~1.~ P.I. Supervisor ~j FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, April 28, 2010 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC NGI-OS PRUDHOE BAY UNIT NGI-OS Src: Inspector NON-CONFIDENTIAL • Reviewed By: P.I. Suprv ~F'~- Comm Well Name: PRUDHOE BAY UNIT NGI-OS API Well Number: 50-029-20196-00-00 Inspector Name: Bob Noble Insp Num: mitRCN100424081039 Permit Number: 176-014-0 Inspection Date: 4/23/2010 Rel Insp Num: Packer Depth 5 Min. 60 Min. Pretest Initial 15 Min. 30 Min. 4 -- Well ~ -- --- NGI-os Type Inj. ~ N TVD 2372 ' IA 280 4200 '~ 4180 4160 yl ~ P.T.D 1760140'` TypeTCSt SPT . Test psi _ 4200 '~ QA 40 40 - ( 40 40 Interval REQvAR p/F P Tubing , zozo z7zo ~_ z6so ~ 26so Notes: A tubing tail }~ was set in the tubing. 202 u g 0 psi was put on tubing . / ~ ,~ Y-~iC~ ~4 ~ . CJ J 2 - Z~~ !"~~~ Wednesday, Apri128, 2010 Page 1 of 1 i Gas Injector Volume Calculation~Flow meters replaced • Regg, James B (DOA) From: Sent: To: Cc: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.comJ Wednesday, May 27, 2009 9:46 AM Regg, James B(DOA); Maunder, Thomas E(DOA) Page 1 of 1 ~ t~~~~1 ~ ~c Engel, Harry R; Rossberg, R Steven; GPB, Area Mgr East (FS1/2/COTU/Seawater); GPB, FS1 OTL; NSU, ADW Well Integrity Engineer; GPB, FS1 Fac Engr Subject: Gas Injector Volume Calculations -- Flow meters repiaced Attachments: Gas Injector volume calculations.xls Jim, ~ / The flow meter on NGI-13 was bfocked in on 03/29/09 an etumed to surface on 05/11/09; as this transmitter developed a small gas leak and was removed from service at that time. It wasn't until later that the lower design pressure was noticed on this and other transmitters, at which time the remainders were blocked in. The flow meters on NGI-01 03 04. 05. 08 12 were blocked in on 04/23/09 ~,.~.r d..~J~ced ack.in service on 05/12/0_9. The pressure-rate data for operation before and after this time was extrapolated graphicall to determine the rates for the time the transmitters were blocked in. Allowing them to operate or a short time after they were put back in service has been helpful in assuring the most accurate representation of the time they were out of service. I have attached a spreadsheet containing daily rates and pressures, as weli as the graphical analysis completed to obtain the data for the time the transmitters were out of service. «Gas Injector volume calculations.xis» ~ Please call with any questions or concerns. c,~~ ~ Thank you, °~'- Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 .~~~ n3C~~.- o~ r 7~ 6~ - ,f ,;~' , ~~* ~ ,t °_ ~' ? ~G~ ~Gt.z ~3C~' - o ~ I7 5 -6L 1 b~~- ~~w P,~~ ~;~T ~ ~ r-7s-o~~ ~f ~Rr,C NG~'-- 05 rZ~-°C`~r~ ~ ~p~ Z,~ ~~ _ C: ~ 1 ~!~ `°G SZ ~ ~~(,c I~C~ - ~ ~ (?`7-~'~ai ~'~~ ~~- ~3~ 2~~- ~~~ 8/6/2009 ~ SUMMARY OF INJECTED VOLUMES DURING FLOW TRANSMITTER OUTAGE Volume Tubing tnjected Pressure Date (MCFPD) (psi) NGI-01 05/12/09 119,210 3,165 05/11/09 117,670 3,148 05/10/09 136,884 3,360 05/09/09 144,134 3,440 05/08/09 143,228 3,430 05/07/09 145,131 3,451 05/06/09 143,681 3,435 05/05/09 140,146 3, 396 05/04/09 140,509 3,400 05/03/09 142,865 3,426 05/02/09 141,868 3,415 05/01 /09 140, 871 3, 404 04/30/09 135,796 3,348 04/29/09 135,977 3,350 04/28/09 134,708 3,336 04/27/09 133,530 3,323 04/26/09 140,056 3,395 04/25/09 142,503 3,422 04/24/09 140,328 3,398 04/23/09 138,515 3,378 NGI-03 05/12/09 110,330 3,450 05/11/09 110,692 3,455 05/10/09 110,836 3,457 05/09/09 111,053 3,460 05/08/09 113,151 3,489 05/07/09 113,657 3,496 05/06/09 113,006 3,487 05/05/09 112,211 3,476 05/04/09 113,947 3,500 05/03/09 113,368 3,492 05/02/09 114,814 3,512 05/01 /09 114, 091 3, 502 04/30/09 113,874 3,499 04/29/09 112,934 3,486 04/28/09 112,138 3,475 04/27/09 111,487 3,466 04/26/09 113,802 3,498 04/25/09 113,947 3,500 04/24/09 114, 091 3, 502 04/23/09 114,742 3,511 ~ NGI Volume Calculations ~ . NGI-04 05/12/09 112,110 3,070 05/11 /09 112,143 3, 050 05/10/09 111,633 3,356 05/09/09 111,437 3,474 05/08/09 114, 568 1, 595 05/07/09 113,765 2,077 05/06/09 111,428 3,479 05/05/09 111,498 3,437 05/04/09 111,488 3,443 05/03/09 111,445 3,469 05/02/09 111,460 3,460 05/01/09 111,488 3,443 04/30/09 111,587 3,384 04/29/09 111,575 3,391 04/28/09 111,603 3, 374 04/27/09 111,630 3,358 04/26/09 111,493 3,440 04/25/09 111,450 3,466 04/24/09 111,490 3,442 04/23/09 111,410 3,490 NGI-05 05/12/09 979,667 3,375 05/11/09 179,789 3,380 05/10/09 179,910 3,385 05/09/09 18Q,007 3,389 05/08/09 179,813 3,381 05/07/09 180,299 3,401 05/06/09 179,935 3,386 05/Q5/09 179,010 3,348 05/04/09 179,108 3, 352 05/03/09 179,667 3,375 05/02/09 179,472 3,367 05/01 /09 179,156 3, 354 04/30/09 177,892 3,302 04/29/09 178,062 3,309 04/28/09 '177,721 3,295 04/27/09 177,405 3,2$2 04/26/09 179,108 3,352 04/25/09 179,667 3,375 04/24/09 179,156 3, 354 04/23/09 180,178 3,396 05/12/09 150,117 3,470 05/11/09 150,117 3,470 05/10/09 150,117 3,470 05/09/09 149,821 3,467 05/08/09 148,833 3,457 05/07/09 151,599 3,485 05/06/09 150,117 3,470 05/05/09 145,869 3,427 05/04/09 146,067 3,429 05/03/09 148,438 3,453 NGI Volume Calculations 2 ~ 05/02/09 147, 351 3, 442 05/01 /09 145, 573 3,424 04/30/09 139,744 3,365 04/29/09 140,535 3,373 04/28/09 138,954 3,357 04/27/09 137,275 3,340 04/26/09 145,672 3,425 04/25/09 148,142 3,450 04/24/09 145,968 3,428 04/23/09 151,006 3,479 NGI-12 05/12/09 179,508 3,400 05/11/09 179,508 3,400 05/10/09 179,508 3,400 05/09/09 181,429 3,419 05/08/09 180,216 3,407 05/07/09 179,508 3,400 05/06/09 179,508 3,400 05/05/09 177,485 3,380 05/04/09 177,587 3,381 05/03/09 180,014 3,405 05/02/09 179,002 3,395 05/01/09 177,283 3,378 04/30/09 171, 721 3, 323 04/29/09 172,429 3,330 04/28/09 170,912 3,315 04/27/09 169,294 3,299 04/26/09 177,485 3,380 04/25/09 180,014 3,405 04/24/09 178,193 3,387 04/23/09 182,946 3,434 NGI-13 05/10/09 246,658 3,350 05/09/09 246, 368 3, 341 05/08/09 246,078 3,332 05/07/09 246,754 3,353 05/06/09 246,497 3,345 05/05/09 243,279 3,245 05/04/09 245,306 3,308 05/03/09 245,692 3,320 05/02/09 245,660 3,319 05/01/09 243,247 3,244 04/30/09 240,801 3,168 04/29/09 243,955 3,266 04/28/09 243,375 3,248 04/27/09 243,086 3,239 04/26/09 245,370 3,310 04/25/09 246,078 3,332 04/24/09 245,564 3,316 04/23/09 246,979 3,360 ~ NGI Volume Calculations 3 • • 04/22/09 247,494 3,376 04/21/09 246,979 3,360 04/20/09 247,366 3,372 04/19/09 247,333 3,371 04/18/09 247,301 3,370 04/17/p9 247,301 3,370 04/16/09 246,658 3,350 04/15/09 246,722 3,352 04/14/09 245,821 3,324 04/13/09 244,244 3,275 04/12/09 243,536 3,253 04/11/09 239,160 3,117 04/10/09 243,729 3,259 04/09/09 244,051 3,269 04/08/09 244,823 3,293 04/07/09 246,304 3,339 04/06/09 247,816 3,386 04/05/09 247,591 3,379 04/04/09 247,816 3,386 04/03/09 248,234 3,399 04/02/09 248,363 3,403 04/01/09 245,692 3,320 03/31/09 243,987 3,267 03/30/09 246,175 3,335 03/29/09 247,237 3,368 03/28/09 249,103 3,426 03/27/09 248,588 3,410 03/26/09 245,757 3,322 03/25/09 245, 049 3, 300 03/24/09 245,049 3,300 NGI Volume Calculations 4 NGI-01 155,000 150,000 y = 90.632x - 167640 ~ 145,000 0 140,000 ~ 135, 000 ~; , 130, 000 125,000 ~ 3,300 3,350 3,400 3,450 pressure 3,500 3,550 ~ ~ ~ M O ~ Z t ; • I ! • I ~ ~ ~ ~. ~ ~ ` ~. 1 ' ~ ~ ~ •~ ~ ( ~~ ~ ~ ~ ~~ ~: Z • ~ • • ' ' ~ , ~ , ~ '~ s ~ ~ 1 ' i ; # ~ ~ N I ~ N ~ I ~ M r. * ~ X ~^ M ~, M A N I~~ ti II ~ ~ O O O O O O O O O O O O O O t7 N O OO CO ~ N ~ ~ ~ M ~ O O ~ M 0 ~ ~ M ~ O ~ M O M W ~ ~ ~ ~ W ~ d 31bR1 y = -1.6665x + 117226 160, 000 140, 000 120, 000 100,000 w ~' 80,000 ~ 60, 000 40, 000 20, 000 0 NGI-04 3,300 3,350 3,400 3,450 3,500 3,550 3,600 ~ ~ PRESSURE NGI-05 182,000 181,500 181,000 180,500 180, 000 m r ~ ~ 179,500 179,000 178,500 178, 000 177,500 y = 24.302x + 97587 n \J ~ 3,300 3,320 3,340 3,360 3,380 3,400 3,420 3,440 3,460 3,480 Pressure NGI-08 160, 000 155,000 y = 98.79x - 192684 u 150, 000 m ~ 145,000 140, 000 135, 000 130, Q00 3,300 3,350 3,400 3,450 3,500 Pressure 3, 550 3,600 ~ NGI-12 rate = 101.13(pressure) - 164334 200, 000 195, 000 190,000 185, 000 d ~ 180,000 175, 000 170,000 i ~ 165, 000 160, 000 3,300 3, 350 3,400 3,450 3, 500 3,550 Pressure NGI-13A 260,000 255,000 ~ 250,000 245,000 w ~ ~ 240,000 235,000 ~ 230,000 225,000 2,500 2,600 2,700 2,800 2,900 3,000 PRESSURE 3,100 3,200 3,300 3,400 3,500 UPDATE: NGI Flow Transmitter~ • Page 1 of 2 Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIilntegrityEngineer@BP.comJ Sent: Monday, May 04, 2009 2:11 PM ~~~~~ ~2'~ /~ To: Regg, James B (DOA) `~ ~ ~ Cc: GPB, FS1 OTL; GPB, Area Mgr North (Gas Plants/GPMA); GPB, FS1 Fac Engr; Rossberg, R Steven; NSU, ADW Well Integrity Engineer; Daniel, Ryan; Bill, Michael L(Natchiq); Cahalane, Ted W; Dahlem, Jason E; Seymour, Len I; NSU, ADW Well Operations Supervisor; Cismoski, Doug A; Engel, Harry R Subject: UPDATE: NGI Flow Transmitters Jim, After further evaluation, it has been decided to leave the underrated flow transmitters on the seven NGI wells isolated until the fullv rated transmitters are available for replacement. The fuliy rated transmitters are expected to arrive on the slope on May 13th and work to install them is planned to begin on May 15th. After the transmitters are replaced, calculations will be made to determine injection volumes and rates for the time the meters were out of service. We wifl also provide our calculation and the exact number of days the flow meters .~ were out of service. We will continue to update you on the status of the replacements. If you have any questions in the interim, please don't hesitate to contact me or Anna Dube. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 From: Engel, Harry R Sent: Thursday, April 23, 2009 4;57 PM To: James Regg Cc: GPB, F51 OTL; GPB, Area Mgr North (Gas Plants/GPMA); GPB, FSl Fac Engr; Rossberg, R Steven; NSU, ADW Well Integrity Engineer; Daniel, Ryan; Bill, Michael L(Natchiq); Cahalane, Ted W; Dahlem, ]ason E; Seymour, Len I; NSU, ADW Well Operations Supervisor; Cismoski, Doug A; Engel, Harry R Subject: NGI Flow Transmitters Jim- This is a follow up to our telephone conversation this afternoon regarding flow transmitters at ~ NGI pad. The NGI 13 flow transmitter failed on March 29th. There was a minor gas release associated with the failure, far below 1 MMSCF. The flow transmitter was found to be underrated, yet the 8/6/2009 ~ UPDATE: NGI Flow Transmitters Page 2 of 2 - ~ ~ body is fully rated. We discovered six additional underrated flow transmitters at NGI 1, 3, 4. 5, 8, 12. All seven flow transmitters have been temporarilv taken out of service. The wells remain on injection. No other gas injection well flow meters are affected. We have taken the following actions; a. Contacted the manufacturer and ordered metal backed Viton O rings which will increase transmitter operating pressure rating. These O rings will be installed in all seven wells within 1'~ week. This is a temporary modification until new transmitters are installed. b. New fully rated transmitters have been identified and will be installed in all wells in ~ approximately 2-6 weeks. Flow rates will be calculated during the periods when the transmitters are out of service. ~ As you requested, we will send you the flow rate calculation method and the total number of ~ days the transmitters were out of service. I will be out of the office for a few days next week. If you have any questions, please contact Andrea Hughes at 659-5102. Regards, Harold R. Engel (Harry) Engineering Team Leader Integrity Management, Alaska Drilling & Wells 907-564-4194 office 907-564-5510 fax 8/6/2009 OPERABLE: NGI-OS (PTD #1760140) Replaced IA Transmitter Page 1 0 ~~~/ Regg, James B (DOA) From: NSU, ADW Well Inte n En ineer NSUADWWeAlnte n En ineer BP.com ~ ~ 7'l 9 ~tY 9 [ 9 ~tY 9 @ l ~~ Sent: Saturday, March 21, 2009 2:49 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr East (FS1/2/COTU/Seawater); GPB, FS1 OTL; GPB, FS1 DS Ops Lead; GPB, FS1 Fac Engr; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: GPB, Wells Opt Eng; GPB, EOC Specialists; NSU, ADW Well Integrity Engineer; Townsend, S. Eliot Subject: OPERABLE: NGI-05 (PTD #1760140) Replaced IA Transmitter All, Well NGI-05 (PTD #1760140) has been reclassified as Operable. The old transmitter has been replaced with another Honeywell transmitter. Once the Rosemont transmitters are ready and the work is scheduled, the transmitters on the gas injectors will be changed out. Well NGI-05 may be returned to injection when convenient. Please let us know if you have any questions. Thank you, ~tnna ~u6e, ~ E. Welt Integrity Coordinator GPB Wells Group Phone: (907) 659-5102 Pager: (907) 659-5100 x1154 ~' Er ~~~` s,'~'ssr From: NSU, ADW Well Integrity Engineer Sent: Wednesday, March 18, 2009 4:16 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr East (FSl/2/COTU/Seawater); GPB, FSl OTL; GPB, FSL DS Ops Lead; GPB, FSl Fac Engr; Rossberg, R Steven; Engel, Hany R; NSU, ADW Well Operations Supervisor Cc: NSU, ADW Well Integrity Engineer; GPB, Wells Opt Eng; GPB, EOC Specialists Subject: NOT OPERABLE: NGI-05 (PTD #1760140) IA transmitter under repair All, Well NGI-05 (PTD #1760140) has an AOGCC Administrative Approval for slow IA repressurization that requires a remote pressure monitor on the IA. With this transmitter currently out of service, the decis"son has been made to shut-in the well until the transmitter has been replaced. Therefore the well has been reclassified as Not Operable. Piease let me know if there are any questions. Thank you, Anna 1~ude, ~ E. Well Integrity Coordinator GPB Wells Group Phone: (807) 659-5102 Pager: (807} 659-5100 x1154 3/23/2009 NGI-OS (PTD #1760140) IA transmitter under repair Regg, James B (DOA) Page 1 of 1 From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Sunday, February 01, 2009 8:09 PM ',~~~ ~~~I ~~ ~ To: Regg, James B(DOA); Maunder, Thomas E(DOA); GPB, Area Mgr East (FS1/2/COTU/Seawater); GPB, FS1 OTL; GPB, FS1 DS Ops Lead; GPB, FS1 Fac Engr; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: NSU, ADW Well Integrity Engineer Subject: NGI-05 (PTD #1760140) IA transmitter under repair Attachments: NGI-05 TIO and Injection Plot.doc ~/ Jim and Tom, ~ The pressure transmitter on the IA of NGI-05 (PTD #1760140) as required by AA 4E.032 has ceased working. A new transmitter has been ordered and is expected to arrive within 3-4 wee s. Our intention is o e~ave t-he well on injection in the interim. I have included a TIO plot and injection plot for reference. ~ «NGI-05 TIO and Injection Plot.doc» ~ I will update you when the transmitter has been replaced. Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 .~.a ~a ls~ t~: ~6 MR':.li' 1 ..., t .:n~~.~i .1 9/11/2009 PBU NGI-OS PTD 176-014 February 1, 2009 TIO Plot ^ ~- ii~~i-+~-i---~+aiyf~f ._ •;~i a faa~a-a~f ~-a L--• h~i-f-~ _.. + +~+ • +-+-~-~ . ~ ~ ~ 1%i06;'C~9 1U13/06 12;20/!18 1212'r.~ Oi/D3lp9 Ut/1CUP3 01/17iU9 0124/09• Otl31l0°. Injection Plot 3,W0 3.600 3.400 3,2~ 3,000 2.~0 2,600 2.1~ 2,200 d 2.000 x 31.800 1,600 1.600 1200 1.~iL1 ~0 ~ 400 200 :ao,ooo ~o.o~ 240,~0 220,~0 zoo,ooo 180,D00 16D 000 £ ~ 0 140.000 ; ~ 120,000 ~ 100.000 BO,D~ 60AD0 40.~ 20,000 12JU6J08 12/13/OB 1U20'OB 12I27J96 01/03/09 01/10l09 01/17/09 01/24f09 O1/31/D9 -f Tbq ~ IA -~ OA OOA ~- 000.4 ~ On - VlHIP -- SW - pv/ - MI - GI - Olha -~- On OPERABLE: NGI -05 (PTD #17600) IA repressurization Slowed • Page 1 of 2 Maunder, Thomas E (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWelllntegrityEngineer @BP.com] Sent: Sunday, September 21, 2008 2:29 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr East (FS1 /2 /COTU /Seawater); GPB, FS1 OTL; GPB, FS1 DS Ops Lead; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor; Daniel, Ryan; GPB, Wells Opt Eng Cc: Holt, Ryan P (ASRC); Randall, Jaclyn S; NSU, ADW Well Integrity Engineer Subject: OPERABLE: NGI -05 (PTD #1760140) IA repressurization Slowed Attachments: NGI -05 TIO and Injection Plots.doc All, The SSSV was reset in well NGI -05 (PTD #1760140) on 09/12/08. Since that time the IA pressure has remained stable indicating the valve replacement was successful in mitigating the rapid TxIA communication. The well has been reclassified as Operable. A TIO and Injection plot have been included for reference. «NGI -05 TIO and Injection Plots.doc» Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator �� " ` �, Office: (907) 659 -5102 Pager: (907) 659 -5100 x1154 From: NSU, ADW Well Integrity Engineer Sent: Friday, September 05, 2008 5:37 PM To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA) ; GPB, Area Mgr East (FS1 /2 /COTU /Seawater); GPB, FS1 OTL; GPB, FS1 DS Ops Lead; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor; NSU, ADW Well Integrity Engineer Cc: Winslow, Jack L.; Townsend, S. Eliot; Randall, Jaclyn S Subject: UNDER EVALUATION: NGI -05 (PTD #1760140) Increase in IA repressurization All, Well NGI -05 (PTD #1760140) is operating under Administrative Approval 4E.032 dated 06/09/08 for slow IA repressurization. Over the last few days the bleed frequency has increased. The showed an IA repressurization rate of —750 psi a day, leading us to believe the SSSV packing has failed. A TIO plot, injection plot and wellbore schematic have been included for reference. Bleed events summary: > 09/04/08: Bled IAP from 2100 psi to 1200 psi, 20 minutes, all gas > 09/05/08 morning: Bled IAP from 1570 psi to 270 psi, 30 minutes, all gas > 09/05/08 afternoon: TIO 3150/660/460 psi 5/23/2011 OPERABLE: NGI -05 (PTD #1760 ) IA repressurization Slowed • Page 2 of 2 The plan forward for the well is as follows: 1. S: Reset SSSV 2. WIC: POI and monitor TIO plot The well has been classified as Under Evaluation and placed on a 28 -day clock. Please call with any questions. Thank you, Taylor Wellman (filling in for Anna Dube) Taylor Wellman Alternate - Jason Dahlem Well Integrity Projects Engineer (907) 659 -5098 (office) (907) 659 -5100 pager #1446 x2418 (harmony) (907) 947 -9533 (mobile) 5/23/2011 • 0 NGI -05 TIO Plot 4,000 • - • - • ................-.....-.-.4.-..-..-.4,-............. .- ..«.».-......-.• ..._......- ......... 3,000 2000 se I CI N , s ■ t` ! '� I 1.080 1� r o j r i 1 I` 1 .. r moralimos a 06/21 /08 06/28 /08 07/05/08 07/12/08 07/19,/08 07/26/08 08/02/08 08/09/08 08/16/06 08123/08 08/30/08 09/26/08 09 /13/08 09/ NGI -05 Injection Plot - 200000 4'080 - 108,000 3,080 - 3,600 ( v -1:1,000 - 170,08D 3,400 160000 3,200 3 ` -1503,000 - 140,000 2,080 - -133008 2,600 2.408 -120,080 m - 110,000 a, 2,200 - 0 2,0CA J 00- 1,� - ! - 90,E 9 1600 - - 80,000 1,400 - - 70,080 1200 - - 60,000 1,080 • - 50,008 800 - - 40,000 • ' - 30,0W 400 . - 20,008 gyp• -10,008 08/21/08 06/28/08 07/05/00 07/12/08 07/19/08 07/26/08 08/02/08 08109/08 00/16 /08 08/23/08 08/20/08 09/08108 09/13/08 09/20/08 r_l SARAH PALtN, GOVERNOR AI ASKA 01% ,A NI) G" 333 W 7th AVENUE, SUITE 100 CONSERVATION CO1r MSSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 278 -7542 ADMINISTRATIVE APPROVAL 4E.032 Mr. Steve Rossberg Wells Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: PBU NOI -05 (PTD 1760140) Request for Administrative Approval Prudhoe Bay Oil Pool Dear Mr. Rossberg: Pursuant to Rule 9 of Area Injection Order (AIO) 04E.000, the Alaska Oil and Gas Conservation Commission ( AOGCC or Commission) hereby grants BP Exploration (Alaska) Inc. (BPXA)'s request for administrative approval to continue gas injection in the subject well. AOGCC finds that BPXA has elected to perform no corrective action at this time on PBU NGI -05. The Commission further finds that the well demonstrates inner annulus (IA) repressurization that can be safely managed with periodic pressure bleeds. Outer annulus pressures do not indicate anomalous conditions or loss of pressure integrity. The Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety, if the well's operation is subject to the constraints enumerated below. AOGCC's administrative approval to continue gas injection in PBU NGI -05 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures and injection rates, and shall flag the well's periodic pressure bleeds on the report; 3. BPXA shall perform an MIT - IA every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2500 psi; AIO 4E,032 June 9, 2008 Page 2 of 2 5. BPXA shall install, operate and maintain remote pressure monitoring equipment on the well's IA; an alarm set point of no higher than 2000 psi shall be maintained to allow for time to respond and bleed pressure from the IA; 6. BPXA shall immediately notify the AOGCC and shut in the well if there is any continued deterioration in well integrity, indicated by increased inner or outer annulus pressure, increased repressure rate, or increased bleed frequency; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is April 26, 2008. DONE at Anchorage, Alaska and dated June 9, 2008 . & SM a by . Foerster 0t Com issioner Commis 'o cc: BPXA Well Integrity Coordinator, PRB -20 �, P.O. Box 196612 Anchorage, AK 99519 -6612 11.0 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of re- consideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Com- mission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by in- action, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on re- consideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on re- consideration. As provided in AS 31.05.080(b), " (t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the pe- riod; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • � Page 1 of 2 Maunder, Thomas E (DOA) From: NSU, ADW Well Integrity Engineer [ NSUADWWelllntegrityEngineer @BP.com] Sent: Tuesday, May 27, 2008 5:55 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: NSU, ADW Well Operations Supervisor; NSU, ADW Well Integrity Engineer; Engel, Harry R; Senden, Leslie B Subject: RE: PBU WGI -05 NGI -05 Ad min Approval Requests Jim, Topic 1: A review was completed by the Facility Engineer and Lead Operator to discuss the likely chain of events if an automatic shut -in occurred on a gas injector supplied through the Central Compression Plant and is summarized in the following paragraph. Though, installing annular automatic shut -in equipment set to trip above normal operating limits and below casing burst ratings provides a level of protection to the well and its immediate vicinity, an unplanned shut -in on any gas injector would initiate a sequence of events requiring reactive measures by operations, field wide, to control facility over pressurization. After an automatic shut -in on a gas injector, Central Compression Plant gas compressors would immediately exhibit increased discharge pressures. Managing these pressures would require a rapid reduction in the volume of gas entering the compression facility by cutting rate from gas supplying facilities. If discharge pressures reach a sufficient level the compressors' high pressure shutdowns trip. At this point the entire gas injection system, including common lines and facility gas systems, begins to increase in pressure. To manage the pressurization and incoming gas rates, facilities would begin to flare gas and shut -in entire pads /drill sites. Topic 2: When a well on AGI, NGI, or WGI -Pad has been found with IA repressurization, one of the first diagnostic steps is to troubleshoot the SSSV. On NGI -05 the SSSV was reset on 04/28/08 and on WGI -05 the SSSV was reset on 04/29/08. In both cases, slow TxIA communication still exists thus bringing us to request an AA. Topic 3: The minor OA repressurization trend could be due to thermal effects related to the TAA communication. However, more diagnostic work is required because there was no report of a bleed in April. Our plan is to bleed the OAP to 0 psi and monitor the build up rate. Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659 -5102 Pager: (907) 659 -5100 x1154 From: Regg, James B (DOA) [mailto:jim.regg @alaska.gov] Sent: Thursday, May 15, 2008 4:31 PM To: NSU, ADW Well Integrity Engineer Cc: Maunder, Thomas E (DOA) Subject: PBU WGI -05; NGI -05 Admin Approval Requests Both requests include wording to the effect that requiring auto shut in capability tied to the annulus pressure represents a hazard. Do you have something more substantial to provide the Commission other than the 3 12/21 /2010 • 0 Page 2 of 2 sentences in your requests that tell us you've reviewed and came to some conclusion? Otherwise, I have nothing to corroborate your statements, and as I have mentioned in past emails, our decision has to be made on the facts provided in the application (and what we have on file, which is not much related to process flow and overpressure protection). Perhaps you have some sort of hazop or similar that could be provided? It seems to me from similar concerns with other injectors at AGI, NGI, WGI that the TxIA communication is directly linked to the SSSV (I believe I have seen statements about gas injection drying seals). At what point do you ( a repair attempt reseat SSSV, install new SSSV, etc.)? Has there been any attempt to make repairs on these 2 wells? Also, looking at the NGI -05 TIO plot, there is an increasing OA pressure beginning in February, with what I would interpret a pressure bleed event sometime in April. Please provide some discussion about this in your response. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 i 12/21 /2010 RECEIVED APR 3 0 2008 by BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Alaska Oil & Gas Cons. Commission Post Office Box 196612 Anchorage, Alaska 99519 -6612 Anchorage 0 April 29, 2008 Mr. Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay well NGI -05 (PTD #1760140) Request for Administrative Approval: Continued Gas Injection Operations Dear Mr. Seamount, BP Exploration (Alaska) Inc. requests approval for continued gas injection operations into Prudhoe Bay well NGI -05. Well NGI -05 exhibits inner annulus re-pressurization and is safe) managed b periodic inner I p Y 9 YP annulus bleeds. The tubing P casing and production competent barriers as indicated by a 9 are com P mechanical integrity test of the inner annulus to 4,150 psi. BP will continue to monitor and record wellhead pressures daily. We will also install remote pressure monitoring equipment on the inner annulus. In the event that IA pressure exceeds BP's maximum allowable annular pressure of 2,000 psi, operations will receive an alarm. This engineering control adds a level of protection and allows operations to actively manage gas rates in the event the well needs to be shut -in. BP has reviewed installing automatic shut -in equipment on dedicated, large volume gas injection wells and has concluded this is not a safe option. An automatic shut -in situation would create the potential for over pressure conditions at several facilities. This could lead to a major flare event at the gas plants and require entire drill sites to be shut down. In summary, BPXA believes Prudhoe Bay well NGI -05 is safe to operate as stated above and requests administrative approval for continued gas injection operations. If you require any additional information, please contact me at 564 -5637 or Anna Dube / Andrea Hughes at 659 -5102. Sincerely, R. Steven Rossberg Wells Manager, BPXA Attachments: Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Bixby /Olsen Dube /Hughes East Area Manager Leslie Senden Harry Engel Janice Vosika II Prudhoe Bay Oil Pool well NGI -05 Technical Justification for Administrative Approval Request April 29, 2008 Well History and Status Prudhoe Bay well NGI -05 (PTD #1760140) exhibits manageable inner annulus repressurization indicated by wellhead pressure trends on a TIO plot. A MIT -IA to 4150 psi passed on 4/26/08 indicating competent tubing and production casing. Recent Well Events: • 04/09/08: Notified AOGCC of IAP increase • 04/20/08: PPPOT -T Passed to 5,000 psi. PPPOT -IC Passed to 3,500 psi. • 04/26/08: Set TTP @ 8013', MIT -T Passed to 2000 psi • 04/26/08: AOGCC MIT -IA Passed to 4150 psi Barrier Evaluation The primary and secondary barrier systems consist of tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 4150 psi, demonstrating competent primary and secondary barrier systems. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Install remote pressure monitoring equipment. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 4 -year MIT -IA to maximum anticipated injection pressure. 5. The well will be shut -in and the AOGCC notified if there is any change in the wells mechanical condition. 4,000 NGI -05 110 Plot t Tbg 3,000 s IA i 2 IA MAASP ! OA i i I 000 OA MAASP OOA I -iF OOOA i 0 arA=7 6rzsrloo7 8n8n007 1012WO07 12fMr"7 2 MOM 4n8 AW 0 0 NGI*5 Daily Allocated Injection Plot g. ° - AHP o Q N ' V $ � V S S � a C7 N x [ 0 7 8 O p fOD O GAS O O 47292007 629/1007 8292007 7 0292007 12292007 2/2972008 5292008 TREE= 7 -1116" CIW SAFET " * *9 -518" CSG SET ON EMERGENCY SLIPS WEL = GRAY * WO PROG N FILE NOTED GRAY 6 -3/8" K BP ACTUATOR = { BAKER �� PROF �E * IN TBG HGR CANT ACCOMMODATE TWC KB. ELEV = 47.0' BF. ELEV - NA KOP = _ 330 Max Angle - 33 Datum MD = Datum TV D = 8800' SS 2184' 7" CAMCO BAL -O SSSV NIP, ID 7- 518" TBG -IPC, 29.7 #, NT -80, 1 -- E - 2182' 4 - 2188" 7" X 7 -518" XO, = 6.151" .0459 bpf, ID = 6.875" 2356 9- 5 /$ "JOYlARCO O/S CSG PATCH, ID = 8.625" Minimum ID = 5.50" @ 8024' 7 HES RN NIPPLE 2393 s -5/$" FoC 2671' 9 -518" FOC 13 -3/8" CSG, 72 #, MN-80, ID = 12.347" 2719' 7 -518" TBG•IPC, 29.7 #, NT -80, 7987 7988 .0459 bpf, ID = 6.875" 7989 9 -5/8" X 7" BKR SA BL -3 PKR, ID = 6.00" 7" TBG -IPC ?, 26 #, NT -80 8035' 8038' 7" wLEG, = 6.z7s" .0383 bpf, 1) = 6.276" —� ELMD TT NOT LOG GED 8108' BOT T1�ACK SLV, I = 7. 8114 9 -518" X 7" BOT MC LNR HGR 9- 518" CSG, 47 #, MN-80, ID = 8.681" 8418' PERFORATION SUMMARY REF LOG: BHCS ON 03/21/76 ANGLE AT TOP PERF: 28 @ 8807' Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn /Sqz DATE 2 -718" 4 8807-8817 O 10/03/77 2 -7/8" 4 8841-8876 O 10/03/77 2 -7/8" 4 8891-8921 0 10/03/77 2 -7/8" 4 8936-8966 O 10/03177 2 -7 /8" 4 8981-9011 O 10/03/77 2 -718 4 9047-9072 O 10/03/77 2 -7/8" 4 9110-9130 O 10/03/77 2 -7/8" 4 9152-9182 O 10/03/77 2 -718" 4 9211-9231 O 10/03/77 3 -3/8" 4 8820-8841 0 11123/86 3 -3/8" 4 8921-8936 0 11/23186 3 -3/8" 4 9011-9042 O 11/23/86 ? FISH - FLAPPER PIN SPRING FROM WRDP 3 -3/8" 4 9072-9110 0 11/23/86 (01/11!06) 3 -318" 4 9130-9152 O 11/23/86 PBTD 9313' 7" LNR, 29 #, MN-80_0371 bpf, ID = 6.184" 1 9398' DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 04/06/76 ORIGINAL COMPLETION 03/04/07 LBS/TLH TBG IPC CORRECTION WILL: NGI-05 06/12/99 RWO 07/22/07 BSE/PJC PULL IA/ SET SSSV NIP (07/11107) PERMIT No: 176 -0140 12/31/01 CHrTP CORRECTIONS 10/22/07 DDK/PJC ACTUATOR CORRECTION API No: 50- 029 - 20196 -00 01/17/06 MORIPAG WRDP PIN LEFT (01/11/06) SEC 12, T1 IN, R1 4E 450' SNL & 1039' EWL 04/19/06 KSB /PAG WRDP FLAPPER FISH (04/10/06) 12/10/06 TWS/TLH SSSV CORRECTION/FISH OUT BP Exploration (Alaska) MEMORANDUM To: Jim Regg ~_ P.I. Supervisor ~~,>I ~'~~{~~1 FROM: Chuck Scheve Petroleum Inspector State of Alaska • Alaska OiI and Gas Conservation Commission DATE: Wednesday, April 30, 2008 SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)PVC NG[-OS PRUDHOE BAY L~VIT NGI-OS Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~~~~ - Comm Well Name: PRUDHOE BAY UNIT NGI-OS ' Insp Num: mitCS080427065933 Rel Insp Num: API Well Number: 50-029-20196-00-00 Permit Number: 176-014-0 Inspector Name: Chuck Scheve Inspection Date: 4/26/2008 Packer Depth Pretest Initial 15 Min. 30 Min. 451Viin. 60 Min. Well NGI os ~~,Type Inj I 'TVD ---- j 7372 ~i h [06o j atao ~' 400 ~ ao6o I 4oso - P.T. 1 t760140 ',TypeTest SPT I 'l'est pSl ~ 1843 ~~i QA I 40 40 ~ 40 I 40 40 Interval oTt-i>JR p~F P Tubing ~~ zoo ~, z6oo ,~ 2sao zsso ' zsso Notes• Test performed for AA request. A plug was set in the tubing tail and the tubing fluid packed. Pressure was applied to prevent tubing collapse. ~'!N MAY ~ ~- 2008 Wednesday, April 30, 2008 Page I of I NGI-OS (PTD #1760140) IA repressurization -Reclassified as Operable Page l of 2 Regg, James B (DOA) • • From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] ,' ~C~-l~ ~ ~~,~ D`~' Sent: Wednesday., April 30, 2008 11:02 AM 1 To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr East (FS1/2/COTU/Seawater}; GPB, FS1 OTL; GPB, FS1 DS Ops Lead; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: Winslow, Jack L.; NSU, ADW Wi Tech; Senden, Leslie B; NSU, ADW Well Integrity Engineer Subject: NGI-05 (PTD #1760140} IA repressurization -Reclassified as Operable Ail, Well NGI-05 passed an AOGCC witnessed MIT(A on 04126108. The passing MITIA proved the tubing, produc#ion packer and production casing competent to liquid. Therefore, the weR is Operable per the Well Integrity System Policy. An Administrative Approval (AA) request has been submitted to the AOGCC for continued injection with IA repressurization to comply with AOGCC Area Injection Order 4E. The well has been reclassified as Operable. Notification Will be sent to Operations upon receipt of AA. If approval is not granted, the Well Will be shut-in and secured. Please call with any questions or concerns. Thank you, ~~,~111d1~ MAY ~ ~ 2008 Andrea Hughes From: NSU, ADW Well Integrity Engineer Sent: Wednesday, April 09, 2008 3:50 PM To: 'Regg, James B (DOA)'; 'Maunder, Thomas E (DOA)'; GPB, Area Mgr East (FSl/2/COTU/Seawater); GPB, FSl OTL; GPB, FSl DS Ops Lead; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: NSU, ADW Well Integrity Engineer; Winslow, Jack L.; NSU, ADW WI Tech; Senden, Leslie B Subject: UNDER EVALUATION -NGI-05 (PTD #1760140) IA repressurization Jim, Well NGI-05 (PTD #1760140) has recently shown an increase in IA pressure. DHD bled the IA pressure from 1110 psi to 460 psi on 04/04/08. A monitor the next day found the IA pressure had increased 100 psi overnight. We plan to keep the well on injection and perform further diagnostics. The plan forward is as follows: 1. D: Monitor IA pressure build up rate 2. S: Troubleshoot SSSV 3. F: AOGCC MITIA 4. WIC: Eval for AOGCC Administrative Approval request A wellbore schematic, TIO plot and Injection plot have been included for your reference. The well has been reclassified as Under Evaluation. Please call with any questions or concerns. 4/30/2008 NGI-OS (PTD #1760140) and WGI-OS (PTD #1900250) MIT Forms Page 1 of 1 • Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Tuesday, April 29, 2008 7:01 AM ~~~~ ~"IZ-`~~Cx To: Regg, James B (DOA); Maunder, Thomas E (DOA); Fleckenstein, Robert J (DOA) Cc: NSU, ADW Well Integrity Engineer; NSU, ADW WI Tech; Senden, Leslie B Subject: NGI-05 (PTD #1760140) and WGI-05 (PTD #1900250) MIT Forms Attachments: MIT PBU NGI-05 04-26-08.x1s; MIT PBU WGI-05 04-27-08.x1s Jim, Tom and Bob, Please see the attached MIT forms for the MIT-IA's performed on NGI-05 (PTD #1760140) and WGI-05 (PTD #1900250). The tests were performed for AA application. The AA requests will follow. «MIT PBU NGI-05 04-26-08.x1s» «MIT PBU WGI-05 04-27-08.x1s» Please call with any questions or concerns. Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 ~'~~r~~~ ~~~ ~' ~ ~Q~~ 4/29/2008 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to: Winton_Aubert@admin.state.ak.us; Bob_Fleckenstein@admin.stale.ak.us; Jim_Regg@admin.state.ak.us; Tom_Maunder@admin.state.ak.us OPERATOR: BP Exploration (Alaska), Inc. FIELD /UNIT /PAD: Prudhoe Bay !PBU (NGI pad ~ i~ ~ jy~ ~O DATE: ~ 0426/08 OPERATOR REP: Andrea Hughes AOGCC REP: Chuck Scheve Packer Depth Pretest Initial 15 Min. 30 Min. Well NGI-05 Type Inj. N TVD 7 372' Tubing 2020 2600 2580 2580 Interval O P.T.D. 1760140 Type test P Test psi 4150 Casing 1060 4140 4100 4060 ~ P/F P Notes: MIT-IA for AA Request OA 40 40 40 40 Additional 15 minute monitor: T/I!O = 2580/4050/40 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPEINJ Codes D =Drilling Waste G =Gas 1 =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature lest INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T=Test during Workover O =Other (describe in notes) MIT Report Form BFL 9/1105 MIT PBU NGI-OS O4-26-OS.xls UNDER EVALUATION -NGI-OS (PTD #1760140} IA repressurization Page 1 of 1 Regg, James B (DOA) ~ • From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Wednesday, April 09, 2008 3:50 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); GPB, Area Mgr East (FS1/2/COTU/Seawater); GPB, FS1 OTL; GPB, FS1 DS Ops Lead; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor Cc: NSU, ADW Well Integrity Engineer; Winslow, Jack L.; NSU, ADW WI Tech; Senden, Leslie B Subject: UNDER EVALUATION -NGI-05 (PTD #1760140) IA repressurization Attachments: NGI-05.pdf; NGI-05 TIO PIot.BMP; NGI-05 Injection PIot.BMP Jim, Well NGI-05 (PTD #1760140) has recently shown an increase in IA pressure. DHD bled the IA pressure from 1110 psi to 460 psi on 04/04/08. A monitor the next day found the IA pressure had increased 100 psi overnight. We plan to keep the / well on injection and perform further diagnostics. The plan forward is as follows: 1. D: Monitor IA pressure build up rate 2. S: Troubleshoot SSSV 3. F: AOGCC MITIA 4. WIC: Eval for AOGCC Administrative Approval request A wellbore schematic, TIO plot and Injection plot have been included for your reference. «NGI-05.pdf» «NGI-05 TIO PIot.BMP» «NGI-05 Injection PIot.BMP» The well has been reclassified as Under Evaluation. Please call with any questions or concerns. ~~i~~~ MAC' Q ~ 200 4/29/2008 f" ~,ooa I`dGl-05 TIC Piat # Tb~ s,aoa ~,~~ r~.~usQ 2,000 - 1 ,000 0 1 fT~2008 -~- iR ,~- oa oo~ o~ 1 !22!2008 2~6~008 2I21 X1008 317008 3l22~2008 4172008 4~22l2008 • ~ ~ A~~i ~11iIP. i~~i~~ aaa' aoa'a aaa'z aaa' ~ a a ~ ~~ •~ ~~[R[ s~ .~ ~[? ~_ L 0 Q N h- O O CV T ~~ a 0 -. ~- o --...__ 0 0 a ~ ~ S Ie aaa' asz aaa' a ~~ oao' ate ~ aaa' a~ a TREE = 7-1116" G>W WELLHEAD= GRRY ACTUATOR = BAKER KB. ELEV = 47.0' BF, ELEV = NA KOP = 3300' Max Angle = 33 @ 430[T Datum MD = Datum TV D = 8800' SS . SAFET 7E5: "'9-518" CSG SET ON E[VtERGE1VCY SLIPS " WU tvt IN FILE NOTED GRAY 6-3.'8" K BF'd ~~ ~ PROFILE IN TBG HGR CA N'T ACCOMMODATE A TWC 7-518" TBG-IPC, '19.7#, NT-80, 21$2' .0459 bpf, ID = 6.875" Minimum #D _ 5,50" @ 8024' 7" HEJ RN NiPP~.E 13-318" CSG, 72#, 4~1N-80, iD = 12.347" ~ 2719' 7-518" TBG-IPC, 29.7#, NT-80, X9$'7" .0459 bpf, ID = 6.875„ 7" TBG-IPC?, ?_6;~; NT-8d, J $03,5' .0383 bpf, ID = 6.276" !] 9-,S.B" CSG, 47#, MN-80, ID = 8.681" ~--~ 841$ PERFORATION SUMh1ARY REF LOG: BRCS ON 03/21/76 ANGLE AT TOP PERF: 28 ~ 8807' Note: Refer to Production DB for historical parf data SIZE SPF INTERVAL UpnlSgz DATE 2-718" 4 8807 - 8817 O 10;03.?77 2-718" 4 8841 - 8876 O 10/03/77 2-718" 4 8891 - 892.1 U 10(03;77 2-718" 4 8936 - 8966 O 10?03,'77 2-718" 4 8981 - 9011 U 10103'77 2-718" 4 9fl47 - 9072 U 1 Q~03,'77 2-718" 4 9110 - 9130 U 1003? 77 2-718" 4 9152 - 9182 O 10!03,'77 2-718" 4 9211 - 9231 U 10?03.!77 3-318" 4 8820 - 8841 U 11?23186 3-318" 4 8921 - 8936 O 11123?86 3-318" 4 9011 - 9042 O 11/23/86 3-318" 4 9072 - 9110 U 11?23?86 3-318" 4 9130 - 9152 U 11?23?86 PBTD 9313' 7" LNR, 29#, h1N-80, .0371 bpf, ID = 6.184" 939$' 21$2' -- f 7-518`° X 7" XU, ID = 6.151'° 21$4' 7" CA P.ACO BA L-O SSSV NIP, ID = 5.937" 21$8' 7" X 7-518" XO, ID = 6.151 " 2356' 9-5;8"JOYIARGO OIS CSG PATCH, ID = 8.625" 2393' 9-5?8" FOC 2671' 9-518" FOC 7w~!$$` °f 7-518'° X 7" XO, ID = 6.250" 79$9' 9-5.!8" X 7'° BKR SABL-3 PKR, ID = 6.00" 8024' 7" HES RN NIP, ID = 5.50" $03$' 7" WLEG, ID = 6.276" ~~ ELMD TT NOT LOGGED $108' BOT TIEBACK sLV. ID = 7.00" 8114' 9-518" X 7" BUT MC LNR HGR DATE REV BY CUM[,•1ENTS DATE REV BY COMMENTS 04(06176 ORIGINAL COM PLE`f'[ON 03104?07 LBS;'TLH TBG IPC CORRECTION 061!2199 R4NO 07?22x07 BSE;'PJC PULL IAl SET SSSV NIP {0711110 12/31101 CHlTP CORRECTIONS id?22/07 DDK?PJC ACTUATOR CORRECTON 01117/06 MORIPRG WRDP PIN LEFT {d1!11106j 04,`19106 KSBIPAG VVRDF' FLAPPER FISH {04110106) 12110106 TUJSITCH SSSV CORRECTION/F1.5H OUT FISH- FLAPPER PIN SPRING FRUM WRDP {01111?06} PRUDFiOE BAY UNIT WELL: NG9-05 '} PERMIT No: 176-0140 API No: 50-029-24196-QO SEC 12, Tt 1 N; R14E 450` SNL & 1039' EWL SP Exploration {AEaska) NGI-05 (PTD #1760140) TxIA co.unication Regg, James B (DOA) . Page 1 of2 From: NSU, ADWWelllntegrity Engineer [NSUADWWelllntegrityEngineer@BP.com] Sent: Friday, September 07, 2007 3:42 PM ('(J t: 1(ZÇ(ù1 To: Regg, James B (DOA) \<../11 Cc: NSU, ADWWelllntegrity Engineer; Austin, Paul A Subject: RE: NGI-05 (PTD #1760140) TxlA Communication Attachments: NGI-05.BMP Hi Jim, ¡/ The wellhead packoffs were tested and passed on 9/3/07 confirming there is no tubing by inner annulus communication through the wellhead. Yesterday on 9/6/07, the injection valve on a carrier was pulled and reset in the SV nipple. The IA pressure is being bled today and will be monitored over the next couple of days. Here is a plot of the TIO pressures. I am going to add this well to the monthly injection report coming your way although it will only show data up to the end of the month. We'll track it for a couple of months to be sure that this mitigated the problem. ./ If you would like to be updated between submittals of the monthly injection report, please send a request to the Well Integrity Engineer account and we'll respond. Thank you, jInna (])u6e, Œ'. f£. Well Integrity Coordinator GPB Wells Group Phone: (901) 659-5102 Pager: (901) 659-5100 x1154 SCANNED SEP 2 7 2007 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Wednesday, September 05,20074:30 PM To: Dube, Anna T Subject: RE: NGI-05 (PTD #1760140) TxIA Communication Timing to complete SSSV diagnostics? Please provide 90 day TIO pressure plot. Appears to be one of the few wells on NGI that have avoided SCP issues Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Dube, Anna T [mailto:Anna.Dube@BP.com] Sent: Monday, September 03,20079:16 PM To: GPB, Area Mgr North (Gas Plants/GPMA); GPB, Area Mgr East (FS1/2/COTU/Seawater); GPB, FS1 OTL; GPB, FS1 DS Ops Lead; Rossberg, R Steven; Engel, Harry R; NSU, ADW Well Operations Supervisor; GPB, Wells Opt Eng; GPB, Optimization Engr; GPB, Prod Controllers; Regg, James B (DOA); Maunder, Thomas E (DOA); Fleckenstein, Robert J (DOA); Senden, Leslie B; NSU, ADW WL & Completion Supervisor; Cismoski, Doug A 9/25/2007 NGI-05 (PTD #1760140) TxIA cownication Cc: NSU, ADW Well Integrity Engineer; au, John, Jack Subject: NGI-05 (PTD #1760140) TxIA Communication . Page 2 of2 Hi all, Well NGI-05 (PTD #1760140) has TxlA communication represented by increasing fA pressure. The wellhead pressures were 3200/2100/150 on 09/02/07 before the IA pressure was bled to 1500 psi. A positive pressure packoff test of the tubing head seals passed today, proving integrity of the seals. The plan forward is to leave the well on injection and troubleshoot the SSSV. The plan for ward is: 1. W: PPPOT-T - PASSED 2. S: Troubleshoot SSSV A wellbore schematic has been included for reference. «NGI-05.pdf» Please call with any questions. Thank you, jInna (])u6e, Œ'. f£. Well Integrity Coordinator GPB Wells Group Phone: (907) 659-5102 Pager: (907) 659-5100 x1154 9/25/2007 . MEMORANDUM State of Alaska . Alaska Oil and Gas Conservation Commission DATE: Tuesday, July 03, 2007 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC NGI-05 PRUDHOE BAY UNIT NGI-05 TO: Jim Regg P.I. Supervisor rn \(if1 1 l¡lë l û 7 FROM: John Crisp Petroleum Inspector Well Name: PRUDHOE SAY UNIT NGI-05 Insp Num: mitJCr070701170257 ReI Insp Num: Packer f----------~;;¡;;;:--~. Well i NGI-05 Type Inj. ! G i TVD ~, 1 '. .1 ' I P.T.Di 1760140 ITypeTest ¡ SPT: Test psi Interval 4YRTST P/F P \ 1b- ollt Src: Inspector Reviewed By: P.I. Suprv \. 1ß12-- Comm NON-CONFIDENTIAL API Well Number: 50-029-20196-00-00 Permit Number: 176-014-0 Inspector Name: John Crisp Inspection Date: 6/30/2007 Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 7372 1/IA¡ 660 I 2200 ! 2200 I 2240 I 2240 V-- _~-+-___--L...- I __ 1843 ! OA I 0 I 0 . 0 ¡ 0 I 0 I ----L..... --I-- I I r +---- /- Tubing I . 3325 I 3325 I 3325 3325' 3325 i --L- I i Notes: 7.5 bbl's pumped for test. Well injecting gas with temp. of 160 degrees. Diesel pumped for test 40 degrees. Possible explanation for test pressure increase. Tuesday, July 03, 2007 ;/ sCANNED JUL 2 0 2007 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: THRU' Jim Regg P.I. Supervisor FROM: Randy Ruedrich DATE: July 11, 2003 · ~ Commissioner ~-',' :'t SUBJECT: Mechanical Integrity Tests John H. Spaulding Petroleum Inspector NON- CONFIDENTIAL BPX NGI 5 PBU Prudhoe Bay Field Packer Depth Pretest Initial 15 Min. 30 Min. J I '~.1 ~ I~.¥.~- I~ I~'~ I~°° I~°° I~°° I~°° I'~t~rv~'l 4 I WoIIJ NGI-05 Typetestj JTestpsiJ 1843 JCasingJ 1400 J 2500J 2450 J 2420 J P/F J P J P.T.D.J 1760140 Type Notes: Well J P.T.D. J Notes: Well J P.T.D. J Notes: P.T.D.I Notes: WellI P.T.D.I Notes: JType Inj. Type test IType,nj. J J T.V.D. J J Tubing J J J J,,-,terva, J I TypetestI J Test psi J ICasing I I I I P/F I I I Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS I NJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey D= Differential Temperature Test Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover O= Other (describe in notes) Test's Details I traveled to BPX's NGI pad to witness the MIT on well 5. Pat Lattner was the BPX rep. The pretest pressures were monitored and found to be stable, the standard annulus pressure test was performed and meets the AOGCC criteria for a successful MIT. M.I.T.'s performed: 1_ Number of Failures: 0 Attachments' Total Time during tests: 1.5 CC: MIT report form 5/12/00 L.G. 2003-071 I_M IT_PBU_NG 1-05is.xls 7/18/2003 ~CANNED AUG 0 ,~ 2003 STATE OF ALASKA ALASKA ,J~L AND GAS CONSERVATION COMIVlISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: I--lOperation Shutdown [--J Stimulate [] Plugging I~ Perforate [~ Pull Tubing []Alter Casing [] Repair Well E~Other 2. Name of Operator ARCO Alaska Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 450' SNL, 1039' EWL, SEC. 12, T11N, R14E, UM At top of productive interval 1371' NSL, 3040' EWL, SEC. 01, T11N, R14E, UM At effective depth 1490' NSL, 3207' EWL, SEC. 01, T11N, R14E, UM At total depth 1530' NSL, 3265' EWL, SEC. 01, T11N, R14E, UM Type of well: I--I Development I--) Exploratory [] Stratigraphic [~i] Service 6. Datum Elevation (DF or KB) 47' RKB 7. Unit or Property Name Prudhoe Bay Unit 8. Well Number NGI-05 9. Permit Number / Approval No. 76-14 399°087 10. APl Number 50-029-20196 11. Field and Pool Prudhoe Bay Field / Prudhoe Bay Pool 12. Present well condition summary Total depth: measured 9404 feet true vertical 8623 feet Effective depth: measured 9247 feet true vertical 8482 feet Casing Size Structural Conductor 81' 20" Surface 2672' 13-3/8" Intermediate 8371' 9-5/8" Production Liner 1290' 7" Fill at 9247' (10/92) Plugs (measured) Junk (measured) Length Cemented 240 sx Permafrost II 6450 sx Permafrost II 875 sx Class 'G' 300 sx Class 'G' MD TVD 81' 81' 2719' 2719' 8418' 7747' 8108'-9398' 7475'-8618' Perforation depth: measured true vertical 8807'-8817', 8820'-8876', 8891'-8966', 8981'-9042', 9047'-9182', 9211'-9231' 8092'-8101', 8103'-8153', 8166'-8232', 8246'-8300', 8304'-8325', 8450'-8468' Tubing (size, grade, and measured depth) 7-5/8" x 7", 29.7# / 26#, L-80 / NT-80 to 8038' Packers and SSSV (type and measured depth) 9-5/8" x 7" Baker 'SABL-3' packer at 7990'; 7" Camco BaI-O 'SVLN' at 2184' 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Prior to well operation: RECEIVED' Naslm Oil & Gas Cons. Commissior, Anchorage Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Subsequent to operation: 15. Attachments 116. Status of well classifications as: [~ Copies of Logs and Surveys run I r--] Oil [-] Gas [~ Suspended [] Daily Report of Well Operations 17. I hereby certify that the foregoing is true and correct to the best of my knowledge Terrie Hubble , ,, Title Technical Assistant III Prepared By Name/Number: Service Gas Injection Terrie Hubble, 564-4628 Form 10-404 Rev. 06/15/88 Submit In Duplicate'~lf~ Progress Report Facility NGI Well NGI-05 Rig Nabors 7ES Page 1 Date 16 June 99 Date/Time 03 Jun 99 04 Jun 99 05 jUn 99 06 Jun 99 07 Jun 99 15:00-16:00 16:00-20:00 20:00-04:00 04:00-06:00 06:00-06:15 06:15-06:45 06:45-07:30 07:30-08:00 08:00-11:30 11:30-12:00 12:00-13:30 13:30-15:00 15:00-18:00 18:00-21:30 21:30-23:00 23:00-00:00 00:00-00:30 00:30-02:00 02:00-04:00 04:00-05:00 05:00-06:00 06:00-09:30 09:30-10:30 10:30-11:00 11:00-12:00 12:00-13:30 13:30-14:00 14:00-15:00 15:00-15:15 15:15-15:45 15:45-16:00 16:00-17:00 17:00-17:30 17:30-18:00 18:00-00:00 00:00-06:00 06:00-07:00 07:00-07:30 07:30-08:00 08:00-08:30 08:30-09:45 09:45-10:30 10:30-11:00 11:00-12:00 12:00-12:30 12:30-14:30 14:30-20:30 20:30-21:00 21:00-22:30 22:30-03:00 03:00-04:00 04:00-04:30 04:30-06:00 06:00-06:30 Duration 1 hr 4 hr 8 hr 2hr 1/4 hr 1/2 hr 3/4 hr 1/2 hr 3-1/2 hr 1/2 ~hr 1-1/2 hr 1-1/2 hr 3 hr 3-1/2 hr 1-1/2 hr lhr 1/2 hr 1-1/2 hr 2 hr lhr lhr 3-1/2 hr lhr 1/2 hr 1 hr 1-1/2 hr 1/2 hr 1 hr 1/4 hr 1/2 hr 1/4 hr 1 hr 1/2 hr 1/2 hr 6hr 6 hr 1 hr 1/2 hr 1/2 hr 1/2 hr 1-1/4 hr 3/4 hr 1/2 hr 1 hr 1/2 hr 2 hr 6 hr 1/2 hr 1-1/2 hr 4-1/2 hr 1 hr 1/2 hr 1-1/2 hr 1/2 hr Activity Rigged down Drillfloor / Derrick Rig waited: Production facilities Rig moved 100.00 % Fill pits with Brine Fill pits with Brine (cont...) Held safety meeting Rigged down Hanger plug Tested Chicksan lines Reverse circulated at 7797.0 ft Installed Hanger plug Removed Xmas tree Rigged up BOP stack Tested BOP stack Retrieved Hanger plug Pulled Tubing on retrieval string to 7803.0 ft Circulated at 7803.0 ft Rigged down Fluid system Laid down 160.0 ft of Tubing Installed Emergency hang off assembly Rigged down BOP stack Installed Tubing head spool Installed Tubing head spool (cont...) Rigged up BOP stack Tested Seal assembly Rigged down BOP stack Rigged up Adapter spool Tested Seal assembly Rigged up BOP stack Installed BOP test plug assembly Tested BOP stack Rigged down BOP test plug assembly Removed Emergency hang off assembly Circulated at 7650.0 ft Rigged up Tubing handling equipment Laid down 2600.0 ft of Tubing Laid down Tubing of 4300.0 ft Laid down 7797.0 ft of Tubing (cont...) Rigged down Completion string handling equipment Removed Wear bushing Rigged up BOP test plug assembly Rigged up Top ram Tested Top ram Rigged down BOP test plug assembly Rigged up Wear bushing Serviced Top drive pipe handler Made up BHA no. 1 R.I.H. to 7785.0 ft Fished at 7785.0 ft Circulated at 7720.0 ft Pulled out of hole to 150.0 ft Pulled BHA Laid down fish Laid down fish Laid down fish Facility Date/Time 08 Jun 99 09 Jun 99 10 Jun 99 11 Jun 99 Progress Report NGI Well NGI-05 Page 2 Rig Nabors 7ES Date 16 June 99 06:30-08:00 08:00-12:00 12:00-13:00 13:00-13:30 13:30-14:00 14:00-20:30 20:30-22:30 22:30-02:00 02:00-02:45 02:45-03:30 03:30-06:00 06:30-08:00 08:00-11:00 11:00-12:00 12:00-13:00 13:00-15:30 15:30-16:00 16:00-17:30 17:30-21:00 21:00-21:30 21:30-22:00 22:00-22:30 22:30-00:00 00:00-03:00 03:00-05:30 05:30-06:00 06:00-10:30 10:30-12:30 12:30-13:00 13:00-14:30 14:30-16:00 16:00-17:30 17:30-06:00 06:00-07:30 07:30-10:30 10:30-11:00 11:00-13:30 13:30-15:00 15:00-16:00 16:00-17:00 17:00-18:00 18:00-19:00 19:00-04:00 04:00-06:00 06:00-07:00 07:00-09:00 09:00-11:00 11:00-14:30 14:30-16:00 16:00-18:00 18:00-19:30 19:30-20:00 20:00-21:00 21:00-22:00 Duration 1-1/2 hr 4 hr lhr 1/2 hr 1/2 hr 6-1/2 hr 2 hr 3-I/2 hr 3/4 hr 3/4 hr 2-1/2 hr 1-1/2 hr 3 hr 1 hr 1 hr 2-1/2 hr 1/2 hr 1-1/2 hr 3-1/2 hr 1/2 hr 1/2 hr 1/2 hr 1-1/2 hr 3 hr 2-1/2 hr 1/2 hr 4-1/2 hr 2 hr 1/2 hr 1-1/2 hr 1-1/2 hr 1-1/2 hr 12-1/2 hr 1-1/2 hr 3 hr 1/2 hr 2-1/2 hr 1-1/2 hr 1 hr 1 hr 1 hr 1 hr 9 hr 2 hr 1 hr 2 hr 2 hr 3-1/2 hr 1-1/2 hr 2 hr 1-1/2 hr 1/2 hr lhr 1 hr Activity Made up BHA no. 2 R.I.H. to 7000.0 ft Serviced Block line Serviced Top drive pipe handler R.I.H. to 7844.0 ft Milled Permanent packer at 7888.0 ft Circulated at 7888.0 ft Pulled out of hole to 200.0 ft Pulled BHA Made up BHA no. 3 R.I.H. to 6000.0 ft Circulated at 8100.0 ft Pulled out of hole to 309.0 ft Pulled BHA Made up BHA no. 4 R.I.H. to 8082.0 ft Fished at 8082.0 ft Circulated at 8082.0 ft Pulled out of hole to 305.0 ft Pulled BHA Laid down fish Pulled BHA Made up BHA no. 5 R.I.H. to 8144.0 ft Circulated at 8105.0 ft Pulled out of hole to 6750.0 ft Laid down 7800.0 ft of 4in OD drill pipe Pulled BHA Retrieved Bore protector Rigged up Top ram Tested Top ram Rigged up Tubing handling equipment Ran Tubing to 4900.0 ft (7-5/8in OD) Installed SCSSSV nipple assembly Ran Tubing to 7100.0 ft (7in OD) Held safety meeting Ran Tubing to 8038.0 ft (7-5/8in OD) Installed Hanger assembly Installed Accessories Installed Hanger plug Serviced Tubing handling equipment Held safety meeting Rigged down BOP stack Installed Xmas tree Retrieved Hanger plug Displace treatment Tested Tubing Rigged up Slickline unit Retrieved SCSSSV dummy pack off Conducted slickline operations on Slickline equipment - Tool run Installed SCSSSV plug Rigged down Lubricator Tested Tubing Tested Casing Facility Date/Time NGI 22:00-23:00 23:00-01:00 Progress Report Well NGI-05 Rig Nabors 7ES Page Date Duration 1 hr 2 hr Activity Rigged down Slickline unit Installed Hanger plug 3 16 June 99 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: [] Abandon [] Suspend [] Plugging []Time Extension [] Perforate [] Alter Casing [] Repair Well [] Pull Tubing [] Variance [] Other [] Change Approved Program [] Operation Shutdown [] Re-Enter Suspended Well [] Stimulate 21 Name of OPe'~'ator ...... ,~. Type' of well: 6. Datum 'El'evation (DF o~ KB)'" ARCO Alaska Inc. E~ Development 47' RKB ................... [--]Exploratory 7. u'ni{'or Pro'P~riy Name .... 3. Address F-iStratigraphic Prudhoe Bay Unit P.O. Box 196612, Anchorage, Alaska 99519-6612 [~Service ............. 4. Location °f'w'ell at surface 8. Well NUmber NGI-05 450' SNL, 1039' EWL, SEC. 12, T11N, R14E, UM 9. 'Permit Numl~er '" At top of productive interval 76-14 ..... 1371' NSL, 3040' EWL, SEC. 01, T11N, R14E, UM 101 APl Number At effective depth 50-029-20196 1490' NSL, 3207' EWL, SEC. 01, T11N, R14E, UM 11. Field and Pool At total depth Prudhoe Bay Field / Prudhoe Bay 1530' N .SL.., 3265'....EWL,. S.EC.. 01, T11..N.,..R14.E,....UM ............. Pool .......... 12. Present well condition summary Fill at 9247' (10/92) '~E CE Total depth: measured 9404 feet Plugs(measured) true vertical 8623 feet Effective depth: measured 9247 feet Junk (measured) bj~/~r' ? U ]999 true vertical 8482 feet Casing Length Size Cemented Structural Conductor 81' 20" 240 sx Permafrost II 81' 81' Surface 2672' 13-3/8" 6450 sx Permafrost II 2719' 2719' Intermediate 8371' 9-5/8" 875 sx Class 'G' 8418' 7747' Production Liner 1290' 7" 300 sx Class 'G' 8108' - 9398' 7475' - 8618' . Perforation depth: measured 8807' - 8817', 8820' - 8876', 8891' - 8966', 8981' - 9042', 9047' - 9182', 9211' - 9231' true vertical 8092' - 8101', 8103' - 8153', 8166' - 8232', 8246' - 8300', 8304' - 8325', 8450' - 8468' Tubing (size, grade, and measured depth) 7", 29#, L-80 NPCT at 7769', 5-1/2", 17#, L-80, NPCT 7771' - 7905', 4-1/2", 12.6#, L-80, NPCT tail 7905' - 8029' Packers and SSSV (type and measured depth) Baker SAB packer at 7892'; Otis RPB SSSV at 2193' ............... 13. Attachments [~ Description summary of proposal E~ Detailed operations program E~ BOP sketch ................... ............... ....... 14. EStimated date for commencing operation 15. Status of well classifications as: 16. if Pr0p'O~al was verbally approved ........................... E~Oil [~Gas E~ Suspended Service Gas Injection ...... Name of approver Date approved ........................ Contact Engineer Name/Number: Bill Isaacson, 564-5521 Prepared By Name/Number: Terrie Hubble, 564-4628 '~ 7. I' h'ereby certify that'the foregoing is trUe anc~ C'0rrect to th'e '~est"of mY ~n'~)~ledge Signed ~--------~'~--'~'"~*~ Title Senior Drilling Engineer Date Dan Stone , ,, Commission Use Only ......................... Conditions of APPrOval: Notify Co~mission'so representative may. witness I Appr°val ~o..,~ Plug integrity~ BOP Test / Location clearance .......... 0o¢ o~o~e6 Mechanical Integrity Test f Subsequent form required 10- Approve~ommission Original Slgne, a u~ Commissioner Date c~] FOrm l~l~ev_ 0~/i"5/~'''"' '88 Oavia W," Johnston Submit I~ Tri~)lJ;a't¢ ,,.l L hared !ervices Alaska a..) rilling BP Exploration / ARCO Alaska Inc. To: From: Subject: Reference: Blair Wondzell - AOGCC Date: May 13, 1999 William Isaacson NGI-05 Application for Sundry Permit - Rig Workover Operations APl #50-029-20196 The NGI-05 rig workover is currently scheduled for Nabors 7ES following the workover operations on well WGI-08. Pre-rig work for the workover is planned to begin May 25th and workover operations are estimated to begin around May 31 st. Objective NGI-05 has tubing x inner annulus communication, which appears to be the SSSV nipple. The balance line is leaking, and multiple attempts at sealing with various packing configurations have been unsuccessful. The Wells Group has done all they can do to mitigate and/or repair the annular communication problem on this well to bring the well into compliance with Operating Guidelines. Over the last several months the bleed frequency has increased to the point the well operates at the limit of our allowed guidelines. If this well is not worked over and the tubing x inner annulus communication repaired, we will be forced to shut the well in. Scope Pre-Rig Work: 1. Test the 9-5/8" mandrel packoff to 80% of the 9-5/8" 47# L-80 casing (casing was landed on slips) for 30 minutes. Test tubing hanger seals to 5000 psi for 30 minutes. 2. Bullhead 2% KCI water down tubing to perforations to load tubing. Liquid pack the 9-5/8" annulus by lubricating in diesel and bleeding of gas as required. (Tubing should be loaded with 2% KCI to avoid possible collapse of 7" tubing during 9-5/8" MIT). Pressure test the 9-5/8" annulus to 4000 psi for 30 minute test. (If annulus is leaking to tubing at SSSV, it may be necessary to set a plug in the tubing tail in order to get a good test on the 9-5/8"). 3. RU slickline. Pull wire-line retrievable SSSV from BaI-O SSSV nipple at 2193' MD. 4. Bullhead sized salt pill down to perforations to serve as lost circulation pill for upcoming workover operations. Follow the same procedure used to spot the salt pills on the WGI-1, 3, and 4 workovers. - 50 bbls of 10 ppg NaCI saturated hi-vis spacer - Sized salt pill in saturated NaCI brine ~12.0 ppg (volume as required) - 40 bbls of 10 ppg NaCI saturated hi-vis spacer - Displace sized salt pill with 9.4 ppg NaCI brine Slow pump rate as hi-vis spacer and salt pill hit the perforations and pump only as required to adequately place sized salt pill in perforations. Do not fracture formation. Shut down and allow salt pill to leak-off to formation and settle out, isolating perforations. $. RU slickline. Drift tubing for upcoming E-line work and tag top of sized salt pill. NGI-05 RWO Sundry 6. RU E-line. RIH and perforate 4-1/2" tubing tail at -7910' MD (1' at 4spf). These perforations will be needed to remove any trapped gas from behind tubing tail, which could otherwise be exposed while milling the packer. RIH and cut 5-1/2" tubing (chemical cutter) immediately above 9-5/8" packer at 7889' MD (this is 3' above the packer in the 5-1/2" pup on top of the packer). 7. RU and circulate annulus to 9.4 ppg NaCI brine by circulating down tubing and up annulus through the tubing cut. Continue to circulate until clean 9.4 ppg brine returns to surface. 8. Set a BPV in the tubing hanger and test to 500 psi. Secure the well. 9. Remove the well house and flowlines. If necessary, level the pad. Please provide total well preparation cost on the handover form. Rig 1. 2. 3. 4. Operations: MIRU Nabors 7ES. Pull BPV. Circulate well with 9.4 ppg brine and verify well is dead and stable. Set BPV. Nipple down tree. Nipple up and test BOPE. Pull BPV. Screw into tubing hanger. PU on completion assembly and pull hanger to floor. Circulate bottoms up to verify the well is dead. 5. POOH laying down the 7"x 5-1/2" completion through the tubing cut. After laying down the SSSV, hang off the completion string on storm packer and change out the tubing head and 9-5/8" pack-off. 6. RIH with overshot and fish remaining tubing stub and K-anchor from 9-5/8" packer. 7. PU packer milling assembly and RIH. Mill packer and push to top of liner. 8. PU fishing assembly and RIH to packer. Engage packer and POOH slowly with packer and tailpipe assembly. 9. PU 6" bit on cleanout assembly with 9-5/8" casing scrapper. RIH with bit to top of sized salt pill and casing scraper to liner top. POOH 10. If necessary, PU 9-5/8" RTTS and RIH to liner top. Set RTTS and test 9-5/8" casing to 4000 psi for 30 minutes. POOH LD DP. 11. Run new 7-5/8" L-80 STL IPC completion with new 9-5/8" x 7" production packer. The tubing tail of the new completion will tie into the 7" liner tie-back sleeve. 12. Displace annulus to 9.4 ppg brine with corrosion inhibitor and freeze protect annulus to -2200' MD. Set packer and test the tubing to 4000 psi for 30 minutes. Test annulus to 4000 psi for 30 minutes. 13. Nipple down the BOPE. Nipple up and test the tree to 5000 psi. 14. Secure the well and rig down and move off. 15. Post rig work will clean out the sized salt pill from across the perforations. Estimated Pre-rig Start Date: Estimated RWO Start Date: 05/25/99 05/31/99 William Isaacson Operations Drilling Engineer 564-5521 NGI-05 RWO Sundry NGI-05 Proposed Completion RKB = 47' Tree: 7-1/16" - 5M L-80 Wellhead: Gray Gen I Retro 13-5/8" x 5M psi I ' ' K. 7" 5M psi Gray Tubing Hanger with crossover pup to 7-5/8" STL tubing. I ' J. 7-5/8" 29# L-80, STL Tubing.to surface with two control lines strapped to tubing. i 1 ~ I. 7" Camco BAL-O SSSV Ported Landing Nipple with 5.937" seal bore ID set at -2200'. Equipped with crossover handling pups to crossover to 7-5/8" STL tubing. 1~-3/8", 72 #, MN-80, R'I'G ~ Iq. 7-5/8" 2~# !_-80, 811_ 'rubin~. , ,, ~ ~ 13. ~-$/8" x 7" Bakor '$-3' Production ~ackor. fiquippod with 10' handling pups abo¥o and Baker Tie Back Sleeve . F. 10'x 7" L-80 pup joint. i I II E. 6-5/8" Halliburton 'R' Landing Nipple with 5.625" selective seal bore (7" NSCT threads). Baker Liner Hanger ~ ~ ! I'~ D. 20' x 7" L-80 pup joint. ' I C. 6-5/8" Halliburton 'RN' Landing Nipple with 5.625" seal bore / 5.50" No-Go (7" NSCT threads). B. 10' x 7" 1_-80 pup ioint. ! i A. 5' x 7" L-80 cut-off pup with OD and ID of cut-off end beveled. Tubing tail spaced out into tie ~,! ' k back sleeve (7.50" ID). 9-5/8", 47 #, MN-80, BTC I i i I i I I I I 7", 29 #, MN-80, BTC Total Depth Date [:lev Blt Comments Prudhoe Bay Unit 5/13/99 WSI Proposed Completion WELL: NGI-05 APl NO: 50-029-20196 Shared Services Drilling I , NOI-L)3 Status Subject: NGI-05 Status Date: Sun, 16 May 1999 15:17:23 -0900 From: "PRB Problem Wells" <P 1041 ~mail.aai.arco.com> To: B lair_Wondzell~admin, state.ak.us 76 Hello Blair. This note is to inform you of the mechanical condition of well NGI-05. NGI-05 is currently injecting 140 MMCFD gas at 3500 psi. NGI-05 is scheduled for a RWO (starting around 6/15/99) to mitigate Tubing x 9-5/8" communication problems, install larger tubing and increase well injection rates. Notes on the well condition: - A Tubing x 9-5/8" leak occurs when the SSSV is pulled for replacement. Diagnostics indicate the balance line has parted, allowing gas to enter the Tubing x 9-5/8" annulus. Also, the sealing area for the SSSV packing elements is apparently damaged. This has resulted in the SSSV being replaced three times so far this year. Currently, the 9-5/8" pressure is stable at 1625 psi. - MIT's on the 9-5/8" cOnducted 3/3/97 and 3/16/97 indicate it is competent to liquid. - The 13-3/8" appears competent and does not track the 9-5/8" pressure. The rig is planning to pull the tubing and run new 7-5/8" plastic coated tubing. The Drilling Department is preparing the sundry application. Please call if you have any questions. Joe Anders Problem Well Specialist 659-5102 1 of 1 5/17/99 8'16 AM ~, Ke: N(51-05 Status Subject: Re: NGI-05 Status Date: Mon, 17 May 1999 12:11:01 -0900 From: "PRB Problem Wells" <P 1041 ~mail.aai.arco.com> To: Blair Wondzell <Blair_Wondzell~admin.state.ak.us> CC: "Jerry L Brady" <JLBRADY~mail.aai.arco.com> Hi Blair. I've copied Jerry Brady on this note - he is the Engineer who did the calculations on injectivity enhancement expected form the larger plastic coated tubing. Jerry, would you please address Blair's questions below. We are planning on running nipples with surface control lines into both wells. Thanks! Joe Blair Wondzell <Blair Wondzell@admin.state.ak.us> on 05/17/99 10:39:02 AM To: PRB Problem Wells/AAI/ARCO CC: Subject: Re: NGI-05 Sta~tus Hi Joe, Thanks for the info on WGI-8 and NGI-5. You've peaked my curosity as to why the need for the plastic coated tubing. Also, will you be running downhole safety valves or the nipples back in the wells? What rates do you expect into these wells after equiping them with the larger plastic coated tubing? Thanks for your help. Blair, 5/17/99. PRB Problem Wells wrote: > > Hello Blair. This note is to inform you of the mechanical condition of well > NGI-05. NGI-05 is currently injecting 140 Fk4CFD gas at 3500 psi. > > NGI-05 is scheduled for a RWO (starting around 6/15/99) to mitigate Tubing x > 9-5/8" communication problems, install larger tubing and increase well injection > rates. Notes on the well condition: > > - A Tubing x 9-5/8" leak occurs when the SSSV is pulled for replacement. > Diagnostics indicate the balance line has parted, allowing gas to enter the > Tubing x 9-5/8" annulus. Also, the sealing area for the SSSV packing elements is > apparently damaged. This has resulted in the SSSV being replaced three times SO > far this year. Currently, the 9-5/8" pressure is stable at 1625 psi. > > - MIT's on the 9-5/8"~ conducted 3/3/97 and 3/16/97 indicate it is competent to > liquid. > > - The 13-3/8" appears competent and does not track the 9-5/8" pressure. > > The rig is planning to pull the tubing and run new 7-5/8" plastic coated tubing. > The Drilling Department is preparing the sundry application. > > Please call if you have any questions. > > Joe Anders 1 of 2 5/17/99 4.04 pM Subject: WGI-08 Date: Sun, 16 May 1999 13:29:29 -0900 From: "PRB Problem Wells" <P 1041 ~mail.aai.arco.com> To: B lair_Wondzell~admin.state.ak.us Hello Blair. This note is to follow-up on our 5/13/99 phone conversation regardin9 well WGI-08. WGI-08 is scheduled for a RWO (startin9 around 5/20/99) to mitigate Tubin9 x 9-5/8" communication problems, install larger tubin9 and increase well injection rates. Notes on the well condition: - The 13-3/8,, is competent to liquid - it was successfully pressure tested to 2000 psi on 12/1/98. MIT's on the 9-5/8" conducted 5/15/99 and 6/13/97 indicate it is also competent to liquid. - A Tubin9 x 9-5/8" leak occurs when the SSSV is pulled for replacement. Diagnostics indicate the balance line has parted, allowin9 9as to enter the Tubin9 x 9-5/8" annulus. Also, the sealin9 area for the SSSV packin9 elements is apparently damaged. This has resulted in the SSSV bein9 replaced three times so far this year. Currently, the 9-5/8" pressure is stable at 700 psi, a 3000 psi difference between the Tubin9 and 9-5/8" pressures. - The 13-3/8,, pressure slowly tracks the 9-5/8" and the leak is thought to be doWnhole. We have done extensive troubleshootin9 and the wellhead appears to be competent. When bled down, the 13-3/8" will equalize with the 9-5/8" in 2-4 days. The ri9 is plannin9 to pull the tubing, replace the 9-5/8" hanger seals and run new larger plastic coated tubing. ' Please call if you have any questions. Joe Anders Problem Well Specialist 659-5102 1 ofl 5/17/99 4:03 PM ~_~._ ~I-ATE Of ALASKA ALASKA . AND GAS CONSERVATION C£ AISSION (..."/x~ REPORT UF SUNDRY WELL OPERATIONS 1. Operations performed: 2. Name of Operator ARCO Alaska, Inc. Operation shutdown Stimulate X , Plugging Perforate .... Pull tubing , Alter casing ,, Repair well Other 5. Type of Well Development Exploratory Stratigraphic Service 3. Address P.O. Box 100360, Anchorage, AK 99510-0360 RECEIVED AUG 2 0 1993 Alaska 0/i & Gas Cons. Commissi0[ Anchorage 6. Datum of elevation(DF or KI~)~ 47' RKB 7. Unit or Property Prudhoe Bay Unit 8. Well number NGI-5 feet 9. Permit number/approval number ~ 7~-~¢ 10. APl number 50 - 029-20196 4. Location of well at surface 450' FNL & 1039' FWL, Sec. 12, T11N, R14E, UM At top of productive interval 1373' FSL & 2239' FEL, Sec. 1, T11N, R14E, UM At effective depth 1487' FSL & 2078' FEL, Sec. 1, T11N, R14E, UM At total depth 1532' FSL & 2015' FWL, Sec. 1, T11N, R14E, UM 11. Field/Pool Prudhoe Bay Oil Pool 12. Present well condition summary Total depth: measured true vertical 9404 feet 8623 feet Plugs(measured) Fill @ 9247' MD (10/6/92) Effective depth: measured 9247 feet true vertical 8482 feet Junk(measured) Casing Length Size Cemented Measured depth True vertical depth Conductor 81' 20" 240 sx Permafrost II 81' 81' Surface 2672' 13-3/8" 6450 sx Permafrost II 2719' 2719' Production 8371' 9-5/8" 875 sx Class G 8418' 7747' Liner 1290' 7" 300 sx G 9398' 8618' Perforation depth: measured 8807-8817'; 8820-8876'; 8891-8966'; 8981-9042'; 9047-9182'; 9211-9231' true vertical 8092-8101 '; 8103-8153'; 8166-8232'; 8246-8300'; 8304-8325'; 8450-8468' Tubing (size, grade, and measured depth) 7", 29#, L-80, NPCT @ 7769' MD; 5-1/2", 17#, L-80, NPCT @ 7905' MD; 4-1/2", 12.6#, L-80, NPCT Tail @ 8029' MD Packers and SSSV (type and measured depth) Baker SAB packer @ 7892' MD; Otis RPB SSSV @ 2193' MD 13. Stimulation or cement squeeze summary Intervals treated(measured) See attached. Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation Representative Daily Average Production or Injection .Dsta, OiI-Bbl Gas-Md Water-Bbl Casing Pressure -- 47,000 .... -- 153,000 ./"~ -- -- Tubing Pressure 3414 3415 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of well classification as: Oil . Gas . Suspended ,,, Service Injector 17. I hereby.certify that the foregoing is true and correct to the best of my knowledge. Signed Title Sr. Area Operations Engineer Form 10-404 Rev 06/15/88 1023/4 KRF cc: SW, JWP Date ~/t (/~,~ SUBMIT IN DUPLICATE ~%~, NGI-5 STIMULATION TREATMENT DESCRIPTION OF WORK COMPLETED 7/22/93: RIH & tagged asphaltenes at 7857' MD. 7/24/93: MIRU CT & PT equipment. Loaded wellbore w/inhibited Seawater, then RIH w/CT & reciprocated an acid stimulation across the perforation intervals at: 8807- 8817' MD (Z4) 8820 - 8876' MD (Z4) 8891 - 8966' MD (Z3) 8981 - 9042' MD (Z2) 9047 - 9182' MD (Z2) 9211 - 9231' MD (Z1) Ref. Log: BHCS 3/22/76. Pumped: a) 59 bbls 75% Diesel/25% Xylene @ 2.0 bpm, followed by b) Shutdown. RIH w/CT & tagged bottom at 9258' MD, then resumed pumping: c) 245 bbls 75% Diesel/25% Xylene @ 2.3 bpm, followed by d) 263 bbls 15% HCI, followed by e) 20 bbls Meth Water displacement, followed by f) Shutdown. POOH w/CT while pumping 1200 bbls Seawater overflush down CT backside. Rigged down. Returned well to gas injection & obtained a valid injection rate. REEEIVED A U6 0 Alas~ Oil & Gas Cons. Commission Anchorage ~_ STATE OF ALASKA ALASKA . AND GAS CONSERVATION C¢-~ /IISS~I~ I {~ I N A L -~ REPORT (JF SUNDRY WELL OPI=HATIONS 1. Operations performed: Operation shutdown Stimulate X Plugging Pull tubing Alter casing Repair well Perforate Other 2. Name of Operator ARCO Alaska, Inc. 3. Address P.O. Box 100360, Anchorage, AK 99510-0360 4. Location of well at surface 450' FNL & 1039' FWL, Sec. 12, T11N, R14E, UM At top of productive interval 1373' FSL & 2239' FEL, Sec. 1, T11N, R14E, UM At effective depth 1487' FSL & 2078' FEL, Sec. 1, T11N, R14E, UM At total depth 1532' FSL & 2015' FWL, Sec. 1, T11N, R14E, UM 12. Present well condition summary Total depth' 5. Type of Well Development Exploratory . Stratigraphic Service X RECEIVED N 0V - 1992 Alaska Oil & Gas Cons. (~0mmiSSi0~ ~.nCh0rage measured 9404 feet true vertical 8623 feet 6. Datum of elevation(DF or KB) 47' RKB feet 7. Unit or Property Prudhoe Bay Unit 8. Well number NGI-5 9. Permit number/approval number 7~-14/92-235 10. APl number 50 - 029-20196 11. Field/Pool Prudhoe Bay Oil Pool Plugs(measured) Fill @ 9247' MD (10/6/92) Effective depth: measured 9247 feet', true vertical 8482 feet Junk(measured) Casing Length Size Cemented Measured depth True vertical depth Conductor 81' 20" 240 sx Permafrost II 81' 81' Surface 2672' 13-3/8" 6450 sx Permafrost II 2719' 2719' Production 8371' 9-5/8" 875 sx Class G 8418' 7747' Liner 1290' 7" 300 sx G 9398' 8618' Perforation depth: measured 8807-8817'; 8820-8876'; 8891-8966'; 8981-9042'; 9047-9182'; 9211-9231' true vertical 8092-8101 '; 8103-8153'; 8166-8232'; 8246-8300'; 8304-8325'; 8450-8468' Tubing (size, grade, and measured depth) 7", 29#, L-80, NPCT @ 7769' MD; 5-1/2", 17#, L-80, NPCT @ 7892' MD; 4-1/2", 12.6~, L-80, NPCT Tail @ 8029' MD Packers and SSSV (type and measured depth) Baker SAB packer @ 7892' MD; Otis RPB SSSV @ 2193' MD 13. Stimulation or cement squeeze summary Intervals treated(measured) See attached. Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation Representative Daily Average Production or Iniection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure -- 105,000 .... -- 180,000 /~ -- -- Tubing Pressure 3637 WHIP 3636 WHIP 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of well classification as: Oil Gas ,. , Suspended ..... Service Injector 17. ! hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Sr. Area Operations Engineer Form 10-404 Rev 06/15/88 914/12 LW CC: SW, JWP Date SUBMIT IN DUPLICATE NGI-05 STIMULATION TREATMENT DESCRIPTION OF WORK COMPLETED 10/2/92: RIH & tagged asphaltenes at 7866' MD. 10/4/92: MIRU CT & PT equipment to 4500 psi. Loaded wellbore w/inhibited seawater, then RIH w/CT & reciprocated an acid stimulation across the perforation intervals at: 8807 - 8817' MD (Z4) 8820 - 8876' MD (Z4) 8891 - 8966' MD (Z3) 8981 - 9042' MD (Z2) 9047 - 9182' MD (Z2) 9211 9231' MD (Z1) Ref. Log: BHCS 3/22/76. Pumped 100 bbls 75% Diesel/25% Xylene @ 2 bpm, followed by Shutdown for 30 minute soak. Resumed pumping Seawater @ 10 bpm down CT backside, while pumping Seawater @ 3.5 bpm down CT, to jet fill from 8150' down to hard bottom at 9252' MD. All organic fill was injected into the formation. Switched back to pumping 232 bbls 75% Diesel/25% Xylene @ 2 bpm, down CT, while continuing to pump Seawater down CT backside @ 2 bpm. Switched to pumping 193 bbls 15% HCI @ 3 bpm, down CT, while continuing Seawater down backside @ 1 bpm, then pumped 100 bbls 1% NH4CI Freshwater down CT, followed by 213 bbls 13% HCI - 1.5% HF, followed by 476 bbls 1% NH4CI Freshwater, followed by Shutdown. POOH w/CT. Rigged down. 10/6/92: RIH & tagged bottom at 9247' MD. Returned well to gas injection & obtained a valid injection rate. NOV - Alask~ Oil & Gas Cons. Anch0r~ge ~ IA I1::: OF ALASKA ALASKA ~' AND GAS CONSERVATION CC ..... fiSSION APPLICA, FOR SUNDRY AP,--ROVALS 1. Type of Request: Abandon Suspend Operation shutdown Re-enter suspended well Alter casing Repair well Plugging Time extension Stimulate X Change approved program Pull tubing Variance Perfor.~te Other , , 2. Name of Operator ARCO Alaska, Inc. 3. Address P.O. Box 100360, Anchorage, AK 99510-0360 5. Type of Well Development Exploratory Stratigraphic Service 4. Location of well at surface 450' FNL & 1039' FWL, Sec. 12, T11N, R14E, UM At top of productive interval 1373' FSL & 2239' FEL, Sec. 1, T11N, R14E, UM At effective depth 1487' FSL & 2078' FEL, Sec. 1, T11N, R14E, UM At total depth RE£EIV£D SEP 1 199 Alaska 0il & Gas Cons. C, omm'tss~O~ 1532' FSL, & 2015' FWL, Sec. 1, T11N, R14E, UM 'Anchorage 6. Datum of elevation(DF or KB) 47"RKB 7. Unit or Property Prudhoe Bay Unit 8. Well number NGI-5 9. Permit number 76-14 10. APl number 50 - 029-20196 11. Field/Pool Prudhoe Bay Oil Pool feet 12. Present well condition summary Total depth: measured true vertical 9404 feet Plugs(measured) 8623 feet Effective depth: measured 9313 feet true vertical 8542 feet Junk(measured) Casing Length Size Cemented Measured depth True vertical depth Conductor 81' 20" 240 sx Permafrost II 81' 81' Su dace 2672' 13-3/8" 6450 sx Permafrost II 2719' 2719' Production 8371' 9-5/8" 875 sx Class G 8418' 7747' Liner 1290' 7" 300 sx G 9398' 8618' Perforation depth: measured 8807-8817'; 8820-8876'; 8891-8966'; 8981-9042'; 9047-9182'; 9211-9231' true vertical 8092-8101'; 8103-8153'; 8166-8232'; 8246-8300'; 8304-8-325'; 8450-8468' Tubing (size, grade, and measured depth) 7", 29#, L-80, NPCT@ 7769' MD; 5-1/2", 17#, L-80, NPCT @ 7892' MD; 4-1/2", 12.6#, L-80, NPCT Tail @ 8029' MD Packers and SSSV (type and measured depth) Baker SAB packer @ 7892' MD; Otis RPB SSSV @ 2193' MD 13. Attachments Description summary of proposal X Detailed operations program BOP sketch X 14. Estimated date for commencing operation September 1992 16. If proposal was verbally approved Name of approver Date approved Service Injector 7. I herelDy certify that the foregoing is true and correct to the best of my knowledge. SignedX~ /__._,. ~~~_.~ Title Sr. Area Operations Engineer FOR COMMIRSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity BOP Test Location clearance Mechanical Integrity Test Subsequent form required 10- /-/'0~ . Original Signed By Approved by orderof the Commissioner David W. Johnston 15. Status of well classification as: Oil Gas Suspended Date ?.,~ ~///:~ -~..~ Form 10-403 Rev 06/15/88 891/11 LW cc: SW, JWP JApproval No. ¥77' -,P :~,-~ Com~'i'ssioner Date SUBMIT IN TRIPLICATE_'~,-- NGI-5 STIMULATION This stimulation is to increase its injectivity index by establishing effective formation communication by removing near wellbore damage. Procedures will be accomplished as follows: , Load well with filtered seawater. R/U slickline, pull SSSV, tag PBTD. , FCO and wash well's perforations with seawater and 75% diesel/25% xylene using CTU. 3. Proceed with stimulation in three stages as follows Stage-1 a. 50 Bbls of 75% diesel/25% Xylene b. 75 Bbls of 15% HCL with additives c. 100 Bbls of 13% HCL/1.5% HF with additives d. 100 Bbls of 1% NH4CL with additives e. 15 Bbls diverter solution f. 30 Bbls of 1% NH4CL water w/ 65% quality foam g. 10 Bbls of 1% NH4CL water spacer Stage-2 - Repeat step a - g Stage-3 - Repeat step a - c - Displace acid with 400 Bbls of 1% NH4CL with additives 4. Return well to NGI service and test. s E P t 1 1992 Alaska Oil & Gas Cons, GommisS'~on Anchora(Io 4 3 2 COILED TUBING UNIT BOP EOUI PHEN~ 1. 5000 PSI 7" WELLHEAD CONNECTOR IrLAhO£ 2. 5000 PSI 4 1/15" PIPE RAMS 3. 5000 PSI 4 1/6" HYDRAULIC SLIPS 4. 5000 PSI 4 1/6" SHEAR RAMS 5. 5000 PSI 4 1/6" BLIND RAJAS 6. 5000 PSI 4 1/16" STUFFING BOX a Oil .& Gas Cons. 'Anchorago __N ! REL. ] ~ BOP, E.O.U,] PH£NT 1. 5000 PSI ?" WELLHblD CONN£C10R rLANG£ 2. 5000 PSI WIRELIN[ RAIDS (VARIABLE SI2[) .3. 5000 PSI 4 1/6" LUBRICATOR 4. 5000 PSI 4 1/6" IrLOW TUBE PACK-OFF F:' !:-' C,- f'.:. 'Y T:-.' i::' N i'.,i K -,," T · '"". 'T' f'~ .... '; ~' '"' ':'" . . 'T' F;: ~':'.", ~,,I .':..': :~,: ,".::: ::::', 4. '.? '.'::' ~ ,':':', F:' i::' !:.:.: f'l *',! F' I".". ...................... ~J~ ............................................................... T'., T F! ","' !:;: T T:'.. t ! T T f'", ~'.., I i:;; t:; i::' !'T I:;: t::. i',t C FiE F;: !::' C. !::' T '-'J .,.".:'f'.'., iq Y R Alaska Oil & Gas Cons. Commission ARCO Alaska, Inc. Prudhoe Bay Engineering Post Office Box 100360 Anchorage, Alaska 99510-0360 TeJephone 907 263 4248 Donald F. Scheve Operations Engineering Manager June 8, 1988 C. V. "Chat" Chatterton Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: DS NGI-5 Approval No. 8-218 Dear Mr. Chatterton: Attached is the Report of Sundry Well Operations detailing work per- formed on the above-referenced well. Very truly yours, D. F. Scheve DFS/JMV/jp Attachment cc: Standard Alaska Production Company J. Gruber, AT0-1478 Pi(DS NGI-5)W1-3 ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany AR3B--6'~32-C STATE OF ALASKA ALASK,, ,_)IL AND GAS CONSERVATION COMM,.,,51ON REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown ~ Stimulate ~ Plugging i-i Perforate -" Pull tubing Alter Casing ~ Other ~ 2. Name of OPerator ARCO Ala. ska, Inc, 3. Address P.O. Box 100360, Anchoras;e, AK 99510 4. Location of well at surface 450' FNL & 1039' FWL, Sec. 12, TllN, R14E, UM At top of productive interval 1373' FSL & 2239' FEL, Sec. At effective depth 1487' FSL & 2078' FEL, Sec. At total depth 1532' FSL & 2015' FWL, Sec. 1, TllN, R14E, UM 1, TllN, R14E, UM 1, TllN, R14E, UM 5. Datum elevation (DF or KB) 47 ' RKB Feet 6. Unit or Property name Prudhoe Bay Unit 7. Well number NGI-5 (33-1-11-14) 8. Approvalnumber 8-218 9. APInumber 50-- 029-20196 10. Pool Sadlerochit 11. Present well condition summary Total depth: measured 9404 feet true vertical 8623 feet Effective depth: measured 9313 feet true vertical 8542 feet Casing Length Size Conductor 81 ' 20" Surface 2672 ' 13-3/8" Production 8371 ' 9-5/8" Liner 1290' 7" Plugs (measured) Junk (measUred) Cemented Measured depth 240 sx Permafrost II 6450 sx Permafrost II 1st Stg: 750 sx "G" 2nd Stg: 125 sx "G" 300 sx "G" 81' 2719' 8418' 9398' True Vertical depth 81' 2719' 7748' 8618' Perforation depth: measured true vertical 8092-8101 '; 8304-8525 '; Tubing (size, grade and measured depth) 8807-8817'; 8820-8876'; 8891-8966'; 8981-9042'; 9047-9182'; 9211-9231' Packers and SSSV (type and measured depth) Baker SAB packer @ 7892' MD/Otis RQ SSSV @ 2193' MD 12. Stimulation or cement squeeze summary 8103-8153'; 8166-8232'; 8246-8300'; 8450-8468' 7", 29#, L-80, 7769' MD' 5½", 17#, L-80, @ 7892' MD' RECEIVED Intervals treated (measured) See attached Treatment description including volumes used and final pressure JUN g 1988 Alaska 011 & Gas Cons. Commission Anchorage 13. Prior to well operation Subsequent to operation Representative Daily Average Production or Injection Data Oi"Bb' M~:~"f Water-Bb, Casing Pressure -- 196 .... 212 Tubing Pressure 3900 REF 3900 REF 14. Attachments Daily Report of Well Operations Copies of Logs and Surveys Run ,Z; 15. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~..~. JT~ Form 10-404 Rev. 12-1-85 WELL S 2 / 61 Title Operations. Enginee!ing Manager J. M. Vitucci, 265-6358 Date ~//'¢"¢'~ Submit in Duplicate NGI 5 12% HCI-3% HF MATRIX ACID STIMULATION ARCO Alaska Inc. performed the following mud acid matrix acid stimulation on Well NGI 5 on 5/20/88: 1. MIRU slickline unit. 2. GIH w/gauge ring and performed a tag run to PBTD to ensure all perforations were clear of fill. POH and RD. 3. MI and RU pump trucks, transports, and N2 unit. 4. Stimulated the well as follows: A. 800 gals of xylene nitrified w/1000 SCF N2/bbl B. 3000 gals of 12% HCI w/additives C. 3000 gals of 12% HCI-3% HF w/additives D. 3000 gals of 2% NH4Cl water E. 150 bbls of foam consisting of 55 bbls of 2% NH4CI water gelled w/HEC polymer and 2500 SCF N2/bbl water F. 800 gals of xylene nitrified w/1000 SCF N2/bbl G 1500 gals of 12% HCl w/additives H. 3000 gals of 12% HCl-3% HF w/additives I. 3000 gals of 2% NH4CI water J. 150 bbls of foam consisting of 55 bbls of 2% NH4CI water gelled w/HEC polymer and 2500 SCF N2/bbl water K. 1200 gals of xylene nitrified w/1000 SCF N2/bbl L. 2500 gals of 12% HCl w/additives M. 5000 gals of 12% HCl-3% HF w/additives N. 150 bbls of 50/50 methanol/water 5. RD and released equipment. Returned well to injection immediately. 6. Tested well for new injection capacity. £E£1VED JUN 9 198 Alasl~ Oil & Gas Cons, commission D/:, TF' ' 1.'.,..-:'l--c,c-x~Ccr. ARf~.FJ ri.(~?-Fr-l~ NFil ':' F'TFJAI F' I '..- ~ :'- , . · ~"t.~.',F. .'"'-.','T!-.;N AND F~.'l:"'rlllTi'"J 'T'N!z' r?:'TTAI~.NF'D f":F!F'¥' A:? Fi'tz'I~.FTF'T I-IF DA'FA E' F: ',-: F~ I V F:' 9 i~-: Y ......................................................... N~hVF ~':; ,;9 ' !' ,:'-.' F DAY ' Alaska Oil a Gas Cons. Commission or. · i i F;.' F-:' F:' F' F;: I::' i'41-.' F" AI:;:tT. 0 f".A.?I:.'T) Ml"il F:' F:'T?4AI I::' F' f'; f: Y A 1"f71- t '5=)9 ~F'F'F;.'OVF:!) .... - ..... _.~.(~"/ , T) ]' ~'r r-;: T R I i'r T n ~ , ~: CENTF~'.~/.. F"I:! .FR ~ f': Fl I: V !-? (1 N '0 ?,, M :,": F~TFNIS'7[f.']N IC×F'J.. I]RATTON -$': H 0 [.:~ .1' I.. r.:, I..i T Il .I .. :[ F'R klgl.. I... F R:,* !) STATE TEXACO .' .!... ARCO Alaska, Inc Prudhoe Bay .~,neering Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4248 Donald F. Scheve Operations Engineering Manager March 23, 1988 C. V. "Chat" Chatterton Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: NGI-4 and Permit Nos. 75-69, 76-14 Dear Mr. Chatterton: Attached are the Application for Sundry Approvals detailing work to be performed on the above-referenced wells. Very truly yours, D. F. Scheve DFS/JMV/jp Attachment cc: Standard Alaska Production Company J. Gruber, ATO-1478 P1 (NGI-4) W1-3 P1 (NGI-5)W1-3 RECEIVED Mastm 0il a Bas Cons. Gommlssto~ Anchorage WELLS2/60 ARCO Alaska, Inc. is a Subsidiary of AllanticRIchfleldCompany AR3B--6132-C STATE OF ALASKA ~' ALAS OIL AND GAS CONSERVATION CPM,. ..~SION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon ~ Suspend ~ Operation Shutdown ~ Re-enter suspended well ~ Alter casing i_] Time extension [] Change approved program [] Plugging [] Stimulate '~, Pull tubing [] Amend order [] Perforate C Other [] 2. Name of Operator 5. Datum elevation (DF or KB) ARCO Alaska~ Inc. 3. Address P.O. Box 100360, Anchorage, AK 99510 4. Location of well at surface 450' FNL & 1039' FWL, Sec. 12, TllN, R14E, UM At top of productive interval 1373' FSL & 2239' FEL, Sec. 1, TllN, R14E, UM At effective depth 1487' FSL & 2078' FEL, Sec. 1, TllN, R14E, UM At total depth 1532' FSL & 2015' FWL, Sec. 1, TllN, R14E, UM 11. Present well condition summary Total depth: measured true vertical 9404 feet 8623 feet 47' RKB 6. Unit or Property name Prudhoe Bay Unit Plugs (measured) 7. Well number NGI-5 (33-1-11-14) 8. Permit number 76-14 9. APl number 50-- 029-20196 10. Pool Sadlerochit RECEIVED feet Effective depth: measured 9313 true vertical 8468 Casing Length Size Conductor 80' 20" Surface 2672 ' 13-3/8" Production 8371 ' 9-5/8" Liner 290 ' 7" feet feet Junk(measured) Naska 0il & Gas Cons. Commissior,: Cemented Measured depth Anch0ragl, rue Vertical depth 240 sx Permafrost II 99' 99' 6450 sx Permafrost II 2719' 2719' 1st Stg: 750 sx "G" 8418' 7748' 2nd Stg: 125 sx "G" 300 sx "G" 8108-9398' 7475-8611 Perforation depth: measured true vertical 8807-8817'; 8820-8876'; 8891-8966'; 8981-9042'; 9047-9182'; 9211-9231' 8304-8525 ' Tubing (size, grade and measured depth) ; 8450-8468' 7", 29#, 7769' MD' 5½", 17#, L-80, 7769-7892' MD' Packers and SSSV (type and measured depth) 4½", 12.5#, L-80, 7892-8029' MD Baker SAB packer @ 7892' MD/Otis RQ SSSV @ 2193' MD 12.Attachments Description summary of proposal [] Detailed operations program ~ 8092-8101'; 8103-8153'; 8166-8232'; 8246-8300'; BOP sketch 13. Estimated date for commencing operation February 1988 14. If proposal was verbally approved Subsequent Work 1Reported Name of approver Form No. ,/g;' V~¢ Dated [_~_/7~7,¢~ Date approved 15. I hereby/c)ertify;// ~////~that-the f. qreg_oing is true and correct to the best of my knowledge Signed ~ji~,/Z:::~-/.¢ ~,/~.~¢,,~/.~ Title O perat ions Engineering Manager Date Conditions of approval Commission Use Only Notify commission, so representative may witness I Approval No. ~ Plug integrity ~ BOP Test ~ Location clearanceI ~,~/~ Approved by ORIGINAL SIGNED BY LONNIE C. SMITH Approved Copy Returned Commissioner Form 10-403 Rev 12-1-85 WELLS2/61 J. M. Vitucci by order of the commission Date Submit in triplicate NGI 4 AND NGI 5 12% HCl-3% HF MATRIX ACID STIMULATION ARCO Alaska Inc, proposes to perform the following mud acid matrix acid stimulation on Wells NGI 4 and NGI 5: 1. MIRU slickline unit. 2. GIH w/gauge ring and perform a tag run to PBTD to ensure all perforations are clear of fill. POH and RD. 3. MI and RU pump trucks, transports, and N2 unit. 4. Stimulate the well as follows: A. 800 gals of xylene nitrified w/1000 SCF N2/bbl B. 3000 gals of 12% HCI w/additives C. 3000 gals of 12% HCI-3% HF w/additives D. 3000 gals of 2% NH4CI water E. 150 bbls of foam consisting of 55 bbls of 2% NH4CI water gelled w/HEC polymer and 2500 SCF N2/bbl water 800 gals of xylene nitrified w/1000 SCF N2/bbl G 1500 gals of 12% HCl w/additives H. 3000 gals of 12% HCl-3% HF w/additives I. 3000 gals of 2% NH4CI water J. 150 bbls of foam consisting of 55 bbls of 2% NH4CI water gelled w/HEC polymer and 2500 SCF N2/bbl water K. 1200 gals of xylene nitrified w/1000 SCF N2/bbl L. 2500 gals of 12% HCl w/additives M. 5000 gals of 12% HCI-3% HF w/additives N. 150 bbls of 50/50 methanol/water 5. RD and release equipment. Return well to injection immediately. 6. Test well for new injection capacity. RECEIVED STATE OF ALASKA ALASKA O~'L AND GAS CONSERVATION CUMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well Gas Injection OIL [] GAS ~' SUSPENDED [] ABANDONED [] SERVICE Operator 7. Permit Number 2. Name of ARCO Alaska, Inc. 76-14 3. Address 8. APl Number P.O. Box 100360, Anchorage, Alaska 99510 50- 029-20196 4. Location of well at surface 9. Unit or Lease Name 450'FNL & 1039'FWL, Sec. 12, TllN, R15E, UM Prudhoe Bay Unit At Top Producing Interval 10. Well Number 1373'FSL & 2239'FEL, Sec. 1, TllN, R14E, UM NGI-5 (33-1-11-14) At Total Depth 11. Field and Pool 1532'FSL & 2015'FEL, Sec. 1, TllN, R14E, UM Prudhoe Bay Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. Prudhoe Bay Oil Pool 47' RKBI ADL 28302 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. I 15. Water Depth, if offshore 16. No. of Completions 03/2/76 03/21/76 4/6/76I N/A feet MSL Single 17. Total Depth (MD+TVD) 18. Plug Back Depth(MD+TVD) 19. Directional Survey 20. Depth where SSSV set I 21. Thickness of Permafrost 9404'MD, 8623'TVD 9313'MD, 8542~TVD YES E~LX NO [] 2193 feet MDI 1900' (Approx.) 22. Type Electric or Other Logs Run DIL/Sonic~ GR~ FDC/CNL~ FDL/CBL and GR/CCL 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~ Vetco H-40 Surf 81' 32" 240 sx Permafrost II C: tt 13-3/8" 72# Butt MN-80 Surf 2718' 17~" 6450 sx Permafrost II :mt 9-5/8" 47# Butt MN-80 Surf 8418' 12~" 750 sx Class G Cmt 2nd Stage w/125 sx Cla~s G Cmt 7" 29~A MN-80 8108' 9398' 300 sx Class G Cmt 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) 8807-8817 ', 8820-8876 ', 8891-8966 ', 8981-9042', 7" 8029' 7892' 9047-9182', 9211-9231'MD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED 8092-8101', 8103-8153' , 8166-8232' , 8246-8300' , N/A 8304-8425 ' , 8450-8468'TVD 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) I 10/17/77 I Gas Injection Well Date of Test Hours Tested PRODUCTION FOR !OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO 11/30/~t6 24 TEST PERIOD I~ __ 159.257 ...... Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (cDr'r) Press. 3699 -- 24-HOUR RATE ~ __ 159,257 .... 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. AUG 2 6 1987 'Alask~ 0ii & Gas Cons. 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 gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. -.. ~ .~ :.. ' Top Sadlerochit 8802' 8088' · . Base Sadlerochit 9294' 8525' · · · _? ; ' ' i ,.~,? f~ : ~ ' ~ " " ' · · · ; , ,, 31. LIST OF ATTACHMENTS . , 32. I hereby certify that the foregOing is true and Correct to the best of my knoWledge Signed ' Title Oper. Engr. Mgr. Date /-//~:~ ~ ... INSTRUCTIONS .. General: This form is designed for submitting a complete and correct well completion report a~d' I°g 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 well should show the details of any multiple stage cement- [r~g and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In~ jectio, n, Gas Injection, Shut~in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 ~-~--' STATE OF ALASKA ~'~ ALt. ,,. ,)IL AND GAS CONSERVATION COiVlN.._.SION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown [] Stimulate [] Plugging [] Perforate [] Pull tubing [] Alter Casing [] Other [] 2. Name of Operator ARCO Alaska: Tnt 3. Address Post Office Box 100360, Anchoraqe, AK 99510 4. Location of well at surface 450'FNL & 1039'FNL, Sec. 12 T11N R14E UM At top of productive interval ' ' ' 1373'FSL & 2239'FEL, Sec. 1, T11N, R14E, UM At effective depth 1487'FSL & 2078'FEL, Sec. 1, T11N, R14E, UM At total depth 1532'FSL & 2015'FEL~ Sec. 1~ T11N, R14E, UM 11. Present well condition summary Total depth: measured 9404 feet true vertical 8623 feet 5. Datum elevation (DF or KB) 47' RKB 6. Unit or Property name Prudhoe Bay Unit 7. Well number NGI-5 (33-1-11-14) Effective depth: measured 9231 feet true vertical 8468 feet 8. Approval number 556 9. APl number 50-- 10. Pool Sadlerochit Plugs (measured) None Junk(measured) 9231' - Fill Casing Length Size Conductor 74' 20" Surface 2694' 13-3/8" Intermediate 8393' 9-5/8" Liner 290' 7" Cemented Measured depth 240 sx Permafrost II 6450 sx Permafrost II 1st Stg: 750 sx "G" 2nd Stg: 125 sx "G" 300 sx "G" 99' 2719' 8418' 8108'-9398' Feet True Vertical depth 99' 2719' 7748' 7475'-8618 Perforation depth: measured 8807-8817' 8820-8876' 8891-8966' 8981-9042' 9047-9182' 9211-9231' true vertical 8092-8101', 8103-8153', 8166-8232', 8246-8300', 8304-8425', 8450-8468' Tubing (size, grade and measured depth) 7", 29#, ABMOD, Brd to 7769'MD 5½" 17# L-80 BTC 7769'-7892 'MD Packers and SSSV (type and measured depth) 4½", 12.5#, L-80, 7892'-8029'MD 9-5/8" x 7" SAB Packer @ 7892'MD/Otis RB Ball Valve (a 2193'MD 12. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 13. Prior to well operation Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure 11/20/86 -- 131,361 ...... Subsequent to operation11/30/86 -- 159,257 --- Tubing Pressure 3884 3699 14. Attachments Daily Report of Well Operations ~ Copies of Logs and Surveys Run [] 15. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~ ,.~¢;~'/~.~~ Form 10-404 Rev. 12-1-85 STAT17/NGI-5 Title Operations Engineering Manager M. R. Olson (265-6810) Date Submit in Duplicate NGI-5 Daily Report of Well Operations Add Perfs 11/23/86 PT rams/hardline. OK. Pump in methanol, water, methanol/water. PT. OK. RIGH w/3-3/8" gun #1, (10', 2', 10'), 4 SPF, 60° phasing. Tagged bottom @ 9232'. Shoot 9142' to 9152', 9140' to 9142', 9130' to 9140'. POH - bottom 10' did not fire (9142' - 9152'). 11/24/86 PT. OK. RIH w/3-3/8" gun #2 (8', 10'), 4 SPF, 90° phasing. Shoot 9100 to 9110', 9092' to 9100'. POH - all shots fired. PT. OK. RIH w/3-3/8" gun #3 (20'), 4 SPF, 60° phasing. Shoot 9072 to 9092'. POH - all shots fired. PT. OK. RIH w/3-3/8" gun #4 (10', 1', 10'), 4 SPF, 90© phasing. Shoot 9032 to 9042', 9031' to 9032', 9021' to 9031'. POH - all shots fired. PT. OK. RIH w/3-3/8" gun #5 (1', 10', 10'), 4 SPF, 90© phasing. Shoot 9011 to 9021', 8926' to 8936', 8840' to 8841'. POH - all shots fired. PT. OK. RIH w/3-3/8" gun #6 (10', 5'), 4 SPF, 90° phasing. Shoot 8921 to 8926', 9142' to 9152'. POH - all shots fired. PT. OK. RIH w/3-3/8" gun #7 (10'), 4 SPF, 60©, 120°, 240©, 360© phasing. Shoot 8820 to 8840'. POH - all shots fired. . ~ .' ARCO Alaska, Inc. I.'-'.0, Box t~)0360'" Anchorage, Alaska DATE: Hay t;3, t987 REFERENCE: ARCO Cased Hole Final 2-6 tt-?-86 F'erf. Record '. Run 3-t 2 t t-2t-86 {;;ET Run 6-t2 5-3-87 Perf. Record '" Run 7-7 3-28-87 Tubing CoLLar Log Run ?--? ~-8-86 F'erf, Record Run ~3-98 ~-~4-86 CH CNL EpithermaL Run ~3-78 ~-~4-86 CH CNL Thermal Run ~3-78 ~-~4-86 CH DIL Run ~3-78 ~2-26-86 CH DIL " Run ~3-78 ~2-26-85 CH CNL Thermal Run ~ 3-?8 ~ 2-26-86 CH CNL Ep i therma L Run .. ~ 4-3~ ::'~ 3-29-87 Tub i ng Co [ Jar Log Run Ngi ~5 ~-2~-8& Perf, Record Run Please sign and return the attached copy aS receipt HAVE A NICE DA?' . I:;:o~'a nne k.~ ~aska Oii & Gas Cot~s Com-'masion. A 'r 0 - t 52 9 ~- ~Anch0ra~2 .... ~ II.(AN~, ~:87243 A p p r' o v 8 cl . DZgTRZ~UTZON t, .,~m 2, 5:' 't o 5:' 26, 5:' 26, ~' 27, ~' t, ~' of da fa, Sch $ch $ch " Otis ~ $ch $ch Sch $ch $ch "' $ch $ch $ch ' '~".'",." .. .,. · .-'" Central Fi Les " Chevron '.'~:' '.',.:., I. I. F'i [es D & H R & D ~ $oh i o · ~ Exten.sion Exptora ,.'"'Exxon ... ~a~e of Alaska ~ Texaco H a r a t h o n · "' H o b i L ARCO Alaska, Inc. Prudhoe Bay ~.,,gineering Post Office Bo:( 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4248 Donald F. Scheve Operations Engineering N~anager November 7, 1986 Mr. C. V. "Chat" Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Chatterton- Re- NGI-5 (33-1-11-14) Permit No. 76-14 Enclosed is the "Intention" Sundry Notice detailing work proposed on the above-mentioned well. Very~truly yours, _ D. F. Scheve DFS/WJP:sd Enclosure cc: Standard Alaska Production Co. File PI(NGI-5)W1-3 ARCO Alaska, inc. is a Subsidiary of AtlanticRichfieldCompany STATE OF ALASKA ALASK.. OIL AND GAS CONSERVATION COMM. ~,51ON APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon [] Suspend [] Operation Shutdown [] Re-enter suspended well [] Alter casing [] Time extension [] Change approved program [] Plugging [] Stimulate [] Pull tubing [] Amend order [] Perforate ~ Other [] 2. Name of Operator ARCO Alaska, Inc, 3. Address Post Office Box 100360, Anchorage, AK 99510 4. Location of well at surface 450' S & 1039' E of NW cr, Sec. 12, T11N, R14E, UN At top of productive interval 1374' N & 2240' W of SE cr, Sec. i T11N, R14, UN At effective depth 5. Datum elevation (DF or KB) 47' RKB 6. Unit or Property name Prudhoe Bay Unit 7. Well number NGI-5 (33-1-11-14) 8. Permit number 76-]4 9. APl number feet At total depth 1532' N & 2015'W of SE cr, Sec. 11. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Conductor 74' St4rface 2694' Intermediate 8393' Liner 290' 1, T11N~ R14E~ UM 9404 feet Plugs (measured) 8623 feet 9313 8542 Size 20" 13-3/8" 9-5/8" 50-- 10. Pool None 029-20196 Sadlerochit feet Junk (measured) None feet Cemented Measured depth True Vertical depth 240 sx Permafrost II 6450 sx Permafrost II 1st Stg' 750 sx "G" 2nd Stg: 125 sx "G" 7" 300 sx "G" 8108'-9398' 7475'-8618' 99' 99' 2719' 2719' 8418' 7748' Perforation depth: measured 8807' -8817' 8841' -8876' 8891' -8921' 8936' -8966' 8981'-9011' 9047'-9072' 9910' -9930' 9152' -9182' 9211 '-9231 true vertical 8092'-8101', 8122'-8153', 8166' -8193', 8206'-8233', 8246' -8273', 8305' -8326', 8360'-8378', 8398' -8425', 8450' -8468 Tubing (size, grade and measured depth) 7", 29#, ABMOD, 8rd to 7769'MD 5½" 17# L-80 BTC 7769'-7892 'MD Packers and SSSV (type and measured depth) 4½", 12.5#, L-80, 7892'-8029'MD 9-5/8" x 7" SAB Packer @ 7892'MD/0tis RB Ball Valve Ca 2193'MD 12.Attachments Description summary of proposal [] Detailed operations program E] BOP sketch ~ 13. Estimated date for commencing opera~6rh' '"~.. ~ ~ '~ ' November 15, 1986 14. If proposal was verbally approved Name of approver ;~i;;.,:~:i;~, ¢!i~ ~ !i~;~; ;', ...... ;/~¥ ,~:, .......... -~., :~; ,~_~, :~:~.,r; Date approved . . 15. I hereb~ertify th~t~e foregCg is true an~;~(~;~ to the best of my knowledge Signed ~~~~~ Title Operations En,ineering Manager Date Commission Use Only Conditions of approval Notify commission so representative may witness ~ Approval No. ~ ~ ~ Plug integrity ~ BOP Test ~ Location clearanceI ~ '~ '~' by order of Approved by , , '~;:. ~ Commissioner the commission Date Form 10-403 Rev 12-1-85 WJP (263-4511 ) Submit in triplicate NGI-5 Proposed Additional Perforations ARCO Alaska, Inc. proposes to add perforations within the Sadlerochit interval in Well NGI-5. The proposed perforation intervals are as follows' Existing Perforations Proposed Perforations Reference 8807-8817 (10') 8841-8876 (35') 8891-8921 (30') 8936-8966 (30') 8981-9011 (30') 9047-9072 (25') 9110-9130 (20') 9152-9182 (30') 9211-9231 (20') 8820-8841 (21') 8921-8936 (15') 9011-9042 (31') 9072-9110 (38') 9130-9152 (22') 9240-9258 (18') 9277-9287 (10') BHCS of 3/21/76 TOTAL' 230' TOTAL' 155' A 5000 psi WP wireline lubricator, tested to working pressure, will be utilized for this work. All perforations will be made with hollow carrier type guns at 4 shots per foot. The well will be loaded with an appropriate fluid, the perforating performed, and gas injection resumed with the wellbore load fluid being displaced into the formation. No flaring is anticipated. iii ~ i ii ii ii 3 iI II ! ! I 1. 5000 PSI 7" WELLHEAD CONNECTOR FLANGE 2. 5000 PSI WlRELINE RAMS (VARIABLE SIZE) .3. 5000 PSI 4 1/6" LUBRICATOR 4. 5000 PSI 4 1/6" FLOW TUBE PACK-OFF H I REL I NE BOP EQU I PNENT NOTE TO THE FILES: ARCO"s NGI .~5 June 19, 1978 At approximately ll:35AM on June 15, 1978 Mr. Chuck Simons with ARCO called to request approval to flare gas from their NGI Well ~5 for approximately 3 hours. They were in the process of working the well over and washing with a water-diesel solution and had the solution in the holeo In a short time this would be ready to open the well up to try to clean the formation face. I gave Mr. Simon verbal approval to flare the gas at the well site until the well cleaned up which should happen in a period of 1 to 3 hours. O. K. Gi1 Jr. AtlanticRichfieidCompany North Ameri ..~"-Producing Division North A!asl' .del Post Office b,.,x 360 Anchorage, Alaska 99510 Telephone 907 277 5637 June 21, 1978 Mr. O. K. Gilbreth, Jr. State of Alaska Division of Oil and Gas 3001 Porcupine Drive Anchorage, Alaska 99501 In response to your requeSt for data pertaining to reservoir pressure information, please find the enclosed data. A list of stabilized flow rates prior to shut in and cummulative oil produced since last pressure equalization has been tabulated for all wells requested; with the exception of the following: D. S. #1-11, 1-12, and 1-14-To be run in the future. D. S. #2-11, 2-12-Are currently being run. D. S. #3-9, 3-10-No plans for these wells to be drilled at this time. Per your request, copies of Initial Static Pressure reports are again being submitted for the following: D. S. #4-7-Distributed to State 5-19-77 D. S. #9-3-Distributed to State 11-24-77 NGI #3- Distributed to State 19-78 ~-NG~I~5'~' Distributed to State 10-9-77 To date, no pressure buildups have been run on NGI wells. Plans are to run pressure surveys only at this time. I hope that this information will satisfy the state requirements adequately. Very truly yours, . / J. A. Roc~o~ 2~~/er HKVP To' parc:. · . ~ OAS North Alaska District ]~gineering T RANSM I TTAL' ~ro~ - -Run No. '.' "- Sepia -. . Scale ' o. - BHC Sonic/CaliPer Log · BHC Sonic/Caliper - Gann~,a Ray Log BHC Sonic/Gamma R~y Log Caliper/CCL . .. ... Cement Bond Log/VDL " Compensated Formation Density Log Compensated Neutron-Formation DensitY' Compensated Neutron Log Core Analysis - Inter~.al · '- Core' No. .- .. Core DescriPtion (SWC) - Interval Core Description (Cony.) - Core No. Directional Survey - Gyro Single Shot' . " ~'hltishot · 'Drili Stem Test - Test No.. · Daal Induction Laterolog. ..- Formation Density Log Formation Density Log/Gamma Ray. Gan~a P~ay/CCL Laterolog ' Location Plat Microlaterolog Microlog Nudlog- Inter~al Sample Log (A.R. c6.) - Interval Synergetic Log RIfD-DIL TFD_Porosity' Log.--- .. ~L~!S .d_z:X.z.~,~.' ~]..~ ~. ~, '..' ,o ..zt xaan _ _ . 'Xerox' · BL Line'.' · Recdipt AcImo~jledged For: Date: Please return receipt to: : Mr. Donovan' Je[ci:son tic Richfield Company h Alaska Engineering P. O. Box 360 Anchorage_. Al a~l-~ ac~q'~ n . · . /- / ?~tanticRichfieldCompany North Amer~- ~roducing Division North Aiask~ _.~rict Post Office Box 360 Anchorage, A~aska 99540 Telephone 907 277 5637 November 3, 1977 Mr. Hoyle Hamilton State of Alaska Department of Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, Alaska 99501 Subject- NGI #5 (33-1-11-14) Permit No. 76-14 Dear Sir' Enclosed please find our Sundry Notice along wi th the Well Completion Report done on the above-mentioned well. Very truly yours, F. M. Brown District Drilling Engineer /am of Subsequend Report detailing the Work 1'1..I Enclosures f,'urm P 7 SUBMIT IN DUr~CATE* STATE OF ALASKA st ructions on OIL AND GAS CONSERVATION COMMITTEE i WELL cOMPLETION OR RECOMPLETION REPORT AND LOG* TYPE OF WELL: on, ~] o,s [-] ~ OtherGas In.iection WeAl WELL lVELL ~ DRY -- v b. TYPE OF COMPLETION: ,,.~:,~ ~ ,,.o,,< [-] DE~;P-~~ []]] ,I,'~'. []] Perforated \VEL[. OVER EN BACK RESVR. Other NAME OF OPERATOR Atlantic Richfield Company 3, ADDRESSOF OPERATOR P.O. Box 360; Anchorage, Alaska 99510 4. LOCATION OF WELL (Report location clearly and in accordance with a~y State requirements)* ~)q~& 1039'E of NW cc Sec. 12, TllN, R14E, UM A~ top prod. interval reported below 1374'N & 2240'W of SE cc Sec. A~ total depth 1532'N & 2015'W of SE cr Sec. 1, TllN, R14E, UM 1, TllN, R14E, UM 5. AP1 NLr~M-Ei~ICAL CODE 50-029-20196 6. LEASE D~S1GNATiON A_ND SERIAL biO. ADL 28302 7, IF INDiA.N, ALLOTTEE OR TRIBE NA-~L~ ~8, UNIT,FAILM OR LEASE NAME ' Prudhoe Bay Unit 9. wE/LL NO. NGI #5 (33-1-11-14) 0. FIt~/,~D A,NI~,POOI.~-OR ~/VI~[.~IDCAT ruanoe ~ay r~ela >rudhoe 0il Pool A. ,SEC., T., R., .M., (BOTTOM ItOL~ OBd ECq'IVE) Sec. 1, T11N, R14E, UM ~2. PERiVIIT NO. 76-14 I~OWI~IA~Y* ROTARY TOOL,q CABI,E TOt3I,,q 9404' & 8623 9313' & 8542' N/A All None 2'3. ~VAS DII~ECTIONAL 22.PRODUCING INTERVAL(S), OF THIS CO.MPLETIO~--TO~, BOTTOM, NAME (MD AND TVD)' I SURVEY MADE Top Sadlerochit 8802'MD 8088'TVD ! Yes Base Sadlerochit 9294'MD 8525'TVD ~ 24. TYPE ELECTRIC AND OTHF-~ LOGS RUN DIL, So. nic, GR., .FDC/.CNL, FDL/CBL and GR/CCL ~5. CASING RECORD (Report all strings set in weld 20" [94~--V~tc° [ H-40 [81' be'iow p[ad 32"I 240 sx Permafrn~t IT 13-M8" [72#-But~reqsMN-8012718' , [17-1/2"{ 6450 9-5/8" [ 47#- Buttre~sMN-80.[ 8418' !12-1/4"! 750 ' [ "[ '1 ' [ ,l 2nd stage w/125 sx ClasslG cmt. SIZ~ [ TOP 'R'ID) [ EOTTO}/i ':<D ) ! SACt<:S CE)'IENT* SCi:E~S~T /'<D) 1 SIZ][3 ------~' [ 8108' ! q-q'q2' ! 300S× ~ 28 pER?ORATiONS OPP.-iN TO PRODUC'ITM (interval size and number) 29 ACID Si:©T KliAC~iUNE CIEL,iLNT SQUJ£XZX, ETC. 9211'-9231' 9152' -9182' '9110'-9130' 9047'-9072' ~."' '8981'-9011' 8936' -8966' 8891' -8921' 8841' -8876' 8807'-8a17' w/4 shot PllO D UCTI ON DI3PTli INTFX%VAL (MD) ; per fggl I'AlioUNf AND liIND OF MfVIE:'.iAL USE.D DATE Fi~JT ~Jii¥~ucTIoN [ PI%ODUCT'ION' ME;i [iOD (Flowil:g, gas lif:, pamping---size and type of pump, : ......... 10/17/77 }7 .... ) Injection on 7" tbq with oacker 9/21/77 ~8~ wvmso iCA2:NO P~SSU~E ICALC~T~ [ ~uu ps.lg > [ ~i-.9~S~smox~ o~ ~,s <Soa ~ jot ~ud, v~nt~, etc.)' Reinfection into p~oduct~on gone 32.LIST OF ATTACHMENTS ] V,,t'JLL :3'fATUS ( Producing or Jn~ection OI~BBL. G-AS--RICF. ~VA'I'Eg--BtlL. 1 GAS-OIL ttA.TIO 196247 1 GAS--2v[CF. WA~R--BBL. [ OIL GRAVITY-~I (CORR.) 96247 t Pete Hellstrom 33. I hereby certify that the forFgoing and attached information is complete and correct as determined from all-available records SIGNED .~ ~&/~/v:~'/ TITLEDistrict Drlg ~n~ineer DATE , *(See Instructions and Spaces Jar Additional Data on Reverse Side) INSTRUCTIONS C~eneral: This form is designed for subrt~tt~mcj a complete and correct well cor-nplet~on report and log on all types of lan.ds and leases in Alaska. Item: 16: Indicate which elevation is used as reference (where not otherwise shown) for depth measure- ments given ~n cther spaces on this forn~ and ~r'~ any att,]:h,'t~ents Items 20, and 22:: If this well is completed for separate prcduction from more than or'~e ~nterval zone (multiple completion), so state ~n ~tem 20, and in ~te,~ 22 show th,,:, prc:]uc~::~l interval, or ~ntervals, top(s), bottom(s) and name (s) (if any) for only the interv~l ret~orted ~r~ iter'~ 30 Submit a separate report (page) on this form, adequately identified, for each additional interval to be seperately produce,d, show- ing the additional data pertinent to such interval. Item26: "Sacks Cement": Attached supplemental records for this well should show the details of any mul- tiple stage cementing and the location of the cementing tool. Item 28: Submit a separate completion report on this form for each interval to be separately produced. (See instruction for items 20 and 22 above). '34. SUMMA~tY Ob' FORMATION 'TE.S'I'S INt'LUDIN(; INTEItVA!L TESTED, PHE~UIIE DATA ~COVEI{I~' OF OIL. GAS. 35. G~GIC MARK~ WAT~ AND MUD NAME , ,,,,,,, , ,, , , ,, . , , a6. ('OHE DATA. A'I'FACII BHiEW D.~CRIPI~ONS OF LITIIOLOGY, POHOSITY. FRACWRES, APP~N'~ DIPS' AND.. I)EI"EUq'EI) SIIOWS OF OIL. GAS Oil ~VAT~I. ................. Form 10-403 REV. 1-10~73 Submit "1 ntentions" in Triplicate & "Subsequent Reports" in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT---" for such proposals.) z' ~v~LLL[---] GAS I----I Gas Injection WELL I--_.J OTHER 2. NAME OF OPERATOR Atlantic Richfield Company 3. ADDRESS OF OPERATOR P.O. Box 360; Anchorage, Alaska 99510 4. LOCATION OF WELL At surface 450'S & 1039'E of NW cr Sec. 12, T11N, R14E, UM 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 18.4' Pad Elev. 14. Check Appropriate Box To Indicate Nature of Notice, Re NOTICE OF INTENTION TO= TEST WATER SHUT-OFF FRACTURE TREAT SHOOT OR ACIDIZE 'REPAIR WELL (Other) PULL OR ALTER CASING MULTIPLE cOMPLETE ABANDON* CHANGE PLANS 5. APl NUMERICAL CODE 50-029-20196 6. LEASE DESIGNATION AND SERIAL NO. ADL 28302 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Prudhoe Bay Unit 9. WELL NO. NGI #5 (33-1-i1-14) ~0. FIELD AND POOL, OR WILDCAT Prudhoe Bay Field-Prudhoe 0il Pool 11.. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec. 1, T11N, R14E, UM 12. PERMIT NO. 76-14 )ort, or Other Data SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ REPAIRING WELL ~ FRACTURE TREATMENT ~.~ ALTERING CASING SHOOTING OR ACIDIZlNG L~ ABANDONMENT* (Other) PerTora te (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent ¢]etalls, and give pertinent dates, including estimated date of starting any proposed work. Began perf operations 10/2/77. Att to run dummy valve w/btm pkg removed to check location of cont &bal lines. Stopped @ 1620'. Att to work thru w/o success. Jarred thru tight spot. RIH to 2207', ball valve nipple OK. POH, left gage ring & tool string in hole. Fish @ 1650'. After several atts rec fish. Reran dummy valve w/o btm pkg. Got positive ID on cont &bal lines as to location. Pulled dummy valve. RIH, perf'd intervals 9221'-9231', 9211"-9221', 9172'-9182', 9152'-9172', 9110'-9130', 9057'-9072', 9047'-9057', 9001'-9011', 8981'-9001', 8946'-8966', 8936'-8946', 8911'-8921', 8891'-8911', 8856'-8876', 8841'-8856', 8807'-8817' w/4 shots per foot; Ran & set ball valve. Tstd bal& cont lines OK. Tstd ball valve OK. Flushed burn line to pit w/diesel. Flowed well to burn pit for cleanup. SI well. Ran Amerada press bombs. Installed & tstd tree cap to 5000 psi OK. Released'well to Production Dept @ 1400 hrs 10/9/77. 16. I hereby certify that the foregoing is true and correct TITLE District Drlg. Engineer DATE 11/2/77 (This space for State office use) APPROVED BY. CONDITIONS OF APPROVAL, IF ANY: TITLE DATE See Instructions On Reverse Side A/lantt~.RichfieldCompany North Ame-~'-'''] Producing Division North Alas Astrict Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637 September 6, 1977 Mr. Hoyle Hamilton State of Alaska Department of Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, Alaska 99501 Subject' NGI #1 (33-12-11-14) Permit No. 75-48 NGI #3 (32-11-11-14)' Permit No. 75-61 ~'~NGI #5 , (33-01-11-14) 14 NGI #8' (21-11-11-14) Permit No. 76-52 Dear Sir' Enclosed please find a Sundry Notice outlining our plans for the above mentioned wells. Very truly, yours, Frank M. Brown District Drilling Engineer /am Enclosure Form 10-403 REV. 1-10~73 Submit "1 ntentions" in Triplicate & '"Subsequent Reports" in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Oo not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT---" for such proposals.) WELLL...I OTHER Gas Injection 2.. NAME OF OPERATOR Atlantic Richfield Company 3. ADDRESS OF OPERATOR P.O. Box 360; Anchorage, Alaska 99510 4. LOCATION OF WELL At surface 450'S & 1039'E of NW cr of Sec. 12, T11N, R14E, UM ELEVATIONS (Show whether DF, RT, GR, etc.) 18' Gravel Pad 14. Check Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 50-029-20196 6. LEASE DESIGNATION AND SERIAL NO. APL-28302 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Prudh0e Bay 9. WELL NO. NGI #5 (33-01-11-14) 10. FIELD AND POOL, OR WILDCAT >rudhoe Bay Fiel d-Prudhoe 0i 1 11. SEC., T., R., M., (BOTTOM HOLE OBJECT 1532'N & 2015'W of Se cr of Sec. 1, T11N, R14E, UM 12. PERMIT NO. 76-14 )ort, or Other Data Pool IVE) NOTICE OF INTENTION TO; TEST WATER SHUT-OFF L..--.-J FRACTURE TREAT SHOOT OR ACIDIZE REPAIR WELL (Other) PULL OR ALTER CASING MULTIPLE COMPLETE ABANDON* CHANGE PLANS Perforate SUBSEQUENT REPORT OF-' WATER SHUT-OFF ~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15, DESCRIBE PROPOSED OR COMPLETED OPERATIONS: (Clearly state all pertinent der&lis, and give pertinent dates, Including estimated date of starting any proposed work. Atlantic Richfield Company proposes to perforate selected intervals within the Sadlerochit interval. All perforated intervals will be reported on subsequent report. A 5000 psi WP wireline lubricator, tested to working pressure, will be utilized with all wireline work. All perforations will be made with hollow carrier type guns at 4 shots per foot. After setting and testing the ddwnhole safety valve, the well will be blown down and flared to th'e pit for clean up only. A static bottom hole pressure survey will then be taken. Estimated Start Date' 9/12/77 16. I hereby certify that the foregoing is true and correct SiGNED/~.~.~' ~ ~ ~ District Drilling Engineer TITLE , DATE (This space for State office use) CONDITIONS OF APPROVAL, IF ANY~. Petroleum Engineer See Instructions On Reverse Side DATE 9-12-77 Approved Copy, Returned CONFIDENTIAL DISTRIBUTED TO: STATE OF ALASKA. To' DIVISION OF OIL & GAS From' T tt A N S H I I T A L J. A..Rochon/p. Hellstro:,. Date' Jan. 21, 1977 Well v~-..~.:,=:~ NGI # 5 Transmi.tted herewith are the following for the subject well' Scale Xerox Sepia BL Line - _ Receipt Acknowledged For' Date: Please rem-rn receipt to: BHC Sonic/Caliper Log BHC Sonic/Caliper - Gamma Ray Log BHC Sonic/Gam~na Ray Log Caliper/CCL Cement Bond Log/%~DL Compensated Formation Density Log Compensated Neutron-Formation Density Compensated Neutro~ Log Core Analysis - Interval Core No. Core Description (Sh'C) - Interval Cora Description (Cony.) - Core No. Directional Survey- Gyro - Single Shot Bhltishot Drill Stem Test - Test No. Dual Induction Laterolog Formation Density Log Formation Density Log/Gamma Ray Gmmma Ray/CCL/Neutron Laterolog Location Plat Microlaterolog Hicrolog Mudlog- Interval Sample Log (A.R.Co.)-Interval) Synergetic Log TVD-DIL ]VD-Porosity Log 5" _= ~. ea. --1 ea. Nor~ Al~ka Engineeri~,g P. O. Box 360 ~i~orage, Alaska 99510 ' Divisi0~ 0l'0il Anohora~a AtlanticRichfiehJ¢;o;npany Norlh Amcri!~ P~o(tucmq Divisiol~ North A'a~ trier ~ ~ .,.~, Post Office [~ox 300 Anchorage, Alaska 9=-3!0 Telephone 907 277 5637 November 9, 1976 Mr. Hoyle Hamilton State of Alaska Department of-Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: B.~.~2~-~1_ (23-25-11 14) Dear Sir' Enclosed please find our Sundry Notice of Subsequent Report detailing the work done on the above-mentioned wells. Very truly yours, C. R. Knowles District Drilling Engineer /jw Enclosures For,~ 10-403 REV. 1-10~73 Submit "1 ntentions" in Triplicate & "Subsequent Reports,' in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) 5. A~ERICAL CODE 5o-o .] 6. LEASE DESIGNATION AND SERIAL NO. ADL 28302 7. IF INDIAN, ALLOTTEE OR TRIBE NAME WELL ~ OTHER 2. NAME OF OPERATOR 8. UNIT, FARM OR LEASE NAME Atlantic Richfield Company Prudhoe Bay 3. ADDRESS OF OPERATOR 9. WELL NO. P. O. Box 360, Anchorage, Alaska NGI #5 (33-1-11-14) 4. LOCATION OF WELL At surface 450'S & 1039'E of NW cr Sec 12, TllN, R14E, UM 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 28.6 'RKB 14. CheCk Appropriate Box To Indicate Nature of Notice, Re 10. FIELD AND POOL, OR WILDCAT Prudhoe Bay - Sadlerochit Pool 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec l, TllN, R14E, UM 12. PERMIT NO. 76-14 )ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ~ PULL OR ALTER CASING FRACTURE TREAT ~ MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL CHANGE PLANS (Other) SUBSEQUENT REPORT OF: WATER SHUT-OFF FRACTURE TREATMENT SHOOTING OR ACIDIZING (Other) Compl eti on' REPAIRING WELL ALTERING CASING ABANDONMENT* (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15, DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. Accepted rig @ 0800 hrs 10/27/76. ND xmas tree. Set Baker 9-5/8" BP @ 90'. NU & press tstd BOPE. Press tstd choke manifold. Pul led tst plug & rec BP. PU 6" bit & BHA. RIH & displ diesel w/mud @ 2511' Cont staging in hole to 9313' Circ & cond mud. Chgd over from m~d to 10.9 ppg CaC1e wtr. Trip, PU'csg scraper. RIH to~'. Cond mud. POH LD DP. Set BP plug @ 1300'. ND BOPE. Pulled 61-d 9-5/8" pkoff & in;tailed new pkoff. Press tstd to 5000 psi w/minor leak. Retorqued lockdown screws. Press tstd to 5000 psi OK. RIH & retrieved Baker BP. Chgd & press tstd 7" rams. Ran junk bskt & gauge ring. Ran 7" completion string w/SAB pkr @ 7892', PBR @ 7847', XN nipple @ 7839', XA sleeve @ 7802', ball valve ni~. Landed & press tstd tbg hgr & ball valve control lines. NU & tstd xmas tree to 5000 psi OK. RIH & retrieved dummy valve. RIH & opened sliding sleeve. Displ tbg w/diesel. Closed & press tstd sliding sleeve to 3000 psi. Ran CNL/GR/CCL logs & dummy gun. RU for long term press tst. Released rig @ 0600 hrs 11-7-76. 16. I hereby certify that the foregoing is true and correct (This space for State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY: TITLE DATE See Instructions On Reverse Side North Alask=~'a~istrict Post Office 360 Anchorage, Alaska 99510 Telephone 907 277 5637 July 14, 1976 Mr. O. K. Gilbreth State of Alaska Department of Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, AK 99501 Subject: NGI No. 1 (33-12-11-14) NGI No. 2 (11-07-11-15) NGI No. 3 (32-11-11-14) NGI No. 4 (13-06-11-15) ~,....NGI No. 5 (33-01-11-14) Dear Sir: Enclosed are our Sundry Notices outlining recompletion plans for the above-mentioned wells. Very truly yours, C. R. Knowles District Drilling Engineer CRK/cs Enclosures ~. ~' orm 10-403 REV. 1~,10-73 Submit "Intentions" In Triplicate & "Subsequent Reports" In Duplicate STATE OF ALASKA ' OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS.ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) 2. NAME OF OPERATOR Atlantic Richfield Company 3, ADDRESS OF OPERATOR P. 0. Box 360.~ Anchoraqe, AK 99510 4. LOCATION OF WELL At surface 450' S & 1039' E of NW cr Sec 12, TllN, R14E, UM @ TD 1532'N & 2015'W of SE cr Sec l, TllN, R14E, UM 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 47' RKB 14. Check Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 50-029-20196 6. LEASE DESIGNATION AND SERIAL NO. ADL 28302 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Prudhoe. Bay 9. WELL NO. NGT ~5 (33-1-11-14~ 10. FIELD AI~ID POOL, OR WILDCAT 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec 1, TllN, R14E, UM 12. PERMIT NO. 76-14 aort, or Other Data NOTICE OF INTENT-ION TO: TEST WATER sHUT-OFF .~ PULL OR ALTER CASING FRACTURE TREAT ~ ' MULTIPLE COMPLETE SHOOT OR ACIDIZE' M ABANDON* REPAIR WELL I J CHANGE PLANS (Other) Completion SUBSEQUENT REPORT OF; FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, Including estlmated date of Starling any proposed work. Atlantic Richfield Company proposed to complete this gas injection well in October 1976. A rig utilizing 13-5/8" 5000 psi Shaffer LWS BOP's (one double plus one single) and a spherical BOP will be used The mud presently in the well will be displaced with CaC1". water. A completion st'rin~ compriSed of a Baker 0il Tool Model "SAM" Production Packe~, PBT mandrel and Otis "RQ" landing nipple with dummy valve in place will be run with 7" 29# L-80 LT&C 8rd A-B modified tubing. A 6" 5000 psi tree .will be installed and the completed well will be left unperforated with diesel in the tubing down to the PBR. Prior to setting the packer and nippling up the xmas tree, all work will be done in a calcium chloride brine with a 300 psi over balance. 16. I hereby certify that the foregoln9 is true and c.9rrect SIGNED ..... TITLE District Drilling Enginee~ DATE (This space for State office use) See Instructions On Reverse Side - - DATE Atlan;,~'~-iichfieldCompany North Am:''~- ?roducir~g Division North A~a~ ~ ~:?strict Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637 June 14, 1976 Mr. O. K. Gilbreth State of Alaska Department of Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, AK 99504 Subject: NGI No. 4 (13-6-11-15) NGI No. 5 (33-1-11-14) Dear Mr. Gilbreth: Enclosed are our Sundry Notices outlining recompletion plans for the above-mentioned wells. Very truly yours, C. R. Knowles District Drilling Engineer /cs Enclosures P ? rm 10-403 RP:V, 1-10-73 Submit '*1 ntentlons" In Triplicate & "Subsequent Reports" In Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) WELL ~ OTHER 2. NAME OF OPERATOR Atlantic Richfiald Comn;anv ~ ADDRE3.S OF OPERATOR P. O. Box* 360, .A~chOrage, Alaska, 99510 4. LOCATION OF WELL Atsudace 450'S & 1039'E of NW cr Sec 12, TllN, R14E, L~ @ TD 1532'N & 2015'W of SE ar Sec 1, TllN, R14E, UM 13. ELEVATIONS (Show whether DF, RT, GR, et~) 47' RKB Check Appropriate Box To indicate Nature of Notice, Re 5. APl NUMERICAL CODE 50-029-20196 LEASE DESIGNATION AND SERIAL NO. ADL 28302 7. If INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Prudhoe Bay 9. WELL NO. NGI #5 (33-1-11-14) 10. FIELD AND POOL, OR WILDCAT Prudhoe Bay - Sadlerochit Pool 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec 1, TllN~ 'R14E~ UM - ].2. PERMIT NO. 76-14. ~ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF L--J PUL1 OR ALTER CASING FRACTURE TREAT ~ MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL , CHANGE PLANS . . (Other) C. omnlet~'m~' .- - SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. Atlantic Richfield Company proposes to complete this gas injection well in August 1976. A rig.utilizing 13-5/8" 5000 psi Shaffer LWS BOP's (one double plus one single) and a spherical BOP will be used. The mud presently in the well will be displaced with an oil fluid.~ A completion string comprised of a Baker Oil Tool Model "SAB" Production Packer, PBR mandrel and Otis_._._,'RQ" landing nipple with dummy valve in place will be run with 7" 29# L-80 LT&C 8rd A-B mbdified tubing. The oil fluid will be left in the 9-5/8" x 7" annulus and in the tubing. A 6" 5000 psi tree will be installed and the complete well will be left unperforatedo 16. I hereby certify that the foregplng is true and correct District Drilling Engineer T IT LE OAT E June 14, 1976 (This space for State. off~.:, e use) AL//~'~ ~~ ~/k~ CONDITIONS OFtA/PPROVAL', IF . ~ - TITLE /c~/ DATE / ** Any ~fluidII utilized must be of sufficient wei§ht to control the reservoir pressure until the tubin9 is landed. See Instructions On Reverse Side To' ATIX~NTi C R£ C] II:IELD COb~ANY rn xl[:ln[: lTl x/ o District Engineer~}:~, DISTBIBUTED TO: T R A N S M I T T A L STATE OF ALASKA DIVIS1ON OF OIL ~ GAS Date' June 9, 1976 From: -. :. .... :JY6 " 'l,' ,,3i' ~' J. A. Rochon/W. Toliver Well Name' NGI #5 (12-11-14) Transmitted herewith are the following for the subject well' Run No. Scale Xerox 0, BHC SoniC/Caliper Log BHC Sonic/Caliper - Gamma'Ray Log BHC Sonic/Gamma Ray Log Caliper/CCL Cement Bond Log/VDL Compensated Formation Density Log Compensated Neutron-Formation Density Compensated Neutron Log Core Analysis - Interval Core No. Core Description (SWC) - Interval Core Description (Cony.) - Core No. Directional Survey -'Gyro Single Shot Multishot Drill Stem Test -'Test No. Dual Induction Laterolog Formation Density Log Formation Density Log/Gamma Ray. Gamma Ray/CC& Laterolog Location Plat Microlaterolog Microlog Mudlog- Interval Sample Log (A.R.Co.)-Interval) Synergetic Log TVD-DIL IVD-Porosity Log . ¥ ' t;,; ,, ,, . . // ?, : 2"&5" Sepia BL Line ReCeipt Acknowledged For' By' Date:/~}'Q~'~~ /~/ /+~ ,, Please return receipt to:~ A~antic Richfield Company k4~orth Alaska Engineering Manager P. O. Box 360 Anchorage, Alaska 99510 AtlanticRichfieldCompany North Amer' Producir~g Division North A~;' ~ umtrict Post Offic~ Box 360 Anchorage, A~aska 995'~0 Telephone 907 277 5637 May 6, 1976 Mr. O. K. Gilbreth State of Alaska Department of Natural Resources Oil and Gas Division 3001 Porcupine Drive Anchorage, Alaska 99504 RE: NGI #5 (33-1-11-14) Permit No. 76-14 Dear Sir: We are enclosing the Well Completion Report along with the Well History and Directional Survey for the above mentioned well. Very truly yours, C. R. Knowles District Drilling Engineer CRK/BDR/jr Enclosures Pt,tm P - 7 SUBMIT IN DU~._ ,3,~TE* STATE OF ALASKA ','So,~oth~r m- st ructions on reverse side~ OILAND GAS CONSERVATION COMMITTEE WELL cOMPLETION OR RECOMPLETION REPORT AND LOG* la. T~/'Pl~. OF WELL: 0II,w~:LL ~ ~aSwgBk ~ ~Y ~ Other Gas Injection We~ b. TYP~ OF COMPLE~ON: ~w ~ ~.o~,~ ~ ~-~ ~'-~ ~ ~'~' ~ Suspended WELI. OVER ~ EN BACK RESVR. Other 9. NAME OF OPERATOR Atlantic Richfield Company ~. ADDRESS OF OPERATOR P.O. Box 360, A~choraae. Alaska gg.~lO 4. r,oc~'r~oN or WELL ('Report locatio~cIearly and in accordance with any State requirements)* At surface 450'S & 1039'E of NW cr Sec 12 TllN-R14E UM At top prod. interval reportedb61'6w ' ' 1374'N & 2240'W of SE cr Sec 1, TllN-R14E, UM At total depth 1532'N & 2015'W of SE cr Sec l, TllN-R14E, UM 5. API N~CAL CODE 50-029-20196 6. LEASE DESIGNATION A.ND SERIAL NO. ADL 28302 IF INDiA/X[, A/~LOTTEE OR TRIBE NA1VIE 8.UNIT,FAR/VI OR LEaISE NAME Prudhoe Bay 9. WELL NO. lo.L~G I #5~)(33-]-] ]-]4) · FiEI~)-i~qD'"~OOL, OR WILDC&T Prudhoe gay-Sadlerochi t 11. SEC., T., R., M., (BOTTOM HOLE: P00 J OBJECTIVE) Sec l, TllN-R14E, UM 12. PE1TMIT NO. 76-14 ( 4.': & 8623' [ ,93t3", & 8542" [ ao~/%~, All " None':*""~ ~. pRO~CiNO ~N~RVAL(S). OF ~IS COMP~TIO~--TO,P, BOSOM, NAME (MD AND ~)* 23.'~VAS DIRECTIONAL SURVEY MADE ~one ~ Yes 24. TYT~E ELECT~IIC AND OTHEr, LOGS RUN DIL, Sonic, GR, FDC/CNL, CA, SIiqG SIZE 20" 13-3/8" 9-5/8" VDL/CBL and GR/CCL and GR/CC.L _ i · CASING RECORD (Report all strings set in well) 94~'-VetCo IH-40 I81'bel6w paB 32" ! 240 sx Permafrost II cmtI 72#-BUttre~sMN-8012718' ' 117-1/2" 6450 sx Permafrost TT em 26. LINER EEC O!RZ) 7" [ 8108'I ;9,3 '8i 300sx gS. PERFO!R.ATJ;OI'gS OP~ 'PO PRODUCTION' (interval size and number) . N/A ,, i i 30. PR, ODUCTI OIq I 2nd stage w/125 sx ClassI G cmt. $Ci~EL-~'~ (~[D) SIZE [' DEPTI5 SE"[' (~(D, [ PACI[EI~ SET ACID, Si:CT, ~'ilAC5 GRE, C~,iENT SQUL!EZ2. ETC. DF~-~T~i I~,;TF~RVA_L (MD) N/A ASIOUNF AND I'[!b.'D OF MA'IESL~AL USF~D CI!O"-ZE SiZE ~,~ -F~z -i · r V .... 1' ""' .L. GAS-OiL [L%TIO ~TE OF TEST' YOURS TEST~ '1 31~ DISP081TIONOF GaS (8old, u~ed ]orfue~, vented, etc.) .......... ]~ST [ 32. LIST OF ATTACHMENTS A~'~'- ;( , Dri]]in~ History and Gyro $~rvev 33. I hereb~, certify 'that the for[~oing and attached informa~ion is complete and correct as determined fr~m all-available record~ SIGNED TITL~ . DATE - ' -' ,, .......... fl · (S~, I.,truetio.~ ~.8 Spoe** Cot Addition=l Dot= on R,v,r,, Side) INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report end log all types of lands and leases in Alaska. item: 16: Indicate which elevation is used as reference (where not otherwise showr~) for depth measure- merits given in c, ther spaces on this form and in ar~y atla'-hments. Items 20, and 22:: If this well is completed for separatc- prcduction from more than one interval zone (mulliple completion), so state ~n item 20, and in item 22 show the p~c:iuc~r~.g intcrv~l, or ~ntervals, top(s), bottom(s) and name (s) (if any) for only the interval reported ia item 30. Submit a separate report (page) on this form, adequately identified, for each additior~al interval to be seperately produced, show- ing the ackJitional data pertinent to such interval. Item26: "Sacks Cement": Attached supplemental records for this well should show the details of any mul- tiple stage cementing and the location of the cementing tool. Item 28: Submit a separate completion report on this form for each interval to be separately produced. (See instruction for items 20 and 22 above). 34. SUMMAI{¥ OF F~)~MATION T~,~'I',% IN('LLII)IN(; INq'EVLVAI. TE~gTEI').'"t;I{E~SURE I')AWA ~ lq.~COVERiE,s OF OIL GAS. 35. G~GIC MA~K~q WATER AND MUD NAME .,,, ,,~ ~ ~ ,, ~, ,, Top Sadler0c~J ¢ 8802' 8088' Base SadlerochJ ~ 9294' 8525' '" ' ...... ~.~ 0 ........ 38. CORg DATA, A'I'I'ACI[. A:N..~ [)~?I:~'TEI) SIIOWS O? OIL, G&S' O'R IVA~I: .... , , ......................... ,, Atlantic Richfield Company NGI #5 (33-1-11-14) API 50-029-20196, ADL 28302, Permit No. 76-14 D_ril ling History Spud at 0030 hrs 3-2-76. Drilled 17-1/2" hole to 2736' Ran 13-3/8" 72# MN-80 butt csg w/shoe @ 2718' and FC @ 2635'. Cmtd w/6450 sx Permafrost II cmt. Washed & blew dry 13-3/8" X 20" anul. Recmtd thru 2-3/8" riser w/183 sx PErmafrost II cmt. Installed & tested packoff, NU test BOP. RIH w/12-1/4" bit, drild FC, shoe & formation to 2746', press tested formation to .65 gradient. Directionally drld 12-1/4" hole to 8387', twisted off DP @ 378'. RecoVered fish & drld ahead to 8457', POH w/multi-shot survey. Ran 9-5/8" 47# MN-80 & S00-95 butt csg w/shOe @ 8418', FC-.@ 8335', lower FO @ 2671' & upper FO @ 2393'. Cmtd w/750 sx Class G cmt. Installed & tested packoff. RIH w/RTTS & shifting tool, cmtd thru lower FO w/125 sx Class G cmt. Closed & tested FO @ 3000 psi. Circ thru upper FO @ 2393' & pumped 270 bbls Arctic Pack. Break thru @ 170 bbls w/final 0% water. Closed FO & press test @ 3000 psi. POH, press test BOPE. RIH w/8-1/2" bit, drld FC & hard cmt 8335-8395'. Tested casing w/3000 psi, drld cmt, csg shoe & formation to 8467'. Tested formation to .62 gradient. Drld 8-1/2" hole to 9404'. POH w/multi-shot. Ran DI,L/Sonic/GR & FDC/CNL logs. RU & run 7" 29# MN-80 butt lnr w/shoe @ 9398' & top @ 8108 . Cmtd w/300 sx Class G cmt. RIH w/8-1/2" bit & 9-5/8" csg scraper, tagged top of cmt @ 7940'. Drld to 8108'. RIH w/6" bit, drld & cleaned out to 9313' Tested lap w/3000 psi okay. RIH w/DST tools, set pkr @ 8061' w/tail @ 8075'. OpeneJ tools @ 0540 hrs w/weak to very weak blow. Closed tools @ 0640 hrs. POH. IHP 4127', IFP 2196, FSI 2509, FH 4127. Ran VD/CBL, GR/CCL logs & ' Gyro survey. Chged over to diesel from 0-2500'. Press test FO's & csg w/lO00 psi. ND BOP, NU & test xmas tree. While making various press tests, received Arctic Pack returns from 9-5/8" X 13-3/8" annulus, indicating leak in 9-5/8" csg or FO open. ND xmas tree, NU & test BOP. RIH w/RTTS, located leak in 9-5/8" @ 1549' & 1564'. Ran & set Baker bridge plug @ 2517' & spotted sand on top of plug. Chged over from diesel to mud @ 2350'. Unland 9-5/8" csg, pulled & laid down 39 joints. Cut and recovered 9-5/8" @ 2356'. Dressed stub, ran 9-5/8" tieback string and casing patch. Landed and packoff 9-5/8" csg, RIH w/RTTS and shifting tool. Opened top FO @ 2393', pumped 209 bbls of Arctic Pack into 9-5/8" X 13-3/8" annulus. Clsoed and tested FO @ 2000 psi. Ran and pulled Baker retrievable BP, changed Invermul to diesel @ 2511'. ND BOPE; NU and test xmas tree. Released rig @ 1800 hrs 4-6-76. Well suspended. Eastman/ Wh pstock A PETROLANE COMPANY REPORT of SU~-$URFACE DIRHC TIONA L SURVEY Atlantic Richfield COMPANY ~dT #5 WELL NAME Prudhoe LOCATI ON JOB NUMBER A576 G0099 TYPE OF SURVEY / DATE ~:,~M ~ ~ 1976 SURVEY BY d'ay Mar'tin OFFICE Alaska GYROSCOPIC "SURVEY K B ELEV(, 47 FT. _C.QS'I.PU.T.E D .... EO.R__E~._5.g. AN_.WH.I_P.S._T_.0CJ<,..) ...... I.NC., .... ~.F_._F.., ..... H_,, ...... L I_ND_SE~_AND__A.$_S_.QC.I.A_T~S ................................................ RECORD OF SURVEY T R U E D O G_LEG__ .F", E A 5, ....... D R JLF..T_._V E. R.T. [.._C.A..L .............. $ U B ............... D R I FZ ............. _T_ O.T A. L._C 00.R D.I.N A ~E.$ ........ C .... L_. 0 $ ._ U .._ R. E ...$ .................. S E V E R.. I T. Y ................ 5 E C.T.~ _0 N.~ _D..~PZ.H,_A NG_ LE ....D. EP_T_H .............. $ E A ............... DI R.E.C ...................................................................... ~__[_~_ZA~ ~ E .................... A.~.G.L.~ ................ 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LL... ............. ]-] ]._'__:.'~].L-L]=]__-~ ............... i ........... ~,~ SCALE }":500~ ............ · ............................ ~ ................... ~ ...... ; -'-~ - ATLANTIC RICHFIELD COMPANY ................ ~ .............. ; ...... ~--. ................... z -~ GYROSCOPIC SURVEY ~ ......... : .... : ........ ~ ~ ................ ....... .......... . _''"' ' "- - : ~ ~- TVD 8623' .............. ~- .... ~ ' ' .......... ~ TMD = 9404'; ........ ........... : .......... 84~ ~ 76~ _ . - ...... 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'"" --' ~'- '~ - -i--- ' - " !~- ' "~ i ! " .... : ',~ ~ ..... - ~ ' ~ i~ ....- .... ; ............ : '_ .... ~ i ...... i ....... -, -i . ; -~ - : - -~ '- - ~ .... --- .... i ........ .: ' ; ' TVD = 86Z5' ' ' ' i ....... . ........ : ...... . _' T~D- L--~4o4' . ..... ; ........ ~ ........ ....................... ................... ~- ............................................................................................... ' ......................................................... ~ ........................ i~ .............. ~ .............. f' ........ ! .... ~ ........ ;.. .... , ......... ,~ ; ...................... . . ; ............ i _ ~ . . - ' ~ : ' ''.' " ~ .... ~ ' ' ' i ......... i ...... ........ ~ i ......... ~ ~ ' ' , , ...................... ~, ......... i ......... i ........ 'i ............. ~--~ '"i"-~-'~/i-~-Z'~ ....... .'-~.' ~i ................................. ................ ~--' .............................................................................. ~, ...... , -i ..... ~--. ~ - ....... r--7~. - -: ...... ~ ....... ' ....... i ............... ~ ............ i ..... ! , . - AtlanticRichfieldCompany North Am :~roducing Division North Alas[ ,~lstrict Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637 April 6, 1976 Mr. O. K. Gilbreth State of Alaska Department of Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, AK 99501 Subject' NGI #5 (33-1-11-14) Permit No. 76-14 Dear Sir' Enclosed please find the Monthly Report of Drilling Operations for the above-mentioned well. Very truly yours, C. R. Knowles District Drilling Engineer /CS Enclosure APR 1976 DfVISION OF 01£ AND OAS Form No. P--.4 i~EV. 3- 1-70 STATE OF ALASKA OIL AND GAS CONSERVATION COMMII-rEE SUBNilT liN' DUP. LICATI~ MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS 1. o,Lw,~L [2 o,,sw,,.L []] o~-,,,., Gas Injection Well 2. NA.MI~. OF OPEI:LATOR Atlantic Richfield Company. 3. ADDRESS OF OPhiR P. O. Box 360~ Anchoraqe~ Alaska, 99510 4. LOCA~ON OF W~ 450'S & 1039 E of NW cr Sec 12, TI~(SR~ APl NI/ME1TICAJu CODE 50-029-201 96 6 LEASE DESIGI'JA'f'ION AND SEqRIAL NO. ADL 28302 IF INDIA]~, ALOTTEE OR TRIBE NAME 8. L~,'IT FA/{A~ OR LEASE NAME Prudhoe Bay 9 WELL NO NGI #5 (33-1-11-14) 10 FIELD A_ND POOL, Oil WILDCAT Prudhoe Bay-Sadlerochit Pool 11 S~C r , T., R., M, (BOTTOM OB.TEcrrvE) Sec l, TllN-R14E, UM 12, PIERMIT NO 76-14 13. REI~ORT TOTAL DEPTH AT END OF MONTH. CHA2','GF-,S IiXL ~f.~SL~ ~..~I]'~.~/~iQE1VIENTING JOES INCLUDING DEPTH SET A/',ID VOLIYME~ USED, PERFORATIONS, TF. STS AN~i~f-.~'%S k'F][SI~fl~ ~J~O]~ JUNK LN HOLE AND SIDE-TRACKED HOLE A3qD A_NY OTHER SIGNIFICANT CHANGF~$ IN HOLI~ CONDITION~[~4()?,;',~i': REPORT ON OPERATIONS FOR THE MONTH OF MARCH Spud at 0030 hrs 3-2-76. Drilled 17-1/2" hole to 2736'. Ran 13-3/8" 72# MN-8O butt csg w/shoe @ 2718' and FC @ 2635'. Cmtd w/6450 sx Permafrost II cmt. Washed & blew dry 13-3/8" x 20" anul. Recmtd thru 2-3/8" riser w/183 sx Permafrost II cmt. Installed & tested packoff, NU & test BOP. RIH w/12-1/4" bit, drld FC, shoe & formation to 2746', press tested formation to .65 gradient. Directionally drld 12-1/4" hole to 8387', twisted off DP @ 378'. Recovered fish & drld ahead to 8457', POH w/multi-shot survey. Ran 9-5/8" 47# MN-80 & S00-95 butt csg w/shoe @ 8418', FC @ 8335', lower FO @ 2671' & upper FO @ 2393'. Cmtd w/750 sx Class G cmt. Installed & tested packoff. RIH w/RTTS & shifting tool, cmtd thru lower FO w/125 sx Class G cmt. Closed & tested FO @ 3000 psi. Circ thru upper FO @ 2393' & pumped 270 bbls Arctic Pack. Break thru @ 170 bbls w/final 0% water. Closed FO & press test @ 3000 psi. POH, press test BOPE. RIH w/8-1/2" bit, drld FC & hard cmt 8335-8395'. Tested casing w/3000 psi, drld cmt, csg shoe & formation to 8467'. Tested formation to .62 gradient. Drld 8-1/2" hole to 9404'. POH w/multi- shot.Ran DIL/Sonic/GR & FDC/CNL logs. RU & ran 7" 29# MN-80 butt lnr w/shoe @ 9398' & top @ 8108'. Cmtd w/300 sx Class G cmt, RIH w/8-1/2" bit & 9-5/8" csg scraper, tagged top of cmt @ 7940'. Drld to 8108'. RIH w/6" bit, drld & cleaned out to 9313'. Tested lap w/3000 psi okay. RIH w/DST tools, set pkr @ 8061' w/tail @ 8075'. Opened tools @ 0540 hrs w/weak to very weak blow. Closed tools @ 0640 hrs. POH. IHP 4127, IFP 2196, FSI 2509, FH 4127. Ran VD/CBL, GR/CCL logs & Gyro survey. Chged over to desel from 0-2500'. Press test FO's & csg w/lO00 psi. ND BOP, NU & test xmas tree. While making various press tests, received Arctic Pack returns from 9-5/8" x 13-3/8" annulust_indicating leak !n_.~.9,5/8',, c~.g_..:O.E,~F.O open. ND xmas tree, NU & test BOP. RIH w/RTTS, located leak in '9:5/8 .... !a...~].~9 .... &_~.1~§64~..-, Ran '& set Baker bridge plug @ 2517' & spotted sand on top of plug. Chged over from diesel to mud @ 2350'. Unland 9-5/8" csg, pulled & laid down 39 joints. Cut and recovered 9-5/8" @ 2344'. Cutting 9-5/8" csg on April 1. 14. I hereby~certify that the £o.regoing is true and _ ._ NOT Ro~ort off this form ii required for each calendar ~nth% regardless of the status of operations, and must ~ filed in duplicate with the oil and gas conservation commiflee by the 15~ of the Iucc~ding mon~, uflle~ otherwise directed. S. TATE of ALASKA DEPART~ENT OF NATURAL RESOURCES Division of Oil and Gas TO: [-- O.K. Gilbreth, Jr~A~k(~ Director Thru: Hoyle H. Hamilton Chief Petroleum Enginee.r FROM: Ben LeNorm~n ~Y~ Petroleum Inspector DATE : SUBJECT: March 24, 1976 ,. BOPE Tests .... Arco NGr!-5,"" , Mobil Kuparuk 30-11-13 and BP E-6 March 5,_ 1976- Departed my ho~e at 7:00 At~I for a 7:30 sho. wup for an 8:30 departure -~ia' Wien Airlines flight #9 to Deadhorse. Arrived at Deadhorse at 10:20 AH and caught a ride with Joe Mann, Arco's drilling foreman on NGI-5, direct to Challenger Rig #51. We arrived_ at the rig at 10:45 AM and met with the tool pusher , Carl Lee, Temperature was -27'F, winds 14 MPH out of the north, heavy fog. They were just finishing their'cement job and ~ere having all kinds of problems with frozen or cemented risers and frozen mud lines. It was obvious it would be some time before BOPE tests would begin. March 6, 1976 - Nippling up began but was slow. A new two stage Koomey l~,000 ~ng pump was to be installed in the choke manifold room. We called Ken Sullivan, Drilling Foreman at ~iobil's Kuparak 30-11-13, who advised they were running pipe and it would be late Sunday afternoon or early Monday morning before BOPE tests would begin there. While waiting for them to nipple up, we toured the location which was ~,~ell organized, the reserve pit welt built, rig in good repair, well sign in place, and steel welded fuel tanks not bermed. March 7, 1976 - T. ests began at 7:45 AM. Sixteen valves and eighty-eight flanges ~n~t-h-e ChOke n~n~fotd tested to 5000. PSIGo .The t~o manual ad..iustable chokes moved freely and the Swaco superchoke was actuated. One of the manifold valves later leaked, but was repaired and again tested. The accumulator was tested to 2600 PSIG and N2 bottles on the backup tested to 1700, 1750, 2t00, 1900, 1850, and lgO0 PSIG. At this point in time some ~difications were made to the kill and choke lines and the air hose to the Koomey p~np changed. A hose end and needle valve were changed. Ba! 1 and dart type valves were on the fl oor. Tests resun~d at 3:10 P~! and both sets of pipe rams and blind rams tested to 500~ PSIG. Both wing valves and the HCR valve on the choke line and both wing valves and the check valve on the kill line tested to 5000 PSIG. The hydril tested to 3000 PSIG. O, K~ Gilbreth, Jr. -2- March 24, 1976 ~Ln. attempt to pick the kelly up found it frozen in the rathole. This was overcome at 5:00 PM and the lower kelly valve was tested to 5000 PSIG. However, the kelly cock would not test despite steaming and several grease jobs. Car] Lee advised they' had no repair parts on =hand and their spare kelly cock was shOpped in Anchorage for ~pairs. The only other Challenger Rig operating in Alaska was on a Texaco location in the Brooks foothills. We discussed this with Joe Mann who advised a repaired kelly cock ~uld be installed and ~sted as soon as possible. This is so noted on the field inspection report. Tests were concluded at 5:45 PM and a field inspection report was prepared with me original given to J~ Mann, a copy mailed to Benny Loudermilk, and a copy at~ch~ to this report. We talked with Bill C~gdOn ~garding Arco's Highland.location in the Kuparak River area and the Abt~ location just south of the injection pad, both of which have just been rigged up by Noble rigs. He advised the Highland location spudded today and the Able location wilt probably spud March 9. Also, Garland Goo~in, drilling foreman on BP's "E" pad, called to advise they were at 600' on surface hole there. I made a taped note to call Hoyle Hamilton when I arrived at Mobil's Ku~ruk location for an update, particularly on the Arco locations, neither of which I had information on before I left on this trip. March - Contacted Ken Sullivan at the Mobil location and he sent someone me up at Arco base at 2:00 PM. We arrived at Mobil's Kuparuk 30-11-13 at 2:45. He advised that tests would begin at approximately 5:00 PM. He also advised that their Kuparuk 22-11-12 spudded today. The drilling contractor on 30-i1~13 is Parker Rig #92 and the toolpusher is No.an Young. I called Garland G~in at BP's "E" pad at 6:30 PM and he suggested I go directly ~ Brinkerhoff Rig #36 tomorrow on completion of Mobil's tests. Tests began, at 11:45 PM with lower kelly valve testing to 5000 PSIG. Ma)ch 9 1976 - Kelly cock tested to 5000 PSIG. While awaiting test plug to be ~oth ball and dart type valves on the floor. At this point a flange leak developed while attempting to pressure up the blind rams. Tests resumed at 12:55 A}4~ with both wing valves on the choke line and both wing valves and check valve on the kill line testing to 5000 PSIG. Blind rams tested to 5000 PSIG. Blind rams tested to 5000 PSIG. Fourteen OCT gate valves, ninety- two flanges and the Swaco superchoke tested to 5000 PSIG. The manual adjustable choke was free moving. This manifold also utilizes a positive choke, bean size unknown. Hydril tested to 2500 PSIG and pipe rams to 5000 PSIG. O, K, Gilbreth, Jr. -3- March 24, 1976 The tocati~ was well organized, reserve pit well built, rig in good repair, well sign in place and steel welded fuel tanks not bermed. The accumulator tested to 2400 PSIG. There was no N2 backup on this accumulator and the toolpusher advised there ms no N2 in the accumulator bottles. We discussed this with Ken Sullivan who advised us a Koomey serviceman would be sent to Parker Rig #92 to check accumulator bottle bladders, and charge to 1000 PSIG. Tests were conc!~d at 4:30 AM.. A field inspection report was prepared, the original give to Ken Sullivan, a copy mailed to Fritz Schall and a copy attached to this report. At 9:30 AM we-were dropped off at BP operations by Ken Sullivan who was on his way to the airport to rotate out. ~ radioed BP "E" pad and a vehicle was sent to pick n~ up. We arrived at BP E-6 location at 10:45 AM. Drilling foreman was Jack Bart and Brinkerhoff Rig #36 toolpusher was Gary Goerlich. Nipplin9 up was almost completed and tests began at 12:00 noon. Both sets pipe rams, both wing valves on the choke line and both wing valves and check valve on the kill line tested to 5000 PSIG. Ten valves, forty flanges, two manual adjustable chokes and the Swaco superchoke were tested to 5000 PSIG. Blind rams tested ~ 5000 PSIG and hydril to 2500 PSIG. While waiting for kelly to be picked up for testing, we toured the location which was well organized, the reserve pit well built, rig in good repair, well sign in Place, and steel welded fuel tanks not bermed. The accumulator tested to 3000 PSIG. N2 bottles ~sted to 875, 2050, 2250, and 2200 PSIG. We recommended the low pressure bottle be replaced. Lower kelly valve tested to 5000 PSIG, However, the kelly cock would not test. The toolpusher advised that he P~d another one in their shop and we agreed it could be install~ later, tested, and the successful test confirmed to our office in ^nchorageo This was so noted on the field inspection report. Tests were concluded at 3:30 PM. A field inspection report was prepared with the original given to Jack Bart, a copy mailed to Swede Swenson and a copy attached to this report. We departed Deadhorse via Wien glight #20 at 4:50 PM, arrivino in Anchorage at 6:30 P~ and at ntv h~ at 7:00 PM. In summary, we witnessed successful BOPE tests at Arco NGI-5, Mobil Kuparuk 30-11-13, and BP E-6. Attach~nts Alaska ~'. and Gas Conservation Committee Fi'eld Inspection Report (~() () () () () () () () () () () () () Re[ b () () () () ( () 4~ Rig (~)~ ( ) (.) Safety Valve Tests (~)~ ( ) 5. Surface-No. Wells - (~ ( ) 6. Subsurface-No. Wells (~ ( ) ( ) Well Test Data (~ ( ) 7. Well NoS. ,~, , (~ ( ) 8. Hrs. obse~ , ,__,__ (~)~ ( ) 9. BS&W , , , (~,)~- ( ) 10. Gr. Bb--~-. , ~ , (~() ( -~-a~me n~ ~ ( ~ ( ) 11 r (~I) 12~ Water well,.( )capped( )plugged (') ) ~0~ Well/t~Fm~ Sec/ T~/A~ R~,_~ Name & Number ~~ cto~~ ~~ ~ection Yes No Item (~oPE Tests (~() ~ , . 15.~ Casing set (~ ( ) 16. Test fluid-( )wt~)m~d (~oil (~ ( ) 17. Master Hyd. Control S 18. N~ btls 19. R~mote s 20. Drilling spool- 21. Kill Line-(~Check valve 22. Choke Flowline (~HCR valve 23. Choke Manifold No. valv~ fles~ 24. Chokes-(~emote( )Pos~.(~dj] 25. Test Plug-(~ellhd( )csg(~)none 26. Annular Preventer~psie 27. Blind Rams ' 28. Pipe Rams, 14, Fe~ar~ .2, 1976 Prudhoe ~y NG! No. 5. (33-1-I1-14) Atlantic Richfield Company S~ Permit ~. 76-14 C. R. Knowtes District Drilling Engir~er Atl antic Richfield Company P. O. ~x 360 Anchorage, Alaska 99510 Sir: Enclosed is the approved application for permit to drill the above referenced well at a location in Section l, Township llN, Range 14E, UM. Well samples, core chips and a mud log are.. not required. A directional survey i s ~qut red. Many .rivers in Alaska and their drai~ge systems have been classified as i~ortant for the spawning or migration of anadromous fish. Operations in these areas am subject to AS 16.50.870 and the regulations promulgated thereunder. {Title 5, Alaska A~inistrattve Code}. Prior to comnencing operations you may be con~cted by the Habitat Coordinator's office, Depart- ment of Fish and Game. Poltuti~ of any waters of the Star is prohibited by AS 46, Chapter 03, Article 7 and ~e regulations p?o!~lgated thereunder (Title 18, Alaska Administrative COde, Chapter 70) and by the Federal Water Pollution Control Act, as amended. Prior to commencing operations you may be contacted by a representative of the ~r~nt of Enviro~ental Conservation. Purs~nt to ~ ~.40, Local Hi~ Under State Leases, the Alaska Department of Labor is being notified of the issuance of this permit to drill. To aid us in scheduling field work, ~ would appreciate your notifying this office wi~in 48 hours after the well is spudded. We. would also like to be notified so that a representative of the Division may be present to witness testing of blc~ut preven~r eo~ipment before surface casing shoe is drilled. C. R. ~owles 2- February 2, 1976 ,4)pe~~r i~,~.~(..O., r ~a~:T..~ceijlm~appr o~.,... 0 f 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, O. K. Gilbreth, Jr. Chairman Alaska Oil and Gas Conservation Committee OKG.bj Enclosure cc: Department of Fish and ~me, Habitat Section w/o encl. Deparbment of Environ~n~l Conservation w/o encl. Department of Labor, Supervisor, Labor Law Compliance Division w/ encl. AtlanticRichfieldCompany North Ameri( ~r North Alaska L~istric, Post Office Bo× 360 Anchorage, Alaska 99510 Telephone 907 277 5637 January 23, 1976 Mr. O. K. Gilbreth State of Alaska Department of Natural Resources Division of Oil and Gas 3001 Porcupine Drive Anchorage, AK' 99501 RE: NGI No. 5 (.33-.1~11-14) Sec 1, TllN, R14E, UM Dear Sir' Enclosed is our Application for Pe~nit to Drill for the subject well, together with the $100 Application Fee and required survey plat. This well will be directionally drilled. The surface location and target location are both on ADL 28302. This lease has an effective date of 10/1/65 and termination date of 3/27/84. The information in the above paragraph will be help-. ful to the State Department of Labor. Very truly yours, C. R. Knowles District Drilling Engineer CRK/JWS/j ha Enclosures la. TYPE OF WORK Form 10-401 SUBMIT IN TIUPLI(?Aq REV. 1-1-71 (Other instructions on reverse side) STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE PERMIT TO DRILl.. OR DEEPEN DRILL J~J DEEPEN J~ b. TYPE OF ~V2.;LL OIL GAS SINGI.E MULTIPLE F'-I ,~%LL D ZONE [] ZONE L~ WELl. ~ OTHER 2.NAME OF OPERATOR Atlantic tLichfield Company 3. ADDRESS OF OPERATOR P.0. Box 360~ Anchorage, ~ 99510 4. LOCATION OF ~,¥TLL At surface 450'S & 1039'E of ~qqC of Sec 12, TllN,. R14E, UM A:propo~eap, od.~o= 1380'N & 2000'W of SEC of Sec 1, TllN, R14E, UM 13. DISTANCE IN MILES AND DIRECtiON FROM NEAREST TO~KN OR POST OFFICE* Approximately. 8 miles ~or_thwest_c~ 'Deadhnrse 14. BOND INFORblATION: TreeStatewide Su,ety~d/orNo: Federal Insurance Co.#8011-38-40 API# 50-029-20196 6. LEASE DI,iSIGNATION AND SERIAL NO. ADL 28302 7. lt.;' INDb\N, AIJ.(YI'I'I~E OR I'RIBE NA,~'IE 8. UNIT t"ARM OR I.I'2ASE NAME Prudhoe Bay 9. WEI,I, NO. NGI No.S (35-.1-11-14) 10. FIELD AND POOL, OR WILDCAT Prudhoe Bay, Sadlerochit ll,SEC., T., R., bi., (IIOITOM IDLE OBJECTIVE) Sec 1, TiiN,.RI4Ej UM 12. Amount $100,000 15. DISTANCE FRO5I PROPOSED * 116. No. OF ACRES IN LEASE LOCATION TO NEAREST PROPERTY OR LEASE L1NE, FT. ()dso to nearest drig, unit, it' any) 2 000 ~ 2560 18. DISTANCE FROM PROPOSED LOCATION 19. PROPOSJdD DEFI'H TO NEAREST WELL DRILLING, COMPLETED OR APPLIED FOR, FT. 2800' tONGI No.4 .'~ 9750' 21. ELEVATIONS (Show whether DF, RT, CR, etc.) 18 ' Gravel Pad 23. PROPOSED CASING AND CEMENTING PROGRAM 17.NO,ACRES ASSIGNED 'TO TillS WELL 320' 20.ROTARY OR CABLE TOOLS Rotary !22. APPROX. DATE WORK WILL START March 1, 1976 sIZE OF HOLE SIZE OF CASING WEIGIIT PER FOOT' GRADE SETTING DEFt11 Quantity of ce,nent ,,, 32" 20" . 94# ~-40 ... Z00~ C5r£? tn -qurface - SO.0_3x 17-1/2" .__ 13-3/8f' 720 YIN-80 2700' Circ to surf_ace - 4000 sx -i2_-1/4'~ 9-5/8" 47#' vN-80 1500 -+' Ont Column. at Shoe'S750 -+__ & 300-95 8400' ~0J) -+' Cmt Col~nn nn 2nd St ~age~ .......... 8.-.!/2" 7" liner 29# ~-80_ T.~. 1650 _+' Ont Co, mm (300 -+ sx) ) -+sx) Atlantic Richfield Company proposes to directionally drill this well to 9750'MD, 8636'TFD as an interim gas supply well from the Sadlerochit gas cap. Ultimately, this well will be recompleted for use as a gas injection well. Logs will be run over selected intervals. A 20-3/4", 2000 psi Hydril will be used on the 20" conductor. A 13-5/8" 5000 psi BOP stack with Hydril, pipe and blind rams will be used after setting 13-3/.8.!' casing. This equipment will be pressure tested weekly and operationally tested each trip. Uncemented annuli within the permafrost interval will be filled with a non-freezing fluid. A Baker "SAB" packer will be set above the liner top. A 7" 23# S00'95 buttress circulating string will be hung above the packer. A tapered string of '3~1/2'' and 4-1/2" tubing with a 4-1/2" safety valve landing nipple will then be run to land in the packer as the production assembly. The well will be shut in waiting on perforating. IN ABOVE SPACE DESCRIBE PROPOSED PROGRAM: If proposal is to deepen give data on present productive zone and proposed new productive zone. If proposal is to drill or deepen directionally, give pertinent data on sub~ttrface locations and measured and true vertical depths. Give blowout preventer program. h regoing is Tr nd Correct 23 1976 SIGNED. DATE January , (This space for State office use) CONDITIONS OF APPROVAL, 1F ANY: SAMPLES AND CORE CttlPS REQUIRED MUD LOG OTItER REQUIREMENTS: D YES ~ NO [] YES ~ NO ~¥ES UNo 50-029-20196 District Drilling TrrLE Engineer PERMIT NO.. 76-14 APPROVAL DATE APPOVED BY~'~,- . TITLE Chairman ' - -" ' ~*See Instruction On Reverse Side February 2, ]976 DATE February 2, 1976 SECTION I 915 940' 965' 989' secfion line 1014' 1039' 1064' t089' 1114' CERTIFICATE OF .SURVEYOR I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASK~ AND THAT THIS PLAT REPRESENTS ~ LOCATION SURVE~ M~DE ,.BY ME OR UNDER MY SUPERVISION, AND ' AND O~HER DETAILS ARE ALL DIMENSIONS CORRECT. OCT 4 ~ 1975 DA TE SURVEYOR AS - BUILT WELL NO. I LAT. 70Ol9'36.129 LONG 148°28'50.016 WELL NO. 2 .LAT. 70° 19'37.284': LONG. 148° 28'50.762' WELL NO. 3 LAT. 70° 19'38.441" LONG. 148°28'51.493'' WELL NO. 4 LAT. 70° 19'59.596" LONG. 148°28'52.223'' WELL NO. 5 LAT 70° 9 40.749 LONG 148028'52.947 WELL NO. 6 LAT, 70° 19' 41. 908" LONG. 148° 28'53.682" WELL I~0. 7 0 i LAT. 70 19,43.052 LONG. 148 o28 54.412" WL~LL NO. 8 LAT. TO° 19'441.210" LONG. 148°~8'55.126'' WEEL NO. 9 LAT. 70° 19' 45.370" LONG. 148028'55.850'' WELL NO. I0 LAT, 70° 19'~6.519" LONG. 148°28'56.589'' Y 5 971 400.07 X 687 350.54 Y 5 971 516.90 X 687 ,322.06 ,Y 5 971 633.76 X 687' 294.09 Y 5 97t 750.62 X 687 266.18 Y 5 971 867.11 X 687 2.58.47 Y 5 971 984.28 X 68,'7 210.54 Y 5 972 099.94 X 687 182.47 Y ,5 972. 217.07 X 687 155.06 Y 5 972 334.31 X 687 127'.31 Y 5 972 450.53: X 687' 099.~4 EXISTING WELL OR CONDUCTOR PIPE WELL NO. I TOP PAD ELEV. : 18.4 FT. MLI..W 12 ARCO:/~ AFE 292265 HVL # ATLANTIC RICHFIELD CO. AS -BUILT WELL I THUR I0 NORTH tNJ£C, TiON SITE LOCATED IN PROTRACTED SECTIONS I &12 TIIN RI4E U.M. PREPARED BY '"'"':HEWITT., V. LOUNSBURY 8~ ASoOC. . (.'~ '..~ '723 W. 6TH. AVE., ANCHORAGE~ ALASKA DATE OCT 9LLI9..75 SCALE I": 300' LOOSE CHI<D. ~Y__.G.,_~.O_ ..............FIE L D B~ ........ L_..F~E~ CHECK LIST FOR NEW WELL PERMITS Company /=/A~F-~ Yes No Remarks 1. Is the permit fee attached ..................... ~}~ Lease & Well No., 2. Is well to be located in a defined pool .............. }f/~d~ 3. Is a registered survey plat attached .......... ...... ~,. 7~bjC 4. Is well located proper distance from property line ..... . .... ~ 5. Is well located proper distance from other wells .......... r'y~¥~ 6. Is sufficient undedicated acreage available in this pool ..... .. 7. Is well to be deviated ....................... 8. Is operator the only affected party ................ K~,~ 9. Can permit be approved before ten-day wait ............ 10. Does operator have a bond in force ................. ~,~ l l. Is a conservation order needed .................. 12. Is administrative approval needed ................. 13. Is conductor string provided ...... ' .............. ~ 1~. Is enough cement used to circulate on conductor and surface .... 15. Will cement tie in surface and intermediate or production strings .~.,.;~ 16. Will cement cover all known productive horizons .......... ~ surface casing protect fresh water zones .......... ~ 17. Will 18. Will all casing give adequate safety in collapse, tension & burst 19. Does BOPE have sufficient pressure ratinm.., . . . . . . . . . . . . . ~\ u Additional Requirements' Approva 1 Recommended' Geology Engi neeri no~' TR,~, HWK ,,,'~., OKG ,, I~HH JAL LCS ,,,~'<.:~.-- dCM Revised 1/15/75