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210-132
New Plugback Esets 6/26/2024 Well Name API Number PTD Number ESet Number Date 2L-320 PB1 50-103-20627-70-00 210-166 T39025 3-8-2011 2L-320 PB2 50-103-20627-71-00 210-166 T39026 3-8-2011 CD4-23 PB1 50-103-20621-70-00 210-067 T39027 8-30-2010 CD4-23 PB2 50-103-20621-71-00 210-067 T39028 8-30-2010 ODSK-13 PB1 50-703-20607-70-00 209-146 T39029 11-18-2011 ODSK-13 PB2 50-703-20607-71-00 209-146 T39030 11-18-2011 ODSK-14 PB1 50-703-20610-70-00 209-155 T39031 3-24-2010 ODSK-14 PB2 50-703-20610-71-00 209-155 T39032 3-24-2010 OP05-06 PB1 50-029-23427-70-00 210-080 T39033 10-28-2010 OP05-06 PB2 50-029-23427-71-00 210-080 T39034 10-28-2010 P2-22A PB1 50-029-22850-71-00 209-161 T39035 6-4-2010 P2-22A PB2 50-029-22850-72-00 209-161 T39036 6-4-2010 S-129 PB1 50-029-23433-70-00 210-132 T39037 5-12-2011 S-129 PB2 50-029-23433-71-00 210-132 T39038 5-12-2011 W-219 PB1 50-029-23429-70-00 210-105 T39039 1-27-2011 W-219 PB2 50-029-23429-71-00 210-105 T39040 1-27-2011 W-220 PB1 50-029-23432-70-00 210-126 T39041 3-27-2013 W-220 PB2 50-029-23432-71-00 210-126 T39042 3-27-2013 S-129 PB1 50-029-23433-70-00 210-132 T39037 5-12-2011 S-129 PB2 50-029-23433-71-00 210-132 T39038 5-12-2011 Originated: Delivered m: 21 01 32 •. 24 -Jan -20 Schlumberger Y JW0520 24Jan- -i AOGCC PTS -PRINT CENTER . •� _ ATTN:Natural ResourcesTechnidanll 3 1 9 5 3 6411A Street % Alaska Oil & Gas Conservation Commision Anchorage, AK 9953$ 333 W. 7th Ave, Suite loo (907) 273.1700 main (907)273-4760fax Anchorage, AK 99501 ORDERSERVICE FIELD NAME DESCRIPTION DELIVERABLE DESCRIPTION DATA DATELOGGED PRINTS CDs S-129 50.029-23433-00 EDWI-00032 AURORA UNIT WL USIT-IBC Rev FINAL FIELD 21 -Nov -19 F nsmittal Re ce' t A Transmittal Receipt signature confirms that a package (box, X7 envelope, etc.) has been received and the contents of the Pr nt We m / ( package have been verified to match the media noted above. The Signature Date $pacific content of the CDs and/or hardcopy prints may or may Please return via Courier or sign/loan and email a copy t� b h Bahlumberger and IIP ppoi ht, bean ven#led for correctness or quality level at this Schlumberger -Private a,��„'i STATE OF ALASKA I �+ 6✓:,y.,,`� ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG {{� 'OiN P; 1a. well SmDEC ;4;.15�q93ry Gas ❑ SPLUG ❑ Other ❑ Abandoned m Suspended ❑ 20AAC 25.105 20MC 25.110 .,� GINJ ❑ T. pS tWAG [IWDSPL 11No. of Completions: Zero 1b. Well Class Development p Exploratory EI d Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or Abend.: 14. Permit to Drill Number/Sundry BP Exploration (Alaska), Inc 11/23/2019 210-132 319-043 3. Address: 7. Date Spudded: 15. API Number: P.O. Box 196612 Anchorage, AK 99519-6612 10/25/2010 50-029-23433-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: 11/12/2010 POU S-129 - Surface: 3645' FSL, 4103' fEL, Sec. 35, T12N, R12E, UM• Ref Elevations 9. KB 62.46 17, Field/Pool(s): Top of Productive Interval: 1612' FST, 3094' FEL, Sec. 34, T12N, R12E, UM GL 33.79 BF 35.77 PRUDHOE BAY, AURORA OIL Total Depth: 2347' FNL, 2690' FEL, Sec, 03, T11N, R12E, UM 10. Plug Back Depth(MDf VD): 18. Property Designation: -3110'/3045' , ADL 028257, 028258 & 028261 4b. 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth (MD/TVD): 19. DNR Approval Number: Surface: x- 619339 ' y- 5979855 Zone - ASP 4 12964'/6791' - 83-47 TPI: x- 615104 y- 5977756 Zone - ASP 4 12, SSSV Depth (MD/TVD): 20 Thickness of Permafrost MD/ D: Total Depth: x- 615376 y- 5973801 Zone - ASP 4 None 1900' (Approx.) 5. Directional or Inclination Survey: Yes ❑ (attached) No m 13. Water Depth, if Offshore: 21. Re-dnll/Lateral Top Window Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) MD/1VD: N/A 22. Logs Obtained List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, crabandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary GR, RES, NEU, AZI DEN, PWD, ABI, DEN Caliper, Periscope 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT. GRADE SETTINGDEPTHMD SETTINGDEPTHTVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP7 BOTTOM TOP BOTTOM 20" 129.45# x 29' 109' 29' 109' 42" -260sx Arctic Set 9-5/8" 40# L -so 29' 3295' 29' 3193' 12-1/4" 1220 sx Arctic Set Lite, 447 sx Class "G' 7" 269 L -so 26' 8875' 26' 6770' 8-3/4" 454 sx UteCrete, 223 sx Class 'G' 3-1/2" 9.2# L -so 8699' 12870' 6674' 6791' 6-1/8" Uncemented Slotted Liner 24. Open to production or injection? Yes ❑ No D 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perid): GRADE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 12.6# 13Cr80 3446' - 8710' 8631' / 6637- x 3-1/2" 9.2# 13Cr80 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. f DATE 2 �Y� Was hydraulic fracturing used during completions Per 20 AAC 25.283 (i)(2) attach electronic and printed � Yes No information Cry p -n, iJ',/(� fe�ya DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED , ` VERIFIES See Attached _CL---- 27. PRODUCTION TEST Date First Production: Not on Production Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Test Period -.11. Oil-Bhl: Gas -MCF: Water -Bbl: Choke Size Gas -Oil Ratio: Flow Tubing Press Casing Press: Calculated 24 Hour Rate �► Oil -Bbl: Gas -MCF: Water -Bbl' Oil Gravity- API(com: Forth 10-407 Revised 5/2017 CONTINUED ON PAGE 2 Submit ORIGINAL only o 0%00 N.e6C-TA+sz0 RBDMSLfo' DEC 312019 28. CORE DATA Conventional Core(s) Yes ❑ No 9 Sidewall Cores Yes ❑ No 0 If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Permafrost - Top Well Tested? Yes ❑ No 0 Permafrost - Base If yes, list intervals and formations tested, briefly summarizing test results. Attach Top of Productive Interval 8876' 6770' separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. Ugnu 3861' 3598' Schrader Bluff N 5813' 4943' Schrader Bluff O 5998' 5084' Base Schrader Bluff / Colville 6540' 5390' HRZ 8501' 6565' Kalubik 8845' 6754' Kuparuk C 8876' 6770' Kuparuk B 11270' 6842' Kuparuk C (Invert) 12290' 6800' Fomnation at total depth: Kuparuk C (From Base) 12290' 6800' 31. List of Attachments: Summary of Pre -Rig Work, Summary of Daily Drilling Reports, Wellbore Schematic Diagram Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070, 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Lastufka, Joseph N Contact Name: Minge, David Authorized Title: ecialis Contact Email: David.Minge@bp.com Authorized Signature: Date:'' 4 of I I I Contact Phone: +1 9075645279 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item la. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b. Well Class Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disp, Water Supply for Injection, Observation or Other. Item 4b. TPI (Top of Producing Interval). Item 9. The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20. Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28. Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30. Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production orwell test results. Form 10-407 Revised 512017 Submit ORIGINAL Only WELL NAME: S-129 26. Acid, Fracture, Cement Squeeze, Etc. Depth Interval (MD) Amount & Kind of Material Used 8667' Set PX Plug 6703' 46 Bbls Class'G' 3446' Cut & Pull Tubing 3155' Cut & Pull 7" Casing 3136 Set EZSV 3110' Set Whipstock T/I/O=SSV/1350/150, Temp=Sl. PPPOT-T (PASS), PPPOT-IC (PASS), DRLG screen. PPPOT-T: Stung into test port (1200 psi), bled void to 0 psi. Monitored for 10 min, no change in pressure. Functioned LDS, all moved freely, torqued to 450 Ib/ft. Pumped through void, good returns. 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. PPPOT-IC: Stung into test port (400 psi), bled void to 0 psi. Monitored for 10 min, no change in pressure. Functioned LDS, all moved freely, torqued to 450 Ib/ft. Pumped through void, good returns. Pressured void to 3500 psi for 30 min test, lost 0 psi in 15 min, 9/12/2019 llost 0 psi in second 15 min (PASS). Bled void to 0 psi. ***WELLS/] ON ARRIVAL***(drlg screen) RAN 3.70" CENTRALIZER, 3.70" GAUGE RING TO XO @ 4,083' MD FOR TBG CUTTER DRIFTED W/ 2.35" CENTRALIZER TO 8,700' SLM 10/9/2019 ***CONTINUE WSR ON 10/10/2019*** ***CONTINUE WSR FROM 10/09/2019*** (drlg screen) RAN SBHPS PER PROGRAM (good data) SET 3 1/2" X CATCHER IN X NIP @ 8,698' MD PULLED RK-OGLV'S FROM ST#1(8460' MD) PULL RK-LGLV FROM STA #3(6872' MD) & STA #5(4163' MD) SET RK-DGLV IN STA #5(4163' MD), STA #3(6872' MD) & STA #1(8460' MD) ATTEMPT TO PULL 3-1/2" X-LOCK CATCHER. RUN 20'x 2.25" PUMP BAILER W/ msfb TO 8677' SLM.(BAILER EMPTY) PULL 3-1/2" X-LOCK CATCHER FROM 8677' SLM 10/10/2019 ****CONT WSR ON 10-11-19**** T/1/0=1573/1695/214 Temp=Sl (LRS Unit 70 - Assist Slickline: Load & Test) Spear in to IA with 5 bbls of 25* 60/40 followed by 230 bbis of 120* crude to load IA. 10/10/2019 ***WSR continued on 10/11/19*** ****CONT WSR FROM 10-10-19****(drlg screen) LRS LOAD TBG W/ 160 BBLS CRUDE. ATTEMPT TO SET 3-1/2" PX PLUG IN X NIP AT 8698' MD. BRUSH NIPPLES WITH 3-1/2" BLB AND 2.805" GAUGE RING. MAKE SECOND ATTEMPT TO SET PX PLUG IN X NIP AT 8698' MD. SET 3-1/2" PX-PLUG BODY IN X-NIP @ 8667' MD. CHECK SET CONFIRMS SET 10/11/2019 ****CONT WSR ON 10-12-19**** ***WSR continued from 10/10/19*** (LRS Unit 70 Assist SL w/ Load & Test) Load Tubing w/ 2 bbls 60/40 meth followed by 160 bbls 65*F crude down TBG to load and kill for secure well. S-line on well on dep Wing shut swab open ssv open master open casing valves open to 10/11/2019 gauges Daily Report of Well Operations PBU S-129 ****CONT WSR FROM 10-11-19****(drlg screen) SET P -PRONG @ 8698' MD. LRS MIT -T TO 3000 psi PASS **see LRS for dptailc** SET 3-1/2" WHIDDON CATCHER @ 8640' SLM. PULL RK-DGLV FROM STA #1(8460'MD) LRS PERFORM CMIT-T x IA TO 2500 psi PASS **see LRS for details. PULL 3-1/2" WHIDDON CATCHER FROM 8640' SLM. LRS PERFORMED 2000 PSI PRESSURE TEST OF OA (PASS). ***WELL TURNED OVER TO DSO*** 10/12/2019 *****GLM #1 OPEN POCKET***** T/1/0= 50/vac/vac Temp= S/1 (LRS Unit 70 - Assist Slickline: MI -T, CMIT-TxIA, OA Integrity Test) MIT -T PASSED to 3309 psi, Target Pressure= 3000 psi, Max Applied Pressure= 3500 psi. Pressured TBG to 3492 psi with 2.75 bbls crude. TBG lost 135 psi in 1st 15 minutes and 48 psi in 2nd 15 minutes, for a total loss of 183 psi during 30 minute test. Bled back TBG, returned —2 bbls CMIT-TxIA PASSED to 2554/2616 psi, Target Pressure= 2500 psi, Max Applied Pressure= 2750 psi. Pressured TxIA to 2676/2743 psi with 23 bbls crude. TxIA lost 98/101 psi in 1 st 15 minutes and 24/26 psi in 2nd 15 minutes, for a total loss of 122/127 psi during 30 minute test. Bled back pressure, returned —5 bbls. Freeze Protected F/L with 4 bbls of 60/40 followed by 36 bbls of Crude. DSO shut inlet and PSI up F/L to 1500 psi. OA Integrity test PASSED. Pumped 1.5 bbls of Crude down OA to verify integrity. Pressured OA to 2000 psi and held for 5 Min. No leaks at surface detected. 10/12/2019 Slickline in control of well upon departure. T/1/0= 80/100/127 Assist SLB cement job (SIDETRACK) Pumped 5 bbls 60/40 spear followed with 221 bbls 60* fresh water down TBG taking returns up IA to S-27 FL, ***WSR 10/24/2019 Continued on 10-25-19*** SLB Cementing Services Job Scope: Balanced Cement Plug P&A. LRS pumping down tbg taking returns from the IA to S-27 flowline: 5 bbls meth spear, 220 bbls of FW away. 10/24/2019 Continue on next day WSR. SLB Fullbore Cementing - TxIA Cement Balance Plug (Sidetrack) LRS pumped 64 bblc (total of 284 bbls of FW) and 160 bbls of 9.8 ppg NaCl. SLB cmenters pumped 5 bbl FW spacer, 46 bbls of 15.8 ppg Class G Cemnet, 2 bbls of FW. Launch (2) 7" foam balls with 5 bbls of FW. LRS pumped 74 bbls of 9.3# NaCL and 17 bbls of diesel. U- tube in Freeze protect to IA. Freeze protect S-27 Flowline. Grease crew serviced the tree valves. Job Complete. Est TOC in Tx IA 7160' MD / 5773' TVD 10/25/2019 Est BOC in Tx IA 8460' MD / 6553' TVD ***WSR Continued from 10-24-19*** Temp= S/I Assist SLB w/ cement (SIDE TRACK) Pumped 63 bbls (total of 284 bbls) 60* fresh water, 160 bbls 80* 9.3 brine down TBG taking returns up IA to S-27 FL SLB pumped 46 bbls cement followed with 7 bbls fresh water, Pumped 74 bbls 70* 9.3 brine followed with 17 bbls diesel, U-tube for 1 hour to put FP in place 10/25/2019 1 Pumped 3 bbls 60/40 followed with 19 bbls crude down FL of S-27 for FL FP Daily Report of Well Operations PBU S-129 ***WELL S/I ON ARRIVAL*** (Sidetrack) BRUSHED WELLHEAD/BPV PROFILE FOR 30 mins W/ 4-1/2" BRUSH & 3.25" GAUGE RING. DRIFTED TO XO AT 4070' SLM / 4083' MD WITH 3.70" CENT & 2.50" SAMPLE BAILER. TAGGED TOC @ 6698' SLM W/ 2.50" CENT & 1-3/4" SAMPLE BAILER (recovered sample of wet cement). 11/5/2019 RAN READ MITT PER PROGRAM. T/1/0=285/0/130 Temp=ST Assist SL (SIDE TRACK) CMIT-TxIA **STATE AOGCC*** to 3559/3500 psi ***PASSED***, Max Applied Pressure=3750 Target Pressure=3500 psi. Pressured T/IA to 3700/3729 psi with 2.2 bbls DSL. CMIT-TxIA lostl1/25 psi in 1st 15 minutes and 11/20 psi in 2nd 15 minutes for a total of 22/45 psi during 30 minute test. Passed by S -Line WSL and State witness Bled TBG/IA to 35/57 psi. 11/6/2019 SL in control of well upon departure. CV's OTG AFE sign on MV ***FLUID PACKED ***JOB CONTINUED FROM 05-NOV-2019***(sidetrack) RAN 2.50" CENT & 1-3/4" SAMPLE BAILER TO TAG TOC @ — 6703' SLM (aogcc witnessed, recovered cement sample). LRS PERFORMED PASSING CMIT-TxIA to 3500 psi (aogcc witnessed, see Irs log). 11/6/2019 ***WELL S/I ON DEPARTURE, PAD -OP NOTIFIED OF WELL STATUS*** T/I/O = 100/340Nac. Temp = SI. Inflow Test PASSED (pre rig). ALP = 0 psi, blinded @ CV. TBG & IA FLs @ surface. Bled TP to BT from 100 psi to 0 psi in 6 min (0.10 bbls), IAP decreased 10 psi. Monitored for 30 min. No observable flow detected during monitor. Bled IAP to BT from 330 psi to 10 psi in 6 min (0.10 bbls), TP went on a Vac. Monitored for 30 min. WHPs unchanged. Final WHPs = Vac/10/Vac. 11/8/2019 ISV, WV, SSV = C. MV = O. IA, OA = OTG. 23:15 ***WELLS SHUT-IN ON ARRIVAL***Qet cut) RU HES ELINE UNIT 4836 11/8/2019 ***CONTINUE ON 11/9/2019 WSR*** ***CONT FROM 11/8/2019***(tubing cut) CUT TUBING W/ 3.625" JET CUTTER AT 3446', CCL TO CUTTER OFFSET: 5.8', CCL STOP DEPTH: 3440.2'. CORRELATE TO TUBING JOINTS ON READ CH MITT LOG DATED 5-NOV-2019 FOR CUTTER. 11/9/2019 ***WELL SHUT IN, TURN OVER TO DSO*** T/1/0=30/40/0 temp=Sl (LRS Unit 46 - CMIT-TxIA Post Jet Cut) Spotted equipment/Rigged 11/12/2019 up/ Pressure tested. *** WSR continued on 11/13/19 *** *** WSR continued from 11/12/19 *** (LRS Unit 46 - CMIT-TxIA Post Jet Cut) CMIT-TxIA **PASSED**(TEST #3) to 3647/3693 psi Max Applied Pressure=3750psi Target Pressure=3500 psi. Pressured T/IA to 3686/3733 psi with 3.2 bbls of diesel. CMIT-TxIA lost 22/22 psi in 1st 15 minutes and 17/18 psi in 2nd 15 minutes for a total of 39/40 psi during a 30 min test. Bled T/IA to 0/0 psi recovering — 3 bbls. SV/SSV/WV= Closed MV=Open CV's=OTG Tags hung on well 11/13/2019 FWHP's=0/0/0 TWO = 0/0/0. RU Piggyback to IA, PT'd 350/3500 PSI (Pass) Charted and Retained. RU Piggyback to OA, PT'd 350/3500 PSI (Pass) Charted and Retained. Set 4" H BPV #143 @125" w/ Lubricator 840. RD Upper tree, RU Temp to MV, PT'd 350/5000 PSI (Pass) Charted and Retained. Pulled 4" H BPV #143 @ 85". RDMO. ***Job Complete***. MV=O, SV=C, IA/OA=OTG. 11/14/2019 Daily Report of Well Operations PBU S-129 T/1/0= 100/100/0 Set 4" HP BPV w Dart to make it a TWC. PT 350/3500psi (PASS). ***Job 11/14/2019 complete*** ****See log for details.**** T/110 = BPV/7010+. Temp = SI. Bleed WHPs (pre RIG). No wellhouse, scaffolding, AL, or flowline. Dryhole tree installed. IA FL @ surface. OA FL @ surface. Bled OAP to BT from 0+ psi to 0 psi in 1 minute (all gas). Bled IAP to BT from 70 psi to 0 psi in 3 minutes (all fluid, <.25 bbls). Monitor for 30 minutes. Final WHPs = BPV/010. 11/16/2019 SV = C. MV = O. IA, OA = OTG. 15:45 T/I/O = BPV/3/1. Temp = SI. WHIPS (post bleed). No wellhouse, flowline, AL, or scaffolding. Dryhole tree installed. IAP increased 3 psi and OAP increased 1 psi overnight. 11/17/2019 SV = C. MV = O. IA, OA = OTG. 14:00 Printed 12/16/2019 12:06:07PM **All dephts reported in Drillers Depths** North America - ALASKA - BP Page 1 CA, Operation Summary Report Common Well Name: S-129 AEE No Event Type: RE-ENTER- ONSHORE(RON) Start Date: End Date: 12/8/2019 H-S4DW092443-EX-D1-DN-(5,908,452.00) Project: PBU Site: S 1 Rig Name/No.: PARKER 272 1 Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: Rig Contractor. PARKER DRILLING CO. I BPUOI: USA00000153 Active datum: ACTUAL KB P272 @81.47usft (above Mean Sea Level) Date From - To His Task j Code I NPT Total Depth Phase ! Description of Operations 1 (hr) (usft) 17/79/2019 14:00 - 15:30 1.50 MOB P 0.53 PRE PJSM SKID RIG FLOOR -PREFORM PRE SKID CHECK LIST j15:30 - 16:30 1.00 MOB P 0.53 PRE PJSM LAY DERRICK OVER ON I- PREFORMUPBARRICADES I - SET UP BARRICADES IN FRONT OF RIG IN FRONT — I- LAY MAST OVER = 380K ON RACK 16:30 - 19:00 2.50 MOB P 0.53 PRE MOVE RIG FROM S-202 TO S-129 -WARM HYDROUCS I-SPLITMODULES 19:00 19:30 _ - MOVE MODULES TO - 0.50 MOB P53 PRE PICKUP TREE, ADAPTER FLANGE PRIOR TO 1,19:30 - 22:00 2.50 _ MOB P 0.53 PRE SPOTTING OVER WELL S O ULES I -FUNCTION ESTOPS PRIOR TO SPOTTING OVER WELL - RIG UP UTILITY MOD PIPE SHED AND INTER ! ! .CONNECT '- RIG UP MUD MOD PIPE SHED AND INTER _CONNECT ;122.00 - 00:00 ! 2.00 O P : 0.53 PRE PLUG IN MODULES -RAISE DERRICK =508K OFF RACK -SKID RIG FLOOR - RIG UP MAN RIDERS - BUTTON UP HAUNCH - INSTALL FLOW LINES 11/20/2019 10000 - 02:30 2.50 RIGU P 1 0.53 PRE GENERAL RIG UP OPERATIONS .-CONNECT MM -DM &UM -DM INTERCONNECT LINES - CALIBRATE TOTCO - SPOT CUTTINGS BIN - CONNECT WATER, AIR, STEAM TO RIG 1 FLOOR __ 02 30 0530 3.00 ,.— - RIGU P 0.53 PRE ACCEPT RIG AT 02:30 HRS GENERAL RIG UP OPERATIONS - INSTALL HIGH PRESSURE MUD & CEMENT JUMPER HOSES ON RIG FLOOR 1 -TIGHTEN 1502 STANDPIPE AND KELLY HOSE UNIONS I- BRIDLE DOWN, HANG BRIDLE LINES, CONNECT BLOCKS TO TOP DRIVE - CALIBRATE DRAWWORKSAMPHION SYSTEM '. i- RIG UP TONGS, OFFLINE MOUSE HOLES, INSTALL ROOF WALKWAYS -TABLE TOP H2S/RIG EVACUATION DRILL Printed 12/16/2019 12:06:07PM **All dephts reported in Drillers Depths** Printed 12/18/2019 12:06:07PM **All dephts reported in Drillers Depths** North America - ALASKA - BP Page 2 00A.' Operation Summary Report Common Well Name: 5-129 AFE No Event Type: RE-ENTER- ONSHORE (RON) i Start Date: End Date: 12/8/2019 H-S4DW092443-EX-D1-DN- (5,908,452.00 ) Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 10/25/2010 12:00 OOAM Rig Release: Rig Contractor: PARKER DRILLING CO. BPUOI: USA00000153 Active datum: ACTUAL KB P272 @81.47usR (above Mean Sea Level) Date From -To Him Task Code NPT ! Total Depth Phase Description of Operations 05:30 - 10:00 4.50 WHSUR Pt 0.53 1 PRE NIPPLE DOWN TREE FMC WELLHEAD BLEEDADAPTER VOIDAND EVACUATE (TREE '- NIPPLE DOWN TREEAND REMOVE FROM IWELLOUSE I- TERMINATE I-WIRE ! - DRY RUN TCII x 4 1/2" IF XO: 6 1/2 TURNS NIPPLE UP ADAPTER FLANGE ON WELLHEAD TUBING SPOOL - C/0.13 5/8" RISER SECTIONS FOR CORRECT LENTH SIMOPS: '.- TAKE ON FLUID IN THE PITS ._ 1.50 BOPSUR P0.53 PRE -M/U VALVES 87"TJ FOR BOP TEST NIPPLE UP RISERS AND BOP STACK 11:30 SET BOP STACK ON RISERAND TQ FLANGE ! - INSTALL BELL NIPPLE :- CHANGE OUT UPPER 27/8"X5"VBR TO 1/2"X7"VBR - �' _ _-TORQUE --f—_T- FLANGES 11:30 - 73:30 2.00 BOPSUR P 80.53 PRE RIG UP TO TEST BOP AND CKOKE -RIG UP 7" TJ AND WELL CONTROLVALVES PER TEST PROCEDURE � ! _ __ ! �-FILL LINES AND PURGE AIR 13:30 - 18.30 5.00 BOPSUR P 0.53 PRE I TEST BOPE TO 250 PSI LOW, 3500 PSI HIGH FOR 5 MINUTES EACH - -TEST WITH 4", 4.5".5" AND 7"TESTJOINTS i- TESTED ALARMS,PVT AND FLOWSHOW I- PREFORM BLACK OUT AND ACCUMULATOR TEST - TEST WITNESS WAIVED BYAOGCC REP �. t �, _ GUY COOK 18 30 - 18:00 eOPSUR P j 0.53 DECOMP I RIG DOWN TEST EQUIPMENT 1.00 __--BLS OWDOWN CHOKE AND KILL LINES 2000 119:00 - BOPSUR P 0.53 DECOMP HOLD RIG E-VAC DRILLAND PRE SPUD WITH 2.00 WHSUR P 5 DECOMP !RIG CREW RIG UP TO PULL HIGH PRESSURE BPV WITH -2000 - 22 OOJ T-BAR -DRAIN STACK I,- PULL BPVAND DARTAS PER FMC REP WITH i ITBAR I SIMOPS: - BUILD 4" DP STANDS UTILIZING OFF -LINE STAND BUILDING EQUIPMENT 122:00 - 22:30 0.50 WHSURP 3,446.53 DECOMP RIG UP AND ROCK OUT FREEZE PROTECT "- PUMP 15 BBL DOWN IA: 8 BPM, 1700 PSI j - PUMP 30 BBL DOWN TBG: 8 BPM, 1700 PSI !.-BLOW DOWN LINES '.. SIMOPS: - BUILO 4" DP STANDS UTILIZING OFF -LINE STAND BUILDING EQUIPMENT Printed 12/18/2019 12:06:07PM **All dephts reported in Drillers Depths** North America - ALASKA - BP Page 3at^ Operation Summary Report Common Well Name S-129 - - - - - - _ AFE No - --- Event Type: RE-ENTER- ONSHORE(RON) Start Date: , End Date: 12/812019 IH-S4DW092443-EX-DI-DN-(5,908,452.00) --__ Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: Rig Contractor: PARKER DRILLING CO. BPUOI: USA00000153 Active datum: ACTUAL KB P272 @81.47usft (above Mean Sea Level) _Date From - To Him Task hr) Code ! NPT Total Depth (usH) Phase I Description of Operations 122:30 - 23:30 I 1.00 CEMT P 3,446.53 DECOMP — _ PULL4-1/2"TBG FROME-LINE CUT AT 3446' MD i I- M/U LANDING JTAND SCREW INTO HANGER BACK OUT LOCK DOWN SCREWS - PULL HANGER TO RIG FLOOR = PULLED j13K jSIMOPS: - BUILD 4" DP STANDS UTILIZING OFF-LINE STAND BUILDING EQUIPMENT TEST BACK SIDE OF CHOKE VALVES 23:30 - 00:00 0.50 WHSUR P -_- ! 3,446.53 DECOMP CIRCULATE SOAP PILL SURFACE TO 'SURFACE 420 GPM, 500 PSI 11/21/2019 00:00 05:30 5.50 CASING P _ 3,446.53 DECOMP PULLOUT OF THE HOLEAND DOWN 41/2 VAM TOP TUBING WITH I -WIRE FROM 3446' MD TO SURFACE - PU 65 KLBS, SO 65 KLBS AT 2900' MD ..05:30 i -RECOVERED: 81 FULL JOINTS, 1 CUT JOINT 37.13' FLARE 5 3/16", 1 X NIPPLE JT, 1 10' PUP, - 06:30 1.00 CASING P __43 CLAMPS 3,446.53 DECOMP RIG DOWN TUBING HANDLING EQUIPMENT - RIG DOWN DOYON CASING EQIPMENT - RIG DOWN SPOOLING UNIT - CLEAN & CLEAR RIG FLOOR INSTALL WEAR RING 7" ID 3,448.53 DECOMP RIG UP SLB E -LINE TO PERFORM IBC LOG 106:30 - 09:00 2.50 CASING p - - BRING E -LINE TOOLS TO RIG FLOOR - RIG UP E -LINE SHEAVES III - MAKE UP HEAD TO RUNNING TOOLS 09:003,446,53 � 4.50 CASING P - SIMOPS: - BUILD STANDS OF 4" DP WITH OFF-LINE STAND BUILDING EQUIPMENT 3,446.53 DECOMP LOG 7" CASING WITH SLB E -LINE -RUN JUNK BASKET &6.13"GAUGE RING ON I., E -LINE - RUN E -LINE IBC/CCL LOG OF 7" ! 'SIMOPS: - X13:30 - 14:30 1.00 CASING P — — BUILD STANDS OF 4" DP WITH OFF-LINE STAND BUILDING EQUIPMENT 3,446.53 DECOMP 'RIG DOWN E- LINE PER SLB .__ _ _.._....._._. —.i ' ! I 'REPRESENTATIVE SEND TOOLS OUTAND CLEAN AND CLEAR ..._. _ _ _ RIG FLOOR -1430 - 17:00 2.50 CASING P + 3,446.53 DECOMP MAKE UP AND RUN IN THE HOLE WITH : CASING CUTTER ASSEMBLY DRESSED TO - I CUT 7"CASING -T03105'MID ! - PU 83 KLBS, SO 82 KLBS - 17:00 - 18:30 1 1.50 L CASING P _ _ BRINE WEIGHT IN/OUT= 9.3 PPG 3,446.53 �DECOMP REVIEW IBC LOG AND MTT LOG WITH ODE AND ATTEMPT TO LOCATE COLLAR AT 3174' ! -MD WITH KNIVES ON CUTTER 97 GPM, 380 PSI UNABLE TO LOCATE COLLAR BETWEEN 3185' 11 MD AND 3170'MD CONTINUE TO RUN IN THE HOLE AND TAG TUBING STUBAT3466' MD WITH 8 KLBS Printed 12/18/2019 12:06:07PM **Ali dephts reported in Drillers Depths** North America - ALASKA - BP Page 4 gjyr Operation Summary Report Common Well Name'. S-129 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: End Date. 12/8/2019 iH-S4DW092443-EX-DI-DN-(5,908,452.00) Project: PBL Site: S Rig Name/No.: PARKER 272 Spud DaterTime: 10/25/2010 12:00:00AM Rig Release: Rig Contractor: PARKER DRILLING CO. BPUOI: USA00000153 Active datum'. ACTUAL KB P272 @Bt47usft (above Mean Sea Level) Date From - To Mrs Task Code NPT Total Depth Phase Description of Operations 18:30 - 19:30 1.00 ! CASING P 1 1 3,446.53 DECOMP PICK CUPTO CUT DEPTH OF 3143' MD AND CUT 7" CASING - 60 RPM, 2 KFT-LBS TORQUE I I j-3 BPM, 535 PSI OBSERVE POSITIVE INDICATION OF CUT ON OAAFTER 6 MIN, CONTINUED TO TURN ON ''. CUT FOR 20 MIN 1 - PRESSURE ON OA INCREASED SLOWLY TO X250 PSI I '-FINAL CIRCULATING CULATING PRESSURE ON IA: 160 IPSI 'I- TORQUE SMOOTHED OUT AND DECREASED TO 1.8 KFT-LBS '- MONITOR WELL FOR 10 MIN: STATIC SIMOPS: -BUILD STANDS OF 5" DP UTILIZING ---III OFF -LINE STAND BUILDING EQUIPMENT__ - 20:30 1 1.00 CASING P 3,446.53 DECOMP ATTEMPTTO CIRCULATE OUT FREEZE 119:30 PROTECT IN THE 7'X 9 5/e ANNULUS PRESSURE UP TO 600 PSI WITH NO CIRCULATION --SHUT DOWN AND VERIFY LINE UP; NO ISSUES PRESSURE UP TO 1000 PSI WITH NO CIRCULATION -BLOW DOWN LINES 'SIMOPS: j - BUILD STANDS OF 5" DP UTILIZING OFF -LINE STAND BUILDING EQUIPMENT 2030.- 21:00 0.50 i CASING P 3,446.53 DECOMP PICK UP T03142'MD AND ATTEMPT TO j RE-CUT 7" CASING ! - 60 RPM, 2 KFT-LBS TORQUE - - 3 BPM, 535 PSI - PRESSURE ON OA INCREASED TO 300 PSI IMMEADIATELY - FINAL CIRCULATING PRESSURE ON [A 335 PSI li - BRINE WEIGHT IN/OUT= 9.3 PPG - MONITOR WELL FOR 10 MIN: STATIC SIMOPS: - BUILD STANDS OF 5" DP UTILIZING t OFF -LINE STAND BUILDING EQUIPMENT 21:00 - 23:30 2.50 CASING P 1 3,446.53 DECOMP 'ATTEMPT TO CIRCULATE OUT FREEZE PROTECT IN THE T'X 9 5/8" ANNULUS - SLOWLY STAGE PUMP TO 3 BPM, 1560 PSI - PUMP SOAP PILL SURFACE TO SURFACE i - BRINE WEIGHT IN/OUT= 9.3 PPG SIMOPS: - BUILD STANDS OF 5" DP UTILIZING Printed 12/18/2019 12:06:07PM **All dephts reported in Drillers Depths" North America - ALASKA - BP Page s! Operation Summary Report Common Well Name: S-129 AFE No Event Type: RE-ENTER- ONSHORE(RON) .Start Date: End Date. 12/8/2019 H-S41DW092443-EX-DI-DN-(5,908,452.00) Project PBUte'. S Rig Name/No.: PARKER 272 Spud Date/Time: 10/25/2010 12:00:OOAM Rig Release: Rig Contractor. PARKER DRILLING CO. BPUOi: USA00000153 Active datum: ACTUAL KB P272 @81.47usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth. Phase Description of Operations (hr)—rt_ j j (usft) 123:30 - 00:00 0.50 1 CASING P 3,448.53 DECOMP . PULLOUT OF THE HOLE ON ELEVATORS WITH 7" CASING CUTTER ASSEMBLY FROM 3140' MD TO 2540' MD MONITOR WELL FOR 10 MINUTES PRIOR TO PULLING OFF BOTTOM: STATIC PU 83 KLBS, SO 83 KLBS AT 31 00'MD - - BRINE WEIGHT IN/OUT= 9.3 PPG - MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE PULLING: GOOD FILL SIMOPS: -BUILD STANDS OF 5" Did UTILIZING _-11— I OFF -LINE STAND BUILDING EQUIPMENT 11/22/2019 0000 01:30 1.50 CASING I P ! 3,446.53 DECOMP I CONTINUE TO PULL OUT OF THE HOLE ON ELEVATORS WITH 7" CASING CUTTER ASSEMBLY FROM 2540' MD TO SURFACE -BRINE WEIGHT IN/OUT=9.3 PPG - MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE PULLING: GOOD FILL - GOOD INDICATION OF CUT ON CUTTER BLADES 101.30 - 03:00 1.50 WHSUR Id 3,446.53 DECOMP PULL 7" CASING PACK-OFF PER FMC - 1 REPRESENTATIVE '– PULL WEAR RING AND LAY DOWN - FMC REPRESENTATIVE BACK OUT LOCKDOWN SCREWS, NO SIGNS OF CASING GROWTH ENGAGE PACK OFF AND PULL TO RIG !„FLOOR: PULLED FREE WITH 7 KLBS 1,03:00 - 06:30 3.50 CASING P 1 '�. 3,446.53 DECOMP ' ATTEMPTTO PULL?"CASING - MAKE UP 7" CASING SPEAR WITH PACK-OFF I PER SLB FISHING REPRESENTATIVE 1 ! - ENGAGE SPEAR IN 7” CASING - STRAIGHT PULL UP TO 190 KLBS OVER IN 10 KLBS INCREMENTS - STAGE UP PUMPS TO BPM: ICP 1220 PSI, FCP 605 PSI - INCREASE RATE TO 8.5 BPM, 1275 PSI AS HOLE CLEANED UP 0630 - 07:00 0.50 CASING P 3,44fi.53 DECOMP MAKE UP JARS AND ACCELERATOR TO SPEARASSEMBLY -DIS-ENGAGE SPEARAND PULLTO RIG 1. FLOOR - MAKE UP ACCELERATOR AND JARS TO '.. ASSEMBLYAND RE-ENGAGE 7" CASING WITH SPEAR 07:00 - 11:00 4.00 CASING P 3446.53 DECOMP JAR 7" CASING FREE - JAR 100-125 KLBS OVER AND STRAIGHT PULL UP TO 190 KLBS OVER - PULL UP TO 185 KLBS OVER AND LET SIT -AFTER ^30 MIN, STRING BEGAN TO MOVE UP HOLE - PULL HANGER TO THE FLOOR WITH 185 'KLBS OVERPULL - BREAK OFF AND LAY DOWN HANGER Y -' '-ENGAGE SPEAR INTO 7" CASING 1100 - 12:00 1.00 CASING P 3,446.53 DECOMP ATTEMPT TO CIRCULATE THROUGH SPEAR I- 1 BPM, PRESSURE UP TO 1200 PSI - WORK PIPE STRETCH WHILE STAGING UP _--_ -- PUMP Printed 12/18/2019 12:06 07PM **All dephls reported in Drillers Depths** Printed 12/18/2019 12:06:07PM "All dephts reported in Drillers Depths`" North America -ALASKA - BP Page 6 Operation Summary Report Common Well Name. 5-129 AFE No Event Type'. RE-ENTER- ONSHORE (RON) Start Date End Date: 12/8/2019 IH-S4DW092443-EX-D1-DN- (5,908,452,00) Project: PBU Site: S Rig Name/i PARKER 272 Spud Date/Time: 10/25/2010 12:00 OOAM Rig Release: Rig Contractor: PARKER DRILLING CO. BPUOP USA00000153 Active datum: ACTUAL KB P272 @81 47usft (above Mean Sea Level) Date From - To Has Task Code NPT Total Depth 1 Phase Description of Operations (hr) _ Waft) i 12:0—r 0 - 73:007.00 CASING P _ 3,446.53 DECOMP LAV DOWN SPEARASSEMBLY PER SLB FISHING REP - CHANGE OUT ELEVATORS TO 7" SIDE j DOORS !, SIMOPS: i BUILD STANDS OF 5" DP UTILIZING STAND BUILDING -LINE EQUIPMENT 14:30 1.50 CASING P 3,446.53 DECOMP PULL AND LAY DOWN 7" CASING FROM 3100' MD TO 2975'MD SWABBING WHILE PULLING 3 JTS. 1- PU 165 KLBS, SO 85 KLBS AT 3000' MD ' MAKE UP HEAD PIN AND ATTEMPT TO 1 CIRCULATE AT -29751 MD r STAGE PRESSURE UP TO 1000 PSI -WORK JT SEVERAL TIMES 14:30 15:00 0.50 CASING P--—.3,446.53 DECOMP CIRC 1.5X BOTTOMS UP - STAGE UP TO 10 BPM, 775 PSI II- BRINE WEIGHT IN/OUT= 9.3 PPG !-WELL UNLOADEDAT BOTTOMS UP WITH I SIGNIFICANT AMOU NT OF SOLI DS 15:00 - 15:30 ' 0.50 CASING P 3,446.53 DECOMP TPULL AND LAV DOWN 7"CASING FROM 2975' '.I MD TO 2767' MD PU 108 KLBS, SO 90 KLBS AT 2800'MD SWABBING WHILE PULLING SJTS. 15:30 - 16:00 0.50 1 CASING i P 3,446.53 DECOMP CIRC 1.5X BOTTOMS UP -STAGE UP TO 10 BPM, 530 PSI - BRINE WEIGHT IWOUT=9.3 PPG - MINIMALAMOUNT OF SOLIDS AFTER BOTTOMS UP 20:00 4.00 CASING P 3,446.53 DECOMP PULLAND LAY DOWN 7" CASING FROM 2767' MD TO SURFACE - PU 98 KLBS, SO 90 KLBS AT 2700' MD -BRINE WEIGHT IN/OUT=9.3 PPG . - MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE PULLING: GOOD FILL. - LAY DOWN A TOTAL OF 75 FULL JOINTS AND { 1CUT JOINT OF 7" CASING 20:00 20:30 0.50 CASING P 1 3,446.53 DECOMP RIG DOWN CASING TOOLSAND CLEAR RIG FLOOR 120:30 - 21:00 0.50 CASING P 1 3,446.53 DECOMP PERFORM POST -JARRING DERRICK �INSPECTION .21:00 - 21:30 _ 0 50 CASING P 3,446,53DECOMP CHANGE SAVER SUB FROM HT -38 TO NC50 22:00 I 0.50 WHSUR P i, I 3,446.53 ', DECOMP INSTALL 10" ID WEAR RING 122:00 - 22:30 0.50 WHSUR P 3,446.53 DECOMP SERVICE TOP DRIVE AND RIG FLOOR __'22 �— �....._—t-_.._.�— _ .-_ ._—i EQUIPMENT 22'30 - 00:00 1.50 CLEAN P 3,448.53 WEXIT MAKE UP 8-1/2" CLEANOUT ASSEMBLY PER j ISLE FISHING REPAND RUN IN THE HOLE TO 417' MD -8-1/2" BIT, BIT SUB, 8-1/2" WATERMELLON MILL, 4' EXTENTION, 8-1/2" STABILIZER, JARS, (9) DRILL COLLARS, (21) 5" HWDP - PU 70 KLBS, SO 70 KLBS • - BRINE WEIGHT IN/OUT= 9.3 PPG - MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD ._. _. ;DISPLACEMENT Printed 12/18/2019 12:06:07PM "All dephts reported in Drillers Depths`" North America - ALASKA - BP Page 7 ` bil Operation Summary Report Common Well Name: S-129 AFE No Event Type: RE-ENTER- ONSHORE (RON) Start Date. End Date: 12/8/2019 H-S4DW092443-EX-D1-DN- (5,908,452.00 ) ! Project: PBU Site: S ' Rig Name/No.: PARKER 272 Spud Dale/Time: 10/25/2010 12:00:00AM Rig Release'. Rig Contractor: PARKER DRILLING CO. BPUOI: USA00000153 Active datum: ACTUAL KB P272 @81.47usft (above Mean Sea Level) Date From - To Hrs Task Code I NPT - Total Depth Phase Description of Operations (hr) _ (usft) +i 11/23Y1019 00:00 - 02:30 2.50 CLEAN P 3,446.53 WEXIT RUN IN THE HOLE WITH 8-1/2" CLEANOUT ASSEMBLY FROM 417' MD TO TOP OF 7" � ! CASING STUB AT 3155' MD ISI - TAG TOP OF 7" STUB AT 3155' MD WITH 8 KLBS - BRINE WEIGHT IN/OUT= 9.3 PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD - 03'30 1.00 102:30 ! CLEAN P 3,446.53 DISPLACEMENT _ WEXIT CIRCULATE 2X BOTTOMS UP - 625 GPM, 1270 PSI - 60 RPM, 3.5 KFT-LBS TORQUE - BRINE WEIGHT IN/OUT= 9.3 PPG '.- CIRCULATE 35 BBL HIGH -VIS SWEEP MINIMAL SOLIDS BACK WITH SWEEP 03:30 - 05.00 1.50 CLEAN P 3,446.53 WEXIT PULLOUT OF THE HOLE WITH CLEAN OUT I', ASSEMBLY FROM 3155 MD TO 300 MD - MONITOR WELL FOR 10 MIN PRIOR TO ! PULLING OFF BOTTOM: STATIC -BRINE WEIGHT IN/OUT= 9.3 PPG - MONITOR WELLWITH HOLE FILLAND TRIP TANK WHILE PULLING OUT: GOOD FILL 05:00 - 07:00 2.00 WHIP P I 1 3,446.53 WEXIT LAY DOWN CLEAN OUTBHA PER SLB FISHING REP FROM 300' MD CLEAN & CLEAR FLOOR BRING EZSV & RUNNING TOOL TO RIG FLOOR 07:00 09:30 1 2.50 WHIP P 3,446.53 WEXIT RUN IN THE HOLE WITH 9-5/8" EZSV TO 3136 MD' SET DEPTH - TAG 7" STUMP AND PICK UP 16' TO 3136' MD - SET EZSV PER HALLIBURTON PACKER Ili HAND - PU 114 KLBS, SO 106 KLBS AT 3136' MD - BRINE WEIGHT IN/OUT= 9.3 PPG — MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT 09:30 - 11:00 1.50 WHIP P 3,446.53 WEXIT PULL OUT OF THE HOLE WITH EZSV RUNNING TOOL FROM 3136' MD TO SURFACE '- MONITOR WELL FOR 10 MIN PRIOR TO PULLING OFF BOTTOM: STATIC - BRINE WEIGHT IN/OUT= 9.3 PPG - MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE PULLING OUT: GOOD FILL 111:00 __ _ ------ 12:30 Y T 1.50 WHIP P 3,446.53 ! WEXIT iPRESSURE TEST 9-5/8"CASINGTEOMINEZSV I ! PLUG TO 3500 PSI FOR 30 CHARTED MIN I- PURGEAIR FROM LINES LOST 15 PSI IN FIRST 15 MIN, 5 PSI IN SECOND 15 MIN -4.2 BBLS TO PRESSURE UP, BLED BACK 4.2 ! BBLS TEST MET BP TESTING CRITERIA PER BP PRACTICE 100218 '- TEST APPROVED BY ACTING WELLS 1230 - 13:00 ! 0.50 �� WHIP P 3,446.53 WEXIT l LSUPERINTENDENT SERVE AND RIG FLOOR (EQUIPMENT Printed 12/18/2019 12:06:07PM **All dephts reported in Drillers Depths** Printed 12/18/2019 12:06:07PM **All dephts reported in Drillers Depths** North America - ALASKA- SP Page 8 of7d Operation Summary Report Common Well Name: 5-129 AFE No Event Type: RE-ENTER- ONSHORE (RON) Start Date'. End Date: 12/8/2019 'H-S4DW092443-EX-Di-DN- (5,908,452.00 ) Project: PBU – ----- - - Site: S� Rig Name/No.: PARKER 272 Spud Date/Time: 10/25/2010 12:00:OOAM Rig Release' Rig Contractor. PARKER DRILLING CO. BPUOI: USA00000153 Active datum: ACTUAL KB P272 Q81.47usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations 13:00 - 16:00 3.00 T WHIP P 3,446.53 WEXIT MAKE UP AND RUN IN THE HOLE WITH WHIPSTOCKAND MILLING BHA PER SLB FISHING REP / BAKER MWD -SCRIBE WHIPSTOCKAND MWD '- SHALLOW HOLE TEST MWD TOOLSAT 1000'' j 550 GPM, 880 PSI - PU 92 KLBS, SO 90 KLBS li -BRINE WEIGHT IN/OUT =9.3 PPG - MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD (DISPLACEMENT 16:00 - 17:30 1.50 WHIP P 3,446.53 WEXIT RUN IN THE HOLE ON ELEVATORS WITH 8.5' WHIPSTOCKAND MILLING BHA FROM 1000' MD TO 3031' MD FILL PIPE EVERY 2000' MD ';- PU 132 KLBS, SO 122 KLBS AT 3000'MD - BRINE WEIGHT IN/OUT= 9.3 PPG '- MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD — ,DISPLACEMENT :17:30 - 18:00 0.50 _ WHIP P 1T 3,446.53 WEXIT _ I ORIENT AND SET WHIPSTOCK PER BAKER DO / SLB FISHING REP j-550 GPM, 1240 PSI I- ORIENT 150° RIGHT OF HIGH SIDE -' - TAG EZSV AT 3136'MD - SET DOWN 15 KLBS TO TRIP THE ANCHOR - PU LL UP 4'TO 3132'MD WITH WHIPSTOCK 'ANCHOR SET DOWN 61 KLBS TO SHEAR MILLS FROM SLIDE - PICK UP I0' AND SET BACK DOWN: TAG TOWAT3110'MD 18:00 - 18:30 0.50 WHIP P 3,446.53 WEXIT DISPLACE 9.3 PPG BRINE WITH 9.3 PPG -SND MILLING FLUID - 550 GPM, 1140 PSI MONITOR WEII FSTATIC 18:30 - 00:00 5.50 STWHIP ',. P 'i 3,446.53 I WEXIT -- _— _ ,MILL 8.5° WINDOW PER SLB FISHING REP FROM 3110' MD TO 3125' MD, 3056' TVD. - 450 GPM, 835 PSI ON, 830 PSI OFF BTM, - 130 RPM, 2-11 KFT-LBS TQ ON BOTTOM 4 KFT-LBS TQ OFF BTM, 4 KLBS WOB - PU 133 KLBS, SO 120 KLBS, ROT 126 KLBS r -MUD WEIGHT IN/OUT = 93 PPG 11/24/2019 00 00 - 06'.00 6.00 STWHIP p 3,144.53 WEXIT CONTINUE TO MILL WINDOW IN 9-5/8" CASING AND 20 OF NEW FORMATION - FROM 3125' MD TO 3144' MD (3056' TVD) 500 GPM, 1035 PSI ON BOTTOM, 975 PSI OFF BOTTOM i ! - 120 RPM 2-8 KFT-LBS TORQUE Q ON j ! BOTTOM, 4 KFT-LBS TORQUE OFF BOTTOM, 4-14 KLBS WOB - PU 133 KLBS, SO 120 KLBS, ROT 126 KLBS IIS - MUD WEIGHT IN/OUT = 9.3 PPG 'WORK THROUGH WINDOW SEVERAL TIMES WITH AND WITHOUT ROTATION AND PUMPS SPOT 40 BBL, 40 PPB SIZED CaG03 LCM PILL ON BOTTOM AND PULL UP INSIDE WINDOW '- MONITOR WELL FOR 10 MIN: STATIC TOP OF WINDOW: 3110' MD, 3045' TVD BOTTOM OF WINDOW: 3124' ME, 3057 TVD Printed 12/18/2019 12:06:07PM **All dephts reported in Drillers Depths** TREE= 4-1/16' CNV WELLHEAD= FMC ACTUATOR= LEO OKB. ELEV = 62.49 BF. ELEV = 35.7T KOP= 2300 Max Angie = 95' @ 12170' Datum MD= 886P Datum TVD = 670DSS S-129 CHROME TBG* 6*• MAX DOGLEG:25.8• @ 065'** "*LNR DAMAGE -SEE WELL PICTURES*** 20' COND, 108' #,J ID 9-518' CSG, 40#, LA03295' BTC. D = 8935' 4-12' TBG,12.6#, 13CR-80 VAM TOP, .0152 bpf, D = 3.958' CSG. 26#. L-80 VT -HC XO L-80 BTGM Minimum ID = 2.813" @ 8530' 3-1/2" HES X NIPPLE 3-1/2- TBG, 9.2#, 13CR-85 VAM TOP, .0087 bpf, D = 2.992' '**LNR DAMAGE STARTING @ ' ***UNABLE TO DRIFT PAST -8' ***SEE WELL PICTURES`** 3, 26#, L-80, BTC -M, 1-t 9435' bpf, D = 6.276' 20' OIL SWILL PACKERS NO SIZE TOP DEPTH MN ID 4 3-1/2' 8930 2.992' 3 3-12' 9714 2.992" 2 3-12' 10659 2.992" 1 3-12" 12266 2.992" PERFORATION SUMMARY REF LOG: LWD ON XX/XX/10 ANGLE AT TOP PERF: *@' Note: Refert0 Pmducficn DB fortislodcal per SPF INTERVAL Oor✓Spz SHOT 3155' BALANCED PLUG IN TX W 12" HES X NP, D = 2.813- 112' NDPG SINGLE SENSOR X 3-1/2' HES TNT PKR, D - 12 -HES X NP, D=2.813' 12' PX PLUG (10/12/19) 12 -HES X NP, D=2.813' 869W 7' X 5' BKR HRD ZXP LTP w/FLEXLCK HGR D=4.400' 8710' 3-12' WLEG, D = 2.992' 8730' 5- X 3-1/2- XO, D = 2.99' MILLED OUT WNDOW (7') 8875'-8910' MLLEDWFDCBP 1-1 11891' BKRCMDSLDSLV IRX PRDRI R NO# TOPDEP H Opn/Sgz DATE MND 7 8909 C 05/07/18 2.817 6 9198 C 05/07118 2.817 5 9446 C 05/07/18 2.817 4 9951 C 05/07/18 2.817 3 10446 C 05/07/18 2.817 2 11097 C 05/07/18 2.817 1 11890 O 03/24/11 2.817 4112"XJ"LIIC-SLYUN SWf3L PKR, D= 3.958' DATE REV BY COMMENTS DATE I REV BY I COMMENTS 1120110 N7ES ORIGINAL COMPLETION 11/14/19 TJS/JMD JETCUrTBG 11/09/19 0625/19 EPD/JMD ADPERFS 06/07119 0927/19 DD/JMD CHANGED PERFS TO PUNCHES 10131/19 MWJMD SET PX PLUG (10112119) 10131/19 MWJMD GLVC/O 10/12119 10131/19 MSS/JMD SET BALANCE PLUG 1024119 AURORA UNir WELL: S-129 PERMIT Nu:'1101320 API No: 50-029-23433-00 BP Exploration (Alaska) MEMORANDUM TO: Jim ReggIII Zell Cq P.I. Supervisor ' State of Alaska Alaska Oil and Gas Conservation Commission FROM: Austin McLeod Petroleum Inspector Section: 35 Township: 12N Drilling Rig: NA Rig Elevation: NA Operator Rep: Miles Shaw Casing/Tubing Data (depths are MD) DATE: November 6, 2019 SUBJECT: Plug Verification Prudhoe Bay Unit S-129 BPXA , PTD 2101320; Sundry 319-443 Range: 12E Meridian: Umiat Total Depth: 12964 ft MD Lease No.: ADL 028257 Conductor: 20" - O.D. Shoe@ 109 Feet Surface: 9-5/8" - O.D. Shoe@ 3,295 Feet Intermediate: T' - O.D. Shoe@ 8875 - Feet Production: NA - O.D. Shoe@ NA Feet Liner: 3-1/2" - O.D. Shoe@ 12,870 - Feet Tubing: 4 -1/2"x3 -1/2""O. D. Tail@ 8,710 ' Feet Plugging Data: Test Data: Suspend: NA P&A: X Depth To MW Above Verified Casing Removal: Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Tbg Cut@ NA Feet Type Plug Founded on Depth Btm Depth To MW Above Verified Fullbore Balanced 8,667 ft MD 6,703 ft WLM 9.3/6.7 ppg Wireline tag OA 49 56 54 51 Initial 15 min 30 min 45 min Result Tubing 3700 3640 3612 — 3593 IA IA 3729 3653 3610 3575 49 OA 49 56 54 51 60 min 75 min 90 min Result Tubing 3579 3568 - 3559 ' IA 3545 3520 3500 � f��l P OA 49 47 47 Remarks: I traveled to PBU S-129 to witness the tag and then combination pressure test (tubing and inner annulus) of a cement plug. BPXA was not able to get a work string past the 3 -1/2 -inch liner top to put cement across and above the perforations, so a variance was granted by AOGCC. Three tags were made with a 1.75 -inch sample bailer slickline string (— 200 pounds) at 6,703 ✓ ft WLM (inclination -51 degrees) which was 3.9 barrels higher than anticipated. After pulling out of the hole they did the tubing x inner annulus pressure test extending it out to 90 minutes to confirm a stabilizing trend before calling it a passing test. The above test data shows the continuous test. The pressure test took 3.25 barrels in, with 3 barrels back once bled. The sample bailer was then broke down with cement observed in it. Operators sundry application called for the bottom of plugs in both tubing and IA to be 8,460 It MD (bottom station depth). Referencing the well schematic it appeared to me the bottom of the plug in the tubing would be the plugged x -nipple and the bottom of the plug in the inner annulus would be the packer -8,631 ft MD. The bottom depth of the plug in the above plugging data is the x -nipple depth. , Attachments: none rev. 11-28-18 2019-1106_Plug_Verification_PBU_S-129_am THE STATE °fALASKA GOVERNOR MIKE DIINLEAVY Kenneth Allen Engineering Team Lead BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, PBU S-129 Permit to Drill Number: 210-132 Sundry Number: 319-443 Dear Mr. Allen: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov 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, Jessieelowski Commissioner DATED this q day of October, 2019. RBDMSd/"OCT 0 7 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon D Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other SSmulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill 0 • Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other ❑ 2, Operator Name: BP Exploration (Alaska), Inc 4. Current Well Class: Exploratory ❑ Development 0 5. Permit to Dnll Number: 210-132 " 3Address: P.O. Box 196612 Anchorage, AK . 99519-6812 Stretigraphic ❑ Service ❑ 6. API Number: 50-029.23433-00-00 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 ❑ No 0 PBU S-129 9, Property Designation (Lease Number):10. Field/Pools: ADL 028257. 028258 8 028261 PRUDHOE BAY, AURORA OIL 11, PRESENT WELL CONDITION SUMMARY Total Depth MD 00: Total Depth TVD(ff): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12964 • 6791 9030 6829 2814 None 11891 Casing Length Size MD TVD Burst Collapse Structural Conductor 80 20" 29-109 29-109 Surface 3266 9-5/81• 29-3295 29-3193 5750 3090 Intermediate 8849 7" 26-8875 26-6770 7240 5410 Production Liner 4171 3-1/2" 8699-12870 6674-6791 1 10160 10530 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: 1 Tubing Grade: Tubing MD (ft): 8909-1 6, 4-1/2"12.6#x3-1/2"92# 13Cr85 24-8710 Packers and SSSV Type: 3.5" HES TNT Packer Packers and SSSV MD (ft) and TVD (ft): 8631 / 6637 No SSSV Installed No SSSV Installed 12. Attachments: Proposal Summary 0 Wellbore Schematic 0 13. Well Class after proposed work. Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: October 15, 2019 15. Well Status after proposed work: Oil ❑ WINJ ❑ WDSPL ❑ Suspended 0 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Minge, David be deviated from without prior written approval. Contact Email: David.MingeQbp.com Authorized Name: Allen, Kenneth W Contact Phone: +1 9075645279 Authorized Title: Engineering Team Lead Authorized Signature: �"Date J112-6 / / q COMMISSION US ONLY Conditions of approval: Notify Commission so that a representative may witness / Sundry Number: — Plug Integrity W BOP Test 11Mechanical Integriity/Test Itl' Location CI rance ❑ Other. VG r t tS,kAJC� �C 2� .4a Z'�, //��Gi�•f Q rENGO� 57RT6W �TNE55 Rr�iRG�C'Ah�nn7- !Ir � ©O�Osr� fi'i�JlvUl4r o Post Initial Injection MIT Req'd? Yes ❑ No ❑ �iLF /. Spacing Exception Required? Yes ❑ No 13Subsequent Form Required: /e- Y6 9, y APPROVED BYTHE Approved by: COMMISSIONER COMMISSION Date. ORIGINAL gBDMSAI CT 0 7 20191V6R03CC7=1? Submit Form and Form 10-403 Revised 04/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate by GP6_Pe11 S-129 Sundry Application Well Type: Producer Current Status: Shut-in Request: P&A for rotary rig sidetrack Planned Pre -Rig Work Start Date: October 15, 2019 Planned Rig Start Date: November 15, 2019 MIT -IA Passed to 4181 psi (5/12/2018) PPPOT-T Passed to 5000 psi (9/12/2019) PPPOT-IC Passed to 3500 psi (9/12/2019) MASP: 2814 psi (10.0 ppg EMW in Kuparuk at 6700' TVDss with 0.1 psi/ft gas gradient). Pending updated pressure reading as part of pre -rig screening work. Well History: S-129 is a horizontal producer that was drilled in 2010 and completed with sliding sleeves and open hole swell packers. The well was tracked in May of 2018, and the 4-1/2" liner was collapsed -25' below the 4-1/2" x 7" liner hanger. Numerous attempts have been made between May and December 2018 with Slickline, E -Line and Coiled Tubing (8 separate rigups) to re -access the well with no success. It is proposed to replace the well with a sidetrack. Scope of Work: Prior to rig arrival, the 5-129 wellbore will be abandoned with a 1300' cement plug (tubing and IA) with top of cement at -7160' MD. Final top of cement will be determined with a drift run followed by an integrity test of the tubing and IA. The 4-1/2" x 3-1/2" tubing will be cut at -3400' MD. Wellbore integrity will again be verified. A variance is being requested to 20 AAC 25.112.(C).(1) which states that a cement plug must be placed across the perforations, to 100' above the top pert. Due to the repeated, failed attempts to access the 4-1/2" liner with Service Coiled Tubing (motor / mill runs), it is not feasible to place cement across the perforations. The planned tubing and IA cement abandonment plug will be across the Coleville and HRZ shales and will isolate the Kuparuk from surface and the Schrader Bluff formation. The bottom of the cement plug will be at most -260' above the top of the junk. The rig will move over the well and pull the 4-1/2" tubing. A cut and pull of the existing 7" casing will be performed to a depth -150' above the 9-5/8" casing shoe. A 9-5/8" whipstock will be used to mill a window out of the existing surface casing at -3150' MD. This sidetrack is a horizontal producer targeting the Kuparuk reservoir. The planned well is a two string, ultra-slimhole design using 7" intermediate casing and 4-1/2" production liner. The intermediate casing will be set at the top of the Kuparuk, and the production interval will be completed with a cemented and perforated liner. S-129 Sundry 1 9/26/2019 Pre -Rig Prep Work: 1. S Set X -Plug in 3-1/2" nipple profile at 8698' MD. Pressure test to 3500 psi. 2 F Circulate cement plug through GLM #1 at 8460' MD. TOC -7160' MD. Load well with 9.3 ppg brine and -500' diesel cap. 3. S Brush BPV profile. DBT TOC. MTT Log. Drift for Jet Cut. AOGCC Witness. -Z r- 4. F CMIT-TxIA to 3500 psi. AOGCC Witness. - ,2S11j� AGE 5. D Inflow Test. 6. E Jet Cut TBG -3400' MD. 7. F CMIT-TxIA to 3500 psi. 8. W PPPOT-TBG and IC. Function LDS. 9. V Install Dry Hole Tree. Install Annulus Valves. Set HP BPV. Proposed Drilling Rig Operations: 1. MIRU Parker 272. 2. Test BPV from below to 3500 psi. 3. Nipple down dry hole tree. Install test dart in BPV. Nipple up BOPE (annular, 4-1/2" x 7" VBR, blind -shear, 2-7/8" x 5" VBR) and test to 5000 psi (annular to 3500 psi). Subsequent BOPE tests to 3500 psi rams, 3500 psi annular. 2 VJ r. V,07,LE %d *6: CC_ 4. Pull BPV. Circulate out freeze protect with 9.3 ppg brine. 5. Pull 4-1/2" tubing from the pre -rig cut at -3400' MD. 6. Cut 7" casing at -3150' MD (-150' above 9-5/8" shoe). 7. Circulate out OA freeze protect with 9.3 ppg brine. 8. Pull 7" casing from cut depth. 9. Run GR/CCL log on E -Line. Set EZSV at -3150' MD and pressure test to 3500 psi. 10. Set 9-5/8" whipstock on EZSV. Displace the well to LSND milling fluid. --------------------------------------End of Sundry / Start of Permit to Drill ------------------ Drilling Engineer: Production Engineer: Geologist: David Minge (907) 250-2917 Lea Duong (907) 5644840 Sarah King (907) 5644841 314- yy3 S-129 Sundry 2 9/26/2019 TREE= 4-1/16"OW Vu9-LHE4D= FMC ACTUATOR= LEO QKB. ELEV = 62.46 BF. ELEV = 35.7T KOP= 23W Mex Angle = 95• @ 12170' Dahn MD= 8861' Gahm TVD= 67WSS 1 108' 1 41" CSG, 9W, L-80 BTC, D = 8.835" I—I 3295' 4-12' TBG, 12.6#, 13CR-80 VAMTOP, .0152 bpf, D = 3.958' CBG. 26#, L-80 VT -HC XO L-80 BTC -M 5334' Minimum ID = 2.813" @ 8530' 3-1/2" HES X NIPPLE 4 9.2#, 13CR-85 D=2.992" ***LNR DAMAGE STARTING @ -8724'*** ***UNABLE TO DRIFT PAST -8739'*** ***SEE WELL PICTURES*** CF�ETE3G '. MAXDOGLEG: 250Re 8° @ 065' S-129 •••LNR DAMAGE - SEE WELL PICTURES "• I2006' 4-A4 D=6.276' 20' OIL SWELL PACKSM NO SIZE TOP DEPTH MN D 4 312" 8930 2.992' 3 312' 9714 2.997 2 312' 10659 2997 1 312' 12266 2.997 PERFORATION SL% MRY REF LOG: LWD ON XX/XX/10 ANGLE AT TOP PERF 56' @ 8722' NDte: Refer tD Procimbon DB for Wbrical pert data SIZE I SPF I MHRVAL I OpNSgz I SHOT SQZ 1-9116-1 6 1 8722-8737 1 O 06/07/19 14-12' SLTD 12297-12838 O 11/15110 GAS LIFT MANDRELS ST MD I TVD I DEV ITYPEI VLV ILATCHIPOKI'l 8909 DATE 5 4163 3811 46 MMG DOME RK 16 08/09/18 4 4263 3881 46 MMG OMY RK 0 11/17/10 3 6872 5597 52 MMG DOME RK 16 08/09/18 2 8358 6483 54 MMG DMY RK 0 11/17/10 1 8460 6542 56 MMG SO RK 22 08/09/18 88698' I-j3-12'HESXNP,1D=2.813' ® 7-X8 SKRHRD ZXP UP w/FLEXLCK HGP, D=4.400" MLLE370Ur WNNDOW(7') 8875'-8910' 13-12' LNR 9.2#, L-80 BT -M, .0087 bpf, D = 2.992' 11 12870' 1 D = 2.992" BKR CMD SLD SLV IBX PROFILE) NON TOP DEPTH Opn/Sgz DOTE MID 7 8909 C 05/07/18 2 812" 6 9198 C 05!07/18 2.812" 5 9446 C 05/07/18 2.812" 4 9951 C 05/07/18 2.812" 3 10446 C 05/07/18 2.812" 2 11097 C 05/07/18 2.812' 1 11890 O 0324/11 2.812" 1 11546' 1 PKR D = 3.958' AURORA LUT WELL 5729 FE RMT No' '2101320 AR No: 50-029-2343300 SEC 35, T12, Rl2E 1635' FNL & 1177' FVbL DATE REV BY COR&ENTS DATE REV BY CONANTS 1120110 WES ORIGINAL COMPLETION 08!15/18 DGfJMD GLV 00(08/09/18) 0722115 MIOJ GLV 00 (06/12115) 06/25/19 EFUJND ADPBRFS (06/07/19) 05/08/18 JTC/JM7 CLOSED SLAPS (05107/18) 05/15118 CJWJMD GLV C/O (05/11/18) 06/27118 JNJJMD SBF ELEV DEPTH ElP Exploration (Alaska) 07/26118 FrUA D ADDED SAFETY NOTE=S E2E LNR DAMAGE " "'6" °P" PRE -RIG PROPOSED 20" ODN7lXTOP„ D= " 1/2" TBG, 12.6#, 13CR-80 VAM TOP, I-1 4083' r D 52 bpf, = 3.958" 3.269, L-80 VT-HCXO L-80 BTOM 633V 10 T X N TOP d BOT CM7 7160' - 6460' - Minimum ID = 2.813" @ 8530' 3-112" HES X NIPPLE ST S-1291 SAFETY NOTES: W ELL ANGLE> 70" @ 8971' "" CHROME TBG •". MAX DOGLEG: 25.8• @ 9065' TYPE VLV LATCH *•*LNR DAMAGE - SEE WELL PICTURES**" DATE 5 4163 4-12" H6S X NP, ID = 3.813' 1� MMG DOME R-3400"D—E-G 16 08109/18 4 4263 3881 46 MMG 4083'4-12" X 3 -1/2" XO, D = 2.992' 3295' 0 11117/10 GAS LFT MANDRELS 1/2" TBG, 12.6#, 13CR-80 VAM TOP, I-1 4083' r D 52 bpf, = 3.958" 3.269, L-80 VT-HCXO L-80 BTOM 633V 10 T X N TOP d BOT CM7 7160' - 6460' - Minimum ID = 2.813" @ 8530' 3-112" HES X NIPPLE ST MD TVD DEV TYPE VLV LATCH PDITT DATE 5 4163 3811 46 MMG DOME RK 16 08109/18 4 4263 3881 46 MMG DMY RK 0 11117/10 3 6872 5597 52 MMG DOME RK 16 08/09/18 2 8358 6483 54 MMG DW RK 0 11117/10 1 8460 6542 56 MMG SO RK 22 08109/18 8630' 3-1/2" HES X NP, D = 2.813" 8696' 3-1/2" NDPG SINGLE SENSOR SUB, D= 8631' 7" X 3-12" HEs TNr PKR. D = 2.949" 8667' 3-112" HES X NP, D = 2.813' 8888' 3-1/2" HES X NP, D = 2.813' 8698' 3-12" WRP 3-12" TBG, 9.2#, 13CR-85 VAM TOP, 8710' / \ 9" 7" X 5" BKR HRD ZXP LTP .0087 bpf, ID = 2.992" w IFLEKLCX HGR, D= 4.400' 8710' 3-12" WLEG, D = 2.992" ***LNR DAMAGE STARTING @ -8724' ***UNABLE TO DRIFT PAST -8739'*** ***SEE WELL PICTURES*** 1 8876' 7" CSG, 26#, L-80, BTC -M, 943-�5' rtl" .0383 bpf, D = 6.276" 20' OIL SWELL PACKERS NO SIZE TOP DEPTH MND 4 3-12" 8930 2 992" 3 312" 9714 2.992" 2 3-12" 10659 2.992" 1 3-12' 12266 2.992" PERFORATION SUMMARY Rff LOG: LVO ON XXIXX110 ANGLE AT TOP PERF: 56' @ 8722' Note: Refer to Production DB for historical pert data !E SPF ME2VAL Opn/Sgz SST Sc 161 6 1 8722 - 8737 1 O 0 2" I SLTD 112297 - 128381 O 1 17�9:i71Lit -m' 8730' 5" X 3-12" XO, ID = 2.99" MILLED OUT VINDOW (7") 8875'-89110' BKR CMD SLD SLV (BX PROFILE! NO# TOP DEPTH Opn/Sgz DATE MN ID 7 8909 C 05/07/18 2.817 6 9198 C 05/07/18 2.812' 5 9446 C 05/07/18 2.812" 4 9951 C 05/07/78 2.812" 3 10446 C 05/07/18 2.812" 2 11097 C 05/07/18 2.812" 1 11890 O 0324111 2.812" 4lrz ASult-A uN SWELL FKR, D = 3.958' DATE REV BY COMMENTS DATE REV BY COMMENTS 1120110 N7ES ORIGINAL COMPLETION 08/15/18 DG/JMD GLVC/0 08/09/18 0722115 MJC/JMD GLV C/O 0811275 0625119 EPD/JMD ADPERFS 06/07119 05/08/18 JTC/JMD CLOSED SLEEVES 05/07/18 0924/19 DM/JMD PREM PROPOSED 05115/18 CJWJMD GLV C/O 05/11/18 0627/18 JNUJMD CORRECTED BF ELEV DEPTH 0726/18 JTC/JMD ADDED SAFETY NOTES RE: LNR DAMAGE BP Exploration (Alaska) PROPOSED SAFETY NOTES: WELL ANGLE >70°@ REV 1 S-1 29A MAX DLS: _" @ _'. CHROME TBG & LNR. 20-COND, 108' I9A/8" WHIPSTOCK C—!/—) 1--L_ 9-5/8" CSG, 40#, LA0 BTC, D = 8.835" Minimum ID = " @ TOP OF 4-12" LNR 4-12" TBG, 12.6#, 13CR-85 VAM TOP, .0152 bof. D = 3.958' 7° CSG, 26#, LA0 VAM TOP HC, .0383 bot, ID = 6.276' PERFORATION SUMMARY REF LOG: ON _/_I ANGLE AT TOP PERF: _° @ _' Note RaMrto Production DB for NstDdcal Derfdata PBTD - 4-12' LNR, 12.6#, 13C R-85 VAM TOP, .0152 bpf, D = 3.958' MLLOUT WINDOW (S -129A) _'-_' nAC I F MANnRF1 S ST I MD I ND I DEVI TYPE VLV LATCH PORT DATE 6 SIDETRACK(S-129A) 09/19/19 JMD BULTPROPOSED 0924/19 JMD 5 4 3 2 i ---- DATE REV BY COMMENTS DATE REV BY COMMENTS 1120110 N7ES ORIGINAL COMPLETION I I SIDETRACK(S-129A) 09/19/19 JMD BULTPROPOSED 0924/19 JMD BUILT PROPOSED REV 1 14-1 2" HES X NP, D = 3.813" 1 7'X 4-12' HES TNT PKR, D = 3.856" 4-12" HES X NP, D = 3.813' 4-12' HES XN NP. D = 3.725' I7"X 5" WFD LTP & HGR wrr EBAC K SLV, D = 4.310" 4-12' WLEG, D = 3.958" 5' X 4-12" XO, D = 3.910" AURORA UNIT WELL: S -129A PERMIT No: API No: 50-029-22846-01 BP Exploration (Alaska) Sundry Application Plug for Re -drill Wells Work Flow This process is used to identify wells that are suspended for a very short time prior to being re - drilled. Those wells that are not re -drilled immediately are identified every 6 months and assigned a current status of"Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box Geologist / in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" /66 / boxes are also checked, cross out that erroneous entry and ✓✓✓ initial it on both copies of the Form 10-403 (AOGCC's and operator's copies). 2 If the "Abandon" box is checked in Box 15 (Well Status after proposed Geologist work) the initial reviewer will cross out that erroneous entry and initial then / it on both copies of the Form 10-403 (AOGCC's and operator's copies). v Instead, check the "Suspended" box and initial that change. Drilling Engineer The drilling engin6ers will serve as quality control for steps I and 2. (QC) 3 When the Stat Tech receives a Form 10-403 with a check in the "Plug Stat Tech for Redrill" box, they will enter the Typ_Work code "IPBRD" into the ' History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." 4 When the Stat Tech receives any Form 10-407, they will check the Stat Tech History tab in RBDMS for the "Intent: Plug for Redrill" code (IPBRD). If present and there is no evidence that a subsequent re -drill has been COMPLETED, the Stat Tech will assign a status of SUSPENDED to the well bore in RBDMS no matter what status is listed on the 10-407. The Stat Tech will also change the status on the 10-407 form to SUSPENDED, and date and initial this change. If the Stat Tech does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. 5 When the Form 10-407 for the redrill is received, the Stat Tech will Stat Tech change the original well's status from SUSPENDED to ABANDONED. 6 The first week of every January and July, the Stat Tech and one of the Stat Tech Geologists will check the "Well by Type Work Outstanding" user query Geologist in RBDMS to ensure that all of the Plug for Redrill wells have been handled properly. At this same time, they will also review the list of suspended wells for accuracy. N a 'm m C m E 7 V ° a N @ E C C a « 3 Y 0 O u N � '� O C a a O � aL• L a a @ � � S 9 Y m F s @ M o a r @ N N @ 3 p < ra N L N A V +>.• ~'> U O w m aCU in y aL`+ c CD W Y O Y 3 O r a o m - E = U = Z N 60 L N H m ac Z O W @ c`0 O o u > N -O_ O M s > -D y _ O T Y O > @ _ O o $ 3 o 7 c >cr a N A N ` C y C ECL n O E �. QCL O m _ @ > Y E d rm• n fl. L N V fl. 'O = O c w o L@ C 00 3 i "O m W _ _ a U �m m o+-' m c s 5A C O « C O b0 V C •n N 'O N m O C A N N y u 0 N j m O O x @ u n a m a E c w V N c w m C A C" Q O w 01 a O. N lD ON .G Q' U ` u 01 r .� C r x w m a C N n �" I, n c O S A I� > d m E V a 01 @) Laj m m `�- E Y V O OO C Y •Y E 10 r v Fa o a 2 E w c !0 3 U m a 0 ccu a .� Y N O O@ O C O @ p OC a u u c £ a" C 'L > pv E@ O v o Owl a>>H _ p == Y a 'D V `• a E m a- N VI }� T N 0@ x x a N o@0 > C C d m N C tNb Z n a w- V L t a@ a O O a 0 O O 0 O u. V1 h Vf Barrels of Oil per Month or Barrels of Water per Month 0 0 0 00 0 C O O G G C O O O O O O I 0 6 e C 8 G O O eO•l O G CD O O � o!lem I!O-se0 Jo gjuow aad („j:)W„) seO jo;aaj a!qn:) puesnoyl PTV a 10 -/3 Z • • Loepp, Victoria T (DOA) From: Loepp,Victoria T(DOA) Sent: Thursday,June 07, 2018 2:04 PM To: 'Sidoti,Todd' Subject: RE: PBU S-129(PTD 210-132, Sundry 318-044) Fracture Stimulation Time extension(30 days) for filing the 10-404 is granted. Victoria scmiNED JUN 1 gZUlr6 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservati Ian 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 Tito you,contact Victoria Loepp at(907)793-1247 or From:Sidoti,Todd<Todd.Sidoti@bp.com> Sent:Thursday,June 07,2018 1:55 PM To: Loepp,Victoria T(DOA)<victoria.loepp@alaska.gov> Cc: Lastufka,Joseph N<Joseph.Lastufka@bp.com> Subject: PBU S-129(PTD 210-132,Sundry 318-044) Fracture Stimulation Hi Victoria, After attempting to perform a fill cleanout of the first stimulation stage we were only able to make it a couple feet past the liner hanger assembly into the 3.5" liner. Our current plan is to troubleshoot with slickline and coil, resume the fill, cleanout and perform the second stimulation.We are requesting a 30 day extension to the sundry in order to give tim',e to troubleshoot and frac.Thank you for your consideration. Best Regards, Todd todd.sidoti@bp.com 1 THE STATE °fALASKA GOVERNOR BILL WALKER Todd Sidoti Well Intervention Engineer BP Exploration (Alaska) Inc. P.O Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, PBU S-129 Permit to Drill Number: 210-132 Sundry Number: 318-044 Dear Mr. Sidoti: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov 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 fiuther time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French 1 Chair DATED this 2-b day of February, 2018. RPD.rt.S L-- F7° Z 11 H18 F1r..%JC1 V CLei STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ti APPLICATION FOR SUNDRY APPROVALS 201 20 AAC 25.260 PSI- P ? f -PA � , 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 ' Repair Well ❑ Op9e) rjiiy �v1r0 `❑•/ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program Plug for Redrill ❑ Perforate New Pool ❑ Reenter Susp Well ❑ Alter -Casing ❑ Other ❑ 2. Operator Name: BP Exploration (Alaska), Inc 4. Current Well Class: Exploratory ❑ Development 0. 5. Permit to Drill Number. 210-132 ' 3. Address: P.O. Box 196612 Anchorage, AK 995195612 Stretigrephic ❑ Service ❑ 6. API Number: 50-029-23433-00-00 ' 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 ❑ No 0 PBU S-129 , 9. Property Designation (Lease Number): 10. Field/Pool s n_ b Z�Z91 Zai- - ADL 028257.0 & 028261 �/ Z' PRUDHOE BAY, AURORA OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Dept' TVD(ft) : Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12964 • 6791 12869 6791 None 11891 Casing Length Size MD TVD Buret Collapse Structural Conductor 80 20" 29-109 29-109 Surface 3266 95/8" 29-3295 29-3193 5750 3090 Intermediate 9410 7" 26-9436 26-6820 7240 5410 Production Liner 4171 3-1/2" 8699 - 12870 6674-6791 10160 1 10530 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grace: Tubing MD (ft): 8909- 12838 6787 - fi791 4-1/2" 12.6# x 3-1/2' 9.2# 13Cr85 24-8710 Packers and SSSV Type: 3.5' HES TNT Packer Packers and SSSV MD (ft) and TVD (ft): 8631 /6636 No SSSV Installed No SSSV Installed 12. Attachments: Proposal Summary 0 Wellbore Schemafic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: March 15. 2018 15. Well Status after proposed work: Oil 0 WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Sidoti, Todd be deviated from without prior written approval. Contact Email: Todd.Sidotipjbp.com Authorized Name: Sidoti, Todd Contact Phone: +1 907 564 5113 Authorized Title: Well Intervention Engineer AuthorizedSignature. �`j,.7 Date: 2-/' / ye COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: �� _ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No M-�/ Spacing Exception Required? Yes ❑ No f Subsequent Form Required: 16-401 APPROVED BYTHE Approved by: J `� COMMISSIONER COMMISSION Date:.. Lb II e- ��,�� r4RIGINaL `Y CA) 11112- Form 10403 Revised D4/20 7 Approved application is valid for 12 months from the date of approval. ReenIs wr L , L t K' y" ZU' /8 Submit Form and Attachments in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AFFIDAVIT OF NOTICE OF OPERATIONS Before me, the undersigned authority, on this day personally appeared~ who being duly sworn states: 1. My name is Todd Sidoti. I am 18 years of age or older and I have personal knowledge of the facts stated in this affidavit. 2. I am employed as an Engineer by BP Exploration (Alaska) Inc. ("BPXA") and I am familiar with the Application for Sundry Approvals to stimulate the S-129 Well (the "Well") by hydraulic fracturing as defined in 20 AAC 25.283(m). 3. Pursuant to 20 AAC 25.283(1), BPXA prepared a Notice of Operations regarding the Well, a true copy of which is attached to this Affidavit as Attachment I ("Notice of Operations"). 4. On January30th, 2018, the Notice of Operations was sent to all owners, landowners, surface owners and operators within a one-half mile radius of the current or proposed wellbore trajectory of the Well. The Notice of Operations included: a. A statement that upon request a complete copy of the Application for Sundry Approvals is available from BPXA; b. BPXA's contact information. Signed this 30th day of January, 2018. // V E (Signature) STATE OF ALASKA THIRD JUDICIAL DISTRICT Subscribed and sworn to or affirmed before meat v�°t C1 _� on day of� 20N:�. v � Signature of Officer \ Title of Olylcer ASKA < PUBLIC ."NIA HICKS My Con m;ss;cr " m;.; ,s November 13, 2019 the $J t Date: January 30, 2015 &&17- ��ti �••r.- �%�du�/ Z. /�j�/moi Subject: 5-129 Fracture Stimulation From: Todd Sidoti Engineer, BP Alaska o: 907.564.5113 c: 907.632.4113 To: AOGCC Attached is BP's proposal and supporting documents to fracture stimulate the middle and toe Kuparuk intervals of well 5-129. In May of 2015, a heel frac was performed on well 5-129 which resulted in an excellent production increase that has held very good rates even to today. It is proposed to perform a similar treatment on the middle and lower reservoir intervals to further increase productivity. We are requesting a variance to sections 20 AAC 25.283, a, 3-4 which requires identification of fresh water aquifers and a plan for baseline sampling. Please direct questions or comments to Todd Sidoti. Affidavit of Notification (20 AAC 25.283, a, 1) Partners notified 01/30/2018: ConocoPhillips ExxonMobil Chevron Department of Natural Resources Plat Identifying Wells (20 AAC 25.283, a, 2, A -B) Per the plat above, there are no water wells within +/: mile of the subject well. a, s-zze s411 e'40l I?G i81 q �. Solt SaQi�... 5-�c y aP -m &yl s� Y� • 0 1 + i V S286 1M b / M1 % l v � r � / �l VL n q• / IO h r z• "B� I t N f s2sA s�r i +.coo o +.c: ®Feet ■ S-129Rac Location �S-129- Deviation Survey WeIS Within tr2 mile of S-129 ora..ees %115 Uti Cpatine nainw[Y W RPM ' c..fa+hr by S-129 ....,. 8129 Pend CUon Interval 12 toile Biller Pm 1 La,4 ° 0 O 5.129 112 Mlle Buller MAP 1 BP Leases _ Per the plat above, there are no water wells within +/: mile of the subject well. Producers within t/2 mile of well trajectory (20 AAC 25.283, a, 2, C) moommA S -M Development Abandoned SIIMPBI Service Plumed Back For Redrill 5-213AL1-01 Development Oil Producer Flowin SOLA Develo merit Abandoned 5-3364PB2 Service Plumed Back For Redrill 5-213AL2 Develo ent Oil Well S BIB Development Abandoned 5-117 Development Oil Producer Shut In S213AB Develosurnerent Oil Well SOIc Develo mens Oil Producer5hut-In 5-110 Development Oil Producer Shut -In 5-215 Service Water hector lnedin 5-02 Develoment Abandoned 5119 Develoment 011 ProducerGas lift 5-216 Service Water Interior Shut In 5-o2A Develoment Oil Producer Gas hit SDA Serviu Abandoned 5-212 Service Water Injector Shut -In 5 NAL! Develoment Or Well 5.136 Servim MstiWe heed., Shut -In 5-218 Service Msdble lneRor Shut -In SO2AUP81 D.-lo,drand Plumed Bad For Redrill 5-12 Develo mend Abandoned 5-21 Development Abandoned S-02APB1 Servide Plumed Bad For Redrill 5120 Service Water Injector Injecting 5-22A Development Abandoned 503 DevelomeM Oil Producer Gas Wt 5-121 Development Oil Producer Gas lilt Sd2B Service Water lnect.r lnecti S -Oa Se"o, Msdble Injector Shut -In S121PB1 Development Mucted Bad: For Redrill 523 Development Oil Producer Shut In 5-05 DeASPIncent Abandoned 5122 Development OIIProducer Gas Oft SN Devil. men[ Abandoned 5-05A Service Water lnettor In actin 5-122P01 Devel mend Plumed Bad For Redrill 5-M Service Abandoned S 0SAPS1 Servide Plumed Bad For Redrill 5122PB2 Develo ent Plumed Back For Redtlll 5-2,wB3 Service IPlumed Back For Redrill 506 Sam. Water hector Shut -In 5-122PU Development Plugged Back For Redrill 5240 Service lWater Injector Shut -In 5-02 Development Abandoned 5-123 Service Water lneRor Shut -In S25 Devil. meM lAb.ndenPd S -VA Development Oil Producer Shun -In 5324 Service Msdble Injector Shut -In S -ISA Service Water lnettor Inholnut 5 -De DervkrIancent Abandoned 5325 Desel.parreent Oil Produce Gx UR 5-25APB1 Service Plu dBack For Redrill 5084 Development Abandoned 5125PB1 Development Plu dBack ForRadrill 5-16 Development Oil Producer5hut-In 5088 Dreceloarrent Gil Producer Shu, In 5-126 Service Water lnettor Shut-in 5-D Develo eat Abandoned 509 Sasid, Abandoned 5-128 Srurvia, Water Injector 'getting 5-22A Develo merit Abandoned S_M Servet Muddle Injector Shut -In 5328P81 Service Plugged Bad For Redrill 5-27APB1 Develo Ment Plugged Beek For Redrill 5-09APB3 s,"o, Plumed Back For" drill Sd2SP82 Servide Plumed Bad For Redrill 5-27B Development Oil Producers In 509APB2 Semte Plumed Bad For Redrill 5-129 Develo mint 10.1 Producer Gas OR S,M Dcvelotabrerd Abandoned 509AP83 Service Emed Bad For Redrill 5.129PB1 Develo merit Plumed Back For Bacilli 5-ffiA Devel. enc Abandoned 520 Development Abandoned 5-129PB2 Development Plumed Back For Redtlll 5388 Development Oil Producer Shut -In S100 Development Oil Producer Shut -In 5-12A Development Abandoned S3BBPB1 Development Plugged Back For Redrill Y1D1 SeMce Water Injector Injecting 5-12B Develo Ment Oil Producer Gas Gft 529 Development Abandoned 5-1O1P01 Development Plugged Bad For Redrill 513 D—loethrent Abandoned 5-29A Service lWater hector Sendin 5-102 Develo merit 011 Producer Gas Orr 5-134 Service "sable hector Shut -In 5-29AL1 Service Waterinled.,Shut-In 5-]02L3 Devm elo int Abandoned 55 13 Develo men, Oil Producer Gas pfd 5-30 Develo m cr Oil ProdurerShul-In S102I3PB1 Development Plumed Bad For Redrill 5-135P01 Develo mens Plumed Bank For Rather S31 Development Abandoned S102PB1 Devoloornint Plumed Bad For Redrill 5-135PB2 Development Plumed Back For Bacilli S 31 Service Water Injector lneRin 5103 Develo mint Ohl Producer Gas tint 5-13A Development Oil Producer Shut -In 532 Development Abandoned i -10o; Servide Water ln'ectorinectin 5-13APBI Development Plumed Bad For Redrill S3M Development Oil Producer Shut-in 5305 Develoment Oil Producer Gas Oil 1514 Servide Alsndoned 533 Development Oil Producer Gas lift Sa06 IN,elotarent Oil Producer shut -In s14A SeMce ws ended S,M Service Water Injector mem 51061,81 De-I.thrent Pwed Bad For Recall Sm IS Servide Water Ineaor Shut-in S-35 Development Oil ProdumrShuDln S-107 Service Watermecter Shut -In S-I5PB3 Serves Plumed Back For Redrill s-36 Devem end on Producer Shut-in 5109 Develo Ment Sus ended 5-16 Development Oil Producer Shu -In S32 Development Abandoned 5103 Development Oil Producer Shut -In S I6PB1 Development Phu ed Back For Radrill 532A Development Oil Producer Gas ph 5-109PB1 Development PI.,,,d Back For Redrill 512 Denheloancent Abandoned S-37APB1 Development Plumed Back For Redrill S=iM Development Suspended 5 17 Develo ern Abandmmd S,M Development Oil Producer Shubin 510APB1 De,oletancent Plugerd Bad For Redrill S12AL3 Dew1orurnent Abandoned 5-40 oval. men[ lAteard.ned 510APB2 Dewhophorcent Plumed Bah For Redrill 517ALlPBI Deselo,schant Plumed Back For Redrill 5-400 SeMm IAWnd.n.d 511 Servide Abandoned S-12APa1 Develo ment Plugged Back For Bedell 5.400A Service Iwater Injector Shut -In 5310 Service Sus ended S 12B Development Abandoned 5401 Service lWater Injector Shut-in S11A Servide Abandoned 512c Develo mend Oil Producer Shut -In 54p1PBl Seroce Plumed that For Redrill 51100 Service Water Injector lineching S17081 Development Plumed Bad For Redrill S40A Development Bir Producer Shubin 5111 Servlet Water Inventor tweeffics, 51X1,02 Development Plumed Back For Redrill 541 Develo maul Abandoned S I11PB1 Servh<e Plumed Bad For Redrill 518 Devil. meM Abandoned SAM SeMas Wale, In etlar deem 5-111P82 Service Mudded Bed For Redrill S18A Development Abandoned 54ML1 De'efolanuent Oil Producer Gas Oft 5-112 Samee Water Injector Injection 5-188 Development Oil Producer Shut In 541L1 Development Abandoned 5 112L Servide Water And Gasinector 5-19 Development Oil Producer Shut-in 541PB1 Service PIrr,,Pd Bad For Redrill 5-112LIPS1 Semm IPluUed Back For Redrill 5-20 Service Abandoned 5@ Development Abandoned 5112LIP82 Servhte Plumed Bad For Redrill S 2 Development Oil Producer Shut -In 5-02A Development CHIP mdrsh Gaspk 5113 Develoment Abandoned 5-21)DA Denersdandint Our Pdduar5hut.ln SOPRI IService Phrases Bah For Redrill s4m Develo mend Abandoned 5-2"BI Development Plumed Bah For Redrill 5-43 Devem ment oil Produce. Shut -In 531311 Development Oil Producer5hut-In 5201 Dewl. meM Oil Producer ShutinSwett DesPlinspinend Oil Producer Gas Lif, 5113BL1 Development Oil Procure, Shut -In 5-NiPBI Development Plugged Back For Redrill 5-04 Development Abandoned 5114 Dewla ment Abandoned 5-20A SeMce Wrterinector Injecting 5-041 Development Oil Producer Gas Uft S114A SeM¢ Wale.Intender Shut-in 5-21 Develo men[ Oil Produder Gas lih S44L] Develo mint Abandoned 5-115 Development Oil Poduar Gas Aft 5-213 Develo mint an 544LIPB1 Deveh. mint Plumed Back For Redrill 5.116 Servre Abandoned I5-Il3A Develo mint OII Producer Gas pct S5W Service Wader lnettor Shut -In 511" Service Msdblehector Shut -In 1521MU ID,eal.itrunat Oil Producer Flowin ISN -c Develp mart Abandoned Exemption for Freshwater Aquifers (20 AAC 25.283, a, 3-4) Well S-129 is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1-4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location the makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have a total dissolved solids content of 7000 mg/I or more. 4. By letter of July 1, 1986, EPA -Region 10 advises that the aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non -substantial program revision not requiring notice in the Federal Registrar. Per the above findings, "Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25.440." thus allowing SP exemption from 20 AAC 25.283, a, 3-4 which require identification of freshwater aquifers and establishing a plan for basewater sampling. Detailed Casing and Cement Information (20 AAC 25.283, a, 5-6) Well 5-129 was spudded on 12/25/2010. A 12-1/4" hole was drilled to 3305' where 9-5/8" 40#, L-80, BTC csg w/ CBU 1X @ base of permafrost @ 1926' was run and cemented in place with 1200 sx ArticSet lite lead and 447 sx of 15.8 ppg Class G cmt with good returns (365 bbls cmt) to surface. After plug was dropped, the casing was tested to 3500 psi for 5 min for a good test. A LOT to 11.96 ppg was performed after the shoe was drilled. A 8-3/4" intermediate hole was drilled to 9445'. Once past casing set point, 7", 26# VT -HC and BTC csg was run and cemented in place with 454 sx of UteCrete cmt and 223 sx Class G. After milling a window from 8875'-8910', a 12.1 ppg EM W test was successfully achieved. A 6-1/8" hole was drilled to TD of 12,964'. 3-1/2" 9.2# L-80 IBT-M solid and slotted liner with swell packers was run to 12,870'. Displaced the openhole section to 10.4 ppg bring then set the liner top packer. The completion assembly consisting of 3-1/2" and 4-1/2" tubing was run to 8710' with the packer at 8631'. Prior to 2015 the well had been producing via the bottom 6 sleeves and slotted liner, when the top sleeve was opened to evaluate the production potential, no noticeable change in oil rate was observed. The well had paraffin issues and was on recurring B&Fs and HOTs, alternating every 3 weeks. In May 2015, a heel frac was performed on well 5-129 which resulted in an excellent production increase. The well has been producing from all seven sleeves and the slotted liner since then. Pressure Test Information (20 AAC 25.283, a, 7) In 2011 after cementing, a passing MIT was performed on the 7" Casing to 3500 psi for 30 minutes. In 2005 a passing CMIT-TxIA was performed to 4000 psi and a passing MIT -T was performed to 5000 psi. These tests will be re -performed ahead of the frac job. Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 8) HEY= M.Cl 2300 20'GONIA'IW - 108' , nnw- fimr " .,TvO- e7ara D• i 95!'CSG, IOR, L -m BTC, D'8.035' 32916' 41?TBG. 1244. 1X.IFm YAM TOG -� 0152501, 10- 3 958• �izu-2m,ie0vl.x: nui eti nl�B+�� 333 Minimum IDM 2.813' 86630' L3-vz_ nn5 n mrrl.e S-129 COVIIYwTE4 WE lANQE>70'�bTl'••• 111�r11�1I ILII ,, 1, ,' CNNOME TBR•'• MAl DOQEO't5 t• ®8085' ••' 1 , • f1= 2002' �ia w SIM WDIPnI AMD / 2 B8T0 2 W 3 3 w 0211 29AT 2 2V7 10559 2.99T 1 3w 12266 2997 OASLVIMMM00 Fs-IT-anTnvol E) ![M IW lrywl 19V HAIMIR.4 MTF 5 410 3811 44 YC DOBE R( 16 061215 1 1 3881 IB MAa U. R( 0 1V17110 3 6872 M97 52 LNG DDBE R( 16 00/1315 2 8158 Iml 51 1810 DW 71( I 0 '1 V17110 1 8160 6512 5811400 SO KK 20;061315 r x r wnule2xnLm POiD(LCK1Gq D=t/0P u 17818131w (r1 ens'. mw MCYOBID dV B)[ w E) ![M twowl"lowvW1 07=15 W(2 %voo(0M215) MW 4410 T 0909 O 018644 MIT 6 9198 O (KI01111 Mir 5 9448 O 032V11 Mir 1 9951 O 03 11 MIT 3 10816 O 0a 11 "IT 2 11097 O Mwil MIT 1 11890 O Mwil 2812 R300NATDn Si w WLOG. LW7t1NU X'10 1168{' 41?A3•Il1EH AAIGLEATTOPF736 511`6587VSVHL � D=3 N9Y. A1Mb R80,r1On 001. 1 dCW pM OWe FCw' PD CBp 11001' 62E SfF MHIVAL O.xSAz SNOT SOZ IOe0v 151 41? SLID 12297.12818 O IV1610 12Mf N MID ADTE L B VASBII® 11?LMLOb,L-0O BT-µ .0001 OpI, D'299T H17870 MW O wj A11iOMIlAT VB.L: S-125 Ri08T M tmlv0 ARM -56@9-23132 0 8 SAL X. TI2. M 2E 1635 M A 1177'M 11410lR lives ORG08(LCOµFUllm_ 07=15 W(2 %voo(0M215) 67—W114 MAD GLV C000167N'441 02'111157178 SET 097 QDff51DSV5 02'1&15 GLV 00 1 0 115 4107MD GLV W (05W15) ®6pbrWbn (Alate) 07714415 18L133®R5ET719110801f51 Name/Size Weight Grade ID Burst, psi Collapse, psi 9-5/8" Surface 40# L-80 8.835" 5750 3090 7" Production 26# L-80 6.276" 7240 5410 3-1/2" Liner 9.2# L-80 2.992' 10,160 10,540 4-1/2" Tubing 12.6 13Cr80 3.958" 8430 7500 3-1/2' Tubing 9.2# 13Cr85 2.992' 10,160 10,530 Wellhead: FMC manufactured wellhead, rated to 5000 psi. Tree: 4-1/16" 5,000psi Tubing head adaptor: 11" 5,000psi x 4-1/16" 5,000psi Tubing Spool: 11" 5,000psi w/ 2-1/16" side outlets Casing Spool: 11" 5,000psi w/ 2-1/16" side outlets Tree saver: The top connection is 3" 1502 hammer union which will be crossed over to 4" 1002 in order to connect to the frac treating iron. The bottom connection is 7-1/16". The tree saver is rated to 10,000 psi. Geological Frac Information (20 AAC 25.283, a, 9) Lithologic Description Geological Name MD Top, ft TVD Top, ft MD Thickness, ft TVD Thickness, ft I Est. Frac Pressure Shale Kulubik 8646 6645 112 57 0.70 Sandstone Kuparuk C4 8760 6708 34 19 0.49 Sandstone Kuparuk C2 8794 6726 67 36 0.51 Sandstone Kuparuk C1 8959 6810 97 47 0.64 Location, Orientation and a Report on Mechanical Condition of Each Well that may Transect Confining Zone (20 AAC 25.283, a, 10) N I- s 0 Spr _ 1)A LL -- S -AB 51YCPBt "� -- S115pPB1 Q� �1 .m 5• 0- T U, Y $0 R u l ➢ m a` 0 _m � N U Y u cU + u 'S[ c HOBO SUB Fru Loca+un Dya sourus: WNa Uma r.0]fEa1! man aee g B:ap ®Fee+ � 5-IIB-Oeweon Survey we K wmm tn_ mk a s -+m Ca+o9oMY by S-12� i TNUPFauM1Pdypons wM hun numhr 0P$M2 :a,mrowys5 S-129Pmtivcaon Interval 11S Mak Buller O S 12 L2 Mik Rafter MAP 1 BP Leases Location of, Orientation of, and Geological data for each known or suspected fault. (20 AAC 25.283, a, 11) BP has formed the opinion based on seismic, well and other subsurface information available that there are 11 mapped faults that transect the Kuparuk interval and enter the confining zone within the h radius of the production and confining zone trajectory for S-129. Fracture gradients within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of —16ppg. Thickness and fracture pressure for the confining layer is discussed in Section 9. The S-129 crossed one mapped fault in the Kuparuk interval. Fault #6 terminates in the Colville. Fault #6 did not take losses when drilled. S-129 Fault MD SSTVD THROW Fault#6 11162' 6776' 25'(DTNE) The S-128 crossed one mapped fault in the Kuparuk interval. Fault #1 terminates in the Colville. There were no report losses with Fault #1. The fault crossing in S-128 is greater than 2000' from the S-129. S-128 Fault MD SSTVD THROW Fault#1 11067' 6844' 120'(DTS) The S-1281382 crossed one mapped fault in the Kuparuk interval. Fault #1 terminates in the Colville. There were no report losses with Fault #1. The fault crossing in S -128P82 is greater than 2000' from the S-129. S-128PB2 Fault MD SSND THROW Fault #1 11000' 6877' 120' (DTS) The S-116APB1 crossed one mapped fault in the Kuparuk interval. Fault #8 terminates in the Colville. There were no report losses with Fault N. The fault crossing in S-116APB1 is greater than 1400' from the S-129. 5-116APB1 Fault MD SSTVD I THROW Fault#8 1 8790' 6827' 30'(DTSW) The S-116APB2 crossed one mapped fault in the Kuparuk interval. Fault #8 terminates in the Colville. There were no report losses with Fault #8. The fault crossing in S-116AP81 is greater than 1400' from the S-129. S-116APB2 Fault MD SSTVD THROW Fault#8 8786' 6811' 30'(DTSW) Fault #2, Fault #3, Fault #4, Fault #5, Fault #7, Fault #9, Fault #10 and Fault #11 intersect the production interval and confining zone within the % mile radius. Their displacements, sense of throw and zone in which they terminate upwards in are given below. Faults THROW Fault Termination Zone Fault #2 100' (DTW) Colville Fault#3 70'(DTW) Ugnu Fault#4 170'(DTS) Ugnu Fault#5 100'(DTW) Sagavanirktok Fault #7 50' (DTS) Colville Fault#9 25'(DTW) Colville Fault #10 30' (DTN) Colville Fault#11 40'(DTW) Colville Summary Hydraulic Fracture Program (20 AAC 25.283, a, 12) 1. C Drift & Tag SS#1, Close SS #2-6• 2. S D&T, Install dummy GLVs, Set Evo-Trieve plug, MIT -T, MIT -IA, Pull Evo-Trieve plug 3. F Assist SL 4. 0 Install Tree Saver 5. F Injection Test, Data Frac, Hydraulic Fracture Treatment 6. C Post frac FCO, set CBP plug below SS #7, open SS #4 7. T Assist with FCO S. F Hydraulic Fracture Treatment 9. S D&T, Install GLVs 10. C Post frac FCO, mill CBP 11. T Assist with FCO, post -frac flowback Pump Schedule (Same for Stage i and Stage 2(: BTB R 57AGE I AVERADE PPA CCMM.I FLOD TYPE PUMP BATE IBMI Cf PATE IBPMI 9TADE (BBL) ppxY VOWME CIIN STA4E MIAJ MAW CW MAW 9TRDE (LBS) PPMPA.. WM IL051 51g 4 1 PAD VF12BFNAD 30 20.0 IN 459 0300 19270 0 2055 0 5 1 04 PUT WINFIexD 3D294 150 609 6300 25578 3%25 136 S I PAD YFlNFMxD % 30.0 160 159 fi300 31070 0 5,136 1 1 PUT YF128FjPxD N 287 N W9 2100 33978 2011 ],14] low B 1 T NMP YF128FkxD % 287 38 847 1575 35553 1500 8.656 s 1 2 NMP YF128FIe.D 30 276 3B W4 1575 37126 2694 115W 10 1 3 RAMP YF128FkxD 30 265 98 922 IM 38703 4171 15,721 1 4 NMP YF128FloW 30 255 38 959 1575 40270 5353 21,074 1 5 MMP YF128H..0 30 24.6 38 897 1575 41853 6448 27,522 13 1 6 MNP YFI%FNxD W 237 30 1036 1575 43428 7460 34.990 15rzou.eow. 14 1 7 MNP YMNFMZD M 229 38 1072 1575 45M M10 43,407 Is 1 8 RAMP YF128FNxD 30 222 30 1109 1575 465]0 %o6 52,713 16 1 0 F. YF1%FMxD M 222 0 1159 21M 48678 12408 65.122 11 1 9 Ni WIWFMAD 30 215 50 1209 2100 50FP 13517 78.639 1e 1 10 FLAT YF128FIeAD 30 208 50 1259 2100 52870 14559 %,197 srzo c. eemm 1B 1 11 PLAT YFIMFNED 30 20.2 10D 1359 6200 1 5]0]8 310]6 126,273 4i 1 FLWB wF123 3D 300 % 1465 4012 fi10% 1262]3 1m TOTAW FLUSH Freeze IOM01 15 150 i 33 1608 14 88 1406 62496 124213 124 2]3 Anticipated Pressures and frac dimensions: Maximum Anticipated Treating Pressure: 6700 psi Anticipated half length: —250' Stage 1 & 2TVD Frac top: 6708' Stage 1 & 2 TVD Frac bottom: 6768' Due to the horizontal nature of the well we are unable to provide MD top and bottom for the planned fracs. The above values were calculated using modeling software. Surface pressure is calculated based on a closure pressure of —0.5 psi/ft or 3700 psi, this combined with the anticipated net pressure to be built and the friction gives a surface pressure of 5500 psi at the time of flush. The frac height is primarily based on closure pressure differences between the harder Kuparruk formation and the softer confining layers. Average confining layer stress is `0.70 psi/ft. Half length is based on confining layer stress as well as leak -off and formation modulus. Given the values we used, a half length of 250' is expected. Pressure Test Information (20 AAC 25.283, a, 7) Per the frac program, the both the tubing and the IA will be pressure tested. The IA will be tested to 4000 psi and the tubing will be tested to 4500 psi (110% of max differential of 4500 psi). PRV setting procedures and annulus monitoring: Maximum Allowable Treating Pressure: Stagger Pump Kickouts between: Global Kickout: IA pop -Off set pressure: Treating line test pressure: 6350 psi and 6050 psi (90% to 95% of MATP) 6350 psi (95% of MATP) 3000 psi (75% of MIT -IA) 7700 osi 10,000# 16/30 Sand, 160,000# 16/20 CarboLite, Sand Requirement 100,000# CarboBond Minimum Water Requirement 3000 bbls (pump schedule: 2700 bbls) IA Hold Pressure 2700 psi Monitor and maintain open to atmosphere There are three overpressure devices that protect the surface equipment and the wellbore from overpressure. Each individual frac pump has an electronic kickout that will kick the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are set between 90% and 95% of the maximum allowable treating pressure. There is the primary pressure transducer in the treating line that will trigger a global kickout which will kick all the pumps into neutral. Finally, there is a manual kickout that is controlled from the frac van. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. r wpm ^ 5-129 Rig Up = r�eeav \l .wed lone Amu Lme ■ .` 7mr.1.!Ol In namn io. C+name . onei Chemical Disclosure (20 AAC 25.283, a, 12) :AS Number - Chetuical N� tie Wahr Dnduding Mix Water Supplledb CY IieMl• ! VB% 407 - - CeralMv materials antl ware;chemicals ^IO% 1490b68 1480&604 __ Duana. Crystalline silica <1 % _.. _. 9 D Guar gum <1 % 62-08-1_._ 6748- 2 -yd N,N-rim xy-N, t IFVNthanaminiu!n chdonde <] % 1319-33 1 - _ Went, <D.1 % 107.21 .1 _ _ _ Ethvbne GIYcul <0.1% - 7727-52-0<D.1 _ _ Dlammoniu pe ozkisWpM1ate % 62£3-0 _ Propan-2-o1 - - <0.1 % 111463 2-buto."Pt... I <0.1 % 68131-40-8 Alwhols,ell-155econdaWethaxylated <D,1% 3439&01-2 Ethoxylatrad Cll Alcohol _ <DA K 129898-01-2 2-Fruppencrid acid. polymer with sodium phodphircaae ea.1 % 1310-733 Sodium hYd... iid. limpidty) <0.1 % 2503&7-6 Vin liderN rhloritle/meth lad Wtecopolymer <0.1 % 68131-39-5 ENI Wand Abohot a 0.1 % 13113 96 4 Sodium Tetraberate Decahycrate <D.t % 2647-14-5 Sodom dJorirle c 0.01 % 1D4M2- _ bolkime <O.ol% W0435L4 Cablum Cbladtle cilicide <0.01% 112 @-5 Untleanol <D01 % 91053.39-3 D140unaaom earth calcined - <0.D1% _ 2631.86.9 -- - NomcmbMine Wicalier, it l <0.001 % 14802-96-6 Magnesium Akira, hydrate lolrl - --- - - -, - - <DMI % 10374t0A _ Magneslum Nvate <O.001 % lll46-6 _-2617-55-4 2roydhanllimpartvl -0.01% _ 5-cMoro-bmetFyb2h.edAbudolob3 one <O.ODl % -_ 9W2 M 0 _ - _ p.M cmafunroethybnc) <O.OD1 % 22863115 MagneDotan bride <O.001 % 595585 _ - _ _ _. _ G��tan <o.00l 115005-8 1.0 Diatan gum <o.00l x 12708 2 Acroc acid, potassium salt <0."1 % 2442-004 -.. Potaseiwn chbride (impurity <0 o0D1 % 2G81--46 2-meMyl-2Mso.1ire, l-3one <n OODI Y — IN6F46.1_ - Crlitebalne <o D001 ss "-19 7 Aleck acid im ubt <D Dom S-129 Hydraulic Fracturing Procedure 1. C Drift & Tag SS #1, Close SS #2-6 2. S D&T, Install dummy GI -Vs, Set Evo-Trieve plug, MIT -T, MIT -IA, Pull Evo-Trieve plug 3. F Assist SL 4. O Install Tree Saver 5. F Injection Test, Data Frac, Hydraulic Fracture Treatment 6. C Post frac FCO, set CBP below SS #4, open SS#4 7. T Assist with FCO 8. F Hydraulic Fracture Treatment 9. S D&T, Install GI -Vs 10. C Post frac FCO, mill CBP 11. T Assist with FCO, post -frac flowback Current Status: Minimum ID: Max Deviation: Top Perf Deviation: Last TD Tag: Last Downhole Op: SBHP/SBHT: Latest H2S: Proqram Contacts Operable 2.813" at @ 8698', 8667', & 8530' MD. 3-1/2" X -Nipple 2.812" Sliding Sleeves @ 8909', 9198' 95 deg at 12,170' MD 59 deg at 8909' MD 6/3/2015: CT tagged SS#1 @ 11,891' MD 7/8/2015: B&F to deviation @ 8965' 4/14/2014: 2767 psi and 147F at 6700' datum. 25 ppm, 9/15/2017 Page 11 of 6 Contact Phone - Work Phone - Mobile / Home Interventions Engineer Todd Sidoti 907-564-5113 907-632-4113 Interventions Engineer David Wages 907-564-5669 713-380-9836 Page 11 of 6 Coiled Tubing D&T SS#1, Close SS #2-6 1. RIH with BHA including 2.6" nozzle and attempt to dry tag SS#1 at 11890' MD. 2. RIH with BHA including Tempress vibration tool and HB -3 shifting tool. Close sleeves #2-6. Sleeves are CMD shift up to close. Slickline D&T, Install dummy GLVs, Set X -Plug, MIT -T, MIT -IA, Pull X -Plug 1. D&T to deviation 2. Install Evo-Trieve Plug @ 8650' 3. Load IA and Tbg with inhibited 9.8ppg NaCl and dead crude 4. Install catcher sub and dummy off GLVs 5. MIT -T to 4500 psi 6. MIT -IA to 4000 psi 7. Pull Evo-Trieve plug Fulibore Assist SL w/ CMIT 1. Pump down tubing taking returns from the IA per below schedule, do not exceed 3500 psi surface pressures: • 46 bbis dead crude • 207 bbls inhibited 9.8ppg NaCl • 38 bbls dead crude Spec Projects Install Tree Saver 1. Install tree saver Fullbore Injection Test • Pump the following down the TBG at max rate (8 bpm) not to exceed 4500 psi. Please attempt to keep a stable rate if possible. • 5 bbis meth spear • —300 bbis diesel • 8 BPM is important, please RU hardline. • Record surface pressure and rate at 1 second intervals. • Work with SLB to obtain BH gauge data at 1 second intervals. • Perform hard shut down of pumps (do not operate tree valves) and monitor pressure decline for 1 hour, then shut well in and RD. • Send pump rate and pressure data to Todd Sidoti (todd.sidotiCD_bp.com) and David Wages (david.wagesCoDbp.com) Page 12 of 6 Fullbore Hydraulic Fracture Treatment 2. Frac treatment stage 1 per pump schedule. Pressure testing Maximum Allowable Treating Pressure: 6700 psi Stagger Pump Kickouts between: 6350 psi and 6050 psi (90% to 95% of MATP) Global Kickout 6350 psi (95% of MATP) IA pop-off set pressure 3000 psi (75% of MIT -IA) Treating Line Test Pressure 7700 psi 10,000# 16/30 sand, 160,000# 16/20 Carbolite, Sand Requirement 100,000# CarboBond _Minimum Water Requirement 3000 bbls (pump schedule: 2700 bbls) IA Hold Pressure 2700 psi OA Monitor and maintain open to atmosphere Coiled Tubing Contingent post frac FCO, set CBP plug above SS #1, perforate SS #4 1. FCO - See Appendix A 2. Set CBP plug at -10,100' MD & test to 2000 psi 3. RIH with BHA including Tempress vibration tool and HB -3 shifting tool. Open sleeve #4. Sleeves are CMD shift down to open. Fullbore Hydraulic Fracture Treatment 1. Frac treatment stage 2 per pump schedule. Slickline D&T, Install GLVs 2. Drift and tag fill. • Previous SL runs have deviated out around 9000' 3. Install Deep GL design Coiled Tubing Contingent post frac FCO, mill CBP 1. FCO - See Appendix A 2. RIH with BHA including 2.6" junk mill, mill CBP and push to bottom Testers Post frac flowback 4. Post frac flowback - See Appendix B Page 13 of 6 Appendix A - CT FCO Procedure Notes: This is a generic FCO procedure for a post frac FCO. Specific info such as amount of proppant left in tubing and estimated sand top will not be known until after the job is pumped. The objective of this procedure is to get the well cleaned to facilitate post frac well test. Recommend reviewing PE Manual section for Coiled Tubing Fill Cleanouts for specifics on reversing rates, speeds and CT loading. Planned Procedure 1. MIRU CT 2. MU BHA. 3. RIH down to estimated sand top and begin cleaning out with slick 1% KCL. 4. Continue down to 8909' CTMD. At this point we are at the sliding sleeve. Ensure CT is clean as it is expected that returns will begin to fall off as the nozzle nears the sleeve. If returns begin to fall off, reducing BHP by lowering rate may keep returns at a manageable level. 5. Slowly continue to clean out until returns fall off to -80%. During the second cleanout if returns are still good even after the nozzle is past the sleeve (not likely but possible), continue to clean out to the composite bridge plug at -10,100' a. If returns are too low, it may be necessary to mill the bridge plug without taking returns. 6. Continue to mill plug and push to PBTD. 7. FP to 2500'. 8. Pump a gel pill at surface out to the tanks to ensure CT is clean if necessary. 9. RDMO. Page 14 of 6 Appendix B - Test Separator Additional Flowback Procedure 1. MIRU ASRC. RU equipment to in a manner that allows CT to RU if an additional FCO is necessary. 2. POP the well to ASRC at minimum choke. Flow the initial returns to the flowline as long as the shake -outs meet the returned fluid/solids management guidelines. 3. Limit flow to 500 bpd 4. If solids are < 1 %, increase the production rate to 1000 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1 %, allow well to flow to 1500 BLPD. Flow bottoms up and sample for solids production. If solids are still below I% continue to increase the flow rate in 500 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well clean up before choke is opened further. 6. Once at FOC, stabilize the well for 4 hrs. Obtain a 3 hr purge, 8 hr welltest. Page 15 of 6 41116 -CII I )EAD • FIC 1. tLGV = 62 4u - I1.EV AND tAnple 70' COIM C = -95-@ 12170 .W= seal - e j9 =-MIG, 408. L aQ OTC. D' 8.635'j --t 32W 4-1? TBG. 12.641, 13CR-BO VA M TOP, - " 0152 6p/, D - 3 956' _ [7 '-LSU, 288,E -0V 111 tN:XOL WBICM I� 8J34•_. Minimum 10 ■ 2.813- @ 8630' 3-71L- MGs A P41P'YLt 12' ISG, 8 21. 13CR-I )61 6p1. D - 2 997 SAFLTTYNOTES: WELL ANGLE -70'@8971•••• 5-129 CHROME TOG"' MAX OOGLIO: 251• @ 9085"" 2008• 4 1 n• Fl9 X W, n- 3813- l/Y%1112'%O, D=219T1 n IS(: * C. 260. L 80, O I C M OJ8:10p1. D - 6176- W OIL SINAL PACKEM NO SeE TOP OF�fH AND 4 112' M) Nn IPV fYSE MY IAIO1 f4M•T DATE 3-11T 5 416J 3611 46 MG DOME W 16 0&12115 4 4263 3861 46 MG OW RK 0 11117110 t4lSl' 3 6872 5597 52 A" OO6[ R( 16 06n2/15 2 8358 6483 54 MMG OW W 0 IV17110 1 8460 6542 56 MIG SO R( 2D 06712115 n IS(: * C. 260. L 80, O I C M OJ8:10p1. D - 6176- W OIL SINAL PACKEM NO SeE TOP OF�fH AND 4 112' 6930 2.99r 3 }12' 9714 2997 2 3-11T 10559 2 Wr I }7? 12266 2.99T RiiFORN IX)N 5(.MWLR/ W LOG. LWDON XX!%Xr10 ANGLEATTOPPUF 58'06675" Nola Reser to Prodwbn OB IM llebrcal pert o41A = 2 813' 8686" ]—L3Ilr PBXs; Smu SeaD 6631' 7'x3-12'FES IW n(R O E08r]iNY H3 x Ir, 10-2.81r tow r Vr9VAHd Z"Lm W IFLD(LCK NG)1, D=4.400' 5717 3-1rr waa—D=2.1192' 5737 5'X 1t2'XO.D=2.9s• NIFn O0IVA4[XXN(r) 8875• Miff " q 1 q OP, "• � Mgt CMOSLD av(SK PRDPIL _ IOR IOPl1F}IfM 0041502 ___ DAtE 7 8909 0 01A9/14 6 9198 O 0324111 r�aq 6 0 03024111 \4 9@U- - o 03rz4111 3 10446 O OW4011 11091 O 03124111 a 1 11890 - o 0324111 �r OI1 _ r D=3950' 1/15710 12841' PBIU 11? LM 921• L-00 nT-M .0087 Ops, D- 2%7 1287r Page 16 of 6 DAfE- REV BY OOMIBdIS ALJ40PA LM WELL S129 FEF&U W 7101320 API. WC29-2343100 )6SEC 35, TV. R12E. 1635FK 6 11 77'FW7 DATE REIT BY COM61f5 111111"0 ION JOW.W.L COMPLISim ----- 072215 M)CIPAD GLV (7V (0611211 5) _ _. _ AD 07107114 nW GI V CI040FOW q 07/11/15 TIPoP SET CBR CLOSE SLDSLV'S 0211&15 P GLV C10 ---- 0321115 C91AD GLV C/0 (05MV15) BP Fsplo,XU n (Alk.) 07722J75 A4)C2 MLFDCEA'SET F73N(DM3115) Page 16 of 6 Date: January 30, 2018 Subject: 5-129 Fracture Stimulation From: Todd Sidoti Engineer, BP Alaska To: AOGCC o! 907.564.5113 c: 907.632.4113 Attached is BP's proposal and supporting documents to fracture stimulate the middle and toe Kuparuk intervals of well 5-129. In May of 2015, a heel frac was performed on well 5-129 which that has held very good rates even to today. It is proposed to pe lower reservoir intervals to further increase productivity. We are requesting a variance to sections 20 AAC 25.283, aquifers and a plan for baseline sampling. Please direct questions or comments to Todd Sidoti. ed in an excellent production increase + a similar treatment on the middle and which requires identification of fresh water 9 Affidavit of Notification (20 AAC 25.283, a, 1) Partners notified 01/30/2018: ConocoPhillips Exxon Mobil Chevron Department of Natural Resources Plat Identifying Wells (20 AAC 25.283, a, 2, A -B) Per the plat above, there are no water wells within % mile of the subject well. s s-0*c Swt s;01 'F's, s�:actpsz Y .11: 1: I- , Y O I v 1�j1 5?gg I0A q N , i I f M1 % m � m I o n I y � s �, N Sy �5 �lyl t�Y��1 e, N s.zy,1 r ,Qr J % .. ccc c i uaa ■ 5129 Frac Location ox, Sow e.: ®F!M WNS. Uni6 CDffiywe TamSR! kY BP%A 5729 - DevuOon Survey Wells wthm 72 mile of 5129 Cobww"l by 5-129 5129 ProWcOon Interval 12 Mile BtdW Ic Q 5129 12 Mile Buffer MAP 1 BP Leases aK...• .�. -a.¢ Per the plat above, there are no water wells within % mile of the subject well. Producers within % mile of well trajectory (20 AAC 25.283, a, 2, C) Exemption for Freshw9ter Aquifers (20 AAC 25.283, a, 3-4) Well 5-129 is in the est Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order 7icempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1-4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. Development ned S-11MPB1 Servlce Plugged Back For Retlrill 5-21MU-01 Development Oil Produ< Flowin Development netl 5-116APB2 Service Plumed Back Forgedrlll 5-21MU Development Oil Well Development Abandoned Yll] Develo meat Oil Producer SM1u[-In 5-213AL3 Development Oil Vi Development ducer Shut -In 5-118 Develo ment Oil Producer Shut -In 5.215 Service Wall deader Injecting • 7�2 Develo men, netl 5.119 Develo men. Oil ProtlucerGasLift 1216 Service HerleectorShut-In Develo men. tlucerGas lift LS-13A 5.11A Service Abantloned 5-212 Srvice ater lo'ecturShut-In Develoment ll S -11B Servlce Miscible lriect.r Shut -In 5-218 ServiceMiscible ln'ectmSM1ut-In 1. Development d Back For Redhill S 12 Development Abandoned s-22 Develo nt Abandoned • Service d Back For Reddll 5-120 Service Wale r lnjettor l electin S -22A DevaImerit Abandoned Development ducer Gas Lift 5-121 Develo menf Oil ProducerGas Lift 5-220 Serve Water Inector InjectinService e InjectorSbut-In 5-121PB1 Development Plugged Bad For Redrill S2a a menf 011 Producer Shut -In 5 -OS Development Abantlonetl S-122 Development 011 Producer Gas Lift 5-24 vel. menf Abandoned 5-05A Service Water lnjeRor l pecting S-II2PB3 Development Plugged Back For Retlrill 544A J Service Abandoned 5.05AP81 Service Plugged Back For Redrill i-1P2PB2 Development Plugged Back For Redrill 5-24APB1 Service Plugged Back For Redrill •S -O6 Service Wafer Inecton Shut -In S1nPB3 Develoment Plu ed Back For Redrill Service Water Injector Shut -In SO] Development Abandoned SAin Service Weer Injector ShutIn25 Development Abandonetl S -0]A Develo ment Oil Protlucer Shut -In 5-120 Service Miscble ln'ector5M1ut-ln !-XXB� service Water lnjeRor injecting 5-W Development Abandoned 5-125 Development Oil ProducerGas Lift Bl service Plu etl Back Forgedrlll s -B84 Develo ment Abantloned S-125PB1 - Development Plu etl Back Fpr Redrill - Development Oil Producer Shut -In . S -M Development Oil Producersbut-In 5126 Service Weerinector Shut -In 532 Development Abandoned S-09 Be,[. Abandoned S -IID Service Waterin actor lnjectin 5 -DA DeveloOment Abantloned 5-0Al Service Miscible l nject.r Shut -In S -128P01 Servire Plumed Back For ReI I S2]APBl Development Plumed Back For Redrill S-0MPBS r Service Plumed Back For Redrill S -1211i Service Plugged Back For R in S -1)B Development Oil Producerfiuf-In .5-09APS2 Service Plugged Back for Redrill S-129 Development Oil ProduarGas ft 5-29 Development Abandoned S-09APh3 .Service Plugged Back For Redrill S-12SPB1 Development Plugged Backl' Redrill 5-28A Development Abandoned SAID Development Abandoned S-129PB2 Development Plu ed Bac Dr Redrill S-288 Development Oil Producer Shut -In 5-100 Development OIIProducer Shia In 5-11A Development Abandon 5 28BPB3 Development Plumed Back For Redrill 5101 Servire Water Injectorlinfecting 54213 Development Oil ProctiferGas Lift SH Development Abandoned 5-101PB3 Development Plumed Back For Retlrill 5-13 m Development Alentl etl S29A Servlce Water Injector Shut -In .5102 Development Oil ProtlucerGeo Oft 5-134 Service Misc" le injector Shut -In S29AL] Servlce Water lnjeRor Shut -In T102L1 Development Abandoned S-135 Development Oil roducer Gas Lift S -ID Development Oil Producer Shut -In S-102L1PBi• Development Plugged Back For Redrill S135PB1 - Develo merit p tlBack For Retlrill 5-31 Development Abandoned S-102PB1 - Development Plugged Back For Fail 5-135PB2 Development Plurl Back For Redrill S -31A Servltt Waterinectorinectin 6103 Development Oil Protlucer Gas Llk 5-I3A DemeeporeV Oil Producer Shut -In 532 Development Abandoned 5-104 Service Weerine[forlriecting S-13APB1 Damolopprel Plumed Back For Redrill S32A Development Oil Producer Shut -In 5-105 Development Oil Producer Gas Lift 5-14 Service Abandoned S-33 Development Oil Producer Gas Lift 5-106 Development OilProducer5buoln S14A Service Suspended S-34 Service Water Injector Injecting S-1DSPB1 Development pleased Back For Redrill S15 Semi Walerinechn Shu. -In S-35 Development Oil Producer Shut -In SAW Servlce Water Injector Shut In S15PB1 Sarrike Plumed Back For Redrill S 3 Development Oil Producer Shut -In S -101I Development Suspended 5-16 D lopment Oil Producer Shut -In 5-32 Development Abandoned 5309 Development Oil Producer Shut -In S -16P01 velopment Multipart Back For Redrill S -32A Development Oil Producer Gas Oft 9d09P81 Development Plu ed Back For Redrill 5-1 Development Abandoned 5-37APBl Development Plu ed Back For Redrill S-104 Development Suspended S -17A Development Abandoned S-38 Development Oil Producer Shut -In S-1MPB1 Development Plugged Back For Redrill 5-17ALl Development Abandoned s-40 Development Abandoned 5-10APB2 Development Plugged Back For Redrill S12ALIP1 Development Plugged Back For Redrill 5-400 Service Abandoned 5 -ll Service Abandoned 5-17AP 1 Development Plugged Back For Reddll Sd00A Service Warl"jettor Shut -In S-110 Service IS.rpended 5-120 Development abandoned 5401 Service water lnjettor Shut -In 5-110 Servire Abandoned S-1] Develo merit of l Producer Shull. S-401PB1 Service Plumed Back For Redrill 5-1108 Servlce WHerin'etl.rin'eRln S-Yri Development Plumed hack For Reddll S -40A Development Oil Producer Shut -In 5-111 Service Waterin'ectorlirl 7OPB2 - Development Plumed Back For Redrill 5-41 Development Abandoned S -111P81 Service Plugged Back Far Redrill 18 Development Abandoned 5-41A Service Water Injection Injecting S -111P82 Service Plugged Back For Redrill 5384 Development Abandoned SAML1 Development Oil Producer Gas Lift 5412 Service Water Injection lnettin 5-18B Development Oil Producer Shut -In 541111 Development Abandoned Tliai Service Water And Gas lneoo 5-19 Development Oil Producer Shut -In 5-41PB1 . Servlce Plumed Bad For Redrill S11ri1P01 Service Plu etl Back Forge ill 5-2o Service Abandoned S-42 Development Abandoned 9d1ri1PB2 Service Plu tlBack For rill 5-200 Development Oil Protlucer Shut -In 547A Development Oil Protlucer Gas Oft 5413 Development Abantloned 5-201, Development Oil Producer Shut-in 5-42P01 . Service Plumed Back For Redrill S-1]34 Development Abandoned 5-200Ph1 Development Plumed Back For Redrill s-03 Development Oil Produce r Shut -In 5-1138 Development OilPmducer5 ut-In 5201 Development Oil ProducerShut In S-431.1 Development Oil Producer Gas Lift 5-113BL1 Development n Oil Pn.,5hut-In S 201Ph1 Development Plumed Back For Redrill Development Abe cloned 5-114 Development AbaS-2M Servire Waferinect0rmlecting Development Oil ProtlucerGas Lift s -114A Service Water -In S-21 Development Oil Producer Gas Lifl Dever. menf Abandoned 5 -lis Development OIIP S-213 Development Abandoned 1 ' Fc Depile menf Plu ed Back For RedrillS-116 Service AbeS]33A Development Oil ProducerGasDft Service Wafer Infector Shut -In 5-11M Service Mluut-In 5-213411 Development OilPmducer Flowing Develoment Abantloned Exemption for Freshw9ter Aquifers (20 AAC 25.283, a, 3-4) Well 5-129 is in the est Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order 7icempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1-4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location the makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and /to the Prudhoe Bay Unit are reported to have a total dissolved solids content of 7000 mg/I 4. By letter of July 1, 1986, EPA -Region 10 advises that the aquifers occurring beneath Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is consiminor exemption and a non -substantial program revision not requiring notice in the Fed Per the above findings, "Those portions of freshwater aquifers lying directly below the stern Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 0 AC 25.440." thus allowing BP exemption from 20 AAC 25.283, a, 3-4 which require identification of fr shwater aquifers and establishing a plan for basewater sampling. Detailed Casing and Cement Information (20 AAC 25.283, a, 5-6) Well 5-129 was spudded on 12/25/2010. - A 12-1/4" hole was drilled to 3305' where 9-5/8" 40ff, L-80, BTC csg w/ (;U 1X @ base of permafrost @ 1926' was run and cemented in place with 1200 sx ArticSet lite lead and 4 7 sx of 15.8 ppg Class G cmt with good returns (365 bbls cmt) to surface. After plug was dropped, the ca ng was tested to 3500 psi for 5 min for a good test. A LOT to 11.96 ppg was performed after the shoe was rilled. A 8-3/4" intermediate hole was drilled to 9445'. Once past c Ing set point, 7", 26# VT -HC and BTC csg was run ' and cemented in place with 454 sx of LiteCrete cmt and 23 sx Class G. After milling a window from 8875'- 8910', a 12.1 ppg EMW test was successfully achieved. A 6-1/8" hole was drilled to TO of 12,964'. 3-1/2" 9. L-80 IBT-M solid and slotted liner with swell packers was run to 12,870'. Displaced the openhole sectionto 0.4 ppg bring then set the liner top packer. The completion assembly consisting of 3-1/2" and 4-1/2" tubin as run to 8710' with the packer at 8631'. Prior to 2015 the well had been producing v(a the bottom 6 sleeves and slotted liner, when the top sleeve was opened to evaluate the production pot ti 1, no noticeable change in oil rate was observed. The well had paraffin issues and was on recurring B&sand HOTS, alternating every 3 weeks. I In May 2015, a heel frac was perfor ed on well 5-129 which resulted in an excellent production increase. The well has been producing from all seven sleeves and the slotted liner since then. Pressure Test Information (20 AAC 25.283, a, 7) In 2011 after cementing, a,¢assing MIT was performed on the 7" Casing to 3500 psi for 30 minutes. In 2005 a passing CMIT-TxIA was performed to 4000 psi and a passing MIT -T was performed to 5000 psi. These tests will be re -performed ahead of the frac job. Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 8) 1BG. 12 tl. I•{3{:.3M.CWVI rII:%UL WBIGM L w"' Minimum D M 2.813- @ 8630' j8-Ird- Me5 A NlrrL6 -288T CSG. ". L W, w no MIR 1 mrl S-129 CR MlIBGS"MAX WQEQ25162885"" INDI Gn TOPOMm I MND 11 M 2 3 1 9714 2.99r 2 1R' 10658 2997 1 w 12266 2967 sil MO Nn nRi TYR-1 VY ^IAtal R1 7 MTF 5 1163 3811 tl mr, DL)IE R( 16 06112/15 1 1283 3881 a: Mw Qjryry W 0 1111 to 3 6872 5597 1 52 MIG 110101 R( 16 w1D15 2 8368 8183 51 G cwv F1( 0 1 V 17110 1 8160 6512 56 2817 SO i W 20 W12115 D=1.q u 1 R)DDf VAVT%%Nf7ry ams' - tlM BMI MD M -D WV IM 21DiiR M) i0P�1/1 0p1V50i MME TMID 7 BBOB O 01.41'19 281T 6 9186 O Onan 2617 5 9M6 0 038411 2.817 % Ml 0 OnO11 2.117 3 $01 o my 2.812 z nw7 G wr111n z91r 1 ntlB o anon 2817 R380W11DN s1JaAAW 18} LOG. LVA)lRl 11888' 41? %3• LBE SLPa ANIEAT TOP PR9" ST 8875+ SMflI 802, O-19ia' Nob. fiW bRoOUcbn OB br blial Ph Bie FBf.M iv, NlU my-{ 11891' tE SPF MFiAIAL QVo' I SNOT SOZ (Ma 15) YC SLTD; 1229]-12JY 11115110 12689• �� wtu IE LBH! a LltBB11® �11?LHl928, L-BOBT-M .00�6q.D=2982' 1787Q • M1E TRV BY AURORA a81 VALS-In PMEW hW1320 SEC 35. T12. R12E 1635' FIA 8 11TT RM1L 0 IBB 0N O71rI115 MJCJJMU GLY fA IOd12/15) 07D71M 061 GI V C_ JGSET®LVARIb-5a@32313fw GLV M�FM - - Mv m6pbrelbAlAW ts) M08gy151 Name/Size Weight Grade ID Burst, psi Collapse, psi 9-5/8" Surface 40# L-80 8.835" 5750 3090" 7" Production 26# L-80 6.276" 7240 54.10 3-1/2" Liner 9.2# L-80 2.992" 10,160 ,10,540 4-1/2" Tubing 12.6 13Cr80 3.958" 8430 i 7500 3-1/2" Tubing 9.2# 13Cr85 2.992" 10,160 10,530 Wellhead: FMC manufactured wellhead, rated to 5000 psi. ' Tree: 4-1/16" 5,000psi Tubing head adaptor: 11" 5,000psi x 4-1/16" 5,000psi Tubing Spool: 11" S,000psi w/ 2-1/16" side outlets Casing Spool: 11" 5,000psi w/ 2-1/16" side outlets Tree saver: The top connection is 3" 1502 hammer union which will be crossed over to 4" 1002 in order to connect to the frac treating iron. The bottom connection is 7-1/16". The tree saver is rated to 10,000 psi. Geological Frac Information (20 AAC 25.283, a, 9) Uthologic Description Geological Name MD Top, ft TVD Top, ft MD Thickness, ft TVD Thickness, ft Est. Frac Pres re Shale Kulubik 8646 6645 112 57 0.70 Sandstone Kuparuk C4 8760. 6708 34 19 0.49 Sandstone Kuparuk C2 8794 6726 67 36 0.51 Sandstone Kuparuk C1 8959 6810 97 47 0.64 Location, Orientation and a Report on Mechanical Condition of Each Well that may Transect Confining Zone (20 AAC 25.283, a, 10) N s I 'oma � �o Spy i s g 117aL. 9' C b1]A w - - 5-t10APBt b m . r <` �� �� a 1 �. --j a N '(Ir U ... azo 6-122 Frac LPcz�wn Oaa sowces. ®' 5-129-Dexaoon Survey WM6 +rMln t 2 n * es -t20 iwi5 JieG Coatlrt+e ma.mmN ry aFYA C�y by p P724 e T 129 F" PdYgo rM Sun,10 - MAP 1 Rm2 =auh 'n¢ a -t24 Pmauction imervai t 2 OS1201:2M,e8u Mile Buller S - BP Leasez S-17 lies due east, which is perpe!dicular to the direction that our frac will grow. S-101 lies to the northwest and across several faults. Since we would like to avoid the fault and the well is to the west, we will avoid this wellbore by limiting our frac length. S-128 lies due west, which is perpendicular to the direction that our frac will grow. Location of, Orientation of, and Geological data for each known or suspected ault. (20 AAC 25.283, a, 11) BP has formed the opinion based on seismic, well and other subsurface inf rmation available that there are 11' mapped faults that transect the Kuparuk interval and enter the confi ing zone within the h radius of the production and confining zone trajectory for S-129. Fracture gradien within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would t refore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale with s e silts with an estimated fracture pressure of—16ppg. Thickness and fracture pressure for the confining la er is discussed in Section 9. The 5-129 crossed one mapped fault in the Kuparuk intery Fault #6 terminates in the Colville. Fault #6 did _ take losses when drilled. _ Y 5-129 Fault MD SSTVD THRO Fault #6 11162' 6776' 25'(D NE) The S-128 crossed one mapped fault in the paruk interval. Fault #1 terminates in the Colville. There were no report losses with Fault #1. The fault cros ng in S-128 is greater than 2000'f rom the S-129. 5-128 Fault MD SSTV THROW Fault#1 11067' 1 68/4' 1 120'(DTS) The S-1281362 crossed one m pped fault in the Kuparuk interval. Fault #1 terminates in the Colville. There were no report losses with F ult #1. The fault crossing in S-128PB2 is greater than 2000' from the S-129. S-128PB2 Fault D SSTVD THROW Fault #1 1000' 1 6877' 1 120' (DTS) The S-116APB1 crossed one mapped fault in the Kuparuk interval. Fault #8 terminates in a Colville. There were no report losses with Fault #8. The fault crossing in 5-116APB1 is greater than 1400' rom the 5-129. 5-116AP81 Fault MD SSTVD THROW Fault#8 8790' 1 6827' 30'(DTSW) The S-116APB2 crossed one mapped fault in the Kuparuk interval. Faul 8 terminates in the Colville. There were no report losses with Fault #8. The fault crossing in 5-116APB1 is reater than 1400' from the 5-129. 5-116AP82 Fault MD SSTVD THROW Fault #8 8786' 1 811' 30' (DTSW) Fault #2, Fault #3, Fault #4, Fault #5, Fault #7, Fault #9, interval and confining zone within the''/: mile radius. Thej they terminate upwards in are given below. 7 Faults THROW Fault Termination Zone Fault #2 ) Colville Fault #3 ) Ugn Fault #4 ) U nu Fault #5 ) Sag anirktok Fault #7 j(D Colville Fault#9 ) Colville Fault #30 Colville Fault #11 Colville Ault #10 and Fault #11 intersect the production displacements, sense of throw and zone in which Summary Hydraulic Fracture Program (20 AAC 25.283, a, 12) 1. C Drift & Tag SS#1, Close SS #2-6 2. S D&T, Install dummy GLVs, Set Evo-Trieve plug, MIT -T, MIT -IA, Pull Evo-TrieveP149 3. F Assist SL 4. 0 Install Tree Saver 5. F Injection Test, Data Frac, Hydraulic Fracture Treatment ` 6. C Post frac FCO, set CBP plug below SS #7, open SS #4 7. T Assist with FCO 8. F Hydraulic Fracture Treatment 9. 5 D&T, Install GLVs 10. C Post frac FCO, mill CBP 11. T Assist with FCO, post -frac flowback Pump Schedule (Same for Stage 1 and Stage 2): .1. 4 STAGE • RV.. SPI WMMEBTB FLUID ME PUMP BPTE (BPM) CF RITE IBPMI STAGE IBBL) pxryVOLUNE CUM STAGE IBBLI SAL) CUM (OIL) STAGE ILSD PMOPPRNT CUM "EU SHE 4 1 PAD YF128FIexD 30 200 150 469 63M 19270 0 2055 0 / 5 1OS MT YFHBFkxO 30 MA 150 809 6300 25570 3082 5,136 -6 T 1 _ t PID FLAT YF128FbxD YF128FbxD 30 _ 30 _ 300 287 180 50 789 809 6300 2100 31870 NOTE 0 2011 5,138 7,14) _ "1". e 9 +0 t t + 1 2 3 sAMP MMP MNP YF128FI..D YF128FIeeD YF128FIeiD 30 30 30 287 276 285 38 M] 15]5 35553 1508 8,658 tirzop� _ 39 884 1575 3]128 2894 _ 11,550 JB 922 15]S 38703 4171 15,721 tone rMlne 1. MMP YF128FHDD b 255 38 859 1575 40276 5353 21074 15 8 6 MaxP MMP _ VF128Fkx0 YF128Fkx0 30 30 206 237 38 38 987 1031 1575 1575 41855 63428 8440 7488 2],522 __ 34,990 _ V41 ] -8 Mxv YF128FkxD 30 229 38 1072 1575 45003 8418 43407 ua ur sr 1s +S + + 8 MMT_ i4TYF128FbxD YF128F1exD 30 30 _ 222 222 _ 38 50 1109 1169 1575 2100 _ 48578 49670 9308 12408 52,43vrzouimu+. 8,122 +irzounaa +7 _ 9 RAT YF128FbxD 30 21 5 50 1209 2100 SOA. 1351] 8,639 m tB 10 _ 11 FAST FLATYFt28Fbx0 _ W128FWXD 30 30 288 202 Sp 1259 210-6.5 78 "G'. 93.197 lmo unoewa _ 100 1]59 4200 - 57078 31076 124,273 tE8 TOTALS t - _RUSH FLUSH WF128 FreetepmWM 30 1-5 -- 300 +50 96 14SS 4012 61090 124273 33 1488 1106 82498 124,93 4273 Anticipated Pressures and frac dimensions: Maximum Anticipated Treating Pressure: 6700 psi Anticipated half length: `250' Stage 1 & 2 TVD Frac top: 6708' Stage 1 & 2 TVD Frac bottom: 6768' Due to the horizontal nature of the well we are unable to pr vide MD top and bottom for the planned fracs. The above values were calculated using modelin/presure softwr . Surface pressure is calculated based on a re of "'0.5 psi/ft or ^3700 psi, this combined with the anticipated net pressure to be built and thes a surface pressure of 5500 psi at the time of flush. The frac height is primarily based on closuifferences between the harder Sag formation and the softer confining layers. Average confining l^'0.655psi/ft. 2Half length is based on confining layer streleak-off and formation modulus. Given the values we used, a half length of 250' is expected. Pressure Test Information (20 AAC 25.283, a, 7) Per the frac program, the both the tubing and the IA will be pressure tested. The IA will be tested to and the tubing will be tested to 4500 psi (110% of max differential of 4500 psi). i PRV setting procedures and annulus monitoring: Maximum Allowable Treating Pressure: 6700 Stagger Pump Kickouts between: 6350 Global Kickout: 6350 IA pop-off set pressure: 3000 Treating line test pressure: 7700 10,000# 16/30 Sand Requirement 100,000# Cart Minimum Water Requirement 3000 bbls IA Hold Pressure 2700 psi M Of 160,000# 16/20 CarboLite, schedule: psi There are three overpressure devices that protect th urface equipment and the wellbore from overpressure. Each individual frac pump has an electronic kicko that will kick the pumps into neutral as soon as the set pressure is reached. Since there are multiple pu ps, these set pressures are set between 90% and 95% of the maximum allowable treating pressure. There ' the primary pressure transducer in the treating line that will trigger a global kickout which will kick all a pumps into neutral. finally, there is a manual kickout that is controlled from the frac van. All three these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, jA pressure and OA pressure will be monitored in the frac van. r 5-129 Rig Up _ ivvc.lmWn Lme L n ®.taenia ide J Chemical Disclosure (20 AAC 25.283, a, 12) - _ Water(Includine Mia Water Supplied by Client)' -.78% ,40) 1P. 4 ceramic materials and wares, demhcah -^ p % 1'308 6C 1 Qualm, silica 1X -- 9000-30-0 _ _ _Guth gum / c I % 67-48-1 _ FhYdrory-NNN-trimetMiethammmium chloride � <1%-- _ 131933-1 ulc.rue _ - -- — _— <0.1% I07-21-1 _ Ethylene Glycol <0.1 % 7727-54-0 Dido'..nlum lerovidi..ulphil d _ _ <0.1% 67-63-0 _ propan-2-ol _ <0.1 % 11176 2 2-mdri. mhannl - <0.1 % 68131-40-8 Alcohol, c1l-15sewndary, ethoaylaladi <0.1 % 34398-01.1 Ethoaylaled Cll Alcohol <0.1 % 12989801-0 2 -Pro enoic acid, olymer with sodium phos Moate <0.1 is 1310.73 2 Sodium hydrovlde (impurity) _ _ <0.1 Is 25038-72-6 Vin lidene chloride/me[hylaavkte co of mer eD.l % 68131-39-5 Ethoaylated Alcohol <0.1 % 1303-96-4 _ Sodmm Tenraborate Decahydra[e <01 % 7647-14-5 _.. - - - --- Sodium chloride <0 01 % 17-17-8 but-2-enedioic acid --_ <0.01 % 10043-524 _ Calcium Chloride <001 % _ -I12-02 5. Undecanol c 0.01 % 9105339-3 Diatomaceous earth, cakined <D.01 % 7631-86-9 No c staN d (i.,du D.W1 % 3480)96_6 _ Magnesium silicate hydrate air) 0.00I% 10377-60-3 iI Magnes um mVate 0.001% _ 11146-6 22 aydiethanol( rit) _ 0.001% 26172-55.4 _ _ 5 M1I 2 ethyl Zb sot ololdone <0.001 % 9W284-0 _- . .- ..-- _ polyf ndfluoroe Ylene) <D.W1% 7]86-30-3 _ _ _ _ _ _ Magnesium ride c0.001 % 59558515-2 Did <0.WI Is 125005-87-0 Dlmaum e0.W1 % 127-08-2 Acebcacid, otassiummit <0A001% 7U-2— - potassium Imide(impurity)__ - —---_.-"- 268240-4 .. DmethVl- isathiaad-3-ane<0.0001 % 14464-461 — — - dncildiite - �003101 Is Sit 191:7 tic and(impuri[v)-� --- - - c0.0001 is Loepp, Victoria T (DOA) From: Wages, David <David.Wages@bp.com> Sent: Wednesday, February 21, 2018 5:05 PM To: Loepp, Victoria T (DOA); Sidoti, Todd Cc: Wallace, Chris D (DOA) Subject: RE: PBU S-129(PTD 210-132, Sundry 318-044) Fracture Stimulation Follow Up Flag: Follow up Flag Status: Flagged Victoria, Sleeves 1 & 4 is correct. Sleeve 7 will be closed soon in a separate procedure. Once we have verified that the sleeve is closed, we will proceed with the procedure to isolate to sleeve 1 and frac sleeve 1. Sleeve 4 will be frac'd after isolating sleeve 1 with a bridge plug. David Wages SP I AK I Completion Engineer 900 E. Benson Blvd 1744c I Anchorage, AK 99515 Direct: +1.907564.5669 1 Mobile: +1.713.380.9836 From: Loepp, Victoria T (DOA) [mailto:victoria.loepp@alaska.gov] Sent: Wednesday, February 21, 2018 3:16 PM To: Wages, David; Sidoti, Todd Cc: Wallace, Chris D (DOA) Subject: PBU S-129(PTD 210-132, Sundry 318-044) Fracture Stimulation David, Todd, Are the two stages of the frac through SS#1 and SS#4? I don't see anywhere in the procedure where SS#7 is closed. Is SS#7 open? Please clarify. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loeooiilalaska aov 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 Victoria Loepp at (907)793-1247 or Victoria. Loeoo@alaska clov Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Friday, February 16, 2018 3:10 PM To: Sidoti, Todd' Cc: Guhl, Meredith D (DOA) Subject: RE: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Digital Data Request Todd, From your email below: "No, we do not believe there is an additional fault at 11,855' MD. Instead we believe that this is due to a change in lithology (increasing shaliness) supported by the gamma ray, neutron porosity and bulk denisty logs." In the digital well log data provided by BP to AOGCC, I can only find resistivity curves for S-129 between the 7" casing shoe at 9436' MD and the TD of the well at 12,964' MD. Could BP please provide digital data files for the gamma ray, neutron porosity, and bulk density logs for this interval? A file in .las, Alis, or ASCII format would be appreciated. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska aov. From: Sidoti, Todd [mailto:Todd.Sidoti@bp.com] Sent: Tuesday, February 13, 2018 9:42 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: RE: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Hi Steve, Please see my answers below in blue. I have attached a corrected PDF of the application. If and when you are satisfied with our answers I can re -submit the application if that is necessary. Please let me know if you have any further questions or need better clarification. Thanks, Todd Todd Sidoti I BPXA Well Intervention Engineer I Office 907-564-5113 1 Cell 907-6324113 1 todd.sidotinbo.com From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska govl Sent: Wednesday, February 7, 2018 5:25 PM To: Sidoti, Todd <Todd.SidotiCa) bp.com> Subject: FW: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Z/U' 13-2-- Davies, 3Z Davies, Stephen F (DOA) From: Sidoti, Todd <Todd.Sidoti@bp.com> Sent: Tuesday, February 13, 2018 9:42 AM To: Davies, Stephen F (DOA) Subject: RE: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Attachments: S-129 AOGCC Notification Revl.pdf Hi Steve, Please see my answers below in blue. I have attached a corrected PDF of the application. If and when you are satisfied with our answers I can re -submit the application if that is necessary. Please let me know if you have any further questions or need better clarification. Thanks, Todd Todd Sidoti I BPXA Well Intervention Engineer I Office 907-564-51131 Cell 907-632-4113 1 todd.sidoti0&p.com From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Wednesday, February 7, 2018 5:25 PM To: Sidoti, Todd <Todd.Sidoti@bp.com> Subject: FW: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Todd, Rather than send my additional questions to you in piecemeal fashion, I've gathered them together in this single email. Please ignore the two emails that I sent to you earlier this afternoon. I'm working through BP's Application for Sundry Approvals to hydraulically fracture well PBU S-129. This application is nicely formatted, and it contains most of the information required by 20 AAC 25.283, but I need clarification on a few points. 1. Map 1 shows two black rectangles that the map key indicates are "S-129 Frac Location[s)". From the S-129 well completion diagram and the positions of the black rectangles on Map 1, I'm assuming that these rectangles represent the sleeves placed at 9,951' and 11,890' MD, and that the other five sliding sleeves i shown on the well completion diagram will be closed. Correct? Correct. The bottom sleeve will be treated first followed by isolating it and treating through sliding sleeve #4. 2. What is the maximum regional stress direction in the vicinity of PBU S-129? How was this direction determined? The direction is determined with X -Y caliper data which we use to calculate borehole breakout. Depending on the azimuth of the wellbore when drilling, there is a predominate trend for when borehole breakout occurs. For us, in the Kuparuk, this happens when we drill —30 degrees south of west, which is indicative of the maximum stress direction. The minimum stress direction would then be perpendicular to the maximum: 30 degrees west of north. ✓ 3. BP's description of Fault 6 states: "Fault #6 did take losses when drilled." However, BP's Operations Summary Report for PBU S-129 dated 10/24/2010 states that at 11,060' MD some gas was observed in the riser and the drilling mud was cut by gas from 10.3 to 9.7 ppg, but there is no mention of fluid loss while drilling from 11,060'to 11,323' MD. • What is BP's source of information for the fluid loss while drilling Fault #6? • What fluid volume was lost? • Will this fault compromise containment of injected fracturing fluids? • How will BP prevent loss of fracturing fluids to this fault? • What mitigation measures are planned in the event fluid loss is recognized during fracturing operations? Application corrected, it should have read "Fault #6 did not take losses when drilled." ✓ 4. BP's "Anticipated Pressures and frac dimensions" section states: "The frac height is primarily based on closure pressure differences between the harder Sag formation and the softer confining layers. Average confining layer stress is ^0.655 psi/ft." The reference to the Sag formation suggests that these two sentences may be left over from a previous document. Could BP please correct the reference to the Sag formation and confirm that 0.655 psi/ft is an accurate value for the frac gradient? Application corrected, Sag reference changed to Kuparuk and fracture gradient updated to 0.70 psi/ft. 5. Related to Item 5, BP's "Geological Frac Information" table presents an estimated frac pressure [gradient] of 0.70 [psi/ft) for the Kalubik Shale. The portion of BP's application presenting Geological Data for each known or suspected fault states: "The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of ^16 ppg." To avoid any confusion, could BP please review these 0.655 psi/ft, 0.70 [psi/ft], and —16.0 ppg values and provide fracture -gradient range and average values for the a) Kalubik Shale, b) HRZ Shale, and c) underlying Miluveach Shale? The "fracture pressure' that is noted in the geology section (16.0 ppg) should probably be renamed "breakdown pressure" as it is the value that the rig would use while drilling to determine upper limit of mud weight. This value includes the pressure required to overcome the initial hoop stress (to open up the rock) and is different than the (lower) closure pressures that we are concerned with when determining fracture growth. When we frac the Kuparuk formation, decline analysis (taken from injectivity tests) is what we use to determine the closure pressure for the C4 sands. Defining the exact closure pressures of the confining layers is more difficult to determine. We know that shales have a much higher Poisson's Ratio relative to sandstones and therefore have higher closure pressures, so the frac is much more likely to grow downward than up into the shale (as there exists no shale of significant thickness below the C4 sands for more that 100' TVD). We also analyze the injectivity test in orderto predict the growth of the frac. Once the frac is established, a negative slope on the BH pressure while pumping into the formation indicates that the frac is growing in height, flat slope indicates that the frac is growing in height as well as length, and finally, a positive slope indicates that the frac is growing in length at a higher rate than in height. BP has matched treating pressures from previous jobs to come up with a best estimate for the closure pressures of the confining shales. We know that the closure pressure of the Kalubik is at least 0.70 psi/ft as we have not seen significant height growth indicators mentioned above. Since we have never fractured through the shale, it is difficult the estimate the upper bounds of the fracture pressure. The closure pressure of the shales below is also difficult as we have not recently fractured into them either. Essentially, BP knows that the closure pressures of our confining shales is are at least 0.70 psi/ft and this is all the information we need to inform our models. 6. Did PBU 5-129 intersect Fault 10 while drilling? Map 1 indicates this occurred about 300' north-northwest of the TD of the well. If so, at what measured depth did 5-129 intersect Fault 10? If not, please correct Map 1. Map corrected, 5-129 did not cross Fault 10 while drilling. Looking closely at the resistivity curves recorded in PBU 5-129, 1 see a relatively abrupt resistivity shift at 11,855' MD that is similar to the shift evident at 11,162' MD, which corresponds to BP's Fault #6. Is there an additional fault at 11,855' MD? If so, please provide fault orientation, vertical displacement, and vertical persistence information from BP's seismic dataset. No, we do not believe there is an additional fault at 11,855' MD. Instead we believe that this is due to a change in lithology (increasing shaliness) supported by the gamma ray, neutron porosity and bulk denisty logs. 8. Do the separation of the resistivity curves between 12,355 and 12,375' MD, the sharp change in deep resistivity at 12,375' MD, or the change in resistivity character at 12,519' MD represent additional faults? If so, please provide fault orientation, vertical displacement, and vertical persistence information from BP's seismic dataset. We believe the that sharp change in the resistivity logs and separation (13,555-13,575' MD) are cause by siderite as seen by the high and sporadic bulk density log. We believe that the change in character at 12,519' MD is also caused by a decrease in sidertite, which can happen relatively quickly in the upper C sands as seen just below top Kuparuk earlier in the log ("8875-8920' MD). I'll let you know if I have any additional questions. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesftalaska.¢ov. From: Davies, Stephen F (DOA) Sent: Wednesday, February 7, 2018 4:56 PM To: 'todd.sidoti@bp.com'<todd.sidoti@bp.com> Subject: RE: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Todd, An additional question: Did PBU 5-129 intersect Fault 10 while drilling? Map 1 indicates this occurred. If so, at what depth? If not, please correct Map 1. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.eov. From: Davies, Stephen F (DOA) Sent: Wednesday, February 7, 2018 4:11 PM To: 'todd.sidoti@bp.com' <todd.sidoti@bp.com> Subject: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Todd, I'm working through BP's Application for Sundry Approvals to hydraulically fracture well PBU 5-129. This application is nicely formatted, and it contains most of the information required by 20 AAC 25.283, but I need clarification on a few points. 1. Map 1 shows two black rectangles that the map key indicates are "5-129 Frac Location[s]". From the 5-129 well completion diagram and the positions of the black rectangles on Map 1, I'm assuming that these rectangles represent the sleeves placed at 9,951' and 11,890' MD, and that the other five sliding sleeves shown on the well completion diagram will be closed. Correct? 2. What is the maximum regional stress direction in the vicinity of PBU 5-129? How was this direction determined? 3. BP's description of Fault 6 states: "Fault #6 did take losses when drilled." However, BP's Operations Summary Report for PBU 5-129 dated 10/24/2010 states that at 11,060' MD some gas was observed in the riser and the drilling mud was cut by gas from 10.3 to 9.7 ppg, but there is no mention of fluid loss while drilling from 11,060'to 11,323' MD. • What is BP's source of information for the fluid loss while drilling Fault #6? • What fluid volume was lost? • Will this fault compromise containment of injected fracturing fluids? • How will BP prevent loss of fracturing fluids to this fault? • What mitigation measures are planned in the event fluid loss is recognized during fracturing operations? 4. BP's "Anticipated Pressures and frac dimensions" section states: "The frac height is primarily based on closure pressure differences between the harder Sag formation and the softer confining layers. Average confining layer stress is —0.655 psi/ft." The reference to the Sag formation suggests that these two sentences may be left over from a previous document. Could BP please correct the reference to the Sag formation and confirm that 0.655 psi/ft is an accurate value for the frac gradient? 5. Related to Item 5, BP's "Geological Frac Information" table presents an estimated frac pressure [gradient] of 0.70 [psi/ft] for the Kalubik Shale. The portion of BP's application presenting Geological Data for each known or suspected fault states: "The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of —16 ppg." To avoid any confusion, could BP please review these 0.655 psi/ft, 0.70 [psi/ft], and —16.0 ppg values and provide fracture -gradient range and average values for the a) Kalubik Shale, b) HRZ Shale, and c) underlying Miluveach Shale? I'll let you know if I have any additional questions. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. Z l4f) Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Thursday, February 8, 2018 5:18 PM To: 'Sidoti, Todd' Subject: BP's Hydraulic Fracturing Applications for PBU S-129, P1-20, L -205A, S -200A, and S-109 - Information Needed Thank you Todd. For BP's five Hydraulic Fracturing Applications under review, I need: 1. S-129 (PTD #210-132; Sundry # 318-044): Answers to questions and requests emailed to you on 2/7/2018. 2. P1-20 (PTD #192-094; Sundry # 317-548): Fault information requested in my email to David Wages dated 12/19/2017; Area -of -Review maps similar to those in recent PBU L -205A application. When I spoke with Carl on the phone on 1/29, he said that BP would provide the info in the next day or two. 3. L -205A (PTD #217-118; Sundry # 318-020): 1 have all of the information that I need for L -205A. 4. S -200A (PTD #217-125; Sundry #317-491): Information requested in my email to David Wages dated 11/28/2017; Area -of -Review maps similar to those in recent PBU L -205A application. 5. S-109 (PTD #202-245; Sundry #316-444): A revised application per my most recent email exchange with David Wages regarding S-109 (dated 1/14/17) that is attached below. Thanks for your help, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 907-793-1224 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Wages, David [mailto:David.Wages@bp.com] Sent: Wednesday, June 14, 2017 11:30 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Cc: Carlisle, Samantha J (DOA) <samantha.carlisle@alaska.gov> Subject: RE: PBU 5-109 (PTD #202-245, Sundry #316-444) - Application to Fracture Stimulate - Request for Additional Information Nope, we are looking to get that one back up and runner here in a bit. We've had quite a few issues with our deployment system as you may be aware and feel we've finally gotten things ironed out. I will go over it and submit an application per our most recent approved frac sundry (L -200a). From: Davies, Stephen F (DOA) [mailto:steve.daviesCaalaska aov] Sent: Wednesday, June 14, 2017 10:59 AM To: Wages, David Cc: Carlisle, Samantha J (DOA) Subject: RE: PBU S-109 (PTD #202-245, Sundry #316-444) - Application to Fracture Stimulate - Request for Additional Information Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Wednesday, February 7, 2018 5:25 PM To: 'todd.sidoti@bp.com' Subject: FW: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Todd, Rather than send my additional questions to you in piecemeal fashion, I've gathered them together in this single email. Please ignore the two emails that I sent to you earlier this afternoon. I'm working through BP's Application for Sundry Approvals to hydraulically fracture well PBU S-129. This application is nicely formatted, and it contains most of the information required by 20 AAC 25.283, but I need clarification on a few points. 1. Map 1 shows two black rectangles that the map key indicates are "S-129 Frac Location[s]". From the S-129 well completion diagram and the positions of the black rectangles on Map 1, I'm assuming that these rectangles represent the sleeves placed at 9,951' and 11,890' MD, and that the other five sliding sleeves shown on the well completion diagram will be closed. Correct? 2. What is the maximum regional stress direction in the vicinity of PBU S-129? How was this direction determined? 3. BP's description of Fault 6 states: "Fault #6 did take losses when drilled." However, BP's Operations Summary Report for PBU S-129 dated 10/24/2010 states that at 11,060' MD some gas was observed in the riser and the drilling mud was cut by gas from 10.3 to 9.7 ppg, but there is no mention of fluid loss while drilling from 11,060' to 11,323' MD. • What is BP's source of information for the fluid loss while drilling Fault #6? • What fluid volume was lost? • Will this fault compromise containment of injected fracturing fluids? • How will BP prevent loss of fracturing fluids to this fault? • What mitigation measures are planned in the event fluid loss is recognized during fracturing operations? 4. BP's "Anticipated Pressures and frac dimensions" section states: "The frac height is primarily based on closure pressure differences between the harder Sag formation and the softer confining layers. Average confining layer stress is `0.655 psi/ft." The reference to the Sag formation suggests that these two sentences may be left over from a previous document. Could BP please correct the reference to the Sag formation and confirm that 0.655 psi/ft is an accurate value for the frac gradient? 5. Related to Item 5, BP's "Geological Frac Information" table presents an estimated frac pressure [gradient] of 0.70 [psi/ft] for the Kalubik Shale. The portion of BP's application presenting Geological Data for each known or suspected fault states: "The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of —16 ppg." To avoid any confusion, could BP please review these 0.655 psi/ft, 0.70 (psi/ft], and —16.0 ppg values and provide fracture -gradient range and average values for the a) Kalubik Shale, b) HRZ Shale, and c) underlying Miluveach Shale? 6. Did PBU 5-129 intersect Fault 10 while drilling? Map 1 indicates this occurred about 300' north-northwest of the TO of the well. If so, at what measured depth did 5-129 intersect Fault 10? If not, please correct Map 1. Looking closely at the resistivity curves recorded in PBU S-129, I see a relatively abrupt resistivity shift at 11,855' MD that is similar to the shift evident at 11,162' MD, which corresponds to BP's Fault #6. Is there an additional fault at 11,855' MD? If so, please provide fault orientation, vertical displacement, and vertical persistence information from BP's seismic dataset. 8. Do the separation of the resistivity curves between 12,355 and 12,375' MD, the sharp change in deep resistivity at 12,375' MD, or the change in resistivity character at 12,519' MD represent additional faults? If so, please provide fault orientation, vertical displacement, and vertical persistence information from BP's seismic dataset. I'll let you know if I have any additional questions. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.zov. From: Davies, Stephen F (DOA) Sent: Wednesday, February 7, 2018 4:56 PM To: 'todd.sidoti@bp.com' <todd.sidoti@bp.com> Subject: RE: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Todd, An additional question: Did PBU S-129 intersect Fault 10 while drilling? Map 1 indicates this occurred. If so, at what depth? If not, please correct Map 1. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.aov. From: Davies, Stephen F (DOA) Sent: Wednesday, February 7, 2018 4:11 PM To: 'todd.sidoti@bp.com'<todd.sidoti@bp.com> Subject: PBU S-129 (PTD #210-132) Hydraulic Fracturing Application (Sundry #318-044) - Questions Todd, I'm working through BP's Application for Sundry Approvals to hydraulically fracture well PBU S-129. This application is nicely formatted, and it contains most of the information required by 20 AAC 25.283, but I need clarification on a few points. 1. Map 1 shows two black rectangles that the map key indicates are "5-129 Frac Location[s]". From the 5-129 well completion diagram and the positions of the black rectangles on Map 1, I'm assuming that these rectangles represent the sleeves placed at 9,951' and 11,890' MD, and that the other five sliding sleeves shown on the well completion diagram will be closed. Correct? 2. What is the maximum regional stress direction in the vicinity of PBU 5-129? How was this direction determined? 3. BP's description of Fault 6 states: "Fault #6 did take losses when drilled." However, BP's Operations Summary Report for PBU 5-129 dated 10/24/2010 states that at 11,060' MD some gas was observed in the riser and the drilling mud was cut by gas from 10.3 to 9.7 ppg, but there is no mention of fluid loss while drilling from 11,060' to 11,323' MD. • What is BP's source of information for the fluid loss while drilling Fault #6? • What fluid volume was lost? • Will this fault compromise containment of injected fracturing fluids? • How will BP prevent loss of fracturing fluids to this fault? • What mitigation measures are planned in the event fluid loss is recognized during fracturing operations? 4. BP's "Anticipated Pressures and frac dimensions" section states: "The frac height is primarily based on closure pressure differences between the harder Sag formation and the softer confining layers. Average confining layer stress is -0.655 psi/ft." The reference to the Sag formation suggests that these two sentences maybe leftover from a previous document. Could BP please correct the reference to the Sag formation and confirm that 0.655 psi/ft is an accurate value for the frac gradient? 5. Related to Item 5, BP's "Geological Frac Information" table presents an estimated frac pressure [gradient] of 0.70 [psi/ft] for the Kalubik Shale. The portion of BP's application presenting Geological Data for each known or suspected fault states: "The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of -16 ppg." To avoid any confusion, could BP please review these 0.655 psi/ft, 0.70 [psi/ft], and -16.0 ppg values and provide fracture -gradient range and average values for the a) Kalubik Shale, b) HRZ Shale, and c) underlying Miluveach Shale? I'll let you know if I have any additional questions. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware ---of-the mistake intending -it to-you-,centact-Steve Davies at-907-793-1224-orsteve:daviestaataska.gov - - — 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Paragraph (a) Application for Sundry Approval (a)(1) Affidavit (a)(2) Plat Sub -Paragraph _� Section Complete? Provided with application. Notification to ConocoPhillips, I SFD (a)(2)(A) Well location (a)(2)(8) Each water well within % mile (a)(2)(C) Identify all well types within '/, mile (a)(3) Freshwater aquifers: geological name; measured and true vertical depth ExxonMobil, Chevron, DNR. 2/2/20 Provided with application. SFD Provided with application. SFD 2/2/2018 Provided with application: No wells are used for drinking water purposes are known to lie within %, mile of the surface location of PBU S-129. According to the Water Estate map available through DNR's Alaska Mapper application (accessed online Feb. 2, 2018), the nearest water -source well (Milne Point K-34) is located 8.4 miles northwest of the fracturing interval. (See DNR LAS Case Files 20693 and 30050.) MPU K-34 is open to the Ugnu SFD Formation between -4,327 and -4,516 true vertical feet 2/2/2018 subsea ("TVDSS"), which is about 2,170 true vertical feet shallower than the proposed fracturing interval within the Kuparuk Formation of PBU 5-129. The nearest temporary surface water right is for BP to withdraw water from a lake west of S -Pad, which is located 1.3 miles to the northeast. (See DNR LAS Case File 28154.) Within % mile there are 145 wells and lateral wellbores and 50 plugged -back wellbores that were lost during SFD drilling operations. Within'/, mile of the fracturing interval, 2/16/2018 there are 16 wells and lateral wellbores. Tertiary -aged Sagavanirktok Formation, which lies beneath permafrost. In this area, permafrost appears to be about 1,550' thick. (Only one older exploratory well located in SFD this area—N Kuparuk State 26-12-12—was logged with a 2/2/2018 sonic tool from ground level to surface casing point.) However, in AEO 1 the AOGCC concluded that those AOGCC Page 1 February 22, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Paragraph Sub -Paragraph Section Complete? portions of freshwater aquifers occurring beneath the Western Operating Area of Prudhoe Bay Unit 1) do not currently serve as a source of drinking water, 2) are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable, and 3) have TDS content of 7,000 mg/I or more. By letter dated July 1, 1986, EPA exempted aquifers in this area for Class II injection activities (source: AOGCC's AEO 1 order file, Sections #5 and #6). For an outline of the Western Operating Area, see the EPA's "Alaska Oil & Gas Aquifer Exemptions Interactive Map" available online under the "Permits" section of EPA Region 10's web page at https://www.epa.gov/uic/underground-iniection- (a)(4) Baseline water sampling plan I No drinking water sources. Sampling not required. (a)(5) Casing and cementing information Provided with application. (a)(6) Casing and cementing operation assessment (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 (o)(6)(8) Each hydrocarbon zone is isolated Intermediate casing cement spotty but provides isolation and containment of the reservoir to upper formations. As a precaution, the closest open sliding sleeve to the heel will be 1076' ft away so this is nearest point that frac will initiate. (The/: length of each frac stage is predicted to be 250 ft so this will keep the last frac stage wing from intersecting the -casing -shoe. ) Provided with application. Yes. In PBU S-129, 8-3/4" intermediate hole was drilled to 9,445' MD (6,820' TVD, -6,757' TVDSS), and 7" casing was run to 9,436' MD (also 6,820' TVD, -6,757' TVDSS because SFD 2/2/2018 SFD CDW 2/12/2018 VTL 2/22/18 CDW 2/12/2018 SrL) 2/6/2018 AOGCC Page 2 February 22, 2018 Paragraph 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Sub -Paragraph Section Complete?J this section of PBU 5-129 is nearly horizontal), and cemented with 144 barrels (808 W; 454 sacks; yield = 1.78) SFD of LiteCrete and 39 barrels (219 ft3; 223 sacks; yield = 0.98) 2/20/2018 of Class G Cement (pertinent cementing reports are appended to the base of this checklist, below). Volumetrically, the top of cement for the 7" casing string is estimated to be about 4,178 MD, 3,822' TVD, -3,760' TVDSS (assuming 30% hole washout), so cement covers the Kuparuk Formation at the heal of the well and the confining shales, likely reaching upward to cover the stratigraphic equivalent of all but the shallowest oil shows in nearby well PBU TW -C ("Term Well C"; see oversized AOGCC cross-section, attached separately). (a)(7) Pressure test: information and pressure -test plans for casing and tubing Provided with application. 3500 psi rig casing test, 4000 psi CDW installed in well MITIA planned, 4500 PSI MITT plan. 2 12 2018 / / Pressure ratings and schematics: Provided with application. 5K psi wellhead 10K psi tree CDW w wellbore, wellbore, wellhead, ROPE, treating head saver, max. frac. Pressure 6700 psi. Pump knock out 6050 2/12/2018 1 psi and 6350 psi, Global kickout 6350 psi. Upper confining zones: from PBU TW -C mud log - several lithol ogic description for each zone (A) Fracturing and confining zones: intervals of shale and silty shale within the Hue, HRZ, and ithol Kalubik Shale intervals between about 8,054' and 8,872' (a)(9)(B) Geological name of each zone measured depth (MD; equivalent to -6,242' to -6,706' true vertical depth subsea, or TVDSS) have an aggregate 818' (o)(9)(C) and (a)(9)(D) Measured and true measured thickness (MT) and 464' true vertical thickness SFD vertical depths (TVT). (See attached figures, below.) Estimated fracture 2/6/2018 gradient provided by operator is 0.70 psi/ft. (a)(9)(E) Fracture pressure for each zone Fracturing Zone: from Operator — Kuparuk Formation, about 8,872' and 9,030' MD (-6,706' to -6,767' TVDSS) having an aggregate 158' MT and 61' TVT. The mud lo¢ AOGCC Page 3 February 22, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Paragraph Sub -Paragraph Section Complete? Cementing information for PBU S-129 Surface Casing Intermediate Casing — 7" Description of Operations �CEMENTLINES- Description of Operations PJSM, WITH SLB CEMENTERS. RU SLB . _. PUMP 56BLS OF 10.0 PPG CIRCULATE AND CONDITION HOLE IN 'MUD PUSH. SHUT DOWN AND PRESSURE PREPARATION FOR CEMENT JOB. TEST TO 3500 PSL PUMP 95 BBLS OF MUD - STAGE UP IN 112 -BBL INCREMENTS TO 6 PUSH AHEAD AT 5 BPM AND 225 PSI. SHUT BPM. DOWN AND DROP BOTTOM PLUG. PUMP 500 RR1 cr 1020 SKS 12za rl l�rcnrK) OF 101 - ICP 905 PSI, FCP 780 PSI. PPG ARCTIC SFT LITP LPAD AT 6 BPM AND - RECIPROCATE PIPE IN 10 -FT STROKES. 220 PSI, RECIPROCATE PIPE IN 10FT STOKES PU WT 240K, $O WT 135K. - 6 BPM, 210 PSI, 156 BELS LEAD AWAY, MUD _- 7" CASING CEMENT JOB, PUSH AT SHOE - 6 BPM.225 PSI, 244 BELS LEAD AWAY, P UMPED 30 BBLS 10 8 PPG MUD PUSH 11 AT BOTTOM PLUG LATCHED AT 900 PSI STOP 6 BPM. RECIPROCATING PIPE AND LAND ON PRESSURE TESTED SURFACE LINES TO LANDING RING 3,500 PSI; TEST GOOD. - 6 BPM, 400 PSI, 338 BELS LEAD AWAY. -DROP BOTTOM PLUG. SPACER AT SHAKERS 419- - 6 BPM, 424 PSI,I, 419 BBLS LEAD AWAY. PUMPED 144 BBLS 11.0 PPG LITE CRETE CEMENT SPACER INTERFACE TO SURFACE CEMENT AT 6 BPM. - SLOW TO 2.8 BPM, 288 PSI, 500 BBLS LEAD - A54 SKS_ 1 Al CLI FTISK YIELD. AWAY - PUMPED 39 BBLS 15.8 PPG CLASS G SWAP ON THE CEMENT AT 6 BPM_ FLY AND PUMP R7 ARI x ��73p OF 15 6 fl ASS C. CEMENT (1 f R - 223 SKS. 1.16 CU FTISK YIELD. CUFTISACK) AT 6 BPM AND 440 PSI -DROP TOP PLUG. - 3 BPM, 320 PSL 74 BBLS TAIL AWAY. GOOD - DISPLACED WITH 5 BBLS OF 8.3 PPG CEMENT BACK TO SURFACE CLEAN-UP WATER FROM SLB TRUCK AND 350 BBLS OF 10.3 PPG BRINE FROM RIG, DROP TOP PWG AND BEGIN DISPLACEMENT - BUMPED PLUGS; PRESSURED UP TO 500 AT 7 BPM AND 295 PSI - 5 BPM, 1140 P51, 209 BBLS DISPLACED PSI OVER FCP TO 1,900 PSL SLOW TO 3 BPM FOR BUMP, 1029 PSI, 223 - BLED OFF AND CHECKED FLOATS; FLOATS BBLS DISPLACED HELD. BUMP PLUG AT 234 BBLS DISPLACED AND - CEMENT IN PLACE AT 1039 HRS. PSI. BLEED OFF PRESSURE AND CHECK CHECK FLOATS. TOTAL OF 365 BBLS RD CASING AND CEMENTING EQUIPMENT. CEMENT BACK TO SURFACE. PRESSURE UP TO 3500 PSI FOR 5 MIN TO TEST CAST AOGCC Page 9 February 22, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Paragraph Sub -Paragraph Section Complete? j K S -09A S -24A S-201 K 5 N KUPAFQI. RVV6-12-1 K K' S-21 S-34 S-32 a it 401 AAS-35 K 6 K 9J*108 S-110 pti S -113A `� S-2281, Ks _' W -S -110B 4 K K S-'9pall0A 5-101 S-22 - OQ'� 38 S -44L1 K_12 S -25K 8 K� / S- S -01 Krf K36 K ,'S_ti.$L -172 sY� /J el 5-115- 1 3dgKcs�r,�-1 OA S-1 K K°5-100 R-41 As-1 i3B L1 5-126 +K 4S it �k' K M-19 26 S-1 87 1 r�-" 29A ,q K - ,� !3- 8 �^ S-14 O 3� • �i7 00 D4 S4'�SAKa6R K K S 1237- 05 S-26 S-118 M-2 `SSF134K � •5�=�5B�A S -28B GB' 6 K�' M-06 M -26A S-1 28A X28 K S-08 20A 5-11 M-30 (YS -11 S-20 M- AS -116 K S -11A S-215 86S-SWA 9 r S-19 — — - — t S-217 r S-06 S_12 S 128 �j S-216 5-27 t -40 S -27A -. � KEY S-129 S-213 L3 S-02te S- S -21 L1 -27B S-213 LI -01 Well Paths A S 213 1 S -02A W-202 Ter 13 2 S-218 Sr0)°S_ �\ One -Halt Mile Radius 5-135 W -202L1 Well C - S 29A i Frac interval -Proposed aW-C011 r %'' Ruparuk Fm Intercepts 0 1ml S-29AL1 5-29 1 S-18 • Surface Using Points • Intermediate Csg Points • Production Ug Points S -18A Perforations AOGCC Page 10 February 22, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Paragraph Sub -Paragraph Section Complete? AOGCC Page 11 February 22, 2018 500292343300 2101320 PBU AURORA S-129 111111111111 ISM awl L^f mo ..., - Hue Shale +wo �- uoo 8Y0 -8500 Upper Confining � WN HRZ °°°° �3 3— -8500 Layers KLBK. Fracturi L ig Interval WKPRKC y --� — — -9000 _ _-' KPRKB BIM - _ _.- 9000 Lower C nfining Layers FKPIKI Vertical scale for reference log is in units of feet of measured depth AOGCC Page 11 February 22, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist PBU AURO S-129 (PTD No. 210-132; Sundry No. 318-044) Paragraph Sub -Paragraph Section Colville dV0 Hue Shale -M! euro HRZ Shale Kalubik Shale - Kuparuk Miluveach "W Cualn 1.0 mks 2101320 cei0. 0.1 nVaa 2031810 Complete? I I 5. 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O 0. ,_ ,_ X>.0.�s 0 CU - 7 •0 9 X CO-0.- L 2 L 0 O 0 0 (0 O 0 7 E (6 7 O E.0 O a) CO N `p O U U C(f N.E o a N'p.0 L o.3 ~O E V o .N m `o L o N.`° U N g, N Q 0 (n co (/) 0 m 2 LL 0 Q r (A"6 to Z 2 2 N C/) n Co 2 2 u._'O C N Q)L(/)M 0J) d N < (1) 6 X C/)N(/) H€Q — U) 0 U) 2 U) C) C) L fa m T a) i U) ca CC U O N d a)'Q a) a a) � aoN O cCn E o L o C o-o o f° c a) o E'm CC `o a 3 > _c O 0 E c eco >,z o❑ o x a) N c Y c 3 O mY cn N co a -O O LL O U F L N = C 0 a o a) C,— • U • U cc is `o rU L N U N N N O O O O O U C — 0 N O C Y N E N a x a C E E N m a E 0 f• LC , L CC U C O O0o o N N C E m > o 2 a) o N ❑ E > — -o 0 C m a$N C E C a) m o o a) 0 ▪ om Z EIVED STATE OF ALASKA - ALASKA OIL AND GAS CONSERVATION COMMISSION ,JUL, 2 3 2015 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations U Fracture Stimulate L'_I Pull Tubing U A0GQptions shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pod❑ Repair Well El Re-enter Susp Well ❑ Other ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: BP Exploration(Alaska),Inc Development ❑ Exploratory 210-132 3.Address: P.O.Box 196612 Stratigraphic ❑ Service 0 6.API Number: Anchorage,AK 99519-6612 50-029-23433-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0028261 AURA S-129 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): PRUDHOE BAY,AURORA OIL 11.Present Well Condition Summary: Total Depth measured 12964 feet Plugs measured None feet true vertical 6790.65 feet Junk measured 8667 feet Effective Depth measured 12964 feet Packer measured 8631 feet true vertical 6790.65 feet true vertical 6636.63 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80 20"91.5#H-40 29.36-109.36 29.36-109.36 1490 470 Surface 3266.02 9-5/8"40#L-80 28.86-3294.88 28.86-3193.14 5750 3090 Intermediate Production 9409.55 7"26#L-80 26.35-9435.9 26.35-6819.69 7240 5410 Liner 4170.92 3-1/2"9.2#L-80 8699.08-12870 6674.37-6790.93 10160 10530 Perforation depth Measured depth 8919-8930 feet 8959-9714 feet 9743-10659 feet 10687-11546 feet 11556-12266 feet 12294-12838 feet True Vertical depth 6792.23-6797.48 feet 6809.87-6814.74 feet 6813.52-6824.27 _feet 6825.73-6845.71 feet 6845.36-6802.51 feet 6799.99-6791.03 feet Tubing(size,grade,measured and true vertical depth) 4.5"12.6#13Cr80 25-4083 25-3755 3.5"9.2#13Cr80 4083-8710 3755-6681 Packers and SSSV(type,measured and true vertical depth) See Attachment See Attachment See Attachment Packer None None None SSSV 12.Stimulation or cement squeeze summary: Intervals treated(measured): 8919'-8930',8959'-9714'. Treatment descriptions including volumes used and final pressure: Please See FracCAT Treatment Report 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 661 479 90 1066 224 Subsequent to operation: 739 537 106 1056 224 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run ❑ Exploratory ❑ Development 0 Service ❑ Stratigraphic ❑ Daily Report of Well Operations 0 16.Well Status after work: Oil 0 Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-080 Contact Garry Catron Email Garry.Catron@BP.Com Printed Name Garry Catron Title PDC PE Signature ay/ CZ/7 "----7 Phone 564-4424 Date 7/23/2015 I/7-Z-rf r c J 101osp%' RBDMS)k JUL 2 4 2015 /z�/ib Eod ✓ "1 .2.4,//6 Form 10-404 Revised 10/2012 Submit Original Only • i Packers and SSV's Attachment AURA S-129 SW Name Type MD TVD Depscription S-129 PACKER 8631.22 6636.63 7"X3.5" HES TNT Packer S-129 PACKER 8699.08 6674.37 5" Baker ZXP Top Packer S-129 PACKER 8930.05 6797.51 3-1/2" OBM Swell Packer S-129 PACKER 9714.35 6814.72 3-1/2" OBM Swell Packer S-129 PACKER 10658.65 6824.24 3-1/2" OBM Swell Packer S-129 PACKER 11546.14 6845.71 4.5"X5.75" Lite Slip-on Swell Packer S-129 PACKER 12266.35 6802.48 3-1/2" OBM Swell Packer . • 51- -0 _ N 0 0) �° n3 E 0 0)2 c a) cn o °�.0 co o 2_ E U ,� �- 0 06 U)co 00 ( Y 0 C O) c 0_CD 0)(n CO O coo 2 > LL o - C a N 3 coao O = >, o� Eb" -a - °� O 3 O w w C (O O M (6 Y 7 OO J a c2 L ia) LL C , < CO U O _- -C U Q- U) (n C O .- _ - oONuaO _ 0 3 o rn.Q-O I > E ami U ,_ m as o w 2 € Q Zai CO ao) .(7) 32 2bU N J c 60 L * O N Z -a O ` O - O (n O N- X • c 2 a O o U O °� _ °� __ C� ca CI)(N rn C U C To LE- 'S °O O Q p CD L p QCia o 0 06 ai 0 a) aria. 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S \ _ CIS k � . 2 b - / E N- • © k u_ = < / f k \ k / • 5 < m = < Ill ) _ \o0C 25 t — 333 $ E 7 5 2 — e Rte $ \ ƒ O Et \ % mo & ƒ • \ @ 2 c E \ \ 0 _ - a » a ± r o• % / f co (NJ - \ / / / U RO (N u) < c 6 m < Lo r \ / A / / • FracCAT Treatment Report S-129 Well :S-129 Field :Aurora Formation : Kuparuk C Prepared for Client :BPXA Client Rep :Dan Scarpella Date Prepared May 10,2015 Prepared by Name :Alexander Martinez Division :Schlumberger WS Phone :907-659-6115 Proppant and Pressure Total Proppant Pumped(Ib) 89,741 Total Proppant in Formation(Ib) 88,722 Initial Wellhead Pressure(psi) 710 Total YF125FIexD Fluid Pumped(gal) 30,818 Injection Test ISIP(psi) 4,440(BH) Treating Lines Pressure test(psi) 8,245 End of Job ISIP(psi) 4,630(BH) Maximum Treating Pressure(psi) 6,244 Well Shut-in Pressure(•si) 1,540 Treatment Totals(bbl) Total Slurry Pumped Total Clean Fluid Pumped (Water+Adds+Proppant+Freeze Protect) 1045 (Water+Adds+Freeze Protect) 950 Total Chemical Additives Used Total Chemical Additives Past Wellhead 16/20 CarboLite(lbs) 60,240 16/20 CarboLite(lbs) 60,240 16/30 Sand(lbs) 31,540 16/30 Sand(lbs) 31,540 J580(lbs) 939 J580(lbs) 889 J604(gal) 70 J604(gal) 70 M002(Ib) 15 M002(Ib) 15 F103(gal) 37 F103(gal) 37 L065(gal) 43 L065(gal) 43 L064(gal) 67 L064(gal) 67 J475(Ib) 330 J475(Ib) 330 M275(Ib) 18 M275(Ib) 13 J134(Ib) 26 J134(lb) 0 D206(gal) 5 D206(gal) 5 LVT200(bbl) 48 LVT200(bbl) 25 Water(bbl) 983 Water(bbl) 935 Disclaimer Notice This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced by a computer model including various assumptions on the well,reservoir and treatment.The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values.The quality of input data,and hence results,may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment,and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. • • Schlumberger Client:BP Exploration Alaska Well:5-129 Formation.Kuparuk C District.Prudhoe Bay Country:United States Section 1 : 1 Frac Design, Diagnostic: As Measured Pump Schedule As Measured Pump Schedule Step Step Slurry Slurry Pump Fluid Prop Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name Cone Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 Load hole 99.6 19.7 5.5 WF125 4'83 0.0 0.0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 Load hole 19.7 23.3 5144 6244 452 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 99.6 5.5 4183 0 Average Treating Pressure: 5144 psi Maximum Treating Pressure: 6244 psi Minimum Treating Pressure: 452 psi Average Injection Rate: 19.7 bbl/min Maximum Injection Rate 23.3 bbl/min Average Horsepower 2528.5 hhp Maximum Horsepower 3556.4 hhp Maximum Prop Concentration: 0.0 PPA Section 2: 1 Frac Desi • n, Dia• nostic: Job Messa• es Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure Psi) (psi) (bbl) (bbl/min) (PPA) 1 9:10:14 Arrived on location 7AM 0 0 0.0 0.0 D.0 2 9:36:28 Pumps started and warmed,waiting for company 0 0 0.0 0.0 0.0 man to prime up 3 9:36:36 POD pull test done 0 0 0.0 0.0 0.0 4 9:36:47 Bucket checks done on PCM and LAS 0 0 0.0 0.0 0.0 5 9:37:24 Waiting on BP 0 0 0.0 0.0 0.0 6 9:57.06 Company men here,asked to see LAS bucket 0 0 0.0 0.0 0.0 checks 7 11:05:30 88 bbls of LVT 0 0 0.0 0.0 0.0 8 12:00:00 Begin safety meeting 0 0 0.0 0.0 0.0 9 12:54:06 BP safety meeting done 0 0 0.0 0.0 0.0 10 12:58.21 Mixing gel in PCM 0 0 0.0 0.0 0.0 11 13.03:30 Confirm IA open -1 -2 0.0 0.0 0.0 12 13:10:41 Confirmed flush volume with client 1 -2 0.0 0.0 0.0 13 13:14:31 25#gel from PCM 0 -2 0.0 0.0 0.0 14 13:15.10 Priming POD with gelled water 1 -2 0.0 0.0 0.0 • • Schiumberger Client:BP Exploration Alaska Well S-129 Formation:Kuparuk C District.Prudhoe Bay Country:United States Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (psi) (psi) (bbl) (bbl/min) (PPA) 15 13:25.49 Priming pumps 53 -2 0.0 6.1' D.0 16 13:4458 Getting Clear all around\ 97 -2 0.0 0.1 0.0 17 13:45:46 Bringing up low PT 96 -2 0.0 0.1 0.0 18 13:46:41 All pumps tripped,global shutdown tripped 2727 -2 0.0 0.0 D.0 19 13:46:55 Bleeding lines down 200-300 psi 2651 -2 0.0 0.0 0.0 20 13:47:26 Waiting for 5 min low PT 415 -2 0.0 0.0 0.0 21 13:52:55 Getting all clear for high PT 283 -2 0.0 0.1 0.0 22 14:02.11 Good 5 min PT 7862 -2 0.0 0.1 D.0 23 14:03:56 Bleeding pressure down to 5k for check valve test 5478 -2 0.0 0.1 0.0 24 14!04:52 Bled off backside of the check valve:holding 5451 -2 0.0 0.0 0.0 steady Test 25 405:14 Test confirmed:bleeding front side pressure to 645 -2 0.0 0.0 0.0 26 14:05:53 Getting good zero on global trips 82 -2 0.0 0.1 D.0 27 14:07,00 All done fueling,fuelers leaving location 82 -2 0.0 0.1 0.0 28 14:09:09 LRS PT'd their lines:good PT 83 -2 0.0 0.1 0.0 29 14:09:23 Setting popoff to 8,650psi 82 -2 0.0 0.0 0.0 30 1409:50 Stinger's manual valve open,hydraulic valve still 84 -2 0.0 0.0 0.0 closed 31 14:1021 Getting all clear,bumping pressure to 1,000psi to 84 -2 0.0 0.1 0.0 equalize 32 14:11:52 Confirming bleed valves closed 83 -2 0.0 0.1 0.0 33 14:11:57 Stinger checking valves 82 -1 0.0 0.0 0.0 34 14:12:35 Bleeding pressure down to 1,000 to equalize to WH 2923 -1 0.0 0.0 0.0 35 14:13:58 Client approval to open WH 962 -2 0.0 0.0 0.0 36 14:14:16 Walking LRS IA to 2,900psi 704 -2 0.0 0.1 0.0 37 14:14:35 WH open:710 psi 705 -2 0.0 0.1 0.0 38 14:20:12 LRS confirm pressure 724 2943 0.0 0.1 0.0 39 14:20:21 Getting ready all around to go down hole 724 2942 0.0 0.0 0.0 40 14:21:33 Watching IA... Bleeding back to 2,500psi 718 2931 0.0 0.0 0.0 41 14:24:24 Start Diagnostic Automatically 708 2512 0.0 0.1 0.0 42 14:24:24 Start 1 Frac Desig Automatically 708 2512 0.0 0.1 0.C, 43 C- 43 14:24:24 Started Pumping 708 2512 0.0 0.1 0.0 44 14:24:38 Client approval to start pumping 708 2510 0.0 0.0 0.0 45 14:29:27 Getting deck side of POD back up to rate 5009 2759 86.0 20.0 0.0 46 14.29:40 Switched between POD and FPC 4870 2755 90.3 20.0 0.0 47 14:29:50 Activated Extend Stage 4764 2755 93.7 20.0 0.0 48 14:30:35 Pumps down,brake set 1287 2614 99.6 0.1 O.C. 49 14:30:46 ISIP:4440psi,1,520 psi surface 1224 2624 99.6 0.1 C C- Agre50 14:50.13 PAD ed with client to add an extra 100 bbls to XL 469 2655 99.6 0.0 0.0 51 14:52:04 Getting ready all around 457 2654 99.6 0.0 0.0 52 1453:08 Deactivated Extend Stage 452 2653 99.6 0.1 0.0 • • Scidumberger Client:BP Exploration Alaska Well S-129 Formation:Kuparuk C District.Prudhoe Bay Country:United States Section 3: Pros sed Frac: As Measured Pum s Schedule As Measured Pump Schedule Ste Ste Slurry Slurry Pump Fluid MaxrProp Prop #p Name Volume Rate Time Fluid Name Volume Proppant Name Cone Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (lb) 1 Displace 50.0 25.1 2.4 WF125 2100 0.0 0.0 C 2 Pad 167.6 34.8 4.9 YF125FIexD 7040 0.0 0.0 C 3 0.5 PPA 100.0 35.1 2.8 YF125FIexD 4109 16/20 CarboLite 0.8 0.2 1986 4 Pad 100.0 35.4 2.8 YF125FIexD 4195 16/20 CarboLite 0.5 0.0 0 5 1.0 PPA 50.0 35.3 1.4 YF125FIexD 2016 Jordan Unimin 16/30 1.0 0.6 1825 6 3.0 PPA 49.5 35.0 1.4 YF125FIexD 1885 Jordan Unimin 16/30 3.8 2.1 4180 7 6.0 PPA 49.5 35.1 1.4 YF125FIexD 1672 Jordan Unimin 16/30 6.5 1.5 8888 8 8.0 PPA 100.6 35.0 2.9 YF125FIexD 3120 Jordan Unimin 16/30 9.2 1.9 24379 9 10.0 PPA 60.0 29.2 2.1 YF125FIexD 1766 Jordan Unimin 16/30 9.9 4.8 16618 10 10.0 PPA 119.4 29.3 4.1 YF125FIexD 3630 16/20 CarboLite 10.1 0.0 31865 11 Flush 33.0 30.8 1.1 YF125FIexD 1385 0.0 0.0 C 12 Flush 33.0 26.2 1.4 WF125 1391, 0.0 0.0 C 13 Flush 33.6 16.2 2.2 Freeze Protect 1411 0.0 0.0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 Displace /25.1 32.4 4750 5594 492 2 Pad 34.8 40.0 5551 6115 4253 3 3.5 PPA 35.1 35.4 5538 5598 5464 4 Pad 35.4 35.5 5509 5679 5348 5 1.0 PPA 35.3 35.4 5363 5414 5337 6 3.0 PPA 35.0 35.2 5311 5344 5271 7 6.0 PPA 35.1 35.2 5160 5305 4966 8 8.0 PPA 35.0 35.4 5375 5871 4908 9 10.0 PPA 29.2 32.3 4620 4730 4595 10 10.0 PPA 29.3 30.4 4961 5076 4711 11 Flush 30.8 31.0 5271 5410 5076 12 Flush 26.2 31.0 4621 5525 2477 13 Flush 16.2 16.9 2904 3045 4 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 946.3 30.9 35722 89741 Average Treating Pressure: 5169 psi Maximum Treating Pressure: 6115 psi Minimum Treating Pressure: 4 psi Average Injection Rate: 32.3 bbl/min Maximum Injection Rate: 40.0 bbl/min Average Horsepower: 4163.2 hhp Maximum Horsepower: 5987.3 hhp Maximum Prop Concentration: 10.1 PPA • • Scliluniberger Client:BP Exploration Alaska Well:5-129 Formation.Kuparuk C District:Prudhoe Bay Country:United States Section 4: 1 Frac Design, Propped Frac: Job Messages Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (psi) (psi) (bbl) (bbl/min) (PPA) 1 14:53:14 Start Propped Frac Manually 573 2665 99.6 1.5 0.0 2 14:5423 Stage at Perfs:Load hole 4033 2767 14.7 19.8 0.0 3 14:55:47 Walking rate up slowly 5406 2765 54.8 31.6 0.0 4 14:57:34 Stage at Perfs:Pad 5439 2818 114.6 34.2 0.0 5 14:58:55 Stage at Perfs:Pad 6158 2799 165.1 39.9 0.0 6 14:59:22 Pump tripped out 5834 2791 181.3 34.9 0.0 7 14:59:32 Tank 1:8'8" 5008 2768 187.4 38.2 0.0 8 14:59:44 Pump tripped again 4517 2738 193.8 26.5 0.0 9 14:59:55 Activated Extend Stage 5340 2784 198.7 27.8 0.0 10 15:00:29 Deactivated Extend Stage 5541 2797 217.6 34.8 0.0 11 15:00:29 Started Pumping Prop 5541 2797 217.6 34.8 0.0 12 15:01:46 Uo28 bumped to 1.4gpt 5504 2817 262.6 35.4 0.4 13 15:03:45 Stage at Perfs:Pad 5363, 2818 332.5 35.2 -0.0 14 15:03:50 Stopped Pumping Prop 5331 2818 335.5 35.5 0.0 15 15:04:03 Prop at perfs 5418 2826 343.2 35.4 0.0 16 15:04:58 XL pH=9.3 5597 2820 375.6 35.4 0.0 17 15.06:03 Started Pumping Prop 5428 2796 414.0 35.5 0.0 18 15:06:35 Stage at Perfs:1.0 PPA 5367 2796 432.8 35.1 1.0 19 15:09:26 Stage at Perfs:3.0 PPA 5272 2801 532.8 35.2 4.8 20 1510:52 Stage at Perfs:6.0 PPA 5023 2766 583.0 34.9 7.1 21 15:12:17 Stage at Perfs:8.0 PPA 5652 2775 632.8 35.0 8.1 22 15:13:46 Stage at Perfs:10.0 PPA 4607 2721 681.4 28.9 9.2 23 15:17:03 pH=9.2 5025 2732 777.1 29.3 10.0 24 15:17:13 Stopped mixing gel at 720 total clean 5066 2730 782.0 29.2 10.0 25 15:17:27 holding rate at 30 BPM per client request 5047 2723 788.8 29.4 10.2 26 15:18:17 Activated Extend Stage 5011 2781 813.2 29.3 9.9 27 15:19:16 Stage at Perfs:10.0 PPA 5032 2772 842.1 30.2 0.1 28 15:19:25 Deactivated Extend Stage 5109 2777 846.7 30.5 0.0 29 15:20:30 Called flushed at 946 5445 2781 880.1 30.9 0.0 30 15:20:49 Cut XL 979 total slurry 5488 2786 889.9 31.0 O.C. 31 15.20:56 Shutdown at 1045 5522 2788 893.5 31.0 -0.0 32 15:21:15 Dropping rate for LVT 3268 2672 902.3 18.5 -0.0 33 15:21:42 Stopped Pumping Prop 2453 2750 909.8 12.7 -1.5 34 15:23:49 Activated Extend Stage 3057 2868 943.7 16.8 0.0 35 15:25:04 Shutdown,brakes set 1869 2821 945.7 0.0 0.0 36 15:27:12 ISIP:4630psi 1705 2805 945.7 0.0 0.0 37 15:29:51 Shutting in well per client request 1564 2783 945.7 0.0 0.0 38 15:30:05 Monitoring BH gauge 1554 2781 945.7 0.0 0.0 39 15:30:32 WH shut 1525 2778 945.7 0.0 0.0 40 15:33:07 Bleeding down surface lines 1328 2762 945.7 0.0 0.0 41 15:34:39 Well shut in pressure: 1540psi 5 2753 945.7 0.0 0.0 • • Schlumberger Client:BP Exploration Alaska Well:S-129 Formation:Kuparuk C District:Prudhoe Bay Country:United States Section 5: Plots Pressure Test BP Exploration Alaska S-129 05-10-2015 9000 45 8000' - Treating Pressure Annulus Pressure - BH Pressure • 36 7000- , -•-- Clean Flus- + — Slurry Rate 6000- JJ — Prop Concentration BH Prop Concentration 5000- 27 9 . . 4000 -g 18 i 3000- 2000- 9 E. 1000- 3 0 • 0 13:43:58 13:50:38 13:57:18 14:03:58 14:10:38 Time-hh:mm:ss ©Schlumberger 1994-2012 SChlumberger • • Schlumberger Cr :iet:BP Exploration Alaska U �• WellS-129 Formation:Kuparuk C District:Prudhoe Bay Country:United States Main Treatment — TreatingPressure BP Exploration Alaska S-129 — Annulus Pressure 05-10-2015 — BH Pressure 7000 — Clean Fl. —' Slurry Rate • 50 500 Prop Concentration ,� rry, 0 MM �/ - BH Prop Concentration n 6000- — Outer Annulus 0 4 40 o -400 4 m 5000- • o $ — 4000- 30 3001m73 Go D Z L D Zc r H 3000 rnr^� 20 d 200 N _8. o a 2000- � 1-. � 10 33-- 100 1000-) a 3 14:23:30 14:40:10 14:56:50 15:13:30 15:30:10 Time-hh:mm:ss ©Schlumberger 1994-2012 Schlumberger . • SchlumhergerClient,BP Exploration Alaska Well.S-129 Formation.Kuparuk C District Prudhoe Bay Country,United States SLUR RATE BP Exploration Alaska POD Additives S-129 ........;=CFLD RATE 05-10-2015 50 —t PROP_CON 20 } -J604Conc 0 -__--- U028Conc 18 -13 n 40 - i475-CONO- 16 o -POD DK PPA by Gate 4 35 _ 14 POD RD PPA by Gate D aar' 30 ' " 12 0, ; o 25 10 n 0 i 20 - a01 - g 01 m 10P 7' 15 6 I 10 I 4 rw CO 0 0 n 0 3 s — oa 14:23:18 14:31:37 14:39:57 14:48:17 14:56:37 15:04:57 15:13:17 15:21:32 Time hh:mm:ss • • 1 Schiumberger Client:BP Exploration Alaska Well:S-129 Formation:Kuparuk C District:Prudhoe Bay Country:United States PCM Additives Main Treatment BP Exploration Alaska S-129 05-10-2015 50 300 16 — Slurry Rate -14 40- — PCM Viscosity -250 — J580 Cone -^-^^ F103 -12 - L065 r — J604 Conc -200 -a a 30- a 3 10 c D a n y n la -150 p -8 2 N O I 1 j 20 < m n W -100 v -6 ro PCM Lgst Prime 4 10- 1711- 50 0 0 14:20:25 14:37:05 14:53:45 15:10:25 15:27:05 Time-hh.mm ss ©Schlumberger 1994-2012 Schtunstargiw W TFC_ 41116'GW i s-129 CHROME TBG'""MAX DOGLEG 25 8 e 9065"'• V1IELLH6AD= FMC ACTUATOR- L� OKB.ELEV= 62.46' I BF.B_EV= 33.6' P= .. . .._. I I 2006' —412'FSS X PF,D=3.813' KOP= 23()0 20'CONDUCTOR H 108' Max Angie= 95'@ 12170' 4083' —4-1/2'X 3-1/2'XO,D=2.992' I Datum MD= 8861' — • ' D= GAS LFT MANDRELSDatum TVD-_ 670(Y SS ST M) TVD DEV TYPE VLV LATCH PORT DATE 9-5/8'CSG,40#,L-80 BTC,E)=8.835' -- 3295' / / 5 4163 3811 46 MMG DOME RK 16 06/12/15 4-1/2'TBG, 12.6#,13CR-80 VAM TOP, — 4083' 4 4263 3881 46 MAG DMY RK 0 11/17/10 .0152 bpf,1).3.958' = 3 6872 5597 52 WAG DOME RK 16 06/12/15 2 8358 6483 54 MAG DMY RK 0 11/17/10 r CSG.26#,L-80 VT-HC XO L-80 BTC-M H 6334' 1 8460 6542 56 MMC SO FE 20 06/12/15 Minimum ID =2.813" @ 8630' 8530• I--3-12'I-ES X NP,D=2.813' I 3-1/2" HES X NIPPLE II— 8696' —13-1/2'?DPG SINGLE SENSOR SUB,D=2.992' X 8631' H7'X 3-12"I$TNT PER,D=2.949• ' 866T —3-1/2'FES X NP,D=2.813' 8698' —3-12"HES XNP,D=2.813" 86993-12"TBG,9.2#,13CR-86 VAM TOP, — 8710' .t \ ' • —r X 5'BKR I-RD ZXP LIP 0087 bpf,I)=2.992" w/FLEXLCK HGR,I)=4A00' N N 8710' 1--3-1/2''LEG,D=2.992' 8730' H5"x 3-12'XO,ID=2.99" r BKR WHFSTOCK — 8875' — MLLED OUT WNDOW(r) 8875'-8910' 4.1.44 •1•�•�••• CM D SLD Sly(BX P E) r CSG,26#,L-80,BTC-M, — 9435' NOS TOP DEPTH Opn/Sgz DATE MN D 0383 bpf,D=6.278" 7 8909 0 01/09/14 2.812' 20'OIL SWELL PAC � 6 9198 0 03/24/11 2.812' ND SIZE TOP DEPTH MND ` 5 9446 0 03/24/11 2.812 4 ' 3-1/2" 8930 2992 4 9951 0 03/24/11 2.812' 3 3-1/2- 9714 2.992' 3 10446 0 03/24/11 2.812' 2 3-1/2 10659 2.992' :',t, 2 11097 0 03/24/11 2.812' 1 3-1/2' 12266 2992" Oil1 11890 0 03/24/11,2.81T PERFORATION SUMMARY' • REF LOG:LAU ON x xixxi 10 c11546' 41/2'X 3'LITE-SLP ON ANGLE AT TOP PERF: 58°@ 8875'1 S SVVB1 WI?,D=3.958' Note:Refer to Production DB for historical pert data FSH:MLLED WFD CBP — 11891' ' SIZE SPF NTERVAL C n/Sgz SHOT SQZ (06/03/15) ` 4-1/2' SLID 12297-12838 0 11/15/10 `� ` , 12888' —I PBTD ` N3uB OTE L G UNC JTH) 3-1/2"LHR,9.2#,L-80 ST-M.0087 bpf,D=299T H 12870' DATE REV BY CX ENTS DATE REV BY COIJMUU5 AURORA UNIT 11/20/10 N7ES ORIGINAL COMPLETION 07/22/15 M1CJJM)GLV CIO(06/12/15) WELL 5-129 07/07/14 DJS/JLD GLV C/O(06/29/14) PERMIT No:`1101320 02/11/15 TTR/PJC SET C8R CLOSE SLD SLV'S AR No: 50-029-23433-00 02/19/15 GJB/PJC GLV 00 SEC 35,T12,R12E,1635'FNL&117T FWL 05/21/15 CIWJMD GLV 00(05/01/15) 07/22/15 MICIJMD MLLE)CSP/SET F15H(06/03/15) BP Exploration(Alaska) t..J M � o o vi Q v i m to V ..O u u v •u a V (a O a fl h . . 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INTERMEDIATE FINAL Yes—RECEIVED (mandatory) DATA LOGGED WELL NAME S-129 RUN NUMBER 1 Co/1 /2015 (mandatory) M.K.BENDER MAY 0 7 2015 FIELD Prudhoe Bay Unit BH SALESMAN Paul Canizares (mandatory) (mandatory) AO G C C COUNTY North Slope BH DISTRICT Prudhoe Bay,AK (mandatory) (mandatory) STATE Alaska PAGE 1 OF 1 (mandatory) LOG DATE: March 29,2015 TODAYS DATE: 5/5/2015 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: Paul Canizares (mandatory) SCANNED HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? SCANNED JUN12 �G�S COMPANY A B C D ADDRESS(FEDEX WILL NOT DELIVER TO P.O.BOX) L.I.S. FILM PERSON ATTENTION #OF PRINTS#OF COPIES#OF COPIES#OF COPIES#OF COPIES#OF COPIES 1 ConocoPhillips Alaska Inc. 2 1 1 1 Attn:Ricky Elgaricio A= S-129_MRPM_RAW_BORAX_29MAR2015_BHIV2.meta ATO 3-344 700 G Street Anchorage,AK 99510 B= *(Folder 1 on cd/dvd) S-129_MRPM_RAW_BORAX_29MAR2015_BI- C= **(Folder 2 on cd/dvd) S-129_MRPM_RAW_BORAX_29MAR2015_BE D= ***(Folder 3 on cd/dvd) S-129_MRPM_RAW_PASSO1UP_29MAR2015_BHl.dlis S-129_MRPM_RAW_PASSO2U P_29 MAR2015_BH I.dlis S-129_MRP M_RA W_BO RAX_PAS S0 3 U P_29 MAR2015_B I S-129_MRPM_RAW_BO RAX_PASSO4U P_29 MAR2015_B I ****(Folder 4 on cd/dvd S-129_MRPM_RAW_PASSO1UP_29MAR2015_BHl.las S-129_MRPM_RAW_PASSO2UP_29MAR2015_BH I.las S-129_MRPM_RAW_BORAX_PASSO3U P_29MAR2015_BI S-129 MRPM RAW BORAX_PASSO4UP_29MAR2015_BI Folder 1 on cd/dvd needs to be named"META" ** Folder 2 on cd/dvd needs to be named"PDF" *** Folder 3 on cd/dvd needs to be named"DLIS" *yr** Folder 4 on cd/dvd needs to be named "LAS" 2 ExxonMobil,Alaska Attn:Lynda M.Yaskell and/or 1 I 1 1 1 Leonardo Elias 3700 Centerpointe Dr.Suite 600 Anchorage,AK 99503 3 j State of Alaska-AOGCC IAttn:Makana Bender 1 1 1 1 333 W.7th Ave,Suite 100 (Anchorage,Alaska 99501 4 DNR-Division of Oil&Gas Attn:Sean Clifton 0 0 1 1 550 West 7th Avenue,Suite 802 Anchorage,Alaska 99501 TOTALS FOR THIS PAGE: TOTALS FOR ALL PAGES: 4 3 4 4 0 0 • `, of Tht \�� I�j, ,is THE STATE � Alaska Oil and Gas ��►-s����, of/� /k, JK /�,L Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 � nA _U13 Main: 907 279.1433 �� ALASs'� �''� M� 1 Fax 907.276 7542 S �� www aogcc.alaska gov David Wages Well Intervention Engineer N 1 ✓ 1 BP Exploration(Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, AURA S-129 Sundry Number: 315-080 Dear Mr. Wages: 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. Variance to 20 AAC 25.283 (d) is GRANTED. 20 AAC 25.283(d) requires that a pressure relief valve be installed on the treating line between the pump and the wellbore, and requires that the well be equipped with a remotely controlled shut in device. Information supplied on the automatic and manual pump shutdown parameters provides at least an equally effective means of complying with the requirement of protecting the surface equipment and wellbore from overpressure. 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, ()717--e.-44/6•&_ Cathy . Foerster Chair DATED this day of May, 2015 Encl. RECEIVED STATE OF ALASKA FEB 1 2 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION l 564--1 1 S APPLICATION FOR SUNDRY APPROVALS AOG (v� 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Rednll❑ Perforate New Pool❑ Repair WeII❑ Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well Stimulate 0 • Alter Casing❑ Other. ��a 6(14'- 7 2.Operator Name. 4.Current Well Class: 5 Permit to Dnll Number 5h‘-2-, BP Exploration(Alaska),Inc. Exploratory ❑ Development 0 • 210-132-0 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: • P.O.Box 196612,Anchorage,AK 99519-6612 50-029-23433-00-00 7.If perforating: 8 Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? AURA S-129 • Will planned perforations require a spacing exception? Yes ❑ No ❑ 9 Property Designation(Lease Number): 10.Field/Pool(s): /1P 4ial1;5S, ADL0028261 e?:-.,.... [S PRUDHOE BAY, AURORA OIL • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft). Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 12964 • 6791- 9100 6832 9100 8667 Casing Length Size MD TVD Burst Collapse Structural Conductor 80 20"91.5#H-40 29.36-109.36 29.36-109.36 Surface 3266 9-5/8"40#L-80 28.86-3294.88 28.86-3193.14 5750 3090 Intermediate None None None None None None Production 9410 7"26#L-80 26.35-9435.9 26 35-6819.69 7240 5410 Liner 4171 3-1/2"9.2#L-80 8699.08-12870 6674.37-6790.93 10160 10530 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: See Attachment for Packer Types Packers and SSSV MD(ft)and TVD(ft). See Attachment for Packer Depths No SSSV Installed No SSSV Installed 12.Attachments: Description Summary of Proposal ❑ 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Development 0 • Service ❑ 14.Estimated Date for 1 15 Well Status after proposed work: � Commencing Operations: C-/ 7/(9 Oil 0 - Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact David Wages Email David.Wages@BP.Com Printed Name �--� David Wages Title Well Intervetions Engineer Signature _/-/_ / Phone 564-5669 Date 1 Prepared by Garry Catron 564-4424 7f� COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: - 3 0 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Po 5 f I v2 f 4 r levy Gt fi r o) r ccL y r r c cl -1--c) --f- k c Fr 4. c Fa c.`-'5L, C I' i c-.- 1 firc.c fo c vs , o ;G P l v s v f- t.• r rt% u i e-r wl.-rte.�5 17_15c1 n5 �✓G R.ci5'tr1 tvww J t 20A#G 25. 253 - Spacing Exception Required? Yes ❑ No [( Subsequent Form Required: i C L} C 4-- ) APPROVED BY Approved by r) .2COMMISSIONER THE COMMISSION Date: S-- ( -1 S VTz ` zi /S CANw ,s��ls 4z1- � Form 10-403 Revised 10/2012 0 R 1,Gr s valid for 12 months from the date oapp oval. Su i Form and Attachments in Duplicate RRDMS MAY - 5 7015 Perforation Attachment ADL0028261 Well Date Perf Code MD Top MD Base TVD Top TVD Base 5-129 1/9/14 STO 8919 8930 6792 6797 S-129 2/11/15 STO 8959 9100 6810 6832 S-129 2/11/15 BPS 9100 9714 6832 6815 S-129 2/11/15 BPS 9743 10659 6814 6824 S-129 2/11/15 BPS 10687 11546 6826 6846 S-129 2/11/15 BPS 11556 12266 6845 6803 S-129 2/11/15 BPS 12294 12838 6800 6791 AB ABANDONED MIR MECHANICAL ISOLATED REMOVED APF ADD PERF MIS MECHANICAL ISOLATED BPP BRIDGE PLUG PULLED MLK MECHANICAL LEAK BPS BRIDGE PLUG SET OH OPEN HOLE FCO FILL CLEAN OUT STC STRADDLE PACK, CLOSED FIL FILL STO STRADDLE PACK, OPEN SQF SQUEEZE FAILED SPS SAND PLUG SET SQZ SQUEEZE SL SLOTTED LINER PER PERF SPR SAND PLUG REMOVED RPF REPERF O O o o O O w v °o °oco00 L• = J J J cv) M r r a) Q O 0 0 N I� u') V 0) CD U 0 0 0 0 0 0 rnC° vU) M �O 3 Lc) aoo a) U) � acoLo O O N C7) U) co O I� co r--- CO CO CO CO Co I- CD- 0 O O) N. CO CA U) U) Q N CO CV N N • Cfl M >.(13 I- 1- EE a) NmoagoU) rncocD 00vNor� (n CN O0 " rnMveo O 0 Q o � I- rn rn co a) incoU Q N U) N N Nco ov O O O Cb � coO °ooMU co J N IIC) N J O *k (n • CD Co CV CV O CV (A O 1.0 (V N N M (A r •:t• co L +' O Co CO I� CI) CO N- ' N O C J V C)) M V [ O C O w U U D p Z Z Z w O a m m OZCCDDD Uro (nHH Packers and SSV's Attachment ADL0028261 Well Facility Type MD Top Description TVD Top S-129 PACKER 8631 7"X3.5" HES TNT Packer 6637 S-129 PACKER 8699 5" Baker ZXP Top Packer 6674 S-129 PACKER 8930 3-1/2" OBM Swell Packer 6798 S-129 PACKER 9714 3-1/2" OBM Swell Packer 6815 S-129 PACKER 10659 3-1/2" OBM Swell Packer 6824 S-129 PACKER 11546 4.5"X5.75" Lite Slip-on Swell Packer 6846 S-129 PACKER 12266 3-1/2" OBM Swell Packer 6802 . TREE= 4-1/16"CNV I - - WELLHEAD= FMC S-129 -12 9 SA!_ _ NOTES: W A I ANGLE>70°@ 8971''**_ ACTUATOR LEO �/ CHROME TBG*** MAX DOGLEG:25.8"@ 9065' OKB.ELEV= 62.46' I I BF.ELEV= 33.6' / 11 KOP= 2300' ' 2006' -'4-1/2"FES X NP,D=3.813' Max0"CONDUCTOR H 108 ax Angle= 95^@ 12170' # � 4083' - 41/2"X 3-1/2"XO,D=2.992" Datum = 8861' - Datum TVD= 6700'SS D= GAS LFT MANDRE ST MD TVD DEV TYPE VLV LATCH PORT DATE 9-5/8"CSG,40#,L-80 BTC,D=8.835' H 3295' / 5 4163 3811 46 MAG DOME RK 16 06/29/14 4-1/2"TBG,12.6#, 13CR-80 VAMTOP, - 4083' 4 4263 3881 46 MAG DMY RK 0 11/17/10 .0152 bpf,D=3.958" / 3 6872 5597 52 ME DOME RK 16 06/29/14 2 8358 6483 54 MNG DMY RK 0 11/17/10 17"CSG.26#,L-80 VT-HC X0 L-80 BTC-M -1 5334' 1 8460 6542 56 MAG SO RK 20 06/29/14 Minimum ID =2.813" @ 8530' 8530' -13-1/2"HESXNP,ID=2.813" 3-1/2" HES X NIPPLE 8595' -13-1/2"NDPG SINGLE SENSOR SUB,D=2.992" M ►�� 8631' H7"X 3-1/2"FES TNT PKR,D=2.949' 8667' -13-1w',0=2.813' 8698' -13-1/2"FES X NP,D=2.813" 3-1/2'TBG,9.2#,13CR-85 VAM TOP, I- 8710' M, 8699' �7"X 5"BKR HRDZXPLTP .0087 bpf,ID=2.992" w/FLEXLCK HGR,D=4.400" 8710' -13-12"WLEG,D=2.992" 8730' -15"X 3-12'X0,10=2.99" 7"BKR WHIPSTOCK -1 8875' - !ALLIED OUT WINDOW(7") 8875'-8910' 111111 9100'CTM 3-12"VVFD GBP(02/11/15) 11111111111• BKR CM D SLD SLV(BX PRORLE) 7"CSG,26#,L-80,BTC-M, - 9435' *fpNO# TOP DEFTH Opn/Sqz DATE MN D .0383 bpf,D=6.276" 7 8909 0 01/09/14 2.812" 20 OIL SWELL PCKFES 6 9198 'O 03/24/11 2.812" NO SIZE TOP DEPTH MND 5 9446 O 03/24/11 2.812" 4 3-1/2" 8930 2.992" 4 9951 '0 03/24/11 2.812" 3 31/2" 9714 2.992" 3 10446 '0 03/24/11 2.812" 2 3-1/2" 10659 2.992"1 312" 12266 2.992" 1 11890 '0 03/24/11 2.812" *Si* •#1-# 6 SLD SLV'S below plug @ 9100 ' PERFORATION StJMtNARY (SFT 02/11/15) REF LOG:LWD ON XX/XX/10 11546' -4-1/2"X 3"LITE-SLP ON '. I SWELL A<R,D=3.958" ANGLE AT TOP FERE: 580 @ 8875 Note:Refer to Ptoduction DB for historical pert data vt SIZE SPF INTERVAL Opn/Sqz SHOT SQZ 4-1/2" SLID 12297-12838 C 11/15/1012869' -I STD 1 y,, NOTE-LINER IS tRJC 1 ENTED T- D=2.992" 3-12'LPR9.2#,L80 ET-M.0087 bpf, -{ 12870' DATE REV BY COMMENTS DATE REV BY COMMENTS AURORA UNI' 11/20/10 MES ORIGINAL COMPLETION 07/07/14 DJS/JMD GLV 00(06/29/14) WELL: S-129 11/25/10 CD DRLG HO CORRECTIONS 02/11/15 TTR/PJC SET CBA'CLOSE SLD SLV'S PER fT No: 2101320 12/27/10 TW/JMD DIG DRAFT CORRECTIONS API No: 50-029-23433-00 03/27/11 RFNV/PJC SLD SLV OPENED(3/25/11) SEC 35,T12,R12E, 1635'EN_&1177'FW!_ 05/14/13 CNJ/JMD XO D CORRECTION(05/04/13) 01/15/14 DJS/JMD SLD SLV OPENED(01/09/14) BP Exploration(Alaska) Wellwork Procedure Request To: Well Services Operations Team Lead Date: 11/7/2014 Wireline Operations Team Lead VER1 AFE: APBFRACS From: David Wages -Well Intervention Engineer Josh Allely - Well Intervention Engineer IOR: 300 Est. Cost: 1,000K Subject: S-129 - Pre and Post Frac Procedure Please perform the following steps 1. S Drift to deviation 2. C Set Composite Bridge Plug Well test w/ pad separator 3. S Install DGLVs and circ valve, Set plug 4. F Circ. packer fluid 5. S Install DGLV, MIT-IA, pull X-plug 6. F Injection Test 7. F Hydraulic Fracture Treatment / 8. C Post frac FCO, mill Plug 9. S D&T, Install GLVs 10. T Post frac flowback Current Status: Operable Minimum ID: 2.813" at @ 8698', 8667', & 8530' MD. 3-1/2" X-Nipple 2.812" Sliding Sleeves @ 8909', 9198' Max Deviation: 95 deg at 12,170' MD Top Perf Deviation: 59 deg at 8909' MD Last TD Tag: NA well angle > 70deg at 9004' MD. Last Downhole Op: 6/30/2014: SL-Pull X-Catcher Sub from X-nipple @ 8460' (full of scale and sand). SBHP/SBHT: 4/14/2014: 2466 psi and 167F at 8480' datum. Latest H2S: 8 ppm, 6/12/12 Program Contacts Contact Phone-Work Phone -Mobile/Home Interventions Engineer David Wages 907-564-5669 713-380-9836 Interventions Engineer Josh Allely 907-564-5732 907-350-7362 Page 11 of 7 Previous SL runs have deviated out around 9000' Notes This well has been on HOT and brush n' flush treatments every -3 months, most recent HOT: 10/17/14. > 10/17/14: HOT > 7/2014: GLV Change-out, when pulling X-catcher, it came out covered in scale and sand. > 7/2014: Brush and Flush w/ HOT > 1/2014: Shift sleeve 7 open, no noticeable change in production rates, thus the need for frac. > 3/2011: Shift sleeves 1-6 open (Sleeve 7 at heel still closed) "Optimum shifting rate seems to be 1.2 to 1.3 BPM @ 8-9 fpm." Slickline Drift to deviation 1. Drift to deviation with 2.70" centralizer • Composite Bridge Plug OD: 2.659" • Previous SL runs have deviated out around 9000' Coil Set Composite Bridge Plug 2. Set CBP plug at 9100', mid joint • Please use a Baker or Weatherford bridge plug as they have the differential pressure rating required. • Minimum plug rating is 10,000 psi from above • X-nipples @ 8530', 8667', 8698', IDs: 2.813" • Sliding Sleeves @ 8909' & 9198', IDs: 2.812" • Baker Standard Bridge Plug OD: 2.55" • Weatherford FracGuard Series 400 plug OD: 2.695" • Must be set below Swell Packer @ 8930' Slickline Install DGLVs and circ valve, Set plug Before performing work, confirm with pad operator and/or David Wages that the pad has obtained a well test through their facilities. 3. Install DGLVs in all but station 1 @ 8460' 4. Install circ valve in station 1 @ 8460' 5. Set plug in X Nipple @ 8,698' Fullbore Circ. packer fluid 6. Load tubing/IA with 290 bbls inhibited Seawater (with MI KI-3869 corrosion inhibitor/0.45% v/v) • Pump down IA and up tubing • Use methanol spear as required • Total tubing+lA volume is 292 bbls • Tubing+IA volume to 2500' is 85 bbls, please freeze protect with diesel or crude Slickline Install DGLV, MIT-IA, pull X-plug 7. Install dummy GLV in Station 1 @ 8460' Page I2of7 8. MIT-IA to 4000 psi. • Stage up to high pressure test. 9. MIT-T to 5000 psi. • Stage up to high pressure test. 10. Pull X-plug from nipple @ 8698' Fullbore Injection Test • Please call David Wages prior to pumping injection test. 11. Pump the following down the TBG at max rate (8 bpm) not to exceed 4500 psi. Please attempt to keep a stable rate if possible. 1. 5 bbls neat meth (if necessary) 2. -290 bbls diesel • 8 BPM is important, please RU hardline. • Record surface pressure and rate at 1 second intervals. • Work with SLB to obtain BH gauge data at 1 second intervals. • Perform hard shut down of pumps (do not operate tree valves) and monitor pressure decline for 1 hour, then shut well in and RD. • Send pump rate and pressure data to David Wages Fullbore Hydraulic Fracture Treatment 12. Frac treatment per pump schedule. Pressure testing Maximum Allowable Treating Pressure: 7000 psi Stagger Pump Kickouts between: 6650 psi and 6300 psi (90% to 95% of MATP) Global Kickout 6650 psi (95% of MATP) IA pop-off set pressure 3000 psi (75% of MIT-IA) Treating Line Test Pressure 8000 psi Sand Requirement 62,000# 16/30 sand , 26,000# 16/20 Carbolite Minimum Water Requirement 1000 bbls (pump schedule: 752 bbls) IA Hold Pressure 2500-2800 psi OA Monitor and maintain open to atmosphere Coiled Tubing Post frac FCO, mill Plug See Appendix B for FCO procedure 13. Mill Bridge Plug and push to TD Slickline D&T, Install GLVs 14. Drift and tag fill. Page 13 of 7 • Previous SL runs have deviated out around 9000' 15. Install Deep GL design Testers Post frac flowback 16. Post frac flowback • Page 14of7 Appendix A - CT FCO Procedure Notes: • This is a generic FCO procedure for a post frac FCO. Specific info such as amount of proppant left in tubing and estimated sand top will not be known until after the job is pumped. • The objective of this procedure is to get the well cleaned to facilitate post frac well test. • Recommend reviewing PE Manual section for Coiled Tubing Fill Cleanouts for specifics on reversing rates, speeds and CT loading. Planned Procedure 1. MIRU CT 2. MU BHA. 3. RIH down to estimated sand top and begin cleaning out with slick 1% KCL. 4. Continue down to 8909' CTMD. At this point we are at the sliding sleeve. Ensure CT is clean as it is expected that returns will begin to fall off as the nozzle nears the sleeve. If returns begin to fall off, reducing BHP by lowering rate may keep returns at a manageable level. 5. Slowly continue to clean out until returns fall off to —80%. If returns are still good even after the nozzle is past the sleeve (not likely but possible), continue to clean out to the bridge plug at 9100' a. If returns are too low, it may be necessary to mill the bridge plug without taking returns. 6. Continue to mill plug and push to PBTD. 7. FP to 2500'. 8. Pump a gel pill at surface out to the tanks to ensure CT is clean if necessary. 9. RDMO. Page 15 of 7 Appendix B -Test Separator Additional Flowback Procedure 1. MIRU ASRC. RU equipment to in a manner that allows CT to RU if an additional FCO is necessary. 2. POP the well to ASRC at minimum choke. Flow the initial returns to the flowline as long as the shake-outs meet the returned fluid/solids management guidelines. 3. Limit flow to 500 bpd 4. If solids are < 1%, increase the production rate to 1000 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1%, allow well to flow to 1500 BLPD. Flow bottoms up and sample for solids production. If solids are still below 1% continue to increase the flow rate in 500 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well clean up before choke is opened further. 6. Once at FOC, stabilize the well for 4 hrs. Obtain a 3 hr purge, 8 hr welltest. Page 16 of 7 • 1 ' * TREF= 4.111r OW SARTY NOTES: WELL ANGLE>70°la 89 71', 1E.._LHEAD, FlIdE S-1 29 , -4-1Ir&3-117 CHROME TEG A CAUATOR= LEO 14TiAL 43.ELE 6246' /r I 1 ,..1 U-3 813' 33.6 -0'- 2300 120'COM.— 106 I Ma:A ngle= 95"CI 12170' r , 4083. -f-It?X 3-172"X0.0-2.997 ntrn MD= 8861' A ast_rn TI",= non ss 1 ..-----.. GAS LIFT 14A/ORES if 1,11 TVD'(]V TY PF 'd1%,. LATO i PORT EWE 9 518"CSG,:00._80 EITC,13-8 635" ---- 3296' 7 ..., 4163-3811 46 MAG DONE PK 16 060904 -- , .1 i:' Ilil, I.,s14' 11CR-99 YAM 1,* 4063' 1--- i I 4761 :3881 46 kW Mar t1 0 11117110 11x'Lry:4 U-3"158' 1 168721 5597 52 PM G COME FK 16 0609114 7'CSG 764 l 30 VT IC X0_W STC.'N , I:53.34' —),,,C. :-...C: •1 ? ,e.358 1 64a3 54 P643 akt1 FE 0 11117/10 . 1 M60 E542 56 FAIAG SO FK 20 06129/14 , . 1Minimum ID 2.813"@ 8530' i if------ 6630' t 31/2-HES X OW,ID 2.817 131/2" HES X NIPPLE ....- 3-1,..'%.04.;:;1',/2 V.;FuR t31.13. --1 8595- 1---- '.. 1, mu' j 7,,X 1 i V'I cc 7parnn,0-?944* 1 13-2.997 >--- II • • •-----,--estimiTh 3-1/7 I-FS X M; I 1--4 8688' --H 3.NT .4ES X 1.4,*,ID,,2.81S" 1 3-1/7/BO.9 20,13CR-88 VAN TOP, .4.. 1710r ir X 5 .008?bet.U=2.997 t -- "HRO 131(61 ZniLTP&REXL GCS, tr ,L.N14 aiL El=6407 '-'-•,. 7-6117-1WIF WIG,113;2987 -----'4,- 8730* -,5"X IA127 X0,13 2 99'I ------ , ----1 7'8101 INNESTOCK-I .1 13875` -1 r WILLEDOUP40.00/4471. WV 801e 1' R CND SUCMC SLEEVE ID=2.817 6X PROF SIZE t424 TOP CEPTH OpreSog i DATE IWAT41 \ I 1 117 7 8909 0 l'0114 1144410. ' 13_1(r 6 9198 0 0317411 IG4.4.44•10 file Fr csG,288,1-80,MUM.0363 44,I)-6.276"hi 9436 • • — 3-117' 5 9446 0 030611 3-1/7 4 9961 0 03/25.1 t 3-117 3 10446 0 03f2811 I 3-1/3117 2 11097 0 03124,11 7 1 11890 . 0 '03,24e1 1 PERIFORAT1ON SUI.6114R1 1114-I(X I.M) ANGLE AT TOP 1U8 Ur@ 887e AIV, 1.1546' 4-1,7 X 3'LITE SLP ON 1 bte:Refer to Production E23 tor tesloncal pert data SIZE SW HIERVAL CIpniSqz SI-OT SQZ Pir* 4% 404 i SWELL MR,Et-3 ssr ... 4-1/7 SLID Inv-12838 0 11115110 I., ler nil Sioni i Der nun .0, 4.% , I;), ND SUE TOP!MYTH WI ID • _. 6 4 3-Il? 8930 2.897 —NOTE-i itifnUNC13430ED — 3 3-117 9714 2.987 2 3-117 10659 216? \ 1 lur 12265 2 997 3 1.2-LW;924.L BO BT 14 0C476p1,Co=2 997 H 12870' 1-- „ DATE REV BY 1111.944419 I CV\lE 14,./AY ' 0244161401 AURORA INT Immo NIE6 011101181.L COMPLETION 37/07114 WS/JM)'GLV C)0(06.29/141--- WR t 5-129 11175%10 CD 01LG110 rj318,W110145 PERM'143.' 101320 17/7100 !WOAD L114.0 DRAFT CORRECT1CNS AM No: 50-029-23433-00 0307111FRINRIC r=D Stv OPENED{3175111'e SEC 35,712,RUE 1835 FM.&1177'RN( 0ir14/13 c3-&3J1.1) XC)ID 00f4ECI EN(05104113 01115114 MAC a_DSLV OFENED{01.09/14) 91'Bipiaration 1Al1aka) Page 17 of 7 Date: February 9, 2015 Subject: S-129 Fracture Stimulation From: David Wages Engineer, BP Alaska o: 907.564.5669 c: 713.380.9836 To: Chris Wallace Attached is BP's proposal and supporting documents to fracture stimulate the Kuparuk interval of well S-129. Well S-129 is offset to well S-125. In 2011, a heel frac was performed on well S-125 which resulted in excellent production increase that has held very good rates even to today. It is proposed to perform a similar treatment on well S-129. We are requesting a variance to sections 20 AAC 25.283, a, 3-4 which require identification of fresh water aquifers aquifers and a plan for basewater sampling. Please direct questions or comments to David Wages Affidavit of Notification (20 AAC 25.283,a, 1) All partners and landowners have been notified of operations planned for well S-129. Plat Identifying Wells(20 AAC 25.283,a,2,A-C)and Faults(20 AAC 25.283,a, 11) 101 ;S-117°0- S-117.0 ,. 4. S. S-117 5F , , S-13. 310' ---•sa . H s� S 116A 1 1 —250' $-1 ' • ' —630' us got 9T Wells within 1/2 mile of S-129: S-116A S-101 S-134 S-128 S-117 S-17 Per thelat above, there are no water wells within /z mile of the subject well. p1 Three faults of concern as shown above are to the west ( -250' away), to the north (-310' away) and to the west (-630' away). The maximum stress direction from log data runs almost due North-South, thus the primary fault of concern is the fault to the north. In order to ensure this fault does not affect the fracture treatment, the half-length of the frac will be designed to be -250'. The fracture and the frac fluid should not come in contact with the fault of concern. However, if we see a surface indication (sudden drop in surface treating pressure indicating our frac fluid has found a weak path i.e. a fault), we will immediately go to flush. Exemption for Freshwater Aquifers(20 AAC 25.283,a,3-4) Well S-129 is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1-4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location the makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have a total dissolved solids content of 7000 mg/I or more. 4. By letter of July 1, 1986, EPA-Region 10 advises that the aquifers occurring beneath the ✓ Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non-substantial program revision not requiring notice in the Federal Registrar. Per the above findings, "Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25.440." thus allowing BP exemption from 20 AAC 25.283, a, 3-4 which require identification of freshwater aquifers and establishing a plan for basewater sampling. Detailed Casing and Cement Information (20 AAC 25.283,a,5-6) Well S-129 was spudded on 12/25/2010. A 12-1/4" hole was drilled to 3305' where 9-5/8" 40#, L-80, BTC csg w/ CBU 1X @ base of permafrost© 1926' was run and cemented in place with 1200 sx ArticSet lite lead and 447 sx of 15.8 ppg Class G cmt with good returns (365 bbls cmt)to surface. After plug was dropped, the casing was tested to 3500 psi for 5 min for a good test. A LOT to 11.96 ppg was performed after the shoe was drilled. A 8-3/4" intermediate hole was drilled to 9445'. Once past casing set point, 7", 26# VT-HC and BTC csg was run and cemented in place with 454 sx of LiteCrete cmt and 223 sx Class G. Casing was tested to 3500 psi for a passing MIT. After milling a window from 8875'-8910', a 12.1 ppg EMW test was successfully achieved. A 6-1/8" hole was drilled to TD of 12,964'. 3-1/2" 9.2# L-80 IBT-M solid and slotted liner with swell packers was run to 12,870'. Displaced the openhole section to 10.4 ppg bring then set the liner top packer. The completion assembly consisting of 3-1/2" and 4-1/2" tubing was run to 8710' with the packer at 8631'. Since Initial completion, the well has been producing via the bottom 6 sleeves, when the top sleeve was opened to evaluate the production potential, no noticeable change in oil rate was observed. Due to low production rates, the well has paraffin issues and is on recurring B&Fs and HOTs alternating every 3 weeks. • Accurate Pressure Ratings of Tubulars and Schematic(20 AAC 25.283,a,8) rJ 4,,,�` S-129 �L-lino_ --- Fuca.,.. SAFETY NOTES: WELL ANGLE).».e 21171'- ACTLI4TOR- LID'; "*4-1/2 a 3-1/2'CHROME MG.. MNL F03 ELF 62.46' BF t1EY= 33.6' ' 9 2009. 14 112.14s x NP,D■3,617' 1,. ._C,r.7C3/JU -4 108° Mix Angle= 95°6)121717 —' -J 4083 8 u2-X 3 1r2 O13- 1-2A02" WtunIAD= 8861' A SS ! Dolan ` GAS 1 I kMNt13i3 DolanN D= 67 50' .. _ 19- n C G,4aR,L-Bo BR:,D=tf.835 3295 VT! MD TVD DEV TYPE VLV LATCH OATS 5{4183 3811 46 MG BONE= FR 16 D6/29/14 x4112°TBG,12.64,13CR-60 VAM roP,IH 4083` I- 4 1 42E3 3881 46 MC DIN RK 0 11117110 1'.. V 0157 INN,1)=3 958' 3 9 6872 5587 52 1.940 DOW! Ti( 16 06129114 CSC; 760,18CV 1I C X0I BO MC J {y_6334' 1 x t 2 6463 54 MC MYrac 0 11!17110 I 8463.,8512 56 6fdG SO 1 RK 20 1 062914 Minimum ID 2'2.813"@ 8630' 13-1/2"NES X NIPPLE 1 ' („.6630" j {3-117'FES k OFF..._Da2113'i 1.7-I l?M 1 SAK',F SFFS014 5163, �---1 8595' tom^'"` p 1 4 �.__ _.1 1 L pg t1' t 7•It 0 c•I[n rnrr n+R n__94B D=2.992' I J 966T 3-V2"FkS X NPD7264S I t 8688'...H3 112"N9S k.MR 13,2.613'J 3142"1BG.9.2N.1JGR$8YAM TOR $119' HP'W 7•XS"HEI!RZXPLT1FLEXLOGK I 0061'01,V s2h1B2 8 L1d2HD 42)=4403' 8730' :3'X 3-1/2'XO,D.2.99'1 L1 BKFtVNN'SJOCK I--( 8875' 044L.E309-t60),FI)N(T)8875 8910' 14, 72 OM SUMO SLEEVE,10=2.812BXPROF We-I&.T C 'T l7pnM�z 441E W 3-1/2" 7 8909 0 01109114 • •9l- 3.12' 6 9196 0 03724111 V CSG,260.1-80,STCM 0383 bpf,D.6.276"i---I 9435' J b4'"' -' 3-1/7 5 9446 0 03/24/11 vo- L� 31/7 4 9951 0 03/25111 [ _ 3-12' 3 10446 0 0325111 312' 11097 0 032N11 F-ORATLtN SU1N4AFRY 31/1' 1 1 11690 0 0324111 REF LOG:LNO i ANGLE AT TOP FERE 58` 8875'' -/A . - Nair Naar fiefar tot Production DO For hsbncal part data 7/� 4-1/2'X3'LIFE SLPON SFE SPF INTERVAL C rWSgc SF1DT 501tor ,(� �1 8V183.1 Rot 13-7 456- 4-1,9 SI.11) 12291-12838 0 11/15110 OS 20'OIL SWELL PAc111318 ,/! NO SIZE TOPO�IH IND I _ �� i 4 3112 8930 2-992' NOR-1 I*H 6 UNEEMMTED 3 3-12' 9714 2.992' „elk, 2 3-112" 10659 2.992' 1 3.12' 12266 2.992' I RIM ]-I 1288, . 111P 3 1. -LIYZ 9.26.L 884 fB 1 M 30a!tlpi b 2 992" l l 12871Y OATS REV BY CO NT0 11A1L ttLV 9Y 1:0001440r5 I AURORA UNIT 11/20110 b '.0181134M COMPLETION 071777/14 OJSOMDIGLV 00(06/29114) I UNIT Y413L:S-129 1125/10 CD i CMG MD 1 X38*C7113t44 I I MUT No"2101320 j 12127110 TVWJMD*1:11110 DRAFT CORRECTIONS , —� AFI)4 50-029-23433-00 103127111 RRMPJC SLD SLY OPENED(3125'fir-7� SEC 35,712,R12E,1635'IN,a 1177'PVC 05/14/13 CHYYM)X0 D CORRECTION(05'04113)— i01/15/14 DJS/JAO,,SLDSL.VOPENED(01109114) - SP08pinratfon(Alaska) Name/Size Weight Grade ID Burst,psi Collapse,psi 9-5/8" Surface 40# L-80 8.835" 5750 3090 7" Production 26# L-80 6.276" 7240 5410 3-1/2" Liner 9.2# L-80 2.992" 10,160 10,540 4-1/2" Tubing 12.6 13Cr80 3.958" 8430 7500 3-1/2" Tubing 9.2# 13Cr85 2.992" 10,160 10,530 Wellhead: 41* FMC manufactured wellhead, rated to 5000 psi. Tree: 4-1/16" 5,000psi Tubing head adaptor: 11" 5,000psi x 4-1/16" 5,000psi Tubing Spool: 11" 5,000psi w/2-1/16" side outlets Casing Spool: 11" 5,000psi w/2-1/16" side outlets Tree saver: Top connection is 3" 1502 hammer union which will be crossed over to 4" 1002 in order to connect to the frac treating iron. Bottom connection is 7-1/16" The treesaver is rated to 10,000 psi. Alb Alb "Th. rr 'I' :LI 111) .'1^f'.. MINIM - /JJ kl (.}A:\ 1 vz Ex re all11111111111L r/ \\I P0 WL!■7li U u i 0 a • J is i Geological Frac Information (20 AAC 25.283,a, 9) DeptSen gd ess et _ &mesa et R Loss to Top dr DltTVG erne su Gra�ert Top of Graders Bottom t f.4odulus Pennon's Coeffwert Spun Proppart ne{it} One from Surface Zone Zone {ftfraot Loss Embedment ZLeper ijpe {Peat, [per (pa) !fattest} aw K-h entre) ge1/100ft'2 16ft42) 1 6644.9 Shale Q 0.0 0.701 4655.2 0700 4688.3 1.000000 0.30 2000.0 0.001100 10.00000 0.10000 2 6707.9 Ot 13 -1071.5 0.541 3627.8 0.720 3678.8 3.000000 0.20 2000.0 0.003500 1000000 0.10000 3 6782.3 Shade (] 1015.4 0.682 4695.3 0700 4714.7 1.000000 0.30 2000.0 0.001000 10.00000 0.10000 4 6810.0 'Water 0 258.6 0.730 4973.3 0.700 0.0 1.000000 0.25 2000.0 0002000 1000000 0.10000 Mechanical Information of nearby wells(20 AAC 25.283,a, 10) Per plat above, the following wells have been reviewed for casing and cement information: S-116A Spud Date: 12/2/13 7" 26# L-80 production casing set at 7990' in a 8-3/4" hole, cemented with 393 sx of LiteCrete, 159 sx of Class G 3-1/4" 6.6# L-80 set from 7812'-9155' in a 4-1/8" hole, cemented with 87 sx of Class G 2-3/8" 4.4# L-80 set at 9099-9774' in a 3" hole, this is a slotted liner. 4-1/2" 12.6# L-80 tubing set at 7821' with the packer @ 7761' Slots from 9155'-9774' 5-116A lies to the east which is perpendicular to the primary stress direction, thus our frac will avoid this wellbore. S-134 Spud Date: 9/16/09 7" 26# L-80 production casing set at 7996' in a 8-3/4" hole, cemented with 346 sx LiteCrete and 175 sx Class G. 4-1/2" 2.6# L-80 tubing set at 7506', packer at 7429' Perfs: 7644'-7714', 7814'-7832' S-134 lies to the Northeast and across a fault that we will avoid, our frac should not encounter this well S-117 Spud Date: 2/17/03 7" 26# L-80 production casing set at 8315' in a 8-3/4" hole, cemented with 230 sx LiteCrete and 174 sx Class G 3-1/2" 9.2# L-80 tubing set at 7871' packer at 7812' Perfs 8104'-8118'frac'd with 5800#of 12/18 Carbolite 7930'-7990' frac'd with 173,900# 16/20 Carbolite S-117 lies almost due north which is in the fault plane, however, it is across a fault that we will want to avoid and it is over 1000' away, with an anticipated frac length of 250', we should avoid this well. S-101 Spud Date: 8/9/00 7" 26# L-80 production casing set @ 8881' in a 9-7/8" hole, cemented with 500sx Class G and 190 sx Class G. 4-1/2" 12.6# L-80 set from 8709'-11721' in a 6-1/8" hole, cemented with 73 sx of Class G (solid and slotted liner. 3-1/2" 9.2# 13Cr tubing set at 8713', packer @ 8673' Slots from 9535'-11699' S-101 lies to the northwest and across several faults. Since we would like to avoid the faults and the well is to the west, we will avoid this wellbore by limiting our frac length. S-128 Spud Date: 11/28/10 7" 26# L-80 @ 9116' in a 8/3/4" hole, cemented with 316 sx LiteCrete, 189 sx of Class G 4-1/2" 12.6# L-80 set from 8963'-12,596' in a 6-1/8" hole, slotted liner with swell packers 4-1/2" 12.6# L-80 tubing set at 8969', packer at 8884' Sleeves from 9272'-12,416' S-128 lies due west, which is perpendicular to the direction that our frac will grow. S-17 Spud Date: 2/16/02 9-5/8" 47# L-80 production Casing set at 8300' in a 12-1/4" hole, cemented with 1933 cu ft of Class G 3-1/2'x3-3/16"x2-7/8" 8.8#/6.2#/6.16# L-80 liner set from 8041'-10610' in a 3-3/4" hole with 101 cu ft of Class G 4-1/2" 12.6# NT 13Cr80 tubing set at 8089', packer at 8002' Perfs: 10,292'-10,609' S-17 lies due east, which is perpendicular to the direction that our frac will grow. Summary Hydraulic Fracture Program (20 AAC 25.283,a, 12) (Detailed program included) Pump Schedule: 'Ape Stage Fluid Type Clean Cu.. Clean Cum Slurry Cum SIurry Can Proppant Type Prop Prop I Cum Rae Pumping Cum 0esorglen Volume Clean Volume Clean Volume Shay Volume Slurry Cone. Stage Prop (bpml Time Pump (gat) loan Ibbll (bbll lid) leen 161.1) IbbI) (ppal Obs) Dial Time 0 PT,set kgs LVT200 0 0 1 Load hole 60127 4200 4200 100.0 100.0 4200 42W 100.0 X10.0 11,4 0 0 5 2000 2000 2 SMB-4n 0 4,207 0.0 1500 0 4,200 00 1000 NA 0 0 0 30.00 5000 3 Pre-pad VF127Fletd 2,100 6,300 500 150.0 2,00 6,300 50.0 150.0 NA 0 0 20 250 5250 4 Pad YF127FIe,0 2,100 8400 500 2000 2,100 8,400 500 2000 NA 0 0 40 1.25 2525 5 Scour W12701ex0 4106 2,540 97.8 2970 4,200 /2600 1100 300.0 16130 sand 5 2,053 2,053 40 2.50 52.50 6 Pad YF127F1ex0 4,200 16,708 100.0 397.8 4,200 16.800 100.0 400.0 NA 0 2,053 40 2.50 55.00 7 SLF 10127F1ee0 2,008 18,715 47.8 445.6 2,100 13,900 50.0 4500 16130 sand 1 2,008 4,062 40 125 56.25 8 SLF YF127F1a0 1,847 20,562 44.0 489.6 2,100 21,000 500 500.0 16630 sand 3 5,542 9,603 40 125 57.50 9 SLF Y0127F1.0 1,649 22,211 39.3 528.8 2100 23,100 500 50.0 16630 sad 6 9.893 19,497 40 1.25 5875 10 SLF Y0127FlerO 9077 25,288 73.3 602.1 4,200 27300 100.0 450.0 16.130 sand 8 24,613 44,116 40 2.50 61.25 11 SLF 5012719ee0 0731 27,019 402 643.3 2,520 29,820 600 713.0 16630 sand 11 17,308 61423 40 150 62.75 12 SLF 80127Fba0 2.936 29,615 61.8 705.1 3,780 33.600 900 8000 16620 Carbone 11 25,962 87,385 40 2.25 5.00 13 Flush VF127Flet0 1.092 30,707 26.0 7311 1092 34,692 26.0 8280 NA 0 0 87,35 40 065 655 10 Flush WF127 1,092 31,793 26.0 7571 1,092 35.784 26.0 520 NA 0 0 87,35 20 130 6815 5 Flush L0T200 2,100 33,839 500 807.1 2,130 37,884 500 902.0 NA 0 0 87,35 20 2.50 6945 Clean Volume Ratio YF127FIex0 nontains, Hydration Curves for B887 @ 511 1n Pad 12600.0 39.90. 6882(gelling agent) 6.50 galPet moa 9kary 18,964.0 60100 76041crossllnkm3 220 gaper moat 4.7001"4'2804041) 016.1844 gal J 324.'1600"0 51611000 gal Tot) 31,584.0 752 bbls M002(Activator) 1.70 gal ow ingot 301601000 qa1 ��ti�� 25141866461 J511(0elaking Agent) 4.00 gal per moat ' 20 I4<1000491 I 1514,10089a1 Proppant Concentration Ratio F1131Setractantl 1.00 gal per ego Q Nth;Mil 6x1 Prospers 1-6 19,497 22.30. L064(Clay 5tabil:zed 2.00 gal per mg) Pioppant>6PPg 67,888 7770. L0651Scala Inh,b,or) 100 gainer eget T,mperalute'de00 Total 87,35 14275186ocidel 0,30 gaiPm legal J 18 16 21 27 32 38 13 J9 J569(Encapsulated Breekal 0.5-6.0 bpm meal 40 Fluid 8 Proppant per Net Thidrmss Na PayTreated24 MB882101.9 821contains:999.nl 50 Prospers 14610 02 1 F103(S d n tagentl 6.50 gainer moa Fluid(gagf0 451 L01315wfaotantl 000 gal, dOk� - --~"""•"�..: "�� L065(ScalStablker) 2.00 gel pet meal Material Requirements LOBS(Scab Inhibitor) 1.00 gal pm meal _ Acid Requirement OgMons M275(Biocide) 0.30 gal pm mya n 30 • Want Requirement 1,200 Ws J5691EncapuWated Breaker] 0,5-6.0 lb per moa -�_l • Procyon,Requitemen 87,35 la ' 20 660.of moppant 57,674 •• 0 JO 59 60 10 00 19 100 110 120 Tomgrenlum.1,98' Anticipated Pressures and frac dimensions: Maximum Anticipated Treating Pressure: 5500 psi Anticipated half length: -250' TVD Frac top: 6640' MD Frac top: 8875' TVD Frac bottom: 6790' MD Frac bottom: 9005' The above values were calculated using modeling software. Surface pressure is calculated based on a closure pressure of -0.5 psi/ft or -3700 psi, this combined with the anticipated net pressure to be built and the friction gives a surface pressure of 5500 psi at the time of flush. The frac height is primarily based on closure pressure differences between the harder Sag formation "' and the softer confining layers. Average confining layer stress is -0.655 psi/ft. Half length is based on confining layer stress as well as leak-off and formation modulus. Given the values we used, a half length of 250' is expected. Pressure Test Information (20 AAC 25.283,a,7) Per the frac program, the both the tubing and the IA will be pressure tested. The IA will be tested to 4000 psi and the tubing will be tested to 5000 psi (110% of max differential of 4500 psi). PRV setting procedures and annulus monitoring: Maximum Allowable Treating Pressure: 7000 psi Stagger Pump Kickouts between: 6650 psi and 6300 psi (90%to 95%of MATP) Global Kickout: 6650 psi (95%of MATP) IA pop-off set pressure: 3000 psi(75%of MIT-IA) Treating line test pressure: 8000 psi Sand Requirement 62,000# 16/30 Sand, 26,000#16/20 Carbolite Minimum Water Requirement 1000 bbls (pump schedule: 752 bbls) IA Hold Pressure 2500-3000 psi OA Monitor and maintain open to atmosphere There are three overpressure devices that protect the surface equipment and the wellbore from overpressure. Each individual frac pump has an electronic kickout that will kick the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are set between 90% and 95% of the maximum allowable treating pressure. There is the primary pressure transducer in the treating line that will trigger a global kickout which will kick all the pumps into neutral. Finally, there is a manual kickout that is controlled from the frac van. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. S-129 Rig Up via..lin. Treesaver mounted o mea4241 Inner Annulus Lute II"'UlC'�r• `• awl 1 Dmriermeoer 1II on heating line V pump for LApresmre control CBooa Trur — Fac Tank Prop End pump — Fac Tank _ Frac Car Control Van and Lab — Frac Tank L _ —1 Frac Tank Chemical Disclosure (20 AAC 25.283,a, 12) CAS Number Chemical Name Mass Fraction - Water(Including Mix Water Supplied by Client)` '"76% 14808-60-7 Crystalline silica —16% 66402-68-4 Ceramic materials and wares,chemicals "'7% 9000-30-0 Guar gum <1% 7727-54-0 Diammonium peroxidisulphate <0.1% 107-21-1 Ethylene Glycol <0.1% 75-57-0 Tetramethylammonfum chloride <0.1% 129898-01-7 2-Propenoic acid,polymer with sodium phosphinate <0.1% 25038-72-6 Vinylidene chloride/methylacrylate copolymer <0.1% 111-76-2 2-butoxyethanol <0.1% 67-63-0 Propan-2-ol <0.1% 1310-73-2 Sodium hydroxide(impurity) <0.01% 11138-66-2 Gum,xanthan <0.01% 68131-39-5 C12-15 alcohol ethyoxyiated <0.01 96 34398-01-1(7E0) Linear C11 alcohol ethoxylate(leo) <0.01 96 34398-01-1(3E0) Linear Cli alcohol ethoxylate(3eo) <0.01 96 1330-43-4 Sodium tetraborate <0.01 96 91053-39-3 Diatomaceous earth,calcined <0.01% 7647-14-5 Sodium chloride <0.01% 10043-52-4 CALCIUM CHLORIDE <0.01 96 10377-60-3 Magnesium nitrate <0.001% 7631-86-9 Non-crystalline silica(impurity) <0.001 96 14807-96-6 Magnesium silicate hydrate(talc) <0.001% 26172-55-4 5-chloro-2-methyl-2h-isothiazolol-3-one <0.001 96 7786-30-3 Magnesium chloride <0.001% 9002-84-0 poly(tetrafluoroethylene) <0.001% 111-46-6 2,2"-oxydiethanol(impurity) <0.001% 2682-20-4 2-methyl-2h-isothiazol-3-one <0.001% 14464-46-1 - Cristobalite <0.0001% 7447-40-7 Potassium chloride im.uri <0.0001% Total 100% r N c1 n. \ 0 4, CNI C013000 0 0 0 \ 0 0 L fl- LL LL LL LL LL LL LL LL LLLL i N N N N N N N N '1 .3 '2 /a N N to OF 3 '{ t 0 V M fli f6 C N z v s- ca CD w U w C 1.-. } t Q t 7 N N 'O Cr C O C c6 +' O to a Tr +, rV }, la-) -a U ++ V U N C O C �; ( c of ami vii ++ N c6 0.0 v O I N s_ U d .0 C C U N L •O si 0O O v 00 N > N ., I W t C Y NC - N X Z v a) ca) v+ o � M w I c ri d I ,� ++ C C N N I c0 L Q- V 0 . 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A +_' In C a) i 0 to Q 342 O "' D o +' C u U U U • O -t...,, CI 2 fa N +-+ a) N tv (a +•; C fa fa i (.) m 0 ca O M a) p c +' -a L.L. c L O Q) C Y ,I N as C `� 00 O '1 p U �+ c am0 ' C V1 O ^ C I N00 o N ' a6 NNo o ' a) cc C co a) m a o � 0 0 0 p cu N C .D N c •L 1 o t .. —>. Q u L a) C +' N u 4-1,,, Al c a, ' a -, � � U `i � -0 wm aa) a � '� v n � � 0 ell 0 c v s .c U +� C 4- E co ._ +' O _. 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U cu ` Y cu L C L N 4— th c co Q o 0 o C a E o co v) V 0 — cnN -4-, L el ---- ,_ _N U 0 C- .ro O � N oo (7.) 4'2 2 E3 N tao -a c a) E N a o a a s L 3 c io v i ct D U (o c c ve U lD D. o U a C U c co co N ii Es a E V 0 > U a Davies, Stephen F (DOA) From: Wages, David <David.Wages@bp.com> Sent: Tuesday,April 21, 2015 4:02 PM To: Davies, Stephen F (DOA) Cc: Wallace, Chris D (DOA); Loepp, Victoria T (DOA); Roby, David S (DOA) Subject: RE: PBU S-129 (PTD #210-132) - Sundry Application for Hydraulic Fracturing Operations -Additional Questions 1. What are the vertical displacement footages for the three faults that lie near PBU S-129? The map below shows the displacement of each fault in feet. -- A - 44, .... t;� 14 ,.-ice .,,..„ ,c 50 34 1R t S 5 S-128 ... c -- 1 S-1 291 -�- in 11e(25122114 8 j 1 t • `y heel 1 �5 04 ct 19 36 / 6+:0 10 ..,, 2 0 9 4000 . . 53 ; IIIA ,,,,: WM 02 � y I: iii 00 7 17 2. Will these faults compromise containment of the injected fluids within%2 mile of PBU S-129? Possibly, however, it is in our interest to keep fracturing fluids within the producing interval. If we see a surface or DH gauge indication that the fluid has intercepted a fault (sudden, unexpected/non-predicted drop in treating pressure), we will evaluate the issue and possibly go to flush early.At this point,we are expecting a 250' half length, which is shorter than the closest fault.Again,the frac geologic model will be re-calibrated based on the injection test performed prior to the frac job. 3. What are BP's estimated fracture pressures for the Kalubik Shale (upper confinement), the Kuparuk(target injection interval), and the underlying Miluveach shale (lower confinement)? 1 Upper: 0.75psi/ft estimated Kuparuk: ^'0.5-0.65 psi/ft Lower: 0.73 psi/ft David Wages o. 907.564.5669 c. 713.380.9836 W I E-AK From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Tuesday, April 21, 2015 10:53 AM To: Wages, David Cc: Wallace, Chris D (DOA); Loepp, Victoria T(DOA); Roby, David S (DOA) Subject: RE: PBU S-129 (PTD #210-132) - Sundry Application for Hydraulic Fracturing Operations - Additional Questions David, I don't believe that AOGCC received a response to the three questions, below. If BP could please provide answers, I can move the Sundry Application for fracture stimulation of PBU S-129 along in AOGCC's review process. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (DOA) Sent: Monday, March 30, 2015 4:53 PM To: 'Wages, David' Cc: Wallace, Chris D (DOA); Loepp, Victoria T(DOA); Roby, David S (DOA) Subject: PBU S-129 (PTD #210-132) - Sundry Application for Hydraulic Fracturing Operations - Additional Questions David, The information provided by BP to date is scattered between the Sundry Application and many emails, so in making one final pass through all of BP's submitted information, I have a few remaining questions: 1. What are the vertical displacement footages for the three faults that lie near PBU S-129? 2. Will these faults compromise containment of the injected fluids within%2 mile of PBU S-129? 3. What are BP's estimated fracture pressures for the Kalubik Shale(upper confinement), the Kuparuk(target injection interval), and the underlying Miluveach shale (lower confinement)? Others on AOGCC's review team may submit additional questions separately. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential 2 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Tuesday, April 21, 2015 10:53 AM To: 'Wages, David' Cc: Wallace, Chris D (DOA); Loepp,Victoria T (DOA); Roby, David S (DOA) Subject: RE: PBU S-129 (PTD #210-132) - Sundry Application for Hydraulic Fracturing Operations - Additional Questions David, I don't believe that AOGCC received a response to the three questions, below. If BP could please provide answers, I can move the Sundry Application for fracture stimulation of PBU S-129 along in AOGCC's review process. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (DOA) Sent: Monday, March 30, 2015 4:53 PM To: 'Wages, David' Cc: Wallace, Chris D (DOA); Loepp, Victoria T(DOA); Roby, David S (DOA) Subject: PBU S-129 (PTD #210-132) - Sundry Application for Hydraulic Fracturing Operations - Additional Questions David, The information provided by BP to date is scattered between the Sundry Application and many emails, so in making one final pass through all of BP's submitted information, I have a few remaining questions: 1. What are the vertical displacement footages for the three faults that lie near PBU S-129? 2. Will these faults compromise containment of the injected fluids within %z mile of PBU S-129? 3. What are BP's estimated fracture pressures for the Kalubik Shale (upper confinement), the Kuparuk (target injection interval), and the underlying Miluveach shale (lower confinement)? Others on AOGCC's review team may submit additional questions separately. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 1 From: Wages, David [mailto:David.Wages@bp.com] Sent: Tuesday, March 24, 2015 6:39 AM To: Davies, Stephen F (DOA) Subject: FW: S-129PB1 Steve, Please see our geologist's response below. David Wages o. 907.564.5669 c. 713.380.9836 W I E-AK I think that you can keep the picks the same as you have them in Techlog for S-129PB1. I cannot decide if the sand stringer at 6800TVDss should actually be the C1a. Looking at offsets does not provide a quick answer. The stringer at approx.. 6800TVDss looks HC filled and I would guess that it is probably in communication with the C sands above. So the C sands have an oil down to of approx.. 6789TVDss. There is a deeper ODT at approx. 6802TVDss (B shale). Empirically, based on 50-ish wells from Aurora our average OWC is 6810'TVDss but this really can vary depending on rock quality. Our best guess on the Aurora free water level is 6855'TVDss, a number that I often quote in addition to the OWC. Thanks Graham Graham Emerson Geoscientist West Satellites Area, BP Alaska 674-D Email:graham.emerson@bp.com Office: +1 (907) 564-4686 Cell: +1 (907) 793-0315 2 RECEIVED STATE OF ALASKA 1 7 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION AFFIDAVIT OF NOTICE OF OPERATIONS AOGCC Before me, the undersigned authority, on this day personally appeared 7\U4 CA Ct e S , who being duly sworn states: 1. My name is David Wages. I am 18 years of age or older and I have personal knowledge of the facts stated in this affidavit. 2. I am employed as a Engineer by BP Exploration (Alaska) Inc. ("BPXA") and I am familiar with the Application for Sundry Approvals to stimulate the S-129 Well (the "Well") by hydraulic fracturing as defined in 20 AAC 25.283(m). 3. Pursuant to 20 AAC 25.283(1), BPXA prepared a Notice of Operations regarding the Well, a true copy of which is attached to this Affidavit as Attachment 1 ("Notice of Operations"). 4. On February 13, 2015, the Notice of Operations was sent to all owners, landowners, surface owners and operators within a one-half mile radius of the current or proposed wellbore trajectory of the Well. The Notice of Operations included: a. A statement that upon request a complete copy of the Application for Sundry Approvals is available from BPXA; b. BPXA's contact information. Signed this 17"'day of Febuary, 2015. '1U1 (Signature) /(4-7 STATE OF ALASKA THIRD JUDICIAL DISTRICT e Subscribed and sworn to or affirmed before me at 4'14 rat 0 e /i-1\ on the ii l 7 day of rc6 ruAtiry , 20 t5 . / ... 41 ..„,_ ir nature of Officer /` 0111Wille% As, 1-• J0,9 0711 A 1 f Q'. c "41.O'''. S4 Title of Officer if NOTARY; PUBLIC ' ` timiAl4`���`®`� RECEIVED FEB 17 2015 Steve, AOGCC Below is a screenshot of the labeled formations. Please let me know if you need it expanded. (, Stress Stress a Stress a Pad Loss ND Depth Stress Stress Gradient Top d Bottom d Coefficient Spurt Proppert to Top d 0slerace from Surface Zone Grethen Zone Lloottus F''''''''' ffOroot Loss Embedmert Layer Zone Rt! Type PSI I.<! (pa) i t 1, i1•*• i Ram K-Ic lmnli pal OO1"21 'b:h'f2; I 5544.5 Kulubik (] 0.0 0701 4655.2 0700 4686.3 1.000000 0.30 2000.0 0.001100 10.00000 0.10000 2 6707.5 Kuparuk C4 Q -1071.5 0.541 3627.6 0700 3675.5 3.000000 0.20 2000.0 O.D03500 10.00000 010000 3 6782.3 Kuparuk Cl O 1015.4 0.652 4655.3 0.700 4714.7 1.000000 0.30 2000.0 0.001000 10.00000 0.10000 4 6810.0 Water (] 258.6 0730 4873.3 0 700 0.0 1.000000 0.25 2000.0 0.002000 10.00000 0.10000 MD for each zone: Kulubik:8758.74' Kuparuk C4:8876.08' Kuparuk Cl: 11,323.53' Due to the horizontal nature of the well,we never reach 6810'TVD. When drilling the well,a pilot hole was drilled at the heel of the horizontal section in order to obtain logs/formation tops.This is where the log we used for the frac simulator came from (see screenshot below: N O i G v -aN= 0 { 0 0 EEEE y ,_ .. EEEE .. ' - A 0 0 0 0 ao Qii.aa I IO 8.5,8 Q 1 � o ao IIIIMIM o S g H co iso I 8 cp We think the water contact is right around 6810 TVD(thus the blue formation labeled water),the primary purpose of labeling a water formation is to give us a better visual as to how close our modeled frac will come to the OWC. Please note,the only useable logs we could use were Gamma ray, Bulk Density and Porosity which do not give us values for Modulus, Poisson's Ratio or Permeability.These values were obtained from offset data. All the above data for each formation will be verified and corrected via an injection test to be performed prior to the fracture stimulation. Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, March 30, 2015 4:53 PM To: 'Wages, David' Cc: Wallace, Chris D (DOA); Loepp, Victoria T (DOA); Roby, David S (DOA) Subject: PBU S-129 (PTD #210-132) - Sundry Application for Hydraulic Fracturing Operations - Additional Questions David, The information provided by BP to date is scattered between the Sundry Application and many emails, so in making one final pass through all of BP's submitted information, I have a few remaining questions: 1. What are the vertical displacement footages for the three faults that lie near PBU S-129? 2. Will these faults compromise containment of the injected fluids within Y2 mile of PBU S-129? 3. What are BP's estimated fracture pressures for the Kalubik Shale (upper confinement), the Kuparuk (target injection interval), and the underlying Miluveach shale (lower confinement)? Others on AOGCC's review team may submit additional questions separately. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Wages, David [mailto:David.Wages@bp.com] Sent: Tuesday, March 24, 2015 6:39 AM To: Davies, Stephen F (DOA) Subject: FW: S-129PB1 Steve, Please see our geologist's response below. David Wages o. 907.564.5669 c. 713.380.9836 WIE-AK I think that you can keep the picks the same as you have them in Techlog for S-129PB1. I cannot decide if the sand stringer at 6800TVDss should actually be the C1a. Looking at offsets does not provide a quick answer. 1 Davies, Stephen F (DOA) From: Wages, David <David.Wages@bp.com> Sent: Tuesday, March 24, 2015 6:39 AM To: Davies, Stephen F (DOA) Subject: FW: S-129PB1 Steve, Please see our geologist's response below. David Wages o. 907.564.5669 c. 713.380.9836 W I E-AK I think that you can keep the picks the same as you have them in Techlog for S-129PB1. I cannot decide if the sand stringer at 6800TVDss should actually be the C1a. Looking at offsets does not provide a quick answer. The stringer at approx.. 6800TVDss looks HC filled and I would guess that it is probably in communication with the C sands above. So the C sands have an oil down to of approx.. 6789TVDss. There is a deeper ODT at approx. 6802TVDss(B shale). Empirically, based on 50-ish wells from Aurora our average OWC is 6810'TVDss but this really can vary depending on rock quality. Our best guess on the Aurora free water level is 6855'TVDss, a number that I often quote in addition to the OWC. Thanks Graham Graham Emerson Geoscientist West Satellites Area, BP Alaska 674-D Email:graham.emerson@bp.com Office: +1 (907) 564-4686 Cell: +1 (907) 793-0315 1 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, March 16, 2015 1:39 PM To: 'Wages, David' Subject: RE: PBU Aurora S-129 (PTD#210-132) Supplemental Information David, My question "What is the basis for the determination of the oil-water contact?" was poorly worded, so let me try again. Why does BP place the oil-water contact at-6810'TVDSS on the well log from the PB1 pilot hole? This particular footage on the PB1 well log lies in the upper portion of a 16-foot thick(ND thickness) interval of silty sandstone and siltstone—according to the gamma-ray log—that displays nearly uniform resistivity of about 6 ohm-m. The neutron and density logs give no clue, so I'm curious as to what is the reason for selecting that particular footage (9073' MD,-6810' TVDSS)? Thanks again for your help, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Wages, David [mailto:David.Wages@bp.com] Sent: Monday, March 16, 2015 1:20 PM To: Davies, Stephen F (DOA) Subject: RE: PBU Aurora S-129 (PTD #210-132) Supplemental Information Please see responses below in Red. Again, let me know if you need anything else. David Wages o. 907.564.5669 c. 713.380.9836 WIE-AK From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, March 16, 2015 11:36 AM To: Wages, David Subject: RE: PBU Aurora S-129 (PTD #210-132) Supplemental Information David, 1 Following up on your email from this morning: I loaded into my workstation all of the directional survey and well log data that BP supplied to AOGCC for the PBU S-129PB1 pilot hole, and I utilized the TVD reference elevation provided on the directional survey report. I could not match the MD values that you supplied for the top of each zone. So, by comparing the gamma ray curve in my workstation to the log plot that you provided, I arrived at the following depth and thickness values for the PB1 borehole. Top TVD MD Marker Top MD Top TVD Subsea Thickness TVD Thickness KLBK 8,756.3 6,707.3 -6,644.9 117.5 63.1 KPRKC4 8,873.8 6,770.4 -6,707.9 36.5 18.9 KPRKC2 8,910.3 6,789.3 -6,726.9 70.25 36.2 KPRKC1 8,980.5 6,825.5 -6,763.1 92.5 47.0 OWC 9,073.0 6,872.5 -6,810.1 The TVD values that you provided seem instead to actually be true vertical depth subsea values (TVDSS). Could you please confirm this?Or have I overlooked something? If correct,will these small depth necessitate changes to BP's fracture model?This is correct. The small difference in sub-sea vs surface TVD will not have an effect on the way our frac will propagate.The stress, Modulus and leak-off coefficient are the important factors that we will adjust following the interpretation of the injection test. What is the basis for the determination of the oil-water contact? Confirmed when drilling PB1 (same borehole we used to find tops of lower formations). Also, I'm not familiar with the abbreviation K-Ic. Google indicates that this is related to "fracture toughness." Can you briefly describe this? "Stress intensity factor" or apparent fracture toughness. It is the ability of a rock to resist fracture propagation. So glass would have a low K-Ic because once a crack is made,the crack likes to grow very far and with very little additional stress. For our modeling (and almost every model I've ever created) a value of 2000 is applied, knowing that the property will not affect the fracture geometry.This is the same practice that BP's central frac gurus do and is considered acceptable. When will the injection test be conducted? How far in advance of the fracture stimulation will this test be conducted? Will the simulation be re-run prior to the actual fracturing operation? —3-5 days before the frac equipment heads out there.The injection test will confirm closure stress and the stresses of the confining layers as well as leak-off coefficient. 2 ``etcaon 7 D =w'Sh e.Coupl 5 r.-od 8 Match thesepressuresto Match threslape ofthis line confirry nfintng€ayer'sstresse3 coefficient ` + r ' g I 4,%fah "'Jrt ncp- �P F g Y i t✓add 4 d' End of pronor ig G5 First Shut in tY Q. L Q 3Ck 2} 0. ... t 0 Cts Tkne Ow) Thanks for your help, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. From: Wages, David [mailto:David.Wages@bp.com] Sent: Friday, March 13, 2015 1:34 PM To: Davies, Stephen F (DOA) Subject: RE: S-129 Supplemental Information 3 Davies, Stephen F (DOA) From: Wages, David <David.Wages@bp.com> Sent: Friday, March 13, 2015 1:34 PM To: Davies, Stephen F (DOA) Subject: RE: S-129 Supplemental Information Attachments: AOGCC Notification Supplement V2.docx Steve, Please find attached the information you requested.Thank you for your patience. David Wages o. 907.564.5669 c. 713.380.9836 WIE-AK From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Thursday, February 26, 2015 1:14 PM To: Wages, David Cc: Loepp, Victoria T(DOA); Wallace, Chris D (DOA) Subject: RE: S-129 Supplemental Information David, I'm trying to keep the PBU Aurora S-129 application moving through AOGCC's review process. I don't believe that I ever received BP's answers to my second round of questions, below. Thanks, Thanks, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7`h Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (DOA) Sent: Thursday, February 19, 2015 11:17 AM To: 'Wages, David' 1 Steve, 1. I notice that the application lacks the Affidavit required by 20 AAC 25.283(a)(1). Please provide an Affidavit as required by the regulation;the simple statement of notification provided within the application is not an acceptable substitute. Thank you for providing the Affidavit. Who were the owners, landowners,surface owners and operators that received a copy of the Notice of Operations? BP, Conoco Phillips, Exxon, Chevron, Department of Natural Resources. 2. Please amplify the brief table of geological and engineering information provided to better meet the requirements of 20 AAC 25.283(a)(9). Please provide: • geological name of each fracturing and confining zone, Incomplete response: Does BP consider the Kalubik Shale to be the upper confining interval for the proposed fracturing operation? Yes.Which interval(s)will provide confinement beneath the fractured interval? We will not have a hard layer below our frac initiation point.The barrier(s)are a culmination of smaller shale layers that assist in confining the frac fluid.The pumping operation will be halted when our stimulation indicates we are approaching the OWC. Please provide more information. AOGCC is concerned about the true vertical thickness and the lateral continuity of the upper and lower confining interval(s). A detailed structure cross-section through S-129 and surrounding wells that demonstrates the thickness and lateral continuity of both the fractured interval and the confining interval(s) along with any nearby faults would be most helpful,and it will greatly speed the geologic portion of this review. • %dog SI awe • Swill Patter bP r..bS�S81g SIECVC' —*swayS-129 Measured Depth Profile 0 Net* Swat —Peartaa IMO, PPK txC4 ._ -Pet -......_,per 6703. .r' i" �.' :.y.t.. �TWR.CV 6710 •' • -1KCMC a -at CM 0: Pe2 '� 3C1 6666 N tVS0 � � KaWli � 51688a0 Unr ® "C)1.10°lli"I.PPIP"'- -h66 MCI IV80 '11110,0 6P6o r Noo 6 164 esw 6833 6679 a P131yy y g t g yt ¢* ■ Ea ■ ts g gg gg g gg gg g@ g gg pp gg g gg QQ g 4 4 i 4 4 4 4 i 4 i 11 4 t • • f i 4 411 E 4 Il If E $ E 4 i 3 9 ! t • Y i i ■ # 3 i Meestled Depth In the above cross section, our logs were taken from PB1.The closed sliding sleeve(#7) is the zone to be stimulated. Will both the Kuparuk C4 and Cl intervals be fractured? Does the C4 directly overlie the Cl.in this area?Or are there strata in between?See below screenshot of geologic layers Below is a screenshot of the labeled formations. Please let me know if you need it expanded. NO Depth StressStrew Strew a gree Stress a Flux Lou Greoert Top d Bottom d Ceoetf.oert Spun Proppr* to Top d DMererxe "'WT.' '1/40.0,4 .cel Surf ace Zone ZoneIltroat Loa EmOednest Lei Zone Rtl Typo ip8' (Pa.fil Ip®i 19.1") 1 1 (1•V4544Rro 1C-10Owl (..'10062 •1t .. 1 m WW1* 0 0 0 1 552 10309 5 0 700 10355.0 1 000000 0.30 2000.0 0 001000 pm.I 0.10000 2 MEM Kupruk C4 . .7077 7 0.088 3276 3 0 700 3289.6 3 000000 0 20 0.003300 10.00000 010000 3 amin Ktq.utc2 0 119.8 0.607 3500.5 0.700 e434.8 2.000000 0.26 2000.0 ice.. 5 :..d.s'eF .. D USA,.,, 1328 2 0700 4831 0 2.000006 0 2 =1111 -,LL.+ -., 31 5 6810.0 tiler - 635 2 0 735 5995 2 0 700 0.0 000020 0 25 2000 0 0 002500 100 00002 2 12000 MD for each zone: TVD for each zone (from the table above): Kulubik: 8646' Kulubik: 6645' Kuparuk C4:8760' Kuparuk C4: 6708' Kuparuk C2:8794' Kuparuk C2: 6726' Kuparuk Cl:8959' Kuparuk Cl: 6810' N/A OWC: 6810' Due to the horizontal nature of the well, we never reach 6810'TVD. When drilling the well, a pilot hole was drilled at the heel of the horizontal section in order to obtain logs/formation tops.This is where the log we used for the frac simulator came from (see screenshot below: Top Bottom Type o ft It Delete Kulubik 06644 9 6707.9 Delete Kuparuk C4 06707.9 6726.9 Delete Kuparuk 62 1000211152WDelete --4'a - Delete Wales 0.:10.0 .982.2 Delete 1 _- 1-4- T -T r j I Nva r,,�.--„ ..A '- .1 ,s iiik.-: i 1 i 1... I -f i I I 1 I r — dare-4, S - -.' '' i Er -"_- ---.1 --^— _ ---_----- t U r'i ^.r^'1...+..1f V .e..�'•_iJvr.'r� LM^, 0.,..,ewe'J"'�Jk/A'� .7./v-e'�.Jv',^ co co We think the water contact is right around 6810 TVD (thus the blue formation labeled water),the primary purpose of labeling a water formation is to give us a better visual as to how close our modeled frac will come to the OWC. Please note,the only useable logs we could use were Gamma ray, Bulk Density and Porosity which do not give us values for Modulus or Poisson's Ratio.The values for Stress were estimated based on GR and Bulk density. Fluid loss coefficient is taken from the logs. K-Ic,Spurt loss and Proppant embedment are estimated and play a small role in modeling the frac. All the above data for each formation will be verified and corrected via an injection test to be performed prior to the fracture stimulation,this is where Modulus will be adjusted to match the pressure trend seen. Steve, Please find attached the information you requested. Thank you for your patience. David Wages o. 907.564.5669 c. 713.380.9836 WIE-AK From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Thursday, February 26, 2015 1:14 PM To: Wages, David Cc: Loepp, Victoria T(DOA); Wallace, Chris D (DOA) Subject: RE: S-129 Supplemental Information David, I'm trying to keep the PBU Aurora S-129 application moving through AOGCC's review process. I don't believe that I ever received BP's answers to my second round of questions, below. Thanks, Thanks, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (DOA) Sent: Thursday, February 19, 2015 11:17 AM To: 'Wages, David' Cc: Loepp, Victoria T(DOA); Wallace, Chris D (DOA) Subject: RE: S-129 Supplemental Information David, From my previous email: 1. I notice that the application lacks the Affidavit required by 20 AAC 25.283(a)(1). Please provide an Affidavit as required by the regulation;the simple statement of notification provided within the application is not an acceptable substitute. 4 Thank you for providing the Affidavit. Who were the owners, landowners, surface owners and operators that received a copy of the Notice of Operations? 2. Please amplify the brief table of geological and engineering information provided to better meet the requirements of 20 AAC 25.283(a)(9). Please provide: • geological name of each fracturing and confining zone, Incomplete response: Does BP consider the Kalubik Shale to be the upper confining interval for the proposed fracturing operation? Which interval(s) will provide confinement beneath the fractured interval? Please provide more information. AOGCC is concerned about the true vertical thickness and the lateral continuity of the upper and lower confining interval(s). A detailed structure cross-section through S-129 and surrounding wells that demonstrates the thickness and lateral continuity of both the fractured interval and the confining interval(s) along with any nearby faults would be most helpful, and it will greatly speed the geologic portion of this review. Will both the Kuparuk C4 and Cl intervals be fractured? Does the C4 directly overlie the Cl in this area? Or are there strata in between? • lithologic description of each zone,and Incomplete response: No additional information has been provided. • measured depth and true vertical depth of each zone. Incomplete response: Measured depths supplied for only Kalubik, Kuparuk C4 and Kuparuk Cl. No true vertical depth information has been provided. 3. What is BP's source for the layer information provided in the "Geological Frac Information"table? Incomplete response: Which offset wells were used? What measurements or laboratory analyses were used to derive the values provided? Thanks for your help. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 5 From: Wages, David [mailto:David.Wages@bp.com] Sent:Tuesday, February 17, 2015 10:18 AM To: Davies, Stephen F(DOA) Cc: Loepp, Victoria T(DOA); Wallace, Chris D (DOA) Subject: S-129 Supplemental Information Steve, Please find attached the information you requested. Thanks, please let me know if you need anything else. A hard copy will be delivered this afternoon containing this and any further information you need. Thanks, David Wages o. 907.564.5669 c. 713.380.9836 W I E-AK From: Davies,Stephen F (DOA) Sent: Friday, February 13, 2015 10:05 AM To: 'david.wages@bp.com' Cc: Loepp, Victoria T(DOA); Wallace, Chris D (DOA) Subject: PBU Aurora S-129 (PTD#210-132): Sundry Application for Proposed Hydraulically Fracture Stimulation David, AOGCC received BP's application for sundry approval for the proposed hydraulic fracture stimulation of PBU S- 129 on Thursday, February 12, 2015. BP's estimated date for commencing operations is Tuesday, February 17th. This application is now in AOGCC's review process queue, but please be aware that all AOGCC personnel needed for review and approval of this application may or may not be available to meet your rush request because of: other applications already in the review process queue, regularly scheduled flex days, the up- coming weekend, and the Federal holiday on Monday, February 16th As I review the geological aspects of BP's application, I will send my questions to you as they arise. To begin: 1. I notice that the application lacks the Affidavit required by 20 AAC 25.283(a)(1). Please provide an Affidavit as required by the regulation; the simple statement of notification provided within the application is not an acceptable substitute. 2. Please amplify the brief table of geological and engineering information provided to better meet the requirements of 20 AAC 25.283(a)(9). Please provide: • geological name of each fracturing and confining zone, • lithologic description of each zone, and • measured depth and true vertical depth of each zone. 6 What is BP's source for the layer information provided in the "Geological Frac Information" table? Please correlate this information with each of the fracturing and confining zones described above. Please provide a copy of BP's source, marking it Confidential and provide justification for the claim for confidentiality, if applicable. In the provided "Geological Frac Information" table, what do the "Type" listings of"Oil" and "Water" signify? The other members of AOGCC's review team may send additional questions via separate emails. Thank you for your help, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7`h Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 7 '2kD-t32 25to15 WELLLOG DATA LOGGED S/1/2015 11114S TRANSMITTAL M.K.BENDER !RECEIVED PROACTIVE DIAGNOSTIC SERVICES, INC. APR 0 9 2015 AOGCC To: AOGCC Makana BenderI, 333 W. 7th Ave �� y 1 G) Suite 100 Anchorage,Alaska 99501 (907) 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/ MU) 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: Analisa Steger LR2 - 1 900 Benson Blvd. Anchorage,AK 99508 gancpdc@bp.com and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage,AK 99518 Fax: (907) 245-8952 1) Injection Profile 27-Mar-15 S-129 BL/ CD 50-029-23433-00 2) Signed : Date : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGE(5 MEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM D\Archives' asterTemplateFIles\Templates\Dtstnbution\TransmtttalSheets\BP_Transmit docx Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. c' j Q - _I 3. Well History File Identifier Organizing (done) ❑ Two-sided III IIIIIIIIIII II III ❑ Rescan Needed II IIiIIII II I IIII RES914N DIGITAL DATA OVERSIZED (Scannable) //olor Items: ❑ Dis ettes, No. ❑ Maps: 'p�Greyscale Items: Other, No/Type: C, t No, I ❑ Other Items Scannable by V✓ a Large Scanner Poor Quality Originals: nciii,S OVERSIZED (Non-Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: A21210 Date: ... YY • ` _ /s/ Project Proofing 111111111H I 1 BY: C . ! Date: Agr... /s/ Scanning Preparation x 30 = 1 a0 + I = TOTAL PAGES 6 ta. 1 (Count does not include cover sheet) BY: Maria�— Date: al 1 rim /s/ Production Scanning 1311111 I Stage 1 Page Count from Scanned File: /a a. (Count does include cover eet) Page Count Matches Number in Scanning Pre aration: YES NO BY: Date: 1 a i L4,- /s/ ,4 io Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. 1311111111111 ReScanned 1311111111111 BY: Maria Date: /s/ Comments about this file: Quality Checked II DFIIIII IIII III 1 c 06 o ! f° cc o 2a U 0 0 () o co ct . J 0 I co �ooO a v Omcn� y v • Z 0 = N O Q>-�a. O N N N — ma) Ito�Q'= -2 2 N . v"DLL -o —'—0 co CO) 0 N E a) caoa o -0ooQ� I y E otS 2 `^ U N c oh 0 0 0 as E m x ' c 0 oicna. 2 2 z (n o V m m = 3-eQX 0 p.riNmO=? mg) n o d d 0 rn_]C9 2 J a. cc E. a.J a. 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Transmittal Number:93192 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. (BPXA FIELD LOG DATA) If you have any questions, please contact Doug Dortch at the PDC at 564-4973 Delivery Contents 1 CD-ROM Containing Field Log Data & Electronic Log Prints for the following wells: 15-11CPB1 ato-14,3 o fK 18-13C 01,10-4154 /4.) � A-39A c)-10— 1`5S 1s-ltnt F-28B a t O—I(0 g /`(C0(99 S-01C ato—tq '411;3,c)S-18B 'aIO—O3l 11443 t S-129 -129PB1 S-129PB2 \.. 9-[0—(3a ke-4,3a :- Ple a � and Return one copy of this transmittal. } Thank You, Doug Dortch Petrotechnical Data Center . , ,l yW „a , ' ' Attn: State of Alaska - AOGCC Attn: Christine Shartzer 333 W. 7th Ave, Suite 100 Anchorage, Alaska 99501 Petrotechnical Data Center LR2-1 900 E.Benson Blvd.PO Box 196612 Anchorage,AK 99519-6612 I Saltmarsh, Arthur C (DOA) From: Hubble, Terrie L [Terrie.Hubble @bp.com] Sent: Tuesday, April 05, 2011 4:05 PM To: Saltmarsh, Arthur C (DOA) Subject: PBU S-129 I PTD#210-132 Hi Art, Please reference the following well: Well Name: PBU S-129 Permit#: 210-132 API #: 50-029-23433-00-00 Top Perf MD: 8909' Bottom Perf MD: 12838' This well began Production on March 27, 2011 Method of Operations is: Gas Lifted Date of Test: 03/25/11 Hours Tested: 8 24-Hour Rate/Oil-Bbl: 1,308 24-Hour Rate/Gas-Mcf: 789 24-Hour Rate/Water-Bbl: 19 Test Rate/Oil-Bbl: 436 Test Rate/Gas-Mcf: 263 Test Rate/Water-Bbl: 6 Choke Size: 128 Gas-Oil Ration: 603 Flow Tubing Pressure: 100 Casing Pressure: 1,400 Oil Gravity-API: Not Available 1 STATE OF ALASKA DEC 2 1 2010 ` ALASKA OIL AND GAS CONSERVATION COMMI06ION eJaRka Oil&Gas Cans.Commission WELL COMPLETION OR RECOMPLETION REPORT AND Lore LaatioraCe 1 a. Well Status: ®Oil ❑Gas ❑SPLUG ❑Other ❑Abandoned ❑Suspended lb. Well Class: 20AAC 25.105 20AAC 25.110 ® Development ❑Exploratory ❑GINJ ❑WINJ ❑WAG ❑WDSPL ❑Other No.of Completions One ❑Service ❑Stratigraphic 2. Operator Name: 5.Date Comp.,Susp.,or Aband.: 12. Permit to Drill Number: BP Exploration(Alaska) Inc. 11/20/2010 210-132 3. Address: 6.Date Spudded: 13. API Number: P.O. Box 196612,Anchorage,Alaska 99519-6612 10/25/2010 50-029-23433-00-00 4a. Location of Well(Govemmental Section): 7.Date T.D.Reached: 14. Well Name and Number: Surface: 11/12/2010 PBU S-129 1635'FNL,4103'FEL, SEC. 35,T12N, R12E, UM 8. KB(ft above MSL): 62.46' 15.Field/Pool(s): Top of Productive Horizon: 3648'FNL, 3076'FEL, SEC. 34,T12N, R12E, UM GL(ft above MSL): 33.79' Prudhoe Bay Field/Aurora Pool Total Depth: 9.Plug Back Depth(MD+TVD): 2347'FNL,2886'FEL, SEC.03,T11 N, R12E, UM 12964' 6791' ■ 4b. Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16. Property Designation: Surface: x- 619339 y- 5979855 Zone- ASP4 12964' 6791' ADL 028257,028258&028261 TPI: x- y- Zone- ASP4 11.SSSV Depth(MD+TVD): 17. Land Use Permit: Total Depth:x- 615380 y- 5973800 Zone- ASP4 N/A 18.Directional Survey: 18I Yes ❑No 19.Water depth,if offshore: 20. Thickness of Permafrost(TVD): (Submit electronic and printed information per 20 AAC 25.050) N/A ft MSL 1900'(Approx.) 21.Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): 22. Re-Drill/Lateral Top Window MD/TVD: GR, RES, NEU,AZI DEN, PWD,ABI, DEN Caliper, Periscope 23. CASING,LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING WT.PER FT. GRADE TOP I BOTTOM TOP BOTTOM SIZE CEMENTING RECORD PULLED 20" 129.5# X-65 Surface 108' Surface 108' 42" -260 sx Arctic Set 9-5/8" 40# L-80 29' 3295' 29' 3193' 12-1/4" 1220 sx Arctic Set Lite:447 sx Class'G' 7" 26# L-80 26' 8875' 26' 6770' 8-3/4" 454 sx LiteCrete:223 sx Class'G' 3-1/2" 9.2# L-80 8686' 12870' 6667' 6791' 6-1/8" Uncemented slotted liner 1 24. Open to production or injection? ®Yes ❑No / 25. TUBING RECORD If Yes,list each interval open SIZE DEPTH SET(MD) PACKER SET(MD/TVD (MD+TVD of Top&Bottom;Perforation Size and Number): ) 3-1/2", 9.2#, L-80 Slotted Liner 3-1/2"BKR Sliding Sleeve 4-1/2"x 3-1/2',12.6#/9.2#,13Cr85 8710' 8631'/6637' MD TVD MD ND 12297'-12838' 6800'-6791' 8909'-8913' 6787'-6789' 26. ACID,FRACTURE,CEMENT SQLEEZE,ETC. 9198'-9202' 6826'-6826' 9446'-9450' 6820'-6820' DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 9951'-9955' 6809' 6809' Freeze Protected with 74 Bbls of Diesel 10446'-10450' 6817'-6817' _ . P. ,tY 10 11097'-11101' 6838'-6838' _A. LM 11890'-11894' 6829'-6829' T. wl su,j ek es. 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,Gas Lift,etc.): Not on Production N/A Date of Test: Hours Tested: Production For OIL-BBL: GAS-MCF: WATER-BBL: CHOKE SIZE: GAS-OIL RATIO: Test Period 4 Flow Tubing Casing Press: Calculated OIL-BBL: GAS-MCF: WATER-BBL: OIL GRAVITY-API(CORR): Press. 24-Hour Rate 28. CORE DATA Conventional Core(s)Acquired? ❑Yes ®No Sidewall Core(s)Acquired? ❑Yes to No If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed). Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 250.071. None RBDMS DEC 2 2 2010 L Form 10-407 Revised 12/2009 CONTINUED ON REVERSE Submit Original Only.*1 .-'.. / j 29. GEOLOGIC MARKERS(List all formations and markers encountered): 30. FORMATION TESTS NAME M TVD Well Tested? r s ®No 'Permafrost Top 34' 34' If yes,list intervals am,..rmations tested,briefly summarizing test Permafrost Base 1925' 1922' results. Attach separate sheets to this form,if needed,and submit detailed test information per 20 AAC 25.071. Top Ugnu 3861' 3598' Top Ugnu M Sands 5496' 4732' None Top Schrader Bluff N Sands 5813' 4943' Top Schrader Bluff 0 Sands 5998' 5064' Base Schrader Bluff/ 6540' 5390' Top Colville Mudstone I'I Top HRZ 8501' 6565' Top Kalubik 8845' 6754' Kuparuk C 8876' 6770' Kuparuk B 11270' 6842' Kuparuk B 12290' 6800' Kuparuk C 12890' 6791' Formation at Total Depth(Name): Kalubik(from below) 7879' 6202' 31.List of Attachments: Summary of Daily Drilling Reports,Well Work Summary,Well Schematic Diagram,Surveys and Leak-Off Test Summary. 32.I hereby certify that the foregoi • is true and correct to the best of my knowledge. I► Signed: Sondra • - e///1 /.i7��1!' Title: Drilling Technologist Date: `aj 1— 10 PBU S-129 210-132 Prepared By Name/Number. Sondra Stewman,564-4750 Well Number Permit No./Approval No. Drilling Engineer: Mark Staudinger,564-5733 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 a: Classification of Service Wells: Gas Injection,Water Injection,Water-Altemating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevation in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-In,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 Submit Original Only 1 TREE= -WELLHEAD= g SAF. NOTES: WELL ANGLE>70°@ 8971'. ACTUATOR= J M D D RA F 1 ***4-1/2"&3-1/2"CHROME TBG*** KB.ELEV= 62.46' BF.ELEV= 33.6' KOP= 2300 Max Angle=95°@ 12170' 2006' I-14-1/2"HES X NIP, ID=3.813" I Datum MD= 8861' 20"COND H 108' iii Datum TVD= 8800'SS 9-5/8"CSG,40#, L-80 BTC, ID=8.835" H 3295' / I�� 4083' _I-I4-1/2"X 3-1/2"XO, ID=3.813" I 4-1/2"TBG,26#,13CR-80 VAM TOP, H 4083' � .0152 bpf, ID=3.958" GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE Minimum ID = 2.813" @ 8667' IA 5 4163 3811 46 MMG DCR-1 RKP 1.5" 11/17/10 3-1/2" HES X NIPPLE 4 4263 3881 46 MMG DMY RK 1.5" 11/17/10 • 3 6872 5597 52 MMG DMY RK 1.5" 11/17/10 2 8358 6483 54 MMG DMY RK 1.5" 11/17/10 7"CSG.26#, L-80 VT-HC, H 5334' I >< >< 1 8460 6542 56 MMG DMY RK 1.5" 11/17/10 .0383 bpf, ID=6.276" - 1 1 8530' 1-13-1/2"HES X NIP, ID=2.813" I 3-1/2"NDPG SINGLE SENSOR SUB, -I 8595' I • ID=2.992" 8631' I-17"X 3-1/2"HES TNT PKR,ID=2.949" I 2.992"OD SLICKLINE SET H 8642' WRP FOR TBG FT 181 I 8667' I-13-1/2"HES X NIP, ID=2.813"w/PX PLUG(11/18/10) 181 8698' I-3-1/2"HES X NIP, ID=2.813" w/RHC-M PLUG&BALL&ROD ON SEAT 8699' I-7"X 5"HRD BKR ZXP LTP w/FLEXLOCK - I- LNR HGR, ID=4.430" 3-1/2"TBG,9.2#, 13CR-85 VAM TOP, -L 8710' I / ' 8710' IH3-1/2"WLEG, ID=2.992" I .0087 bpf, ID=2.992" \ / 8730' H 5"X 3-1/2"X0, ID=2.99" 7"BKR WHIPSTOCK H 8875' I 3-1/2"BKR CMD Sliding Slv@ 8909',9198', 9446',9951', 10446', 11097'and 11890' MILLED OUT WINDOW(7") 8875'-8910' 1, OBM Swell Packers &8930', PBTD H 9354' vv,v,v,vv,v,v,vv" 9714', 10659'and 12266' 7"CSG,26#,L-80,BTC-M, H 9436' ".4.AWA et1144 �� 4 1 .0383 bpf, ID=6.276" 44 *°,, ? PERFORATION SUMMARY REF LOG: , ANGLE ATTOPPERF: 1� ,/ Note: Refer to Production DB for historical perf data . $ i( SIZE SPF INTERVAL Opn/Sqz DATE 4-1/2"x 5-3/4"LITE SLIP-ON -I 11546' I 4' N SWELL PKR, ID=3.958" 3-1/2"SLD LNR,9.2#,L-80 IBT-M, ID=2.992" H 12259' �� ■ 3-1/2"SLTD LNR,9.2#, L-80 IBT-M, ID=2.992" H 12838' 3-1/2"HES FLOAT SHOE H 12870' I DATE REV BY COMMENTS DATE REV BY COMMENTS AURORA UNIT 11/20/10 N7ES ORIGINAL COMPLETION WELL: S-129 11/25/10 CD DRLG HO CORRECTIONS PERMIT No:r2101320 12/14/10 ?/JMD DRLG DRAFT CORRECTIONS API No: 50-029-23433-00-00 SEC 35.T12. R12E,3644'NSL&4103'FEL BP Exploration(Alaska) • North America -ALASKA- BP Page 1 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type:DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 10/24/2010 00:00 - 01:30 1.50 MOB P PRE MOVE CAMP TO S-129 AND SPOT 01:30 - 02:00 0.50 MOB P PRE PJSM,PULL PITS OFF SUB AND STAGE 02:00 - 05:00 3.00 MOB P PRE PJSM,MOVE SUB FROM S-41A TO S-129, STAGE SUB. 05:00 - 07:00 2.00 MOB P PRE MOVE PITS TO S-129 AND STAGE. PJSM, INSPECT DERRICK AND RAISE DERRICK 07:00 - 08:30 1.50 MOB P PRE PJSM,HANG SURFACE RISER AND TREE IN CELLAR. PREP 5-129 TO RECEIVE RIG. PLACE WELLHEAD EQUIPMENT IN CELLAR 08:30 - 10:30 2.00 MOB P PRE SPOT SUB OVER S-129,SPOT PITS 10:30 - 11:30 1.00 MOB P PRE SPOT CUTTINGS BOX,CONNECT PITS SERVICE LINES,BERM CELLER AND FLOW LINE,RU RIG FLOOR 11:30 - 14:00 2.50 MOB P PRE PJSM, BRIDLE DOWN, HANG BRIDLE LINES AND RU FLOOR. PREP PITS AND INTERCONNECT,SET BERMS 14:00 - 16:30 2.50 MOB P PRE NU RISER AND ANNULUS VALVES,TAKE ON MUD 16:30 - 17:30 1.00 MOB P PRE PJSM,S-129 PRE SPUD MEETING. 17:30 - 20:00 2.50 RIGU P PRE NU DIVERTER AND R SER. RIG ACCEPTED AT 18:00 HRS ON 10- 4-2010 • 20:00 - 21:00 1.00 RIGU P PRE PREP TO MU DP STA DS,FUNCTION TEST fIVFRTFR AOGCC EP CHUCK SCHIEVE 01.J' WAIVED WITNESS T THE TEST. TEST WITNESSED BY WSL RYAN CIOLKOSZ AND BRETT ANDERSON A D TOOLPUSHER BIFF PERRY 21:00 - 00:00 3.00 RIGU P PRE PU 66 4"DP SINGLES AND STAND BACK IN DERRICK 10/25/2010 00:00 - 01:30 1.50 RIGU P PRE CONTINUETO PU 15 TS OF DRILL PIPE AND 15 JTS OF HWDP AN STAND BACK IN DERRICK 01:30 - 03:00 1.50 RIGU P PRE RU TO RUN 12.25"SURFACE BHA. EXPEDITE STABILIZERS AND BIT TO RIG FLOOR. LOAD PIPE SHED 03:00 - 05:00 2.00 RIGU P PRE PU BHA#1 12.25"SURFACE BHA, HUGHES 12.25"MXL-1X BIT AND MUD MOTOR. PERFORM DIVERTER DRILL 05:00 - 06:30 1.50 BOPSUR P PRE RIH WITH BHA AND PRESSURE TEST LINES TO 3500 PSI AND CHECK FOR LEAKS. FIX • _ LEAKING AIR BOOT. 06:30 - 07:00 0.50 DRILL P SURF SPUD WELL AND DRILL AHEAD FROM 108'TO 145'MD -10KWOB -300 GPM,210 PSI -40K RTW -30 RPM POOH TO 56'MD 07:00 - 10:30 3.50 DRILL P SURF PU GWD,MWD AND STABILIZER FROM 120' TO 145'MD Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 2 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 10:30 - 12:00 1.50 DRILL P SURF DRILL AHEAD ROTATING FROM 145'TO 210' MD. -450 GPM,410 PSI -10K WOB -30 RPM,1K TORQUE _ -48K RTW 12:00 - 14:00 2.00 DRILL P SURF SLIDE DRILL FROM 210'TO 329'MD. PROBLEMS WITH GETTING GOOD TOOLFACE FROM GWD. TAKING 2-3 ATTEMPTS TO GET GOOD SURVEY FROM GWD -450 GPM,410 PSI -10K WOB -48K PUW,48K SOW 14:00 - 15:00 1.00 DRILL P SURF POOH FROM 329'TO 118'MD 15:00 - 16:30 1.50 DRILL P SURF PU BHA FROM 118'TO 310'MD AND RIH TO 329'MD 16:30 - 00:00 7.50 DRILL P SURF DRILL AHEAD FROM 329'TO 758'MD. TAKING 2-3 ATTEMPTS TO GET GOOD SURVEY FROM GWD -550 GPM,1000 PSI -10K WOB -40 RPM,2.5K TQ ON,1K TQ OFF 73K PUW,70K SOW,70K RTW 10/26/2010 00:00 - 04:00 4.00 DRILL P SURF DRILL AHEAD FROM '58'TO 1285'MD. TAKING 2-3 ATTEMPTS TO GET GOOD SURVEY FROM GWD -550 GPM,1000 PSI -10K WOB -40 RPM,2.5K TQ ON,1K TQ OFF -73K PUW,70K SOW,70K RTW 04:00 - 05:00 1.00 DRILL N RREP 1,282.96 SURF LOST SWAB ON PUMP. CHANGE OUT LINERS AND SWABS ON PUMP#1 05:00 - 12:00 7.00 DRILL P SURF DRILL AHEAD IN 12.25"SURFACE HOLE FROM 758'TO 2090'MD. -600 GPM,1675 PSI ON,1570 PSI OFF -10-20K WOB -60 RPM,2.5K TQ ON,1.5K TQ OFF -93K PUW,85K SOW,87K RTW 12:00 - 00:00 12.00 DRILL P SURF DRILL AHEAD IN 12.25"SURFACE HOLE FROM 2090'TO 3107'MD. -600 GPM,1856 PSI ON,1800 PSI OFF -10-20K WOB -60 RPM,4K TO ON,3K TQ OFF -110K PUW,85K SOW,94K RTW 10/27/2010 00:00 - 02:00 2.00 DRILL P SURF DRILL AHEAD IN 12.25"SURFACE HOLE FROM I'D 3107'TO TD AT 3305'MD_ , °� -600 GPM,2005 PSI ON,1895 PSI OFF -10-20K WOB -60 RPM,5K TQ ON,3.5K TQ OFF -112K PUW,90K SOW,98K RTW 02:00 - 03:30 1.50 DRILL P SURF CBU 3X AT 600 GPM AND 1856 PSI 03:30 - 05:00 1.50 DRILL P SURF SHUT DOWN AND MONITOR HOLE,STATIC. POOH ON ELEVATORS FROM 3305'TO BASE PERMAFROST AT 1926'MD. WIPE TIGHT SPOT FROM 2790'TOi2720'MD 05:00 - 06:00 1.00 DRILL P SURF MONITOR WELL,STATIC. RIH FROM 1926'MD TO 3305'MD. WORK TIGHT HOLE FROM 2850' TO 2870'MD AND 3000'TO 3008'MD. NO FILL ON BOTTOM Printed 12/20/2010 5:03:04PM • North America -ALASKA- BP Page 3 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site:PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 06:00 - 07:00 1.00 DRILL P SURF CBU 1X AT 660 GPM AND 2195'MD -80 RPM,4K TQ -95K RTW 07:00 - 08:30 1.50 DRILL P SURF MONITOR WELL,STATIC. POOH FROM 3305' TO 758'MD. WORK TIGHT HOLE FROM 1670' TO 1620'MD. NOTIFIED STATE OF UPCOMING BOPE TEST AT 08:00 08:30 - 12:30 4.00 DRILL P SURF PJSM, LD BHA#1. RAK BACK 6 STANDS OF HWDP. MXL-1X BIT GRADED: 2-3-WT-A-E-2-SS-TD 12:30 - 15:00 2.50 CASING P SURF RU TO RIH WITH 9-5/8"40#BTC CASING. DUMMY RUN ON CASING HANGER 15:00 - 18:00 3.00 CASING N SFAL SURF AIR BOOT ON RISER LEAKING. CHANGE OUT AIR BOOT. 18:00 - 00:00 6.00 CASING P SURF RIH WITH 9-5/8"40#BTC CASING TO 1445' MD. FILL PIPE EVERY JOINT. WASH DOWN EVERY 10TH JOINT. -95K PUW,65K SOW UPDATED STATE REPRESENTIVE BOB NOBLE OF UPCOMING BOPE TEST AT 19:00 ON 10/27/2010 10/28/2010 00:00 - 03:30 3.50 CASING P SURF : . - •- :" I : : ► :•M 1445' MD TO 3295'MD.FILL PIPE EVERY JOINT. WASH DOWN EVERY 10TH JOINT. CBU 1X AT BASE OF PERMAFROST AT 1926'MD. -95K PUW,65K SOW 03:30 - 04:30 1.00 CASING P SURF PU 9-5/8"MANDREL HANGER AND LANDING JOINT.RD 350 TON SLIPS. LAND HANGER ON LANDING RING. RD FRANK'S TOOL. RU CEMENT HEAD. 04:30 - 07:00 2.50 CEMT P SURF BREAK CIRCULATE AND STAGE PUMPS UP TO 5 BPM AND 350 PSI. RECIPROCATE PIPE IN 10'STROKES. CONDITION MUD FOR CEMENT JOB. 150K PUW,125K SOW. RECIPROCATE PIPE IN 10FT STOKES -2 BPM,285 PSI -3 BPM,303 PSI -4 BPM,342 PSI -5 BPM,350 PSI Printed 12/20/2010 5:03:04PM ` North America _Operation Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10o4/2010 End Date: x3-00VNH-C(5.893.419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Date From To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 07o0 10:30 3.50 CEMT • P SURF PJGm.WITH 8LsCEMEwTsR8. nusLa v CEMENT LINES. ^� PUMP ` MUD PUSH. SHUT DOWN AND PRESSURE TEST TO 3500 PSI. PUMP 95 BBLS OF MUD PUSH AHEAD AT 5 BPM AND 225 PSI. SHUT DOWN AND DROP BOTTOM PLUG. PUMP 500 nn/m1r,nyxn(vsxm/rnyAcpOOF1o.r PPG ARCTIC SET I ITF I FAD AT 6 BPM AND 220 PSI.RECIPROCATE PIPE IN lOFT STOKES PSI,156 BBLS LEAD AWAY,MUD PUSH OE 'o BPM,225 PSI,244 BBLS LEAD AWAY, BOTTOM PLUG LATCHED AT 900 PSI STOP RECIPROCATING PIPE AND LAND ON LANDING RING ( 6 BPM,400 PSI,338 BBLS LEAD AWAY •~�` ``� SPACER AT SHAKERS 'sBPM.424 PSI,41S8oLS LEAD AWAY, CEMENT SPACER TERFACE TO SURFACE -SLOW TO 2.8 BPM,288 PSI,500 BBLS LEAD AWAY SWAP ON THE FLY AND PUMP 87 BBLS/447 SACKS OF1suo/ASS ocFMFwT(1 16 CUFT/SACK)AT 6 BPM AND 440 PSI 3 BPM,320 PSI,74 BBLS TAIL AWAY,GOOD "/ CEMENT BACK TO SURFACE DROP TOP PLUG AND BEGIN DISPLACEMENT xTrsPm AND zs5PSI -ooPM.114o PSI,zoVsouSDISPLACED SLOW TOaBPM FOR BUMP 1028 PSI,223 BBLS DISPLACED BUMP PLUG AT 234 BBLS DISPLACED AND 1830 PSI. BLEED OFF PRESSURE AND ` } CHECK FLOATS TOTAL OF 365 BBLS CEMENT BACK TO SURFACE. PRESSURE UP TO 3500 PSI FOR 5 MIN TO TEST CASING. 10o0 12:00 1a0 CEMT P SURF no CASING AND CEMENT EQUIPMENT. FLUSH FLOW LINE AND RISER. FUNCTION AND CLEAN HYDRIL CLEAN CELLAR BOX. 12:00 15o0 3.00 BOPSUR P SURF woo|vERTEn AND Lo CASING EQUIPMENT 15:00 - 17:30 2.50 WHSUR P SURF wuoswo CASING AND TUBING HEAD. TEST SEALS TO 1100 PSI FOR 30 MIN. 17:30 - 00:00 0.50 BOPSUR P SURF wUoOpE.CHANGE OUT MANUAL VALVE, LOAD AND STRAP 198 JTS OF 4''oP|mSHED, CHANGE FRO "LINERS TOo^L|wEnS. CHANGE BALES.CHPNGE OUT TOP RAM SLIDE KOOMY HOSE! 10/29/2010 00:00 01:30 1.50 BOPSUR P SURF CONTINUE TOwUo0PE. REPLACE AIR BOOT, INSTALL RISER,TAKE RKB MEASUREMENTS, INSTALL DOUBLE ANNULUS VALVE 01:30 02:30 1.00 BOPSUR P SURF GREASE HCR'S AND MANUAL VALVES. RU TO TEST BOPE Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 5 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 02:30 - 06:00 3.50 BOPSUR P SURF TEST BOPE AND CHOKE MANIFOLD TO 3500 PSI HIGH AND 250 PSI LOW WITH 4"TEST n JOINT. TEST ANNULUR PREVENTER TO 25001_ PSI HIGH AND 250 PSI LOW WITH 4"TEST JOINT. TEST ACCUMULATOR UNIT. AOGCC REP LOW GRIMALDI WAIVED WITNESS TO TEST AT 17:00 HRS ON 10/28/2010. TEST WITNESSED BY NAD TOOLPUSHER LENWARD TOUSSANT AND BP REP'S RYAN CIOLKOSZ AND MITCH SKINNER 06:00 - 07:00 1.00 BOPSUR P SURF RD,BLOW DOWN TEST EQUIPMENT. INSTALL WEAR RING 07:00 - 10:00 3.00 CEMT P SURF PJSM,MU MULE SHOE AND PU DP TO 3102' MD. KICK WHILE TRIPPING DRILL-D1 10:00 - 11:30 1.50 CEMT N FLUD 3,101.99 SURF POOH WITH FIRST STAND. PULLING WET. CIRCULATE DP VOLUME. STILL OUT OF BALANCE. CIRCULATE SURFACE TO SURFACE VOLUME. THICK,CLABBERED UP MUD RETURNS. BUILD AND PUMP DRY JOB. 11:30 - 12:30 1.00 CEMT P SURF POOH FROM 3102'TO 1411'MD 12:30 - 13:30 1.00 CEMT P SURF PJSM, PU DRILL PIPE TO 755'MD 13:30 - 14:00 0.50 CEMT P SURF POOH AND RACK BACK STANDS FROM 755' MD 14:00 - 15:00 1.00 CEMT P SURF PJSM,PRESSURE TEST 9-5/8"CASING TO 3500 PSI FOR 30 MIN. LOST 0 PSI IN 30 MIN 15:00 - 17:30 2.50 CEMT P SURF PJSM, PU BHA#2:8-3/4"DTX619M-D2 DRILL BIT,1.5 DEG MOTOR,ARC6,POWERPULSE AND ADN4 TO 735'MD 17:30 - 18:30 1.00 CEMT N DFAL 735.00 SURF SHALLOW HOLE TEST MWD AT 350 GPM AND 610 PSI. TROUBLE GETTING SIGNAL. 18:30 - 21:00 2.50 CEMT P SURF PU DRILL PIPE TO 1205'MD. SHALLOW HOLE TEST MWD AT 350 GPM AND 780 PSI. GOOD TEST. CONTINUE TO PU DRILL PIPE TO 3178' MD. -108K PUW,80KSOW\ KICK WHILE TRIPPING DRILL-D1 21:00 - 22:00 1.00 CEMT P SURF WASH DOWN AND TAG STRINGERS AT 3195' MD. TAG FLOAT COLLAR AT 3209'MD. DRILL FLOAT COLLAR AND CEMENT TO 3284'MD -450 GPM,1590 PSI -40 RPM,4K TQ -108K PUW,80K SOW,95K RTW 22:00 - 22:30 0.50 CEMT P SURF CIRCULATE 58 BBLS AT 450 GPM AND 1475 PSI. MONITOR WELL FOR 10 MIN,STATIC 22:30 - 23:00 0.50 CEMT P SURF PUMP 20 BBLS HIGH VIS SPACER AND FOLLOW WITH 50 BBLS OF 8.8 PPG LSND MUD.SHUT DOWN AND MONITOR WELL. STATIC. CONTINUE TO DISPLACE WELL TO 8.8 PPG LSND MUD AT 450 GPM AND 1050 PSI. ROTATE AT 40 RPM AND RECIPROCATE PIPE.THICK, CLABBERED UP MUD RETURNS AT BEGINNING OF DISPLACEMENT. SHUT DOWN AND MONITOR WELL,STATIC SLOW PUMP RATES TAKEN Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 6 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 23:00 - 00:00 1.00 CEMT P SURF CONTINUE TO DRILL OUT CEMENT AND SHOE TO 3295'MD -460 GPM,1025 PSI -40 RPM,3.5K TQ -15K WOB -108K PUW,85K SOW,95K RTW DRILL OUT 10'OF RAT HOLE AND 21'OF NEW HOLE TO 3326'MD 10/30/2010 00:00 - 01:00 1.00 CEMT P SURF RACK BACK STAND. RU AND PREFORM LOT. 1-6'r 8.8 PPG MW IN AND OUT. PREFORM LOT TO 525 PSI AT 3295'MD/3192'TVD. 11 96 PPG EMW 01:00 - 02:00 1.00 DRILL N WAIT INT1 CONSULT WITH TOWN ON PLAN FORWARD 02:00 - 02:30 0.50 DRILL P INT1 RD AND BLOW DOWN TEST EQUIPMENT 02:30 - 12:00 9.50 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 3326'TO 4875'MD. BUILD FROM 35 TO 46 DEG INC AND TURN FROM 251 TO 247 DEG AZM -570 PSI,2210 PSI ON,1950 PSI OFF -10-20K WOB -80 RPM,5.5K TQ ON,4.5k TQ OFF -120K PUW,95K SOW,105K RTW -9.31 PPG CALC ECD,10.18 PPG ACTUAL ECD KICK WHILST DRILLING DRILL-D2 12:00 - 00:00 12.00 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 4875'TO 6662'MD. BUILD FROM 46 TO 51 DEG INC AND HOLD AT 247 DEG AZM -570 PSI,3020 PSI ON,2730 PSI OFF -10-20K WOB -80 RPM,8K TQ ON,6.5k TQ OFF -142K PUW,105K SOW,115K RTW -9.63 PPG CALC ECD,10.21 PPG ACTUAL ECD SPILL DRILL 10/31/2010 00:00 - 12:00 12.00 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 6662'TO 8030'MD. -570 gpm,3410 PSI ON,3190 PSI OFF -10-20K WOB -80 RPM,8K TQ ON,6.5k TQ OFF -157K PUW,115K SOW,127K RTW -9.72 PPG CALC ECD,10.35 PPG ACTUAL ECD SLOW PUMP RATES TAKEN UNANNOUNCED KICK WHILST DRILLING DRILL-D2 FIRE DRILL 12:00 - 15:30 3.50 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 8030'TO 8354'MD. -570 gpm,3400 PSI ON,3205 PSI OFF -10-15K WOB -80 RPM,9.5K TQ ON,8.5k TQ OFF -157K PUW,115K SOW,127K RTW -9.72 PPG CALC ECD,10.27 PPG ACTUAL ECD KICK WHILST DRILLING DRILL-D2 Printed 12/20/2010 5:03:04PM North America —ALASKA- BP Page 7 of 22. Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 15:30 - 17:00 1.50 DRILL P INT1 CBU 1X AT 570 GPM AND 3200 PSI WHILE ROTATING 80 RPM. 8K TQ. MONITOR WELL, STATIC. 17:00 - 18:30 1.50 DRILL P INT1 DISPLACE WELL WTIH SPIKE FLUID TO 10.3 PPG LSND MUD. MONITOR WELL,STATIC. INCREASE MW TO 10.5 PPG WITH ADDITIONS OF BARITE ON RIG. SLOW PUMP RATES TAKEN 18:30 - 00:00 5.50 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 8354'TO 8752'MD. -570 PSI,3820 PSI ON,3560 PSI OFF -10-15K WOB -80 RPM,7K TQ ON,5.5k TQ OFF -160K PUW,115K SOW,130K RTW -10.97 PPG CALC ECD,11.56 PPG ACTUAL ECD 11/1/2010 00:00 - 02:00 2.00 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 8752'TO 8960'MD. -570 GPM,3820 PSI ON,3560 PSI OFF -10-15K WOB -80 RPM,7K TO ON,5.5k TQ OFF -160K PUW,115K SOW,130K RTW ---10.97 PPG CALC ECD,11.38 PPG ACTUAL ECD KICK WHILE DRILLING DRILL-D2 02:00 - 04:00 2.00 DRILL P INT1 NOTICED INCREASE IN FLOW AND GAS CUT MUD TO SURFACE. SHUT DOWN AND FLOW CHECKED WELL. NOT FLOWING,GAS BREAKING OUT. DRILL REST OF STAND DOWN TO 9012'MD. SHUT DOWN AND CHECKED WELL. WELL NOT FLOWING,GAS BREAKING OUT OF MUD. MW 10.5 PPG GOING IN,GAS CUT TO 9.2 PPG AT SHAKERS. DRILLED NEXT STAND DOWN TO 9104'MD WHILE CBU 1X. SHUT DOWN AND FLOW CHECKED WELL. WELL NOT FLOWING, NO GAS BREAKING OUT. 04:00 - 08:00 4.00 DRILL P INT1 DRILL AHEAD IN 8-3/4"INTERMEDIATE HOLE FROM 8960'TO TD AT 9445'MD. -500 GPM,3590 PSI ON,3420 PSI OFF -10-15K WOB -80 RPM,7K TQ ON,6k TQ OFF -165K PUW,120K SOW,135K RTW -11.00 PPG CALCULATED ECD,11.58 PPG ACTUAL ECD 08:00 - 10:30 2.50 DRILL P INT1 CIRCULATE 3X BOTTOMS UP. 550 GPM AND 3825 PSI. ROTATE AT 100 RPM AND 5K TQ. -135K RTW Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 8 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 10:30 - 14:00 3.50 DRILL P INT1 MONITOR WELL.STATIC. 10.5 PPG MW IN AND OUT POOH FROM 9201'TO 8000'MD. 135K PUW,100K SOW. 35K OVERPULL AT 8650'MD,8435'MD,8315-8270'MD. OVER PULL AND SWABBING AT:8190',8170',8077', 8042',8002'MD. CONTINUE TO POOH FROM 8000'MD. OVER PULLING AND SWAB FROM 7920'-7906',7820-7720'MD,7323'-7285, 7164',7074'-7040',6854'-6735',5683'MD. WORK TIGHT AREAS. 45K OVERPULL AT 6535'. BACK BACK REAM FROM 6535'TO 6340'MD -350 GPM,1720 PSI -60 RPM,5K TQ -160K PUW,95K SOW,115K RTW FIRE DRILL 14:00 - 15:30 1.50 DRILL P INT1 MAD PASS HOLE FROM 6420'TO 6340'MD AND FROM 6160'TO 6060'MD AT 225'FPH -500 GPM,2700 PSI -80 RPM,5K TQ 15:30 - 16:30 1.00 DRILL P INT1 CBU 1X AT 500 GPM AND 2520 PSI. ROTATE AT 80 RPM AND 5K TQ. MONITOR WELL, STATIC. 16:30 - 18:00 1.50 DRILL P INT1 RIH FROM 6060'TO 9445'MD. WASH TO BOTTOM,NO FILL 18:00 - 21:00 3.00 DRILL P INT1 PUMP 35 BBLS HI VIS SWEEP. INCREASE IN SOFTBALL SIZE TO GOLF BALL SIZE CLAY BALLS AT BOTTOMS UP STROKES. PUMP ANOTHER SWEEP AND CONTINUE TO CIRCULATE ANOTHER 2X BU AT 500 GPM AND 3665 PSI. NO SIGNIFICANT INCREASE IN CUTTINGS FROM SECOND SWEEP. ROTATING 80 RPM,8-9K TQ. MONITOR WELL, STATIC. 10.5 PPG IN AND OUT. 21:00 - 00:00 3.00 DRILL P INT1 POOH FROM 9445'TO 7602'MD. -175K PUW,120K SOW MONITOR WELL,STATIC. 10.5 PPG MW IN AND OUT PUMP DRY JOB. POOH FROM 7602'TO 4688' MD 11/2/2010 00:00 - 01:00 1.00 DRILL P INT1 POOH FROM 4688'TO SHOE AT 3295'MD ON ELEVATORS. -105K PUW,95K SOW KICK WHILE TRIPPING(D1)DRILL. 01:00 - 01:30 0.50 DRILL P INT1 CBU 1X AT 570 GPM AND 2570 PSI. ROTATE AT 40 RPM WITH 2.5K TQ. 90K RTW -MONITOR WELL;WELL STATIC. -MW IN AND OUT 10.5 PPG. 01:30 - 02:30 1.00 DRILL P INT1 PJSM,SLIP AND CUT 133'OF DRILLING LINE 02:30 - 03:30 1.00 DRILL P INT1 SERVICE TOP DRIVE, BLOCKS AND CROWN. INSPECT BRAKES AND DRAWWORKS. ADJUST BRAKES 03:30 - 04:00 0.50 DRILL P INT1 POH FROM 3295'TO BHA AT 768'MD. -MONITOR WELL;WELL STATIC. Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 9 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft 04:00 - 07:30 3.50 DRILL P INT1 LD 8-3/4"BHA#2. -PJSM FOR REMOVING RA SOURCES FROM BHA. -BIT GRADE: 1-1-CT-G-X-I-WT-TD. -CLEAN AND CLEAR RIG FLOOR. 07:30 - 09:30 2.00 CASING P INT1 CHANGE OUT TOP RAMS TO 7"FIXED. -PJSM. -PULL WEAR RING. -INSTALL TEST PLUG. -RU TEST EQUIPMENT. -TEST RAMS TO 250 PSI LOW AND 3,500 PSI HIGH--TEST GOOD. -RD/BD TEST EQUIPMENT. 09:30 - 12:30 3.00 CASING P INT1 RU TO RUN 7"CASING. -MAKE DUMMY RUN WITH MANDREL HANGER AND LANDING JOINT. -RU TO RIH WITH 7"CASING WITH FRANKS FILL-UP TOOL AND 350-TON SLIPS. 12:30 - 18:00 5.50 CASING P INT1 RIH WITH 7",26#, BTC-M CASING TO 3,287'. -PJSM WITH ALL HANDS INVOLVED. -MU/RIH AND BAKER-LOK SHOE TRACT. -CHECK FLOATS;CHECKED GOOD. -FILL ON THE FLY(TOP OFF EVERY 10)AND BREAK CIRCULATION EVERY 20 JTS. -PU WT 115K,SO WT 105K. -MU TQ 8,600 FT-LBS. 18:00 - 19:00 1.00 CASING P INT1 CIRCULATE 1.5 LINER VOLUMES AT THE 9-5/8"SHOE. -189 BBLS. -STAGE PUMPS TO 5 BPM,400 PSI. -MONITOR WELL;WELL STATIC. -MW IN AND OUT 10.5 PPG. 19:00 - 00:00 5.00 CASING P INT1 RIH WITH 7",26#CASING FROM 3,287'TO 6,562'. -RIH WITH 7",26#, BTC-M CASING FROM 3,287'TO4,062'. -MU/RIH WITH XO JT TO 4,101'. -RIH WITH 7",26#,VAM-TOP HC CASING FROM 4,101'TO6,562'. -TORQUE TURN WITH OPTIMUM MU TQ= 11,950 FT-LBS. -PU WT 190K,SO WT 115K. -MW IN AND OUT 10.5 PPG. 11/3/2010 00:00 - 02:30 2.50 CASING P INT1 -RIH WITH 7",26#,VAM-TOP HC CASING FROM 6,562'TO 8,450'. -TORQUE TURN WITH OPTIMUM MU TQ= 11,950 FT-LBS. -PU WT 240K,SO WT 145K. -MW IN AND OUT 10.5 PPG. 02:30 - 03:30 1.00 CASING P INT1 CBU ABOVE HRZ. -STAGE UP TO 6 BPM,900 PSI. -HOLE RELATIVELY CLEAN; NO EXCESSIVE UNLOADING NOTED. 03:30 - 05:30 2.00 CEMT P INT1 RIH WITH 7",26#,VAM-TOP HC CASING FROM 8,450'TO 9,435'. -MU LANDING JT WITH MANDREL HANGER AND RIH. -MU CEMENT HEAD. -PU WT 275K,SO WT 130K. Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 10 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 05:30 - 08:30 3.00 CEMT P INT1 CIRCULATE AND CONDITION HOLE IN PREPARATION FOR CEMENT JOB. -STAGE UP IN 1/2-BBL INCREMENTS TO 6 BPM. -ICP 905 PSI, FCP 780 PSI. RECIPROCATE PIPE IN 10-FT STROKES. -PU WT 240K,SO WT 135K. 08:30 - 11:00 2.50 CEMT P INT1 7"CASING CEMENT JOB. -PUMPED 30 BBLS 10.8 PPG MUD PUSH II AT 6 BPM. -PRESSURE TESTED SURFACE LINES TO 3,500 PSI;TEST GOOD. -DROP BOTTOM PLUG. -PUMPED 144 BBLS 11.0 PPG LITE CRETE CEMENT AT 6 BPM. -454 SKS.1 83 CU FT/SK YIELD. -PUMPED 39 BBLS 15.8 PPG CLASS G CEMENT AT 6 BPM. -223 SKS,1.16 CU FT/SK YIELD. -DROP TOP PLUG. -DISPLACED WITH 5 BBLS OF 8.3 PPG CLEAN-UP WATER FROM SLB TRUCK AND 350 BBLS OF 10.3 PPG BRINE FROM RIG. -BUMPED PLUGS;PRESSURED UP TO 500 PSI OVER FCP TO 1,900 PSI. -BLED OFF AND CHECKED FLOATS;FLOATS HELD. -CEMENT IN PLACE AT 1039 HRS. 11:00 - 12:00 1.00 CEMT P INT1 RD CASING AND CEMENTING EQUIPMENT. 12:00 - 13:00 1.00 CEMT P INT1 MONITOR WELL. -1 q.3 PPG BRINE STARTED TO RUN OVER 7" LANDING JOINT:SUSPECT THERMAL- EXPANSION. -NO FLOW NOTED IN OUTER ANNULUS DURING WELL MONITORING. -STAB TIW VALVE;PRESSURE BUILT TO 35 PSI OVER 8 MINUTES; BLED OFF TO ZERO PSI WITHIN 30 SECONDS. -SHUT TIW VALVE AND PRESSURE BUILT BACK TO 35 PSI. -WAITED UNTIL CEMENT REACHED PUMPING THICKENING TIME(70 BC)AND OPENED TIW VALVE;BLED OFF--NO FLOW OUT OF 7"LANDING JOINT. 13:00 - 15:00 2.00 CEMT P INT1 RD REMAINING CASING EQUIPMENT AND LD LANDING JOINT. -PJSM. -CHANGE OUT BAILS. 15:00 - 16:30 1.50 CEMT P INT1 MU PACK-OFF RUNNING TOOL AND PACK-OFF. -RIH AND SET IN WELLHEAD. -RI LDS AND TQ TO 450 FT-LBS. -TEST PACK-OFF TO 250 PSI LOW FOR 5 MINUTES AND 5,000 PSI HIGH FOR 30 MINUTES;TESTS GOOD. 16:30 - 17:30 1.00 CEMT P INT1 INJECT 5 BBLS 11.3 PPG MUD DOWN OA. -BREAKDOWN AT 1,000 PSI AT 1.5 BPM. 17:30 - 19:00 1.50 BOPSUR P INT1 CHANGE OUT 7"FIXED RAMS FOR 3-1/2"X 6" VBRS. -PJSM. Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 11 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 19:00 - 20:00 1.00 BOPSUR P INT1 PRESSURE TEST 3-1/2"X 6"VBRS. ae -PJSM. rJ -RU TEST EQUIPMENT. -TEST TO 250 PSI LOW AND 3,500 PSIMIGH WITH 4"TEST JOINT;TESTS GOOD. -RD/BD LINES. -SET WEAR RING. 20:00 - 20:30 0.50 CEMT P INT1 INJECT 10 BBLS AT 1 BPM DOWN OA. -BREAKDOWN AT 1,400 PSI AND INJECTED AT 900 PSI. 20:30 - 21:00 0.50 CEMT P INT1 PRESSURE TEST 7"CASING TO 3.500 PSI ,. FOR 30 MINUTES. -LOST 50 PSI IN FIRST 15 MINUTES AND 10 PSI IN LAST 15 MINUTES;TEST GOOD. 21:00 - 22:30 1.50 STWHIP P INT1 PU WHIPSTOCK BHA DRILL COLLAR STANDS (3)AND RACK BACK IN DERRICK. 22:30 - 00:00 1.50 STWHIP P INT1 PU WHIPSTOCK BHA TO 90'. -RACK BACK IN DERRICK. -ORIENT TO 65 DEGREE LEFT OF MWD HIGH SIDE. -SIMULTANEOUSLY INJECT 122 BBLS OF 11.3 PPG MUD DOWN OA PRIOR TO FRFF7F PROTECTING OA; FCP=2 BPM,575 PSI. 11/4/2010 00:00 - 00:30 0.50 STWHIP P INT1 CONTINUE MU WHIPSTOCK BHA MILLING SECTION AND STAND BACK IN DERRICK. 00:30 - 03:00 2.50 STWHIP P INT1 RU 4-1/2"CASING EQUIPMENT AND MU/BAKERLOK BULLNOSE AND RIH WITH 11 JTS OF 4-1/2"IBT TO 457'. -MU WHIPSTOCK SLIDE TO 4-1/2"TUBING. -OFF THE CRITICAL PATH,FREEZE PROTECT OA WITH 68 BBLS 80 DEGREE F DEAD CRUDE. 03:00 - 04:30 1.50 STWHIP N HMAN 457.00 INT1 ATTEMPT TO MU MILL SECTION TO WHIPSTOCK SLIDE AND TUBING STRING. -3-1/2"HWDP JOINT BENT DURING ELEVATOR-LATCHING OPERATION. -SWAPPED OUT BENT 3-1/2"HWDP JT. 04:30 - 06:00 1.50 STWHIP P INT1 MU WHIPSTOCK BHA AND MILL SECTION TO WHIPSTOCK SLIDE AND TUBING STRING. -ORIENT TO 37 DEGREES LEFT OF MWD HIGH SIDE. -SHALLOW-HOLE TEST MWD TOOLS AT 250 GPM,790 PSI;TEST GOOD. -RIH TO 2,000'. 06:00 - 10:30 4.50 STWHIP P INT1 RIH WITH WHIPSTOCK/MILLING BHA FROM 2 000'TO 9 281' . vi1■A -TAG UP ON CEMENT PLUGS ON DEPTH AT 9,352'. -SET DOWN 15K AND SHEAR ANCHOR; PU 5K TO CONFIRM SET. -SET DOWN 50K AND SHEAR BOLT HOLDING SLIDE. -PU WT 183K,SO WT 100K;PU WT WITHOUT SLIDE=175K. 10:30 - 13:00 2.50 STWHIP P INT1 DISPLACE WELL FROM 10.3 PPG BRINE TO 10.3 PPG MILLING FLUID. -250 GPM,1,610 PSI. -MONITOR WELL;WELL STATIC. Printed 12/20/2010 5:03:04PM North America-ALASKA'- BP g Page 12 of 22 4 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/28 2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Descriptio of Operations (hr) (ft) 13:00 - 22:30 9.50 STWHIP P INT1 MI L WINDOW IN 7" _ ► ►11'I- NEW FORMATION FROM 8,875'TO 8,910'. -TOW=8,875',BOW m 8,888'. -DRILL AHEAD IN NEW FORMATION TO 8,910'. -290 GPM,1,970 PSI. -100 RPM. 9-10K TQ. -5-10K WOM. PU WT 185K,SO WT 105K,ROT WT 125K. FAIR AMOUNT OF CEMENT SEEN AT SHAKERS. -122#OF METAL SHAVINGS RECOVERED. 22:30 - 23:30 1.00 STWHIP P INT1` CIRCULATE HI-VIS SUPER SWEEP SURFACE TO SURFACE. -290 GPM,2,415 PSI. -WORK WINDOW MILL ACROSS SLIDE WITH AND WITHOUT ROTATION AND WITH AND WITHOUT PUMPS;WINDOW APPEARS TO BE IN GOOD SHAPE; NO HANG-UPS NOTED. 23:30 - 00:00 0.50 DRILL P INT1 FORMATION INTEGRITY TEST(FIT)AT 7" WINDOW. RU TEST EQUIPMENT. { -PUMP 10 STROKES,.6 BBLS;SURFACE 1 PRESSURE=650 PSI. -19 1 PPP.FMW -RD/BD TEST EQUIPMENT. 11/5/2010 00:00 - 01:00 1.00 DRILL P PROD1 CBU X 1.5. -310 BBLS,290 GPM,2,440 PSI. -PU WT 170K,SO WT 105K. -MW 10.3 PPG IN AND OUT. -MONITOR WELL FOR 15 MINUTES BEFORE POH WITH BHA;WELL STATIC. 01:00 - 04:00 3.00 DRILL P PROD1 POH WITH WHIPSTOCK/MILLING BHA FROM 8,910'TO 815'. -PUMP DRY JOB PRIOR TO POH. KICK WHILE TRIPPING DRILL(D1). 04:00 - 07:00 3.00 DRILL P PROD1 LD WHIPSTOCK/MILLING BHA FROM 815'TO SURFACE. -MONITOR WELL;W LL STATIC. -HOLD PJSM. -LD 5 STANDS OF 4" WDP AND 3 STANDS OF 4-3/4"DRILL COL RS. -LD MILLING BHA. -UPPER WATERMELON MILL IN GAUGE. 07:00 - 08:00 1.00 BOPSUR P PROD1 SERVICE WEAR RING -JET AND FLUSH BOP STACK -PERFORM FUNCTION TEST OF ALL BOP RAMS AND ANNULAR PREVENTER (11/05/2010) -INSTALL WEAR RING -BLOW DOWN LINES 08:00 - 08:30 0.50 DRILL P PROD1 SERVICE TOP DRIVE 1 Printed 12/20/2010 5.03.04PM North America-ALASKA- BP Page 13 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 08:30 - 09:30 1.00 DRILL P PROD1 PU/MU BHA#4 -BHA#4 CONSISTS OF 6-1/8"HUGHES EP7258 INSERT BIT JETTED 3 X 13,SHORT PAK PDM WITH 1.69 DEGREE BEND, NM IBS 6"STAB, NM PONY FLEX COLLR,SLIMPULSE MWD,2 NM FLEX DCS,XO, 15 JTS 4"DP,AND HYDRAULIC JARS. 09:30 - 12:00 2.50 DRILL P PROD1 PU 4"14#S-135 DRILL PIPE FROM PIPE SHED 1X1 -F/131'MDT/1100'MD -FLOW TEST MWD,200 GPM/1100 PSI;TEST GOOD. 12:00 - 13:30 1.50 DRILL P ■ PROD1 CONTINUE TO PU 4"DP F/2040'MD T/4391' MD AND FILL DRILL STRING EVERY 30 STANDS. 13:30 - 15:00 1.50 DRILL P PROD1 RIH FROM DERRICK F/4391'MD T/8809'MD -PUW-170K,SOW-105K -FILL EVERY 30 STANDS 15:00 - 15:30 0.50 DRILL P ® PROD1 CBU AT 250 GPM/2290 PSI -MW 10.3 PPG IN AND OUT. 15:30 - 16:30 1.00 DRILL P PROD1 CIRCULATE AND ATTEMPT TO ORIENT 37 DEG. -MWD FAILED(NO SIGNAL) -TROUBLESHOOT PRIOR TO POH. -D-2 DRILL(KICK WHILE DRILLING)30 SECONDS. 16:30 - 20:00 3.50 DRILL N DFAL 8,809.00 PROD1 POH F/8809'T/1099'MD FOR FAILED MWD TOOL. -PJSM -MONITOR WELL,WELL STATIC. -MW 10.3 PPG IN AND OUT. -PUMP DRY JOB. 20:00 - 20:30 0.50 DRILL N DFAL 8,809.00 PROD1 FLOW TEST MWD AT 1,099'MD. -FAILED WITH 300 GPM/1945 PSI -D-1 DRILL(KICK WHILE TRIPPING) 20:30 - 21:00 0.50 DRILL N DFAL 8,809.00 PROD1 CONTINUE TO POH F/1099' T/131'MD -MONITOR WELL,WELL STATIC. 21:00 - 21:30 0.50 DRILL N DFAL 8,809.00 PROD1 LID MWD TOOLS -PJSM 21:30 - 22:00 0.50 DRILL N DFAL 8,809.00 PROD1 L/D MWD TOOLS -CLEAN AND CLEAR RIG FLOOR. 22:00 - 23:30 1.50 DRILL N DFAL 8,809.00 PROD1 WAIT ON MWD PARTS(O-RING). 23:30 - 00:00 0.50 DRILL N DFAL 8,809.00 PROD1 PU BHA#5 TO 131'. -BHA#5 CONSISTS OF 6-1/8"HUGHES EP7258 INSERT BIT JETTED 3 X 13, SHORT PAK PDM WITH 1.69 DEGREE BEND, NM IBS 6"STAB, NM PONY FLEX COLLR,SLIMPULSE MWD,2 NM FLEX DCS,XO, 15 JTS 4"DP,AND HYDRAULIC JARS. 11/6/2010 00:00 - 04:30 4.50 DRILL N DFAL 8,809.00 PROD1 RIH WITH BHA#5 FROM 131'TO 8,620'. -FILL PIPE AND SHALLOW-HOLE TEST MWD EVERY 2,000';TESTS GOOD. 04:30 - 05:00 0.50 DRILL N DFAL 8,809.00 PROD1 SLIP AND CUT 72'OF DRILLING LINE. -KICK WHILE TRIPPING(D1)DRILL Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 14 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 05:00 - 06:30 1.50 DRILL N DFAL 8,809.00 PROD1 CBU AT 7"WINDOW. -250 GPM,2,290 PSI -INCREASE IN FLOW AT BOTTOMS-UP(TRIP GAS)--NO PIT GAIN. -CIRCULATE TILL CLEAR 10.3 PPG MW OUT -PUW-165K,SOW-100K. -MW 10.3 PPG IN AND OUT. 06:30 - 15:00 8.50 DRILL P PROD1 DRILL 6-1/8"OH F/8,910'T/9,290'MD -SPR 8910'MD,6761'TVD. -MP#1 AT 2 BPM/790 PSI,3 BPM/990 PSI. -MP#2AT2 BPM/750 PSI,3 BPM/990 PSI. -WOB-15K, GPM-250/2385 PSI ON,2235 PSI OFF. -TORQUE-8K ON,7K OFF BOTTOM. -PUW-165K,SOW-100K,FREE RT/WT- 115K. -MW 10.3 PPG IN AND OUT. -KICK WHILE DRILLING(D2)DRILL 15:00 - 15:30 0.50 DRILL P PROD1 CIRCULATE AT 9290'MD WITH 136 BBLS AT 250 GPM/2290 PSI,40 RPM,7.5K TORQUE. -MONITOR WELL;WELL STATIC. -MW 10.3 PPG IN AND OUT. 15:30 - 16:00 0.50 DRILL. P PROD1 POH F/9290'MD TO P/U ROTARY STEERABLE MOTOR ASSEMBLY -PUMP OUT OF HOLE F/9290'- T/8888'MD (250 GPM/2210 PSI). -POH F/8888'-T/8809'MD -POH WITH CONTINUOUS HOLE FILL,10.3 PPG MW. 16:00 - 17:00 1.00 DRILL P PROD1 CBU AT 8809'MD WITH 201 BBLS AT 250 GPM /2175 PSI. -CUTTINGS INCREASED DURING BOTTOMS UP. -MONITOR WELL;WELL STATIC. 17:00 - 19:00 2.00 DRILL P PROD1 PUMP DRY JOB -CONTINUE POH F/8809'-T/5041'MD. -HELD WEEKLY"CONTINUOUS IMPROVEMENT"MEETING 19:00 - 19:30 0.50 DRILL P PROD1 SERVICE TOP DRIVE. 19:30 - 22:00 2.50 DRILL N RREP 5,041.00 PROD1 ELECTRIC POWER FAILED TO OPERATE LINK TILT AND BACK-UP WRENCH. -TROUBLE SHOOT AND REPLACE"PLC" CARD. -CONTINUOUS HOLE FILL W/10.3 PPG MW. 22:00 - 00:00 2.00 DRILL P PROD1 CONTINUE TO POH F/8809'-T/131'MD -CONTINUOUS HOLE FILL W/10.3 PPG MW. -MONITOR WELL;WELL STATIC. -SANDED LOCATION DUE TO ICING CONDITIONS. 11/7/2010 00:00 - 00:30 0.50 DRILL P PROD1 FINISH UD BHA#5 -BIT GRADE: 1-1-WT-A-E-I-RG-BHA. 00:30 - 01:30 2.00 DRILL P PROD1 CLEAR AND CLEAN FLOOR. Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 15 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 01:30 - 02:30 1.00 DRILL P PROD1 PU BHA#6 TO 201' -BHA#6 CONSISTS OF 6-1/8"HYCALOG MSF513D-B1C PDC BIT(5X12--TFA=.552), POWER DRIVE X5 RSS MOTOR,(FLOAT)PD RECEIVER, PD FLEX, PERISCOPE, IMPULSE MWD,ADNL,2 NM FLEX DCS, PUMP-OUT SUB,XO, HYDRAULIC JARS. -TBHA=201.30' 02:30 - 06:30 4.00 DRILL P PROD1 RIH WITH BHA#6 FROM 201'TO—8,850'. -FILL PIPE AND SHALLOW-HOLE TEST MWD EVERY 2,000';TESTS GOOD. -PUW-145K,SOW-105K. -KICK WHILE TRIPPING(D1)DRILL 06:30 - 07:30 1.00 DRILL P PROD1 CIRCULATE TWO BOTTOMS UP -250 GPM/2250 PSI -PUW-145K,SOW-105K. -INCREASE IN FLOW AT BOTTOMS-UP(TRIP GAS)--NO PIT GAIN. -CIRCULATE TILL CLEAR AND 10.3 PPG MW OUT 07:30 - 08:30 1.00 DRILL P PROD1 MAKE MAD PASS WITH MWD PERISCOPE TOOL -F/8850'T/9090'MD,GOOD LOGS. -285 GPM/2460 PSI,AT 300 FT/HR. 08:30 - 09:30 1.00 DRILL N SFAL 9,290.00 PROD1 MAKE MAD PASS WITH MWD PERISCOPE TOOL -FAILED F/9090'T/9290'MD -285 GPM/2460 PSI,AT 300 FT/HR. 09:30 - 10:00 0.50 DRILL P PROD1 DRILL 6-1/8"OH F/9,290'T/9,414'MD -WOB-10K, GPM-285/2560 PSI ON,2560 PSI OFF. -TORQUE-8K ON,7K OFF BOTTOM. -PUW-145K,SOW-105K,FREE RT/WT- 115K. -MW 10.3 PPG IN AND OUT. 10:00 - 11:00 1.00 DRILL N SFAL 9,413.00 PROD1 PERISCOPE TOOL FAILED TO CYCLE INTO SYNC 11:00 - 15:00 4.00 DRILL P PROD1 POH F/9414'T/9090'MD -REPEAT MAD PASS F/9090 T/9290'MD, GOOD LOGS. -290 GPM/2570 PSI,AT 350 FT/HR. -RIH FROM 9,290'TO 9,414'MD. -PUW-145K,SOW-105K. 15:00 - 23:30 8.50 DRILL P PROD1 DRILL 6-1/8"OH F/9414'T/10080'MD -WOB-10K, GPM-290/2745 PSI ON,2670 PSI OFF. -TORQUE-9K ON,8K OFF BOTTOM. -PUW-165K,SOW-100K, FREE RT/WT- 115K. -RPM-140. -MW 10.3 PPG IN AND OUT. Printed 12/20/2010 5:03:04PM North America -;ALASKA-BP Page 16 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 23:30 - 00:00 0.50 DRILL N DPRB 10,080.00 PROD1 CIRCULATE BOTTOMS UP FOR FORMATION SAMPLES -290 GPM/2265 PSI,100 RPM,TORQUE- 7.8K. -POH F/10080' T/9978'MD. 11/8/2010 00:00 - 01:00 1.00 DRILL N DPRB 10,080.00 PROD1 CONTINUE CIRCULATE BOTTOMS UP FOR FORMATION SAMPLES -290 GPM/2240 PSI,100 RPM,TORQUE- 7.8 K. -POH F/10080' T/9978'MD -SAMPLES/LOGS SHOWED THAT WE DRILLED INTO THE KALUBIK SHALE AT —10,021'MD. -CONSULT WITH ON-SITE DD AND GEO, TOWN ENGINEER AND GEOS,WTL,AND DAY WSL AND DECISION IS MADE TO OPEN-HOLE SIDETRACK WELL AT 9,822'. -MW 10.3 PPG IN AND OUT. 01:00 - 03:30 2.50 DRILL N DPRB 10,080.00 PROI1t _IR NCI-LDRILL 6-118"OH -F/9822'T/9830'MD -285 GPM/2496 PSI -140 RPM 03:30 - 12:00 8.50 DRILL N DPRB 10,080.00 PROD1 DRILL 6-1/8"OH SIDETRACK -F/9,831'T/9,836'MD TIME DRILL 1'EVERY 2 HOURS -WOB-0-10K, GPM 285/2496 PSI -PUW-160K,SOW-100K, FREE RTNVT- 115K. -RPM-140. -MW 10.3 PPG IN AND OUT. 12:00 - 21:00 9.00 DRILL N DPRB 10,080.00 PROD1 DRILL 6-1/8"OH SIDETRACK -F/9,836'T/9,884'MD TIME DRILL 3'AND THEN 5'EVERY HOUR. -WOB-0-10K, GPM/285/2496 PSI -PUW-160K,SOW-100K,FREE RTNVT- 115K. -RPM-140. -DROPED 94.5 DEG TO 92 DEG AND TURNED 4 DEG TO THE RIGHT. 21:00 - 23:00 2.00 DRILL N DPRB 10,080.00 PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL -ROTARY DRILL AHEAD F/9,884'T/10,021'MD -WOB-9-10K,GPM 290/2695 PSI -2690 PSI OFF BOTTOM -PUW-160K,SOW-100K, FREE RTNVT- 115K. -RPM-130,TORQUE ON BOTTOM-9.5K, TORQUE OFF BOTTOM-8K. -MW 10.3 PPG IN AND OUT. Printed 12/20/2010 5:03:04PM North America -ALASKA BP Page 17 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 23:00 - 00:00 1.00 DRILL N DPRB 10,080.00 PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL -ROTARY DRILL AHEAD F/9,884'T/10,072'MD -WOB-9-10K,GPM 290/2695 PSI -2690 PSI OFF BOTTOM -PUW-160K,SOW-100K,FREE RT/WT- 115K. RPM-130,TORQUE ON BOTTOM-9.5K, TORQUE OFF BOTTOM-8K. 11/9/2010 00:00 - 00:30 0.50 DRILL N DPRB 10,080.00 PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 10,072'TO 10,080'MD. -WOB 3-10K. -GPM 290. -2,810 PSI ON,2,800 PSI OFF BOTTOM. -PU WT 165K,SO WT 95K,ROT WT 110K. -RPM 130. -TQ ON 9.5K,TQ OFF 8K. -ADT 10.85. -MW 10.3 PPG IN AND OUT. 00:30 - 14:00 13.50 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 10,080'TO 10,825'MD. -WOB 3-10K. GPM 290. -2,810 PSI ON,2,800 PSI OFF BOTTOM. -PU WT 165K,SO WT 95K,ROT WT 110K. -RPM 130. -TQ ON 9.5K,TQ OFF 8K. -ADT 10.85. -MW 10.3 PPG IN AND OUT. KICK WHILE DRILLING(D2). 14:00 - 14:30 0.50 DRILL N DPRB 10,825.00 PROD1 CBU WHILE CONSULTING WITH TOWN ABOUT SURVEY CORRECTIONS. -DISCOVERED SOFTWARE GLITCH THAT USED DECLINATION DATE IN SEP 03; RESULTED IN WELLBORE EXITING DRILLER'S POLYGON TO THE EAST. -285 GPM,2,820 PSI. -MONITOR WELL;SLIGHT LOSS. -MW 10.3 PPG IN AND OUT. 14:30 - 17:00 2.50 DRILL N DPRB 10,825.00 PROD1 PUMP OUT OF HOLE FROM 10,825'TO INSIDE 7"WINDOW AT 8,850'. -285 GPM,2,750 PSI. -MONITOR WELL;SLIGHT LOSS. -MW 10.3 PPG IN AND OUT. 17:00 - 17:30 0.50 DRILL N DPRB 10,825.00 PROD1 SERVICE TOP DRIVE. -GREASE BLOCKS AND WASHPIPE PACKING. -CHECK ALL FLUID LEVELS. 17:30 - 18:30 1.00 DRILL N DPRB 10,825.00 PROD1 CIRCULATE AT 7"WINDOW WHILE AWAITING DIRECTION FROM TOWN. -358 BBLS,285 GPM,2,620 PSI. -MONITOR WELL;WELL STATIC. -MW 10.3 PPG IN AND OUT. 18:30 - 19:30 1.00 DRILL N DPRB 10,825.00 PROD1 RIH FROM 8,850'TO 10,825'. -WASH LAST STAND TO BOTTOM. -NO FILL; NO PROBLEMS. Printed 12/20/2010 5:03:04PM • North America-ALASKA- BP Page 18 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 19:30 - 00:00 4.50 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 10,825'TO 11,028'MD. -WOB 3-10K. -GPM 290. -2,780 PSI ON,2,740 PSI OFF BOTTOM. -PU WT 170K,SO WT 95K, ROT WT 112K. -RPM 130. -TQ ON 9.5K,TQ OFF 8K. -ADT 2.55. -MW 10.3 PPG IN AND OUT. 11/10/2010 00:00 - 00:30 0.50 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 11,028'TO 11,060'MD. -WOB 3-10K. -GPM 290. -2,780 PSI ON,2,740 PSI OFF BOTTOM. -PU WT 170K,SO WT 95K,ROT WT 112K. -RPM 120. -TQ ON 10K,TQ OFF 8K. -ADT 1.1. -MW 10.3 PPG IN AND OUT. 00:30 - 02:30 2.00 DRILL N DFAL 11,060.00 PROD1 TROUBLESHOOT POWERDRIVE RSS AND CONSULT WITH TOWN. V/ -POWERDRIVE RSS WILL NOT HOLD TOOLFACE. -DECISION MADE BY TOWN ENGINEER AND GEOS TO POH FOR NEW POWERDRIVE RSS. 02:30 - 05:30 3.00 DRILL N DFAL 11,060.00 PROD1 PUMP OUT OF HOLE FROM 11,060'TO 7" WINDOW AT 8,850'. -250 GPM,2,025 PSI. 05:30 - 06:30 1.00 DRILL N DFAL 11,060.00 PROD1 CBU AT 7"WINDOW. -285 GPM,2,063 PSI. -MONITOR WELL;WELL STATIC. 06:30 - 09:30 3.00 DRILL N DFAL 11,060.00 PROD1 POH WITH BHA#6 FROM 8,850'TO 200'. 09:30 - 11:00 1.50 DRILL N DFAL 11,060.00 PROD1 PJSM AND LD BHA#6 FROM 200'TO SURFACE. -UNLOAD RA SOURCE. -BIT GRADE:0-0-NO-A-X-I-NO-DTF. 11:00 - 11:30 0.50 DRILL N DFAL 11,060.00 PROD1 CLEAN AND CLEAR RIG FLOOR. 11:30 12:30 1.00 BOPSUR P ■- PROD1 TEST TOOLS AND RU TEST LE. -PULL WEAR AR BUSHING AND ND INSTALL L TEST PLUG. 12:30 - 18:00 5.50 BOPSUR P PROD1 TEST BOPE AND CHOKE MANIFOLD TO 250 PSI LOW AND 3,500 PSI HIGH WITH 3.5"AND 4.5"TEST JOINTS. TEST ANNULUR /t _n PREVENTER TO 250 PSI LOW AND 2,500 PSI +I✓�"�-' HIGH WITH 3.5"TEST JOINT. TEST KOOMEY UNIT. ALL TESTS GOOD. AOGCC REP JEFF JONES WAIVED WITNESS TO TEST AT 0645 HRS ON 11/10/2010. TEST WITNESSED BY NAD TOOLPUSHER CHRIS WEAVER AND BP WSL MATT MARTYN. 18:00 - 19:00 1.00 BOPSUR P ■- PROD1 AND BD TEST EQUIPMENT. -PULL AND -PULL TEST PLUG AND AND SET WEAR BUSHING. Printed 12/20/2010 5:03:04PM forth America -ALASKA- BP Page 19 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 19:00 - 20:30 1.50 DRILL N DFAL 11,060.00 PROD1 PJSM AND PU BHA#7 TO 230'. -SAME BHA COMPONENTS AS BHA#6, BUT WITH NEW POWERDRIVE RSS AND ADN4; RERUNNING 6-1/8"HYCALOG MSF513D-B1C PDC BIT FROM BHA#6. -TEST POWERDRIVE RSS WITH 230 GPM, 340 PSI;TEST GOOD. -HANDLE RA SOURCE. 20:30 - 23:30 3.00 DRILL N DFAL 11,060.00 PROD1 RIH WITH BHA#7 FROM 230'TO 8,850'. -SHALLOW-HOLE TEST MWD TOOLS AT 1,140'WITH 250 GPM,1,180 PSI;TEST GOOD. -PU WT 165K,SO WT 105K. 23:30 - 00:00 0.50 DRILL N DFAL 11,060.00 PROD1 CBU AT THE 7"WINDOW. -201 BBLS,250 GPM,2,190 PSI. 11/11/2010 00:00 - 01:00 1.00 DRILL N DFAL 11,060.00 ` PROD1 CONTINUE CBU. -285 GPM,2,487 PSI. -SAW SOME GAS BREAK-OUT IN RISER AND GAS-CUT MUD(DOWN TO 9.5 PPG EMW); CLEANED UP COMPLETELY BY 2,000 STROKES PAST BU(BY—5,700 STROKES). -MW 10.3 PPG. 01:00 - 02:00 1.00 DRILL N DFAL 11,060.00 PROD1 RIH WITH BHA#7 FROM 8,850'TO 11,060'. -PU WT 165K,SO WT 100K. 02:00 - 03:00 1.00 DRILL N DFAL 11,060.00- PROD1 CBU ON BOTTOM TO FLUSH ANY GAS POCKETS OUT OF BUILD/HORIZONTAL SECTION. -285 GPM,2,780 PSI. -SAW SOME GAS BREAK-OUT IN RISER AND GAS-CUT MUD(DOWN TO 9.7 PPG EMW); CLEANED UP COMPLETELY BY 2,000 STROKES PAST BU(BY—7,000 STROKES). -MW 10.3 PPG. 03:00 - 12:00 9.00 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 11,060'TO 11,323'MD. -WOB 3-10K. -GPM 285. • -2,780 PSI ON,2,740 PSI OFF BOTTOM. -PU WT 170K,SO WT 95K, ROT WT 112K. -RPM 120. -TQ ON 10K,TQ OFF 8K. -INCREASE MW TO 10.4 PPG, IN AND OUT AT 09:00 HOURS. 12:00 - 00:00 12.00 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 11,323'TO 12180'MD. -WOB 10-15K. -GPM 285. -3075 PSI ON,3000 PSI OFF BOTTOM. -PU WT 170K,SO WT 95K,ROT WT 110K. -RPM 130. -TQ ON 11K,TQ OFF 9K. -MW 10.4 PPG IN AND OUT. Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 20 of 22 Operation Summary Report Common Well Name:S-129 1 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No : NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 11/12/2010 00:00 - 06:00 6.00 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 12,180'TO 12,477'MD. -WOB 10-15K. -GPM 285. -3,075 PSI ON,3,000 PSI OFF BOTTOM. -PU WT 170K,SO WT 95K,ROT WT 110K. -RPM 130. TQ ON 11K,TQ OFF 9K. MW 10.4 PPG IN AND OUT. 06:00 - 12:00 6.00 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL. -ROTARY DRILL AHEAD FROM 12,477'TO 12,891'. -WOB 10-15K. -GPM 285. -3,338 PSI ON,3,210 PSI OFF BOTTOM. -PU WT 165K,SO WT 80K, ROT WT 105K. RPM 130. -TQ ON 10K, TO OFF 8K. -ART AND ADT 8.82 HRS FOR TOUR. -MW 10.4 PPG IN AND OUT. 12:00 - 13:30 1.50 DRILL P PROD1 DRILL 6-1/8"OH PRODUCTION LATERAL TO TD AT 12,964'MD. -ROTARY DRILL AHEAD FROM 12.891'TO o " 12,964'MD. WOB 15K. -GPM 285. -3,380 PSI ON,3,360 PSI OFF BOTTOM. -PU WT 175K,SO WT 95K,ROT WT 106K. -RPM 130. -TQ ON 10K,TQ OFF 8K. -ART AND ADT 1.43 HRS FOR TOUR. -MW 10.4 PPG IN AND OUT. 13:30 - 14:00 0.50 DRILL P. PROD1 CIRCULATE AND CONDITION BHA/HOLE FOR BACKREAMING. -MONITOR WELL;W LL STATIC. -MW 10.4 PPG IN AN OUT. 14:00 - 00:00 10.00 DRILL P PROD1 BACKREAM FROM 12;964'TO 11,899'MD. -MAD PASS FROM 12,300'-12,150'MD AT 120'-150'/HR. -TIGHT SPOTS AT 12,635'MD -TIGHT SPOTS WITH PACKING OFF AT 12,208',12,035',11,945',AND 11,916'MD. -300 GPM,3,260 PSI. -PU WT 175K,SO WT 90K,ROT WT 105K. -RPM 120. -TO OFF 7-10K. -MW 10.4 PPG IN AND OUT. 11/13/2010 00:00 - 06:00 6.00 DRILL P PROD1 BACKREAM FROM 11,899'TO 11,300'MD. -MAD PASS FROM 11,899'TO 11,300'MD AT 120'-150'/HR. -300 GPM,3,260 PSI. -PU WT 175K,SO WT 90K,ROT WT 105K. -RPM 120. -TQ OFF 7-10K. -MW 10.4 PPG IN ANI)OUT. -LOSS RATE 2-3 BBLS/HR WHILE BACKREAMING. Printed 12/20/2010 5.03:04PM Vorth America -ALASKA- BP 4111 Page 21 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 06:00 - 12:00 6.00 DRILL P PROD1 BACKREAM FROM 11,300'TO 9,790'MD. -MAD PASS FROM 11,300'TO 9,790'MD AT 120'-150'/HR. -START PULLING SPEED OF 900 FT/HR AT 11,000'MD. -300 GPM,3,260 PSI. -PU WT 175K,SO WT 90K,ROT WT 105K. RPM 120. -TQ OFF 7-10K. -MW 10.4 PPG IN AND OUT. LOSS RATE 2-3 BBLS/HR WHILE BACKREAMING. 12:00 - 14:00 2.00 DRILL P PROD1 BACKREAM FROM 9,790'TO 9,290'MD. -MAD PASS FROM 9,790'TO 9,736'MD AT 120'-150'/HR.' -300 GPM,2,900 PSI. -PU WT 140K,SO WT 100K,ROT WT 112K. -RPM 120. -TQ OFF 7-10K. -MW 10.4 PPG IN AND OUT. -LOSS RATE 2-3 BBLS/HR WHILE BACKREAMING. 14:00 - 15:00 1.00 DRILL P PROD1 PUMP OUT OF HOLE FROM 9,290'TO 8,805' MD. 300 GPM,2,780 PSI. -PU WT 135K,SO WT 118K. -NO OVERPULLS NOTED. 15:00 - 16:00 1.00 DRILL P PROD1 CIRCULATE AND CONDITION 10.4 PPG MUD. -CIRCULATE AND RECIPROCATE FROM 8,850'TO 8,755'. -316 GPM,3,015 PSI PU WT 135K,SO WT 118K,ROT WT 110K. -RPM 80. -TQ OFF 4K. -MONITOR WELL,STATIC. 16:00 - 16:30 0.50 DRILL P PROD1 CUT 117'OF DRILLING LINE -CHECK CROWN SAVER. 16:30 - 17:30 1.00 DRILL P PROD1 SERVICE TOP DRIVE AND DRAW WORKS. -CALIBRATE BLOCK HEIGHT. 17:30 - 18:30 1.00 DRILL P PROD1 CIRCULATE AND CONDITION 10.4 PPG MUD. -CIRCULATE AND RECIPROCATE FROM 8,850'TO 8,755'. -PUMPED 235 BBLS AT 310 GPM,2,925 PSI -PU WT 140K,SO WT 115K,ROT WT 112K. -RPM 80 -TQ OFF 4K. -MW 10.4 PPG IN AND OUT. -MONITOR WELL,STATIC. -NOGASSEENATBU. 18:30 - 21:30 3.00 DRILL P PROD1 RIH FROM 8,850'TO 18,880'MD. -20K DRAG AT 11,920'AND 12,060'MD;WIPED BOTH,OK. -NO FILL NOTED. Printed 12/20/2010 5:03:04PM forth America -ALASKA- BP Page 22 of 22 Operation Summary Report Common Well Name:S-129 AFE No Event Type: DRL-ONSHORE(DON) Start Date: 10/24/2010 End Date: X3-00VNH-C(5,693,419.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 21:30 - 23:30 2.00 DRILL P PROD1 CIRCULATE AND CONDITION 10.4 PPG MUD. -CIRCULATE AND RECIPROCATE FROM 12,880'TO 12,797'MD. -PUMPED 622 BBLS AT 300 GPM,3,373 PSI. -PU WT 165K,SO WT 90K,ROT WT 104K. -RPM 135. -TQ OFF 7.5K. -MW 10.4 PPG IN AND OUT. -MONITOR WELL,STATIC. 23:30 - 00:00 0.50 DRILL P PROD1 POH WITH BHA#7 FROM 12,880'TO 12,609' MD. -PU WT 160K,SO WT 90K. 11/14/2010 00:00 - 02:00 2.00 DRILL P PROD1 POH WITH BHA#7 FROM 12,609'TO 8,850' MD. -PU WT 160K,SO WT 90K. 02:00 - 03:30 1.50 DRILL P PROD1 CBU AT 8,850'MD. -MONITOR WELL,STATIC. -DROP DART OPEN CIRC SUB. -CBU TWICE WITH CLEAN SHAKERS. -400 GPM,2,280 PSI -MONITOR WELL,STATIC. -PUMP DRY JOB. -BLOW DOWN TOP DRIVE. 03:30 - 06:00 2.50 DRILL P PROD1 POH WITH BHA#7 FROM 8,850'TO 201'MD. -MONITOR WELL,STATIC. -PU WT 150K,PU WT 110K. 06:00 - 08:00 2.00 DRILL P PROD1 LAY DOWN BHA#7 -BIT GRADE 0-0-N0-A-X-I-NO-TD. -PJSM FOR LD BHA AND HANDLING RA SOURCE. 08:00 - 08:30 0.50 DRILL P PROD1 CLEAN AND CLEAR RIG FLOOR. Printed 12/20/2010 5:03:04PM North America -ALASKA- BP Page 1 of 5 Operation Summary Report Common Wet Name:S-129 AFE No Event Type:COM-ONSHORE(CON) Start Date: 11/14/2010 End Date: 11/20/2010 X3-00VNH-C(1,356,139.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) I Date From-To Hrs Task Code NPT NPT Depth Phase Descriptio(t of Operations (hr) (ft) 11/14/2010 08:30 - 10:00 1.50 CASING P RUNPRD PJSM,R/U TQ RUN 3 1/2"SLOTTFD I INFR �. 10:00 - 18:00 8.00 CASING P RUNPRD RUN 3-1/2"SLOTTED/SOLID LINER -3-1/2",9.2#, L-80, IBT-M. AVERAGE MAKE UP TORQUE TO 2,800 FT/LBS. -USED BEST-O-LIFE 2000 PIPE DOPE. 17 JOINTS SLOTTE 100 JOINTS SOLID -7 SLIDING SLEEVE -5 SWELL PACKERS -FLEX-LOCK LINER ANGER -ZXP LINERTOP PACKER -HYDRAULIC SETTING TOOL 18:00 - 19:00 1.00 CASING P RUNPRD MU"ZXP"LINER TOP PACKER AND HANGER PER BAKER REP. -RIH ON ONE STAND OF 4"DP FROM DERRICK. -TO 4,288'MD. 19:00 - 19:30 0.50 CASING P RUNPRD CIRCULATE 55 BBLS OF 10.4 PPG MUD AT 4,288'MD. -STAGE UP PUMP RATE TO 210 GPM AT 600 PSI. PU WT 70K,SO WT 60K. -MONITOR WELL,STATIC. 19:30 - 22:00 2.50 CASING P RUNPRD RUN 3-1/2"SLOTTED/SOLID LINER -FROM 4,288'TO 8,801'MD. -ON 4"DP FROM DERRICK. -AT 1+MINUTE PER STAND. -PU WT 125K,SO WT 95K. 22:00 - 23:30 1.50 CASING P RUNPRD CIRCULATE 217 BBLS OF 10.4 PPG MUD AT 4,288'MD. -STAGE UP PUMP RATE TO 211 GPM AT 1,044 PSI. -PU WT 123K,SO WT 100K. -MONITOR WELL,STATIC. 23:30 - 00:00 0.50 CASING P RUNPRD RUN 3-1/2"SLOTTED/SOLID LINER -FROM 8,801'TO 9271'MD. -ON 4"DP FROM DERRICK. -AT 1+MINUTE PER STAND. -PU WT 125K,SO WT 95K. 11/15/2010 00:00 - 04:30 4.50 CASING P RUNPRD RUN 3-1/2"SLOTTED/SOLID LINER -FROM 9,271'TO 12,870'MD. -ON 4"DP FROM DEORICK. -AT 1+MINUTE PER STAND. -LD 2 JOINTS FOR SPACE OUT. -PU WT 150K,SO WT 100K. Printed 12/20/2010 5:02:53PM • ,North America -ALASKA- BP Page 2 of 5 Operation Summary Report Common Well Name:S-129 1 AFE No Event Type: COM-ONSHORE(CON) Start Date: 11/14/2010 End Date: 11/20/2010 X3-00VNH-C(1,356,139.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum: S-129 Actual©62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 04:30 - 10:00 5.50 CASING P RUNPRD DISPLACE OH WITH 10.4 PPG BRINE. 190 GPM AT 1472 PSI. -186 GPM AT 1215 PSI. -SHUT DOWN TO FLOW CHECK WELL. -DISCREPANCY IN DISPLACEMENT DURING SPOT CHECKS OF FLUID IN/FLUID OUT. -FOUND LEAKING SUCTION VALVE IN BETWEEN PIT#4 AND PILL PIT. -RESUME DISPLACEMENT OF 10.4 PPG BRINE. -FLUID WEIGHT CUT TO 10.1 PPG AS THE HI-VIS SPACER RETURNED TO SURFACE. -FCP WAS 186 GPM 937 PSI. 10:00 - 11:30 1.50 CASING P RUNPRD MONITOR WELL,STATIC. -PJSM -DROP 1-3/4"BALL AND PUMP DOWN. -OBSERVED SET AND RELEASE RUNNING TOOL. -PRESSURE TESTED LINER TOP PACKER TO 1,500 PSI FOR 10 CHARTED MINUTES.GOOD TEST. 11:30 - 12:00 0.50 CASING P - RUNPRD RD TEST EQUIPMENT AND BLOW DOWN LINES. 12:00 - 13:00 1.00 CASING P RUNPRD MONITOR WELL -PERFORM PRE-TOUR CHECKS. -TAKE SLOW PUMP RATES. -RU TO POH AND LD 4"DRILL PIPE. 13:00 - 16:30 3.50 CASING P RUNPRD POH FROM 8,663'TO 4,468'MD. -LD 4"DP TO PIPE SHED. -USE CONTINUOUS HOLE FILL WITH 10.4 PPG BRINE. 16:30 - 19:00 2.50 CASING P RUNPRD RIH WITH 4"DP STANDS FROM DERRICK TO 8662'MD. -PU WT 150K,SO WT 105K. -RIH AT 100 FEET/MINUTE TO PREVENT SURGING. 19:00 - 00:00 5.00 CASING P RUNPRD MONITOR WELL,STATIC. -PON FROM 8662'TO 3,621'MD. -LD 4"DP SINGLES TO PIPE SHED. -USE CONTINUOUS HOLE FILL WITH 10.4 PPG BRINE. 11/16/2010 00:00 - 02:30 2.50 CASING P RUNPRD POH FROM 3,621'TO PACKER SETTING TOOL. -LD 4"DP SINGLES TO PIPE SHED. -USE CONTINUOUS HOLE FILL WITH 10.4 PPG BRINE. 02:30 - 03:00 0.50 CASING P ■- RUNPRD PJSM -LD LINER TOP PACKER SETTING TOOL. -DOGS EXPOSED ON RUNNING TOOL. 03:00 - 03:30 0.50 WHSUR P -_ RUNCMP CLEAN AND CLEAR RIG FLOOR. PULL WEAR RING. 03:30 - 06:00 2.50 RUNCOM P • iYlli l:111.105/4i[cr :-:. ILA •- : CHANGE BAILS, RU TORQUE TURN EQUIPMENT, MAKE DUMMY RUN WITH LANDING JOINT AND HANGER. RU SCHLUMBERGER I-WIRE SPOOL AND SHEAVE. 06:00 - 07:30 1.50 RUNCOM N RREP _ RUNCMP REPAIR SKATE. UPPER RAMP ELECTRICAL SHORT Printed 12/20/2010 5:02:53PM North America -ALASKA- BP Page 3 of 5 Operation Summary Report Common Well Name:S-129 'AFE No Event Type: COM-ONSHORE(CON) Start Date: 11/14/2010 End Date: 11/20/2010 X3-00VNH-C(1,356,139.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor: NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 07:30 - 20:00 12.50 RUNCOM P RUNCMP PJSM, RUN 3-1/2"9.2#13CR-80 VAMTOP TUBING TO 4625'MD. TORQUE TURN TO 2900 FT/LBS. BAKER LOKALL CONNECTIONS BELOW PACKER. INSTALL I-WIRE CLAMP KICK WHILE TRIPPING DRILL-D1 20:00 - 00:00 4.00 RUNCOM P RUNCMP RD 3.-1/2"TUBING HANDLING EQUIPMENT. RU 4-1/2"TUBING RUNNING EQUIPMENT. RUN 4.5"12.6#13CR-80 TUBING WITH I-WIRE FROM 4625'TO 6158'TORQUE TURN TO 4440 FT/LBS -85K PUW,75K SOW 11/17/2010 00:00 - 06:30 6.50 RUNCOM P RUNCMP RUN 4.5"12.6#13CR-80 TUBING WITH I-WIRE FROM 6158'TO 8672'TORQUE TURN TO 4440 FT/LBS. TAG UP INSIDE OF POLISHED BORF_ RECEPTICAL. SPACE OUT COMPLETION WITH PUP JOINT—7 FT INSIfF PRP 108K PUW,90K SOW UNANNOUNCED KICK WHILE TRIPPING DRILL -D1 06:30 - 08:00 1.50 RUNCOM P RUNCMP TERMINATE I-WIRE THROUGH HANGER AND TEST TO 5000 PSI. LAND ON DEPTH. RIH LOCK DOWN SCREWS 08:00 10:00 2.00 RUNCOM P RUNCMP REVERSE CIRCULATE 102 BBLS OF CLEAN 10.4 PPG BRINE FOL'OWED BY 118 BBLS OF 10.4 PPG BRINE TREITED WITH CORROSION INHIBITOR. 10:00 - 12:00 2.00 RUNCOM N WAIT RUNCMP WAIT ON ORDERS FROM TOWN. PENDING PHASE III CONDITIONS 12:00 - 00:00 12.00 RUNCOM N WAIT RUNCMP WAIT ON WEATHER,PHASE III WEATHER CONDITIONS. FIRE DRILL 11/18/2010 00:00 - 04:00 4.00 RUNCOM N WAIT RUNCMP WAIT ON WEATHER. WAIT FOR ROADS TO BE CLEARED AND CONVOY OVER TO RIG. WAIT ON SERVICE PERSONNEL TO CONVOY TO RIG 04:00 - 05:30 1.50 RUNCOM P RUNCMP RU TO TEST TUBING DROP 1-5/16"BALL AND ROD WITH ROLLERS AND PRESSURE UP M1� TO 3500 PSI TO SET PACKER. ATTEMPT TO TEST TUBING TO 3500 PSI. —700 PSI LOST RATE IN FIRST 5 MIN, UNABLE TO GET TEST. ATTEMPT TO TEST A AIN WITHOUT SUCCESS. PRESSUFE TEST IA TO 1500 PSI _FOR 30 MIN HOI nl C;PRFCRI IRF 05:30 - 12:00 6.50 RUNCOM N DFAL RUNCMP WAIT ON SLB SLICKLINE SPILL DRILL 12:00 - 16:00 4.00 RUNCOM N DFAL RUNCMP PJSM,RU SLICKLINE SPOT TRUCK 16:00 - 18:00 2.00 RUNCOM N DFAL RUNCMP RIH AND SET PX PLUG BODY IN X NIPPLE AT 8666'MD. POOH WITH SLICKLINE SPILL DRILL 18:00 - 20:30 2.50 RUNCOM N DFAL RUNCMP ATTEMPT TO PRESSURE TEST TUBING TO 3500 PSI. LOST 3100 PSI IN 15 MIN. BLEED OFF PRESSURE. 20:30 - 23:30 3.00 RUNCOM N DFAL RUNCMP RIH WITH SLICKLINE AND SET PX PLUG IN X NIPPLE AT 8529'MD. POOH WITH RUNNING TOOL Printed 12/20/2010 5:02:53PM ■orth America -ALASKA- BP Page 4 of 5'f Operation Summary Report Common Well Name:S-129 AFE No Event Type: COM-ONSHORE(CON) Start Date: 11/14/2010 End Date: 11/20/2010 X3-00VNH-C(1,356,139.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.:NABORS 7ES Spud Date/Time: 10/25/2010 12:00:OOAM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual©62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 23:30 - 00:00 0.50 RUNCOM N DFAL RUNCMP ATTEMPT TO PRESSURE TEST TUBING TO 3500 PSI. 3100 PSI PRESSURE LOSS IN 15 MIN. 11/19/2010 00:00 - 01:00 1.00 RUNCOM N DFAL RUNCMP PRESSURE TEST IA AGAIN TO 1500 PSI WHILE CONSULTING WITH TOWN ON PLAN FORWARD. GOOD TEST. 01:00 - 04:00 3.00 RUNCOM N DFAL .RUNCMP RIH AND RETRIEVE PX PRONG AND PLUG MAN DOWN DRILL 04:00 - 06:00 2.00 RUNCOM N DFAL RUNCMP RIH WITH KICK OVER TOOL AND INDICATE ON GLM#1 FOR WRP RUN. 06:00 - 12:00 6.00 RUNCOM N DFAL RUNCMP PREP AND RUN WRP PLUG 12:00 - 14:00 2.00 RUNCOM N DFAL RUNCMP SET WRP PLUG AT 8642'MD WLD • 14:00 - 15:00 1.00 RUNCOM N DFAL RUNCMP PRESSURE TEST TUBING TO 3250 PSI FOR 30 MIN. LOST 59 PSI IN FIRST 15 MIN. LOST 17 PSI IN THE SECOND'5 MIN 15:00 - 15:30 0.50 RUNCOM N DFAL RUNCMP RD SLICKLINE 15:30 - 17:30 2.00 RUNCOM P RUNCMP PRESSURE UP TUBING TO 1600 PSI AND, PRESSURE TEST IA TO 3500 PSI FOR 30 MIN. LOST 49 IN FIRST 15 MIN AND 11 PSI IN THE SECOND 15 MIN. 17:30 - 18:30 1.00 RUNCOM P RUNCMP SHEAR DCR WITH 2400 PSI AND PUMP 2 BBLS BOTH WAYS TO CONFIRM SHEARED FIRE DRILL 18:30 - 19:30 1.00 WHSUR P RUNCMP DRY ROD IN TWC. PI✓ZESSURE TEST FROM ABOVE TO 1000 PSI FOR 10 MIN AND BELOW TO 1000 PSI FOR 10 MIN. 19:30 - 20:00 0.50 BOPSUR P RUNCMP BLOW DOWN CHOKE AND KILL LINES; CHOKE MANIFOLD;STAND PIPE,HOLE FILL LINES 20:00 - 00:00 4.00 BOPSUR P RUNCMP ND 20"RISER,BOP,DSA. RACK BACK BOPE AND SECURE. 11/20/2010 00:00 - 05:00 5.00 WHSUR P RUNCMP PJSM, NU ADAPTER =LANGE. TERMINATE AND TEST I-WIRE. TEST ADAPTER FLANGE AND PACKOFF TO 50,00 PSI FOR 30 MIN. TEST INCONCLUSIVE DUE TO DIGITAL CHARTING GAUGE. NU DOUBLE MASTER AND TEST TO 5000 PSI HIGH AND 250 PSI LOW FOR 5 MIN EACH. 05:00 - 06:30 1.50 WHSUR P RUNCMP RETEST ADAPTER FLANGE TO 5000 PSI FOR 30 MIN. GOOD TEST. 06:30 - 09:30 3.00 WHSUR P RUNCMP PJSM,RU LUBRICATOR,TEST TO 250 PSI LOW AND 3500 PSI H GH FOR 10 MIN. PULL TWC AND RD LUBRICATOR 09:30 - 12:00 2.50 WHSUR P RUNCMP PJSM, RU LINES AND PRESSURE TEST TO 3500 PSI. REVERSE CIRCULATE 74 BBLS DIESEL AT 2 BPM ANpp 1050 PSI. RU AND ALLOW TO U-TUBE. D AND BLOW DOWN LINES 12:00 - 13:30 1.50 WHSUR P RUNCMP RU DSM LUBRICATOR AND PRESSURE TEST TO 250 PSI LOW AND 3500 PSI HIGH FOR 5 MIN EACH. INSTALL BPV AND RD LUBRICATOR. 13:30 - 14:30 1.00 WHSUR P RUNCMP PRESSURE TEST BPV FROM BELOW TO 1000 PSI FOR 10 MIN. RD ITTLE RED • Printed 12/20/2010 5.02.53PM forth America -ALASKA- BP Page 5 of 5 Operation Summary Report Common Well Name:S-129 AFE No Event Type: COM-ONSHORE(CON) Start Date: 11/14/2010 End Date: 11/20/2010 X3-00VNH-C(1,356,139.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.: NABORS 7ES Spud Date/Time: 10/25/2010 12:00:00AM Rig Release: 11/20/2010 Rig Contractor:NABORS ALASKA DRILLING INC. UWI: Active Datum:S-129 Actual @62.46ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 14:30 - 16:00 1.50 WHSUR P RUNCMP REMOVE SECONDARY VALVES ON IA AND OA. INSTALL FLANGES AND GAUGES. CLEAN CELLAR RELEASE RIG FROM S-129 TO S-128 AT 16:00 HRS ON 11/20/2010 7 Printed 12/20/2010 5:02:53PM S-129, Well History Date Summary 11/18/10 ***WELL S/I ON ARRIVAL***(rig-assist) �0�h SET 3-1/2" PX PLUG IN X-NIP @ 8682'SLM 8660' MD, SET P-PRONG @ 8675' SLM MIT-T TO 3500 (FAILED), SET 3 1/2" PX PLUG @ 8536'SLM/8524' MD, Ot) SET PRONG @ 8530'SLM, MIT-T TO 3500(FAILED) (all leak off rates the same) ***CONT ON 11-19-10 WSR*** 11/19/10 ***CONT FROM 11-18-10 WSR***(7 ES rig assist) PULLED 3-1/2" PX PLUG FROM 8536' SLM/8550' MD •' 1 �i SET 2.69"OD, 3-1/2" SPECIAL CLEARANCE WRP @ 8637' SLM/8642"MD l) RIG TESTS WRP TO 3200 psi, PASS ***WELL TURNED OVER TO RIG ON DEPARTURE*** 11/20/10 T/I/O=0/0/0 Upon arrival tree cap was removed,attached lubricator/pulling tool, pressure tested lubricator 300 psi/Low- Pass 3500 psi/High- Pass. Pulled 4-1/16" CIW "H"TWC#286 CO 92"...After Hot Oil was completed with their task attached lubricator and pressure tested to 300 psi/Low- Pass 3500 psi/Pass,set 4-1/16" CIW "H" BPV# 131 @ 88"....7ES moving off of well...no problems. 11/24/10 T/I/O=0/0/0 Removed 4 1/16 model 120 swab from dry hole tree configuration (Post Rig Move) Installed upper tree configuration with 4" ME-60 actuator,4"cross,4"wing and swab valve.Torqued flanges to spec.Tested tree to 500 psi against master valve for 5 min. Good test.Tested upper tree to 5000 psi for 15 min. 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V p 0 0 0 0 0 0 V 8 o OONm V m AL 0000(00 0 m 2 °PNiA28 E g' I ' 1 0.E E 0= 'N o > > _ o COO I • a rn & 0 J C 5 c w Z W my c C ° z O p W Z y r w v � U Q v O W E Vl 0 X 0'- O F C v o 0 •1p u m o E v a e^ 5 U c x 5 w � m ° E E ° U 4 S Data Analyzer Query Results Query Name: LOT/FIT Fixed Field Data by Wellbore Comm.WB Date LOT/FIT MW Surface Name (ppg) TVD(ft) TMD(ft) press(psi) BHP(psi) EMW(ppg) S-129 :11/4/2010 11:30:00 PM FIT 10.30: 6,777.46: 8,882.00: 650.0: 4,276.4i 12.15 S-129PB1 410/30/2010 1:00:00 AM LOT 8.801 3,194.991 3,294.991 525.0: 1,985.61 11.96 S-129PB1 411/4/2010 FIT 10.30; 6,774.004 8,882.001 650.04 4,274.54 12.15 12/20/2010 16:56 Page 1 of 1 C1 t.) Ti r X cri n cn CD H (D a CD H. H a h7 (D 11 rr rr CD H. Cr cr C C) H. .7 H (D Ai r• ar C) G R. ¢ CGr p. 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H O CO■ H N N N N N N CO CO' C' C' C' co co co CO CO co CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO N N CO CO' O CO in N N CO N CO CO CD N CO N CD N CO CO' in CD CO 61 H N N CO' CO N O N CO H O . . . . . . . . . . . . . . . . . . CO CO H CO in CO N CO co co H H co in Lf) N CO O co CO CD CO CO Cr, N in CO CO N Ln co H CO' N O CO in in CO CO CO CO N N N N CO CO CO CO CO CO O O CO CO CO CO CO CO CO CO O1 CO CO CO CO CO CO CO CD O H H a Li I S 6 v SEAN PARNELL,GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Robert Tirpack Engineering Team Leader BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, PBU S-129 BP Exploration (Alaska), Inc. Permit No: 210-132 (revised) Surface Location: 1635' FNL, 4103' FEL, SEC. 35, T12N, R12E, UM Bottomhole Location: 2447' FNL, 2937' FEL, SEC. 03, T11N, R12E, UM Dear Mr. Tirpack: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the perm' lePN . . Nor ommissioner DATED this / day of November, 2010. cc: Department of Fish 86 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA l� ir NOV 0 9 2010 ALAS ')IL AND GAS CONSERVATION COMM' DN \) l //�G o ; �� PERMIT TO DRILL \lO Arta U(I�t Gas Cuts CUB 20 AAC 25.005 Correction:Surface Loc.&KB/GL 11/08/10 1 a.Type of work: An � ,oposed Well Class: ®Development Oil ❑Service-Winj ❑Single Zone 1c. Specify if well is proposed for: ® Drill ❑Redrill ❑ Stratigraphic Test ❑Development Gas ❑Service-Supply ❑Multiple Zone ❑Coalbed Gas ❑Gas Hydrates ❑ Re-Entry ❑ Exploratory ❑Service-WAG ❑Service-Disp ❑Shale Gas 2. Operator Name: 5.Bond: ® Blanket ❑Single Well 11. Well Name and Number: BP Exploration(Alaska)Inc. Bond No. 6194193 PBU S-129 3. Address: 6. Proposed Depth: 12.Field/Pool(s): P.O. Box 196612,Anchorage,Alaska 99519-6612 MD 13090' TVD 6825' Prudhoe Bay Field/Aurora 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Pool Surface: ADL 028257,028258&028261 1635'FNL,4103'FEL, SEC. 35,T12N, R12E, UM Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 3673'FNL,3098'FEL, SEC.34,T12N, R12E, UM October 5,2010 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2447' FNL,2937'FEL,SEC.03,T11 N, R12E, UM 2560 14,000' 4b. Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 62.29 feet 15.Distance to Nearest Well Open Surface: x- 619339 y-5979855 Zone- ASP4 GL Elevation above MSL: 33.79 feet to Same Pool: 1750' 16.Deviated Wells: Kickoff Depth: 300' feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 95 degrees Downhole: 3588 Surface: 2892 18. Casing Program: Specifications Top-Setting Depth-Bottom Quantity of Cement,c.f.or sacks Hole Casing Weight ; Grade Coupling Length MD TVD MD , TVD (including stage data) 42" _ 20" 129.5# , X-65 WLD 80' Surface Surface 80' 80' .-260 sx Arctic Set 12-1/4" 9-5/8" 40# L-80 BTC 3350' Surface Surface 3350' . 3230' 526 sx Arctic Set Lite:407 sx Class'G' 8-3/4" 7" 26# L-80 TCII/BTC-M 9345' Surface Surface 9345' 7019' 333 sx LiteCrete: 183 sx Class'G' 6-1/8" , 3-1/2" 9.2# L-80 IBT-M 4330' 8760' 6700' 13090' 6825' Uncemented slotted liner 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effective Depth MD(ft): Effective Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural , Surface Intermediate Production _ Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 20.Attachments: ❑ Property Plat ❑BOP Sketch ®Drilling Program ❑Time vs Depth Plot ❑Shallow Hazard Analysis ®Diverter Sketch ❑Seabed Report 0 Drilling Fluid Program 0 20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Mark Staudinger,564-5733 Printed Name Robert Tirpack Title Engineering Team Leader Prepared By Name/Number. Signature �j-,j Phone 564-4166 Date %///h Elizabeth Barker,564-4628 Commission Use Only Permit To Drill API Number: Permit Appro al e: See cover letter for Number:cJ�Qfu?a 50-Oa9�j�.f,1v?,,,4(it,C0 11 C 1� 1 e other requirements Conditions of Approval: If box is checked,well may not a used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained shales:�/le Other: 3 r� r. -.. � test. Samples Req'd: ❑ Yes [�No Mud Log Req'd: ❑Yes 67(No --Zs.� r. , Ail"- L .,...51---(�•:-�) HZS Measures: 'Ye ❑No Directional Survey Req'd: 'Yes ❑No < loat ' *jo0 zs 633 (j1 APPROVED BY THE COMMISSION Date /���'/D �' / ,COMMISSIONER Form 10-401 Revised 07/2009 This permit is valid for 24 months from the •ate o -pproval(20 AAC 25.005( Submit In Duplicate ORIGINAL /,.,z_.�� . ,,,o, siro [E '-1 SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Robert Tirpack Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, PBU S-129 BP Exploration (Alaska), Inc. Permit No: 210-132 Surface Location: 1902' FNL, 4106' FEL, SEC. 35, T12N, R12E, UM Bottomhole Location: 2447' FNL, 2937' FEL, SEC. 03, T11N, R12E, UM Dear Mr. Tirpack: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. :'nc- e or an o - issioner DATED this i?" day of September, 2010. cc: Department of Fish 86 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA I- !V V ,,..*V. ALASI )IL AND GAS CONSERVATION COMMI' )N Jj 1yb PERMIT TO DRILL SEP 1 0 2010 20 AAC 25.005 '7*;ka I:�,��s Camay C 4IiiiissiGn 1 a.Type of work: lb.Proposed Well Class: ®Development Oil ❑Service-Winj ❑Single Zone lc. Spe �f.well is roposed for: ® Drill ❑Redrill ❑ Stratigraphic Test ❑Development Gas ❑Service-Supply ❑Mufti, =Zone ❑CoalbeciVa1 'U Gas Hydrates ❑ Re-Entry ❑ Exploratory ❑Service-WAG ❑Service-Disp ❑Shale Gas 2. Operator Name: 5.Bond: ® Blanket ❑ ngle Well 11. Well Name and Number: BP Exploration(Alaska)Inc. Bond No. 6194193 PBU S-129 3. Address: 6. Proposed Depth: 12.Field/Pool(s): P.O.Box 196612,Anchorage,Alaska 99519-6612 MD 13090' D 6825' Prudhoe Bay Field/Aurora 4a. Location of Well(Governmental Section): 7. Property Designatio 'Lease Number): Pool Surface: ADL 028257, • 8258&028261 1902'FNL,4106'FEL, SEC. 35,T12N, R12E, UM(as staked) Top of Productive Horizon: 8. Land Permi. 13. Approximate Spud Date: 3673'FNL, 3098'FEL, SEC. 34,T12N,R12E, UM October 5,2010 Total Depth: 9.Acr Pro.=rty: 14.Distance to Nearest Property: 2447'FNL,2937'FEL, SEC.03,T11 N, R12E, UM 2560 14,000' 4b. Location of Well(State Base Plane Coordinates-NAD 27): 10. B E- ation above MSL: 64.5 feet 15.Distance to Nearest Well Open Surface: x- 619340 y-5979855 Zone- ASP4 L El-vation above MSL: 36.0 feet to Same Pool: 1750' 16.Deviated Wells: Kickoff Depth: 300' feet • . a • urn Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 95 degree ) s• nhole: 3588 Surface: 2892 18. Casing Program: Specifications i Top-Setting Depth-Bottom Quantity of Cement,c.f.or sacks Hole Casing Weight Grade Couplin ngt MD TVD MD TVD (including stage data) 42" 20" 129.5# X-65 WLD r)80' Surface Surface 80' 80' -260 sx Arctic Set 12-1/4" 9-5/8" 40# L-80 B C 33.0' Surface Surface 3350' 3230' 526 sx Arctic Set Lite:407 sx Class'G' • 8-3/4" 7" 26# L-80 TM Tc-M ••'5' Surfa Surfa 9345' 7019' 333 sx LiteCrete: 183 sx Class'G' . 6-1/8" 3-1/2" 9.2# L-80 1. '330' 8760' 6700' 13090' 6825' Uncemented slotted liner -F sa.ul( pc4Eee,/ 19. PRESENT WELL C N ITIO SUMMARY(To be completed for Redrill and Re-entry Operations) Total Depth MD(ft): Total Depth TVD(ft): ugs( =asured): I Effective Depth MD(ft): Effective Depth TVD(ft): I Junk(measured): Casing Length '' O Cement Volume MD ND Conductor/Structural Surface Intermediate \� Production Liner \\r Perforation Depth MD(ft): \ 0, Perforation Depth ND(ft): 20.Attachments: ❑ Property I g C∎ BOP Sketch IN Drilling Program ❑Time vs Depth Plot 0 Shallow Hazard Analysis % Diverter Sketch ❑Seabed Report IN Drilling Fluid Program 0 20 AAC 25.050 Requirements 21. Verbal Approval: Commission 'epresentative: Date: 22. I hereby certify that the foregoin• s true and correct. Contact Mark Staudinger,564-5733 Printed Name Ro•ert Tirp.ck Title Engineering Team Leader Prepared By Name/Number. Signature ,. r !4 ��/�' Phone 564-4166 Date 'l' 7//`1 Elizabeth Barker,564-4628 Commission Use Only Permit To Drill API Number: PermitApp oval Date: See cover letter for Number: �f�/.�7 so-oa9..3.1J300.00 C"11 n i,C) other requirements Conditions of Approval: If-ox is checked,well may noused to explore for,test,or produce coalbed methane,gas hydrates,or gas contained shales: k ZS°--61 pS` f lest- Other: SSamples Req'd:� �-- / p eq' : ❑ es �No Mud Log Req'd: 0 Yes �No of 2._%304 ps c nn /eC1-( S Measures: �es ❑No Directional Survey Req'd: Yes ❑No - Pa..d l�e WaW'4 °ap /.641c:Q 4./ant, /J ,ti 1) /. *- Z . a 33(`j) Y APPROVED BY THE COMMISSION Date 906'10 ,COMMISSIONER Form 10-401 Revised 07/2009 This permit is valid for 24 months from the • (20 C 25.'' Subm- In Duplicate 0 R I ' 7 i ./a PO0 STATE OF ALASKA ALASK, ,IL AND GAS CONSERVATION COMMIb...JN PERMIT TO DRILL 20 AAC 25.005 1 a.Type of work: 1 b.Proposed Well Class: ®Development Oil ❑Service-Winj ❑Single Zone 1 c. Specify if well is proposed for. ® Drill ❑Redrill ❑ Stratigraphic Test ❑Development Gas ❑Service-Supply ❑Multiple Zone ❑ Coalbed Gas ❑Gas Hydrates ❑ Re-Entry ❑ Exploratory ❑Service-WAG ❑Service-Disp ❑Shale Gas 2. Operator Name: 5.Bond: ® Blanket ❑Single Well 11. Well Name and Number: BP Exploration(Alaska) Inc. Bond No. 6194193 PBU S-129 3. Address: 6. Proposed Depth: 12.Field/Pool(s): P.O. Box 196612,Anchorage,Alaska 99519-6612 MD 13090' TVD 6825' Prudhoe Bay Field/Aurora 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Pool Surface: ADL 028257,028258&028261 1902'FNL,4106'FEL, SEC. 35,T12N, R1 'E, UM(as staked) 8. Land Use Permit: 13. Approximate Spud Date: Top of Productive Horizon: 3673'FNL, 3098'FEL, SEC. 34,T12N, R12 UM October 5,2010 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2447'FNL,2937'FEL, SEC. 03,T11 N, R12E, M 2560 14,000' 4b. Location of Well(State Base Plane Coordinates-NA 27): 10.KB Elevation above MSL: 64.5 feet 15.Distance to Nearest Well Open Surface: x- 619340 y-5979855 Zone- 'SP4 GL Elevation above MSL: 36.0 feet to Same Pool: 1750' 16.Deviated Wells: Kickoff Depth: 300' feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 95 ,egrees Downhole: 3588 Surface: 2892 18. Casing Program: Specifications Top-Setting Depth-Bottom Quantity of Cement,c.f.or sacks Hole Casing Weight Grade Couple,g Length _ MD ND , MD ND (including stage data) 42" 20" 129.5# X-65 WLD 80' Surface Surface 80' 80' —260 sx Arctic Set 12-1/4" 9-5/8" 40# L-80 BTC 3350' Surface Surface_ 3350' 3230' 26 px Arct' Class'G' 7" •. -;, TCII/BTC-M,• . ' - - - • . ' • ':4 X1C • - - : '�`� -1/:" -1/ " 9.2# IBT-M n art I c M P;'' ,- 19. PRESENT WELL CONDITION SUMM -Y(To be completed for Redri and --. - Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effective Depth MD(ft): , Effective Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Pelf. ation Depth ND(ft): 20.Attachments: ❑ Property Plat ❑ BOP Sketch ®Drilling Program • Time vs Depth Plot ❑Shallow Hazard Analysis ®Diverter Sketch ❑Seabed Report ® s rilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Mark Staudinger,564-5733 Printed Name Robert Tirpack Title ineering Team Le.der Prepared By Name/Number: Signature „f/ // 12./A7 Phone 564-4166 sate OA ^ Elizabeth Barker,564-4628 Commission Use Only Permit To Drill API Number: Permit • •proval Date: I See cover letter for Number: 50- other requirements Conditions of Approval: If box is checked,well may not be used to explore for,test,or produce coalbe• ethane,gas hydrates,or gas contained shales: ❑ Other: Samples Req'd: ❑Yes • No Mud Log Req'd: ❑ Yes ❑No HZS Measures: ❑Yes • No Directional Survey Req'd: ❑ Yes ❑No APPROVED BY THE COMMISSION Date ,COMMISSIONER Form 10-401 Revised 07/2009 This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Submit In Duplicate Well Name: S-129 Drill and Complete Plan Summary Name Position Office Home Cell Mark Staudinger Drilling Engineer 5733 929-5850 440-7403 Stephen Crumley Geologist 4078 441-1479 Bob Dawson Ops Geologist 5264 345-3359 242-2391 Taylor West Pad Engineer 4647 337-2028 632-0111 Type of Well (service/producer/ injector): 1 Producer Targets Northing Easting Z TVDss Township Range Section FSL FEL Surface 5979855 619340 Na 12N 12E 35 3644 4103 Pilot Hole Target 5977750 615100 6715 _ 12N 12E 34 1606 3098 BHL 5977464 614868 6954 12N 12E 34 1323 3335 Horizontal Section Target 1 5977060 614900 6752 12N 12E 34 919 3310 BHL 5973700 615330 6760 111N 12E 3 2832 2938 API NUMBER: I TBD I Rig: I Nabors 7es Estimated Start Date: 1 10/5/2010 Operating Days to complete: 1 26.5 MD: 113090' TVD: 16825' RT/GL: 128.5'/36.0' RTE: 164.5' Well Design: Grassroots Ultra Slim Hole, Kuparuk Horizontal Producer 4 1/2" x 3 '/2" 13Cr tubing with 31" solid/slotted liner with swell packer and sliding sleeve design / Objective: 1 Drill and complete new Kuparuk C Sand horizontal producing well r Direction al Plan: _Version: SLB P6 (PB1) and P7 KOP: 300' MD, build 1.5/100 Maximum Hole Angle: 95°horizontal section Close Approach Wells: All wells pass major risk criteria. Reference anti-collision report Nearest well within Pool S-129 is 1750'from S-116i. ..- Distance to Nearest Property 14,000'to PBU boundary • Line: S-129 Permit Application Page 1 Logging Program: Surface Interval Drilling, MWD: GR Open Hole: None Cased Hole: None Intermediate Interval Drilling, MWD: GR, RES, NEU,Azimuthal Density, PWD Open Hole: None Cased Hole: None Production Interval Drilling, MWD: GR, RES, NEU,Azimuthal Density,ABI, Density Caliper, Periscope Open Hole: None Cased Hole: None Mud Program: 12 1/4" Surface Hole: MAXDRIL Surface Mud Density Funnel Viscosity LSYP API FL pH (ppg) _ (seconds) (2x3-6 rpm) (mis/30min) `8 Spud to TD .5-9.5 80-120 (for reference 30-50 <10.0 9.5-10.5 only. Fluid should be run off LSYP) 8 3/4" Intermediate Hole: LSND Mud Interval Density YP PV pH API !(ppg). Fluid Loss CsgShoetoTHRZ `- 8-9) 20-28 _ 12-18 9-9.5 < 10.0 THRZ to TD T05 20-28 15-22 9-9.5 <6.0 6 1/8" Production Hole: Baradril n Mud Interval Density YP PV pH API Appg)4_, Fluid Loss Csg Window toTD,10.3- 10.5 20-28 12-20 9-9.5 <8.0 Casing/Tubing Program: Hole Size Csg/ Wt/Ft Grade Connection Length Top Btm Tbg O.D. MD/TVD MD/TVD RTE 42" 20" 129.5 X-65 WLD 80' GL 80'/80' 12 1/4" 9 5/8" 40 L-80 BTC 3350' GL 3350'/3230' 8 3/4' 7" 26 L-80 TC-II 4850' GL 4850'/4282' ' 8 3/4' 7" 26 L-80 BTC-M 4495' 4850'/4282' 9345'/7019' 6 '/8" 3 1/2" 9.2 L-80 IBT-M 4330' 8760'/6700' 13090'/6825' • Tubing 4'/2" 12.6 13Cr-80 Vam Top 4100' GL _ 4100'/3760' . Tubing 31/2" 9.2 13Cr-80 Vam Top 4660' 4100'/3760' 8760'/6700' S-129 Permit Application Page 2 Integrity Testing: Test Point Depth Test Type 9 543" Surface Casing 20'—50'from surface shoe LOT Test Point Depth Test Type 7" Intermediate Casing 20'—50'from window FIT Cement Calculations: Surface Casing: Casing Size 19 5/8" Basis: Lead: Open hole volume+250%excess in permafrost and 40%excess below permafrost. Port collar used if necessary. Lead TOC: Surface Tail: Open hole volume+40% excess+80'shoe track. Tail TOC: 1000' MD above the casing shoe (2350' MD) Total Cement Volume: Lead 417 bbl/2341 ft3/526 sks of Arctic Set Lite at 10.7 ppg and 4.45 cf/sk Tail 84 bbl/472 ftd/407 sks of Class `G'at 15.8 ppg and 1.16 cf/sk Intermediate Casing: Casing S ize I 7" I Basis: Lead: None Open hole volume with 30%excess Lead TOC: 500' MD above the Mc Formation Top Tail: Open hole volume with 30%excess and 80' shoe track volume, ID 6.276" Tail TOC: 1000'above the 7" intermediate shoe Total Cement Volume: Lead 109 bbl/609 ft'/333 sks of LiteCrete at 11.0 ppg and 1.84 cf/sk Tail 38 bbl/213 ft'/183 sks of Class `G' at 15.8 ppg and 1.16 cf/sk Formation Markers: Est. Commercial Formation Hydrocarbon Est. Pore Tops Uncertainty Bearing Est. Pore Press. Press. Formation (TVDss) (feet) (Yes/No) (Psi) (ppg EMW) NOTE:All formation tops are required from 1000'above proposed KOP to TD for sidetracks NOTE:All formation tops are required from surface to TD for all new wells Pilot Hole S- 129PB1: G1 330 +/-30' No 149 8.7 SV6 1535 +/-30' No 691 8.7 See fault detail Fault#1 1600 +/- 150' M.D. information below. Base Permafrost 1865 +/-30' No 839 8.7 EOCU +/-50' No SV5 2135 +/-50' No 961 8.7 SV4 2300 +/-50' No 1035 8.7 S-129 Permit Application Page 3 SV3 2700 +/-50' No 1215 8.7 SV2 2850 +/-50' No 1283 8.7 9 5/8"casing +/-50' SV1 3170 +/-50' No 1427 8.7 UG4 3505 +/-50' Thin coal 1577 8.7 UG4A 3550 +/-50' Heavy oil 1598 8.7 Heavy oil and thin UG3 3855 +/-50' coals 1735 8.7 UG1 4395 +/-50' Heavy oil 1978 8.7 UG_MA 4635 +/-50' Heavy oil 2086 8.7 UG_MB1 4680 +/-50' Heavy oil 2106 8.7 UG_MB2 4735 +/-50' No,wet 2131 8.7 ./ UG_MC 4805 +/-50' Heavy oil 2162 8.7 SB_NA 4870 +/-30' No 2192 8.7 SB_NB 4885 +/-30' Yes 2198 8.7 SB_NC 4905 +/-30' No 2207 8.7 Fault#2 4910 +/- 150' M.D. SB_OA 4995 +/-30' Yes 2248 7.5-8.5 SB_OBa 5045 +/-30' Yes 2270 7.5-8.5 SB_OBb 5085 +/-30' Yes 2288 7.5-8.5 SB_OBc 5130 +/-30' Yes 2309 7.5-8.5 SB_OBd 5175 +/-30' Yes 2329 7.5-8.5 SB_OBe 5235 +/-30' No 2356 8.7 SB_OBf 5280 +/-30' No 2376 8.7 OBf Base 5320 +/-30' No 2394 8.7 CM1 6115 +/-30' no 2721 8.6 TLBK 6365 +/-30' no 2832 8.6 THRZ 6520 +/-30' no 2901 8.6 TKLB 6705 +/-30' no 2984 8.6 TKC4 6715 +/-30' Oil 3492 10.0 TKC2B 6735 +/-30' Oil 3502 10.0 TKC2A 6750 +/-30' Oil 3510 10.0 TKC1C 6765 +/-30' Oil 3518 10.0 TKB/LCU 6785 +/-30' no 3528 10.0 TKA6 6833 +/-30' no 3553 10.0 TKA5 6840 +/-30' Oil 3557 10.0 TKA4 6865 +/-30' no 3570 10.0 TMLV 6900 +/-30' no 3588 10.0 TD(100'MD below TMLV) +/-30' no S-129 Permit Application Page 4 Well Control: 12 '/4" holes will be drilled with diverter. The 8 3/4" intermediate hole and 6 '/8" production hole sections will use well control equipment consisting of 5000 psi working pressure pipe rams(2), blind/shear rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Annular preventer will be tested to 2500 psi. Rams will be tested to 3500 psi. The BOP test frequency will be conducted on a 14 day frequency, with a function test every 7 days. Except for significant operational issues that may effect well integrity or pose safety concerns, an extension to the 14 day BOP test period should not be requested. Diverter, BOPE and drilling fluid system schematics of Nabors 7es are attached to this permit to drill. 12-1/4" Surface 9-5/8" Casing BOPE A tested diverter system per AOGCC regulations Maximum Anticipated BHP 1,283 psi © 2,994'TVD, 8.3 ppg EMW Maximum Surface Pressure 984 psi (0.10 psi/ft gas gradient to surface) (SV2) Planned BOP test pressure Function Test 9-5/8" Casing Test 3,500 psi surface pressure Kick Tolerance NA 8-3/4" Intermediate 7" Casing BOPE Hydril, 13-%", 5000 psi Maximum Anticipated BHP 3,588 psi @ 6,965'TVD, 9.9 ppg EMW Maximum Surface Pressure 2,892 psi (.10 psi/ft gas gradient to surface) (TMLV) Planned BOP test pressure Rams test to 3,500 psi/250 psi. Annular test to 2,500 psi/250 psi 7" Casing Test 3,500 psi surface pressure Integrity Test—9-'/8" Hole LOT after drilling 20'—50'of new hole Kick Tolerance 51 bbls with a 12.5 ppg FIT/LOT 6-Y8" Production 3-'/s" Liner BOPE Hydril, 13-%", 5000 psi _Maximum Anticipated BHP 3,528 psi © 6,850'TVD, 9.9 ppg EMW✓ Maximum Surface Pressure 2,843 psi (0.10 psi/ft gas gradient to surface) (TKB) Planned BOP test pressure Rams test to 3,500 psi/250 psi. Annular test to 2,500 psi/250 psi 3-1" Liner Test None. Planned 1500 psi Liner Top Packer Test. Integrity Test—6-'/8" Hole FIT to 12.0 ppg EMW after drilling 20'—50' of new hole Kick Tolerance Infinite with a 12.0 ppg FIT/LOT Planned Completion Fluids 10.3 ppg Corrosion Inhibited Brine/6.8 ppg Diesel Disposal: • No annular disposal in this well. • Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS-04. • Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for disposal. Haul all Class I wastes to Pad 3 for disposal. Variance Request: • To avoid the risk of plugging the flow line with large rocks and wood encountered while drilling surface hole, it is requested to drill without a flow paddle for the first portion of the surface hole. After drilling past the larger rocks and wood sections, the flow paddle will be put back in the flow line. S-129 Permit Application Page 5 S-129 Drill and Complete Procedure Summary Pre-Rig Work: 1. Install Cellar Box and set 20" Conductor to+/- 108'. 2. Weld an FMC landing ring for the FMC Gen 5 wellhead on the conductor. 3. If necessary, level the pad and prepare location for rig move. Shut in nearby wells, bleed off process" lines, and remove well houses as necessary. Rig Operations: 1. MIRU. Nipple up diverter spool and function test diverter. 2. Prepare pits with MAXDRIL Mud and PU 4" DP as required and stand back in derrick. 3. MU 12-1/4" drilling assembly with MWD/GR and directionally drill surface hole to TD approximately 50' TVD below the top of the SV1. If needed, perform wiper trip at the base of permafrost. CBU and condition hole as necessary,then POH for casing. • 4. Run and cement 9-5/8" surface casing. A TAM port collar may be run at 1000' as a contingency. • 5. ND diverter and NU casing / tubing head. NU BOPE and test to 3500psi. Give the AOGCC 24 hrs • notice prior to testing. 6. Make up 8-3/4' drilling BHA with MWD/GR/RES/AZI-DEN/NEU/PWD and RIH to float collar. Pressure test 9-5/8" casing to 3500 psi for 30 minutes. Drill out shoe track and displace well to LSND drilling fluid. Drill 20' of new formation and perform LOT. 7. Drill to ±200' above the HRZ, ensure mud is conditioned and properly weighted for shale stability, and perform short trip as needed. Ensure pre-reservoir meeting is held highlighting kick tolerance and detection prior to entering the HRZ and Kuparuk. 8. Drill ahead to target TD, (below top TMLV). Circulate and condition fluid. Back-ream/MAD Pass as required, then POH to run casing. - $0P 9. Change to 7" rams and test prior to running casing. • ? . 5 • 6 Sun1 10. Run 7" intermediate casing and cement in 1 stage. Displace with mud. Bring TOC to 10Q0' of the surface shoe. Bump plug and ensure that float holds. Pressure test casing to 3500 psi for 30 minutes. 11. MU and RIH w/ 7" Whipstock assembly. Hang 4.5" space-out tubing below whipstock and set whipstock such that windo is at the top of the Kuparuk C4. 12. Displace the casing with Baradril n mud. Mill Window and drill 20'of new formation. Perform FIT test. POOH and LD milling assembly. —1 13. MU 6-%" build section BHA. RIH and build to horizontal. POOH. 14. MU 6-W RSS drilling assembly with MWD/GR/RES/Azi-Den/Neu/Density Caliper/ABI/Periscope (All real time). 15. Drill ahead in Kuparuk C sands to TD. Circulate and condition mud. MAD-Pass / Backream as required and POH for ' liner run. Lay down excess DP as necessary. 16. Run the 3-1/2" solid/slotte O'er with swell packers and sliding sleeves. There will be 150' of overlap into the 7" intermediate casing. Set liner hanger and liner top packer as per BOT Rep and test LTP to 1500 psi for 10 minutes. Release from liner and displace well to brine. POOH and LD Drill Pipe. 17. Run 4-1/2"x 3-Y2"chrome completion w/SLB pressure gauge and land tubing hanger. RILDS: 18. Drop RHC ball and rod on rollers and set packer as per Baker recommendation and test tubing to 3,500 psi and annulus to 3,500 psi. Shear the DCR-1 valve and pump both ways to confirm circulation ability. 19. Install and test TWC. Nipple down the BOPE. Nipple up and test double master valves to 5000 psi. RU DSM and pull TWC. 20. Freeze protect the well to 2200' TVD by first pumping corrosion inhibited brine down the IA with rig pumps followed by diesel down IA w/ Hot Oil truck, taking clean brine returns to surface. Allow diesel to u-tube into tubing. 21. Install BPV in tubing hanger. Install all annulus valves and secure the well. Ensure that T/IA/OA are protected with two barriers. RDMO. - S-129 Permit Application Page 6 Post-Rig Work: 1. Install tree with electric valve. Pull BPV. . 2. R/U Slickline and pull ball and rod/RHC. , 3. Replace the DCK shear valve with a dummy GLV. • 4. RU coil and establish circulation through the openhole annulus. Displace the drilling mud out of the liner and openhole annulus with clean brine. 5. Displace the 3-1/2" liner and open hole annulus to diesel from the slotted liner to the uphole sliding sleeve. This fluid is to allow the swell packers to swell. 6. Pull dummy valves and replace with gas lift valves. Pull VR Plugs. 7. Install wellhouses and flowlines. 8. Pump RG2401 (Blue-Goo) on top of surface casing cement. S-129 Permit Application Page 7 Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control/Reservoir Pressures: A. The Schrader Bluff reservoir is expected to be pressured from 7.5 to 8.7 ppg EMW. The Kuparuk sands may be pressured as high as 10 ppg EMW due to pressure uncertainty in this fault block. Plan to maintain adequate mud weight. II. Hydrates and Shallow gas: A. Free gas and/or gas hydrates may be present in the SV intervals while drilling the surface hole below the Permafrost base. Use standard operating procedures for hydrates, if encountered. Set surface casing below deepest SV sand hydrate zone to isolate gas bearing intervals behind cemented pipe in surface hole from intermediate hole section. III. Running Gravels: A. Unconsolidated sand, gravel, & cobbles and thawing permafrost could impede well angle build and casing running through permafrost. Keep moderate to low build angles until out of permafrost section. Keep flow rates low. Hazards include wood and cobbles, running gravels, lost circulation, and tight hole problems while drilling and running casing. See S Pad Data Sheet for details. IV. Faults Formation Where TVDSS Throw Encounter Fault MD Intersect Intersect Est. Throw Direction Uncertainty Fault#1 - SV6 1670 1600 120' West +1- 150' M.D. Fault#2 - SB_Nb 5850 4910 60' NE +/- 100' M.D. V. Lost Circulation/Breathing: A. Both faults have been penetrated by several S Pad wells at similar formation depths with no reported losses. Expected fault related losses are minimal. B. Breathing in the Colville has occurred on S-Pad in the past, but is not considered a major risk. Maintain ECD hardlines and good tripping practices to minimize risk of breaking down the formations. C. Minor pressure depletion of Schrader OA, OBa, OBb, OBc and OBd zones can yield pore pressures as low as 7.5 ppg. VI. Kick Tolerance/Integrity Testing: Maximum Anticipated BHP 3,588 psi @ 6,965'TVD, 9.9 ppg EMW Maximum Surface Pressure 2,892 psi (.10 psi/ft gas gradient to surface) (TMLV) Kick Tolerance(Intermediate) 51 bbls with a 12.5 ppg FIT/LOT Kick Tolerance(Production) Infinite with a 12.0 ppg FIT/LOT Planned BOP Test Pressure Rams test to 3,500 psi/250 psi. Annular test to 2,500 psi/250 psi 9-5/8" Casing Test 3,500 psi surface pressure Integrity Test—8-3/4" Hole LOT after drilling 20'—50'of new hole r7" Casing Test 3,500 psi surface pressure Integrity Test—6-'/8" Hole FIT to 12.0 ppg EMW after drilling 20'—50' of new hole Planned Completion Fluids 10.3 ppg Corrosion Inhibited Brine/6.8 ppg Diesel S-129 Permit Application Page 8 VII. Heavy Oil A. Heavy oil is expected in the UG4A through UG_Mc intervals which could result in plugging of shaker screens. Follow established operating practices for drilling in heavy oil zones. VIII. Broaching A. Monitor adjacent wells for broaching while drilling surface hole. VIII. Stuck Pipe A. There is a risk of differential sticking while drilling the 8-3/4" intermediate section and while running 7" casing due to the partially depleted Schrader sands and the high mud weight. Keep the pipe moving as much as possible to reduce this risk. For the casing run, follow the centralizer program to help with standoff. IX. Hydrogen Sulfide A. All S Pad gas lift wells are expected to have H2S levels in the 20 to 300 ppm range; result of PBU gas lift gas. This site should be treated as an H2S site with all the required precautions. Date of Well Name H2S Level Reading #1 Closest SHL Well H2S Level S-05 100 ppm 2/24/2008 #2 Closest SHL Well H2S Level S-27B 180 ppm 2/27/2007 #1 Closest BHL Well H2S Level S-118 20 ppm 11/26/2009 #2 Closest BHL Well H2S Level S-125 20 ppm 12/8/2009 Max.Recorded H2S on Pad/Facility S-201 300 ppm 5/30/2009 Occasional H2S release(<50ppm) from injection Other Relevant H2S Data wells during WAG swaps. (H2S alarms from rigs,etc.) CONSULT THE S PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION S-129 Permit Application Page 9 TREE= 4-1/18" WELLHEAD= FMC LiFETY NOTES: ""CHROME TBa** ACTUATOR= Electric s—1 ip P ropose d _1 KB.ELEV= BF.ELEV= /I 1 KOP= 300 Max Angle= 95 @ 11489' 20"CONDUCTOR H 108' _1 — TBD 9-5/8"TAM PORT COLLAR I Datum MD= Datum ND= , 1 2000' 41 HES X NIP,ID=3.813" 1 19-5/8"CSG,40#,L-80 BTC,ID=8.835" H 3350' 1— A GAS LIFT MANDRELS 41/2"12.6#13Cr VT 3-1/2"9.2#13Cr VT X01-1 -4100' I \ ST MD TVD DEV TYPE VLV LATCH PORT DATE 5 3800 MMG DUM RK 1.5" 4 3870 MMG DUM RK 1.5" 3 5600 MMG DUM RK 1.5" 2 6700 M 1G DUM RK 1.5" 1 .6770 MMG DCR-1 RK 1.5" 7"CSG,26#,L-80 TCII,.0383 bpf,ID=6.276" —1 4850' 8700' H3-1/2"HES X NIP, ID=2.813" 1 13-1/2"NDPG SINGLE-SENSOR SUB, ID=2.992" H xxxx. T_____, 8710' 1—7"X 3-1/2"PROD PACKER ID=xx x" Minimum ID = 2.813" 3-1/2" X Nipple ' , 8730' 1—F-1 Ti TIES X NIP, ID=2.813" I ri8750' 1-13-1/2"HES X NIP, ID=2.813" I 13-1/2"TBG,9.2#, 13 Cr,VT, .0087 bpf,ID=2.992" H 8760' I ' 8755' I 7"X 5"BKR ZXP PKR&LNR HGR �w/11EBACK SLV,ID=xx" 17"BKR WHIPSTOCK H TKC4 I 8760' H 3-1/2"WLEG,ID=2.992" MILLED OUT WINDOW(7").-- 8905'-8918' 7"PBTD 9265' I 177-CSG,26#,L-80, BTC-M, .0383 bpf,ID=6.276" H 9345' r�' ' t ' ' ' 'it t. PERFORATION SUMMARY W REF LOG: LD ON 3-1/2"Bkr CMD Sliding Sleeve @ xxxx',ANGLEATTOPPERF: xxxx',xxxx',xxxx',and xxxx' Note:Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE , OBM Swell Packers xxxx', , 0 xxxx',and xxxx' .40"/ ■ 3-1/2"Solid LNR,9.2#, L-80 IBT-M,ID=2.992" H 12500' `` , 3-1/2"Slotted LNR,9.2#,L-80 IBT-M,ID=2.992" I--f 13090' I , DATE REV BY COMMENTS DATE REV BY COMMENTS AURORA UNIT 08/25/10 MIS Proposed Completion WELL: S-129 PERMIT No: API No: SEC TWP RGE NSL FEL BP Exploration(Alaska) m� 04040,0 AO AAm 0,,-,-, AAAAA ,N01 O W i00f N m,'-T- 101000a NW N C? (0U N A A 0:00-,T-. 0 7 W O W W W W W<O (...0110 00 M 7 m W N O A M 7 N N O M M N 00 O)mmma W N A 700oioi NNNNN OI∎Oi1A N r0 M0M 664W.- W 7N N W 77 p 0 Z' MMMMM M M N N N ,-0000 00000 m m W W A W M M O A M m m 7 N 0,0-000. 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OirM.'0 000 OOOO O.02m LON MO a0 NN W 0W 0000 .-N Mm OW N 0,0022 W 00) W M.-.- Oy NOO N 0' O W COW W 0 00 00 7yaCO 0)0.- 00 0 ' 0 T O N7 2 =F M M M M 00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 O r r r r 0 0 0 0 0 0 0 0 0 00 0 0 W 0 m m m mmm r M M 00 0 M. m f7 b O1 CO J m m N J 6 P.-kJ) $ N 22u- 0N 00 O egg°o °o F IA: N 0 E Z 1n 2 2 a m ¢U-I V TT 01 E 0O a Mr N O 0.00-0 0).F 0)N.- M 6 0 �mNO N N,- -00 a>r 4" C E cU' U' .-ma a 2 m cu c ¢mmmm mmmol- Z m 9 0_00 uom -+� ZZ 0 WO »>MM s z zz w 00000 0000o o 1- W uig 1-O NN o by Schlumberger WELL I FIELD STRUCTURE S-129PB1 (P6) Prudhoe Bay Unit-WOA 1 S-PAD Magnetic Parameter 1 Surface Location NAD27 Alaska State Plane,Zone e4.US Feet ` Miscellaneous Model: BGGM 2009 Dip: 80 940' Oats: 0ct°ber 27,2010 Lat: N 70 21 12.951 Northing: 5979855 03 805 Grid Cenv 0.91287540' Slot: S-129 SL3 ND Ree. MSLIOebelow MSL) Mae Dec: 21 830° FS'. 57098.301 Lon: W 149 1 51.312 Easting. 819339 50 005 Scale Fact 0.99991818 Plan'. S-129PB1(P81 SIw Date:October 27.2010 0 1000 2000 3000 4000 5000 RTE 0 0 Ndg 1.5/100 _.._.._.._.._.. T.._.._.._.._.._.._.._..e..-.._..-.._..-..-..-..-.•_'•_e•_•.-.._..-..-..-..-.-.._..-..-..-..-..-..-.._.._.._.._..-..-..-..-.._..-._.._.._ Drp 1.5/100 1000 1000 End Drp _..-..-.._..-.. -V6 -..-..-..-..-..-.._.._.._..-..-..-..-..-..-..�..-..-..-..-..-.._.._.._._.._.._.._.._.._.._.._..-_-.._.._.._.._..-.._.._.._._..-..- Cry 1100.._..:ase�errn.._.._..-..- -..-..-..-.._..-..-.._.._..-..-..-..-.._..-..-..-..-.-..-..-..-.._..-..-.._..-�-.._.._.._.._..-.._.._.._._.._.._ 2000 _.._..-.._.._..<. u-..-.._..-.._.._..a.._.._.._.._.._.._.._.._.. .._.._.._..-.._.._.._.._.-..-.._.._.._.._.._.._.._a-.._.._.._.._..-.._.._.._r._.._.._ 2000 _.._.._.._.._..-...- V4-..-..-..-..-..-..a..-..-..-..-..-.._..-.._..}.._.._..-.._..-..-..-..-.-..-..-.._.._..-.._.._..-a_..-.._.._.._..-.._.._.._._.._.._ End Civ 3000 V2 ••••9-5/$F•Cs9 3000 0 cr.3:5/100 c a1 io to 0 4000 i i i 4000 H Cry 3.5/100 !iE!!.a..!r!!!:a!r:!!r!!!!.r!!!s!r!»!:(!(*EM!(:a(r!!(railansrrOna::- -!!!! !!!0!!!!!!!!a1i!((!((!n!lta arlsl!nl!n!rr!tun!n!!!!!U!!! 5000 5000 _.._.._.._.._.._._.._._.�.�.._.._.._:?::_.._.._._._.._.._.._..-.._.._._._.._.._ :t lies._.._.._.._.._.._.�__.._.._.._.._.. .._.._.._._.._.._ _.._.._.._.._.._._.._.._.._.._.._.._.._.._.._.._.._..-..-..-..-..-..-..-.._..-..-.._..-..-.._._.._.. 4_2_.._.._..-..-__.._..-.._.._..�.._.._.._._.._.._ Cry 3.5/100 6000 6000 End Cry _.._.._..-..-...:..-..-..-..-..-.._..-.._.. ..-..-..-..-..-..-..-..-..r..-..-..-..-..-..-..-..-.-..-..-..-..-..-..-.._..-.:-..-.._.. -._._.._ _._.._ $-29PB1 T s t • 7000 7000 TD/7"Csg S-129PB1(P6). 0 1000 2000 3000 4000 5000 Vertical Section(ft)Azim=242.779°,Scale= 1(in):1000(ft) Origin=0 N/-S,0 E/-V 0 0 0 0 0 0 0 O N O V O (9 CV °o � aa2 O z 0 w` o V / 0 U m S v 9 '' W m __G' $R g g = r I (O a (D Mt e 8 �+ eF61 U 9 - FN W dB CI a if o O O 0 FF .- N w 6 ce in I A bm 0 0 A O A O ; W < n 3 g 0 ��1 0 1 0- co m ,!$ o u�o u O a O �m N w N f6 cti M w U) G t '(S V L a v Q° z3 0 0 0 0 M C? LL =afi • i 0 0 0 0° co 0 0 5 ai Q V m a $: _ Li 03 O N O . N a f .0.N m N _ 7 eR g o . V) a€� m S 3 i$ W O O O O O ' q V O O O O O CO N C4 V N «< N (11)009:(uOI.=ahS S >>> BPPASSPORT Anticollision Report Company: North America-ALASKA-BP Local Co-ordinate Reference: Well Plan S-129 SL3 Project: Prudhoe Bay ND Reference: Plan S-129 @ 64.50ft(Nabors XES) Reference Site: ---- PBS Pad MD-Reference: Plan S-129 @ 64.50ft(Nabors XES) Site Error: 0.00ft North Reference: True Reference-Weil: Plan-S-1-29-SL3 Survey-Calculation Method: ---Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore Plan S-129PB1 Database: EDM.16-Anc Prod-WH24P Reference Design: Plan#6 S-129PB1 Offset ND Reference: Offset Datum Reference Plan#6 S-129PB1 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of refer Interpolation Method: MD Interval 5.00ft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,131.64ft Error Surface: Elliptical Conic Survey Tool Program Date 2/1/20T0 From To tffl (ft)-___ Survey(Vlfelibore) Tool Name — Description_ 28.50 700.00 Plan#6 S-129PB1 (Plan S-129PB1) GYD-GC-SS Gyrodata gyro single shots 700.00 1,700.00 Plan#6 S-129PB1 (Plan S-129PB1) MWD MWD-Standard 700.00 3,300.00 Plan#6 S-129PB1 (Plan S-129PB1) MWD+IFR+MS MWD+IFR+Multi Station 3,300.00 4,300.00 Plan#6 S-129PB1 (Plan S-129PB1) MWD MWD-Standard - 3,300.00 9,344.87 Plan#6 S-129PB1 (Plan S-129PB1) MWD+IFR+MS MWD+ IFR+Multi Station 2/1/2010 2:01:54PM Page 2 of 5 COMPASS 2003.16 Build 71 BPPASSPORT Anticollision Report Company: North America-ALASKA-BP Local Co-ordinate Reference: Well Plan S-129 SL3 Project: Prudhoe Bay TVD Reference: Plan S-129 @ 64.50ft(Nabors XES) Reference Site: PB S Pad MD Reference: - Plan S-129 @ 64.50ft(Nabors XES)-- Site Error: 0.00ft North Reference: True Reference Welk - Plan S-129-SL3 Survey-Calculation-Method:-----Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore Plan S-129PB1 Database: EDM.16-Anc Prod-WH24P Reference Design: Plan#6 S-129PB1 Offset TVD Reference: Offset Datum Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Welt--Wellbore-=Design - (ft) (ft)- tftr -(ft)- PB S Pad Plan S-128 SL2-Plan S-128-Plan#4 S-128 937.14 885.00- 585.48 16.60 569.02 Pass MajorRisk Plan S-129 SL3-Plan S-129-Plan#6 S-129 8,910.05 8,655.00 0.03 187.26 -184.02 FAIL-Major Risk j Plan xS-129 SL4 do not use-Plan S-129-Plan# 8,699.85 8,040.00 273.72 187.86 103.60 Pass-Major Risk Plan xS-129 SL4 do not use-Plan S-129PB1 -Pk 8,699.85 8,040.00 273.72 187.86 103.60 Pass-Major Risk S-01 -S-01 -S-01 3,170.50 3,085.00 166.75 55.39 111.52 Pass-Major Risk S-01-S-01A-S-01A 3,170.50 3,085.00 166.75 55.39 111.52 Pass-Major Risk S-01 -S-01 B-S-01 B 3,171.52 3,090.00 166.78 55.43 111.52 Pass-Major Risk S-02-S-02-S-02 2,968.79 2,945.00 122.30 45.42 77.08 Pass-Major Risk S-02-S-02A-S-02A 2,969.15 2,945.00 122.31 45.59 76.92 Pass-Major Risk S-02-S-02APB1 -S-02APB1 2,969.15 2,945.00 122.31 45.43 77.08 Pass-Major Risk S-03-S-03-S-03 1,360.24 1,360.00 167.47 21.28 146.23 Pass-Major Risk S-04-S-04-S-04 2,303.64 2,310.00 83.14 33.55 49.66 Pass-Major Risk S-05-S-05-S-05 444.62 455.00 18.92 11.09 7.83 Pass-Major Risk S-05-S-05A-S-05A 440.99 445.00 18.85 11.17 7.67 Pass-Major Risk S-05-S-05APB1 -S-05APB1 440.99 445.00 18.85 11.02 7.83 Pass-Major Risk S-06-S-06-S-06 468.48 475.00 127.33 8.84 118.49 Pass-Major Risk S-07-S-07-S-07 400.00 405.00 238.74 7.70 231.04 Pass-Major Risk S-07-S-07A-S-07A 400.00 405.00 238.74 7.70 231.04 Pass-Major Risk S-08-S-08-S-08 439.74 450.00 349.63 11.45 338.18 Pass-Major Risk S-08-S-08A-S-08A 439.74 450.00 349.63 11.45 338.18 Pass-Major Risk S-08-S-08B-S-08B 439.74 450.00 349.63 11.45 338.18 Pass-Major Risk S-116-S-116 S-116-S-116-S-116 5,327.68 5,250.00 648.72 95.91 568.40 Pass-Major Risk S-118-S-118-S-118 4,193.98 4,125.00 201.77 83.67 119.94 Pass-Major Risk S-123-S-123-S-123 303.93 300.00 166.77 7.99 158.84 Pass-Major Risk S-124-S-124-S-124 350.11 350.00 185.49 6.50 179.00 Pass-Major Risk S-134-S-134-S-134 5,298.74 5,230.00 205.87 90.79 153.94 Pass-Major Risk S-15-S-15-S-15 3,348.91 3,255.00 78.32 48.82 29.67 Pass-Major Risk S-16-S-16-S-16 3,454.96 3,350.00 192.88 57.77 135.23 Pass-Major Risk S-17-S-17-S-17 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-17-S-17A-S-17A 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-17-S-17AL1 -S-17AL1 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-17-S-17APB1 -S-17APB1 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-17-S-17B-S-17B 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-17-S-17C-S-17C 3,788.77 3,610.00 364.12 73.29 290.93 - Pass Major Risk S-17-S-17CPB1 -S-17CPB1 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-17-S-17CPB2-S-17CPB2 3,788.77 3,610.00 364.12 73.03 291.19 Pass-Major Risk S-19-S-19-S-19 2,989.26 2,945.00 174.47 46.54 128.00 Pass-Major Risk S-20-S-20-S-20 2,803.96 2,785.00 69.62 47.76 21.88 Pass-Major Risk S-20-S-20A-S-20A 2,803.96 2,785.00 69.62 47.76 21.88 Pass-Major Risk S-21 -S-21 -S-21 2,607.66 2,595.00 93.40 36.37 57.09 Pass-Major Risk S-213-S-213-S-213 6,022.97 6,040.00 386.10 131.08 258.79 Pass-Major Risk S-213-S-213A-S-213A 6,349.66 6,390.00 176.13 121.10 67.95 Pass-Major Risk S-213-S-213AL1 -S-213AL1 6,341.40 6,380.00 177.32 120.07 68.39 Pass-Major Risk S-213-S-213AL1-01 -S-213AL1-01 6,341.40 6,380.00 177.32 120.08 68.38 Pass-Major Risk S-213-3-213AL2-3-213AL2 6,260.58 6,290.00 206.58 117.10 95.31 Pass-Major Risk S-213-S-213AL3-S-213AL3 6,194.36 6,215.00 234.08 114.23 122.47 Pass-Major Risk S-216-S-216-S-216 2,912.75 2,980.00 459.64 60.35 403.31 Pass-Major Risk S-22-S-22-S-22 3,071.57 3,010.00 170.28 43.97 126.38 Pass-Major Risk S-22A-S-22A-S-22A 3,071.25 3,010.00 169.88 43.96 126.01 Pass-Major Risk S-22B-S-22B-S-22B 3,071.25 3,010.00 169.88 43.96 126.01 Pass-Major Risk S-23-S-23-S-23 2,777.18 2,750.00 119.50 36.95 82.63 Pass-Major Risk S-24-S-24-S-24 2,420.43 2,415.00 82.57 32.45 50.17 Pass-Major Risk S-24-S-24A-S-24A 2,422.84 2,415.00 82.60 32.49 50.17 Pass-Major Risk 2/1/2010 2:01:54PM Page 3 of 5 COMPASS 2003.16 Build 71 BPPASSPORT Anticollision Report Company: North America-ALASKA-BP Local Co-ordinate Reference: Well Plan S-129 SL3 Project: Prudhoe Bay TVD Reference: Plan S-129 @ 64.50ft(Nabors XES) Reference-Site: _ PBS Pad MD-References Plan S-129 @ 64.50ft(Nabors XES) Site Error: 0.00ft North Reference: True Reference-Well:- Plan S-129-SL3--- Survey-Calculation Method:----Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore Plan S-129PB1 Database: EDM.16-Anc Prod-WH24P Reference Design: Plan#6 S-129PB1 Offset TVD Reference: Offset Datum Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Wetl--Wellbore-Design (ft} ----- (ft} (ft} Y PB S Pad S-24=S=24B-S-24B 2,422.84 2,415.00 82.60 32.49 50.17 Pass-Major Risk S-25-S-25-S-25 844.67 845.00 45.69 14.25 31.45 Pass-Major Risk S-25-S-25A-S-25A 844.67 845.00 45.69 14.25 31.45 Pass-Major Risk S-25-S-25APB1 -S-25APB1 844.67 845.00 45.69 14.25 31.45 Pass-Major Risk S-26-S-26-S-26 589.58 590.00 14.33 9.28 5.07 Pass-Major Risk S-27-S-27-S-27 453.76 455.00 55.59 8.46 47.13 Pass-Major Risk S-27-S-27A-S-27A 453.76 455.00 55.59 8.46 47.13 Pass-Major Risk S-27-S-27B-S-27B 452.94 455.00 55.57 8.44 47.13 Pass-Major Risk S-28-S-28-S-28 353.90 355.00 93.10 6.86 86.24 Pass-Major Risk S-28-S-28A-S-28A 353.90 355.00 93.10 6.86 86.24 Pass-Major Risk S-28-S-28B-S-28B 355.09 355.00 -93.12 6.87 86.24 Pass-Major Risk S-28-S-28BPB1 -S-28BPB1 355.09 355.00 93.12 6.87 86.24 Pass-Major Risk S-30-S-30-S-30 412.26 415.00 204.10 7.36 196.73 Pass-Major Risk S-31 -S-31 -S-31 384.60 390.00 273.64 6.97 266.67 Pass-Major Risk S-31A-S-31A-S-31A 384.61 390.00 272.99 6.97 266.02 Pass-Major Risk S-33-S-33-S-33 396.11 405.00 311.36 6.91 304.45 Pass-Major Risk 2/1/2010 2:01:54PM Page 4 of 5 COMPASS 2003.16 Build 71 Project: Prudhoe Bay Site: PBS Pad Well: Plan S-129 SL3 Wellbore: Plan S-129PB1 Design: Plan #6 S-129PB1 From Surface to TD Scan interval 100 ft Scale 1 : 50 All wells pass Major Risk 0 •S-22B/S-'+ •s ,, , > f S-231S-23 330 !' } ' -''\ 4.29bo 30 , - 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(4)009:(4 I.=ales CIAl by 0 Schlumberger WELL FIELD STRUCTURE S-129 (P7) Prudhoe Bay Unit -WOA S-PAD Magnetic Parameters Surface Location NAD27 Atasaa Slate Plane.Zone 04.US Feet Mbcellarmrs Model: 8GGM 2009 Ow 80.940' Dale: Odobe127.2010 Lat. N 70 21 12 951 NwlMrg: 597985500 ftUS God Cony:0.91251540' SW: S-129 SL3 TVD Ref: Rotary TaMet86.56 above MSL) Mao Dec'. 21 830' FS. 57698 3n Lon: W 149 1 51 312 Easing 519339.50 11116 Scale Fad'.0.99991818 Plan_ 5129(P1) 5ny Dale:October 27.2010 -5400 -4800 -4200 -3600 -3000 S-1?9PB1(P6) -1800 -1800 ITop Whipstock Base Whipstock S-129PB1(P6) Wifil Cry 22J100/100 90°Pt -2400 CnAl10D • •••EnAC, ' -2400 S-129 Tgt 1 4 End Crir -3000 -3000 A N Z -3600 if -3600 IP 11" 0 co c Cry 4/100 B 6) TO -4200 s-129rgt2 -4200 CO / V V End Cry IR 4800 Cry 4/100 3 -4800 S-129 Tgt3 WIPP. 1 End Ciy 1 -5400 -5400 1 7 TDI4-1/2'taw -6000 -6000 129(• ) • • -5400 -4800 -4200 -3600 -3000 <<< W Scale=1(in):600(ft) E >>> BPPASSPORT Anticollision Report Company: North America-ALASKA-BP Local Co-ordinate Reference: Well Plan S-129 SL3 Project: Prudhoe Bay TVD Reference: Plan S-129 @ 64.50ft(Nabors XES) Reference Site _ PB S Pad MD-Reference: Plan S-129 @ 64.50ft(Nabors XES) Site Error: 0.00ft North Reference: True Reference Well: Plan S-129 SL3 -Survey-Calculation -- Method: Minimum Curvature------Well Error: O.00ft Output errors are at 1.00 sigma Reference Wellbore Plan S-129 Database: EDM.16-Anc Prod-WH24P Reference Design: Plan#7 S-129 Offset TVD Reference: Offset Datum Reference Plan#7 S-129 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of refer( Interpolation Method: MD Intervals 00ft Error Model: ISCWSA Depth Range: 8,905.19 to 13,089.84ft Scan Method: Tray.Cylinder North -Results Limited by: Maximum center-center distance of 1,506.13ft Error Surface: Elliptical Conic Survey Toot Program Date 2/1%2010 From To (ft) (ft) Survey(Wellbore) Tool Name — Description 28.50 700.00 Plan#6 S-129PB1 (Plan S-129PB1) GYD-GC-SS Gyrodata gyro single shots 700.00 3,300.00 Plan#6 S-129PB1 (Plan S-129PB1) MWD+IFR+MS MWD+ IFR+Multi Station 3,300.00 8,905.19 Plan#6 S-129PB1 (Plan S-129PB1) MWD+IFR+MS MWD+ IFR+Multi Station 8,905.19 9,400.00 Plan#T S-129(Plan S-129) MWD MWD-Standard 8,905.19 13,089.84 Plan#7 S-129(Plan S-129) MWD+IFR+MS MWD+IFR+Multi Station Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance fromm an Offset Well-Wellbore-Design (ft) (ft) (ft) (ft) PB S Pad Plan S-129 SL3-Plan S-129PB1 -Plan#6 S-1291 8,929.99 8,930.00 0.66 1.61 -0.85 FAIL-Major Risk Plan xS-129 SL4 do not use-Plan S-129-Plan# 12,724.51 11,925.00 0.24 164.99 -161.90 FAIL-Major Risk Plan xS-129 SL4 do not use-Plan S-129PB1 -Piz 9,433.92 8,650.00 133.60 159.06 -22.58 FAIL-Major Risk S-02-S-02-S-02 Out of range S-02-S-02A-S-02A Out of range S-02-S-02APB1 -S-02APB1 Out of range S-06-S-06-S-06 Out of range S-07-S-07 S-07 Out of range S-07-S-07A-S-07A Out of range S-08-S-08B-S-08B Out of range S-17-S-17-S-17 Out of range S-213-S-213A-S-213A Out of range S-213-S-213AL1 -S-213AL1 Out of range S-213-S-213AL1-01 -S-213AL1-01 Out of range S-213-S-213AL2-S-213AL2 Out of range S-213-S-213AL3-S-213AL3 Out of range S-216-S-216-S-216 Out of range S-27-S-27-S-27 Out of range S-27-S-27A-S-27A Out of range S-27-S-27B-S-27B Out of range S-28-S-28-S-28 Out of range S-28-S-28A-S-28A Out of range S-28-S-28B-S-28B Out of range S-28-S-28BPB1 -S-28BPB1 Out of range S-30-S-30-S-30 Out of range 2/1/2010 3:31:48PM Page 2 of 3 COMPASS 2003.16 Build 71 Project: Prudhoe Bay Site: PB S Pad Well: Plan S-129 SL3 Wellbore: Plan S-129 Design: Plan #7 S-129 From KOP 8905'md to TD Scan interval 50 ft Scale 1 : 50 All wells pass Major Risk Plan S-129 SL3/Plan#6 S-129P81 330 30 917 150 12 9142 10� 300 60 9109 7 9078 5 9041 2 8998 270 �� 90 i 75 i 240 120 100 125 150 210 150 175 180 Travelling Cylinder Azimuth (TFO+AZI)[c']vs Centre to Centre Separation [50 Win] - - -- y - Taiga: n l4geccPrudhoena -_. -- - -- Well:Pi.ns-av-sn -- ---- --------. —.-- Dolling l angel Cont.:9S __— limed on:Planned Program:Plan 11617129— DeaeMhoO: —Wn—waT ithT:b/89.50 ft below Pare fZ4 —. _— .00fF__ _Toca—T+V-S:-224.Ibft —lc aap beefing::14900.00 Map Whng:O 46..16 ft -Ta d I49 62. n Lanmde:70°20'46.146 N _- — Loognde:IJ9°i'1.113 W — Shape:Polygon g points �r Tin � � :. _ _, .� _ r pO T�•T � /i, ..;� ..- .4 C ,w 11 .....,. 1' ...'3' S.TfL-i1'aF�aY4�,Y>rF - ,.. 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Og rn 3 ► ' Irr. ► in I A = • 1/:.`.>,' di co 0 la ______\ a °L c5 JU 1i J 11-1 LTQ Q A w O V 1 1-- f CZ J i/ \ = a 4 hg MM.= \ _ • • m zI J c) �I = o O O O O 8")e —ZN . . � N— nim- • Alaska Department of Natural "esources Land Administration System Page 1 ofd` Alaska Mapper Land Records/Status Plats Recorder's Search State Cabins Natural Resources I- Alaska DNR Case Summary File Type: ADL File Number: 28257 *Printable Case File Summary See Township,Range, Section and Acreage? 0 Yes 0 No [ New Search LAS Menu I Case Abstract I Case Detail I Land Abstract File: ADL 28257 laP Search for Status Plat Updates As of 09/13/2010 Customer: 000107377 BP EXPLORATION(ALASKA)INC PO BOX 196612/900 E. BENSON BL ATTN: LAND MANAGER- ALASKA ANCHORAGE AK 995196612 Case Type: 784 OIL&GAS LEASE COMP DNR Unit: 780 OIL AND GAS File Location: DOG DIV OIL AND GAS Case Status: 35 ISSUED Status Date: 08/11/1965 Total Acres: 2560.000 Date Initiated: 05/28/1965 Office of Primary Responsibility: DOG DIV OIL AND GAS Last Transaction Date: 12/04/2006 Case Subtype: NS NORTH SLOPE Last Transaction: AA-NRB ASSIGNMENT APPROVED Meridian: U Township: 012N Range: 012E Section: 25 Section Acres: 640 Search Plats Meridian: U Township: 012N Range: 012E Section: 26 Section Acres: 640 Meridian: U Township: 012N Range: 012E Section: 35 Section Acres: 640 Meridian: U Township: 012N Range: 012E Section: 36 Section Acres: 640 Legal Description 05-28-1965 ***SALE NOTICE LEGAL DESCRIPTION*** C14-52 12N 12E UM 25,26,35,36 2560.00 04-01-1977*** UNITIZED LEGAL DESCRIPTION*** PRUDHOE BAY UNIT ESTABLISHED T. 12 N., R. 12 E., U.M. http://dnr.alaska.gov/prof ects/las/Case_Summary.cfm?FileType=ADL&FileNumber=2825... 9/13/2010 Alaska Department of Natural R esources Land Administration System Page 1 of/ ( Alaska Mapper Land Records/Status Plats Recorder's Search State Cabins Natural Resources Alaska DNR Case Summary File Type: ADL File Number: 28258 di Printable Case File Summary See Township,Range, Section and Acreage? ( New Search Yes 0 No LAS Menu I Case Abstract I Case Detail I Land Abstract File: ADL 28258 `__�'" Search for Status Plat Updates As of 09/13/2010 Customer: 000107377 BP EXPLORATION(ALASKA)INC PO BOX 196612/900 E. BENSON BL ATTN: LAND MANAGER- ALASKA ANCHORAGE AK 995196612 Case Type: 784 OIL&GAS LEASE COMP DNR Unit: 780 OIL AND GAS File Location: DOG DIV OIL AND GAS Case Status: 35 ISSUED Status Date: 09/14/1965 Total Acres: 2560.000 Date Initiated: 05/28/1965 Office of Primary Responsibility:DOG DIV OIL AND GAS Last Transaction Date: 12/04/2006 Case Subtype: NS NORTH SLOPE Last Transaction: AA-NRB ASSIGNMENT APPROVED Meridian: U Township: 012N Range: 012E Section: 27 Section Acres: 640 Search Plats Meridian: U Township: 012N Range: 012E Section: 28 Section Acres: 640 Meridian: U Township: 012N Range: 012E Section: 33 Section Acres: 640 Meridian: U Township: 012N Range: 012E Section: 34 Section Acres: 640 Legal Description 05-28-1965 ***SALE NOTICE LEGAL DESCRIPTION C14-53 12N 12E UM 27,28,33,34 2560.00 04-01-1977***UNITIZED AND PARTICIPATING AREA LEGAL DESCRIPTION*** ENTIRE LEASE COMMITTED TO PRUDHOE BAY UNIT AND OIL RIM PA PRUDHOE BAY UNIT, TRACT 21,IN ENTIRETY OIL RIM PARTICIPATING AREA http://dnr.alaska.gov/prof ects/las/Case_Summary.cfm?FileType=ADL&FileNumber=2825... 9/13/2010 Alaska Department of Natural Resources Land Administration System Page 1 of 4 Alaska Mapper Land Records/Status Plats Recorder's Search State Cabins Natural Resources Alaska DNR Case Summary File Type: ADL File Number: 28261 6 Printable Case File Summary See Township,Range, Section and Acreage? O Yes Q No New Search LAS Menu I Case Abstract I Case Detail I Land Abstract File: ADL 28261 MaP_ Search for Status Plat Updates As of 09/13/2010 Customer: 000107377 BP EXPLORATION(ALASKA)INC PO BOX 196612/900 E. BENSON BL ATTN: LAND MANAGER- ALASKA ANCHORAGE AK 995196612 Case Type: 784 OIL&GAS LEASE COMP DNR Unit: 780 OIL AND GAS File Location:DOG DIV OIL AND GAS Case Status: 35 ISSUED Status Date: 08/11/1965 Total Acres: 2560.000 Date Initiated: 05/28/1965 Office of Primary Responsibility: DOG DIV OIL AND GAS Last Transaction Date: 12/04/2006 Case Subtype: NS NORTH SLOPE Last Transaction:AA-NRB ASSIGNMENT APPROVED Meridian: U Township: 011N Range: 012E Section: 03 Section Acres: 640 Search Plats Meridian: U Township: 011N Range: 012E Section: 04 Section Acres: 640 Meridian: U Township: 011N Range: 012E Section: 09 Section Acres: 640 Meridian: U Township: 011N Range: 012E Section: 10 Section Acres: 640 Legal Description 05-28-1965 ***SALE NOTICE LEGAL DESCRIPTION C14-56 11N 12E UM 3,4,9,10 2560.00 04-01-1977*** UNITIZED LEGAL DESCRIPTION*** PRUDHOE BAY UNIT TRACT 48 http://dnr.alaska.gov/prof ects/las/Case_Summary.cfm?FileType=ADL&FileNumber=2826... 9/13/2010 TRANSMITTAL LETTER CHECKLIST WELL NAME PTD# V Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: ,e��,c.4dE'Z�}y POOL: ,4e4e, ,eW t2 / OOG . Circle Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name)must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 S • l To (0 0) 0)) a o _0 a) ° O (4 L V C Q C o 7 E a) O) o n > L a w' N co Ii G co E p co 2 V rn vi a) °o ro °- a E 3 0 D o m o m o. 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