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Home My WebLink About196-009CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Stephen Soroka To:Regg, James B (OGC); Wallace, Chris D (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Ryan Thompson; Alaska NS - Wells Integrity Subject:Milne Point, Northstar & Point Thompson July MIT"s Date:Thursday, July 31, 2025 1:26:00 PM Attachments:MIT-IA MPU B-24, B-50 7-20-2025.xlsx MIT-IA MPU B-34 07-16-2025.xlsx MIT-IA MPU E-26 07-21-2025.xlsx MIT-IA MPU R-105 7-4-2025.xlsx MIT-IA NS10, NS32 EPA 07-20-2025.xlsx MIT-IA PTU DW-01 7-20-2025.xlsx All – Attached are recently completed MIT’s performed in July for Milne Point, Northstar and Point Thompson. Well PTD# Comment MPU B-24 1960090 Annual EPA MIT-IA MPU B-34 2161390 Annual EPA MIT-IA/Operable Status change MPU B-50 2042520 Annual EPA MIT-IA MPU E-26 2002060 4-Year MIT-IA MPU R-105 2250170 Initial 4-Year MIT-IA NS-10 2001820 Annual EPA MIT-IA NS-32 2031580 Annual EPA MIT-IA PTU DW-01 2142060 Annual EPA MIT-IA Thank you, Steve Soroka Hilcorp Alaska LLC Field Well Integrity Steve.Soroka@hilcorp.com P: (907) 830-8976 Alt: Chris Casey The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 038% 37' MPU B-24 1960090 Annual EPA MIT-IA Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1960090 Type Inj I Tubing 1055 1056 1052 1050 Type Test P Packer TVD 4364 BBL Pump 5.7 IA 0 3512 3412 3406 Interval O Test psi 3500 BBL Return 3.0 OA 203 251 251 250 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2042520 Type Inj I Tubing 920 918 912 907 Type Test P Packer TVD 3890 BBL Pump 5.4 IA 17 3513 3447 3417 Interval O Test psi 3500 BBL Return 5.0 OA 147 165 163 161 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Milne Point / MPU/ B-pad Witnessed waived by Kam St John. Chris Casey 07/20/25 Notes:Class 1 Disposal Well- MIT-IA. Well injects Slurry. Notes: Notes: Notes: B-24 B-50 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:EPA Class 1 Injection well annual MIT-IA to 3500 psi. Notes:EPA Class 1 Injection well annual MIT-IA to 3500 psi. Notes: Form 10-426 (Revised 01/2017)2025-0720_MIT_MPU_B-24 9 9 9 9 99 9 999 9 9 9 -5HJJ B-24 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250813 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# KBU 24-06RD 50133204990100 206013 4/2/2025 YELLOWJACKET GPT-PERF MPB-24 50029226420000 196009 7/9/2025 READ CaliperSurvey MPB-34 50029235690000 216139 7/7/2025 READ CaliperSurvey MPF-45 50029225560000 195058 7/30/2025 READ CaliperSurvey ODSK-41 50703205850000 208147 8/9/2025 READ CaliperSurvey ODSN-25 50703206560000 212030 6/22/2025 READ CaliperSurvey ODSN-31 50703205650000 208003 8/11/2025 READ CaliperSurvey PBU 06-11A 50029204280100 225042 7/13/2025 BAKER MRPM PBU 13-19 50029206900000 181180 6/4/2025 HALLIBURTON WFL-TMD3D PBU 14-18C 50029205510300 225040 6/24/2025 BAKER MRPM PBU 14-43A 50029222960100 225041 7/30/2025 BAKER MRPM PBU C-01B 50029201210200 212053 7/19/2025 BAKER MRPM SD-07 50133205940000 211050 7/27/2025 YELLOWJACKET SCBL SP 12-S3 50629235130000 214067 7/18/2025 YELLOWJACKET PERF Please include current contact information if different from above. T40771 T40772 T40773 T40774 T40775 T40776 T40777 T40778 T40779 T40780 T40781 T40782 T40783 T40784 MPB-24 50029226420000 196009 7/9/2025 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.15 10:11:56 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Cut Tubing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Install Packer & Tubing Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,584 feet 10,060 & 11,692 feet true vertical 7,934 feet 8,250 feet Effective Depth measured 8,250 feet 7,220 & 7,291 feet true vertical 4,650 feet 4,341 & 4,363 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 4-1/2" 13.5 / L-80 / TSH-625 7,278 4359 Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 / Hydril 521 7,312' 4,370' 7''x 4-1/2'' Tripoint Ret. Packers and SSSV (type, measured and true vertical depth)7” Hyd Set Perm. N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data WDSPL GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: 5,750psi 7,240psi12,066' 7,443' Burst N/A Collapse N/A 3,090psi 5,410psi Casing Conductor 12,066' 4,080'Surface Production 20" 9-5/8" 7" 80' 4,080' measured TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 196-009 50-029-22642-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0047432 & ADL0392703 MILNE POINT / UNDEFINED WDSP, KUPARUK RIVER OIL MILNE PT UNIT B-24 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 110' 520 Size 110' 3,328' 16,031 5330 0 00 1,433 324-426 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Todd Sidoti todd.sidoti@hilcorp.com 907-777-8443 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:28 am, Oct 22, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.10.18 16:32:41 - 08'00' Taylor Wellman (2143) DSR-10/23/24WCB 2-10-2025 RBDMS JSB 103124 _____________________________________________________________________________________ Revised By: TDF 9/19/2024 SCHEMATIC Milne Point Unit Well: MPB-24 Last Completed: 9/6/2024 PTD: 196-009 TD =12,584’ (MD) / TD = 7,934’(TVD) 20” CBL TOC @ 4100’ MD / 3,336’ TVD Orig. KB Elev.: 46’/ GL Elev.: N/A 7” 2 8 9-5/8” Ugnu PBTD =10,060’(MD) / PBTD =5678’(TVD) Calc. TOC @ 10,296’ MD / 5,899’ TVD 1 Plug 1 @ 11,692’ -12,584’ 7 3 TOF @ 8,250’ CTM 5/31/2016 4 5 6 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/ NT-80LHE/ N/A N/A Surface 110’ 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 4,080’ 7" Production 26/ L-80 / BTC 6.276 Surface 12,066’ TUBING DETAIL 4-1/2” Tubing 13.5#/ L-80/ TSH-625 3.920 Surface 7,278’ 4-1/2” Tubing 12.6#/ L-80/ Hydril 521 3.958 7,241’ 7,312’ JEWELRY DETAIL No Depth Item 1 7,220’ 7''x 4-1/2'' Tripoint Retrievable Packer 50K SHEAR 2 7,245’ 4-1/2” X Nipple (3.813” ID) 3 7,266’ 4-1/2” Non-sealing Overshot – Btm @ 7,278’ 4 7,291’ 7” Hyd Set Permanent Packer 5 7,305’ 4-1/2” XN Nipple (3.725” ID) w/ PXN Plug, set 8/17/2024 6 7,311’ WLEG –Btm @ 7,312’ 7 9,164’ HOWCO Type ‘H-ES’ Cementer 8 10,060’ EZSV Plug OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I(Approx.) in 30” Hole 9-5/8" Cmt w/ 802 sks PF “E” (lead), 250 sx Class “G”(tail), 250 sx PF “C”’ (Top Job) in 12-1/4” Hole 7” Cmt w/ 200 sks (1 st Stage) then 250 sks (2nd Stage) Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 74.66 deg. @ 5,824’ MD Hole Angle at perfs ~70° GENERAL WELL INFO API: 50-029-22642-00-00 Drilled and Cased by Nabors 27-E - 2/28/1996 Plugged and Suspended by Nabors 27-E – 3/3/1996 Recompleted by Nordic 3 – 5/10/15 CT FCO - 5/31/2016 Install Packer & Tubing by ASR#1 – 9/6/2024 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu 8,260’ 8,280’ 4,654’ 4,660’ 20 7/6/2015 Open INJECTION ZONE DEPTHS Top of Injection Zone (feet TVD/MD) Base of Injection Zone (feet TVD/MD) Injection Zone Thickness (feet TVD/MD) 3,993’/6,129’ 4,978’/9,083’ 985’/2,954’ Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 ASR#1 50-029-22642-00-00 196-009 9/1/2024 9/30/2024 8/30/2024 - Friday No operations to report. 8/28/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 8/29/2024 - Thursday No operations to report. CONT POOH w/ 4-1/2",12.6#,L, TSH-521 maintaining 1x displacement F/ 950' to cut joint (25.43' OAL - 5.125" OD) Material loss observed on pin end throughout entire string. RIH w/ 6-1/8" x 4-1/2" Dress-off Shoe BHA to TBG stub at 7,240' MD. Establish parameters. Mill over TBG stub F/ 7,240' - T/ 7,248' . Mill top 1' off and swallow 8'. FINAL depths 7,241' - 7,249'. STBY for fluids. No operations to report. 8/31/2024 - Saturday Continue testing BOPE 250/3000psi, Annular 250/2500psi charted 5min - good. POOH w/ 4-1/2",12.6#,L, TSH-521 maintaining 1x displacement F/ 7,210' - T/ 950'. 9/3/2024 - Tuesday 9/1/2024 - Sunday Replace service loop hose and pressure test - good. Function test BOPE - good. Continue RU ASR-1. Rig accepted 21:00 9/1/2024. Begin testing BOPE 250/3000psi, Annular 250/2500psi charted 5min. 9/2/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 ASR#1, SL & WH 50-029-22642-00-00 196-009 9/1/2024 9/30/2024 Pump 100bbls DSL, allow to U-Tube. Drop B&R. Pump down TBG at 2bpm to push B&R, catch pressure after 15bbls away. Pressure up TBG to 3800psi, MIT-T (Pass). MIT-IA to 3,675psi (Pass). Install BPV. Release rig 06:00 9/10/2024. WELLHEAD:Set 4" Bpv from RIG floor with T bar.BOP stack pulled, clean hgr void, install SBMS meatal seal and RX54 gasket. PU and land 4 1/16 tree/adapter, torque to spec and test 500/5000 psi (PASS). Pull Bpv with dry rod, well secured. Multiple Slickline runs to size TBG stub at 7,246' SLM and bail metal debris to 7,254' SLM. (see Slickline log) RD Slickline. Set BPV, RDMO ASR-1. 9/7/2024 - Saturday Slickline Continue working Pump Bailers in TBG stub to 7,253' SLM, Magnets T/ 7,253' SLM. RIH w/ 10'x3" P.Bailer w/ Flapper BTM. Work tools at 7,260' - work thru to 7,273' SLM. RIH W/ 3" LIB and 3.26 centralizer. tagged 7,275' SLM. POOH. had impressions on outer edge. no impression of prong. 24 finger caliper F/ 7,268' to 6,999'. After looking at caliper, decision made to rig down and test BOPs for weekly test. Decision made to set packer in place. Rig down test equipment. Pull TWC. Rig up Slickline. RIH w/ brush to clear X-nipple. Set RHC-M in X-Nipple at 7,221' SLM. RD Slickline. RU LRS and Transport. PT lines to 5000psi. Bring pump on down IA taking returns up TBG to Tiger Tank. Pump 175bbls 9.7ppg KCl w/ CI at 4.5bpm 850psi. 9/10/2024 - Tuesday 9/8/2024 - Sunday Continue RDMO ASR-1. Decision made to continue well w/ rig. RU ASR-1. Hook up HCR lines. Function test BOP. Install spacer spools and flow spool. Hook up fluid lines. Take on fresh water for testing. Pull BPV. Install TWC. Test breaks on Kill and cho ke line 250 low/ 3,000 high. good test. Slickline Continue working Pump Bailers in TBG stub to 7,253' SLM, Magnets T/ 3,714' SLM. 9/9/2024 - Monday 9/6/2024 - Friday RIH w/ 4-1/2",13.5#, L, TSH-625 R3 completion at 48FPM. Displacement returns are as calculated. RIH T/ TBG stub. Unable to see overshot shear initially, work pipe w/ resistance. see shear and no-go. Figure Space-out and inform OE of findings. Decision made to drift into LWR 4-1/2" w/ Slickline. Final PUW = 68k, SOW = 39k. Land hanger, RILDS. RU Slickline and RIH w/ 4-1/2" GS. Latch and pull RHC-M at 7,221' SLM (7,216' MD), POOH. 9/4/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary FWD circ. surf to surf. Establish parameters above stump - 3bpm at 400psi. Park BHA 1' above no-go 3.8bpm at 900psi. 253BBLS total pumped. POOH. LD BHA. Recovered ~2gal metal shavings, 2 slabs of metal in wash pipe. Boot Baskets completly full of shavings. PU/MU 3-1/8" Venturi, XOs, 1JT 2-7/8" PH6, XO Oil Jars. 9/5/2024 - Thursday RIH w/ 3-1/8" Venturi, XOs, 1JT 2-7/8" PH6, XO Oil Jars, 3-1/2" NC31 WS - T/ TBG Stub 7,240'. Establish parameters, work Venturi to T/ 7,265' staying 2' from prong. POOH and LD Venturi - Recovered ~1cup metal shavings. Decision made to set packer in place. Pump 100bbls DSL, allow to U-Tube. Drop B&R. Pump down TBG at 2bpm to push B&R, catch pressure after 15bbls away. Pressure up TBG to 3800psi, MIT-T (Pass). MIT-IA to 3,675psi (Pass). RIH w/ 4-1/2",13.5#, L, TSH-625 R3 completion at 48FPM Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 ASR#1, SL & WH 50-029-22642-00-00 196-009 9/1/2024 9/30/2024 9/13/2024 - Friday RAN 3.50" & 3.60" SWAGES TO RESTRICTION @ 7,231' SLM (see log). 9/11/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary PULLED B&R AND 4 1/2" RHC-M FROM 7,202' SLM / 7,246' MD. RAN 3.25" CENT, 9' x 3.0" PUMP BAILER TO 7,242' SLM (unable to pass restriction). RAN 2.70" CENT, 2.50" PUMP BAILER TO 7,254' SLM (recovered 1cup metal shavings). MADE 2 RUNS W/ 3.75" CENT, 10' STEM, 3.70" LONG TAPPERED SWAGE TO RESTRICTION @ 7,230' SLM (make 15" travel into restriction). RAN 3.75" CENT, 10' STEM, 3.50" CENT TO RESTRICTION @ 7,229' SLM (make 17" travel into restriction). 9/12/2024 - Thursday SWAGE RESTRICTION OUT W/ 3.23" & 3.32" CENT @ 7,233' SLM (~1.5' long restriction). PERFORMED WELL CONTROL / MAN DOWN DRILL W/ CREW. MADE 3 RUNS W/ 3.75" CENT, 10' OF STEM, 3.50" SWAGE TO RESTRICTION @ 7,230' SLM (make 30" of travel). LOST AND RECOVERED OJ FISH THAT CAME APART FROM TOOLSTRING WHILE JARRING @ 7,232' SLM. MADE 3 RUNS W/ 3.65" SWAGE TO RESTRICTION @ 7,230' SLM (worked thru, improving). MADE 2 RUNS W/ 2.30" FLAT MAGNET RESTRICTION AND 7,248' SLM (recovered several big chunks of metal). MADE 3 RUNS W/ 3.70" SWAGE TO RESTRICTION @ 7,230' SLM (make 70" depth). MADE 6 RUNS W/ 3.60" SWAGES TO RESTRICTION @ 7,231' SLM. MADE 2 RUNS W/ 3.55" SWAGE TO RESTRICTION @ 7231' SLM. PERFORMED FIRE / WELL CONTROL DRILL WITH DAY AND NIGHT CREWS 9/14/2024 - Saturday RAN 3.60" & 3.65" SWAGES TO RESTRICTION @ 7,230' SLM (improving). 9/17/2024 - Tuesday 9/15/2024 - Sunday MADE 2 RUNS W/ 3.55" SWAGE TO RESTRICTION @ 7,030' SLM (make 130" depth). RAN 3.41" X-MAGNET W/ ROLLER WHEELS TO 7,243' SLM (lost 2 wheels). FISHED 2 WHEELS AND MISC LARGE METAL DEBRIS FROM 7,252' SLM. MADE 2 RUNS W/ 3.60" SWAGE TO RESTRICTION @ 7,030' SLM (make 130" depth, tight spot from 7,235' to 7,236' slm). 9/16/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 FB & SL 50-029-22642-00-00 196-009 9/1/2024 9/30/2024 9/20/2024 - Friday WORK RESTRICTION AT 7,231' SLM W/ 3.725" SWEDGE. 9/18/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary T/I/O = 109/23/235 MIT-IA 3500 psi, 2.6 bbls diesel to pressure up, 15 min IA lost 118 psi, 30 min IA lost 21 psi, MIT-IA PASS 3564psi, 2.6 bbls recovered FWP = 105/10/238. SWEDGE RESTRICTION @ 7,231' SLM W/ SWEDGES 3.65" UP TO 3.7". 9/19/2024 - Thursday WORK RESTRICTION @ 7,231' SLM W/ 3.70" TO 3.72" SWEDGE. MIRU CTU #2. N/U BOPE to Wellhead and function test BOP rams. Drifted BHA with 3/4" & 5/8" balls. M/U MHA, pull test to 35k and PT to 3500 psi. Test checks. M/U YJ milling BHA and RIH - 3.81" string reamer & 3.81" carbide tapered crayola mill, 3.813" Go / 3.80" No Go. Tagged @ 7,245' ctm. PUH and establish 1:1 returns and free spin. Begin milling obstruction, saw initial motor work 100-200# then fell off with no depth change. Stack weight and no response on circ pressure. POOH to inspect BHA. MPU Well Support tied well back into process,Post-RWO. Added cellar extension,did major dirtwork and locked it all down. PT'd surface lines. Had to skew house on foundation,to allow COIL to R/U. Serviced wellhead 9/21/2024 - Saturday No operations to report. 9/24/2024 - Tuesday 9/22/2024 - Sunday No operations to report. 9/23/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 CT 50-029-22642-00-00 196-009 9/1/2024 9/30/2024 9/27/2024 - Friday Unable to work mill past 7,244.40' E / 7,262' M, 19 total stalls. POOH w/BHA to catch up on fluids and inspect BHA. Mill shows wear on 3.60" - 3.70" tapered OD. M/U milling BHA - 3.625" tapered mill and RIH. Dry tagged 7,247'. Establish 1:1 returns and free spin. Begin milling 7,245.90' E / 7,265' M. Mill down thru 7252' E / 7269' M. POOH. Gauge tapered mill 3.60". MU 3.80" tapered mill. RIH & Dry tagged 7248' E / 7263' M. Try mill and just stack down weight and no motor work. POOH and motor is shot. B/D motor. PT MHA. C/O motors. M/U Milling BHA w/3.72" tapered mill and RIH. Establish free spin and mill through damaged tubing stub 7,244' - 7,248' and break through. Make passes milling / reaming tubing stub 7,240' - 7,250'. Off pump. Dry drift through tubing stub and tagged P-Prong 2k down @ 7,267' E / 7,283' M. POOH w/milling BHA. 9/25/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary POOH to inspect milling BHA, On surface. marks on EOP indicate connector came loose milling and swiveled off pipe. Cut 100' of pipe. M/U YJ fishing BHA & RIH. Tagged @ 7,221' ctm -10k down. Repeat 5 times, saw 4-6k overpull. POOH w/BHA. On surface, recovered all 28.10' of milling BHA. Inspect connector, still tight. Perform weekly BOPE test 300 psi low / 4250 psi high. NU BOPs & function =test. MU BOT milling tool BHA w/ 3.80" String mill and Tapered Mill. RIH. Tagged 7,239' ctm, establish 1:1 returns and free spin 2.5 bpm / 3600 psi. Mill obstruction from 7,239' - 7,246' ctm. Backream. 9/26/2024 - Thursday Bleed IA / OA from thermal. Milled obstruction from 7,239' - 7,246' ctm. Backream. Attempt to mill @ 7,246', no motor work. POOH to inspect BHA. Mills show minimal wear. Swap out string reamer. Function test motor on well. RIH w/milling BHA. 6653' Tag. Pump down to 7200'. RIH dry tag @ 7243.93' CTM / 7259' Mech. mill w/ 12 stalls @ same depths. POOH. BD tapered mill 3.81" go / 3.80" no go / string reamer 3.79" go / 3.78" no go. PT MHA to 3500'. MU Venturi 3.60" w/ two tattle tails (0.56' & 0.83' from btm). RIH @ dry tag @ 7247.5' CTM / 7265' Mech. Work Venturi 7200' - 7247'. POOH w/BHA, recovered 1/2 cup of what appears to be steel bands. M/U & RIH w/BOT milling BHA - 3.81" Tapered Mill. Dry tagged 7,245' ctm. Begin milling. Unable to work mill past 7,244.40' ctm, 19 total stalls. POOH w/milling BHA. On surface, gauge 3.72" mill = 3.71". Upsize mill to tapered 3.81" Go / 3.80" No Go. RIH w/milling BHA. Start milling 7242'. Not making depth. POOH bit trip. MU new 3.80" tapered mill. RIH start mill 7245' E / 7260' M. Mill through 7247'. Reaming passes 7256' - 7200' CTM. Dry drift to P-Prong 7268' E / 7283' M. POOH w/milling BHA. On surface gauge mill = 3.80". Discuss plan foreward w/Wells Foreman. M/U & RIH w/3.50" JDC OS w/1.75" catch. Dry tagged 7268' E / 7283' M. WHP = 500 psi. Unable to latch prong. Repeat. Wash down to prong and no change in circ, not getting over FN. POOH w/BHA. On surface, JDC OS has large chunk of aluminum slip wedged across inside the mule shoe. M/U milling BHA w/3.81" string reamer & 3.60" venturi. RIH w/milling BHA. 9/28/2024 - Saturday Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 CT 50-029-22642-00-00 196-009 9/1/2024 9/30/2024 Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. Continue RIH w/4 G-spear and baited 3.625" Overshot w/1.875" grapple. Tagged 5X 7,272 ctm. POOH w/BHA. Recovered P- Prong. Appears prong FN was dressed off. Bottom of prong broke off. Prong OAL = 91" OAL. RIH w/4-1/2 Hydraulic G-Spear. Latch PXN Plug Body. Jar until came free. POOH. PXN Plug Body recovered (full of metal debri). BD Fishing Tools. Perform Step Rate Injection Test. 1 bpm @ 522 psi, 2 bpm @ 863 psi, & 3 bpm @ 1040 psi. Freeze Protect the Coil w/ 49 bbls diesel and tubing w/ 40 bbls diesel. RDMO CTU2. Travel to GPB. 10/1/2024 - Tuesday 9/29/2024 - Sunday M/U milling BHA & RIH w/3.81" Go / 3.80" No Go string reamer & 3.60" venturi (TT pins). Dry drift clean through tubing stub and tagged 7,267' E / 7,283' M. Work string reamer & venturi passes 7,230' - 7,263'. Dry drift to P-Prong @ 7,267' E / 7,283' M. POOH w/BHA. On surface w/venturi, recovered a 2nd aluminum slip wedge from RWO, TT pins not touched. M/U & RIH w/motor and 3.60" venturi. Dry Tag @ 7266' E / 7284' M. Venturi. Dry tag same depths. POOH. Marks on btm inside end mule shoe. No indication from Tattle tails P-Prong inside. Retrieved another piece of aluminum (matches other three), a set screw, pieces of banding, & brass circle 1-1/2 OD, btm side nub 1" OD. MU 3.60" Venturi w/o tattle tails. RIH. Dry Tag 7268.38' E / 7284' M. Venturi down to 7270.29' E. Dry Tag again 7271.8' (~3' deeper). Venturi again. Dry Tag 3rd time 7273.26 stacked down 8k. POOH. At Surf WHP 190 psi (KWF 9.7) BD Venturi trace of shavings - but flutter cages indicate P- Prong went above and blew out screen. MU & RIH 3.50" JDC OS w/ 1.75" catch. RIH. Tag three times @ 7269.8' E / 7285' M. POOH. No recovery. Re-run JDC while waiting on overshot. No recovery. 9/30/2024 - Monday CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Brooks, Phoebe L (OGC) To:Alaska NS - ASR - Well Site Managers Cc:Regg, James B (OGC) Subject:RE: MPB-24_ASR-1_MIT-T, MIT-IA Test Report, 09/10/2024 Date:Wednesday, October 23, 2024 9:41:03 AM Attachments:MIT MPU B-24 09-10-24 Revised.xlsx Attached is a revised report correcting the formatting and the type of injection as “I” with remarks. Please review and update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Alaska NS - ASR - Well Site Managers <AlaskaNS-ASRWellSiteManagers@hilcorp.com> Sent: Wednesday, September 11, 2024 2:19 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Alaska NS - ASR - Well Site Managers <AlaskaNS-ASRWellSiteManagers@hilcorp.com>; Jess Hall <Jess.Hall@hilcorp.com> Subject: MPB-24_ASR-1_MIT-T, MIT-IA Test Report, 09/10/2024 Please see attached. Thank you, Regards, ASR DSM’s Hilcorp DSM: 907-685-1266 Hilcorp Alaska, LLC Attached is a revised report correcting the formatting and the type of injection as “I” with remarks.Attached is a revised report correcting the formatting and the type of injection as “I” with remarks. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1960090 Type Inj I Tubing 0 3800 3692 3656 Type Test P Packer TVD 4345 BBL Pump 1.2 IA 0 133 137 121 Interval O Test psi 3650 BBL Return 1.2 OA 265 265 265 262 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1960090 Type Inj I Tubing 46 46 50 54 Type Test P Packer TVD 4345 BBL Pump 2.8 IA 6 3710 3570 3546 Interval O Test psi 3500 BBL Return 2.7 OA 259 343 340 333 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: HILCORP ALASKA, LLC MILNE POINT UNIT / MPB-24 A. HABERTHUR / M. HEINZ-BROWN 09/10/24 Notes:CLASS 1 DISPOSAL WELL - MIT-T. Well injects slurry. Notes: Notes: Notes: B-24 B-24 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:CLASS 1 DISPOSAL WELL - MIT-IA. Well injects slurry. Notes: Notes: Form 10-426 (Revised 01/2017)2024-0910_MIT_MPU_B-24_2tests I I CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Ryan Thompson To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Cc:Taylor Wellman; Darci Horner - (C) Subject:MIT-IA"s for Milne Point wells MPB-24, MPJ-45 & MPL-24 Date:Friday, September 27, 2024 3:59:31 PM Attachments:MIT MPU J-45 09-18-24.xlsx MIT MPU B-24 09-18-24.xlsx MIT MPU L-24 9-13-24.xlsx All, Please find attached completed MIT-IA’s for Milne Point wells: MPJ-45 (PTD# 2241040) – 9/18/24 MPB-24 (PTD# 1960090) – 9/18/24 MPL-24 (PTD# 1950700) – 9/13/24 Please let me know if any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MPB-24 (PTD# 1960090) – 9/18/24 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1960090 Type Inj N Tubing 109 755 755 745 Type Test P Packer TVD 4,333'BBL Pump 2.6 IA 23 3703 3585 3564 Interval O Test psi 3500 BBL Return 2.6 OA 235 312 312 310 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: EPA Class 1 injection well MIT-IA to 3500 psi post RWO. AOGCC witness waived by Sully Sullivan. EPA virtual witness by James Robinson. Notes: Hilcorp Alaska, LLC Milne Point / MPU / B Matt Ross 09/18/24 Notes: Notes: Notes: Notes: B-24 Form 10-426 (Revised 01/2017)2024-0918_MIT_MPU_B-24 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/04/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241004 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 214-13 50283201870000 222117 9/26/2024 AK E-LINE Perf END 2-72 50029237810000 224016 8/26/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON RBT MPI 2-16 50029218850000 188134 9/9/2024 AK E-LINE Perf MPI 2-16 50029218850000 188134 9/20/2024 AK E-LINE Perf MPU B-16 50029213840000 185149 9/28/2024 READ CaliperSurvey MPU B-24 50029226420000 196009 8/20/2024 HALLIBURTON PERF MPU B-28 50029235660000 216027 9/28/2024 HALLIBURTON TUBINGCUT MPU I-01 50029220650000 190090 8/17/2024 HALLIBURTON PERF MPU R-103 50029237990000 224114 9/20/2024 AK E-LINE Hoist MRU M-02 50733203890000 187061 9/23/2024 AK E-LINE Perf PBU 02-21B 50029207810200 211033 9/30/2024 HALLIBURTON RBT PBU L2-10 50029217460000 187085 8/23/2024 HALLIBURTON RBT PBU L-212 50029232520000 205030 9/24/2024 HALLIBURTON IPROF PBU L-254 50029237520000 223030 9/20/2024 HALLIBURTON IPROF PBU P1-17 50029223580000 193051 9/7/2024 HALLIBURTON RBT PBU S-09A 50029207710100 214097 8/21/2024 HALLIBURTON RBT PBU Z-235 50029237600000 223055 9/19/2024 HALLIBURTON IPROF Please include current contact information if different from above. T39619 T39620 T39620 T39620 T39621 T39621 T39622 T39623 T39624 T39625 T39626 T39627 T39628 T39629 T39630 T39631 T39632 T39633 T39634 MPU B-24 50029226420000 196009 8/20/2024 HALLIBURTON PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.04 15:10:24 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 9/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240927 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T39593 T39594 T39595 T39596 T39597 T39598 T39599 T39600 T39601 T39602 T39603 T39603 T39604 T39605 T39605 T39605 T39605 T39606 T39606 T39607 T39608 T39609 T39609 T39610 T39611 MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 14:47:28 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Operable: MPB-24 (PTD #1960090) - Passing MIT-IA post RWO Date:Monday, September 23, 2024 8:11:16 AM Attachments:EXTERNAL Re Not Operable MPB-24 (PTD #1960090) - IA Pressure Increase.msg From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Friday, September 20, 2024 11:18 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Operable: MPB-24 (PTD #1960090) - Passing MIT-IA post RWO Mr. Wallace, Class 1 Disposal Well MPB-24 (PTD# 1960090) had a RWO performed to replace tubing, with a passing MIT-IA to 3546 psi on 9/10/24 on rig. A post rig passing MIT-IA was performed with EPA virtual witness on 9/18/24 to 3564. The well is now classified as OPERABLE and will be brought on injection once the tubing tail plug is recovered by slickline. Per AOGCC agreement in the attached email, an online MIT-IA post injection start up will not be performed based on passing MIT-IA’s on rig and post rig. Please respond with any questions, Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, July 8, 2024 3:44 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, On 7/7/24, on Disposal Well MPB-24 (PTD# 1960090) MPU Field Operations received a high inner annulus (IA) pressure alarm, and subsequently confirmed that while injecting slurry, the pressure of the inner annulus increased rapidly, breaking the normal trend. Field Operations then verified that the pressure on the outer annulus (OA) was still within the normal operating parameters. The wellbore was flushed with clean water, then injection was shut down and the well shut in. Field Operations immediately began monitoring shut in pressures on the tubing, IA and OA. Based on the information observed thus far where the tubing and inner annulus pressure track each other, Hilcorp believes that communication exists between the injection tubing and IA. Hilcorp is investigating the anomaly and once the source of communication is identified a repair plan will be developed. The well will remain shut in with no injection until the well is repaired. The well is now classified as NOT OPERABLE. A PPPOT-T passed to 5000 psi after the well was shut in. EPA notification has been made. Attached is a wellbore schematic and 90 day TIO plot. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Alaska NS - ASR - Well Site Managers To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Cc:Alaska NS - ASR - Well Site Managers; Jess Hall Subject:MPB-24_ASR-1_MIT-T, MIT-IA Test Report, 09/10/2024 Date:Wednesday, September 11, 2024 2:19:20 AM Attachments:MPB-24_ASR-1_MIT-1_MIT-IA_09-10-2024.xlsx Please see attached. Thank you, Regards, ASR DSM’s Hilcorp DSM: 907-685-1266 Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 196-009 Type Inj S Tubing 0 3800 3692 3656 Type Test P Packer TVD 4345 BBL Pump 1.2 IA 0 133 137 121 Interval I Test psi 3650 BBL Return 1.2 OA 265 265 265 262 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 196-009 Type Inj S Tubing 46 46 50 54 Type Test P Packer TVD 4345 BBL Pump 2.8 IA 6 3710 3570 3546 Interval I Test psi 3500 BBL Return 2.7 OA 259 343 340 333 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: HILCORP ALASKA, LLC MILNE POINT UNIT / MPB-24 A. HABERTHUR / M. HEINZ-BROWN 09/10/24 Notes:CLASS 1 DISPOSAL WELL - MIT-T Notes: Notes: Notes: MPB-24 MPB-24 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:CLASS 1 DISPOSAL WELL - MIT-IA Notes: Notes: Form 10-426 (Revised 01/2017)2024-0910_MIT_MPU_B-24_2tests CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Wallace, Chris D (OGC) To:Ryan Thompson Subject:[EXTERNAL] Re: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Date:Thursday, September 5, 2024 3:47:27 PM Ryan, For 1. AOGCC should be notified and told about the EPA witnessing option up next so AOGCC inspectors have opportunity to waive witness. For 2. AOGCC will probably defer to the EPA witness and waive witness although in some cases where EPA is remote witnessing we may witness. For 3. AOGCC will be OK with the #2 EPA offline test if it passes without concern, so we wouldn't require an injecting MIT. The Sundry also doesn't have the initial MIT checked. Thanks Chris From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, September 5, 2024 2:38:40 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, We are currently in progress on a RWO to replace the tubing on MPB-24, Class 1 disposal well under sundry 324-426. 1. We will perform a MIT-IA to 3500 psi, providing AOGCC notification for witness on rig post packer set per the sundry. 10-426 will be submitted. 2. Once the rig is RDMO, we will perform a 3500 psi MIT-IA that will be virtually witnessed by EPA, with AOGCC notification to witness. 10-426 will be submitted. This will be an offline test at EPA preference. 3. Question: Does AOGCC require an online test to 3500 psi once the well is placed on injection in addition to test #2? Please let me know if the online test is required. Attached is a copy of the sundry for reference. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, July 8, 2024 3:44 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, On 7/7/24, on Disposal Well MPB-24 (PTD# 1960090) MPU Field Operations received a high inner annulus (IA) pressure alarm, and subsequently confirmed that while injecting slurry, the pressure of the inner annulus increased rapidly, breaking the normal trend. Field Operations then verified that the pressure on the outer annulus (OA) was still within the normal operating parameters. The wellbore was flushed with clean water, then injection was shut down and the well shut in. Field Operations immediately began monitoring shut in pressures on the tubing, IA and OA. Based on the information observed thus far where the tubing and inner annulus pressure track each other, Hilcorp believes that communication exists between the injection tubing and IA. Hilcorp is investigating the anomaly and once the source of communication is identified a repair plan will be developed. The well will remain shut in with no injection until the well is repaired. The well is now classified as NOT OPERABLE. A PPPOT-T passed to 5000 psi after the well was shut in. EPA notification has been made. Attached is a wellbore schematic and 90 day TIO plot. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Date:Friday, September 6, 2024 9:12:11 AM From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, September 5, 2024 3:47 PM To: Ryan Thompson <Ryan.Thompson@hilcorp.com> Subject: Re: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Ryan, For 1. AOGCC should be notified and told about the EPA witnessing option up next so AOGCC inspectors have opportunity to waive witness. For 2. AOGCC will probably defer to the EPA witness and waive witness although in some cases where EPA is remote witnessing we may witness. For 3. AOGCC will be OK with the #2 EPA offline test if it passes without concern, so we wouldn't require an injecting MIT. The Sundry also doesn't have the initial MIT checked. Thanks Chris From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, September 5, 2024 2:38:40 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, We are currently in progress on a RWO to replace the tubing on MPB-24, Class 1 disposal well under sundry 324-426. 1. We will perform a MIT-IA to 3500 psi, providing AOGCC notification for witness on rig post packer set per the sundry. 10-426 will be submitted. 2. Once the rig is RDMO, we will perform a 3500 psi MIT-IA that will be virtually witnessed by EPA, with AOGCC notification to witness. 10-426 will be submitted. This will be an offline test at EPA preference. 3. Question: Does AOGCC require an online test to 3500 psi once the well is placed on injection in addition to test #2? Please let me know if the online test is required. Attached is a copy of the sundry for reference. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, July 8, 2024 3:44 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, On 7/7/24, on Disposal Well MPB-24 (PTD# 1960090) MPU Field Operations received a high inner annulus (IA) pressure alarm, and subsequently confirmed that while injecting slurry, the pressure of the inner annulus increased rapidly, breaking the normal trend. Field Operations then verified that the pressure on the outer annulus (OA) was still within the normal operating parameters. The wellbore was flushed with clean water, then injection was shut down and the well shut in. Field Operations immediately began monitoring shut in pressures on the tubing, IA and OA. Based on the information observed thus far where the tubing and inner annulus pressure track each other, Hilcorp believes that communication exists between the injection tubing and IA. Hilcorp is investigating the anomaly and once the source of communication is identified a repair plan will be developed. The well will remain shut in with no injection until the well is repaired. The well is now classified as NOT OPERABLE. A PPPOT-T passed to 5000 psi after the well was shut in. EPA notification has been made. Attached is a wellbore schematic and 90 day TIO plot. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Date:Friday, September 6, 2024 9:12:11 AM Attachments:MP B-24 AOGCC 10-403 APPROVAL 7-31-2024.pdf From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, September 5, 2024 2:38 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, We are currently in progress on a RWO to replace the tubing on MPB-24, Class 1 disposal well under sundry 324-426. 1. We will perform a MIT-IA to 3500 psi, providing AOGCC notification for witness on rig post packer set per the sundry. 10-426 will be submitted. 2. Once the rig is RDMO, we will perform a 3500 psi MIT-IA that will be virtually witnessed by EPA, with AOGCC notification to witness. 10-426 will be submitted. This will be an offline test at EPA preference. 3. Question: Does AOGCC require an online test to 3500 psi once the well is placed on injection in addition to test #2? Please let me know if the online test is required. Attached is a copy of the sundry for reference. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, July 8, 2024 3:44 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, On 7/7/24, on Disposal Well MPB-24 (PTD# 1960090) MPU Field Operations received a high inner annulus (IA) pressure alarm, and subsequently confirmed that while injecting slurry, the pressure of the inner annulus increased rapidly, breaking the normal trend. Field Operations then verified that the pressure on the outer annulus (OA) was still within the normal operating parameters. The wellbore was flushed with clean water, then injection was shut down and the well shut in. Field Operations immediately began monitoring shut in pressures on the tubing, IA and OA. Based on the information observed thus far where the tubing and inner annulus pressure track each other, Hilcorp believes that communication exists between the injection tubing and IA. Hilcorp is investigating the anomaly and once the source of communication is identified a repair plan will be developed. The well will remain shut in with no injection until the well is repaired. The well is now classified as NOT OPERABLE. A PPPOT-T passed to 5000 psi after the well was shut in. EPA notification has been made. Attached is a wellbore schematic and 90 day TIO plot. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Cut Tubing Other: Install Packer & Tubing 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,584'8,250' Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Wells Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7" Hyd Set Perm Pkr and N/A 7,291'MD/ 4,363'TVD and N/A Todd Sidoti todd.sidoti@hilcorp.com 777-8443 Perforation Depth MD (ft): See Schematic See Schematic 4-1/2" 80' 20" 9-5/8" 7" 4,080' 12,066' MD N/A 5,750psi 7,240psi 3,328' 7,443' 4,080' 12,066' Length Size Proposed Pools: 110' 110' 12.6# / L-80 / Hydril 521 TVD Burst 7,312' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047432 & ADL0392703 196-009 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22642-00-00 Hilcorp Alaska LLC 20 AAC 25.055 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 8/5/2024 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT B-24 MILNE POINT UNDEFINED WDSP, KUPARUK RIVER OIL N/A 7,934' 8,250' 4,650' 2,629 10,060' & 11,692' No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.07.23 12:52:57 - 08'00' Taylor Wellman (2143) 324-426 By Grace Christianson at 2:09 pm, Jul 23, 2024 MGR26JUL24 DSR-7/29/24SFD 7/29/2024 * BOPE test to 3000 psi. Annular to 2500 psi. * Hilcorp to assure EPA approval. * Variance to 20 AAC 2.412(b) approved for packer placement > 200' MD above top of perforations. * MIT-IA required every 4 years * MIT- IA after setting packer. 24 hour notice for AOGCC opportunity to witness.10-407 CDW 07/25/2024 2,6292,629 Class I (EPA) *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.31 14:53:09 -08'00'07/31/24 RWO – Tubing Swap Well: MPU B-24 Date: 18 July 2024 Well Name: MPU B-24 API Number: 50-029-22642-00-00 Current Status: SI Injector [T x IA] Pad: B-Pad Estimated Start Date: August 5, 2024 Rig: ASR 1 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 202-173 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Ryan Lewis (303) 906-5178 (M) Current Bottom Hole Pressure: 3094 psi @ 4654’ TVD Full fluid column, 1000 psi at surface| 12.8 PPGE MPSP: 2629 psi Gas Column Gradient (0.1 psi/ft) 70° Inclination: 4782’ Min Restriction: 3.725” @ 7305’ XN Brief Well Summary: MPU B-24 is a Class 1 disposal well that suddenly developed T x IA communication in July 2024. A caliper was run in the well and showed damaged tubing from 5000’-5320’. The objective of this project is to repair the T-IA communication. Notes Regarding Wellbore Condition x MIT-IA Passed to 3500 psig on 7/20/2023. x Caliper ran 7/17/24 demonstrated damaged tubing from 5000’-5320’. x Slickline is having good progress swaging the damaged tubing open as of 7/23/24. x This program assumes that a plug is set in the tubing tail and the well is secured Objective: Pull 4-1/2” upper completion, install a 4-1/2” heavy wall completion and return well to disposal. Pre-Rig Procedure (No sundry required): Eline & Fullbore 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU reverse out skid and 500 bbl returns tank. 4. MIRU eline and pressure test PCE to 250 psi low / 3000 psi high. 5. RIH with mechanical tubing cutter. 6. Cut tubing in middle of first full joint above packer at ~7270’. POOH and RDMO eline. 7. Circulate 250 bbls KWF down tubing, taking returns up casing to 500 bbl returns tank. 8. Confirm well is dead. Well will remain full of KWF, no freeze protection is required. 9. RD fullbore pumpers and reverse out skid. 10. RU crane. Set BPV. ND tree and tubing head adapter. NU BOPE. 11. NU BOPE house. Spot mud boat. RWO – Tubing Swap Well: MPU B-24 Date: 18 July 2024 Brief RWO Procedure (Sundry Approval Required): 12. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines. 13. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ KWF prior to setting CTS. 14. Test BOPE to 250 psi Low/ 3000 psi High, annular to 250 psi Low/ 2500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams and annular on 3-1/2” and 4-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV, run lubricator as required for pressure management. 16. MU landing joint or spear, PU and recover tubing hanger. a. Recorded PU weight was 105k and SO was 80k with 35k blocks. 17. POOH and lay down the 4-1/2” tubing. 18. PU new 4-1/2” completion and run: A 4-1/2” Non-Sealing Overshot with Dual Pins @ ~7270’ Pup Joint, 4-1/2" B Pup Joint, 4-1/2” 4-1/2” XN Nipple with RHC Installed Pup Joint, 4-1/2” C Pup Joint, 4-1/2" 7” x 4-1/2” Packer @ ~7225’ Pup Joint, 4-1/2" D Pup Joint, 4-1/2” 4-1/2” Sliding Sleeve (Closed) Pup Joint, 4-1/2” ~180 Joints Tubing, 4-1/2" 19. Shear out on 4.5” tubing stub at 7,270’. Space out and land tubing hanger. Note pickup and slack- off weights on tally. 20. Drop ball & rod and pressure up on tubing to set packer as per manufacturer procedures. Perform MIT-T to 3650 psi for 30 minutes charted. Perform MIT-IA to 3500 psi for 30 minutes charted. 21. Set BPV. Post-Rig Procedure: Slickline, Fullbore & Well Support 22. RD mud boat. RD BOPE house. Move to next well location. - 24 hour notice to AOGCC for opportunity to witness. - mgr RWO – Tubing Swap Well: MPU B-24 Date: 18 July 2024 23. RU crane. ND BOPE. 24. NU 4-1/16” 5M tree. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 25. RD crane. Move 500 bbl returns tank and rig mats to next well location. 26. MIRU fullbore and rig up a choke manifold to enable reverse circulating and to allow us to choke returns to the brine storage upright. 27. MIRU SL, PT lubricator to 250 psi low / 3000 psi high. 28. RIH and open sliding sleeve. POOH. 29. Reverse out KWF to upright. a. Pump 136 bbls inhibited water down the IA with FOC on returns. b. At 136 bbls down IA the tubing will be full of KWF and the IA will be full of water, making us overbalanced by ~1900 psi. c. The next 109 bbls will to be reversed out using the driller’s method to keep the BHP static and recover all KWF. d. FP tubing and IA at WSL discretion. 30. Close sliding sleeve. 31. Perform MIT-IA to 3500 psi for 30 minutes charted. 32. Pull Ball & Rod and RHC plug from 4-1/2” XN. 33. Pull plug from tubing tail. 34. RDMO SL. 35. Turn well over to production. RU well house and flowlines. ATTACHMENTS: 1. Current wellbore schematic 2. Proposed wellbore schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: STP 6/29/2016 SCHEMATIC Milne Point Unit Well: MPB-24 Last Completed: 7/6/2015 PTD: 196-009 TD =12,584’ (MD) / TD = 7,934’(TVD) 20” CBL TOC @ 4100’ MD / 3,336’ TVD Orig. KB Elev.: 46’/ GL Elev.: N/A 7” 2 5 9-5/8” Ugnu MF PBTD = 10,060’(MD) / PBTD =5678’(TVD) Cal c. TOC @ 10,296’ MD / 5,899’ TVD 1 Plug 1 @ 11,692’ -12,584’ 4 3TOF @ 8,250’ CTM 5/31/2016 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/ NT-80LHE/ N/A N/A Surface 110’ 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 4,080’ 7" Production 26/ L-80 / BTC 6.276 Surface 12,066’ TUBING DETAIL 4-1/2” Tubing 12.6#/ L-80/ Hydril 521 3.958 Surface 7,312’ JEWELRY DETAIL No Depth Item 1 7,291’ 7” Hyd Set Permanent Packer 2 7,305’ XN Nipple (3.725” ID) 3 7,311’ WLEG 4 9,164’ HOWCO Type ‘ H-ES’ Cementer 5 10,060’ EZSV Plug OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I(Approx.) in 30” Hole 9-5/8" Cmt w/ 802 sks PF “E” (lead), 250 sx Class “G”(tail), 250 sx PF “C”’ (Top Job) in 12-1/4” Hole 7” Cmt w/ 200 sks (1 st Stage) then 250 sks (2 nd Stage) Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 74.66 deg. @ 5,824’ MD Hole Angle at perfs ~70° GENERAL WELL INFO API: 50-029-22642-00-00 Drilled and Cased by Nabors 27-E - 2/28/1996 Plugged and Suspended by Nabors 27-E – 3/3/1996 Recompleted by Nordic 3 – 5/10/15 CT FCO - 5/31/2016 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu MF 8,260’ 8,280’ 4,654’ 4,660’ 20 7/6/2015 Open _____________________________________________________________________________________ Revised By: TDF 7/23/2024 PROPOSED SCHEMATIC Milne Point Unit Well: MPB-24 Last Completed: 7/6/2015 PTD: 196-009 TD =12,584’ (MD) / TD = 7,934’(TVD) 20” CBL TOC @ 4100’ MD / 3,336’ TVD Orig. KB Elev.: 46’/ GL Elev.: N/A 7” 3 9 9-5/8” Ugnu PBTD =10,060’(MD) / PBTD =5678’(TVD) Calc. TOC @ 10,296’ MD / 5,899’ TVD 2 Plug 1 @ 11,692’ -12,584’ 8 4 TOF @ 8,250’ CTM 5/31/2016 5 6 7 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/ NT-80LHE/ N/A N/A Surface 110’ 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 4,080’ 7" Production 26/ L-80 / BTC 6.276 Surface 12,066’ TUBING DETAIL 4-1/2” Tubing 13.5#/ L-80/ Hydril 625 3.920 Surface ~7,270’ 4-1/2” Tubing 12.6#/ L-80/ Hydril 521 3.958 ~7,270’ 7,312’ JEWELRY DETAIL No Depth Item 1 ~7,205 Sliding Sleeve 2 ~7,225 7” X 4-1/2” Hydraulic Packer 3 ~7,245 4-1/2” X Nipple (3.813” ID) 4 ~7,270’ 4-1/2” Non-sealing Overshot 5 7,291’ 7” Hyd Set Permanent Packer 6 7,305’ 4-1/2” XN Nipple (3.725” ID) 7 7,311’ WLEG –Btm @ 7,312’ 8 9,164’ HOWCO Type ‘H-ES’ Cementer 9 10,060’ EZSV Plug OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I(Approx.) in 30” Hole 9-5/8" Cmt w/ 802 sks PF “E” (lead), 250 sx Class “G”(tail), 250 sx PF “C”’ (Top Job) in 12-1/4” Hole 7” Cmt w/ 200 sks (1 st Stage) then 250 sks (2nd Stage) Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 74.66 deg. @ 5,824’ MD Hole Angle at perfs ~70° GENERAL WELL INFO API: 50-029-22642-00-00 Drilled and Cased by Nabors 27-E - 2/28/1996 Plugged and Suspended by Nabors 27-E – 3/3/1996 Recompleted by Nordic 3 – 5/10/15 CT FCO - 5/31/2016 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu 8,260’ 8,280’ 4,654’ 4,660’ 20 7/6/2015 Open INJECTION ZONE DEPTHS Top of Injection Zone (feet TVD/MD) Base of Injection Zone (feet TVD/MD) Injection Zone Thickness (feet TVD/MD) 3,993’/6,129’ 4,978’/9,083’ 985’/2,954’ Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30' Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 8/7/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240807 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# END 2-72 50029237810000 224016 6/27/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON RBT END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON TEMP END 2-74 50029237850000 224024 7/20/2024 HALLIBURTON MFC MPU B-24 50029226420000 196009 7/16/2024 HALLIBURTON MFC MPU E-19A 50029227460100 224010 6/22/2024 HALLIBURTON COILFLAG NS-10 50029229850000 200182 7/18/2024 HALLIBURTON MFC NS-10 50029229850000 200182 7/18/2024 HALLIBURTON TEMP NS-32 50029231790000 203158 7/16/2024 HALLIBURTON MFC NS-32 50029231790000 203158 7/15/2024 HALLIBURTON TEMP PBU H-13A 50029205590100 209044 7/23/2024 HALLIBURTON RBT PBU L-246 50029237650000 223078 7/23/2024 HALLIBURTON IPROF PBU R-26B 50029215470100 210025 7/5/2024 HALLIBURTON RBT PBU R-36 50029225220000 194144 6/21/2024 HALLIBURTON RBT PBU V-216 50029232160000 204130 7/11/2024 HALLIBURTON IPROF PBU V-217 50029233340000 206162 7/11/2024 HALLIBURTON IPROF Please include current contact information if different from above. T39365 T39365 T39365 T39366 T39367 T39368 T39369 T39369 T39370 T39370 T39371 T39372 T39373 T39374 T39375 T39376 MPU B-24 50029226420000 196009 7/16/2024 HALLIBURTON MFC Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.07 13:19:30 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Cut Tubing Other: Install Packer & Tubing 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,584'8,250' Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Wells Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7" Hyd Set Perm Pkr and N/A 7,291'MD/ 4,363'TVD and N/A Todd Sidoti todd.sidoti@hilcorp.com 777-8443 Perforation Depth MD (ft): See Schematic See Schematic 4-1/2" 80' 20" 9-5/8" 7" 4,080' 12,066' MD N/A 5,750psi 7,240psi 3,328' 7,443' 4,080' 12,066' Length Size Proposed Pools: 110' 110' 12.6# / L-80 / Hydril 521 TVD Burst 7,312' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047432 & ADL0392703 196-009 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22642-00-00 Hilcorp Alaska LLC 20 AAC 25.055 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 8/5/2024 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT B-24 MILNE POINT UNDEFINED WDSP, KUPARUK RIVER OIL N/A 7,934' 8,250' 4,650' 2,629 10,060' & 11,692' No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.07.23 12:52:57 - 08'00' Taylor Wellman (2143) 324-426 By Grace Christianson at 2:09 pm, Jul 23, 2024 MGR26JUL24 DSR-7/29/24SFD 7/29/2024 * BOPE test to 3000 psi. Annular to 2500 psi. * Hilcorp to assure EPA approval. * Variance to 20 AAC 2.412(b) approved for packer placement > 200' MD above top of perforations. * MIT-IA required every 4 years * MIT- IA after setting packer. 24 hour notice for AOGCC opportunity to witness.10-407 CDW 07/25/2024 2,6292,629 Class I (EPA) *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.31 14:53:09 -08'00'07/31/24 RBDMS JSB 080224 RWO – Tubing Swap Well: MPU B-24 Date: 18 July 2024 Well Name: MPU B-24 API Number: 50-029-22642-00-00 Current Status: SI Injector [T x IA] Pad: B-Pad Estimated Start Date: August 5, 2024 Rig: ASR 1 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 202-173 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Ryan Lewis (303) 906-5178 (M) Current Bottom Hole Pressure: 3094 psi @ 4654’ TVD Full fluid column, 1000 psi at surface| 12.8 PPGE MPSP: 2629 psi Gas Column Gradient (0.1 psi/ft) 70° Inclination: 4782’ Min Restriction: 3.725” @ 7305’ XN Brief Well Summary: MPU B-24 is a Class 1 disposal well that suddenly developed T x IA communication in July 2024. A caliper was run in the well and showed damaged tubing from 5000’-5320’. The objective of this project is to repair the T-IA communication. Notes Regarding Wellbore Condition x MIT-IA Passed to 3500 psig on 7/20/2023. x Caliper ran 7/17/24 demonstrated damaged tubing from 5000’-5320’. x Slickline is having good progress swaging the damaged tubing open as of 7/23/24. x This program assumes that a plug is set in the tubing tail and the well is secured Objective: Pull 4-1/2” upper completion, install a 4-1/2” heavy wall completion and return well to disposal. Pre-Rig Procedure (No sundry required): Eline & Fullbore 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU reverse out skid and 500 bbl returns tank. 4. MIRU eline and pressure test PCE to 250 psi low / 3000 psi high. 5. RIH with mechanical tubing cutter. 6. Cut tubing in middle of first full joint above packer at ~7270’. POOH and RDMO eline. 7. Circulate 250 bbls KWF down tubing, taking returns up casing to 500 bbl returns tank. 8. Confirm well is dead. Well will remain full of KWF, no freeze protection is required. 9. RD fullbore pumpers and reverse out skid. 10. RU crane. Set BPV. ND tree and tubing head adapter. NU BOPE. 11. NU BOPE house. Spot mud boat. RWO – Tubing Swap Well: MPU B-24 Date: 18 July 2024 Brief RWO Procedure (Sundry Approval Required): 12. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines. 13. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ KWF prior to setting CTS. 14. Test BOPE to 250 psi Low/ 3000 psi High, annular to 250 psi Low/ 2500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams and annular on 3-1/2” and 4-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV, run lubricator as required for pressure management. 16. MU landing joint or spear, PU and recover tubing hanger. a. Recorded PU weight was 105k and SO was 80k with 35k blocks. 17. POOH and lay down the 4-1/2” tubing. 18. PU new 4-1/2” completion and run: A 4-1/2” Non-Sealing Overshot with Dual Pins @ ~7270’ Pup Joint, 4-1/2" B Pup Joint, 4-1/2” 4-1/2” XN Nipple with RHC Installed Pup Joint, 4-1/2” C Pup Joint, 4-1/2" 7” x 4-1/2” Packer @ ~7225’ Pup Joint, 4-1/2" D Pup Joint, 4-1/2” 4-1/2” Sliding Sleeve (Closed) Pup Joint, 4-1/2” ~180 Joints Tubing, 4-1/2" 19. Shear out on 4.5” tubing stub at 7,270’. Space out and land tubing hanger. Note pickup and slack- off weights on tally. 20. Drop ball & rod and pressure up on tubing to set packer as per manufacturer procedures. Perform MIT-T to 3650 psi for 30 minutes charted. Perform MIT-IA to 3500 psi for 30 minutes charted. 21. Set BPV. Post-Rig Procedure: Slickline, Fullbore & Well Support 22. RD mud boat. RD BOPE house. Move to next well location. - 24 hour notice to AOGCC for opportunity to witness. - mgr RWO – Tubing Swap Well: MPU B-24 Date: 18 July 2024 23. RU crane. ND BOPE. 24. NU 4-1/16” 5M tree. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 25. RD crane. Move 500 bbl returns tank and rig mats to next well location. 26. MIRU fullbore and rig up a choke manifold to enable reverse circulating and to allow us to choke returns to the brine storage upright. 27. MIRU SL, PT lubricator to 250 psi low / 3000 psi high. 28. RIH and open sliding sleeve. POOH. 29. Reverse out KWF to upright. a. Pump 136 bbls inhibited water down the IA with FOC on returns. b. At 136 bbls down IA the tubing will be full of KWF and the IA will be full of water, making us overbalanced by ~1900 psi. c. The next 109 bbls will to be reversed out using the driller’s method to keep the BHP static and recover all KWF. d. FP tubing and IA at WSL discretion. 30. Close sliding sleeve. 31. Perform MIT-IA to 3500 psi for 30 minutes charted. 32. Pull Ball & Rod and RHC plug from 4-1/2” XN. 33. Pull plug from tubing tail. 34. RDMO SL. 35. Turn well over to production. RU well house and flowlines. ATTACHMENTS: 1. Current wellbore schematic 2. Proposed wellbore schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: STP 6/29/2016 SCHEMATIC Milne Point Unit Well: MPB-24 Last Completed: 7/6/2015 PTD: 196-009 TD =12,584’ (MD) / TD = 7,934’(TVD) 20” CBL TOC @ 4100’ MD / 3,336’ TVD Orig. KB Elev.: 46’/ GL Elev.: N/A 7” 2 5 9-5/8” Ugnu MF PBTD = 10,060’(MD) / PBTD =5678’(TVD) Cal c. TOC @ 10,296’ MD / 5,899’ TVD 1 Plug 1 @ 11,692’ -12,584’ 4 3TOF @ 8,250’ CTM 5/31/2016 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/ NT-80LHE/ N/A N/A Surface 110’ 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 4,080’ 7" Production 26/ L-80 / BTC 6.276 Surface 12,066’ TUBING DETAIL 4-1/2” Tubing 12.6#/ L-80/ Hydril 521 3.958 Surface 7,312’ JEWELRY DETAIL No Depth Item 1 7,291’ 7” Hyd Set Permanent Packer 2 7,305’ XN Nipple (3.725” ID) 3 7,311’ WLEG 4 9,164’ HOWCO Type ‘ H-ES’ Cementer 5 10,060’ EZSV Plug OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I(Approx.) in 30” Hole 9-5/8" Cmt w/ 802 sks PF “E” (lead), 250 sx Class “G”(tail), 250 sx PF “C”’ (Top Job) in 12-1/4” Hole 7” Cmt w/ 200 sks (1 st Stage) then 250 sks (2 nd Stage) Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 74.66 deg. @ 5,824’ MD Hole Angle at perfs ~70° GENERAL WELL INFO API: 50-029-22642-00-00 Drilled and Cased by Nabors 27-E - 2/28/1996 Plugged and Suspended by Nabors 27-E – 3/3/1996 Recompleted by Nordic 3 – 5/10/15 CT FCO - 5/31/2016 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu MF 8,260’ 8,280’ 4,654’ 4,660’ 20 7/6/2015 Open _____________________________________________________________________________________ Revised By: TDF 7/23/2024 PROPOSED SCHEMATIC Milne Point Unit Well: MPB-24 Last Completed: 7/6/2015 PTD: 196-009 TD =12,584’ (MD) / TD = 7,934’(TVD) 20” CBL TOC @ 4100’ MD / 3,336’ TVD Orig. KB Elev.: 46’/ GL Elev.: N/A 7” 3 9 9-5/8” Ugnu PBTD =10,060’(MD) / PBTD =5678’(TVD) Calc. TOC @ 10,296’ MD / 5,899’ TVD 2 Plug 1 @ 11,692’ -12,584’ 8 4 TOF @ 8,250’ CTM 5/31/2016 5 6 7 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/ NT-80LHE/ N/A N/A Surface 110’ 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 4,080’ 7" Production 26/ L-80 / BTC 6.276 Surface 12,066’ TUBING DETAIL 4-1/2” Tubing 13.5#/ L-80/ Hydril 625 3.920 Surface ~7,270’ 4-1/2” Tubing 12.6#/ L-80/ Hydril 521 3.958 ~7,270’ 7,312’ JEWELRY DETAIL No Depth Item 1 ~7,205 Sliding Sleeve 2 ~7,225 7” X 4-1/2” Hydraulic Packer 3 ~7,245 4-1/2” X Nipple (3.813” ID) 4 ~7,270’ 4-1/2” Non-sealing Overshot 5 7,291’ 7” Hyd Set Permanent Packer 6 7,305’ 4-1/2” XN Nipple (3.725” ID) 7 7,311’ WLEG –Btm @ 7,312’ 8 9,164’ HOWCO Type ‘H-ES’ Cementer 9 10,060’ EZSV Plug OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I(Approx.) in 30” Hole 9-5/8" Cmt w/ 802 sks PF “E” (lead), 250 sx Class “G”(tail), 250 sx PF “C”’ (Top Job) in 12-1/4” Hole 7” Cmt w/ 200 sks (1 st Stage) then 250 sks (2nd Stage) Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 74.66 deg. @ 5,824’ MD Hole Angle at perfs ~70° GENERAL WELL INFO API: 50-029-22642-00-00 Drilled and Cased by Nabors 27-E - 2/28/1996 Plugged and Suspended by Nabors 27-E – 3/3/1996 Recompleted by Nordic 3 – 5/10/15 CT FCO - 5/31/2016 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu 8,260’ 8,280’ 4,654’ 4,660’ 20 7/6/2015 Open INJECTION ZONE DEPTHS Top of Injection Zone (feet TVD/MD) Base of Injection Zone (feet TVD/MD) Injection Zone Thickness (feet TVD/MD) 3,993’/6,129’ 4,978’/9,083’ 985’/2,954’ Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30' Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: NOTICE: Notification of Noncompliance, Class I Permit AK-1I005-B, Milne Point Unit Well MPB-24 Date:Tuesday, July 23, 2024 5:00:14 PM PTD 1960090 From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, July 23, 2024 4:55 PM To: Robinson, James <Robinson.James@epa.gov>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Amy Peloza <apeloza@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: NOTICE: Notification of Noncompliance, Class I Permit AK-1I005-B, Milne Point Unit Well MPB-24 James, Our diagnostics have confirmed that the tubing has a leak. To repair the well to an operable status we will be performing a rig workover to replace the tubing. Upon completion we will look to schedule a time to demonstrate integrity via a passing mechanical integrity test of the inner annulus. We are working the workover into our schedule and we are aiming for it to be repaired sometime between 8/4/24 – 8/20/24. We will keep you updated on our progress. Thank you and please reach out with any questions, Taylor Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Robinson, James <Robinson.James@epa.gov> Sent: Monday, July 15, 2024 7:23 AM To: Taylor Wellman <twellman@hilcorp.com>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Amy Peloza <apeloza@hilcorp.com>; 'Wallace, Chris D (DOA)' <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: NOTICE: Notification of Noncompliance, Class I Permit AK-1I005-B, Milne Point Unit Well MPB-24 Caution: This email originated from outside EPA, please exercise additional caution when deciding whether to open attachments or click on provided links. Taylor, Thank you for providing the noncompliance report. Please keep us updated as you work to diagnose the issue and develop a repair strategy. Regards, James Robinson, PE, PG Underground Injection Control and Sole Source Aquifer Programs U.S. EPA Region 10 Alaska Operations Office Phone: 907.271.6627 From: Taylor Wellman <twellman@hilcorp.com> Sent: Friday, July 12, 2024 2:10 PM To: Robinson, James <Robinson.James@epa.gov>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Amy Peloza <apeloza@hilcorp.com>; 'Wallace, Chris D (DOA)' <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: NOTICE: Notification of Noncompliance, Class I Permit AK-1I005-B, Milne Point Unit Well MPB-24 James, In accordance with Condition I.E.12.b, please find the attached written report submitted within 5 days of the initial notification. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Robinson, James <Robinson.James@epa.gov> Sent: Wednesday, July 10, 2024 4:54 PM To: Amy Peloza <apeloza@hilcorp.com>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Aubrey Malik <Aubrey.Malik@hilcorp.com>; Alaska NS - Environmental Specialist <mpuenviro@hilcorp.com>; Claire Costello - (C) <ccostello@hilcorp.com> Subject: [EXTERNAL] RE: NOTICE: Notification of Noncompliance, Class I Permit AK-1I005-B, Milne Caution: This email originated from outside EPA, please exercise additional caution when deciding whether to open attachments or click on provided links. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Point Unit Well MPB-24 Amy, Thank you for the notice. Please keep us updated as more information becomes available. Per the permit (AK1I005-B, Part II.C.3.d.5), the well must remain shut in until the EPA re-approves injection through MPB-24 after a passing mechanical integrity test of the inner annulus at minimum. Regards, James Robinson, PE, PG Underground Injection Control and Sole Source Aquifer Programs U.S. EPA Region 10 Alaska Operations Office Phone: 907.271.6627 From: Amy Peloza <apeloza@hilcorp.com> Sent: Monday, July 8, 2024 3:13 PM To: Robinson, James <Robinson.James@epa.gov>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Aubrey Malik <Aubrey.Malik@hilcorp.com>; mpuenviro@hilcorp.com; Claire Costello - (C) <ccostello@hilcorp.com> Subject: NOTICE: Notification of Noncompliance, Class I Permit AK-1I005-B, Milne Point Unit Well MPB-24 James, Tim~ In accordance with Condition I.E.12.a.2 of Class I Permit AK-1I005-B, Milne Point Unit, Well MPB-24 to notify EPA within 24 hours of “any noncompliance with a permit condition or malfunction of the injection system.” Please consider this email a follow up to the phone notification made to James Robinson on July 8, 2024. On July 7, 2024, Hilcorp Alaska, LLC (Hilcorp) Milne Point Unit (MPU) Field Operations received a high inner annulus (IA) pressure alarm, and subsequently confirmed that while injecting slurry, the pressure of the inner annulus increased rapidly, breaking the normal trend. Field Operations then verified that the pressure on the outer annulus (OA) was still within the normal operating parameters. The wellbore was flushed with clean water, then injection was shut down and well shut in. Field Operations immediately began monitoring shut in pressures on the tubing, IA and OA. Based on the information observed thus far where the tubing and inner annulus pressure track each other, Hilcorp believes that communication exists between the injection tubing and IA. Hilcorp is investigating the anomaly and once the source of communication is identified a repair plan will be developed. The well will remain shut in with no injection until the well is repaired. In accordance with Condition I.E.12.b, a written report will be submitted within 5 days. Thank you, Amy Peloza Environmental Team Manager -Kenai and North Slope Field Teams-Waste/UIC, Cont Sites and Restoration Programs Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 – office (907) 317-0521 – cell Email: apeloza@hilcorp.com Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240712 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU B-24 50029226420000 196009 7/8/2024 READ Caliper Survey MPU I-40 50029236890000 220071 7/4/2024 READ Caliper Survey MPU I-40 50029236890000 220071 7/9/2024 READ Caliper Survey PCU 2 50283200229000 179009 7/8/2024 AK E-LINE Tubing cut Revision Explanation: There are additional images added to the final report and a few new .las files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and POOH are new .las files Please include current contact information if different from above. T39179 T39180 T39180 T39181 MPU B-24 50029226420000 196009 7/8/2024 READ Caliper Survey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.15 10:32:44 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Date:Tuesday, July 9, 2024 8:10:42 AM Attachments:MPB-24 SCHEMATIC 6-29-2016.pdf MPB-24 90 day TIO.docx From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, July 8, 2024 3:44 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: MPB-24 (PTD #1960090) - IA Pressure Increase Mr. Wallace, On 7/7/24, on Disposal Well MPB-24 (PTD# 1960090) MPU Field Operations received a high inner annulus (IA) pressure alarm, and subsequently confirmed that while injecting slurry, the pressure of the inner annulus increased rapidly, breaking the normal trend. Field Operations then verified that the pressure on the outer annulus (OA) was still within the normal operating parameters. The wellbore was flushed with clean water, then injection was shut down and the well shut in. Field Operations immediately began monitoring shut in pressures on the tubing, IA and OA. Based on the information observed thus far where the tubing and inner annulus pressure track each other, Hilcorp believes that communication exists between the injection tubing and IA. Hilcorp is investigating the anomaly and once the source of communication is identified a repair plan will be developed. The well will remain shut in with no injection until the well is repaired. The well is now classified as NOT OPERABLE. A PPPOT-T passed to 5000 psi after the well was shut in. EPA notification has been made. Attached is a wellbore schematic and 90 day TIO plot. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 _____________________________________________________________________________________ Revised By: STP 6/29/2016 SCHEMATIC Milne Point Unit Well: MPB-24 Last Completed: 7/6/2015 PTD: 196-009 TD =12,584’ (MD) / TD = 7,934’(TVD) 20” CBL TOC @ 4100’ MD / 3,336’ TVD Orig. KB Elev.: 46’/ GL Elev.: N/A 7” 2 5 9-5/8” Ugnu MF PBTD = 10,060’(MD) / PBTD =5678’(TVD) Cal c. TOC @ 10,296’ MD / 5,899’ TVD 1 Plug 1 @ 11,692’ -12,584’ 4 3TOF @ 8,250’ CTM 5/31/2016 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/ NT-80LHE/ N/A N/A Surface 110’ 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 4,080’ 7" Production 26/ L-80 / BTC 6.276 Surface 12,066’ TUBING DETAIL 4-1/2” Tubing 12.6#/ L-80/ Hydril 521 3.958 Surface 7,312’ JEWELRY DETAIL No Depth Item 1 7,291’ 7” Hyd Set Permanent Packer 2 7,305’ XN Nipple (3.725” ID) 3 7,311’ WLEG 4 9,164’ HOWCO Type ‘ H-ES’ Cementer 5 10,060’ EZSV Plug OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 250 sks of Arcticset I(Approx.) in 30” Hole 9-5/8" Cmt w/ 802 sks PF “E” (lead), 250 sx Class “G”(tail), 250 sx PF “C”’ (Top Job) in 12-1/4” Hole 7” Cmt w/ 200 sks (1 st Stage) then 250 sks (2 nd Stage) Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 74.66 deg. @ 5,824’ MD Hole Angle at perfs ~70° GENERAL WELL INFO API: 50-029-22642-00-00 Drilled and Cased by Nabors 27-E - 2/28/1996 Plugged and Suspended by Nabors 27-E – 3/3/1996 Recompleted by Nordic 3 – 5/10/15 CT FCO - 5/31/2016 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu MF 8,260’ 8,280’ 4,654’ 4,660’ 20 7/6/2015 Open 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Tuesday, September 12, 2023 2:48 PM To:Darci Horner - (C) Cc:Regg, James B (OGC) Subject:RE: MIT-IAs for Milne Point Class 1 injection wells B-24, B-34 and B-50 as well as Northstar Class 1 wells NS-10 and NS-32 Attachments:MIT MPU B-24 07-20-23 Revised.xlsx; MIT MPU B-34 & B-50 07-19-23 Revised.xlsx Darci, AƩached are revised reports changing the type of injecƟon to “I”, as we include industrial wastewater (instead of water) for Class 1 wells. Please update your copies or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Darci Horner ‐ (C) <dhorner@hilcorp.com> Sent: Tuesday, July 25, 2023 3:53 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Brian Glasheen <Brian.Glasheen@hilcorp.com>; Brenden Swensen <Brenden.Swensen@hilcorp.com>; Alaska NS ‐ Milne ‐ Wells Foreman <AlaskaNS‐WellsForeman@hilcorp.com>; Alaska NS ‐ Milne ‐ Wellsite Supervisors <AlaskaNS‐Milne‐WellsiteSupervisors@hilcorp.com>; Derek Weglin <Derek.Weglin@hilcorp.com>; Josh McNeal <jmcneal@hilcorp.com>; Alaska NS ‐ Northstar ‐ Field Foreman <AlaskaNS‐ Northstar‐Field‐Foreman@hilcorp.com>; Alaska NS ‐ Northstar ‐ Operations Leads <AlaskaNS‐Northstar‐ OperationsLeads@hilcorp.com>; Alaska NS ‐ Environmental Specialist <mpuenviro@hilcorp.com>; Chuck Wheat <cwheat@hilcorp.com>; apeloza <apeloza@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Sara Hannegan <shannegan@hilcorp.com>; Jess Hall ‐ (C) <Jess.Hall@hilcorp.com>; Matthew Ross <Matthew.Ross@hilcorp.com>; Donald Maxon <Donnie.Maxon@hilcorp.com> Subject: MIT‐IAs for Milne Point Class 1 injection wells B‐24, B‐34 and B‐50 as well as Northstar Class 1 wells NS‐10 and NS‐32 All, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. MPU B-24PTD 1960090 2 Milne Point wells B‐24 (PTD # 1960090), B‐34 (PTD # 2161390), and B‐50 (PTD # 2042520) successfully passed MIT‐IAs on July 20, and 19, 2023, respecƟvely. Northstar wells NS‐10 (PTD # 2001820) and NS‐32 (PTD # 2031580) also successfully passed MIT‐IAs on July 23, 2023. Please note that EPA indicated in 2021 the required test pressure for the Northstar wells has been reduced from 3500 psi to 1500 psi. All wells are class 1 injecƟon wells requiring annual MITs. Please call myself or Ryan Thompson (907‐301‐1240) with any quesƟons. Regards, Darci Horner Technologist Alaska Islands Team Office: (907) 777‐8406 Cell: (907) 227‐3036 Email: dhorner@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 1960090 Type Inj I Tubing 794 800 788 783 Type Test P Packer TVD 4,363'BBL Pump 3.5 IA 12 3701 3596 3571 Interval O Test psi 3500 BBL Return 2.9 OA 245 247 246 246 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting EPA Class 1 injection well MIT-IA to 3500 psi. AOGCC witness waived by Brian Bixby (EPA witnessed). Notes: Hilcorp Alaska, LLC Milne Point / MPU / B Roger Allison 07/20/23 Notes: Notes: Notes: Notes: B-24 Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Form 10-426 (Revised 01/2017)2023-0720_MIT_MPU_B-24        J. Regg; 10/12/2023 Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230728 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU-23 50133206350000 214093 7/16/2023 HALLIBURTON PPROF BCU-24 50133206390000 214112 7/15/2022 HALLIBURTON PPROF BRU 223-34 50283201880000 223041 7/9/2023 HALLIBURTON RMT3D KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON EPX KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON MFC KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON EPX KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON MFC KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON EPX KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON MFC MPU B-24 50029226420000 196009 7/24/2023 HALLIBURTON WFL-TMD3D MPU B-34 50029235690000 216139 7/23/2023 HALLIBURTON WFL-TMD3D MPU B-50 50029232400000 204252 7/21/2023 HALLIBURTON WFL-TMD3D MPU E-23 50029225700000 195094 6/17/2023 HALLIBURTON COILFLAG MPU F-17 50029228230000 197196 7/2/2023 HALLIBURTON COILFLAG MPU L-13A 50029223350100 223017 6/21/2023 HALLIBURTON COILFLAG MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON COILFLAG MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON RBT PBU 11-07 50029206870000 181177 6/28/2023 HALLIBURTON RMT3D SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON EPX SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON MFC SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON EPX SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON MFC Please include current contact information if different from above. T37886 T37887 T37888 T37889 T37889 T37890 T37890 T37891 T37891 T37892 T37893 T37894 T37895 T37896 T37897 T37898 T37898 T37899 T37900 T37900 T37901 T37901 MPU B-24 50029226420000 196009 7/24/2023 HALLIBURTON WFL-TMD3D Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.01 10:05:02 -08'00' David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/3/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220930 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU I-17 500292321200 204098 3-Aug-22 READ CaliperSurvey MPU B-24 500292264200 196009 7/19/2022 READ CaliperSurvey MPU F-38 500292261400 195168 9/19/2022 READ CaliperSurvey MPU F-73A 500292274401 200198 7/31/2022 READ CaliperSurvey MPU I-01 500292206500 190090 8/31/2022 READ CaliperSurvey MPU I-30 500292371000 222023 7/12/2022 READ Inj_Profile MPU J-27 500292355700 215153 8/11/2022 READ CaliperSurvey MPU L-47 500292355000 215117 7/23/2022 READ CaliperSurvey Please include current contact information if different from above. T37121 T37122 T37123 T37124 T37125 T37126 T37127 T37128 MPU B-24 500292264200 196009 7/19/2022 READ CaliperSurvey Kayla Junke Digitally signed by Kayla Junke Date: 2022.10.05 13:20:28 -08'00' 5HJJ-DPHV%2*& )URP'DUFL+RUQHU&GKRUQHU#KLOFRUSFRP! 6HQW0RQGD\-XO\30 7R5HJJ-DPHV%2*&%URRNV3KRHEH/2*&:DOODFH&KULV'2*&'2$$2*&&3UXGKRH%D\ &F-HULPLDK*DOORZD\7RGG6LGRWL%ULDQ*ODVKHHQ$ODVND16:HOOV)RUHPDQ$ODVND160LOQH :HOOVLWH6XSHUYLVRUV'HUHN:HJOLQ-RVK0F1HDO$ODVND161RUWKVWDU)LHOG)RUHPDQ$ODVND16 1RUWKVWDU2SHUDWLRQV/HDGV7UDYLV6SDUNV7RQ\0DQJDQR:LOOLDP'UDNH$ODVND16 (QYLURQPHQWDO6SHFLDOLVW&KXFN:KHDWDSHOR]D'DYLG+DDNLQVRQ7RULQ5RVFKLQJHU 6XEMHFW0,7,$VIRU0LOQH3RLQW&ODVVLQMHFWLRQZHOOV%%DQG%DVZHOODV1RUWKVWDUZHOOV16 DQG16 $WWDFKPHQWV0,7,$16 16[OV[0,7038%[OV[0,7038%[OV[ 0,7038%[OV[ ůů͕ DŝůŶĞWŽŝŶƚǁĞůůƐͲϮϰ;WdηϭϵϲϬϬϵϬͿ͕Ͳϯϰ;WdηϮϭϲϭϯϵϬͿ͕ĂŶĚͲϱϬ;WdηϮϬϰϮϱϮϬͿƐƵĐĐĞƐƐĨƵůůǇƉĂƐƐĞĚD/dͲ/Ɛ ŽŶ:ƵůǇϭϵ͕ϮϬĂŶĚϮϭ͕ϮϬϮϮ͕ƌĞƐƉĞĐƚŝǀĞůǇ͘ EŽƌƚŚƐƚĂƌǁĞůůƐE^ͲϭϬ;WdηϮϬϬϭϴϮϬͿĂŶĚE^ͲϯϮ;WdηϮϬϯϭϱϴϬͿĂůƐŽƐƵĐĐĞƐƐĨƵůůǇƉĂƐƐĞĚD/dͲ/ƐŽŶ:ƵůǇϭϵ͕ϮϬϮϮ͘ WůĞĂƐĞŶŽƚĞƚŚĂƚWŝŶĚŝĐĂƚĞĚůĂƐƚǇĞĂƌƚŚĞƌĞƋƵŝƌĞĚƚĞƐƚƉƌĞƐƐƵƌĞĨŽƌƚŚĞEŽƌƚŚƐƚĂƌǁĞůůƐŚĂƐďĞĞŶƌĞĚƵĐĞĚĨƌŽŵϯϱϬϬ ƉƐŝƚŽϭϱϬϬƉƐŝ͘ ůůǁĞůůƐĂƌĞĐůĂƐƐϭŝŶũĞĐƚŝŽŶǁĞůůƐƌĞƋƵŝƌŝŶŐĂŶŶƵĂůD/dƐ͘ WůĞĂƐĞĐĂůůŵǇƐĞůĨŽƌ:ĞƌŝŵŝĂŚ'ĂůůŽǁĂǇ;ϵϬϳͲϱϲϰͲϱϬϬϱͿǁŝƚŚĂŶǇƋƵĞƐƚŝŽŶƐ͘ ZĞŐĂƌĚƐ͕ DarciHorner Technologist Office:(907)777Ǧ8406 Cell:(907)227Ǧ3036 Email:dhorner@hilcorp.com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ubmit to: OOPERATOR: FIEL DD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1960090 Type Inj I Tubing 602 612 598 592 Type Test P Packer TVD 4,363'BBL Pump 3.6 IA 2 3512 3418 3393 Interval O Test psi 3500 BBL Return 3.6 OA 243 258 243 243 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec hanicall Integrityy Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp Alaska, LLC Milne Point / MPU / B Derek Weglin 07/19/22 Notes:Annual Class 1 Injection Well. Virtually witnessed MIT-IA to 3500 psi. Notes: Notes: Notes: B-24 Form 10-426 (Revised 01/2017)2022-0719_MIT_MPU_B-24 9 9 9 9 9 9 -5HJJ Annual Class 1 Injection Well. Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/12/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-24 (PTD 196-009) TMD3D Water Flow Log 08/07/2020 Please include current contact information if different from above. Received by the AOGCC 11/13/2020 PTD: 1960090 E-Set: 34244 Abby Bell 11/13/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/12/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-24 (PTD 196-009) Multi Finger Caliper Log 08/05/2020 ANALYSIS Please include current contact information if different from above. Receive by the AOGCC 11/13/2020 PTD: 1960090 E-Set: 34243 Abby Bell 11/13/2020 DATE: 7/18/2019 19 60 09 Debra Oudean Hilcorp Alaska, LLC 3 1 0 0 2 AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-24 PTD(196-009)I CD: HALLIBURTON 10 AUG 2018 MPU B-24 MULTI FINGER CALIPER RECEIVED JUL 19 2019 AOGCC Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 MPtk P,._7,4 PT6 1% 6V10 Regg, James B (CED) From: Darci Horner - (C) <dhorner@hilcorp.com> � Sent: Wednesday, July 17, 2019 10:48 AM qq To: Regg, James B (CED); Brooks, Phoebe L (CED); DOA AOGCC Prudhoe Bay; Wallace, Chris D (CED) Cc: Wyatt Rivard; Nick Frazier - (C) Subject: Milne Point EPA Class 1 Disposal Well MITs 2019 Attachments: MIT MPU B-34 7-14-19.xlsx; MIT MPU B-24 7-13-19.xlsx All, Milne Point Class 1 disposal wells B-24 (PTD # 1960090) and B-34 (PTD # 2161390) successfully passed annual EPA witnessed MIT-IAs on July 13 and 14, 2019, respectively. Please call myself or Wyatt Rivard (777-8547) with any questions. Regards, Darci Horner (Northern Solutions) Technologist Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Office: (907) 777-84o6 Cell: (907) 227-3036 Email: dhorner@hilcorp.com The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to In repOnaksustiov: OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test AOGCGInsoectors2gIaska.00v: phoebe.brooksdialaska Oov chns wallace[Aalaska.gov 07/13119 Nick Frazier Jeff Jones waived winess Well 8.24 INTERVAL Order; Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. i=Tow Teat C". F=Teal PTO 1960090 Type Int W Tubing 234 242 - 239. 237 N = Not thrice, Type Test P Packer TVD 4.353' - BBL Pump Bd - IA zero 3523 - 3432- 3412 - Interval 0 Test psi 3500 1 BBL Return 2.B DA 239 263 243 1 242 Result P Notes: EPA Class 1 injection wall MIT -IA to 3590 psi. Well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typa lnjTubing Type TasI Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures Pretest Initial 15 Min. 30 Min. 45 Min. 6DMin. PTD Type lnl Tubing Type Tes t Packer TVD BBL Pump IA Interval Testpsi BBL Return OA Result Notes: well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Packer TVD BBL Pump IA IntervalTesl Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Ing Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result N954: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Ing .Tubing Type Tesl Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Result NL: Well Pressures. Pretest Initial 15 Min. W Min. 45 Min. 60 Min, PTDType Inj Tubing Type Tast Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Nates: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Typa Test Packer TVD BBLPump IA Interval Test psi BBL Relum OA Result Not s: TYPE INJ CoEn TYPE TEST Co4o INTERVAL Order; Result Codes try =water P=Pressure Test 1=Initial TCA P=Pa. G=Ghr O= Other leescnbe In West i=Tow Teat C". F=Teal s=Slurry V= Rapuired by Vvunce 1=1mmnGwrve I = IMuamal waaewaer o = Omer least in vers) N = Not thrice, Form 10-426 (Revised 01 aO17) MIT MPU &24 7-13-19 Post Anchorage, Box 9524 44027 Anchorage, AK 99524 3800 Centerpoint Or Suite 1400 Hilcorp Alaska, LLC Anchorage, AK 99503 Phone: 907/777-8300 March 18, 2019 Fax: 907/777-8560 Mr. Edward J. Kowalski RECEIVE Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency MAR 2 7 2019 1200 Sixth Avenue Seattle, WA 98101 AO G C C Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK- 11002-13, General Wastewater Permit No. 2016DB001-0020 Milne Point Injection Well, UIC Permit AK-1I005-13General Wastewater Permit No 2016DB001-0001 Liberty Class 1 Injection Well, UIC Permit AK- 1I013 -A General Wastewater Permit No. 2016DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS 10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK -1I002-13; 2) the annual MIT and fluid movement logs that are required every three years at the Milne Point Class I wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK -1I005-13; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK -1I013 -A. Mechanical Integrity Test Notification March 18, 2019 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Ryan Gross of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782-7431, or via e-mail at dheebner@hilcorp.com. Sincerely, Deborah Heebner North Slope Environmental Specialist HILCORP ALASKA, LLC Attachment cc: Ryan Gross, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Evan Osborne, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Kyle Monkelien, BSEE Bureau of Safety And Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Jason Seltisch Proposed Schedule for 2019 Mechanical Integrity Testing Well I It:: uoeny UKI well will not be drilled in 2019. All logs required to complete the well would be scheduled with the eadline Proposed MIT test Flexibility in Fluid Movement be extended date test date? Logs Planned 3 months after MIT? 77pt777 irector al Point 4 gust 9, Approximately July Coordinate with No Fluid movement 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-24 every three years. Previously done on Milne Point MPB-34 By August 8, Approximately July Coordinate with Fluid m17. vement 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-34 every three years. Previously done on Milne Point MPB-50 B Au ust 9, Y 9 q Approximately July Coordinate with 4/9/2017. No Fluid movement 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-50 every three years. Previously done on Northstar NS10 By August 12, Approximately July Coordinate with 7/7/2017. No Fluid movement 2019 11 -15, 2019. Milne test date. logs are planned as they are required at NS 10 every two years. Previously Northstar NS32 By August 13, Approximately July Coordinate with done on 1301. No Fluid movement 2019 11 -15,2019 Milne test date. logs are planned as they are required at NS32 every two years. Previously Lihertv CRI nun done on 8/14/2018. Well I It:: uoeny UKI well will not be drilled in 2019. All logs required to complete the well would be scheduled with the 19000 Regg, James B (DOA) From: Brooks, Phoebe L(DOA) Sent: Tuesday,August 1, 2017 10:46 AMl� To: Wyatt Rivard l 2 Cc: Regg,James B (DOA) Subject: RE: EPA Class 1 Disposal Well MITs 2017 Attachments: MIT MPU B-24 07-06-17.xlsx; MIT NSU NS-10, 32 07-06-17.xlsx Wyatt, I made a minor revision, adding the trailing zero to PTD#1960090(MPU B-24). I also combined the two Northstar Unit reports as they were tested on the same day. Please update your copies. Thank you, Phoebe Phoebe Brooks Statistical Technician II AAlaska Oil and Gas Conservation Commission SCANNED �� j!; Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you. are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Phoebe Brooks at 907-793-1242 or phoebe.brooks©alaska.gov. From:Wyatt Rivard [mailto:wrivard@hilcorp.com] Sent: Monday,July 31, 2017 5:21 PM To:Wallace, Chris D (DOA)<chris.wallace@alaska.gov>; Brooks, Phoebe L(DOA)<phoebe.brooks@alaska.gov>; Regg, James B (DOA) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov> Cc:Alaska NS- Northstar-Operations Leads<AlaskaNS-Northstar-OperationsLeads@hilcorp.com>; Alaska NS- Milne - Wellsite Supervisors<Alaska NS-Milne-WellsiteSupervisors@hilcorp.com> Subject: EPA Class 1 Disposal Well MITs 2017 All, The following Class 1 Disposal Wells had passing annual 2017 EPA witnessed MIT-lAs. Please note that the newly completed Class 1 disposal well MPB-34(PTD#2161640)was previously MIT'd in May 2017.The MIT forms are attached for reference. Well Field PTD MPB-50 Milne Point 2042520 MPB-24 Milne Point 1960090 NS-10 North Star 2001820 NS-32 North Star 2031580 Thank You, 0 r • • . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test • Submit to: jim.reoo(rDalaska.aov AOGCC.InscectorsOalaska.00v phoebe.brooksaalaska.00v chris.wallace(Salaska.00v OPERATOR: Hilcorp Alaska,LLC FIELD/UNIT/PAD: Northstar/NSU/Northstar (C 1 DATE: 07/06/17 OPERATOR REP: Matt Linder AOGCC REP: Well MPB-24 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1960090' Type Inj N - Tubing 913 - 911- 909 ' 906 - Type Test P Packer TVD 4,363' - BBL Pump 2.8 - IA 0 3547- 3463 - 3422 - Interval 0 Test psi 3500 , BBL Return 2.8 - OA 275 - 258' 258- 257- Result P IV Notes: Annual Class 1 Injection Well EPA witnessed MIT-IA to 3500 psi.Witness waived by AOGCC's Jeff Jones.The well was SI in preparation for the MIT-IA to minimize pressure fluctuations due to temp changes. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Mini 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing - Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result • Notes: • Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test I=Initial Test P=Pass G=Gas 0=Other(describe in Notes) 4=Four Year Cycle F=Fail 5=Slurry V=Required by Variance I=Inconclusive I=Industrial Wastewater 0=Other(describe in notes) N=Not Injecting Form 10-426(Revised 01/2017) MIT MPU B-24 07-06-17 kCI (cel-0O q •th Nolan Hilcorp Alaska, CtC 2..u� GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVED Anchorage, AK 99503 VO Tele: 907 777-8308 ffilenrp MaMk*,f.1A: Fax: 907 777-8510 JUL 19 2017 E-mail: snolan@hilcorp.com DATA LOGGED '1f 26/2011 DATE 07/19/17 AOGCC M. K.BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SCANNED AUG 4. 8 2017: MPU B-24 Prints: GR/CCL/Press/Temp/RST CD 1: DLIS Data 7/18/2017 7:47 AM File folder LAS Data 7/18/2017 7:51 AM File folder 16,1 Log 7/18/2017 7:51 AM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: g, Date:mA.12.42.06.eAtet STATE OF ALASKA • ALOA OIL AND GAS CONSERVATION COMMON REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations Li Fracture Stimulate LI Pull Tubing❑ Operations shutdown U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 8rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: CT FCO 0 2. Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska LLC Development ❑ Exploratory ❑ 196-009 3.Address: Stratigraphic Service Q 6.API Number: 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-22642-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0047432/ADL 392703 MILNE PT UNIT KR B-24 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A MILNE POINT/KUPARUK RIVER OIL&UNDEFINED WDSP 11.Present Well Condition Summary: Total Depth measured 12,584 feet Plugs measured 10,060&11,692 fe EtoEI0 true vertical 7,934 feet Junk measured 8,250(Fill) feet 1 JUN 302016 Effective Depth measured 8,250 feet Packer measured 7,291 feet true vertical 4,650 feet true vertical 4,363 feet AOGCC Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 110' 110' N/A N/A Surface 4,080' 9-5/8" 4,080' 3,328' 5,750psi 3,090psi Production 12,066' 7" 12,066' 7,443' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic � ari True Vertical depth See Attached Schematic SC"`NEED E .L. ' Tubing(size,grade,measured and true vertical depth) 4/1/2" 12.6#/L-80/Hydril 521 7,312' 4,370' Packers and SSSV(type,measured and true vertical depth) 7"Hyd Set Perm Pkr N/A See Above N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 3,055 594 917 Subsequent to operation: 0 0 10,094 665 1,108 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations Q Exploratory❑ Development❑ Service ❑✓ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL Q Printed and Electronic Fracture Stimulation Data ❑ 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: 316-300 Dp Contact Paul Chan Email pchantp�hilcorp.com .4r rAm4 Printed Name Bo York Title Operations Engineer Signature i 2-17.9— ..........______.-- �� Phone 777-8345 Date 6/27/2016 [ 7"7--/te Form 10-404 Revised 5/2015 G! � RB DMS �- �U� 0 6 2016 Submit Original Only • • Mime MPB-24Point Unit • II We SCHEMATIC Last Completed: 7/6/2015 ail,Alaska,LLC PTD: 196-009 Orig.KBEIev.:46'/GLEIev.:N/A OPEN HOLE/CEMENT DETAIL 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole j i,,.`'•4 ii•) 110:41 20" )' 7" Cmt w/200 sks(1st Stage)then 250 sks(2"d Stage)Class"G"in 8-1/2"Hole CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm it , 20" Conductor 91.1/NT-80LHE/N/A N/A Surface 110' 9-5/8" Surface 40/L-80/BTC 8.835 Surface 4,080' 7" Production 26/L-80/BTC 6.276 Surface 12,066' TUBING DETAIL 9-5/8 41 i 4-1/2" Tubing 12.6#/L-80/Hydril 521 3.958 Surface 7,312' WELL INCLINATION DETAIL KOP @ 500' i 1 Max Hole Angle=74.66 deg. @ 5,824'MD Hole Angle at perfs-70° , JEWELRY DETAIL No Depth Item 1 7,291' 7"Hyd Set Permanent Packer CBLTOC@ 2 7,305' XN Nipple(3.725"ID) 4100333 TV 3 7,311' WLEG 3,336'TVD ?; t 4 9,164' HOWCO Type'H-ES'Cementer br kto 5 10,060' EZSV Plug r 1 Ev PERFORATION DETAIL 1, , .-" Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Ugnu MF 8,260' 8,280' 4,654' 4,660' 20 7/6/2015 Open I, 2 ' GENERAL WELL INFO ?i API:50-029-22642-00-00 It T0F@8,250' it: 3 Drilled and Cased by Nabors 27-E -2/28/1996 CTM 5/31/2016 Plugged and Suspended by Nabors 27-E-3/3/1996 - - Recompleted by Nordic 3-5/10/15 UgnuNF ,4-,ES •tt ' 3 qs CT FCO -5/31/2016 '. 4 5 Calc.TOC @ 10,296'MD/ 5,890 TVD k 10 74 z't fir iA "'ttYerI� Plug 1@ 4 11,692'-12,584' 7 fs xtt1 r TD=12,584'(MD)/TD=7,934'(TVD) PBTD=10,060'(MD)/PBTD=5678'(TVD) Revised By:STP 6/29/2016 • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 CTU 50-029-22642-00-00 196-009 5/29/16 5/31/16 Daily Operations: 5/25/2016-Wednesday No activity to report. 5/26/2016 Thursday No activity to report. 5/27/2016- Friday No activity to report. 5/28/2016-Saturday No activity to report. 5/29/2016-Sunday Hold safety meeting with SLB Crew. MIRU CTU 14. Spot choke, return tanks, Upright tank with pit liner. Start BOPE test. Draw down test complete.Start 5 minute tests on all rams and valves. Start full body low. 283psi-268Psi. Good low. Full body high.4,774-4,757psi. Good Test. Inner reel valve and outside choke valves tested with Full body. 2nd set test Top Blind shears. 330-295 Low PT good.4600-4590psi high pt. Good. Test second set blind shear 305-295psi good test.Also test 2nd set of choke. High pt 2nd set blind shear 4600-4590psi. Good test. Rlh close pipe rams. Push 10k pull 20k. No movement. Good test. Close pipe rams. Low pt pipe slips to 292-266psi. Good test. High PT pipe rams to 4625-4600psi good test. Dump pump check vavle. Good differential check valve holding. BOPE test complete. Pop off well. Make up Coil connector. Pull test to 20k. Make up BHA as follows. CC 2.125" OD x.93', DFCV 2.125" OD x.92',Straight bar 2" OD x 5', Straight bar 2" OD x 5', DJS nozzle 2" ODx.42'. BHA total length 11.568'. Stab on well. Pressure test stack to closed swab and choke to 250 low and 4500psi high. Good PT. Bleed down. Close choke, open swab valve 23.5 turns. RIH with closed choke. Opsi on wellhead when opened up. RIH wiht closed choke. Notice WHP increasing to 200 psi.STop Ct. Open choke Pipe p lighttag 0 pick andcontinue to RIH. Pi a dis lacment test indicates wellbore will hold column of fluid. Saw from 4498 '-5100' up. Come online with 5 bbl gel sweep followed with 1% Kcl and slick water. Continue to cirulate to tubing tail. Noticed thick grey in returns.Took samples every Bottoms up. Pump bottoms up of 86bbls at 7296'to clean 4.5"tubing. Continue into 7" casing. Increase rate to 2.6 bbls/min 3700 psi circulation pressure. Perform weight checks every 1000'.Took 50' bite and pulled back to tubing tail. Continued in pumping gel sweeps and taking 50' bites and Picking up. OOH wt 18k. RIH wt 1000 lbs. All weigth checks clean. No overpull. Slowed Coil speed at 8000'to 10 ft/min.Started stacking weight at 8194'. Pulled OOH for wiper trip to tubing tail. 7300' Rlh Continue to clean and saw 1-2k in CT weight loss from 8194'-8250'.Stacked 5k at 8250' maintaining 1:1 returns during cleanout via tank straps vs. Pumped volume. Noticed Increase in Circ pressure at 8250' Decided to POOH to tubing tail. Picked up to 8050' and pump spiked from 3650-4200psi and tripped pump and coil delta P. Reset peramiters and attempted to bring pump online and move coil. No returns at surface and coil stuck. Circ pressure increase to 4100psi @ 1.5 bbls/min.Worked coil and called town to notify. 18k up weight over pulled to 35k Coil moving OOH returns came back 1:1. @ 8050'. Picking up OOH pulled heavy and lost returns at 7850'. Picked 30k over string weight returns back to surface. Pulled free. Continue OOH at 18k 7292'stuck again in tubing tail. Pu to 22k loose returns. Over pull to 36k returns back. Weight slowly dropping. Once weight gets back to 18K without moving pipe we loose reutrns. Pulled free. Continue OOh from 7292'. Circulating bottoms up.Tagged up at surface. Blow down stack. Pop off. Opsi on tree. G&I Attempt to Pump produced fluids down well. Pressure up to 2700psi and no rate. While stuck we injected with CT at 1.5 bbls/min. SDFN. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-24 CTU 50-029-22642-00-00 196-009 5/29/16 5/31/16 Daily Operations: 5/30/2016-Monday Hold safety meeting and discuss plan forward. Pick injector head and make up make up BHA. No go coil connector DFCV, 2x straight bar, 2"JSN. BHA 11.568'. Stab on well. PT stack to 250/4500 psi. Good pt. Bleed down. Open well and Rlh with choke closed. Wellhead pressuring up to 500psi. Open choke taking pipe displacement to OT. At 500' come online at 2.3 bbls/min circulating while RIH. Perform weight checks every 1000'. Clean pick up weights. 7100' Wt check 17k clean. RIH at 1000 lbs to 7300'. Gel at nozzle. Pump bottoms up of 89 bbls. Chase out of Hole with CT. At surface. Master swab closed. 220 bbls pumped for cleanout. No indications of fill or debris in return samples. Clean fluid circulated in tubing. 5/31/2016-Tuesday Hold safety meeting. Discuss JSA and job procedure. Fire equipment. Pick injector head. Make up BHA: No go roll on connector 2.125" OD x.93', DFCV 2.125" ODx.92', 2x weight bar 2" ODx 5',Jet swirl nozzle 2.0" ODx.42. total BHA length 11.568'. Stab on well. PT stack 250/4500psi. Good PT. Bleed down. Open well and RIH. Parked at tubing tail waiting for meeting with town. 7300'. Continue moving pipe. Procedure for cleaning out 7" casing obtained. Online with pump at 3.5 bbls/min @ 3700 psi.Take 4 50' bites and chase back to tubing tail with gel sweeps of 5 bbls. Returns clean. No indication of solids. Obtained permission to take 100' bites until we get closer to perfs. 7500 start taking 100' bites to 7800'. 5 bbl gel pill at nozzle. Chase to inside of tubing tail. No indications of solids. Rih from tubing tail at 7300' back to 7800' saw some weight stack. Take 50' bite at 7850' Pick up to 7800'and rih for another 50' bite to 7900'. Pump 10 bbl gel sweep at nozzle. Chase OOH to tubing tail at 7300'. Continue RIH and start taking 50' bite from 7900'-7950'. Pu to 7900'. Continue in hole to 8000' gel sweep at nozzle. Pick up and chase 100' bite to TT @ 7300'. Still pumping 3.5 bbls/min at 2700psi.Taking bite from 8000-8050. Pick up to 8000' .Continue RIH to 8100' Gel sweep at nozzle. Pu to tubing tail at 7300'. Wash down to 8100 and repeat.At 8250' pump 30 bbl gel sweep. Once turned the corner PU and chase to surface. Still geting 1:1 returns. Returns have small trace of soilds and are dark grey. Look like drilling mudd. Pu into tubing tail and Pulled heavy at 7296' Lost returns. Pulled 25k over string weight and weight dropped back to 15k OOh weight . Returns came back. Send another gel sweep. Pumped 86 bbls to clear 4.5"tubing. Picked up to 6500'. Waiting on vac trucks to fill upright tanks and empty both return tanks. 860 bbls total pumped for first cleanout run. Filling tanks.Tanks full Online at 3.5 bbls/min at 6500' Rlh and stack weight at 7292' 10k down. Not washing off. PU and run back into obstruction. Stack-10k. No indication of washing off. Pumped 30 bbls ontop of obstruction. No luck. Pu to 7000'. Line up with CT pump down Ctxtubing anuuli and down 2" CT. Come online and walk rate up to 4.5 bbls/min. Pressure climbs and breaks over at 1600psi. Look to be injectin. Injected 45 bbls into formation. Shut down pumps and RIH and made it past 7292'. Pick up and continue 3x from 7200'- 7350'. No signs of obstruction. Looks like it went into 7". Circulated 86 bbls tubing volume and chased to surface.Tagged up at surface. Master swab closed 23.5 turns. 256 bbls pumped during second Cleanout run. 1116bbls pumped for the day. G&I facility attempting to inject fluid. Coiled tubing SDFN. qco- o®q • • Hilcor LLC Post Office Box 24402 p Alaska, Anchorage,AK 99524 3800 Centerpoint Dr Suite 1400 CERTIFIED MAIL. Anchorage,AK 99503 Phone: 907/777-8300 March 12, 2017 Fax: 907/777-8560 RECEIVED Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement MAR g 2017 U.S. Environmental Protection Agency 1200 Sixth Avenue AOGGC Seattle, WA 98101 Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley SCANNED Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK-11002-B, General Wastewater, Permit No. 2005DB001-0020 Milne Point Injection Well,UIC Permit AK-1I005-B, General Wastewater, Permit No. 2005DB001-0001 Liberty Class 1 Iniection Well. UIC Permit AK-11013-A. General Wastewater. Permit No. 2005DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp)respectfully submits the following notifications: 1) The annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS 10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK-1I002-B; 2) The annual MIT and fluid movement logs that are required every three years at the Milne Point Class 1 wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK-1I005-B; 3) The MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-1I013-A. Mechanical Intel,Test Notification • March 12,2017 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Evan Osborne of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782- 7431, or via e-mail at dheebner@hilcorp.com. Sincerely,a rr^ Deborah Heebner North Slope Environmental Specialist HILCORP ALASKA,LLC Attachment cc: Evan Osborne, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Kyle Monkelien, BSEE Bureau of Safety and Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Kevin Pendergast, BSEE Bureau of Safety and Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Timothy Mayers, EPA Region 10 Jason Selitsch, Denali Environmental • ID Proposed Schedule for 2017 Mechanical Integrity Testing Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Movement Deadline date test date? Logs Planned after MIT? Northstar NS10 By July 6, Approximately July 5- Coordinate with No Fluid 2017 10, 2017. Milne test date. movement logs are planned as (May be they are required extended up at NS10 every to 3 months two years. with Director Previously done approval) on 7/7/2016. Northstar NS32 By July 8, Approximately July 5- Coordinate with No Fluid 2017 10, 2017 Milne test date. movement logs are planned as (May be they are required extended up at NS32 every to 3 months two years. with Director Previously done approval) on 7/9/2016. Milne Point By July 10, Approximately July 10- Coordinate with Fluid movement MPB-24 2017 15, 2017. Northstar test logs are planned date. even though logs were previously done on 7/23/2015. This will get MPB-24 on the same schedule as MPB-50. Milne Point By July 10, Following the Well's Coordinate with The Mechanical MPB-34 2017 Completion Evan Osborne Integrity Testing and Jason and Fluid Selitsch with Movement Logs EPA will be done following the Well's completion Milne Point By July 10, Approximately July 10- Coordinate with Fluid movement MPB-50 2017 15, 2017. Northstar test logs are planned date. as they are required for MPB- 50 every three years. Previously done on 7/24/2014. Liberty CRI Well N/A The Liberty CRI well All logs required will not be drilled in to complete the 2017. well would be scheduled with the MIT. y OF 7'�� • • .21. I%%yam* THE STATE Alaska Oil and Gas �, of/\ T /� S Conservation Commission -.ALA KAL ,!T,,,,-, �� 333 West Seventh Avenue t'. .� i GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ligri- ., Main: 907.279.1433 FA :S�� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York SCANNED SEP 2, 8 2016 Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Undefined WDSP Pool, MPU KR B-24 Permit to Drill Number: 196-009 Sundry Number: 316-300 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 116P9v.A.44-k Cathy 7 Foerster Chair DATED this 2-day of June, 2016. RBDMS I-t- JUN 0 6 2016 • RECEIVEL STATE OF ALASKA JUN 0 1 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION 07-5 G. 17.1 1 !o APPLICATION FOR SUNDRY APPROVALS A®(`,, CC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CT FCO ' Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC ` Exploratory ❑ Development ❑ 196-009 3.Address: Stratigraphic ❑ Service a , 6.API Number: 3800 Centerpoint Dr,Suite 1400 Anchorage AK 99503 50-029-22642-00-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055 / Will planned perforations require a spacing exception? Yes ❑ No El ✓ MILNE PT UNIT KR B-24 9.Property Designation(Lease Number): 10.Field/Pool(s): b'+$ ADL0047432/ADL 392703 . MILNE POINT 1146 14-UNDEFINED itAI ,5? 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,584' 7,934' 10,060' 5,678' 550 10,060' N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 110' 110' N/A N/A Surface 4,080' 9-5/8" 4,080' 3,328' 5,750psi 3,090psi Production 12,066' 7" 12,066' 7,443' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80/Hydril 521 7,312' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 7"Hyd Set Perm Pkr and N/A 7,291'MD/4,363'TVD and N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development❑ Service ❑✓ 14. Estimated Date for 15.Well Status after proposed work: 5/29/2016 ❑ ❑ WDSPL ❑ , Suspended ElCommencing Operations: OIL WINJ 16.Verbal Approval: Date: 5/29Y2016 GAS ❑ WAG ❑ GSTOR El SPLUG El Commission Representative: Guy Schwartz GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved 1 herein will not be deviated from without prior written approval. Contact Paul Chan j Email pchan@hilcorp.com Printed Name Bo York Title Operations Manager Signature -e-.7:7L-------- Phone 777-8345 Date 5/31/2016 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. ` 3 d1-- of Plug Integrity ❑ BOP Test W Mechanical Integrity Test ❑ Location tiClearance ❑ Other. �f\'6(2,,,(J1' n kb be, l,'\ act- 1/11 1 p '1 �, v,t t 'SS��4l p-t Ilk 1-1... 0 05-is fes" uo s<; T w's . j e Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Q'' Subsequent Form Required: (0 - 404 RBDMS L_1' JUN 0 6 2016 6.) APPROVED BY Approved by: �f/� COMMISSIONERTHE COMMISSION Date: -Z—/. C�►^1 2c to t'1411 Gill/c- 74, c -Z-lc. Submit Form and Form 10-403 Revised 11/2015 QndL 1ti INsAaiii r 12 months from the date of approval. Attachments in Duplicate • • Well Prognosis Well: MPU B-24 Hilcort)Alaska,LLQ Date:5/28/2016 Well Name: MPU B-24 API Number: 50-029-22688-00 Current Status: Class I Disposal Well Pad: B-Pad Estimated Start Date: May 29th, 2016 Rig: CTU Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 196-009 First Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Current Bottom Hole Pressure: 2,588 psi @ 4,636' TVDss (SBHPS 07/18/2015/ 10.7 ppg EMW) Maximum Expected BHP: 2,588 psi @ 4,636' TVDss (No new perfs being added) MPSP: 550 psi (Calculated SITP with column of 8.45 produced fluid from perfs to surface) Brief Well Summary: The Milne Point B-24 well was drilled as a Kuparuk development well that TD'd at 12,584' and ran and cemented 7" casing in March 1996. The well was suspended due to wet Kuparuk and Schrader targets. Cement isolation plugs were set across the 7" casing shoe (11,692'-12,584'), intermediate plug (4,000'-4,200'), and surface (5'-250'). The most recent casing pressure test of casing (above bottom cement plug) was performed to 2,000psi on 3/1/1996. Under Sundry 315-249 the upper and intermediate cement plugs were removed and a clean-out BHA was run followed by an MIT-IA test was executed and passed to 3,500psi. Under Sundry 315-277 an EZSV plug was set @ 10,060' then 4-1/2" tubing was run and a packer was set @ 7,291' on 5/10/2015. The well was perforated on July 6, 2015 and has been in service until the perforations became plugged while disposing of solids and liquids on May 27, 2016. Objective: Perform a CT FCO to 10,060' PBTD and return the well to service. Coil Tubing Procedure 1. MIRU CTU and tanks. 2. NU CT BOPE. Perform initial pressure test to 250 psi low and 4,500 psi high. Subsequent pressure tests will be to 250 psi low/3500 psi high. a. Notify AOGCC 24 hours in advance of BOP test. b. Confirm test pressures are per the approved Sundry. c. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. d. Nitrogen will NOT be used for the CT FCO. ✓ l/ 3. PU lubricator. MU and test coil connector. MU coil cleanout BHA. 4. Stab lubricator onto tree and pressure test to 250 psi low/3500 psi high. 5. Open tree and count turns on valves. Record in Ops cab. Start RIH and perform weight checks as needed 6. RIH with CT and attempt to dry tag. Slickline will tag top of fill prior to CT operations. • Well Prognosis Well: MPU B-24 l3ilwrp Alaska.LL) Date:5/28/2016 7. Clean out fill down to 10,060' MD with seawater and/or produced water and viscosifiers as needed. Fluff and stuff solids into the perforated interval. If needed, pump down the 2" CT x 4-1/2" annulus for additional rate to dispose of the solids in the wellbore. Add lubricant as needed. "- 8. POOH with CT once well bore is clean. 9. RDMO CTU. 10. Turn well over to production. Attachments: 1. Well Schematic 2. CTU BOPE schematic 3. Tree/Wellhead Schematic 4. Flow diagram: Fill Cleanout 111 • • Milne Point Unit Well: MPB-24 SCHEMATIC Last Completed: 7/6/2015 Irkcorp Alaska,LLC PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn ID Top Btm s 20" Conductor 91.1/NT-80LHE/N/A N/A Surface 110' 20 + Lrd ii: 9 5/8 " Surface 40/L-80/BTC 8.835 Surface 4,080' 7" Production 26/L-80/BTC 6.276 Surface 12,066' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Hydril 521 3.958 Surface 7,312' L" ( JEWELRY DETAIL No Depth Item 1 7,291' 7"Hyd Set Permanent Packer it tet 2 7,305' XN Nipple(3.725"ID) 95/8" , 3 7,311' WLEG 4 9,164' HOWCOType'H-ES'Cementer 5 10,060' EZSV Plug PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Ugnu MF 8,260' 8,280' 4,654' 4,660' 20 7/6/2015 Open WELL INCLINATION DETAIL CBL TOC @ KO P @ 500' 4100'ND/ Max Hole Angle=74.66 deg. @ 5,824'MD k 3,336 TVD Hole Angle at perfs—70° (:i a: OPEN HOLE/CEMENT DETAIL 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole .e, Cf, 7" Cmt w/200 sks(1st Stage)then 250 sks(2"d Stage)Class"G"in 8-1/2"Hole 6" 4 Ugnu GENERAL WELL INFO ri* API:50-029-22642-00-00 4 Drilled and Cased by Nabors 27-E -2/28/1996 Plugged and Suspended by Nabors 27-E—3/3/1996 Recompleted by Nordic 3—5/10/15 - 5 Calc.TOC @ 10,296'MD/ k. . 5,899 TVD 1 +: K PCIF} t' Plug 1 @ t, ` '`.*:11-; 1 11,692-12,584' 7 TD=12,584'(MD)/TD=7,934'(TVD) PBTD=10,060'(MD)/PBTD=5678'(R/D) Revised By:PC 5/28/2016 H .• H Me Point Unit COIL BOPE MPU B-24 5/28/2016 toi.,,,,p,S,11a.ka.Lit I Lubricator to injection head 771 1-75"Single Stripper 1 I Q I--i - ..1 ,,,..,[111:1 /5!4-: 1/16 151A f3=,nd c-- . s .3 s I p I, Illiti 1" El 1, orill ill1 . LIE i 1 Crossover spool ivii mi 4 1/16 15M X 4 1/16 101VI ail .iti Crossover spool iti, iv 4 1/16 10M X 4 1/16 51v1 piti !fli i._ Purrip-In Sub 4 1/16 SM ..n i 1502 uon till ii 1 ic. i i Crossover spool ezi Manual Gate Manual Gate 4 1/16 SM X 2 9/16 SM i 2 1/8 5M 2 1/8 5M I o q • • BHTA,Pis,4 1/16 5M 1 MPB-24 Completed ) l Tubing hanger,FMC-TC-B- 05/10/15EC,11 X 41/16/4 h 521 �e rat sok t,t HYdril lift and susp,w/4' Valve,Swab,CIW r, 0 0 pup&4"type H BPV 4 1/16 5M FE,HWO,DD ,.; , profile,300-4 pkt,1-CCL, trim t J' • 0 3.266"centers,Alloy 7 ® a material tilt IMO II' N. / ® • 01 1 M °,7',,, 2 \ t,- - l G --) Valve,SSV,CIW t---1,..,.. A�j16• 4. 4 1J16 SM FE,Baker oper, F 47 e EE trim Fir• - c2L O Ili w H. Valve,Master,CIW t r ®` 4 1/6 5M FE,HWO,DD L s trim 3,®.3`:rr ...Moo' Adapter,FMC A-5-EC, 11"5M rot flg btm X 2 9/16 5M stdd top,w/ 300-4 pkt,w/2-CCL, im 1— Tubing prepped f/BIW Tubing head,FMC-OBS, ,0,— penetrator,3.266 centers 13 5/8 5M Stdd bottom x ! �' 11 5M FE,Top,wJ 2-2 1/ _I- ={ il ® �a=l_ 16 5M SSO,IP style lockpins ' I ® i 1i='I—p I�l``,t246 . '1 III♦ 'l I .-<?,/®11�I -1.-1 Casing head,FMC-OBS, ,.. All casing valves2 1/16 5M 13 5/8 5M FE X 13 3/81. * OCT-20 SOW,w/2-2 1/16 5M Elf ® ®e �T N ._ SSO,IP style lockpins ill to Ott -1- f'111.'4% . 1lIll i �Ir .,® •' 111 1 �/ I • 0 H H a 0 a s E D n a ® § § °P E *E g o o '8 .0 G A o v v ° > U .0 3o R R' U is °" o» ¢ m0z L.accz w > W a° cMZ 3m 0 3F I; 4 La m w m L. IIIIgZZo E Cs 1 > > C7 a w > C7 CO 0 r. 11,1111o r•, I O L Ahr V G .., . d iii . C IVp 'L:\\N‘, -5 Ir' : 1 --4 .,—..,- 1111:MM111131Ll ..t-'41""--"''.... : nnnnea o O o WY N - - - N Z - w a 4 -- w . i c c c , 0 o' 0 0 m b. m0 o Cd u+ a 7 Z Q H Y co m O O L. 0gp 2 i • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Saturday, May 28, 2016 5:01 PM To: Paul Chan Cc: Quick, Michael J (DOA); Bo York;Ted Kramer;John Barnes; Rob Handy; Sloan Sunderland; Luke Keller; Monty Myers Subject: Re: MP B-24 CT FCO Verbal Approval Request Paul, Verbal approval granted to use coil tubing to perform a FCO as proposed in the attached sundry request. Regards, Guy Schwartz AOGCC Sent from my iPhone On May 28,2016, at 1:00 PM, Paul Chan<pchan@hilcorp.com>wrote: Guy/Mike MP B-24 is our permitted disposal well for Grind and Inject. While pumping down the well with liquids and solids from the MP J-28 drill well the well locked up and we are assuming that the perforations are plugged. A slickline tag will be performed to determine top of fill. The well requires a coiled tubing fill cleanout in order to continue with drilling operations. We have contingency plans in place to temporarily handle liquids and solids, but returning the B-24 well to service is critical for us to efficiently handle the liquids and solids being generated. Hilcorp Alaska respectfully requests verbal approval to perform a CT FCO on the well. The documents have been reviewed by the Operations Engineer,Operations Manager, and Field Foreman. Attached is the procedure and 10-403 for your review. Thanks Paul than Senior Operations Engineer Alaska North Slope Team Hilcorp Alaska LLC (907) 777—8333 (w) (907)444—2881 (c) <MPU B-24 CT FCO 2016-05-28.docx> <MPB-24 SCHEMATIC 7-17-2015.pdf> 1 1 '1(p -009 3 • • RECEIVED FEB 292016 AOGCG Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524 3800 Centerpoint Dr Suite 1400 CERTIFIED MAIL#7014 0150 0000 6324 9220 Anchorage,AK 99503 Phone:907/777-8300 February 25, 2016 Fax:907/777 8560 Mr.Edward J. Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Mr.Chris Wallace SCANNEC Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage,AK 99501-3192 Mr.Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage,AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK-1I002-B, General Wastewater, Permit No.2005DB001-0020 Milne Point Injection Well, UIC Permit AK-1I005-B, General Wastewater., Permit No.2005DB001-0001 Liberty Class 1 Injection Well, UIC Permit AK-11013-A, General Wastewater., Permit No. 2005DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test(MIT) and fluid movement tests that are required every two years at the Northstar NS 10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK-1I002-B; 2) the MIT that is required every year at the Milne Point Class 1 wells, MPB-50 and MPB-24 to meet the permit requirement in UIC Permit AK-1I005-B; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-11013-A. • • • Mechanical Integrity Test Notification February 25,2016 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Thor Cutler of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782- 7431, or via e-mail at dheebner@hilcorp.com. Sincerely, 6)619 f,taty Deborah Ileebner North Slope Environmental Specialist HILCORP ALASKA, LLC Attachment cc: Thor Cutler,EPA Region 10 Kyle Monkelien, BSEE Kevin Pendergast, BSEE Jason Seltisch • • Proposed Schedule for 2016 Mechanical Integrity Testing Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Deadline date test date? Movement Logs Planned after MIT? Milne Point By July 20, Approximately July 10- Coordinate with No, fluid MPB-24 2016 15, 2016. Northstar test movement logs date. were done in 2015 and are only required at Milne Point every three years. Milne Point By July 20, Approximately July 10- Coordinate with No, fluid MPB-50 2016 15, 2016. Northstar test movement logs date. were done in 2014 and are only required at Milne Point every three years. Northstar NS10 By July 24, Approximately July 5- Coordinate with Fluid movement 2016 10, 2016. Milne test date. logs are planned as they are (May be required at NS10 extended up every two years. to 3 months Previously done with Director in 2014. approval) Northstar NS32 By July 25, Approximately July 5- Coordinate with Fluid movement 2016 10, 2016 Milne test date. logs are planned as they are (May be required at NS32 extended up every two years. to 3 months Previously done with Director in 2014. approval) Liberty CRI Well N/A The Liberty CRI well All logs required will not be drilled in to complete the 2016. well would be scheduled with the MIT. • • RECEIVED s 7-4 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 JAN 22 2016 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101-3140 AOGCC PRONe' JAN 19 2016 OFFICE OF COMPLIANCE AND ENFORCEMENT Reply To: OCE-l01 CERTIFIED MAIL-RETURN RECEIPT REQUESTED Mr. John Barnes Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 SCANNED MAY 01 2018 Anchorage, Alaska 99503 Re: Issuance of Modified Underground Injection Control(UIC) Permit No. AK1I005-B Milne Point Unit,North Slope, Alaska Dear Mr. Barnes: The U. S. Environmental Protection Agency, Region 10, (EPA) is issuing a modified Underground Injection Control permit for Hilcorp Alaska, LLC (Flacon)), Milne Point Unit (MPU),North Slope, Alaska. The enclosed document authorizes the facility to inject non-hazardous industrial waste utilizing up to four(4) Class I injection wells at the MPU into the naturally saline intervals of the Schrader Bluff (West Sak) and Ugnu (Prince Creek) Formations. No comments were received during the public comment period of December 14, 2015 through January 14,2016. A public hearing was offered January 14, 2015, in the Federal Building in Anchorage, Alaska; however, due to the absence of any specific written requests for the hearing, the hearing was cancelled. This letter constitutes service of notice under 40 C.F.R. 124.19(a). The modified permit will become effective on the date signed as indicated in the permit unless the Environmental Appeals Board receives a timely appeal meeting the requirements of 40 C.F.R. 124.19. Information about the administrative appeal process may be obtained on-line at epa.govieab or by contacting the Clerk of the Environmental Appeals Board at(202) 233-0122. S' ceref 111F Edward J. Kowalski Director Enclosure: Modified Permit AK.11005-B cc wienc: Marc Bentley, ADEC Division of Water!Wastewater Discharge Permits ,/Chris Wallace, AOGCC • • Page 1 of 23 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK.-11005-B In compliance with provisions of the Safe Drinking Water Act(SDWA), as antended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, Hilcorp Alaska LLC (Hilcorp) (Permittee) is authorized to inject non-hazardous industrial waste utilizing up to four(4) Class I injection wells at the Milne Point Unit(MPU) located on the Alaskan North Slope (NS). Injection is authorized into the Schrader Bluff(West Sak) and Ugnu(Prince.Creek) Formations, in accordance with Title 40 C.F.R. § 144.33 and the conditions set forth herein. The Milne Point oilfield located in the MPU near the Beaufort Sea about 250 miles north of the Arctic Circle and lies west of Prudhoe Bay, on the North Slope of Alaska approxintately 25 miles west of Deadhorse. Alaska. The proposed disposal well(s) are in an area where there are no underground sources of drinking water(USDWs) and an aquifer exemption delineated by a cylinder along the well trajectory of the Class I injection well(s) from(below permafrost) 2000 feet true vertical depth(TVD) to 4270 feet TVD. The aquifer exemption was issued by EPA on September 29, 2004 for aquifers between approximately 2000 feet(base of the permafrost) and 4,270 feet true vertical depth subsea(TVDss) and was clarified to include the area delineated by.a cylinder of V4 mile radius along the well trajectories whose latitudes and longitudes (per NAD83)respectively at the well surface location are latitude 70.472809 and longitude -149.413148 for well MPB-50, latitude 70.4728 and longitude -149.4131 for well MPB-51, latitude 70.4728 and longitude - 149.4131 for well MPB-52 and latitude 70.475454 and longitude-149.415140 for well MPB-24. (Exact well locations are subject to change or correction.) Injection of hazardous waste as defined under the Resource Conservation and Recovery Act(RCRA), as amended, (42 USC 6901) or radioactive wastes (other than naturally occurring radioactive material — NORM from pipe scale) are not authorized under this permit. All references to Title 40 of the Code of Federal Regulations are to regulations that are in effect on the date that this permit is issued. Figures and appendices are referenced to BP Exploration(Alaska) Inc. (BPXA) I3PXA's Renewal Application for Milne Point Unit UIC Permit AK-11005-A dated April 30, 2014. This permit shall become effective on November 3, 2014, in accordance with 40 C.F.R. § 124.15. This permit and the authorization to inject shall expire at midnight,November 2, 2024, unless terminated. Modification signed this 15th day of Januar , 201.. Edward J. Kowalski, Director e Office of Compliance and Enforcement U.S. Environmental Protection Agency Region 10 (OCE-101) 1200 Sixth Avenue Suite 900 Seattle, WA 98101 Page 2 of 23 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE 1 PART I GENERAL PERMIT CONDITIONS 4 EFFECT OF PERMIT 4 PERMIT ACTIONS 4 Modification,Reissuance,or Termination 4 Transfer of Permits 5 SEVERABILITY 5 CONFIDENTIALITY 5 GENERAL DUTIES AND REQUIREMENTS 5 Duty to Comply 5 Penalties for Violations of Permit Conditions 6 Duty to Reapply 6 Need to Halt or Reduce Activity Not a Defense 6 Duty to Mitigate 6 Proper Operation and Maintenance 6 Duty to Provide Information 6 Inspection and Entry 7 Records 7 Reporting Requirements 9 Anticipated Noncompliance 9 Twenty-Four Hour Reporting 9 Other Noncompliance 10 Reporting Corrections 10 Signatory Requirements 10 PLUGGING AND ABANDONMENT 11 Notice of Plugging and Abandonment 1 1 Plugging and Abandonment Report 11 Cessation Limitation 11 Cost Estimate for Plugging and Abandonment 12 FINANCIAL RESPONSIBILITY 12 . 1 Page 3 of 23 PART II WELL SPECIFIC CONDITIONS 13 CONSTRUCTION 13 Casingkind Cementing 13 Tubing, Packer and Completion Details 13 New Wells in the Area of Review 14 CORRECTIVE ACTION 14 WELL OPERATION 14 Prior to Commencing Injection 14 During Injection 15 Mechanical Integrity 15 Injection Zone 18 Waivers to UEC Program Requirements 19 Injection Rate and Pressure 19 Annulus Pressure 20 Injection Fluid Limitation 20 MONITORING 21 Monitoring Requirements 21 Contindous Monitoring Devices 21 Monitoring Direct Waste Injection 21 Alarmsland Operational Modifications 21 REPORTING REQUIREMENTS 22 Quarterly Reports 22 Report Certification 22 REPORTING FORMS 23 • • Page 4 of 23 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The Permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The Permittee shall not construct,operate, maintain,convert, plug, abandon,or conduct any other activity in a manner that allows the movement of any contaminant into USDWs,except as authorized by 40 CFR Part 146. The underground injection activity,otherwise authorized by this permit shall not allow the movement of fluid containing any contaminant into underground sources of drinking water,if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 C.F.R. Part 142 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act(SDWA). Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA,or any other law governing protection of public health or the environment from imminent and substantial endangerment to human health or the environment. This permit may be modified,revoked and reissued, or terminated during its term for cause. Issuance',',of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights,or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling,storage,or treatment facilities. This perrinit is based on the permit application submitted by BP Exploration(Alaska)Inc. (BPXA)on April 30,2014, and supplemental material related to the aquifer exemption ruling granted 11y EPA dated September 29, 2004. B. PERMI11 ACTIONS I. Modification, Reissuance.or Termination Thii permit may be modified, revoked and reissued,or terminated for cause as specified in 40 C.F.R. §§ 144.39 and 144.40. In addition,the permit can undergo minor modifications for cause as specified in 40 C.F.R. § 144.41. The filing of a request for a permit modification,revocation and reissuance,or termination, or the notification of planned changes,or anticipated noncompliance on the part of the Permittee does not staythe applicability or enforceability of any permit condition. • • • . Page 5 of 23 • 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT(EPA Form 7520-7)and in accordance with 40 C.F.R. § 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SDWA. C. SEVERABILITY The pro'iisions of this permit are severable,and if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances,and the remainder of this permit,shall not be affected(thereby. D. CONFIDENTIALITY In accordance with 40 C.F.R. Part 2, any information submitted to EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time!of submission in the manner prescribed in 40 C.F.R. §2.203 and on the application form or instructions,or, in the case of other submissions, by stamping the words "confidential" or"confidential business information" on each page containing such information. If no claim is made at the time of submission,EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 C.F.R. Part 2(Public Information). Claims of confidentiality for the following information will be denied: 1. The name and address of the Permittee. 2. Information that deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REOUIREMENTS 1. Duty to Comply The Permittee shall comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action,permit termination, revocation and reissuance, modification,or for denial of a permit renewal application;except that the Permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 C.F.R. § 144.34. 4 . • Page 6 of 23 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty value calculated on a per day basis of such violation. Any person who willfully or negligently violates permit conditions is subject to a fine calculated on a per day basis of the violation and/or being imprisoned. 3. Duty to Reapply If the Permittee wishes to continue an activity regulated by this permit after the expiration date of this permit,the Permittee must apply for and obtain a new permit. To be timely,a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for a Permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. { 5. Duty to Mitigate The Pennittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The Pennittee shall,at all times,properly operate and maintain all facilities and systems of treatment and control (and related appurtenances)which are installed or used by the Permittee to achieve compliance with the conditions of this permit. Proper operation andlmaintenance includes effective performance, adequate funding, adequate operator staffing and training.and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve coniipliance with the conditions of this permit. De-characterized waste may be appropriately disposed in a Class I non-hazardous well [refer to 40 C.F.R. § 148.10)1. 7. Duty to Provide Information The Permittee shall provide to the Director,within a reasonable time,any information that the Director may request to determine whether cause exists for modifying, revoking and reissuing, terminating this permit,or to determine compliance with this permit. The Permittee shall also provide to the Director, upon request,copies of records required to • S Page 7 of 23 be kept by this permit. 8. Inspection and Entry The Permittee shall allow the Director,or an authorized EPA representative,upon the presentation of credentials and other documents as may be required by law to: a. Enter upon the Permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy,at reasonable times, any records that are kept under the conditions of this permit; I f c. Inspect at reasonable times any facilities, equipment(including monitoring and control equipment), practices,or operations regulated or required under this permit; and d. I Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA,any contaminants or parameters at any location. 9. Records a. The Permittee shall retain records and all monitoring information, including all calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation,copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time. b. The Permittee shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the Permittee: shall deliver the records to the Director. The Permittee shall continue to retain the records after the three-year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. This permit does not require retention of hard copies or original records. The record keeping requirements of the permit are met by retaining the records in electronic or original hard copy format. The original records are not required to be retained when electronic versions are retained. e. Records of monitoring information shall include: (1) The date, exact place,and time of sampling or measurements; ' I i Page 8 of 23 (2) The name(s)of the individual(s)who performed the sampling or measurements; (3) The date(s)analyses were performed; (4) The name(s)of the individual(s)who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 C.F.R. § 136.3, in appendix HI of 40 C.F.R. Part 261, or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including,but not limited to measurements of pressure, temperature, mechanical integrity,and chemical analyses shall be done in accordance with EPA's Quality Assurance Program Plan. f. As part of the COMPLETION REPORT,the Permittee must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. This permit covers four wells,including two active Class I wells(MPB-50& MPB-24)that have been in operation since 2005 and 2015, respectively plus two additional wells(MPB-51 and MPB-52). An updated Waste Analysis Plan(WA?)was submitted as part of the September 18, 2015 MPB-24 Completion Report. The WAP from the completion report may be incorporated by reference to satisfy the WAP plan submittal requirements. g. The Permittee shall require a written manifest for each batch load of waste received for waste streams that are not hard piped and continuous. The manifest shall contain a description of the nature and composition of all injected fluids,date of • • • Page 9 of 23 receipt,source of material received for disposal,name and address of the waste generator,a description of the monitoring performed and the results,a statement stating if the waste is exempt from regulation as hazardous waste as defined by 40 C.F.R. §261.4,and any information on extraordinary occurrences. For waste streams that are hard-piped continuously from the source to the wellhead, the Permittee shall also provide for continuous,recorded measurement of the 1 discharge rate and shall provide such sampling and testing as may be necessary to provide a description of the nature and composition of all injected fluids,and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR §261.4. h. Dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit shall be noted on the gauge or meter. Earlier records shall be available through a computerized maintenance history database. 10. Reporting Requirements The Permittee shall give notice to the Director,as soon as possible,of any planned physical alterations or additions to the permitted facility or changes in type of injected waste. 11. Anticipated Noncompliance The Pennittee shall give advance notice to the Director of any significant planned changes in the permitted facility or activity that may result in noncompliance with permit requirements. 12. Twenty-Four Hour Reporting a. ' The Permittee shall report to the Director or an authorized EPA representative any noncompliance that may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the Permittee becomes aware of the circumstances. If EPA or the Permittee discovers that fluids have moved above the upper confining zone along a wellbore within the AOR. then injection shall cease until the fluid movement problem can be diagnosed and corrected. The following shall be included as information that must be reported orally within 24 hours: (1) Any monitoring or other information that indicates that any contaminant may cause an endangerment to an underground source of drinking water. (2) Any noncompliance with a permit condition or malfunction of the injection system. • • Page 10 of 23 b. A written submission shall also be provided within five(5)days of the time the Permittee becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause, the period of noncompliance, including exact date and times, and,if the noncompliance has not been corrected, the anticipated time it is expected to continue,and steps taken or planned to reduce, eliminate,and prevent recurrence of the noncompliance. 13. Other Noncompliance The Permittee shall report all other instances of noncompliance not otherwise reported at theitime monitoring reports are submitted. The reports shall contain the information listed in Permit.Condition Part I E.12.b. 14. Reporting Corrections When the Permittee becomes aware that he/she failed to submit any relevant facts in the permit application or submitted incorrect information in a permit application or in any report to the Director, the Permittee shall promptly submit such facts or information. 15. Signatory Requirements a. All permit applications, reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level of vice-president,or by a duly authorized representative of that person. A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager,operator of a well or a well field, superintendent,or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization is submitted to the Director. b. If an authorization under paragraph 15.a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph 15.a. of this section must be submitted to the Director prior to or together with any reports, information, or applications to be signed by an authorized I � IP • • Page 1 l of 23 representative. c. Any person signing a document under paragraph 15.a. of this section shall make the following certification: "I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information,I believe that the information is true,accurate,and complete. I ant aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F. PLUGdING AND ABANDONMENT t. Notice of Pluggkie and Abandonment The Permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2. Plugging and Abandonment Report The Pennittee shall plug and abandon the well as provided in the Final Well Abandonment(Closure)portion(Section 6.5)of the April 30,2014. Permit Renewal Application for Milne Point UIC Permit AKII005-A(Permit Renewal Application) submitted by the Permittee,which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the Permittee shall submit a report to the Director in accordance with 40 C.F.R. § 144.51(p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the Permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the Permittee shall plug and abandon the well in accordance with the plan unless he/she: a. Provides notice to the Director; b. Demonstrates that the well will be used in the future; or c. Describes actions or procedures. satisfactory to the Director that the Permittee will take to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the technical requirements applicable to active injection wells unless waived by the Director. . • Page 12 of 23 4. Cast Estimate for Plugging and Abandonment a. The Permittee estimates the 2014 cost of plugging and abandonment of the permitted Class I well(s)to be approximately$300,000/well. Please refer to I Section 6.5 and Exhibits 6-3 and 6-4 of the April 30,2014 Permit Renewal Application. b. The Pennittee must submit financial assurance and a revised estimate prior to April of each year. The estimate shall be made in accord with 40 C.F.R. § 144.62. c. The Permittee must keep at the facility or at the Permittee central files in Anchorage during the operating life of the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes,the documentation submitted under 40 C.F.R. § 144.63(0 shall be amended as well to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. e. The Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor,within 10 business days after the commencement of the proceeding. G. FINANCIAL RESPONSIBILITY The Permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close, plug,and abandon the underground injection well. If the financial test and corporate guarantee provided under 40 C.F.R. § 144.63(0 should change, the Permittee si?all immediately notify the Director. The Permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved,unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. Consistent with 40 C.F.R.§144.63 and regarding incapacity of owners or operators,guarantors, or financial institutions,the Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, namiiig the owner or operator as debtor,within 10 business days after the commencement of the proceeding. Furthermore, an owner or operator must notify the Regional Administrator by certified mail of the commencement of a voluntary or involuntary proceeding under title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. A guarantor of a corporate guarantee as specified in §144.63(0 must make such a notification if he is named as debtor,as required under the terms of the guarantee(§144.70(0). 1 • . , Page 13 of 23 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION I. Casing and Cementing of Existing Sidetrack and/or Replacement Wells The Permittee shall case and cement the well(s)to prevent the movement of fluids into or between underground sources of drinking water other than the authorized injection interval(see II.C.4,below). Casing and cement shall be installed in accordance with a casing and cement program approved by the Director and in accordance with EPA Class I well construction practices(40 C.F.R. § 146.12) and the State of Alaska/AOGCC Regulations(20 AAC § 25.412 and 20.AAC § 25.252). If primary cement returns to surface are not observed for the(20 inch or other)surface ca.ing cementing procedure, the Director or authorized EPA representative is to be notified as to the nature of the augmented testing proposed to ensure the integrity of the cement bond and adequacy of any Top Job procedure.The Cement Bond/Ultrasonic Imaging(USIT or other) logs and pressure tests(leak off test and/or formation integrity test) will be run for both the(20 inch or other)surface and(9 5/8 inch or other)injection casings to confirm zonal isolation and verify casing integrity.The Permittee shall prgvide not less than fourteen(14)days advance notice to the Director or authorized EPA representative for all cementing operations. Should a change(s) be required to the design casing and cementing program(due to unanticipated conditions),the Director or authorized EPA representative shall be notified as to the nature of the change(s),so that approval is obtained from the Director or authorized EPA representative enabling the well to be drilled and completed in a safe an successful manner. The casing,cementing and well construction data will be in compliance with the procedures outlined in Well Construction portion (Section 6),and the well schematics (Ehibits 6-1,6-2 and 6-3)of the April 30, 2014 Permit Renewal Application. 2. Tubing,Packer and Completion Details of Existing Sidetrack and/or Replacement Wells The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with the procedures in the permit application. The current tubing and packer locations for well MPB-50 and MPB-24 are approved. In the event that a packer needs to be set or re-set at a revised depth at a later date,and the Permittee will perform a mechanical integrity test prior to resuming injection, submit the necessary • data and obtain authorization from EPA prior to resuming injection.The packer will be set no more than 100 feet MD from the top of the injection zone. • Page l4of23 3. New Wells in the Area of Review EPA has set a quarter mile radius as the Area of Review(AOR) for this Class I UIC permit application.New Class I permitted UIC wells shall be installed in accordance with a casing and cement program approved by the Director and in accordance with EPA Class I well construction practices(40 C.F.R. § 146.12)and will also follow the State of Alaska/AOGCC Regulations(20 AAC 25.412 and 20 AAC 25.252). New wells within the AOR shall be constructed in accordance with the Alaska Oil and Gas Conservation Commission Regulations Title 20 Chapter 25. If in the future,any deilelopment or service wells are drilled that penetrate the injection intervals within the area of review,these wells shall have casing cemented to the formation throughout the entire section from 200 feet TVD below the proposed injection zone to 200 feet TVD above the injection zone as identified in the April 30,2014 Permit Renewal Application. B. CORRECTIVE ACTION The applicant has identified no wells in the Area of Review(AOR)which require corrective action in order to prevent fluids from moving above the confining zone. If the applicant later discover that a welt or wells within the AOR require(s)corrective action to prevent fluid movement, then the applicant shall inform the EPA upon such discovery and provide a corrective action plan for EPA review and approval. C. WELL cPERATION 1. The existing well (MPB-50)has fulfilled requirements of Part II C.I. Prior to Commencing Injection of New, Existing Sidetrack and/or Replacement Wells Injection operations pursuant to this permit may not commence until: a. Construction is complete and the Permittee has submitted two copies of COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-9), see APPENDIX A; and i F (1) The Director or authorized EPA representative has inspected or otherwise reviewed the new, existing,sidetrack or replacement injection well(s)and finds it is in compliance with the conditions of the permit;or (2) The Permittee has not received notice from the Director or authorized EPA representative of intent to inspect or otherwise review the new,sidetrack or replacement injection well(s)within thirteen(13)days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the Permittee may commence injection. • Page 15 of 23 b. The Permittee demonstrates that the well has mechanical integrity as described in Part II.C.3. Mechanical Integrity below and the Permittee has received notice from the Director or authorized EPA representative that such a demonstration is satisfactory. The Permittee shall notify EPA at least two weeks prior to conducting this initial test so that an authorized EPA representative may be present.Note: Since well MPB-50 has been on injection since 2005 and has successfully demonstrated mechanical integrity on an annual basis, the requirements of C.l.a and C.I.b. from above have been met. MPB-24 similarly demonstrated mechanical integrity and met the requirements of C.1.a and C.1.b above following the well's completion in 2015. However, the requirements under Part LI.C.3.—Mechanical Integrity remain in force for wells MPB-50 and MPB-24;and c. The Permittee has conducted a step-rate injection test(SRT)and submitted a preliminary report to EPA that summarizes the results. A SRT was conducted on wells MPB-50 and MPB-24 and the results were submitted to the EPA. Therefore, the Permittee is not required to conduct another SRT prior to resumption of Class I injection activities upon permit modification. 2. During Injection During injection, the well injection pressure,tubing-casing(inner)annulus pressure, inje6tion rate,will be monitored on a continuous basis. Out-of-limit alarms and shut-off systems will be installed and the injection facility plant shall be monitored by trained and qualified operators during injection. Visual and automatic monitoring of the tubing- casing(inner annulus)and tubing pressures will occur routinely with pre-set,out-of- limit alarms to inform supervisory personnel. The wellhead,controls,and monitoring instrumentation will be enclosed in an insulated structure. 3. Me4hanical Integrity a. Standards The injection well(s) must have and maintain mechanical integrity pursuant to 40 C.F.R. § 146.8. • S Page 16 of 23 b. Prohibition without Demonstration of Mechanical Integrity Injection operations are prohibited after the effective date of this permit unless the Permittee has conducted the following tests and submitted the results to the Director: 1) In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig)for not less than thirty minutes. Pressure shall show a stabilizing tendency. That is, the pressure may not decline more than 10 percent during the 30-minute test period and shall experience less than one-third of its total loss in the second (last) half of the 30-minute test period. If the total loss exceeds 10 percent or if the loss during the second 15 minute period is equal to or greater than one-half the loss during the first 15 minutes, the Permittee may extend the test period for an additional 30 minutes to demonstrate stabilization. However, the MIT meets criteria at the completion of the first 30 minute test if the total pressure loss in the 30 minute period is 2%or less and the pressure loss in the first 15 minutes(first time period) is more than the pressure in the second 15 minutes(second time period). The MPB-50 well has been on injection since 2005 and has successfully demonstrated its mechanical integrity(both internal and external)on an annual basis(with the tests being witnessed by EPA representatives). Similarly, MPB-24 successfully demonstrated its mechanical integrity (both internal and external) following the well's completion in 2015 (with the tests being witnessed by EPA representatives). The wells is are approved to continue injection upon approval of this permit modification. After the effective start date of this permit,the SAPT will be required annually until expiration of the ten (10) year permit period. This internal mechanical integrity test(standard annulus pressure test-SAPT) will be required annually if the well is active and once every two (2)years if the well is inactive.The internal mechanical integrity test due dates may be extended up to three(3) months to accommodate constraints resulting from drilling,operational or other logistics related to operating in the Arctic North Slope environment. At the discretion of the Director, and depending on the results of the internal annulus mechanical integrity test data,the frequency for demonstrating internal mechanical integrity(no leaks in the tubing-casing annulus or in the tubing-packer assembly) may be revised (either increase or decrease in frequency)as specified and approved by the Director or authorized EPA representative. (2) To detect movement of fluids in vertical channels adjacent to the well bore and to determine that the confining zone is not fractured, an approved fluid movement test shall be conducted at an injection pressure at least equal to the average continuous injection pressure observed in the previous six months. Page 17 of 23 Approved fluid movement tests include, but are not limited to tracer surveys, temperature logs,noise logs.oxygen activation/water flow logs(WFL), borax pulse neutron logs(PNL),or other equivalent logs. Fluid movement test procedures not previously used to satisfy this requirement must be submitted 30 days in advance and are subject to prior approval by the Director or authorized EPA representative. Copies of all logs shall be accompanied by a descriptive and interpretive report. Fluid movement/confinement logs will be run initially upon completion of a new, existing sidetrack and/or replacement well and prior to initiation of injection at start-up. After acquiring this baseline data,the fluid movement/ confinement logs will be required every three(3)years while the well is active until expiration of the ten(10)year permit period. The test due dates may be extended up to three(3)months to accommodate constraints related j to operating in the Arctic North Slope environment. At the discretion of the Director,and depending on the results of the baseline data, the frequency for demonstrating external mechanical integrity(no flow behind pipe and isolation above injection interval)and utilizing alternative diagnostic techniques, may be revised(either increase or decrease in frequency)as specified and approved by the Director or authorized EPA representative. Note:The past well MPB-50 fluid movement logs completed in 2014 are recognized to fulfill this three(3)year requirement. (3) Internal tubing inspection logs(pipe analysis logs,caliper logs, or other equivalent logs)shall be run once every three(3) years while the well is active, or at the Director or authorized EPA representative's discretion, to monitor condition, thickness and integrity of the downhole tubing. A three month grace period is granted to the test due dates. Any exposed section of the injection casing will have to be logged during any scheduled workover for tubing change-out etc.Copies of the logs shall be accompanied by a descriptive and interpretive report.Note: This is a new requirement.The past well MPB-50 internal tubing inspection logs completed in 2014 are recognized to fulfill this three(3)year requirement. c. Terms and Reporting (1) Two(2)copies of the log(s)and two(2)copies of a descriptive and interpretive report of the mechanical integrity tests identified in 3.b(2)and 3.b(3)shall be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in 3.b.(1)any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The Permittee shall report the results of such tests within 45 days of completion of the tests. r • • Page 18 of 23 (3) After the initial mechanical integrity demonstration, the Permittee shall notify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations. (4) The Director will notify the Permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this 13-day review period. If the Director does not respond within 13 days, injection may continue. (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the Permittee shall halt operation immediately and shall not resume operation until the Director or authorized EPA representative gives approval to resume injection. (6) The Director may, by written notice, require the Permittee to demonstrate mechanical integrity at any time. 4. Injection Zone Injction shall be limited to the Schrader Bluff(also referred to as the West Sak)and the Ugnu(also referred to as the Prince Creek) Formations. The top of the injection interval will be at the TUZC stratigraphic marker(within the Ugnu Formation) with the base of the injection interval defined by the base of the Schrader Bluff Formation at the SBA5 marker(see Exhibits 3-2- Mike Point Well B-02 Type Log and Exhibit 3-3 - Milne Point Area Cross Section Map in the 2004 original permit application). The top of the injciction interval is currently at 4080' TVD (9020' MD)and the base of the injection interval is at 4923' TVD(11 172' MD) in the MPB-50 reference well location.The top of the injection interval is at 4329' TVD(7366' MD) and the base of the injection inteuval is at 4920' TVD (9081' MD) in the MPB-24 well location. • Page 19of23 5. Waivers to UIC Program Requirements As a result of the subsurface aquifer conditions and the aquifer exemption for Class I injection granted by EPA on September 29. 2004,there are no underground sources of drinking water below the permafrost in the MPU area of the Class I injection wells. Furthermore on July 2, 1987,EPA concurred with Alaska Oil and Gas Conservation Commission on the decision made to exempt aquifers beneath MPU for Class II injection activities,as recorded in AOGCC Area Exemption Order(AEO) two (2). EPA is granting the following waivers of UIC regulatory program requirements as listed below: (i) Compatibility of Formation and Injectate [40 C.F.R. §§ 146.12 (e)and 146.14(a) (8)]: Based upon the applicability of past injection studies, petrophysical logging data, existing rock and fluid samples plus successful injection practices into the same formation for the initial permit period and similar formations on the North Slope of Alaska,EPA is waiving the above two requirements for any additional sampling and characterization of formation fluids and injection rock matrix in order to determine whether or not they are compatible with the proposed injectate. (ii) Injection Zone Fracturing,Ambient Monitoring and Pressure Buildup [40 C.F.R. § 146.13 (a)(1),and (d) (1)and(2)]: Based on log surveillance results over the initial permit period that consistently verify no significant upward movement of injected fluids in the MPB-50 well, continuity of geologic formations and that transmission through faulting is not likely to transmit fluid above the confining zone, and there are no improperly sealed,completed,or abandoned wellbores in the area of review,EPA is waiving the above three requirements of an ambient monitoring of saline aquifers above the confining zone and a monitoring program including a pressure buildup of the injection zone annually. Also,based on the above. EPA is waiving the prohibition against fracturing the injection interval,and would instead allow fracturing to a minor extent at the injection well confined to the injection zone so long as new fractures are not initiated nor existing ones propagated within the upper and lower confining zone. However, in no case shall injection pressure initiate fractures in the confining intervals above and below the injection zone. Authorized injection in the wells will be limited to the permitted injection zone injection intervals located between 4080' TVD(9020' MD)and 4923' TVD(11172' MD). However. external mechanical integrity demonstrations are required. [See Part II C.3.b(2)1. 6. Injection Rate and Pressure Injection pressures shall not initiate new fractures or propagate existing fractures in the upper confining zone as that stratigraphic interval is described in the Milne Point Unit Well B-02 Type Log, Exhibit 3-2 of the permit application. Neither shall the maximum S Page 20 of 23 injection pressure, measured at the wellhead.exceed 3000 pounds per square inch(psig), exept as follows. Inhe event of a plant shut-down or outage,there may be instances where injection pressures exceed 3000 psi(unrelated to fluid injection activities). In such instances, the Permittee shall notify the Director or his designee by telephone or electronic mail within twenty four(24)hours of the initial exceedance of the 3000 psig limitation and shall submit a written incident report not later than ten (10)days thereafter. It should be noted that the wellhead working pressure limit of 5000 psig should not be exceeded at any time. Besides alarms and automatic shutdown controls, the wellhead assembly will include a surface safety valve to provide additional security. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non-freezing solution. To accommodate swings in wellbore temperatures and tubing thermal expansion,a positive surface pressure up to 1500 nsig is authorized for the inner annulus(tubing x long string injection casing). Since the tubing-casing annulus pressure will vary due to temperature changes.the high-low annulus pressure limits can be adjusted, if necessary and upon approval by the Director or authorized EPA representative, (to include both the summer and winter amlpient temperature swings). Note_ The authorization of up to 1500 psi on the inner annulus is to enable shut-down and alann systems to be set at appropriate pressure limits,so as not to shut-down the facility from unintended causes not related to direct injection activities,and is not intended to allow the Permittee to continue to maintain the well on injection, in the evert of a loss of mechanical integrity or when there is pressure build-up either in the tubing by inner annulus or between the injection casing and surface casing(between the inner annulus by outer annulus),resulting in a potential sustained casing pressure scenario.In the event of a loss of mechanical integrity,then the Permittee has to meet the requirements as outlined in Part II.C.3.c.5 of this permit. 8. Injection Fluid Limitation This permit only authorizes the injection of those fluids identified in the permit doc.imentation. In the event that third party wastes are accepted, the third party must certify that fluids for injection are not hazardous waste or radioactive wastes. Fluids gen4rated from Class I injection well construction and well workover,and fluids generated from the operation and maintenance of Class i injection wells and associated injection well piping, may be disposed in a Class I non-hazardous injection well. De- � E Page 21 of 23 characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. § 148.1(d)). NOTE: Neither hazardous waste as defined in 40 C.F.R. Part 261 nor radioactive wastes other than naturally occurring radioactive material (NORM) from pipe scale shall be injected for disposal. D. MONITORING 1. Monitoring Requirements Samples and measurements collected for the purpose of monitoring shall be representative of the monitored activity. 2. Cottinuous Monitorina Devices Continuous monitoring devices shall be installed, maintained, and used to monitor injection pressure and rate for those streams that are hard-piped and continuous, and to monitor the pressure of non-freezing solution in the annulus between the tubing and the long string casing. Calculated flow data are not acceptable except as a back-up system if the primary continuous injection rate device malfunctions. 3. Monitoring Direct Waste Injection Dire t waste injection pumping operations at the well site shall be continuously manned and visually monitored. During these pumping operations, a chronological record of the . time of day,a description of the waste pumped, injection rate and pressure,and well annulus pressure observations shall be maintained.The person in charge of the pumping • operations must be identified on the pumping record. k 4. AlaLms and Operational Modifications a. The Pennittee shall install,continuously operate, and maintain alarms to detect excess injection pressures and significant changes in annular fluid pressure. These alarms must be of sufficient placement and urgency to alert operators in the control room.The Permittee shall install and maintain an emergency shutdown system to respond to losses of internal mechanical integrity as evidenced by deviations in the annular fluid pressures. b. Plans and specifications for the alarms shall be submitted to the Director or authorized EPA representative prior to the initiation of injection. Since well MPB- 50 is an existing Class I well,and has been on injection since 2005. and the plans and specifications were submitted in the Completion Report,the monitoring and alarm systems in place for the existing well MPB-50 is hereby approved as meeting • S Page 22 of 23 the requirements of this section. E. REPORTING REQUIREMENTS 1. Quarterly Reports The Permittee shall submit quarterly reports to the Director containing the following infIormation: a. Monthly average,maximum,and minimum values for injection pressure,rate,and volume shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Graphical plots of continuous injection pressure and rate monitoring. c. Daily monitoring data in an electronic format. d. Physical,chemical, and other relevant characteristics of the injected fluid. e. Any well workover or other significant maintenance of downhole or injection- related surface components. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice" tests. g. Any other tests required by the Director. 2. Report Certification Al� reporting and notification required by this permit shall be signed and certified in accordance with Part I.E.15.; electronically stored and maintained at the permittee's facility,or company headquarters;electronically submitted to an electronic(email) address provided by the Director or authorized EPA Representative; and upon request by the Director or authorized EPA representative, submitted as a hard copy to the following address: UI Manager,Ground Water Unit(OCE- 101) U.S. Environmental Protection Agency Region 10 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 E 4 • • • • Page 23 of 23 APPENDIX A REPORTING FORMS Enclosed ar EPA Forms: 7520-7 APPLICATION TO TRANSFER PERMIT 7524-8 INJECTION WELL MONITORING REPORT 75 0-9 COMPLETION FORM FOR INJECTION WELLS • S OMB No.2040.0042 Approval Expires 11130/2014 i United States Environmental Protection Agency 4-CEPA Washington,DC 20460 Application To Transfer Permit Name and Address of Existing Permittee Name and Address of Surface Owner • State County Permit Number Locate Well and Outline Unit on Section Plat•640 Acres • N Surface Location Description I I I I I I 114 of 114 of 1/4 of,®114 of Section_ Township Range -4-1-4- -4-I-4- Locate wall In two directions from nearest lines of quarter section and drilling unit I I I I I 1 -f-�--� - - -r-7- Surface — - -4- - - -- Location ft.fan(NIS) Line of quarter section I 1 1 I 1 I and—It.from(E1W) Line of quarter section. W i I I I I I . e Weil Activity Well Status Type of Permit —-I — — -4-1---I-- Class I _individual Operating I _I I _ _ I _I I _ _Class a ModiticatlonlConversion —Area r? r Brine Disposal Number of Wells Proposed I I I I I I —Enhanced Recovery Hydrocarbon Storage S !Class III Other Lease Number Well Number Namo(s)and Addresses)of New Owner(s) Name and Address of New Operator • Attach to this application a written agreement between the existing and new permittee containing a specific date for transfer of permit responsibility,coverage,and liability between them. The new permittee must show evidence of financial responsibility by the submission of a surety bond,or other adequate assurance,such as financial statements or other materials acceptable to the Director. Certification I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that,based on my inquiry of those individuals Immediately responsible for obtaining the information,I believe that the information is true,accurate, and complete.I am aware that there are significant penalties for submitting false information,including the possibility of fine and imprisonment (Ref.40 CFR 144.32) Name and Official Title (Please type or print) Signature Cate Signed EPA Form 7520.7(Rev. 12.11) • • PAPERWORK REDUCTION ACT The public reporting and record keeping burden forthis collection of information is estimated to average 5 hours per response. Burden means the total time,effort, or financial resource expendedby persons to generate,maintain, retain,or disclose or provide information to or for a FederalAgency.This includes the time needed to review instructions;develop, acquire, install. and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to the collection ofnformation;search data sources;complete and review the collection ofinformation;and,transmitor otherwise disclose the information.An agencymay not conduct or sponsor,and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.Send comments on the Agency's need for this information,the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division,U.S.Environmental Protection Agency(2822), 1200 Pennsylvania Ave., NW,Washington,D.C. 20460.Include the OMB control number in any correspondence. Do not send theompleted forms to this address. Well Class and Type Code Class I Wells used to inject waste below the deepest underground source of drinking water. Type"1" Nonhazardous industrial disposal well Nonhazardous municipal disposal well "W" Hazardous waste disposal well injecting below USDWs Other Class I wells(not included in Type"I'"M,'or'W) Class II Oil and gas production and storage related injection wells. Type"D" Produced fluid disposal well "R" Enhanced recovery well Hydrocarbon storage well (excluding natural gas) "X" Other Class II wells(not included in Type"D,""R,"or"H") Class III Special process injection wells. Type"G" Solution mining well Sulfur mining well by Frasch process "U" Uranium mining well Other Class III wells(not included in Type"G,""S," or"U") Other Classes Wells not included in classes above. Class V wells which may be permitted under§ 144.12 Wells not currently classified as Class I, II, Ill, or V EPA Form 7520-7(12-11)Reverse ° . • OMB No.2040-0042 Approval Expires 1113012014 United States Environmental Protection Agency \".EPA Washington,DC 20460 Injection Well Monitoring Report Year Month Month Month injection Pressure(PSI). 1. Minimum i 1 2. Average 3. Maximum Injection Rate(GalIMln)' 1. Minimum 2. Average 3. Maximum Annular Pressure(PSI) 1. Minimum 2. Average 3. Maximum Injection Volume(Gal) 1. Monthly Total 2. Yearly Cumulativo Temperature IF°) 1. Minimum 2. Average -- 3. Maximum pH 1. Minimum 2. Average 3. Maximum Other I - • Name and Address of Permittee Permit Number , Name and Official TitI$ (Please type or prim) Signature Data Signed EPA Form 7520.8(Rev12-11) • , Paperwork Reduction Act The public reporting and record keeping burden for this collection of information is estimated to average 25 hours per quarter for operators of Class I hazardous wells, 16 hours per quarter for operators of Class I non- hazardous wells,and 30 hours per quarter for operators of Class III wells. Burden means the total time, effort, or financial resource expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal Agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to the collection of information; search data sources; complete and review the collection of information; and,transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Send comments on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division, U.S. Environmental Protection Agency(2822), 1200 Pennsylvania Ave.,NW., Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send the completed forms to this address. EPA Form 75204 Revers, • • 0M8 No.2040.0042 Approval Expires 11/3412014 United States Environmental Protection Agency `APA Washington.DC 20460 /+� Completion Form For Injection Wells Administrative Information 1.Permittee - • Address (Permanent Mailing Address)(Street City,and ZIP Code) . • 2.Operator • Address (Street,City,1State and ZIP Code) 3.Facility Name Telephone Number _ Address (Street,City,)State and ZIP Code) _ • 4.Surface Location D4crlption of Injection Well(s) State County . Surface Location Doseption 1/4 of 114 o o 1/4 of, 114 of Section Township Range Locate well In two directions from nearest lines of quarter section and drilling unit Surface Location—ft.inn(yS) Line of quarter section and ft.from(VW), Line of gimlet section. Well Activity I Well Status Type of Permit Class IOperating _Individual _Class IIModification/Conversion _Area:Number of Wells „_Brine Disposal Proposed Enhanced Recovery Hydrocarbon Storage Class 1111 Other Lease Numbei Well Number SU11mit with this Completion Form the attachments listed in Attachments for Completion Form. Certification I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document 'nd all attachments and that,based on my inquiry of those individuals immediately responsible for obtaining the Iformation,I believe that the information is true,accurate, and complete.lam aware that there are significant pen ties for submitting false information, including the possibility of fine and Imprisonment (Ref.40 CFR 144.32) j Name and Official Titi (Please type or print) Signature Date Signed I EPA Form 7620.9(Rev. 12-11) • PAPERWORK REDUCTION ACT The public reporting and record keeping burden for this collection of information is estimated to average 49 hours per response for a Class t hazardous facility, and 47 hours per response for a Class t non-hazardous facility. Burden means the total time,effort, or financial resource expended by persons to generate,maintain,retain,or disclose or provide information to or for a Federal Agency.This inctudesthe time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information,and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements:train personnel to be able to respond to the collection of information;search data sources; complete and review the collection of information;and, transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to,a collection of information unless it displays a currently valid CMB control number.Send comments on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden.including the use of automated collection techniquesto Director,Collection StrategiesOivision,U.S.Environmental Protection Agency(2822). 1200 Pennsylvania Ave.. NW.Washington,D.C.20460.Include the CMB control number in any correspondence. Do not send the completed forms to this address. Attachments to be submitted with the Completion report: I.Geologic Information 4.Provide data on centralizers to include number,type and depth. 1.Lithology and Stratigraphy 5. Provide data on bottom hole completions. A.Provide a geologic description of the rock units pene- trated by name,age,depth,thickness,and lithology of 6.Provide data on well stimulation used. each rock unit penetrated. III.Description of Surface Equipment B.Provide a description of the injection unit. 1.Provide data and a sketch of holding tanks,flow lines, (1)Name filters,and injection pump. (2)Depth(drilled) (3)Thickness IV.Monitoring Systems (4)Formation fluid pressure (5)Age of unit 1.Provide data on recording and nonrecording injection (6)Porosity(avg.) pressure gauges,casing-tubing annulus pressure (7)Permeability gauges,injection rate meters,temperature meters,and (8)Bottom hole temperature other meters or gauges. (9)Lithology (10)Bottom hold pressure 2.Provide data on constructed monitor wells such as (11)Fracture pressure location,depth,casing diameter,method of cementing. etc. C.Provide chemical characteristics of formation fluid (attach chemical analysis). V.Logging and Testing Results D.Provide a description of freshwater aquifers. Provide a descriptive report interpreting the results of geophysical logs and other tests. Include a description (1)Depth to base of fresh water(less than 10,000 mg/I and data on deviation checks run during drilling. TDS). (2)Provide a geologic description of aquifer units with VI.Provide an as-built diagrammatic sketch of the injec- name,age,depth,thickness,lithology,and average total lion well(s)showing casing,cement,tubing,packer,etc., dissolved solids. with proper setting depths.The sketch should include well head and gauges. II.Well Design and Construction VII.Provide data demonstrating mechanical integrity 1.Provide data on surface,intermediate,and long string pursuant to 40 CFR 146.08. casing and tubing.Data must include material,size, weight,grade,and depth set. VIII.Report on the compatibility of injected wastes with fluids and minerals in both the injection zone and the 2.Provide data on the well cement,such as type/class, confining zone. additives,amount,and method of emplacement. 1X.Report the status of corrective action on defective 3.Provide packer data on the packer(if used)such as wells in the area of review. type,name and model,setting depth,and type of annular fluid used. X.Include the anticipated maximum pressure and flow rate at which injection will operate. EPA Form 7520-9 Reverse 10u -coq • Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524 3800 Centerpoint Dr Suite 1400 Certified Mail: 7012 1640 0000 6132 6944 Anchorage,AK 99503 Phone: 907/777-8300 Fax: 907/777-8560 November 25, 2015RE UIC Manager, Ground Water Protection Unit C E'VE U.S. Environmental Protection Agency(OCE-127) DEC 0 2 2015 1200 Sixth Avenue Seattle, WA 98101 AGC C Re: Class I Injection Well—Milne Point MPB-24 Courtesy Notification Milne Point Unit(MPU) Permit Number AK-1I005-B Dear UIC Manager: The Completion Report required in Part II C.l.a. of permit AK-11005-B for well MPB- 24 submitted by Hilcorp Alaska, LLC (Hilcorp) on September 18, 2015 included a copy of the Waste Analysis Plan for the Class I UIC Wells authorized by AK-1I005-B. This Waste Analysis Plan states waste generated by non-Hilcorp activities are considered Third Party wastes. By this letter, Hilcorp is providing a courtesy notification that we intend to accept third party wastes in the first quarter of 2016 at the MPU Grind and Inject Facility for injection into B-24. Attached is a copy of our Third Party Waste Analysis and Sampling Plan for your files. Initially Hilcorp will only accept third party RCRA-Exempt or Exploration and Production Exempt waste as defined by 40 CFR Section 261.4. The Third Party Waste Analysis and Sampling Plan requires that an Officer of the Company certify that wastes sent to the MPU Grind and Inject Facility for injection into B-24 are not hazardous or radioactive waste as defined by 40 CFR Section 261.23. In addition to a Hilcorp approved Third Party Waste Analysis and Sampling Plan, a written North Slope Manifest and Hilcorp Third Party Disposal Approval letter is required for every load of waste received at the facility as required in AK-1I005-B permit condition E.9.g. In the future, Hilcorp may decide to expand the acceptance of wastes to other items allowed under the Class I UIC permits. Hilcorp will provide notification to USEPA and submit a revised Third Party Waste Analysis and Sampling Plan before accepting these additional wastes. UIC Manager, Ground Ar Protection Unit U.S. Environmental Protection Agency November 25, 2015 Page 2 If you have any questions, please contact at Deborah Heebner at 907-670-3382 or dheebner@hilcorp.corn. Sincerely, Dave Wilkins Senior Vice President HILCORP ALASKA, LLC. Enclosures cc: Thor Cutler, EPA Region 10 Chris Wallace, AOGCC Marc Bentley, ADEC Jason Selitsch EPA Region 10 UIC Program Compliance Inspector Denali Environmental P.O. Box 771794 Eagle River, Alaska 99577 • • HILCORP THIRD PARTY WASTE ANALYSIS AND SAMPLING PLAN MPU Grind and Inject Waste Injection Facility This Waste Analysis and Sampling Plan must be approved by Hilcorp Alaska, LLC (Hilcorp) before third party wastes can be accepted for disposal at the Milne Point Unit (MPU) Grind and Inject Facility located at B Pad. Please complete and return this form to the Hilcorp North Slope Environmental Specialist's office in the Central Facilities Production Facility (CFP) at Milne Point (email AlaskaNS-EnvironmentalSpecialist@hilcorp.com). If a consultant or contract laboratory is preparing your plan, make sure that all of the required information is included. In addition to an approved Waste Analysis and Sampling Plan, a North Slope Manifest and Third Party Disposal Approval Letter is required for all wastes accepted at the MPU Grind and Inject Facility. Manifests may only be completed and signed by generators, transporters, and receivers who have satisfactorily completed Waste Management"Red Book" Training {Alaska Waste Disposal and Reuse Guide (also known as "The Red Book)}1. If you have anyquestions, please contact the HilcorpNorth Slope Environmental Specialist's office in Milne Point at p the email above or at 907-670-3382. WASTE ANALYSIS PLAN APPROVAL (to be completed by Hilcorp) Signature: Date: Printed Name: Title: 1. GENERATOR INFORMATION Name of Company Mailing Address North Slope Contact(Name) Phone Number Title Fax Plan Prepared By (Name/Company/Title) Signature and Date Authorized Company Management (Name) Signature 2. FACILITY INFORMATION: Describe the facility(ies) where waste is generated, handled, or stored. Name of Facility Location Describe the types of activities or operations that take place at the facility(ies). 1 Alaska Waste Disposal and Reuse Guide. (Also known as "The Red Book") BP Exploration (Alaska) Inc. (BPXA) and ConocoPhillips Alaska, Inc. (CPA I). Rev 1 11/12/15 • • Are any of the following used or stored at the facility(ies)? Check&explain all that apply. Paints (bulk/aerosol ?) Fuels (diesel, gasoline, aviation fuel) Thinners Lubricating/hydraulic oils Solvents (types ?) Chlorinated solvents (Lectra-Clean, etc.) Acids or caustics Radioactive sources or tracers Antifreeze/glycols Parts washers (Solvent type ?) Methanol Sumps Tank containments (Tank contents) Explain Each: 3. WASTE MANAGEMENT INFORMATION Describe all wastes generated at the facility(ies) -exclude office type wastes i.e. paper, cardboard, camp trash, etc. Waste type Source (operation or activity) HILCORP Third Party Waste Analysis/Sampling Plan for p. 2 of • • Describe procedures used to properly manage waste handled at the facility. Standard Operating Procedures or a Waste Management Plan may be attached. HILCORP Third Party Waste Analysis/Sampling Plan for p. 3 of • Hilcorp will only accept RCRA-Exempt or Exploration and Production Exempt waste from third parties. Complete Section 4 for EACH WASTE TYPE you wish to dispose of at MPU Grind and Inject Facility. 4. WASTE DISPOSAL INFORMATION: Waste Type: How is this waste generated? Provide a physical description of this waste. How much of this waste do you expect to dispose of at the MPU Grind and Inject Facility? (volume, total number&type of containers, etc.) Is this one-time-only, or will there be regular loads of this material in the future? The MPU G&I facility will require that the Flashpoint be greater than 140° F and that the pH be greater than 2 and less than 12.5. Will the Flashpoint be greater than 140° F and will the pH be greater than 2 and less than 12.5 for your waste? Hilcorp reserves the right to spot test deliveries of waste, to visit your facilities to inspect the waste generation at your facility and request copies of your procedures to ensure the waste is RCRA-Exempt or Exploration and Production (E&P) exempt waste as defined in 40 CFR 261.4(b)(5). Is this waste E&P exempt? Why ? HILCORP Third Party Waste Analysis/Sampling Plan for p.4 of • • Attachment 1 Reactivity Checklist Initial Waste Characterization Complete for each waste sent to the MPU Grind and Inject Facility. Multiple wastes may be listed under a single certification. Wastes listed must correspond to the names/types of wastes included under the Waste Analysis Plan. For the initial hazardous waste determination, a waste stream must be evaluated for the characteristic of reactivity. A waste is a reactive hazardous waste if it exhibits one or more of eight properties described below (40 CFR Section 261.23). EPA's Methods Innovation Rule (70 FR 34538, 6/14/05) withdrew specified reactivity test methods. Instead, generators must use other appropriate methods or process knowledge in determining whether a particular waste is hazardous due to its reactivity. The following checklist is to be completed by the waste generator and submitted to the HILCORP North Slope Environmental Specialist for review. A copy of this checklist should be filed with the analytical data for each the waste stream. Waste Type/Name: 1. 2. 3. 4. Do any of the following criteria apply to this/these waste stream(s)? YES NO 1. Normally unstable and readily undergoes violent change without detonating 2. Reacts violently with water 3. Forms potentially explosive mixtures with water 4. When mixed with water, generates toxic gases, vapors or fumes in a quantity sufficient to present a danger to human health or the environment 5. Is a cyanide or sulfide bearing waste which, when exposed to pH conditions between 2 and 12.5 can generate toxic gases 6. Is capable of detonation or explosive reaction if it is subjected to a strong initiating source or if heated under confinement (example:pressurized aerosol cans) 7. Is readily capable of detonation or explosive decomposition or reaction at standard temperature and pressure 8. Is a forbidden explosive as defined in 49 CFR 163.51, a Class A explosive as defined in 49 CFR 163.53, or a Class B explosive as defined in 49 CFR 163.88 Company Name & Title Date HILCORP Third Party Waste Analysis/Sampling Plan for p. 5 of • Attachment 2 Hilcorp MPU G&I Waste Disposal Facilities Certification for Lack of Radioactivity Complete for each waste sent to the MPU Grind and Inject Facility. Multiple wastes may be listed under a single certification. Wastes listed must correspond with the names/types of wastes included under the Waste Analysis Plan. Waste Type/Name: 1. 2. 3. 4. 5. 6. 7. 4. I certify that the waste liquids and/or solids to be disposed at the MPU Grind and Inject disposal facilities contain no radioactive waste or material. This conclusion is based on my personal knowledge of the waste-stream and/or prior testing. Name & Title Date Company HILCORP Third Party Waste Analysis/Sampling Plan for p. 6 of • • Attachment 3 Hilcorp MPU G&I Waste Disposal Facilities Company Certification of Authorized Personnel for Waste Generator Certification and North Slope Manifest Signatures I, (name, title) officer of (company) authorize the following people to complete a "North Slope Manifest" to document delivery of waste to the Milne Point facility owned by Hilcorp Alaska, LLC. This waste is generated from petroleum industry related operations at (company, field name). The people approved on this list have: • Completed North Slope Manifest (Red Book) training, • Been trained in methods to characterize and segregate hazardous waste, nonhazardous waste, RCRA-Exempt or Exploration and Production Exempt waste and waste suitable for injection in a Class I UIC well, and • Authorization from our company to certify the loads have been generated at our facility and they are legal for delivery to your facility according to the Hilcorp Third Party Waste Analysis and Sampling Plan. Option 1: All (company) personnel and contractors with RedBook Training and listed on the current RedBook authorized personnel lists are allowed to sign and document North Slope Manifests delivered from company facilities to Hilcorp Alaska, LLC facility at Milne Point. Option 2: Only listed company personnel and contractors are authorized to sign North Slope Manifests for delivery to the waste facility. (listed names and titles) Signed by: Printed Name & Title Date Signature Company HILCORP Third Party Waste Analysis/Sampling Plan for p. 7 of • Attachment 4 INDEMNIFICATION AGREEMENT In consideration of the agreement of the Milne Point Unit and its working interest owners ("Owners") to allow Company to dispose of Resource Conservation And Recovery Act (RCRA) exempt waste at the Milne Point Grind and Inject Facility (Facility) operated by Hilcorp Alaska, LLC ("Operator") and located on B Pad within the Milne Point Unit, Company, on behalf of itself and its working interest owners (if any) in the operation which generated, handled, or stored the subject waste, agrees as follows: Company shall defend, indemnify, and hold harmless Owner, Operator, and their respective owners, members, directors, officers, employees, contractors, and agents ("Owner-Operator Group") from and against all claims, actions, suits, liability, losses, and damages of every kind for property damage or loss, environmental damage or loss, personal or bodily injury or disfigurement, and death, including actual costs and attorney's fees, arising out of, or in any manner related to the transportation to, and storage, testing, handling, and disposal of Company's waste at the Facility, whether or not such liability, loss, or damage is caused in whole or in part by the negligence or other fault of any member of the Owner-Operator Group. Company shall undertake the duties outlined in the previous paragraph without regard to the jurisdiction, venue, or merit of any such claims, actions, or suits. In any claim, action or suit between Company and third parties concerning matters which are the subject of the duties of the Company outlined herein, Operator may, in its sole and unfettered discretion, employ attorneys and experts of its own selection to appear and represent the interests of any member of the Owner-Operator Group at the expense of Company. The obligations under this agreement shall commence when Company first contacts Operator regarding waste disposal or Operator initially accepts waste for disposal from Company (whichever occurs first), and shall continue for the life of the Facility and for 30 years following the end of the Facility's operation and closure. If this indemnification agreement is ruled to be invalid, then the Third Party shall share in the Facility's closure costs. This agreement is binding on Company, its owners, members, directors, officers, employees, and agents, and their respective successors and assigns. Company: Hilcorp Alaska, LLC, as Operator and Working Interest Owner of Milne Point Unit By: By: Name: Name: Title: Title: Date: Date: HILCORP Third Party Waste Analysis/Sampling Plan for p. 8 of STATE OF ALASKA • RECEIVE® AKA OIL AND GAS CONSERVATION COMMISSION SEP 2 9 2015 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations J Fracture Stimulate J Pull Tubing Operations shutdown Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ 8rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 0 Other:Convert to Class!Disposal Inj. ❑✓ 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska, LLC Development E Exploratory ❑ 196-009 3.Address: Stratigraphic❑ Service ❑ 6 API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage AK,99503 50-029-22642-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0047432/ADL 392703 MILNE PT UNIT KR B-24 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A MILNE POINT/UGNU UNDEFINED/KUPARUK RIVER OIL 11.Present Well Condition Summary: Total Depth measured 12,584 feet Plugs measured 10,060 feet true vertical 7,934 feet Junk measured N/A feet Effective Depth measured 10,060 feet Packer measured 7,291 feet true vertical 5,678 feet true vertical 4,363 feet Casing Length Size MD TVD Burst Collapse Conductor 110' 20" 110' 110' Surface 4,080' 9-5/8" 4,080' 3,328' 5,750psi 3,090psi Production 12,066' 7" 12,066' 7,443' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic feet SCANNED JAjV 2.Ul True Vertical depth See Attached Schematic feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80/BTC 7,312' 4,370' 7,291'MD Packers and SSSV(type,measured and true vertical depth) 7"Hyd Set N/A 4,363'TVD N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 100 0 Subsequent to operation: 0 0 0 80 0 14.Attachments(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations CI Exploratory❑ Development p Li Service ❑✓ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: WDSPL Class I a WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ Li 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: 315-249,315-277&315-382 Contact Stan Porhola Email sporhola@hilcor..com Printed Name Stan Porhola Title Operations Engineer Signature �, / /,4, 9 �j-if t. Phone 777-8412 Date 9/29/2015 031 j to) I3L/.$ 74_ ,% i e 13-f� RBDMS 1( �,� ULl 0 1 2015 Form 10-404 Revised 5/2015 l�//r/� Submit Original Only 6 /� H . • Milne Point Unit Well: MPB-24 . HSCHEMATIC Last Completed: 7/6/2015 Hilcorp Alaska,LLC PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn ID Top Btm j t -yk.. 20" Conductor 91.1/NT-80LHE/N/A N/A Surface 110' 20' 1' 9-5/8" Surface 40/L-80/BTC 8.835 Surface 4,080' 7" Production 26/L-80/BTC 6.276 Surface 12,066' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Hydril 521 3.958 Surface 7,312' r ri JEWELRY DETAIL +I No Depth Item yr 1 7,291' 7"Hyd Set Permanent Packer 9-5/8"'�'t I 2 7,305' XN Nipple(3.725"ID) 3 7,311' WLEG 4 9,164' HOWCO Type'H-ES'Cementer 5 10,060' EZSV Plug PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status Ugnu MF 8,260' 8,280' 4,654' 4,660' 20 7/6/2015 Open WELL INCLINATION DETAIL CBL TOG @ KOP @ 500' 4100'ND/ Max Hole Angle=74.66 deg. @ 5,824'MD 3,335 TVD 4 y'�! OPEN HOLE/CEMENT DETAIL 20"" Cmt w/250 sks of"Arcticset I(Approx.)in 30"Hole 9-5/8' OM w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole 7Cmt w/200 sks(1Stage)then 250 sks(2"d Stage)Class"G"in 8-1/2"Hole v = GENERAL WELL INFO t 2 API:50-029-22642-00-00 Drilled and Cased by Nabors 27-E -2/28/1996 lr Plugged and Suspended by Nabors 27-E-3/3/1996 3 ' Recompleted by Nordic 3-5/10/15 irst 91s=ugnu 1,,F 4 g 4 Cl g r -- 5 I-o(ac' M D Calc.TOC @ 10,295 MD/ ii � 5,899'TVD a 44 P It i .1 1 44 ',,.» ° Plug 1 @ 11,697-12,584' 7 TD=12,584'(MD)/TD=7,934'(1VD) PBTD=5'(M))/PBTD=5'(TVD) Revised By:TDF 7/17/2015 • • • Hilcorp Alaska, LLC HiIcor!)Alaska.LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MP B-24 50-029-22642-00-00 196-009 5/3/2015 7/6/2015 Daily Operations: 4/29/15-Wednesday No operations to report. 4/30/15-Thursday No operations to report. 5/1/15-Friday No operations to report. 5/2/15-Saturday No operations to report. 5/3/15-Sunday Move in spot rig accepted 0530. Berm, Cellar spot tanks. 5/4/15-Monday Spot equipment, remove dry hole tree,set test plug by hand, NU BOPE,test waived by AOGCC Jeff Johnson @ 0730. Pressure test all lines function test and measure stack. PU 1 jt DP and connect to test plug and seat same .Attempt to shell test,chasing leak through out system. Pull test plug attempt to test against PA plug no go. Change out single seal test plug for tubing hanger w/TWC.Shell test to 3,500psi, OK.Test BOPE to 250psi low/3,500psi high and chart. Upper pipe ram failure.Test Annular to 250psi low/3,500psi high. Problems w/3.5" rams. Open and repair. Replace ram packers.Test 3.5" pipe rams 250psi low/3,500psi high,good test.Accumulaor draw down test OK.On load mill, pump out sub, bumper sub, oil jars 9 drill collars and drill pipe.Total DP needed 285 jts. Back out lock down screws retrieve hanger. MU milling BHA deep throat mill 6"OD, pump out sub 4-3/4"OD, bumper sub 4-3/4"OD, Oil jars 4-3/4" OD and 1 4-3/4" DC and Kelly jt 3.5" DP all connections 3.5" IF no x-overs in string.Tag up on cement @ 7'. Drilling cement, MU remaining DC BHA Circ 8.9 ppg SW @ 8 bpm/350-400 psi. Pump small sweeps on connections. Depth 176'. 5/5/15-Tuesday Drillin cement from 176'-269'through plug freeze protect in returns. Kick drill, all hands performed appropriately. Circ hole clean pipe is stuck (expected from diesel cement mix),work pipe swap circulation work pipe free. PU last DC total in hole 9 DC's RIH with DP break circ.Work way in hole PU DP to 1,200' circ hole,continue work pipe to 2,250',circ and sticking and set down problems from dehydrated drilling mud,freeze protect,SW mix, work continue in hole to 3,900' pump sweep and displace all fluid above second plug to 8.7+ppg SW. Resume RIH top of plug @ 3,950'getting some_ rubber back over shakers. @ 4,000' ROP slowed in solid cement-mill to slowed WOB and pump rates varied,torque inconsistant. Mill to 4,025'circulate hole to balance. POOH for mill change, mill was fouled with junk rubber and hard phenolic material origin unknown. Replace mill with same for new cutting matrix, RIH. Resume milling @ 4,025'still encountering some rolling junk torque fluctuating working it out with WOB,speed, circ rates and periodic reverse circ. • • Hilcorp Alaska, LLC t1&oil)Alaska,LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MP B-24 50-029-22642-00-00 196-009 5/3/2015 7/6/2015 Daily Operations: 5/6/15-Wednesday Continue milling from 4,035'-4,130' before breaking up junk,contine milling to 4,180'.Continue milling cement to top of retainer @ 4,209'. Minimal cement last 10'above plug.Torque disappeard and a quick wash to top of plug. Milling on EZSV immediate torque/junk problems still fighting junk. Multiple rotating and circulation variations applied still fighting junk from cement drillout above plug.Junk getting alongside, reverse returns, producing junk through deepthroat mill. POOH to check mill. Deep throat mill ID restricted with rubber and possibly locking remnant from top of CIBP. Install double pin X-over boot basket and PU original deep throat mill. RIH with modified milling assy.Tag up @ 4,210'+/-. Milling ahead better torque,depth 4,211'. 5/7/15-Thursday Mill ahead, mill fouling with junk again.Work all parameters.Torque needed too much surface action.Stop @ 4,212'. Install wear bushing to accomodate milling torque and rotation. Resume milling, plug broke free, begin chasing down hole. Displace drilling mud in 1,000' intervals to 10,183'. Rig up to test, EPA Witness Jason Selitsch/Region 10 UIC inspector on location with Wyatt Rivard Well Integrity Engineer HAK.JSA to perform 3,500psi casing test as per program. Multiple test multiple times max 1.6%loss in 30 minutes. Final test LP 3,619psi 15 minutes 3,601psi,30 minutes 3,588psi, 45 min 3,576psi. 1 hr 3,565 psi.Test over. POOH rack back DP, LD DCs and BHA, pull wear bushing.Spot in E line. RU E- Line and prepare to log. 5/8/15-Friday Continue wireline operations, multiple trips adjusting rollers and weights to get past 5,900'. Run CBL from 10,140'-1,380' to TOC. Run repeat sections in upper pipe.TOC 2,790'. RD wireline,set test plug, clean cement and trash in BOPs and pits, retrieve test plug. PU MU CIBP and setting tool, RIH w/DP from derrick PU 6 singles space out,set EZ Drill BP @ 10,060'. Set down and verify set. 5/9/15-Saturday Displace well bore with corrosion inhibitor treated packer fluid. Slip n'cut drilling line. POOH LD 3-1/2" DP and plug running tool. PU MU BHA verify packer set depth with Jason Selitsch/EPA. RIH w/completion and 175 jts 4-1/2" 12.6#L- 80 Hydril 521 tbg.Torque 4,500 ft/lbs. PU hanger and landing jt SW 105k up 80k do RILD. Land Tbg depths. WLEG 7,312.12',IBT PJ 7,306.01',4.5" IBTXN 7,304.76', 7" DL Permanent packer 7,290.63',XO 4.5 7,288.89',XO 7,284', 175 jts (7,233.89')4.5 12.6#Hydril 521 @ 50.31' hanger and PUP JT 3.31'. KB plus 47'. ND BOP NU tree. Pressure test void 500psi low/5,000psi high. Pump 90 bbls diesel freeze protect down annulus. 5/10/15-Sunday P/T lines, pump 90 bbl diesel down annulus drop ball bar.Wait on bar 1 hour pressure up to set packer 2,600psi initial _ �'j • shear pressue to 4,000psi set packer. PT and chart both tbg and annulus to 3,500psi and chart same.Test witnessed by tVt° \ Jason Selitsch UIC/EPA. RDMO release rig. M 5/11/15-Monday No operations to report. 5/12/15-Tuesday No operations to report. S 110 Hilcorp Alaska, LLC Hi!carp Alaska.LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MPB-24 50-029-22642-00-00 190-009 5/4/2015 7/7/2015 Daily Operations: 7/1/15-Wednesday No operations to report. 7/2/15-Thursday No operations to report. 7/3/15-Friday No operations to report. 7/4/15-Saturday No operations to report. 7/5/15-Sunday No operations to report. 7/6/15-Monday Arrive on location. PJSM prior to activities. MIRU.WLV function test. Pressure test lubricator to 3,000psi. Make up 20' of perf guns and RIH to tie in to CBL dated 5/8/2015 and correlate depth. Contact geologist and confirm depth correlation of perf guns. Fire guns from 8,260'to 8,280'. Tubing pressure increase to 350psi. POOH.Secure well, RDMO. Final Pressures-T/I/0= 350psi/Opsi/190psi. 7/7/15-Tuesday No operations to report. \069- coc • 0 1ED sti UNITED STATES ENVIRONMENTAL PROTECTION AGENCY . Art yo. REGION 10 z 1200 Sixth Avenue, Suite 900 5i w 422 o % gr Seattle,Washington 98101-3140 4 e 4, 44, ,,le AUG 3 -- 2015 OFFICE OF COMPLIANCE ANC ENFORCEMENT Reply to: OCE-101 CERTIFIED MAIL—RETURN RECEIPT REQUESTED RECEIVED Mr. John Barnes Hilcorp Alaska, LLC AUG 1 0 2015 3800 Centerpoint Drive, Suite 100 4 Anchorage,Alaska 99503 SCANNED 14 4 '" 140G CC Re: Underground Injection Control (UIC) Program Interim Approval to Inject into UIC Class I Well MPB-24 under Permit number AK1I005-B Milne Point Unit, North Slope, Alaska Dear Mr. Barnes: The U.S. Environmental Protection Agency, Region 10 (EPA), has witnessed portions of the well construction and reviewed tests conducted on Hilcorp Class I Well MPB-24. Based on the on-site observations and recent results of the tests, the EPA grants interim approval to Hilcorp under EPA UIC permit number AK-11005-B to commence injection at Milne Point Well MPB-24. The EPA looks forward to receiving the completion report within 30 days. Afler all permit requirements are fillfilled including the submittal of the completion information with the"Completion Form For Wells (EPA Form 7520-9)"per permit Part II CA.), then EPA will review the completion report and make an adequacy determination for final approval for injection into the LTIC Class I well MPB-24 at Milne Point. As you know, the aquifer exemption issued by the EPA on September 29, 2004, for aquifers between approximately 2000 feet (base of the permafrost) and 4,270 feet true vertical depth subsea(TVDss) includes the area delineated by a cylinder of 1/4 mile radius along the MPB-24 well trajectory whose surface location (per NAD83) is approximately latitude 70.475717 North and longitude-149.411925 West. We appreciate the cooperation of your staff during the well construction process. If you should have any questions, please do not hesitate to contact Thor Cutler of my staff at 206-553-1673 or at cutler.thor@enn.gov. S. ry, - - -I Edward J. Kowalski Director cc: Chris Wallace V Alaska Oil and Gas Conservation Commission-Anchorage Marc Bentley Alaska Department of Environmental Conservation-Anchorage M4/t -ZA- PthRegg, James B (DOA) �� From: Brooks, Phoebe L (DOA) Sent: Friday, July 31, 2015 9:36 AM tY)1 iC To: Wyatt Rivard Cc: Regg, James B (DOA) Subject: RE: EPA Class 1 Disposal Well MITs Attachments: MIT MPU B-24 07-20-15 Revised.xls Wyatt, Attached is a revised report changing the test type to "0" for MIT MPU B-24 07-20-15. I also removed Waived from the AOGCC Rep field (as this field should reflect an inspector's name if witnessed or be left blank if waived). Please update your copies or let me know if you disagree. Thank you, Phoebe Phoebe Brooks SCANNED rrAUG ` 2015 Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Wyatt Rivard [mailto:wrivard@hilcorp.com] Sent: Thursday, July 30, 2015 4:59 PM To: Wallace, Chris D (DOA); Brooks, Phoebe L (DOA); Regg, James B (DOA); DOA AOGCC Prudhoe Bay Cc: Alaska NS - Northstar - Operations Leads; Alaska NS - Milne - Wellsite Supervisors; Taylor Wellman; Stan Porhola Subject: EPA Class 1 Disposal Well MITs All, The following Class 1 Disposal Wells had passing EPA witnessed MIT-lAs. Please note that MPB-50 (PTD#2042520) demonstrated difficult stabilization due to—10degF wellhead temperature swings while injecting at—29000BWPD. Two attempts were required before operations and EPA inspectors were satisfied with stabilization. The attached plot shows 1 the MPB-50 Pressure vs Temperature correlation during the second, passing, test. The MIT forms are attached for reference. I Well Field PTD MPB-50 Milne Point 2042520 MPB-24 Point 1960090 r). NS 10 North Star 2001820 NS 32 North Star 2031580 1 Thank You, WyattRivard j W(•11 Inti Lrit\' Enp;inhyr () (9O7 777-8517 C. O09)G70-13001 ! wrivard@hilcorp.com ;C00 Ct•nt , PoInt. I t lye, Lilt(' 1•1OO Anchor:1;c. AK 99503 2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to Jim reggJ alaska cloy doa aoacc prudhoe bavlrDalaska goy phoebe brooks(Walaska qov OPERATOR: Hilcorp Alaska LLC FIELD/UNIT/PAD: Milne Point/MPU/B DATE: 07/20/15 OPERATOR REP: Kruskie AOGCC REP: Packer Depth Pretest Initial 15 Min 30 Min. 45 Min 60 Min Well MPB-24 Type In) N TVD 4,363' Tubing '781 -804 - 780 -781 Interval 0 P,T.D 1960090 " Type test P Test psi " 1500 Casing 10 -3,530_ " 3,433 "3,415_ P/F P ✓ Notes: Class 1 DW One year MIT witnessed by EPA Thor 7 OA 218 226 "220 �220 Cutler and Jason Selitsch Waived b AOGCC Bob Noble 2 5 bbls to reach test pressure Well tested shut-in Well Type In) TVD _ Tubing Interval P.T D Type test Test psi Casing P/F Notes: OA Well Type In) TVD Tubing Interval P T D Type test Test psi Casing P/F Notes: OA Well Type Int. TVD Tubing Interval P T D Type test Test psi Casing P/F • Notes: OA Well Type In) TVD Tubing Interval P T D Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D=Dnlling Waste M=Annulus Monitonng I=Initial Test G=Gas P=Standard Pressure Test 4=Four Year Cycle I=Industrial Wastewater R=Internal Radioactive Tracer Survey V=Required by Variance N=Not Injecting A=Temperature Anomaly Survey 0=Other(descnbe in notes) W=Water D=Differential Temperature Test Form 10-426(Revised 02/2012) MIT MPU B-24 07-20-15 Revised xis I Tree: 4.5" CIW tree. MPU F-851 Orig. __. elev. = 44.72 ' (N 27E) • Wellhead: 11" 5M FMC uen. 5 w/ 11" x 4.5" FMC Tbg. Hng.w/4.5: r 1, Orig. GL. elev.= 11.1' NSCT& 4" CIW "H" BPV profile }; DF to t/7" csg. hnr. = 31.7' (N 27E) Well required to have a SSSV 20" 91.1 ppf, H-40 113' installed. ES cementer 2288' 0 Cx 4.5" HES "X" nipple 2202' KOP@600' ` 3.813" ID Max. hole angle = 72 to 76 deg. f/ 3400' to 16,500' Hole angle through perfs. = 56 deg. Q SET MCX 8/13/2013 .75 BEAN INSTALLED 9 5/8",40 ppf, L-80 surface 8378 ' casing. 4.5", 12.6#, L-80 8rd EUE mod ( drift ID = 3.833", cap. = .01522 bpf) ° 7" 29 ppf, L-80, prod. csg.The bottom 15 jts. have btrs.threads, the remainder have FJ Hydril 563 ( drift ID = 6.059", cap. = 0.0371 bpf) Radioactive tag on tubing collar at 16852' and Radioactive tag on casing collar at 16,926' and 11 Two 7" x 19' marker joints from 17,172' to 17,210' and Baker S-3 perm packer 17109' Stimulation Summary (3.875" ID) none performed 4.5" HES"XN" nipple 3.813" 17133' Perforation Summary Ref log: USIT 01/03/99 - A a Size SPF Interval r (TVD) 4.5" SWS WLEG 17362' PACKING BORE W/3.75"NO-GO 3 3/8" 6 17436'-17496' (7067'-7100') 34B HJ II charges @ 60 deg. phasing Est. top of fish at 17568' 0 00 FISH: Tubing convey perf guns 138' a and RHC plug ball and seat. „•,•y,,,, , ,•,• 7"float collar (PBTD) 17,706' 7" casing shoe 17,792' DATE REV.BY COMMENTS MILNE POINT UNIT 12/30/98 JBF Drilled and Cased by Nabors 27E WELL F-85i 1/15/99 M. Linder Initial perf& completion by Nabors 4-ES API NO: 50-029-22936 BP EXPLORATION (AK) Milne Point Unit tilt WeII: MPUS27 SCHEMATIC Last Completed: 7/20/2015 lbIcon)Alaska,LLC PTD: 202-085 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 92/1-1-40 N/A Surface 112' Orig.DF Elev.=67.30/Orig.GL Elev.=39.30' 7" Intermediate 26/L-80/Btc-Mod 6.276 Surface 8,302' j i 20 4-1/2" Slotted Liner"A" 12.6/L-80/IBT 3.958 7,936' 11,009' 4-1/2" Slotted Liner"B" 12.6/L-80/IBT 3.958 8,165' 11,155' TUBING DETAIL 2-3/8" Tubing 4.6/1-55/SuperMax 1.995 Surface _ 7,692' 4-1/2" Tubing 12.6/L-80/IBT 3.958 Surface 7,775' 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.992 7,775' 7,838' JEWELRY DETAIL 1 No Depth Item 1 2,185' Camco 4.5"x 1"KGB-2 GLM w/RP valve BK Latch 2 7,656' Jet Pump and Retriever Assembly(Ran 7/25/15) 3 7,657' XO 2-3/8"Supermaxx 2-3/8"8RD 4 7,659' Jet Pump BHA 5 7,660' Standing Valve(Set 7/25/15;7,632'SLM) 6 7,661' Locator Seal Assembly(Spaced out 3.46'above Sealbore) 7 7,665' Sealbore,20'Long 8 7,686' Anchor Latch 9 7,688' Packer,Paragon II(2.0"ID Bore) 10 7,692' WLEG 11 7,727' Phoenix Discharge Pressure Gauge—3.850"ID -1 2 12 7,738' HES 4.5"`XD'Dura Sliding Sleeve !i Ik 3 13 7,758' Phoenix Sensor 4-1/2"Casing—ID Change to 2.840" 14 7,773' X0 4.5"12.6#NSCT Box x 3.5"NSCT Box 4 15 7,775' HSE 3.5"X-Nipple NSCT 16 7,786' Baker Premier Packer 7"x 3.5" I1= 5 17 7,833' HES 3.5"XN-Nipple—2.750"No Go 6 I 7 8 E 18 7,836' 3.5"NSCT WLEG—Bottom @ 7,837' 19 7,936' Baker Hook Wall,Hanger above 7"Window 20 7,962' Baker Hook Wall,Hanger outside 7"Window 21 8,165' Baker Tie Back Sleeve 22 8,177' Baker ZXP Liner Top Packer Ar 23 8,185' Baker 7"x 5"HMC Liner Hanger 9 LATERAL WINDOW DETAIL OPEN HOLE/CEMENT DETAIL Window in 7"Casing @ 7,948'to 7,960' 20" Cmt w/260 sx of Arcticset(Approx)in 42"Hole 11`10 Well Angle @ Window=74 Deg. 7, Cmt w/1,360 sx Class PF"L",650sx Glass"G"in 9-7/8"Hole j 11 WELL INCLINATION DETAIL WELLHEAD •:.•• '.12 KOP @ 600'MD Tree 4-1/16"-5M FMC 13 70 to 73 Deg.2,900'—7,800' 11"x 4.5"5M Gen.6 w/4.5"TC-II T&B 14Max Hole Angle=73 deg. @ 6,000'MD Wellhead Tubing Hanger CIW"H"BPV Profile Hole 15 New Tubing Head(Installed 2015) R �� 72 Deg.@Sliding Sleeve 16 Tubing Hanger w/2-3/8"8RD Lift Threads '17 Fish:Aluminum Blowout Plug—Lost 7/25/15 GENERAL WELL INFO issol OD:2.49"/Length:2.75"/Tag @ 7,732'SIM 18 API:50-029-23084-00-00 Drilled and Completed by Doyon 141 -15/28/2002 19 20 NOTE: 4,x° Prior to setting or pulling 4.5"BPV or TWC,notify FMC. C14 Lateral 4.5"TCII thread profile compatibility issue exists. 21 In 22 I "OB"Lateral 7" No TD=11,186'(MD)/TD=4,084'(1VD) PBTD=11,186'(MD)/PBTD=4,084'(TVD) Downhole Revised:7/25/2015 Updated By:STP 7/28/2015 , F T r(<0 s9 THE STATE Alaska Oil and Gas �, " O Conservation Commission fALAsKA Liget•t; _ __ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907 279.1433 OF ALAS' Fax 907.276 7542 www aogcc alaska.gov SCOSEU , U L 0 `� Z U i5 Tom Fouts k?._. ©O Ct Operations Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Ugnu Undefined and Kuparuk River Oil Pool, MPU KR B-24 Sundry Number: 315-382 Dear Mr. Fouts: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair DATED this day of June, 2015 Encl. ALCOVED ELS STATE OF ALASKA ,JUN 1 8 2U1„ ALASKA OIL AND GAS CONSERVATION COMMISSION 07f 4/2,11 f isAPPLICATION FOR SUNDRY APPROVALS 'AOGCC 20 MC 25.280 1.Type of Request Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well❑ Change Approved Program 2 Suspend ❑ Plug Perforations ❑ Perforate Q Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re-enter Susp Wel' D Stimulate ❑ Alter Casing ❑ Other:Convert to aassl Disposal In;. Q 2.Operator Name. 4 Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development Q 196-009 • 3.Address: Stratigraphic ❑ Service 1116.API Number. 3800 Centerpoint Drive,Suite 1400,Anchorage AK,99503 50-029-22642-00-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055 Will planned perforations require a spacing exception? Yes ❑ No 0 MILNE PT UNIT KR B-24 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0047432/ADL 392703 MILNE POINT/UGNU UNDEFINED• f K AIV6I-0,"/ 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) 12,584 7,934 10,060 5,678 10,060' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 20" 110' 110' Surface 4,080' 9-5/8" 4,080' 3,328' 5,750psi 3,090psi Intermediate Production 12,066' 7" 12,066' 7,443' 7,240psi 5,410psi Liner Perforation Depth MD(ft). Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80/Hydril 521 7,312' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): 7"Hyd Set Perm Pkr and N/A 7,291'MD/4,363'TVD and N/A 12.Attachments: Description Summary of Proposal Q 13 Well Class after proposed work. Detailed Operations Program ❑ BOP Sketch ❑ Exploratory 0 Stratigraphic❑ Development ❑ Service ❑✓ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 7/7/2015 Oil 0 Gas ❑ WDSPL Class-I Q Suspended ❑ 16.Verbal Approval: Date: N/A WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge Contact Chris Kanyer Email ckanyer(c�hilcorp.com Printed Name Tom Fouts Title Operations Regulatory Tech Signature )."--- ----4.......i4- Phone 777-8377 Date 6/18/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness 'Sundry Number: 3i5 • '3ZZ Plug Integrity ❑ BOP Test ❑ MechanicalIntegrityTest ❑ Location Clearance ❑ • Other I��exAl OY1 • C 6'�/� '-O 6 e f/1 c,C c taQ/✓L C.Q_ I..%J/ EPA t 5Sie61 p•e rrit.L* Pc,k '„ I o o .s 3 fcrt' Class I 'asfe s. Spacing Exception Required? Yes ❑ No Subsequent Form Required. /6— tiozi n APPROVED BY Approved by: f /'- f .VT. COMMISKs; H C M ISSION Date: /3 IG I Ce '2 3-1 Submit Form and Form 10-403(Revised 10/2012) Approved application is valid r dnt118 frb t e d e approval. Attach nts in Duplicate Z5 rs' RBDM�, g - -J 6/13/2ott \ JUN 3 0 2015 • Well Prognosis Well: MPB-24 Ililcarp Alaska,LL' Date:6/18/2015 Well Name: MPB-24 API Number: 50-029-22642-00-00 Current Status: Suspended Pad: B Pad Estimated Start Date: July 7th, 2015 Rig: Nordic 3 Reg.Approval Req'd? July 1, 2015 Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 196-009 First Call Engineer: Chris Kanyer (907)777-8377 (0) (907) 250-0374 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (M) AFE Number: 1551194 Current Bottom Hole Pressure: N/A (N/A- No open Perfs) Maximum Expected BHP: — 1,900 psi @ 4,000' TVD (Assumed virgin pressure in Schrader OA& OB Sands—added post RWO) Max.Allowable Surface Pressure: 250 psi (Based on actual reservoir conditions and water cut of 100% (0.440psi/ft)with an added safety factor of 1000' TVD of oil cap) Brief Well Summary: The Milne Point B-24 well was drilled as a Kuparuk development well that TD'd at 12,584' and,-an and cemented 7" casing in March 1996. The well was suspended due to wet Kuparuk and Schrader targets.Cement isolation plugs were set across the 7" casing shoe (11,692'-12,584'), intermediate plug (4,000'-4,200'), and surface (5'-250').The most recent casing pressure test of casing (above bottom cement plug) was performed to 2,000psi on 3/1/1996. Under Sundry 315-249 the upper and intermediate cement plugs were removed and a clean-out BHA was run followed by an MIT-IA test was executed and passed to 3,500psi. Under Sundry 315-277 an EZSV plug was set @ 10,060'then 4-1/2"Tubing was run and a packer was set @ 7,291' on 5/10/2015. Notes Regarding Wellbore Condition Current well status is suspended. No subsidence issues suspected. E-Line Objective: Add perforations in Ugnu MF sands.The initial perforation interval will be greater than 200'from the packer depth. Starting low, by injecting into the Ugnu MF, provides the longest potential run time and chance for success.The project objective is to create a successful Grind & Inject Class I service well. If the initial perforations do not achieve injection expectations/ requirements then contingency perforations will be executed, please reference the table below: PERFORATION CONTINGENCY TABLE Contingency# Sands Top (MD) Btm (MD) Top(TVD) Btm(TVD) FT 1 Ugnu ME ±8,070' ±8,090' ±4,595' ±4,601' 20 ±7,820' ±7,840' ±4,521' ±4,572' 20 2 Ugnu MD2 ±7,660' ±7,680' ±4,474' ±4,480' 20 3 Ugnu MB ±7,380' ±7,400' ±4,390' ±4,396' 20 Well Prognosis Well: MPB-24 Ililcoru Alaska,LL Date:6/18/2015 E-line Procedure: 1. MIRU E-line, PT lubricator to 250psi low/2,500psi high. 2. RU 2-7/8" 6 spf Hollow Carrier guns. 3. RIH to perforate Ugnu MF±8,260' to±8,280'. 4. RD E-line. 5. Turn well over to production (Contingency perforations, if needed, would follow the same procedural steps.) Attachments: 1. As-built Schematic 2. Proposed Schematic Milne Point Unit Well: MPB-24 SCHEMATIC Last Completed: 3/3/1996 Mean)Alaska,LLC PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/NT-80LHE/N/A N/A Surface 110' 201. R 9I. -5/8" Surface 40/L-80/BTC 8.835 Surface 4,080' 7" Production 26/L-80/BTC 6.276 Surface 12,066' TUBING DETAIL `' 4-1/2" Tubing 12.6#/L-80/Hydril 521 3.958 Surface 7,312' s' v JEWELRY DETAIL . F, No Depth Item 1 7,291' 7"Hyd Set Permanent Packer 2 7,305' XN Nipple(3.725"ID) 9-5/8"4 te3 7,311' WLEG 4 9,164' HOWCOType'H-ES'Cementer 5 10,060' EZSV Plug WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle=74.66 deg. @ 5,824'MD OPEN HOLE/CEMENT DETAIL CBL TOC @ 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole 4100'IAD/ 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole 3,335 ND 7" Cmt w/200 sks(1st Stage)then 250 sks(2nd Stage)Class"G"in 8-1/2"Hole GENERAL WELL INFO API:50-029-22642-00-00 I Drilled and Cased by Nabors 27-E -2/28/1996 Plugged and Suspended by Nabors 27-E—3/3/1996 S'. Recompleted by Nordic 3—5/10/15 ,�. f 1 0 Ian 3 I ,I. li 4 5 Calc.TOC @ 10,296'ND/ il 5,899'TVD V to p 4r il F '44 14 IV t,r2-4.44a Plug 1 @ !try! 11,692'-12,584' , .. -.. TD=12,584'(MD)/TD=7,934'(1VD) PBTD=5'(MD)/PBTD=5'(TVD) Created By:TDF 6/8/2015 Milne Point Unit .11 Well: MPB-24 PROPOSED Last Completed: 3/3/1996 Ilileorp Alaska,LLC PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/NT-SOLHE/N/A N/A Surface 110' 20 i 9-5/8" Surface 40/L-80/BTC 8.835 Surface 4080' 7" Production 26/L-80/BTC 6.276 Surface 12,066' :;..::: TUBING DETAIL R 4-1/2" Tubing 12.6#/L-80/Hydril 521 3.958 Surface 7,312' JEWELRY DETAIL ,i,,, No Depth Item 1 7,291' 7"Hyd Set Permanent Packer w+; ) • 2 7,305' XN Nipple(3.725"ID) �5/g�` le 3 7,311' WLEG 4 9,164' HOWCO Type'H-ES'Cementer 5 10,060' EZSV Plug PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Ugnu MF ±8,260' ±8,280' ±4,654' ±4,660' 20 Future Pending WELL INCLINATION DETAIL CBL TOC@ KOP @ 500' 410G MD/ Max Hole Angle=74.66 deg. @ 5,824'MD , F� TV 3336 D ,, I, OPEN HOLE/CEMENT DETAIL p ( $' 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole kva 9-5/8' Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"CC"(Top Job)in 12-1/4"Hole . i.: 7" Cmt w/200 sks(ft Stage)then 250 sks(2nd Stage)Class"G"in 8-1/2"Hole e4 fJ" GENERAL WELL INFO API:50-029-22642-00-00 I I 2 ,i 2 Drilled and Cased by Nabors 27-E -2/28/1996 Plugged and Suspended by Nabors 27-E—3/3/1996 3 xa Recompleted by Nordic 3—5/10/15 R Ugnu MF 1 Ili 4 5 Calc.TOC @ 10,296ND/ 5,899'TVD FPlug 1 i 7, 4. ,i6 11,697-12,584' TD=12,584'(MD)/TD=7,934'(TVD) PBTD=5'(MD)/PBTD=5'(TVD) Revised By:TDF 6/8/2015 • Wallace, Chris D (DOA) From: Cutler,Thor <Cutler.Thor@epa.gov> Sent: Friday, May 08, 2015 7:04 AM To: Wyatt Rivard Cc: Wallace, Chris D (DOA); Bentley, Marc H (DEC) Subject: RE: MPB-24 Class 1 well. Exact well location, Aquifer Exemption (September 29, 2004) applies. Attachments: Permit AK11005-B Milne Point Unit dated 9-19-14.pdf Wyatt Rivard Hilcorp May 8, 2015 As you know the much anticipated activity regarding the second class I well at Milne Point Unit is under way. The Class I permit, signed about 7 months ago, is attached and has been signed after stakeholders and public participated in the permitting process as laid out in permitting(includes UIC) regulation 40 CFR 124. On the first page of the signed and current EPA Class I permit,the aquifer conditions have been documented (summarized from previous determinations) which are important to both the permit limits, and the conditions of the permit. Specifically,the Class I EPA(see attached AK11005-B pp1) permit states: "The proposed disposal well(s)are in an area where there are no underground sources of drinking water(USDWs)and an aquifer exemption delineated by a cylinder along the well trajectory of the Class I injection well(s)from(below permafrost)2000 feet true vertical depth(TVD)to 4270 feet TVD. The aquifer exemption was issued by EPA on September 29,2004 for aquifers between approximately 2000 feet(base of the permafrost)and 4,270 feet true vertical depth subsea(TVDss)and was clarified to include the area delineated by a cylinder of'/mile radius along the well trajectories whose latitudes and longitudes (per NAD83)respectively at the well surface location are latitude 70.472809 and longitude-149.413148 for well MPB-50 and latitude 70.472928 and longitude-149.413239 for well MPU-xx. (Exact well locations are subject to change or correction.)". Thank you for clarifying the exact well location for the well (MPB-24)whose surface location is 70.475717 and - 149.411925. We note the change or correction of the decimal degrees (note the change in last several digits after the decimal)of the well top and will work toward updating this information in the aquifer mapping systems that is available to the public at: HTTPS//geoplatforml.epa.gov/aquiferexem Thank you for your continued coordination with EPA to fulfill the Class I permit requirements and your efforts to keep us fully informed of the steps that are being taken to safely proceed toward the next steps to complete the Class I actions. EPA appreciates your measured approach of taking the initial steps now, in May, 2015, followed by future activities to complete commissioning the well in late July, 2015. We look forward to your success in implementing these next steps to assure that we have the proper information to make informed decisions in a timely manner in the very near future. Thank you for working closely with our EPA inspector on site as we perform our role in direct implementation of the Class I UIC program in Alaska. The role of EPA and the on-site presence of an EPA representative is to provide timely witnessing of the information and steps taken,per the permit, so that timely decisions can be made regarding fulfillment of the regulatory requirements set forth in the permit that applies to this EPA Class I well activity. Should you have any questions,please do not hesitate to call myself,Thor Cutler(office 206 553 1673)(cell: 206 992-5119)any time. Sincerely, Thor Cutler ti OF Tye • `,w\� I//j,,sA THE STATE Alaska Oil and Gas �� ,,,. - '7c.14 of A LAsKA Conservation Commission _ 333 West Seventh Avenue terGOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main. 907 279 1433 OF ALAS' Fax 907 276 7542 www.aogcc.alaska.gov Ted Kramer SCONES Y: 1. 3 2.015 Operations Engineer 0 Hilcorp Alaska, LLC 111 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU KR B-24 Sundry Number: 315-277 Dear Mr. Kramer: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ,71)/e Cathy P. oerster Chair DATED this /Z day of May, 2015 Encl. • RECEIVED STATE OF ALASKA MAY 0 Fi 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A " GCC 20 MC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well❑ Change Approved Program p Suspend❑ Plug Perforations ❑ Perforate❑� Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well 0 Stimulate❑ Alter Casing❑ Other. Convert to Disposal Inj. Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC , Exploratory ❑ Development 0 • 196-009 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Suite 1400,Anchorage AK,99503 50-029-22642-00-00 - 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.432C' Will planned perforations require a spacing exception? Yes ❑ No E MILNE PT UNIT KR B-24 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0047432 ' MILNE POINT/KUPARUK RIVER OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 12,584 7,934 5 5 5',4,000'&11,692' N/A Casing Length Size MD ND Burst Collapse Structural Conductor 110' 20" 110' 110' Surface 4,080' 9-5/8" 4,080' 3,328' 5,750psi 3,090psi Intermediate Production 12,066' 7" 12,066' 7,443' 7,240psi 5,410psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): EZSV Cement Retainer and N/A 4,200'MD/3,375'TVD and N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch E Exploratory ❑ Stratigraphic❑ Development❑ Service 0 14.Estimated Date for 15.Well Status after proposed work: OGISS x. 4D14 OSjai/wis Commencing Operations: 5/7/2015 Oil ❑ Gas ❑ WDSPL 0 Suspended 0 16.Verbal Approval: Date: N/A WINJ ❑ GINJ ❑ WAG ❑ Abandoned 0 Commission Representative: N/A GSTOR 0 SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramer@hilcorp.com Printed Name Ted Kramer Title Operations Engineer Signature r"._,,,,;1 -"7/-'-f----Z. Phone 777-8420 Date 5/6/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3(5- 2.27-7 Plug Integrity ❑ BOP Test m Mechanical Integrity Test Location Clearance ❑ Other: , p /lljevheYl dyerali e-11 1 be .'-, aCcor,a n c e ct)M\ Ej A /SS U eOt 0a/4 r Pte* . 1 3 5-61) r &)P s7— ( MAS 1. y.--.-) Spacing Exception Required? Yes ❑ No Subsequent Form Required: /b--it 0 44 1 / APPROVED BY Approved by: ' / 5h+^ COMMISSIONER THE COMMISSION Date: �-'/2.----/S S/115 P Kd -.c/ /A "11,4 S ff/�s Submit Forth and Form 11 3(Revised 10/2012) QrcRd pp If 4i A14 d for 12 mon s from th,date of approval. Atta m nts in Duplicate y�'!/rte RBDMSJ' MAY 1 2 2015 Well Prognosis Well: MPB-24 Hilcon,Alaska,LL Date:5/6/2015 Well Name: MPB-24 API Number: 50-029-22642-00-00 Current Status: Suspended Pad: B Pad Estimated Start Date: May 6, 2015 Rig: Nordic 3 Reg.Approval Req'd? May 6, 2015 Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 196-009 First Call Engineer: Ted Kramer (907) 777-8420(0) (985)867-0665 (M) Second Call Engineer: Chris Kayner (907)777-8377 (0) (907) 250-0374 (M) AFE Number: 1551194 Current Bottom Hole Pressure: N/A (N/A- No open Perfs) Maximum Expected BHP: — 1,900 psi @ 4,000'TVD (Assumed virgin pressure in Schrader OA&OB Sands—added post RWO) Max. Anticipated Surface Pressure: 250 psi (Based on actual reservoir conditions and water cut of 100% (0.440psi/ft)with an added safety factor of 1000' TVD of oil cap) Brief Well Summary: The Milne Point H-04 well was drilled as a Kuparuk development well that TD'd at 12,584' and ran and cemented 7" casing in March 1996. The well was suspended due to wet Kuparuk and Schrader targets.Cement isolation plugs were set across the 7" casing shoe (11,692'-12,584'), intermediate plug (4,000'-4,200'), and surface (5'-250').The most recent casing pressure test of casing(above bottom cement plug) was performed to 2,000psi on 3/1/1996. A casing pressure test (full wellbore above PBTD of 11,692' and above installed packer) will be completed during this workover. 3 SLS L p>,. No subsidence issues are expected in this well. Notes Regarding Wellbore Condition Current well status is suspended. No subsidence issues suspected. AOR(status of wells within 1/4 mile radius of injection zone): *PI Well No Permit Well Current Status Zonal isolation(method) Estimated TOC (calculated)at 6,951'MD 50-029-22642-00-00 196-009 MPB-24 Suspended To be confirmed by CBL. See Decision Tree table below. RWO Objective: ps K61. - Run and Set a plug at 10,060'.Run a packer on a 4-1/2" injection string to within 200'of the top Zone to be perforated as per decision tree below. Brief Procedure: 1. PU RIH with isolation plug to 10,060' (+/-)and set. 2. MU and RIH with hydraulic set permanent packer on 4-1/2" 12.6#L-80 Hydril 521 tubing. Place packer on depth according to Decision Tree(below). Well Prognosis Well: MPB-24 Hilcorp Alaska,LL, Date:5/6/2015 Completion Set Depth-Decision Tree Option Minimum Upper Confining Zone Injection Interval Lower Confining Zone Packer Set Tubing # TOC(MD) Formation Top(MD) Bottom(MD) Top(MD) Bottom(MD) Top(MD) Bottom(MD) Depth(MD) Tail(MD) 1 ±7,305 Ugnu MB 7,270 7,330 7,366 8,118 7,942 7,968 ±7,316 ±7,343 Ugnu MD2 2 ±7,943 Ugnu ME 7,942 7,968 8,020 8,326 8,356 8,435 ±7,970 ±7,997 Ugnu MF 3 ±8,829 SBF OA 8,820 8,854 8,860 9,060 9,090 9,190 ±8,810 ±8,837 SBF OB 3. Space out(if necessary)and land tubing hanger with hydraulic set permanent packer,XN nipple (w/plug installed) at+/-15' below packer,and tubing tail at+/-27' below packer. 4. Space out and hang off tubing. 5. Hydraulically set permanent packer. 6. Perform a charted (IA)casing pressure test to 3,500psi for 30min. Bleed off pressure. 7. ND BOP, NU tree. 8. RDMO workover rig and equipment. 9. Turn well over to production. Post Rig Activities: 10. Slickline to pull plug in XN nipple post rig. 11. Eline to perforate a subset of injection interval listed in the Decision Tree(above). This subset/perforation interval(s)will submitted to Mr. Guy Schwartz(AOGCC) prior to perforating. Attachments: EP& 4, �,�,I _*- M't l4- 1. As-built Schematic a�; OLj 2. Proposed Schematic 3. BOP Schematic Milne Point Unit Well: MPB-24 SCHEMATIC Last Completed: 3/3/1996 Hilcorp Alaska,LI.t: PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn Drift ID Top Btm 20" Conductor 91.1/NT-80LHE/N/A N/A Surf 110' 2D': 9-5/8" Surface 40/L-80/BTC 8.679 Surf 4080' •Plug 3@5' 7" Production 26/L-80/BTC 6.151 Surf 12,066' blow tundra 'to 250'MD JEWELRY DETAIL Freeze No Depth Item Prdect1 4200' EZSV Cement Retainer Fluid 2 9164' HOWCO Type'H-ES'Cementer WELL INCLINATION DETAIL 9-5/8" A KOP @ 500' ' Rug 2 Max Hole Angle=74.66 deg. @ 5824'MD 4.00(7-4,200 MD 1 OPEN HOLE/CEMENT DETAIL 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole 7" Cmt w/200 sks(1st Stage)then 250 sks(2nd Stage)Class"G"in 8-1/2"Hole GENERAL WELL INFO API:50-029-22642-00-00 10.1 ppg Calc.TOC Drilled and Cased by Nabors 27-E -2/28/1996 Drilling Fluid 6,951'MD/ 4,346'TVD Plugged and Abandoned by Nabors 27-E—3/3/1996 • • 2 Calc.TOC 10,296 MD/ 5,899'TVD ti 'n 1« 7„ :', 11,697-12,584' TD=12,584'(MD)/TD=7,934'(TUD) PBTD=5'(MD)/PBTD=5'(TVD) Updated By:CVK 4/23/2015 Milne Point Unit Well: MPB-24 PROPOSED Last Completed: 3/3/1996 IIaeor„Alaska,1,1,(1PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn ID Top Btm I 20" Conductor 91.1/NT-8OLHE/N/A N/A Surface 110' .• !; 9-5/8" Surface 40/L-80/BTC 8.835 Surface 4,080' 3 Plug 3@5' 7" Production 26/L-80/BTC 6.276 Surface 12,0661 below to 250'NarvD TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Hydril 521 3.958 Surface - t JEWELRY DETAIL No Depth Item 1 See Below 7"Hyd Set Permanent Packer 2 See Below XN Nipple 95/8" 3 See Below WLEG Plug 2@ 4,000'-4,200 ND 4 9,164' HOWCO Type'H-ES'Cementer 5 ±10,060' E7SV Plug WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle=74.66 deg. @ 5,824'MD OPEN HOLE/CEMENT DETAIL Calc.TOC @ 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole 6,951'ND/ 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole 4,346 TVD 7" Cmt w/200 sks(1't Stage)then 250 sks(2"d Stage)Class"G"in 8-1/2"Hole • GENERAL WELL INFO API:50-029-22642-00-00 Drilled and Cased by Nabors 27-E -2/28/1996 Plugged and Suspended by Nabors 27-E–3/3/1996 —,—, 1 Completion Set Depth-Decision Tree Option Minimum Formation Upper Confining Zone Injection Interval Lower Confining Zone Packer Set Tubing # TOC(MD) Top(MD) Bottom(MD) Top(MD) Bottom(MD) Top(MD) Bottom(MD) Depth(MD) Tail(MD) 2 1 ±7,305 Ugnu MB 7,270 7,330 7,366 8,118 7,942 7,968 ±7,316 ±7,343 3 Ugnu MD2 Ugnu ME 71- 4 2 ±7,943 Ugnu MF 7,942 7,968 8,020 8,326 8,356 8,435 ±7,970 ±7,997 • 3 ±8,829 SBF OA 8,820 8,854 8,860 9,060 9,090 9,190 ±8,810 ±8,837 SBF OB `_. 5 Calc.TOC @ 10,296'ND/ 5,899'TVD • Plug 1 11,697-12,584' TD=12,584'(MD)/TD=7,934'(TVD) PBTD=5'(MD)/PBTD=5'(TVD) Created By:TDF 5/6/2015 11" BOP Stack ) 7 O Milli Ai ■ i 1 Hydril 11" SM 1111111 Shaffer Y . ... 0 _ 31/2" Rams cci 11" 5M -- 2 7/8-5.5 l ' [\_, = — variables i. -0-------- Hydril — a:174 11" 5M )....L' Blinds ‘ „ a f ; , Optional valve port _____ . tib B-50 e B-24 • / 11 HILCORP ALASKA LLC B-04 MILNE POINT FIELD AOR MAP MPB-24 // / /�/// 0 1 052 /�/ Di FEET If, // POSTED WELL DATA Well Number B-14 • 010 �� WELL SYMBOLS D&A INJ Well(Water Flood) SWD 1/' -- — REMARKS RED DOT=Top Schrader Bluff OA Sand Well Symbol at BHL Black Dash Circle=1320 radius from OA Sand TcF Perfs along wellpath in green April 16,2015 PETRA 4/162015 32152 PM i of T- Alaska Oil and Gas ,w\��\1�jj�� THE STATE �� 'i� of Ac A_ _ _ Conservation Commission t sttt�=-- _= 333 West Seventh Avenue ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279 1 433 ciA 4LAS1'P Fax: 907 276 7542 7 20�` www aogcc alaska gov Chris Kanyer r, © ` 007 Operations Engineer I✓ Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU KR B-24 Sundry Number: 315-249 Dear Mr. Kanyer: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, t). -.1c/Z--- Cathy . Foerster Chair DATED this ‘14-- ay of May, 2015 Encl. :RECEIVED STATE OF ALASKA APR 2 3 2 15 ALASKA OIL AND GAS CONSERVATION COMMISSION 0S S 1/is-5 FOR SUNDRY APPROVALS AOG C 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well 0 Change Approved Program 0 , Suspend❑ Plug Perforations ❑ , Perforate 0. Pull Tubing 0 Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑., Stimulate❑ Alter Casing 0 Other. Convert to Disposal Inj. ❑] 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC ' Exploratory ❑ Development 2 196-009 ' 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Suite 1400,Anchorage AK,99503 50-029-22642-00-00 • 7.If perforating: ,:.20 /14c, . CESS 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? fr•Ar43ccr- Will planned perforations require a spacing exception? Yes ❑ No 2 / MILNE PT UNIT KR B-24 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL-9e47432 •' AbI., 35.2.7.0 a MILNE POINT/KUPARUK RIVER OIL• 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 12,584 , 7,934 5 5 5',4,000'&11,692' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 20" 110' 110' Surface 4,080' 9-5/8" 4,080' 3,328' 5,750psi 3,090psi Intermediate Production 12,066' 7" 12,066' 7,443' 7,240psi 5,410psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): EZSV Cement Retainer and N/A 4,200'MD/3,375'TVD and N/A 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑., Exploratory ❑ Stratigraphic❑ Development❑ Service ❑] 14.Estimated Date for 15.Well Status after proposed work: Gtgs r Commencing Operations: 5/4/2015 Oil ❑ Gas ❑ WDSPL Q Suspended 0 1 16.Verbal Approval: Date: ' , 5-'-(-1 S' WINJ ❑ GINJ ❑ WAG ❑ Abandoned 0 Commission Representative: S(ice,y f-L GSTOR ❑ SPLUG ❑ ' 17.I hereby certify that the foregoing is true nd correct to the best of my knowledge. Contact Chris Kanyer Email ckanyer@hilcorp.com Printed Name Chris Kanyer Title Operations Engineer Signature (Li< Phone 777-8377 Date 4/23/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test / Mechanical Integrity Test j Location Clearance ❑ Other: Inset e-r.‘ © ems ►tee, ,/, acc,o ly2 c e, c(_K, Gass T ..pA x Sun_ nrov. c3 �LQ: P5� C�1r I �S (AA45Py Spacing Exception Required? Yes ❑ No [ Subsequent Form Required: / --I di APPROVED BY Approved by: - p ei..'r COMMISSIONER THE COMMISSION Date: s- 6 _./5— /.e -ntir .e S -c--/s- &iRijiijitNIsj4iLor///'''�� _5/6'/s Submit Form and Fo 10-403(Revised 10/2012) 12 monthsr I u.a c_..eof approval. trer1ts i �peoii112015 ,�f�� bW �i9�Jo/� 5 Y`�\ Well Prognosis Well: MPB-24 Ililcorp Alaska,LL Date:4/22/2015 Well Name: MPB-24 API Number: 50-029-22642-00-00 Current Status: Suspended Pad: B Pad Estimated Start Date: May 4, 2015 Rig: Nordic 3 Reg.Approval Req'd? May 4, 2015 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 196-009 First Call Engineer: Chris Kanyer (907) 777-8377 (0) (907) 250-0374 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907)727-9247 (M) AFE Number: Current Bottom Hole Pressure: N/A (N/A- No open Perfs) Maximum Expected BHP: — 1,900 psi @ 4,000' TVD (Assumed virgin pressure in Schrader OA& OB Sands—added post RWO) Max. Allowable Surface Pressure: 250 psi (Based on actual reservoir conditions and water cut of 100% (0.440psi/ft) with an added safety factor of 1000' TVD of oil cap) Brief Well Summary: The Milne Point H-04 well was drilled as a Kuparuk development well that TD'd at 12,584' and ran and cemented 7" casing in March 1996. The well was suspended due to wet Kuparuk and Schrader targets. Cement isolation plugs were set across the 7" casing shoe (11,692'-12,584'), intermediate plug (4,000'-4,200'), and surface (5'-250'). The most recent casing pressure test of casing (above bottom cement plug) was performed to 2,000psi on 3/1/1996. A casing pressure test (full wellbore above PBTD of 11,692' and above installed packer) will be completed during this workover. No subsidence issues are expected in this well. Notes Regarding Wellbore Condition Current well status is suspended. No subsidence issues suspected. AOR(status of wells within 1/4 mile radius of injection zone): API Well No Permit Well Current Status Zonal isolation (method) Estimated TOC (calculated) at 6,951'MD 50-029-22642-00-00 196-009 MPB-24 Suspended To be confirmed by CBL. See Decision Tree table below. RWO Objective: Drill/clean out surface & intermediate plugs, run CBL, and run 4-1/2" injection completion according to Decision Tree (below). Brief Procedure: 1. MIRU Nordic#3 Rig. 2. ND tree, NU 11" BOPE and test to 250psi low/3, Opsi high, annular to 250psi low/2,500psi high. a. Notify AOGCC 24hrs in advance to witness test. Well Prognosis Well: MPB-24 llilcorp Alaska,LL Date:4/22/2015 3. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer(Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr.Jim Regg(AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path,test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. g. Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. h. If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. 4. Drill out surface plug from 5'to 250', monitor well. 5. RIH to top of intermediate plug at+/-4,000'. 6. Circulate out freeze protect from well with 8.5ppg seawater. Monitor well. 7. Drill out intermediate cement plug and retainer from 4,000'to 4,200', monitor well. // 8. Continue to RIH with milling BHA to 9,300'. 9. Circulate out 10.1ppg drilling fluid from well with 8.5ppg seawater. Monitor well. POOH with same. S./',.//),‘ 10. RIH with cleanout BHA to+/-9,300'. Perform charted casing test down to PBTD at 11,692'to si. POOH with same. = rNs'�f .4c4( < 1 v,- � 35 is p>- 11. RU Eline. RIH with CBL and log from 9 '56'to 5,000'. RD Eline.Verify top of cement(TOC)for steps#12-21.____ 12. MU and RIH with hydraulic set permanent packer on 4-1/2" 12.6#L-80 Hydril 521 tubing. Place packer on depth accordin: o Decision Tree (below). Completion Set Depth-Decision Tree Option Minimum Up.-rConfiningZone Injection Interval Lower Confinin ne Packer Set Tubing Formation }to # TOC(MD) Top(M• Bottom(MD) Top(MD) Bottom(MD) Top(MD) tom(MD) Depth(MD) Tail(MD) t� ( ±7,305 Ugnu MB Ugnu MD2 7,270 330 7,366 8,118 7 • 7,968 ±7,316 ±7,343 Ugnu ME 2 ±7,943 Ugnu MF 7,942 7,96, 8,020 8,32. 8,356 8,435 ±7,970 ±7,997 3 ±8,829 SBF OA 8,820 8,854 8,:.I 9,060 9,090 9,190 ±8,810 ±8,837 SBF OB 13. RU Eline,correlate packer on depth accor•• g to Decision ree (above). POOH with Eline. 14. Space out(if necessary)and land tub' hanger with hydrauli et permanent packer,XN nipple (w/plug installed) at+1-15' below packer nd tubing tail at+/-27' below • cker. 15. Hydraulically set permanen acker. 16. Perform a charted (IA) sing pressure test to 3,500psi for 30min. Bleed • • pressure. 17. ND BOP, NU and tr . 18. RDMO workoval'rig and equipment. 19. Turn well oyer to production. Well Prognosis Well: MPB-24 Hilcorp Alaska,LL, Date:4/22/2015 Post Rig Activities: 20. Slickline to pull plug in,XN nipple post rig. 21. Eline to perforate a subset of injection interval listed in the Decision Tree(above). This subset/perforation interval(s) will submitted to Mr. Guy Schwartz(AOGCC) prior to perforating. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic Milne Point Unit Well: MPB-24 SCHEMATIC Last Completed: 3/3/1996 Hilcorp Alaska,LLC PTD: 196-009 CASING DETAIL Cirig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn Drift ID Top Btm 20" Conductor 91.1/NT-80LHE/N/A N/A Surf 110' 20. 9-5/8" Surface 40/L-80/BTC 8.679 Surf 4080' Plug 3@5' 7" Production 26/L-80/BTC 6.151 Surf 12,066' . below tundra 'to 250'MD JEWELRY DETAIL Freeze No Depth Item Prded 1 4200' EZSV Cement Retainer Fluid 2 9164' HOWCO Type'H-ES'Cementer WELL INCLINATION DETAIL 15/8" a , !•.';'„t & KOP @ 500' Plug 2 @ Max Hole Angle=74.66 deg. @ 5824'MD 4,000'-4,200'MD OPEN HOLE/CEMENT DETAIL 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole 7" Cmt w/200 sks(ft Stage)then 250 sks(2"i Stage)Class"G"in 8-1/2"Hole GENERAL WELL INFO API:50-029-22642-00-00 10.1 ppg Cdc TO © Drilled and Cased by Nabors 27-E -2/28/1996 Drilling Fluid 6951'MD/ ; , 4,34s TVD Plugged and Abandoned by Nabors 27-E—3/3/1996 ti' • Ii 2 Calc.TOC @ 10,296'MD/ 5,899'TVD • • a ,ek } Plug 1 C@ ' 11,69Z-12,584' TD=12,584(MD)/TD=7,934'(TVD) PBTD=5'(MD)/PBTD=5'(1VD) Updated By:CVK 4/23/2015 Milne Point Unit Well: MPB-24 11 PROPOSED Last Completed: 3/3/1996 lli!corp Alaska,LLI: PTD: 196-009 CASING DETAIL Orig.KB Elev.:46'/GL Elev.:N/A Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/NT-80LHE/N/A N/A Surface 110' 20J 1 9-5/8" Surface 40/L-80/BTC 8.835 Surface , 4,080' Plug 3@5' 7" Production 26/L-80/BTC 6.276 Surface 12,066' 250'undra to50'ND TUBING DETAIL to 2 , 4-1/2" Tubing 12.68/L-80/Hydril 521 3.958 Surface JEWELRY DETAIL No Depth Item 1 See Below 7"Hyd Set Permanent Packer 2 See Below XN Nipple 9-5/8" 3 See Below WLEG Plug 2 @ 4,000'-4,200'ND 4 9,164' HOWCO Type'H-ES'Cementer WELL INCLINATION DETAIL KOP@500' Max Hole Angle=74.66 deg. @ 5,824'MD OPEN HOLE/CEMENT DETAIL 20" Cmt w/250 sks of Arcticset I(Approx.)in 30"Hole Calc.TOC @ 9-5/8" Cmt w/802 sks PF"E"(lead),250 sx Class"G"(tail),250 sx PF"C"'(Top Job)in 12-1/4"Hole 6,951'ND/ 7" Cmt w/200 sks(ft Stage)then 250 sks(2"d Stage)Class"G"in 8-1/2"Hole 4,346'TVD GENERAL WELL INFO API:50-029-22642-00-00 Drilled and Cased by Nabors 27-E -2/28/1996 ' Plugged and Suspended by Nabors 27-E—3/3/1996 Completion Set Depth-Decision Tree Option Minimum Upper Confining Zone Injection Interval Lower Confining Zone Packer Set Tubing mL'mm•• 1 Formation 8 TOC(MD) Top(MD) Bottom(MD) Top(MD) Bottom(MD) Top(MD) Bottom(MD) Depth(MD) Tail(MD) 1 ±7,305 Ugnu MB 7,270 7,330 7,366 8,118 7,942 7,968 ±7,316 ±7,343 12 Ugnu MD2 3 U 2 ±7,943 g 7,942 7,968 8,020 8,326 8,356 8,435 ±7,970 ±7,997 gnu MF 0 46 4 3 ±8,829 SBF OA 8,820 8,854 8,860 9,060 9,090 9,190 ±8,810 ±8,837 SBF OB Calc.TOC @ 10,296'ND/ . 5,899 ND • • • Plug l @ , .6' 11,697-12584' TD=12,584'(MD)/TD=7,934'(TVD) PBTD=5'(IVC)/PBTD=5'(TVD) Created By:TDF 4/22/2015 11" BOP Stack `1 - D ■ diMtidi Hydril 11" SM 324- Shaffer '—''_, 31/2" Rams .44-f 9— 0 i 2 7/8-5.5 ^,2:4 -- 11" 5M ;-- '� ' variables ."--\ 0 :,. Hydril aill(L—t if 5M _IL._ Blinds Optional valve port 7Ot11 ,� r�-. . i - B-50 e 0 B-24 its , —,CiLd— / ,' I It i , i / / / , / , /' 18 ' HILCORP ALASKA LLC B-04 ' MILNE POINT FIELD / /� AOR MAP 0 ,, MPB-24 // , // / / / / 0 1 052 1 / FEET PI /I/ •, l/ POSTED WELL DATA Well Number B-14 • hill r I WELL SYMBOLS D&A ® INJ Well(Water Flood) X SWD _„_ REMARKS RED DOT=Top Schrader Bluff OA Sand Well Symbol arde t BH &adc Dash Ci = L 1320 radius from OA San Perfs along wellpath in green April 16,2015 bp 0 ,U Eric West AO0 GCC Vice President Non-Operated Oil Businesses BP Exploration(Alaska)Inc 900 East Benson Boulevard PO Box 196612 May 5, 2015 Anchorage,AK 99519-6612 Main 907 561 5111 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Letter of Support for Hilcorp Alaska, LLC's Application for Sundry Approval re Milne Point Unit KR B-24 Disposal Well Dear Ms. Foerster: Hilcorp bid on and subsequently won lease ADL 392703 at the 2014 Beaufort Sea Areawide lease sale. This lease was formerly included within the Milne Point Unit, but was subsequently contracted out of the unit. There are two wellbores on this lease—both exist outside of the unit. One active wellbore, MB-50, serves as the sole disposal well for the entire Milne Point Unit. The other wellbore, MB-24, is suspended. Originally drilled as a development well, MB-24 proved wet in the Kuparuk and Schrader Bluff formations and was never perforated or open to production. Very recently, Hilcorp has identified this wellbore as a candidate for Class I disposal within non-productive portions of the Ugnu and/or Schrader Bluff formations. BPXA Is in full support of this project. Obviously, obtaining a back-up disposal well is critical and converting a suspended well into disposal will reduce costs and eliminate waste. If successful, this particular project will support long-term operations and promote continued development of unitized hydrocarbons. More importantly, the proposed disposal zones have been previously tested and confirmed not to be productive. For the stated reasons, we request the Alaska Oil and Gas Conservation Commission (AOGCC) support Hilcorp's proposed sundry application. Additionally, Hilcorp and BPXA have reached an agreement for the assignment of a fifty (50%) working interest in ADL 392703 to BPXA and are working with the Department of Natural Resources to process an assignment of ADL 392703. This is purely a procedural matter—but will quickly result in both Hilcorp and BPXA's joint ownership (50/50) of this lease. As soon as reasonably practical, Hilcorp will petition the Department of Natural Resources to incorporate said lease into the Milne Point Unit. Should you have any questions regarding BPXA's position on this matter, please do not hesitate to contact the undersigned. Sincerely, Eric West CC: Corri Feige, DNR (via email)Patrlcia Bettis, AOGCC (via email) Bettis, Patricia K (DOA) fth 19c, From: Bettis, Patricia K (DOA) Sent: Monday, May 04, 2015 2:05 PM To: Ted Kramer(tkramer@hilcorp.com); 'ktabler@hilcorp.com' Cc: Schwartz, Guy L (DOA) Subject: MPU B-24: Sundry Application Good afternoon Ted and Kevin, Kevin thank you for dropping off the lease this morning. In reviewing the sundry application, Hilcorp is proposing to perforate the Ugnu and/or Schrader Bluff sands for injection of disposal waste. Therefore, CO 432C does not apply. Statewide well spacing regulations 20 AAC 25.055 does apply. According to the AOR map included with the application,the perforated intervals will be within 500' of a property line where ownership changes. Therefore, an application for an exception to the provisions of 20 AAC 25.055 will be required in accordance with 20 AAC 25.540, 20 AAC 25.055(d). Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 1...111."1.M1111.11.1.11.11.111.171 ?—..17.1117.175=7111 OF T� ,w4, I%%7.� THE STATE Department of Natural Resources ✓ fALASI�CA `.t:1 '1U111 1(111 _N,,,M, __------- 1^;( H))R MA \i \)k\9) n(-: )„ of P GOVERNOR BILL WALKER lax ,)(1/2(),L;,9;,)ALASY' Picked Up by Hilcorp May 4, 2015 LEASE ISSUANCE Hilcorp Alaska, LLC : Oil and Gas Lease 3800 Centerpoint Dr., Suite 1400 : ADL 392703 Anchorage, AK 99503 : Competitive Oil and Gas Lease Issued Hilcorp Alaska, LLC was named the high bidder on Tract 328 offered in Competitive Oil and Gas Lease Sale Beaufort Sea Areawide 2014W, held November 19, 2014. Having complied with the Award Notice of April 29, 2015 and the provisions of 11 AAC 82.465, Hilcorp Alaska, LLC is issued the referenced oil and gas lease effective May 1, 2015, subject to any valid existing rights. Sincerely, 4f,,_D azZuf,v- Cord Feige Director Enclosure Competitive Oil and Gas Lease Form#DOG 201308W STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES Competitive Oil and Gas Lease ADL No. 392703 THIS LEASE is entered into MAY 01 2015 , between the State of Alaska,"the state," and Hilcorp Alaska, LLC 100% "the lessee,"whether one or more,whose sole address for purposes of notification is under Paragraph 25. In consideration of the cash payment made by the lessee to the state, which payment includes the first year's rental and any required cash bonus, and subject to the provisions of this lease, including applicable stipulation(s) and mitigating measures attached to this lease and by this reference incorporated in this lease,the state and the lessee agree as follows: 1. GRANT. (a) Subject to the provisions in this lease, the state grants and leases to the lessee, without warranty,the exclusive right to drill for,extract, remove,clean,process,and dispose of oil,gas,and associated substances in or under the following described tract of land: Tract 328 T.013N., R.011E., Umiat Meridian,Alaska. Section 5, Protracted,All,640.00 acres; Section 6,Protracted,All,625.00 acres; Section 7,Unsurveyed,All tide and submerged land,566.52 acres; Section 8,Unsurveyed, All tide and submerged land,551.48 acres; T.013N., R.011E.,Tract B, Umiat Meridian, Alaska. Section 7,Surveyed, Fractional, All, including U.S.Survey 8959,61.48 acres; Section 8,Unsurveyed,All,88.52 acres; According to the supplemental survey plat accepted by the United States Department of the Interior,Bureau of Land Management in Anchorage,AK on February 2, 1989. containing approximately 2,533.00 acres, more or less (referred to in this lease as the "leased area");the nonexclusive right to conduct within the leased area geological and geophysical exploration for oil,gas,and associated substances;and the nonexclusive right to install pipelines and build structures on the leased area to find, produce, save, store, treat, process,transport,take care of, and market all oil,gas, and associated substances and to house and board employees in its operations on the leased area. The rights granted by this lease are to be exercised in a manner which will not unreasonably interfere with the rights of any permittee, lessee or grantee of the state consistent with the principle of reasonable concurrent uses as set out in Article VIII, Section 8 of the Alaska Constitution. 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If production is established within the time allowed,this lease is extended only for so long as oil or gas is produced in paying quantities from the leased area. (e) If the state directs or approves in writing a suspension of all operations on or production from the leased area (except for a suspension necessitated by the lessee's negligence), or if a suspension of all operations on or production from the leased area has been ordered under federal,state,or local law, the lessee's obligation to comply with any express or implied provision of this lease requiring operations or production will be suspended,but not voided,and the lessee shall not be liable for damages for failure to comply with that provision. If the suspension occurs before the expiration of the primary term, the primary term will be extended at the end of the period of the suspension by adding the period of time lost under the primary term because of the suspension. If the suspension occurs during an extension of the primary term under this paragraph, upon removal of that suspension,the lessee will have a reasonable time,which will not be less than six months after notice that the suspension has been removed,to resume operations or production. For the purposes of this subparagraph, any suspension of operations or production specifically required or imposed as a term of sale or by any stipulation made a part of this lease will not be considered a suspension ordered by law. (f) If the state determines that the lessee has been prevented by force majeure, after efforts made in good faith,from performing any act that would extend the lease beyond the primary term,this lease will not expire during the period of force majeure. If the force majeure occurs before the expiration of the primary term,the primary term will be extended at the end of the period of force majeure by adding the period of time lost under the primary term because of the force majeure. If the force majeure occurs during an extension of the primary term under this paragraph,this lease will not expire during the period of force majeure plus a reasonable time after that period, which will not be less than 60 days, for the lessee to resume operations or production. (g) Nothing in subparagraphs (e) or(f) suspends the obligation to pay royalties or other production or profit-based payments to the state from operations on the leased area that are not affected by any suspension or force majeure, or suspends the obligation to pay rentals. 5. RENTALS. (a) The lessee shall pay annual rental to the state in accordance with the following rental schedule: (1) For the first year through the seventh year,$10.00 per acre or fraction of an acre;and (2) For the eighth year through the tenth year, $250.00 per acre or fraction of an acre; except that beginning in the year after the year in which sustained production commences on this lease or the state otherwise determines in its sole discretion, upon request, that the lessee has exercised reasonable diligence in exploring and developing this lease the annual rental will be$10.00 per acre or fraction of an acre. In evaluating a request to decrease rental based on the exercise of reasonable diligence, the state will consider the funds expended by the lessee to explore and develop this lease and the types of work completed by or on behalf of the lessee on this lease. (b) The state may increase the annual rental rate as provided by law upon extension of this lease beyond the primary term. (c) Annual rental paid in advance is a credit on the royalty or net profit share due under this lease for that year. (d) The lessee shall pay the annual rental to the State of Alaska (or any depository designated by the state with at least 60 days notice to the lessee) in advance, on or before the annual anniversary date of this lease. The state is not required to give notice that rentals are due by billing the lessee. If the state's(or depository's)office is not open for business on the annual anniversary date of this lease, the time for payment is extended to include the next day on which that office is open for business. If the annual rental is not paid timely,this lease automatically terminates as to both parties at 11:59 p.m.,Alaska Standard Time, on the date by which the rental payment was to have been made. 6. RECORDS. The lessee shall keep and have in its possession books and records showing the development and production (including records of development and production expenses) and disposition (including records of sale prices, volumes, and purchasers) of all oil, gas, and associated substances produced from the leased area. The lessee shall permit the State of Alaska or its agents to examine these books and records at all reasonable times. Upon request by the state,the lessee's books and records shall be made available to the state at the state office designated by the state. These books and records of development, production, and disposition must employ methods and techniques that will ensure the most accurate figures reasonably available without requiring the lessee to provide separate tankage or meters for each well. The lessee shall use generally accepted accounting procedures consistently applied. 7. APPORTIONMENT OF ROYALTY FROM APPROVED UNIT. The landowners' royalty share of the unit production allocated to each separately owned tract shall be regarded as royalty to be distributed to and among, or the proceeds of it paid to, the landowners, free and clear of all unit expense and free of any lien for it. Under this provision, the state's royalty share of any unit production allocated to the leased area will be regarded as royalty to be distributed to, Page 3 of 27 L?}o 17 abed •ajejs eq}Aq panoadde wag seg luewdolanep}o ueid engin in000 Aew ewe paseal ay}}o luewdolanap oN .ewe paseal all 6u!doienap Jo}sued s,easset aqj equosep isnw legs juewdolanap}o ueid'emu! ue}o awls eq}Aq lenoJdde Jo}uogeogdde ue}o se!doo oM1 ail}lleys aassal all `sagguenb 6u!Aed u!seouejsgns paleloosse Jo `se6 '!!o 6ulonpoid to a gedeo gene e}o uolieidwoo Jape syfuow Z! u!yl!M `Moieq (p) ydei6eiedgns u! pep!noJd se ideox3 (e) '1NTWdol3A3a 30 NV-Id '01 .euoz lejseoo ay}wpm jou we pasodoid sa!j!n!foe}!se!doo an!}pue 'auoz le}seoo eqj ugpM we pasodoad samAgoe}!ueid eqi}o se!doo uai ep!noJd !legs aassal all 'IenoJdde Jo}suo!feJedo}o ueid pasodoid a 6u!ji!wgns uI (q) ueid ayi}o lenoJdde}o uog!puoo e se pesodwp sfuewejmbej yi!M'Mous!AlgeuoseeJ pinogs Jo `sMou)I aassal ayi go!gM }o eouegdwoouou Aue 6uliejs pue suogeJedo }o amp uoljaidwoo eqj 6wjeo!pul IJodeJ a f!wgns pue suo!feiado}o ewe aqj joedsu! Hugs aassal ayi 'suo!jeiedo}o uogaidwoo uodn (6) •suo!ieaado}o ueid panoadde ue puawe 'Jauo!ss!wwoo aqj}o lenoadde ayi qpm'Aew aassal ayi (}) iseJaju! ployaseal eqj}o asn algeuosew}o aassal all anudap pinoM go!gM Jo'jlesf!eseei aqj }o swiel ayi qpm Jo 'peu!elgo sem aseal eqj yo!gM Japun ales}o swial ayi qpm luels!suoou!eq pinoM legs ivawpuawe ue w!nbaa jou!pm Jauo!ss!wwoo all lsaaalw s,elels aqj ioaioad of A.iesseoeu sawwielep Jauo!ss!wwoo aqj jeyi sfuewpuawe winbej g!M Jeuo!ss!wwoo ayi 'ueid e}o ivawpuawe ue Jo suo!leiedo}o ueid eseat a 6u!noidde ul (a) .seeje asn oggnd pue`sells!eo!6oloayoie pue ouols!q `sfejlgeq apipl!M pue qs!}6u!pniou! 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'(eaJe pun aqj wag AeMe peiinou!sasuadxa asoyj jo uo!pod Aue pue)sasuadxa pun Ile}o Jeep pue awl`ajejs aqj'01 pied f!Jo speeooid eqj Jo (b) The plan of development must be revised, updated, and submitted to the state for approval annually before or on the anniversary date of the previously approved plan. If no changes from an approved plan are contemplated for the following year, a statement to that effect must be filed for approval in lieu of the required revision and update. (c) The lessee may, with the approval of the state, subsequently modify an approved plan of development. (d) If the leased area is included in an approved unit,the lessee will not be required to submit a separate lease plan of development for unit activities. 11. a) The lessee shall submit to the state, at the Department of Natural Resources, Division of Oil & Gas (Division), all geological, geophysical, and engineering data obtained from the lease within 30 days following completion, abandonment, or suspension of each well, pilot hole, and plugged back well bore. The lessee shall also submit to the Division, on behalf of the state, data acquired subsequent to completion, abandonment, or suspension of each well, pilot hole, and plugged back well bore within 30 days following acquisition of those data. The Division, on behalf of the state, may waive receipt of operational data from some development, service, or injection wells, and will inform the operator of the waiver in writing prior to data submittal. Data shall be submitted according to the instructions set out in Attachment 1. Submission of data under this paragraph does not affect any statutory or regulatory obligation to submit data or other information to the state or any of its agencies. (b) Any data submitted to the state,at the Department of Natural Resources, Division of Oil&Gas will be available at all times for use by the state and its agents, and will be held confidential as provided in AS 38.05.035(a)(8) and its applicable regulations. In accordance with AS 38.05.035(a)(8)(C), in order for geological, geophysical, and engineering data to be held confidential, the lessee must request confidentiality at the time of submission and mark the data"CONFIDENTIAL"in compliance with applicable regulations. 12. DIRECTIONAL DRILLING. This lease may be maintained in effect by directional wells whose bottom hole location is on the leased area but that are drilled from locations on other lands not covered by this lease. In those circumstances, drilling will be considered to have commenced on the leased area when actual drilling is commenced on those other lands for the purpose of directionally drilling into the leased area. Production of oil or gas from the leased area through any directional well surfaced on those other lands,or drilling or reworking of that directional well,will be considered production or drilling or reworking operations on the leased area for all purposes of this lease. Nothing contained in this paragraph is intended or will be construed as granting to the lessee any interest,license,easement,or other right in or with respect to those lands in addition to any interest, license, easement, or other right that the lessee may have lawfully acquired from the state or from others. 13. DILIGENCE AND PREVENTION OF WASTE. (a) The lessee shall exercise reasonable diligence in drilling, producing, and operating wells on the leased area unless consent to suspend operations temporarily is granted by the state. (b) Upon discovery of oil or gas on the leased area in quantities that would appear to a reasonable and prudent operator to be sufficient to recover ordinary costs of drilling, completing, and producing an additional well in the same geologic structure at another location with a reasonable profit to the operator,the lessee must drill those wells as a reasonable and prudent operator would drill, having due regard for the interest of the state as well as the interest of the lessee. (c) The lessee shall perform all operations under this lease in a good and workmanlike manner in accordance with the methods and practices set out in the approved plan of operations and plan of development,with due regard for the prevention of waste of oil, gas, and associated substances and the entrance of water to the oil and gas- bearing sands or strata to the destruction or injury of those sands or strata, and to the preservation and conservation of the property for future productive operations. The lessee shall carry out at the lessee's expense all orders and requirements of the State of Alaska relative to the prevention of waste and to the preservation of the leased area. If the lessee fails to carry out these orders, the state will have the right, together with any other available legal recourse, to enter the leased area to repair damage or prevent waste at the lessee's expense. (d) The lessee shall securely plug in an approved manner any well before abandoning it. 14. OFFSET WELLS. The lessee shall drill such wells as a reasonable and prudent operator would drill to protect the state from loss by reason of drainage resulting from production on other land. Without limiting the generality of the foregoing sentence, if oil or gas is produced in a well on other land not owned by the State of Alaska or on which the Page 5 of 27 ................. 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Ilam hegh woJ; uollOnpoJd hell spud ems eqh `pJeeq eq o1 Apunloddo ue pue aassal eq1 oh eollou Jal}e `p pue 'Join.'ado ayi oh 11;oJd ahgeuoseai a qpm uolhnool 1as110 ue le aJnlonJ1s heo!6oIoe6 awes all w Ilam heuopl!ppe ue 6ulonpojd pue '6ullaldwoo`6upllup 10 s1soo AJeu!pJo JanooaJ Oh huepOl;Ins aq o1 Jolerado wapn.'d pue algeuoseai e of Jeadde phnom ;ell so!;!;uenb u! sAep anphnOasuoo 0€ 10 polled a Job sub Jo!po seonpojd Ilam hall pue `°seal slip o;loafgns uagh spuel 10 Ilam se6 a 10 aseo eql u!1001 009'l Jo Ham llo ue;o aseo ayi U!lee;009 u!gpM sl Ilam ley;pue 'eseal sly;Japun uegh A;IeAoJ 10 ale.'JamoI a sen!eoeJ eNsely;o ems of the state, be severed,and a separate and distinct lease will be issued to the transferee having the same effective date and terms as this lease. 19. SURRENDER. The lessee at any time may file with the state a written surrender of all rights under this lease or any portion of the leased area comprising one or more legal subdivisions or, with the consent of the state, any separate and distinct zone or geological horizon underlying the leased area or one or more legal subdivisions of the leased area. That surrender will be effective as of the date of filing,subject to the continued obligations of the lessee and its surety to make payment of all accrued royalties and to place all wells and surface facilities on the surrendered land or in the surrendered zones or horizons in condition satisfactory to the state for suspension or abandonment. After that,the lessee will be released from all obligations under this lease with respect to the surrendered lands,zones, or horizons. 20. DEFAULT AND TERMINATION; CANCELLATION. (a) The failure of the lessee to perform timely its obligations under this lease, or the failure of the lessee otherwise to abide by all express and implied provisions of this lease, is a default of the lessee's obligations under this lease. Whenever the lessee fails to comply with any of the provisions of this lease (other than a provision which, by its terms, provides for automatic termination), and fails within 60 days after written notice of that default to begin and diligently prosecute operations to remedy that default, the state may terminate this lease if at the time of termination there is no well on the leased area capable of producing oil or gas in paying quantities. If there is a well on the leased area capable of producing oil or gas in paying quantities, this lease may be terminated by an appropriate judicial proceeding. In the event of any termination under this subparagraph,the lessee shall have the right to retain under this lease any and all drilling or producing wells for which no default exists, together with a parcel of land surrounding each well or wells and rights-of-way through the leased area that are reasonably necessary to enable the lessee to drill, operate, and transport oil or gas from the retained well or wells. (b) The state may cancel this lease at any time if the state determines, after the lessee has been given notice and a reasonable opportunity to be heard, that: (1)continued operations pursuant to this lease probably will cause serious harm or damage to biological resources, to property,to mineral resources, or to the environment(including the human environment); (2)the threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and (3) the advantages of cancellation outweigh the advantages of continuing this lease in effect. Any cancellation under this subparagraph will not occur unless and until operations under this lease have been under suspension or temporary prohibition by the state,with due extension of the term of this lease, continuously for a period of five years or for a lesser period upon request of the lessee. (c) Any cancellation under subparagraph(b)will entitle the lessee to receive compensation as the lessee demonstrates to the state is equal to the lesser of: (1)the value of the cancelled rights as of the date of cancellation,with due consideration being given to both anticipated revenues from this lease and anticipated costs, including costs of compliance with all applicable regulations and stipulations, liability for clean-up costs or damages, or both, in the case of an oil spill, and all other costs reasonably anticipated under this lease;or (2) the excess, if any, over the lessee's revenues from this lease (plus interest on the excess from the date of receipt to date of reimbursement) of all consideration paid for this lease and all direct expenditures made by the lessee after the effective date of this lease and in connection with exploration or development, or both, under this lease, plus interest on that consideration and those expenditures from the date of payment to the date of reimbursement. 21. RIGHTS UPON TERMINATION. Upon the expiration or earlier termination of this lease as to all or any portion of the leased area, the lessee will be directed in writing by the state and will have the right at any time within a period of one year after the termination, or any extension of that period as may be granted by the state, to remove from the leased area or portion of the leased area all machinery, equipment, tools, and materials. Upon the expiration of that period or extension of that period and at the option of the state, any machinery, equipment, tools, and materials that the lessee has not removed from the leased area or portion of the leased area become the property of the state or may be removed by the state at the lessee's expense. At the option of the state,all improvements such as roads,pads, and wells must either be abandoned and the sites rehabilitated by the lessee to the satisfaction of the state, or be left intact and the lessee absolved of all further responsibility as to their maintenance, repair, and eventual abandonment and rehabilitation. Subject to the above conditions, the lessee shall deliver up the leased area or those portions of the leased area in good condition. 22. DAMAGES AND INDEMNIFICATION. (a) No rights under the AS 38.05.125 reservation may be exercised by the lessee until the lessee has provided to pay the owner of the land, his lessees and permittees, upon which the AS 38.05.125 reserved rights are sought to be exercised, full payment for all damage sustained by the owner by reason of Page 7 of 27 LZ 10 g abed E9SE-1.0566 VNSV1V'3OVEIOHONb' OOH 31lfS '3f1N3AV H1L 1S3M OSS S30HflOSH 1VHfllt/N 301N3N11HVd3a SVO GNV 110 JO NOISING `£10103£114 :31`d1S 3H101 :smog)}se pessaappe `palsenbaa idlaoaa wniaa 'flew pellgieo JO paaaisl6aa Aq JO AHeuosaad uanl6 eq isnw pue 6uliuM uI JO paooaa lueuewied e bulonpoad elpaw aluoaloale Aq eq isnw eseel slgi aapun peplwJed JO paalnbaa saoliou Au'' (e) '1S31OHd !S30110N 'SZ •sen!n!lae°seal Ile 6uunp awls eq u1-luesaad eq II!M 0 M lue6e ue'ssaappe pue'chili(1of'eweu Aq 'Moleq SZ gdea6eaed aapun eoliou e of wensind'aieu6lsep osle Heys aassal ayi'Aenruepun are suolieiedo 10 ueld e of;uensand sali!ngoe wow •Molaq SZ gdea6eaed gilts aouepaooae u1- uenl6 aaliou e Aq lues eq of ale enlieluesaadaa ley;of saoliou ion"of sseippe ayi JO anlie;uesaadei pezuoyine sit}o uolieu6lsep agl e6ueyo Aew aassal ayi JO °leis ayi •°seal slgi 6uuelslulwpe to sesodind ay1 aol sledlauud anlioedsaa alayi ao; sanllelu°saadaa pezuoyine eq Heys aassal ayi}o peyaq uo°seal sly;6ulinaaxa uosied ayi pue'e)Isely 10 ele1S`saaanoSeH leanieN to luewpedaa `see pue 10}0 uolslnla 011110 aolaaa!a ayi 'S3AI1V1N3S]Eld3H 43ZIEIOH1flV 'b? •lueweeJ6e pun JO anlieaadooa eyi of paiilwwoo ewe peseal ayi}o uolliod ayi of loads°, guts puoq Aue ule;ulew lou paau aassal eq 'puoq eplMeleis a sagslwn}aoleaado ilun ayi pun `eleis eyi Aq pequasaad JO panoadde luaweeJ6e pun JO anlleaad000 e o;ped u!JO alogM u1- paiilwwoo sl eaae pm! ayi)1 (p) •4dea6eaedgns sly;aapun puoq leuolpppe Aue to iunowe eyi pue aol paau ayi 6ululwJelep ui awls 0111 Aq paaaplsuoo eq HIM IN'gdea6eaedgns slgi aapun pesodwl puoq a}o iuewaalnbaa Aue Alslies IOU II!M puoq ap!mams v •°seal 31111 aapun ino peuaeo eq of JO 6ulaq suolleiedo to sedAI ayi ui panlonu! ){su ;o aaa6ap ayi pue sasn sit pue eoepns ayi 10 einieu ayi Aq Pa!plsnf sl lunowe JeIeaa6 e aaayM enoge(e)u1-pal)loeds iunowe eyi uey;Jeleaa6 lunowe algeuoseaa a u1- puoq e aalnbea `paeeq eq of A;!unpoddo algeuoseaa e pue aassal ayi of aaliou Jade `Aew ems 041 (o) •suolleln6aa algeolldde gilts eouepa000e u1- puoq epiMeleis e uleiulew pue yslwnl'enoge(e)aapun paalnbaa puoq awl()nail u! `Aew aassal ayi (q) °leis ayi Aq peJnbeJ se 6uol se puoq leg1 welulew isnw PUe '000'01-$ uegl ssal ou inq `earn peseal ayi ui pauleluoo woe ue to uogaeal JO woe rad g$ ;seal le 01 lenbe lunowe ue u!°seal sly;10 aouenssl ayi of mud puoq e ysluan}!legs aassal ay1'ems ay;Aq paalnbaa 11 (e) 'SaNOEI 'EZ •saoiaealuoa luepuedepul sit to suo!loe lie aol Apl!q!suodsaa ewnsse o;seaa6e Alssaadxa Gesso!au •Aoidwe s,eessal ayi u1-ao;oealuoa luepuedepul ue Aq paiilwwoo uolsslwo JO tae ue uo paseq sl legs luawuoalnue 04101 waey aay;o JO Hlds llo ue wail 6u!ilnsaa se6ewep aol JO°seal sly;lo uolslnoad e to goeaaq aol uol1ae ue o;asualap Aue sanleM Alssaadxe aassal ayi (o) •elels ayi;o aaue6ll6au otos ay;WOa;6ul;Insaa JO Aq pesneo Aanful JO 'e6ewep `ssol Aue Jo' ydea6eaedgns sly; aapun °leis ayi of alglsuodsaa lou sl aassal ayi •aassal ay; }o ;leyaq uo JO Aq °seal sly;aapun paiilwwoo uolsslwo ao tae Aue woo;6ulilnsaa ao Aq pesneo uosied Aue of Aanful JO Alaedoad of a6ewep JO ssol a01 swlela 6ulpnloul 'wlela Aue 'wool sseiwaeg it p104 pun `aol awls ay1 Apuwapul Heys aassal ayi (q) •°seal sly!io enialn Aq O£1-'SO'8E St/aapun algeAed ewooeq Aew;egi sebewep lie}o luawAed ayi aol uolslnoad luelal};ns se awls ayi Aq pepae6as eq IIIM gdea6eaed 91111 gUM aouelidwoa u1- puoq a 1-0 6ulyslwn;0U1 •se6ewep vans gum uolioeuuoo u!ao wail 6ulsue sasuadxa pue 'sali!I!ge11 'spuewap 'swlela Aue isule6e pun WOal ssalwaey ;l Rog pun awls ayi Apuwapul 0; pun O£1'90'8£St/aapun algeAed ewooeq Aew ley;se6ewep Aue ao}Aed 01 saaa6e aassal 0111 •ael)ns Aew pue! an ;o aauMO ayi yalgM se6ewep ayi aulwaalep of paieaol sl puei ayi aaayM uollalpsunf ivaladwoa 10 ;anoo e ui s6ulpeeoaad 1e6al eln;l;sul Aew pue 'se6ewep aol luawAed `seelj!wJed pun saassal sly 'aeuMo ayi()lamas 04 Alunaas pun 'lunowe 'Waal 01 se ivalaylns eq of'peal eq 01 Auuniaoddo ue pue aoliou Jai}e 'ems ay1 Aq peulwielep puoq Alwns e 6ulisod as;le puel ayi Janie Aew aassal ayi 'se6ewep ayi allies lou scop UOse°a Aue aol aauMO ayi)1 'puel ayi 6uua;ue TO THE LESSEE Hilcorp Alaska, LLC Billing Address: Attn: Land Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Attn: Rentals Anchorage, AK 99503 PO Box 61229 Houston, TX 77002 (b) Any notice given under this paragraph will be effective when delivered to the above authorized representative. (c) A lessee who wishes to protest the amount of money due the state under the lease or any action of the state regarding a provision of this lease must file a written protest with the Division of Oil and Gas within 30 days after the mailing date of the state's notice or bill. A lessee who fails to file a protest within the required time waives any further right to protest. The state will establish the administrative appeal procedure to be followed and will inform the lessee of the procedure no later than 30 days after the filing of the written protest. 26. STATUTES AND REGULATIONS. This lease is subject to all applicable state and federal statutes and regulations in effect on the effective date of this lease, and insofar as is constitutionally permissible, to all statutes and regulations placed in effect after the effective date of this lease. A reference to a statute or regulation in this lease includes any change in that statute or regulation whether by amendment, repeal and replacement,or other means. This lease does not limit the power of the State of Alaska or the United States of America to enact and enforce legislation or to promulgate and enforce regulations affecting,directly or indirectly,the activities of the lessee or its agents in connection with this lease or the value of the interest held under this lease. In case of conflicting provisions,statutes and regulations take precedence over this lease. 27. INTERPRETATION. This lease is to be interpreted in accordance with the rules applicable to the interpretation of contracts made in the State of Alaska. The paragraph headings are not part of this lease and are inserted only for convenience. The state and the lessee expressly agree that the law of the State of Alaska will apply in any judicial proceeding affecting this lease. 28. INTEREST IN REAL PROPERTY. It is the intention of the parties that the rights granted to the lessee by this lease constitute an interest in real property in the leased area. 29. WAIVER OF CONDITIONS. The state reserves the right to waive any breach of a provision of this lease, but any such waiver extends only to the particular breach so waived and does not limit the rights of the state with respect to any future breach; nor will the waiver of a particular breach prevent cancellation of this lease for any other cause or for the same cause occurring at another time. Notwithstanding the foregoing, the state will not be deemed to have waived a provision of this lease unless it does so in writing. 30. SEVERABILITY. If it is finally determined in any judicial proceeding that any provision of this lease is invalid, the state and the lessee may jointly agree by a written amendment to this lease that, in consideration of the provisions in that written amendment,the invalid portion will be treated as severed from this lease and that the remainder of this lease, as amended, will remain in effect. 31. LOCAL HIRE. The lessee is encouraged to hire and employ local and Alaska residents and companies,to the extent they are available and qualified,for work performed on the leased area. Lessees shall submit,with the plans of operations, a proposal detailing the means by which the lessee will comply with this measure. The lessee is encouraged, in formulating this proposal,to coordinate with employment services offered by the State of Alaska and local communities and to recruit employees from local communities. 32. CONDITIONAL LEASE. If all or a part of the leased area is land that has been selected by the state under laws of the United States granting lands to the state, but the land has not been patented to the state by the United States, then this lease is a conditional lease as provided by law until the patent becomes effective. If for any reason the selection is not finally approved, or the patent does not become effective, any rental, royalty, or other production or profit-based payments made to the state under this lease will not be refunded. 33. NONDISCRIMINATION. The lessee and the lessee's contractors and subcontractors may not discriminate against any employee or applicant because of race, religion, marital status, change in marital status, pregnancy, parenthood,physical handicap,color,sex,age,or national origin as set out in AS 18.80.220. The lessee and its contractors Page 9 of 27 LZ JO 01. abed Jaylo 'o ales }o Iu!od eq} o} ea'e Hun JO paseal eq} woa} AeMe uo!Iel'odsue'1 }o sisoo algeuoseaa snu!w `uo!loesue'1 g16uai-s,w'e ue u! seoue}sgns pale!oosse'o 'se6 'Ho ay} Has pp aassal eq}}! seouelsgns paleposse 'o `se6 'Ho ay}'o} eiueoa'o}Ioedxe pinoM aassal ay}aoud eq ueaw!pm anoge(q)pus(e)syde'6e'edgns u!„eoud pia!}„w'al ay}'seouelsgns paleposse JO `se6 'Ho ay} uo!poesue'I yl6ual-s,w'e ue u! 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'spoylaw uo!lonpo'd Aaeu!p'o Aq w'o}p nb!l u! peonpoJd We Imp'Apne'6}o ssalp'e6a' 'suoq'eoapAq Jaw pue Ho wnelaled epr'o sueaw „Ho„ (1.) :as!M'aglo samba'Algep!oneun lxaluoo eqi ssalun s6u!ueew 6u!MoIo} eqI aneq sp'oM 6u!Mollo} eqI ''anaMoH '0170'01'1.0 SV Aq sa1nI5ls }o uo!lela'd'alu! eq4 oI loads'' u! pa'mbaw 'auuew ay1 u!alq!ssod O'OyM pala'd'alu!eq 01 a'5 esee!s!q1 u!pasn sese'yd pus sp'oM IIV 'SNOIaINIdla 'ti£ .uo!s!no'd uo!leu!wuos!puou s!q1 lno 6u111as seo!1ou amid snono!dsuoo e 'sod `eseal s!yl'apun suogeJedo Aue 6u!uu!6aq uo 'lsnw s'o1oe'1uoogns pus disposition. The lessee must determine this price in a consistent and logical manner using information available to the lessee and report that price to the state. (d) The state may establish minimum values for the purposes of computing royalties on oil, gas, or associated substances obtained from this lease,with consideration being given to the price actually received by the lessee, to the price or prices paid in the same field or area for production of like quality, to posted prices, to prices received by the lessee and/or other producers from sales occurring away from the leased area, and/or to other relevant matters. In establishing minimum values, the state may use, but is not limited to, the methodology for determining "prevailing value" as defined in 11 AAC 83.227. Each minimum value determination will bp made only after the lessee has been given notice and a reasonable opportunity to be heard. Under this provision, it is expresslyagreed'that the minimum value of royalty oil, gas, or associated substances under this lease may not necessarily equal, and may exceed, the price of the oil, gas, or associated substances. 37. ROYALTY IN VALUE. Except to the extent that.the state elects to receive all or a portion of its royalty in kind as provided in Paragraph 38 below, the lessee shall pay to the state that value of all royalty oil, gas, and associated substances as determined under Paragraph 36 above. Royalty paid in value will be free and clear of all lease expenses (and any portion of those expenses that is incurred away from the leased area), including, but not limited to, expenses for separating, cleaning, dehydration, gathering, saltwater disposal, and preparing the oil, gas, or associated substances for transportation off the leased area. All royalty that may become payable in money to the State of Alaska must be paid on or before the last federal banking day of the calendar month following the month in which the oil, gas, or associated substances are produced. The amount of all royalty in value payments which are not paid when due under this lease or the amount which is subsequently determined to be due to the state or the lessee as the result of a redetermination will bear interest from the last federal banking day of the calendar month following the month in which the oil,gas,or associated substances were produced, until the obligation is paid in full. Interest shall accrue at the rate provided in AS 38.05.135(d) or as may later be amended. Royalty payments must be accompanied by such information relating to valuation of royalty as the state may require which may include, but is not limited to, run tickets, evidence of sales, shipments, and amounts of gross oil, gas, and associated substances produced. 38. ROYALTY IN KIND. (a) At the state's option, which may be exercised from time to time upon not less than 50 days'notice to the lessee,the lessee shall deliver all or a portion of the state's royalty oil,gas,or associated substances produced from the leased area in kind. Delivery will be on the leased area, unit area, or at a place mutually agreed to by the state and the lessee, and must be delivered to the State of Alaska or to any individual, firm, or corporation designated by the state. (b) Royalty oil, gas, or associated substances delivered in kind must be delivered in good and merchantable condition, of pipeline quality, and free and clear of all lease expenses (and any portion of those expenses incurred away from the leased area),including,but not limited to,expenses for separating,cleaning,dehydration,gathering, saltwater disposal, and preparing the oil, gas, or associated substances for transportation:off the leased area. (c) After having given notice of its intention to take,or after having taken its royalty oil,gas,or associated substances in kind, the state, at its option, may elect to receive a different portion or none of its royalty in kind. If, under federal regulations, the taking of royalty oil, gas, or associated substances in value by the state creates a supplier- purchaser relationship,the lessee hereby waives its right to continue to receive royalty oil, gas,or associated substances under that relationship,and further agrees that it will require any purchasers of the royalty oil,gas,or associated substances likewise to waive any supplier-purchaser rights. (d) The lessee shall furnish storage for royalty oil, gas, and associated substances produced from the leased or unit area to the same extent that the lessee provides storage for the lessee's share of oil, gas, and associated substances. The lessee shall not be liable for the loss or destruction of stored royalty oil, gas and associated substances from causes beyond the lessee's ability to control. (e) If a state royalty purchaser refuses or for any reason fails to take delivery of oil, gas, or associated substances, or in an emergency, and with as much notice to the lessee as is practical or reasonable under the circumstances,the state may elect without penalty to underlift for up to six months all or a portion of the state's royalty on oil, gas, or associated substances produced from the leased or unit area and taken in kind. The state's right to underlift is limited to the portion of royalty oil,gas,orassociated substances that the royalty purchaser refused or failed to take delivery of, or the portion necessary to meet the emergency condition. Underlifted oil, gas, or associated substances may be recovered by the state at'a daily rate not to exceed 100 percent of its royalty interest share of daily production at the time of the underlift recovery. 39. REDUCTION OF ROYALTY. Lessee may request a reduction of royalty in accordance with the applicable statutes and regulations in effect on the date of application for the reduction. Page 11 of 27 Z2 Jo Zl abed 9IOZ'CL 43Wgaildg uolseIwur3 AVY t, _ feu 'd 4l!Pnf Air 0119fld AddlON VNISV'1V dO aLV.LS 81.0Z'CI, 4oieW :sandxa uo!ss!wwooAW emsely 4o alelg ay;J04 pue U!o!lgnd ti oN .Auedwoo Al!I!ge!! pal!w!!ayl;o lleuaq uo 'Auedwoo Apga!I pal!wg ammelea e'011 'emsely daool!H;o luap!saJd ao!A Jo!ua9 'sawe8 'y uyo'Aq '91.0Z 'lady 40 Aep s!ql aw aao4aq pa6palmowloe seen luawn.gsu!6u!o6aJo;eq.!. ( louls!a le!o!Pnf PJ!ul .ss( ( V ISV-IV 90 91y1S '32•I3H 32:1f1±VNOIS S,99SS91 dO 1N9WOa91MON)1OV AHVION 12�9SNI luap!saad ao!A Jo!uag 'sawe8 •y ugor :el aweN palu!id :ainleu6!g 31180f)IS lv 0 1IH :39SS91 v0W0*flf . uo�asiueiuo%�;w istirui%NM/ T saJ!dxa uo!ss!wwoo AIN 9tI'ISlld 1C21V.I.U..,., eNs I to ale S ayl Jo4 ue u!oggnd ;' elo VSSV'IV AO SIV,75 1 .Jossal se mlsely;o alelS ayl;o jleuaq uo 1! •u!u61- Aluelunlon pa6palmou)loe pue ash! s!ql palnoaxa oqm pue 'sa3Jnosa�l Ie�nleN 4o luaw Jedaa 'e�lsely 4o alelS ayl : -O pue I!O to uo!s!nla NI to —75 ydj paJeadde aw aao4aq ' s/Q2 p Yt' f/ uO C ( pulsla le!o!Pnf'Paul .ss( ( V>iSV-IV 90 31.VIS seO pue I!0 10 uo!s!n!o 'aoloana a6!a woo C747:42(.3 V>!SV 1V 9O 91V1S .suo!s!noJd sl!Aq punoq aq of aaJ6e aassal ayl pue JossaI se alels ayl '9SV91 SIHI ONINOIS.l9 SUE1® � uo loa}}a sa�lel aseal s!4l '91ya 9AI1O9dd3 'Ob LESSEE: Signature: Printed Name/Title: INSERT NOTARY ACKNOWLEDGMENT OF LESSEE'S SIGNATURE HERE. LESSEE: Signature: Printed Name/Title: INSERT NOTARY ACKNOWLEDGMENT OF LESSEE'S SIGNATURE HERE. Page 13 of 27 LZ Jo},G abed •sesAieue Aen,'ns eJnleJedwal pue a,'nssa,'d Mann pue sesAieue ale,'pAq se6 'sasAieue o!lsnooe `sesAieue u!eals `sesAieue A,'ols!i a,'nieiadwal pue leunq 'A,'1s!wego ,'alert 'sasAieue edolos! `(•ole 'd01 `dHX 'bwd3) sasAleue leo!wauo 'sasAieue aanssaad A,'ep!deo uo!1oe1u! A,'no.1aw 'sasi(!eue uo!snlou! pmu 'sasAieue uo!ss!} 'A6olouo.1yooe6 `s!sAlo,'Ad ien3>iooa 'uoqieo o!ue6io lelol `aoueloal}a,' a1!uu1!n 'Ap.1nlew lewaayl 'side.16o,'o!w was 'sasAleue uo!loe,'}}!p Ae,'-X '(sesAieue lunoo-lu!od 6u!pniou!) Aide.1boJ ed 'A6o!ouAied 'A6o!owoeied 'o1 pip!!lou 1nq '6u!pniou!spode,' pue elep part He}o sal!}alq!6al 'Jeal0 •iZ au;elep 601 ayl of uo!1!ppe u! ddll Jo dad e se pods,' pue suo!lduosep s6u!11no pue 'se!pado.1d pnw 's,'olea!pu! 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Final reports of velocity, checkshot or VSP surveys (an ASCII format digital version of the above data shall also be submitted), including seismic profile data in SEG-Y format. Indicate"none"in your response to this request if no velocity,checkshot or VSP surveys were undertaken. Submission of velocity,checkshot, and VSP surveys is always required by DNR under the operator surface-use permit obligations. 23. All coalbed core, gas, and water quality reports including lab analyses of core lithology, coal rank, vitrinite reflectance, maceral composition, total organic carbon, ash, sulfur and BTU content, moisture content, cleating, adsorption/desorption data, residual gas measurements, porosity and permeability analyses, core photos, if available. 24. Any other geoscience-and engineering-related data sets from the well(s). Please note: Physical samples of well cuttings or cores specified in 20 AAC 25.071(b)(2) and 20 AAC 25.071(b)(4) should be sent to AOGCC, not to the Division. All material should be either hand-carried by bonded courier or mailed by registered mail to: Resource Evaluation Section Alaska Department of Natural Resources, Division of Oil&Gas 550 West 7th Avenue, Suite 1100 Anchorage,AK 99501-3510 Email: DOG.REdata@alaska.gov Page 15 of 27 Le 10 91 abed 801naaS a}!IPI!M Pue ys!d •S'n SMdSf g6noaos adoiS U>JoN EISN eo!nues seuegsid euuefnl leuo!leN S1INN uo!leaJoau pue Sved ;0 uo!s!n!a LIOdC1 (HNCIV) seO pue I!O JO u0!s!n!a s'8Oa (IdNav)Je eM pue`puel `6ulu!w;o uo!sIA!a M1WQ uo!ss!wwoO 6u!IegM OWNS] eilsel`d OMEV seoanosau!eanleN}o luawluedea eMse!y EINay uo!lenuasuos Ieluawuoa!nu3;o luewluedea eNsel`' o3ay awes pue quid}o luewpedea eNse!y O'8doy aweN Aoue6y uo!le!nauggy :we suoge!naagqe Aoue6y •luewwoo J01 sa!1!unwwoo eouels!sgns paloa};e Alle!1uejod pue 'uo!ss!wwos 6u!IegM owp1s3 e>!sely 'y6nouoe edolS L11-10N eqj 0l algel!ene spew eq IHM suo!leogddy 1!waed uogeaoldx3 Ieo!skgdoes ie }o suo!laod Auelaudoad-uou eql ;o sa!doo •pesn uee6 pue Asians;o ed/(1 eqj uo 6u!puedep seven slewwew euuew uo walla}0 1ualxe eq •saanseaw uo!1e6!1!w eouals!sgns eqj aes •suo!lea6!w Ile; uo 6uuds 6uunp sepia! Auoleu6!w aleqm peeq oq ;o A3lup!n eqj u! sl!waed uo!leuoidxe Ieo!s4doe6 uo pasodw! eq Aew saanseajnl •selegM peegMoq}o ao!neyaq ay1 uo loedw!ue aney Aew se!Un!loe Ieo!si(ydoe6 awos legl aleo!pu!se!pn1S •slewwew euuew Aeoi loads `saioads ue odwi uo walla a eaasaao �( euoseau e 1 uopue loefoad asodoad e 3 o i(l!sualu! II .f. 3 >J }3 Iq � Iq U P U } pue'uo!leanp`adoos'ez!s eqj uo puadap Hon`lou uo pelelau-aseai iegjeq n'sl!wied uo!leio!dxe Ieo!skgdoe6 uo suolloulse j •se!3!n!loe palelaa-aseai paaap!suoo aae 'aassal eql Aq paloealuoo JO palonpuoo sAanans o!ws!es eseel-isod 'uanaMoH •wayl/(q paloealuoo lou sawngoe esoyl nano Iouluoo aney jou Aew seessai'ewe ales eql w'sAanans o!ws!as apnlou!go!gM `suo!leaado snouen asodoad Aew seiuedwoo aassal-uou uo saassei •96 ayy l l Aq pawano6 we se!1!n!1oe uo!leaoldxe Ieo!s4doe6 'spuel alels uo uo!leuoldxe Ieo!skydoe6 0l Aidde lou op saanseaw uoge6!1!w eqi 'paleo!pu! se ldeox3 •suo!leuado ueld ay1 }o Ma!AeJ o!Ignd eql 6uunp spew eq ll!M uo!ldeoxe ue luea6 0l aaylegM uo!spap eq •suo!leaado }o mid ay1 u! pepnpu! eq lsnw suo!ldeoxe u0}suo!1eo!;!lsnf pue sjsenbajd •aanseew uo!le6!3!w eqj}o 1uaau! eq1/c;s!les o1 anHewelle aaueq JO lenbe ue ameluepun II!M Gesso! NI 1eil JO a!geo!loead lou Si einseew uo!le6!1!w aUl Ul!M eoue!Idwoo legl aassal eqj I(q 6u!Mogs e uodn pelueu6 eq/quo II!M suolldeox3 •saanseaw uo!le6!3!w aseqj suogdeoxe lueu6 Sew.oloanp eql walla u!ueld e ql!M louls!p lelseoo paloa;;e ue sep!Iod algeeouo;ue an pue spaepuels ep!Melels 6u!pnpu! '(d!Noy) wea6oud luewe6eue!nl !elseoo m{sely eq ;o seio!Iod a!geeoao}ue aU1 y}!M luels!suoo eq lsnw seil!n!loe aseai •pe4eool s! ewe aseai e yo!pM u!y1!M sueld ewe iienloues pue `sueld ewe 1epgeq Ieowio `sueld e6n}aa awe6 Olgday pue !sueld suanu uo!leaaoau pue sueld ewe Id Nay aim}JO luauno He se Ham se`pepuewe se 'suo!leln6aa pue'swims `sapoo leuapa}pue 'awls'pool a!geo!!dde He y1!M*Iwoo lsnw seessei •suo!leuado;o ueld pasodoid e 1!wgns saassa!uagw pasodw! eq Am!I !pm seinseew !euo!1!ppy •seiouabe !eool pue 'e s 'IeJapa}aaylo pue 'suo!lez!ue6uo !eluewuoa!nue 'sluewwano6 Ieoo! 'o!!gnd ay1 pef!wgns uo!lewao}u! pue sluawwoo pue sales aseai eA!p4edwoo Je!uee u! pasodw! swaal 6uuap!suoo ague pedo!anep ejeM saanseaw esayl •a1!s egje 1slxe Aew 1ey1 spiezeq Ieo!sl(gdoe6 le!1ualod Aue ssaappe osie isnw 11 •Mo!aq pals!! suolloulsaa aqj AIdwoo o1 paAoidwe eq o1 spaepuels Ieuo!leJedo pue'spoq ew uo!lonulsuoo`eualuo u6!sep`saanseaw o!}pads eq pue se!1!n!1oe peuue!d uo; sa1!s aqi A;!luep! lsnw suo!leuado ;o ueld y •segin!loe uo!lonpoad ao luewdolenep `uo!leaoldxe 6u!onpuoo atom Joloaa!p ay1 wou; suo!leuado ;o ueld pelielep e ;o !enoadde u!elgo lsnw seossai •saanseaw uo!1e6!pw asayl uo paseq si!waad ueq o pue luawdolenep uo`uo!leuoldxe `uo!leaado}o sued uo!1!puoo!pm pue saanseaw uoUe6!1!w pedolanep say O'8Oa `se!3!n!loe pelelei-eseel o!;!oeds}o sloa};a Ieluewuoa!nue pue!epos esaanpe IeHuelod ay1 a e6giw o1`A1luenbesuoo•slsaaalu!lseq s,alels eq4 u!s! Iesods!p eoanosei e leyi ensue o1`a1n1e1s Aq pasodw! esoyl o1 uowppe w 'suo!1e1!wg JO suo!Hpuoo asodw! 01*owe eyl ql!M`(,doloaa!p„) (o'8oa) se9 pue Ho JO uo!s!n!o `Jolow!p aq1 ep!noad l(1uoylne JO uo!1e6alap leluewlaedap eq pue (e)960'90.9E SV Mbi.OZ ap!Mealy eas poineas ao4 saanseaw uoi4e6Riw A. Mitigation Measures 1. Facilities and Operations a. A plan of operations must be submitted and approved before conducting exploration, development, or production activities, and must describe the lessee's plans to avoid or minimize impacts on residential, commercial, and recreational areas, Native allotments and subsistence use areas.At the time of application,lessee must submit a copy of the proposed plan of operations to all surface owners whose property will be entered. b. Facilities must be designed and operated to avoid or minimize sight and sound impacts in areas of high residential, commercial, recreational, and subsistence use and important wildlife habitat. Methods may include providing natural buffers and screening to conceal facilities, sound insulation of facilities, or by using alternative means approved by the director, in consultation with ADF&G and the NSB. c. To the extent practicable, the siting of facilities, other than docks, roads, utility, and pipeline crossings will be prohibited within 500 feet of all fish-bearing streams and water bodies and 1,500 feet from all current surface drinking water sources. Additionally, to the extent practicable, the siting of facilities will be prohibited within one- half mile of the banks of the main channel of the Colville, Canning, Sagavanirktok, Shaviovik, Kadleroshilik, and Kuparuk rivers. Facilities may be sited within these buffers if the lessee demonstrates to the satisfaction of the director,in consultation with ADF&G,that site locations outside these buffers are not practicable or that a location inside the buffer is environmentally preferred. Road, utility, and pipeline crossings must be consolidated and aligned perpendicular or near perpendicular to watercourses. d. Impacts to identified wetlands must be minimized to the satisfaction of the director, in consultation with ADF&G and ADEC. The director will consider whether facilities are sited in the least sensitive areas. Further, certain activities within wetlands require permission from the U.S. Army Corps of Engineers (see Lessee Advisories). e. Exploration facilities must be temporary and must be constructed of ice unless the director determines that no practicable alternative exists. Use of gravel structures may be permitted on a case-by-case basis by the director, after consultation with DMLW,and ADF&G. Approval for use of existing structures will depend on the extent and method of restoration needed to return these structures to a usable condition. f. Pipelines must utilize existing transportation corridors where conditions permit. Pipelines and gravel pads must be designed to facilitate the containment and cleanup of spilled fluids.Where practicable,onshore pipelines must be located on the upslope side of roadways and construction pads unless DMLW determines that an alternative site is environmentally acceptable. Wherever possible, onshore pipelines must be buried where soil and geophysical conditions permit. All pipelines, including flow and gathering lines, must be designed, constructed and, maintained to assure integrity against climatic conditions,geophysical hazards,corrosion and other hazards as determined on a case-by-case basis. g. Onshore pipelines shall be designed and constructed to minimize alteration of caribou and other large ungulate movement and migration patterns. At a minimum, above-ground pipelines shall be elevated 7 feet, as measured from the ground to the bottom of the pipe,except where the pipeline intersects a road, pad,or a ramp installed to facilitate wildlife passage. Lessees shall consider increased snow depth in the sale area in relation to pipe elevation to ensure adequate clearance for wildlife.ADNR may,after consultation with ADF&G, require additional measures to mitigate impacts to wildlife movement and migration. h. All pipelines,including flow and gathering lines,must be designed and constructed to provide adequate protection from water currents, storm and ice scouring, subfreezing conditions, coastal erosion, permafrost thawing, and other hazards as determined on a case-by-case basis. i. Offshore oil and gas transportation pipelines will be encouraged if the director determines that the laying of such pipelines is technically feasible and environmentally preferable to transport by oil tanker or other means. j. Following the installation of a pipeline of sufficient capacity,no crude oil will be transported by surface vessel from offshore production sites, except in an emergency. The director will evaluate the emergency and determine an appropriate response to the condition. k. Causeways i. Continuous-fill causeways are prohibited. Environmentally preferred alternatives for field development include use of buried pipelines, onshore directional drilling, or elevated structures. Non-continuous-fill causeways must be designed, sited, and constructed to prevent significant changes to nearshore oceanographic circulation patterns and water quality characteristics (e.g., salinity, temperature, suspended sediments) that exceed water quality criteria, and must maintain free passage of marine and anadromous fish. 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Before commencement of any activities, lessees shall consult with ADF&G to identify the locations of any known brown bear den sites that are occupied in the season of proposed activities. Exploration and development activities started between September 20 and May 15may not be conducted within one-half mile of known occupied brown bear dens, unless alternative mitigation measures are approved by ADF&G. A lessee who encounters an occupied brown bear den not previously identified by ADF&G must report it to the Division of Wildlife Conservation, ADF&G, within 24 hours. Mobile activities shall avoid such discovered occupied dens by one-half mile unless alternative mitigation measures are approved by DO&G with concurrence from ADF&G. Non-mobile facilities will not be required to relocate. iii. Before commencement of any activities, lessees shall consult with the USFWS to identify the locations of known polar bear den sites. Operations must avoid known polar bear dens by 1 mile. A lessee who encounters an occupied polar bear den not previously identified by USFWS must report it to the USFWS within 24 hours and subsequently avoid the new den by 1 mile. If a polar bear should den within an existing development, off-site activities shall be restricted to minimize disturbance. e. Permanent, staffed facilities must be sited to the extent practicable outside identified brant, white-fronted goose, snow goose, tundra swan, king eider, common eider, Steller's eider, spectacled eider, and yellow-billed loon nesting and brood rearing areas. f. Due to high concentrations of staging and molting brant and other waterbirds within the coastal habitats along the Teshekpuk Lake Special Area(TLSA) and other areas, operations that create high levels of disturbance, including but not limited to dredging,gravel washing, and boat and barge traffic along the coast,will be prohibited from June 20 to September 15 within one-half mile of coastal salt marshes, specifically tracts 187, 209, 320, 483-485, 493, 494,496,497, 500-514, 517-519, 524,and 530. In addition,tracts 228 and 231,and tracts 521-526 are subject to the same restrictions between May 15 and July 30 to protect large concentrations of breeding snow geese. The construction and siting of facilities within one mile of these areas may be allowed on a case-by-case basis if the director and ADF&G determine that no other feasible and prudent location exists. g. To protect hauled-out spotted seals, boat and barge traffic will be prohibited between July 15 and October 1 within ' one-half mile of the Piasuk River delta and Oarlock Island. 3. Subsistence, Commercial, and Sport Harvest Activities a. i. Before submitting a plan of operations for either onshore or offshore activities that have the potential to disrupt subsistence activities, the lessee shall consult with the potentially affected subsistence communities, the AEWC,and the NSB(collectively"parties")to discuss the siting,timing,and methods of proposed operations and safeguards or mitigating measures that could be implemented by the operator to prevent unreasonable conflicts. The parties shall also discuss the reasonably foreseeable effect on subsistence activities of any other operations in the area that they know will occur during the lessee's proposed operations. Through this consultation, the lessee shall make reasonable efforts to assure that exploration, development, and production activities are compatible with subsistence hunting and fishing activities and will not result in unreasonable interference with subsistence harvests. In order to avoid conflicts with subsistence, commercial, and sport harvest activities, restrictions may include alternative site selection, requiring directional drilling,seasonal drilling restrictions, and other technologies deemed appropriate by DO&G. ii. A discussion of resolutions reached or not reached during the consultation process and any plans for continued consultation shall be included in the plan of operations. The lessee shall identify who participated in the consultation and send copies of the plan to participating communities and the NSB when it is submitted to the division. iii. If the parties cannot agree,then any of them may request that the commissioner of ADNR or his/her designee to intercede.The commissioner may assemble the parties or take other measures to resolve conflicts among the parties. iv. The lessee shall notify the director of all concerns expressed by subsistence hunters during operations and of steps taken to address such concerns. b. Traditional and customary access to subsistence areas shall be maintained unless reasonable alternative access is provided to subsistence users. "Reasonable access" is access using means generally available to subsistence users. Lessees will consult the NSB, nearby communities, and native organizations for assistance in identifying and contacting local subsistence users. c. Whale Harvest Protection: Page 19 of 27 LZ to 0?abed •law uaaq anal seionb 6umegM l!lun uo4ei6!w peegMoq Ile;eql;o luawaouawwoo uodn pepgigoad s! 6u!1!!ap `ZMS welse3 all ul •s,ZMS walsaM pue lealue0 ail u! pasodw! eq Aew `ZMS walse3 eql Jo;pasodw!as041 of Je!!w!s'9uo!loulseJ 6w'i!Jp leuo!1!ppe',moo Aew seil!n!loe bu!IegM aouals!sgns ql!M lo!I;uoo le141 seu!wJelep awls 0141 `eualuo pequosep anoge 0141 6u!sn uo!leaado pesodoid all ;o Me!naJ uodn ;I E al!s pup ail passed eneq o1 pawaap uaaq anal saleUM ail ;o lueoiad og ua4M s! uo!1eJb!w all ;o lu!odp!w ail .gz Jagwaldas uo uo4eJ6!w;3 lulodp!w 0141 yl!M oz Jegoloo-01.aagwaldaS -ZMS Ieilueo 0141;0 lsaM pue pieMeeg 'oz aagwaldas uo uo4e16!w all}o lu!odp!w all 4l!M 01. Jegolo0 - I. aagwaldaS - ZMS walse3 ail ;o pJeMeeS -ZMS eP!slnO •gz aagwaldaS uo uo!leJ6!w ail;o luiodp!w all 4l!M 0Z Jagoloo-01.Jagwaldas -ZMS walsaM pUe ZMS la p°0 •0?aagwaldaS uo uo!leIblw ay;lo lu!odp!w all Ul!M 0l Jegoloo- 1 aagwaldaS-ZMS walse3 :solea uo4ei6!W Z •epnl!6uol M 0L9 L pue opg uaaMlaq eu!laaogs all;o saw Ieo!lneu OZ u!y1!M ewe 1e141 s!ZMS walsaM •apnl!6uol M 01.91. pue obtil uaaMlaq au!iwogs an 40 sel!w leo!ineu oe u!U1!M ewe ley'Si ZMS !eJlue° •epnl!6uol M obt'l pue 01;171. uaaMlaq euueiogs all;o seuw leo!lneu oz u!yllM ewe lei's!ZMS welse3 :seuoz 6u!IegM aouals!sgng 'eey einseaw uo4e640i ql!M aouepa000e u! sMaao 6u!!e4M !ea)! yl!M paleu!pa000 eq !legs seaae 6u!!egM awe u!yl!M buuin000 seinloru s 6u!Ilup yl!M pele!oosse ApAi4oe poddns le!luess3 law uaaq anal selonb &!!apun uo4eJ6!w ale4M ail buunp ZMS lealuaa all u! pal!q!loJd ale 6u!I!up y1!M pale!oosse se!l!n!Pe ie!luasse-uou Ilb' •egy einseaw uo4e6nAl 441M aouepa000e u!sMaao 6u!'egM all 41!M sa!l!n!loe aleu!pi000 of sueld s,JoleJedo 0144 (g pue 'ewe ail u! sMaJO 6u!legM ;o Jagwnu (0'ewe awes 0141 u! suo!leiedo bu!!lup;3 Jegwnu (E 'san!lewalle 6u!Ilup appeal pue adAl uo!leaado 6u!Ilup (Z `se°Je 6u!IegM posodoid Jo awe o1 suo!1eJ°do 6u!11!Jp;o Al!wlxoid(1. :suo4eiodo°sail alenlena of pasn eq II!M eualuo 6u!Mollo;°gl£•1ew uaaq aney selonb 6u!legM all pun s!seq aseo-Aq-aseo e uo pa1!q!lad eq Aew gldep p!ogseiy1 peu!wieiepeid e Molaq pue anoge 61.411up A.iole,io!dxa`ZMS walsaM pue!ep1ue0 0141 u! •law uaaq anal selonb 6u!IegM all pun uo!1eJ6!w ale14M pea4Moq pe;NI 40 luawaouawwoo uodn pel!q!goid s!saJnPnJls bump bu!leoll wOJ;!Ms walse3 all ui yldep plogsaJyl pau!wJelapaJd e Molaq pue anoge 6u!Ilup Aioleioldxe `uo!PulseJ anoge 04101 uo!l!ppe u! z•1u!od-p!w uo4eJ6iw alegM 0141 l!lun uo4ei6!w ale4M peegMoq Ile;all;o luawaouawwoo uodn eas 1Jo;nea8 8141 lnoy6noJy4 pal!q!yoJd s! saJnlonJl9 61. 1lup 6u4eol;woo}suo4wado alo4uMop JalP pue 41dap plolsaail pau!WJalapeJd e Mol°q 6u! up iioleaoldxe `Moleq !!! einseew 31 loafgns :seJnloruls bupl!Ja 6u4eo13 wa; suo!leJedO 6u!Iluo AJoleJoldx3 •!! .law uaaq aney selonb 6u!!egM!!1un uo4ei6!w a!e4M peegMoq Ile;041;0 luawaouawwoo uodn pel!gigoad s!6u!II!Jp `ZMS walse3 0141 ul L•(ZMS) euoz bu!legM aouals!sgns leJ1ue0 0144 u! punoi-JeaA paMo!le we spue!s! leneib pue leanleu pue saJnlonJls 6u!llup pepuno;-wolloq woo;suo!leaado a!oyuMop Ja41)pue 9uo4eiedo 6uglup fuoleaoldxe'Moleq!!!ainseew 01 loafgns :spite's! !amp pue IeJn4eN pue saanlonals 6ug!ua pepuno;-wouo8 w3J j 6u!Ilua AaoleJoldx3 •! •005591 0141 Aq uo!leo!Idde 1!WJed suo!leJedo;o mid e uo!ss!wgns 0141 yl!M uo!lounfuoo u!suo!loulsaa 6u!Ilup leuoseas 31 loafgns aq Aew ewe ales °seal ep!MeeJy eas 4Jo;nese aU1 u! ;o0Ja14l u3!1J3d JO Peal Auy •p •8SN 041 Aq pei!nbet;!lueweeibe aouep!one loll;uoo e u!pau!wielep eq Aew se pue gy uo!Pas u! pau!;ap se saleUM of ssaooe a'geuoseei epnload lou !I!M luewdolenap 044 Imo `OM3v 044 pue 8SN x141 U4!M uo!lellnsuoo Li! 'Jolowlp 044;o uo!loe;s!1e5 all of saleJlsuowap aassa)8U1 ssalun pel!q!goid eq 111M(gp gbnall 0p SPeJI) puelsl Jape9;o pita'sea all pue puelsl Aeiy;o pue;sem all uaaMlaq sJaleM awls u!bu!1!s A4!I!oe;luauewJad !!! •8SN all Aq pai!nbai;!luawaaJ6e aouep!one lo!Uuoo a u!pau!WJalap eq Aew se pue gy uo!loas u! pau!;ap se saleUM o1 ssaooe a!geuoseei apnloaJd lou !Pm luawdolanap 0113 3eUl 'OM3`d 0113 pUe 8SN all 14l!M uo!lellnsuoo u! 'Jolo0J!p 0144 ;o uo!loe;s!les ail 3l saleJlsuowap aassa) 0141 ssalun pel!q!goid eq II!M puelsl 593,0 ;o sal!w E u!41!M sJaleM ale's u! bu!1!s A4!I!oe; luauewJad •!! •sa4!I!oe;luauewJad ezuoglne Aew JoloaJ!p 0141`8SN 041;0 lenoidde all ll!M•8SN 0144 Aq pannbei;! 'luawaaJ6e aouep!one 1o!l;uoo e u!pau!wielep eq Aew se pue gy uo!loes u!pau!;ap se saleUM 01 ssaooe a!geuoseei apnloaJd lou ll!M luawdo!anep 0141 1e41 'omit( 0141 yl!M uoilel'nsuoo w `8SN 0141 ;0 uo!loe;s!les all 03 saleJlsuowap aassa)0141 ssalun pal!q!yoid eq II!M puelsl ssa0 uo 6u!l!s Appel luauewJad "Essential activities"include those necessary to maintain well control,maintain physical integrity of the drilling structure, and scheduled crew changes. Support craft include aircraft, boats, and barges. "Non-essential activity," by exclusion, are those activities that do not fit the definition of essential activities. Both types of activities must be described by the operators in their exploration plans submitted for state review. To the extent feasible, mobilization or demobilization of the drilling structures should not occur during the whale migration. If operators propose to mobilize or demobilize during the whale migration, they must describe the activity in their exploration plan and must demonstrate why the activity must occur during the migration period. iii. Exploratory Drilling in Broken Ice: Lessees conducting drilling operations during periods of broken ice must: A. be trained and qualified in accordance with Minerals Management Service standards pertaining to well- control equipment and techniques; B. have an oil spill contingency plan approved by the state that includes requirements for in situ igniters, fire resistant boom, relief well plans, and a decision process for igniting an uncontrolled release of oil; and C. participate in an oil spill research program. e. Exploration, development and production activities located on lease tracts 1 through 26 shall be conducted in a manner that prevents unreasonable conflicts between oil and gas activities and subsistence whale hunting. i. Before submitting a plan of operations for activities on lease tracts 1 through 26,the lessee shall consult with the NSB, the AEWC, and the community of Kaktovik to discuss how the siting, timing, and methods of proposed operations can be planned and carried out to avoid potential conflicts with subsistence whale hunting.Through this consultation,which may include the negotiation of a conflict avoidance agreement,the lessee shall make every reasonable effort to ensure that their activities will not result in unreasonable interference with subsistence whale hunting. ii. A plan of operations for activities on lease tracts 1 through 26 shall include a discussion of the consultation process and any resulting conflict avoidance agreements. In the event that no agreement is reached, the lessee, the NSB, the AEWC, or the community of Kaktovik may request that ADNR call a meeting of representatives of the NSB, the AEWC, the community of Kaktovik, and the lessee to discuss the potential conflict caused by the proposed activities, and attempt to resolve the issues. If the parties are still unable to reach an agreement, then ADNR will make a final determination of the measures proposed to be taken to prevent unreasonable interference with subsistence whale hunting. 4. Fuel, Hazardous Substances, and Waste a. Secondary containment(see definition)shall be provided for the storage of fuel or hazardous substances. b. Containers with a storage capacity larger than 55 gallons that contain fuel or hazardous substances shall not be stored within 100 feet of a water body, or within 1,500 feet of a current surface drinking water source. c. During equipment storage or maintenance, the site shall be protected from leaking or dripping fuel and hazardous substances by the placement of drip pans or other surface liners designed to catch and hold fluids under the equipment,or by creating an area for storage or maintenance using an impermeable liner or other suitable containment mechanism. d. During fuel or hazardous substance transfer, secondary containment or a surface liner must be placed under all container or vehicle fuel tank inlet and outlet points, hose connections, and hose ends. Appropriate spill response equipment, sufficient to respond to a spill of up to 5 gallons, must be on hand during any transfer or handling of fuel or hazardous substances.Trained personnel shall attend transfer operations at all times. e. Vehicle refueling shall not occur within the annual floodplain, except as addressed and approved in the plan of operations. This measure does not apply to water-borne vessels. f. All independent fuel and hazardous substance containers shall be marked with the contents and the lessee's or contractor's name using paint or a permanent label. g. A fresh water aquifer monitoring well, and quarterly water quality monitoring, may be required down gradient of a permanent above-ground liquid hydrocarbon storage facility. h. Waste from operations must be reduced, reused, or recycled to the maximum extent practicable. Garbage and domestic combustibles must be incinerated or disposed of at an approved site in accordance with 18 AAC 60. (See also Section B2, below.) 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In addition,the program must be designed to help personnel increase their sensitivity and understanding of community values,customs, and lifestyles in areas where they will be operating. 8. Definitions Facilities means any structure, equipment, or improvement to the surface, whether temporary or permanent, including, but not limited to, roads, pads, pits, pipelines, power lines, generators, utilities, airstrips, wells, compressors, drill rigs, camps and buildings. Hazardous substance means(A) an element or compound that, when it enters into or on the surface or subsurface land or water of the state, presents an imminent and substantial danger to the public health or welfare, or to fish, animals, vegetation, or any part of the natural habitat in which fish,animals,or wildlife may be found;or(B)a substance defined as a hazardous substance under 42 USC 9601 -9675(Comprehensive Environmental Response,Compensation,and Liability Act of 1980); "hazardous substance" does not include uncontaminated crude oil or uncontaminated refined oil (AS 46.09.900). identified wetlands are those areas that have been identified as wetlands by the U. S. Army Corps of Engineers under Section 404 of the Clean Water Act.4. Minimize means to reduce adverse impacts to the smallest amount,extent,duration,size,or degree reasonable in light of the environmental,social, or economic costs of further reduction. Plan of operations means a lease plan of operations under 11 AAC 83.158 and a unit plan of operations under 11 AAC 83.346. Practicable means feasible in light of overall project purposes after considering cost, existing technology, and logistics of compliance with the standard. Reasonable access means access using means generally available to subsistence users. Secondary containment means an impermeable diked area or portable impermeable containment structure capable of containing 110 percent of the volume of the largest independent container. Double walled tanks do not qualify as Secondary Containment unless an exception is granted for a particular tank. Temporary means no more than 12 months. B. Other Regulatory Requirements (Lessee Advisories) Lessees must comply with all applicable local, state, and federal codes, statutes, and regulations, as amended. Lessee Advisories alert lessees to additional restrictions that may be imposed at the permitting stage of a proposed project or activity where entities other than DO&G have regulatory, permitting,or management authority. 1. Alaska Department of Natural Resources, Division of Coastal and Ocean Management a. Pursuant to AS 46.40, projects are required to comply with all policies and enforceable standards of the Alaska Coastal Management Program, including the District Coastal Management Plans. 2. Alaska Department of Environmental Conservation a. Pursuant to AS 46.04.030, lessees are required to have an approved oil discharge prevention and contingency plan(C-Plan)before commencing operations.The plan must include a response action plan to describe how a spill response would occur, a prevention plan to describe the spill prevention measures taken at the facility, and supplemental information to provide background and verification information. b. Pursuant to state regulations administered by ADEC and the Clean Air Act administered by EPA, lessees are required to obtain air quality permits before construction and operation. The permits will include air quality monitoring, modeling, and emission control obligations. c. Unless authorized by an ADEC permit, surface discharge of reserve pit fluids and produced waters is prohibited. d. Unless authorized by National Pollutant Discharge Elimination System or state permits,disposal of wastewater into freshwater bodies is prohibited. 4 Wetlands means those areas that are inundated or saturated by surface or groundwater at a frequency and duration sufficient to support, and that under normal circumstances do support, a prevalence of vegetation typically adapted for life in saturated soil conditions. Wetlands generally include swamps, marshes, bogs, and similar areas (40 CFR Parts 122.2, 230.3,and 232.2). 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'slel!gey 6u!aeaa luelaodw!pue 6u!uMeds ys!}6u!ssoao Jo!paa!nbaa eq Aew saanlanals pepuno}wolloq-uou JO se6pue .!!! .pel!q!yoad eq Aew swew s pue S.184 110 seam aaleM uedo u! `sleoq 6u!pnloxe 'luewd!nbe}o uolleJedo ey1 !! .pepq!yoad eq Aew s>IuegJen!a}o uo!leaa;ly .0)83ay woo}peu!elgo eq Aew ewe eyl aeeu pue u!se!poq JeleM snowoapeue}0 uo!leool ell uo uo!lewao}u!o!}loads .sa!poq JeleM 6u!aeeq-qs!1 Ile u!ys!}}o a6essed lua!o!}}a pue aaa} ay;ensue of pue sa!poq JeleM snowoapeue paleu6!sep;oaload of>Iaew aaleM Op; Aaeu!pao ay;Moleq 0�83ay Aq pesodw! eq Aew Moleq pals!! saanseew eyl `salnlels e>Isely ey; }o 91 all!1 }o suo!s!noad ay;aapun •e awed pue qs!3 ;uewiedea eNsely g Common Name ESA Status Bowhead whale Endangered Spectacled eider Threatened Steller's eider(Alaska breeding population) Threatened Polar bear Threatened b. Lessees are advised of the need to comply with the Migratory Bird Treaty Act (MBTA; 16 USC 703) which is administered by the USFWS. Under the MBTA, it is illegal to"take" migratory birds,their eggs, feathers or nests. "Take" is defined (50 CFR 10.12)to include"pursuing, hunting, shooting, wounding, killing,trapping,capturing, or collecting."The MBTA does not distinguish between"intentional"and "unintentional"take. Migratory birds include songbirds, waterfowl, shorebirds, and raptors. In Alaska, all native birds except grouse and ptarmigan (which are protected by the State of Alaska)are protected under the MBTA. In order to ensure compliance with the MBTA, it is recommended that lessees survey the project area before construction, vegetation clearing, excavation, discharging fill or other activities which create disturbance, and confirm there are no active migratory bird nests. It is recommended lessees contact the USFWS for assistance and guidance on survey needs, and other compliance issues under the MBTA.While the USFWS can recommend methods (such as surveys and timing windows) to avoid unintentional take, responsibility for compliance with the MBTA rests with lessees. c. Lessees are advised that they must comply with the provisions of the Marine Mammal Protection Act of 1972, as amended(16 USC 1361-1407). USFWS shares authority for marine mammals with the NMFS. d. Peregrine falcon nesting sites are known to occur in the sale area. Lessees are advised that disturbing a peregrine falcon nest violates federal law. Lessees are required to comply with the federal resource recovery plan for the arctic peregrine falcon. e. Lessee are advised that the Magnuson-Stevens Fishery Conservation and Management Act requires identification of Essential Fish Habitat(EFH)for all species managed under a federal Fisheries Management Plan. Subsequent exploration and/or development activities associated with the lease sale may be subject to consultation under EFH. EFH information, consultation, guidance, and species life history information are available on the NMFS website at http://www.fakr.noaa.gov/habitat. 8. North Slope Borough a. Lessees are advised that the NSB Assembly has adopted a comprehensive plan and land management regulations under Title 29 of the Alaska Statutes (AS 29.40.020-040). The NSB regulations require borough approval for all proposed uses, development, and master plans. The former NSBCMP policies are included as part of the NSB zoning regulations (Title 19) and all NSB permit approvals will require the proposal to be substantially consistent with these policies. b. Lessees are advised that restricting access to and use of fish camps and other subsistence use areas defined in the NSB Traditional Land Use Inventory, may violate the former NSBCMP and NSBMC subsistence harvest protection and land use regulations. Lessees are advised to consult with the NSB Planning Department and local communities during planning of operations. c. Lessees are encouraged to bring one or more residents of communities in the area of operations into their planning process. Local communities have a unique understanding of their environment and community activities. Involving local community residents in the earliest stages of the planning process for oil and gas activities can be beneficial to the industry and to the community. Community representation on management teams developing plans of operation, oil spill contingency plans, and other permit applications can help communities understand permitting obligations and help industry to understand community values and expectations for oil and gas operations being conducted in and around their area. d. In order to protect species that are sensitive to noise or movement, horizontal and vertical buffers will be required, consistent with aircraft, vehicle, and vessel operations regulated by NSB Code f319.70.050(I)(1), which codifies former NSBCMP policy 2.4.4.(a). Lessees are encouraged to apply the following provisions governing aircraft operations in and near the sale area: i. From June 1 to August 31, aircraft overflights must avoid identified brant, white fronted goose,tundra swan, king eider, common eider, and yellow-billed loon nesting and brood rearing habitat, and from August 15 to Page 25 of 27 LZ}O 9Z a6ed •luewaa.]6y eouep!ony lo!I}uoa B°Jobe.] !!!M Aayl elms NI pas!npe Sey 8SN an `sa.]nseew uolle6iuw uo!loaloJd IsanJey °IemM pue uo!loaloJd IsanJey eouals!sgns eq of loafgns puelsl ssaa}o sew E u!yl!M sJaleM alms u!6ull!s Al!I!oe}lueuewied sl!wied JoToanp ayl}!•sJalBM alms u!sa!l!I!oe} luauewied}o 6ums eyl Jo}pw.]ed luewdolanep Jo 6u!uozei 8SN a Jo}6u!Aldde aJo}eq OM3y ayl yBM luewaaJ6y eouep!ony loll}uoa a olu!.]alue of eessal eq aJobej 'sa!luoylne sl!Japun 'Aew 8SN e B leyl pas!npe 8JB se88s81 •pal!q!yoJd eq AlaVg II!M puels! aMoH oluo A.]lue eoepns min pes!npe em saassag (-Age uos!JJeH}o ea.]e eyl u!mono seiuoloo flews!e.]anal:el!aa Jan!!_I mnd){!d>{I eqi u!s!Auo!oo.]aylo eq ) se els pal!un eq u! sa!uoloO 6u!lseu asoo6 Mous uMou) lueo!pu6!s OMl/quo }o auo eq Aew puelsl aMoH min sl.]oda.] ovjay 'Aa)l!eH edea se Je}se pJeMisea puelxe Aew asn leuo!se000 lap!aseaa}o°p!s see eq uo kJepunoq walsee ue yl!M'pue!s!Jadooa}}o g Alalew!xo.]dde 6u!puelxe A.]epunoq walsam e Aq pequoswnoJ!o eale eqi asn s.]°luny MOJJB8 :Jegoloo of .]egwaidas !! •spuelsl.]aims an pJeMeas 'puels! uewxel3 of Jana eulnloa ayl}o leuueya mayoeN eq }o pJeMylJou aug a woJ}6u!pu81xe eeie ue asn sJalegM Insb!nN •puelsl Japes }o see lu!od AeJydwnH of pue!s! 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'seee 6u!uuep Jeeq mod pue asn IMO1JaIBM puelsl uewxeld an •n !Jegweoaa-aunp`spuelsl 549111 pue'663 'alod 'ssOJ3 ayl •A! :Jegweoaa-AJenuep'ellaa Jan! { eii ioa an •n! :Jegweoaa-AJenuep'el!aa Jana 6u!uuea ayl -!! :puna JeeA`punos uossue}eis u!Limed Jepino8 eyl .! :epnlou!Al!n!Hsuas IBJnllno pue leo!6olo!q leioeds}o spouad awn pue seam pa!}!luep! •uo!lBJedo}o sueld 6u!dolenap uegM pa.]ap!suoo eq Isnw seam 6u!Mopo}eq •se!i!n!loe lsan.]ey eoue1slsgns of eouelaodw!J!ayl Jo}pue :soon-tom le.]nilno!seoJnosaJ leo!6olo!q Jeylo JO'says!}'slewwew aupew `spJ!q auuew }o suo!leJluaouoO rayl Jo} algenlen Apepedse 8.]e seam u!epeo leyl pes!npe am saassei •e •suonoulseJ ly6!I}JOAO eouapeoeid amel 1!!M Ala}es uewnH •n! .eeJe ayl u! puno}slew!ue esoyl}o Allsuap IeJeue6 eq }o ssaoXa u!slew!ue}O sJagwnu sueew uo!leJluaOuoo y •suo!leJluaouoo uexoNsnw pue noqueO woJ} `s6u!pue! pue s}}oa)lel 6u!pnloxe 'allw 4 }O aouels!p iBJale!a JO lea}009'i ueyl JeleeJ6 apnl!i!e ue u!elu!ew mous i}e.]One Ile 'eIgeo!loeJd lualxe eq of •n •al!w G}O aouels!p le.]alel e Jo'lea}009'I.}o apnl!lle ue Aq`spJ!geJoys pue`sueMs eJpunl'asaa6 JO}seeJe 6u!6els Del ayl'g Jegweldes 9. Alaska Department of Natural Resources, Division of Oil and Gas a. The State of Alaska is in the process of reviewing and evaluating information from the Deepwater Horizon investigations and the Alaska Risk Assessment reports, and is determining which of the information and recommendations are applicable to Alaska, which recommendations to implement, and the next steps for implementing them. As this process develops, new or modified mitigation measures, lessee advisories, or other statutory or regulatory requirements addressing issues such as safety, environmental safeguards, risk management, and reporting standards may be forthcoming. Page 27 of 27 Exhibit A ADL 392703 ........... :l: ::"T' :B: 13 Tract 328 T. 013N., R. 011E., Umiat Meridian, Alaska. Section 5, Protracted, All, 640.00 acres; Section 6, Protracted, All, 625.00 acres; Section 7, Unsurveyed, All tide and submerged land, 566.52 acres; Section 8, Unsurveyed, All tide and submerged land, 551.48 acres; T. 013N., R. 011E., Tract B, Umiat Meridian, Alaska. Section 7, Surveyed, Fractional, All, including U.S. Survey 8959, 61.48 acres; Section 8, Unsurveyed, All, 88.52 acres; This Tract(BS0328) contains 2,533.00 acres, more or less. According to the supplemental survey plat accepted by the United States Department of the Interior, Bureau of Land Management in Anchorage, AK on February 2, 1989. S Bettis, Patricia K (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Friday, May 01, 2015 11:20 AM To: Wallace, Chris D (DOA) Cc: Bettis, Patricia K (DOA) Subject: RE: MPB-24 RWO for Class 1 Disposal Attachments: Permit AK11005-B Milne Point Unit dated 9-19-14.pdf; Permit AK11005-B Milne Point Unit dated 9-19-14.pdf Chris, It is my understanding that the well will be permitted for injection under the existing or a modified version of the Class 1 Milne Point UIC permit(attached). The permit contains provision for up to two Class 1 injection wells at Milne Point. Thank You, Wyatt Rivard '40" 7 wrivard@hilcorp.com $ tl,„,,& 4i 9 a,„ 6 From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent: Friday, May 01, 2015 11:06 AM To: Wyatt Rivard Cc: Bettis, Patricia K (DOA) Subject: RE: MPB-24 RWO for Class 1 Disposal Wyatt, Thanks for the background. My first(and maybe only) question is what is the Class I permit the well will be permitted with EPA under and can you send us a copy? Thanks Chris Original message From: Wyatt Rivard <wrivard(,hilcorp.com> Date: 05/01/2015 10:53 AM (GMT-09:00) To: "Wallace, Chris D (DOA)" <chris.wallaceAalaska.gov> Subject: MPB-24 RWO for Class 1 Disposal Hello Chris, Chris Kanyer is currently out of the office and asked that I follow-up with you to provide some background information on the MPB-24 (PTD#1690090) RWO. The well was originally completed, plugged and suspended in 1996. The plan, starting next week, is to convert MPB-24 to a Class 1 disposal well supporting the Milne Point G&I facility. A bond long was never run on MPB-24 so one of the early steps will be to drill two cement plugs and then run a cement bond log to compare actual TOC with estimates. Based on this actual TOC, one of three predefined injection/confinement zones may be targeted and tubing/packer set. The EPA is currently scheduled to witness the bond log, packer set and MIT-IA portions of the workover. After the completion is run, the rig will move off of the well with the perforation to be completed later via Eline. Witnessed internal/external integrity testing and initial injection would occur later in the summer, most likely coinciding with the other Class 1 testing for MPB-50 and Northstar in late July. If you have any questions, please give me a call at 777-8547. Thanks, Wyatt Rivard ( Well Integrity Engineer 0: (907) 777-8547 j C: (509)670-8001 I wrivard@hilcorp.com 3800 Centerpoint[)rive,Suite .1.400 I Anchorage,AK 99503 2 ,ceosr UNITED STATES ENVIRONMENTAL PROTECTION AGENCY � >�TYo REGION 10 i 1200 Sixth Avenue, Suite 900 e Seattle Wa hinagn 98101-3140 �•�2 SEP July 41-PROI1'G OFFICE OF COMPLIANCE AND ENFORCEMENT Reply To: OCE-082 CERTIFIED MAIL -RETURN RECEIPT REQUESTED Ms. Katherine Fontaine Area Operations Manager North BP Exploration (Alaska) Inc. (BPXA) 900 East Benson Boulevard Anchorage, Alaska 99519-6612 Re: Issuance of Underground Injection Control (UIC) Permit No. AK1I005-B Milne Point Unit (MPU),North Slope, Alaska Dear Ms. Fontaine: The U. S. Environmental Protection Agency, Region 10, (EPA) is issuing an Underground Injection Control permit for BP Exploration (Alaska) Inc. (BPXA), Milne Point Unit, North Slope,Alaska. The enclosed document authorizes the facility to inject non-hazardous industrial waste utilizing up to two Class I injection wells at the Milne Point Unit into the Schrader Bluff(West Sak) and Ugnu(Prince Creek) Formations, at approximately 4080 feet true vertical depth (TVD) (9020' measured depth (MD) to 4293 feet TVD (11172 feet MD). EPA received no requests for a hearing. Comments on the draft permit during the public comment period were received. Enclosed is EPA's response to the comments received on the draft permit during the public comment period. This letter constitutes service of notice under 40 C.F.R. 124.19(a). The permit will become effective on. the date indicated in the permit unless the Environmental Appeals Board receives a timely appeal meeting the requirements of 40 C.F.R. 124.19. Information about the administrative appeal process may be obtained on-line at epa.gov/eab or by contacting the Clerk of the Environmental Appeals Board at (202)233-0122. Sincere y, Edward J1 owalski Director Enclosure cc w/enc: Chris Wallace, Alaska Oil and Gas Conservation Commission Marc Bentley, Alaska Department of Environmental Conservation Printed on Recycled Paper Response to Comments on the Draft UIC Permit for Milne Point Facility BP Exploration (Alaska) Inc. UIC Permit Number AK-1I005-B On August 13, 2014, EPA issued a public notice of the availability of a draft Class I Underground Injection Control (UIC) permit for BP Exploration(Alaska), Inc., (BPXA), Milne Point Facility to inject fluids into the subsurface under Milne Point Unit,North Slope, Alaska. A Public Notice was published in the Alaska Dispatch News on August 13, 2014, that opened a public comment period(August 13- September 12, 2014), offered a hearing upon request, and described the proposed draft permit. Documents for review were made available in EPA offices in Anchorage, Juneau, and Seattle and on the EPA Region 10 website. Response to Public Comments on the Draft UIC Permit EPA received comments on September 11, 2014, from Ms. Alison Cooke, BPXA, Anchorage, Alaska on the Draft UIC Permit. The comments and responses to the comments follow. Comment Number 1 Dear Mr. Cutler: By this letter, BP Exploration(Alaska) Inc., (BPXA) is providing comments to the Environmental Protection Agency on the draft Underground Injection Control (UIC) Permit No. AK1I005-B for the Milne Point facility. BPXA appreciates the work that has gone in to renewing this permit. 1. Fact sheet, Page 5, 2) Injection Zone Fracturing 2. Draft permit, Page 19, Part II, C.4. Injection Zone Draft permit, Page 20, Part II, C.5 (ii) Injection Zone Fracturing Please correct the typographical error that we found referenced in the above three locations in the Fact Sheet and Draft Permit. The depth at the base of the injection interval is 4923 feet TVD not 4293 feet. I transposed the numbers when I provided them to you previously and did not catch my error until now. 3. Draft Permit, Page 6, Part I, E.6. Proper Operation and Maintenance Draft permit, Page 21-22, Part II, C.B. Injection Fluid Limitation For clarification,please strike the phrase, "generated during remedial well workovers or well construction operations"in the sentence: "De-characterized waste generated during remedial well workovers of well construction operations may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. 148.1(d))." De-characterized waste from activities other than well maintenance and construction can be appropriately disposed in a Class I non-hazardous well. The final sentence in the above referenced two locations in the Draft Permit should read: "De-characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. 148.1(d))." 4. Draft permit, Page 22, Part II C.B. Injection Fluid Limitation Please correct the typographical error. The citation should be 40 C.F.R. 148.1(d) not 148.4(d). 5. Draft permit,page 21, Part II, C.7. Annulus Pressure The final sentence should read"It should be noted that the wellhead working pressure limit of 5000 psig should not be exceeded at any time." 6. Draft permit, Page 21, Part II, C.7. Annulus Pressure For accuracy,please change the word "volume"to "pressure"in the sentence, "Since the tubing-casing annulus volume will vary due to temperature changes, the high-low annulus pressure limits can be adjusted, ..." The final sentence should read: "Since the tubing-annulus pressure will vary due to temperature changes, the high-low annulus pressure limits can be adjusted." If you need any additional information concerning these comments,please contact me, at (907) 564- 4838 or Alison.Cooke@bp.com. Sincerely, Alison Cooke Compliance Advisor,UIC Response Number 1 Regarding your comments 1, 2 and 4, the typographical errors are noted and corrected. The depth at the base of the injection interval is 4923 feet TVD, not"4293." Also, the citation regarding de- characterized waste eligibility for appropriate disposal in a Class I well should be 40 C.F.R. 148.1(d)not 148.4(d). Thank you. Regarding your comment number 3, the phrase, "generated during remedial well workovers or well construction operations"for clarification is struck. EPA agrees, de-characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. 148.1(d))." Regarding your comment number 5, EPA agrees the addition of the phrase"5000 psig"to the reference of the well working pressure limit adds clarity. Regarding your comment number 6, EPA agrees with the word change from"volume"to "pressure." Therefore the sentence regarding annulus pressure should read"Since the tubing-casing annulus pressure will vary due to temperature changes,the high low pressure limits can be adjusted, ..." We thank Ms. Cooke for the comments and cooperation in the development of this permit. End response to comments. . , . Page 1 of 23 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-11005-B In compliance with provisions of the Safe Drinking Water Act(SDWA), as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency(EPA) under Title 40 of the Code of Federal Regulations, BP Exploration(Alaska)Inc. (BPXA) (Pennittee) is authorized to inject non-hazardous industrial waste utilizing up to two (2) Class I injection wells at the Milne Point Unit(MPU)located on the Alaskan North Slope(NS). Injection is authorized into the Schrader Bluff(West Sak) and Ugnu(Prince Creek)Formations, in accordance with Title 40 C.F.R. § 144.33 and the conditions set forth herein. The Milne Point oilfield located in the MPU near the Beaufort Sea about 250 miles north of the Arctic Circle and lies west of Prudhoe Bay, on the North Slope of Alaska approximately 25 miles west of Deadhorse, Alaska. The proposed disposal well(s) are in an area where there are no underground sources of drinking water(USDWs) and an aquifer exemption delineated by a cylinder along the well trajectory of the Class I injection well(s) from (below permafrost) 2000 feet true vertical depth (TVD)to 4270 feet TVD. The aquifer exemption was issued by EPA on September 29, 2004 for aquifers between approximately 2000 feet(base of the permafrost) and 4,270 feet true vertical depth subsea(TVDss) and was clarified to include the area delineated by a cylinder of1/4 mile radius along the well trajectories whose latitudes and longitudes (per NAD83) respectively at the well surface location are latitude 70.472809 and longitude-149.413148 for well MPB-50 and latitude 70.472928 and longitude-149.413239 for well MPU-xx. (Exact well locations are subject to change or correction.) Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended,(42 USC 6901) or radioactive wastes (other than naturally occurring radioactive material–NORM from pipe scale) are not authorized under this permit. All references to Title 40 of the Code of Federal Regulations are to regulations that are in effect on the date that this permit is issued. Figures and appendices are referenced to BPXA's Renewal Application for Milne Point Unit UIC Permit AK-11005-A dated April 30, 2014. This permit shall become effective on November 3, 2014, in accordance with 40 C.F.R. § 124.15. This permit and the authorization to inject shall expire at midnight,November 2, 2024,unless terminated. , / . Signed this /77.11 day of z...I' , 2014. ow" i ...1./ , — Joel ward J. Kow i, Director Office of Compliance and Enforcement U.S. Environmental Protection Agency Region 10 (OCE-184) 1200 Sixth Avenue Suite 900 Seattle, WA 98101 Page 2 of 23 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE 1 PART I GENERAL PERMIT CONDITIONS 4 EFFECT OF PERMIT 4 PERMIT ACTIONS 4 Modification, Reissuance, or Termination 4 Transfer of Permits 5 SEVERABILITY 5 CONFIDENTIALITY 5 GENERAL DUTIES AND REQUIREMENTS 5 Duty to Comply 5 Penalties for Violations of Permit Conditions 6 Duty to Reapply 6 Need to Halt or Reduce Activity Not a Defense 6 Duty to Mitigate 6 Proper Operation and Maintenance 6 Duty to Provide Information 6 Inspection and Entry 7 Records 7 Reporting Requirements 9 Anticipated Noncompliance 9 Twenty-Four Hour Reporting 9 Other Noncompliance 10 Reporting Corrections 10 Signatory Requirements 10 PLUGGING AND ABANDONMENT 11 Notice of Plugging and Abandonment 11 Plugging and Abandonment Report 11 Cessation Limitation 11 Cost Estimate for Plugging and Abandonment 12 FINANCIAL RESPONSIBILITY 12 PART II WELL SPECIFIC CONDITIONS 13 Page 3 of 23 CONSTRUCTION 13 Casing and Cementing 13 Tubing, Packer and Completion Details 13 New Wells in the Area of Review 14 CORRECTIVE ACTION 14 WELL OPERATION 14 Prior to Commencing Injection 14 During Injection 15 Mechanical Integrity 15 Injection Zone 18 Waivers to UIC Program Requirements 19 Injection Rate and Pressure 19 Annulus Pressure 19 Injection Fluid Limitation 20 MONITORING 20 Monitoring Requirements 20 Continuous Monitoring Devices 20 Monitoring Direct Waste Injection 20 Alarms and Operational Modifications 21 REPORTING REQUIREMENTS 21 Quarterly Reports 21 Report Certification 22 REPORTING FORMS 23 Page 4 of 23 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The Permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The Permittee shall not construct, operate, maintain, convert,plug, abandon, or conduct any other activity in a manner that allows the movement of any contaminant into USDWs, except as authorized by 40 CFR Part 146. The underground injection activity, otherwise authorized by this permit shall not allow the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 C.F.R. Part 142 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act(SDWA). Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other law governing protection of public health or the environment from imminent and substantial endangerment to human health or the environment. This permit may be modified, revoked and reissued, or terminated during its term for cause. Issuance of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating,handling, storage, or treatment facilities. This permit is based on the permit application submitted by the Permittee on April 30, 2014, and supplemental material related to the aquifer exemption ruling granted by EPA dated September 29, 2004. B. PERMIT ACTIONS 1. Modification, Reissuance, or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 C.F.R. §§ 144.39 and 144.40. In addition, the permit can undergo minor modifications for cause as specified in 40 C.F.R. § 144.41. The filing of a request for a permit modification,revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the Permittee does not stay the applicability or enforceability of any permit condition. Page 5 of 23. 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT(EPA Form 7520-7) and in accordance with 40 C.F.R. § 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SDWA. C. SEVERABILITY The provisions of this permit are severable, and if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby. D. CONFIDENTIALITY In accordance with 40 C.F.R. Part 2, any information submitted to EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 C.F.R. § 2.203 and on the application form or instructions, or, in the case of other submissions,by stamping the words "confidential" or "confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 C.F.R. Part 2 (Public Information). Claims of confidentiality for the following information will be denied: 1. The name and address of the Permittee. 2. Information that deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to Comply The Permittee shall comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action,permit termination, revocation and reissuance,modification, or for denial of a permit renewal application; except that the Permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 C.F.R. § 144.34. Page 6 of 23 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty value calculated on a per day basis of such violation. Any person who willfully or negligently violates permit conditions is subject to a fine calculated on a per day basis of the violation and/or being imprisoned. 3. Duty to Reapply If the Permittee wishes to continue an activity regulated by this permit after the expiration date of this permit,the Permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for a Permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to Mitigate The Permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The Permittee shall, at all times,properly operate and maintain all facilities and systems of treatment and control (and related appurtenances)which are installed or used by the Permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator • staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. De-characterized waste may be appropriately disposed in a Class I non-hazardous well [refer to 40 C.F.R. § 148.1(d)]. 7. Duty to Provide Information The Permittee shall provide to the Director, within a reasonable time, any information that the Director may request to determine whether cause exists for modifying, revoking and reissuing, terminating this permit, or to determine compliance with this permit. The Permittee shall also provide to the Director, upon request, copies of records required to Page 7 of 23 be kept by this permit. 8. Inspection and Entry The Permittee shall allow the Director, or an authorized EPA representative,upon the presentation of credentials and other documents as may be required by law to: a. Enter upon the Permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records that are kept under the conditions of this permit; c. Inspect at reasonable times any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any contaminants or parameters at any location. 9. Records a. The Permittee shall retain records and all monitoring information, including all calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement,report or application. These periods may be extended by request of the Director at any time. b. The Permittee shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests,the Permittee shall deliver the records to the Director. The Permittee shall continue to retain the records after the three-year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. This permit does not require retention of hard copies or original records. The record keeping requirements of the permit are met by retaining the records in electronic or original hard copy format. The original records are not required to be retained when electronic versions are retained. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; Page 8 of 23 (2) The name(s) of the individual(s)who performed the sampling or measurements; (3) The date(s) analyses were performed; (4) The name(s) of the individual(s)who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 C.F.R. § 136.3, in appendix III of 40 C.F.R. Part 261, or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including,but not limited to measurements of pressure, temperature,mechanical integrity, and chemical analyses shall be done in accordance with EPA's Quality Assurance Program Plan. f. As part of the COMPLETION REPORT,the Permittee must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. This permit covers two wells, including an active Class I well (MPB-50) that has been in operation since 2005 plus a second well (MPU-xx). An updated Waste Analysis Plan(WAP) was submitted as part of the April 30, 2014 Permit Renewal Application. The WAP from the permit application may be incorporated by reference to satisfy the WAP plan submittal requirements. g. The Permittee shall require a written manifest for each batch load of waste received for waste streams that are not hard piped and continuous. The manifest shall contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste Page 9 of 23 generator, a description of the monitoring performed and the results, a statement stating if the waste is exempt from regulation as hazardous waste as defined by 40 C.F.R. § 261.4, and any information on extraordinary occurrences. For waste streams that are hard-piped continuously from the source to the wellhead, the Permittee shall also provide for continuous,recorded measurement of the discharge rate and shall provide such sampling and testing as may be necessary to provide a description of the nature and composition of all injected fluids, and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR § 261.4. h. Dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit shall be noted on the gauge or meter. Earlier records shall be available through a computerized maintenance history database. 10. Reporting Requirements The Permittee shall give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected waste. 11. Anticipated Noncompliance The Permittee shall give advance notice to the Director of any significant planned changes in the permitted facility or activity that may result in noncompliance with permit requirements. 12. Twenty-Four Hour Reporting a. The Permittee shall report to the Director or an authorized EPA representative any noncompliance that may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the Permittee becomes aware of the circumstances. If EPA or the Permittee discovers that fluids have moved above the upper confining zone along a wellbore within the AOR,then injection shall cease until the fluid movement problem can be diagnosed and corrected. The following shall be included as information that must be reported orally within 24 hours: (1) Any monitoring or other information that indicates that any contaminant may cause an endangerment to an underground source of drinking water. (2) Any noncompliance with a permit condition or malfunction of the injection system. Page 10 of 23 b. A written submission shall also be provided within five(5) days of the time the Permittee becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause,the period of noncompliance, including exact date and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue, and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. 13. Other Noncompliance The Permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted. The reports shall contain the information listed in Permit Condition Part I E.12.b. 14. Reporting Corrections When the Permittee becomes aware that he/she failed to submit any relevant facts in the permit application or submitted incorrect information in a permit application or in any report to the Director, the Permittee shall promptly submit such facts or information. 15. Signatory Requirements a. All permit applications,reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level of vice-president, or by a duly authorized representative of that person. A person is a duly authorized representative only if: (1) The authorization is made in writing by.a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager,operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization is submitted to the Director. b. If an authorization under paragraph 15.a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph 15.a. of this section must be submitted to the Director prior to or together with any reports, information, or applications to be signed by an authorized representative. Page 11 of 23 c. Any person signing a document under paragraph 15.a. of this section shall make the - following certification: "I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F. PLUGGING AND ABANDONMENT 1. Notice of Plugging and Abandonment The Permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2. Plugging and Abandonment Report The Permittee shall plug and abandon the well as provided in the Final Well Abandonment(Closure)portion(Section 6.5) of the April 30, 2014, Permit Renewal Application for Milne Point UIC Permit AK1I005-A(Permit Renewal Application) submitted by the Permittee, which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the Permittee shall submit a report to the Director in accordance with 40 C.F.R. § 144.51(p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the Permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the Permittee shall plug and abandon the well in accordance with the plan unless he/she: a. Provides notice to the Director; b. Demonstrates that the well will be used in the future; or c. Describes actions or procedures, satisfactory to the Director that the Permittee will take to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the technical requirements applicable to active injection wells unless waived by the Director. Page 12 of 23 4. Cost Estimate for Plugging and Abandonment a. The Permittee estimates the 2014 cost of plugging and abandonment of the permitted Class I well(s)to be approximately$ 300,000/well. Please refer to Section 6.5 and Exhibits 6-3 and 6-4 of the April 30, 2014 Permit Renewal Application. b. The Permittee must submit financial assurance and a revised estimate prior to April of each year. The estimate shall be made in accord with 40 C.F.R. § 144.62. c. The Permittee must keep at the facility or at the Permittee central files in Anchorage during the operating life of the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes, the documentation submitted under 40 C.F.R. § 144.63(f) shall be amended as well to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. e. The Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. G. FINANCIAL RESPONSIBILITY The Permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close,plug, and abandon the underground injection well. If the financial test and corporate guarantee provided under 40 C.F.R. § 144.63(f) should change, the Permittee shall immediately notify the Director. The Permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. Consistent with 40 C.F.R.§144.63 and regarding incapacity of owners or operators, guarantors, or financial institutions, the Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy),U.S. Code,naming the owner or operator as debtor,within 10 business days after the commencement of the proceeding. Furthermore, an owner or operator must notify the Regional Administrator by certified mail of the commencement of a voluntary or involuntary proceeding under title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor,within 10 business days after the commencement of the proceeding. A guarantor of a corporate guarantee as specified in §144.63(f)must make such a notification if he is named as debtor, as required under the terms of the guarantee(§144.70(f)). Page 13 of 23 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing and Cementing of Existing Sidetrack and/or Replacement Wells The Permittee shall case and cement the well(s) to prevent the movement of fluids into or between underground sources of drinking water other than the authorized injection interval (see II.C.4,below). Casing and cement shall be installed in accordance with a casing and cement program approved by the Director and in accordance with EPA Class I well construction practices (40 C.F.R. § 146.12) and the State of Alaska/AOGCC Regulations (20 AAC § 25.412 and 20 AAC § 25.252). If primary cement returns to surface are not observed for the(20 inch or other) surface casing cementing procedure,the Director or authorized EPA representative is to be notified as to the nature of the augmented testing proposed to ensure the integrity of the cement bond and adequacy of any Top Job procedure. The Cement Bond/Ultrasonic Imaging(USIT or other) logs and pressure tests (leak off test and/or formation integrity test) will be run for both the(20 inch or other) surface and (9 5/8 inch or other) injection casings to confirm zonal isolation and verify casing integrity. The Permittee shall provide not less than fourteen (14) days advance notice to the Director or authorized EPA representative for all cementing operations. Should a change(s)be required to the design casing and cementing program (due to unanticipated conditions), the Director or authorized EPA representative shall be notified as to the nature of the change(s), so that approval is obtained from the Director or authorized EPA representative enabling the well to be drilled and completed in a safe and successful manner. The casing, cementing and well construction data will be in compliance with the procedures outlined in Well Construction portion(Section 6), and the well schematics (Exhibits 6-1, 6-2 and 6-3) of the April 30, 2014 Permit Renewal Application. 2. Tubing, Packer and Completion Details of Existing Sidetrack and/or Replacement Wells The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with the procedures in the permit application. The current tubing and packer locations for well MPB-50 is approved. In the event that a packer needs to be set or re-set at a revised depth at a later date, and the Permittee will perform a mechanical integrity test prior to resuming injection, submit the necessary data and obtain authorization from EPA prior to resuming injection. The packer will be set no more than 100 feet MD from the top of the injection zone. Page 14 of 23 3. New Wells in the Area of Review EPA has set a quarter mile radius as the Area of Review(AOR) for this Class I UIC permit application.New Class I permitted UIC wells shall be installed in accordance with a casing and cement program approved by the Director and in accordance with EPA Class I well construction practices (40 C.F.R. § 146.12) and will also follow the State of Alaska/AOGCC Regulations (20 AAC 25.412 and 20 AAC 25.252). New wells within the AOR shall be constructed in accordance with the Alaska Oil and Gas Conservation Commission Regulations Title 20 Chapter 25. If in the future, any development or service wells are drilled that penetrate the injection intervals within the area of review, these wells shall have casing cemented to the formation throughout the entire section from 200 feet TVD below the proposed injection zone to 200 feet TVD above the injection zone as identified in the April 30,2014 Permit Renewal Application. B. CORRECTIVE ACTION The applicant has identified no wells in the Area of Review(AOR) which require corrective action in order to prevent fluids from moving above the confining zone. If the applicant later discovers that a well or wells within the AOR require(s) corrective action to prevent fluid movement, then the applicant shall inform the EPA upon such discovery and provide a corrective action plan for EPA review and approval. C. WELL OPERATION 1. The existing well (MPB-50)has fulfilled requirements of Part II C.1. Prior to Commencing Injection of New, Existing Sidetrack and/or Replacement Wells Injection operations pursuant to this permit may not commence until: a. Construction is complete and the Permittee has submitted two copies of COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-9), see APPENDIX A; and (1) The Director or authorized EPA representative has inspected or otherwise reviewed the new, existing, sidetrack or replacement injection well(s) and finds it is in compliance with the conditions of the permit; or (2) The Permittee has not received notice from the Director or authorized EPA representative of intent to inspect or otherwise review the new, sidetrack or replacement injection well(s)within thirteen(13) days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the Permittee may commence injection. • Page 15 of 23 b. The Permittee demonstrates that the well has mechanical integrity as described in Part II.C.3. Mechanical Integrity below and the Permittee has received notice from the Director or authorized EPA representative that such a demonstration is satisfactory. The Permittee shall notify EPA at least two weeks prior to conducting this initial test so that an authorized EPA representative may be present.Note: Since well MPB-50 has been on injection since 2005 and has successfully demonstrated mechanical integrity on an annual basis, the requirements of C.1.a and C.1.b. from above have been met. However, the requirements under Part II.C.3.—Mechanical Integrity remain in force for well MPB-50; and c. The Permittee has conducted a step-rate injection test(SRT) and submitted a preliminary report to EPA that summarizes the results. A SRT was conducted on well MPB-50 and the results were submitted to the EPA. Therefore, the Permittee is not required to conduct another SRT prior to resumption of Class I injection activities upon permit renewal. 2. During Injection During injection, the well injection pressure, tubing-casing(inner) annulus pressure, injection rate, will be monitored on a continuous basis. Out-of-limit alarms and shut-off systems will be installed and the injection facility plant shall be monitored by trained and qualified operators during injection. Visual and automatic monitoring of the tubing- casing(inner annulus) and tubing pressures will occur routinely with pre-set, out-of- limit alarms to inform supervisory personnel. The wellhead, controls, and monitoring instrumentation will be enclosed in an insulated structure. 3. Mechanical Integrity a. Standards The injection well(s)must have and maintain mechanical integrity pursuant to 40 C.F.R. § 146.8. b. Prohibition without Demonstration of Mechanical Integrity Injection operations are prohibited after the effective date of this permit unless the Permittee has conducted the following tests and submitted the results to the Director: 1) In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge(psig) for not less than thirty minutes. Page 16 of 23 Pressure shall show a stabilizing tendency. That is,the pressure may not decline more than 10 percent during the 30-minute test period and shall experience less than one-third of its total loss in the second(last)half of the 30-minute test period. If the total loss exceeds 10 percent or if the loss during the second 15 minute period is equal to or greater than one-half the loss during the first 15 minutes, the Permittee may extend the test period for an additional 30 minutes to demonstrate stabilization. However,the MIT meets criteria at the completion of the first 30 minute test if the total pressure loss in the 30 minute period is 2% or less and the pressure loss in the first 15 minutes (first time period)is more than the pressure in the second 15 minutes (second time period). Since the MPB-50 well has been on injection since 2005 and has successfully demonstrated its mechanical integrity(both internal and external) on an annual basis (with the tests being witnessed by EPA representatives), the well is approved to continue injection upon approval of this permit renewal. After the effective start date of this permit, the SAPT will be required annually until expiration of the ten (10)year permit period. This internal mechanical integrity test(standard annulus pressure test- SAPT)will be required annually if the well is active and once every two (2)years if the well is inactive. The internal mechanical integrity test due dates may be extended up to three(3)months to accommodate constraints resulting from drilling, operational or other logistics related to operating in the Arctic North Slope environment. At the discretion of the Director, and depending on the results of the internal annulus mechanical integrity test data, the frequency for demonstrating internal mechanical integrity(no leaks in the tubing-casing annulus or in the tubing-packer assembly)may be revised(either increase or decrease in frequency) as specified and approved by the Director or authorized EPA representative. (2) To detect movement of fluids in vertical channels adjacent to the well bore and to determine that the confining zone is not fractured, an approved fluid movement test shall be conducted at an injection pressure at least equal to the average continuous injection pressure observed in the previous six months. Approved fluid movement tests include,but are not limited to tracer surveys, temperature logs, noise logs, oxygen activation/water flow logs (WFL), borax pulse neutron logs(PNL), or other equivalent logs. Fluid movement test procedures not previously used to satisfy this requirement must be submitted 30 days in advance and are subject to prior approval by the Director or authorized EPA representative. Copies of all logs shall be accompanied by a descriptive and interpretive report. Fluid movement/confinement logs will be run initially upon completion of a new, existing sidetrack and/or replacement well and prior to initiation of injection at start-up. After acquiring this baseline data,the fluid movement/ confinement logs will be required every three(3)years while the well is Page 17 of 23 active until expiration of the ten(10)year permit period. The test due dates may be extended up to three(3)months to accommodate constraints related to operating in the Arctic North Slope environment. At the discretion of the Director, and depending on the results of the baseline data, the frequency for demonstrating external mechanical integrity(no flow behind pipe and isolation above injection interval) and utilizing alternative diagnostic techniques, may be revised (either increase or decrease in frequency) as specified and approved by the Director or authorized EPA representative. Note: The past well MPB-50 fluid movement logs completed in 2014 are recognized to fulfill this three (3) year requirement. (3) Internal tubing inspection logs (pipe analysis logs, caliper logs, or other equivalent logs) shall be run once every three (3)years while the well is active, or at the Director or authorized EPA representative's discretion, to monitor condition, thickness and integrity of the downhole tubing. A three month grace period is granted to the test due dates. Any exposed section of the injection casing will have to be logged during any scheduled workover for tubing change-out etc. Copies of the logs shall be accompanied by a descriptive and interpretive report. Note: This is a new requirement. The past well MPB-50 internal tubing inspection logs completed in 2014 are recognized to fulfill this three(3)year requirement. c. Terms and Reporting (1) Two (2) copies of the log(s) and two (2) copies of a descriptive and interpretive report of the mechanical integrity tests identified in 3.b (2) and 3.b (3) shall be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in 3.b. (1) any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The Permittee shall report the results of such tests within 45 days of completion of the tests. (3) After the initial mechanical integrity demonstration, the Permittee shall notify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations. (4) The Director will notify the Permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this 13-day review period. If the Director does not respond within 13 days, injection may continue. Page 18 of 23 (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation,the Permittee shall halt operation immediately and shall not resume operation until the Director or authorized EPA representative gives approval to resume injection. (6) The Director may,by written notice,require the Permittee to demonstrate mechanical integrity at any time. 4. Injection Zone Injection shall be limited to the Schrader Bluff(also referred to as the West Sak) and the Ugnu(also referred to as the Prince Creek) Formations. The top of the injection interval will be at the TUZC stratigraphic marker(within the Ugnu Formation)with the base of the injection interval defined by the base of the Schrader Bluff Formation at the SBA5 marker(see Exhibits 3-2 -Milne Point Well B-02 Type Log and Exhibit 3-3 -Milne Point Area Cross Section Map in the 2004 original permit application). The top of the injection interval is currently at 4080' TVD (9020' MD) and the base of the injection interval is at 4923' TVD (11172' MD)in the MPB-50 reference well location. 5. Waivers to UIC Program Requirements As a result of the subsurface aquifer conditions and the aquifer exemption for Class I injection granted by EPA on September 29, 2004,there are no underground sources of drinking water below the permafrost in the MPU area of the Class I injection wells. Furthermore on July 2. 1987, EPA concurred with Alaska Oil and Gas Conservation Commission on the decision made to exempt aquifers beneath MPU for Class II injection activities, as recorded in AOGCC Area Exemption Order(AEO) two (2). EPA is granting the following waivers of UIC regulatory program requirements as listed below: (i) Compatibility of Formation and Injectate [40 C.F.R. §§ 146.12 (e) and 146.14 (a) (8)]: Based upon the applicability of past injection studies,petrophysical logging data, existing rock and fluid samples plus successful injection practices into the same formation for the initial permit period and similar formations on the North Slope of Alaska, EPA is waiving the above two requirements for any additional sampling and characterization of formation fluids and injection rock matrix in order to determine whether or not they are compatible with the proposed injectate. (ii) Injection Zone Fracturing, Ambient Monitoring and Pressure Buildup [40 C.F.R. § 146.13 (a) (1), and (d) (1) and(2)]: Based on log surveillance results over the initial permit period that consistently verify no significant upward movement of injected fluids in the MPB-50 well, continuity of geologic formations and that transmission through faulting is not Page 19 of 23 likely to transmit fluid above the confining zone, and there are no improperly sealed, completed, or abandoned wellbores in the area of review, EPA is waiving the above three requirements of an ambient monitoring of saline aquifers above the confining zone and a monitoring program including a pressure buildup of the injection zone annually. Also,based on the above, EPA is waiving the prohibition against fracturing the injection interval, and would instead allow fracturing to a minor extent at the injection well confined to the injection zone so long as new fractures are not initiated nor existing ones propagated within the upper and lower confining zone. However, in no case shall injection pressure initiate fractures in the confining intervals above and below the injection zone. Authorized injection in the wells will be limited to the permitted injection zone injection intervals located between 4080' TVD (9020' MD) and 4923' TVD (11172' MD). However, external mechanical integrity demonstrations are required. [See Part II C.3.b (2)]. 6. Injection Rate and Pressure Injection pressures shall not initiate new fractures or propagate existing fractures in the upper confining zone as that stratigraphic interval is described in the Milne Point Unit Well B-02 Type Log, Exhibit 3-2 of the permit application. Neither shall the maximum injection pressure,measured at the wellhead, exceed 3000 pounds per square inch(psig), except as follows. In the event of a plant shut-down or outage, there may be instances where injection pressures exceed 3000 psi (unrelated to fluid injection activities). In such instances, the Permittee shall notify the Director or his designee by telephone or electronic mail within twenty four(24)hours of the initial exceedance of the 3000 psig limitation and shall submit a written incident report not later than ten(10) days thereafter. It should be noted that the wellhead working pressure limit of 5000 psig should not be exceeded at any time. Besides alarms and automatic shutdown controls, the wellhead assembly will include a surface safety valve to provide additional security. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non-freezing solution. To accommodate swings in wellbore temperatures and tubing thermal expansion, a positive surface pressure up to 1500 psig is authorized for the inner annulus (tubing x long string injection casing). Since the tubing-casing annulus pressure will vary due to temperature changes, the high-low annulus pressure limits can be adjusted, if necessary and upon approval by the Director or authorized EPA representative, (to include both the summer and winter ambient temperature swings). Page 20 of 23 Note: The authorization of up to 1500 psi on the inner annulus is to enable shut-down and alarm systems to be set at appropriate pressure limits, so as not to shut-down the facility from unintended causes not related to direct injection activities, and is not intended to allow the Permittee to continue to maintain the well on injection, in the event of a loss of mechanical integrity or when there is pressure build-up either in the tubing by inner annulus or between the injection casing and surface casing(between the inner annulus by outer annulus),resulting in a potential sustained casing pressure scenario. In the event of a loss of mechanical integrity,then the Permittee has to meet the requirements as outlined in Part II.C.3.c.5 of this permit. 8. Injection Fluid Limitation This permit only authorizes the injection of those fluids identified in the permit documentation. In the event that third party wastes are accepted,the third party must certify that fluids for injection are not hazardous waste or radioactive wastes. Fluids generated from Class I injection well construction and well workover, and fluids generated from the operation and maintenance of Class I injection wells and associated injection well piping, may be disposed in a Class I non-hazardous injection well. De- characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. § 148.1(d)). NOTE: Neither hazardous waste as defined in 40 C.F.R. Part 261 nor radioactive wastes other than naturally occurring radioactive material (NORM) from pipe scale shall be injected for disposal. D. MONITORING 1. Monitoring Requirements Samples and measurements collected for the purpose of monitoring shall be representative of the monitored activity. 2. Continuous Monitoring Devices Continuous monitoring devices shall be installed,maintained, and used to monitor injection pressure and rate for those streams that are hard-piped and continuous, and to monitor the pressure of non-freezing solution in the annulus between the tubing and the long string casing. Calculated flow data are not acceptable except as a back-up system if the primary continuous injection rate device malfunctions. 3. Monitoring Direct Waste Injection Page 21 of 23 Direct waste injection pumping operations at the well site shall be continuously manned and visually monitored. During these pumping operations, a chronological record of the time of day, a description of the waste pumped, injection rate and pressure, and well annulus pressure observations shall be maintained. The person in charge of the pumping operations must be identified on the pumping record. 4. Alarms and Operational Modifications a. The Permittee shall install, continuously operate, and maintain alarms to detect excess injection pressures and significant changes in annular fluid pressure.. These alarms must be of sufficient placement and urgency to alert operators in the control room. The Permittee shall install and maintain an emergency shutdown system to respond to losses of internal mechanical integrity as evidenced by deviations in the annular fluid pressures. b. Plans and specifications for the alarms shall be submitted to the Director or authorized EPA representative prior to the initiation of injection. Since well MPB- 50 is an existing Class I well, and has been on injection since 2005, and the plans and specifications were submitted in the Completion Report, the monitoring and alarm systems in place for the existing well MPB-50 is hereby approved as meeting the requirements of this section. E. REPORTING REQUIREMENTS 1. Quarterly Reports The Permittee shall submit quarterly reports to the Director containing the following information: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Graphical plots of continuous injection pressure and rate monitoring. c. Daily monitoring data in an electronic format. d. Physical, chemical, and other relevant characteristics of the injected fluid. e. Any well workover or other significant maintenance of downhole or injection- related surface components. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice" tests. Page 22 of 23 g. Any other tests required by the Director. 2. Report Certification All reporting and notification required by this permit shall be signed and certified in accordance with Part I.E.15.; electronically stored and maintained at the permittee's facility, or company headquarters; electronically submitted to an electronic(email) address provided by the Director or authorized EPA Representative; and upon request by the Director or authorized EPA representative, submitted as a hard copy to the following address: UIC Manager, Ground Water Unit(OCE-082) U.S. Environmental Protection Agency Region 10 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Page 23 of 23 APPENDIX A REPORTING FORMS Enclosed are EPA Forms: 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 7520-9 COMPLETION FORM FOR INJECTION WELLS OMB No.2040-0042 Approval Expires 11/30/2014 United States Environmental Protection Agency 4-CEPA Washington,DC 20460 Application To Transfer Permit Name and Address of Existing Permittee Name and Address of Surface Owner Locate Well and Outline Unit on State County Permit Number Section Plat-640 Acres Surface Location Description I��1 I II I I II II t 1 1114 of 1/4 of, j114 of I 41/4 of Section Township Range —-4-—I- — — —I—-I-— Locate well In two directions from nearest lines of quarter section and drilling unit I I I I I I —771-7— —7—E-7— Surface —---f'—I—4— — I — 4_ LocatIonl I ft.frm(NIS) Llne of quarter section I I I I I I and I In.from(E/W)=Line of quarter section. I I I I I I E Well Activity Well Status Type of Permit — — — — 'Class I L j Individual II I I I I Operating _ — _r _ Class II Modification/Conversion LI Area I Brine Disposal Proposed Number of Wells — — — — — — Enhanced Recovery I I I I I I Hydrocarbon Storage S Class III I I Other Lease Number Well Number Name(s)and Address(es)of New Owner(s) Name and Address of New Operator Attach to this application a written agreement between the existing and new permittee containing a specific date for transfer of permit responsibility,coverage,and liability between them. The new permittee must show evidence of financial responsibility by the submission of a surety bond,or other adequate assurance,such as financial statements or other materials acceptable to the Director. Certification I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true,accurate,and complete.I am aware that there are significant penalties for submitting false information,including the possibility of fine and imprisonment (Ref.40 CFR 144.32) Name and Official Title (Please type or print) Signature Date Signed EPA Form 7520.7(Rev. 12.11) PAPERWORK REDUCTION ACT The public reporting and record keeping burden forthis collection ofinformation is estimated to average 5 hours per response. Burden means the total time, effort, or financial resource expendedby persons to generate,maintain, retain,or disclose or provide information to or for a FederalAgency.This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to the collection ofnformation;search data sources;complete and review the collection of information;and,transmitor otherwisedisclose the information.An agency may not conduct or sponsor,and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Send comments on the Agency's need for this information,the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division,U.S.Environmental Protection Agency(2822), 1200 Pennsylvania Ave., NW,Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send theompleted forms to this address. Well Class and Type Code Class I Wells used to inject waste below the deepest underground source of drinking water. Type"I" Nonhazardous industrial disposal well "M" Nonhazardous municipal disposal well "W" Hazardous waste disposal well injecting below USDWs Other Class I wells(not included in Type"I,""M,"or"W') Class II Oil and gas production and storage related injection wells. Type"D" Produced fluid disposal well "R" Enhanced recovery well "H" Hydrocarbon storage well(excluding natural gas) Other Class II wells(not included in Type"D,""R,"or"H") Class Ill Special process injection wells. Type"G" Solution mining well Sulfur mining well by Frasch process "U" Uranium mining well Other Class Ill wells(not included in Type"G,""S,"or"U") Other Classes Wells not included in classes above. Class V wells which may be permitted under§ 144.12 Wells not currently classified as Class I, II, Ill, or V EPA Form 7520-7(12-11)Reverse OMB No.2040-0042 Approval Expires 11130/2014 United States Environmental Protection Agency v.EPA Washington,DC 20460 Injection Well Monitoring Report Year J Month Month Month Injection Pressure(PSI) I I I 1. Minimum 2. Average 3. Maximum Injection Rate(Gal/Min) 1. Minimum 2. Average 3. Maximum j T Annular Pressure(PSI) W 1 1. Minimum 2. Average 3. Maximum Injection Volume(Gal) W j 1. Monthly Total 2. Yearly Cumulative I Temperature(F°) 1. Minimum L_ 2. Average 3. Maximum L pH L I 1. Minimum 2. Average 3. Maximum l 1 Other Name and Address of Permittee Permit Number Name and Official Title (Please type or print) Signature Date Signed EPA Form 7520-8(Rev. 12-11) Paperwork Reduction Act The public reporting and record keeping burden for this collection of information is estimated to average 25 hours per quarter for operators of Class I hazardous wells, 16 hours per quarter for operators of Class I non- hazardous wells, and 30 hours per quarter for operators of Class III wells. Burden means the total time, effort, or financial resource expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal Agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to the collection of information; search data sources; complete and review the collection of information; and, transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Send comments on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division, U.S. Environmental Protection Agency(2822), 1200 Pennsylvania Ave., NW., Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send the completed forms to this address. EPA Form 7520-8 Reverse OMB No.2040-0042 Approval Expires 11/30/2014 United States Environmental Protection Agency v,EPA Washington,DC 20460 Completion Form For Injection Wells Administrative Information 1.Permittee Address (Permanent Mailing Address)(Street,City,and Z/P Code) 2.Operator Address (Street,City,State and ZIP Code) 3.Facility Name Telephone Number Address (Street,City,State and ZIP Code) 4.Surface Location Description of Injection Wells) State County Surface Location Description 1/4 of j 1/4 of ri/4 of i 14 of Section I Townshipl I Range Locate well in two directions from nearest lines of quarter section and drilling unit Surface Location_ ft.frm `Line of quarter section and Lj ft.from(E/W)LiLine of quarter section. Well Activity Well Status Type of Permit �[1 Class 1Operating Individual Class 11 I I Modification/Conversion Area:Number of Wells Brine Disposal 7-1 proposed IEnhanced Recovery Hydrocarbon Storage Ej Class III Other Lease Number Well Number Submit with this Completion Form the attachments listed in Attachments for Completion Form. Certification I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true,accurate,and complete.am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment (Ref.40 CFR 144.32) Name and Official Title (Please type or print) Signature Date Signed EPA Form 7520.9(Rev. 12.11) PAPERWORK REDUCTION ACT The public reporting and record keeping burden for this collection of information is estimated to average 49 hours per response for a Class I hazardous facility, and 47 hours per response for a Class I non-hazardous facility. Burden means the total time, effort, or financial resource expended by persons to generate,maintain,retain,or disclose or provide information to or for a Federal Agency.This includesthe time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements;train personnel to be able to respond to the collection of information;search data sources; complete and review the collection of information;and, transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to,a collection of information unless it displays a currently valid OMB control number.Send comments on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden,including the use of automated collection techniques to Director,Collection Strategies Division,U.S.Environmental Protection Agency (2822), 1200 Pennsylvania Ave., NW,Washington,D.C.20460.Include the OMB control number in any correspondence. Do not send the completed forms to this address. Attachments to be submitted with the Completion report: I.Geologic Information 4. Provide data on centralizers to include number,type and depth. 1.Lithology and Stratigraphy 5.Provide data on bottom hole completions. A. Provide a geologic description of the rock units pene- trated by name,age,depth,thickness,and lithology of 6. Provide data on well stimulation used. each rock unit penetrated. III.Description of Surface Equipment B.Provide a description of the injection unit. 1. Provide data and a sketch of holding tanks,flow lines, (1)Name filters,and injection pump. (2)Depth(drilled) (3)Thickness IV.Monitoring Systems (4)Formation fluid pressure (5)Age of unit 1. Provide data on recording and nonrecording injection (6)Porosity(avg.) pressure gauges,casing-tubing annulus pressure (7)Permeability gauges, injection rate meters,temperature meters,and (8)Bottom hole temperature other meters or gauges. (9)Lithology (10)Bottom hold pressure 2.Provide data on constructed monitor wells such as (11)Fracture pressure location,depth,casing diameter, method of cementing, etc. C.Provide chemical characteristics of formation fluid (attach chemical analysis). V.Logging and Testing Results D. Provide a description of freshwater aquifers. Provide a descriptive report interpreting the results of geophysical logs and other tests. Include a description (1)Depth to base of fresh water(less than 10,000 mg/I and data on deviation checks run during drilling. TDS). (2)Provide a geologic description of aquifer units with VI.Provide an as-built diagrammatic sketch of the injec- name,age,depth,thickness,lithology,and average total tion well(s)showing casing,cement,tubing,packer,etc., dissolved solids. with proper setting depths.The sketch should include well head and gauges. II.Well Design and Construction VII.Provide data demonstrating mechanical integrity 1. Provide data on surface,intermediate,and long string pursuant to 40 CFR 146.08. casing and tubing. Data must include material,size, weight,grade,and depth set. VIII.Report on the compatibility of injected wastes with fluids and minerals in both the injection zone and the 2. Provide data on the well cement,such as type/class, confining zone. additives,amount,and method of emplacement. IX.Report the status of corrective action on defective 3.Provide packer data on the packer(if used)such as wells in the area of review. type,name and model,setting depth,and type of annular fluid used. X.Include the anticipated maximum pressure and flow rate at which injection will operate. EPA Form 7520-9 Reverse -1 J��tEosr UNITED STATES ENVIRONMENTAL PROTECTION AGENCY "T�s'L) REGION 10 D2W 1200 Sixth Avenue, Suite 900 i Seattle,_Wash gton 98101-3140 it..• G.�\� 1✓3 I J _ 'I' "IL PROT� OFFICE OF COMPLIANCE AND ENFORCEMENT Reply To: OCE-082 CERTIFIED MAIL - RETURN RECEIPT REQUESTED Ms. Katherine Fontaine Area Operations Manager North BP Exploration (Alaska) Inc. (BPXA) 900 East Benson Boulevard Anchorage, Alaska 99519-6612 Re: Issuance of Underground Injection Control (UIC) Permit No. AK1I005-B Milne Point Unit (MPU), North Slope, Alaska Dear Ms. Fontaine: The U. S. Environmental Protection Agency, Region 10, (EPA) is issuing an Underground Injection Control permit for BP Exploration (Alaska) Inc. (BPXA), Milne Point Unit, North Slope, Alaska. The enclosed document authorizes the facility to inject non-hazardous industrial waste utilizing up to two Class I injection wells at the Milne Point Unit into the Schrader Bluff(West Sak) and Ugnu (Prince Creek) Formations, at approximately 4030 feet true vertical depth (TVD) (9020' measured depth (MD) to 4293 feet TVD (11172 feet MD). EPA received no requests for a hearing. Comments on the draft permit during the public comment period were received. Enclosed is EPA's response to the comments received on the draft permit during the public comment period. This letter constitutes service of notice under 40 C.F.R. 124.19(a). The permit will become effective on the date indicated in the permit unless the Environmental Appeals Board receives a timely appeal meeting the requirements of 40 C.F.R. 124.19. Information about the administrative appeal process may be obtained on-line at epa.gov/eab or by contacting the Clerk of the Environmental Appeals Board at (202) 233-0122. Sincere y, "of Edward J owalski Director Enclosure cc w/enc: Chris Wallace, Alaska Oil and Gas Conservation Commission Marc Bentley, Alaska Department of Environmental Conservation Printed on Recycled Paper • • Response to Comments on the Draft UIC Permit for Milne Point Facility BP Exploration (Alaska) Inc. UIC Permit Number AK-1I005-B On August 13, 2014, EPA issued a public notice of the availability of a draft Class I Underground Injection Control (UIC) permit for BP Exploration(Alaska), Inc., (BPXA), Milne Point Facility to inject fluids into the subsurface under Milne Point Unit,North Slope, Alaska. A Public Notice was published in the Alaska Dispatch News on August 13, 2014, that opened a public comment period(August 13- September 12, 2014), offered a hearing upon request, and described the proposed draft permit. Documents for review were made available in EPA offices in Anchorage, Juneau, and Seattle and on the EPA Region 10 website. Response to Public Comments on the Draft UIC Permit EPA received comments on September 11, 2014, from Ms. Alison Cooke, BPXA, Anchorage,Alaska on the Draft UIC Permit. The comments and responses to the comments follow. Comment Number 1 Dear Mr. Cutler: By this letter, BP Exploration(Alaska) Inc., (BPXA)is providing comments to the Environmental Protection Agency on the draft Underground Injection Control (UIC) Permit No. AK1I005-B for the Milne Point facility. BPXA appreciates the work that has gone in to renewing this permit. 1. Fact sheet, Page 5, 2) Injection Zone Fracturing 2. Draft permit, Page 19, Part II, C.4. Injection Zone Draft permit, Page 20, Part II, C.5 (ii) Injection Zone Fracturing Please correct the typographical error that we found referenced in the above three locations in the Fact Sheet and Draft Permit. The depth at the base of the injection interval is 4923 feet TVD not 4293 feet. I transposed the numbers when I provided them to you previously and did not catch my error until now. 3. Draft Permit, Page 6, Part I, E.6. Proper Operation and Maintenance Draft permit, Page 21-22, Part II, C.B. Injection Fluid Limitation For clarification,please strike the phrase, "generated during remedial well workovers or well construction operations"in the sentence: "De-characterized waste generated during remedial well workovers of well construction operations may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. 148.1(d))." De-characterized waste from activities other than well maintenance and construction can be appropriately disposed in a Class I non-hazardous well. The final sentence in the above referenced two locations in the Draft Permit should read: "De-characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. 148.1(d))." 4. Draft permit,Page 22, Part II C.B. Injection Fluid Limitation Please correct the typographical error. The citation should be 40 C.F.R. 148.1(d)not 148.4(d). ti 5. Draft permit, page 21, Part II, C.7. Annulus Pressure The final sentence should read"It should be noted that the wellhead working pressure limit of 5000 psig should not be exceeded at any time." 6. Draft permit, Page 21, Part II, C.7. Annulus Pressure For accuracy,please change the word"volume"to "pressure"in the sentence, "Since the tubing-casing annulus volume will vary due to temperature changes, the high-low annulus pressure limits can be adjusted, ..." The final sentence should read: "Since the tubing-annulus pressure will vary due to temperature changes,the high-low annulus pressure limits can be adjusted." If you need any additional information concerning these comments,please contact me, at(907) 564- 4838 or Alison.Cooke@bp.com. Sincerely, Alison Cooke Compliance Advisor, UIC Response Number 1 Regarding your comments 1, 2 and 4, the typographical errors are noted and corrected. The depth at the base of the injection interval is 4923 feet TVD, not "4293." Also,the citation regarding de- characterized waste eligibility for appropriate disposal in a Class I well should be 40 C.F.R. 148.1(d)not 148.4(d). Thank you. Regarding your comment number 3, the phrase, "generated during remedial well workovers or well construction operations"for clarification is struck. EPA agrees, de-characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. 148.1(d))." Regarding your comment number 5, EPA agrees the addition of the phrase"5000 psig"to the reference of the well working pressure limit adds clarity. Regarding your comment number 6, EPA agrees with the word change from"volume"to "pressure." Therefore the sentence regarding annulus pressure should read"Since the tubing-casing annulus pressure will vary due to temperature changes, the high low pressure limits can be adjusted, ..." We thank Ms. Cooke for the comments and cooperation in the development of this permit. End response to comments. Page 1 of 23 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-1I005-B In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency(EPA) under Title 40 of the Code of Federal Regulations, BP Exploration(Alaska) Inc. (BPXA) (Permittee) is authorized to inject non-hazardous industrial waste utilizing up to two (2) Class I injection wells at the Milne Point Unit (MPU) located on the Alaskan North Slope (NS). Injection is authorized into the Schrader Bluff(West Sak) and Ugnu (Prince Creek) Formations, in accordance with Title 40 C.F.R. § 144.33 and the conditions set forth herein. The Milne Point oilfield located in the MPU near the Beaufort Sea about 250 miles north of the Arctic Circle and lies west of Prudhoe Bay, on the North Slope of Alaska approximately 25 miles west of Deadhorse, Alaska. The proposed disposal well(s) are in an area where there are no underground sources of drinking water(USDWs) and an aquifer exemption delineated by a cylinder along the well trajectory of the Class I injection well(s) from (below permafrost) 2000 feet true vertical depth (TVD) to 4270 feet TVD. The aquifer exemption was issued by EPA on September 29, 2004 for aquifers between approximately 2000 feet(base of the permafrost) and 4,270 feet true vertical depth subsea(TVDss) and was clarified to include the area delineated by a cylinder of 1/4 mile radius along the well trajectories whose latitudes and longitudes (per NAD83) respectively at the well surface location are latitude 70.472809 and longitude -149.413148 for well MPB-50 and latitude 70.472928 and longitude -149.413239 for well MPU-xx. (Exact well locations are subject to change or correction.) Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 USC 6901) or radioactive wastes (other than naturally occurring radioactive material—NORM from pipe scale) are not authorized under this permit. All references to Title 40 of the Code of Federal Regulations are to regulations that are in effect on the date that this permit is issued. Figures and appendices are referenced to BPXA's Renewal Application for Milne Point Unit UIC Permit AK-11005-A dated April 30, 2014. This permit shall become effective on November 3, 2014, in accordance with 40 C.F.R. § 124.15. This permit and the authorization to inject shall expire at midnight, November 2, 2024, unless terminated. Signed this /r-a day of , 2014. / '`•ward J. Kow. i, Director Office of Compliance and Enforcement U.S. Environmental Protection Agency Region 10 (OCE-184) 1200 Sixth Avenue Suite 900 Seattle, WA 98101 Page 2 of 23 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE 1 PART I GENERAL PERMIT CONDITIONS 4 EFFECT OF PERMIT 4 PERMIT ACTIONS 4 Modification, Reissuance, or Termination 4 Transfer of Permits 5 SEVERABILITY 5 CONFIDENTIALITY 5 GENERAL DUTIES AND REQUIREMENTS 5 Duty to Comply 5 Penalties for Violations of Permit Conditions 6 Duty to Reapply 6 Need to Halt or Reduce Activity Not a Defense 6 Duty to Mitigate 6 Proper Operation and Maintenance 6 Duty to Provide Information 6 Inspection and Entry 7 Records 7 Reporting Requirements 9 Anticipated Noncompliance 9 Twenty-Four Hour Reporting 9 Other Noncompliance 10 Reporting Corrections 10 Signatory Requirements 10 PLUGGING AND ABANDONMENT 11 Notice of Plugging and Abandonment 11 Plugging and Abandonment Report 11 Cessation Limitation 11 Cost Estimate for Plugging and Abandonment 12 FINANCIAL RESPONSIBILITY 12 PART II WELL SPECIFIC CONDITIONS 13 Schwartz, Guy L (DOA) From: Schwartz,Guy L(DOA) Sent: Monday, May 04, 2015 3:20 PM To: 'Ted Kramer' Cc: Bettis, Patricia K(DOA);Wallace, Chris D(DOA) Subject: Sundry Approval for MPB-24(PTD 196-009) Ted, After further discussion you have verbal approval to proceed with sundry as proposed with the changes below. Also the sundry is only valid through step 11. Once the CBL is run you cannot complete the well or perforate without a new sundry and have the required spacing exemption in place. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).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 Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From:Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Monday, May 04, 2015 1:22 PM To: Schwartz, Guy L(DOA) Cc: Bettis, Patricia K(DOA); Wallace, Chris D (DOA) Subject: RE: Sundry Approval for MPB-24 (PTD 196-009) Sorry to hear this Guy, I thought we were in the clear. Please let me know as soon as possible what the issues are so we can fix them or look at other options. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 From: Schwartz, Guy L(DOA) [mailto:guy.schwartzC@alaska.gov] Sent: Monday, May 04, 2015 11:33 AM To:Ted Kramer 1 Cc: Bettis, Patricia K(DOA); Wallace, Chris D (DOA) Subject: RE: Sundry Approval for MPB-24 (PTD 196-009) Ted, We have the lease as of 11:00AM this morning. In reviewing it however there are some issues that have come up. Can't grant a verbal yet or approve the sundry until these are cleared up. Will get back with you later on the exact nature of the issues. In our phone call I summarized some changes to the sundry as listed below: 1) PT BOPE to 3500 psi as you plan on testing casing to 3500 psi later in the procedure. 2) In step 10 test casing to 3500 psi (vs 1500 psi) ...there is significant length of casing that will see injection pressure below your injection zone. Should test all of casing to verify integry before perfing and injection starts.. The EPA Class 1 permit allows 3000 psi surface pressure. Your slurry weights will likely be much higher than the 8.5 ppg seawater. 3) In step 11 log CBL the entire well from 11692' and to 5000'. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALIIY 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 Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From:Ted Kramer[mailto:tkramer@hilcorp.com] Sent: Monday, May 04, 2015 8:51 AM To: Schwartz, Guy L(DOA) Subject: Sundry Approval for MPB-24 Guy, Attached please find the submitted 10-403 that is in the AOGCC office for approval. I would like to speak with you concerning this well and Hilcorp's ability to proceed with well work on a verbal approval. The Nordic#3 is currently rigged up on the well and a Witnessed BOP test is being conducted on a verbal approval by Victoria Loepp on Friday. The work plan involves only setting up this well for disposal. There are no open perfs in this well and NO perforating of this well will be conducted as part of this well work. Please give me a call to discuss further. Thanks, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 2 0 i I56 -oo • ,,,,P—I%i s 1HE STATE repiw.., ____ _ =_____41ai °ALAS :A ki, _.=_ __,___, .10�5 ..*-40 o\ [ �a,t,l: illi 1 ,�,\I KI.1: RECEIVED ALAS APR 2 9 2015 AOGCC PICKED UP BY HILCORP April 29, 2015 AWARD NOTICE Hilcorp Alaska, LLC Oil and Gas Lease Attn: David Duffy ADL 392703 3800 Centerpoint Dr., Suite 1400 Anchorage, AK 99503 Right to Competitive Oil and Gas Lease Awarded Payment of Additional Bonus Money, Interest and Rental Required LEASE AWARDED State of Alaska oil and gas lease ADL 392703 is awarded to Hilcorp Alaska, LLC. The lease contains 2,533.00 acres. EXCESS BID DEPOSIT Based upon the actual lease acreage and your bid per acre, the bonus bid required is $71,481.26. Your excess bid deposit, if any, has been applied to the balance of bonus bid due. DOCUMENTS DUE TO STATE Two lease forms, including mitigation measures and final legal descriptions, are enclosed with this letter. The original leases, including mitigation measures, must be returned within 30 days from receipt of this notice. The leases must be executed by the bidder, or the bidder's agent, as authorized by instruments included in the bidder's qualification file. Notary acknowledgement of lessee's signature block must be completed on the lease forms in the space provided. The notary block on the lease form is for state use only. Item 25 must be completed on both lease forms. Future notices and correspondence regarding this lease will be mailed to the name and address specified in Item 25. If the notification address is different from the billing address, please include both. These documents must be received by the Division of Oil and Gas, Attention: Lease Administration, 550 West 7th Avenue, Suite 1100, Anchorage, Alaska 99501-3563, within 30 days from receipt of this notice, in accordance with 11 AAC 82.465 and the Instructions to Bidders dated October 1, 2014. PAYMENTS DUE TO STATE Payments must be received within 30 days of receipt of this notice, in accordance with 11 AAC 82.465 and the Instructions to Bidders dated October 1, 2014. The following payments are due: • AWARD NOTICE Page 2 ADL 392703 1) Balance of bonus bid. Interest on the balance of bonus bid. The interest rate is 0.0002% per annum, which is the market interest rate for 30 day U.S. Treasury Bills averaged for the week of April 20, 2015 through April 24, 2015. Interest begins accruing from the day following receipt of the Lease Award Notice and continues accruing up to and including the day payment is made. Please note: Interest calculations should be based on a 365-day year times the actual number of days that interest is owed. The State uses the Julian calendar, such as the one enclosed with this letter, to compute the days of interest; instructions are attached to the calendar. Please remember there is a four hour time difference between Alaska Standard Time and Eastern Standard Time that may affect the date payment is received. The formula for calculating the interest due is: Balance of Bonus Bid x Number of Days x 0.00000055 ** = Interest Due ** 0.00000055 is the interest rate of 0.0002% divided by 365. 2) Payment due for the first year's annual rental is$10.00 per acre or portion of an acre. (Do not pay interest on this amount.) Payment for this lease is: (1) Balance of + (2) Interest on + (3) First year annual = (4) Total bonus balance of rental (no interest bid (not bonus due on this amount). including bid. interest). (1) $57,184.26 + (2) $ + (3) $25,330.00= (4) $ Upon request, the state will electronically provide an Excel spreadsheet to assist in calculating the payment due. Please contact the Division of Oil and Gas representative listed at the end of this letter for further information. METHOD OF PAYMENT Payments must be made by wire transfer of federal funds to: State Street Bank and Trust Company, Boston, Massachusetts, ABA #011000028, for credit to State of Alaska, General Investment Fund, AY01, Account #00657189. The wire transfer must specify on whose behalf the payment is being made. If possible, bidders should use only one wire transfer for all leases. The successful bidder must transmit the following information to the three email addresses below, no later than 2:00 p.m. (Alaska Standard Time), the business day prior to the wire transfer settlement: cashmgmt@alaska.gov (State of Alaska, Department of Revenue,Treasury Division) rona.hurst@alaska.gov (Department of Natural Resources, Division of Oil and Gas) dog.leasing@alaska.gov (Department of Natural Resources, Division of Oil and Gas) J AWARD NOTICE Page 3 ADL 392703 1) The Alaska Division of Lands (ADL) number assigned to each tract; 2) Total amount submitted for each tract and a breakdown showing the balance of bonus bid, interest, and annual rental per tract; 3) Name(s) of the bidder(s) on whose behalf the funds are being transferred; 4) Originating bank of the wire transfer; 5) Total amount of the wire transfer; and 6) The date the transfer will be made. ISSUANCE OF LEASE Upon full compliance with this notice, a lease will be issued. The effective date of the lease will be the first day of the month following the day on which the lease is signed on behalf of the State of Alaska, or if requested in writing by the lessee, the first day of the month in which the lease is signed. This date will be noted in the first paragraph on page one and above the notary block in paragraph 40 of the lease; lessee must not enter the effective date. COMPLIANCE Failure or refusal by the bidder to comply with any provision of this notice will cause forfeiture of the right to lease this sale tract and forfeiture of the entire bid deposit to the State of Alaska. FURTHER INFORMATION Should you have any questions regarding this notice please contact: Rona Hurst Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, Alaska 99501-3563 Phone number (907) 269-8810 FAX number (907) 269-8943 Sincerely, Paul Decker Acting Director Enclosures: Lease Form including Mitigation Measures and Exhibit A (2 copies) Julian Calendar and Instructions (1 copy) Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Wednesday, April 29, 2015 12:08 PM To: Ted Kramer(tkramer@hilcorp.com) Subject: FW: Milne Pt Unit B-24 Well (PTD 196-009) Ted, FYI From: Bettis, Patricia K(DOA) Sent: Wednesday, April 29, 2015 12:07 PM To: ckanyer@hilcorp.com Subject: Milne Pt Unit B-24 Well (PTD 196-009) Chris, Thank you for the notice concerning Competitive Oil and Gas Lease ADL 392703. Upon issuance of the lease, please provide a copy to the AOGCC so that we may process Hilcorp's sundry application (No. 315-249) in an efficient manner. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Wednesday, April 29, 2015 12:07 PM To: ckanyer@hilcorp.com Subject: Milne Pt Unit B-24 Well (PTD 196-009) Chris, Thank you for the notice concerning Competitive Oil and Gas Lease ADL 392703. Upon issuance of the lease, please provide a copy to the AOGCC so that we may process Hilcorp's sundry application (No. 315-249) in an efficient manner. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 / ft-- Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Monday, May 04, 2015 3:20 PM To: 'Ted Kramer' Cc: Bettis, Patricia K (DOA);Wallace, Chris D (DOA) Subject: Sundry Approval for MPB-24 (PTD 196-009) fed, After further discussion you have verbal approval to proceed with sundry as proposed with the changes below. Also the sundry is only valid through step11. Once the CBL is run you cannot complete the well or perforate without a new sundry and have the required(pacin exemption)n place. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).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 Guy Schwartz at(907-793-1226 Ior(Gu .schwartzQ I ska o v ) From: Ted Kramer [mailto:tkramer©hilcorp.com] Sent: Monday, May 04, 2015 1:22 PM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA) Subject: RE: Sundry Approval for MPB-24 (PTD 196-009) Sorry to hear this Guy, I thought we were in the clear. Please let me know as soon as possible what the issues are so we can fix them or look at other options. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, May 04, 2015 11:33 AM To: Ted Kramer 1 r- . Cc: Bettis, Patricia K(DOA); Wallace, Chris D (DOA) Subject: RE: Sundry Approval for MPB-24 (PTD 196-009) Ted, We have the lease as of 11:00AM this morning. In reviewing it however there are some issues that have come up. Can't grant a verbal yet or approve the sundry until these are cleared up. Will get back with you later on the exact nature of the issues. In our phone call I summarized some changes to the sundry as listed below: 1) PT BOPE to 3500 psi as you plan on testing casing to 3500 psi later in the procedure. 2) In step 10 test casing to 3500 psi (vs 1500 psi) ...there is significant length of casing that will see injection pressure below your injection zone. Should test all of casing to verify integry before perfing and injection starts.. The EPA Class 1 permit allows 3000 psi surface pressure. Your slurry weights will likely be much higher than the 8.5 ppg seawater. 3) In step 11 log CBL the entire well from 11692' and to 5000'. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).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 Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Ted Kramer [mailto:tkramer©hilcorp.com] Sent: Monday, May 04, 2015 8:51 AM To: Schwartz, Guy L(DOA) Subject: Sundry Approval for MPB-24 Guy, Attached please find the submitted 10-403 that is in the AOGCC office for approval. I would like to speak with you concerning this well and Hilcorp's ability to proceed with well work on a verbal approval. The Nordic#3 is currently rigged up on the well and a Witnessed BOP test is being conducted on a verbal approval by Victoria Loepp on Friday. The work plan involves only setting up this well for disposal. There are no open perfs in this well and NO perforating of this well will be conducted as part of this well work. Please give me a call to discuss further. Thanks, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 2 d... Image Project iNell 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. L ~~ - Q ~ (~ Well History File Identifier Organizing (done) RESCAN ^ Color Items: ^ Greyscale Items: ,wo.~~ momiuimm DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: o ae,~,~~ee~ed iuuiuis~iuuii ^ Poor Quality Originals: ^ Other: OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES: ^ Other:: BY: Maria Date: /s/ Project Proofing III IIIIII VIII II III BY: Maria Date: ~ Q /s/ 1 Scanning Preparation x ~ 30 = Q + ~~ =TOTAL PAGES~~ _ r ~ (Count does not include cover sheet) BY: Maria Date: j l(~ ~ ~ /~ /s/ Production Scanning Stage 7 Page Count from Scanned File: 5..2~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: YES _ BY: Maria Date: ~/~ O v Q ~~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES BY: Maria Date: Scanning is complete at this point unless rescanning is required. r~P "6uuuimn m~ ReScanned BY: Maria Date: /s/ Comments about this file: o~,„„~~e~,ea iuuuiimiuuu 10!6!2005 Well History File Cover Page.doc • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 December 30, 2011 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission °P— O9 333 West 7 Avenue Anchorage, Alaska 99501 4 Subject: Corrosion Inhibitor Treatments of MPB -Pad Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from MPB -Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir BPXA, Well Integrity Coordinator • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10 -404) MPB -Pad 8/22/2011 Corrosion Initial top of Vol_ of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft gal MPB-01 1800750 50029204900000 Sealed coductor NA NA NA NA NA MPB-02 1811420 50029206620000 40 NA Need tob job MPB-03 1820560 50029207320000 Sealed coductor NA NA NA NA NA MPB-04A 1821000 50029207480100 Sealed coductor NA NA NA NA NA MPB -05A 1851480 50029207720100 Sealed coductor NA NA NA NA NA MPB-06 1850130 50029212760000 Tanko conductor NA NA NA NA NA MPB-07 1850620 50029213240000 Sealed coductor NA NA NA NA NA MPB-08 1850630 50029213250000 Tanko conductor NA NA NA NA NA MPB-09 1850340 50029212970000 Tanko conductor NA NA NA NA NA MPB-10 1850170 50029212800000 Tanko conductor NA NA NA NA NA MPB-11 1850430 50029213050000 Tanko conductor NA NA NA NA NA MPB -12 1850800 50029213380000 Tanko conductor NA NA NA NA NA MPB-13 1850930 50029213480000 Tanko conductor NA NA NA NA NA MPB-14 1851120 50029213660000 Tanko conductor NA NA NA NA NA MPB-15 1851210 50029213740000 Tanko conductor NA NA NA NA NA MPB-16 1851490 50029213840000 Tanko conductor NA NA NA NA NA MPB-17 1852090 50029214340000 Tanko conductor NA NA NA NA NA MPB-18 1852290 50029214500000 Tanko conductor NA NA NA NA NA MPB-19 1852300 50029214510000 Tanko conductor NA NA NA NA NA MPB-20 1860050 50029215240000 Tanko conductor NA NA NA NA NA MPB-21 1860230 50029215350000 Tanko conductor NA NA NA NA NA MPB -22 1853020 50029215090000 Tanko conductor NA NA NA NA NA MPB -23 1890160 50029219150000 Sealed coductor NA NA NA NA NA --->" MPB-24 1960090 50029226420000 5 NA 5 NA 35.7 8/22/2011 MPB-25 1972330 50029228410000 3.8 NA 3.8 NA 25.5 8/22/2011 MPB -27 2042210 50029232330000 1.6 NA 1.6 NA 15.3 8/22/2011 MPB-50 2042520 50029232400000 2.1 NA 2.1 NA 8.5 8/22/2011 • • ~p h ~ s. ~~ sa.. , g ~ ; -y ~ u ~ t ' ~, ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~{' ~ ~ ~ `~ ~ ~ ~ ~ ~ ~ ~ ~ ~. ~ ~ ~,~ ~~a~`~ ~~.~~~ ~ ~~ ~ ~ ~ ~ ~ P ~ ~~" ° ~ ~ ~ k ~ ~ ~~ ~ ~ g ~ ~ ~ ~~~ ~' ~ ~ ~ ~ ~ SEAN PARNELL, GOVERNOR ~~ 1+ ~ ~ s~~~~-A ~~ i,n~`~ rz'<,, ~! ~~.~~-~ ~_.`,~ ~~ 4~~ ~~r ~ ~'~.~• ~ ~r~~+ ~ ~~5~ ~IL ~~ Vrt1-7 ~ 333 W. 7th AVENUE, SUITE 100 COi~TSERQATIOI~T COMl-IISSIOi~T ,~ pHONOE~ 907)279K43395013539 ~ FAX (907) 276-7542 Mr. Gary Preble Data Management Engineer BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 r~ ~ Q O ' l~ Re: Milne Point Field, Kuparuk River Sands Pool, PJIPB-24 Sundry Number: 309-298 ~_ . - . ,~ '~.~~ Deax Mr. Preble: ' * """° Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Cathy . Foerster Commissioner DATED this da of September, 2009 /~- y Encl. ` ~ ~~ ~s.,~ ~ ~~ STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMI~N APPLICATION FOR SUNDRY APPROVALS ~n nnr. ~~ ~An ~~~-~ ~~ ~'~~;;~~1 1~.~,~ , i ,~ ~3 ~ ' ~1 ~.~ `1 (~ r~'. \ ~ ~ ~ ~a ~ ~ a fl:` r"t j~"~ . '€~"a d ~ E'K+.~ . t' _ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^ Waiver ~+? ~, ~~ ~ , Othe~ 4 Alter casing ~ Repair well ^ Plug Perforations ~ Stimulate ^ Time Extension ~ Renew Susoension Change approved program [] Pull Tubing ~ Perforate New Pool ~ Re-enter Suspended Weli ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: BP Exploration (Alaska), Inc. Development ~, Exploratory ~ 196-0090 • 3. Address: P.O. Box 196612 Stratigraphic ~ Service ~ 6. API Number: Anchorage,AK 99519-6612 50-029-22642-00-00 • 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ^ MPB-24 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADLO-047432 • 46 DF . MILNE POINT Field / KUPARUK RIVER SANDS Pool • 12• PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): 12584 • 7933.92 • 5 5 5' 4000' 11800' NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 73' 20" 91.1# NT80LHE 37' 110' 37' 110' Surtace 4045' 9-5/8" 40# L-80 35' 4080' 35' 3328' 5750 3090 Intermediate Production 12033' 7" 26# L-80 33' 12066' 33' 7443' 7240 5410 Liner Pertoration Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): NONE - NONE - Packers and SSSV Type: NONE Packers and SSSV MD (ft): 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^~ • Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: Oil ^~ • Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: Prepared by Gary Preble 564-4944 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Gary Preble Printed Name Gary Preb TiUe Data Management Engineer Signature Phone Date 564-4944 8/27/2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~~~~~ Plug Integrity ~ BOP Test ~ Mechanical Integrity Test ^ Location Ciearance ^ Other. ~c1Ct~wo.~ 0-~ S JS @ 2nc,~rO n c~. C~ V e~ .~~ ~~ S G ~'~fJC~~~ ~~ ;~ ~~~~~ r; ~q ~ ~P~ ~P Subsequent Form Required: ~~ ~~ q~ ,~~ ~`r,.~~ APPROVED BY Approved by: MISSIONER THE COMMISSION Date: 9/ -~ Form 10-403 Revise 06/2006 U~ ~ U ~ ~ V h L. '~~=~A~'.' ~'~'~ w.~'' ~_' fp~~' .~ d n Du licate ~-.~`~'~~`~ Lg" =~ i, v~ . BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 August 27, 2009 Mr. Daniel Seamount, Chairman Aiaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Milne Point Well MPB-24 (PTD #1960090) Suspended Well Inspection Report (10-404) Application for Renewal of Existing Suspension (10-403) Dear Mr. Seamount, bp BP Exploration (Alaska) Inc. (BPXA) completed an AOGCC witnessed suspended well inspection of Milne Point well MPB-24 on 7/28/09. Enclosed is a Report of Sundry Well Operations (10-404) with attachments documenting the inspection and the current condition of the well (reference 20 AAC 25.110 (e) and (fl). We believe this information demonstrates that the well is mechanically sound. Specific attachments include: • Suspended Well Site Inspection form documenting the well pressures and site condition, signed by the witnessing AOGCC inspector • Wellbore diagram illustrating the current configuration of the well • Pad map and aerial photo showing well location and other wells within one- quarter mile radius of the surface location • Photographs showing the condition of the wellhead and the surrounding location Milne Point well MPB-24 was suspended on 3/3/96. It is located on a pad with active producing wells and/or service wells. Based on this information, BPXA requests approval for renewal of the existing • suspension status for this well. Attached is an Application for Sundry Approval (10- 403) with a technical justification summarizing the information on the current status and condition of the well (reference 20 AAC 25.110 (a), (b), (e), (h) and (i)). • In summary, BPXA believes Milne Point well MPB-24 is mechanically sound and secure and meets requirements for renewal of suspended status. i ~ If you require any additional information, please contact me at 564-5637 or Anna Dube / Torin Roschinger at 659-5102. Sincerely, ( ~ ~ 1 R. Steven Rossberg BPXA, Wells Manager Attachments: Report of Sundry Operations (Form 10-404) with attachments: Suspended Well Site Inspection form Wellbore Schematic Well location plat and aerial photo Pictures of wellhead and location Application for Sundry Approval (Form 10-403) with attachment: Technical Justification Cc: Dube/Roschinger Harry Engel Mike Bill Josh Chebul Gary Preble ~e Point Oil Pool well MPB-~ Technical Justification for Application for Renewal of Suspension Status August 20, 2009 Well Status Milne Point well MPB-24 (PTD # 1960090) was suspended on 3/3/96. There is no tubing in the well. A cement plug was placed from 11800' to 12,500' MD below and across the 7" casing shoe and pressure tested. Additionally, a bridge plug was set at 4200' MD and is capped with 200' of cement from 4000' to 4200' MD, adjacent to the surface casing shoe. A third cement plug is located at surFace to 250' MD. Additionally, a tree cap is installed. The well is mechanically sound as proven by the casing pressure tests after the casing was cemented and after the first plug was set. The well will not allow the migration of fluids, will not damage freshwater or producing or potentially producing formations, will not impair the recovery of oil or gas, is secure, safe, and not a threat to public health, and is in compliance with all laws, regulations, permits, and orders. The strata through which the well was drilled is neither abnormally geo-pressured or depleted. Condition of the Wellhead and Surface Location Milne Point well MPB-24 is located on an active, well maintained pad with clean gravel. The pit and surrounding area are in good condition. There is no discoloration and no sheens on the pad, pits, or in nearby water. The well pressure readings are slight vacuum on the casing, 200 psi on the outer annulus. ~ ~ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ~~~ ~~ " DATE: August 1, 2009 P. I. Supervisor /~ ~~~,~~ FROM: John Crisp, SUBJECT: Suspended Weil Inspections Petroleum Inspector BPXA Milne Point Unit B-24 ' PTD 1960090 - Auqust 1, 2009: I traveled to Milne Point Unit (MPU) with BPXA representative Mike Shoemake to inspect wellsite MPU B-24. This well is located on an active Drillsite. The area around MPU B-24 is the same ~ as producing & injecting wells on the Drillsite. Guard rail has been placed around the well. All valves are opened to monitor casing and tubing pressures. MPU B-24 seems to meet regulation 20 AAC 25.110 fior Suspended wells Summarv: Suspended well site Inspection performed on MPU B-24. Attachments: Photo's & Operator Wellsite~--6nspeetion Form. f . ~~~~~~~~ ~!~ ~ ~ ~f 2QOS • • MPU B-24 (BPXA) Suspended Well Inspection PTD 1960090 Photos by AOGCC Inspector J. Crisp August 1, 2009 MPU B-24 Suspended Well Inspection 8-1-09 • • MPU B-24 Suspended Well Inspection 8-1-09 Suspended Well S~Inspection Form ~ Notify AOGCC inspectors at least 10 days prior to inspection to allow witness Well Name: MILNE PT UNIT KR B-24 '~ FieldlPool: MILNE POINT / KUPARUK RIVER OIL Permit #(PTD): 196-009 ~ API Number: 50029226420000 Operator: BP EXPLORATION (ALASKA) INC Date Suspended: /3/3 1996 Surface Location: Section: 18 Twsp: 13N Range: 11 E Nearest active pad or road: MILNE POINT B-PAD Take to Location Digital camera Map showing well location /Aerial photos Brief well history Wellbore diagram showing downhole conditio~ Latest Sundry or Completion report Past Site Visit documentation Site clearance documentation Pressure gauges, fittings, tools Sample containers for fluids on or near pad Condition of Surface Location AOGCC requires: 1) a description of the condition of the surface location, including discoloration, fluids or sheens visible on the ground or in any nearby water, 2) photographs showing the condition of the location surrounding the well General location condition: Active pad, well maintained Pad or location surface: Clean Gravel - Location cleanup needed: None Pits condition: Good ' Surrounding area condition: Good . Water/fluids on pad: None Discoloration, Shee~s on pad, pits or water: None Samples taken: Access road condition: Good Photographs taken (# and description): 11 pictures of wellhead, sign, barrier, gauges and area - Condition of Wellhead AOGCC requires: 1) a description of the condition of the wellhead, 2) well pressure readings, where practicable, 3) photographs showing the wellhead condition Wellhead/tree/valve description, condition: FMC Wellhead with one valve and tree cap. All in good condition. ' Plote that bolfs on valve are not flush with top of nuts. Would need chanaed before accessina well. Well susnended w/ 3 pluqs. ---- -._ ellar description, condition, fluids: Cellar clean with dirt bottom and no fluids. Rat Hole: None Wellhouse or protective barriers: Barrier around well - Well identification sign: Yes Tubing Pressure (or casing if no tubing): Slight vacuum ' Annulus pressures: OA = 200psi ~ Wellhead Photos taken (# and description): 11 pictures of wellhead, sign, barrier, gauges and area Work Required: None _ „ Operator Rep (name and sign tu ): 'chael Shcemake // AOGCC Inspector: Other Observers: Inspection Date: 7/28/2 AOGCC Notice Date: Time of arrival: Time of Departure: Site access method: Milne Point Bpad and access road llUC.: l3odyYage • • rage i oi ~ 5 t \ ~ c~-' ~~ - -_ ~~ ~ ~ ~ - ~o-~ ~~ -~~.~_~~ e 20 AAC 25.110. Sus~ended wells (a) If allowed under 20 AAC 25.105, an operator may apply to the commission under this section to approve the suspension of a well or to renew the approval of the suspension of a well. The operator must state the reasons the well should be suspended, and not completed or abandoned, and must demonstrate to the commission's sa.tisfaction that (1) the well ~~ ~Q ~ ~``r` ~ (A) is mechanically sound; ~ ~` "`# ,~ r ;~'r~- ~ ',~'~ _.tr. ~(B) will not allow the migration of fluids; ~(C) will not damage freshwater or producing or potentially producing formations; ~(D) will not impair the recovery of oil or gas; J(E) is secures safe, and not a threat to public health; and (F) is in compliance with all provisions of AS 31.05, this chapter, and any order, stipulation, or permit issued by the commission; (2) the well (A) has future utiliiy as an exploratory, development, or service well; ~ (B) is a viable candida.te for redrittmg; or ~(C) is located on a pad or platform with active producing or service wells. (b) An Application for Sundry Approvals (Form 10-403) must be approved by the commission before opera.tions to suspend a well commence, except that oral approval may be requested under 20 AAC 25.507(b) . In addition to meeting the requirements of (a) of this section, the application must include the following: V(1) wellbore diagrams illustrating the current and proposed mechanical configurations of the well; t-- ~(2) information on abnormally geo-pressured or depleted strata; (3) a description of the proposed work plan, including. how the integrity of existing and proposed plugs will be demonstrated. (c) Unless the commission otherwise requires or approves a variance under 20 AAC 25.112 i, any well suspended under this section must be plugged in accordance with 20 AAC 25.112~, except that the requirements of 20 AAC 25.11_~d~ do not apply if (1) a wellhead is installed or the well is capped with a mechanical device to seal the opening; and httn•//www iPaic.ctatP.ak.i~c/ha.~i~/f~linnr~xv.aSn?url=httn://www.lesis.sta.te.ak.us/cgi-bin/f... 8/3i/2Q09 DOC BodyPage ~ Page 2 of ~'3 ~ (2) a bridge plug capped with 50 feet of cement or a continuous cement plug extending 200 feet within the interior casing string is placed at or above 300 feet below the surface. (d) The operator of a suspended well shall maintain the integrity and safety of the well and surrounding location and clear the location in accordance with 20 AAC _2_5.17~a~ (2) or (b) or with 20 AAC 25.172 ~c~ (2) or (d), as applicable. ~'~` ~ ~~-0 ~ (e) For a well suspended before Januarv 1, 2009, the operator shall inspect the well site before ~ September 30, 2010. For a well initially suspended on or after January 1, 2009, the operator shall inspect the well site within 12 months after the date of suspension. For a well suspended under this section, subsequent inspections shall be conducted within 24 months before September 30 of every calendar year ending in 0 or 5, except that a suspended well is not required to undergo a subsequent inspection under this subsection if the initial inspection under this subsection occurred within the prior 24-month period. For all inspections under this section, the operator shall provide the commission notice at least 10 days before the inspection and the opportunity for commission inspectors to accompany the operator on the inspection tour. If convenient for the commission, shorter notice periods may be accepted. (~ Within 30 days after any well-site inspection required under this section, including (e), (h), and (i) of this section, the o erator shall file a Report of Sundry Well Operations (Form 10-404). The report must include ~~~•r.~,~~ ~l~h ro~, /(1) a description of the condition of the wellhead and surface location, including any discoloration, fluid or sheen visible on the ground or in any nearby water; ./ (2) a plat showing the location of the suspended well and any wells within a one-quarter-mile radius of the wellbore; s~ ~~c~.c~. e~c,~~ ~(3) well pressure readings, if practicable; .4.~~;,~ s t~ ~l~~ vr~..~~~ ~ 41~ - ~~ Q~~ ~(4) photographs clearly showing the condition of the wellhead and surrounding location; and tc~.~. (5) an update of all information and documentation required in (b) of this section. (g) A suspension or renewal of a suspension approved on or after January 1, 2009 is valid for 10 years from the date of approval. ~s~ah p~ __~ (h) Renewal of an existing suspension may be requested by the submission of an Application for Sundry Approvals (Form 10-403) meeting all requirements of (b) of this section. A renewal is not effective until approved by the commission. If a complete renewal application is submitted at least 60 days before the expiration of an existing suspension, the existing suspension will continue until the commission acts on the application. Within 24 months before the submission of a request for suspension renewal, a well-site inspection must be completed. (i) For wells suspended before January 1, 2009, an Application for Sundry Approvals (Form 10-403) requesting a suspension renewal under (h) of this section must be submitted (1) no later than December 31, 2010 for all wells suspended before January 1, 200b; and ;~ (2) no later than December 31, 2015 for all wells suspended on or after January l, 2006. ,.,-,.,..~~..,.,,.,,,on,~ ~+.,+o ~v „~i,.~.;_~,;,,if Qi~i i~nn4 DOC BodyPage ~ ~ Yage ~ ot ~ ~ (j) The operator shall immediately notify the commission and propose appropriate action if the operator learns that there is a reasonable risk that a suspended well is (1) mechanically unsound; (2) allowing the migration of fluids; (3) causing damage to freshwater or producing or potentially producing formations; (4) impairing the recovery of oil or gas; (5) a threat to public health or not secure or safe; or (6) not in compliance with all provisions of AS 31.05, this chapter, and any order, stipulation, or permit issued by the commission. (k) within five working days after notifying the commission under (j) of this section, the operator sha11 file a report and all relevant information and documentation regarding the well, including all information and documentation that may be required by the commission. (~ If the operator leams that any information required under this section is no longer complete or accurate, the operator shall, within 30 days, notify the commission in writing, provide updated information, and propose appropriate action. (m) At any time, the commission may request that an operator provide, within 10 days after the date of request, any information concerning whether suspension remains appropriate for a well. If the operator does not comply with the information request or if the commission determines that information is insufficient to support allowing the well to remain suspended, the commission may take action under 20 AAC 25,540, including (1) revoking the well's suspended status, effective as of the date determined by the commission, and (2) prescribing actions the operator must take, which may include plugging and abandonment of the well; if action is ordered, including plugging and abandonment under this chapter, a separate notice and hearing is not required notwithstanding any other provision of this chapter, including 20 AAC 25.1 O5. (n) Upon written request of the operator, the commission may modify a deadline in this section upon a showing of good cause. History: Eff. 4/Z/86, Register 97; am 11/7/99, Register 152; am 11/19/2008, Register 188 Authority: AS 31.05.030 AS 31.05_040 AS 31.05.095 20 _AAC 25,112.. Well_~lu~ging re~uirements 1,+~,,•//~.n,ns.lA~.;~ ota+P alr ~~eMacic/fnlinr~rnxv acn~nrl=httr-•/han~vtv lr~vic ctate ak nc/[:ui-hin/f R/~1 /7nn9 STATE OF ALASKA ALASK~ AND GAS CONSERVATION COMMIS~ REPORT OF SUNDRY WELL OPERATIONS 'Y , i x'~.~4~x`'~"~ ~ '~ %t)~`4? :,,, , 1. Operations Abandon ~ Repair Well ~ Plug Perforations ~ Stimulate~ <Otk~~r ~;~~~5~',~(S~, ~[diir ""°?: Performed: Alter Casing ~ Pull Tubing ~ Perforate New Pool ~ Waiver ~ Time Extension ~~ Change Approved Program ~ Operat. Shutdown ~ PerForate ~ Re-enter Suspended Well ~ 2. Operator BP Exploration (Alaska), lnc. 4. Current Well Class: 5. Permit to Drill Number: -vame: Deuelopment T~- ~ Expioratory r ~ss-ooso . 3. Address: P.O. Box 196612 StPBtlgt'BphIC r Service r 6. API Number; Anchorage, AK 99519-6612 50-029-22642-00-00 ~ 7. KB Elevation (ft): 9. Well Name and Number: 46 DF . MPB-24. S. Property Designation: 10. Field/Pooi(s): ADLO-047432 • MILNE POINT Field/ KUPARUK RIVER SANDS Pool • 11. Present Well Condition Summary: Total Depth measured 12584 ~ feet Plugs (measured) 5' 4000' 11800 true vertical 7933.92 • feet Junk (measured) None Effective Depth measured 5 feet true vertical 5 feet Casing Length Size MD ND Burst Collapse Conductor 73' 20" 91.1# NT80LHE 37' - 110' 37' - 110' Surface 4045' 9-5/8" 40# L-80 35' - 4080' 35' - 3328' 5750 3090 Production 12033' 7" 29# 1-80 33' - 12066' 33' - 7443' 7240 5410 Pertoration depth: Measured depth: NONE - _ _ _ _ True Vertical depth: _ _ _ _ _ Tubing: (size, grade, and measured depth) none 0 - 0 0 - Packers and SSSV (type and measured depth) none 0 0 0 0 0 0 0 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descrip6ons including volumes used and final pressure: 13• Representative Daily Average Production or injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing pressure Prior to well operation: n/a Subsequent to operation: n/a 14. Attachments: 15. Well Class after oroposed work: Copies of logs and Surveys Run Exploratory r Development ~• Service ~ Daily Report of Well Operations 16. Well Status after proposed work: Suspended Well Site Inspection Report Oil ~• Gas r WAG r GINJ r WINJ r WDSPL ~ 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. Exempf: N/A Contact Gary Preble Printed Name Gary Pre le Title Data Management Engineer Signature Phone 564-4944 Date 8/26/2009 Form 10-404 Revised 04/2006 ~-~S(3~ Submit Original Only ~ _ _ ~_ ~.~ ~~~- r ~' 4? `~ 2009 .~G~~~~j r,~ ~"~3 `. ~ ~ • Suspended Weli Site Inspection Form 1._J Notify AOGCC Inspectors at least 10 days prior to inspection to allow witness Wel{ Name: MILNE PT UNIT KR B-24 Field/Pooi: MILfdE POItdT / KUPARUK RtVER OIL Permit #(PTD): 196-009 API Number. 50029226420000 _ ^ Operator: BP EXPLORATION (ALASKA) INC Date Suspended: ~ /3l3 1996 Surface location: Section: 18 Twsp: 13N Range: 11 E Nearest active pad or road: MlLNE POINT &PAD Take to Location Digital carrtera Brief wsli history Latest Sundry or Completion report Past Site Visit documentation Pressure gauges, fittings, tools Map showing well location /Aerial photos Wellbore diagram showing downhole condition Site clearance documentation Sample containers for fluids o~ or near pad Condition of Surface Location AOGCC requires: 1) a description of the condition of the surface location, including discoloration, fluids or sheens visible on the ground or in any nearby water, 2} photographs showing the condition of the location surrounding the well General location condition: Active pad, wel~ maintained Pad or location surface: Ctean Gravel Location cleanup needed: None Pits condition: Good Surrounding area condition: Good Water/fluids on pad: None Discoloration, Sheens on pad, pits or water: None Samples taken: Access road condition: Good Photographs taken (# and description): 11 pictures of wellhead, sign, barrier, gauges and area Condition of Wellhead AOGCC requires: 1) a description of the condition of the wellhead, 2) well pressure readings, where practicable, 3) photographs showing the wellhead condition Wellhead/tree/valve description, condition: FMC Wellhead with one valve and tree cap. AIf in Note that bolts on valve are not flush with ton of nuts. Would need chanaed before accessina welf. W Cellar description, conctition, fluids: Cellar clean with dirt bottom and no fluids. Rat Hole: None Wellhouse or protective barriers: Barrier around well Well identification sign: Yes Tubing Pressure (or casing if no tubing): Sliqht vacuum Annulus pressures: OA = 200psi Wellhead Photos taken (# and description): 11 pictu~es of wellhead, sign, barrier, gauges and area Work Required: None , ~ Operator Rep (name and AOGCC Inspector. Inspection Date: 7/28~ Time of arrival: Time of Departure: Site access method: Milne Point B pad and access road • ~ - ~ -- ~ MR 8-24 20' 9i~fft K-65 80' K~P @ 5~' Mauc. tida Mg1e 74.58° at b824' ~iD $ 6/8'~ 4T ~tft, ~ NT-80~ BTC 405(J ~ ~ m~s waa ,~ ~~+~a~- a~a~a p~~ a a~aa ~,a ae~9nsted ~ t~ tt wae a deine~n wsY br tha NW M~ne 10.1 PP(i ~a. _._ _ 7` ~.1~1T-80$ 8T~ 12f166 Piu~ 3 5 f~t belaw fundri - c"+~`D' ~• ~~ aooa - a~aa' t~d Camad fi~tsYHr ~ 42d~ a~~ _ Pkq 1 ~~~~t"~" i 1~D -12~ MIO , `~ M ~p ~ IM8 f iJ 1~IW~~ ~-~-~y~ t'IM9tl'I'f'i'~ • 74°~`~CP1'797'/ idr.j&ii6~Y~T! 'fh6e plup ~n+Ni tra pntaure teeted Eo t '~ ~~y ~8~~V@ ~b8 ~.~, 2~ ~y ~~~/, °"~~ ~. ~` ~~~ 111ilNE FOINT LMI{T 2128J89 (~iiN POSt PIu9 ~ c~erallons WFI 1 R.~d APt Nt}: 50-029-22842 BP E7CPL4RATION (AI~ Milne Pt. D-Pad 492' ~ I IJ ~~ ~ 21 ~~~ ,% 20 , . __. ig ~ 19 , 0 24 ~~ ' ~ r2 ~ ~ 8 ~ / 14 7 ~ / / ' ^ ~3 Milne Pt. Mine Site i 11 -~~ 16 ~ ~ ° s ~ --~ ~4~U CO N ~/ ~ ~r.r, ~i - ~ JL,_~ ~~ ~ ~ ~ 15~ ~ ~ ~ ~ ~~~ 1p ~ ~ ~ /~ .; ~ y ~3 . ~'~ ~ ,~~ ~ ~~, i 6 22 _. ~ ~ I ~~ ~ 5 ~ 2 , ;,~ ~ ~ ~ ,~~ 1~ 0 3 25 Ta~k Tank 50 D 9172 ~~~sel oad~ngT 20p~ ESP 1 ,~s~/ Coa . Ar~a 2pg d~n9 Area PV-2pp4 / 2 0 20q 20C Heater Skid nhem~Mo~o Ent xit ~ We/l pad ( siqe du%~n9 Area facilities modu/e 1 WELL PRODUCER ^ or ^ WELLINJECTOR ~ DATE : 01/07/2009 SCALE : 1" = 200' MAP DATE : 2007 MPU - B PAD WELL SLOT W/CONDUCTOR [] bs14495.dgn . ~~;a, ~ .-~ ~ ~ ~~ . i~ 7y~ ~ ~~ I~~ 2 [ ~ ; 1 ~ ~ ! ~ ~~~ _- ` " ,:. s ~ ~~ ~~ ~~ ~ Yj~ik' ~, ~ r u ~• . ~~~~ ~~ ~ ~`' ° ~ t~ r ~ , 1 ' '.a,,,~ . / ~ ~ ~... t ~ ~ +~4` T l ~ ~' ) ' r i -. " ~.f ~ ' '!-li~f+ ' ~{~`Y ~, P«y~: .~ _ ~ ~. ~ ~ .3 •~p,r'' ~~' ` ~ ' ii'. ~''~ ~~~gq~~j'` i ~ .'S ''~ ' .S~ ~~y}~ ~ ~.T. v, ' . _n ~e ~ y f ° i '~~.; ~ ~~~T~ 'lt~Z`M~ i . r ar ~ xa .ti I { ~~r ~~ ~ ' ,~. r e p' ~ ~ ~ ~ ~I.r~: " ~ t i' ~,~` . 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I 41~ '~`~t~•~ , _ ~,~ t,~' ~~'~ ,~'~ t ,~-~-~, ~-.S. , ~b ~ ~ ~ T ~ ~ ~~~~ ,r ~ ~~~• •+~ ;~.''~,, C~~ ;!• ,~ . Y,l::k~; ..1~'~3 } / 3.f ~ x ~ J R . ~ .' '.+ 1' l ~s-. sk,_ . , < ? .r [ 'n,` 4,. `a lR+ .~~;~yr : r,L fx~.r~,y;~ ~k ~ . , L~ 1~ ~~ ~{''~x t~' ~~I~~r"~ ~l"~ 7 *~~~~~ti r ~ GZ ~~ ,: ~ x -.~_~a J . ' f r ~, ~ ,~~'t¢ ~ ~. ~• /'~ t , ~: . ~.` ~+ . ~; -,. +'t~ ~ E~; t~i "` ~•,!~i•j :~ ~+ •t ,~ ~. ~ e ~ ~,~,6 I~ . } ~, -. sr ~' ~ ~~; M1F ?J . . ~ . ~~~ ti, >> ~ ' ~ : . p 1 ~;'~=.4 ~ +~ f a .. ~ ~ i ~ ~.t ~ ~~ ~~~. ~ ` '~i.'1, " f+ Y'.' ~r ~- .r 4, `~ j,~ `~~ . . f ~~ w , f.~-,~ ~~ 7/ ~ i ' . - ~. i:~t,! ~ ~'~ ~~ '~ e~' i -, M%~i .1 M ,~n, ~ ~,~.j ~ ,~ ~~~ , .;~.~. , ~4 , :_ , ,~ ~ ~ 1~ ~ .~ , iM j~ % ,~ i ~ ~ r ~ `~Y, 4 ~,~ ~ ; ~' ..~r~k~ ~ ~ ~ ~,.r ;;`~ '. . {~ : i 1 1 ~ r r- ~ ~ ~ Z 1 M r- ~ ~ ^~ ~ n ~ O ~ ~ ,_, r ~ ~ v ~ ~ ~ ~- o c~ o _ .~ a ~ ~r ~ ~ ~ o 4) W ~"' O ~ ~ _ a ~ ~ ._ ~ m C~ ~ a c v ~ ~. ~ ~ O ~ ~ ~ ~' a ,o~ < ~ V C~ F- O Z ~ a ~ - W ~ J Z ' J W ~ - ~ o- ~ o~ 0 0 ~ ~- ~ ~ ~ ~ ~. ...--~ ~~" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 'i:'-./7'iF~i):f¡O~! . - ".- ,'~ 827' NSL, 4289' WEL, SEC. 18, T13N, R11E, UM .;. D,",.:'f: .~~'.."'" .' '. ..- !, At top of productive interval ; .2,¿¿.lq!,,"~, ,~. ~1~~~d;e~151' EWL, SEC. 8, T13N. R11E, UM;.-~~!~i!_- 1£~'rn:,; 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. KBE = 46' ADL 047432 12. Date Spudded 13. Date T.D. Reached 14. Date Camp., Susp., or Aband. 15. Water depth, if offshore 16. No. of Completions 2/7/96 2/28/96 3/3/96 N/A MSL One 17. Total Depth (MD+ TVD) 18. Plug Back Depth (MD+ TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 12584 7934 FT 55FT ~Yes ONo N/A MD 1800' (Approx.) 22. Type Electric or Other Logs Run MWD, CDR/CDN 23. CASING SIZE 20" 9-5/8" 1. Status of Well :f1 f(l- 0 Gas ~Suspended ~ Abandoned 0 Service OOil ,ÆJECfl1/El Classification of Srrvice Welr--: / C i;' /9 ~/q8J(af1¡' .' '\ 9~ 7. Permit Number 'A3ciS COliC' . 96-009 96-4t!.'7C!]Or,':¡r:J. CO¡ì7/J,' 8. API Number "ur; It~siOf, 50-029-22642 9. Unit or Lease Name Milne Point Unit 10. Well Number MPB-24 11. Field and Pool Milne Point Unit / Kuparuk River Sands 7" WT. PER FT. 91.1# 40# 26# GRADE NT80LHE L-80 L-80 CASING. LINER AND CEMENTING RECORD SETTING DEPTH HOLE Top BOTTOM SIZE CEMENTING RECORD 37' 110' 30" 250 sx Arcticset I (Approx.) 35' 4080' 12-1/4" 802 sx PF 'E', 250 sx Class 'G', 250 sx PF 'C' 33' 12066' 8-1/2" 450 sx Class 'G' 24. Perforations open to Production (MD+ TVD of Top and Bottom and interval, size and number) None 25. SIZE N/A MD MD TVD TVD AMOUNT PULLED TUBING RECORD DEPTH SET (MD) PACKER SET (MD) DEPTH INTERVAL (MD) ACID, FRACTURE, CEMENT SQUEEZE, ETC. 26. 11800'-12500' 4200' 5'-250' PRODUCTION TEST IMethod of Operation (Flowing, gas lift, etc.) N/A PRODUCTION FOR OIL -BBL GAs-McF TEST PERIOD Flow Tubing Casing Pressure CALCULATED Press. 24-HoUR RATE 27. Date First Production Not on Production Date of Test Hours Tested WATER-BBL OIL -BBL WATER-BBL GAs-McF AMOUNT & KIND OF MATERIAL USED Freeze protect with 79 bbls diesel P&A, 32 bbls Class 'G' tested to 2000 psi Bridge plug with 44 sx Class 'G' on top Surface wiper plug, 54 sx PF 'C' nn (,~f\l^ UI\IUII\JtiL CHOKE SIZE I GAS-OIL RATIO OIL GRAVITy-API (CORR) 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Form 10-407 Rev. 07-01-80 Submit In Duplicate -~-. --c =--. 29. Geologic Markers 30. Formation Tests Marker Name Measured Depth True Vertical Depth Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Top Kuparuk 12142' 7514' Top Kuparuk 'C' 12338' 7699' Top Kuparuk 'B' 12344' 7704' Top Kuparuk 'A' 12511' 7864' 31. List of Attachments Summary of Daily Drilling Reports, Surveys 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Sign d '" I'Im1J -rn-:IL T.BrentReeves t/Á/tfl"l Title' . .. . MPB-24 96-009 96-42 Well Number Permit No. / Approval No. Date 5 ? 9B Prepared By Name/Number: Kathy Campoamor, 564-5122 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 ~~~~- SUMMARY OF DAilY OPERATIONS SHARED SERVICES DRilliNG - BPX I ARCO Well Name: Accept Date: MPB-24 02106/96 Rig Name: Spud Date: N-27E AFE# Release Date: 337008 03/03/96 FEBRUARY 05, 1996 SECURE CELLAR, RIG FLOOR & SKATE, PREP ALL LINES. REMOVE ALL TOOLS & EQUIPMENT FROM PIPE SHED. PREP PIPE CHUTE FOR MOVE BLOW DOWN & UNHOOK FLUID & ELECTRIC LINES. PREP OR SET OUT STAIRS & RAILS. SET OUT TESCO UNIT, CEMENT TANKS, PARTS HOUSE & FUEL TANK. SET OUT PIPE SHEDS. REMOVE DIVERTER LINE F/PIPE SHED BRACKETS JACK UP PIPE CHUTE. INSTALL GOOSENECK ON MOTOR COMPLEX. MOVE PITS & MOTOR COMPLEX AROUND PAD. REMOVE CUTTINGS CONVEYOR EXTENSION. MOVE SUB OFF F-06. MOVE MOTORS & PITS TO B-PAD. HAD TO WAIT @ L-PAD. F/0430 TO 0600 BECAUSE OF SPILL OF L-PAD (NOT OURS) REMOVE PIPE CHUTE, MOVE IN TIRES, SET DRILLING LINE SPOOL ON SUB GOOSE NECK. FEBRUARY 06, 1996 PREP 1-ES PIPE SHED TO MOVE, MOVE MOTOR COMPLEX & PIT FROM F PAD TO B PAD. HOOK 3RD 0-8 TO SUB & MOVE TO OTHER SIDE OF F PAD. INSTALL WHEEL BRACES. MOVE PIPE CHUTE, 1 ES SHED & SUB TO B PAD. SPOT SUB TO INSTALL CHUTE. SET DRILLING LINE SPOOL OFF GOOSE NECK. MOVE WHEELS OUT REMOVE FROG LAY MATS FOR SUB & PITS. PIN CHUTE. SPREAD HERCULITE FOR SUB, PITS & MOTOR COMPLEX. SET CUTTINGS & BERM, SPOT PITS. SPOT SUB OVER WELL. LINE UP PITS TO SUB. FEBRUARY 07, 1996 LAY MATS & SET MOTOR COMPLEX PUT WELL HEAD EQUIPMENT & DIVERTER LINE IN CELLAR. INSTALL CELLAR DOORS, LOWER PIPE CHUTE. HOOK UP ELECTRICAL, STEAM & WATER LINES. LAY MATS & HERCULITE FOR PIPE SHED. SET PIPE SHED, REMOVE JEEP, SET RIG FUEL TANK & TESCO UNIT. LEVEL PAD, LAY MATS & SET CAMP. HOOK UP SKATE & TEST WORK ON PIPE SHED & SKATE ROOF, SHORTEN CUTTINGS DARG CHAIN. NU 20" DIVERTER SYSTEM FILL PITS W/WATER WORK ON IRON ROUGH NECK & GRABBER ON TIP DRIVE. INSTALL TOP DRIVE ELEVATORS & HOSES. WELD BRACES ON TOP OF PIPE SHED CHUTE TO KEEP LINES W/RIG CHUTE. INSTALL STAIRS IN CHUTE REPLACE FRICTION ROLLERS BEARINGS & GEARS IN IRON ROUGH NECK. START TO LOAD PIPE SHED. NU 20" RISER, TURNBUCKLES & FLOWLINE. LOWER CHUTE EXTENSION & WRAP GAS W/HERCULITE BUILD BOTTOM LANDING FROM STAIRS. HOOK UP ACCUMULATOR LINES TO HYDRILL & KNIFE VALVE PRESSURE SYSTEM. CHECK FOR LEAKS. FEBRUARY 08,1996 INSTALL MOUSEHOLE. INTALL LANDING @ BOTTOM OF STAIRS. REPLACE HYD LINE ON SKATE WORK ON CUTTINGS BOX FILL INDICATOR. START MIX SPUD Page 1 of 6 -"~"""-=- SUMMARY OF DAILY OPERATIONS MUD. SENT 3 HANDS TO F PAD TO FINISH PAD CLEAN UP. PU & STD BACK 10 STDS DP. PTSM PU DP. REPLACE REMAINING HYD LINES & CABLE ON PIPE SKATE. STD BACK DP PU BHA. STAD BACK HWDP PU BIT & MOTOR. FEBRUARY 09, 1996 FINISH MU BHA. FUNCTION TEST DIVERTER. WITNESSING WAIVED BY BOBBY FOSTER AOGCC FIELD INSPECTOR. DRILLING F/11 0'-226 ART 1.25 HRS. POOH BLOW DOWN TOP DRIVE. PU MWD. ORIENT MOTOR & MWD. MU BHA CHANGE TOP STAB BLADE. DRILLING FROM 226'-2526' ART 8.25 HRS; AST 6.75 HRS. PTSM: #1 DRILLING SURFACE HOLE & #2 TOP DRIVE CONNECTIONS. DIVERTER DRILL; OS: 2 MIN. FEBRUARY 10, 1996 CIRC SWEEP AROUND MONITOR WELL PUMP DRY JOB. POH TO HWDP RIH NO PROBLEMS DRILLING F/2526'-3988' ART: 3.75 HRS; AST: 8.25 HRS. PTSM WORKING ON TIGHT HOLE WELL FIRE DRILL; OS: 3.5 MIN. CHECKOUT TRACTION MOTOR #1 MUD PUMP. DRILLING F/3988'-41 00' ART 5 HRS; AST 5 HRS PTSM TRIPPING PIPE CIRC SWEEP AROUND & CLEAN UP WELL. MONITOR WELL PUMP DRY JOB. POH TO HWDP SLM NO CORRECTION RIH NO PROBLEMS CIRC SWEEP AROUND AND CLEAN UP WELL TO RUN 9 5/8" FEBRUARY 11, 1996 FIN CIRC & CONDITION MUD TO RUN CASING MONITOR WELL OK PUMP DRY JOB BLOW DOWN POH LD BHA CLEAR FLOOR. RU CSG TOOLS RUNNING CASING. RAN 99 JTS (4040.38'), 9 5/8", 40# L-80 BTC CASING AS PER CASING SUMMARY. MU HANGER LAND CASING FS @ 4080' FC @ 3995'. RU HOWCO CIRC & COND FOR CEMENTING WO V AC TRUCK. CEMENT AS PER CEMENT SUMMARY W/802 SXS (310 BBLS) TYPE 'E' PERMAFROST; TAILED IN W/250 SXS (51 BBLS) PREMIUM 'G' BUMP PLUG TO 2000 PSI WICALCULATED STROKES. CIP @ 23302/10/96 FLOATS HELD OK. TEST CASING F/30 MIN OK RD HOWCO BLOW DOWN LINES ND & NU PERFORM TOP JOB W/250 SXS (42 BBSL) TYPE 'c' PERMAFROST RD TOOLS FIFLOOR ND DIVERTER & 20" RISER NU GEN 5 SPEED HD. PU 13 5/8" BOPE. FEBRUARY 12, 1996 FINISH NU BOPE, TEST BOPE TO 25015000 PSI. ANNULAR TO 250/3500 PSI. WITNESSED BY JOHN SPAULDING AOGCC FIELD INSPECTOR. D4 DRILL. SERV TOP DRIVE. CLEAN RIG MOP ALL FLOORS, WIPE DOWN WALLS SPILL DRILL; OS: 3.5 MIN PU TOP DRIVE BAILS & ELEVATORS LD TEST JT INSTALL WR. PU BHA. ORIENT MWD LOAD SOURCES PROGRAM CDR. FIN PU BHA & RIH ON HWDP CUT & SLIP 104' DRILLING LINE. ADJUST BRAKES PU BHA. TEST MWD OK. PU DP. Page 2 of 6 ------ ~ SUMMARY OF DAILY OPERATIONS FEBRUARY 13, 1996 FINISH PU DP. TAG FC @ 3989 CIR HOLE CLEAN. TEST CASING TO 3000 PSI F/30 MIN OK. DRILL FC, CEMENT, FS, CEMENT & 10' NEW HOLE. COND MUD TEST FORMATION TO 12.5# EMW OK. BALES LINK TILT TOO FAR. SWAP BALES SIDE TO SIDE. DRILLING F/411 0'-61 05' ART; 5 HOURS; AST; 6 HRS. EQUIPMENT REPAIR. DAY TOUR D2- DRILL; OS: 3.5 MIN. NIGHT TOUR D2 DRILL; OS: 3 MIN. CBU F/SHORT TRIP. FEBRUARY 14, 1996 MONITOR WELL - OK. PUMP DRY JOB BLOW DOWN MUD LINE. POH 20 STDS. TIGHT F/5731'-4215' CBU @ 4215' RIH 11 STDS HOLE PACKED OFF, FILL PIPE STD BACK 1 STD WASH & REAM F/5161 '-5732' RUN TO BOTTOM HOLE STICKY NO FILL. DRILLING F/61 05'-6176' ART: 5 HR. SHAKERS OVERLOADING PUMP LO- HI SWEEP CIRC HOLE CLEAN DRILLING F/6176'-7050' ART: 3 HRS; AST: 1.75 HRS H2S DRILL; OS: 4 MIN. PUMP LO-HI SWEEP CIRC HOLE CLEAN MONITOR WELL - OK PUMP DRY JOB 30 STD SHORT TRIP TO SHOE. RIH BRIDGE @ 6870' WASH TO 6955' RUN TO BOTTOM NO FILL. DRILLING F/7050'-7705'. ART: 1.5 HRS; AST: 3 HRS. FEBRUARY 15, 1996 DRILLING F/7705'-8085' ART: 1.25 HRS, AST: 1.5 HRS CIRC LO-HI SWEEP MONITOR WELL DRY JOB, BLOW DOWN LINES. SHORT TRIP TO 6861' NO FILL NO PROBLEMS. DRILLING F/8085'-9035' ART: 3.75 HRS; AST: 5.25 HRS. SPILL DRILL; OS: 3.5 MIN. CIRC LO-HI SWEEP MONITOR WELL DRY JOB, BLOW DOWN LINES. SHORT TRIP PUT TO 6800' PU 72 JTS S-135 DP NO FILL NO PROBLEMS. PU DP. DRILLING F/9035'-9295'. ART: .75 HRS; AST: 2 HRS. GRABBER ON TOP DRIVE LEAKING. CIRC LO-HI SWEEP. PREP TO POH TO SHOE. FEBRUARY 16, 1996 FINISH CIR SWEEP MONITOR WELL OK PUMP DRY JOB. POH TO CSG SHOE @ 4080' REPAIR GRABBER ON TOP DRIVE. CHANGE SAVER SUB. RIH 30 STDS. NO FILL NO PROBLEMS, DRILLING F/9295'-9790'. ART: 1.75 HRS; AST: 3.5 HRS. WASHED HOLE IN MUD LINE BETWEEN PUMPS. POH 20 STDS. REPAIR MUD LINE. TEST MUD LINE TO 3500 PSI OK RIH NO FILL NO PROBLEMS, MOTOR OVERPRESSURING WORK WITH SAME. MOTOR FAILED. CBU @ 66 SPM W/3000 PSI. MONITOR WELL. PUMP DRY JOB, BLOW DOWN LINES. POH FOR MOTOR. FEBRUARY 17,1996 FINISH POH WET. UNLOAD SOURCES. DOWNLOAD & LD MWD. CHANGE OUT BIT & MOTOR. CLEAN RIG FLOOR. MU BIT, MOTOR & MWD. ORIENT MWD PROGRAM MWD LOAD SOURCES TEST MWD @ HWDP. RIH BENCHMARK SURVEY @ 5354' RIH NO PROBLEMS - NO FILL. D1 DRILL; as: 3.5 MIN DRILLING F/9790'-10804' ART: 6.5 HRS; AST: 2.75 HRS. CIRC SWEEP F/SHORT TRIP. Page 3 of 6 ~--~. SUMMARY OF DAILY OPERATIONS FEBRUARY 18,1996 SHORT TRIP 12 STDS. NO FILL, NO PROBLEMS. DRILLING F/10804-11148'. ART: 7 HOURS; AST: 1.5 HRS. MONITOR WELL, OK. PUMP DRY JOB. POH F/BIT. MONITOR WELL @ SHOE, HWDP & DC'S PULL SOURCES. POH, BIT LOWER MOTOR HOUSING & ROTOR STILL IN HOLE. LD BHA SLIP & CUT 105' DRILLING LINE SERVICE WR. CALIPER 8-6 %" STEEL DC'S. WO TRISTATE. ~ - FEBRUARY 19, 1996 WO TRISTATE. CALIPER TOOL MU FTA #1 (4 1/8" GRAPPLE). RIH W/FTA #1 PU WT 260K; SO: 135K. STAB OVER FISH PULLED 10K OVER COMING OFF BOTTOM. DROP PUMP OUT SUB OPENING TOOL CIRC DOWN & SHEAR PORTS OPEN. FINISH CBU. TOF @ 11109'. MONITOR WELL OK. PUMP DRY JOB. POH SLOW, NO FISH, FISH HAD BEEN INSIDE OVERSHOT CLEAR FLOOR TO TEST BOPE. PULL WR SET TEST PLUG. TEST BOPE TO 250/5000 PSI; ANNULAR TO 250/3500. WITNESSING WAIVED BY DOUG AMOS AOGCC FIELD INSPECTOR. PULL TEST PLUG SET WEAR RING BLOW DOWN LINES D4 DRILL. MU FTA #2 (TANDEM GRAPPLE - 4" X 4 1/8") START RIH W/FTA #2. FEBRUARY 20, 1996 FINISH RIH W/FTA #2, TAG UP ON FISH @ 11109' WORK TANDEM GRAPPLE OVER FISH PUMP PRESS INCREASED 01 DRILL; OS: 4 MIN. DROP BALL ROD CIRC DOWN @ 6 BPM W/700 PSI WORK FISH & CBU MONITOR WELL. PUMP DRY JOB BLOW DOWN LINES. POH SLOW, MONITOR WELL @ SHOE & HWDP. RECOVERED FISH LD SAME LD FTA & DC'S D1 DRILL; OS: 4.5 MIN. MU BHA. BORIENT MWD. PROGRAM COR PULL JETS OUT OF BIT #3. CLEAN STATOR RUBBER OUT OF NOZZLES. INSTALL NOZZLES. MU BIT RIH MU & PROGRAM CON LOAD SOURCES. FIN PU BHA. TEST MWD. RIH NO PROBLEMS PRECAUTIONARY REAM F/11076'-11148' DRILLING F/11148-11177' ART: 1 HR. FEBRUARY 21, 1996 DRILLING F/11177-12020. ART: 5 HR LOST 143 BBLS. MONITOR WELL, STATIC. ATTEMPT TO CIRC @ REDUCED RATE, STILL LOSING. STAND BACK 1 STD. WORK PIPE WHILE BUILDING VOLUME & ADDING LCM (20 PPB) CUT WT TO 10.1 #. SPOT NEW MUD W/LCM AROUND TO SCHRADER BLUFF @ 3 BPM W/11 00 PSI LOSING APP 10 BPH. BLOW DOWN TIP DRIVE WORK PIPE WHILE BUILDING VOLUME ADDING LCM & CUTTING WT. CIRC @ 3 BPM TILL 10.1 # ALL AROUND. INCREASE RATE TO 4.4 BPM. LOSING MUD OVER SHAKERS DUE TO LCM, CUTTING LCM BACK LOST TOTAL OF 337 BBLS (67 BBLS SINCE MIDNIGHT). FEBRUARY 22, 1996 CIRCULATE WORK PIPE WAIT ON GUZZLES. START CIRCULATE @ 3 BPM, INCREASE RATE TO 10 BPM. 1700 PSI LOSS VARIED F/30 TO 150 BPH. AT LOW LOSS RATE ATTEMPTED TO DRILL DRILLED F/12040 TO 12085. LOSS INCREASED STOPPED DRILLING 100 SPM, 1770 PSI. CIRC MIX 140 BBL LCM SWEEP 15 PPB LIQ CASING 15 PPG BARACARB, 5 PPB OM SEAL. PUMP LCM Page 4 of 6 ----.~.~ SUMMARY OF DAILY OPERATIONS SWEEP CLEAN SUCTION SCREENS. WAIT ON ORDERS. CIRCULATE LCM SWEEP @ 4 BPM, 1120 PSI LOST 33 BBL. CIRCULATE @ 5 BPM, 1300 PSI, 2 BBL LOS/15 MIN 6 BPM, 1575 PSI11 BPM LOSS/15 MIN (0500-0600) MIX PILL. FEBRUARY 23, 1996 CIRCULATE @ BPM WHILE FINISH MIXING PILL LOSS RATE 30 BPH. SPOT 60 BBL PILL ON BTM. POOH TO 8340 SPOT LCM PILL @ 7340 TO 8340 PULL 12 STANDS, PUMP DRY JOB. POOH, WASTE MANAGEMENT SAFETY POOH LD BHA. CLEAN FLOOR. MU BHA, RIH, FILL PIPE & MONITOR WELL @ SHOE, CONTINUE RIH TAGGED BRIDGE @ 11422' MU TOP DRIVE WIPED OUT BRIDGE CIRCULATED TO 12086' CBU LOST 52 BBL ON TRIP IN, LOST 24 BBL WHILE CIRCULATING TO BOTTOM. FEBRUARY 24,1996 CIRC FOR 7' CASING. MONITOR WELL SPOT LCM PILL ON BOTTOM PUMP DRY JOB POOH TO RUN 7" CASING. POOH TO RUN 7" CASING MONITOR WELL @ SHOE LD BHA. CLEAN FLOOR, RIG UP TO RUN CASING PULL WR. RUN 7" CASING RUNNING SLOW TO KEEP LOSSES LOW, 135 JTS RU @ 0600. LOST 28 BBLS WHILE RUNNING CASING TILL 0600. FEBRUARY 25,1996 RUN 7" CASING SLOWED DOWN RUNNING CASING BECAUSE UNABLE TO GET CEMENT PUMP TRUCK TILL LATE AFTERNOON. TRUCK ARRIVED @ 1730. MADE UP CEMENT HEAD, TRIED TO WORK PIPE & BREAK CIRCULATION, COULD NOT DO EITHER ONE, LANDED CASING. WAIT ON ORDERS & VERIFICATION WHEN 2ND STAGE WOULD ARRIVE. DID FIRST STAGE CMT JOB AS PER PROGRAM. DID NOT BUMP W/CALCULATED STROKES, PUMPED 112 SHOE JT, DID NOT BUMP 2000 PSI ON GAGE. DISCUSSED OPTIONS, DECIDED TO WAIT ON CEMENT TO SET. RIG DOWN CMT HEAD, ELEVATORS, CHANGE BAILS RIG UP TO LAY DOWN DRILL PIPE. LD DRILL PIPE 220 JTS LD @ 0600 LOST 218 BBL MUD WHILE RUNNING CASING LOST 464 ON CMT JOB. FEBRUARY 26, 1996 LD 5" DRILL PIPE CHANGE TOP DRIVE OVER TO 3 112" CONNECTION. RIG UP HOWCO PRESSURE UP ON 7" CASING SHEARED CEMENTER W/3100 PSI PUMPED 9 BBLS WITH NO RETURNS CLOSED ANNULAR, REVERSED 4 BBLS, HAD RETURNS. PERFORM 2ND STAGE CEMENT JOB BUMPED PLUG CLOSED CEMENTER HELD 2500 PSI F/10 MIN BLED OFF LD CEMENT HD & LANDING JT. INSTALL 7" PACKOFF TEST PACKOFF W/5000 PSI/15 MIN. CHANGE BOTH SETS PIPE RAMS TO 3 112" LD PACKOFF RUNNING TOOL RIG UP & TEST BOPE CHOKE MANIFOLD, SAFETY VALVES & ACCUMULATOR INSTALL WR. PICK UP BHA, ANADRILL HAVING PROBLEM TALKING TO THEIR TOOL LEFT OUT MU BHA, HWDP, PCK UP 3 112" DP FROM PIPE SHED. Page 5 of 6 --....-."-, SUMMARY OF DAILY OPERATIONS FEBRUARY 27, 1996 PICK UP 3 Y2" DRILL PIPE FROM PIPE SHED. CUT & SLIP DRILLING LINE. PICK UP 3 Y2" DRILL PILE FROM SHED. TAG HES CEMENTER @ 9164. CIRCULATE DRILL PIPE VOLUME DRILL PLUG & CEMENTER. TEST CASING W/3500 PSI. PICK UP 3 Y2" DRILL PIPE FROM SHED TAGGED CMT @ 9399 CLEAN OUT CMT STRINGER F/9399 TO 9430 PICK UP 3 Y2" DRILL PILE FROM SHED. TAGGED CMT @ 11940 DRILL CEMENT TO 11980' CIRCULATE. TEST CASING W/3500 PSI 0 LOSS. DRILL 30' CMT, BAFFLE COLLAR CMT, FLOAT COLLAR @ 12022' DRILL SHOE @ 12066'. FEBRUARY 28, 1996 CIRCULATE & CONDITION MUD FOR FIT. PERFORM FIT TEST, 10.3 MW, 7470 TVD, 11.74 EMW. DRILL F/12096 TO 12218' CHECK FOR FLOW. SAFETY MEETING DRILL F/12218 TO 12584'. PUMP SWEEP CIRCULATE HOLE CLEAN. FEBRUARY 29, 1996 PUMP SWEEP MONITOR WELL, POOH MONITOR WELL @ SHOE, CONTINUE POOH. LD BHA TO MWD, LD MWD, LD REST OF BHA. CLEAR & CLEAN UP FLOOR. MAKE UP MULE SHOE, RIH TO 11806. RIH W/SINGLES TO 12585. CBU, CHANGE BAILS & ELEVATORS ON TOP DRIVE MIX & PUMP 32 BBL BALANCED PLUG ON BOTTOM. POOH. MARCH 01, 1996 RIH TO 4200 TEST BOTTOM CMT PLUG W/2000 PSI F/30 MIN 0 PSI LOSS. SET BRIDGE PLUG @ 4200 HOOK UP LINE & CIRCULATE SET CMT PLUG #2 POOH TO 2200 SLOW WET. CIRCULATE FREEZE PROTECT 7" CASING POOH LD BP RUNNING TOOL. CHANGE BOTH SETS PIPE RAMS TO 5" RIG DOWN RISER, FLOWLINE, CHOKE & KILL LINE & MOUSE HOLE. ND BOP'S PUSH PLUG TO 250' PUMP CMT PLUG F/250 TO 5' BELOW TUNDRA. NU DRY HOLE TREE. TAKE DOWN TOP DRIVE ROTARY HOSE. LD DRILL PIPE. MARCH 02, 1996 LD 3 Y2" DP. CLEAN UP RIG FLOOR REMOVE ELEVATORS & BAILS F/TOP DRIVE. BRING TOP DRIVE CARRIER TO RIG FLOOR. RIG DOWN TOP DRIVE, SET IN CARRIER & SET OUT OF WAY. RIG DOWN SWIVEL. RD TOP DRIVE EXTENSION SECTION. SEND SWIVEL OUTSIDE RIG UP HOOK. TAKE TOP DRIVE RAIL & TORQUE BEAM DOWN FROM DERRICK. PREP TOP DRIVE HYDRAULIC LINES & SPOOLING UNIT SPOOL LINES ON REEL. MARCH 03, 1996 7" CASING WAS FREEZE PROTECTED W/DIESEL FROM 2000' TO 250 A 7" WIPER PLUG WAS PUSHED TO 250' TO KEEP CEMENT & DIESEL FROM SWAPPING PLACE. FINISH REELING UP TOP DRIVE HYDRAULIC HOSES. RIG RELEASED @ 0900. Page 6 of 6 PAGE HO. 1 ~- qro . w 7 *********************************************************** ********* **** * **** * ********* ANADRILL ********** ********* SCHLUMBERGER ********** ********* ********** *********************************************************** *********** SURVEY PROGRÅM *********** COJ1PANY BP WELL NAME B24 LOCATION 1 MILNE PT LOCATION 2 ALASKA MAGNETIC DECLINATION 27.76 GRID COtMRGENCE ANGLE 0 .00 DATE: 7-FEB-96 API t-UMBER 50-029-22642 JOB Hl~ER 37722 WELL HUMBER B-24 WELL HEAD LOCATIOH~ LAT(NJ-S} 0.00 DEP<E/ -\.) ORIGINAL 0.00 AZIMUiH FF:OM ROTARY TABLE TO TAf\'GET IS 41.53 TIE IN F~INT(TIP) ~ I'ŒASœED DEPTH TRUE VERT DEPTH INCLINATION AZI MUTH LATITUDE(N/ -5) DEPARTURE (E!-W) 112.00 112.-00 0.00 0.00 0.00 0.00 ~ r-HU-t f1U. L .... /~.' f **H*h1':***** ANADRILL ************** 9JRVEY CALCULATIONS ************* CIRCULAR ARC METHOD******** MEASURED INTERVÄL V~1ICAL TAf\'GET STATIOH AI I MUTH LATITUDE DEPARTURE DISF'LACEMOO at AZIMUTH DLS DEr'TH DEPTH SECTIOH I He HI. HI-S Ef-\J deç! ft ft ft ft de<! dea ft ft ft deq 100ft 112.00 0.0 112.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 238.51 126.5 238.51 0.10 0.09 42.81 0.07 0.07 0.10 42,81 1).1)7 328.24 89.7 328.24 0.13 0.09 165.90 0.06 0.13 0.14 t,7.01 0\18 417.05 88.8 417.04 0.13 0.12 336~91 0.07 0.11 0.14 57.61 0.23 504.33 87.3 504.33 0.39 0.31 62.83 0.26 0.29 0.39 47.70 0.37 593.29 89.0 5'13.28 1.54 1.21 51.76 0.95 1.24 1.57 52.43 1.02 682.36 89.1 682.31 4.22 2.33 55.34 2.57 3.47 4.32 53.50 1.26 773.19 90.8 773.04 8.47 3.09' 42.77 5.42 6.65 8.58 50.85 1.06 867.67 94.5 M7.31 14.66 4.43 38.73 10.14 10.67 14.72 %.47 1.44 961 .90 94.2 961.16 23.01 5.74 41.83 16.49 16.09 23.03 44.30 1.42 1055.02 93.1 1053.66 33.79 7.56 41.36 24.55 23.24 33.81 43.43 1.95 1149.80 94.8 1147.40 47.76 9/39 40.83 35.08 32.42 47.77 42.74 1.94 1245.04 95.2 1241.02 65.16 11.67 42.59 48.06 44.02 65.17 42.49 2.42 1338.44 93.4 1332.00 86 .'27 14.49 45.43 63.22 58.74 86.30 42.90 3.09 1432.22 93.8 1422.24 111.68 17.04 45.39 81.10 76.88 111. 75 43.47 2.72 1527.75 95.5 1512.71 142.25 20.36 44.69 102.75 98.54 142.36 43.80 3.48 1620.43 92.7 1598.72 176.1:8 23.39 46.06 126.98 123.13 176.87 44.12 3.31 1712.1'1 91.8 1682.49 214.08 24.78 42.54 153.79 149.24 214,30 44.14 2.18 1805.23 93.0 1767.01 252.97 24.65 39.08 183.23 174.66 253. 14 4'" ¡"'" 1.56 ,J. 0',) 1901.47 96.2 1854.84 m.25 23.59 38.46 213.89 199.29 292.34 42,98 1.14 1996.42 95.0 1941.73 330.48 23.98 38.30 243.90 223.07 330.53 42.~5 0.42 2009.M 93.2 2026.69 368.81 24.63 40.26 273.59 247.36 368.83 42.12 1.11 2187.55 97.9 2115.03 4-11.03 26.46" . 41.19 305.58 274.91 411.04 41. 98 1.92 2278.16 90.6 2195.75 452.18 27.57 41.91 336.37 302.21 452.L\) 41. 94 1.27 2371.79 93.6 2277.83 497.21 29.93 42.93 369.61 332.60 497.23 41.98 2.58 2463.71 91.9 '71'356 81", 544.L\; 31.58 43.6e, 403.81 364.85 544.22 42,10 1..34 i.", . l. 2559.03 95.3 2437.13 595.49 33.59 43.8~: 440.89 400.35 595 .53 42.24 2.11 2654.06 95.0 2515.02 649.88 36.29 43.54 480.25 437.94 .649.94 42.36 2.85 2748.01 93.9 2589.02 707.73 39.76 41.64 522.87 477.07 707.80 42.38 3.89 2841.20 93.2 2659.21 769.00 42.49 42.36 568.41 518.08 769.08 42.35 2.98 2934.70 93.5 2727.09 833.31 44.41 41.62 616.21 561.09 833.38 42.32 2.12 3028.80 94.1 2793.17 900.26 46.36 43.75 665.42 606.51 900.35 42.35 2.63 3125.11 96.3 2857" 87 971.53 49.22 44.00 716.84 655.95 971.66 42.46 2.97 3220.28 95.2 2918.10 1045.13 52.24 44.23 . 769.73 707.23 1045.31 42.58 3.18 3315.53 95.3 2974.91 1121.52 54.53 43.41 824.90 760.15 1121.74 42.bh 2.49 3412.10 96.6 3029.22 1201.35 57.03 41.85 883.66 814.22 1201.58 42.66 2.91 3504.17 92.1 3078.05 1279.4() 58.91 41.47 941.97 866.10 1279.62 42.60 2.07 '3599.70 95.5 3125.19 1362.47 61.94 41.68 1004.11 921.23 1362.68 42.54 3.18 3697.22 97.5 3172.00 1448.01 /;IJ.67 41.25 1068.21 977.88 1448.21 42.47 1.36 3790.21 93.0 3215.79 1530.04 63.14 41.21 1129 .90 1031.93 1530.22 42.41 2.65 . PAGE NO. 3 ~ H*********** ANADRILL ************** SUI\'VEY CALCULA TI OMS ************* CIRCULAR ARC METHOD******** MEASURED INTERVAL VERTICAL TARGET STATION AZII'UTH LATITUDE DEPARTURE DISPLACEMENT at AZIMUTH DLS DEPTH DEPTH SECTION lHeLM. H/-S E/-W d e<1/ ft ft ft ft deq deG ft ft ft de<:! 100ft 3886.45 96.2 3"'66.17 1617.38 67 .23 41.93 1195.24 1089.e9 1617.55 42,36 4.31 3982.3H 95.9 3292.18 1706.2'1 68.67 41.42 1261.65 1149.01 1706.45 42.32 LS"ì 4038.45 56.1 3312.52 1758.54 68.81 41.15 1300.92 1183.49 1758.70 42.29 0.52 4117.97 79.5 3342.M 1832.11 66.60 42.11 1355. '7'1 1232.36 1832.27 42.27 3.00 4213.32 95.4 33ßO.96 1919.43 66.06 42.73 1420.38 1291.27 1919.59 42.27 0.82 4306.23 92.9 3418.48 2004.42 66.31 41.72 1483.32 1348.3'1 2004.59 42.27 1.03 4402 .03 95.8 3457 .90 2091.73 65.10 42.53 1548.08 1406.95 ~91.90 42.27 1.47 4499.00 97.0 3497.81 2180.09 66.29 42.58 1613.18 1%6.72 2180.27 42.28 1.23 4591.71 92.7 3533.70 2265.56 68.15 41.54 1676.64 1523.97 2265.75 42.v 2.26 4687.25 95.5 35M.S1 2354.53 69.11 41.40 1743.30 1582.89 2354.71 42.24 1.01 4782.57 95.3 3601.26 2444.04 70.69 40.59 1810.87 1641.61 2444.20 42.19 1.ß4 4877.67 95.1 3632.61 2533.81 70.82 40.72 1878.98 1700.11 2533.96 42.14 0.18 4973.92 96.3 3663.03 2625.13 72.34 41.89 1947.58 1760.38 2625 . 26 42.11 1.95 5065.45 91.5 3689.42 2712.76 74.15 41.24 2013.15 1818.52 2712.89 42.09 2.09 5161.09 95A ')"'1'" 68 2804.13 71.46 41.53 2081.69 1878.93 2804 t 25 42,07 2.82 . - 'oJ!!' 5258.05 97.0 3749.21 2895.81 70.59 41.50 2150.34 1939.70 2895.93 42.05 0.91 5354.12 96.1 3779.56 2986.96 72.'51 41.29 2218.72 1999.97 2987.07 42.03 2 . l).e 5449.48 95.4 3807.94 3077.9'1 72.80 40.66 2287.46 2059.67 3078.10 42.00 0.68 5542.93 93.4 3835 . 06 3167.39 73.46 39.59 2355.84 2117.30 3167.48 41.95 1.30 5637.38 94.4 3861.24 3258 . 04 74.36 38 I Ci9 2426.52 2174.20 3258. O'i 41. 86 LBO '5129.68 92.3 3885.94 3346.90 74.60 40.30 2495.44 2230.40 3346.93 41.79 2.33 5824.99 95.3 3911.20 3438.78 74.66 41.13 2565.10 2290.34 3438.81 41.76 0.84 5917.46 92.5 3936.14 3527.81 74.05 40.01 2632.73 2348.26 3527 .83 41.73 1.33 bOO9 . 64 92.2 3961.36 3616.4-' 74.19 41.48 2699 .90 2406.13 3616.48 41.71 1.54 6103.99 94.4 3986.57 3707.38 74.83 40.52 2768.52 2465.78 3707.'39 41.69 1.20 6197.03 93.0 4011 .61 3796.98 73.95 41.86 2835.95 2524.78 3796.99 41.68 1.68 6291.17 94.1 4038.53 3887.18 72.82 42.03 2903.05 2585.08 3e,~7.20 41.68 1.21 6386.48 95.3 4067.39 3978.02 71.93 42.10 2970.48 2645.94 3978.03 41.69 0.93 6477.80 91.3 4095 . 65 4064.84 72.02 43.26 3034.32 2704.81 4064.86 41.71 1.21 6574.94 97.1 4125.82 4157.07 71.79 45.04 3100.57 2769.12 4157.11 41.77 1.76 6MB.22 93.3 4156.03 4245.13 70.41 45.40 3162.72 2831.76 4245.19 41.M 1.52 6766.10 97.9 4189.28 4337.00 69.88 45.19 3?27.49 2897 .19 4337.09 41.91 O.~ 6857 . 83 91.7 4220.94 4422.88 69.73 45.78 3287.84 2958.58 4423.02 41. 98 0.62 b954.27 96.4 4254.35 4513.11 69.73 45.72 3350.97 3023.38 4513.30 42.06 0.05 7047.26 93.0 4285.78 4600.49 70.76 43.50 3413.27 3084.84 4bOO.7! 42.11 2.50 7141.54 94.3 4316.59 4689.54 71.09 43.27 3478.03 3146.04 4689.80 42.13 0.42 7232.60 91.1 4345.52 4775.87 71.87 42.28 3541.40 3204.68 4776.14 42.14 1.35 7328.18 95.6 - 4374.75 486ó.85 72.51 42.94 3608.38 3266.29 4867.14 42.15 0.94 7422.34 94.2 4403.05 4956.64 72.51 42.57 3674.32 3327.25 4956.94 42.16 0.38 7516.57 94.2 4431.44 5046 . 48 72.43 42.40 3740.59 3387.94 5046.79 42.17 0.19 r, r'ffist NU. 4 ~-- '\. ~\ - -,. ******~~***** AHADRILL *~********** SUh'VEY CALCIJLÅ TI (}IS ************* CIRCULAR Afit METHOD******** MEASlJ<ED IHTERVAL VERTICAL TAt\'GET STATION AZIMUTH LATITUDE DEPARTURE DISPLACEMENT at AZIMH DLS DEPTH DEPTH SECTION IHCLH. N/-S E/-W deç/ ft ft ft tt deq deo ft ft ft deg 100ft 7611.02 94.4 4459.66 5136.61 72.81 41.29 3807.73 3448.07 5136.92 42.16 1.19 7706.92 95.9 4488.15 5228.18 72.63 40.78 3876.80 3ÝJ8.19 5228.48 42.14 0.54 7801.18 94.3 4515.99 5318.22 73.02 43.16 3943.75 3568.41 5318.52 42.14 2.45 7895.80 94.6 4543.79 5408.63 72.81 42.80 4009.91 3630.06 5408.95 42.15 0.43 7989.98 94.2 4571.53 5498.62 72.93 42.08 4076.33 3690.80 5498.95 42.16 0.75 8082.90 92.9 4599.30 5587.26 72.30 44.20 4141.04 3751.43 5587.62 42.17 2.29 8177.75 94.9 4627.93 5677.64 72.57 42.48 4206.80 3813.50 5678.02 42.19 1.75 8271.26 93.5 4657.295766.40 70.83 43.20 4271.90 3873.M 5766.79 42.20 2.00 8368.08 96.8 4689.40 5857.69 70.43 43.15 4338.50 393b.35 5858.11 42.22 0.41 8462.45 94.4 4720.94 5946.60 70.51 42.92 4403.52 3997.05 5947.05 42.23 0.24 8559.19 96.7 4754.07 6037.44 69.44 44.20 4469.38 4059.69 6037.91 42.25 1.67 8653.75 94.6 4788.24 6125.53 68.20 43.66 4532.88 4120.86 6126.05 42.27 1.42 8747.88 94.1 4824.26 6212.43 66.80 43.73 4595.76 4180.93 6212.98 42.29 1.49 8843.52 95.6 4863.63 6299.52 64.58 43.67 4658.76 4241.14 6300.10 42.31 2.33 8939.03 95.5 4906.58 6384.77 61.97 43.29 4720.66 42'19.83 6385.39 42.33 2.75 9010.03 71.0 4940.93 6446.89 60.16 41.62 4766.50 4341.77 6447.52 42,33 3.28 9103.06 93.0 4988.90 6526.59 57.76 42.22 4825.81 4115.02 6527.22 42.33 2.64 9198.18 95.1 5041.11 6606.09 55.66 42.88 4884.38 4448.79 6606.73 42,33 2,28 9289.52 91.3 5094.32 b680.28 53.07 43.32 4938.58 4499.50 6680.94 42.34 2.86 -' 9382.81 93.3 5153.01 6752.76 48.96 41.19 4992.20 4548.26 6753.43 42,34 4.ì5 9474.58 91.8 5215.74 6819.71 44.77 41.96 5042.30 4592.68 6820.38 42.33 4.61 9569.49 94.9 5284.32 6885.31 42.70 42.99 5090.70 4636.97 6885.99 42.33 2.31 9662.74 93.3 5353.57 6947.73 41.38 43.48 512h.20 4679.75 6948.42 42.34 1,46 9756.43 93.7 5425.10 7008.19 39.06 43.73 5180.01 4721.46 7008.90 42.35 2.49 9849.42 93.0 5499.60 7063.76 34.45 38.22 5221.87 4758.01 7~~4.47 42.34 6.09 9947.44 98.0 5581.90 7116.86 31.34 36.67 5264.12 4790.40 7117.51 42,30 3.28 10042.63 95.2 5b63.3ß 7165.90 30.93 36.42 5303.66 4819.71 - 7166.48 42.26 0.45 10137.29 94.7 5744.76 7213.99 30.51 34.61 5343.02 4847.81 7214.50 42.22 1.07 10231.74 94.5 5826.27 7261.38 30.17 35.22 5382.14 4875.12 7261.83 42.17 0.48 10328.36 96.6 5909.89 7309.49 29.96 35.23 5421.69 4903.04 7309 .89 42.12 0.22 10422.79 94.4 5991.75 7356.24 29.82 34.67 5460.26 4930.00 7356.58 42.08 0.33 10516.99 94.2 6073.57 7402.55 29.bO 33.79 5498.85 4956.26 7402.83 42.03 0.52 10612.88 95.9 6157.17 7449.04 29.06 32.96 5538.07 4982.10 7449.26 41.97 0.70 10708.42 95.5 6240.52 7495.46 29 .49 37.70 5576.15 5009.11 7495.64 41. 93 2.47 10801.76 93.3 6321.90 7541.06 29.17 37.39 5612.40 5036.97 7541.23 41.91 0.38 10896.94 'is.2 6405.25 75ß6.81 28.56 35.08 5649.45 5064.14 7586.95 41.87 1.33 10992.90 96.0 6489.82 7631.87 'll .82 35.35 5686.49 5090.28 7631.98 41.83 0.78 11086.31 93.4 6571.75 7676.45 29.59 34.73 5723.22 5116.03 7676.53 41.79 1.91 11182.63 96.3 6654.89 7724.60 31.08 32.28 5763.79 5142.86 7724.65 41.74 2.01 11278.12 95.5 6736.88 7772.85 30.60 31.48 5805.35 5168.71 7772.M 41.68 0.66 ~- PAGE NO. 5 -.- - i F- ******1I:H**** AHADR I LL ************** SUf\'VEY CALŒJLATIOHS ************* CIRCULAR ARC METHOD******** 11 EASUR ED IHTEh'VAL VERTICAL TARGET STATION AZIItfTH LATITUDE DEPARTURE DISPl.AC~T at AZIMUTH DLS DEPTH DEPTH SECTION lMelli. H/-S E/-W de<1/ ft ft ft ft de<] de<] ft ft ft d~ 100ft 11372.07 93.9 6818.01 7819.49 29 .96 31 .32 5845.79 5193.39 7819.50 41.62 0.68 11467.85 95.8 6901.41 7865.81 28.93 31.01 5886 . 08 5217.77 7865.81 41.56 1.09 11559.79 91.9 6982.17 7908.94 28.17 'li . 97 5923.94 5240.07 7908.94 41.49 0.99 11655.22 95.4 70/:.6.75 7952.15 27.02 28.70 5962.47 5261.73 7952.16 41.43 1.35 11752.14 96.9 7153.63 ' 7993.95 25.59 27 . 89 6000.28 5282.09 7993.99 41.36 1.52 11844.67 92.5 7237.68 8031.48 23.83 27 . 16 6034.58 5299.97 8031.55 - 41.29 1.92 11 r,39 . 29 94.6 7324.86 8066.93 21.92 24.91 6067.61 5316.14 M67.04 41.22 2.22 12113.80 174.5 7487.57 8128.09 20.48 30.22 6123.54 5345.23 8128.30 41.12 1.38 '12208.40 94.6 7576.~ 8160.35 19.95 34.97 6151.07 5362.81 8160.60 41.08 1.82 - 12301.10 92.7 76/:.3 . b4 8191.47 19.41 40.86 6175.68 5381.95 8191.73 41.07 2.22 12392.39 91.3 7750.03 8220.96 18.29 43.31 6197.58 5401.70 8221.21 41.07 1.50 12486.30. 93.9 7839.78 8248.56 15.94 44.64 6217.48 5420.87 8248.81 41.08 2.54 12499.10 12.8 7852.10 8252.03 15.61 46.91 6219.91 5423.37 8252.28 41.09 5.47 * ****** * ***** *** *** * ** ** ***** *** * **** *** JH PROJECTED TO TD * *** ìt **** ***** ******* *** * * *** **** *** * u** ***It ** * ** ** * H 12584.00 84.9 7933.87 8274.78 15.61 46.91 6235.51 5440.05 8275.01 41.10 0.00 ************ **************** " :," "':':I¿" "", BP EXPLORATION, Alaska ENTER Attn: Howard Okland Alaska Oil and Gas Conservation Commission (907) 279-1433 Date: Trans# 06/11/97 87127 CONFIDENTIAL DATA MilNE POINT UNIT / MPB-24 ( \ Well Rec Type Date Jobld Company Comments MPB-24 OH 02/22/96 SCH CON (MD) RUN DATES 02/11-22/96, COMPOSITE RUNS - TIGHT HOLE MPB-24 OH 02/22/96 SCH CON (TVD) RUN DATES 02/11-22/96, COMPOSITE RUNS - TIGHHOLE MPB-24 OH 02/22/96 SCH COR (MD) RUN DATES 02/11-22/96, COMPOSITE RUNS - TIGHTHOLE MPB-24 OH 02/22/96 SCH COR (TVD) RUN DATES 02/11-22/96, COMPOSITE RUNS -TIGHTHOLE MPB-24 OH 02/28/96 SCH ARCS (MD) MPB-24 OH 02/28/96 SCH ARCS (TVD) ,MPB-24 MWD 02/28/96 37722 ANA MWD DIRECTIONAL SURVEY ¡MPB-24 DISK 02/22/96 ANA 1 EA. IBM FORMATTED 3.511 DISKETTE: (LIS FORMAT) - COR/CON/ARCS MPB-24 APPL 03/01/96 9600090 BPX SUSPEND NOTICE - PLUG BACK FOR POSSIBLE SIDETRACK & WELL PLAN ADDENDUM #1 Enclosed are the materials listed above. If you have any questions please contact me at (907) 564-5929. ~ Received By: David W. Douglas :;"'; r~ " !."~ "j k: ,I i :,L,é !è!~' "", Petrotechnical Data Center, MB3-3 900 East Benson Boulevard, P.O. Box 196612, Anchorage, Alaska 99519-6612 ,", i\f,\] '1 'j T~¡9'( Þ,', ~::;¡,:;',?',,\:Jji!¡)'!¡ J:, ~';¡as COlas. C~)J~miÌ\$$\\; -,\l""L""",\i~~nl),~,....."" ' I'~"""":!:;""~"""~ , "\ ¡"'f"j:, "~"(',', 1,"'" :¡ì"I)h,lh",,-rn;/)þ:,i ;::":,',,,1 ,~ " hared BlVlces rliling TO: Blair Wondzell FROM: Chris West DATE: October 27, 1995 SUBJECT: MPB-24 Well Suspension API # 50-029-22642 Blair; Please find attached a copy of the Form 10-403 to temporarily suspend this well as per AOGCC 20- AAC 25.110. As discussed this morning we propose setting three plugs in this well as detailed in the attached form. This will allow us to retain the wellbore for potential future sidetrack or service well use. We would like to keep the well's 9-5/811 x 711 annulus available for the injection of liquid wastes. There are no other well annulii on this pad for injection. The annulus for MPB-24 was approved for injection as part of the permit dated 25 January 1996. The annulus will be freeze protected before moving the rig. Thank you for your help in this matter. Please call me if I may be of any assistance. Chris West Drilling Operations Engineer Nabors 27E (907)-564-5089 ~~ ~.~ r "t\vt::.D U "'" \\..= V fE8 2 B 1996 I O~\ & G', ~c Cons. Comm!ssion A\:-:<:'.;t~:! luv , ",,~"V' ,~nGllClraBe ------ -, - " ' STATE OF ALASKA ALA~¡V\ OIL AND GAS CONSERVATION COMMISSIL APPLICATION FOR SUNDRY APPROVALS Type of Request: Abandon - Suspend ..x...- Operation Shutdown - Re-enter suspended well - Alter casing - Repair well - Plugging - Time extension - Stimulate - Change approved program - Pull tubing - Variance - Perforate - Other - 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 827' NSL, 4289' WEL, SEC. 18, T13N, R11E At top of productive interval 1685' NSL, 4099' WEL, SEC. 8, T13N, R11E At effective depth 5. Type of Well: Development ..x...- Exploratory - Stratigraphic - Service - ORIGINAL At total depth 1829' NSL, 3971' WEL, SEC. 8, T13N, R11E 12. Present well condition summary Total depth: measured true vertical 12584' feet feet Plugs (measured) Effective depth: Junk (measured) measured true vertical feet feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Size Cemented Length 20" 250 sx Arcticset I (Approx.) 110' 4080' 12036' 9-5/8" 800 sx PF 'F. 250 sx 'G'. 250 $X PF 'C' 7" 226 sx 'G~ 169 sx 'G' measu red true vertical Tubing (size, grade, and measured depth) 6. Datum elevation (DF or KB) KBE = 46 feet 7. Unit or Property name Milne Point Unit 8. Well number MPB-24 9. Permit number 96-009 10. API number 50- 029-22642 11. Field/Pool Milne Point/Kuparuk River Measured depth True vertical depth 110' 4080' 12066' 110' 3320' 7464' ~t:.L;t:.I\It:D FE8 23 1996 Packers and SSSV (type and measured depth) AJaska Oil & Gas Cons. Commission Anchorage Detailed operations program - BOP sketch - 13. Attachments Description summary of proposal --X...- Plugs will be set per attached sheet 14. Estimated date for commencing operation 02/28/96 16. If proposal was verbally approved 15. Status of well classification as: Oil- Name of approver Blair Wondzell 02/28/96 Date approved Service 17. I hereby c~fy that thelforego¡n: Jj ,- true and correct to the best of my knowledge. Signed "1L/'n ~ ~ /J~i)U Title Senior Drilling Engineer 1/ FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity ý BOP Test - Location clearance /' Mechanical Integrity Test - Subsequent form required 10- t1 0 7 Origine' Signed By Davia VV. Johnston Approved by order of the Commission Form 10-403 Rev 06/15/88 Gas- Suspended ~ Date 2/29A6. Approval No. f? -- ..pd)-- APproved ( -.nu , r..J Retjlirned 3/5 Fì t., -- /- Commissioner Òate 3 /1 lei ~ SUBMIT IN TRIPLICATE f( ~, -, '~----, lM]~ [IDQ~~ \YM~lblb ~lb£[M £[Q)[Q)~[M[Q)(W[M] ~í] order of importance: The PRIORITIES for this work are in the following 1. ZERO ACCIDENTS 2 . ZERO SPILLS 3 . NO POLICY OR REGULATORY VIOLATIONS 4 . MEET or EXCEED COST AND QUALITY TARGETS Let's ensure our op'erations are SAFE with STOP, Team Work, and Pre-Planning. ~~ - --~~ ¡/.i$ 7' ç.. DE Date API# 50-029-22642 ~~~..&J~ .?M6 DES -=--~'-r~ Date PAGE 1 ------------------ FS Date 'f<..t:. \.Î t:. \ ~ ¿ 0 t t. '0 ~ 'ò \~~'ò Co~{{~~\o'{\ .~ &. Ga.~ Co~S' ~a.s~ ~ þS\~~o~'ò~e February 28, 1996 ,---'- -- -~, MPB-24 ADDENDUM 2 Proposed Summary of Operations from Recommended practices Ver 3.2 1 . Run in with 3.5" open ended drill pipe and circulate hole volume. 2. Pump 5 BBL freshwater spacer. Test lines to 3000 PSI. Pump an additional 10 BBL FW spacer. This will not underbalance the well. 3. Pump cement volume for plug 1 as per attached balanced plug worksheet. The calcluated dispacement is to balance the plug, then pull the drillpipe out of the plug at 1 minute per stand. 4. Pull DP 12 stands above cement top and check for flow. POOH to surface. 5. Pressure test first plug to :t 250 PSI over leak off. Leak off pressure for 7" shoe was :t 559 PSI, test plug to 800 PSI. 6. Pick up a 7" cement retainer for second plug and set at 4200 feet. 7. Pump cement volume for plug 2 as per attached balanced plug worksheet. The calcluated dispacement is to balance the plug, then pull the drillpipe out of the plug at 1 minute per stand. 8. Pull DP 12 stands above cement top and check for flow. POOH to surface. 9. Pump cement volumefor plug 3 as per attached balanced plug worksheet. The calcluated dispacement is to balance the plug, then pull the drillpipe out of the plug at 1 minute per stand. The top of the third plug should set cement to 5 feet below tundra level. 10. ND BOP and set Dry hole tree. Test tree as per recommeded practices. 11 . Freeze protect annulus 12. RDMO to MPK-17. Pull out of cement at 1 minute per stand. Do not down squeeze cement in the 9-5/8" x 7" casing annulus at this time. Batch mix all cement plugs ~ t:. \.Í t:'- \ '\l ¿ 0 'Î' \-..I?> '2. i) \ Cj <:\ \j co~{(\\SS\Of\ '\ CI, r'-~s Con~' /I. \ as,,-'é'. tJ\\ t:Io \."J~ t"ol þ.r\c'ç\o~a.91f} API# 50-029-22642 PAGE 2 February 28, 1996 ~, -....., Milne Point Balanced Cement Plug Calculations I Well I MPB-24 Drill Pipe Size ~ Drill Pipe Cap 0.0417 ft^3/ft DP - Ann Volume 0.148Ift^3/ft Cement is Class G with CFA3 and HAS as required Hole Size 6 Casing Size 0 BPF 0.0350 BPF + 30% I 0.04551 Plug 1 Plug of Top Bottom of Plug 11800 -1.-2'500 1 551 sx 85.84~ ! I ----. 6 0 0.0350 0.0455 I I Plug 2 l Plug of Top - , ,: : fQpo Bottom of Plug --".., ,4:'2:'OP Set Cement retainer at 4200 Total G ST1 Displacement to Plug Top Pull out at 1 minute per stand i J Cement is TY.Qe C Permafrost Total G ST1 Displacement to Plug Top Pull out at 1 minute per stand Cement is Class G with 2% CaCI2 Hole Size Casing Size BPF BPF + 30% 441sx 29. 1 91 BBL Hole Size Casing Size BPF BPF + 300/0 i I I 61 ----. 0 0.0350 0.04551 I Cement Plugs BBLS 32 BBLS 9 BBLS 9 Cement Plug Slurry I ¡ I Î Cu. Ft. 179 -- - ~- Yield 1.15 I I Sacks 155 Top of Cemen Calculated 11800 9421 Feet Balanced Cement Plug Slurry Cu. Ft. 51 Yield 1.15 Sacks 44 Top of Cemen Calculated 4000 269 ] Feet Balanced I í I I Cement Plug Slurry Cu. Ft. 51 Plug 3 Plug of Top' 50 Bottom of Plug - ':250 Cement top is to original ground tundra level, and not to the wellhead. Total G ST1 I 54 sx Displacement to Plug Top -0.141 BBL Pull out at 1 minute per stand I Page 1 Yield 0.95 Sacks 54 0 Top of Cemen Calculated 50 2691 Feet Balanced i't:.\Vt:.\ V¿O t t. ß '2. CO ,~~G 0.\ &. ~<:\s cons COf{\m\!)s\ot\ t-.\as~a h \,;1'" . p.nc'r\orage r=-- 20" 91#/ft K-55 KOP @ 500' Max. Hole Angle 74.66° at 5824' MD 95/8",47 #/ft, NT -80S BTC / 80' I I 4050' I - OUTER ANNULUS IS CEMENTED. M P 8-24 Note that this well was originally drilled fro an ice pad 4/94 and designated as No Point #1 It was a delineation well for the NW Milne 10.1 PPG area Drilling Fluid 7" 29#, NT-80S BTC 6" hole TO DATE 2/28/96 REV,BY CRW I 12066 12584' I COMMENTS Pre Plug Setting operations MILNE POINT UNIT WELL 8-24 API NO: 50-029-22642 BP EXPLORATION (AK) Kt:L;t:\Vt:O fEB 2 Q '\996 . G f: Cons. Comffi\!Js\on AlasKa 01\ & a;;¡ AAcnorage 1/ 20" 91#/ft K-55 KOP @ 500' Max. Hole Angle 74.66° at 5824' MD 80' 95/8",47 #/ft, NT-80S BTC I 4050' I - OUTER ANNULUS IS CEMENTED. ,-=--, -', MP 8-24 ........ ..................... ............... ............................. ............... ............................ . ............... ............................. .........".... ........................... .. ............... ............................. ............... .. . .. .. . . . . . ... . . . .. . .. . .. . .. ............... .....,....................... ............... ............................ . ............... ............................. ............... ............................. ."............ .............. ..... .................,..... .............. ....,..................... .. .............. ............................ .............. .................. .......... .............. ............................ .............. ............................ .............. ............................ ..........".. . . . . . . . . .. ... . . . .. .. . . . .. . . . ..".......... ............................ .............. ............................ .............. ............................ Note that this well was originally drilled fro an ice pad 4/94 and designated as No Point #1 It was a delineation well for the NW Milne 10.1 PPG area Drilling Fluid 7" 29#, NT-80S BTC I 12066 6" hole TO 12584' I ........... ................. .............. .. ......... ....... .......... .............. ............................ .............. ....."................... .. .............. ..."..................... .. .............. ........... ................. .............. ............ ................ .............. . . . .. .. . . . . . . . . .. . . . . .. ... . . .............. .. .......................... .............. .........................,.. .............. ........................., .. .............. ",,' ,-"":""",,,"'Æ""""L",:':"""", DATE 2/28/96 REV, BY CRW COMMENTS Post Plug Setting operations Plug 3 5 feet below tundra - 250 I MD Plug 2 4000 - 4200' MD Cement Retainer @ 4200 Plug 1 11800 -12500 MD This plug will be pressure tested to :t '-256- PSI above the LOT. ;2 {) Oc.) CW/ t$W MILNE POINT UNIT WELL 8-24 API NO: 50-029-22642 BP EXPLORATION (AK) MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: THRU: FROM: David JOhnst/ Chai rman~' DATE: February 25, 1996 Blair Wondzell, ~ 2/*2'7 P. I. Supervisor ~ Bobby F ost~ -r- Petroleum Inspector FILE NO: AWQIBYDD.doc SUBJECT: BOPE Test - Nabors 27E BPX - MPU - MPB-24 PTD # 96-0009 Kuparuk River Field ~Y. Feb~arv 25. 1996: I traveled this date to BPX's MPU B pad, well 24 and witnessed the BOPE test. As the attached AOGCC BOPE test report shows there were no failures. All equipment tested OK The rig was clean and all equipment seemed to be in good working order. The location was in good shape and there was good access to all areas of the rig. ~: I witnessed the BOPE test on Nabors 27E drilling BPX's MPB-24 - Test time 3 hours - no failures. Attachment: AWOIBYDD.XLS ",- STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report X Workover: NABORS BPX Rig No. 27E PTD # 96-0009 Rep.: Rig Rep.: 12,032 Location: Sec. 18 Other DATE: 2125/96 Rig Ph.# 659-4384 JIM GAFFNEY RODNEY KLEPZ/G T. 11N R. 13E Meridian MPB-24 Set@ Weekly Urn. OPERATION: Drlg: Drlg Contractor: Operator: Well Name: Casing Size: 7" Test: Initial X MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) PTD On Location YES Standing Order Posted BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Une Valves Check Valve MUD SYSTEM: Trip Tank Pit Level Indicators Flow Indicator Meth Gas Detector H2S Gas Detector Well Sign OK Drt. Rig OK Hazard Sec. YES YES Quan. Test Press. PIF 1 300/3,000 P 1 500/5,000 P 1 500/5, 000 P 1 50015, 000 P 1 500/5,000 P 2 500/5,000 P 1 500/5, 000 P N/A Visual YES YES YES YES YES Alarm YES YES YES YES YES FLOOR SAFETY VALVES: Upper Kelly ¡IBOP Lower Kelly ¡IBOP Bait Type Inside BOP CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes Test Pressure P/F Quan. 2 500/5, 000 P 1 500/5,000 P 1 500/5,000 P 1 500/5,000 P Test Pressure PIF 17 500/5,000 P 42 500/5, 000 P 2 Functioned P 1 Functioned P ACCUMULATOR SYSTEM: System Pressure 3,000 I P Pressure After Closure 1,450 P 200 psi Attained After Closure 0 minutes 22 sec. System Pressure Attained 1 minutes 41 sec. Blind Switch Covers: Master: YES Remote: YES Nitgn. Btl's: 4 @ 2450 Avg> Psig. Number of Failures: 0 ,Test Time: 3.0 Hours. Number of valves tested 24 Repair or Replacement of Failed Equipment will be made within days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: GOOD TEST Distribution: 0 rig-We II File c - Oper./Rig c - Database c - Trip Rpt File c - Inspector FI-021 L (Rev .12/94) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: BOBBY D. FOSTER Witnessed By: AWOIBYDD.XLS ,-~ ,-----~, MEMORANDUM TO: THRU: FROM: State of Alas ka Alaska Oil and Gas Conservation Commission David JOhnstn/( C hairma;ð~ DATE: February 15, 1996 Blair Wondzell~ ~ P. I. Supervisor ~~f/' John Spaulding~~M Petroleum Insp. FILE NO: awqlbkdd .doc SUBJECT: BOPE Test Nabors 27E BPX MPU (MPB-24) Kuparuk River Field PTD 96-009 Sunday February 11 , 1996: I traveled this date to BPX' s exploration well at Milne Point (MPB-24) to witness the BOPE test on Nabors rig 27E. The AOGCC Test Report is attached for reference. As noted on the test report no failures were observed, the testing went quite well. Summary: I witnessed the successful BOPE test on Nabors rig 27E with no failures~ 5 hours test time. Attachments: awqlbkdd.xls ~ , ,~ S1 A 1E OF ALASKA OIL AND GAS CONSERVATION COMMISSION BaPE Test Report OPERATION: Drlg: X Workover: DATE: 2/11/96 Drlg Contractor: Nabors Rig No. 27E PTD# 96-009 Rig Ph.# Operator: BPX Rep.: Brian Busby Well Name: MPB-24 Rig Rep.: Tom England Casing Size: 9 5/8" Set@ 4080' MD Location: Sec. 18 T. 13N R. 11E Meridian Umiat Test: Initial X Weekly Other MISC. INSPECTIONS: Location Gen.: ok Housekeeping: ok (Gen) PTD On Location yes Standing Order Posted BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve MUD SYSTEM: Trip Tank Pit Level Indicators Flow Indicator Meth Gas Detector H2S Gas Detector Well Sign Dr!. Rig Hazard Sec. yes ok yes yes Quan, Test Press, P/F TEST DATA FLOOR SAFETY VALVES: Upper Kelly I IBOP Lower Kelly I IBOP Ball Type Inside BOP CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Nitgn. Btl's: Quan. Test Pressure P/F 1 300/3,000 1 500/5,000 1 500/5,000 1 500/5,000 1 500/5,000 2 500/5,000 1 500/5,000 Visual ok ok ok ok ok Alarm ok ok ok ok ok 1 500/5,000 P 1 500/5,000 P 1 500/5,000 P 1 500/5,000 P Test Pressure P/F 15 500/5,000 P 39 500/5,000 P 2 Functioned P 1 I Functioned P 1 Master: X 8 @ 2300 avg. I = minutes 22 minutes 40 Remote: x 2,900 1,500 sec. sec. Psig. ,/ TEST RESULTS Number of Failures: 0 ,Test Time: 5.0 Hours. Number of valves tested 21 Repair or Replacement of Failed Equipment will be made within 0 days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the p, I. Supervisor at 279-1433 REMARKS: Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c - Inspector FI-O21 L (Rev,12/94) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: ~ ?I. SftaJái#tt} AWQLBKDD,XLS (~ ' ; . /T\, :-~ r ; : , ' ,", ,--- ,..\\ ;1/,:;\)1 ir' I I I J '; :' ,\ ;' ¡ ~ 1..";:""" ~ '.-! ~ /~=:-~! i-: /E\ '! ¡ T:\;;~ flX / J \ ,; ',' ' i"; i '..; ,i ¡ \ " I ï: í ~ :~ -=:....l .~ '...:- ' ¡,.,; "";' LJ ~ I , ,- -' ; I ',~'U , ! / I ¡ TONY KNOWLES, GOVERNOR ALAS KA 0 IL AND GAS CONSERVATI ON COMMISSION i ! 3001 PORCUPINE DRIVE ANCHORAGE. ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 ,. I '""c, 19CR vanuary ¿"", ---u Tim Schofield, Senior Driiling Engineer BP Exploration (Alaska), Inc. POBox 196612 Anchorage, AK 99519-6612 Re: Milne Point Unit MPB-24 BP Exploration (Alaska), Inc. Permit No 96-009 Surf Loc. 827'NSL, 4289'WEL, Sec. 18, T13N, R11E, UM. Btmhole Loc. 1829'NSL, 3971'WEL, Sec. 8, T13N, R11E, UM Dear Mr. Schofield: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blo~ut prevention equipment (BOP E) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BaPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission petroleum field inspector 659-3607. ~í David W. Johnston Chairman ¡encl c: Dept of Fish & Game, Habitat Section - wlo end Dept of Environmental Conservation - wlo encl , , ./,:C<, ,,:.::..:,~,:.",.;~: :;",<...,:;.:;t¡;.;;i.,'::;;>:>:',.:;;;.~""'~:',::;'i'.';:. - i,',"",::":;":",,,;,;,,,~:';'.~;.¿~~t~ 1 a. Type of work Drill IX] Redrill 0 1 b. Type of well. Exploratory 0 Stratigraphic Test 0 Development Oil IX] Re-Entry 0 Deepen 0 Service 0 Development Gas 0 Single Zone 0 Multiple Zone 0 2. Name of Operator 5. Datum Elevation (OF or KB) 10. Field and Pool BP Exoloration (Alaska) Inc KBE = 46 feet Milne Point / Kuparuk River 3. Address 6. Property Designation P. O. Box 196612 AnchoraGe Alaska 99519-6612 ADL 047432 4. Location of well at surface 7. Unit or property Name 11. Type BOnd(see 20 AAC 25,025) 827' NSL, 4289' WEL, SEC. 18, T13N1 R11E Milne Point Unit At top of productive interval 8. Well number Number 1685' NSL, 4099' WEL, SEC. 8, T13N1 R11 E MPB-24 2S100302630-277 At total depth 9. Approximate spud date Amount 1829' NSL, 3971' WEL, SEC. 81 T13N, T11 E 02/01/96 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 1829 feet No Close Approach feet 1268 12402' MD /7807' TVD feet ADL 047438 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25,035 (e)(2)) Kickoff depth 300 feet Maximum hole angle 61 0 Maximum surface 3005 psig At total depth (TVD) 7529' /3758 psig 18. Casing program Specifications Setting Depth size Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 30" 20" 91.1# NTBOLHE Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 4144' 31' 31' 4175' 3624' 818 sx PF 'E: 250 sx 'G', 250 sx PF 'c' 8-1/2" 7" 26# L-80 Btrc & Mod B 12372' 30' 30' 12402' 7807' 442 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structu ral Conductor Surface Intermediate Production Liner Perforation depth: measured true vertical 20. Attachments Filing fee [X] Property plat 0 BOP Sketch 0 Diverter Sketch 0 Drilling program ŒJ Drilling fluid program IX] Time vs depth plot 0 Refraction analysis 0 Seabed reportD 20 AAC 25.050 requirementsD 21, I hereby certi;y ,tha~ 1ego;:1 ~ true and correct to the best of my knowiedge Date ¡!,z/Q6. Signed - !t~}. G ~j 'Ai. Title Senior Drillina Enqineer II Commission Use Only perm~ Number At'! nL' nber Approval date (¿, See cover letter 'b""OC) <7 50-0.2 '7-Z.2C;; 7<:2-. /-~5- If for other requirements Conditions of approval Samples required 0 Yes ~ No Mud log required D Yes ~ No Hydrogen sulfide measures 0 Yes J8I'. No Dìrectional survey required þr Yes D No Required working pressure for BOPE D2M; D3M; ~5M; 010M; D15M; Other: Original Signed By by order of Date 41>k Approved by David W. Johnston Commissioner me commission -'- , STATE OF ALASKA BP Secret ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Form 10-401 Rev. 12-1-85 Submit In triplicate ( (' BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 January 11th, 1996 Mr R. Crandall AOGCC 3001 Porcupine Drive, Anchorage, AK 99501 Ref.: Milne Point 8-24 (96F) Well Dear Sir, We expect to begin drilling operations on our Milne Point 8-24 (968) well sometime between January 24th and February 15th 1996. The well is being classified "Secret" by 8PX and I would appreciate any assistance in helping to maintain confidentiality. The permit application contains the names and contact numbers for the 8P Drilling staff involved with the Milne Point 8-24 (96F) operation. The geological contact will be: Eric Dixon Staff Geoscientist Tel: 564-5657 Thank you for your assistance in this matter. Yours sincerely, ti/77/H Chris West 8P Exploration (Alaska) Inc Kt: lA::.\ \! t"::. 0 J~N 1 2 1996 ,- '~Q (' ¡J!¡nn'\ì~v5lion A1 ka au & Ga~ Con.., ./. as Anchon:Jlg0 , ' >~,""""';<~ ,( BP EXPLORATION To: Distribution /J~' ~ ~ 7; ;/ 17 J.../ B J P I' k II 'b'l , . 0 IC Y From: Subject: D North Confidentialit if 'I, Mem orand urn Date: November 27, 1995 Please review and sign the attached at your earliest convenience. The original should be returned to me. Thanks, Distribution: M, Bendersky T. Cook E. Dixon S. Horton J. Kirchner E, Luttrell H. Maysol'). , J. Morgan T. Schofield R. Thomas C. West P. Zseleczky cc: M. Davis h fi"'" ii "¡'""", ,i ¡, ':i"~ 0', ~."" 1,1,""1,6' t¡ gl % tf ,~I""'" ñ. ' ""'....!I ':;r i:b",.. Æ ' J AN 7 2 1~-I) "- .J~O Af::lí,"~""" ".'I~ r n "..,I'/¡ì""I\.,,61~~(:~"/"~.ri\<.,,,i:" ", , " '"" c"-,, '¡;¡ ,. ""'1" . . ,II. "'.,t..., ,','" ".'~Ji[inms~m"w {oJ.l'ii¡/', . "',,., ", , .1 ,,'W..!u'.,'{~c, '.:ii'..' --- -- BP Secret IWel1 Name: I MPB-24 96(F) I We II Plan Summary [!Xpe ofWeIi (producer or fiiJector): l~aruk"Pf"ooucer I Surface Location: 827' FSL 4289' FEL See 18 T13N RIlE UM., AK. Target Location: 1685' FSL 4099 FEL See 8 T13N RIlE UM., AK. Bottom Hole 1829' FSL 3971' FEL See 8 T13N RIlE UM., AK. Location: Note: Target & BHL footages are based on assumed true and square sections and are not surveyed legal locations. (AFENíilnber: I 337008 I ~bors 27£ I Fmated Start Date: ~6 I Operating days to drill and case: 15 ~: fI2402' I JTVffil7807' BKB I ~ Well Design (conventional, slimhole, etc.): Ultra Slimhole, 7" Longstring Formation Markers: Formation Tops MD TVD Formation PressurelEMW Base permafrost 1811' 1807' n/a NA (Top Schrader) 6310' 4647' 1653 psig 1 8.0 ppg OA 6686' 4827' 1744 psig 1 8.0 ppg Base OB Sands 6874' 4917' 1848 psig 1 8.0 ppg Top HRZ 11418' 7107' n/a Base HRZ 11519' 7167' n/a Kupark D Shale 11807' 7357' n/a Target Kuparuk Cl 12011' 7507' 3598 psig 1 9.6 ppg KUPA 12293' 7723' 3616 psig 1 9.6 ppg Total Depth 12402 I 7807' n/a Casing/Tubing Program: Hole CsgI W tIFt Grade Conn Length Top Btm Size Tbg MD/TVD MD/TVD O.D. 30" 20" 91.1# NT80LHE weld 80 32/32 112/112 12 1/4" 9 5/8" 40# L-80 btrc 4144' 31/31 4175/3624 8 1/2" 7" 26# L-80 Btrc & 9872' 30/30 12402/7807 ModB 2500' NI A (tbg) 2-7/8" 6.5# L-80 EUE 11771 ' 29/29 11800/7353 8rd Internal yield pressure of th~ 7" 26# casing is 7240 p~i. W orst .c~se surface pressur~ wO.~~? ~fC~r\,vuÞQl!ll column of gas to the reservOIr at 7529' TVDSS. Maxnnum antICIpated surface press~~nase assulTIlng a reser:r°ir pressure of 3758 p.si is 3005 psi, well below the internal yield pressure rating of the 7"2.' c.. The ModIfied Buttress 7" 26# will be run on bottom. J~~ 1 1'j~:O, C rr-.fí\Ì{'.$\on ,,;I{' [",;,c;-,r:":.Cr;ns. Q,lil,iJ , . . ," ,". . Logging Program. â" """, ,..,.- , ' Open Hole Logs: rc-"'" Surface L WD GR/Resistivity Intermediate Final L WD GR/Resistivityl Neutron/Density Cased Hole None Logs: A gamma ray log will be obtained from surface to TD with L WD tools. Sample catcher will be required. API # SO-O29-22XXX January 11, 1996 ..-.., -" BP Secret Mud Pro~m: Special design considerations LSND freshwater mud.~ Special attention to gravel and coal in the surface hole, with appropriate viscosity and weight to control each. The use of frequent short trips as per the updated pad dat(;l, sheet - (I.l"e- encouraged. Surface Mud Properties: I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.6 80 15 8 10 9 8 to to to to to to to 9.6 100 35 15 30 10 15 Production Mud Properties: I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 40 15 3 7 8.5 6-10 to to to to to to to 9.9 50 20 10 20 9.5 4-6 Well Control: Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Directional: I KOP: I 300' I Maximum Hole Angle: 61 degrees Maximum Dog Leg: < 4 degrees Inclination in target: 40 Degrees Close Approach Well: See Traveling Cylinder report There are not any close approach wells for drilling MPB-96F . The well path should be followed as close as possible to ensure we do not compromise the proximity toleranxces. API # 50-029-22XXX January 11, 1996 ,,""-"'" -~ BP Secret Disposal: Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A. The Milne Point reserve pit can be opened in emergencies by notifying Karen Thomas (564-4305) with request. Fluid Handling: All drilling and completion fluids can be annular injected after allowing the cement on the 7" casing cement job to cure 6 hours following CIP. Request to AOGCC for Annular Pumping Approval for MPB-24: 1. Approval is requested for Annular Pumping into the MPB-24 , 9-5/811 x 711 casing annulus. 2. Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. There are no domestic or industrial use water wells located within one mile of the project area. 3. The 9-5/811 casing shoe will be set at 41751 md (36241 tvd) which is above the Schrader Bluff Sands and into the Prince Creek formation which has a long established history of annular pumping at Milne Point. 4. The burst rating (800/0) for the 9-5/811 40# L80 casing is 4600 psig while the collapse rating (800/0) of the 711 26# L80 casing is 4325 psig. The break down pressure of the Prince Creek formation is 13.5 ppg equivalent mud weight. The Maximum Allowable Surface Pressure while annular pumping is calculated according to the following equation and is 2723 psi for a 10.4 ppg fluid in this well. MASP = 4325 psig - «fluid density ppg - 1.9) X 0.052 X 9-5/811 Casing Shoe TVD 5. A determination has been made that the pumping operation will not endanger the integrity of the well being drilled by the submission of data to AOGCC on 7-24-95 which demonstrates the confining layers, porosity, and permeability of the injection zone. 6. Pumping into the hydrocarbon reservior will not occur. DO NOT EXCEED 35,000 BBlS IN ANY ANNULUS. AREA WEll PREV VOL PERMITTED PERMITTED DATES INJECTED (BBl) VOL (BBl) Milne Point MPB-24 0 35,000 1/1/96 - 12/31/96 FREEZE PROTECTION: Pay close attention to annulii being used for disposal so to avoid freezing. Sometimes the annulii are kept open by ensuring that an adequate volume (+60 bbls) is injected every 6-12 hours. This practice is more economical than pumping 60 bbls of diesel freeze protection every time the pumps are shut down; however, if this practice is used, it is important that the injection frequency into the annulus be adequate to prevent freeze ups -- the drillers must communicate to each other the last time the annunlus was injected into to avoid freezing. API # SO-O29-22XXX January 11, 1996 -- BP Secret DRILLING HAZARDS AND RISKS: See both the updated Milne Point B-Pad Data Sheet prepared by Pete Van Dusen. Most of the trouble time on recent wells has been due to equipment mechanical problems with the surface equipment, rather than formation drilling problems. The MPU PE group will be perforating, hydraulic fracturing and cleaning out wells shortly after the rig drills and completes them. This will make the near rig area congested and as a result potentially hazardous. Ensure personnel use caution moving around adjacent production activities. Lost Circulation: The Kuparuk sands and a number of shallower intervals typically are highly fractured. Be prepared to treat lost circulation while drilling initially with LCM treatments. There has not been any appreciable amount of lost circulation in surface hole on any of the B Pad well. Stuck Pipe Potential: Well MPF-53 was stuck coming out on the short trip at surface casing point. Proir to this incident there was only minor indications that the gravel and coal were present. It appears that we dragged the gravel up into the bottom of the curve and reduced our ability to move up or down. Then we lost the ability to circulate when the hole collapsed. Kick Tolerance: The surface casing setting depth for this well allows a kick tolerance of 77.5 bbl influx (Gas) based on a 12.5 ppg LOT at the 9-5/811 casing shoe and a estimated reservoir pressure of 3594 psig (9.6 ppg equivalent MW). Trip Schedules are required for all trips. All trips will be performed with a trip tank or one pit isolated for use as a trip tank. Formation Pressure: The wells at B Pad have been on production and pressure maintenance for several years, thus we expect to have a good idea of the bottom hole pressure. The maximum expected pore pressure for this well is 9.6 ppg EMW (3594 psi @ 7200' ssTVD). There has been no injection in this region since then, therefore the reservoir pressure should not exceed this estimate. There is limited information regarding hydrate problems, so we will plan to monitor for and drill with established Shared Services Drilling policy for shallow gas hazards until the presense of hydrates is confirmed. WATER USAGE Have the water truck drivers track the water usage on a daily log. Send a copy of this log to Dennise Casey in the Anchorage Office on a monthly basis. '-' 'r-¡., rtc~c.r V i,:U JAN 1 2 '~96 Alaska Oil & Gas Cons, Commission Anchorage API # SO-O29-22XXX J an nary 11, 1996 1. 2. 3. 4. 5. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. ,~ ."--, BP Secret MP B-24 Proposed Summary of Operations 8400 Feet Displacement Drill and Set 20" Conductor. Weld an FMC landing ring for the FMC Gen SA Wellhead on the conductor. Prepare location for rig move. MIRV Nabors 27E drilling rig. NV and function test 20" Diverter system. Ensure the diverter is as per AOGCC specifications and is approved by AOGCC supervisor. Build Spud Mud. Drill the 12-1/4" surface hole to 4175' md (3624' tvd). (Note: This hole section will be LWD logged with GR/Res). Run and cement 9-5/8" casing. ND 20" Diverter, NU and Test 13-5/8" BOPE. Run Wear Bushing. RllI wI PDC bit and Double Power Section PDM (motor). Test the 9-518" casing to 3000 psig and plot pressure vs volume for LOT baseline. Drill out float equipment and 10 feet of new foll11ation, Perform a LOT to a maximum of 12.5 ppg as per Recommended Practices Manual. Record pressure vs. cumulatrive volume for LOT test for well file. Ensure the mud is suited for ERD wells with lubrication, monitored for Torque and drag. Follow Pad Data Sheet short trip guidelines. Drill 8-1/2" hole to TD at 12402' MD (7807' TVD). (Note: This hole section will be logged LWD with Triple Combo (GR/ReslNeuJDens). Pull Wear Bushing, and Change Pipe Rams to 7". Run and Cement 7" casing, in two stage cement job. Test casing to 3500 psi and freeze protect wellbore to 2000' TVD with diesel. Closely monitor casing running loads for drag. Make sure there is a circulating head for the topdrive before starting to run casing. ND BOPE and NU dry hole tree. Release rig to MPK Pad. Note: This well will be perforated, hydraulically fractured and cleaned out with a completion rig and prior to running the ESP completion. Following the stimulation the well will be left with a retrievable bridge plug (RBP) set 500' above the perforations and kill weight brine in the wellbore. MIRV workover completion unit. ND dry hole tree. NU BOPs and test. PV and RllI with 2-7/8" EUE 8rd tubing with RBP retrieving tool. Release RBP and POR standing back tubing. RllI with Electric Submersible Pump (ESP) completion on 2-7/8" EUE 8rd tubing. Set 2 way check. ND BOPE and NU tree and test. Pull two way check, freeze protect, set BPV, close valves. Test tree. RDMO with workover/completion rig. POST RIG WORK 1 . 2. 3. 4. Complete the handover form and turn it and the well files over to production. Turn over the well files along with the handover form. A SBT /G R/CCl is not required on this well and will only be run if there are problems on the production cement job. An adequate volume to cover 2000' of diesel needs to be injected down the 1" X 9-5/8" annulus before moving the rig off the well. Please note type and volume of freeze protection pumped down the outer annulus on the mornina report. The rig will not complete this well. PEs will perforate, frac and clean out this well with a completion rig. API # SO-O29-22XXX January 11, 1996 ,,""-'- ..-, BP Secret MPB 24 WELL 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON CASING SIZE: 9-5/8" CIRC. TEMP 80 deg F at 4000' TVDSS. SPA CER: 75 bbls fresh water. LEAD CEMENT TYPE: Type E Permafrost ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD: 2.17 ft3/sx MIX WATER: 11.63 gal/sk APPROX #SACKS: 818 THICKENING TIME: Greater than 4 ills at 50° F. TAIL CEMENT TYPE: Premium G ADDITIVES: 0.2% CFR-3, 0.2% Halad-344, 2.0% CaCl2 WEIGHT: 15.8 ppg APPROX #SACKS: 250 YIELD: 1.15 ft3/sx MIX WATER: 5.0 gal/sk THICKENING TIME: Greater than 4 ills at 50° F. FLUID LOSS: 100-150 cc FREE WATER: 0 TOP OB CEMENT TYPE: Type C Permafrost ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD: 2.17 cu ftlsk. MIX WATER: 11.63 gal/sk APPROX NO SACKS: 250 CENTRALIZER PLACEMENT: 1. 1 Bowspring centralizer per joint of 9-5/8" casing on the bottom 10 joints above the FS. 2. Place all centralizers in middle of joints using stop collars. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 bpm. Do not overdisplace by more than 1/2 the shoe joint. Mix slurry on the fly -- batch mixing is not necessary. Make sure to fill the casing every joint to avoid having to shut down to fill the casing. Casing has been stuck while we were shut down filling only 5 joints. CEMENT VOLUME: 1. The Tail Slurry volume is a standard 250 sacks is calculated to cover the 9-5/8" Casing Shoe with 30% excess. 2. The Lead Slurry volume is calculated to cover from the top of the Tail Slurry to 1500' md with 30% excess and from 1500' md to surface with 100% excess. 4. 80'md 9-5/8", 40# capacity for float joints. 5. Top Job Cement Volume is 250 sacks. ~¿L;t:§ Vt:[~) JAN 12 1996 AJa5,~a ryJ & Ga.9 Cons. CommiSSion Art::;~h1;',z~ API # 50-029-22XXX January 11, 1996 ~ ~--'- BP Secret MPB-24 7" PRODUCTION CASING CEMENT PROGRAM- HALLIBURTON STAGE I CEMENT OB ACROSS THE KUPARUK INTERVAL: CIRC. TEMP: 1150 F BHST 120 deg F at 7040' TVDSS. SP ACER: 20 bbls fresh water. 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg current mud weight. CEMENT TYPE: Premium G ADDITNES: 0.2% CFR-3, 0.1 % HR-5, 0.4% Halad 344 WEIGHT: 15.8ppg YIELD: 1.15 cu ft/sk MIX WATER: 5.0 gallsk APPROX # SACKS: 281 THICKENING TIME: 3 1/2 - 4 1/2 hrs @ 1400 F FLUID LOSS: < 50cc/30 min @ 1400 F FREE WATER: Occ @ 45 degree angle. STAGE II CEMENT OB ACROSS THE SCHRADER BLUFF SANDS: CIRC. TEMP: 600 F BHST 80 deg F at 7040' TVDSS. SPACER: 20bbls fresh water. 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg current mud weight. TAIL CEMENT TYPE: Premium G ADDITNES: 0.2% CFR-3, 0.2% Halad 344 WEIGHT: 15.8ppg YIELD: 1.15 cu fUsk MIX WATER: 5.0 gal/sk APPROX # SACKS: 161 THICKENING TIME: 4 hours @ 50 FLUID LOSS: 100-150 cc FREE WATER: Occ @ 45 degree angle. CENTRALIZER PLACEMENT: 1. 7" x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 17 joints of 7" Casi: total). This will cover 200' above the C Sand. 2. 7" x 8-1/4"Straight Blade Rigid Centralizers-- one per joint from 6550' - 5700' to cover the S Bluffs Sands (20Total). 3. Run one 7" x 8-1/4"Straight Blade Rigid Centralizer inside the 9-5/8" casing shoe. 4. Total 7" x 8-1/4" Straight Blade Rigid Centralizers needed is 55. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and compatibility prior to pumping job. Ensure thickening times are adequate relative to pumpiJ requirement. Displace at 8-10 bpm. Batch mixing is not necessary. CEMENT VOLUME: 1. Stage 1 cement volume is calculated to cover 1000' md above the C Sand with 30% excess. 2. Stage 2 cement volume is calculated to cover from the OG base to the to 1000' above the NA Top with 30% excess. k¿\';crvt:D JAN 1 2 i996 API # 50-029-22XXX Al'.'\e!t~ tì1.1 jÌ A~).!'l i<'",~., f"., ,.." "~«¡ I;,Iw,"" ,,*h '" \Ju;;. y.VÎi~. '...Ü¡! it; í:~;;;-BJ¡' Anchorage January 11, 1996 i II ,I I I I I! ~~\~\, a~t\~ ~ o.oØ tð<c,(J ~~ BPX -Shared Services Drilling Alaska State Plane: Zone4 Milne pt : MPB MPB-96F MPB-96F CONFIDENTIAL Wp2 VERTICAL VIEW SCALE 1000 ft. / DIVISION TVD REF: WELLHEAD VERTICAL SECTION REF: WELLHEAD 0,00. @ 0 MD TI E IN CRITICAL POINT DATA MD Inc Azi, TVD N/S E/W TIE IN 0 0,00' 41. 58' 0 0 N 0 E KDP I START 1000 0,00' 41. 58' 1000 0 N 0 E OF BUILD @ 1. 00' 11 00 ft START OF BUILD 1300 3,00' 41. 58' 1300 6 N 5 E @ 1.50'/100 ft START OF BUILD 1600 7,50' 41. 58' 1599 26 N 23 E @ 2,00' 1100 ft END OF BUILD 1700 9,50' 41. 58' 1697 37 N 33 E Bo.se 1811 9,50' 41. 58' 1807 51 N 45 E PerMo.frost START OF 1900 9,50' 41. 58' 1895 62 N 55 E CURVE @ 2,50'/100 ft END OF CURVE 3975 61,37" 41,58' 3528 932 N 827 E NA So.nols 6310 61. 37' 41,58' 4647 2465 N 2187 E DA So.nols 6686 61,37" 41. 58' 4827 2712 N 2406 E DB So.nols 6811 61,37" 41. 58' 4887 2794 N 2479 E Bo.se Of DB 6874 61. 37' 41. 58' 4917 2835 N 2515 E START OF 11156 61. 37' 41. 58' 6968 5647 N 5009 E CURVE @ 2, 50' 11 00 fi; THRZ 11418 54, 82' 41. 58. 7107 5813 N 5157 E BHRZ 11519 52, 29' 41. 58' 7167 5874 N 5211 E TKLB 11630 49,52' 41. 58' 7237 5938 N 5268 E TKUP/UD 11807 45,09' 41. 58' 7357 6036 N 5354 E To.r¡3et I TKUC1 12011 40,00' 41,58' 7507 6139 N 5446 E TKU B/B8 12036 40,00' 41. 58' 7526 6151 N 5456 E TKB7 12052 40,00' 41. 58' 7539 6159 N 5464 E TKB6 12083 40,00' 41. 58' 7562 6173 N 5476 E TKUA 12293 40,00' 41. 58' 7723 6274 N 5566 E TD 12402 40,00' 41. 58. 7807 6327 N 5613 E .t¡;f' .. ,:;00" HORIZONTAL VIEW (TRUE NORTH) SCALE 1000 ft. / DIVISION SURVEY REF: WELLHEAD AWD 0 Q ! ~ ii .."-,,..rr """"'. ..Ii'" <.0 0-:. lb") ..- 1000 0,00. @ 1000 MD KDP I START OF BUILD @ 1. 00'/100 fi; .""~,, ,g~J , "it¡ ~ """" # ~ ~"Jì C\J 1300 3,00' @ 1300 MD START OF BUILD @ 1. 50'/100 ft ,..- :z: « --:> 1599 1697 r~~§ 2000 7,50' @ 1600 MD START OF BUILD @ 2,00'/100 ft 9,50' @ 1700 MD END OF BUI LD ~,%~', ~ \~bb ~~ ~~~~tbrM'ttrRrvtt @ 2,50'/100 fi; 14,50' @ 2100 MD 19,50' @ 2300 MD 24,50' @ 2500 MD 29, 50' @ 2700 MD 34,50' @ 2900 MD 39,50' @ 3100 MD 44,50' @ 3300 MD 49,50' @ 3500 MD ~37' @ 3975 MD END OF CURVE ~9 5/8 in 00, @4175 MO, 3624 iVO Gri 01 X 577375 Gri 01 Y 6030143 3000 TVD 7507 To.rget No.Me To.rget NS 6139 N EW 5446 E 3528 1245 61,37' @ 11156 MD START OF CURVE 54, 8~. @11418MDTHIß 52. 9' @ r51~ MD BrJr1Z 4 5~cr9' ~ 1íü~W7 rwD NJp IUD '0.00' @ 12011 MD TClr.,¡¡et / TKUC1 ~~Ö.ð'o,1~01M~ MDKU!f~~~8 ---""¡O.OO' @ 12083 MD TKB6 ~ 40.00' @ 12293 MD TKUA ~ 40,00' @ 12402 MD TD 7 in 00, @ 12402 MO, 7807 TVD ] I 8000 9000 4000 CASING POINT DATA MD Inc Azi 4175 61. 37" 41. 58' 12402 40,00' 41. 58' TVD N/S E/W 3624 1063 N 943 E 7807 6327 N 5613 E DD 9 5/8 in 7 in 4647 4827 4887. 4917. 5000 61,37' @ 6310 MD NA So.nols 61.37' @ 6686 MD DA So.nols 'L ~~: ~ g~Y4 ~ ~Bo.sSeüro1-s DB 5000 1 I I I I 5958 i 7000 = ~k~~ ~ 7357 ~~~f3 ~~~1 0 1000 2000 At¡Clf '9ót:' ¥.oç:> @ 2,50'/100 ft .J 7771 78527938 8058 8205822282338252; 83878458 8000 I ! I I 0 1000 2000 VERTICAL SECTION PLANE: 41.58" I 3000 ¡ 4000 ¡ 5000 ¡ 6000 ¡ 7000 e: .£11 (.i .<:.~ E ~::: d () ~ø t'" 1..'J1) ¿:::. ,,'j f ,J .'" ...)d f,-;¡ ..JI-' t:¡:.J () (J :iE ~$ '::::: C) \ì':J ~~§ t1J :.;¡: , 1/10/96'>Q:! 3: 34 pM .>S; u.> .> 6~ ' .> -Y~<' ' Ý<, ./~ ' Ý<, '~6'. 6.9.9 ý' ~ I 66' ' <:~ w. Ý<, <:9 , .~ Ý<, (9. '~ <:9. , Ý<, .~ (9. Ý<, .~ (9. 3000 4000 5000 -----.-J HALLIBURTON 7000 ..... S' 0 ,0 @ 000 ~ "'" 0 '" 3: ,0 ..... ex> 0 ..... ~ .5000 000 3000 000 1000 \ t I ,. 6000 Do.te Plotted: ;;ZV96 - ~ . Creo. ted By :' fi'J.o / --'. , Checkeol By : Approveol By Do.te Halliburton Energy Services - Drilling Systems PSL Page 1 Proposal Report Date: 1/10/96 Time: 4:42 pm Wellpath ID: MPB-96F Wp2 Last Revision: 1/10/96 Calculated using the Minimum Curvature Method Computed using WIN-CADDS REV2.1.B Vertical Section Plane: 41.58 deg. Survey Reference: WELLHEAD Reference World Coordinates: Lat. 70,28.33 N - Long, 149,24.43 W CO~f'Dt.~1\~1. Reference GRID System: Alaska State Plane Zone: Alaska 4 Reference GRID Coordinates: (ft): 6023950.53 N 571991.58 E North Aligned To: TRUE NORTH 6~ SECRE1' Vertical Section Reference: WELLHEAD Closure Reference: WELLHEAD TVD Reference: WELLHEAD ) BPX-Shared Services Drilling Alaska State Plane: Zone4 ) Milne Pt : MPB MPB-96F MPB-96F CONFIDENTIAL Wp2 A WD Measured lncl Drift Subsea TVD Course TOTAL GRID Coordinates Closure Vertical Build Walk DLS Cum. Expected Total Max Hor Min Hor Dir. Vert Survey Tool Depth Dir. Depth Length Rectangular Offsets Northing Easting Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) (ft) (ft) (ft) (deg.) (ft) (dg/l00ft) (dg/l00ft) (dg/l00ft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) TIE IN 0.00 0.00 0.00 -57.00 0.00 0.00 O.OON O.OOE 6023950.53 571991.58 O.OC@ 0.00 0.00 0.00 0.00 0.00 0.0 O.OON O.OOE 0.00 0.00 0.00 0.00 MWD KOP / START OF BUILD @ 1.00 deg/l00 ft 1000.00 0.00 0.00 943.00 1000.00 1000.00 O.OON O.OOE 6023950.53 571991.58 O.OC@ 0,00 0.00 0.00 0.00 0.00 0.0 O,OON O.OOE 2.47 2.47 0,00 1.41 BPHM-PBD 1100.00 1.00 41.58 1042.99 1099.99 100.00 O,65N 0.58 E 6023951.19 571992.15 0.87@ 41.58 0.87 1.00 0.00 1.00 1.0 0.65N 0.58 E 2.73 2.73311.58 1.57 BPHM-PBD 1200.00 2,00 41.58 1142.96 1199,96 100.00 2,61N 2,32E 6023953.17 571993.87 3.4S@ 41.58 3.49 1.00 0.00 1.00 2.0 2.61N 2.32E 3.00 2.99 311.58 1.72 BPHM-PBD START OF BUILD @ 1.50 deg/l00 ft 1300.00 3.00 41.58 1242.86 1299.86 100,00 5,87N 5,21 E 6023956.46 571996.73 7,85@ 41.58 7.85 1.00 0.00 1.00 3.0 5.86N 5.22E 3.27 3.25 311.58 1.87 BPHM-PBD 1400.00 4.50 41.58 1342.65 1399.65 100,00 10.77N 9.55 E 6023961.39 572001.03 14.3S@ 41.58 14.39 1.50 0.00 1.50 4.5 10.74N 9.58E 3.57 3.51 311.58 2.03 BPHM-PBD 1500,00 6.00 41.58 1442.22 1499.22 100.00 17.61 N 15.62 E 6023968.29 572007.03 23.54@ 41.58 23,54 1.50 0,00 1.50 6,0 17.55N 15.69 E 3.91 3.77 311.58 2.20 BPHM-PBD " ,I START OF BUILD @ 2.00 deg/l00 ft J 1600.00 7.50 41.58 1541.53 1598,53 100.00 26.40N 23.42 E 6023977.16 572014.74 35.3C@ 41.58 35.30 1.50 0,00 1.50 7.5 26.30N 23.54 E 4.30 4.03 311,58 2.37 BPHM-PBD END OF BUILD 1700.00 9.50 41.58 1640.42 1697.42 100.00 37.46N 33.23 E 6023988.31 572024.45 50.08@ 41.58 50.08 2.00 0.00 2.00 9.5 37.28N 33.43 E 4.77 4,29 311.58 2,56 BPHM-PBD Base Pennafrost 1811.10 9.50 41.58 1750.00 1807.00 111.10 51.17N 45.40 E 6024002.14 572036.48 68.41@ 41.58 68.41 0,00 0.00 0.00 9.5 50,92N 45,69 E 5.33 4.60 311.58 2.73 BPHM-PBD START OF CURVE @ 2,50 deg/l00 ft 1900.00 9.50 41.58 1837.68 1894.68 88.90 62.15N 55.14 E 6024013.21 572046.11 83.0S@ 41.58 83.09 0.00 0.00 0.00 9,5 61.83N 55.51 E 5.80 4.85 311.58 2.87 BPHM-PBD 2000.00 12.00 41.58 1935.92 1992.92 100.00 76.10N 67.52 E 6024027.28 572058.35 101.74@ 41.58 101.74 2.50 -0.00 2,50 12.0 75.66N 68.01 E 6.45 5.11 311.58 3.09 BPHM-PBD 2100.00 14.50 41.58 2033.25 2090.25 100.00 93.25N 82.73 E 6024044,57 572073.39 124.65@ 41.58 124.65 2.50 -0.00 2.50 14.5 92.64 N 83.41 E 7.24 5.37 311.58 3.34 BPHM-PBD 2200.00 17.00 41.58 2129.49 2186.49 100.00 113.55N 100.74 E 6024065.04 572091.21 151.8C@ 41.58 151.80 2.50 -0.00 2.50 17,0 112.71 N 101.69 E 8.17 5.64 311.58 3.60 BPHM-PBD 2300,00 19.50 41.58 2224.45 2281.45 100.00 136.97N 121.52 E 6024088.66 572111.76 183.11@ 41.58 183.11 2.50 -0,00 2.50 19.5 135.84N 122.81 E 9.28 5.91 311.58 3.89 BPHM-PBD 2400.00 22.00 41.58 2317.96 2374,96 100.00 163.47N 145.03 E 6024115.39 572135.01 218.54@ 41.58 218.54 2.50 -0.00 2.50 22,0 161.96N 146.74 E 10.56 6,18 311.58 4.20 BPHM-PBD 2500.00 24,50 41.58 2409.83 2466.83 100.00 193.00N 171.23 E 6024145.17 572160.91 258.01@ 41.58 258.01 2.50 -0.00 2.50 24,5 191.02N 173.46 E 12.02 6.47 311.58 4,54 BPHM-PBD 2600,00 27.00 41.58 2499.89 2556.89 100,00 225,50N 200.06 E 6024177.94 572189.42 30 1.45@ 41.58 301.45 2.50 -0.00 2,50 27.0 222.96N 202.91 E 13.67 6.77 311.58 4.91 BPHM-PBD 2700.00 29.50 41.58 2587,97 2644.97 100,00 260,90N 231.47 E 6024213.64 572220.48 348.78@ 41.58 348.78 2.50 -0.00 2.50 29,5 257.72N 235.06 E 15.52 7.07 311.58 5.30 BPHM-PBD Halliburton Energy Services - Drilling Systems PSL EC~E'1 Page 2 6~ S Date: 1/10/96 Proposal Report CONfID(NtiAl Wellpath ID: MPB-96F Wp2 n_,- Measured loci Drift Subsea TVD Course TOTAL GRID Coordinates Closure Vertical Build Walk DLS Cum, Expected Total Max Hor Min Hor Dir. Vert Survey Tool Depth Dir. Depth Length Rectangular Offsets Northing Easting Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) (ft) (ft) (ft) (deg.) (ft) (dgll00ft) (dgll00ft) (dgll00ft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) 2800.00 32.00 41.58 2673.91 2730.91 100.00 299.15N 265.39 E 6024252.21 572254.04 399.9C@ 41.58 399.90 2.50 -0.00 2.50 32.0 295.20N 269.84 E 17,56 7.39 311.58 5.73 BPHM-PBD 2900.00 34.50 41.58 2757.53 2814.53 100,00 340.16N 301.78E 6024293.57 572290.02 454,73@ 41.58 454.73 2,50 -0.00 2.50 34,5 335.35N 307.19E 19.80 7.72 311.58 6.19 BPHM-P~ c ..2 3000.00 37,00 41.58 2838.68 2895.68 100.00 383,86N 340.55 E 6024337,64 572328,36 513.15@ 41.58 513.15 2.50 -0,00 2.50 37.0 378.08N 347.06 E 22.24 8.05 311.58 6.68 BPHM-P, 'Ð.,¡ 1:;') .g:? : ~ ," l: ,....""A CD f- 3100.00 39.50 41.58 2917,20 2974.20 100,00 430,17N 381.63 E 6024384.34 572368.98 575.05@ 41.58 575,05 2.50 -0,00 2,50 39.5 423.30N 389.37 E 24.88 8.39 311.58 7.20 BPHM-PBQ C}~ I"~ 0') ~S 3200.00 42.00 41.58 2992.95 3049.95 100,00 478.99N 424.95 E 6024433.58 572411.82 640.32@ 41.58 640.32 2.50 -0.00 2.50 42.0 470.92N 434.04 E 27.72 8.74 311.58 7.76 BPHM-P~: .-- () 3300.00 44.50 41.58 3065.79 3122,79 100.00 530.25N 470.41 E 6024485.27 572456.78 708.84@ 41.58 708.84 2,50 -0.00 2,50 44.5 520,85N 481.00 E 30.76 9.09 311.58 8.35 BPHM-P12 ~ ø ("\J I". I..':F) ':5 ro BPHM-P;ß1b ç-- Ù::S 3400.00 47.00 41.58 3135.56 3192.56 100.00 583.83N 517.94E 6024539.31 572503.78 780.46@ 41.58 780.46 2.50 -0.00 2.50 47.0 572.99N 530.15 E 34.00 9.44 311.58 8.98 GO ..c::: :æ: cr$ c::: 3500.00 49.50 41.58 3202.14 3259.14 100.00 639.63N 567.45 E 6024595.58 572552.74 855,06@ 41.58 855.06 2.50 -0.00 2.50 49.5 627.24N 581.41 E 37.43 9.79 311.58 9,65 BPHM-~ « ø~ 3600.00 52.00 41.58 3265.41 3322.41 100.00 697.55N 618.84 E 6024654.00 572603.55 932.4Ç@ 41.58 932.49 2.50 -0.00 2,50 52.0 683.50N 634,68 E 41.05 10.13 311.58 10,35 BPHM- - ~ ~ ) " ð 3700.00 54.50 41.58 3325.24 3382.24 100.00 757.49N 672.01 E 6024714.45 572656.13 1012.61@ 41.58 1012.61 2.50 -0.00 2.50 54.5 741.65N 689.86 E 44.86 10.46 311.58 11.08 BPHM-PBD -~ 3800.00 57.00 41.58 3381.51 3438.51 100.00 819.32N 726.86 E 6024776.80 572710.37 1095.26@ 41.58 1095.26 2.50 -0.00 2.50 57.0 801.58N 746.85 E 48.84 10.78 311.58 11.86 BPHM-PBD ~.) 'ft.] 3900.00 59.50 41.58 3434.13 3491.13 100.00 882.92N 783.29 E 6024840.95 572766.17 1180.2Ç@ 41.58 1180.29 2.50 -0.00 2.50 59.5 863.19N 805.53 E 52.99 11.09 311.58 12.66 BPHM-PBD « END OF CURVE 3974.92 61.37 41.58 3471.09 3528.09 74.92 931.67N 826.53 E 6024890.11 572808.93 1245.45@ 41.58 1245.45 2.50 -0.00 2.50 61.4 910.39N 850.52 E 56.20 11.31 311.58 13.28 BPHM-PBD CASING POINT OD = 9 5/8 in, ID = 8.84 in, Weight = 40.00 lb/ft. 4175.32 61.37 41.58 3567.10 3624.10 200.40 1063.26N 943.26 E 6025022,82 572924.36 1421.36@ 41.58 1421.36 0.00 0.00 0.00 61.4 1063.26N 943.26 E 0.00 0.00 0.00 0.00 BPHM-PBD NA Sands 6310.33 61.37 41.58 4590.00 4647.00 2135.01 2465,14N 2186.91 E 6026436.80 574153.97 3295.38@ 41.58 3295.38 0.00 0,00 0.00 61.4 2395.45N 2265.47 E 157.73 22.32 311.58 31.45 BPHM-PBD OA Sands 6686.03 61.37 41.58 4770.00 4827.00 375.70 2711.83N 2405.76 E 6026685.64 574370.33 3625.15@ 41.58 3625.15 0.00 0.00 0.00 61.4 2634.35N 2493.10 E 174.16 24.10 311.58 34.53 BPHM-PBD OB Sands 6811.26 61.37 41.58 4830.00 4887.00 125.23 2794.06N 2478.71 E 6026768.59 574442.44 3735.07@ 41.58 3735.07 0.00 0.00 0.00 61.4 2713.99N 2568,97 E 179.63 24.69 311.58 35.56 BPHM-PBD Base Of OB 6873.88 61.37 41.58 4860,00 4917,00 62,62 2835,18N 2515.18 E 6026810.06 574478.50 3790.04@ 41.58 3790.04 0.00 0.00 0.00 61.4 2753.81 N 2606.91 E 182.37 24.99 311.58 36.07 BPHM-PBD START OF CURVE @ 2.50 degll00 ft 11155,79 61.37 41.58 6911.49 6968.49 4281.91 5646.75N 5009.41 E 6029646,62 576943.75 7548.51@ 41.58 7548.51 0,00 0,00 0,00 61.4 5476.63N 5201.18 E 369.85 45.34 311.58 71.71 BPHM-PBD 11255.79 58.87 41.58 6961.30 7018.30 100.00 5711.61 N 5066,95 E 6029712.06 577000,61 7635.21@ 41.58 7635.21 -2.50 0.00 2,50 63,9 5539.52N 5260.94 E 374.07 46.19 311.58 72,29 BPHM-PBD ) 11355.79 56.37 41.58 7014.84 7071.84 100.00 5774.78N 5122.99 E 6029775.81 577055,99 7719,66@ 41.58 7719.66 -2,50 0.00 2,50 66.4 5600.82N 5319.09E 378,13 47.07 311.58 72.81 BPHM-PBD THRZ 11418.01 54,82 41.58 7050.00 7107.00 62.22 5813.18N 5157.06E 6029814.56 577089.65 7771.0C@ 41.58 7771.00 -2.50 -0.00 2.50 67.9 5638,11 N 5354.41 E 380.58 47.64 311.58 73.12 BPHM-PBD 11455.79 53.87 41.58 7072,02 7129.02 37.78 5836,15N 5177.43E 6029837.73 577109.78 7801.6Ç@ 41.58 7801.69 -2.50 0.00 2.50 68.9 5660.41 N 5375.53 E 382,04 47,98 311.58 73.30 BPHM-PBD BHRZ 11519,02 52,29 41.58 7110.00 7167.00 63.23 5873.96N 5210.98 E 6029875.88 577142.93 7852.24@ 41.58 7852.24 -2.50 0.00 2.50 70.5 5697.16N 5410,28 E 384.42 48.57 311.58 73.57 BPHM-PBD 11555.79 51.37 41.58 7132.72 7189.72 36,77 5895.59N 5230,17 E 6029897.70 577161.89 7881.15@ 41.58 7881.15 -2.50 0.00 2.50 71.4 5718.18N 5430.15 E 385.78 48.92 311.58 73.73 BPHM-PBD TKLB 11630.03 49.52 41.58 7180.00 7237.00 74,24 5938.41 N 5268.15 E 6029940.91 577199.43 7938.3Ç@ 41.58 7938.39 -2.50 0.00 2.50 73.2 5759.84N 5469.44 E 388.41 49.62 311.58 74.01 BPHM-PBD 11655.79 48.87 41.58 7196.83 7253,83 25,76 5952.99N 5281.09 E 6029955.63 577212,21 7957.8Ç@ 41.58 7957.89 -2.50 0.00 2.50 73,9 5774.03N 5482.82 E 389.31 49.87 311.58 74.11 BPHM-PBD 11755.79 46.37 41.58 7264.23 7321,23 100.00 6008.25N 5330.11 E 6030011.38 577260.65 8031.76@ 41.58 8031.76 -2,50 0,00 2.50 76.4 5827.88N 5533.43 E 392.61 50.83 311.58 74.42 BPHM-PBD TKUP/UD 11807.04 45.09 41.58 7300,00 7357.00 51.25 6035.70N 5354.47 E 6030039.09 577284,72 8068.45@ 41.58 8068.45 -2.50 0.00 2.50 77.7 5854,64N 5558.56 E 394.26 51.32 311.58 74,57 BPHM-PBD 11855.79 43.87 41.58 7334.78 7391.78 48,75 6061.25N 5377.14 E 6030064.87 577307.12 8102.61@ 41.58 8102.61 -2.50 0,00 2.50 78,9 5879.56N 5581.94E 395.77 51.79 311.58 74.70 BPHM-PBD 11955.79 41.37 41.58 7408.36 7465.36 100.00 6111.90N 5422.07 E 6030115.98 577351.52 8170.32@ 41.58 8170.32 -2.50 0.00 2.50 81.4 5929.03N 5628,20 E 398.67 52.75 311.58 74,92 BPHM-PBD Target I TKUC 1 Halliburton Energy Services - Drilling Systems PSL E1' Page 3 CONfiD(NT~t\L S~C~ Date: 1/10/96 Proposal Report -.Ø9 Wellpath ID: MPB-96F Wp2 Measured Inc1 Drift Subsea TVD Course TOTAL GRID Coordinates Closure Vertical Build Walk DLS Cum, Expected Total Max Hor Min Hor Dir. Vert Survey Tool Depth Dir. Depth Length Rectangular Offsets Northing Easting Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (de g.) (deg.) (ft) (ft) (ft) (ft) (ft) (ft) (ft) (ft) (deg.) (ft) (dgilOOft) (dgll00ft) (dgilOOft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) 12010.71 40.00 41.58 7450.00 7507.00 54.92 6138.68N 5445.83 E 6030143.00 577375.00 8206.13@ 41.58 8206.13 -2,50 0.00 2.50 82.7 5955.20N 5652.65 E 400.20 53.27 311.58 75.03 BPHM-PBD TKUPB/B8 12035.51 40.00 41.58 7469.00 7526.00 24.80 6150.61 N 5456.41 E 6030155.04 577385.45 8222.07@ 41.58 8222,07 0.00 0.00 0.00 82.7 5966.85N 5663.54 E 400.90 53.41 311.58 75.15 BPHM-PBD TKB7 12052.48 40.00 41.58 7482.00 7539.00 16.97 6158.77N 5463.65 E 6030163.27 577392.61 8232,98@ 41.58 8232.98 0.00 0.00 0.00 82.7 5974,83N 5671.00 E 401.37 53.50 311.58 75.23 BPHM-PBD TKB6 12082.50 40.00 41.58 7505.00 7562.00 30.02 6173.20N 5476.46 E 6030177.84 577405.26 8252.28@ 41.58 8252.28 0.00 0.00 0.00 82.7 5988.93N 5684.18 E 402.21 53.67 311.58 75.37 BPHM-PBD TKUA 12292.67 40.00 41.58 7666.00 7723.00 210.17 6274,26N 5566.12 E 6030279.81 577493.86 8387.37@ 41.58 8387.37 0.00 0.00 0.00 82.7 6087.65N 5776.47 E 408.07 54.84 311.58 76.37 BPHM-PBD CASING POINT 00 = 7 in, ID = 6.28 in, Weight = 26.00 Ib/ft. ) 12402.31 40.00 41.58 7749.99 7806.99 109.64 6326.98N 5612.89 E 6030333.01 577540.07 8457.85@ 41.58 8457.85 0.00 0.00 0.00 82.7 6326.98N 5612,89 E 0.00 0,00 0.00 0.00 BPHM-PBD TD 12402.33 40.00 41.58 7750,00 7807.00 0.01 6326.98N 5612.90 E 6030333.02 577540.08 8457.8E@ 41.58 8457.86 0,00 0.00 0.00 82.7 6139.15N 5824.62 E 411.13 55.45 311.58 76.89 BPHM-PBO MPU B-P AD 1995 WELL LOCATIONS 11/30/95 (PROPOSED LOCATIONS) WELLS MPB96F and MPB96A NAME COMMENTS ALASKA STATE PLANE ZONE 4 (NAD 27) DECIMAL DEGREES (NAD 27) S & E SEC LINE OFFSETS SECTION, TOWN., Y X LATITUDE (N°) LONGITUDE (W°) FSL ÆL RANGE, UMIAT, AK MPB-96A Proposed Location 6,023,602.09' 572,082.57' 70.4747651° 149.4111903° 478' 4,203' SEC18 T13N R11E MPB-96F Proposed Location 6,023,950.53' 571,991.58' 70.4 757195° 149.4119060° 827' 4,289' SEC 18 T13N R11E .. - \ I. t Notes: Coordinates shown are North American Datum 1927 (NAD 27). J. Cotton 564-4969 F. Robert Bell Assoc. File Name: MPU B-Pad Wells.xl4 11/30/95 ---- " MPU B-Pad Wells 1995 Future Wells J. NAD 27 ASP Zone 4 SF= 0.999905887 Scale: 1"=200' Note: Distances and Azimuths shown are ASP Grid. Cotton II Well 8-21 II Well 8-20 II Well 8-19 Well 896F 0 Proposed Well Loc. II Well 8-18 X=571991.58 .. Well 8-12 Y=6023950.53 II Well 8-8 II - . Well B-14 II Well B- 7 11/29/95 II Well 8-13 Well 896A 0 Proposed Well Lac. E Well 8-11 X=572082.57 Ii Well 8-16 Y=6023602.09 III Well 8-9 II Well B-15 II Well 8-10 II Well 8-23 II Well 8-6 II Well B-22 II Well B-5 II Well B-2 II Well 8-3 II Well B-17 II Well 8-4 II Well B-1 /~Ch.-. r ' MPU ß-Pad Wells 1995 Future Wells J. NAD 27 ASP Zone 4 SF= 0.999905887 Scale: 111=2001 Note: Distances and Azimuths shown are ASP Grid. Cotton 11/29/95 II Well 8-21 L1 120.26 345°13110" POL #1 \..A '\ 5.000" 15°,\3"\ . Well 8-20 II Well 8-18 Well 8-19 Well 896F Proposed Well Loc. X=571991.58 Well B-12 Y=6023950.53 Ii Well B-8 . Ii Well B-14 II Well 8-11 L2 POL #2 1 1 9 . 6 1 \..3 345 ° 1 0 I 2 1" '\ 5 .00,\ II 15°'\ 0"2. II Well B-7 Well B-13 Well 896A Proposed Well Lac. X=572082.57 Well B-16 Y=6023602.09 II Well B-9 II Well B-15 II Well B-10 Well 8-23 II II Well B-22 Bell Proposed ReG. X=571930.82 Y=6023295.44 II Well B-6 II Well 8-5 II Well B-2. II Well 8-3 II Well B-17 . Well 8-4 II Well 8-1 ,"'=' ~ Well 8-13 FRB As-bit Well X=572052.77 Y=6023656.07 " '\5.00 15°'\ 0'2,'\ It ,.; (5),.; q,.; ,.;<0 0.. '(5) "",.; ,.; " ,.; (5) <J'<J' j.<o 0.. '0' ~,.; ,.; -=~ . Well 896A Proposed Well Loc. X=572082.57 Y=6023602.09 Well 8-16 FR8 As-bIt Well X=572083.38 Y=6023540.44 Well 8-19 FR8 As-bit Well X=571961.74 Y=6024004.84 ~ (1') Q(1') ~o ~> ~C.Þ 0 ~ ~~ Q~r-: ~o~ ~N ~ð) o~ r=~~, , Well B96F Proposed Well Loc. X=571991.58 Y=6023950.53 Well 8-12 FRS As-bit Well X=571992.42 Y=6023888.56 WELL PERMIT CHECKLIST FIELD & POOL COMPANY .6 / INIT CLASS I L}e¡/ 1- 0(/1/ {;~SIO ~ I WELL NAME /f / ð ..., 2. '7 ~C) PROGRAM: exp [] de~ /1 JQ <l redrll [] serv [] wellbore seg I] ON/OFF SHORE o~ UNITt GEOL AREA ADMINISTRATION ENGINEERING APPR ç¡¡-- t:' .Df:;'Et --t¡.a/- '9.b 1- 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. Permit fee attached. . . . . . . . . . . . . . . . .. Y Lease number appropriate.. ............. Y Unique well name and number. . . . . . . . . . . . .. Y Well located in a defined pool. . . . . . . . . . . . . .Y Well located proper distance from drlg unit boundary. . .Y Well located proper distance from other wells. . . Y Sufficient acreage available in drilling unit. . . . . . Y If deviated, is wellbore plat included. . . . . . . . . Y Operator only affected party. . . . . . . . . . . . . . Y Operator has appropriate bond in force. . . . . . . . . .Y Permit can be issued without conservation order. . .. Y Permit can be issued without administrative approval. . .Y Can permit be approved before 15-day wait. . . . . . . . Y REMARKS N N N N N N N N N N N N N c 0 Z 0 -I ~ :::0 - -I m - Z -I :I: - ( rn rn -C :Þ 0 m 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. Conductor string provided. . . . . . . . . . . . . . . (Y) N Surface casing protects all known USDWs . . . . . . . . (£) N CMT vol adequate to circulate on conductor & surf csg. (Jþ N CMT vol adequate to tie-in long string to surf csg . . . Y (jb CMT will cover all known productive horizons. . . . . . . Casing designs adequate for C, T, B & permafrost. . . . . Adequate tankage or reserve pit. . . . . . . . . . . . If a re-drill, has a 10-403 for abndnmnt been approved. Adequate wellbore separation proposed. . . . . . . . . . If diverter required, is it adequate. . . . . . . . . . .Y Drilling fluid program schematic & equip list adequate. BOPEs adequate. . . . . . . . . . . . . . . . . . . . .~ BOPE press rating adequate; test to ~~ psig.~ Choke manifold complies w/API RP-53 (May 84). . . . . . ~ Work will occur without operation shutdown. . . . . . . ~ Is presence of H2S gas probable. . . . . . . . . . . . ~ ,()A- '~ N N N N N u-P.Á- N N APR ~ GEOLOGY 30. 31- 32. 33. þ.¿ 34. Permit can be issued wlo hydrogen sulfide measures. . . .Y Data presented on potential overpressure zones. . Y Seismic analysis of shallow gas zones. . . . . . . Seabed condition survey (if off-shore) . Contact name/phone for weekly progress reports. . [exploratory only] /vi /1 , , GEOLOGY: RPc#C / ENGINEERING: B~ l{ Þ\ JDH~ COMMISSION: DW~ JDN TAB HOWlljb - A:\FORMS\cheklist rev 11195 Comments/Instructions: Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. ~-, /~, MPB24.tmp created Wed Jun 11 09:50:22 1997 by CLEANUP V1.0 * 7q q ò q ~/ t \) C\ ISL ISL Summary Listing - version 1.01 ISL ISL Date Processed - 11 JUN 97 ISL Input File Name - MPB24 ISL i-"'j.~""",'"f,,~.,,',,,\,~ ~~,' f,,'1 ~:<,~,'\\ ~\ te.\' û raft ,~,,\.~{ vI ,-,~,Ia" IC) I ... Ó '3 ~ Dl Date v ¡F~,r::,(~; ~::, \l'-:",.;(' ~t:~ t" " ! U \1 1 ." FHì '7 ",) \, ¡ ,'.,J'. / N;;~j([;~ O;~ b G!!;; C(:rn, C:.;¡ ¡1::;j~;G;UU ð~nt¡:vrrXJ:: ,-'- File 1 - File Header Information Reel Nbr - 1 Tape Nbr - 1 File Nbr - 1 LIS File Nbr - 001 Start - Stop Depth Service Name - MINCOM Service Sub Name - MWD Origin of Data - File Type - LO Reel Comments - Tape Comments - 3995.0 - 12539.5 (F) / -.... File 1 - Channel Listing Mnem NbrSamp NbrEntry ServID Stat InUnit OutUnit Start Stop DEPT 1 1 MWD 01 ALLO F F 3995.000 12539.500 AT1F 1 1 MWD 0 1 ALLO OHMM OHMM -999.250 -999.250 ATR 1 1 MWD 0 1 ALLO OHMM OHMM -999.250 -999.250 DCAL 1 1 MWD 0 1 ALLO IN IN -999.250 -999.250 DER 1 1 MWD 0 1 ALLO OHMM OHMM -999.250 -999.250 DRHO 1 1 MWD 01 ALLO GCC GCC -999.250 -999.250 GR 1 1 MWD 01 ALLO API API -999.250 68.160 NPHI 1 1 MWD 01 ALLO PCT PCT 52.300 -999.250 PEF 1 1 MWD 01 ALLO BARN BARN -999.250 -999.250 PS1F 1 1 MWD 01 ALLO OHMM OHMM -999.250 -999.250 RHOB 1 1 MWD 0 1 ALLO GCC GCC -999.250 -999.250 ROP 1 1 MWD 01 ALLO FTHR FTHR -999.250 52.110 RPD 1 1 MWD 01 ALLO OHMM OHMM -999.250 3.480 RPM 1 1 MWD 01 ALLO OHMM OHMM -999.250 3.310 RPS 1 1 MWD 01 ALLO OHMM OHMM -999.250 3.210 RPX 1 1 MWD 01 ALLO OHMM OHMM -999.250 3.130 RPXX 1 1 MWD 01 ALLO OHMM OHMM -999.250 2.990 r-==-, File 1 - Comments Listing File does not contain any comments