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215-095
Carlisle, Samantha J (DOA) From: Loepp, Victoria T (DOA) Sent: Tuesday, March 01, 2016 7:19 AM To: Carlisle, Samantha J (DOA) Subject: FW: Cancel Permit for S-136 (PTD #215-095) Please handle. Thanx, Victoria From: Lastufka, Joseph N[mailto:Joseph.Lastufka(a)bp.com] Sent: Monday, February 29, 2016 3:53 PM To: Loepp, Victoria T (DOA) Subject: Cancel Permit for S-136 (PTD #215-095) Victoria, Please cancel the Permit to Drill for S-136 (PTD #215-095). We will be submitting a replacement sidetracked well in its place. Please let me know if you have any questions or need additional information. Thank you, Joe Lastufka Information and Data Controller Cell: (907) 227-84961 Office: (907) 564-4091 w BP Exploration AlaskaJ900 E. Benson B1vd.lRoom: 788DIAnchorage, AK -------------------------------------------------------------------------------------------- 1 i THE STATE "'ALASKA GOVERNOR BILL WALKER Ken Allen Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, PBU S-136 BP Exploration (Alaska), Inc. Permit No: 215-095 1 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Surface Location: 4137' FSL, 4503' FEL, SEC. 35, T12N, R12E, UM Bottomhole Location: 604' FSL, 3545' FEL, SEC. 21, T12N, R12E, UM Dear Mr. Allen: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P. Foerster Chair DATED this �&y of June, 2015. STATE OF ALASKA RECEIVED ALA,,--, OIL AND GAS CONSERVATION COMA 3ION JUN 04 2015 PERMIT TO DRILL 20 AAC 25.005 A n � r'r 1 a.Type of work: 1 b.Proposed Well Class: • ® Development Oil ❑ Service - Wini • ® Sinqle Zone 1 c. Specify if well is proposed for: ® Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas 2. Operator Name: 5. Bond • ® Blanket ❑ Single Well 11. Well Name and Number. BP Exploration (Alaska) Inc. Bond No 6194193 PBU S-136 3. Address 6. Proposed Depth: 12. Field / Pool(s) P.O. Box 196612, Anchorage, Alaska 99519-6612 MD 14828' • TVD 6823' Prudhoe Bay / Aurora Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: ADL 028257 & 028256 61..e " G �•� !S 4137' FSL, 4503' FEL, Sec. 35, T12N, R12E, UM 8. Land Use Permit: 13. Approximate Spud Date: Top of Productive Horizon: 432' FSL, 2365' FEL, Sec. 21, T12N, R12E, UM January 15, 2016 9. Acres in Property: 14.Distance to Nearest Property: Total Depth 604' FSL, 3545' FEL, Sec. 21, T12N, R12E, UM 2560 6900' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10.KB Elevation above MSL: 82.95' feet 15.Distance to Nearest Well Open Surface: x 618930 . y- 5980341 • Zone- ASP4 GL Elevation above MSL: 36' feet to Same Pool: 1340' 16. Deviated Wells: Kickoff Depth: 300' feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 104 degrees Downhole: 3276 • Surface: 2591 ' 18. Casing Program Specifications Top - Setting Depth - Bottom Quantity of Cement, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" x 34" 129# A-53 80' Surface Surface 80' 80' 12-1/4" 9-5/8" 40# L-80 TCII 4108' Surface Surface 4108' • 2903' 1778 sx Dee Crete 410 sx Class 'G' 8-3/4" 7" 26# L-80 VamTop HC 13602' Surface Surface 13602' 6823' 472 sx LiteCrete 181 sx Class 'G' 6-1/8" 4-1/2" 12.6# 13Cr85 VamTop 1376' 13452' 6723' 14828'. 6823' 1181 sx Class' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD 7 Effective Depth TVD (ft): Junk (measured) Casing Length Size Cement Volume MD TVD Conductor / Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20.Attachments: ❑ Property Plat ® BOP Sketch ® Drilling Program ❑ Time vs Depth Plot ❑ Shallow Hazard Analysis ® Diverter Sketch ❑ Seabed Report ® Drilling Fluid Program ® 20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct: Contact Brad Gorham, 564-4649 Email Bradley.Gorham@bp.com Printed Name Ken Allen Title Engineering Team Leader Signature Phone 907-564-4366 Date Commission Use Only Permit To Drill j �/ 5a�� API Number: 2 �!Z �- �����L� Permit Approv I ate: �J01,57 See cover letter for Number: 50- )�i other requirements: Conditions of Approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas Q /" contained shales: Other: 13 D ,0 f CS f f� SO U 5 Samples Req'd ❑ Yes EI No Mud Log Req'd: ❑ Yes BIND f} n vt ! a r'P i C Ye' ve f fa Z 55i�UP 5) HZS Measures: © Yes ❑ No Directional Survey Req'd: Yes [],No Spacing exception req'd: ❑ Yes D/No inclination -only svy Req'd: ❑ Yes ® No J APPROVED BY n1 �LV9(L--COMMISSIONER — ) APPROVED BY THE COMMISSION Date — i Form 10-401 Revised 10/2012 TMGT f nths from the date of approval (20 AAC 25.005(g)) Submit Form and Attachments In Duplicate V7-L- to 1Z s115--NA � ��-�� "�;' /5. by r0+4r To: Alaska Oil & Gas Conservation Commission From: Brad Gorham, ODE Date: June 4, 2015 RE: S-136 Permit to Drill The S-136 well is scheduled to be drilled by Parker 273 in Jan 2016. This grassroots well is a horizontal producer targeting the Kuparuk C Sands. The planned well is a three string, ultra-slimhole design using a 9-5/8" surface casing, 7" intermediate casing, and 4-1/2" production liner. The surface casing will be set in the SV3 shale. The intermediate casing will be set at the top of the Kuparuk, and the production interval will be cemented and perforated. The maximum anticipated surface pressure from the Kuparuk with a full column of gas from TD to surface is 2,550 psi (assumes 9.20 ppg EMW most likely pore pressure and a 0.1 psi/ft gas gradient). . The well will be drilled by Parker 273 using their 5,000 psi four preventer BOP stack (3 rams and an annular). The BOP rams and annular will be tested to 3,500 psi. A detailed operations summary is included with the permit application. Below is a brief summary of planned drilling operations: 1. Move in Parker 273 and function test diverter. 2. Drill 12-1/4" surface hole to —4,108 ft MD. 3. Run 9-5/8" surface casing and cement to surface. 4. Nipple up BOPE and test rams to 3,500 psi. 5. Pressure test surface casing to 3,500 psi. Drill out the shoe and perform LOT. 6. Drill 8-3/4" intermediate hole to top of the Kuparuk C4 at—13,602 ft MD. 7. Run 7" casing and cement to 500 ft MD above Schrader Bluff Na (SB_Na) (TOC at —8,792 ft . MD). Pressure test casing to 3,500 psi. 8. Drill out of intermediate shoe and perform FIT. 9. Drill 6-1/8" horizontal production hole through Kuparuk C3 to TD at —14,828 ft MD. 10. Run and cement 4-1/2", 12.6# 13Cr-85 liner. 11. Pressure test liner and liner top packer to 3,500 psi. 12. Run 4-1/2" chrome completion tubing. Sting into liner tieback sleeve and set production packer. 13. Pressure test the tubing and the inner annulus to 3,500 psi each. 14. Rig down and move off the well. In addition to a planned well summary, a proposed completion diagram, directional plan, planned diverter layout, wellhead, and tree diagrams are attached to the permit application. If there are any questions concerning information on S-136, please do not hesitate to use the contact information below. Brad Gorham Office: (907) 564-4649 Cell: (907) 223-9529 Email: Bradley.Gorham (a)_bp,com Attachments: Well Bore Schematic Directional Plan BOPE Schematic Diverter Line Layout Diagram Well Head Schematic Tree Schematic S-136 PTD 1 6/4/2015 Planned Well Summary Well S-133 Well Producer Obarget Kuparuk pectivCurrent Status Grass Roots Well Estimated Start Date: 1/15/2016= Time to complete: 34.8 Days Northing Easting Offsets TRS Surface 4136.8' FFEL 4503.09' Location 5980340.65 618930.38 12N 12E Sec 35 Northing Easting TVDss Offsets TRS 3 5,987,065.50 610,392.33 6,738' 4847.1' 2365.2' 12N 12E Sec 21 TKgt FEL/ Tgt 6 5,987,220.00 609,210.00 6,740 4675.2' FNL / 3544.7' 12N 12E Sec 21 BHL FEL Planned KOP: 300' MD Planned TD: 14,828' MD / 6,740' TVDss Rig: Parker 273 GL-RT: 46.95' RTE (ref MSQ: 1 82.95' Directional - SLB wp06 KOP: 300' MD Maximum Hole Angle: -67' in the 8-3/4" intermediate section -1040 in the production section Close Approach Wells: None Survey Program: Surface to 1,700' MD = GYRO 1.700' MD to TD = MWD+IFR+MS Nearest Property Line: -6,900' Nearest Well within Pool: I -1,340' S-107 S-136 PTD 2 6/4/2015 Formation Tops and Pore Pressure Estimate (SOR) Formation Estimated Formation Top (TVDss) Minimum Pore Pressure (EMW ppg) Most Likely Pore Pressure (EMW ppg) Fluid Type (for sands) G1 335 8.35 8.40 Water/ Ice SV6 1,565 8.35 8.40 Water/ Ice BPRF 1,860 8.35 8.60 Water/ Ice EOCU 2,075 8.35 8.40 Water SV5 2,195 8.35 8.40 Water SV4 2,380 8.35 8.60 Water SV3 2,760 8.35 8.60 Water 9 5/8" Surface Csg (50' tvd above SV2 2,820 8.35 8.60 SV2 2,870 8.35 8.70 Water/ Gas cut mud SV1 3,160 8.35 9.00 Water/ Free Gas Fault #1 3,370 8.35 9.00 UG4 3,470 8.35 8.85 Water/ Heavy Oil UG4A 3,520 8.35 8.85 Water/ Heavy Oil UG3 3,935 8.35 8.85 Water/ Heavy Oil UG1 4,370 8.35 8.70 Water/ Heavy Oil UG MA 4,670 8.35 8.70 Water/ Heavy Oil UG_MB1 4,715 8.35 8.70 Water/ Heavy Oil UG_MB2 4,760 8.35 8.70 Water/ Heavy Oil UG_MC 4,825 8.35 8.70 Water/ Heavy Oil NA 4,865 8.35 8.70 Water NB 4,875 8.35 8.70 Water NC 4,895 8.35 8.70 Water NE 4,905 8.35 8.70 Water NF 4,935 8.35 8.70 Water OA 5,015 6.30 8.60 - Water OBA 5,025 6.30 8.60 Water OBB 5,055 6.30 8.60 Water OBC 5,100 6.30 8.60 Water OBD 5,140 6.30 8.60 Water OBE 5,180 8.35 8.60 Water OBF 5,230 8.35 8.60 Water OBF BASE 5,260 8.35 8.60 Water CM2 5,660 8.40 - 9.20 Water/ Gas cut mud Fault #2 5,980 8.40 9.20 Water/ Gas cut mud CM-1/TLBK 6,320 9.60 10.00 Water/ Gas cut mud THRZ 6,580 9.60 10.00 Water/ Gas cut mud TKLB 6,640 9.60 10.00 Water/ Gas cut mud TKUD 6,738 7.40 9.20 Light Oil TKC4 6,738 7.40 9.20 Light Oil 7 " intermed casing 6,740 7.40 9.20 Light Oil TKC3D 6,759 7.40 9.20 Light Oil TKC3C 6,777 7.40 9.20 Light Oil TKC36 6,812 7.40 9.20 Water �,, �- �'a V- /0, S-136 PTD 3 6/4/2015 Fault #3 6,844 7.40 9.20 Water TKC36 6,823 7.40 9.20 Water TKC3C 6,792 7.40 9.20 Water TKC313 6,771 7.40 9.20 Water TD 6,740 7.40 9.20 Water Casing/Tubing Program 6,g, I-(' Hole Size Liner / MR Grade Conn Length Top Bottom Tbg O.D. MD / TVDss MD / TVDss 20" x 34" 129# A-53 - 80' Surface 80' / 13.6' 12-1/4" 9-5/8" 40# L-80 TCII 4,108' Surface 4,108'/2,820' 8-3/4" 7" 26# L-80 VamTop HC 13,602' Surface 13,602' / 6,740' 6-1/8" 4'/2" 12.6# 13Cr-85 VamTop 1,376' 13,452' / 6,640' 14,828' / 6,740' (150' lap) Tubing 4'/2' 12.6# 13Cr-85 VamTop 13,452' Surface 13,452'/6,640' (-5' into liner TBS) Mud Program Surface Mud Properties: Drill lex 12-1/4" Hole Section ty YP LSR-YP Depth Interval (PPg) PV (cp) (lb/1 00ft2) API FL (2x3 - 6) pH rpm Surface - 4,108' MD 8.8 - 9.2 - 30-50 50-80 <15 <1000 10.8 Intermediate Mud Properties: LSND 8-3/4" Hole Section Depth Interval Density PV (cp) IbNo0ft2 API FL HTHP FL MBT pH 4,108' MD - 12,700' MD g 6 - 9.8 10-15 20-30 <8 NA <20 8.5 - 9.5 (-200' above CM 1) 12,700' MD - 13,602' MD 10.4 - 10.6 10 - 18 18 - 26 <8 NC <18 9 - 10 (Section TD) , Production Mud Pro erties: Water Based Polymer Fluid (FloPro) 6-1/8" Hole Section Depth Interval Density PV (cp) lb/1 Oft2 API FL HTHP FL MBT pH 13,602' MD - TD 9.6 - 10.0 . <12 10 - 20 1 <10 1 >15000 <4 8 - 9.5 Logging Program 12-1/4" Surface I Sample Catchers - not required for surface hole Drilling: Dir/GR Open Hole: None Cased Hole: None 8-3/4" Intermediate Sample Catchers - as required by Geology Drilling: Dir/GR/GRAB/RES Open Hole: None Cased Hole: None 6-1/8" Production Sample Catchers - as required by Geology Drilling: Dir/GR/GRAB/RES/NEU Open Hole: None Cased Hole: None S-136 PTD 4 6/4/2015 Cement Program Casing Size 9-5/8" 40# L-80 BTC Surface Casing Lead Open hole volume + 350% excess in permafrost and 40% excess below permafrost Basis Lead TOC Target surface Tail Open hole volume + 40% excess + 80 ft shoe track Tail TOC 500 - 1,000 ft MD above casing shoe Spacer -100 bbls of Viscosified Spacer weighted to -10.5 p (Mud Push II Total Cement Lead' 606 bbls, 3,397 cuft, 1,778 sks of 11.0 ppg Dee CRETE, Yield: 1.91 cuft/sk Volume Tail 84.78 bbls, 475 cult, 410 sks 15.8 lb/gal Class G - 1.16 cuft/sk Temp BHST 54° F Casing Size 7" 26# L-80 amTop Intermediate Casing Lead Open hole volume + 40% excess Lead TOC Target 500 ft MD above Schrader Bluff DPZ (-8,700' MD) Basis Tail Open hole volume + 40% excess + 80 ft shoe track Tail TOC 500 - 1,000 ft MD above casing shoe Spacer -50 bbls of Viscosified Spacer weighted to --11.0 Mud Push II) Total Cement Lead 146.27 bbls, 821.16 cuft, 471.9 sks of 11.5 ppg LiteCRETE, Yield: 1.74 cuft/sk Volume Tail 37.49 bbls, 210.4 cuft, 181.4 sks 15.8 lb/gal Class G - 1.16 cuft/sk Temp BHST 154' F P20D!/C7/oN L/h/ER r(-- Casin Size 4-1/2" 12.6# 13Cr-86 VamTo Lead Open hole volume + 40% excess Basis Lead TOC Top of 4-1/2" Liner at 13,452' MD Tail None Planned Spacer -50 bbls of Viscosified Spacer weighted to -11.0 Mud Push II) Total Cement Lead 37.38 bbls, 209.62 cuft, 180.70 sks of 15.8 Ilb/ al Class G, Yield: 1.16 cuft/sk Volume Tail None Planned Tern BHST 154' F Surface and Anti -Collision Issues Surface Close Proximity: No wells will be affected by the Parker 273 rig shadow. Sub -Surface Pressure Management: Jurassic/Cretaceous: Check pressure estimates 1 month prior to spud and verify that injection rates have not changed in the closest injection wells. Obtain SIBHP from S-107i and S-114Ai 3-6 months prior to spud and shut-in 2 weeks prior to well spud. If S-114Ai pressure is greater than 3,600 psi then evaluate a longer shut-in time. Anti -Collision: None, all wells pass major risk criteria for WP06. S-136 PTD 5 6/4/2015 Hydrogen Sulfide ,f S Pad is considered an H2S site. Recent H2S data from the pad is as follows: Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level S-43 28 1/8/2015 #2 Closest SHL Well H2S Level S-42 66 9/25/2014 #1 Closest BHL Well H2S Level S-100 122 1/10/2015 #2 Closest BHL Well H2S Level S-106 50 3/20/2015 #3 Closest BHL Well H2S Level S-119 25 1/11/2015 #4 Closest BHL Well H2S Level S-102 10 1/9/2015 Max Recorded H2S on Pad/Facility S-201 180 3/9/2012 Note - Neighbouring well S-41 was converted to an injector in 2013. Faults Formation Where Fault MD Intersect TVDss Intersect Throw Direction and Magnitude Uncertainty Lost Circ Potential Encountered Fault #1 - SV1 5,522.0 3,370.0 West, 100 ft. +/- 250 ft. MD Low Fault #2 - CM2 12,148.0 5,980.0 West, 60 ft. +/- 250 ft. MD Low Fault #3 - 13,980.0 6,844.0 West, 10 ft. +/- 200 ft. MD Moderate Ku aruk Drilling Waste Disposal • There is no annular injection in this well. ` • Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS-04. Any metal cuttings will be sent to the North Slope Borough. • Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for injection. Haul Class I waste to DS-04 and/or Pad 3 for disposal. Contact the GPB Environmental Advisors (659-5893) for guidance. S-136 PTD 6 6/4/2015 Well Control The 12-1/4" surface hole will be drilled with a diverter (see attached diverter layout). The 8-3/4" hole and 6-1/8" hole sections will be drilled with well control equipment consisting of 5,000 psi working pressure rams (2), blind/shear rams, and annular preventer capable of handling the maximum potential surface pressures. Based upon calculations below, BOP equipment will be tested to 3,500 psi. BOP test frequency for S-136 will be 14 days with function test every 7 days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14 day BOP test period should not be requested. 8-3/4" Intermediate Interval Maximum anticipated BHP 3,223 psi at the TKUD at 6,738' TVDss (9.2 ppg EMW) Maximum surface pressure 2,549 psi at the TKUD (0.10 psi/ft gas gradient to surface) 25 bbls with 12.0 ppg frac gradient. Kick tolerance Assumes 9.2 ppg pore pressure in the KUP + 0.5 ppg kick intensity and 10.8 ppg MW. Planned BOP test pressure Rams test to 3,500 psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test — 12-1/4" hole LOT after drilling 20'-50' of new hole 9-5/8" Casing Test 3,500 psi surface pressure 6-1/8" Production Interval Maximum anticipated BHP 3,276 psi in the KC4 at 6,849' TVDss (9.2 ppg EMW) Maximum surface pressure 2,591 psi (0.10 psi/ft gas gradient to surface) Kick tolerance Infinite with >11.2 ppg frac gradient. Assumes an 9.2 ppg max pore pressure in the KC4 + 0.5 ppg kick intensity and 9.7 ppg MW. Planned BOP test pressure Rams test to 3,500 psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test — 6-1/8" hole FIT after drilling 20'-50' of new hole 4-1/2" Liner Top Packer 3,500 psi surface pressure Planned completion fluids 8.5 ppg seawater / 2,200 ft diesel to 1,932 ft TVDss S-136 PTD 7 6/4/2015 Variance Requests 1. To avoid the risk of plugging the flow line with large rocks and wood encountered while drilling surface hole, it is requested to drill without a flow paddle for the first portion of the surface hole. After drilling past the larger rocks and wood sections, the flow paddle will be put back in the flow line (<1000 ft). This is a variance from 20 AAC 25.033. Procedures/Safeguards with paddle removed: • Fluid levels will be monitored in the pits for both gains and losses while drilling. Alarms will be set to indicate if gain or loss of more than 5 bbls has occurred. • The well will be monitored for flow when the pumps are off at each connection. • The planned 8.8 — 9.2 ppg fluid will provide over balance to formation fluid. S-136 PTD 8 6/4/2015 S-136 OPERATIONS SUMMARY Pre -Rig Work: 1. Set a 20" conductor. Weld an FMC landing ring for a Gen 5 well head. 2. If necessary, level the pad and prepare location for rig move. 3. Remove well houses as necessary. 4. Validate injection/production in area per SOR. Rig Operations: 1. MIRU Parker 273. Nipple up diverter spool and function test diverter. Notify AOGCC 24 hours in advance of test. 2. Prepare pits with spud mud and PU DP as required and stand back in derrick. 3. MU 12-1/4" drilling assembly with MWD/GR and directionally drill surface hole to Base Permafrost. Gyro survey until magnetic interference clears up. CBU and short trip to surface. Change bit and dial up/down motor bend as required. 4. RIH and continue drilling 12-1/4" surface hole to section TD at—4,108' MD in SV3. CBU until hole is clean. POOH on elevators (if b$ackreaming is required, RIH until able to POOH on elevators). Lay down BHA. 5. Run and fully cement 9-5/8" 40# BTC-M casing to surface, displacing cement with drilling fluid. A TAM port collar may be run between 500' - 1000' MD as a contingency. 6. ND diverter and NU casing head and spacer spool. NU BOPE (Configured from top to bottom: annular preventor, 2-%e" x 5'/2" VBR, blind/shear, mud cross, 2-7/8" x 5'/2" VBR). Test BOPE to 250 psi low, 3,500 psi high. Give the AOGCC 24 hrs notice prior to testing. 7. Pressure test 9-5/8" surface casing and wellhead to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high (this will test casing, wellhead, and OA valves). 8. Make up 8-3/4" drilling BHA with RSS and MWD/GR/GR at bit/RES/PWD and RIH to float collar, picking up drillpipe as required to TD intermediate interval. 9. Drill out shoe track and displace well to LSND drilling fluid. Drill 20' of new formation and perform LOT. 10. Drill ahead in the intermediate hole per the drilling program with specific mud weight -ups with a special focus on effective hole cleaning through this long section of the well. 11. Drill ahead to the intermediate hole TD at the Top KUP (estimated at—13,602' MD). At TD, CBU, and condition hole as necessary to run 7" casing. POOH. 12. Change upper cavity rams to 7" fixed. RU and run 7" 26# L-80 Vam Top HC casing to TD. Cement the 7" casing to 5,500' MD. After bumping the plug on the cement job, pressure test the 7" casing to 3,500 psi for 30 charted minutes. 13. Install 7" packoff and test void to 250 psi low / 5,000 psi high. 14. Change 7" rams to to 2-7/8" x 5-1/2" VBR's in upper cavity and test. 15. Freeze -protect the 9-5/8" x 7" annulus to —2000' MD, once cement has reached 500 psi compressive strength. Confirm that the OA is open before freeze protecting. 16. PU 6-%" drilling BHA assembly to include MWD/GR/Res/Den/Neu and RIH to the float collar. (NOTE: This section of the well may be drilled with a single BHA RSS.) 17. Displace the well to an 9.6 ppg FloPro. 18. Drill out shoe and 20' of new formation and perform the planned FIT. 19. Drill ahead in lateral section per rig site geologist to TD at—14,828' MD. 20. Circulate bottoms -up, short trip, circulate and condition hole for liner run. POOH. 21. MU and run 4-'/2" 12.6# 13CR-85 liner to TD. S-136 PTD 9 6/4/2015 22. Cement the 4-'/2" liner to top of liner displacing the cement with perf pill. Reciprocate liner throughout cement job. Bump plug and check floats prior to setting liner hanger. 23. Set liner hanger / liner top packer and circulate excess cement off the top of liner. 24. POOH, UD drillpipe and the liner running tool. 25. Pressure test liner to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high after cement reaches 500 psi compressive strength. 26. RIH with perforating assembly and perforate the well per procedure after cement reaches 1,000 psi compressive strength. CBU and POOH. Laydown guns and verify all shots have fired. 27. R/U and run a 4-1/", 12.6#, 13Cr-85, VamTop tubing completion. Space out and land the tubing with tubing tail inserted into the liner tieback sleeve. 28. Make up tubing hanger per FMC Rep. Land the tubing hanger, and run in lock down screws. 29. Reverse circulate brine and corrosion inhibitor into the tubing x casing annulus. 30. Drop ball/rod and set packer and individually test the tubing to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high. Bleed tubing pressure to 1,500 psi and test annulus to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high. Record each test. 31. Shear the DCK valve. Pump both ways to confirm valve has sheared. 32. With landing joint still rigged up, reverse circulate diesel freeze protect using rig injection pump. 33. Allow diesel to U-tube, drain stack, and rig down landing joint. Monitor well for 1 hour to confirm well is dead. 34. Install TWC and test from above to 250 psi low / 3,500psi high for 5 minutes low / 30 minutes high. 35. Nipple down the BOPE. Nipple up the adaptor flange and tree and test to 5,000 psi with diesel. a. Ensure Heet® is left on TWC and only diesel (no water) is left in tree. 36. Install all annuls valves and secure the well. Ensure T/IA/OA all have two barriers in place. 37. Secure the well. Rig down and Move Off. Post -Rig Work: 1. Pull TWC 2. MIRU slickline. Pull the ball and rod / RHC plug. Install generic GLM design 3. Blue Goo 9 %" x 20" annulus. 4. Install well -house and instrumentation and flowline. 5. Pre -produce well. S-136 PTD 10 6/4/2015 S-136 Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Surface Hole: No overpressure is expected in the surface hole and possible hydrates have been present below the permafrost. Surface broaching has occurred on S-Pad. Keep and maintain the mud temperature as low as possible. B. Intermediate Hole: There is a low potential for free gas to be present in the SV 1 which will be mitigated by utilizing 9.4 - 9.6 ppg mud weight to prevent bringing any gas to surface. C. Production Hole: The Kuparuk is expected to be at a 9.2 ppg EMW. Reservoir pressures will be controlled by using 9.6 — 10.Opgg water based mud. II. Lost Circulation/Breathing A. Surface Hole: Lost circulation is considered a minimal risk if mud properties remain in specification. B. Intermediate Hole: There are two expected fault crossings in the intermediate hole and both have a low probability of having lost circulation. Breathing in the Colville has occurred on S-Pad in the past, but is not considered a major risk. Maintain ECD hardlines and good tripping practices will be utilized to minimize the risk of breaking down the formations. C. Production Hole: The production hole has a moderate probability of having losses due to having one planned fault crossing. III. Fault Locations Formation Where Fault Encountered MD Intersect TVDss Intersect Throw Direction and Magnitude Uncertainty Lost Circ Potential Fault #1 - SV1 5,522.0 3,370.0 West, 100 ft. +/- 250 ft. MD Low Fault #2 - CM2 12,148.0 5,980.0 West, 60 ft. +/- 250 ft. MD Low Fault #3 - Ku aruk 13,980.0 6,844.0 West, 10 ft. +/- 200 ft. MD Moderate IV. Intearitv Testina Test Point Test Depth Testtype EMW (lb/gal) 9-5/8" Shoe 20'-50' from the 9-5/8" shoe LOT 12.0 ppg 7" shoe 20'-50' from the 7" shoe FIT 11.2 ppg S-136 PTD 11 6/4/2015 V. Hydrogen Sulfide S-Pad is considered an H2S site. Recent H2S data from the pad is as follows: Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level S-43 28 1/8/2015 #2 Closest SHL Well H2S Level S-42 66 9/25/2014 #1 Closest BHL Well H2S Level S-100 122 1/10/2015 #2 Closest BHL Well H2S Level S-106 50 3/20/2015 #3 Closest BHL Well H2S Level S-119 25 1/11/2015 #4 Closest BHL Well H2S Level S-102 10 1/9/2015 Max Recorded H2S on Pad/Facility S-201 180 3/9/2012 Note - Neighbouring well S-41 was converted to an injector in 2013. VI. Anti -Collision Issues - None CONSULT THE S-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. S-136 PTD 12 6/4/2015 SAF -NOTES: WELL ANGLE> 70° @ TREE= 41 S � 13 6 VI�LFEAD= 4-1/16' 5M 5MFMc PROPC �L ACTUATOR= OIB. ELEV = 100.9' BF. ELEV = 53.9' KOP = —300' Max Angle = _' @ Datum MD = D6tumTVD= 88W SS 2 # D �.. 9-5/8" CSG, 40#, L-80 BTC, D = 8.834" 4j OW Minimum ID = 3.725" @ 4-1/2" HES XN NIPPLE OF CEMWF 1-� —8,700' ITOP OF 4-1/2" LNR 1--i —13,442' 4-1/2" TBG, 12-6#, 13CR-_VAM TOP, �13,44T .0152 bpf, D = 3.958" 7" CSG, 26#, L-80 VAM TOP HC,-13,602' .0383 bpf, D = 6.276" PERFORATION SUMMARY REF LOG ON XX/XYJXX ANGLE AT TOP PERF: @ Note: Refer to Production DB for historical pert data SIZE I SPF I NTFRVAL I Opn/Sqz I SHOT I SQZ PBTD 4-1/2" LNR, 12.6#, 13CR-_, VAM TOP, ^-14,828' .0152 bpf, 1) = 3.958" -500 - 1000' 1-19-5/8" TAM PORT COLLAR -2000 4-1/2" HES X NIP, D = 3.813" GAS LIFT MANDRELS ST MD TVD DEV TYPE I VLV LATCH PORT DATE 4 5,810' 3,575' 3 10,188' 5,300' 2 12,224' 6,100' 1 13MV 6,500' 4-1/2- HES X NIP, D = 3.813" ^-13,302' �7" X 4-1/2' HES TNT PKR, D = 3.856" 4-1/2" HES X NP, D = 3.813" —� 4-1/2" HES XN NIP. D = 3.725" --13,447'-4-1l2" WLEG, D= " �52° 7" X 5" BKR HRD-E ZXP LTP w / ' T1EBK , " fiMD TT NOT LOGGED 7" X 5" HES V ERSA FLEX HGR, D = " �—]5" X 4-1/2" XO, D = 3.900" PRUDHOE BAY UNIT WELL: S-136 PERMT No: API ND: 50-029- -00 SEC _, T N, _E,_' FNL & FWL DATE REV BY C *AV[34 5 DATE REV BY COMMENTS XXIXXI14 INITIAL COMPLETION BP Exploration (Alaska) 0 r- 0 a W OC 13 O ,d V = � a 0 N Q O O a` m a_ w r N N C • • 07 j � O W L J J O m O O m m W 15 Z 2 m p m m 0 m m c N E m o H w• o m a N Z o E Zo o W -E—o �wooxNomol 0 o O o �coio�mn`AOOurim O cc Y t z cc c r � m = ' c in w � a9•°12 > Qin v ni ccmr m • ® m E O0W c a a� �.. m0 O c c O G• LL c a•+ c• c Z 6, .2. v C C 0 .•O •a _s o m m El R J O m r o 0 0- O C 0 C❑ m W N 2 O W u n i A O D `m c O O m 'O o � 1' C C '• '2 C 0.L U U CV C2O C u a Y�$ N>><9�F 'UF ri C�2C7F y O m m m CO (V o o ai a W c a 3 w _ W m , O D N O Q X W Y W m � x r N � V) tW+I tW+l X a N e Q� • tO0 O m O ❑ v) O� m m n N O O m N a Q c c N (+WI Q N O m m m n tp D_ a N m o A N Q r m m N m 2m a rO aatO 05NZ Z ZO ON E o m w ) ac W m Y c 01 Y Oe W m c `e O W O .. 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Cl C) CD C) CY) INS CD LLI C) CD CD C) C) 00 PH. 00 CD I!i I �i i! Eli iiiiiii i i i i iii =- .2) O C, !!! CD C) H i ii, C) ..... ....... ri C:) C) H CD ini iiiiiii i ii r i Cl IL C) CD (D CD co 47 00 C) CD C) z C) U') ro CD W) RI N < 86 N. CD CD i i = CD CD r— z C) .0 lial iiiii ii i CD CD C) C) co iri iiii— L! CD CD CD C:) iri iiiiiii i CD 04 ! deirii iiiiiii i CD CD i CDCD CD SQ! rii i i§g I lai : w i I IVR i. C) CD C) 0 CD C, 0 C) C) 0 CD 0 Cl C) CD CD o CN C) co CD Cl CD C) 0 Woog 1: L = al-S (4) 4/\i C- CQ / a W C.2 2 & / \ « ) \ m !S J t ! LL k . § _ a t)\ 7=a � c 2 CL , � 7 CD � - \ � � - . )s x ! ! ,( 8� j! ;( §[ @ ; a else=mom v m \\\ . LU I I 0 j p �— o r I co ! f I •- j j I I o I j I r 'n o — i r o N r C i � j p O C � O O in o i N o v Q I 1 00 a)O7 cc c y o �d v 'v �� (n ;c - - -- ----- -- ----o I o j y O 7 pp n ch cb I I I � C O CD Q r 63L in T co N r j o0 n r LaU� El) --- — — — — — ;mctsccr—z CLCLiL0-0- O V�NC O �.�j N ,� •� N �O i i O O 1n O N O In O N O In O p Ln p I� O w Ln In w V (o m N N .- (ui/usn 0 uoilejedag aiivao of ailuao Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB S Pad Site Error: 0.00usft Reference Well: Plan S-136 (Arsenal) Well Error: 0.00usft Reference Wellbore Plan S-136 Reference Design: Plan #6b S-136 BP Anticollision Report Local Coordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVO Reference: Well Plan 5-136 (Arsenal) 5-136 plan @ 82.95usft (rigx) S-136 plan @ 82.95usft (rigx) Tru e Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference Plan #6b 5-136 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 5.00usft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,678.18usft Error Surface: Elliptical Conic Survey Tool Program Date 5/19/2015 From To (usft) (usft) Survey (Wellbore) 46.95 1,700.00 Plan #6b 5-136 (Plan 5-136) 1,700.00 3,200.00 Plan #6b 5-136(Plan S-136) 1,700.00 4,100.00 Plan #6b 5-136 (Plan S-136) 4,100.00 5,600.00 Plan #6b 5-136 (Plan 5-136) 4,100.00 13,600.00 Plan #6b 5-136 (Plan 5-136) 13,600.00 14,828.76 Plan #6b 5-136 (Plan 5-136) 13,600.00 14,828.76 Plan #6b 5-136 (Plan S-136) Tool Name Description GYD-GC-SS Gyrodata gyro single shots MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 511912015 8 06.-46AM Page 2 of 5 COMPASS 5000.1 Build 61 BP Anticollision Report Company: North America - ALASKA- BP Project: Prudhoe Bay Reference Site: PB S Pad Site Error. O.00usft Reference Well: Plan S-136 (Arsenal) Well Error: O.00usft Reference Wellbore Plan S-136 Reference Design: Plan #6b S-136 Local Co-ordinate Reference: TVD Reference: MD Reference North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well Plan S-136 (Arsenal) S-136 plan @ 82.95usft (dgx) S-136 plan @ 82.95usft (rigx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCPt Offset Datum Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) PB S Pad Plan Kup S-xxx Manchester United Slot SS-18 v3. 2,930.56 3,360.00 243.76 119.86 129.81 Pass - Major Risk S-100 - S-100 - S-100 3,938.36 3,710.00 172.87 144.79 34.00 Pass - Major Risk 5-101 - S-101 - S-101 1,940.98 1,925.00 162.01 41.68 127.42 Pass - Major Risk S-101-S-tOIPB1-S-101PB1 1,940.98 1,925.00 162.01 41.68 127.42 Pass - Major Risk S-102 - S-102 - S-102 263.74 245.00 316.18 4.77 311.41 Pass - Major Risk S-102 - S-102L1 - S-102L1 263.74 245.00 316.18 4.77 311.41 Pass - Major Risk S-102 - S-102L1 PB1 - S-102L1 PB 1 263.74 245.00 316.18 4.77 311.41 Pass - Major Risk S-102 - S-102PB1 - S-102PB1 263.74 245.00 316.18 4.77 311.41 Pass - Major Risk S-106 - S-106 - S-106 3,880.51 3,490.00 185.84 107.96 101.69 Pass - Major Risk S-106 - S-106PB1 - S-106PB1 3,880.51 3,490.00 185.84 108.07 101.58 Pass - Major Risk S-107 - S-107 - S-107 7,168.82 6,885.00 255.75 209.97 45.94 Pass - Major Risk S-112 - S-112 - S-112 497.42 485.00 192.01 9.52 182.50 Pass - Major Risk S-113 - S-113 - S-113 2,704.02 2,510.00 210.79 84.93 160.07 Pass - Major Risk S-113 - S-113A - S-113A 2,704.02 2,510.00 210.79 84.94 160.07 Pass - Major Risk S-113 - S-113B - S-113B 2,704.02 2,610.00 210.79 84.94 160.07 Pass - Major Risk S-114 - S-114 - S-114 3,003.09 2,740.00 219.40 104.81 144.55 Pass - Major Risk S-114 - S-114A - S-114A 3,003.09 2,740.00 219.40 104.81 144.55 Pass - Major Risk S-115 - S-115 - S-115 2,261.93 2,220.00 98.94 53.43 56.90 Pass - Major Risk S-116 - S-116 - S-116 1,543.83 1,535.00 140.01 28.58 113.34 Pass - Major Risk S-116 - S-116A - S-116A 1,543.83 1,535.00 140.01 29.02 112.91 Pass - Major Risk S-116 - S-116APB1 - S-116APB1 1,543.83 1,535.00 140.01 28.58 113.34 Pass - Major Risk S-116 - S-116APB2 - S-116APB2 1,543.83 1,535.00 140.01 28.58 113.34 Pass - Major Risk S-117 - S-117 - S-117 1,518.40 1,505.00 253.81 28.93 225.45 Pass - Major Risk S-118 - S-118 - S-118 567.26 550.00 149.81 9.67 140.21 Pass - Major Risk 5-119 - S-119 - S-119 395.95 375.00 361.30 7.19 354.12 Pass - Major Risk S-120 - S-120 - S-120 2,306.31 2,210.00 102.49 61.14 60.82 Pass - Major Risk S-121 - S-121 - S-121 373.51 355.00 120.00 6.47 113.54 Pass - Major Risk S-121 - S-121 PB1 - S-121 PBt 373.51 355.00 120.00 6.47 113.54 Pass - Major Risk S-122 - S-122 - S-122 783.10 775.00 246.57 13.11 233.48 Pass - Major Risk S-122 - S-122PBI - S-122PB1 783.10 775.00 246.57 13.11 233.48 Pass - Major Risk 5-122 - S-122PB2 - S-122PB2 783.10 775.00 246.57 13.11 233.48 Pass - Major Risk S-122 - S-122PB3 - S-122PB3 783.10 775.00 246.57 13.11 233.48 Pass - Major Risk S-125 - S-125 - S-125 1,573.47 1,555.00 45.09 30.29 17.46 Pass - Major Risk S-125-S-125PB1-S-125PB1 1,573.47 1,555.00 45.09 30.29 17.46 Pass - Major Risk S-200 - S-200 - S-200 540.76 525.00 164.65 8.39 156.31 Pass - Major Risk S-200 - S-200PB1 - 5-200PB1 540.76 525.00 164.65 8.39 156.31 Pass - Major Risk S-213 - S-213 - S-213 679.46 665.00 208.71 10.50 198.44 Pass - Major Risk S-213 - S-213A - S-213A 678.56 660.00 208.70 10.48 198.44 Pass - Major Risk S-213 - S-213AL1 - S-213AL1 678,56 660.00 208.70 10.48 198.44 Pass - Major Risk S-213 - S-213AL1-01 - S-213ALl-01 678.56 660.00 208.70 10.48 198.44 Pass - Major Risk S-213 - S-213AL2 - S-213AL2 678.56 660.00 208.70 10.48 198.44 Pass - Major Risk S-213 - S-213AL3 - S-213AL3 678.56 660.00 208.70 10.48 198.44 Pass - Major Risk S-216 - S-216 - S-216 1,311.09 1,300.00 107.54 23.49 85.23 Pass - Major Risk S-400 - S-400 - S-400 493.49 475.00 15.05 8.14 6.92 Pass - Major Risk S-400 - S-400A - S-400A 493.69 475.00 15.06 8.14 6.92 Pass - Major Risk S-401 - S-401 - S401 508.36 490.00 28.71 8.65 20.06 Pass - Major Risk S-401 - S-401 PBt - S-401 PB1 508.36 490.00 28.71 8.65 20.06 Pass - Major Risk S-41 - S-41 - S-41 446.63 435.00 15.47 6.96 8.53 Pass - Major Risk S-41 - S-41 A- S-4IA 442.86 425.00 15.41 6.90 8.53 Pass - Major Risk S-41 - S-41AL1 - S41AL1 442.86 425.00 15.41 6.90 8.53 Pass- Major Risk S-41 - S41 L1 - S-41 L1 446.63 435.00 15.47 6.96 8.53 Pass - Major Risk S-41 - S-41 PB1 - S-41 PB1 446.63 435.00 15.47 6.96 8.53 Pass - Major Risk S-42 - S-42 - S-42 696.04 685.00 44.51 12.12 32.41 Pass - Major Risk 5/19/2015 8:06:46AM Page 3 of 5 COMPASS 5000 1 Build 61 Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB S Pad Site Error: 0.00usft Reference Well: Plan S-136 (Arsenal) Well Error: 0.00usft Reference Wellbore Plan S-136 Reference Design: Plan #6b S-136 BP Anticollision Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well Plan S-136 (Arsenal) S-136 plan @ 82.95usft (rigx) S-136 plan @ 82.95usft (dgx) True Minimum Curvature 1.00 sigma EDM R5K -Alaska PROD - ANCP1 Offset Datum Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) PB S Pad S-42 - S-42A - Plan #5 S-42A kop 2000 693.80 695.00 44.48 12.08 32.40 Pass - Major Risk S-42 - S-42A- S-42A 46.95 45.85 43.80 0.91 42.89 Pass - Major Risk S-42 - S-42PB1 - S-42PB1 696.04 685.00 44.51 12.12 32.41 Pass - Major Risk S43 - S-43 - S43 449.80 435.00 77.64 7.55 70.10 Pass - Major Risk S-43 - S-431_1 - S-43L1 449.80 435.00 77.64 7.55 70.10 Pass - Major Risk S-44 - Plan S-44A- Plan #6 S-44A 563.84 565.00 106.58 8.88 97.76 Pass - Major Risk S-44 - S-44 - S-44 565.28 550.00 106.61 8.90 97.76 Pass - Major Risk S-44 - S-441_1 - S-441_1 565.28 550.00 106.61 8.90 97.76 Pass - Major Risk S44 - S-44L1 P61 - S-441_1 PB1 565.28 550.00 106.61 8.90 97.76 Pass - Major Risk S-504 - S-504 - S-504 128.95 120.00 45.42 3.48 41.94 Pass - Major Risk 511912015 8:06:46AM Page 4 of 5 COMPASS 5000. 1 Build 61 m Project: Prudhoe Bay Site: PB S Pad Well: Plan S-136 (Arsenal) Wellbore: Plan S-136 Design: Plan #6b S-136 From 13600'md (T) to TD Scan interal 25 ft Scale 1 inch : 50ft All wells pass the major risk See AC summary report for details 0 From Colour To MD 47 500 800 1100 1500 2000 3000 4000 5000 6000 7 125 7000 8 8000 — — --- 9 - _ 9000 1 100 300 60 75 50 2 50 240 75 120 100 ..- . 125. 210 150 1150 180 Azimuth from North [I vs Centre to Centre Separation [40 usft/in] )0 )0 100 500 )00 )00 )00 )00 )00 000 000 000 4835 90 V03 �S Cl/ -- I MOD 23 6 50co FMTedffabgies jM : j:"ill 's012 7 S 7 '_X<10'NN SCRENS -500, 4-5�, „rE_M PeRr NUMBER 'I� 2E SCRIM-iON �E3-300-030 �� 3 yE4-_R _4��DiW, 41ap: ' 39322 !�OOS'I: 3 S%2 --Aslgx —' P 7'1)7 IS, P- .r �_aNIDINC 9 n10 _ 6,8'3 CaSI SIC NFAD ASScu51 -_3 300-7i8 i �Epl 5 'JBiNG -F4:) ASSEMBL__ 2 27 .'021 / AS I:, H4tl.FR ------� ilk .0 i s 7 a A SEMB_ 9 "5b9b3 II UB NG �A CER ASHM6 / 9 02-0-47 T B.Ic -EA❑ A04P -R AS-FwB-; 9 23 ' -09B ' _ CA51NG �A'`IGFR J 7-B OD i;aS'IvG �i_ CAS NG -----a "' OJ CAS�PI - R�1-- Q, x 7 N M PRI VArE AND CONFIDENTIAL --SS E,—, S ]Esraior nu i na NJ NES S C C - liF-'.'I[ '] _ /'(F._ _ter AD vans +r< pnae x�rw E5 71l .f3[,g- PARKER 273 BOP STACK RAM TYPE BOP: DUTCH LOCK DOWN FLANGE SHAFFER LXT DOUBLE BOP 13 5/8"-5M 13 5/8"-5M STUDDED TOP 13 5/8"-5M FLANGED BOTTOM o o 13-5/8" 5M STUDDED TOP ANNULAR BOP W/(2) 14" UL2 OPERATOR, UPPER CAVITY SHAFFER LXT 5/8"-SM AND (2) 14" PSLK W/BSTR OPERATOR, LOWER CAVITY 13-5/8" 5M FLANGED BOTTOM: C. e � e � o o •� o a. DRILLING CROSS: 13 5/8"-5M FLANGED TOP 13 5/8"-5M FLANGED BOTTOM W (2) 3 1/8"-5M SIDE OUTLETS KILL LINE: 2-1/16" 5M FLEX HOSE 2-1/16" 5M X 3-1/8" 5M D.S.A. 3-1/8" 5M FLANGED MANUAL GATE VALVE 3-1/8" 5M FLANGED HYDRAULIC GATE VALVE r o 0 o o oo CHOKE LINE: RAM TYPE BOP: 3-1/8" 5M FLANGED MANUAL GATE VALVE SHAFFER LXT SINGLE 13 5/8" 5M 3-1/8" 5M FLANGED HYDRAULIC GATE VALVE 13 5/8"-5M STUDDED TOP 13 5/8"- 5M FLANGED BOTTOM 3-1/8" 5M FLEX HOSE W/(2) 14" UL2 OPERATOR Loepp, Victoria T (DOA) From: Gorham, Bradley M <Bradley.Gorham@bp.com> Sent: Friday, June 19, 2015 6:46 AM To: Loepp, Victoria T (DOA) Subject: RE: PBU S-136(PTD 215-095) Diverter Route Schematic Attachments: S-136 Diverter Line Radius.pdf Follow Up Flag: Follow up Flag Status: Completed Victoria, Please see attached. Feel free to contact me if you have any other questions or concerns. Thanks, Brad From: Loepp, Victoria T (DOA)[mailto:victoria.loepp@alaska.gov] Sent: Thursday, June 18, 2015 1:44 PM To: Gorham, Bradley M Subject: PBU S-136(PTD 215-095) Diverter Route Schematic Brad, Please provide a blown up version of the diverter route schematic on the pad showing a 75' radius area around the diverter outlet. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave, Ste 100 Anchorage, AK 99501 Work: (907)793-1247 Victoria. LoeppCo)alaska.aov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or yictoria_Loegp a aloska.gov TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 2-1 Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: - POOL: ,,d,_ y—CG'-11t� --J Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL (If last two digits No. , API No. 50- - - - Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sample are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool PRUDHOE BAY, AURORA OIL - 640120 PTD#:2150950 Company BP EXPLORATION (ALASKA) INC Initial Class/Type Well Name: PRUDHOE BAY UN AURO S-136 Program DEV Well bore seg ❑ DEV / PEND GeoArea 890 Unit 11650 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes Addition made to 10-401: Surface location in ADL 028257, portion of well passes thru 3 Unique well name and number Yes ADL 028258, top prod interval and TD in ADL 028256. 4 Well located in a defined pool Yes PRUDHOE BAY, AURORA OIL - 640120, governed by CO 457B - Corrected 5 Well located proper distance from drilling unit boundary Yes Rule 1: "Spacing units within the pool shall be a minimum of 40 acres. 20 AAC 25.055(a)(1) 6 Well located proper distance from other wells Yes and (2) shall not apply to property lines within the external boundaries of the Aurora 7 Sufficient acreage available in drilling unit Yes Participating Area." Well will conform to spacing requirements. SFD 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes SFD 6/8/2015 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 18 Conductor string provided Yes Engineering 19 Surface casing protects all known USDWs Yes 20 CMT vol adequate to circulate on conductor & surf csg Yes 21 CMT vol adequate to tie-in long string to surf csg No 22 CMT will cover all known productive horizons Yes 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes 27 If diverter required, does it meet regulations Yes Appr Date 28 Drilling fluid program schematic & equip list adequate Yes VTL 6/18/2015 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismic analysis of shallow gas zones NA SFD 6/8/2015 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date YJ5 80' conductor driven Surface casing set to 4108' MD 201% excess cement TOC at 8700' MD Productive interval will be completed with cemented production liner and perforated Rig has steel tanks; all waste to approved disposal wells Anti -collision analysis performed; no major risk failures Diverter route schematic provided and is acceptable. Max formation pressure is 3276 psi(9.2 ppg EMW); will drill w/8.8-10.6 ppg EMW MPSP is 2591 psi; will test BOPS to 3500 psig H2S measures required PBU S-Pad wells are H2S-bearing. Per 20 AAC 25.065(b), H2S measures are required. Strata below the CM2 horizon may be abnormally geo-pressured (>9.6 ppg). Planned mud program appears adequate for BP's most likely estimated pore pressures.
