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Home My WebLink About216-1251 Guhl, Meredith D (CED) From:Guhl, Meredith D (DOA) Sent:Monday, April 1, 2019 3:51 PM To:Lastufka, Joseph N Cc:Browning, Zachary H; Thompson, Jacob Subject:RE: L-200A (PTD # 216-125) expired permit Joe, Thank you. I’ll mark it expired in the AOGCC database and add your email to the well history file. Regards, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793‐1235 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 Meredith Guhl at 907‐793‐1235 or meredith.guhl@alaska.gov. From: Lastufka, Joseph N <Joseph.Lastufka@bp.com> Sent: Monday, April 1, 2019 3:36 PM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Browning, Zachary H <Zachary.Browning@bp.com>; Thompson, Jacob <Jacob.Thompson@BP.com> Subject: L‐200A (PTD # 216‐125) expired permit Meredith, Please consider the Permit to Drill for L‐200A (PTD #216‐125) as expired. Any future drilling plans will be re‐submitted to the AOGCC with a new permit and API ending in ‐02‐00. If you have any questions, please don’t hesitate to let me know. Thank you, Joe Lastufka SIM Specialist Cell: (907) 227-8496 | Office: (907) 564-4091 --------------------------------------------------------------------------------------------------- 2 BP Exploration Alaska | 900 E. Benson Blvd. | Room: 717B | Anchorage, AK --------------------------------------------------------------------------------------------------- Guhl, Meredith D (DOA) From: Lastufka, Joseph N <Joseph.Lastufka@bp.com> Sent: Monday, April 1, 2019 3:36 PM To: Guhl, Meredith D (DOA) Cc: Browning, Zachary H; Thompson, Jacob Subject: L -200A (PTD # 216-125) expired permit Meredith, Please consider the Permit to Drill for L -200A (PTD #216-125) as expired. Any future drilling plans will be re -submitted to the AOGCC with a new permit and API ending in -02-00. If you have any questions, please don't hesitate to let me know. Thank you, Joe Lastufka SIM Specialist Cell: (907) 227-8496 1 Office: (907) 564-4091 1SIM 11 ► Subsurface & Wells In!ormv$nn ►rar%agem.ent BP Exploration Alaska 1900 E. Benson Blvd. I Room: 717B I Anchorage, AK ID o a /6 - i zs^ Loepp. Victoria T (DOA) From: Lastufka, Joseph N <Joseph.Lastufka@bp.com> Sent: Wednesday, August 16, 2017 4:06 PM To: Loepp, Victoria T (DOA) Subject: New Parker NOV 6012 BOP Stack Attachments: 6012 BOP STACK.PDF Follow Up Flag: Follow up Flag Status: Flagged Victoria, Here is the list of Rotary wells that will have the updated BOP stack. If you need any additional information, please don't hesitate to let me know. 01-35 — PTD #216-021 14-16B — PTD #217-093 L -200A — PTD #216-125 NK -15A — PTD #216-175 Thank you, Joe Lastufka Information and Data Controller Cell: (907) 227-84961 Office: (907) 564-4091 tki BP Exploration Alaska1900 E. Benson Blvd.lRoom: 788DIAnchorage, AK 1 L i -M MI�nil •:, ■■ >s a i i i ----- - ---- RAI (g1 1 Y\f ( N INN kN a C --.0-s Caoxm k. —wm VOL ---O a, n 00 N 0 c.D THE STATE 'ALASKA GOVERNOR BILL WALKER David Wages Well Interventions Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU L -200A Permit to Drill Number: 216-125 Sundry Number: 317-051 Dear Mr. Wages: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for 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 . Foerster Chair 4L DATED this _ day of March, 2017. ,RBDM3 V - J 2017 STATE OF ALASKA <A OIL AND GAS CONSERVATION COMMISSIOI . j,PLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVE® JAN 3 0 2017 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 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 ❑ 2. Operator Name: BP Exploration (Alaska), Inc 4. Current Well Class: Exploratory ❑ Development 0 5. Permit to Drill Number: 216-125 3_ Address: P.O. Box 196612 Anchorage, AK 99519-6612 Stratigraphic ❑ Service ❑ 6. API Number: 50-029-23191-01-00 7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? 8. Well Name and Number: Will planned perforations require a spacing exception? Yes ❑ No 0 PBU L -200A - 9. Property Designation (Lease Number): 10. Field/Pools: ADL 028239 PRUDHOE BAY, PRUDHOE OIL ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9389 4693 9389 —4693 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 78 20" X 34" —50-128 —50-128 Surface ~3351 10-3/4" —49--3400 —49--2434 5210 2480 Intermediate Production —9342 7-5/8" —47--9389 —47--4693 6890 4790 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8383 - —9002 4205 - —4499 4-1 /2" 12.6# 13Cr80 —45--9240 Packers and SSSV Type: See Attachment Packers and SSSV MD (ft) and TVD (ft): No SSSV Installed 12. Attachments: Proposal Summary RI Wellbore Schematic H 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: M"-, ' 1, 2017 Y 15. Well Status after proposed work: / d 2 J oV Oil m - WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Wages, David be deviated from without prior written approval. Email David.Wages@bp.com Printed Name Wages, David Title Well Interventions Engineer Signature ,' Phone +907 564 5669 Date I t� ` } COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 r7—�� 1 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ BIZ, (tq Other: f/ Post Initial Injection MIT Req'd? Yes ❑ No L—I Spacing Exception Required? Yes ❑ No Q" Subsequent Form Required: APPROVED BYTHE Approved by: COMMISSIONER COMMISSION Date:3- Zq YT` 317611 7- ORIGINAL RS!Mns l t t, - 3 2017 Submit Form and Form 10-403 Revised 11/2015 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AFFIDAVIT OF NOTICE OF OPERATIONS Before me, the undersigned authority, on this day personally appeared Lldz4,who being duly sworn states: Z %, / My name is David Wages. 1 am 18 years of age or older and I have personal knowledge of the facts stated in this affidavit. 2. lam employed as an Engineer by BP Exploration (Alaska) Inc. ("BPXA") and I am familiar with the Application for Sundry Approvals to stimulate the L -200a Well (the "Well") by hydraulic fracturing as defined in 20 AAC 25.283(m). 3. Pursuant to 20 AAC 25.283(1), BPXA prepared a Notice of Operations regarding the Well, a true copy of which is attached to this Affidavit as Attachment 1 ("Notice of Operations"). 4. On December 29, 2016, the Notice of Operations was sent to all owners, landowners, surface owners and operators within a one-half mile radius of the current or proposed wellbore trajectory of the Well. The Notice of Operations included: a. A statement that upon request a complete copy of the Application for Sundry Approvals is available from BPXA; b. BPXA's contact information. Signed this 3rd day of January, 2017. STATE OF ALASKA THIRD JUDICIAL DISTRICT Subscribed and sworn to or affirmed before me at on the '1'-)-4 day o , 20�. Signature of Offic Title of Officer STATE OF ALASKA NOTARY PUBLIC DONNA EUGENIA HICKS M Commission Expires November 13, 2019 Packers and SSV's Attachment PBU L -200A SW Name Type MD TVD Depscription L -200A TBG PACKER 8324 4171 4-1/2" HES TNT PACKER L -200A TBG PACKER 8398 4203 4-1/2" HES TNT PACKER L -200A TBG PACKER 8464 4220 4-1/2" HES TNT PACKER L -200A TBG PACKER 8560 4276 4-1/2" HES TNT PACKER L -200A TBG PACKER 8666 4329 4-1/2" HES TNT PACKER L -200A TBG PACKER 8784 4384 4-1/2" HES TNT PACKER Date: December 26, 2016 Subject: L-200 Frac and Pack Stimulation From: David Wages Engineer, BP Alaska o: 907.564.5669 c: 713.380.9836 To: AOGC Commission Attached is BP's proposal and supporting documents to frac and pack stimulate the Schrader interval - of well L -200a. This well will be a replacement for the failed L-200 multi -lateral. L-200 has major damage at the L2 junction and has produced sand and rocks, rendering it inoperable. The L-200 area is supported by three previously drilled injectors (L-211 i, L-2181, and L -212i). 1 Current plan is to drill next to the existing laterals with the sidetrack then attempt to frac into the laterals in order to restore some of the production. To achieve sand control, a unique completion that incorporates proven technology and practices is proposed. It is tailored to BP Alaska style of frac pack. We are requesting a variance to sections 20 AAC 25.283, a, 3-4 which requires identification of fresh - water aquifers and a plan for basewater sampling. We are also requesting that the requirements in section 20 AAC 25.283, a, 10 be met by pressure tests of the tubulars on the well to be stimulated and by investigation into the mechanical condition of the wells within 1/z mile of the wellplan within the producing interval. Please direct questions or comments to David Wages Summary of Work The Schrader Bluff sands will often have sand production issues. One way to provide sand control is deploying a frac pack system. Due to cost, spaceout constraints and available resources, conventional frac pack systems have been deemed inadequate. As a result, BP has invented an entirely new way to achieve a frac-pack. The system is deployed in a cased hole on a 4-1/2" lower completion. A packer separates each stage. There are two sleeves per stage. The top sleeve is an open/close frac sleeve and the bottom sleeve is an open to a screen/closed sleeve. The open/closability of the frac sleeve is necessary to require the screened sleeve to produce all the reservoir fluid. The screened sleeve does not necessarily have to be closable but it would be preferable. After the lower completion is run, fracing operations can begin. The frac operation is as follows: 1) The sleeves below the frac sleeve is isolated via a CT deployed packer 2) The frac sleeve is opened 3) Fracture operations commence. 4) If possible (but not necessary) a screenout will occur and the fluid above the isolation plug between sleeves is cleaned up. 5) The top frac sleeve is closed leaving clean fluid inside the lower completion and slurry on the outside 6) The sand laden fluid in the annulus of the lower completion will lose viscosity as the fluid breaks and allow the sand to fall. When the sand falls, it will pack off around the lower sleeve providing the gravel pack. 7) The process is repeated on zones further up hole until all zones are complete. 8) The screened sleeves are opened to allow reservoir fluids into the wellbore. Affidavit of Notification (20 AAC 25.283, a, 1) Partners notified 12/27/2016: ConocoPhillips Exxon Mobil Chevron Department of Natural Resources Plat Identifying Wells (20 AAC 25.283, a, 2, A -C) and Faults (20 AAC 25.283, a, 11) Red lines indicate approximate length and location of fracs. Producers within 'h mile of L -200a: L-117 L-200 L-212 L-124 L-211 L-218 �IVI uie NiaL aucrvC, mere are no water weirs wanin r2 miie OT the subject well. The above map shows 2 primary faults of concern: 1 and 2. The remaining faults are well away from stimulation chemicals and/or not in the direction that the induced fractures are predicted to travel. Per the frac modelling, historical data, and post frac analysis of past jobs, we are expecting a half-length of about 150' which is well short of the distance to faults 3 and 4. To reach faults 1 or 2, the frac half- length would have to be over 500 feet long. The intent of the frac it to connect to the L-200 laterals, the wellplan is designed so that the new bore is between 10' and 150' away from the old laterals. The frac will connect to the laterals well before the fluids connect to faults 1 or 2. Once the frac connects to the laterals, frac growth will stop and we will move to a period of packing in the frac (putting as much sand as possible into the frac in order to ensure good connectivity to the laterals). Exemption for Freshwater Aquifers (20 AAC 25.283, a, 3-4) Well L -200a is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1-4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location the makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000 mg/I or more. 4. By letter of July 1, 1986, EPA -Region 10 advises that the aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non -substantial program revision not requiring notice in the Federal Registrar. Per the above findings, "Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25.440." thus allowing BP exemption from 20 AAC 25.283, a, 3-4 which require identification of freshwater aquifers and establishing a plan for basewater sampling. Detailed Casing and Cement Information (20 AAC 25.283, a, 5-6) Well L -200a is to be spudded on 1/20/2017. Please see Proposed completion schematic Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 8) "nVVELPROPOSED EAR „ , L -200A A(.'nJ ^TOR - REV 5 TYPE _- OKB RFV = 77IT ILAT01 BF. ELEV - 53.80' KDP= 380' ZDA' COND _.� 114' - 4 '1432; Max Angle - 2470 Datm MO = 29.7# ca TVD= 44W SS 6.875" - -- ----- �10-L4' YMIPSTOCX l � � 3�0• 6195' ta3u csG 45 s.. LA0. D = a 95 J--{ -3000' _ 12.6# 7-518' CSG, 29. Ib, L 80 XO TO 13CR-80 -BOW 3.958" VAM TOP FC, D - 8.875' 7810 Minimum ID = 3.725" @ 8874' 1 7193 4-112" HES XN NIPPLE RA TAC r-StE• USNGGix1.AR -1, 83"j0' PERFORAIMISUMMARY Wf LOG ANaL AT ROP PERF ...- we %ft b Pl0dxbm DB b NSIMCM Pelfdata -_.- __.. ----- 6 �- ---- - ... . SDF SPF 7TY�F NIFRVAI OtrV4y� MTF 45A6' , 5 088 8363 -8388 O '. 4518 S OBG 8452 - 8557 O . } 4518' 5 OBC 85548 - 855.3 O 1 4518' � 5 Clad 8858.8663 0 14 -SC i 5 C9e 8772 - 8777 O 4-,W 5 OM 8W7 . WN '. O SAFETY NOTES: WELL ANGLE> 70• @ "CHROME CSG 8 TBG•" 986' 10-1N' TAM 1VKT WIJIFi L 2009' - 4- t!2' FES X NP. D = 3.813• MILLOUT WINDOW (L -200A) -3000 -3013' '10 �jlsE1 GAS lFT MANDRELS ST MD :TVD DEV TYPE I VLV ILAT01 PORT DOTE 4 '1432; 5210 2470 7-5/8" Production Casing 29.7# 13Cr-80 6.875" 3 6195' 4-1/2" Production Lnr/tbg 12.6# 13Cr-85 3.958" 8960 7810 2 7193 1 31141 .. iGA f2- HFS 93 OVRASL �YE.r P(tF. D-34 8255' -,4-12• SGWNMG N CA SGLE OROP SA A'HRE _ D = 3864- 9324 - 864-8324' 7-!V8• X 4-1/2- FPS TNT WR D = 3.856' 8330' _ - d 1Yi• NC : FTiAC PO(7T D 3 958• 8367 j a -1!Y FES x NP. D - 3AI3• 8370• t4 112• NCS SCREEN SLEEVE D -3 8' 8398' ..... J-518 X 41/2' Fi'S TIYT FCR D - 3 656'-- 1 8403' 41fY K;51 -WAC PORT, D .39513' v J 4 111 t�5 X 1'JP D.a 3 813• _ ....._ 8438' ,4117 1WS SCREE3V SLEEVED= 2958 6488-1-- 7-518• X 4_117- Fi'S TNT FKR D - 3 856• 8470',,. „ 4 1!Y H1C5 FRAC PC)RT D 3.958 8618' I4.1r2'FBSXT. D=3.813• --------- ---- 8637 74-117 FCS SCRMN SLEEVE_ D - 3 956' 8680' 7-518' x 4-112• FES TNT FCR D= 3BW 8686' a-12• NGS FRAC PORT, D - 3;— .1 8614'.-.-- -t4- v2- HES X NP, D- 3.813' 81138' �--�a trr Ncs scT�u st�v�, D _ yvs� __8888' 7-518 X 4-trr FES tMT ACR, D; 3.856' 4 112• NOS FftAC POiRT, D - 3.956• 8730 4-1rZ HES X rp. D A813' 8766' 4111 Nrs saw, sL.EEVE D= 3 s5a' 8784' H. 7-518' X 4-112• FES TNT ACR D - 3.856' CR -68 VAM TOP 8&16' 4 lrY FB X NP. D = 3 813• a v2' TBG, t2.8a. 13 ;,- 8891 ' ----------- '--- .0 f 52 bpf, O - 3.958' 8874' a-112' FL" -'u xN NP, K);73 7n•1 8881' 4-V2• VVI EG, D= ].956• 7-5r6•csc�2s.7a,lacR-BovAMTOPrIc, 8086' ID 6 875* — - OATS REV BY rn---_ COMMENTS �--- -DATE REV BY I COMMENTS--�- i ORION UNIT 82/22/04 N9E8 ORIGINAL COMPLETION 1211:2r16 .IT1.IMn PRCPOEW RFV 3 WFI I I- DDA 101 1V26 0-10 RWO 12/12/18 JT/JMO PROPOSAL REVS PERWT No SYOEtRAGK (L-26011. API N4 504829-2319VO L'116,15 JTT'tJMD BUILT FROPOSEO SEC 34 T'2N, R11E, 256T FSL d 1573' FEL 05!0&16 1CAA0 PROPOSAL REV 1 05'09116 JT'AAC PROPOSAL REV 2 8P Explwatim (Alsdw) Name/Size Weight Grade ID Burst, psi Collapse, psi 10-3/4" Surface Casing 45.5# L-80 9.95 5210 2470 7-5/8" Production Casing 29.7# 13Cr-80 6.875" 6890 4790 4-1/2" Production Lnr/tbg 12.6# 13Cr-85 3.958" 8960 7810 Wellhead: FMC manufactured wellhead, rated to 5000 psi. Tree: 4-1/16" 5,000psi Tubing head adaptor: 11 " 5,000psi x 4-1/16" 6,500psi Tubing Spool: 11 " 5,000psi w/ 2-1/16" side outlets Casing Spool: 11 " 5,000psi w/ 2-1/16" side outlets Geological Frac Information (20 AAC 25.283, a, 9) Formation Top B Dt TVDss Top TVDss Bot Thi knees Frac Grad Lithological Desc. UG1 6693 7895 3523 4018 495 0.8 Shale and sandstone interbedded NA 7895 7937 4018 4038 20 0.67 Shale/silt NB 7937 8002 4038 4069 32 0.67 Sandstone NC 8002 8019 4069 4078 9 0.67 Silty Sandstone NE 8019 8114 4078 4125 47 0.67 Shale/silt NF 8114 8184 4125 4161 35 0.67 Shale/silt OA 8184 8256 4161 4197 36 0.69 Sandstone OA_FS1 8256 8292 4197 4215 18 0.69 Shale/silt OBA 8292 8356 4215 4247 32 0.69 Sandstone OBA FS1 8356 8381 4247 4259 13 0.69 Shale/silt OBB 8381 8418 4259 4278 18 0.7 Sandstone OBB_FS3 8418 8484 4278 4311 33 0.7 Shale/silt OBC 8484 8545 4311 4341 30 0.67 Sandstone OBC_FS1 8545 8583 4341 4360 19 0.67 Shale/silt OBD 1 8583 8696 4360 4417 56 0.67 Sandstone OBD_FS1 8696 8709 4417 4423 7 0.67 Shale/silt OBE 8709 8785 4423 4461 38 0.67 Sandstone OBF 8785 8877 4461 4507 46 0.67 Silty Sandstone OBF BASE 8877 N/A 4507 4800 300 0.8 1 Shale Mechanical Information of nearby wells (20 AAC 25.283, a, 10) of Pay imenral 7VD.Feet 0 to surface Production Summary Hydraulic Fracture Program (20 AAC 25.283, a, 12) (Detailed program included) Z scale 3 00 1. ]4v OUS it MMI OUs n hrb".S.ft ,cc acus rt t 4` 4200 4400 .3Y 4500 5000 5500 6000 6500 7W0 7500 8007 Above is a cross-section of the wellbore. Sliding sleeves or fracports are labelled with green circles and the packers are labelled with the red circles, both of which are along the wellbore. Hydraulic fracture treatment schedule stage 1-5: The maximum horizontal stress has been determined to be nearly perpendicular to the wellbore, this is based on historical information as well as borehole breakout data. The maximum horizontal stress means that the induced hydraulic fractures will be perpendicular to the wellbore. Maximum Anticipated Treating Pressure: 2500 psi Maximum Allowable Treating Pressure: 5000 psi Stage 1-5: Anticipated half length: 150' Anticipated height growth: 90' Due to the horizontal nature of the well and the transverse nature of the fracs, we are unable to specify a MD for the frac height. Each frac will initiate at their corresponding perforations. The perforations are located at: 8383'-8388' 8452'-8557' 8548'-8553' 8658'-8663' 8772'-8777' The above frac dimensions were calculated using modeling software. Surface pressure is calculated based on a closure pressure of —0.67 psi/ft or 2700 psi, this combined with the anticipated net pressure to be built, hydrostatics and the friction gives a surface pressure of 2500 psi at the time of flush. The frac height is primarily based on closure pressure differences between the confining shale layers and the unconfined sandstone reservoir. Average confining layer stress is anticipated to be —0.7 ps i/ft. Half length is based on confining layer stress as well as leak -off and formation modulus. Given the values, the above half lengths are calculated. Pressure Test Information (20 AAC 25.283, a, 7) Per the drilling program both the tubing and the IA will be pressure tested. The IA will be tested to 3500 psi and the tubing will be tested to 4000 psi. PRV setting procedures and annulus monitoring: Maximum Allowable Treating Pressure: 5000 Stagger Pump Kickouts between: 4500 psi and 4750 psi (90% to 95% of MATP) Global Kickout: 5750 psi (95% of MATP) IA pop-off set pressure: 3000 psi (75% of MIT -IA) Treating line test pressure: 6000 psi 5501000# 30-50 Econoprop NRT, 5000# 20-40 Sand Requirement sand Minimum Water Requirement 4,000 bbls (pump schedule: 3811 bbls) IA Hold Pressure 2500-2600 psi (IA pop-off @ 3000 psi) OA Monitor and maintain open to atmosphere There are three overpressure devices that protect the surface equipment and wellbore from overpressure. Each individual frac pump has an electronic kickout that will kick the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are set between 90% and 95% of the maximum allowable treating pressure. There is the primary pressure transducer in the treating line that will trigger a global kickout which will kick all the pumps into neutral. Finally, there is a manual kickout that is controlled from the frac van. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. r L-200 Rig Up I. L Chemical Disclosure (20 AAC 25.283, a, 12) Schlumberger Client: BP Exploration Alaska Well. L -200A Basin/Field. Prudhoe Bay Stare: Alaska Countyj Parish: North Slope Borough Case. Breaker Aid D i scl osure Ty pe: Pre -Job Well Completed: 2/20/2017 Date Prepared: 1120/201710:46 AM Report ID: RPT -47429 F103 Surfactant _ 1 Gal / 7000 Gal 130.0 Gal J218 Breaker _ 7.1 Lb/ 1000 Gal _ 910.0 Lb 1318 Breaker Aid -� 67-63-0 1.2 Gal j 1000 Gal 155.0 Gal YF12DST:WF120 12B4O16 Gal J532 Crosshnker __.7--t_ <0.1% 3.5 Gal j 1000 Gal 450,0 Gal .189_1_ _ _ Guar Slurry 1-undecanol 4.7 Gal j 1000 Gal 600.0 Gal L071 Clay Control Agent 1303.96-4 2 Gal / 1000 Gal 260.0 Gal M275 Bactericide -i- <0.0001 % 0.4 Lb/ 1000 Gal 48.0 Lb 5522-2]40-NRT Propping Agent Diarnrnon ium peroxidisulph ate varied concentrations _ 513,000 0 Lb fiatnmf wfwrmfsmdin Ola mbfasabow rapaxnC Masuvrm9'nn of va m•mda�rziws Wo mr is sappfiniby mn[ 9000-30-0 Guargum <1% - Water (including Mbc Water Supplied by Client)- -67 % _ 56-81-5 _ _ _ 1, 2, 3- Propanetriol <0.1 % 64-19-7 _ _ Acetic and(impurity) <0.0001 % 67-48-1 2 -hydroxy -N, N, N -tri methy let han amin ium chloride - c 1 % -� 67-63-0 Propan-2-ol <0.1 % 102-71-6.._ 2,2-,2"- n itri l otri eth an of <0.1% 111-76-2 i ___....-.__...._ 2-butoxyetharof _------ 10.1 % 112-42-5 _ + 1-undecanol -}- J <0.01 % 12708-2 _ - Acetic acid, potassium salt i 10.0001% 1303.96-4 Sodium tetraborate decahydrate <0.1% 2682-201-4 i 2-methyl-2h-isothiaxol-3-one -i- <0.0001 % 7631-86-9 Silicon Dioxide < 0,001 % _._ 7727-54-0 Diarnrnon ium peroxidisulph ate -- <D.1% 7786-30-3 _ Magnesium chloride 10.001% 9000-30-0 Guargum <1% 10377-60-3 Magnesium nitrate _ <0.001 % 14464-46-1 ---------- Cristobalite - <0.0001 % 14808-60-7 - Quart; Crystalline silica <0.0001 % 26172-55-4 5-chloro-2-methyl-2h-isothimolol-3 one 10.001 % 34398-01-1 _ Alcohol, C11 linear, ethmxylated c 0.1 % 64742-47-8 Distillates, petroleum, hydrotreated light < 1 % 66402-68-4 Ceramic materials and wares, chemicals -32% 68131-39-5 _ C12-15 alcohol ethymcylated _ ' 10.01 % 68153-30-0 Amine treated snectite clay _ < 0.01 % 91053-39-3 T Diatomaceous earth, calcined <0.01 % Mx .w m• rs s r�r� by My cfmne YhfunMrgw has pw/orrxdno arofyzis cf no wnev ondcanro rpv xdaa brcnFdawn f com,aviona rnor,r,ay by w Mon adiW m Ma wo m• by elird-�rdvs ' 7ha avdavton of asmchW dot urrrcn «s Fvrfarmadbamdan Av compuitan cf Maidantlffadproda C m 01v oxmnt dv is ah canryvshvmf inforrmvtim was Rnown m 6[C-Oiwrniafs as of do dam c{ by he wmv r ws podoead. n,ynaw apra ms wff rorbarafTw mdin Mis docuixne L -200a Post -Rig Frac-Pack Wellwork Procedure Request To: D. Scarpella/J. Disbrow Date: 12-6-16 R. Mielke/C. Olsen: Coil and Well Testing Supt. 2. S L. Seymour/ R. Burnett: Well Support Supt. AFE: F From: David Wages - Well Intervention Engineer IOR: 726 RU Buffalohead Est. Cost: $2,120k Subject: L -200a 5. C Revision: 2 Job Se uence: WBL Steps 1. WH C/O WH, Pull TWC 2. S Pull B&R, Dummy GLMs, Pull RHC, Run RPM, 3. F Perform Step Rate test, Injectivity test 4. SP RU Buffalohead 5. C/SP Frac 5 zones, vibrate through zones, Run RPMZ 5. C Top off zones per RPMZ, Open all sleeves 6. E Obtain SLB PNX or HAL RMT for Gadolinium Spectroscopy 7. S Install Plug to isolate OBf, Install LGLMs 8. T Flowback Job Obiec_ tive: Specific Well Objective 1 Perform Frac-Pack 2 Evaluate and Remediate pack Program Contacts: Page 11 of 10 Contact Phone - Work Phone - Mobile / Home Interventions Engineer David Wages 907-564-5669 713-380-9836 Interventions Engineer Tyson Shriver 907-564-4133 406-690-6385 Petrophysist David Itter 907-564-5687 907-538-3230 Page 11 of 10 1. History New Sidetrack 7-5/8" Production casing has been tested to 4000 psi per drilling program. 4-1/2" completion has been tested to approximately 3500 psi to set packer and liner hanger per drilling program. Current Status: Minimum ID: Max Deviation: Top Perf Deviation Last TD Tag: Last Downhole Op SBHP/SBHT: H2S: 2. Critical Issues A. Tree Configuration New Drill 3.813" X Nipples 69 - 71 deg @ 4,500'-8100' MD -60 deg at 8,900' MD N/A New Drill N/A New Drill Est. @ 2000 psi per SOR @ 4200' TVD Est. -r40 ppm per offset BHL (L-202) a. To shift the NCS style sleeves and pump frac, a Buffalo head needs to be rigged up. Available from Stinger, this is a flowcross on the tree that has a connection on top for coil and 4 side outlets for hooking up frac pumping equipment. 3. Procedure A. Wellhead- Install production tree, pull hanger plug The tubing has been tested to 4000 psi The IA has been tested to 3500 psi a. Ensure Rig has installed a MV and a Surface Actuated valve as the tree. Install production tree. b. Pressure test tree to 5000 psi c. Pull TWC/BPV d. Install secondary swab at some point so we do not have to shut in the well when the well test is complete B. Slickline- Pull B&R, Dummy GLMs, Pull RHC, Run RPM, a. Pull ball and rod b. Pull circ valve c. Dummy gas lift valves d. Pull RHC e. Run RPM, log i. Rig up Memory RPM for SL. Toolstring: RPM-GR-CCL-Pressure-Temperature- Capacitance-GR2. a. Ensure GR detector is above RPM tool so silicon activation can be recorded when performing two down passes. Employ all radiation safety related procedures as per Baker operations manual. ii. RIH and perform baseline GR -CCL up pass with minitron still in off mode. iii. Perform two down passes from XXXX' — XXXX at 12 fpm Page 12 of 10 a. Down passes capture Silicon activation iv. Perform two up passes from XXXX' — XXXX' at 6 fpm a. Up passes capture Formation Sigma V. Rig down RPM and confirm good data. vi. Tie RPM -GR -CCL log into USIT-GR (to be supplied once drilled) and forward LAS and pdf print to David Itter (david.itter@bp.com). Please modify LAS file format to include the following in addition to the standard deliverables: GR, CCL, apparent near borehole sigma, apparent far borehole sigma, borehole sigma, apparent far formation sigma, apparent far formation sigma, formation sigma, total far detector counts, total near detector counts. C. Fullbore- Perform Step Rate test, Injectivity test a. Perform Step Rate test Stage Fluid Rate Volume Total Vol Comments Type Bbl/min Bbls Bbls 1 Methanols ear Max 5 5 As Re 'd 2 Crude Max 140 145 Load Hole, flush WB fluids 3 N/A 0 0 145 SD 1 Hour for Frac Closure 4 Crude Min 0.25) 1 146 Step 1 5 Crude 0.5 2 148 Step 2 6 Crude .75 3 151 Step 3 7 Crude 1 4 155 Step 4 8 Crude 2 8 163 Step 5 9 Crude 3 12 175 Step 6 10 Crude 4 16 191 Step 7 11 Crude 5 20 211 Step 8 12 Crude 6 24 235 Step 9 13 Crude 7 28 263 Step 10 14 Crude 8 32 295 Step 11 15 N/A 0 0 295 SD 1 hour for Frac Closure 16 Crude Max 145 440 Injection Test, Constant Rate 17 N/A 0 0 440 SD 1 hour for Frac Closure i. Please call David Wages prior to Ina test! ii. Please obtain 1 sec surface treating pressure and rate data and send to david.wages@bp.com iii. Max Allowable Surface Pressure: 4000 psi iv. No need to hold pressure on the IA v. Monitor surface treating pressure during SDs, if surface pressure is lost, can continue on to next stage vi. BHP=2200 psi, hydrostatic of crude=1640 psi ---We should have surface pressure the entire time. D. Special Projects- RU Buffalo head Page 13 of 10 i. RU and pressure test Buffalohead E. Coil/Special Projects- Pump fracture stimulation • 2" 0.204 wall coil to be used for stimulation. • Overpulls are to be managed on the fly, plan on pumping pills of safelube laden KCI between stimulation stages. Pressure Criteria -CT Annulus ONLY Maximum Allowable Treating Pressure: 5000 psi Stagger Pump Kickouts between: 4750 psi and 4500 psi (95% to 90% of MATP) Global Kickout 4750 psi (95% of MATP) Treating Line Test Pressure 6000 psi Minimum Water Requirement 4500 bbls (pump schedule: 3500 bbls) IA Hold Pressure 2000 psi OA (There is the possibility the OA could be cemented to surface if subsidence is seen on the rig, creating a small void in the OA. Check drilling reports to confirm.) Monitor and maintain open to atmosphere Pressure Criteria -CT ONLY Maximum Allowable Treating Pressure: 8500 psi Stagger Pump Kickouts between: 8000 psi and 7600 psi (95% to 90% of MATP) Global Kickout 8000 psi (95% of MATP) Treating Line Test Pressure 9500 psi Minimum Water Requirement TBD bbls a. MIRU CT Unit and SLB frac pumping units and pressure test BOPs. b. RIH w/ NCS BHA (Max OD: 3.785"): i. If any difficulty is seen getting down, circulate in safelube for subsequent runs, the NCS shifting tool drags -500 additional pounds ii. Min ID in tubing/liner is 3.813" X nipples c. Stimulate stage #1/FracPort #1 per pump schedule d. Cleanup wellbore, shift sleeve close and continue on to treat remaining frac sleeves. i. If any overpulls are seen, circulate in a pill of safe -lube e. Once all fracs are pumped, RBIH and vibrate using agitator through screened sleeve, plan on spending at least 15 minutes on each sleeve. f. POH and download gauge data g. RDMO Frac fleet h. RIH and obtain RPM2 log. Page 14 of 10 a. Rig up Memory RPM. Toolstring: RPM-GR-CCL-Pressure-Temperature-Capacitance-GR2. Ensure GR detector is above RPM tool so silicon activation can be recorded when performing down passes b. Employ all radiation safety related procedures as per Baker operations manual. c. RIH and perform baseline GR -CCL up pass with minitron still in off mode d. Perform two down passes from XXXX— XXXX' at 12 fpm i. Down passes capture Silicon activation e. Perform two up passes from XXXX' — XXXXat 6 fpm i. Up passes capture Formation Sigma f. Tie RPM -GR -CCL log into USIT-GR (to be supplied once drilled) and forward LAS and pdf print to David Itter (david.itterAbp.com). Please modify LAS file format to include the following in addition to the standard deliverables: GR, CCL, apparent near borehole sigma, apparent far borehole sigma, borehole sigma, apparent far formation sigma, apparent far formation sigma, formation sigma, total far detector counts, total near detector counts. i. Once OOH with the logging string, C/O BHA for NCS BHA to manipulate screened sleeves RIH to screened sleeve #1 k. If log confirms a good pack, open screened sleeve #1 Continue to open screened sleeves per RPM2 Top off Procedure -To be implemented if RPM2 indicates a poor pack Screened sleeves below must be opened prior to opening upper sleeves i.e. zone 1 screened sleeve open prior to opening zone 2. a. Open screened sleeve of zone to be treated b. PUH to sister frac port and open, leave packer set c. Establish injectivity starting at very low rates a. Max rate is extension rate from Step Rate Test d. Once injectivity confirmed, proceed to perform top off: a. Mix up 300 pounds of 30-50 EconoProp NRT (Same as frac proppant) in 10 bbls of 20 cp HEC or linear gel i. 0.7 pounds of proppant per gallon of base fluid ii. Additional QA/QC of the fluid should follow SLB's fluid testing procedures. e. Begin pumping slurry down the backside, it may be necessary to take returns up the coil to facilitate circulating down the fluid at a faster rate. f. Once fluid is at the fracport, stop taking returns if applicable and begin laying in pack. a. Flowpath: Coil x 4-1/2" annulus, out fracport, down 4-1/2" x 7-5/8" annulus, in through opened screened sleeve, down to disposal zone. b. Do not exceed XXXX psi coil pressure (coil will be the dead string) g. Once bump in pressure is seen, reduce rate to minimum and continue to "squeeze in slurry until max pressure indicated by Step Rate test is gained then immediately open up backside to take returns and circulate out proppant remaining in tubing. a. If unsure, please call David Wages h. Pick up on NCS packer, this will automatically close the fracport. i. Repeat this process on remaining sleeves per RPM2. Page 15 of 10 Once all zones are topped off, ensure all screened sleeves are open then POOH. F. E -Line- Obtain PNX or RMT -3D for Gadolinium Spectroscopy a. Rig up SLB PNX or RMT -31D with E -line i. Toolstring: PNX-GR-CCL-Pressure-Temperature-Capacitance-GR2. Employ all radiation safety related procedures as per Service Company operations manual b. Tie PNX-GR-CCL log into USIT-GR (to be supplied once acquired) and perform baseline GR -CCL up pass with minitron still in off mode. c. With Minitron on, perform two up passes at 6fpm in Sigma mode from TD to 50ft above top reservoir (depth to be determined). Ensure that the E -line maintains constant speed. d. Perform two up passes at 2fpm in GSH -Lith mode for Gadolinium Yields, sigma and silicon activation. Ensure that the E -line maintains constant speed. e. Confirm good data and POOH to safe depth. Deploy all radiation safety barriers and confirm PNX tool is in safe mode. POOH to surface. f. Rig down PNX. Forward LAS and pdf prints to David Itter (david.itter@bp.com) and David Wages (david.wages@bp.com). Please modify sigma LAS file format to include the following in addition to the standard deliverables: GR, CCL, apparent near borehole sigma, apparent far borehole sigma, borehole sigma, apparent far formation sigma, apparent far formation sigma, formation sigma, total far detector counts, total near detector counts. Ensure that the IC/CO mode LAS file contains GR -CCL, near gadolinium yields, far gadolinium yields in addition to standard deliverables. g. If run up logs, just make sure GR tool is below PNX tool. G. Slickline- Install Plug to isolate OBf, Install LGLMs a. Drift to deviation. b. Install plug in X -nipple in tubing tail to isolate disposal zone (very bottom set of perfs) c. Install GL design per GL Engineer d. Ensure a secondary swab valve is in place so we do not have to shut in the well when the well test is complete H. Testers- See Appendix for Post Frac Flowback Page 16 of 10 NCS BHA: Page 17 of 10 T*dDncffiwm TMAOM ID In ITahl R CaesecliaEs And 1Pa 3.12" 1.769" 7.44 0.62 2.5" SA Pin 1 « >1 2.0" Coil Connector 2 << >2 Gauge 3.06" 1.50" am 1.66 2.5" SA B X B 3 << >3 Disconnect She ac- Sub, 3.063" 1.990" j 12.14 2.67 2.6"SABxP 4 << > 4 4.5" 2 Dot Centlahar 3.78" 2.00" 36.00 5.67 1.5" SA BxP « Disconnect Ball Seat Cartier, 3.06" 1.37F' 7.93 6.34 2.5" SA BxF 1.375" Carbide, 6 t< 4 4.5" 2 Dot Expansion Joint Cent n tier 3.78" 2.00" 43.62 10.39 I r �" SA BxP 7 « Blast Joint i 3.06" ( :.60^ 9.83 12.21 2.z 5.4BxP 8 a flow Dmrter Sub 3.062" 1875" ! 8-25 I 1190 d 2.5" Sa BxP 9 � 9 EQ l"ah a ar Ball Check, 3.25" 125" j 1 t i 2093 i i 13.01 i 2.5" SAB x 10 « -10 4.5" Shilli FmCClose Faclar 3.75" 1.50" i 1995 15.30 2.5" SA B x 2312" SA P j 11 « >11 4.5" Doc Vulcan SIS Locator 5.216" 3.00" I i { I 27.04 17.56 2.311" SAB x 2 5" SA P 12 ti= r1. De ocWressicnSnb 3.64" 1.30" 5.90 18.04 251"S_;BIF 13 = _ > 13 Gauge 3.06" LEO" 12.50 19.08 2-F' &A B X B 14 4 > 14 Pin x Pin 7i -mw 3.06" ( 1.996" 2.04 � 19.25 2.5" SA Pin t Pin 15 f > 13 4.5" 2 DotMagoefic Bosnase 3.785" 2.20" 1294 20.33 2.5" SAB With Magnetic Cartier i 'i�fl. _ Total Length of BMA.: B20 N.1.,4 �I.T1 swtwewenar_�_ ._.oma: _ ,k'ax-da To ¢i ore. S. is G? ic•Cy'f�b1"�ati ¢'fi JC 3' 7•v+:a¢?+stro cm• BliAt Soon ik5vt 06-AUKk15 Page 17 of 10 Appendix A - Test Separator Flowback Procedure 1. MIRU ASRC. RU equipment to in a manner that allows CT to RU if an additional CT runs are necessary. 2. POP the well to ASRC at minimum choke. Flow the initial returns to the flowline as long as the shake -outs meet the returned fluid/solids management guidelines. 3. Limit flow to 500 bpd 4. If solids are < 1 %, increase the production rate to 1000 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1 %, allow well to flow to 1500 BLPD. 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Ri 1E. 2597' FSL I, 157.4 FEL SP EzPlc92bm {,ilaaa] Tubmove Calculations aAL 9 7 v •- aaaiaa ttm ee<vao ------------------------ 1111 Page 110 of 10 I Loepp. Victoria T (DOA) From: Wages, David <David.Wages@bp.com> Sent: Thursday, March 23, 2017 9:53 AM To: Loepp, Victoria T (DOA); Lastufka, Joseph N Subject: RE: PBU L-200A(PTD 216-250, Sundry 317-051) Fracture Stimulation Sundry Withdrawal L-200 is currently on the schedule for November, Not withdrawn, just on the back burner for a bit. David Wages o. 907.564.5669 c. 713.380.9836 WIE-AK From: Loepp, Victoria T (DOA) [mailto:victoria.loepp@alaska.gov] Sent: Thursday, March 23, 2017 9:41 AM To: Lastufka, Joseph N Cc: Wages, David Subject: FW: PBU L-200A(PTD 216-250, Sundry 317-051) Fracture Stimulation Sundry Withdrawal Joe, Could you please facilitate this? Thanx, Victoria From: Loepp, Victoria T (DOA) Sent: Friday, February 24, 2017 10:01 AM To: Wages, David <David.Wages@bp.com> (David.Wages@bp.com) <David.Wages@bp.com> Cc: Wallace, Chris D (DOA) <chris.waIlace@alaska.gov>; Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: PBU L-200A(PTD 216-250, Sundry 317-051) Fracture Stimulation Sundry Withdrawal David, With the suspension of drilling operations on PBU L-200, PBU-20OL1 and PBU-2001-2 will you be withdrawing this sundry for fracture stimulation? Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loepp a[7.alaska.00v 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 Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Thursday, February 16, 2017 11:22 AM To: Wages, David (David.Wages@bp.com) Subject: PBU L -200A (PTD #2161250, Sundry #317-051) - Application to Fracture Stimulate - Request for Additional Information David, We are progressing the application but I have a few questions. Please provide a diagram and pressure rating of this "Buffalo head" mentioned in Step D of the program? I am assuming it is either a high pressure rated tree saver/valve bypass attachment/ tubing head adaptor but I cannot find the pressure rating, pressure test plan, or what pressure it will be subjected to during the Steps C, D, and E, of your frac program. I am especially concerned about "Step E. Pressure criteria -CT only" where the treating pressure increases from the 5000 psi of the frac to the mentioned 8500 psi. Please explain what pressures will be seen on each component including the wellhead/BOPS, the 4.5 inch tubing, and the IA (4 %2" x 7 5/8" annulus) during the CT work including the top off procedure? Please confirm where the frac fluids and flowback will be disposed of? Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 if to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST OF STANDARD ) Aquifer Exemption ALASKA PRODUCTION ) Order No. 1 COMPANY ) for an Aquifer Exemption Order for that ) Western Operating Area portion of the Prudhoe Bay Unit commonly known as the Western Operating Area including the contiguous K Pad Area. IT APPEARING THAT: including the K Pad Area Prudhoe Bay Unit Prudhoe Bay Field July 11, 1986 1. Standard Alaska Production Company, by letter of May 16, 1986, requested that the Oil and Gas Conservation Commission issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II injection activities. 2. Notice of an opportunity for a public hearing on July 21, 1986, was published in the Anchorage Times on June 13, 1986. 3. Neither a protest nor a request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hearing. 4. A copy of Standard Alaska Production Company's request was forwarded to the U.S. Environmental Protection Agency (EPA) - Region 10, on May 21, 1986, in conformance with Section 13 of the Memorandum of Agreement, between the Alaska Oil and Gas Conservation Commission and EPA, effective June 19, 1986. FINDINGS: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit are reported to have a total dissolved solids content of 7000 mg/I or more. 4. By letter of July 1, 1986, EPA -Region 10 advises that the aquifers occurring beneath the Western Operating and K Pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a nonsubstantial program revision not requiring notice in the Federal Register. 5. The Western Operating Area and the contiguous K Pad Area constitute a compact land parcel which can readily be described by governmental subdivisions. CONCLUSION: Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25.440. NOW, THEREFORE, IT IS ORDERED THAT the portions of aquifers on the North Slope described by the 1/4 mile area beyond and lying directly below the following tracts of land are exempted for Class II injection activities only. UMIAT MERIDIAN T12N R10E Sections 13 and 24. T12N R11 E Sections 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 23, 24, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35 and 36. T12N R12E Sections 7, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36. T12N R1 3E Sections 19, 20, 21, 22, 23, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, And 36. T12N R14E Sections 27, 28, 29, 31, 32, 33 and 34. T11 N R11 E Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24 and 25. T11 N R1 2E Entire Township. T11 N R1 3E Entire Township. T11 N R14E Sections 3, 4, 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31 and 32. T1 ON R1 2E Sections 1, 2, 3, 4, 10, 11, and 12. T1 ON R1 3E Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, And 24. T1 ON R14E Sections 5, 6, 7, 8, 17, 18, 19 and 20. Done at Anchorage, Alaska and dated July 11, 1986. C.V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission Lonnie C. Smith, Commissioner Alaska Oil and Gas Conservation Commission William W. Barnwell, Commissioner Alaska Oil and Gas Conservation Commission JNOZ :)ISSVIdi—OWil3d CQ W W < + D O + 00 N O On Z W - M N 0 1 7W 0�V O N 1 CV N O - ' O>NN0 NO NQ N0 N J u, o 0 � N W W La Q r �a m (Y) I 10098 0 8 0088 008 , W I LL w O O V UI I�1 Q UO 1 Q 0 0� 1 Z 3 a , Z a IL 3NOZ N01133f NI 3ISSVIa1-OWa3d oa of aW Y - LL W _ ig 1i � III ii 0 W W � a V Y40 W< U. LL > W Y F- y Z W W Z W Z I- ai (jj Z Y m Z CL Q < f)r J t: yo0 < C7 W 4 W C0 c7 z O W ] < J O / 0cr < CC< U Y r= O R ►-< �' m Z 0 Nav < }0- J� ¢°� w Yl J 0 i LL U W — m Y o W ., aH i J CC W LLJ O ~ =3Y �� W � O L �/ // Wv ��: ?; 111 1 1 1 1 1 1 1 1 1 1 1 1 11111111 11111111 XX i 1111 11111 �Iyy. IIII�y 1111� f o CL 1111111 111 JNOZ :)ISSVIdi—OWil3d SOHIO PBU C-11 19-T 1 1 N -R 1 4E • SUB—SEA Age Formation GR .6t/ILD p O(.I� ..6 " IL D�-gin 1 W z o N _ kr Z -- L C� LL z -- .— O r Sagavanirktok =_ J60 �-- ................................................................... -- - L 3800 m;; ..... r... .... .......... --- .000 .2 W - .6 Z --- 0 — N - z o Ugnu _ 5 -- 5200 z s.00 West Sak 5600 ' 5800 V.4 ... ........1. ........ ul ..... n 6200 W U Z 6.00 CIO --- i-0 U. 6600 (D z Seabee - 1_ 68 CIO U U_ =- -- Z o U Pebble Shale - - TYPE LOG FOR. CRETACEOUS/TERTIARY INTERVALS WELL PBU C-1 1 FIGURE F-2 SECTION L AQUIFER EXEMPTION 20 AAC 25.402(c)(13) 20 AAC 25.252(c)(11) w [ An exemption under 20 AAC 25.440 is requested for all aquifers which could It potentially contain freshwater within the area of review. The regulations define freshwater as "water having a TDS concentration of less than 10,000 mg/l .,.". As described in Section F, available information suggests that some zones of the Tertiary sands may contain aquifers with salinity between 7000 and 10,000 mg/l total dissolved solids (TDS). The aquifers contain relatively high TDS and they are situated at a depth and remote location that makes recovery of water for drinking water purposes economically impractical. These aquifers within the area of review do not currently serve as a source of drinking water and cannot reasonably be expected to supply a public water system. These criteria meet the requirements for exemption under 20 AAC 25.440(a)(2). Geologic Data Based on an evaluation of well log data, certain sand sequences within the WOA { potentially contain freshwater aquifers with less than 10,000 mg/l TDS. i variations and uncertainties in measured and derived aquifer salinities { preclude definitive classification of these aquifers. The strata expected to ` contain less than 10,000 mg/l TDS correlate with the sand zones found in the Sohio Well C-11 between measured depth of 2,000 and 4,650 feet subsea (see Figure F-2). Formation water salinities, as calculated by the spontaneous potential (SP) method, yield 7,000 to 24,000 mg/l NaCl equivalents in several of the Tertiary sands. -37- a Drinking Water in Area Drinking water for the WOA is obtained from surface sources, primarily Big Lake, Lake Africa, and the Kuparuk reservoirs. These readily available sources are sufficient to meet the fresh water needs, and there are no plans to obtain drinking water from underground sources for WOA operations. Due to the water quality, depth, and remote location of the aquifers below permafrost, recovery of water from these sands for drinking water purposes would be both economically and technologically impractical. With these limitations and the abundance of fresh water from surface sources, the underground aquifers cannot be reasonably expected to supply a public water system. -38- 4. Formation Water Salinities For the PBU WOA, Cretaceous and Tertiary formation water salinities have been calculated using well log data and also analyzed using water samples. Over the entire Cretaceous interval, petrophysically derived salinities (NaCl equivalents) range from 17,000 to 45,000 ppm NaCl using the SP method. Cretaceous water analysis, for zones sampled, range from 36,800 to 44,100 ppm total dissolved solids (TDS). See Note 1 below. In the Tertiary interval, petrophysically derived salinities (NaCl equivalents) range from 7,000 to 24,000 ppm NaCl using the SP method. Cretaceous water analysis, for zones sampled, range from 9,900 to 11,100 ppm TDS. f Tertiary water salinities less than 10,000 ppm NaCl (ranging from 7,000 to l 10,000) are generally located west of GC -2 in the western half of the PBU WOA. Areas east of GC -2 have formation water salinities greater than 10,000 ppm TDS. A fresh water aquifer exemptions is requested in Section L. 5. References More information pertaining to salinity data and measurement techniques is provided in Standard's UIC application, Form 4, Attachment E. NOTE 1: At the concentrations found, mg/l and ppm may be used interchangeably. -20- J��JleD STgr�S UJ � O c7 Z Q 011 ��ylgC PRO tol REPLY TO ATTN OF: M/S 409 U.S 6 -AMENTAL PROTECTION AC REGION 10 1200 SIXTH AVENUE SEATTLE, WASHINGTON 98101 J U L 10 1986 C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Standard Alaska Production Company Aquifer Exemption Request May 16, 1986. Dear Mr. Chatterton: Based on a July 7, 1986, telephone conversation between Lonnie Smith and Harold Scott, I understand there were no comments during the public comment period regarding the proposed exemption. Therefore, we concur with your decision to exempt the aquifers beneath the Western Operating Area of the Prudhoe Bay Unit for Class II injection activities only. This is a "non -substantial program revision" in accordance with Section 13 of our Memorandum of Agreement. Sincerely, Robert S. Burd Director, Water Division �cE,v�v �uL 496 Alaska Oil &Gas cons. Gomm�sslQ� Anchorage U JVIRONMENTAL PROTECTION, } a�JEo srgTE REGION 10 0 s 1200 SIXTH AVENUE 'Z SEATTLE, WASHINGTON 98101 o c JUL 01 1999 FilgC Pf70�EG1 RLPLY To M/S 409 ATTN OF: C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 %Y RE: Standard Alaska Production Company Aquifer Exemption Request . May 16, 1986 Dear Mr. Chatterton: As you know, the UIC permit application submitted by the Standard Alaska Production Company (formerly Sohio Alaska Petroleum Company) to EPA on June 6, 1984, indicated there were no underground sources of drinking water (USDW's) at the Prudhoe Ray Oil Field (Western Operating Area). However, in their May 16, 1986, aquifer exemption request to AOGCC, it appears there are USDW's in the area. We will be contacting the operator for clarification as to when they became aware of the existence of USDW's. We will keep you informed of our findings and any subsequent actions. In accordance with our Memorandum of Agreement, EPA has conducted a preliminary review of the aquifer exemption request. We believe that the subject aquifers qualify for an exemption. Our final concurrence/ non -concurrence with your decision will be based on the results of your detailed evaluation of the exemption request and any additional information developed through your public comment process. This action is considered to be a minor exemption and a "nonsubstantial program revision" and will not require notice in the Federal Register. Sincerely, V` Robert S. Burd Director, Water Division- PECEIVED Jul- 0 ? 1986 /llaska Oil € c""; Certs. Ccm:rli-sion /1nc!,or�rge THE NATE F11 ASM11160fl,45 GOVERNOR BILL WALKER October 14, 2016 Mr. John Barnes Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: OTH-16-024 Defeated Safety Valve System Duck Island Unit 3-09A (PTD 1950190) Duck Island Unit 2-56A (PTD 1980580) Dear Mr. Barnes: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 9495071-3572 Main: 907.279, 1433 Fax: 907.276.7542 --w.caogcc.elaskc.cgov The Alaska Oil and Gas Conservation Commission (AOGCC) reviewed Hilcorp Alaska, LLC (Hilcorp)'s October 3, 2016 written explanation regarding the safety valve system violations on Duck Island Unit (DIU) wells 3-09A and 2-56A.t AOGCC became aware of the DIU 2-56A violation (failure to install a subsurface safety valve; failure to tag the well) after issuance of the DIU 3-09A notico of violation (defeated safety valve system) and advised Hilcorp representatives during a September 1.9, 2016 meeting that it would not issue a separate notice of violation. Instead, Ililcorp was instructed to address the DIU 2-56A violation in its response to the DIU 3-09A notice of violation. In its responses to numerous past notices of violations Hilcorp committed to complete corrective actions to prevent recurrence of the violations at the DIU wells. Recent examples of its commitment include Hilcorp's responses to the defeated safety valve system at Northstar 15 in February 2015, two defeated alternate safety valve systems at Soldotna Creek Unit rod pump wells (January 2014), and the defeated safety valve system at Sterling 43-09X (April 2013). AOGCC closed out these violations based on Hilcorp's commitment to complete corrective actions. Evidence suggests that Hilcorp's emphasis on training its operating personnel and other corrective actions have been ineffective at preventing recurrences at Hilcorp. Hilcorp now indicates that corrective actions may take up to six months to complete. AOGCC intends to monitor implementation of Hilcorp's corrective actions as outlined in the October 3, 2016 response to the notice of violation for safety valve system violations at DIU. For the present, AOGCC will take no action. However, unless Hilcorp has demonstrated to AOGCC's satisfaction by April 15, 2017 that corrective actions sufficient to prevent recurrences of these violations have been implemented, the AOGCC will move forward on this matter. ' Both wells are located on Endicott Satellite Drilling Island /•► .l"4 Y 1 O •N M V O Z .2Ln . m LA .y N i Q to N ._ O Z i. V � a LL. ..r V Q O m N L J �Ti Z M p N Z LA D � co Q W Q W N = a O d N ,s CL L. ouo m L. CL n n! 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C O CL o a j y E Ln ►, Nil u u cD O a P'110 zl(, - izs- Loepp, Victoria T (DOA) From: Thompson, Jacob <Jacob.Thompson@BP.com> Sent: Friday, January 27, 2017 2:09 PM To: Loepp, Victoria T (DOA) Subject: L -200A (PTD216-125 revised) Change Request Follow Up Flag: Follow up Flag Status: Flagged Victoria, On step 12 of the proposed drilling rig operations section of the L -200A original sundry and PTD the 10-3/4" surface casing was to be pressure tested to 3,500 psi. 3,500 psi is our standard test pressure for producers in the Greater Prudhoe Bay Field to cover all well types. As stated in the PTD L -200A is accessing reserves in the Schrader Bluff formation where a MASP of 1,840 psi is expected. In order to not exert unnecessary stress on the existing surface casing we are requesting that the 10-3/4" surface casing test pressure be reduced to 2,400 psi. This is well above MASP and meets all AOGCC requirement, and will reduce the chances of damaging the surface casing. Please advise if you approve this change. Thank you and have a great weekend, .Jacob Thompson BP Alaska Rotary Drilling Engineer Cell. (907) 854-4377 Office: (907) 564-5579 Pl0 2-16,- !Z7 Loepp, Victoria T (DOA) From: Thompson, Jacob <Jacob.Thompson@BP.com> Sent: Thursday, December 29, 2016 8:43 AM To: Loepp, Victoria T (DOA) Subject: PBU L -200A (PTD 216-125) Ram Configuration Change Request. Attachments: L -200A PTD Final REV2.docx Follow Up Flag: Follow up Flag Status: Flagged Victoria, The BOP configuration in the permit to drill submitted had Parker 272 using an annular, 7-5/8" fixed bore rams, Blind Shear rams, and 2-7/8" x 5" VBR for the entirety of the L -200A sidetrack well. This ram configuration meets both BP and AOGCC requirements. BP's operation management has requested that we swap the 7-5/8" fixed bore rams for 2-7/8" x 5" VBR whenever drill pipe will be tripped into the hole. This will add an extra layer of protection during well work, and exceeds the state requirement. I have attached a revision of the PTD that has the extra ram change out and pressure testing that is being requested. The sections that were added are highlighted in green. Let me know if you have any questions. Kind Regards, Jacob Thompson BP Alaska Rotary Drilling Engineer Cell. (907) 854-4377 Office: (907) 564-5579 To: Alaska Oil & Gas Conservation Commission From: Jacob Thompson, ODE Date: February 7, 2017 RE: L -200A Permit to Drill The L -200A well is scheduled to be drilled by Parker 272 in January 2017. This well will be sidetracked out of the existing L-200 multi -lateral's 10-3/4" surface casing. The pre -rig work outlined in the sundry will have the well abandoned with a 1,500' cement plug across the tubing and IA. The objective of L -200A is to recover the reserves left over from the L-200 motherbore. The rig will then move over the well and pull the 4-1/2" tubing and cut the 7-5/8" casing at 3,100' MD. A clean out run will then be performed, followed by the setting of an EZSV bridge plug in preparation of the whipstock exit at 3,000' MD. The objective of the L -200A sidetrack is to drill a slant well near three L-200 laterals, and hydraulically fracture into them to recover their reserves. The well will be sidetracked out of the existing 10-3/4" surface casing, and a 9-7/8" production hole will be drilled down into the OBf formation. A string of 7-5/8" casing will be run into the well, and cemented to 1,000' above the SB_Na formation. The well will be perforated and a 4-1/2" multi -zone frac pack completion will be run. The maximum anticipated surface pressure from the Schrader Bluff with a full column of gas from TD to surface is 1,840 psi (assumes 9.62 ppg EMW most likely pore pressure and a 0.1 psi/ft gas gradient). The well will be drilled by Parker 272 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. If there are any questions concerning information on L -200A, please do not hesitate to use the contact information below. Jacob Thompson Office: (907) 564-5579 Cell: (907) 854-4377 Email: Jacob.thompson@bp.com Attachments: Well Bore Schematic Proposed Pre -Rig Schematic Proposed Completion Directional Package BOPE Schematic 272 L -200A PTD 1 2/7/2017 Planned Well Summary Well L -200A Well Producer Target Schrader T e Objective Bluff Current Status Not Operable Estimated Start Date: 1 1/10/17 Time to Complete: 1 19 Days Surface Northing Eastin Offsets TRS Location 5,978,289 583,209 1 2567 FSL / 3705' FEL I 12N 11 E Sec 34 Planned KOP: 3000' MD Planned TD: 9,114' MD / 4,597' TVDss Rig: Parker 272 GL -RT: 46.95 RTE ref MSL): 1 96.05 Directional — Baker L -200A wPO5 KOP: 3000' MD Northing Easting TVDss Offsets TRS Window 5,979,800 583,795 -2,130 1208' FNL / 3099' FEL 12N 11E Sec 34 Oba Lateral 5,984,110 581,840 -4,200 2156' FNL / 4998' FEL 12N 11 E Sec 27 TD 5,984,514 581,290 -4,597 1745' FNL / 263 FEL 12N 11E Sec 28 Planned KOP: 3000' MD Planned TD: 9,114' MD / 4,597' TVDss Rig: Parker 272 GL -RT: 46.95 RTE ref MSL): 1 96.05 Directional — Baker L -200A wPO5 KOP: 3000' MD Maximum Hole Angle: �70° Close Approach Wells: None. All offset wells pass BP Anti -collision Scan Criteria. Survey Program: See attached Directional Plan Nearest Property Line: 5,400' Nearest Well within Pool: 1,675' L -200A PTD 2 2/7/2017 Formation Tops and Pore Pressure Estimate (SOR) Estimated Formation Top Pore Pressure Formation (TVDss) (DDM) Fluid Tvoe (for sandsl SV2 2154 8.6 Hydrates SV1 2475 8.6 Hydrates UG4 2783 9 Heavy Oil UG4A 2804 9 Heavy Oil Fault 1 2891 9 A-53 UG3 3029 9 Heavy Oil / Water UG1 3524 9 Heavy Oil / Water UG Ma 3795 9 Heavy Oil / Water UG Mb1 3842 8.76 Heavy Oil / Water UG Mb2 3901 8.72 Heavy Oil / Water UG Mc 3957 8.76 Heavy Oil / Water NA 4018 8.7 Water NB 4038 8.65 Water NC 4070 8.73 Water NE 4079 8.73 Water NF 4126 8.73 Water OA 4161 9.65 Viscous Oil / Water Oba 4214 9.62 Viscous Oil Obb 4258 9.62 Viscous Oil Obc 4309 8.7 Viscous Oil Obd 4358 8.71 Viscous Oil Obe 4419 8.61 Viscous Oil OBf 4458 8.59 Viscous Oil OBf base 4525 8.59 Viscous Oil Casing/Tubing Program Hole Size Liner / Wt/Ft Grade Conn Length Top Bottom pH Tbg O.D. <25 <8 NA <20 8.5-9.5 MD / TVDss MD / TVDss 48" 20" x 34" 215.5# A-53 - 114' Surface 114'/ 94.9' 13-1/2" 10-3/4" 45.5# L-80 BTC 3,000' Surface 3,000'/ 2,129' Window 9-7/8" 7-5/8" 29.7# L-80 / VamTop HC 8,320'/ Surface 9,114'/ 4,597' 13Cr-80 794' Tubing 4-1/2" 12.6# 13Cr-80 VamTop 8,891' Surface 8,891'/ 4,485' Mud Program Intermediate Mud Properties: LSND 9-7/8" Hole Section Depth Interval Density PV (cp) Ib/1 0ftz API FL HTHP FL MBT pH KOP - 8,100' MD 9.3-9.8 1 10-15 <25 <8 NA <20 8.5-9.5 8,100' MD - 9,114' MD 10.0-10.2 1 10-15 <25 <8 NA <20 8.5-9.5 L -200A PTD 3 2/7/2017 Logging Program Interval MWD/LWD OH Logs CH Logs Coring Sampling Surface Basis Lead TOC N/A Intermediate N/A N/A N/A N/A N/A Tail TOC Tar et 1000 ft above the Na sands USIT log to Sampling -50 bbls of Viscosified Spacer weighted to -12.0 Mud Push II GR/RES assess 7- as needed Volume Contingent use of 5/8 9-7/8" NEU/DENS logs cement Potential Production top. for high GR on perforation GR CCL to frequency assembly log the sampling completion near L-200 on depth. laterals Tie-in requirements if a N/A sidetrack Cement Program Casing Size 7-6/8" 29.7# 1_-80 VamTop HC Intermediate Casing Lead N/A Basis Lead TOC N/A Tail Oen hole volume + 40% excess + 85 ft shoe track Tail TOC Tar et 1000 ft above the Na sands Spacer -50 bbls of Viscosified Spacer weighted to -12.0 Mud Push II Total Cement Lead N/A Volume Tail 109.2 bb1s, 612.77 cuft, 528.25 sks 15.8 lb/gal Class G - 1.16 cuft/sk Temp BHST 87° F Surface and Anti -Collision Issues Surface Close Proximity: No wells will be affected by the Parker 272 rig shadow. Sub -Surface Pressure Management: SV1 / UGNU: Presence of hydrates / heavy oil. No injection / production in these intervals, assume original pressures. Schrader Interval: Check pressure and fluid data from production engineer to confirm pressure prediction and fluid input into PPFG. Collect a SBHP in L-211 4-6 months prior to spud to verify OA, OBA/OBB pressures. Confirm Schrader waterflood mandels are dummied in L-117. Shut in L-212, L-218, and L-211 (all offset injectors) one week prior to drilling and keep shut in until well is completed. Anti -Collision: The original laterals L-200, L-2001_1, and L-2001_2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L -200A well path must be drilled in close proximity to them in order to hydraulically fracturing into them. If an intersection were to occure there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. Offset well ownership information All offset wells identified within 200 ft of the proposed wellbore are operated by BP. Hydrogen Sulfide L -Pad is considered an H2S site. Recent H2S data from the pad is as follows: L -200A PTD 4 2/7/2017 Parent Well (if sidetrack) #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level #3 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Other Relevant H2S Data (H2S alarms from rigs, ets. Well Name H2S Level Readina Date Comments L-200 18 ppm 3/10/13 70' , down to S/SW L-250 14 ppm 8/7/12 NA L-202 38 ppm 1/12/15 Low L-203 20 ppm 7/13/12 120', down E n to L-204 16 ppm 1/4/15 NA L-205 2 ppm 1/3/12 NA L-116 190 ppm 3/19/15 Kuparuk Producer L-250 is close on surface and with its BH location. Faults Formation Where Throw Encounter MD TVDss direction and Lost Circ Fault Intersect Intersect Magnitude Uncertaintv Potential Ugnu 4A 4992 2891 70' , down to S/SW 250'N/125'S Low NA NA 2891 60, down to E 250'E/275'W Low NA NA 4450 120', down E n to 175'N/300'S NA NA NA 4450 75', down to N 100'N/175'S NA 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. L -200A PTD 5 2/7/2017 Well Control The decomplete and drilling of the 9-7/8" hole section will be done with well control equipment consisting of 5,000 psi working pressure 7-5/8" fixed ram (upper), 2-7/8" x 5" VBR (lower), 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 L -200A will be 7 days during the decomplete phase of the well and 14 days during the drilling phase of the well 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. 9-7/8" Intermediate Interval Maximum anticipated BHP 2,300 psi at TD at 4,597' TVDss 9.62 ppg EM Maximum surface pressure 1,840 psi at TD 0.10psi/ft gas gradient to surface) 25 bbis with 12.1 ppg frac gradient. Kick tolerance Assumes 10.12 ppg PP (9.62 most likely PP + 0.5 ppg kick intensity) and a 10 ppg MW. Planned BOP test pressure Rams test to 3,500psi / 250 psi. Annular test to 3,500 psi / 250psi' Integrity Test—12-1/4" hole LOT after drilling 20'-50' of new hole 7-5/8" Casing Test 3,500 psi surface pressure L -200A PTD 6 2/7/2017 Drill and Complete Operations Summary Pre -Rig Prep Work: Proposed Drilling Rig Operations: 1. MIRU Parker 272. 2. Test TWC from below to 3,500 psi for 30 minutes. 3. Nipple down tree. Nipple up and test Annular, 2-7/8° x 5" VB upper rams, blind shear rams, and 2-7/8" x 5" VB lower rams to 3,500 psi. 4. Pull TWC with lubricator. 5. RU hard lines to BOP. Circulate out diesel freeze protection through choke to tiger tank with clean 8.5 ppg seawater. 6. RU and pull the 4-1/2" tubing from the pre -rig jet cut. 7. MU casing cutter and cut 7-5/8" casing at 3,100' MD. 8. Change out u r 2-7/8" x 5" VB rams to 7-5/8" fixed bore rams and test to 3,500 psi. 9. RU and pull 7-5/8" casing from cut. 10. Change out upper 7-5/8" fixed rams to 2-7/8" x 5" VB bore rams and test to 3,500 psi. 11. RIH with 10-3/4" clean out assembly down to the top of the 7-5/8" casing stub. 12. RU E -line w/ GR/CCL log and set EZSV at 3,000' MD and pressure test to 250 psi for 5 min and 3,500 psi for 30 min. Chart both tests. 13. PU 10-3/4" whipstock, bottom trip anchor and 9-7/8" window milling assembly. RIH to the top of the EZSV. Orient and set the whipstock. 14. Swap the well over to 9.5 ppg fresh water LSND milling fluid. ----------------------------------------End of Sundry: Start of Permit to Drill ---------------------------------- 15. Mill window in the 10-3/4" casing plus 20' of formation. 16. Perform LOT. POH for drilling BHA. 17. MU 9-7/8" drilling BHA, GR/RES/PWD, UBHO (Gyro), and RIH. Kick off and drill 9-7/8" intermediate interval. 18. Drill to the end of build section at 3,600' MD. 19. POOH and LD 9-7/8" motor BHA. 20. PU 9-7/8" RSS drilling BHA, GR/RES/PWD/DENS/NEU and RIH. L -200A PTD 7 2/7/2017 Pre Rig Plan for L -200A Step Service Operation 1 F LLR TAA (potential LDL) 2 S Pull GLV Drift run for gyro. 3 E Run Gyro as deep as possible. 4 F Circ Cement 1500' Plug 5 S D&T TOC. Drift for Jet Cut 6 F CMIT-TxIA to 3,000 psi. 7 E Jet Cut 3500' 8 F Circ out. CMIT-TxIA to 3,000 psi. 9 1 V Install Dry Hole Tree. Configure TWC. Proposed Drilling Rig Operations: 1. MIRU Parker 272. 2. Test TWC from below to 3,500 psi for 30 minutes. 3. Nipple down tree. Nipple up and test Annular, 2-7/8° x 5" VB upper rams, blind shear rams, and 2-7/8" x 5" VB lower rams to 3,500 psi. 4. Pull TWC with lubricator. 5. RU hard lines to BOP. Circulate out diesel freeze protection through choke to tiger tank with clean 8.5 ppg seawater. 6. RU and pull the 4-1/2" tubing from the pre -rig jet cut. 7. MU casing cutter and cut 7-5/8" casing at 3,100' MD. 8. Change out u r 2-7/8" x 5" VB rams to 7-5/8" fixed bore rams and test to 3,500 psi. 9. RU and pull 7-5/8" casing from cut. 10. Change out upper 7-5/8" fixed rams to 2-7/8" x 5" VB bore rams and test to 3,500 psi. 11. RIH with 10-3/4" clean out assembly down to the top of the 7-5/8" casing stub. 12. RU E -line w/ GR/CCL log and set EZSV at 3,000' MD and pressure test to 250 psi for 5 min and 3,500 psi for 30 min. Chart both tests. 13. PU 10-3/4" whipstock, bottom trip anchor and 9-7/8" window milling assembly. RIH to the top of the EZSV. Orient and set the whipstock. 14. Swap the well over to 9.5 ppg fresh water LSND milling fluid. ----------------------------------------End of Sundry: Start of Permit to Drill ---------------------------------- 15. Mill window in the 10-3/4" casing plus 20' of formation. 16. Perform LOT. POH for drilling BHA. 17. MU 9-7/8" drilling BHA, GR/RES/PWD, UBHO (Gyro), and RIH. Kick off and drill 9-7/8" intermediate interval. 18. Drill to the end of build section at 3,600' MD. 19. POOH and LD 9-7/8" motor BHA. 20. PU 9-7/8" RSS drilling BHA, GR/RES/PWD/DENS/NEU and RIH. L -200A PTD 7 2/7/2017 21. Drill 9-7/8" intermediate interval to section TD at. Weight up drilling fluid using spike fluid maintaining the following density ranges: • KOP - 4,000' TVDss: 9.3 - 9.8 ppg • 4,000' TVDss - TD: 10 - 10.2 ppg 22. At TD, CBU until hole is clean (minimum 2x), then perform short trip. 23. RIH to TD and circulate the well clean and POH on elevators. 24. Change out upper 2-7/8"-x 5r. VB rams to'1-51W fixed bore rams and test to 1,500. psi. 25. Run and cement 7-5/8", 29.7#, L-80, VAM TOP HC casing to TD. Top of cement will be at 6,959' MD. Bump the plug with 9.9 ppg NaCl brine. (RA tag to be run above the estimated top perforation.) 26. Pressure test the 7-5/8" casing to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes 27. Install the 7-5/8" pack -off through the stack and test to 250 psi low / 5,000 psi high for 30 minutes. 28. 29. Freeze protect the 9-5/8" x 7" annulus, once the tail cement has reached compressive strength. 30. MU pert assembly with MWD GR. 31. RIH and tag the float collar, PU log guns on depth, and fire. 32. POOH lay down guns. 33. R/U E -line run GRJB to drift perfs, Run USIT log to confirm TOC in 7-5/8" Casing. 34. R/U and run a 4-'/2", 12.6#, 13CR, VT tubing completion with GLM's, 6 production packers 5 NCS frac sleeves, 5 NCS screen sleeves, and SLB Gauge on Iwire. (RA tag to be run in completion.) 35. With completion spaced out RU a -line and log the RA tags to confirm the completion is on depth. 36. Land the tubing hanger, and run in lock down screws. 37. Reverse circulate 9.9 ppg brine and corrosion inhibitor into the tubing x casing annulus. 38. Drop ball/rod, set packer and individually test the tubing and annulus to 3,500 psi for 30 minutes. 39. Hold pressure on the IA and bleed tubing pressure to zero, shearing the DCK shear valve. Pump both ways to confirm circulation ability. 40. Install TWC and test from above to 250 psi low / 3,500 psi high for 5 minutes each and from below to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high. 41. Nipple down the BOPE. Nipple up the adaptor flange and double master valves and test to 5,000 psi with diesel. 42. Remove TWC. 43. Reverse circulate diesel freeze protect using rig injection pump. 44. Allow diesel to U-tube, drain stack, and rig down landing joint. Monitor well for 1 hour to confirm well is dead. 45. Dry Rod BPV in and install all annulus valves and secure the well. 46. RDMO. Planned Post -Rig Operations: 1. Change out tree. L -200A PTD 8 2/7/2017 2. Pull BPV, Pull Ball, Rod and RHC Plug with slickline. 3. Pull shear valve and dummies, change GI -Vs. 4. RU coil and individually hydraulically fracture each zone thru the NCS sleeves with coil. 5. RU E -line and run a gravel pack log. 6. RU coil, open up screen sleeves, and top off zones requiring more gravel. 7. Flowback as per ASRC. 8. Install flow lines and well house. L -200A PTD 9 2/7/2017 L -200A Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Production Hole: The Schrader Bluff Oba formation is expected to be at a 9.62 ppg EMW. Reservoir pressures will be controlled by using 10.0 — 10.2 ppg water based mud. B. Shallow Gas: Wells at L -Pad have had a history of shallow gas and hydrates in the SV2, SV3 and UG4A formations, although L-200 parent bore did not experience any. The importance of the fluid monitoring process will need to be stressed in this interval as well as the review of the RP: Handling Gas Hydrates While Drilling. II. Stuck Pipe/Hole Cleaning A. Hole Cleaning: The planned well path has a difficult hole cleaning environment with a substantial amount of 600 - 70° hole. This increases the probability of encountering hole cleaning problems from cutting build up. The ROP limits, sweep strategy, and ECD limitation outlined in the well program help to prevent and identify problems with hole cleaning. B. Ugnu Coals: L -Pad wells have a history of encountering troublesome coals while drilling and tripping thru the Ugnu formation. This may result in instances of abnormally high and erratic torque or overpulls. Problems thru the Ugnu coals usually reduce with time after they have been allowed to be agitated mechanically. III. Fault Locations Formation Where MD TVDss Throw Direction and Uncertainty Lost Circ Fault Encountered Intersect Intersect Magnitude 1/12/15 Potential Fault 1 UG4A 4,492 -2,891 dips S/SW (70 ft) 150 ft lateral Low 1/4/15 L-116 190 ppm & MD Kuparuk Producer IV. Integrity Testing Test Point Test Depth Test aEMW Ib/ al 10-3/4" Window 20'-50' from the middle of the 10-3/4° LOT 12.1 ppg L-202 Window 1/12/15 V. Hydrogen Sulfide L -Pad is considered an H2S site. Recent H2S data from the pad is as follows: Well Name H2S Level Reading Date Comments Parent Well (if sidetrack) #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Other Relevant H2S Data (H2S alarms from rigs, ets. L-200 18 ppm 3/10/13 L-250 14 ppm 8/7/12 L-202 38 ppm 1/12/15 L-203 20 ppm 7/13/12 L-204 16 ppm 1/4/15 L-116 190 ppm 3/19/15 Kuparuk Producer L-250 is close on surface and with its BH location. VI. Anti -Collision Issues The original laterals L-200, L-2001-1, and L-2001_2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L -200A well path must be drilled in close proximity to them. This will allow them to be hydraulically fracturing into. If an intersection were to occur there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. CONSULT THE L -PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. L -200A PTD 10 2/7/2017 L -200A PTD 11 2/7/2017 Tla£= 4-1116'CIW WELLHEAD- 11' FRC{ ACTLATOR- B.AKIR OK13 FIS r =_ -- -- n.tr 13F. BBV = 53.80 KOP- 380" Rbx Angle = 96- a 115 ' Datura W _ . ..751! DEK= TVD = 4/00 SS Minimum ID = 3213" @ 2174' 4-1/2" HES X NIPPLE � 7-w X 9-718- Troc --{.. fiiw .. RA HAG I 65-W .4-12- sGm4vpc-CA7On 3-I MIXT4D90P SLG, D=3 -9W 4- 112- acA44CV�- rA 7006' U-LTFDRDPSUB, D= 3.958" C4 V2 TBG. 12.6N,13CR 80 VAM TOP -i 7250' 0158 bpf, D - 3.958' 15-12- X 4-112" XO. D = 3.93(- (-j 7405- DA KB211pOK FLA WAR 7419' w / L1 NON -S6ALM LE M. D = 3.71' FIEWOYSTDN SLVAWRY SEF LOG: ANGLE AT TOP i Note: Refer to Roductbn 08 for 19storic at pert data svi- ( -4+ WtWA4.. F Op6u5c)r DAM 4 -VI 57.19 OF3a .. %39Q 4-10 SLTD OBb 7497- 12944 O 02/12/04 4-117 SLID OLd 7870- 13000 O 02/44104 T?:T�j SAFETY MOVES: WELL ANGLE i 70"@ 6807- »'4-112" CHROME TBGi --LEM @ 731V IS COLLAPSED. CAN NOT PASS TFRU WITH ANY TOOLS. 'FESXW,1D=3813" GAS 1 RT AYaWM S ST! ND 14-112. 18G, 121W L-80 HT RA H 7296' �- TYPE .0152 bpf. D = 3.958' I 15-112" X 4- I,2' XO, 1E)=3 930' 1-F —2 BA KER nuL/K KA WAR 7315 w1i2NON-SFAtAGtHM 9-371- GO OLLAT'S®1.9A - GN N(7T PA, S5 BY l ^ T315 ONAVD.H VIDEO) (12114112) O 15-12- X 4-112" XO. D = 3.93(- (-j 7405- DA KB211pOK FLA WAR 7419' w / L1 NON -S6ALM LE M. D = 3.71' FIEWOYSTDN SLVAWRY SEF LOG: ANGLE AT TOP i Note: Refer to Roductbn 08 for 19storic at pert data svi- ( -4+ WtWA4.. F Op6u5c)r DAM 4 -VI 57.19 OF3a .. %39Q 4-10 SLTD OBb 7497- 12944 O 02/12/04 4-117 SLID OLd 7870- 13000 O 02/44104 T?:T�j SAFETY MOVES: WELL ANGLE i 70"@ 6807- »'4-112" CHROME TBGi --LEM @ 731V IS COLLAPSED. CAN NOT PASS TFRU WITH ANY TOOLS. 'FESXW,1D=3813" GAS 1 RT AYaWM S ST! ND ND I UEV TYPE VLV LATC" PORT DATE O 3040 2430 GO IUXi2 ❑Mt Olf O 11f0411� 5 i 3565 4 5373 3 5490 211X;45 IJ 2495 3133 3498 4068 4157 60 SB 56 69 69 KBC+2 G2 K® KtF(Q HBW KRG2 OW URN OR4:' F1l611Y (3K RK UK 9K R.K 0 0 0 0 - 11721/09 07103!11 11121M 11121819 07!03!11 MID] —) Ifz "KK l SLS ti V, ul 3a15- 7067 7-Sla" X 4-112- BlOi FiRul RSR D= 3.875 7122 -i 11? KSXW.9) 3813' 7127 l4 V7 F'9f R L1G (11 bSn 5y 7193' 4-1/2- FFS X NP, 9=3813- 7184' X S f 72.)(0, D = 3-940' 7277' 5.7S' BKR SLAL STB4 (SFALS F94OVF371, D= 4.83' 72142" 75W X 4112'13KR ZXP UP w MWK. D-5.750 1-2 (-a) L2 I ©11- LEM A1NC0'N6`- t ?320'-7331' OPENING WOTH = 3.33' 7315'- 13044' 6-3A'08a LATERAL, ID = 1958' 7398' I -+d-117-Mlx.ESHDF,9-3.958' �L'ItOBbILEXI'"IWNE4- PF?424 Li (OBb) . TH=nw�x : Lrolntrl = .3 is OBb P87D 1298T 7419' - 12988' 6-314' 013b LATERAL, D - 3.958" i T53T 1-" 7-516- X 5 1r1- fIKR 7XP I NR TOPPKR ..7548- 4-117- MU F SHt7F. n - 3 958' 7Ti6T 5 112- X 4 /.4- XOD0 t 7-5 8 CSG, 29.7tt, L SO f3TG/ll U= 6.a75"H 7872' I I t t I � i IL -2001 /b/2'- 13052' 8-3/4" OUd LAI LRAL, 10 = 3.958' 0Hd 13050' DATE FEV BY CONKINT5 DATE REV BY OOANENTS 02/Va4 MID Or\GiNAL COM('LLTION Oril26116 TTAIJRU r'LLLLD MOCK CATO Cn (UCr W161 11Q -m 1116 HaIPO 12!03115 GFB1J1rD GLV CFO (I vow 15) 04109112 TBIYJ6U SET ROOK CATCFH2 (CWD7/ 12193115 GPFVJRD SET PX PLUG (11815115) 04N0112 JRS/A.D GLV CIO ((4108612) 12J18712 17RJN'JFOCYRSHROCKGATcHwcoLLM(12114112) 01/15113 C U1JFU SU RX -A (A ICII4t 12131112) OWN UNIT YTiL L 200 PERP N7: 2040010 (02(1) (030) AR No-. 50-029-23191.00(60)(611 SEC34, T12N R1I F 256T FSL 8 1575 FH- UP 5cplora0on (AUsM L -200A PTD 12 2/7/2017 TRUE = 4-1116" CNV wta r rsn n - ACTLATOR= BAKER PRE -RIG B. b:_-.-...._.._._...._.-_-__- OKB. l7� - 77 6' BF. ELEV = 53.80' KOP- 380' 200CArD - 114' Max Angle = 96' § 11569' OellarlMD= 7515' D31um ND= -- 4400' SS 10314' CSG 45,54, L 851. D 995'F 3$71' MinFlum ID = 3.813" 21T4� 4-112" HES X NIPPLE 4-12 x_' 518- TOC 4-112' SGA4FOPGCA 7035' M11ll-ORDI SIi3.D=3.958' 4- 12- SGM FDPG CA68 70 MILTWRDP SIB, D=3958' 1 14-1? TBG, 1284, 13(01-fi0 VAM TOP 7250' 0158W. ID- 3 958- ; RA TAG]--� 7270_ 4-112- TBG, 12.60 L-80 6T -M, —�7M .0152 W, ID - 3 958' 5-12- X 4-1? X0. D = 3.930' 7301' BAKER HOOK HAtG 731T w 11.2 NON-SEALtJG LEA. D - 3.71' (XXLAPSFT) t FTA- CAN NOT PASS BY -7315 (SEEN INDH VMO)(12J44J12) 17-5V X 5 V7 BKRZXPLTP. D`= 4.94 7386 [5.1?X417XO,D-3930' H 74106'--� BAKER HOOK wANUR� 741 9' w! L1 NON -SEA LNG LELL DD3 71' _ ---- FEiFORATDN SLAMARY REI' LOG: ANGLLAT TOPPEW NDle Refer to Rodueeon DB for erstmCal pert date 47E SPF FIFE VAL Opn/Sgz DATE 4-10 SLTD OBa 7392-13000 0 - 0211&04 4-12' SLTD 08b 7497-129" O 02/12104 4.12- ELTO 08d 7870-13008 O 02/DM04 CSG, 29.70, L-80 1 � 6.875'] 7872' t 1 i IL -2001 OBd REIM 13950• SAFETY NOTES: WELL ANQE > 70- @ 6602'. »•442' CHROME TBG '-LEM @ 7315' IS COLLAPSER CAN NOT PASS THRU WITH ANY TOOLS, -985' 10 1'4- TAM PORT COt FAR HESX NP, D=3.813' GAS LIFT MANd4AS ST MD I ND OEV TY FE VLV LATCH POW DATE 6 3448 2436 60 KBC;2 ODM BK 0 11/04115 5 3565 2495 60 KBG2 ORN BK 0 1/121109 4 5373 3433 58 KBG2 DM BK 0 07103111 3 5490 3498 56 KBG2 DW BK 0 1121109 2 6645 4068 69 193M OM! SK 0 11121109 1 6888 4157 69 1 KBG2 E.PIY BK - 07!03!11 4-12" BKR CAD 5LDNG SLV. D= 3 813' 7-518' X 4-12' 8161 PREM RCR, D= 3 875 4-12'FES XNIP, D=7.817' i=irr 3�i Fuc n vosiis>� 4i/?'FES XFP, D=3813'1 ^72�-14-112- X 5-112- XO, D = 3 840' j 727T5-75 BM SEAL STIW -- (SEALS F MDVE ),D=4.8Y 02$2•7-SB-X4-12-SKRZXPLTPwiiFW.D-5750- _ _ -L2 (OBa) _ _ _ _ l2 (OBa: LEPA'WNDOW 65' 7320'-7331' OP�JfY1G V.'D1F+ * 3 l3' --08a PBID 13043' 7315' - 13044' 6314' OBa LATERAL, D = 1958' 73$8' 4-1J2-MILESHOE D=3.958' L1 (OBb; LEPA IN DOW 6a' L1 (OBb)- 7424'-7435' 0PFFF1ir VMTH = :! ! aee PBm1298T L7419' - 12988' 63/4' OBb LATERAL, H) = 3.958' 1 7649 -14AW WILE SHOE D= 3.958- 1 766T S 12- X 4-12- XO, D= 3.930 1 7572'- 13052' 6-314' 08d LATERAL, D = 3 958' DATE REV BY ODMMB4TS UA TE FEV BY SITS 02122/04 NDES ORCML COMPLETION 0626!75 TFA/JMD P1LLm RDCK CATcFER 062om1 11125M 616 RWO 12!03/15 U"JMD (;LV GO(I IAWIS) 04109112 TBDlJAD SET RDCK CATCFER (04107/ 12!03115 &&JLAD SFT PX PLUG (11105/I5) --- OV IO112 .806!.0.0 GLV 00 (04108/12) 12/10/15 JT7JMD PREM CMT FCOdPISH ROCK CATCFf3a'OOL. LfT1E (12!14112) 12/18/12RiYW 01/15/13 GJB/JMD SET ROCK CATUIER(ID31112) Of" LNPT WS -L_ L 200 F4 -RW ND2040010 (020) (WO) AFIW 50-029-73191.00(60X61) 34, T12K R1 iL 256T ESL d 1575 FLl BP Ekploratbn (Alaska) L -200A PTD 13 2/7/2017 PROPOSED L -200A RMS= REV 2 3. ELEV = 77.V ELEV = 53W / I. 3W 201 OOFD -! 111' / , AnCL- m MO= _ m TVD= 4400 SS 1 a -3a- wF4PSTOcx 1_r_I_l 3tt0' 31a• CSG, x5.51, L-00. O - 9.85' -3tt0' r' CSO, 29.71, L-80 zO 10 11GW40�- ow TOPIC, 0= 6 875* Minimum ID = 3.725" @ 8874' 1-112" HES XN NIPPLE RA TAO4-117 nema ILAR 8288' --fl IRA TAG /-YB' GSIVG COLLAR -�— PEf4KmTION Sl86MR'7 REF LOG ANOLEATTOPPE F: NDW Refer to PFodckan OB for holomM pert data SFE SPF 70NE WTURVAL Qn/r.W DATE 4438- 7 OBe 8383 8988 O 4-3A8 1 OBD 8457 - 8557 O 4 3AY / OBC 8548 - 8853 O 2 4-38' 7 ON 8858 - 8883 O 4-30W I OF% 8172 •8711 O 4 I 7 OBI am - W75 O 8' CSC 5 875* SAH IY NO W57 W Fl. L ANG'LF > 70" a ••'CHROML G&G & TW" RI.LOLR VW4WW (L-A*QA) -38W--37W PJC. �WY Q 5$ M1 TVD DEV IYFE Vv 'ATCit F1gif fYi7 4 3427 16 .R/AO PROPOSAL REV 1 HP gWma on IAI=ka) -- , F JT/ARO PROPOSAL FW4 2 3 6181 2 7241 1 BOW 4-1/2' SCACNDP(' CA SWAE DROP SAPPHW GALIGL O = 3.884 - NC.'. FRAC PTWT. O- 3 956' 518' x 4- I!2• FES TNT RKIL D = 3.858• 117 NCS FRAC PORT. O- 3 958* 1 84M' 7•5r8' x 4. Irl' IC3 Ym R(R D. 3.650• 8466• 4- 117 NCS FRAC PORT. D = 3 958- 11! ICL I ry I tNC Y= J FRAC PORT. D+ 3 958' QBti• j-j7L518'x4.17YFF.s TNTFKFLD=3.8%- air 4-Ir7NC8FRA-k"t0=3958' 6781' t-j7-`JB'x 4,: ;i rxR.D-3858• HF5 xN NP. D- 3 725• DATE PLV eY COWA34TS 047E REV BY I COAI@1P5 OP171Lm WELL L -200A 1$JwLf Fb. AR No' 50.029-23191-0_ SEC 34. T12K RI IF 2567- PSL & 1575 FEL OZr1711W_ Nth ONG ML COMPLETION 11,75" ptt RiN0 _ 99*TRACK (L -200A) 15 JMJkO BMT PROPOSED 16 .R/AO PROPOSAL REV 1 HP gWma on IAI=ka) -- , F JT/ARO PROPOSAL FW4 2 L-20OA PTD 14 2/7/2017 zra .;.... �• � • _ -_ _ _ � _ --I aaiwi aL �a :-c aTaarl.- I► _ iiu a: n ra wWr..]eul aw o]L Wto :I> • �f .�m^_ ... '- __- �_ r as a --' i __ �]yt•�iv cacm -rmm: �-xw=aar } .• r i '..I...-. .a �..T v Yli I.fwL. GS %Y — e � �witn� M• .0 vt l _ .s•„xm �-" �i•iu .xss ra INL L -200A PTD 15 2/7/2017 Ken Allen THE STATE Alaska Oil and Gas ofA LASKA Conservation Commission GOVERNOR BILL WALKER Drilling Supervisor BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L -200A BP Exploration (Alaska), Inc. Permit to Drill Number: 216-125 revised 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Surface Location: 2568' FSL, 3704' FEL, SEC. 34, T12N, RI IE, UM Bottomhole Location: 3619' FSL, 164' FEL, SEC. 28, T12N, RI IE, UM Dear Mr. Allen: Enclosed is the approved application for permit to re -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 . Foerster Chair DATED this 2.6 day of January, 2017. STATE OF ALASKA SKA OIL AND GAS CONSERVATION COMMIE PERMIT TO DRILL 20 AAC 25.005 REVISED: CHANGED KICKOFF POINT 1a. Type of Work:1 b. Proposed Well Class: Exploratory - Gas EIService - WAG ❑ Service - Disp El c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ElDevelopment - Oil 0 ' Service - Wnj ❑ Single Zone 0 • Coalbed Gas ❑ Gas Hydrates ❑ Redrill 0 . Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond Blanket 0 • Single Well ❑ 11 Well Name and Number: BP Exploration (Alaska), Inc Bond No. 29S105380 PBU L -200A - Address: 3. 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 196612 Anchorage, AK 99519-6612 MD: 9389'' TVD: 4693' - PRUDHOE BAY, SCHRADER BLUFF OIL 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): ADL 028239 Surface: 2568' FSL, 3704' FEL, Sec. 34, T12N, R11E, UM $ Land Use Permit: 13. Approximate Spud date: Top of Productive Horizon: 3133' FSL, 4958' FEL, Sec. 27, T12N, R11E, UM 00-001 January 25, 2017 ' 9. Acres in Property: 2560 14. Distance to Nearest Property: Total Depth: 3619' FSL, 164' FEL, Sec. 28, T12N, R11E, UM 5400 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 96.05 . feet 15. Distance to Nearest Well Open to Same Pool: Surface: x- 583209 y- 5978290 - Zone - ASP 4 GL Elevation above MSL: 49.1 -feet 1675 16. Deviated wells: Kickoff Depth: 3400 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 71 degrees Downhole: 2300 - Surface: 1840 - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casinq Weiqht Grade Coupling Length MD TVD M12 TVD(including stage data 9-7/8„ 7-5/8" 29.7# L-80/13Cr80 VamTopHC 9389' Surface Surface 9389' 4693' 589 sx Class'G' L Raw1wili V Ilk MW 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) ; Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): 1 Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 1 13067 4367 7122 7122 4250 None -' Casing Length Size Cement Volume MD TVD Conductor/Structural 78 20"x34" 260 sx Arctic Set (Approx.) 31 -110 31 -110 Surface 3840 10-3/4" 723 sx AS Lite, 338 sx Class 'G' 31 -3871 31 -2668 Intermediate 7843 7-5/8" 515 sx Class 'G' 29-7872 - 29-4496 Tieback Liner 266 4-1/2" Uncemented Tieback Liner 7282-7320 4302-4318 Liner 5515 4-1/2" Uncemented Slotted Liner 7537-13052 4409-4356 Perforation Depth MD (ft): 7870-13008 Perforation Depth TVD (ft): 4495-4366 20. Attachments Property Plat ❑ BOP Sketch 0 Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated Contact Thompson, Jacob from without prior written approval. Email Jacob.Thompson@BP.com Printed Name Ken Allen Title Drilling Supervisor Signature Phone +1 907 564 4366 Date Commission Use Only Permit to Drill 16-125 Number: API Number: 50- 029-23191-01-00 Permit Approval Date:O ZS _ See cover letter for other e _ ` 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 contained in shales: [� i Other: t/�✓SSS � Samples req'd: Yes ❑ No L� Mud log req'd: Yes ❑ No 0e f30%� fi�S � �� rw H2S measures Yes E2( No ❑ Directional svy req'd: Yes F� No ❑ Spacing exception req'd: Yes ❑ No 19 Inclination -only svy req'd: Yes ❑ No 19/ A-7 SS V�� ✓ Post initial injection MIT req'd: Yes ❑ No 15-- 1_0 25 r APPROVED BY Approved b COMMISSIONER THE COMMISSION Date: ORIGNAL V7-1- I/ -/(,/)f Form 10401 Revised 11/2015 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g) Submit Form and Attachments in Duplicate To: Alaska Oil & Gas Conservation Commission From: Jacob Thompson, ODE Date: January 23, 2017 RE: L -200A Permit to Drill The L -200A well is scheduled to be drilled by Parker 272 in January 2017. This well will be sidetracked out of the existing L-200 multi -lateral's 10-3/4" surface casing. The pre -rig work outlined in the sundry will have the well abandoned with a 1,500' cement plug across the tubing and IA. The objective of L -200A is to recover the reserves left over from the L-200 motherbore. The rig will then move over the well and pull the 4-1/2" tubing and cut the 7-5/8" casing at 3,100' MD. A clean out run will then be performed, followed by the setting of an EZSV bridge plug in preparation of the whipstock exit at 3,000' MD. The objective of the L -200A sidetrack is to drill a slant well near three L-200 laterals, and /i. BGG hydraulically fracture into them to recover their reserves. The well will be sidetracked out of the existing 10-3/4" surface casing, and a 9-7/8" production hole will be drilled down into the OBf formation. A string of 7-5/8" casing will be run into the well, and cemented to 1,000' above the SB_Na formation. The well will be perforated and a 4-1/2" multi -zone frac pack completion will be run. The maximum anticipated surface pressure from the Schrader Bluff with a full column of gas from TD to surface is 1,846 psi (assumes 9.62'ppg EMW most likely pore pressure and a 0.1 psi/ft gas gradient). The well will be drilled by Parker 272'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. If there are any questions concerning information on L -200A, please do not hesitate to use the contact information below. Jacob Thompson Office: (907) 564-5579 Cell: (907) 854-4377 Email: Jacob.thompson@bp.com Attachments: Well Bore Schematic Proposed Pre -Rig Schematic Proposed Completion Directional Package BOPE Schematic 272 L -200A PTD 1 1/23/2017 Planned Well Summary Well L -200A Type Producer FOTbWective et Schrader Current Status Not Operable Estimated Start Date: 1/25/17 1 Time to Com lete: 19 Da s Surface I Northing Easting Offsets I S Location 5,978,289 583,209 2567 FSL / 3705' FEL 12N 1SeE34 - ElE Planned KOP: 3,400' MD Planned TD: 9,389' MD / 4,597' TVDss - Rig: Parker 272 GL -RT: I I RTE Of MSL): 96.05 Directional - Baker L -200A wol1 KOP: 3400' MD Northing. Easting TVDss Offsets TRS Window 5,980,113 583,924 -2,338 896' FNL / 2966' FEL 1201E Sec 34 Oba Lateral 5,984,120 581,880 -4,200 21146' FNL / 4,958' FEL 12N 11E Sec 27 TD 5,984,601 581,388 -4,597 1660' FNL / 164 FEL 12N 11 _ESec 28 Planned KOP: 3,400' MD Planned TD: 9,389' MD / 4,597' TVDss - Rig: Parker 272 GL -RT: I I RTE Of MSL): 96.05 Directional - Baker L -200A wol1 KOP: 3400' MD Maximum Hole Angle: -71' Close Approach Wells: None. All offset wells pass BP Anti -collision Scan Criteria. Survey Program: See attached Directional Plan Nearest Property Line: -✓5,400' Nearest Well within Pool: 1,675' L -200A PTD 2 1/23/2017 Formation Tops and Pore Pressure Estimate (SOR) Estimated Formation Top Pore Pressure Formation (TVDss) (ppCl) Fluid TVDe (for sands) SV2 2154 8.6 Hydrates SV1 2483 8.6 Hydrates UG4 2784 9 Heavy Oil UG4A 2818 9 Heavy Oil Fault_1 2960 9 A-53 UG3 3090 9 Heavy Oil / Water Fault_2 3197 9 L-80 UG1 3534 9 Heav Oil /Water UG Ma 3792 9 Heav Oil /Water UG_Mb1 3827 8.76 Heavy Oil / Water UG_Mb2 3882 8.72 Heavy Oil / Water UG Mc 3955 8.76 Heavy Oil / Water NA 4021 8.7 Water NB 4040 8.65 Water NC 4071 8.73 Water NE 4079 8.73 Water NF 4126 8.73 ' Water OA 4161 9.65 Viscous Oil / Water Oba 4214 9.62 Viscous Oil Obb 4259 9.62 Viscous Oil Obc 4310 8.7 Viscous Oil Obd 4360 8.71 Viscous Oil Obe 4423 8.61 Viscous Oil OBf 4461 8.59 Viscous Oil OBf base 4507 8.59 Viscous Oil Casing/Tubing Program Hole Size Liner / Wt/Ft Grade Conn Length Top Bottom <20 Tbg O.D. 8,200' MD — 9,389' MD 10.0 — 10.2 10-15 <25 <8 NA <20 8.5-9.5 MD / TVDss MD / TVDss 48" 20" x 34" 215.5# A-53 - 114' Surface 114' / 94.9' 13-1/2" 10-3/4" 45.5# L-80 BTC 3,400' Surface 400' / 2,338' 3,Window 9-7/8" 7-5/8" 29.7# 13r - 3Cr- /80 VamTop HC 8,389' / 1,000' Surface 9,389'/ 4,597' Tubing 4-1/2" 12.6# 13Cr-80 VamTop 9,240' Surface 9,240'/4,522' Mud Program Intermediate Mud Properties: LSND 9-7/8" Hole Section Depth Interval Density PV (cp) YP Ib/1 Oftz API FL HTHP FL MBT pH KOP — 8,200' MD • 9.3-9.8 10-15 <25 <8 NA <20 8.5-9.5 8,200' MD — 9,389' MD 10.0 — 10.2 10-15 <25 <8 NA <20 8.5-9.5 L -200A PTD 3 1/23/2017 Logging Program Interval MWD/LWD OH Logs CH Logs Coring Sampling Surface Basis Lead TOC N/A Intermediate N/A N/A N/A N/A N/A Tail TOC Target 1000 ft above the Na sands USIT log to Sampling -50 bbls of Viscosified Spacer weighted to -12.0 pp Mud Push II) GR/RES assess 7 - as needed Volume Contingent use of 5/8 9-7/8" NEU/DENS logs cement Potential Production top. for high GR on perforation GR CCL to frequency assembly log the sampling completion near L-200 on depth. laterals Tie-in requirements if a N/A sidetrack Cement Program Casing Size 7-5/8" 29.7# L-80 VamTop HC Intermediate Casing Lead N/A Basis Lead TOC N/A Tail Open hole volume + 40% excess + 85 ft shoe track Tail TOC Target 1000 ft above the Na sands Spacer -50 bbls of Viscosified Spacer weighted to -12.0 pp Mud Push II) Total Cement Lead N/A Volume Tail 121.7 bbls, 683.4 cuft, 589.1 sks 15.8 lb/gal Class G — 1.16 cuft/sk Temp BHST 87° F Surface and Anti -Collision Issues Surface Close Proximity: No wells will be affected by the Parker 272 rig shadow. . Sub -Surface Pressure Management: SV1 / UGNU: Presence of hydrates / heavy oil. No injection / production in these intervals, assume original pressures. Schrader Interval: Check pressure and fluid data from production engineer to confirm pressure prediction and fluid input into PPFG. Collect a SBHP in L-211 4-6 months prior to spud to verify OA, OBA/OBB pressures. Confirm Schrader waterflood mandels are dummied in L-117. Shut in L-212, L-218, and L-211 (all offset injectors) one week prior to drilling and keep shut in until well is completed. Anti -Collision: j The original laterals L-200, L-2001-1, and L-2001_2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L -200A well path must be drilled in close proximity to them in order to hydraulically fracturing into them. If an intersection were to occure there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. Offset well ownership information All offset wells identified within 200 ft of the proposed wellbore are operated by BP. Hydrogen Sulfide L -Pad is considered an H2S site. Recent HZS data from the pad is as follows: L -200A PTD 4 1/23/2017 Parent Well (if sidetrack) #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level #3 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Other Relevant H2S Data (H2S alarms from rigs, ets. Well Name H2S Level Readina Date Comments L-200 18 m 3/10/13 20-40" , down to S/SW L-250 14 ppm 8/7/12 5,805 - L-202 38 ppm 1/12/15 Low L-203 20 ppm 7/13/12 120', down E n to L-204 16 ppm 1/4/15 NA L-205 2 ppm 1/3/12 NA L-116 190 ppm 3/19/15 Kuparuk Producer L-250 is close on surface and with its BH location. Faults Formation Where Throw Encounter MD TVDss direction and Lost Circ Fault Intersect Intersect Mannihirlp IInrcrtninhi D..+e.,+:,i Ugnu 4A 5,088 • -2,960 20-40" , down to S/SW 250'N/1 25'S . vLow,4, UG3 5,805 - -3,197 80-100'Edown to 250'E/275'W Low NA NA 4450 120', down E n to 175'N/300'S NA NA NA 4450 75', down to N 100'N/175'S NA 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. L -200A PTD 5 1/23/2017 Well Control The decomplete and drilling of the 9-7/8" hole section will be done with well control equipment consisting of 5,000 psi working pressure 7-5/8" fixed ram (upper), 2-7/8" x 5" VBR (lower), 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 L -200A will be 7 days during the decomplete phase of the well and 14 days during the drilling phase of the well 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. 9-7/8" Intermediate Interval Maximum anticipated BHP 2,300 psi at TD at 4,597' TVDss (9.62 ppg EMW) - Maximum surface pressure 1,840 psi at TD (0.10 psi/ft gas gradient to surface) Kick tolerance 25 bbls with 11.71 ppg frac gradient. Assumes 10.12 ppg PP (9.62 most likely PP + 0.5 ppg kick intensity) and a 10.2 ppg MW. ' Planned BOP test pressure Rams test to 3,500psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test — 12-1/4" hole LOT after drilling 20'-50' of new hole 7-5/8" Casing Test 3,500 psi surface pressure L -200A PTD 6 1/23/2017 Drill and Complete Operations Summary Pre -Rig Prep Work: Proposed Drilling Rig Operations: 1. MIRU Parker 272. 2. Test TWC from below to 3,500 psi for 30 minutes. 3. Nipple down tree. Nipple up and test Annular, 2-7/8" x 5" VB upper rams, blind shear rams, and 2-7/8" x 5" VB lower rams to 3,500 psi. 4. Pull TWC with lubricator. 5. RU hard lines to BOP. Circulate out diesel freeze protection through choke to tiger tank with clean 8.5 ppg seawater. 6. RU and pull the 4-1/2" tubing from the pre -rig jet cut. 7. MU casing cutter and cut 7-5/8" casing at 3,100' MD. 8. Change out upper 2-7/8" x 5" VB rams to 7-5/8" fixed bore rams and test to 3,500 psi. 9. RU and pull 7-5/8" casing from cut. 10. Change out upper 7-5/8" fixed rams to 2-7/8" x 5" VB bore rams and test to 3,500 psi. 11. RIH with 10-3/4" clean out assembly down to the top of the 7-5/8" casing stub. 12. RU E -line w/ GR/CCL log and set EZSV at 3,400' MD and pressure test to 250 psi for 5 min and 3,500 psi for 30 min. Chart both tests. 13. PU 10-3/4" whipstock, bottom trip anchor and 9-7/8" window milling assembly. RIH to the top of the EZSV. Orient and set the whipstock. 14. Swap the well over to 9.5 ppg fresh water LSND milling fluid. ----------------------------------------End of Sundry: Start of Permit to Drill ---------------------------------- 15. Mill window in the 10-3/4" casing plus 20' of formation. 16. Perform LOT. POH for drilling BHA. 17. MU 9-7/8" drilling BHA, GR/RES/PWD, UBHO (Gyro), and RIH. Kick off and drill 9-7/8" intermediate interval. 18. Drill to the end of build section at 3,900' MD. 19. POOH and LD 9-7/8" motor BHA. 20. PU 9-7/8" RSS drilling BHA, GR/RES/PWD/DENS/NEU and RIH. L -200A PTD 7 1/23/2017 Pre Rig Plan for L -200A Step Service Operation 1 F LLR TAA (potential LDL) 2 S Pull GLV Drift run for gyro. 3 E Run Gyro as deep as possible. 4 F Circ Cement 1500' Plug 5 S D&T TOC. Drift for Jet Cut 6 F CMIT-TxIA to 3,000 psi. 7 E Jet Cut 3500' 8 F Circ out. CMIT-TxIA to 3,000 psi. 9 V Install Dry Hole Tree. Configure TWC. Proposed Drilling Rig Operations: 1. MIRU Parker 272. 2. Test TWC from below to 3,500 psi for 30 minutes. 3. Nipple down tree. Nipple up and test Annular, 2-7/8" x 5" VB upper rams, blind shear rams, and 2-7/8" x 5" VB lower rams to 3,500 psi. 4. Pull TWC with lubricator. 5. RU hard lines to BOP. Circulate out diesel freeze protection through choke to tiger tank with clean 8.5 ppg seawater. 6. RU and pull the 4-1/2" tubing from the pre -rig jet cut. 7. MU casing cutter and cut 7-5/8" casing at 3,100' MD. 8. Change out upper 2-7/8" x 5" VB rams to 7-5/8" fixed bore rams and test to 3,500 psi. 9. RU and pull 7-5/8" casing from cut. 10. Change out upper 7-5/8" fixed rams to 2-7/8" x 5" VB bore rams and test to 3,500 psi. 11. RIH with 10-3/4" clean out assembly down to the top of the 7-5/8" casing stub. 12. RU E -line w/ GR/CCL log and set EZSV at 3,400' MD and pressure test to 250 psi for 5 min and 3,500 psi for 30 min. Chart both tests. 13. PU 10-3/4" whipstock, bottom trip anchor and 9-7/8" window milling assembly. RIH to the top of the EZSV. Orient and set the whipstock. 14. Swap the well over to 9.5 ppg fresh water LSND milling fluid. ----------------------------------------End of Sundry: Start of Permit to Drill ---------------------------------- 15. Mill window in the 10-3/4" casing plus 20' of formation. 16. Perform LOT. POH for drilling BHA. 17. MU 9-7/8" drilling BHA, GR/RES/PWD, UBHO (Gyro), and RIH. Kick off and drill 9-7/8" intermediate interval. 18. Drill to the end of build section at 3,900' MD. 19. POOH and LD 9-7/8" motor BHA. 20. PU 9-7/8" RSS drilling BHA, GR/RES/PWD/DENS/NEU and RIH. L -200A PTD 7 1/23/2017 21. Drill 9-7/8" intermediate interval to section TD at. Weight up drilling fluid using spike fluid maintaining the following density ranges: • KOP - 4,000' TVDss: 9.3 - 9.8 ppq ' • 4,000' TVDss - TD: 10 - 10.2 ppg ' 22. At TD, CBU until hole is clean (minimum 2x), then perform short trip. 23. RIH to TD and circulate the well clean and POH on elevators. 24. Change out upper 2-7/8" x 5" VB rams to 7-5/8" fixed bore rams and test to 3,500 psi. 25. Run and cement 7-5/8", 29.7#, L-80, VAM TOP HC casing to TD. Top of cement will be at 6,959' MD. Bump the plug with 9.9 ppg NaCl brine. (RA tag to be run above the estimated top perforation.) 26. Pressure test the 7-5/8" casing to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes 27. Install the 7-5/8" pack -off through the stack and test to 250 psi low / 5,000 psi high for 30 minutes. 28. Change out upper 7-5/8" fixed rams to 2-7/8" x 5" VB bore rams and test to 3,500 psi. 29. Freeze protect the 9-5/8" x 7" annulus, once the tail cement has reached compressive strength. 30. MU perf assembly with MWD GR. 31. RIH and tag the float collar, PU log guns on depth, and fire. 32. POOH lay down guns. 33. R/U E -line run GRJB to drift perfs, Run USIT log to confirm TOC in 7-5/8" Casing. 34. R/U and run a 4-%", 12.6#, 13CR, VT tubing completion with GLM's, 6 production packers 5 NCS frac sleeves, 5 NCS screen sleeves, and SLB Gauge on Iwire. (RA tag to be run in completion.) 35. With completion spaced out RU a -line and log the RA tags to confirm the completion is on depth. 36. Land the tubing hanger, and run in lock down screws. 37. Reverse circulate 9.9 ppg brine and corrosion inhibitor into the tubing x casing annulus. 38. Drop ball/rod, set packer and individually test the tubing and annulus to 3,500 psi for 30 minutes. 39. Hold pressure on the IA and bleed tubing pressure to zero, shearing the DCK shear valve. Pump both ways to confirm circulation ability. 40. Install TWC and test from above to 250 psi low / 3,500 psi high for 5 minutes each and from below to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high. 41. Nipple down the BOPE. Nipple up the adaptor flange and double master valves and test to 5,000 psi with diesel. 42. Remove TWC. 43. Reverse circulate diesel freeze protect using rig injection pump. 44. Allow diesel to U-tube, drain stack, and rig down landing joint. Monitor well for 1 hour to confirm well is dead. 45. Dry Rod BPV in and install all annulus valves and secure the well. 46. RDMO. Planned Post -Rig Operations: 1. Change out tree. L -200A PTD 8 1/23/2017 2. Pull BPV, Pull Ball, Rod and RHC Plug with slickline. 3. Pull shear valve and dummies, change GI -Vs. 4. RU coil and individually hydraulically fracture each zone thru the NCS sleeves with coil. 5. RU E -line and run a gravel pack log. 6. RU coil, open up screen sleeves, and top off zones requiring more gravel. 7. Flowback as per ASRC. 8. Install flow lines and well house. L -200A PTD 9 1/23/2017 L -200A Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Production Hole: The Schrader Bluff Oba formation is expected to be at a 9.62 ppg EMW. Reservoir pressures will be controlled by using 10.0 — 10.2 ppg water based mud. B. Shallow Gas: Wells at L -Pad have had a history of shallow gas and hydrates in the SV2, SV3 and UG4A formations, although L-200 parent bore did not experience any. The importance of the fluid monitoring process will need to be stressed in this interval as well as the review of the RP: Handling Gas Hydrates While Drilling. II. Stuck Pipe/Hole Cleaning A. Hole Cleaning: The planned well path has a difficult hole cleaning environment with a substantial amount of 60° - 70° hole. This increases the probability of encountering hole cleaning problems from cutting build up. The ROP limits, sweep strategy, and ECD limitation outlined in the well program help to prevent and identify problems with hole cleaning. B. Ugnu Coals: L -Pad wells have a history of encountering troublesome coals while drilling and tripping thru the Ugnu formation. This may result in instances of abnormally high and erratic torque or overpulls. Problems thru the Ugnu coals usually reduce with time after they have been allowed to be agitated mechanically. III. Fault Locations Formation Where MD TVDss Throw Direction and 10-3/4" Window Lost Circ Fault Encountered Intersect Intersect Magnitude Uncertainty Potential Fault 1 UG4A 5,088' -2,960' dips down to E (20-40 250 ft lateral Low 1/4/15 L-116 ft) & MD Kuparuk Producer Fault 2 UG3 5,805' -3,197' dips down to E (80- 250 ft lateral Low 100 ft) & MD IV. Integrity Testing Test Point Test Depth - -- 3/10/13 EMW (lb/gal) 10-3/4" Window —Testtype 20'-50' from the middle of the 10-3/4" LOT 12.1 L-202 Window 1/12/15 ppg V. Hydrogen Sulfide L -Pad is considered an H2S site. Recent H2S data from the pad is as follows: Well Name H2S Level Readina Date Comments Parent Well (if sidetrack) #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Other Relevant H2S Data (H2S alarms from rigs, ets. L-200 18 ppm - -- 3/10/13 - ------------ L-250 14 ppm 8/7/12 L-202 38 ppm 1/12/15 L-203 20 ppm 7/13/12 L-204 16 ppm 1/4/15 L-116 190 ppm 3/19/15 Kuparuk Producer L-250 is close on surface and with its BH location. VI. Anti -Collision Issues The original laterals L-200, L-2001-1, and L -200L2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L -200A well path must be drilled in close proximity to them. This will allow them to be hydraulically fracturing into. If an intersection were to occur there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. CONSULT THE L -PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. L -200A PTD 10 1/23/2017 TFa£.= 4-1118' CMI WELLHEAD= 1TFRC ACTUATOR- BAKER - — ace., EiFv = 77.6 BP EifV = 53.80' KOP - 380 7OAF CON'1 114' MU Angle = 96'0 11569' Othin 6D = 7515' Oaten TVD = 4400'SS 10.314' CSG. 45 .59, L-80, 10=9.95` -�3 711' Minimum ID = 3813" @ 2174' 4112" HES X NIPPLE j 7.Sf8' x 9-718- TOC H 8800' I MILTFOF40P 51[1. D=3.958' i 4-112- SGMW.P-- c 7006" �hAA.T>-027P S1B, D= 9.958' (4 1/7 T6G.12.61. 13CR 80 VAM TOP 7250' � -01588pf, D- 3-968' I -t . XS112'BKRLXPLIP,U=4.94' 5-117" 1f 4- in, Yr] in = i a•IM BA KERHQOK KA NGER --j 7419' w 1 L7 NON-SEiALM LEK D = 3.7 1- F43WORATON St&&%RY REE LOG: AFIGLE AT TOPF$F- Nole: Refer Do ProducBon OB for historic al per! data SVr i 5PF 1NTF}C✓At Oprasql (IAw 4-lf1t SLIDJ o8a...M-130001 0 ❑7!1!5104 4-12' i SLTD 0% 7497 - t 2944'; 0 02/12/04 4-111"1 SLTD OBd 7870-13008L 0 0204104 I , /-5'S GSG, 29.7A. L-8013TGM D= 8.87Y 7872' � j I , 1L-2001 013 d ® 1s1� SAFETY NOTES_ WELL ANGLE> 70'@ 8802•. —4-112" CHROME TBG'--LEM @ 7315' LS COLLAPSED. CAN NOT PASS THRU WITH ANY TOOLS. 'FESX NP, U=3.813 GAS LFT MAFURE-1,S 0 ! 3440 0 1!2' TBG, 12.6A1 L SO 8T M i -t 7296' 00 .0152 6pf. D = 3.958' Cwt! 5.12" X 4.112- XO. 0 = 3930' 7301' B.A It@2,71NKtiANli6i 7515" w 117 NON -SFA! ING I Fid, D 3 71' 60 )OLLAPSED Lt3A • CAN NOT PAss By 7315 SEEN N D.H. V C.EO) (1 211 41 1 2 1 I XS112'BKRLXPLIP,U=4.94' 5-117" 1f 4- in, Yr] in = i a•IM BA KERHQOK KA NGER --j 7419' w 1 L7 NON-SEiALM LEK D = 3.7 1- F43WORATON St&&%RY REE LOG: AFIGLE AT TOPF$F- Nole: Refer Do ProducBon OB for historic al per! data SVr i 5PF 1NTF}C✓At Oprasql (IAw 4-lf1t SLIDJ o8a...M-130001 0 ❑7!1!5104 4-12' i SLTD 0% 7497 - t 2944'; 0 02/12/04 4-111"1 SLTD OBd 7870-13008L 0 0204104 I , /-5'S GSG, 29.7A. L-8013TGM D= 8.87Y 7872' � j I , 1L-2001 013 d ® 1s1� SAFETY NOTES_ WELL ANGLE> 70'@ 8802•. —4-112" CHROME TBG'--LEM @ 7315' LS COLLAPSED. CAN NOT PASS THRU WITH ANY TOOLS. 'FESX NP, U=3.813 GAS LFT MAFURE-1,S 0 ! 3440 2430 00 I{D02 Cwt! OI( 0 111040 5 j 3565 2495 60 KBG2 OW SK 0 11f21A 415373 3433 68 KEtG2 CJA4/ BK 0 07)n, 3 15490 3498 56 KBG2 I EM BK I 0 11121A 2 6645 4068 69 KBG2 DW BK ❑ 1IMA 1:6888 4157 69 KFJG2 FAMITY BK - 07103r 705. 1� 4-72"BISN OuO':�AY"gLV U=3813' T08T 7-518- X 4112- 3.875- 7122' 4112' lfS X fF', IT - 3 813"; `7122 --{4-1/T Fait gtH3 (11,1151157 T193' +s_vz-FosxNP,n=3ata- x.. u = J.ya BKR SEAL STEM LS FEUOVWo, D= 4.BT - - - L2-(- - - - L2 (OBa) LF9.11hR1C0'A'B.' 7320'-7_31' (� O6.t f11T13 130'13• OPENMG WOTH = 3.33' I 7315' -13044' 6314' OBa LATERAL, ID = 3.958' tL 7398' I..'4-1li I.AX F SFC1E, /7 - 3 95R' '. i Lt i DBot LO.i .NINOOfV64' L1 (OBb) 424 :sss ---------------- nFPNw.wnTH=3>3' L18c PBTO 1298T j 7419'- 12968' 6-3A' Oeb LATERAL, ID - 3.958' i '{-7WT I-{7-58-X5-lrr BKR7XP1NRTOPP,KR 'F7 � 4-14Y MSA F SHOF. D - 3 958' 755T 5 la - —X 4 1r2--X-01D - 3-930' 7572' - 13052' 6-314'013d L.AILRAL, 0) = 3.958- f]AIE FEV BY OO DATE REV BY COk6@4TS 6?/+P104 MME OrSG M&L GOMPLCT10N 06!28116 Tf"AJJbU fI.�L@ MKIK G^TO En (0620116) 11/25109 D16 IO1VO 12f(IN15 GJB1Jk4) GLV(70(ll04115) 0409112 TBU-W SET FUCK CATCFER(04071 12/03115 GJEYJLCSET PX FLl1G (1105!15) 04110112 JPeJAID GLV CIO (04KW12) 1211&12 RR✓4' FCO SH ROCK CATt}6YCOL LEM(12114112) 171/15713 GJBiAU SET K)CK GA 10 ii2 12/31712) OFaON LNLE —1 L 200 iEFUY No'. 2010010 (02(1) (OW) AFI No: 50-029-23191-00(60)(61, SE3 34, Tl2N Rl IE, 256T FSL & 1575' F73 BP OKPI*ratlon (Alaska) L -200A PTD 11 1/23/2017 TTiL£ - 4- V 16' CNV MLL I-EAO - 11' F4C ACT'LYI TOR = BAKFR PRE -RIG OKB ELEV 77 6' BF E -EV = 53.80' KOP- 360' 2pNCp.D 114' Max Angle = 96` @ 11568' Datum AU 7515' Dal= NO.- 4400' SS 10 374' CSG 45 5N, L -_1D - 9 9S 4 3871 Minknum ID = 3.813" @) 2174' 4-112" HES X NIPPLE _ 4172' X 7-518' TOC I— 558; 4-10' SGFA tCPG CA 7036• M111 -DROP SM, 0= 3.958' DEI/ a 12 3CSMt47ft3CA H. 7066'- . FAJL RDROP SIA. D = 3.956' 4i/2'TBG. 126N, 13<3Z8(1 VAM TOP 7250' 0158 Ept, D = 3i9fi6' F4A TAG--�j27Q• 41(2' TBG, 12.8N 1.80 STAL7296' 0152 hp1, IQ = 3.958' D = 3 930' 7301' BAKER HOOK HANCAN 7315' w 7 L2 N0N SEALNG LFA, D = 3 71' -7315 CANNOTFiA-SBY �CXXIAPSFDIFM (SE9JMDH VIDEO)(12114/12) l 5 578' X SVT BKR ZXP LTP. D = 4 94'H 7386' - 5-1,-X4-V2-XO.ID=3930' H 7405 BAKB2t-IDOK l4ANG'Ei2 7419• w/Li NON -SEA LNG LF3A.D=371' i PERFORA110N SLA&4ARY --.. MT LOG' ANGLE AT TOP PEfE: Nole Refer to Production OB for hmtwcal pert data SQE SPF NTEii1/AL jj Opn7'.gz DATE 4-12' SLTD OBa 7392 12944 - .....0211&O4 41/1' SLTD OBb 7497- 12944 O 02/12/04 412' SLID OBd 7870- 13008 O 021MA4 - I t CSG. 29.71. L-80 STC -9 D IL -200, J �-- OBd — C13 SAFETY NOTES: WELL ANG -E > 70' @ 6602' «•412- CHROME TBG"LEM @ 731F IS COLLAPSED CAN NOT PASS THRU WITH ANY TOOLS. 98S 103l4'TAMPOR(OOI DAR 2174' Z1-FESXNP,D=3.813' t r_ac I cr ua�.aioo c ST MD ND DEI/ TY FE VLV LAT(.?1 PDKi DATE 6 3448 2436 60 1 KBM DMt' BK 0 11/04!15 5 3565 2495 60 POW DMI 8K 0 1121709 4 5373 3433 58 111 t DFM BK 0 07703111 3 5490 3498 56 KBG2 DMI BK 0 11/21/09 2 6645 4068 69 KBG2 OMY BK 0 11/21/09 1 6888 4157 69 KBM EMPTY BK - 07103/11 ' 7051' 4-12'BKR CAO SLDlG SLY,0=3.873" 7087 7-578'X4-12'BKRMMFKKD=3.875 7127 f 412'HESXDP.D-3.8/3' 7127 H4 t/2' PIC MUG (11It}5715) 7193` j--44. 1!1'' fFS X PP, D = 3 613- 7264' �-j 41/Y X 5-172' XO, D = 3.940' -7277 5 75' BKR SLAL STEM \r (SEALS MAMED),IT) =4.83 l 7282 7-518'X4-t2'BKR ZXPLTPwli1B91C,p=5.750' -L2 (08a) r:6EU A NDOW RS" 7331' OBa f$TD 13043' = 3.33' 7315'- 13044' 6-374' OBa LATERAL, ED = 3 958' 7388' 4 -ill' MJIE SHDE- D = 3.958' � Li (08b LEA" 914N0OW 64` L1 (OBb) 7424•-1a3� ---------- - - - --- ? OPFN3•X; vans 33' OBb -BTO 12987' �7 7419' 12988' 6-374' OBL LATLF2AL, D = 3.958' I 75$7 7-518' X 5-172' WR ZXP LNR TOP PKR 764C ��4.172' MU -E StpE; D - 3.958' 7667 S 172' % 4 12' XO, 9) .. 3 930' 7572'- 13052' 6-314'08d LATERAL, D = 3 958 -FATE F?El/ BY (DF,fAB4T5VI___ 02722704 N96 OAOMLCOMPL.ETION TFA7JMD PILL® ROCK CATCF62(06120/151 11!25109 1116 MNO G)B/JMD GLV C!0(11104/15) 04/09117 TBLYJhD SET PoDCK CATf3i32 (04!GIOIJNO SET Pl( PLUG04/10112 JFIC/JMD GLVC/O (04/0&12) JT/JAO RTL -P10 CMT 1211&12 F3MN FC01MH ROCK CATdti:!(XIL. LF1U (12114!12) 01/15/13 G"J%D SET ROCK CATCIER(12/31112) ORION LNI WELL. L 200 P UM W 2040010 (0201) (030) API W 50-029-23191-00(60X61) 1SM34.T12KR1lF_2WrFSL&l579TU BP Btploration (Alaska) L -200A PTD 12 1/23/2017 L -200A PTD 13 1/23/2017 --I .Y �T DI•T.[S .'L OTT .i iL 1+6a K- d .`fie I =Y YLr o- LY' 1i~i-1�.: [wivu: L -200A PTD 13 1/23/2017 ";jT_ WELLHEAD = 11' FMC PROPOSE ACTUATOR= ANGLE AT TOP PERF: REV 6 OKB. ELEV = 77.6' I BE ELEV = 53.80' / Ill 7 380' 20# COLD 114' Max Angle = ° @ Datum_MD- _ Datum ND = 4400' SS 10314" vVliif'S OCKL/_/_) 3400• 143/4' CSG. 45.5#, L-80, D = 9.95" •••3400• 7-5/8" CSG, 29.7#, L-80 XO TO 13CR-80 -8300• VA M TOP HC, ID = 6.875" Minimum ID = 3.725" @ 8874" 4-1/2" HES XN NIPPLE RA TAG 7-5/8" CASING COLLAR 8320' PERFORATION SUMMARY REF LOG: ANGLE AT TOP PERF: Note: Refer to Production DB for historical pert data SIZE SPF ZONE INTERVAL Opn/Sqz DATE 4-3/8" 7 013a 8383-8388 O 12/12/16 4-3/8" 7 OBb 8452-8557 O 01/23/17 4-3/8" 7 OBc 8548-8553 O 4-3/8" 7 OBd 8658-8663 O 6195 4-3/8" 7 OBe 8772-8777 O 4-3/8" 7 OBf 8997-9002 O 4-1/2" TBG, 12.6+X, 13CR-85 VAM TOP 0152 Ill ID = 3-958" 75/8" CSG, 297#, 13CR-80 VAM TOP HC, ID = 6.875" I 9200' J L _2 00ASAFE OTES: WELL @ -CHROME CSG &TBG*" ANGLE > 70° 986' 10-3/4" TAM PORT COLLAR 2009' 4-1/2" HES X NP, D = 3.813" MILLOUT WINDOW (L -200A) -3400' - --3413' GAS LIFT MIA hill R 8240' -14 1/2" HES SSD DURASLEEV E w nc NP, D = 3.813" 8258' 4-1/2' SGM-NDPG-CA SINGLE DROP SAPPHIRE GAUGE, D = 3.864" 8324' 7-5/8" X 4-1/2" HES TNT R llD = 3.856" 8330' 4-112" NCS FRAC FORT, D = 3.958" 8367' 4-1/2" HES X NIP, D = 3.813" 8370' H4-1/2" NCS SCREEN SLEEVE, D= 3.958" 8398• 7-5/8" X 4-1/2" HES TNT Ill D = 3.856" 8403' 4-112" NCS FRAC PORT, D = 3.958" 8420' 4-1/2" HES X NP, D = 3.813" 8436' H4-1/2" NCS SCREEN SLEE=VE, ll 3.958- 8464' 1-� 7-5/8" X 4-1/2" HES TNT R(R, D = 3.856" 8470' 1-14-1/2" NCS FRAC PORT, D = 3.958" 8619' 14-1/2" HES X T, p = 3.813" 8632' 4-1/2" NCS SCREEN Sll D = 3.958- 8660. .958" 866-�� 7-5/8' X 4-1 /2" HES TNT PKR p = 3.856" 8666' 8614' 4-112" NCS FRAC PORT, D = 3.958" 4-1 /2" HFA X NP, D = 3.813" ST MD ND DEV TYPE VLV LATCH PORT DATE D-16 RWO 12/12/16 JUJMD PROPOSAL REV 5 4 3432 SIDETRACK (Ill 01/23/17 JT PROPOSAL REV 6 WP11 12/16/15 JTP/JMD BUILT PROPOSED 05/09/16 JT/JMD PROPOSAL REV 1 3 6195 05/09/16 JT/JMD PROPOSAL REV 2 2 7193 1 8114 8240' -14 1/2" HES SSD DURASLEEV E w nc NP, D = 3.813" 8258' 4-1/2' SGM-NDPG-CA SINGLE DROP SAPPHIRE GAUGE, D = 3.864" 8324' 7-5/8" X 4-1/2" HES TNT R llD = 3.856" 8330' 4-112" NCS FRAC FORT, D = 3.958" 8367' 4-1/2" HES X NIP, D = 3.813" 8370' H4-1/2" NCS SCREEN SLEEVE, D= 3.958" 8398• 7-5/8" X 4-1/2" HES TNT Ill D = 3.856" 8403' 4-112" NCS FRAC PORT, D = 3.958" 8420' 4-1/2" HES X NP, D = 3.813" 8436' H4-1/2" NCS SCREEN SLEE=VE, ll 3.958- 8464' 1-� 7-5/8" X 4-1/2" HES TNT R(R, D = 3.856" 8470' 1-14-1/2" NCS FRAC PORT, D = 3.958" 8619' 14-1/2" HES X T, p = 3.813" 8632' 4-1/2" NCS SCREEN Sll D = 3.958- 8660. .958" 866-�� 7-5/8' X 4-1 /2" HES TNT PKR p = 3.856" 8666' 8614' 4-112" NCS FRAC PORT, D = 3.958" 4-1 /2" HFA X NP, D = 3.813" 8638' 4-1/2" NCS SCREEN SLEE D = 3.958" 8666' :3.856" 8671' 4-1/2" NCS FRAC PORT, D = 3-958- 8730' .958" 873 112" HES X NP, D = 3.813" 8766' 4-1/2- NCS SCREEN SLEEVE. D= 3.958" 8784' 1-17-5/8" X 4-1/2" HES TNT PKR, D = 3.856" 8846'4-1 /2" HESX NP, D= 3.813" $$7¢' 4-1/2" HES XN NIP, ID = 3.725" 8891'4112" WLEG, ID = 3.958" DATE REV BY COMMENT'S DATE I REV BY COMMENTS 02/22/04 N9ES ORIGINAL COMPLETION 12/12/16 JT/JMD PROPOSAL REV 3 11/25/09 D-16 RWO 12/12/16 JUJMD PROPOSAL REV 5 _I_I_ SIDETRACK (Ill 01/23/17 JT PROPOSAL REV 6 WP11 12/16/15 JTP/JMD BUILT PROPOSED 05/09/16 JT/JMD PROPOSAL REV 1 05/09/16 JT/JMD PROPOSAL REV 2 ORION UNIT WELL- Ill PERMIT No: API No: 504)29-23191-0_ SEC 34, T12N, RI 1E, 256T FSL & 1575' FEL BP Exploration (Alaska) m L 0 a C. U J G1 a Rt � L r � � Q 3 /1 a � m QN C L 0 pCD N J �a p t J C C a N y m ■ `W; N fh O O O C7 O O c1 O N N O a O N m O � Cl) a � � U 2 O a U X X C w CL 3 7 3 Y � U O O 07 N N N Z> °'rn ¢ .V o U o — o > d a� J a0 a0 E R' (n cm W J N N 3 C .N U 'O N Oc J J H W 0) N d Y QI 7 c C O y J J U 01 > 7 O ui ° .FM 0J t J J Ci L w d � LI R' c F O y C c ii cu Q m d w a m ❑ N N N � o .� m o U C d m m U❑❑ t! m w T o 0 o m Cl)CO N O O 0 - o U .... V T > J F ri Z U) ❑ N 0 N V! 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N O O O O O O O O zO O 04 O V V V M M M M U Q tm y U p J o orrn O in a D- oo -� m 3 O Y u7 N N O O m W (D m m W (D Q W N N M lo ( `l mN O r m m m r� ul W M N W r" O aa'1 U N OD M m W N r- W ry v E N tT W M m a T m O O Cl) O J O O E m o -C` M M M M M Cl) M O O U1 N N W co W W W m W OVD M OD Ooo N N O c p N In In LI'l Ln m In N N N ll'l J J H� W W` O n U"i mO N W M (n co m n W W Lo N W � W N m m M O Mo m N M c O N EN v W W m f� N W W wm fU co OD m m L H W o OW O O O O O O y 0 7 m m m m m rn m m CD m m U 2 (n (n (O (n (n (n Ln (n 16 16 (n d O to ti v m O O U 4i c N a N C W V m W (O r W M O 4 c w A N N d c c O V In M O M W o w d M W (O O U7 W m W N O O E E O` N .� M M V V W m m N V N t` V y T m M D)v m U n r- r- r- r, r- � co m W W m a L W a c c E J 2to 3 u E E -' W 2 c c m a+ + c o o rn a c m c + e Q. C U U c d' c a' a m m - m -D + .6 i + W W V W M r m T U O O -6 O❑ >❑> '0 m r- W m W M (ND N N m V W V W V N M O M V o C7 C7 m C7 � m coo m NW W m rn rn o m N iL N S_-' c- r N N N N N Q Q `• Q U U U !n rn to M O M O W D t- O N O vi m ro Lri v ci (ri Di ai m ri (l) m U U M M V (O W N N m W m M N E FL FLof � M M M M M V V V V V N N Z U U❑ m +❑ + (n r N N N N N N N N N N N a O ❑ ❑ ❑ OO N N W (O N O CO m m In r- r, M O V r-, W r o N O V N O m N (n m N m M M V NOD V V V V V (n (N u7 N ID!'I W N N N N N N N N N N N F 7 (� (n O O O O O N W V c Q Q Q Q Q Q Q Q N NM W W CO W W W W V 0 0 0 0 0 0 0 0 0 (D o W vN O 0 0 0 0 o 0 0 L N N m N N N N N N N N M 0 a a a a a s a s m o m 3 3 3 3 3 3 3 3 N N �,m Q Q Q Q Q Q Q Q a M d -D o o o o 0 o o o o o o o o o o 0 0 (n N T N N N N N N N N N m m m (O lO O M r o N O en (D J J J J J J J J 47 (n O D O W W O W to Cl) Q y N o 0 o 0 0 0 0 O o N N V dD ai CD o CO pp V O O O O O O O V W W W O W W W W W W W W m M O o O O O O m m O U T r m 0 0 0 0 W O W W (p O N md E -0 3 F Q o mQ Q O O LL LL O? m N N NE O O Z d a J J J 2N N O 0 0 o o 0 0 V L R O v v o o O o 0 0 0 (n o 0 o a o o (n r� o W o O Q G W M o 0 a 0 0 0 o V O O O y 0 o r- y 0 W O o m 0 0 0 0 N 0 o T M O W O oQ o J O M O O co a M V V m m u7 O O N m O N M D O O O D O W O O N C7 (h C') M M W M T M V V V N W (D � c p w C')a (o a of y m y M (+i M r- I- W m M M M (h o a _ ell m ` c T LL 3 a _ F Y (n to N N r. ♦ Z E m a Po o w N C c)if m3:3o rn a N . 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N m N N N In N Ln Ln Ln Ln N F W V M N m m N m m n M O) mm n O W m m n N to m O m N nM O Ln M n m V N N (p OD m m (0 � V O m N Ln n m M N (Vn m m Ln V O d Ln n O M Ln n O O m m W m m oo m 1n m N V n n N O m � m M L C d C ((O n m b) O N N (o V N oN uD m M m N n O m m m Ln Q) Ln V Z O O O O m O w d t+ m Ln m m m (D m m m m m m m m rn m m m m m m m m m m m m m N N w L Z _, Ln Ln Ln N In In Ln Ln Lf) Ln Ln m(3 Ln o m(3 Ln N m Ln m Ln m Ln m Ln m Ln rn Lm m Ln rn Ln m N d O i° u io L d O `Q m co M m N O) n V M m N V n O L N CN'l •-- n N N M m m u7 r V Ln r n V m04 n O m OD N O w d d (,1 d V m M m n m N m m mf, n V m O m V V m M O m m Ln O m n m N6 M N (� d T 1c0 m m m m m mm m m m m n n V n N n O n O n N m m VV) LMn V >> J F 2 N O W O CL N T O tT m N O M m N Ln m n o m m M M m mN O m m V m m L7) m m m M V m r (D Ln V m Cl) r M M N m m O � O n r O m Ln n N m m M m V m M V N m n m m m O W m W Ol W m O m m N m N M V M N V O Ln m N m m n -D N N N N N N N N N N N M M M Cl) M (") m M c M M M M Ma W c Z IL a� m O N N N V V m m V t2 OV O V O O LJ] N m Ln Ln O O n N n N O n N m d 0 n n O V V � m m Ln V .- m n V N O n m O N m O O O) M O n O O 7 m O O N N �T m Ln m m m n Ln n m n m n m N m m m O m Cl) W V m m m m m M m m W N ( N N m N N N N N N N N N N N N N N N D7 N W N O M O Cl) O (h o co — M — N � N I •- •' n N n V M Ln M N O N to O a, V N O O M V Ln O O M In N N O N O n O C14 � Ln N nM m O V n r Ln m Onp V M N m m M W m N D) M m Ln O M m T O m N N N Ln M m m n n n m m m m W D7 LA W O O O O O Ln m O N N N N N N N N N N N N M M M m M r) 07 (h (•1 N (h N M >0 F O N m O) m n N Ln O M m O M Ln n OR '- Ln m m O Ln V M O) O O O O O O O O O O O O n co O n V m n Ln V m Ln V V O V O V O V O V O V O V O V O V Cl)M M M V M V M V M V M V M M M M M MM M Cl) M M M M M M M M M Cl) M M M Cl) M M N ° m N a � g N co m Ln N m M o m o m m m m O m .- m Ln o O o m o n 0 0 0 0 0 o o o Q m m m m m m m m m m m m m m m m O) m O) m W m O n O n O m 4 n O n O n O n O n O O O O O c > (0 N n p H p n n n n n n n n n d m d C N E d o 3 m tI M 0 o a L o U J O O O O O m N N N o t Z O O O O O O O O O O O O V O O M O OO O O O O O O m G O p O O O O O N O O O T d O0 O 0 O o m O V' O O O 0 0 O O 0 O 0 O O O O O O M O O O O O 0 n M O O O O N O M O V O Ln n Ln O m n m Q O n O m O 07 O O m0 �I O O O O m O O O nj O N V V V V V V V V V V V V m Ln Ln r Ln N Ln M to V to V Ln m Ln Ln m Ln n Ln / a (n N LL O t a y a m d c n ff o c)ai��3o a N N tum O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O Lor- m � V n O M m m N T T N m T N m m N tO n N M c M R G N O LO T m T m LO r r LO m n LO m Ln M O mm N m n m m N M N O m m t7l T T D7 lA T O) T m T O O O O O O O O O O O O 0 0 o O o 0 o O O O O o m m co m o m o m m of m o m m O o o O O o O o O O O O O o O o O O O o O 0 N T O O O o O O 0 0 O O 0 O m T m m V M m T 0 o m T T V m n n O n cmD N m m M M M M co N N N N j J O N N m m Ln N m m m N m In m Ln m Ln m m m Lo m Ln m m N Ln 0 O M llt V V N Ln Ln T n M m M n cm'1 m V LO V' N V N m n LO T M m m m m n V m >0 �, M M V m N n m O N T m OR n Ln m N N T R m N V m V V r T n V N O n M = n LO n 47 M u] T V V O V m M N M m N M N N N it: jA H Lh m a) m co m mm m m M m m m (7 m M m m m M m LQ 7 W In In In to Ln Ln lf) In In N ll') M m LO N m 7 O m T n M N NN N m N T O m M N n m O M T n co (� O LO M m a n r- Nm M O In T M m N V C N N M M V N M � m Gi W L N N N N N N N N N N N t N O m T m m m T m m m m m m m T m T m m m m m m Z u) N Ln LL) Ln Ln N Ln Ln Ln In O — M m m 7 m m N m m m Ln n V O m N T O m T m m LO V N� T V d' O V m M N M m N N N N n m W � a Oo N n m V N T n N m g M m m M W m m N n N �Y O n M T M T O O .- m n N N M V LO m m O O O T O Q O n O n O n O n O n O n Z; O n O n O n O n O n O n m m T m m m m m m m M M O O m M M V m � M m m N w m T m V n M M Lor- m � V n O M m m N T T N m T N m m N tO n N M c M R G N O LO T m T m LO r r LO m n LO m Ln M O mm N m n m m N M N O m m t7l T T D7 lA T O) T m T O O O O O O O O O O O O 0 0 o O o 0 o O O O O o m m co m o m o m m of m o m m m O m M M N V M Ln N N N m O n LO T m N T m T M n n n V m m T LO m V V n m N o O m T m m V M m T 0 o m T T V m n n O n cmD N m m M M M M co N N N N N N N m m Ln N m m m N m In m Ln m Ln m m m Lo m Ln m m N Ln M M llt V V N Ln Ln T n M m M n cm'1 m V LO V' N V N m n LO T M m m m m n V m >0 �, M Cl) m n V O m M m T O m O co N N T N m M N V m V N N Ln N M M M M M M M M c M M m m T T m T m m m m CO m m T m m m T m m m m T T O O In O T m r N n L(j <M') T N V M N m (0 t IT Cl) M (m0 n V M V V M M V n m M m W n W T T Ln N M m NN N .- m t7 N M O n co (� O r) n C? a v LNn M O Ln — V m N T O n m n T m m m n M Ln T m O N ID m In n co m LO O N O n (7 T n T Ln M O n V O m m r m h m T O O N N N M v V v v It o n n n Ln m m M Cl) ON_ O n M T N O m T n0 O N m Ln th O O N m It m .; m N m V N o m N M m m M m O M n m r V LO Ln Ln N fD m n n r m M M M M M th M M M M M M m 0 N m M Ln o M V m M Ln m Ln M m m m V n m n m M m T m n Ln O n N o N M m m V m O N m M N O M T M m N n Ln O T M N m Ln T m N N 0 N m m m m N N O M n In N T n N N m m T M n m O N N M M M llt V V N Ln Ln N m m m m n n n m m m T >0 �, M Cl) M M M M M M co M M M M M M M Cl) M M M Cl) M M O O O O O O O O O O O O O O O OOM O O O In O T m r N n L(j <M') T n V m N t IT Cl) M Iq M V M V M V M v M V 7 M V M V M N M m N m N Ln N N N m m N .- O M O O O M M M M M Cl) M M M M M M M M M M M M M M M M M E N ° Ln Ln N � a g O O n O n O n O n O n o n O n O n O n O n V u) O m T M n m V Ln N O O m T O O O T O Q O n O n O n O n O n O n O n O n O n O n O n O n O n m m T m m m m m m m T m w m m m m m T m U > U O N N N m O. 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O O O O O O O 12 W f� o O O O O O O O o O O (O M N rl r- m � M m m m M 0 (0 0 `.alz r- 0 0 0 0 0 0 0 0 o ry - .- r O O 0 m 0 a 0 Z3 m miLL° ~ a= o o m In � o o o 0 0 D o o o 0 0 o o 0 0 0 o 0 0 o 0 0 o 0 0 0 0 0 o 0 0 0 015 0 0 0 0 a U ri o 0 0 0 0 0 0 0 o ri (•� ri (•i (.� (.� (,.� o Z O Q pr m U 0 0 m Q o o 0 N N m In Ui N O O N E7 N O V O N N m O O m m (O Q m m m N N m N N N m m r- r m m M f` (`N') m N V (NA m O �` //�� U �/ G m OI m m t m m m m O m m O N M 'r N m 7 (O m m m (O ([) m O O J a a m C N 7 V M M N N o O O O O m ()�j O O E N N 7 m N m N m N m N m N m N m OND m O04 ND mN OND Nm U) N N 7 C Q m � (n 1n m In (1') N to In U] mN �Il OND N OND l0 OND u7 m J J H LU W m m O M m uN7 (`m'1 M V M N uD N (� T N N V O f� f� O N a � C p N � O C m O N m m ( m m m m n m m m f� r m m f� m m to w m r- N m m m m m m m O N m (f) m m ll) O m N M m w sp ,E M M M M M M M M M m m m O O O EI ) t+ N m m m m m m m m m m M m M m M m M m M m co m M m m m m Z m m m m m m m m m m m m m m m m m m C In N ((] N LO In (l7 In LO (!) Y] 1!f In (n N V7 lfl (l) Lr E O R Er r V ES C V d C d C U `yF w m N M O (`�) ' f� m O m Lr)O m M N m V m (D N V M O m In O M 0 Qj O w El :.1 N �! d T m M m N r O r m m N m M m V � N m N M m v m m N m m N O m m O r- O m M D m O y L EI d N O ry J r2 Z fA Q W O CL N O m m m M t` N N V m M m O r -O O V N V (O M T Z m M V m r N O m m w m rl m m m 4) r\ m m m r- to m Om m m O M N m N m n N m r` M M M 7 (n m m m m m m m N a m 0 O O 04 O N M O M O O O 0 m 0 m10 MO mN m m V m m m OND m m INO LO N Go m v (0 o o o N 0 o O 0 m V 0 o � 0 o m C m r- o m m u7 M y_ N m m m m o, >Q phi O m O O V m V O m O N o IA m lfi O N o V N m o Mm N V n n •) - m cr m N m !� m M O m f� m N M N m G m m m m O O O O O _ O N N N N N >Q F 7 M m M m M m M m M m M m M m M m M m M m M Lq m rl M rl m N Nm m O_ r V m N L O N O N O N O N O N O N O N O N O N O V O V O m O O r- O 0 a) O N M M M Mm M M M M M M M M M M O M O M M M E _ N ° CL N Qm Y a Q •-N Q m m m tR m m m m m m m m m m m m m m m m mm 0 m m � m N N m M m m M m m N m n o cc U > E) m a V — O ('J N N a Q L a Q Q O U. 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If N U z Q O mrn O a� a 7 7 T CA 0 N O O � l6 m T 3 Q O O O Q O O N N N C p J J H W L6 U > N CO O_ E N 3 L D Q Q E NN ON O m Z O J J J N T O E ti .. s C O C A E Om Z m a E o «! d m .y Z'rNa't .am330 LL 0 0 L J N E m z M U O YI NI L N m 2 U 3 3 'O 1 Cl) C'4 /0 N V 0 0:) W>> z LL O O O=) U) =) U) 0 0 0 z z z>> z In LO In N In N 0 U) In u7 In N N In N In L!] In N NN N In m 0 O O OP O O O O O O O O O O O O O O O O O O O O O jp L L- m O m O � m M to m L- M W m m m O Ol M M r m V N U m O m N M 49 M m N N to N n m V m .-- O N V m O m O r N M V N m W N m M u7 m m m N d 0 7 V V N M M V V M V V V M N M N Cl) V V -,rV M N O m m m m N 1(J m N M O r O O O m M O -a V V V O N M l0 O V V m V m M N V V V V m m V t0 O I- ` M u2 I2 r -, M m m M m M V m V O V m m N V N V O M m Of� V N C H m LO O m O N m L,m LO m P, V O tf] m O N M M m m V 0= m m V N m m m L m m m r, M V M m m m m m m V m 0 N m 00 m 0 0 O U ei C O W t w d C y O C C 9 V d o w y u ` A :' 01 U (D w T m N L d L u C Z m >>0 J F z fn O O Q N T N a "' 133 a d in L6 U > N CO O_ E N 3 L D Q Q E NN ON O m Z O J J J N T O E ti .. s C O C A E Om Z m a E o «! d m .y Z'rNa't .am330 LL 0 0 L J N E m z M U O YI NI L N m 2 U 3 3 'O 1 Cl) C'4 /0 N V 0 0:) W>> z LL O O O=) U) =) U) 0 0 0 z z z>> z In LO In N In N 0 U) In u7 In N N In N In L!] In N NN N In m 0 O O OP O O O O O O O O O O O O O O O O O O O O O jp L L- m O m O � m M to m L- M W m m m O Ol M M r m V N U m O m N M 49 M m N N to N n m V m .-- O N V m O m O r N M V N m W N m M u7 m m m N d 0 7 V V N M M V V M V V V M N M N Cl) V V -,rV M N O m m m m N 1(J m N M O r O O O m M O -a V V V O N M l0 O V V m V m M N V V V V m m V t0 O I- ` M u2 I2 r -, M m m M m M V m V O V m m N V N V O M m Of� V N C H m LO O m O N m L,m LO m P, V O tf] m O N M M m m V 0= m m V N m m m L m m m r, M V M m m m m m m V m 0 N m 00 m 0 0 O U H m W Luz`19 a W � m ci a= 0 0 co m co Q U Z O Q U m m O a OO N m O (D 3 Q m m p U Y J a0 E j N N 7 C_ Q J i I W ui U L C 0 d L w d d � � C d o V U d d a C a d ` (id Wm o w 0 d d U d � y T d a L 0 u O r Z s O J > F 2 M 0 O Q N � o �o a O ooNol°' C T O 1Il W � LA W N m (D O l9 0U O 0 - H� o LL 0 0 d o o F v a 0 o L O O L O o O 0 L 0 0 O L 0 L V M M M O O m OBD m E N O O o C U H d 0 Y r r r m .0 9 U) (n Un r (0 Uo r f0 Un r N co r r W YO in (n r 9 U) N 0 H p� W O mM O M (D m N W W W L0 CO m m (l M N O W O W V N V W O N W � fP- N W 7 N + A C T O O m ID W W O m N LD d 0) O m V W N m V m W N m r -1 f/i W W w -C M (( M N N Cl Z' r M V Ln LD to (D W + IL O] LO _ W M m N 01 O V W Ln Ll� W M V m W N V O Ln O m O (� O1 L d V N N m W m N (D W CO QJ a VI 7 V' V V Ln O (n T O N W tD Q a)�, N N N N N CO M M V V V V N U T - (0 _ d co CL tD O O O N m m 0 Q dO a Q Q V L M O O O O Il W (D W O W O W W O LD V N L6 V m V m L L O O O -? m O M O M M N m M W p D� N N N 01 W N M V V V (D O W (D Ln N M Z O M M M M M N (D (, W co m m C d C d pQd C N �� d y L) a rn 3 3 0 a N (*'!& by 101ir North America - ALASKA - BP Prudhoe Bay PB L Pad L-200 L -200A L -200A wp11 Anticollision Summary Report 20 January, 2017 MCA' &0"-- a BAKER HUGHES BP rias ' by Anticollision Report BAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: O.00usft Reference Well: L-200 Well Error: O.00usft Reference Wellbore L -200A Reference Design: L-200Awp11 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well L-200 L -200A @ 96.05usft (rigx) L -200A @ 96.05usft (rigx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference L -200A wp11 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 3,300.00 to 9,389.41 usft Scan Method: Trav, Cylinder North Results Limited by: Maximum center -center distance of 1,134.24usft Error Surface: Elliptical Conic Survey Tool Program Date 1/20/2017 From To (usft) (usft) Survey (Wellbore) 118.45 3,393.45 Gyrodata Gyro (L-200) 3,393.45 3,400.00 L -200A wpl1 (L -200A) 3,400.00 3,900.00 L-200Awp11 (L -200A) 3,400.00 3,900.00 L -200A wpl1 (L -200A) 3,900.00 5,200.00 L-200Awp11 (L -200A) 3,900.00 8,550.00 L -200A wpl1 (L -200A) 8,550.00 9,000.00 L -200A wpl1 (L -200A) 9,000.00 9,389.00 L -200A wpl1 (L -200A) 9,000.00 9,389.41 L -200A wp11 (L -200A) Tool Name Description GYD-CT-CMS Gyrodata cont.casing m/s GYD-CT-CMS Gyrodata cont.casing m/s BLIND Blind drilling GYD-BM-MS Gyrodata - bat/mem drop m/s MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal BLIND Blind drilling MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 1/20/2017 12.48.28PM Page 2 of 5 COMPASS 5000.1 Build 61B I BP I by Anticollision Report Company: North America - ALASKA - BP Local Co-ordinate Reference: Well L-200 Project: Prudhoe Bay ND Reference: L -200A @ 96.05usft (rigx) Reference Site: PB L Pad MD Reference: L -200A @ 96.05usft (rigx) Site Error: 0.00usft North Reference: True Reference Well: L-200 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 1.00 sigma Reference Wellbore L -200A Database: EDM R5K - Alaska PROD - ANCP1 Reference Design: L -200A wpl1 Offset ND Reference: Offset Datum Fel us6 BAKER HUGHES 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 9 (usft) (usft) (usft) (usft) PB L Pad L-01 - L-01 - L-01 Out of range L-01 - L-01 A - L -01A Out of range L-01 - L-01 A - Plan #8b L -01A Out of range L-02 - L-02 - L-02 Out of range L-02 - L -02A - L -02A Out of range L-02 - L-02APB1 - L-02APB1 Out of range L-02 - L -02B - L -02B Out of range L-02 - L-02PB1 - L-02PB1 Out of range L-03 - L-03 - L-03 Out of range L-03 - L-03APB1 - L -03A wp08A Out of range L-03 - L-03APB1 - L-03APB1 Out of range L-04 - L-04 - L-04 Out of range L-101 - L-101 - L-101 Out of range L-103 - L-103 - L-103 Out of range L-104 - L-104 - L-104 Out of range L-105 - L-105 - L-105 Out of range L-106 - L-106 - L-106 Out of range L-112 - L-112 - L-112 Out of range L-115 - L-115 - L-115 Out of range L-115 - L-11 5A - L -115A Plan #1 Out of range L-116 - L-116 - L-116 Out of range L-117 - L-117 - L-117 3,301.57 3,625.00 935.20 92.92 852.25 Pass - Major Risk L-118 - L-118 - L-118 3,303.56 3,450.00 407.90 89.53 349.18 Pass - Major Risk L-118 - L-1181-1 - L-1181-1 WP03 3,303.56 3,450.00 407.90 89.55 349.39 Pass - Major Risk L-119 - L-119 - L-119 3,308.98 3,600.00 909.96 89.93 835.63 Pass - Major Risk L-120 - L-120 - L-120 Out of range L-122 - L-122 - L-122 Out of range L-122 - L-1 22A - L-1 22A Plan #2 Out of range L-123 - L-123 - L-123 Out of range L-123 - L-123PB1 - L-123PB1 Out of range L-124 - L-124 - L-124 Out of range L-124 - L-124PB1 - L-124PB1 Out of range L-124 - L-124PB2 - L-124PB2 Out of range L-200 - L-200 - L-200 3,713.44 3,700.00 42.27 0.00 42.27 Pass - NOERRORS L-200 - L -200A - L -200A Out of range L-200 - L -200A- L -200A wp06 9,389.41 9,096.40 0.00 0.35 0.00 Pass - NOERRORS L-200 - L-20OLl - L-20OLl 8,759.67 9,450.00 40.26 2.41 40.26 Pass - NOERRORS L-200 - L-2001-2 - L-2001-2 8,661.51 9,350.00 31.00 2.39 31.00 Pass - NOERRORS L-201 - L-201 - L-201 3,303.93 3,300.00 394.29 90.15 338.78 Pass - Major Risk L-201 - L-201 L1 - L-201 L1 3,303.93 3,300.00 394.29 90.28 338.65 Pass - Major Risk L-201 - L-201 L1 PB1 - L-201 L1 PBI 3,303.93 3,300.00 394.29 90.28 338.65 Pass - Major Risk L-201 - L-201 L2 - L-201 L2 3,303.93 3,300.00 394.29 90.28 338.65 Pass - Major Risk L-201 - L-201 L3 - L-201 L3 3,303.93 3,300.00 394.29 90.15 338.78 Pass - Major Risk L-201 - L-201 L3PB1 - L-201 L3PB1 3,303.93 3,300.00 394.29 90.28 338.65 Pass - Major Risk L-201 - L-201 PB1 - L-201 PB1 3,303.93 3,300.00 394.29 90.28 338.65 Pass - Major Risk L-201 - L-201 PB2 - L-201 PB2 3,303.93 3,300.00 394.29 90.28 338.65 Pass - Major Risk L-202 - L-202 - L-202 3,309.11 3,525.00 532.44 91.34 462.65 Pass - Major Risk L-202 - L-2021-1 - L -202L1 3,309.11 3,525.00 532.44 91.34 462.65 Pass - Major Risk L-202 - L -202L2 - L-2021-2 3,309.11 3,525.00 532.44 91.34 462.65 Pass - Major Risk L-202 - L-2021-3 - L-20213 3,309.11 3,525.00 532.44 91.34 462.65 Pass - Major Risk L-203 - L-203 - L-203 3,302.09 3,600.00 589.03 93.01 508.64 Pass - Major Risk L-203 - L -203L1 - L-2031-1 3,302.09 3,600.00 589.03 93.01 508.64 Pass - Major Risk L-203 - L-2031-2 - L-2031-2 3,302.09 11 00.00 589.03 93.01 508.64 Pass - Major Risk 112012017 12:48:28PM Page 3 of 5 COMPASS 5000.1 Build 81B BP HAM Z� p Anticollision Report BAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.00usft Reference Wellbore L -200A Reference Design: L -200A wp11 Summary Site Name Offset Well - Wellbore - Design PB L Pad L-203 - L-2031-2-01 - L-2031-2-01 L-203 - L-2031_3 - L -203L3 L-203 - L-203L3PB1 - L-203L3PB1 L-203 - L-203L3PB2 - L-203L3PB2 L-203 - L-2031_4 - L-2031_4 L-204 - L-204 - L-204 L-204 - L-2041_1 - L-2041_1 L-204 - L-2041_2 - L-2041_2 L-204 - L-2041_3 - L-2041_3 L-204 - L-2041_4 - L-2041_4 L-210 - L-210 - L-210 L-210 - L-210PB1 - L -210P61 L-211 - L-211 - L-211 L-211 - L-211 P61 - L-211 PB1 L-212 - L-212 - L-212 L-212 - L-212PB2 - L-212PB2 L-215 - L-215 - L-215 L-215 - L-215PB1 - L-215PB1 L-215 - L-215PB2 - L-215PB2 L-216 - L-216 - L-216 L-217 - L-217 - L-217 L-218 - L-218 - L-218 L-219 - L-219 - L-219 L-222 - L-222 - L-222 L-223 - L-223 - L-223 L-250 - L-250 - L-250 L-250 - L -250L1 - L -250L1 L-250 - L-2501_2 - L-2501_2 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Reference Measured Depth (usft) 3,302.09 3,302.09 3,302.09 3,302.09 3,302.09 Offset Measured Depth (usft) 3,600.00 3,600.00 3,600.00 3,600.00 3,600.00 Centre to Centre Distance (usft) 589.03 589.03 589.03 589.03 589.03 6,923.81 3,350.00 6,575.00 3,303.18 155.41 7,280.39 3,303.18 6,775.00 638.51 540.71 3,319.43 638.51 3,400.00 508.64 844.89 3,308.85 508.63 3,400.00 93.02 873.08 3,319.43 93.02 3,400.00 Pass - Major Risk 844.89 3,320.14 Pass - Major Risk 3,275.00 189.24 4,411.18 4,525.00 208.78 3,302.98 3,350.00 216.10 3,303.18 3,450.00 638.51 3,303.18 3,450.00 638.51 3,303.18 3,450.00 638.51 Well L-200 L -200A @ 96.05usft (rigx) L -200A @ 96.05usft (rigx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum No -Go Allowable Distance Deviation Warning (usft) from Plan (usft) 93.01 508.64 Pass - Major Risk 93.02 508.63 Pass - Major Risk 93.02 508.63 Pass - Major Risk 93.02 508.63 Pass - Major Risk 93.02 508.63 Pass - Major Risk Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range 139.35 58.77 Pass - Major Risk 149.61 439.57 Pass - Major Risk 91.46 754.12 Pass - Major Risk 93.34 780.64 Pass - Major Risk 91.46 754.12 Pass - Major Risk 90.74 99.55 Pass - Major Risk 105.51 142.52 Pass - Major Risk Out of range Out of range Out of range 97.93 142.69 Pass - Major Risk 91.75 554.00 Pass - Major Risk 91.62 554.13 Pass - Major Risk 91.75 554.00 Pass - Major Risk 1/20/2017 12:48:28PM Page 4 of 5 COMPASS 5000.1 Build 81B 4 BP r/.Ra pAnticollision Report BAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.00usft Reference Wellbore L -200A Reference Design: L-200Awp11 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well L-200 L -200A @ 96.05usft (rigx) L -200A @ 96.05usft (dgx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference Depths are relative to L -200A @ 96.05usft (rigx) Coordinates are relative to: L-200 Offset Depths are relative to Offset Datum Coordinate System is Alaska NAD27 State Plane Zones, NAD27' OGP-Usa AK Central Meridian is 150° 0'0.000 W ° Grid Convergence at Surface is: 0.64° Ladder Plot 1200 _J--- +- ---- � --- I I I I I I 900- � 00 C) 0 O I I C _ _. �_ - - -- --- J- �- -I- I J Q I .ill I Ca/) 600 --- -_- I I I a) U- - - - - - - - - - __J - a) 300 L-212, L-212, L-212 V11 -12 , L 124PB2, - B2 -217; 17,L -217V5 (V U L-212,L-212PB1, L-212PB1 V9 L -2L-200, L-200 V7 219, 19, L-219 V10 _ L-212,)--212PB2, L-212PB2 V2 -L- 0, L -200A, L -200A VO L 211 - 1, L-221 V5 L-01,4-01,1--01 V14 L-200„L-200L1,L-20OLl V3 -I - .. - 2 23,L-223 VO - L-01, L-01 A, L-01 A VO L-200, L -200L2, L -200L2 V6 2 -250, L-2 $O V4 L-01,L-01A,Plan #8bL-01AVO - L -201,L -201,L-201 V6 L -2501-1, L+2501-1 0 - L-02,L-02A,L-b5 5 L-201,1--201 1-1 201L1P61 V10 L -250,E -250P PBI V4 4 X666 8dou � 12000 -r�- L-02,1--02APB1, L-02APB1 V2 $ Wela U2re 01 L 211-50 USWin) � L -200,1--200A, L -200A wp06 V0 -$- L-02, L-02 B, L-02 B VO -- L-201, L-201 L3, L- 01 L13LVU211 $ L-101, L-101, L-101 V4 $ L-03, L-03, L-03 V5 - L-201, L-201 PB1, L-201 PB1 V12 $ L-105, L-105, L-105 V4 -�- L-03, L -03A, L -03A VO $ L-201, L-201 PB2, L-201 PB2 V3 L-106, L-106, L-106 V14 �f L-03,L-03APB1,L-03AwpO8AVO -f L-202, L-202, L-202 V6 - L -110,L -110,L -110V11 $ L-03,L-03APB1,L-03APB1 VO $ L-202, L-2021-1, L -202L1 V8 $ L -116,L -116,L -116V10 -+- L-04, L-04, L-04 V5 $ L-202, L-2021-2, L-2021-2 V7 L-204, L-204, L-204 V8 $ L-103, L-103, L-103 V23 L-202, L-2021-3, L-2021-3 V8- L-204, L-2041-1, L-2041-1 V5 $ L-107, L-107, L-107 V14 $ L-203, L-203, L-203 VO L-204, L-2041-2, L-2041-2 V7 - L-108, L-108, L-108 V18 $ L-203, L -203L1, L -203L1 VO $ L-204, L-2041-3, L-2041-3 V5 $ L-109, L-109, L-109 V12 $ L-203, L-2031-2, L-2031-2 VO L-204, L-20414, L-2041-4 V5 1/20/2017 12:48:28PM Page 5 of 5 COMPASS 5000.1 Build 81B (u!/13sn 00£) 9adaQ leaivan ani L _ R N Q 2, O I 'E s a� — p a z p J g3 Zed (u!/13sn 00£) 9adaQ leaivan ani L _ R 9} - �100t -OZ I a� — p a J d1JJ� gt�o �ai9ioo �o .. �N3og Qua �i c9j is 4'��jo foo e� o�� a�� agaaa ag a` 3r J - J o00Z20 0�0 —I _ I 000, F � _ Dass m�2 6 Zrmi�?rn�t^M�� L t F• I f - �G9 _ I mwmmmg�G`36°i�13 >�a<m 2 R a sma u om I QNc�m�m Sgrnm000 c�c��rgM•t%i� nnt� ��888�8&6�3<ae mmm � (u!/13sn 00£) 9adaQ leaivan ani L _ R 9} - 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Z�3 32 2 2 66 66.16 0 o�mm��mm m m \ / Evv0000000 a �o NOW Leonm sg N9ene�n4�N�� $8�„8$$8858$0 FIS s 4*m� mw nna�� g ; Y� i NR�mg$gsl��S $ 'Fir�sieoinnm MI6 gm @ < wa newon nommemmm � 0 0 o U LL t7 n Y tD r m oI Z n~ m o m SLL N CO 7 LO t � c CDO f0 d U i i o N� U�pm —t r °o > gaaaaaa3"a Z a Q � �a 33333 33 366 5� oons nen mo�o�m my o0 p m JCL � J w 0 o 6 m P � C Q 3F a y/� I y m' N N j 6 `r° N U O — / N J C O 0 L r O i N J J N J C N CO 7 LO t � c CDO f0 d U i i o N� U�pm —t r °o > gaaaaaa3"a Z a Q � �a 33333 33 366 5� oons nen mo�o�m my o0 JCL J � o m � m P � 0 3F a y/� I y N N j ♦o N N CO 7 LO t � c CDO f0 d U i i o N� U�pm —t r °o > gaaaaaa3"a Z a Q � �a 33333 33 366 5� oons nen mo�o�m Obp North America - ALASKA - BP Prudhoe Bay PB L Pad L-200 L -200A L -200A wp11 AOGCC Offset Well Report 20 January, 2017 FMA I R-- 2 BAKER HUGHES V7bn BP lbs 1" Anticollision Report BAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.00usft Reference Wellbore L -200A Reference Design: L-200Awp11 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well L-200 L -200A @ 96.05usft (rigx) L -200A @ 96.05usft (rigx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference L -200A wpl l Filter type: NO GLOBAL FILTER: Using user defined selection & filtering criteria Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 3,300.00 to 16,236.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 200.00usft Error Surface: Elliptical Conic Survey Tool Program Date 1/20/2017 Centre to Measured From To Depth Depth (usft) (usft) Survey (Wellbore) Tool Name Description 118.45 3,393.45 Gyrodata Gyro (L-200) GYD-CT-CMS Gyrodata cont.casing m/s 3,393.45 3,400.00 L-200Awp11 (L -200A) GYD-CT-CMS Gyrodata cont.casing m/s 3,400.00 3,900.00 L-200Awp11 (L -200A) BLIND Blind drilling 3,400.00 3,900.00 L-200Awp11 (L -200A) GYD-BM-MS Gyrodata - battmem drop m/s 3,900.00 5,200.00 L-200Awp11 (L -200A) MWD MWD - Standard 3,900.00 8,550.00 L-200Awp11 (L -200A) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 8,550.00 9,000.00 L-200Awpll (L -200A) BLIND Blind drilling 9,000.00 9,389.00 L-200Awpll (L -200A) MWD MWD - Standard 9,000.00 9,389.41 L-200Awp11 (L -200A) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal Summary Site Name Offset Well - Wellbore - Design PB L Pad L-200 - L-200 - L-200 L-200 - L -200A - L -200A wp06 L-200 - L-200Ll - L-200Ll L-200 - L-2001_2 - L-2001_2 L-212 - L-212 - L-212 L-216 - L-216 - L-216 Reference Offset Centre to Measured Measured Centre Depth Depth Distance (usft) (usft) (usft) 8,972.11 9,650.00 50.70 8,593.01 8,300.00 0.00 8,781.40 9,475.00 40.73 8,682.32 9,375.00 33.47 6,923.81 6,575.00 155.41 3,320.17 3,275.00 189.24 1/20/2017 11:37.45AM Page 2 of 13 COMPASS 5000.1 Build 81B N Wall WCC o Northing (500 usft/in) m= 587500s e s s s s s s s 0 qq�77 `587500 m [L 587250587250 `o N J V 587000 587000 586750 N - -. _� rn ` -� r N a- o. j -586750 _ 586500 - - c� --- - —�- - J.. -586500 O oIg o 586250- - - - __ _. - - . - I(�N -586250 R �a 586000 586000 e EE 585750 - - -- - - j - 385750 2 b 2 O J N r J U2 _zN o� 585500 585500 5 a a o 585250 X 1.19 `m �\ J -585250 � J J 585000 - - - - - �� o -585000 - — M J v� 584750 --584750 584500 - -N - -- - -584500 o J 584250 __ xv ,584250 F- a 7 v❑ 564000 .t�- -- - - -N - - - - \._¢ -\ - 584000 0 $ cJ L ix3 d li 583750 583750 O «F 4 J \ N a583500-. - _ - N -- °' .583500 3 W) J N v N, 583250: - - 583250 F 583000583000 C w, H� W 562750. N - - - - ,. - �.._.____--'' _ J -562750 W O 582500 '� - - � .582500 582250- 582250 582000-- Q - - -- - - - - 582000 Q J o `v 581750. _No N J X71' o 561750 AIV 5815000 N < 581500 a 581250- 581250 tl J e 8 581000 - mo 581000 v a a 580750- - - - - - - -580750 $8 0 c 3 <ea 580500 - _.-. - _ .. _. - - - - - - -580500 580250 J - - i Tr. - - - - -1580250 580000 o J X580000 579750 m - N a - - }579750 c - r a N N 579500 - - cv �- - `� - - ,579500 579250. a; -� N - 579250 J J 6 579000 o c -6579000 0 0 0 0 n N m 8OOP P P .�..i � (u�R3sn OOS) Sm411o�I a d LN m53. Rey g as 0 .4A t Y]IMn70)_ V 91 4 U�a� o> foo at eW -a > : � wW �w5 mun* ,9 12, io e 2- _-_-_---�- it 4 U�a� o> foo : � wW �w5 mun* ,9 TRANSMITTAL LETTER CHECKLIST WELL NAME: /�`�. Z' PTD: 12 - Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: _ POOL: 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 No. , API No. 50- - - - (If last two digits 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, SCHRADER BLUF OIL - 64013 PTD#:2161250 Company BP EXPLORATION (ALASKA) INC. Initial Class/Type _ Well Name: PRUDHOE BAY UN ORIN L -200A 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 Entire Well lies within ADL0028239. 3 Unique well name and number Yes 4 Well located in a defined pool Yes PRUDHOE BAY, SCHRADER BLUFF OIL — 640135, governed by CO 505B 5 Well located proper distance from drilling unit boundary Yes Rule 1: Spacing units shall be a minimum of 10 acres. The Schrader Bluff Oil Pool shall not be opened 6 Well located proper distance from other wells Yes in any well closer than 500' to an external boundary where ownership changes. 7 Sufficient acreage available in drilling unit Yes Well conforms to CO 505B, Rule 1. 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 1/26/2017 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 NA Conductor set in PBU L-200 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in PBU L-200 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons Yes Productive interval will be completed with intermediate casing, cemented and perforated 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved Yes PTD 204-001, Sundry 316-508, PTD 204-002, Sundry 316-507, PTD 204-003, Sundry 316-506 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures except existing L-200 laterals 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is 2300 psig(9.62 ppg EMW); will drill w/ 9.3-10.2 ppg EMW VTL 1/26/2017 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 1840 psig; will test BOPs to 3500 psig 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 H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No L -Pad is an H2S site. H2S measures are required. Geology 36 Data presented on potential overpressure zones Yes Planned mud weight (9.3 — 10.2 ppg) appears adequate to control the operator's forecast of most likely Appr Date 37 Seismic analysis of shallow gas zones NA pore pressures (9.65 ppg) in the operator's geologic prognosis. SFD 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Engineering Public REVISION: Kick-off point and well path changed. L -Pad wells have a history of shallow gas and hydrates in the SV22, SV3, and Commissioner: Date: Com ioner: Date Commissioner Date UG4A intervals. L -Pad wells also have a history of encountering troublesome coals while drilling and tripping through the Ugnu —r 11 Z W&& ` I � formation. Both are discussed in the Drilling Critical Issues section on page 10. SFD THE STATE 1AI.ASKA GOVERNOR BILL WALKER Ken Allen Drilling Supervisor BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-200A BP Exploration (Alaska), Inc. Permit to Drill Number: 216-125 Surface Location: 2568' FSL, 3704' FEL, SEC. 34, T12N, RI IE, UM Bottomhole Location: 3534' FSL, 263' FEL, SEC. 28, T12N, RI IE, UM Dear Mr. Allen: Enclosed is the approved application for permit to re -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 . Foerster Chair DATED this Z5 day of October, 2016. STATE OF ALASKA _ASKA OIL AND GAS CONSERVATION COMMIS PERMIT TO DRILL 20 AAC 25.005 IF T 0 3 2016 la. Type of Work: Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill El ❑ 11b. Stratigraphic Test ❑ Development - Oil 0 • Service - Winj ❑ Single Zone Lf - Coalbed Gas ❑ Gas Hydrates ❑ Redrill 0 • Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond Blanket 0 Single Well ❑ 11 Well Name and Number: BP Exploration (Alaska), Inc Bond No. 29S105380 PBU L-200A 3 Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 196612 Anchorage, AK 99519-6612 MD: 9114' • TVD: 4694' . P/RUDHOE BAY, ORION OIL ( - e- `�<<��r_1.5;4 ''J 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): ADL 028239 S� <4=.4—/ 8. Land Use Permit: 13. Approximate spud date: Surface: 2568' FSL, 3704' FEL, Sec. 34, T12N, RV E, UM Top of Productive Horizon: 3124' FSL, 4998' FEL, Sec. 27, T12N, RI E, UM 00-001 January 10, 2017 9. Acres in Property: 2560 14. Distance to Nearest Property: Total Depth: 3534' FSL, 263' FEL, Sec. 28, T12N, R11E, UM 5400 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 96.05' ' feet 15. Distance to Nearest Well Open to Same Pool: Surface: x- 583209 • y- 5978290 • Zone - ASP 4 GL Elevation above MSL: 49.1 - feet 1675 16. Deviated wells: Kickoff Depth: 3000 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 70 degrees Downhole: 2300 ' Surface: 1840 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casinq Grade Coupling Length MD TVD TVD (includingstage data 9-7/8„ 7-5/8" E297# L-80/ VamTop HC 9114' Surface Surface 9114' 4694' 528 sx Class 'G' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MO (ft): Total Depth TVD (ft): 1 Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 1 13067 4356 7122 7122 4239 None Casing Length Size Cement Volume MD TVD Conductor/Structural 78 20" 260 sx Arctic Set (Aoorox.) 31 - 110 31 - 110 Surface 3840 10-3/4" 723 sx AS Lite, 338 sx Class 'G' 31 - 3871 31 - 2653 Intermediate 7843 7-5/8" 515 sx Class'G' 29 - 7872 29 - 4485 Tieback Liner 266 4-1/2" Uncemented Tieback Liner 7282 - 7548 4302 - 4413 Liner 5515 4-1/2" Uncemented Slotted Liner 7537 - 13052 4409 - 4356 Perforation Depth MD (ft): 7870 - 13008 Perforation Depth TVD (ft): 4484 - 4355 20. Attachments Property Plat ❑ BOP Sketch 0 Drilling Program 0 Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated Contact Thompson, Jacob from without prior written approval. Email Jacob.Thompson@BP.com Printed Name Ken Allen Title Drilling Supervisor Signature ��._. Phone +1 907 564 4366 Date Commission Use Only Permit to Drill �7 / I j Number ! Z API Number: 50- 029-23191-01-00 Permit Approval Date: See cover letter for other `© ^ Z5^ 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 contained in shales: Other: ff 0P � 5t t-p 2� GC Sfl Samples req'd: Yes ❑1 No LN Mud log req'd: Yes El No 1� JGV-eG2 f r' of H2S measures Yes q1J No ❑ Directional svy req'd: Yes E3' No E �95El Spacing exception req'd: Yes No Inclination -only svy req'd: Yes No Post initial injection MIT req'd: Yes ❑ No APPROVED BY I / Approved by'&, O s- t/6 COMMISSIONER THE COMMISSION Date: (/' "" °„"„` ORIGINAL Form 10-401 Revised 11/2015 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Submit Form and Attachments in Duplicate le, .s-/�_ To: Alaska Oil & Gas Conservation Commission From: Jacob Thompson, ODE Date: September 19, 2016 RE: L-200A Permit to Drill The L-200A well is scheduled to be drilled by Parker 272 in January 2017. This well will be sidetracked out of the existing L-200 multi -lateral's 10-3/4" surface casing. The pre -rig work outlined in the sundry will have the well abandoned with a 1,500' cement plug across the tubing and IA. The objective of L-200A is to recover the reserves left over from the L-200 motherbore. The rig will then move over the well and pull the 4-1/2" tubing and cut the 7-5/8" casing at—3,100' MD. A clean out run will then be performed, followed by the setting of an EZSV bridge plug in preparation of the whipstock exit at—3,000' MD. The objective of the L-200A sidetrack is to drill a slant well near three L-200 laterals, and hydraulically fracture into them to recover their reserves. The well will be sidetracked out of the existing 10-3/4" surface casing, and a 9-7/8" production hole will be drilled down into the OBf formation. A string of 7-5/8" casing will be run into the well, and cemented to—1,000' above the SB_Na formation. The well will be perforated and a 4-1/2" multi -zone frac pack completion will be run. The maximum anticipated surface pressure from the Schrader Bluff with a full column of gas from TD to surface is 1,840 psi (assumes 9.62 ppg EMW most likely pore pressure and a 0.1 psi/ft gas gradient). The well will be drilled by Parker 272 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. If there are any questions concerning information on L-200A, please do not hesitate to use the contact information below. Jacob Thompson Office: (907) 564-5579 Cell: (907) 854-4377 Email: Jacob.thompson@bp.com Attachments: Well Bore Schematic Proposed Pre -Rig Schematic Proposed Completion Directional Package BOPE Schematic 272 L-200A PTD 1 9/19/2016 Planned Well Summary Well L-200A Well Producer Target Schrader Type I L Objective I Bluff Current Status Not Operable Estimated Start Date: 1/10/17 Time to Complete: 19 Days Surface Northin Eastin Offsets TRS Location 5,978,289 583,209 I 2567 FSL / 3705' FEL 12N 11 E Sec 34 Northing Easting TVDss Offsets TRS Window 5,979,800 583,795 -2,130 1208' FNL / 3099' FEL 12N 11E Sec 34 Oba Lateral 5,984,110 581,840 -4,200 2156' FNL / 4998' FEL 12N 11E Sec 27 TD 5,984,514 581,290 -4,597 1745' FNL / 263 FEL 12N 11 E Sec 28 Planned KOP: I 3000' MD Planned TD: 9,114' MD / 4,597' TVDss Rig: Parker 272 GL-RT: 1 46.95 RTE ref MSL : 96.05 Directional - Baker L-200A wp05 KOP: 3000' MD Maximum Hole Angle: -700 Close Approach Wells: None. All offset wells pass BP Anti -collision Scan Criteria. Survey Program: See attached Directional Plan Nearest Property Line: -5,400' Nearest Well within Pool: -1,675' L-200A PTD 2 9/19/2016 Formation Tops and Pore Pressure Estimate (SOR) Estimated Formation Top Pore Pressure Formation (TVDss) (Ppq) Fluid Tvoe (for sands) SV2 2154 8.6 Hydrates SV1 2475 8.6 Hydrates UG4 2783 9 Heav Oil UG4A 2804 9 Heavy Oil Fault_1 2891 9 UG3 3029 9 Heavy Oil / Water UG1 3524 9 Heavy Oil / Water UG_Ma 3795 9 Heavy Oil / Water UG_Mb1 3842 8.76 Heavy Oil / Water UG_Mb2 3901 8.72 Heavy Oil / Water UG_Mc 3957 8.76 Heavy Oil / Water NA 4018 8.7 Water NB 4038 8.65 Water NC 4070 8.73 Water NE 4079 8.73 Water N F 4126 8.73 Water OA 4161 9.65 Viscous Oil / Water Oba 4214 9.62 Viscous Oil Obb 4258 9.62 Viscous Oil Obc 4309 8.7 Viscous Oil Obd 4358 8.71 Viscous Oil Obe 4419 8.61 Viscous Oil OBf 4458 8.59 Viscous Oil OBf base 4525 8.59 Viscous Oil Casing/Tubing Program Hole Size Liner / WVFt Grade Conn Length Top Bottom Tbg O.D. MD / TVDss MD / TVDss 48" 20" x 34" 215.5# A-53 - 114' Surface 114' / 94.9' 13-1/2" 10-3/4" 45.5# L-80 BTC 3,000' Surface 3,000'/2,129' Window 9-7/8" 7-5/8" 29.7# L-80 / 13Cr-80 VamTop HC 8,320' / 794' Surface 9,114' / 4,597' Tubing 4-1/2" 12.6# 13Cr-80 VamTop 8,891' Surface 8,891' / 4,485' Mud Program Intermediate Mud Properties: LSND 9-7/8" Hole Section Depth Interval Density PV (cp) YP Ib/1 w API FL HTHP FL MBT pH KOP - 8,100' MD 9.3 - 9.8 10-15 <25 <8 NA <20 8.5 - 9.5 8,100' MD - 9,114' MD 10.0 - 10.2 10-15 <25 <8 NA <20 8.5 - 9.5 L-200A PTD 3 9/19/2016 Logging Program Interval Surface Intermediate 9-7/8" Production Tie-in MWD/LWD OH Logs CH Logs Coring Sampling N/A N/A N/A N/A N/A USIT log to Sampling GR/RES assess 7- as needed Contingent use of 5/8 NEU/DENS logs cement Potential top. for high GR on perforation GR CCL to frequency assembly log the sampling completion near L-200 on depth. laterals requirements if a N/A sidetrack Cement Program Casing Size 7-6/8" 29.7# L-80 VamTop HC Intermediate Casing Lead N/A Basis Lead TOC N/A Tail Open hole volume + 40% excess + 85 ft shoe track Tail TOC Tar et 1000 ft above the Na sands Spacer -50 bbls of Viscosified Spacer weighted to -12.0 Mud Push II Total Cement Lead N/A Volume Tail 109.2 bbls, 612.77 cuft, 528.25 sks 15.8 lb/gal Class G - 1.16 cuft/sk Temp BHST 87- F Surface and Anti -Collision Issues Surface Close Proximity: No wells will be affected by the Parker 272 rig shadow. Sub -Surface Pressure Management: SV1 / UGNU: Presence of hydrates / heavy oil. No injection / production in these intervals, assume original pressures. Schrader Interval: Check pressure and fluid data from production engineer to confirm pressure prediction and fluid input into PPFG. Collect a SBHP in L-211 4-6 months prior to spud to verify OA, OBA/OBB pressures. Confirm Schrader waterflood mandels are dummied in L-117. Shut in L-212, L-218, and L-211 (all offset injectors) one week prior to drilling and keep shut in until well is completed. Anti -Collision: The original laterals L-200, L-2001-1, and L-2001_2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L-200A well path must be drilled in close proximity to them in order to hydraulically fracturing into them. If an intersection were to occure there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. Offset well ownership information All offset wells identified within 200 ft of the proposed wellbore are operated by BP. Hydrogen Sulfide L-Pad is considered an H2S site. Recent 112S data from the pad is as follows: L-200A PTD 4 10/20/2016 Logging Program Interval Surface Intermediate 9-7/8" Production Tie-in MWD/LWD OH Logs CH Logs Coring Sampling N/A N/A N/A N/A N/A Sampling as needed GR/RES/NEU/DENS GR CCL to log the Potential GR on perforation completion for high assembly on depth. frequency sampling near L-200 laterals requirements if a N/A sidetrack Cement Program Casing Size 7-5/8" 29.7# L-80 VamTop HC Intermediate casing Lead N/A Basis Lead TOC N/A Tail Open hole volume + 40% excess + 85 ft shoe track Tail TOC Target 1000 ft above the Na san Spacer -50 bbls of Viscosified Spacer wei d to -12.0 Mud Push II Total Cement Lead N/A Volume Tail 109.2 bbls, 612.77 cuft, 528 25 k 15.8 lb/gal Class G - 1.16 cuft/sk Temp BHST 87- F v u Surface and Anti -Collision Issues ,�V \� ti Surface Close Proximity: \0\ No wells will be affected by the Parker 272 shadow. • Sub -Surface Pressure Management: r SV1 / UGNU: Presence of hydrates / heavy oil. No injection / production in these intervals, assume original pressures. --- Schrader Interval: Check pressure and fluid data from production engineer to confirm pressure prediction and fluid input into PPFG. Collect a SBHP in L-211 4-6 months prior to spud to verify CA, - OBA/OBB pressures. Confirm Schrader waterflood mandels are dummied in L-117. Shut in L-212, L-218, and L-211 (all offset injectors) one week prior to drilling and keep shut in until well is . completed. Anti -Collision: The original laterals L-200, L-2001-1, and L-2001_2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L-200A well path must be drilled in close proximity to them in order to hydraulically fracturing into them. If an intersection were to occure there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. Offset well ownership information All offset wells identified within 200 ft of the proposed wellbore are operated by BP. Hydrogen,tulfide L-Pad is considered an H2S site. Recent 112S data from the pad is as follows: L-200A PTD 4 9/19/2016 Parent Well (if sidetrack) #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level #3 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Other Relevant H2S Data (H2S alarms from rigs, ets. Well Name H2S Level Readinci Date Comments L-200 18 pprn 3/10/13 L-250 14 ppm 8/7/12 L-202 38 ppm 1/12/15 L-203 20 ppm 7/13/12 L-204 16 ppm 1/4/15 L-205 2 ppm 1 /3/12 L-116 190 ppm ' 3/19/15 Kuparuk Producer L-250 is close on surface and with its BH location. Faults Formation Where Throw Encounter MD TVDss direction and Lost Circ Fault Intersect Intersect Maanitude Uncertainty Potential Ugnu 4A 4992 2891 70' , down to S/SW 250'N/125'S Low NA NA 2891 60, down to E 250'E/275'W Low NA NA 4450 120', down E n to 175'N/300Is NA NA NA 4450 75', down to N 100'N/175'S NA 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. L-200A PTD 5 9/19/2016 Well Control The decomplete and drilling of the 9-7/8" hole section will be done with well control equipment consisting of 5,000 psi working pressure 7-5/8" fixed ram (upper), 2-7/8" x 5" VBR (lower), 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 L-200A will be 7 days during the decomplete phase of the well and 14 days during the drilling phase of the well 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. 9-7/8" Intermediate Interval Maximum anticipated BHP 2,300 psi at TD at 4,597' TVDss (9.62 ppg EMW) Maximum surface pressure 1,840 psi at TD (0.10 psi/ft gas gradient to surface) 25 bbls with 12.1 ppg frac gradient. ✓ Kick tolerance Assumes 10.12 ppg PP (9.62 most likely PP + 0.5 ppg kick intensity) and a 10 ppg MW. Planned BOP test pressure Rams test to 3,500psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test — 12-1/4" hole LOT after drilling 20'-50' of new hole 7-5/8" Casing Test 3,500 psi surface pressure L-200A PTD 6 9/19/2016 Drill and Complete Operations Summary Pre -Rig Prep Work: Pre Rig Plan for L-200A Step Service Operation 1 F LLR TxIA (potential LDL) 2 S Pull GLV Drift run for gyro. 3 E Run Gyro as deep as possible. 4 F I Circ Cement 1500' Plug 5 S D&T TOC. Drift for Jet Cut 6 F CMIT-TxIA to 3,000 psi. 7 E Jet Cut 3500' 8 F Circ out. CMIT-TxIA to 3,000 psi. 9 V Install Dry Hole Tree. Configure TWC. Proposed Drilling Rig Operations: 1. MIRU Parker 272. 2. Test TWC from below to 3,500 psi for 30 minutes. 3. Nipple down tree. Nipple up and test Annular, 7-5/8" Fixed upper rams, blind shear rams, and 2-7/8" x 5" lower rams to 3,500 psi. 4. Pull TWC with lubricator. 5. RU hard lines to BOP. Circulate out diesel freeze protection through choke to tiger tank with clean 8.5 ppg seawater. 6. RU and pull the 4-1/2" tubing from the pre -rig jet cut. 7. MU casing cutter and cut 7-5/8" casing at—3,100' MD. 8. RU and pull 7" casing from cut. 9. RIH with 9-5/8" clean out assembly down to the top of the 7-5/8" casing stub. 10. RU E-line w/ GR/CCL log and set EZSV at—3,000' MD and pressure test to 250 psi for 5 min and 3,500 psi for 30 min. Chart both tests. 11. PU 10-3/4" whipstock, bottom trip anchor and 9-7/8" window milling assembly. RIH to the top of the EZSV. Orient and set the whipstock. 12. Swap the well over to 9.5 ppg fresh water LSND milling fluid. ----------------------------------------End of Sundry: Start of Permit to Drill ---------------------------------- 13. Mill window in the 10-3/4" casing plus 20' of formation. 14. Perform LOT. POH for drilling BHA. ✓H f r, I A,'vm /__�T 15. MU 9-7/8" drilling BHA, GR/RES/PWD, UBHO (Gyro), and RIH. Kick off and drill 9-7/8" intermediate interval. 16. Drill to the end of build section at—3,600' MD. 17. POOH and LID 9-7/8" motor BHA. 18. PU 9-7/8" RSS drilling BHA, GR/RES/PWD/DENS/NEU and RIH. 19. Drill 9-7/8" intermediate interval to section TD at. Weight up drilling fluid using spike fluid maintaining the following density ranges: • KOP — 4,000' TVDss: 9.3 - 9.8 ppg L-200A PTD 7 9/19/2016 • 4,000' TVDss - TD: 10 - 10.2 ppg 20. At TD, CBU until hole is clean (minimum 2x), then perform short trip. 21. RIH to TD and circulate the well clean and POH on elevators. 22. Run and cement 7-5/8", 29.7#, L-80, VAM TOP HC casing to TD. Top of cement will be at 6,959' MD. Bump the plug with 9.9 ppg NaCl brine. (RA tag to be run above the estimated top perforation.) 23. Pressure test the 7-5/8" casing to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes 24. Install the 7-5/8" pack -off through the stack and test to 250 psi low / 5,000 psi high for 30 minutes. 25. Freeze protect the 9-5/8" x 7" annulus, once the tail cement has reached compressive strength. 26. MU pert assembly with MWD GR. 27. RIH and tag the float collar, PU log guns on depth, and fire. 28. POOH lay down guns. 29. R/U E-line run GRJB to drift perfs, Run USIT log to confirm TOC in 7-5/8" Casing. 30. R/U and run a 4-'/2°, 12.6#, 13CR, VT tubing completion with GLM's, 6 production packers 5 NCS frac sleeves, 5 NCS screen sleeves, and SLB Gauge on Iwire. (RA tag to be run in completion.) 31. With completion spaced out RU a -line and log the RA tags to confirm the completion is on depth. 32. Land the tubing hanger, and run in lock down screws. 33. Reverse circulate 9.9 ppg brine and corrosion inhibitor into the tubing x casing annulus. 34. Drop ball/rod, set packer and individually test the tubing and annulus to 3,500 psi for 30 minutes. 35. Hold pressure on the IA and bleed tubing pressure to zero, shearing the DCK shear valve. Pump both ways to confirm circulation ability. 36. Install TWC and test from above to 250 psi low / 3,500 psi high for 5 minutes each and from below to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes high. 37. Nipple down the BOPE. Nipple up the adaptor flange and double master valves and test to 5,000 psi with diesel. 38. Remove TWC. 39. Reverse circulate diesel freeze protect using rig injection pump. 40. Allow diesel to U-tube, drain stack, and rig down landing joint. Monitor well for 1 hour to confirm well is dead. 41. Dry Rod BPV in and install all annulus valves and secure the well. 42. RDMO. Planned Post -Rig Operations: 1. Change out tree. 2. Pull BPV, Pull Ball, Rod and RHC Plug with slickline. 3. Pull shear valve and dummies, change GLVs. 4. RU coil and individually hydraulically fracture each zone thru the NCS sleeves with coil. 5. RU E-line and run a gravel pack log. 6. RU coil, open up screen sleeves, and top off zones requiring more gravel. L-200A PTD 8 10/20/2016 4,000' TVDss - TD: 10 - 10.2 ppg ' 20. At TD, CBU until hole is clean (minimum 2x), then perform short trip. 21. RIH to TD and circulate the well clean and POH on elevators. 22. Run and cement 7-5/8", 29.7#, L-80, VAM TOP HC casing to TD. Top of cement will be at 6,959' MD. Bump the plug with 9.9 ppg NaCl brine. (RA tag to be run above the estimated top perforation.) 23. Pressure test the 7-5/8" casing to 250 psi low / 3,500 psi high for 5 minutes low / 30 minutes 24. Install the 7-5/8" pack -off through the stack and test to 250 psi low / 5,000 psi high for 30 minutes. 25. Freeze protect the 9-5/8" x 7" annulus, once the tail cement has reached compressive strength. 26. MU pert assembly with MWD GR. 27. RIH and tag the float collar, PU log guns on depth, and fire. 28. POOH lay down guns. 29. MU cleanout assembly with full gauge string mill and a used mill tooth bit. 30. RIH and ream across perforations. Tag the landing collar and CBU. 31. R/U and run a 4-1/", 12.6#, 13CR, VT tubing completion with GLM's, 6 production packers 5 NCS frac sleeves, 5 NCS screen sleeves, and SLB G49e on Iwire. (RA tag to be run in completion.) 32. With completion spaced out RU a -line and log heTA tags to confit� the completion is on depth. 33. Land the tubing hanger, and run in lock dow screws. J 34. Reverse circulate 9.9 ppg brine and corroZinhibitor into the tubing x casing annulus. 35. Drop ball/rod, set packer and individuallWst the tubing and annulus to 3,500 psi for 30 minutes. 36. Hold pressure on the IA and bleed to �ing pressure to zero, shearing the DCK shear valve. Pump both ways to confirm circul tign ability. 37. Install TWC and test from abo 250 psi low / 3,500 psi high for 5 minutes each and from below to 250 psi low / 3,500 pigh for 5 minutes low / 30 minutes high. 38. Nipple down the BOPS. Nipple up the adaptor flange and double master valves and test to 5,000 psi with diesel 39. Remove TWC. 40. Reverse circulate diesel freeze protect using rig injection pump. 41. Allow diesel.to U-tube, drain stack, and rig down landing joint. Monitor well for 1 hour to confirm well is dead. 42. Dry Rod,;8PV in and install all annulus valves and secure the well. 43. RDMG.' Planned Post -Rig Operations: 1. hange out tree. i 2. Pull BPV, Pull Ball, Rod and RHC Plug with slickline. 3. Pull shear valve and dummies, change GLVs. 4. RU coil and individually hydraulically fracture each zone thru the NCS sleeves with coil. 5. RU E-line and run a gravel pack log. L-200A PTD 8 9/19/2016 6. RU coil, open up screen sleeves, and top off zones requiring more gravel. 7. Flowback as per ASRC. 8. Install flow lines and well house. L-200A PTD 9 9/19/2016 L-200A Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Production Hole: The Schrader Bluff Oba formation is expected to be at a 9.62 ppg EMW. Reservoir pressures will be controlled by using 10.0 - 10.2 ppg water based mud. . B. Shallow Gas: Wells at L-Pad have had a history of shallow gas and hydrates in the SV2, SV3 and UG4A formations, although L-200 parent bore did not experience any. The importance of the fluid monitoring process will need to be stressed in this interval as well as the review of the RP: Handling Gas Hydrates While Drilling. II. Stuck Pipe/Hole Cleaning A. Hole Cleaning: The planned well path has a difficult hole cleaning environment with a substantial amount of 60' - 70' hole. This increases the probability of encountering hole cleaning problems from cutting build up. The ROP limits, sweep strategy, and ECD limitation outlined in the well program help to prevent and identify problems with hole cleaning. B. Ugnu Coals: L-Pad wells have a history of encountering troublesome coals while drilling and tripping thru the Ugnu formation. This may result in instances of abnormally high and erratic torque or overpulls. Problems thru the Ugnu coals usually reduce with time after they have been allowed to be agitated mechanically. III. Fault Locations Formation Where MD TVDss Throw Direction and Lost Circ Fault Encountered Intersect Intersect Magnitude Uncertainty Potential Fault 1 UG4A 4,492 -2,891 dips S/SW (70 ft) 150& lateral Low - MDft IV. Integrity Testing Test Point Test Depth Testtype EMW (lb/gal) 10-3/4" Window 20'-50' from the middle of the 10-3/4" LOT 12.1 Window ppg V. Hydrogen Sulfide L-Pad is considered an H2S site. Recent H2S data from the pad is as follows: Well Name H2S Level Readina Date Comments Parent Well (if sidetrack) #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Other Relevant H2S Data (H2S alarms from rigs, ets. L-200 18 m 3/10/13 L-250 14 ppm 8/7/12 L-202 38 ppm 1/12/15 L-203 20 ppm 7/13/12 L-204 16 ppm 1/4/15 L-116 190 ppm 3/19/15 Kuparuk Producer L-250 is close on surface and with its BH location. VI. Anti -Collision Issues The original laterals L-200, L-2001-1, and L-2001_2 all fail the major risk rule. In order to meet the objective of replacing the reserves from the laterals the L-200A well path must be drilled in close proximity to them. This will allow them to be hydraulically fracturing into. If an intersection were to occur there would be no HSE risks, and BP has deemed the financial risk acceptable by our policies. CONSULT THE L-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. L-200A PTD 10 9/19/2016 k(l L-200A PTD 11 9/19/2016 TREE= 4-1/16" CIW WELLHEAD = 11' me ACTUATOR = BAKER OKB. ELEV FIEF B_EV = 77.6' BF. ELEV = 48.99' KOP = I;6x Angle = *9 _38U Q 11569' Datum MD 751 5' _= Datum TV D = 4400' SS SAF NOTES: WELL ANGLE > 70" @ 6602'. �-200 ***4-i/2" CHROME TBG***LEM @ 7315' IS 1 L2 COLLAPSED. CAN NOT PASS THRU WITH ANY TOOLS. 20# COr`� 114" 985• 10-314" TAM FORT DOLLAR 2174' 4-1/2' FES X NP, tD = 3.813" GAS LIFT MANDRELS (10-3/4" (SG. 45.5#, L-80, ID = 9.95" 3871 Minimum ID = 3.813" @ 2174' 4-1/2" HES X NIPPLE 7-518" X 9-718- TOC� 58w RA TAG 6 883' 4-1/2" SGM-NDPG�CA 7035' MIJLTl-DRDP SUB, D = 3.958" 4-1/2" SGM-NDPG-CA 7066' MULTI -DROP SUB, D = 3.958* 4-1/2" TBG, 12.6#, 13Ch 80 VAMTOP 7250' .0158 bpf, 1) = 3.958" RA TAG 727W 4-1/2" TBG, 12.6# L-80 IBTM, 0152 bpf, ID = 3.958" 72W 5-10 X 4-1/2" XO, D = 3.930" 7301' BAKER HOOK HANGER w / L2 NON -SEALING LEM, ID = 3.71" 7315' COLLAPSED LEM - CAN NOT PASS BY (SEEN IN D.H. VIDEO) (12/14/12) --7315 RA TAG 737V 7-5/8" X 5-1 /2" BKR ZXP LTP, D = 4.94" 3386' 5-1/2" X 4-1/2" XO, D = 3,930" 7405' BAKER HOOK FANGER w / L1 N0N -SEALING LEM, ID = 3.71" 741W PERFORATION SUMMARY REF LOG: ANGLE AT TOP PEWF Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn/Sqz DATE 4-1/2" SLTD OBa 7392 - 13000 O 02/18/04 4-1/2' SLID OBb 7497 - 12944 O 02/12J04 4-1/2" SLTD OBd 7870 - 13008 O 02104/04 l TAG 7663' 1 I 1 I 7-5/8" CSG, 29.7#, L-80 BTC-M ID = 6.875" 7872" I 1 � I � I.. 0,G) P"" B' 11 13050' ST MD TVD DEV TYPE VLV LATCH PORT I DATE 6 3448 2436 60 KBG2 DMY BK 0 11/04/15 5 3565 2495 60 KBG2 DMY BK 0 11/21/09 4 5373 3433 58 KBG2 DMiY BK 0 07/03/11 3 5490 3498 56 KBG2 DMN SK 0 11/21/09 2 6645 4068 69 KBG2 DMN BK 0 11/21109 1 1688814157. 69 1 KBG2 I EMPTY I BK I - 07/03/11 7051' 4-1/2" BKR CMD SLU4G SLV, ID = 3.813" 708T 7-5r8" X 4-1/2" BKR PREM PKR, D = 3.875" NIP,7122' 4112" HES X NP, ID = 3.813" 7122* — 4-ir2" PX PLUG (11fa5/15} 7193' 4 112' HES X N, id = 3.813" 72" j—j4-1/2" X 5-1t2" XO, ID = 3.940" -- 7f 277' I—j5.75" BKR SEAL STEM Ii (SEALS REMOVED), 9) = 4.83" � 7282' 7-5/8" X 4-1t2" BKR ZXP LTP w lT�K, ®= 5.750" - - - - - - - - - - - - - - - - " ( ) L2 (OBa) LEM WfNDOW65' - - - - - - - - - - - - - - - - 7320'-7331' OBa FBTD 13043' OPENING WIDTH = 3.33" F7371- 13044' 6-3/4" OBa LATERAL, ID = 3 958* 7398' 4-112" MULE SFIO� D = 3.958" - - - - - L1 (OBb) LEM WINDOW 64° - - - - -(-3 - - - - - - - OPENING NG - WIDTH T= = 3 33" OBb PBTD 1298T 7419' - 12988' 6-3/4" OBb LATERAL, ID = 3.958" -4 �753T�7-5/8" X 5-1/2- BKR ZXP LNR TOP PKR 7548' �4-f12" MULE SFE IJ = 3.958" 755T 5-1/2" X 4-1/2" XO, D = 3.930" 7572' - 13052' 6-3/4" OBd LATERAL, ID = 3.958" DATE REV BY COMMENTS DATE REV BY COMMBfTS 02/22/04 N9ES ORIGINAL COMPLETION 06/26/15 TFA/JMD PULLED ROCK CATCHER (06120/15) 11/25/09 DA6 RWO 12/03/15 GJB/JMD GLV C/O (11/04/15) 04/09/12 TBD/JMD SET RDCK CATCHER (04/07/ 12/03/15 GJB/AD SET PX PLUG (11/05/15) 04/10/12 JF KJJMD GLV CIO (04108/12) 07/25/16 JNUJMD ADDED REF & BF R EV 12/18/12 1 RlWV/JNq FOO/F ISH ROCK CATCHERiCOL LEM (12114112) 01/15/13 GiBijLD SET FXXX CATCHER (12/31/12) ORION LINTT WELL L-200 PERW No: 2040010 (020) (030) API No: 50-029-23191-00 (60)(61) SEC 34, T12N, R11F_ 256T FSL & 1575' FE3 BP Exploration (Alaska) Tw. . 4-1/16, cow v*il tAD = l l' FW ACTUATOR- BAKER PRE -RIG OKB E-EV 7/ 6' BF E1.EV = 53.B0' I Maz Angie = 96' @ 11569' Datum M 7515' 'Datum ND= 4400'SS] Ill 3/4'- CSG 45 5#, L-80, D = 9 95' 3271' Minimum ID = 3.813- @ 2174' 4-1/2" HES X NIPPLE s-lrr x 7 _S1Ir Toc--�ssg7' 7-Wr X 9-IB• TOC 7� SBW RA TAG 8'983' 4112' SC#043311-CA 7035' MILTI- I SU%D=3" 4-172'300*NDF0-CA Tow MULTI.ORDP SUB. D = 3.958' _ ..—_ ___ 4- V2' IBG 12 6#, 13CRM VAM TOP 7250' 0158 bpt, D = 3.958' 4.12• T8G, 12.6# L-80 BT-K H 7296' .0152 bp1, D = 3.958' 5.1?'X412'x0,D=3.93lr H 7301' 7BA KIR HOOK HA?4GER 73/5' w / L2 NON -SEALING I_BA D - 3.71' CXII I APSM I FM CANNOT PASS 8V -7315 (S�IN D H VIDEO) (12014112) RA TAG 737b' 7-SIB'X5•VTBMZXPLTP.1)=4.94' H 7386' 5.1/2- x 4.12' X0. D - 3 93(r7406' Iw / LI NON-SFAUNG LBA D = 3 71' FFt37F0R0kTDN SLA WIRY REF LOG: ANGLEAT TOPF6iF: Note: Refer to Rodwbon DB for hotoneal pert data SQE SPF NTE2VAL rOpn?Sgz DATE 41fY SLT) OBa 7392 1301X1r O 02/18l04 41/Y SLTD OBb 7497- 12944 O OM2104 412' SLID OBd 7870 - 1300E O 02/04/04 F(A LAG 7g63' SAFETY NOTES: WELL ANGLE > 70' @ 6602' 200 "'4-12- CHROME TB(Y--L91 @ 7315' IS 1& L2 COLLAPSM CAN NOT PASS THM WITH MY TOOLS. Ar 965' 10-314-TAM PORT COLLAR ' 2174' 4-wrHmxNP,D=3.813' C,As1FT WN C ST AO ND OEV TYPE VLV LATCH PORT DATE 6 MO 2436 80 KBM DAN BK 0 IIIW15 5 3665 2495 60 KBG2 CM BK a 1IMI09 �, 4 5373 34M 58 KBG2 OW BK 0 07MII 3 5490 3498 50 M3G2 DMY BK 0 1V21109 2 6645 4068 69 KBG2 DW BK 0 1121A39 �, .- i 8888 4157 89 KBG2 Ghf" BK - 07Xq/11 I I CSG, 29.T#, L-80 STC-M D=6.875' 7872' I --- 'L-2001 4Bd BKR CMD SLOPAC SLV, D= 3.813' X 4-12- BKR PR I A ROZ D = 3.87N' HMXNlP,D=3.813' 7193'-{4-1lIHI:SXNP,D=3813' UT X 512' XO, D = 3.94(r 75 EIM STAL STEM SEALS REMMED), D = 4.83' L /2ui (-jr-aro'X4-1f2-BKH LXP LTPMII�Ir, D=5.750' _-L2 OBa-______ ( ' 12 (0154) LBd VWJDOW 65"- 7320' -733 t' CX3a PBTD 13043' I OPENING WDTH 7315' - 13044' 63/4' O8a LATERAL, D = 3.958' I 7388 4-lWMa ESHOE D=32W Li (08b'- LEM'MNDOW 64 - -------------- 11 (OBb) 74 t424• - 743s OT+Ti , WDTH = 1 1 i' Glib R3TD 12lW7' 7419' - 12988' 6-U' 00b LATERAL, ID = 3.95fr 4- 7^ 53T 1 T—wa- X 5-1/7 BKR ZXP LNR TOP RCR 764Ir-i4-lI2- MULE SHOE D = 3.958- 7W 1&12-X412'XO,D-3.930' 7572' - 13052' 6-314' OBd LATERAL., D = 3.9588 ..-DATE l2tl! BY i COMMFMS DATE FLV BY COM&NTS 02JZU041 NIMM JORGIMALCOMPLIETION OtN26/15 TFAtJMD Plil®RDIXGATCHM(0620/15) 11125M 616 18N0 12MVIS GIBWMD GLV C/O(1V04115) 04/M12 TBDUT✓D SET ROCKCATCiM(041071 12=15 112/110115 GIBIJAD SETPKFLUC,(11XGIS) 04MOM2 J W AD GLV 00 ( 1411=12) J17JMD FRERxi CMT 12018112 FC O FIS I ROCK CALHd (1,114112) 01/15M3 GJBIAD SETFDO(CATOFER(12/3V12) ORDH LM HELL L 200 PE MT N1' 2040010 (020) (030) AR No: 50-029-23191-00 (601(61) SM 34, T72t4 R11E 256T FSL 6 1S75 FEL BP Bcpioradon (Alaska) L-200A PTD 13 9/19/2016 VVELLF EAD = 11' FMC ACTUATOR = OKB. 9LV = 77.6' BF. ELEV = 53.80' KOP = 380' Max Angle = _" Datum MD = _ Datum TVD = 44W SS PROPOS I REV 3 20# COND 114' / L-200A-*C-"R0MECSG &TBG`•* GLE>70°@ ' 10-3/4" TAM PORT COLLA�I9� ■ 8' 4 V2' HES X NP, ID = 3.81 163/4" WHIPSTOCK (_/ 1___) 3000' 103/4- CSG. 45.5#, L-80, ID = 9.95' —3000' 7-5/9- CSG, 29.7#, L-60 XO TO 13CR-80 ^ 8000' VAM TOP HC, D = 6.875' �� = Minimum ID = 3.725" @ 8874', 4-112" HES XN NIPPLE l i RA TAG 4-1C2' TUBNG COLLAR 8266' 1 RA TAG 7-5/8' CASNG COLLAR 8320' PERFORATION SUMMARY REF LOG ANGLEAT TOP PERR Note: Refer to Production DB for historical pert data SIZE SPF ZONE M-ERVAL Qm/Sgz DATE 4-3)8' 7 OBa 8383 - 8388 O 4-318' 7 OBb 8452 - 8557 O 4-318' 7 OBc 8548 - 8553 O 4-318' 7 OBd 8658 - 8663 O 4-318" 7 OBe 8772 - 8777 O 4-3/8' 7 OBf 8820 - 8825 O GAS UFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 4 3422 3 6181 2 7241 1 8094 8164' 8235 4-12" SGM-NDPG-CA SNGLE OROPSAFP4W GAUGE, D = 3.864- 8311' 7-5/8' X 4-12' HeS TNT FKR, D = 3..856' 8316' 412' NCS FRAC PORT, D = 3.958' $368° 4-12' NCS SCREEN SLAVE, D= 3.958" 83W H 7-51$' X 4-12' HES TNT PKR, D = 3.856" $402' 4-12" NCS FRAC PORT, D = 3-95W 841r 4-12' HES X NIP, D = 3.813" $421' 412" NCS SCF�V SL�NE, D= 3.958" 8"S' 7-5J$" X 4-w- HE'S TNT pKR D = 3..8W 8516' H 4-12' IjES X NIP D = 3..813' j 8525' 4-12' NCS 8CREay SLEL-/E, D = 3..%W 85W H 7-5/8' X 4-12" FES TNT PKI2, D= 3-8W 8558' 4-12" NCS FRAC PORT, D= 3.958" 8629" 4-12- HES X NIP D = 3_813" 8639' 4-12' NCS SCREEN SLEEVE, D = 3..958" 86W H 7-5/$' X 4-12" 11 S TNi FKR, D= 3-856- 8672' 4-12' NCS FRAC PORT, D = 3.958' 874T 4-12" HES X NP, D = 3.813- 875T 4-12' NCS SCREEN SLEEVE, D = 3-958" 8784" H 7-5/8' X 4-12' HFs TNT PKR, D = 3..SW TBG, 12.6#, 13CR-80 VAM TOP 8891' 884T 412' HPS X NIP, D = 3.813' � L , �� p 14-12' -0152 bpf, D = 3.958' 75/8' CSG• 29.7#, 13CR-80 vaM TOP HC, 9114' 8874' 8891' 4-12' HES XN NP, D = 3.725- 4 112` WLEG, D= 3.958' �o ID = 6.875' DATE REV BY COMMENTS DATE REV BY COMMENTS 02/22/04 WES ORIGINAL COMPLETION 10/05/16 JPT PROPOSAL REV3 11/25/09 D46 RWO _/_!_ SIDETRACK (L-200A) 12/16/15 JIP/JMD BUILTPROPOSED 05/09/16 JT/JMD PROPOSAL REV 1 05M16 JT/JMD PROPOSAL REV 2 ORION UNIT WELL: L-200A PERMIT No: API No: 50-029-23191-0 SEC 34, T12N, R11E, 256T FSL 8 1575' FEL BP Exploration (Alaska) V19.LMEAD= 11.F#C PROPOSED L-200A ACTOR= -- : REV 2 Ott. ELEV ,. -77 66 BF Lift/ 538G! / LT" 3W; 20lCOhD 114' wax Anpk • ]mum hU = 3W—TVD= 44W S i0.3�1`VJNPSTCICI(; r _1 3490' 10.7/6' fSG. d5.5f, L-00 D+ 9.95• 99l0' ' S8' CS(x -ii 70, L-BO XO TO 1?Cii-10 A M TOP FO, D = 6.875' Minimum ID = 3.725" @ 8874 4-1iZ" HES XN N1PPLE RA TA0 4.112' TLI6NG COLLA R 7-5(S' CASNG COLLAR j--i 832W Mi*ORAT10N SLOAP RY FEY LOG ANGLE AT TOPiHF Me: Re1a b Rodlcfon M for 1lelorcal Pert dab SEE I SPT I ZONEI PoEwAL OPn/,gz GATE 4.3+d' 7 00a 8383 9388 O 4.3V 1 08b 8452 MI O 4-3l8' 7 OHe 85" - B53 O 4-3V 7 09d 885a - 8883 O 4-30T 7 08a 8772 - 877I O 4 3W 7 Ow 8820 8825 O VAM TOP H 9991' 0152 bp1, D = 3.958' Srd' CSG, 20 7M. i3ORi =B$75' SAFETY NOTES: WELL ANQ.E> 70" (? ... CHROME'w i 1w.. ' 98S fP3N'TAMPORTC0.UR 1985' 4. 1/2" K3 X 4 P 0- 3 MIL LOUT W NDOW(L-200A) -390' - -3700' GAS LIFT VANEMS AO NDTDE\�', TY F'F VlV U1TCtt R7RT rA TF 1 1 181 2 7241 1 BO94 4-ti2'SGAXNDPr3CA S111Ot E DROP SAS GAUGE D = 3.061' t 8969' t' ja 1Iz' N� SCfifi7d SLkEV F D • 3 9ii' �-±7 S8- 74 12' VIM TNT C 8402' ]-+ib_1/T NC&FRACFLRT�Q+J.95B"� 8412' 0-112-htSxlf+.U-7.8t3' 8421• - 1 1n Nr„S 8C1� SLEtvE, D 3 93e• 844!' 7 "a`t3' x 4 1fC h[3 TM RCR, D - 3.B i0' 1 ppp �—jd- i!Z' NG5 Fi7AG POR(, D = 3 058' 8616' 14- 112- +" X NP, 0�3813'� 8525' ��j-�a. V2 NOS SCREEN SLEEVE ID a �- 7-S8' X 4- V2' HS TNT R = 3.856' a668' H4 112" NOS FRAC POW 9i39 4 v2�SCgE N SLEEV E, D = J 0a8• uii• 7.98- % �, R 16' TNT RCR D= J_856" fes7T d-fl2-'NCS FWtC FOH(. D=J.958" -9TCT 1-tr1' Ncf; SCAf$J SLEEVE, D= i 95R' d. i!Y 14S TNT F fk 994T � 4-17T CSXNV 0-J91J' �'j4�1s-Ira' lii3 7tNrs>: D--JfT2}' j ��4-1l2 11t.Ef�, D = 3 358� DATE REV BY I 0OM.@R5 DATE MV BY OOWANTS 02rW" NBES P!"4Y L COMPLE110N 1 t 81L1ETRACNjL-BOA) ' 12Ji&i5 OS09+16 JTRAA) J(1,9.0 Bu rFR1JR7S$7 ._ F'f70PO5At REY 1--- M9116 J(LA.0 P C1 L fEV 2 . 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Ln LO W Z M O) M m M W M W M O) M O V W N O m O) V 0) M V N M OO M M Ln m (R M OR O O T D) V .- W N V V W LO V n O 0) m N Cl) m n M M M m M D) n O M M M m m O V V m m M m N N m O O IT N m N m 0) m r- LO d m N C O O N cl N M M M M V V Ln M LO LO m m m n n 01 M Na. M M M Cl) M M M Cl) M M M Cl) M M M co M M M M M M M N O z� V V V V V V V V V Ln V V M Ln m V m V V m V n M m V m U) M n m m tO O V O O) V M (3) V V (q m n m m m N Cl) Ln M O) n N — m LO 0 M O m N LO m N O O V V m 0) n m n N m m O N m M LM n V M m N m - M O n N N N M M M V V V V Ln Ln LO to m m n n n m m D M z= M M Cl) M M M Cl) M M M M M M M Cl) M Cl) Cl) M Cl) M Cl) M n n n n n n n LO Ln Ln lO Ln In Ln Ln m Ln Ln Lr) Ln O) m m in W W 0) m Lf) CIO N Cl! N N N N N N N N N (N! N N m t M M M Cl) M M 0) M m M M M 0) M n M V M � M m N m N m N m N m N m N m N m N m N m N m N m N m N m N M M M M M M M co M M M M M M M M M M m M M M M E N o_ d m N a � N N � N ci N 6 N N •" N O) V n m m M M LO W N m Ln m LO m N 0) N O) Ln T L!') O) N 0) m 0) LL7 0) m 0) to m Q O n O n O n O n O n o n 0 n O) a m w m r- m n to m m a m '� m co m (D CO f0 m co m M m 0 m 0 m 0 m c0 CO (D (D m m b La U N O .d O LO O M Q CO O. C l0 O E d o N 3 O A LZ a p J ILL- 0 70 J 0 C p O m N La N G Z d 0_ J O_ J p p O p O O O O O O O O N N M O U) 0 O O O O o O V LO c? O LO O O O o C! O O n 7 O O O O O O O O O p O O O O 0. T O O o O o O O O O O O O M N J O 0 O O O O O o O m " p O O O o O O O OI Ln O O O O O O O O O O O O O O Q 2 V Ln LO m m m n m m LO m LO CD Ln O m m m N m M m M m V m N m m m n m n m m m m m C n — n N n M n V n In C .. 0 U)0 7 N N 7 M o. � o c d E d a m — O D ad+ N N y c N o V U a y� . 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O Q N V m M V O � V V Q) V N O) O V M m m T m n O O V n 7(f) n W m Q) 0) n N cn M N (D M Cl) (D � ITu) m O 0 O M 00 N M N M p-O M M m V n V M to u) u7 a)M N m u) (D u) (D (D (D CD (D 0 n n u) n m ui (n m ui (n m m m (n m m (ri N ui m Z4 Co a_ O O O) Cl! (D O O p V (D V V O p M M O O W C) O 0 a) p O C7 O 0 O p O (n m O O u) O) m 0 V N V V (n n O) O N V n u] m OD m n m O O (3) n (O O7 uJ n m m m cc oc C CA cl W O Cl) O M O LOn O O n O m C N .- N Cl) N M Cl) M M M M Cl) Cl) M V V V V V V V V >O F p CD 0 m u) V LO u) m u) m m O u) O M O (O V O M O N O O) O O O O p (? (!] O m O co n m M m V M V m m u) M N T m p O) O M W I!] O) 0) M O C M C u) 0 00 O _ M M V (D n m N cV M m Cl) Cl) M M M M V V V V V V V V V V V N u] O 0 � m N V m V p- CD m O C) C)O O N N m Q) O O m O O D) O n n O O O O O (D L N (O N In N M N M N O N () I� (L) M N O O O O O O O co M M M M Cl) m M M M M M Cl) M Cl) M Cl) M E, N ° CL (T] N a � gU) u7 0) (n O) n n 00 n u) Cl m p OD m m (O m N V V V n n N n N O O 0 0 O 0 O 0 O O O Q (D (D m m m s m u) (O m (O M m Cl) (D N (D N m m O (O O m O to O (D O m Cl O (O O tO O (O t6 U N < LO0 (D u C °' c N Co 0 CL EE o m N 3 CD m a J t c p o J O C O F a O m N M N C L Z CL [L J O_ J u) M u) m 'i O O c) V O O O O O O U] n O O m (n O O O N O M R S O M O M O O O M T O) In n A m J O 0 O CA m O d 0 O O m N O a O O M O 0C'i W t O 00 O O V V N mO O (O m m 0 O O (V n n n n aco m m m m m mn c ` -O r2 7 U7 7 7 7 2 2 M 2 2 Z t7 CL y _ a c 0 m c> a U) d a ( . H _ O O 0 0 I- N O _ __ m O 0 0 0 O 0 0 -O O m W O 0 O 0 O 0 O 0 (n � Cl! (� N v O O O O O O O O O m ,. m v m v N 0 0 0 0 0 0 0 0 0 a W; d m o mLL _ o a= m O O O O O O a o 0 0 00 0 O 0 CDO 0 0 O 0 O 0 O 0 O 0 O 00 O O 0 O 09 O U O O o O N N N N O O O O O O 0 O O O � Z Q N U U � d � � J O p O O1 O) O U) U) N O O d a) C m O N (D m O O m m m N m � (n M M O M m 'T O m O m O m O T 0) Q N N N o (l N v M U) ^ ^ N m O 0 O U Y M N m O m - O m O O N m (- (D M O) U) O ry V7 N C m m m OD m V m N m_ m r, m � V m m v (O N (O (� N M m O_ U) m m 0)) N 7 m m m m m m m m m m m m m m m m O o d N N N C 5 J J W N m In Ln m m In LO m m m m (n 1 W M m U) O (D 0 N I- m N 10 m O LON N I- o (� (O O N (l m m � o m m m V: V O U 'O O V n m m CDN O m O (O m N O M N M (n NCl) n O It 0 (N f� O co O C O O O N N N N M co M M v V L L V 'R V V V V d' V' C V 7 v V .1 v d rn rn m m rn m m rn m rn rn rn rn rn (3 m m G C Z N 11) N (n (n m (n m l!] V7 (n LO ll) N ((') N (n V7 d 0 O C 'O C ad) d 7 V Cl) m (- N O m Ih N O V Cl) U) m (D m m (n d C 4 d w d d N N m N U) m m v M M v U) r- N M M Cl) V m N (0 (M Cl) O 0) N N 7 N N m h U) 0 (D Vw d (,) d d L N m N a0 N O M N co N M m M CD v N U) 0) �{ N ((') m M O (D M (D U) m O n r N .0N J 2 fA p W 7 r O Q N (n N N V m In m U) 0 m m M N n O T "T N -7 m 0) 7 (O N N a0 m M 7 m O U] (D (mD (D m m N m M m U) CO- m N aD m m M m N O U) O N O O N M CO (D m m m O (n M m m n. 7 N U) (n m U) U) m m (!'1 m (n m U) m LO m (!') O m O (D O m O (D (D (o UJ a a� m O m O O O Cl) m O O N O V' N O O O U) 0 O (� 0) O O M o 0) O d m r- M m r- m 0 O I-- M m U) M r- m m m O m Cl) m U) m m [A Cl? a) M O m U) m m m O N N a) y �- y v v v N v N v N v N v N v N v M v M v M v M C v �{ v v v U)Ol v a >O F ` o m N O O m V) O m O m m U) O (- O (D Cl! U) O U) (O (n O N O U) O m M U) O V U) m M (n m m m (D m o (o M v U) m v g v v vi ui m v (l U) O m N N N N M M M (p M m M O v M V m m N M m V7 U) m U) m U) O O O O O O O O (D M m N v co (n m U) m LO m U) m U) m U) m U) (D U7 m m (D N m U) (p O M O ') O M O m O m o (- O m O m O m O to O m O m O m O m O m O to O (D O E M M M M Cl) M M M M M M M M M M NC_ a - ca N a Y U) O O O O N m O m O m m m m m m m m m m p g o 0 0 0 0 o 0 m m � m m r �P- � �� a m 0 m m (0 u) m N U) a) m �, m r (n m m m N M (n m (n CD m m n m u) m (n m m U (TO Q O C) U) CO O Gl C - T 00 07 E d m (0`r 3 O m r m a o c o LL p a 'n O m NM N m L L Z d d J d J O O O O N I- O v m r O N O O z O M O M W N o m r� h 0 N O U) O o r m O O (- O O o m 0 a O m O v N O O m M m m O 0v O O m M O O Nm O (� M O NOp m 4) N N ao m m m m m co am w ao u m m 'O m 00 d (A m cu m aD m aD V Mm O U) O O y O O O O y U o c d 10 1 $ c d p U a ip p a N . y -o OOO m 11i o 0 0 0 d Q1 _] MW2 ` p o 0 LO co co a o 0 0 0 0 0 0 0 z Q O O) N d � rn O O rn U d a- m � N N O O 0 � m Lo m CDQ O) m m m r O o Ud Ud U Y rn (D o m N 0 CD C Cl M l") N O O N N ` C N In N N J J H W W N N m m N O O N m m m C p p 0i V C V m N C W O v) u) d m w N 7 Om ) Z O) m m CD C y O d = d u7 W y C d C) _N 'O V p C W" C d 2 CD m N N O i ` m N w O O O O 41 ) V N n m ipi d - - m - u 7 0 o J p z Z u) a W d tm o c m O N c E a � r. U C rn m v) v m o W rn r- W co N m N a. 7 N �' m m W W m 2 7 t6 d O O R VV N O O r� W 07 m uv'i u°ii u b y v v v v a O N z= • d Z U) o N (1) (DM W W m W W W v z= Z rn Q U W n m n N U m m W m LL r o 0 0 0 a m = r- 1p Q N h N m N m Y g � n � r d j N V mac_ ^ a m m a; LO m m m m tu o u - c_ o vCD E m 3 d rp N m L 7 a �'' O v a o c CS 0 mm v O m N m N • Z a a J a J O O W y O Cl N A O O O) W d O ►� N c N CO m0 to m m A C d M M m w — coE d a m o N c c N o N ad+ U a M3: 3: 0 a U N I U z Q rn rn O a m w � m O O 0 0 CD ON1 3 Q N@E� J O O N N 2C J J H W (0 a) m O d Q O d N Q J 6 J O C O O m N (0 N 2 0 d J D J a a C .. ` o a E E (D_ a rn o m m '� co I r. 0" LL a 0 0 r J d d 2 _ d wl n m > U w m 3 I I v a M v v d �I �I m l u 0 z z 0 LL >� z 0 0 D 0>> O (fin >> z z 00 0 N N N N N N N N N (N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O O O O O jp t O (p N n M v m N LO OD N O N N N N O I- m O) M M N, N N O 4) N N NM O aD v M N G aO N N O O N(((p d ` N v v v N V M v v v M V N N V N co v v v M V v O O f- O N N W v N O m f- V w _ Cl)O O (- N N M M O O I- M N N W cO M M (D W v N M N N m w m m N r- N m O m O) O (D N m O N (D w M O M N N M M m'q M n N N O O N O. y O O O CO Cl 00 v O (D v ClCl N N r- r- !� M O3 M (O dD 00 v f, O m N aD C C 06 co P- n (O 07 O (D m W Z6 m _00 a Ewe o _ O O LO 0 z o a X X � rn rn O � C � a 7 7 7 Y O O @ m Q 0 W 7 N E u7 J ¢O ¢O 7 U7 N N 7 G O J J F W N I C p at L w N rL Q' C O N C u YI C C C V 4 Q1 W R U N U w m w cc v o G > 0 J F Z U) Q O d O � O O O O O (D U o o Go m �_ o (n o O N V V O M m a.O v m O N � m O M C l0 O M (rj O m M ; (O �" (mD m (gyp OD -6 'O F o F o F F U _ O L O L O O O = O L O L � L O N O .- O O O 7 m M M M O N r- O V J N o O a. m Q1 E O -� m J O J'T N O- 0 � O M O v L m E W r r r r r r r r r r m Oi a U F p m m m m m m m Y w w In 0 w to w (n m (n m to F 4m O M � lD m m M O (p r� r- N N O f� m (O N 1� N m m M O O V OD N N M m N m m V O O O N m O O M O m V O Y] m m m m m N f- M 7 1, OD N W 7 _ � A O p U O (D N V m O CO V R (p O (O lu 'C N M m m 7 O I� m m (p m m U m V N M 0r� O OD (O M M N J ul M �'+ o .- M M m (n m M In N Ll M O V M (p OD m m v N a m Q m (D (O V' M M M O O O O lO (� m N V M O m O m m m E a cM JQ Q j C N N N N N M M M K V V V V m U m Q Lo O m OaL E gyp O 3 N (N I- 'O (O CDO O O N O a L d J a L O d' O O M m N m m p? Co NM N d N m N N O O O m m M V O M m V m m Z U_ 5-J R J m y Q .3. N M M M M u7 m r� m m m m m I (A C p T M T ` C C C o m V p C m a a+ Q o `e _ E a .d. a� 6 m C O U a a1 3 30, a v North America - ALASKA - BP Prudhoe Bay PB L Pad L-200 Plan L-200A L-200A wp05 Anticollision Summary Report 24 June, 2016 Ff PF_-- 'A Ulu BAKER MU6NES z.0. by Anticollision Report BAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.0ousft Reference Wellbore Plan L-200A Reference Design: L-200A wp05 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well L-200 L-200A @ 96.05usft (hgx) L-200A @ 96.05usft (hgx) True Minimum Curvature 1.00 sigma EDM R5K -Alaska PROD - ANCP1 Offset Datum Reference L-200A wp05 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 2,900.00 to 9,114.15usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,106.72usft Error Surface: Elliptical Conic Survey Tool Program Date 6/24/2016 From To (usft) (usft) Survey (Wellbore) 218.11 2,940.57 L-200 Srvy #1 MWD+IFR+MS (L-200) 2,940.57 3,000.00 L-200A wp05 (Plan L-200A) 3,000.00 3,600.00 L-200Awp05 (Plan L-200A) 3,000.00 3,600.00 L-200A wp05 (Plan L-200A) 3,600.00 4,950.00 L-200A wp05 (Plan L-200A) 3,600.00 8,270.00 L-200A wp05 (Plan L-200A) 8,270.00 8,790.00 L-200Awp05 (Plan L-200A) 8,790.00 9,114.15 L-200Awp05 (Plan L-200A) 8,970.00 9,114.15 L-200Awp05 (Plan L-200A) Tool Name Description MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal BLIND Blind drilling GYD-BM-MS Gyrodata - bat/mem drop m/s MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal BLIND Blind drilling MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 6/24/2016 3:26:16PM Page 2 of 5 COMPASS 5000.1 Build 81B �.4 BP r�.g 0 by Anticollision Report BAKER HUGHES Company: North America - ALASKA - BP Local Coordinate Reference: Well L-200 Project: Prudhoe Bay ND Reference: L-200A @ 96.05usft (rigx) Reference Site: PB L Pad MD Reference: L-200A @ 96.05usft (rigx) Site Error: 0.00usft North Reference: True Reference Well: L-200 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 1.00 sigma Reference Wellbore Plan L-200A Database: EDM R5K - Alaska PROD - ANCP1 Reference Design: L-200A wp05 Offset ND Reference: 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 L Pad L-01 - L-01 - L-01 Out of range L-01 - L-01 A- L-01 A Out of range L-01 - L-01 A - Plan #8b L-01A Out of range L-02 - L-02 - L-02 Out of range L-02 - L-02A - L-02A Out of range L-02 - L-02APB1 - L-02APB1 Out of range L-02 - L-02B - L-02B Out of range L-02 - L-02PB1 - L-02PB1 Out of range L-03 - L-03 - L-03 Out of range L-03 - Plan L-03A - Plan #8 L-03A Out of range L-04 - L-04 - L-04 Out of range L-101 - L-101 - L-101 Out of range L-103 - L-103 - L-103 Out of range L-104 - L-104 - L-104 Out of range L-105 - L-105 - L-105 Out of range L-106 - L-106 - L-106 Out of range L-112 - L-112 - L-112 Out of range L-115 - L-115 - L-115 Out of range L-115 - L-115A - L-115A Plan #1 Out of range L-116 - L-116 - L-116 Out of range L-117 - L-117 - L-117 2,920.44 3,225.00 824.07 70.94 761.11 Pass - Major Risk L-118 - L-118 - L-118 2,904.40 3,050.00 383.57 67.41 337.23 Pass - Major Risk L-119 - L-119 - L-119 2,905.73 3,175.00 829.93 68.59 773.51 Pass - Major Risk L-120 - L-120 - L-120 Out of range L-122 - L-122 - L-122 Out of range L-122 - L-122A - L-122A Plan #2 Out of range L-123 - L-123 - L-123 Out of range L-123 - L-123 - L-123 L1 plan #3 Out of range L-123 - L-123PB1 - L-123PB1 Out of range L-124 - L-124 - L-124 2,906.79 3,225.00 1,047.30 68.57 981.35 Pass - Major Risk L-124 - L-124PB1 - L-124PB1 2,906.79 3,225.00 1,047.30 68.57 981.35 Pass - Major Risk L-124 - L-124PB2 - L-124PB2 2,906.79 3,225.00 1,047.30 68.57 981.35 Pass - Major Risk L-200 - L-200 - L-200 8,676.37 9,625.00 20.19 0.65 20.19 Pass - NOERRORS L-200 - L-200Ll - L-200L1 8,485.30 9,450.00 3.84 0.67 3.84 Pass - NOERRORS L-200 - L-2001_2 - L-2001_2 8,386.68 9,350.00 1.66 0.58 1.66 Pass - NOERRORS L-201 - L-201 - L-201 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 L1 - L-201 L1 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 L1 P61 - L-201 L1 PB1 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 L2 - L-201 L2 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 L3 - L-201 L3 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 L3PB1 - L-201 L3PB1 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 PB1 - L-201 PB1 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-201 - L-201 P62 - L-201 PB2 2,911.87 2,900.00 329.57 69.51 284.23 Pass - Major Risk L-202 - L-202 - L-202 3,601.24 3,750.00 526.09 116.97 421.20 Pass - Major Risk L-202 - L-2021-1 - L-2021_1 3,601.24 3,750.00 526.09 116.97 421.20 Pass - Major Risk L-202 - L-2021-2 - L-2021_2 3,601.24 3,750.00 526.09 116.97 421.20 Pass - Major Risk L-202 - L-2021_3 - L-2021_3 3,601.24 3,750.00 526.09 116.97 421.20 Pass - Major Risk L-203 - L-203 - L-203 3,000.00 3,275.00 568.71 72.55 510.18 Pass - Major Risk L-203 - L-203 -Plan #11 temp 2,921.34 3,200.00 579.26 72.00 519.51 Pass - Major Risk L-203 - L-2031-1 - L-2031_1 3,000.00 3,275.00 568.71 72.55 510.18 Pass - Major Risk L-203 - L-2031_2 - L-2031_2 3,000.00 3,275.00 568.71 72.55 510.18 Pass - Major Risk L-203 - L-2031-2-01 - L-2031-2-01 3,000.00 3,275.00 568.71 72.55 510.18 Pass - Major Risk L-203 - L-2031_3 - L-2031_3 3,000.00 3,275.00 568.71 72.55 510.18 Pass - Major Risk 6/24/2016 3:26:16PM Page 3 of 5 COMPASS 5000,1 Build 8 1 B �. BP EPA .2 by Anticollision Report BAKER •«�,,. HUGHES Company: North America - ALASKA- BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.00usft Reference Wellbore Plan L-200A Reference Design: L-200A wp05 Summary Site Name Offset Well - Wellbore - Design PB L Pad L-203 - L-203L3PB1 - L-203L3PB1 L-203 - L-203L3PB2 - L-203L3PB2 L-203 - L-2031-4 - L-2031-4 L-204 - L-204 - L-204 L-204 - L-2041-1 - L-2041-1 L-204 - L-2041-2 - L-2041-2 L-204 - L-2041-3 - L-2041-3 L-204 - L-2041-4 - L-2041-4 L-210 - L-210 - L-210 L-210 - L-210PB1 - L-210PB1 L-211 - L-211 - L-211 L-211 - L-211 PB1 - L-211 PB1 L-212 - L-212 - L-212 L-212 - L-212PB2 - L-212PB2 L-215 - L-215 - L-215 L-215 - L-215PB1 - L-215P61 L-215 - L-215PB2 - L-215PB2 L-216 - L-216 - L-216 L-217 - L-217 - L-217 L-218 - L-218 - L-218 L-219 - L-219 - L-219 L-222 - L-222 - L-222 L-223 - L-223 - L-223 L-250 - L-250 - L-250 L-250 - L-250L1 - L-250Ll L-250 - L-2501-2 - L-2501-2 L-250 - L-250PB1 - L-250PB1 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Reference Offset Centre to Measured Measured Centre Depth Depth Distance (usft) (usft) (usft) 3,000.00 3,275.00 568.71 3,000.00 3,275.00 568.71 3,000.00 3,275.00 568.71 6,191.15 5,950.00 153.86 6,238.82 5,950.00 366.56 2,917.28 2,975.00 715.68 2,914.44 2,975.00 723.30 2,917.28 2,975.00 715.68 2,921.61 2,875.00 138.36 3,600.56 3,725.00 194.83 2,912.25 3,050.00 1,011.60 3,227.08 3,250.00 172.89 4,044.58 4,025.00 513.94 4,044.58 4,025.00 513.94 4,044.58 4,025.00 513.94 2,901.94 3,050.00 568.49 Well L-200 L-200A @ 96.05usft (rigx) L-200A @ 96.05usft (rigx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum No -Go Allowable Distance Deviation Warning (usft) from Plan (usft) 72.55 510.18 Pass - Major Risk 72.55 510.18 Pass - Major Risk 72.55 510.18 Pass - Major Risk Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range 136.55 57.12 Pass - Major Risk 146.42 256.05 Pass - Major Risk 68.33 647.77 Pass - Major Risk 70.19 653.63 Pass - Major Risk 68.33 647.77 Pass - Major Risk 68.62 69,80 Pass - Major Risk 119.55 92.51 Pass - Major Risk Out of range 73.92 938.04 Pass - Major Risk Out of range 82.99 104.78 Pass - Major Risk 92.77 445.04 Pass - Major Risk 92.80 445.01 Pass - Major Risk 92.77 445.04 Pass - Major Risk 68.38 505.41 Pass - Major Risk 6/24/2016 3:26:16PM Page 4 of 5 COMPASS 5000.1 Build 8 1 B BP FSFAN %W'At by Anticollision Report RAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.00usft Reference Wellbore Plan L-200A Reference Design: L-200A wp05 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well L-200 L-200A @ 96.05usft (dgx) L-200A @ 96.05usft (dgx) True Minimum Curvature 1.00 sigma EDM R5K- Alaska PROD - ANCP1 Offset Datum Reference Depths are relative to L-200A @ 96.05usft (rigx) Coordinates are relative to: L-200 Offset Depths are relative to Offset Datum Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04 Central Meridian is 150' 0' 0.000 W ° Grid Convergence at Surface is: 0.64° Ladder Plot 1200 - - -- - -- . - - - - I I I I I I I I I _ _ _ _ _I_ _ _ C i I OT 900 I �I -- M I C--- p --'--- - - - - ---- _. -- -'---'---- -- - I-- --- n ID 600 ---- - - - - - -� - N o AND LD D O L-01,L-01,L-0104 -1 � =1 PB1,L-123PB1W3 - - L-2 iL-204L4,L-204L 5 L-01,4-01A,L-01A1VO - 724 L- 24,L-124V13 L-2 5, L-205, L-205 V3 L-01,L-01A,Plan#8bL01AV0 12 124PB1,L-124PB1V5 L- 05�L-205L1,L-205L1 L-02, L-02, L-02 �F1 L-1 4, L-124PB2, L-124PB2 V4 -205, L-205L2, L-205L2 V L-02, L-02A, L-02,A V5 200, L-200, L-200 V7 $ L-205; L-205L3, L-2051-3 V3 L-02, L-02 B, L-q y0 3 L-200, L-2001- ,�W L2 V6 6Dft L-205, L-205LW&5L5 V2 9000 $ L-02, L-02PB1, L-02PB1 V21 $ 01 201 01 6- L-205,L-205P61,L-205PB1 V4 e� tired eFptX (1500 usft/in) -�- L-03, L-03, L-03 V5 • L-201, L-201 L1, L-201 L1 V9 $ L-210, L-210, L-210 V6 an - an - - - L-04, L-04, L-04 V5 -*- L-201, L-201 L2, L-201 L2 V5 $ L-211, L-211, L-211 V6 $ L-101, L-101, L-101 V4 $- L-201, L-201 L3, L-201 L3 V2 $ L-211, L-211 PB1, L-211 PB 1 V6 $ L-103, L-103, L-103 V23 $ L-201, L-201 L3PB1, L-201 L3PB1 V6 -e- L-212, L-212, L-212 V 11 $ L-104,L-104,L-104V7 $ L-201, L-201 PB1, L-201 PB1 V12 $ L-212,L-212PB1,L-212PB1 V9 $ L-105, L-105, L-105 V4 $ L-201, L-201 PB2, L-201 PB2 V3 $ L-212, L-212PB2, L-212PB2 V2 -;- L-106, L-106, L-106 V14 $ L-202, L-202, L-202 V6 L-213, L-213, L-213 V9 $ L-107, L-107, L-107 V14 -F L-202, L-2021-1, L-202L1 V8 L-215, L-215, L-215 V7 $ L-108, L-108, L-108 V18 $ L-202, L-2021-2, L-20212 V7 $ L-215, L-215PB1, L-215PB1 V4 -� L-109, L-109, L-109 V12 -- L-202, L-2021-3, L-2021-3 V8 $ L-215, L-215PB2, L-215PB2 V2 612412016 3 26.16PM Page 5 of 5 COMPASS 5000.1 Build 81B o U W --- w - `go O Fo a _ F � Q N J I + i Q a N J � � N a G JN J � d❑ F J 02 w 3a ❑ ro w it c~ m M a pQ I N I M F o - _ O U O N 3 G (u►/I3sn OOL) (+)ulioN/( )ulnoS J H W O U co y N �� h ¢ 6 T OO�� N CCNpp y N v N Omi N W� R �t0•J I� NHmN N(d u-i EOG V' �H.y.I O�2H HQOO.�COS ... . 0 0 O�OmSO�dGO ------- 00OOO- -W-- �OOOOOHO000 06cs NO V 6c66 C7 G<V CC LvYOJ-C p� tOO H lD fOO N N m O n m <IO IQ VVVq Hq CNp � � t!') l0 ll'J It1 tD tp H � R . t'^. . . . �0pp 0 U O 0 CNN Hf NC'1 V- N NNNcc�� Q<C'� ¢vN°n°nrnrnc�c`i'.�H c`no NN��H(•OjNN �O 5? !�, �2V�Lq.9Ho_�pe�0- Q7 O�«OOtD tDCO��Qi lO lh c0 tD I� 1� (D tD t0 t0 ) 4J M9 Hc Oq N�aq e7H� . N t�]t•J l7 t7 IA (O I�OO 8(= It- p �\ QWW 8\ �3 0 I q I ❑ O ❑ ❑ tO Ln Of O[hrN LL'i�cD Q W Q W 0 r N r vD M� s F S F 8- M. g cgo�ooLL'r 1 Nt^•JHV H O Ofn Eg Nfn O(nQ�� CJO)J�JOJO� Z � Nor-O�❑t�❑v.-� Q H205U)wIAfAlntgwww1 - ❑�8882F� �;28sgo �Op8p Z6 �p "i C� t•O] M tm7 lA � ^ COO ODD � OOO Of �f`J�000O uO dN�uyi� sNty)� (((•��I 1� (7q�+ lG (pG� �Opi m N N N N Cmh 9-MA Q O V W V U U p U i Cb I Y y �' �NNarlisNNNtY,I d w 8 �saaasssa Q818 R H�}QSQ}{{`�Qgy�Qxg BgyQg'�� Z Q �g��jQg/}Qgy QxS `�gggg aN2V t�i�S Ai M&P96 ii O - I I _ - I I r- A r I C) o a 4-1 H - � I a � ey I I � (%0_'I� r: m ; S 00 �i V R (u►/jsn OS£) q;daa ivoivan otujL VA sung g as 09 v CD . . . . . . . . . . ID� 138n erv�'zo n u, �v / �— —� N CN cn i o mmm vnm /� -r-- 00 i r C9 CL fsmmm Cl) vy, s3 es 0 'o 0 0 U) 0 w 0 0 ...... C5,0 'T m m N N m co -01 v U) N 0 1--CL 2�1 cu cc m C) O O \\---T_-/ N O . . . . C,4 � CD C) C� c, cli C\j �j C, 2 0 N w CD O .2m. cn 0 IL m N / -- - I' �_ E. 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NNN 10 :3 C-i W sun a a QomomoNoo Jlao w''�gn n mN ry oBo�� N ?vNio�nvmino �m�n�vf ' e��rv$$umi umi vtOi vmimm ONnNome�n�aoo�v°'i d"o< Nrv� mm��mm�`m8� �" E - 4' E3�gs cm ag min umi u+ z g E E5�5 '. �In`SSSS��Nto a `ewe= wyyE rvm.�o, m�mm�m m U Nm U 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 � N c7 M V u� Y'l m t0 tD 00 f C m v 00 LD M N � M '7 m \ a I I l i Ui!_ 1 ` �t0 h a0 O l0 � 0 O 414, N N �_ C V- 12p] m /, l39 O 0 O i� oN C _ fp O � n j i > m \\\\�N N cMn`` \ J O o O N f"i / O O J N O —�--- / Z N C 0 0 � _ M U' m Q Oc7l N o O r m N J m � f� Z CN U 33 3 tio0 � e .0m r 'N0 D�� AO iN IOI+xx EI❑mi zmi lLL mo❑❑o❑2md 14 u°r'� o; wz U) m d �N �ri m Qi +": - '� ¢ .2 +00000000 LLNNNNN NNN IL w 1� N m m \\ Z } 2EYYY 2aa O o VVj�'mf O o a C33555533 M _ �Y �� __- -.— -�� f \ � N � fn �'oa QQo�000 O NJJJJJJ JJJ p Z� O O .z _ �- _�L�.._ —� _J✓' i O �NMMc�vmromrn J N O N e�u�ioo 00000 O _ Heo O J --- — �/ IY LLtOvoa oon mn o N O + e N North America - ALASKA - BP Prudhoe Bay PB L Pad L-200 Plan L-200A L-200A wp05 plus 500' MD AOGCC Offset Well Report 24 June, 2016 fig BAKER HUGHES Company: North America - ALASKA - BP Project: Prudhoe Bay Reference Site: PB L Pad Site Error: 0.00usft Reference Well: L-200 Well Error: 0.00usft Reference Wellbore Plan L-200A Reference Design: L-200Awp05 plus 500' MD BP rias Anticollision Report BAKER HUGHES Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well L-200 L-200A @ 96.05usft (rigx) L-200A @ 96.05usft (rigx) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference L-200A wp05 plus 500' MD Filter type: NO GLOBAL FILTER: Using user defined selection & filtering criteria Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 2,900.00 to 9,614.15usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 200.00usft Error Surface: Elliptical Conic Survey Tool Program Date 6/24/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description 218.11 2,940.57 L-200 Srvy #1 MWD+IFR+MS (L-200) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 2,940.57 3,000.00 L-200Awp05 plus 500' MD (Plan L-200A) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 3,000.00 3,600.00 L-200A wp05 plus 500' MD (Plan L-200A) BLIND Blind drilling 3,000.00 3,600.00 L-200Awp05 plus 500' MD (Plan L-200A) GYD-BM-MS Gyrodata - bat/mem drop m/s 3,600.00 4,950.00 L-200A wp05 plus 500' MD (Plan L-200A) MWD MWD - Standard 3,600.00 8,270.00 L-200Awp05 plus 500' MD (Plan L-200A) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 8,270.00 8,790.00 L-200Awp05 plus 500' MD (Plan L-200A) BLIND Blind drilling 8,790.00 9,114.15 L-200Awp05 plus 500' MD (Plan L-200A) MWD MWD - Standard 8,970.00 9,614.15 L-200Awp05 plus 500' MD (Plan L-200A) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal Summary Site Name Offset Well - Wellbore - Design PB L Pad L-200 - L-200 - L-200 L-200 - L-200L1 - L-200Ll L-200 - L-2001_2 - L-2001_2 L-200 - Plan L-200A - L-200A wp05 L-212 - L-212 - L-212 L-216 - L-216 - L-216 L-217 - L-217 - L-217 L-223 - L-223 - L-223 Reference Offset Centre to Measured Measured Centre Depth Depth Distance (usft) (usft) (usft) 8,655.51 9,600.00 23.29 8,485.30 9,450.00 3.84 8,365.26 9,325.00 11.22 7,500.00 7,500.00 0.00 6,191.15 5,950.00 153.86 2,921.61 2,875.00 138.36 3,600.56 3,725.00 194.83 3,227.08 3,250.00 172.89 6/24/2016 5.10:06PM Page 2 of 19 COMPASS 5000.1 Build 818 W W `Northing (700 usft/in) wn 888888o8p88p8N8�8W8888888p88 592500 1; N N - 592500 J O M M O N m �, O 592000 p N a 592000 .n J J O N N O M 591500 m rn J N N J � N p N J d _ - 591500 _ O N OPJ J N N O N N J O 591000' Mo J ry -� N J N 591000 N J NO J J J N r N 590500 m N -j �' p -J 590500 m O o o e ? 590000 No � 590000 a z N N O < oU N E 589500 J N - o-589500 CO o d 8 589000 N N CN N 589000 J NO CD 588500 - N 588500 O t 588000 rn N N7 588000 %> m J 587500 co O d o o N 587500 N J 587000 CNEt J J 0- 587000 7 \ 586500- CO ry J u� 0 586500 0 lCG N� (VIA J N� _J N IL o N 586000 -j � J 0 586000 m N m Q O O 0 J N w `p J a 585500,J _ J 585500 o d o _ w �m p CD o a.\y. 585000 J N a-- 585000 m a rn CD c� y W 584500 O ,, ry 584500kc a J T 3 C - o �, n � _ _ N 584000 � �� g y 583500 N C rg o sSsS to m Sf Of O J J N O O N 583500 y yy L' H� fro N J J R W 583000 0 Qo m 583000 W LO N N m 582500 OJ J 582500 O J 582000 J Ln � 0 582000 c o _N CD J J 581500 d N n J 581500 o d N V 581000p 2jJ 581000 Q p C4 o N q $ 580500' o -j 3r Q 580500 M J J m o a s800oo' a o N 7 J J 580000 CO N d9N NN N O . d N c° a o S 579500 S p Cl) N 7 579500 2mN A2 ry J J J a 0. S a o 579000 o 1 N J m - cNv 579000 whi . J a -,J a N 3 d h 578500 N N N 578500 578000' N N o J J N 578000 CD 577500 N J 577500 c � m A IL 577000 CO o 577000 CN 576500 : o o m a 576500 N 1 � Q O 576000 N 576000 J -- (V _-.... - O O O O O O O O O O O O O O pa0 0 O O O_ O O O ONl ODD W On � LLn] � Qm m m m ao w ao ao ao m w m m m n n n n n n n (Uilljsn 00L) 2ui43josl r 00Al MIR �nKW �O� �� N ;•N l+v\jNhy� Vv\1N •�.• Z\\\\ C„i(\fN H., ;2i x El 1 A i g yyq�� aaaga� $ga g��l,Zn��2e ?8Y4ss€$u Loepp, Victoria T (DOA) From: Thompson, Jacob <Jacob.Thompson@BP.com> Sent: Thursday, October 20, 2016 1:15 PM To: Loepp, Victoria T (DOA) Cc: Lastufka, Joseph N; Allen, Kenneth W Subject: RE: PBU L-200A(PTD 216-125) Attachments: L-200A PTD Final REV1.docx Victoria, The minimum LOT will be 12.1 ppg EMW to give a 25 bbl kick tolerance (please refer to pg. 6). The original PTD was missing our evaluation method for determining TOC in the 7-5/8" casing annuls. I have amended the PTD and attached a new version. I have added a USIT log to the logging requirements section as well as the operational summary. I have also added another change to the logging requirements. The original logging program called for Neu/Den logs in the 9-7/8" hole section. It is likely that these logs may not be needed since the L-200A sidetrack is being drilled so close to the existing L-200 laterals. I have changed the Neu/Den to be contingent upon further evaluation. All of the changes have been highlighted for your reference. Let me know if you have any questions and thanks for catching that mistake. Kind Regards, Jacob Thompson BP Alaska Rotary Drilling Engineer Cell: (907) 854-4377 Office: (907) 564-5579 From: Loepp, Victoria T (DOA) [mailto:victoria.loepp@alaska.gov] Sent: Thursday, October 20, 2016 8:38 AM To: Thompson, Jacob Subject: PBU L-200A(PTD 216-125) Jacob, In step 14, what is the minimum LOT? Since this well will be fracture stimulated, what are your plans for cement evaluation of the intermediate? Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loepp(a)alaska.gov 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 THm- 4-1116'C8K ! VYEL.LtEJtQ = T 1' F4C �ACiUATOR - BAKHd PRE -RIG OKEl E EV OF. ELEV Kam'' 20a CCOPD 114 �163x Able = 96` @ 11569' t !OM= D= 7515, Datum N0= 4400' SS 1 O 314' CSG 45. SN, L Minimum ID = 3.813- @ 2174' 4-1J2" HES X_ NIPPLE j 7-518' x 9-78- TOC ;^-f 58W RA TAG {-698T SW D=3-95W jFAJLnCROP SLB, D = 3 9S8' f 41r1 TBG, 12 BN, 13CRSD VAM TOP 725Q' 0158 bpf, D= 3.958- - _j�V TAG 7270' 4-12' TOG, 126Y L-80 ST-#L - 9' .0152 bpf, D - 3.958- 5.12'X4-IQ-X0,D=3930' 7301' BAKBt HOOK F141vC�i �-' 77315' w 1 L3 NON-SEALNG L9t D - 3 71'i I APSEO LEW CAN NOT PASS BY +7315 (SEEN W D.H.VICEO) (12714112) `RA TAG]- L.- 7 5/8' x ss yr BI42 zXP LTP. D = 4.94' �-j 733s' [S•w-X412'XO, D-3 sii-w H Udi BAKER HOOK HANGER 7419' w/ L 1 NON-SEALNG L E Lt D- 3 71' PERFORATION SIEi11tARY RB' LOG- ANGLEAl TOPFEJ+. Note: Refer to Roductlon 08 for historical pert data SIZE SPF NIH7VAL oprWSW DATE 412' SLTD OBs 7392 13000 ../)-... 02/18104 4-12' SLTD OBb 7497 12944 O _- - 02112AT4 4rr - 1SLID OBd 78ro 13008 O 02N4M SAFETY NOTES: WELL ANGLE > 701 @ 6602' -4-12- CHROME 76G"-LE M @ 7315' LS COLLAPSED. CAN NOT PASS TMW WITH ANY TOOLS. 98T 10'J4'TA MPOWCXX(AR _381FIL t..ec i c-r..e.rm c ST MD Lt1l�-TYPE VLV (ATOi FORT--T pg1E 6 3448 T361 ?60 KBG2 QA? (�( 0 11104/155 3565 260 KBG2 DW BK 0 jO7Ml 111211091 415313 3433 58 KBG2 DW BK 0 1 3 5490 i 3498 56 ' KBG2 DMY OK 0 11121/09 2 6645�4068� 69 KBG2 QM7 8K 0 J1121709 1 6888 4157 69 KBG2 E6PfY SK 07I03111 7051' 12 BKR ChD SLDNG SIY, 13.11 t 708T � 7. 5!_6' X 4.112' BKR FT�A PKR, D = 3.875 J (E7122' - 412' FES X W. D = 3.81 ' -- 7122' -�4 t/2 PX PLl1G (11I0511 S) 7193' �--�1 irI' FFS X FP D = 3 813' 727T MS.7S BKR SEAL STEM (SEALS FFMDVM D= 4.83' �� 7282' 7-518' X 4112- BKR ZXP LTP r rnEBK D = 5.7S0' L2 (018a) rise iErr nlrxx�wss _ _ _ _ _ 7 _ _ 7320 7331' OBa R3TD 13013' 7315' - 13044' 8-374' OBa LATERAL, D = 3.958' 7388 4-17YSDLE SHOE D=3.958' i t I foBb Lw 11APDOW 64` Li (U-Bb) 4 7424'_7435, •--------------- cwfrs4r;mm�=spa (oe R86�iCi I y lmr 7419' - 12988' 8 3!4' OBb LATERAL, ID = 3.96W IrZ- sa.A L srgF, D= 3.958' IQ* X41Q'XO, D-3,OW' � 1 v 7-5 8 CSG 29. . L-80 OTC-M D= 6.87T 7877 I I IL-2W l: 7572 - 13052' 6-3J4' OBd LATERAL, D = 3 958' _ 0Bd �rBfD �—{� 13050' DATE REV BY - ODANB4I5 DATE REV BY----- 02122M4 NOES OW INAL COMPLETION 06726/1S TFA/JLD Pll..iIDROCK CATCHER (O&MIS) 11125IOO 616 TBYADETRD_K RNO _ 1 CATCHFR(04071 12=15 CJO(11I((4111/5O) SU_tWUDGV LSFTPXPG0409112 S115j ------ M10112 JPKIAD GLV GO (WWI2) 12/1015 TJD RtE-RKi cmr � 12J18J12 FT FOOfF7 RIXXCATCHFW_ fEAJ(12/14112) --�------�--1 OV15113 GJf3 Ac SET PACKCATGtETR(12131112) \HELL L 200 P~ W 2040010 (020) (030) ARW 50-W9-23191-00(60X61) SEC 34, T12K RI I C 2567" rSL A 1575 r EL OP Explora8on (Alaska) L-2O0A PTD 13 9/19/2016 Davies, Stephen F (DOA) From: Thompson, Jacob <Jacob.Thompson@BP.com> Sent: Wednesday, October 05, 2016 4:06 PM To: Davies, Stephen F (DOA); Lastufka, Joseph N Subject: RE: Directional Survey L-200A Attachments: L-200A ST PROPOSED REV 3 2016-5-10.pdf Steve, Sorry for the mistake. The correct depth for the window will be around—3,000'. I've attached a PDF of the schematic which will hopefully be more clear. Let me know if you have any other questions. Thanks, Jacob Thompson BP Alaska Rotary Drilling Engineer Cell: (907) 854-4377 Office: (907) 564-5579 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Wednesday, October 05, 2016 2:57 PM To: Lastufka, Joseph N; Thompson, Jacob Subject: RE: Directional Survey L-200A Joe, Jacob: I'm reviewing the Permit to Drill application for PBU L-200A, and I have a question. On the Permit to Drill application form and in the proposed directional survey, the kick-off point is listed at 3000' MD. But on the schematic wellbore diagram for the proposed L-200A well (which, incidentally, is small, blurry, and somewhat hard to read without a magnifying glass), the depth of the whipstock is listed as 3690' and the window is listed at 3690'-3700'. Which depths are correct? Could BP please provide a legible copy of the wellbore diagram? Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies(Walaska.gov. From: Lastufka, Joseph N[mailto:Joseph.Lastufl<a@bp.coml Sent: Monday, October 03, 2016 8:56 AM Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Wednesday, October 05, 2016 2:57 PM To: 'Lastufka, Joseph N';jacob.thompson@bp.com Subject: RE: Directional Survey L-200A Joe, Jacob: I'm reviewing the Permit to Drill application for PBU L-200A, and I have a question. On the Permit to Drill application form and in the proposed directional survey, the kick-off point is listed at 3000' MD. But on the schematic wellbore diagram for the proposed L-200A well (which, incidentally, is small, blurry, and somewhat hard to read without a magnifying glass), the depth of the whipstock is listed as 3690' and the window is listed at 3690'-3700'. Which depths are correct? Could BP please provide a legible copy of the wellbore diagram? Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Lastufka, Joseph N [mailto:Joseph.Lastufka@bp.com] Sent: Monday, October 03, 2016 8:56 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov>; Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> Subject: Directional Survey L-200A Steve, This Permit to Drill will be delivered this afternoon. Please let me know if you need any additional information. Thanks, Joe Well: Name: PBU L-200A —Data Input V Loepp <== Data Input muo welgni (ppg) I a.bu I — Data Input Weak point or LOT - Measured depth (ft) Weak point or LOT True vertical depth (ft) Weak point or LOT - Hole angle (deg) Weak point or LOT - Hole size (in) Weak point pressure or LOT - EMW (ppg) 3,000' — Data Input — Data Input — Data Input — Data Input — Data Input 2,226' 60.00 10.750" 12.10 Zone of interest - Measured depth (ft) Zone of interest - True vertical depth (ft) Zone of interest - Hole angle (deg) Zone of interest - Hole size (in) Zone of interest - Pore pressure EMW (ppg) 8,383' — Data Input — Data Input — Data Input — Data Input — Data Input 4,320' 60.00 9.875" 10.12 — Data Input tsortom note assernmy uu (In) ti.u" <_= Data Input Bottom hole assembly length (ft) 200' <_= Data Input Drill pipe OD (in) 5.500" <== Data Input BHA annular vol. @ zone of interest (bbl/ft) 0.0326 No DP annular vol. @ zone of interest (bbl/ft) 0.0653 DP annular vol. A weak point (bbl/ft) 0.0829 Weak point pressure (psi): PIo 1,401 psi Weak point pressure - Safety margin: Pmax Pmax EMW 1,401 psi 12.10 ppg Max anticipated formation pressure (psi): Pf C,; ,,,� Psi Weak Pt to Zone of Interest distance (ND ft): OH (TVD) 2,094' Weak Pt to Zone of Interest distance (MD ft): OH (MD) 5, 383' Maximum influx height at the bit (TVD ft): H {TVD) 432' Maximum influx height at the bit (MD ft): H {MD) 865' Calc. volume of (H) around BHA: Calc. volume of (H) around drill pipe: Calc. volume that H equals @ initial shut in: V1bha V1dp V1 6.5 bbl 43.4 bbl 49.9 bbl Calc. vol. that H equals @ weak point (MD ft): VWp 71.7 bbl Ca1c. volume of Vwp @ initial shut in: V2 44.1 bbl Kick Tolerance: V2 44.1 bbl TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: i� Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: POOL: K44L 24 '��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 No. , API No. 50- - - - (If last two digits 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 samples 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, SCHRADER BLUF OIL - 64013 PTD#:2161250 Company BP EXPLORATION (ALASKA) INC. Initial Class/Type Well Name: PRUDHOE BAY UN ORIN L-200A Program DEV Well bore seg DEV / PEND GeoArea 890 Unit 11650 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes Entire Well lies within ADL0028239. 3 Unique well name and number Yes 4 Well located in a defined pool Yes PRUDHOE BAY, SCHRADER BLUFF OIL —640135, governed by CO 505E 5 Well located proper distance from drilling unit boundary Yes Rule 1: Spacing units shall be a minimum of 10 acres. The Schrader Bluff Oil Pool shall not be opened 6 Well located proper distance from other wells Yes in any well closer than 500' to an external boundary where ownership changes. 7 Sufficient acreage available in drilling unit Yes Well conforms to CO 505B, Rule 1. 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes SFD 10/5/2016 13 Can permit be approved before 15-day wait Yes 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 18 Conductor string provided NA Conductor set in PBU L-200 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in PBU L-200 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons Yes Productive interval will be completed with intermediate casing, cemented and perforated 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved Yes PTD 204-001, Sundry 316-508, PTD 204-002, Sundry 316-507, PTD 204-003, Sundry 316-506 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures except existing L-200 laterals 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure is 2300 psig(9.62 ppg EMW); will drill w/ 9.3-10.2 ppg EMW VTL 10/12/2016 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 1840 psig; will test BOPS to 3500 psig 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 H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No L-Pad is an H2S site. H2S measures are required. Geology 36 Data presented on potential overpressure zones Yes Planned mud weight (9.3 — 10.5 ppg) appears adequate to control the operator's forecast of most likely Appr Date 37 Seismic analysis of shallow gas zones NA pore pressures (9.6 ppg) in the operator's geologic prognosis. No abnormally geo-pressured strata are SFD 10/5/2016 38 Seabed condition survey (if off -shore) NA anticipated. 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Engineering Public L-Pad wells have a history of shallow gas and hydrates in the SV22, SV3, and UG4A intervals. L-Pad wells also have a history of Commissioner: Date: Commissioner: Date / om Date encountering troublesome coals while drilling and tripping through the Ugnu formation. Both are discussed in the Drilling Critical � 1�A-257-jV i4Its Issues section on page 10. SFD