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Home My WebLink About2018-02-26_318-078STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 EGEIVEU FF8 2 6 2018 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 Repair -Well ❑ ��Q]p Pf[ �-�tt'^11jj��,, h "'''"""'-' Ah Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Ar)pS,�6=r.un w 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 215-218 3, Address: P.O. Box 196612 Anchorage, AK 99519-6612 Stretigrephic ❑ Service ❑ 6. qpl Number: 50-029-23094-80-00 7. If perforating: 8. Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes ❑ No 0 PBU S-113131-1 9, Property Designation (Lease Number): 10. Field/Pools: ADL 028257. 028258 8 028259 PRUDHOE BAY, AURORA OIL (Undefined) 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): 15368 6709 15368 6709 None None Casing Length Size MD TVD Buret Collapse Structural Conductor 80 20" 33-113 33-113 1490 470 Surface 5553 10-3/4" 33-5586 33-3370 5210 2480 Intermediate 1 13008 1 7" 31 -13039 31-6767 7240 5410 Production Liner 2530 2-3/8" 12838-15368 6588-6709 11200 1 11780 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 15240- 1 6714 - 6709 3-1/2" 9.2# L-80 29-12942 Packers and SSSV Type: 4-1/2" Baker S-3 Penn Packer Packers and SSSV MD (ft) and TVD (ft): 12884 / 6629 No SSSV Installed No SSSV Installed 12. Attachments: Proposal Summary 0 Wellbore Schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: March 20, 2018 15. Well Status after proposed work: Oil 0 WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Shriver, Tyson be deviated from without prior written approval. Contact Email: Tyson.Shriveratip.com Authorized Name: Shriver, Tyson Contact Phone: +1 9075644133 Authorized Title: Well Intervention Engine r Authorized Signature: L — Date: 2 /93 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: APPROVED BYTHE Approved by: COMMISSIONER COMMISSION Date: ORIGINAL Submit Form and Form 10403 Revised D4/2017 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 J 17 ✓4101 ✓f/ who being duly sworn states: 1. My name is Tyson Shriver. I am 18 years of age or older and I have personal knowledge of the facts stated in this affidavit. 2. I am employed as an Engineer by BP Exploration (Alaska) Inc. (`BPXA") and I am familiar with the Application for Sundry Approvals to stimulate the S -I 13BL1 Well (the "Well") by hydraulic fracturing as defined in 20 AAC 25.283(m). 3. Pursuant to 20 AAC 25.283(1), BPXA prepared a Notice of Operations regarding the Well, a true copy of which is attached to this Affidavit as Attachment 1 ("Notice of Operations"). 4. On February 21, 20 ,18 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 2151 day of February, 2018. (Signat (e) STATE OF ALASKA THIRD JUDICIAL DISTRICT Subscribed and sworn to or affirmed before me atT k on the4r 1 day of X 120S. Slate of Alaska Notary Public Lorrie L. Jordheim W Commission Expires: 3.20-20 'gnature of Officer Title of Officer Date: February 2111, 2018 Subject: 5-113BL1 Fracture Stimulation From: Tyson Shriver— Wells Engineer, Alaska e: Tvson.Shriver@bp.com o: 907.564.4133 c: 406.690.6385 David Wages— Wells Engineer, Alaska e: David.Waaes@bo.com o: 907.564.5669 c: 713.380.9836 To: Chris Wallace Attached is BP's proposal and supporting documentation to perform a fracture stimulation on well 5-11361_1 (PTD# 202- 143-0) in the Kuparuk reservoir of the Prudhoe Bay Unit. Well 5-11361.1 is a coiled tubing drilling sidetrack that was completed in October 2016. The well is an undulating lateral through the Kuparuk C sands that is expected to be fracture stimulated in the toe, mid-lateral and heel. The base plan is to perform a toe and mid-lateral fracture stimulation now and return at a later date (later than a year) to execute the heel stage. However, access in the liner is currently restricted due to suspected scale build-up. A coiled tubing intervention has been planned to clean out the 2-3/8" liner to TD. If the intervention is successful in gaining liner access all the way to TD, the toe and mid-lateral frac's will be executed. If coiled tubing is unsuccessful in cleaning out to TD, the plan will be to perform the mid-lateral (accessible at this time) and heel fracs. BP is applying for all three stages knowing that, at most, only two of the three possible stages will be performed. Please direct questions or comments to Tyson Shriver or David Wages. Section 1— Affidavit of Notification (20 AAC 25.283, a, 1): All owners, landowners, surface owners and operators within %: mile radius of the current wellbore trajectory have been provided a notice of operations on 02/21/2018: ConocoPhillips ExxonMobil Chevron Department of Natural Resources Section 2 — Plat Identifying Wells (20 AAC 25.283, a, 2): Plat Figure 1: Plat showing well location (highlighted in red) and all wells that penetrate within one-half mile of the current wellbore trajectory and fracturing interval (brown & orange outline). s $rna� m r m _ SboA �6q3 8 2Q h f, J St1G big � h S o <(r s'11aPet � ? 5126 g-, h - N r; s-ZBB_-?-4 N m + PO v N y' Y N N u+ 9 N { N )p8 "UJ , { N 5'>�29A11 ti h T -FB 109 S-1131311 Pmc Localron VaRc Ua6. Goodin-ainrenae M BPu ®Feet S113BLi - Deviation Survey Wells within 12 mile of S-113BL1 "a��'y ' Abp S-113BL1 S-11361_1 Production tntemal 112 Mile Buffe 0 v Rix is L. -A. ners S-11381_1 12 Mile Buller MAP 1 - 6P Leases Figure 1: Plat showing well location (highlighted in red) and all wells that penetrate within one-half mile of the current wellbore trajectory and fracturing interval (brown & orange outline). Well Name Well Classification Well Status S-01 Development Abandoned S -01A Development Abandoned S -01B Development Abandoned S -01C Development Oil Producer Shut -In 5-02 Development Abandoned S -02A Development Oil Producer Gas Lift S-02AL1 Development Oil Well S-02AL1PB1 Development Plugged Back For Redrill S-02AP81 Service Plugged Back For Redrill 5-03 Development Oil Producer Gas Lift 5-04 Service Miscible Injector Shut -In 5-05 Development Abandoned S -OSA Service Water Injector Injecting S-0SAPB1 Service Plugged Back For Redrill S-06 Service Water Injector Shut -In 5-07 Development Abandoned S -07A Development Oil Producer Shut -In 5-08 Development Abandoned S -08A Development Abandoned S -OSB Development Oil Producer Shut -In 5-09 Service Abandoned S -09A Service Miscible Injector Shut -In S-09APB1 Service Plugged Back For Redrill S-09APB2 Service Plugged Back For Redrill S-09APB3 Service Plugged Back For Redrill 5-10 Development Abandoned 5-100 Development Oil Producer Shut -In 5-101 Service Water Injector Injecting 5-1011381 Development Plugged Back For Redrill 5-102 Development Oil Producer Gas Lift 5-102L1 Development Abandoned 5-1021-11>81 Development Plugged Back For Redrill 5-1021381 Development Plugged Back For Redrill 5-103 Development Oil Producer Gas Lift 5-104 Service Water Injector Injecting 5-105 Development Oil Producer Gas Lift 5-106 Development Oil Producer Shut -In 5-106PBI Development Plugged Back For Redrill 5-107 Service Water Injector Shut -In 5-108 Development Suspended 5-109 Development Oil Producer Shut -In 5-109PB3 Development Plugged Back For Redrill S -10A Development Suspended Well Name Well Classification Well Status 5-110 Service Suspended 5-110A Service Abandoned 5-110B Service Water Injector Injecting 5-111 Service Water Injector Injecting 5-111PB1 Service Plugged Back For Redrill S-111PB2 Service Plugged Back For Redrill 5-112 Service Water Injector Injecting 5-1121_3 Service Water And Gas Injector 5-112LSPB1 Service Plugged Back For Redrill 5-1121113132 Service Plugged Back For Redrill 5-113 Development Abandoned 5-113A Development Abandoned 5-1138 Development Oil Producer Shut -In 5-113811 Development Oil Producer Shut -In 5-114 Development Abandoned 5-114A Service Water Injector Shut -In 5-115 Development Oil Producer Gas Lift 5-116 Service Abandoned 5-116A Service Miscible Injector Shut -In 5-116APB1 Service Plugged Back For Redrill 5-116APB2 Service Plugged Back For Redrill 5-117 Development Oil Producer Shut -In 5-118 Development Oil Producer Shut -In 5-119 Development Oil Producer Gas Lift S -11A Service Abandoned S -11B Service Miscible Injector Shut -In 5-12 Development Abandoned 5-120 Service Water Injector Injecting 5-121 Development Oil Producer Gas Lift 5-1211381 Development Plugged Back For Redrill 5-122 Development Oil Producer Gas Lift 5-122PB1 Development Plugged Back For Redrill 5-122PB2 Development Plugged Back For Redrill 5-1221383 Development Plugged Back For Redrill 5-123 Service Water Injector Shut -In 5-124 Service Miscible Injector Shut -In 5-125 I Development Oil Producer Gas Lift 5-125PB1 Development Plugged Back For Redrill 5-126 Service Water Injector Shut -In 5-128 Service Water Injector Injecting 5-128PB1 Service Plugged Back For Redrill 5-1281382 Service Plugged Back For Redrill 5-129 Development Oil Producer Gas Lift Well Name Well Classification Well Status Well Name Well Classification Well status S-10APB3 Development Plugged Back For Redrill S-30APB2 Development Plugged Back For Redrill 5-11 Service Abandoned S -12B Development Oil Producer Gas Lift 5-13 Development Abandoned 5-134 Service Miscible Injector Shut -In 5-135 Development Oil Producer Gas Lift 5-135PB1 Development Plugged Back For Redrill 5-135PB2 Development Plugged Back For Redrill S -13A Development Oil Producer Shut -In S-13APB3 Development Plugged Back For Redrill 5-14 Service Abandoned 5-14A Service Suspended 5-15 Service Water Injector Shut -In S-15PB3 Service Plugged Back For Redrill 5-16 Development Oil Producer Shut -In 5-161383 Development Plugged Back For Redrill 5-17 Development Abandoned S -17A Development Abandoned S-17AL1 Development Abandoned S-17AL1PB1 Development Plugged Back For Redrill S-17APB3 Development Plugged Back For Redrill S -17B Development Abandoned S -17C Development Oil Producer Shut -In S-17CPB1 Development Plugged Back For Redrill S-17CPB2 Development Plugged Back For Redrill 5-18 Development Abandoned S -18A Development Abandoned S -18B Development Oil Producer Shut -In 5-19 Development Oil Producer Shut -In 5-20 Service Abandoned 5-200 Development Oil Producer Shut -In 5-200A Development Oil Producer Shut -In 5-200PB1 Development Plugged Back For Redrill 5-201 Development Oil Producer Shut -In 5-201PB1 Development Plugged Back For Redrill S -20A Service Water Injector Injecting 5-21 Development Oil Producer Gas Lift 5-213 Development Abandoned 5-213A Development Oil Producer Gas Lift 5-213AL1 Development Oil Producer Flowing 5-213AL1-01 Development Oil Producer Flowing 5-213AL2 Development Oil Well 5-129PB1 Development Plugged Back For Redrill 5-129PB2 Development Plugged Back For Redrill 5-12A Development Abandoned S -22A Development Abandoned S -22B Service Water Injector Injecting 5-23 Development Oil Producer Shut -In 5-24 Development Abandoned S -24A Service Abandoned S-24APB1 Service Plugged Back For Redrill S -24B Service Water Injector Shut -In 5-25 Development Abandoned S -25A Service Water Injector Injecting S-25APB1 Service Plugged Back For Redrill 5-26 Development Oil Producer Shut -In 5-27 Development Abandoned S -27A Development Abandoned S-27AP31 Development Plugged Back For Redrill S -27B Development Oil Producer Shut -In 5-28 Development Abandoned 5-28A Development Abandoned 5-288 Development Oil Producer Shut -In S-28BPB1 Development Plugged Back For Redrill 5-29 Development Abandoned S -29A Service Water Injector Shut -In S-29AL3 Service Water Injector Shut -In 5-30 Development Oil Producer Shut -In 5-31 Development Abandoned S -31A Service Water Injector Injecting 5-32 Development Abandoned 5-32A Development Oil Producer Shut -In 5-33 Development Oil Producer Gas Lift 5-34 Service Water Injector Injecting 5-35 Development Oil Producer Shut -In 5-36 Development Oil Producer Shut -In 5-37 Development Abandoned S -37A Development Oil Producer Gas Lift S-37APB1 Development Plugged Back For Redrill 5-38 Development Oil Producer Shut -In 5-40 Development Abandoned 5-400 Service Abandoned 5-400A Service Water Injector Shut -In 5-401 Service Water Injector Shut -In 5-401PB1 Service Plugged Back For Redrill Well Name Well Classification Well Status S-213AL3 Development Oil Well S-215 Service Water Injector Injecting S-216 Service Water Injector Shut -In S-217 Service Water Injector Shut -In 5-218 Service Miscible Injector Shut -In S-22 Development Abandoned 5-42 Development Abandoned S -42A Development Oil Producer Gas Lift S-42PB1 Service Plugged Back For Redrill S-43 Development Oil Producer Shut -In 5-431_1 Development Oil Producer Gas Lift 5-44 Development Abandoned S -44A Development Oil Producer Gas Lift 5-44L1 Development Abandoned S-44LiP81 Development Plugged Back For Redrill 5-504 Service Water Injector Shut -In V-200 Exploratory Abandoned Well Name Well Classification Well Status S -40A Development Oil Producer Shut -In S-41 Development Abandoned S -41A Service Water Injector Injecting S-41AL1 Development Oil Producer Gas Lift S -41L1 Development Abandoned 5-41PB3 I Service I Plugged Back For Redrill Sections 3-4 — Exemption for Freshwater Aquifers (20 AAC 25.283, a, 3-4): Well S-113131_1 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 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 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. Sections 5-6— Detailed Casing and Cement Information (20 AAC 25.283, a, 5-6A): The parent bore of 5-113BL1 (5-1138) was spudded 07/08/2002. Surface location for 5-113BL1 (PTD # 215-218) is as follows: 4542' FSL, 4496' FEL, Sec. 35, T12N, R12E, UM. A 13-1/2" hole was drilled to 5600' MD where 10-3/4", 45.5#, L-80, BTC casing was run (casing shoe at 5587' MD, 3371' TVD) and cemented in place with 620 bbls of "G"ArcticSet 3 - Lite lead cement slurry and 156 bbls of 15.8 ppg Class G tail cement. During cement displacement, approximately 30 bbls of cement were seen back to surface. The 10-3/4" casing was successfully pressure tested to 3500 psi for 30 minutes. Float collar, shoe and 20' of new formation were drilled out with a 9-7/8" bit to 5620' MD where a leak off test (LOT) was performed with 9.4 ppg mud (1220 psi surface pressure, 3371' TVD, 16.35 ppg EMW). A 9-7/8" production hole was drilled from 5620' to 14,440' MD for reservoir evaluation (5-113). A 105 bbl, 15.8 ppg cement plug was laid in from 14,440'— 13,440' MD as per program. No losses were encountered while spotting the P&A cement plug. After lying in cement, a balanced kick-off plug was spotted from 10,575'— 10,150' MD for sidetracking to another BH location for additional formation evaluation. A 9-7/8" production hole was sidetracked from 10,095'- 12,640' MD (5-113A). Cement was laid in from 12,640'— 11,840' as per program. Above the P&A plug, a balanced kick- off plug was spotted from 10,025'— 9,600' MD for sidetracking 5-1138. The top of the kick-off plug was dressed off to 9,700' MD and a 9-7/8" production hole was directionally drilled to TD at 13,515' MD where 7", 26#, L-80, BTC casing was run (casing shoe at 13,490' MD, 7169' TVD) and cemented in place (5-1138). The casing was cemented with 105 bbls, 15.8 Class G premium cement. No losses were noted during cementing and plug bumped on calculated volume. The completion assembly consisting of 3-1/2", 9.3#, L-80 IBT tubing was run to 12,944' MD with the production packer set at 12,884' MD (6559' TVDss). 5-113BL1 kicked -off in the existing perfs and was directionally drilled to 15,368' MD (6639' TVDss) undulating through the Kuparuk sands. An uncemented 2-3/8", 4.7#, L-80, TH511 liner was run consisting of both solid (12,838'MD — 15,240' MD) and slotted liner (15,240'-15,368' MD). Since this is a coiled tubing drilling sidetrack, the existing production tubing is being utilized for production. Section 7 — Pressure Testing (20 AAC 25.283, a, 7): Table 1—Tubina and Production Casine Pressure Testine Date Tubing Pressure (psi) Production Casing Pressure (psi) Differential Pressure (psi) 07/22/2017 4662 0 4662 07/22/2017 2540 4694 2154 *The tubing was most recently pressure tested to 4662 psi differential which is greater than 110% max differential during stimulation per 20 AAC 25.283, b. 7600 psi (max tbg pressure) — 3500 psi (IA casing pressure) = 4100 psi (differential while stimulating) 4100 psi (differential) x 1.1= 4510 psi (110% max differential pressure while stimulating) Section 8 — Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 8): Wellbore Schematic S-1138 SAFETYNOTES 3-12"CHROME NIPPLES WELL L1 ANGLE> 70" @ 5009' MAX DLS: 37" @ 13175' 10-31MCSG,45.50,L-80,D=9950" 55g'/'- —� VaU1FAD= 13-5V5MFW 18 GAS LFT WANOPELS - KB. f3EV = 70.33 EF ELVV = 70.3,10 F. R = 37.49 OP= — 700 bx Angle = 113' Q 1336V sNm AD- 6700 stM1vD= 6700 SS S-1138 SAFETYNOTES 3-12"CHROME NIPPLES WELL L1 ANGLE> 70" @ 5009' MAX DLS: 37" @ 13175' 10-31MCSG,45.50,L-80,D=9950" 55g'/'- —� 18 GAS LFT WANOPELS p Minimum ID = 1.92" 12838' G 2.63" DEPLOYMENT SLEEVE TOPCF CFMLTar SF*ATH 128{8' - 12942' STI MD I ND 1084 TYPE I VLV [LATCfi[PM1 LV 4 16713 3800 69 M G I DIM 01 0 3 11147 $508 6 C, 2 W DIM W0 2 12712 6460 33 LING DIM RK 0 1 12802 6557 30 MMG DW RK D 07r 07r 0711 07r 12898' 2.63" DH7-0V MBJr SIHVE D= 1T 12882 }12"IBXNP,°•2.613' BENNO CT LNP 12694' 7' X 4-12' BAKER S3 WR D = 3 875" FEFIFORAT17N StRAARY FEF LOG: BAKER RRVI ON 10'15/16 ANGLEATTOPFHFI NA Note: fuer M Rod Von DB for hslomal part Osla SQE SPF NTBNALI Opn15w I SLUT I SOT S,113B 2-1? 6 13°74 - "I S 0712&62 0911&16 2-L7 6 13018 -130381 S 1110&02 OW&I6 2-tr2" 8 113(011-13000j S 0629114 0911&16 011 1 13 09 MD411 O 160rtIO S -113B L1 I SLTDI 15240 -153681 SLOT 110/13/161 1 12936' H}12'1ESXNP,D=2613.1 FLOW COLLAR D= 1.930') 12971 ELOW R,LIG Y2 (2.54' FLOW COLLAR D - 1.930') MLLOIfT V?DOW ($-11381Q 13039' - 13044' SOLD L -M Tfeli. FLOW COLLAR D- 1.930') I�-�F jl W rNA IAG] X 5' LNt, 12B45'- 15240' 95- 2 -ale' SLTD LRR _I5240'-15368'2 5240' - 15368' 4'70'L-008511' S -113B L1 .W30 bpf, D _ 1.gas- AURORA 05'AU ORA UNIT NAIL S-113BL1 FIEIW W: "2152180 An W: SO -029-23094.02160 SEC 35, T12N R12F 738' FP18 78Y FW1_ B+Fspbmtion IAWka) Figure 2—Proposed wellbore schematic for well S-113BL1. Table 2—Tubular Ratings Size/Name Weight Grade Connection ID Burst, psi Collapse, psi 10-3/4" Surface 45.5# L-80 BTC 9.950" 5,210 2,480 7" Production Casing 26# L-80 BTC 6.276" 7,240 5,410 3-1/2" Production Tubing 9.2# L-80 IBT 2.992' 10,160 10,530 2-3/8" Production Liner (Solid) 4.7# L-80 H511 1.995" 11,200 11,780 2-3/8" Production Liner (Slotted) 4.7# L-80 H511 1.995' N/A N/A Wellhead Wellhead: FMC manufactured wellhead, rated to 5,000 psi. • Tubing head adaptor: 13-5/8" 5,000 psi x4-1/16" 5,000 psi • Tubing Spool: 13-5/8" 5,000 psi w/ 2-1/16" side outlets • Casing Spool: 13-5/8" 5,000 psi w/ 2-1/16" side outlets Tree: Cameron 4-1/16" 5,000 psi Tree -saver Top connection is 3" 1502 hammer union which will be crossed over to 4" 1002 in order to connect to the treating iron. Bottom connection is 7-1/16" The tree -saver is rated to 10,000 psi. Figure 3—Diagram of tree -saver to be used during fracture stimulation. Section 9 - Geological Frac Information (20 AAC 25.283, a, 9): Table 3-Geoloeical Information Formation MD Top MD Bottom TVDss Top TVDss Bottom TVD Thickness Frac Grad Lithological Desc. Top HRZ 12,784 13,000 6471 6662 191 -0.83 Shale (Upper confining zone) Top Kalubik 13,000 13,017 6662 6677 15 `0.83 Shale TKUP- Parent 13,017 - 6677 - - - - C4 13,017 13,026 6677 6685 8 0.63 SS C38 13,026 13,037 6685 6695 10 0.63 SS C3A 13,037 13,050 6695 6706 11 0.63 SS KOP 13,039 13,044 6697 6701 - - - C2E 13,050 13,066 6706 6720 14 0.63 SS C21) 13,066 13,085 6720 6735 15 0.63 SS C2C 13,085 13,101 6735 6747 12 0.63 SS C28 13,101 13,126 6747 6763 16 0.63 SS C2A 13,126 13,151 6763 6776 13 0.63 SS C1c 13,151 13,231 6776 6794 18 0.63 SS Invert in C1C - 13,231 - 6794 - - - c1C 13,351 13,231 6771 6794 23 0.63 SS C2B 13,408 13,351 6750 6771 21 0.63 SS C2C 13,438 13,408 6739 6750 11 0.63 SS C20 13,480 13,438 6724 6739 15 0.63 SS C2E 13,529 13,480 6708 6724 16 0.63 SS C3A 13,579 13,529 6696 6708 12 0.63 SS Revert in OB 13,719 - 6689 - - - - C3A 13,800 13,850 6690 6691 1 0.63 SS Unmapped Fault 13,850 - 6691 - - - - C2C 13,906 13,967 6697 6707 10 0.63 SS C2B 13,967 14,014 6707 6714 7 0.63 SS C2A 14,014 14,066 6714 6723 9 0.63 SS c2c 14,066 14,183 6723 6736 13 0.63 SS Invert in CIC - 14,183 - 6736 - - C1C 14,454 14,183 6721 6736 15 0.63 SS C2A 14,725 14,454 6708 6721 13 0.63 SS C2B 14,825 14,725 6697 6708 11 0.63 SS C2C 14,895 14,825 6687 6697 10 0.63 SS Unmapped Fault 14,990 - 6674 - - - C2E 15,035 14,990 6668 6674 6 0.63 SS C3A 15,165 15,035 6652 6668 16 0.63 SS TD 15,368 - 6639 - - - Miluveach - - 6801 7781 980 -084 Shale (Lower confining zone) Within the reservoir section, formation tops were picked from GR logs and cuttings while drilling 5-113BL1. The upper confining zone (HRZ) and top Kuparuk were determined from the parent wellbore logs and cuttings. Top of the lower confining Miluveach shale was projected from isopach maps of the area and thickness was determined from offset well 5-01. Sections 10-11— Location of Wells, Mechanical Information and Faults (20 AAC 25.283, a, 10-11): Area of Review Figure 4—Plat showing Area of Review of wells and faults transecting the confining zones within one-half mile of S-113BL3 wellbore trajectory (brown outline). Also depicted are the planned intervals containing "300' half-length hydraulic fractures (black lines) in the main stress orientation ("N -S). N 73 y 2000 0 Z 000www Few 3 BBC1 Foc Lw Don —SI13BLt Frac Half Lengths - 'a -I I3BL t . Dewamn Surrey 'Nd9 wirhln 112 ma &S 113BLI Prow n4ntetwal Data sources: We's '..h]:. Ccastlirre-�ainb:naa by 6Pn4 �'anigraphy. r� bp Sit 13gl1 Potf TKUP5-113 Plat 2-. Fauh.4naly;a lftduwA Inti ler Dnlr 3- 113BL1 Production lntervd V2 Atile BuiFer O 5- II3BL1 1.: Mile Bu1fe• MAP 1 �rwo. wsa IiYE: 1. �)! 6P. ries see+, f Figure 4—Plat showing Area of Review of wells and faults transecting the confining zones within one-half mile of S-113BL3 wellbore trajectory (brown outline). Also depicted are the planned intervals containing "300' half-length hydraulic fractures (black lines) in the main stress orientation ("N -S). The plat in Figure 4 shows wells and faults that transect the confining zones within a t/a mile radius of the subject well's trajectory. Based on the following assessments for each well, BP concludes that none of these wells will interfere with the containment of hydraulic fracturing fluids. 5-113: This wellbore was plugged and abandoned as per state regulations on 07/03/2002. 5-113A: This wellbore was plugged and abandoned as per state regulations on 07/07/2002. 5-113B: The rig report from 07/12/2002 indicates the 7" casing cement job was pumped according to design and no losses were noted once cement entered the 7" x Open Hole annulus. The job was pumped with 15.8 ppg cement. Seawater was used to displace the cement and plug bumped with 1,200 psi. After the plug bumped, pressure was increased to 3000 psi for 10 minutes to pressure test the casing (good test). Pressure was then bled off after the test to check the floats and they held. 5-126: The rig report from 10/30/2007 indicates the 7" casing cement job was pumped according to design and no losses were noted once cement entered the 7" x Open Hole annulus. The job consisted of 12.0 ppg lead cement and 15.8 ppg tail cement. Seawater was used to displace the cement and plug bumped with 2,400 psi. Casing was reciprocated until 9 bbls of displacement remained. Pressure was bleed off post cement job to check floats and they held. The 7" casing was subsequently pressure tested to 4000 psi for 30 minutes (good test). Well Well Type Casing Type Casing Casing Depth Hole Size Top ofKuparuk C Sand TopofCement Top ofcement Zonal Isolation (in) (MD) (NDss) (MD) (TVD.) Name Sire Cement Summa ry determination (rvDssl Reserv°ir Status Mechanical Integrity 5-113BL3 Producer Production Casing 7" 9-7/8" 13,013 6,673 11931 5908 504 sx 15.8 ppg Class"G" Calculated TOC@5,908' Cemented casing isolati ng MIT -IA to 4,694 psi T3,4,97"27 Volumetrically Packer@6,629' hydroca rbon zones (07/22/2017) 5126 Prodcuer Production Casing 7" 9-7/8" 11,473 fi,631 5,490 3,394 720sx12.Oppg Lite Crete Cement Log TOC @3,394 Cement and perforated MIT-IAto 2,700 psi 298 sx 15.8 ppg Class 'G" Packer@6,478' casing open to production (06/04/2016) * All top of cement calculations estimated volumetrically were calculated as follows: TOC = Casing/Liner Bottom MD — (Volume of Cement [bbls] _ Annular Volume [bbl/ft] X 0.7 [30% Hole Washout]) BP has formed the opinion based on seismic, logs, drilling data and other subsurface information available that there are 9 mapped faults that transect the Kuparuk interval and enter the confining zone within the''/: mile radius of the production and confining zone trajectory for 5-113131-1. Fracture gradients within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of at least 0.83 psi/ft. During pumping activities, if pressures are seen that indicate fracturing out of zone, linkage to a fault or any other event leading to loss of treating pressure, operations will be shut down immediately. Issues will be identified and dealt with accordingly prior to proceeding with any further pumping. There are two faults that are of concern while performing fracturing operations that were crossed by the 5-113BL1 production interval (Fault #1 & 2). Both Fault #1 and Fault #2 terminate upwards in the Colville. No losses were observed when Fault #1 or Fault #2 were crossed. 5-113131-1 Fault MD SSTVD THROW Fault#1 13850' 6691' 35'(DTNE) Fault #2 14990' 6674' 10' (DTSW) Fault #3-9 intersect the production interval and confining zone within the % mile radius. Their displacements, sense of throw and zone in which they terminate upwards in are given below. Faults THROW Fault Termination Zone Fault#3 200'(DTW) Sagavanirktok Fault#4 150'(DTS) Ugnu Fault #5 220' (DTSW) Schrader Bluff Fault #6 90' (DTW) Colville Fault #7 100' (DTSW) Colville Fault #8 40' (DTSW) Colville Fault #9 120' (DTE) Colville If the heel is frac'd, the solid liner will be perforated in the heel 600' MD up -hole of Fault #1 (13,850' MD) and should ensure adequate standoff between the perforations and fault for fracturing operations. The wellbore is generally drilled perpendicular to the maximum stress orientation in this area which runs N/S (100 W of N) based on a regional stress map. With this wellbore orientation, a transverse fracture will be created leaving an —600' standoff from Fault #1 assuming 300' half-length. Since this will be an open hole completion utilizing perforations, it is assumed the fracture will initiate at the perforations, 13,100-13,130' MD for the heel frac. The middle portion of production hole is drilled perpendicular to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated in perforations that will be added from 14,420-14,450' MD. With a fracture initiating at perforations and a modelled 300' half-length, 360' of standoff exist between the tip of the fracture and Fault #1 and 440' of standoff exist between the tip of the fracture and Fault #2. The toe portion of production hole is drilled perpendicular to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated within 15,150'-15,240 MD in the open hole interval with solid liner Qunction of the slotted/solid liner crossover (15,240' MD)). If the liner clean out is successful to the junction, fracture initiation will be assumed at the junction. If the hole clean out does not get to the junction, the solid liner will be perforated and the fracture initiation will be assumed at the perforations. With a fracture initiating at the junction (15,240' MD) and a modelled 300' half-length, 100' of standoff exist between the tip of the fracture and Fault #2. Expecting -300 ft fracture half -lengths; minimum stand-off from faults can be seen in Table 4—Standoff Values. Table 4—Standoff Values. Heel Frac 13,100'-13,130' MD Fault #1 600 Heel Frac 13,100'-13,130' MD Fault #6 650 Middle Frac 14,420'-14,450' MD Fault #1 360 Middle Frac 14,420'-14,450' MD Fault #2 440 Toe Frac 15,150'-15,240' MD Fault #2 100 Section 12 - Hydraulic Fracture Program (20 AAC 25.283, a, 12): Fracture Stimulation Pump Schedule STEP # STAGE # AVERAGE PPA COMMENTS FLUID TYPE PUMP RATE (BPM) CF RATE (BPM) STAGE (BBL) DIRTY VOLUME CUM STAGE (BBL) (GAL) cum (GAL) STAGE (LBS) PROPPANT CUM (LBS) SIZE 1 1 PAD YF128FIexD 20 20.0 100 453 4200 19026 0 0 0 2 1 0.5 _ PAD YF128FIexD 20 19.6 5o 503 2100 21126 1027 1,027 16120CBLNRT 3 1 PAD YF128FlexD 20 20.0 100 603 4200 25326 0 1,027 4 1 1 FLAT YF128FlexD 20 19.2 50 653 2100 27426 2011 3,038 16120 CBL NRT 5 1 2 RAMP YF128FlexD 20 18.4 43 696 1806 29232 3318 6,357 16/20 CBL NRT 6 1 3 RAMP YF128FIexD 20 177 43 739 1806 31038 4783 11,140 16/20 CBL NRT 7 1 4 RAMP YF128FIexD 20 17.0 43 782 1806 32844 6138 17,278 16/20 CBL NRT 8 1 5 RAMP _ YF128FIexD 20 16.4 43 825 1806 34650 7394 24,672 16120 CBL NRT 9 1 6 RAMP _ YF128FlexD 20 15.8 43 668 1806 36456 8563 33,235 16120 CBL NRT 10 1 7 RAMP YF128FIexD 20 15.3 43 911 1806 38262 9652 42,887 16nocBLNRT 11 1 8 RAMP YF128FIexD 20 14.8 43 954 1806 40068 10671 53,558 16/20 CBL NRT 12 1 8 FLAT YF128FIexD 20 14.8 50 1004 2100 42168 12408 65,966 16naceLNRT 13 1 9 FLAT YF128FIexD 20 14.3 50 1054 2100 44268 13517 79,483 16/20 CBL NRT 14 1 10 FLAT YF128FIexD 20 13.9 70 1124 2940 47208 20382 99,865 1612acBLwiT 18 1 FLAT WF128 20 20.0 0 1124 0 47208 0 99,865 19 2 PAD YF128FIexD 20 20.0 0 1124 0 47208 0 99,865 20 2 PAD YF128FIexD 0 0.0 0 1124 0 47208 0 99,865 21 2 PAD YF128FIexD 20 20.0 100 1224 4200 51408 0 99,865 22 2 0.5 PAD YF128FIexD 20 19.6 50 1274 2100 53508 1027 100,893 lsaocBLNRT 23 2 PAD YF128FIexD 20 20.0 100 1374 4200 57708 0 100,893 24 2 1 FLAT YF128FIexD 20 19.2 50 1424 2100 59808 2011 102,904 16/20 CBL NRT 25 2 2 RAMP YF128FIexD 20 18.4 43 1467 1806 61614 3318 106,222 16120 CBL NRT 26 2 3 RAMP YF128FIexD 20 17.7 43 1510 1806 63420 4783 111,005 16/20 CBL NRT 27 2 4 RAMP YF128FlexD 20 17.0 43 1553 1806 65226 6138 117,143 16/20 CBL NRT 28 2 5 RAMP YF128FIexD 20 16.4 43 1596 1806 67032 7394 124,537 16120 CBL NRT 29 2 6 RAMP YF128FlexD 20 15.8 43 1639 1806 68838 8563 133,100 16120 CBL NRT 30 2 7 RAMP YF128FIexD 20 15.3 43 1682 1806 70644 9652 142,752 16120 CBL NRT 31 2 8 RAMP YF128FIexD 20 14.8 43 1725 1806 72450 10671 153,423 16120 CBL NRT 32 2 9 FLAT YF128FIexD 20 14.3 50 1775 2100 74550 13517 166,941 16120 CBL NRT 33 2 10 FLAT YF128FIexD 20 13.9 50 1825 2100 76650 14559 181,499 16/20 CBL NRT 34 2 11 FLAT YF128FIexD 20 13.5 50 7875 2100 78750 15538 197,037 16/20 CBL NRT 153 4 FLUSH WF128 20 20.0 98 1973 4110 82860 197,037 154 TOTALS 4 FLUSH Freezeprotect 15 15.0 191992 1992 804 83664 197037 197,037 Anticipated Treating Pressures Table 5—Anticipated Pressures Maximum Anticipated Treating Pressure: 6700 psi Maximum Allowable Treating Pressure: 7600 psi Stagger Pump Kickouts Between: 6840 psi and 7220 psi (90% to 95% of MATP) Global Kickout: 7220 psi (95% of MATP) N2 IA Pop-off Set Pressure: 4275 psi (95% of 4500 psi MIT -IA) IA Minimum Hold Pressure: 4000 psi Treating Line Test Pressure: 8600 psi Maximum Anticipated Rate: 30 bpm Sand Requirement: 197,000Ibs 16/20 CarboBond Lite NRT Minimum Water Requirements: 2400 bbls (pump schedule: 1900 bbls) OA Pressure: Monitor and maintain open to atmosphere There are three overpressure devices that protect the surface equipment and wellbore from an overpressure event. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. 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. Frac Dimensions: TVD, feet Frac Half -Length, ft Top 6745 ^300 ft Bottom 6855 The above values were calculated using modeling software. Maximum Anticipated Treating Pressure: 6700 psi Surface pressure is calculated based on a closure pressure of -0.63 psi/ft or -4200 psi. Closure pressure plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a surface pressure of 2950 psi at the time of flush. 4200 psi (closure) + 500 psi (net) + 4950 psi (friction) - 2950 psi (hydrostatic) = 6700 psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average confining layer stress is anticipated to be -0.83 psi/ft limiting fracture height to 110 ft TVD. Fracture half-length is determined from confining layer stress as well as leak -off and formation modulus. The modeled frac is anticipated to reach a half-length of -300 ft. Chemical Disclosure /� Chem: BP a9an Aloka One `J• Wall: 511381213SU I Baser/FWd: Prudhoe Bay Sbte: Alaska Courty/Parish.: North Slope Borough C. Disdo re Type: Pm -bb We14 Completed: 3/18/2018 Pate Prepared: 2/19f2018 7 44 PM Report 10: RPT -53581 F103 ii rtaaanr 1 Gaj 1000 Ga: _ 85D Gal 1218 Breaker 1.6 ib(IWO Gal 140-0lD J475 Breaker 67 Lb/100 Gal SMA lb 1604 Crossibaw L9 Gal/ 1000 Gan 165D Gal 1891 Ct 6.3 Gal 10M Gas sw0o Gal W128FIex0-W IM %,310 QI L065 Sole kalagi 1 GWI 1000 GW 85.0 Gal L071 aw Cm4rW AV r "GaI/IODO Gal 165D QI FAM AAMM 1.2 Lbf00DQl IWD Lb U275 Ba¢xiade Ob Ib 100DQI SD Lb 6123 Adavaw 2.3 Gal/ 1000 GW MAD Gal 826-1620 ProppM ApmvariM mncarorateons 197,OWD Lb raw mm�w.u�mo-sn xe mwx: mew ma+�+.m al...minm�of.w.mmmaamrez wamaawKsnrd'en. VVStW(Indudft WxWabers lied thead' 'T7% 6"02384 Ceamit matcials and wares, ci+arniW -2196 64742.47$ Distlba¢es, pebWeum, hydrdaeatM Int <S % 9000-300 Guam -196 67481 2 'dro.'r-N,N 7Hrirreeth anamiliuwn ddorkle .2% 67.630 P r 2 -of <0.1% 131433-1 _ _ Uleate <0.1 % 68131.403 _ : cohols, UI -15 semndw , edioxytated -0-1% 7727-540 D'amnanun mole rte <0.1 % 107-21-1 Edwi-w Glycol <01% IU -76-2 x-duoryethanW <o_x % ----- - -- 34391-01-1 -- "- -- - -- - EMo,4aled Cil McD W - - <0-1 % 12989841-7_ 2-Pro_penoic add risA sod'eum sw hirm <0.1% 68131-393 Ethm VlMd Alcohol <0.1 % 25038.72E Wn kdene aHortle(rreWybuylase copoFims <0.1% -- 3310.73-2 indium hydro+dde jxnpuric/) <01 % 1303-9" So um Tebaborace Deofijodrate -MM 68153-30-0 Am+me treated xnedite ca <0.01 % 7647-144 Sodium di l.ride -0-01% 91a53-343 Diatomaceous earsh, uioned <0.01 % 11617$ but-2-enedinac acid <0.D3 % 10043-524 Calaum Chloride _ GDD1 % 11242-5 Undecanol <0.01 % 7631-869 S icon Dioxide <0A01 % 10377.60-3 Magrwsmm nitrate <0A01 % 14807-963 - - Magnesium silicate hydrate {talc) -- - - - <OMI % 26172-554 5-Nlaro-2-meth-2hisoMoxobl-3-one <0001 % 778630.3Marnpsumddoride <0A01 % 111466 2,2'-azydieNalW (inpwiry) —. <0801% 9002840 {bbaihwroathykrsa) <111.001 96 1250D5-97-0 Diutan <0.0113 % 595585-15-2 dubn <OA01 % _ 2682-204 2-me[hy62MisoNiazoF3rorrc -- - <0A01 % _ -- 127-082 Ace& add, pe a..0 dt <0.0001 % 14464461 CrWobalite <a0001 % 14808.60-7 Ouar[z CsymllMe sil"¢a <00001 % - - 744740.7 Potassium ddoride (impurity) <0.0001 % ._ _.._ 6419-7 Acetic add(mpurM} -.._.-..-0-0001% 0 dnalem 2019. U.d ba aP bpbreeen Afefke by iermusron. Page, 1 / 2 5-113BL3 Fracture Stimulation Intervention Engineer Tyson Shriver (907) 564-4133 Intervention Engineer David Wages (907) 564-5669 Objective Perform a two stage fracture stimulation on the newly drilled coil sidetrack to increase well's PI and off -take. Procedural Steps Slickline with Fullbore Assist 1. Install a liner top packer. Coiled Tubing 2. Mill scale in liner to gain access to liner / toe of well. Special Projects with Fullbore and Coiled Tubing Assist 3. Rig up tree -saver for fracturing operations 4. Execute two stage fracture stimulation with the following pressure limits: Maximum Anticipated Treating Pressure: 6700 psi Maximum Allowable Treating Pressure: 7600 psi Stagger Pump Kickouts Between: 6840 psi and 7220 psi 90% to 95% of MATP Global Kickout: 7220 psi 95% of MATP IA Pop-off Set Pressure: 4275 psi 75% of 4500 psi MIT -IA IA Minimum Hold Pressure: 4000 psi Treating Line Test Pressure: 8600 psi Maximum Anticipated Rate: 30 bpm Sand Requirement: 197,000 lbs 16/20 CarboBond Lite NRT (split between two stages) Minimum Water Requirements: 2400 bbls (pump schedule: 1900 bbls OA Pressure: Monitor and maintain open to atmosphere Coiled Tubing S. Between fracturing stages, RD tree saver, set CIBP, perforate for next stage of fracture stimulation and re -install tree saver. 6. Perform a fill cleanout to TD of the well post stimulation Slickline 7. Install a generic GLV design Well Testers 8. Flow well back post stimulation to ensure solids are at a manageable level for facilities to handle and conduct a post frac/post drill well test Pane 1 of 1