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Home My WebLink About2018-04-06_318-154STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEDED APR 0 6 2018 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 21 Repair Well ❑ Ope on shul0own ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Chan 13gr/a(l�ay-�p Plug for Rednll ❑ Perforate New Pool ❑ Reenter Susp Well ❑ Alter Casing ❑ Other ❑ 2. Operator Name: BP Exploration (Alaska), Inc 4. Current Well Class: Exploratory ❑ Development 0 5. Permit to Drill Number: 217-006 3. Address: P.O. Box 196612 Anchorage, AK 99519-6612Slretigrephic ❑ Service ❑ e. API Number: 50.029-23043-60-00 7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? 8. Well Name and Number: Will planned perforations requirea spacing exception? Yes ❑ No ❑ PBU L-11BL1 9. Property Designation (Lease Number): 10. Field/Pools: ADL 028239 PRUDHOE BAY. PRUDHOE OIL 11, PRESENT WELL CONDITION SUMMARY Total Depth MD (8): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12780 6686 12761 6686 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 78 20" 31-109 31-109 1490 470 Surface 3265 7-5/8" 30-3295 30-2622 6890 / 8180 4790/5120 Intermediate Production 8703 5-1 /2" x 3-1/2" 27-8730 27-6506 7000 / 10160 4990/10530 Liner 4108 2-3/8" 8662 - 12770 6439-6686 11200 11780 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 1 11748- 12753 6659 - 6685 3-1/2" 9.2# 25-8481 Packers and SSSV Type: No Packer Packers and SSSV MD (ft) and TVD (ft): No Packer No SSSV installed No SSSV Installed 12. Attachments: Proposal Summary 10 Wellbore Schematic M 13, Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Slratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: May 15, 2018 15. Well Status after proposed work: Oil ® 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: Wages, David be deviated from without prior written approval. Contact Email: David.WagesMbp.com Authorized Name: Wages, David Contact Phone: 907.564.5669 Authorized Title: Well piterventions Engineer // ,./ Authorized Signature: V� Date: � j �}( COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: S13— '!�r q 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 10-003 Revised 04/2017 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 DAJ C who being duly sworn states: 1. My name is David Wages. I am 18 years of age or older and 1 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 -1 18L1 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 April 5'", 2018, the Notice of Operations was sent to all owners, landowners, surface owners and operators within a one-half mile radius of the current or proposed wellbore trajectory of the Well. The Notice of Operations included: a. A statement that upon request a complete copy of the Application for Sundry Approvals is available from BPXA; b. BPXA's contact information. Signed this 51h day of April, 2018. STATE OF ALASKA THIRD JUDICIAL DISTRICT -6 '� (Signature) Subscribel and sworn to or affirmedA G before me at hyi4Ca Y� {� on the 7—Aday of ` i , 20 E isska ic ftft dheimion Expires: 3.20.20 Sjg�ature of Officer' Mql r /I Title of Offider L-11861.1 Fracture Stimulation Intervention Engineer Tyson Shriver (907) 564-4133 Intervention Engineer David Wages (907) 564-5669 Objective Perform a ball drop three stage fracture stimulation on the newly drilled coil sidetrack to increase well's PI and off -take. Procedural Steps Slickline with Fullbore Assist 1. Set a retrievable bridge plug in the tubing 2. Pull DGLV from Station #2 and set a circulation valve 3. Circulate well with 9.8 ppg brine and leave a 500' freeze protect in the tubing and inner annulus 4. Pull circulation valve and set a DGLV S. MIT -T to 4500 psi with 0 psi on IA 6. MIT -IA to 4500 psi with 2500 psi on tubing 7. Pull retrievable bridge plug from tubing and drift to deviation 8. Set a LTP in deployment sleeve Special Projects with Fullbore Assist 9. Rig up tree -saver for fracturing operations 10. Execute three fracture stimulation with the following pressure limits: Maximum Anticipated Treating Pressure: 6600 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: 3600 psi Treating Line Test Pressure: 8600 psi Maximum Anticipated Rate: 22 bpm OA Pressure: Monitor and maintain open to atmosphere Pane 1 of 2 Coiled Tubing 11. Perform a fill cleanout to TD of the well post stimulation Slickline 12.Install a generic GLV design Well Testers 13. Flow well back post stimulation to ensure solids are at a manageable level for facilities to handle and conduct a post frac well test Paae 2 of 2 Date: April 51", 2018 Subject: L-1181_1 Fracture Stimulation From: Tyson Shriver— Wells Engineer, Alaska e: Tyson.Shrlyer(n1bp.com o: 907.564.4133 c: 406.690.6385 David Wages — Wells Engineer, Alaska e: David.Waees bp.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 L -118L1 in the Kuparuk reservoir of the Prudhoe Bay Unit. Well L-1181.1 is a coiled tubing drilling sidetrack that was drilled March 2018. The well is an undulating lateral (^'4000') through the Kuparuk C sands that is expected to be fracture stimulated. This is a cementless 2-3/8" completion with three ball drop frac sleeves installed. A ball drop completion was chosen to help decrease cost & time and improve efficiency of fracturing operations as compared to a plug and pert completion. The fracs are planned to connect all C - sands to increase well productivity. BP is applying for a three -stage fracture stimulation of L -118L1. 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 04/05/2018: 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). N �C 2 t �lA. 3Y C_ Y T J111 k � v ( X - -ZG? <nA'j << y ^ y y - L-naa L-teb L.2ilt — 1iBF�-- --��- � y r �-fBY�'Qj4l TyNI➢if IT f o - =Do • L -118U Fracs L-ttBLt — Weft WMM Mnrile of L -118L1 urcn: wes, Uei6. emslf•e m>Awnea W eoxn �•9�x ®:eet by -118L1 L-1181.1 Pmducbw Interval 1r Nve Mer 0L OL -11811 I/2 %file Buffer MAP 1 BP 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 Well Name Well [lasslficarinn well I L -UTA I Development I Oil Producer Gas Lift I L -02A Development Abandoned L-02AP61 Development Plugged Back For Redrill vel Development Oil Producer Shut -In vegged Development Plugged Back For Redrill vel Development Oil Producer Shut -In ve Development Suspended vegged Development "L-03APB1Development Plugged Back For Redrill Service Water Injector Injecting Development Oil Producer Gas Lift Development Oil Producer Gas Lift Development Oil Producer Gas Lift Development Plugged Back For Redrill L-102PB2 Development Plugged Back For Redrill L-103 Service Water Injector Injecting L-104 Development Oil Producer Gas Lift L-105 Service Water Injector Injecting L-106 Development Oil Producer Shut -In L-107 Development Oil Producer Gas Lift L-108 Service Miscible Injector Shut -In L-109 Service Water Injector Injecting L-110 Development Oil Producer Shut -In L-111 Service Water Injector Injecting L-112 Development Oil Producer Shut -In L-114 Development Abandoned L -114A Development Oil Producer Shut -In L-115 Service Water Injector Injecting L-116 Development Oil Producer Gas Lift L-117 Service Water Injector Injecting L-118 Development Oil Producer Shut -In L-119 Service Water Injector Injecting L-120 Development Oil Producer Gas Lift L-121 Development Abandoned L -121A Development Oil Producer Shut -In L-122 Development Oil Producer Gas Lift L-123 Service Miscible Injector Shut -In L-123PB1 Development Plugged Back For Redrill L-124 Development Oil Producer Gas Lift L -124P61 Development Plugged Back For Redrill L -124P82 Development Plugged Back For Redrill vMPlugged l Producer Gas Lift vel Well vegged Back For Redrill ML-20IL3PBI vel Well ve Well vegged Back For Redrill Well Name Well Classification Well Status L-200 Development Oil Producer Shut -In L-20OLl Development Oil Well L-2001_2 Development Oil Well L-219 Service Water Injector Shut -In L-220 Service Water Injector Shut -In L-221 Service Water Injector Shut -In L-222 I Service I Water Injector Injecting L-223 Service Miscible Injector Shut -In L-250 Development Oil Producer Gas Lift L-25OLl Development Oil Producer Gas Lift Well Name Well Classification well status L-216 Service Water Injector Injecting L-217 Service Miscible Injector Shut -In L-218 Service Water Injector Shut -In L-2501_2 Development Oil Producer Gas Lift L-250PBI Development Plugged Back For Redrill L-50 Development Oil Producer Shut -In L-50PB1 Development Plugged Back For Redrill NWEl-01 Exploratory Abandoned V-04 Development Oil Producer Gas Lift Sections 3-4— Exemption for Freshwater Aquifers (20 AAC 25.283, a, 3-4): Well L-1181_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 L -118L1 (L-118) was spudded 03/22/2003. A 9-7/8" hole was drilled to 3310' MD where 7-5/8", 29.7#, L-80 / 5-95, BTC / NSCC casing was run (casing shoe at 3295' MD, 2622' TVD) and cemented in place with 293 bbls of Permafrost L lead cement slurry (10.7 ppg) and 41 bbis of 15.8 ppg Premium Class G tail cement. During cement displacement, approximately 50 bbls of good cement were seen back to surface. The 9-7/8" casing was successfully pressure tested to 3500 psi for 30 minutes. Float collar, shoe and 20' of new formation were drilled out with a 6-3/4" bit to 3330' MD where a leak off test (LOT) was performed with 9.7 ppg mud (675 psi surface pressure, 2642' TVD, 14.6 ppg EMW). A 6-3/4" production hole was drilled from 3330' to 8980' MD where a combination of 3-1/2", 9.2#, L-80, IBT / EUE / NSCT / TC -II / BTC x 5-1/2", 15.5#, L-80, BTC casing was run (casing shoe at 8969' MD, 6743' TVD) and cemented in place. The casing was cemented with 62 bbis of 12.5 ppg Silica Lite lead cement and 24 bbls of 15.8 ppg Class G premium cement. No losses were noted during cementing and plug bumped on calculated volume. Pressure was bled off the casing and floats held. The completion assembly consisting of 3-1/2", 9.3#, L-80 IBT tubing was run to 8481' MD. Corrosion inhibited seawater was reverse circulated into the IA and tubing was stabbed -15' into the polished bore receptacle at 8469' MD (6251' TVD). Pressure tested tubing and 3-1/2" production liner to 4000 psi for 30 minutes. On 12/31/2017 coiled tubing performed a cement packer repair where 6 bbls of 15.8 ppg cement were circulated into the IA leaving estimated top of cement at 7950' MD (5748' TVD). L-1181.1 kicked -off in the existing parent bore perfs and was directionally drilled to 12,780' MD (6686' TVD) undulating through the Kuparuk sands. An uncemented 2-3/8", 4.7#, L-80, TH511 liner was run consisting of three ball drop frac sleeves. 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—Tubine and Vrnd,,M.n raai..o u.e.....e re..:.... Date Tubing Pressure (psi) Production Casing Differential Pressure Pressure (psi) (psi) TBD 4500 0 4500 TBD 2500 4500 2000 : I 1r i.uumg will oe pressure testea to 45uu psi aitterential which is greater than 110% max differential during stimulation per 20 AAC 25.283, b. 7600 psi (max tbg pressure) — 3600 psi (IA casing pressure) = 4000 psi (differential while stimulating) 4000 psi (differential) x 1.1= 4400 psi (110% max differential pressure while stimulating) Section 8 — Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 8): Proposed Wellbore Schematic --—— RC acrlwTOR= BaiURc ice. ELEV � 76.9 BF. aEV = 52.03' 1fOP= 3001 Max Anyle = 101' g JMD DRAFT Minimum ID =1.375" @ 12753' 2-318" NS FRAC SLEEVE `FST TOC N A 02131I171�'-V 7" E51R•CSG-1550,1-Mn=4950•_I-{., 8468• 7-3B' FRAr Of1RT GI ccvcc Di SEAT 4. ACTlY1LSIZE OfC DATE TYPE 8 7688' t2r 2-318' C 9331' Onium NDS 12257 JMD DRAFT Minimum ID =1.375" @ 12753' 2-318" NS FRAC SLEEVE `FST TOC N A 02131I171�'-V 7" E51R•CSG-1550,1-Mn=4950•_I-{., 8468• 7-3B' FRAr Of1RT GI ccvcc PERFORATION SUMMARY JULOG: SWDVISION D-NON03129103 ANGLEAT 101 10'® 8728 8 I 8726-8776 I O L-11! LI L-118 ti L-1 1 B SAiETYNOTW: WELL ANGLE> 70° @ 1895'. MAx DL5:/97°@8l50'. ST Di SEAT 4. ACTlY1LSIZE OfC DATE TYPE 8 7688' t2r 2-318' C 03131118 21 1 '.ACT 2-'318' C 00!3111919 1030 2 1130' 2-518• C ON31118 PERFORATION SUMMARY JULOG: SWDVISION D-NON03129103 ANGLEAT 101 10'® 8728 8 I 8726-8776 I O L-11! LI L-118 ti L-1 1 B SAiETYNOTW: WELL ANGLE> 70° @ 1895'. MAx DL5:/97°@8l50'. ST M) TVD DPI TYPE VLV UTRI VURT DATE 4 4786 3502 51 1030 2 DW M 0 00113!16 3 6385 4196 51 103& 2 DW M 0 09113116 2 7671 5486 23 KBG-2 DIM M 0 04H3H6 1 8381 6166 14 KBI 101M M 0 11r2W11 •••�� -•+••• •mow �Wcv�mwn.°do Wvna.0 of Itl[i FAIW I asBs• s•1T2• H1Bs x rp. o=2e1s- 8564• X NPEUO LOGO®ON 11/1783 SEAL BORE O = 2.25' MILLOUT WINDOW (L-118 L1) 8730' - 8736' 647EMJUNal-HOLCEMMIGNIS O41O1N3MPLDrIM 046HH8RACK(LA78L1(041W18 _.-. "_ ' - ..�...........�.�.....� auric...... Wcn L-aa0u. L-116 L1 BOPEALIS UIr %CLL: L-110 L1 FB6R No: 2174)06 AR No: 504M9-23043.00, 60 BVE1clsIeraOon (Alaska) Table 2—Tubular Ratings Size/Name Weight Grade Connection ID Burst, psi Collapse, psi 7-5/8" Surface Casing 29.7# L-80 BTC / NSCC 6.875" 6890 / 8180 4790/5120 5-1/2" Production Casing 15.5# L-80 BTC -M 4.950" 7000 4990 3-1/2" Production Liner 9.2# L-80 IBT/ NSCT/ E U E 2.992" 10,160 10,530 / BTC / TC -11 2-3/8" Production Liner 4.7# L-80 HYD511 1.995" 11,200 11,780 3-1/2" Production Tubing 9.2# L-80 IBT 2.992" 10,160 10,530 Wellhead Wellhead: FMC manufactured wellhead, rated to 5,000 psi. • Tubing head adaptor: 11" 5,000 psi x 3-1/8" 5,000 psi • Tubing Spool: 11" 5,000 psi w/ 2-1/16" side outlets • Casing Spool: 11" 5,000 psi w/ 2-1/16" side outlet Tree: Cameron 3-1/8" 5,000 psi Tree -saver Top connection is 3" 1502 hammer union which will be crossed over to 4" 1002 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—Geological Information Formation MD Top MD Bottom TVDss Top TVDss Bottom TVD Thickness Frac Grad Lithological Desc. Top HRZ (parent) 8373 8578 6081 6280 199 —0.83 Shale Top Kalubik (parent) 8578 8724 6280 6424 144 —0.83 Shale TKUPC4(parent) 8724 8732 6424 6431 7 0.63 SS KOP 8730.0 - 6429 - - SS TKOE 8732 8740 6431 6439 8 0.63 SS TKOD 8740 8757 6439 6456 16 0.63 SS TKC3C 8757 8779 6456 6476 20 0.63 SS TKOB 8779 8802 6476 6494 19 0.63 SS TKC3A 8802 8811 6494 6501 7 0.63 SS TKC2E 8811 8819 6501 6507 6 0.63 SS TKC2D 8819 8828 6507 6513 6 0.63 SS TKC2C 8828 8837 6513 6519 6 TKC2B 8837 8844 6519 6523 4 TKC2A 8844 8854 6523 6528 6 TKC1C 8854 8871 6528 6537 8 =0.63SS TKC1B 8871 8899 6537 6548 11 TKC1A 8899 - 6548 - - Invert 8950 6556 SS Invert TKC1A 9021 6549 0.63 SS InvertTKC1B 9089 9021 6538 6549 11 0.63 SS Invert TKC1C 9131 9089 6530 6538 8 0.63 SS Invert TKC2A 9155 9131 6526 6530 4 0.63 SS Invert TKC2B 9188 9155 6521 6526 6 0.63 SS InvertTEX 9231 9188 6513 6521 8 0.63 SS Invert TKC2D 9260 9231 6508 6513 5 0.63 SS Invert TKC2E 9293 9260 6502 6508 6 0.63 SS Invert TKC3A 9324 9293 6496 6502 6 0.63 SS InvertTKC3B 9420 9324 6481 6496 15 0.63 SS Invert TEE 9990 9420 6487 6481 -6 0.63 SS Revert TKC3C 11478 - 6565 - - 0.63 SS TD 12780 6609 - SS Top B Silts (Parent) - 6559 6721 162 0.7 Silts Top A Interval (Projected) 6721 6814 93 0.72 Silts Top Miluveach (Projected) 6814 980 —0.84 Shale Within the reservoir section, formation tops were picked from GR logs and cuttings while drilling L-1181-1. 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 wells. Sections 10-11— Location of Wells, Mechanical Information and Faults (20 AAC 25.283, a, 30-11): Area of Review N 3 A fi LI4Yi"rv.'`; 1,500 C 15C9 FEEL by L -118L1 0 flat 2: Fault Analysis • _1190P R. TM1�.PPgS L-ir9Ll �49rLrn990 �L-11:9L1 MI: Mt91b L. m1e 01 L -a La TS^J Fyry W1V�r1 _ 119L1 P2GRtpn intern Ari U1. SP' O= 9L11::11118Y 'hNt U,,6 02asone malrl rwe b.: epm a Yynpo: MAP 1 - I --1-1IS nICO VI nevlew lurown ouumel or wells ana taus transecting the confining zones within one-half mile of L -118L1 wellbore trajectory (red line). Also depicted are the planned fracture locations with "200' half-length hydraulic fractures (blue lines) in the main stress orientation (-N-5). w Y C 3 N 3 v di L O m c O C Y m L cu w a c 0 CL m 3 cc v O v Q OJ L C L 3 3 L V m N L w C N E v m c - m x Y N .n m A C d Y E 3 G 3 E w a L Y_ N r0+ N 7 O 00 m m o UL O N LL L 7 a " n a0+ +L.+ N v •� c ,c 3 p Y O O N E a c C6 y a O A w O E v cu m Lon rn 3 m `L- a 0 v h E o 3 v Y m •N n N 3 w m L J N On CLCL V U CL p m Z L y 0 00,1 CL oo Y n E ,(� o ON 00 N N u0 d m 0 \ N 0 U C L N N O E m 3 m ao m n V y W 3 c 0 a0 v a 0 ` 0 O N C d y C u N L to N N v N W u a N m� a E a O 3 o Y v, 0 CL c o 3 Z. 3�o r E H c '6 Y On 'O Y O L00 O cu 0 u v ? u 0 C' n E 0 -0 a p p_ u i o 3 vc u IE Y o£ Q N v J v O �° Y O c u E 3 0 u c 0. O u a n m m a v u o0 v m n 3 o L 3 OD Q p c cu 3 c -0„' 0 c~ N O N m E O 7 u N 0 c 00) cu u 0 m 3” 0 u en u o o vi 0 L \ O X y b0 c H q N nw a u u c c E ti 0 0 u v cO �' 0000 w I� C '0 ^ u NO O M o - n y 3 Y Y Y Y Q \ n N -0 •3 N '' v 3 ,-i n Y O a Y n Y N\ N u L a u u m 0 O a F' E E LL E C vi rn O L c L ri Y O ., N w •3 NN 0 3 0 0 a C C m N a cu N O/ O O/ W CL U O 'O 00 n= Y y m �o m SEL m S Y O O Y O O O c n od) ENE ca L to E 3 w 0 3 w o u ° o ` L C y Y Y C X 0 O a N Y U0) L a L Y C n a C E 3 v `1 U L N N nJ U 00 » _m no o u On v 3 2 CL .010 N v L Y w 0 L L N 1p m 0 O a o p N c l7 v t"1 Y a ^ D N O a GJ N u yNj 0/ E E m J aL+ d J u U c - .n m n u , V m o m m o •� Y �Y 8 a " oa o, & ao j a ti c =a o u c - .n m V m m tY •� Y �Y 8 a " a� O & ao j a ti c =a o u r `oo E a E a E E V U V E n O p p n m o m- .� V e A o A O c - .n m V m - E _ E E a V V O F 9 j j V ti c u o u r `oo o _ E - J - E m m O p p n m o m E V e O m E E u s 60 � o s C m m q G Y s o - n o e b0 1p m m V c - .n m V m V V V C y O O 'F u u y ti c u o u n r `oo o _ 3 - - _ 3 z L FA p BP's technical analysis based on seismic, well and other subsurface information available indicates that there are 6 mapped faults that transect the Kuparuk interval and enter the confining zone within the %: radius of the production and confining zone trajectory for L-1181-1. 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 gradient of -0.83 psi/ft. Thickness and fracture pressure for the confining layer is discussed in Section 9. No faults were crossed when the L-1181-1 was drilled. L -118L1 drilled close to the presumed tip out of Fault 1, but was not seen drilling. Losses were taken from start and were assumed to be losses to the parent wellbore (that was fracture stimulated). Total losses were 2318 bbls. Fault #2-7 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 Upward Fault Termination Zone Fault #2 40' (DTW) Colville Fault #3 10' (DTE) Colville Fault #4 80-150' (DTE) Schrader Bluff Fault #5 100-120' (DTN) Colville Fault #6 200' (DTE) Ugnu The location of Frac sleeve #1 of the production hole was drilled -30 degrees to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated at the frac sleeve at 11748' MD. With a fracture initiating at the sleeves and a modelled 200' half-length, 1000' of standoff exist between the tip of the fracture and Fault #5 and 1100' of standoff exist between the tip of the fracture and Fault #6. The location of Frac sleeve #2 of the production hole was drilled —50 degrees to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated at the frac sleeve at 12250' MD. With a fracture initiating at the sleeves and a modelled 200' half-length, 650' of standoff exist between the tip of the fracture and Fault #5. The location of Frac sleeve #3 of the production hole was drilled —35 degrees to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated at the frac sleeve at 12752' MD. With a fracture initiating at the sleeves and a modelled 200' half-length, 500' of standoff exist between the tip of the fracture and Fault #5. Table 4—Standoff Values. Frac #1 11748' MD Fault 5 1000' Frac #1 11748' MD Fault 6 1100' Frac #2 12250' MD Fault 5 650' Frac #3 12752'MD Fault 5 500' Section 12 - Hydraulic Fracture Program (20 AAC 25.283, a, 12): Fracture Stimulation Pump Schedule STEP STAGE AVERAGE COMMENTS FLUID PUMP CF DIRTY VOLUME DIRTY VOLUME PROPPANT # # PPA TYPE RATE RATE STAGE CUM STAGE CUM STAGE CUM SIZE BPM BPM BBL BBL GAL GAL LBS LBS 1 Prime u pressure tesfreezeProt 5 5.0 10 10 420 420 2 Injection test WF128 2020.0 100 110 4,200 4,620 3 Shut down to isolate CPS 0.0 110 0 4,620 4 Calibration Test YF128FIexD 30 30.0 200 310 8,400 13,020 6 Flush WF128 30 30.0 91 401 3,831 16,851 _ HARD SHUTDOWN, MONITOR PRESSURE TILL CLOSURE. FLUID PUMP CF DIRTY VOLUME DIRTY VOLUME PROPPANT STEP STAGE AVERAGE COMMENTS TYPE RATE RATE STAGE CUM STAGE CUM STAGE CUM SIZE # # PPA BPM (BPM) BBL BBL GAL GAL LBS LBS 6 1 PAD YF128FIexD 30 30.0 125 526 5,250 22,101 0 0 7-1 0.5 FLAT YF128FIexD 3029.4 50 576 2,100 24,201 1,027 1,027 16/30 Sand 8 1 PAD YF128FIexD 30 30.0 125 701 5,250 29,451 0 7,027 9 1 1 FLAT YF728FIexD 30 28.7 50 751 2,100 31351 3,038 16/20 C -Lite 10 1 1 RAMP YF128FIexD 30 287 38 789 1, 96 33,14 ,011 1,528 4,567 16/20 C -Lite 11 1 2RAMP YF128FlexD 30 27.6 38 827 1,596 34,743 2,933 7,499 16/20 C -Lite 12 7 3 RAMP YF728FIexD 30 26.5 38 865 1,596 36,339 4,227 11,726 16120 -C-Lite 13 1 4 RAMP YF728FIexD 30 25.5 38 903 1,596 37,935 5,424 17,150 16120 C -Lite 14 1 5 RAMP YF128FIexD 30 24.6 38 947 1,596 39, 31 6,534 23,685 16/20 C -Lite 15 1 6 RAMP YF128FI0xD 30 23.7 38 979 1,596 41,127 7,567 31,252 16/20 C -Lite 16 1 7 RAMP YF128FIexD 30 22.9 38 1,017 1,596 42,723 8,530 39,782 78/20 C{8e 17 1 8 RAMP YF128FIexD 30 22.2 38 1,055 1,596 44,319 9.,430 49,212 16120 C -Lite 18 1 8 FLAT YF728FIexD 30 22.2 50 1,105 2,100 46,419 12,408 61,620 16/20 C -Lite 19 1 9 FLAT YF728FIexD 30 21.5 50 1,155 2,100 48,519 13,517 75,137 16/20 CBL 20 7 70 FLAT YF728FIex0 30 20.8 80 1,235 3,360 51,879 23,294 98,437 16/20 CBL 21 1 Dro Ball DISPLACE YF128FIexD 30 30.0 20 1255 840 52,719 0 98,431 22 2 DISPLACE YF128FIex 30 30.0 49 1,305 ,070 54,789 98,431 23 2 DISPLACE YF128FIexD 12 12.0 20 1,325 840 55,629 0 98,431 24 2 PAD YF128FIexD 30 30.0 36 1,340 1,500 56,289 0 98,431 25 2 0.5 FLAT YF728FIexD 30 29.4 50 7 390 2,700 58,389 1,027 99,458 16130 and 26 2 PAD YF128FIexD 30 30.0 125 1,515 5,2 0 63,639 0 99,458 27 2 1 FLAT YF128FIexD 30 28.7 50 1,565 2,100 65,739 2,011 101,469 16120 C -Lite 28 2 1 RAMP YF728FIexD 30 28.7 38 1,603 1,596 67,335 1,528 102,998 76/20 C -Lite 29 2 2 RAMP YF728FIexD 30 27.6 38 1 641 1,596 68,937 2,933 105,930 16/20 C -Lite 30 2 3 RAMP YF128FIex) 30 26.5 38 1,679 1,596 70,527 4,227 710,157 16120 C -Lite 31-2 4 RAMP YF1241 w 30 25.5 38 1,717 1,596 72,123 5,424 115, 81 16/20 C -Lite 32 2 5 RAMP YF128FIexD 30 24.6 38 1755 1,596 7 ,719 6,534 122,116 76120 C -Lite 33 2 6 RAMP YF728FIexD 30 23.7 38 7,793 1,596 75,315 7, 67 129,683 76120 C -Lite 4 2 7 RAMP YF126FIexD 30 22.9 38 1,837 1,59 76,9 1 8,530 138,213 16120 -Lite 35 2 8 RAMP YF128 IexD 30 22.2 38 1,869 1, 96 78,507 9,43 147,643 1620 C -Lite 36 2 8 FLAT YF128FIexO 30 22.2 50 1,919 2,100 80,607 12,408 180,051 76120 C -Lite 37 2 9 FLAT YF128FIexD 30 21.5 50 1,969 2,100 82,707 13,517 173,568 76120 CBL 38 2 10 FLAT YF128FIexD 30 20.8 80 21049 3,360 86,067 23,294 196,862 16/20 BL 3 2 Dro Ball DISPLACE YF128FIexD 30 30.0 20 2,069 840 86,907 0 196,862 40 3 DISPLACE YF128FIexD 30 30.0 51 2,120 2,151 89,059 0 196,862 41 3 DISPLACE YF128FIexD 72 72.0 20 2140 840 9,899 0 196,862 42 3 PAD YF128FIexD 30 30.0 34 2,754 7,419 90,477 0 196,862 43 3 O.S FLAT -PAD YF128FIexD 30 29.4 50 2,204 2,7 0 92,577 1,02 197,889 16/30 and 44 3 YF128FIexD 30 30.0 125 2,329 5,250 97,827 0 197,889 45 3 7 FLAT YF128FIexD 30 28.7 50 2,379 2,100 99,927 2,011 199,900 16/20 C -Lite 46 3 1 RAMP YF128FIexD 30 28.7 38 2417 1,596 101,523 1,528 201,429 16/20 C -Lite 47 3 2 RAMP YF128FIexD 30 27.6 38 2,455 1,596 103,119 2,933 204,361 16120 C -Lite 48 3 3 RAMP YF128FIexD 30 26.5 38 2,493 1,596 104, 15 4,227 208,588 16/20 C•Lite 49 3 4 RAMP YF128FIex0 30 25.5 38 2,531 1,596 106,317 5,424 214,012 16120 C -Lite 50 3 5 RAMP YF128FIexD 30 24.6 38 2569 -T-5-96107 907 6,534 220,547;16/20 C -Lite 51 3 6 RAMP YF728FIexD 30 23.7 38 2,607 1596 109503 7,567 228,1140 C-Lite523 7 RAMP YF128FIexD 30 22.9 38 2,645 1, 6 711,0998,53 236,6440 C-Lite53 3 8 RAMP YF728FIexD 30 22.2 38 2,663 1,596 112,695 9,4 0 246,0740 Cute54 3 6 FLAT YF128FIex0 30 22.2 50 2733 2,100 114,795 12,408 258,4820 C -Lite YF128FIexu 30 21.5 50 2,783 2,100 116,89 13,517271,99920 L3YF128FIexu 30 20.8 86 2,863 3, 60 120,255 23,294295,293 BL 57 3 FLUSH YF128FIexD 30 30.0 20 2,883 840 121,095 0 295,293 58 3 FLUSH WF128 30 30.0 37 2,920 1,538 122,633 0 295,293 59 3 FLUSH FreezeProt 12 12.0 27 2,947 1,750 123,783 0 295,293 TOTALS 2987 295,293 Chemical Disclosure `W` 1`1'°'AlmaAlma'JY'eIH: Schlumberger 1_1181I eas #/ ,Wd: Sole: Alma Caunty,V .nslr: Case: Diztlasme TYp P.eAOb We Competed: 5)1f7018 Date Prepared: SlIV20131155 "1 Report b: RPT -53996 MMMMM�211 8103 a.. ... ,• Surfxtas _ "•a +7�06a0 115.0 GM 8reaiet - c : 700Dfr1 40A Lb _ &Mdw - . ipiD al 610.0Ib Gd6r81iEmt 3,120.0 Lb Croaa� : S 25SA Oat SOR YBtbloor _-_115-0 OxYR22bTIeaD^NFtffi Lttp28 �ICbyiwNW _ AOus Sai WS526� 23x0Addme ISA Lb Badsriude .. - OD -0 1b O A'oPPiKABes me' : --111s 3,100.0 Lb Amuamr 60A GalD Y'Y1=c - -:xtTabaes _ ]09.0 Lb - -0 rn>: :_-._emsaboms -:,;. SOO.O ID n(LmaumYmmb@Se Te ACb.abae rtiR9D96 eMiluPmcYpn aTwu.a,eaasra.maY�aW�Y'n< _._ - Wrter(IncWft Mi, ,Vater Supplied by * — Ceram¢ materalz and'.vasr, dxvni�ib - --z4 %'- 1400604 Quark, crjv a, Ine S ica GZ % 67-tl'1 ?-kytlrovy-H,W.�4trimethyetharmmmuYm dhloride <7 % 1313331 Vlexi - - <O % Ethylene Gl�eal —_ _ <OA % TZ7-Sq-0 Diammpneum eroAdis ,.hare Gal qg _ 674" Prupan2-cl _— 229898-017-_ 2-Propenoic aciq polymer-rvith wtlium phcVfimxe _ _-- _— 6SM4" Acoholz, dl-16zeconAare, efkoqlatetl <0.1 % 111-762 2-buc <O % — - 34390-01-1 Ethorylxad Cil AlmYeo <0-1A % 1303-964 Scdau Tetnbo Deahydrate -0.01% 25038-724 VIIObdeoe chbrideJmeOiyppyPay. cppolYmea _ - _. _ 1310-73-2 Sodium 6813E-335 5h Ah'php_ 7647-145 - Sodaen chkaide _ <OA196 <0A1 % 91053-39-3 Oixamxews eamh, ol!mn.ad <0.01 %.._. _ 1161T-8 _ - —_ bis-2a>eakac acid <OAl % 1OD43-52-4 _ _ _ CMd. Chloride _ <OAl 1L24Ni lhulecanol -0.01 ]D3T7463 _ mnitrat� -0.0037631$69 1:1 N_ 26172-554 7786-363 5-dibro-z-meth zl.isothiaxdol-34ne -0.001 % Mag_rreslum chloride -0.001 % 1 "9K Magnesium zaicate hytate(to,) — -0.001% 111-466 2,2'bsytllethaipi (impurilyj _ -0.001 % _ 004840 9 tetra 0u -0.00196 695585-15-z Oiutan -0.001 % 125ao587-0_ O't'dn gwn -0.001 % 2682-261 z-tnNnyL2l.isotlriu4i3ar _. ---- - <o.ao 96 14/64461 Cristobalhe <0.0001 % 7447.467 _ Potassium ch u de i <OA001 % 127-042 Aca0c.d '.sah -0.0001% 64137 Aoebc acid (imWriNY -0.0001 % e Senbmercgw Sold UsW br avbPbracen Abrke e�pmevsien. tr Page- 1 / 2 Anticipated Treating Pressures Table 5—Anticipated Pressures Maximum Anticipated Treating Pressure: 6600 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. 3600 psi Treating Line Test Pressure: 8600 psi Maximum Anticipated Rate: 22 bpm Sand Requirement: 182,000 lbs 16/20 Carbo Lite 110,000 lbs 16/20 CarboBond Lite Minimum Water Requirements: 3100 bbls (pump schedule: 2700 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: Frac. Top Sleeve (ftMD) Base Sleeve (ftMD) TopYDftth Sleeveands (ftTVDSS)VDSS) Top Depth Base C Sands Frac Height (ftTVDSS) (ft TVD) Frac Half - LengthLocaiton (ft)#1 11,748 11,750 6582536 6663 127 —Inn#2 12,250 12,252 6600548 6682#3 12,752 12,754 6609559 6693 134 200 were caicuiated using modeling software. Maximum Anticipated Treating Pressure: 6600 psi The abo ve valu E41 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 and friction pressure minus hydrostatic results in a surface pressure of 6600 psi at the time of flush. 4200 psi (closure) + 500 psi (net) + 6325 psi (friction) - 4425 psi (hydrostatic) = 6600 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 the thickness of the C -sands. 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 ^200 ft.