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213-202
Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: (907) 564-4891 02/09/2024 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor through 02/09/2024. Dear Mr. Rixse, Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off with cement, corrosion inhibitor in the surface casing by conductor annulus through 02/09/2024. Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement fallback during the primary surface casing by conductor cement job. The remaining void space between the top of the cement and the top of the conductor is filled with a heavier than water corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached spreadsheets include the well names, API and PTD numbers, treatment dates and volumes. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations. If you have any additional questions, please contact me at 564-4891 or oliver.sternicki@hilcorp.com. Sincerely, Oliver Sternicki Well Integrity Supervisor Hilcorp North Slope, LLC Digitally signed by Oliver Sternicki DN: cn=Oliver Sternicki, c=US, o=Hilcorp North Slope LLC, ou=PBU, email=oliver.sternicki@hilcorp.com Date: 2024.02.09 11:15:58 -09'00' Oliver Sternicki Hilcorp North Slope LLC. Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-off Report of Sundry Operations (10-404) 02/09/2024 Well Name PTD # API # Initial top of cement (ft) Vol. of cement pumped (gal) Final top of cement (ft) Cement top off date Corrosion inhibitor (gal) Corrosion inhibitor/ sealant date L-293 223020 500292374900 30 8/29/2023 S-09A 214097 500292077101 2 9/19/2023 S-102A 223058 500292297201 2 9/19/2023 S-105A 219032 500292297701 10 9/19/2023 S-109 202245 500292313500 7 9/19/2023 S-110B 213198 500292303002 35 9/19/2023 S-113B 202143 500292309402 10 9/19/2023 S-115 202230 500292313000 4 9/19/2023 S-116A 213139 500292318301 4 9/19/2023 S-117 203012 500292313700 3 9/19/2023 S-118 203200 500292318800 9 9/19/2023 S-122 205081 500292326500 5 9/19/2023 S-125 207083 500292336100 2 9/19/2023 S-126 207097 500292336300 3 9/19/2023 S-134 209083 500292341300 35 9/19/2023 S-200A 217125 500292284601 7 9/19/2023 S-202 219120 500292364700 13 9/19/2023 S-210 219057 500292363000 10 9/19/2023 S-213A 204213 500292299301 4 9/19/2023 S-215 202154 500292310700 3 9/19/2023 S-216 200197 500292298900 4 9/19/2023 S-41A 210101 500292264501 3 9/19/2023 W-16A 203100 500292204501 2 9/23/2023 W-17A 205122 500292185601 3 9/23/2023 Well Name PTD #API # Initial top of cement (ft) Vol. of cement pumped (gal) Final top of cement (ft) Cement top off date Corrosion inhibitor (gal) Corrosion inhibitor/ sealant date W-19B 210065 500292200602 8 9/23/2023 W-21A 201111 500292192901 8 9/23/2023 W-32A 202209 500292197001 4 9/23/2023 W-201 201051 500292300700 44 9/23/2023 W-202 210133 500292343400 6 9/23/2023 W-204 206158 500292333300 3 9/23/2023 W-205 203116 500292316500 3 9/23/2023 W-207 203049 500292314500 3 9/23/2023 W-211 202075 500292308000 8 9/23/2023 W-213 207051 500292335400 3 9/23/2023 W-214 207142 500292337300 10 9/23/2023 W-215 203131 500292317200 2 9/23/2023 W-223 211006 500292344000 7 9/23/2023 Z-69 212076 500292347100 2.0 27 1.5 10/24/2023 S-128 210159 500292343600 11 12/27/2023 S-135 213202 500292350800 16 12/27/2023 V-113 202216 500292312500 24 12/31/2023 V-114A 203185 500292317801 5 12/31/2023 V-122 206147 500292332800 5 12/31/2023 V-205 206180 500292333800 2 12/31/2023 V-207 208066 500292339000 8 12/31/2023 V-214 205134 500292327500 5 12/31/2023 V-215 207041 500292335100 2 12/31/2023 V-218 207040 500292335000 5 12/31/2023 V-224 208154 500292340000 16 12/31/2023 V-225 209118 500292341900 6 12/31/2023 V-01 204090 500292321000 3 1/1/2024 V-02 204077 500292320900 5 1/1/2024 V-04 206134 500292332200 5 1/1/2024 V-102 202033 500292307000 8 1/1/2024 V-104 202142 500292310300 5 1/1/2024 V-220 208020 500292338300 4 1/1/2024 S-135 213202 500292350800 16 12/27/2023 • - � 42o 2.. 'WS WELL LOG TRANSMITTAL RECEIVED .IES PROACTIVE DIACINOSTIC SERVICES, INC. MAR 11 2®1�i DATA LOGGED GCC /)4/201G, BENDER BENDER To: AOGCC Makana Bender 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and /or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Analisa Steger LR2— 1 900 Benson Blvd. Anchorage, AK 99508 uancpdcabp.com and ProActive Diagnostic Services, Inc. SCAM, APR 0 8 2-is Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 1) LeakPointTM Survey 29-Dec-15 S-135 BL/CD 50-029-23508-00 2) iYLQ� Signed : Date : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGE@MEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM D:Wchives\MasterTemplateFiles\Templates\Distribution\TransmittalSheets\BP_Transmit.docx STATE OF ALASKA "'ALASKA OIL AND GAS CONSERVATION COMMI N REPORT OF SUNDRY WELL OPERATIONS 2 6 9 4 0 1. Operations Performed Abandon 0 Plug Perforations 0 Fracture Stimulate Q Pull Tubing 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Alter Casing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Repair Well 0 Re-enter Susp Well 0 Other: 0 2. Operator Name: BP Exploration(Alaska),Inc 4. Well Class Before Work 5. Permit to Drill Number: 213-202 3. Address: P.O.Box 196612 Anchorage, Development Q Exploratory 0 AK 99519-6612 Stratigraphic 0 Service ❑ 6. API Number: 50-029-23508-00-00 7. Property Designation(Lease Number): ADL 0028261 8. Well Name and Number: AURA S-135 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pools: PRUDHOE BAY,AURORA OIL 11.Present Well Condition Summary: RECEIVED Total Depth: measured 14501 feet Plugs measured feet true vertical 6953 feet Junk measured 14039 feet FEB 16 2016 Effective Depth: measured 14042 feet Packer measured 11704 feet true vertical 6979 feet Packer true vertical 6697 feet AOGCC Casing: Length: Size: MD: TVD: Burst: /Collapse: y Structural Conductor 80 20"94#H-40 46-126 46-126 1530 520 Surface 4597 9-5/8"40#L-80 46-4643 46-3215 5750 3090 Intermediate 11947 7"26#L-80 45-11992 45-6874 7240 5410 Production Liner 2295 4-1/2"12.6#13Cr8 11819-14114 6770-6980 8430 7500 Perforation Depth: Measured depth: 11840 12102 feet 12715-13020 feet 13060-13190 feet 13190-13454 feet 13596-14042 feet 13493-13557 True vertical depth: 6783-6931 feet 6932-6918 feet 6919-6926 feet 6926-6943 feet 6952-6979 feet 6945-6949 Tubing(size,grade,measured and true vertical depth) 4-1/2"12.6#13Cr85 43-11826 43-6774 Packers and SSSV(type,measured and 4-1/2"HES TNT Perm Packer 11704 6697 true vertical depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): 1/2/16,Fracture Stimulation Stage 1:12715'-13020'. APR 8 2016 1/4/16,Fracture Stimulation Stage 2:11840'-12102'. SCANNED iJ Treatment descriptions including volumes used and final pressure: SCANNED Please see FracCAT Treatment Post Job Reports 4130 psi 5'2+6 `S1 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 482 1134 3356 1303 261 Subsequent to operation: 248 -894 588 1452 223 14.Attachments:(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations Q s\ Exploratory 0 Development Q Service 0 Stratigraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil Q Gas 0 WDSPL 0 Printed and Electronic Fracture Stimulation Data Q GSTOR ❑ WINJ 0 WAG 0 GINJ 0 SUSP ❑ SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-707 Contact Catron,Garry R(Wipro) Email Garry.Catron@bp.com Printed Name Catron,Garry R(Wipro) Title PDC Principal Engineer Signature ,\ /'4 4Ars Phone +1 907 564 4424 Date 2/15/16 Form 10-404 Revised 5/2015 i�/ ` 3/0c/k, �° joy nl., J\\ G \1�i( RBDMS �L FEB 1 6 2016 feDGt•uta Submit Original Only • • +' c a) V pL Q CD a (- c 73 a) ms +J O p i N 006 ° O L Z pt L c N C) L J O O a (n -O a) 0 (a a) "C c O • + C d O a) d *' L c Q I (0 p (a - C * L > N E ▪ Q' N CT N — a- O O a) _ .� o O w — N p O N 3 a) �).N co N a) Q-•S a) Cl) N t ii C O .0 Y $ co "O CO - d CO N a) +� fn Q Cl) p) .- N ) L > c -D N L ' C > >•-> O 2 I- 0 Q m H E a) UD CD H ° N 0 C)> U H co- co- a)ri o N H a) 73 E O * Cl) -a -p o c c0 a) > 0 p Z Cl) as c N (n N N U --- O c N N O (n N _O (p O N () N ,— 0 L (n M o N fn C3 Y fn rn _ ▪ C N CO v L = O c ( 4* c N J N 04- • O (n p 13 N p C > L L C Q) L cu a) — O a) L O Q a) co co N a) (� co Cl) >> C -- V) a) a. 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J a) O O N O� Y Ca m CO o_ C c oHtol- tol- tol- to 2U � cc6 � NN � � � Q D — c c o c m m � � U) � U) 6U) � U) 0S 4Y0 vo) � , � COO a) ~ c _c _c QQc * � � � co � � � co co Z ❑ U � � � > _22o o 3 0 Et CO O U O o .— * J N J N J N J N J J J .— a. 0 CO CO CO CO C_O O O O O O L1J N N N CO 7 O C') J lf) CO CO O O LO O N V N = N Nco m Lo Q 0) N N N— 03 N N NNNN N LL CO • Schlumberger FracCAT Treatment Report Well :S-135,Stage 1 Field :Aurora Formation :Kuparuk C Well Location :Greater Prudhoe Bay County : North Slope Borough State :Alaska Country :United States Prepared for Client :BP Exploration Alaska Client Rep :David Wages Date Prepared :January 2,2016 Prepared by Name :Michael Hyatt Division :Schlumberger Phone :770-597-6685 Initial Wellhead Pressure(psi) 486 Maximum Treating Pressure(psi) 4.130 Final Surface ISIP(psi) 2,281 Surface Shut in Pressure(psi) 1,754 DataFRAC ISIP 1,847 treatment Totals Total Slurry Pumped(Water+Adds+Proppant) 1,617 Total Proppant Pumped(lbs.);From Straps 79,000 (bbl) Total YF128FIexD(bbl) 713 Total 16/20 CarboLite(lb);From Straps 75,000 Total WF128(bbl) 433 Total 16/30 Sand(lb);From Straps 4000 Total Proppant in Formation(lbs.) 77,544 Total Chemical Additives • I F103(gal) 37 37 J957(gal) 29,945 29,945 L065(gal) 52 52 B882(gal) 331 314 L071 (gal) 99 99 J604(gal) 82 82 J475(lb) 413 413 M002(Ib) 28 28 M275(Ib) 60 18 Freeze Protect(bbl) 0 11 Disclaimer Notice This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced by a computer model including various assumptions on the well,reservoir and treatment.The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model,the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values.The quality of input data,and hence results,may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment,and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. • Schlumberger Client:BP Exploration Alaska Well:S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Section 1 : Executive Summary The treatment for Stage 1 was executed on January 2, 2016. The treatment started with a DataFRAC, followed by the Prop Frac consisting of a 1 PPA step, 1-11 PPA ramp and Flush. The original design consisted of a 1-8PPA ramp and proppant steps for 9 to 11 PPA. During the treatment a discrepancy in proppant concentration to downstream densitometer and gate percentage was spotted.This resulted in higher proppant concentration than shown during the treatment and all of the proppant being delivered during the ramp stages. While not using the downstream densitometer to determine proppant concentration, they were used as a reference to determine concentration during the ramp. Upon returning to the district, the job was analyzed using the downstream densitometers to determine a more accurate representation of the proppant delivery. In this report the proppant concentration is shown based on downstream densitometers. The analysis shows that 75,000± lb of proppant were placed in formation. The initial design was to place 62,000±Ib into formation. The main treatment and POD additive charts in this report were taken from the analysis performed in the district. While not executing the design, this stage proved to be of use when designing the second stage of the treatment. The data from Stage 1 indicates that there is a potential for a more aggressive schedule. The POD blender was calibrated after the treatment to prevent this off reading from reoccurring. The pump schedules in this treatment report are split into several treatments,which was needed for the desired ramping. • • Schlumberger Client:BP Exploration Alaska Well:S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Section 2: Dial nostic, As Measured Pum . Schedule As Measured Pump Schedule Slurry Slurry Pump Fluid Max Prop Step pp Prop # Step Name Volume Rate Time Fluid Name Volume Proppant Name Copp Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (Ib) (PPA) 1 Injection 50.0 15.4 3.8 WF128 2100 0.0 0.0 0 2 Linear Scour 51.1 18.3 2.8 WF128 2123 16/30 Sand 0.5 0.2 548 3 XL Scour 55.1 18.5 3.0 YF128FIexD 2277 16/30 Sand 0.5 0.0 846 4 Calibration 25.0 19.9 1.2 YF128FIexD 1049 16/30 Sand 0.0 0.0 16 5 Displace 202.4 29.1 7.0 WF128 8501 16/30 Sand 0.0 0.0 37 6 Shut Down 0.0 20.2 0.0 WF128 0 0.0 0.0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 Injection 15.4 19.9 3465 4036 490 2 Linear Scour 18.3 19.9 3766 3973 3541 3 XL Scour 18.5 19,6 3484 3639 3290 4 Calibration 19.9 21.4 3219 3321 3149 5 Displace 29.1 30.1 3359 3467 381 6 Shut Down 20.2 15.0 2662 1924 381 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 383.7 17.8 16051 1447 Average Treating Pressure: 3435 psi Maximum Treating Pressure: 4036 psi Minimum Treating Pressure: 381 psi Average Injection Rate: 23.8 bbl/min Maximum Injection Rate: 30.1 bbl/min Average Horsepower: 2003.9 hhp Maximum Horsepower: 2549.0 hhp Maximum Prop Concentration: 0.5 PPA • 0 SchluSchlumberger Client:BP Exploration Alaska mberger Well S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Section 3: Pros sed Frac, As Measured Pum • Schedule As Measured Pump Schedule Ste Ste Slurry Slurry Pump Fluid Max Prop Prop p p Volume Rate Time Fluid Name Volume Proppant Name Prop Conc Mass # Name (bbl) (bbl/min) (min) (gal) Conc (PPA) (Ib) (PPA) 1 PAD 100.0 25.1 4.7 YF128FIexD 4200 16/30 Sand 0.0 0.0 5 2 0.5 PPA 66.5 34.0 2.0 YF128FIexD 2756 16/30 Sand 0.7 0.0 825 3 PAD 2 100.0 34.2 2.9 YF128FIexD 4200 16/30 Sand 0.1 0.0 7 4 1.0 PPA 50.0 33.6 1.5 YF128FIexD 2024 CarboLite 16/20 1.1 0.4 1724 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step it Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 PAD 25.1 33.1 3147 3528 381 2 0.5 PPA 34.0 34.3 3523 3556 3493 3 PAD 2 34.2 34.4 3600 3640 3526 4 1.0 PPA 33.6 34.2 3573 3630 3515 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 316.5 11.1 13178 2562 Average Treating Pressure: 3438 psi Maximum Treating Pressure: 3640 psi Minimum Treating Pressure: 381 psi Average Injection Rate: 31.2 bbl/min Maximum Injection Rate: 34.4 bbl/min Average Horsepower: 2663,8 hhp Maximum Horsepower: 3053.0 hhp Maximum Prop Concentration: 1.1 PPA • II Schlumberger Client:BP Exploration Alaska Well:S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Section 4: Ram ., As Measured Pum . Schedule As Measured Pump Schedule Step Step Slurry Slurry Pump Fluid Ma Prop Prop I Name Volume Rate Time Fluid Name Volume Proppant Name Conc Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 1 27.6 33.3 0.8 YF128FIexD 1101 CarboLite 16/20 1.6 0.6 1350 2 2 28.6 33.4 0.9 YF128FIexD 1101 CarboLite 16/20 2.5 0.3 2294 3 3 29.6 33.3 0.9 YF128FIexD 1101 CarboLite 16/20 3.2 2.1 3261 4 4 30.6 33.1 0.9 YF128FIexD 1097 CarboLite 16/20 4.3 1.3 4292 5 5 31.6 34.1 0.9 YF128FIexD 1100 CarboLite 16/20 5.1 4.0 5191 6 6 32.6 34.1 1.0 YF128FIexD 1103 CarboLite 16/20 5.8 1.5 6099 7 7 33.6 33.1 1.0 YF128FIexD 1106 CarboLite 16/20 6.9 5.7 6983 8 8 34.6 29.1 1.2 YF128FIexD 1102 CarboLite 16/20 7.4 1.9 8027 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step I Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 1 33.3 33.7 3504 3516 3491 2 2 33.4 34.2 3455 3488 3421 3 3 33.3 33.7 3381 3416 3347 4 4 33.1 33.6 3343 3352 3337 5 5 34.1 35.0 3366 3400 3344 6 6 34.1 34.6 3486 3583 3407 7 7 33.1 34.4 3594 3659 3508 8 8 29.1 31.1 3491 3591 3406 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 249.0 7.6 8811 37497 Average Treating Pressure: 3455 psi Maximum Treating Pressure: 3659 psi Minimum Treating Pressure: 3337 psi Average Injection Rate: 32.9 bbl/min Maximum Injection Rate: 35.0 bbl/min Average Horsepower: 2783.0 hhp Maximum Horsepower: 3088.3 hhp Maximum Prop Concentration: 7.4 PPA • • Schlumberger Client BP Exploration Alaska Well:S-135,Stage 1 Formation Kuparuk C District:Prudhoe Bay Section 5: Flat & Flush, As Measured Pum . Schedule As Measured Pump Schedule StepStepSlurry Slurry Pump Fluid Max Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name Conc Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 9.0 PPA 19.5 27.3 0.7 YF128FIexD 613 CarboLite 16/20 7.9 6.8 4727 2 10.0 PPA 20.1 26.8 0.7 YF128FIexD 629 CarboLite 16/20 8.0 7.7 4937 3 11.0 PPA 53.1 27.7 1,9 YF128FIexD 1706 CarboLite 16/20 8.1 0.0 12061 4 Flush 40.0 27.7 1.4 YF128FIexD 1680 1.5 0.0 0 5 Flush 130.0 26.3 5.1 WF128 5460 0.0 0.0 0 6 Flush 18.4 16.1 1.2 Freezeprotect 775 0.0 0.0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 9.0 PPA 27.3 29.1 3529 3614 3463 2 10.0 PPA 26.8 27.6 3601 3662 3544 3 11.0 PPA 27.7 28.3 3816 3979 3671 4 Flush 27.7 28.6 4032 4130 3949 5 Flush 26.3 27.5 3834 4081 3073 6 Flush 16,1 16.1 3223 3284 2109 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (lb) 281.2 11.1 10863 21725 Average Treating Pressure: 3780 psi Maximum Treating Pressure: 4130 psi Minimum Treating Pressure: 2109 psi Average Injection Rate: 26.2 bbl/min Maximum Injection Rate: 29.1 bbl/min Average Horsepower: 2445.9 hhp Maximum Horsepower: 2890.7 hhp Maximum Prop Concentration: 8.1 PPA • 0 Schiumberger Client:BP Exploration Alaska Well:5-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Section 6: Job Messa•es Message Log Message Treating Annulus # Time g Pressure Pressure Total Slurry Slurry Rate Prop.Conc. (psi) (psi) (bbl) (bbl/min) (PPA) 1 Remark 0 0 0.0 0.0 0.0 2 Arrived on location at 0700 0 0 0.0 0.0 0.0 3 Reset Executed Steps 0 0 0.0 0.0 0.0 4 Reset Executed Steps 0 0 0.0 0.0 0.0 5 arrived on location at 0700 0 0 0.0 0.0 0.0 6 9:04:35 All pumps running 0 0 0.0 0.0 0.0 7 9:55:25 Pre-Prime up meeting complete 71 1079 0,0 0.0 0.0 8 10:02:04 Priming POD 72 1079 0.0 0.0 0.0 9 10:22:32 Flooding lines 73 1512 0.0 0.0 0.0 10 11:28:28 Starting low PT 1927 1551 0.0 0.0 0.0 11 11:38:33 Good Low PT 326 1556 0.0 0.0 0.0 12 11:54:21 Good High PT 5833 1565 0.0 0.0 0.0 13 11:54:37 Pump trips and Global Trip verified 5827 1565 0.0 0.0 0.0 14 11:55:12 Good Check Valve Test 5808 1566 0.0 0.0 , 0.0 15 11:56:45 Bled Off 105 1566 0.0 0.0 0.0 16 11:57:34 Batching Up 28#gel 114 1567 0.0 0.0 0.0 17 12:56:34 PJSM Complete 101 1597 0.0 0.0 0.0 18 12:56:39 28#Gel Verified 101 1597 0.0 0.0 0.0 19 13:20:38 Investigating issue with LRS truck,Standing By. 99 1609 0.0 0.0 0.0 20 14:52:20 LRS Mechanic on location. Issue appears to have 97 1650 0.0 0.0 0.0 been fixed. 21 15:13:03 Lining up to bring the IA to 2000psi 96 1658 0,0 0.0 0.0 22 16:48:44 POD Primed on water 135 2032 0.0 0.0 0.0 23 16:49:16 Equalizing to wellhead 150 2032 0.0 1.5 0.0 24 16:50:26 Opening Wellhead 2340 2032 0.0 0.0 0.0 25 16:50:56 Initial Wellhead Pressure 490 487 2032 0.0 0.0 0.0 26 16:51:10 Swab Valve open 23.5 turns 483 2031 0.0 0,0 0.0 27 16:53:12 Start Injection Automatically 488 2028 0.0 0.0 0.0 28 16:53:12 Start Diagnostic Automatically 488 2028 0.0 0.0 0.0 29 16:53:12 Start Toe Stage De Automatically 488 2028 0.0 0.0 0.0 30 16:53:12 Started Pumping 488 2028 0.0 0.0 0.0 31 16:57:02 Start Linear Scour Automatically 3966 2218 50.2 19.8 0.0 32 16:57:02 Started Pumping Prop 3966 2218 50,2 19.8 0.0 33 16:59:50 Start XL Scour Automatically 3602 2242 101.3 17.7 0.4 34 17:00:25 Activated Extend Stage 3509 2248 111.9 18.3 0.5 35 17:02:48 Deactivated Extend Stage 3271 2265 156.3 19.5 0.0 36 17:02:48 Start Calibration Manually 3271 2265 156.3 19.5 0.0 37 17:0149 Activated Extend Stage 3252 2277 176.4 20.4 0.0 38 17:03:55 Deactivated Extend Stage 3255 2278 178.4 21.1 0.0 39 17:04:03 Start Displace Automatically 3324 2284 181.3 22.1 0.0 40 17:04:17 Cutting XL Adds 3385 2288 186.6 23.6 -0.0 41 17:04:50 Stage at Perfs: Injection 3372 2292 200.3 26.1 -0.0 42 17:05:43 XL Sample 10.10 pH 3454 2319 225.0 29.5 0.0 43 17:06:34 Stage at Perfs:Linear Scour 3438 2349 250.4 30.1 0.0 S • Schiumberger Client,BP Exploration Alaska Well S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Message Log Message Treating Annulus # Time g Total Slurry Slurry Rate Prop.Conc. Pressure Pressure (bbl) (bbl/min) (PPA) (psi) (psi) 44 17:07:12 Stopped Pumping Prop 3382 2371 269.4 30.0 -0.0 45 17:08:17 Stage at Perfs:XL Scour 3409 2339 302.0 30.1 0.0 46 17:10:05 Activated Extend Stage 3333 2330 356.1 30.1 0.0 47 17:10:06 Stage at Perfs:Calibration 3332 2330 356.6 30.1 0.0 48 17:10:56 Stage at Perfs:Displace 711 2264 381.6 29.8 0.0 49 17:11:16 Shutdown 1933 2313 383.7 0.0 0.0 50 17:45:25 Deactivated Extend Stage 420 2196 383.7 0.0 0.0 1 17:45:26 Start Shut Down Automatically 391 2195 383.7 0.0 0.0 2 17:45:27 Start PAD Automatically 387 2196 0,0 1.0 0.0 3 17:45:27 Start Propped Frac Automatically 387 2196 0.0 1.0 0.0 4 17:50:08 Started Pumping Prop 3505 2351 94.6 32.9 0.0 5 17:50:18 Start 0.5 PPA Automatically 3504 2352 100.2 33.1 0.0 6 17:51:41 Activated Extend Stage 3520 2376 147.1 34.2 0.3 7 17:52:14 Deactivated Extend Stage 3537 2317 165.9 34.2 0.1 8 17:52:15 Start PAD 2 Automatically 3539 2318 166.5 34.1 0.1 9 17:52:16 Stopped Pumping Prop 3534 2316 167.1 34.2 0.1 10 17:53:14 Stage at Perfs:PAD 3585 2348 200.2 34.4 0.0 11 17:53:52 XL pH 10.12 3618 2373 221.8 34.3 0.0 12 17:55:03 Started Pumping Prop 3630 2340 262.3 34.2 0.0 13 17:55:11 Start 1.0 PPA Automatically 3639 2345 266.9 34.2 0.1 14 17:56:11 Stage at Perfs:0.5 PPA 3541 2372 300.6 32.9 1.0 1 17:56:40 Start 1 Automatically 3532 2355 0.0 33.8 1.0 2 17:56:40 Start Ramp Automatically 3532 2355 0.0 33.8 1.0 3 17:57:30 Start 2 Automatically 3490 2328 27.7 33.2 1.7 4 17:58:10 Stage at Perfs:PAD 2 3428 2340 50.0 33.6 2.4 5 17:58:21 Start 3 Automatically 3407 2343 56.1 33.3 2.5 6 17:59:15 Start 4 Automatically 3352 2353 86.0 32.8 3.4 7 18:00:10 Start 5 Automatically 3338 2358 116.4 33.2 4.3 8 18:01:06 Start 6 Automatically 3407 2358 148.4 34.8 5.2 9 18:01:10 Stage at Perfs:1.0 PPA 3435 2358 150.7 34.7 5.3 10 18:02:03 Start 7 Automatically 3590 2356 180.6 33.6 5.8 11 18:02:38 Stage at Perfs:1 3628 2350 200.3 32.9 6.5 12 18:03:05 Start 8 Automatically 3556 2343 214.6 31.4 7.0 13 18:03:33 Stage at Perfs:2 3471 2334 228.3 28.1 7.4 1 18:04:16 Start 9.0 PPA Automatically 3611 2327 0.0 29.3 7.4 2 18:04:16 Start Flat&Flush Automatically 3611 2327 0.0 29.3 7.4 3 18:04:32 Stage at Perfs:3 3469 2319 7.6 26.9 7.8 4 18:05:00 Start 10.0 PPA Automatically 3561 2314 19.8 26.4 8.0 5 18:05:40 Stage at Perfs:4 3649 2308 37.7 27.6 8.1 6 18:05:45 Start 11.0 PPA Automatically 3686 2307 40.0 27.3 8.1 7 18:05:50 Activated Extend Stage 3696 2306 42.2 27.3 8.0 8 18:06:47 Stage at Perfs:5 3838 2297 68.2 27.9 8.0 9 18:07:38 Deactivated Extend Stage 3985 2289 92.1 28.2 0.6 10 18:07:39 Start Flush Automatically 3988 2289 92.6 28.2 0.5 11 18:07:39 Stopped Pumping Prop 3988 2289 92.6 28.2 0.5 12 18:07:55 Stage at Perfs:6 4121 2292 100.1 28.5 0.0 • • Schlumberger Client BP Exploration Alaska Well.5-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay Mess..e Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (bbl) (bbl/min) (PPA) (psi) (psi) 13 18:09:05 Stage at Perfs:7 4080 2289 132.2 27.2 0.0 14 18:09:06 Start Flush Automatically 4079 2289 132.7 27.2 0.0 15 18:09:13 Activated Extend Stage 4080 2289 135.9 27.2 0.0 16 18:09:26 Cut XL 4076 2292 141.8 27.2 0.0 17 18:10:20 Stage at Perfs:8 3962 2300 166.3 27.2 0.0 18 18:11:35 Stage at Perfs:9.0 PPA 3889 2323 200.4 27.4 0.0 19 18:12:18 Stage at Perfs:10.0 PPA 3838 2337 219.9 27.3 0.0 20 18:13:03 Stage at Perfs:11.0 PPA 3796 2355 240.5 27.3 0.0 21 18:13:29 Deactivated Extend Stage 3173 2344 251,3 18.2 0.0 22 18:13:58 On full LVT 3140 2355 259.4 16.1 0.0 23 18:14:10 Start Flush Automatically 3174 2361 262.7 16.0 0.0 24 18:14:15 Activated Extend Stage 3191 2363 264.0 16.1 0.0 25 18:18:37 Deactivated Extend Stage 2231 2298 281.0 0.0 0.0 26 18:36:41 Swab Shut 23.5 turns 1685 2201 281.0 0.0 0.0 27 18:40:09 SSV Shut 47 2079 281.0 0.0 0.0 i • Schlumberger Client:BP Exploration Alaska Well:S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay • • Section 7: Treatment Plots — Treating Pressure BP Exploration Alaska — Annulus Pressure Pressure Test 1-135 — BHP t-z-zo1 s — Slurry Rate - Clean Fluid Rate 000 Prop Con 15 9 -- BH Prop Con -14 8 6000- -13 -12 -7 • 5000- -11 41 • -6 -10 • -9 -5 N 4000- • CL , -8 / 4 d = a u) 7 u) I E 3000– _._._ _ ) CL • 6 3 5 2000 �1 -2 4 -3 -1 1000+-- - -- _ -2 - � 0 1 11:18:49 11:39:39 12:00:29 12:21:19 12:42:09 Time-hh:mm:ss • • Schlumberger Client:BP Exploration Alaska Well:S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay — Treating Pressure — Annulus Pressure BP Exploration Alaska — BHP DataFrac PRC 1-136 1-2-2016 Slurry Rate — Clean Fluid Rate — Prop Con 6000 ' , • , 42 -6 — 8H Prop Con 5000- . 35 -5 4000- _._ -__.... _.._.. __....... I _— 28 -4 N a 1 I -il 3000— 3 _-__. 21 i -3 N _ 4 CL ' x 2000- -- __. .. I ._._ _. 1000- __.-- 0 . 'i r#V n _ . . _. 16:26:01 16:46:51 17:07:41 17:2831 17:49:21 Time-hh:mm:ss - Treating Pressure — Annulus Pressure BP ExplorarionAlaska Main Treatment PRC S-135, — BHP 1-2-2016. — Slurry Rate — Clean Fwd date — Prop Con . , • , 43 _15. — Bit Prop Con -r3 -12 0003 '33 .N 5033 _g r------------ ,. A 1 Y Q .. 1.- N 4300 ir/ e Wr,70-'In r ---ii 23 0 ArtoitrA a 3' 10 3000 D 2300 10 d 1338 1 a i' , I .1\ 0 0 17:41:32 17:51 57 18.3222 18.12:47 1823:12 Time-hh mm:ss • III Schiumberger CBP Explion Alaska Well:S-135,Stage 1 Formation:Kuparuk C District:Prudhoe Bay — B882 Concentration — F103 Concentration BP Exploration Alaska PCM Additives S-135 — L085 Concentration 1-2-2016 — L071 Concentration — Sluny Rate g — Clean Fluid Rat&0 -40 ' ' — PCM Viscosity . 7 i 35 -35 6- _-. �i,,I`tl __- --- —i ii -- ---.. -'30 -30 • I • Vi, �25 -25 4, • E 1 • - 20 -20 45 • 3 ---- -15 -15 2 • -_ .__ - 10 -10 • 1 •{,.--. r-� �- Mill 5 -5 • 16:45:28 17:10:28 17:35:28 18:00:28 18:25:28 Time-hh:mm:ss • — Slurry Rate — Clean Ruid Rate BP Exploration Alaska — Prop Con • POD Additives S-136 — BH Prop Con 1/212016 — J476 Concentration — J604 Concentration — 1128 Concentration 40 — POD Gate Percentage . 30 -110 -100 r ip • ,` -25 T1 -90 Ili 30 y 3 -20 -0 D -70 c a 0 •, N o r-. CD am -60 -13 20-- a O 15 Y ;A 50 C 7 E e 40 1 0 10 m418.0rl Y S •30 3 a I 5 -20 • II 0 I- libl . --"i A 11. . 0 0 18:53:13 17.1813 17:43:13 18:08:13 18:33:13 Time-hh:mm:ss Schlumberger FracCAT Treatment Report Well :S-135,Stage 2 Field :Aurora Formation :Kuparuk C Well Location :Greater Prudhoe Bay County : North Slope Borough State :Alaska Country :United States Prepared for Client :BP Exploration Alaska Client Rep :David Wages Date Prepared :January 4,2016 Prepared by Name :Michael Hyatt Division :Schlumberger Phone :770-597-6685 Initial Wellhead Pressure(psi) 433 Maximum Treating Pressure(psi) 5,246 Final Surface ISIP(psi) Screenout Surface Shut in Pressure(psi) 121 Total Slurry Pumped(Water+Adds+Proppant) 899 Total Proppant Pumped(lbs.);Remaining 74,340 (bbl) Proppant from Loadout Total YF128FIexD(bbl) 729 Total 16/20 CarboLite(Ib);Remaining 72,000 Proppant from Loadout Total WF128(bbl) 145 Total 16/30 Sand(lb);Remaining Proppant 2,340 from Loadout Total Proppant in Formation(lbs.) 61,870 .1 Additives Invoiced F103(gal) 30 30 J957(gal) 30,588 30,588 [065(gal) 38 38 B882(gal) 209 192 L071 (gal) 73 73 J604(gal) 73 73 J475(Ib) 303 303 M002(Ib) 30 30 M275(Ib) 36 22 Freeze Protect(bbl) 0 4 Disclaimer Notice This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced by a computer model including various assumptions on the well,reservoir and treatment.The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model,the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values.The quality of input data,and hence results,may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. S Schlumberger Client:BP Exploration Alaska Well:S-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay Section 1 : Executive Summary The treatment for Stage 2 was executed on January 4,2016. No DataFRAC was pumped on this treatment,the design was based on Stage 1.The Prop Frac consisting of a 1 PPA step, 1-10 PPA ramp,followed by 11 PPA and 12PPA flat steps and Flush. Based off of the load tickets and straps of the Sand Chief, an estimate was made that 79,000 lbs of proppant was pumped during Stage 1. This left a total of about 73,000±lbs to be pumped on Stage 2. During pad the POD blender Deck Side Suction Flowmeter failed due to a worn cable. The sensor was operational during the pressure test. The job was temporarily shut down and Job Supervisor, Service Quality Coach and company man discussed the options. The decision was made to run the blender in manual on the Deck Side while controlling the Road side in remote from FracCAT.Once we began pumping,the job went well until we were on flush. During the treatment,we were not reading pressure from the downhole gauge. The ET restarted the box in the FracCAT and we immediately got an updated reading for BHP, but it failed to give new data. The job was treating fairly well, so we continued to pump the job.Once on flush, pressure started increasing;with about 40bbl remaining in flush,the rate was dropped to 12bpm once we started pumping LVT. The well pressured out almost immediately. An attempt was made to surge the well, but the well was completely locked up.After the screen out,we bled the surface lines and attempted to put freeze protect into the wellhead. Once again, we almost immediately pressured out. We then shut in the well and rigged down to allow for coil to rig up and start their clean out. The pump schedules in this treatment report are split into several treatments,which was needed for the desired ramping. • S Schlumberger Client BP Exploration Alaska Well:S-135,Stage 2 Formation.Kuparuk C District:Prudhoe Bay Section 2: Heel Sta•e, As Measured Pum . Schedule As Measured Pump Schedule Step Step Slurry Slurry Pump Fluid Max Prop Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name Conc Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 PAD 24.9 13.4 2.3 YF128FIexD 1044 0.0 0.0 0 2 PAD 133.9 27.1 5.0 YF128FIexD 5626 16/30 Sand 0.0 0.0 3 3 0.5 PPA 50.1 30.1 1.7 YF128FIexD 1987 16/30 Sand 2.0 0.2 2570 4 PAD 2 172.3 28.2 7.0 YF128FIexD 7222 16/30 Sand 0.4 0.0 281 5 1.0 PPA 50.0 30.0 1.7 YF128FIexD 2022 CarboLite 16/20 2.1 0.1 1776 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step I Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 PAD 13.4 18.2 2178 2603 371 2 PAD 27.1 30.4 3459 3891 2522 3 0.5 PPA 30.1 30.4 3260 3588 2889 4 PAD 2 28.2 30.6 2880 3060 1008 5 1.0 PPA 30.0 30.3 2857 2891 2835 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 431.2 17.7 17901 4630 Average Treating Pressure: 3063 psi Maximum Treating Pressure: 3891 psi Minimum Treating Pressure: 371 psi Average Injection Rate: 27.5 bbl/min Maximum Injection Rate: 30.6 bbl/min Average Horsepower: 2092.0 hhp Maximum Horsepower: 2884.4 hhp Maximum Prop Concentration: 2.1 PPA 0 S SchluSchlumherger Client:BP Exploration Alaska mherger G aU7 Well:S-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay Section 3: Ram ., As Measured Pum • Schedule As Measured Pump Schedule Ste Ste Slurry Slurry Pump Fluid Max Prop Prop Prop #p Name Volume Rate Time Fluid Name Volume Proppant Name Conc Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (Ib) (PPA) 1 1 PPA 21.5 29.9 0.7 YF128FIexD 867 CarboLite 16/20 1.0 0.9 806 2 2 PPA 22.3 29,8 0.7 YF128FIexD 878 CarboLite 16/20 1.8 0.2 1316 3 3 PPA 23.1 29.8 0.8 YF128FIexD 878 CarboLite 16/20 2.7 1.5 2071 4 4 PPA 23.9 29.8 0.8 YF128FIexD 882 CarboLite 16/20 3.5 1.9 2737 5 5 PPA 24.7 29.8 0.8 YF128FIexD 881 CarboLite 16/20 4.3 3.7 3525 6 6 PPA 25.4 29.8 0.9 YF128FIexD 883 CarboLite 16/20 5.2 3.2 4250 7 7 PPA 26.2 29.9 0.9 YF128FIexD 883 CarboLite 16/20 5.9 5.3 5013 8 8 PPA 27.0 29.8 0.9 YF128FIexD 884 CarboLite 16/20 6.9 3.2 5752 9 9 PPA 27.8 29.6 0.9 YF128FIexD 879 CarboLite 16/20 7.9 0.6 6629 10 10 PPA 28.6 29.6 1.0 YF128FIexD 884 CarboLite 16/20 8.7 8.2 7286 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 1 PPA 29.9 29.9 2845 2847 2841 2 2 PPA 29.8 29.9 2828 2844 2801 3 3 PPA 29.8 29.8 2758 2800 2716 4 4 PPA 29.8 29.9 2669 2712 2622 5 5 PPA 29.8 29.8 2598 2621 2575 6 6 PPA 29.8 29.9 2553 2573 2541 7 7 PPA 29.9 30.0 2572 2583 2557 8 8 PPA 29.8 29.9 2621 2656 2590 9 9 PPA 29.6 29.8 2713 2777 2656 10 10 PPA 29.6 29.9 2851 2921 2777 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 250.5 8.4 8799 39384 Average Treating Pressure: 2698 psi Maximum Treating Pressure: 2921 psi Minimum Treating Pressure: 2541 psi Average Injection Rate: 29.8 bbl/min Maximum Injection Rate: 30.0 bbl/min Average Horsepower: 1967.5 hhp Maximum Horsepower: 2098.1 hhp Maximum Prop Concentration: 8.7 PPA • I Schlumberger Client BP Exploration Alaska Well S-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay Section 4: Flat & Flush, As Measured Pane Schedule As Measured Pump Schedule Step Step Slurry Slurry Pump Fluid Max Prop Prop Name Volume Rate Time Fluid Name Volume Proppant Name Conp Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 11.0 PPA 47.2 29.5 1.6 YF128FIexD 1389 CarboLite 16/20 10.3 0.0 13572 2 12.0 PPA 32.9 29.4 1.1 YF128FIexD 939 CarboLite 16/20 11.4 0.0 10071 3 YF Flush 38.0 30.5 1.2 YF128FIexD 1560 CarboLite 16/20 10.7 0.1 800 4 WF Flush 100.0 29.7 4.6 WF128 4197 CarboLite 16/20 0.1 0.0 59 Freeze 5 4.0 3.4 1.3 Freeze protect 170 0.0 0.0 0 Protect Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 11.0 PPA 29.5 30.0 3026 3143 2929 2 12.0 PPA 29.4 30.0 3195 3325 3138 3 YF Flush 30,5 30.6 3663 4079 3340 4 WF Flush 29.7 30.6 3815 4598 101 5 Freeze Protect 3.4 4.3 111 115 102 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 222.1 9.9 8255 24501 Average Treating Pressure: 3469 psi Maximum Treating Pressure: 4598 psi Minimum Treating Pressure: 101 psi Average Injection Rate: 29.4 bbl/min Maximum Injection Rate: 30.6 bbl/min Average Horsepower: 2535.0 hhp Maximum Horsepower: 3101.7 hhp Maximum Prop Concentration: 11.4 PPA ID • Schiumberger Client:BP Exploration Alaska Well:S-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay Section 5: Pro• sed Frac Job Messa.es Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. I Time Pressure Pressure (bbl) (psi) (psi) ) (bbl/min) (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0.0 2 Reset Executed Steps 0 0 0.0 0.0 0.0 3 Arrived on location at 0650 0 0 0.0 0.0 0.0 4 0905.Waiting on Vac trucks 0 0 0.0 0.0 0.0 5 10:41:58 POD Primed 113 -74 0.0 0.0 0.0 6 10:42:05 Start Priming Pumps 112 -75 0.0 0.0 0.0 7 11:11:07 Start Low PT 330 1166 0.0 0.0 0.0 8 11:16:26 Good Low PT 280 1168 0.0 0.0 0.0 9 11:17:06 Making a Gel 276 1168 0.0 0.0 0.0 10 11:22:36 All Pumps Tripped.Global Trip Verified 5904 1170 0.0 0.0 0.0 11 11:25:44 pumping pressure back up 5999 1170 0.0 0.0 0.0 12 11:34:13 Pre Job Sample 28#XL 10.20 5961 1172 0.0 0.0 0.0 13 11:38:07 Good High PT 5824 1173 0.0 0.0 0.0 14 11:41:59 Good Check Valve Test 100 1174 0.0 0.0 0.0 15 12:18:03 PJSM Complete 102 1186 0.0 0.0 0.0 16 12:23:36 Priming LAS lines to PCM 100 1031 0.0 0.0 0.0 17 12:24:40 SSV Open 102 1031 0.0 0.0 0.0 18 12:25:00 LRS lined up to the IA. Bringing IA to 2000psi 101 1031 0.0 0.0 0.0 19 12:28:13 Priming POD on Water 101 1251 0.0 0.0 0.0 20 12:33:59 Swab Valve Open 23.5 turns.Wellhead Open. 282 1971 0.0 0.0 0.0 21 12:35:23 Start PAD Automatically 391 1973 0.0 0.0 0.0 22 12:35:23 Start Propped Frac Automatically 391 1973 0.0 0.0 0.0 23 12:35:23 Start Heel Stage D Automatically 391 1973 0.0 0.0 0.0 24 12:35:23 Started Pumping 391 1973 0.0 0.0 0.0 25 12:37:48 Start PAD Manually 2554 1969 24.9 18.2 0.0 26 12:37:53 Activated Extend Stage 2552 1965 26.4 18.2 0.0 27 12:38:15 Start PAD at 30bbls total 2628 1949 33.1 19.1 0.0 28 12:39:35 XL sample 10.10 3295 1924 63.8 25.8 0.0 29 12:42:42 Started Pumping Prop 3620 2240 154.8 30.4 0.0 30 12:42:49 Deactivated Extend Stage 3576 2263 158.3 30.3 -0.0 31 12:42:50 Start 0.5 PPA Automatically 3578 2268 158.8 30.3 -0.0 32 12:44:24 Stage at Perfs:PAD 2894 2313 206.0 30.3 0.3 33 12:44:30 Start PAD 2 Automatically 2877 2316 209.0 30.2 0.4 34 12:44:52 Cut Prop 2880 2333 220.1 30.3 0.4 35 12:45:07 Stopped Pumping Prop 2878 2329 227.7 30.4 0.4 36 12:45:14 Stage at Perfs:PAD 2872 2299 231.2 30.5 0.0 37 12:47:40 Shut down to investigate POD DK Suction 2031 2233 303.8 7.6 0.0 38 12:57:06 Activated Extend Stage 1006 2260 304.3 0.0 0.0 39 12:58:00 Extending pad by 50bbls 2793 2269 307.3 9.1 0.0 40 13:00:23 Stage at Perfs:PAD 2898 2295 365.0 30.3 0.0 41 13:00:51 Started Pumping Prop 2886 2299 379.2 30.2 0.0 42 13:00:54 Deactivated Extend Stage 2889 2300 380.7 30.3 0.0 43 13:00:55 Start 1.0 PPA Automatically 2882 2299 381.2 30.3 0.0 44 13:02:03 Stage at Perfs:0.5 PPA 2851 2271 415.2 30.0 0.6 45 13:02:35 Start 1 PPA Automatically 2846 2276 0.0 30.0 0.9 46 13:02:35 Start Ramp Automatically 2846 2276 0.0 30.0 0.9 47 13:03:19 Start 2 PPA Automatically 2839 2285 21.9 29.9 1.1 • • Scidumberger Client BP Exploration Alaska Well:5-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. 8 Time Pressure Pressure (bbl) (bbl/min) (PPA) (psi) (psi) 48 13:04:03 Start 3 PPA Automatically 2791 2291 43.8 29.7 2.0 49 13:04:50 Start 4 PPA Automatically 2706 2273 67.1 30.1 2.7 50 13:05:38 Start 5 PPA Automatically 2620 2269 90.9 29.8 3.6 51 13:06:11 XL pH 10.04 2589 2271 107.3 29.7 4.2 52 13:06:28 Start 6 PPA Automatically 2565 2270 115.7 29.7 4.5 53 13:07:19 Start 7 PPA Automatically 2571 2272 141.1 30.0 5.3 54 13:07:49 Stage at Perfs:PAD 2 2580 2268 156.0 29.7 5.9 55 13:08:12 Start 8 PPA Automatically 2592 2266 167.4 29,8 6.1 56 13:09:06 Start 9 PPA Automatically 2670 2259 194.3 29.8 7.0 57 13:09:30 Stage at Perfs:1.0 PPA 2695 2255 206.1 29.4 7.5 58 13:10:02 Start 10 PPA Automatically 2788 2253 221.9 29.8 7.6 59 13:10:15 Stage at Perfs:1 PPA 2811 2252 228.3 29.6 8.0 60 13:10:59 Stage at Perfs:2 PPA 2934 2249 250.0 29.3 8.7 61 13:11:01 Start 11.0 PPA Automatically 2927 2246 0.0 29.2 8.7 62 13:11:01 Start Flat&Flush Automatically 2927 2246 0.0 29.2 8.7 63 13:11:46 Stage at Perfs:3 PPA 3036 2239 22.1 29.1 10.2 64 13:12:35 Stage at Perfs:4 PPA 3146 2282 46.2 30.0 10.3 65 13:12:36 Start 12.0 PPA Manually 3132 2282 46.7 30.0 10.3 66 13:12:44 Activated Extend Stage 3138 2283 50.7 29.6 10.4 67 13:13:26 Stage at Perfs:5 PPA 3229 2271 71.2 29.2 11.3 68 13:13:43 Deactivated Extend Stage 3378 2272 79.6 30.1 7,8 69 13:13:43 Start YF Flush Manually 3378 2272 79.6 30.1 7.8 70 13:14:16 Stage at Perfs:6 PPA 3688 2275 96.4 30.6 0.0 71 13:14:54 Cut XL 4120 2304 115.7 30.5 0.0 72 13:14:58 Start WF Flush Automatically 4070 2298 117.7 30.4 0.1 73 13:15:08 Stage at Perfs:7 PPA 4115 2281 122.8 30.4 0.0 74 13:16:01 Stage at Perfs:8 PPA 4045 2277 149.6 30.4 0.0 75 13:16:56 Stage at Perfs:9 PPA 3714 2269 177.5 30.5 0.0 76 13:17:53 Stage at Perfs:10 PPA 3637 2283 206.6 30.5 0.0 77 13:18:34 Stopped Pumping Prop 4164 2242 216.1 0.3 0.0 78 13:26:06 Swab shut 23.5 turns 4381 2275 217.1 0.0 0.0 79 13:26:20 Lining up to push LVT through our lines. 115 2275 217.1 0,0 0.0 80 13:26:47 Once fluid packed with LVT at surface we will 105 2275 217.1 0.0 0.0 attempt to pump L 81 13:28:31 Start Freeze Protect Automatically 102 2274 217.6 1.6 0.0 82 13:39:00 Equalizing wellhead 114 2268 221.6 0.0 0.0 83 13:40:28 Swab Open 23.5 turns.Wellhead Open. 4354 2266 221.6 0.0 0.0 84 13:42:36 Bleeding well 3604 2254 221.6 0.0 0.0 85 13:45:45 Swab valve Shut 119 1922 221.6 0.0 0.0 86 13:46:16 Bleeding IA to 500 psi 118 1801 221.6 0.0 0.0 87 13:48:37 SSV Shut 116 1223 221.6 0.0 0.0 • • Schiomberger Client:BP Exploration Alaska Well:S-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay Section 6: Treatment Plots — Treating Pressure Pressure Test BP Exploration Alaska — Annulus Pressure 5-135 1-4-2016 — Slurry Rate -- Clean Fluid Rate 000 — Prop Con .BH Prop Con 7 14 6000— _ ---- --- 6 -12 5000 S -10 .y Q 4000- N E.) 3000' -3 -6 D CI- 2000- -2 1000- l 0, P rik iii _a 11'.04.32 11:14:57 11:25:22 11'.35'.47 11'.46'.12 Time-hh:mm:ss • • • Schiumberger CBP ExploraionAlaska Well:5-135,Stage 2 Formation:Kuparuk C District,Prudhoe Bay — Treating Pressure — Annulus Pressure BP Exploration Alaska PRC Main Treatment 5-135 — slurry Rate 1-4-2016 — Clean Fluid Rate — Prop Con 6000 1 — RH Prep Cor 40 -12 Attempt to bleed pressu••and push Freeze Protect into well Shutdown due t POD suction sensor s red Out s000 _ - _ — IJUP _ .,0 •30 4000 8 11. /17"). 7*-:-- g 3000 . ,41- - 20 -6 i t j' li D 2000 i %F -4 ' [ 7\ 0 1000 -2 --- - 0 —I 4 - - - _i 12:33:09 12:53:59 13:14:49 13:35:39 13:56:29 Time-hh:mm:as - 0882 Concentration PCM Additives OP xplorationAlaska — F103 Concentration 1-4-2016 — L065 Concentration L071 Concentration 10 r i i 40 25 — Shiny Rate 9- -- Clean Fluid Rate — PCM Viewaty 8- -20 11 7 PriliM0110.41 le 6- -15 5 l: 20 g 4 0 RI133 •10 2- 5 1- i --- 12:30:25 12:47:05 13'.03'.45 13:20:25 13:3705 Time-hh:mm:ss • S Client.BP Exploration Alaska SchiumbergerWell:S-135,Stage 2 Formation:Kuparuk C District:Prudhoe Bay - slurry Rab POD Additives — Clean Fluid Rate BP Exploration Alaska — Prop Con s-136 — BM Prop Con 1-4-2016 40 — J604 Concentration U28 Concentration I — — J475 Concentration 12 100 — POD Road Gate Percentage -11 -90 ii: POD Deck Grab Percentage :10 80 ..-70 8 c •7 j41 '60 i r" . frr _i., Li ... . 5 I 0 : 40 4 110------ / -30 J 3 Jk. 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O CD [6 O CO c a) o a Op > 6 N O 5 U M n a) a N CI) o m E o 0 c a) r .� o- c o f E m� on U O c O O L ct O IT C6 N a) C) N -U — T .O N •cn -,-?•.• N N N O c -O o'0 ` O a) N O -O0 E C6 U (n L O O O N �-' - C6 7 N_E c L c a) U 8 , O a) :0 O 'O _ N O L m O 0 O n T/6 0 0 ti o C r c -0 CC p 0 o 0C c%� L a E o c E C) r o` 0 0_ E-- m o C) x E U 0 E >, D o r a) r = c E E 0 o f m E s m -o T- >a C N N >. _ O L C6 U O U N .0 -O (6 = O a) N 7 a (6 7 N c — _C N a):CD-o > c x o °'c E E (0 ❑ E E r E `) m o m ( .` . o °of X o > .2 m m m a u) (>_ o o o .0 0 r a ? o a _ `m a o -o c c c o `° = 9 - m -,--,; 00 ._,-2 .,=,m ❑ n -O "O N U c c O) O) . _c t U)Q c L o o _o r E O o = 0 ftl E m o o ? m m ff 0 p m N o . E o .N (oi (o) (n Y 2 a > O C)LL N Q ❑ (6 co U) U U) co ❑ 7 U LL m 2 r 2 2 Q (I] N 2 N n Q N d U C Q m 2 - c (Cm Q Q . c ❑ -0 OLLO U1 ,_c O C _ 3r _O c O O ° -c r U O n Oc N r N U _0 Q 6 O N LL 3 -U _c Tzl (nN O 2 N j O N n O N • E d-0 c E U CC) >• x -O 0 E E O U_ U0 LL E U c_c CC U C c E O o o n (n ao c m E _o 7_0 a) N o ❑ E >-- o C`m o m c i6.� LL- - `o c E LL_ Ti c 0 _0 0 O O N H- 0 0)0 x Z_ TREE= • SAFETY NOTES: W ANGLE> ACTUATOR= 41BA FMC _ER C CHROME TBG 8 NRLL M X 01 70 2. 12112417' OKB ELEV= 84.4' BF.ELEV= 39.23' KOP= 137' Vit Max Angle= 109"@ 12606' Datum MD= 11843' ttlI , 2182' —I4-1/2"FES X NF,D=3.813" Llatum ND= 6700.SS lC 20'C O DUCTOR,94#,H-40,D= 19.124" --80 • GAS LFT MANDRELS 9-5/8"CSG,40#,L-80 BTC,D=8.835" —I 4643' ST MD ND DEV TYPE VLV LATCH PORT DATE 4 5451 3604 62 KBG4-5 DONE BK 16 01/08/16 3 9300 5401 62 KBG4-5 •DMY BK 0 12/31/15 TOP OF CEM@YT(02/25/14) 5643' - I. e 2 10990 6252 53 KBG4-5 SO BK 24 01/08/16 I. iti 1 11564 6608 50 KBG4-5 •01W BK 0 12/31/15 • r I STA#3=EXTENDED PACKING I, f I. Minimum ID =3.813" @ 2182' 1. all 4-1/2" HES X NIPPLE b I I ; 11642' —I4-1/2"FES xMP,D=3.813" b r 11671' —I4-1/2"NDPG CSA PPF*EGAUGE,D=3.813" eir it tsr �� MI _17"X 4-1/2"HES TNT PKR,D=3.856" 54 k. 11738' —14-1/2"HES X NP,D=3.813" • 11809' —14-1/2"HES X NP,D=3.813" t to ;11 ` 11819' --17'X 5"BKR I-F1D-E ZXP LTP w/117E13K,D=4.34" 44/7 TBG,12.6#,13CR 85 VAM TOP11825' �.y+ +, 11826' Ha-lir WL6G,D=4.00 .0152 bpf,0-3.958" 0 + —{ELMD TT NOT LOGGED 7"CSG,26#,L-80 V AM TOP HC XO TO BTGM 11865' • ii 11843• H7'X 5"BKR DG FLEX-LOCK HGR D=4.31" i NI 7'CSG,26#,L-80 BTC-M,D=6.276" —I 11992' 11852' —5"X 4-1/7 XO SUB,D=3.92" HES SWELL PACKERS a-_. _ 4-1/r HES XD SLD SLV,ID=3.813" NO SIZE TOP DEPTH MN ID 11111111 NO DEPTH OIC DATE 5 4-1/7 12102 3.958" 8 12025 0 01/25/16 4 4-1/2" 12675 3.958" _ _ 7 12048 0 01/25116 3 4-117 13020 3.958' 111111116 12744 0 01/25/16 2 4-1/2" 13454 3.958" 5 12847 0 03/24/14 1 4-1/2" 13557 3.958" RI 4 13258 0 03/24/14 _ _ 3 13401 0 03/24/14 •�•� 2 13543 0 03/14/14 falo 1 13724 0 03/24/14 ■n 0=OPEN C=CLOSE) MR ASH TW)RUGS MLLED&PUSHED H-14039'CIM _'=' 14019' H4-112"BKR SHIFT TOOL VERFICATION SUB,D=3.89" (01/25/16) EMI 14042' H4-112"BKR ISOLATION VALVE,D=-1.00" PBTD — 14042' 2 14059' -I4-1/2"X 3-1/2"XO,D=2.992" _, _. 14060' —13-1/2"HES SWELL R(R,D=2.997 4-1/2"LNR,12.6#,13CR-85 HYD 521, H 14114' 14092' H 3-112"X 4-1/2"XO,D=2.992" .0152 bpf,D=1958" X21 DATE REV BY COMMENTS DATE REV BY COMMBJTS AURORA UNIT 03/17/14 PKR2731WT1ALCOMPLETION 01/29/16NXW/JNCGLVCIO(12/31/15) WELL S-135 03/21/14 PJC DRLG HO CORRECTIONS 01/29/16 IBD/AD GLV C/O(02/08/16) PERMT No:`2132020 03/28/14 JU PJC FINAL ODE APPROVAL 01/29/16 ALM IM)MLL&PUSH RUGS DWOPEN SLD SLVS AR No: 50-029-23508-00 05/19/14 PJC GLV CORRECTION(STA#3 SO) SEC 35,T12N,R12E 2187'FAL&713'FWL 03/08/15 SWC/PJC GLV C/O 12/22/15 JLS/JND SET CBP&CLSD SID SLVS(11_ BP Exploration(Alaska) 111111111111111111.1111111111111.11111111.11111111r11111111.1.11M11.1.1.11111111111.11.111111111.1.11111.11.11111111111111111111. OF y �w \�\I%%TsA THE STATE Alaska Oil andGas ��, of T /1� Conservation Commission sKA 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 AL7,5*P Fax: 907.276.7542 www.aogcc.alaska.gov Michael Hibbert Well Interventions Engineer apa BP Exploration(Alaska), Inc. c P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Aurora Oil Pool, PBU S-135 Sundry Number: 315-707 Dear Mr. Hibbert: 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, Daniel T. Seamount, Jr. Commissioner DATED this day of December, 2015 Encl. RBDMS DEC 0 9 2015 STATE OF ALASKA RECEIVED •ALASKA OIL AND GAS CONSERVATION COMMON NOV 9 2015 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 r-N,. 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate M " Repair Well ❑ ) Operations shuvydown 0 Suspend El Perforate ❑ Other Stimulate ❑ Pull Tabing ❑ Change Approved Program El Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other ❑ 2. Operator Name: BP Exploration(Alaska),Inc 4. Current Well Class: 5. Permit to Drill Number: 213-202 Address: P.O.Box 196612 Anchorage,AK Exploratory 0 Development p 3. 9 6. API Number: 50-029-23508-00-00 ' 99519-6612 Stratigraphic El Service ❑ 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 El No ll PBU S-135 9. Property Designation(Lease Number): 10. Field/Pools: ADL 028257,028258&028261 PRUDHOE BAY,AURORA 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): 14501 6953 14042 6979 3 ow p a:. None None Casing Length Size MD ND Burst Collapse Structural Conductor 80 20"94#H-40 46-126 46-126 1530 520 Surface 4597 9-5/8"40#L-80 46-4643 46-3215 5750 3090 Intermediate 11947 7"26#L-80 45-11992 45-6874 7240 5410 Production Liner 2295 4-1/2"12.6#13Cr85 11819-14114 6770-6980 8430 7500 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment See Attachment 4-1/2"12.6#13Cr85 13Cr85 43-11826 Packers and SSSV Type: See Attachment Packers and SSSV MD(ft)and TVD(ft): See Attachment No SSSV Installed No SSSV Installed 12.Attachments: Proposal Summary El Wellbore Schematic p 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development El Service 0 14.Estimated Date for Commencing Operations: December 15,2015 15. Well Status after proposed work: Oil El ' WINJ ❑ WDSPL El Suspended El 16.Verbal Approval: Date: GAS 0 WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and the procedure approved herein will not Contact Hibbert,Michael(Alaska) be deviated from without prior written approval. Email Michael.Hibbert@BP.com Printed Name Hibbert,Michael(AlaSta) Title Well Interventions Engineer Signature Phone : ISEONLY Date67- l I/ Conditions of approval:Notify Commission so that a representative may witness Sundry Number: 3 1 6--L707 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance 0 Other: ?Oy-t' t0'0"N•Ol ►o 4o 11-0. Fr7c.F04-,J% (-heit4AA 4 Di SC(03cirt fVLR33 1..NA Lv/n/a✓,(--jac-ft,WS.0r (J1 JS 0442.3' re`1/fitr ''W' of 20 AAC- 2s-, 283 `1 Post Initial Injection MIT Req'd? Yes El No 0 Spacing Exception Required? Yes El No II( Subsequent Form Required: I 0' 4 0 4- APPROVED BYTHE �� Approved by: • COMMISSIONER COMMISSION Date: / Z C sli- 6-( ac / ,z.,_,)-- L, \2\,`�It RBDM DEC 0 gam ,_ ; '- r s _ v4 r12i(ZO1� ORIGINAL Submit Form and Attachments in Duplicate Form 10-403 Revised 11/2015 Approved application is valid for 12 months from the date of approval. • • d N m CV CO CO M CO ti d p, ti N CA C)) d co n p a) C3) C) C)) C) p co (0 CO CO CO > H 0- 0 I- CO CA CO L CO o. CV (V 00 In a) (0 M "1- In O CS) CS) CA (A p (0 (0 (0 (0 (D F a) N t6 r• N O d- N.- N O N In In CI- a..+ a O (n O = a�▪ N CO CO M 7 CDN a7 d C.) Qr � a o ~ _ L O LU O M (0 _0 w aai CO CO LU p r rrr R r L d c 2 It 0 () C, c .200000 H H H H H CD CO (i) (f) a 0 m a a) is ▪ o co co) co) co p N N N N • N (V N N N a M M M M M 0 m E as Z In (n (ULULU co co co co co Cn Cn ch Cn [I • • Packers and SSV's Attachment S-135 SW Name Type MD TVD Depscription S-135 TBG Packer 11704 11016 4-1/2" HES TNT Perm Packer S-135 Packer 12102 11342 4-1/2" Swell Packer S-135 Packer 12675 11811 4-1/2" Swell Packer S-135 Packer 13020 12094 4-1/2" Swell Packer S-135 Packer 13454 12449 4-1/2"Swell Packer S-135 Packer 13557 12533 4-1/2" Swell Packer • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AFFIDAVIT OF NOTICE OF OPERATIONS Before me, the undersigned authority, on this day personally appeared \A\ ��T, who being duly sworn states: 1. My name is Michael Hibbert. 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-135 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 November 18, 2015, 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 18th day of November, 2015. (Signature) STATE OF ALASKA THIRD JUDICIAL DISTRICT A rr'' �,� Subscribed and sworn to or affirmed before me at Cn tva,ec 1�-- on the /2 day of Ve 042 20/5".. J ` I ature of Officer O��Q° L. Jp9�� 1 - ° '•`•0'S-� Title of Officer . f pOTARY LIC/ 3 • Date: August 3, 2015 Subject: S-135 Fracture Stimulation From: Michael Hibbert Engineer, BP Alaska o: 907.564.4351 c: 907.903.5990 To: Chris Wallace Attached is BP's proposal and supporting documents to fracture stimulate the Kuparuk interval of well S-135 S-135 is a horizontal sliding sleeve & swell packer completion in Aurora field, drilled and put on production in 2014. The well has an undulating trajectory, dropping through the Kuparuk C& B sands during the build before following the C4 sands in the middle of the production interval. The OWC was found to be variable (likely due to variable rock quality), coming in at 6,853 TVDss at the heel and 6,877 TVDss at the toe. However, all of the S-135 likely shares the same Free-Water Level (approx 6900' TVDss). The well will be stimulated with 2 hydraulic fracture stages. These fractures will be pumped through SS#5 and#8. We are requesting a variance to sections 20 AAC 25.283, a, 3-4 which require identification of fresh ------- water aquifers and a plan for basewater sampling. Please direct questions or comments to Michael Hibbert • • Affidavit of Notification (20 AAC 25283,a, 1) Partners notified 6/11/2015: ConocoPhillips ExxonMobil Chevron Department of Natural Resources Plat Identifying Wells(20 AAC 25.283, a,2,A-C) and Faults(20 AAC 25.283,a, 11) 605500 606000 606500 607000 607500 600000 600500 609000 609500 610000 610500 611000 611500 612000 612500 413000 613500 614000 p614500 - 5161) ; AURORA 2015-FINAL HORIZON-MO0E1. "1 , 1:1 ' --S-125 ryX � -��W',Y 171 , ' F{ \, 5 S 6810 ,_. 7'.. 63930 `.:"".. ` 6820:. <. 6830 " b 6800 ^i, 6790 ,/ 6780 4 6770 ? £ , E 6760 `1 .-1 ".v.y 6750 l''. . ii 6740 6710 ✓ 5 w. N 6720 l+ 1204,'' }, g 6710 \ , kbb ,. 6700 '^_.. p.,.:.. 2 6690 44 '' 6670 { 6660 g 6650 .E 6640 , 1. _ •S-1356626 q 6610 6600 7-'41° x >" �` „`` ,)0'6, Fault throw (ft) f 4 � '.. and direc fion Proposed frac . .. . b locations • - Represents the proposded prop fracs in S-135 l Wells within 1/2 mile of S-135: • ✓ S-125 S-128 Per the plat above, there are no water wells within 'h mile of the subject well. • There is a north-south trending fault to the west of the proposed frac locations (650ft west and 510ft • west respectively). However, the maximum stress direction is oriented just west of north and fractures are unlikely to propogate towards this fault plane. An east-west trending fault is located approximately 1450ft to the north of the proposed heel frac, so is unlikely to be intersected by any fracture created in the heel sleeve as it is too far away. Given the above information, all fracturing fluids should remain within the matrix areas of the C-sands. As always if a sudden loss of treating pressure is seen then pumping operations will cease. . `51 • • Exemption for Freshwater Aquifers(20 AAC 25.283,a,3-4) Well S-135 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 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 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 S-135 was spudded on 2/15/14. A 12.25" hole was drilled to 4643' MD (3215' TVDss) where 9-5/8" 40#/ft, L-80, BTC csg was run and cemented in place with 890 bbls of 11 ppg LiteCRETE* lead and 88 bbls of 15.8 ppg Class G tail cement with good returns (460 bbls cmt) to surface. After cement was set, the casing was tested to 3500 psi for 30 min for a good test. A LOT to 16.7 ppg EMW was performed after the shoe was drilled. A 8-3/4" intermediate hole was drilled to 11,992' MD (6875' TVDss). A 7", 26 #/ft, L-80 BTC-M casing was run and cemented in place with 200.5 bbls of 11.5 ppg LiteCrete lead slurry and 40.7 bbls 15.8 ppg Class G cement. Plug bumped and displacements went as designed. A LOT to 14.1 ppg EMW. A 6-1/8" production hole was drilled to 14,114' MD. A 4.5", 12.6 #/ft, 13Cr-85, Hydril 521 sliding sleeve and swell packer completion was run. About 8 sliding sleeves and 6 water swell packers are were run. 4.5", 12.6#, 13Cr-85, VAM Top tubing is planned to be set, with the packer at 11,704' MD. Drilling operations on S-135 were completed on 3/17/14. 3 0 0 . Accurate Pressure Ratings of Tubulars and Schematic(20 AAC 25.283,a,8) 'ME= 4 1/1W CAN --- WELLHEA ANGLE a AR=....._ BAPC434C S-135 SAFETY TBG&LNR'L'MAX DL 7923'6 12417' C1ICB_D.LV= 84.4' r BF.EL&= 39.23' 4 KOP= UT Mac Arpk= 109'@ 12806' C Datum NI.) -. 11843' ' �' 2182' 4"1!7 FES X RR D.3 813 I OMIa1'1TVD= 6700.SS 120'CCIVOLICTb9411. -40.D=19.124" I -•Bp R _ 19.3/8"CSG,400,L-S0 BTC, 8.835 '4— 3' ST MD TVD BEV TYPE VLV A D= TCH PORT ATE . + 4 5451 3604 62 K3G4-5 [X*E. BK 16 03/06/15 3 9300 5401 62 KBG4-5 DOME BK 16 03/06/15 [TOP OF CT9.E34T(a2/25I14) --( 6843' I I. 4, 2 10990 6252 53 I0304-5 MAY BK 0 03/16/14 �^ 4, 1 11564 66081 50 KB — G 5 50 BK 22 03/08/15 5 i* Minimum N):3.813"42 2182' 5 4"1/2"HES X NIPPLE N ( 11sarl—fM1/2'HE$XNP,13=3.813•I to 9 '61 11671' 41/7 MPG-CSAPPHRE GiAUGE,C 3.819 r r co 11744' 7"X4-1/2"HES INT PICK D=3.856" q 1173$' 4-1/2"fO1XNP,D=3913"1 zyyt fL § 1180!' 4-1/YBD / XNP, =3_813' �j1i c 4. 11618' T X 5"BKR HP8?E ZXP LIEN,//1'7810(,113.--4.34'1 4-t/2'TRG,1298,13CPT 44 VAMTOP 11825' 4 _ 11826' 4112'1 LEG,D=4401 41526p(,D-3.%5" •,-,'14 '•f 3, I 1--IELM°TT NOT LOGGED I 17"CSG,259,L-80 YAM TOPHC X1310 BTC-M 11886' 9 y 11843' I7 X 5'BKR D6 FLEX-LOCK ocx FK23 D=4.31" , IT CSG,26111,L-80BTC•M,D=6.275' 11an' " 11862' 8•X4-115XOSL8,D=342' 11111 4-1/2'HIS XD SLD SLY,ID=3:613" ND CEPni.-OfC DATE �Syy�L PACKERS ..t. -4 B 12025 O 03/24/14 �^ NO, SIZE TOPD PTH MND .a�.-. 7 12046 O 00/24/14 5 41/2• 12102 3.958" UM6 12744 O 0321/14 4 4-1/2" 12675 3.958'8 MN 5 12847 0 03/24/14 3 4-1/2' 13020 3.956"! 4 13258 0 03/24/14 2 4 112" 13454 3.858'` 3 13401 0 03124114 1 4 42' 13557 3.958'j , 2 13543 0 03/14/14 �� I 13724 0 08124114 r_ II NS 0=OPe4 C.CLOSED 111 - 1.110.--- -14-147-SKR 5f'1-TTDOL VCRIFICATION 305,a9-3.491 EMI 1.4042"-14-1/2'BKR SOLATp4VALVE,D=-L00' I ) TO ,1042' 14052' 4-117 X 3-117 XO,O.2.997 j 14080' 3-112'HBs SWELL PIIR,0=2.997 I 4-1/2'LAR.12.68,13CR-R HYD 521, —) 14114' 1 14092' H3-117X4-1/2"X0,13=2.992" .0152 bpi,0"3.958' „�i, X11►; DATE FEY BY 008MEJTS DATE REV BY COMMENTS AURORA L44T O3H7114 P8)8273 INITIAL COMPLETION O6/10414 1310 CLV CORRECTION(ETA 4/3 SO) AELL,5136 03/21/14 PJC O LG HO C C1OPRS 03 15:SMCJPJC GLV C/O FEW Mx'2132020 03/26/14 BSFIJMD GLV(7O(03122/14) AR 1,11:50-029-2350800 03/26/14 TWA/IND OPENED SLD SLVS(03/24/14) SEC 35,T12N,R12E,2187'ENL&713'PM.. 0327/14 RC DRLG HD CORRECTORS 03/28/14 ,L/PJC FP4AL OCEAPPROVAL _ BP Exploration(Alas?a) Name/Size Weight Grade ID Burst,psi Collapse,psi 9-5/8" Surface Casing 40# L-80 8.835" 5750 3090 7" Production Casing 26# L-80 6.276" 7240 5410 4-1/2" Production Liner 12.6# 13Cr85 3.958" 8430 7500 4-1/2" Production Tubing 12.6# 13Cr85 3.958" 8430 7500 7 • i Wellhead: FMC manufactured wellhead, rated to 5000 psi. Tree: 4-1/16" 10,000psi Tubing head adaptor: 13-5/8" 5,000psi x 4-1/16" 10,000psi Tubing Spool: 13-5/8" 5,000psi w/2 1/16" side outlets Casing Spool: 13-5/8" 5,000psi w/2-1/16" side outlets ,, ,....; tr... °A ': . '., - . ,.,.,. .....4 ,-,:i.:.-- ,,ii'' - - , „.„,if r „f, ' 1 : Y y - :'Ilrl'. - '5 11111% t „c s ► • .;,',?i, At'-'°: ,,,-'...: .'44:7'4'--Iii. '''. .'-f-,- Z ,,,-f R V • • Geological Frac Information (20 AAC 25.283,a,9) Formation Depth Depth TVD Frac gradient Lithological Name [MDJ [TVDSS] thickness (psi/ft) description THRZ 11662 6586 177 0.87 Shale TKLB 11947 6763 23 0.87 Shale TKC4 11986 6786 20 0.69 Sandstone TKC2C 12020 6806 0 0.69 Sandstone TKC3E 12020 6806 8 0.69 Sandstone TKC2B 12035 6814 11 0.69 Sandstone TKC2A 12057 6826 17 0.69 Sandstone TKC1C 12092 6842 22 0.69 Sandstone TKC1B 12146 6864 4 0.69 Sandstone LCU 12157 6868 0.69 Siltstone Invert#1 LCU 12612 6878 4 0.69 Siltstone TKC1B 12626 6874 21 0.69 Sandstone TKC1C 12699 6852 13 0.69 Sandstone TKC2A 12758 6839 7 0.69 Sandstone TKC2B 12894 6833 34 0.69 Sandstone TKC2A 13577 6866 29 0.69 Sandstone TKC1C 14059 6896 0.69 Sandstone Invert#2 TKC4 14350 6881 7 0.69 Sandstone TKLB 14430 6874 179 0.87 Shale *THRZ 6695 0.87 Shale *estimate Mechanical Information of nearby wells(20 AAC 25.283,a, 10) Per plat above, the following wells have been reviewed for casing and cement information: Wei Mine Current Status Cosine Type Casing Size Casing Dent% Nee Sise Val ant TOC est.sb TOC TOC Ta*of pay iNerwt Zonis Isolation? Comments Inches Feet Indies W Ft MOFeet TMDstFeet 7VDsdeet 5-125 Online Producgoo Casing 7 10,729 875 1101 Vnfuwetric 3529 MO 5721 Online production Casing 7 _ 9116 875 875 Vo6unetric 3141 64.30 • 110 / 15900 - 1 -' �� •s■ a u i a 15800 ? o �t •t Rr .d .t a .e. ..t { m tJl t 15700 � 4 4 _ — " 6 P, F � � � cqMP + �� ,---o ( 15600 ao D o 000000c: ;- '; ; IiA�il! u. ������ INIEill 15500 10 © © C70C� ODC� t.. 15400 i -- R d-4-- i (t I , 15300 p 1a • art � oc) er r. cc> .- �n � ��,�.�_. `4 N N IE N CV CO A , � r2 i.ii I Wi 152005 15100 .-•- , .. 5i ! a N 15000 Ca) ZO ti cn1u�J e M N .- Q Ina FI� 14900- Q} a) Liz ■ , �� -BM 111 It iigNIMINIII 14600 N O �^ /AA 11 1 _ 1470 0 i 111=1r --1_i_i --- .Jaiu -- - ------f.-----4-4"'4..-�... '� - , 14600 2 " ,� ` ,---1----1------f--1,-- �1 t -----1-1--F-1-- r f /�� ff ! ' 3` 14500 V/ - --7-'1-------f- . i -t--Q .5 '#.. ' ..}-- a ... _ 0.f : Baa . I " as . 14400 MEMINI .0 . t 4ii ,. ,-.;sm 14300 SU ��;15'� ME - V 14200 . , ME,!I` ! ��1111 M 14100 W It 1111 : --_ i 1I r o + ---1-4--4--------H-----, , , Ili R ifi� -. . -- - 13900 i , r • { i f r 13800 a 0 " tv > 4 ' E • • 1 4 ; 13700 N .4..4_4_,.4..._...1...4.4....E mina :... ..+ .. .. �_.... #.._{..- �4. i H -r 13500 h a 4 __}_--F---,--+------�---------------��/r��i h Nay/r• , _ --j- -;----�-�-+---t--- 13600 • .N r-- --+ ---i•- ---i-- •1' E 4 / . 'ii i---j --r--# i-+ i 34Q0 \_ in ..4++... ..... - " _..... : ..:_ 1 Art i 13300 1111170" 13200 -+"--t-,—• �W iUrn [Q, . ...1 . , 3 100 6 -. ... .t _-. " . . ' _ , AU S a lw . , L , :El 13000 x �, N � i 1 , t. 44 4. Q MINI 12900 =IMFI CI --: al .•' .111. 31111 I ' : ' 12800 " °' + e tr, ; 12700 - 1..- -4----444. '--> ' a ...j. .__4,..1....;... ...4.4- 1, l 1� • Y §) §1 00 : +- igummimill 12600 25ao I Dm51 mmN � lir12400 d0000Onrili 1 12300 Y i_ a 2v - r- 'o NEE Jw �� � 12200 fur:;% tea Ell Tv' ,i ,• 11'1 N CV mi F-1- 11-- 11 , . , , i ',W . 1 /- 4. 11900 20 S S 8 d 8 8 o O A1SS • • Summary Hydraulic Fracture Program (20 AAC 25.283,a, 12) (Detailed program included) bp **4100 _., __ lo4, Jr S-135 Horizontal Borehole Profile — shoo -4--- 6650 • , 1 , � , 7 •.I, - ,- ., ro brei wnr! . . 1 I ) . :..i::+ t_ . t S 1 �;. + ..t INION_ ' 1 r , I o : 1. _ I .. . 6 1204* O .2.'2'1. Y2VN 0 6700 .1 sown► to 13,5Mes: a Imp' O I ono: _1_ Et 13.337 to 13,3%'MD �' _ 3 1309 O i 0.314714 1.� 12:13.434'to 13,493'MO 't:k1 " I j 2 /340 O OL1YM 3 13:13071 to 13.061 MD '•�""w 1 130N O Lltt$ St 12,675' 012.71s MO S 6756 - 13s 12 203 t HR2 SHALES , 0 r I • `ak‹ -..› ! 1- l- -}- f. 1 ' .was m. :. a- 1.- x si'4 '-','t: tK ' ' ' ` �4y� i IDS 1 fS d+74,Silt MU 4349'(1/1),6850 . :; , . ^.� --- 1 j*WC.Yx1ib 40011/10 s.+... '...--'y'` ;i ry 6900- I _.. . .+ t Jlay 4 ,YY LCU�7F(8 14r' "'-'-': 76-0--4 ' 5950 Kuparuk B, A ! . m F�; ,j 161 __ _� _ . . i--1. t-7000.-0oOi oopppp SOOOpppppiOOOQOOppppooppiippippooppQ O C pa. Measured Depth Above is a cross-section of the wellbore. Sliding sleeves or fracports are labelled with yellow diamonds and are numbered and the swell packers (external casing swell packers) are labelled with the green lines, both of which are along the wellbore. Sleeves #8 and #5 will be stimulated with sand proppant hydraulic fractures. Hydraulic fracture treatment schedule: • 1A.BE OABRMS F P9B _INITYVOL* AYANP Pd 7R CLAMV.A. 3415 304 A. In BA NA .984 913, Aster 238 3 10.3 w ®U 1 on 42U Ate) OA T 0.16 18511 0 53.4) 486.4 YANG 4MR 14.444 2 LYT200 5 '550_ 16 II 420 420 10 10 0.0 JO 063 0.0 07.0.0.1..1 RM. 28 293 40 34 1,600 2.100 40 59 1.0 6.0 00 04 INR SWP9M.AMOR PRESSURE TILL CLOSURE RAW 18101134E WRVFABT OSS VOL G Nn AS AN AR SSB 30FRBf# OpgRMi TYPE PATE STAGE 0300 10 7 0244 [w STAGE310SRF 68333 GA AAA OAS. AAA • • IBP1ry 860 3404 WC O6 !24.00 80 600 IRU OWL) 145000 (02008) k20 1601461 PAO v5105FN40 30 250 200 10.500 12310 0 0 250 347 60 280 20 1$ 3 MT 0712051080 39 50 400 2100 15600 4,427 7,984 670C-142 47 342 6.0 260 29 15 5/` • 400 701287400 30 50 490 2,IO 1.apW 8354 4.04 670 tie 44 392 60 25.0 20 15 R 801 7012671.00 30 50 450 ZN4 18300 8361 14345 6.200 'e 43 435 4,0 250 20 45 re I 014::: 1 880.171 16287600 30 50 300 2,100 21,(40 5_3 2333. 20<L'5e 40 425 863 280 20 1,5 R Tf 12870x0 30 44 50 SM 2100 23100 B,�e A28N E2 L-LOT 40 518 80 2863 20 15 MT 771200000 l0 50 800 2,100 1528 18001 43235 8201 Ye 39 554 80 38.0 20 1.5 Mi 5712071.40 30 - 50 ROB 2190 27340 7.130 50301 61201 lite 42 597 86 280 20 1.5 II 0000033 _ 107123 30 .0 0 162 442 8,083 14.333 3 54392 182 789 80 280 Stun down tor c10.0.Tia set,etee,e le60127 TF1280460 30 10.2 220 13862 6,340 44603 0 8362 223 1,009 CO 380 20 65 Itq IT SAT 037710605.10 Y 50 5,992 2,108 N,AI 2x154 53315 6/201 0-Lite 47 1,058 CO 23.0 29 15 TO RA 7712535.0 30 60 1,162 2100 NAR3 4,727 14436 16201 Re 45 1,103 6.0 28.0 20 0.5 N 071067b.O 30 50 1212 2100 61.003 8380 84404 1060 .re 43 1004 84 200 20 15 Zv 30 R43 771287.40 30 50 1.252 2� SLOW 826 73096 1'.01,IN 40 1,181 84 28.0 29 I.S / 21 M 7128700 30 9 32 4 SEM 9224 f♦2� 1620C-La. 40 +15 00 280 20 55 22 RAT 001mFb00 30 50 1.352 2190 57203 11420 84211 1620 C-Ln0 36 12661 00 203 20 0.5 MT 70128Fbv0 it 7 50 1312 2100 50303 11825 108034 10204-L4e 38 1,307 00 280 20 15 14 30 803 Y%NF140 TO 50 1.102 2100 81600 12653 1!8044 I6I20 0-1i0 37 1,337 89 250 20 t5 3 RL38 WF120 N 16301 8,414 6T,BTB 0 158041 157 5,464 00 28.0 KUM 1,14204 42 ... 133 4,032 1604 B9.%3 0 110380 TOTALS 33 5 0052 MAN 1127 Ya4P4R.Nre6r.)•. RWe•411100W1URIi MIMIC O3:}T000RMCVO938 *Ms vol. WPO84BY. i4 Nova on,kw. 1641467f3. 8043808 An 400 SN AllneSfl 64 •TKF11G AS Mr MR Y AAAA. *MMYR RANI...1M 1055000.2x13.3.. .061563:. � E Ws .6006664E ...TA• �0,4 76660.866. 6101131111.388180 TA,IDP PRP, AS..10 MAMA.9e0 P' .901 %] 1 PPE 7864.640 CO"CV MIA, n:w *^ FAA 7,000.4,.-1.t8Ustrn 048410.7314 0,18»74.0560• 341]6x066-.3,3.3.1 OBS,42< 58* 1 _ _ , 54.2 AM Sege NOR.966t6 SA. •AC 10. AA AAA s•8 W onuno .:NG4. Ag.0 OAS LANA PAN.TEL. Al 5lA. RR.AN M. r 'Apt ups 7'KAi ARA J p..] Y LA 9.AA AA IA .a Aar oS .7. AMR Q Tea- Sq Mw 1n AM R 1.001 10�A 3611 I-'--I•/` 70.061000. N'2os Rorw '680 1MB 00AMA 43633 N 1A 0218 Si Stege �� a This pump schedule will change slightly after the data frac/injectivity is completed. I`�I ZS The final pump schedule will include the above fluid/sand volumes per the respective stage: U Stage Desc. Zone/fault Treated Frac Frac TVD TVD Frac height length Frac top bottom • 1(SS#5) Sand Kuparuk C Sand 150 175 6875 7025 2(SS#8) Sand Kuparuk C Sand 190 170 6860 7050 The maximum horizontal stress has been determined to be roughly 30 degrees offset to the wellbore, this is based on historical information. As per the attached Plat the fracture half lengths are not planned to come into contact with any other wellbore or known faults. If a large drop in treating pressure is observed then it will be assumed that a fault has been intersected by the fracture and the treatment will be ended at that point. Maximum Anticipated Treating Pressure: 3000 psi The above values were calculated using modeling software. Surface pressure is calculated based on a closure pressure of -0.6 psi/ft or -4000 psi, this plus the anticipated net pressure to be built (500 psi) and the friction minus the hydrostatic gives a surface pressure of 3550 psi at the time of flush. 4000 psi (closure)+500 psi (net)+3000 psi (friction -4500 hydrostatic = 3000 psi (Max anticipated surface pressure) The frac height is primarily based on closure pressure differences between the confining shale layers and the harder more brittle sandstone layers. Average confining layer stress is anticipated to be -0.7 psi/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 frac program, the both the tubing and the IA will be pressure tested. The IA will be tested to 4000 psi and the tubing will be tested to 3000 psi (130% of max differential of 2300 psi). We will test the wellhead to 5000 psi to ensure that ti wellhead is PT to potential treating pressures, but the IA and tubing differentials will never exceed 2300 psi due to holding pressure on the IA during the treatment. PRV setting procedures and annulus monitoring: Maximum Allowable Treating Pressure: 5000 psi Stagger Pump Kickouts between: 4500 psi and 4750 psi (90%to 95%of MATP) Global Kickout: 4750 psi (95%of MATP) IA pop-off set pressure: 3000 psi (75%of MIT-IA) Treating line test pressure: - 6000 psi Sand Requirement 120,000#20/40 Carbolite Minimum Water Requirement 1,600 bbls(pump schedule: 1500 bbls) IA Hold Pressure 2700 psi (IA pop-off @ 3000 psi) OA Monitor and maintain open to atmosphere There are three overpressure devices that protect the surface equipment and the 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 '7 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 ,----:- --- S-135 Rig Up ,--- ---,„ N, mounted On V i Inner Annulus Late 111111-1-11. on enint2 isle ) 1 pump forlAPressix* IItrol= con --...._.------ Boom Track I e 1 0 I * e • • --- , Prop 1 Fre.:Tank tan Dun.,,- I i Frac Iuk II Ern:Tank J 1... — Fts.r.Tztic... • • Chemical Disclosure (20 AAC 25.283, a, 12) Fluid Description(,) YF12SFIeaO:Wf128 62,328 Gal Contains:Water,Surfactant,Breaker,Gelling Agent,Crossiinker,Scale inhibitor,Clay Control Agent,Additive, Bactericide,propping Agent The ro:ai volume esred In the tote.,above represents the summo0on of ware,and additives Water j5 se,ppfir 6 by diem. CAS Number Chemical Name Mass Fraction • • Water(Including Mix Water Supplied by Client). a 79% 64-19-7 Acetic add(impurity) <0.0001% 67-48-1 2-hydroxy-N,N,Ndnmethylethanaminium chloride <1% 67-63-0 Propan-2-ol <0.1% 107-21-1 Ethylene Glycol <0.1% 110-17-8 Fumark add <0.01% 111-46-6 .T.�._._2,2n Oxydiethanol(impurity) <0.001% • 111-76-2 2-butoxyethanol <0.1% 112-42-5 1-undecanol <0.01% 127-08-2 Acetic acid,potassium salt <0.0001% 1310-73-2 Sodium hydroxide(impurtty <0.1% 1319-33-1 Boronatrocalcite .__ <0.1% 1330-43-4 Sodium tetraborate <0.01% 2682-20-4 2-m 2h-lsothiazol-3-one <0.001% 7447-40-7 Potassium chloride(imp'yrE_4.r) <QA001% 7631-86-9 Non-crystalline silica(impurity) <001% 7647-14-5 Sodium ddorlde <0.01% • 7704-73-6 Monosodium fumarate _.._.." <0.01% 7727-54-0 Diammonium peroai isulphate <0.1% 778630-3 Marmium chloride <OA01% 9000-30-0 Guar gum ••2% 9002-840 poly(tetrafluoroethyiene) <O.Oltl% 10043-35-3 Bork acid <0.01% 10043-52-4 Calcium Chloride <001% 10377-60-3 Magnesium nitrate <0.001% 14464-46-1 __.._.... Crtstobatite14807-96-6 <0.0001% Magnesium s8f<ate hydrate(talc) <0.001 ---_" 14808-60-7 ___--- Quartz,Crystalline sikica <00001% 25038-72-6 MiNidenr!chbrade/metl^+yAauylaie sopoiyrceer <0.1% di 26172-55-4 ..�_ 5bro-2-methyil-2h-isothaazolol-3-one <0.001 5 34398-01-1 Akohol,C11 linear,ethoxyfated <0.1% 66402-68-4 Ceramk materials and wares,den-deals ...is% 68131-39-5 C12-15 alcohol ethyoxylated <0.01% 91053-39-3 Diatomaceous earth,calcined <0.01% 125005-87-0 Dretagum n <01001% / 129898-01-7 2-Pronereorx acid,polymer with sodium phosphinate <0.1% 1(81% •Mit wrote,:i'combed by nbe cb.et 5cbfumberyer hoe belorene6 ob onoFyssorraeab.,onO manse 0+ow!e a ar.sirne eofo.,-'en bergrtc r,ro how teen entledta she rice•d6 et.4-ear'st'x I • • Wellwork Procedure Request To: Well Services Operations Team Lead Date: 10/7/15 Wireline Operations Team Lead VER1 AFE: APBFRACS From: Michael Hibbert-Well Intervention Engineer David Wages -Well Intervention Engineer IOR: 500 Est. Cost: $250k Subject: S-135 Frac Pre Work Please perform the following steps: 1. W PPPOT-T/IC 2. C Set CBP, shift sleeves, two 4 hr wells tests, test SS's and plug, injectivity test 3. SL Dummy GLVs, set WRP @ 11,760'. MIT-T to 3000 psi and MIT-IA to 4000 psi. Pull plug. 4. F Assist SL— load IA. MITs. Step rate injectivity test thru SS #5 5. V Set TWC. Test tree to 5000 psi. Pull TWC. Current Status: Operable producer Minimum ID: 3.813" X Nipples Max Deviation: 109 deg @ 12,606' MD Top Perf Deviation: 57.5 deg at —12,039' MD (top sleeve) Last TD Tag: 5/10/15—CT tagged verification sub @ 14,042' ctm Last Downhole Op: 9/4/15 —SL B&F to 11,800' SBHP/SBHT: 2936 psi @ 6700' TVDSS 147F Latest H2S: N/A 0 ppm Program Contacts Contact Phone-Work Phone-Mobile/Home Interventions Engineer Michael Hibbert 907-564-4351 907-903-5990 Interventions Engineer David Wages 907-564-5669 713-380-9836 Production Engineer Eric Zoesch 907-564-4695 406-270-9837 Page I1of6 • • Detailed Work Procedure Coil This work would ideally be completed by CTU #8 due to it having the most powerful triplex. Set CBP, shift sleeves, two 4 hr wells tests, injectivity test. 1. D&T w/ GR/CCL and flag pipe for CBP set @ 13,200'. 2. Set CBP (Baker Quick Drill is rated for 10k psi from above) @ 13,200'. POOH. 3. POP well and test well for 4 hours. 4. MU 2 HB-3 shifting tools—one to open and one to close as well as a circ sub above the checks valves (this is to allow us to pump a ball and defeat the check valves which will allow the CT to act as a dead string to monitor BHP during the injectivity test—Call Michael Hibbert if there are any concerns with this). 5. SI well and RIH w/shifting tools and close SS #7 and #8. 6. POP well and test well for 4 hours. SI well. CT can stay in the well during this test. 7. Shift SS#6 and #5 closed. 8. PT to 1000 psi to confirm all sleeves are isolated and that CBP is holding. 9. Open SS#5. 10. Pump ball to open circ sub above check valves. 11. RIH to 12,800'. • This will act as a dead string and collect BHP data for this injectivity test. • Collect BHP data points at 1/second 12. Perform injectivity test down CTBS into SS #5. • The goal is to inject at 8 bpm or as close to that as possible. • Max treating pressure of 3000 psi. • Inject 250 bbls of diesel for this test. • Record surface pressures at a frequency of 1 data point per second • Perform hard shutdown of pumps at the end of the test and monitor pressure for 1 hr (do NOT operate tree valves, then shut in the well and rig down. • Note fluids in CT and wellbore before injectivity test and during • Send pump rate and pressure data to Michael Hibbert in .txt format or excel 13. POOH. 14. RDMO. Slickline Set 4-1/2"WRP @ 11,760'. Dummy GLVs. MIT-T to 3000 psi and MIT-IA to 4000 psi. Pull plug. 1. Set Baker 43A 4-1/2"WRP (verify its rated to 8k psi from above) at 11,760'. 2. Dummy GLVs 3&4. Pull SO from GLM #1. 3. Load IA and tubing w/dead crude/diesel. Set dmy GLV in GLM #1. • Pump down IA taking returns up tbg to production flowline. • IA volume to GLM #1 —215 bbls • Tbg volume to WRP @ 11,760' — 179 bbls • Once fluid is at GLM#1 slow rate to 1 bpm to prevent flow cutting mandrel 4. MIT-T to 3000 psi and MIT-IA to 4000 psi. • Bump up pressure several times to get as high a passing test (ending pressure) as possible. • No pressure on the IA during MIT-T per AOGCC requirements ✓ • Hold 2000 psi on the tbg during the MIT-IA. • Record final test pressure in AWGRS. 5. Pull WRP from 11,760'. Page 12of6 • • Fullbore Assist SL w/ loading IA and MITs. Injectivity test thru SS #5. (Will need hardline rigup to pump at required rate.) 1. After SO is pulled load IA with 225 bbls of dead crude taking returns to formation. 2. If coil was unable to acquire sufficient data during their injectivity test then proceed with the following steps. If coil data was sufficient then skip the injectivity test and RDMO after circing the well and obtaining MITs. 3. After wellbore is dummied off and WRP is pulled perform injectivity test down CTBS into SS #5. a. The goal is to inject at 8 bpm @ 2000 psi, or as close to these criteria as possible. Max treating pressure 4000 psi. b. Inject 250 bbls of ail for this test. c. Record surface pressures at a frequency of 1 data point per second. d. Perform hard shutdown of pumps at the end of the test and monitor pressure for 1 hr(do NOT operate tree valves, then shut in the well and rig down. e. Send pump rate and pressure data to Michael Hibbert 4. FP well and RDMO. Valve Shop Test Tree 1. Set TWC 2. PT tree to 5000 psi 3. Pull TWC Page 3 of 6 I7 • • VVell S-135 MIT#1 Test Type MIT-T Work Desc Load Well,MIT-T,MIT-IA Target Pressure 3000 AFE APBFRACSFB Max Applied Pressure 3200 Date 10/13/15 Test Fluid Crude Engineer Michael Hibbert Integrity Lirrsts Confirmed ❑� Phone 907-561-4351 Leave 2000 psi on the tubing when proceeding to MITA. Job objective Load well and obtain tests for upcoming Ziac SL to seta WRP, Load IA and TBG with crude. Perform a MIT-T and MT-LA MIT ll2 Test Type MIT-IA u^'o Schedule Target Pressure 3900 Stage Fluid Type Pump Into Volume(bats) Rate(bpm; Max Pressure Max Applied Pressure 4000 Load Crude IA 215 2500 Test Fluid Crude Load MIT#1 r��Cr�u�de 179 2502500 Integrity Limits Confirmed 0 // /1/, ix/ MIT#2 /7 / 4 Detailed Procedure hI T s SL to set WRP @11,760.Confirm this plug is ratedtoSk psi from above. Load IA with crude Pump at rrrax rate until liquid at bottom value GLM#1 @ 11,564'which will be - e -215 obis dawn the IA(catch pressure)then lower rate to 1.0 bpm Continue pimping into IA.and take all returns down 9awiine. Max `.vied Pressure ChiT-TdA to 2500 »=i Test Fluid it Limits Coninneri ❑ Directions When filling out the pimping template..please note the following If"MT is selected as a stage,the corresponding MT section must be filled out. The boxes are defined as follows Test Type:Type of test to be performed (MT-T, MT-IA. MIT-OA, etc) Target Pressure; This is the requested hilt test pressure(ie MIT-T to 2500 psi) let° Max Applied Pressure This is the max pressure that can be applied rider to achieve a passing MT of the target test pressure,typically 10%greater than target pressure BP practice 100213 (10.45)requires that the test pressure must remain above or equal to the target pressure during the entire test evaluation period.This pressure must not exceed the lowest rated working pressure(taking into account corrosion, erosion.etc) of any well barier element in the well barrier envelope. Test Fluid; The fluid to be used for the test. Integrity Limits Confirmed:By checking this box,you have confirmed that the"Max Applied Pressure"requested is within the limits of the wells"Well Barrier Envelope". • Page 14 of 6 • • WBD: TREE= 4-1116"CM/ _ SAL AC1ITC1 * BAK RC CHROME TBG&LNR 'MAXdX DL=92 3°02417' l C43.E_EV- 84.4' BF FEV= 39.23' /� KW= 13T ✓ '. Max Angle= 109"@ 12606' ' Ca TOM MD 11843' i/ ; Nt 248i--1-14•112"HES X NP,D w 3-8i 3" I OauunND= 6703.SS Tt' 120'CIY4CUCTOR q,1r,)--4p D ° _] - 19.124 --T -80 I M _ GAS LIFT AM CRELS 3-5/8"C'SG.40# I-80 BTC D=8.835' 4643' I r ST ND DEV 1 VLV LAT(3# FLIRT TE C1A i.4I AD TYPE 5451 3604 62 COW 5 COBK ' 16 03108/15 _ y 3 9300 5401 62 •K8 G4-5 DONE i BK 16 03f06/151 10PC4=CE?&t' /15/ f(0214) --r-5843' - s 2 10990 6252 53 .K8G45 DMM i 8K 0 03/16114 Li 111564 66008 50 ri KBC4-5 1 SO 1 BK C 22 03108/15 r Minimum to =3.813"Q 2182' 4 1c 4-112"H ES X NIPPLE Kt , 11647 j-34-1/2"HES x NIP,13=3.813-1 I. mi� 11671' 1-[iI2 PC'•CBAF>a1f1ECAL IE,1)43.8,3" —. ON p.i, 11704 u7"X4-1/2"FES TNT 11103,113,---8) 3.856" It 1 k 4-1/2"NES X PAP,,D=3.813' I i. 0 11809 4-12'FSXNP,O=3.813" I 11819' --I 7"X 5"BKR NIRD-E ZXP LTP w/11'TESK D=4.34'1 4-112"TBG,12.80,13CR415 VAM TAP - 11825'--; S 0152 bpf.D-3 958" fA El 1187N H4-12"WLEG,D=4.00 1 F_, TT NOT LOGGED G,264,1-80 VAN TDPN89 C XO TO BTC-M H 116' "--7 3 T CS11847 -17'x s•SKR DG FLEX-L OCK f4f2t,6=4.31" 1 I7"CSG.268,L-80 BA1 TG ,D=6.276' H 1199? ? 11862' 5'X 4-1/2"X0 SLI3,D=3.92" 1111 4-112'HES)(OSLO SLV,10=3.813' Q'/ NO (]PIH CYC DATE NES EWELL PACI03iE 8 12025 0 0324/14 HO SIZE TDP CEP-0-1 MND 2"-r s 7 12048 O 0012411 d 5 4.1/2" 12102 3.958" 6 12744 O 03124/14 5 11847 0 03124)14 4 4-112" 12675 1958" 4 11258 0 03/24/14 3 4 1/2 13020 3.958" 3 13401 0 03/24/14 2 4-12" 13454 3.958" :• 2 13543 3 O 03/14114 1 4-1/2" 13557 3.958"! 1 13724 O x24114 111 O-OPEN C=CLOSED AIL14019' H4-12"2-DICK 511FT TOOL VD'FICATI)N SL10,C e 3.691 mono 14042' --I4-1!2'BKR PSOI.A 104VAL.V D=^1.00' 311! P1111) j-' 14042' 14069 41/2 X 3-1/2"7(0,0.2.992-J aa :. f 14999' J--12712"AYES SWELL F1CR,.ID=2-902"...j i4-112'LNR12.6#,13CR-35LWD521, - 14114',1 14052' H3-1/2'X4-11TXo,D= 0 • Tubmove Calculations Force(01)(•Teale) c roii w s ;°, a o S $ = 0 8 0 0 0 0 'o 'ore N, rim w A > o ,� A - -8 • O y.N .f oN V 1 a H 4� N 3 G T. 3 _ o r o, W c m Q O>ti i i m Mo nu v Mogi .4 0O O 88 I I O m 1 p a $ T 3 a a R $ ; r r r r. o- --�i•--.-F--•--i••--,-..--►-••–t+—a a + I a i 0 O gw o a w1,.-r-,,,,,,,,,, i m 9.1 � r �y(1 ,-.5g `- ' g`� � ' fJx( T � 1 Q .y�1.• ....„.741,,,,,f,..., �1 240 1.,i1 / . c it A 111 ti I 11 • � _;w� 2 A f A • y 4.— T iv N Page 16 of 6 ZU ! • Wellwork Procedure Request To: Well Services Operations Team Lead Date: 11/17/15 Wireline Operations Team Lead VER1 AFE: APBFRACS From: Michael Hibbert-Well Intervention Engineer David Wages -Well Intervention Engineer IOR: 500 Est. Cost: $1.2mm Subject: S-135 Frac and Post Frac Procedure Please perform the following steps: ✓ 1. F Hydraulic Fracture Treatment SS# 5 2. C - Contingent FCO, set CBP and shift SS#8 open 3. F Hydraulic Fracture Treatment SS# 8 4. C FCO—mill and push CBPs to TD 5. S , Install generic GL design 6. T , Post frac flowback Current Status: Operable producer Minimum ID: 3.813" X Nipples Max Deviation: 109 deg @ 12,606' MD Top Perf Deviation: 57.5 deg at —12,039' MD (top sleeve) Last TD Tag: 5/10/15—CT tagged verification sub @ 14,042' ctm Last Downhole Op: 9/4/15—SL B&F to 11,800' SBHP/SBHT: 2936 psi @ 6700' TVDSS 147F Latest H2S: N/A 0 ppm Program Contacts Contact Phone -Work Phone-Mobile/Home Interventions Engineer Michael Hibbert 907-564-4351 907-903-5990 Interventions Engineer David Wages 907-564-5669 713-380-9836 Production Engineer Eric Zoesch 907-564-4695 406-270-9837 Page I 1 of 5 • S Detailed Work Procedure Ibor #..nd coiland Colt Hydraulic Fracture Treatment 1. Rig up Frac equipment as well as CT on the well with the goat head. This will allow the frac to be pumped and have CT ready to RIH as soon as pumping the first stage is complete. 2. Frac treatment on SS#5 per pump schedule 3. RIH GR/CCL and JSN. Tag fill and verify wellbore is clean to CBP set depth. Flag pipe. POOH. 4. Set CBP at 12,300'. Mini PT to verify CBP. POOH. 5. PU shifting tool and shift SS#8 open. 6. Frac treatment on SS#8 per pump schedule 7. RIH w/ FCO assembly. Cleanout down to CBP @ 12,300' if possible. If not, then jet GLM and POOH. RDMO. Pressure Testing Maximum Allowable Treating Pressure: 5000 psi Stagger Pump Kickouts between: 4500 psi and 4750 psi (90% to 95% of MATP) Global Kickout: 4750 psi (95% of MATP) IA pop-off set pressure: 3000 psi (75% of MIT-IA) Treating line test pressure: 6000 psi Sand Requirement 120,000#20/40 Carbolite Minimum Water Requirement 1,600 bbls (pump schedule: 1500 bbls) IA Hold Pressure 2700 psi (IA pop-off @ 3000 psi) OA Monitor and maintain open to atmosphere '�"�r: �i rick' �F�'lf,�!aT%r�.�^w/ Vi e , :�f F r� D&T, Set GL Design keiA1. D&T fill. 2. Install deep GL design FCO and Post Frac Flowback and test 1. Finish FCO w/JSN. 2. MU motor and mill BHA. Mill CBPs and push to TD. 3. Shift SS#6 open. 4. POP well and allow it to cleanup per Appendix A. 5. Perform 8 hr test. Page I2of5 7 • Appendix A -Test Separator Additional Flowback Procedure 1. MIRU ASRC. RU equipment to in a manner that allows CT to RU if an additional FCO is 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. Flow bottoms up and sample for solids production. If solids are still below 1% continue to increase the flow rate in 500 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well clean up before choke is opened further. 6. Once at FOC, stabilize the well for 4 hrs. Obtain a 3 hr purge, 8 hr welltest. Page 1 3 of 5 • • WBD: TREE= 4-1/16"CW V LHEAD= RC S-13 5 E TBG&LNR MAX 131 7 8t�3'�/211?' ACTUATOR.. BA1ORC !>M.EIPI= 84.4' 8F H.EV= -� 3'9.23" KOP= 137' /�r M Angie-- 109` 12'806' Morn ND= 11843' 218Y -;1P2'HES X NP,D=3.611" Datum TVD- 6700.SS v j20"CONOUCTC7p sna,H-40,D= 19.124" J--I -80 I A "q GAS L.ITMANDR IS 9-518'CSG,400,1.-80 BTC.D=8 835' H 4643' 1, r - _ _..__ �S�T q(? ND Otl/ TYPE VLV UTCH, FORT CY1TE 4 5451 3604 62 KHG4-5 DOSE 8K 16 03415 _ 1 3 9300 501 82 KBG4-5 Df34/E 8K I 16 03708/15 TOP OF CEMENT(9225/141 I- 5643 _ 17 10990 6232 53 KB(i4 3 C7AJM BK 01fs(14 1 1 11564 6608 50 103G4-5 SO BK j 22 03/08115 II 1Minimum IID a 3.813"0 21$ 2' 4-112"HES X NIPPLE 1 _ 11542" -14-lir HFS X MP,0.3813' > 411671' 4-1/2"NOPG;6-6A.P 1i GAUGED'=3.813- 1 4 41 4 c +4 11704' 7'X 4-112'HES TNT PIM,D.=3-8561 11738' 4-11?HES X MP,D=3.813" 11809' 4-Ur HOS X MP,D.3.813'J F44t• r 11819' I--{1X5'BKRHB6E 2XP LIP w/117183K,D=4.34 j 4-WI tiiG.128I.13GR.SSYAMTOP -i 11825' I.f11826'-4-1a-vi,.Ea,D=4.00I .0152bpt.D-3.958" ii id - EL W TT NOT LOGGED i 7'CSG,268,1-80 VAN TCIPfiC XO TC18TC-M 11866'J 11643' I-7'x s•13/O2 DG FLEX-LOCK MGR,D=4 31* 7"CSG,26/1,L-80 8T0441,D=6276' -1 11992'J- 'g ` 1186Y iH 5"X 4-132"XO SL43,0=3.92" } 1111 4-132"HES XD SLD SLV,10=3.813" �■ NO DEPTH' DIC ()Ale HEC SWELL PACKET 8 12025 0 03/24/14- ND ME TOP DEPTH MID7 12048 0 03324/14 5 4 1/2 12102 3.958' 6 12744 0 03124/14 4 4-1/2' 12375 3:958" 5 12847 0 03/24/14 4 13258 0 03/24/14 3 4-172" 13020 3.958' 3 13401 0 03/24/14 2 4-1/Y 13454 3958' - 2 11543 0 03114/14 1 4-17 13557 3.958" 1 13724 0 03/24/14 11111.1* 0-OPEN C= ES CLOS ..11111•=t '___.14019' kilt-If2-©Kft ShiFT TOOL YOiP6ATPN 3913/O=3.CO"] ORM 14942' 3--14-1.32'SKR ISOI.A TION VALVE,D=-1.00" MD - 1404? -'_ 160_6_81.1-1:4-2/2_2(13.1/2"x0,D=2.992-J �, p.•-"""a 1 3-1/2"HESSKELL - - I 14090'µ_J� �_.�..,.� ..a.��a�xR' -2*sea',.1 41/2'LNR 12.644,13CR-65 FMD 521, --L-14114' j 14092' I-3-1/2"X 4-1/?3(0,D=2.992" .0152 bpf,D=1958" .. 7)4TE REV BY COMI•EN S DATE REV BY C0*U4TS ADRORA LTJT 03/17114 MR 273 INITIAL COMPLETION 06'10114 RIC CLV CORRECTION(ETA 43 SO) Wri l E 135 03/21/14 PJC [7RLG HO CORRECTIONS 03108115 SVC/PIG GLV CID PTTBAT No.2132020 03126114 BS/JIB GLV Cfd(03/22114) AllNo=50-029-23508-00 03/26/14 TFN,*1)OFTNED SW SLVS(03/24/14) SEC-35,T12N,R12E,2187'FTL 8 713'P//l 03127114 PJC CRLG HO CORRECTIONS 03/28/14 JL/PJC FINALODEAPF44CVAL BPExploration(Alas ka) Page 14 of 5 • • Tubmove Calculations Force(1b1)(+Tensile) ol 73. 8888 . 88888 § : g § a '8 8 .:. m ,i. ... .. , V 7,i,-. 2 8- :• ,A x 0 com a, .v gionsolognimmi — ' ' .......................................................,„_......„mommonimr :I' .............0411 l't -0 Fr, 0, 0 ....J. ,.....A....ap ••••••••••••••1111111 .11.1111111111111111.1111111111111111111111111111.111111111111111111111111 ..—.--....-----...,..--....- ,...mmimimm. -.5 g. IIIIIIIIIIIIIIIIIII11111111111.11 i:g- .............. 3 2 I 0,7 . ............ m a . ;'.,Z2' • • " a; o 4 g a a i .4........---" ,• a 8 g g a t- s 0 g. i i I 8 4 .. 7.11—•.71r S 21 g 1 mom oE IAD lit -'• ",...' g g 8 8 V S S t S 8 4 t . 0 . 8 . . . 0 . 8 .88888888888s . ! 8 : : , ,•. ,,= -..,. .—, a e I l 1 I 7 is 8 4' . . . ,^ _.• . . A ..- i 4 -; f• 1. f f f 3 8- 4 Si 8 ;. . .1. • 4. . 4' + s- _ • • • ...- , 4 ,-.44--44*---..-- ...----f------ -----. i I • i E_ ...... .._...., , , ,-. ea_ • • 4 t3 , o • p; 2 ,i. .-. v. 0 : :7 CI""• '" ',Al...., , r, ..• , . ,-„,.... II 0.-• 1.1,, .,.., • a - §- 4 4 -.-r i fq 1.4 '-'4"-i-Ogn,-_,-.w..--,,.:-._.-•-,--"--..'' :44:134 Ns'ttin.....1 : ;AO : r . 1 ............ / • i ^,..k.r.... .,zea.-... e.r... z.r,,,....- ‘,- • • . • .' • .... ,..-/ a iiiriffilifij il Fi g> g 40 -,—---.------r----r - .> . . , . N "f'I Z,s3—- -•} ti : 8 a ...-: ii, ..._ 0 .•. ,,,- ;,,,, a 1 • . — a 7-' " I ,i :- .., 0, g 8 0 _ Page 1 5 of 5 2-211 • • Davies, Stephen F (DOA) From: Hibbert, Michael (Alaska ) <Michael.Hibbert@BP.com> Sent: Friday, November 20, 2015 8:57 AM To: Davies, Stephen F (DOA) Subject: RE: PBU S-135 (PTD#213-202) - Sundry Application to Fracture Stimulate - Requests Attachments: S-135 Horizontal Borehole Profile.pptx Hi Steve, Attached is another copy of the Horizontal Borehole Profile. Let me know if that is not satisfactory. As far as the table you generated there are a few minor changes I would make. Perf Interval Frac Sliding Sleeve Perf Interval Perf Interval Perf Interval Bottom Interval Sleeve Depth(MD) Top(MD) Top(TVD) Bottom(MD) (TVD) 12675 (bottom 1 5 12847 of 7" casing) 13020 6918 11992(Swell 2 8 12025 packer#4) 6874 12102 6931 Please reply or call me if you have any further questions or clarifications to make. Thanks, Michael Hibbert 907-903-5990 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Thursday, November 19, 2015 6:34 PM To: Hibbert, Michael ( Alaska ) Subject: PBU S-135 (PTD #213-202) - Sundry Application to Fracture Stimulate - Requests Michael, 1. Reading through BP's Application for Sundry Approvals to fracture stimulate PBU S-135, I found that the Horizontal Borehole Profile diagram on page 10 of the supporting documents is not legible. Could BP please provide a clearer or larger format copy? 2. To make the application clearer, I put together a small table that lists—for each perforated interval that will receive frac fluids and proppant—the top depth (both MD and TVD) and bottom depth (both MD and TVD). It's getting late, did I get this right? Perf Interval Frac Sliding Sleeve Perf Interval Perf Interval Perf Interval Bottom Interval Sleeve Depth(MD) Top(MD) Top(TVD) Bottom(MD) (TVD) 1 5 12847 12715 6932 13020 6918 2 8 12025 11840 6783 12102 6931 1 • I will be in the office tomorrow, November 20th, but will be out of the office from November 23rd through November 30th. During my time away, if you have any questions please contact Patricia Bettis. Thank you, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 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. Sent from my desktop PC 2 • • 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 ) including the K Pad commonly known as the Western ) Area Operating Area including the ) contiguous K Pad Area. ) Prudhoe Bay Unit ) Prudhoe Bay Field ) July 11, 1986 IT APPEARING THAT: 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. • 0 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 R11E 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 R13E 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. T11N R11 E Sections 1 , 2, 3, 4, 9, 10, 11 , 12, 13, 14, 15, 24 and 25. • • T11 N R12E Entire Township. T11 N R13E Entire Township. T11 N R14E Sections 3, 4, 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31 and 32. T10N R12E Sections 1 , 2, 3, 4, 10, 11 , and 12. T10N R13E Sections 1 , 2, 3, 4, 5, 6, 7, 8, 9, 10, 11 , 12, 13, 14, 15, 16, And 24. T10N 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 U.S ONMENTAL PROTECTION AC Ilk REGION 101� \IED STgr '-`51:52�y 'r a s 1200 SIXTH AVENUE r J`I! tie Ott 'Z SEATTLE, WASHINGTON 98101 ,� i = SEUL 1 0 1986 Fylq� PROT�G,\0 AREPLY OF:TO m/s409 ' TTN I L_ l`: raaed a1 C. V. Chatterton, Chairman _ T Alaska Oil and Gas Conservation Commission ,r . �_ , 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, J ,t,04/1 Robert S. Burd Director, Water Division �cE�v �D 3U 114 6 Alaska Oil & Gas Dons. Commiss�o Anchorage • ENVIRONMENTAL PROTECTION •NCY ��- REGION 10 s 1200 SIXTH AVENUE s 0 SEATTLE, WASHINGTON 98101 I 44 pilo t- JUL 01 1985 rTer�Lv TO M/S 409 (`_ ATTN OF: 1 + :f C. V. Chatterton, Chairman ALaska Oil and Gas Conservation Commission � �• _ 3001 Porcupine Drive Anchorage, Alaska 99501 FILA: 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 Bay 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, Gi-t!CC./ c-t` �/7 Robert S. Burd L( Director, Water Division - RECEIVED ivisionRECEIVED JUL. 0 7 1986 Alaska Oil& Gas Cons. 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