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213-146
Originated: Delivered to:5-Jul-24 Alaska Oil & Gas Conservation Commiss 05Jul24-NR ATTN: Meredith Guhl 333 W. 7th Ave., Suite 100 600 E 57th Place Anchorage, Alaska 99501-3539 Anchorage, AK 99518 (907) 273-1700 main (907)273-4760 fax WELL NAME API # SERVICE ORDER #FIELD NAME SERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED CD4-586 50-103-20857-00-00 223-046 Colville River WL TTiX-PPROF FINAL FIELD 3-Mar-24 CD4-536 50-103-20863-00-00 223-079 Colville River WL TTiX-PPROF FINAL FIELD 7-Mar-24 2M-12 50-103-20181-00-00 192-090 Kuparuk River WL SCMT FINAL FIELD 8-Mar-24 1B-16A 50-029-22457-01-00 218-155 Kuparuk River WL RST FINAL FIELD 9-Mar-24 CD4-588 50-103-20853-00-00 223-029 Colville River WL TTiX-PPROF FINAL FIELD 22-Mar-24 CD5-23 50-103-20761-00-00 217-155 Colville River WL Packer Setting FINAL FIELD 24-Mar-24 3F-08 50-029-21464-00-00 185-246 Kuparuk River WL SCMT FINAL FIELD 30-Mar-24 2M-03 50-103-20160-00-00 191-141 Kuparuk River WL SCMT FINAL FIELD 31-Mar-24 2B-14 50-029-21143-00-00 184-111 Kuparuk River WL WFL FINAL FIELD 3-Apr-24 2T-41 50-103-20675-00-00 213-146 Kuparuk River WL PPROF FINAL FIELD 7-Apr-24 MT7-03A 50-103-20830-01-00 223-084 Greater Mooses Tooth WL TTiX-Fiber FINAL FIELD 22-May-24 MT7-01 50-103-20832-00-00 221052 Greater Mooses Tooth WL TTiX-Fiber FINAL FIELD 27-May-24 Transmittal Receipt ________________________________ X_________________________________ Print Name Signature Date Please return via courier or sign/scan and email a copy to Schlumberger. Nraasch@slb.com SLB Auditor - TRANSMITTAL DATE TRANSMITTAL # A Delivery Receipt signature confirms that a package (box, envelope, etc.) has been received. The package will be handled/delivered per standard company reception procedures. The package's contents have not been verified but should be assumed to contain the above noted media. # Schlumberger-Private T39122 T39123 T39124 T39125 T39126 T39127 T39128 T39129 T39130 T39131 T39132 T39133 2T-41 50-103-20675-00-00 213-146 Kuparuk River WL PPROF FINAL FIELD 7-Apr-24 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.05 10:30:21 -08'00' 0c • ! .r4. v - o N a, c1.6r- m -(.7.) > Y > X fop Q1 co C 3 Q � Q Y VI O v a O UJ y w ,0., a) Y L C O lin U . 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O N # O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 CSI OMB t#9 /� u ' UUUU ❑ ❑ ❑ E ILI ��f co ca 0o co U U U d aN U' C7 a a o to J x CC W O ❑ ❑ ❑ U U U 5 N -, ... .4 a U S 0 0 0 0 0 0 tL o 0 0 0 0 0 U E c 0 o 0 iri N 6 t- IA N 1- do �'' Y MMM1 0) r tO !- 0) tO �^ 0) co 0_ m 0 0) v m N., 0 0 0 N N �'r - Q ty N N N N N N 0.1 L F. 6 do M 0 0) 0) E • a N O N 0 N N N H 0 Q� O O O O O C U O O O O O O O ` c CL O L In U) ID II) In In N4' O O �,,, C u O O O O) E 4) _ _ U Q, W N e71 a 2 CO IA CO a cc v �� O GC d Z O 7 O V LID Y E y w , y l/1 • m ry N N N N M ❑ M E Z ty 'D w C a a 1Q w In AP CD 8y .. 3 E � ` 1 III I l l F= . a 2\- 1 4 Ca MAY 17 21i WELL LOG TRANSMITTAL#903155639 A OC1 To: Alaska Oil and Gas Conservation Comm. May 13, 2016 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 DATA LOGGED CD Anchorage, Alaska 99501 5 VY/2 01idi.K.BENDER RE: Production Profile: 2T-41 Run Date: 2/12/2016 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Fanny Sari, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage,AK 99518 FRS_ANC@halliburton.com 2T-41 Digital Data in LAS format, Digital Log Image file, Interpretation Report 1 CD Rom 50-103-20675-00 Production Profile Log 1 Color Log 50-103-20675-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNIN_ G A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline &Perforating Perforating SCANNED Attn: Fanny Sari v 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-275-2605 Fax: 907-273-3535 r._ FRS_ANC@halliburton.com Date: Signed: / ✓Qga'fr'°v - / -edt'`'"C RECEINitti 11LTE OF ALASKA FEB 7 2016 AKA OIL AND GAS CONSERVATION COMMSION 2 6 9 4 1 REPORT OF SUNDRY WELL OPERATIONS Anne ` 1.Operations Abandon — Plug Perforations r.- Fracture Stimulate Iv. Pull Tubing r Operations Shutdown Performed: Suspend Perforate .... Other Stimulate r Alter Casing r Change Approved Program r- Plug for Redrill I Perforate New Pool I Repair Well i Re-enter Susp Well ', 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number ConocoPhillips Alaska, Inc. Development IExploratory 1 213-146 3.Address: 6.API Number: P. O. Box 100360,Anchorage,Alaska 99510 Stratigraphic , Service 50-103-20675-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 25569 KRU 2T-41 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): none Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 7946 feet Plugs(measured) None true vertical 6213 feet Junk(measured) None Effective Depth measured 7946 feet Packer(measured) 0 true vertical 6213 feet (true vertical) 0 Casing Length Size MD TVD Burst Collapse CONDUCTOR 133 16 133.5 133.5 0 0 SURFACE 3196.9 10 3/4 3196.9 2580 0 0 INTERMEDIATE 7222.2 7 5/8 7222.2 5684.6 0 0 LINER 7946.5 512 7946.5 6212.3 0 0 Perforation depth: Measured depth: 7368-7408, 7490-7550 c True Vertical Depth: 5793-5822, 5882-5925 APR 0 8 2016 swine° Tubing(size,grade, MD,and TVD) 3.5, L-80, 6884 MD, 5425 TVD Packers&SSSV(type,MD,and TVD) PACKER-Baker Premier Packer @ 6892 MD and 5431 TVD, HRDE ZXP Liner Top Packer @ 6992 MD and 5509 TVD, BAKER FA-1 Production Packer @ 7472 MD and 5869 TVD SSSV: NONE 12.Stimulation or cement squeeze summary: Intervals treated(measured): 7368-7408, 7368-7408, 7490-7550, 7490-7550 Treatment descriptions including volumes used and final pressure: PERFORMED C-SAND FRACTURE TREATMENT AT 20 BPM,PLACING 47K#OF 16/20 FRAC SAND(47%OF DESIGN).WELL SCREENED OUT ON 5 PPA STAGE 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 242 184 280 986 260 Subsequent to operation 347 192 _ 489 1033 219 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations F' Exploratory i...... Development iv Service I Stratigraphic Copies of Logs and Surveys Run I c,:oVi 16.Well Status after work: Oil iv Gas I.... WDSPL r Printed and Electronic Fracture Stimulation Datari GSTOR WINJ — WAG i W GINJ I....... SUSP r SPLUG T 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 315-759 Contact Michael Hazen 265-1032 Email hazenmc(a. conocophillips.com Printed Name Mich-- Ha -n Title Wells Engineer Signatureall1/4 '` - Phone:265-1032 Date l& ffEE3 IL, VTi- 3r1IL t,b4,1 /# 3a1, '' eV c«revcd Form 10-404 Revised 5/20 5 Submit Original Only 311tp0o BDMS L FES 1 8 216 a KUPD • 2T-41 ConocoPhi lips a t Well Attribu Max Angl D TD Alaska II.,,,, Wellbore APVUWI Field Name Wellbore Status ncl(°t MD(ftKB) Act Btm(ftKB) 0.000 hrgrps 1'81 501032067500 KUPARUK RIVER UNIT PROD 57.72 3,106.62 7,988.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date DEVIATED-2T-41,2/12/201612:15:05 PM SSSV:NIPPLE 14 3/20/2014 Last WO: 27.50 11/28/2013 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag'SLM 7,757.0 1/16/2016 Rev Reason:TAG,GLV C/0 pproven 1/18/2016 HANGER,23.4 .x[aI.1';. Casing Strings ® Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread 1",.' : CONDUCTOR 16 15.250 27.5 133.5 133.5 65.00 H-40 Welded Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread SURFACE 103/4 9.950 28.5 3,196.9 2,580.0 45.50 L-80 Hydril 563 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread ti ti' INTERMEDIATE 75/8 6.875 25.6 7,2222 5,684.6 29.70 L-80 Hydril 563 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread LINER 51/2 4.892 6,992.5 7,946.5 6,212.3 17.00 P-110 DWC-C Liner Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Dec Com (in) CONDUCTOR;27.5-133.5 6,992.5 5,508.6 39.93 PACKER "HRDE":ZXP LINER TOP PACKER w/10'TIE- 4.930 III BACK SLEEVE NIPPLE,413.4 = 7,012.3 5,523.8 39.91 NIPPLE "RS"PACKOFF SEAL NIPPLE 4.880 ii 7,015.1 5,526.0 39.91 HANGER "DG"FLEX LOCK LINER HANGER 4.810 .r Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth In.. Set Depth(ND)(...Wt(Ib/ft) Grade Top Connection I I TUBING I 31/21 2.992 23.41 6,884.91 5,426.21 9.30 L-80 IEUE Completion Details 6 li 1 I Nominal ID 1 Top(ftKB( Top(TVD)(ftKB) Top Incl(°) Item Des Com (in) 23.4 23.4 0.00 HANGER FMC TUBING HANGER 3.958 24.1 24.1 0.00 FMC TUBING HANGER 57.9 57.9 0.23 XO Reducing X/0 4-1/2"IBTM Box X 3-1/2"EUE Pin 2.992 GAS LIFT;3,196.9 - SURFACE,28.63,196.9 413.4 412.6 7.09 NIPPLE •CAMCO DS NIPPLE 2.875 I` 6,844.2 5,394.9 39.44 NIPPLE HES"X"NIPPLE 2.812 6,862.2 5,408.7 39.59 SEAL ASSY 'BAKER 80-40 PBR w/20'stroke 3.000 Tubing DescriptionString Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(ND)(...Wt(lb/It) Grade Top Connection STACKER PACKER I 31/21 2.9921 6,86727 7,473 .31 5,870.31 9.201P -110 J Hydril 563 Completion Details _I Nominal ID Top(ftKB) Top(ND)(ftKB) Top Ind(°) Item Des Com (in) Gas LIFT,4 919 6,867.2 5,412.6 39.63 PBR BAKER 80-40 PBR w/20'Stroke,Pinned w/40,000# 3.000 Shear 6,892.4 5,431.9 39.85 PACKER BAKER PREMIER PACKER 659-287 2.870 GAS LIFT.5,602.1 - 7,353.9 5,783.3 42.77 BLAST RING CARBIDE BLAST RING on 2jts P-110 pipe(overlap C 2.992 _ sand pert's+5')50'of blast rings. 7,457.4 5,858.8 43.67 SLEEVE-0 3.5 CMU SLIDING SLEEVE 2.813'X'PROFILE 2.813 GAS LIFT;6,4182 (OPENED 1/7/2016) 7,471.6 5,869.0 43.87 SEAL ASSY KBH-22 ANCHOR SEAL ASSY 2.990 Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection FA PACKER 4.55 3.000 7,472.0 7,479.0 5,874.4 9.20 L-80 GAS LIFT;6,765.2 r. Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Corn (in) MIN 7,472.0 5,869.3 43.87 PACKER BAKER FA-1 PRODUCTION PACKER(4.55 OD AND 3.000 NIPPLE;6,844.2 -:: :: 3.0 ID are for the Packer not the tubing.WV chooses al longest section in tubing) SEAL ASSY;6,882.2 - 7,476.8 5,872.8 43.94 NIPPLE HES 2.75"D"NIPPLE 2.750 PBR;6,887.2 - 7,478.1 5,873.7 43.95 WLEG WIRELINE GUIDE SHEAR OUT SUB-(WLEG has not 2.950 00 Thread;6,890.6 been sheared open) PACKER;6,892.4 - - Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) XO Thread;6,899.0 Top(TVD) Top Incl Top(ftKB) (ftKB) (°) Des fRA Com Run Date ID(in) 7,244.3 5,701 4 40.54 Radioactive Tag installed in 5-1/2"liner,pin end of joint#18. 11/22/2013 Marker Perforations&Slots Shot Dens Top(ND) Btm(TVD) (shoal Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com r. I 7,368.0 7,388.0 5,793.6 5,808.2 C-4,2T-41 11/25/2013 6.0 IPERF 3 3/8 Millenum Gun,25 Gram 60 Deg Phase 1 1 7,388.0 7,408.0 5,808.2 5,822.9 C-4,2T-41 11/25/2013 6.0 (PERF 3 3/8 Millenum Gun,25 Gram 60 Deg Phase INTERMEDIATE;25.6-7,222.2--. RadioacSve Marker,7,244.3 7,490.0 7,510.0 ..6 A-3,2T-41 11/25/2013 6.0 IPERF 3 1/8 Millenum Gun,21 IPERF;7,368.0-7,388.0 p s Gram 60 Deg SVM Frac;7,368.0 BLAST RING;7,353.9 r. 7,510.0 7,530.0 . • 1• 1 6.0 IPERF 3 1/8 Millenum Gun,21 - (PERF;7,388.0-7,408.0 _ 60 Deg Sand Frac;7,3800 7,530.0 7,550.0 5,910.9 5,925.1 A-3,2T-41 11/25/2013 •1 IPERF 3 1/8 Millenum Gun,21 litt Gram 1 Deg Phase Stimulations&Treatments XO Thread;7,455.4 SLEEVE-0;7,457.4 III, Min Top Max BtmDepth Depth Top ITVD) Btm(TVD) 1; (ftK13) (ftKB) (ftKB) (ftKB) Type Date Com - 7,368.0 7,408.0 5,793.6 5,808.2 Sand Frac 1/10/2016.6 • ERFORMED C-SAND FRACTURE TREATMENT AT SEAL ASSY;7,471 I • 1 FRAC SAND PACKER;7,472.0 '•OF• •OUT ON 5 I■I PPA STAGE *' PERFORMED 1 • • 1 FRAC SAND NIPPLE;7,476.8 r: ._ WLEG;7,478.1 _� • • • •• • N 5 PPA STAGE (PERF;7,490.07,510 0 FRAC;7,490.01 , ••1 1 7,550.0 1 Gel Placing HPBD;7,490.0 I 01201 • 1 (101%of Design) 07,530.0 , IPERF;7,530.0-7,5500 , 7,490.0 1 1 :• 1 1 bbls sea water at :1. IPERF;7,510. pumped 1 bbls freeze protect LINER;6,992.5-7,948.5 a KUP 10)13 • 2T-41 ConocoPhilllps Alaska,Inc. Conoco hips DEVIATED-2T-41,2112/2016 12.15.05 PM Vertmal schema9E(actual} HANGER;23.4— L1.i P.,.. Mandrel Inserts I Sc au °^ Top(TVD) Valve Latch PortSize TRO Run d Top(RKB) (0KB) Make Model OD(in) Sere Type Type (in) (psi) Run Date Com 1 3,192.0 2,577.4 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.188 1,298.0 1/16!2016 a! rr- 2 4,912.9 3,697.4 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.188 1,278.0 1/16/2016 • 3 5,802.1 4,492.3 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.188 1,259.0 1/17/2016 4 6,418.3 5,044.0 CAMCO MMG 1 1/2 GAS LIFT OV RK 0.250 0.0 1/17/2016 5 6,785.2 5,349.0 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 8/23/2014 it' Notes:General&Safety CONDUCTOR;27.5-133.5 1, . End Date Annotation IFNote: NIPPLE,413.4 •; IS GAS LIFT;3,1920 SURFACE,28.5-3,196.9-9 of sa GAS LIFT,4,912.9 III IP GAS LIFT;5,802.1 -. it GAS LIFT;8418.2 ant III GAS LIFT,6,785.2 lir aig NIPPLE,6,844.2 it ID SEAL ASSY;6,862.2` MR,6,867.21 r. I XO Thread;6,890.6 s PACKER,6,892.4 7. _ XO Thread,6,899.0 l INTERMEDIATE 25.6-7222.2 A Radioactive Marker,7,244.3— IPERF;7,368.0-7,388.0 Sand Frac,7,368.0 sk BLAST RING;7,353.9 r IPERF;7,388.0-7,408.0 I Sand Frac,7,388.0 r MK it XO Thread,7,455.4 SLEEVE-O,7,457.4 - SEAL ASSY;7,471.6 PACKER;7,472.0 I _ Or NIPPLE;7,476.8 g. WLEG;7,478.1 r in— IPERF,7,490.0-7,5100 FRAC;7,490.01 , •-1 HPBD;7,490.0 IPERF,7,510.0-7,530.0 (PERF;7,530.0.7,550.0 LINER;6,992.5-7,946.5 L • • 2T-41 DTTMS.JOBTYP SUMMARYOPS 1/7/16 *COPY* DUMP BAIL 15' OF SILICA SAND BRINGING TOS TO 7465' RKB; ATTEMPT TO FRACTURING PT &ABLE TO PUMP .18 BPM @ 2500 PSI (TBG BLEEDS DOWN & HOLDS @ 1000 PSI); RE-TAG TOS @ SAME; OPEN CMU @ 7457' RKB & OBTAIN INJECTIVITY RATE OF 2 BPM @ 2600 PSI. JOB COMPLETE. 1/7/16 FRACTURING DUMP BAIL 15' OF SILICA SAND BRINGING TOS TO 7465' RKB; ATTEMPT TO PT&ABLE TO PUMP .18 BPM @ 2500 PSI (TBG BLEEDS DOWN & HOLDS @ 1000 PSI); RE-TAG TOS @ SAME; OPEN CMU © 7457' RKB & OBTAIN INJECTIVITY RATE OF 2 BPM @ 2600 PSI. JOB COMPLETE. 1/10/16 FRACTURING PERFORMED C-SAND FRACTURE TREATMENT AT 20 BPM, PLACING 47K#OF 16/20 FRAC SAND (47% OF DESIGN). WELL SCREENED OUT ON 5 PPA 1/14/16 FRACTURING Post-Frac Fill Clean out performed down to TD at 7,815' CTMD utilizing SSW with PowerVis gel sweeps. Samples at return tanks contained thick Frac Gel with moderate to heavy amounts of Frac Proppant and sand plug sand in gel pills. Approximate 265' of rathole. Well Freeze protected. Ready for Slickline. ***Job in 1/16/16 FRACTURING TAGGED TD © 7757' SLM (EST. 220' RAT HOLE); SET 2.84" CATCHER @ 6844' RKB; PULLED DV'S @ 6418', 5802', 4912', & 3192' RKB; SET GLV'S @ 3192' & 4912' RKB. IN PROGRESS. 1/17/16 FRACTURING SET GLV© 5802' RKB & OV @ 6418' RKB; OBTAIN GOOD TT W/ HOLEFINDER & PULL CATCHER @ 6844' RKB. JOB COMPLETE. ` • • U) c m E 0 E co cr; 0 co 0 ii W N O F 0 © r (U (OOO. ,,) ,...... , a) f3 •5 ca ti 0 0 0 0 E '5 L E E CD L Unu n c O N Q c o 0 0 0 0 0 * 00 0 0 0 0 .i ,'';,, tii) 0 0 0 0 0 0 •M v Lam++ v c p a, cin o 0 0 0 0 0 N ( ' n CD cB :„.-E ? 0 0 0 0 00 cD 0 O ID C ° O a) U — Q �': CU co .L c �CC - V a U C a O (f) 1.. s c6 z 0 c�0 0 0� a� U 2 N N Q < Q U) (co O r--- O O < Z Z 7 (o (-D N- u7 y a) — � (ri ca 02 a) is m C u) 0 O O CO RS T O 0 () O O Cr) U N N- O - (0 O a) 7r 0 0 CO 'U1- O a Co _w CO 0 0 E- ti Q Z N u) N E CNI O N Q C O O N O < (NC) 7 m E rn Z 0 - - - N- 7 N N C - (a V L (O pp c[ O co as E N E E RI O O d U n) 0 = N ♦+ N N- O mEo) ,- N a) C.) o Q Q < Q (U a) a) C6 0 `o Z Z 7 , n U oO 0_ co Co O- N C Y C d C O C 1E—a_ • C Q w•' co6 O C U '- •O 0-O N TV 0 _ 7 -6 C U 6 O j o M N O O U . 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(., () CO CO -co 0 0 0 0 a a 0 0 2 CO o CO CO o CO o CO CO CO CO CO CO 0 0 0 0 0 0 0 0 -- 0 CO 0 0 0 CO 0 0 0 0 CO CO 0 0 0 0 0 0 0 0 0 U) CO 0 0 0 0 0 0 0 CO CO 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 OO o 0 0 0 0 0 0 0 0 0 0 p CO 6O 6O CO CO CO CO LO . ,- CO .- CO .-- N- L- CO L CO CO (D CO CO CO CO CO CO Ci) (6 C6 a T a) co • U) C6 aa) a o v _ CO co -a g To rn LO > d. N V O CO C CO c CO CO co Ln O C CO O O CO O) . A p (D p co (O co d- h._ N N p co COOn N -0 OD N N In CO .O Cj -O C%) N LO CO (`� -p c n L� CO CO 0) ti CO 'C CO 4- CO N a) co N CO CO V 4= CO CO CO N n N- N CO V O CO co 4 N- N 0 d' 0 N .N- CO CO N CO CO O CO CO o ) CO C.) T. CO N- = C0 x- C.) a) ,- ,- N- CO N 0) C.) a) CoCn E CO LSE N O 0) o L O C L 'p 0 = C`. N c n O N O-0 .� E a) 0 N N > N C a)E n EI-2 a) O O U N N p E C6 U p p Q) 'O (E6 >'m T c N CO 1) O-0 -0- (6 (6 T.T j a) p (U n L a) p T C O C O a) a) '� .L...L p Q C C E'O 'O (`� N C O -p N T a) (U -p n ...r..1 ,N x -N (6 c.-1--• L OX U) E p p E C C6 L N .X U :72N E p p (6 L U a) O N >' a) d U) U o n a) p a) C n_X U o T C a X E >. - T 6 E -p E n E N U (V N CU L p 'C OU >' L • O j X E — 0 ` 4 C T O p f — T .� L N (6 C • (U Y C E",5 >...-d (6 p E U N 0) U n E C `p L o o a) (S E p D o >,m = o o m o O : 2-o i - u m , ♦ . v i . I . ♦ ♦ m-0 - C 0 00 O. • E 0.- V.0 LL 00 U Ca L N c 3-o c o a) c� no a,rn a) U �CK o LL • wU L.0 �rn U N w N 0 O p O O U -o n n•p 0 E '-'.a C E U V) > x "O (6 E E O U LL E CO N U.L.. C L p U O C 153-. O O pp C E m >_o 0 2 a)16 o - 0 E • c a) O .-C N @ E O aa)) LL (6 O O C p N F— O O) « « z E 8,OF 7,4 •• • 4w,\\��%%,�4 THE STATE w o Alaska Oil and Gas f L Conservati®n Commission _ 333 West Seventh Avenue ITh, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 of ALASitP Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Michael Hazen Wells Engineer SCANNED t ` 1 ConocoPhillips Alaska, LLC P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2T-41 Permit to Drill Number: 213-146 Sundry Number: 315-759 Dear Mr. Hazen: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy '. Foerster �,y/_ Chair DATED this �,'S' day of January, 2016. RBDMS'JAN 1 12016 0 RECEIVED STATE OF ALASKA DEC 16 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS qhs r l.0 20 AAC 25.280 1.Type of Request: Abandon El Plug Perforations❑ Fracture Stimulate ❑., - Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing El Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska,Inc. , Exploratory ❑ Development ❑l . 213-146-0 ` 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: P.O.Box 100360,Anchorage,AK 99510 50-103-20675-00 ,, 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? none KRU 2T-41 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 25569 . Kuparuk River Field/Kuparuk River Oil Pool 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): 7946 6213 7946 6213 820 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 133 16 133.5 133.5 Surface 3196.9 10 3/4 3196.9 2580 Intermediate 7222.2 7 5/8 7222.2 5684.6 Production Liner 7946.5 51/2 7946.5 6212.3 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 7368-7408,7490-7550 . 5793-5822,5882-5925 3 1/2 L-80 6884 Packers and SSSV Type: Baker Premier Pckr(7-5/8 x 3.5")2.875"ID Packers and SSSV MD(ft)and TVD(ft): • Baker Premier Packer 6892'MD,5431'TVD No SSSV Baker FA-1 Prod Pckr(4.5 x 3.5")3.0"ID No SSSV , Baker FA-1 Prod Pckr 7472'MD,5869'TVD 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program El BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑✓ ' Service ❑ 14.Estimated Date for 15.Well Status after proposed work: January 6th,2016 Commencing Operations: OIL ❑ ' WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown El Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Michael Hazen 265-1032 Email hazenmc(a�conocophillips.com Printed Name Michael Ap Title Wells Engineer `Ai-,-,-' 265.--/032- 1,51E-C2 015" Signature Phone Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 315- 759 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: &Lac(Kssure ei 3.-00rsk on IA Ilwr,nc C . Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No d Subsequent Form Required: f Q -4 U 4 APPROVED BY Approved by: i° ,;,2.4...4..1 COMMISSIONER THE COMMISSION Date: - 5� /6 OAR0IeG144Akid RSMSForm 10-ao3 R ised 11/205 for 12 months from the d t of approval. !D rah itFL- / 5/76 1����� t✓ow lig/zo16 Ott • S ConocoPhillips Alaska, Inc. Paul K.Wharton Staff Landman P.O.Box 100360—Suite ATO 1482 Anchorage,Alaska 99510-0360 Phone(907)263-4076 Fax (907)263-4966 Paul.K.Wharton@conocophillips.corn To: Operator and Owners (shown on Exhibit 2) Re: Notice pursuant to 20 AAC 25.283 (1) 2T-41 Kuparuk River Unit, Alaska ADL 25569, KRU Tract 44 Dear Sirs: ConocoPhillips Alaska, Inc. ("CPAI") as Operator and on behalf of the Kuparuk River Unit ("KRU") working interest owners, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing pursuant to the provisions of 20 AAC 25.280 ("Application") for the 2T-41 Well (the "Well"). The Application will be filed with the Alaska Oil and Gas Conservation Commission ("AOGCC") on or about December 15, 2015. This Notice is being provided pursuant to 20 AAC 25.283. The Well has been drilled as a directional well on lease ADL 25569, KRU Tract 44 as depicted on Exhibit 1 as follows: Surface Location: 5183' FNL, 4722' FEL, Section 1, T11N, RO8E, UM Target Location: 1130' FNL, 1946' FEL, Section 11, T11N, RO8E, UM Bottomhole Location: 953' FNL, 1980' FEL, Section 11, T11N, RO8E, UM Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well, including the reservoir section ("Notification Area"). Exhibit 2 is a list of the names and addresses of all owners, landowners and operators of record of all properties within the Notification Area. Upon your request CPAI will provide a complete copy of the Application to you. If you require any additional information, please contact the undersigned. Very truly yours, Paul Wharton Staff Landman cc: Mike Hazen Rebecca Swensen • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 1 -Affidavit 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that owners, landowners, surface owners, and operators, within one- half mile radius of the current or proposed wellbore trajectory, have been provided notice of operations in compliance with 20 AAC 25.283(a)(1). 21-41 Hydraulic Fracturing Notice Letter December 14, 2015 Page 2 Exhibit 1 2T-41 Hydraulic Fracturing Notice Lett • December 14, 2015 Page 3 A.CLC249 ADL025548 T12N R8EConocoPhillips 2T-41 Well Alasxa 12+07!15 '/2 mile radius from Well i D S2T ADL0255f+87..°''''''''''''"'""'""#"°'ml . ACLO2 f e 44 2T e8 1 l.CLO2F• \\\:\ ?Y T11NR9E T11NR8E MINE SITE F ACL02t57fl Legend REFERENCES Well Data ConocoPhillips Alaska Well Database iATDB) • Frac Point Surface Facilities ATDB N Open Section Well Trajectory 0 1.2 mi. Buffer 0 015 03 045 06 Miles i ] CP..I Lease 2T-41 Hydraulic Fracturing Notice Lette'T" December 14, 2015 Page 4 Exhibit 2 Mineral Owners: Operator: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO 1226 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attention: Erik Keskula, NS Development Manager Non-Operators: BP Exploration (Alaska) Inc. P.O. Box 196612 900 E. Benson Boulevard (Zip 99508) Anchorage, AK 99519-6612 Attention: Mr. Robert Kinnear Chevron U.S.A. Inc. 310 K Street, Suite 406 Anchorage, AK 99501 Attention: Mr. Glenn Fredrick ExxonMobil Alaska Production Inc. P.O. Box 196601 3301 C Street, Suite 400 (Zip 99503) Anchorage, AK 99519-6601 Attention: Mr. Gilbert Wong Surface Owners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Attention: Director North Slope Borough (ADL 417951) PO Box 69 Barrow, AK 99723 Attention: Planning Department • TO THEPLASKA OIL AND GAS CONSERVATION COMMISSION Before the Commissioners of the Alaska Oil and Gas Conservation ) Commission in the Matter of the ) AFFIDAVIT OF Paul K.Wharton Request of ConocoPhillips Alaska, Inc. for Hydraulic fracturing for the 2T-41 Well under the Provisions of 20AAC 25.280 ) STATE OF ALASKA ) §§ THIRD JUDICIAL DISTRICT Paul K.Wharton, being first duly sworn, upon oath, deposes and states as follows: 1. My name is Paul K. Wharton. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. I am Staff Landman for the well operator, ConocoPhillips Alaska, Inc. ("CPAI") 3. Pursuant to 20 AAC 25.283 (1) CPAI prepared the attached Notice of Operations ("Notice"). 4. On December 15, 2015, CPAI sent a copy of the Notice by certified mail to the last known address of all other owners, landowners, surface owners, and operators of record within a one-half mile radius of the current proposed well trajectory. Subscribed and sworn to this 15th day of December, 2015. Pa�Wharton STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT This instrument was acknowledged before me this 15th day of December, 2015, by Paul K.Wharton. Notary Public, State of Alaska My Commission Expires: STATE OF ALASKA NOTARY PUBLIC REBECCA SWENSEN Ie -� 4,My Commission Expires Aug.27,2016 • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 2— Plat 20 AAC 25.283 (a)(2) 0 • ConocoPhillips 2T-41 Plat Analysis Alaska WELLS 11/23/15 ,\III\b� cn v , N 2 , N N T � � / O � D-\ o r22 cT l ; 2T-39 �` `1,1 til 21-0' 21 OSP 2-x-201 2,T-2°A .i..±/ �'p7 if 21-18 , '.73 � 0.0 10v1A1 v. It 'c' MINE SITE F - Well in 1/2 mi. Radius of Open Interval REFERENCES: Well Data: ConocoPhillips Alaska Well Database (ATDB) - Wells in 1/2 mi. Radius of Trajectory Surface Facilities:ATDB ^' Well Trajectory I V Open Section 2T-41openBuff 0 0.1 0.2 0.3 0.4 Miles Ej 1/2 Mile Radius • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application WELL NAME PERMIT NUMBER API BUSINESS AREA DRILLSITE FLUID TYPE STATUS WELL TYPE 21-16 186-046 501032006300 KRU 2T MWAG SUSP INJ 2T-03A 213-039 501032007301 KRU 2T OIL ACTIVE PROD 2T-21 195-013 501032021200 KRU 2T OIL SUSP PROD 2T-12 /g(21168 098 501032006600 KRU 2T PA EXPEND 2T-218 203-017 501032044900 KRU 2T OIL ACTIVE PROD 21-201 195-122 501032023000 KRU 2T MWAG ACTIVE INJ 2T-10L1 214-065 501032006460 KRU 2T OIL ACTIVE PROD 2T-207 198-231 501032027800 KRU 2T OIL ACTIVE PROD 2T-38 195-112 501032022900 KRU 2T PA EXPEND 2T-41 213-146 501032067500 KRU 2T OIL ACTIVE PROD 2T-22 195-086 501032022400 KRU 2T OIL ACTIVE PROD 2T-39 201-183 501032039200 KRU 2T OIL ACTIVE PROD 2T-10 186-096 501032006400 KRU 2T OIL ACTIVE PROD 2T-19 195-026 501032021400 KRU 2T OIL ACTIVE PROD 2T-04 186-143 501032007400 KRU 2T MWAG SUSP INJ 2T-36 195-102 501032022800 KRU 2T MWAG ACTIVE INJ 2T-07 186-108 501032006900 KRU 2T PA EXPEND 2T-10L1-01 214-066 501032006461 KRU 2T OIL ACTIVE PROD 2T-38A 197-205 501032022901 KRU 2T OIL ACTIVE PROD 2T-15 186-045 501032006200 KRU 2T MWAG ACTIVE INJ 2T-18 195-017 501032021300 KRU 2T MWAG ACTIVE INJ 2T-14 I86-O4111 18G 084 501032006100 KRU 2T OIL ACTIVE PROD 2T-37 195-101 501032022700 KRU 2T OIL ACTIVE PROD 2T-12A 186-128 501032006601 KRU 2T PA EXPEND • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 3—Freshwater Aquifers 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. See conclusion of the Aquifer Exemption Title 40 CFR 147.102 (b) (3), which states "The portions of aquifers on the North Slope described by a 1/4 mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field." ELECTRONIC CODE OF FEDERAL REGULATIONS View past updates to the e-CFR. Click here to learn more. e-CFR data is current as of August 18, 2015 Title 40—>Chapter I —> Subchapter D—f Part 147-->Subpart C Title 40: Protection of Environment PART 147—STATE, TRIBAL, AND EPA-ADMINISTERED UNDERGROUND INJECTION CONTROL PROGRAMS Subpart C—Alaska Contents §147.102 Aquifer exemptions. §147.102 Aquifer exemptions. (a)This section identifies any aquifers or their portions exempted in accordance with §§144.7(b) and 146.4 of this chapter at the time of program promulgation. EPA may in the future exempt other aquifers or portions, according to applicable procedures,without codifying such exemptions in this section. An updated list of exemptions will be maintained in the Regional office. (b)The following aquifers are exempted in accordance with the provisions of§§144.7(b) and 146.4 of this chapter for Class II injection activities only: (1)The portions of aquifers in the Kenai Peninsula, greater than the indicated depths below the ground surface, and described by a 1/4 mile area beyond and lying directly below the following oil and gas producing fields: (i) Swanson River Field-1700 feet. (ii) Beaver Creek Field-1650 feet. (iii) Kenai Gas Field-1300 feet. (2)The portion of aquifers beneath Cook Inlet described by a 1/4 mile area beyond and lying directly below the following oil and gas producing fields: (i) Granite Point. (ii) McArthur River Field. (Hi) Middle Ground Shoal Field. (iv)Trading Bay Field. (3)The portions of aquifers on the North Slope described by a '/4 mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field. • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 4— Plan for Baseline Water Sampling for Water Wells 20 AAC 25.283(a)(4) There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable.' • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 5— Detailed Cementing and Casing Information 20 AAC 25.283(a)(5) All casing is cemented in accordance with 20 AAC 25.52(b) and was tested in accordance with 20 AAC 25.030 (g) when completed. See Wellbore schematic on following two pages for casing details. KUP PROD 2T-41 ConocoPhillips ; Well Attributes Max Angle&MD TD Alaska Inc Wellbore API/DWI Field Name Wellbore Status ncl(°) MD(ftKB) Act Btm(ftKB) 0,..,0,4,• dips 501032067500 KUPARUK RIVER UNIT PROD 57.72 3,106.62 7,988.0 --• Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date DEVIATED-2T-41,9/27/20142-.03.19 PM SSSV:NIPPLE 14 3202014 Last WO: 27.50 11/28/2013 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date ----------------------------- - ---Last Tag:SLM 7,728.0 4/28/2014 Rev Reason:HPBD,Pull Catcher/Plug/Gauges, hipshkf 9/22/2014 HANGER;23.4- „:(p,•!,)21), GLV C/O,Cycle CMU C" Casing Strings ■ Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...WtlLen(I...Grade Top Thread CONDUCTOR 16 15.250 27.5 133.5 133.5 65.00 H-40 Welded Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(IVO)... Wt/Len(I...Grade Top Thread 10 3/4 9.950 28.5 3,196.9 2,580.0 45.50 L-80 Hydril 563 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread -11 INTERMEDIATE 75/8 6.875 25.6 7,222.2 5,684.6 29.70 L-80 Hydril 563 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...WtlLen(I...Grade Top Thread LINER 51/2 4.892 6,992.5 7,946.5 6,2123 17.00 P-110 DWC-C Liner Details Nominal ID CONs'''‘ Top(ftKB) Top(ND)(ftKB) Top Incl(9) Item Des Com (in) DUR;27.5- CTO133.5 6,992.5 5,508.6 39.93 PACKER "HRDE":ZXP LINER TOP PACKER w/10'TIE- 4.930 -- BACK SLEEVE NIPPLE;413.4 s 7,012.3 5,523.8 39.91 NIPPLE "RS"PACKOFF SEAL NIPPLE 4.880 7,015.1 5,526.0 39.91 HANGER "DG"FLEX LOCK LINER HANGER 4.810 Tubing Strings Tubing Description I String Ma...I ID(in) I Top(ftKB) I Set Depth(ft..f Set Depth(TVD)(...I Wt(Ib/ft) I Grade I Top Connection �i -. . I TUBING 31/2 2.992 234 6,884.91 5,4262 9.301L-80 EUE Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Inel(9) Item Des Com (in) 23.4 23.4 0.00 HANGER FMC TUBING HANGER 3.958 57.9 57.9 023 XO Reducing X/O 4-1/2"IBTM Box X 3-1/2"EUE Pin 2992 413.4 412.6 7.09 NIPPLE CAMCO DS NIPPLE 2.875 GAS LIFT;3,192.0 )i 6,844.2 5,394.9 39.44 NIPPLE HES X NIPPLE 2.812 SURFACE;28.5-3,196.9 ---- I 6,862.2 Tubing Description (5,408.7 39.59 SEAL ASSY BAKER 80-40 PBR w/20'stroke 3.000 String Ma...IID(in) (Top(ftKB) Set Depth(ft..Sat Depth(ND)(...I WI(Ibitt) (Grade I Top Connection STACKER PACKER 31/2 2.992 6,867.2 7,473.3I5.8703 9.20 P-110 Hydril 563 ® Completion Details Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl("I Item Des Com (in) P 6,867.2 5,412.6 39.63 PBR BAKER 80-40 PBR w/20'Stroke,Pinned w/40,0008 3.000 GAS LIFT;4,912.9 - Shear GAS LIFT;5,802.1IIIIr- 6,892.4 5,431.9 39.85 PACKER BAKER PREMIER PACKER 659-287 2.870 7,353.9 5,783.3 42.77 BLAST RING CARBIDE BLAST RING on 2 its P-110 pipe(overlap C 2.992 sand peas+5')50'of blast rings. f� 7,457.4 5,858.8 43.67 SLEEVE-0 3.5 CMU SLIDING SLEEVE 2.813'X'PROFILE 2.813 lin ar /V'Jy� (OPENED 9/8/2014) �n1 / 7,471.6 5,869.0 43.87 SEAL ASSY KBH-22 ANCHOR SEAL ASSY 2.990 GAS LIFT;6,418.2 '1 Tubing Description I String Ma...I ID(in) (Top(ftKB) (Set Depth(ft..ISet Depth(ND)t..I Wt7.201 Ib/ft( (Grade (Top Connection �. J FA PACK(-R 4.55 3.000 7,472.0 7,479.0 5,874.4 9.20 L-80 Completion Details GAS LIFT;6,785.2 Nominal ID Top(ftKB) Top(ND)(ftKB) Top Incl(9) Item Des Com (in) 7,472.0 5,869.3 43.87 PACKER BAKER FA-1 PRODUCTION PACKER(4.55 OD AND 3.000 3.0 ID are for the Packer not the tubing.WV chooses longest section in tubing) NIPPLE;6,844.2 7,476.8 5,872.8 43.94 NIPPLE 'HES 2.75"D"NIPPLE 2.750 SEAL ASSY;6,862.21 7,478.1 5,873.7 43.95 WLEG WIRELINE GUIDE SHEAR OUT SUB-(WLEG has not 2.950 PBR;6,867.2 ' been sheared open)Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) DO Thread;6,890.6 L 1 Top(ND) Top Incl PACKER;6,892.4 ileTop(ftKB) (ftKB) (9) Des Com Run Date ID(in) Xo Thread;6,899.0 J 7,244.3 5,701.4 40.54 Radioactive RA Tag installed in 5-1/2"liner,pin end of joint#18. 1122/2013 Marker ':' k Perforations&Slots Shot Den Top(ND) Btm(ND) (shots/f 1 Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com 7,368.0 7,388.0 5,793.6 5,808.2 C-4,2T-41 11/25/2013 6.0 (PERF 33/8 Millenum Gun,25 Gram 60 Deg Phase 7,388.0 7,408.0 5,808.2 5,822.9 C-4,21-41 11/25/2013 6.0 IPERF 33/8 Millenum Gun,25 Gram 60 Deg Phase 7,490.0 7,510.0 5,882.3 5,896.6 A-3,2T-41 11/25/2013 6.0 IPERF 31/8 Millenum Gun,21 INTERMEDIATE,25.6-7222.2 Gram 60 Deg Phase Radioactive Marker;;7,244.3 7,510.0 7,530.0 5,896.6 5,910.9 A-3,27-41 11/25/2013 6.0 (PERF 3 1/8 Millenum Gun,21 Gram 60 Deg Phase (PERF;7,36807,388.01 7,530.0 7,550.0 5,910.9 5,925.1 A-3,2T-41 11/25/2013 6.0 IPERF '3 1/8 Millenum Gun,21 BLAST RING;7,353.9 Gram 60 Deg Phase (PERF;7,388.0-7,408.0 1 Stimulations&Treatments Min Top Mao Btm - Depth Depth Top(TVD) Btm(ND) XO Thread;7,455.4 (ftKB) (ftKB) )BK8) (ftKB) Type Date Com SLEEVE-O;7,457.4 7,490.0 7,550.0 5,882.3 5,925.1 FRAC 12/12/201 "A"Sand Frac w/25#Linear/X-Linked Gel Placing 3 01201 LBS OF 16/20 Proppant(101%of Design) 7,490.0 7,550.0 5,882.3 5,925.1 HPBD 9/3/2014 Pumped 5 bbls meth spear down tubing/pumped 720 SEAL ASSY;7,471.6 111' l bbls sea water at 180 bbls x 4,pumped 5 bbls meth/ PACKER;7,472.0 pumped 20 bbls freeze protect Mandrel Inserts 111. alt NIPPLE;7,476.8 l WLEG;7,478.1 on Top(ftKB) Top(ftKB)) Make Model OD In Sery Valve Latch Port Size TRO Run (PERF;7,090.07,510.0 N () Type Type (in) (psi) Run Date Com FRAC;7,490.0 - 1' 3,192.0 2,577.4 CAMCO MMG 11/2 GAS LIFT GLV RK 0.188 1,298.0 9/8/2014 HPBD;7,490.0 2 4,912.9 3,697.4 CAMCO MMG 11/2 GAS OFT GLV RK 0.188 1,278.0 9/8/2014 PERF;7,510.07,530.0 (PERF;7.530.0-7,550.0 3 5,8021 4,492.3 Camco MMG 11/2 GAS OFT GLV RK 0.188 1,259.0 9/7/2014 4 6,418.3 5,044.0 CAMCO MMG 1 1/2 GAS LIFT OV RK 0.250 0.0 9/7/2014 LINER;6,992.5-7,946.5 KUP PROD1111 2T-41 ConocoPhillips Alaska.Inc. CoraxoRullipa DEVIATED-2T-41,9/27/2014 2.03:21 PM Vertical schematic(actual) ............................................................... HANGER;23.4- ittini Mandrel Inserts C_ ] St ice N Top(TVD) Valve Latch Port Size TRO Run Top(11KB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com d 6,785.2 5,349.0 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 8/23/2014 I. Notes:General&Safety End Date Annotation Note CONDUCTOR;27.5-133.5 NIPPLE;413.4 GAS LIFT;3,192.0 SURFACE;28.53,196.9 GAS LIFT;4,912.9 II.. c4 GAS LIFT;5,802.1 I '` GAS LIFT;6,418.2 4: GAS LIFT;6.785.2 NIPPLE;6,844.2 SEAL APER;6,867.21 PBR;6,867.2 50 Thread;6890.6 PACKER;6,892.4 XO Thread;6,899.0 INTERMEDIATE;25.6-7,222.2-A Radioactive Marker;7,244.3 IPERF;7,368.0-7,388.0.E ii BLAST RING;7,353.9 �' i IPERF;7,388.0-7,408.0 XO Thread;7,455.4 SLEEVE-0;7.457.4 SEAL ASSY;7,471.6 PACKER;7,472.0 I a4 I NIPPLE;7,476.8 WLEG;7,478.1 =.. IPERF;7,490.0.7,510.0 FRAC;7,490.0 HPBD;7,490.0 IPERF;7,510.0.7,530.0 IPERF;7,530.0-7,550.0 LINER;6,992.5-7,946.5 i S Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 6—Assessment of Each Casing and Cementing Operation to be Performed to Construct or Repair the Well 20 AAC 25.283(a)(6) Casing&Cement Assessments: KRU 2T-41: The 10-3/4" casing cement pumping report on 11/9/2013 states the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 80-bbl of 8.4-ppg CW100, 83.4-bbl of 10.5-ppg MudPush-II spacer, followed by 588-bbl of 11.0-ppg lead cement, and 60-bbl of 12.0-ppg LiteCrete tail cement. Displacement consisted of 9.9-ppg mud at 5-bpm, 250-psi, staged up to 7-bpm and 550-psi. Pipe was reciprocated and full returns were observed throughout the job; had cement to surface at 900-stks. Cement was in place 00:32-hrs on 11/10/13 with 189-bbl of 11.0-ppg cement to surface. The 7-5/8" casing cement pumping report on 11/17/2013 shows that the job was pumped as designed, indicating competent cementing operations.The cement job was pumped in two stages, the first consisting of 40-bbl CW100, 40-bbl 12.5-ppg MudPush-II, first-stage bottom plug, 57-bbl (40%excess) 15.8-ppg lead cement, top plug, and 10-bbl water, displaced with 10.4-ppg LSND at 6- bpm, 400-psi. Plug bumped and floats held with no flowback.The first stage had CIP 19:50-hrs. Second stage after pressure up to 3350-psi to open ES Cementer, 40-bbl CW100,40-bbl 12.5-ppg MudPush-II, 17-bbl (40%excess) 16.0-ppg lead, 32.9-bbl 15.8-ppg tail cement, ES Cementer closing plug, 10-bbl water, the 10.4-ppg conditioned mud displacement at 6-bpm, 250-psi. Slowed rate to 3- bpm and bumped plug 1950 stks pressuring up to close ES cementer, 196-bbl. The 5-1/2" liner cement pumping report on 11/22/2013 shows that the job was pumped as designed, indicating competent cementing operations.The cement job consisted of 42.8-bbl of MudPush-II, followed by 27.5-bbl of 15.8-ppg class G tail slurry, cement dart launched with 10-bbl water, chased with rig pumps at 4-bpm, 500-psi. Observed latch up at 619-stks and plug bumped at 817-stks; pressured up to 2700-psi then 4u00-psi to set liner hanger and set down 40k to ensure set. With liner set, bled off pressure to test floats. Cement and liner pressure tested to 3000-psi. Cement bond logging was also performed over the 5-1/2" liner cement interval (7800-5800'MD) on 11/23/2013 and indicated good cement(TOC 5937') and zonal isolation between the A- and C-sands (final log presentation provided 12/26713). *16" surface casing driven. **An A-sand only (7490-7550'MD) fracture stimulation treatment was performed on KRU 2T-41 on 12/12/2013 with 25# linear and crosslinked gel placing 201,201-lb of 16/20 proppant behind pipe (101%design). Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 7—Pressure Test Information and Plans to Pressure-Test Casings and Tubing Installed in the Well 20 AAC 25.283(a)(7) On 10/15/2013 the 16" casing was driven and not cemented. On 11/12/2013 the 10-3/4" casing was pressure tested to 3000-psi for 30-min. On 11/12/2013 the 7-5/8" casing was pressure tested to 3000-psi for 30-min. On 8/23/2014 the 3.5"tubing was pressure tested to 4000-psi for 30-min. The 3.5"tubing will again be pressure tested to 4000-psi prior to starting the fracturing stimulation. • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 8—Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head 20 AAC 25.283(a)(8) Size Weight Grade API Burst API Collapse 16" 65 H-40 1,640-psi 630-psi 10-3/4" 45.5 L-80 3,580-psi 2,090-psi 7-5/8" 29.7 L-80 6,890-psi 4,790-psi 5.5" 17 P-110 10,640-psi 7,480-psi 3.5" 9.3 L-80 10,160-psi 10,540-psi 0 110 Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Stimulation Surface Rig-Up m a i • Minimum pressure rating on all surface Br ems• =4 i:1 P*4 Il treating lines 10,000-psi. Ti k: i� a • Main treating line PRV is set to 95%of max w 2> �:� treating pressure. • IA parallel PRV set to 3500-psi. • Frac pump trip pressure settings are PO 11:41 IPC• staggered and set below main treating line PRV. • Tree saver used on all fracs rated for 15,000- T, 5 1106 1 psi. er '� V ` to se . two _. d e 1- r m 71 0010r ii I 1 t )13n-11 diun6 d 1 p Cq1 Tank 1 Dil PopOflTa* —L� — PumrTru-k aN cZ a 7co cu Cr H 5.°3-4'7P81--- :r 3. t C 2.3 taa Frac Pump + 1—XJ--- —f --- - Frac Pump Frac Pump N �— m N l Frac Pump Frac Pump --Da, N Frac Pump • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application OPEN POSITION CLOSED POSITION (PRIOR TO MANDREL INSERTION) (MANDREL INSERTED) /FRAC IRON ,r cdNNECTION ...,,.. .. r r ,er i , i t i + i r TT ,REMOTE OPERATED . MATTER VALVEmmuinnom ��• Ft 1111- MANUAL OPERATED \ .... MASTER VALVE so worrommini fr. ak Stinger 1�^Stinger I 1 p MANDREL .1 L JJJ ,, , 1 ti j� VENT I ! •„^C.�r'.II—VALVE — — `N I OPEN uta ,Iti !"I 111111111114 ikT ' RJ, .....\ N. FLOW TEE AND � ,. ''i �c., VENT VALVE WELLHEAD Nla%wr;inl VALVES .7/I■,/.. OPEN �*'! WELLHEAD VALVES y �* CLOSED -°'t.,.,�47 '"'' (. dot1.. 1 L 4 1 E ` I ' QUAD PACKOFF7. ASSEMBLY IN no +.. PLACE IN TUBING upi ,,ate TUBING''- �✓ r • The universal tool is rated for 15,000-psi and has 84" of stroke. • Tool ID 2.25" down 4-%2" tubing and 1.75" down 3-%2" tubing. • Max rate with 2.25" mandrel is 60-bpm and with 1.75" mandrel 36-bpm. • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 9— Data for Fracturing Zone and Confining Zones 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone,the Kuparuk C sand interval, is approximately 31'TVD (42' MD)thick, with the top of the Kuparuk C starting at 5689'TVDSS (7367' MD). The Kuparuk C interval at 2T-41 is exclusively C4, a medium grained sandstone rich in glauconite and siderite.The estimated fracture pressure for the Kuparuk C is 12.5 ppg. The overlying confining zone has an overall thickness of 400'ND (526' MD) and consists of Kalubik and HRZ mudstones.The estimated fracture pressure for the confining layer is 16 ppg.Top HRZ is 5289'TVDSS (6841' MD). • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 10—Location, Orientation and a Report on Mechanical Condition of Each Well that May Transect Confining Zone 20 AAC 25.283(a)(10) The plat shows the location and orientation of each well that transects the confining zone. ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing&Cement assessments for all wells that transect the confining zone: 2T-41: 7 5/8"Casing two stage cement job using was pumped on 11/17/2013 as designed, indicating competent cement operations. The first stage was 15.8 ppg cement, displaced by 10.4 LSND mud. The plug was bumped and the float held.The 2"d stage was 16.0 lead cement followed by 15.8 tail cement; it was displaced by 10.4 ppg mud. The plug was bumped and we pressured up to close the ES cementer. 2T-16: 5" Liner cement job was pumped on 4/09/1986 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced by seawater,floats were checked and held. 2T-03A: 7" Casing cement job was pumped on 9/13/1986 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg 50/50 Healy Fly Class G cement and 100%G cement, displaced by 11.2 ppg brine. The plug was bumped. 2T-21: 7" Casing cement job was pumped on 2/24/1995 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg G cement, displaced by 11.2 ppg brine. The plug was bumped and floats held.A CBL was performed and log submitted 3/14/1995. 21-12: 5" Liner cement job was pumped on 9/28/1986 as designed, indicating competent cement operations. The cement pumped was 15.9 ppg Class G cement. 2T-218: 7" Casing has a gravel pack completion 5547-7235'.The 10-3/4" Surface Casing cement job was pumped on 3/29/2001 as designed, indicating competent cement operations. The cement pumped was 12.0 ppg LiteCrete cement, displaced by 9.8 ppg mud. The plugs bumped and full returns were observed during the job. 2T-201: 7" Casing cement job was pumped on 8/17/1995 as designed, indicating competent cement operations.The cement pumped was 15.8 ppg Class G cement.The plug was bumped and floats held. A CBL was performed and log submitted 8/29/1995. 2T-10: 7" Casing cement job was pumped on 6/6/1986 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced by 12.2 ppg NaBr brine. The plug was bumped and returns were observed during the job. 2T-207: 7" Casing has a gravel pack completion 4081-4413'.The 9-5/8" Surface Casing cement job was pumped on 12/11/1998 as designed, indicating competent cement operations. The cement pumped was 10.7 ppg AcrticSet Lite and Class G cement, displaced by 9.8 ppg mud. The plugs were not bumped. 2T-38A: 3-Y2" Liner cement job was pumped on 11/29/1997 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced by seawater,floats were checked and held. 2T-22: 7" Casing cement job was pumped on 6/25/1995 as designed, indicating competent cement operations.The cement pumped was 15.8 ppg Class G cement.The plug was bumped and floats held. • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application 2T-39: 7" Casing cement job was pumped in two stages on 11/2 2001 as designed, indicating p p g / , g competent cement operations. The cement pumped was 15.8 ppg Class G GASBLOK cement, displaced with seawater. Both plugs bumped, had good circulation throughout job, and floats held good. 3-1/2" Liner job was pumped on 11/10/2001 as designed, indicating competent cement operations.The cement pumped was 15.8 ppg Class G cement with Gas Check additive.The wiper plug was bumped and floats held.The liner was pressure tested to 3500-psi. 2T-19: 7" Casing cement job was pumped on 3/15/1995 as designed, indicating competent cement operations. Pipe was reciprocated during the job and full returns were observed during the job. 2T-04: On 1/19/2012 the well was cemented to surface and suspended. Originally, the 7" Casing cement job was pumped as designed on 8/9/1986, indicating competent cement operations.The cement pumped was 50/50 POZ Class G and 100%Class G cement.The plug bumped and the casing/cement was pressure tested to 3000-psi.The 5" Liner cement job was pumped on 8/13/1986 as designed, indicating competent cement operations.The cement pumped was Class G and the plug was bumped. 2T-36: 7" Casing was pumped on 7/27/1995 as designed, indicating competent cement operations. The floats were check and they held. Full returns were observed during the job. 2T-07: On 7/10/2015 the well was cemented to surface and suspended. Originally,the 7" Casing cement job was pumped on 8/1/1986 with 50/50 Healy Flyash Class G and 100%Class G cement.The plug was bumped with 3500-psi. A top job followed pumping 200-sx AS1 and 53-bbl Arctic Pak. 2T-15: 7" Casing was pumped on 4/18/1986 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G and the plug bumped.The 5" Liner cement job was pumped on 4/23/1986 as designed, indicating competent cement operations. The cement pumped was 16.1 ppg Class G cement. The plug was bumped as calculated, and the floats held. 2T-18: 7" Casing was pumped on 3/4/1995 as designed, indicating competent cement operations. The floats were check and they held. Full returns were observed during the job. 2T-14: 5" Liner cement job was pumped on 5/4/1986 as designed, indicating competent cement operations. The cement pumped was 16.1 ppg Class G cement. The plug was bumped as calculated, and the floats held. 2T-37: 7" Casing cement job was pumped on 8/12/1995 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced with seawater. The plug was bumped @ 1,930 psi, floats held. Summary Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. It has also been determined that the frac will not adversely affect wells within a 1/2-mile radius or any other nearby well. I • ConocoPhillips ADL025549 ADL025548 2T-41 Fault Analysis Alaska 12/07/15 ADL025568 ADL025569 ADL025644 C PERF o >"n N 0 "1/ l sx*. 3 ,,,,,e,„,,,,„,.mww I B C Perf Well Pad REFERENCES: Well Data: ConocoPhillips Alaska Well Database (ATDB) — Fault within Radius Surface Facilities:ATDB — A Sand Horizontal Well Within Confining Zone Well Trajectory N 1/2 Mile Trajectory Radius V 1/2 Mile Open Section Radius Pad Outline 0 0.15 0.3 0.45 0.6 Miles CPAI Lease • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 12— Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) Kuparuk well 2T-41 was drilled in November 2013 and completed with a 5-1/2" liner across the A- and C-sands and a 3-%2" selective completion isolating the C-sand. A fracture stimulation treatment on the A-sand only (C-sand isolated) was performed on 12/12/2013 using 25# linear and crosslinked gel, placing 201,201-lb of 16/20 proppant in the formation (101% design). The well was BOL in March of 2014, but to date no C-sand production has been realized. A C-sand only frac is now proposed utilizing 25# linear and crosslinked gel to place approximately 100,000-lb of 16/20 ceramic proppant. We expect to increase C-sand production from 0 to approximately 400-bopd with a successful stimulation, adding to the existing A-sand production of 240-bopd. Proposed Procedure: Halliburton (HES) Pumping Services: (Kuparuk C-sand Frac) 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any hazardous conditions. 2. Ensure all Pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to 2,000'TVD. 3. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 4. MIRU 3 clean insulated frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 1002 F seawater(approx. 1000-bbl are required for the treatment with breakdown, maximum pad, and 450-bbl usable volume per tank). 5. Ensure lift plan is reviewed and signed prior to RU of Frac equipment requiring lifts. 6. MIRU Stinger Tree Saver Equipment and HES Frac Equipment. 7. PT Surface lines to 8,000 psi using a Pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Pump the Frac job by following schedule @ 20-bpm, increasing to 25-bpm, with a maximum expected treating pressure of 5,500 psi. S`OW Ii ,nvrCcve, I A fieM41.-rt, Z .00 , as f 1aIf pre.SsvfeA Stage 1 p • Stage 1: 12-bbl 25#linear gel load well vl Gb tom! • Stage 2: 310-bbl HyborG 25# Pad )// b • Stage 3: 95-bbl HyborG 25#with 1 PPA 16/20 Carbolite Proppant • Stage 4: 95-bbl HyborG 25#with 2 PPA 16/20 Carbolite Proppant • Stage 5: 95-bbl HyborG 25#with 3 PPA 16/20 Carbolite Proppant • Stage 6: 95-bbl HyborG 25#with 4 PPA 16/20 Carbolite Proppant • Stage 7: 95-bbl HyborG 25#with 5 PPA 16/20 Carbolite Proppant • Stage 8: 95-bbl HyborG 25#with 6 PPA 16/20 Carbolite Proppant 110 OKuparuk Well 2T-41 (PTD 213-146) Hydraulic FracturingGCC Sundry Application • Stage 9: 54-bbl HyborG 25#with 7 PPA 16/20 Carbolite Proppant • Stage 10: 65-bbl 25# linear gel and freeze protect flush • Total Sand: Approx. 100,000-lb of 16/20 Carbolite 10. Monitor the surface pressure fall-off at the end of the job for 30 minutes, if the well does not screen out. 11. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. 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Q . - V l7 _ t o u u u u V V V E• a E _ _ ..!..5, 1!3:4.. a.4.E.R.4 E w w u u a LLsss5 B4 . a o 2 E E E g a m 3 < c Ha a. o. a a a o. µ E 4 u .m 0 0 o u u o v t. t Sn ° - n F z -'E � 1- s ai mM ry a .0 . 4 o . . . . 3 .. ., ., • a mn a A m a i E :6 n p E 3..i1Z"9Sl ilfl.S:'OW 0 g E a p PW*6 tl n u Y lltmo, ill¢ w m o 0 L7 • • Hydraulic Fracturing Fluid Product Component Information Di sclosu Fracture Data 2016-01-25 State; Alaska County; Harrison 515 Al %mbar a310320675 CONOCO PHILLIPS Operator tilling:NOM" SLOPE ESUS Weil Nemo and Number. Kupkruk Rtver 2T-4 I Lonellade; 450 01 Letitia's: 7023 Lone/Let Projection, Producton Type: True Vertical Noel ITVDt Total Wear Volume oar; 42.527 Hydraulic Frturim)iIou Composiths77. C hemical Maximum Abstract Maximum Ingredient Ingredient Masa Trade Name Supplier Purpose Ingredients servile Concord rut Ain in Add itive Concentration Ingredient' C om ment2s lbs Number ICAS 1%by Maar HF F ixi I%by 41 massr• 56a Water Dperebsr Elsa!F bid PA-20 13 LIFFERING AGENT,EC-8 ',ADAM IODIDE• CL-22 VD.DI.-11 Aldttes,H7ocde, CROS SOWER, gronka,Wen-, LOSURF-3000, CrosaJDeer,311.11.10 NA • )40-67.OPTIrt 0- Apes..Microbe/3de, iti DELAYED Nonnent Surfactant, RELEASE cmi Cola Malys BREMER,SP 9REND1471, WU- 78GaIMG 1 AGENT Cautestee 1020 :7-97-Oors,ancs Procren1 NA NA 0 NA 1.2.4 I rrnetivsenrene 1t-1n-6 1.r.C1 4 2-flremr2m.to-I,3-0,a94,4*, 52-51-7 1C7D,uCi 0.1:012% 7 ;cote add 01-I1- 22,CC% 25 Dense Tuck, Feelirelon.1300 N.Sam Iss0 slon Acfylete polymer Co-Adele, 1.DDt D.[FC!...11 5 PkwyE.,wou Apo, TX 77(012,281- 87I-86 Arenunium acetae 621.318 100,20% 0.01174.1 83 Arrnortum prikirralk 7727-540 500.20i 0,20902% 42 ilansinne,senrie,nyclfoce7nancl IstowaSIVIdMetraerrrronurn 12160a-6d-4 5.25 0,21112.1 Si stewate COnlY.ft Pc1,8e salts Oxide-as • 1k :eq-K,mane reo Ls and wawa, CE-47X1-68-4 21.4712775 10900 efiereIs Dry.sa 1450.0-fe.7 20,005 0-.00721777.5 1.4 CryliSthe SMS,Qual2 1484193-7 D.107% 7.,7-.7,9%7"7. 2 Cured ecroc ratan Cul I dent& Mena 554,17-5 SD, 195 9•,,rn 90063401 100, 1064 tesvyanseatc kds-Jrn nestle's .1474231 5 , ,a9 kw/44ms 91-X-3 5.DIA Sea'Mier NA 120.707% , ; )331a0 '554-7 Okyekyased prend,c man Ccnkd5115a7 35.VD% D.0277E1 131 Poly1clay,1,2.et1atedy eginsi4. nom4friervi-orressnydrocy-, 127087-81-0 0.D01 0.02347% Il winched Pots ssum torrraie 050-29-4 254 Astesstim titles ede 131458,3 r721.11% 7 SSUM rnelabOrate 705-311-9 . , 7 79 N9ce 11262603 . 11 Sodium carbasyrnelryi(Widow 930432-4 :7.i . i 5 Sodten chloilde 7647 145 I. % SzOkon704copelm 2036-12-0 1,02% 5 Sedum nydroode 1310732 .7, 7.idtimees7..PAsi 7775.27-I 00.005 42 Sedum i.Ritve 7757 826 0,I Dt e.pooet Sotecsmme,,ra Cs-dIdenta , 0,054571 22 &ale/ 7732185 0.11.7071 550 •T c4a0 Water'As vnie schAtes may MOW,Erckze,l' r...14K/wale, Irricernaton 75 eased on Ire maxim-01 pter-ta I 000755113507 and this 1 ne iota may Dearer 1975l. Nolo For Reid DevcSoprnent Products products Inst begin Darn FO1977,,SA sp S yol orq s rdorrnaVon Nae been prov4t4 Al con:coal IP-1Ix".1100"5111615'Am ablik^ed*Om tNespSc3 1111111e94 We'?r7011$Nxt,,iMSDS} As 5-45,the OPerabr not,espanetke br naccuralear4.4ne neon,pfe1e deorrnston Any sons /pseudo;tine contem 01 tne MSDS!bead becreceo to Ire supper Dano pr0510ed1 ire Occopatorai Suety and Heath A17TIFT5111110O JOS1-1.41 reguallons govern tne cnIev1411011t*disclosure O s into/melon F5.44e neo V=4!F443404 t ago Proleels"PrOPP44arr'traCe rxIter.and"Oaride-14 bua.neSe dearNatOn"and re cnStea te 0%06 5131, 2,751011 a ropoloO on on 174931s a,,,D.frej to;77; 1510.12030 and Apperckx • • Kuparuk Well 2T-41 (PTD 213-146) Hydraulic Fracturing AOGCC Sundry Application Section 13—Post-Fracture Wellbore Cleanup and Fluid Recovery Plan 20 AAC 25.283(a)(13) A coiled tubing fill cleanout is planned immediately following the fracture treatment. Flowback will subsequently be initiated through test equipment until the fluids clean up at which time it will be turned over to production. (Initial flowback fluids to be taken to appropriate disposal well until clean enough for production.) • 2T-41 Hydraulic Fracturing Sundry Application SECTION 9—DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the Kuparuk C sand interval, is approximately 31'TVD (42' MD) thick, with the top of the Kuparuk C starting at 5689'TVDSS (7367' MD). The Kuparuk C interval at 2T-41 is exclusively C4, a medium grained sandstone rich in glauconite and siderite.The estimated fracture pressure for the Kuparuk C is 12.5 ppg. The Kuparuk A sand was previously hydraulically fractured in the 2T-41 well. The overlying confining zone has an overall thickness of 400'TVD (526' MD) and consists of Kalubik and HRZ mudstones.The estimated fracture pressure for the overlying confining layer is 16 ppg.Top HRZ is 5289'TVDSS(6841' MD). The underlying confining zone consists of the Miluveach interval, a marine shale, approximately 380' thick.The estimated fracture pressure for the Miluveach is 15.5 ppg. SECTION 11—LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(11) CPAI has formed the opinion based on seismic, well, and other subsurface information currently available that there are four mapped faults that transect the Kuparuk C interval and enter the confining zone within one half mile radius of the wellbore trajectory for 2T-41. The mapped faults do not intersect the 2T-41 wellbore within the confining zone. One mapped fault crosses the 2T-41 wellbore below the C35 Marker at 4971'TVDSS (6454' MD). The C-35 consists of shale, siltstone and sandstone lithologies with an estimated fracture pressure as high as—16 ppg. All other faults within the AOR terminate at or below the overlying confining zone.The 2T-41 well was previously hydraulically fractured in the Kuparuk A sand in March 2013. CPAI has formed the opinion, based on seismic, well and other subsurface information currently available that the faults will not interfere with containment. 1. Please provide a list of fault-cuts (MD,TVDSS and vertical displacement)that have been observed within wells and well branches within and near the AOR. One mapped fault intersects the 2T-41 wellbore within the AOR.The fault intersects the wellbore above the confining zone at approximately 6623' MD(5114'TVDSS) with approximately 35'of vertical displacement. The 2T-10L1-01 A sand horizontal well, located 2,100' west of the 2T-41 C Sand perfs, crossed five small faults,two of which (Fault 1 and Fault 2) are within%2 mile radius of the C sand perfs in the 2T-41 parent well.The following are the faults that were crossed with the 2T- 10L1-01 lateral. Fault 1 intersects the confining zone. • 2T-41 Hydraulic Fracturing Sundry Application Fault MD SSTVD Throw Fault#1(A3 UT/A3 DT) 9053.7 5823 13 Fault#2(A3 DT/A3 UT) 9530.6 5821 6 Fault#3(A3 UT/A3 DT) 10143 2808 2 Fault#4(A3 UT/A3 DT) 10400 5799 6 Fault#5 (A3 DT/A3 UT) 10645 5780 7 The 2T-10L1-01PB1 crossed the same faults 2-5 and was unlined. 2. Discuss any occurrences of lost circulation in those wells and well branches that occurred while drilling. Losses were observed after crossing Fault 2 in the 2T-10L1-01PB1 lateral (initial rate of over 60 bbls per hour and continued for 24 hours). Minimal losses were observed in the subsequent lateral 2T-10L1-01 when crossing the same Fault 2. 3. Please provide estimates of the horizontal distances from the ends of the projected fracture wings to any nearby faults. If any of these fracture wings are likely to intersect or even closely approach a fault, please discuss why that fault will not provide a pathway for injected fluids to migrate out of the pool. With the effective fracture length estimated to be 300',the nearest induced fractures will be ^'100'from where the fault intersects the reservoir. 4. Discuss the thickness and competence of the top seal for the Kuparuk River Oil Pool within the AOR and how any faults within the AOR that cut this top seal will not affect the ability of that top seal to confine injected fluids to the pool. Thickness and fracture pressure for the confining layer is discussed in Section 9. One mapped fault crosses the 2T-41 wellbore below the C35 Marker at 4971'TVDSS(6454' MD).The C-35 consists of shale,siltstone and sandstone lithologies with an estimated fracture pressure as high as—16 ppg. All other faults within the AOR terminate at or below the overlying confining zone. 5. Please discuss any mitigation plans ConocoPhillips may have should any of the fracture wings appear to intersect a fault during fracturing operations. Our mitigation plan should there be any evidence as to the likelihood of fracture wings intersecting a fault during the treatment is to terminate the fracturing operation. Moreover, if this type of connection were to occur, it is likely we would experience a much higher leak off rate than of that to the formation in all probability resulting in a screen out.A coiled tubing post-frac FCO is presently planned within the scope of this work. • • 2T-41 Hydraulic Fracturing Sundry Application SECTION 9—DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the Kuparuk C sand interval, is approximately 31'TVD(42' MD) thick, with the top of the Kuparuk C starting at 5689' TVDSS (7367' MD). The Kuparuk C interval at 2T-41 is exclusively C4, a medium grained sandstone rich in glauconite and siderite. The estimated fracture pressure for the Kuparuk C is 12.5 ppg. The Kuparuk A sand was previously hydraulically fractured in the 2T-41 well. The overlying confining zone has an overall thickness of 400'TVD (526' MD) and consists of Kalubik and HRZ mudstones.The estimated fracture pressure for the overlying confining layer is 16 ppg• Top HRZ is 5289'TVDSS(6841' MD). The underlying confining zone consists of the Miluveach interval, a marine shale, approximately 380'thick.The estimated fracture pressure for the Miluveach is 15.5 PPg• SECTION 11—LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(11) CPAI has formed the opinion based on seismic, well, and other subsurface information currently available that there are four mapped faults that transect the Kuparuk C interval and enter the confining zone within one half mile radius of the wellbore trajectory for 2T-41. The mapped faults do not intersect the 2T-41 wellbore within the confining zone. One mapped fault crosses the 2T-41 wellbore below the C35 Marker at 4971'TVDSS (6454' MD). The C-35 consists of shale, siltstone and sandstone lithologies with an estimated fracture pressure as high as"'16 ppg. All other faults within the AOR terminate at or below the overlying confining zone.The 2T-41 well was previously hydraulically fractured in the Kuparuk A sand in March 2013. CPAI has formed the opinion, based on seismic, well and other subsurface information currently available that the faults will not interfere with containment. 1. Please provide a list of fault-cuts (MD,TVDSS and vertical displacement)that have been observed within wells and well branches within and near the AOR. One mapped fault intersects the 2T-41 wellbore within the AOR.The fault intersects the wellbore above the confining zone at approximately 6623' MD(5114'TVDSS)with approximately 35' of vertical displacement. The 2T-10L1-01 A sand horizontal well, located 2,100'west of the 2T-41 C Sand perfs, crossed five small faults,two of which (Fault 1 and Fault 2) are within 1/2 mile radius of the C sand perfs in the 2T-41 parent well.The following are the faults that were crossed with the 2T- 10L1-01 lateral. Fault 1 intersects the confining zone. • • 2T-41 Hydraulic Fracturing Sundry Application Fault MD SSTVD Thro Fault#1(A3 UT/A3 DT) 9053.7 5823 13 Fault#2(A3 DT/A3 UT) 9530.6 5821 6 Fault#3(A3 UT/A3 DT) 10143 2808 2 Fault#4(A3 UT/A3 DT) 10400 5799 6 Fault#5 (A3 DT/A3 UT) 10645 5780 7 The 2T-10L1-01PB1 crossed the same faults 2-5 and was unlined. 2. Discuss any occurrences of lost circulation in those wells and well branches that occurred while drilling. Losses were observed after crossing Fault 2 in the 2T-10L1-01PB1 lateral (initial rate of over 60 bbls per hour and continued for 24 hours). Minimal losses were observed in the subsequent lateral 2T-10L1-01 when crossing the same Fault 2. 3 Please provide estimates of the horizontal distances from the ends of the projected fracture wings to any nearby faults. If any of these fracture wings are likely to intersect or even closely approach a fault, please discuss why that fault will not provide a pathway for injected fluids to migrate out of the pool. With the effective fracture length estimated to be 300',the nearest induced fractures will be ^'100'from where the fault intersects the reservoir. 4. Discuss the thickness and competence of the top seal for the Kuparuk River Oil Pool within the AOR and how any faults within the AOR that cut this top seal will not affect the ability of that top seal to confine injected fluids to the pool. Thickness and fracture pressure for the confining layer is discussed in Section 9. One mapped fault crosses the 2T-41 wellbore below the C35 Marker at 4971'TVDSS(6454' MD).The C-35 consists of shale, siltstone and sandstone lithologies with an estimated fracture pressure as high as^'16 ppg. All other faults within the AOR terminate at or below the overlying confining zone. 5. Please discuss any mitigation plans ConocoPhillips may have should any of the fracture wings appear to intersect a fault during fracturing operations. Our mitigation plan should there be any evidence as to the likelihood of fracture wings intersecting a fault during the treatment is to terminate the fracturing operation. Moreover, if this type of connection were to occur, it is likely we would experience a much higher leak off rate than of that to the formation in all probability resulting in a screen out.A coiled tubing post-frac FCO is presently planned within the scope of this work. 1110 • Wallace, Chris D (DOA) From: Hazen, Mike C <Michael.C.Hazen@conocophillips.com> Sent: Friday, January 08, 2016 9:08 AM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: RE: Application for Sundry Approvals Hydraulic Fracturing 2T-41 (PTD 2131460) Sundry 315-759 Good Morning Chris, Thanks for your update and inquiry, and sorry up front for the confusion. I appreciate your progressing the application as we are hoping to frac over the weekend if at all possible. On January 1, 2016, as part of the pre-frac wellwork, we pressure tested the tubing and then the inner annulus, each to 4000-psi and each one passing. During the frac treatment we will hold 3500-psi on the IA. I called over to Halliburton as well to help follow up on the chemical information; I could only leave a message as of yet but I trust they are expediting a response to you. Regards, Mike Mike Hazen Wells Engineer—ConocoPhillips Alaska, Inc. Office(907)265-1032; Mobile(907)268-9279; Home(907)868-3424; 700 G Street,ATO-2048,Anchorage,AK 99501 From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent:Thursday,January 07, 2016 4:00 PM To: Hazen, Mike C<Michael.C.Hazen@conocophillips.com> Subject: [EXTERNAL]Application for Sundry Approvals Hydraulic Fracturing 2T-41 (PTD 2131460) Sundry 315-759 Michael, We are progressing the sundry and I have sent off a request to Denise Tuck at Halliburton for chemical disclosure information for a few of the chemicals. She indicated we may receive this information tomorrow. I see an estimated treating pressure mentioned as 5500 psi. I see the tubing test pressure is stated as 4000 psi, and the IA casing tested to 3000 psi. 20 AAC 25.283(b) and (c) is about the required 110%test pressure and relates to the backpressure you plan to hold on the IA. I cannot determine if your tubing test pressure is adequate without seeing a backpressure on the IA being stated. So my question is can you restate what the backpressure to be held on the IA is, or can you better detail what the tubing pressure will be during the frac? Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 • 333 West 7th Avenue Anchorage,AK 99501 (907)793-1250(phone) (907) 276-7542(fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. 2 • • (C I o a ' N Cl , CO CO CO CO m Co CO CO 03 a Ne a °° °Y. a a a p p Y O 0 0 00- Ti. a u u { C.) U CO U i f O C 01 r m Ln o m a i. r^ a-be VI 1i.i u 5. s o r-1 ° 4 �O N a o � C o In Y M Iozv .� � ' `� • h2iO +CU .Q H r-1 C M I ap c aaoN m F- c �v N N cv L I a 0 a N o �1 — N m N .c >, d O r 1 m O c O (0''p . -0 ,-.4 a ++ 0 u 't3 .-i 4-' 3 a a ° C o o •`-' u m a Y . L. Z ::-:)- 4-, LLIcii to ' I� 13 -' uaQm � mo -- otoP v `'' V N a ''a z2 o m a N a '"' *' c - on v� a, +, �, c N u a S a c . +. 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Co p , co V C al to , Lfl riti Vhf .i mom Ll mom e-1 u M CU -Co u Z I >. C i 4.+ 0 Q. kO to M r-1 •i N ,� O Li Z CO L u- ra u G. -- a O MNI R5 o tn ▪ N . a _ v a 01 1� U — `� i 00 i a Y bp ! UUC C N P IL a y • O ra ° o N Z -o �a .v,-a 1' GJ vi 1 v 0 .o Q E CU c c 3i Q t6 a a, •-• °i c MOM Z i ° "-t'j O N N l alo � ° H r a •a, C al % `ti t3 Q +v., 4 O E;0 v" `til; 0-, U O a Bettis, Patricia K (DOA) From: Hazen, Mike C <Michael.C.Hazen@conocophillips.com> Sent: Thursday, January 07, 2016 8:26 AM To: Bettis, Patricia K (DOA) Subject: RE: KRU 2T-4 (PTD No. 213-146): Sundry Application No. 315-759 Attachments: 2T-41_AOGCC_Sundry_Supplement_FINAL_1-7-2016_Sections_9_and_ll_MCH.doc Dear Ms. Bettis, Attached is the additional information that you requested. We extracted the original Sections 9 & 11 and inserted the pertinent material there in red and blue. Please let me know if you have any more questions or require any additional information. Regards, Mike Mike Hazen Wells Engineer—ConocoPhillips Alaska, Inc. Office(907)265-1032; Mobile(907)268-9279; Home(907)868-3424;700 G Street,ATO-2048,Anchorage,AK 99501 From: Bettis, Patricia K(DOA) [mailto:patricia.bettis@alaska.govj Sent:Tuesday, December 29, 2015 12:32 PM To: Hazen, Mike C<Michael.C.Hazen@conocophillips.com> Subject: [EXTERNAL]KRU 2T-4 (PTD No. 213-146): Sundry Application No. 315-759 Good afternoon Michael, Additional information request: 1. Please provide a list of fault-cuts (MD,TVDSS and vertical displacement)that have been observed within wells and well branches within and near the AOR. 2. Discuss any occurrences of lost circulation in those wells and well branches that occurred while drilling. 3. Please provide estimates of the horizontal distances from the ends of the projected fracture wings to any nearby faults. If any of these fracture wings are likely to intersect or even closely approach a fault, please discuss why that fault will not provide a pathway for injected fluids to migrate out of the pool. 4. Discuss the thickness and competence of the top seal for the Kuparuk River Oil Pool within the AOR and how any faults within the AOR that cut this top seal will not affect the ability of that top seal to confine injected fluids to the pool. 5. Please discuss any mitigation plans ConocoPhillips may have should any of the fracture wings appear to intersect a fault during fracturing operations. Thank you, 1 . Patrica Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907)793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 2 • 4110 Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Tuesday, December 29, 2015 10:53 AM To: 'hazenmc@conocophillips.com' Subject: KRU 21-41: Sundry Application No. 315-759 Good morning Michael, Please provide a description of the lower confining zone for the proposed Kuparuk C fracturing zone: lithologic description,geologic name and measured and true vertical depths. The Sundry Application provided the information for the upper confining zone, i.e., the Kalubik and HRZ mudstones; however, no information was provided for the lower confining zone. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 WELL LOG TRANSMITTAL DATA LOGGED S i$/2015 K BENDER To: Alaska Oil and Gas Conservation Comm. March 30, 2015 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 SCANNED MA,' 0 6 2015 9A,KR RE: Production Profile: 2T-41 AOGGV Run Date: 3/19/2015 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Chris Gullett, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com 2T-41 Digital Data in LAS format, Digital Log Image file, Interpretation Report 1 CD Rom 50-103-20675-00 Production Profile Log SCANNED MAY 0 6 ails 1 Color Log 50-103-20675-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Chris Gullett 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fax: 907-273-3535 FRS_ANC@halliburton.com Date: Signed: •at(1-4"46--emzet STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 2 `� "f '3 WELL COMPLETION OR RECOMPLETION REPORT AND ticaciCC la.Well Status: Oil ❑ , Gas ❑ SPLUG ❑ Plugged ❑ Abandoned ❑ Suspended ❑ lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ . Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ Other ❑ No.of Completions: Service ❑ Stratigraphic Test 2.Operator Name: 5.Date Comp.,Susp., 12.Permit to Drill Number: ConocoPhillips Alaska, Inc. or Aband.: November 28,2013 • 213-146/ • 3.Address: 6.Date Spudded: 13.API Number: P.O.Box 100360,Anchorage,AK 99510-0360 November 5,2013 • 50-103-20675-00• 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: Surface: 5182'FNL,4722'FEL,Sec. 1,T11 N,R8E,UM • November 20,2013 • 2T-41 Top of Productive Horizon: 8. KB(ft above MSL): 103.8'RKB 15.Field/Pool(s): 1241'FNL, 1946'FEL,Sec. 11,T11 N,R8E,UM GL(ft above MSL): 76'AMSL • Kuparuk River Field Total Depth: 9.Plug Back Depth(MD+TVD): 819'FNL,2011'FEL,Sec. 11,T11 N,R8E, UM 7826'MD/6124'TVD Kupuruk River Oil Pool 4b.Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16.Property Designation: Surface: x-498946.5 y- 5970077 Zone-4 7988'MD/6243'TVD ADL 25569 TPI: x-496444 y- 5968740 Zone-4 11.SSSV Depth(MD+TVD): 17.Land Use Permit: Total Depth: x-496379 y- 5969163 Zone-4 landing nipple @ 415'MD/415'TVD 2667 18.Directional Survey: Yes Q, No❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) 1443'MD/1425'TVD 21.Logs Obtained(List all logs here and submit electronic and printed information per 20 AAC 25.071): 22.Re-drill/Lateral Top Window MD/TVD GR/Res,CBL,sonic, neutron,density not applicable 23. CASING,LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING SIZE WT.PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE CEMENTING RECORD PULLED 16" 65# H-40 28' 106' 28' 106' 24" pre-installed 10.75" 45.5# L-80 29' 3197' 29' 2580' 13.5" 1596 sx Class G,194 sx Class G 7.625" 29.7# L-80 26' 7222' 26' 5685' 9.875" 276 sx Class G,158 sx Class G,82 sx Class G 5.5" 17# P-110 6992' 7946' 5508' 6212' 6.75" 133 sx Class G 24.Open to production or injection? Yes 0 No ❑ If Yes,list each 25. TUBING RECORD Interval open(MD+TVD of Top&Bottom;Perforation Size and Number): SIZE DEPTH SET(MD) PACKER SET(MD/TVD) 4.5"x 3.5" 66'MD/7479' 6992'MD/5508'TVD and 7472'MD /5869'TVD 7368'-7408'MD 5794'-5823'TVD 6 spf 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. 7490'-7550'MD 5882'-5925'TVD 6 spf iiZs- .-_-. ' Was hydraulic fracturing used during completion? Yes❑ No Q J DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED na 27. PRODUCTION TEST Date First Production Method of Operation(Flowing,gas lift,etc.) waiting on facility hook-up Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO Test Period--> Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-API(corr) Press. 24-Hour Rate-> 28. CORE DATA Conventional Core(s)Acquired? Yes ❑ No Q Sidewall Cores Acquired? Yes ❑ No ❑l If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (Submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. NONE RBDME MAR 2 0 20 I Form 10-407 Revised 10/2012CONTINUED ON REVERSE -?0,?) 44 I I Ct II 141 Submit original only Vzc */lam/l'- `r//.57r'�` e 29. GEOLOGIC MARKERS(List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? LI Yes Q No If yes,list intervals and formations tested, Permafrost-Top ground surface ground surface briefly summarizing test results. Attach separate sheets to this form,if Permafrost-Bottom 1443' 1425' needed,and submit detailed test information per 20 AAC 25.071. Top of West Sak 2538' 2211' Base of West Sak 3387' 2684' Tabasco 4067' 3077' Top of Kuparuk C 7367' 5793' Top of Kuparuk A 7472' 5869' N/A Formation at total depth: Kuparuk C 31. LIST OF ATTACHMENTS Summary of Daily Operations,final directional survey,schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. r ' Contact: Lindsey Hunter @ 265-6427 Email: Lindsev.HunterCa�conocophillips.com ) ' Printed Name E.Jolley Title: Supervising Drilling Engineer 1 Signature /� /�� Phone 265-6247 Date /�,a--,3 A-3 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas injection,water injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13:The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20.Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 26: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 27:Provide a listing of intervals cored and the corresponding formations,and a brief description in this box.Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a list of intervals tested and the corresponding formation,and a brief summary of this box.Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 KUP PROD 2T-41 ConocoPhillips , _ Well Attributes Max Angle&MD TD Alaska Inc. Wellbore API/UWI Field Name Wellbore Status nal(°) MD(ftKB) Aa Btm MKS) l,,,,,, 111yu 501032067500 KUPARUK RIVER UNIT PROD 57.72 3,106.62 7,988.0 .-. Comment H2S(ppm) Date Annotation End Date KB-Ord(ft) -Rig Release Date DEVIATED-2T-41.111,20143.50.4 01:1 SSSV:NIPPLE Last WO: 27.50 11/28/2013 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Data Last Tag:SLM 7,816.0 12/28/2013 Rev Reason:GLV C/O,TAG lehallf 1/1/2014 HANGER.23 4-', I".I:' Casing Strings ll II Casing Description OD(in) ID(in) Top(ftKB) Set Depth((KB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread CONDUCTOR 16 15250 27.5 133.5 133.5 65.00 H-40 Welded ,. , Casing Description OD(in) ID(In) Top)ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread • SURFACE 103/4 9.950 28.5 3,196.9 2,580.0 45.50 L-80 Hydril 563 I Casing Description OD(in) ID(In) Top)ftKB) Set Depth)ftKB) Set Depth(ND)...Wt/Len(I..,Grade Top Thread INTERMEDIATE 75/8 6.875 25.6 7,222.2 5,684.6 29.70 L-80 Hydril 563 Casing Daaeripgon OD(in) ID(In) Top)ftKB( Set Depth(ftKB) 'Set Depth(ND)...Wt/Len(L..Grade Top Thread LINER 51/2 4.892 6,992.5 7,946.5 6,212.3 17.00 P-110 DWC-C Liner Details Nominal ID Top)ftKB) _Top(ND)(ftKB) Top Ind(°) Item Des Com (in) CONDUCTOR;27.5-133.5 6,992.5 5,508.6° 39.93 PACKER "HRDE":ZXP LINER TOP PACKER w/10'TIE- 4.930 BACK SLEEVE NIPPLE,413.4 z 7,012.3 5,523.8' 39.91 NIPPLE '"RS"PACKOFF SEAL NIPPLE 4.880 - 7,015.1 5,526.0' 39.91 HANGER "DG"FLEX LOCK LINER HANGER 4.810 ' Tubing Strings I Tubing Descriptio String Ma...ID(In) Top(ftKB) Set Depth(ft..,Set Depth(ND)(...Wt(Ib/ft) Grade Top Connection TUBING 3112 2.992 23.4 6,884.9 5,426.2 9.30 L-80 EUE Completion Details Nominal ID Top(ftKB) Top(NO))ftKB) Top Incl(°) Item Des Com (in) 23.4 23.4 0.00 HANGER FMC TUBING HANGER 3.958 57.9 57.9 0.23 XO Reducing X/O 4-1/2"IBTM Box X 3-1/2"EUE Pin 2.992 GAS LIFT:3,192.0 -. 413.4 4126 7.09'NIPPLE CAMCO DS NIPPLE 2.875 SURFACE,28.5-3,198.9 - 6,844.2 5,394.9 39.44 NIPPLE HES"X"NIPPLE 2.812 6,862.2 5,408.7 39.59 SEAL ASSY BAKER 80-40 PBR w/20'stroke 3.000 • Tubing Description String Ma...ID(in) Top)ftKB) Set Depth(ft..Set Depth(ND)(...Wt(lb/ft) Grade Top Connection STACKER PACKER 3 1/2 2991 6,867.2 7,473.3 5,870.3 9.20 P-110 Hydril 563 Completion Details Nominal ID Top(ftKB) _Top(ND)(ftKB) Top Incl(°) Ilam Des Com (in) 6,867.2 5,412.6 39.63 PBR BAKER 80-40 PBR w/20'Stroke,Pinned w/40,000# ' 3.000 Shear GAS LIFT,4,912.9 6,892.4 5,431.9' 39.85 PACKER 'BAKER PREMIER PACKER 659-287 2.870 7,353.9 5,783.3 42.77 BLAST RING CARBIDE BLAST RING on 2 jts P-110 pipe(overlap C 2.992 sand perf's+5')50'of blast rings. GAS LIFT,5,802.1 7,4574 5,858.8' 43.67 SLEEVE 3.5 CMU SLIDING SLEEVE 2.813'X'PROFILE 2.990 7,471.6 5,869.0 43.87 SEAL ASSY "KBH-22 ANCHOR SEAL ASSY 2.990 Tubing Description String Ma...ID lin) Top)ftKB) Set Depth(ft..Set Depth(ND)(...Wt(Ib#1( Grade Top Connection FA PACKER 4.55 3.0011 7,472.01 7,479.01 5,874.4 9.20 L-80 GAS LIFT,6,418.2 { Completion Details Nominal ID Top(ftKB) _Top(ND))kKB)_Top Incl(°) Item Des Com (in) 1.. 7,472.0 5,869.3 43.87 PACKER 'BAKER FA-1 PRODUCTION PACKER(4.55 OD AND 3.000 GAS LIFT,8,785.2 P 3.0 ID are for the Packer not the tubing.WV chooses _ longest section in tubing) 7,476.8' 5.872.8 43.94 NIPPLE 'HES 2.75"X"NIPPLE ' 2.750 NIPPLE:6.844.2 - Z' 7,478.1 5,873.7 43.95 WLEG WIRELINE GUIDE SHEAR OUT SUB-(WLEG has not 2.950 been sheared open) SEAL ASSY;8,862.2 s FOR,6,867.2 ' c 0 Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) Top(ND) Top Incl X0 Thread;6,890.0 • ( Top(ftKB( (ftKB) (°) Des Com Run Date ID(In) PACKER;6.892 4 "� 7,244,3 5,701.4 40.54 Radioactive RA Tag installed in 5-1/2"liner,pin end of joint#18. 11/22/2013 X0 Thread;6,899.0 Marker Perforations&Slots • Shot Dens Top(ND) Bim(ND) (shot.# Top(ftKB) Bern(NKB) )KKB) )NKB) Zone _ Date t) Type Corn 7,368.0 7,388.0 5,793.6 5,808.2 C-4.2T-41 11/25/2013 6.0 (PERF 33/8 Millenum Gun,25 Gram 60 Deg Phase 7,388.0 7,408.0 5,808.2 5,822.9 C-4,2T-41 11/25/2013 6.0 IPERF 3 3/8 Millenum Gun,25 G am - 7,510.0 7,490,0- 3 1/8 60 Deg Phase 5,882.3 5,896.6 A-3,21-41 11/25/2013 6.0 (PERF 3 1/8 Millenum Gun,21 Gram 60 Deg Phase INTERMEDIATE:25.8-7.222.2 7,510,0 7,530.0 5,896.6 5,910.9 A-3.2T-41 11/25/2013 6.0 (PERF 3118 Millenum Gun,21 Gram 60 Deg Phase RedioecM1w Marker;7,244.3 7,530.0 7,550.0 5,910.9 5,925.1 A-3,21-41 11/25/2013 6.0 IPERF 31/8 Millenum Gun,21 - Gram 60 Deg Phase IPERF;7.348.0-7,386 0 a - BLASTRING;7,353.9 ' Stimulations&Treatments • IPERF;7,3880-7,408.0 1 Min Top Max Bim lili Depth Depth Top(ND) Btm(ND) (ftKB) (ftKB) )ftKB) (ftKB) Type Date Com 7.490.0 7.550.0' 5,882.3 5,925.1 FRAC 12/12/2013 "A"Sand Frac w/25#Linear/X-Linked Gel Placing 01201 xo Thread;7,455.4 LBS OF 16/20 Proppant(101%of Design) SLEEVE;7,457.4 1 Mandrel Inserts St SEAL ASSY;7,471.6 all C PACKER;7,472.0 on Top(ND) Valve Latch Port Size TRO Run I No Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date m 1 3,192.0 2,577.4 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.188 1,298.0 12/29/2013 NIPPLE,7,478.8 - ti 2 4,912.9 3,697.4 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.188 1,278.0 12/29/2013 WLEG;7,478.1 I 3 5,802.1 4,492.3 Camco MMG 1 1/2 GAS LIFT GLV RK 0.188 1,259.0 12/29/2013 IPERF,7,4900-7.510.01 - 4 6,418.3 5,044.0 CAMCO MMG 11/2 GAS LIFT OV RK 0.250 0.0 12/29/2013 FRAC;7,490.0 5 6,785.2' 5,349.0 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 11/21/2013 IPERF;7,5100-7.530.0 IPERF,7,5300-7.550.0 LINER,8,992.5-7,948.5 ConocoPhillips Time Log & Summary Wellvlew Web Reporting Report Well Name: 2T-41 Rig Name: DOYON 141 Job Type: DRILLING ORIGINAL Rig Accept: 11/4/2013 10:00:00 AM Rig Release: 11/28/2013 2:00:00 PM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11/03/2013 24 hr Summary Moved rig from 1C-150 to 2T-41. Spotted sub-base and modules. Continued rigging up while moving rig camp from 1C pad to 2T pad. 00:00 01:30 1.50 MIRU MOVE DMOB P PJSM, Prep rig for move to 2T-Pad, Blow down steam,water,disconnect rock washer, pipe sheds,disconnect service lines between complexes, - Jack up pipe sheds. 01:30 03:00 1.50 MIRU MOVE SFTY P PJSM with Peak truck drivers. Move out pipe sheds and rockwasher and stage down the pad. 03:00 04:00 1.00 MIRU MOVE DMOB P Hook up sows to rig complexes and stage down pad. 04:00 07:00 3.00 MIRU MOVE MOB P Move complexes from 1C-pad to 2T-pad and return back to 1C-pad. 07:00 12:00 5.00 MIRU MOVE MOB P Pull sub off 1C-150 and move sub and pipe sheds to 2T-pad. 12:00 14:00 2.00 MIRU MOVE MOB P PJSM, Move sub over 2T-41 but stopped because tires are to close to sea water flow line, Call pad operator and engineer for plan forward. 14:00 17:00 3.00 MIRU MOVE MOB P Decision made to Bleed and drain flow line and raise 12"with jacks, wait on jacks, raise flow line. Move and spot sub over well. 17:00 20:00 3.00 MIRU MOVE MOB P Spot pits, Motor&boiler complexes and pipe sheds. Trucks returned to move camp. 20:00 00:00 4.00 MIRU MOVE RURD P PJSM, Hook up inner connects,work on rig acceptance list, calibrate and test gas alarms. (SIM-OPS left 1C-pad with camp @ 21:45 hrs moving to 2T-Pad) 11/04/2013 Crews working on rig acceptance list,Assemble pumps, Lay herculite for rockwasher, Spot rock washer and berm same, Spot tioga, Set cuttings box, Perform pre-spud derrick inspection, Load BHA into shed,Take on spud mud in pits, N/U diverter spool, C/O saver sub to 5", Start load shed with 5"dp,Accepted rig at 10:00 hrs 11/4/2013, Continue rigging up and loading shed with hwtdp, (Test Diverter with State Rep.Jeff Jones witness of test), PJSM, P/U 5"dp and hwtdp and stand back in derrick. 00:00 04:00 4.00 MIRU MOVE RURD P PJSM, Continue with rig acceptance list, assemble pumps, set herculite for rockwasher,turn on water. 04:00 10:00 6.00 MIRU MOVE RURD P Spot rockwasher,set handy berm, secure 16"diverter line, spot Tioga, set cuttings box, continue berming rock washer,dress shakers, perform pre-spud derrick inspection, N/U diverter, load pipe shed with 5"dp. (Accept rig @ 10:00 hrs, 11/4/2013) Page 1 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 10:00 12:00 2.00 MIRU MOVE RURD P Take on spud mud to pits, continue N/U diervter spool, C/O saver ub, load pipe shed. 12:00 13:45 1.75 MIRU MOVE RURD P PJSM, Continue N/U diverter, load 5" dp&Hwt in shed,charge pumps, function test diverter, continue taking on spud mud. 13:45 17:00 3.25 MIRU MOVE RURD P PJSM, C/O saver sub, (SIM-OPS cut DSA flange studs&torque same), load 100 jts of 5"dp, HWT and Jars in shed. 17:00 18:45 1.75 SURFA( DRILL BOPE P Test Diverter system, Closing time= 30 sec, Knife valve open= 13 sec, System pressure=3000psi,After closing= 1900 psi,200 pressure increase=41 sec, Full recovery= 168 sec, 5 bottles avg=2050 psi,Tested gas alarms, PVT, Gain/loss and flow alarms. (State Rep.Jeff Jones with AOGCC witness the test). 18:45 00:00 5.25 SURFA( DRILL TRIP P PJSM, L/D diverter test joint, R/U to P/U 5"dp and hwtdp and stand back in derrick via mouse hole. 11/05/2013 P/U 5" DP and HWDP,flood and leak check diverter with water, leaked 2 gallon in containment. R&R knife valve, repair seal and re-check OK. M/U BHA#1 clean out conductor to 160'MD. M/U BHA#2 and drill ahead to 675'MD, 673'TVD. 00:00 00:45 0.75 0 0 SURFA( DRILL TRIP P Finish picking up HWDP and 2 7" DC's, rack back into derrick 00:45 01:15 0.50 0 0 SURFA( DRILL PULD P P/U SLB tools to rig floor from beaver slide. 01:15 02:00 0.75 0 0 SURFA( DRILL SFTY P Held Prep-sud meeting with crew. Test surface lines to 3500 psi. 02:00 02:15 0.25 0 0 SURFA( DRILL RGRP T Flood stack with water, observed knife leaking, had 2 gallon spill of water into containment,decision made to break 16"diverter and knife _ valve apart and inspect same. 02:15 05:00 2.75 0 0 SURFA( DRILL RGRP T PJSM, Repair knife seal on 16" Diverter system, re-flood system and check for leaks. 05:00 06:30 1.50 0 42 SURFA( DRILL PULD P Make up clean out BHA#1, Bit, Motor, Stabilizer, Bottle neck x-over and HWDP. 06:30 07:30 1.00 42 106 SURFA( DRILL DRLG P M/U stand and tag cement @ 42' MD. DRLG cement&ice plugs T/106'MD,425 GPM,450 PSI, 100 SPM, TQ=2-10K. 07:30 09:00 1.50 106 160 SURFA( DRILL DRLG P Drill F/106'MD T/160'MD,425 GPM, 100 SPM, 500 PSI,TQ 2-10K, P/U=50K, S/0=40K, ROT WT 50K. 09:00 09:30 0.50 160 41 SURFA( DRILL PULL P POOH F/160' MD T/41'MD&UD Bottle Neck XO. 09:30 09:45 0.25 41 0 SURFA( DRILL OTHR P Clear&clean rig floor. 09:45 11:00 1.25 0 87 SURFA( DRILL PULD P PSJM&M/U BHA#2 T/87'MD. 11:00 12:00 1.00 87 87 SURFA( DRILL PULD P POOH to check bit, scribe motor to MWD. Page 2 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:00 14:30 ' 2.50 87 160 SURFA( DRILL PULD P PJSM. Continue to M/U BHA#2 as per SLB rep. 14:30 15:15 0.75 160 160 SURFA( DRILL PRTS P SPT @ 440 GPM, 725 psi, 70% F/O, 491 gpm, 825 psi, 74% F/O, 15:15 18:00 2.75 160 260 SURFA( DRILL DDRL P Drill f/160'MD to 260' MD, TVD= 260',ART=.39, AST=.71,ADT=1.10, Total Jar hrs=0, Bit hrs=2.40, P/U wt=57k, S/O wt=60k, ROT wt= 59k, TQ on= 1k, TQ off= 1k, ECD= , F/O=76%,WOB=5k-15k, RPM =40, GPM =478, psi=925. 18:00 00:00 6.00 260 675 SURFA( DRILL DDRL P Drill f/260'MD to 675' MD, 673'TVD. ART=2.33,AST=1.25,ADT=3.58, Total Jar Hours=0, Bit hours=4.68, P/U=64k, S/0=61k, ROT=63k, TO on/off= 1.5k/1 k, Flow out 72%, WOB=5-15k, 40 rpm,481 gpm @ 925 psi. 11/06/2013 Drill ahead with BHA#2 from 675' MD to 1727' MD. Surveying every 45'to ensure low AC risk. Rack back 1 stand and ream to reduce DLS at 1638'-1727' MD. 00:00 06:00 6.00 675 1,049 SURFA( DRILL DDRL P Drill f/675'MD to 1,049' MD,1,042' TVD.ART=2.57,AST=1.10, ADT=3.67, Total Jar Hours=5.95, Bit hours=8.35, P/U=81k, S/0=80k, ROT=81 k, TQ on/off=2k/4k, Flow out 72%, WOB=15-17k, 40 rpm, 525 _ gpm @ 1,150 psi. 06:00 12:00 6.00 1,049 1,450 SURFA( DRILL DDRL P Drill f/1,049' MD to 1,450' MD,1,430' TVD.ART=1.71, AST=2.44, ADT=4.15, Total Jar Hours=10.1, Bit hours=12.5, P/U=93k, S/0=84k, ROT=90k, TQ on/off=3k/8k, Flow out 72%, WOB=15-20k, 40 rpm, 520 gpm @ 1,150 psi. 12:00 13:30 1.50 1,450 1,542 SURFA( DRILL DDRL P Drill f/1,450' MD to 1,542' MD,1,433' TVD.ART=0.16,AST=1.07, ADT=1.23, Total Jar Hours=12.43, Bit hours=13.73, P/U=100k, S/0=81k, ROT=90k, TQ on/off= 3k-9k/2k-4k, Flow out 70%, WOB=15-30k, 40 rpm, 521 gpm @ 1,100 psi. 13:30 15:00 1.50 1,542 1,542 SURFA( DRILL CIRC T PJSM-C/O 2 swabs& 1 liner MP #1, svy on btm, rack back 1 stand above base of permafrost, (per SLB DD), M/U stump circ @ recip from 1408'MD to 1358'MD, @210 gpm, 300 psi, 55%F/O, SIMOPS screen up shakers. RIH. 15:00 21:30 6.50 1,542 1,727 SURFA( DRILL DDRL P Drill from 1542' MD to 1727' MD, 1677'TVD. ART=.21, AST=2.2, ADT=2.41,Total Jars Hrs=14.84, Bit Hrs=16.14, P/U=97k, S/0=86k, ROT=92k,TQ on/off=3-9k/2-5k, Flow out 70%,WOB=10-25k, 40 rpm, 485 gpm @ 950 psi. Page 3 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 21:30 00:00 2.50 1,727 1,660 SURFA( DRILL REAM P Stand back one stand and ream out 10°dogleg. Kelly up© 1638' MD, ream back to 1546' MD. Ream down to 1604' MD and took weight. Continue reaming per SLB DD, ream to 1660' MD. 11/07/2013 Drill ahead with BHA#2 from 2,000' MD to 3,120' MD, 2,564'TVD. 00:00 01:00 1.00 1,660 1,727 SURFA( DRILL REAM P PJSM-Continue ream f/1,660'MD t/1,727' MD, 40 RPM,485 GPM, 950 PSI,TQ=3-9 K, WOB=15-20 K 01:00 06:00 5.00 1,727 2,060 SURFA( DRILL DDRL P Drill f/1,727' MD t/2,060' MD, TVD=1,926'ART=1.1,AST=1.40. ADT=2.51.Total jar hours=18.65, bit hours=18.65. P/U weight=97 K. S/O weight=83 K, ROT weight=93 K, Torque on bottom=5-8 K, Torque off bottom=2-5 K, Flow out=72%, WOB=20-30K, RPM=40, GPM=575 © 1,300 PSI. 06:00 12:00 6.00 2,060 2,469 SURFA( DRILL DDRL P Drill f/2,060' MD t/2,469' MD, TVD=2,181'ART=2.25,AST=0.80. ADT=3.05.Total jar hours=21.70, bit hours=21.70. P/U weight=104 K. 5/O weight=80 K, ROT weight=89 K, Torque on bottom=5-7 K, Torque off bottom=3-7 K, Flow out=80%, WOB=20-30K, RPM=50, GPM=675 @ 2,050 PSI. 12:00 18:00 6.00 2,469 2,749 SURFA( DRILL DDRL P Drill f/2,469' MD t/2,749' MD, TVD=2,337'ART=4.55,AST=0.21. ADT=4.76. Total jar hours=24.46, bit hours=24.46. P/U weight=108 K. S/O weight=82 K, ROT weight=94 K, Torque on bottom=6 K, Torque off bottom=3-6 K, Flow out=84%, WOB=5-25K, RPM=50, GPM=666 @ 1,950 PSI. 18:00 00:00 6.00 2,749 3,120 SURFA( DRILL DDRL P Drill f/2,749' MD t/3,120' MD, TVD=2,564'ART=2.12, AST=1.4. ADT=3.52. Total jar hours=29.98, bit hours=29.98. P/U weight=112 K. S/O weight=84 K, ROT weight=95 K, Torque on bottom=7 K, Torque off bottom=5 K, Flow out=84%, WOB=15-30K, RPM=50, GPM=725 @ 2,200 PSI. 11/08/2013 Drill to section TD @ 3,209' MD, 2,594'TVD. Condition, wiper trip/backream to HWDP, RIH and C&C. POOH and L/D BHA#2. R/U to run and cement 10 3/4"casing. Page 4 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 01:30 1.50 3,120 3,209 SURFA( DRILL DDRL P Drill f/3120'MD t/3209'MD, TVD=2594'ART=0.87,AST=0. ADT=0.87.Total jar hours=31.51,bit hours=31.51. P/U weight=114 K. S/O weight=84 K, ROT weight=95 K, Torque on bottom=7 K,Torque off bottom=5 K, Flow out=82%, WOB=25-30K, RPM=50, GPM=725 @ 2,200 PSI. 01:30 03:00 1.50 3,209 3,209 SURFA( CASING CIRC P Survey, Circulate B/U, GPM=725 @ 2100 PSI. RPM=50, Torque off bottom=5-7 K, Circulate another B/U and Pump 30 bls weighted Hi-Vis sweep 03:00 09:30 6.50 3,209 804 SURFA( CASING REAM P PJSM&backream out of the hole. GPM=725, PSI=2,000. RPM=50, Torque off bottom=4-7 K, reduce pump rate to 600 gpm, 1500 psi at base of permafrost. Hole unloading with excess cuttings from 1500'MD. reduce rate to 300 gpm,400 psi @ 1100'MD to 804'MD. Cal fill=20.2 bbl,Act fill=28.7 bbl. 09:30 10:00 0.50 804 804 SURFA( CASING CIRC P Monitor well(static), CBU @ 804'MD, Rotate and recip pipe @ 450 gpm, 850 psi, 50 rpm,TQ-2k. 10:00 10:15 0.25 804 804 SURFA( CASING OWFF P Monitor well(static), B/D top drive. 10:15 11:30 1.25 804 1,546 SURFA( CASING TRIP P PJSM,TIH from 804'MD to 1460'MD tag up. Rotate and Circ through, Ream to 1546'MD @ 460 gpm,900 psi,40 rpm,TQ 3-10k. 11:30 12:00 0.50 1,546 2,100 SURFA( CASING TRIP P Cont RIH to 2100'MD, Calc Disp=10.22,Actual Disp-1.93 bbls (shaker overloaded t/rockwasher, lost 12 bbls to rockwasher). 12:00 13:00 1.00 2,100 3,209 SURFA( CASING TRIP P PJSM-Cont RIH from 2100'MD t/3120'MD. M/U top drive, ream t/ 3209' MD,total Calc=18.72 bbls, total Actual=17.45 bbls. 13:00 14:45 1.75 3,209 3,120 SURFA( CASING CIRC P CBU x 4,condition per Mud engineer, Circulate @ 650 GPM, 2050 PSI,50 RPM,4-6 K TQ, Stage up to 725 GPM, 2325 psi,70 RPM, 4-6 K TQ, P/U 105K, S/0 75K, ROT 92K 14:45 15:00 0.25 3,120 3,120 SURFA( CASING OWFF P PJSM, monitor well for flow(static), blow down top drive. 15:00 16:15 1.25 3,120 1,731 SURFA( CASING TRIP P POOH from 3120'MD to 1688'MD. Pulled into obstruction, made several attempts, pulling 75k over lx. Kelly up to ream section. Calc Fill=11.25 bbl,Actual Fill=15.75 bbl. Page 5 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 16:15 18:15 2.00 1,731 1,546 SURFA( CASING REAM P Backream from 1731' MD to 1546' MD at 500 gpm, 1100 psi, 50 rpm, 3-12k erratic torque and ample clay returns at shakers. RIH from 1546' MD to 1823'MD on elevators no problems. 18:15 19:00 0.75 1,823 804 SURFA( CASING TRIP P POOH from 1823'to HWDP @ 804' MD no problems. Monitor well at _HWDP(static). 19:00 19:45 0.75 804 160 SURFA( CASING TRIP P POOH, rack back HWDP, Jars and Flex collars. 19:45 22:30 2.75 160 0 SURFA( CASING PULD P PJSM, L/D BHA per SLB reps. Lot of clay on stabilizers and bit, otherwise no damage, bit<1/16 under guage, no damage. Cumu Calc Fill=30.29 bbl,Actual Fill=44.95 bbl. 22:30 00:00 1.50 0 0 SURFA( CASING RURD P Clean and clear rig floor,send down tools. R/U top drive for running casing, bring up casing running tools. 11/09/2013 Run casing and cement per program. 189 bbls cement to surface on stage 1, full returns, CIP @ 00:32 11/10/13. 00:00 01:30 1.50 0 40 SURFA( CASING RURD P PJSM, R/U to run 10.75"casing. 01:30 06:30 5.00 40 480 SURFA( CASING RNCS P PJSM, Run 10.75"casing. Could not get casing to go down, push casing from 40' MD to 480' MD. 06:30 07:00 0.50 480 480 SURFA( CASING CIRC P Cirulate©2 bpm, hole packed off, work pipe and stage pumps up to 4.5 bpm, 150-300 psi, flow=50%-75%, Circ until hole cleaned up. 07:00 10:00 3.00 480 1,586 SURFA( CASING RNCS P RIH with 10.75"casing from 480' MD to 1586' MD, Circulate every other joint down to keep mud moving. 10:00 10:15 0.25 1,586 1,586 SURFA( CASING CIRC P CBU @ 4.5 bpm, 225 psi, flow= 53%@ 1586' MD. 10:15 12:00 1.75 1,586 1,901 SURFA( CASING RNCS P RIH w/ 10.75"casing. from 1586' MD to 1901' MD, Circ every third joint down ©4.5 bpm, 220 psi, flow 53%. Act disp=35.7 bbls, calc disp= 30.55 bbls. 12:00 15:00 3.00 1,901 3,197 SURFA( CASING RNCS P PJSM, RIH w/10.75"casing from 1901' MD to 3197' MD, M/U hanger and landing joint, land hanger OK. Circulate every third joint down @ 4.5 bpm, 220 psi, flow=53%.Act disp= 8.3 bbls, Calc disp= 18.33 bbls. Total losses to formation for day, 102 bbl. 15:00 16:00 1.00 3,197 3,197 SURFA( CASING CIRC P CBU with Franks tool, stage pumps up from 2 bpm to 6 bpm, ICP=300 psi, FCP=400 psi FCP, 59% Flow out. 16:00 16:45 0.75 3,197 3,197 SURFA( CEMEN-RURD P PJSM-Rig up cement head and circulation hoses. Page 6 of 29 J Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 16:45 20:30 3.75 3,197 3,197 SURFA( CEMEN-CIRCP Circulate and condition mud per Mud Engineer, circulate @ 6 bpm, 350 psi. Reciprocate pipe 15 while conditioning. Reduce YP from 44 to19, MW from 10.0 to 9.9 ppg. SIMOPS-Rig up Schlumberger,crew change SLB and ASRC. 20:30 00:00 3.50 3,197 3,197 SURFA( CEMEN-CMNT P PJSM-Pump cement job per program. Pumped 5 bbl water,test lines to 4000 psi. Pumped 80 bbl 8.4 ppg CW100, 83.4 bbl 10.5 ppg MudPushll Spacer, 588 bbl 11.0 ppg Lead Cement and 60 bbl 12.0 ppg LiteCrete Tail Cement. Drop top plug, chase with 20 bbl water from SLB. Swap to rig for displacement, begin pumping displacement with 9.9 ppg Mud @ 5 bpm 250 psi, stage up to 7 bpm 550 psi, reciprocate 15'through job,full returns. Cement to surface @ 900 stks. CIP @ 00:32 11/10. 189 bbl 110.0 ppg cement to surface. 11/10/2013 Complete surface cement job. Secure/cancel ES cementer. N/D Diverter, N/U BOPE and test. 00:00 01:15 1.25 3,197 0 SURFA( CEMEN-CMNT P PJSM, finish pumping 12.0 ppg tail cement, reciprocated the entire time, P/U wt= 190k, S/O wt=70k. Drop Halliburton plug, Pump 20 bbls fresh water,swap to rig and chase down plug @ 5 bpm,staging up to 7 bpm ©500 psi, 56%flow,slow pumps down to 3 bpm @ 2600 strokes. Bump plug with 2710 strokes. Pressure up to 900 psi and hold for 5Min. Bleed pressure off, check _ floats{good). 01:15 04:15 3.00 0 0 SURFA( CEMEN-CMNT P Drop Halliburton plug to close HES cementer as per Halliburton Rep. Let free fall for 20 min. Pressure up slowly to close HES cementer. Observed pressure jump @ 2,450 psi. Indication HES cementer was closed. Observed well, everything static. Call town and Halliburton Reps. Decision made to N/D cement head. observed HES plug logged in cement head. Call town and Halliburton Reps. Decision made to drop HES plug againn and let free fall for 30 mins.Attempt to pressure up but could not hold pressure, pumped 7 bbls away. Conference with town. Decision made to RIH with drill pipe to seat HES cementer. 04:15 06:30 2.25 0 0 SURFA( CEMEN-CMNT T PJSM back out landing joint. Flush stack out wtih black water, change handling equipment over of 5"and P/U bit sub. Page 7 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:30 07:30 1.00 0 0 SURFA( CEMEN-CMNT T RIH to+/-1000'MD set down 15k on HES plug 3 times then 25K. Decision made to POOH. 07:30 09:00 1.50 0 0 SURFA( CEMEN-RURD P Clean and clear rig floor. P/U amd M/U landing joint. Pressure up, observe pressure jump to 1,000 psi. Indication HES cementer closed. Pressure up to 1,400 psi and hold for 5 mins. Good pressure bleed off and R/D landing joint. Blow down lines. 09:00 12:00 3.00 0 0 SURFA( CEMEN-RURD P PJSM flush out hydril and N/D diverter equipment. 12:00 13:30 1.50 0 0 SURFA( CEMEN'NUND P PJSM,Cont N/D diverter,tag cement, continue N/U per plan per town eng and AOGCC. 13:30 15:00 1.50 0 0 SURFA( CEMEN-NUND P PJSM, N/U speed head and casing spool,test casing hanger and wellhead seal to 1000 psi for 10 min per FMC&town eng(witnessed by Co Rep). 15:00 20:00 5.00 0 0 SURFA( CEMEN'NUND P PJSM, C/O riser flange to dutch riser, cont N/U BOPE. 20:00 20:45 0.75 0 0 SURFA( CEMEN-RURD P PJSM-R/U to test BOPE. 20:45 00:00 3.25 0 0 SURFA( CEMEN'BOPE P Test BOPE,#1-Top pipe rams,valve 1,12,13,14 and manual kill.#2- Upper IBOP, HCR Kill,valves 9,11. #3-Lower IBOP,valves 5,8 and 10. #4-Dart valve,valves 4,6,7.#5-Floor valve and valve 2.#6-HCR choke,4" Kill line Demco Valve.#7-Manual choke valve, HCR kill,#8-Annular preventer.All tests performed with 5" test joint to 250/3500 psi for 5 min each. Tested annular to 250/2500 psi 5 minutes.AOGCC Chuck Scheve waived witness of test. 11/11/2013 Complete BOP test. P/U remaining 5"DP. Shut down and wait on weather 11 hrs, M/U BHA#3 w/Rock bit for drilling Tabasco section. Single in,drill out stage collar. Continue singling in. 00:00 01:00 1.00 0 0 SURFA( CEMEN'BOPE P PJSM,test BOPE to 250/3500 psi for 5 min each.#9 lower pipe rams; #10 Blind rams, C.V.#3; Accumulator test:System pressure= 3000 psi, pressure after closed= 1800 psi,200 psi attained=46 sec, full pressure attained= 189 sec, 5 bottle average= 2000 psi.Test gas alarms.Test waived by State of Alaska Rep Chuck Scheve. 01:00 01:45 0.75 0 0 SURFA( CEMEN'RURD P R/D test eqpt, Blow down TD, Kill line,choke line and choke. 01:45 02:45 1.00 0 0 SURFA( CEMEN'SLPC P PJSM, Slip and cut drilling line. (8 wraps,52') 02:45 03:15 0.50 0 0 SURFA( CEMEN-RURD P R/U to P/U 5"DP via mouse hole. 03:15 04:45 1.50 0 0 SURFA( CEMEN'PULD P PJSM, P/U 45 joints of 5"DP and rack back in derrick. Page 8 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:45 05:00 0.25 I 0 0 SURFA( CEMENT PULD P L/D mouse hole, P/U 9.9375" ID wear bushing and install. 05:00 12:00 7.00 0 0 SURFA( CEMENT OTHR T Shut down due to Phase 3 weather. SIMOPS: Clean and review drills. 12:00 16:15 4.25 0 0 SURFA( CEMENT OTHR T PJSM, Shut down due to Phase 3 weather. SIMOPS: Clean and review drills. 16:15 20:00 3.75 0 990 SURFA( CEMENT PULD P PJSM, P/U M/U BHA#3 per SLB Rep. PJSM, load nuke sources. Cont M/U BHA#3, RIH w/collars, HWDP and Jars to 773' MD, P/U 7 more singles to 990' MD. 20:00 20:45 0.75 990 990 SURFA( CEMEN-TRIP P Shallow pulse test MWD @ 410 gpm, 800 psi. 20:45 21:00 0.25 990 1,007 SURFA( CEMENT DHEQ P Establish parameters, P/U=72k, S/0=71k, ROT=73k, 60 rpm, 1k TQ. RIH and tag HES plug on depth @ 1007' MD. 21:00 00:00 3.00 1,007 1,007 SURFA( CEMENT DRLG P Drill HES plug @ 400-450 gpm, 750-950 psi, 30-70 rpm,2-3k TQ, 3-20k WOB.Varying parameters to drill plug. Drilled through plug© 00:00 hrs. 11/12/2013 Tag float collar, Pressure test 10 3/4"casing to 3,000 psi. Drill out float equipment and shoe track. Drill 20"of new hole. Displace to LSND mud and LOT to 13.2 ppg equivalent at the shQe.Drill 9 7/8"hole down to 3765' MD,2903'TVD. 00:00 02:45 2.75 1,007 3,012 SURFA( CEMEN'TRIP P PJSM-Single in hole f/1,007'MD to 2,903'MD. RIH out of derrick stand f/ 2,903'MD. Tagging up @ 3,102'MD, set 5K down. Rack back one stand. Actual displacement= 18.99 bbls, Calculated displacement= 19.5 bbls 02:45 03:15 0.50 3,012 3,012 SURFA( CEMENTCIRCP Circulate and condition the mud @ 4.5 bpm, 1,125 psi, 56%flow,40 RPM, TQ=6K, S/O WT=70K, P/U WT= 125 K. 03:15 03:30 0.25 3,012 3,012 SURFA( CEMENT RURD P R/U to test 10 3/4"casing. 03:30 04:15 0.75 3,012 3,012 SURFA( CEMENT PRTS P PJSM,test casing to 3,000 psi on chart for 30 mins. 04:15 04:30 0.25 3,012 3,012 SURFA( CEMENT RURD P R/D test equipment 04:30 08:30 4.00 3,012 3,209 SURFA( CEMENT DRLG P Drill out cement f/3,102 t/3,115' MD. Float equipment and shoe track @ 450 gpm, 1,250 psi, 70 RPM, TO =3-10 K. 08:30 10:00 1.50 3,209 3,229 SURFA( CEMENT DRLG P Drill 20'of new hole f/3,209'MD t/3.229'MD,TVD=2597'@ 450 GPM, 1,250 psi,60-80%flow, P/U weight= 120 K, S/O weight=77 K, WOB= 10-20 K, Bit hours= 1.13, Total jar hours=32.66. Page 9of29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 10:00 10:45 0.75 3,229 3,229 SURFA( CEMEN-CIRC P PSJM and pump 20 bbls Hi Vis spacer and displace well f/9.7ppg drillplex mud to 9.6 ppg LSND mud @ 450 GPM, 1,250 psi, FCP=850. Slow Pump Rates: MD=3229',TVD =2597', MW=9.6 ppg, Time= 10:45 #1:20 spm= 120 psi; 30 spm= 160 psi #2:20 spm= 120 psi; 30 spm= 160 psi 10:45 11:15 0.50 3,229 3,179 SURFA( CEMEN-OWFF P POOH f/3,229' MD t/3,179' MD. Monitor well,static. Blow down top drive. 11:15 11:30 0.25 3,179 3,179 SURFA( CEMEN-RURD P R/U to perform LOT 11:30 12:15 0.75 3,179 3,179 SURFA( CEMEN-LOT P Perform LOT as per CO. Rep. Perform test w/9.6 ppg mud,surface pressure 490 psi,2,594'TVD for a EMW of 13.2 ppg,R/D test equipment. 12:15 18:00 5.75 3,179 3,455 INTRM1 DRILL DDRL P Est parameters, drilling from 3229' MD to 3455'MD,TVD=2739',ART =3.98,ADT=3.98,total jar hours= 36.65, bit hours=5.14, P/U wt= 107k, 5/0 wt=87k, Rot wt=96k, TQ on=6k,TQ off=4k, ECD= 10.36, Flow out=74%,WOB= 13-18k, RPM= 140, GPM=750, PSI =2200. 18:00 00:00 6.00 3,455 3,765 INTRM1 DRILL DDRL P Drilling from 3455'MD to 3765'MD, TVD=2903',ART=5.16,ADT= 5.16,total jar hours=41.81, bit hours= 10.3, P/U wt= 107k, S/O wt =92k, Rot wt= 100k,TQ on=5k, TQ off=3k, ECD= 10.31, Flow out =74%,WOB=5-18k, RPM= 140, GPM=750, PSI =2200. Slow Pump Rates: MD=3734', TVD =2885', MW=9.6 ppg,Time= 22:40 #1: 20 spm= 130 psi; 30 spm= 170 psi #2: 20 spm = 130 psi; 30 spm = 170 psi 11/13/2013 Drill 9 7/8"hole through Tabasco, Pump out of hole through Tabasco then POOH to change BHA and drill bit. 00:00 06:00 6.00 3,765 4,012 INTRM1 DRILL DDRL P Drill f/3,765'MD t/4,012'MD, TVD=3,045',ADT=5.01,total jar hours=46.82, bit hours=15.31, P/U weight=109K, S/O weight=94 K, ROT weight=102 K,TQ on=5-8 K, TQ off=5K,ECD=10.44,Flow out=81%,WOB=10-14,RPM=150,GP M=750,PS I=2,350. 06:00 07:45 1.75 4,012 4,012 INTRM1 DRILL EQRP T Trouble shoot SLB tools Page 10 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:45 12:00 4.25 4,012 4,105 INTRM1 DRILL DDRL P Drill f/4,012'MD t/4,105'MD, TVD=3,099'MD,ADT=2.43, total jar hours=49.25, bit hours=17.74, P/U weight=113K, S/O weight=95 K, ROT weight=105 K, TQ on=5-6 K, TQ off=5K,ECD=10.35,Flow out=82%,WOB=15,RPM=150,GPM= 750,PSI=2,410. 12:00 16:30 4.50 4,105 4,289 INTRM1 DRILL DDRL P Drill f/4105'MD t/4289'MD, TVD=3223'MD,ADT=4.23, total jar hours=53.48, bit hours=21.97, P/U weight=115K, S/O weight=98 K, ROT weight=106 K, TQ on=5.5 K, TQ off=3.5K,ECD=10.41,FIow out=83%,WOB=15-18,RPM=150,GP M=750,PSI=2500. Ream stand, survey on bottom. Slow Pump Rates: MD=4105', TVD =3099', MW=9.6 ppg,Time= 11:15 #1:20 spm= 130 psi; 30 spm= 160 psi #2: 20 spm= 130 psi; 30 spm = 170 psi 16:30 17:45 1.25 4,289 4,289 INTRM1 DRILL CIRC P CBU x3, pump 20 bbl Hi Vis sweep @ 750 gpm, 2450 psi, 140 rpm,TQ =3.5k 17:45 18:00 0.25 4,289 4,289 INTRM1 DRILL OWFF P Monitor well(STATIC). SIMOPS: PJSM for pumping out of hole and POOH. 18:00 18:45 0.75 4,289 3,830 INTRM1 DRILL TRIP P Pump out of the hole from 4289'MD to 3830'MD, pump @ 3 bpm,200 psi, ump on Cal=3.75 bbls, pump on Act=6.86 bbls. Slow Pump Rates: MD=4289',TVD =3223', MW=9.6 ppg, Time= 18:00 #1: 20 spm= 130 psi; 30 spm = 160 psi #2: 20 spm= 130 psi; 30 spm = 170 psi 18:45 19:15 0.50 3,830 3,830 INTRM1 DRILL OWFF P Monitor well(STATIC), B/D top drive. 19:15 20:00 0.75 3,830 3,181 INTRM1 DRILL TRIP P POOH to 3181' MD. 20:00 20:30 0.50 3,181 3,181 INTRM1 DRILL OWFF P Monitor well(STATIC). 20:30 21:30 1.00 3,181 866 INTRM1 DRILL TRIP P POOH to 866' MD. Total Cal=24.75 bbls, Total Act=23.8 bbls. 21:30 21:45 0.25 866 866 INTRM1 DRILL OWFF P Monitor well @ HWDP(STATIC). 21:45 22:00 0.25 866 310 INTRM1 DRILL TRIP P POOH racking back HWDP to 310' MD. 22:00 23:00 1.00 310 125 INTRM1 DRILL PULD P PJSM, POOH, rack back 2 stands HWDP, remove nuke sources from BHA. Cal= 12.41 bbls,Act= 12.58 bbls. 23:00 00:00 1.00 125 73 INTRM1 DRILL PULD P PJSM, L/D BHA per SLB Rep, L/D ADN, Sonicscope, ILS Stab. Page 11 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11/14/2013 24 hr Summary Change out BHA, RIH, Drill 9 7/8" hole with PDC bit. Drill 9 7/8"hole from to 4289'MD to 5650'MD,4357' TVD. 00:00 00:30 0.50 73 0 INTRM1 DRILL PULD P PJSM, L/D BHA and M/U new bit as per SLB Rep.Act fill =3.23, Cal fill = 4.99. 00:30 01:00 0.50 0 0 INTRM1 DRILL SVRG P Service rig 01:00 02:00 1.00 0 0 INTRM1 DRILL OTHR T Wait on SLB (working on tools). 02:00 03:00 1.00 0 55 INTRM1 DRILL PULD P PJSM, M/U BHA#4 as per SLB Reps. 03:00 04:15 1.25 55 55 INTRM1 DRILL PULD P PJSM, Load sources into ADN tool as per SLB Rep. 04:15 04:45 0.50 55 773 INTRM1 DRILL TRIP P RIH with drill collars and HWDP to 773'. 04:45 05:30 0.75 773 773 INTRM1 DRILL CIRC P Shallow hole pulse test tools @ 600 GPM= 1125 PSI, good. Blow down top drive. 05:30 06:45 1.25 773 4,197 INTRM1 DRILL TRIP P PJSM, RIH w/5"drill pipe f/773' MD to 4197' MD, filling pipe every 20 stands. 06:45 07:45 1.00 4,197 4,289 INTRM1 DRILL WASH P Wash and ream from 4,197'-4,289' and at 750 gpm, 2,300 psi, 140 rpm, 5K ft-lb TQ. Heavy cuttings loads returning on shakers. Continue circulating to clean hole. Obtain slow pump rates. 07:45 12:00 4.25 4,289 4,643 INTRM1 DRILL DDRL P Drilled 9-7/8" hole w/SWS Xceed RSS f/4,289'to 4,643'MD, 3,485' TVD ADT-2.59 hrs. ECD-10.59 ppg Footage-354' WOB 4-6K RPM 140 GPM 750 @ 2400 psi String wt. PU= 119 SO= 102 ROT= 110 Torque on/off btm.-7/4K ft-lbs. Bit Hrs=2.59, Jar Hrs=56.09 SPR MP#1 = 190 psi at 30 spm, 260 psi at 40 spm SPR MP#2= 190 psi at 30 spm, 250 psi at 40 spm 12:00 18:00 6.00 4,643 5,214 INTRM1 DRILL DDRL P Drilled 9-7/8"hole w/SWS Xceed RSS f/4,643'to 5,214' MD, 3,962' TVD ADT-4.27 hrs. ECD- 10.83 ppg Footage-571' WOB 3-8K RPM 140 GPM 750 @ 2,550 psi String wt. PU= 137 SO= 114 ROT= 125 Torque on/off btm.-7.5/4K ft-lbs. Bit Hrs=6.86, Jar Hrs=60.36 Page 12 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 18:00 00:00 6.00 5,214 5,650 INTRM1 DRILL DDRL P Drilled 9-7/8"hole w/SWS Xceed RSS f/5,214'to 5650' MD, 4357' TVD ADT-3.32 hrs. ECD- 10.8 ppg Footage-436' WOB 5-13K RPM 140 GPM 750 @ 2,675 psi String wt. PU= 145 SO= 120 ROT= 130 Torque on/off btm.-8/4K ft-lbs. Bit Hrs=10.18, Jar Hrs=63.68 SPR MP#1 =220 psi at 30 spm, 280 psi at 40 spm SPR MP#2=210 psi at 30 spm, 270 psi at 40 spm 11/15/2013 Drill 9 7/8"hole from to 5,650'MD to Intermediate TD 7,234.2'MD, 5,693.8'TVD. 00:00 06:00 6.00 5,650 6,254 INTRM1 DRILL DDRL P Drill from 5650'MD to 6254' MD, TVD =4903', ADT=4.94, Total Jar hours =68.62, Bit hours= 15.12, P/U wt= 158k, S/O wt= 131 k,Rot wt= 145k, TQ on=8.5k,TQ off=6k, ECD= 10..91, Flow out=82/76%,WOB= 4-7k, RPM = 140, GPM =750,PSI = 2810. Slow Pump Rates: MD=6791', TVD =5360', MW=9.8+ppg, Time= 05:30 #1: 30 spm=250 psi; 40 spm =330 psi #2: 30 spm=250 psi; 40 spm =340 psi 06:00 12:00 6.00 6,254 6,791 INTRM1 DRILL DDRL P Drill from 6254' MD to 6791' MD, TVD =5360',ADT= 3.59, Total Jar hours =72.21, Bit hours= 18.71, P/U wt= 165k, S/O wt= 136k,Rot wt= 152k, TQ on=9k, TQ off=7k, ECD= 10.92, Flow out=78/82%,WOB= 5-7k, RPM= 140, GPM =750, PSI = 2900 12:00 18:30 6.50 6,791 7,234 INTRM1 DRILL DDRL P Drill from 6,791' MD to 7,234.2' MD, TVD=5,693.8',ADT=5.06, Total Jar hours=77.27, Bit hours=23.77, P/U wt= 175k, S/O wt= 140k, Rot wt= 154k, TQ on=9.5k, TQ off= 6.5k, ECD= 10.87, Flow out=75%, WOB=7-10k, RPM = 140, GPM= 746, PSI =3075 18:30 21:15 2.75 7,234 7,234 INTRM1 CASING CIRC P Pump Hi Vis sweep, Circ and condition mud @ GPM=745, RPM = 140, TQ on=6k, PSI =3025, P/U wt= 140k, S/O wt= 149k, ECD= 10.84. Increase MW to 10.0 ppg from 9.9+ppg. 21:15 21:45 0.50 7,234 7,234 INTRM1 CASING OWFF P Monitor well (STATIC). Page 13 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 21:45 00:00 2.25 7,234 5,781 INTRMI CASING REAM P PJSM, BROOH from 7230'MD to 5781' MD @ 650 gpm =2500 psi, RPM = 140. 11/16/2013 BROOH to base of Tabasco Fm, flow chk, RIH to TD, C&C mud for casing. POOH. Change rams, test BOPE. R/U to run 7 5/8"casing. 00:00 02:30 2.50 5,781 4,570 INTRMI CASING REAM P PJSM, BROOH from 5781'MD to 4570' MD @ 650 gpm =2250 psi, RPM= 140, TQ=5-6k. 02:30 03:00 0.50 4,570 4,570 INTRM1 CASING SVRG P PJSM, Service rig. 03:00 03:15 0.25 4,570 4,238 INTRM1 CASING REAM P BROOH from 4570' MD to 4200' MD ©650 gpm, RPM= 140,TQ=5k. 03:15 04:30 1.25 4,238 4,238 INTRM1 CASING CIRC P CBU x3 @ 750 gpm,2725 psi, 140 rpm, TQ=5k. 04:30 05:45 1.25 4,238 7,163 INTRM1 CASING TRIP P PJSM, RIH from 4294'MD to 7163' MD.Act disp=20.4bbls, Calc disp= 24.18bbls. 05:45 06:00 0.25 7,163 7,234 INTRM1 CASING REAM P Wash and Ream from 7163' MD to 7234'MD @ 750 gpm, 3200 psi, 76%flow, 140 RPM, TQ on=7.5k, P/U wt 146k, 5/0 wt= 150k. 06:00 08:15 2.25 7,234 7,163 INTRM1 CASING CIRC P Circulate and condition mud,wt up mud system from 10.0 ppg to 10.3 ppg @ 750 gpm, ICP=3200 psi, 140 =RPM, TQ=7.5k, FCP=3125 psi, TQ=5k, P/U wt= 175k, 5/0 wt= 145k, Obtain SPR's, Monitor Well (STATIC) Slow Pump Rates: MD=7163', TVD =5648', MW= 10.3 ppg,Time= 08:05 #1: 30 spm=240 psi;40 spm=320 psi #2: 30 spm=240 psi;40 spm =340 psi 08:15 09:15 1.00 7,163 6,797 INTRM1 CASING CIRC P PJSM,attempt to pump out of hole at 2 bpm, hole started to pack off, work through tight spot, increase pump rate to 650 gpm and pump out of hole from 7163'MD to 6797'MD @ 650 gpm, 2550 psi,68%flow.Act fill =5.1, Calc fill=3.9. 09:15 09:30 0.25 6,797 6,797 INTRM1 CASING OWFF P Monitor well(STATIC), Blow down TD. 09:30 11:15 1.75 6,797 3,181 INTRM1 CASING TRIP P POOH on elevators from 6797'MD to 3181'MD.Act fill=31.79 bbls, Calc fill=29.64 bbls/ 11:15 12:00 0.75 3,181 3,181 INTRM1 CASING OWFF P Monitor well(STATIC) 12:00 12:30 0.50 3,181 800 INTRMI CASING TRIP P PJSM, Cont POOH on elevators from 3181' MD to 800' MD. 12:30 12:45 0.25 800 800 INTRMI CASING OWFF P Monitor well @ last joint of DP (STATIC). 12:45 13:00 0.25 800 190 INTRM1 CASING TRIP P Rack back HWDP. 13:00 13:45 0.75 190 125 INTRM1 CASING PULD P L/D flex collars 13:45 14:30 0.75 125 125 INTRM1 CASING PULD P PJSM, L/D nukes. Page 14 of 29 Time Logs Date From To Dur S. Depth.E.Depth Phase Code Subcode T Comment 14:30 16:15 1.75 125 0 INTRM1 CASING PULD P Cont to L/D BHA. 16:15 16:45 0.50 0 0 INTRM1 CASING RURD P Clean and clear rig floor. 16:45 17:15 0.50 0 0 INTRM1 CASING RURD P PJSM,flush stack RID, B/D Top Drive 17:15 18:00 0.75 0 0 INTRM1 CASING RURD P PJSM, Pull wear buching, set test plug. 18:00 19:15 1.25 0 0 INTRM1 CASING RURD P PJSM, C/O top pipe rams from 3.5" x 6"to 7-5/8"solid body rams. 19:15 20:45 1.50 0 0 INTRM1 CASING BOPE P PJSM, R/U and test 7-5/8"top rams to 250/3500 psi for 5 min each, Test annular to 250/2500 psi for 5 min each, all charted. 20:45 22:00 1.25 0 0 INTRMI CASING PULD P L/D tools from rig floor, P/U casing tools. 22:00 00:00 2.00 0 0 INTRM1 CASING RURD P PJSM, R/U casing equipment. 11/17/2013 Run 7 5/8"casing. Circulate. Cement casing. R/D Cement eqpt.. 00:00 00:15 0.25 0 0 INTRM1 CASING RNCS P Finish RU 7 5/8"casing equipment 00:15 00:30 0.25 0 0 INTRM1 CASING SFTY P PJSM for running 7-5/8" Intermed casing 00:30 05:45 5.25 0 3,115 INTRMI CASING RNCS P PU casing Float shoe, 1 Jt 7-5/8", 29.7 Ib/ft, L-80, BTC casing, HES Float collar with By-Pass Baffle adapter, 1 Jt 7-5/8",29.7 Ib/ft, L-80 BTCM casing, HES Shut-off Baffle Adapter, 1 jt of 7-5/8",29.7 lb/ft, L-80, BTCM casing,XO BTC pin x Hydril 563 box.Thread lock all connections to top of Shut-off Baffle Adapter. Check floats-okay. Contine to run 75 Jts 7-5/8", 29.7 Ib/ft, L-80, Hydril 563, R2 casing with MU to 10,300 ft-lb TQ and recorded with Torque-Turn. Ran Tandem-Rise centralizers 5'and 8'above Float Shoe on stop collars and one 10'below the Baffle Collar on stop. Installed centralizers on collars on joint 4-17. 05:45 06:30 0.75 3,115 3,115 INTRM1 CASING CIRC P Circ casing volume(143 bbl)with Fillup tool at 5 bbl/min and 350 psi and 52%flowline returns. 06:30 08:30 2.00 3,115 5,182 INTRM1 CASING RNCS P Contine to run 52 Jts 7-5/8", 29.7 Ib/ft, L-80, Hydril 563, R2 casing to 5,112'md,with MU to 10,300 ft-lb TQ and recorded with Torque-Turn. 08:30 09:15 0.75 5,182 5,182 INTRM1 CASING CIRC P CBU with Fillup tool at 5 bbl/min and 550 psi and 54%flowline returns. 09:15 10:45 1.50 5,182 6,792 INTRM1 CASING RNCS P Contine to run 40 Jts 7-5/8",29.7 lb/ft, L-80, Hydril 563, R2 casing to 6792'md,with MU to 10,300 ft-lb TQ and recorded with Torque-Turn. Page 15 of 29 S Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 10:45 12:00 1.25 6,792 6,792 INTRM1 CASING CIRC P CBU with Fillup tool at 5 bbl/min and 580 psi and 54%flowline returns. PU (pumps on)= 195K, SO=133K lb. 12:00 12:15 0.25 6,792 6,792 INTRM1 CASING SFTY P PJSM for running 7-5/8"Intermed casing,with new crew. 12:15 13:15 1.00 6,792 7,222 INTRM1 CASING RNCS P Contine to run 5 Jts 7-5/8", 29.7 lb/ft, L-80, Hydril 563, R2 casing to 7222' md,with MU to 10,300 ft-lb TQ and recorded with Torque-Turn. PU(pumps off)= 134K, S0= 112K lb. 13:15 13:45 0.50 7,222 7,222 INTRM1 CASING RNCS P MU landing Jt and set down on hanger. RD Fill-up tool. RU cement head and lines. 13:45 17:15 3.50 7,222 7,222 INTRM1 CASING CIRC P Circ and condition mud staging up from 3 bbl/min to 6 bbl/min with 600 psi. Reciprocate casing with 30' strokes. 17:15 17:30 0.25 7,222 7,222 INTRM1 CEMEN-PRTS P PJSM, Pump 5 bbl of fresh water, pressure test lines to 250 low/4,000 psi high(GOOD). 17:30 18:45 1.25 7,222 7,222 INTRM1 CEMEN'CMNT P Pump 40 bbl CW 100,40 bbl 12.5 ppg Mudpush II, shut down,drop 1st stage bottom plug, pump 57 bbl (40%excess)of 15.8 ppg Lead cmt, drop top plug, 10 bbl of water. Reciprocate casing with 30'strokes. Up wt=215K, SO wt= 140K lb. 18:45 19:45 1.00 7,222 7,222 INTRM1 CEMEN'CIRC P Displace cement with 10.4 ppg LSND mud using rig pumps at 6 bbl/min,400 psi. Slow pumps to 3 SPM while plugs passed ES cementer and also for the last 10 bbl prior to bumping plug. Continue to reciprocate casing with 30'strokes. PU=215K, SO= 140K. Land casing at 2,400 strokes. Bumped plug with 3,155 strokes, Pressure up to 900 psi and hold for 5 min. Bleed pressure off to check floats-no flowback. 1st stage CIP at 19:50 hrs. 19:45 21:15 1.50 7,222 7,222 INTRM1 CEMEN'RURD P Load cement plug for second stage,. Pressure up to 3,350 psi and open ES Cementer. Circulate 2x BU at 6 bbl/min and 400 psi. 21:15 22:15 1.00 7,222 7,222 INTRM1 CEMEN-CMNT P Pump 40 bbl CW 100,40 bbl 12.5 ppg Mudpush II at 6 bbl/min,shut down, pump 17 bbl(40%excess)of 16.0 ppg lead cmt,with 0.8 gal D177 -(8 hr thickening time), 32.9 bbl 15.8 ppg tail cmt w/D186(thickening time_ 4 hr). Page 16 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 22:15 23:00 0.75 7,222 7,222 INTRM1 CEMEN-CIRCP Drop ES Cementer closing plug, Pump 10 bbl of water, swap over to rig pumps to displace w/ 10.4 ppg conditnioned mud @ 6 bpm, 250 psi. Slow pumps down to 3 bpm, 550 psi 10 bbls prior to bump plug. Bump plug 1950 strokes(196 bbls). 23:00 23:30 0.50 7,222 7,222 INTRM1 CEMEN-CMNT P Pressure up-to close ES Cementer to 1750 psi, stage up to 2400 psi. Stage tool closed, held pressure for 5 minutes, bled off pressure to monitor for flow back(no flow). 23:30 00:00 0.50 7,222 7,222 INTRM1 CEMEN-RURD P R/D Cement head. 11/18/2013 Install and test packoff. LOT for OA, freeze protect annulus. LD 5"DP. Change pipe rams to VBRs. Test BOPs with 4"and 5.5"test jts. PU BHA#5 and 4"DP. 00:00 01:00 1.00 7,222 7,222 INTRM1 CEMEN-RURDP PJSM, R/D casing eqpt, Back out landing joint. Clean casing tools and clear rig floor. 01:00 01:30 0.50 7,222 7,222 INTRM1 CEMEN RURD P LD long casing bales install drilling bales. Change to 5"handling tools. PU and install mouse hole. PU thread protectors for DP. 01:30 02:45 1.25 7,222 0 INTRM1 CEMEN WWSP P Set pack off and test 250 psi for 5 min, 5000 psi for 10 min as per FMC Rep. -test good. 02:45 03:00 0.25 0 0 INTRM1 CEMEN-PULD P PJSM, L/D 5" HWDP and DP 03:00 08:00 5.00 0 0 INTRM1 CEMEN-PULD P PJSM, L/D 6 stands of 5" HWDP and 71 stds of 5" DP from derrick. SIMOPS: Flush 10.75"x 7.625"OA intermediate annulus with 150 bbls water followed by 75 bbls diesel. Leak off Pressure: 600 psi. Shut in Pressure: ????psi 08:00 08:15 0.25 0 0 INTRM1 CEMEN BOPE P PJSM for changing rams 08:15 11:00 2.75 0 0 INTRM1 CEMEN-BOPE P Change out Top Pipe rams from 7-5/8"solid body rams to 3.5"x 6.0" VBRs. Change out TD Saver sub from 5"to 4",XT-39. 11:00 12:00 1.00 0 0 INTRM1 CEMEN BOPE P Pull WB. RU 4"test joint and recording equip for BOP test. 12:00 12:30 0.50 0 0 INTRM1 CEMEN BOPE P Continue RU test equip. 12:30 12:45 0.25 0 0 INTRM1 CEMEN-SFTY P PJSM for BOP test 12:45 14:30 1.75 0 0 INTRM1 CEMEN BOPE P Test pipe rams with 4"test joint to 250 low/3,500 high, test Floor valve, Dart valve to 250/3,500 psi-okay. Test Annular with 4"test jt to 250/ 2,500 psi-all okay. Pull and LD 4" test jt, PU, set 5.5"test jt. Test top pipe rams to 250/3,500 psi,test Annular to 250/3,500 psi-okay 14:30 15:15 0.75 0 0 INTRM1 CEMEN-BOPE P LD test jt. RD test equip. Set WB. 15:15 15:30 0.25 0 0 INTRM1 CEMEN-SFTY P PJSM for PU DP and BHA Page 17 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 15:30 17:00 1.50 0 0 INTRMI CEMEN'PULD P PU and single in hole with 10 stands of 4",XT-39 DP and rack back in derrick. 17:00 18:15 1.25 0 0 INTRM1 CEMEN-SLPC P Cut and slip 59'(9 wraps)of drill line, service TD. 18:15 18:45 0.50 0 0 INTRM1 CEMEN-SVRG P Lubricate rig. 18:45 19:30 0.75 0 0 INTRM1 CEMEN-PULD P P/U tools from slide. 19:30 20:45 1.25 0 0 INTRM1 CEMEN RURD P Clean and clear rig floor.Work on MP#2,finish prep MWD tools 20:45 23:00 2.25 0 0 INTRMI CEMEN'PULD P PU/MU 6-3/4"BHA#5 23:00 23:15 0.25 0 0 INTRM1 CEMEN-SFTY P PJSM for loading RA source 23:15 00:00 0.75 0 0 INTRM1 CEMEN-PULD P Load RA source in ADN tool. 11/19/2013 P/U 6-3/4"drilling BHA, RIH and test tools.Trouble shoot SLB tools, re-test, good. RIH P/U 4"drill pipe to stage collar, drill out stage collar and cont. RIH P/U drill pipe to 7177'.Test 7-5/8"casing to 3000 PSI for 30min, good. Drill out shoe track and rat hole to 7234'. 00:00 00:15 0.25 55 55 INTRM1 CEMEN'PULD P PJSM, Cont to load sources in to ADN as per SLB rep. 00:15 00:45 0.50 55 489 INTRM1 CEMEN-PULD P RIH picking up drill collars and HWDP to 489'MD. 00:45 01:15 0.50 489 489 INTRM1 CEMEN-CIRC P Pulse test MWD @ 300 GPM=2225 PSI, 50%flow as per SLB rep. Higher than expected pressure. POOH to trouble shoot BHA as per SLB rep. 01:15 01:45 0.50 489 153 INTRM1 CEMEN TRIP T POOH f/489'to 153' 01:45 02:45 1.00 153 153 INTRM1 CEMEN"PULD T PJSM, Remove sources from ADN tool as per SLB rep. 02:45 03:30 0.75 153 153 INTRM1 CEMEN"OTHR T Trouble shoot MWD as per SLB rep, Discovered at pump rate of 300 GPM is to high for the tools. Pump down BHA @ 200 GPM=1000 PSI,good. 03:30 04:00 0.50 153 153 INTRM1 CEMEN'PULD T PJSM, Load sources in ADN as per SLB rep. 04:00 04:15 0.25 153 489 INTRM1 CEMEN'TRIP T RIH with drill collar and HWDP to 489'. 04:15 04:45 0.50 489 489 INTRM1 CEMEN-CIRC T Pulse test tools @ 200 GPM=1000 PSI,good. 04:45 05:30 0.75 489 772 INTRM1 CEMEN-TRIPP Blow down top drive, RIH t/772'MD. 05:30 07:45 2.25 772 3,610 INTRM1 CEMEN PULD P RIH picking up 4"drill pipe to 3610' MD,filling pipe every 20 stands. 07:45 10:45 3.00 3,610 3,610 INTRM1 CEMEN RGRP T Pipe skate hose leaked 2-1/2 gallons of hydraulic oil into secondary containment. Repair hose on pipe skate. 10:45 11:30 0.75 3,610 4,460 INTRM1 CEMEN-PULD P Cont RIH picking up 4"drill pipe to 4460'MD. Tagged up on cement @ 4460'MD, set down 5K. Pick up and UD 1 joint.Actual displacement= 32.9 bbls, Calculated displacement= 30.9 bbls. 11:30 12:30 1.00 4,460 4,455 INTRM1 CEMEN-PRTS P PJSM, Rig up and test 7-5/8"casing above stage collar to 3000 PSI for 10 minutes, good. Page 18 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:30 13:00 0.50 4,455 4,501 INTRM1 CEMEN-COCF P Establish parameters, pump @ 230 GPM=1875 PSI, 50 RPM,Tq=4K, P/U=93K, S/0=80K, ROT=85K. Ream 4455'to 4501'.Tagged up on stage collar. 13:00 14:15 1.25 4,501 4,505 INTRM1 CEMEN-DRLG P Drill stage collar f/4501'to 4505'. WOB 8K,Tq=5K. Ream f/4520'to 4480'several times with no issues. 14:15 15:00 0.75 4,505 4,525 INTRM1 CEMEN-CIRC P CBU @ 230 GPM= 1800 PSI, observed traces of rubber and metal on shakers at bottoms up. 15:00 15:30 0.50 4,525 4,525 INTRM1 CEMEN-PRTS P PJSM, Pressure test casing to 3000 PSI for 10min to ensure stage collar is closed,good. Blow down top drive and kill line. 15:30 17:45 2.25 4,525 7,117 INTRM1 CEMEN-PULD P PJSM, Cont. RIH picking up 4"drill pipe to 7117'. 17:45 18:45 1.00 7,117 7,110 INTRMI CEMEN-CIRC P CBU @ 7110', pump @ 200 GPM= 1750 PSI. 18:45 19:30 0.75 7,110 7,110 INTRMI CEMEN-PRTS P PJSM, Rig up to test casing.Test 7-5/8"casing to 30 minutes on chart, good. 19:30 20:00 0.50 7,110 7,120 INTRM1 CEMEN-CIRCP Establish parameters, P/U= 165K, S/0=90K, ROT= 120K,Tq= 10K. Pump @ 230 gpm=2200 psi. Obtain SPR's @ 7120'TVD=5606'MW= 10.25 ppg @ 19:45 hours. 20:00 20:15 0.25 7,120 7,138 INTRMI CEMEN"DRLG P Drill cement @ 7130',tagged baffle adapter @ 7138'.WOB=7-8K, Tq-11 K. Decision made to ass lubes to mud for high torque. 20:15 21:15 1.00 7,138 7,138 INTRM1 CEMEN-CIRC P Work pipe and add Lube 776 to mud, pump @ 230 GPM=2100 PSI. 21:15 00:00 2.75 7,138 7,234 INTRM1 CEMEN-DRLG P Drill shoe track @ 230 GPM=2150 PSI,40 RPM, Tq=8.5K f/7138'to 7222'. Drill rat hole to 7234'. Tagged baffle adapter @ 7138, Float collar @ 7180'and shoe @ 7222'. 11/20/2013 Drilled 20'of new hole to 7254'. CBU, perform FIT to 16.1 ppg EMW. Drilled 6-3/4"hole to TD @ 7988' MD, TVD=6243'. CBU X 3, make wiper trip to shoe, CBU. RIH to 7988'and CBU. 00:00 00:15 0.25 7,234 7,254 INTRM1 CEMEN-DRLG P Drill 20'of new hole f/7234'to 7254, pump @ 230 GPM=2150 PSI,40 RPMs, Tq=10K. P/U= 165K, S/0= 90K. 00:15 01:15 1.00 7,254 7,254 INTRM1 CEMEN-DISP P Circulate and condition hole for FIT, displace to new 10.6 ppg LSND mud system with SackBlack and LCM added. Pump @ 200 GPM= 1425 PSI,44%flow,40 RPM,Tq=9K. 01:15 01:30 0.25 7,254 7,204 INTRM1 CEMEN-TRIP P POOH f/7254'to 7204', blow down top drive. 01:30 02:15 0.75 7,204 7,204 INTRM1 CEMEN-FIT P R/U, perform FIT to 16.1 ppg EWM. R/D testing equipment. Page 19 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 02:15 03:00 0.75 7,204 7,254 PROD1 DRILL CIRC P RIH f/7204'to 7254'.Attempt to drill ahead @ 200 GPM= 1150 PSI, shakers running over very bad, large amount of LCM/Black product being stripped out. Pull up to casing shoe and pump.5 BPM=150 PSI while changing screens. Obtain SPR @ 7256'TVD=5710'. 10.6 ppg MW, 2:10 hours. 03:00 06:00 3.00 7,254 7,360 PROD1 DRILL DDRL P Drill ahead f/7254'to 7360',TVD= 5790'.ART=2.25,AST=.95,ADT= 3.20,Total Jar Hrs=3.20, Bit Hrs= 3.20, P/U= 145K, S/O=98K, ROT= 120K, Tq on=7K,Tq off=6K, ECD= 11.33 ppg EMW, Flow out=43%, WOB=9-15K, 80 RPM, 230 GPM= 2200 PSI. 06:00 12:00 6.00 7,360 7,684 PROD1 DRILL DDRL P Drill ahead f/7360'to 7684',TVD= 6035'.ART= 1.52,AST= 1.07,ADT= 2.59, Total Jar Hrs=5.79, Bit Hrs= 5.97, P/U= 153K, S/O= 100K, ROT= 122K, Tq on=7K,Tq off=6K, ECD= 11.51 ppg EMW, Flow out=46%, WOB= 15K, 80 RPM,230 GPM= 2200 PSI. 12:00 16:00 4.00 7,684 7,988 PROD1 DRILL DDRL P Drill ahead f/7684'to 7988', TVD= 6243'.ART=5.56,AST=0,ADT= 5.56,Total Jar Hrs= 11.35, Bit Hrs= 11.35, P/U= 156K, S/O= 101K, ROT= 124K, Tq on=7.5K,Tq off= 6.5K, ECD=11.54 ppg EMW, Flow out=46%,WOB=6-8K, 80 RPM, 240 GPM=2250 PSI. 16:00 18:15 2.25 7,988 7,987 PROD1 CASING CIRC P CBU X 3, pump @ 230 GPM=2050 PSI,80 RPM. Obtain SPR @ 7987' MD,TVD=6242. 10.6 ppg MW, 18:15 hours. 18:15 18:30 0.25 7,987 7,962 PROD1 CASING PULD P Lay down single and blow down top drive. 18:30 19:00 0.50 7,962 7,962 PROD1 CASING OWFF P Monitor well, static. 19:00 19:30 0.50 7,962 7,962 PROD1 CASING TRIP P POOH on elevators f/7962'to 7679'. Improper hole fill,decision made to RIH back to bottom. 19:30 20:00 0.50 7,962 7,962 PROD1 CASING CIRC P Send down link to SLB tools to relax tools as per SLB reps. 20:00 21:15 1.25 7,962 7,208 PROD1 CASING TRIP P POOH w/pump @ 3 BPM=950 PSI. Actual displacement=6.4 bbls, Calculated displacement=4.6 bbls. 21:15 22:00 0.75 7,208 7,208 PROD1 CASING CIRC P CBU @ shoe, pump @ 240 GPM= 1825 PSI, 15 RPM,46%flow. P/U= 113K, S/O=95K. 22:00 22:15 0.25 7,208 7,208 PROD1 CASING OTHR P Blow down top drive. 22:15 23:00 0.75 7,208 7,988 PROD1 CASING TRIP P RIH f/7208'to 7988'.Actual displacement=4.4 bbls, Calculated displacement=4.6 bbls. Page 20 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 23:00 00:00 1.00 7,988 7,988 PROD1 CASING CIRC P Send down link to SLB tools. CBU X 3, pump @ 240 GPM= 1825 PSI,40 RPMs,Tq=5.5K,46%flow. P/U= 118K, S/O= 120K. 11/21/2013 Circulated hole clean, POOH and L/D BHA#5. R/U casing equipment, RIH w/5-1/2" DWC-C liner to 955'. M/U ZXP and RIH w/5-1/2"liner on 4"drill pipe to 6262'MD. 00:00 00:30 0.50 7,988 7,988 PROD1 CASING CIRC P PJSM, CBU X 3, pump @ 240 GPM= 1950 PSI,46%flow, 50 RPM, Tq=5.5K. Circulate hole clean. 00:30 01:00 0.50 7,899 7,957 PROD1 CASING OWFF P POOH f/7988'to 7957'. L/D working single and OWFF,static. 01:00 02:00 1.00 7,957 7,206 PROD1 CASING TRIP P POOH on elevators to 7206'. OWFF @ 7-5/8"casing shoe, static. 02:00 02:15 0.25 7,206 7,206 PROD1 CASING CIRC P Pump 20 bbls of 12.6 ppg slug, blow down top drive. 02:15 04:45 2.50 7,206 772 PROD1 CASING TRIP P POOH on elevators f/7206'to 772'. Actual displacement=54.74 bbls, Calculated displacement=50.34 bbls. 04:45 05:00 0.25 772 772 PROD1 CASING OWFF P Monitor well @ HWDP. SIMOPS, P/U thread protectors. 05:00 06:30 1.50 772 180 PROD1 CASING PULD P PJSM, L/D HWDP and drill collars. 06:30 07:00 0.50 180 180 PROD1 CASING PULD P PJSM, Remove sources from ADN as per SLB rep. 07:00 08:00 1.00 180 0 PROD1 CASING PULD P L/D BHA#5 as per SLB rep, 08:00 08:30 0.50 0 0 PROD1 CASING PULD P Clean and clear rig floor. 08:30 09:00 0.50 0 0 PROD1 CASING SVRG P Service top drive. 09:00 10:00 1.00 0 0 PROD1 CASING RURD P PJSM, P/U cement head and make up pup joints/XO's. 10:00 11:30 1.50 0 0 PROD1 CASING RURD P PJSM, P/U and R/U 5-1/2"liner running equipment. 11:30 16:00 4.50 0 0 PROD1 CASING OTHR T Wait for DTH to mobilize centralizers to rig. 16:00 16:30 0.50 0 0 PROD1 CASING PULD P P/U tools from slide and pull wear bushing. 16:30 18:45 2.25 0 955 PROD1 CASING RNCS P PJSM, RIH with 5-1/2" 17#P-100 DWC-C liner as per detail. Installed 23 centralizers. Check floats after making up shoe track. 18:45 19:15 0.50 955 955 PROD1 CASING PULD P P/U ZXP liner top packer and fill tie-back sleeve with Pal Mix. 19:15 19:30 0.25 955 955 PROD1 CASING CIRC P Establish circulation on 1st stand of drill pipe, pump @ 3 BPM= 150 PSI. P/U=47K, SIO=48K. 19:30 00:00 4.50 955 6,262 PROD1 CASING RUNL P RIH w/5-1/2"liner on 4"drill pipe f/ 955 to 6262', filling pipe every 10 stands. P/U= 125K, SIO=80K. Actual displacement=32.73 bbls, Calculated displacement=35.35 bbls. 11/22/2013 CBU, RIH w/5-1/2"liner to 7978'. Circ and cond. mud for cement job, circ until hole stopped packing off. Cement liner as per program, unable to release off liner, attempt to POOH w/liner. Liner released w/TOL @ 6977'. CBU and POOH to run CBL on E-line. Page 21 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 00:15 0.25 6,262 7,209 PROD1 CASING RUNL P PJSM, RIH w/5-1/2"liner on 4"drill pipe to 7209'. 00:15 01:00 0.75 7,209 7,209 PROD1 CASING CIRC P Establish parameters @ casing shoe and circulate a pipe volume. Pump @ 2 BPM=330 PSI, stage pumps up to 3 BPM=380 PSI, 32%flow, P/U= 140K, S/O=90K, ROT= 12K, 20 RPM with 5K Tq. 01:00 01:30 0.50 7,209 7,963 PROD1 CASING RUNL P RIH w/5-1/2"liner on 4"drill pipe to 7963'.Actual displacement=42.7 bbls, Calculated displacement= 45.69 bbls. 01:30 02:15 0.75 7,963 7,985 PROD1 CEMEN-RURD P M/U Baker cement head, RIH to 7985',tag bottom. P/U and put liner hanger on depth with shoe @ 7978', 02:15 07:00 4.75 7,985 7,985 PROD1 CEMEN'CIRC P Establish circulation @ 2 BPM=420 PSI, 15%flow, attempt to stage pumps to 5 BPM, hole packing off @ pump rate above 4 BPM.Work liner and attempt to stage pump rate up. Able to pump @ 4.3 BPM=720 PSI without packing off. 07:00 07:30 0.50 7,985 7,985 PROD1 CEMEN-SFTY P Hold PJSM with SLB cementing crew on cementing 5-1/2"liner. 07:30 08:30 1.00 7,985 7,985 PROD1 CEMEN'CMNT P Batch up 47 bbls of 11.5 ppg MudPush II as per SLB. 08:30 10:00 1.50 7,985 7,985 PROD1 CEMEN-CMNT P Pump 5 bbls of 11.5 ppg MudPush II, shut down and test lines to 4300 PSI,good. Pump 42.8 bbls of Mud Push II followed by 27.5 bbls of 15_.8 ppg class G tail slurry. Shut down and launch dart with i0 bbls of H2O, chase with rig pumps @ 4 BPM=500 PSI.Observed latch up @ 619 stks. As mud push turned the corner pressure began to climb. Pump pressure was at 2200 PSI when plug bumped @ 817 stks. Pressure up to 2700 PSI for 5 minutes(500 PSI over FCP)Pressure up to 4000 PSI to set liner hanger,set down 40K to ensure liner hanger set, bleed of pressure and test floats. 10:00 12:00 2.00 7,985 7,963 PROD1 CEMEN-PACK P Pick up 7'to attempt to release, P/U to 165K and S/O to 45K twice, unable to release. Lay down cement head and make up top drive.Attempt to emergency release by turning to the left and work torque down, no success.Turn 7 times to the right and work torque down, pull 225K several times, unable to release. Decision made to POOH w/liner. Page 22 of 29 Time Logs Date From To Dur S. Death E. Depth Phase Code Subcode T Comment 12:00 13:00 1.00 7,963 7,931 PROD1 CEMEN'PACK T PJSM,Attempt to POOH w/5-1/2" liner, P/U=275K, 115K overpull. Drag liner up hole to 7931', liner top @ 6977.48'and up weight suddenly dropped to 120K. Liner released, pick up above liner top 46'and circulate to clean up cement, pump @ 10 BPM=2150 PSI. 13:00 14:00 1.00 7,931 6,900 PROD1 CEMEN-CIRC T CBU @ 10 BPM=2150 PSI @ bottoms up observed 70 bbls of interface,40 bbls of MudPush II and 10 bbls of cement. 14:00 14:30 0.50 6,900 6,900 PROD1 CEMEN'OWFF T Obtain SPRs @ 6900' MD TVD= 5710, MW= 10.6 ppg @ 14:00 hours. Blow down top drive, OWFF, static. 14:30 17:30 3.00 6,900 120 PROD1 CEMEN-TRIP T PJSM, POOH f/6900'to 120'. OWFF, static. 17:30 18:15 0.75 120 0 PROD1 CEMEN-PULD T L/D Baker running tool as per Baker rep. Dogs on the Dog Sub had debris around them and not all the dog were out. 18:15 18:45 0.50 0 0 PROD1 CEMEN-PULD T Clean and clear rig floor. 18:45 00:00 5.25 0 0 PROD1 CEMEN-OTHR T Wait on HES E-line to run CBL. Service rig and work on MP2s. Clean rig and cement valves. 11/23/2013 Run CBL on HES E-line, R/D HES E-line. M/U Baker Dog Sub and RIH, Set ZXP, Liner top now @ 6992.47' MD. CBU and test casing to 3000 PSI. POOH and L/D BHA. M/U Scraper BHA and RIH. 00:00 02:45 2.75 0 0 PROD1 CEMEN-RURD T Spot HES E-line truck, load lubricator in pipe shed and prep _E-line tools. 02:45 03:45 1.00 0 0 PROD1 CEMEN-RURD T PJSM, Rig up HES E-line and M/U CBL tools. 03:45 07:30 3.75 0 0 PROD1 CEMEN'ELOG T Run CBL on HES E-line, log 5-1/2" liner cement job. CBL showed good zonal isolation between A and C sands. 07:30 08:30 1.00 0 0 PROD1 CEMEN RURD T PJSM, R/D HES E-line, L/D tools and rig down Dutch Riser. 08:30 09:15 0.75 0 0 PROD1 CEMEN'RURD T Un-load HES E-line tools from pipe shed into E-line truck. 09:15 10:15 1.00 0 0 PROD1 CEMEN'PULD T Load 4"HWDP into shed, strap and tally HWDP. Set mouse hole on rig floor. 10:15 12:00 1.75 0 0 PROD1 CEMEN-PULD T RIH picking up 15 joints of HWDP, POOH and stand HWDP back in _derrick. 12:00 12:30 0.50 0 0 PROD1 CEMEN'OTHR T PJSM, Set wear bushing 6-3/4"ID X _ 10-1/4"OD. 12:30 15:45 3.25 0 6,914 PROD1 CEMEN-TRIP T M/U Baker Dog Sub and RIH to 6914',to set liner top packer.Actual displacement=43.4 bbls, Calculated displacement=43.8 bbls. Page 23 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 15:45 16:00 0.25 6,914 6,999 PROD1 CEMEN-PACK T Slack off f/6914'to 6999'. P/U= 140K, S/O=90K. Set down 30K, observed dog sub shear. Set down additional 15K, P/U 8"and slack off 50K. Pick up 5'and rotate @ 20 RPM, 115K, 6K Tq. Set down 60K, P/U and set down 70K. New calculated liner top @ 6992.47'. 16:00 16:45 0.75 6,999 6,900 PROD1 WELLPF CIRC P CBU @ 8 BPM= 1200 PSI. 16:45 17:15 0.50 6,900 6,900 PROD1 WELLPF RURD P PJSM, Blow down top drive and R/U to test 5-1/2"liner. 17:15 17:45 0.50 6,900 6,900 PROD1 WELLPF PRTS P Test 5-1/2"liner to 3000 PSI for 30 minutes,good. 17:45 18:15 0.50 6,900 6,900 PROD1 WELLPF RURD P R/D testing equipment and obtain SPRs @ 6900',TVD=5710', 10.4 ppg MW, 18:00 hours. OWFF, static. 18:15 21:00 2.75 6,900 477 PROD1 WELLPF TRIP P PJSM, POOH f/6900'to 477'.Actual displacement=45.8 bbls, Calculated displacement=42.8 bbls. 21:00 21:45 0.75 477 0 PROD1 WELLPF PULD P Stand back HWDP and L/D Baker tools. 21:45 23:00 1.25 0 0 PROD1 WELLPF PULD P PJSM, P/U Baker tools for slide and R/U handling tools. 23:00 00:00 1.00 0 0 PROD1 WELLPF PULD P PJSM, Make up scraper BHA as per Baker rep. 11/24/2013 RIH w/7-5/8"and 5-1/2"casing scrapers to 7750'. CBU and test liner/packer to 3000 PSI for 30 minutes. Displace well to 10.6 ppg brine and POOH, L/D BHA. R/U and test BOPE to 250 PSI low 3500 PSI high. Witness of test waived by AOGCC rep Jeff Jones. 00:00 02:45 2.75 0 1,223 PROD1 WELLPF PULD P Cont to M/U BHA and P/U 3-1/2" PH6 string to 1223'. 02:45 05:00 2.25 1,223 7,740 PROD1 WELLPF TRIP P RIH to 7460',work 5-1/2"casing scraper f/7460'to 7490', Baker FA packer setting depth. RIH to 7635', 7-5/8"casing scraper @ 6877',work scraper at Baker Premier packer setting depth. Cont RIH and No-Go on liner top with 7-5/8"scraper @ 7750'bit depth.TOL @ 6992'. P/U 155K, S/0=92K.Actual displacement=47.1 bbls, Calculated displacement=47.8 bbls. 05:00 05:30 0.50 7,740 7,740 PROD1 WELLPF CIRC P CBU @ 7.5 BPM= 1800 PSI. 05:30 06:00 0.50 7,740 7,720 PROD1 WELLPF RURD P L/D single and blow down top drive, rig up to test casing. 06:00 07:00 1.00 7,720 7,720 PROD1 WELLPF PRTS P Test 5-1/2"liner and liner top packer to 3000 PSI for 30 minutes on chart, good. R/D testing equipment and P/U single. 07:00 07:30 0.50 7,720 7,740 PROD1 WELLPF SFTY P Hold PJSM on displacing well to 10.6 ppg brine with MI Swaco,truck drivers and rig crews. Page 24 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:30 08:30 1.00 7,740 7,740 PROD1 WELLPF DISP P Displace well, pump 47 bbls of 10.3 ppg spacer and had to shut down. Observed a sheen in pit#6, 1/2 bbl on drilling mud had leaked into pit#6 (filter brine) 08:30 10:15 1.75 7,740 7,740 PROD1 WELLPF COND T Gel up leak in trough to keep mud from leaking in pit#6. Skim the top of pit#6 to remove the drilling mud from the brine. Removed all traces of mud from the brine. 10:15 14:00 3.75 7,740 7,740 PROD1 WELLPF DISP P Cont displacing well to filtered brine, pumped 35 bbls of High Vis weighted sweep,290 bbls of hot water, 65 bbls of SAFE-SURF/Causitc pill, 35 bbls High Vis spacer followed by 310 bbls of filtered 10.6 ppg 15 NTUs brine. Shut down and cleaned under shakers. OWFF, static. 14:00 16:15 2.25 7,740 1,200 PROD1 WELLPF TRIP P PJSM, POOH to HWDP @ 1200', good hole fill 16:15 16:30 0.25 1,200 1,200 PROD1 WELLPF OWFF P OWFF, static. 16:30 17:15 0.75 1,200 757 PROD1 WELLPF PULD P L/D HWDP in pipe shed. 17:15 18:15 1.00 757 757 PROD1 WELLPF RURD P PJSM, Rig up to L/D 3-1/2" PH6 tbg. 18:15 19:00 0.75 757 0 PROD1 WELLPF PULD P L/D 3-1/2"PH6 tbg in pipe shed. 19:00 20:15 1.25 0 0 PROD1 WELLPF PULD P L/D BHA as per Baker rep. L/D Baker tools and clear floor. 20:15 20:45 0.50 0 0 COMPZ WHDBO SEQP P Pull wear bushing and set test plug. 20:45 21:15 0.50 0 0 COMPZ WHDBO RURD P Rig up to test BOPE. 21:15 00:00 2.75 0 0 COMPZ WHDBO BOPE P PJSM,Test BOPE with 4"test joint to 250/3500 PSI for 5 minutes each on chart. Test#1:Top pipe rams, CV 1,12,13,14 and manual kill. Test #2: Upper IBOP, HCR kill, CV 9,11 and 13. Test#3: Lower IBOP, CV 5,8 and 10. Test#4: Dart valve, CV 5,6 and 7. Test#5: Floor valve and CV 2. Test#6: HCR choke and 4" kill line Demco. Witness of BOPE test waived to AOGCC inspector Jeff Jones. 11/25/2013 Cont.testing BOPE to 250/3500 PSI,AOGCC rep Jeff Jones waived witness, R/U E-line and perf A sand 7550'-7490')and C sand(7408'-7368')M/U 5-1/2"casing scraper and junk mill and RIH. Page 25 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 03:15 3.25 0 0 COMPZ WHDBO BOPE P PJSM, Cont to test BOPE to 250 PSI low/3500 PSI high for 5 minutes each.Test#7: Manual choke and HCR kill. Test#8:Annular preventer. Test#9: Lower pipe rams 2-7/8"X 5 VBR. Test#10: Blind rams and CV 3. Test#11: Top pipe rams w/3-1/2" test joint. Test#12: Lower pipe rams with 3-1/2"test joint. Test#13: Annular preventer with 3-1/2"test joint. Accumulator test: System pressure=3000 PSI, pressure after closing= 1750 PSI, 200 PSI attained after 50 sec., Full pressure attained after 202 sec. Nitrogen 5 bottle avg.=2025 PSI.Tested pit level alarms. AOGCC rep Jeff Jones waived witness. 03:15 03:45 0.50 0 0 COMPZ WHDBO RURD P R/D testing equipment, blow down choke and kill lines, set wear bushing. 03:45 04:00 0.25 0 0 COMPZ PERF RURD P R/U Dutch riser and circ lines. 04:00 07:15 3.25 0 0 COMPZ PERF RURD P Rig up HES E-line,full lubricator. M/U guns for run#1. 07:15 07:30 0.25 0 0 COMPZ PERF PRTS P Test lubricator to 1500 PSI, good. 07:30 19:30 12.00 0 0 COMPZ PERF PERF P PerfA and C sands on E-line. PerfA sand with 3-1/8"Millennium 21 gr. guns,6 SPF, Phasing 60°. Perforated from 7550'MD to 7490' MD. Made three E-line runs. Perf C sand with 3-3/8"Millennium 25gr. guns, 6 SPF, Phasing 60°. Perforated from 7408'MD to 7388' MD. Made two E-line runs.A total of five E-line run made. Observed no _ gain or loss in pits while perforating. 19:30 21:15 1.75 0 0 COMPZ PERF RURD P PJSM, R/D E-line and L/D Dutch riser. 21:15 22:00 0.75 0 0 COMPZ WELLPF PULD P PJSM, P/U Baker tools from slide. 22:00 22:30 0.50 0 0 COMPZ WELLPF RURD P R/U to run clean out BHA,junk mill and 5-1/2"casing scraper. 22:30 00:00 1.50 0 720 COMPZ WELLPF PULD P PJSM, P/U Junk mill and 5-1/2" casing scraper and PH6 tbg 720'. Calculated displacement=3.4 bbls, Actual displacement=2.72 bbls. 11/26/2013 Perform cleanout/scraper run. Set FA packer at 7472.3'MD with E-line. R/U and run upper completion per detail. 00:00 02:30 2.50 720 7,566 COMPZ WELLPF TRIP P Continue RIH f/754'MD to 7566'MD, work through perfs 2X 7368'-7408' and 7510'-7550'MD, no problems. Calc Disp=39.4 bbl.Actual Disp=40.1 bbl. 02:30 02:45 0.25 7,566 7,566 COMPZ WELLPF OWFF P Monitor well(Static for 15 minutes) Page 26 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 02:45 03:00 0.25 7,566 7,284 COMPZ WELLPF TRIP P POOH to 7284' MD to circulate. Calc Fill=1.3 bbl,Actual Fill 1.8 bbl. 03:00 04:30 1.50 7,284 7,284 COMPZ WELLPF CIRC P CBU @ 7284'MD,4 bpm 500 psi. Observed some oil and gas breakout at surface, circulate until clean. 04:30 05:30 1.00 7,284 7,284 COMPZ WELLPF OWFF P Monitor well for flow(Static)Take on clean filtered brine from filter van. 05:30 08:30 3.00 7,284 754 COMPZ WELLPF TRIP P POOH to 754' MD, Calc Fill=37.2 bbl,Actual Fill=43.2 bbl. 08:30 08:45 0.25 754 754 COMPZ WELLPF OWFF P Monitor well for flow, (fluid level dropping slightly) 08:45 09:00 0.25 754 754 COMPZ WELLPF RURD P PJSM-R/U DBL stack tongs, CIO elevators, monitor well via TT. 09:00 10:30 1.50 754 0 COMPZ WELLPF PULD P L/D 24 jts 3-1/2"PH6 DP, Junk Mill BHA.Calc Fill=3.3 bbl,Actual Fill=4 bbl. 10:30 11:00 0.50 0 0 COMPZ WELLPF RURD P Clean and clear rig floor, Rig up Dutch riser for E-Line ops. 11:00 12:00 1.00 0 0 COMPZ WELLPF RURD P PJSM-R/U E-Line w/lubricator. Loss rate @ 2 bph. 12:00 14:30 2.50 0 32 COMPZ WELLPF RURD P PJSM-Continue R/U Wireline,ARM tool, P/U Baker FA Packer 14:30 15:45 1.25 32 7,472 COMPZ WELLPF TRIP P RIH w/packer to 7472.3'MD and set packer. 15:45 16:30 0.75 7,472 0 COMPZ WELLPF TRIP P POOH with E-Line from 7472'MD. 16:30 18:00 1.50 0 0 COMPZ WELLPF RURD P R/D Wireline 18:00 18:15 0.25 0 0 COMPZ WELLPF PULD P L/D Dutch Riser 18:15 18:45 0.50 0 0 COMPZ WELLPF RURD P Pull wear bushing 18:45 23:00 4.25 0 1,031 COMPZ RPCOM RCST P PJSM-Run 3-1/2"liner Anchor latch assy, sliding sleeve, 1 jt 3-1/2"563, 50'Blast rings on 2 jts 563, 15 jts 3-1/2"9.2#P-110 563, Baker premier Packer,2.812"X nipple, 1 jt 9.3# L-80, 1-3-1/2"x 1-1/2"MMG GLM w/Dummy, 11 jts 9.3#L-80. Calc Disp=2.2 bbl,Actual Disp=1.5 bbl. 11/27/2013 Run completion, latch anchor, set packer,shear out PBR. Spot inhibitor, space out and land completion. N/D BOPE and N/U tree. 00:00 07:30 7.50 1,031 7,472 COMPZ RPCOM RCST P PJSM-Continue RIH with 3-1/2"GL completion per detail. RIH to 7472' MD,tag packer. 07:30 08:45 1.25 7,472 6,860 COMPZ RPCOM PACK P R/U circulating equipment,set down 25k twice and P/U 10k over to verify anchor seal assy latched. Slack off to 65k, pressure up to 2000 psi, stage up to 2500 psi hold for 5 min, pressure up to 3000 psi hold for 15 minutes recorded on chart. Bleed pressure to zero, pressure up to 1500 psi, P/U on string and sheared out PBR @ 115k, P/U 20'to circulate. Page 27 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 08:45 09:00 0.25 6,860 6,860 COMPZ RPCOM SFTY P PJSM on pumping inhibited brine with rig crew, Co Rep and mud engineer. 09:00 10:00 1.00 6,860 6,860 COMPZ RPCOM CRIH P Pump 50 bbl 10.6 ppg inhibited brine, followed by 56 bbl straight brine @ 3 bpm, 100 psi.While chasing at 45 bbl, noticed the bleeder was in the open position. Shut down ops, decision made to re-pump the inhibitor. 10:00 12:00 2.00 6,860 6,860 COMPZ RPCOM CRIH X Mix 50 bbl inhibited brine per Mud Engineer,wait on thawed inhibitor. 12:00 13:30 1.50 6,860 6,860 COMPZ RPCOM HOSO P PJSM,space out, make up hanger and landing joint. 13:30 14:15 0.75 6,860 6,860 COMPZ RPCOM CRIH P Spot 58 bbl 10.6 ppg corrosion inhibited brine, chased with 56 bbl straight 10.6 ppg brine. 14:15 14:45 0.50 6,860 6,860 COMPZ RPCOM RURD P Blow down lines, drain stack and prep hanger. 14:45 15:15 0.50 6,860 6,884 COMPZ RPCOM HOSO P Land Hanger, RILDS. P/U=85k, S/O=66k 15:15 15:30 0.25 6,884 6,884 COMPZ RPCOM SFTY P PJSM-Pressure testing tubing and IA. 15:30 17:30 2.00 6,884 6,884 COMPZ RPCOM PRTS P Test tubing to 4000 psi on chart 30 minutes. Bleed off presure to 2000 psi,shut in tubing. Pressure up IA to 3500 psi charted 30 minutes. 17:30 18:00 0.50 6,884 0 COMPZ RPCOM RURD P Bleed off, RID landing jt, B/D lines and hole fill. Drain stack. 18:00 19:00 1.00 0 0 COMPZ WHDBO RURD P PJSM,pull riser, mouse hole, install boot protector, N/D BOP stack. 19:00 20:00 1.00 0 0 COMPZ WHDBO NUND P Nipple up tree adapter flange 20:00 20:45 0.75 0 0 COMPZ WHDBO NUND P Nipple up tree 20:45 21:30 0.75 0 0 COMPZ WHDBO PRTS P Test tree adapter void to 250/5000 psi for 10 minutes each witness by Co Rep. SIMOPS clean out drain pan. 21:30 22:30 1.00 0 0 COMPZ WHDBO RURD P R/U scaffolding in cellar. 22:30 23:00 0.50 0 0 COMPZ WHDBO RURD P PJSM-R/U to test tree. 11/28/2013 N/U Tree and test, FP with 96 bbl LEPD. UD 4"DP and RDMO. Rig released @ 14:00. 00:00 00:45 0.75 0 0 COMPZ WHDBO PRTS PJSM-Continue R/U and test tree 250/5000 5 min each. 00:45 01:45 1.00 0 0 COMPZ WHDBO RURD R/D test equipment, R/U lubricator and test to 2000 psi. Pull TWC. 01:45 02:30 0.75 0 0 COMPZ WHDBO RURD PJSM-R/U Circ lines. 02:30 02:45 0.25 0 0 COMPZ WHDBO SFTY PJSM-Rig crew and Little Red Svcs, freeze protect well. 02:45 03:45 1.00 0 0 COMPZ WHDBO PRTS PT Lines to 2500 psi, pump 96 bbl diesel down annulus,taking returns up tubing via SOV. ICP 450 psi @ 1.5 bpm, FCP 800 psi @ 1.5 bpm. SIP 400 psi. 03:45 04:00 0.25 0 0 COMPZ WHDBO RURD Blow down circ lines, R/D LRS R/U to U-Tube. Page 28 of 29 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:00 06:00 2.00 0 0 COMPZ WHDBO SLPC PJSM, Cut and slip 65'of drilling line, service top drive, R/U mouse hole. 06:00 07:30 1.50 0 0 COMPZ WHDBO MPSP R/U Lubricator, set BPV, secure well, R/D scaffolding. 07:30 13:30 6.00 0 0 DEMOB MOVE PULD PJSM and lay down 4"pipe via mouse hole. 13:30 14:00 0.50 0 0 DEMOB MOVE DMOB Rig released @ 14:00 hrs. 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Q O N tm0f0 Y3 r {� O N ti 2 N NN N t0Ei to m N N m n m Q V l 1 1 m G' m❑O' ❑❑ C 2 Q ` mne ;17.888 bNv QS $ ro $ wwoFEnuu� o ° as K E em mal nmvnA n on n N Z o0 ,-Z o• g to M n I:F O m o y- m .,_-°3 m J _I- 1,1_, N ,E O C tnp N2 O �N Tnr'r nto t - - Lt. pLL C Np70 N 444 4< Fs; N ka N O m m p J m Z n N N K LL LL p m i? U gc$.'--mm 224?-22 v'-, o C. n242L-, Egz.p2 p, m cdo 0] m o a S c N rn '� Ec p E CgitEF N EC o 2 2 m C . . a a, (7,e) ."5' o 2:5103 WELL LOG TRANSMITTAL DATA LOGGED A.G/2013 M K BENDER To: Alaska Oil and Gas Conservation Comm. November 25, 2013 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 RECEIVED Anchorage, Alaska 99501 DEC 132013 RE: Radial Cement Bond Log: 2T-41 Run Date: 11/23/2013 AOGCC The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Matthew Cook, Halliburton Wireline&Perforating, 6900 Arctic Blvd., Anchorage,AK 99518 matthew.cook@halliburton.com 2T-41 Data in LAS format, Digital Log Image files 1 CD Rom 50-103-20675-00 Cement Bond Log 1 Color Log 50-103-20675-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline &Perforating Attn: Matthew Cook 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3572 Fax: 907-273-3535 matthew.cook@halliburton.com Date: VZ`‘ t3 Signed: 2v 3-kg& WELL LOG TRANSMITTAL DATA LOGGED M16/2013 M K BENDER To: Alaska Oil and Gas Conservation Comm. December 2, 2013 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED DEC 13 2013 RE: Perforation Record/Packer Setting Record: 2T-41 AOGCC Run Date: 11/23/2013 - 11/26/13 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Matthew Cook, Halliburton Wireline&Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 matthew.cook@halliburton.com 2T-41 Digital Data in LAS format, Digital Log Image file 1 CD Rom 50-103-20675-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline& Perforating Attn: Matthew Cook 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3572 Fax: 907-273-3535 matthew.cook@halliburton.com Date: vL1«(t'70 Signed: )1 b_e_e_KA)e wry\ %%i- s. THE STATE Alaska Oil and Gas °ALASKA ( ..,,Gnservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue ALAW' Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Robert Blakney ( / Completion Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk Oil Pool, 2T-41 Sundry Number: 313-613 Dear Mr. Blakney: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair, Commissioner DATED this4—p d of November, 2013. Encl. ` STATE OF ALASKARECEIVED . AL A OIL AND GAS CONSERVATION COMM- JN APPLICATION FOR SUNDRY APPROVALS NOV 21 201 20 AAC 25.280 1.Type of Request: Abandon r Rug for Redrill r Ferforate New Pool r Repair w ell r Change Ap Suspend r Rug Perforations r Perforate r Pull Tubing r o Operational Shutdown r Re-enter Susp.Well r Stimulate r- Alter casing r Other: r 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Exploratory r- Development F• 213-146-0 , 3.Address: Stratigraphic r Service r 6.API Number: P.O. Box 100360,Anchorage,Alaska 99510 50-103-20675-00 7.If perforating, 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require spacing exception? Yes r No F 2T-41 . 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 25569 . Kuparuk River Field/Kuparuk River Oil Pool . 11. PRESENT WELL CONDITION SUMMARY Total depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 7234 5694 none none Casing Length Size MD TVD Burst Collapse Conductor 106' 16" 106' 106' Surface 3209' 10.75" 3209' 2600' Intermediate 7222' 7.625" 7222' 5678' Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): none none none none none Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft) no packer no SSSV 12.Attachments: Description Surmiary of Proposal , p 13. Well Class after proposed work: Detailed Operations Program r BOP Sketch r Exploratory r Stratigraphic r Development r. Service r 14.Estimated Date for Commencing Operations: 15. Well Status after proposed work: 12/1/2013 Oil r • Gas r WDSPL r Suspended r 16.Verbal Approval: Date: WINJ r GINJ r WAG r Abandoned r Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Robert Blakney @ 265-6417 Email: Robert.G.Blaknev@conocoohillips.com Printed Name Robert Blakne Title: Completion Engineer {{ J Signature i Phone:265-6417 Date t I /ZO //3 Commission Use Only Sundry Number: Conditions of approval: Notify Commission so that a representative may witness - V3--4k Plug Integrity r BOP Test r Mechanical Integrity Test r Location Clearance r Other: Spacing Exception Required? Yes ❑ No Subsequent Form Required: I 0-1. 0 + APPROVED BY ' / / Approved by: COMMISSIONER THE COMMISSION Date: /f' (� —f pproved application Is valid tor 12 months trom the ate of approval. Form 10- rtyis d \,� �?�ORIGINAL '1� I� /3 Submit Form and Attach nts in Duplicate RSM � � 1 � ' J ,kor,,�,\� Ci))W I I/.1Y//'3 . r/0/f 2T-41 Sundry Application 2T-41 was spudded on November 4th. The well will be completed with a 5.5" liner across the A and C sands and a 3.5" selective completion isolating the C sand. We are going to stimulate the A sand down the 3.5" tubing with the selective closed. We expect the production to be 400 bpd in 2013 if a successful stimulation is achieved. A planned schematic is attached. Proposed Procedure: Schlumberger Pumping Services: (Kuparuk A sand Frac) 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre existing conditions. 2. Ensure all Pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to 2,000' TVD. 3. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 4. MIRU 4 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 100° F seawater(approx. 1,300 bbls are required for the treatment with breakdown, maximum pad, and 450 bbls usable volume per tank). 5. Ensure lift plan is reviewed and signed prior to RU of Frac equipment requiring lifts. 6. MIRU Stinger Tree Saver Equipment and SLB Frac Equipment. 7. PT Surface lines to 5,000 psi using a Pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Pump the Frac job by following schedule @ 20 bpm with a maximum expected treating pressure of 4,000 psi. Stage 1 • 450 bbls Schlumberger fluid Pad • 105 bbls Schlumberger fluid w/ 1 ppa • 110 bbls Schlumberger fluid w/3 ppa • 115 bbls Schlumberger fluid w/5 ppa • 122 bbls Schlumberger fluid w/7 ppa • 165 bbls Schlumberger fluid w/9 ppa • 139 bbls Schlumberger fluid w/ 10 ppa • Flush with 57 bbls of linear fluid and freeze protect • Total Sand: Approx. 200,000 lbs of 16/20 CarboLite 10. Monitor the surface pressure fall-off at the end of the job for 30 minutes, if the well does not screen out. 11. RDMO SLB Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. Well is ready for Post Frac well prep for flowback (Slickline and possibly CTU). 13. Flowback will be initiated through Expro until the fluids clean up at which time it will be turned over to production. (Initial flowback fluids to be taken to appropriate disposal well until they are clean enough for production.) RB Cement Evaluation of 2T-41 and wells within 1/4 mile of 2T-41 2T-41: 7 5/8 Casing two stage cement job using was pumped on 11/17/2013 as designed, indicating competent cement operations. The first stage was 15.8 ppg cement, displaced by 10.4 LSND mud. The plug was bumped and the float held. The 2nd stage was 16.0 lead cement followed by 15.8 tail cement; it was displaced by 10.4 ppg mud. The plug was bumped and we pressured up to close the ES cementer. 2T-14: 5" Liner cement job was pumped on 5/4/1986 as designed, indicating competent cement operations. The cement pumped was 16.1 ppg Class G cement. The plug was bumped as calculated, and the floats held. 2T-16: 5" Liner cement job was pumped on 4/09/1986 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced by seawater, floats were checked and they held. 2T-18: 7" Casing was pumped on 3/4/1995 as designed, indicating competent cement operations. The floats were check and they held. Full returns were observed during the job. 2T-12A: 5" Liner cement job was pumped on 9/28/1986 as designed, indicating competent cement operations. The cement pumped was 15.9 ppg Class G cement. 2T-37: 7" Casing cement job was pumped on 8/12/1995 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced with seawater. The plug was bumped @ 1,930 psi, floats held. 2T-10: 7" Casing cement job was pumped on 6/6/1986 as designed, indicating competent cement operations. The cement pumped was 15.8 ppg Class G cement, displaced by 12.2 ppg NaBr brine. The plug was bumped and returns were observed during the job. 2T-19: 7" Casing cement job was pumped on 3/15/1995 as designed, indicating competent cement operations. Pipe was reciprocated during the job and full returns were observed during the job. Summary Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. It has also been determined that the frac will not adversely affect wells within a %4 mile radius or any other nearby well. RB Stimulation Surface Rig-Up (:) Bleed 1 Tates Tale Tank 004 004 004 t':, • Minimum pressure rating on all surface treating lines 10,000 psi • Main treating line PRV is set to 95%of max -t)814011 004D8t1 treating pressure • IA parallel PRV set to 3500 psi • Frac pump trip pressure setting are staggered and m DErtai set below main treating line PRV • Tree saver used on all fracs rated for 15,000 psi. Ma z Kauidwnd Pop-Oa Tank Pop-Off Tank Dal Pump Truck Frac Pump -ff--D81-.. Frac Pump Frac Pump N � — 1 —CeIC— Frac Pump Frac Pump — — --1{- Frac Pump RB 4 Stimulation Tree Saver OPEN POSITION CLOSED POSITION (PRIOR TO MANDREL INSERTION) )MANDREL INSERTED) RAC RON CTION . . i �i • • •;,/cFoN,..E • • _ • • T•••• ,,REMOTE OPERATED .wnwaw. MASTER VALVE "• rOr MANUAL OPERATED '6Oi errs 60oh I (s� l 4...,1,36, \?,,,,,w, . . Ammia, .. Stinger I 1 I MANDREL I VENT t, '`._0 I.f--VALVE — _ `4 \y1:;111* y OPEN \ TX 111Ly..,, i I•.`/(111 ,. FLOW TEE AND ,I i i e' 4(' VENT VALVE 1VEt11#AD ::= i+)I •.;1Nt VALVES „ ✓✓✓fi. OPEN T, ;, n _: WELLHEAD r VALVES ,i...1 ?{yy % • r. CLOSED -' . !' ``(.0 z 4 .;.t a OUAD PACKOFF ,, ' ` ASSEMBLY IN lG. , k PLACE IN TUBING i' �1 s TUBING 7z q s, ,' • The universal tool is rated for 15,000 psi and has 84" of stroke. • Tool ID 2.25" down 4 %2 tubing and 1.75" down 3 %2 tubing. • Max rate with 2.25"mandrel is 60 bpm and with 1.75"mandrel 36 bpm RB 2T-41 ConocoPhillips Grass Roots Conventional Topset Slant Proposed Wellbore Schematic C Updated blakney Oct 22,2013 Hunter Oct 25,2013 Top 100'of tubing are 4.5"L-80 Per WP11 for wellhead New Insulated Conductor: Fresh Water 16" 164.8#H-40 Spud Mud Permafrost 3-W Nipple DB Profile(2.875")@ 400'MD. 9.6 PPG Fresh Water 13-%" Surface Hole Spud Mud 9.8-10 PPGII II 10-3/4"HES Backup Cementer @ 1000'MD. Surface Casino: : 10-3/4"45.5#L-80 Hydril 563 Gam°3%'x1-%"MMG 3,340'MD/2,670'TVD @ 55° Top West Sak Base West Sak• `'`' : : 590 ME3�2,194 TVD ' .,..„-",.."•1!JiiM4�f 4 Set Surface 484'TVD below 1 op West Sak TaS o 40 4iND 3,Q4::9::�. .6:a TOC1S:8 pp• 500.MO ti h3tfhiah TafiaSCO C83€',i . . : .:.:..:..g...:.::.....: .:,.:;...,...., .:.::.ii:;. :.:.:.:.:...::...:.:.:.:.:.:.:.:*•:: Camco 3'h'x1-'h'MMG 0 0 0 7-5/8"HES Cementer @—4,525'MD. LSND , Tubing: 9.8 PPG 3-W 9.3#L-80 EUE8RD—6,978'to surface Keep up with Camco 3 F"x 1-/ MMG 111 3-1/2"9.2#P-110 Hydril 563 7420'to 6,978'MD Dilution 9-7/8" Intermediate Hole Camco 3'w x 1-X'MMG TOC 15.8 ppg @+/-6,278'MD 3 W X Nipple 2.81" 1=1 4"Seal Assembly with No Go 20 ft Stroke --- _ 7-5/8"x 3-W Premier Packer with PBR @6,978'MD Shear to 40K Lbs 7-5/8"x 5-%"ZXP,RS,Flexlock Hanger @7,078'MD ..... intermediate Casing: ". 7-5/8"29.7#L-80 Hydril 563 7,278'MD/5,738'TVD@40° G 1 :.:. .:. .:. • 8i0 .:.: :.:.:.: :.:.:.:.:.:.:............................ .. ...... ...... .. ... 1 . CMU sliding sleeve, 2.813"X nipple profile 3.5" Tubing Anchor LSND Made upto Anchor 5-1/2"x 3-1/2"FA Packer at 7,400'MD 10.6 PPG Btm C to Top A 62' MD,47' TVD t t 2.725"D nipple 6-3/4" Production Hole SOS @ 7,415'MD i .iiii°: iii'€ € `'''€ € �''.:.:`T'�`i'�``' ''`''''``'''''` '''1:iii1i1`•1'• '' ;'' 45s l ...1 .: .. .: ill /5$5 ::7kID ....... . .. ii Cemented Production Liner: 5-1/2" 17#P-110 DWC 7,727' MD/6,081'TVD @ 40° c 0 co-..-_-, EsiE ....-z, ,_ u) 'I- -0 1 c co N w a ... 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ED. 46 a) a- c5 tLI: = a p 2 L- ai i LTs13 0 Z ' 0 O 1- }, LL LL G> >+ a) — Q (6 Lm a. N ca ca _ L. CD L (� N cn L O > E E = cn -E — — — 1Eocncna) oo Vi ._ I . v _ X N D N N cn NO U O E 45 .Q T E NUI U a0 � cn N O _0 ID • 4— N 41- �� /O� \� �-' /�� �•_ a c-, M, ten- N 0 y N Q / (6 y o Of]•. M ' ILI- 12 ea N N — Q fn (n o o yl 1 ti o g, g <i UI g QI O1 _ < < .G� m R rn o CT' ',, m M M o O a = V .-. C ,c y, .a '.� .':i N O O lb 1474 � V — �C D y� ld.. d N N N W N N a V E A L (% F ZQ E • II IIII43 15 fJ N - _ ,...>" 1,i, _ p ,- i .401,1, ___, 1 Vlitllh14H '11\ iN ,. J • a m Oo --' N tD m I -, m I I- I t t— N t— I— N N CI m ED \V N N I— ,,,, li , ''''' gri IF 2 - - .... ...- a) 73 CI. - -'1.°11111111111......----1-71 \\.,..\\,,. erI I— I N i \\V I— I — N 'llir ' /7 ,-,,,\ \ \k's, \ N NI m1121, I- /- N 111rNI N N s N I— { N N I-- 03 I I ,v, N I-- i O � To, THE STATE Alaska Oil and Gas w � ✓ .�'y,� m of LAs� Conservation Commission wet GOVERNOR SEAN PARNELL 333 West Seventh Avenue OA, Anchorage,Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 li Ely Jolley Supervising Drilling Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk Oil Pool, 2T-41 ConocoPhillips Alaska, Inc. Permit No: 213-146 Surface Location: 5182' FNL, 4722' FEL, Sec. 1, T11N, R8E, UM Bottomhole Location: 996' FNL, 1973' FEL, Sec. 11, R8E, UM Dear Mr. Jolley: Enclosed is the approved application for permit to redrill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, P)Mt411— Cathy P Foerster Chair, Commissioner DATED this l day of November, 2013. ►1'5 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION OCT 3 1 2013 PERMIT TO DRILL ��G�� 20 AAC 25.005 1a.Type of Work: 1 b.Proposed Well Class: Development-Oil a, Service-Winj El Single Zone ❑ 1c.Specify if well is proposed for: Drill o, Lateral ❑ Stratigraphic Test❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone a Coalbed Gas ❑ Gas Hydrates El Redrill El Reentry E Exploratory ❑ Service-WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: ,,u Blanket a Single Well 11.Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180. 2T-41. 3.Address: 6.Proposed Depth: 12. Field/Pool(s): P.O. Box 100360 Anchorage,AK 99510-0360 MD:7727' . TVD: 6082' = Kuparuk River Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface:5182'FNL,4722'FEL,Sec. 1,T11N, R8E, UM . ADL 25569• Kuparuk River Oil Pool . Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1243'FNL, 1745'FEL,Sec. 11,T11N, R8E, UM 2667 10/26/2013 Total Depth: 9.Acres in Property: 14.Distance to 996'FNL, 1973'FEL,Sec. 11,T11N,R8E,UM. 2560 Nearest Property: >1 mile 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: .109.7 feet 15.Distance to Nearest Well Open Surface:x- 498946.5 y- 5970077 Zone- 4 . GL Elevation above MSL: , 81.7 feet to Same Pool: 2T-10,55' 16.Deviated wells: Kickoff depth: 300 . ft. 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 55° - deg Downhole:3158 psig . Surface:2550 psig • 18.Casing Program: Specifications Top - Setting Depth -Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 16" 16" 164.8# H-40 Welded 107' 37' 37' 134' 134' Driven 13.5" 10.75" 45.5# L-80 Hyd563 3312' 37' 37' 3340' 2670' 1596 sx ALC,194 sx DeepCRETE 9.875" 7.625" 29.7# L-80 Hyd563 7250' 37' 37' 7278' 5738' 285 sx Class G,200 sx Class G 6.75" 5.5" 17# P-110 DWC 649' 7078' 5575' 7727' 6081' 102 sx Class G 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) 1 Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured) Effective Depth MD(ft): Effective Depth TVD(ft): Junk(measured) Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20.Attachments: Property Plat El BOP Sketch❑ Drilling Program a Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Programa 20 AAC 25.050 requirements Q 21.Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Lindsey Hunter @ 265-6427 Email Lindsey.Hunter@conocophillips.com Printed Name E. Jolley Title Supervising Drilling Engineer SignatureglOd14Phone: 265-6120 Date /0/3 03 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter Number: 2,kS-\.L{(A 50- 1p3-aOO7S -00-00 Date: /Q/G//3 for other requirements Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed m thane,gas hydrates,or gas contained in shales: d Other: 5 op tc-5 1- 76 s.UOc ipS / Samples req'd: Yes No Mud log req'd: Yes❑ No 2 H2S measures: Yes No Directional svy req'd: Yes Er No❑ Spacing exception req'd: Yes El No Inclination-only svy req'd: Yes❑ No E �/n '"b 1, pPPR©V D B44 THE �. Approved by: / � �, COMMI4SIp ER ' I y 0m MISSir* Date: // -' !! . ,.w ( . Form 10-401 ( cased 10/2012) This permit is valid for 4 months from the date of approval(20 AAC 25.005(g)) /1/1// ��� vi_r" it /d/d3 ConocoPhillips Alaska, Inc. Post Office Box 100360 RECEIk Anchorage, Alaska 99510-0360 ConocoPhillips Telephone 907-276-1215 OCT 3 12013 October 30, 2013 AOGCC Alaska Oil and Gas Conservation Commission (� V 333 West 7th Avenue, Suite 100 Anchorage,Alaska 99501 Re: Application for Permit to Drill 21-41 (Amended, changes highlighted in yellow) Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a permit to drill Well 2T-41 a Kuparuk producer from the 2T drilling pad. This well targets an unswept area due to faulting. The intended spud date for this well is November 1st , 2013 using Doyon Rig 141. With this permit to drill, the Doyon 141 rig will drill a 13 1/2" surface hole to 3,340' MD and case the hole with 10 3/4"45.5#L-80 casing and cement. Then,the rig will drill a 9 7/8" intermediate section to TD at 7,278' MD, and case the hole with 7 5/8"29.7# L-80 casing and cement. Then,the rig will drill a 6 3/4" production hole to TD at 7,727' MD, and case the hole with 5 1/2" 17#P- 110 liner and cement. It is expected that the Tabasco sand will be considered a significant hydrocarbon bearing zone. A stage tool will be run to cement off the Tabasco with 500' of cement above the interval:Lead cement will be pumped, then the stage tool will be opened and a second cement job pumped to isolate the Tabasco. This will leave a mud gap between the two stages. The Kuparuk formations will be top set with 7-5/8" intermediate casing and cemented 1000' MD,the 5-1/2" liner will be cemented 255' above top of the sands. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a). 2. A proposed drilling program 3. A drilling fluids program summary. 4. Proposed completion diagram 5. Pressure information as required by 20 ACC 25.035 (d)(2). 6. Directional drilling/collision avoidance information as required by 20 ACC 25.050 (b). Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Lindsey Hunter at 265-6427. Sincerely,, c � Lindsey Hunter Drilling Engineer Attachments cc: 2T-41 Well File/Sharon Allsup-Drake ATO 1530 Chip Alvord ATO 1566 Liz Jolley ATO 1700 'cation for Permit to Drill,Well 2T-41 Saved:30-Oct-13 2T-41 Application for Permit to Drill Document ConocoPhillips Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) 3 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) 3 Requirements of 20 AAC 25.050(b) 3 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005(c)(3)) 3 4. Drilling Hazards Information (Requirements of 20 AAC 25.005 (c)(4)) 3 ASP CALCULATIONS 4 5. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 (c)(5)) 5 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) 5 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) 5 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) 5 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) 6 10.Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) 6 11.Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) 6 12.Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) 7 13.Proposed Drilling Program (Requirements of 20 AAC 25.005 (c)(13)) 7 14.Discussion of Mud and Cuttings Disposal and Annular Disposal 9 (Requirements of 20 AAC 25.005 (c)(14)) 9 2T-41 APD Page 1 of 11 Printed:30-Oct-13 0 R ! �� ication for Permit to Drill,Well 2T-41 Saved:30-Oct-13 15.Attachments 9 Attachment 1 Directional Plan 9 Attachment 2 Drilling Hazards Summary 9 Attachment 3 Proposed Well Schematic 8 Attachment 4 Cementing Summary .9 2T-41 APD Page 2 of 11 ,., Printed:30-Oct-13 ) �i . cation for Permit to Drill,Well 2T-41 Saved: 30-Oct-13 1. Well Name (Requirements of 20 AAC 25.005(f)) The well for which this application is submitted will be designated as 2T-41. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Well 2T-41 is planned as a grassroots Kuparuk A and C sand selective Producer. Planned operations include: drill a 13 /2" surface hole to 3,340' MD and case the hole with 10 3/4" 45.5#casing and cement. Then, the rig will drill a 9 7/8" intermediate section to TD at 7,278' MD, and case the hole with 7 5/8" 29.7#casing and cement to 1000' above TD. The rig will then drill a 6 3/4" production hole to TD at 7,727' MD, and case the hole with 5 '/2" 15.5# liner and cement to liner top (255' MD above Kuparuk reservoir). A cement bond log will be run to provide evidence of bonding in the 5-1/2" and 7 5/8" casing and cemented intervals. (We don't plan to run a CBL since this is a producer unless the state requires it.) The Kuparuk intervals will be perforated with wireline conveyed perforation guns. The selective completion with 3-1/2" tubing and 3-1/2" x 5 1/2" packer will be located between the Kuparuk A and C sands. Finally, the upper completion of 3-1/2" tubing will be run to surface with a 3 1/2" x 7 5/8" top packer set at 6978' MD. Location at Surface 5182' FNL 4722' FEL Sec 1 T11N R8E NAD 1927 RKB Elevation 109.7' AMSL Northings: 5,970,077 Eastings: 498,946.5 Pad Elevation 81.7'AMSL Location at Total Depth 996' FNL, 1973' FEL, Sec. 11, T11N, RO8E Nad 1927 Measured Depth, RKB: 7,727' Northings: 5,968,984.89 Eastings: 496,417.05 Total Vertical Depth, RKB: 6,081' Total Vertical Depth, SS: 5,978' Requirements of 20 AAC 25.050(b) Please see Attachment 1: Directional Plan The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005(c)(3)) Please reference BOP schematics on file for Doyon 141. 4. Drilling Hazards Information (Requirements of 20 AAC 25.005 (c)(4)) The following presents data used for calculation of anticipated surface pressure (ASP) during drilling of this well: Csg Setting Fracture Pore Casing Size Depth Gradient pressure ASP (in) MD/TVD(ft) (lbs. /gal) (psi) Drilling (psi) 16" 134/ 134 10.9 N/A • N/A 10 3/" 3,340/2,670 12.5 1,202 63 7 5/8" 7,278 / 5,738 13.5 2,584 1,469 5-1/2" 7,727 /6,081 12.5 3,158 2,550 2T-41 APD Page 3 of 11 Printed:30-Oct-13 'cation for Permit to Drill,Well 2T-41 Saved:30-Oct-13 PROCEDURE FOR CALCULATING ANTICPATED SURFACE PRESSURE (ASP) (A)ASP is determined as the lesser of 1)surface pressure at breakdown of the formation casing seat with a gas gradient to the surface, or 2) formation pore pressure at the next casing point less a gas gradient to the surface as follows: 1) ASP = [(FG x 0.052)—0.1]D Where: ASP = Anticipated Surface pressure in psi FG = Fracture gradient at the casing seat in lb/gal 0.052 = Conversion from lb. /gal to psi/ft 0.1 = Gas gradient in psi/ft D = true Vertical depth of casing seat in ft RKB OR 2) ASP = FPP—(0.1 x D) Where; FPP = Formation Pore Pressure at the next casing point ASP CALCULATIONS 1. Drilling below Conductor(16") ASP = [(FG x 0.052) — 0.1] D = [(10.9 x 0.052) —0.1] x 134 = 63 psi OR ASP = FPP — (0.1 x D) =1,202 —(0.1 x 2,670) = 935 psi 2. Drilling below surface casing (10 3/4") ASP = [(FG x 0.052) — 0.1] D = [(12.5 x 0.052) —0.1] x 2,670 = 1,469 psi OR ASP = FPP—(0.1 x D) =2,584— (0.1 x 5,738) = 2,010 psi 3. Drilling below intermediate casing (7 5/8") ASP = [(FG x 0.052)—0.1] D = [(13.5 x 0.052)—0.1] x 5,738= 3,454 psi OR ASP = FPP—(0.1 x D) = 3,158—(0.1 x 6,081) = 2,550 psi (B) Data on potential gas zones; The well bore is not expected to penetrate any gas zones. (C) Data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; 2T-41 APD Page 4 of 11 Printed:30-Oct-13 cation for Permit to Drill,Well 2T-41 Saved: 30-Oct-13 Please see Attachment 2 — Drilling Hazards Summary S. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5)) Drill out from surface casing shoe and perform LOT or FIT in accordance with the Kuparuk LOT/ FIT procedure that ConocoPhillips, Alaska has on file with the Commission. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) Casing and Cementing Program Hole Top Btm Csgfrbg Size Weight Length MD/TVD MD/TVD OD(in) (in) (lb/ft) Grade Conn. (ft) (ft) (ft) Cement Program 16 16 164.8 H-40 Welded 107' Surf 134'/134' Existing: Driven Planned: Cemented to Surface with 10 3/4" 13 1/2" 45.5 L-80 Hyd563 3,312' Surf 3,340'/2,670' 1596 sx 11#ALC lead& 194 sx 12# DeepCRETE tail Planned: 1st Stage Cement Top planned @ 6,278'MD 285 sx 15.8#Class G tail 7 5/8" 9 7/8" 29.7 L-80 Hyd563 7,250' Surf 7,278'/5,738' planned:2nd Stage Cement Planned for 500'above and 300'below the Tabasco sand 200 sx 15.8#Class G Planned:Cement Top planned @ 7,078' MD 5'/z" 6 3/4" 17 P110 DWC 649' 7,078'/5,575' 7,727'/6,081' 102 sx 15.8 ppg Class G 3'/z" 9.3 L-80 EUE8RD 6,978' Surf 6,978'/5,508' Uncemented tubing 3 Y2" 9.3 P110 Hyd563 437' 6,978' 7,72776,081' Uncemented tubing 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) While drilling the surface hole a 21-1/4", 2000 psi annular with a 16"diameter diverter line will be the diverter system used. Please reference diverter schematic on file for Doyon 141. 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Drilling will be done using mud systems having the following properties: 2T-41 APD Page 5 of 11 R16 Printed:30-Oct-13 ication for Permit to Drill,Well 2T-41 Saved:30-Oct-13 Surface Intermediate Production 13 1/2" Hole 9 7/8" Hole 6 3/4" Hole 10 1/2" Casing 7 5/8" Casing 5 1/2" Liner Density 8.6-9.2 9.6-10.5 10.6 PV 10-20 20 30 YP 40-80 24 22 Funnel Viscostiy 60-120 N/A N/A Initial Gels 30-50 N/A N/A 10 minute Gels 30-50 N/A N/A API Filtrate NC <6 <6 HPHT Fluid Loss at 160 N/A N/A N/A PH 10.8 9.5-10 9.5-10 Surface Hole Section: Spud mud will be MI Swaco's Drilplex MMO (mixed metal oxide) fluid system is planned for this interval. Gravel may cause hole cleaning issues, extra circlulation and wiping of the hole may be necessary to clean excess gravel. Hydrates may be encountered in this interval, follow RP for handling gas gydrates, be careful not to thin the mud with lecithin, it isn't compatable in this mud system. Sticky clays may be encountered in the permafrost and below, bit balling is a risk, incorporate nut plug in sweeps to minimize clay to metal sticking if needed. Intermediate Hole Section: Drill below surface shoe with spud mud reserved from surface hole and treat cement contamination as needed. Displace mud to LSND (low solids non-dispersed) system for FIT/LOT. Drill ahead watching for sticky clays, to treat pump high viscosity sweeps. Expect large sloughing solids in the Tabasco interval, extra circulation and hole wiping may be required as seen in previous wells drilling into this formation. Production Hole Section: Drill out casing shoe with LSND mud reserved from the previous hole section, treat cement contamination as needed, treat system with spike fluid and drill forward. Expect differential pressures in the Kuparuk A and C sands, allow for extra circulation time with drill string rotation to catch up on hole cleaning following slides, high ROP or drilling with reduced drill string rotation. Diagram of Doyon 141 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A-Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A-Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A-Application is not for an offshore well. 2T-41 APD Page 6 of 11 r g .. E E ¢; Printed:30-Oct-13 ication for Permit to Drill,Well 2T-41 Saved:30-Oct-13 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of20AAC 25.005(c)(13)) The proposed drilling program is listed below. Please refer to Attachment 3: Well Schematic. Rig Work Plan (New PTD Continuing from P&A Sundry in the Process of Being Submitted) 1. Move in/rig up Doyon Rig 141. Install 21-1/4"Annular with 16"diverter line and function test. 2. Spud and directionally drill 13.5"hole to casing point at+/-3,340' MD/2,670' TVD as per directional plan(wpl l),TD will differ from well plan(WP11)and will be determined as—470'below top of West Sak formation as determined by wellsite geologist. Survey with MWD,Gamma,Resistivity, Gyro and Sonic. / 3. Run and cement 10-3/4",45.5#,L80,Hyd-563 casing to surface. Displace cement with mud. (Due to the HES cementer equipment only one plug can be dropped on the primary cement job.) 4. Perform 2nd stage cement job using the HES cementer located at 1000' MD to ensure good cement job to surface. Evacuate top 2 feet of cement from annulus for sealant job(post rig.) 5. Remove diverter system,install and test 13-5/8"x 5,000 psi BOP's to 3000 psi(annular preventer to 2500 psi). Notify AOGCC 24 hrs before test. 6. PU 9-7/8"Rock bit/Clean out assembly and directional drilling assembly,with MWD/LWD(Gamma, resistivity and sonic)./RIH and clean out 2nd stage cement to 100' above shoe. Test surface casing to 3000 psi for 30 minutes. 7. Drill out shoe track and 20' of new hole. Perform formation integrity test to a minimum of 12.0 ppg, maximum of 16 ppg EMW leak off,recording results. 8. Directionally drill to—4,300'MD/3,235' TVD,through the Tabasco sand package,Wellsite geo will call when we are through the Tabasco,ensuring the whole package is logged with LWD. Circulate hole clean, rotating to ensure good hole cleaning through the Tabasco. 9. POOH. Lay down rock bit. 10. PU 9-7/8"PDC bit and directional drilling assembly,with MWD/LWD(Gamma,resistivity and sonic). / 11. Directionally drill to 7-5/8"casing point at 7,278'MD/5,738' TVD. 12. Pull out of hole with directional assembly rotating from 4,000' MD to surface casing shoe to get ultrasonic caliper data(real time)through Tabasco formation for 2nd stage cement volume calculations. 13. Laydown BHA and 5"DP. 14. Run 7-5/8",29.7#L80,Hydril 563 casing from TD to surface. 15. Pump 1st stage cement job as per Schlumberger proposal,top of cement to be 6,278' MD/4,954' TVD. 16. Pump 2nd stage cement job through HES cementer as per Schlumberger proposal,cement will be placed 300' below and 500' above the tabasco interval. Volumes are critical to calculate so that the cement top 2T-41 APD Page 7 of 11 Printed:30-Oct-13 i cation for Permit to Drill,Well 2T-41 • Saved:30-Oct-13 does not enter the surface casing shoe. The top 100' of cement will have a cement setting time of 8-10 hrs. The tail cement will have a standard setting time of 4 hrs. 17. Set slips and install wellhead x 7-5/8"packoff and test to 3500 psi. 18. Wait at least 4 hrs after pumping 2nd stage job(but no longer than 7 hrs)to allow tail cement to set and flush 10-3/4"x 7-5/8"annulus with water,followed by diesel to freeze protect. 19. PU 4"DP,6-3/4"bit,and drilling assembly with MWD/LWD(Gamma,resistivity,sonic and neutron density.) RIH and clean out 2nd stage cement to 100' above shoe. Test intermediate casing to 3500 psi for 30 minutes. 20. Drill out shoe track and 20' of new hole. Perform formation integrity test to minimum of 12.5 ppg, maximum of 16 ppg EMW leak off,recording results. 21. Directionally drill 6-3/4"hole to Kuparuk A sand TD—200'below A sand at+/-7,727' MD/6,082'TVD as per directional plan(wp10). 22. Circulate hole clean and POOH. 23. PU and run 5-1/2", 17#,P-110,DWC liner. The top of liner will be placed at 7,078' MD,allowing for 200' of overlap in the 7-5/8"casing. Ensure pup with RA tag is on rig prior to running. 24. Pump liner cement job per Schlumberger procedure. Set liner hanger. Slackoff and set liner top packer. Circulate out excess cement above liner. 25. Monitor well for flow for 15 minutes 26. Pick up 5-1/2"scraper BHA,space out and M/U tandem 7-5/8"scraper assembly. RIH and tag PBTD. Displace to clear brine, 10.6 ppg. PT liner to 3,000 psi at surface for 30 minutes,chart results. 27. R/U perforation guns on wireline. 28. RIH to perforation depth and perforate prognosed intervals. 29. RIH on 4"DP to de-burr 5-1/2"liner. Swap to clean 10.6 ppg brine. 30. Flow check well for 30 minutes to run 3-1/2"selective completion on wireline. Stab seal assemblies in seal bore and set tubing hanger in wellhead housing. 31. Nipple down BOPE,nipple up tree and test. 32. Freeze protect well with diesel and install BPV. 33. RDMO. 2T-41 APD Page 8 of 11 0 n 1 r' ' ' ' I Printed:30-Oct-13 ication for Permit to Drill,Well 2T-41 Saved:30-Oct-13 14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005(c)(14)) • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.v • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18 or 1B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. / • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (659- 7212). 15. Attachments Attachment 1 Directional Plan Attachment 2 Drilling Hazards Summary Attachment 3 Proposed Well Schematic Attachment 4 Cement Summary 2T-41 APD Page 9 of 11 Printed:30-Oct-13 cation for Permit to Drill,Well 2T-41 Saved:30-Oct-13 Attachment 2—Drilling Hazards Summary (To be posted in Rig Floor Doghouse Prior to Spud) (See Well Plan Attachment: Detailed Risk Information for further discussion of these risks) Risk Description Mitigation Differential /10.3 EMW expected in the A A sand pressures are Pressures in the sands and 8.8 EMW expected expected to be as prognosed Kuparuk A and C in the C sands. and mud weight will be 10.6 to sands control, C sand pressures may be higher than expected and will be less likely to lose returns. Lost Circulation Lost circulation possible Reduced pump rates, trip Zones speeds, real time PWD monitoring, mud rheology, LCM addition Barite Sag Settling or stratification of Close attention to mud barite in a drilling fluid properties and drilling resulting in a density gradient operations to minimize sag. Pack off while In previous 2T wells the Drill slowly through the drilling Tabasco unconsolidated Tabasco Tabasco and spend extra time interval interval caused hole cleaning rotating and circulating to issues and pack offs leading clean the hole. to stuck pipe. Swab/Surge BHA&tripping runs Reduced tripping speeds, mud properties, proper hole filling practices, pumping out of hole, real time ECD, weighted sweeps Two stage Cement The Tabasco Interval will be The 2"d stage cementing job Job cemented using an HES Cementer will set cement across Tabasco and ensure open surface casing shoe. Have PJSM to review the cement procedure thoroughly with all parties involved. Well Proximity Risks: Directional drilling/collision avoidance information as required by 20 ACC 25.050 (b) is provided in the attachments. 2T-41 wp07 fails major risk analysis with an adjacent pluged and abandoned well 2T-12A. 2T-12A has been P&Aed to surface with cement in all annuli, the wellhead was removed and the casing strings have been cut down to 3 feet below tundra level with a welded cap to designate the existence of the well. A tolerable collision worksheet and evaluation has been performed on the wells. Drilling Area Risks: Reservoir Pressure: We are confident in the predicted reservoir pressures in the Kuparuk A sands and expect the Kuparuk C sands to be at an equivalent mud weight of/8.8 ppg or higher. The 2T-41 APD Page 11 of 11 t F F 1 Printed:30-Oct-13 y . cation for Permit to Drill,Well 2T-41 Saved:30-Oct-13 differential pressures may cause losses in the C but we have a mitigation plan for losses. When drilling through the Tabasco interval in the intermediate section we may experience abnormal pressures because the Tabasco interval is an active producing interval. The closest monitoring point in the Tabasco is Well 2T-201, an injector. This well will be shut in prior to drilling based on the average pressure reduction time required and will be monitored to ensure that we will not see abnormally high or low pressures while drilling through the zone. 2T-41 APD Page 12 of 11 Printed:30-Oct-13 2t-41 ConocoPhillips Grass Roots Conventional Topset Slant Proposed Wellbore Schematic Updated blakney Oct 22,2013 4 C '1 Hunter Oct 25,2013 Top 100'of tubing are 4 5"L-80 Per WP11 for wellhead New Insulated Conductor: Fresh Water mu, 16" 164.8#H-40 Spud Mud Permafrost 3-W Nipple DB Profile(2.875")@ 400'MD. 9.6 PPG Fresh Water 13-1/2" Surface Hole Spud Mud 9.8-10 PPG 10-3/4"HES Backup Cementer @ 1000'MD. Surface Casing: Campo3'h'x1-WMMG 10-3/4"45.5#L-80 Hydril 563 3,340'MD/2,670'TVD©55° W i4 est Sad Base West Sak ,609 MIS 2,194 TVD ` 5340 MD ��•: TVD .Set Surface 480' 2TVD below Top West Sak :Tabasco 4,003 MD%.3;049'.TVD TOC 15.8 Pp9 G�500 MD,bighet'ttiaq,Tabaseo to80y;:. `: i; -. Camco3G x1-.4"MMG 0 O 0 7-5/8"HES Cementer @-4,525'MD. LSND Tubing: 9.8 PPG 3-W 9.3#L-80 EUE8RD—6,978'to surface Keep up with Camco 3%"e 1-W MMG Vii3-14"9.2#P-110 Hydril 563 7420'to 6,978'MD Dilution 9-7/8" Intermediate Hole Camco 3%'x 1-'/:"MMG ISA tiU;' TOC 15.8 ppg @+/-6,278'MD 3 W X Nipple 2.81'• illik 4"Seal Assembly with No Go 20 ft Stroke rr111r_ 7-5/8"x 3-1/2"Premier Packer with PBR @6,978'MD Shear to 40K Lbs 7-5/8"x 5-1/2"ZXP,RS,Flexlock Hanger @7,078'MD r Intermediate Casing: " 7-5/8"29.7#L-80 Hydril 563 7,278'MD/5,738'TVD@40° Ku�aruk s;� � Sar�� :;;_.;:_::;: � � 2645 SI $:�:i�P�::€ ; ; ; : 5,78OT.ii 1 • CMU sliding sleeve, 2.813"X nipple profile ` 3.5" Tubing Anchor LSND Made upto Anchor 5-Yx"x 3-'%'FA Packer at 7,400'MD 10.6 PPG Btm C to Top A 62' MD,47' TVD t t 2.725"D /4" Production Hole SOS @ 7,415nipple'MD 6 3 1I STUk:A:: �I1LS. a4�1�q!: : ' 0.1.1 T/{� 3 i i:i is3g l::]i i ''i!!i'`'........ili Cemented Production Liner: 5-1/2" 17#P-110 DWC 7,727' MD/6,081'TVD @ 40° n p 1 r`. ! r x r ' r k� resa "Tir ROy *ONAMet; 01t419 jA1 y ""'0 # ?+, , e m "+'6 aw ✓,� he CO0 4q E CtS ■ CtS • CL a � M O _> 3 N ) MN � I• (1) C C L i N N O OaRS a = = c ca 0 03 V Y Y a a o M 0 a N N Vm fli flb O O O N C C °O O O> Or O r Q 0 C z, O o co o U . 0 M O w 00N > U N C (O G© fON0 M wt. 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CPAI Coordinate Converter _ El la From: To: -_-- -- Datum: NAD83 + Region: lalaska j Datum: INAD27 Region: Ialaska zi C' Latitude/Longitude !Decimal Degrees J C` Latitude/Longitude 'Decimal Degrees 2:1 C' UTM Zone: I r South +` UTM Zone: True r South 6` State Plane Zone: 4 Units: us ft _+'' State Plane Zone: True +1 Units: us ft + - (tea_ (_ _.___. C' Legal Description(NAD27 or-,€yJ 4- Legal Description(NAD27 only) -Starting Coordinates: ----- -Legal Description X: 11638978.84 Township: lull N + Range: 1008 FE ..1- Y: Y: 15969827.99 Meridian: lu ---,--1 Section:ll _ _.—.___.______. IFNL +1 15162.8875 FEL + 14722.4490 Transform Quit Help 1 I 2T-41wp11 Intermediate Casing I M CPAI Coordinate Converter From: __ _ __ To: Datum: INAD83 + Region: 'alaska +1 Datum: INAD27 +x Region: alaska +x C` Latitude/Longitude 'Decimal Degrees J C` Latitude/Longitude 'Decimal Degrees C` UTM Zone: 1 r South " UTM Zone: !True f South 6 State Plane Zone: 14 +, Units: jus•Ft �J ( State Plane Zone: True + Units: 'us-ft •;-1 C` Legal Description(NAD27 only) 6 Legal Description(NAD27 only) Starting Coordinates: i Legal Description X: 11636499.58 Township: 1011 IN + Range: 1008 VA. Y: 15968451.16 Meridian: jU +, Section:lll FN L +' 11280.5516 FEL + 11922.6774 r Transform Quit I Help 1 n11 1 r' I I e1 i"4 L 2T-41wp11 TD j ,. �`,a,�. �", ,;�4 ro ,'�"i rs k,,,fie �s+ ,,fit � �`*htt' CPA I Coordinate Converter [nIL From: _._ _._- To: Datum: 1NAD83 Region: Ialaska Datum: ]N.4D27 _H Region: Ialaska C LatitudelLongitude Decimal Degrees r Latitude/Longitude Decimal Degrees zi i" UTM Zone: I f– South C UTM Zone: True r South a State Plane Zone: 1' Units: us-ft C State Plane Zone: [True Units: us-ft ` Legal Description(NAD27 only) 6' Legal Description(NAD27 only) –Starting Coordinates: _- Legal Description— X: 11636449.50 Township: 011 N j Range: 008 [E Y: 15968735.54 Meridian: IU J Section:111 IFNL vi INETOT IFEL w 11972.6233 Transform Quit I Help ORIGINAL. TRANSMITTAL LETTER CHECKLIST WELL NAME: I( u,, PTD: o?I 31 y Development Service Exploratory Stratigraphic Test Non-Conventional FIELD: jrKl ,(` 1 POOL: K(pciwK R1JEAr/ 141)(4J( ai�✓k-r v t Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are Well Logging rn also required for this well: Requirements t / Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 5/2013 To N a) 0- o !n ° 0 vi ° m o) -o L C 7 a) c CO E 0 a ° a L 2 O U V2 Li) O CA C O) v o a C -0 a7 a7 O Z N O 00 cp (p c ° "O N ° 0a 'N > L O .0 a --3' 7 LLI u)0 C @ N 22 U 3 a) O O C ° @ C @ a 02 NN C co C C O U 7 L Q 3 d T C 3 o a wLU o a 0 mi c ° o_ o g o a a w co C T O ° a coN _co M c d ° a) Y d „ a 0 a") o - 3 coa M rn a n c m c N o c O co co O > a 7 _o L c a) a as F- O N N O c a`) m u) E ica o @ a) V 0) 3 O j( 0 -O N 0) M ° c _ a) a) a) o E N N J p •- n c"7) co > < @ 'p N °. 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N _ CO C. O 7 3 @ @ m a) @ @ E co 3 c (1) 8S' @ @ ° ° - ° w -° 2 @ — C /Y) U @ N @ U C 0 c ° 0 0 0 .° - - a 0 = o o c c > > 3 cmc . c ) 0.) `') w ° 3 N@ n U . co ai �� J 00 E 0 Q - - - aa)) a) a) E E c - 3 a c a ,o F F F N a 3 = 0 li 0 0 .- k 0 E �° N (0 c is c C a a a 7 -° n n a) `° @ ° - a) 0 0 7 2 2 2@ -0 @ -0 P O O L ° °- a) ° co a) a) o V c d .0 0 U) • O O a a U a CL z 0 (/) 0 0 0 U Q t Q 't- o m m U N 2 0- 0 (1) (n U W a O N M V LU O r CO 6) O N M In (0 r CO O O N M V O 00 O) I EO �- N co V LU (0 N- 00 0) = r- r- (n _ - N N N N (71-.1 N N N N N (M M M M M M C') (`M CC) M M M co C� a) G O C — N r N w N U 0 W M - C - - O = 0 a. 9 E J . E a) a 0 C C L O W 0IE a CO a) G J 0 a Y 0 > as a a w` a > 0 as oF 60" I%%%s9 THE STATE Alaska Oil and Gas °fALASKA Conservation Commission wti GOVERNOR SEAN PARNELL 333 West Seventh Avenue 01tA FALASY'P Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 E. Jolley Supervising Drilling Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk Oil Pool, 2T-41 ConocoPhillips Alaska, Inc. Permit No: 213-146 Surface Location: 5182' FNL, 4722' FEL, Sec. 1, T11N, R8E, UM Bottomhole Location: 1154' FNL, 1737' FEL, Sec. 11, T11N, R8E, UM Dear Mr. Jolley: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. In addition, please record a gamma ray curve from the base of conductor to TD along with the logging program proposal by ConocoPhillips Alaska, Inc. and approved by the AOGCC. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, fs-44'/4 Cathy P. oerster Chair, Commissioner DATED this/O./flay of October, 2013. STATE OF ALASKA f ALASKA OIL AND GAS CONSERVATION COMMISSION is 13l I i 3 '� PERMIT TO DRILL --)(106,1- 1,0 ?`o��k5 20 AAC 25.005 -Rk.W.SEct la.Type of Wodc: lb.Proposed Well Class: Development-Oil p Service-WinJ ❑ Single Zone ❑ 1c.Specify If wall I proposed for. DrillEl Lateral❑ Stratigraphtc Test 0 Development-Gas 0 Service-Supply 0 Multiple Iona[' Coalbed Gas r41 Gas Hydrates 0 - Redd! Reentry[ Exploratory ❑ Service-WAG 0 Service-Div ❑ d Geothermal ❑ Shale Gas 0 2.Operator Name: -5. Bond: U Blanket U Single Well 11.Well N s and Number: ConocoPhillips Alaska,Inc. Bond No. 59-52-180 2T-41 k 3.Address: 8.Proposed Depth: 12. =Id/Pool(s): P.O.Box 100360 Anchorage,AK 99510-0360 MD:7098'.- TVD: 5896' • Kuparuk River Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface:5182'FNL,4722'FEL,Sec.1,T11N,R8E,UM • ADL 25569. Kuparuk River Oil Pool, Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1243'FNL,1745'FEL,Sec.11,T11N,R8E,UM 2667 10/26/2013 Total Depth: 9.Acres in Property. 14.Distance to 1154'FNL,1737'FEL,Sec.11,T11N,R8E,UM . 2560• Nearest Property: >1 mile 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: . 109.7 feet 15.Distance to Nearest Weil Open Surface:x- 498946.5 y- 5970077 Zone- 4. GL Elevation above MS * 81.7 feet to Same Pool: 2T-10.55' 18.Deviated wells: Klokoff depth: , 300 ft. 17.Maximum Antic'.. ,Pressures in prig(see 20 MC 25.096) Maximum Hole Angle: ,44.9° deg Downhole:315; •,Ig. Surface:2588 psig ' 18.Casing Pro6ram: Specifications Top- _ , 1-pth -Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD ND (including stage data) 42" 16" 62.5# H-40 Welded 84' 37' 37' 121' 121' Driven 13.5" 10.75" 45.5# L-80 Hyd563 2770' 37' ' 2770' 2430' 1232 sx DeepCRETE,195 sx DeepCRETE 9.875" 7.625" 29.7# L-80 Hyd563 6414' 37' 37' 6414' 5342' 277 sx Class G,200 sx Class G 6.75" 5.5" 15.5# P-110 Hyd563 884' 6214' 5158' 7098' _ 5896' 115 sx Class G I 19 PRESENT WELL CONDITION SUMMARY I (To be completed for Reddli and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): -` ,<(measu :, - :Depth MD(ft) Effective Depth ND(ft): Junk(measured) Casing Length - e k.` .' ems MD TVD Conductor/Structural / Surface 1 11 Intermediate Production Liner Perforation Depth MD(ft): f Perforation Depth TVD(ft): 20.Attachments: Property Plat 0 BOP ketch n Drilling Program 0Tine v.Depth Plot 0 Shallow Hazard Analysis 0 Sketch rL�Ji Seabed Report 0 . Drilling Fluid Program Q 20 MC 25.050 req = = Q 21.Verbal Approval: Commission Representeil : Date: / t...' ' 22. I hereby certify that the foregoing is true tri d correct. Contact Lindsey Hunter @ '' r' 7 p/T/(� Email1-indsev.Hunter�conocoohillios.coi�(t Printed Name E.Jyfley rifle Supervising Drilling Engineer Signature ��leireser Phone: 265-6120 Date tO/,1/3 . / Commission Use Only Permit to Drill / API Number: Permit n See cover letter Number. ,2 /3 -;/// 4c60- /D 3-26675=0o-06 I Date: \ 'I0 ( I Iotherrements Conditions of app vat: 1LIf box Is checked,well may not be5used to explore for,test,or produce coalbed kethane,gas hydrates,or gas contained in shales: [2j Other: 8 O t-t 5 % 71-0 30 O 6 ,5/ Samples req'd: Yes measures: Yes 0 No 121 Mud log req'd: Yes❑ No[i H2S Q No Directional svy req'd: Yes[ ' NOEL Spacing exception req'd: Yes 0 No L Inclination-only svy req'd: Yes 0 Nog' APPROVED BY THE Approved by: i ?/�CAMMISSIONER COMMISSION Date: 10 - 0•- Form 10-401(Rev.16. 10/201 ) This perm Gddars of approval(20 MC 25.0013(g)) ?l �L io11lb l." c STATE OF ALASKA RECEIVEDSEP 2 A 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCC 20 MC 25.005 1 a.Type of Work: lb.Proposed Well Class: Development-Oil Q• Service-Winj ❑ Single Zone ❑ 1c.Specify if well is proposed for: Drill Q. Lateral ❑ Stratigraphic Test❑ Development-Gas❑ Service-Supply ❑ Multiple Zone 0' Coalbed Gas ❑ Gas Hydrates❑ Redrill ❑ Reentry❑ Exploratory ❑ Servi_ce-yyAGService-Disp ❑ Geothermal El Shale Gas ❑ 2.Operator Name: `: ' '- 5,+ • u Blanket u Single Well 11.Well Name and Number: ConocoPhillips Alaska,Inc. Bond No. 59-52-180 • 2T-41 • 3.Address: - .. _, _ 6.Proposed Depth: 12.Field/Pool(s): P.O. Box 100360 Anchorage,AK 99510-0360 MD:"7098':" TVD: 5896' • Kuparuk River Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface:5182'FNL,4722'FEL,Sec. 1,T11N,R8E, UM , ADL 25569 . Kuparuk River Oil Pool • Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1243'FNL, 1745'FEL,Sec. 11,T11N,R8E,UM 2667 10/26/2013 Total Depth: 9.Acres in Property: 14.Distance to 1154'FNL, 1737'FEL,Sec. 11,T11N,R8E, UM - 2560• Nearest Property: >1 mile / 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: -109.7 feet 15.Distance to Nearest Well Open Surface:x- 498946.5 y- 5970077 Zone- 4 . GL Elevation above MSL: . 81.7 feet to Same Pool: 2T-10,55' 16.Deviated wells: Kickoff depth: , 300 ft. 17.M ' m a•' - -. • r ures in psig(s AAC 25.035) Maximum Hole Angle: •44.9° de Downhole:2568 psig, Surface: 1872 psig • / 18.Casing Program: Specifications Top - Setting Depth_ =ottom ..__CementQuantity;ciTor sacks Hole Casing Weight Grade Coupling Length D TVD (including stage data) 42" 16" 62.5# H-40 Welded 84' 37' 37' 121' / 121' Driven 13.5" 10.75" 45.5# L-80 Hyd563 2770' i 37' 37' 2770' 2430' 1232 sx DeepCRETE,195 sx DeepCRETE 9.875" 7.625" 29.7# L-80 Hyd563 6414w 37' 37' 6414' 5342' 277 sx Class G,200 sx Class G 6.75" 5.5" 15.5# P-110 Hyd563 884' 6214' 5158' 7098' 5896' 115 sx Class G 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured) Effective Depth MD(ft): Effective Depth TVD(ft): Junk(measured) Casing Length Size Cement Volume MD TVD Conductor/Structural Surface iPERS Erx ED Intermediate � � Production / Liner .. .._ ._- �. •____. Perforation Depth MD(ft): ' Perforation Depth TVD(ft): 20.Attachments: Property Plat] BOP Sketch El Drilling Program Q- Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements Q 21.Verbal Approval: Commysion Representative: Date: 22. I hereby certify that the/foregoing is true and correct. Contact Lindsey Hunter @ 265-6427 Email Lindsey.Hunter©conocophillips.com Printed Name E. Jolley Title Supervising Drilling Engineer Signature ..40, , • PgiltS R Date (1/2 bil3 Commission Use OnTy Permit to Drill API Number: Permit Approval See cover letter Number: iz;11. 14 (0 50-I 0. ,.^00-. Date: for other requirements Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: d (O(1/ Other: p ,fts 7L fv 3 0 00 p S i Samples req'd: Yes No Er Mud log req'd: Yes❑ No E�� H2S measures: Yes No ❑ Directional svy req'd: Yes[f No❑ "n Spacing exception�r req'd: DYes,❑ No 2 Inclination-only svy req'd: Yes❑ No o ,APPROVED IN THE ' .,... `.) Approved by: COMMISSIONER COMMISSION Date: '1 Ferguson, Victoria L (DOA) From: Hunter, Lindsey L <Lindsey.Hunter@conocophillips.com> Sent: Monday,October 07,2013 9:02 AM To: Ferguson,Victoria L(DOA) Subject: RE:2T-41 PTD 213-146 Attachments: 2013100712011730.pdf Follow Up Flag: Follow up Flag Status: Flagged Victoria, I apologize; this was a transcription error between the application document and the 10-401. The correct numbers are both included in the table on page 3 of the application (calculations are continued on page 4.) The correct values are as listed below: Downhole maximum anticipated pressure—3158 psig(at 5,896'TVD) Surface maximum anticipated pressure— sig(see calculation#3 on page 4 of application) 5bps ; I scanned in a new 10-401, please let me know if you need me to send over the original. Thanks, Lindsey Lindsey Hunter Drilling Engineer ConocoPhillips Alaska DB&W 907-265-6427 lindsey.hunter(u?conocophillips.com From: Ferguson, Victoria L(DOA) [mailto:victoria.ferguson@alaska.gov] Sent: Friday, October 04, 2013 2:30 PM To: Hunter, Lindsey L Subject: [EXTERNAL]2T-41 PTD 213-146 Lindsey, The downhole maximum anticipated pressure is listed as 2568 psig on the PTD application but 2568 psi is listed as the ASP on page 4. Also,the max anticipated surface pressure is listed as 1872 psi while the ASP appears different. Please provide the maximum anticipated downhole pressure and the depth as well as the maximum potential surface pressure and the calculation. Thanx, Victoria Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil&Gas Conservation Commission 333 W.7th Ave,Ste 100 Anchorage,AK 99501 1 ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage,Alaska 99510-0360 ConocoPhillips Telephone 907-276-1215 September 13,2013 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage,Alaska 99501 Re: Application for Permit to Drill 2T-41 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a permit to drill Well 2T-41 a Kuparuk producer from the 2T drilling pad. This well targets an unswept area due to faulting. The intended spud date for this well is November 1st,2013 using Doyon Rig 141. With this permit to drill,the Doyon 141 rig will drill a 13'/"surface hole to 2,770' MD and case the hole with 10 3/4"45.5#L-80 casing and cement. Then,the rig will drill a 9 7/8"intermediate section to TD at 6,414' MD, and case the hole with 7 5/8"29.7# L-80 casing and cement. Then,the rig will drill a 6 3/4"production hole to TD at 7,098'MD, and case the hole with 5'/" 17#P- 110 liner and cement. It is expected that the Tabasco sand will be considered a significant hydrocarbon bearing zone. A stage tool will be run to cement off the Tabasco with 500'of cement above the interval. Lead cement will be pumped,then the stage tool will be opened and a second cement job pumped to isolate the Tabasco. This will leave a mud gap between the two stages. The Kuparuk formations will be cemented a minimum 500'above top of the sands. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005(a). 2. A proposed drilling program 3. A drilling fluids program summary. 4. Proposed completion diagram 5. Pressure information as required by 20 ACC 25.035(d)(2). 6. Directional drilling/collision avoidance information as required by 20 ACC 25.050(b). Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035(a)and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information,please contact Lindsey Hunter at 265-6427. Sincerely, 016/,;19 go,J- - or L.id cY t{ogter Lindsey Hunter Drilling Engineer Attachments cc: 2T-41 Well File/Sharon Allsup-Drake ATO 1530 Chip Alvord ATO 1566 Liz Jolley ATO 1700 Aq„...,ation for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 2T-41 Application for Permit to Drill Document Drilling &Wells: ConocoFhillips Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) 3 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) 3 Requirements of 20 AAC 25.050(b) 3 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005(c)(3)) 3 4. Drilling Hazards Information (Requirements of 20 AAC 25.005 (c)(4)) 3 ASP CALCULATIONS 4 5. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 (c)(5)) 5 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) 5 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) 5 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) 5 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (OP)) 6 10.Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) 6 11.Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) 6 12.Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) 7 13.Proposed Drilling Program (Requirements of 20 AAC 25.005 (c)(13)) 7 14.Discussion of Mud and Cuttings Disposal and Annular Disposal 8 (Requirements of 20 AAC 25.005 (c)(14)) 8 2T-41 APD Page 1 of 11 Printed: 13-Sep-13 QIG1fi 'tii'. € ._.. Apr..,,ation for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 15.Attachments 8 Attachment 1 Directional Plan 8 Attachment 2 Drilling Hazards Summary 8 Attachment 3 Proposed Well Schematic 8 Attachment 4 Cementing Summary .8 2T-41 APD P ; Page 2 of 11 v Printed: 13-Sep-13 ,ation for Permit to Drill,Well 2T-41 Saved:13-Sep-13 1. Well Name (Requirements of 20 AAC 25.005(f)) The well for which this application is submitted will be designated as 2T-41. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Well 2T-41 is planned as a grassroots Kuparuk A and C sand selective Producer. Planned operations include: drill a 131/2"surface hole to 2,770' MD and case the hole with 10 3/"45.5#casing and cement. Then, the rig will drill a 9 7/8" intermediate section to TD at 6,414' MD, and case the hole with 7 5/8" 29.7#casing and cement to 1000' above TD. The rig will then drill a 6 3/" production hole to TD at 7,098' MD, and case the hole with 51/2" 15.5#liner and cement to liner top(700' above Kuparuk reservoir). A cement bond log will be run to provide evidence of bonding in the 5-1/2" and 7 5/8"casing and cemented intervals. The Kuparuk intervals will be perforated with wireline conveyed perforation guns. The selective completion with 3-1/2" tubing and 3-1/2"x 5 1/2" packer will be located between the Kuparuk A and C sands. Finally, the upper completion of 3-1/2"tubing will be run to surface with a 31/2"x 7 5/8"top packer set at 6114' MD. Location at Surface 5182' FNL 4722' FEL Sec 1 T11N R8E NAD 1927 RKB Elevation 109.7'AMSL Northings: 5,970,077 Eastings: 498,946.5 Pad Elevation 81.7'AMSL Location at Total Depth 1154' FNL 1737' FEL Sec 11 T11N R8E Nad 1927 Measured Depth, RKB: 7,098' Northings: 5,968,826.92 Eastings:496,652.3 Total Vertical Depth, RKB: 5,896' Total Vertical Depth, SS: 5,786' Requirements of 20 AAC 25.050(b) Please see Attachment 1: Directional Plan The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005(c)(3)) Please reference BOP schematics on file for Doyon 141. 4. Drilling Hazards Information (Requirements of20AAC 25.005(c)(4)) The following presents data used for calculation of anticipated surface pressure(ASP) during drilling of this well: Csg Setting Fracture Pore Casing Size Depth Gradient pressure ASP (in) MD/TVD(ft) (lbs./gal) (psi) Drilling (psi) 16" 121 / 121 10.9 N/A N/A 10 3/" 2,770/2,430 12.5 1,094 57 7 5/8" 6,414/5 342 13.5 2,46 1,337 5-1/2" 7,09 ,896 ) 12.5 3,158 ) 2,568 2T-41 APD r—!• ; t M Page 3 of 11 Printed: 13-Sep-13 Ap,...ation for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 PROCEDURE FOR CALCULATING ANTICPATED SURFACE PRESSURE (ASP) (A)ASP is determined as the lesser of 1)surface pressure at breakdown of the formation casing seat with a gas gradient to the surface, or 2)formation pore pressure at the next casing point less a gas gradient to the surface as follows: 1) ASP = [(FG x 0.052)—0.1]D Where: ASP=Anticipated Surface pressure in psi FG= Fracture gradient at the casing seat in lb/gal 0.052 = Conversion from lb. /gal to psi/ft 0.1 = Gas gradient in psi/ft D =true Vertical depth of casing seat in ft RKB OR 2) ASP = FPP—(0.1 x D) Where; FPP = Formation Pore Pressure at the next casing point ASP CALCULATIONS 1. Drilling below Conductor(16") ASP = [(FG x 0.052)—0.1] D = [(10.9 x 0.052)—0.1]x 121 = 57 psi OR ASP= FPP—(0.1 x D) =1,094—(0.1 x 2,430) = 851 psi 2. Drilling below surface casing (10 3/4") ASP= [(FG x 0.052)—0.1] D = [(12.5 x 0.052)—0.1]x 2,430 = 1,337 psi OR ASP = FPP—(0.1 x D) =2,406—(0.1 x 5,342) = 1,872 psi 3. Drilling below intermediate casing (7 5/8") ASP= [(FG x 0.052)—0.1] D = [(13.5 x 0.052)—0.1]x 5,342= 3,216 psi OR ASP = FPP—(0.1 x D) = 3,158—(0.1 x 5,896)=2,568 psi (B)Data on potential gas zones; The well bore is not expected to penetrate any gas zones. (C)Data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 2—Drilling Hazards Summary 2T-41 APD Page 4 of 11 a Printed. 13-Sep-13 Ap,.....ation for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 5. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5)) Drill out from surface casing shoe and perform LOT or FIT in accordance with the Kuparuk LOT/ FIT procedure that ConocoPhillips,Alaska has on file with the Commission. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) Casing and Cementing Program Hole Top Btm Csg/Tbg Size Weight Length MD/TVD MD/ND OD(in) (in) (lb/ft) Grade Conn. (ft) (ft) (ft) Cement Program 16 42 62.5 H-40 Welded 84' Surf 121'/121' Planned:Driven Planned:Cemented to Surface with 10 3/4" 13 1/2" 45.5 L-80 Hyd563 2770' Surf 2,770'/2,430' 1232 sx 11#DeepCRETE lead&195 sx 12#DeepCRETE tail Planned: 1st Stage Cement Top planned @ 5,414'MD/4,400'TVD 277 sx 15.8#Class G tail 7 5/8" 9 7/8" 29.7 L-80 Hyd563 6,414' Surf 6,414'/5,342' Planned:2nd Stage Cement Planned for 500'above and 300'below the Tabasco sand 200 sx 15.8#Class G Planned:Cement Top planned @ 6,214' 5%2" 6 3/4" 15.5 P110 Hyd563 884' 6,214'/5,158' 7,098'/5,896' MD/5,158'ND 115 sx 15.8 ppg Class G 3'/2" 9.3 L-80 EUE8RD 6,000' Surf 6,000'/4,958' Uncemented tubing 3'/z" 9.3 P110 Hyd563 1000' 6,000' 7,098'/5,896' Uncemented tubing 7. Diverter System Information (Requirements of 20 AAC 25.005(C)(7)) While drilling the surface hole a 21-1/4", 2000 psi annular with a 16"diameter diverter line will be the diverter system used.✓Please reference diverter schematic on file for Doyon 141. 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(C)(8)) Drilling will be done using mud systems having the following properties: 2T-41 APD Page 5 of 11 Printed:13-Sep-13 AFS_ration for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 Surface Intermediate Production 13 1/2" Hole 9 7/8" Hole 6 3/4" Hole 10 1/2" Casing 7 5/8" Casing 5 1/2" Liner Density 8.6-9.2 9.6-10.5 10.6 PV 10-20 20 30 YP 40-80 24 22 Funnel Viscostiy 60-120 N/A N/A Initial Gels 30-50 N/A N/A 10 minute Gels 30-50 N/A N/A API Filtrate NC <6 <6 HPHT Fluid Loss at 160 N/A N/A N/A PH 10.8 9.5-10 9.5-10 Surface Hole Section: Spud mud will be MI Swaco's Drilplex MMO (mixed metal oxide) fluid system is planned for this interval. Gravel may cause hole cleaning issues, extra circlulation and wiping of the hole may be necessary to clean excess gravel. Hydrates may be encountered in this interval, follow RP for handling gas gydrates, be careful not to thin the mud with lecithin, it isn't compatable in this mud system. Sticky clays may be encountered in the permafrost and below, bit balling is a risk, incorporate nut plug in sweeps to minimize clay to metal sticking if needed. Intermediate Hole Section: Drill below surface shoe with spud mud reserved from surface hole and treat cement contamination as needed. Displace mud to LSND (low solids non-dispersed) system for FIT/LOT. Drill ahead watching for sticky clays, to treat pump high viscosity sweeps. Expect large sloughing solids in the Tabasco interval, extra circulation and hole wiping may be required as seen in previous wells drilling into this formation. Production Hole Section: Drill out casing shoe with LSND mud reserved from the previous hole section, treat cement contamination as needed, treat system with spike fluid and drill forward. Expect differential pressures in the Kuparuk A and C sands, allow for extra circulation time with drill string rotation to catch up on hole cleaning following slides, high ROP or drilling with reduced drill string rotation. Diagram of Doyon 141 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A-Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A-Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A-Application is not for an offshore well. 2T-41 APD _ e Page 6 of 11 Printed:13-Sep-13 t r l ' t b tL Ar. ation for Permit to Drill,Well 2T-41 Saved:13-Sep-13 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) The proposed drilling program is listed below. Please refer to Attachment 3: Well Schematic. Rig Work Plan (New PTD Continuing from P&A Sundry in the Process of Being Submitted) 1. Move in/rig up Doyon 141. 2. Install 21 1/4"annular with 16"diverter line and function test. 3. Spud and directionally drill 13 1/" surface hole to casing point at+/-2,770'MD/2,430'TVD according to the directional plan. Survey with MWD/LWD. 4. Run and cement 10 3/", 45.5#, L-80, Hydril 563 casing to surface. Displace cement with mud and pressure test casing to 2500 psi for 30 minutes and record results. If required, perform 2nd stage cement job using the HES cementer located at 500'MD to ensure good cement job to surface. 5. Remove diverter system, install and test 10 3/" x 5,000 psi BOP's, as described in Section 3 above, and test to 3000 psi (annular preventer to 250,psi). Notify AOGCC 24 hrs before test. 6. PU 9 7/8" bit and drilling assembly, with MWD and run in hole to top of float equipment. Test surface casing to 3000 psi for 30 minutes. 7. Drill out cement and 20' and of new hole. Perform formation integrity test to leak off, recording results. 8. Directionally drill to 7 5/8"casing point at 6,414' MD/5,342' TVD. 9. After TD, Circulate hole clean and POOH with directional BHA and lay down the same. 10. Run 7-5/8", 29.7#L80, Hydril 563 casing to surface. 11. Pump 1st stage cement job placing top of cement at 5,414' MD/4,406' TVD. 12. Pump 2"d stage cement job. Cement will be placed 300' below the bottom and 500' above the top of the Tabasco sand. 13. Set slips and install wellhead x 7-5/8" packoff and test to 3500 psi. 14. PU 6-3/4" Bit and drilling assembly, with MWD and LWD logging tools. RIH to top of float equipment and test intermediate casing to 3500 psi for 30 minutes. 15. Drill out shoe track and 20' of new hole. Perform formation integrity test recording results, stop if you reach 15 ppg equivalent mud weight without leak off, minimum FIT of 12 ppg required. 16. Drill 6 3/" production hole to TD at 7,098' MD/5,896' TVD. 17. Circulate hole clean and pull out of hole. 18. Pick up and run 5-1/2", 15.5#, P110, Hydril 563 liner. The top of liner will be placed at 6,214' allowing for 200' of overlap in the 7 5/8"casing. 2T-41 APD Page 7 of 11 Printed:13-Sep-13 At., .tion for Permit to Drill,Well 2T-41 Saved:13-Sep-13 19. Pump liner cement job. Set liner hanger. Slackoff and set liner top packer. Circulate out excess cement above liner. 20. Monitor well for flow for 30 minutes then pull out of hole laying down drill pipe. 21. R/U wireline to run CBL for 5-1/2" liner and 7 5/8"cement jobs. 22. RU perforation guns on wireline. 23. RIH to perforation depth and perforate prognosed intervals. 24. Run 3-1/2" selective completion per procedure. Displace well to kill weight fluid, flow check for 30 minutes. Stab seal assemblies in seal bore and set tubing hanger in wellhead housing. 25. Nipple down BOPE, nipple up tree and test. Pull BPV. 26. Freeze protect well with diesel 27. Set BPV and move rig off. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005(c)(14)) • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class ll disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (659- 7212). 15. Attachments Attachment 1 Directional Plan Attachment 2 Drilling Hazards Summary Attachment 3 Proposed Well Schematic Attachment 4 Cement Summary 2T-41 APD Page 8 of 11 Printed: 13-Sep-13 L Ap,...-ation for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 Attachment 1 —Directional Plan 2T-41 APD Page 9 of 11 • r°� - ' r Printed:13-Sep-13 Al. .on for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 Attachment 2—Drilling Hazards Summary (To be posted in Rig Floor Doghouse Prior to Spud) (See Well Plan Attachment: Detailed Risk Information for further discussion of these risks) Risk Description Mitigation Differential /10.3 EMW expected in the A A sand pressures are Pressures in the sands and 8.8 EMW expected expected to be as prognosed Kuparuk A and C in the C sands. and mud weight will be 10.6 to ✓ sands control, C sand pressures may be higher than expected and will be less likely to lose returns. Lost Circulation Lost circulation possible Reduced pump rates, trip Zones speeds, real time PWD monitoring, mud rheology, LCM addition Barite Sag Settling or stratification of Close attention to mud barite in a drilling fluid properties and drilling resulting in a density gradient operations to minimize sag. Pack off while In previous 2T wells the Drill slowly through the drilling Tabasco unconsolidated Tabasco Tabasco and spend extra time interval interval caused hole cleaning rotating and circulating to issues and pack offs leading clean the hole. to stuck pipe. Swab/Surge BHA&tripping runs Reduced tripping speeds, mud properties, proper hole filling practices, pumping out of hole, real time ECD, weighted sweeps Two stage Cement The Tabasco Interval will be Job cemented using an HES The 2nd stage cementing job Cementer will set cement across Tabasco and ensure open surface casing shoe. Have PJSM to review the cement procedure thoroughly with all parties involved. Well Proximity Risks: Directional drilling/collision avoidance information as required by 20 ACC 25.050 (b) is provided in the attachments. 2T-41 wp07 fails major risk analysis with an adjacent pluged and abandoned well 2T-12A. 2T-12A has been P&Aed to surface with cement in all annuli, the wellhead was removed and the casing strings have been cut down to 3 feet below tundra level with a welded cap to designate the existence of the well. A tolerable collision worksheet and evaluation has been performed on the wells. Drilling Area Risks: Reservoir Pressure: We are confident in the predicted reservoir pressures in the Kuparuk A sands and expect the Kuparuk C sands to be at an equivalent mud weight of 8.8 ppg or higher. The 2T-41 APD Page 10 of 11 Printed:13-Sep-13 A. don for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 differential pressures may cause losses in the C but we have a mitigation plan for losses. When drilling through the Tabasco interval in the intermediate section we may experience abnormal pressures because the Tabasco interval is an active producing interval. The closest monitoring point in the Tabasco is Well 2T-201, an injector. This well will be shut in prior to drilling based on the average pressure reduction time required and will be monitored to ensure that we will not see abnormally high or low pressures while drilling through the zone. 2T-41 APD Page 11 of 11 Printed: 13-Sep-13 t 6 d B ; Ap, ,ion for Permit to Drill,Well 2T-41 Saved: 13-Sep-13 Attachment 3—Proposed Well Schematic 2T-41 APD Page 12 of 11 Printed 13-Sep-13 2T-41 ' Grass Roots Conventional Topset Slant ConocoPhillips Proposed Wellbore Schematic FMC -I Dadang May 28,2013 Updated Hunter Aug 21,2013 New Insulated Conductor: Fresh Water 16"62.6#H-40 • Spud Mud Permafrost 3-W Nipple DB Profile(2.875")@-500'MD. 9.6 PPG Fresh Water 13-1/2" Surface Hole Spud Mud 9.8-10 PPG C ' 10-3/4"HES Backup Cementer @-1,000'MD. • LL - 3'"Cam.KBR-2-1 R tat Casing: 10-3/4"45.5#L-80 Hydril 563 2,770'MD/2,430'TVD @ 45° TOC 156:pp9 x©600 MEQ higher#hai Taba0&.:::::::::: i `:'i'i: : [ Tabasco 3l#1�9'.N[D:I 3.04U`�Vd �;, ....:...:..•:�:.:.::•:•:. ::i:::. :........` 3 T Cameo KBR-2-1 R 0 O 0 7-5/8"HES Cementer @-3,300'MD. ID Tubing: •—10.5 PPG 3 Camco KBR z,R''; is 3-'/2"9.3#L-80 EUE8RD-6000'to surface p up with 3-1/2"9.3#TN-110SS Hydril 563 6595'to 6000'MD tion may: 9-718" Intermediate Hof 3 W Cameo KBR-2-1- • TOC 15.8 ppg @+/-6,xxx'MD 3 W Camco X Nipple 2.81 f' 4"Seal Assembly with No Go 20 ft Stroke 7-5/8"x 3'/,"Premier Packer with PBR @B,XXX'MD virsi Shear to 60K Lbs 7-5/8"x 5 Y,"ZXP,RS,Flexlock Hanger @6,XXX'MD Intermediate Casing; eil 7-5/8"29.7#L-80 Hydril 563 6,414'MD/5,342'TVD @ 27° R • • :8ii°'1?: ',i' :::]::i:: E:E:of oi:` iiiiiiiiiii A : ..iiiia'sc�:::f�i�..��..�..R P�+:. Eif:`ii`E'ri�':EiEAnchor&PBR with Seal Assy 10ft stroke(shear to 20K lbs) LSND ..�.. 5-W x 3-'/z"FA Packer at 7,030'MD 10.6 PPG 108' MD 6-3/4"x 7.5" (Riptide) 48' TVD t 2.813"X Nipple Profile WEGat7,oa5'MD Production Hole k 1 is€i€Ku•�'arufc:: . .:.5�: d :; ::: i .... A.. 1� s .. :� ::::::: :::::::: :: :::€::isisi::;:::i:::i:::::s: :::€:€:€:: :i: :i:i: ::i: :isi: :i: ...7Q63„:„„IVIS....587::::'f fC iiiiiiiiiii!iiiiiiii :.. ' iiiiiii€iii€€iiiii Cemented Production Liner: 5-1/2” 15.5#TN-110SS Hyd 563 7,098' MD/5,896'TVD @ 40° U I Ua �--t L A,_, ..ation for Permit to Drill,Well 2T-41 Saved:13-Sep-13 Attachment 4—Cement Summary 2T-41 APD Page 13 of 11 Printed: 13-Sep-13 S . Mi RECEIVED OCT 0 1 2013 AOGCC INTEGRATED FLUIDS ENGINEERING (IFE) DRILLING FLUIDS PROPOSAL 2T-41 ConocoPhillips Alaska, Inc. • -.ate Prepared by: Customer Approval: Name: Scotten Blair Name: Lindsey Hunter Position: Project Engineer Position: Drilling Engineer Company: M-I SWAco Alaska Company: ConocoPhillips Alaska, Inc. Date: September 30, 2013 M-I Loglt# Version: 1.1 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties required. 1 ConocoPhillips Mi SWACO Well Summary The Kuparuk development well, 2T-41, is planned as a conventional grassroots slant producer, targeting the Kuparuk A and C sands. 2T-41 will be drilled by the rotary drilling rig Doyon 141 to a planned total depth of 7,098' MD / 5,896'TVD. The 13-1/2" Surface interval will be drilled with a fresh water, unweighted DRILPLEX AR Spud Mud to a planned depth of 2,770' MD / 2,430' TVD, with 10-3/4" surface casing run and cemented. The 9-7/8" Intermediate interval will be drilled with a 9.6 PPG fresh water LSND fluid to a depth of 6,414' MD / 5,342'TVD, with 7-5/8" intermediate casing run and cemented. At the intermediate TD, the mud weight will be increased to 10.5 PPG for trip margin. The 6-3/4" Production interval will be drilled with a 10.6 PPG fresh water LSND fluid to a planned TD of 7,098'MD/ 5,896'TVD, with a 5-1/2"production liner run and cemented. After drilling out of the intermediate casing shoe, treatments will be made to promote shale stability while drilling the HRZ and Kalubik shales, as well as LCM added preemptively to prevent lost circulation in the Kuparuk C sands. Casing and Project Summary Hole Casing Mud Size Size Casing MD TVD Mud Weight (in) (in) Program (ft) (ft) System (Ib/gal) 13-1/2 10-3/4 2,770' 2,430' DRILPLEX AR 8.6—9.2 • 9-7/8 7-5/8 6,414 5,342 LSND 9.6— 10.5 • 6-3/4 51/2 7,098 5,896 LSND 10.6 Liner ConocoPhillips Mi SWAG Surface Interval Summary Drilling Fluid System DRILPLEX AR Key Products DRILPLEX, GELPLEX, Soda Ash, Caustic Soda, RE-PLEX • Large gravel sizes can cause hole-cleaning problems • Sticky clays in the permafrost can slow ROP from bit and BHA balling • Swabbing in the clays may also be a problem Potential Problems • Hydrates may be encountered • Wash out in unconsolidated sections • Organics may thin mud • Excessive viscosity in lower clays • Maintain fluid temperature as low as possible (target < 70 F) Interval Objectives • Provide adequate viscosity to clean the hole of drill cuttings • Minimize time in hole section • Condition mud to provide a good cement job SURFACE INTERVAL MUD PROPERTIES Funnel LSYP API Fluid Depth MD Mud Wt. Viscosity Yield Point Loss (2 X 3 RPM Chlorides (ft) (lb/gal) (sec/qt) —6 RPM) (Ib/100ft2) (mL/30 min) (mg/I) pH 60— 120 (for 80'—2,770' 8.6—9.2 reference only, 30—50 40—80 NC <1000 10.8 fluid should be run off of LSYP) Recommended Initial DRILPLEX AR Formulation Base water Use"cold lake water"only, to keep the fluid temperature as low as possible Soda Ash 0.5 lb/bbl (add to base water) GELPLEX 12.5 lb/bbl (add to the base water and allow to hydrate > 12 hours) DRILPLEX 1.25 lb/bbl (starts the viscosity complex) RE-PLEX 0.25 lb/bbl (anionic suppressant) Soda Ash 1.25 lb/bbl (added to complete the complex) Caustic Soda As needed for pH of 10.8 (fluid must have minimum pH of 10.8 for complete viscosity development) Note: Makeup water and water used in the pits while drilling should be as cold as possible. 3 ConocoPhillips 11/Y BW 9 Recommended Solids Control Equipment • LO/TO the shakers. • Inspect all shaker bed decking panels for wear, replace as necessary.This will allow for optimum screen performance during drilling operations. It is important to develop a good preventive maintenance schedule which includes replacing the decking panels before it becomes a performance related issue. • Install 84— 110 mesh screens or finer if losses over shaker are not a problem . Ensure screens are Shakers properly tensioned, per manufacture's best practice suggestions. Spray down new screens with fresh water before operating the shakers. • As fluid shears,screen up as necessary to higher mesh screen sizes. • Minimize flowline"jetting"during drilling,as additional mud flow will allow shakers to be overrun with fluid. If possible,only jet the flowline during connections or in short bursts during drilling operations. • Check screens for holes between each connection. • Ensure that properly functioning gauge is available at the equipment's feed header. 75' of head is NECESSARY for proper 12"cone performance. Additional changes to feed pump may be necessary to create ample feed head. De-Sander • Inspect cone body sections and apexes for signs of wear,replace as necessary. Ensure that spare parts are available on site for future maintenance. • Monitor discharge weight and sample sand content to ensure proper operation of the De-Sander(s) • Inspect all cone bodies and apexes,replace as necessary. • 3/8"apex size may be best suited for finer particle size,as the De-Sander(s)up stream should allow for low sand size particles which will ensure that the De-Silter is working on the 24 - 45 micron sized particles without packing off. If packed off cones become a problem,open apexes up to Yi'. • Ensure that the feet of head gauge is available at the De-Silter,not the pump. De-Silter • Ensure that De-Silter feed pump can achieve 95'of head. CRITICAL! Changes can be made quickly to the impeller or speed of the pump to improve the head capabilities. • Ensure that sufficient spares are located at rig site. These spares would include enough apexes to install 5/8",%", or 3/8"assemblies,depending on well formations,fluid rheology,and circulating rates. • Particle size of the solids in the active mud system will determine the best apex size to utilize. • Surface interval requires a greater through put during most operations, which requires the centrifuge to run at a lower speed (2,500 rpm). This setting allows the centrifuge to process more fluid, discharge more cuttings, and ultimately discharge more solids at the end of the day. The only drawback of the lower rpm's, is the cut point is reduce from 3-6 micron cut, to approximately 6- 10 micron. MI Swaco recommends and stands behind the suggestion to run the centrifuge at the lower speeds during the Centrifuge upper sections of hole. • Continuous operation of both centrifuges will help control ultra fine solids from overwhelming the mud system. Cycling the centrifuges from on-off-on will result in larger particles breaking down to a size which is very difficult to remove mechanically. If the mud weight is getting too low, reduce the feed rate, but continue to operate the centrifuges. 4 ConocoPhillips M� SWACCLr,, Surface Interval Discussion ✓ Gravel may cause hole-cleaning problems. Extra circulation and wiping of the hole may be necessary to clean excess gravel out of the hole. Hydrates may be encountered in this interval. Determine severity of any influx and follow the RP for handling Gas Hydrates. Do not add Lecithin to the Drilplex system without consulting the technical representative or the M-I SWACO project engineer(Pilot testing showed significant thinning of the sample when Lecithin was added). SCREENKLEEN has proven effective at reducing aeration and should be considered if aeration problems occur. Additional small quantities o RE-PLEX may be needed after the addition of SCREENKLEEN. All additions should be pilot tested prior to adding especially in the Drilplex system. Hydrates are seen to more readily break out at the shakers as compared to a "conventional"spud mud. Thinning of the Drilplex system may be used to allow hydrates to more readily break out of the mud if necessary. r Maintain flow rates of at least 650 gpm. Recommended average ROP for adequate hole cleaning is 150 fph. Reduce pu rates immediately if packing off occurs. ✓ Dilution rates of 80-100 bbls/hr of"cold"Drilplex mud may be required to maintain a mud weight <9.4 ppg by TD and keep the mud temperature to <60-70°F at TD. Ensure stable mud weights are maintained to avoid spiking up or dow • Sticky clays in the permafrost, and also in the zone below the permafrost, can slow ROP from bit and BHA balling. Incorporate Nut Plug M in sweeps(as allowed by MWD tools)to minimize clay to metal sticking if needed. r Drill ahead and adjust low end rheology, ROP, pipe rotation speed (80-100 rpm), pipe running speeds and pump rates .1_, needed to insure proper hole cleaning and ECD. Watch for any indications of wellbore instability problems. Any fluid weight adjustments should be performed in 0.1- 0.2 lb/gal increments if absolutely necessary. r Lubricants may be used sparingly. A combination of LOTORQ&Lube 776 at 0.25 % each has shown significant improvements in COF in lab testing at the mud plant.The viscosity of the Drilplex system will be reduced with lubricant additions so EMI 1008 (RePlex) may need to be added to regain viscosity. Based on results from past wells it is MI Swaco"s recommendation to thin back the Drilplex to LSYP value of< 20 wit ,p water once casing is on bottom. Desco CF can be used as a chemical thinner. A water spacer of 50 bbls, pumped ahead of the mud push will provide further dilution of the mud. Chemical thinners should not be used prior to getting casing on bottom as overtreatment can easily occur with this system. Water should be used if thinning is necessary pricr to the casing run. ✓ MI Swaco recommends reducing rheology with water and adding citric acid and or Desco CF to the Drilplex used to displace the cement with to ensure there is no excess viscosity seen while running in to drill out. Drilplex Mud System mixing and volume addition plan MI Swaco Drilplex MMO (Mixed Metal Oxide) fluid system is planned for this interval. Additional support will be provide on the slope by MI Swaco's IFE coordinator. r The mud plant will be used for the initial mud system and volume additions necessary while drilling. The initial volume will be made at the mud plant according to the basic formula listed prior or from the triple strength Gelplex blended with cold lake water. See table for making 290 bbls Drilplex from triple strength Gelplex below: 5 ConocoPhillips MI SWACO Rig products needed for 290 BBLS of DrilPlex AR Mud made from "triple strength"prehydrated Gelplex 30.0 ppb GelPlex Slurry, 116 bbl Cold Lake Water,bbl 174 Soda Ash,50 lb sx 6 DrilPlex,25 lb sx 14 ScreenKleen,gal 122 RePlex,gal 7 The volume additions needed while drilling will be by the use of triple strength prehydrated Gelplex additions diluted wi cold lake water in the pill pit or whole mud brought out from the mud plant at the discretion of the mud engineer. T fluid will then be added to the active system as necessary while drilling. The formula for the triple strength Gelplex mix at the mud plant is given below: ✓ Base water Use only"cold lake water"to keep the fluid temperature at a minimum. • Soda Ash 0.5 lb/bbl added to make up water • Gelplex 30 lb/bbl (add to the make-up water and allow to hydrate > 12 hrs) o Triple strength Gelplex can be added to the pill pit at the rig and diluted back as necessary for viscosity adjustments to the active system. Drilplex will then be added to this volume in the pill pit to achieve a fin ration of 1:10 (ppb Drilplex to ppb Gelplex)along with 1.0— 1.2 ppb Soda Ash in the pill pit to achieve the desired viscosity. RePlex at 0.2 - 0.25 ppb will also be added as an anionic suppressor. Expected ratio of water to triple strength Gelplex to achieve a LSYP of 25-50 is 1.5:1. Example using the previous table adjusted for 50 bbls pill pit volume: Rig products needed for 50 BBLS of DrilPlex AR Mud made from "triple strength"prehydrated Gelplex 30.0 ppb GelPlex Slurry, 20 bbl Cold Lake Water,bbl 30 Soda Ash,50 lb sx 1 DrilPlex,25 lb sx 2.5 ScreenKleen,gal 21 RePlex,gal 1.2 Drilplex low shear rheology of the 6&3 rpm reading should be the same or very close to one another as measured by the Fann viscometer.This is a good indication that the fluid is in good shape. The gel strengths should be elevated bu' flat ensuring a highly pump able fluid with excellent hole cleaning ability. Desirable properties of the Drilplex system ar: listed below: Spud to Base Permafrost o LSYP 30-50 o PV ALAP(should be 10-20) o YP 40-80 o Gels 30-50 o 6 rpm 30-50 o 3 rpm 30-50 The Drilplex system is susceptible to anionic thinning and as such all anionic compounds, i.e. Pacs, Lignites and thinners should be avoided. Coal seams will tend to thin the complex and while not expected in this well the system will be lightly treated with the anionic suppressant REPLEX at the rig. Mud engineers should have a minimum of one pallet(4 Drums)of this product on site for contingency purposes. 6 ConocoPhillips Mi Recommended Practices for Drilling Hydrates Care should be taken in the event that hydrates occur. If the hydrate issue is deemed to be a major problem, use the following guidelines to help minimize the effect that any hydrates may have to the drilling operation. • Weigh the mud at both the possum belly and at the suction pit using pressurized and regular mud balances to determin= the amount of gas that has become entrained in the mud. • Maintain the fluid temperature as low as practical (<70°F if possible). • Minimize circulation time and flow rate in the hydrate section to mitigate hydrate thawing. • Watch both drill rates and flow rates and make adjustments as needed to help diminish any problems that the surface equipment may have in handling the fluid and cuttings while circulating out any hydrates. • Reduce flow rate and continue drilling through the hydrates in order to minimize additional thawing and hole enlargement. • If the fluid viscosity becomes too thick with the hydrate influx then the Drilplex system viscosity can be reduced temporarily to allow the hydrates to break out and prevent pumping issues. • Use water additions only to adjust rheology(lower). 7 ConocoPhillips MI Virtual Hydraulics 13.5" Hole Model • N,■�'�w,A�"�O 21.41 Nuw,0A Protium MO:249824 Operator:8awc0PAwg Mask..kw. VIRTUAL HYDRAULICS* �7Y YAC - ,:r- TVD:2430 ft Wel N.m.:21.41 A ScnwrnLoa er Coml.,' !1 PPO 0121191.04 AR BHSIY:11!In Location:50,55 Slop.,Amok. Snapshot* •uw c.c.,c. 13.1/2. 9006PY 80 RPY.I50 FPH Roy%NSIWWW%1:80410 Country:U9A Depth Geometry Anglo Ueu3y PV(OP) Tamponten V. Hob Cl,tSn9 Pressure Distribution III 0011V0 tag OM 1% 0.990 YP,LS)P ObXOBM ('F) (Muni Indu Ann=0% Brt=89% 09.15% ON OW 45 90 91 9 6 III 104 s m 90 60 W loo 0 WO VG G F P 16 9m I( - . il ' �a taw DNY.v Rid DRILPIfk AR rIL{cr m Nod Weight 9.1 lb/gal Test Temp SO°F IP PV 105571 10 c0 IIII YP 12 101100X' I I LSYP 1)10110011' System!). L Flow Rete fi50 0.Ilmin P<nelle0on Pete 150 Mr Rotary Speed 80 Ip.o Weight an Bit 35 1 Bit Naxdes 1].16.18.10.0 00000 ',mute Lemma 1 YodYM Power Lew DNIISINn9 451 p.1 YWD 1i8 poi Motor BBB psi • Bit p)psi _ Bit On1011 310 psi Annulu. 6]psi Sunece EOuip 11 psi - U.TUM Effect 44 psi 111 IP IIII IP 11/ IP IP 1.1 .11 T0tel System 2142 q1 ill t<» 19500 ' I _ E60 ECO 0.0? TL COp Me 911 cCut 9D1 B.B/ © —Eco - v =34090 . Tw nal yu.0en�n911 9.T1 10.07 mmn1 R Y — F.D.C. -159P uA SAeY O , ]'14,°,Ia 8 onoco CPhillips Mi SWio►C_ Virtual Hydraulics 13.5" Hole Cleaning Model MigRI/Or�_It"7 1111 HUWrvk Producer MD: 11658 opernor. ConocoPMlalps Alnka,Inc Well NameIiJt w . VIRTUAL HYDRAULICS* MMMp91 PPG URILPLE%AR iM. '�a . A acheeaee Cemrw Rn She: Sin LocMlen. Ronk slope,Alaska wor Hale.650 GPM-ao RPM-150 EPR nee 9111013 Coonln. USA VRDH* Hole Cleaning ConocoPhillips Alaska,Inc.2141 110 -- MM. -- 1 __— I— ra ' er_ -00P Iii ROP 1000Mr —_ 1111111111111.1114— — ROP 150 My _— — ROP200aar IIIIIIIIIII —'""1"1111111111111111111.1 == 010-_ _— �� 2LIMIll- on-- --_ Vary good Hole Claenlne MIMI aoo srp 1, aoo soo Flow Rate(gal/min) C) ConocoPhillips Mi SWACD,sor,„. Intermediate Interval Drilling Fluid System LSND Key Products Flowzan, Drispac Plus Superlo, Caustic Soda, M-I WATE, DRILZONE, SCREENKLEEN, LOTORQ, LUBE 776, Busan 1060, Myacide 25GA • Hole cleaning Potential Problems • Well bore instability • Lost circulation • Well control • Adequately clean hole using pipe rotation, controlled ROP, and maintaining good fluid properties Interval Objectives • Minimize magnitude and severity of ECD/ pressure fluctuations to prevent fracturing weak formation bedding planes • Maintain minimal ECD by minimizing drill solids accumulation INTERMEDIATE INTERVAL MUD PROPERTIES Low Shear Rate Drill Depth MD Mud Wt. Yield Point(LSYP) API Fluid Loss Solids (ft) (lb/gal) (Ib/100ft2) (mL/30min) pH (%v/v) 2,770-6,414 9.6 - 10.5 5 - 10 < 6 9.5 - 10.0 < 7 Intermediate Interval Fluid Formulation Soda Ash 0.25 ppb Flowzan 0.75 - 1.25 ppb Drispac Plus Superb 0.5 ppb RESINEX 2 ppb Soltex 2 ppb DRILZONE 1 0/0 SCREENKLEEN 1 % M-I WATE as needed Caustic Soda if needed 10 ConocoPhillips Recommended Solids Control Equipment • Inspect decking rubbers, c/o as necessary. • Install 200 - 230 mesh screens if shakers will handle flow rate. Ensure screens are properly tensioned, per manufacture's best practice suggestions. Shakers Spray down new screens with fresh water before operating the shakers. • Adjust shaker deck angle to allow for good cuttings conveyance and minimal residence time on the screens. • Check screens for holes between each connection. De-Silter • Only use if necessary. Use Centrifuge. • Intermediate intervals generally call for a "high-speed"centrifuge, which is rotating at approximately 3,200 rpm's. This allows the centrifuge to make the 3 - 6 micron cut, and eliminate a percentage of the "ultra fine" cuttings from the fluid. Through put must be decreased while running the centrifuge at 3,200 rpm's, since there is a greater risk of"packing off"the centrifuge back drive and auger. Centrifuge • Refer to mud engineer for solids information to determine speed and feed rate of centrifuge. • Continual processing at low feed rates will yield better results than shutting centrifuge down and starting it up. Slow feed rate down to maintain an acceptable weight if needed. • Run continuously. Replenish M-I WATE as needed. 11 ConocoPhillips Mi SWACQ.:: .-.- Intermediate Interval Operations& Recommendations 1. Drill out casing with Spud Mud reserved from Surface interval. Treat cement contamination with additions of CF Desco II, Citric Acid, and Sodium Bicarbonate as needed. SAPP may also be used. 2. Displace to LSND fluid for performing FIT/ LOT. 3. Maintain DRILZONE and SCREENKLEEN concentrations while drilling through the sticky upper clays. Discontinue once outside these clays. 4. Pump high viscosity or high viscosity, high density sweeps every "300' MD drilled while drilling through the sticky upper clays. Discontinue once these sweeps become ineffective or drilling progresses beyond this formation. 5. Maintain a thinner rheology through the sticky upper clay section to aid in dispersion of oversized, agglomerated cuttings. Target a low shear rate yield point (LSYP) of 5 - 7 (this should correlate to a yield point of 13 - 17). Increase rheology once drilling progresses beyond the sticky clay around 4200'- 4400'MD to a LSYP of 8 - 10 (this should correlate to a yield point of 18- 22). 6. Control MBT around 20 PPB with whole mud dilutions every 1000'MD drilled or more frequently as needed. 7. Maintain rheology with Flowzan as needed to balance hole cleaning and ECD. 8. Use Drispac to maintain fluid loss control. 9. Add Caustic Soda as needed to maintain pH 9.5 - 10.0. 10. Add Myacide GA 25 regularly and before any trips to control bacterial activity. 11. Add LOTORQ or LUBE 776, or a combination of the two, if needed to control excessive torque or drag. Only add lubricants if confidant the excess torque and / or drag observed is not due to increased cuttings bed generation from recent high ROP, sliding, reduced drill string rotation, or reduced flow rate. Be cautious that insufficient hole cleaning could be temporarily masked by the addition of the lubricants. Do not exceed total lubricant concentration of 3%v/v. 12. Keep accurate record of all water and whole mud additions to the active system and report in daily mud report. 13. Rotate drill string at maximum rotation as much as possible to aid hole cleaning. 14. Control ROP as necessary to allow for adequate hole cleaning. 15. Allow for extra circulation time, with drill string rotation, to catch up on hole cleaning following slides, high ROP, or drilling with reduced drill string rotation. 12 ConocoPhillips MI SWACO Virtual Hydraulics 9.87511 Hole Model Mr SWAG_] xuwru3 Producer MD Swan Operator c Pe Wino, VIRTUAL HYDRAULICS' Y ND 6411 n WMIMma'. RJt 105 PPG LSxD WU �31vn1nru.ryet cnrnPanY wn..« \TIF NWe•750 GPM.100 RPM.150 FPM RMIYys1101m").Da See: 50120 9 In Lf mey UNSAM1SIew,Alaska SnapShot* N. Geometry MOM Densly P✓1cv1 Temwretun V. Mole cleaning Pressure DM01XMn 1111 URNS CP00510 P) 0901) YP,LSYP MAW PH Mein) Ilea ++n=Y. S0=10% D5=51% m 01 0 00 a m w. M m n M I a _ m A ap a nap Milling FIUM 6x0 Im Mud Weight 105 1101 Test 00 °F I« PV1®110PF1 0 cP YP N 11100151 LSYP B 11f00R' ° System Ws MD Flow Rale 160 gagmin PennrMlen Rale 150 Me 301. o 2185 L vm R1ary 5peetl 1W rpm loco eg on Bn 10 110011 ma Bil'Noaln 1LILILILII � 11 14.0.0.0.0 1« vrneure Lena Mall.Power L« Drill String 314 psi nm • MWD IM w1 Mwe 531 psi 00 013 pal SX NAM 100 gel NM / Annulus Iw gel Surface Equip U gel UTube Eflsd M pal _—moo L TOIM SYvmm 4130 wl seem In ® em V - '-1.. .„..., ' , ESD KD .CW 01.00 ♦♦V Cm.MP 1051 10.33 11.11 F. 110 - TO 1051 11.01 11.10 A ___ —1.0... —my -.—ua WmO n n.r x<rme.mr..: 000n14013 13 ConocoPhillips Mi_ Q Virtual Hydraulics 9.875" Hole Cleaning Model Mi 2341 nuPntuw wedwAr Mo-. MOOn ND5392oP^ntor cunoro8nne.ALA..Wall Name Inc VIRTUAL HYDRAULICS. 10.5 PPG 1500 MAI : n '. wemwaewa.ecwewm• en5i:e: Dan mn' In i . Slop,MOM VRDH* .... �, .. VW Vole PM Mk .]50 GPM.100 MI.150 F . 911112. Country USA8006 USA Hole Cleaning CalwcoPhillipa Alaska,Inc.2TJ1 oa ! — _ — ROP so ft/hr — ROP 100Mr IOW P•• NanlnM — ROP 150 Me — ROP 200 NW ROP 250 Mr 07 • Fant Hole Cleaning 1 050 9-2 Good 6a 005 L Very Good Hole CN)ningMIIIIMEri.......111'1011.0MMIN111111111 0 _._.._... _ 500 600 ;,_.._.. _.... _.._..... __._ 500 Flow Rate(gagmin) 14 ConocoPhillips Mi SWACclor, Production Interval Drilling Fluid System LSND Key Products Flowzan, Drispac Plus Superlo, Caustic Soda, M-I WATE, DRILZONE, SCREENKLEEN, RESINEX, Soltex, LOTORQ, LUBE 776, SACK BLACK, Busan 1060, Myacide 25GA • Hole cleaning Potential Problems • Well bore instability • Lost circulation Torque and Drag • Adequately clean hole using pipe rotation, controlled ROP, and maintaining good fluid properties Interval Objectives • Minimize magnitude and severity of ECD/ pressure fluctuations to prevent fracturing weak formation bedding planes • Maintain minimal ECD by minimizing drill solids accumulation INTERMEDIATE INTERVAL MUD PROPERTIES Low Shear Rate Drill Depth MD Mud Wt. Yield Point(LSYP) API Fluid Loss Solids (ft) (lb/gal) (Ib/100ft2) (mL/30min) pH (% v/v) 6,414-7,098 10.6 5 - 6 < 6 9.5 - 10.0 < 6 Production Interval Fluid Formulation Soda Ash 0.25 ppb Flowzan 0.75 - 1.25 ppb Drispac Plus Superb 0.5 ppb RESINEX 4 ppb Soltex 6 ppb SACK BLACK 6 ppb DynaRed Fine 6 ppb SAFE-CARB 40 20 ppb M-I WATE as needed Caustic Soda if needed 15 ConocoPhillips Mi SWACGI . Recommended Solids Control Equipment • Inspect decking rubbers, c/o as necessary. • Install 200 - 230 mesh screens if shakers will handle flow rate. Ensure screens are properly tensioned, per manufacture's best practice suggestions. Shakers Spray down new screens with fresh water before operating the shakers. • Adjust shaker deck angle to allow for good cuttings conveyance and minimal residence time on the screens. • Check screens for holes between each connection. De-Silter • Only use if necessary. Use Centrifuge. • Production intervals generally call for a "high-speed" centrifuge, which is rotating at approximately 3,200 rpm's. This allows the centrifuge to make the 3 - 6 micron cut, and eliminate a percentage of the "ultra fine" cuttings from the fluid. Through put must be decreased while running the centrifuge at 3,200 rpm's, since there is a greater risk of"packing off"the centrifuge back drive and auger. Centrifuge • Refer to mud engineer for solids information to determine speed and feed rate of centrifuge. • Continual processing at low feed rates will yield better results than shutting centrifuge down and starting it up. Slow feed rate down to maintain an acceptable weight if needed. • Run continuously. Replenish M-I WATE as needed. 16 ConocoPhillips Mi SWA Q Production Interval Operations& Recommendations 1. Drill out casing with LSND fluid reserved from Intermediate interval. Treat cement contamination with additions of CF Desco II, Citric Acid, and Sodium Bicarbonate as needed. SAPP may also be used. 2. After drilling out most of the cement, treat system with a spike fluid to achieve the concentrations of SACK BLACK, DynaRed Fine, and SAFE-CARB 40 listed in formulation above. 3. Have additional M-I WATE on hand to increase density as required by observed reservoir pressure. 4. Maintain rheology with Flowzan as needed to balance hole cleaning and ECD. 5. Use Drispac to maintain fluid loss control. 6. Add RESINEX, Soltex, SACK BLACK, DynaRed Fine, and SAFE-CARB 40 continuously while drilling ahead to maintain concentrations in the active system as this material is removed by the solids control equipment and diluted by rig water additions. 7. Add Caustic Soda as needed to maintain pH 9.5 - 10.0. 8. Add Myacide GA 25 regularly and before any trips to control bacterial activity. 9. Add LOTORQ or LUBE 776, or a combination of the two, if needed to control excessive torque and / or drag. Only add lubricants if confidant the excess torque and / or drag being observed are not due to increased cuttings bed generation from recent high ROP, sliding, reduced drill string rotation, or reduced flow rate. Be cautious that insufficient hole cleaning could be temporarily masked by the addition of lubricants. Do not exceed total lubricant concentration of 3% v/v. 10. Keep accurate record of all water and whole mud additions to the active system and report in daily mud report. 11. Rotate drill string at maximum rotation as much as possible to aid hole cleaning. 12. Control ROP as necessary to allow for adequate hole cleaning. 13. Allow for extra circulation time, with drill string rotation, to catch up on hole cleaning following slides, high ROP, o drilling with reduced drill string rotation. 17 ConocoPhillips F '.:,,,,,, Virtual Hydraulics 6.75" Hole Model Mil BWALI 27.41 Nu..Producer NO: 7100 It Name: ton ovnulip gid. lnc. VIRTUAL HYDRAULICS' :i��/I'~/ 100 PPG LaxOwBM Tw. eeMn Oilm 1T.n A avleMAxrxxr Canpnry BM stn. 6.75 In wLoolll on'. North Slop.,Ales. awxc.„r. °..,o ii, 6.Wr Hole.903 GPI.-p 11116.100 FPN 114.11611(186.), 60120 Country: USA Snapshot* Deg. Geometry Angle Density PV(DPI Temperelur. Vs Hole Cleaning Pressure Dimrigulion It UDIIVD Ceg 0011D 1°) DwtA VP.LSYP(I12/I001P) PFI (Mnln) Index Ann=10% Sn=1e, Os-61% N o se lo l lir u in lx lx m n � .6 m �..� e 11 I � m Drilling Fluid SXD Purl Weight IWO °F TM Temp 100 °F IllM 10 no 5 . ( PVI®110°F) 10 cP 111 1111 YP 11 11.09111—._.._. 1 LSYP 6 1110x1 Sy1111 x m DW •tam emg Flow Me ]011 6Wmin Pennrmion Pale W 6611 1111 1111 — BO Notary Sped 0-0-0-0-0 p000 x1 lIlWeight an BitBN Non. 11-11.1b11-11 1111 Pressoe Mode.PowLosses e aLaw 1111 • Drill Suln9I] psi I.WD 118 pi Motor 912 pi I en .__3mp� _ .. B^ONOM .170 ,pel ow Sartre Egulp �1 pl UioM EMM 39 pal All Tool System 1619 pal 1111 I ens I ESD ECD eCul lam erx 1` Cep Slave 10.60 11 l0 IIBe n 1_ TD tDet 1180 1113 ( at v.x..ra r..,a Taw —wary. —taro —o.1.o V64 '-. rw.rra'.wrwn ..wart,, b 18 ConocoPhillips Mi SWACa Virtual Hydraulics 6.75" Hole Cleaning Model M' \A/A/"�O _ 1tal NnowA ProducerMD 44064 D enerovn niaa>inc VIRTUAL HYDRAULICS' •a p company ,/ 10.6 PPG LSND WSM rvD. 6696M1 We N 1T-41 &I Sae 681n Location North Stop,Alaska VRDH' ,,,„ . 6-31.-Nee•300 GPM•60 RPM•100 FPH Date'. 9M011013 C ry'. USA Hole Cleaning ConocoPhillips Alaska,Inc.21d1 I no _ — ROP 40 fVNr — ROP 60 Mx ,._. --___...._._.__ RAI m mina — ROP BO Mr ___._.._.—_' --”— — ROP 100 RAr ... I __— — ROP DOM. • Millignaillill cl -----� i _ _�� – _ - - Good Hole Cleanl t III Cts MI ._.11111._— —__� - _ Very Good Role GIs ming 200 220 NO 2030 260 .0 3. 340 Flow Rate(gegmin) 19 ConocoPhillips MiB Lost Circulation Decision Tree—Intermediate/Production Interval Losing fluid while drilling Measure rate of loss • ♦ ♦ Seepage losses < 20 bbl/hr static Partial losses 20-60 bbl/hr static Severe losses 60—200 bbl/hr or total loss of returns V If fault related drill across fault If fault related drill across fault 1-1.5 If fault related drill across fault 1-1.5 1-1.5 times the length of the times the length of the throw before times the length of the throw before throw before treating losses treating losses treating losses ♦ V V Spot 50 ppb pill*: Spot 80 ppb pill: Squeeze high-fluid-loss Spot 40 ppb pill*: pill: Slotted Liner Solid Liner Completion Completion SAFECARB 40 35 ppb DYNARED Med 12 ppb No FORM-A-BLOK SAFECARB 40 20 ppb No SAFECARB 250 15pp b SAFECARB 40 12 ppb success success 80 ppb in water weighted NUT PLUG F 8 ppb SAFECARB 250 10 ppb SAFECARB 500 30 ppb up to desired density G-SEAL 8 ppb SAFECARB 500 20 ppb No success ♦ T p No ♦ ♦ ISpot 80 ppb pill through circ.sub: / Spot plug: Contact Drilling/Asset Enaineer for aooroval ( I FORM A SET AK or M-I SEAL F&M 30 ppb FORM-A-PLUG II or DYNARED M 30 ppb NUTPLUG F 20 ppb Gunk Squeeze 41 *The particle sizing is smaller than Nut Plug Medium for these products 20 ConocoPhillips Mg SWACO HSE Issues Handling of Drilling Fluid Products Health and Safety •Drilling crews should be instructed in the proper procedures for handling fluid products. •Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. •PPE must be in good working order and be utilized as recommended by the PPE charts. •Product additions should be made with the intent to use complete unit amounts of products (sacks, drums,. cans), as much as possible in order to minimize inventory of partial units. •Ensure all MSDS sheets are up to date and readily available for workers to access for information. •Environmental •Ensure that all product stored outside is protected from the weather. •Do not store partial units (sacks) outside if possible. •When transferring fluids and/or cuttings from the rig to tanks, insure all hoses are properly secured. Perform-a, transfer checklist as needed in order to avoid spills. 21 ConocoPhillips Mi SWAG -'1) (77 W r4Y,0 1\ 3 PPE Chart Product Function Health Flammability Reactivity PPE CAUSTIC SODA Alkalinity control 3 0 1 X CITRIC ACID pH Adjuster 1 0 0 E DEFOAM X Defoamer 1 1 0 J DESCO CF Dispersant 1 1 0 E DUOVIS Viscosifier 1 1 0 E FLOWZAN Viscosifier 1 1 0 E G-SEAL Graphite loss circulation 1 1 0 E GELEX Bentonite Extender 1 1 0 E MYACIDE Biocide 3 0 0 J LUBETEX Lubricant 1 1 0 J MI WATE Weighting Agent *1 1 0 E MI GEL Viscosifier *1 1 0 E MI SEAL F, M,C Loss circulation material *1 1 0 E DYNA RED Loss circulation material *1 1 0 E NUT PLUG Loss circulation material *1 1 0 E DRISPAC SL Viscosifier, Fluid Loss Control *1 1 0 E SALT(NACL)&Brine Solution Densifier 1 0 0 E SAPP Dispersant *1 0 0 E SODA ASH Calcium precipitation 1 1 0 E SODIUM BICARB Alkalinity control 1 0 0 E HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS)HAZARD RATINGS 4-Severe hazard 3-Serious hazard 2- Moderate hazard 1 -Slight hazard 0- Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A-Safety Glasses B-Safety Glasses, Gloves C-Safety Glasses,Gloves, Synthetic Apron D-Face Shield,Gloves, Synthetic Apron E-Safety Glasses,Gloves, Dust Respirator F-Safety Glasses,Gloves, Synthetic Apron, Dust Respirator G -Safety Glasses, Gloves,Vapor Respirator H -Splash Goggles,Gloves, Synthetic Apron, Vapor Respirator I-Safety Glasses, Gloves, Dust and Vapor Respirator J-Splash Goggles,Gloves, Synthetic Apron, Dust and Vapor Respirator K-Air Line Hood or Mask,Gloves, Full Suit, Boots X-Consult your supervisor for special handling directions. a �1� 0 0 0 ConocoPhillips MI SWAB air INTEGRATED FLUIDS ENGINEERING (IFE) DRILLING FLUIDS PROPOSAL 2T-41 ConocoPhillips Alaska, Inc. 4000 . x I 'lljr { ` iii 1 „pe.7„,../gow/w, 1 * j /f f Prepared by: .. ./ 4// Customer Approval: Name: Scotten Blair `" , Name: Lindsey Hunter Position: Project Engineer Position: Drilling Engineer Company: M SWAco Alaska Company: ConocoPhillips Alaska, Inc. Date: eptember 12, 2013 / M-I Loglt# Version: 1.0 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties required. 1 ConocoPhillips C E Y, Mi SWAC_ �;� Well Summary The Kuparuk development well, 2T-41, is planned as a conventional grassroots slant producer, targeting the Kuparuk A and C sands. 2T-41 will be drilled by the rotary drilling rig Doyon 141 to a planned total depth of 7,098' MD/ 5,896'TVD. The 13-1/2" Surface interval will be drilled with a fresh water, unweighted DRILPLEX AR Spud Mud to a planned depth of 2,770' MD / 2,430' TVD, with 10-3/4" surface casing run and cemented. The 9-7/8" Intermediate interval will be drilled with a 9.6 PPG fresh water LSND fluid to a depth of 6,414' MD/ 5,342'TVD, with 7-5/8"intermediate casing run and cemented. At the intermediate TD, the mud weight will be increased to 10.5 PPG for trip margin. The 6-3/4"x 7-1/2" Production interval will be drilled with a 10.6 PPG fresh water LSND fluid to a planned TD of 7,098'MD/ 5,896'TVD, with a 5-1/2"production liner run and cemented. After drilling out of the intermediate casing shoe, treatments will be made to promote shale stability while drilling the HRZ and Kalubik shales, as well as LCM added preemptively to prevent lost circulation in the Kuparuk C sands. Casing and Project Summary ,, ,4>,^ Hole Casing Mud Size Size Casing MD TVD / Mud Weight (in) (in) Program (ft) (ft) System (lb/gal) 13-1/2 10-3/4 2,770' ,430' DRILPLEX AR 8.6—9.2 9-7/8 7-5/8 6,414 5,342 LSND 9.6— 10.5 6-3/4 x -1/2 7,098 5,896 LSND 10.6 7-1/2 Liner 2 � . ConocoPhillips Mi Surface Interval Summary Drilling Fluid System DRILPLEX AR Key Products DRILPLEX,GELPLEX, Soda Ash, Caustic Soda, RE-PLEX • Large gravel sizes can cause hole-cleaning problems • Sticky clays in the permafrost can slow ROP from bit and BHA balling • Swabbing in the clays may also be a problem Potential Problems • Hydrates may be encountered • Wash out in unconsolidated sections • Organics may thin mud • Excessive viscosity in lower clays • Maintain fluid temperature as low as possible (target < 70 F) Interval Objectives • Provide adequate viscosity to clean the hole of drill cuttings ▪ Minimize time in hole section • Condition mud to provide a good cement job SURFACE INTERVAL MUD PROPERTIES Funnel LSYP API Fluid Depth MD Mud Wt. Viscosity (2 X 3 RPM Yield Point Loss Chlorides (ft) (lb/gal) (sec/qt) —6 RPM) (Ib/10�ftz) (mL/30 min) (mg/I) pH 60— 120 (for 80'—2,770' 8.6—9.2 reference only, 30—50 40—80 NC <1000 10.8 fluid should be run off of LSYP) f • Recommended Initial DRILPLEX AR Formulation Base water Use"cold lake water"only,to keep the fluid temperature as low as possible Soda Ash 0.5 lb/bbl (add to base water) GELPLEX 12.5 lb/bbl (add to the base water and allow to hydrate > 12 hours) DRILPLEX 1.25 lb/bbl (starts the viscosity complex) RE-PLEX 0.25 lb/bbl (anionic suppressant) Soda Ash 1.25 lb/bbl (added to complete the complex) Caustic Soda As needed for pH of 10.8(fluid must have minimum pH of 10.8 for complete viscosity development) Note: Makeup water and water used in the pits while drilling should be as cold as possible. 3 ConocoPhillips Mi Recommended Solids Control Equipment • LO/TO the shakers. • Inspect all shaker bed decking panels for wear, replace as necessary.This will allow fir optimum screen performance during drilling operations. It is important to develop a good prevAntive maintenance schedule which includes replacing the decking panels before it becomes a performance related issue. • Install 84— 110 mesh screens or finer if losses over shaker are not a probleyn . Ensure screens are Shakers properly tensioned, per manufacture's best practice suggestions. Spray down new screens with fresh water before operating the shakers. • As fluid shears,screen up as necessary to higher mesh screen sizes. • Minimize flowline"jetting"during drilling,as additional mud flow will all shakers to be overrun with fluid. If possible,only jet the flowline during connections or in short bursts during drilling operations. • Check screens for holes between each connection. • Ensure that properly functioning gauge is available at the equipment's feed header. 75' of head is NECESSARY for proper 12"cone performance. Additional changes to feed pump may be necessary to create ample feed head. De-Sander • Inspect cone body sections and apexes for signs of wear, replace as necessary. Ensure that spare parts are available on site for future maintenance. • Monitor discharge weight and sample sand content to ensure proper operation of the De-Sander(s) • Inspect all cone bodies and apexes, replace as necessary. • 3/8"apex size may be best suited for finer particle size, as the De-Sander(s) up stream should allow for low sand size particles which will ensure that the De-Silter is working on the 24 - 45 micron sized particles without packing off. If packed off cones become a problem,open apexes up to%". • Ensure that the feet of head gauge is available at the De-Silter, not the pump. De-Silter • Ensure that De-Silter feed pump can achieve 95'of head. CRITICAL! Changes can be made quickly to the impeller or speed of the pump to improve the head capabilities. • Ensure that sufficient spares are located at rig site. These spares would include enough apexes to install 5/8",'/I",or 3/8"assemblies,depending on well formations,fluid rheology,and circulating rates. • Particle size of the solids in the active mud system will determine the best apex size to utilize. • Surface interval requires a greater through put during most operations, which requires the centrifuge to run at a lower speed (2,500 rpm). This setting allows the centrifuge to process more fluid, discharge more cuttings, and ultimately discharge more solids at the end of the day. The only drawback of the lower rpm's, is the cut point is reduce from 3-6 micron cut, to approximately 6- 10 micron. MI Swaco recommends and stands behind the suggestion to run the centrifuge at the lower speeds during the Centrifuge upper sections of hole. • Continuous operation of both centrifuges will help control ultra fine solids from overwhelming the mud system. Cycling the centrifuges from on-off-on will result in larger particles breaking down to a size which is very difficult to remove mechanically. If the mud weight is getting too low, reduce the feed rate, but continue to operate the centrifuges. FConocoPhilhips Ma EliArA__ Surface Interval Discussion / > Gravel may cause hole-cleaning problems. Extra circulation and wiping of the hole may be necessary to clean excess gravel out of the hole. > Hydrates may be encountered in this interval. Determine severity of any influx and follow the RP for handling Gas Hydrates. Do not add Lecithin to the Drilplex system without consulting the technical representative or the M-I SWACO project engineer(Pilot testing showed significant thinning of the sample when Lecithin was added). SCREENKLEEN has proven effective at reducing aeration and should be considered if aeration problems occur. Additional small quantities . RE-PLEX may be needed after the addition of SCREENKLEEN. All additions should be pilot tested prior to adding especially in the Drilplex system. Hydrates are seen to more readily break out at the shakers as compared to a "conventional"spud mud. Thinning of the Drilplex system may be used to allow hydrates to more readily break out of the mud if necessary. > Maintain flow rates of at least 650 gpm. Recommended average ROP for adequate hole cleaning is 150 fph. Reduce pu rates immediately if packing off occurs. > Dilution rates of 80-100 bbls/hr of"cold"Drilplex mud may be required to maintain a mud weight<9.4 ppg by TD and keep the mud temperature to <60-700F at TD. Ensure stable mud weights are maintained to avoid spiking up or dow > Sticky clays in the permafrost, and also in the zone below the permafrost, can slow ROP from bit and BHA balling. Incorporate Nut Plug M in sweeps(as allowed by MWD tools)to minimize clay to metal sticking if needed. > Drill ahead and adjust low end rheology, ROP, pipe rotation speed(80-100 rpm), pipe running speeds and pump rates needed to insure proper hole cleaning and ECD.Watch for any indications of wellbore instability problems.Any fluid weight adjustments should be performed in 0.1-0.2 lb/gal increments if absolutely necessary. D Lubricants may be used sparingly.A combination of LOTORQ&Lube 776 at 0.25 %each has shown significant improvements in COF in lab testing at the mud plant.The viscosity of the Drilplex system will be reduced with lubricant additions so EMI 1008(RePlex) may need to be added to regain viscosity. D. Based on results from past wells it is MI Swaco"s recommendation to thin back the Drilplex to LSYP value of< 20 wi water once casing is on bottom. Desco CF can be used as a chemical thinner.A water spacer of 50 bbls, pumped ahead of the mud push will provide further dilution of the mud. Chemical thinners should not be used prior to getting casing on bottom as overtreatment can easily occur with this system. Water should be used if thinning is necessary prior to the casing run. D MI Swaco recommends reducing rheology with water and adding citric acid and or Desco CF to the Drilplex used to displace the cement with to ensure there is no excess viscosity seen while running in to drill out. Drilplex Mud System mixing and volume addition plan > MI Swaco Drilplex MMO(Mixed Metal Oxide)fluid system is planned for this interval. Additional support will be provid- on the slope by MI Swaco's IFE coordinator. > The mud plant will be used for the initial mud system and volume additions necessary while drilling. The initial volu will be made at the mud plant according to the basic formula listed prior or from the triple strength Gelplex blended w cold lake water. See ta.'e for making 290 bbls Drilplex from triple strength Gelplex below: ConocoPhillips 1 Rig products needed for 290 BBLS of DrilPlex AR Mud made ,from "triple strength"prehydrated Gelplex 30.0 ppb GelPlex Slurry, 116 bbl Cold Lake Water,bbl 174 Soda Ash,50 lb sx 6 DrilPlex,25 lb sx 14 ScreenKleen,gal 122 / RePlex,gal 7 > The volume additions needed while drilling will be by the use of triple strength prehydrated Gelplex additions diluted wi cold lake water in the pill pit or whole mud brought out from the mud plant at the discretion of the mud engineer. T fluid will then be added to the active system as necessary while drilling. The formula for the triple strength Gelplex mix at the mud plant is given below: > Base water Use only"cold lake water"to keep the fluid ternPerature at a minimum. D Soda Ash 0.5 lb/bbl added to make up water D Gelplex 30 lb/bbl (add to the make-up water and allow to hydrate> 12 hrs) o Triple strength Gelplex can be added to the pill pit at the,rig and diluted back as necessary for viscosity adjustments to the active system. Drilplex will then be added to this volume in the pill pit to achieve a fin ration of 1:10 (ppb Drilplex to ppb Gelplex)along with 1.0—1.2 ppb Soda Ash in the pill pit to achieve th desired viscosity. RePlex at 0.2-0.25 ppb will also be added as an anionic suppressor. Expected ratio o water to triple strength Gelplex to achieve a LSYP of 25-50 is 1.5:1. Example using the previous table adjusted for 50 bbls pill pit volume: Rig products needed for 50 BBLS of DrilPlex AR Mud made Mill from "triple strength"prehydrated Gelplex 30.0 ppb GelPlex Slurry, 26 bbl Cold Lake Water,bbl 30 Soda Ash, 50 lb sx 1 DrilPlex;25 lb sx 2.5 ScreenKleen,gal i 21 RePlex,gal / 1.2 / > Drilplex low shear rheology of the 6&34-pm reading should be the same or very close to one another as measured by the Fann viscometer.This is a good in 'cation that the fluid is in good shape. The gel strengths should be elevated but flat ensuring a highly pump able fluiith excellent hole cleaning ability. Desirable properties of the Drilplex system are listed below: Spud to Base Permafrost o LSYP 30-50 i o PV ALAP(should be 10-20) o YP 40-80 / o Gels 30-50 / o 6 rpm 30-50;' o 3 rpm 30-50 The Drilplex system is suss ptible to anionic thinning and as such all anionic compounds, i.e. Pacs, Lignites and thinners should • avoided. Coal seams will nd to thin the complex and while not expected in this well the system will be lightly treated with the 1 anionic suppressant REP EX at the rig. Mud engineers should have a minimum of one pallet(4 Drums)of this product on site for contingency purposes 1 and , p. f @ f ConocoPhillips Mi sw�►�c___�,�,� Recommended Practices for Drilling Hydrates / Care should be taken in the event that hydrates occur. If the hydrate issue is deemed to be a major proble , use the following guidelines to help minimize the effect that any hydrates may have to the drilling operation. • Weigh the mud at both the possum belly and at the suction pit using pressurized and regular ud balances to determin the amount of gas that has become entrained in the mud. • Maintain the fluid temperature as low as practical (<70°F if possible). • Minimize circulation time and flow rate in the hydrate section to mitigate hydrate th ing. • Watch both drill rates and flow rates and make adjustments as needed to help di inish any problems that the surface equipment may have in handling the fluid and cuttings while circulating out any ydrates. • Reduce flow rate and continue drilling through the hydrates in order to minimize additional thawing and hole enlargement. • If the fluid viscosity becomes too thick with the hydrate influx then the Drilplex system viscosity can be reduced temporarily to allow the hydrates to break out and prevent pumping issues. • Use water additions only to adjust rheology(lower). , ConocoPhillips • • MI SWACO Virtual Hydraulics 13.5" Hole Model M'QUA/A r�A 2�1 Kupamk Producer YD:2165 R Operator C°nocoPhiOlpe Noe,In. VI UAL HYDRAULICS' :7�Y/e'�V�el // ND:24302 Wall Name:2T41 CPU-SO A Schlumleryer Compam 93 PPC %AR Blf Sia:13.5 In Location: MA N on:North SnapShot A coo.)on(c wadi.. 13,Or Male•650 GPM-SO RPM.150 FPN Rotf6)ISIidinO(54):80120 Ceunhy:USA 1 Depth Geometry Angle Densly P0 GP) Temperature Va Kole Cleaning PMawre Mab160030 TO MDRVD Cog own (°) 0610,1) VP,LOOP(1611002') CF) (Rhin) Index Apo aS% le O%L D5.45% PO OM, o o 60 ex et too 104 e m w 00 60 M 100 e M 1011 F P N6 10q Driling Fluid a 60 . iaaaa oRAPLE%AR Mud Weight 9]Ihlgel Test Temp 80°F PV 1®56°F) 10 cP YP 72 11d1001M Ab lSYP 43 Md100M System Data 1001 Flow Rale 650 gellmin Penetialson Rale 150 Mr IM Rotary Speed 80 rpm Ie% Weight on Bit 25 1000 RA 6,0Nome. 13-16.10.1U0 Imo, 0.0.0.0.0 Pre,Oem Lou.. lett Mnd10.4 Power LOW MA String 451 psi 200( -1_ MWD 410 psi Motor 181 pal Bit 491 pal F./ / Bu orlon zoo vol Annulus63 pal Mt Surface Equip 24 pal 260( =-.-::: r23CUe.TpuShonecl 2,,,,c250I Total E9 2196W22 pp9aall9 2ECD apid N 9t! 0.73 10.02 zt t — -ECD IX +1:e b9 war 2°4q -500.4 -2500 3005 tt+':M1Z l5 a:aki rt.302(MUM. warsra j fr, r �% f/'/ o f '4 .1 ` . ,j„ ,o, / / "40 4 / i 1 ConocoPhillips Mi E1NAG . Virtual Hydraulics 13.511 Hole Cleaning Model M' AiAC/"� nMupaluw Producer mo:n6sn of Hanle cono<ovnill P:AI..61no- VIRTUAL HYDRAULICS• —7�I�I �6-1M' 9.x PPGORILPLE%AR TVG 200 ft Well Name: xi 11 AfbMtembe.p�.G+mpa�y BM Six: 105 In Location: North Slope,Alaska ee u•,wu< wnr Hole•650 GPM•60 RPM•150 APH Pare: 9/1117011 Comity: USA VRDH' Hole Cleaning ConocoPhil lips Alaska,Inc.2141 1001 \_ � ^_ \\ POP 106 a'hr ole Clea lin• — ROP 150 M /_____./_____. — ROP 200 Men / 0%5 _ - -�� �� — Fair Hale Clean nq 00 Good sole Cleanln• _ 025- -,-__,______._— .. Very Good Holli Cleaning 100 500 609 xaO BOB 9OO Flow Rate(gadmin) //7":04* ,p... v 'Jr :), 4 ',A 4t../. e. ,r'' P ConocoPhillips L Mi SWACD - Intermediate Interval Drilling Fluid System LSND Key Products Flowzan, Drispac Plus Superlo, Caustic Soda, M-I WATE, DRILZONE, SCREENKLEEN, LOTORQ, LUBE 776, Busan 1060, Myacide 25GA • Hole cleaning Potential Problems • Well bore instability • Lost circulation • Well control • Adequately clean hole using pipe rotation,controljed ROP, and maintaining good fluid properties Interval Objectives • Minimize magnitude and severity of ECD/ pressure fluctuations to prevent fracturing weak formation bedding planes • Maintain minimal ECD by minimizing drill solids accumulation INTERMEDIATE INTERVAL MUD PROPERTIES Low Shear Rate Drill Depth MD Mud Wt. Yield Point(LSYP) API Fluid Loss Solids (ft) (lb/gal) (Ib/100ft2) (mL/30min) pH (%v/v) 2,770-6,414 9.6 - 10.5 5 - 10 < 6 9.5 - 10.0 < 7 / ' Intermediate Interval Fluid Formulation /' V, Soda Ash 0.25 ppb r Flowzan 0.75 - 1.25 ppb ,,},�, Drispac Plus Superb , 0.5 ppb .r f r RESINEX � rr 2 ppb o,z Soltex f ▪' r 'ff .2 ppb DRILZONE _,66rr, _ 1 % SCREENKLEEN r, 1 % M-I WATE as needed Caustic Soda if needed r; fJ'fJ} 1) SIO ,-..> I ! ` i ConocoPhillips Mi SWACD Recommended Solids Control Equipment • Inspect decking rubbers,c/o as necessary. • Install 200 -230 mesh screens if shakers will handle flow rate. Ensure screens are properly tensioned, per manufacture's best practice suggestions. Shakers Spray down new screens with fresh water before operating the shakers. • Adjust shaker deck angle to allow for good cuttings conveyance and minimal residence time on the screens. • Check screens for holes between each connection. De-Silter ✓ Only use if necessary. Use Centrifuge. • Intermediate intervals generally call for a "high-speed"centrifuge, which is rotating at approximately 3,200 rpm's. This allows the centrifuge to make the 3 - 6 micron cut, and eliminate a percentage of the "ultra,°fine" cuttings from the fluid. Through put must be decreased while running the/centrifuge at 3,200 rpm's, since there is a greater risk of"packing off"the centrifuge back drive and auger. Centrifuge • Refer to mud engineer for solids information to determine speed and feed rate of centrifuge. ■ Continual processing at low feed rates will yield better results than shutting centrifuge down and starting it up. Slow feed rate down to maintain an acceptable weight if needed. ■ Run continuously. Replenish M-I WATE as needed. ///,41/40:,,b. / • ":" ConocoPhillips Mi SWAG_=- Intermediate Interval Operations&Recommendations 1. Drill out casing with Spud Mud reserved from Surface interval. Treat cement contamination with dditions of CF Desco II, Citric Acid,and Sodium Bicarbonate as needed. SAPP may also be used. 2. Displace to LSND fluid for performing FIT/ LOT. 3. Maintain DRILZONE and SCREENKLEEN concentrations while drilling through the sticky uper clays. Discontinue once outside these clays. 4. Pump high viscosity or high viscosity, high density sweeps every "300' MD drilled while drilling through the sticky upper clays. Discontinue once these sweeps become ineffective or drilling progresses beyond this formation. 5. Maintain a thinner rheology through the sticky upper clay section to aid in dispersion of oversized, agglomerated cuttings. Target a low shear rate yield point (LSYP) of 5 - 7 (this should correlate to a yield point of 13 - 17). Increase rheology once drilling progresses beyond the sticky clay around "'4700'- 4400'MD to a LSYP of 8 - 10 (this should correlate to a yield point of 18-22). 6. Control MBT around 20 PPB with whole mud dilutions every-1000'MD drilled or more frequently as needed. 7. Maintain rheology with Flowzan as needed to balance hole cleaning and ECD. 8. Use Drispac to maintain fluid loss control. / r 9. Add Caustic Soda as needed to maintain pli 9.5 10.0. 10. Add Myacide GA 25 regularly and before any trips to control Bacterial activity. r r 11. Add LOTORQ or LUBE 776, or a combination of the two, if needed to control excessive torque or drag. Only add lubricants if confidant the excess torque and / or drag observed is not due to increased cuttings bed generation from recent high ROP, sliding, reduced drill string rotation,9t reduced flow rate. Be cautious that insufficient hole cleaning could be temporarily masked by the addition of the lubricants. Do not exceed total lubricant concentration of 3%v/v. 12. Keep accurate record of all water and whole mud additions to the active system and report in daily mud report. 13. Rotate drill string at maximum rotation as much'as possible to aid hole cleaning. 14. Control ROP as necessary to allow for adequate hole cleaning. i 15. Allow for extra circulation time, with drill string rotation, to catch up on hole cleaning following slides, high ROP, or drilling with reduced drill string rotation. / / / f' �:- 12 ConocoPhillips i MI SWAG / Virtual Hydraulics 9.875" Hole Model ME SV1/AC ...UP.Redoes Kt 6100 8 Operator Co wnPRYNp.Na q be RTUAL HYDRAULICS. taWWISPPG LS110 WTVP. .1 n WO Mom 11.11A Soblumb.ryer CemP.r1Y BR Sim 9175 In Location: Not.Soso Nolo smw..,,c 4.44,.."‘ L9Rxob•150GPI,100xP\-150FPx RotaySid109(l41: gyp Ca., USA $nap$hoY Depth Geometry Angle Density PVIW1 T.mp.rstom Va Pole Ch oMS Ptevun01b0990. 01) O Cs9own n 5b19a11 YP.LSYPIIbl10011'1 C() (WOO) LWn *,*.fl 17.10{ D6.51% A WI e n x Aa pa lu e N x • w _ in 1 1m P DNxty Flue Ts co LSNO sx. - - 41ud WelgM 10.5 Ibl9al \ ' ' Ten Temp 1W •f •u PV 1�110'FJ 00 cP YP 11 Ib11006' y LSD, 6 I5111001Y Synem oala M. flow Rale Iso Van,. Penebaban Pate tso I. No MI 4154Rotary Speed 100 rpm • Weight on Bit 10 1000 rot w 1 • Bit Maio 1.1.161111 I — 11.0.0.0.0 so I ORM Power Losses 1 x Prissu Losses DBI151rIn0 1113 pal xwD 116 pal sea ' Paolo/ 55pd 1 p Bit 610 psi Bit On/OR170 psi / Surfaces psi m 118 Surface psi UiubBled M — e Bled psi Total System 0 pal 1 1 to CSO ECO •Cut ulr1 on1 F,..a--__: Cs9 Shoe 1010 10.09 11.11 • - ID 51 11.06 11.10 F — ..a mW ---LLPGe 4444444445 v44. _ra. '»I,..j 1545 . 0.059W 00 ,,.n...„„d.m • 0< p • e/ / 4.0,.../.>., . . ..:,..,, ,„." . 4. fir? A..„:„:„,„,. /..,A,„,. �� ie..,# „2,-...w," , ...7.(71 /9--,..w.,. ,,/. ,ei • Nte . ) .qi:". .1.. V".„ r `'..:'..Z.,;* 0 *Ai/. ConocoPhillips MI SWACO Virtual Hydraulics 9.87551 Hole Cleaning Model M' /A� Kupa kPratlu MP.SAN II Op nor. C mPM1Mp Aaglnc Y{�TUAL HYDRAULICS �7�Y/'— 10.5 PPG LOP WPM N0:553A2075 Wrll Name ]i 01 / A Sealumaeeser CornmealBa SbK 5US le Location North Slop,AlwW �aawua vaw„c 9,n'Hole.150 GPM.100 RPM.150 FPN We MuVID11 Country. USA VRDH* / Hole Cleaning ConocoPhillips Naska,Inc.2T et a0 1_ -- — IIIIIIIIM — ROP 100 Mr Po• Cleanln• — ROP150Me _ — ROP 200 Mr — RCP 25C Mo 0]5 Fair Hole Cleaning ow m Good He le a • 005` ��_— I �'�.—^__ Very Good Hole Cleaning 01. 000 700 600 900 Flow Rate(gamin) $7f /71, io ',‘,)'////1://1/;:' „a',,,,. .. 'V a, a/ .0,, '4.0, .2'. • . f ) 14 . .` . t I ConocoPhillips Mg SWAC9. Production Interval Drilling Fluid System LSND Key Products Flowzan, Drispac Plus Superlo, Caustic Soda, M-I WATE, DRILZON., SCREENKLEEN, RESINEX, Soltex, LOTORQ, LUBE 776, SACK BLACK, Busan 1060 acide 25GA • Hole cleaning Potential Problems • Well bore instability • Lost circulation • Torque and Drag • Adequately clean hole using pipe rotation, controlle OP, and maintaining good fluid properties Interval Objectives • Minimize magnitude and severity of ECD/ pressu e fluctuations to prevent fracturing weak formation bedding planes • Maintain minimal ECD by minimizing drill solids accumulation INTERMEDIATE INTERVAL MUD PROPERTIES Low Shear Rate Drill Depth MD Mud Wt. Yield Point(LSYP) API Fluid Loss Solids (ft) (lb/gal) (Ib/100ft2) (mL/30min) pH (%v/v) 6,414-7,098 10.6 5-6 < 6 9.5 - 10.0 < 6 Production Interval Fluid Formulation f. �r Soda Ash 0.25 ppb Flowzan 0.75 - 1.25 ppb . Drispac Plus Superlo 0.5 ppb RESINEX 4 ppb f. r{ . f , Soltex v py,; 6 ppb SACK BLACK ppb „ DynaRed Fine f;;,, 6 ppb SAFE-CARB 40 • 20 ppb M-I WATE as needed Caustic Soda Y if needed ///1</:;.; 15 ConocoPhillips MI Recommended Solids Control Equipment • Inspect decking rubbers,c/o as necessary. • Install 200 -230 mesh screens if shakers will handle flow rate. Ensure screens are properly tensioned, per manufacture's best practice suggestions. Shakers Spray down new screens with fresh water before operating the shakers. • Adjust shaker deck angle to allow for good cuttings conveyance and minimal residence time on the screens. • Check screens for holes between each connection. De-Silter • Only use if necessary. Use Centrifuge. • Production intervals generally call for a "high-speed" centrifuge, which is rotating at approximately 3,200 rpm's. This allows the centrifuge to make the 3 - 6 micron cut, and eliminate a percentage of the "ultra fine" cuttings from the fluid. Through put must be decreased while running the centrifuge at 3,200 rpm's, since there is a greater risk of"packing off"the centrifuge back drive and auger. Centrifuge • Refer to mud engineer for solids information to determine speed and feed rate of centrifuge. • Continual processing at low feed rates will yield better results than shutting centrifuge down and starting it up. Stow feed rate down to maintain an acceptable weight if needed. • Run continuously. Replenish M-I WATE as needed. .;•.40. /...6,,-d'_,4 / ",;.,,,,,,,„,„7,,..,,„,s , /1"PA.,., ,/,./. -,...fty„..4. , / „.„;. r 4, . " 70:r ' nr,c1.6 ConocoPhillips Production Interval Operations& Recommendations / 1. Drill out casing with LSND fluid reserved from Intermediate interval. Treat cement contamination with additions of CF Desco II,Citric Acid, and Sodium Bicarbonate as needed. SAPP may also be used. 2. After drilling out most of the cement, treat system with a spike fluid to achieve the concentrations of SACK BLACK, DynaRed Fine,and SAFE-CARB 40 listed in formulation above. 3. Have additional M-I WATE on hand to increase density as required by observed reservoi pressure. 4. Maintain rheology with Flowzan as needed to balance hole cleaning and ECD. 5. Use Drispac to maintain fluid loss control. 6. Add RESINEX, Soltex, SACK BLACK, DynaRed Fine, and SAFE-GARB 40 conti ously while drilling ahead to maintain concentrations in the active system as this material is removed by the solids control equipment and diluted by rig water additions. 7. Add Caustic Soda as needed to maintain pH 9.5 - 10.0. 8. Add Myacide GA 25 regularly and before any trips to control bacterial activity. 9. Add LOTORQ or LUBE 776, or a combination of the two, if needeq to control excessive torque and / or drag. Only add lubricants if confidant the excess torque and/or drag being ob erved are not due to increased cuttings bed generation from recent high ROP, sliding, reduced drill string rotation, or reduced flow rate. Be cautious that insufficient hole cleaning could be temporarily masked by the addition of lubricants. Do not exceed total lubricant concentration of 3% v/v. 10. Keep accurate record of all water and whole mud additions to the active system and report in daily mud report. 11. Rotate drill string at maximum rotation as much as possible to aid hole cleaning. 12. Control ROP as necessary to allow for adequate hole cleaning. 13. Allow for extra circulation time, with drill string rotation, to catch up on hole cleaning following slides, high ROP, or drilling with reduced drill string rotation. i Y 17 !; ConocoPhillips MISW9. Virtual Hydraulics 6.75" Hole Model Mil SVVA_Crf_._ _ n+f NvpuuwPo V.r ND: Haan Well C9wwPI.mIp,AAA ma VIRTUAL HYDRAULICS' ~----ter••' 106 PPG LSNDWBM rvD: 5696 II Operator Nam.: n11 aA Schlumberger GpmP.rrY US.: 7.5 1n Lomnom MA SM... asw.rllp +a..W„u i.11t•IIae.JSOcvY.eOnrll.IWfPH RVC4ySIldLrpry: Sm0 Cmonry. USA $nap$h0 Dept Go*, ADM Dmrny ENDV1 T.panu. N Ile. Pressure NADA. Ill) Wilt C19D610 0 MA YP,LSTP P.M CD (fJS) Ann.1l•. en•21S DS•SMA A f�4.1 e u w — lu e a a os a IY a AO . f • m y YYIf IY —4-I) ill I , Drilling FW. w ,. LSND NM III MAMA.A. 101 W19a1 AAA. 00 •F fur - III I W(env') D I a WIMP YPele hl aM '. LAP p m as S 171005 M llw u rrw '. elion Rale 100 pallmm Pen am III Rotary Speed W rpo 1 Weigh!on BN5 1000 1131 W1 .I MI Naaalel 11.12.11.11.11 app .- Modified Losses `I fief Power Lan -� 1 IDlrin9 t1611 psi t168 pal Jl Al / Molar BII 361 psi _ • .I I Al o.Vrd. 1W psi Annulus J00 p11 Surlau ERulp 15 Pei U.,.EAU b p11 Ad 111i .w � 2fw Total System 1J11 011 J ew rm 1. A1VAI I TO ESD ECD Cut mg Cay Shoe106010 6a 1151 17 57 It]I UN 0* —110 —P... I. .IN.a . re ,,a,,.,ps. �� no —5 5 f . ..” ip,o,„ :,„ ..„ . �; 1r � , • f fir f :'. r ,�^4 # 18 ConocoPhillips MSW Virtual Hydraulics 6.75" Hole Cleaning Model MI EVViAC-__.Q 2341 NuPamN Peedaeaa 00 I106 ft Gw ax cmwmPoewo woio VIRTUAL HYDRAULICS to.6 PPG LGND WBb1 1W:5896 n Well Nam 3T.41 A Sehlumb•ry•r Com0909V ._-- ell SlZ 751n Loulbn. NodM1 SbPe.Alaska VRDH* a.mmwuc +.944.. Inn'Hole•MOM-80 8811-100 FPN Date'. 9111000 ,0949839 USA Hole Cleaning ConocoPhillips Alaska,Inc.2T-41 100 `_Il_ s-_ --C`- `-1 _`-"----------• — R0Pr MT .- = -IM�-��� •� --------• - ORMnil 111 ■■■■■■■■■MCM ■■\_■■■■■■■L__--Al 025-- -11"---- -- M-- 1 �- ---`---MII`---I♦PI --`---NIWNM•JII -------MINIMINIIIIIIIIM1�11111--��-11111--TEM -----`----I♦LILI --- ----11111613.11.1-_-�I•� ------==----��---���--0M� °�-------1111EM --MININZW��---61M�---�� ---------- ----FAMELINI----1iiiiMEILI -----------IOM•- •.MINI---MIT`-MINI---M -------------mtiliZ:RE------M�.'.__�—E 0 25--� -MINI�,--- __ �-- - Ve Good le Cle Nog o / 200 300 320 340' 360 350 100 420 Flow Rale(gallmin) . . JfJ .* :het Ace } Jf •�' r f `; ,, 0 6 41 :, "747,4,./ ', -,,,,,,,& ./i .....„:, i,„, ,, v v: ,, ,e•-• „, vo, ,,v ,,o, No ,7., ,, „,,, „ JJf*2 /4 e , 19 ConocoPhillips MI SWACO - Lost Circulation Decision Tree—Intermediate/Production Interval Losing fluid while drilling Ili Measure rate of loss V • V • Seepage losses < 20 bbl/hr static Partial losses 20-60 bbl/hr static Severe losses 60—200 bbl/hr or total loss of returns fjf{r • :, • If fault related drill across fault ' ' If fault related drill across fault 1-1.5 If fault related drill across fault 1-1.5 1-1.5 times the length of the times the length of the throw before times the length of the throw before throw before treating losses treating losses treating losses • *: Spot 50 ppb pill*: / Spot 80 ppb pill: Squeeze high-fluid-loss Spot 40 ppb pill pill: Slotted Liner Solid Liner Completion Completion SAFECARB 40 35b DYNARED Med 12 ppb pp No FORM-A-BLOK SAFECARB 40 20 ppb No SAFECARB 250 15b SAFECARB 40 12 ppb success ► pp success 80 ppb in water weighted NUT PLUG F 8 ppb SAFECARB 250 10 ppb SAFECARB 500 30 ppb up to desired density G-SEAL 8 ppb SAFECARB 500 20 ppb No • ' • r r No success Et f >�l/ T • A. Spot 80 ppb pill through circ.sub: / Spot plug: I Contact Drillina I Asset Engineer for aooroval li FORM A SET AK or M-I SEAL F&NI 30 ppb FORM A PLUG II or DYNARED NI 30 ppb NUTPLUG F 20 ppb Gunk Squeeze It / ,The particle sizing is smaller than Nut Plug Medium for these products i 20 < onocoP Chillips MI BW HSE Issues Handling of Drilling Fluid Products Health and Safety •Drilling crews should be instructed in the proper procedures for handling fluid prod.cts. •Personal Protective Equipment (PPE) charts should be posted in the pit room he mud lab, and the office the Drilling Forman. •PPE must be in good working order and be utilized as recommended by th- PPE charts. •Product additions should be made with the intent to use complete unit amounts of products (sacks, dru cans), as much as possible in order to minimize inventory of partial wilts. •Ensure all MSDS sheets are up to date and readily available for workers to access for information. •Environmental •Ensure that all product stored outside is protected from t .._, weather. •Do not store partial units (sacks)outside if possible. , •When transferring fluids and/or cuttings from the rig to tanks, insure all hoses are properly secured. Perfor transfer checklist as needed in order to avoid spills. i / j �' / , 21 ConocoPhillips MI SW 7 0 0 • PPE Chart Product Function Health Flammability Reactivity PPE CAUSTIC SODA Alkalinity control 3 0 1 X CITRIC ACID pH Adjuster 1 0 0 E DEFOAM X Defoamer 1 1 0 J DESCO CF Dispersant 1 1 0 E DUOVIS Viscosifier 1 1 0 E FLOWZAN Viscosifier 1 1 0 E G-SEAL Graphite loss circulation 1 1 0 E GELEX Bentonite Extender 1 1 0 E MYACIDE Biocide 3 0 0 ] LUBETEX Lubricant 1 1 0 ] MI WATE Weighting Agent *1 1 0 E MI GEL Viscosifier *1 1 0 E MI SEAL F, M,C Loss circulation material *1 1 0 E DYNA RED Loss circulation material *1 1 0 E NUT PLUG Loss circulation material *1 1 0 E DRISPAC SL Viscosifier, Fluid Loss Control *1 1 0 E 11 SALT(NACL)&Brine Solution Densifier 1 0 0 E SAPP Dispersant *1 0 0 E SODA ASH Calcium precipitation 1 1 0 E SODIUM BICARB Alkalinity control 1 0 0 E 7,,s, ,7": , ./....,. _ ,,,,.4.7' ,„ "00:),,, HAZARDOUS MATERIALS IDENTIFICATION SYSTE, //.. (HMIS) HAZARD RATINGS rard {'�� ,r� / ". / 3-Serious hazard r, 'f�'� f irk- r' �! / /'�° rr�r 2 Moderate hazard s r.fr': J4, r 1 -Slight hazard ��� ;r, 0-Minimal hazard �r,, * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A-Safety Glasses B-Safety Glasses,Gloves / C-Safety Glasses, Gloves,Synthetic Apron D-Face Shield,Gloves,Synthetic Apron r Y E-Safety Glasses, Gloves, Dust Respirator F-Safety Glasses,Gloves, Synthetic Apron, Dust Respirator G-Safety Glasses,Gloves,Vapor Respirator H -Splash Goggles,Gloves,Synthetic Apron,Vapor Respirator I-Safety Glasses,Gloves, Dust and Vapor Respirator J-Splash Goggles,Glovis,Synthetic Apron, Dust and Vapor Respirator K-Air Line Hood or Mask,Gloves, Full Suit, Boots X-Consult your supervisor for special handling directions. 0 JIP 22 ConocoPhillips Schlumberger CemCAD well cementing recommendation for 5.5" Liner Operator : CPAI Well : 2T-41 Country : USA Field : Kuparuk State : Alaska Prepared for : Lindsey Hunter Location : Kuparuk Proposal No. : v2 Service Point : Prudhoe Bay Date Prepared : 9.12.13 Business Phone : (907)659-2434 Prepared by : Jenna Houston(reviewed by Stephen Lauper) Phone : (907)223-8916 E-Mail Address : jhouston2©slb.com • {7 C 1-/ATE Disclaimer Notice: Schlumberger submits this document with the benefit of its judgment.experience,and good oilfield practices. This information is provided in accordance with generally accepted industry practice,relying on facts or information provided by others,limitations,computer models,measurements,assumptions and inferences that are not infallible. Calculations are estimates based on provided information.All proposals,recommendations.or predictions are opinions only. NO WARRANTY IS GIVEN CONCERNING ACCURACY OR COMPLETENESS OF DATA,INFORMATION PRESENTED,EFFECTIVENESS OF MATERIAL,PRODUCTS OR SUPPLIES,RECOMMENDATIONS MADE,OR RESULTS OF THE SERVICES RENDERED. Freedom from infringement of any intellectual property rights of Schlumberger or others is not to be inferred and no intellectual property rights are granted hereby. Mark of Schlumberger Page 1 27-41 cement vl.cfw;09-12-2013; LoadCase 5.5in Liner(al;Version wcs-cem473_08 Client : CPAI Well : 2T-41 Schi Tigger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Section 1 : well description Configuration : Liner Stage : Single Rig Type : Land Mud Line : 0.0 ft Total MD : 7098.0 ft BHST : 144 degF Previous String MD OD Weight ID (ft) (in) (lb/ft) (in) 6414.0 7 5/8 29.7 6.875 Drill Pipe MD OD Weight ID Grade Collapse Burst (ft) (in) (lb/ft) (in) (psi) (psi) 6214.0 4 14.0 3.340 E-75 11360 10830 Liner Hanger : 6214.0 ft Landing Collar MD : 7018.0 ft Casing/liner Shoe MD : 7098.0 ft Casing/Liner MD OD Joint Weight ID Grade Collapse Burst Thread (ft) (in) (ft) (lb/ft) (in) (psi) (psi) 7098.0 5 1/2 40.0 15.5 4.950 TN- 4040 4810 BTC 110SS Page 2 21-41 cement v1.cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 Client : CPAI Well : 2T-41 Scam huger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Mean OH Diameter : 6.750 in Mean Annular Excess :40.0% Mean OH Equivalent Diameter:7.189 in Total OH Volume : 34.3 bbl (including excess) Max. Deviation Angle : 45 deg Max. DLS : 3.512 deg/100ft Directional Survey Data MD TVD Deviation Azimuth Dogleg Sev. (ft) (ft) (deg) (deg) (deg/100ft) 0.0 0.0 0.0 0.0 0.000 100.0 100.0 0.0 0.0 0.000 200.0 200.0 0.0 0.0 0.000 300.0 300.0 0.4 260.0 -0.440 400.0 400.0 2.4 260.0 2.000 500.0 499.8 4.4 260.0 2.000 600.0 599.4 5.5 260.0 1.060 700.0 698.9 5.5 260.0 0.000 800.0 798.4 6.7 254.4 1.292 900.0 897.4 9.2 247.3 2.746 1000.0 995.7 11.9 243.3 2.757 1100.0 1093.0 14.7 238.7 2.991 1200.0 1189.1 17.5 235.5 2.993 1300.0 1283.6 20.5 233.2 3.006 1400.0 1376.4 23.4 231.4 3.002 1491.7 1459.7 26.1 230.2 2.991 1500.0 1467.1 26.3 230.1 3.055 1600.0 1555.6 29.3 228.9 2.997 1700.0 1641.5 32.2 228.0 3.008 1800.0 1724.7 35.2 227.2 2.993 1900.0 1804.9 38.2 226.5 3.008 2000.0 1881.8 41.2 225.9 2.995 2100.0 1955.4 44.1 225.4 3.002 2200.0 2026.7 44.9 225.3 0.775 2300.0 2097.5 44.9 225.3 0.000 2400.0 2168.4 44.9 225.3 0.000 2500.0 2239.2 44.9 225.3 0.000 2600.0 2310.0 44.9 225.3 0.000 2700.0 2380.9 44.9 225.3 0.000 2769.6 2430.2 44.9 225.3 0.000 2800.0 2451.7 44.9 225.3 0.000 2900.0 2522.5 44.9 225.3 0.000 3000.0 2593.4 44.9 225.3 0.000 3100.0 2664.2 44.9 225.3 0.000 3200.0 2735.0 44.9 225.3 0.000 3300.0 2805.9 44.9 225.3 0.000 3400.0 2876.7 44.9 225.3 0.000 3500.0 2947.5 44.9 225.3 0.000 3510.7 2955.1 44.9 225.3 0.000 3600.0 3018.4 44.9 225.3 0.000 3616.6 3030.1 44.9 225.3 0.000 3630.7 3040.1 44.9 225.3 0.000 3700.0 3089.2 44.9 225.3 0.000 3800.0 3160.0 44.9 225.3 0.000 3900.0 3230.9 44.9 225.3 0.000 4000.0 3301.7 44.9 225.3 0.000 4100.0 3372.5 44.9 225.3 0.000 4200.0 3443.4 44.9 225.3 0.000 Page 3 2T-41 cement vt.cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 Client : CPAI Well : 2T-41 Schlumberger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Directional Survey Data MD TVD Deviation Azimuth Dogleg Sev. (ft) (ft) (deg) (deg) (deg/100ft) 4300.0 3514.2 44.9 225.3 0.000 4400.0 3585.0 44.9 225.3 0.000 4500.0 3655.9 44.9 225.3 0.000 4600.0 3726.7 44.9 225.3 0.000 4700.0 3799.2 42.1 227.2 -3.075 4800.0 3875.2 39.0 229.7 -3.503 4900.0 3954.5 36.0 232.5 -3.502 5000.0 4036.9 33.0 235.8 -3.499 5100.0 4122.1 30.1 239.6 -3.500 5200.0 4209.8 27.4 244.1 -3.499 5258.8 4262.3 25.9 247.2 -3.500 5300.0 4299.6 24.8 249.6 -3.492 5400.0 4391.1 22.5 256.1 -3.501 5500.0 4484.2 20.5 263.9 -3.499 5589.3 4568.3 19.0 272.1 -3.502 5600.0 4578.3 18.9 273.2 -3.489 5700.0 4673.2 17.8 283.8 -3.499 5800.0 4768.6 17.4 295.3 -3.500 5900.0 4863.9 17.6 306.9 3.502 6000.0 4959.0 18.5 317.8 3.498 6100.0 5053.4 20.0 327.5 3.499 6200.0 5146.8 21.9 335.7 3.500 6300.0 5238.8 24.1 342.6 3.500 6400.0 5329.1 26.6 348.3 3.497 6414.4 5342.0 27.0 349.0 3.503 6500.0 5417.4 29.3 353.0 3.506 6600.0 5503.3 32.2 357.1 3.502 6653.3 5548.0 33.7 358.9 3.485 6700.0 5586.6 35.1 0.5 3.504 6776.2 5648.0 37.4 2.8 3.501 6800.0 5666.8 38.2 3.4 3.512 6840.5 5698.5 38.9 4.1 2.105 6900.0 5744.5 40.0 5.0 2.098 6901.3 5745.5 40.0 5.0 0.000 6920.9 5760.5 40.0 5.0 0.000 6960.0 5790.5 40.0 5.0 0.000 7000.0 5821.1 40.0 5.0 0.000 7005.7 5825.5 40.0 5.0 0.000 7068.4 5873.5 40.0 5.0 0.000 7098.0 5896.1 40.0 5.0 0.000 Formation Data MD Frac. Pore Name Lithology (ft) (lb/gal) (lb/gal) 6507.0 12.50 8.80 Kuparuk C Sandstone 6616.0 13.00 10.30 Kuparuk A Sandstone 7098.0 12.50 8.80 TD Sandstone Page 4 2T-41 cement v1 cfw;09-12-2013; LoadCase 5 5in Liner(al;Version wcs-cem473_08 Client : CPAI Well : 21-41 Schlumberger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Geothermal Temperature Profile MD TVD Temperature Gradient (ft) (ft) (degF) (degF/100ft) 0.0 0.0 20 0.0 1492.0 1460.0 32 0.8 6414.0 5341.6 132 2.1 7098.0 5896.1 144 2.1 Page 5 21-41 cement vi.cfw;09-12-2013; LoadCase5.5inLiner(a);Version wcs-cem473_08 Client : CPAI Well : 2T-41 Schlumberger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Section 2: centralizer placement Top of centralization :6214.0 ft Bottom Cent. MD :7088.0 ft Casing Shoe :7098.0 ft NB of Cent. Used :44 NB of Floating Cent. :44 Centralizer Placement Bottom MD Nbr. Cent./ Cent. Name Code Min.STO @ Depth (ft) Joint (%) (ft) 7098.0 44 2/1 5.5"CENTEK 62.8 7098.0 Centralizer Description Centralizer Tests Cent.Name Code Casing Max. Min.OD Rigid Origin Hole Size Running Restoring OD OD (in) (in) Force Force (in) (in) (lbf) (Ibf) , 5.5"CENTEK 5 1/2 6.750 5.620 No 6.750 0.00 1050.00 ft a0 61 t 80 90 100 —-iserx.z_. .._rt. -1At Car t. CJ - O O _ Pipe Standoff Page 6 2T-41 cement vt.cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 Client : CPAI Well : 21-41 SalkPier String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Section 3: fluid description Mud DESIGN Fluid No: 1 Density : 10.60 lb/gal Rheo.Model :HERSCHEL_B. k : 1.51 E-2 Ibf.s^n/ft2 At temp. :80 degF n :0.527 Ty :3.92 lbf/100ft2 Gel Strength :27.75 lbf/100ft2 MUD Mud Type :WBM Job volume :76.5 bbl Water Type : Fresh MUDPUSH II DESIGN Fluid No:2 Density : 11.50 lb/gal Rheo.Model :HERSCHEL_B. k :3.51 E-2 Ibf.s^n/ft2 At temp. :65 degF n :0.406 Ty : 16.35 lbf/100ft2 Gel Strength :29.67 Ibf/100ft2 Job volume :40.0 bbl Tail Slurry DESIGN Fluid No:4 Density : 15.80 lb/gal Rheo. Model :HERSCHEL_B. k : 1.53E-2 lbf.s^n/ft2 At temp. :78 degF n :0.779 Ty : 1.531bf/100ft2 Gel Strength :(Ibf/100ft2) DESIGN BLEND SLURRY Name :G Mix Fluid :5.076 gal/sk Job volume :23.8 bbl Dry Density : 199.77 lb/ft3 Yield : 1.16 ft3/sk Quantity : 114.88 sk Sack Weight :94 lb Solid Fraction :41.6% BASE FLUID Type :Fresh water Density :8.32 lb/gal Base Fluid :5.076 gal/sk Additives Code Conc. Function D046 0.200%BWOC Antifoam D065 0.400%BWOC Dispersant D167 0.600%BWOC Fluid loss Fresh Water DESIGN Fluid No:5 Density :8.32 lb/gal Rheo.Model :NEWTONIAN At temp. :(degF) Viscosity :5.000 cP Gel Strength :(Ibf/100ft2) Job volume : 10.0 bbl Page 7 21-41 cement v1 cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 Client : CPAI Well : 21-41 SchINrger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Section 4: fluid sequence Original fluid Mud 10.60 lb/gal k:1.51E-2 Ibf.s^n/ft2 n :0.527 Ty:3.92 lbf/100ft2 Displacement Volume 86.5 bbl Drill Pipe Volume 67.3 bbl Total Volume 150.3 bbl TOC 6071.6 ft Fluid Sequence Name Volume Ann.Len Top Density Rheology (bbl) (ft) (ft) (lb/gal) MUDPUSH II 40.0 1317.0 4754.6 11.50 k:3.51 E-2 Ibf.s^n/ft2 n:0.406 Ty:16.35 lbf/100ft2 Tail Slurry 23.8 1026.4 6071.6 15.80 k:1.53E-2 Ibf.s^n/ft2 n:0.779 Ty:1.53 lbf/100ft2 Fresh Water 10.0 6597.9 8.32 viscosity:5.000 cP Mud 76.5 0.0 10.60 k:1.51 E-2 Ibf.s^n/ft2 n:0.527 Ty:3.92 lbf/100ft2 Static Security Checks: Frac 292 psi at 7098.0 ft Pore 274 psi at 6616.0 ft Collapse 3409 psi at 7018.0 ft Burst 4810 psi at 7018.0 ft Csg.Pump out 32 ton Check Valve Diff Press 313 psi Page 8 2T-41 cement vl.cfw:09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 Client : CPAI Well : 21-41 Silobeli ' String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Section 5: pumping schedule Pumping Schedule Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments (bbl/min) (bbl) (min) (bbl). Temp. (degF) MUDPUSH II 5.0 40.0 8.0 40.0 80 Pause 0.0 0.0 5.0 0.0 80 Tail Slurry 5.0 23.8 4.8 23.8 80 Pause 0.0 0.0 5.0 0.0 80 Fresh Water 5.0 10.0 2.0 10.0 80 Pause 0.0 0.0 5.0 0.0 80 Mud 5.0 63.0 12.6 63.0 80 Mud 1.5 13.5 9.0 76.5 80 Total 00:51 150.3 bbl hr:mn Dynamic Security Checks: Frac 4 psi at 7098.0 ft Pore 85 psi at 6616.0 ft Collapse 3409 psi at 7018.0 ft Burst 4457 psi at 6214.0 ft Temperature Results BHCT 113 degF Simulated Max HCT 104 degF Simulated BHCT 103 degF Max HCT Depth 6808.3 ft CT at TOC 103 degF Max HCT Time 00:51:20 hr:mn:sc Static temperatures: At Time 1 (hr:mn) 1 (hr:mn) Geo.Temp. Top of Cement (degF) (degF) 1 124 degF Bottom Hole (degF) (degF) 144 degF Page 9 2T-41 cement v1 cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_00 Client : CPAI Well : 2T-41 ScbIIllirger String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) ft (x 1000)psi 0 2 4 I 0- O � Hydrostatic -Calc.Purrp Press. -Mn.Hydrostatic ( Calc.CemHP - -Max.Dynamic -Nin.Dynamic co I --Frac N(L) N< _ ..I 1 -Pore N 0..0 O- \______ N O I 0 20 40 60 Time(min) _ o Depth= 7098 ft O N -Annular Velocity o_ a E t1or1 N 1 > 1c i-\/ ci 7 ‘ <O n- O — ' l , 0 20 40 60 Fluid Sequence Dynamic Well Security Time(min) vDepth= 7098 ft 1 I _ I 11 as I I r 1 1 I- C �o CLr T I 0 5 10 15 20 25 30 35 40 45 50 55 Time(min) Fluids at 7098 ft -Acquired a Out Arryurwrl Q h .' j _._._. _._... —QOut c — — --- a id } , 12C N , II 0 5 10 15 20 25 30 35 40 45 50 55 Time(min) Page 10 2T-41 cement v1 cfw;09-12-2013; LoadCase 5.5in Liner Cal;Version wcs-cem473_08 L Client : CPA! Well : 2T-41 Schlamhcrgcr String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a} Section 6: WELLCLEAN II Simulator % % ft 0 60 70 80 90 100 0 25 50 7I15 100 o —Std Betw.Cent. —Mud Contamination 0 co —Cement Coverage —Uncontaminated Slurry i 0 0 ! I 0 CO CO ( on o i CV Cement Coverage Uncontaminated Slurry Fluids Concentrations Risk Mud on the Wall 0 i 52001 r -6200 6200 6200 6300- -8300 6300 6300 6400- -8400 6400 8400 5500- -6500 5500 6500 :> - C' •; 6600- -6600 6600 6600 =- r - s I r ;i 6700- -6700 6700 6700 0 CS - - 0 6 0 6600- -6800 6800 6800 6900- -6900 6900 6900 7000- -7000 7000 7000 7100- -7100 7100 7100 t 1 o ; m a ; m riZ ® Mud Tail Slurry I IHigh =I Low 1 NM Fresh Wateriii MUDPUSH II [ Medium ® None Page 11 2T-41 cement vt.cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 Client : CPAI Well : 21-41 Schl kergcr String : 5.5 District : Prudhoe Bay Country : USA Loadcase : 5.5in Liner(a) Tolerances - Spacer Max Rate is 5 BPM - Cement rate 5 BPM (remain within +1-0.2ppg Density Range,to be checked periodically with a mud balance) - Max Shut down time is 30-minutes; if time is being approached, contact Town Engineer - Max displacement Rate is 5 BPM, must slow to 2 BPM as indicated - Min Displacement Rate to be determined based on remaining Thickening Time from field blend testing - Mud to be conditioned prior to cementing - Maintain returns during cement job if possible Contingencies In the event that a problem occurs during mixing, pumping, or displacement, contingency plans should be systematically followed. If a shutdown occurs during the job, make note in the CemCAT report of when the stoppage occurred and how much time is available to remedy an issue before the thickening time becomes a problem. 1) If losses are encountered prior to cementing a) Utilize CemNET(1-2 lb/bbl; 2 lb MAX) b) Slow rate until full circulation is regained c) Determine max rate with full circulation and pump job at this rate if possible 2) Cement unit failure while mixing a) Attempt to continue pumping cement at minimum rate b) Attempt to remedy issue in less than 30 mins c) If issue with mixing system—switch to back-up mixing system d) If issue with triplex pump—continue with secondary triplex on unit 3) Mud Pump failure during displacement a) Discuss rig up in the event of cement unit displacement in PJSM b) Attempt to continue displacement with secondary rig pump c) Attempt to remedy issue(downtime<10 mins) d) Note displacement volume pumped by mud pumps: verify with well site leader e) Subtract pumped volume from total volume,which will be the volume pumped by the cement unit f) Rig up hoses to get mud to Cement Unit and begin displacement with cement unit(verify volume with well site leader) Page 12 2T-41 cement vi.cfw;09-12-2013; LoadCase 5.5in Liner(a);Version wcs-cem473_08 CemCAD E*well cementing recommendation for 7 5/8" Intermediate Stage 2 Operator : CPAI Well : 2T-41 Country : USA Field : Kuparuk State : Alaska Prepared for : Lindsey Hunter Location : Kuparuk Proposal No. : v1 Service Point : Prudhoe Bay Date Prepared : 8.15.13 Business Phone : (907)659-2434 Prepared by : Jenna Houston(reviewed by Stephen Lauper) Phone : (907)223-8916 E-Mail Address : jhouston2Qslb.com 430,k,‘ C q(UAT E 4-4-''i''; � Disclaimer Notice: Schlumberger submits this document with the benefit of its judgment.experience,and good oilfield practices. This information is provided in accordance with generally accepted'industry practice.relying on facts or information provided by others,limitations,computer models,measurements,assumptions and inferences that are not infallible. Calculations are estimates based on provided information.All proposals.recommendations.or predictions am opinions only. NO WARRANTY IS GIVEN CONCERNING ACCURACY OR COMPLETENESS OF DATA,INFORMATION PRESENTED,EFFECTIVENESS OF MATERIAL,PRODUCTS OR SUPPLIES.RECOMMENDATIONS MADE.OR RESULTS OF THE SERVICES RENDERED. Freedom from infringement of any intellectual property rights of Schlumberger or others is not to be inferred and no intellectual property rights are granted hereby. Mark of Schlumberger Page 1 21-41 cement v1.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_06 Client : CPAI Well : 21-41 Schlberger String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Section 1 : well description Configuration : Casing Stage :2nd of 2 Rig Type : Land Mud Line :0.0 ft Total MD : 6414.0 ft BHST :88 degF Bit Size :9 7/8 in Previous String MD OD Weight ID (ft) (in) (lb/ft) (in) 2538.0 10 3/4 45.5 9.950 1st Stage Collar :3900.0 ft Landing Collar MD :6334.0 ft Casing/liner Shoe MD :6414.0 ft Casing/Liner MD OD Joint Weight ID Grade Collapse Burst Thread (ft) (in) (ft) (lb/ft) (in) (psi) (psi) 3894.0 7 5/8 40.0 29.7 6.875 L-80 4310 5900 IFJ 6414.0 7 5/8 40.0 29.7 6.875 L-80 4310 5900 IFJ Mean OH Diameter :9.875 in Mean Annular Excess :40.0% Mean OH Equivalent Diameter: 10.643 in Total OH Volume :426.5 bbl (including excess) Caliper and Hole Size Data MD Caliper Excess Equiv. Diam. (ft) (in) (%) (in) 3900.0 9.875 40.0 10.643 6414.0 9.875 40.0 10.643 Page 2 2T-41 cement v1 cfw;09-06-2013; LoadCase Intermediate Stage 2:Version wcs-cem473_08 Client : CPAI Well : 2T-41 ScIiekergcr String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Max. Deviation Angle :45 deg Max. DLS :3.614 deg/100ft Directional Survey Data MD TVD Deviation Azimuth Dogleg Sev. (ft) (ft) (deg) (deg) (deg/100ft) 0.0 0.0 0.0 0.0 0.000 100.0 100.0 0.0 0.0 0.000 200.0 200.0 0.0 0.0 0.000 300.0 300.0 0.4 260.0 -0.440 400.0 400.0 2.4 260.0 2.000 500.0 499.8 4.4 260.0 2.000 600.0 599.4 5.5 260.0 1.060 700.0 698.9 5.5 260.0 0.000 800.0 798.4 6.7 254.4 1.292 900.0 897.4 9.2 247.3 2.746 1000.0 995.7 11.9 243.3 2.757 1100.0 1093.0 14.7 238.7 2.991 1200.0 1189.1 17.5 235.5 2.993 1300.0 1283.6 20.5 233.2 3.006 1400.0 1376.4 23.4 231.4 3.002 1491.7 1459.7 26.1 230.2 2.991 1500.0 1467.1 26.3 230.1 3.055 1600.0 1555.6 29.3 228.9 2.997 1700.0 1641.5 32.2 228.0 3.008 1800.0 1724.7 35.2 227.2. 2.993 1900.0 1804.9 38.2 226.5 3.008 2000.0 1881.8 41.2 225.9 2.995 2100.0 1955.4 44.1 225.4 3.002 2200.0 2026.7 44.9 225.3 0.775 2300.0 2097.5 44.9 225.3 0.000 2400.0 2168.4 44.9 225.3 0.000 2500.0 2239.2 44.9 225.3 0.000 2600.0 2310.0 44.9 225.3 0.000 2700.0 2380.9 44.9 225.3 0.000 2769.6 2430.2 44.9 225.3 0.000 2800.0 2451.7 44.9 225.3 0.000 2900.0 2522.5 44.9 225.3 0.000 3000.0 2593.4 44.9 225.3 0.000 3100.0 2664.2 44.9 225.3 0.000 3200.0 2735.0 44.9 225.3 0.000 3300.0 2805.9 44.9 225.3 0.000 3400.0 2876.7 44.9 225.3 0.000 3500.0 2947.5 44.9 225.3 0.000 3510.7 2955.1 44.9 225.3 0.000 3600.0 3018.4 44.9 225.3 0.000 3616.6 3030.1 44.9 225.3 0.000 3630.7 3040.1 44.9 225.3 0.000 3700.0 3089.2 44.9 225.3 0.000 3800.0 3160.0 44.9 225.3 0.000 3900.0 3230.9 44.9 225.3 0.000 4000.0 3301.7 44.9 225.3 0.000 4100.0 3372.5 44.9 225.3 0.000 4200.0 3443.4 44.9 225.3 0.000 4300.0 3514.2 44.9 225.3 0.000 4400.0 3585.0 44.9 225.3 0.000 4500.0 3655.9 44.9 225.3 0.000 4600.0 3726.7 44.9 225.3 0.000 4700.0 3799.2 42.1 227.2 -3.075 Page 3 27-41 cement vl.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_08 i Client : CPAI Well : 21-41 SCMINke1 ier String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Directional Survey Data MD TVD Deviation Azimuth Dogleg Sev. (ft) (ft) (deg) (deg) (deg/100ft) 4800.0 3875.2 39.0 229.7 -3.503 4900.0 3954.5 36.0 232.5 -3.502 5000.0 4036.9 33.0 235.8 -3.499 5100.0 4122.1 30.1 239.6 -3.500 5200.0 4209.8 27.4 244.1 -3.499 5258.8 4262.3 25.9 247.2 -3.500 5300.0 4299.6 24.8 249.6 -3.492 5400.0 4391.1 22.5 256.1 -3.501 5500.0 4484.2 20.5 263.9 -3.499 5589.3 4568.3 19.0 272.1 -3.502 5600.0 4578.3 18.9 273.2 -3.489 5700.0 4673.2 17.8 283.8 -3.499 5800.0 4768.6 17.4 295.3 -3.500 5900.0 4863.9 17.6 306.9 3.502 6000.0 4959.0 18.5 317.8 3.498 6100.0 5053.4 20.0 327.5 3.499 6200.0 5146.8 21.9 335.7 3.500 6300.0 5238.8 24.1 342.6 3.500 6400.0 5329.1 26.6 348.3 3.497 6414.0 5341.6 27.0 349.0 3.614 Formation Data MD Frac. Pore Name Lithology (ft) (lb/gal) (lb/gal) 2798.0 12.50 8.30 West Sak Top Sandstone 3616.0 12.50 8.30 C80 Sandstone 3630.0 12.50 8.30 Top Tabasco Sandstone 5258.0 12.50 8.30 C50 Sandstone 5589.0 12.50 8.30 C40 Sandstone 6414.0 12.50 8.30 TD Sandstone Geothermal Temperature Profile MD TVD Temperature Gradient (ft) (ft) (deg F) (degF/100ft) 0.0 0.0 20 0.0 1492.0 1460.0 32 0.8 3900.0 3230.9 88 2.1 6414.0 5341.6 132 2.1 Page 4 21-41 cement vl.cfw;09-06-2013; loadCaseIntermediate Stage 2;Version wcs-cem473_08 Client : CPAI Well : 2T-41 Schlumberger String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Section 2: centralizer placement Top of centralization :0.0 ft Bottom Cent. MD :3874.0 ft Casing Shoe :6414.0 ft Tension at 1st stage :46715.83 Ibf NB of Cent. Used :19 NB of Floating Cent. :19 Centralizer Placement Bottom MD Nbr. Cent./ Cent. Name Code Min.STO @ Depth (ft) Joint (%) (ft) 3134.0 0 0/0 0.0 3152.2 3934.0 20 1/1 7 5/8"TANDEM 41.0 3154.0 Centralizer Description Centralizer Tests Cent.Name Code Casing Max. Min.OD Rigid Origin Hole Size Running Restoring OD OD (in) (in) Force Force (in) (in) (lbf) (lbf) 1C-150 TANDEM 7 5/8 10.260 8.863 No 9.875 90.00 3168.00 ft — 0 1 0 60 80 100 1 Eer'.e Cart. I- . —I I I -IAt Cart. 0 o tn 0 o _ ___.___ __ ___ _._ _._._ ._- o- o_ _--_-w._..___.__._ .. __._____-_____ - Pipe Standoff Page 5 22-41 cement v1.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_00 Client : CPAI Well : 21-41 Scklhrger String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Section 3: fluid description Mud DESIGN Fluid No: 1 Density : 10.50 lb/gal Rheo. Model :BINGHAM Pv :12.000 cP At temp. :80 degF Ty :20.00 Ibf/100ft2 Gel Strength :21.00 Ibf/100ft2 MUD Mud Type :WBM Job volume : 169.1 bbl Water Type : Fresh MUDPUSH II DESIGN Fluid No:2 Density : 12.50 lb/gal Rheo. Model : HERSCHEL_B. k :3.51 E-2 lbf.sAn/ft2 At temp. :65 degF n :0.406 Ty :16.35 lbf/100ft2 Gel Strength :29.67 Ibf/100ft2 Job volume :40.0 bbl CW100 DESIGN Fluid No:3 Density :8.33 lb/gal Rheo. Model :NEWTONIAN At temp. :(degF) Viscosity :5.000 cP Gel Strength :(Ibf/100ft2) Job volume :40.0 bbl Tail Slurry DESIGN Fluid No:4 Density : 15.80 lb/gal Rheo. Model : HERSCHEL_B. k : 1.53E-2 lbf.sAn/ft2 At temp. :78 degF n :0.779 Ty :1.53 lbf/100ft2 Gel Strength :(Ibf/100ft2) DESIGN BLEND SLURRY Name :G Mix Fluid :5.076 gal/sk Job volume :41.2 bbl Dry Density : 199.77 lb/ft3 Yield : 1.16 ft3/sk Quantity : 199.20 sk Sack Weight :94 lb Solid Fraction :41.6% BASE FLUID Type : Fresh water Density :8.32 lb/gal Base Fluid :5.076 gal/sk Additives Code Conc. Function D046 0.200%BWOC Antifoam D065 0.400%BWOC Dispersant D167 0.600%BWOC Fluid loss Page 6 27-41 cement vl.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_08 Client : CPAI Well : 2T-41 SiIkrger String : 75/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Fresh Water DESIGN Fluid No:6 Density :8.32 lb/gal Rheo.Model :NEWTONIAN At temp. :(degF) Viscosity :5.000 cP Gel Strength :(Ibf/100ft2) Job volume : 10.0 bbl Section 4: fluid sequence Original fluid Mud 10.50 lb/gal Pv: 12.000 cP Ty:20.00 Ibf/100ft2 Dead end fluid Mud 10.50 lb/gal Displacement Volume 179.1 bbl Total Volume 300.3 bbl TOC 3130.0 ft Previous TOC 5923.3 ft Fluid Sequence Name Volume Ann. Len Top Density Rheology (bbl) (ft) (ft) (lb/gal) CW100 40.0 1007.7 1321.2 8.33 viscosity:5.000 cP MUDPUSH II 40.0 801.1 2328.9 12.50 k:3.51 E-2 lbf.s^n/ft2 n:0.406 Ty:16.35 lbf/100ft2 Tail Slurry 41.2 770.0 3130.0 15.80 k:1.53E-2 lbf.s^n/ft2 n:0.779 Ty:1.53 Ibf/100ft2 Fresh Water 10.0 3682.2 8.32 viscosity:5.000 cP Mud 169.1 0.0 10.50 Pv:12.000 cP Ty:20.00 Ibf/100ft2 Static Security Checks: Frac 219 psi at 3900.0 ft Pore 182 psi at 2538.0 ft Collapse 4004 psi at 3900.0 ft Burst 5808 psi at 2328.9 ft Check Valve Diff Press 135 psi Page 7 21-41 cement v1.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_08 Client : CPAI Well : 21-41 S Ism rg ' String : 75/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Section 5: pumping schedule Pumping Schedule Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments (bbl/min) (bbl) (min) (bbl). Temp. (degF) CW 100 6.0 40.0 6.7 40.0 80 MUDPUSH II 6.0 40.0 6.7 40.0 80 Pause 0.0 0.0 5.0 0.0 80 Tail Slurry 6.0 41.2 6.9 41.2 80 Pause 0.0 0.0 5.0 0.0 80 Fresh Water 5.0 10.0 2.0 10.0 80 Pause 0.0 0.0 5.0 0.0 80 Mud 6.0 159.1 26.5 159.1 80 Mud 3.0 10.0 3.3 169.1 80 Total 01:07 300.3 bbl hr:mn Dynamic Security Checks: Frac 99 psi at 3900.0 ft Pore 173 psi at 2538.0 ft Collapse 3891 psi at 5471.1 ft Burst 5591 psi at 2328.9 ft Temperature Results BHCT 84 degF Simulated Max HCT 74 degF Simulated BHCT 66 degF Max HCT Depth 0.0 ft CT at TOG 66 degF Max HCT Time 00:06:40 hr:mn:sc Static temperatures: At Time (hr:mn) 1 (hr:mn) Geo.Temp. Top of Cement (degF) (degF) 71 degF Bottom Hole (degF) (de9F) 88 degF Page 8 27-41 cement vi.cfw;09-06-2013; loadCase Intermediate Stage 2;Version wcs-cem473_08 Client : CPAI Well : 21-41 SGhi rgen String : 75/8 District : Prudhoe Bay Y4 Country : USA Loadcase : Intermediate Stage 2 ft (x 1000)psi 0 2 4 -Hydrostatic M Calc.Ponp Ress. —Nin.Hydrostatic ___. Calc.CenW _—Max.Dynamic ^ —Mm.Dynamic p Frac N —Pore co co 2 •O o (n'- CS o- rn ii 1 10 25 Ti50 75 Time(min) 1 O __ De•th= 3900 ft o N —Annular Vebcity 0 in moo oT a.) > o c Ci o Q � - o 0 25 50 75 Fluid Sequence Dynamic Well Security Time(min) Depth= 3900 ft o) N c coO a r C a 0 25.0 50.0 75.0 Time(min) Fluids at 3900 ft —Acquired Q Out -Acquired Q h c —Q Out — - --- �� Qh N c M- O O r r 0 25.0 50.0 75.0 Time(min) Page 9 2T-41 cement vl.cfw;09-06-2013; LoadCaseIntermediate Stage 2;Version wcs-cem413_06 Client : CPAI Well : 21-41 Schlumbergcr String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Section 6: WELLCLEAN II Simulator ft 0 0 25 50 715 100 0 25 50 715 100 o —Std Betw.Cent. —Mud Contamination o —Cement Coverage —Uncontarrinated Slurry c0 ....? o o In CO O p 1 Cement Coverage Uncontaminated Slurry Fluids Concentrations Risk Mud on the Wall z° g g i g I .—.1.- 3200 .1s3200- -3200 3200 3200 3300- -3300 3300 3300 3400- -3400 3400 3400 `" 3500- -3500 `~ 3500 3500 --- x - .c _c -1 a. n n a• 3800 3500 0` 0 3800 5600 n` 3700- -3700 3700 5700 3500- -3500 3500 5800 39001 -3900 3900 3900 I • g • • ; • 5. z z MN Mud MN MUDPUSH II 0 High Low iiiii Fresh Water NM CW100 I-1 Medium M None I-1 Tail Slurry Page 10 2T-41 cement vt.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_08 Client : CPAI Well : 21-41 ScImiWrger String : 7 5/8 District : Prudhoe Bay Country : USA Loadcase : Intermediate Stage 2 Tolerances - Spacer Max Rate is 6 BPM - Cement rate 5-6 BPM (remain within+/-0.2ppg Density Range,to be checked periodically with a mud balance) - Max Shut down time is 30-minutes; if time is being approached, contact Town Engineer - Max displacement Rate is 6 BPM, must slow to 3 BPM as indicated - Min Displacement Rate to be determined based on remaining Thickening Time from field blend testing - Mud to be conditioned prior to cementing - Maintain returns during cement job if possible Contingencies In the event that a problem occurs during mixing, pumping, or displacement, contingency plans should be systematically followed. If a shutdown occurs during the job, make note in the CemCAT report of when the stoppage occurred and how much time is available to remedy an issue before the thickening time becomes a problem. 1) If losses are encountered prior to cementing a) Utilize CemNET(1-2 lb/bbl; 2 lb MAX) b) Slow rate until full circulation is regained c) Determine max rate with full circulation and pump job at this rate if possible 2) Cement unit failure while mixing a) Attempt to continue pumping cement at minimum rate b) Attempt to remedy issue in less than 30 mins c) If issue with mixing system—switch to back-up mixing system d) If issue with triplex pump—continue with secondary triplex on unit 3) Mud Pump failure during displacement a) Discuss rig up in the event of cement unit displacement in PJSM b) Attempt to continue displacement with secondary rig pump c) Attempt to remedy issue (downtime<10 mins) d) Note displacement volume pumped by mud pumps: verify with well site leader e) Subtract pumped volume from total volume,which will be the volume pumped by the cement unit f) Rig up hoses to get mud to Cement Unit and begin displacement with cement unit(verify volume with well site leader) Page 11 2T-41 cement vl.cfw;09-06-2013; LoadCase Intermediate Stage 2;Version wcs-cem473_08 Schlumberger CemCAD E*well cementing recommendation for 10 3/411 Surface Operator : CPAI Well : 2T-41 Country : USA Field : Kuparuk State : Alaska Prepared for : Lindsey Hunter Location : Kuparuk Proposal No. : v2 Service Point : Prudhoe Bay Date Prepared : 9.12.13 Business Phone : (907)659-2434 Prepared by : Jenna Houston(reviewed by Stephen Lauper) Phone : (907)223-8916 E-Mail Address : jhouston2@slb.com O C7 =F � Disclaimer Notice: Schlumberger submits this document with the benefit of its judgment,experience,and good oilfield practices. This information is provided in accordance with generally accepted industry practice,relying on facts or information provided by others.limitations,computer models,measurements.assumptions and inferences that are not infallible. Calculations are estimates based on provided information.All proposals.recommendations,or predictions are opinions only. NO WARRANTY IS GIVEN CONCERNING ACCURACY OR COMPLETENESS OF DATA INFORMATION PRESENTED,EFFECTIVENESS OF MATERIAL PRODUCTS OR SUPPLIES,RECOMMENDATIONS MADE.OR RESULTS OF THE SERVICES RENDERED. Freedom from infringement of any intellectual property rights of Schlumberger or others is not to be inferred and no intellectual property rights are granted hereby. *Mark of Schlumberger Page 1 21-41 cement v1.cfw;09-12-2013; LoadCase Surface w/crete;Version wcs-cem473_08 Client : CPAI Well : 21-41 S Schihrier String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surfacew/crete Section 1 : well description Configuration : Casing Stage :Single Rig Type : Land Mud Line :0.0 ft Total MD :2770.0 ft BHST :71 degF Bit Size : 13 1/2 in Previous String MD OD Weight ID (ft) (in) (lb/ft) (in) 110.0 16 65.0 15.250 Landing Collar MD :2690.0 ft Casing/liner Shoe MD :2770.0 ft Casing/Liner MD OD Joint Weight ID Grade Collapse Burst Thread (ft) (in) (ft) (lb/ft) (in) (psi) (psi) 2770.0 10 3/4 40.0 45.5 9.950 L-80 2090 3580 Hydril 563 Mean OH Diameter : 13.500 in Mean Annular Excess : 153.9% Mean OH Equivalent Diameter: 16.879 in Total OH Volume :736.2 bbl (including excess) Caliper and Hole Size Data MD Caliper Excess Equiv.Diam. (ft) (in) (%) (in) 1492.0 13.500 250.0 18.681 2770.0 13.500 50.0 14.683 Page 2 21-41 cement vl.cfw;09-12-2013; LoadCase Surface w/Crete;Version wcs-cem473_08 Client : CPAI Well : 21-41 Scilwnkrgnr String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/crete Max. Deviation Angle :45 deg Max. DLS :3.055 deg/100ft Directional Survey Data MD TVD Deviation Azimuth Dogleg Sev. (ft) (ft) (deg) (deg) (deg/100ft) 0.0 0.0 0.0 0.0 0.000 100.0 100.0 0.0 0.0 0.000 200.0 200.0 0.0 0.0 0.000 300.0 300.0 0.4 260.0 -0.440 400.0 400.0 2.4 260.0 2.000 500.0 499.8 4.4 260.0 2.000 600.0 599.4 5.5 260.0 1.060 700.0 698.9 5.5 260.0 0.000 800.0 798.4 6.7 254.4 1.292 900.0 897.4 9.2 247.3 2.746 1000.0 995.7 11.9 243.3 2.757 1100.0 1093.0 14.7 238.7 2.991 1200.0 1189.1 17.5 235.5 2.993 1300.0 1283.6 20.5 233.2 3.006 1400.0 1376.4 23.4 231.4 3.002 1491.7 1459.7 26.1 230.2 2.991 1500.0 1467.1 26.3 230.1 3.055 1600.0 1555.6 29.3 228.9 2.997 1700.0 1641.5 32.2 228.0 3.008 1800.0 1724.7 35.2 227.2 2.993 1900.0 1804.9 38.2 226.5 3.008 2000.0 1881.8 41.2 225.9 2.995 2100.0 1955.4 44.1 225.4 3.002 2200.0 2026.7 44.9 225.3 0.775 2300.0 2097.5 44.9 225.3 0.000 2400.0 2168.4 44.9 225.3 0.000 2500.0 2239.2 44.9 225.3 0.000 2600.0 2310.0 44.9 225.3 0.000 2700.0 2380.9 44.9 225.3 0.000 2770.0 2430.4 44.9 225.3 0.000 Formation Data MD Frac. Pore Name Lithology (ft) (lb/gal) (lb/gal) 1492.0 12.50 8.00 Base permafrost Sandstone 2770.0 12.50 8.00 TD Sandstone Geothermal Temperature Profile MD TVD Temperature Gradient (ft) (ft) (degF) (degF/100ft) 0.0 0.0 20 0.0 1492.0 1460.0 32 0.8 2770.0 2430.4 71 2.1 Page 3 21-41 cement vi.cfw;09-12-2013; LoadCase Surface w/Crete;Version wcs-cem473_08 Client : CPAI Well : 2T-41 Schi hcrgor String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/crate Section 2: centralizer placement Top of centralization :0.0 ft Bottom Cent. MD :2750.0 ft Casing Shoe :2770.0 ft NB of Cent. Used :69 NB of Floating Cent. :34 Centralizer Placement Bottom MD Nbr. Cent./ Cent. Name Code Min.STO @ Depth (ft) Joint (%) (ft) 2770.0 69 1/1 10.75" BOW SPRING 56.3 370.0 Centralizer Description Centralizer Tests Cent.Name Code Casing Max. Min.OD Rigid Origin Hole Size Running Restoring OD OD (in) (in) Force Force (in) (in) (Ibf) (lbf) 10.75"BOW SPRING 10 3/4 16.125 13.500 No 13.500 709.00 1440.00 ft °o _ 50 A0 70 80 90 100 - E_t aar Cart. I I I _ + -fAt Cart. r T O c O r' 1 i C r. i ' ) O O Cr)— Pipe Standoff f Page 4 21-41 cement v1 cfw,09-12-2013; LoadCase Surface w/Crete;Version wcs-cem473_08 Client : CPAI Well : 2T-41 SIr er String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/crete Section 3: fluid description Mud DESIGN Fluid No:1 Density :9.60 lb/gal Rheo. Model : BINGHAM Pv : 12.000 cP At temp. :80 degF Ty :20.00 Ibf/100ft2 Gel Strength :21.00 Ibf/100ft2 MUD Mud Type :WBM Job volume :248.7 bbl Water Type : Fresh MUDPUSH II DESIGN Fluid No:2 Density : 10.50 lb/gal Rheo.Model :HERSCHEL_B. k :3.51 E-2 Ibf.s"n/ft2 At temp. :65 degF n :0.406 Ty : 16.35 lbf/100ft2 Gel Strength :29.67 Ibf/100ft2 Job volume :50.0 bbl CW100 DESIGN Fluid No:3 Density :8.33 lb/gal Rheo.Model :NEWTONIAN At temp. :(degF) Viscosity :5.000 cP Gel Strength :(Ibf/100ft2) Job volume :50.0 bbl Surface Tail DeepCRETE Slurry DESIGN Fluid No:4 Density : 12.00 lb/gal Rheo.Model :HERSCHEL_B. k :2.00E-2 lbf.s^n/ft2 At temp. :65 degF n :0.645 Ty : 14.85 lbf/100ft2 Gel Strength : 19.36 Ibf/100ft2 DESIGN BLEND SLURRY Name : 12.0(0.80) Mix Fluid : . 82 gal/sk Job volume :56.3 bbl Dry Density : 112.29 lb/ft3 Yield : 1.63 ft3/sk Quantity : 194.40 sk Sack Weight :100 lb Solid Fracti :54.9 /o BASE FLUID Type : Fresh water Density :8.32 lb/gal Base Fluid :5.392 gal/sk Additives Code Conc. Function D046 0.200%BWOB Antifoam D185 0.060 gal/sk blend Dispers. LT D186 0.030 gal/sk blend Accelerator Page 5 21-41 cement vt.cfw;09-12-2013; LoadGase Surface WI Crete;Version wcs-Cem473_00 Client : CPAI Well : 2T-41 SiInherit' String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/Crete Fresh Water DESIGN Fluid No:6 Density :8.32 lb/gal Rheo.Model :NEWTONIAN At temp. :(degF) Viscosity :5.000 cP Gel Strength :(Ibf/100ft2) Job volume : 10.0 bbl Surface Lead DESIGN Fluid No:7 Density : 11.00 lb/gal Rheo.Model : HERSCHEL_B. k :6.31 E-3 Ibf.s^n/ft2 At temp. :68 degF n :0.845 Ty : 12.00Ibf/100ft2 Gel Strength :(lbf/100ft2) DESIGN BLEND SLURRY Name : 11.0(0.76) Mix Fluid : I k Job volume :401.5 bbl Dry Density :98.03 lb/ft3 Yield 1.83 ft3/sk Quantity :1231.81 sk Sack Weight : 100 lb Solid Fract n :55.9°/ BASE FLUID Type : Fresh water Density :8.32 lb/gal Base Fluid :5.951 gal/sk Additives Code Conc. Function D046 0.200%BWOB Antifoam D185 0.060 gal/sk blend Dispers. LT D186 0.030 gal/sk blend Accelerator Page 6 21-41 cement vi.cfw;09-12-2013; LoadCaseSurface w/Crete;Version wcs-cem473_08 Client : CPA! Well : 2T-41 silrg�r String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/crete Section 4: fluid sequence Original fluid Mud 9.60 lb/gal P�:12.000 cP Ty:20.00 Ibf/100ft2 Displacement Volume 258.7 bbl Total Volume 816.4 bbl TOC 0.O ft Fluid Sequence Name Volume Ann.Len Top Density Rheology (bbl) (ft) (ft) (Ib/gal) CW100 50.0 0.0 8.33 viscosity:5.000 cP MUDPUSH II 50.0 0.0 10.50 k:3.51 E-2 Ibf.s^n/ft2 n:0.406 Ty:16.35 Ibf/100ft2 Surface Lead 401.5 2270.0 0.0 11.00 k:6.31 E-3 Ibf.s^n/ft2 n:0.845 Ty:12.00 Ibf/100ft2 Surface Tail 56.3 500.0 2270.0 12.00 k:2.00E-2 Ibf.s^n/ft2 n:0.645 Ty:14.85 Ibf/100ft2 DeepCRETE Slurry Fresh Water 10.0 2586.0 8.32 viscosity:5.000 cP Mud 248.7 0.0 9.60 Pv:12.000 cP Ty:20.00 Ibf/100ft2 Static Security Checks: Frac 9 psi at 110.0 ft Pore 17 psi at 110.0 ft Collapse 1809 psi at 2690.0 ft Burst 3580 psi at 0.0 ft Csg.Pump out 39 ton Check Valve Diff Press 193 psi Page 7 2T-41 cement vi.cfw;09-12-2013; LoadCase Surface w/Crete;Version wcs-cem473_08 Client : CPAI Well : 2T-41 SiIker er String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/Crete Section 5: pumping schedule A stage collar will be placed at 500'in the event of a top job becoming necessary.Extra lead cement will be on location for this purpose. Pumping Schedule Name Flow Rate Volume Stage Time Cum.Vol lnj. Comments (bbl/min) (bbl) (min) (bbl). Temp. (degF) CW 100 7.0 50.0 7.1 50.0 80 MUDPUSH II 7.0 50.0 7.1 50.0 80 Pause 0.0 0.0 5.0 0.0 80 Surface Lead 7.0 401.5 57.4 401.5 80 Surface Tail 7.0 56.3 8.0 56.3 80 DeepCRETE Slurry Pause 0.0 0.0 5.0 0.0 80 Fresh Water 6.0 10.0 1.7 10.0 80 Pause 0.0 0.0 5.0 0.0 80 Mud 8.0 238.7 29.8 238.7 80 Mud 3.0 10.0 3.3 248.7 80 Total 02:09 816.4 bbl hr:mn II, Dynamic SecurityChecks: Y Frac 7 psi at 110.0 ft Pore 2 psi at 110.0 ft Collapse 1809 psi at 2690.0 ft Burst 3325 psi at 0.0 ft Temperature Results BHCT 75 degF Simulated Max HCT 78 degF Simulated BHCT 77 degF Max HCT Depth 2770.0 ft CT at TOC 74 degF Max HCT Time 00:32:01 hr:mn:sc Static temperatures: At Time (hr:mn) 1 (hr:mn) Geo.Temp. Top of Cement (degF) (degF) 20 degF Bottom Hole (degF) (degF) 71 degF Page 8 2T-41 cement vl.cfw;09-12-2013; LoadCase Surface w/Crete;Version wcs-cem473_08 Client : CPAI Well : 21-41 SGhi NPger String : 103/4 District : Prudhoe Bay 4 �j, Country : USA Loadcase : Surface w/trete ft (x 1000)psi 0 1 2 o- I i o —Hydrostatic M —Calo.Ring Ress.' —Mn.Hydrostatic —Calc.Cer*IP _ —N1ax.Dynamo �— —Mn.Dynantic p �. —Frac �:N- � I —Pore 2 • - -- IL ao 1 I o- \ 1 to 1 ca i T 0 I 0 50 100 150 Time(min) o Depth= 2770 ft o - Annular Velocity Ica Cq g 8_ ii- t 1 >• .4- c __ i o Q 0 M- o — 0 50 100 150 Fluid Sequence Dynamic Well Security Time(min) o Depth= 2770 ft Lri ,- cc cp 11 ul a �T — o aoff ^' _.. _ C J I I Lo 1 i 0 20 40 60 80 100 120 140 Time(min) o Acquired Q in I ft r Fluids at 2770 —Acquired Q Ou IQ Out fl —'--(+01 Itt LL ;� ._ I- I I I o r 0 20 40 60 80 100 120 140 Time(min) fPage 9 2T-41 cement vl.cfw;09-12-2013; LoadCase Surface w/Crete;Version wcs-cem473_08 Client : CPAI Well : 2T-41 Schi he String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/crete Section 6: WELLCLEAN II Simulator ft 0,0 % 0 25 _ 50 75 100 0 25 50 75 100 —Std Betw.Cent ` -Mud Contamnation + -Cement Coverage H -Uncontaminated Slurry I I %' O I r I l 1 i � � I O O i i l I l I O O O CO Cement Coverage Uncontaminated Slurry Fluids Concentrations Risk Mud on the Wall a 0 0 0 50O- -SOO 500 500 10(10- -1ODD 1DOO 1ODD,_. I i r t s 15(1a- -+son Is s 15(10 +sOO It ao a a 2000- -2040 2000 2000 2500 2000 2500 2500 5 1 ! IMI Mud M High Low iiii Fresh Water Medium M None U Surface Tail DeepCRETE Slurry Surface Lead ▪ MUDPUSHII CW100 Page 10 2T-41 cement vi.cfw;09-12-2013; LoadCaseSurface w/crete;Version wcs-cem473_08 Client : CPAI Well : 21-41 SekMerger String : 103/4 District : Prudhoe Bay Country : USA Loadcase : Surface w/crete Tolerances - Spacer Max Rate is 7 BPM - Cement rate 5-7 BPM (remain within+1-0.2ppg Density Range,to be checked periodically with a mud balance) - Max Shut down time is 30-minutes; if time is being approached, contact Town Engineer - Max displacement Rate is 8 BPM, must slow to 3 BPM as indicated - Min Displacement Rate to be determined based on remaining Thickening Time from field blend testing - Mud to be conditioned prior to cementing - Maintain returns during cement job if possible Contingencies In the event that a problem occurs during mixing, pumping, or displacement, contingency plans should be systematically followed. If a shutdown occurs during the job, make note in the CemCAT report of when the stoppage occurred and how much time is available to remedy an issue before the thickening time becomes a problem. 1) If losses are encountered prior to cementing a) Utilize CemNET(1-2 Ib/bbl; 2 lb MAX) b) Slow rate until full circulation is regained c) Determine max rate with full circulation and pump job at this rate if possible 2) Cement unit failure while mixing a) Attempt to continue pumping cement at minimum rate b) Attempt to remedy issue in less than 30 mins c) If issue with mixing system—switch to back-up mixing system d) If issue with triplex pump—continue with secondary triplex on unit 3) Mud Pump failure during displacement a) Discuss rig up in the event of cement unit displacement in PJSM b) Attempt to continue displacement with secondary rig pump c) Attempt to remedy issue(downtime<10 mins) d) Note displacement volume pumped by mud pumps:verify with well site leader e) Subtract pumped volume from total volume, which will be the volume pumped by the cement unit f) Rig up hoses to get mud to Cement Unit and begin displacement with cement unit(verify volume with well site leader) Page 11 21-41 cement vl.cfw;09-12-2013; LoadCase Surface w/crete;Version wcs-cem473_08 0 as CI 2 • Q NZ soon •— s am0 4.4 i u E. '''t. 0 $-. o C P. o u C ti N CU 0 CC Z CO Q =0 wCm .. E CO ■— =2 a. i Q. co N • a). w a . i. ::.:. _ ,c.i � , 3 > t . ,... ,_ E C L i N N N Q o a a _ _ _ N 2T-41wp07 5D773 Plan Summary !rSURVEY PROGRAM _ A Depth From Depth To Survey/Plan Tool , 28.00 950.00 2T-41wp07(Plan: 2T-41) GYD-GC-SS 950.00 2769.64 2T-41wp07 (Plan: 2T-41) MWD+IFR-AK-CAZ-SC / II' 2769.64 6414.44 2T-41wp07 (Plan: 2T-41) MWD+IFR-AK-CAZ-SC �; 6414"44 7098"40 2T-41wp07 (Plan: 2T-41) MWD+IFR-AK-CAZ-SC // �L • CASING DETAILS - ' TVD MD Name Size " 2429.84 2769.64 10-3/4"x 13-1/2" 10-3/4 5341.64 6414"44 7-5/8"X 9-7/8" 7-5/8 5895"68 7098"40 6-3/4"X 7-1/2" 6-3/4 J " Top HRZ B.HRZ/Top-Kalubilt o 0° 7-5/8"X 9-7/8" >.5- , - �0 O 10-3/4x13-1 " Base Perm C50 C40 \ / -5 g0 �°o ' O o iv ' 10-3/4"x 13-1/2" •� o 90 b5 O co C80 sI 6-3/4"X 7-1/2' N apo Top W-Sak Fault X45' Kup,C LW/Kuq B 89 7-5/8"X 9-7/8" o - j r f Top Tabasc 0 20 + 6-3/4"X 7-/2" I _. '� l , K-1/Base Kalubk I ` ... 1 i Lup_A3 o j I 000 ° d lot 13� 0 1 1 1 I I i' 1 1 1 I I1 r D I 1 I 1 I 1 1 I 1 I 1 I ii 1 1 1 0 2000 4000 6000 0 500 1000 1500 2000 2500 3000 3500 Measured Depth Horizontal Departure ,�1y ys I 0 C � "11 'I '1 - �A1 yp �. 330 zr io � '1 o '11 .��7�'I1111� Il li :. i " I.. I - zat9 TO 60 11I�II111� I I' I 300 ��t' .. 89ry,.2T-12 M a# me - 'I�ll;I l , �ll� _ I tt; �l 11 _ MO 02 011���'..r 1 C. - Per _ I a:!,• - u `M I � e c I ul is � �e'� p� u i Tilt.. A 270 (2_5; 30 nS11111111.14lli I 4OA.0 P' ;l O ''. $ i1 „13 i.. Elvia �1' .zn4 - m 2T- 5500 _ ,illii, c l l l� ti-12A 240 : to I" tr�'C' 120 U 2112A ;pp _ "�h iJ' I ,1��1rS. ,sesoo 6600 0 I I I I I I I I I I I I I I I I I 1 + I I I 1 I I 1 I I I 1 210'4 .V1 ''''''1.17'�•' 7$0 woo- 5703- 6000 0 800 1600 2400 3200 4000 4800 5600 6400 7200 180 SECTION DETAILS >..o - Mt Sec MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLeg TFace VSec Target - 1 28.00 0.00 0.00 28.00 -81.70 0.00 0.00 5969828.32 1638978.90 0.00 0.00 0.00 2 278.00 0.00 0.00 278.00 168.30 0.00 0.00 5969828.32 1638978.90 0.00 0.00 0.00 - 1459.7 3 353.00 1.50 260.00 352.99 243.29 -0.17 -0.97 5969828.15 1638977.93 2.00 260.00 -0.25 4 553.00 5.50 260.00 552.58 442.88 -2.29 -12.99 5969826.03 1638965.91 2.00 0.00 -3.41 5 753.00 5.50 260.00 751.66 641.96 -5.62 -31.87 5969822.71 1638947.04 0.00 0.00 -8.37 6 1003.00 11.96 243.21 998.67 888.97 -19.39 -66.82 5969808.94 1638912.08 2.75 -30.00 -25.14 7 2126.00 44.90 225.25 1973.95 1864.25 -360.78 -463.66 5969467.67 1638515.21 3.00 -23.10 -399.81 Base Perm 8 4612.00 44.90 225.25 3734.77 3625.07 -1596.29 -1709.95 5968232.52 1637268.81 0.00 0.00 -1739.24 9 6860.05 40.00 5.00 5713.10 5603.40 -1403.93 -2307.48 5968424.97 1636671.39 3.50 154.94 -1599.70 10 6960.05 40.00 5.00 5789.70 5680.00 -1339.89 -2301.87 5968489.00 1636677.00 0.00 0.00 -1535.42 2T-41 (wp06)T1 11 7068.40 40.00 5.00 5872.70 5763.00-1270.51 -2295.80 5968558.37 1636683.08 0.00 0.00 -1465.77 2T-41 (wp06)T2 revl _ofkiW-Sak 12 7098.40 40.00 5.00 5895.68 5785.98 -1251.30 -2294.12 5968577.58 1636684.77 0.00 0.00 -1446.49 Top Tabasco -4261.7 C50 -4567.7 C40 55 Z 6;.SHR ''t, ,I,% kik -59. .- Top Miluveach Surface Location Geodetic Datum: North American Datum 1983 Magnetic Model: BGGM2012 T M Depth Reference: Plan:81.7+28 @ 109.70ft(Doyon 141) Magnetic Model Date: 13-Sep-13 System(SS)Reference: Mean Sea Level Magnetc Declination: 19.66° North /Y: 5969828.32 Ground Level/Mud Line: 81.70 To convert a Magnetic Direction to a True Direction,Add 19.66°East East/X: 1638978.90 Rig: Doyon 141 GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference f 0) '0 fl.8 z 3 km,,, Ca i e- t COo ': M j\* O O N U C OT O N- 4 C 0 O +k'- O ., 9 )�f� n- Fp ,, k a U 0 O O O C 0 g e (1)0 m e ' / CO CO 2 a > � . ft,;,:',',.,, N ++ O d J— -000 To- n E O 0 0 0 y €.. 0. c0 c0 > j u)> m d J — c c 0 E . 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Q CO .rr. ti Lin 7 N 0 oo a C 00 �^ 0 0 V 0 00 n N N N 7 � E its g0 m m 7 > a)- m m 2 - p clE F- mo w ci U .8 C o s °.0' m ce C 0 p • ci •- u Ili '5 2 0 7 c O v y w m 0 41 d d U C1 U ce y A CN6 Tt m -0 .w. 0 0 0 0 7 0 J 1- mZ (g0 N L0 O Q 0) Z L � • C 7 V m CO L m o u) o a) m n a 1 Q Q C) C Mil a) Y CN D CO +' Q 0 "Om 0 a ? a L 2 N id' p O- 2 2 N N C 0. d C C I la O W F- O 7 7_ U Y Y d d N 4 C m V - -a C .. CID n .. .0 4) E O• ad+a) G7 d .0 U a t5 ci 0 rn I 2T-41wp07 Surface Location J EZ:1- CPAI Coordinate Converter — j 171 LI ; From: - ---- i Datum: INAD27 7_1 Region: Ialaska ...ri Datum: INAD27 ,j Region: Ialaska j r Latitude/Longitude 'Decimal Degrees zi C Latitude/Longitude 'Decimal Degrees _11 ‘.. C' UTM Zone: 1 — F South C UTM Zone: True F South t; State Plane Zone: 1,-1 ,.1 r I Units: lu,-It , State Plane Zone: Units: 'us-ft i !True , C _ .:1-Ji De:criptiott ihj il D27 only) 6' Legal Description(NAD27 only) 71 Starting Coordinates: - — -Legal Description X: 1498946.49 __ Township: 1011 IN -.I Range: 1008 1E Y: 15970077.58 Meridian: 1u , Section:f / - IFNL j 15182.5519 'FEL 27] 14722.3922' Transform Quit j Help 1 r 2T-41wp07 Intermediate Casing I -I in. CPAI Coordinate Converter LL-J 0 ILICJ i From: -- ,- To: 1 Datum: INAD27 ..l Region: Ialaska ri Datum: INAD27 ,1 Region: Ialaska ., ] 1 C Latitude/Longitude 1Decimal Degrees zi C Latitude/Longitude IDecimal Degrees .. t Zone: C' UTM Zone: 1 P South r UTM Zone: F South is State Plane Zone: 14 _..v.i Units: lus-ft •.1 C State Plane Zone: IT rue ,' Units: lus-ft ... C' 1_,g51 De:cripliort 11'14/27 Or 1 (r Legal Description(NAD27 only) Starting Coordinates: Legal Description X: 1496645.75 Township: 1011 IN Range: 1008 IE v I Y: 15968430/9 Meridian: lu , Section:I 1 1 — IFNL .: 11550.2187 IFEL j 11744.1715 i Transform Quit I Help I ___ I2T-41wp07 TD r. . CPAI Coordinate Converter L' italLi 1 From: - — -- - - - -To:• Datum: INAD27 w Region: jalaska •ri Datum: INAD27 Region: Jalaska j (- Latitude/Longitude ]Decimal Degrees zi C Latitude/Longitude 'Decimal Degrees 2_7 C UTM Zone: ' i- South r UTM Zone: 'True 1- South C: State Plane Zone: 14 ---;;;1 Units: Jus ft .,1 State Plane Zone: 'True �] Units: Jus-ft . C" L g&)De criplio n INSD27 only! C Legal Description(NAD27 only) Starting Coordinates: - -- -Legal Description X: 496652.32 Township: (011 IN ;] Range: Fig- 1E Y: 15968826.93 Meridian: (U ‘.' Section:111 IFNL .. 11154.0442 'FEL 1 11737.4126 I Transform Quit Help F Schlumberger ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 2T Pad Plan: 2T-41 Plan: 2T-41 2T-41wp07 Anticollision Report 13 September, 2013 ConocoPhillips Schiumber er Schlumberger hubAolsoReport oPhillips Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well Plan:2T-41 Project: Kuparuk River Unit TVD Reference: Plan:81.7+28 @ 109.70ft(Doyon 141) Reference Site: Kuparuk 2T Pad MD Reference: Plan:81.7+28©109.70ft(Doyon 141) Site Error: 0.00ft North Reference: True Reference Well: Plan:2T-41 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore Plan:2T-41 Database: EDM v16 Prod Reference Design: 2T-41wp07 Offset TVD Reference: Offset Datum Reference 2T-41wp07 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of refer( Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 907.04ft Error Surface: Elliptical Conic Warning Levels Evaluated at: 2.00 Sigma Survey Tool Program Date 9/13/2013 From To (ft) (ft) Survey(Wellbore) Tool Name Description 28.00 950.00 2T-41wp07(Plan:2T-41) CB-GYRO-SS Camera based gyro single shot 950.00 2,769.64 2T-41wp07(Plan:2T-41) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 2,769.64 6,414.44 2T-41wp07(Plan:2T-41) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 6,414.44 7,098.40 2T-41wp07(Plan:2T-41) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 9/13/2013 2:17:18PM Page 2 of 75 COMPASS 2003.16 Build 69 S Schlumberger Anticollision Report ConocoPhillips Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well Plan:2T-41 Project: Kuparuk River Unit TVD Reference: Plan:81.7+28 @ 109.70ft(Doyon 141) Reference Site: Kuparuk 2T Pad MD Reference: Plan:81.7+28 @ 109.70ft(Doyon 141) Site Error: 0.000 North Reference: True Reference Well: Plan:2T-41 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore Plan:2T-41 Database: EDM v16 Prod Reference Design: 2T-41wp07 Offset ND Reference: Offset Datum Summary Reference Offset Distance Measured Measured Between Between Separation Warning Site Name Depth Depth Centres Ellipses Factor Offset Well-Wellbore-Design (ft) (ft) (ft) (ft) Kuparuk 2T Pad 21-04-21-04-21-04 28.10 35.40 254.92 253.90 251.837 CC 21-04-2T-04-21-04 612.48 625.00 260.35 243.94 15.862 ES,SF 2T-05-2T-05-21-05 109.70 117.00 229.97 227.88 109.762 CC 21-05-21-05-21-05 513.93 525.00 233.32 222.66 21.893 ES,SF 21-06-21-06-21-06 109.70 117.00 204.95 202.85 97.819 CC 21-06-21-06-21-06 341.85 350.00 207.18 200.28 30.037 ES,SF 21-07-2T-07-21-07 292.54 300.00 179.86 173.23 27.137 CC 21-07-21-07-21-07 514.39 525.00 182.50 169.76 14.319 ES,SF 21-08-21-08-21-08 242.70 250.00 154.94 150.20 32.692 CC 21-08-21-08-21-08 465.60 475.00 157.00 147.41 16.363 ES,SF 21-09-2T-09-2T-09 317.40 325.00 129.95 123.59 20.424 CC 2T-09-2T-09-2T-09 515.29 525.00 132.00 121.32 12.361 ES,SF 2T-10-2T-10-2T-10 367.39 375.00 54.03 45.35 6.226 CC 2T-10-2T-10-2T-10 466.79 475.00 55.06 43.67 4.832 ES,SF 2T-11 -2T-11 -21-11 109.70 117.00 30.16 28.07 14.397 CC 2T-11-2T-11-2T-11 516.82 525.00 32.57 19.88 2.568 No Errors,ES,SF 21-12-21-12-2T-12 142.70 150.00 4.52 1.65 1.577 No Errors,CC 21-12-2T-12-2T-12 367.65 375.00 6.09 -0.88 0.874 No Errors,ES,SF 2T-12-2T-12A-2T-12A 142.70 150.00 4.52 1.65 1.577 No Errors,CC 2T-1Z-2T-12A-2T-12A 367.65 375.00 6.09 -0.88 0.874 NQ Errors,ES Se 21-13-2T-13-2T-13 442.77 450.00 19.67 8.97 1.839 No Errors,CC 21-13-2T-13-2T-13 517.48 525.00 20.45 7.71 1.606 No Errors,ES,SF 2T-14-21-14-21-14 542.78 550.00 41.55 28.07 3.083 CC 21-14-21-14-2T-14 667.20 675.00 43.28 26.37 2.559 No Errors,ES,SF 21-15-21-15-21-15 518.05 525.00 68.27 55.48 5.339 CC 2T-15-2T-15-21-15 692.07 700.00 70.55 52.95 4.009 ES,SF 21-16-21-16-21-16 109.70 117.00 94.76 92.66 45.225 CC 21-16-21-16-21-16 468.56 475.00 96.28 84.85 8.426 ES,SF 21-17-21-17-21-17 109.70 117.00 119.89 117.79 57.219 CC 2T-17-2T-17-2T-17 418.41 425.00 120.79 110.72 11.998 ES,SF 21-18-21-18-21-18 464.28 475.00 131.87 122.78 14.504 CC 2T-18-2T-18-2T-18 615.34 625.00 133.50 121.11 10.776 ES,SF 2T-19-2T-19-2T-19 1,851.01 1,875.00 72.55 43.44 2.493 No Errors,CC,ES,SF 2T-20-21-20-21-20 880.07 900.00 132.80 115.91 7.864 CC,ES,SF 21-201-21-201 -2T-201 585.82 600.00 135.83 124.28 11.759 CC 21-201-2T-201 -21-201 635.61 650.00 136.62 123.92 10.755 ES,SF 2T-21 -21-21 -21-21 61.70 75.00 179.71 178.17 116.300 CC 2T-21 -21-21 -21-21 261.68 275.00 180.92 175.79 35.244 ES,SF 2T-36-2T-36-2T-36 1,610.20 1,600.00 63.93 37.21 2.392 No Errors,CC 2T-36-2T-36-2T-36 1,635.49 1,625.00 64.18 37.12 2.372 No Errors,ES,SF 2T-37-2T-37-2T-37 2,328.53 2,250.00 124.80 86.90 3.293 CC, ES,SF 21-38-21-38-21-38 109.70 122.00 32.18 30.09 15.359 CC 2T-38-2T-38-2T-38 637.80 650.00 33.22 21.36 2.800 No Errors,ES,SF 2T-38-2T-38A-2T-38A 109.70 113.00 32.18 30.09 15.359 CC 2T-38-2T-38A-2T-38A 646.77 650.00 33.44 21.37 2.770 No Errors,ES,SF 21-39-2T-39-21-39 494.16 500.00 162.00 152.59 17.206 CC 2T-39-2T-39-2T-39 543.82 550.00 162.47 152.08 15.638 ES,SF 21-40-2T-40-2T-40 31.90 41.05 192.68 191.62 181.547 CC 2T-40-2T-40-2T-40 140.84 150.00 194.00 191.06 65.888 ES,SF CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 9/13/2013 2:17:18PM Page 3 of 75 COMPASS 2003.16 Build 69 Schiumberger Schlumberger p Anticollision Report ConocoPhillips Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well Plan:2T-41 Project: Kuparuk River Unit TVD Reference: Plan:81.7+28 @ 109.70ft(Doyon 141) Reference Site: Kuparuk 2T Pad MD Reference: Plan:81.7+28 @ 109.70ft(Doyon 141) Site Error: 0.00ft North Reference: True Reference Well: Plan:2T-41 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore Plan:2T-41 Database: EDM v16 Prod Reference Design: 2T-41wp07 Offset TVD Reference: Offset Datum Reference Depths are relative to Plan:81.7+28 @ 109.70ft(Doyon 141Coordinates are relative to:Plan:2T-41 Offset Depths are relative to Offset Datum Coordinate System is US State Plane 1983,Alaska Zone 4 Central Meridian is 150°0'0.000 W° Grid Convergence at Surface is:-0.01° Ladder Plot 1 I 1000 ' 1 I I I I I I I I 1 I I 1 I I I � I 1 r7 I - - -- I -�-- - -. I I ! . I 750 1I); fl f.IJXta �17it CD C7 I I I 1 I j "' r j '500 U II I I I I I I I ..i 1' 1 I I I I a) o y.: I if,f' r,p- I I I I 250 •�•i r /'r. t�di y . Vrj.f.;: a 1 I I I 1 t 1f PAl 1 I I I % 1 1a\�� I I I 1 r.�s ,. -- - - - - I - - - - I - - - 1 - - - - - -- �'aGn,. �• n -•e, I I 1 1 I .wwr ,7'o. I 1 I 1 I I I I I I 0 '''.1.17. � I I I , 0 1500 3000 4500 6000 7500 9000 M ea su re d Depth LEGEND -i- 2T-04,21-04.2T-04 V3 -9-2T-12.21.12A,21.12AW - -2T-201,2T-201,2T-201 VA -e- 2T-05,2T-05.2T-05 1/2 -X-2T-13.2T-13,2T-13 V2 -0-2T-21.2T-21.2T-21 V1 -X- 2T-06,2T-06.2T-06 V2 -9-2T-14,2T-14,2T-14 V2 -#-2T-36,2T-36.2T-36L47 --0- 2T-07.2T-07,2T-07 V3 -a-2T-15.2T-15.2T-15 V2 $- 2T-37,2T-37,2T-37 L'0 -JE- 2T-08.2T-08,2T-08 V3 --1-2T-15,2T-16.2T-16 V2 -3(—2T-38,2T-38,2T-38L'0 —4— 2T-09,2T-09,2T-09 V2 -0.-2T-17,2T-17,2T-17 V1 --he-2T-38,2T-38A,2T-38ALo - - 2T-10,2T-10.2T-10 V2 -2T-18,2T-18,2T-18 V1 -+a- 2T-39,2T-39,2T-39 V9 -9- 2T-11,2T-11.2T-11 V2 2T-19.2T-19,2T-19 W -A-2T-40,2T-40,2T-40 V3 CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 9/13/2013 2:17:11 PM Page 75 of 75 COMPASS 2003.16 Build 69 1 Bettis, Patricia K (DOA) From: Hunter, Lindsey L [Lindsey.Hunter@conocophillips.com] Sent: Tuesday, October 01, 2013 7:50 AM To: Bettis, Patricia K(DOA) Subject: RE: KRU 2T-41: Permit to Drill Application Attachments: 2T-41 - IFE Mud Program -v1 1 9-30-2013.docx Patricia, Thanks for looking at the 2T-41 PTD. Here is an updated Drilling Fluid Proposal. Thanks, Lindsey Lindsey Hunter Drilling Engineer ConocoPhillips Alaska D&W 907-265-6427 lindsey.hunte a,conocophillips.com From: Bettis, Patricia K(DOA) [mailto:patricia.bettis@alaska.gov] Sent: Monday, September 30, 2013 2:20 PM To: Hunter, Lindsey L Subject: [EXTERNAL]KRU 2T-41: Permit to Drill Application Good afternoon Lindsey, Please forward a final copy of the MiSWACO" Drilling Fluid Proposal". The proposal submitted with the application is marked "DRAFT". The final Drilling Fluid Proposal may be sent to me via email. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 Bettis, Patricia K (DOA) From: Bettis, Patricia K(DOA) Sent: Monday, September 30, 2013 2:20 PM To: 'Lindsey.Hunter@conocophillips.com' Subject: KRU 2T-41: Permit to Drill Application Good afternoon Lindsey, Please forward a final copy of the MiSWACO" Drilling Fluid Proposal". The proposal submitted with the application is marked "DRAFT". The final Drilling Fluid Proposal may be sent to me via email. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: a 1_6i/1c, /Development Service Exploratory Stratigraphic Test Non-Conventional FIELD: f{ i 4< j4.r POOL: tn .1c � ��ii CT Akx:.l x pv`Ji,:s 6,-) Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are Well Lo rn also required for this well: gg g Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonmentofthis well. / AC.1117\01� �1 •�C.4� & CllCti (- n�Y' 1k)/ l r / /' C�nc�C1�dY�a { S w dC Cf A-4016-CC' Revised 5/2013 u) a) Q1 U 0 , a) E a) O m a) a c o Cc a) Q 0 n L 2 U U W , c 0) CO 3 a c o 0 m a -0 O Z m o E 0N - (p o 'a u) O Co a wL 0 n cr) O r a) 3 c° o cm U U O O O c a) 0 > 3 a) a '0 O EN O a) U co 2 UI O C cO 0 L a >` c 3 U a W 7 ▪ = o - C U Cr) a O c -`O - O a 0 a) T O a) O L- 3 N N L ou) n c -um o 0 n aa) .3 ' O LTo N d N > O O .3 0 m m`o N ifl o m o u) m M co so H J o C C p_ a) co-O a) Cs16 < ca -0 N 0. 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