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Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. c::Q LA - j ( a Well History File Identifier Organizing (done) wo-sided ❑ Rescan Needed RE AN: OVERSIZED: NOTES: Col Items: ❑ Ma s: Grayscale Items: Logs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: C Maria ) Date: ir _.J 03/11-1- /s/ v4P Project Proofing BY: Maria Date: I a3 1 if /s/ MP Scanning Preparation ) x 30 = 30 a3 = TOTAL PAGES E --3 ^ r,I (Count does not include cover sheet) BY: <Maria� Date: I p� d�3 1�-F /s/ I Production Scanning Stage 1 Page Count from Scanned File: 5/4" (Count does include cover eet) Page Count Matches Number in Scannin Prepa ation: YES NO BY: dE. Date: 1 a d`,.3 / Is! Mr Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: YES NO TOTAL PAGES: Digital version appended by: Meredith Michal Date: /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked 7/8/2014 Well History File Cover Page_20140708.doc r o I I 0 I >. a (Q icc c Q Q /�7Q coI _ m co m / Z /Z/ \ N c E E E E E ce a)4 r >- >- (o U ml C7 C7 O E„ 0 inN C7 a v c >. ( N N �, (0 Q ) < 'I o aw o '> E `� I cu 0 cc CCC c 0 Er_ y c c c yp 0 a. Q g c ITS m o CC t aooa o m ma .►�o) o) 0 0 0 Z m o0o 0 C eL frn OU a 0, a Q) a) a Q) 7 ? o N a) O a) o a.E °0 y c Q y a E Tao ao a m / /Z 7 E :. -,m a) c y `° o U,24z 2 E �� a•= 0_ Ef } } > 'I ;Si -J o . ` _ " J U N 13 M M M M N a d .�-. a. J Y > o 0 0 0 o Ey E p LUco (Ni N N N N 7 p -±" N y N N N N coCV (A Z vi O) IX O 0: N N N N U a E _ u) W 0 J 22 a a a a a m m v) 0. CD I ✓ U O O U O O O O 0 E E Z co y m co `� _ $ )"cr LO v (`nn (`) to o 0 rn Q y (0 (o y co co ado cohado Q E wc- a m Z 7 0 I I a 0 u) ', oI a; C U U M C Z C t I(0 (0 (0 (0 I. 0 G / O O O C.0 oa) y G O 2 y (O,N- N- N- F- (0 o 0 a La O E ! a l • •- E /z 1•-• a U 0o I r } >- 1 'I I co I Cez o� M N C dll— YO I E = co Z N l i J 2 I0 0 0 o y I m c G cc, i C) m m N I I O) (a 0 o E Ca cc .- J y N u) u) 5 0 E Y I t ( - fn n m 1I c v, Cn Qci. a y E a) co ,� C C Q g ,cu c o a) 1� loQ a ao / z ! u) ! Qo w w w w v A J Ce N N N N Z 7 a) a) N a) (n ra 3• co C E .o .o .o .o 0 1 c z � - 1 o co I CeZ 0 0 0 > E 'I IP c c c c p co } } O p z O — k D / o / O co r N N N N coN C > N Z �' O W O Z N N CV CV CV N CV N W U `o 3 N j O r W r N O Q 6. 10 r a a, o E 1 > .` Z V .� LL A E 0 y Yfr 0 (0 re .+ C a N Z H c ~ N 1/1 V O O a) 0 a) a) Q o C 2 ' r c .. ao i cc 1 Z w c U c '� y J U 0 a 7 o E a • a =U'ILI o:( a —y o) '.9 a o 0 o a a y OLL o ° aa)) 0 0 a. ce 10 F- J 0 F- J J J W a ? 0 a 0 : U U / 2 / / STATE OF ALASKA ALASr.A OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Performed: Abandon r Repair w ell r Rug Perforations r Perforate r Other y, Prod to WINJ Alter Casing r Pull Tubing r Stimulate-Frac r Waiver r Time Extension r Change Approved Program r Operat.Shutdown r Stimulate-Other 17 Re-enter Suspended Well r 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: ' F.ConocoPhillips Alaska, Inc. Development ; Exploratory r 212-86q4 14 v 3.Address: 6.API Number: Stratigraphic r Service P.O. Box 100360,Anchorage,Alaska 99510 - 50-103-20091-60 7.Property Designation(Lease Number): 8.Well Name and Number. ADL025531 - 3H-11AL1 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): A Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 8455 feet Plugs(measured) None true vertical 6088 feet Junk(measured) None Effective Depth measured 8455 feet Packer(measured) 2701, 6776,6825, 7065 true vertical 6088 feet (true vertical) 2401,5837, 5872,6040 Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 115 115 0 0 1 SURFACE 3602 10.75 3637 3088 0 0 WINDOW AL1 0 4.5 7066 6040 0 0 LINER AL1 1194 2.7 8453 6087 0 0 o o 0 0 0 0 Perforation depth: Measured depth: 7285-8452 True Vertical Depth: 6099-6087 . 4 Tubing(size,grade,MD,and TVD) 3.5, L-80,6825 MD, 5872 TVD Packers&SSSV(type,MD,and TVD) WHIPSTOCK-WHIPSTOCK SET FOR SIDETRACK A @ 2701 MD and 2401 TVD ' ` • NIPPLE-HES X NIPPLE @ 6776 MD and 5837 ND LOCATOR-BAKER 80-40 GBH-22 LOCATOR SUB @ 6825 MD and 5872 ND WHIPSTOCK-SET FOR CTD LATERALS AL1,AL1-01 @ 7065 MD and 6040 ND 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 308 825 1516 14.Attachments 15.Well Class after work: Copies of Logs and Surveys run Exploratory r Development r Service p, Stratigraphic r 16.Well Status after work: Oil r Gas r! WDSPL r Daily Report of Well Operations x GSTOR r WIND C WAG r GINJ r SUSP r SPLUG r 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C 0.Exempt: 313-112 Contact Bob Christensen/Darrell Humphrey Email N1139(a)conocophillips.com Printed Name Ro B Christense Title NSK Production Engineering Specialist Signature , '� Phone:659-7535 Date /�9//3 AW Form 10-404 Revised 12/ReDMS MAR 2 9 2013 Vi-- /3 Submit Original Only 3H-11AL1 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 03/20/13 PULLED OV&GLVs @,6593', 5978', 5303', 4256' &2867' RKB. SET DVs @ 5978', 5303', 4256' &2867' RKB. IN PROGRESS. 03/21/13 LOADED IA WITH INHIBITED SW& DSL CAP. CMIT FAILED. SET DV @ 6593' RKB. MIT IA 2500 PSI, PASSED. PULLED AVA CATCHER @ 6776' RKB. 03/25/13 Commenced WINJ service `, py KUP 3H-11AL1 Conoc hiIIi :.%Pa Well Attribuk(Aa.; ,Max Angle&I TO Wellbore API/UWI Field Name Well Status Incl(°) MD(ftKB) Act Btm(ftKB) Alaska.loC �r.k,cda„il,r„, 501032009160 KUPARUK RIVER UNIT PROD 97.01 7,960.70 8,455.0 _ Comment H2S(ppm) Date Annotation End Date KB-Ord(It) Rig Release Date •Well Con59:DEVIATED-3H-11AL1,3/1720139:5271 AM SSSV:TRDP 245 11/26/2009 Last WO: 8/17/2012 42.01 12/28/1987 Schematic-Actual Annotation Depth(RKB) End Date Annotation Last Mod...End Date Last Tag .,Rev Reason WAIVER CANCELED 3/20/2013 osborl 3/27/2013 HANGER.26 i Casing Strings Casing Description String 0... String ID...Top(ftKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd Liner AL1 23/8 1.995 7,258.7 8,453.0 6,087.6 4.60 L-80 ST-L liner Details Top Depth (TVD) Top Incl Nomi... Top(MB) (ftKB) (°) Rem Description Comment ID(In) III 7,258.7 6,100.0 90.65 BILLET LINER TOP BILLET 1.000 CONDUCTOR, I Perforations&:SIMS 35-115 Shot Top(ND) Btm(TVD) Dens Top(RKB)Btm(RKB) (ftKB) (RKB) Zone Date Oh— Type Comment SAFETY vw - - 1,978 o. , 7,285.3 8,452.6 6,099.1 6,087.6 A-2,A-3,A-2, 11242012 32.0 SLOTS -- A-3,A-2, P 3H-11AL1 wHIP6T270K1 - s:General&Safety V4NDOW A. I-I- End Date Annotation 2.701-2,721 4/30/1999 NOTE:WORKOVER ii 7/21/2001 NOTE:WORKOVER GASLI,667 FT,__. 8/172012 NOTE:WELL WORKOVER/SIDETRACK'A'-Original Prod Csg cut/pulled @ 2451' 2 s� E 12/2/2012 NOTE:CTD ADDED LATERALS AL1,AL1-01 It SU353.63RFACE,7 . _ _o a i I GAS LIFT. lir 4,256 I I I GAS LIFT, 5,303 I I I GAS LIFT. IL 5.978 I I GAS LIFT. -11 6593 ■ ■ a NIPPLE,6.776 it I I LOCA682TOR5 M SEALA6,82SSY, 6 illtandrel Details, Top Depth Top Poll (TVD) Incl OD Valve Latch Size TRO Run N...Top(ftKB) (RKB) (°I Make Model (in) Sery Type Type (In) (psi) Run Date Com... PRODUCTION 1 2,867.4 2,524.0 41.74 CAMCO MMG 1 12 GAS LIFT GLV R-20 0.188 1,300.0 12/112012 POST art, 2 4,255.9 3,723.1 26.79 CAMCO MMG 1 12 GAS LIFT GLV R-20 0.188 1,277.0 12/12/2012 26.6.907\ -.---e • WHIPSTOCK, 3 5,302.7 4,651.9 26.44 CAMCO MMG 1 12 GAS LIFT GLV R-20 0.188 1,256.0 12/12/2012 � WINDOW7. AL1, 4 5,978.4 5,243.4 32.82 CAMCO MMG -1 12 GAS LIFT GLV R-20 0.188 1,237.0 12/12/2012 7,0INER 7 6513-7,375 LINE "� 5 6,593.4 5,707.5 45.04 CAMCO MMG 1 12 GAS LIFT OV rdo20 0.250 0.0 12/112012 SLOTS. 7285-8,453 Liner AL1, 7,259-8,453- il TD(3H-11AL1), \ 8.455 , . . • (-,, ,,F�jy��s� THE STATE Alaska Oil and Gas i='"' °'ALASI�:A Conservation Commission �*R GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF ;,'•.� Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Darrell R. Humphrey NSK Production Engineering Specialist at , / / c3 ConocoPhillips Alaska, Inc. 1 �O P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, 31-1-11AL1 Sundry Number: 313-112 Dear Mr. Humphrey: 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 Commission grants for good cause shown, a person affected by it may file with the Commission 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, --V-(- f4e- Cathy . Foerster � / Chair DATED this ll'`" day of March, 2013. Encl. STATE OF ALASKA & A (A OIL AND GAS CONSERVATION COMM I IN r I 1� APPLICATION FOR SUNDRY APPROvALS Sal 20 AAC 25.280 1.Type of Request: Abandon ❑ Rug for Redrill ❑ Perforate New Pool ❑ Repair w ell ❑ Change Approved Program ❑ Suspend ❑ Rug Perforations ❑j Perforate [I RAI Tubing ❑ Time Extension ❑ Operational Shutdown ❑ Re-enter Susp.Well ❑ Stimulate ❑ Atter casing ❑ Other:Prod to WINJ • 12 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. i IiZol3 ConocoPhillips Alaska,Inc. Development R. Exploratory ❑ 242 68U' .20,/(0c. '. 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: P.O.Box 100360,Anchorage,Alaska 99510 50-103-20091-60 • 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 ❑ No E 3H-11AL1 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 25531• Kuparuk River Field I Kuparuk River Oil Pool • 11. PRESENT WELL CONDITION SUMMARY Total depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 8455 • 6088 • 8455' 6088' Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 115' 115' SURFACE 3602 10.75 3637' 3088' WINDOW AL1 0 4.5 7066' 6040' RECEIVED LINER AL1 1194 2.7 8453' 6087' MAR 0 5 2013 AOGCC Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): •7285-8452 6099-6087 3.5 L-80 6825 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft) WHIPSTOCK-WHIPSTOCK SET FOR SIDETRACK A MD=2701 TVD=2401 • NIPPLE-HES X NIPPLE MD=6776 TVD=5837' LOCATOR-BAKER 80-40 GBH-22 LOCATOR SUB MD=6825 TVD=5872 • WHIPSTOCK-SET FOR CTD LATERALS AL1,AL1-01 MD=7065 TVD=6040 SSSV-CAMCO TRMAXX-CMT-SR-5 MD=1978 TVD=1839 12.Attachments: Description Summery of Proposal R• 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory r Stratigraphic ❑ Development ❑ Service r • 14.Estimated Date for Commencing Operations: 15. Well Status after proposed work: 3/7/2013 Oil ❑ Gas ❑ WDSPL ❑ Suspended r 16.Verbal Approval: Date: WINJ l• GINJ ❑ WAG ❑ Abandoned In Commission Representative: GSTOR ❑ SPLUG In 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Bob Christensen/Darrell Humphrey Email: N1139@conocophillips.com Printed Name Darrell R. Humphrey Title: NSK Production Engineering Specialist Signature Phone:659-7535 Date 3.3. /3 Comission Use Only Sundry Number..3i"J - Conditions of approval: Notify Commission so that a representative may witness Plug Integrity In BOP Test p ,Jlechanical Integrity Testor Location Clearance ❑ • Other: fj 1 h I 1-e,1-7 -)q Stab' ku1 fiilrs.5rL Jr ffrr bi I1se Spacing Exception Required? Yes ❑ No [r Subsequent Form Required: /v — 46 RBDMS MAR 1 g @!, /� APPROVED BY IVB 4 Approved by: f" COMMISSIONER THE COMMISSION Date: 3 '�( f� Approved application Is valid tor 12 months trom the date of approval. O m 1 3 012) Submit Form and Attachments i Duplicate N, 3H-11AL1 - ' DESCRIPTION SUMMARY OF PROPOSAL ConocoPhillips Alaska Inc. requests approval to convert Kuparuk Well 3H-11A and its associated laterals from Oil Production service to Water Injection service. The CTD Permit to Drill (which added multi-laterals AL1,AL1-01)was completed with the well as an injection well, but the completion report was filed as an oil producer to allow for extended pre-production. The pre-production period following CTD operations has now been completed and the well is being prepared for initial water injection. - KUP 3H-11AL1 �, l� A�COnOCOrnilp5 : Well Attributes Max Angle&MD TD AlaskaWellbore API/UWI Field Name Well Status Incl(°) MD(ftKB) Act Btm(ftKB) ixxwar„ 501032009160 KUPARUK RIVER UNIT PROD 97.01 7,960.70 8,455.0 Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date •••Well ConBg:DEVIATED-3H-11 AL1,1/24/2013 8:3834 AM SSSV:TRDP 245 11/26/2009 Last WO: 8/17/2012 42.01 12/28/1987 Schematic-Actual Annotation Depth(ftKB) End Date Annotation Last Mod...End Date Last Tag: Rev Reason:GLV C/O osborl 1/24/2013 Casing Strings HANGER.26 Casing Description String 0... String ID...Top(ftKB) Set Depth(t...Set Depth(TVD)...String Wt..String... String Top Thrd _._, Liner AL1 23/8 1.995 7,258.7 8,453.0 6,087.6 4.60 L-80 ST-L Liner Details Top Depth (ND) Top incl Nomi... Top)ftKB) (ftKB) (°) :Item Description Comment ID(In) 7,258.7 6,100.0 90.65 BILLET LINER TOP BILLET 1.000 CONDUCTOR. Perforations&Slots 35-115 Shot Top(ND) Btm(TVD) Dens Top(5KB)Btm(ftKB) (ftKB) (ftKB) Zone Date (a0.- Type Comment SAFETY VLV. - f-----I 7,285.3 8,452.6 6,099.1 6,087.6 A-2,A-3,A-2, 11/24/2012 32.0 SLOTS 1,978 A-3,A-2, 3H-11AL1 WHIPSTOCK, Notes:General&Safety , WINDOW A, 1 _ End Date Annotation 2. 2,701-2.721 4/30/1999 NOTE:WORKOVER 7/21/2001 NOTE:WORKOVER GAS LIFT, 12/2/2012 NOTE:CTD ADDED LATERALS AL1,AL1-01 2,887 SURFACE, A I ' 35-3,637 11 V GAS LIFT, 4,IT, LEI GAS LIFT. f 5.303 T. GAS LIFT, 5 9?? 1 GAS LIF6,593 T. 1 C NIPPLE,5776 ---- �[ LOCATOR. S825 1 SEAL ASS(, 6.826 Mandrel Details Top Depth Top Port (ND) Incl OD Valve Latch Size TRO Run N...Top(ftKB) (11(13) (1 Make Model (in) Sery Typa Type (In) (psi) Run Date Com... PRODUCTION 1 2,867.4 2,524.0 41.74 CAMCO MMG ' 1 1/2 GAS LIFT GLV R-20 0.188 1,300.0 12/11/2012 POST,907 • •s/T. 2 4,255.9 3,723.1 26.79 CAMCO MMG 1 1/2 GAS LIFT GLV R-20 0.188 1,277.0 12/12/2012 29-0 WHIPSTOCK 7.085 3 5,302.7 4,651.9 26.44 CAMCO MMG 1 1/2 GAS LIFT GLV R-20 0.188 1,256.0 12/12/2012 WINDOW AL1, 7,088-7,072 4 5,978.4 5,243.4 32.82 CAMCO MMG 1 1/2 GAS LIFT GLV R-20 0.188 1,237.0 12/12/2012 LINER A. 8.8137,375 5 6,593.4 5,707.5 45.04 CAMCO MMG 1 1/2 GAS LIFT OV rdo20 0.250 0.0 12/11/2012 SLOTS, 7.2853.453 Liner ALL\ 7,259$453 TO(3H-11AL1), 0.455 BAKER PRINT DISTRIBUTION LIST HUGHES -�-] COMPANY ConocoPhillips,Alaska Inc. INTERMEDIATE FINAL Yes irno IWI(UIy) WELL NAME 3H-IIAL1 RUN NUMBER (mandatory) FIELD Kuparuk BH SALESMAN Woods,Jim (mandatory) (mandatory) COUNTY North Slope Borough BH DISTRICT Alaska (mandatory) (mandatory) STATE Alaska PAGE OF (mandatory) LOG DATE: November 24,2012 TODAYS DATE: 2/11/2013 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: ConocoPhillips,Alaska Inc. mandatory) HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? COMPANY CD FIELD FINAL (digital/ ADDRESS(FEDEX WILL NOT DELIVER TO P.O.BOX) LOGS LOGS image) FILM PERSON ATTENTION #OF PRINTS #OF PKIN I #OF COPIES #OF COPIES _ 1 ConocoPhillips Alaska,Inc. 1 NSK Wells Aide,NSK 69 ATTN:MAIL ROOM 700 G Street, Anchorage,AK 99501 2 AOGCC 1 1 Christine Mahnken 333 West 7th Ave,Suite 100 Anchorage,Alaska 99501 3 BP 1 1 Petrotechnical Data Center,MB33 David Douglas 900 East Benson Blvd Anchorage,Alaska 99508 4 Chevron/KRU REP 1 1 Glenn Fredrick 3800 Center Point Drive,Suite 100 Anchorage,Alaska 99503 5 Brandon Tucker,NRT I State of Alaska;DNR,Div.of Oil and Gas 550 W.7th Ave,Suite 800 Anchorage,Alaska 99501-3510 TOTALS FOR THIS PAGE: 0 4 4 0 0 0 TOTALS FOR ALL PAGES: 0 4 4 0 0 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la Well Status Oil O • Gas ❑ SPLUG ❑ Plugged ❑ Abandoned ❑ Suspended ❑ 1b.Well Class: 20AAC 25.105 20AAC 25.7 .1-.tl!ievelopment ❑✓ • Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ Other ❑ No.of Completions. 1 Service ❑ Stratigraphic Test❑ 2.Operator Name: 5.Date Comp.,Susp, aw 12.Permit to Drill Number: ConocoPhillips Alaska, Inc. orAband.: November 2012 212-160/ • 3.Address. 6.Date Spudded: 13.API Number: P.O. Box 100360,Anchorage,AK 99510-0360 November 23,2012 • 50-103-20091-60 • 4a.Location of Well(Governmental Section): 7.Date TD Reached 14.Well Name and Number: Surface: 1232'FNL,281'FWL,Sec. 12,T12N,R8E,UM • November 24,2012 3H-11AL1 • Top of Productive Horizon. 8. KB(ft above MSL): 69.6'RKB • 15 Field/Pool(s). 376'FSL,2381'FEL,Sec. 1,T12N,R8E, UM GL(ft above MSL): 38.7'AMSL • Kuparuk River Field Total Depth: 9.Plug Back Depth(MD+TVD): 343'FSL,2478'FWL,Sec. 1,T12N,R8E,UM 8455'MD/6088'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-498655 • y- 6000425 • Zone-4 ' 8455'MD/6088'TVD• ADL 25531 ' TPI: x-501272 y- 6002033 Zone-4 11.SSSV Depth(MD+TVD): 17.Land Use Permit Total Depth: x-500851 y- 6002000 Zone-4 1978'MD/1839'ND 2657 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) 2701'MD/2401'ND 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 7066'MD/6040'ND • 23. CASING,LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH ND HOLE AMOUNT CEMENTING RECORD CASING SIZE WT.PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE PULLED 16" 62.5# H-40 36' 115' 36' 115' 24" 215 sx AS I 10.75" 45.5# J-55 35' 3637' 35' 3088' 13.5" 1200 sx AS III,600 sx Class G,130 sx AS I 7" 26# L-80 28' 6907' 28' 5929' 8.75" 239 sx Class G,116 sx LiteCRETE 2.375" 4.7# L-80 7259' 8455' 6100' 6088' 3.25" slotted liner 24.Open to production or injection? Yes ❑✓ No ❑ If Yes,list each 25. TUBING RECORD Interval open(MD+ND of Top&Bottom,Perforation Size and Number): SIZE DEPTH SET(MD) PACKER SET(MD/TVD) 3.5" 6863' 6813'MD/5863'ND 7285'-8453'MD 6100'-6088'ND �g.�E: 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. E C E r"' Was hydraulic fracturing used during completion? Yes❑ No 0il. DEC 2 8 2[11/ DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED '• t AOGCC 27 PRODUCTION TEST Date First Production Method of Operation(Flowing,gas lift,etc.) December 20,2012 • gas lift oil ' Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO 12/22/2012 21 hours • Test Period--> 769 1533 627 128/64 1993 Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-API(corr) Press. 211 1000 psig 24-Hour Rate-> 879 1752 717 22.3 deg. 28. CORE DATA Conventional Core(s)Acquired? Yes ❑ No Q • Sidewall Cores Acquired? Yes ❑ No ❑✓ If Yes to either question,list formations and intervals cored(MD+ND 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. NOT APPLICABLE RR :MS DEC 3 1 2012 �• 17? Form 10-407 Revised 10/2012 CONTINUED ON REVERSE Submit original only /Z 3/IL `� `�' 29 GEOLOGIC MARKERS(List all formations and ma..._.s encountered) 30. FORMATION TESTS NAME MD TVD Well tested? Yes Q No If yes,list intervals and formations tested, Permafrost-Top ground surface ground surface bnefly summarizing test results. Attach separate sheets to this form,if Permafrost-Bottom 2701' 2401' needed,and submit detailed test information per 20 AAC 25.071. Kuparuk A2 8196' 6074' Kuparuk A3 8020' 6067' N/A Formation at total depth: Kuparuk A3 31. LIST OF ATTACHMENTS Summary of Daily Operations,schematic,final directional survey 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kai Starck @ 263-4093 Email: Kai.Starck@conocophillips.com Printed Name Lamar Gantt /4 Title: CT Drilling Manager Signatur lL%r� fri llPhone 263-4021 Date /Z " z.7' -/2 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 3H-11AL1 ConocoPhillips ' Well Attributes Max Angle&MD TD IncWellbore APUUWI Field Node Well Status Incl(1) MD(ft/(13) Act Btm(ftKB) Alaska. 501032009160 KUPARUK RIVER UNIT ,INJ 8,455.0 Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date .. Well tonna:-3H-nnu,12/4/2012 105721 AM —SSSV:TRDP 245 11/26/2009 Last WO: 42.01 12/28/1987 Schematic-Actual Annotation Depth(ftKB) End Date Annotation Last Mod...End Date Last Tag: Rev Reason:ADD LATERALS ninam 12/4/2012 HANGER,28 Casing Strings Casing Description String 0... String ID...Top)ftKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd Liner AL1 2 3/8 1.995 7,258.7 8,453.0 4.60 L-80 ST-L Liner Details Top Depth (TVD) Top Incl Nomi... I I Top(KKB) (MD) C) Item Descciptten Comment ID(in) i 7,258.7 & BILLET LINER TOP BILLET 1.000 CONDUCTOR. I r. Perforations Slots 35-115 j Shot ETop(TVD) Btm(TVD) Dens Top(ORB) BUR(ftKB) (ftKB) (ftKB) Zone Date (ah-. Type Comment SAFETY VLV, �o 7,285 8,453 11/24/2012 32.0-SLOTS 1,978 Notes:General&Safety k End Date Annotation WRIPSTOCK ` 11/29/2012 NOTE:CTD LATERAL AL1,AL1-01 2,701 WINDOW 1 2,701-2,721 • GAS LIFT. - f 1 2,887 ] T P 1 I] SURFACE. J l 35-3.637 l I 1111 GAS LIFT. =. 4,256 GAS LIFT, 5.303 GAS LIFT. IWE-. 5.978 GAS LIFT, 6.593 NIPPLE,6,776 r P LOCATOR. 6.825 SEAL ASSY, 6,826 Mandrel Details Top Depth Top Port (TVD) Incl OD Valve Latch Size TRO Run Stn Top(ORB) OMB) C) Make Model (In) Se, Type Type (in) (pall Run Date Com... PRODUCTION 1 2,867.4 2,524.0 41.74 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 10/6/2012 P28-ST srt. 2 4,255.9 3,723.1 26.79 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 10/6/2012 CK, • • WHIPSTOCK 3 5,302.7 4,651.9 26.44 CAMCO MMG 1 12 GAS LIFT DMY RK 0.000 0.0 10/6/2012 WINDOW AL1, 7,066-7,072 4 5,978.4 5,243.4 32.82 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 10/6/2012 LINER A, 6.8737375 L 5 6,593.4 5,707.5 45.04 CAMCO MMG 1 12 GAS LIFT DMY RK 0.000 0.0 10/26/2012 SLOTS, 7,285-8,453 Liner AL7, �" 7,259-8,453 TO(311-17AL1),\ 8.455 0 N i'') .�' l O 7. > Lo O co (O ❑ co O N co O 01,0-b M o co o r ' M M co M ❑ • • (6 Lo N Q 2 N C _ N M C N.O �+ _ M o O U) (0 N In W J U coas co co - J 0 0 c ❑ Q O O OO V �O LO is3 65 p N V M N J pp N ti I— o) 2 CC)� E O (o ` "� C RS © U Q C V -lu E O O Q H X I— Q Q "O p- (6 O J Q ` C 4) Q O O LU O 4) tq ` I- Q En c CV0 'O N C = \r. 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OOU S S 2 O C 2 2 O M C W W W m m m m n C W O n m m (m) m m m N N N W o W CN M V O n W m O N M m V O W O m n O M n 10 M m N I0 O M M M N M M V (0 0 m 0 V m n 10 N V 0 0 0 0 V c n m (O 0 m m O d0 O O O O O O O O O O O O O O C O O O C 0 0 0 0 0 O O O O U) • O CO m W N 10 m V n O CO m W N l'.. m " O CO m W N m m 10 N C C Cl ❑ - m co co m n n n OD m m W W W W O O- O N N N N CO CO M V V O 3' A C S. �" ti N t• n r h f• t• f• n r t• m m m O m m m m a0 co' m CO CO m m 0 G d a ? cu rn U ocowd � � 7 • U d y ❑ N Il 3H-11 Pre-Rig Well Work Summary DATE SUMMARY • 10/24/12 (PRE-CTD) PT& DD TEST IViv- PASSED; SSV-PASSED; SV- PASSED; So6V- PASSED 10/25/12 DRIFTED TBG WITH 2.66" TO 7291' SLM. IN PROGRESS. 10/26/12 DRIFT TBG WITH 2.62" x 17.5' DMY WHIPSTOCK TO 7309' RKB. LRS CIRC OUT TBG & IA WITH 250 BBLS DSL. SET CATCHER @ 6641' SLM. PULLED SOV @ 6593' RKB & REPLACE WITH DV. MIT IA TO 2500 PSI ( PASS) PULLED CATCHER © 6641' SLM. JOB COMPLETE. ConocoPhillips Time Log & Summary Wel!view Web Reporting Report Well Name: 3H-11 Rig Name: NABORS CDR2-AC Job Type: DRILLING SIDETRACK Rig Accept: 11/21/2012 2:00:00 AM Rig Release: 12/2/2012 12:00:00 AM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11/20/2012 24 hr Summary Move from 2F-19 to 3H-11,Spot rig modules 06:00 19:00 13.00 MIRU MOVE MOB P Move off 2F-19 to 3H-11 19:00 21:00 2.00 MIRU MOVE MOB P Arrive on 3H pad, PJSM, Remove Jeeps, remove scaffolding from tree, pad inspection with night operator,all _good 21:00 00:00 3.00 MIRU MOVE MOB P Spot rig modules and rig up 11/21/2012 Complete BOPE Test, PT PDL's and TT. RIH and set whipstock @ 7065 High Side 00:00 02:00 2.00 0 0 MIRU MOVE MOB P Complete rig up, ACCEPT RIG @ 0200 02:00 05:00 3.00 0 0 MIRU WHDBO NUND P Nipple up BOPE,tighten tree flanges 05:00 12:00 7.00 0 0 MIRU WHDBO BOPE P Begin BOPE test, low 250, high 4000 psi.2500 psi for annular. (Note: Sue 24-hr notice given to state inspector via email @—09:30 11/20,follow-up email at—03:00 11/21. Email received back from state inspector Chuck Sheve @ 06:52 waiving witness). 12:00 16:00 4.00 0 0 MIRU WHDBO PRTS P BOPE test complete. Remove checks.Test inner-reel valves. Lubricate out BPV.Test PDLs., Hook up to SSSV 16:00 18:45 2.75 0 0 MIRU WHDBO PRTS P Test PDLs., Hook up to SSSV,Test TT line 18:45 18:45 0.01 0 0 SLOT WHDBO PRTS P 18:45 19:29 0.74 0 0 PROD1 WHPST SFTY P Hold Pre spud with Night crew (Corder) 19:29 20:41 1.20 0 75 PROD1 WHPST PULD P Make up whipstock running BHA., M/U to coil and surface test tool. 20:41 22:47 2.10 75 6,905 PROD1 WHPST TRIP P RIH, EDC Open circulating well with seawater 22:47 23:29 0.70 6,905 7,255 PROD1 WHPST DLOG P Log K-1 Marker for-21'correction, Make CCL pass and corolate to log. 23:29 23:35 0.10 7,255 7,078 PROD1 WHPST TRIP P, Tri tp o setttingdepth of 7077.98 TOWS=7065,Close EDC, Orient to high side 23:35 23:41 0.10 7,078 7,059 PROD1 WHPST WPST P Pumps on,see tool shift @ 1900PSI, Set down 5K, PUH to 23:41 23:59 0.30 7,059 7,059 PROD1 WHPST CIRC P Circulate hole to 9.8 PPG Milling fluid Page 1 of 9 Time Logs Date From To Dur S. Depth E.Depth Phase Code Subcode T Comment 11/22/2012 24 hr Summary Set Whipstock @ 7065', Milled window,7067 to 7091, RIH with Build BHA 00:00 00:18 0.30 7,059 7,059 PROD1 WHPST CIRC P Circulate well to milling fluid 00:18 02:24 2.10 65 PROD1 WHPST TRIP P Trip out, PUW=35K 02:24 03:30 1.10 65 73 PROD1 WHPST PULD P At surface, Flow check well. PJSM, Lay down BHA#1 whipstock setting tools. P/U BHA#2 window milling BHA with.6°motor,2.80 window mill with string reamer.Make up to coil and surface test 03:30 05:24 1.90 73 6,905 PROD1 WHPST TRIP P Trip in with BHA#2 Window milling BHA, EDC Open 05:24 06:00 0.60 6,905 7,066 PROD1 WHPST DLOG P Log Tie In,-21.5'correction 06:00 08:00 2.00 7,066 7,067 PROD1 WHPST MILL P Dry tag at 7067', Attempt to get window started; multiple stalls. Immediately pick up wgt and stall on contact.4 stalls,add 1%776 to help lube. PUH, attempt to let pipe walk into get started, ROP 0.2, Pumping 1.4 bpm,23 psi WHIP, 3290 CTP, WGT=19.3K. 08:00 10:45 2.75 7,067 7,072 PROD1 WHPST MILL P At 7067'; ROP=0.6,WOB=.20, pumping 1.45 bpm,CTP=3350 psi, BHP=3569 psi,WHTP=17 psi. Continue milling maintaining—1'/hr. 10:45 14:00 3.25 7,072 7,075 PROD1 WHPST MILL P At 7071.6: ROP=1.1'/hr,WOB=1.61, BHP=3563 psi,CTP=3380 psi, WGT=18.3,WHP=17 psi. IA=300 _ psi,OA=588 psi. 14:00 16:45 2.75 7,075 7,084 PROD1 WHPST MILL P Exit liner @ 7075' and drill ahead @ 1.1 ROP.WOB=.27, CTP=3220 psi, WGT=17.9, BHP=3560 psi, Rate=1.45 BPM. 16:45 18:33 1.80 7,084 7,091 PROD1 WHPST MILL P At 7084'; ROP=3.1,WOB=3.25, BHP=3558 psi,CTP=3290 psi, WHTP=8 psi,WGT=14.3, rate=1.45 BPM. 18:33 19:39 1.10 7,091 7,091 PROD1 WHPST REAM P TD Rat hole,start reaming passes, 1 @ HS, 1 @ 30L, 1 @ 30R, Dry drift window, looks great 19:39 21:45 2.10 7,091 51 PROD1 WHPST TRIP P POOH for build section BHA 21:45 22:15 0.50 51 0 PROD1 WHPST PULD P PJSM, Flow check well, Lay down BHA#2 widow milling run 22:15 23:39 1.40 0 62 PROD1 DRILL PULD P M/U BHA#3, Build section with 2.5° Motor and 3.25 Hycalog Bi Center bit. M/U to coil and surface test 23:39 00:00 0.35 62 250 PROD1 DRILL TRIP P Trip in well, EDC Open 11/23/2012 Drill Build section to TD @ 7340,Trip for lateral BHA#4, RIH drill to 7773 00:00 02:00 2.00 250 6,905 PROD1 DRILL TRIP P Continue in well, EDC Open 02:00 02:12 0.20 6,905 6,946 PROD1 DRILL DLOG P Log tie in for-23.5, Shut EDC, PUW=31K Page 2 of 9 Time Logs Date From To Dur S. Depth E.Depth Phase Code Subcode T Comment 02:12 02:24 0.20 6,946 7,091 PROD1 DRILL TRIP P Trip in to drill, RIW=19.5K, Good pass through window with high bend motor 2.5° 02:24 04:30 2.10 7,091 7,240 PROD1 DRILL DRLG P Bring pumps online, 1.5 BPM @ 3400 PSI FS, BHP=3690,WHP=125 PSI 04:30 04:54 0.40 7,240 6,900 PROD1 DRILL WPRT P Wiper trip up through window with tie into K-1 and log RA, PUW=32K, Clean pass up through window.Open EDC pull up to 6900' 04:54 05:00 0.10 6,900 6,930 PROD1 DRILL DLOG P log K-1 for no correction 05:00 05:12 0.20 6,930 7,090 PROD1 DRILL WPRT P RIH to 7000',Trap Pressure, Shut down pump, Shut EDC, RIH to 7090 05:12 05:24 0.20 7,090 7,110 PROD1 DRILL DLOG P Log RA marker @ 7073.5, TOWS=7066,TOW=7068, BOW=7076 05:24 07:30 2.10 7,240 7,340 PROD1 DRILL DRLG P Drill ahead build.section..Perform • mud swap.TD build section at 7340'. 07:30 09:30 2.00 7,340 0 PROD1 DRILL TRIP P Begin POOH. Pass cleanly through window. 09:30 12:30 3.00 0 0 PROD1 DRILL PULD P Pressure undeploy BHA.Make up Lateral AL1 drilling BHA#4. 12:30 14:30 2.00 0 7,340 PROD1 DRILL TRIP P Run in hole with BHA#4. Log tie-in, -25, and cont RIH. 14:30 17:00 2.50 7,340 7,490 PROD1 DRILL DRLG P Begin drilling ahead. PUW=31K, RIW=16.5K, pumping 1.50 BPM, 3770 psi Circ, 1.0 WOB, 185 psi WHP, 3705 psi BHP, IA=247, OA=136 psi. Begin bring up ROP=50'/hr. 17:00 18:00 1.00 7,490 7,490 PROD1 DRILL WPRT P Wiper trip with MAD Pass 7350- 7090 18:00 20:18 2.30 7,490 7,640 PROD1 DRILL DRLG P 7490', Drill Ahead, 1.45 BPM @ 3290 PSI FS, BHP=3730 20:18 21:00 0.70 7,640 7,640 PROD1 DRILL WPRT P Wiper to window, PUW=31K, RIW=19K, BHP=3780 21:00 21:48 0.80 7,640 7,675 PROD1 DRILL DRLG P 7640', Drill Ahead, 1.44 BPM @ 3300 PSI FS, BHP=3780,WHP=250 21:48 00:00 2.20 7,675 7,773 PROD1 DRILL DRLG P Stall @ 7675, Bring pump rate up to 1.6 BPM @ 3700 PSi FS, WHP=250, BHP=3800 11/24/2012 TD AL1 Lateral @ 8455',Condition hole,Trip out and M/U AL1 Liner 00:00 00:18 0.30 7,773 7,790 PROD1 DRILL DRLG P Drilling ahead(Cont.) 00:18 00:54 0.60 7,790 7,090 PROD1 DRILL WPRT P Wiper to window with tie in to RA marker, PUW=33K,WHP=220, BHP=3760 00:54 01:00 0.10 7,090 7,114 PROD1 DRILL DLOG P Log RA Marker for+2.5' 01:00 01:24 0.40 7,114 7,792 PROD1 DRILL WPRT P Continue wiper trip to bottom, Clean trip in and out 01:24 03:12 1.80 7,792 7,940 PROD1 DRILL DRLG P Drill Ahead, 1.61 BPM @ 3700 PSI FS, RIW=17.4K, BHP=3780, WHP=230 03:12 04:06 0.90 7,940 , 7,940 PROD1 DRILL WPRT P Wiper trip to 7090', PUW=32K, Clean trip in and out Page 3 of 9 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:06 07:06 3.00 7,940 8,090 PROD1 DRILL DRLG P 7940', Drill Ahead, 1.6 BPM @ 3760 PSI FS,WHP=210, BHP=3760, RIW=17.5 07:06 10:06 3.00 8,090 8,240 PROD1 DRILL DRLG P Perform wiper. Drill ahead-50' ROP, 1.5 bpm,3840 BHP, 11.25 RIW,2.43 WOB. 10:06 11:36 1.50 8,240 7,095 PROD1 DRILL WPRT P Perform wiper/Tie-in(+3.5'). PUW=33K,Circ=4100 psi, 1.55 BPM, BHP=3830 psi. 11:36 13:00 1.40 8,240 8,390 PROD1 DRILL DRLG P RBIH; resume drilling ahead. Pumping 1.53 bpm,3837 BHP, 3880 circ,2.24 WOB,WHP=290, ROP 62'/hr. IA=480, OA=414. 13:00 15:30 2.50 8,390 8,455 PROD1 DRILL DRLG P Perform wiper; resume drilling ahead to 8455'. Pump 12/14 bbl low/hi-vis sweep.Circ=3630 psi,WHP=240 psi, Rate=1.53, BHP=3859 psi.TD • well at 8455'. 15:30 16:45 1.25 8,455 7,095 PROD1 DRILL WPRT P Pick up off bottom,chase sweep out of window. PUW=44K 16:45 16:51 0.10 7,095 7,110 PROD1 DRILL DLOG P Log tie in for+2.5'correction 16:51 17:45 0.90 7,110 8,455 PROD1 DRILL WPRT P Continue wiper trip back to bottom, Al_jY confirm TJ .JAW_ 17:45 20:45 3.00 8,455 50 PROD1 DRILL TRIP P Tripping out laying in beaded liner running pill, Paint EOP flags @ 7100 and 5700', Open EDC and flush SSSV 20:45 21:30 0.75 50 0 PROD1 DRILL PULD P Tag up at surface,Trap 660 PSI, Shut EDC and perform No Flow test, all good, PJSM Lay down drilling BHA#4 21:30 22:30 1.00 0 0 COMPZ CASING PUTB P Prep floor to run liner.service top drive 22:30 00:00 1.50 0 0 COMPZ CASING PUTB P PJSM, P/U BHA#5 NonP orted Bullnose, 35 Jts 2 3/8"liner 2 Pups joints with liner top billet, Perform Safety joint drill @ Jt 5 2 Minute drill 11/25/2012 Set AL1 Liner @8445',TOL 7258,M/U BHA and drill off liner top billet 00:00 00:30 0.50 0 1,157 COMPZ CASING PUTB P Continue to make up AL1-Liner, 35 Jts,two pups, Liner top billet 00:30 01:24 0.90 1,157 1,229 COMPZ CASING PULD P Liner in well, M/U coil track,surface test tools,Strip on well,Tag up and set counters 01:24 03:24 2.00 1,229 6,954 COMPZ CASING RUNL P Trip in well, EDC shut,Open SSSV 03:24 03:30 0.10 6,954 6,929 COMPZ CASING DLOG P Stop and correct to 5700'EOP flag for-25'correction, PUW=33K 03:30 03:54 0.40 6,929 8,070 COMPZ CASING RUNL P Continue in well 03:54 04:06 0.20 8,070 8,093 COMPZ CASING DLOG P Log K-1 for-.5'made no correction, Drive by 7100'EOP flag right on depth Page 4 of 9 Time Logs Date From To Dur S.Depth E.Depth Phase Code Subcode T Comment 04:06 04:36 0.50 8,093 8,442 COMPZ CASINGIRUNL P Continue in well, Ratty from 8425, No setdowns until)8442,Work liner at different speeds 20-50 FPM same spot every time. Hard Bottom-5.5K DHWOB, PUW=38K, Pumps on @1.3 @ 3600 PSI, PUW=32K. Lost 3.5K DHWOB. BOL=8442. TOL=7258 t!A ( 1 *Later discovered pipe tally error. Liner was 10'longer than planned 1 and in fact did reach TD. 04:36 07:00 2.40 8,442 0 COMPZ CASING TRIP P Tri out of well with liner running 9 tools, remove liner length left in hole from counters 07:00 08:30 1.50 0 0 COMPZ CASING PULD P Pressure undeploy liner running BHA#5. 08:30 10:00 1.50 0 0 PROD2 STK PULD P Pressure deploy AL1-01 drilling BHA#6. 10:00 10:15 0.25 0 0 PROD2 STK TRIP P Trip in hole. 10:15 12:00 1.75 1,500 7,258 PROD2 STK TRIP P At 1500'; pumping 1.25 bpm,490 psi WHP, 1355 BHP,6.5K RIW. 12:00 12:30 0.50 7,258 7,258 PROD2 STK DLOG P Log tie-in.-25'correction. 12:30 15:00 2.50 7,258 7,261 PROD2 STK KOST P Tag billet at 7257'. Begin time milling,stall(X3). PUH and S reattempt. Rate=1.48,WHP=187 psi, BHP=3733 psi, Circ=3450 psi. IA=140,OA=100. 15:00 16:15 1.25 7,261 7,268 PROD2 STK KOST P Continue to mill per CTD guideline. CTW=18.7, 1.48 bpm, ROP=6.9, WOB=.47,WHP=240 psi, BHP=3716 psi. 16:15 17:00 0.75 7,268 7,315 PROD2 DRILL DRLG P Drill ahead past billet. 1.5 BPM @ 3410 PSI FS, BHP=3761 17:00 18:00 1.00 7,315 7,315 PROD2 DRILL WPRT T Wiper trip past billet to drift. Clean trip up set down @ 7257 dry.Try 4 times to get by at multiple speeds. Attemp to creep by<3FPM. No good consult town. Set down lightly and roll pumps at min rate. Popped right through,Continue wiper to bottom 18:00 20:18 2.30 7,315 7,465 PROD2 DRILL DRLG P Drilling Ahead 1.5 BPM @ 3470 PSI FS, BHP=3780 20:18 20:54 0.60 7,465 7,465 PROD2 DRILL WPRT P Wiper to window, PUW=31K,Clean trip up past billet,Set down @ 7257 Dry. PUH pumps on Min rate .3 BPM not a bobble going down past billet @ 15 FPM. Continue in to drill 20:54 21:54 1.00 7,465 7,550 PROD2 DRILL DRLG P 7465', Drill ahead, 1.5 BPM @ 3530 PSI FS,WHP=220, BHP=3770 21:54 22:30 0.60 7,550 7,550 PROD2 DRILL WPRT T POOH for AKO Change, re evaluate numbers Decide to RBIH drill ahead, PUW=31K 22:30 23:24 0.90 7,550 7,615 PROD2 DRILL DRLG P 1.5 BPM @ 3660 PSI FS, BHP=3825,WHP=180 23:24 00:00 0.60 7,615 7,615 PROD2 DRILL WPRT P Wiper to window, PUW=32K,Clean trip past billet dry Page 5 of 9 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11/26/201224 hr summary Drill ahead from 7615 to 7650. POOH for AKO Adj. Drill ahead from 7650 to 8353,Swap Mud 00:00 00:18 0.30 7,615 7,650 PROD2 DRILL DRLG P Drill Ahead 1.4 BPM @ 3500 PSI FS, BHP=3816 00:18 02:36 2.30 7,650 44 PROD2 DRILL TRIP T Trip out of hole to dial up motor.will not stay in polygon. .9°motor with Hughes bit avg DLS=10.6, PUW=31 K 02:36 04:06 1.50 44 0 PROD2 DRILL PULD T At Surface, PJSM to PUD BHA#6, .9°motor 04:06 05:30 1.40 0 72 PROD2 DRILL PULD T PD BHA#6,AL1-01 Lateral BHA with 1.5°AKO motor and re run Hughes 2.8 X 3.25"Bi Center 05:30 07:15 1.75 72 6,891 PROD2 DRILL TRIP T Trip in Hole 07:15 07:30 0.25 6,891 6,920 PROD2 DRILL DLOG T Log tie-in.-25'correction. 07:30 08:00 0.50 6,920 7,650 PROD2 DRILL TRIP T Continue trip.Tag top of billet at 7257'dry, roll pump @ min rate and make it thru w/no issues.Trip to bottom. 08:00 09:30 1.50 7,650 7,748 PROD2 DRILL DRLG P Resume drilling ahead.CTW=17K, 1.42 BPM,Circ=3665,WHP=204, BHP=3797,.WOB=1.55, ROP=100'. Prep for mud swap. 09:30 10:30 1.00 7,748 7,810 PROD2 DRILL DRLG P Wgt check at 7748'. PUW=32K. Continue drilling ahead. 10:30 11:06 0.60 7,810 7,116 PROD2 DRILL WPRT P Wiper to window. PUW=32K. 11:06 11:42 0.60 7,116 7,810 PROD2 DRILL WPRT P Trip back in hole. Begin mud swap. 11:42 13:00 1.30 7,810 7,880 PROD2 DRILL DRLG P Back on bottom drilling ahead. (new mud @ bit 7815'). 13:00 13:18 0.30 7,880 7,735 PROD2 DRILL WPRT P Short wiper while town/geo's confirm path forward. 13:18 13:42 0.40 7,735 7,810 PROD2 DRILL WPRT P Trip back to bottom. RIW=17.2K. 13:42 14:42 1.00 7,880 7,960 PROD2 DRILL DRLG P Drill ahead. BHP=3834,WOB 1.87, 1.4 bpm @ 4105 psi,WHP=140 psi. ✓ 14:42 15:06 0.40 7,960 7,132 PROD2 DRILL WPRT P Perform wiper. 15:06 15:30 0.40 7,132 7,960 PROD2 DRILL WPRT P Trip back in hole to TD. RIW=17.2, WHP=137, Pump=1.36 bpm@3677, BHP=3775. IA=383, OA=282. 15:30 16:30 1.00 7,960 8,025 PROD2 DRILL DRLG P Drilling ahead. Note: Swapping mud from PowerPro to FloPro system increased circ pressure from 3500 to 3700 psi. 16:30 17:45 1.25 8,025 8,110 PROD2 DRILL DRLG P Trip back in hole to TD. RIW= 16.4. WHP=165, Pump=1.38 bpm @ 3758 psi. 17:45 18:30 0.75 8,110 7,095 PROD2 DRILL WPRT P Perform wiper trip#3 18:30 21:00 2.50 8,110 8,260 PROD2 DRILL DRLG P Trip back in hole to TD. Drill ahead RIW= 16.4.WHP= 162, Pump= 1.39 bpm @ 3850 psi. 21:00 22:09 1.15 8,260 8,260 PROD2 DRILL WPRT P Perform wiper trip to window. 22:09 00:00 1.85 8,260 8,353 PROD2 DRILL DRLG P Drill ahead RIW=16.2,WHP= 172, Pump= 1.39 bpm @ 3850 psi. Page 6of9 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11/27/2012 24 hr Summary Drill AL1-01 lateral to TD 00:00 01:18 1.30 8,353 8,410 PROD2 DRILL ;DRLG P Continue drilling Ahead, 1.4 BPM @ 3785 PSI FS, BHP=3840,WHP=140 01:18 02:48 1.50 8,410 8,410 PROD2 DRILL WPRT P Wiper trip to window, PUW=31K, BHP=3885 02:48 05:18 2.50 8,410 8,560 PROD2 DRILL DRLG P 8410', Drill ahead 1.4 BPM @ 3775 PSI FS, BHP=3842,WHP=145 05:18 07:18 2.00 8,560 8,560 PROD2 DRILL WPRT P 8560,Wiper to window, PUW=31K 07:18 09:18 2.00 8,560 8,700 PROD2 DRILL DRLG P 8560', Drill ahead, 1.41 BPM @ 3920 PSI FS, BHP=3860,WHP=140 09:18 10:42 1.40 8,700 7,095 PROD2 DRILL WPRT P 8700',Call TD,Sweeps going down coil,Wiper to wndow with tie in, PUW=32.5K, BHP=3850 10:42 10:48 0.10 7,095 7,112 PROD2 DRILL DLOG P Log RA marker for+2'correction 10:48 11:36 0.80 7,112 8,700 PROD2 DRILL WPRT P Trip back in hole to confirm TD, @.8700'_ 11:36 14:36 3.00 8,700 130 PROD2 DRILL TRIP P POOH laying in beaded liner pill in open hole, PUW=32K, Paint EOP Flags @ 6900 and 5300 EOP,Wash SSSV on way out 14:36 15:06 0.50 130 130 PROD2 DRILL SSSV P Trap pressure and dump SSSV,Well will not quit flowing, .1 BPM,Shut in choke get mud out of lubricator needle valve. Cycle SSSV same results. 15:06 16:00 0.90 1,950 1,950 PROD2 DRILL SSSV T Trip in hole to jet SSSV, Recip accross SSSV twice, Dump SSSV Flowcheck well still flowing 16:00 17:45 1.75 1,950 6,900 PROD2 DRILL TRIP T Trip into well to Kill 17:45 18:00 0.25 6,900 6,936 PROD2 DRILL DLOG T 6900ft-Tie into RA correction of+2 ft. 18:00 20:30 2.50 6,936 8,700 PROD2 DRILL TRIP T 6936ft-Continue tripping to bottom. Switch to 12.0ppg completion fluid w/beads down coil. 20:30 22:45 2.25 8,700 0 PROD2 DRILL TRIP T 8700ft-POOH laying in 12.0ppg liner running pill with beads. Paint EOP flag 6900ft. Paint EOP flag 5300ft 22:45 00:00 1.25 0 0 PROD2 DRILL PULD P Surface-PJSM L/D BHA#7 11/28/2012 Lay in completion fluid w/beads. POOH and Run AL1-01 completion to TD 8700ft. Swap entire well to Sea Water. Freeze protect well from 2500ft with Diesel Set BPV. 00:00 00:15 0.25 0 0 COMPZ CASING SFTY P Surface-Prep rig floor,saftey joint and handling tools for running AL1-01 liner. 00:15 02:30 2.25 0 0 COMPZ CASING PUTB P Surface-M/U 50 jts of 2 3/8 STL Slotted Liner for AL1-01. 02:30 02:45 0.25 1,672 1,672 COMPZ CASING SFTY P 1673ft-PJSM for M/U smart tools and GS spear Page 7 of 9 Time Logs Date From To Dur S. Death E. Depth Phase Code Subcode T Comment 02:45 03:30 0.75 1,672 7,017 COMPZ CASING RUNL P 1673ft-Trip in hole with AL1-01 liner_ BHA#8. Shorty Deployment Sleeve 50 jts of Slotted liner Non-ported bull nose 03:30 03:45 0.25 7,017 7,017 COMPZ CASING DLOG P 7017ft-Correct to EOP flag correction of-23ft. 03:45 05:15 1.50 7,017 8,555 COMPZ CASING RUNL P 7117ft-Continue tripping in hole. 05:15 05:57 0.70 8,555 8,585 COMPZ CASING DLOG P Tie into K-1 for+5 did not stop liner and reset counters 05:57 06:03 0.10 8,585 8,702 COMPZ CASING RUNL P Continue in with liner,tag up and see weight @ 8697 PUW=38K,Set back down and release from liner, BOL=8702 TOL=7028 06:03 08:03 2.00 8,702 6,996 COMPZ CASING CIRC P PUH 30' , Circ out KWF to Sea water,remove liner length from counters 08:03 10:03 2.00 6,996 13 COMPZ CASING TRIP P POOH, PJSM with LRS to freeze protect well. Pump 35 BBLs Diesel out @ 2550' 10:03 11:51 1.80 13 0 COMPZ CASING PULD P At surface, PJSM to PUD BHA#8 11:51 13:06 1.25 0 0 DEMOB WHDBO PLUG P PJSM,Set BPV, Lay down BPV equipment 13:06 16:21 3.25 0 0 DEMOB WHDBO CIRC P Install Nozzle,stab on WH. PJSM, Flush stack, Pump CI down coil. Blow down coil reel with air. 16:21 18:21 2.00 0 0 DEMOB WHDBO SFTY P PJSM-bleed coil down. Unstab _coiled tubing from injector head. 18:21 19:30 1.15 0 0 DEMOB WHDBO SVRG P PJSM-Remove pac-off from injector head and secure coil at reel counter/levelwind. 19:30 00:00 4.50 0 0 DEMOB WHDBO SVRG P PJSM-Prep rig floor for injector head work. Remove injector head chains and change out injector skates. 11/29/2012 Pipe Management, Rehead BHI UQ.Work on PM items 00:00 03:30 3.50 0 0 DEMOB WHDBO SVRG P Contine to swap skates on injector head. 03:30 04:30 1.00 0 0 DEMOB WHDBO SVRG P PJSM-Stab Coil into injector head. 04:30 07:30 3.00 0 0 DEMOB WHDBO CTOP P PJSM-Cut 700ft of coil for pipe management 07:30 09:00 1.50 0 0 DEMOB WHDBO CTOP P Trimed 670'of coil, Install boot on E-Line stab on well,fill coil in reverse, Perform slack Mgmt after coil full. Unstab, cut 45'coil to find wire,Trim 5'for CTC instal,Total trim length=720' 09:00 11:00 2.00 0 0 DEMOB WHDBO CTOP P Test E-line, Dress coil and install CTC,pull test to 40K 11:00 12:00 1.00 0 0 DEMOB WHDBO CTOP P Head up E-line and test connection, PT CTC 4000PSI 12:00 13:30 1.50 0 0 DEMOB MOVE MOB P Blow down coil,stack, and surface lines Page 8 of 9 Time Logs Date From To Dur S. Depth E.Depth Phase Code Subcode T Comment 13:30 18:00 4.50 0 0 DEMOB MOVE MOB P Start rig move checklist,Service PDL connections 18:00 00:00 6.00 0 0 DEMOB MOVE MOB T Waiting on completion of well prep at 1 R-29. Work on PM items: agitator's,Tuggers, reel drive motor's, eye wash stations,and shaker. 11/30/2012 PM rig equipment. 00:00 00:00 24.00 0 0 DEMOB MOVE MOB T Continue to work on PM items such as tuggers,shaker,coiled tubing reel motor,C-16 1502 hammer unions, and pumps. 12/01/2012 00:00 00:00 24.00 0 DEMOB MOVE MOB T Continue to PM rig equipment. y Page 9 of 9 Letter of Transmittal rpI BAKER Date: December 3, 2012 HUGHES To: From: Christine Mahnken Carl Ulrich/Sachin Gandra AOGCC Baker Hughes INTEQ 333 West 7th Ave, Suite 100 795 East 94th Avenue Anchorage, Alaska 99501 Anchorage, Alaska 99515 Please find enclosed the directional survey data for the following well(s): 3H-11AL1 2m2 kk 3H-11AL1-01 2%2'kG (2) Total prints Enclosed for each well(s): 1 hardcopy print of directional survey reports (NAD27) 1 compact disk containing electronic survey files Note: Please feel free to send us an email in place of return mail. 1 Sachin Gandra, Baker Hughes, Project Engineer Sachin.Gandra@BakerHughes.com Carl.Ulrich, Baker Hughes, Survey Manager Carl.Ulrich@BakerHughes.com I., OF Ttji , aftfr Iy//'tt THE STATE Alaska Oil and Gas °f LASKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue ^^ yFb Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Lamar Gantt CT Drilling Manager ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 3H-11AL1 ConocoPhillips Alaska, Inc. Permit No: 212-160 Surface Location: 1232' FNL, 281' FWL, SEC. 12, T12N, R8E, UM Bottomhole Location: 372' FSL, 2578' FWL, SEC. 1, T12N, R8E, UM Dear Mr. Gantt: Enclosed is the approved application for permit to drill the above referenced service well. The permit is for a new wellbore segment of existing well KRU 3H-11A, Permit No 212- 062, API 50-103-20091-01. Production should continue to be reported as a function of the original API number stated above. 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 Commission 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 Commission 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 Commission order, or the terms and conditions of this permit mayresult in the revocation or suspension of the permit. P Sincerely, Ca y P oe ster Chair DATED this rJ day of November, 2012. cc: Department of Fish & Game, Habitat Section w/o end. (via e-mail) Department of Environmental Conservation w/o end. (via e-mail) 'FIECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 0 C T 2 E 2012 AAGCC PERMIT TO DRILL , , 20 AAC 25.005 ory; la.Type of Work: • lb.Proposed Well Class: Development-Oil ❑ Service-Winj ❑ ' Single Zone El lc.Specify if well is proposed for: Drill ❑ Lateral Q Stratigraphic Test ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone❑ Coalbed Gas ❑ Gas Hydrates LI Redrill ❑ Reentry❑ Exploratory ❑ Service-WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 15. Bond. U Blanket U Single Well 11.Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180 - 3H-11AL1 3.Address' '6.Proposed Depth: 12. Field/Pool(s): P.O Box 100360 Anchorage,AK 99510-0360 MD:8385' - TVD: 6005' Kuparuk River Field 4a. Location of Well(Governmental Section): 7 Property Designation(Lease Number): Surface: 1232'FNL,281'FWL,Sec. 12,T12N,R8E, UM • ADL 25531 Kuparuk River Oil Pool - Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 116'FNL, 1864'FEL,Sec. 12,T12N,R8E,UM • 2657 11/15/2012 Total Depth: 9.Acres in Property: 14.Distance to 372'FSL,2578'FWL,Sec. 1,T12N,R8E,UM \ 489 Nearest Property: 25249 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10 KB Elevation above MSL . 69.6 feet 15.Distance to Nearest Well Open Surface:x- 498655 • y- 6000425 ' Zone- 4 GL Elevation above MSL: , 38.7 feet to Same Pool: 3H-10CL2-02,700 16 Deviated wells: Kickoff depth: 7065 • ft. 17 Maximum Anticipated Pressures in psig(see 20 MC 25 035) Maximum Hole Angle: 94.7° deg, Downhole:3918 psig • Surface:3320 psig • 18 Casing Prorcram: Specifications Top - Setting Depth -Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) 3" 2.375" 4.7# L-80 ST-L 1085' 7300' 6393' 8385' 6004' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured) Effective Depth MD(ft): Effective Depth ND(ft). Junk(measured) 7750 6460 7635 6363 Casing Length Size Cement Volume MD TVD Conductor/Structural 115' 16" 215 sx AS I 115' 115' Surface 3561' 10.75" 1200 sx AS III,600 sx CI G 3637' 3088' Intermediate Production 6907' 7" 650 sx Class G,300 sx AS I 6907' 5929' Liner 562' 4.5" 84 sx Class G 7375' 6200' Perforation Depth MD(ft): Perforation Depth ND(ft): none none 20.Attachments: Property Plat❑ BOP Sketch❑ Drilling Program Q Time v.Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements Q 21 Verbal Approval Commission Representative Date' 22. I hereby certify that the foregoing is true and correct. Contact Kai Starck @ 263-4093 Email Kai.Starck@conocophillips.com Printed Name Lamar Gantt , 1 Title CT Drilling Manager � a/251/ Signature (��'j�(,�f\ 7f • Phone:265-4021 Date � Z Commission Use Only Permit to Drill / API Number: Permit Approval See cover letter Number: 2 12 /(rri C) 50-/U > 2r-- --) / - j(�•-66 Date: I tI '`Z 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: E Other: *`4o 10••": &D1 /c Sfi— Samples req'd: Yes ❑ No 121 Mud log req'd: Yes❑ No VI IA. »�.kc p H2S measures: Yes Q No Li Directional svy req'd: Yes[]" No cwti Ac-surX. ,( At° 213 Spacing exception req'd: Yes ❑ No L Inclination-only svy req'd: Yes❑ No 2 41 APPROVED BY THE / ^/ .� 11\ \i Approved by ��� COMMISSIONER COMMISSION Date ! nVl' Form 10-401 (Re sed 10/201;" This permit is valid for 44 riiont{t‘frc)m the date of approval(20 AAC 25.005(g)) l a/ ,/ J s ConocoPhillip Alaska RECEIVED P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 OCT 2 -; 2012 October 24, 2012 AOGCC Commissioner-State of Alaska Alaska Oil &Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits Permit to Drill (PTD) applications to drill and complete 3H-11AL1 and 3H-11AL1-01 from Kuparuk well 3H-11A(PTD#212-062). Coiled tubing drilling (CTD)operations are scheduled to begin November 15, 2012 using the Nabors CDR2-AC rig.• The objective of the CTD project is to improve Kuparuk A-Sand sweep efficiency and oil recovery within the target pattern by drilling lateral sidetracks. A rotary setup has recently been completed in which 7" casing was topset above the Kuparuk reservoir and a 4-1/2" production liner was run through the Kuparuk sands. Once CTD operations are completed then a 10-407 will be submitted to classify the original 3H-11 completion as 'Abandoned'. Attached to this application are the following documents that explain the proposed job operations. A BOP schematic for slimhole CTD operations from Nabors CDR2 is already on file with the Commission. — Drilling program summary — Permit to Drill application forms for 3H-11AL1 and 3H-11AL1-01 — Directional plans for 3H-11AL1 and 3H-11AL1-01 — Current wellbore schematic following the rotary setup — Proposed wellbore schematic after CTD operations If you have any questions or require additional information please contact me at my office 907-263-4093. Sincerely, Kai Starck ConocoPhillips Alaska Coiled Tubing Drilling Specialist Kuparuk CTD Laterals NABORS ALASKA 3H-11AL1 and 3H-11AL1-01 LiJ, Application for Permit to Drill Document .214C 1. Well Name and Classification 2 (Requirements of 20 AAC 25.005(1)and 20 AAC 25.005(b)) 2 2. Location Summary 2 (Requirements of 20 AAC 25.005(c)(2)) 2 3. Blowout Prevention Equipment Information 2 (Requirements of 20 AAC 25.005(c)(3)) 2 4. Drilling Hazards Information and Reservoir Pressure 2 (Requirements of 20 AAC 25.005(c)(4)) 2 5. Procedure for Conducting Formation Integrity tests 2 (Requirements of 20 AAC 25.005(c)(5)) 2 6. Casing and Cementing Program 2 (Requirements of 20 AAC 25.005(c)(6)) 2 7. Diverter System Information 3 (Requirements of 20 AAC 25.005(c)(7)) 3 8. Drilling Fluids Program 3 (Requirements of 20 AAC 25.005(c)(8)) 3 9. Abnormally Pressured Formation Information 4 (Requirements of 20 AAC 25.005(c)(9)) 4 10. Seismic Analysis 4 (Requirements of 20 AAC 25.005(c)(10)) 4 11. Seabed Condition Analysis 4 (Requirements of 20 AAC 25.005(c)(11)) 4 12. Evidence of Bonding 4 (Requirements of 20 AAC 25.005(c)(12)) 4 13. Proposed Drilling Program 4 (Requirements of 20 AAC 25.005(c)(13)) 4 Summary of Operations 4 Pressure Deployment of BHA 5 Liner Running 6 14. Disposal of Drilling Mud and Cuttings 6 (Requirements of 20 AAC 25.005(c)(14)) 6 15. Directional Plans for Intentionally Deviated Wells 6 (Requirements of 20 AAC 25.050(b)) 6 16. Quarter Mile Injection Review (for injection wells only) 6 (Requirements of 20 AAC 25.402) 6 17. Construction of Injection Wells 7 (Requirements of 20 AAC 25.412) 7 Attachment 1: Directional Plans for 3H-11AL1, 3H-11AL1-01 7 Attachment 1: Quarter Mile Pool Scan 7 Attachment 2: Current Well Schematic for 3H-11 7 Attachment 3: Proposed Well Schematic for 3H-11 CTD Laterals 7 Page 1 of 7 ;: ` R �, y t Ls October 25,2012 PTD Applicati,__ for KRU 3H-11AL1, AL1-01 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) There are two proposed laterals described in this document: KRU 3H-11AL1 and 3H-11AL1-01. 3H-11A is a rotary sidetrack from the 3H-11 motherbore. The AL1 lateral will be drilled off the A motherbore and the AL1-01 • will be drilled off the AL1 lateral. Both will be classified as"Service— Water Injection"wells. • 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) The 3H-11AL1 lateral is planned to target the Kuparuk A2 sand. The 3H-11AL1-01 lateral is planned to target the Kuparuk A3 sand. See the attached 10-401 forms for surface and subsurface coordinates of each of the 3H-11 laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005(c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and 4000 psi. Using a 1 maximum potential formation pressure of 3918,0i, the maximum potential surface pressure;is 3320 psi assuming a gas gradient of 0.1 psi/ft., Seethe"Drilling Hazards Information and Reserves_--- Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005(c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005(c)(4)(a)) The final mti\d weight while drilling the 3H-11A rotary sidetrack in October 2012 was 10.5 ppg, ECD while drilling was 11.9. Based on the shoe depth of 5929' TVD this is a BHP of 3237 psi. The proposed laterals will approach existing production wells to the north and west so our expectation is that we will not encounter significantly elevated formation pressures. The highest recent formation pressure in the area is 3H-10C laterals that had post August 2011 CTD formation pressures at 3921 psi (12.6 EMW). 3H-34 to the north has a June 2012 SBHP of 2956 psi (9.5 EMW) Maximum potential formation pressure is based on the August 2011 pressure from 3H-10C, to the west, which had a measured formation pressure of 3921 psi in the A2 and A3 sands, pr 12.6,EMW at 5980' ND. For 3H- 11A this equates to a maximum potential formation pressure of 3918 psi ( O&5'MD, 5980' TVD) and a maximum potential surface pressure of 3320 psi assuming a gas gradient to surface. Potential Gas Zones (Requirements of 20 AAC 25.005(c)(4)(b)) No specific gas zones will be drilled. 3H pad has MI injection but the fault blocks being drilled into have not been injected into. It is unlikely that an influx while drilling will produce a significant amount of gas. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005(c)(4)(c)) The major expected downhole risk in the 3H-11 laterals is hole stability due to interbedded shales and silts in the A-sand. We will mitigate hole instability by maintaining a minimum ECD target of 11.8 ppg EMW at the window V while drilling the CTD laterals, as well as using mud additives that minimize chemical instability. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) Each of the 3H-11 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so formation integrity tests are not required. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) ,- k nito A Page 2 of 7 , - g October 25,2012 PTD for KRU 3H-11AL1, AL1-01 New Completion Details Liner Liner Liner Liner Lateral Name Top MD Btm Top Btm Liner Details MD TVD TVD 3H-11ALI 7300' 8385' 6393' 6004' 2% 4.7#, L-80, ST-L slotted liner; aluminum billet on top 3H-11AL1-01 7050' 8505' 5970' 5979' 23/" 4.7#, L-80, ST-L slotted liner; Deployment sleeve on top Existing Casing/Liner Information Category OD Weight Grade Connection Top Btm Top Btm Burst Collapse (ppf) MD MD TVD TVD psi psi Conductor 16" 62 H-40 Welded 0' 115' 0' 115' Surface 10%" 45.5 J-55 BTC 0' 3637' 0' 3178' 3580 2090 Casing 7" 26 L-80 BTC 0' 6907' 0' 5929' 4980 4320 Liner 4W 12.6 L-80 IBT-M 6813' 7375' 5780' 6200' 8430 7500 Tubing 3W 9.3 L-80 EUE 8rd-Mod 0' 6863' 0' 5898' 10,160 10,530 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR2-AC will be operating under 20 AAC 25.036 for thru-tubing drilling operations so no diverter system is required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Chloride-based Biozan brine or used drilling mud (-9.7 ppg) ' — Drilling operations: Chloride-based Flo-Pro Flo Vis mud (9.7 ppg). This mud weight alone will not hydrostatically overbalance formation pressure in the 3H-11 motherbore, but overbalanced conditions will be maintained using MPD practices described below. — Completion operations: 3H-11 contains a subsurface safety valve (SSSV) at 1930' MD. The SSSV will be used to pressure deploy the liner in lieu of loading the well with completion fluid. In the event that the SSSV becomes inoperable, the well will be loaded with 12.0 ppg sodium bromide completion fluid in order to maintain pressure over-balance while picking up liner. — Emergency Kill Weight fluid: Two well bore volumes (-150 bbl) of 13.1 ppg emergency kill weight fluid will be within a short drive of the rig during drilling operations. Page 3 of 7 GJNLL October 25, 2012 PTD Applicati. for KRU 3H-11AL1, AL1-01 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing pressure over- balance to the formation. In the 3H-11 laterals we will target a constant BHP/of 11.8 ppg EMW at the window. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain overbalance. Additional choke pressure or increased mud weight may also be employed for improved borehole stability but not necessarily for well control. Pressure at the 3H-11A Window (7065' MD, 6039' TVD, 5970' SSTVD) Using MPD Pumps On (1.5 bpm) Pumps Off A-sand Formation Pressure (10.5 ppg) 3260 psi 3260psi Mud Hydrostatic (9.7 ppg) 3012 psi 3012 psi Annular friction (i.e. ECD, 0.090 psi/ft) 636 psi 0 psi Mud + ECD Combined 3647 psi 3012 psi (no choke pressure) (overbalanced (underbalanced —387 psi) —248 psi) at Window(11.8 ppg) 3660 psi 3660 psi • Choke Pressure Required to Maintain 13 psi 648 psi arget BHP 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 exploratory or stratigraphic test well. 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)) Summary of Operations Background 3H-11, the original well, was drilled and completed as a producer in December 1987 in the Kuparuk A-and C-sands. 10-3/4" 45.5#J-55 surface casing was run to 3,637' MD; 7" 26#J-55 production casing was run to 7,716' MD. The well was recently sidetracked to a new bottom hole location (3H-11A PTD 212-062) as a set up for CTD operations. A mechanical whipsto2k will be placed in the 4W liner at the planned kickoff point. The 3H-11A sidetrack will exit the 4W liner pt 7065' MD and will target the A2 sand west of the existing well with a 1320' lateral. The hole will be completed with a 2%' slotted liner to the TD of 8385' MD with an aluminum billet at 7300' MD. Page 4 of 7 QR I N ` L October 25, 2012 • PTD Applicata,__ ror KRU 3H-11AL1, AL1-01 The 3H-11AL1 lateral will kick off from the aluminum billet at 7300'MD and will target the A3 sand west of the existing well with a 1205' lateral. The hole will be completed with a 2%'slotted liner to the TD of 8505' MD with a liner top deployment sleeve at 7050' MD. ' Pre-CTD Work 1. Run whipstock dummy. 2. Prep site for Nabors CDR2-AC, including setting BPV Rig Work t toy 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. ,, 2. 3H-11AL1 Sidetrack a. Set whipstock at 7065' MD with high-side orientation. • 4);., b. Mill 2.80"window through 4W liner at 7065' MD eft) c. Drill 2.70" x 3" bi-center lateral to TD of 8385' MD d. Run 2%" slotted liner with an aluminum billet from TD up to 7300', using the SSSV as a barrier to formation pressure if available j 3. 3H-11AL1-01 Lateral a. Kick off of the aluminum billet at 7300' MD b. Drill 2.70"x 3" bi-center lateral to TD of 8505' MD c. Run 2%" slotted liner with a deployment sleeve from TD up to 7050', using the SSSV as a barrier to formation pressure if available 4. Freeze protect. Set BPV, ND BOPE. 5. RDMO Nabors CRD2-AC. Post-Rig Work 1. Pull BPV and install gas lift design. 2. Perform static BHP survey 3. Put on production. a. Note: The 3H-11 laterals will be pre-produced for over 30 days before being converted to water injection service. ---- Pressure Deployment of BHA The planned bottomhole assemblies (BHAs)are too long to simply isolate by closing the double swab valves on the Christmas tree. Because of this, MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slickline lubricator. This pressure control equipment ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. Page 5 of 7 = I l y r October 25,2012 PTD Applicata. for KRU 3H-11AL1, AL1-01 — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment the steps listed above are conducted in reverse. Liner Running — Since 3H-11 is equipped with a SSSV, the CTD laterals will not need to be displaced to an over-balancing fluid prior to running liner unless the SSSV fails. In that case, fluid of sufficient density to over-balance the formation will be used to provide well control. See the"Drilling Fluids" section for more details. — While running 2%" slotted liner, a joint of 2%" non-slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" pipe rams provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) — No annular injection on this well. — Class II liquids to KRU 1R Pad Class II disposal well , — Class II drill solids to Grind & Inject at PBU Drill site 4 — Class I wastes will go to Pad 3 for disposal. 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — There are no other affected owners — Please see attached directional plans for each lateral. — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire openhole section. — Distance to nearest property line and nearest well in the same pool. Distance Distance to Directional to Unit Nearest Lateral Name Plan Boundary Well Nearest Well 3H-11AL1 09 25,249' 700' 3H-10CL2-02 3H-11AL1-01 05 25,245' 700' 3H-10CL2-02 16. Quarter Mile Injection Review (for injection wells only) (Requirements of 20 AAC 25.402) There are three wells that fall into the Quarter Mile Injection area, 3H-10, 3H-11 and 3H-33. 3H-10 is a producer with northern CTD laterals that fall within the quarter mile radius. 3H-33 is also a producer with CTD laterals that kick-off at the edge of the quarter mile radius and extend beyond the quarter mile radius. The original 3H- 11 wellbore also is at the edge of the quarter mile radius and has been plugged and abandoned. 3H-10CL2, 3H10CL2-01 and 3H10CL2-02 are horizontal CTD laterals completed with 2 3/8" slotted liner. We believe these laterals are isolated from 3H-11 laterals by a sealing north/south fault. The window from the 3H- 10C motherbore for these three laterals exits the 3-1/4" liner in the Kuparuk A2 sand at 6230' MD, 5985'TVD. A window in the 4-1/2" liner at 6043' MD exits into the C sand at 5882' TVD. The 3-1/4" liner was cemented in with 9 Bbls. 15.8 PPG class G cement and has a liner top packer(tested to 1100 PSI) installed in the 4-1/2" liner at 5354' MD, 5230' TVD. The 4-1/2" liner was installed during the rotary sidetrack in May 2004 from a window in the 7" casing at 3549' to TD at 6405', across the entire Kuparuk interval. The 4-1/2" liner was cemented in place and pressure tested to 3500 PSI. There is IA X OA communication in this well, the last MITOA was done on 10/20/2012 to 1800 PSI and the last MITT was on 10/13/2004 to 2500 PSI. �; Page 6 of 7 ". t ,`t October 25, 2012 PTD Applicati. for KRU 3H-11AL1, AL1-01 3H-33 was a grass roots well drilled in Jan. 2009 and the CTD laterals were drilled in Oct. 2009. The 3H-33 mother bore was casing drilled with 7" casing to TD at 8020', 6396' TVD and cemented in with 64 Bbls class G cement. The cement job went as planned and a USIT log showed good quality cement from float collar up to / 5800' MD, 4661' TVD. The top of the Kuparuk C sand in this well is at 7638' MD, 5973' TVD. The production packer is set at 7547', 5895' TVD. For the CTD laterals the 7" liner was cemented up to the tubing tail at 7606', a cement pilot hole was drilled and two windows where milled at 7665' and 7685' MD. The 4 laterals are completed with 2-3/8' slotted liner. The last MIT-IA was performed on 9/24/2009 to 2500 psi and the last MIT-T to 1400 PSI was on 5/23/10. The OA has an open shoe at 4315' MD, 3609' TVD. 3H-11 was sidetracked in September 2012 to a new bottom hole locaion. The original bottom hole location is on the edge of the 1/4 mile radius. A cement retainer was set at 7164' MD, 5965' TVD and the bottom hole was plugged with 67 Bbls of classG cement, 20 bbls below the retainer, 35 Bbls into the IA and 12 Bbls above the ✓ retainer. A subsequent RCBL showed cement in the IA at 5715' and the tag in the tubing was at 5764'. The top of the Kuparuk C sand in this well is at 5980'. The 3-1/2" tubing was jet cut at 5603' and another cement plug layed in to 4530'with 5Bbls squeezed through the 7' casing leak at 4880'. The 7" casing was then cut and pulled from 2750'. The sidetrack was begun with a window in the 10-3/4" casing at 2701'. 17. Construction of Injection Wells (Requirements of 20 AAC 25.412) The top of liner packer hanger is 197' above Kuparuk C and we have 106' liner overlap with 7" casing. Attachment 1: Directional Plans for 3H-11AL1, 3H-11AL1-01 Attachment 1: Quarter Mile Pool Scan Attachment 2: Current Well Schematic for 3H-11 Attachment 3: Proposed Well Schematic for 3H-11 CTD Laterals i r Page 7 of 7 October 25, 2012 J Q. M in A rn CO `n o co o p N o o co U') �1` _ C 1 2 67 (6 V (0 co p N Q M co J t6 M O 00 C C L-Lo —c FS ti `r co p MOO QOY � rn r - Q Y H CO V U N CO M CN gU) U) U a C) o m I- o73 E a) C (6 g O 0 U) (13 I1g E _N d X I- d _ X -c, — o_- ca O o Q U) C Q) W U) C I- p 0 N ._ I— W C 2 0 E_CD CO X m N I O 0J 0 N x c.) co (0 W = - u) rn U 2 ri in N N N N N o Y ,C M A M M m m i ,' ,, V i ,''',/ RS 1- ,--11---Ailifit O \ zU p O 1 Tii 0- 4r op oo X v ti Loain pCON N cj � W © M M a) iNS �O _.-u1.-- o ti O o Q c *k I� Y N o COLO _ o io M J 2 = i L T v p v C) it ct u, _ d• \ NO O- M ctoo � o2 i� � Y r (I) ED v z KUP 3H-IIA • ' ConocoPhillips Well Well Attributes •Max Angle&MD TD Alaska NH; Wellbore APUUWI Field Name Well Status Ind(*) MD(RKB) Act Btm(RKB) conoc tyy� 501032009101 KUPARUK RIVER UNIT SVC 46.18 7,165.15 7,375.0 " Comment H2S(ppm) Date Annotation End Date KB-Ord(R) Rig Release Date "' _SSSV:TRDP 245 11/26/2009 Last WO: 10/6/2012 42.01 12/28/1987 Well Contig:-3H-n1e1mAa -2A4ct7l2 7139'.34 AM Annotation Depth)RKB) End Date Annotation Last Mod...End Date Last Tag: Rev Reason:WORKOVER/SIDETRACK'A'REVIEW osborl 10/24/2012 Casing Strings HANGER,26 -- Casing Description String 0... String ID...Top(MID) 'Set Depth(t.Set Depth(ND)...Strin Wt...String���String Top Thrd .z� CONDUCTOR 16 15.062 35.5 115.0 _ 115.0 62.50 H-40 WELDED Casing Description String 0... String ID...Top(RKB) Set Depth(6...Set Depth(ND)...String Wt...String...String Top Thrd SURFACE 103/4 I 9.950 35.2 3,637.1 3,178.4 45.50 J-55 BTC Casing Description String 0... String ID...Top(RKB) Set Depth(L.Set Depth(ND)...String Wt...String...String Top Thrd WINDOWA 103/4 8.000 2,701.0 2,721.0 2,415.7 Casing Description String 0... String ID...Top(RKB) Set Depth(t...Set Depth(ND)...String Wt...String...String Top Thrd PRODUCTION 7 6.276 27.9 6,907.2 5,929.0 26.00 L-80 BTC CONDUCTOR, POST SIT 35-115 Casing Description String 0... String ID...Top OMB) Set Depth(t...Set Depth(ND)...String WI...String...String Top Thrd LINER 41/2 3.930 6,813.0 7,375.0 12.60 L-80 IBT-M SAFETY VLV, Liner Details 1,978 I o Top Depth (ND) Top Incl Nomi... Top IRKS) (RKB) i (°) Item Description Comment ID(in) WHIPSTOCK, f 6,813.0 5,863.1 45.40 PACKER BAKER ZXP LINER TOP PACKER 4.410 � a 2'701- 6,831.5 5,876.2 45.58 HANGER BAKER KSI HYDRAULIC FLEX LOCK HANGER 4.470 WINDOW A. 2.701-2,721 6,842.1 5,883.6 45.69 SBE 80-40 SEAL BORE EXTENSION 4.000 ci _ Tubing Strings GAS LIFT, Tubing Descriptn ng ring... Top Thrd a O TU BINNGW oo Detailr312.. St 2.902 Top 26.0) Set 6,863.0Depth x...Set D5,8984D)...stri9.301...stL-80 String EUE8RDMOD 2.867 Z Top Depth (ND) Top Incl Noml... lop(RKB) (RKB) 1°) Item Description Comment ID(in) 26.0 26.0 -0.01-HANGER FMC TUBING HANGER 3.950 1,978.3 1,839.0 37.57 SAFETY VLV CAMCO TRMAXX-CMT-SR-5 SAFETY VALVE w/2.813"PROFILE 2.812 SURFACE, a 6,776.3 5,837.4 45.03 NIPPLE HES X NIPPLE 2.813 ' 35-3,637 6,825.1 5,871.7 45.52 LOCATOR BAKER 80-40 GBH-22 LOCATOR SUB 3.000 6,826.4 5,872.6 45.53 SEAL ASSY BAKER SEAL ASSEMBLY w/20'STROKE AND 1/2 MULESHOE(`6' 2.990 OFF LOCATOR) • Other In Hole ireline retrievable plugs,valves,pumps,fish,etc.) ■ Top Depth (ND) Top Incl GAS LIFT, _ Top(ftKB) (RKB) (°) Description Comment Run Date ID(in) 4.256III 2,701.0 2,400.8 41.44 WHIPSTOCK WHIPSTOCK SET FOR SIDETRACK A 9/17/2012 III Notes:General&Safety End Date Annotation • 7/24/2001 NOTE:ESP WORKOVER GAS LIFT. 5,303 8/172012 NOTE:WELL WORKOVER/SIDETRACK'A'-Original Prod Csg cut/pulled @ 2451' . I 11111 GAS LIFT, 5,978 ■ IL' ■ GAS LIFT, 6.593 Irli NIPPLE.6.775 4.1 ■ I LOCATOR, 6,625 • SEAL ASSY, 6,826 1 Mandrel Details Top Depth Top Port (ND) Incl OD Valve Latch Size TRO Run Stn Top(RKB) (RKB) F) Make Model (in) Sere Type Type (in) (psi) Run Date Com... 1 2,867.4 Z524.0 41.74 CAMCO MMG 1 12 GAS LIFT 'DMY RK 0.000 0.0 10/6/2012 PRODUCTION 2 4,255.9 3,723.1 26.79 CAMCO MMG 1 12 GAS LIFT DMY RK 0.000 0.0 10/6/2012 POST SR, 28-6.907 3 5,302.7' 4,651.9 26.44 CAMCO MMG ' 1 12 GAS LIFT DMY RK 0.000 0.0 10/6/2012 4 5,978.4 5,243.4 32.82 CAMCO MMG 1 12 GAS LIFT DMY RK 0.000 0.0 10/62012 5 6,593.4 5,707.5 45.04 CAMCO•MMG 1 12 GAS LIFT'SOV REK 0.000 0.0 10/6/2012 I [ I LINER, j 7.375 ORIGINAL ConocoPhilhips Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 3H Pad 3H-11 3H-11AL1 Plan: 3H-11AL1_wp09 Standard Planning Report 18 October, 2012 r' 1 BAKER HUGHES ConocoPhillips or its affiliates Fr ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3H-11 Company: ConocoPhillips(Alaska)Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Site: Kuparuk 3H Pad North Reference: True Well: 3H-11 Survey Calculation Method: Minimum Curvature Wellbore: 3H-11AL1 Design: 3H-11 AL 1_wp09 Project Kuparuk River Unit Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 3H Pad Site Position: Northing: 6,000,110.73 ft Latitude: 70°24'41.531 N From: Map Easting: 498,655.44 ft Longitude: 150°0'39.416 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: -0.01 ° Well 3H-11 Well Position +N/-S 0.00 ft Northing: 6,000,425.37 ft Latitude: 70°24'44.626 N +E/-W 0.00 ft Easting: 498,655.44 ft Longitude: 150°0'39.418 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 38.70ft Wellbore 3H-11AL1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2011 12/31/2012 15.83 79.98 57,380 Design 3H-11AL1_wp09 Audit Notes: Version: Phase: PLAN Tie On Depth: 6,977.78 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (ft) (ft) (ft) C) -38.70 0.00 0.00 315.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (ft) (°) (°) (ft) (ft) (ft) (°/100ft) (°/100ft) (°/100ft) (°) Target 6,977.78 45.56 36.39 5,908.73 880.75 2,990.52 0.00 0.00 0.00 0.00 7,065.00 45.02 36.24 5,970.09 930.70 3,027.23 0.63 -0.62 -0.17 -168.89 7,090.00 48.02 36.24 5,987.29 945.33 3,037.96 12.00 12.00 0.00 0.00 7,211.00 90.37 36.24 6,029.30 1,034.49 3,103.31 35.00 35.00 0.00 0.00 7,386.00 89.30 335.00 6,029.85 1,200.48 3,119.64 35.00 -0.61 -35.00 269.00 7,665.00 89.42 301.52 6,033.06 1,405.68 2,936.53 12.00 0.04 -12.00 270.00 7,800.00 94.65 316.86 6,028.25 1,490.63 2,832.30 12.00 3.88 11.37 71.00 7,925.00 94.49 301.82 6,018.23 1,569.38 2,736.21 12.00 -0.13 -12.04 270.00 8,020.00 91.48 290.81 6,013.27 1,611.35 2,651.30 12.00 -3.17 -11.59 255.00 8,385.00 91.06 247.00 6,004.76 1,604.51 2,295.29 12.00 -0.11 -12.00 270.00 10/18/2012 11:20:21AM Page 2 COMPASS 2003.16 Build 69 tn1r1 , 1' 'r [ i1/4:',) I I 'Y L. `-' ConocoPhillips or its affiliates Irf' ConocoPhillips Planning Report BAKERH Alaska UGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3H-11 Company: ConocoPhillips(Alaska)Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Site: Kuparuk 3H Pad North Reference: True Well: 3H-11 Survey Calculation Method: Minimum Curvature Wellbore: 3H-11 AL1 Design: 3H-11 AL1_wp09 Planned Survey Measured ND Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +EI-W Section Rate Azimuth Northing Easting (ft) (°) (°) (ft) (ft) (ft) (ft) (°110oft) r) (ft) (ft) 6,977.78 45.56 36.39 5,908.73 880.75 2,990.52 -1,491.83 0.00 0.00 6,001,305.49 501,645.82 TIP 7,000.00 45.42 36.35 5,924.31 893.51 2,999.92 -1,489.46 0.63 -168.89 6,001,318.25 501,655.22 7,065.00 45.02 36.24 5,970.09 930.70 3,027.23 -1,482.48 0.63 -168.86 6,001,355.43 501,682.54 KOP 7,090.00 48.02 36.24 5,987.29 945.33 3,037.96 -1,479.71 12.00 0.00 6,001,370.05 501,693.26 Start 35 DLS 7,100.00 51.52 36.24 5,993.75 951.48 3,042.47 -1,478.55 35.00 0.00 6,001,376.21 501,697.78 7,200.00 86.52 36.24 6,029.00 1,025.63 3,096.81 -1,464.55 35.00 0.00 6,001,450.34 501,752.13 7,211.00 90.37 36.24 6,029.30 1,034.49 3,103.31 -1,462.88 35.00 0.00 6,001,459.20 501,758.63 4 7,300.00 89.80 5.10 6,029.16 1,116.74 3,134.34 -1,426.66 35.00 -91.00 6,001,541.44 501,789.67 7,386.00 89.30 335.00 6,029.85 1,200.48 3,119.64 -1,357.06 35.00 -91.05 6,001,625.16 501,774.99 Start 12 DLS 7,400.00 89.30 333.32 6,030.02 1,213.07 3,113.54 -1,343.83 12.00 -90.00 6,001,637.76 501,768.89 7,500.00 89.32 321.32 6,031.23 1,297.08 3,059.65 -1,246.32 12.00 -89.98 6,001,721.77 501,715.01 7,600.00 89.37 309.32 6,032.37 1,368.05 2,989.46 -1,146.51 12.00 -89.83 6,001,792.74 501,644.85 7,665.00 89.42 301.52 6,033.06 1,405.68 2,936.53 -1,082.47 12.00 -89.70 6,001,830.39 501,591.93 6 7,700.00 90.78 305.49 6,033.00 1,425.00 2,907.35 -1,048.18 12.00 71.00 6,001,849.70 501,562.76 7,800.00 94.65 316.86 6,028.25 1,490.63 2,832.30 -948.70 12.00 71.01 6,001,915.34 501,487.72 7 7,900.00 94.55 304.82 6,020.20 1,555.70 2,757.03 -849.47 12.00 -90.00 6,001,980.41 501,412.47 7,925.00 94.49 301.82 6,018.23 1,569.38 2,736.21 -825.07 12.00 -90.97 6,001,994.11 501,391.66 8 8,000.00 92.12 293.12 6,013.90 1,603.88 2,669.84 -753.75 12.00 -105.00 6,002,028.61 501,325.30 8,020.00 91.48 290.81 6,013.27 1,611.35 2,651.30 -735.35 12.00 -105.50 6,002,036.09 501,306.77 9 8,100.00 91.45 281.20 6,011.22 1,633.38 2,574.52 -665.49 12.00 -90.00 6,002,058.12 501,229.99 8,200.00 91.37 269.20 6,008.74 1,642.42 2,475.14 -588.82 12.00 -90.25 6,002,067.18 501,130.63 8,300.00 91.23 257.20 6,006.47 1,630.60 2,376.05 -527.11 12.00 -90.54 6,002,055.38 501,031.55 8,385.00 ' 91.06 247.00 6,004.76 , 1,604.51. 2,295.29 , -488.45 12.00 -90.82 6,002,029.31 500,950.79 TD at 8385.00 10/18/2012 11:20:21AM Page 3 COMPASS 2003.16 Build 69 f ! r • `.= ConocoPhillips or its affiliates MP! ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3H-11 Company: ConocoPhillips(Alaska)Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Site: Kuparuk 3H Pad North Reference: True Well: 3H-11 Survey Calculation Method: Minimum Curvature Wellbore: 31-I-11AL1 Design: 3H-11AL1_wp09 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (°) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 31-I-11AL1_T2 0.00 0.00 6,033.00 1,405.96 2,933.79 6,001,830.67 501,589.19 70°24'58.448 N 149°59'13.402 W -plan misses target center by 1.21ft at 7667.44ft MD(6033.09 TVD,1406.97 N,2934.45 E) -Point 3H-11AL1_Fault1 0.00 0.00 0.00 1,508.95 2,788.76 6,001,933.67 501,444.19 70°24'59.461 N 149°59'17.653 W -plan misses target center by 5945.45ft at 6977.78ft MD(5908.73 TVD,880.75 N,2990.52 E) -Polygon Point 1 0.00 1,508.95 2,788.76 6,001,933.67 501,444.19 Point2 0.00 1,673.99 2,888.73 6,002,098.67 501,544.18 Point3 0.00 1,508.95 2,788.76 6,001,933.67 501,444.19 3H-11AL1_Polygon 0.00 0.00 0.00 928.92 2,896.86 6,001,353.67 501,552.18 70°24'53.756 N 149°59'14.490 W -plan misses target center by 5909.67ft at 6977.78ft MD(5908.73 TVD,880.75 N,2990.52 E) -Polygon Point 1 0.00 928.92 2,896.86 6,001,353.67 501,552.18 Point2 0.00 824.95 3,087.90 6,001,249.68 501,743.18 Point 3 0.00 1,074.01 3,238.86 6,001,498.69 501,894.17 Point4 0.00 1,433.04 3,197.77 6,001,857.69 501,853.15 Point 5 0.00 1,612.01 3,000.71 6,002,036.68 501,656.14 Point6 0.00 1,750.98 2,804.66 6,002,175.67 501,460.13 Point7 0.00 1,785.94 2,624.63 6,002,210.66 501,280.13 Point8 0.00 1,773.84 2,190.59 6,002,198.64 500,846.13 Point9 0.00 1,362.80 2,196.69 6,001,787.64 500,852.15 Point 10 0.00 1,374.90 2,607.73 6,001,799.66 501,263.16 Point 11 0.00 1,229.96 2,925.79 6,001,654.68 501,581.16 Point 12 0.00 928.92 2,896.86 6,001,353.67 501,552.18 3H-11AL1_T1 0.00 0.00 6,029.00 1,030.96 3,091.86 6,001,455.67 501,747.18 70°24'54.759 N 149°59'8.772 W -plan misses target center by 7.15ft at 7201.37ft MD(6029.08 TVD,1026.73 N,3097.62 E) -Circle(radius 1,320.00) 3H-11AL1_T3 0.00 0.00 6,015.00 1,559.93 2,626.74 6,001,984.67 501,282.19 70°24'59.963 N 149°59'22.403 W -plan misses target center by 56.93ft at 8029.40ft MD(6013.03 TVD,1614.60 N,2642.49 E) -Point 3H-11AL1_T4 0.00 0.00 6,005.00 1,572.87 2,258.70 6,001,997.67 500,914.20 70°25'0.092 N 149°59'33.193 W -plan misses target center by 48.38ft at 8385.00ft MD(6004.76 TVD,1604.51 N,2295.29 E) -Circle(radius 1,320.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (") 11 2,701.00 2,331.22 10 3/4"TOW 10-3/4 13-1/2 8,385.00 6,004.76 2 3/8" 2-3/8 3 10/18/2012 11:20:21AM Page 4 COMPASS 2003.16 Build 69 u " , 61 L • ConocoPhillips or its affiliates VP' ConocoPhillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co-ordinate Reference: Well 3H-11 Company: ConocoPhillips(Alaska)Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Site: Kuparuk 3H Pad North Reference: True Well: 3H-11 Survey Calculation Method: Minimum Curvature Wellbore: 3H-11AL1 Design: 3H-11 AL1_wp09 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) (ft) Comment 6,977.78 5,908.73 880.75 2,990.52 TIP 7,065.00 5,970.09 930.70 3,027.23 KOP 7,090.00 5,987.29 945.33 3,037.96 Start 35 DLS 7,211.00 6,029.30 1,034.49 3,103.31 4 7,386.00 6,029.85 1,200.48 3,119.64 Start 12 DLS 7,665.00 6,033.06 1,405.68 2,936.53 6 7,800.00 6,028.25 1,490.63 2,832.30 7 7,925.00 6,018.23 1,569.38 2,736.21 8 8,020.00 6,013.27 1,611.35 2,651.30 9 , 8,385.00 6,004.76 1,604.51 2,295.29 TD at 8385.00 10/18/2012 11:20:21 AM Page 5 COMPASS 2003.16 Build 69 VI I I I too O q . il -I--- rMil t �;''�0 a. e \O N \ I N h P. \ O O P O L Z FI `, O ZO 2 m g M r oa E ^cj \ m N W �? 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L . + , .• _. . _ -_1:1„11121:--_- :ses-:- ��. ►._;1- - _ 'vl !��� ,.»—:I. 8ON O O O O Vp p p p 8 p 8 O O $ O M N1 M M CON N VI N il 8 O, W CD V.1 M N O C� [� .O , q ' (11I/8 OST) (+)111.Io1W( )41noS ORIGINAL ConocoPhillips ConocoPhillips (Alaska) Inc. -Ku p2 Kuparuk River Unit Kuparuk 3H Pad 3H-11 3H-11 AL1 3H-11AL1_wp09 Travelling Cylinder Report 18 October, 2012 BAKER HUGHES ORIGINAL 1.,, Baker Hughes INTEQ ��" ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 3H-11 Project: Kuparuk River Unit TVD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Reference Site: Kuparuk 3H Pad MD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Site Error: 0.00ft North Reference: True Reference Well: 3H-11 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore 3H-11AL1 Database: EDM Alaska Prod v16 Reference Design: 3H-11AL1_wp09 Offset TVD Reference: Offset Datum Reference 3H-11AL1_wp09 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 6,977.78 to 8,385.00ft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,035.41ft Error Surface: Elliptical Conic Survey Tool Program Date 10/18/2012 From To (ft) (ft) Survey(Wellbore) Tool Name Description 93.60 2,693.60 3H-11(3H-11) GCT-MS Schlumberger GCT multishot 2,701.00 6,977.78 3H-11A(3H-11A) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 6,977.78 8,385.00 3H-11AL1_wp09(3H-11AL1) MWD MWD-Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (") ("1 8,385.00 6,074.36 2 3/8" 2-3/8 3 2,701.00 2,400.82 10 3/4"TOW 10-3/4 13-1/2 Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Well-Wellbore-Design (ft) (ft) (ft) (ft) Kuparuk 3H Pad 3H-11-3H-11-3H-11 Out of range 31-1-11-3H-11A-3H-11A 7,075.00 7,075.00 0.11 3.13 -2.38 FAIL-Major Risk 3H-11-3H-11AL1-01-3H-11AL1-01_wp05 7,325.73 7,325.00 1.81 0.67 1.16 Pass-Minor 1/10 3H-14-3H-14-3H-14 Out of range 3H-14-3H-14A-3H-14A Out of range 3H-14-3H-14APB1-3H-14APB1 Out of range 3H-14-3H-14B-3H-14B 8,000.00 6,925.00 1,015.06 171.14 853.01 Pass-Major Risk 3H-14-3H-14BL1-3H-14BL1 8,000.00 6,925.00 1,015.06 171.14 853.00 Pass-Major Risk 3H-14-3H-14BL2-3H-14BL2 8,000.00 6,925.00 1,015.06 171.14 853.00 Pass-Major Risk 3H-14-3H-14BL3-3H-14BL3 8,000.00 6,925.00 1,015.06 171.14 853.00 Pass-Major Risk 3H-14-3H-14BL4-3H-14BL4 8,000.00 6,925.00 1,015.06 171.14 853.00 Pass-Major Risk 3H-17-3H-17-3H-17 Out of range 3H-20-3H-20-3H-20 Out of range 3H-33-3H-33-3H-33 Out of range 3H-33-3H-33A-3H-33A Out of range 31-I-33-3H-33AL1-3H-33AL1 Out of range 3H-33-3H-33AL1 PB1-3H-33AL1 PB1 Out of range 3H-33-3H-33AL2-3H-33AL2 Out of range 3H-33-3H-33AL2-01-3H-33AL2-01 Out of range CC Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 10/18/2012 10:34:58AM Page 2 ofN 11 COMPASS 2003.16 Build 69 t .. t " °4 Pn 1 t i I.- Baker Hughes INTEQ FIR' COfOCOPhIIhhpS Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips(Alaska)Inc.-Kup2 Local Co-ordinate Reference: Well 3H-11 Project: Kuparuk River Unit TVD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Reference Site: Kuparuk 3H Pad MD Reference: 3H-11A @ 69.60ft(Nordic 3(38.7+30.9)) Site Error: 0.00ft North Reference: True Reference Well: 3H-11 Survey Calculation Method: Minimum Curvature Well Error: 0.O0ft Output errors are at 1.00 sigma Reference Wellbore 3H-11AL1 Database: EDM Alaska Prod v16 Reference Design: 3H-11AL1_wp09 Offset TVD Reference: Offset Datum Offset Design Kuparuk 3H Pad- 3H-11-3H-11A-3H-11A Offset Site Error: 0.00 ft Survey Program: 94-OCT-MS,2701-MWD+IFR-AK-CAZ-SC,4196-MVD+IFR-AK-CAZ-SC,6921-MWD+IFR-AK-CAZ-SC Rule Assigned:Major Risk Offset Well Error: 0.00 ft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface+ Offset Wellbore Centre Casing- Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/...S +E/-W Hole Size Centre Distance Deviation (ft) (ft) (n) (n) (ft) 0l 1°) (ft) 1581 In) In) Ift) (ft/ 7,000.00 5,993.91 7,000.00 5,993.91 0.09 0.05 65.08 893.51 2,999.92 0.22 0.00 1.21 -0.84 FAIL-Major Risk,CC 7,025.00 6,011.48 7,025.00 6,011.48 023 0.10 65.07 907.84 3,010.46 0.22 0.00 1.60 -1.24 FAIL-Major Risk 7,050.00 6,029.09 7,050.00 6,029.09 0.38 0.15 65.06 922.13 3,020.95 0.22 0.00 2.34 -1.69 FAIL-Major Risk 7,075.00 6,046.68 7,075.00 6,046.76 0.53 0.20 -143.99 936.40 3,031.41 0.22 0.11 3.13 -2.38 FAIL-Major Risk,ES,SF 7,099.89 6,063.28 7,100.00 6,064.38 0.68 0.25 -144.32 950.70 3,041.91 0.22 1.41 3.91 -1.46 FAIL-Major Risk 7,123.98 6,076.84 7,125.00 6,081.90 0.85 0.29 -144.28 965.05 3,052.48 022 5.85 4.72 2.80 Pass-Major Risk 7,146.44 6,086.74 7,150.00 6,099.32 1.02 0.34 -144.26 979.48 3,063.13 0.22 13.60 5.52 10.50 Pass-Major Risk 7,166.72 6,093.23 7,175.00 6,116.66 1.19 0.39 -144.25 993.95 3,073.86 0.22 24.27 6.30 21.25 Pass-Major Risk 7,184.56 6,096.94 7,200.00 6,134.03 1.34 0.44 -144.22 1,008.40 3,084.56 0.22 37.55 7.03 34.67 Pass-Major Risk 7,200.00 6,098.60 7,225.00 6,151.48 1.48 0.49 -144,18 1,022.79 3,095.22 0.22 52.98 7.69 50.30 Pass-Major Risk 7,214,17 6,098.88 7,250.00 6,168.99 1.62 0.54 -145.30 1,037.12 3,105.83 0.22 70.12 8.28 67.47 Pass-Major Risk 7,231.82 6,098.78 7,275.00 6,186.58 1.78 0.59 -152.32 1,051.40 3,116.41 0.22 87.82 8.76 84.91 Pass-Major Risk 7,248.96 6,098.73 7,300.00 6,204.26 1.94 0.65 -159.87 1,065.61 3,126.92 0.22 105.66 9.04 102.43 Pass-Major Risk 7,265.26 6,098.71 7,325.00 6,222.04 2.09 0.70 -167.47 1,079.75 3,137.36 0.22 123.75 9.09 120.16 Pass-Major Risk 7,280.49 6,098.71 7,350.00 6,239.89 2.22 0.78 -174.82 1,093.83 3,147.75 0.22 142.16 8.97 13824 Pass-Major Risk 7,294.58 6,098.74 7,375.00 6,257.75 2.34 0.89 178.19 1,107.91 3,158.13 0.22 160.90 8.63 156.69 Pass-Major Risk I CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 10/18/2012 10:34:58AM Page 3 of 11 COMPASS 2003.16 Build 69 OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHEC/KLIST WELL NAME /74- �- PTD# 2-7/ ( (-c Development ✓ Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: i-� Q_� t c L (� G�-�POOL: t Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segm nt existing well 21�C 3, — 7/ (If last two digits in Permit No. 2—/z API No. 50463- -L /. API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE 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 name C PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev:9/09/2011 N U) N ' d 8. N !n a) o a m o -c cn w c 3; �. . . o. o a rNi. '3. ay, o' c: co' 3 0 ° H' C� �: ;, 2, ui «, 5 c , ay , N a O2. ° a . a). ° o "co o c co $. -00 c rn 0 r. ° 3, a �, m, c o: c, N C, . m o: o, 5 « E, is • c , a 0 ,• °' 3. , ay _ . . 0 ❑0 co y: o, w, $Q • C _, s, 7 , o C, C; N o 4) , >: co, , 0, C0: N °. 00. `, a � N '° N w 7, Q CO N, v, �, m, Y. No. T �, M. ami �, �, 4 a. o. a E, of oy F x C O. t L7 N. ay �, 1 N: > ,-. CO, 0, O, 2. O. @. '>. a 0) _ ZZ C, 3, , a) J. 'fl, , �, O, N. -, O, •N. m, �, m. 4 N. to O: ro -° C N, O, a U. O, y. 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