Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
210-013
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, July 22, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1E-15A KUPARUK RIV UNIT 1E-15A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/22/2024 1E-15A 50-029-20769-01-00 210-013-0 W SPT 6066 2100130 3000 2300 2300 2300 2300 760 900 900 900 REQVAR P Sully Sullivan 6/3/2024 test to 3000 per AIO. 2B.081 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1E-15A Inspection Date: Tubing OA Packer Depth 1060 3300 3180 3165IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS240604103440 BBL Pumped:2.5 BBL Returned:2.5 Monday, July 22, 2024 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9AIO. 2B.081 James B. Regg Digitally signed by James B. Regg Date: 2024.07.22 15:04:40 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, June 20, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Austin McLeod P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1E-15A KUPARUK RIV UNIT 1E-15A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/20/2022 1E-15A 50-029-20769-01-00 210-013-0 W SPT 6066 2100130 3000 2381 2384 2383 2392 680 820 820 820 REQVAR P Austin McLeod 6/5/2022 MITIA to MAIP. AIO 2B.081. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1E-15A Inspection Date: Tubing OA Packer Depth 1100 3300 3180 3170IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSAM220605185548 BBL Pumped:2.6 BBL Returned:2.5 Monday, June 20, 2022 Page 1 of 1 9 9 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2022.06.20 15:36:36 -08'00' MEMORANDUM TO: Jim Regg lZef�, 11,E 1 P.I. Supervisor 2417. FROM: Austin McLeod Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, June 8, 2020 SUBJECT: Mechanical Integrity Tests ConocoPhdlips Alaska, Inc. IF -15A KiIPARUK RIV UNU IE -15A Src: Inspector Reviewed By: P.L Sup" Comm Well Name KUPARUK RIV UNIT 1E -15A API Well Number 50-029-20769-01-00 Inspector Name: Austin McLeod Permit Number: 210-013-0 Inspection Date: 6/'1/2020 ✓ In3p NUm: mi[SAM200607204011 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well IE -15A ' Type Inj N TVD 6066 -Tubing 1250 1250- 1250 1250 ' PWD 2100130 Type Test SPT Test psi 3000 IA 150 3310 - 3180 3160 BBL Pumped: 3.3 - BBL Returned: 3.3 OA 40 - 40 - 40 _ 40 - Interval REQVAR P/F P _ Notes: 2 year MIT -IA to MAID as per AIO 2B.081. ✓ Monday, June 8, 2020 Page 1 of • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday,June 12,2018 TO: P.I.Jimgg uRper 17/1511 a� SUBJECT: Mechanical Integrity Tests P.I.Supervisor �C� f I CONOCOPHILLIPS ALASKA,INC. 1E-15A FROM: Adam Earl KUPARUK RIV UNIT 1E-15A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1E-15A API Well Number 50-029-20769-01-00 Inspector Name: Adam Earl Permit Number: 210-013-0 Inspection Date: 6/10/2018 Insp Num: mitAGE180611092651 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well IE-15A '[Type Inj W "TVD 6066 " Tubing 2615 - 2615 - 2630 - 2625 PTD 2100130 -[Type Test SPT Test psi 3000 IA 640 3300 3190 • 3165 1 BBL Pumped: 3.2 BBL Returned: 3.1 OA 125 - 320- 320 ' 320 ' Interval ; REQVAR P/F P Notes: MIT-IA tested as per AIO 2B.081 to max ant.Inj.Pressure SCANNED JUN 2LU,5 Tuesday,June 12,2018 Page 1 of 1 • zea- 43 295 36TRANSMITTAL 44: 2. WELL LO (� DATA LOGGED /11/20i 7 PROACTIVE DIAgINOSTIC SERVICES, INC. RECEIVED M.K.BENDER JUL 132017 To: AOGCC /^. Makana Bender AOGCC 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: ProActive Diagnostic Services, Inc. Attn: Ryan C. Rupe 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 SCAN�EQ AUC 0 4 2017, 1) Caliper Report 13`Jun-17 2M-09A 1 Report /CD 50-103-20177-01 2) Caliper Report 13-Jun-17 1E-15A 1 Report /CD 50-029-20769-01 Signed : .. ?5...es4eltDate : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGE(WMEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM D:Wchives\MasterTemplateFiles\Templates\Distribution\TransmittalSheets\ConocoPhillips_Transmit.docx • vo_o 3 R CEIVED 21 3$2 11.1 JUL 13 2017Memory Multi-Finger Caliper NI II. Log Results Summary y Company: ConocoPhillips Alaska, Inc. Well: 1E-15A Log Date: June 13, 2017 Field: Kuparuk Log No.: 14257 State: Alaska Run No.: 4 API No. 50-029-20769-01 Pipe Description: 3.5 inch 9.3 lb. J-55 IPC Top Log Interval: Surface Pipe Use: Tubing Bottom Log Interval: 7,379 Ft. (MD) Inspection Type : Corrosive and Mechanical Damage Inspection COMMENTS : This caliper data is tied into the top of GLM 7 at 7,359 feet(Driller's Depth). This log was run to assess the condition of the tubing with respect to internal corrosive and mechanical damage. The caliper recordings indicate the 3.5 inch tubing logged appears to be in good to fair condition, with a maximum recorded wall penetration of 26% at an isolated pit in joint 55 (1,701 ft). No significant areas of cross-sectional wall loss or I.D. restrictions are recorded throughout the tubing logged. The caliper recordings indicate slight to moderate buckling from-3,850 feet to 7,379 feet(end of log). A 3-D log plot overlay of the centered and un-centered caliper recordings across the interval of tubing logged is included in this report. This is the fourth time a PDS caliper has been run in this well and the 3.5 inch tubing has been logged. A comparison of the current and previous log (March 12, 2010) indicates an increase in corrosive damage during the time between logs. A graph illustrating the difference in maximum recorded wall penetrations on a joint-by-joint basis between logs is included in this report. MAXIMUM RECORDED WALL PENETRATIONS : L) (i ipticr i Per tnt Pc 1 Feu th): ] Isolated Pitting 26 55 1,701 Ft. (MD) Isolated Pitting 20 2 68 Ft. (MD) Isolated Pitting 20 1 65 Ft. (MD) No other significant wall penetrations(> 19%) are recorded throughout the tubing logged. MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 9%) are recorded throughout the tubing logged. MAXIMUM RECORDED ID RESTRICTIONS : No significant I.D. restrictions are recorded throughout the tubing logged. C. Goerdt C. Waldrop J. Condio F.;eld t luii i•;;ef ks) I t a y..ti.>l J s ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565-9085 Fax: (281) 431-7125 E-mail: PDSAnalysis@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 • • illl PDS Multifinger Caliper 3D Log Plot Litt Company : ConocoPhillips Alaska, Inc. Field : Kuparuk Well : 1E-15A Date : June 13, 2017 Description : Overlay of Centered and Un-Centered Caliper Recordings Across 3.5 Inch Tubing. Nominal I.D. Depth 3-D Log(Un-Centered) Image Map(Un-Centered) 3-D Log(Centered) Image Map(Centered) t it 2.5 3.5 1:600 0° 0° 90° 180° 270° 0° 0° 0° 90° 180°270° 00 Maximum I.D. 2.5 inches 3.5 Minimum I.D. 2.5 inches 3.5 .4.._ Maximum Radius 1.25 inches 1.75 Minimum Radius : 1.25 inches 1.75 Oirmilra ME=nia.111111=11111111. - - .-...........imilINOMININ1.11111iliiiiiiA hilhimamloilli.....7.....;z - . .. . .. W. - NO .0 • -4 - _ - rinurriiiiir===m _ _ - - !...,- .1111.115011111 .1.111. 50 JO ..1.7 1111.111111161MNIMMENI ",' IIMIIEIIEV P-MMI911.EMI 1,-- .- -_-- 110.111EntarirMill . ,- .' ".7. . ._. 111111111111111111211.11111111 1 '.:7"-^' 1111.1111NEWM11111111111111 ,Ila '.... 1.11111111111MSOMMINIII 100 . -. ---z. 1.111111111111111111111111111111 - , 1.1111115111EL- -WS— : -1- rz-L. immistairimemm , . _ IIIIIIIIIMMEII __. _-_,-.- MINIIIIIIRD_ViAMIIIIII 150 - ._. _ _ _-_.. NIIIIINIII/IIIIINIIIIN _ ,r :,-.- 1111111NIIMONIMINIIIII - - _ .7- _,..... 1111111111111/4111•111111.11 ---- EMIIIIIIIMUIIIIIINIIIM -:-_-- MIIIIIIIIIIMIIIIIMMIIMI 200 . _-.. ,.7. -- 7.. 111111.11111M11111.1111111 , , - 111.11111MHIMINIIIII r-- z.;_ -..., IMINIIIIIIIHMINIIIIIIIM - -- _ -„,-- - MINIM : :111111611111•111 250 - - --- 7----. 111111111111gaririliiiiiiiillal - -_-- 1.11.1111111101111.111. - zrzt - - _...z„ 1111111111011111111111011 - -E NIIIIIIMMIMMINII - _ ..7,:..-- 111111111r1111MINIMMIIII - ==•- :.,_ - _ 111111111101112MMINIMM 3°° . ,.. -- J.- -•-•,_-.-- IIIMMIE17.17usaMIIIN -- - _.. -. 11111111101FMNIIIIIII ,_ .., IIIIIIIIIIIIMIIIIIMII ..,_ .-, ._-- IIIM1111111::;:-Elr'="ZIMIN 350 _-- IIIIIIMMi:!z.51.416;..0111111111 , .-.._ • • ■■■■ `:s;Egg ;:::;;i■■■ i �iiW�� ■ milic ,'ilir�= ■■■■R Ems■■■■ -_ _ ■■■ENIE �■■■ 400 _ _,,. = ENEINSEMEIEEE 11111111EIMEr MEM 450 _ . ■■■�Mii■■■ =- ...now i! ■NIM■ ■■■ -,::.gym■ME■■■ EEEMIDECENEEE 5 0 ■■■■ERNIEE■ ■■■ .Ei i ■■■ ■■M ► ■■■ 550 _ ■IN®II -777: ■■■ei ■ai■■■ 60o ■■E N � �■■■ __ ■■■ IEA ■■■ =- ■■EIREUREE ■ 650 -- ■■®:}t-•-rt:am�■L'i■ t ■■■::w iillirEl■■ - 1iu:i ■ E� ■■ �■■ _ ■■■ i 1f1 ■■■ 700 ■■■umi ■■■■ 750 - ■■■NEFit E■■■ __ EISIMEMEMIEUE■■■■ Z :'■■■ soo ■■Esc ��■®■ ,-ENEEMIIIMEEE ..-- z-."- 4z r immimmuliiiimium ., g :T. ■■■■E ►IM■■■■ 850 _ • 9 ■■■IEIMf`M�■■■ ' ■■■�► E■ 1111111111111911111111111111111 " T ■■�■ ```�■111■■ ti, ■ ■■ ortrwE mmos 950 ■ ■■ ' NIMMENO ,_ ■ ttrill■■ •,. _ ■■■11■E1■■■■■ ■■■■� '■®■■■1000 !"!R■lN IMEME ■®■ ■■■®i ■■■■■ - _ IMIEMMIIMIIIIMIIIII air* ■■�� a� 1050 - , ■■■■ 1D■■■■ _ ■■■■�I �E®■ x ■■■■E I■■■■ -- .. 111111111111111E UM■■■ _� mmi1100 Emmo...li Mi' ■■■ ■� � ���■■ ■MERI'iI _ ■■■� m ■■■1150 c __ . ■■■111 {111■■■■ =y - , ■■■11111 •1■■■■ - ■®■■iii®ai®■1200 ■111111111ENN IM ®■■ ■■111E-17O ■■ 1_ ■■■11MIZ■■■■1250 MIMEMNSIBM11.111111. -- 101111101MainiIMIENIMIIMEM -_ t MEMIE ..- os- :,- ■■■ M,.. ■�■�IIMIENIMFF`�■� 1300 _ b `- '` ■■IMIiEARIM■■ ■■■■EES■!■■■ ■■111i ■■�'1350 - =_ • • ■■■ 1/ EIMMENUN■ - ■1111115 � `1 ®■■1400 111111191111M1 -f,_ .111111C;'511111131111111 111111111/111111111111511111111111111 - _----- ■missra;�� ■ m 1450 ... _ _ ■■i■L iIIIIIIM■■ _- ■■ii1MBii■■ 11111111111111111111111E11111011111111500 -.---_ ■■®111115®■■ `"_ 111111111111111111M1111111111111111 , -.--. - 1 ■■■ fihrlalail■1550 = 1111111111111111111111111111114 - INIMEIRIV111/11111111111 _.- ®® ■L 7�sominnutitirommi. It.,. r .-,- - 4 ■® �rir =MI=imasumitiliaim 1111111011111M11111111111111111600 -n -_ . ..„.- ,:... ■1111I■intui■■■ = a- -_ ■■■inn o■■■■ =' 1650 ■■■■f i ■■■■ _ ■■1!■RMI■■■ iiIIi■F "'MI= 1700 1111.1011111111.111111.1011111111.1111.. w ■■iiiiii■■■ ■■■■� ■r■i■ _ _ 111111111111M111111111111111111111 4 '' 4r.'...,08 r-- 111111111111112111111111111111M111750 - - • 111111111111111111•1115111111111 _ ■■■■E11111■■■■ iii■ ■IIii0i ■i® ._1.- ..".- 11111161111111111111111111111111111800 "V,4.'-" _ ■■ENIEEMIS■■■ F-- — =_= milingrairdinom ..,, ,.., ir,.._ __,__:. inmesinisimemm ___.:. 1 Im■isie,vr==i .. ,- _,_ ■■■� 1MMI 1850 1111111111111E1111 . ■iii "MAIi■ - ■ngi € iiiliiiiliiiimmoi • ■■ ESIVER■■■19111111.011111111111111111.1111 00 r -- _ ,.- sminsaitimillum t -IT_ ■■■■M Eu■■■■BEEMBE .. .... _. ... WIABENINIEBE—Tr------ a. --1950 aNa - "--imisiverai ii- _ , 2._., ___ ■■■■b •• ,...__,....,_ ■■■miuiaN■■ _ ■■■■/111■' ■■�2000 ■■��!,tIk .. -■ ■■■.�2'UUW.•u ■■■ l nin■2050 szIIIMINIraliIIIIIIIIIII __ ■■PIS IMlNIIIII - ■■■ III■MMI ■■ ■■■E ■ ■ 4Z ■■� E �■2100 _ ■■■■iII■■■■■ .r ■■■111f411MI■■■ ■■■IINFIM■■■ - - ■■■■ ■ ■ ■ ■2150 ■■MI■TIII ■■■ ■■■IIIIIi ■■■■ - r ■■■■arms■■ ■2Immionsweenus 200 ■IIIIIIIAMIIMMI■ f 1111111IMMEIIMMINIIIIIM __.-7_ ...±. .- 11111111111113111111111101111112250 ■■ ■11EM IMIN — - ■■■■EII■ ■■■ _ ■■■■ amu■■■ .- - _ = ■■IIAIR ......��� _ - - - ■■11■ RI ■®■■2300 ■■■■ LIMA ■ ■ ■ ' ■ a ■■■ ■■ PIENIM ■■■ liirr ■■■ ■■■■II° !■■■■ ti - ■■1111111MMEME■2350 = ■■■■iFa®■■■ - - _ ■■■■eI■■■■■ - ---.::- ■■■11 111 ■■■ _- -L= i • ■■■■ my■■■■ _: ■■■N■WI■■■■■ ■■■® !��■■■2450 _y f ■■■■N;iiMI■■■ ■■■■moi# E■■■ _ ■■FILEN!®2500MEMENnalnall.. _ _. ■■■i RIMINI■ s ; ■■i®'i lase-i!■ MINEESMINEMINEll 2550 `_ ■■IIIi , IniffsiiE „ - - ■■���+ ENI■■■2600 - ■■■ "__:` 11111■■■ 11•111110111111131111M. - ,- _ ■iaie■faiiii■265° _- ■�■ii ■ E� ■■ _ __ ■IFIRE ONMEN i ■■■iN VI �i■■ - ■■exp®�■■2700 = ■■■ ENI■■■IIMEMERIMENNE1 _Y 2750 ■■■■11i21111.■■ _ - - - 11111111=111Inallill '''' ■�isl��u �■2 800 _ . Kirlinirlira -„=,- ■■EiGrliiimoi® _- MOM 411EINEEMINIE■■■ � �� ■■■2850 :- ■■■�' 11_=ii® - , ■■■E4f111■■■ ■ EN1101611 11■ 2900 • 0 IIIMIIIIIILIWIIVIINMIIMIIII . .,...--_ IIIIMEIBILPASIEIIIIIMI . ,..„__ - - 111111111EMOMIIMMII -- ...,_ - IIIIIIMIDERMIEMM 2950 1.11INENCHIr112=1.1 111111111MSaliThillEMI _ C IIIIIIIMERIMEAMMIll . - „--- t,- IMMEMINEMIEMEEM -.... . _Ill -NM• IIIMMIESHIRINIMINI -.*--; - . - =: MIIIMMILIMENIME 300°1 _ ..._ INERIMENr", 'ffirnima - -..m. -- IIIIMENEURIEMENIN - - .-, _ IIMIENSIIIIMMIIIIII - , mi INEMINEMP.-"MMIEM 3, -L. - .---:-_-- r_- Nowsirimmunmo 5° , 111•11631111=11111 15 1111111; illi="'" El _ .,:... , _ -- --- ---_-.._-_ ummiimaincliali - - INEMINIMMISIM _., IIMMIENIMMEESIMIN 31 00 .. i-- -= ..,-..- 111111111111111111111. 11t. - ,... 11111111111111 11031M111111 _ - IIMMEINIE F,EFAMERI -...*. -- - 11111111EVEMBIEMMINI I _: . IIIIMINEPEIREMIIIMI 3 5° _ -:- -..., E...:- 1111/1611.ellillEIRILIINEE ...role _ - . _ IIIIIIMEINIMININI .-,-: -,.._ INIIMMEISSESEEM .., . .----- . 1111111111011F4MilmInEE 2 '... - ,.-- ----- IMENEEMINFINEINIMI -- „ -7,=_.- IIIIMMEMPAPPER: AI _ . .--- MINIONSETHEffilliiN --- _ _.--- Nompii,::IPME11.11111113250 F,.. --17. -.-= MEW P11.110.1.101 - EINEFElkiffil,"' MEM = --. morialmiamm ,... ._,.... 1 _._ 1111111ffl. BIBMINSEMEM ___, . -,, ,.., ...„ Immainamomms 33°° - , , 1 1 11111111111NEIMEINIIIII - , -...- F INNIMISIMEMINEINI :' .,-= MAIIIMEMMEN111111 - NM • Allidirsilififilill 335° ...r - "---„. 1 - 111111111PESIMINNEEN ia: .. _ . 1 , 7-- 1111111111110.1111111111111111 ._ . ,.,...- IMIEENINEZITEMP- El ._, - .=- - , IIIIIMEIBMINIMIll 4 -,- ...*.-„„ IninilliffillIMMI 3 °° -4-- _., • u 3450 • ?; f -• 4. :et,. si — � of..: ....!.. " ... 3500 '"fit a yt __ _ g�,„7/%.*:. -i .c 3550 , 1i�. �`#t.. ..,ttt::::::. m- ,::y ..:::,3....... 3600 se '. y. ,t.•• . ::.. ' I. .. t t t. - - _ �,;` 3650 t a_. „�5-ao Ai 3700 F_ - — .::N ::t• =,:...'. 3750 } t :.tri i I" -. .. _ .• w r. x Ps. •, .. 3800 — Y; I �i •Mai.. — T, • t _ .r.....•......... ...,,,.» 1 :Y 3850 r _. �— _ _ __ — +1 .......y::1 I'.. 3900 - 7 .i: .............................. ..„ .,..., .. • • •........ .... ................ _.1., ..... 3950 . ...t. t ✓ 4000 ._ '; is •rl. . - *47:fit.. ;...».., s . 4050 _ ? :.- -t 7 k. :iii�� ..:.,.,: ff..K� . _4100 ,,'........ .... 3 ,. 4150 j ., ...mow. :i 1' . %' 4200 • t - ,_...•vett.Y ......r't j.•! t #- R— .�� 470. s^ lir ....•� t.. f r-a .. _,�< :,-"lt...... .! _4250 "'; 5 .J: — - - 4300 SN""• _ :t:............:.................. ; .. ..:.. f:. • .4. "> 4350 _ I• 4400 - _ i..... . • • ■ 11111111■61111 4450 _ 1.1 ■■■E R■■■■ 1111111=1111111111011111114 500 7.■■■■:-ara'■mm i : . 11111111111111111111§11111111111 _ w■■■ESU■■® N - r _ ■■■■: M1_=■■ 4550 -MINIIIIIIMITHEINIII - ' Pliost, ...Tw. ■■�■111E11■■ ■ d - ■■�i�11(1■■���4600 . . _, ■■® Er Ca = F ■■■■MLI■■■■ w ■■1MEME■PI ■■NEEMENNMENIMMEN 4650 ■■■■1111■1111®■ ■IEIEr= l1111 1111111111M1111111.1.4700 _ ■NI■■ F1■■1111■ : MINISMIAL"MMENE re 1111111151111 1111111111111111 - ■■■ERS ■■■■4750 - . 111111111111111111 ■■NNIMFAITI■■■mmomminnsimiem4800 NV;ft ■■U Ems■ ■■ - ■■■■ i■■■■■ MIIIIIMIMPIIIIRMIMMIMIII 4850 1.11451111.0111.111111111 .je;711 :: BIENIM■KTMMMEI 4900 � ' 1111111111111111111911111111111 _ Mini■■ll a■i0■'■ . . rt ��_., _ 0 • ®11® 111111®®Ei® `-7 11.11111121M1111111111111111111111 F ■■■■WRIUME■■ffilli=mpuimmionom5000 - a ■ ■■11■■■1■ . =- ■■■■l �!■■�■ ■■i■� ��! ■ii■■s num■■■ ■■■ a ■■■5 • 050 - ` ■ani■FIR■ ■ __ . - - implelittloMMIIIIMI■■�NINSIV■■■5100 - 111111111MENPUIMII .,• - .;=- rLorneuraimm�� 5150 _=. ■■■■11■■■■■ -_ , . ■■■®E [R®■■■ ■ i■umai■i■■ -■■■ M11511!■■5200 ®!■ice!!® -- _ ■■® 1■S1i■ ■��� --i r .._*- -.. c ■ !MESS;■■■■■1111.111111ErammEMEM __--_ - ����1 � �■■5300 r FIS■■■■ .. — ■■umim..,,.4,.■5350 -- impsiiiiinIIENIMPAtimilimim 5400 - ■1iiiilE1Fa■iii! _ - Nzti ■■!• I_i■•■ �- =- ■■■11 11 ■■■■ __ • • . -:::_ 15 ■■t1171i■il5500 111.1121111111110111.1121111111110111.11211111111101111111111 _T iii■il'gids>: ''i ■ ■ M �■■6 ■5550IMMEMILIMMINIIIM t.11102 !lSIi :7ii® -_:-_ ■■11111t11 3 leni®itiiiiiIikAi MINEMEMINEIEEMMII 5600 t. " �=: -" A_ ■11111E■MIMMEM �" . kr 111111111/11111E � � 5650 „_ --- . �6 0�0 ■i®iFIii®i■ _- r ■iEMINER M■i®iii ■■ii_ _i___ r- _ ■■MIEB1=11111•111 5700 ■iiia » - i = ■ii■114;i■ii■ --- 111111111111106110111111111115750 ■■■mtim■■■ 1111111•11E1111111111111111111 -= IIMMENNIEWIMMENIII ., 5800 ■■..,,.::aEiriiii■ Z ElLigragimi ... a trL_ : 1.,, ■ ®1KNI® ■5850 __ w ■iMiiFIIME Ni■11.1..11m11111111i111i111111Mm1E1u1n1NUr2fiiNt1Nai1i—mIIr..NMa..aE.IwNMinI1E1-1m1tI1iNiNlslI - 5900 - T59:;7,g ■ iiiiliMIZEi■ ■■■iLMlM■■■ _ ps® a7III�=1 .5950 111 ■111 ■2911 _ s ___........ . ..... .. ... ,c ,.._.�......, .1.1.1.1...--- :.• „� .. .: u __ .:}: _..._ 6000 ._ .d::',' ``. _ 4::. _. .. - _ s -- ::15 ,. 6050 '- = :t di =}. �' 6100 '°' �' .1.1.1.1 rill. .1.1.1.1 y :�...: 6150 N.- ,•..... ... ..O:^'. ••,•.. .• ... ........ "..r. _..— ,.1.1.1.1 _-- /I 6200 .1.1•••% s . r .,.1.1.1.1. o- , v= _. .. t .1,.1.1.1... „, _ �. p; 6250 ::s .,;.1.1.1.1 ... — c`•' .. .y a i- 6300 .1.1,.1.1_ ..-- •n:• .- ....1... '• ..:::.yam' es.1.1:k:w.... "" 3. .!_, •.:.rf 6350 __ — G ....:: �;u.1.1.1.1.. . a* :c:• -.._—.. _ ... 6400 .. Zia ,......:.,: . ■Eirimmtimmumm■■■ri■■■■ ®�■14=1 =MI 6500 ■■INER 1[ZEIN■■ ' MOINIEBRFASEEEMIN IMEMIMIltiallignil6550 ■■!E■E4112 ■■® IMMEMIVIUMMEEN 6600 ■■■EMII■■■ ■■EELISMEIN■■ ; ■■MMiitiiINE■■ ■■■ ERMISIM■■6650 DEmmtmoisamomm MEIMIEWSIMENNIME ■!■■ EMBEN _ a ■�� �� �■6700 ` = ■■■ IR ■■■■ ■■■®1 ffi■■■■ 1111111115111111 110121111111 s5o ■■■■ER■Ni■■■ ■■■■E ■■■■■ ■111■■LILU■■■■ _ orzet ■■ESIMIERM■■6800 ■■■■Ei■■■■■ ii■■AM■i®i ■■■i11:■■■■■ !®■■■ila■li■■ mossmorimmenin 6850 MINEMENEESIMMIN MIESIMINEVAIIIMMIN MMINEERMENIMEN ■■NNIMITA■ E-■6900 11111111111111EMENIMIN ■IN®■SER■®■■6950 ■■■■iNIMMEM■ ■■■■ IIIM■■■ `= ■■ I■MUN■■!'ME■ • 0 111151111,Lit II MI 111111111111 ...., ■mai Enum■■ =7000 — 11111111111111111111111111111111111111 — 1111111111111111N11111111111111111f ■■■11111MME ■■7050 _ . 1111111.1110-111111111111111111 111111111111111M1111111111111111 _1111111111111111111111111111111111111111111111111 _ - ■■!■EIM■■■■ ■■■■k1110 ■■■ - _ 1.111111111111M11111111117100 M1111151111111111111111111■■■■Ei�■'s,: ®■ ■■■l1111111■■■■ _ ■■■ � 011110.111117150 1111IFIAMI7200 11111111111115111111111111111111•111 - ._ ■ ■■ , ■■■1.1111/11r—ir MN T.,.s.,...iiii __ ■■■■11•■i■ L rr -� _._ ,moi -_ 1111111 i l 7250 -- 7. �iiYiiBi�� ■0111111111fl ■■■ il :7300 y 1111111111111111111111111111111111111111111 ■■■■11` ■■■■ :7350 --� `—��..:tttt _ �liiiii� ��.�aa>ufiaiiYYYWr11W Minimum Radius • 1.25 inches 1.75 Maximum Radius 1.25 inches 1.75 Minimum I.D. I 2.5 inches 3.5 Maximum I.D. -. --1 2.5 inches 3.5 Nominal I.D. Depth 3-D Log(Un-Centered) Image Map(Un-Centered) 3-D Log(Centered) Image Map(Centered) 2.5 3.5 1:600 0° 0° 90° 180°270° 0° 0° 0° 90° 180°270° 0° • • Ca Maximum Recorded Penetration Comparison To Previous Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Previous Date: March 12,2010 Company: ConocoPhillips Alaska, Inc. Tool Type: UW MFC 24 No. 211387 Country: USA Tubing: 3.5"9.3 lb J-55 IPC Overlay Difference Maximum Recorded Penetration(mils) Difference in Maximum Penetration(mils) 0 50 100 150 200 250 -50 -25 0 25 50 0.1 0.1 9 — 19 — 19 29 3 39 39= 49 49 _.:- 59 5 = GLM 1 = 67—= 67 77 -- 7Z- 87 — —8-. it 97 974_ d 107 iv 11771_ c 117 117 Z GLM'_ Z tS '$126 I 126 -ti 136 1�- x- 146 146 L 156 1564 166 166-_ GLM3 _ 175 — 175 - 185 == 185 195 195 - 8E0$ 204 204 213 213 y= 223 — 223 233 — 2332 GLM 6 GLM 239 - 239 7'77- -7 -3 0 3 7 U June 13,2017 I March 12,2010 Approximate Corrosion Rate(mpy) Corrosion Rate(mpy) Top 10 Jts. Overall Average 3 0 Median 3 0 • • Correlation of Recorded Damage to Borehole Profile II Pipe 1 3.5 in (28.2'-7,379.0') Well: 1E-15A Field: Kuparuk Company: ConocoPhillips Alaska,Inc. Country: USA Survey Date: June 13,2017 ■ Approx.Tool Deviation ■ Approx.Borehole Profile 1 36 25 I 774 50 1,543 GLM 1 --E J 75 2,318 7 100 3,076 E ct GLM 2 c L.L.c Z 125 3,853 L c a a) .5 p 150 4,606 GLM3 175 5,379 6LM i 200 6,136 225 - 6,906 GLM6 IINIMII GLM 7 239 7,366 0 50 100 Damage Profile(%wall)/Tool Deviation (degrees) Bottom of Survey=239 . • • PDS Report Overview (IRS. Body Region Analysis Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pi.e 3.5 in. 9.3 ..f J-55 IPC Anal st: C.Waldro. Pipe Nom.OD Weight Grade&Thread Nom.ID Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC 2.992 in. 28 ft. 7,379 ft. Penetration(%wall) Damage Profile(%wall) 250 Penetration body milml Metal loss body 0 50 100 0.1 200 150 100 49 50 GLM 1 0 0 to 20 to 40 to over 20% 40% 85% 85% Number of joints analyzed (total=241) 97 238 3 0 0 1 GLM 2 (4:00) Damage Configuration(body) 30 ii 146 20 GLM 3 (8:00) 10 195 ON 4 Pi®®) 0 Isolated General Line Other Hole/ Pitting Corrosion Corrosion Damage Pos.Hole Number of joints damaged(total=31) EEM 9'(11:98) 239 21 0 10 0 0 Bottom of Survey=239 • • Ili 4L ii 0 PDS Report Joint Tabulation Sheet Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. 1 Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC Tubing 2.992 in. 0.254 in. 28 ft. 7,379 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 0.1 28 0 0.02 9 2 2.91 Pup Lt. Deposits. t 0.2 32 0 0.02 8 2 2.95 Pup • 1 36 0 0.05 20 9 2.95 Isolated Pitting. C 2 67 0 0.05 20 4 2.94 Isolated Pitting. 3 99 0 0.02 9 3 2.93 Lt.Deposits. • 4 128 0 0.03 10 3 2.96 • 5 158 0 0.03 11 3 2.92 Lt.Deposits. • 6 189 0 0.02 8 2 2.94 • 7 221 0 0.02 9 2 2.95 • 8 252 0 0.03 10 2 2.95 C 9 284 0 0.03 11 4 2.93 10 314 0 0.03 10 2 2.94 • 11 346 0 0.02 8 2 2.95 • 12 375 0 0.02 9 3 2.95 II 13 407 0 0.03 10 2 2.95 ■ 14 438 0 0.02 9 3 2.94 • 15 470 0 0.02 9 2 2.96 • 16 499 0 0.02 9 2 2.93 • 17 530 0 0.02 9 2 2.94 • 18 561 0 0.02 9 3 2.94 • 19 592 0 0.02 8 2 2.93 Lt.Deposits. II 20 621 0 0.02 9 2 2.93 Lt.Deposits. • 21 653 0 0.02 9 3 2.92 Lt.Deposits. • 22 683 0 0.02 8 2 2.94 A 23 715 0 0.02 6 2 2.92 Lt.Deposits. 1 24 745 0 0.04 16 3 2.90 Shallow Pitting. Lt Deposits. MIN 25 774 0 0.03 10 3 2.94 • 26 806 0 0.03 10 2 2.92 Lt.Deposits. I 27 835 0 0.02 9 2 2.93 Lt.Deposits. • 28 865 0 0.02 7 2 2.91 Lt.Deposits. • 29 894 0 0.02 9 2 2.91 Lt.Deposits. • 30 925 0 0.02 8 2 2.94 • • 31 956 0 0.02 7 2 2.91 Lt.Deposits. 32 987 0 0.03 10 2 2.92 Lt.Deposits. • 33 1017 0 0.02 8 2 2.91 Lt.Deposits. • iii 34 1046 0 0.02 7 2 2.92 Lt.Deposits. 35 1077 0 0.02 9 2 2.93 a 36 1108 0 0.02 9 3 2.93 Lt.Deposits. • 37 1140 0 0.02 8 2 2.93 Lt.Deposits. • 38 1171 0 0.02 7 2 2.92 Lt.Deposits. • 39 1202 0 0.02 8 2 2.93 Lt.Deposits. • 40 1234 0 0.02 9 3 2.93 Lt.Deposits. • 41 1265 0 0.02 9 3 2.91 Lt.Deposits. • 42 1297 0 0.03 10 2 2.91 Lt.Deposits. • 43 1328 0 0.02 7 2 2.94 • 44 1359 0 0.03 13 4 2.93 a 45 1389 0 0.03 10 3 2.94 • 46 1420 0 0.02 9 2 2.94 IN 47 1450 0 0.03 11 3 2.93 Lt.Deposits. C 48 1481 0 0.02 9 3 2.92 Lt.Deposits. IPenetration Body Metal Loss Body Page 1 • • d=r1°)S PDS Report Joint Tabulation Sheet Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC Tubing 2.992 in. 0.254 in. 28 ft. 7,379 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 is 49 1512 0 0.03 10 3 2.93 Lt.Deposits. 50 1543 0 0.03 12 2 2.95 Is • 51 1575 0 0.02 9 3 2.93 Lt.Deposits. 52 1605 0 0.02 8 2 2.93 • 53 1636 0 0.02 9 2 2.93 Lt.Deposits. U 54 1665 0 0.02 7 3 2.92 Lt.Deposits. N M 55 1695 0 0.07 26 2 2.93 Isolated Pitting. 56 1724 0 0.03 12 2 2.92 Lt.Deposits. n 57 1753 0 0.02 9 2 2.93 Lt.Deposits. ■ 58 1783 0 0.02 9 2 2.93 1 59 1815 0 0.03 10 2 2.94 0 60 1846 0 0.03 12 5 2.95 r 60.1 1878 0 0 0 0 2.79 CAMCO TRDP-1A SSSV 61 1889 0 0.02 9 3 2.94 • 62 1917 0 0.03 12 2 2.95 s• 62.1 1949 0 0 0 0 2.79 GLM 1 (NO DEVIATION) 63 1955 0 0.02 8 3 2.94 i 64 1985 0 0.03 13 3 2.93 Lt.Deposits. U 65 2017 0 0.03 10 3 2.94 • 66 2048 0 0.03 10 3 2.93 I l 67 2079 0 0.02 9 2 2.94 • 68 2109 0 0.03 12 3 2.92 Lt.Deposits. r• 69 2138 0 0.03 10 2 2.94 • 70 2169 0 0.03 12 4 2.92 Lt.Deposits. II 71 2200 0 0.03 10 4 2.96 • 72 2228 0 0.04 , 16 3 2.95 Shallow Pitting. is 73 2259 0 0.03 10 2 2.92 Lt.Deposits. • 74 2288 0 0.04 14 2 2.93 75 2318 0 0.04 16 2 2.94 Shallow Line of Pits. _ INI 76 2348 0 0.03 13 2 2.93 ni 77 2377 0 0.03 12 2 2.92 Lt.Deposits. l• 78 2406 0.05 0.03 13 3 2.92 Lt.Deposits. r 79 2436 0 0.02 7 2 2.941 80 2467 0 0.04 14 3 2.98 81 2496 0 0.02 9 2 2.93 Lt.Deposits. • 82 2527 0 0.03 13 2 2.93 Lt.Deposits. me 83 2558 0 0.03 11 2 2.92 Lt.Deposits. r 84 2588 0 0.03 10 2 2.92 Lt.Deposits. • 85 2619 0 0.02 9 2 2.92 Lt.Deposits. • 86 2649 0.04 0.05 19 3 2.92 Shallow Line of Pits.Lt. Deposits. on 87 2679 0 0.03 11 2 2.94 U 88 2710 0 0.02 9 3 2.92 Lt.Deposits. • 89 2742 0 0.04 14 3 2.97 C 90 2773 0 0.03 11 3 2.95 G 91 2804 0 0.03 11 2 2.90 Lt.Deposits. 92 2833 0 0.04 17 3 2.95 Shallow Pitting. in 93 2864 0 0.02 7 2 2.97 s 94 2894 0 0.03 12 2 2.96 Is 95 2926 0 0.02 7 2 2.95 96 2956 0 0.03 12 2 2.95 a IPenetration Body Metal Loss Body Page 2 • . 11111 PDS Report Joint Tabulation Sheet Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC Tubing 2.992 in. 0.254 in. 28 ft. 7,379 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 97 2987 0 0.02 9 3 2.92 Lt.Deposits. J 98 3016 0 0.03 13 3 2.92 Lt.Deposits. ■ 99 3046 0 0.03 11 2 2.90 Lt.Deposits. ■ 100 3076 0 0.03 13 2 2.92 Lt.Deposits. ■ 101 3107 0 0.03 10 3 2.92 Lt.Deposits. ■ 102 3137 0 0.03 10 2 2.91 Lt.Deposits. ■ 103 3168 0 0.04 14 2 2.93 Lt.Deposits. • 104 3198 0 0.03 12 2 2.95 105 3229 0 0.02 9 2 2.94 106 3259 0 0.03 12 2 2.94 • 107 3290 0 0.03 12 2 2.89 Lt.Deposits. 108 3322 0 0.02 9 2 2.94 109 3353 0 0.03 10 2 2.95 • 110 3384 0 0.03 10 2 2.90 Lt.Deposits. ■ 111 3415 0 0.03 11 2 2.91 Lt.Deposits. • 112 3446 0 0.03 10 2 2.92 Lt.Deposits. ■ 113 3476 0 0.05 18 2 2.91 Shallow Pitting. Lt Deposits. 114 3507 0 0.02 9 2 2.91 Lt.Deposits. 115 3538 0 0.03 10 2 2.89 Lt.Deposits. ■ 116 3568 0 0.03 12 2 2.89 Lt.Deposits. ■ 117 3598 0 0.04 14 2 2.94 • 118 3630 0 0.03 11 2 2.92 Lt.Deposits. 119 3660 0 0.02 9 2 2.90 Lt.Deposits. 119.1 3691 0 0 0 0 2.87 GLM 2(LATCH @ 4:00) 120 3697 0 0.03 11 3 2.91 Lt.Deposits. • 121 3729 0 0.03 11 2 2.94 • 122 3760 0 0.04 15 3 2.95 Shallow Pitting. ■ 123 3790 0 0.03 12 3 2.96 • 124 3822 0 0.03 11 2 2.92 Lt.Deposits. ■ 125 3853 0 0.03 11 2 2.95 • 126 , 3883 0 0.04 14 3 2.94 a 127 3914 0 0.03 11 4 2.94 • 128 3946 0 0.03 13 3 2.91 Lt.Deposits. • 129 3976 0 0.04 15 4 2.89 Shallow Line of Pits.Lt. Deposits. ■ 130 4005 0 0.04 15 3 2.93 Shallow Pitting. Lt Deposits. ■ 131 4035 0 0.03 12 2 2.92 Lt.Deposits. • 132 4066 0 0.03 11 2 2.96 • 133 4095 0 0.03 10 3 2.95 • 134 4124 0 0.04 14 2 2.92 Lt.Deposits. • 135 4155 0 0.03 13 3 2.89 Lt.Deposits. ■ 136 4186 0 0.03 11 2 2.93 • 137 4217 0 0.03 11 3 2.91 Lt.Deposits. ■ 138 4247 0 0.04 14 3 2.88 Lt.Deposits. • 139 4275 0 0.03 12 3 2.91 Lt.Deposits. ■ 140 4304 0 0.04 15 2 2.90 Shallow Pitting. Lt Deposits. ■ 141 4334 0 0.03 12 3 2.90 Lt.Deposits. • 142 4363 0 0.03 13 3 2.90 Lt.Deposits. ■ 143 4394 0 0.03 13 2 2.93 • 144 4425 0 0.03 11 2 2.93 Lt.Deposits. ■ 145 4456 0 0.03 12 3 2.90 Lt.Deposits. IPenetration Body Metal Loss Body Page 3 • • Pi PDS Report Joint Tabulation Sheet Well: 1 E-15A Survey Date: June 13,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC Tubing 2.992 in. 0.254 in. 28 ft. 7,379 ft. Joint it.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 146 4486 0 0.04 14 2 2.92 Lt.Deposits. m 147 4514 0 0.03 11 2 2.91 Lt.Deposits. • 148 4545 0 0.03 . 11 3 2.93 • 149 4575 0 0.04 15 2 2.92 Shallow Line of Pits.Lt. Deposits. a 150 4606 0 0.04 15 2 2.91 Shallow Line of Pits.Lt. Deposits. ■ 151 4636 0 0.04 15 2 2.90 Shallow Pitting. Lt Deposits. a 152 4665 0 0.04 . 14 3 2.92 Lt.Deposits. ■ 153 4696 0 0.03 12 2 2.88 Lt.Deposits. ■ 154 4726 0 0.04 14 4 2.92 Lt.Deposits. ■ 155 4756 0 0.03 11 2 2.92 Lt.Deposits. El 156 4786 0 0.03 13 3 2.92 Lt.Deposits. • 157 4818 0 0.03 13 2 2.92 Lt.Deposits. li 158 4850 0 0.03 10 3 2.88 Lt.Deposits. 159 4881 0 0.02 9 3 2.92 Lt.Deposits. 160 4912 0 0.03 13 2 2.93 • 161 4943 0 0.04 17 3 2.94 Shallow Pitting. a 162 4975 0 0.03 12 4 2.94 163 5007 0 0.02 8 2 2.93 Lt.Deposits. 164 5037 0 0.03 13 2 2.95 • 165 5069 0 0.03 11 3 2.91 Lt.Deposits. ■ 166 5098 0 0.03 13 2 2.93 Lt.Deposits. ■ 167 5129 0 0.03 11 3 2.93 Lt.Deposits. • 168 5158 0 0.04 14 3 2.92 Lt.Deposits. ■ 169 5189 0 0.03 13 3 2.91 Lt.Deposits. 169.1 5220 0 0 0 0 2.85 GLM 3(LATCH @ 8:00) 1 170 5226 0 0.03 10 2 2.88 Lt.Deposits. • 171 5257 0 0.03 11 3 2.92 Lt.Deposits. ■ 172 5287 0 0.03 10 2 2.91 Lt.Deposits. • 173 5318 0 0.03 11 , 3 2.88 Lt.Deposits. • 174 5349 0 0.03 10 2 2.93 w 175 5379 0 0.03 12 2 2.93 Lt.Deposits. a 176 5411 0 0.03 13 3 2.89 Lt.Deposits. ■ 177 5440 0 0.04 14 2 2.92 Lt.Deposits. • 178 5472 0 0.03 12 2 2.92 Lt.Deposits. ■ 179 5503 0 0.04 14 4 2.92 Lt.Deposits. ■ 180 5534 0 0.03 12 2 2.93 Lt.Deposits. ■ 181 5564 0 0.03 10 3 2.89 Lt.Deposits. • 182 5593 0 0.02 9 3 2.93 Lt.Deposits. I 183 5624 0 0.03 13 4 2.89 Lt.Deposits. 184 5654 0 0.02 9 3 2.90 Lt.Deposits. 185 5685 0 0.04 15 3 2.91 Shallow Line of Pits.Lt. Deposits. ■ 186 5712 0 0.03 13 4 2.93 Lt.Deposits. • 187 5744 0 0.03 10 3 2.92 Lt.Deposits. ■ 188 5774 0 0.03 11 2 2.92 Lt.Deposits. ■ 189 5803 0 0.03 11 2 2.92 Lt.Deposits. • 190 5833 0 0.03 12 3 2.93 Lt.Deposits. 191 5862 0 0.02 9 2 2.90 Lt.Deposits. 192 5893 0 0.04 14 3 2.94 • 193 5924 0 0.03 11 3 2.93 Lt.Deposits. ■ 194 5954 0 0.05 18 4 2.90 Shallow Line of Pits.Lt. Deposits. IPenetration Body Metal Loss Body Page 4 • • 1111 PDS Report Joint Tabulation Sheet Well: 1 E-15A Survey Date: June 13,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC Tubing 2.992 in. 0.254 in. 28 ft. 7,379 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 195 5984 0 0.03 11 3 2.92 Lt.Deposits. ■ 196 6015 0 0.03 11 2 2.91 Lt.Deposits. 197 6044 0 0.02 9 3 2.91 Lt.Deposits. 198 6075 0 0.03 12 2 2.92 Lt.Deposits. • 199 6106 0 0.04 14 3 2.91 Lt.Deposits. • 200 6136 0 0.03 13 3 2.90 Lt.Deposits. ■ 201 6165 0 0.03 13 3 2.91 Lt.Deposits. • 202 6195 0 0.03 11 3 2.93 Lt.Deposits. • 203 6224 0 0.04 16 4 2.91 Shallow Pitting. Lt Deposits. 203.1 6256 0 0 0 0 2.82 GLM 4(LATCH @ 3:00) 204 6262 0 0.04 16 2 2.92 Shallow Line of Pits.Lt. Deposits. 204.1 6291 0 0 0 0 2.88 GLM 5(LATCH (4 7:00) 205 6298 0 0.03 13 4 2.91 Lt.Deposits. ■ 206 6328 0 0.03 10 2 2.93 Lt.Deposits. ■ 207 6359 0 0.03 11 2 2.94 208 6389 0 0.03 10 2 2.91 Lt.Deposits. 209 6419 0 0.05 19 2 , 2.91 Shallow Line of Pits.Lt. Deposits. 210 6448 0 0.04 15 2 2.92 Shallow Pitting. Lt Deposits. ■ 211 6476 0 0.04 14 3 2.92 Lt.Deposits. ■ 212 6506 0 0.04 14 2 2.93 Lt.Deposits. • 213 6537 0 0.03 13 4 2.93 Lt.Deposits. ■ 214 6567 0 0.05 19 2 2.95 Shallow Pitting. • 215 6599 0 0.05 . 18 3 2.91 Shallow Pitting. Lt Deposits. ■ 216 6630 0 0.04 16 2 2.91 Shallow Pitting. Lt Deposits. 217 6660 0 0.03 11 3 2.89 Lt.Deposits. • 218 6691 0 0.04 14 3 2.93 Lt.Deposits. • 219 6721 0 0.03 13 3 2.92 Lt.Deposits. 220 6751 0 0.03 13 3 2.90 Lt.Deposits. 221 6782 0 0.02 9 2 2.90 Lt.Deposits. • 222 6813 0 0.03 11 3 2.91 Lt.Deposits. 223 6844 0 0.03 12 2 2.93 Lt.Deposits. 224 6874 0 0.03 10 2 2.92 Lt.Deposits. 225 6906 0 0.02 9 2 2.94 ■ 226 6937 0 0.03 10 2 2.94 227 6967 0 0.05 18 3 2.94 Shallow Pitting. • 228 6998 0 0.03 13 2 2.94 229 7029 0 0.03 10 2 2.89 Lt.Deposits. 230 7060 0 0.05 19 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 231 7091 0 0.03 13 4 2.93 Lt.Deposits. 232 7122 0 0.03 10 3 2.92 Lt.Deposits. 233 7152 0 0.04 15 2 2.92 Shallow Pitting. Lt Deposits. 234 7182 0 0.03 10 2 2.92 Lt.Deposits. 235 7214 0 0.03 11 2 2.93 Lt.Deposits. 236 7243 0 0.04 17 2 2.89 Shallow Pitting. Lt Deposits. 236.1 7272 0 0 0 0 2.90 GLM 6(LATCH @ 11:00) 237 7279 0 0.04 16 3 2.93 Shallow Pitting. Lt Deposits. 237.1 7309 0 0 0 0 2.92 BAKER PBR 237.2 7323 0 0 0 0 2.95 BAKER FHL PACKER 238 7330 0 0.03 10 2 2.91 Lt.Deposits. 238.1 7359 0 0 0 0 2.87 GLM 7(LATCH @ 11:30) IPenetration Body Metal Loss Body Page 5 • • ci err Sµ PDS Report joint Tabulation Sheet Well: 1 E-15A Survey Date: June 13,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf J-55 IPC Tubing 2.992 in. 0.254 in. 28 ft. 7,379 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 239 7366 0 0.04 14 2 2.89 Lt.De•osits. 111/ IPenetration Body Metal Loss Body Page 6 • • PDS Report Cross Sections Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubin:: 3.5 in. 9.3 ••f J-55 IPC Analyst: C.Waldro. Cross Section for Joint 55 at depth 1,701 .020 ft. Tool speed= 51 Nominal ID=2.992 Nominal OD=3.5 • Remaining wall area=98% Tool deviation=3° Finger=4 Penetration=0.066 in. Isolated Pitting 0.07 in.=26%Wall Penetration HIGH SIDE=UP • • PDS Report Cross Sections Well: 1E-15A Survey Date: June 13,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 in. 9.3 ppf J-55 IPC Analyst: C.Waldrop Cross Section for Joint 2 at depth 67.760 ft. Tool speed=53 Nominal ID=2.992 Nominal OD=3.5 Remaining wall area=97% Tool deviation=5° i 1 - Finger= 10 Penetration=0.051 in. Isolated Pitting 0.05 in.=20%Wall Penetration HIGH SIDE= UP • • KUP INJ 1E-15A Conon i hiIIips " 2=1 Well Attributes Max Angle&MD TD AIL/515E,Inc, Wellbore APUUWI Field Name Wellbore Status Inc)(^) MD IRKS) Act Btm(RKB) rcvxlcxafiiu,p. 500292076901 KUPARUK RIVER UNIT (NJ 100,75 9,280.35 9,800,0 ••• Comment H2S(ppm) Date Annotation End Date KB-Grd(R) Rig Release Date 1E-15A.2/2/201511:29:49 AM SSSV:TRDP Last WO: 11/5/1984 40,71 8/4/1982 Vertical schematic (actual) Annotation Depth(RKBI End Date Annotation Lost Mod By End Date Last Tag:SLM Rev Reason:NOTE UPDATE lehallf 2/2/2015 11. `r Casing Strings Casing Description OD lin) ID(in) Top(RKB) Set Depth IRKS) Set Depth(TV131... WI/Len(1...Grade Top Thread CONDUCTOR 16 15,060 32.0 112.0 112,0 65,00(4-40 WELDED Crating Description OD lin) ID(in) Top(ftKB) Set Depth(RKB) Set Depth(TVD)...WULen p,..Grade Top Thread SURFACE 103/4 9.950 34.0 2,193.0 2,192.8 45.50 K-55 BTC .. - , „ , „ ,,,,,luau Casing Description OD(in) ID(in) Top OMB) Set Depth(RKB) Set Depth(TVD)...WULen IL..Grade Top Thread -^-^:-'GONWCTOR'32.6-1120"' yi..WINDOW AL2-01 8 6.000 7.557.8 7,564.7 6,256.8 Casing Description OD Un) ID(in) Top(RKB) Set Depth MKS) set Depth(fVDI... WVlen(1...Grade Top Thread WINDOW ALI 8 6.000 7,633,1 7,640.8 6,316.2 SAFETY VIV 1.871.8 -.0.°' Casing Description 00)(n) ID(in) Top(RKB) Set Depth(RKB) Set Depth(TVD)...WULen 11...Grade Top Thread . PRODUCTION 7 6.276 35.0 8,415.0 6,390.5 26.00 K-55 BTC GAS UFT:1,948.5 ,. Casing Description 00(in) ID(in) Top IRKED Set Depth IRKS) Set Depth(TVD)...Wulan(I...Grade Top TMead Liner A(off AL)) 23/8 1.995 8,326.3 9,797.0 6,361.7 4.60 L-80 STL Uner Details Top(RKB) Top(TVD)(RKB) Top Incl V) Item Dee Com rJominID I n) • 8,326.3 6,392D 89.84 Junction(billet) Liner top billet 1.000 Tubing Strings SURFACE:34.0.2.193.0 „ Tubing Description I String Ma...l ID(in) I Top IRKB) I Set Depth)ft..J Set Depth(TVD)(,..I WI(IbIS) I Grade /Top Connection TUBING 3 1/2 2.992 29.8! 7,682.41 6,340 5 9.30 J-55 I IPC GAS UFT:3,9905 II ' Completion Details Nominal ID Top 0•056) Top(TVD)OMB) Top Incl(') Item Des Com (in) GAS LIFT:5,218.8 129.8 29,8 0.00 HANGER FMC TUBING HANGER 3.500 1,877.8 1.62 SAFETY VLY CAMEO TRDP-1A 2.813 GAS LIFT;5,205.e 71.430777149- 6,055.0 38,07 PER BAKER PER 3,000 7,321.8 6,066.3 6,177.9 38.11 PACKER BAKER FHL PACKER 3,000 GAS LIFT,6,2012 7,464.0 38.39 BLASTJT 2.992 7,661.9 6,330.0 54.61 LOCATOR BAKER LOCATOR 4.000 GAS LIFT.72n.9 7,662.5 6,330.4 54.94 PACKER BAKER FE-I PACKER 4.000 ''!'l 7,676.1 6,337.5 60.34 NIPPLE CAMCO'D'NO GO NIPPLE 2.750 PBR 73074 7.881.7 6,340.3 61.53 SOS BAKER SHEAR OUT SUB 2.992 PACKER 7,321,e Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) M Top(TVD) Top Incl INJECTION:7,380.0 s'• Top(RKB) (RKB) (') Des Com Run Date ID(in) 7,557.0 6,250.8 38.42 WHIPSTOCK AL1 Baker monobore WS with 4-deg kick removed 3/24/2010 1.000 INJECTION:7,423.4 7,631.0 6,308.8 38.52 WHIPSTOCK AL2-01 Baker monobore WS with 4-deg kick 3/16/2010 1.000 removed 1' Perforations&Slots Shot CMT sOZ;7.678.0-7,554.9 Dens Top(TVD) Btm(TYD) (anotae TW(RKBI Barn(RKB) (RKBI (RKB) Zone Date t) Type Con. 8,332.3 9,792.6 6,392.0 6,361.7 3/22/2010 32.0 SLOTS Alternating solid/slotted CMT SW;7,559_o-7,s64.o it pipe-0.125"x2.5"0 4 circumferential adjacent rows,3'centers staggered 18 deg,3'non -slotted ends WHIPSTOCK:7.557.0 :(I5-' Mandrel Inserts WINDOW AL2-01:7,557.8- l ,_ I. St 7.684.7 eti on Top(TVD) Valve Latch Port Size TRO Run SLOTS:7.543.0-7.508_5 N Top(RKB) (RKB) Make Model OD(in) Sere Type Type let) (psi) Rum Date Com • • 1 1,948,5 1,948,4 CAMEO KBUG 1 GAS UFT DMY BK 0.000 0.0 8/31/2010 INJECTION:7,502.1 2 3,690.5 3,5049 CAMEO KBUG 1 GAS LIFT DMI BK 0.000 0.0 8/31/2010 3 5,218.8 4,525.7 CAMCO KBUG 1 GAS UFT DM)" BK 0.000 0.0 6/5/1990 4 6,255.6 5,252.1 CAMEO KBUG 1.GAS LIFT .DMV BK 0.000 0.0 11/5/1984 5 6,291.2 5,277.8 CAMEO KBUG 1 GAS LIFT WY BK 0.000 0.0 6/3/1990 ` 6 7,271.9 6,027.0 CAMCO KBUG 1 GAS LIFT DMV BK 0.000 0.0 6/5/1990 CMT saz:7.a19.o-7,e99.9 7 7,359,0 6,095.5 CAMEO KBUG 1 INJ CAW BK 0.000 0.0 7/20/1993 • 8 7.425.4 6,147.6 CAMEO KBUG 1 INJ DMI BK 0.000 0.0 7/20/1993 • 9 7,592.1 6,278.3 CAMEO KBUG 1 IN) DWI' BK 0.000 0.0 7)20/1993 Notes:General&Safety WHIPSTOCK:7,531.0 Ili End Date Annotation 4/20/2010 NOTE:VIEW SCHEMATIC w/Alaska ScheltlatIc9.0 WINDOW AL1:7.933-1-7.e408 f 4/20/2010 NOTE:SIDETRACK w/LATERALS 1E-15A,15AL1,15AL2,15AL2-01 2/22115 NOTE:T X IA COMMUNICATION ON MI only-water infection only LOCATOR 7.551.4 PACKER 7502.5 i I NIPPLE 7,078.1 077_4( SLOTS:7.088.4-0,753.5 SOS:7,501.7-, I Liner AL2-01 rolemain wellborn): I 7,542,49.705.0 SLOTS:8.0819-8,810.13------ Liner .081.9-8,0109Liner AL1;7.823.4-8,812,0 1 PRODUCTION:35.0-8,4150 SLOTS:8.332.3-9,792.0 - I I -. Liner A(oAL 1);8.325.3- j a 0.797.0 f . A CASING /TUBING / LINER DEIAIL Ki1PARI ii< r':)J.IiR, OW- DRILL SiTE I E -15 '- py- GINEDift,u DATE II-A Ali4 ARCNklask6Onci40` 4 i7' Pae i of i Paget Svasidliry 0 Aginil0ktohfirdt!'"!IP,Iii \I ti‘ .1,1 ir g _ NITEMS COMPLETE DISePIP 6AP EOUIPMENT RuN LENGTH DEPTH II I i eleilAL ' A2-3 )R•491, /,1° .2,, -92,- '__,3 a `2)V ii-rifiemi- 734-. is.”161 .3)0x G i rr)(11) 'TyP)bst.i. . , ..- La ...0 zit . '11 it 20_,Sill_tyll -t- ' 5 -1-#.ie /4 • 44140,0_954! -5'. .(2.. Cjlin 4.0 61-M .1.4) l".b4ern, it,i1.369.e,,34, ___617,,,e6. :52ZA 1 _Pik 44 .4 3 C,g W Ck4In 4.4)/ribli4iilly I a.-2,'" 1,5,24,Ki- , ____iii , tp 't ., A. 0.30 si S.2p2•1,91 6-241 L,)] 1me9 I_ 3r 32.1! "rvPiell, •?./ 4.2Vt 6n,4m ex) c.,4)-yi 14)//ii beim A i to ;t:40 , 2,,,•291,-, . ,... .. , a , .-2, A.. • 32 • - • I INSII, " . • 20,3° tiZ•I')46'2-' I..Sr 511.4" TYPkek_. 7._ .h,4ka 1-,,0 LA),3at,S44.e. 1349 - Xoitp To sN , 14),k1) x.5015& .1- Zr 3 '2.1." 1-1511t.g). 764,-, raif 96 ‘3,20,' 41- t knez 604 RI/i" bemlmy94- ._ ,,, r; ..,.. ..0 4 Ag,ls ,48,104. 1 3 „64 r_, 109,v tp-Lir ts.)1)"bamirly Y-z 4LI,Z5,3-t ' " PI I. 6- r 11' . 4c ..... •, -... P .1r• ,p2 3'1_5 f4k5 X i1)-1.,S ,g)e.9s ,.'30.°•°- 57,9/t 444111),4-2.- .1 rA4.0 e)0/0(. 522487 C PAY ,29.cs ,Z9 -is' AASSA.,)f I 5 Y.a" Tab- Adios TYP)tm.L. ii, is M ci C.Aroes 61.m t.,)/iorloom, 62 3r.S 3,22', 7-9Piou. The,. -I t..0..3 +.'31c4' 2412.014` ..5/I, " 1 II L : •... • ..f r , ' .. Li. _ LdA.Lgit_i_iiLjlithAL-511' 521" 18crit- 6 P TY'ibli..) ?,,, i, w9,94, 0.-4m0.. ` N 3 . a..ii • i A 5q.2..- :.' V -sieibe otai-- iteohk. 40 14) 4 X .24' S74 71/423 90170M OF TUBING TAIL raft Mai?.... PA•1 4.A Li--k e.C,e_ticei 4,16110 '..- tl, I.• 7L WliV,..4 ?iltir.e PI/ '' .S.:5 2 TV U1;4/ 0 •. ; = i, " (Y..2- 3-SS 41.7-4 C.. Pe- 78 c i. CA.,a...t. 4,8m, <,.. z & _ . _ . .. ... . .. _ ... . .._ . ...._..._..„.... SO • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Tuesday,January 10,2017 Jim Regg Supervisor I�e /P.I. z-1(7 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC IE-15A FROM: Chuck Scheve KUPARUK RIV UNIT 1E-15A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry .) NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1E-15A API Well Number 50-029-20769-01-00 Inspector Name: Chuck Scheve Permit Number: 210-013-0 Inspection Date: 1/8/2017 Insp Num: mitCS170109060820 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well IE-15A Type Inj W TVD 6066 Tubing 2595 2602 - 2605 • 2601 - PTD 2100130 Type Test SPT Test psi 3000 - IA 870 3410 w 3320 3300 • BBL Pumped:..— BBL Returned: OA 500 660 - 660 . 660 • Intervale REQVAR P/F P Notes: Tested per AIO 2B.081 sCONED APR 0 52.01 Tuesday,January 10,2017 Page 1 of 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Monday,November 30,2015 P.I.Supervisor Irl` 1((3b)15 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1E-15A FROM: Bob Noble KUPARUK RIV UNIT 1E-15A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 1E-15A API Well Number 50-029-20769-01-00 Inspector Name: Bob Noble Permit Number: 210-013-0 Inspection Date: 11/20/2015 Insp Num: mitRCN151120175437 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1E-15A - Type Inj TVD 6066 - Tubing 1518 - 1516 1516 - 1515 PTD 2100130 - Type Test SPT Test psi 3000 - IA 700 3300 . 3200 - 3200 - Interval 1EQVAR P/F P ✓ OA 295 - 320 - 320 _ 320 • Notes: AIO 2B.081 MIT-IA required by variance to mmaximum anticipated injection pressure of 3000 psi SCANNED SEP 16 2016. Monday,November 30,2015 Page 1 of 1 410) Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Thursday, December 05, 2013 8:39 AM To: 'NSK Problem Well Supv' Cc: Senden, R. Tyler Subject: RE: Report of multiple bleeds of Kuparuk injector 1E-15A(PTD 210-013) Kelly, Agree with the plan. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue FT--;:: Anchorage,AK 99501 SCANNED 0 <. (907)793-1250(phone) (907)276-7542 (fax) chris.wallace @alaska.gov From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent:Thursday, December 05, 2013 8:15 AM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: Report of multiple bleeds of Kuparuk injector 1E-15A(PTD 210-013) - CHOKE FTP FTT IAP OAP TJI/O Plot-1E-15 3500 — I I 3000 - 2500 2 — I!I l d. 1500 1000 500 T / / r 0 11 i I i l l II i i I i i 4 I l i i I i i i II 05-Sep-13 18-Sep-13 01-Oct-13 14-Oct-13 27-Oct-13 09-Nov-13 22-Nov-13 Date I neglected to include the updated TIO plot. From: NSK Problem Well Supv Sent:Thursday, December 05, 2013 8:14 AM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: RE: Report of multiple bleeds of Kuparuk injector 1E-15A(PTD 210-013) 1 O Chris, As a follow up to the email below,there is now suspected TxIA communication while on MI injection, based on the overall upward trend of the IA pressure,amidst localized thermal swings. CPAI intends to perform initial DHD diagnostics which will include but not be limited to packoff testing(and repair as necessary)/MIT/DDT. That work is scheduled to begin tomorrow 12-6-13. We would like to keep the well on-line in MI injection service during the testing and for a follow up diagnostic monitor period. Because of the slow nature of the apparent leak,it may be to needed to request an extension of the monitor period, but at this point we plan to monitor for 30 days post diagnostics. If the suspected slow communication continues to persist,we would plan to WAG to water injection service ASAP for continued monitoring to see if the communication would only be present on MI, in preparation for a tentative AA submittal. Please let me know if you disagree with the plan. The well will be added to the monthly report. Brent Rogers/Kelly L 9 Y ons Y Problem Wells Supervisor ConocoPhillips Alaska, Inc Desk Phone(907)659-7224 Pager(907)659-7000 pgr 909 From: NSK Problem Well Supv Sent: Friday, November 08, 2013 4:16 PM To: Wallace, Chris D (DOA) Subject: Report of multiple bleeds of Kuparuk injector 1E-15A(PTD 210-013) Chris, This email is to inform you of several recent bleeds performed on Kuparuk injector 1E-15A(PTD 210-013),which is currently on-line in Ml injection service. In addition,the IA pressure is also fluctuating,which at this point is believed to be thermally induced. The bleeds were initiated as an experiment to see if the IA pressure could be easily managed under 2000psi. This experiment is related to the recent dialogue between ConocoPhillips and the Commission regarding the allowable operating IA pressures on MI injectors. I have attached a 90 day TIC plot,which is at daily resolution. I have also included the 90 day SCADA snapshot at hourly resolution with only the IA pressure and temperature. We plan to continue to monitor the well for 30 days of heightened scrutiny. If TxIA communication becomes suspected during this monitor period,we will inform you immediately. At this point,we will not be adding it to the monthly report. However,a follow up email at the end of the 30 days will be provided. Please let us know if you don't agree with this plan. «File:1E-15A 90 day TIC 11-8-13.jpg» «File:1E-15A SCADA snapshotJPG» «File: 1E-15A schematicpdf.pdf» Brent Rogers/Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc Desk Phone(907)659-7224 Pager(907)659-7000 pgr 909 2 DATA SUBMITTAL COMPLIANCE REPORT 10/20/2011 Permit to Drill 2100130 Well Name /No. KUPARUK RIV UNIT 1E -15A Operator CONOCOPHILLIPS ALASKA INC API No. 50- 029 - 20769 -01 -00 MD 9800 TVD 6362 Completion Date 4/20/2010 Completion Status 1WINJ Current Status WAGIN 4IC Y REQUIRED INFORMATION Mud Log No Samples No Directional Survey DATA INFORMATION Types Electric or Other Logs Run: GR / RES (data taken from Logs Portion of Master Well Data Maint Well Log Information: III Log/ Electr Data Digital Dataset Log Log Run Interval OH / Tye Med /Frmt Number Name Scale Media No Start Stop CH Received Comments E D C Lis 19774�nduction /Resistivity 7363 9800 Open 6/17/2010 EWR OH LIS plus PDF, CGM, and TIFF graphics og Induction /Resistivity 2 Col 7632 9800 Open 6/17/2010 MD MPR, GR L Induction /Resistivity 5 Col 7632 9800 Open 6/17/2010 MD MPR, GR L Induction /Resistivity 5 Col 7632 9800 Open 6/17/2010 TVD MPR, GR D C Directional Survey 7600 9800 Open pt Directional Survey 7600 9800 Open Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments • ADDITIONAL INFORMATION Well Cored? `�O Daily History Received? Chips Received? Formation Tops lip' N Analysis cYsf'K" Received? Comments: Compliance Reviewed By: ____ Date:_ 1 1 • • N ConocoPhillips Alaska.: P.O. BOX 100360 -- ANCHORAGE, ALASKA 99510 -0360 %.> ' ,�1 I r ^ ,1:., Cora December 30 2010 Commissioner Dan Seamount r i 0 - r (3 Alaska Oil & Gas Commission la 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Commissioner Dan Seamount: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor. These voids were filled with corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10 -404, Report of Sundry Operations. The cement was pumped September 8 2010 and the corrosion inhibitor /sealant was pumped st rd the well name, top of December 21 , 22 23 , 24 , 2010. The attached spreadsheet presents e p cement depth prior to filling, and volumes used on each conductor. Please call Perry Klein or MJ Loveland at 907 - 659 -7043, if you have any questions. Sincerely, Perry Klein ConocoPhillips Well Integrity Projects Supervisor • 0 0 ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10 -404) Kuparuk Field Date 12/30/2010 1C, 1E, 1F, 1G & 1Y PAD Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name API # PTD # cement pumped cement date inhibitor sealant date ft bbls _ ft gal 1C-07A 50029205690100 2090290 3'2" n/a 3'2" n/a 4.3 12/23/2010 1E-09 50029207200000 1820280 _ 13' 1.00 __ 13" 09/08/2010 3.8 12/22/2010 e E 50029207690100 2100130 3'9" n/a 3'9" n/a 11.6 12/22(2010 14 1 E -16 50029207770000 1821100 4' n/a 4' n/a 13.7 12/22/2010 ■ 1E -17 50029207930000 1821160 3'11" n/a 3'11" Na 8.5 12/24/2010 1F-13 50029210200000 1831440 6" n/a 6" n/a 3 12/23/2010 1F17 50029226570000 1960470 SF n/a 18" Na 7.65 12/23/2010 1F-20 50029226610000 1960530 6" Na 20" n/a 6.1 12/23/2010 1G -13 50029210160000 1831400 13'10" 1.50 30" 09/08/2010 2.5 12/24/2010 1Y-01 50029209330000 1830500 SF n/a _ 6" n/a 1.9 12/212010 1Y -03 50029209430000 1830610 SF n/a 6" n/a 1.7 12/21/2010 1Y-04 50029209480000 1830660 SF n/a _ 6" n/a 1.7 12/21/2010 1Y-11 50029209260000 1830410 9" n/a 9" n/a 2.6 12/21/2010 1Y-12 50029209130000 1830260 4' n/a _ 4' n/a 8 12/21/2010 1Y-13 50029209030000 1830150 15" Na 15" n/a 1.7 12/21/2010 1Y-14 50029209100000 1830230 24" n/a 24" n/a 1.7 12/21/2010 1Y-16 50029209270000 1830420 , 12" n/a 12" n/a 1.7 12/21/2010 Page 1 of 2 • • Maunder, Thomas E (DOA) From: CPF1 Prod Engr In1269 @conocophillips.com] Sent: Saturday, October 02, 2010 8:41 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA); CPF1 Prod Engr Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt; NSK Prod Engr Specialist; Wu, Jianbing; Bommarito, Forest Subject: LPP /SSV Returned to Service on 1E-15 (PTD 210 -013) 10 -02 -10 Tom /Jim, The low pressure pilot (LPP) on injection well 1E-15 (PTD 210 -013) was returned to service on 10/02/2010 after the wellhead injection pressure stabilized above the setting of the low pressure pilot. Current wellhead injection pressure is 1,054 psig; injection rate is 4,410 BWIPD. With the reservoir in this area being depressurized due to a pre - production period combined with reservoir restrictions limiting injection rate to minimize damage to the laterals, the low pressure pilot was defeated on 9/14/10. Please let me know if you have any questions. Daniel Bearden /David Lloyd Lagerlef CPF1 Production Engineers n1269 @conocophillips.com 659 -7493 pager659 -7000 765 From: Lagerlef, David L [mailto:David.L.Lagerlef @conocophillips.com] Sent: Tuesday, September 14, 2010 8:16 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt; NSK Prod Engr Specialist; Wu, Jianbing Subject: LPP /SSV defeated on 1E -15 (PTD 210 -013) - 09 -13 -2010 - request for temporary waiver Tom /Jim, ConocoPhillips requests administrative approval under CO 432D to operate a Kuparuk water injection well with a defeated safety valve system. This request is similar to CO 406B administrative approval granted to the West Sak Pool. The LPP for injection well 1E-15 (PTD 210 -013) has been defeated due to low injection pressure as the well was converted to an injector and brought online yesterday, 9/13. The well had been pre - produced since 5/30/10 following a coil tubing sidetrack so the reservoir pressure has been locally depressed. We expect injection pressure to increase sufficiently in the next few days to allow us to re- engage the SVS system and operate under normal conditions. The well is currently injecting 1650 bwpd at pressures below the minimum LPP set point. The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP /SSV function is retumed to normal Please let me know if you have any questions. 10/25/2010 . • 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, September 29, 2010 - TO: Jim Reg'. 1 /C1.6 (X P.I. Supe visor SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1E -15A FROM: John Crisp KUPARUK RIV UNIT 1E -15A Petroleum Inspector Src: Inspector Reviewed B� P.I. Suprv NON- CONFIDENTIAL Comm Well Name: KUPARUK RIV UNIT 1E -15A API Well Number: 50- 029 - 20769 -01 -00 Inspector Name: John Crisp Insp Num: mitJCr100923071050 Permit Number: 210 -013 -0 Inspection Date: 9/21/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1E -15A' Type Inj. W j TVD i 6065 ' IA 760 2340 • 2200 2190 ' p 2100130 ' TypeTest 1 SPT Test psi 151 OA , 290 320 320 320 Interval P/F P . Tubing 250 250 250 250 Notes: 1.8 bbls pumped for test. Wednesday, September 29, 2010 Page 1 of 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon r Repair w ell r Plug Perforations r Stimulate ❑ Other []i PROD to WAG Alter Casing r Pull Tubing r Perforate New Pool r Waiver r Time Extension r Change Approved Program r Operat. Shutdow n r Perforate r Re -enter Suspended Well r 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 210 -013 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service ❑ 50- 029 - 20769 -01 7. Property Designation: 8. Well Name and Number: ADL 25651 1E 9. Field /Pool(s): Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 9800 feet Plugs (measured) None true vertical 6362 feet Junk (measured) None Effective Depth measured 9794 feet Packer (measured) 7322, 7663 true vertical 6362 feet (true vertucal) 6066, 6330 Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112 112 0 0 SURFACE 2163 10.75 2193 2193 0 0 WINDOW AL2 -01 7 8 7565 6151 0 0 WINDOW AL1 8 8 7641 6316 0 0 PRODUCTION 8380 7 8410 6916 0 0 LINER A (OFFAL 1471 2.625 9797 6392 0 0 Perforation depth: Measured depth: Slots: 8332 - 9793 True Vertical Depth: RECEIVED Tubing (size, grade, MD, and TVD) 3.5, J -55, 7682 MD, 6340 TVD EP 3 0 2010 Packers & SSSV (type, MD, and TVD) PACKER - BAKER FHL PACKER (415 and 6066 TVD 4110011 eii & fl Can .Cl/0143W PACKER - BAKER FB -1 PACKER @ 7663 MD and 6330 TVD SAFETY VLV - CAMCO TRDP -1A @ 1878 MD and 1878 TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil - Bbl Gas - Mcf Water - Bbl Casing Pressure Tubing Pressure Prior to well operation 231 462 1107 850 194 Subsequent to operation 1877 700 73 13. Attachments 14. Well Class after proposed work: Copies of Logs and Surveys run Exploratory r Development r Service C 15. Well Status after work: Oil r Gas r WDSPL r Daily Report of Well Operations x GSTOR r WAG r GASINJ r WIND r SPLUG r 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt•. 310 -311 Contact Bob Christensen /Darrell Humphrey Printed Name • reiie D. - hrist y s c Title Production Engineering Specialist Signature -' '►' -1-------Phone: 659 -7535 Date 9� /® 0 Form 10-404 Revised 7 /2009 RBDMS SEP 3 0101 � 3a. O iir� Su Original Only • 1E-15A DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 08/29/10 TAGGED LINER TOP © 7546' SLM. MEASURED SBHP @ 7400' RKB (2215 PSI) & GRADIENT @ 7273' RKB (2211 PSI) SET SS CATCHER @ 3825' RKB. PULLED GLV @ 1948' RKB & OV @ 3690' RKB. IN PROGRESS. 08/31/10 SET DV @ 1948' RKB. PULL CATCHER @ 3825' SLM (PACKED W/ SCALE) BULLHEAD 125 BBLS DIESEL DN IA. SET DMY @ 3690' RKB. MITIA 3000 PSI (PASS) COMPLETE. 09/13 /10ICommenced Water Injection Service 09 /20 /10IPRE STATE WITNESSED MIT -IA ( PASSED) 09/21/10 'STATE WITNESSED ( JOHN CRISP) MIT -IA ( PASSED ). T A . KUP 1 E -15A ConocoPhillips 8 Well Attributes Max Angle & MD TD Alaska, Inc. Well bore API /UWI Field Name Well Status Intl ( °) MD (RKB) Act Btm (ftKB) nips 500292076901 KUPARUK RIVER UNIT INJ 100.75 9,280.35 9,800.0 "" Comment 1423 (ppm) Date Annotation End Date KB-Grd (ft) Rig Release Date weuCunha. - tE- tsgs�rzoto /.IeosPM - SSSV: Last WO: 40.71 8/4/1982 Schematic - Actual Annotation Depth (MB) End Date Annotation Last Mod ... End Date Last Tag: SLM _ Rev Reason: GLV C/O Imosbor 9/6/2010 Casing Strings Casing Description String 0... String 10 ... Top (ftKB) Set Depth (r.. Set Oepth (TVD) ... String Wt... String ... String Top Thrd CONDUCTOR 16 15.060 32.0 112.0 112.0 65.00 H - 40 Casing Description String 0... String ID ... Top (MB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd S URFACE 103/4 9.794 30.0 2,193.0 2,192.8 45.50 K - 55 BTC C asing Description String 0... String ID ._ Top IRKBI Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd WIN DOW AL2 -01 8 6.000 7,557.8 7,564.7 6,256.8 CONDU O 2 Casing Description String 0... String ID ... Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd WINDOW AL1 8 6.000 7,633.1 7,640.8 6,316.0 8AFETV VLV Casing Description String 0... String ID ... Top (FMB) Set Depth (f... Set Depth (TVD) ... String Wt... Stung ... String Top Thrd 1979 - - PRODUCTION 7 6.151 30.0 8,410.0 6,390.7 26.00 K BTC W Casing Description String 0... String ID ... Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd Liner A (off AL1) 23/8 1.995 8,326.3 9,797.0 6,361.7 4.60 L STL OAS LIFT, 1,949 Liner Details Top Depth SURFACE, (TVD) Top Inc! Nonni... 30.2,193 Top (ft69) (1189) ( °) Item Description Comment ID (in) 8,326.3 6,392.0 89.84 Junction (billet) Liner top billet 1.000 OAS LIFT, 3,690 Tubing Strings Tubing Description String 0... !String ID .Top (1168) Set Depth (f... Set Depth (TVD) ... ng Wt... String ... String Top Thrd TUBING I 31/2 I Str .. 2.992 I 29.8 I 7,682.4 I 6,341.2 I Stri 9.30 I J -55 I IPC "6 5 ' 2 9 Completion Details Top Depth III (TVD) Top Intl Noml... GAS LIFT, 5,266 �. Top (nice) (RK B) 1 ° ) Item Description Description Comment ID (in) 29 29.8 -0.26 HANGER FMC TUBING HANGER 3.500 . 1,877.9 1,877.8 1.70 SAFETY VLV CAMCO TRDP -1A 2.813 GAS LIFT, 7,307.4 6,055.0 38.07 PBR BAKER PBR 3.000 6,291 - 7,321.8 6,066.3 38.11 PACKER BAKER FHL PACKER 3.000 7,464.0 6,177.9 38.43 BLASTJT 2.992 OAS LIFT, 7,272 IC 7,661.9 6,329.8 54.61 LOCATOR BAKER LOCATOR 4.000 . 7,662.5 6,330.2 54.94 PACKER BAKER FB -1 PACKER 4.000 PBR, 7,3D7 . 7,676.1 6,338.7 65.92 NIPPLE CAMCO 'D' NO GO NIPPLE 2.750 7,681.7 6,340.9 65.81 SOS BAKER SHEAR OUT SUB 2.992 PACKER, 7,322 I - Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Depth - (TVD) Top Inel INJECTION. 7,359 Top (pl(9) MKS) ( °) Description Comment Run Date ID (In) 7,369 7,557 6, 250.8 38.42 WHIPSTOCK Baker Rarabore WS with 4-deg kick removed 3/24/2010 1.000 7,6 6,308.8 37.99 WHIPSTOCK Baker monobore WS with 4-deg kick removed 3/16/2010 1.000 INJECTION, 7,425 Perto & Slots Shot Top (TVD) Btm (TVD) Dens Top (88(8) Btm (IRKS) 0008) (RKB) Zone Date (sh... Type Comment IPERFS, 8,332 9,793 6,391.4 6,361.7 3/22/2010 32.0 Slots Alternating solid/slotted pipe - 7179 - 7,s51 ac adjacent rows, s,3 circumferential cetestaggered APERF, 18 deg, 3 non- slottedends 7.550-7,564 Notes: General & Safety End Date Annotation 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 WHIPSTOCK, 4/20/2010 NOTE: SIDETRACKw/LATERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 7,557 WINDOW -- I AL2D1, 7,558- 7,565 INJECTION, • 7,592 A .7,638 7,6167 636 WHIPSTOCK, 7631 WINDOW ALT, • 7,633 -7641 J LOCATOR, 7,662 PACKER, 7,663 C NIPPLE, 7,676 I Mandrel Details Top Depth Top Port (TVD) Inc! OD Valve Latch Size TRO Run SOS. 7,682 Stn Top (66(8) (RKB) (°) Make Model (In) Sery Type Type (in) (psi) Run Date Com... 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT DMY ' BK 0.000 0.0 8/31/2010 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 k 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11!5/1984 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 30$410 - I I Slots, 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,332 - 9193 l I 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner A(off 8,3269,79AL1)7 l i g 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 TO (1E \ 9,800 9,800 • • sum 0[F KtaKKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMJ'IISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Darrell R. Humphrey Production Engineering Specialist ConocoPhillips Alaska, Inc. f 0 13 P.O. Box 100360 �. Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk Oil Pool, 1E-15A Sundry Number: 310 -311 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, with the Commission an application for a person affected by it may file pp reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Chair S f DATED this j day of September, 2010. Encl. • STATE OF ALASKA . V ALASKA OIL AND GAS CONSERVATION COMMISSION q/ZV' Z APPLICATION FOR SUNDRY APPROVALS ° l' 20 AAC 25.280 1. Type of Request Abandon r Rug for Redrill ❑ Perforate New Pool ❑ Repair w ell ❑ Change Approved Rogram r Suspend r Rug Perforations r" Perforate r Rill Tubing r Time Extension ❑ Operational Shutdow n r Re -enter Susp. Well r Stimulate ❑ Alter casing r Other: PROD to WINJ . p 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development n • Exploratory ❑ 210 -013 • 3. Address: Stratigraphic r Service r 6. API Number. P. O. Box 100360, Anchorage, Alaska 99510 50-029-20769-01° 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership or landownership changes: Spacing Exception Required? Yes r No p 1E -15A • 9. Property Designation: 10. Field/Pool(s): ADL 25651 • Kuparuk River Field / Kuparuk Oil Pool '• 11. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9800 • 6362 • 9794' 6362' Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112' 112' SURFACE 2163 10.75 2193' 2193' PRODUCTION 8380 7 8410' 6916' LINER A (OFF AL1) 1471 2.625 9797' 6392' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8332 -9793 6391 -6362 3.5 J -55 7682 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft) PBR - BAKER PBR MD= 7307 TVD= 6055 PACKER - BAKER FHL PACKER MD= 7322 TVD= 6066 PACKER - BAKER FB -1 PACKER MD= 7663 TVD= 6330 SAFETY VLV - CAMCO TRDP -1A MD= 1878 TVD= 1878 12. Attachments: Description Summary of R 17 13. Well Class after proposed work: Detailed Operations Program r BOP Sketch r" Exploratory r Development r Service r e 14. Estimated Date for Commencing Operations: 15. Well Status after proposed work: 9/1/2010 Oil r Gas r WDSPL r Suspended r W INJ �! . G INJ Abandoned r 16. Verbal Approval: Date: r WAG r Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Bob Christensen /Darrell Humphrey Printed Name Darrell R. Humphrey Title: Production Engineering Specialist Signature Lso..L4 Phone: 659 -7535 Date - 15 4 1 a Commission Use Only Sundry Number:3/0` 31 t Conditions of approval: Notify Commission so that a representative may witness ✓, Plug Integrity r BOP Test r Mechanical Integrity Test Location Clearance r ' % Other. C EP 1 7 2010 Subsequent Form Required: / U - ! 01 , ;,�; -,4 II & lias CoaCitrnission Anchorage Zfer i APPROVED BY Approved by: � COMMISSIONER THE COMMISSION Date: 7 (21 I ( D Std' ill ii I R Form 10 -403 Revised 1/2010 A L 1 G 1 I �t La 7o Submit' in iOe1s/O • • 1E-15A DESCRIPTION SUMMARY OF PROPOSAL ConocoPhillips Alaska Inc. requests approval to convert KRU Well 1E -15 from Oil Production service to Water Injection service.Well 1E -15A CTD was completed in the Kuparuk formation on April 23, 2010 as a ps injector with initial production commencing on May 31, 2010. Conversion to Injection service is required due to potential reservoir depletion. Well 1E- 15A injection will provide pressure support to offset producers 1E -12, 1F -06, 1F -14 and 1F -19. J p P pP p The 16" Conductor was cemented with 326sx of AS II. The 10 -3/4" Surface casing ( 2193' and / 2193' tvd) was cemented with 1025sx AS III and 250sx AS II. The 7" Production casing (8410' and / 6916' tvd) was cemented with 605 sx Class "G ". The top of the Kuparuk B1 was found at 7665' and / 6331' tvd. The top of the Kuparuk A6 was found at 7738' and / 6364' tvd. The top of the Kuparuk A5 was found at 7763' and / 6375' tvd. The top of the Kuparuk A4 was found at 9322' and / 6365' tvd. The USIT CBL performed on March 11, 2010 indicates good continuous formation quality bond from 7460' and (6175' tvd) to 7580' and (6269' tvd). The injection tubing/casing annulus is isolated via Baker FHL Packer 6.151" OD x 2.94" ID located @ 7322 and / 6066' tvd. An MIT -IA was last performed on 8/31/10; MITIA 3000 psi, 15 minutes, Passed. MITIA 3000 PSI (PASS) COMPLETE. Initial T/I/0= 1600/0/330: Start T/I/0= 1600/3000/360: 15min. reading T/I/0= 1600/2910/360: 30min. reading T/I/0= 1600/2890/360 • KUP 1 1E -15A ConocoPhillips Well Attributes Max Angle & MD TD Alaska, Inc. Wellbore API /UWI Field Name Well Status Inc! (°) MD (ft86) Act Btln (1588) ( nptymps 500292076901 KUPARUK RIVER UNIT INJ 100.75 9,280.35 9,800.0 Comment H28 (ppm) Date Annotation End Date KB (ft) Rig Release Date "' SSSV: TRDP Last WO: 40.71 8/4/1982 Weil Cone): -1E- 15091620104:1805 PM 1. Schsmenc - Actual Annotation Depth(HKB) End Date Annotation Last Mod... End Date Last Tag: SLM Rev Reason: GLV C/O Imosbor 9/6/2010 Casing Strings l.kC Casing Description String 0... String ID ... Top (MB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd CONDUCTOR 16 15.060 32.0 112.0 112.0 65.00 H-40 Casing Description String 0... String 10 ... Top (f KB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd SURFACE 103/4 9.794 30.0 2,193.0 2,192.8 45.50 K BTC acing Description String 0... String ID ... Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd WINDOW AL2 - 01 8 6.000 7,557.8 7,564.7 6,256.8 • CONDUCTOR, Casing Description String 0... String ID ... Top (RKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd 32 -112 WINDOW AL1 8 6.000 7,633.1 7,640.8 6,316.0 SAFETY VLV, Casing Description String 0... String ID ... Top (MB) Set Depth (f... Set Depth (TVD) ... String WE.. String ... String Top Thrd 1,878 PRODUCTION 7 6.151 30.0 8,410.0 6,390.7 26.00 K - 55 BTC GAS LIFT, 1,949 Casing Liner DescriptlDetails on String 0... String ID ... Top (69(6) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd Liner A (off AL1) 23/8 1.995 8,326.3 9,797.0 6,361.7 4.60 L -80 STL Top Depth SURFACE, (TVD) Top Intl Noml... 30 -2193 Top (ftKB) OMB) ( Item Description Comment ID (in) 8,326.3 6,392.0 89.84 Junction (billet) Liner top billet 1.000 3,690 Tu Strings Tubi Description String 0... String ID ... Top (888) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd TUBING 3 1/2 2.992 29.8 7,682.4 6,341.2 9.30 J -55 IPC GAS uFr• Completion Details s.z19 T Oe pth (TVD) Top Inci Noml... 2.813 GAS LIFT, Top (HKB) (RK ( °) Item Des Comment ID (In) 5 29.8 29.8 -0.26 HANGER FMC T UBING HANGER 3.500 1 1,8 1.70 SAFETY VLV CAMCOTRDP -1A GAS LIFT, 7,307.4 6,055.0 38.07 PBR BAKER PBR 3.000 6,zst 7,321.8 6,066.3 38.11 PACKER BAKER FHL PAC 3.000 GAS LIFT, 7,464.0 6,177.9 38.43 BLASTJT 2 GAS LIFT, 7,272 7,661.9 6,329.8 54.61 LOCATOR BAKER LOCATOR 4.000 7,662.5 6,330.2 54.94 PACKER BAKER FB -1 PACKER 4.000 J� ° - 7,676.1 6,338.7 65.92 NIPPLE CAMCO 'D' NO GO NIPPLE 2.750 PBR, 7,307 7,681.7 6,340.9 65.81 SOS BAKER SHEAR OUT SUB 2.992 PACKER, 7,322 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) 4 Top Depth (TVD) Top Intl INJECTION, Top (FMB) (8K8) ( °) Description Comment Run Date ID (In) 7,359 7,557 6,250.8 38.42 WHIPSTOCK Baker monobore WS with 4 -deg kick removed 3/24/2010 1.000 7,631 6,308.8 37.99 WHIPSTOCK Baker monobore WS with 4 -deg kick removed 3/16/2010 1.000 INJECTION, 7 Perforations & Slots Shot Top (TVD) Btm (TVD) Oena Top (ftl(B) Btm (HKB) (RKB) (MB) Zone Date leh... Type Co mment IPERFS, 8,332 9,793 6 6 3/22/2010 32.0 Slots Alternating so id / slotted pipe - 7478 - 7554 0.125" 2.5" @ 4 circumferential adjacent rows, 3" centers staggered APERF, 18 deg, 3' non - slotted ends 7,550-7,554 N otes: General & Safety End Date Annotator 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 WHIPSTOCK 4/20/2010 NOTE: SIDETRACKw /LATERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 7.557N i , \ WINDOW A LL- 1, -7565 7,5 A INJECTION, 7,592 II APERF, 7,618 -7,638 WHIPSTOCK, ._. I 7,631 WINDOW ALt, • 7,833.7,641 LOCATOR. 7,662 PACKER, 7,663 p. NIPPLE, 7,676 i m . Mandrel Details III Top Depth Top Port (TVD) Ind OD Valve Latch Slae TRO Run S05, 7552 q Stn Top (MB) (RIO) (°) Make Model (In) Sere Type Type ((n) (psi) Run Data Com... 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 8/31/2010 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 30 8,410\ 1 1 Slots, 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 03320,793 1 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner A (off AL1), l ` i 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 6,326 - 9,797 \ r TO (1E-15A), 9,600 9,600 • • Robert Christensen/Darrell Humphrey Production Engineering Specialists. Greater Kuparuk Unit , NSK -69 PO Box 196105 ConocoPhillips Anchorage, AK 99519 -6105 Phone: (907) 659-7535 Fax: 659 -7314 June 22, 2010 Dan Seamount AOGCC Commissioner State of Alaska, Oil & Gas Conservation Commission 33 W. 7 Ave. Ste. 100 Anchorage, AK 99501 Dear Mr. Seamount, Enclosed you will find 10 -404 reports of Sundry Well Operations recording the continued production of longer than 30 days for Kuparuk Well 1E -15A (PTD 210 -013), 1E -15AL1 (PTD 210 -014), 1E -15AL2 (PTD 210 -015), 1E- 15AL2 -01 (PTD 210 -016) . If you have any questions regarding this matter, please contact myself or Robert D. Christensen at 659 -7535. Sincerely, Darrell R. Humphrey Attachments Sundry application Well schematic 2 lv -o(3 III STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abandon r Repair well r Plug Fbrforations r ; Stimulate r Other n WINJ to PROD Alter Casing r Pull Tubing r Perforate New Pool r Waiver r Time Extension r Change Approved Program r Operat. Shutdow n r Perforate r Re -enter Suspended Well 2. Operator Name: 4. Current Well Status: '5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 210 -013 3. Address: N6. API Number: P. 0. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service 50 - 20769 - 7. Property Designat%on: 8. Well Name and Number: ADL 25651 ‘1E-15A 9. Field /Pool(s): Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 9800 feet Plugs (measured) None true vertical 6362 feet Junk (measured) None Effective Depth measured 9794 feet Packer (measured) 7307, 7322, 7663 true vertical 6362 feet (true vertucal) 6055, 6066, 6330 Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 16 112 112 0 0 SURFACE 2163 10.75 2193 2193 0 0 PRODUCTION 8380 7 8410 6916 0 0 LINER A (OFFAL 1471 2.625 9797 6392 0 0 0 0 0 1 0 0 0 Perforation depth: Measured depth: 8332 - 9793 True Vertical Depth: 6391 -6362 RECEIVED Tubing (size, grade, MD, and TVD) 3.5, J -55, 7682 MD, 6340 TVD .JUN 242010 Packers & SSSV (type, MD, and TVD) PBR - BAKER PBR @ 7307 MD and 6055 TVD Alaska Oil & Gas Cars. Commission PACKER - BAKER FHL PACKER @ 7322 MD and 6066 TVD Anchorage PACKER - BAKER FB -1 PACKER @ 7663 MD and 6330 TVD SAFETY VLV - CAMCO TRDP -1A @ 1878 MD and 1878 TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation 479 1100 2020 Subsequent to operation 229 151 1805 914 145 13. Attachments 'Il, Well Class after proposed work: Copies of Logs and Surveys run Exploratory r Development pi Service r \4. Well Status after work: Oil n Gas r WDSPL r Daily Report of Well Operations X GSTOR r WAG r GASINJ r WINJ r SPLUG r 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt N/A Contact Bob Christensen /Darrell Humphrey Printed Name Darrell R. Humphrey Title Production Engineering Specialist Signature Phone: 659 -7535 Date moo. (a • 22- t Rt3DMS JUN 24 7 7 �� Form 10-404 Revised 7 /2009 , 7 Submit Original Only • • , -. 1E-15A DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 05/31/10 Well currently being pre- produced to improve injection quality post CTD sidetrack operations. Put on production at 0732 hours. Well being gas lifted from 1E-31 @ 926 psi, 1000 MSCFD I I I I I I I I I I � I I I I I I I I I I a KUP • 1E -15A ConocoPhiliips °- Well Attributes Max Angle & MD TD Ai,Jv".' : : ,;' Wellllore APIIUWI Field Name Well Status Inc! ( MD (ftKB) Act Btm (5548) COnocoPMkpz 500292076901 KUPARUK RIVER UNIT INJ 100.75 9,280.35 9,800.0 Comment H2S (ppm) Date An notation End Date KB-Ord (R) Rig Release Date Well conrg. - 10-15A, 4/250010 7 57 os AM - SSSV: TRDP Last WO: 40.71 8/4/1982 Schematic - Actual Annotation Depth (ftKB) End Oate Annotation Last Mod... End Date Last Tag: SLM Rev Reason: GLV C/O Imosbor 4/25/2010 ar J Casing Strings Caaing Description String 0... String ID ... Top (1168) Set Depth (5.." Set Depth (TVD) ... String Wt.. String ... String Top Thrd CONDUCTOR 16 15. 32.0 112.0 112.0 65.00 H-40 Casing Descriptlon String 0... String ID ... Top (55(8) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd � SURFACE 103/4 9.794 30.0 2,193.0 2,192.8 45.50 K - 55 BTC acing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd WINDOW AL2 - 01 8 6.000 7,557.8 7,564.7 6,256.8 CONDUCTOR, 1E1 i Casn Descri Son String 0... String ID ... Top (5169) Set Depth (5... Set Depth TVD) ... String Wt... String ... String Top Thrd 32 -112 9 P g P 1 WINDOW AL1 8 6.000 7,633.1 7,640.8 6,316.0 SAFETY VLV, Casing Description String 0... String ID ... Top (55(8) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd 1,878 - ° PRODUCTION 7 6.151 30.0 8,410.0 6,390.7 26.00 K - 55 BTC Casing Descriptlon String 0... String ID ... Top (RKB) Set Depth (5... Set Depth (TVD) ... String Wt.. String ... String Top Thrd Liner A (off ALI) 23/8 1.995 8,326.3 9,797.0 6,361.7 4.60 L - 80 STL GAS LIFT, 1,90.9 Liner Details Top Depth SURFACE, (TVD) Top Inc! Nomi... 30-2,193 Top (ftKB) (RKB) (°) Item Description Comment ID (In) 8,326.3 6,392.0 89.84 Junction (billet) Liner top billet 1.000 GAS LIFT, 3,590 Tubing Strings Tubing Description String 0... String ID ... Top (5169) Set Depth (5... Set Depth (TVD) ... String Wt... String ... String Top Thrd TUBING I 31/2 2.992 I 29.8 I 7,682.4 I 6,341.2 I 9.30 I J -55 I IPC GAS 5 9 Completion Details Top Depth (TVD) Top Incl N omi... GAS LIFT, T op (RKB) (RK B) (°) Item Descrlpton Comment ID (In) 6,256 29.8 29.8 -0 .26 HANGER FMC TUBING HANGER 3 .500 1,877.9 1,8 77.8 1.70 SAFETY VLV CAMCOTRDP -1A 2 .813 GAS LIFT, 7,307.4 6,055.0 38.07 PBR BAKER PBR 3.000 6,291 7,321.8 6,066.3 38.11 PACKER BAKER FHL PACKER 3.000 7,464.0 6,177.9 38.43 BLASTJT 2.992 °i z z 7,661.9 6,329.8 54.61 LOCATOR BAKER LOCATOR 4.000 7,662.5 6,330.2 54.94 PACKER BAKER FB -1 PACKER 4.000 794 7307 7,676.1 6,338.7 65.92 NIPPLE CAMCO 'D' NO GO NIPPLE 2.750 7,681.7 6,340.9 65.81 SOS BAKER SHEAR OUT SUB 2.992 PACKER, 7,322 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Depth (TVD) Top Inc! INJECTION, p Top (RKB) ( 1160 ) (1 Description Comment Run Date ID (In) 7,359 t 7,557 6,250.8 38.42 WHIPSTOCK Baker monobore WS with 4 -deg kick removed 3/24/2010 1.000 7,631 6,308.8 37.99 WHIPSTOCK Baker monobore WS with 4-deg kick removed 3/16/2010 1.000 INJECTION, 7,425 t Perforations & Slots Shot Top (TVO) Btm (TVD) Dena Top (RKB) 8tm (RKB) (RKB) (RKB) Zone Date (sh••• Type Comment 176470, 8,332 9,793 6,391.4 6,361.7 3/22/2010 32.0 Slots Alternating solid/slotted pipe - 7,476 - 7,554 0.125 "x2.5" @ 4 circumferential adjacent rows, 3" centers staggered APERF, 18 deg, 3' non - slotted ends 7,550-7,554 / 1 0 Notes: General & Safety End Data Annotation 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 WHIPSTOCK, _ 4/20/2010 NOTE: SIDETRACK WMTERALS 1E -15A, 15AL1, 15AL2, 15AL2 -01 7,557 WINDOW AL2 -01, • k 7,558 -7,565 INJECTION, nt 7.592 APE 1 I 1 7,618-T638 WHIPSTOCK. _ - 7,631 -. WINDOW ALI, 7,633 -7,641 - LOCATOR, 7,882 PACKER, 7,583 NIPPLE, 7.676 Mandrel Details Top Depth Top Port (TVD) Inci OD Valve Latch Site TRO Run SOS, 7,682 Stn Top (MB) (RKB) 1 Make Model (in) Sere Type Type (In) (Pei) Run Date Com... -- 1 1,948.5 1,948.4 1.46 CAMCO KBUG 1 GAS LIFT GLV BK 0.188 1,346.0 4/24/2010 2 3,690.5 3,504.9 46.84 CAMCO KBUG 1 GAS LIFT OV BK 0.250 0.0 4/24/2010 ki 3 5,218.8 4,525.2 45.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6!5/1990 4 6,255.6 5,252.2 43.86 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 5,277.8 43.53 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, 6 7,271.9 6,027.0 37.97 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 30 I sloe, 7 7,359.0 6,095.5 38.22 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 6,3325,793 8 7,425.4 6,147.7 38.44 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner A (elf 5.329 - 9,79ALI)7 \ i I 9 7,592.1 6,278.3 38.42 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 TD (1 E -15A), 9,800 Page 1 of 1 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, June 22, 2010 1:43 PM To: 'NSK Prod Engr Specialist' Subject: RE: Pre - produced Injection Wells DA ° -0 % -S Darrell, Only a 404 is needed for all segments until such time as you switch back and then a 403 for all segments. Tom From: NSK Prod Engr Specialist [mailto:n1139 @conocophillips.com] Sent: Tuesday, June 22, 2010 11:43 AM To: Maunder, Thomas E (DOA) Subject: RE: Pre - produced Injection Wells Tom- in the case of 1 E -15A and it's laterals being produced longer than 30 days just want to clarify that you said only a 404 needs to be filed and then before we switch it back to WINJ file a 403. Correct? Thanks, Darrell From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, June 22, 2010 8:52 AM To: NSK Prod Engr Specialist Cc: McMains, Stephen E (DOA); Brooks, Phoebe L (DOA); Allsup- Drake, Sharon K; NSK Problem Well Supv; NSK Well Integrity Proj Subject: Pre - produced Injection Wells Darrell, You called regarding pre - produced injectors. What wells are you referring to? This topic can get confusing. I presume these are new wells? The protocol we are following is: 1. If the well will ultimately be an injector, then it should be permitted as such regardless if it will be pre - produced or not. This allows the necessary construction requirements (MIT and area of review, etc) to be included /satisfied at the time of drilling. 2. If the well will be pre - produced for more than 30 days, then the well should be "completed" as development, 1 -oil when the 407 is filed. Completing this way makes sure the production data gets to the right database. Reporting production volumes with the well classified as service makes for problems in the database and requires making hand corrections. 3. When it is desired to finally put the well on injection, then a 403 should be filed converting the well from development to service. Do the above points answer your question? CaII or message with any questions. I have copied this to others who might have an interest in our discussion. Tom Maunder, PE AOGCC 7/1/2010 'ARV Q ID -0(3 R, , E , C ,,,,,,,, F D Company ,.,,,,,, r\ ,, BAKER ConocoPhillips, Alaska, Inc. HUGHES Well Name 1E-15A MITEQ 6/9/2010 Date AkIl'4;fn 031 A, / ConocoPhillips Alaska Greater Kuparuk Area*** Data Distr , , ;; r ,;;;,,,,,,..}. , ';;; ; ; ';'. , . , .. , o; , ,F.; ,, A, ,,, , :) RECIPIENTS 'i '1 ,.1;,.."11,-) ' OH FINAL OH FINAL ' . ''' ,' ,„„ t:,,, , '• ,1 I. ,- .,. t , • ...0i''''' ! ' 11 ` t'''' '' '''' ';',,, No other distribution is allowed without , - Image riles and/or Di Data ',, '11 .)' '''' `, 'i ,, ;; ; ,;) , ,,,,,,,,; , ; 1, ;.;:. ,ii,;:;;1,0 ,1,, ,+, t■ ,' .,, ,..,,,„,,k•.(1•11'','14,.4•'.-4Z written approval from ConocoPhillips . '-',));'7,f,,i."'Irlit);rilirc',),.-,:r,';'''l • contact: Lisa Wright, 907 2634823 i '' hardcopy prints 1 t I, -,,,,,,,,••••:,''• ".,)'?,;44''''',4.1.,kil ConocoPhillips Alaska, Inc ' 40 Sharon Allsup-Drake Drilling Tech, ATO-1530 ConocoPhillips . 1 Hardcopy Print lips Alaska , Inc . r• t''''' ',„ ''''),""'". , v'''. , ';'r , ,,'":4.! ) ,P! , ..) ) ;;.„ ) •,t1' . , ; ,,•,,,, .,,,,,,,,,,s,;-,;t4,'.',1'..,,,,1 NSK Wells Aide, NSK 69 ATTN: MAIL ROOM t 700 G Street, Anchorage, AK 99501 ' ,' r '',") -'''', : ConocoPhillips Alaska, Inc. :` ' ' ' ' '' ' ' ' ' . „,1',,,.ii,i41,1iil,,,.?J. 1 Graphic Image ElleDcLitisrsok*nlic 1 , 1 , , ,, , ' I i ' , Ricky Elgarico File**/*** ' ■ e 1-g02 ' ■ , i , 4 "''', '',. ' CGM/TWF i 7-00-G-Strcet, -- Arve..14()rage-AK-1- Q804 ! , ”" ! , ftp://b2bftp.conocophillips.com 1 , 1 , 1 I : ' ■ , . 1, , '' , Hardcopy Print, , , , . ,, , , ; AOGCC 1 I ' ' ' , , , , Ltirsonio T.;)iiiii„,,4i • Christine Mahnken 1 Graphic image file 1 Disk / 333 West 7th Ave, Suite 100 in lieu of se pi a ** Electronic I , , •1, i• • ,i,'' , , 't') I )i),l • Anchorage, Alaska 99501 CGM / TIFF i . t ,, , , ,, , , „ , I, '-, ;,t.,eie! illi BP 1 Hardcopy Print, I ' ,* 1 ' `, ,, , , ,,, , , , " 1 Graphic image file 1 Disk / .', . i , , Mir Petrotechnical Data Center, MB33 „ , .., , , .... David Douglas in lieu of sepia** Electronic '' '' , ,, , ! ' ' i )'j P.O. Box 196612 CGM/TIFF LIS i ,' , , ' = ' ' , , , f tr ',°•<' t ,,,,. Anchorage, Alaska 99519-6612 1 i , 11GFriaaprdhcicoiPmY CHEVRON/KRU REP Glenn Fredrick P.O.Box 196247 in lieu of seapPgiraein*f*ti'le ElleDcLitisrS Brandon Tucker, NRT Electronic Anchorage, Alaska 99519 i''' ''' 1 ' ' , 1 I : ' 1 , State of Alaska; DNR, Div. of Oil and Gas ", CGM / TIFF i , . . 550 W. 7th Ave, Suite 800 . , '' • .°, , 1 ., ' ' Anchorage, Alaska 99501-3510 " . 1 Disk*/, ' _ , Electronic , , , , , , LIS r ■ ` ! DS Engineer / Rig Foreman ! , , TOTAL Hardcopy Prints 4 Page 1 of 4 1 • RE CE%V' STATE OF ALASKA • AY 19 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION • M AY COMPLETION OR RECOMPLETION REPORT la. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 1b. Well Class: A1del* 20AAC 25.105 20AAC 25.110 Development 0 Exploratory El GINJ ❑ WINJ 0 WAG ❑ WDSPL ❑ No. of Completions: Service El Stratigraphic Test ❑ 2. Operator Name: 12. Permit to Drill Number: 5. Date Comp., Susp., ConocoPhillips Alaska, Inc. or Aband.: April 20, 2010 210 - 013 / 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 100360, Anchorage, AK 99510 - 0360 March 18, 2010 50 029 - 20769 - 01 ' 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 444' FSL, 814' FEL, Sec. 16, T11N, R10E, UM March 22, 2010 1E - 15A Top of Productive Horizon: 8. KB (ft above MSL): 105.7' RKB 15. Field /Pool(s): 1385' FSL, 1131' FWL, Sec. 16, T11N, R10E, UM GL (ft above MSL): 41' AMSL Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): 2114' FNL, 488' FWL, Sec. 16, T11N, R10E, UM 9794' MD / 6362' TVD Kuparuk River Oil Pool 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x 549710 y 5960030 Zone 4 9800' MD / 6362' TVD ADL 25651 TPI: x - 546367 y - 5960949 Zone 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x 545709 y 5962726 Zone 4 SSSV @ 1878' MD / 1878' TVD 469 18. Directional Survey: Yes 0 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) 1450' 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 7631' MD / 6310' TVD 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE CEMENTING RECORD PULLED 16" 62.5# H -40 Surf. 112' Surf. 112' 24" 326 sx AS II 10.75" 45.5# K -55 Surf. 2193' Surf. 2193' 13.5" 1025 sx AS III, 250 sx AS II 7" 26.0# K -55 Surf. 8410' Surf. 6916' 8.75" 605 sx Class G 2.375" 4.7# L -80 8323' 9794' 6392' 6362' 3" slotted liner _ I 24. Open to production or injection? Yes ig No ❑ If Yes, list each 25. TUBING RECORD Interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKERS (MD/TVD) 3.5" 7682' 3 MD / 6066' TVD alternating solid / slotted liner from 8332' -9793' MD / 6392' -6362' TVD 7663' MD / 6331' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. GOw "LETjrN I DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED _ s /0 1 , l1 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) flowback in progress Date of Test Hours Tested Production for OIL -BBL GAS -MCF WATER -BBL CHOKE SIZE GAS - OIL RATIO Test Period - -> Flow Tubing Casing Pressure Calculated OIL -BBL GAS -MCF WATER -BBL OIL GRAVITY - API (corr) Press. psi 24 -Hour Rate -> 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No Q Sidewall Cores Acquired? Yes ❑ No Q If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (Submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. NONE Form 10 -407 Revised 12/2009 • SDPd?S MAY 19 200 �NUED ON REVERSE t ' i 1 Submit original only , IXO 6' A 28. GEOLOGIC MARKERS (List all formations and markers • • encountered): 29. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 0 No If yes, list intervals and formations tested, Permafrost - Top ground surface ground surface briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Bottom 3398' 3291' needed, and submit detailed test information per 20 AAC 25.071. Top B1 7665' 6331' Top A6 7738' 6364' Top A5 7763' 6375' Top A4 9322' 6365' N/A Formation at total depth: Kuparuk A4 / A5 30. LIST OF ATTACHMENTS Summary of Daily Operations, final directional survey, schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: ary Eller @ 263 - 4172 Printed Nam V. a Title: Alaska Wells Manager f p !!\\ Signature Phone 265 - 6306 Date / � B �1 V Sharon Allsu p -Drake 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 la: 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 12/2009 r "— • KU P • 1 E-1 5A IV ! �/1� ' * Well Attributes Max Angle & MD TD AAO�. Inc, Wellbore APBUWI Field Name Well Status Intl ( °) MD (ftKB) Act Btm (ftKB) 1 500292076901 KUPARUK RIVER UNIT INJ I 9,800.0 Comment H25 (ppm) Date Annotation End Date KB -Grd (ft) Rig Release Date SSSV: TRDP Last WO: 4071 8/4/1982 SdnBn7alic• – Annotation '.Depth (058) End Date lAnnotation Last Mod .. End Da Last Tag: SLM' Rev Reason:SIDETRACK w /LATERALS I Imosbor 1 4/20/2010 Casing Strings I Casing Description String 0... String ID .. Top (ftKB) Set Depth ft.. Set Depth (TVD) ... String Wt... String .. String Top Thrd CONDUCTOR 16 15 060 32.0 112 0 65.00 H Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt... String ... String Top Thrd SURFACE 10314 9.794 30.0 2,193.0 45.50 K - 55 BTC Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt... String ... String Top Thrd WINDOW AL2 - 01 8 6.000 7,557 8 7,564.7 CONDUCTOR, 32112 Casing Description String 0... String ID . Top (5156) Sat Depth (5... Set Depth (ND) ... String Wt... String ... String Top Thrd WINDOW AL1 8 6.000 7,633.1 7,640.8 SAFETY VLV, (Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd 1,878 , PRODUCTION 7 6.151 30.0 8,410.0 26.00 K - 55 BTC Casing Description String 0... String ID Top (ftKB) Set Depth (f.. Set Depth (ND) ... String Wt... String String Top Thrd LnerA (of( AL1) 23/8 1995 8,326.3 9,7970 460 L80 STL GAS LIFT, Liner Details 1,949 SURFACE, 30-2,193 w To p }2fi ( KBPth Top) c Juno D top billet Comment ND(m)1 GAS LFT,_ r .. 3,I690 Tubing Strings Tubing Description String 0 String ID ... Top (ftKB) Set Depth (f... S Depth (ND) ... String Wt Strg . String Top Thrd T USING 3 U 2. 992 298 I /,682.4 I et i 9 30 � m J-55 IPC -- GAS LIFT, Details 11- . -: To p Depth 1 it (TVD) Top Intl N omi... GAS LIFT, Top (MKS) ("KB) P) Item Description Comment ID (In) It 6.256 29.8 HANGER FMC TUBING HANGER 3.500 1,877.9 SAFETY VLV CAMCO TRDP - 1A 2.813 GAS UFr, — 7,307.4 PBR BAKER PBR 3.000 s,z91 ■ L L ■ 7,321.8 PACKER BAKER FHL PACKER 3.000 7,464.0 BLAST JT 2.992 GAS LIFT, 7,272 7,661.9 LOCATOR BAKER LOCATOR 4.000 t 7,662.5 PACKER BAKER FB -1 PACKER 4.000 PBR, 7,307 7,676.1 NIPPLE CAMCO 13' NO GO NIPPLE 2.750 ;. 7.681.7 SOS BAKER SHEAR OUT SUB - � . - -- 2 -992 PACKER, 7,322 .. Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Depth (TVD) Top I cl INJECTION, Top (ftKB) (ftKB) _(I Description Comment Run Dab ID (in) 7,359 11 It 7,557 WHIPSTOCK Baker monobore WS with 4-deg kick removed 3/24/2010 1.000 7,631 WHIPSTOCK Baker monobore WS with 4-deg kick removed 3/16/2010 1.000 INJECTOR, 7,426 t1 F & Slots Shot Top (TVD) Btm (TVD) Dens Top MKS) Bbn(RKB) (ftKB) (ftKB) Zone Date (.h°• •e Comment IPERFS, - 8,332 9,793 3/22/2010 32.0 Slots Alternating solid /slotted pipe 7,478 654 0.125"x2.5" @ 4 circumferential � adjacent rows, 3" centers staggered APERF, � 18 deg, 3' non - slotted ends 7.556 -7.554 X 11 : — Notes: General & Safety End Date 4/20/2010 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 WHIPSTOCK, - 4/20/2010 NOTE: SIDETRACK w/LATERALS 1E -15A, 15AL1, 15A1.2, 15AL2-01 (2 pg schematic) 7,557 WINDOW AL2 -01, 7,558 -7,565 F. 1 INJECTION,_ 7,592 APERF, 7,618 -7838 i WHIPSTOCK, 7,631 WINDOW ALI,_ 7,633 -7,641 IP LOCATOR, 7,662 4nr PACKER, 7,863 -- I. NIPPLE, 7,676- - - - - -- Mandrel Details It Top Depth Top Pod (TVD) Inc! OD Volvo Latch She TRO Run SOS,7,682— Stn Top (RKB) (ftKB) (1 Make Model (in) Sew Type Type (in) (Pal) Run Date Com... 1 1,948.5 CAMCO KBUG 1 GAS LIFT DMY bk 0.000 0.0 6/5/1990 2 3,690.5 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 3 5,218.8 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 \ 4 6,255.6 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 11/5/1984 5 6,291.2 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/3/1990 PRODUCTION, I 6 7,271.9 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 6/5/1990 30 - 8,410 - ,..__ — _ - 1 1 7, X 79 3 - -- 7 7,359.0 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,332 - 9,79 I 1 8 7,425.4 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 Liner A (oft — - -- 1eL � 11 9 7,592.1 CAMCO KBUG 1 INJ DMY BK 0.000 0.0 7/20/1993 8,326.9,797 -- - - - -- -- TD (1E-5A), – _ —_– — 1E-15 CTD Sidetrack - Final Last Updated: 21- Apr -10 3 -1/2" Camco TRDP -1A nipple @ 1878' MD 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface k- k. 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H -40 shoe @ 112' MD M- Baker 3 -1/2" PBR @ 7307' MD ' Baker FHL packer @ 7321' MD • -„ 3 -1/2" Camco KBUG injection mandrels @ 7354', 7425', 7592' 10 -3/4" 45.5# K -55 shoe @ 2193 MD 111 Carbide blast rings 7446' - 7552' (7452' -7538' CBL) Baker FB -1 packer @ 7663' MD w/ Baker SBE 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) 3 -1/2" tubing tail @ 7682' MD C -sand perfs 7478' - 7554' MD ""v'" —. ... AL2 -01, TD = 9765' AL2, TD = 10,085' Sqz perfs (2/14/10) - � � � � °- 7550' - 7554' CBL "'" 2 -3/8" liner 7542' -9765' 2 -3/8" liner 7690'- 10,058' 7618' - 7638' CBL w Deployment sleeve at 7542' Billet at 7690' AL2 -PB3, TD = 9710' y - -__ Unintended sidetrack at pis k.I /i :_:" 7855' KOP #2 at 7557' MD •_____ __ ___ __ __ ____ KOP #1 at 7631' MD k AL2 -PB2, TD = 10,135' / 2 -3/8" liner 8200'- 10,135' Baker flow -by monobore ''' 4 „..--- --. Billet at 8200' whipstocks % /ice AL2 PB1, TD _ 9835' - 2-3/8 I nver 8864'-9835' Billet at 8855' _ l A -sand perfs 7716' - 1=-1 / V / AL1 Lateral, TD = 8812' 7796' MD (plugged) ` — / 7 2 -3/8" liner 7623' - 8812' — ----------- ) Liner top at 7623' A Sidetrack, TD = 9800' CIBP at 7656' ELM 2 -3/8" liner 8323' - 9794' 7" 26# K -55 shoe @ Billet at 8323' 8410' MD (7674' MD, 2/13/10) • ConocoPhiIIips Time Log & Summary Wel'v,ew Web Reportmg Report Well Name: 1E-15 Rig Name: NABORS CDR2 -AC Job Type: DRILLING SIDETRACK Rig Accept: 3/15/2010 3:00:00 AM Rig Release: 4/20/2010 6:00:00 PM Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 03/14/2010 24 hr summary Move Rig to 1E-15 11:00 14:00 3.00 MIRU MOVE MOB P Preparing rig for move. 14:00 00:00 10.00 MIRU MOVE MOB P PJSM, Move rig from 1E12 to 1E -15. Replace skates on Injector head 03/15/2010 Rig accept @ 03:00 HRS. Pump Slack into CT string, cut 200 ft of Coil, 18 ft to find cable. BOPE test - waived by Bob Noble. Pulled BPV. 00:00 03:00 3.00 MIRU MOVE EQRP P Complete installing injector chains, install pack -off assembly. Roll injector. Take on fluids in pits. Rig up BOP's & replace HCR valve on BOP stack B -8. Stab CT into injector head. 03:00 05:00 2.00 SURPRI WELLPF SLPC P * ** Rig Accept * ** - Move injector over well and set up lines and valves to fill lines & reverse circulating with SW. Install electrical boot on E -line. Check BHI counter on injector head. 05:00 06:00 1.00 SURPRI WELLPF SLPC P Pump slack in CT & remove CT off well. 06:00 07:00 1.00 MIRU WHDBO BOPE P Crew change, PJSM, go over valve alignment on rig, Fluid pack 07:00 10:00 3.00 SURPRI WELLPF SLPC P Scaffolding crew arrive to build scaffolding around wellhead, Thaw BOP test pump lines. Rig Crew start rigging up to cut CT (155'). Need to cut 45' more. Found a -line 18' cut 10:00 10:30 0.50 MIRU WHDBO BOPE P MU BOP testlines back up, Fluid pack lines and assure all lines thawed 10:30 17:30 7.00 MIRU WHDBO BOPE P BOP Testing ** Test gas alarms. 5000 psi High - 250 low. Bravo 8 valve leaked. 17:30 20:00 2.50 SURPRI WELLPF SLPC P Change out Bravo 8 valve, finish cutting coil 200ft. in total and re -head CT 20:00 20:30 0.50 MIRU WHDBO BOPE T Re -test new Bravo 8 HCR. Hyd. leak,. Mechanic fixing. Hold TBT to pull BPV. Page 1 of 35 1 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 20:30 23:00 2.50 MIRU WHDBO MPSP P Open SSV - test BPV lubricator to 1000 psi and attempt to pull BPV. First try did not get it, Master valve leaking. Call out crease crew. Grease the tree, Rig up lubricator and pull BPV. Pulled with 700 psi below BPV. 23:00 00:00 1.00 MIRU WHDBO MPSP P Rig down Lubricator and release FMC. 03/16/2010 Run Dummy Whipstock, Set Whipstock, TOWS @ 7631, 00:00 00:30 0.50 MIRU WHDBO CIRC T Set up lines and safety meeting for BOP testing of B -8. 00:30 02:00 1.50 MIRU WHDBO BOPE T Test Bravo 8 on stack. leaked. Troubleshoot hydraulic actuator. Re -test B -8. Held 250 & 5000 psi. 02:00 02:30 0.50 MIRU WHDBO BOPE P Set up to test inner reel valve and return line to pits. Blow down lines. 02:30 03:00 0.50 MIRU WHDBO BOPE P reverse Circ. through stack and reel. Stop pumping use BOP test pump and test inner reel valve & pack -off. * *BOP test complete. ** 03:00 05:00 2.00 PROD1 RPEQP1 RURD P Break off injector and rig up PDL's & test to 2500 psi. 05:00 06:00 1.00 PROD1 RPEQP1 PULD P P/U Dummy BHA and clean up rig floor. 06:00 06:30 0.50 PROD1 RPEQPI SFTY P Crew change PJSM, 06:30 07:00 0.50 MIRU WHDBO PRTS P Pressure test backside line out to tiger tank. 07:00 08:45 1.75 PROD1 RPEQP1 PULD P Deploy BHA 08:45 10:27 1.70 0 7,350 PROD1 RPEQP1TRIP P RIH 10:27 10:45 0.30 7,350 7,600 PROD1 RPEQP1DLOG P Tie into formation marker at 7375', -8' correction. 10:45 10:57 0.20 7,600 7,654 PROD1 RPEQP1TRIP P Continiue RIH. Weight check, 25 PUW, 10 RIW. Tag CIBP at 7654' dry, PUH, pump on line at 1.4 BPM, retag at 7654'. 10:57 13:09 2.20 7,654 0 PROD1 RPEQP1TRIP P POOH, swap well over to used flo -pro 13:09 15:45 2.60 0 0 PROD1 RPEQPI PULD P Lay down Dummy WS, PU WS. 15:45 17:30 1.75 0 7,375 PROD1 RPEQP1TRIP P RIH with open EDC, Circ at .3 BPM. 17:30 17:42 0.20 7,375 7,400 PROD1 RPEQP1DLOG P Tie in, -10' 17:42 18:00 0.30 7,400 7,641 PROD1 RPEQP1TRIP P RIH, wt. check, 25K PUW, 10K RIW. Set WS at 7640.73', TOWS at 7631'. Set down 4400 Lbs. 18:00 20:00 2.00 7,641 0 PROD1 RPEQP1TRIP P POOH 20:00 20:30 0.50 0 0 PROD1 RPEQPI PULD P PJSM, Flow test well, No Flow on test. Pull BHA #2 20:30 21:15 0.75 0 0 PROD1 WHPST PULD P Make up BHA #3 to mill 3.5" exit to, 7" wall. 2.80 Mill, 2.79 No -Go String reamer and straight motor 21:15 23:00 1.75 0 7,380 PROD1 WHPST TRIP P Trip in well Page 2 of 35 • Time Logs 9 Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 23:00 23:21 0.35 7,380 7,633 PROD1 WHPST DLOG P 7380, Perform Gamma Tie in for -8' correction Wt Chk 24K Up, 9.5K RIW RIH to Mill 23:21 00:00 0.65 7,633 7,633 PROD1 WHPST TRIP P 7633.4, Dry tag Whipstock, PUH, Bring pumps online 1.45 BPM @ 3710 FS Stalled two times, feather into bottom 03/17/2010 Mill dual string exit and 7' of rathole 00:00 04:30 4.50 7,633 7,636 PROD1 WHPST MILL P 7633.09 Start time milling, 60Lbs Motor work 400Ibs WOB 144 BPM @ 3675 FS 04:30 08:18 3.80 7,636 7,639 PROD1 WHPST MILL P 7635.7 Lost 1500 Lbs DH WOB, 2.61' into first milling run over last 1/2 foot. 08:18 08:48 0.50 7,639 7,639 PROD1 WHPST REAM P Ream up and down three times. Dry pass looks good. 08:48 10:30 1.70 7,639 0 PROD1 WHPST TRIP P POOH 10:30 10:48 0.30 0 0 PROD1 WHPST SFTY P PJSM, checking for no flow 10:48 11:18 0.50 0 0 PROD1 WHPST PULD P Lay down BOT motor, string reamer and mill. Mill and reamer are 2.80 go, 2.78 no -go. 11:18 12:06 0.80 0 0 PROD1 WHPST PULD P MU Inteq BHA with HOT, 2.5 -deg WFT motor and 2.80" f- 1. u' 12:06 13:00 0.90 0 0 PROD1 WHPST SVRG P Service injector 13:00 15:00 2.00 0 7,400 PROD1 WHPST TRIP P RIH circulating at 0.3 BPM 15:00 15:18 0.30 7,400 7,430 PROD1 WHPST DLOG P Tie in, -11' 15:18 19:06 3.80 7,639 7,640 PROD1 WHPST MILL P Tag, pinch point at 7638.6, PUH and start pumping at 1.4 BPM, 3750 CTP, 0 WHP. RIH, 40 psi motor work at 7638.1', begin time milling. 19:06 23:00 3.90 7,640 7,644 PROD1 WHPST MILL P 7640.3, Lost WOB, 2.2' on 7 ". Possible pop out of second string. Continue time milling per program 23:00 00:00 1.00 7,644 7,649 PROD1 WHPST MILL P 7644' go to mill rat hole 1.43 BPM @ 4420 FS Midnight depth 7649 03/18/2010 Completed window and build section. R/U slickline for window evaluation 00:00 01:00 1.00 7,649 7,651 PROD1 WHPST MILL P 7651' Start back reaming per program 01:00 01:06 0.10 7,651 7,651 PROD1 WHPST MILL P Reaming passes complete, trap pressure and dry pass through window Looks good 7630 to 7648, Pull up through window Do not see the need to run Crayola at this time 01:06 03:00 1.90 7,651 0 PROD1 WHPST TRIP P Trip out of well following pressure schedule 03:00 04:15 1.25 0 0 PROD1 WHPST PULD P PJSM, Undeploy BHA, Mill guaged 2.79 No -Go Page 3 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:15 06:33 2.30 0 62 PROD1 DRILL PULD P P/U Build section BHA #5 w/ 2.45 degree motor 06:33 08:24 1.85 62 7,400 PROD1 DRILL TRIP P RIH following MPD tripping schedule. 08:24 08:42 0.30 7,400 7,430 PROD1 DRILL DLOG P Tie in, - 10' 08:42 12:12 3.50 7,651 7,765 PROD1 DRILL DRLG P Window clean, tag bottom at 7650', 21K PUW, 9K RIW Start mud swap Drill ahead, 1.45 BPM, 3700 CTP, 12.16 ECD, 1 -3K WOB, 100 to 300 psi motor work. Start at 20 -30 ROP, some stick /slip problems initially Increase ROP to 40 -60 12:12 12:24 0.20 7,765 7,765 PROD1 DRILL WPRT P wiper to window 12:24 14:24 2.00 7,765 7,885 PROD1 DRILL DRLG P Drill ahead, 1.41 BPM, 3700 CTP, 12.1 ECD, 1 -3K WOB, 100 to 300 psi motor work. 14:24 16:45 2.35 7,885 0 PROD1 DRILL TRIP P POOH 16:45 18:00 1.25 0 0 PROD1 DRILL PULD P At surface with BHA #5, PJSM, Undeploy and lay down tool, 18:00 21:00 3.00 0 0 PROD1 WHPST SLKL P MIRU slickline unit to run PDS Caliper for dual string window evaluation 21:00 23:00 2.00 0 0 PROD1 WHPST SLKL P RIH with 3" OK -1 Kick over tool and 1.35" LIB. down to GLM #6 locate poorly @7265 SLM. Unable to set down. Drift down to 7430 SLM. POOH seeing all mandrels 6' higher SLM Call a +6' correction for caliper run. 23:00 00:00 1.00 0 0 PROD1 WHPST SLKL P M/U PDS caliper and RIH 03/19/2010 Run Caliper through window, M/U lateral BHA with resistivity, Drill Ahead 00:00 03:42 3.70 0 0 PROD1 WHPST SLKL P Continue in well with PDS Caliper to evaluate window. RIH set down lightly at 7657 SLM. Work gently down to 7667 target was 7670' Wait for tool to open @ 1:13, Log up @ 20 FPM to 7400' SLM Slight over pull @ 7657' SLM (250Lbs) RBIH to 7667 SLM and log up @ 20 FPM, 400 Lbs overpull @ 7650. RBIH and repeat again. Trip out of well 03:42 04:12 0.50 0 0 PROD1 WHPST SLKL P On Surface, PJSM unstab lubricator, PDS to check for good data 04:12 06:42 2.50 0 0 PROD1 WHPST SLKL P Good caliper data, R/D Slickline, crew change 06:42 07:00 0.30 0 PROD1 DRILL SFTY P PJSM, Pressure deploy and HCR changeout 07:00 07:30 0.50 0 0 PROD1 DRILL PULD P Deploy drilling BHA Page 4 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:30 08:00 0.50 0 0 PROD1 DRILL RGRP T Replaced hydraulic actuator on B8. Function test and pressure test to 250 low, 5000 high 08:00 09:00 1.00 0 72 PROD1 DRILL PULD P Complete pressure deployment 09:00 10:54 1.90 72 7,400 PROD1 DRILL TRIP P RIH 10:54 11:06 0.20 7,400 7,430 PROD1 DRILL DLOG P Tie in, -11' 11:06 11:30 0.40 7,430 7,885 PROD1 DRILL TRIP P Continue RIH, 9K PUW, 24K RIW, window clean, stacked 2 K at 7648', no PU needed. RIH to tag at 7885'. 11:30 14:30 3.00 7,885 7,995 PROD1 DRILL DRLG P Drilling ahead. 1.4 BPM, 3700 CTP, 4074 BHP, 1 -3K WOB, 100 to 300 psi motor work. Seem to have some bit balling issues. After short wipers ROP temporarily inceases. 14:30 15:12 0.70 7,995 8,035 PROD1 DRILL DRLG P Start adding drill zone to suction pit and saw an increase in ROP. 15:12 17:18 2.10 8,035 8,035 PROD1 DRILL DLOG P Wiper to window with MAD pass for resistivity and gamma RIH to drill, tag up at 7925 with stall, trap pressure, relax coil and pick up, Pump sweep Run through clean, continue to bottom 17:18 19:48 2.50 8,035 8,185 PROD1 DRILL DRLG P 8035', Drill Ahead 1.4 BPM @ 3800PSI FS BHP= 4090 1.2K WOB 100 - 150 PSI Motor Work 19:48 20:33 0.75 8,185 8,185 PROD1 DRILL WPRT P 8185, Pumped to /high sweep before coming off bottom for wiper PUW = 25k, 1.44 BPM 3800 FS Saw 7K overpull @ 7927' area no motorwork Clean trip Running in 20:33 22:33 2.00 8,185 8,335 PROD1 DRILL DRLG P 8185', Drill Ahead 22:33 23:18 0.75 8,335 7,660 PROD1 DRILL WPRT P 8335', Wiper to window with Tie In PUW =25k BHP =4110 1.45 BPM @ 3880 FS Pumped to -high vis sweep 5K overpull @ 7989 23:18 23:27 0.15 7,660 7,673 PROD1 DRILL DLOG P Tie into RA Marker, +1 foot correction 23:27 23:51 0.40 7,673 8,335 PROD1 DRILL WPRT P 7673, wiper trip to bottom RIW 8K Clean trip 23:51 00:00 0.15 8,335 8,345 PROD1 DRILL DRLG P 8335 Drill Ahead 1.45 BPM @ 3850 PSI FS BHP =4110, ECD =12.5 Midnight Depth 8345 03/20/2010 Drilled Ahead from 8345 to 9126 00:00 01:30 1.50 8,345 8,485 PROD1 DRILL DRLG P Drilling ahead from 8345 1.45 BPM @ 3810 FS BHP = 4110 80 -90 FPH Avg ROP Page 5 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 01:30 02:45 1.25 8,561 8,485 PROD1 DRILL WPRT P Wipe to window PUW =26K Good clean trip up and down 02:45 03:15 0.50 8,485 8,561 PROD1 DRILL DRLG P 8485', Drill Ahead 1.43 BPM @ 3810 PSI FS BHP =4110, ECD 12.5 WOB 1270 LBS Surface weight 6K 03:15 10:15 7.00 8,561 8,635 PROD1 DRILL DRLG P 8561' Drilling Break ROP Decreased from 115 FPH to 2 -10 FPH DH WOB 2 to 3K 150 to 200 PSI Motor work Confer with Geo, Acting like Ankorite, 10:15 11:33 1.30 8,635 8,635 PROD1 DRILL WPRT P Wiper trip to window, 27K PUW 11:33 13:15 1.70 8,635 8,785 PROD1 DRILL DRLG P Drilling ahead. 8K RIW, 1.4 BPM, 3950 CTP, 4090 BHP, 1 -3K WOB, 100 to 300 psi motor work. Drilling break at 8669', ROP increased to 100 -150 13:15 14:27 1.20 8,785 7,645 PROD1 DRILL WPRT P Wiper to window, 28K PUW. Over pull with motor work at 8605, RIH and pull up clean, continue with wiper 14:27 14:36 0.15 7,645 7,680 PROD1 DRILL DLOG P Tie in to RA, +2' 14:36 15:06 0.50 7,680 8,785 PROD1 DRILL WPRT P Continue wiper trip back in hole. 11K RIW. Set down weight at 8605', adjusted tool face and slid right by 15:06 17:06 2.00 8,785 8,935 PROD1 DRILL DRLG P Drilling ahead. 6K RIW, 1.4 BPM, 3950 CTP, 4090 BHP, 1 -3K WOB, 100 to 300 psi motor work. 17:06 18:48 1.70 8,935 8,935 PROD1 DRILL WPRT P Wiper trip to window 18:48 21:00 2.20 8,935 9,085 PROD1 DRILL DRLG P 8935', Drill Ahead 1.45 BPM @ 4100 PSI FS BHP =4195 DH WOB =1.6K @ 4K surface 21:00 23:00 2.00 9,085 9,085 PROD1 DRILL WPRT P 9085' Wiper trip PUW =27K 23:00 00:00 1.00 9,085 9,126 PROD1 DRILL DRLG P 9085' Drill Ahead 1.4 BPM @ 3850 PSI FS BHP =4200, 1.4 WOB, 2.9K Surface weight Midnight Depth 9126 03/21/2010 Drilled from 9196 to 9573, BHA Failure, POOH to swap out 00:00 01:00 1.00 9,126 9,237 PROD1 DRILL DRLG P 9126', Drill Ahead 01:00 02:15 1.25 9,235 7,662 PROD1 DRILL WPRT P 9235', Wiper Trip to window with Tie In PUW =26K, BHP =4200 1.4 BPM @ 3700 FS Pump Lo -Hi Sweep. Mud Swap following sweep 02:15 02:23 0.14 7,662 7,672 PROD1 DRILL DLOG P Gamma tie in to RA marker for a +4.5 correction, continue wiper Page 6 of 35 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 02:23 03:24 1.02 7,672 9,237 PROD1 DRILL WPRT P RIH to Drill Set down @ 9166, P/U and orient to as drilled 70R Continue in hole 03:24 06:18 2.90 9,237 9,378 PROD1 DRILL DRLG P 9237' Drill ahead 1.4 BPM @ 3700 FS BHP =4010 ECD =12.2 Added 50 PSI to Choke WOB =1.1 k RIW =4.2K 06:18 08:48 2.50 9,378 9,378 PROD1 DRILL WPRT P Poor weight transfer, wiper trip to window. 31 K PUW. Pump sweeps - 5 low, 5 high. 08:48 12:00 3.20 9,378 9,545 PROD1 DRILL DRLG P Drilling ahead. -6K RIW, 1.4 BPM, 3950 CTP, 4090 BHP, 1 -2K WOB, 100 to 200 psi motor work. 12:00 15:00 3.00 9,545 9,545 PROD1 DRILL WPRT P Wiper to window, 29K PUW 15:00 16:00 1.00 9,545 9,573 PROD1 DRILL DRLG P Drilling ahead. -6K RIW, 1.4 BPM, 3900 CTP, 4120 BHP, 1 -2K WOB, 100 to 200 psi motor work. 16:00 20:00 4.00 9,573 0 PROD1 DRILL TRIP T MWD failure POOH 20:00 21:45 1.75 0 0 PROD1 DRILL PULD T PJSM UD failed BHA #6, P/U BHA #7, 1.3 degree motor with agitator 21:45 23:21 1.60 0 7,400 PROD1 DRILL TRIP T RIH, EDC open, follow tripping pressure schedule 23:21 23:33 0.20 7,400 7,419 PROD1 DRILL DLOG T Tie in formation -8' correction. Shut EDC, Wt Chk PUW 24K, RIW =10K 23:33 23:59 0.44 7,419 8,032 PROD1 DRILL TRIP T Continue in well to drill Midnight Depth 8032 03/22/2010 TD Well @ 9800, Lay in Liner Pill, Kill Well. M/U liner and start in hole 00:00 01:00 1.00 8,032 9,573 PROD1 DRILL TRIP T Continue trip in well 01:00 03:15 2.25 9,573 9,725 PROD1 DRILL DRLG P 9579 Drill Ahead 1.3 BPM @ 3825 FS WOB =1.1 K 4.6K RIW 03:15 06:15 3.00 9,725 9,725 PROD1 DRILL WPRT P 9725 Wipe to window 1.3 BPM @ 3850 FS PUW =31k BHP =4125 ECD =12.7 06:15 09:30 3.25 9,725 9,800 PROD1 DRILL DRLG P Drilling ahead. -10K RIW, 1.3 BPM, 4025 CTP, 4100 BHP, 1 -2K WOB, 100 to 200 psi motor work. 09:30 11:06 1.60 9,800 7,650 PROD1 DRILL WPRT P Called TD at 9800' after hitting ankerite. Pump 5 low /5 high vis sweeps and wiper to window for tie -in. Over pull and motor work at 9446'. Over pull with no motor work at 9359' 11:06 11:12 0.10 7,650 7,670 PROD1 DRILL DLOG P Tie into RA, +3' 11:12 12:42 1.50 7,670 9,800 PROD1 DRILL WPRT P Wiper back in hole, weight started dropping fast at - 9100'. No motor work on the way in. Tag TD at 9800'. 12:42 13:48 1.10 9,800 7,600 PROD1 DRILL DISP P Lay in liner running pill in open hole. Continue circulating flo -pro while POOH Page 7 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 13:48 14:54 1.10 7,600 1,700 PROD1 DRILL TRIP P Continue circulating flo -pro while POOH, Paint flag at 6132' EOP Flag. 14:54 16:06 1.20 1,700 7,600 PROD1 DRILL TRIP T Attempt to close SSSV. Well continued to flow at < 0.1 BPM after 5 minutes. Pressure back up, open SSSV and RIH to circulate in KWF 16:06 17:54 1.80 7,600 0 PROD1 DRILL TRIP T Lay in 12.0 NaBr KWF from window to surface 17:54 18:30 0.60 0 0 PROD1 DRILL SFTY P Monitor for no -flow while doing crew changeout., PJSM Pulling BHA out of dead well and running liner 18:30 19:30 1.00 0 0 PROD1 DRILL PULD P Lay down BHA # 7 19:30 19:45 0.25 0 0 PROD1 DRILL BOPE P P/U Test joint and function test BOPE 19:45 23:00 3.25 0 1,515 COMPZ CASING PUTB P Prep Floor and run 45 Joints of liner and aluminum billet with GS profile. Surface test tool 23:00 00:00 1.00 1,515 4,800 COMPZ CASING RUNL P RIH with BHA #8 03/23/2010 Ran Liner in A lateral from 9790 to 8326'. KO Top of Billet @ 8326' - drill to TD of AL1 Lateral to 8810'. 00:00 01:00 1.00 4,800 7,647 COMPZ CASING RUNL P Continue in well with "A" lateral liner 01:00 01:45 0.75 7,647 9,794 COMPZ CASING RUNL P Correct @ 6132' EOP flag. -13', continue in well PUW =33, 01:45 01:57 0.20 9,790 9,790 COMPZ CASING RUNL P Tag and set down aA 9797, PUW =35K @ 9790 Repeat and confirm Pump 1.3 @ 3900, Pick up 23k Released from liner Line up to pump across top, Start out of well 01:57 02:15 0.30 9,790 9,100 COMPZ CASING RUNL P POOH 02:15 02:30 0.25 9,100 7,648 COMPZ CASING DLOG P 9100' ( No correction after setting liner) log down to RA Marker, +4' correction Liner at 9794 corrected, TOL @ 8323.25 Reset bit depth to 7647.53, Bottom of GS. Current tool string 44.6 02:30 04:30 2.00 7,648 0 COMPZ CASING TRIP P POOH 04:30 05:00 0.50 0 0 COMPZ CASING PULD P Lay down liner running BHA 05:00 06:00 1.00 0 72 PROD2 STK PULD P PU drilling BHA for AL1 06:00 07:30 1.50 72 7,614 PROD2 STK TRIP P RIH 07:30 08:30 1.00 7,614 7,614 PROD2 STK DISP P Circulate out KWF 08:30 08:42 0.20 7,614 7,670 PROD2 STK DLOG P Tie in, -10' 08:42 08:57 0.25 7,670 8,326 PROD2 STK TRIP P RIH to tag billet 08:57 11:27 2.50 8,326 8,329 PROD2 STK KOST P 8326', Dry tag billit 1.43 BPM @ 3900 FS Started milling off billit Page 8 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11:27 11:57 0.50 8,329 8,350 PROD2 DRILL DRLG P 8329', Drill Ahead 15 FPH to 8330 then drill ahead to 8350 @ 30FPH Back ream up through kick off area then pass through not pumping. 11:57 14:42 2.75 8,350 8,505 PROD2 DRILL DRLG P 8350 Drill ahead 1.45BPM @ 4000 PSI FS BHP =4120 EDC =12.6 1.5k WOB, RIW =10k 14:42 15:42 1.00 8,505 8,505 PROD2 DRILL WPRT P 8505', Wiper to window 1.45 BPM @4100 FS PUW =28K, BHP =4080 Slight bobble (200Ibs DH) running in past billit, nothing on way up 15:42 18:42 3.00 8,505 8,655 PROD2 DRILL DRLG P 8505' Drill Ahead 1.45BPM @ 4050 FS 1.4K WOB 8.8K RIW BHP =4110 18:42 20:42 2.00 8,655 8,655 PROD2 DRILL WPRT P Wiper trip - P/U weight off bottom 28K. had problems © 7926' & 7930' RIH. Stacked weight, slid through with lower pump rate. 20:42 23:00 2.30 8,655 8,810 PROD2 DRILL DRLG P Drilling ahead - 1.30 bpm, circ 4200 psi, BHP 4100, ECD 12.7, WOB 2k, ROP 60. Pump a low visc pill 10 bbls 1 to lower circ pressure - continue drilling ahead. 23:00 00:00 1.00 8,810 8,810 PROD2 DRILL WPRT P TD lateral - P/U weight 29K, pump visc pill & Wiper trip. 03/24/2010 Pump KWF, Run liner in AL1 Lat from 8810 - 7623'. P/U Whipstock and set 180 lowside TOWS 7557'. P/U Milling BHA with centralizer. 00:00 02:00 2.00 8,812 8,812 PROD2 DRILL WPRT P Final wiper trip - noticed overpull @ 7840' while wiping. Tie in +3 ft correction. Mix up Liner pill. RIH tag bottom @ 8812' 02:00 04:30 2.50 8,812 71 PROD2 DRILL TRIP P P/U and start pumping 12 bbl liner pill. Flag EOP @ 7479' & 6367'. Pump KWF from window to surface. 04:30 05:00 0.50 71 0 PROD2 DRILL PULD P CT @ surface, flow check for 15 minutes & TBTfor laying down BHA. Lay down BHA. 05:00 06:00 1.00 0 0 COMPZ CASING SFTY P Prep rig floor for P/U liner. Safety joint drill. 06:00 09:30 3.50 0 1,232 COMPZ CASING PUTB P Crew change, PJSM, P/U Liner, Perform Safety joint drill with day crew 09:30 11:30 2.00 1,232 7,611 COMPZ CASING RUNL P RIH with Liner 11:30 12:00 0.50 7,611 8,812 COMPZ CASING RUNL P At 6367 Flag, correct -11.7, close EDC PUW =30K, 12:00 12:06 0.10 8,812 8,555 COMPZ CASING RUNL P 8812, Set down with liner, PUW =35K, Roll pumps 1.3 BPM @ 4000PSI PUW= 24K, Released from liner, Start out of well Page 9 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:06 12:18 0.20 8,555 8,565 COMPZ CASING DLOG P Log tie in, Correct +2', Remove liner length from counters Bottom of liner @ 8812 corrected, TOL @ 7623.47 12:18 13:54 1.60 8,565 0 COMPZ CASING TRIP P POOH 13:54 14:36 0.70 0 0 COMPZ CASING PULD P At surface, PJSM to remove BHA from dead well Monitor well for flow, Pull liner running tools from well 14:36 15:42 1.10 0 0 PROD3 RPEQP1 PULD P M/U Whipstock and coil track, Surface test tool and make up injector 15:42 18:30 2.80 0 7,567 PROD3 RPEQP1TRIP P RIH with 3.5" Whipstock. Tie in -10 ft correction. P/U weight 27K. Close EDC. RIH slowly to setting depth. TOWS 7557' BOWS 7566.7' 180 lowside. 18:30 20:00 1.50 7,567 54 PROD3 RPEQP1TRIP P Start pumping KWF down CT - pressure up to 4300 psi, Set - sat down 5K looked good. P/U weight 25K, start pumping KWF down CT while POOH. 20:00 21:00 1.00 54 0 PROD3 RPEQP1 PULD P CT @ surface, flo- check. Safety meeting for BHA handling. Lay down BHA. change out pack off. 21:00 22:00 1.00 0 70 PROD3 WHPST PULD P P/U BHA # 12 window milling BHA with centrilizer & 10 ft vibration sub. 22:00 00:00 2.00 70 7,450 PROD3 WHPST TRIP P RIH and swap fluid to flo -pro on bottom. Tie in - 10ft. 03/25/2010 Mill LS window from 7557' - 7575' TOWS 7557' BOWS - 7565'. P/U 2.5 AKO build BHA. 00:00 03:00 3.00 7,558 7,560 PROD3 WHPST MILL P Dry tag @ 7558', P/U and slowly RIH with pumps @ 1.45 bpm. free spin 3950, lightly tag @ 7557.8'. Start milling window. Seeing metal returns 1.5' ft into window. WOB 1.4, Ct weight 12K, 1.45 bpm, 4100 psi. 03:00 05:00 2.00 7,560 7,561 PROD3 WHPST MILL P Continue Milling - WOB 1.8, CT weight 12K, 1.45 bpm, 4100psi, good metal returns over shaker. Continue time drilling. 05:00 11:00 6.00 7,561 7,565 PROD3 WHPST MILL P Weight dropped off WOB @ 7560.5' Start to auto drill .8 fph with WOB .8K. CT weight 12K. 1.45 bpm @ 3900 psi. 11:00 14:00 3.00 7,565 7,570 PROD3 WHPST MILL P 7564.7, Lost WOB and Differential pressure. Bottom of window 6.9' Window. Continue to time drill to 12' past TOWS 14:00 14:30 0.50 7,570 7,575 PROD3 WHPST MILL P 12' Below pinch point, Drill formation 14:30 15:30 1.00 7,575 7,575 PROD3 WHPST REAM P Drilled formation, Start dressing / back reaming, Made two down reaming passes then •o through dry, Looks good 15:30 17:00 1.50 7,575 70 PROD3 WHPST TRIP P POOH following pressure schedule Page 10 of35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 17:00 19:00 2.00 70 0 PROD3 WHPST PULD P PJSM, Lay down BHA #12 and M/U BHA #13 builsd section. Bit and reamer came out a 2.79" Light gouges were noted on EDC & PC BHA (did not go near window). 19:00 20:30 1.50 0 62 PROD3 DRILL PULD P Deploy BHA# 13 with 2.5 AKO with Hughes Bi- center. 20:30 22:30 2.00 62 7,575 PROD3 DRILL TRIP P RIH following MP schedule. Tie in -9 ft correction, Stop pumping, close EDC, RIH through window, weight bobbles but not tagging. 22:30 00:00 1.50 7,575 7,612 PROD3 DRILL DRLG P Bring pumps up to 1.40 bpm, start pumping new mud down, drilling ahead. Quick stall on bottom. P/U 27K and restart with slower ROP. Drilling ahead with new mud 1.35 bpm, 3700 psi, WOB 1.5, CT weight 8K, ROP 25. ECD 12.2 03/26/2010 Mud swap- Drill build section from 7565 - 7855'. P/U Rib steer BHA and continue drilling ahead L2. No issues at window. 00:00 04:00 4.00 7,612 7,707 PROD3 DRILL WPRT P Drilling build section - 1.40 bpm, 3800 psi, CT weight 6K, WOB 1.3, ROP 30, ECD 12.2, BHP 3930psi. Samples indicate silt & clay shales (7600 & 7650) Starting to slightly stick and have weight transfer problems. P/U weight 35K. 04:00 04:30 0.50 7,707 7,707 PROD3 DRILL WPRT P Wiper trip 28K off bottom, come up through window & tie into formation then PIP tag to correct window depths. +2 ft correction. RA tag 7565' 04:30 09:30 5.00 7,707 7,855 PROD3 DRILL DRLG P Drilling ahead - 1.40 bpm, 3900 psi, BHP 3970, ECD 12.2, ROP 50, WOB 1.5, CT weight 4K. 09:30 09:45 0.25 7,855 7,530 PROD3 DRILL WPRT P Geo wiper to determine plan forward, DD is landed with turn PUW 32K, Pull up through window, Open EDC, Wait on plan 09:45 11:15 1.50 7,530 0 PROD3 DRILL TRIP P EOB @ 7830, End of turn 7855, Trip out for lateral BHA 11:15 14:15 3.00 0 0 PROD3 DRILL PULD P At Surface, PJSM, Lay down BHA #13, P/U BHA #14 Ribsteer With New Hycalog Bi- Center with Cheetha Cutters 14:15 15:45 1.50 0 7,390 PROD3 DRILL TRIP P Trip in Hole 15:45 16:15 0.50 7,390 7,855 PROD3 DRILL DLOG P 7390, Log tie in for -9' correction, RIH Log RA Marker. Correct RA is 7564 RIH to Drill 16:15 18:45 2.50 7,855 8,005 PROD3 DRILL DRLG P 7855' Drill ahead 1.35BPM @ 3995 FS 1.8K WOB 6K RIW BHP =4025 18:45 19:30 0.75 8,005 8,005 PROD3 DRILL WPRT P Wiper trip with MAD pass. P/U weight 30K off bottom. Page 11 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 19:30 21:30 2.00 8,005 8,155 PROD3 DRILL DRLG P Drilling ahead - 1.35 bpm, 4000 psi, BHP 4080, ECD 12.4, ROP 80, WOB 1.5, CT weight 5K. 21:30 22:30 1.00 8,155 8,155 PROD3 DRILL WPRT P Wiper trip - P/U weight 28K. 22:30 00:00 1.50 8,155 8,305 PROD3 DRILL DRLG P Drilling ahead - 1.38 bpm, 3900 psi, BHP 4080, ECD 12.4, ROP 70, WOB 1.5, Ct weight 7.3K. 03/27/2010 Continued drilling ahead with RSM. Mud spwa with 1300 ft on system. 00:00 01:00 1.00 8,305 8,305 PROD3 DRILL WPRT P Wiper trip & tie in +3 ft correction. P/U weight 27K off bottom. 01:00 03:30 2.50 8,305 8,455 PROD3 DRILL DRLG P Drilling ahead 1.35 bpm, 3800 psi, BHP 4080, ECD 12.4, ROP 60, WOB 1.8, CT weight 7K. Fluid losses roughly 5 bbls an hour 03:30 04:30 1.00 8,455 8,455 PROD3 DRILL WPRT P Wiper trip - P/U weight 25K. 04:30 07:15 2.75 8,455 8,605 PROD3 DRILL DRLG P Onn bottom drilling - 1.35 bpm, 3800 psi, BHP 4090, ECD 12.5, ROP 50, WOB 1.5 07:15 08:00 0.75 8,605 8,605 PROD3 DRILL WPRT P 8605, Wiper to window, 27K PUW 08:00 09:45 1.75 8,605 8,745 PROD3 DRILL DRLG P 8605', drill Ahead 1.36BPM @ 3900 FS 1.4K WOB, 9.3K RIW BHP =4095 09:45 10:30 0.75 8,745 7,580 PROD3 DRILL WPRT P 8745, Wipe to window, 28K PUW 10:30 10:36 0.10 7,580 7,600 PROD3 DRILL DLOG P Tie into RA Marker fora +4' correction 10:36 11:36 1.00 7,600 8,756 PROD3 DRILL WPRT P Continue wiper trip back to bottom 11:36 11:48 0.20 8,756 8,756 PROD3 DRILL DRLG P 8756' Drilling Ahead 1.38 BPM @ 3890 FS 1.9K WOB, 8.4K RIW BHP =4095 Hit Ankerite interval 8756 to 8785, ROP 5 to 7 FPH 11:48 15:18 3.50 8,756 8,785 PROD3 DRILL DRLG P 8785, Stalled twice then took off 80 to 100 fph Pump lo hi vis sweep after coming out 15:18 17:03 1.75 8,785 8,895 PROD3 DRILL DRLG P 8785- Drill ahead 1.38 BPM @ 3890 FS 17:03 18:33 1.50 8,895 8,895 PROD3 DRILL WPRT P 8895, Wipe to window, 24K PUW 18:33 20:09 1.60 8,895 9,055 PROD3 DRILL DRLG P Drilling ahead - Mud swap (1300 ft of system), 1.35 bpm, 4000 psi, BHP 4100, ECD 12.7, WOB 1.8, ROP 90, CT weight 6K. 20:09 22:00 1.85 9,055 9,055 PROD3 DRILL WPRT P Wiper trip - P/U weight 27K 22:00 00:00 2.00 9,055 9,173 PROD3 DRILL DRLG P Drilling ahead - 1.35 bpm, 3800psi, BHP 4020, ECD 12.3, ROP 50, WOB 2.2, CT weight 6K. 03/28/2010 Drilling ahead, crossed two faults. Slow, ratty drilling through lower A -4/A -3 shale after 1st fault (9000'), better sand & ROP after 2nd fault (9450'). 00:00 00:30 0.50 9,173 9,205 PROD3 DRILL DRLG P Drilling ahead - starting to stack out slightly @ 9200'. Planned wiper 9205'. CT weight -2K. Page 12 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:30 03:00 2.50 9,205 9,205 PROD3 DRILL WPRT P Wiper trip - P/U weight 29K off bottom - tie in. +6 ft correction. Weight bobble @ 9025' fault section while RIH. Tagged up early @ 9160' slow RIH speed to 10 fpm. Pump low /high visc pill on bottom. Weight transfer problems. P/U 50 ft better weight transfer @ 1.30 bpm. 03:00 05:30 2.50 9,205 9,320 PROD3 DRILL DRLG P Drilling ahead - Low /high pill helped on bottom - 1.34 bpm, 3700 psi, BHP 4020, ECD 12.3, ROP 80, WOB 2K, CT weight 5K. Not finding any good sand. looks like lower A -4. 05:30 06:15 0.75 9,320 9,320 PROD3 DRILL WPRT P Wiper trip - discuss in town next step. P/U weight 29K Pulled up to 8900. Plan to drill ahead to planned wiper at 9355 Some mild stacking on way in, popped through without reducing pump rate No setdowns 06:15 07:15 1.00 9,320 9,355 PROD3 DRILL DRLG P 9320', Drill ahead 1.35 BPM @ 3660 FS BHP =4130 1.3K WOB, 6K RIW Pump Lo -Hi Sweep 07:15 10:30 3.25 9,355 9,355 PROD3 DRILL WPRT P Wiper trip to window, Clean trip to window, PUW =28K Set down @ 9202. P/U and run through @ 15 FPM and full pump rate set down @ 9306. PUH, had to reduce rate to get down.. PUH @ 5 FPM at full rate up to 9250 Able to turn around and get to bottom at full rate. 10:30 14:15 3.75 9,355 9,470 PROD3 DRILL DRLG P 9355', Drill Ahead , 1.3 BPM @ 3790 FS 1.9K WOB, 2.7K RIW, BHP =4150, EDC =12.6 ROP 30 -40 FPH 14:15 14:30 0.25 9,470 9,470 PROD3 DRILL WPRT P Perform Mini Wiper, PUW= 31K everything looks good, Just got out of high gamma area at 9400 to 9460 wanted to see how this area would react 14:30 15:12 0.70 9,470 9,515 PROD3 DRILL DRLG P Drill Ahead to 9515, Drilling break @ 9470 ROP from 26 FPM to 60 then 100 15:12 18:12 3.00 9,515 9,515 PROD3 DRILL WPRT P 9515' Wiper to window PUW =28K 1.35 BPM @ 3810 FS BHP =4215 Pumped lo hi sweep to come out bit before we came off bottom Over pull @9353 4.5K Playing with pump rate & speed from 9350' to 9450' to get back to bottom. Weight check on bottom 29K Page 13 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 18:12 20:42 2.50 9,515 9,675 PROD3 DRILL DRLG P Drilling ahead to 9530' had to P/U due to weight stack, had overpull to 35K, wiper trip to 9470'. RIH, pump low /high visc. sweep. 1.35 bpm, 3600 psi, BHP 4180, ECD 12.7, ROP 50, WOB 1.8K, CT weight 3K. Good ROP & Rez @ 9550' indicates in upper A -4 sand. 20:42 23:30 2.80 9,675 9,675 PROD3 DRILL WPRT P Pump Low /high prior to wiper - P/U weight 28K Tie in +8 ft. RIH - had to reduce pump rates @ 9300 - 9350, & 9420'. 23:30 00:00 0.50 9,675 9,703 PROD3 DRILL DRLG P Back on bottom drilling. 03/29/2010 TD lateral 9835' - Pump KWF & P/U liner assembly. Run liner from 9835 - 8864'. P/U Anchored Billet - Set TOB @ 8852' 2 00:00 02:30 2.50 9,703 9,835 PROD3 DRILL DRLG P Drilling ahead - 1.35 bpm, 3800psi, �� BHP 4220, ECD 12.8, ROP 50, WOB 1.8, CT weight 1 K. TD hole at 9835' MD. 02:30 06:30 4.00 9,835 9,386 PROD3 DRILL WPRT T Pump Low /high pill - P/U weight 28K, wiper to window with tie in +4 ft. 06:30 08:00 1.50 9,386 0 PROD3 DRILL TRIP T Trip out of well laying in beaded liner running pill to window then 12.0 Lbs /GI KWT to surface. Paint 8500' and 6200' EOP flags on trip out 08:00 09:30 1.50 0 0 PROD3 DRILL PULD T At surface, monitor well for flow, PJSM pull BHA from dead well 09:30 10:30 1.00 0 0 COMPZ CASING SFTY T PJSM, Prep floor to rum liner 10:30 12:45 2.25 0 1,015 COMPZ CASING PUTB T P/U AL2 Liner 12:45 14:45 2.00 1,015 7,228 COMPZ CASING RUNL T RIH with AL2 Liner 14:45 15:30 0.75 7,228 8,557 COMPZ CASING RUNL T 7227.8. correct -12 @ Flag to 7215.21 PUW =25.5K RIW =12K 15:30 16:15 0.75 8,557 9,833 COMPZ CASING RUNL T Set down hard at 8557, top of BHA @ 7541.7 just above window. Pick up and Run in at slower speed 15 FPM got through. Set down again @ 8591' BHA out of window pick up twice and go past Appears indexing guide shoe working 16:15 17:00 0.75 9,833 8,530 COMPZ CASING RUNL T 9833, Set dowm PUW =30K, Set back down, Pumps on 1.1 BPM @ 4K PUW =22K, PUH pumping across top 17:00 17:15 0.25 8,530 8,539 COMPZ CASING DLOG T Log RA fora +4 ft correction BOL 9837, TOL 8866.4 Made correction and removed liner depth. Bit depth is now GS Spear 17:15 19:45 2.50 8,539 0 COMPZ CASING RUNL T POOH pumping down CT 19:45 20:15 0.50 0 73 COMPZ CASING PULD T LD liner BHA 20:15 20:45 0.50 8,864 PROD4 STK PULD T PU anchored billet BHA. Page 14 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 20:45 23:45 3.00 73 8,864 PROD4 STK TRIP T RIH with EDC open pumping . 3 bpm. Tie in - 10 ft correction. Stop pumping & close the EDC. RIH - clean through window. Sat down @ 8860' P/U weight 28K, RIH Tag TOL @ 8864' 23:45 00:00 0.25 8,864 8,864 PROD4 STK CIRC T Tag TOL 8864' P/U 27K - RIH tag 8863' - P/U string weight TOB 8852' Orientate Left 30 degrees. Increase pump rate, set @ 4200 psi, P/U rate 25K. 03/30/2010 BOP testing 00:00 02:00 2.00 8,864 0 PROD4 STK TRIP T POOH and pump across top until window. Stop and pump down CT from window to surface with KWF. 02:00 03:00 1.00 0 0 PROD4 STK PULD T CT @ surface. Flo -check well. Lay down BHA. 03:00 04:30 1.50 0 0 PROD4 STK BOPE P Grease the tree & flush the stack. Got a good seal on master valve when greased. Tested to 4800 psi. Good Flat line. / 04:30 06:00 1.50 0 0 PROD4 STK BOPE P Start testing BOPE. Lou Grimaldi (/ (AOGCC) witness. 06:00 07:30 1.50 0 0 PROD4 STK BOPE T Tree valves not testing, call out grease crew to trouble shoot 07:30 10:30 3.00 0 0 PROD4 STK BOPE T Repair valves on choke manifold. ** 3 Hours of Nabors Non - Billable Rig Repair time** 10:30 21:00 10.50 0 0 PROD4 STK BOPE P Continue Testing BOP- all passed. Total test time 16.5 Hours 21:00 23:00 2.00 0 0 PROD4 STK PULD T Hold PJSM, Install check valves, MU BHA #17 23:00 23:18 0.30 0 0 PROD4 STK CIRC T Open EDC, Displace CT to KWF mud 23:18 00:00 0.70 72 3,360 PROD4 STK TRIP T RIH 03/31/2010 Pin Hole CT, RD reel, remove from rig, Attempt to install new reel, Reel drum to wide. 00:00 00:48 0.80 3,360 7,394 PROD4 STK DLOG T Tie in depth, -13' correction 00:48 02:18 1.50 7,394 7,550 PROD4 STK CIRC T RIH to 7550', Displace well over to Flo Pro. 02:18 02:30 0.20 7,550 7,550 PROD4 STK TRIP T RIH to tag Billet, .3 BPM 02:30 04:30 2.00 7,550 7,682 PROD4 STK TRIP T Pin Hole in CT at 7611' EOP. Bleed CT down, assure check valves are holding. Mark Pinhole (yellow) PUH to window placing pinhole on reel. Open EDC, line up to pump down MP line maintaning BHP. POOH 04:30 06:00 1.50 7,682 0 PROD4 STK PULD T At surface, Undeploy BHA 17 06:00 07:00 1.00 0 0 SURPRI WELLPF CTOP T Stab back on well, circulate fresh water into reel. 07:00 07:30 0.50 0 0 SURPRI WELLPF SFTY T PJSM with SLB nitrogen pumpers Page 15 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:30 13:00 5.50 0 0 SURPRI WELLPF CTOP T Blow down reel. Cut off CTC, install grapple, tail pipe back to reel. Secure pipe at reel. RD inner reel iron. RU slings for reel swap 13:00 13:30 0.50 0 0 SURPRI WELLPF SFTY T PJSM with Peak truck drivers 13:30 18:00 4.50 0 0 SURPRI WELLPF CTOP T Swap reels. Tighten bolts on adapter hubs. 18:00 21:00 3.00 0 0 SURPRI WELLPF RGRP T Reel not fitting into saddle. Remove adapter hubs. 21:00 00:00 3.00 0 0 SURPRI WELLPF RGRP T Remove adapter hubs off pinholed _ _ reel. 04/01/2010 Perform various tasks while waiting nn adapter flanges continue maintaining BHP through MP line. 00:00 03:00 3.00 0 0 SURPRI WELLPF RGRP T Remove spacer washers on adapters on new reel. New reel still does not fit. Close up rig to warm up. 03:00 06:00 3.00 0 0 SURPRI WELLPF RGRP T Remove old brass from stripper and install new 06:00 18:00 12.00 0 0 SURPRI WELLPF RGRP T Perform various operations while waiting on modified adapter flanges to be fabricated.. 18:00 00:00 6.00 0 0 SURPRI WELLPF RGRP T Install PSI bulk head 04/02/2010 0900 Adapter Flanges arrived on location. RU CT, RIH to KO for L2 -01 Lateral 00:00 10:30 10.50 0 0 SURPRI WELLPF RGRP T Prepare reel for RU, Repair /Replace valves on rig, Psi test. Adapter arrived from Deadhorse at 09:15. Installed on reel and set reel into saddles * ** *End of Trouble Time for Improper Sizing of Reel Drum * * * ** 10:30 18:00 7.50 0 0 SURPRI WELLPF CTOP T Reel is in saddles, continue with reel swap operations, finish MU inner reel iron and wire into collector. Install grapple and pull coil into injector. test wire and pressure bulkhead. Seal end of a -line and fill coil with water. Displace reel to fresh water. Pressure test inner reel iron, preesure bulk head and swival. 18:00 19:00 1.00 0 0 SURPRI WELLPF SLPC T Crew change PJSM, reverse circulate for slack management 19:00 19:45 0.75 0 0 SURPRI WELLPF SLPC T Rig up to cut CT, Install counters Found cable at 37 cut. 19:45 20:30 0.75 0 0 SURPRI WELLPF SLPC T RD cutter, Install CTC and pull test to 25K 20:30 21:15 0.75 0 0 SURPRI WELLPF CTOP T BHI Install drilling, Meg test good 21:15 22:00 0.75 0 0 SURPRI WELLPF SLPC T Pressure test CTC 4500psi, stab injector onto well displace CT back to Flo -Pro 22:00 22:15 0.25 0 0 SURPRI WELLPF SFTY T Lift off well with injector, Perform Valve checklist, hold PJSM for Pressure Deployment 22:15 23:30 1.25 0 0 PROD4 STK PULD T Deploy BHA 18 Page 16 of 35 a Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 23:30 00:00 0.50 72 500 PROD4 STK TRIP T RIH, check alignment of gooseneck. Looks good 04/03/2010 ST off Allum. Billet at 8848'. Drill Ahead L2 -01 Lateral 8848' to 9443'. 00:00 01:15 1.25 500 7,390 PROD4 STK TRIP T RIH 01:15 01:30 0.25 7,390 7,412 PROD4 STK DLOG T Tie in depth +4' correction 01:30 01:39 0.15 7,412 7,682 PROD4 STK TRIP T RIH to TOW, Close EDC, Perform weight check, RIH to Billet 01:39 02:15 0.60 7,682 8,849 PROD4 STK TRIP P Continue RIH 02:15 02:30 0.25 8,848 8,848 PROD4 STK KOST T Dry tag billet 8848.5' .5' /min, Start milling down, at slightest weight/motor work start time milling auto driller 1' /hour 02:30 03:00 0.50 8,848 8,848 PROD4 STK KOST T Time Drill 1' /hr 1.4 BPM in, 1.23BPM out, 8K CTW, 3400psi CTP, .3WOB 03:00 03:18 0.30 8,849 8,849 PROD4 STK WPRT T Small amount of alluminum in returns. Surface weight stacking/ Slip sticking. PUH BHA length to trough at ST TF =80L 03:18 03:42 0.40 8,848 8,849 PROD4 STK KOST T Start time milling 1' /hr 03:42 03:48 0.10 8,849 8,849 PROD4 STK WPRT T PUH, Not getting motor work, WOB stacking 03:48 04:06 0.30 8,849 8,849 PROD4 STK KOST T RIH Stall PUH X 2, RIH to mill 04:06 04:36 0.50 8,849 8,849 PROD4 STK KOST T Start milling with Auto Driller 1' /hour 04:36 05:06 0.50 8,849 8,849 PROD4 STK KOST T Stall PU continue milling 1' /hour 05:06 06:06 1.00 8,849 8,850 PROD4 STK KOST T Stall PU, Continue milling 1' /hour 06:06 07:00 0.90 8,850 8,951 PROD4 STK KOST T 2' /hour for 0.5' then 3' /hour for 1'. 07:00 08:42 1.70 8,951 8,990 PROD4 DRILL DRLG T AT 8951' increased ROP to 10' /hour for 5' then drilled ahead. At 8880' PU and run past billet with pump down. Continue drilling ahead. 1.4 BPM, 3800 CTP, 0 WHP, 4130 BHP, 1 - 2K WOB and 200 -400 motor work. 08:42 10:42 2.00 8,990 8,990 PROD4 DRILL WPRT T Wiper to window, 25K PUW. MWD software lock up while coming up hole. Tie into RA 10:42 13:12 2.50 8,990 9,140 PROD4 DRILL DRLG T Continue drilling, 1.4 BPM, 3900 CTP, 0 WHP, 4120 BHP, 1 - 3K WOB and 200 -400 motor work. Swap to new mud system. 13:12 15:06 1.90 9,140 9,140 PROD4 DRILL WPRT T Wiper to window, Clean trip 15:06 17:36 2.50 9,140 9,290 PROD4 DRILL DRLG T Continue drilling, 1.4 BPM, 3900 CTP, 0 WHP, 4150 BHP, 1 - 3K WOB and 200 -400 motor work. 17:36 19:24 1.80 9,290 9,290 PROD4 DRILL WPRT T Wiper Trip to window 7580'. 26K PUW 19:24 22:00 2.60 9,290 9,444 PROD4 DRILL DRLG T Continue drilling, 1.4 BPM, 3900 CTP, 0 WHP, 4220 BHP, 1 - 3K WOB and 200 -400 motor work. 22:00 23:15 1.25 9,444 9,444 PROD4 DRILL WPRT T Wiper to Window 27K PUW Page 17 of 35 li • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 23:15 23:21 0.10 9,444 7,564 PROD4 DRILL DLOG T Tie in depth to RA marker, -3' correction 23:21 00:00 0.65 7,564 9,250 PROD4 DRILL WPRT T RIH to Drill 04/04/2010 Drill lateral L2 -01 to TD @ 10,135'. Lay in liner running pill and kill well while POOH. 00:00 00:15 0.25 9,250 9,444 PROD4 DRILL WPRT T RIH to Drill 00:15 03:00 2.75 9,444 9,590 PROD4 DRILL DRLG T Continue drilling, 1.4 BPM, 4209 CTP, 11 WHP, 4220 BHP, 1 - 2K WOB and 200 -400 motor work. 12.7 ECD 03:00 05:12 2.20 9,590 9,590 PROD4 DRILL WPRT T Wiper trip to window, 28 PUW 05:12 07:42 2.50 9,590 9,740 PROD4 DRILL DRLG T Continue drilling, 1.4 BPM, 3800 CTP, 20 WHP (open choke), 4210 BHP, 1 - 3K WOB and 200 -400 motor work. 07:42 10:00 2.30 9,740 9,740 PROD4 DRILL WPRT T Wiper trip to window. Found a "gouge" in the coil at 8531'. Apparently came from manufacturer. Derated coil life in this segment by 5 %. 10:00 12:48 2.80 9,740 9,890 PROD4 DRILL DRLG T Continue drilling, 1.4 BPM, 3800 CTP, 27 WHP (open choke), 4215 BHP, 1 - 3K WOB and 200 -400 motor work. 12:48 15:48 3.00 9,890 9,890 PROD4 DRILL WPRT P Wiper to window 15:48 17:48 2.00 9,890 10,040 PROD4 DRILL DRLG P Continue drilling, 1.4 BPM, 3850 CTP, 23 WHP (open choke), 4216 BHP, 1 - 3K WOB and 200 -400 motor work. 17:48 20:48 3.00 10,040 10,040 PROD4 DRILL WPRT P Wiper to window. 30 PUW. 20:48 22:30 1.70 10,040 10,135 PROD4 DRILL DRLG P Continue drilling, 1.3 BPM, 3850 CTP, 18 WHP (open choke), 4240 BHP, 1.5 - 2.5 WOB and 300 motor work. At 10125', pump 5 bbls lo-vis and 5 bbl hi -vis pills (TD is 10,135'). 22:30 00:00 1.50 10,135 10,135 PROD4 DRILL WPRT P Wiper trip to window, 33K PUW. 04/05/2010 Ran liner from 10,135' - 8211'. PU and set anchored billet on top of liner. TOB @ 8201'. Function tested BOP's. 00:00 00:24 0.40 10,135 7,564 PROD4 DRILL WPRT P Continue wiper trip to window. 00:24 00:30 0.10 7,564 7,564 PROD4 DRILL DLOG P Tie into RA marker. Correction of -2'. 00:30 01:30 1.00 7,564 10,135 PROD4 DRILL WPRT P Continue to RIH. 01:30 02:30 1.00 10,135 7,560 PROD4 DRILL DISP P Tag TD ng 10135', Begin to POOH laying in beaded LRP (25 bbls). 02:30 03:15 0.75 7,560 5,571 PROD4 DRILL TRIP P At window. Begin laying in 12.0 ppg KWF. Continue to POOH. 03:15 04:30 1.25 5,571 0 PROD4 DRILL TRIP P Paint EOP flag (yellow) at 5500' (5571.75' bit depth). Continue to POOH. 04:30 06:12 1.70 0 0 PROD4 DRILL PULD P At surface. Monitor well for flow. PJSM. Pull BHA #18 from dead well. Prep floor to run liner. Page 18 of 35 . • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:12 06:42 0.50 0 0 COMPZ CASINGSFTY P PJSM, Crew change 06:42 09:42 3.00 0 1,967 COMPZ CASING PUTB P Pick up liner for AL2 -01 lateral. Run 59 Jts. 09:42 10:18 0.60 1,967 1,967 COMPZ CASING SVRG P Service injector and calibrate MM 10:18 11:36 1.30 1,967 7,467 COMPZ CASING RUNL P RIH with liner, closed EDC pumping .2 BPM 11:36 11:48 0.20 7,467 7,467 COMPZ CASING RUNL P Correct depth at flag, +5.65'. PUW 29K, RIW 11K 11:48 12:42 0.90 7,467 10,135 COMPZ CASING RUNL P RIH to TD 12:42 14:12 1.50 10,135 0 COMPZ CASING RUNL P Stacked 5K down and come on line with pump at 1.4 BPM, 4000 psi and PUH to realease liner, 23.5K PUW. POOH. 14:12 14:48 0.60 0 0 COMPZ CASING PULD P Lay down liner running BHA 14:48 15:30 0.70 0 0 PROD5 STK PULD P PU anchored billet BHA 15:30 17:12 1.70 0 7,400 PROD5 STK TRIP P RIH 17:12 17:20 0.14 7,400 7,500 PROD5 STK DLOG P Tie in correlation, +2. 17:20 18:45 1.42 7,500 8,213 PROD5 STK TRIP P Continue to at 25 FPM. Tag top of liner @ 8213.47'. PU off liner. PUW = 25K. PUH to 8211.25'. RBIH to 8213.3' and bring pump on line. Pressure up to 3800# and set anchor. PU off anchor = 26K. 18:45 20:45 2.00 8,213 0 PROD5 STK TRIP P Begin to POOH keeping hole full with 12.0 ppg KWF. 20:45 21:15 0.50 0 0 PROD5 STK PULD P At surface. Monitor well for flow. PJSM. Lay down BHA #20. 21:15 21:23 0.14 0 0 PROD5 STK BOPE P Function test GOP's. 21:23 22:59 1.60 0 0 PROD5 STK PULD P PJSM. Begin PU BHA #21. Check packoff, all ok. 22:59 23:59 1.00 0 4,838 PROD5 STK TRIP P Open EDC. Begin to RIH. 04/06/2010 Kick off billet @ 8201' - continue to drill ahead. Total fluid losses for 24 hours 75 bbls. 00:00 00:30 0.50 4,838 7,374 PROD5 STK TRIP P Continue to RIH with BHA #21. Pumped a 10 bbl hi -vis pill to help recover KWF. Swap to flo -pro. 00:30 00:36 0.10 7,374 7,374 PROD5 STK DLOG P Tie into formation marker @ 7374'. Correction of +2'. 00:36 01:36 1.00 7,374 7,542 PROD5 STK CIRC P RIH to 7542' stop and circ out KWF. Close EDC. 01:36 02:00 0.40 7,542 8,201 PROD5 STK TRIP P Continue to RIH. 1.4 BPM, 4000# circ press., 4100 BHP, 450# diff press (free spin). Dry tag billet @ 8201.5'. PUW = 26K. PUH to 8178'. RBIH. 02:00 03:36 1.60 8,201 8,202 PROD5 STK KOST P RBIH. 1.4 BPM, 3875# circ press., 4160# BHP, 440# diff. press free spin. RIH wt = 9K #. Stalled on first two touches @ 8201'. Engaged on third attempt. Begin time drilling at 1' /hr. 03:36 04:06 0.50 8,202 8,203 PROD5 STK KOST P Increase ROP to 2' per hour Page 19 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:06 04:30 0.40 8,203 8,204 PROD5 STK KOST P Increase ROP to 3' per hour 04:30 05:00 0.50 8,204 8,210 PROD5 DRILL DRLG P Increase ROP to 10' per hour 05:00 07:12 2.20 8,210 8,353 PROD5 DRILL DRLG P Drilling ahead, 1.4 BPM, 3900 CTP, 4140 BHP, 9K RIW, 24K PUW, 1 -3K WOB, 200 -400 motor work, 07:12 08:12 1.00 8,353 8,353 PROD5 DRILL WPRT P Wiper to window 08:12 11:06 2.90 8,353 8,510 PROD5 DRILL DRLG P Drilling ahead, 1.4 BPM, 3900 CTP, 4140 BHP, 9K RIW, 24K PUW, 1 -3K WOB, 200 -400 motor work. At 8445', wt. check PU 26K #. PU wt. off bottom = 27K 11:06 12:42 1.60 8,510 8,510 PROD5 DRILL WPRT P Wiper to window. Above window to swap over from hi -line power to generator (DS work). Swapped over @ 12:00. 12:42 14:42 2.00 8,510 8,660 PROD5 DRILL DRLG P Drilling ahead, 1.4 BPM, 3900 CTP, 4140 BHP, 8500 RIW, 25K PUW, 1.5 - 2.5K WOB, 200 -400# motor work, 80 -95 ROP. Swap to new mud @ 8658' (14:40) 14:42 15:54 1.20 8,660 7,575 PROD5 DRILL WPRT P Wiper to window. PU wt. = 25K #. Make short trip to space out new mud at bit when on bottom. PUH to 8294' and RBIH to 8660'. Continue to PUH for wiper trip. 15:54 16:03 0.15 7,575 7,580 PROD5 DRILL DLOG P Tie into RA marker @ 7564. Correction = 0' 16:03 16:45 0.70 7,580 8,660 PROD5 DRILL WPRT P Wiper back to bottom. On way back to bottom stopped at 8600' and ran a MAD pass up to 8585'. 16:45 19:15 2.50 8,660 8,775 PROD5 DRILL DRLG P Continue drilling ahead. 1.42 BPM, 4100 CTP, 8500 RIW, 1 -2 WOB, 100 -300 motor work. PUH to 8000' while we swith from generator to hi -line power. Off of generator power @ 18:00. Total generator time = 6 hrs. RBIH and continue drilling. 19:15 21:00 1.75 8,775 8,805 PROD5 DRILL DRLG P ROP slowing down, hard time getting good weight transfer to bottom. CT weight -4K, WOB 1.2, ROP 10 fph. P/U 3 times to get started on bottom. clean P/U weight - 26K. Losign roughly 3-4 bbls /hour. 21:00 23:00 2.00 8,805 8,805 PROD5 DRILL WPRT P Wiper trip - P/U weight 25K 23:00 00:00 1.00 8,805 8,861 PROD5 DRILL DRLG P Drilling ahead - 1.35 bpm, 4000psi, BHP 4150, ECD 12.7, WOB 1.4, CT weight 5K, ROP 50 fph. Total losses for 24 hours = 75 bbls 04/07/2010 Drille ahead to 9405'. POOh and P/U agitator & 1.0 AKO motor. 68 bbls lost for 24 hours. 00:00 01:30 1.50 8,861 8,960 PROD5 DRILL DRLG P Drilling ahead - 1.35 bpm, 4000psi, BHP 4160, ECD 12.7, ROP 70fph, CT weight 5K, WOB 2K. total 4 bbl /hour losses. Page 20 of 35 1 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 01:30 03:00 1.50 8,960 8,960 PROD5 DRILL TRIP P Wiper trip - 25K off bottom. Saw overpull @ 8800' while POOH. Saw 8800' when RIH. Correct TF, RIH with no problems 60 left. 03:00 05:00 2.00 8,960 9,110 PROD5 DRILL DRLG P Drilling ahead - 1.35 bpm, 4050psi, BHP 4180, ECD 12.8, ROP 65, WOB 1.8K, CT weight 4.5K. 05:00 05:54 0.90 9,110 7,580 PROD5 DRILL TRIP P Wiper trip to window. 05:54 06:06 0.20 7,580 7,590 PROD5 DRILL DLOG P Tie -in log. Correction = -2.5'. 06:06 07:00 0.90 7,590 9,110 PROD5 DRILL TRIP P Wiper back to bottom 07:00 13:45 6.75 9,110 9,260 PROD5 DRILL DRLG P Drilling ahead. 1.35 BPM, 4035 psi CTP, 4150 BHP, ECD = 12.94, ROP = 80 -110, WOB 1 - 2.75, CT WT = 2000 #. At 9151', PUW = 31K. RBIH, all ok but CT wt = - 1500#. Continue drilling ahead. At 9158', 6.9 ROP with 2.75 WOB. PU wt. = 24K. Continue drilling. At 9159', 6.7 ROP. PU WT = 26k. Continue drilling with very low ROP. 13:45 15:45 2.00 9,260 9,260 PROD5 DRILL TRIP P Wiper to window. PU WT = 26.5K 15:45 17:30 1.75 9,260 9,403 PROD5 DRILL DRLG P Drilling ahead - 1.36 BPM, 4000 CTP, 4240 BPH, 13.05 ECD, 500 - 1200 CT WT, WOB = 1.4 - 2.5, 100 - 150 ROP. Have been losing 5 bbls /hr all day. 17:30 20:30 3.00 9,403 71 PROD5 DRILL TRIP P Wiper trip to surface for BHA swap. 20:30 21:30 1.00 71 0 PROD5 DRILL PULD P Undeploy BHA 21:30 22:30 1.00 0 0 PROD5 DRILL PULD P Make up BHA # 22 with agitator & 1.0 AKO. 22:30 23:30 1.00 71 71 PROD5 DRILL PULD P Deploy BHA 23:30 00:00 0.50 71 9,403 PROD5 DRILL TRIP P RIH 04/08/2010 Drilled ahead to 9710'. While RIH after wiper trip could not make it past 7857'. POOH to swap to 1.4 AKO also lost comms with BHA while POOH. P/U new BHA & RIH - could not make it past 7857'. Orientated around in 15 degree increments - no luck. POOH to P/U dummy liner BHA. Total mud losses for past 24 hours = 28 bbls. to the formation. 00:00 02:00 2.00 9,403 9,403 PROD5 DRILL TRIP P RIH - Tie in +2 ft correction. Close EDC - RIH, small weight bobble @ 9280. Increased Claygaurd by 1% & lube 776 by .5 % while RIH. 02:00 05:00 3.00 9,403 9,560 PROD5 DRILL DRLG P P/U weight 25K. Start drilling - 1.30 bpm, circ 4300psi, BHP 4220, ECD 12.9, ROP 70, WOB 1k, CT weight 5.5K. Crossed fault @ 9518'. fluid losses slowed to 2 bbl /hour. 05:00 07:15 2.25 9,560 9,560 PROD5 DRILL TRIP P Wiper trip - P/U weight 27K. Page 21 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:15 10:30 3.25 9,560 9,710 PROD5 DRILL DRLG P Continue drilling - 1.25 BPM, 4250 CTP, 4230 BHP, 13.01 ECD, 1.2 - 1.9 WOB, 40 - 70 ROP, CT WT = -2K - 2K. Stalled @ 9616'. PU WT. = a clean 30K. At 9690' pump 5 bbls each low /high vis sweep. 10:30 13:30 3.00 9,710 7,858 PROD5 DRILL TRIP P Wiper trip - PU wt. = 28K. Space out so that sweeps are at bit when on bottom. All good. Slight increase in returns from sweeps. On way back in the hole stacked wt. @ 7855' (bottom of build section). Make several attempts to pass. PU wts. are clean. Making adjustments to TF each time. Continue to sit down @ 7858'. Shut down pumps and make serveral attempts. Discuss options with town. Pull up into tbg above window and open EDC. Increase pump rates to 1 bpm. 13:30 15:30 2.00 7,858 0 PROD5 DRILL TRIP T Begin to POOH for BHA swap. On way out of hole lost communication with BOT equipment. EDC still open. 15:30 20:00 4.50 0 71 PROD5 DRILL PULD T At surface. Space out BHA such that we can place open EDC below deployment ram. Undeploy BHA #22. Tested electronics. All OK in the CT. Problem area is BOT's equip. Deploy BHA #23. * ** 1.5 hrs of NPT time to BHI for failed BHA at surface * ** 20:00 22:00 2.00 71 7,857 PROD5 DRILL TRIP T RIH 300ft & test agitator. Open ECD - RIH. Tie in +2 ft correction. Close EDC. RIH through build pumping .3 bpm. 35 fpm - 60 Left. tagged up @ 7857'. P/U weight 25K. RIH HS, hard tag 7857', 30 right tag 7856.2'. Turn TF on bottom with light tag. P/U and try 180 - 7857' tag, Try 15 degree changes. 22:00 00:00 2.00 7,857 7,857 PROD5 DRILL TRIP T 15 degree changes starting @ 180 degree TF. No luck all the way around, P/U into cased hole and conference call. POOH for BHa change. 04/09/2010 P/U dummy linner BHA and try to RIH through 7857'. No luck with multiple tries /pump rates. P/U RSM with Bi- center and tried to drill into same lateral with no luck. Start new lateral @ 7855'. Mud losses for the past 24 hours = 12 bbls to the formation. 00:00 02:00 2.00 7,857 77 PROD5 DRILL TRIP T POOH for dummy liner assembly. 02:00 04:00 2.00 77 68 PROD5 DRILL PULD T Undeploy BHA & P/U dummy Liner assembly (BHA #25). Page 22 of 35 110 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:00 05:00 1.00 68 68 PROD5 DRILL CIRC T EDC open - pump at surface. Higher pressures. cycle EDC - still high pressures. Start undeploy procedure - Close rams - strip off to check ball valves. Fully opened. Strip down, tried to pump down again, still higher pressure. Problem above EDC to CT manifold. Start undeploy to check CT and upper Quick assembly. 05:00 08:45 3.75 68 68 PROD5 DRILL PULD T Break off CT - Pumped through CT @ surface - pressures are good. Undeploy BHA. Blow air at 100 psi through BHA with no problem. Inspect fluid ports on guide shoe, and all ok. There are a total of 4 size 16 ports. 08:45 10:30 1.75 68 7,395 PROD5 DRILL TRIP T Begin to RIH. Pumping 0.3 BPM @ 1780 psi. While RIH performed rate test through BHA. During the testing BHP's were held constant via the tripping schedule. Rates /pressure were: 0.3 @1800; 0.5 @1850; 0.72 @2000; 1.0 @2550; and 1.3 @3200. This was with the EDC open. All appear good. 10:30 10:36 0.10 7,395 7,409 PROD5 DRILL DLOG T Tie -in correction of +2'. 10:36 11:36 1.00 7,409 7,858 PROD5 DRILL TRIP T Close EDC and continue to RIH. Repeat rate /pressure test now that EDC is closed. Test results: 1.3 @3550 (3780 BHP); 0.75 @2350 (3861 BHP) ; 0.3 @1700 (3700BHP). Tagged up at 7857'. Increase pump rate to 1.3 BPM @ 3600#. Make several attempts. Back pump rate down to 0.7 and make several attempts. Drop to min at 0.22 BPM for several attempts. Unable to pass trouble spot at 7858'. Total of 24 attempts made. 11:36 14:10 2.57 7,858 0 PROD5 DRILL TRIP T Begin to POOH. 14:10 16:04 1.90 0 0 PROD5 DRILL PULD T At surface. PJSM. Undeploy BHA #25. 16:04 18:34 2.50 0 0 PROD5 DRILL SLPC T Prep floor for cutting CT. Cut 150' of CT. Make up CTC. Pull test CTC to 30K. Pressure test CTC to 4K. 18:34 20:34 2.00 0 0 PROD6 STK PULD T Injector inspection & Deploy BHA #26. 20:34 22:34 2.00 0 7,856 PROD6 STK TRIP T RIH pumping .4 bpm, following MPD. Tie +2 ft correction Page 23 of 35 • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 22:34 23:34 1.00 7,856 7,875 PROD6 STK KOST T Tag @ .5 bpm, P/U weight 25K. RIH @ .8 bpm, feather in from 7855'. Circ. press 2600, BHP 4000, Rib steer in off mode. 7855' - seeing WOB .5 K, circ. 3000 psi, BHP 3970, diff 767 psi. P/U & increase to 1.1 bpm - 3100psi free spin - 7855.2 - WOB .6K, - Stall again 4100 psi. P/U try 1.3 bpm. free spin 3580 - 7855.4' - WOB.7K, circ 3700psi, BHP 4088, dill 400psi, CT weight 10K, rib steer ON, ROP 6fph. Stick in nuetral - WOB 2.5 K, circ 3750, diff 600 psi, drilled off. 7856.8 break through - Circ press. dropped - Returns P/U to surface - WOB dropped off to 1 K, Drilled to 7859' P/U 30 ft stacked @ 8760' -P /U and drill again. Drilled 15 ft with no indication of main hole - looks like new hole being drilled. ROP 50 fph, 3800psi, diff press 600psi. WOB 2K. 7875' P/U - 25K weight. 23:34 23:59 0.43 7,875 7,875 PROD6 DRILL TRIP T P/U and tried a run with no luck. Decision looks like a new hole is drilled startign @ 7856'. POOH to cased hole to reset parameters on BHI display and DD set up drilling paremeters. 04/10/2010 Drilled ahead in L2 lateral. Perfromed mud swap & recorded 57 bbls losses for 24 hours. 00:00 01:00 1.00 7,875 7,875 PROD6 DRILL TRIP T POOH slowly to case hole, pump B /U. Sit and reset BHI display and DD work out drilling paremeters. RIH back to bottom. Order new mud. 01:00 04:45 3.75 7,875 8,025 PROD6 DRILL DRLG T Drilling ahead - 1.35 bpm, 4000 psi, BHP 4130, ECD 12.6, WOB 1.57, Ct weight 7.7K, ROP 40. Assumption we are to the right of the original hole. 04:45 05:30 0.75 8,025 8,025 PROD6 DRILL WPRT T Wiper trip - P/U weigth 25K. 05:30 08:30 3.00 8,025 8,175 PROD6 DRILL DRLG T Drilling ahead - 1.35 BPM, 4000 CTP, 4100 BHP, 12.65 ECD, 1.75 -2.75 WOB, 8K CT WT, 30 -60 ROP, 200 -300 motor work. 08:30 09:15 0.75 8,175 8,175 PROD6 DRILL WPRT T Wiper trip to window. PU wt. = 28K (RSM pads still engaged). 09:15 12:39 3.40 8,175 8,325 PROD6 DRILL WPRT T Drilling ahead - 1.35 BPM, 4100 CTP, 4180 BHP, 12.75 ECD, 1.75 - 3 WOB, 3 -7K ct wt, 30 -60 ROP, -200 motor work. 12:39 13:09 0.50 8,325 7,578 PROD6 DRILL WPRT T Wiper trip for tie in. PU wt = 27K. 13:09 13:15 0.10 7,578 7,595 PROD6 DRILL DLOG T Tie in correction = +.5' 13:15 13:45 0.50 7,595 8,325 PROD6 DRILL WPRT T Wiper trip back to bottom. Page 24 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 13:45 16:15 2.50 8,325 8,475 PROD6 DRILL DRLG T Drilling ahead - 1.35 BPM, 4080 CTP, 4275 BHP, 13.05 ECD, 4000 CT WT, 1.5 -3 WOB, 30 -60 ROP, 200 -300 motor work. At 8330' (13:45) swapped to new mud. 16:15 17:00 0.75 8,475 8,475 PROD6 DRILL WPRT T Wiper trip to window. PU wt = 27K. 17:00 19:00 2.00 8,475 8,625 PROD6 DRILL DRLG T Drilling ahead 19:00 20:00 1.00 8,625 8,625 PROD6 DRILL WPRT T Wiper trip to window P/U 26K 20:00 23:00 3.00 8,625 8,775 PROD6 DRILL DRLG T Drilling ahead - 1.40 bpm, 4000psi, BHP 4080, ECD 12.5, WOB 2.4, CT weight 2K, ROP 30 - 40. Heavy oil embedded in sand samples from 8500 - 8650'. 23:00 00:00 1.00 8,775 8,775 PROD6 DRILL WPRT T Wiper trip with tie in. - 3ft correction. 04/11/2010 Drilled ahead to 9412' slow drilling from 9100 to 9430'. Pulled up to cased hole to have Safety Discussion with both ric crews at 17:30 hrs. 25 bbls losses for 24 hours. 00:00 01:00 1.00 8,775 8,775 PROD6 DRILL WPRT T Wiper trip with -3 ft correction 01:00 03:30 2.50 8,775 8,925 PROD6 DRILL DRLG T Drilling ahead - 1.40 bpm, 3900psi, BHP 4090, ECD 12.5, ROP 40, WOB 2.1, Ct weight 6K. 03:30 05:30 2.00 8,925 8,925 PROD6 DRILL WPRT T Wiper trip - 28K P/U weight. 05:30 07:15 1.75 8,925 9,075 PROD6 DRILL DRLG T Drilling ahead - 1.43 BPM, 3900 CTP, 4100 BHP, 12.68 ECD, 50 -110 ROP, 1.4 -2.4 WOB, 6K CT WT. 07:15 09:00 1.75 9,075 9,075 PROD6 DRILL WPRT T Wiper trip - 29K PU wt. 09:00 12:40 3.67 9,075 9,225 PROD6 DRILL DRLG T Drilling ahead - 1.40 BPM, 3950 CTP, 4108 BHP, 12.58 ECD, 40 -60 ROP, 2.5 -3.0 WOB, 850 CT WT. 12:40 13:40 1.00 9,225 7,657 PROD6 DRILL WPRT T Wiper trip - 31 K PU wt. 13:40 13:55 0.25 7,657 7,600 PROD6 DRILL DLOG T Tie -in correction = -.5' 13:55 14:55 1.00 7,600 9,225 PROD6 DRILL WPRT T Wiper trip back to bottom. 14:55 16:10 1.25 9,225 9,298 PROD6 DRILL DRLG T Drilling ahead - 1.40 BPM, 4155 CTP, 4108 BHP, 12.78 ECD, 40 -60 ROP, 1 -3.0 WOB, 3 -4K CT WT. 16:10 17:28 1.30 9,298 7,530 PROD6 DRILL SFTY P Wiper trip to window for stand up safety meeting 17:28 18:28 1.00 7,530 7,530 PROD6 DRILL SFTY P PJSM, Park CT in cased hole for Stand up safety meeting. Hold managed pressure during meeting pumping 0.5 bpm. 18:28 19:58 1.50 7,530 9,298 PROD6 DRILL SFTY P RIH 19:58 23:59 4.03 9,298 9,412 PROD6 DRILL DRLG T Drilling ahead - 1.32 bpm, 4100psi, BHP 4190, ECD 12.8, ROP 20, WOB 2.2, CT weight 5K. Hit ankerite @ 9300'. Poor drilling most of the night. 04/12/2010 Drilled ahead to 10,013. Mud swap with 1590 ft. drilled on system. Page 25 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 00:00 01:18 1.30 9,412 9,450 PROD6 DRILL DRLG T Drilling ahead - slow ROP in until we cross the fault @ 9430'. Drilling break @ 9440' 01:18 04:18 3.00 9,450 9,450 PROD6 DRILL WPRT T Wiper trip - P/U weight 32K off bottom - cleaned up to 28K. RIH tagged up early @ 9425'. P/U and RIH slowly. 04:18 08:18 4.00 9,450 9,552 PROD6 DRILL DRLG T Drilling ahead - 1.40 bpm, 4000psi, BHP 4150, ECD 12.8, ROP 6 -50, WOB 2K, CT weight 5.5K. Good Rop until 9525' then slowed to 8 fph. 08:18 08:45 0.45 9,552 9,564 PROD6 DRILL DRLG T Break through Ankerite 08:45 09:00 0.25 9,564 9,620 PROD6 DRILL DRLG T Increased ROP, Drilling ahead - 1.40 bpm, 4130psi, BHP 4222, ECD 12.9, WOB 2K, CT weight 0 -1 K. ROP 75 -100 FPH. 09:00 11:00 2.00 9,620 7,560 PROD6 DRILL WPRT T Wiper trip to window 11:00 11:15 0.25 7,560 7,562 PROD6 DRILL DLOG T Tie in depth to RA marker. Correction= -1.5' 11:15 12:45 1.50 7,562 9,620 PROD6 DRILL WPRT T RIH to Drill 12:45 14:00 1.25 9,620 9,780 PROD6 DRILL DRLG T Drilling ahead - 1.40 bpm, 4130psi, BHP 4222, ECD 12.9, WOB 2K, CT weight 0 -1 K. ROP 75 -100 FPH. 14:00 16:15 2.25 9,780 9,780 PROD6 DRILL WPRT T Wiper Trip to 7875'. 16:15 20:15 4.00 9,780 9,940 PROD6 DRILL DRLG T Drilling ahead - 1.40 bpm, 4230psi, BHP 4242, ECD 13, WOB 2K, CT weight 0-1K. ROP 75 -100 FPH. Slower ROP 20 - 30 from 9810', get set up for a mud swap. 20:15 22:30 2.25 9,940 9,940 PROD6 DRILL WPRT T Pump low /high sweep prior to wiper - P/U weight 30K Wiped up to 7900' to stay above shale area. Start pumping new mud RIH due to higher pressures and slow ROP's. (mud .8 % solids 1590 ft drilled). 22:30 00:00 1.50 9,940 10,013 PROD6 DRILL DRLG T Drilling ahead - new mud at bit. 1.40 bpm, 3900 psi, BHP 4140, ECD 12.7, ROP 70, WOB 2.2k, CT weight 6K. Had to P/U and re -boot BHI computer, correct +20ft continue drilling ahead @ 9970'. 04/13/2010 TD Well @ 10085, Run Liner to 10058', TOL @ 7701 Start BOPE Test. Witness waived by Jeff Jones 00:00 02:00 2.00 10,013 10,100 PROD6 DRILL DRLG T Drilling ahead - 1.40 bpm, 4000 psi, BHP 4160, ECD 12.7, ROP 40, WOB 2.6K, Ct weight 4K. Pump High /Low visc sweep on bottom 02:00 04:15 2.25 10,100 7,580 PROD6 DRILL WPRT T Wiper trip chasing sweep. P/U weight 30K. Pulled heavy @ 7830' 04:15 04:36 0.35 7,580 7,900 PROD6 DRILL WPRT T RIH to 7900' .75 BPM, 40FPM, POOH to window, Looks Good 04:36 04:51 0.25 7,900 7,580 PROD6 DRILL DLOG T Tie in Depth to RA marker -17' correction 04:51 06:03 1.20 7,580 10,085 PROD6 DRILL WPRT T RIH to TD. Page 26 of 35 s Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:03 08:48 2.75 10,085 0 PROD6 DRILL WPRT T Tag TD 10085'. POOH laying in Liner pill with Alpine beads chasing with KWF 08:48 09:03 0.25 0 0 PROD6 DRILL OWFF T Check for flow, Hold PJSM 09:03 10:03 1.00 0 0 PROD6 DRILL PULD T Looks good LD BHA - 10:03 13:33 3.50 0 2,400 COMPZ CASING PUTB T Safety meeting - P/U liner - safety joint drill 4 stands in 2 min. 45 secs. P/U 73 joints of liner in total. 13:33 14:33 1.00 2,400 2,400 COMPZ CASING PULD T P/U Coiltrak BHA - set in rams & strip over injector. 14:33 16:33 2.00 2,400 10,058 COMPZ CASING RUNL T RIH pumping . 3 bpm. Correct @ flag depth EOP. BHI depth + 4.5 ft. P/U weight 27K. above window. smooth through window. CT weight 13K RIH down to 10068' P/U 10 ft, Ct weight 35K.Set depth 10058' bottom & Liner top - 7701' 16:33 17:03 0.50 10,058 7,564 COMPZ CASING DLOG T P/U pump rate to 1.3 bpm, pressure 4200 psi, P/U and release off liner. _ CTT weight 23K. Stop pumping - POOH to RA tag for tie. Correction depth +1 ft. Liner top @ 7701'. Correct BHA depth. 17:03 18:33 1.50 7,564 0 COMPZ CASING TRIP T POOH - pumping KWF 18:33 18:51 0.30 0 0 COMPZ CASING SFTY T PJSM / Monitor well for flow. Well is dead 18:51 19:45 0.90 0 0 COMPZ CASING PULD T Pull off well and lay down BHA 27. 19:45 00:00 4.25 0 PROD7 STK BOPE T Begin Bi Weekly full BOPE witnes waived by Jeff Jones. AOGC 04/14/2010 / Complete Full BOPE test. Set Anchored Billit (a), 7701, P/U drill by BHA. Time mill off billit, drill build _ f/"� 00:00 04:45 4.75 0 0 PROD7 STK BOPE T Continue testing BOPE Witness waived by Jeff Jones AOGC. Test completed @ 0400, Install Checks back in UQC, Roll Coil back to KWF, Remove injector from well 04:45 06:45 2.00 0 73 PROD7 STK PULD T PJSM, M/U anchored billit BHA and Coil Trak BHA #28 06:45 08:45 2.00 73 7,700 PROD7 STK TRIP T RIH with EDC open pumping .3bpm. Tie in with +2 ft correction. Stop pumping and close the EDC. RIH through window. weight check @ 7695' - 26K. Orientate HS. Tag TOL @ 7700' - TOB @ 7689'. P/U neutral weight and bring pumps online. Anchor set at 3500 psi. POOH to window. 08:45 10:45 2.00 7,700 0 PROD7 STK TRIP T POOH pumping KWF. 10:45 11:45 1.00 0 0 PROD7 STK PULD T Lay down Billet BHA & P/U Build BHA with 2.5 AKO. Billet setting tool looked good, all parts intact. Page 27 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 11:45 15:00 3.25 0 7,688 PROD7 STK TRIP T RIH pumping with EDC open. Swap well over to flow pro on bottom.Close EDC - RIH through window. 15:00 18:30 3.50 7,688 7,698 PROD7 STK KOST T Dry Tag TOB @ 7688.8' P/U weigth 26K, start pumping 1.4 bpm. 3700psi, BHP 4000, ECD 12.4, CT weight 7K, WOB .6 - milling lfph from 7688.4'. Stall @ 7888.7' P/U and start again. 18:30 18:45 0.25 7,698 7,700 PROD7 STK KOST T Going to 20 Ft/Hr, Pull up past billit. Looks good Drill to 7700. Wipe up to window 23 K PUW, 1.4 BPM @ 3940 FS 18:45 19:45 1.00 7,700 7,520 PROD7 STK WPRT T 7520, Pulled up through window, open EDC, circulate while waiting on well plan 11 19:45 20:00 0.25 7,520 7,700 PROD7 STK WPRT T Close EDC, RIH to drill build 20:00 21:27 1.45 7,700 7,752 PROD7 DRILL DRLG T 7700, Drill ahead RIW =12k 1.4 BPM @ 3848 PSI FS BHP =4006 21:27 23:27 2.00 7,752 7,810 PROD7 DRILL DRLG T 7752, Taking losses 1.49 in .5 BPM Out P/U off bottom and confirm rates, Annular dropped 175 PSI Go back to bottom and drill, Losses steadiliy improving BHP =3825 23:27 23:42 0.25 7,810 7,818 PROD7 DRILL DRLG T 7810, Losses have healed to 1.1BPM out, 1.49 In BHP =3990, ECD =12.1 Slow ratty drilling, ROP = 5 to 15 FPH 7.2K RIW, 3k DH WOB 23:42 00:00 0.30 7,818 7,818 PROD7 DRILL DRLG T Midnight depth 7818 Landed @ 7810 TVD= 6321.69 1.8' high of plan, Continue to turn. Avg DLS 50.5 Loss rate @ .25 BBI /Min 04/15/2010 Complete build /turn section @7864. Drill intermidiate section to 8227 00:00 02:00 2.00 7,818 7,864 PROD7 DRILL DRLG T Drill by section landed with turn 1.44 BPM @ 3820 PSI FS 1.15 BPM Returns BHP =3980, ECD =12.12 02:00 02:09 0.15 7,864 7,500 PROD7 DRILL TRIP T Trip out of well 02:09 02:30 0.35 7,500 7,500 PROD7 DRILL TRIP T Stop above window, Trap 700 PSI, Shut down pump to open EDC Well taking fluid @ 550 PSI WHP. Shut in well and monitor for static BHP Stactic pressure @ window 3690 02:30 03:30 1.00 7,500 0 PROD7 DRILL TRIP T Trip out of well 03:30 03:45 0.25 0 0 PROD7 DRILL TRIP T At surface, Close EDC Page 28 of 35 • 1 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 03:45 04:45 1.00 0 0 PROD7 DRILL PULD T PJSM to pressure undeploy. Unable to maintain 700 PSI WHP. Well static @ 425. Will start MPL @ 500 PSI Lost 10 BBIs on trip out 04:45 07:15 2.50 0 72 PROD7 DRILL PULD T Load Motor in well. Make up pre loaded BHA - crew change and complete deploying BHA with 1.3 AKO 07:15 10:03 2.80 72 7,864 PROD7 DRILL TRIP T RIH holding MP schedule, pumping .8 bpm through open EDC. Tie in +2 ft correction, Close EDC RIh through window to TD 10:03 12:33 2.50 7,864 8,015 PROD7 DRILL DRLG T Drilling ahead - 1.40 bpm, 3800 psi, BHP 3996psi, ECD 12.2, ROP 65, WOB 1.8, Ct weight 7800, rate out 1.2. 12:33 13:15 0.70 8,015 8,015 PROD7 DRILL WPRT T Wiper trip - Ct weight 26K off bottom. Losing roughlyt 16 bbls an hour. 13:15 15:15 2.00 8,015 8,165 PROD7 DRILL DRLG T Drilling ahead - 1.40 bpm, 4000psi, BHP 4050, ECD 12.4, ROP 60, WOB 2.5, Ct weight 5K, Rate out 1.25 bpm. Losses are down to 10 -12 bbls hour. 15:15 17:00 1.75 8,165 8,165 PROD7 DRILL WPRT T Wiper trip Mad pass with Tie in. P/U weight 25K. 17:00 19:30 2.50 8,165 8,227 PROD7 DRILL DRLG T 8165', Drill ahead 1.40 BPM @ 4100 PSI FS RIW =6.6 DH WOB =1.5K BHP =4086 19:30 21:30 2.00 8,227 0 PROD7 DRILL TRIP T 8227, TD Intermediate build, POOH PUW =30K 21:30 00:00 2.50 0 0 PROD7 DRILL PULD T PJSM, Lay down BHA #30, P/U BHA #31 Surface test tool, 04/16/2010 M/U .9 Degree motor, Found debrie in injector sump during service. Observed dimples on coil while RIH. POOH to replace skates 00:00 00:27 0.45 0 0 PROD7 DRILL PULD T M/U and test tool BHA #31 with 0.9 degree motor 00:27 02:27 2.00 0 7,590 PROD7 DRILL TRIP T RIH 02:27 02:33 0.10 7,590 7,604 PROD7 DRILL DLOG T Log Gamma Tie in for a +1 foot correction, RIH 02:33 02:48 0.25 7,604 8,227 PROD7 DRILL TRIP T RIH to Drill, Set down at 8178 (tool face change) P/U and rih 02:48 04:01 1.23 8,227 8,300 PROD7 DRILL DRLG T 8227', Drill Ahead 1.43 BPM @ 3840 FS BHP =4150 RIW =7.7K with 1.6K WOB 04:01 06:25 2.40 8,300 8,379 PROD7 DRILL DRLG T 8300' Drilling Lost 10 BBIs since midnight No new pipe markings while on bottom drilling. Page 29 of 35 • 1 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 06:25 07:25 1.00 8,379 8,379 PROD7 DRILL WPRT T Wiper trip - 26K off bottom. Watch for pipe markings and they start @ 8215' - Markings Indicates obstructions was in the chains POOH during yesterday's trip to surface. 8215' is BHA depth minus BHA = 8143' EOP. 07:25 09:25 2.00 8,530 8,530 PROD7 DRILL DRLG T Drilling ahead - 1.35 bpm, BHP 4100, ECD 12.6, ROP 80, WOB 2.5, CT weight 1K, Out rate 1.20 09:25 12:25 3.00 8,530 71 PROD7 DRILL TRIP T Wiper trip - P/U weight 27K. Saw a slight weight bobble @ 8215' at surface. Decision made to POOH and change skates on injector head. Stopped and measured depth of inditations..065" POOH following Manged pressure schedule. 12:25 13:59 1.57 71 0 PROD7 DRILL PULD T CT @ surface - Safety meeting & Start undpleoying BHA. Lay down Motor & bit. Set up on Managed A L� Pressure for Pipe stabbing. keeping 550 psi on WHP injecting roughly 2 -3 bbl /hour. 13:59 15:59 2.00 0 0 PROD7 DRILL RGRP T Pre -job for cutting CT and unstabbing pipe. Unstab coil and secure to reel 15:59 17:59 2.00 0 0 PROD7 DRILL RGRP T PJSM Remove stripper from injector 17:59 19:59 2.00 0 0 PROD7 DRILL RGRP T PJSM Remove railings and guards from Injector. Inspect gripper block and chains for debrie 19:59 22:29 2.50 0 0 PROD7 DRILL RGRP T Remove Goosneck tilt cylinder, roll chains out, remove skates 22:29 23:59 1.50 0 0 PROD7 DRILL RGRP T Clean injector sump, Inspect injector for foreign objects Prep for skate instal - Total 24 Hr Fluid loss 61 BBIs 04/17/2010 Complete injector skate chage out. Perform slack mgmt. RIH and drill 00:00 01:30 1.50 0 0 PROD7 DRILL RGRP T Skates installed Check gooseneck rollers and lubricate. Continue to pump down MPL. 01:30 03:30 2.00 0 0 PROD7 DRILL RGRP T Install stuffing box, inspect stuffing box brass 03:30 04:30 1.00 0 0 PROD7 DRILL RGRP T PJSM, Rig up and stab coil into injector 04:30 05:00 0.50 0 0 PROD7 DRILL RGRP T PJSM, Install new packoffs, seal end of eline, Reverse circulate water into coil 05:00 07:30 2.50 0 0 PROD7 DRILL SLPC T Perform slack mngt - Cut 10 ft of coil off. 7 ft to find the cable. 07:30 10:00 2.50 0 0 PROD7 DRILL RGRP T Re -head CT connector, pressure & pull test. Continue pumping down MPL. injecting 2 bbl /hour @ 550 psi. 10:00 12:00 2.00 0 0 PROD7 DRILL RGRP T Begin Deploying BHA (same BHA as last run). Page 30 of 35 • i Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 12:00 13:15 1.25 0 7,400 PROD7 DRILL TRIP T Start RIH, check SSSV & pressure guages. RIH 200 ft. Stop - problems with choke sequence. 13:15 13:30 0.25 7,400 7,413 PROD7 DRILL DLOG T Perform TIE -In log from 7398' do To 7410.39. + 3' Correction. Corrected depth = 7413.39. PUH 100' to check Injector & Coil tubing for marks or damage. 13:30 13:45 0.25 7,413 7,313 PROD7 DRILL TRIP T PUH 100' to check Injector & Coil Tubing for marks or Damage before going thru Window. 13:45 14:15 0.50 7,313 8,171 PROD7 DRILL TRIP T Stop & Trap 500 psi and Close EDC. Continue Tripping in hole thru Window. Inspecting pipe while RIH. 14:15 15:45 1.50 8,171 8,150 PROD7 DRILL CIRC T Tagged up @ 8171', WOB 3.5K, P/U weight 35K, backed pump rate down. RIH, orient TF, RIH 15 fpm, tagged @ 8159', P/U 100ft. RIH to 8158' tagged up, WOB 2K, P/U 60 ft. RIH 125right, made it to 8161' tag up. RIH down to 8150' slow speed to 7 fpm, slow pump rate to .8 bpm, and try to steer through. Made it to 8181' P/U pulled heavy. Slack off, ciculate to get 1:1. Continue working pipe with pump rates and slower POOH speeds. 15:45 16:27 0.70 8,150 8,180 PROD7 DRILL WPRT T Popped free increase pump rate to 1.3. Wipe up to window. Looks like clay returns over shaker. Pump low /high pill to get © nozzle on bottom. 16:27 17:27 1.00 8,180 8,180 PROD7 DRILL WPRT T 8155' Light tag, P/U - lower pump rate - RIH to 8160' - P/U light over pull 31 K, Increase pump rate to 1.4 while BHA wiper - RIH 8170' - P/U 31K BHA wipe, RIH to 8180' - Drag @ 37K for 15ft- BHA wiper. RIH to 8170' Clean P/U wipe up to 7720' - Add drill zone to low visc sweep - RIH for another bite while mixing up sweep. 17:27 18:15 0.80 8,180 8,200 PROD7 DRILL WPRT T RIH down to 8190' @ 1 bpm. Looked clean in /out. P/U weight 27K Wiper to 8100'. RIH to 8200'. Stacked @ 8196' P/U 29K to 8100'. RIH to 8200'. Wiper up to 7720' for hand -over and sweep is ready to pump. 18:15 20:00 1.75 8,200 8,531 PROD7 DRILL WPRT T Pump sweep - RIH. Tag @ 8199 twice, Reduce rate to .5 BPM RIH clean to 8146. PUH @ 5 FPM slight motor work @ 8198 & 8188. Turn around @ 8180 at full pump rate. Stack out @ 8260, 8294, 8324, 8390, Pump sweep and pull back up to 8380. Worked all areas where set down Page 31 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 20:00 21:45 1.75 8,531 8,670 PROD7 DRILL DRLG T 8531', Drill ahead 1.33 BPM @ 3835 PSI FS RIW =2.5, DHWOB =1.9 BHP =4040 21:45 23:15 1.50 8,670 8,670 PROD7 DRILL WPRT T 8670, Sweeps coming out of bit, wipe to 7695 PUW =28k, Overpull with motor work @8150 Bobble @8199 going in. Full pump rate going in 23:15 00:00 0.75 8,670 8,726 PROD7 DRILL DRLG T 8670', Drill Ahead 1.35 BPM @ 3610 PSI FS Lost 99 BBIs to formation 04/18/2010 Drilled from 8958 to 9555 00:00 01:12 1.20 8,726 8,815 PROD7 DRILL DRLG T Drilling Ahead 1.35 BPM @ 3610 PSI FS 01:12 02:45 1.55 8,815 8,815 PROD7 DRILL WPRT T 8815 Wiper to window, with low high sweep PUW =30K 1.37 BPM @ 3720 BHP =4039 Motorwork 8182 & 8141 with light overpulls Clean run in at full pump rate 02:45 04:45 2.00 8,815 8,958 PROD7 DRILL DRLG T 8815, Drill Ahead 1.35@ 3670PSI FS RIW =6.7K with 1.6K DH WOB, BHP =4090 ROP 75 FPH 04:45 05:45 1.00 8,958 7,580 PROD7 DRILL WPRT T 8958 Wiper to window with 5 & 5 low high sweep 1.34 BHP @3630 PSI FS BHP =4103 Light motor work 8181 -8142 PUH and 8145 -8190 RIH 05:45 07:00 1.25 7,580 8,958 PROD7 DRILL DLOG T Tie into RA Tag. -.5 ft correction. Continue Back down to last drill depth. 07:00 08:45 1.75 8,958 9,050 PROD7 DRILL DRLG T 8959, Drill Ahead 1.35 bpm @ 3940 psi BHP =4168 psi RIW= 6.6K w/1.68k DH WOB ROP= 38 - 50 fph 08:45 09:30 0.75 9,050 9,110 PROD7 DRILL DRLG T Pick -up and made tool face change. Up Wt =27k. Continue w/ drilling operation. 09:30 11:48 2.30 9,110 9,110 PROD7 DRILL WPRT T 9110 Wiper to Window. PUW =29k 1.36 bpm @ 3730 psi BHP =4173 / Seen small overpull 8150' 11:48 14:03 2.25 9,110 9,161 PROD7 DRILL DRLG T 9110 Drill Ahead 1.4bpm @ 4028 psi RIH Wt= 9k WOB While Drilling= 1.78k ROB =65 -80 fph. Seen no problems while Tripping In Hole. Page 32 of 35 . 1 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 14:03 14:33 0.50 9,161 9,215 PROD7 DRILL DRLG T Drilling Break Around 9161' ROP Down from 76 fph to 33 fph. 1.4 bpm @ 4075 psi WOB =1.6k to 1.9k Possible Fault area. 14:33 14:48 0.25 9,215 9,215 PROD7 DRILL WPRT T BHA Wiper Trip across slow drilling area from 9158' - 9215' Up Wt =28k 1.4 bpm / 3988 psi 4192 psi BHP 14:48 15:48 1.00 9,215 9,260 PROD7 DRILL DRLG T BHA Wiper Trip Look Good. 9215 Drill Ahead. 1.4 bpm @ 4040 psi ROP down to 10 - 15 W /2.4k WOB 15:48 18:03 2.25 9,260 9,260 PROD7 DRILL WPRT T 9260' Wiper To Window, W/ 10 & 10 low -high sweep PUW =28.5k 1.41 bpm @ 3875 psi BHP =4144 Seen slight over -pull again 8150' 18:03 19:33 1.50 9,260 9,408 PROD7 DRILL DRLG T 9260' Drill Ahead 1.32 BPM @ 3770 PSI FS BHP =4264 19:33 22:03 2.50 9,408 9,408 PROD7 DRILL WPRT T 9408, wiper to window with lo high sweep and tie in pl PUW =32k /11;11 � Clean trip up, Set down @ 8202, tool face change, went right through Correct -2 at RA Tag 22:03 23:48 1.75 9,408 9,555 PROD7 DRILL DRLG T 9408 Drill Ahead 1.35 BPM @ 3750 PSI FS RIW = -8k, DHWOB= 2K 23:48 00:00 0.20 9,555 9,550 PROD7 DRILL WPRT T 9555 Wiper to Billit with sweeps PUW =32K 04/19/2010 TD AL2 -01 Lateral @ 9765 M/U and Run liner to 9765, TOL =7542, Roll well to Seawater, F/P from 2100' 00:00 01:30 1.50 9,555 9,555 PROD7 DRILL WPRT T Contine on wiper from 9555 Motor work @ 8140 on way up Set down @ 8202, Adj. TF and clean pass through 01:30 03:30 2.00 9,555 9,705 PROD7 DRILL DRLG T 9555, Drill Ahead 1.3 BPM @ 3980FS RIW = -4K, 2K WOB BHP =4216 Swap to new mud 3% Clay Guard 2011' on system 03:30 05:15 1.75 9,705 9,705 PROD7 DRILL WPRT T Wiper trip to Billit PUW =30K 05:15 06:00 0.75 9,705 9,765 PROD7 DRILL DRLG T Continue drilling down to TD @ 9765' RIW= -3.6k 1.35 bpm / 3930 psi BHP =4182 psi 06:00 07:45 1.75 9,765 7,580 PROD7 DRILL WPRT T Wiper Trip To Window w/5 & 10 low - high sweep. Up Wt =30k 1.4 bpm @ 3882 psi. Motor Work @ 8185' & 8148' and slight over pull. Page 33 of 35 • • Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 07:45 08:00 0.25 7,580 7,601 PROD7 DRILL DLOG P Tie -In with GR from 7580' to 7602.27'. Had -1 correction. New Corrected depth= 7601.27' 08:00 09:15 1.25 7,601 9,765 PROD7 DRILL TRIP P Continue in hole to TD Maintaining MB. RIH Wt =11k 1.3 bpm @ 3670 psi. BHP =4022 psi. 09:15 10:30 1.25 9,765 9,765 PROD7 DRILL DISP P RIH to TD @ 9765'. Liner Pill @ Bit. PUH Laying in 1 for 1 pumping @ .45 bpm @ 50 fpm follow MPS UP WT =32k CTP =2225 psi. BHP =3905 psi 10:30 11:00 0.50 9,765 7,472 PROD7 DRILL DISP P Stop & Paint Flag @ 7472'. Continue to PUH Laying in 12.0 ppg KWF 1 for 1. Up Wt =20k CTP= 2200psi @ 1.1 bpm 11:00 11:45 0.75 7,472 5,272 PROD7 DRILL DISP P Stop & Paint Flag @ 5272'. Continue to POOH laying in 12.0ppg KWF @ 1 for 1 Up Wt =15k CTP =2344 @ 1.1 bpm. 11:45 12:00 0.25 5,272 0 PROD7 DRILL OWFF P OOH With KWF @ surface. Observe Well for flow. 12:00 12:15 0.25 0 0 PROD7 DRILL SFTY P Hold PJSM on removing Drilling BHA. No Flow On Well 12:15 13:45 1.50 0 0 PROD7 DRILL PULD P Start Removing BHA from well. 13:45 18:45 5.00 0 0 COMPZ CASING PUTB P Held PJSM. Start Picking Up 2 3/8" Liner 18:45 19:09 0.40 0 0 COMPZ CASING PULD P PU coil track, M/U to liner, stab on well and surface test tool 19:09 20:35 1.44 0 2,267 COMPZ CASING RUNL P RIH with liner 20:35 20:47 0.20 2,267 7,466 COMPZ CASING DLOG P Tie into flag for +6' correction Wt Chk 27K, RIH 20:47 23:02 2.25 7,466 9,765 COMPZ CASING RUNL P Tag bottom, PUW =42K, Set liner back on bottom Pump 1.3 BPM @ 4168 Pull up to 24K liner released Pull up 20' Pump 5 BBL hi vis spacer followed by seawater 23:02 23:32 0.50 9,765 9,585 COMPZ CASING DLOG P 9739 tie into formation -1 foot correction 23:32 23:59 0.46 9,585 4,000 COMPZ CASING TRIP P POOH Line up little LRS to freeze protect coil from 2100' 04/20/2010 FP well, set BPV, Rig Down. Rig released at 18:00. 00:00 01:30 1.50 4,000 0 COMPZ CASING TRIP P Continue tripping out of well, Freeze protect from 2100' 01:30 02:00 0.50 0 0 COMPZ CASING SFTY P OOH.Spaceout, PJSM 02:00 03:45 1.75 0 0 COMPZ CASING PULD P UnDeploy BHA #33 03:45 04:00 0.25 0 0 DEMOB WHDBO SFTY P PJSM On Steps for Setting BPV. Page 34 of 35 Time Logs Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment 04:00 05:00 1.00 0 0 DEMOB WHDBO NUND P Pick -Up Equipment & Set BPV 05:00 06:00 1.00 0 0 DEMOB WHDBO NUND P Set BPV & Tested. BPV didn't test.. Pull BPV & Check 0-Ring. 06:00 08:00 2.00 0 0 DEMOB WHDBO NUND T Found that the rubber o -ring on BPV had rolled off of plug. Call out sucker rod x -over to try and used a wireline brush to fish out rubber seal from tree. 08:00 10:00 2.00 0 0 DEMOB WHDBO NUND T No luck fishing out rubber o -ring. Bushed profile several times and made another attempt to set BPV. Seen good set and tested plug. Good test on BPV. Rig down / lay down BPV lubricator 10:00 11:00 1.00 0 0 DEMOB WHDBO CIRC P Rig Injector and coil back to well to wash tree stack & BOPE. 11:00 12:00 1.00 0 0 DEMOB WHDBO NUND P Blow down Coil and Rig with 350 PSI Compressor 12:00 13:00 1.00 0 0 DEMOB WHDBO SFTY P Safety stand down / discuss incidents from last 36 Hours, Head injury, finger injury, shoulder strain, Spill. Communicate, think before act 13:00 18:00 5.00 0 DEMOB WHDBO NUND P Rig down cellar, MP Line, Transducers. " "" Rig Released "" Waiting on trucks for move. Wait time will be charged to 1Q-03 I I Page 35 of 35 Conoc�Phillips Alaska ConocoPhillips(Alaska) Inc. • Kuparuk River Unit Kuparuk 1E Pad 1E-15A 50- 029 - 20769 -01 Baker Hughes INTEQ Fa k • Definitive Survey Report rt BAKER p HUGHES 21 April, 2010 ).,-- Conoco Phillips Wake Conoco Phillips Definitive Survey Report BAKER HUGHES Alaska I Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: 1E Project: Kuparuk River Unit TVD Reference: 1E-15 @ 105.70ft (1E-15) ; Site: Kuparuk 1E Pad MD Reference: 1E-15 @ 105.70ft (1E-15) Well: 1E North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature Design: 1E-15 Database: EDM Alaska Prod v16 _ — _ — ----1 Project Kuparuk River Unit 1 I Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point I Map Zone: . Alaska Zone 04 Using geodetic scale factor Well 1E-15 Well Position +N/ 0.00 ft Northing: 5,960,029.95ft Latitude: 70° 18' 5.686 N +E/ 0.00 ft Easting: 549,710.04ft Longitude: 149° 35' 50.538 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft _ . ; Wellbore 1E Magnetics Model Name Sample Date Declination Dip Angle Field Strength (1 ( (nT) BGGM2009 3/25/2010 17.33 79.80 57,371 Design 1E-15A Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 7,600.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction • (ft) (ft) (ft) ( 105.70 0.00 0.00 304.35 Survey Program Date From To Survey Survey (ft) (ft) Survey (Wellbore) Tool Name Description Start Date End Date 200.00 7,600.00 1E-15 (1E-15) FINDER-MS SDC Finder multishot 8/25/2000 , 7,632.00 9,744.85 1E-15A (1E-15A) MWD MWD - Standard 3/18/2010 3/21/2010 1 — — 4/21/2010 10:47:58AM Page 2 COMPASS 2003.16 Build 69 M ConocoPhillips Ci ConocoPhillips Definitive Survey Report BAICER HUGHES Alaska � Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference; 1 E - 15 I Project: Kuparuk River Unit TVD Reference: 1E-15 @ 105.70ft (1E-15) ! Site: Kuparuk 1E Pad MD Reference: 1E-15 © 105.70ft (1E-15) I Well: 1E North Reference: TRUE i Welibore: 1E-15 Survey Calculation Method: Minimum Curvature Design: 1E-15 Database: EDM Alaska Prod v16 Survey - - -- -- - - - - -- - - MD Inc Azi TVD TVDSS +N /-S +E/ -W Map Map DLS Vertical Northing Easting Section Survey Tool Name Annotation • (ft) C) ( °) (ft) (ft) (ft) (ft) (ft) (ft) mow) (ft) 7,600.00 38.42 287.28 6,284.50 6,178.80 878.62 - 3,225.19 5,960,887.13 546,479.42 0.11 3,158.43 MWD (2) TIP 1E - 7,632.00 38.52 287.25 6,309.55 6,203.85 884.53 - 3,244.20 5,960,892.91 546,460.37 0.32 3,177.46 MWD (2) KOP; Top of Window 7,670.28 59.12 290.60 6,334.62 6,228.92 893.95 - 3,271.26 5,960,902.15 546,433.26 54.20 3,205.11 MWD (2) Interpolated AZI 7,700.35 65.47 292.41 6,348.60 6,242.90 903.72 - 3,296,01 5,960,911.75 546,408.44 21.78 3,231.05 MWD (2) 7,730.27 64.92 313.11 6,361.26 6,255.56 918.29 - 3,318.69 5,960,926.18 546,385.67 62.77 3,258.00 MWD (2) 7,760.61 67.00 327.36 6,373.68 6,267.98 939.54 - 3,336.33 5,960,947.30 546,367.89 43.42 3,284.55 MWD (2) 7,790.47 69.74 341.43 6,384.73 6,279.03 964.50 - 3,348.25 5,960,972.18 546,355.80 44.73 3,308.48 MWD (2) 7,820.34 73.79 355.51 6,394.12 6,288.42 992.22 - 3,353.87 5,960,999.86 546,350.01 46.76 3,328.76 MWD (2) 7,850.42 81.37 350.63 6,400.59 6,294.89 1,021.34 - 3,357.43 5,961,028.96 546,346.26 29.76 3,348.13 MWD (2) 7,880.49 90.21 339.12 6,402.80 6,297.10 1,050.21 - 3,365.25 5,961,057.77 546,338.25 48.15 3,370.88 MWD (2) 7,910.48 87.82 332.87 6,403.32 6,297.62 1,077.59 - 3,377.44 5,961,085.07 546,325.88 22.31 3,396.39 MWD (2) 7,940.45 85.45 328.53 6,405.07 6,299.38 1,103.67 - 3,392.07 5,961,111.05 546,311.07 16.48 3,423.19 MWD (2) 7,970.40 86.07 323.37 6,407.29 6,301.59 1,128.41 - 3,408.79 5,961,135.67 546,294.19 17.31 3,450.96 MWD (2) 8,000.39 88.83 318.78 6,408.63 6,302.93 1,151.71 - 3,427.61 5,961,158.85 546,275.22 17.84 3,479.64 MWD (2) 8,030.68 94.12 316.47 6,407.85 6,302.15 1,174.07 - 3,448.01 5,961,181.07 546,254.68 19.05 3,509.10 MWD (2) 8,060.68 97.57 317.07 6,404.79 6,299.09 1,195.81 - 3,468.45 5,961,202.67 546,234.10 11.67 3,538.24 MWD (2) 8,090,58 97.70 322.87 6,400.82 6,295.12 1,218.49 - 3,487.50 5,961,225.22 546,214.90 19.23 3,566.77 MWD (2) 8,120.60 95.38 328.13 6,397.39 6,291.69 1,243.06 - 3,504.38 5,961,249.68 546,197.85 19.04 3,594.57 MWD (2) 8,150.59 91.57 331.97 6,395.58 6,289.88 1,268.99 - 3,519.32 5,961,275.51 546,182.74 18.02 3,621.53 MWD (2) ill 8,180.49 90.68 336.92 6,394.99 6,289.29 1,295.95 - 3,532.21 5,961,302.38 546,169.68 16.82 3,647.39 MWD (2) 8,210.51 90.28 342.82 6,394.74 6,289.04 1,324.12 - 3,542.54 5,961,330.48 546,159.16 19.70 3,671.81 MWD (2) 8,240.60 92.33 348.63 6,394.05 6,288.35 1,353.26 - 3,549.95 5,961,359.57 546,151.56 20.47 3,694.38 MWD (2) 8,270.52 92.12 354.63 6,392.89 6,287.19 1,382.83 - 3,554.30 5,961,389.10 546,147.01 20.05 3,714.65 MWD (2) 8,300.48 90.74 1.60 6,392.14 6,286.44 1,412.74 - 3,555.29 5,961,419.01 546,145.83 23.71 3,732.35 MWD (2) 8,330.72 89.69 6.64 6,392.03 6,286.33 1,442.90 - 3,553.11 5,961,449.17 546,147.80 17.02 3,747.57 MWD (2) 8,360.85 90.12 11.06 6,392.08 6,286.38 1,472.66 - 3,548.48 5,961,478.96 546,152.24 14.74 3,760.54 MWD (2) 8,390.55 91.66 4.64 6,391.61 6,285.91 1,502.06 - 3,544.43 5,961,508.38 546,156.10 22.23 3,773.78 MWD (2) 8,420.55 93.87 358.47 6,390.17 6,284.47 1,532.00 - 3,543.61 5,961,538.32 546,156.72 21.82 3,790.01 MWD (2) 8,450.94 96.92 351.80 6,387.31 6,281.61 1,562.13 - 3,546.17 5,961,568.43 546,153.96 24.04 3,809.12 MWD (2) j 8,480.77 96.27 345.71 6,383.88 6,278.18 1,591.17 - 3,551.95 5,961,597.44 546,147.99 20.40 3,830.28 MWD (2) 4/21/2010 10:47:58AM Page 3 COMPASS 2003.16 Build 69 ConocoPhillips Fri a S ConocoPhilli BAKER ConocoPhillips Definitive Survey Report HUGHES Alaska Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference: 1E - 15 Project: Kuparuk River Unit TVD Reference: 1E-15 @ 105.70ft (1E-15) (t Site: Kuparuk 1E Pad MD Reference: 1E-15 @ 105.70ft (1E-15) Well: 1E North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature Design: 1E-15 Database: EDM Alaska Prod v16 i Survey - -- - - -- - -- � -. ______ _�_ _ . . _.. -._.� ____.____ I Map Map Vertical MD Inc Azi TVD TVDSS +NI S +E/-W Northing Easting DLS Section Survey Tool Name Annotation (ft) C) (1 (ft) (ft) (ft) (ft) (ft) (ft) moo.) (ft) 8,510.94 95.99 339.39 6,380.65 6,274.95 1,619.78 - 3,560.94 5,961,625.98 546,138.81 20.85 3,853.84 MWD (2) • W } 8,540.20 92.92 336.15 6,378.38 6,272.68 1,646.77 - 3,571.97 5,961,652.90 546,127.60 15.23 3,878.19 MWD (2) } 8,570.17 91.99 331.51 6,377.09 6,271.39 1,673.64 - 3,585.18 5,961,679.67 546,114.22 15.78 3,904.25 MWD (2) 8,600.16 89.36 326.77 6,376.74 6,271.04 1,699.37 - 3,600.55 5,961,705.30 546,098.67 18.07 3,931.46 MWD (2) 8,631.04 83.64 321.26 6,378.63 6,272.93 1,724.29 - 3,618.65 5,961,730.10 546,080.42 25.69 3,960.46 MWD (2) 8,660.93 85.73 316.85 6,381.40 6,275.70 1,746.77 - 3,638.14 5,961,752.44 546,060.77 16.27 3,989.24 MWD (2) 8,700.58 85.92 309.78 6,384.29 6,278.59 1,773.88 - 3,666.90 5,961,779.36 546,031.84 17.79 4,028.28 MWD (2) 8,730.79 88.01 310.41 6,385.89 6,280.19 1,793.30 - 3,689.97 5,961,798.63 546,008.64 7.22 4,058.29 MWD (2) 8,760.94 87.24 316.48 6,387.14 6,281.44 1,814.01 - 3,711.84 5,961,819.19 545,986.65 20.28 4,088.02 MWD (2) 8,790.77 84.65 322.33 6,389.25 6,283.55 1,836.59 - 3,731.19 5,961,841.64 545,967.14 21.40 4,116.74 MWD (2) 8,825.71 82.92 329.28 6,393.03 6,287.34 1,865.30 - 3,750.70 5,961,870.21 545,947.45 20.38 4,149.05 MWD (2) 8,860.53 78.91 334.38 6,398.54 6,292.84 1,895.59 - 3,766.93 5,961,900.39 545,931.02 18.49 4,179.55 MWD (2) } 8,890.25 84.03 337.24 6,402.94 6,297.24 1,922.39 - 3,778.97 5,961,927.11 545,918.81 19.68 4,204.60 MWD (2) 8,920.86 88.99 339.83 6,404.81 6,299.11 1,950.81 - 3,790.14 5,961,955.46 545,907.45 18.27 4,229.87 MWD (2) 8,950.83 89.48 333.68 6,405.21 6,299.51 1,978.33 - 3,801.96 5,961,982.90 545,895.44 20.58 4,255.16 MWD (2) } 8,980.50 92.18 329.26 6,404.78 6,299.08 2,004.39 - 3,816.13 5,962,008.86 545,881.11 17.45 4,281.55 MWD (2) 9,010.39 90.43 323.85 6,404.10 6,298.40 2,029.31 - 3,832.59 5,962,033.67 545,864.48 19.02 4,309.21 MWD (2) 9,040.70 92.92 319.04 6,403.21 6,297.51 2,053.00 - 3,851.46 5,962,057.22 545,845.45 17.86 4,338.16 MWD (2) 9,070.52 93.56 313.22 6,401.52 6,295.82 2,074.45 - 3,872.09 5,962,078.54 545,824.69 19.60 4,367.29 MWD (2) 9,100.55 95.90 308.98 6,399.05 6,293.35 2,094.12 - 3,894.63 5,962,098.06 545,802.02 16.08 4,397.00 MWD (2) 9,130.58 96.52 305.39 6,395.80 6,290.10 2,112.16 - 3,918.41 5,962,115.94 545,778.12 12.06 4,426.81 MWD (2) 9,160.86 97.44 311.32 6,392.11 6,286.41 2,130.80 - 3,941.97 5,962,134.42 545,754.44 19.67 4,456.78 MWD (2) 9,190.63 99.49 315.90 6,387.73 6,282.03 2,151.10 - 3,963.29 5,962,154.58 545,733.00 16.70 4,485.84 MWD (2) 9,220.55 99.19 320.66 6,382.87 6,277.17 2,173.13 - 3,982.93 5,962,176.48 545,713.21 15.73 4,514.48 MWD (2) 9,250.67 100.37 325.64 6,377.75 6,272.05 2,196.88 - 4,000.72 5,962,200.10 545,695.26 16.76 4,542.57 MWD (2) 9,280.36 100.75 330.98 6,372.31 6,266.61 2,221.70 - 4,016.05 5,962,224.82 545,679.77 17.73 4,569.24 MWD (2) 9,310.59 99.66 336.55 6,366.95 6,261.25 2,248.38 - 4,029.19 5,962,251.40 545,666.45 18.49 4,595.14 MWD (2) 9,340.28 98.48 341.75 6,362.26 6,256.56 2,275.77 - 4,039.62 5,962,278.72 545,655.84 17.75 4,619.21 MWD (2) 9,370.45 99.64 348.23 6,357.51 6,251.81 2,304.53 - 4,047.34 5,962,307.43 545,647.94 21.56 4,641.80 MWD (2) 9,400.62 95.79 352.53 6,353.46 6,247.76 2,333.99 - 4,052.33 5,962,336.86 545,642.76 19.03 4,662.55 MWD (2) 9A30.50 94.64 357.87 6,350.74 6,245.04 2,363.63 - 4,054.81 5,962,366.48 545,640.07 18.21 4,681.33 MWD (2) 4/21/2010 10:47:58AM Page 4 COMPASS 2003.16 Build 69 ConocoPhillips Pa ConocoPhillips BAKER l� Definitive Survey Report HUSHES Alaska Company: ConocoPhillips(Alaska) Inc. Local Co- ordinate Reference: 1 E - 15 Project: Kuparuk River Unit ND Reference: 1E-15 @ 105.70ft (1E-15) Site: Kuparuk 1E Pad MD Reference: 1E-15 @ 105.70ft (1E-15) Well: 1E North Reference: TRUE Wellbore: 1E Survey Calculation Method: Minimum Curvature t Design: 1E Database: EDM Alaska Prod v16 1 Survey i Map Map Vertical MD Inc Azi ND NDSS ++141/-S +E/ -W DLS Northing Easting ° Section Survey Tool Name Annotation (ft) (1 ( °) (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) 111 , 9,465.51 90.77 2.07 6,349.08 6,243.38 2,398.59 - 4,054.83 5,962,401.43 545,639.82 16.30 4,701.07 MWD (2) 9,500.44 85.82 5.33 6,350.12 6,244.42 2,433.41 - 4,052.58 5,962,436.27 545,641.84 16.96 4,718.86 MWD (2) 9,535.97 87.17 11.19 6,352.30 6,246.60 2,468.49 - 4,047.49 5,962,471.37 545,646.71 16.89 4,734.45 MWD (2) 9,565.23 87.30 13.21 6,353.71 6,248.01 2,497.06 - 4,041.31 5,962,499.98 545,652.69 6.91 4,745.47 MWD (2) 9,595.30 86.56 18.62 6,355.32 6,249.62 2,525.92 - 4,033.08 5,962,528.89 545,660.73 18.13 4,754.97 MWD (2) 9,625.38 85.69 23.91 6,357.36 6,251.66 2,553.88 - 4,022.20 5,962,556.92 545,671.42 17.78 4,761.76 MWD (2) 9,655.39 86.13 22.35 6,359.50 6,253.80 2,581.41 - 4,010.44 5,962,584.52 545,683.00 5.39 4,767.59 MWD (2) 9,685.22 88.86 16.43 6,360.80 6,255.10 2,609.50 - 4,000.56 5,962,612.68 545,692.70 21.84 4,775.28 MWD (2) 9,715.23 90.21 10.85 6,361.04 6,255.34 2,638.65 - 3,993.48 5,962,641.87 545,699.58 19.13 4,785.89 MWD (2) 9,744.85 89.36 5.95 6,361.16 6,255.46 2,667.95 - 3,989.16 5,962,671.19 545,703.71 16.79 4,798.85 MWD (2) 9,800.00 89.36 5.95 6,361.77 6,256.07 2,722.80 - 3,983.44 5,962,726.07 545,709.06 0.00 4,825.08 PROJECTED to TD al I I l 4/21/2010 10:47:58AM Page 5 COMPASS 2003.16 Build 69 Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, March 31, 2010 9:04 AM To: 'Eller, J Gary' Subject: RE: New Lateral for KRU 1E-15 I • Gary, You have verbal approval to add the additional lateral in 1E-15L2-02 as outlined below. Please submit the PTD application as soon practical. Lateral 1E-15L2-01 is not moved significantly and will not need to be re- permitted. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Eller, J Gary [ mailto: J.Gary.Eller @conocophillips.com] Sent: Tuesday, March 30, 2010 3:24 PM To: Schwartz, Guy L (DOA) Cc: Venhaus, Dan E; Cawvey, Von Subject: New Lateral for KRU 1E -15 Guy — Greetings! I've put together a wellbore schematic for you that will help explain what we're trying to accomplish at KRU 1 E -15. The attached schematic shows as- drilled items in black with yellow boxes; the proposed operations are shown in blue. Basically, Guy, because of different geology than we expected, we want to kick off the 1 E- 15AL2 -01 lateral deeper than originally planned (now proposed at 8855', TD at 10,000' MD) and add a new lateral 1E-15AL2-02 from 8200' — 9475'. The formation objective is the same as the original AL2 -01 proposal, and in map -view well is essentially unchanged from what was originally proposed. This additional lateral will not affect the quarter -mile review that was previously submitted. I anticipate kicking off the AL2 -01 lateral tonight and kicking off the AL2 -02 lateral by Thursday. I will submit a written 10-401 on Thursday, so I would like permission from the Commission to proceed with uninterrupted drilling operations on 1E-15 pending formal approval of the 10 -401. Please let me know what else I can provide that will help with getting this authorization. Thanks much. Gary Eller ConocoPhillips Wells CTD Engineer 3/31/2010 3 -3j - 1E-15 Proposed CTD Sidetrack Last Updated: 30- Mar -10 3 -1/2" Camco TRDP -1A nipple @ 1878' MD 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H -40 shoe l ........_ 0 @ 112' MD Baker 3 -1/2" PBR @ 7307' MD Baker FHL packer @ 7321' MD 3 -1/2" Camco KBUG injection mandrels @ 7354', 7425', 7592' 10 -3/4" 45.5# K -55 shoe @ 2193 MD Carbide blast rings 7446' - 7552' (7452' -7538' CBL) �i Baker FB -1 packer @ 7663' MD w/ Baker SBE , f 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) C-sand perfs 3 -1/2" tubing tail @ 7682' MD 7478' - 7554' MD --- Sqz perfs (2/14/10) 7550' - 7554' CBL 7618'- 7638'CBL �\\ AL2 -02 Lateral (A5 sand, southeast) KOP #2 at 7557' MD \ TD = 9475', KO from 8200' AL2 01 Lateral (A5 sand, southeast) TD = 10,000', KO from 8855' KOP #1 at 7631' MD ^nn Liner to p at 7550' Billet/liner at 8200' 1 Baker flow -by monobore ---- — — , AL2 Lateral, TD = 9835' whipstocks = / �� 2-3/8" liner 8864' -9835' — / , _ _ Billet at 8855' c 4i it _ _ _ _ AL1 Lateral, TD = 8812' A -sand perfs 7716' - / / ----- 2 -3/8" liner 7623' - 8810' 7796' MD (plugged) — / / _ \ Liner top at 7623' — <c — _ — A Sidetrack, TD = 9800' CIBP at 7656' ELM 2 -3/8" liner 8326' - 9790' 7" 26# K -55 shoe @ Billet at 8326' (7674' MD, 2/13/10) 8410' MD �„� ■ O Page l of l Schwartz, Guy L (DOA) From: Eller, J Gary [ J.Gary.Eller @conocophillips.com] 7[) Z/O — o (3 Sent: Wednesday, February 10, 2010 8:09 AM To: Schwartz, Guy L (DOA) Cc: Allsup- Drake, Sharon K Subject: Clarification on Sundry #023 ) 0./0. Guy — As we discussed over the phone, 1 need to clarify something on plugging sundry #301 -023 for well KRU 1E-15. The squeeze perforations listed in pre -rig step #8 will be deep penetrators designed to shoot through the 3 -1/2" tubing and the 7" casing. This will hopefully allow us to squeeze some cement behind the 7" casing. Please call if you have any questions. 3. Gary Eller Wells Engineer ConocoPhillips - Alaska work: 907 - 263 -4172 cell: 907 - 529 -1979 fax: 907-265-1535 2/10/2010 • 1 , „:„ c L - \ � t y� � 6 SEAN PARNELL, GOVERNOR FA ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mr. Von Cawvey Alaska Wells Manager ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, Alaska 99510 -0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, 1E -15A ConocoPhillips Alaska Inc. Permit No: 210 -013 Surface Location: 443' FSL, 815' FEL, SEC. 16, T11N, R10E, UM Bottomhole Location: 2382' FNL, 435' FWL, SEC. 16, Ti 1N, R10E, UM Dear Mr. Cawvey: Enclosed is the approved application for permit to re -drill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the 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 may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). Sincerely, 4110/ o an Commi '.ner DATED this day of February, 2010 cc: Department of Fish & Game, Habitat Section w/o encl. (via e -mail) Department of Environmental Conservation w/o encl. (via e -mail) . RECEIVED • STATE OF ALASKA S JAN 2 6 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL Alaska Oil & Gas Cons. Commission 20 AAC 25.005 Anchorage la. Type of Work: , lb. Proposed Well Class: Development - Oil ❑ Service - Winj 0 • Single Zone ig • lc. Specify if well is proposed for: Drill ❑ Re -drill El Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Re -entry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: [✓J Blanket [J Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59 - 52 - 180 • 1 E - 15A • 3. Address: 6. Proposed Depth: 12. Field /PooI(s): P.O. Box 100360 Anchorage, AK 99510 - 0360 MD: 9525 • TVD: 6260' , Kuparuk River Field 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 443' FSL, 815' FEL, Sec. 16, T11N, R10E, UM • ADL 25651 • Kuparuk River Oil Pool • Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1952' FSL, 903' FWL, Sec. 16, T11N, R10E, UM 469 3/15/2010 Total Depth: 9. Acres in Property: 14. Distance to 2382' FNL, 435' FWL, Sec. 16, T11N, R10E, UM 2560 Nearest Property: 26100' , 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 102 feet 15. Distance to Nearest Well Open Surface: x - 549710 • y - 5960030 • Zone 4 GL Elevation above MSL: 41 feet to Same Pool: 1E-11 & 1E-13 @ 1015' , 16. Deviated wells: Kickoff depth: 7635 • ft. 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 100° • deg Downhole: 4895 psig • Surface: 4264 psig • 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 3" 2.375" 4.7# L - 80 ST - L 1125' 8400' 6290' 9525' 6260' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured) Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured) 8435' 6936' 8323' 6848' 7884' Casing Length Size Cement Volume MD TVD Conductor /Structural 112' 16" 326 sx AS 1 112' 112' Surface 2155' 10.75" 1025 sx AS III, 250 sx AS II 2193' 2193' Intermediate Production 8376' 7" 605 sx Class G 8410' 6916' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 7478'- 7554', 7716'- 7739', 7742' -7796' 6190'- 6249', 6375'- 6393', 6396' -6438' 20. Attachments: Property Plat ❑ BOP Sketch 0 Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date: \� 22. I hereby certify that the foregoing is true and correct. Contact J. G. Eller @ 263 - 4172 S ^�J Printed Name V. Cawvey Title Alaska Wells Manager \ v \ Signature 1 Phon 265 - 6306 Date 04/Zoi 0 Commission Use Only Permit to Drill API Number: Permit Approv See cover letter Number �/ D('- -, LO l• 50 -�? -_/ �` ` 7�� (1-6.t. Date: 77//e:/' 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: 2 • • 5060 ps'. 80 P T;5 5't Samples req'd: Yes ❑ No 2 / Mud log req'd: Yes ❑ No Other: ( T [ �- H2S measures: Yes "No ❑ Dire tional svy req'd: Yes [r' No ❑ •6— 2sob e s, Ann 4 is / ,. k tbi k..c.'c_ o �, Q' .o••, %.„, a-cGV,-.Q ..:-k. Ato lK(T' l,4 4{ -� • Row kAa�. / ' a / APPROVED BY THE COMMISSION 5-' r DATE: 0R1G1NAL / COMMISSIONER Form 10 - 401 (Revised 7/2009) This permit is valid for 24 months from the da of approve 20 A C 2 005(g)) Submit in Duplicate /. 4.Y. /O % 1 , •7.7. ;17 • • Conoco Phillips p RECEIVE D Alaska 6 P.O. BOX 100360 JAN 2 6 Z O 10 ANCHORAGE, ALASKA 99510 -0360 Moho ON & Gas Cons. Commission Anchorage January 25, 2010 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 applications for four lateral sidetracks out of Kuparuk Well 1E-15 (PTD# 182 -102) using the coiled tubing drilling rig, Nabors CDR2 -AC. Work is scheduled to begin on 1 E -15 in late March 2010. The CTD objective is to drill four A -sand lateral sidetracks (1E-15A, 1 E- 15AL1, 1 E- 15AL2, and 1E-15AL2-01). The original wellbore perforations will be plugged ✓ with cement and a bridge plug prior to CTD operations (Sundry application is attached). Attached to this application are the following documents that explain the proposed job operations: - Permit to Drill Application Forms for 1 E -15A, 1 E- 15AL1, 1 E- 15AL2, 1 E- 15AL2 -01 - Proposed & Current Wellbore Schematic - BOP Schematic - Detailed Summary of Operations - Directional Plans - Sundry application for plugging the KRU 1 E -15 motherbore If you have any questions or require additional information please contact me at my office 907 - 263 -4172. 9kncerely, Gary Eller\ ConocoPh s Alaska Coiled Tubing Drilling Engineer • • KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Summary of Operations: Well 1E -15 is a Kuparuk A -sand and C -sand injection well equipped with 31/4" tubing x 7" casing. Four proposed A -sand CTD laterals will improve sweep efficiency and reserve recovery. Prior to drilling, the existing C -sand in 1E -15 will be squeezed with cement and the A -Sand perfs will be plugged with a bridge . plug. After squeezing the existing C -sand perfs with cement, a mechanical whipstock will be placed in the 31/4" tubing at the first kickoff point. The 1E -15A sidetrack will make a 2- string exit through the 31/4" tubing and 7" casing at 7635' MD. It will target the A4/5 sand northwest of the existing well with an 1890' lateral. The hole will be completed with a 2%" slotted liner to the TD of 9525' MD with a liner top aluminum billet at 8400' MD. The 1E -15AL1 lateral will kick off from the aluminum billet at 8400' MD and will also target the A4/5 sand northwest of the existing well with a 430' lateral. The hole will be completed with a 2 slotted liner to the TD of 8830' MD with the final liner top located just inside the 31/4" tubing at 7630' MD. The 1E -15AL2 lateral will make another 2- string exit through the 31/4" tubing and 7" casing at 7557' MD via a second mechanical whipstock placed in the 31/4" tubing. It will target the A4 sand southeast of the existing well with a 2593' lateral. The hole will be completed with a 2%" slotted liner to the TD of 10,150' MD with a liner top aluminum billet at 8500' MD. The 1E- 15AL2 -01 lateral will kick off from the aluminum billet at 8500' MD and will target the A4/5 sand southeast of the existing well with a 1575' lateral. The hole will be completed with a 2 slotted liner to the TD of 10,075' MD with the final liner top located just inside the 31/4" tubing at 7550' MD. CTD Drill and Complete 1E -15: March /April 2010 Pre -Ri2 Work 1. Test packoffs — T & IC. 2. Positive pressure and drawdown tests on MV, SV, & SSSV. 3. DGLV's, load tbg & IA. MIT -IA. MIT -OA. 4. Obtain updated static BHP on A -sand & C -Sand 5. Pull tubing patch isolating injection mandrel at 7592' 6. Dummy injection mandrels at 7354' & 7452' 7. Set 31/4" CIBP at 7679' MD to plug off A -sand perfs 8. Shoot squeeze perfs thru the 31/4" tubing and 7" casing at 7630' & 7552' ELM 9. Lay in cement on top of CIBP isolating A -sand. Squeeze the C -sand perfs with cement. . 10. RU slickline. Tag cement top. Pressure test cement squeeze. 11. Drill out cement from the 31/4" tubing to 7665' using special clearance bi- center bit 12. Run whipstock dummy 13. Set monobore whipstock at 7635' MD with high -side orientation. . 14. Prep site for Nabors CDR2 -AC. Page 2 of 5 ORIGINAL January 25, 2010, FINAL • • KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Ri! Work 1. MIRU Nabors CDR2 -AC rig using 2" coil tubing. NU 7 -1/16" BOPE, test. 2. 1E -15A Lateral (A4/5 sand, northwest) a. Mill 2.74" 2- string window with high -side orientation at 7635' MD. • •'1 b. Drill 2.70" x 3" bi- center lateral to TD of 9525' MD. D �✓ c. Run 2%" slotted liner with an aluminum liner -top billet from TD up to 8400' 3. 1 E -15IAL 1 Lateral (A4/5 sand, northwest) a. Kick off of the aluminum billet at 8400' MD b. Drill 2.70" x 3" bi- center lateral to TD of 8830' MD. c. Run 2%" slotted liner from TD up to 7630' MD, up inside the 7" casing 4. 1 E -15AL2 Lateral (A4 sand, southeast) a. Set 31/2" monobore whipstock in 31/2" tubing at 7557' MD with low -side orientation. b. Mill 2.74" 2- string window with low -side orientation at 7557' MD. c. Drill 2.70" x 3" bi- center lateral to TD of 10,150' MD. d. Run 2 slotted liner with an aluminum liner -top billet from TD up to 8500' 5. 1E- 15AL2 -01 Lateral (A4/5 sand, southeast) a. Kick off of the aluminum billet at 8500' MD b. Drill 2.70" x 3" bi- center lateral to TD of 10,075' MD. c. Run 2%" slotted liner from TD up to 7550' MD, up inside the 3'/2" tubing 6. Freeze protect. ND BOPE. RDMO Nabors CRD2 -AC. Post -Rig Work 1. Obtain static BHP 2. Run GLVs 3. Flow back well to tanks or to the system for clean up prior to putting on injection 4. Conduct MIT -IA 5. Put well on injection Mud Program: • Will use chloride -based Biozan brine or used drilling mud (8.6 ppg) for milling operations, and chloride - based Flo -Pro mud ( -10.0 ppg) for drilling operations. 'There is a SCSSV installed in 1E -15, so we should not have to kill the well to deploy 2%" slotted liner. Disposal: • 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. Casing Program: • 1E -15A: 2W, 4.7 #, L -80, ST -L slotted /solid liner from 8400' MD to 9525' MD • • 1E- 15AL1: 2% ", 4.7 #, L -80, ST -L slotted /solid liner from 7630' MD to 8830' MD • 1E- 15AL2: 2 ", 4.7 #, L -80, ST -L slotted/solid liner from 8500' MD to 10,150' MD • 1E- 15AL2 -01: 2% ", 4.7 #, L -80, ST -L slotted /solid liner from 7550' MD to 10,075' MD Existing Casing/Liner Information Surface: 10 ", K -55, 45.5 ppf Burst 3580 psi; Collapse 2090 psi Production: 7 ", K -55, 26 ppf Burst 4980 psi; Collapse 4320 psi Page 3 of 5 ORIGINAL January 25, 2010, FINAL ! • KRU 1E-15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Well Control: • Two well bore volumes ( -180 bbl) of KWF will be available to the rig during drilling operations. The kill weight fluid may or may not be stored onsite, but if it is stored offsite it will be in the Kuparuk Field within a short drive to the rig. • BOP diagram is attached for operations with 2" coil tubing. • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 5000 psi. Maximum potential surface pressure in 1E -15 is 4264 psi assuming a gas gradient to surface and maximum potential formation pressure. Maximum potential formation pressure is based on the highest recent measured bottom hole pressure in the vicinity, which is 4895 psi at 7633' MD, 6310 TVD (i.e. 14.9 ppg) from 1E -15 ✓ itself in late November 2009. Since that time, the A -sand has been allowed to crossflow to the lower - pressure C -sand, so the formation pressure in the A -sand is now reduced. • The annular preventer will be tested to 250 psi and 2500 psi. Directional: • See attached directional plans: 1. 1E -15A, plan #3 2. 1E- 15AL1, plan #3 3. 1E- 15AL2, plan #5 4. 1E- 15AL2 -01, plan #5 • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • 1E -15 CTD northwestern laterals (A & AL1): —26,100' to property line, 1015' to wells 1E -11 & 1E -13 • 1E -15 CTD southeastern laterals (AL2 & AL2 -01): —24,400' to property line, —675' from well 1E -16 Logging • MWD directional, resistivity, and gamma ray will be run over the entire open hole section. Reservoir Pressure • The most recent static BHP survey in well 1E -15 was taken January 2010 after allowing the A -sand to cross flow to the lower pressure C -sand for a month. The 72 -hour buildup measured reservoir pressure of 3719 psi at 6238' SSTVD, corresponding to 11.5 ppg EMW. We generally expect to encounter decreasing pressure as the laterals are drilled away from the mother well due to offset producing wells. Hazards • Lost circulation is usually not particularly troublesome in the A -sand, but it is a possibility in 1E -15 since we expect to encounter decreasing formation pressure as the laterals are drilled away from the mother well. • Over - pressured zones are a potential hazard in 1E -15. Even though cross flow to the C -sand has significantly reduced A -sand pressure in the 1E -15 wellbore to 11.5 ppg, there is opportunity to encounter high- pressure stringers (up to 15.0 ppg) while drilling. With 10.0 ppg mud and expected • formation pressure, no choke pressure is needed to maintain well control. If high pressure formations are encountered, a combination of mud weight and /or choke could be needed to maintain well control. Use of the SSSV to deploy slotted liner should eliminate the need to spot heavy kill weight fluid, but if the SSSV fails then completion fluids in excess of 13.0 ppg will be needed to kill the well. • Shale stability is a potential problem, particularly in the build section where the A6 sand will be encountered. Will mitigate potential sloughing problems by cutting this interval at less than 70° hole angle, and by holding a constant pressure on the formation throughout drilling operations. • Well 1E -15 has no measured H since it is an injection well. Well 1E -31 is located 105' to the right side and 1E -16 is 120' to the left side of the 1E -15 surface location. 1E -16 has no measured H since it also is an injection well. Well 1E -31 has 60 ppm H as measured on 8/6/09. The maximum H level on the pad is 130 ppm from well 1E -24A (8/6/09). All H monitoring equipment will be operational. Page 4 of 5 January 25, 2010, FINAL ORIGINAL • • • KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 10.0 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of less expensive drilling fluid and minimizes fluid losses and /or fracturing at the end of the long well bores. A hydraulic choke for regulating surface pressure is installed between the BOPE choke manifold and the mud pits, and is independent of the BOPE choke. Using this technique will require deployment of the BHA under trapped wellhead pressure. Pressure deployment of the 2 BHA will be accomplished utilizing the 2%" pipe rams and slip rams. The annular preventer will act as a secondary containment during deployment and not as a stripper. Well 1E -15 has a SCSSV, so the well should not have to be killed prior to running slotted liner. Operating parameters and fluid densities will be adjusted based on real -time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected at TD: • Expected reservoir pressure is 3711 psi at 7635' MD (6206' SSTVD), or 11.5 ppg EMW. • • Expected annular friction losses while circulating: 763 psi (assuming annular friction of 100 psi /1000 ft due to the 3 tubing) • Planned mud density of 10.0 ppg equates to 3227 psi hydrostatic bottom hole pressure at 6206' SSTVD • While circulating 10.0 ppg mud, bottom hole circulating pressure is estimated to be 3990 psi or 12.4 ppg . EMW without holding any additional surface pressure. This is sufficient to overbalance expected formation pressure in 1E -15. If increased formation pressure is encountered, mud weight or choke pressure will be increased to maintain overbalance. • When circulation is stopped, -760 psi of surface pressure shall have to be applied to maintain the same • borehole pressure as during drilling operations. Quarter -Mile Injection Review The following wells lie within one - quarter mile of the proposed 1E -15 CTD laterals. A detailed review will be made of each of these wells separately and subsequently to the submission of the drilling permits. • 1E -15 motherbore (injector) • 1E -15 CTD northwestern laterals (A & AL1): - • 1E -11 (injector) - • 1E -13 (injector) • 1F -19 (producer) . • 1E-15 CTD southeastern laterals (AL2 & AL2 -01): • 1 E -06 (producer) • 1E -14 (producer) • 1E -16 (injector) • 1E -17 (injector) • 1E -30 (injector) Page 5 of 5 January 25, 2010, FINAL OR1GIN!,L KUP • 1 E -15 ConocoPhillips s WglLPtk Max Angle & MD TD Alaska, r Wellbore API /UWI Field Name Well Status Inc! (') MD (ftKB) Act Bim (ftKB) �C' 3 Caxrd .,, ',1 500292076900 KUPARUK 1.1 1 I, UNIT i INJECI ING 49 3.800.00 8,4350 Comment H2S (pp I Date Annotation End Date KB (ft) .Rig Release Date •.• Weuc ag 1E- 15,71512)09 - ,0.3400AM SSSV TRDP r 8/18/2008 Last WO- 11/5/1984 40.71 8/41982 _ ! AM.! Annotation Depth (ftKB) End Date Annotation Last Mod By /End Date Last Tag' S 7,848.0 6,1: l 1 Rev Reason SET STRADDLE PATCH trlpiw) 7/8/2009 CasingStrings - ,v.t�,w,4z,. '4 String OD String .D Set Depth Set Depth (TVD) String Wt String Casing D esa'ipt ien (in) (in■ Top (ftKB) (ftKB) (ftKB) (Ibs/ft) Grade String Top Thrd CONDUCTOR, CONDUCTOR 16 1. I Iti0 32.0 112.0 112 0, 65.00 H 112 _. - _ _..._. _.__ __ - . SURFACE 103/4 , ,,794 0.0 2,193.0 2,192.8 45.50 K55 -- SAFETYVLV, o '. PRODUCTION 7 H 151 0.0 8,410.0 6,916.2 26.00 K -55 1.878 Tubing Strings 2 ', GAS LIFT, =.. St' g OD Eft iiiii ID Set Depth Set Depth (TVD) String Wt String 1,948 TUBING Description (in) t _ ( Top (11KB) (ftKB) (ftKB) (Ibs /ft) Grade String Top Thrd 992 00 7,6820 63486 9 20 3 55 BTC IPC SURFACE, Other In Hole (All Jewelry: 1::Ibing Run & Retrievable, Fish, etc.). ,4;;;, z,:;,tp: gi , *' : ` , Top Depth GAS LIFT. ',... (ND) Topincl 3,690 Top (ftKB) (.KB) (`) Des, r, lit :.,: Comment Run Date ID(in) 1,878 1..877.9 1.69 SAFE: I', ,i i' Cameo TRDP- 1A-ENC 11/5/1984 2.813 1,948 1 947.9 1.46 GAS 1 I CAMCO /KBUG /1/DMY /// /Comment STA 1 6/5/1990 2.875 GAS LIFT, _ . 5,218 3,690 3,504.6 46.83 GAS LIE - CAMCO /KBUG /1/DMY /// /Comment: STA2 6/5/1990 2.875 5,218 4,524.6 45 86 GAS 1.1) CAMCO /KBUG /1/DMY / /// Comment: STA 3 6/5/1990 2.875 GAS LIFT, , 6,256 5,252.5 43.86 GAS I_ II CAMCO /KBUG /1 /DMYI /// Comment: STA 4 11/5/1984 2.875 i 6,255 6,291 5,277.7 43 -53 GAS LIE I CAMCO /KBUG /1 /DMYI /// Comment: STA 5 6/3/1990 2.875 GAS LIFT, 7,2711 6,026.3 37.97 GAS LIE CAMCO /KBUG /11DMY /U/ Comment: STA 6 6/5/1990 2.875 6291 - 7,307 6,054.7 38.07 PBR Baker PBR 11/5/1984 3.000 7,321 6,065.7 38 11 PACKER Baker'FHL' PACKER 11/5/1984 3.000 GAS LIFT, __. 7,354 6,091.6 38.20 INJECTION CAMCO/ KBUG /1/DMY / /// Comment: CLOSED STA 7 7/20/1993 2.875 • matte 7,271 7,425 6,147.4 38 44 INJECTION! CAMCO /KBUG/) /DMY / /I/ Comment: CLOSED STA 8 7/20/1993 2.875 7,575 6264.9 38.42 PACKER PATCH: UPPER WEATHERFORD ER PACKER 2.87" OAL 7/6/2009 1.750 PBR, 7,307 - -- - (GOOD TEST TO 25008) 7,578 6,267.0 38.42 PATCH PATCH: SPACER PIPE, SNAP LATCH, SEAL ASSY OAL 7/6/2009 1.750 i -4 22.22' OAL (25.09" BETWEEN ELEMENTS) PACKER, 7,321 __ _ _.._, . ............ ..... ____.__ .__. _.,.. - .,.. - ° .: 7,592 6,278.2 38.42 INJECTION CAMCO/ KBUG /1/DMY /U/ Comment: CLOSED STA 9 7/20/1993 2.875 7,602 6,286.4 38 89 PACKER PATCH: LOWER WEATHERFORD ER PACKER 2.8T OAL 7/3/2009 1.750 INJECTION. ) 7,354 INJECTION, ..„'. 7,663 6,333.8 38.78 PACKER Baker'FB-l' PACKER 11/5/1984 4.000 7,676 6,344.0 38.76 NIPPLE Cameo 'D' Nipple NO GO 11/5/1984 2.750 -- - 7,682 6,348.6 38.75 SOS Baker _•_• 11/5/1984 2.992 INJECTION,_ - - ... - Ip25 . �� 7,682 6,348.6 38.75 TTL .... ... _..._ _ 11/5/1984 2.992 ,lI 7,884 6,506.5 38.52 FISEI VANN GUN LOST DOWNHOLE 8/12/1993 8/12/1993 0.000 IPERFS, .i __.__ _..... - - - _ 7A78 -7.554 Perforations & Slots Shot , Top (TVD) Blot (TED/ Dens PACKER, 7,575 _ TTY (rtKBBBtm (ftKB) (81(6) __ (ftKB) Zone Date ( Type Comment _. a i. 7,478 7,554 6,188.9 6,248.5 C4, C-3, C -1, 8/12/1982 12.0 IPERFS GEO VANN GUNS s UNIT B, 1E -15 PATCH, 7,578 - ' - I _f. INJECTION, 7,716 7,725 6,375.2 6,382.2 A -5, 1E-15 8/12/1993 4 0 RPERF 2.5" Titan Hollow Cartier guns, 180 7,592 ? deg phase, 96 deg CCW orient 7,723 7,732 6,380.6 6,387 7 A -5, 1E -15 8/12/1982 12 0 IPERFS GEO VANN GUNS PACKER, 7,602 - -- " - 7,730 7,739 6,386.1 6,393.1 AS, A4, 1E -15 11/5/1984 120 RPERF SCHLUMBERGER GUNS 7,742 7,769 6,395 5 6,4)11.11 A-4, 1E -15 8/12/1993 4 0 RPERF 2.5 Titan Hollow Carrier guns, 180 deg phase, 96 deg CCW orient >... _...^_..___.____ - 7,749 7,776 6,401.0 6 41 A-4, . 0 A , 1E -15 8/12/1982 12 0 IPERFS CE VANN GUNS - 7,756 7,783 64064 - 6,427.5 A-4, 1E -15 11/5/1984 120 RPERF SCHLUMBERGER GUNS NIPPLE, 7,676 1 I 7,775 7,782 6,421.3 6 428 7 A4, 1E-15 8/12/1993 4 0 RPERF 2 5 Titan Hollow Carrier guns, 180 deg phase, 96 deg CCW orient SOS, 7,682 7.782 7,789 6 426.7 6,432 _ , A4 1E-15 8/12/1982 12 0 IPERFS GEO VANN GUNS TTL,7,682 - 7,789 7,796 6 432 2 96 -... 8,43 • ^, -4 1E-.-15 11/5/1984 12.0 APERF SCHLUMBERGER GUNS Stimulations & Treatments n' E a Bottom RPERF, - III Min To Me% Btm To De Depth 7,718 -7,725 I� P P Pih __ Depth Depth (TVD) (TVD' (ftKB) (ftKB) (ftKB) (ftKB/ Type Data Commend IPERFS, _ i 7 7,796.0 6,375.2 6 49T 7 A -SAND 8/19/1993 A4 /A5 SAND RE FRAC, PUMP 193,3978 BEHIND 7.723 - 7,732 RE -FRAC PIPE 1 End 0a 7 796.0 6,386. 1 4 1' FRAC 12/17/1984 A-SAND FRAC 7730 -7,739 Notes General & Safety RPERF,_ , i Date Annotation RPERF, 824 /2009 (NOTE: C - SAND LI:I F OUND @ 7596' ELMD AROUND GLM #9 7,742 - 7,7691_ - -- A -SAND RE -FRAC, 7,716 IPERFS, 7,749 -7,776 \, Ill FRAC, 7,730 RPERF, 7,756 -7,783 RPERF, • 7,775 -7,782 IPERFS, " 7,782 -7,789 ......ill APERF, 7,789 -7,796 l FISH, 7,884 PRODUCTION,, 6416 9 \ \\ -OR - I G l N A L .. _. _... 1E-15 Proposed CTD Sidetrack Last Updated: 21- Jan -10 3 -1/2" Camco TRDP -1A nipple @ 1878' MD N 3 -1/2" 9.3# K -55 EUE 8rd Tubing to surface 3 -1/2" Camco KBUG gas lift mandrels @ 1948', 3690', 5218', 6256', 7271' 16" 65# H -40 shoe.f 112' 112 M D ., I .<- @ Baker 3-1/2" PBR @ 7307' MD .. Baker FHL packer @ 7321' MD ,- 3 -1/2" Camco KBUG injection mandrels @ 7354', 7425', 7592' 10 -3/4" 45.5# K -55 shoe @ 2193 MD Carbide blast rings 7446' - 7552' (7452' -7538' CBL) Baker FB -1 packer @ 7575' MD w/ Baker SBE • 3 -1/2" Camco D landing nipple @ 7676' MD (2.75" min ID, No -Go) 3 -1/2" tubing tail @ 7682' MD O 70 C -sand perfs 7478' 7554' MD Top of cement at injection mandrel #8 for C -sand perfs x AL2 -01 Lateral (A5 sand, southeast) w 'NN. TD = 10075' ��n� top a "5�0 KOP #2 at 7557' MD P ione \ N i I KOP #1 at 7635' MD r-- Baker flow -by monobore � ; • .;----,- ----------- — — — 9 AL2 Lateral (A4 sand, southeast) whipstocks /�i. / TD = 10150' ..., — / / — — Billet at 8500' AL1 Lateral (A5 sand, northwest) TD = 8830' A -sand perfs 7716' - hI Liner top at 7630' 7796' MD (plugged) 42i;Iii'-n. cSIca---------------- A Sidetrack (A4 /A5 sand, Northwest) 7" 26# K -55 shoe @ ,� 00 �� TD = 9525' taz k "ia - M . l:i . u° Billet at 8400' 8410' MD ■1 • 1 Nabors CDR -2AC Kuparuk Managed Pressure Coil Tubing Drilling BOP Configuration for 2" Coil Tubing N I Lubricator Riser r n Annular/ Blind / Shear 2" Pipe / Slip (CT) Pump into Lubricator J L , ■■ above BHA ram i 40.-- = � �j - 1 - 1 r C hoke 1 II 2 -3/8" Pipe / Slip (BHA) 101 Choke Equalize Manifold I 2 -3/8" Pipe / Slip (BHA ' ._ - � L pp�� � J l >< ><1 I 111 1 _ Kill ► l �7Q17Q L 1 [ ,t Blind / Shear 2" Pipe / Slip (CT) II ') Choke 2 11 • i I Swab Valves JIIIIL Wing Valves 1 K r 0 4 ti Tree Flow Cross Alt Surface Safety Valve BOPE: 7- 1/16 ", 5M psi, TOT Choke Line: 2- 1/16 ", 5M psi Master Valve Kill Line: 2- 1/16 ", 5M psi Equalizing Lines: 2- 1/16 ", 5M psi Choke Manifold: 3 -1/8 ", 5M psi Riser: 7- 1/16 ", 5M psi, C062 Union ORIGINAL I Np Conochiflips Alaska ConocoPhillips(Alaska) Inc. Kuparuk River Unit Kuparuk 1E Pad 1E -15 1E -15A Plan: 1 E -15A wp03 Standard Planning Report 13 January, 2010 BAKER HUGHES 1JR1G1NAL Iv' • 1. Iv , , ConocoPhillips aka C011000N11111pS Planning Report Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1 E -15 Company:. ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1E -15 @ 105.7Oft (1E -15) , Site: Kuparuk 1 E Pad North Reference: True Well: 1E-15 Survey Calculation Method: Minimum Curvature Wellbore: 1E-15A Design: 1 E- 15A_wp03 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 1 Site Kuparuk 1 E Pad Site Position: Northing: 5,959,760.24ft Latitude: 70° 18' 3.022 N From: Map Easting: 549,589.51 ft Longitude: 149° 35' 45.358 W Position Uncertainty: 0.00 ft Slot Radius: " Grid Convergence: 0.38 ° Well 1E -15 Well Position +N / -S 0.00 ft Northing: 5,960,029.95 ft • Latitude: 70° 18' 5.686 N +E / -W 0.00 ft Easting: 549,710.04 ft • Longitude: 149° 35' 50.538 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00ft - Weilbore 1E-15A Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( °) (') {nT) BGGM2009 3/25/2010 17.33 79.80 57,371 Design 1E- 15A_wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,600.00 Vertical Section: Depth From (TVD} +N /-S +E/.w Direction (ft) (ft) (ft) (') 0.00 0.00 0.00 333.00 1/1312010 7 :45 :34AM Page 2 COMPASS 2003.16 Build 69 ORIGINAL. 4110 • ✓ ConocoPhillips rid ConocoPhill ps Planning Report BAKER Database: : EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1E -15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1E -15 @ 105.70ft (1E -15) Site: Kuparuk 1E Pad North Reference: True Well 1E -15 Survey Calculation Method: Minimum Curvature Wellbore: 1E-15A Design: 1E-15A wpG3 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N /-S +El -W Rate Rate Rate - - TFO (ft) ( ( (ft) (ft) (ft) (1100ft) (°l1OOft) ( ( Target 7,600.00 38.42 287.28 6,178.80 878.62 - 3,225.19 0.00 0.00 0.00 0.00 7,635.00 38.52 287.24 6,206.20 885.08 - 3,245.99 0.29 0.29 -0.11 -13.99 7,655.00 40.32 287.24 6,221.65 888.85 - 3,258.11 9.00 9.00 0.00 0.00 7,685.00 53.82 287.24 6,242.04 895.34 - 3,279.04 45.00 45.00 0.00 0.00 7,715.00 65.74 294.60 6,257.12 904.67 - 3,303.15 45.00 39.74 24.52 30.00 7,775.00 63.12 324.45 6,283.50 938.45 - 3,344.35 45.00 -4.37 49.76 102.00 7,834.73 90.00 324.45 6,297.26 985.29 - 3,377.81 45.00 45.00 0.00 0.00 7,949.73 90.00 345.15 6,297.26 1,088.78 - 3,426.50 18.00 0.00 18.00 90.00 8,024.73 87.91 358.49 6,298.63 1,162.83 - 3,437.15 18.00 -2.79 17.79 99.00 8,174.73 89.99 331.57 6,301.43 1,306.38 - 3,475.54 18.00 1.39 -17.95 274.10 8,224.73 91.55 322.70 6,300.76 1,348.33 - 3,502.64 18.00 3.11 -17.73 280.00 8,409.73 95.14 355.87 6,289.66 1,518.60 - 3,567.13 18.00 1.94 17.93 83.00 8,459.73 94.29 4.86 6,285.54 1,568.37 - 3,566.80 18.00 -1.69 17.98 95.00 8,634.73 90.02 333.63 6,278.80 1,738.00 - 3,599.09 18.00 -2.44 -17.85 263.00 8,804.73 79.50 304.72 6,294.63 1,864.79 - 3,708.15 18.00 -6.18 -17.00 249.00 8,934.73 89.88 325.82 6,306.78 1,956.24 - 3,798.46 18.00 7.98 16.23 65.00 9,009.73 98.51 336.24 6,301.29 2,021.51 - 3,834.64 18.00 11.51 13.89 50.00 9,134.73 100.15 313.49 6,280.76 2,121.71 - 3,905.09 18.00 1.31 -18.20 276.00 9,159.73 99.34 309.00 6,276.53 2,137.95 - 3,923.61 18.00 -3.24 -17.96 260.00 9,334.73 90.28 339.31 6,261.51 2,277.68 - 4,024.17 18.00 -5.18 17.32 105.00 9,525.00 90.23 13.56 6,260.63 2,464.76 - 4,035.82 18.00 -0.03 18.00 90.00 1/13/2010 7:45 :34AM Page 3 COMPASS 2003.16 Build 69 ORIGINAL • • ,� "-- ConocoPhillips Pii t Conoco fillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate R eference: ' Well 1E -15 Company: ConocoPhillips(Alaska) Inc. ND Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1E -15 @ 105.70ft (1E -15) Site: Kuparuk 1E Pad North Reference: True Well: 1 E -15 Survey Calculation Method: Minimum Curvature Weflbore: 1E-15A Design: - 1E -15A wp03 Planned Survey - Measured TVD Below Vertical Dogleg Toolface Map- Map Depth Inclination Azimuth - System + NJS- - +E/.W Section Rate - Azimuth Northing Easting (ft) () ( (ft) (ft) (ft) (ft) (1100ft) - ( (ft) - (ft) 7,600.00 38.42 287.28 6,178.80 878.62 - 3,225.19 2,247.07 0.00 0.00 5,960,887.13 546,479.42 TIP 1E -15 7,635.00 38.52 287.24 6,206.20 885.08 - 3,245.99 2,262.26 0.29 -13.99 5,960,893.46 546,458.59 KOP 7,655.00 40.32 287.24 6,221.65 888.85 - 3,258.11 2,271.12 9.00 0.00 5,960,897.14 546,446.43 End of DLS 9 7,685.00 53.82 287.24 6,242.04 895.34 - 3,279.04 2,286.41 45.00 0.00 5,960,903.49 546,425.46 4 7,700.00 59.73 291.14 6,250.25 899.48 - 3,290.88 2,295.47 45.00 30.00 5,960,907.55 546,413.60 7,715.00 65.74 294.60 6,257.12 904.67 - 3,303.15 2,305.67 45.00 27.86 5,960,912.66 546,401.29 5 7,775.00 63.12 324.45 6,283.50 938.45 - 3,344.35 2,354.47 45.00 102.00 5,960,946.16 546,359.88 6 7,800.00 74.37 324.45 6,292.55 957.38 - 3,357.87 2,377.47 45.00 0.00 5,960,965.00 546,346.24 7,834.73 90.00 324.45 6,297.26 985.29 - 3,377.81 2,411.39 45.00 0.00 5,960,992.77 546,326.11 End of DLS 45 7,900.00 90.00 336.20 6,297.26 1,041.90 - 3,410.07 2,476.48 18.00 90.00 5,961,049.17 546,293.49 7,949.73 90.00 345.15 6,297.26 1,088.78 - 3,426.50 2,525.71 18.00 90.00 5,961,095.93 546,276.74 8 8,000.00 88.59 354.09 6,297.88 1,138.17 - 3,435.55 2,573.83 18.00 99.00 5,961,145.26 546,267.37 8,024.73 87.91 358.49 6,298.63 1,162.83 - 3,437.15 2,596.52 18.00 98.89 5,961,169.91 546,265.61 9 8,100.00 88.92 344.98 6,300.72 1,237.12 - 3,447.94 2,667.61 18.00 -85.90 5,961,244.11 546,254.33 8,174.73 89.99 331.57 6,301.43 1,306.38 - 3,475.54 2,741.85 18.00 -85.52 5,961,313.18 546,226.27 10 8,200.00 90.78 327.09 6,301.26 1,328.11 - 3,488.42 2,767.06 18.00 -80.00 5,961,334.82 546,213.24 8,224.73 91.55 322.70 6,300.76 1,348.33 - 3,502.64 2,791.54 18.00 -80.03 5,961,354.95 546,198.90 11 8,300.00 93.14 336.17 6,297.66 1,412.93 - 3,540.80 2,866.42 18.00 83.00 5,961,419.29 546,160.32 8,400.00 94.98 354.12 6,290.52. 1,508.94 - 3,566.28 2,963.53 18.00 83.55 5,961,515.12 546,134.20 8,409.73 95.14 355.87 6,289.66 1,518.60 - 3,567.13 2,972.52 18.00 84.84 5,961,524.77 546,133.29 12 8,459.73 94.29 4.86 6,285.54 1,568.37 - 3,566.80 3,016.73 18.00 95.00 5,961,574.54 546,133.29 13 8,500.00 93.38 357.66 6,282.85 1,608.52 - 3,565.92 3,052.09 18.00 -97.00 5,961,614.68 546,133.90 8,600.00 90.91 339.81 6,279.08 1,706.11 - 3,585.37 3,147.88 18.00 -97.48 5,961,712.14 546,113.81 8,634.73 90.02 333.63 6,278.80 1,738.00 - 3,599.09 3,182.52 18.00 -98.15 5,961,743.93 546,099.88 14 8,700.00 85.83 322.64 6,281.17 1,793.30 - 3,633.46 3,247.40 18.00 - 111.00 5,961,799.00 546,065.15 8,800.00 79.77 305.54 6,293.78 1,862.11 - 3,704.35 3,340.89 18.00 - 110.60 5,961,867.33 545,993.82 8,804.73 79.50 304.72 6,294.63 1,864.79 - 3,708.15 3,345.00 18.00 - 108.44 5,961,869.98 545,989.99 15 8,900.00 87.05 320.24 6,305.85 1,928.51 - 3,777.59 3,433.31 18.00 65.00 5,961,933.24 545,920.14 8,934.73 89.88 325.82 6,306.78 1,956.24 - 3,798.46 3,467.49 18.00 63.17 5,961,960.83 545,899.09 16 9,000.00 97.40 334.87 6,302.64 2,012.73 - 3,830.65 3,532.44 18.00 50.00 5,962,017.10 545,866.53 9,009.73 98.51 336.24 6,301.29 2,021.51 - 3,834.64 3,542.07 18.00 50.58 5,962,025.85 545,862.48 17 9,100.00 99.84 319.83 6,286.80 2,096.85 - 3,881.63 3,630.53 18.00 -84.00 5,962,100.87 545,815.00 9,134.73 100.15 313.49 6,280.76 2,121.71 - 3,905.09 3,663.33 18.00 -86.63 5,962,125.57 545,791.38 18 9,159.73 99.34 309.00 6,276.53 2,137.95 - 3,923.61 3,686.21 18.00 - 100. 00 5,962,141_69545,772.75 1/1312010 7:45:34AM Page 4 COMPASS 2003.16 Build 69 O • p r& .- � � ConocoPhilli s Col 04hillips Planning Report BAKER Alaska HUGHES Database: EDM Alaska Prod v16 Local Co- ordinate Reference: Well 1E -15 Company: ConocoPhillips(Alaska) Inc. TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 1E -15 @ 105.70ft (1E -15) Site: Kuparuk 1 E Pad North Reference: True Well: 1E-15 Survey Calculation Method: Minimum Curvature Weltbore: 1E -15A Design: 1 E- 15A_wp03 Planned Survey Measured TVD Below Vertical Dogleg Toolface . Map ' Map Depth inclination Azimuth System e N /„S + E_yy Section Rate Azimuth Northing fasting (ft) (°) (0) (ft) (ft) (ft) (ft) ( °I100ft) (') (ft) (ft) 19 9,200.00 97.40 316.06 6,270.66 2,164.87 - 3,952.94 3,723.51 18.00 105.00 5,962,168.41 545,743.25 9,300.00 92.17 333.35 6,262.26 2,245.89 - 4,010.23 3,821.71 18.00 106.03 5,962,249.05 545,685.43 9,334.73 90.28 339.31 6,261.51 2,277.68 - 4,024.17 3,856.36 18.00 107.48 5,962,280.74 545,671.29 20 9,400.00 90.28 351.06 6,261.19 2,340.67 - 4,040.82 3,920.05 18.00 90.00 5,962,343.61 545,654.21 9,500.00 90.25 9.06 6,260.73 2,440.26 - 4,040.72 4,008.73 18.00 90.06 5,962,443.18 545,653.66 9,525.00 • 90.23 13.56 6,260.63 • 2,464.76 - 4,035.82 4,028.34 18.00 90.14 5,962,467.72 545,658.40 TD 1/13/2010 7 :45 :34AM Page ORUNAL 5 COMPASS 2003.16 Build 69 Azlmahsto7rueNmh WELLBORE DETAILS: 1E -15A REFERENCE INFORMATION Project: Kuparuk nit - Mpi gO 83° II 1E Pad Kuparuk 1 E Pad Site: Ku Co- ordinals (ME) Reference Well 1E- 15, True North M P egnee5 Field Parent Tie re: 1E -15 Tie orr MD: 7600.00 - ' Well: 1E - Strength. 576571sn7 Vertical (ND) Reference: Mean Sea Level on lrrt 11 Wellbore: 1E -15A a 8o Se oAngta e Section (VS) Referetrce: Slot -(O OON,000E) �a,/� 1Q�V Phillips � L Plan: 1E- 15A_wp03(1E- 15/1E -15A) 0 eq, Measured Depth Reference: 1E- 15@105706 (1E•15) Calculation Method: Minimum Curvature HUGHES 2851 WELL DETAILS: 1E -15 2701 . +NI -S +E / -W Northing E shag Level: O Latiltude Longitude Slot 2551 - - - - --- -- - -- -- - - - - - --- --- 0.00 0.00 5960029.95 549710.04 70° 18' 5.686 N 149° 35' 50.538 W - - - -1l 1511E -15A -_.. - :_ --- I____. SECTION DETAILS ANNOTATIONS 401 `` Sec MD Inc Azi TVDSS +NI -S +E/-W DLeg TFace VSec Target Annotation 2251 op - t f 1 7600.00 38.42 287.28 6178.80 878.62 - 3225.19 0.00 0.00 2247.07 TIP 1E-15 1 9 8 2 7635.00 38.52 287.24 6206.20 885.08 - 3245.99 029 -13.99 2262.26 I KOP _ _ i 2101 f -- 17 3 7655.00 40.32 287.24 6221.65 888.85 - 3258.11 9.00 0.00 2271.12 End ofDLS9 .�. 4 7685.00 53.82 28724 6242.04 895.34 - 327904 45.00 0.00 2286.41 4 16 j' 5 7715.00 65.74. 294.60 6257.12 904.67 - 3303.15 45.00 3900 2305.67 5 1951 - i-- t-- --- -_. _ -_._ _ .__ -.._. _... - - -_- - i . - - -. -__ -. 6 7775.00 63.12 324.45 6283,50 938,45 - 3344.35 45.00 102.00 2354.47 6 0 ; 7 7834.73 90.00 324.45 6297.26 8 794973 90.00 34515 6297.26 1068 8 3426.50 18.00 9000 2525.79 and ofDLS45 - -- X1800 1 9 8024.73 87.91 358.49 6298.63 1162.83 -343715 18.00 99.00 2596.52 9 '�' 10 8174.73 89.99 331.57 6301.43 1306.38 - 3475.54 18.00 274.10 2741.85 10 650 11 8224.73 91.55 322.70 6300.76 1348.33 - 3502.64 18.00 280.00 2791.54 11 G t 3 12 8409.73 95.14 355.87 6289.66 1518.60 - 3567.13 18.00 83.00 2972.52 12 1 77 1500 -- - - r 13 8459.73 94.29 4,86 6285.54 1568.37 - 3566.80 18.00 95.00 3016.73 j 13 14 8634.73 90.02 333.63 6278.80 1738.00 - 3599.09 18.00 263.00 3182.52 14 11 15 8804.73 79.50 304.72 6294.63 1864.79 - 3708.15 18.00 249.00 3345.00 15 -01350 t 1 16 8934.73 89.88 325.82 6306.78 1956.24 - 3798.46 18.00 65.00 3467.49 16 8 17 9009.73 98.51 33624 6301.29 2021.51 - 3834.64 18.00 50.00 3542.07 17 1200 4 End of ' ` 18 9134.73 100.15 313,49 6280.76 2121.71 - 3905.09 18.00 276.00 3663.33 18 D1S 45 19 9159.73 99.34 309.00 6276.53 2137.95 - 3923.61 18.00 260.00 3686.21 19 20 9334.73 90.28 339.31 6261.51 2277.68 -4024.17 18.00 105.00 3856.36 20 1050 r� r t Endo DLS 900 21 9525.00 9023 13.56 6260.63 2464.76 -4035.82 18.00 90.00 402834 TD rt E s .... �� _= KOP -- -- TII'lE 1 750 I r- 600 - 5250 - 5100 - -4800 -4650 -4500 -4350 -4200 -4050 -3900 -3750 -3600 - 3450 3300 300 -3150 -3000 -2850 -2727 00 -2550 West(-)/East(+) (150 ft/in) 6050 -- ._ -. --- .__.____.. - - -- --- __.__.. _.. - -- -- - -- - I, 6111 -.. TIP IE: IS -_- - -- -- - -_ _. = KOP Z _. 6.00 - H I . - - -- -- - -- -� - --) o - > 5 t 11- TD 20 • _ - Ea�lofD +45 12 15 16 1 18.15)1 &15A ,� • ca 6300 .... 6 - 13 T4 r- - -- -'- - --- t - -- f U 6350 - __. __ -_ - _.. __._.. �- T N E - _ - - - -- - -_ -_ - - -- -- -- -_ - +• ._ -- -!- - -- _ -- ? --.__ _.-.- - - -- - �. -. I 645 r- -- - -- 6500 .. ! 6550 - -.. - - �- - - - -- _ i - - ---- -- - - - - -- -------- .._ - - -- --- - _ - - - -- - -- I - - - -- -- 4 6600 -_ -.. -- - - -- 1 -- - - - -. _ __. __.- -- - - -- -- -- -- - - -- - - - - - -� , 2200 2250 2300 2350 2400 2450 2500 2550 2600 2650 2700 2750 2800 2850 2900 2950 3000 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 36■1 3650 3700 3750 3800 3850 3900 3950 4000 4050 4100 Vertical Section at 333.00° (50 ft/in) t FvimihsbTrue North WELLBORE DETAILS: 1E -15A REFERENCE INFORMATION ir Protect: Kuparuk River Unit Magnea M_2 cNO1.83' Site: Kuparuk 1E Pad Co- ordinate (NIE) Reference: Well 1E -15, True North III P Me r3O G M ie ' U Paren Tie on MD: 7600.t Wellbore: 1E - 15 00 '@ ��� - Well: 1 E - stegN;57657ns,T Vertical (TVD) Reference. 1E.15 105.70f1105.70(1.05.15) r Welibore: 1E - 15A DD d.3 e5 /2010 Section (VS) Reference. Slot (O.00N, 0.00E) Conoco Phillips Plan:1E 15A_wp03(1E 1511E - 15A) pD8 o M�suedDepMReference. 1E- 15Q105.701t (1E45) Calculation Method, Minimum Curvature 4800 _.- _._... . -_. - - - -- - - --- -- - _.- - - -- --- --- - - - -_- - -- --- ` - - - -- - - - - - -- - - -- -- ---- --- ___----- -.- -__ - _._.__.._ _._._- _. 4600- -- -- _. -- - ' --- --- - -- -- -- -- ----- -- -- ---' -- --- - - ---- - - r -- - -- - --- -- -_ ----- -- - -- --- --- 4200 . 4000 __ , -- 3800 /------ c 1E111111* - • 3000 _... `` ___. __...... I 2.-i• 600-1 -_ - -- L - -- ---F - -___ _._._ -_ a _ \ -.. -. - - - -- O 2400_. ... { 1 E. 15:1 E 15.4 -6i \ — . - t - - - _ - -- I 0 0 2000 J 6:46 6:46 79 F =7? lEl 'iE 1QAL1 � \ - r T, � —� .— _.__ _.- - -T_ -- _ -__ _.___ _ -__.. _ __.__ I — _ 1 ::: ! _ - - - _ j _ 1 120(1- - - - - - - -_ . I - -- -- — - I 1000-, ? I f X / o Y ., u.,.l j 800- _. _._ - - -_ - -. - - - - -- - - - -- , 6691 6001 _ r ao — , / , 0 a .. A E_U6 :E Uh -200 - j 1 / ' __�- -. o� 1.E 400 — — 1 E. -15 `E 6 fiL i E U ■ -600- __ � � �. ' _ _ - _ —_. —_ _ + - -._ -_. _. - - -. _. - . -.. _ - -6800 -6600 -6400 - 6200 - 6000 -5800 -5600 -5400 - 5200 -5000 -4800 -4600 -4400 -4200 -4000 - 3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600 1E -15 © 105.70ft (1E -15) West( - )/East( +) (200 ft/in) • • Quarter -Mile Injection Review KRU 1E -15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Wells Within 1/4 -Mile of 1E -15 Northwestern Laterals (A & AL1) 1. KRU 1E -15 (motherbore injector) • Completed with 7 ", 26 #, K -55 casing on 7- 31 -82. Included 23 B &W Turbo -fin centralizers. Cemented with 280 sacks of lead + 325 sacks of tail "G" cement. Reciprocated casing for most of the job. No mention in cementing reports of lost returns. • C -sand perf d 7478'- 7554', A -sand perf d 7716'- 7796'. The tubing tail is at 7682' MD and the upper packer is at 7321'. The CBL of 7 -1 -82 shows very good cement around the C -sand but generally poor cement around the A -sand, although there is cement isolation between the two intervals. There is no reason to expect injection out of zone. • Well 1E -15 is currently shut -in awaiting sundry approval to plug the A -sand and C -sand perfs. 2. KRU 1E - 11 (injector, 1001' away) • Completed with 7 ", 26 #, K -55 casing on 5 -4 -82. Target TOC = 6708' MD. Casing became stuck 13' off bottom while attempting to reciprocate casing prior to cement job. Lost full returns when casing got stuck. Cemented with 475 sacks of lead + 600 sacks of tail "G" cement with no returns during the cement job. • The CBL of 5 -5 -82 shows very poor cement around both the Kuparuk C -sand and A -sand. • Following the CBL of 5 -5 -82, they perforated at 7674' (i.e. above the C -sand) and performed a squeeze with 41 bbl "G" cement through a retainer to 1400 psi. Drilled out cement and retainer the following day and tested the squeeze perfs to 1000 psi. • On 10 -17 -84 performed additional squeeze work at 7910' (i.e. above the A -sand perfs) using 200 sacks of 15.9 ppg "G" cement. No bond log was run to assess the success of the squeeze. • 1E -11 was pre - produced in the C/A sands from April 1982 to May 1996, and was converted to injection in May 1996. The A sand was frac'd two different times -- in 1985 and 1991. Both were gelled water frac's. The C sand was never frac'd. The most recent IPROF (May 2007) showed 71% C -sand and 29% A -sand injection. Significant A to C sand crossflow was detected into the injection mandrels at 7577' and 7643' MD. • Present completion: C -sand perf'd 7708'- 7794', A -sand perf d 7996'- 8076'. The tubing tail is at 7955' MD and the uppermost packer is at 7491'. Well 1E -11 has been shut in since 2007 due to flowline problems but in 2009 it was put back on miscible gas injection, and water injection is expected to resume in 2011. 3. KRU 1E - 13 (injector, 1144' away) • Completed with 7 ", 26 #, K -55 & L -80 casing on 7 -1 -82. Included 14 B &W Turbo -fin centralizers. Cemented with 564 sacks of lead + 670 sacks of tail "G" cement. Reciprocated casing for most of the job. No mention in cementing reports of lost returns. • C -sand perf d 7110'- 7192', A -sand perf d 7345'- 7416'. The tubing tail is at 7055' MD and the only packer is at 6976'. The CBL of 7 -1 -82 shows good cement around both the C -sand and A- sand perfs. There is no reason to expect injection out of zone. Well 1E -13 is currently on long term shut in due to flowline problems. Page 1 of 3 February 5, 2010, FINAL • • Quarter -Mile Injection Review KRU 1E-15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling 4. KRU 1F -19 (producer, 1103' away) • Completed with 3'/2" (9.3 ppf, L -80) x 5'/2" (15.5 ppf, L -80) tapered production casing on 3- 22 -96. Included 20 centralizers on the 3%2" portion and 12 centralizers on the 5%2" portion. Cemented with 230 sacks "G" cement. Calculated TOC was 7114' MD. Reciprocated casing until 20 bbl cement had turned the comer. Poor returns during cementing, but noted a 400 psi increase in pump pressure as cement moved uphole. • A -sand perf'd 9124'- 9198'. There is no packer installed, but there is a 3'/2" sealbore at the 3%2" x 5%2" crossover at 8772'. The 3'A" tubing seals stab into this sealbore. The CBL of 4 -12 -96 shows excellent cement adjacent to the A -sand perfs. Well 1F -19 is actively producing from the A -sand. Wells Within 1/4 -Mile of 1E -15 Southeastern Laterals (AL2 & AL2 -01): 1. KRU 1E -06 (producer, —938' away) • Completed with 9 ", 47 #, L -80 casing on 9 -7 -80. No casing detail available. Cemented in 2 stages: first stage out the shoe and the second stage through a DV collar at 7127' MD. Cemented via the shoe with 300 sacks (stage #1) and via the DV collar with 900 sacks (stage #2) of "G" cement. There were no returns during the second stage of cementing through the DV collar. Drilled ahead to 9847' MD, but later the open hole and a portion of the cased hole was plugged back in stages to 7400'. • The CBL of 9 -20 -80 only logged down to 7124' MD, but it shows very poor quality cement across both the C -sand and A -sand perfs. • In December 1984 performed a cement squeeze at 6760' MD (i.e. below the C -sand perfs) through a retainer with 100 sacks of "G" cement (-80 sacks behind pipe). Achieved a squeeze pressure of 3000 psi. No bond log was run to assess the success of the squeeze, nor did they pressure test the squeeze after drilling out. • The most recent PPROF in 1E -06 was obtained in March 2009. It showed 79% C -sand to 21% A- sand production contributions. No crossflow was detected. Both the A and C sand have been frac'd in this well. The A -sand was a gelled water batch frac in 1985, and the C -sand was frac'd with 71,000 lbs in 1988. • Present completion: C -sand perfd 6648'- 6710', A -sand perfd 6838'- 6900'. Tubing tail is at 6801' MD, and the uppermost packer is at 6538'. Well 1E -06 is presently shut in due to low productivity, but it is expected to benefit from injection into the 1E -15 CTD laterals. 2. KRU 1E - 14 (producer, 1430' away) • Completed with 7 ", 26 #, K -55 casing on 7- 16 -82. Included 12 B &W Turbo -fin centralizers on bottom 12 joints, plus 8 more uphole. Cemented with 350 sacks of lead + 425 sacks of tail "G" cement. Reciprocated casing for entire job and maintained full returns. • C -sand perfd 6660'- 6724', A -sand perf'd 6853'- 6888'. The tubing tail is at 6803' MD, and the upper packer is at 6430'. The CBL of 7 -17 -82 shows adequate cement across the C -sand perfs and excellent cement across the A -sand perfs. Another CBL run on 5 -4 -83 only logged down to 6620' and does not add anything significant to this assessment. Well 1E -14 is currently on long term shut in due to flowline problems. Page 2 of 3 February 5, 2010, FINAL • • Quarter-Mile Injection Review j Q � KRU 1E -15A, AL1, AL2, AL2-01 — Coiled Tubing Drilling 3. KRU 1E -16 (injector, —646' away) • Completed with 7 ", 26 #, K -55 casing on 8- 13 -82. Included 13 B &W centralizers on bottom 12 joints. Cemented with 355 sacks of lead + 300 sacks of tail "G" cement. Reciprocated casing for most of job, but casing was stuck high for a little while. Maintained full returns entire job. • C -sand perf d 7193'- 7256', A -sand perf d 7396'- 7454'. The tubing tail is at 7319' MD, and the upper packer is at 7043'. The CBL of 8 -13 -82 shows excellent cement throughout the entire Kuparuk sand interval. There is no reason to expect injection out of zone. Well 1E -16 is currently on long term shut in due to flowline problems. 4. KRU 1E - 17 (injector, — 1286' away) • Completed with 7 ", 26 #, K -55 casing on 8- 24 -82. Included 12 B &W Turbo -fin centralizers on the bottom 11 joints. Cemented with 340 sacks of lead + 310 sacks of tail "G" cement. Reciprocated casing for most of job. No mention made of losses or of the quality of returns during cementing. • C -sand perfd 7373'- 7441', A -sand perf d 7587'- 7636'. The tubing tail is at 7523' MD, and the upper packer is at 7230'. The CBL of 8 -24 -82 shows excellent cement across the C -sand and A- sand perforated interval. There is no reason to expect injection out of zone. Well 1E -17 is currently on long term shut in due to flowline problems. 5. KRU 1E - 30 (injector, — 797' away) • Completed with 7 ", 26 #, K -55 casing on 9- 12 -82. Included 10 B &W Turbo -fin centralizers on the bottom 12 joints, plus 8 more uphole. Cemented with 300 sacks of lead + 350 sacks of tail "G" cement. Reciprocated casing for entire job and maintained good returns. • C -sand perfd 6792'- 6847', A -sand perfd 6991'- 7042'. The tubing tail is at 6909' MD, and the upper packer is at 6630'. The CBL of 9 -11 -82 shows excellent cement around both the C -sand and A -sand perfs. There is no reason to expect injection out of zone. Well 1E -30 is currently on long term shut in due to flowline problems. Page 3 of 3 February 5, 2010, FINAL :sa,nWM *Tar Norm WELLBORE DETAILS: 1E - 15AL2 REFERENCEINFORMADON ✓• Project: Kuparuk River Unit MagretcNo8h2ta9' FGL, Site: Kuparuk 1E Pad Magma Free Parent WelIbore: 1E -15 Co -ordinate (N/E) Reference'. Wel 1E -15, True North Well: 1E -15 5trengt57s57 Tie on MD: 7500.00 Verrnal( ND )Reference:1E- 15 @105.705(1E -15) BAKER Wetlbore: 1E -15AL2 DpAngle : ConocoPhillips Plan ;tE -15AL2 wpO5(1E-1511E- 15AL2) M ecc Section Slot - (O.00N,0.00E) nMZOOe P @ (1E-15) Measured Depth Reference: Minim 105.705 HUGHES Calculation Method: Minimum Curvature JE - 72AL7 2.11 lE- I 5 /IE -15A_ 2' 11 .___ . _ - _ 6.466 - - - il`- 12i1E- 126 ;�5 .540 - 2 11 - -_ _ _. _. _� _ - - S oo , l5- 15 /1E -I[Al I r 6346 1811 ___ _ ` ' _ ` `,, 1E- 102B-Lateral 7 El - .. 1000 - /1:1>"----- _ . ? ` R. o8 I 15i7E -15 _tip, I1: -I4 IL -Ik 800 _ _ }1111 / _ -- -_..__ _____ - _..___ ___ - .. --, ~� el 201 ▪ ° IFo671Fi16 - • 201 - li k, 1 -- tin •11 - 11111 '" - - - -- -1m • IE 15l1Ed5A1,2 - 01 - 1211 --- - _ - ' IE.I /t[`.- 75AL2` , . . . . ________ _ ___________________-- ----(.: _ _,_ ://: _1.11 --- _ -. - _- - _- - -_._ _... _\ 1 . -02 /1E -02 _1600 / _.. -1800 -_. - - - -_- -- -. I E -ion E-a0 1 E - 1 7 / 1 E - 1 7 -2111 - - -. _2211 —... - 2400 --- - 11 -341114 -34 18 .04/1E - I fi -3I E -31PE 1 -6400 -6200 -6000 -580(1 -5600 -5400 -5200 -5000 -4800 - 4600 -4400 - 4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 - 800 - 600 -400 -200 0 200 400 600 800 1000 1E -15 0 105.700 (1E -15) West( - )/East( +) (200 ft/in) AnmuratoTnrNorer WELLBORE DETAILS: 1E -15A REFERENCEINFORMATION Project: Kuparuk River Unit MagneticN0r93:21.133• III Site: KuparuklEPad Mill Well: Kuparuk Mw ex Fbu Parent Wellbore: 1E -15 Co-ordinate (NE) Reference: We11E- 15,Tme North Mi SlrerpUr57a71eoT Tie on MD: 7600.00 Vertical (IVD) Reference: 1E -15 ( 105.7011 (1E -15) Welibore: 1E -15A D ip Angle8D.84• Section(VS)Reterance: Slot (OAON, O.00E) BAKER • Conoco Phillips Dab:3/25201P h Plan: 1E -15A wp03(1E 1611E - 15A) Made! 0GG Measured Depth Reference: 1E -15(d} 105.70ft(1E -15) - -_ __ Calculation Method: Minimum Curvature HUGHES 48•1 4400 4211 -- 4000 3811 6$ 3.11 1E-11 1E -1I -- - ft-12,1k -, 3400 • 3211 3111 2800 - - •5 2.11 - O 2.11. IE- 13;IE -15A" IE- 13 /IE -13- \ o 1E- 1211E -12 — 1 _ -- • csi 2211 _ 1/4;'' \II 30?t 2111 o 1F 19/1F - 19 IE -I /10 -ISALI - - -- •` 1601 \ _. ____- - - . - - - -_� - 1601 _.. - -- • 1411 ... -._ �$g - 1201 1 • 000 �, le -u Il L rend 11 11114464i � � -- 800 " 669/ 1 1E- 102/Dd.areeal 61.00 II i 1 -0I 600 1E- 1211E -12AL2 401 -.__ 211 — " . _.__ -__. __ -_ . -____— b 0 i o b" - - 211 _ . - ___ __ -_... _ _ _ 1E4)3 /IE 1E- 16 /IE -16 I _. _. \ 1E- 3411E -3d ` --U 2/1E -02 J „ '1 E- 1511E- ISAL2 -nl -5400 -5200 -3600 -6800 -6600 -6400 -6200 -6000 -5800 -5600 5400 5200 -5000 - 4800 - 4600 -4400 -4200 -4000 -3800 3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 - 600 -400 -200 0 200 400 600 1E-15 @ 105.7Oft (1E-15) West(- )/East( +) (200 ft/in) EPA Aquifer Exemption - 40 CFR 147.102 (b)(3) 6050000 AEO 2 6000000 i i 1 AEO 1 5950000 1E-15A ML 5900000 140 CFR 147.102 (b)(3) 1 110 5850000 400000 500000 600000 700000 800000 4 • rrb aio - /3 Quarter -Mile Injection Review KRU 1E-15A, AL1, AL2, AL2 -01 — Coiled Tubing Drilling Wells Within 1/4 -Mile of 1E -15 Northwestern Laterals (A & AL1) 1. KRU 1E -15 (motherbore injector) • Completed with 7 ", 26 #, K -55 casing on 7- 31 -82. Included 23 B &W Turbo -fin centralizers. Cemented with 280 sacks of lead + 325 sacks of tail "G" cement. Reciprocated casing for most of the job. No mention in cementing reports of lost returns. • C -sand perfd 7478'- 7554', A -sand perfd 7716'- 7796'. The tubing tail is at 7682' MD and the upper packer is at 7321'. The CBL of 7 -1 -82 shows very good cement around the C -sand but generally poor cement around the A -sand, although there is cement isolation between the two intervals. There is no reason to expect injection out of zone. • Well 1E -15 is currently shut -in awaiting sundry approval to plug the A -sand and C -sand perfs. 2. KRU 1E - 11 (injector, 1001' away) • Completed with 7 ", 26 #, K -55 casing on 5 -4 -82. Target TOC = 6708' MD. Casing became stuck 13' off bottom while attempting to reciprocate casing prior to cement job. Lost full returns when casing got stuck. Cemented with 475 sacks of lead + 600 sacks of tail "G" cement with no returns during the cement job. • The CBL of 5 -5 -82 shows very poor cement around both the Kuparuk C -sand and A -sand. • Following the CBL of 5 -5 -82, they perforated at 7674' (i.e. above the C -sand) and performed a squeeze with 41 bbl "G" cement through a retainer to 1400 psi. Drilled out cement and retainer the following day and tested the squeeze perfs to 1000 psi. • On 10 -17 -84 performed additional squeeze work at 7910' (i.e. above the A -sand perfs) using 200 sacks of 15.9 ppg "G" cement. No bond log was run to assess the success of the squeeze. • 1E -11 was pre - produced in the C/A sands from April 1982 to May 1996, and was converted to injection in May 1996. The A sand was frac'd two different times -- in 1985 and 1991. Both were gelled water frac's. The C sand was never frac'd. The most recent IPROF (May 2007) showed 71% C -sand and 29% A -sand injection. Significant A to C sand crossflow was detected into the injection mandrels at 7577' and 7643' MD. • Present completion: C -sand pert d 7708'- 7794', A -sand perfd 7996'- 8076'. The tubing tail is at 7955' MD and the uppermost packer is at 7491'. Well 1E -11 has been shut in since 2007 due to flowline problems but in 2009 it was put back on miscible gas injection, and water injection is expected to resume in 2011. 3. KRU 1E - 13 (injector, 1144' away) • Completed with 7 ", 26 #, K -55 & L -80 casing on 7 -1 -82. Included 14 B &W Turbo -fin centralizers. Cemented with 564 sacks of lead + 670 sacks of tail "G" cement. Reciprocated casing for most of the job. No mention in cementing reports of lost returns. • C -sand perfd 7110'- 7192', A -sand perfd 7345'- 7416'. The tubing tail is at 7055' MD and the only packer is at 6976'. The CBL of 7 -1 -82 shows good cement around both the C -sand and A- sand perfs. There is no reason to expect injection out of zone. Well 1E -13 is currently on long term shut in due to flowline problems. Page 1 of 3 February 5, 2010, FINAL • • Quarter -Mile Injection Review KRU 1E-15A, AL1, AL2, AL2-01 — Coiled Tubing Drilling 4. KRU 1F -19 (producer, 1103' away) • Completed with 3'/2" (9.3 ppf, L -80) x 5'/2" (15.5 ppf, L -80) tapered production casing on 3- 22 -96. Included 20 centralizers on the 3%2" portion and 12 centralizers on the 5%2" portion. Cemented with 230 sacks "G" cement. Calculated TOC was 7114' MD. Reciprocated casing until 20 bbl cement had turned the corner. Poor returns during cementing, but noted a 400 psi increase in pump pressure as cement moved uphole. • A -sand perfd 9124' - 9198'. There is no packer installed, but there is a 3'/2" sealbore at the 3'/2" x 5%2" crossover at 8772'. The 3'/2" tubing seals stab into this sealbore. The CBL of 4 -12 -96 shows excellent cement adjacent to the A -sand perfs. Well 1F -19 is actively producing from the A -sand. Wells Within 1/4 -Mile of 1E -15 Southeastern Laterals (AL2 & AL2 -01): 1. KRU 1E -06 (producer, —938' away) • Completed with 9% ", 47 #, L -80 casing on 9 -7 -80. No casing detail available. Cemented in 2 stages: first stage out the shoe and the second stage through a DV collar at 7127' MD. Cemented via the shoe with 300 sacks (stage #1) and via the DV collar with 900 sacks (stage #2) of "G" cement. There were no returns during the second stage of cementing through the DV collar. Drilled ahead to 9847' MD, but later the open hole and a portion of the cased hole was plugged back in stages to 7400'. • The CBL of 9 -20 -80 only logged down to 7124' MD, but it shows very poor quality cement across both the C -sand and A -sand perfs. • In December 1984 performed a cement squeeze at 6760' MD (i.e. below the C -sand perfs) through a retainer with 100 sacks of "G" cement (-80 sacks behind pipe). Achieved a squeeze pressure of 3000 psi. No bond log was run to assess the success of the squeeze, nor did they pressure test the squeeze after drilling out. • The most recent PPROF in 1E -06 was obtained in March 2009. It showed 79% C -sand to 21% A- sand production contributions. No crossflow was detected. Both the A and C sand have been frac'd in this well. The A -sand was a gelled water batch frac in 1985, and the C -sand was frac'd with 71,000 lbs in 1988. • Present completion: C -sand pert d 6648'- 6710', A -sand pert d 6838'- 6900'. Tubing tail is at 6801' MD, and the uppermost packer is at 6538'. Well 1E -06 is presently shut in due to low productivity, but it is expected to benefit from injection into the 1E -15 CTD laterals. 2. KRU 1E - 14 (producer, 1430' away) • Completed with 7 ", 26 #, K -55 casing on 7- 16 -82. Included 12 B &W Turbo -fin centralizers on bottom 12 joints, plus 8 more uphole. Cemented with 350 sacks of lead + 425 sacks of tail "G" cement. Reciprocated casing for entire job and maintained full returns. • C -sand perf'd 6660'- 6724', A -sand perf'd 6853'- 6888'. The tubing tail is at 6803' MD, and the upper packer is at 6430'. The CBL of 7 -17 -82 shows adequate cement across the C -sand perfs and excellent cement across the A -sand perfs. Another CBL run on 5 -4 -83 only logged down to 6620' and does not add anything significant to this assessment. Well 1E -14 is currently on long term shut in due to flowline problems. Page 2 of 3 February 5, 2010, FINAL Quarter -Mile Injection Review KRU 1E-15A, AL1, AL2, AL2-01 — Coiled Tubing Drilling 3. KRU 1E -16 (injector, —646' away) • Completed with 7 ", 26 #, K -55 casing on 8- 13 -82. Included 13 B &W centralizers on bottom 12 joints. Cemented with 355 sacks of lead + 300 sacks of tail "G" cement. Reciprocated casing for most of job, but casing was stuck high for a little while. Maintained full returns entire job. • C -sand perf d 7193'- 7256', A -sand perf d 7396'- 7454'. The tubing tail is at 7319' MD, and the upper packer is at 7043'. The CBL of 8 -13 -82 shows excellent cement throughout the entire Kuparuk sand interval. There is no reason to expect injection out of zone. Well 1E -16 is currently on long term shut in due to flowline problems. 4. KRU 1E - 17 (injector, 1286' away) • Completed with 7 ", 26 #, K -55 casing on 8- 24 -82. Included 12 B &W Turbo -fin centralizers on the bottom 11 joints. Cemented with 340 sacks of lead + 310 sacks of tail "G" cement. Reciprocated casing for most of job. No mention made of losses or of the quality of returns during cementing. • C -sand perfd 7373'- 7441', A -sand perfd 7587'- 7636'. The tubing tail is at 7523' MD, and the upper packer is at 7230'. The CBL of 8 -24 -82 shows excellent cement across the C -sand and A- sand perforated interval. There is no reason to expect injection out of zone. Well 1E -17 is currently on long term shut in due to flowline problems. 5. KRU 1E - 30 (injector, — 797' away) • Completed with 7 ", 26 #, K -55 casing on 9- 12 -82. Included 10 B &W Turbo -fin centralizers on the bottom 12 joints, plus 8 more uphole. Cemented with 300 sacks of lead + 350 sacks of tail "G" cement. Reciprocated casing for entire job and maintained good returns. • C -sand pert d 6792'-6847', A -sand pert d 6991'-7042'. The tubing tail is at 6909' MD, and the upper packer is at 6630'. The CBL of 9 -11 -82 shows excellent cement around both the C -sand and A -sand perfs. There is no reason to expect injection out of zone. Well 1E -30 is currently on long term shut in due to flowline problems. Page 3 of 3 February 5, 2010, FINAL t Ku River Unit /Mime/Ise True More WELLBORE DETAILS: 1E -15A REFERENCE INFORMATON Project: Kuparuk North: Krill Slte: Kuparuk 1E Pad Magnetic Feld Parent Wellbore: 1 E -15 Co-ordinate (N /E) Reference: Well 1E-15, True North `� Weil: 1E - Strength: 57e67.2005 T ie on MD: 7600.00 V ertical (TVS )Reference: ) Reference: Sbt- (0.00N, 0. E) R(1E -15j �'� ConocoPhillips oD ata3/ /2010 Measured Sbt -1 ,70ft Section Plan: 1E 15Awp03 (1E 1511E - 150) leeeleactiuxt Measured Depth Reference: 1E -15 @ 105,70ft (1E -15) Calculation Method: Minimum Curvature LS 4800 -I I 46001 44001 _. - . -..._ 4200 - -- 4000 - 3811 —___.. lE- II/18 -11" 3600 3 ,a • o° 3200 b�. >. 3000 2:11 __ •EE•• 2 °11 _... -__. _ ___ IE- 13/10 -13- 1S 9 C 2400 IE -I511E -150' __- y ,,�c� \ b46 1E- 121E -12 1 X 2211 , 1� _000 t 2000 O -. - _-___- -_ 634 IF- 19/1F -19 1 -41 /1E -15AL1 1111111 1801 \ __ _ - _ - -- 1 4k 4,, _ t 1600 's O g ' 1400 a - \41 4014144,0 : s \-.‘, ...,,...,:, EA • lzoo 1000 li - n "No \ 1E- 102/D- Latew1 800 ." - -- Z&14R 11 69/ 62* IE- 12/1E- 12AL2 -01 600- _..... -_. __.. _ IE•12 /IE -L2AL2 400 _ __._ zoo- -b° , • 4 1E4/6/1E -06 _� 1E -03/IE -03 -200 - 4001 ! 1 1E- 16 /1E -16 • � - - - -- " \ -02/1E -02 -600- -- - r ' 1E- 34/18 -34 g 1E- 15/1E -01 1 -6800 - 6600 -6400 - 6200 -6000 -5800 -5600 -5400 -5200 - 5000 -4800 -4600 - 4400 -4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 - 800 - 600 - 400 - 200 0 200 400 600 1E -15 i 105.708 (1E -15) West( - )/East( +) (200 ft/in) ' . Azlmw,etrr True North WELLBORE DETAILS: 1E -15AL2 REFERENCE INFORMATION i Project: KuparukRiverUnit MagneocNoM:21.83• .a.. Site: Kuparuk 1E Pad M,a,,,a F;,d Parent Wellbore: 1E -15 Coordinate (N/E) Reference: Well 1E -15, True North Well: 1E Seergu�: 57657.1e Vertical (TVD) Reference: 1E-15 @ 105.7011 (1E -15) BAKER Tie on MD: 7500.00 �](, Wellbore: 1E - 15AL2 D da134 e: M2006 Section (VS) Reference: Slot- (0.00N, 0.00E) COtt000�11(� S Dab:Y252oi0 Measured Depth Reference: 1E -15 105.70fl(1E -15) p Plan :1E - 15A1 ? 15I1E 15ALZ1 MotletBIX3M2706 Calculation Calculation Method: Minimum Curvature HUGHES 1E- 12 /1E -12AL1 2.11 - . — . IE15 /IE15A_ 7. 2400._ _.. 666 2200 -- -- 1r,io 6 . 0 0 IF 2000 - - - - f 0346 1800 - i - - 1E 13 1601 - -_ i 1401 - _ 1201 __ - 1000 -- - 8 8 8 1.1 — _ r 1E -14 . \ C 6 .,,o E- 12/1E -12 Al C 600 _ — \_ . o c el 200 _. - ___.__ y'8 __. -_ - - -_ - - - - -.. – q .S lE-0W1E-06 -- . t 1E - 01 IF .: x ' , Ilk . , 1 C4 1E -10 11 w of 3 • - 800. _ - - - __ - - _ _ ___- _ -. _ __ - - -_. -- - --_ -_ - _. -- - - 1000 - __ 40 E- 1? /lE- I�AL2 -0 t - 1200 — .. 1E -15 /IE TSALT - 1400 iiit- 1' 1 2 /IE -02 - 1600 _. ; - 1800. - -.. _ _ - - -.. _ IE 30/IE - 30 1E ‘ . •••• /) , - 2000_ v. - - ... - 2200 - 1E 34/1E - 34 - 2400_._- - 2600 - -- 1E - 04/1E - 04 16 3111E 316731 f -6400 - 6200 -6000 -5800 -5600 -5400 -5200 -5000 -4800 - 4600 - 4400 - 4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 - 1200 - 1000 - 800 - 600 - 400 - 200 0 200 400 600 800 1000 1E-15 @ 105.70ft (1E-15) West( - )/East( +) (200 ft/in) 4110 • TRANSMITTAL LETTER CHECKLIST WELL NAME KUPARUK RIVER UNIT 1E -15A PTD# 2100130 Development X Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: KUPARUK POOL: KUPARUK RIVER OIL RIVER POOL Circle 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 segment of existing well , Permit No. (If last two digits in API No. . Production / injection should API number are continue to be reported as a function of the original API number between 60 -69) stated above. PILOT HOLE In accordance with 20 AAC 25.005(0, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( 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 perforate and 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: 1/11/2008 .,' Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well —_ -_ Name: KUPARUK RIV UNIT 1E -15A Program SER Well bore seg ❑ PTD #: 2100130 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type SER / PEND GeoArea 890 _ Unit 11160 On /Off Shore On Annular Disposal ❑ Administration 11 Permit fee attached NA 2 Lease number appropriate Yes Top prod interval and TD in ADL 25651 1 3 Unique well name and number Yes 4 Well located in a defined pool Yes 5 Well located proper distance from drilling unit boundary Yes Kuparuk River Oil Pool, governed by Conservation Order No. 432C 6 Well located proper distance from other wells Yes Conservation Order No. 432C contains no spacing restrictions with respect to drilling unit 7 Sufficient acreage available in drilling unit Yes boundaries and no interwell spacing restrictions. Wellbore will be more than 5 miles 8 If deviated, is wellbore plat included Yes from an external property line where ownership or landownership changes. 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15 -day wait Yes SFD 1/27/2010 I • 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes Area Injection Order No. 2B 15 All wells within 1/4 mile area of review identified (For service well only) Yes KRU 1E-11, KRU 1E-13, KRU 1F-19 16 Pre - produced injector: duration of pre production less than 3 months (For service well only) No Well will be flowed back for cleanup only. 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 18 Conductor string provided NA Conductor set in 1 E -15 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in 1E -15 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in 1E-15 21 CMT vol adequate to tie -in long string to surf csg NA Production casing set in 1 E -15 22 CMT will cover all known productive horizons No OH slotted liner completions are planned. 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig equipped with steel pits. All waste to approved disposal wells. 25 If a re- drill, has a 10-403 for abandonment been approved Yes 310 -023 126 Adequate wellbore separation proposed Yes Proximity analysis performed. No issues. 27 If diverter required, does it meet regulations NA Wellhead in place. BOP installed on tree. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pressure= 4895 psi. (14.9 ppg) Expected Pressure is 11.5 ppg ... will drill with 10.0 ppg & MPD. GLS 1/28/2010 29 BOPEs, do they meet regulation Yes 130 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 4264 psi Will test BOP to 5000 psi • 1 31 Choke manifold complies w /API RP -53 (May 84) Yes 1 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes H2S on 1E pad. Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) Yes AOR complete for area impacted by lateral. - -- - - - - - -- - - - - -- 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 1E pad are H2S-bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Expected reservoirpressure is 11.5 ppg EMW; however, 1E -15 was an injector, so pressures Appr Date 37 Seismic analysis of shallow gas zones NA encountered may reach 15.1 ppg. Will be drilled using 10.0 ppg mud and managed pressure SFD 1/27/2010 38 Seabed condition survey (if off - shore) NA drilling technique to keep ECD at about 12.4 ppg. Hazards program notes potential for 39 Contact name /phone for weekly progress reports [exploratory only] NA encountering high- pressure (15+ ppg) stringers while drilling. Mitigation measures discussed. Geologic Engineering Pu..:� Re -drill of A -sand injector to improve sweep efficiency. Commissioner: Date: Com issioner: Date Co �� er Date
