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207-015
C:\Users\grgluyas\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\R97USUAM\2024-11-24_22200_KEU_1J-160_InjectionProfile_Transmittal.docx DELIVERABLE DISCRIPTION Ticket # Field Well # API # Log Description Log Date 22200 KRU 1J-160 50-029-23344-00 Injection Profile 24-Nov-24 DELIVERED TO Company & Address DIGITAL FILE # of Copies LOG PRINTS # of Prints CD’s # of Copies 1 AOGCC Attn: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Ak. 99501-3539 Delivered By: CPAI Sharefile ______________________________ _____________________________________ Date received Signature ______________________________ ______________________________________ PLEASE RETURN COPY VIA EMAIL TO: DIANE.WILLIAMS@READCASEDHOLE.COM READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM 207-015 T39854 12/11/2024 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.11 10:52:25 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, July 22, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1J-160 KUPARUK RIV U WSAK 1J-160 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/22/2022 1J-160 50-029-23344-00-00 207-015-0 W SPT 3212 2070150 1500 592 592 592 593 261 264 264 264 4YRTST P Adam Earl 5/7/2022 MIT IA 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 U WSAK 1J-160 Inspection Date: Tubing OA Packer Depth 1155 2000 1950 1935IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE220509083708 BBL Pumped:2.4 BBL Returned:2.2 Friday, July 22, 2022 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, June 13, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1J-160 KUPARUK RIV U WSAK 1J-160 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ 1J-160 50-029-23344-00-00 207-015-0 W SPT 3212 2070150 1500 592 592 592 593 261 264 264 264 4YRTST P Adam Earl 5/7/2022 MIT IA 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 U WSAK 1J-160 Inspection Date: Tubing OA Packer Depth 1155 2000 1950 1935IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE220509083708 BBL Pumped:2.4 BBL Returned:2.2 Monday, June 13, 2022 Page 1 of 1 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2022.06.13 15:23:52 -08'00' VS -11. PROACTIVE DIAGNOSTIC SERVICES, INC. WELL LO TRANSMITTAL To: AOGCC Natural Resources Technician 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 793-1225 207015 30400 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 : 1) Injection Profile 2) Signed . Print Name: ProActive Diagnostic Services, Inc. Attn: Diane Williams 130 West International Airport Road Suite C Anchorage, AK 99518 pdsanchoraaeO.memorvloa com 07 -Mar -19 11-160 CD M%E^E'Vr MAR 2 2 2019 CC AOG 50-029-23344-00 Date :al�w zfi/� PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245$952 E-MAIL: POSANCHORAGEaMEMORYLOGCOM WEBSITE: V—M.MEMORYLOG.COM D.6 -U.-..; .m_ .Cib.\Temple-aib-�;i m\Ti m111.U_a �Phft, 'Gan.,mh.dncc MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Monday,May 14,2018 Jim Regg P.I.Supervisor {`1 ? S''Zi I/6 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA,INC. 1J-160 FROM: Lou Laubenstein KUPARUK RIV U WSAK 1J-160 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV U WSAK 1J-160 API Well Number 50-029-23344-00-00 Inspector Name: Lou Laubenstein Permit Number: 207-015-0 Inspection Date: 5/9/2018 Insp Num: mitLOL180510145156 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1J-160 Type Inj W TVD 3212 Tubing 288 288 - 291 - 290 PTD 2070150 Type Test SPT Test psi 1500 IA 980 2000 - 1935 - 1925 BBL Pumped: 3 BBL Returned: 2.6 OA 254 258- 258 - 258 - Interval 4YRTST JP/F P1. Notes: SCANNED JUN 0 4 18 Monday,May 14,2018 Page 1 of 1 • 0► to - X coa �J ' 3J i COco ,N W rco > / _ N E 0) O• W o E. u N y+ > _in c0 Y0 y N Q V p, a O O T +-, o� +., c -6 a +J a I CI O O n n n n n 1••• n v O JQu NO -1w :1, 111111 v- C _C 0 VI O N N 00 C L C Q N u -0 CO O ++ u O >_ 0) }' co O C v O Nu O O O O O O a.,- Q L L" J J J J J J J - C U O t- ).- W W W W W W W vl v ' ,•-• I- LL LL LL LL LL LL LL a) 0 Q > a) t0 1- 0 0 0 Q Q Q Q a) '^ O 4L. O Z Z Z Z Z Z Z N L a) .O a) LL LL LL LL LL LL LL CC L C > � a vo > Er. +'' _c O E 0E.0 t^ 2 N Q c u > 00 O C O to > U a) 0 co 0 V 2 Q aa)) a o c a U CO ' LL LL LL O) F E c• O p -i00 ,0 c 2 Y O w O IY tYcea V u CZ . 1:$ u m a a a /- N O. 0 aEa U 4 I r�I W `n ' 4D M1 J v I. O� > O \ p CJ o 01 m6l< W d1-4 r4 N °" zLI CO as o \ S I3 0 a. Ida W U Io.- J J J J J J J11 Zo� Zc � � �� 1 y� w a v ► w w w w w W CCCCCC w W W W W W4 VI w > > > > > > > z Y Y Y Y Y Y Y O > > > > > > > CLCCCCMCLCCW a) 4-; Q 1,w Q Q Q Q Q Q Q . a a a a a a a 0 Y Y Y Y Y Y Y �„ CC G LJ X n (0 =0w O O) O N O) O CO 1.1.. C.4 U N N a-▪ O O O E r7 0 o 0.0 0 0 0 0 0 0 10 W 10 CV 0 0 0 0 ,CO ,CO ,CO › U5ccw0000000 a W Q �0 V) w U 0 0E � N IX 0 '. 0 0 0 0 O 0 4., O c LCI O 0 O O O O O V Q N. o 0 0 00 0o co : 4) N M n '7 CO n n Q n') N M M M VN 00 ) = - N ! O O M M M M E - N N N N N N N N In L L N M o) o) o) o) o) o) c o a RO N N N N N N Ql ,:,,: :}.; 0 0 0 0 0 0 CO u 0 6 6 0 0 0 0 O 1+- C O 0000 C V) V) 1() V) V) V) V) d 0U O as in -I= Iw- Q) f0 ... u c ,. U C. m E v co a z w E E c rn U al Q ^ G c0 Q) Y Y W ,a z .a`-1 m m z N 0 CO M o0 0�0 •�"' E h u aJ d moor a 4 `O N � N r- N a- N S = E co W 0 0 72 IfiZ a IIY�M '-i LJ.1 a-+ ra O 1 a Q I- a a H H Image Pect Well History File Co~r Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~~~ ~- ~ ~~ Well History File Identifier Two-sided II I II II II II II ((~ III ^ Rescan Needed II I II II II II I I II ~ III Organizing (done) RE AN DIG TAL DATA Color Items: Diskettes, No, ^ Greyscale Items: ^ Other, No/Type: ^ Poor Quality Originals: ^ Other: OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES: ^ Other:: BY: Maria Date: ~ ~ ~ /s/ Pro'ect Proofing II I II ~I II I I III I I III ! n BY: Maria Date: ~ ~ ~- (, /s/ (- Scanning Preparation ~ x 30 = / ~ ~ + ~._ =TOTAL PAGES / (Count does not include cover sheet) I/~/~ BY: _ Maria Date: ~~~ ~- ~~~ /s/ ~° 1 Y Production Scanning Stage 1 Page Count from Scanned File: ~~'_T (Count does include/c'o~ver sheet) Page Count Matches Number in Scanning Pr paration: !/ YES NO BY: Maria ~~°, Date: ~~~ ~ ~~ /s/ ~~~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scannin is complete at this point unless rescanning is required. ~) I II'I ~) I II II I I III 9 ReScanned III IIIIII (III) IIIII BY: Maria Date: /s/ Comments about this file: Quality Checked III II~III III (III III 10/6!2005 Well History File Cover Page.doc Page 1 of 2 • 0 Maunder, Thomas E (DOA) From: NSK West Sak Prod Engr [n1638 @conocophillips.com] Sent: Tuesday, September 20, 2011 9:53 AM To: CPF1 Prod Engr; Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; NSK West Sak Prod Engr; Hutcherson, Mark R; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt; NSK Prod Engr Specialist Subject: RE: RLPP /SSV defeated on multiple 1J West Sak injectors: 16- Sept -2011 Tom and Jim, The low pressure pilots (LPP) on the wells listed below have been returned to service on 9/20/2011 after the wellhead injection pressure stabilized above the setting of the low pressure pilot. Current wellhead pressure pressures and injection rates are also listed below. This pilot had been defeated on 9/16/2011 in accordance with "Administrative Approval No. CO 406B.001." The injection pressures has increased on the following wells so as to remain above 500 psi and the LPP /SSV function has been returned to normal. Well Permit to Drill #s Wellhead Injection Pressure (PSI) Injection Rate (BWPD) 1J-156 (206-067, 555 1095 _:_1J-160 (207 -015)207- 016,207 -017) 545 607 Please let me know if you have any questions. Jenn Gauer Work - 907.265.6782 Mobile - 303.248.6641 ,, a > �y SEP ` • ? (I 2 0 1 uV rh w ar J From: CP • od Engr Sent Friday, Se• ber 16, 2011 6:44 PM To: 'tom.maunder a.gov'; 'jim.regg @alaska.gov' Cc: CPF1 DS Lead Techs, • Fl Ops Supv; NSK Problem Well Supv; NSK West Sak Prod Engr; Hutcherson, Mark R; NSK Prod Engr & Optimization Supv; Seir c ian; CPF1&2 Ops Supt; NSK Prod Engr Specialist; Gauer, Jenn L Subject: RLPP /SSV defeated on tiple 13 West Sak injectors: 16 -Sept -2011 Tom and Jim, The low pressure pilots (LPP) on the followin • . ells were defeated on 09/16/2011 when the injectors were returned to service after being shut in since Augu 7, 2011 for pipeline pigging facility modifications. The LPP and SSV have been tagged and their status is record ' the "Facility Defeated Safety Device Log" since the wells are all either below 500 psi or very close. As of 18 b • s on 09/16/2011, wellhead injection pressure and injection rates are as follows for each well: Well Permit to Drill #s Wellhead Injec ': I Pressure (PSI) Injection Rate (BWPD) 1J-105 (207 - 027,207 -028,207 -029) 345 639 1J-118 (206- 176,206- 177,206 -178) 327 1020 1J -127 (206 -047,206 -048, 206 -049) 337 934 1J-154 (205- 036,205 -037) 369 623 1 J -160 (207- 015,207 - 016,207 -017) 352 568 9/20/2011 • Page 1 of 1 Maunder, Thomas E (DOA) From: CPF1 Prod Engr [n1269 @conocophillips.com] Sent: Friday, September 16, 2011 6:44 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; NSK West Sak Prod Engr; Hutcherson, Mark R; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt; NSK Prod Engr Specialist; Gauer, Jenn L Subject: RLPP /SSV defeated on multiple 1J West Sak injectors: 16- Sept -2011 Tom and Jim, The low pressure pilots (LPP) on the following wells were defeated on 09/16/2011 when the injectors were returned to service after being shut in since August 17, 2011 for pipeline pigging facility modifications. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log" since the wells are all either below 500 psi or very close. As of 1830 hrs on 09/16/2011, wellhead injection pressure and injection rates are as follows for each well: Well Permit to Drill #s Wellhead Injection Pressure (PSI) Injection Rate (BWPD) 1J-105 (207- 027,207- 028,207 -029) 345 639 1J-118 (206- 176,206- 177,206 -178) 327 1020 1J-127 (206- 047,206 -048, 206 -049) 337 934 1 J -154 (205-036,205-037) 369 623 1 J -1 0 207- 01b07- 016,207 -017) 352 568 1J-164 (205- 144,205 -145, 205 -146) 479 1082 1J-180 (206- 150,206 -151) 537 478 1 J -184 (206- 044,206 -045) 502 646 The AOGCC will be notified when the injection pressures have increased so as to remain above 500 psi and the LPP /SSV function is returned to normal, in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. David Lagerlef /Dan Bearden CPF1 Production Engineers n1269 @conocophillips.com 659 -7493 pager 659 -7000 765 I I 9/19/2011 • Page 1 of 1 Maunder, Thomas E (DOA) From: Gauer, Jenn L [ Jennifer .L.Gauer @conocophillips.com] Sent: Friday, January 07, 2011 3:53 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; Jenkins, Lubbie Allen; NSK West Sak Prod Engr; Hutcherson, Mark R; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt; CPF1 Prod Engr g Subject: LPP /SSV Returned to Service on 1J -160 - 07- January-2011 ( 1o7 Tom / Jim, The low pressure pilot (LPP) on tri- lateral injector 1J -160 (PTD 207 -015, 207 -016, 207 -017) was returned to service on 1/7/2011 after the wellhead injection pressure stabilized above the setting of the low pressure pilot. Current wellhead pressure is 518 psig; injection rate is 641 bwpd. This pilot had been defeated on 12/7/2010 in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. ConocoPhillips Alaska, Inc. E West Sak Production Engineer A 1 Work - 907.265.6782 r ' Mobile - 303.248.6641 From: Pierson, Chris R Sent: Tuesday, December 07, 2010 10:41 AM To: 'Maunder, Thomas E (DOA)'; 'jim.regg @alaska.gov' Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; Jenkins, Lubbie Allen; Gauer, Jenn L; NSK West Sak Prod Engr; Hutcherson, Mark R; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt Subject: LPP /SSV defeated on 13-160 - 07- DECEMBER -2010 Tom / Jim, The low pressure pilot (LPP) on 1J -160 (PTD 207 -015, 207 -016, 207 -017) was defeated on 12/07/2010 when the well was returned to service after being shut in since October 29, 2010. As of 10:40 hrs on 12/7/2010, wellhead injection pressure is 410 psi; injection rate is 592 bwpd. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP /SSV function is returned to normal, in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. Chris Pierson West Sak Production Engineer Conocophillips Alaska, Inc. Office: 265 -6112 CeII: 240 -5056 1/7/2011 Page 1 of 1 Maunder, Thomas E (DOA) From: Pierson, Chris R [Chris. R. Pierson@conocophillips.com] Sent: Tuesday, December 07, 2010 10:41 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Ops Supv; NSK Problem Well Supv; Jenkins, Lubbie Allen; Gauer, Jenn L; NSK West Sak Prod Engr; Hutcherson, Mark R; NSK Prod Engr & Optimization Supv; Seitz, Brian; CPF1 &2 Ops Supt Subject: LPP /SSV defeated on 1J -160 - 07- DECEMBER -2010 Tom / Jim, The low pressure pilot (LPP) on >6, 207 -016, 207 -017) was defeated on 12/07/2010 when the well was returned to service after being shut in since October 29, 2010. As of 10:40 hrs on 12/7/2010, wellhead injection pressure is 410 psi; injection rate is 592 bwpd. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP /SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Chris Pierson West Sak Production Engineer Conocophillips Alaska, Inc. Office: 265 -6112 Cell: 240 -5056 KJAM DEL' 0 ZU1U 12/9/2010 • ~ ~ ~ ~ "- x ~~. ~. ~; }" ~~ ~ ~ ~~„. ~ Y. ' g ' ~ , ~~' MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: ~ DATE: Monday, May 24, 2010 Jim Regg ' \~ (~~ I I ~" P.I. Supervisor ~ ( SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1J-160 FROM: $pl) NOble KUPARUK RIV U WSAK 1J-160 Petroleum Inspector Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv :~~'?s- Comm Well Name: KUPARUK RIV U WSAK 1J-160 API Well Number: 50-029-23344-00-00 Inspector Name: Bob Noble Insp Num: mitRCN100516143944 Permit Number: 207-015-0 Inspection Date: 5/14/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well P.T.D 1J-160 ` 2070150 Type Inj. TypeTest W I TVD sPT Test psi 3212 ~ IA 1680 '~~ OA 925 332 1680 '~ 333 1650 333 ~ 1640 ~ 334 Interval 4YRTST prn, P '' Tubing 626 626 ~ 626 -625 Notes: A,l~ ~ . r ~~ GL ~(eq*- t S~%~~s ~i,~, ~ 'y~ ~ F.~... iG.iF ~FV I} ~~vh 6Y -M. ivT ~ . . V Monday, May 24, 2010 Page 1 of 1 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION. COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; phoebe.brooks@alaska.gov; tom.maunder@alaska.gov; doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Kuparuk /KRU / 1J 05/14!10 Colee /Phillips - AES Bob Noble ~ '~~~ ~~ Packer Depth Pretest Initial 15 Min. 30 Min. Well 1J-102 Type Inj. W TVD 3,566' Tubing 657 656 655 654 Interval 4 P.T.D. 2061100 Type test P Test psi 1500 Casing 990 1,700 1,680 1,680 P/F P Notes: OA 165 205 172 165 Well 1J-105 Type Inj. W TVD 3,639' Tubing 558 558 558 557 Interval 4 P.T.D. 2070270 Type test P Test psi 1500 Casing 1,098 1,800 1,780 1,780 P/F P Notes: OA 155 156 156 156 Well 1J-118 Type Inj. W TVD 3,599' Tubing 657 658 658 658 Interval 4 P.T.D. 2061760 Type test P Test psi 1500 Casing 1,100 1,790 1,780 1,780 P/F P Notes: OA 175 192 177 175 Well 1J-122 Type Inj. G TVD 3,684' Tubing 1,751 1,751 1,751 -1,750 Interval 4 P.T.D. 2070700 Type test P Test psi 1500 Casing 809 1,690 1,640 1,620 P/F P Notes: OA 141 214 174 156 Well 1J-127 Type Inj. W TVD 3,482' Tubing 620 620 622 622 Interval 4 P.T.D. 2060470 Type test P Test psi 1500 Casing 1,020 1,700 1,680 1,680 P/F P Notes: OA 206 273 260 253 Well 1J-136 Type Inj. N TVD 3,503' Tubing 600 600 600 600 Interval 4 P.T.D. 2061540 Type test P Test psi 1500 Casing 276 1,700 1,670 1,660 P/F P Notes: OA 173 183 182 180 Well 1J-154 Type Inj. W TVD 3,437' Tubing 624 624 624 624 Interval 4 P.T.D. 2050350 Type test P Test psi 1500 Casing 1,098 1,850 1,840 1,840 P/F P Notes: OA 527 527 527 527 Well 1J-156 Type Inj. W TVD 3,410' Tubing 628 625 623 620 Interval 4 P.T.D. 2060670 Type test P Test psi 1500 Casing 1,147 1,900 1,890 1,890 P/F P Notes: OA 206 206 206 205 Well 1J-160 Type Inj. W TVD 3,212' Tubing 626 626 626 q~ 625 Interval 4 P.T.D. 2070150 Type test P Test psi 1500 Casing 925 1,680 1,650 1,640 P/F P Notes: OA 332 333 333 334 ~. ../' J V yr V MIT Report Form BFL 11/27/07 KRU 1J pad 05-14-10.x1s • Packer Depth Pretest Initial 15 Min. 30 Min. Well 1J-164 Type Inj. W TVD 3,424' Tubing 580 578 576 576 Interval 4 P.T.D. 2051440 Type test P Test psi 1500 Casing 140 1,700 1,690 1,690 P/F P Notes: OA 731 731 732 732 Well 1J-170 Type Inj. G TVD 3,392' Tubing 1,863 1,865 . 1,866 1,866 Interval 4 P.T.D. 2060620 Type test P Test psi 1500 Casing 440 2,600 2,560 2,550 P/F P Notes: OA 155 304 243 217 Well 1J-176 Type Inj. W TVD 3,159' Tubing 665 Interval 4 P.T.D. 2070990 Type test P Test psi 1500 Casing 1,268 P/F Notes: Test inconclusive OA 170 Pumped 10 and pressured up 100 psi. Need to top off and retest. Well 1J-180 Type Inj. W TVD 3,290' Tubing 584 584 585 587 Interval 4 P.T.D. 2061500 Type test P Test psi 1500 Casing 1,050 1,690 1,680 1,680 P/F P Notes: OA 145 226 225 224 Well 1J-184 Type Inj. W TVD 3,337' Tubing 598 598 597 597 Interval 4 P.T.D. 2060440 Type test P Test psi 1500 Casing 925 1,700 1,680 1,680 P/F P Notes: OA 165 220 178 172 i/ ,v/ V ,~ TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D =Drilling Waste M =Annulus Monitoring I =Initial Test G =Gas P =Standard Pressure Test 4 =Four Year Cycle I =Industrial Wastewater R =Internal Radioactive Tracer Survey V =Required by Variance N =Not Injecting A =Temperature Anomaly Survey T =Test during Workover W =Water D =Differential Temperature Test O =Other (describe in notes) MIT Report Form BFL 11/27/07 KRU 1J pad 05-14-10.x1s • Page 1 of 1 Maunder, Thomas E (DOA) From: Pierson, Chris R [Chris.R.Pierson@conocophillips.com] Sent: Monday, May 03, 2010 11:07 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Engr; CPF1 Ops Supv; NSK Problem Well Supv; Hutcherson, Mark R; NSK West Sak Prod Engr Subject: LPP/SSV Returned to Service on 1 J-160 - 05-02-2010 Tom /Jim, The low pressure pilot (LPP) on tri-lateral injector 1J-160 (PTD 207-015, 207-016, and 207-017) was returned to service on 05/02/2010 after the wellhead inject a the setting of the low pressure pilot. Current wellhead pressure is 554 psig; injection rate is 920 bwpd. This pilot had been defeated on 03/01/10 in accordance with "Administrative Approval No. CO 4066.001." Please let me know if you have any questions. Chris Pierson West Sak Production Engineer Conocophillips Alaska, Inc. Office: 265-6112 Cell: 240-5056 '~.. w „ t~ ~:5..- - 5/3/2010 • • Page 1 of 1 Maunder, Thomas E (DOA) From: Pierson, Chris R [Chris.R.Pierson@conocophillips.com] Sent: Monday, March 01, 2010 2:01 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Engr; CPF1 Ops Supv; NSK Problem Well Supv; Hutcherson, Mark R; NSK West Sak Prod Engr Subject: LPP/SSV defeated on 1J-160 - 01-March-2010 Tom /Jim, The low pressure pilot (LPP) on tri-lateral injector 1J-160 (PTD 207-015, 207-016, and 207-017) was defeated on 3/01/2010 when the well was returned to injection service after being shut in for 39 days. Current wellhead pressure is 245 psig; injection rate is 840 bwpd. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. Chris Pierson West Sak Production Engineer Office: 265-6112 Cell: 240-5056 r., r 3/1/2010 Page 1 of 1 ~ • Maunder, Thomas E (DOA) From: CPF1 Prod Engr [n1269@conocophillips.com] Sent: Monday, November 09, 2009 6:13 AM To: NSK West Sak Prod Engr; Maunder, Thomas E{DOA); Regg, James B(DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; Rodgers, James T Subject: LPP/SSV defeated on 1J-160 - 08-NOV-09 Tnm / Jim, The low pressure pilot (LPP) on 1J-160 (PTD 207-015, 207-016, 207-017) was defeated on 11/08/2009 when the well was returned to service after being shut in for 25 days. Current wellhead pressure is 188 psi; injection rate is 1130 bwpd. We expect to have the LPPs returned to service in appraximatety one week. The LPP and SSV have been tagged and their status is recorded in the "Facility pefeated Safety Device Log." Permit to drill numbers: The AOGCC wilt be notified when the injection pressure has increased to above 500 psi and the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 406B.001." Please let me know if you have any questions. David Lloyd Lagerlef/Kenneth Lloyd Martin CPF9 Production Engineers r\~; ;~; ~' 2~~~ n1269@conocophillips.com ¢.,~~-~t '_ ~ ~ ` '` ax5 ~ Ya' 659-7493 ~~'~'° "` pager 659-7000 765 From: SK West Sak Prod Engr Sent: Sa#u , February 16, 2008 1:43 PM To: 'Maunder, mas E (QOA)'; jim.regg@alaska.gov' Cc: CPF1 DS Lead s; CPFl Prod Supt; Rodgers, James T; NSK West Sak Prod Engr Subject: LPP/5SV de ed on 1J-160 „ Tom / Jim, Tti.`eS s~ ~~'~~~ The low pressure pilat (LPP) on 1J- PTD 2~7-015, -016, 207-017) was defeated on 2/16/2008 when the well was returned to service after being shut ~ r 12 d . Current wellhead pressure is 472 psi; injection rate is 1408 bwpd. We expect to have the LPPs returned rvice in approximately one week. The LPP and SSV have been tagged and their status is recorded in the " ility feated Safety Device Log." Permit to drill numbers: The AOGCC will be notified wh~ injection pressure is returned to normal, in acco nce with "Administrative Please let me know i u have any questions. Regards, Hai Hun~ ~Hai Hunt / Eric Hollar NSK West Sak Production Engineer ConocoPhiflips Alaska, Inc. Phane: (907) 659-7061 Fax: (9Q7) 659-7749 Email: n1638@ConocoPhillips.com to above 500 psi and the tPP/SSV function CO 4066.001." 11/10t2009 • • Page 1 of 2 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, July 02, 2009 12:42 PM To: 'NSK Prod Engr SpecialisY Subject: RE: -160L2 ~~--~~~ o~~R --fl ~ ~ Darrell, I have reviewed the file and see what Eric wrote about. There was no penetration drilled out of the 9-5/8" casing that was set at 9150'. The "B" or L1 lateral exited the casing at -8750' and the "D" or LZ lateral exited the casing at -8391. Based on the depths provided in the sundries I have, the L1 lateral was isolated as indicated by Eric. After further review, it may not be necessary to send in new 404s. I think it will be possible to make the corrections by hand. Please give me a call. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) ~->, - ~ #+ Sent: Thursday, July 02, 2009 8:04 AM ~k~'~~~°~ '~U~' ~~~~~ To: 'NSK Prod Engr Specialist' Subject: RE: 1J-160L2 (207-017) Darrell, Thanks for looking into this. When you send in the new 404s, please put a note somewhere that these documents are revised. Tom From: NSK Prod Engr Specialist [mailto:n1139@conocophillips.com] Sent: Thursday, July 02, 2009 6:21 AM To: Maunder, Thomas E (DOA) Subject: FW: 1J-160L2 (207-017) Tom- as you can see from below it looks like we filed the 404 for the wrong sand. You are not going nuts. I will correct the 404 for isolating the B sand and resubmit it. You should have it in the next couple of days. Darrell From: Hollar, Eric Andrew Sent: Wednesday, ]uly 01, 2009 3:05 PM To: NSK Prod Engr Specialist Subject: RE: 1J-160L2 (207-017) Darrell, This well is a little unusual in that--according to the multilat drawing--it was drilled in the traditional tri-lateral way with a motherbore extending to the A sand. However, no lateral was completed in the A sand. I am going to assume that Tom's reference to the L2 matches a full tri-lateral (motherbore = A sand, L1 = B sand, L2 = D sand), even though this well isn't really a full tri-lateral well. The D sand (L2) isn't isolated in this well. A plug is set in a nipple at 8443' MD, which is below the D sand lateral junction. If we filed that the L2 was isolated, we should amend it. The B sand (L1) was isolated due to rapid water injection breakthrough. 7/2/2009 • • Page 2 of 2 Eric Hollar West Sak Production Engineer ConocoPhillips Alaska, Inc. Phone 907-265-6525 Cell 907-748-0181 _ _ . From: NSK Prod Engr Specialist Sent: Wednesday, July O1, 2009 2:38 PM To: Holiar, Eric Andrew Subject: FW: 1J-160L2 (207-017) Eric, would you be able to provide some insight to Tom's question? thanks Darrell From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednesday, July O1, 2009 9:28 AM To: NSK Prod Engr Specialist Subject: 1J-160L2 (207-017) Bob and Darrell, I am revie~nring the series of 404s submitted for this 1J-160L2 and the other segments reporting the isolation of 1J- 160L2. Do you have additional information as to why this lateral was isolated? I don't have any emails and did not find any new information in the well file. Thanks in advance. Tom Maunder, PE AOGCC 7/2/2009 ~C~~T~/~~ ' ~ ~ JUN 2 6 2009 r STATE OF ALASKA ,~185{~~ A~I cQ,t G~S ~;tJt;~~ ~~i~t?`~i~~~~ ~.t ALASKA OIL AND GAS CONSERVATION COMMISSION ~~~~~+~~¢ I REPORT OF SUNDRY WELL OPERATIONS r.~- ~~o~ ~. operations Performed: Abandon ^ Repair Well ^ Plug PerforaUons ~ Stimulate ^ Other ~ Isolated - Alter Casing ^ Pull Tubing ^ PerForate New Pool ~ Waiver ^ Time Extension ^ "a' sand . Change Approved Program ^ Operat. Shutdown^ Perforate ~ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: Co11oCOPhilllps Alaska, InC. Development ^ Exploratory ^ 207-015 / 3. Address: Stratigraphic ^ Service Q~'' 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-029-23344-00 7. KB Elevation (ft): 9. Well Name and Number: RKB 122' ~ 1 J-160 8. Property Designation: 10. Field/Pool(s): ADL 25663 ~ Kuparuk River Field / West Sak Oil Pool . 11. Present Well Condition Summary: Total Depth measured 10271' feet true vertical 3456' • feet Plugs (measured) Effective Depth measured 8750' feet Junk (measured) true vertical 3286' feet Casing Length Size MD ND Burst Collapse Structural CONDUCTOR 120' 20" 120' 120' SURFACE 3428' 13-3/8" 3550' 2191' INTERMEDIATE 9028' 9-5/8" 9150' 3343' WINDOW D-SAN 1' 9-5/8" 8392' 3224' WINDOW B-SAN 1' 9-5/8" 8751' Perforation depth: Measured depth: None r-~ true vertical depth: None ~_"'~~ Tubing (size, grade, and measured depth) 4-1/2" , L-80, 8357' MD. ~ ~ ~ ~ u~~ ~ ~ 2~09 Packers & SSSV (type & measured depth) PKR = SLZXP Liner top pkr, 'HRD' Liner top pkr PKR's = 8324', 8519' SSSV= NIP SSSV= 506' 12. Stimulation or cement squeeze summary: ~-.~t - ~ ~1\~ ' ~~~='~-~ ~ `~ h~ . Intervals treated (measured) d f l i i i l d l d ~~- ~~~ ~~~"~~~~~~~ pressure: an ina pt ons nc u ing vo umes use Treatment descr ~ 13. Representative Daily Average Production or injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation 1227 1221 957 Subsequent to operation 1177 _ 1121 . 997 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory ^ Development ^ Service ~` Daily Report of Well Operations X 16. Well Status after proposed work: . Oil^ Gas^ WAG^ GINJ^ WINJ ~^ , WDSPL^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NiA if C.O. Exempt N/A Contact Bob Christensen / Darrell Humphrey Printed Nam o D. Chris~nsen Titie Production Engineering Techn,ician Signature - Phone 659-7535 Date /„ t~7 ~ p~ ' CU CX C> ~ --..,..~..... , ~ ~. - - ` ,. _'' ; ~ ~,~ g'"`~ ~ l~! ~' ~ ' ~;- L-'~ 1 Form 10-404 Revised 04/2004 ~mit ~e~~"~f • • 1J-160 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 06/08/09 PERFORM FINAL RUN FOR IPROF IN B-LAT TO 12151 CTMD, SET 3.562 CS LOCK & PRONG IN DB-NIPPLE @ 8443 RKB. WELL IS FREEZE PROTECTED & SHUTIN. . ConocoPhillips ,1i.i . .~ lii~. •••WSII Con6 ~. Multl Ir laMal~ ~ 1J-1t elc~ ~AriGER. Fs_ _ _ CONDUCTOR, eain NIPPLE,506 GAS LIFT, 2,28f1 SUNFACE. 59-3.551 SLEEVE-0, 8,291 ~ocnroR 8 302 SEALASSY, 8,343 PIUG, D-SAND LINER, 8519-13,D55 KUP ~ 1 J-160 Well Attributes Max An le & MD TD Wallbora APIIUWI Field Name Wall ShNs 500292334400 WESTSAK INJECTING Incl (°) 87.26 MD (IfKB) 9,862.32 Act Blm (fIKB) 10,271.0 Commanl HYS (ppm) O SSSV: NIPPLE ate Mnatatlon Entl Dale Last W0: KB-0rd ~fq 43.01 Rig Ralaaea Deta 4/10/2007 Mnofetlon Last Tag: DapN (ItKB) End Dab MnotaHan Rev Reason: Set CS LceWProng Laet Motl By Imasbor Entl Date &10/2009 Casin Strin s Caaing ~eecription CONDUCTOR String 0... 20 Siring ID ... 19214 Top (HXB) 40.0 Sat Dept~ ~f... 121.0 Set DepN (TVD) ... 121.0 Strlnp WI... 94.00 String ... H-00 String Top ThM WELD Caeing ~eecripHOn SURFACE Casing Daecrlptlon INTERMEDIATE String 0... 133/8 String 0... 95/8 String ID ... 12.415 String ID ... 8.835 Top ~fll(B) 57.5 Top ~fIKB) 40.6 Set Dept~ ~1... 3,550.9 Sal Dapt~ (f... 9,150.0 Set Dept~ (7V0) ... 2,190.9 Sat Depth (TVD) ... 3,343.3 String WL.. 68.00 Strlnp Wl... 40.00 String ... L-SO String ... L-80 Strinq Top T~rtl ButtressThread S[ring Tap ThM BTC-M Gsing Dascrlptlon D-SAND LEM String 0... 4 1/2 String ID ... 3.958 Top (fll(B) 8,324.0 Sat Dept~ ~f... 8,561.9 Sel Oepth (TVO) ... 3,252.7 Strlnp WI... 72.75 String ... L-80 String Tap T~rtl Casing Descrlptlon DSANO HH Strlnp 0... 4 1/2 String ID ... 3.958 7op ~f1KB) 8,391.5 Sal Dapt~ (f... 8.656.8 Sal Dept~ (TVD) ... 3,271.0 Strlnp WI... 12.60 String ... L-80 String Tap ThN Casing DaecripHOn WHIPSTOCK String 0,.. 41/2 String ID ... 3.958 Top (M(8) 8,750.0 Sat Dept~ ~I... 9,064.0 Sel Dept~ (TVD) ... 3,331.3 String WL.. 12.60 SGing ... L-80 String Top T~N IBT-m Tubin Strin s Tubing DeacripHon String 0... String ID ... Top (ftKB~ Sal Dapt~ (1... Sat Oepth (TVD) ... String WI... String ... S[ring Top T~rE TUBING 41/2 3.980 36.0 5,357.0 3,217.1 L-80 IBTM Com le tion Details Top (ftl(B) Top Dept~ (TVD~ IRKB~ Top Incl (°) ~( am Dascriptlon Comment ID (in) 36.0 36.0 -0.01 H ANGER Vetco Gray 11" x 4-1 Y2" w/ 4.909" MCA Top Connecti 3.980 505.6 503.1 9.14 N IPPLE 41l7' Camco "DB-6" Nipple wl 3.875" No-Go Profile 3.875 8,290.5 3,206.6 80.04 S LEEVE-0 Baker 4.5"CMD Sliding Sleeve w/ Camco 3.817"DB' (OPEN) 3.812 8,341.6 3,214.1 79.18 L OCATOR BakerLocata 5.16"O.D. I.D.3.95" 4.000 8,342.7 3,214.3 79.19 S EAL ASSY Baker 4.74" SBE Seal Assy. w/ 4.5" 18T box up I. 3.880 Other In Hole Wireline retrievable lu s valves um s flsh etc. Top (ltNB) rop oeP~n (TVD) (RHB) Top Incl (°) De/Crlptlon Comment Run Date ID (in) 8,443 3,234.3 80.60 P LUG LOCK/PRONG PLUG SET IN 0.SAND LEM NIPPLE 6/&2009 0.000 Notes: General & Safe ' e~a o.ro n~~oeono~ ~ 4/11/2007 NOTE: NOTES: MULTILAT WELL - 1J-160 (NOT PERFD), 1J-160L1 (B-SANO), 1J-16012 (O-SAND) ~ 6/10/2009 NOTE: VIEW SCHEMATIC w/Alaska Schematlc9.0 Mandrel Dehails Stn Top(kMe~ Top DepM ~TVD) (RNB) Top Incl (°) Maks MoCel OD l~~) Ssrv Valw Type LaOC~ Type Port glza (~~) 7qORun ~psi) RunDale Go:~~. 1 2,280.0 1,859.4 70.66 CAMCO KBMG 1 GAS LIFT OMY BKS 0.000 0.0 6/25/2007 --~ ~~~~ Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth .f ~`, JUN ~. 9 20G9 ~ask~ ail ~ Gas Cons. Cornrrlissior~ NO. 5284 Ar9ChOr8~B Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Well Job # Log Description Date BL Kuparuk Color CD 06/17/09 1 B-19 ANHY-00091 PRODUCTION PROFILE C- < 05/27/09 1 1 3K-i6 ANHY-00094 GLS /' 05/29/09 1 1 3G-10 B04C-00058 INJECTION PROFILE ~' 05/31/09 1 1 iJ-160 62WY-00006 MEMORY INJECTION PROFILE ~ - 05/31/09 1 1 1J-164 B2WY-00009 MEMORY INJECTION PROFILE 06/01/09 1 1 iJ-160L2 AXBD-00028 MEMORY INJECTION PROFILE( 06/07/09 1 1 1 A-04A B04C-00040 RST a ~ 05/05/09 1 1 3M-03A AZJZ-00011 CH EDIT SFRT 01/11/09 1 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. • LPP/SSV na longer defeated on 1J-160 - 09-JUNE-09 Maunder, Thomas E (DOA) Page 1 of 1 From: CPF1 Prod Engr [n1269@conocophillips.com] Sent: Tuesday, June 09, 2009 9:48 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; NSK Problem Well Supv; Jenkins, Lubbie Allen; Gangl, Melissa A; Hibler, Kaycee; NSK West Sak Prod Engr Subject: LPP/SSV no longer defeated on 1 J-160 - 09-JUNE-09 Tom /Jim, The low pressure pilot (LPP) on 'hl-'4Sfl;~T[~ -=2p!7-016, 207-017) was returned to service on 6/07/2009 when the well was shut in for coil tubing work. The well was put back on injection this morning, 06/09/09, and currently has a wellhead pressure of 540 psi and an injection rate of 1184 bwpd. Thank you for your assistance, if you have any questions please contact me. David Llayd Lagerlef/Kenneth Lloyd Martin CPF1 Production Engineers n1269@conocophiliips.com 659-7493 pager 659-7000 765 ~_ ~. u;~ 6!9/2009 Maur>Ider, Thomas E (®OA) From: CPF1 Prod Engr [n1269@conocophillips.com] Sent: Saturday, June 06, 2009 7:26 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; NSK Problem Well Supv; Jenkins, Lubbie Allen; Gangl, Melissa A; Hibler, Kaycee; NSK West Sak Prod Engr Subject: LPP/SSV defeated on 1J-160 - 06-JUNE-09 ~I om /Jim, The low pressure pilot (LPP) on 1J-160 (PTD 207-015,,207-016, 207-017) was defeated on 6/06/2009 when the well was returned to service after being shut in or 6 ays. Current wellhead pressure is 474 psi; injection rate is 1170 bwpd. We expect to have the LPPs returned to service in approximately one week. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP/SSV function is returned to normal, in accordance with "Administrative Approval No. CO 4068.001." Please let me know if you have any questions. Regards, F~lai Hunt Hai Hunt /Eric Hollar NSK West Sak Production Engineer ConocoPhillips Alaska, Inc. Phone: (907) 659-7061 Fax: (907) 659-7749 Email: n1638@ConocoPhillips.com 6/8/2009 MEMORANDUM To: Jim Regg ~~,~ 5'~1U5 P.I. Supervisor ~ l FROM: BO1) NO1)le Petroleum Inspector r1 LJ State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, May 27, 2009 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1J-160 KUPARUK RIV U WSAK 1J-160 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv Comm Well Name: KUPARUK RN U WSAK 1J-160 Insp Num: mitRCN090526115514 Rel Insp Num: API Well Number: 50-029-23344-00-00 Permit Number: 2o7-ols-o Inspector Name: Bob Noble Inspection Date: 5/2a/2oo9 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well IJ-160 Type Inj. ~' TVD 3zI2 ~ IA is6o 2l0o zoso zoso P.T.D zo7olso TypeTest Test psi zloo pA I99 20o zoz zoz Interval 4YRTST p~ P / Tubing 529 525 530 529 Notes: n~~n $~{\~• 1 7~ i~ ~ ii,: "'ro xl khg 'ft...~ i ~ ... . ,., lt.~~1L.~ Li Lii6 1 Wednesday, May 27, 2009 Page I of I /' `~ DATA SUBMITTAL COMPLIANCE REPORT 5/7/2009 Permit to Drill 2070150 Well Name/No. KUPARUK RIV U WSAK 1J-160 Operator CONOCOPHILLIPS ALASKA INC API No. 50-029-23344-00-00 MD 10271 TVD ,3456 Completion Date 4/9/2007 Completion Status REQUIRED INFORMATION Mud Log No Samples No DATA INFORMATION Types Electric or Other Logs Run: GR/Res Well Log Information: Log/ Electr 1WINJ Current Status 1WINJ UIC ~:, v Directional Survey Yes (data taken from Logs Portion of Master Well Data Maint Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ~~'-'Lf og __.- -____.. __... _-----__._.. Cement Evaluation __--- -- 5 ---- _._-_._. Col D Asc Directional Survey og Production 5 Blu f/ED C Lis 15185 ~nduction/Resistivity t 15185 LIS V ifi ti p er ca on iiV"' I 15233~njection Profile 5 Blu 1 i~l !-Log Injection Profile 2 Blu ~D ` C Pds 16299 Injection Profile n ED C //'1~"~LM~~d+w ~tl:l T~J~ 17991~Se -N t ~ i e o e ~g Induction/Resistivity 25 Col Induction/Resistivity __ _. 25 Col Interval OH / Start Stop CH Received Comments 4000 8470 Case 4/6/2007 USITT, GR< CCL, GPIT 29- Mar-2007 41 10271 Open 5/8/2007 100 8540 Case 6/11/2007 PPL w/Well Tractor 19-Mar- 2007 3525 10271 Open 6/12/2007 LIS Veri, GR, NPHI, RHOB, NCNT, ROP w/Graphics 3525 10271 Open 6/12/2007 LIS Veri, GR, NPHI, RHOB,NCNT,ROP 8304 8824 Case 6/20/2007 Injection profile, GR, CCL, Temp, Pres, Spin, ILS 11- May-2007 w/Graphics PDF, Tif LAS 100 8490 Case 5/23/2008 Injection pro w/Maxtrac 17- May-2008 100 8490 Case 5/23/2008 Injection Pro w/Maxtrac 17- May-2008 0 0 5/5/2009 EWR Logs in PDS, EMF and CGM graphics ~n"• 121 10271 Cass 5/5/2009 MD ROP, EWR, DGR, ALD, CNT 121 34551 ~S€ 5/5/2009 TVD EWR, DGR, ALD, CNT DATA SUBMITTAL COMPLIANCE REPORT 517/2009 Permit to Drill 2070150 Well Name/No. KUPARUK RIV U WSAK 1J-160 Operator CONOCOPHILLIPS ALASKA INC API No. 50-029-23344-00-00 MD 10271 TVD 3456 Completion Date 4/9/2007 Completion Status 1WINJ Current Status 1WINJ UIC Y Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION ~j Well Cored? ~ Daily History Received? ''"/ N Chips Received? ~Y7N~ Formation Tops Analysis "PTI~- Received? __ Comments: --- - __ ~ t __ - ~ ~ _ __ /~.0~ Compliance Reviewed By: __ _ Date: W~~,L LDS `~"RA1~S1~1'1'TAL ~'~a State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs: 1 J-160+L 1+L 1 PB 1+L2 April 29, 2009 AK-MW-4877337 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of Bryan Burinda, Sperry Drilling, Arctic Blvd., Anchorage, AK 99518 1J-160+L1+L1PB1+1,2 2" x 5" MD RESISTIVITY & GAMMA RAY Logs: 1 Color Log 50-029-23 344-00,60,61, 70 2" x 5" TVD RESISTIVITY & GAMMA RAY Logs: 1 Color Log 50-029-23344-00,60,61,70 Digital Log Images 4 CD Rom 50-029-23 344-00,60,61,70 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry Drilling ~ Attn: Bryan Burinda 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3536 Fax: 907-273-3535 Bryan.Burnda@haliburton.com °~; BP Exploration (Alaska) Inc. Petrotechnical Data Center, MB33 900 E. Benson Blvd. Anchorage, Alaska 99508 ~ r(a a~~ - ~ ~~ ~ ~e ate- -~ t ~ Tlata • ~ i ~necl ~.... -- -a--- -- ~~C,:~~~ ~l~ ~~-~ 1 ~~ 9~~ ~~~~~ ~ ,=-~, • ConocoPhillips Alaska P.0. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Sept 6, 2008 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Maunder: ~s~~~ r~ t x,07 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 cement if needed and 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 August 28th, 2008. The corrosion inhibitor/sealant was pumped August 29th, Sept 5-6',2008. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call MJ Loveland or Perry Klein at 907-659-7043, if you have any questions. Sincerely, Perry Klei ConocoPhillips Well Integrity Projects Supervisor • • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Kuparuk Field Date 9/6/2008 Well Name PTD # Initial top of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft al 1A-17 190-151 SF NA SF NA 2.55 8/29/2008 1A-18 190-153 21' 2.80 27" 8/28/2008 1A-20 190-162 21' 2.80 25" 8/28/2008 7.65 8/29/2008 1A-25 190-167 14' 1.90 25" 8/28/2008 7.65 8/29/2008 1 J-101 205-182 6" NA 6" NA 1.28 9/5/2008 1J-102 206-110 7" NA 7" NA 1.70 9/5/2008 1 J-103 206-114 7" NA 7" NA 1.28 9/5/2008 1J-105 207-027 8" NA 8" NA 1.28 9/5/2008 1J-107 207-107 7" NA 7" NA 1.28 9/5/2008 1 J-109 206-050 14" NA 14" NA 8.08 9/5/2008 1J-115 206-122 10" NA 10" NA 2.55 9/5/2008 1J-118 206-176 5" NA 5" NA 6.80 9/5/2008 1J-120 207-045 4" NA 4" NA 2.55 9/5/2008 1 J-127 206-047 6" NA 6" NA 1.70 9/5/2008 1 J-135 207-038 8" NA 8" NA 1.70 9/6/2008 1 J-136 206-154 9" NA 9" NA 1.70 9/6/2008 1J-137 206-108 12" NA 12" NA 5.10 9!6/2008 1 J-154 205-035 4" NA 4" NA 4.67 9/6/2008 1 J-156 206-067 8" NA 8" NA 5.95 9/6/2008 1J-159 206-005 20" NA 20" NA 14.87 9/6/2008 1J-160 207-015 20" NA 20" NA 7.23 9/6/2008 1J-164 205-144 20" NA 20" NA 11.90 9/6/2008 1 J-176 207-099 6" NA 6" NA 1.28 9/6/2008 1J-184 206-044 8" NA 8" NA 1.28 9/6/2008 r I ~~rlll~lll~rl ~r~ Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Job # °~ a. , Log Description „~F 05/22/08 NO. 4717 Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnker~ 333 West 7th Ave, Suite '100 Anchorage, AK 99501 Field: Kuparuk Date BL Color CD iJ-180 11964605 I 1E-168 11964601 NJECTION PROFILE - / GLS 05/19/08 1 1 1J-160 1A-01 11964603 11996636 [. _ INJECTION PROFILE PRODUCTION PROFILE w/FSI ~- 05/15/08 05/17/08 05/14/08 1 1 1 1 1 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. RE:-LPP/SSV defeated on 1J-lb~ Page 1 of 1 Maunder, Thomas E (DOA) From: NSK West Sak Prod Engr [n1638@conocophillips.com] Sent: Monday, February 25, 2008 3:01 PM To: Maunder, Thomas E (DOA); Regg, James B {DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; Rodgers, James T; NSK West Sak Prod Engr Subject: RE: LPP/SSV defeated on 1J-160 Tom /Jim, The ?J-160 (PTD 207-0~f5, 207-016, 207-017} LPP/SSV was returned to normal service on 2/23. The well is currently injecting 1471 bwpd at 591 psi wellhead pressure. Regards, Hai Hunt From: NSK West Sak Prod Engr Sent: Saturday, February 16, 2008 1:43 PM To: 'Maunder, Thomas E (DOA}'; yim.regg@alaska.gov' Cc: CPFl DS Lead Techs; CPF3 Prod Supt; Rodgers, James T; NSK West Sak Prod Engr Subject: LPPJSSV defeated on 1J-i60 Tom /Jim, The low pressure pilot (LPP) on 1J-160 (PTD 207-015, 207-016, 207-017} was defeated on 2!16/2008 when the well was returned to service after being shut in for 12 days. Current wellhead pressure is 472 psi; injection rate is 1408 bwpd. We expect to have the LPPs retumed to service in approximately one week. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." Permit to drill numbers: The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPP/SSV function is retumed to normal, in accordance with "Administrative Approval No. CO 4068.001." Please let me know if you have any questions. Regards, Hai Hunt Hai Hunt /Eric Hollar NSK West Sak Production Engineer ConocoPhillips Alaska, lnc. Phone: (907) 659-7061 Fax: (907) 659-7749 Email: n1638@ConocoPhillips.com 2/ZS/Zaag LPP/SSV defeated on 13-160 • • Page 1 of 1 Maunder, Thomas E (DOA) From: NSK West Sak Prod Engr [n1638@conocophiHips.comJ Sent: Saturday, February 16, 2008 1:43 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; Rodgers, James T; NSK West Sak Prod Engr Subject: LPPlSSV defeated on 1J-160 Tom !Jim, The tow pressure pilot (LPP) on 07-016, 2o7-097j was defeated on 2!1612008 when the wet! was returned to service after being shut in for 12 days. Current wellhead pressure is 472 psi; injection rate is 1408 bwpd. We expect to have the LPPs returned to service in approximately one week. The LPP and SSV have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." Permit to drill numbers: The AOGCC will be notified when the injection pressure has increased to above 500 psi and the LPPlSSV function is returned to normal, in accordance with "Administrative Approval No. CO 4068.001." Please let me know i# you have any questions. Regards, Hai Hunt Hai Hunt /Eric Hollar NSK West Sak Produc#ion Engineer ConocoPhillips Alaska, Inc. Phone: {907) 659-7061 Fax: (907) 659-7749 Email: n1638@ConocoPhillips.com 2/17/2008 LPP/SSV defeated on 1J-136, in service on 1J-160 Page 1 of 1 Maunder, Thomas E (DOA) From: NSK West Sak Prod Engr [n1638@conocophillips.com] Sent: Wednesday, November 07, 2007 10:52 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA} Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; NSK West Sak Prod Engr; Rodgers, James T Subject: LPP/SSV defeated on 1J-136, back in service on 1J-160 Tom /Jim, The low pressure pilot (LPP) on 1J-160 has come up above 500 psi and the LPP/SSV function was returned to normal on 11!7/2007. Permit to drill numbers: 1J~'f~ 1J-160L1 207-015, 1J-160L2 207-017. The low pressure pilot (LPP) on 1J-136 was defeated on 11/4!2007 when the welt was returned to service after an extended shut in time (the welt had been shut in since 6/8/07 due surtace proximity to a workover rig). Current wellhead pressure is 461 psi; injection rate is 1277 bwpd. We expect to have the LPPs returned to service within a week. The LPPs and SSVs have been tagged and their status is recorded in the "Facility Defeated Safety Device Log." Permit to drill numbers: 1J-136 206-154, 1J-136L1 206-155. The AOGCC wi{I be notified when the injection pressure has increased to above 500 psi and the LPP/SSV function is returned to norma{, in acx;ordance with "Administrative Approval No. GO 4066.001." Please let me know if you have any questions. Regards, Hai Hunt Hai Hunt /Eric HoI{ar NSK West Sak Production Engineer ConocoPhillips Alaska, Inc. Phone: (907} 659-7061 Fax: (907) 659-7749 Email: n1638@GonocoPhitNps.com 11 /7/2007 L1 Y / UIJ • KV1Vf.L{.VIL Vli ii/ i iv•• va.r~ a.r ar. r ~ a.. :.. .~ ~.. ~.~.. Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, August 27, 2007 9:52 AM To: 'NSK West Sak Prod Engr'; Regg, James B (DOA) Cc: CPF1 DS Lead Techs; CPF1 Prod Supt; Hollar, Eric Andrew; Rodgers, James T Subject: RE: LPP/SSV defeated on 1E-112, 1J-102, 1J-127, 1J-164, 1J-180 Thanks Hai, While we will file this information in the main wellbore file, it is probably appropriate to list the lateral permit numbers for completeness. Call or message with any questions. Tom Maunder, PE AOGCC From: NSK West Sak Prod Engr [mailto:n1638@conocophillips.com] Sent: Sunday, August 26, 2007 8:59 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: CPFl DS Lead Techs; CPF1 Prod Supt; NSK West Sak Prod Engr; Hollar, Eric Andrew; Rodgers, James T Subject: RE: LPP/SSV defeated on 1E-112, 1J-102, iJ-127, 1J-164, 1J-180 Tom ;Jim, The LPP/SSV's on all of the West Sak DS1 E and DS1 J wells are now back in service as their wellhead injection pressures have increased to above 500 psi. The following wells had been defeated; permit to drill numbers are also listed. I wasn't sure if you wanted the permit to drill number for the mainbore only or the laterals as well so I included both. WELL ID Permit to Drill No. 1 E-112 204-091 (MAINBORE), 204-092 (L1), 204-093 (L2) 1J-102 206-110 (MAINBORE), 206-111 (L1 ), 206-112 (L2) 1J-105 207-027 (MAiNBORE), 207-028 (L1}, 207-029 (L2) 1J-127 206-047 (MAINBORE), 206-048 (L1}, 206-049 (L2'~ ,---~ 1J-160 207-015 (MAiNBORE), 207-016 (L1), 207-017 (L2) 1J-164 205-144 (MAiNBORE}, 205-145 (L1), 205-146 (L2) 1J-180 206-150 (MAINBORE), 206-151 (L1) Note: 1J-105 and 1J-160 were defeated in early July 2007, before the CPF1 ESD, because they were new injectors (notification for these wells was sent 7/9/2007). Let me know if you have any questions. Regards, Hai Hunt Hai Haant /Pete Nezaticky /Eric Hollar NSK West Sak Production Engineer ConocoPhillips Alaska, Inc. Phone: (907} 659-7061 Fax: (907} 659-7749 Email: n1638@ConocoPhillips.com 8/27/2007 MEMORANDUM To: Jim Regg ~~~~~ 7 ~2 ~~C~ / P.I. Supervisor FROivt: Bob Noble Petroleum Inspector State of Alaska Alaska OiI and Gas Conservation Commission DATE: Friday, July 20, 2007 SUBJECT: Mechanical Integrity Tests CONOCOPHII.LIPS ALASKA INC 1J-160 KUPARUK RIV U WSAK 17-160 Src: Inspector nlnlv_~r+NFinF,NTi A L ~~. o ~~~ Reviewed By: P.I. Suprv Comm Well Name: KUPARUK RIV U WSAK IJ-160 API Well Number: 50-029-23344-00-00 Inspector Name: Bob Noble mitRCN070714191337 Insp Num: Permit Number: 207-015-0 Inspection Date: 7/14/2007 nei Insp Num: Packe;~ Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ~~ IJJ-t6o ,Type Inj. ~ ~' ~ TVD ~ ~z'~' ~i~- ! I2so ~ I97o I L r t9ao I I9ao I i ~ P T zo7olso ',iTypeTest I SPT'~ Test psi _ T ~~ t97o j OA j __ --- - tas j 20o j ~ -- ~ zoo i zoo j I F- _ P _ ~ TUbing j 300 ~ 300 ~ 300 ~ 300 I ~ InteCVal INITAL P/F Notes: ~N~~ AU G ~ ~ 2007 Friday, July 20, 2007 Page 1 of 1 West Sak LPP Defeat Update• • Page 1 of 1 Maunder, Thomas E (DOA) From: NSK West Sak Prod Engr [n1638@conocophillips.com] Sent: Monday, July 09, 2007 4:37 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: NSK West Sak Prod Engr Subject: West Sak LPP Defeat Update Tom/Jim ~ ~~..~_©' This email is to notify the AOGCC that 1J-105 and 1J-160 West Sak pre-produced injectors, LPP (Low Pressure Pilot) have been defeated in accordance with "Administrative Approval No. CO 4068.001 ". The LPP and SSV (Surface Safety Valve) have been tagged and recorded on the "Facility Defeated Safety Device Log". Both wells required anon-adjustable choke insert on the water injection line to limit and control water injection at lower rates. Following are the current well conditions: 1J-105 Converted from pre-production to injection 07/06/2007, LPP defeated 7/6/2007. Injecting 2200 bwpd at 0 psi. 1J-160 Converted from pre-production to injection 07/01/2007, LPP defeated 7/6/2007. Injecting 1250 bwpd at 80 psi. The AOGCC will be notified when the injection pressure has increased above 500 psi and the LPP function is returned to normal. This email is also to notify the AOGCC that 1J-180 and 1J-136 West Sak pre-produced injectors, LPP (Low Pressure Pilot) have been placed back in service 1J-180 LPP defeated 06/09/2007, back in service 06/28/2007 1J-136 LPP defeated 06/08/2007, back in service 07/01/2007 Regards, Peter Nezaticky / Hai Hunt ConocoPhillips Alaska Inc. West Sak Production Engineers Ph: 907-659-7061 Fax: 907-659-7749 7/10/2007 ~ R~~ovEQ STATE OF ALASKA ,J (.~ ~ ~ ~ 2 ~ ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIO~~`a oil & bas cons. Ct~mmis~sion 1. Operations Performed: .Abandon ^ Repair Well ^ Plug Perforations ^ Stimulate ^ Other ~ Prod to WIND ~ Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown^ Perforate ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: COnOCOPhlllips AlBSka, InC. Develdpment 0 Exploratory ^ 207-015 / 3. Address: Stratigraphic ^ Service ^ 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510. 50-029-23344-00 / 7. KB Elevation (ft): 9. Well Name and Number: RKB 122' 1J-160 8. Property Designation: ~D G 2~4G V 10: Field/Pool(s): Kuparuk River Unit /rD~ 1~iGG3/S~ ~./$'•~~ Kuparuk River Field/West Sak Oil Pool 11. Present Well Condition Summary: Total Depth measured 10271' feet true vertical 3456' feet Plugs (measured) Effective Depth measured 8750' ' feet Junk (measured) true vertical 3286' feet Casing Length Size MD ND Burst Collapse Structural CONDUCTOR 120' 20" 120' 120' SURFACE 3428' 13-3/8" 3550' 2191' INTERMERIATE 9028' 9-5/8" 9150' 3343' WINDOW D-SAN 1' 9-5/8" 8392' 3224' WINDOW B-SAN 1' 9-5/8" 8751' Perforation depth: Measured depth: None -true vertical depth: None Tubing (size, grade, and measured'depth) 4-1l2" , L-80, 8357 MD. Packers &SSSV (type & measured depth) PKR = SLZXP Liner top pkr, 'HRD' Liner top pkr PKR's = 8324', 8519' SSSV= NIP SSSV= 506' 12. Stimulation or cement squeeze summary: intervals treated (measured) DFL ~v~ ~ ~ 7~~ h- Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation 702 - 100 23 1011 207 Subsequent to operation 327 1339 932 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory ^ Development ^ Service Daily Report of Well Operations _X 16. Well Status after proposed work: Oil^ Gas^ WAG^ GINJ^ WINJ ^~ ~ WDSPL^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N!A if C.O. Exempt: 307-183 contact Bob Christensen /Bob Buchholz Printed Name ,~tObert D. Chr' ensen Title Production Engineering Technician Signature Phone 659-7535 Date .. Form 10-404 Revised 04/2004 ~ R ~ G I ~ A L ~\ a~~/~O~ bmit Original O~~ ~ 1J-160 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 07/01/07 Commenced Water Injection Service EL.L LAG ProActive Diagnostic Services, Inc. To: AOGCC Christine Mahnken 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 659-5102 1) 2) 3) 4) ~) 6) 7) Signed • 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: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fax (907) 245.8952 1 BL / EDE Disk 1 J- -180 Production Profile use. ~®`~-~~r~ ~` ~ ~ ~ 11-May-07 _~ ,-~ ~ ~ 1 ~~_ : ~i ~ .~~ Print Name: ~~~? Date ~~; PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 9951$ PHONE: (907)?A5-8951 Fax: (907)245-8952 E-MAIL : - ~ =("? a ~^,' .'.9 wE831TE t nn;1t " ~~.., i D:\Master Copy_00_PDSANC-ZO~oc\Z_Word\Disiubution\T~anacrittal_Sheets\Tratvsmit_Onginal.doc • T®: State of Alaska ~b"ELL, L®G TI~.~~iS1~IIT"T~SI, Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7`" Avenue, Suite 100 Anchorage, Alaska RE: NIWD Formation Evaluation Logs 1J-160 1 LDWG formatted CD Rom with verification listing. API#: ~0-029-23344-00 June 1, ?007 AK-MW-4877337 PLEASE ACKNOWLEDGE RECEIPT BY SIG~TiV'G AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 -E ~ r_. ,~ ,~ _~, Date: _ , ~ , Signed: vsc ~0~-0~5' ~ i51°~g~ 06/08/07 Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Job # ~ -- N0.4286 .~~-.~ ~~ '~ ~~r yin q;~,i ~ ~-~ ~~~•~~ Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 'E 00 ~~~.fi;~rg~6h~i ~~°~°,9~9'~ Anchorage, AK 99501 Field: Kuparuk UT~ 8~~-OIJ Log Description Date BL Color CD ~ ° 2L-321 11629010 MULTI-FINGER CASING INSPECTION 05112107 1 2C-16 11629008 PPROFILDL 05/10/07 1 2G-11 11638863 PRODUCTION PROFILE 05105/07 1 1C-125 N/A MEM INJECTION PROFILE 05105/07 1 2D-13 11638861 PRODUCTION PROFILE 05103/07 1 2D-08 11638862 PRODUCTION PROFILE 05104107 1 2G-09 11638864 PRODUCTION PROFILE 05106107 1 2N-349A 11629004 RSTI WFL 05/04/07 1 3H-19 11638867 PRODUCTION PROFILE 05/09107 1 1Q-10 11628771 MEM PRODUCTION PROFILE 05/03/07 1 1 E-11 11629012 INJECTION PROFILE 05114107 1 2L-321 11665439 USIT 05125107 1 2V-08A 11629013 PMIT 05115107 1 1J-160 11632704 PRODUCTION PROFILE 03119107 1 1H-07 11665436 SBHP SURVEY 05120/07 1 2F-11 11665434 PRODUCTION PROFILE 05/19/07 1 2X-07 11665433 INJECTION PROFILE 05118/07 1 16.01 11665432 PRODUCTION PROFILE 05/17/07 1 2X-01 11637338 INJECTION PROFILE 05115107 1 2Z-29 11665438 PRODUCTION PROFILE 05122107 1 1 H-22 11637339 INJECTION PROFILE 05116107 1 1Y-11 11632708 INJECTION PROFILE 05123/07 1 1G-03 11637336 INJECTION PROFILE 05114107 1 1A-23 11665443 MEM PRODUCTION PROFILE 05/29/07 1 1 F-08 11665435 SBHP SURVEY 05/20107 1 1J-170 11632709 INJECTION PROFILE 05124/07 1 1D-109 NIA INJECTION PROFILE 05H3/07 1 2M-24 11665440 SBHP SURVEY 05/28107 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. a ~ ~ a SARAH PAL/N, GOVERNOR ~5~ O~ ~ ~5 333 W. 7th AVENUE, SUITE 100 C01~5ERQA~`I011T COMI-IIS5IOIIT ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Robert Christensen Production Engineering Technician ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, West Sak Oil Pool, 1J-160 Sundry Number: 307-183 Dear Mr. Christensen: 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. 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). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this ~ day of June, 2007 Encl. ~U~-dl5 Sincerely, ConocoPhillips June 1, 2007 Tom Maunder, P.E. Senior Petroleum Engineer State of Alaska, Oil & Gas Conservation Commission 33 W. 7th Ave. Ste. 100 Anchorage, AK 99501 Robert Buchholz /Robert Christensen Production Engineering Tech. Greater Kuparuk Unit , NSK-69 PO Box 196105 Anchorage, AK 99519-6105 Phone: (907)659-7535 Fax: 659-7314 ~~GIV~V JUN 0 5 2007 4iasica Oil $t Gas Cons. Commission Anchorage Dear Mr. Maunder, ConocoPhillips Alaska, Inc. requests approval to convert Kuparuk West Sak wells 1J-160 (PTD 207-015), 1 J-160L 1 (PTD 207-016), and 1 J-160L2 (PTD 207-017) from Oil Production to Water Injection service. Enclosed you will find the 10-403 Application for Sundry Approvals for ConocoPhillips Alaska, Inc. wells 1J-160, 1J-160L1, and 1J-160L2. If you have any questions regarding this matter, please contact myself or Robert Buchhloz at 659-7535. Sincerely, ,~ Robert D. Christensen Attachments ~ tom' c~~ /~ G!~" G 7 STATE OF ALASKA • RECEIVED ~6~~UN 0 5 2007 ALASKA OIL AND GAS CONSERVATION COMMISSION Alaska Oil & Gas Cons. Commissian APPLICATION FOR SUNDRY APPROVAL Anchorage 20 AAC 25.280 1. Type Of Request: Abandon ^ Suspend ^ Operational Shutdown ^ Perforate ^ Waiver ^ Other O Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Chan e a roved ro ram g pp p g ^ Pull Tubing ^ Perforate New Pool ^ Producer to ~' Re-enter Suspended Well ^ Injector 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, InC. Development ^/ Exploratory ^ 207-015 3. Address: Stratigraphic ^ Service ^ 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-029-23344-00 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 NO ^~ 1J-160 r 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): Kuparuk River Unit ~DL ~5~~3 ~~~b-a7 RKB 122' Kuparuk River Field /West Sak Oil Pool ~ 12. PRESENT WELL CONDITI ON SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 10271' - 3456' ~ 8750' ' 3286' Casing Length Size MD ND Burst Collapse CONDUCTOR 120' 20" 120' 120' SURFACE 3428' 13-3/8" 3550' 2191' INTERMEDIATE 9028' 9-5/8" 9150' 3343' WINDOW D-SAND 1' 9-5/8" 8392' 3224' WINDOW B-SAND 1' 9-5/8" 8751' 3287' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): None None 4-1/2" L-80 8357' Packers and SSSV Type: Packers and SSSV MD (ft) PKR = SLZXP Liner top pkr, 'HRD' Liner top pkr PKR's = 8324', 8519' SSSV= NIP SSSV= 506' 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^ Service ^~ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: June 20, 2007 Oil ^ Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ~ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Bob Christensen /Bob Buchholz Printed Name Obe D. Chri tensen Title: Production Engineering Technician Signature ----- Phone 659-7535 Date ~ ~ ~j Commission Use Onl Sundry Number: Conditions of approval: Notify Commission so that a representative may witness -1 Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ~ Location Clearance ^ Other: ~ ~~~a"~V.~rc °OQQ'cc~,~\pC~S ~~ ~L. ~ ~ ~ ~~~ ~ Q , Subsequent Form Required: ~-~©y ~ 17T-~ ,JAN 0 $ 7d~7 APPROVED BY 6 ~ Approved by: C MMISSIONER THE COMMISSION ~ ~Q Date: Form 10-403 Revised 06/2006 ~ ~~~~~~ -[ f ~~ ~ ~ _i. Submit in Dupli to ~ ,7 ~~ ~. a 1 J-160 DESCRIPTION SUMMARY OF PROPOSAL ConocoPhillips Alaska Inc. requests approval to begin Water Injection service in West Sak Tri- lateral Well 1J-160. This well has been reported as being pre-produced for 30 days in order to recover Oil based drilling fluids (1J-160L1 & L2) prior to putting the well on injection. The 1J- 160 A2 sand penetration was found to be wet. Consequently, the 9-5/8" cement shoe was set at 9150' and (3343' tvd) and the well was plugged back to 8750' MD (3286' TVD) isolating the well from the A2 sand water. 1 J-160 will need to remain an "ACTIVE" well since all lateral injection (1 L-160L1 & L2) will be reported against the 1 J-160 motherbore. The 13-3/8" Surface casing (3551' and / 2190' tvd) was cemented with 667 sx Class 'G'. The 9• 5/8" Intermediate casing (9150' and / 3340' tvd) was cemented with 735 sx DeepCRETE. The injection tubing/casing annulus is isolated via the following: Upper D sand SLZXP 7" x 9- 5/8" Liner Top Packer with 190-47 Casing Sealbore Receptacle located @ 8324' and / 3212' tvd, Upper B sand HRD ZXP 5-1/2" x 7-5/8" Liner Top Packer with 190-47 Casing Sealbore Receptacle located @ 8519' and / 3247' tvd. The top of West Sak D sand was found at 8387' and / 3223' tvd. D sand Lateral window top is located @ 8391' and / 3224' tvd. The top of West Sak B sand was found at 8767' and / 3289' tvd. B sand Lateral window top is located @ 8750' and / 3286' tvd. The top of West Sak A sand was found at 10241' and / 3454' tvd. ConocoPhillips May 10, 2007 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Reports for 1 J-160, 1 J-160L1 and 1 J-160L2 Dear Commissioner: ~~CEIVEQ ~iAY 1 4 2007 Alaska Di1 ~ Gas Gons. C~issian Anchorage ConocoPhillips Alaska, Inc. submits the attached Well Completion Reports for the recent drilling operations on the West Sak wells 1J-160, 1J-160L1, 1J-160L2. If you have any questions regarding this matter, please contact me at 265-6830 or Mike Greener at 263-4820. Sincerely, R. Thomas Kuparuk Drilling Team Leader CPAI Drilling Randy Thomas Kuparuk Drilling Team Leader Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-6830 RT/skad STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ~;AY 1 4 2007 WELL COMPLETION OR RECOMPLETION REPORT;~-bli~Q.~f~Q~'~°r"""SS'on 1a. Well Status: pil ^ Gas Plugged Abandoned Suspended ^ 20AAC 25.105 20AAC 25.110 GINJ ^ WINJ ^~ WDSPL ^ WAG ^ Other ^ No. of Completions: 1b. Well Class: (iC Development ~ Exploratory ^ Service ^~ ~ Stratigraphic Test ^ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Date Comp., Susp., -( ~5•~' orAband.: April;Kl, 2007 12. Permit to Drill Number: 207-015 / 3. Address: P. O. Box 100360, Anchorage, AK 99510-0360 6. Date Spudded: March 2, 2007 ~ 13. API Number: 50-029-23344-00 4a. Location of Well (Governmental Section): Surface: 2016' FSL, 2541' FEL, Sec. 35, T11N, R10E, UM 7. Date TD Reached: March 13, 2007 14. Well Name and Number: 1J-160 Top of Productive Horizon: 988' FNL, 1688' FWL, Sec. 3, T10N, R10E, UM 8. KB (ft above MSL): 122.5' AMSL ~ Ground (ft MSL): 81' AMSL 15. Field/Pool(s): Kuparuk River Field Total Depth: 1101' FNL, 3592' FEL, Sec. 3, T10N, R10E, UM 9. Plug Back Depth (MD + TVD): 8750' MD / 3286' TVD West Sak Oil Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 558668.6 y- 5945827.5 Zone- 4 10. Total Depth (MD + TVD): ~ 10271' MD / 3456' TVD . 16. Property Designation: ALK 25660, 25661, 25663' TPI: x- 552365 s,) y- 5942777 Zone- 4 Total Depth: x- 55236$~f DS•'~• - 5942665 • Zone- 4 11. SSSV Depth (MD + TVD): nipple @ 505' MD / 498' TVD 17. Land Use Permit: 470, 472 18. Directional Survey: Yes ^/ No ~ (Submit electronic and printed inforrrtation per 20 AAC 25.050) 19. Water Depth, if Offshore: N/A (ft MSL) 20. Thickness of Permafrost (TVD): 2183' TVD - 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): GR/RES 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE TING CORD AMOUNT CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE CEMEN RE PULLED 20" x 34" 78.6# H-40 40' 120' 40' 120' 42" 365 sx AS 1 13.375" 68# L-80 40' 3551' 40' 2190' 16" 513 sx Class G, 106 sx Class G, 48 sx Class G 9.625" 40# L-80 40' 9150' 40' 3340' 12.25" 735 sx DeepCRETE 23. Open to production or injection? Yes No Q If Yes, list each 24. TUBING RECORD Interval open (MD+TVD of Top & Bottom; Pertoration Size and Number): SIZE DEPTH SET (MD) PACKER SET e ~ ~ 3 ~- ~ ` 8324' none 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED na 26. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) none Date of Test Hours Tested Production for Test Period --> OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO Flow Tubing press. psi Casing Pressure Calculated 24-Hour Rate -> OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY -API (corr) 27. CORE DATA Conventional Core(s) Acquired? Yes No a Sidewalt Cores Acquired? Yes No ~ 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 I ~~5'~F~ .IUN n ~ 2007 u . ~ 9•G E ._ ___~"-.. Form 10-407 Revised 2/2007 ORIGINAL CONTINUED ON REVERSE SIDE ,~ s. z9.o~ 28. GEOLOGIC MARKERS (List all formations and marke encountered): 29. FORMATION TESTS NAME MD TVD Well tested? ~ Yes ^/ 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 3519' 2183' ~ needed, and submit detailed test information per 20 AAC 25.071. T3 3519' 3519' K15 3519' 3519' T3+550 Ugnu C 5973' 2709' Ungu B 6742' 2873' Ungu A 6924' 2913' K13 7622' 3067' West Sak D 8387' 3223' West Sak B 8767' 3289' West Sak A 10241' 3454' N/A Formation at total depth: West Sak 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey 31. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Mike Greener @ 263-4820 Printed Na Rand Thomas Title: Drillino Team Leader Sl Salo ~ - Signature Phone Date 2-Gs 6z3 3 c7 INSTRUCTIONS Sharon Allsup-Drake General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a list of intervals tested and the corresponding formation, and a brief summary of this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 Halliburton Company Survey Report Comp:un~: ConocoPhlllips Alaska Inc . ..Date: 4/26!2007 Timr. 15;02;25 Page: 1 Field: Kuparuk River Unit Co- ordinate(NE)Reference: V~Jell: 1J-160, Tru e North Site: Kupa~uklJPad Vertical (T~'D)Re ferenee: 1J-X60.122.3 Wells 1J-160 Sec tion(VS)Refer encei Well (QOON,O.OO E,180.OOAzi} Wellpath: 1J-160 Survey Calculatio _- n Method: Minimum Curvature ilh: Oracle --_ --- _ _- Field: Kuparuk River Unit ~ North Slope Alaska United States Map System:US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2006 Well: 1J-160 Slot Name: - -~ Well Position: +N/-S -91.18 ft Northing: 5945827.52 ft Latitude: 70 15 45.361 N i +E/-W -122.08 ft Easting : 558668.60 ft Longitude: 149 31 32.559 W Position Uncertainty: 0.00 ft Wellpath: 1J-160 Drilled From: Well Ref. Point 500292334400 Tie-on Depth: 41.29 ft Current Datum: 1 J-160: Height 122.29 ft Above System Datum: Mean Sea Level Magnetic Data: 2/27/2006 Declination: 24.03 deg I Field Strength: 57598 nT Mag Dip Angl e: 80.79 deg ~ i Vertical Section: Depth From (TVD) ft ~ +N/-S ft +E/-W ft Direction deg ~ 41.29 0.00 0.00 180.00 Survey Program for Definitive Wellpath - ____ _ ~ ~ Date: 8/8/2006 Validated: No Version: 4 Actual From To Survey Toolcode Tool Name ft ft r 100.00 600.00 1 J-160 gyro (100.00-600.00) CB-GYRO-SS Camera based gyro single shot i 666.10 10241.22 1J-160 (666.10-10241.22) t MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC Survey _ NID Intl Haim TVD ti}sTy~l) V/S F,,1> ~~IapN J4apE Tool ft deg deg -_ ft _ - R ft ft ft ft ~ i 41.29 0.00 0.00 41.29 -81.00 0.00 0.00 5945827.52 558668.60 TIE LINE 100.00 0.15 293.36 100.00 -22.29 0.03 -0.07 5945827.55 558668.53 CB-GYRO-SS 200.00 0.59 243.72 200.00 77.71 -0.15 -0.65 5945827.37 558667.95 CB-GYRO-SS 300.00 3.54 277.00 299.92 177.63 0.00 -4.18 5945827.49 558664.42 CB-GYRO-SS 400.00 6.99 280.33 399.49 277.20 1.47 -13.23 5945828.89 558655.36 CB-GYRO-SS 500.00 10.60 279.01 498.29 376.00 4.00 -28.31 5945831.30 558640.26 CB-GYRO-SS ~ 600.00 12.77 273.73 596.22 473.93 6.16 -48.42 5945833.30 558620.14 CB-GYRO-SS 666.10 15.31 273.65 660.34 538.05 7.19 -64.42 5945834.21 558604.13 MWD+IFR-AK-CAZ-SC 761.80 19.50 270.99 751.64 629.35 8.27 -93.02 5945835.07 558575.53 MWD+IFR-AK-CAZ-SC 856.80 21.31 271.11 840.67 718.38 8.88 -126.13 5945835.42 558542.41 MWD+IFR-AK-CAZ-SC 951.55 22.79 271.51 928.49 806.20 9.70 -161.69 5945835.96 558506.85 MWD+IFR-AK-CAZ-SC 1046.43 26.48 271.02 1014.72 892.43 10.56 -201.22 5945836.51 558467.32 MWD+IFR-AK-CAZ-SC 1140.73 28.46 269.82 1098.39 976.10 10.86 -244.72 5945836.48 558423.83 MWD+IFR-AK-CAZ-SC 1236.43 30.07 270.84 1181.87 1059.58 11.14 -291.50 5945836.39 558377.05 MWD+IFR-AK-CAZ-SC 1331.29 34.01 271.18 1262.26 1139.97 12.04 -341.80 5945836.90 558326.75 MWD+IFR-AK-CAZ-SC I 1427.82 38.94 273.79 1339.87 1217.58 14.60 -399.10 5945839.01 558269.43 MWD+IFR-AK-CAZ-SC 1522.70 40.38 275.76 1412.91 1290.62 19.66 -459.44 5945843.60 558209.07 MWD+IFR-AK-CAZ-SC 1616.58 42.50 273.46 1483.29 1361.00 24.63 -521.36 5945848.08 558147.11 MWD+IFR-AK-CAZ-SC 1712.58 43.81 274.04 1553.32 1431.03 28.92 -586.88 5945851.87 558081.57 MWD+IFR-AK-CAZ-SC 1807.77 49.26 274.61 1618.78 1496.49 34.15 -655.74 5945856.55 558012.67 MWD+IFR-AK-CAZ-SC ~ 1903.13 51.56 271.96 1679.55 1557.26 38.33 -729.09 5945860.16 557939.30 MWD+IFR-AK-CAZ-SC j 1996.53 56.44 269.59 1734.44 1612.15 39.30 -804.62 5945860.55 557863.78 MWD+IFR-AK-CAZ-SC 2093.62 61.82 270.96 1784.24 1661.95 39.73 -887.92 5945860.33 557780.49 MWD+IFR-AK-CAZ-SC 2187.20 66.18 272.62 1825.25 1702.96 42.38 -971.96 5945862.32 557696.43 MWD+IFR-AK-CAZ-SC 'i 2282.89 70.74 274.59 i 1860.38 1738.09 48.00 -1060.76 5945867.25 557607.60 MWD+IFR-AK-CAZ-SC 2378.18 73.48 273.77 1889.65 1767.36 54.60 -1151.19 5945873.15 557517.13 MWD+tFR-AK-CAZ-SC 2473.19 76.25 274.34 1914.45 1792.16 61.09 -1242.67 5945878.92 557425.61 MWD+IFR-AK-CAZ-SC j 2569.11 75.19 274.37 1938.11 1815.82 68.15 -1335.36 5945885.26 557332.88 MWD+IFR-AK-CAZ-SC ~i 2664.24 76.14 275.44 1961.67 1839.38 76.03 -1427.18 5945892.42 557241.00 MWD+IFR-AK-CAZ-SC Halliburton Company Survey Report Company: ConocoPhillips .Alaska Ina - Date: 4/26!2007 Time: 15.02:25 Yagc: 2 Field: Ku paruk River Uni t Co-o rdinate(\ G: ~ kcfcrence: Well: 1 J-16 0, Tr ue North Sitc: Ku paruk iJ Pad Verti cal {TYllYReferencr. 1 J-160: 12 2.3 ~~cIL• 1J -160 Section (VSpl~eference: Well (O OON,O.O OE,180:OOAzi) ~~cllpath: 1 J-160 Snrvey Calculation Method: Minimum C urva ture Db: Oracle tiuni•~ ~IU fact Azim TVA -- SVSTVD ~/S 1:'W fl1apN T1apE. Tont 1 ft deg deg ft ft ft ft ft ft 2758. 57 75.86 274 .88 1984. 49 1862 .20 84. 26 -1518.34 5945899. 94 557149. 80 MWD+IFR-AK-CAZ-SC 2851. 96 74.81 273 .90 2008. 13 1885 .84 91. 18 -1608.42 5945906. 16 557059. 67 MWD+IFR-AK-CAZ-SC 2948. 15 75.36 275 .64 2032. 89 1910 .60 98. 91 -1701.04 5945913. 17 556967. 00 MWD+IFR-AK-CAZ-SC 3044. 30 75.45 275 .64 2057. 12 1934 .83 108. 06 -1793.64 5945921. 59 556874. 35 MWD+IFR-AK-CAZ-SC 3139. 49 70.69 275 .49 2084. 83 1962 .54 116. 89 -1884.25 5945929. 71 556783. 68 MWD+IFR-AK-CAZ-SC 3208. 76 73.20 274 .22 2106. 30 1984 .01 122. 45 -1949.86 5945934. 77 556718. 03 MWD+IFR-AK-CAZ-SC 3232. 39 74.16 273 .99 2112. 94 1990 .65 124. 08 -1972.48 5945936. 21 556695. 40 MWD+IFR-AK-CAZ-SC i 3327. 00 76.38 273 .00 2136. 99 2014 .70 129. 65 -2063.81 5945941. 07 556604. 04 MWD+IFR-AK-CAZ-SC 3422. 91 77.13 270 .67 2158. 97 2036 .68 132. 64 -2157.11 5945943. 33 556510. 73 MWD+IFR-AK-CAZ-SC 3505. 57 74.33 271 .00 2179. 34 2057 .05 133. 80 -2237.20 5945943. 88 556430. 64 MWD+IFR-AK-CAZ-SC i 3585. 63 76.30 269 .24 2199. 64 2077 .35 133. 96 -2314.64 5945943. 43 556353. 21 MWD+IFR-AK-CAZ-SC 3682. 35 78.55 269 .66 2220. 70 2098 .41 133. 05 -2409.03 5945941. 79 556258. 84 MWD+IFR-AK-CAZ-SC 3775. 98 79.30 270 .21 2238. 68 2116 .39 132. 95 -2500.92 5945940. 97 556166. 96 MWD+fFR-AK-CAZ-SC 3871. 49 77.27 268 .63 2258. 07 2135 .78 132. 01 -2594.42 5945939. 30 556073. 48 MWD+IFR-AK-CAZ-SC ~ 3966. 38 76.90 270 .39 2279. 28 2156 .99 131. 22 -2686.91 5945937. 79 555981. 01 MWD+IFR-AK-CAZ-SC !i 4061. 25 77.27 270 .60 2300. 49 2178 .20 132. 02 -2779.37 5945937. 87 555888. 55 MWD+IFR-AK-CAZ-SC 4156. 45 78.17 272 .30 2320. 74 2198 .45 134. 37 -2872.36 5945939. 50 555795. 56 MWD+IFR-AK-CAZ-SC 4252. 44 78.17 271 .32 2340. 42 2218 .13 137. 34 -2966.26 5945941. 73 555701. 64 MWD+IFR-AK-CAZ-SC 4346. 85 78.17 271 .73 2359. 77 2237 .48 139. 80 -3058.63 5945943. 47 555609. 26 MWD+IFR-AK-CAZ-SC 4440. 64 77.21 270 .93 2379. 77 2257 .48 141. 93 -3150.24 5945944. 89 555517. 65 MWD+IFR-AK-CAZ-SC 4536. 81 76.27 271 .04 2401. 83 2279 .54 143. 54 -3243.83 5945945. 77 555424. 06 MWD+IFR-AK-CAZ-SC 4632. 22 77.79 271 .66 2423. 24 2300 .95 145. 73 -3336.78 5945947. 23 555331. 11 MWD+IFR-AK-CAZ-SC 4726. 71 77.53 272 .00 2443. 43 2321 .14 148. 68 -3429.04 5945949. 46 555238. 84 MWD+IFR-AK-CAZ-SC ~ 4821. 96 76.83 273 .07 2464. 57 2342 .28 152. 78 -3521.82 5945952. 84 555146. 03 MWD+IFR-AK-CAZ-SC I 4916. 93 78.61 274 .80 2484. 77 2362 .48 159. 15 -3614.39 5945958. 49 555053. 43 MWD+IFR-AK-CAZ-SC 5011. 45 78.41 274 .77 2503. 60 2381 .31 166. 88 -3706.69 5945965. 50 554961. 07 MWD+IFR-AK-CAZ-SC 5106 .28 77.10 275 .39 2523. 71 2401 .42 175. 09 -3799.00 5945972. 99 554868 .72 MWD+IFR-AK-CAZ-SC 5202 .19 78.22 275 .38 2544. 21 2421 .92 183. 88 -3892.28 5945981. 05 554775 .38 MWD+IFR-AK-CAZ-SC ', 5296. 10 78.29 274 .82 2563. 32 2441 .03 192. 05 -3983.86 5945988. 51 554683 .75 MWD+IFR-AK-CAZ-SC 5388. 25 77.28 274 .64 2582. 82 2460 .53 199. 48 -4073.62 5945995. 24 554593. 95 MWD+IFR-AK-CAZ-SC 5485. 00 77.47 274 .47 2603. 97 2481 .68 206. 98 -4167.73 5946002. 00 554499. 79 MWD+IFR-AK-CAZ-SC 5583. 88 77.34 273 .88 2625. 53 2503 .24 214. 00 -4263.97 5946008. 27 554403. 50 MWD+IFR-AK-CAZ-SC 5678. 36 77.98 273 .66 2645. 72 2523 .43 220. 07 -4356.07 5946013. 62 554311. 37 MWD+IFR-AK-CAZ-SC 5777. 05 78.04 269 .67 2666. 23 2543 .94 222. 87 -4452.54 5946015. 68 554214. 88 MWD+IFR-AK-CAZ-SC 5868. 89 77.16 266 .73 2685. 95 2563 .66 220. 06 -4542.19 5946012. 16 554125. 27 MWD+tFR-AK-CAZ-SC 5963. 84 77.66 265 .63 2706. 65 2584 .36 213. 89 -4634.64 5946005. 27 554032. 88 MWD+IFR-AK-CAZ-SC 6059. 13 77.55 263 .42 2727. 11 2604 .82 205. 01 -4727.28 5945995. 67 553940 .32 MWD+IFR-AK-CAZ-SC 6154 .34 77.86 262 .17 2747. 38 2625 .09 193. 34 -4819.57 5945983. 29 553848 .13 MWD+IFR-AK-CAZ-SC 6249 .56 77.92 260 .43 2767. 36 2645 .07 179. 26 -4911.60 5945968. 49 553756 .23 MWD+IFR-AK-CAZ-SC 6344 .64 77.66 256 .98 2787. 47 2665 .18 161. 06 -5002.71 5945949, 58 553665 .27 MWD+IFR-AK-CAZ-SC ~ 6439 .37 77.83 253 .45 2807. 59 2685 .30 137. 44 -5092.20 5945925. 27 553575 .97 MWD+IFR-AK-CAZ-SC 6534 .39 77.79 248 .57 2827. 66 2705 .37 107. 23 -5180.00 5945894 .38 553488 .42 MWD+IFR-AK-CAZ-SC j 6630 .46 77.47 244 .65 2848. 25 2725 .96 69. 98 -5266.11 5945856 .47 553402 .61 MWD+IFR-AK-CAZ-SC 6725 .46 77.34 241 .24 2868. 97 2746 .68 27. 82 -5348.66 5945813 .67 553320 .40 MWD+IFR-AK-CAZ-SC 6819 .15 77.27 238 .32 2889. 57 2767 .28 -18. 18 -5427.63 5945767 .06 553241 .80 MWD+IFR-AK-CAZ-SC 6914. 80 76.77 235 .22 2911. 06 2788 .77 -69. 24 -5505.59 5945715 .39 553164 .25 MWD+IFR-AK-CAZ-SC 7010 .91 77.79 233 .52 2932. 22 2809 .93 -123. 86 -5581.78 5945660. 19 553088 .49 MWD+IFR-AK-CAZ-SC 7105 .85 76.88 231 .23 2953. 04 2830 .75 -180. 40 -5655.14 5945603. 08 553015 .58 MWD+IFR-AK-CAZ-SC 7201 .03 76.96 228 .08 2974. 58 2852 .29 -240. 41 -5725.79 5945542. 53 552945 .40 MWD+IFR-AK-CAZ-SC 7295 .69 77.80 223 .74 2995. 27 2872 .98 -304. 67 -5792.12 5945477 .76 552879 .59 MWD+IFR-AK-CAZ-SC 7391 .01 77.53 220 .85 3015. 64 2893 .35 -373. 54 -5854.78 5945408. 41 552817 .47 MWD+IFR-AK-CAZ-SC i 7485 .86 77.16 218 .95 3036. 42 2914 .13 -444. 54 -5914.14 5945336 .96 552758 .67 MWD+IFR-AK-CAZ-SC ~~ Halliburton Company Survey Report Company: ConocoPhillips Alaska Inc. Date: 4/26/2007 Timr: 15:fl2:25 Page: 3' Field: Kuparuk River Unit Co-ordinate(NE)Reference: Well: 1J-166,True North Site: Kuparuk 1J Pad Vertical (TVD) Reference: 1J-160: 122.3 Well: 1J-160 tiection IVS)Reference: 'Well (O.OON,O.OOE,180.OOAzi) R'ellpath: 1J-16G Sui~~cy ('akulation,nlethod: MinimumCurvature Db: Oracle Surec~' -- -- ~tU Intl Ati~n TVD Sys TVD ~'V1S E/W NIapN MapE Fool ft ceg deg ft ft ft ft ft ft 7579.69 77.15 216.43 3057.29 2935.00 -516.92 -5970.06 5945264.15 552703.32 MWD+IFR-AK-CAZ-SC 7674.68 77.28 211.84 3078.32 2956.03 -593.58 -6022.03 5945187.10 552651.96 MWD+IFR-AK-CAZ-SC 7770.42 77.15 207.30 3099.51 2977.22 -674.76 -6068.09 5945105.57 552606.53 MWD+IFR-AK-CAZ-SC 7866.83 77.27 203.67 3120.86 2998.57 -759.61 -6108.54 5945020.41 552566.75 MWD+IFR-AK-CAZ-SC 7962.10 77.22 200.77 3141.90 3019.61 -845.62 -6143.67 5944934.14 552532.29 MWD+IFR-AK-CAZ-SC 8056.00 77.79 196.74 3162.23 3039.94 -932.41 -6173.14 5944847.13 552503.51 MWD+IFR-AK-CAZ-SC 8151.22 78.98 192.83 3181.40 3059.11 -1022.57 -6196.93 5944756.80 552480.42 MWD+IFR-AK-CAZ-SC 8246.11 79.80 190.56 3198.88 3076.59 -1113.90 -6215.83 5944665.34 552462.23 MWD+IFR-AK-CAZ-SC ', 8340.39 80.30 189.08 3215.17 3092.88 -1205.40 -6231.67 5944573.73 552447.11 MWD+IFR-AK-CAZ-SC ail 8436.16 79.61 189.65 3231.87 3109.58 -1298.44 -6247.01 5944480.57 552432.50 MWD+IFR-AK-CAZ-SC ~ 8531.29 80.04 188.99 3248.68 3126.39 -1390.84 -6262.17 5944388.07 552418.05 MWD+IFR-AK-CAZ-SC ~ 8627.07 79.43 189.05 3265.75 3143.46 -1483.92 -6276.95 5944294.89 552404.01 MWD+IFR-AK-CAZ-SC 8721.13 80.86 187.17 3281.85 3159.56 -1575.66 -6290.02 5944203.06 552391.65 MWD+IFR-AK-CAZ-SC 8817.41 82.24 185.74 3295.99 3173.70 -1670.28 -6300.72 5944108.36 552381.69 MWD+IFR-AK-CAZ-SC I 8912.74 81.54 184.43 3309.44 3187.15 -1764.29 -6309.09 5944014.30 552374.05 MWD+IFR-AK-CAZ-SC 9007.86 81.67 184.11 3323.33 3201.04 -1858.13 -6316.09 5943920.42 552367.78 MWD+IFR-AK-CAZ-SC 9102.73 82.05 183.27 3336.76 3214.47 -1951.84 -6322.14 5943826.67 552362.47 MWD+IFR-AK-CAZ-SC 9197.26 81.80 180.16 3350.05 3227.76 -2045.38 -6324.94 5943733.12 552360.40 MWD+IFR-AK-CAZ-SC 9292.41 81.86 179.91 3363.57 3241.28 -2139.57 -6325.00 5943638.95 552361.07 MWD+IFR-AK-CAZ-SC 9387.64 81.74 180.19 3377.15 3254.86 -2233.82 -6325.08 5943544.70 552361.72 MWD+IFR-AK-CAZ-SC 9481.73 82.62 179.57 3389.95 3267.66 -2327.04 -6324.88 5943451.50 552362.65 MWD+IFR-AK-CAZ-SC 9577.07 82.98 180.02 3401.90 3279.61 -2421.62 -6324.55 5943356.93 552363.72 MWD+IFR-AK-CAZ-SC 9671.79 83.79 179.67 3412.81 3290.52 -2515.71 -6324.29 5943262.85 552364.71 MWD+IFR-AK-CAZ-SC 9766.74 86.71 180.85 3420.67 3298.38 -2610.32 -6324.72 5943168.25 552365.01 MWD+IFR-AK-CAZ-SC iI 9862.32 87.26 180.35 3425.70 3303.41 -2705.76 -6325.72 5943072.81 552364.76 MWD+IFR-AK-CAZ-SC 9957.25 87.26 180.91 3430.24 3307.95 -2800.58 -6326.76 5942978.00 552364.45 MWD+IFR-AK-CAZ-SC j 10052.34 85.46 180.00 3436.28 3313.99 -2895.47 -6327.52 5942883.12 552364.44 MWD+IFR-AK-CAZ-SC 10147.19 83.16 179.09 3445.68 3323.39 -2989.84 -6326.77 5942788.76 552365.92 MWD+IFR-AK-CAZ-SC ~ 10241.22 86.53 178.91 3454.13 3331.84 -3083.46 -6325.14 5942695.17 552368.29 MWD+IFR-AK-CAZ-SC I 10271.00 86.53 178.91 3455.93 3333.64 -3113.18 -6324.57 5942665.45 552369.08 • PROJECTED to TD 1~ Conoc~Phil~ips Time Log Summary YvelN7ew Nleb Reporf'^g _.. __... Well Name: 1 J-160 Job Type: DRILLING ORIGINAL Time Logs _ __ ___ __ Date From_ To D__ur S. De th E De th Nhase Code Subcode T CQM __ ~ _- 02/28/2007 00:00 06:00 6.00 0 0 MIRU MOVE DMOB P Rig released from 1J-180 @ 2400 HRS 2/27/07 .Continue demob rig for move. Disconnect all steam, air, water & h draulic lines. Crew Chan e 06:00 12:00 6.00 0 0 MIRU MOVE DMOB P Continue disconnect all steam, air , water & hydraulic lines. Pull rockwasher & cutings tanks away from ri . 12:00 18:00 6.00 0 0 MIRU MOVE DMOB P Continue disconnect all steam, air , water & hydraulic lines. Pull Pit module away from sub. Continue lay matting boards on 1J -160. Crew Chan e 18:00 00:00 6.00 0 0 MIRU MOVE DMOB P Skid rig floor and derrick. Move Sub module away from well 1j-180. Pull onto pad. Move sub module to 1J-160 and spot over well with DSO on location as tanned. 03/01/2007 00:00 06:00 6.00 0 0 MIRU MOVE MOB P Continue spot Sub Module over well 1J -160. Move Pit Module and spot same. Skid ri floor & Derrick. Crew Chan e. 06:00 12:00 6.00 0 0 MIRU MOVE MOB P Pick the stomper up, adjust shims. Set stompers down and lock in place. Lay Herculite berm for rockwasher. Connect all steam, air, hydraulic and water lines. PJSM, then skid rig floor into place, centered over the well. Install roof caps on pipe shed and install all handrails. Rig up Beaver slide. Install plugs on all centrifugal pumps. Set rockwasher in place with truck. Connect all lines to rockwasher. 12:00 18:00 6.00 0 0 MIRU MOVE MOB P Lay herculite, spot and install cuttings tanks. Connect mud line. Berm and build pit products loading dock. Connect bleed line, mud bucket drain line and all lines under rig floor area. Install remaining bolts on speed head. Crew Chan e. 18:00 20:00 2.00 0 0 MIRU MOVE MOB P Remove flush mounted slips, lower from rig floor. Install riser, connect flowline, fillup lines, and pit module to sub module interconnects. Continue checking and making up Handi-Berm for outside of rig. Check stairs, and lay down nut plug as needed. Rig accepted @ 2000 hrs as per company man and toolpusher. with rig acce tance checklist. Time Logs Date From To Dur S De tht E. De th Phase Code Subcode T COM 03!01/2007 20:00 00:00 4.00 _ 0 0 MIRU WELCT __ NUND _ P Install diverter line and orient same. Connect riser turnbuckles and tighten same. Continue to make up remaining diverter system. Install hydraulic lines on knife valve and Annular. Wrap annular with herculite and apply a tioga heater hose. Connect steam loops in cuttings tanks. Begin loading pipe shed with 5" dp and BHA assembl . 03/02/2007 00:00 03:00 3.00 0 0 SURFA DRILL PULD P Load pipe shed with 5" DP & BHA assembly. Pull protectors and strap DP. Install 2 - 3" ball valves on Diverter head. Inspect lay down machine and re for ickin u DP> 03:00 06:00 3.00 0 0 SURFA DRILL PULD P Pick up 5" drill pipe, drift pipe to 2.75" in singles and rack back stands in derrick.Crew Chan e 06:00 08:45 2.75 0 0 SURFA DRILL PULD P Continue pick up 5" DP in singles and drift to 2.75" ,rack back in sderrick. 08:45 09:15 0.50 0 0 SURFA DRILL OTHR P Pull mousehole from rotary table, and install in normal position. Check & tighten all bolts again on diverter s stem. 09:15 10:00 0.75 0 0 SURFA DRILL PULD P Pick up 11 joints of 5" HWDP with 8" Drillin ~ars and rack back in derrick. 10:00 12:00 2.00 0 0 SURFA WELCT BOPE P Perform Diverter function test and Accumulator test. Knife valve open in 19 seconds and hydrill fully closed in 46 seconds. Perform Accumulator test. Check pressure in nitrogen bottles. Witness of Diverter test waived by AOGCC rep -Chuck Sheave. 12:00 12:45 0.75 0 0 SURFA DRILL PULD P Pull tools to rig floor and rig up to make u BHA #1. 12:45 13:15 0.50 0 0 SURFA DRILL PULD P Rig up Halliburton Gyro unit. lines and sheaves. 13:15 13:45 0.50 0 0 SURFA DRILL SFTY P Held PJSM & Table top drill on diverting shallow gas with entire crew, S er Sun re sand MI re . . 13:45 15:30 1.75 0 0 SURFA DRILL PULD P Make up BHA #1.16" Bit & Motor assembl . Plu in and u load MWD. 15:30 15:45 0.25 0 0 SURFA DRILL OTHR P Pick up 1 stand of HWDP and tag bottom at 102' MD. Flood conductor system with mud. Inspect system for leaks. Check all surface a ui ment. 15:45 16:15 0.50 0 0 SURFA DRILL OTHR P Blow air through lines to ensure all clear and not froze up. Pressure test mud line to 3000 PSI. Good test. 16:15 16:45 0.50 0 0 SURFA DRILL REAM P Wash & ream from 102' - 117' with H2O and swap to spud mud @ 450 GPM's - 790 PSI 16:45 17:30 0.75 0 226 SURFA DRILL DRLG P Spud well drilling from 117' - 226;'. as er DD. ®v ~ ~ .~ ~ P~€~e ~ sat ~~~ L_ Time Logs ~~ Date From To Dur S Depth E De~th.Phase Code Subcode T COM ______ _ 03/04/2007 22:30 00:00 1.50 2,907 2,907 SURFA DRILL REAM NP Gain MWD surveys with full pump strokes observing dogleg still in well bore. Continue wash & ream to knockout do le , as er DD. 03/05/2007 00:00 01:30 1.50 2,907 2,907 SURFA DRILL REAM NP Continue wash & ream to knockout dogleg, as per DD from 5.7 deg to 3 de . 01:30 06:00 4.50 2,907 3,193 SURFA DRILL DDRL P Continue driectional drill 16" surface hole from 2907' - 3193' MD. TVD = 2103'. Observed survey indicating severe drop, with 600 PSI on drill string. Suspect motor failure. Crew Chan e 06:00 07:00 1.00 3,193 3,193 SURFA DRILL CIRC T Reciprocate & rotate drill string while circulate 2 times @ 750 GPM's - 3450 PSI to clean hole. 07:00 07:45 0.75 3,193 3,098 SURFA DRILL TRIP T Stand back 1 stand. Blow down Top drive & lines. Monitor well -static. Attempt to POOH on elevators -well swabbin . 07:45 11:30 3.75 3,098 1,576 SURFA DRILL REAM T BROOH from 3098' - 1576' @ 750 GPM's - 2900 PSI. Attempt to POOH periodically observing hole swabbing. Observe hole unloading and cleaning u after a ood 4 bottoms u um in . 11:30 12:00 0.50 1,576 1,098 SURFA DRILL TRIP T Monitor well-static. POOH on elevators with well swabbing. Continue POOH with pumps on - no rotation @ 400 GPM's - 780 PSI. Hole fill - ood. 12:00 13:00 1.00 1,098 513 SURFA DRILL TRIP T Continue pump out of hole @ 400 GPM's - 850 PSI. POOH to 513'. 13:00 .14:45 1.75 513 0 SURFA DRILL TRIP T Continue POOH on elevators. Hole fill -good. Spin mud out of mud motor and check for bearing play. Observed asembly balled up with mud. Breakout & ins ect bit to 1/1/WT/A/E/I/FC/BHA. 14:45 15:15 0.50 0 0 SURFA DRILL PULD T Plug in and download MWD assembl . 15:15 16:00 0.75 0 0 SURFA DRILL PULD T Lay down mud motor, pull back up motor to ri floor. 16:00 16:30 0.50 0 0 SURFA DRILL OTHR T Clean & clear rig floor area. 16:30 17:00 0.50 0 0 SURFA DRILL PULD T Make up bit & back up motor. Adjust BHA strap. New BHA total length = 532.11'. 17:00 17:15 0.25 0 0 SURFA DRILL PULD T Plug in and Upload MWD assembly. 17:15 18:00 0.75 0 162 SURFA DRILL PULD T Make up remaining BHA to 162'. Crew Chan e 18:00 18:30 0.50 162 532 SURFA DRILL PULD T Continue making up BHA to 532'. 18:30 20:15 1.75 532 2,530 SURFA DRILL TRIP T Trip in hole from 532' - 2530'. Fill drill string on stand #10, Blow down top drive & lines. Observe good hole and ro er hole fill. ..-. ~'~~~ _~ c, ~Ca Time Lo s Date From To Dur S. De th E. Depth Phase Code Subcode T COM 03!05/2007 20:15 21:30 1.25 2,530 2,530 SURFA DRILL CIRC T Circulate & condition mud cleaning up hole @ 2530 MD as per Co. Rep. Observed hole unloading while slowly staging pumps to 750 GPM's - 2700 PSI. Mode swith MWD tools, and ulse test same. 21:30 22:15 0.75 2,530 3,193 SURFA DRILL TRIP T Continue trip in hole from 2530' - 3193'. Obtain T & D parameters every 5 stands. Observed good clean hole to bottom. 22:15 00:00 1.75 3,193 3,321 SURFA DRILL DDRL P Continue directional drill 16" surface hole from 3193' - 3321' MD. ND = 2134'. ADT = .74 HRS. 03/06/2007 00:00 03:30 3.50 3,321 3,560 SURFA DRILL DDRL P Continue directional drill 16" surface hole from 3321' - 3560' MD. ND = 2190'. ADT = 2.49 HRS. 03:30 04:00 0.50 3,560 3,560 SURFA DRILL CIRC P Circulate hole obtaining check shot surveys as per DD. Reciprocate & rotate drill string, increasing pump rates to 850 GPM's - 3500 PSI. 04:00 06:00 2.00 3,560 2,950 SURFA DRILL REAM P BROOH slow @ 20 ft/min to clean hole and obtain 3 bottoms up. Pull from 3560' - 2950' MD. Crew Chan e 06:00 07:00 1.00 2,950 2,718 SURFA DRILL REAM P Continue BROOH from 2950' - 2718' @ 840 GPM's -3400 PSI. Observed ressure dro to 2700 PSI. 07:00 07:45 0.75 2,718 2,623 SURFA DRILL REAM P Continue BROOH from 2718' - 2623' MD. 07:45 08:15 0.50 2,623 2,433 SURFA DRILL TRIP P POOH on elevators from 2623' - 2433'. Good hole fill - no swabbin . 08:15 08:45 0.50 2,433 2,433 SURFA DRILL CIRC P Pump 30 BBLS dry job. Blow down To Drive & lines. 08:45 11:15 2.50 2,433 532 SURFA DRILL TRIP P Continue POOH on elevators from 2433' - 532'. Obtain T&D parameters as er ri en ineer. 11:15 11:45 0.50 532 532 SURFA DRILL PULD P Plug in and download MWD assembl . 11:45 12:00 0.25 532 0 SURFA DRILL PULD P Breakout & lay down BHA #2. 12:00 12:30 0.50 0 0 SURFA DRILL PULD P Continue breakout & lay down BHA #2. Inspect & gauge bit to 1 /1 /WT/A/E/i/FC/TD. 12:30 13:30 1.00 0 0 SURFA DRILL PULD P Send tools out. Clean & clear rig floor area. 13:30 17:00 3.50 0 0 SURFA CASINC RURD P PJSM with crew &GBR reps. Discuss safety issues and procedure for rigging up casing equipment and making up hanger on running tools. Pull hanger and short landing joint to rig floor. Make up same and lay down in pipe shed. 17:00 18:00 1.00 0 0 SURFA CASIN RURD P Rig up casing tongs & euipment for 13 3/8". Crew Chan e 18:00 19:15 1.25 0 0 SURFA CASIN RURD P New crew. Held PJSM with crew & GBR reps. Discuss safety issues and procedure for rigging up and running 13 3/8" casin . (-.- I Time Logs Date ____ .From To_ Dur S. De th E_ D~th Phase _ Code Subcode T ___ _ COM __ 03/06/2007 19:15 22:15 3.00 0 1,052 SURFA CASIN( RNCS P Make up shoe joint, threadlock & float collar joint. Install 13 3/8" bowspring centralizer 5' above shoe, 20' above & below float collar. Fill pipe & check floats. Floats good. Continue run casin fillip eve 'oint to 1052'. 22:15 22:30 0.25 1,052 1,052 SURFA CASIN CIRC P Circulate bottoms up @ 1052' staging to 7 BPM - 400 PSI. 22:30 00:00 1.50 1,052 2,292 SURFA CASINO RNCS P Conitnue run 13 3/8" casing from 1052' - 2292'. Observed fluid loss of 27 BBL loss since start run in hole, indicating 5.6 BBLS / HR loss. 03/07/2007 00:00 04:00 4.00 2,292 3,502 SURFA CASIN( RNCS P Continue run 13 3!8" casing from 2292' - 3502'. Observed fluid losses of 14 BBLS / HR. 85 Total jnts run. 105 bbl loss on RIH with casin . 04:00 04:45 0.75 3,502 3,550 SURFA CASINO RNCS P Install casing hanger & pup with short landing joint. Breakout short joint & install 47' landing joint. Pull casing slips, and land casing on depth of 3550.91'. 04:45 06:00 1.25 3,550 3,550 SURFA CASIN( RURD P Fill casing with mud. Blow down Top drive & lines. Rig down Franks fill up tool. Make up crossover & casing head with plugs previously installed. Make up circulating lines. SIMOPS: Spot & rig up trucks and Dowell cementers. Crew Chan e 06:00 09:30 3.50 3,550 3,550 SURFA CEME~ CIRC P Circ & Condition mud to properties of 9.4 ppg, 57 vis, 25 PV, 14 YP, 2/3 gels, Stage rate up to 5 bpm @ psi with no losses -When attempt to increase rate to above 5 bpm hole began to loose mud. After mud was in shape staged rate up to 7 bpm w/ full returns. Reciprocate pipe 15'. Total of 20 bbls lost while circ & cond mud. Held PJSM on cement job with all arties. U 260K, Dn 132K. 09:30 12:00 2.50 3,550 3,550 SURFA CEME~ CIRC P Turn rig over to Dowe-1 cementers. Pump 10 BBLs CW 100. Test Lines to 2500 PSI. Good test. Continue pump 40 BBLS CW 100, 50 BBLS MudPush II @ 10.5 ppg, Drop Bottom plug. pump a total of 523.4 BBLS of Lead Cement @ 10.7 ppg, and 102.6 BBLS of Tail @ 12.0 ppg. Drop Top plug. Pump 20 BBLS of water. NOTE: Movement of casing became sticky when 37 bbls cmt around shoe, Land casing, stop reciprocation. Full returns. ~ ~~ ®. e ~ .~ 1'atJ~; 6 oaf ~._.W._ Time Logs __ ___ Date From To Dur S Depth E De th Phase Code Subcod_e___ T COM 03/07/2007 12:00 13:30 1.50 3,550 3,550 SURFA CEME DISP P Turn over to rig pumps. Start displace cement @ 7 BPM - 210 psi to 570 psi. After pumping 900 stks lost returns, Worked pipe up to 1' off hanger (Note; Pipe pulling up to 400K) -Regain partial returns after 1300 stks, Regain full returns after 1500 stks into displacement, Returns began to diminish after 3100 stks, Slowed rate to 5 bpm @ 510 psi to 650 psi, Returns began to diminish after 3650 stks, Slowed rate to 4.5 bpm @ 660 psi to 640 psi, Lost full returns at 4750 stks, Slowed rate to 3 bpm @ 580 psi after 4850 stks (10 bbls prior to bump). Bumped plug w/ 4949 Stks = 497.8 BBLS. Continue pressure to 1080 PSI. Hold pressure for 5 minutes. Check floats. Floats held. CIP @ 1330 HRS. Observed red dye to surface @ 3500 stks- No cement observed. Estimated loss of 75 bbls while cementin . 13:30 16:00 2.50 3,550 3,550 SURFA CASIN RURD P Rig down cement head & lines. Lay down landin 'oint. 16:00 18:00 2.00 3,550 0 SURFA WELCT NUND P Nipple down diverter equipment. Pull riser to rig floor and stand back same. Crew Chan e 18:00 20:15 2.25 0 0 SURFA WELCT NUND P Continue nipple down diverter equipment. Set Annular, knife valve & "T" in cellar. With rig welder, cut a slot in the 20" conductor for CS Hydril. The Hydril tubing would not pass through the fluted han er. 20:15 00:00 3.75 0 0 SURFA CEME RURD T Rig up equipment to run 1 1/4" CS Hydril tubing down Annulus. Run CS Hydril to 301' from rotary table. Observed pipe would not go any deeper. Rig up line from manifold and attempt to pump down Hydril, pipe plugged. Pressure to 1500 PSI. Rig down & blow down lines. 03/08/2007 00:00 03:45 3.75 0 0 SURFA CEME RURD T Continue attempt to circulate down CS Hydril tubing. No success. Pull 90' of Hydril, Mule shoe at 227' from rot. Table. Attempt to circulate. Gain circulation. Attempt to run back in hole with 1 joint. NO - Go. Discuss options with AOGCC rep Chuck Sheave. He recommended cementing at this depth. Break circulation staging to 2.5 BPM - 800 PSI. Circulate until verified good 8.5 PPG water returns & clean fluid, pumping a total of 58 BBLS. NOTE: AOGCC rep waived witness of cementin to ~ob. ~~~~ ~ o~ X13 Time Logs Date From To b_ur ___ S Depth E. De th Phase Code Subco_de T COM _ __ 03/08/2007 03:45 04:30 0.75 0 0 SURFA CEME DISP T Turn over to Dowell. Pump a total of 32 BBLS until observing good 10.5 PPG cement, and finish with a total of 39 BBLS pumped away. Wash lines, and blow down same. 04:30 05:30 1.00 0 0 SURFA CEME~ RURD T Pull 1 1/4" CS Hydril form well bore, washing each joint & blowing down same. 9 total joints. 11 joints sent to Tubocso a for ins ection. 05:30 06:00 0.50 0 0 SURFA CASIN( NUND P Clean rig floor and cellar area. Prep to rig up wellhead. Attach bridge cranes to well head in cellar.Crew than e 06:00 07:30 1.50 0 0 SURFA WELCT NUND P Makeup landing ring on 13 3/8" hanger as per rep. Continue set Vetco Gray M222 13 5/8" x 4 1/16" Multibowl injector wellhead, nipple up same. Rig up & test to 5000 ft/Ibs. for 10minutes. Witnessed b driller. 07:30 13:00 5.50 0 0 SURFA WELC NUND P Nipple up drilling spool. Continue clear rig floor from all casing equipment. Complete Top Job pouring cement in top of conductor. NOTE: Cement Top = 24" from casin han er. 13:00 13:15 0.25 0 0 SURFA WELCT SFTY P Held PJSM with crew. Discuss safety & hazard recognition issues. Discuss Ni le u BOPS's. 13:15 17:30 4.25 0 0 SURFA WELC NUND P Nipple up BOP stack, choke & kill lines. Utilize sween wrench for NU. 17:30 18:00 0.50 0 0 SURFA WELCT NUND P Install 16" bell nipple. Crew Change 18:00 20:00 2.00 0 0 SURFA WELCT NUND P Continue nipple 16" nipple & flowlines. Install fill up lines. Continue torque up bolts on BOP stack. Install turnbuckles and ad'ust same. 20:00 21:15 1.25 0 0 SURFA WELC BOPE P Rig up lines and tools to test BOP's. Blow air through all lines. Fill BOP stack, lines, and choke manifold with water. Make up 5" test joint with test lu .Install lu . 21:15 00:00 2.75 0 0 SURFA WELCT BOPE P Test BOP stack, rams & valves. 250 PSI low & 3000 PSI high test as per permit. NOTE: AOGCC rep Chuck Sheave waived witness of test. Record all tests on chart. 03/09/2007 00:00 03:00 3.00 0 0 SURFA WELCT BOPE P Continue test BOP's. Perform Koomey test. Pull test plug & test joint. Lay down same. Rig down all BOP testing e ui ment. ~.._ v ®e ~_~ ~<~~e 8 of r,7 l J Time Logs Date From To Dur S__ Depth E. De th Phase Code Subcode T COM _ __ 03/09/2007 03:00 06:00 _ _ 3.00 0 0 SURFA RIGMN _ RURD P _ PJSM with Franks Rep, and rig crew. Discuss safety & hazard recognitiion issues. Rig up and install Franks Stab-Rite casing tool as per reps. Install Electrical unit behind draw works. Test run Top Drive by Stab Rite. Observed Top drive would pass by it. Obtain measurements and remove Stab -Rite assembly. Crew Chan e 06:00 06:30 0.50 0 0 SURFA RIGMN' RURD P Continue removing Stab-Rite assembl from derrick. 06:30 07:30 1.00 0 0 SURFA DRILL OTHR P Pick up test joint. Install wear bushing & RILDS. Held PJSM on picking up DP from shed. 07:30 12:30 5.00 0 0 SURFA DRILL OTHR P Install mousehole in rotary table. Pick up 96 joints of 5" DP from pipe shed with super sliders previously installed. Rack back stands in derrick. 12:30 13:30 1.00 0 0 SURFA DRILL OTHR P Breakout & lay down 8" drilling jars from HWDP stand in BHA #2. The shoulder was damaged when coming throu h stack on last run. 13:30 17:15 3.75 0 0 SURFA DRILL PULD P PJSM with crew, Sperry Sun reps. Discuss safety & hazard recognition issues including handling & installation of nuclear sources in BHA. Make u BHA to MWD assembl . 17:15 18:00 0.75 0 0 SURFA DRILL PULD P Plug in and upload MWD assembly. Crew Chan e 18:00 18:45 0.75 0 0 SURFA DRILL PULD P Continue with upload of MWD assembl . 18:45 19:00 0.25 0 570 SURFA DRILL PULD P Continue make up BHA #3, installing float. 19:00 19:30 0.50 0 0 SURFA DRILL PULD P Quick PJSM on nuclear sources. Install signs and clear rig floor. Install Nukes as er S er Sun re s. 19:30 20:00 0.50 0 0 SURFA DRILL PULD P Make up flex drill collars and XO, Install corrossion ring in top of first stand of HWDP. 20:00 21:00 1.00 0 570 SURFA DRILL PULD P Perform Shallow pulse test @ 700 GPM's - 1150 PSI. Break in geo-Pilot @ 30 RPM's. Obtain good signals and commands to tools. Blow down Top drive & Iines.Continue MU last stand of HWDP with drillin 'ars. 21:00 00:00 3.00 570 3,050 SURFA DRILL TRIP P Trip in hole with 5" slick Drill Pipe from i e shed to 3050' MD. 03/10/2007 00:00 00:15 0.25 3,050 3,429 SURFA DRILL TRIP P Continue trip in hole with 5" slick Drill Pi a from i e shed to 3429' MD. 00:15 01:00 0.75 3,429 3,429 SURFA DRILL CIRC P Make top Drive connection and circulate bottoms up @ 700 GPM's - 2000 PSI. ~ ~ Time Logs Date From__ To ur D Depth S E. Depth Phase Co de Subcode T COM _ _ _ ___ 03/10/2007 01:00 _ _ 02:30 _ __ 1.50 __ 3,429 3,429 SURFA _ _ _ DRILL DHEO P _ __ _ ____ Rig up lines & chart recorder. Blow down top drive. Fill all lines and kill line with mud removing air from system. Pressure to 3000 PSI on the 13 3/8" casing for 30 minutes. Record on chart. Good test. Bleed pressure, rig down & blow down lines. Simops: Rig up vac trucks for LSND dis lacement. 02:30 05:00 2.50 3,460 3,551 SURFA CEME~ COCF P Tag FC & plugs on depth @ 3460'. Drill plugs, FC and cement down to shoe at 3551'. 05:00 05:15 0.25 3,551 3,580 SURFA DRILL DDRL P Drill 20' of open hole to 3580' MD. 2199' TVD. Simops: Held PJSM with crew, mud engineer & vac truck drivers. Discuss safety & hazard issues including -43 deg temperatures. Discuss procedure for displacing well with 9.0 PPG LSND mud. 05:15 06:00 0.75 3,580 3,580 SURFA DRILL CIRC P Circulate to displace well with 9.0 PPG LSND mud as planned. Pumps @ 700 GPM's - 1300 PSI. Crew Chan e 06:00 07:30 1.50 3,580 3,580 SURFA DRILL LOT P Rig up test equipment for LOT. Pump down annulus and DP to perform a LOT to 14.2 PPG MWE as per computer schedule. Bleed pressure & ri down test e i ment. 07:30 07:45 0.25 3,580 3,580 INTRMI DRILL CIRC P Obtain SPR's @ 3550' MD. See pump checks. 07:45 08:00 0.25 3,580 3,580 INTRM1 DRILL CIRC P Performed staged PWD test obtaiing clean hole ECD baseline = 9.1 PPG EMW. 08:00 12:00 4.00 3,580 4,055 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 3580' - 4055' MD. TVD = 2230'. ADT = 2.48 HRS. ECD = 9.49 PPG. 12:00 18:00 6.00 4,055 4,851 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 4055' - 4851' MD. TVD = 2471'. ADT = 2.48 HRS. ECD = 9.49 PPG. Crew Chan e 18:00 00:00 6.00 4,851 5,661 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 4851' - 5661' MD. TVD = 2642'. ADT = 3.79 HRS. ECD = 9.72 PPG. pumped 35 BBL Hi Visc sweep. Observed 10% increase in cutting across shakers u on return. 03/11/2007 00:00 06:00 6.00 5,661 6,156 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 5661' - 6156' MD. TVD = 2748'. ADT = 3.86 HRS. ECD = 9.98 PPG. Crew Chan e 06:00 12:00 6.00 6,156 6,621 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 6156' - 6621' MD. TVD = 2846'. ADT = 3.74 HRS. ECD = 10.12 PPG. ~~~.~. r~~ _ ~~c~~ i~t'i ut ~~ ~ Time Lo s Date From To Dur S Depth_ E Depth_Phase___Code __Subcode T COM _ 03/11/2007 12:00 18:00 6.00 6,621 7,270 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 6621' - 7270' MD. TVD = 2990'. ADT = 3.87 HRS. ECD = 10.17 PPG. Crew Chan e 18:00 00:00 6.00 7,270 7,872 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 7270' - 7872' MD. TVD = 3122'. ADT = 4.08 HRS. ECD = 10.24 PPG. K-13 formation = 7619' MD, 3066' TVD as er Geolo ist. 03/12/2007 00:00 06:00 6.00 7,872 8,355 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 7872' - 8355' MD. TVD = 3217'. ADT = 4.13 HRS. ECD = 10.32 PPG. K-13 formation = 7619' MD, 3066' TVD as per Geologist. Crew Chan e 06:00 12:00 6.00 8,355 8,846 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 8355' - 8846' MD. TVD = 3299'. ADT = 3.73 HRS. ECD = 10.28 PPG."D" Sand top = 8387' MD , TVD = 3223' as er Geolo ist. 12:00 18:00 6.00 8,846 9,390 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 8846' - 9390' MD. TVD = 3377'. ADT = 4.09 HRS. ECD = 10.28 PPG."B" Sand top = 8766' MD , TVD = 3289' as per Geologist. Crew Chan e 18:00 00:00 6.00 9,390 9,942 INTRM1 DRILL DDRL P Directional Drill 12 1/4" Intermediate hole from 9390' - 9942' MD. TVD = 3429'. ADT = 3.86 HRS. ECD = 10.41 PPG. 03/13/2007 00:00 06:00 6.00 9,942 10,271 INTRMI DRILL DDRL P Directional Drill 12 1/4" Intermediate hole. Jar hours 107.05 hrs. Max gas 112 units. 06:00 11:15 5.25 10,271 9,894 INTRM1 DRILL CIRC P Pump a 55 bbls weighted (11.2ppg), hi vis (270 vis). While circulating 4 bottom's up, backream out of hole from 10271' to 9894'. Pumping 850 gpm w/ 3250 psi, rotating 160 rpm w/ 15 k ft Ibs torque. Pulling speed .7' per min. 11:15 11:45 0.50 9,894 9,514 INTRM1 DRILL TRIP P Pull out of hole on elevators. 11:45 12:00 0.25 9,514 9,514 INTRM1 DRILL CIRC P Spot a 60 bbl gel pill in hole f/ 9514' to 9137'.30 b el. 12:00 13:00 1.00 9,514 8,754 INTRM1 DRILL TRIP P Pull out of hole on elevators. Hole swabbing slightly. Pumped out f/ 8944' to 8849'. Pulled out from 8849' to 8754'. 13:00 13:30 0.50 8,754 9,150 INTRM1 DRILL TRIP P Trip in the hole 13:30 13:45 0.25 9,150 9,150 INTRMI DRILL OWFF P Monitor well. Static. 13:45 16:30 2.75 9,150 7,233 INTRM1 DRILL REAM P Backream every other stand. Pumping 850 gpm w/ 3100 psi. Rotate 160 rpm w/ 13-15k ft Ib for ue. Pulled 50k over. 16:30 16:45 0.25 7,233 7,708 INTRM1 DRILL TRIP P Stopped pulling pipe and tripped back to 7708'. ~~m _.-. ~ _ _m...- ~ ~<~~~~ 1 ~~ ~u .~ C~ Time Logs - - -- _- . _ Date From_ To Dur S Depth E. Depth Phase Code Subcode T COM ___ 03/13/2007 16:45 17:45 1.00 7,708 7,708 INTRM1 DRILL CIRC P Circulate bottom's up. Pumping 850 gpm w/ 3100 psi. Rotate 160 rpm w/ 13k ft Ib torque. Hole unloaded a good bit of cuttin s. 17:45 20:45 3.00 7,708 6,297 INTRM1 DRILL TRIP P Backream every stand. Pumping 850 gpm w/ 3100- 2600 psi. Rotate 150 rpm w/ 10-23k ft Ib torque. PU wt 160k, SO wt 100k, Rot wt 130k. While backreaming, hole was tight and for ued u to 23k ft Ibs 6297'. 20:45 22:15 1.50 6,297 6,377 INTRM1 DRILL OTHR T Pumping 850 gpm w/ 2600 psi. Trying to rotate pipe w/ 23k ft Ib torque. Worked pipe free going down. Slacked off to 6377'. 22:15 00:00 1.75 6,297 6,231 INTRM1 DRILL REAM P Backream every stand. Pumping 850 gpm w/2600 psi. Rotate 150 rpm w/ 10-18k ft Ib torque. Pulling slow while circulatin a bottom's u . 03/14/2007 00:00 06:00 6.00 6,231 4,284 INTRM1 DRILL REAM P Backream every stand. Pumping 850 gpm w/2500 psi. Rotate 150 rpm w/ 10-15k ft Ib torque. Pulling slow as hole conditions allowed 10-45'/min . 06:00 09:45 3.75 4,284 3,524 INTRM1 DRILL REAM P Backream every stand. Pumping 850 gpm w/2500- 2300 psi. Rotate 150 rpm w/ 10-20k ft Ib torque. Pulling slow as hole conditions allowed (10-45'/min). Note: Torque dropped off from 10-20k ft Ibs to 8-10k ft Ibs after the bit was pulled up into the casing shoe 3551'. 09:45 11:30 1.75 3,524 3,524 INTRM1 DRILL CIRC P Circulate and condition mud @ the 13-3/8" casing shoe. Pump a 40 bbl sweep (9.3 ppg, 300 vis) Pump 4 bottom's up. Pumping 850 gpm w/ 2300 psi. Rotate 150 rpm w/ 7-8k ft Ibs of torque. Slight increase in cuttin s. 11:30 11:45 0.25 3,524 3,524 INTRM1 DRILL OWFF P Monitor well. Static. 11:45 12:00 0.25 3,524 3,524 INTRM1 DRILL CIRC P Pump a dry job and blow down the top drive. 12:00 13:00 1.00 3,524 570 INTRM1 DRILL TRIP P Pull out of the hole on elevators. Hole took ro er dis lacement. 13:00 13:45 0.75 570 109 INTRM1 DRILL TRIP P Stand back 4 stands of HWDP w/ jars, stand back a stand of flex collars. 13:45 14:00 0.25. 109 109 INTRM1 DRILL SFTY P PJSM on removing sources f/MWD. 14:00 14:30 0.50 109 109 INTRM1 DRILL OTHR P Remove sources from Sperry Sun MWD tools. 14:30 15:00 0.50 109 60 INTRM1 DRILL PULD P Break and lay down float sub and a flex drill collar. Clean and inspect MWD tools. Note: Some damage found on sleeve for CTN drill collar. ® ~ ~ .~ ~~~ E~~~a~ ~ ~ a° tea? Time L©gs __ - --._-- - __ _ __ ~ Date From To Dur S De th E._Depth Ph_a_se Code___ Subcode T COM__ ~ 03/14/2007 15:00 15:45 0.75 60 60 INTRM1 DRILL OTHR P Download Sperry Sun MWD. 15:45 16:45 1.00 60 0 INTRM1 DRILL PULD P Lay down BHA #3. Break off bit. 16:45 17:30 0.75 0 0 INTRM1 DRILL PULD P Clear and clean rig floor. Lay down BHA #3 (subs and bit). PU BHA #4 subs to floor and hole o ener. 17:30 18:00 0.50 0 110 INTRM1 DRILL PULD P Make up BHA #4: 12-1/4" hole opener, bit sub, a flex drill collar, stabilizer, two flex drill collars and crossover. 18:00 18:30 0.50 110 475 INTRM1 DRILL TRIP P Continue to makeup BHA #4. 18:30 20:00 1.50 475 475 INTRM1 RIGMN SVRG P Slip and cut dril-ing line. Cut 148'. Monitor well on tri tank. 20:00 21:30 1.50 475 475 INTRM1 RIGMN SVRG P Service top drive, crown and drawworks. 21:30 22:30 1.00 475 2,380 INTRM1 DRILL TRIP P Trip in hole w/ BHA #4. Filling pipe every 20 stands. Monitor well on trip tank. Record PU and SO wt's. 22:30 23:00 0.50 2,380 2,380 INTRM1 DRILL CIRC P Fill pipe w/ 20 bbls, then stage pumps up to 650 gpm w/ 600 psi, 800 gpm w/ 970 si. Blow down to drive. 23:00 23:45 0.75 2,380 3,530 INTRM1 DRILL TRIP P Continue to trip in the hole to the 13-3/8" casing shoe. Record PU and SO wt's. 23:45 00:00 0.25 3,530 3,530 INTRM1 DRILL CIRC P Fill pipe, then increase pump rate to 850 gpm w/ 1260 psi. PU wt 130k, SO wt 108k. 03/15/2007 00:00 00:45 0.75 3,530 4,576 INTRM1 DRILL TRIP P Continue to trip in the hole w/ BHA #4. Record PU and SO wt's every 5 stands. 00:45 01:00 0.25 4,576 4,576 INTRM1 DRILL CIRC P Fill pipe, then increase pump rate to 434 gpm w/ 450 psi. PU wt 136k, SO wt 100k. 01:00 01:45 0.75 4,576 5,527 INTRM1 DRILL TRIP P Continue to trip in the hole w/ BHA #4, RIH 60'/min as hole would allow. Record PU and SO wt's every 5 stands. PU wt 150k, SO wt 105k. 01:45 02:00 0.25 5,527 5,527 INTRM1 DRILL CIRC P Fill pipe, then increase pump rate to 434 m w/ 550 si. 02:00 02:30 0.50 5,527 6,479 INTRM1 DRILL TRIP P Continue to trip in the hole w/ BHA #4, RIH 60'/min as hole would allow. Record PU and SO wt's every 5 stands. Fill pipe ,pump 437 gpm w/ 600 si. PU wt 160k, SO wt 105k. 02:30 03:15 0.75 6,479 7,430 INTRM1 DRILL TRIP P Continue to trip in the hole w/ BHA #4, RIH 60'/min as hole would allow. Record PU and SO wt's every 5 stands. Fill pipe ,pump 434 gpm w/ 660 si. PU wt 170k, SO wt 105k. 03:15 04:00 0.75 7,430 8,381 INTRM1 DRILL TRIP P Continue to trip in the hole w/ BHA #4, RIH 60'/min as hole would allow. Record PU and SO wt's every 5 stands. Fill pipe, pump 431 gpm w/ 740 si. PU wt 180k, SO wt 108k. f _ ~ ~~~~ ,~ ~f ~a ~ ~ ~ Time Logs I Date From To Dur S. D~th E. D_epth_.Phase___Oode Subcod_e_ T__ COM 03/15/2007 04:00 04:45 0.75 8,381 9,150 INTRMI DRILL TRIP P Continue to trip in the hole w/ BHA #4, RIH 60'/min as hole would allow. Record PU and SO wt's every 5 stands. Fill pipe, pump 431 gpm w/ 790 si. 04:45 06:00 1.25 9,150 9,150 INTRM1 DRILL CIRC P Fill pipe, then increase pump rate to 900 gpm w/ 2440 psi. Rotate 130 rpm w/ 11-12k ft Ibs torque. After pumping 200 bbls, slow pumps to 475 gpm and pump 48 bbls of 9.2 ppg, 250 vis sweep. Then bring pumps back up to 900 gpm while reciprocating 60'. Max as observed was 511 units on BU. 06:00 06:45 0.75 9,150 9,150 INTRM1 DRILL CIRC P Continue pumping 900 gpm w/ 2440 psi while reciprocating 60'. Rotate 130 rpm w/ 14k ft Ib. Slight to no increase in cuttin son BU. 06:45 08:30 1.75 9,150 9,041 INTRM1 DRILL CIRC P Continue pumping 900 gpm w/ 240 psi while reaming out slow. Rotate 130 mw/14kftlb. 08:30 09:00 0.50 9,041 9,041 1NTRM1 DRILL OWFF P Monitor well. Static. Pump dry job and blow down to drive. 09:00 13:00 4.00 9,041 476 INTRM1 DRILL TRIP P POOH on elevators. Hole took proper displacement. Record PU and SO weight's every 5 stands in open hole and eve 10 stands in casin . 13:00 14:30 1.50 476 0 INTRM1 DRILL PULD P Work BHA #4. Lay down crossover, flex drill collars, stabilizer, bit sub and hole o ener. 14:30 15:00 0.50 0 0 INTRM1 DRILL OTHR P Clean and clear rig floor. 15:00 15:30 0.50 0 0 INTRM1 DRILL OTHR P Pult Vetcco/Gray 13-3/8" x 12-3/16" x 59-1/2" Ion wear bushin . 15:30 17:15 1.75 0 0 INTRM1 CASIN( RURD P Rig up to run 9-5/8", 40 ppf, L-80, BTC-mod casin . 17:15 17:30 0.25 0 0 iNTRM1 CASINO SFTY P Pre job safety meeting on running intermediate casin . 17:30 18:00 0.50 0 120 INTRMI CASIN( RNCS P Run 9-5/8", 40 ppf, L-80, BTC-mod casing per running order. Baker lock float a ui ment. 18:00 23:15 5.25 120 3,500 INTRM1 CASIN RNCS P Crew change. Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every 10 joints while in casin . 23:15 00:00 0.75 3,500 3,500 INTRM1 CASINO CIRC P Circulate at the 13-3/8" casing shoe. Stage pumps up f/ 5 bpm w/ 300 psi, 6 bpm w/ 380 psi, 7 bpm w/ 460 psi, 8 bpm w/ 550 psi, 9 bpm w/ 650 psi, 10 bpm w/ 750 psi. PU wt 175k, SO wt 132k. 03/16/2007 00:00 00:45 0.75 3,500 3,500 INTRM1 CASINO CIRC P Continue to circulate at the 13-3/8" casing shoe. Pumping 10 bpm w/ 750 psi. PU wt 175k, SO wt 132k. Recip i e 20' stroke. Circ total of 472 bbls. e ~ ~ ~ __~ . ~ f~a~a 1 ~ c~~~ ~ Time Logs -- __ _ _ Date From To Dur Depth S Depth E. Phase Code Subcode T ~ COM ! 03/16/2007 00:45 03:45 3.00 _ _ 3,500 _ _ 6,353 INTRM1 CASINC RNCS P Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every 10 'oints in o en hole. 03:45 05:15 1.50 6,353 6,353 INTRM1 CASINC CIRC P Circulate. Stage pumps up f/ 3bpm w/ 260 psi, then 4 bpm w/ 320 psi, 5 bpm w/ 390 psi, 6 bpm w/ 460 psi, 7 bpm w/ 540 psi. Circ total of 450 bbls. PU wt 215k, SO wt 115k. Recip pipe 20' stroke. Note: Had a MOBM spill of 10 gals at the tank farm. Spill cleanup was performed while circulating. 3 gals outside of secondary containment, 7 gals inside of berm (secondary containment . 05:15 06:00 0.75 6,353 7,124 INTRMI CASIN( RNCS P Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every 10 ~oints in o en hole. 06:00 08:30 2.50 7,124 9,150 INTRM1 CASINC RNCS P Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every 10 'oints in o en hole. 08:30 10:00 1.50 9,150 9,150 INTRM1 CEME CIRC P Circ 10:00 10:30 0.50 9,150 9,150 INTRM1 CEME PULD P UD Fill up tool & Rig up Cement head 10:30 13:00 2.50 9,150 9,150 INTRM1 CEME CIRC P Circ, Held PJSM with all parties 13:00 14:45 1.75 9,150 9,150 INTRM1 CEME CIRC P Dowell pump 10 bbls CW100 (8.34 ppg), pressure test lines to 2500 psi, pump an additiona140 bbls CW100 (Total of 50 bbls), follow w/ 75.2 bbls mud push (11 ppg), drop bottom plug, follow w/ 296.5 bbls DeepCrete (736 sx) (Yield 2.26 cuft/sx) (7.485 gal/sx water) mixed @ 12.5 ppg, pumped @ 6 bpm, drop top plug, pump 10 bbls water, turn over to rig f/displacement. Reci rotated i e f/ 30' to 5'. ~. ~ s .®s~ ~ ~ ~~. ~J Time Logs Date From 7o Dur S. Depth - -- E. Depth Phase Code - Subcode - T ---- - -i -- - - - COM 03/16/2007 14:45 16:45 _ _ 2.00 9,150 9,150 INTRM1 __ CEME~ DISP P Rig displace cement w/ 8.4 ppg MOBM. Pumping at rate of 7 bpm at initial 360 psi with a steady 29% to 30% flow indication on the flow indicator. Had good cement lift pressure for first 5850 strokes (588.5 bbls) w/ 30% flow indication (30% is full returns), Pressure increased f/ 360 psi to 1130 psi, Then from 5850 strokes to 6600 strokes observed flow indicator start decreasing f/ 30% to 19% while holding 7 bpm, Pressure held steady with no more increase @ 1120 psi, Last 10 bbls pumped at 3 bpm @ 930 psi, Did not bump plug after pumping total of 692.0 bbls (Max calculated bbls of 690.4 bbls = Displacemenrt to float collar + 1/2 the shoe track) .Bleed off pressure, check floats- held OK. CIP @ 1630 hrs 3/16/2007. Reciprocated pipe 20' to 5' when finally ran out of down wt. stopped pipe after 37.6 bbls turned around shoe. 16:45 18:00 1.25 9,150 9,150 INTRMI CASIN( NUND P Drain stack, Nipple down stack and vacuum out fluid in landing joint. Blow down cement line. 18:00 19:45 1.75 9,150 0 INTRM1 CASIN( OTHR P Set casing on Vetco/Gray emergency slips. Weight indicator 170K. Pipe with 68k tension. Remove Dowell cement head and GBR elevators. Hold landing joint w/ tugger while cutting w/ E.H. Wach's Split Frame O.D. Machine (casing cutter). Lay down cutoff measured to be 27.60'. 19:45 21:15 1.50 0 0 INTRM1 WELCT NUND P Install Vetco/Gray packoff. Lower BOP stack back into place, tighten bolts. Laying down casing running tools f/ rig floor. 21:15 21:30 0.25 0 0 INTRM1 WELCT OTHR P Energize packoff seal. Test packoff seal to 80% of 9-5/8" 40ppf L-80 casing collapse. Test to 2500 psi f/ 10 min. Good test. 21:30 23:45 2.25 0 0 INTRM1 WELCT NUND P NU BOPE while rigging up to perform LOT on 13-3/8" x 9-5/8" annulus. Lay down long casing running bales. PU shorter drilling bales for top drive and 5" elevators. Vetco/Gray wear bushing to floor. Clean and clear ri floor. 23:45 00:00 0.25 0 0 INTRM1 DRILL LOT P Performing LOT on 13-3/8" x 9-5/8" annulus. 13-3/8" shoe @ 3551'MD (2190' TVD), mud wt 9.2 ppg, broke down w! applied pressure of 337 psi = 12.2 ppg EMW. Pumped a total of 15 bbls. ~ _ e~ ~ ~m.~ ~m ~ F~<~t;t~ ~~ ~~ ~~ E _____~ • i Time Logs Date _ From _____ To -- Dur - S. Depth E De th Phase _ Code__ Subc_ode - T --- COM _____; -- - 03/17/2007 00:00 00:30 0.50 0 0 INTRM1 DRILL LOT P Performing LOT on 13-3/8" x 9-5/8" annulus. 13-3/8" shoe @ 3551'MD (2190' TVD), mud wt 9.2 ppg, broke down w/ applied pressure of 337 psi = 12.2 ppg EMW. Pumped a total of 15 bbls. 00:30 01:00 0.50 0 0 INTRM1 DRILL OTHR P Install Vetco/Gray 13-3/8" od x 9" ID x 38" long wear bushing. Lay down test 'oint. 01:00 01:45 0.75 0 0 INTRM1 DRILL OTHR P Bring (24) 5"super sliders to floor. Pick up bit sub to floor. Hang 2" cement hose u .Clean and icku cellar area. 01:45 02:30 0.75 0 0 INTRM1 DRILL OTHR P Change out joint of 5" HWDP. Rack 4 stands of 5" HWDP on driller's side of derrick. Install mousehole in rotary table. 02:30 03:00 0.50 0 0 INTRM1 DRILL PULD P PU/MU stand back 3 stands of 5" HWDP on driller's side of derrick. Rabbit i e w/ 2-3/8" rabbit. 03:00 04:30 1.50 0 0 INTRM1 DRILL PULD P Lay down 10 stands of 5" drill pipe from off driller's side of derrick. 04:30 05:30 1.00 0 0 INTRM1 DRILL PULD P Remove mousehole from rotary table. PU LoTads to the rig floor. Remove skate extension f/ handling pipe at the ri floor. 05:30 06:00 0.50 0 185 INTRM1 DRILL PULD P MU BHA#5. 06:00 08:30 2.50 185 4,561 INTRM1 DRILL TRIP P Trip in hole w/ 5" slick drill pipe to 4561'. 08:30 13:45 5.25 4,561 7,724 INTRM1 DRILL TRIP P Continue trip in the hole w/ BHA #5. Install Lotads on top of first single of stands # 47-78. 13:45 16:00 2.25 7,724 8,515 INTRM1 DRILL TRIP P Continue trip in the hole w/ BHA #5. Install Lotads on top of first single of stands # 79-86.Install super sliders on each 't in the middle 16:00 16:30 0.50 8,515 9,064 INTRM1 DRILL TRIP P Continue trip in the hole w/ BHA #5. Install Lotads on top of first single of stands # 87-92. 16:30 18:00 1.50 9,064 9,064 INTRM1 DRILL CIRC P Tag up on wiper rubbers @ 9064' (54.5' in on stand #92). Circulate, pumping 740 gpm w/ 3350 psi, 46% flow, rotate 50 rpm w/ 8k ft Ib torque. PU wt 195k, SO wt 105k. Blow down to drive. 18:00 18:15 0.25 9,064 9,009 INTRM1 DRILL TRIP P Pull a stand of 5" drill pipe. 18:15 20:00 1.75 9,009 9,009 INTRM1 RIGMN' SVRG P Change out saver sub on top drive. Note: Rig flushed 13-3/8" x 9-5/8" annulus w/ 220 bbls water pumping 2 bpm w/ 650 psi, then little Red freeze protected w/ 120 bbls diesel pumping 2 bpm w/ 550 psi. (1050 psi at the pump) Note: Tested 4" Floor safety valve and dart valve to 250 psi and 3000 psi while circulatin . _`" _ ~ _ ~ ~~t~~ 1'7 c~~ ~~ r L J J e Logs 1 Da ~ From To Dur S. De th E. De th Phase Code Subcode T COM - - --- 03/17/2007 20:00 20:45 0.75 9,009 9,009 INTRM1 DRILL DHEQ P Pickup 4" subs and lifters from beaver slide while ri u to test 9-5/8" casin . 20:45 21:15 0.50 9,009 9,009 INTRM1 DRILL TRIP P Pull a stand of 5"drill pipe. Change out elevators to 4", rig up skate extension @ the rig floor. PU a single 't of 4". 21:15 22:15 1.00 9,009 9,009 INTRMI CASIN OTHR P Fill stack with water. Rig up hos, guage and fittings to test 9-5/8" casin . 22:15 23:30 1.25 9,009 9,009 INTRMI CASIN DHEQ P Test 9-5/8" 40 ppf L-80 BTC casing. Chart test. Pumping down annulus and drillpipe @ 6 spm. Also testing the upper rams (variable 3-1l2" x 6" with 4" drill pipe). Test rams low to 250 psi f/ 5 min. Continue to test casing to 3000 psi. Hold test f/ 30 min. Chart test. 23:30 00:00 0.50 9,009 9,009 INTRM1 WELCT BOPE P Test annular to 250 psi and 3000 psi with a joint of 4"drill pipe. Chart test. Test to 250 psi low f/ 5 min. then 3000 si hi h f/ 5 min. OK. 03/18/2007 00:00 00:30 0.50 9,009 9,009 INTRM1 WELCT BOPE P Finish testing annular to 250 psi and 3000 psi with a joint of 4" drill pipe. Chart test. Test to 250 psi low f/ 5 min. then 3000 si hi h f/ 5 min. OK. 00:30 01:30 1.00 9,009 8,911 INTRMI WELC OTHR P Rig down lines after testing. Blow down kill line. Lay down 4" drill pipe to the pipe shed. Change elevators to 5". MU to drive connection. 01:30 02:00 0.50 8,911 8,911 INTRM1 DRILL CIRC P Pumped a 25 bbl dry job. Pumped @ 6bpm w/ 530 psi. PU wt 195k, SO wt 110k, Rot wt 155k. Blow down top drive. 02:00 06:00 4.00 8,911 5,550 INTRM1 DRILL TRIP P Pull out of hole w/ BHA #5. Inspecting and moving super sliders to fit in fingers in derrick board. Inspecting LoTads, SLM, record PU and slack off weights. Pick up Centurian circulating valve to rig floor. PU a short cut off joint of 4-1/2" 12.6ppf L-80 IBT tubing to be run with the whipstock to the rig floor. 06:00 07:30 1.50 5,550 4,561 INTRM1 DRILL TRIP P Pull out of hole w/ BHA #5. Inspecting and moving super sliders to fit in fingers in derrick board. Inspecting LoTads, SLM, record PU and slack off wei hts. 07:30 09:15 1.75 4,561 185 INTRM1 DRILL TRIP P Pull out of hole w/ BHA #5. SLM, record PU and slack off wei hts. 09:15 09:30 0.25 185 0 INTRMI DRILL PULD P Stand back 2 stands of 5" HWDP. Lay down bit sub, break bit. 09:30 10:00 0.50 0 0 INTRM1 DRILL OTHR P Clear and clean rig floor. 10:00 10:15 0.25 0 0 INTRM1 CASIN SFTY P Pre job safety meeting on running the permenant whipstock assembly to drill "B" lateral. ~'~a€~~ ~~~u ra3 ~~ • Time Logs Date From To Dur S. De th E. De th Phase Code Subcode T COM 03/18/2007 10:15 10:45 0.50 0 0 PROD2 CASIN RURD P Rig up GBR tongs to run the cut off jt and 9 jts of 4-1/2" 12.6 ppf L-80 IBT-m tubin below the whi stock. 10:45 11:00 0.25 0 292 PROD2 CASIN( RNCS P Run 9 joints+ cut offjoint of 4-1/2" 12.6 f L-80 IBT-m tubin . 11:00 11:15 0.25 292 292 PROD2 CASIN( RURD P Rig down GBR tongs and tools. 11:15 12:00 0.75 292 314 PROD2 CASIN RUNL P Make up the crossover, bottom trip anchor, and the 9-5/8" Gen 2 Whipstock slide. Note: This assembly will be left in the hole setting on top of wiper rubbers which were to ed 9064'. 12:00 13:15 1.25 314 385 PROD2 FISH PULD P PU/MU 8-1/2" window mill, bit sub, upper string mill (8-1/2"), 1jt 5" HWDP, float sub, then Sperry Sun MWD. 13:15 13:45 0.50 385 385 PROD2 FISH OTHR P Upload Sperry Sun MWD. 13:45 14:15 0.50 385 455 PROD2 FISH PULD P Continue to PU/MU BHA #6: Bumper sub, 2 ~oints 5" HWDP. 14:15 14:30 0.25 455 455 PROD2 FISH OTHR P Shallow test MWD, OK. Pumping 600 m w/ 900 si. Blow down to drive. 14:30 18:00 3.50 455 5,143 PROD2 FISH TRIP P Trip in hole w/ permenant whipstock assembly f/ "B" lateral. RIH w/ 5" dp to 5143'. Record PU and So wt's. 18:00 18:45 0.75 5,143 5,143 PROD2 RIGMN SVRG P Service top drive. Closed manual valves on BOP stack. 18:45 20:30 1.75 5,143 7,910 PROD2 FISH TRIP P Continue RIH w/ BHA #6. Running s eed 95'/min. 20:30 21:15 0.75 7,910 7,950 PROD2 FISH OTHR P Fill pipe. Increase pump rate to 650 gpm w/ 2950 psi. Mad pass f/ bottom of assembly @ 7910' to 7950'. Gamma f! 7550' to 7590'. Log @ 3'/min 180'/hr . 21:15 22:00 0.75 7,950 8,968 PROD2 FISH TRIP P Continue RIH w/ BHA #6. Running s eed 95'/min. 22:00 23:00 1.00 8,968 9,064 PROD2 FISH OTHR P Orient whipstock while working pipe fJ 8968' to 9055'. PU wt 190k, SO wt 115k. Pumping 550 gpm w/ 2170 psi. Oriented until 17L. Make a connection and slack off to tag top of wiper rubbers @ 9064' w/ bottom of assembly. Set down 15k to set anchor, set down 25k, PU to 10k overpull. Slack off 50k to shear mills free of whi stock. 23:00 23:15 0.25 8,750 8,750 PROD2 FISH OTHR P Pick up above whipstock top @ 8750', obtain parameters. Rotate @ 90 rpm w/ 8k ft Ibs torque. Rot wt 145k. PU wt 185k, SO wt 115k. 23:15 00:00 0.75 8,750 8,754 PROD2 FISH MILL P Milling on 9-5/8" 40 ppf L-80 BTC-m casing f/the window f/the "B" lateral. Rotating 90 rpm w/ 8-11 k ft Ib torque, running 2k weight on mills. Pumping 545 m w/ 2150 si. Time Logs Date From To_ Dur S Depth E. Depth Phase Code Subcode T COM_ 03/19/2007 00:00 03:00 3.00 8,754 8,767 PROD2 FISH MILL P Milling on 9-5/8" 40 ppf L-80 BTC-m casing f/ the window f/the "B" lateral. Rotating 100-110 rpm w/ 8-11 k ft Ib torque, running 3-6k weight on mills. Pumping 545 gpm w/ 2150 psi. Pumped a 40 bbls 10.4 ppg 185 vis swee while millin 8758'. 03:00 03:45 0.75 8,767 8,782 PROD2 FISH MILL P Milling on 9-5/8" 40 ppf L-80 BTC-m casing f/the window f/ the "B" lateral. Rotating 110 rpm w/ 8k ft Ib torque, running 5-6k weight on mills. Pumping 545 m w/ 2150 si. 03:45 04:15 0.50 8,782 8,782 PROD2 FISH MILL P Work mills through window, cleaning up window. TOW @ 8750' (3286' TVD), BOW 8767' 3289' ND 04:15 04:30 0.25 8,782 8,787 PROD2 FISH MILL P Milling 8-1/2" open hole. Rotating 90 rpm w/ 8-11 k ft Ib torque, running 2-5k weight on mills. Pumping 545 gpm w/ 2150 psi. Pumped a 40 bbls 10.4 ppg 185 vis swee while millin 8782'. 04:30 05:15 0.75 8,787 8,787 PROD2 FISH CIRC P Continue to circulate and work window w/ milling assembly while circulate sweep to surface. Pumping 545 gpm w/ 2150 si. 05:15 06:00 0.75 8,787 8,741 PROD2 FISH OTHR T POOH above window. Prepare to stand back stand # 90. While attempting to break off stand # 90, pumps were still running. Had a unplanned release of mineral oil base mud to rig floor (secondary containment) and windwalls around the rig floor, partially broke off stand # 90 f/ stand #89.. Estimated spill @ 3 bbls (126 gals). Rig time to clean up all OBM from the ri floor. 06:00 10:15 4.25 8,741 8,741 PROD2 FISH OTHR T Cleaning rig floor and windwalls from spilt. Circ hole while cleaning. Pum in 560 m w/ 2150 si. 10:15 10:45 0.50 8,741 8,741 PROD2 DRILL CIRC P Continue to circulate prior to LOT. 10:45 12:00 1.25 8,741 8,741 PROD2 DRILL LOT P Blow down top drvie. Rig up to perform LOT after drilling 20' of new hole below bottom of window f/ "B" lateral. LOT = 14 ppg. TOW @ 8750' (3286.33'), BOW @ 8767' (3288.87') Open hole to 8787' (3291.77' ND . 12:00 12:30 0.50 8,741 8,741 PROD2 DRILL LOT P Blow down kill line. Close manual valve on kill line. Rig down testing e ui ment. 12:30 12:45 0.25 8,741 8,741 PROD2 FISH TRIP P Monitor well, static. 12:45 13:15 0.50 8,741 8,741 PROD2 FISH CIRC P Pump 25 bbl dry job. Blow down top drive. Install stripper rubbers. Pumped d 'ob 6 b m w/ 550 si. 13:15 15:00 1.75 8,741 6,904 PROD2 FISH TRIP P POOH w/ BHA #6 (8-1/2" mills). Inspect and clean IoTads and super sliders ~~€~~ _-~; zaf ~t~ • Time Logs -- _--- --- -- --- ---_ __ _. --- __ __ __ _-- I i Date From. To Dur S De~t_h__E, Depth Phase Cpde__, Subcode_ T COM ___ 03/19/2007 15:00 18:00 3.00 6,904 1,523 PROD2 FISH TRIP P Continue to POOH w/ BHA #6. 18:00 19:00 1.00 1,523 141 PROD2 FISH TRIP P Continue to POOH w/ BHA #6. 19:00 19:45 0.75 141 71 PROD2 FISH PULD P Lay down 2 joints of 5" HWDP and bum er'ars. 19:45 20:15 0.50 71 71 PROD2 FISH OTHR P Download Sperry Sun MWD. 20:15 21:15 1.00 71 0 PROD2 FISH PULD P Finish laying down milling BHA. 21:15 22:00 0.75 0 0 PROD2 FISH PULD P Remove Baker mills from floor. Clear and clean ri floor. 22:00 22:30 0.50 0 0 PROD2 WELCT OTHR P Rig up, then pull Vetco/Gray wear bushing (13-3/8" OD x 9" ID x 38" Ion ). 22:30 23:30 1.00 0 0 PROD2 WELCT OTHR P Rig up then flush stack out with stack washing tool, after milling operations. Blow through choke and HCR lines. Perform weekly function test of Annular, upper pipe rams, kill HCR and choke HCR and blind rams, OK. 23:30 00:00 0.50 0 0 PROD2 WELC OTHR P Install Vetco/Gray wear bushing (13-3/8" OD x 9" ID x 38" long). Rig down runnin tools. 03/20/2007 00:00 01:00 1.00 0 0 PROD2 DRILL PULD P Pickup tools and equipment for BHA #7. 01:00 01:15 0.25 0 0 PROD2 DRILL SFTY P Pre job safety meeting on picking up BHA #7. 01:15 03:00 1.75 0 97 PROD2 DRILL PULD P PU/MU BHA #7. 03:00 03:30 0.50 97 97 PROD2 DRILL OTHR P Upload Sperry Sun MWD. 03:30 04:30 1.00 97 220 PROD2 DRILL PULD P PU/MU BHA #7. 04:30 05:00 0.50 220 220 PROD2 DRILL OTHR P Shallow test MWD. Pump 280 gpm w/ 1550 si. Blow down lines. 05:00 05:45 0.75 220 283 PROD2 DRILL PULD P Continue PU/MU BHA#7. 05:45 06:15 0.50 283 283 PROD2 RIGMN SVRG P Service traveling equipment. 06:15 09:00 2.75 283 283 PROD2 RIGMN RGRP T Repair leak on hydraulic cylinder on to drive. Service travelin a ui ment. 09:00 11:45 2.75 283 1,837 PROD2 DRILL PULD P PU/MU 48 jts of 4"drill pipe from pipe shed, rabbit to 2-3/8", PU/MU crossover, agitator, shock sub and crossover, then fill pipe, test agitator @ 1837'. Pumping 330 gpm w/ 2780 si. 11:45 13:00 1.25 1,837 1,837 PROD2 DRILL PULD NP Lay down agitator, PU another agitator, test same pumping 330 gpm w! 2700 psi. Sperry Sun MWD tested ok 1837'. ~ _____~.......P`~~ 2~c~f ~Q Time Logs - Date From _ To _ Dur S De th EDEpth Phase Code Su6code - T COM_ _ 03/20/2007 13:00 15:30 2.50 1,837 3,588 PROD2 DRILL PULD P PU/MU 57 jts of 4"drill pipe from pipe shed, rabbit to 2-3/8". Fill pipe. Pumping 315 gpm w/ 2990 psi. Rig down pumping equipment and blow down. Sperry Sun MWD tested ok @ 3584'. 15:30 16:30 1.00 3,588 4,544 PROD2 DRILL PULD P PU/MU 30 jts of 4"drill pipe from pipe shed, rabbit to 2-3/8". MU crossover to 5"drill pipe, MU Centurian circulation valve. 16:30 18:00 1.50 4,544 5,495 PROD2 DRILL TRIP P Clean floor, install airslips. Continue to RIH f/derrick w/ 5" drill pipe filling every 20 stands. Sperry Sun MWD tested ok 5486'. 18:00 20:00 2.00 5,495 8,550 PROD2 DRILL TRIP P Continue trip in the hole recording PU and SO wt's every 10 stands. Fill pipe @ 7382'. Sperry Sun MWD tested ok. RIH to 8550'. 20:00 20:15 0.25 8,550 8,550 PROD2 DRILL OTHR P Blow down top drive. 20:15 20:30 0.25 8,550 8,550 PROD2 RIGMN SFTY P Pre job safety meeting on cutting drillin line. 20:30 22:15 1.75 8,550 8,550 PROD2 RIGMN SVRG P Slip and cut 104' of 1-3/8"drilling line. Install new brass in deadman tie down. Inspect brakes, reset crown o matic. 22:15 23:15 1.00 8,550 8,749 PROD2 DRILL TRIP P Make top drive connection and orient to 14 left. PU wt 160k, SO wt 115k. RIH to 8653'. Then top drive connection, RIH to top of the window pumping 316 gpm w/ 3150 psi. Sperry sun u dates takin 6-7 min. 23:15 23:45 0.50 8,749 8,777 PROD2 DRILL TRIP T Make top drive connection, RIH w/o pumping to 8777', then try to pump up survey's, too much noise. Swapped pumps, isolated pumps, checked pulsation dampner pressures. Nothing im roved detection. 23:45 00:00 0.25 8,777 8,600 PROD2 DRILL TRIP T POOH to continue to trouble shoot S er Sun MWD detection roblems. 03/21/2007 00:00 00:15 0.25 8,600 8,600 PROD2 DRILL CIRC T Establish circulation, trouble shoot Sperry Sun MWD detection problems. Detection was ood. 00:15 01:00 0.75 8,600 8,747 PROD2 DRILL TRIP T Run back in the hole pumping. 01:00 01:15 0.25 8,747 8,787 PROD2 DRILL TRIP P RIH w/o pumps. Establish circulation, 01:15 06:00 4.75 8,787 9,044 PROD2 DRILL DDRL P Directional drill "B" lateral. Concretion drilled @ 8794' to 8797' (3'), 8800' to 8803' (3'), 8878' to 8890' 12' , 8982' to 8984' (2' . 06:00 09:00 3.00 9,044 9,200 PROD2 DRILL DDRL P Directional drill "B" lateral. Concretion drilled @ 9053' to 9058' 5',9169'to9172'(3'. ~® ~ ~ ~_.-~~ _ ®e ~~~~ ................._. ._._...._._ P~~ 2~ of 4fl 04-May-07 AOGCC Librarian 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 Re: Distribution of Survey Data for Well 1J-160 Dear Dear Sir/Madam: Enclosed is one disk with the *.PTT and *.PDF files. Tie-on Survey: 41.29' MD Window /Kickoff Survey ' MD (if applicable) Projected Survey: 10,271.00' MD PLEASE ACKNOWLEDGE RECEIPT BY SENDING AN EMAIL TO Timothy.Allen@HALLIBURTON.COM OR SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Timothy Allen 6900 Arctic Blvd. Anchorage, AK 99518 „~ ~ ~/ _ ~ ~ ~ Date ~ Signed Please call me at 273-3534 if you have any questions or concerns. Regards, Timothy Allen Survey Manager Attachment(s) ~.o~- t1~si Re: 1J-160 (PTD 2070160) pre-production with intentional TxIA c... • Subject: Re: 1J-160 (PTD 2070160) pre-production with intentional T~IA-communication. From: Thomas Maunder <tom_malmder@admin.state.ak.us> Date: Thu, 19 Apr 2007 13:39:14 -0800 'I'o: '~~SK Prohleir~ 1~"ell Su~~ '~u i (i 17iricoi~ocophillips.con~-> ~~j`~ _~ C'C: Jaule~ hc,~~t~ ~ jin~_re~~%u;admin.~tate.ak.us Marie, It is acceptable to place the well in production with the conditions as you describe. Successfully conducting the pressure tests detailed proves the ability of the well to contain pressure. In the production mode, the lowest pressure in the well will be in the tubing at the surface. Annulus pressures should should all be less than the listed test pressures. As noted, when the well is configured for injection an MIT IA will be conducted that will demonstrate the integrity of the casing, tubing and packer. Call or message with any questions. Tom Maunder, PE AOGCC NSK Problem Well Supv wrote, On 4/18/2007 12:49 PM: Tom, New West Sak injector 1 J-160 (PTD 2070160) is being prep'd fora 30 day pre-production period to start later this week. CPAI would like to pre-produce 1 J-160 with the sliding sleeve above the packer open (intentional TxIA comm) and to delay the tbg pressure test until after the pre-production period has ended. This plan is identical to the previously approved pre-production plan for 1J-118. The completion has a packer at 8350' RKB with a sliding sleeve (CMD) at 8290' RKB and a GLM at 2280' MD above the packer. To lift the well as deep as possible, a gaslift valve will be installed in the GLM and the sliding sleeve will be left open as the bottom lifting point. With the sliding sleeve open, there will be TxIA communication. The annulus (IA) will not be isolated from produced fluids per 20 AAC 25.200 (d) while on pre-production; however, gas lift will be injected down the IA, minimizing or preventing produced fluids from entering the IA. The packer, production casing, and surface casing were all tested by the rig and have demonstrated sufficient integrity to prevent an uncontrolled release. The casings were each tested to 3000 psi for 30 mins prior to drilling ahead after cementing operations. The ZXP packer was tested to 2500 psi for 30 mins on drill pipe just prior to running the completion. The tbg was not tested on the rig as the completion was ran with the sleeve open for the pre-production. Coiled tbg is required to shift the sleeve due to wellbore deviation. The tbg will be tested when the sleeve is closed at the end of the pre-production period. Please confirm it is acceptable to proceed as planned. Thanks, Marie McConnell Problem Well Supervisor (907) 659-7224 n1617 a~conocophillips.com 1 of 1 4/19/2007 1:39 PM i -- M ~o~_d r ~ ~--- i~C:iANICAL INTEGRITY REPORT ~ ~-~ ?liD a-._v ~ ~.cc~~ av0~ OPER ~ rIEI.D C.~Q~ ~ ~b `~ t -. _ G ~. ~ ~ ~r ..:.. h:.LL NtJMF tR i ..~ ~~~ ' ~~.~~--a n ~ LL DAT ~_ TD : 2~.. 'I'V•D ; . BTD : ?~ -~ ~~ _ Corsi^g : ~'~x. Shoe: ~~~ ~~~}~ TV'D ; DV : ~?~ ~1~ T~`i __.~er : Shoe : '~ '?•`TS ; =CP : '•~ ~'iD _~b»v • Packer ".D TVD; Set et ((~~ r i r j L~ w~+~tC~~ ~5~~ o1e S«e and Perfs to La ~,,,~~ ~ 4'r3~,1 V`~= C'r'.r~?~ =C~~ INTEGRITY - P 4..RT # I ~n.:ulus Press Test: _~ Comments: 15 Qin :;0 min _'~CHPNIC~s, INTEGRITY' - PART #Z ~Ca~.~S = a~S ~~~5 . Cement Volumes: Amt. Liner ~~ Csg ~~~5~ DV QJ~, C,mt -JOl to cover oer=; ~\ ~~\s S ~tc~~en~- ~ CC,e~C~ Law W~SC~ ~ ~ 3c~~~ ~ S _ :eoretical TOC ~ 3~~oY~S =y`~ C~ ~o~~~~ ~~ ~ l~~v~rS Cement Bond Log (Yes or No) y~; In AOGCC File ~~~ CBL Evaluation, gone above perfs ~, rtcZs SOC~~tx~c 0. ~~~, ~`~\~-~~OC~ ~~'9p\,~5 4~~~~1Q ~1~D4-rte ~~-b® - 1--~ ~l'~~v,~ Production I.og: Type : Evaluati on CONCLJSIONS: ?art #1: ,.~ Part T 2 : ~ ~ t `~ •t~~` ~CS~'S`L ~Ii~~~~ Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Be1:h _. APB 0 6 2007 t)il ~nrls. ~r3rrrilrlissiorl ~Q~ ~ l `~ Well/ Job # Log Description C.~ N0.4205 Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Date BL Color CD 04/05/07 2M-12 11632681 PRODUCTION PROFILE 03/29/07 1 3S-22 (REDO) N/A INJECTION PROFILE 03/16/07 1 1 H=11 11665413 PRODUCTION PROFILE 03/31107 1 1H-15 11686723 GLS 03/21/07 1 1B-02 11665409 INJECTION PROFILE 03124/07 1 2L-305 11665416 SBHP SURVEY 04102/07 1 2L-329 11665414 SBHP SURVEY 04/01107 1 26-T2 11628989 INJECTION PROFILE 03/21107 1 2W-08 11632687 SHUT IN BHP 04104107 1 2A-09 11686726 MEM PROD PROFILE 03124107 1 1H-04 11632682 INJECTION PROFILE 03/30/07 1 2P-449 11688724 PRODUCTION PROFILE 03/22107 1 1H-02' 11638845 GLS 03/21/07 1 2W-05 11632686 SHUT IN BHP 04/03107 1 1A-26 - 11686725 MEM PROD PROFILE 03/23107 1 2N-331• NIA INJECTION PROFILE 03/23/07 1 3A-06 - 11665407 INJECTION PROFILE 03/22/07 1 1J-160- 11665412 USIT 03129/07 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. (~ FW: 1 J-160 top Ugnu +USIT log • ~~~~ Subject: FW: 1J-160 top Ugnu +USIT log From. Gr~,ener,.Mike R. <Mike:R.Greener@~onocophillips.com> ~~~ _~ ~ ~' Date: Fri, 30 Mar 2007 10:15:08 -0800 To: I~um ~1~uinder ~~-t~~n~ maui~der~~r a~lnun.state.ak.us = 'I._ipped file. «USIT_GPIT_1J-160_29-MAR-2007.zip» -----Original Message----- From: Greener, Mike R. Sent: Friday, March 30, 2007 10:04 AM To: Thomas Maunder' Cc: Thomas, Randy L Subject: 1J-160 top Ugnu +USIT log Here is tlae US:f.1-, :Ion frUm tl~e 1J-1.60, Also, below is our geos call on the top Of"the UC~NU C and the tip of the hydrocarbon. show in the UGNtJ C. A11 tops are ~~easured. depths. Cal.]. m.c~ or serld an email. if fl~ere are any questions. -----Original Message----- From: Buchanan, Andrew Sent: Wednesday, March 14, 2007 10:04 AM To: Greener, Mike R.; Hartwig, Dennis D Subject: 1J-160 top Ugnu The top of the Ugnu C is at 5,973' MD. The top if oil in the Ugnu C is at 6215' (a questionable show at best). Let me know if there is anything else that you need. Andrew Buchanan Operations Geologist Heavy Oil Development ConocoPhillips Alaska Inc. Office: (907) 265-6788 Cell: (907) 250-6545 Fax: (907) 263-4486 Content-Description: USIT GPIT IJ-160_29-MAR-2007.zip 'USIT_GPIT_1J-160_29-MAR-2007.zip Content-Type: application/x-zip-compressed Content-Encoding: base64 1 of 1 4/19/2007 1:21PM 1J-160 Intermediate Cement Job Recap • Subject: IJ-160 Intermediate Cement Job Recap From: "Hartwig, Dennis D" <Dennis.D.Hartwig@conocophillips.com> _ _ Date: Mc~n, 19 Mar 200710:53:23 -0800 ~~~~-Q t `.~ To: `T`homas Maunder 'tom maunclcri~i%adrnin.statc.ak.us CC: "Thomas, Ra~~dv L" ~=fZandv.L.."Th~nias(~r cunocophilli}~s.com~~=. "Greener, Mike. R.'~ '-I~~Iike.R.Greener<c'conocophillihs.com% Tom, This weekend, during cementing operations for the 1J-160, 9-5/8" casing, we experienced a few abnormalities. I have attached the drilling daily report for your review as well as the short summary below. At this time we have no confirmation (USIT log) that our cement job does not meet required regulations but we felt it prudent to provide a short recap. The 9 5/8" was successfully set to a depth of 9150'md with TD at 10271'md for the hole section. The 9 5/8" was run shorter due to a wet leg in the A2 sand. A 55 bbl, 30ppb gel pill was spotted from 9150 - 9527' on the previous bit run prior to the casing run. The cement job went according to plan with a few exceptions in blue; ~,hy ~~~~ bh~ 1. Had good cement lift pressure and returns for first 5850 strokes (588.5 bbls) full returns. 2. Returns decreased and lift pressure did not increase from 5850-6600 strokes. 3. The plug did not bump 6780 strokes. ~~.a ~~~~ 6~a- 5'~~ ~S =- ci,3v~ ~~`S Following cementing operations, a run was made to confirm the top of float collar for purposes of correct B-Sand whipstock setting depth. The plug was tagged 4' high or nearly on depth and most likely would have bumped had we continued pumping. The casing was successfully tested to 3000 psi for 30 minutes. Currently, we have set the B-Sand whipstock, milled the window and are in the process of performing an LOT in the B-Sand. Following the B-Sand liner run we will then run a USIT log on tractor. We will keep you apprised of any further developments or findings concerning the intermediate cement job. Please contact me with questions or concerns... Dennis «1J-160 Daily 3_16_07.PDF» Dennis Hartwig Drilling Engineer ConocoPhillips Alaska, Inc. Office :907-265-6862 Cel I :907-980-1433 ~,'~' Q~~ tc..~ 1 of ~ 4/19!2007 1:21 PM ~~ • Security Level: Development Daily Drilling Report 1J-160 Report Number: 17 . »• Rig: DOYON 15 Report Date: 3/16/2007 Welibore Well Type Field Name Spud Date DFS (days) Depth Start (ftKB} Depth End (ftfCB) Depth Progress (ft) 1J-160 development WESTSAK 3/2/2007 14.30 9,150.0 9,150.0 0.00 AFE / RFE ! Malnt.# Daily Mud Cost Cummulative Mud Cost Daily Cost Total Cummr•'°"••° ^-^' Total AF° "^,^°^` 10165578 4,889.97 366,557.99 848,995.97 Last Casing String Next Casing OD (in) Next Casing Set Depth (ftKB) Intermediate, 9,150.OftKB 4 1!2 13,000.00 Ops and Depth @ Morning Report 24hr Forecast RIH w/ BHA #5 @ 185'. PU 5" HWDP, UD 10 stands of 5" dp, MU BHA to tag TOC, circ, test casing, POOH. Last 24hr Summary Continue RIH w/ 9-5/8" casing to 6353', circ, continue RIH to 9150', circ prior to cementing, Dowell pump cement, rig displace cement, did not bump plug, floats held, PU BOPE, set slips w/ 68k tension, cut off, install packoff, NU BOPE, test to 2500 psi f/ 10 min, finish NU BOPE, perform LOT on 13-3/8" x 9-5l8"= 12.2 pP9• General Remarks Weather Head Count Rig on Hi-Line Power. -16 deg, 5 knots SW, WC -28 46.0 -- Supervisor Title --" _ Mike Thornton Rig Supervisor Granville Rizek Rig Supervisor Time Lo '-Staff End Dur Tme Depth Start Depth End Time: ' lima (hrs) Phase Op Code OpSob-Co... i'-N-T Trbl Code Trbl Class. IftKB) (ftK6) _ Comm/Operation 00:00 00:45 0.75 INTRMI CASING CIRC P 3,500.0 3,500.0 Continue to circulate at the 13-3l8" casing shoe. Pumping 10 bpm w/ 750 psi. PU wt 175k, SO wt 132k. Recip pipe 20' stroke. Circ total of 472 bbis. 00:45 03:45 3.00 INTRM1 CASING RNCS P 3,500.0 6,353.0 Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every 10 joints in open hole. 03:45 05:15 1.50 INTRMI CASING CIRC P 6,353.0 6,353.0 Circulate. Stage pumps up f/ 3bpm w! 260 psi, then 4 bpm w/ 320 psi, 5 bpm w/ 390 psi, 6 bpm w/ 460 psi, 7 bpm w/ 540 psi. Circ total of 450 bbis. PU wt 215k, SO wt 115k. Recip pipe 20' stroke. Note: Had a MOBM spill of 10 gals at the tank farm. Spill cleanup was performed while circulating. 3 gals outside of secondary containment, 7 gals inside of berm (secondary containment). 05:15 06:00 0.75 INTRMI CASING RNCS P 6,353:0 7,124.0 Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every 10 joints in open hole. 06:00 08:30 2.50 INTRM1 CASING RNCS P 7,124.0 9,150.0 Continue to run 9-5/8" 40 ppf, L-80, BTC-mod casing per running order. Record PU and SO weight's every i0 joints in open hole. 08:30 10:00 1.50 INTRM1 CEMENT CIRC P 9,150.0 9,150.0 Circ 10:00 10:30 0.50 INTRM1 CEMENT PULD P 9,150.0 9,150.0 UD Fill up tool & Rig up Cement head 10:30 13:00 2.50 INTRM1 CEMENT CIRC P 9,150.0 9,150.0 Circ, Held PJSM with all parties 13:00 14:45 1.75 INTRM1 CEMENT CIRC P 9,150.0 9,150.0 Dowell pump 10 bbls CW100 (8.34 ppg), pressure test lines to 2500 psi, pump an additiona140 bbls GW100 (Total of 50 bbls), follow w/ 75.2 bbis mud push (11 ppg), drop bottom plug, follow w/ 296.5 bbis DeepCrete (736 sx) (Yield 2.26 cuft/sx) (7.485 gai/sxwater) mixed @ 12.5 ppg, pumped @ 6 bpm, drop top plug, pump 10 bbis water, turn over to rig f/displacement. Reciprocated pipe f/ 30' to 5'. Latest BOP Test Data _ _ ___ - - _. _. _ _. Date Comment 3/9/2007 First full BOP test on the well. Witness of test waived b AOGCC re Chuck Sheave Page 1/3 Report Printed: 3/19/2007 Security Level: Development -. Daily Drilling Report 1J-160 Report Number: 17 .• Rig: DOYON 15 Report Date: 3/16/2007 Time Lod --- Start End Dur Time Time (hrs) Phase Time Depth Start Depth End Op Code OpSub-Co... P-N-T Trbl Code Trbl Class. (ftK6j (ftKB) CommlOperalwn 14:45 16:45 2.00 INTRMI CEMENT DISP P 9,150.0 9,150.0 Rig displace cement w/ 8.4 ppg MOBM. Pumping at rate of 7 bpm at initial 360 psi with a steady 29% to 30% flow indication on the flow indicator. Had good cement lift pressure for first 5850 strokes (588.5 bbls) w/ 30% flow indication (30% is full returns), Pressure increased f/ 360 psi to 1130 psi, Then from 5850 strokes to 6600 strokes observed flow indicator start decreasing f/ 30% to 19% while holding 7 bpm, Pressure held steady with no more increase @ 1120 psi, Last 10 bbls pumped at 3 bpm @ 930 psi, Did not bump plug after pumping total of 692.0 bbls (Max calculated bbls of 690.4 bbls = Displacemenrt to float collar+ 1/2 the shoe track) . Bleed off pressure, check floats- held OK. CIP @ 1630 hrs 3/16!2007. Reciprocated pipe 20' to 5' when finally ran out of down wt. stopped pipe after 37.6 bbls turned around shoe. 16:45 18:00 1.25 INTRMI CASING NUND P 9,150.0 9,150.0 Drain stack, Nipple down stack and vacuum out fluid in landing joint. Blow down cement line. 18:00 19:45 1.75 INTRM1 CASING OTHR P 9,150.0 0.0 Set casing on Vetco/Gray emergency slips. Weight indicator 170K. Pipe with 68k tension. Remove Dowell cement head and GBR elevators. Hold landing joint w/ tugger while cutting w/ E.H. Wach's Split Frame O.D. Machine (casing cutter). Lay down cutoff measured to be 27.60'. 19:45 21:15 1.50 INTRMI WELGTL NUND P 0.0 0.0 Install VetcolGray packoff. Lower BOP stack back into place, tighten bolts. Laying down casing running tools f! rig floor. 21:15 21:30 025 INTRMI WELGTL OTHR P 0.0 D.0 Energize packoff seal. Test packoff seal to 80% of 9-5/8" 40ppf L-80 casing collapse. Test to 2500 psi f/ 10 min. Good test. 21:30 23:45 2.25 INTRMI WELGTL NUND P 0.0 0.0 NU BOPE while rigging up to perform LOT on 13-3l8" x 9-5l8" annulus. Lay down long casing running bales. PU shorter drilling bales for top drive and 5" elevators. Vetco/Gray wear bushing to floor. Clean and clear rig floor. 23:45 00:00 0.25 INTRM1 DRILL LOT P 0.0 0.0 Performing LOT on 13-3/8" x 9-5/8" annulus. 13-318" shoe @ 3551'MD (2190' TVD), mud wt 9.2 ppg, broke down w! applied pressure of 337 psi = 12.2 ppg EMW. Pumped a total of 15 bbls. - Mud Check Data __. -- - --- _ _ -- - YP Calc Gel (10s} Gel (10m) Gel (30m) HTHP Filt Density.Temp Solids, Corr. Type Depth (ftKB) Dens (Ib/gal) Vis (s/qt) PV Calc (cp) (Ibf/100ft') (Ibf/100ft'} (Ibf/t00R') (Ibflt00ft') MBT (Ib(bbl) (mLl30min) pH (°F) (%) Water 10,271.0 9.20 43 9.0 13.000 4.000 6.000 7.000 6.0 8.3 6.0 Based Mud Water 10,271.0 9.20 46 11.0 17.000 7.000 13.000 15.000 6.1 8.3 6.0 Based Mud In~ection Fluid _ _ Fluid __ Cuttings Source _ _ F_r_o__m Lease (bbl) I Destmation Note -_ 1J-160 14.0 DS 4 G&I ICu yds. Cuttings/WBM Water Based Mud 1J-160 1160.0 1R-18 WBM Returns Water Based Mud 1J-160 490.01R-18 Rinsate/H20 Water Based Mud 1J-160 290.0 1R-18 WBM Returns _ Wellbores _ _- - Wellbore Name Wellbore APIfUWI 1J-160 500292334400 Page 2/3 Repoli Printed: 3/19!2007 Re: 1J-160 Update Subject: Re: IJ-160 Update From: Thomas Maunder <tom_maunder~~admin.state.ak.us> Date: Fri, 16 Mar 2007 l 3:3 LOS -0800 ~[~o: "Hart~~i;, Dennis l_)" L)eniris.D.Harttivigcvcariocophillips.com-- • Dennis, This information is sufficient for 1J-160L1 and -L2. I will place a copy of this message in the files. In our call you indicated that 1J-176 has yet to be permitted. Nothing is needed for that well at this time. Call or message with any questions. Tom Maunder, PE AOGCC Hartwig, Dennis D wrote, On 3/16/2007 1:21 PM: Tom, r--~ ~~`Z - C`~ ~ 5 I am covering the 1J-160 while Mike Greener is taking some much earned vacation. I thought I would update you on some current activities and forward plans on the 1J-160 being drilled by Doyon 15. As you already know, the West Sak A-Lateral was wet and thus the A-sand lateral: will not be drilled. Further, Both the B & D laterals will be shortened by approximately 1500' (moved 1500' to the North). Shortening the laterals by 1500' allows for a much simpler Intermediate casing /cementing on the offset well to the South (1J-176). The new 1J-176 Intermediate will be landed approximately 1500' further North making it a much more feasible well If shortening the 1J-160 B & D lateral requires any change to permitting etc... please contact me. Thanks and have a good weekend... Dennis Dennis Hartwig Drilling Engineer ConocoPhillips Alaska, Inc. Office :907-265-6862 Cell :907-980-1433 Fax :907-265-1535 1 of 1 3/16/2007 1:31 PM 1J-160 status as of 3/13/07 ~ ~ Page 1 of 1 Allsup-Drake, Sharon K From: Greener, Mike R. Sent: Tuesday, March 13, 2007 9:39 AM To: Allsup-Drake, Sharon K Subject: FW: 1 J-160 status as of 3/13/07 For your information. See below. -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Tuesday, March 13, 2007 9:36 AM To: Greener, Mike R. Cc: Thomas, Randy L; Hartwig, Dennis D; Steve Davies Subject: Re: i]-160 status as of 3/13/07 Thanks Mike. Your plan should effect isolation from the water. This situation poses an interesting situation since this well was intended to be a tri-lateral and what would have been the motherbore penetration will essentially be plugged. , In order to avoid what likely would be significant paperwork, it is probably best that the originally planned naming convention continue with 1 J-160L 1 in the B sand and 1J-160L2 in the D sand. 1J-160 still needs to be "on the books" since all lateral production is reported against the motherbore that has the -00- suffix in the API number. Lets all be aware of the situation on this well. It is probably appropriate to be sure that your other colleagues (especially Sharon) are aware of this well. Call or message with any questions. Tom Maunder, PE AOGCC Greener, Mike R. wrote, On 3/13/2007 9:19 AM: Last night we finished our drilling of the intermediate section for this well. We drilled to a measured depth of 10,271' NIIID, 3,455' TVD. Our TD is in the A2 sand. The A2 sand is wet. The D and B sands are oil bearing. Our plan forward is to set our intermediate casing (9-5/8") at 9,150' MD, 3,340' TVD. ~ The top of the B sand is at 8,750' MD, 3,285' TVD. We will cut a window to access the B sand. By setting our shoe at 9,150' MD we expect to isolate any water from the A2 Sand. Mike Greener «Greener, Mike R..vcf» 4/10/2007 • TUBING (ae357, OD:4.500, ID:3.958) LOCATOR (8342-8343, OD:5.200) CSG SBR (8347-8366, OD:6.310) PUP (8368-8377, OD:5.210) HANGER (8541-8551, OD:8.300) SBE (8552-8571, OD:6.270) TERMEDIATE (as15o, OD:9.625, Wt:40.00) ConocoPhillips Alaska, Inc. KRU 1 J-160 1 J-160 A PI: 50029233 44 0 0 Well T e: SVC Angle t7a TS: d _ SSSV T e: _ NIPPLE _ _ . __ Ori Com letion: __ 4/10/2007 An le TD: 80 d 10271 Annular Fluid: Last W10: Rev Reason: GLV C/O Reference L 40' RKB Ref L Date: Last U date: 4/26/2007 Last Ta TD: 10271 ftKB Last Ta Date: Max Hole An le: 87 d 9957 Casing Strin -ALL S Description CONDUCTOR TRINGS Size To~_ Bottom TVD Wt Grade Thread 20.000 0 120 120 94.00 H-40 WELDED SURFACE 13.375 0 3550 2191 68.00 L-80 BTC INTERMEDIATE 9.625 0 9150 3343 40.00 L-80 BTCM WINDOW D-SAND 9.625 8301 8392 3224 _0.00 WINDOW B-SAND 9.625 87:i0 8751 3286 0.00 Tubin Strin -TUBIN G Size Top Bottom TVD Wt Grade_ Thread 4.500 0 _ 8357 3218 12.60 L-80 IBTM Gas Lift MandrelsNal ves St MD TVD Man Mfr 1 2280 1859 CAMCO Other lu s, a ui ., De th TVD T e 36 36 HANGER Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv Cmnt KBMG GLV 1.0 BK-5 0.188 1415 4/25/2007 etc. -COMPLETION Descri tion ID VETCO GRAY TUBING HANGER 4.500 506 504 NIP CAMCO DB-6 w/NO GO PROFILE 3.875 8290 3206 SLEEVE-O BAKER CMD SLIDING SLEEVE w/OPEN PROFILE 3.812 8342 3215 LOCATOR BAKER LOCATOR 3.940 8343 3216 SEAL BAKER SEAL ASSEMBLY PBR/SBR 3.880 8357 3218 SHOE 3.958 Other lu s, a ui ., etc. -LINER DETAIL De th TVD T e Descri tion ID 8324 3212 PACKER D-SAND SLZXP LINER TOP PACKER 7.500 8345 3216 XO _ D-SAND LEM CROSSOVER 7" x 5.5" 4.920 8347 3216 CSG SBR D-SAND LEM 190-47 CASING SEAL BORE RECEPTACLE 4.750 8366 3220 XO Bushin D-SAND CROSSOVER BUSHING 3.940 8368 3220 PUP 3.958 8377 3222 HANGER D-SAND LEM ABOVE HOOK HANGER 3.960 8391 3224 HANGER D-SAND BAKER MODEL 'B' LEM HOOK HANGER INSIDE CSG 7.470 8519 3247 PACKER B-SAND'HRD' ZXP LINER TOP PACKER 7.500 8537 3250 NIP B-SAND'RS' PACKOFF SEAL NIPPLE 6.180 8541 3250 HANGER B-SAND FLEXLOCK LINER HANGER 6.210 8551 3252 XO Bushin~c B_SAND CROSSOVER BUSHING 4.930 8552 3252 SBE B-SAND 190-47 CASING SEAL BORE EXTENSION 4.750 8571 3256 XO Bushin B-SAND CROSSOVER BUSHING 3.910 8750 3286 Whi stock B-SAND GEN II WHIPSTOCK 2.250 General Notes Date Note 4/11/2007 NOTES: MULTILAT WELL- 1J-160 NOT PERF'D , 1J-160L1 B-SAND , 1J-160L2 D-SAND Re: 1J-160 status as of 3/13/07 • Subject: Re: 1J-160 status as of 3/13/07 From: Thomas Maunder <tom maunder@admin.state.ak.us> Date: Tue, 13 Mar 2007 09:36:01 -0800 ~~~~ _ "t'o: "Greener, Mike fZ." -Mike.R.Greener a%conocophilli~s.com> C'C: "ll~~>m~~s, Ran~1~ ~." Randy.L.Thomas(a~conocophillips.com?_ "(l:~ri~~i~~. I)~nni~ D" [>~nnis.I).f lart~~ i~~~~r ci~~~~~c~~phillips.com>, Steve Davies ~steve davies~ ~~~itnin.state.ak.us> Thanks Mike. Your plan should effect isolation from the water. This situation poses an interesting situation since this well was intended to be a tri-lateral and what would have been the motherbore penetration will essentially be plugged. In order to avoid what likely would be significant paperwork, it is probably best that the originally planned naming convention continue with IJ-160L1 in the B sand and I J-160L2 in the D sand. 1 J-160 still needs to be "on the books" since all lateral production is reported against the motherbore that has the -00- suffix in the API number. Lets all be aware of the situation on this well. It is probably appropriate to be sure that your other colleagues (especially Sharon) are aware of this well. Call or message with any questions. Tom Maunder, PE AOGCC Greener, Mike R. wrote, On 3/13/200? 9:19 AM: I_,ast night ~Te t~shed our ril.ln~ of the intermediate section for this ~ve11. ~Ie drilled to ~ measured depth of ~,27I' ~~I~, 3.~~~' TVL). Clur T is ~n the A? sanei. The ~~2 sand is ~~et. The D ~.nd sands a~•e. oil bearing. (fur plan t~>r~vard is to set our intetmecliate casing (~-~I") at X3,15()' MLA, x3,34' TVL~. The top of tl~e ~ sand is ~~t x,75()' M1~, 3,25' TVL). Vie •ill cut a u~ido• to access t1~e ~3 sand. ~~ setting our slue at ~),15(~' 3 ~~ expect to isolate and-~ -c~t~r from the A2 Sand. ~lilcc Oreet~er «Greener, Mike R..vcf» 1 of 1 3/13!2007 9:37 AM Re: 1J-160 (207-015) surface cement job Subject: Re: 1J-160 (207-015) surface cement job From: Thomas Maunder <tom_maunder cr admin.state.ak.us> Date: Wed, 07 Mar 2007 14:29:18 -0900 To: "Greener, Mike R." ~-(\tihe.R.Grccner«;conocophillips.coin> . ' IZ~~~ert~. Ii~n~~~cn i_" -I3u~~en.l~:.I:~~bcrtsuconoCOph1'.1(ii~s.com -_ "Meh~~~cr_ ~le~c Stc~~c.~1rKc:~~c:r~~rcoi~oc<~phillips.a~m- _ "~l~homi~c, Ran~Iv L'. <Rand~~.L~:Thomas(i cunocoi~hilli}~s.com~ Mike, As you pointed out, there isn't really an option when you consider the long term operation of the well and the need to assure that the upper portion of the casing is isolated to prevent external corrosion. I am forwarding this message to the North Slope Inspectors. Have Mike stay in touch with them so they may witness operations as able. Call or message with any questions. Tom Maunder, PE AOGCC Greener, Mike R. wrote, On 3/7/2007 2:24 PM: e finished running cur 13-318"su~•face casing to 3,SS 1' at 0~:~~ 3/7~2~7. The casing was cis°culated anc~ the annulus mud cleaned. up in preparatican fc~r cementing. The cement joh went as planned. with an excess voluane of 225'10 pumped. -l,he mud. hush with red. dye was observed.: at tl~e surface and when. the plug ~~umped we had yct to see cc;~nent to sitrfacc. ~~~ tr are currently rigging up to run a 1- l /~" cement string to the cement top and we will cement the annulus to surface usir-~.~ this string. Make Greener «Greener, Mike R..vcf» 1 of 1 3/7/2007 2;30 PM C®1~TSER~A1'IO1dT C®Dffi~iISSIOIQ Randy Thomas Greater Kuparuk Area Drilling Team Leader ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 SARAH PALIIN, GO!/ERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kuparuk River Field, West Sak Oil Pool, 1J-160 ConocoPhillips Alaska, Inc. Permit No: 207-015 Surface Location: 2016' FSL, 2541' FEL, Sec. 35, T11N, RlOE, UM Bottomhole Location: 96' FNL, 1842' FWL, Sec. 10, T10N, R10E, UM Dear Mr. Thomas: Enclosed is the approved application for permit to 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) X59-3607 (pager). DATED this ~ day of February, 2007 cc: Department of Fish 8v Game, Habitat Section w/ o encl. Department of Environmental Conservation w/o encl. Conoco~hillips Alaska Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Email: Randy.L.Thomas@conocophillips.com ! \/ ~i~~N~ 3 0 2DQ7 January 29, 2007 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Alaska ~li~ Gas Cons. Commission ~Iacharaga Re: Applications for Permit to Drill, West Sak Injector, 1J-160, 1J-160 L1, 1J-160 L2 Dear Commissioners: ConocoPhillips Alaska, Inc. hereby applies for Permits to Drill for an onshore injection well, a trilateral horizontal well in the West Sak °A2", "B"and °D" sands. The main bore of the well will be designated 1]- 160, and the lateral bores of the well will be designated 1J-160L1 and iJ-160L2. Please find attached for the review of the Commission forms 10-401 and the information required by 20 ACC 25.005 for each of these well bores. The expected spud date of iJ-160 is February 14th, 2007. If you have any questions or require any further information, please contact Mike Greener at 263-4820. Sincerely, Randy Thomas Greater Kuparuk Area Drilling Team Leader STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ~~~~ V JA~i 3 0 2007 Alaska Oil ~ Gas Cons. Commission 1 a. Type of Work: Drill Q Re-drill ^ Re-entry ^ 1 b. Current Well Class: Exploratory Development Oil ^ Stratigraphic Test ^ Service ^/ Development Gas ^ Multiple Zone^ Single Zone ^ 1 c. Specify if well is propo i`$~~ Coalbed Methane ^ Gas Hydrates ^ Shale Gas ^ 2. Operator Name: ConocoPhillipsAlaska, Inc. 5. Bond: ~ Blanket Single Well Bond No. 59-52-180 ~ 11. Well Name and Number: 1J-160 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 14478' ' TVD: 3407' f 12. Field/Pool(s): Kuparuk River Field 4a. Location of Well (Governmental Section): Surface: 2016' FSL, 2541' FEL, Sec. 35, T11 N, R10E, UM 7. Property Designation: ADL 25660 & 256631 Ltb4 ~ West Sak Oil Pool Top of Productive Horizon: 606' FNL, 1684' FWL, Sec. 3, T10N, R10E, UM 8. Land Use Permit: p ALK 470 & 472 t'~~ 13. Approximate Spud Date: 2/14/2007 Total Depth: 96' FNL, 1842' FWL, Sec. 10, T10N, R10E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: < 1 mile 4b. Location of Well (State Base Plane Coordinates): Surface: x- 558668 ~ y- 5945827 Zone- 4 10. KB Elevation (Height above GL): 28' RKB feet 15. Distance to Nearest I well within Pool: 1 E-117L2 , 936 16. Deviated wells: Kickoff depth: 400 ft. Maximum Hole Angle: g3° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) _ 1• Downhole: 1568 psig ' Surface: 1185 psig 18. Casing Program if ti S Setting Depth Quantity of Cement Size ica ons pec Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 20" x 34" 94# K-55 Welded 80' 28' 28' 108' 108' 260 cf ArcticCRETE 16" 13.375" 68# L-80 BTC 3226' 28' 28' 3226' 2135' 650 sx AS Lite, 220 sx DeepCRETE 12.25" 9-5/8" 40# L-80 BTCM 9704' 28' 28' 9704' 3472' 790 sx DeepCRETE 6.75" 4.5" 11.6# L-80 BTC 5715' 8773' 3323' 14478' 3407' 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 (ff): Effective Depth TVD (ft): Junk (measured) Casing Length Size Cement Volume MD ND Conductor/Structu ra I Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ^/ BOP Sketch ^ Drilling Program ^ Time v. Depth Plot Shallow Hazard Analysis Property Plat ^ Diverter Sketch ^ Seabed Report ^ Drilling Fluid Program ^ 20 AAC 25.050 requirements ^/ 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Greener @ 263-4820 Printed Name Randy Thomas title Greater Kuparuk Area Drilling Team Leader Signature '~~, ,~__._. Phone `Z~. j ~ ~-r~ ~, Date 1 ~Lrl ~~,:~ P r h n All k Commission Use Only Permit to Drill •+~ Number: ZU ! " U~~ API Number: 50-029- Z335<y ~ Permit Approval Date: ~o2lb g ~(~ 7 See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed me hane, gas hydrates, or gas contained in shales: '+.r~~'~~~~~„~~ ~~>`Ati ,~ Samples req'd: Yes ^ No ~ Mud log req'd: Yes ^ No [v~ Other: ~ ~ H2S measures: Yes ^ No [~ Dir i nal svy req'd: Yes [/Y No ^ ,~ Q.~O ~f~' APPROVED BY THE COMMISSION DATE: ~ (J --ff ,COMMISSIONER /`1 Form 10-401 Revised 12/2005 ~.* ~~ ~ Y i ~ i.~ v ~./ ~~ r. ~7 Submit in Duplicate .~ '/~~7 A~tion for Permit to Drill, Well 1J-160 Revision No.0 Saved: 29-Jan-07 Permit It -West Sak Well #1J-160 ~~°° r.w +'t Application for Permit to Drill Document •, ~+I~x~ll Mpxirriia~ 1Mel I 'l41u e Table of Contents 1. Well Name ................................................................................................................. 2 Requirements of 20 AAC 25.005 (fl ....................................................................................................... 2 2. Location Summary ................................................................................................... 2 Requirements of 20 AAC 25.005(c)(2) ................................................................................................... 2 Requirements of 20 AAC 25.050(b) ....................................................................................................... 3 3. Blowout Prevention Equipment Information ......................................................... 3 Requirements of 20 AAC 25.005(c)(3) ................................................................................................... 3 4. Drilling Hazards Information ................................................................................... 3 Requirements of 20 AAC 25.005 (c)(4) .................................................................................................. 3 5. Procedure for Conducting Formation Integrity Tests ........................................... 4 Requirements of 20 AAC 25.005 (c)(5) .................................................................................................. 4 6. Casing and Cementing Program ............................................................................ 4 Requirements of 20 AAC 25.005(c)(6) .......................................................:........................................... 4 7. Diverter System Information ................................................................................... 4 Requirements of 20 AAC 25.005(c)(7) ................................................................................................... 4 8. Drilling Fluid Program ............................................................................................. 4 Requirements of 20 AAC 25.005(c)(8) ................................................................................................... 4 Surface Hole Mud Program (extended bentonite) .................................................................................. 5 Intermediate Hole Mud Program (extended bentonite) .............................................................:............ 5 Lateral Mud Program (MI VersaPro Mineral Oil Base) ........................................................................... 5 9. Abnormally Pressured Formation Information ..................................................... 5 Requirements of 20 AAC 25.005 (c)(9) .................................................................................................. 5 10. Seismic Analysis ..................................................................................................... 5 Requirements of 20 AAC 25.005 (c)(10) ................................................................................................ 5 11.Seabed Condition Analysis ..................................................................................... 6 Requirements of 20 AAC 25.005 (c)(11) ................................................................................................ 6 1J-160 PERMIT IT Page 1 of 8 Printed: 29-Jan-07 ORIGINAL ,7 Aption for Permit to Drill, Well 1J-160 Revision No.O Saved: 29-Jan-07 12. Evidence of Bonding ............................................................................................... 6 Requirements of 20 AAC 25.005 (c)(12) ................................................................................................ 6 13. Proposed Drilling Program ..................................................................................... 6 Requirements of 20 AAC 25.005 (c)(13) ................................................................................................ 6 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ....................... 8 Requirements of 20 AAC 25.005 (c)(14) ................................................................................................ 8 15. Attachments ............................................................................................................. 8 Attachment 1 Directional Plan .............................................................................................:.................. 8 Attachment 2 Drilling Hazards Summary ............................................................................................... 8 Attachment 3 Cement Loads and CemCADE Summary ....................................................................... 8 Attachment 4 Well Schematic ............................................................................................................... 8 Attachment 5 1/4 Mile Radius Effect for Injector ......................................................................8 1. Well Name Requirements of 20 AAC 25.005 (17 Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(6). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this Application is submitted will be designated as iJ-160. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines. (e) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Location at Surface 2,016' FSL, 2,541' FEL, Section 35, T11N, R10E ASP Zone 4 NAD 27 Coordinates RKB Elevation 109.0' AMSL Northings: 5,945,827 Eastings: 558,668 Pad Elevation 81.0' AMSL Location at Top of Productive Interval West Sak "A2" Sand 606' FNL, 1,684' FWL, Section 03, T10N, R10E ASP Zone 4 NAD 27 Coordinates Measured De th, RKB: 9,704 Northings: 5,943,158 Eastings: 552,357 Total Vertical De th, RKB: 3,472 Total Vertical De th, SS: 3,351 Location at Total De th 96' FNL, 1,842' FWL, Section 10, T10N, R10E ASP Zone 4 NAD 27 Coordinates Measured De th, RKB: 14,478 Northings: 5,938,391 Eastings: 552,556 Total Vertical De th, RKB: 3,407 Total Vertical De th SS: 3 286 1J-160 PERMIT IT Page 2 of 8 Printed: 29-Jan-07 IGINAL and (D) other information required by 20 AAC 25.050(b); Ation for Permit to Drill, Well 1J-160 ' Revision No.O Saved: 29-Jan-07 Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form i 0-40i) must (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; Please see Attachment 1: Directional Plan 1J-160 and (2) for all wells within 200 feet of the proposed wellbore (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (8) state that the applicant is the only affected owner. The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (3) a diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; An API 13-5/8" x 5,000 psi BOP stack (RSRRA) will be utilized to drill and complete well 1J-160. For all operations the stack will be equipped with 3-1/2" to 6" variable bore rams in the uppermost ram cavity, blind rams in the middle cavity, and 7-5/8" rams in the lowermost cavity. See attached diagram entitled °Doyon 141 West Sak 2004 3ksi BOP Configuration" for clarification. Upon initial nipple up, and at intervals of no more than 14 days thereafter, a test plug will be set below the lowermost rams, the annular preventer will be tested to 1,500 psi and the blind rams and upper rams will be tested to 3,000 psi. (This test will test the shell and end connections of the lowermost ram). The lowermost rams will be closed and tested to 3,000 psi on a 7-5/8" OD. 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that maybe encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient; r The expected reservoir pressures in the West Sak sands in the iJ area are 0.45 psi/ft, or 8.7 ppg EMW (equivalent mud weight). These pressures are predicted based on the undisturbed West Sak pressure gradient. `- _. The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11), and the deepest planned vertical depth of the West Sak A2 sand formation is 1,185 psi, calculated thusly: MPSP = (3,485 ft TVD)(0.45 - 0.11 psi/ft) = 1,185 psi (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 2: iJ-160 Drilling Hazards Summary. 1J-160 PERMIT IT Page 3 of 8 Printed: 29-Jan-07 ORIGINAL • A~tion for Permit to Drill, Well 1J-160 Revision No.0 Saved: 29-Jan-07 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); 1J-160 will be completed with 9-5/8" intermediate casing landed at the top of the West Sak A2 sand. The casing shoe will be drilled out and a formation integrity test will be performed in accordance with the "Formation Integrity Test Procedure" that ConocoPhillips Alaska placed on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre- perforated liner, or screen to be installed; Casing and Cementing Program See also Attachment 3: Cement Summary Hole Top Btm Csg g eig ~~..._ . MD/TVD OD in in t Ib/ft Grade Connection (ft) (ft (ft) Cement Pro ram 20 x 34 42 94 K55 Welded 80 28 / 28 108 / 108 Cemented to surface with 260 cf ArcticCRETE Cemented to Surface with 13-3/8 16 68 L-80 BTC 3,226 28 / 28 3,226 /2,135 650 sx ASLite Lead, 220 sx DeepCRETE Tail Cement Top planned @ 9-5/8 12-1/4 40 L-80 BTCM 9,704 28 / 28 9,704 / 3,472 5,300' MD / 2,561' TVD. Cemented w/ 790 sx Dee CRETE 4-1/2 6-3/4" A Sand 11.6 L-80 BTC 5,715 8,773 / 3,323 14,478 / 3,407 slotted- no cement Slotted Lateral (1]-160) 4-1/2 6-3/4" B Sand 11.6 L-80 BTC 5,803 8,663 / 3,309 14,466 / 3,249 Slotted- no cement slotted Lateral (1J-160 Ll) 4-1/2 6-3/4" D Sand 11.6 L-80 BTC 6,184 8,273 / 3,234 14,457 / 3,173 Slotted- no cement Slotted Lateral (1J-160 L2) 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); A 21-1/4", 2000 psi annular with a 16" diameter diverter line will be the diverter system used in the drilling of iJ-160. Please see diagrams of the Doyon 15 diverter system on file with the Commission. 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling will be done with muds having the following properties over the listed intervals: 1J-160 PERMIT IT Page 4 of 8 Printed: 29-Jan-07 ORIGINAL • Surface Hole Mud Program (extended bentonite) A~tion for Permit to Drill, Well 1 J-160 Revision No.O Saved: 29-Jan-07 S ud to Base of Permafrost Base of Permafrost to 13-3/8" Casin Point Initial Value Final Value Initial Value Final Value Density (ppg) 8.9 9.2 9.5 9.6 Funnef viscosity 150 250 200 300 seconds Yield Point 50 70 30 50 (cP) Plastic Viscostiy 20 45 15 20 Ib/100 s pH 8.5 9.0 8.5 9.0 API Filtrate NC 8 0 5 0 7 0 (cc / 30 min)) . . . *9.6 ppg if hydrates are encountered Intermediate Hole Mud Program (LSND) Lateral Mud Program (MI VersaPro Mineral Oil Base) A/B/D sand laterals 13-3/8" Cs Shoe to 9-5/8" Cs Point Value Density (ppg) 9.0 - 9.1 Funnel Viscosity 45 - 60 (seconds) Plastic Viscostiy 12 - 18 (Ib/100 sf) Yield Point 26 - 35 (cP) API Filtrate 4 - 6 (cc / 30 min)) Chlorides (mg/I) <500 pH 9.0 - 9.5 MBT <20.0 Value Densit (ppg) 8.8 Plastic Viscostiy (Ib/100 sf) 15.25 Yield Point 18 - 28 cP HTHP Fluid loss (ml/30 min @ <4.0 200psi & 150° Oil /Water Ratio 70 / 30 Electrical >600 Stabilit Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Please see information on file with the Commission for diagrams and descriptions of the fluid system of Doyon Rig 15. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (9) for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); Not applicable: Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); Not applicable: Application is not for an exploratory or stratigraphic test well. 1J-160 PERMIT IT Page 5 of 8 Printed: 29-Jan-07 ORIGINAL Ation for Permit to Drill, Well 1J-160 Revision No.O Saved: 29-Jan-07 11.Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (11) for a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); Not applicable: Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (i2) evidence showing that the requirements of 20 AAC 25.025 {Bonding}have been met; Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: The proposed drilling program is listed below. Please refer also to Attachment 4, Well Schematic. 1. Excavate cellar, install cellar box, set and cement 20" x 34" insulated conductor to +/- 108' RKB. Install landing ring on conductor. 2. Move in /rig up Doyon Rig 15. Install 21-1/4"Annular with 16" diverter line and function test. 3. Spud and directionally drill 16" hole to casing point at +/- 3,226' MD / 2,135' TVD as per directional plan. Run MWD tools as required for directional monitoring. 4. Run and cement 13-3/8", 68#, L80, BTC casing to surface. Displace cement with mud and, pressure test casing to 2500 psi for 30 minutes and record results. Perform top job if required. 5. Remove diverter system, install and test 13-5/8" x 5,000 psi BOP's as described above in Section 3 above and test to 3,000 psi (annular preventer to 1500 psi). Notify AOGCC 24 hrs before test. 6. PU 12-1/4" bit and 6-1/4"drilling assembly, with MWD, LWD & PWD. RIH, clean out cement to top of float equipment. Re-test casing if cement is tagged more than 100 feet above the float collar. 7. Drill out cement and between 20' and 50' of new hole. Perform formation integrity test to leak off, recording results. (ECD's modeled to be less than 11.0 ppg) 8. Directionally drill to 9-5/8" casing point at 9,704' MD / 3,472' TVD, the prognosis top of the A2 sand. 9. Run 9-5/8", 40# L80, BTC Mod casing to surface. Pump cement and displace with mud (top of cement to be 5,363' MD / 2,570' TVD if Ugnu C formation is oil bearing. Top of cement to be 500 feet (MD) above shallowest oil bearing sand.). Pressure test casing to 3,000 psi for 30 minutes and record results. 10. Install wellhead x 9-5/8" packoff and test to 5000 psi. 11. Flush 13-3/8" x 9-5/8"annulus with water, followed by diesel. 12. PU 6-3/4" PDC Bit and 4-3/4"drilling assembly, with MWD, and LWD logging tools. RIH, clean out cement to top of float equipment. Re-test casing if cement is tagged more than 100 feet above the float collar 13. Drill out cement and between 20' and 50' of new hole. Displace hole to lateral drilling mud. Perform formation integrity test to leak off, recording results. (Expected ECD's in 6-3/4" lateral modeled to be less than 12.5 ppg). 14. Directionally drill 6-3/4" hole to TD at +/- 14,478' MD / 3,407' TVD as per directional plan. 1J-160 PERMIT IT Page 6 of 8 Printed. 29-Jan-07 ORIGINAL • A~ation for Permit to Drill, Well 1 J-160 Revision No.O Saved: 29-Jan-07 15. POOH, back reaming out of lateral to 9-5/8" shoe. TIH to bottom & displace to solids-free oil based mud. POOH on elevators. ~d~ 16. Run USIT log to evaluate cement bond on intermediate casing. ~~ ~ 17. PU and run 4-1/2" slotted liner. 18. Land liner, set liner hanger @ +/- 8,763' MD / 3,323' ND. POOH. ~, Note: Remaining operations are covered under the 1J-160L1 Application for Permit to Drill, and are provided here for information only. ~~~ ^d` ~ 19. Run and set Baker WindowMaster whipstock system, at window point of +/- 8,663' MD / 3,309' TVD, the top of the B sand. 20. Mill 6-3/4" window. POOH. 21. Pick up 6-3/4"drilling assembly with LWD and MWD and PWD. RIH. 22. Drill to TD of B sand lateral at +/- 14,466' MD / 3,249' TVD, as per directional plan. 23. POOH, back reaming out of lateral to window. TIH to bottom & displace to solids-free oil based mud. POOH on elevators. 24. RIH with whipstock retrieval tool. Retrieve whipstock and POOH. 25. PU and run 4-1/2" slotted liner. 26. RIH, until liner hanger is just above window. Orient hanger to window and land hanger. 27. Release hanger running tool. POOH. 28. Make up junction isolation / re-entry assembly (Lateral Entry Module or LEM) and RIH to depth. Orient and set packer atop assembly and release from assembly. POOH. Note: Remaining operations are covered under the 1J-160L2 Application for Permit to Drill, and are provided here for information only. ~1 _v~ ~ 29. Run and set Baker WindowMaster whipstock system, at window point of +/- 8,273' MD / 3,233' TVD, the top of the D sand. 30. Mill 6-3/4" window. POOH. 31. Pick up 6-3/4"drilling assembly with LWD and MWD and PWD. RIH. 32. Drill to TD of D sand lateral at +/- 14,457' MD / 3,173'TVD, as per directional plan. 33. POOH, back reaming out of lateral to window. TIH to bottom & displace to solids-free oil based mud. POOH on elevators. 34. RIH with whipstock retrieval tool. Retrieve whipstock and POOH. 35. PU and run 4-1/2" slotted liner. 36. RIH, until liner hanger is just above window. Orient hanger to window and land hanger. 37. Release hanger running tool. POOH. 38. Make up junction isolation / re-entry assembly (Lateral Entry Module or LEM) and RIH to depth. Orient and set packer atop assembly and release from assembly. 39. POOH, laying down drill pipe as required. 40. PU injection completion and RIH to depth. Land tubing. Set BPV. 41. Nipple down BOPE, nipple up tree and test. Pull BPV. 1J-160 PERM/TIT Page 7 of 8 Printed: 29-Jan-07 ORIGINAL • 42. Freeze protect well with diesel. 43. Set BPV and move rig off. A~tion for Permit to Drill, Well 1 J-160 Revision No.O Saved: 29-Jan-07 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well.; Waste fluids generated during the drilling process will be disposed of either by pumping authorized fluids into a permitted annulus on iJ Pad, or by hauling the fluids to a KRU Class II disposal well. All cuttings generated will be disposed of either down a permitted annulus on lJ Pad, hauled to the Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. ConocoPhillips Alaska may in the future request authorization for the use of this well for annular disposal operations. 15. Attachments Attachment 1 Directional Plan Attachment 2 Drilling Hazards Summary Attachment 3 Cement Loads and CemCADE Summary Attachment 4 Well Schematic 1J-160 PERMIT IT Page 8 of 8 Printed: 29-Jan-07 ORIGINAL • ConocoPhillips Alaska • Plan: 1J-160 (wp06) Sperry Drilling Services Proposal Report -Geographic 26 January, 2007 ConocoPhillips Alaska, Inc. Kuparuk River Unit Kuparuk 1J Pad Plan 1J-160 Plan 1J-160 Local Coordinate Origin: Centered on Well Plan 1J-160 Viewing Datum: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) TVDs to System: N North Reference: True Unit System: API - US Survey Feet Sperry ~riliing Services ORIGINAL HAh.LIBURTQN WELL DETAILS: Plan U-160 Ground Level: 8L00 Sperry Drilling Services +N/-S +L'/-W Northing Fasting Latittude Longitude Slot 0.00 0.00 5945827.52 558668b0 70°l5'45.361N 149°3 P32559W FORMATION TOP DETAILS No.TVDPath NDSS MDPath Formation 1 1525.76 1404.76 1667.19 Pfrost 2 1651.58 1530.58 1856.80 T3 3 1939.25 1818.25 2423.51 K15 4 2153.28 2032.28 3317.26 Casing Pt -500 5 2678.05 2557.05 5863.51 Ugnu C G 2861.21 2740.21 6672.60 Ugnu B 7 2923.21 2802.21 6925.75 Ugnu A 8 3086.20 2965.20 7595.32 K 13 SHL - 2016' FSL, 2541' FEL -Sec35-T11 N-R10E 9 3228.00 3107.00 8244.03 W Sak D _ _ _ 10 3279.00 3158.00 8504.39 W Sak C 0 _ _ _ _ - - - - - 11 3303.00 3182.00 8631.13 W Sak B 12 3343.00 3222.00 8851.28 W Sak A4 13 3425.00 3304.00 9340.61 W Sak A3 0° 14 3479.00 3358.00 9828.07 W Sak A2 500- 500 CASING DETAILS 10° No MD TVD TVDss None Si I 14478.35 3407.01 3286.01 41/2" 4-~ 2 9704.44 3472.53 3351.53 9 5/8" 9-~ 1000 1000 3 3317.26 2153.23 2032.28 13 3/8" 13- 30° 1500 1500 -Pfrost- - - - - - - - T3 ------- - ~ 2000 ~ - K15- - - - - - - ~y00 13 3/8" Csg @ 3317' MD, 2153' ND - 1988' FSL, 747' FWL -Sec35-T11 N-R10E L2: BHL @ 14457' MD, 3173' ND - 96' FNL, 1842' FWL - Sec10-T10N-R10E 00 2000 _---- , I o ----------- \ Casing Pt----~ -___ ------------------------z - .~ 3500 ---------- ----------------------------- L L2: 9 5/8" TOW @ 8274' MD, 3234' ND - 791' FSL, 1738' FWL -Sec34-T11 N-R10E ~ ~ n 13 3/8" 4500 ` 0 2500 L1: 9 5/8" TOW @ 8664' MD 3309' ND - 419' FSL, 1651' FWL -Sec34-T11 N-R10E `~ 5500 ~ - ' ~m -UgnuC---- - o---------------,-~~--------------,~=---------------------------------i--------------- - -o o ' - ` _ 1J-160 L2 (wp06) _ _ ~r -Ugnu B- ------------------- 3000 - -UgnuA--- ---~ ---~--- 0 1-------- _,, -==-------------------------------------41/2"--r----~ - _ _ _ _ _ ~ o o ° 0 ~ 1J-160 L1 w 06 3500 - _- ~~ - -----~~-~--- ~ -------~- -W--q =----- - ~ -cfl- ~~ ----~ -- ta, -~ --6~---~-~----Ai 1J-160(wp06)r- -'--~- W Sak A4 9 5/8" TOW i~ `~ o ° o ° i~o o~ ~ o ~ o ' o ~ ` WSak A3 i ~ i ~ t t ' ' `~ 41/2" W Sak A2 1 J-160 D_Top 1/19/07 ,~ 9 5/8" TOW ' ~~ ~ ; ; ~ ' ` 4000 i ~' ~' ~ ~ t i ' ~ ~~ ~ i i ~ ~ ~ i 1J-160Top_B ~ i~ ' ' i t ' ' ~~ i i ~ ~ ~ i ~ ~ ~ ' i~ ~ ~ i t ~ 1J-160A CPOt 10/27/06 1J-160A_CP0310/27/06 ~ 1J-160A CP0510/27/06 ~ 1J-160A CP0710/27/06 , i ` 4500 - - ~ - ~ i ` 1J-160A_CP0210/27/06 1J-160A_CP0410l27/06 1J-160A_CP06 10/27/06 1J-160A CP0810/27/06 ~ 1J-160A_Toe 10/27/06 - i 5000 BHL @ 14478' MD, 3407' ND - 96' FNL, 1842' FWL - Sec10-T10N-R10E 5500 ~~ -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 Vertical Section at 180.00° (1000 ftlin) „_ _ _ _ -'r;,_.,,.__ _ HAt..t. .IBURTON Project: Kuparuk River Unit WELLDETA1LS: elan a-16o Site: Kuparuk 1J Pad Ground Level: 81.00 Sperry Grilling Services Well: Plan 1J-160 +N/-S +F.-~~ Sorthing Easting Latittude Longitude Slot Wellbore: Plan 1J-160 0.00 0.00 $94$827.$2 5$8668.60 70°15'45361 NI49°31'32559W Plan: 1 J-160 (wp06) REFERENCE INFORNIATION Co-ortlinate (N/E) Reference: Well Plan 1J-160, True North 1000 Vertical (TVD) Reference: Doyon 15 (40+61) ~ t21.00ft (Doyon 15 (40+81)) Measuretl Depth Reference: Doyon 15 (40+61) @ 121.OOft (Doyon 15 (40+81)) Calculation Methotl: Minimum Curvature 500 13 3/8" N c o 0 i j r 250 ~ ~ ro c ~ ~ ~ o ~ o ~ -500 ~ ` ~ ` ~o ' ~ SHL-2016 FS4 2541'FEL-Sec35-TlIN-RlOE 9 5/8" TOW ` 13 3/8" Csg rCJ 331 T MD, 2153' TVD - 1988' FSL, 747 FWL -Seca S-TI I N-Rl OE -1000 L2: 9 S/8" TOW ~ 8274' MD, 3234' TVD - 791' FSL, 1738' FWL -Sec34-TI 1 N-RI OE 3Z t 9 5/8" TOW 0 -1500 LI 9 5.8" TOW rr 8664' MD 3309' Tl~'D - 419' FSL, I GS I' FlV'L -Sec34-TI 1 N-RIOE -2000 -2500 9 S 8" ~ ~ -3000 -3500 C o -4000 N ~ -4500 O -5000 7 O -5500 -6000 L2: BHL@14457 MD,3173'TVD-9G'PNh IS42'PWL-Sec10-TION-RIOE -6500 -7000 BHL (r~ 14478' MD, 3407 TVD- 9V' FNL, 1842' FU'L- Sec10-TI ON-RI OE 4 1/2 - _ _ _ T M Azimuths to True North - Magnetic North: 24.65° 07 -7500 1 ~~ t Magnetic Field ~~ ~ 1 . Strength: 57552.4nT IJ-IGOLI(wp06) ~ IJ-160 (~cp06) t Dip Angle: 80.75° -8000 ~ Date: 11 /18/2004 1 Model: BGGM2005 I1-I(0 L2 (wp06) -8500 -9000 CASING DETAILS No MD TVD TVDss Nat11e Size -9500 1 1447835 3407.01 3286.01 41/2" 4-1/2 2 9704.44 3472.53 3351.53 9 5/8" 9-5/8 3 3317.26 2153.28 2032.28 13 3/8" 13-3/8 -10000 -7500 -7000 -6500 -6000 -5500 -5000 -4500 -4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 West(-)/East(+) (1250 ft/in) ~ ConocoPhillips ORIGINAL Car~ocoPhitlips Alaska ! ~ Halliburton Company Planning Report -Geographic ~~.~~~ Sperry Oritling Services Database: ° Compass 2003.11 Local Co-ordinate Reference: Well Plan 1J-160 Company: !;onocoPhillips Alaska, Inc. TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Project: Kuparuk River Unit MD Reference: Doyon 15(40+81) @ 121.OOft (Doyon 15 (40+81)) Site: ~ Kuparuk 1J Pad North Reference: True ' Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature Wellbore: Plan 1J-160 Design: 1J-160 (wp06) Project KuF,anik Eivrr Unit North Slope Alaska, U nited States 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 Well Plan 1J-160 Well Position +N/-S 0.00 ft Northing: 5,945,827.52 ft Latitude: 70° 15' 45.361" N +E/-W 0.00 ft Easting: 558,668.60ft Longitude: 149° 31' 32.559" W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 81.OOft Wellbore m ~ , ,~ ., Plan 1J 1~tb w ~ ~ ~ _ Magnetics Model Name Sample Date Declihation Dip Angle Field Strength bggm2005 11/18/2004 24.65 80.75 57,552 Design 1J-'160 (wpOnr Audit Notes: Version: 31 Phase: PLAN Tie On Depth: 40.00 Vertical Section: Depth From (ND) +N/-S +E!-W Direction (ft) (ft) (ft) (°) 40.00 0.00 0.00 180.00 1/26/2007 3:53:03PM Page 2 of 10 COMPASS 2003.11 Build 48 OR161NAL • Cor~ocoPhi[~~ps Alaska • Halliburton Company .A,L.I.,.~~IJRT`C~I Planning Report -Geographic Sperry Drilling Services Database: Compass 2003.11 Local Co-ordinate Reference: Well Plan 1J-160 Company: ConoeoPhillips Alas ka, Inc. TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Project: Kuparuk River Unit M D Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site: Kuparuk 1J Pad North Reference: True Well: Plan 1J-160 Survey Calculatio n Method: Minimum C urvature Wellbore: Plan 1 J-160 Design: 1J-16 0 (wp06) Plan Summary Measured Vertical Dogleg Build Turn Depth inclination Azimuth Depth +N/_g +E/-W Rate Rate Rate TFO (ft) (~) (°) (ft) (ft) (ft) (°1100ft) (°/100ft) (°/100ft) (~) 40.00 0.00 0.00 40.00 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 0.00 702.06 10.05 267.00 700.00 -1.84 -35.13 2.50 2.50 0.00 267.00 1,629.32 47.14 267.00 1,500.00 -24.67 -470.64 4.00 4.00 0.00 0.00 1,729.32 47.14 267.00 1,568.02 -28.50 -543.85 0.00 0.00 0.00 0.00 2,768.31 78.11 271.11 2,040.14 -38.82 -1,454.97 3.00 2.98 0.40 7.79 5,904.98 78.11 271.11 2,686.60 20.77 -4,523.72 0.00 0.00 0.00 0.00 8,219.03 78.50 200.00 3,223.02 -1,172.34 -6,261.45 3.00 0.02 -3.07 -97.96 8,244.03 78.50 200.00 3,228.00 -1,195.36 -6,269.83 0.00 0.00 0.00 0.00 9,035.32 80.47 175.93 3,374.47 -1,959.86 -6,376.28 3.00 0.25 -3.04 -87.53 9,479.48 80.47 175.93 3,447.99 -2,396.78 -6,345.21 0.00 0.00 0.00 0.00 9,704.63 87.00 177.68 3,472.54 -2,620.12 -6,332.77 3.00 2.90 0.78 15.01 9,904.63 87.00 177.68 3,483.01 -2,819.68 -6,324.68 0.00 0.00 0.00 0.00 10,112.11 93.22 177.68 3,482.60 -3,026.88 -6,316.29 3.00 3.00 0.00 0.04 10,336.02 93.22 177.68 3,470.01 -3,250.26 -6,307.26 0.00 0.00 0.00 0.00 10,611.98 90.52 178.23 3,460.99 -3,525.86 -6,297.45 1.00 -0.98 0.20 168.49 10,940.80 90.52 178.23 3,458.01 -3,854.52 -6,287.32 0.00 0.00 0.00 0.00 10,980.62 90.90 178.11 3,457.51 -3,894.31 -6,286.05 1.00 0.95 -0.32 -18.76 11,460.12 90.90 178.11 3,450.01 -4,373.49 -6,270.21 0.00 0.00 0.00 0.00 11,464.11 90.86 178.11 3,449.95 -4,377.48 -6,270.08 1.00 -0.99 0.10 174.04 12,061.48 90.86 178.11 3,441.01 -4,974.46 -6,250.39 0.00 0.00 0.00 0.00 12,196.90 89.50 178.07 3,440.58 -5,109.80 -6,245.88 1.00 -1.00 -0.03 -178.37 12,592.57 89.50 178.07 3,444.01 -5,505.23 -6,232.57 0.00 0.00 0.00 0.00 12,655.37 90.13 178.05 3,444.21 -5,568.00 -6,230.45 1.00 1.00 -0.04 -2.08 13,178,55 90.13 178.05 3,443.01 -6,090.87 -6,212.64 0.00 0.00 0.00 0.00 13,323.18 93.02 178.14 3,439.03 -6,235.35 -6,207.84 2.00 2.00 0.06 1.84 13,759.76 93.02 178.14 3,416.01 -6,671.09 -6,193.71 0.00 0.00 0.00 0.00 13,886.14 90.50 178.10 3,412.13 -6,797.33 -6,189.57 2.00 -2.00 -0.03 -179.10 14,478.56 90.50 178.10 3,407.01 -7,389.41 -6,169.96 0.00 0.00 0.00 0.00 1/26/2007 3:53:03PM Page 3 of 10 COMPASS 2003.11 Build 48 ORIGINAL • ~O©~ll~~t~S Alaska • Halliburton Company IF~~E..I~l1 '1`G'~N Planning Report -Geographic g~y~.~„y Q~iliing 8ervicr~ Database: Company: Project: Site: Well: Wellbore: Design: Planned Survey Compass 2003.11 !~onocoPhillips Alaska, Inc Kuparuk River Unit Kuparuk 1J Pad Plan 1 J-160 Plan 1J-160 1J-160 n~~~p0~_;i 1 J-1 EO (wp06) ' Map Map MD .Inclination Azimuth TVD SSTVD +N/-S +E/_y~ Northing Easting DLSEV Vert Section (ft) (`) (~) (ft) (ft) (ft) (ft- ~~~ eft) (`1100ft) (ft) 40.00 0.00 0.00 40.00 -81.00 0.00 0.00 5,945,827.52 558,668.60 0.00 0.00 SHL - 2016' FSL, 2541' FEL - Sec35-T11 N-R10E 100.00 0.00 0.00 100.00 -21.00 0.00 0.00 5,945,827.52 558,668.60 0.00 0.00 200.00 0.00 0.00 200.00 79.00 0.00 0.00 5,945,827.52 558,668.60 0.00 0.00 300.00 0.00 0.00 300.00 179.00 0.00 0.00 5,945,827.52 558,668.60 0.00 0.00 400.00 2.50 267.00 399.97 278.97 -0.11 -2.18 5,945,827.39 558,666.42 2.50 0.11 500.00 5.00 267.00 499.75 378.75 -0.46 -8.71 5,945,827.00 558,659.90 2.50 0.46 600.00 7.50 267.00 599.14 478.14 -1.03 -19.58 5,945,826.34 558,649.03 2.50 1.03 700.00 10.00 267.00 697.97 576.97 -1.82 -34.77 5,945,825.43 558,633.85 2.50 1.82 702.06 10.05 267.00 700.00 579.00 -1.84 -35.13 5,945,825.41 558,633.49 2.50 1.84 800.00 13.97 267.00 795.78 674.78 -2.91 -55.48 5,945,824.18 558,613.15 4.00 2.91 900.00 17.97 267.00 891.90 770.90 -4.35 -82.94 5,945,822.53 558,585.70 4.00 4.35 1,000.00 21.97 267.00 985.87 864.87 -6.13 -117.04 5,945,820.47 558,551.62 4.00 6.13 1,100.00 25.97 267.00 1,077.23 956.23 -8.26 -157.60 5,945,818.03 558,511.08 4.00 8.26 1,200.00 29.97 267.00 1,165.53 1,044.53 -10.71 -204.43 5,945,815.22 558,464.28 4.00 10.71 1,300.00 33.97 267.00 1,250.34 1,129.34 -13.48 -257.29 5,945,812.03 558,411.45 4.00 13.48 1,400.00 37.97 267.00 1,331.26 1,210.26 -16.56 -315.93 5,945,808.50 558,352.84 4.00 16.56 1,500.00 41.97 267.00 1,407.89 1,286.89 -19.92 -380.07 5,945,804.64 558,288.73 4.00 19.92 1,600.00 45.97 267.00 1,479.84 1,358.84 -23.55 -449.39 5,945,800.47 558,219.45 4.00 23.55 1,629.32 47.14 267.00 1,500.00 1,379.00 -24.67 -470.64 5,945,799.19 558,198.21 4.00 24.67 1,667.19 47.14 267.00 1,525.76 1,404.76 -26.12 -498.36 5,945,797.52 558,170.50 0.00 26.12 Pfrost 1,700.00 47.14 267.00 1,548.08 1,427.08 -27.38 -522.39 5,945,796.08 558,146.49 0.00 27.38 1,729.32 47.14 267.00 1,568.02 1,447.02 -28.50 -543.85 5, 945, 794.78 558,125.04 0.00 28.50 1,800.00 49.24 267.38 1,615.14 1,494.14 -31.08 -596.47 5,945,791.80 558,072.45 3.00 31.08 1,856.80 50.93 267.67 1,651.58 1,530.58 -32.96 -639.99 5,945,789.57 558,028.95 3.00 32.96 T3 1,900.00 52.22 267.88 1,678.43 1,557.43 -34.28 -673.81 5,945,788.00 557,995.14 3.00 34.28 2,000.00 55.20 268.34 1,737.61 1,616.61 -36.93 -754.36 5,945,784.71 557,914.63 3.00. 36.93 2,100.00 58.17 268.76 1,792.53 1,671.53 -39.04 -837.89 5,945,781.95 557,831.13 3.00 39.04 2,200.00 61.15 269.16 1,843.03 1,722.03 -40.60 -924.17 5,945,779.73 557,744.87 3.00 40.60 2,300.00 64.14 269.54 1,888.98 1,767.98 -41.60 -1,012.97 5,945,778.04 557,656.08 3.00 41.60 2,400.00 67.12 269.90 1,930.24 1,809.24 -42.04 -1,104.05 5,945,776.89 557,565.02 3.00 42.04 2,423.51 67.82 269.98 1,939.25 1,818.25 -42.06 -1,125.76 5,945,776.70 557,543.31 3.00 42.06 K15 2,500.00 70.10 270.25 1,966.71 1,845.71 -41.91 -1,197.15 5,945,776.28 557,471.93 3.00 41.91 2,600.00 73.08 270.58 1,998.29 1,877.29 -41.23 -1,292.02 5,945,776.23 557,377.07 3.00 41.23 2,700.00 76.07 270.90 2,024.88 1,903.88 -39.99 -1,388.40 5,945,776.72 557,280.69 3.00 39.99 2,768.31 78.11 271.11 2,040.14 1,919.14 -38.82 -1,454.97 5,945,777.37 557,214.12 3.00 38.82 2,800.00 78.11 271.11 2,046.67 1,925.67 -38.22 -1,485.97 5,945,777.73 557,183.12 0.00 38.22 2,900.00 78.11 271.11 2,067.28 1,946.28 -36.32 -1,583.80 5,945,778.87 557,085.28 0.00 36.32 3,000.00 78.11 271.11 2,087.89 1,966.89 -34.42 -1,681.64 5,945,780.00 556,987.45 0.00 34.42 3,100.00 78.11 271.11 2,108.50 1,987.50 -32.52 -1,779.47 5,945,781.14 556,889.61 0.00 32.52 3,200.00 78.11 271.11 2,129.11 2,008.11 -30.62 -1,877.31 5,945,782.28 556,791.77 0.00 30.62 3,300.00 78.11 271.11 2,149.72 2,028.72 -28.72 -1,975.14 5,945,783.42 556,693.93 0.00 28.72 1/26/2007 3:53:03PM Page 4 of 10 COMPASS 2003.11 Build 48 Local Co-ordinate Reference: Well Plan 1J-160 TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) North Reference: True - Survey Calculation Method:. Minimum Curvature . ORIGINAL • '`~'"`' ~ ~ ~~ Halliburton Comp any HAelb„L~BII,Jt~'i'"€~t\1 df~ ~ 1E 1~?S ,~ Planning Report -Geog raphic Sperry E3ri lting S®rv~ces D base: Compass 2003.1 1 Local Co-o rdinate Reference: =Well Plan 1J-160 Company: ConocoPhillips A laska, Inc. TVD Reference: Doyo n 15 (40+81) @ 121 .OOft (Doyon 15 (40+81)) Project: .Ku paruk River Un it MD Refere nce: Doyo n 15 (40+81) @ 121 .OOft (Doyon 15 (40+81)) Site: K uparuk 1J Pad North Refe rence: True i Well: Pl an 1J-160 Survey Cal culation Meth Minim od: um Curvature Wellbore: Pl an 1J-160 . Design: 1J -160 (wp06) - Planned Survey 1J-160 (wp 06) Map Map MD Inclination Azimuth TVD SSTVD +N/-S +E/-W Northing Easting DLSEV Vert Section (ft) (`~) (°) (ft) (ftl (ft) (ft) (ft) (ft) (°I100ft) lftl 3,317.26 78.11 271.11 2,153.28 2,032.28 -28.39 -1,992.03 5,945,783.61 556,677.05 0.00 28.39 13 3/8" Csg @ 3317' MD, 2153' TVD -1988' FSL, 747' FWL - Sec35-T11 N-R10E -Cas ing Pt -13 3/8" 3,400.00 78.11 271.11 2,170.33 2,049.33 -26.82 -2,072.98 5,945,784.55 556,596.10 0.00 26.82 3,500.00 78.11 271.11 2,190.94 2,069.94 -24.92 -2,170.81 5,945,785.69 556,498.26 0.00 24.92 3,600.00 78.11 271.11 2,211.55 2,090.55 -23.02 -2,268.65 5,945,786.83 556,400.42 0.00 23.02 3,700.00 78.11 271.11 2,232.16 2,111.16 -21.12 -2,366.48 5,945,787.96 556,302.59 0.00 21.12 3,800.00 78.11 271.11 2,252.77 2,131.77 -19.22 -2,464.32 5,945,789.10 556,204.75 0.00 19.22 3,900.00 78.11 271.11 2,273.38 2,152.38 -17.32 -2,562.15 5,945,790.24 556,106.91 0.00 17.32 4,000.00 78.11 271.11 2,293.99 2,172.99 -15.42 -2,659.99 5,945,791.38 556,009.08 0.00 15.42 4,100.00 78.11 271.11 2,314.60 2,193.60 -13.52 -2,757.82 5,945,792.51 555,911.24 0.00 13.52 4,200.00 78.11 271.11 2,335.21 2,214.21 -11.62 -2,855.66 5,945,793.65 555,813.40 0.00 11.62 4,300.00 78.11 271.11 2,355.82 2,234.82 -9.72 -2,953.49 5,945,794.79 555,715.56 0.00 9.72 4,400.00 78.11 271.11 2,376.43 2,255.43 -7.82 -3,051.33 5,945,795.92 555,617.73 0.00 7.82 4,500.00 78.11 271.11 2,397.04 2,276.04 -5.92 -3,149.16 5,945,797.06 555,519.89 0.00 5.92 4,600.00 78.11 271.11 2,417.65 2,296.65 -4.02 -3,246.99 5,945,798.20 555,422.05 0.00 4.02 4,700.00 78.11 271.11 2,438.26 2,317.26 -2.12 -3,344.83 5,945,799.34 555,324.22 0.00 2.12 4,800.00 78.11 271.11 2,458.87 2,337.87 -0.23 -3,442.66 5,945,800.47 555,226.38 0.00 0.22 4,900.00 78.11 271.11 2,479.48 2,358.48 1.67 -3,540.50 5,945,801.61 555,128.54 0.00 -1.67 5,000.00 78.11 271.11 2,500.08 2,379.08 3.57 -3,638.33 5,945,802.75 555,030.71 0.00 -3.57 5,100.00 78.11 271.11 2,520.69 2,399.69 5.47 -3,736.17 5,945,803.88 554,932.87 0.00 -5.47 5,200.00 78.11 271.11 2,541.30 2,420.30 7.37 -3,834.00 5,945,805.02 554,835.03 0.00 -7.37 5,300.00 78.11 271.11 2,561.91 2,440.91 9.27 -3,931.84 5,945,806.16 554,737.19 0.00 -9.27 5,400.00 78.11 271.11 2,582.52 2,461.52 11.17 -4,029.67 5,945,807.30 554,639.36 0.00 -11.17 5,500.00 78.11 271.11 2,603.13 2,482.13 13.07 -4,127.51 5,945,808.43 554,541.52 0.00 -13.07 5,600.00 78.11 271.11 2,623.74 2,502.74 14.97 -4,225.34 5,945,809.57 554,443.68 0.00 -14.97 5,700.00 78.11 271.11 2,644.35 2,523.35 16.87 -4,323.18 5,945,810.71 554,345.85 0.00 -16.87 5,800.00 78.11 271.11 2,664.96 2,543.96 18.77 -4,421.01 5,945,811.85 554,248.01 0.00 -18.77 5,863.51 78.11 271.11 2,678.05 2,557.05 19.98 -4,483.15 5,945,812.57 554,185.87 0.00 -19.98 Ugnu C 5,900.00 78.11 271.11 2,685.57 2,564.57 20.67 -4,518.85 5,945,812.98 554,150.17 0.00 -20.67 5,904.98 78.11 271.11 2,686.60 2,565.60 20.77 -4,523.72 5,945,813.04 554,145.30 0.00 -20.77 6,000.00 77.73 268.22 2,706.49 2,585.49 .20.23 -4,616.62 5,945,811.78 554,052.41 3.00 -20.23 6,100.00 77.36 265.17 2,728.07 2,607.07 14.61 -4,714.09 5,945,805.40 553,955.00 3.00 -14.61 6,200.00 77.03 262.12 2,750.24 2,629.24 3.82 -4,810.99 5,945,793.86 553,858.20 3.00 -3.82 6,300.00 76.73 259.05 2,772.95 2,651.95 -12.11 -4,907.06 5,945,777.18 553,762.27 3.00 12.11 6,400.00 76.47 255.98 2,796.13 2,675.13 -33.14 -5,002.02 5,945,755.42 553,667.48 3.00 33.14 6,500.00 76.25 252.90 2,819.72 2,698.72 -59.20 -5,095.63 5,945,728.63 553,574.09 3.00 59.20 6,600.00 76.06 249.82 2,843.65 2,722.65 -90.23 -5,187.61 5,945,696.88 553,482.35 3.00 90.23 6,672.60 75.95 247.57 2,861.21 2,740.21 -115.83 -5,253.24 5,945,670.78 553,416.93 3.00 115.83 Ugnu B 6,700.00 75.92 246.73 2,867.87 2,746.87 -126.15 -5,277.73 5,945,660.27 553,392.53 3.00 126.15 6,800.00 75.81 243.64 2,892.30 2,771.29 -166.84 -5,365.74 5,945,618.89 553,304.85 3.00 166.84 6,900.00 75.75 240.54 2,916.87 2,795.87 -212.21 -5,451.39 5,945,572.86 553,219.57 3.00 212.21 6,925.75 75.73 239.74 2,923.21 2,802.21 -224.64 -5,473.03 5,945,560.27 553,198.02 3.00 224.64 Ugnu A 7,000.00 75.72 237.45 2,941.52 2,820.52 -262.13 -5,534.44 5,945,522.31 553,136.91 3.00 262.13 1/26/2007 3:53:03PM Page 5 of 10 COMPASS 2003.11 Build 48 ORIGINAL • CC}I'N~tOp"~'11 ~~1 ~5 Alaska • Halliburton Company I~~-,t..~.iE3U'TC~ Planning Report -Geographic g~6e~.y Ciriliing Services Database: Company: Project: Site: Well: Wellbore: Design: Compass 2003.11 ConocoPhillips Alaska, Inc. Kuparuk RiverUnit Kuparuk 1J Pad Plan 1J-160 Plan 1J-160 1J-160(wp06) Local Co-ordinate Reference: Well Plan 1J-160 TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey 1J-160 (wp06) Map Map MD Inclination Azimuth TVD SSTVD +N/-S +E/-W Northing Fasting DLSEV Vert Section (ft) (,) (°) (ft) (ft) {ft) (ft) (ft) j~) (°I100ft) (ft) 7,100.00 75.73 234.35 2,966.18 2,845.18 -316.46 -5,614.68 5,945,467.36 553,057.11 3.00 316.46 7,200.00 75.79 231.26 2,990.79 2,869.79 -375.05 -5,691.88 5,945,408.18 552,980.37 3.00 375.05 7,300.00 75.88 228.16 3,015.27 2,894.27 -437.74 -5,765.83 5,945,344.92 552,906.93 3.00 437.74 7,400.00 76.01 225.07 3,039.56 2,918.56 -504.36 -5,836.32 5,945,277.76 552,836.96 3.00 504.36 7,500.00 76.18 221.99 3,063.59 2,942.59 -574.72 -5,903.17 5,945,206.88 552,770.67 3.00 574.72 7,595.32 76.38 219.05 3,086.20 2,965.20 -645.11 -5,963.32 5,945,136.04 552,711.07 3.00 645.11 K13 7,600.00 76.39 218.91 3,087.30 2,966.30 -648.65 -5,966.19 5,945,132.48 552,708.23 3.00 648.65 7,700.00 76.64 215.83 3,110.62 2,989.62 -725.92 -6,025.20 5,945,054.75 552,649.83 3.00 725.92 7,800.00 76.93 212.77 3,133.49 3,012.49 -806.33 -6,080.05 5,944,973.92 552,595.61 3.00 806.33 7,900.00 77.25 209.71 3,155.84 3,034.84 -889.66 -6,130.59 5,944,890.21 552,545.73 3.00 889.66 8,000.00 77.60 206.65 3,177.62 3,056.62 -975.68 -6,176.67 5,944,803.84 552,500.32 3.00 975.68 8,100.00 77.99 203.61 3,198.76 3,077.76 -1,064.16 -6,218.18 5,944,715.05 552,459.51 3.00 1,064.16 8,198.96 78.41 200.61 3,219.00 3,098.00 -1,153.90 -6,254.63 5,944,625.04 552,423.76 3.00 1,153.90 1J-160 D_Top 10/27/06 8,200.00 78.42 200.58 3,219.21 3,098.21 -1,154.85 -6,254.99 5,944,624.09 552,423.41 3.00 1,154.85 8,219.03 78.50 200.00 3,223.02 3,102.02 -1,172.34 -6,261.45 5,944,606.55 552,417.09 3.00 1,172.34 8,244.03 78.50 200.00 3,228.00 3,107.00 -1,195.36 -6,269.83 5,944,583.47 552,408.89 0.00 1,195.36 W Sak D - 1J-160 D_Top 1119/07 8,300.00 78.58 198.29 3,239.12 3,118.12 -1,247.18 -6,287.82 5,944,531.51 552,391.31 3.00 1,247.18 8,400.00 78.74 195.23 3,258.79 3,137.79 -1,341.05 -6,316.09 5,944,437.44 552,363.77 3.00 1,341.05 8,500.00 78.93 192.18 3,278.16 3,157.16 -1,436.35 -6,339.33 5,944,341.97 552,341.27 3.00 1,436.35 8,504.39 78.94 192.05 3,279.00 3,158.00 -1,440.56 -6,340.24 5,944,337.74 552,340.40 3.00 1,440.56 W Sak C 8,596.51 79.15 189.24 3,296.51 3,175.51 -1,529.43 -6,356.94 5,944,248.76 552,324.39 3.00 1,529.43 1J-160 Top_B 8,600.00 79.16 189.13 3,297.16 3,176.16 -1,532.82 -6,357.49 5,944,245.36 552,323.87 3.00 1,532.82 8,631.13 79.23 188.19 3,303.00 3,182.00 -1,563.06 -6,362.09 5,944,215.10 552,319.50 3.00 1,563.06 W Sak B 8,700.00 79.41 186.09 3,315.76 3,194.76 -1,630.20 -6,370.50 5,944,147.90 552,311.62 3.00 1,630.20 8,800.00 79.70 183.06 3,333.90 3,212.89 -1,728.22 -6,378.34 5,944,049.83 552,304.54 3.00 1,728.22 8,851.28 79.85 181.50 3,343.00 3,222.00 -1,778.65 -6,380.35 5,943,999.39 552,302.93 3.00 1,778.65 W Sak A4 8,900.00 80.01 180.02 3,351.52 3,230.52 -1,826.61 -6,380.99 5,943,951.44 552,302.66 3.00 1,826.61 9,000.00 80.35 177.00 3,368.58 3,247.58 -1,925.09 -6,378.43 5,943,852.98 552,305.99 3.00 1,925.09 9,035.32 80.47 175.93 3,374.47 3,253.47 -1,959.86 -6,376.28 5,943,818.24 552,308.41 3.00 1,959.86 9,100.00 80.47 175.93 3,385.17 3,264.17 -2,023.48 -6,371.76 5,943,754.66 552,313.43 0.00 2,023.48 9,200.00 80.47 175.93 3,401.73 3,280.73 -2,121.85 -6,364.76 5,943,656.35 552,321.19 0.00 2,121.85 9,300.00 80.47 175.93 3,418.28 3,297.28 -2,220.22 -6,357.76 5,943,558.05 552,328.95 0.00 2,220.22 9,340.61 80.47 175.93 3,425.00 3,304.00 -2,260.18 -6,354.92 5,943,518.12 552,332.10 0.00 2,260.18 W Sak A3 9,400.00 80.47 175.93 3,434.83 3,313.83 -2,318.60 -6,350.77 5,943,459.74 552,336.71 0.00 2,318.60 9,479.48 80.47 175.93 3,447.99 3,326.99 -2,396.78 -6,345.21 5,943,381.61 552,342.88 0.00 2,396.78 9,500.00 81.07 176.09 3,451.28 3,330.28 -2,416.99 -6,343.80 5,943,361.42 552,344.45 3.00 2,416.99 1/26/2007 3:53:03PM Page 6 of 10 COMPASS 2003.11 Build 48 IL~I... ConoccPhiflips Alaska Halliburton Company Planning Report -Geographic • ~~L~>e~URTON Spero-y Ori!ling services Database: Compass 2003.11 Local Co-ordinate Reference: Well Plan 1J-160 Company: ConocoPhillips Alaska, Inc. TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Project: Kuparuk River Unit MD Reference; Doyon 15 (40+81) @ 121AOft (Doyon 15 (40+81)) Site: Kuparuk 1J Pad North Reference:. True Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature Wellbore: Plan 1J-160 Design: 1J-160 (wp06) ~'~ Planned Survey 1J-160 (wp06) Map Map MD Inclination Azimuth TVD SSTVD +N!-S +EI-W Northing Fasting DLSEV Vert Section (ft) (') (°) (~) (ft) ~h) (ft) (ft) (ft) (°I100ft) (ft) 9,600.00 83.97 176.87 3,464.30 3,343.30 -2,515.94 -6,337.72 5,943,262.53 552,351.30 3.00 2,515.94 9,700.00 86.87 177.64 3,472.29 3,351.29 -2,615.49 -6,332.95 5,943,163.02 552,356.84 3.00 2,615.49 9,704.44 86.99 177.68 3,472.53 3,351.53 -2,619.92 -6,332.77 5,943,158.60 552,357.05 3.00 2,619.92 9 5/8" Csg @ 9704' MD, 3473' TVD - 606' FNL, 1684' FWL - Sec03-T10N -ROE - 9 518" 9,704.63 87.00 177.68 3,472.54 3,351.54 -2,620.12 -6,332.77 5,943,158.40 552,357.06 3.00 2,620.11 9,800.00 87.00 177.68 3,477.53 3,356.53 -2,715.27 -6,328.91 5,943,063.29 552,361.66 0.00 2,715.27 9,828.07 87.00 177.68 3,479.00 3,358.00 -2,743.29 -6,327.78 5,943,035.29 552,363.01 0.00 2,743.29 W Sak A2 9,900.00 87.00 177.68 3,482.76 3,361.76 -2,815.05 -6,324.87 5,942,963.55 552,366.48 0.00 2,815.05 9,904.63 87.00 177.68 3,483.01 3,362.01 -2,819.68 -6,324.68 5,942,958.93 552,366.70 0.00 2,819.68 1J-160 A CP01 10/27/06 10,000.00 89.86 177.68 3,485.62 3,364.62 -2,914.92 -6,320.82 5,942,863.73 552,371.30 3.00 2,914.92 10,100.00 92.86 177.68 3,483.24 3,362.24 -3,014.80 -6,316.78 5,942,763.89 552,376.12 3.00 3,014.80 10,112.11 93.22 177.68 3,482.60 3,361.60 -3,026.88 -6,316.29 5,942,751.82 552,376.70 3.00 3,026.88 10,200.00 93.22 177.68 3,477.66 3,356.66 -3,114.56 -6,312.75 5,942,664.18 552,380.93 0.00 3,114.56 10,300.00 93.22 177.68 3,472.03 3,351.03 -3,214.32 -6,308.72 5,942,564.46 552,385.74 0.00 3,214.32 10,336.02 93.22 177,68 3,470.01 3,349.01 -3,250.26 -6,307.26 5,942,528.54 552,387.47 0.00 3,250.26 1J-160 A CP02 10/27/06 10,400.00 92.60 177.81 3,466.76 3,345.76 -3,314.10 -6,304.75 5,942,464.72 552,390.48 1.00 3,314.10 10,500.00 91.62 178.01 3,463.08 3,342.08 -3,413.97 -6,301.11 5,942,364.90 552,394.90 1.00 3,413.97 10,600.00 90.64 178.21 3,461.11 3,340.11 -3,513.89 -6,297.82 5,942,265.01 552,398.97 1.00 3,513.89 10,611.98 90.52 178.23 3,460.99 3,339.99 -3,525.86 -6,297.45 5,942,253.05 552,399.43 1.00 3,525.86 10,700.00 90.52 178.23 3,460.19 3,339.19 -3,613.84 -6,294.73 5,942,165.10 552,402.83 0.00 3,613.84 10,800.00 90.52 178.23 3,459.29 3,338.28 -3,713.79 -6,291.65 5,942,065.19 552,406.69 0.00 3,713.79 10,900.00 90.52 178.23 3,458.38 3,337.38 -3,813.74 -6,288.57 5,941,965.28 552,410.55 0.00 3,813.74 10,940.80 90.52 178.23 3,458.01 3,337.01 -3,854.52 -6,287.32 5,941,924.51 552,412.12 0.00 3,854.52 1J-160 A CP03 10/27/06 10,980.62 90.90 178.11 3,457.51 3,336.51 -3,894.31 -6,286.05 5,941,884.74 552,413.70 1.00 3,894.31 11,000.00 90.90 178.11 3,457.21 3,336.21 -3,913.68 -6,285.41 5,941,865.37 552,414.49 0.00 3,913.68 11,100.00 90.90 178.11 3,455.65 3,334.65 -4,013.61 -6,282.10 5,941,765.48 552,418.57 0.00 4,013.61 11,200.00 90.90 178.11 3,454.08 3,333.08 -4,113.55 -6,278.80 5,941,665.58 552,422.65 0.00 4,113.55 11,300.00 90.90 178.11 3,452.51 3,331.51 -4,213.48 -6,275.50 5,941,565.69 552,426.74 0.00 4,213.48 11,400.00 90.90 178.11 3,450.95 3,329.95 -4,313.41 -6,272.19 5,941,465.79 552,430.82 0.00 4,313.41 11,460.12 90.90 178.11 3,450.01 3,329.01 -4,373.49 -6,270.21 5,941,405.74 552,433.27 0.00 4,373.49 1J-160 A CP04 10!27/06 11,464.11 90.86 178.11 3,449.95 3,328.95 -4,377.48 -6,270.08 5,941,401.75 552,433.43 1.00 4,377.48 11,500.00 90.86 178.11 3,449.41 3,328.41 -4,413.35 -6,268.89 5,941,365.90 552,434.89 0.00 4,413.35 11,600.00 90.86 178.11 3,447.91 3,326.91 -4,513.28 -6,265.60 5,941,266.00 552,438.97 0.00 4,513.28 11,700.00 90.86 178.11 3,446.42 3,325.42 -4,613.22 -6,262.30 5,941,166.11 552,443.04 0.00 4,613.22 11,800.00 90.86 178.11 3,444.92 3,323.92 -4,713.15 -6,259.01 5,941,066.21 552,447.12 0.00 4,713.15 11,900.00 90.86 178.11 3,443.42 3,322.42 -4,813.09 -6,255.71 5,940,966.32 552,451.19 0.00 4,813.09 12,000.00 90.86 178.11 3,441.93 3,320.93 -4,913.02 -6,252.41 5,940,866.42 552,455.27 0.00 4,913.02 12,061.48 90.86 178.11 3,441.01 3,320.01 -4,974.46 -6,250.39 5,940,805.00 552,457.77 0.00 4,974.46 1J-160 A CP05 10/27/06 12,100.00 90.47 178.10 3,440.56 3,319.56 -5,012.96 -6,249.12 5,940,766.52 552,459.34 1.00 5,012.96 1/26/2007 3:53:03PM Page 7 of 10 COMPASS 2003.11 Build 48 Q~~~INAL ~, Caru~coPhi[~ips Alaska Halliburton Company Planning Report -Geographic • Sperry Driiling Services Database: Compass 2003.11 Local Co-ordinate Reference: Well Plan 1J-160 Company: ConocoPhiHips Alaska, Inc. TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Project: Kuparuk River Unit MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site: Kuparuk 1J Pad North Reference: True Well: Plan 1J-160 Survey Calculation Methods: Minimum Curvature Wellbore: Plan 1J-160 Design: I J-160'(wp~F, Planned Survey 1J-160 (wp06) MD Inclination Azimuth: TVD SSTVD +N/-S +E/-W (ftl (~) (~) (ft- (ft) (ft) (ft) 12,196.90 89.50 178.07 3,440.58 3,319.58 -5,109.80 -6,245.88 12,200.00 89.50 178.07 3,440.61 3,319.61 -5,112.90 -6,245.77 12,300.00 89.50 178.07 3,441.47 3,320.47 -5,212.84 -6,242.41 12,400.00 89.50 178.07 3,442.34 3,321.34 -5,312.78 -6,239.05 12,500.00 89.50 178.07 3,443.21 3,322.20 -5,412.72 -6,235.68 12,592.57 89.50 178.07 3,444.01 3,323.01 -5,505.23 -6,232.57 1J-160 A CP06 10/27/06 12,600.00 89.58 178.07 3,444.07 3,323.07 -5,512.66 -6,232.32 12,655.37 90.13 178.05 3,444.21 3,323.21 -5,568.00 -6,230.45 12,700.00 90.13 178.05 3,444.10 3,323.10 -5,612.60 -6,228.93 12,800.00 90.13 178.05 3,443.88 3,322.87 -5,712.54 -6,225.52 12,900.00 90.13 178.05 3,443.65 3,322.65 -5,812.48 -6,222.12 13,000.00 90.13 178.05 3,443.42 3,322.42 -5,912.42 -6,218.72 13,100.00 90.13 178.05 3,443.19 3,322.19 -6,012.37 -6,215.31 13,178.55 90.13 178.05 3,443.01 3,322.01 -6,090.87 -6,212.64 1J-160 A CP07 10/27!06 13,200.00 90.56 178.06 3,442.88 3,321.88 -6,112.31 -6,211.91 13,300.00 92.56 178.13 3,440.16 3,319.16 -6,212.21 -6,208.59 13,323.18 93.02 178.14 3,439.03 3,318.03 -6,235.35 -6,207.84 13,400.00 93.02 178.14 3,434.98 3,313.98 -6,312.02 -6,205.35 13,500.00 93.02 178.14 3,429.70 3,308.70 -6,411.83 -6,202.12 13,600.00 93.02 178.14 3,424.43 3,303.43 -6,511.64 -6,198.88 13,700.00 93.02 178.14 3,419.16 3,298.16 -6,611.45 -6,195.64 13,759.76 93.02 178.14 3,416.01 3,295.01 -6,671.09 -6,193.71 1J-160 A CP08 10/27(06 13,800.00 92.22 178.13 3,414.17 3,293.17 -6,711.27 -6,192.40 13,886.14 90.50 178.10 3,412.13 3,291.13 -6,797.33 -6,189.57 13,900.00 90.50 178.10 3,412.01 3,291.01 -6,811.19 -6,189.11 14,000.00 90.50 178.10 3,411.14 3,290.14 -6,911.13 -6,185.80 14,100.00 90.50 178.10 3,410.28 3,289.28 -7,011.07 -6,182.49 14,200.00 90.50 178.10 3,409.41 3,288.41 -7,111.01 -6,179.18 14,300.00 90.50 178.10 3,408.55 3,287.55 -7,210.95 -6,175.87 14,400.00 90.50 178.10 3,407.69 3,286.69 -7,310.90 -6,172.56 14,478.36 90.50 178.10 3,407.01 3,286.01 -7,389.21 -6,169.97 BHL @ 14478' MD, 3407 ' TVD - 96' FNL, 1842' FWL - Sec10-T10N-R10E - 4 1/2" 14,478.56 90.50 178.10 3,407.01 3,286.01 -7,389.41 -6,169.96 1J-160 A Toe 10/27!06 Map Map Northing Easting DLSEV Vert Section (ft) (ft) ('I100ft) (ft) 5,940,669.71 552,463.33 1.00 5,109.80 5,940,666.62 552,463.46 0.00 5,112.90 5,940,566.72 552,467.60 0.00 5,212.84 5,940,466.82 552,471.74 0.00 5,312.78 5,940,366.92 552,475.89 0.00 5,412.72 5,940,274.44 552,479.72 0.00 5,505.23 5,940,267.02 552,480.03 1.00 5,512.66 5,940,211.70 552,482.33 1.00 5,568.00 5,940,167.11 552,484.20 0.00 5,612.60 5,940,067.21 552,488.38 0.00 5,712.54 5,939,967.31 552,492.56 0.00 5,812.48 5,939,867.41 552,496.74 0.00 5,912.42 5,939,767.50 552,500.93 0.00 6,012.37 5,939,689.03 552,504.21 0.00 6,090.87 5,939,667.60 552,505.10 2.00 6,112.31 5,939,567.74 552,509.20 2.00 6,212.21 5,939,544.60 552,510.14 2.00 6,235.35 5,939,467.96 552,513.22 0.00 6,312.02 5,939,368.19 552,517.23 0.00 6,411.83 5,939,268.42 552,521.25 0.00 6,511.64 5,939,168.65 552,525.26 0.00 6,611.45 5,939,109.03 552,527.66 0.00 6,671.09 5,939,068.87 552,529.28 2.00 6,711.27 5,938,982.84 552,532.78 2.00 6,797.33 5,938,968.99 552,533.35 0.00 6,811.19 5,938,869.08 552,537.44 0.00 6,911.13 5,938,769.18 552,541.52 0.00 7,011.07 5,938,669.28 552,545.61 0.00 7,111.01 5,938,569.38 552,549.70 0.00 7,210.95 5,938,469.47 552,553.79 0.00 7,310.90 5,938,391.19 552,556.99 0.00 7,389.21 5,938,390.99 552,557.00 0.00 7,389.41 1/26/2007 3:53:03PM Page 8 of 10 COMPASS 2003.11 Build 48 ORIGINAL • ,`,, C4t'~O-C0~1I~~tpS Alaska Halliburton Company Planning Report -Geographic • ~LIL~ I~ V PTO Sperry DrilEing ServEcee Database: Compass 2003.11 Local Co-ordinate Reference: Well Plan 1J-160 Company: ConocoPhillips Alaska, Inc. ND Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Project: Kuparuk River Unit MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site: Kuparuk 1J Pad North Reference: True Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature Wcllbore: Plan 1J-160 Design: 1J-1E~i~,~I~i~Ci Geologic Targets Plan 1J-1F~0 ND Target Name +Nl-S +El-W Northing Easting (ft) -Shape ft ft (ft) (ft) 3,458.01 1J-160 A_CP03 10/27/06 -3,854.52 -6,287.32 5,941,924.51 552,412.12 - Polygon Point 1 0.00 0.00 5,941,924.51 552,412.12 Point 2 -518.99 17.11 5,941,405.74 552,433.27 3,296.51 1J-160 Top_B -1,499.78 -6,363.62 5,944,278.36 552,317.48 - Point 3,219.00 1J-160 D_Top 10/27/06 -1,154.00 -6,375.33 5,944,624.00 552,303.08 - Point 3,443.01 1J-160 A_CP07 10/27/06 -6,090.87 -6,212.64 5,939,689.03 552,504.21 - Polygon Point 1 0.00 0.00 5,939,689.03 552,504.21 Point 2 -580.22 18.93 5,939,109.03 552,527.66 3,450.01 1J-160 A_CP04 10/27/06 -4,373.49 -6,270.21 5,941,405.74 552,433.27 - Polygon Point 1 0.00 0.00 5,941,405.74 552,433.27 Point 2 -600.97 19.82 5,940,805.00 552,457.77 3,407.01 1J-160 A_Toe 10/27/06 -7,389.41 -6,169.96 5,938,390.99 552,557.00 - Point 3,228.00 1J-160 D_Top 1/19/07 -1,195.36 -6,269.83 5,944,583.47 552,408.89 -Point 3,483.01 1J-160 A_CP01 10/27/06 -2,819.68 -6,324.68 5,942,958.93 552,366.70 - Polygon Point 1 0.00 0.00 5,942,958.93 552,366.70 Point 2 -432.72 17.49 5,942,528.54 552,387.47 3,416.01 1J-160 A_CP08 10/27/06 -6,671.09 -6,193.71 5,939,109.03 552,527.66 - Polygon Point 1 0.00 0.00 5,939,109.03 552,527.66 Point 2 -718.32 23.75 5,938,390.99 552,557.00 3,441.01 1J-160 A_CP05 10/27/06 -4,974.46 -6,250.39 5,940,805.00 552,457.77 - Polygon Point 1 0.00 0.00 5,940,805.00 552,457.77 Point 2 -530.77 17.82 5,940,274.44 552,479.72 3,470.01 1J-160 A_CP02 10/27/06 -3,250.26 -6,307.26 5,942,528.54 552,387.47 - Polygon Point 1 0.00 0.00 5,942,528.54 552,387.47 Point 2 -604.41 19.95 5,941,924.51 552,412.12 3,444.01 1J-160 A_CP06 10/27/06 -5,505.23 -6,232.57 5,940,274.44 552,479.72 - Polygon Point 1 0.00 0.00 5,940,274.44 552,479.72 Point 2 -585.14 19.93 5,939,689.53 552,504.21 1/26/2007 3:53:03PM Page 9 of 10 COMPASS 2003.11 Build 48 ;'21GINAL ~- • '/ C " ~I P~" Halliburton Company HAR..t_IBUIFF~TCtI OI 1000 tE 1~JJ5 Alaska Planning Report -Geographic Sperry Drilling Servicees Database: Compass 2003.11 Local Co-ordinate Reference: " Well Plan 1J-160 Company: ConocoPhillips Alaska, Inc. TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Project: Kuparuk River Unit MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site: Kuparuk 1J Pad North Reference: True Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature Wellbore: Plan 1J-160 I Design: 1J-160 (wp06) Prognosed Casing Points Measured Vertical Casing Hote Depth Depth Diameter Diameter lft1 (ft) C') (") 14,478.35 3,407.01 4-1 /2 6-314 9,704.44 3,472.53 9-518 12-114 3,317.26 2,153.28 13-318 16 Prognosed Formation Intersection Points Measured Depth Inclination Azimuth 1,667.19 47.14 267.00 1,856.80 50.93 267.67 2,423.51 67.82 269.98 3,317.26 78.11 271.11 5,863.51 78.11 271.11 6,672.60 75.95 247.57 6,925.75 75.73 239.74 I 7,595.32 76.38 219.05 8,244.03 78.50 200.00 8,504.39 78.94 192.05 8,631.13 79.23 188.19 8,851.28 79.85 181.50 9,340.61 80.47 175.93 9,828.07 87.00 177.68 Vertical s Depth +N/-E +E/-W eft) (ft) (ft) 1,525.76 -26.12 -498.36 1,651.58 -32.96 -639.99 1,939.25 -42.06 -1,125.76 2,153.28 -28.39 -1,992.03 2,678.05 19.98 -4,483.15 2,861.21 -115.83 -5,253.24 2,923.21 -224.64 -5,473.03 3,086.20 -645.11 -5,963.32 3,228.00 -1,195.36 -6,269.83 3,279.00 -1,440.56 -6,340.24 3,303.00 -1,563.06 -6,362.09 3,343.00 -1,778.65 -6,380.35 3,425.00 -2,260.18 -6,354.92 3,479.00 -2,743.29 -6,327.78 Name Pfrost T3 K15 Casing Pt Ugnu C Ugnu B Ugnu A K13 WSakD W Sak C WSakB W Sak A4 W Sak A3 W Sak A2 Plan Annotations Measured Vertical Local Coor dinates - Depth Depth +Ni-S +EI-W Comment (ft) (ft) (ft) eft) 40.01 40.01 0.00 0.00 SHL - 2016' FSL, 2541' FEL -Sec35-T11 N-R10E 3,317.26 2,153.28 -28.39 -1,992.03 13 3/8" Csg @ 3317' MD, 2153' TVD - 1988' FSL, 747' FWL-Sec35-T11 N-R10 9,704.44 3,472.53 -2,619.92 -6,332.77 9 5/8" Csg @ 9704' MD, 3473' TVD - 606' FNL, 1684' FWL-Sec10-T10N-R10E 14,478.36 3,407.01 -7,389.21 -6,169.97 BHL @ 14478' MD, 3407' TVD - 96' FNL, 1842' FWL - Sec10-T10N-R1 OE 1/26/2007 3:53:03PM Page 10 of 10 COMPASS 2003.11 Build 48 • ConocoPhillips Alaska • Plan: 1J-160 (wp06) Sperry Drilling Services Anticollision Summary 26 January, 2007 ConocoPhillips Alaska, Inc. Kuparuk River Unit Kuparuk 1J Pad Plan 1J-160 Plan 1J-160 Local Coordinate Origin: Centered on Well Plan 1J-160 Viewing Datum: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) TVDs to System: N North Reference: True Unit System: API - US Survey Feet Sperry Drilling 8erviae: e~i~iNa~ O z Sl'Ii~T:Y PROGRAM Uate: 2000-11-UT1'U0:00:00 Validated: Yes Version: 31.000 Depth FromUepth To Survey/Plan Tool ~O.OU 1000.00 W-IGO(wp06) CtiGYRO-SS 1000.00 3929.01 IJ-1GO(wpOG) MW'U+IFR-AK-CATrSC 3929.01 853a.G4 IJ-IGU(wpUG) MW[T+IFR-AK-CA2•rSC 9970.U21a478.36 IJ-IGO(wpOG) MWD+INR-AK-CAZrSC COMPANY DETAILS: ConocoPhillips Alaska, Inc- Engineering Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Trav. Cylinder North Error Surtace: Elliptical Conic Warning Method: Rules Based 1J-09 1J-154 r • . d.a t` 1J-1 a2 i ~ 1J-10 i 1J-103 ( P ) 1J-105 w 03 ~ i a~ ~ ~ ~~ ~ i 330 ~~~~~~~i ~ ~~ .al ~~~~~1)~~~1~~'~ 30 1J-156 J~ WSP-1S 1{1'f i~ II?1 ~ ` ~ ~(~°?~Ii~1~r~~'" )Tf ~~ ~ 1J-159 ~7p~ `A~ ~ j6 ~~4 ~ I~~~h IIN"~YF ~~. i ~ ~~~~~~~~ ~\~. (~~ >f ~~;, 1J-107 (wp0; /; ~ 1 ~ ~~~,-"; ~`a `4` "sz (~ '~"~~ ^'''~~„}~)~~~y~~ /WSP-15 300 ~ ~ j j~ / ~~ ~ ~ / -~+t ~~,~ ~ ~ / ~ G`0 1 J-03 i It ~ ''i. 'J.tl /'~ ~~ '^ ~,~ ~ I _" __-1J-109 ~A~ J ~ ~ ~ i/ ~e~ ' ~ ~ _ _ 1J-164 i j / , 7~ l~•. ~.., ~ - - -WSP-02 r ~ ~~ ~ s ~~. ^'r y - - ~ -~- i ~~ ~ ~/ ~ j ~~ - ~ - 1J-111 (wp03; i ;~ , \ - ~ _ a; I 1 ~ '~ ~~ `i~ / ? 5n~ 270 , I "` ~\ K. / ~ ~,.'<>~ WSP-03 - ~_ t\ ~ ;~ "' 1J-115 _ 1~ 1J-162 (wp05) '/ '~ ~ '~_ -.- `WSP-04 °~ WSP-20 2ao ~ \ ~~ ~__ ~}~_ ~ / p~4 1J-118 (wp06) ~; ~ ~ _ - 1 \_ ~~. t t ,~ Y~__ I ~~ - ~ I ,,. ~ ,.. ~ 7` ~ 1 210 - - T ~,'• 1 ` ~/ ~ 150 1 _ _ °-1"~ / 1 J-166 180 \ ~ 1J-168 1J-170 Rig Surveys Travelling Cylinder Azimuth (1'FO+AZI) [°~ vs Centre to Centre Separation ~ 150 ft/ink NAD 27 ASP Zone 4 : WELL DETAILS: Plan 1J-160 Ground Level: 0.00 +NI-S+EI-W Northing Easting Latittude Longitude Slot 0.00 0.00 5945827.52 558668.60 70°15'45.361N 149°31'32.565W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan 1J-160, True North Vertical (TVD) Reference: Doyon 15 (40+g1) @ 121.OOft (Doyon 15 (40+81)) Section (VS) Reference: Slot - (O.OON, O.OOE) Measured Depth Reference: Doyon 15 (40+g1) @ 121.OOft (Doyon 15 (40+81)) Calculation Method: Minimum Curvature From Colour To MD 40 250 250 500 500 750 750 1000 1000 - 1250 1250 1500 1500 1750 1750 2000 2000 2250 2250 -- - 2500 2500 2750 2750 3000 3000 3500 3500 4000 4000 4500 4500 -- 5000 5000 5250 5250 5500 5500 5750 5750 --- 6000 6000 6250 6250 - - 6500 6500 6750 6750 7000 7000 7250 7250 7500 7500 7750 7750 8000 8000 -'--- 8500 8500 9000 9000 9500 9500 10000 10000 --- 11000 11000 12000 12000 -- 13000 13000 14000 14000 15000 ANTI-COLLISION SETTINGS Interpolation Method: MD Interval: 50Stations Depth Range From: 40.00 To 14478.36 Maximum Range:1643.83637143 Reference: Plan: iJ-160 (wp06) 180 Travelling Cylinder Azunuth (T FO+AZI) )°~ vs Centre to Centre Separation X50 ft/in( SECTION DETAILS 6ec MD iM / ' ND +W-8 +EI-W DLe9 1 40.00 0.00 0.00 4000 000 0.00 0.00 TFece V6ac Tar9e1 0.00 0.00 2 300 00 0.00 0.00 300.00 000 0.00 0.00 3 ]02 % 10.05 3fi] 00 ]0000 ~1 B4 ~J5 13 2.50 0.00 000 26].00 t Bd d 1629.32 4].14 26]00 150000 -246] ]0.64 400 0.00 246] 5 1]2932 4].id 2fi100 156802 -2850 -54385 0.00 6 2]68.29 ]8.11 2]1.11 2040.14 -3882 -145495 300 0.00 20.50 ].]9 38.82 ] 5904.]8 ]8.11 2]1.11 2686.58 20i8 452351 000 0.00 -20.]8 8 8218.83 JH.50 200.00 322302 -11]232 -626125 300 9 8243.83 ]850 200.00 322800 -119534 -6269.63 0.00 -91% 11]2)2 0.00 1195.34 iJ~160D Tap 111910) 10 9035.13 804] 1]59] 33]4.4] -195904 -6)]608 3.00 -8].53 1959.84 11 94)9.29 804] 1]593 344]99 -2396.)] -634501 0.00 12 9]0444 8]00 1]i.68 34)2.54 2620.10 6332.56 J.00 0.00 23%.]] 15.01 2620.10 1] 9904.44 8]00 1]166 348).01 -281966 -632448 000 14 10111.92 93.22 1]168 348260 -30280] -6318.09 300 000 201966 1J-160 A_CPO11N2]I06 004 )026.01 15 1033583 9322 1]]68 34]0.01 -325024 -630].06 0.00 1610611.]8 %.52 1]823 3460.99 -352505 -629].25 1.00 0.00 3250.24 IJ-1fi0q CP021012]I% 1fi8.49 3525.85 1] 10940.61 90.52 1]8.23 345801 -385450 -628].12 000 000 ]054.50 iJ~160q CP031012J1% 1810900.42 90.90 1]8.11 3451.51 -3094.29 -6285.85 100 19 1145992 90.50 1]8.11 345001 .43]34) -62]0.01 000 -18.16 3894.29 0.00 43]34) 1J~160q CP0010/2]/% 20 1146392 90.86 1]811 3049.% -03]14] -626988 100 1]4.04 43]J bJ 21 12061.29 90.88 1]8.11 )04101 -09]444 -6250.19 000 22 12196.]0 09.50 1]80] 344058 -5109.)8 -624568 100 000 49]444 1J~1fi0A CP0510/2)/06 -I ]8.3] 5109.]8 23 125923] 89.50 1)80] 34M.01 -5505.21 -6232.)] 000 0.00 5505.21 1J-160q CP06 10/2]/06 2412655.18 %.13 1]805 344421 -556]98 ~62J025 100 25131]8.35 90.13 1]805 344301 -609055 -621244 000 -2.08 556].% 0.00 60%.85 1J-1fi0 A_LPO]f0/2J/O6 2613322.99 93.02 1]8.14 3439.03 b2]5 J3 -620164 200 1.8a 623533 2] 13]59.56 93.02 1)8.14 341601 -6fi]10] 6193.51 000 2813885.90 90.50 1]8.10 3412.13 -6]91.)1 ~6t e9.J] 0.00 fifi]10] 1J-1fi0 q_LP%10/2]/% ~iJ9.10 6]9).31 29 14d]03fi 90.50 1)8.10 340101 -]389.39 ~61 G9.]6 0.00 0.00 ]389.39 1}160A Toe Id2]~% C4IR000PE'il~~1p5 Alaska Halliburton Company Anticollision Report Sperry Ciriiiiing Services ', Company: ConocoPhillips Alaska, Inc. Local Co-ordinate Reference: Well Plan 1J-160 Project: Kuparuk River Unit TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Reference Site: Kuparuk 1J Pad MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site Error: O.OOft North Reference: True Reference Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature i Well Error: O.OOft Output errors are at 2.00 sigma Reference Wellbore Plan 1J-160 Database: Compass 2003.11 Reference Design: 1J-160 (wp06) Offset TVD Reference: Offset Gatum Reference 1J-160 (wp06) Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refer Interpolation Metho d: MD Interval 25.OOft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Trav. Cylinder North Results Limited by: Maximum center-center distance of 1,643.84ft Error Surtace: Elliptical Conic Warning Levels eva luated at: 0.00 Sigma Survey Tool Program Date 1/25r20D7 From To (ft) (ft) Survey (Wellbore) 40.00 1,000.00 1J-160 (wp06) (Plan 1J-160) 1,000.00 3,929.01 1J-160 (wp06) (Plan 1J-160) 3,929.01 8,534.64 1J-160 (wp06) (Plan 1J-160) 9,970.02 14,478.36 1J-160 (wp06) (Plan 1J-160) Tool Name Description CB-GYRO-SS Camera based gyro single shot MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 1/26/2007 7:15:12AM Page 2 of 6 COMPASS 2003.11 Build 48 ~~~~~~ . Corx3coPhit~ips Alaska • Halliburton Company Anticollision Report ~~ ~ ~ ~~~ Sperry DriNing Servicxss Company: ConocoPhillips Alaska. Inc. Local Co-ordinate Reference:: Well Plan 1J-160 Project: Kuparuk River Unit TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Reference Site: Kuparuk 1J Pad MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site Error: O.OOft North Reference: True Reference Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature Well Error: O OOft Output errors are at 2.00 sigma Reference Wellhore Flan 1J-160 Database: Compass 2003.11 Reference Desiyn: 1J-160 (wp06) Offset ND Reference: Offset Datum Summary - - Reference - - -- Offset - Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Sitc Name Depth Depth Distance (ft) from Plan Offset Well - Wellbore -Design (ft) (ft) (ft) (ft) Kuparuk 1E Pad 1 E-117 - 1 E-117 - 1 E-117 7,666.95 15,774.03 564.07 193.31 370.76 Pass -Major Risk 1 E-117 - 1 E-117L1 - 1 E-117L1 7,541.95 15,667.03 507.43 200.32 307.11 Pass -Major Risk 1 E-117 - 1 E-117L2 - 1 E-117L2 7,546.67 15,661.03 505.67 208.96 296.71 Pass - Major Risk CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 1/26/2007 7:15:12AM Page 3 of 6 COMPASS 2003.11 Build 48 .tea ~..~.: • '-~' ~~ C ~ Halliburton Company t-t,AL..l..I~~R'~'~,1 OC~OCC} ll' ~~5 Alaska Anticollision Report Sperry Oriiiing Services Company: ConocoPhillips Alaska, Inc. Local Co-ordinate Reference: Well Plan 1J-160 Project: Kuparuk River Unit ND Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Reference Site: Kuparuk 1J Pad MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) Site Error: O.OOft North Reference: True Reference Well: Plan 1J-160 Survey Calculation Method: Minimum Curvature Well Error: O.OOft Output errors are at 2.00 sigma Reference Wellbore Plan 1J-160 Database: Compass 2003.11 Reference Design: 1J-160 (wp06) Offset ND Reference: Offset Datum Summary I Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offiset Well -Wellbore -Design (ft) (ft) (ft) (ft) kuparuk 1J Pad 1J-03 - 1J-03 - 1J-03 154.88 150.00 152.81 2.27 150.53 Pass -Major Risk 1J-09 - 1J-09 - 1J-09 331.31 325.00 140.79 5.60 135.19 Pass -Major Risk 1J-10 - 1J-10 - 1J-10 481.22 475.00 21.41 8.75 12.66 Pass -Major Risk 1J-109 - 1J-109 - 1J-109 174.16 175.00 152.60 3.03 149.57 Pass -Major Risk 1J-109 - 1J-109 P61 - 1J-109PB1 174.16 175.00 152.60 3.03 149.57 Pass -Major Risk 1 J-115 - 1 J-115 - 1 J-115 357.97 350.00 167.63 7.41 160.22 Pass -Major Risk 1 J-115 - 1 J-115 - 1 J-115 (wp05) 40.00 40.00 166.66 0.47 166.19 Pass -Major Risk 1J-115 - 1J-115L1 - 1J-115 L1 (wp05) 404.53 400.00 164.83 8.75 156.07 Pass -Major Risk 1J-115 - 1J-115L1 - 1J-115L1 357.97 350.00 167.63 7.15 160.48 Pass -Major Risk 1J-115 - 1J-115L1P61 - 1J-115L1P61 357.97 350.00 167.63 7.41 160.22 Pass -Major Risk 1 J-115 - 1J-115L1 PB2 - 1 J-115L1 PB2 357.97 350.00 167.63 7.15 160.48 Pass -Major Risk 1J-115 - 1J-115L2 - 1J-115 L2 (wp05) 40.00 40.00 166.66 0.47 166.19 Pass -Major Risk 1J-115 - 1J-115L2 - 1J-115L2 357.97 350.00 167.63 7.41 160.22 Pass -Major Risk 1J-115 - 1J-115L2PB1 - 1J-115L2PB1 357.97 350.00 167.63 7.15 160.48 Pass -Major Risk 1J-115 - 1J-115L2P62 - 1J-115L2PB2 357.97 350.00 167.63 7.15 160.48 Pass -Major Risk 1J-115 - 1J-115P61 - 1J-115PB1 357.97 350.00 167.63 7.41 160.22 Pass -Major Risk 1J-115 - 1J-115PB2 - 1J-115PB2 357.97 350.00 167.63 7.15 160.48 Pass -Major Risk 1J-115 - 1J-115P63 - 1J-115P63 357.97 350.00 167.63 7.15 160.48 Pass -Major Risk 1J-115 - 1J-115PB4 - 1J-115PB4 357.97 350.00 167.63 7.41 160.22 Pass -Major Risk 1 J-152 - 1 J-152 - 1 J-152 413.55 400.00 180.03 8.47 171.55 Pass -Major Risk 1J-152 - 1J-152 L1 - 1J-152 L1 413.55 400.00 180.10 8.47 171.63 Pass -Major Risk 1J-152 - 1J-152 L2 - 1J-152 L2 413.55 400.00 180.10 8.47 171.63 Pass -Major Risk 1J-152 - 1J-152 L2 PB1 - 1J-152 L2 P61 413.55 400.00 180.10 8.47 171.63 Pass -Major Risk 1J-152 - 1J-152 P61 - 1J-152 P61 413.55 400.00 180.10 8.21 171.89 Pass -Major Risk 1J-152 - 1J-152 PB2 - 1J-152 PB2 413.55 400.00 180.03 8.21 171.81 Pass -Major Risk 1J-154 - 1J-154 - 1J-154 562.49 550.00 124.98 11.85 113.13 Pass -Major Risk 1J-154 - 1J-154 L1 - 1J-154 L1 562.49 550.00 124.98 11.85 113.13 Pass -Major Risk 1J-154 - 1J-154 L2 - 1J-154 L2 562.49 550.00 124.98 11.85 113.13 Pass -Major Risk 1J-156 - 1J-156 - 1J-156 362.42 350.00 81.58 7.49 74.09 Pass -Major Risk 1J-156 - 1J-156L1 - 1J-156L1 362.42 350.00 81.58 7.49 74.09 Pass -Major Risk 1J-156 - 1J-156L1PB1 - 1J-156L1PB1 362.42 350.00 81.58 7.49 74.09 Pass -Major Risk 1J-156 - 1J-156L2 - 1J-156L2 362.42 350.00 81.58 7.49 74.09 Pass -Major Risk 1 J-159 - 1 J-159 - 1 J-159 436.97 425.00 18.53 9.11 9.42 Pass -Major Risk 1J-159 - 1J-159 L1 - 1J-159 L1 436.97 425.00 18.53 9.11 9.42 Pass -Major Risk 1J-159 - 1J-159 L1 PB1 - 1J-159 L1 PB1 436.97 425.00 18.53 9.11 9.42 Pass -Major Risk 1J-159 - 1J-159 L1 PB2 - 1J-159 L1 PB2 436.97 425.00 18.53 9.11 9.42 Pass -Major Risk 1J-159 - 1J-159 L2 - 1J-159 L2 436.97 425.00 18.53 9.11 9.42 Pass -Major Risk 1J-159 - 1J-159 P61 - 1J-159 PB1 436.97 425.00 18.53 8.85 9.68 Pass -Major Risk 1J-164 - 1J-164 - 1J-164 607.61 600.00 102.45 12.50 89.95 Pass -Major Risk 1J-164 - 1J-164 L1 - 1J-164 L1 607.61 600.00 102.45 12.76 89.69 Pass -Major Risk 1J-164 - 1J-164 L2 - 1J-164 L2 607.61 600.00 102.45 12.76 89.69 Pass -Major Risk 1J-164 - 1J-164 L2 PB1 - 1J-164 L2 P61 607.61 600.00 102.45 12.76 89.69 Pass -Major Risk 1 J-166 - 1 J-166 - 1 J-166 508.94 500.00 142.74 10.69 132.04 Pass -Major Risk 1J-166 - 1J-166 L1 - 1J-166 L1 508.94 500.00 142.74 10.69 132.04 Pass -Major Risk 1J-166 - 1J-166 L1 PB1 - 1J-166 L1 PB1 508.94 500.00 142.74 10.69 132.04 Pass -Major Risk 1J-166 - 1J-166 L2 - 1J-166 L2 508.94 500.00 142.74 10.69 132.04 Pass -Major Risk 1J-166 - 1J-166 L2 P61 - 1J-166 L2 P61 508.94 500.00 142.74 10.69 132.04 Pass -Major Risk 1J-168 - 1J-168 - 1J-168 361.15 350.00 180.96 7.38 173.58 Pass -Major Risk 1J-168 - 1J-168 L1 - 1J-168 L1 361.15 350.00 180.96 7.38 . 173.58 Pass -Major Risk 1J-168 - 1J-168 L2 - 1J-168 L2 361.15 350.00 180.96 7.38 173.58 Pass -Major Risk 1J-168 - 1J-168 L2 PB1 - 1J-168 L2 PB1 361.15 350.00 180.96 7.38 173.58 Pass - Major Risk CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 1/26/2007 7:15:12AM Page 4 of 6 COMPASS 2003.11 Build 48 ORIGINAL ~'1~. t( Hallibulrton Company l~~..Ll~t~~TC1i~.t CQCIUCQ~'1t~~1~?5 Anticollision Report Sperry Oriiiing Servicei~ Company: ConocoPhillips Alaska. Inc. Local Co-ordinate Reference: Well Plan 1J-160 I Project: Kuparuk River Unit TVD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) ~ Reference Site::.. Kuparuk 1J Pad MD Reference: Doyon 15 (40+81) @ 121.OOft (Doyon 15 (40+81)) ~ Site Error: O.OOft North Reference: True Reference WeII: Plan 1J-160 Survey Calculation Method: Minimum Curvature Well Error: O.OOft Output errors are at 2.00 sigma Reference Wellbore Plan 1J-160 Database: Compass 2003.11 Reference Design: 1J-160 (wp06) Offset TVD Reference: Offset Datum Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Well -Wellbore -Design (ft) (ft) (ft) (ft) Kuparuk 1J Pad 1J-170 - 1J-170 - 1J-170 Rig Surveys 58'2.33 575.00 215.95 12.3(1 203.59 Pass -Major Risk iJ-170 - 1J-170 L1 - 1J-170 L1 Rig Surveys 582.33 575.00 215.95 12.36 203.59 Pass -Major Risk 1J-170 - 1J-170 L2 - 1J-170 L2 Rig Surveys 582.33 575.00 215.95 12.36 203.59 Pass -Major Risk 1J-170 - 1J-170 PB1 - 1J-170 PB1 582.33 575.00 215.95 12.36 203.59 Pass-Major Risk 1J-170- 1J-170 P62 - 1J-170 P62 Rig Surveys 582.33 575.00 215.95 12.10 203.85 Pass -Major Risk Plan 1 J-105 - 1 J-105 - 1 J-105 (wp03) 358.96 350.00 202.73 7.28 195.44 Pass -Major Risk Plan 1J-105 - 1J-105 L1 - 1J-105 L1 (wp03) 358.96 350.00 202.73 7.28 195.44 Pass -Major Risk Plan 1J-105 - 1J-105 L2 - 1J-105 L2 (wp03) 358.96 350.00 202.73 7.28 195.44 Pass -Major Risk Plan 1J-107 -Plan 1J-107 - 1J-107 (wp03) 335.08 325.00 177.55 6.76 170.79 Pass -Major Risk Plan 1J-107 -Plan 1J-107 L1 - 1J-107 L1 (wp03) 335.08 325.00 177.55 6.76 170.79 Pass -Major Risk Plan 1J-107 -Plan 1J-107 L2 (wp03) - 1J-107 L2 ~ 335.08 325.00 177.55 6.76 170.79 Pass -Major Risk Plan 1J-111 -Plan 1J-111 - 1J-111 (wp03) 334.81 325.00 146.46 6.86 139.59 Pass -Major Risk Plan 1J-112 Kuparuk Prelim - 1J-12 E Lateral - 1J 346.04 350.00 147.87 7.04 140.83 Pass -Major Risk Plan 1J-112 Kuparuk Prelim - 1J-12 Pilot - 1J-12 I 346.04 350.00 147.87 7.04 140.83 Pass -Major Risk Plan 1J-112 Kuparuk Prelim -Plan 1J-12 W Later 346.04 350.00 147.87 7.04 140.83 Pass -Major Risk Plan 1J-118 - 1J-118 - 1J-118 (wp06) 334.45 325.00 202.74 6.75 195.99 Pass -Major Risk Plan 1J-118 - 1J-118 L1 - 1J-118 L1 (wp06) 334.45 325.00 202.74 6.75 195.99 Pass -Major Risk Plan 1J-118 - 1J-118 L2 - 1J-118 L2 (wp06) 334.45 325.00 202.74 6.75 195.99 Pass -Major Risk Plan 1J-120 -Plan 1J-120 - 1J-120 (wp06) 311.14 300.00 232.27 6.23 226.04 Pass -Major Risk Plan 1J-120 -Plan 1J-120 L1 - 1J-120 L1 (wp06) 311.14 300.00 232.27 6.23 226.04 Pass -Major Risk Plan 1 J-120 -Plan 1J-120 L2 - 1J-120 L2 (wp06) 311.14 300.00 232.27 6.23 226.04 Pass -Major Risk Plan 1J-150 (Ugnu Disposal) -Plan 1J-UgnuDispc 364.12 350.00 220.37 6.26 214.11 Pass -Major Risk Plan 1J-158 - 1J-158 - 1J-158 (wp06) 714.02 700.00 44.77 14.86 29.92 Pass -Major Risk Plan 1J-158 - 1J-158 L1 - 1J-158 L1 (wp06) 714.02 700.00 44.77 15.12 29.66 Pass -Major Risk Plan 1J-158 - 1J-158 L2 - 1J-158 L2 (wp06) 714.02 700.00 44.77 15.12 29.66 Pass -Major Risk Plan 1J-160 -Plan 1J-160 L1 - 1J-160 L1 (wp06) 8,675.00 8,675.00 0.13 0.47 -0.34 FAIL - No Errors Plan 1J-160 -Plan 1J-160 L2 - 1J-160 L2 (wp06) 8,275.00 8,275.00 0.00 0.47 -0.47 FAIL - No Errors Plan 1 J-162 - 1 J-162 - 1 J-162 (wp05) 611.57 600.00 58.53 13.07 45.46 Pass -Major Risk Plan 1J-162 - 1J-162 L1 - 1J-162 L1 (wp3.1) 611.57 600.00 58.53 12.70 45.83 Pass -Major Risk Plan 1J-162 - 1J-162 L2 - 1J-162 L2 (wp3.1) 611.57 600.00 58.53 13.07 45.46 Pass -Major Risk Plan 1J-174 (Q1 Phase 2) - 1J-174 - 1J-174 (wp0: 384.94 375.00 300.95 7.84 293.10 Pass -Major Risk Plan 1J-174 (Q1 Phase 2) - 1J-174 L1 - 1J-174 L1 384.94 375.00 300.95 7.84 293.10 Pass -Major Risk Plan 1J-176 (02 Phase 2) - 1J-176 - 1J-176 (wp0: 14,478.36 10,425.00 493.90 203.94 289.97 Pass -Major Risk Plan 1J-176 (Q2 Phase 2) - 1J-176 L1 - 1J-176 L1 14,478.36 10,425.00 493.90 204.12 289.78 Pass -Major Risk Rig: 1J-103 - 1J-103 - 1J-103 311.44 300.00 232.53 6.38 226.15 Pass -Major Risk Rig: 1J-103 - 1J-103 L1 - 1J-103 L1 311.44 300.00 232.57 6.38 226.19 Pass -Major Risk Rig: 1J-103 - 1J-103 L1 PB1 - 1J-103 L1 (wp10) 334.63 325.00 232.14 6.75 225.39 Pass -Major Risk Rig: 1J-103 - 1J-103 L1 PB1 - 1J-103 L1 PB1 311.44 300.00 232.53 6.38 226.15 Pass -Major Risk Rig: 1 J-103 - 1 J-103 L2 - 1 J-103 L2 311.44 300.00 232.57 6.38 226.19 Pass -Major Risk Rig: 1 J-103 - 1 J-103 L2 - 1 J-103 L2 Pilot Toe (wp 310.77 300.00 232.52 6.37 226.15 Pass -Major Risk Rig: 1J-103 - 1J-103 L2 Pilot Toe - 1J-103 L2 Pilo 310.77 300.00 232.52 6.37 226.15 Pass -Major Risk Rig: 1J-103 - 1J-103PB1 - 1J-103PB1 311.44 300.00 232.53 6.38 226.15 Pass -Major Risk Rig: 1J-103 - 1J-103PB2 - 1J-103PB2 311.44 300.00 232.53 6.38 226.15 Pass -Major Risk Rig: 1J-103 - 1J-103PB3 - 1J-103PB3 311.44 300.00 232.53 6.38 226.15 Pass -Major Risk WSP-02 -WSP-02 -WSP-02 350.19 350.00 181.22 6.44 174.79 Pass -Major Risk WSP-03 -WSP-03 -WSP-03 361.06 350.00 185.65 8.62 177.03 Pass -Major Risk WSP-04 -WSP-04 -WSP-04 372.83 375.00 205.23 6.84 198.39 Pass -Major Risk WSP-15 -WSP-15 -WSP-15 369.02 375.00 199.87 8.60 191.27 Pass -Major Risk WSP-1 S -WSP-1 S -WSP-1 S 400.00 400.00 229.79 11.11 218.68 Pass -Major Risk WSP-20 -WSP-20 -WSP-20 714.77 700.00 106.91 17.33 89.59 Pass -Major Risk CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 1/26/2007 7:15:12AM Page 5 of 6 COMPASS 2003.11 Build 48 ORIGINAL Co-noe Phillips ~~~~ ~,~._,~ ~~..~~ ConocoPhillips Alaska, Inc. Kuparuk River Unit Kuparuk 1J Pad Plan: 1J-160 L2 (wp06) 1/4 Mile Pool Scan Sperry Drilling Services January 26, 2007 ~~~ i • • HALLIBURTON Drilling and Formation Evaluation ORIGINAL ~:~'a ~~~ ze ~~~s ~~ oamg F~ gg nmi £~«~ C N = moo 0 ~dco cn a 3 ~ ~ N Y Y J ` c c ~ ~ A ~ ~ aaaa YY=y ~~ m ~;3~a c o N °' a a ~ _ o a @~ $ o 2 "~Oe ~ u' o E uai v`"m ~f rv Fu~n~~u J -NU ar ~E`= °'_ W$oo b $!:~;;Sa S N$£f ~~ ti$ ASS ~~E~a '`~"sEg~ o~~ -m~K ~~aa ~ ¢~ ~m ctS z w LI.Y ry~ 0 ~../ U D ~3 ~ ~~ 3 ~ ~ m 0 C ~ U ~ N ~r~ ~ ~. r O r V j '~ i i 2 .~ r O co 7 r ~ v~ C ~ ~ _- - - - ~_ -- ~ c~ to = N ~ v ~ ~ N U ~ ~ ~ C ~ ._ ~ O ~ U ~ ~ ~ ~ o ~ ~ ~ r- L ~ ~ M LLJ N O ~ ~ ~ No ~ O ~ ~ (~ ~~ ~r ~ - - p L ~ >~ W ~_~>~ ~ H 0 o 0 0 --..__..._.._ 0 0 o o O N i a ~ p p C ~ . ~' 3 ~ ~ °~ r ~ ~ _. J ~ o O -j r r tD r p N t0 r ~ O + ~ N ~ r i ~ W -- --- ---- ----- ----_ ' i , ~ O o ' ~ ~ i ° d ~ ~ ~ ' ~ \ '~ 0 o ~~ co O o _ N °o °o ° °o °o °o °o °o °o c 0 0 0 0 0 ov o ~ ~ (u!/u OOOZ) (+)43~oN/l-)43nog `~~'~~~~~~1 Closest in POOL ~,s.J e„~ d d~`~.-. ~~,~ Closest Approach: Reference Well: 1J-160 L2 (wp06) Plan Offset Well: 1E-117L2 Coords. - Coords. - ASP ASP 3-D ctr-ctr Meas. Subsea N(+)/S(-) View VS Meas. Subsea N(+)/S(-) View VS Min. Dist. Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments m istance POOL Min Distance (929.63 ft) in POOL (929.63 ft) in POOL (8243.83 - 14457.05 (8243.83- 14457.05 MD) to 1J-160 L2 ' MD) to 1E-117L2 (wp06) Plan (9391 - 929,63 8250 78.51 199.81 3108.01 5944577.1 552406.3 1201.175 (9391 - 15661.03 MD) 15661.03 90.45 179.7 3112.862 5945506.5 552383.9 279.366 15661.03 MD) Closest A roa ch: Reference Well: 1J-160 L2 (w 06 Plan Offset Well: K UP 34-11 -10-1 Coords. - Coords. - ASP ASP 3-D ctr-ctr Meas. Subsea N(+)/S(-) View VS Meas. Subsea N(+)/S(-) View VS Min. Dist. Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments POOL Min Distance POOL Min Distance (1729.08 ft) in POOL (1729.08 ft) in PO (8243.83 - 14457.05 (8243.83 - 14457. MD) to KUP 34-11-10 MD) to 1J-160 L2 1 (3488.19 - 3894.05 (wp06) Plan (3488.19 1729.08 8250 78.51 199.81 3108.01 5944577.1 552406.3 1201.175 MD) 3475.01 32.39 342.73 3051.07 5945830.3 551216.3 -1173.82 - 3894.05 MD) Closest Approa ch: Reference Well: 1J-160 L2 wp 06) Plan Offset Well: 1J -158 L2 w 06 Coords. - Coords. - ASP ASP 3-D ctr-ctr Meas. Subsea N(+)/S(-) View VS Meas. Subsea N(+)/S(-) View VS Min. Dist. Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments POOL Min Distance POOL Min Distance (1444.15 ft) in POOL (1444.15 ft) in POOL (9243.83 - 14457.05 (9243.83 - 14457.05 MD) to 1J-158 L2 MD) to 1J-160 L2 (wp06) (7026.7 - (wp06) Plan (7026.7 - 1444.15 9310 85.2 175.11 3143.115 5943529.8 552338.8 2247.883 13506.18 MD) 8353 90.01 175.3 3133.88 5943663.6 553776.8 2164.73 13506.18 MD) Closest A roach: Reference Well: 1J-160 L2 w 06 Plan Offset Well: 1J-162 w 05 Coords. - Coords. - ASP ASP 3-D ctr-ctr Meas. Subsea N(+)/S(-) View VS Meas.. Subsea N(+)/S(-) View VS Min. Dist. Depth Incl. An fe TRUE Azi. TVD E + /W - (180° Comments Depth Incl. An le TRUE Azi. TVD E + /W - (180°) Comments POOL Min Distance POOL Min Distan (1579.5 ft) in POOL (1579.5 ft) in POOL (8243.83 - 14457.05 (8243.83 - 14457.05 MD) to 1J-162 (wp05) MD) to 1J-160 L2 (9936.89 - 15661.96 (wp06) Plan (9936.89 1579.5 8970 89.65 179.65 3122.85 5943868.2 552315.7 1909.341 MD) 10387 81 179.55 3152.29 5943847.7 550736.6 1859.08 - 15661.96 MD) Closest A proach: Reference Well: 1J-160 L2 wp06 Plan Offset Well: 1J-176 L1 w 02 Coords. - Coords. - ASP ASP 3-D ctr-ctr Meas. Subsea N(+)/S(-) View VS Meas. Subsea N(+)/S(-) View VS Min. Dist. Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180° Comments Depth Incl. Angle TRUE Azi. TVD E(+)/W(-) (180°) Comments POOL Min Distance POOL Min Distance (805.03 ft) in POOL (805.03 ft) in POOL (8243.83 - 14457.05 (8243.83 - 14457.05 MD) to 1J-176 L1 MD) to 1J-160 L2 (wp02) (11330.8 - (wp06) Plan (11330.8 805.03 14457.05 91.17 178.1 3051.806 5938389.7 552556.7 7389.554 17396.79 MD) 11315 80.92 180.58 3033 5937585 552570.9 7863.79 - 17396.79 MD) POOL Summary Template.xls 1/25/2007 4:11 PM 1J-160 i~rillin~ Hazards Soma (SEE WELL PLAN AND ATTACHMENTS FOR DETAILED DISCUSSION OF THESE RISKS) 16" Open Hole / 13-3/8" Casing Interval Hazard Risk Level Miti anon Strate Broach of Conductor Low Monitor cellar continuously during interval. Gas Hydrates Moderate / Control drill, Reduced pump rates, Reduced drilling fluid temperatures, Additions of Driltreat. Running Sands and Low Maintain planned mud parameters, Increase Gravels mud weight, use weighted sweeps. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out 12-1/4" Open Hole / 9-5/8" Casing Interval Hazard Risk Level Miti anon Strate Running Sands and Low Maintain planned mud parameters, Increase Gravels mud weight, use weighted sweeps. Gas Hydrates Low Control drill, reduced pump rates, reduced drilling fluid temperatures, additions of Driltreat. Stuck Pipe Low Good hole cleaning, pre-treatment with lost circulation material, stabilized BHA, decreased mud weight Abnormal Reservoir Low s BOP training and drills, increased mud weight. Pressure Lost circulation Low Reduced pump rates, mud rheology, LCM Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out 6-3/4" Open Hole / 4-1/2" Liner Interval Hazard Risk Level Miti anon Strate Abnormal Reservoir Pressure Low k Stripping drills, shut-in drills, increased mud weight. Stuck Pipe Low Good hole cleaning, PWD tools, hole opener runs, decreased mud weight Lost Circulation Low Reduced pump rates, mud rheology, LCM Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets),pumping out, backreaming 1J-160 Drilling Hazards Summary ~` ~, ~ prepared by Mike Greener ?' ~ t `1 ~ ~ek a > 10/5/2006 2:35 PM •' schlumberger CemCADE Preliminary Job Design 13 3/8" Surface Preliminary Job Design based on limited input data. For estimate purposes only. Rig: Doyon 15 Location: West Sak Client: ConocoPhillips Alaska, Inc. Revision Date: 1/25/2007 Prepared by: Maureen Torrie Location: Anchorage, AK Phone: (907) 265-6336 Mobile: (907) 952-0445 email: mtorrie@slb.com < TOC at Surface Previous Csg. J < 20", 91.5# casing at 80' MD < Base of Permafrost at 1,700' MD (1,548' TVD) 1 i < Top of Tail at 2,726' MD < 13 3/8", 72.0# casing in 16" OH TD at 3,226' MD (2,134' TVD) Mark of Schlumberger Volume Calculations and Cement Systems Volumes are based on 250% excess in the permafrost and 35% excess below the permafrost. The top of the tail slurry is designed to be at 2,426' MD. Lead Slurry Minimum pump time: 290 min. (pump time plus 120 min.) ARCTICSET Lite @ 10.7 ppg - 4.45 ft3/sk 1.0190 ft3/ft x (80') x 1.00 (no excess) = 81.5 ft3 0.4206 ft3/ft x (1700' - 80') x 3.50 (250% excess) = 2384.8 ft3 0.4206 ft3/ft x (2426' - 1700') x 1.35 (35% excess) = 412.2 ft3 81.5 ft3 + 2384.8 ft3+ 412.2 ft3 = 2878.5 ft3 2878.5 ft3 / 4.45 ft3/sk = 646.9 sks Round up to 650 sks Have 320 sks of additional Lead on location for Top Out stage, if necessary. Tail Slurry Minimum pump time: 220 min. (pump time plus 120 min.) DeepCRETE @ 12.0 ppg - 2.47 ft3/sk 0.4206 ft3/ft x (3226' - 2426') x 1.35 (35% excess) = 454.2 ft3 0.8315 ft3/ft x 80' (Shoe Joint) = 66.5 ft3 454.2 ft3 + 66.5 ft3 = 520.7 ft3 520.7 ft3/ 2.47 ft3/sk = 210.8 sks Round up to 220 sks BHST = 45~, Estimated BHCT = 63`F. (BHST calculated using a gradient of 2.6/100 ft. below the permafrost) PUMP SCHEDULE Pump Rate Stage Stage Time Cumulative Stage Volume Time (bpm) (bbl) (min) (min) CW 100 5 50 10.0 10.0 Drop Bottom Plug 15.0 25.0 MudPUSH II 6 50 8.3 33.3 Lead Slurry 7 515 73.6 106.9 Tail Slurry 6 97 16.2 123.1 Drop Top Plug 8.0 131.1 Water 5 20 4.0 135.1 Switch to Rig Pumps 5.0 140.1 Displacement 7 426 60.9 201.0 Slow Rate 3 20 6.7 207.7 MUD REMOVAL Recommended Mud Properties: 9.6 ppg, Pv < 15, TY < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 10.5 ppg MudPUSH* II, Pv = 17-21, TY = 20-25 Centralizers: Recommend 1 per joint across zones of interest for proper cement placement. ORIGI~..A'. ~ ~ Schlumberger CemCAD E*well cementing recommendation for 13 3/8 Surface Operator : CPAI Well 1J-160 Country :USA Field West Sak State :Alaska Prepared for :Mike Greener Location 1J Pad Proposal No. : V2 (wp06) Service Point Prudhoe Bay Date Prepared :January 25, 2007 Business Phone (907) 659-2434 FAX No. (907) 659-2538 Prepared by Phone E-Mail Adtlress Maureen Torrie 1-907-265-6336 mtorrie@slb.com ~~`~ C7 C FG q~UATE Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Mark of Schlumberger ~~~~~.. • • Client CPAI Well 1J-160 String 13 3/8 Surface District Prudhoe Bay Country USA Loadcase 1338 Surface Section 1: well description Configuration :Casing Stage :Single Rig Type :Land Mud Line : 0.0 ft Total MD :3226.5 ft BHST : 45 degF Bit Size : 16 in Previous String MD OD Weight ID ft in Ib/ft in 80.0 20 94.0 19.124 Landing Collar MD :3146.0 ft Casing/liner Shoe MD :3226.0 ft ~~Ir~~r Casing/Liner MD OD Joint Weight ID Grade Collapse Burst Thread (ft) (in) (ft) (Ib/ft) (in) (psi) (psi) 3226.0 13 3/8 40.0 68.0 12.415 L-80 2040 4310 IFJ Mean OH Diameter :16.000 in Mean Annular Excess :145.7 Mean OH Equivalent Diameter :19.193 in Total OH Volume :1125.7 bbl (including excess) Caliper and Hole Size Data MD Caliper Excess Equiv. Diam. ft in % in 1700.0 16.000 250.0 21.184 3226.0 16.000 35.0 16.822 Formation Data MD Frac. Pore Name Lithology (ft) {Ib/gal) (Ib/gal) 1700.0 12.50 8.20 P-Frost 3227.0 12.50 8.70 TD Geothermal Temperature Profile MD TVD Temperature Gradient ft ft de F de F/100ft 0.0 0.0 25 0.0 1700.0 1548.1 30 0.3 3226.0 2134.4 45 0.9 3226.5 2134.5 45 0.9 3227.0 2134.6 45 0.9 1J-160cemen[,V2.cfw;01-25-2007; LoadCase1338Surface;Versionwcs-cem45_89 Page 2 • • Client CPAI Well 1J-160 String 13 3/8 Surface District Prudhoe Bay Country USA Loadcase 1338 Surface Max. Deviation Angle : 78 deg Max. DLS :4.002 deg/100ft MD ft Directional Survey Data ND Deviation Azimuth ft de de Dogleg Sev. de /100ft 0.0 0.0 0.0 0.0 0.000 40.0 40.0 0.0 0.0 0.000 100.0 100.0 0.0 0.0 0.000 200.0 200.0 0.0 0.0 0.000 300.0 300.0 0.0 0.0 0.000 400.0 400.0 2.5 267.0 -2.500 500.0 499.7 5.0 267.0 2.500 600.0 599.1 7.5 267.0 2.500 702.1 700.0 10.1 267.0 2.499 800.0 795.8 14.0 267.0 4.002 900.0 891.9 18.0 267.0 4.000 1000.0 985.9 22.0 267.0 4.000 1100.0 1077.2 26.0 267.0 4.000 1200.0 1165.5 30.0 267.0 4.000 1300.0 1250.3 34.0 267.0 4.000 1400.0 1331.3 38.0 267.0 4.000 1500.0 1407.9 42.0 267.0 4.000 1600.0 1479.8 46.0 267.0 4.000 1629.3 1500.0 47.1 267.0 3.990 1667.2 1525.8 47.1 267.0 0.000 1700.0 1548.1 47.1 267.0 0.000 1729.3 1568.0 47.1 267.0 0.000 1800.0 1615.1 49.2 267.4 2.998 1856.8 1651.6 50.9 267.7 3.001 1900.0 1678.4 52.2 267.9 3.010 2000.0 1737.6 55.2 268.3 3.003 2100.0 1792.5 58.2 268.8 2.991 2200.0 1843.0 61.2 269.2 3.000 2300.0 1889.0 64.1 269.5 3.009 2400.0 1930.2 67.1 269.9 2.998 2423.5 1939.2 67.8 270.0 2.994 2500.0 1966.7 70.1 270.3 2.999 2600.0 1998.3 73.1 270.6 2.996 2700.0 2024.9 76.1 270.9 3.006 2768.3 2040.1 78.1 271.1 3.002 2800.0 2046.7 78.1 271.1 -0.000 2900.0 2067.3 78.1 271.1 0.000 3000.0 2087.9 78.1 271.1 0.000 3100.0 2108.5 78.1 271.1 0.000 3200.0 2129.1 78.1 271.1 0.000 3226.5 2134.5 78.1 271.1 0.000 iJ-160 cement,V2ciw;01-25-2007; Loadcase 1338 Surface;Versionwcs-cem45_69 ~clr~~r Page 3 C~R~`~r ~ • Client CPAI Well 1J-160 String 133/8 Surface District Prudhoe Bay Country USA Loadcase 1338 Surface Section 2: centralizer placement Top of centralization :2725.0 ft Bottom Cent. MD :ft Casing Shoe :3226.0 ft NB of Cent. Used NB of Floating Cent. Schlumb~rgcr Centralizer Placement Bottom MD Nbr. Cent. / Cent. Name Code Min. STO @ Depth ft Joint % ft 3226.0 2/1 S1104613-13 3/8-8-46 (3/16") Centralizer Description Centralizer Tests Cent. Name Code Casing Max. Min. OD Rigid Origin Hole Size Running Restoring OD OD (in) (in) Force Force in in Ibf Ibf S1104613-13 3/8-8- 13 3/8 18.752 14.500 No Houma 17.500 490.08 2214.37 46 3/16" (1) -Centralizer performance data is based on tests by WEATHERFORD as per the current API 10D specifications ft % deg (x 1000) ft 0 40 80 o~ 0 0 o- N O 0 0 a Pipe Standoff Deviation 1J-160 cement, V2.cfw; 01-25-2007; Loadcase 1338 Surface; Version wcs-cem45_89 Page 4 ORIGINAL Client CPAI Well 1J-160 String 133/8 Surface District Prudhoe Bay Country USA Loadcase 1338 Surface ~ • Section 3: fluid description Mud DESIGN Fluid No: 1 Rheo. Model :BINGHAM At temp. : 80 degF MUD Mud Type : WBM Water Type :Fresh VOLUME FRACTION Solids :95.0 Oil : 0.0 Water : 5.0 Density :9.601b/gal P~ :45.000 cP Ty :30.OOIbf/100ft2 Gel Strength :76.85 Ibf/100ft2 Job volume :451.0 bbl CW100 DESIGN Fluid No: 2 Density : 8.32 Ib/gal Rheo. Model :NEWTONIAN At temp. : 80 degF Viscosity :5.000 cP Gel Strength : (Ibf/100ft2) Job volume :50.0 bbl MUDPUSH II DESIGN Fluid No: 3 Density : 10.50 Ib/gal Rheo. Model :BINGHAM P~ :23.000 cP At temp. : 80 degF Ty :30.00 Ibf/100ft2 Gel Strength : (Ibf/100ft2) Job volume :50.0 bbl ASL DESIGN Fluid No: 5 Density : 10.70 Ib/gal Rheo. Model :BINGHAM P~ :28.660 cP At temp. : 65 degF Ty :16.97 Ibf/100ft2 Gel Strength : (Ibf/100ft2) DESIGN BLEND Name : G Dry Density : 199.77 Ib/ft3 Sack Weight : 94 Ib BASE FLUID Type :Fresh water SLURRY Mix Fluid :20.722 gal/sk Yield :4.45 ft3/sk Porosity :62.3 Density :8.321b/gal Job volume :512.7 bbl Quantity :647.49 sk Solid Fraction :37.7 Base Fluid :20.153 gal/sk 1J-160 cement,V2.cfiv;01-25-2007; Loadcase 1338 Surface; Versionwcs-cem45_89 Page 5 Client CPAI Well 1J-160 String 13 3/8 Surface District Prudhoe Bay Country USA Loadcase 1338 Surface • Sclrg~r DeepCRETE DESIGN Fluid No: 6 Rheo. Model : BINGHAM At temp. : 63 degF DESIGN BLEND Name : G Dry Density : 199.77 Ib/ft3 Sack Weight : 94 Ib BASE FLUID Type :Fresh water Density :12.OOIb/gal Pv :105.064 cP Ty :11.811bf/100ft2 Gel Strength : (Ibf/100ft2) SLURRY Mix Fluid :8.231 gal/sk Yield :2.47 ft3/sk Porosity :44.5 Density :8.321b/gal Job volume :92.9 bbl Quantity :211.06 sk Solid Fraction :55.5 Base Fluid :8.131 gal/sk .Page 6 iJ-760 cement, V2.cfw; 01-2{5'-'2007 ; Loadcase 1338 Surfac'lett; Version wcs-cem45_89 Client CPAI Well 1J-160 String 133/8 Surface District Prudhoe Bay Country USA Loadcase 1338 Surface • • ~GIr~~r Section 4: fluid sequence Original fluid Mud 9.60 Ib/gal P~ :45.000 cP Tv :30.00 Ibf/100ft2 Displacement Volume 471.0 bbl Total Volume 1176.6 bbl TOC 0.0 ft Name Volume bbl Ann. Len ft Top ft Fluid Sequence Density Ib/ al Rheology CW 100 50.0 0.0 8.32 viscosity:5.000 cP MUDPUSH II 50.0 0.0 10.50 P~:23.000 cP Tv:30.00 Ibf/100ft2 ASL 512.7 2426.0 0.0 10.70 P~:28.660 cP Tv:16.97 Ibf/100ft2 DeepCRETE 92.9 800.0 2426.0 12.00 P~:105.064 cP Tv:11.81 Ibf/100ft2 Water 20.0 3012.4 8.32 viscosity:1.000 cP Mud 451.0 0.0 9.60 P~:45.000 cP Tv:30.00 Ibf/100ft2 Static Security Checks Frac 7 psi at 80.0 ft Pore 10 psi at 80.0 ft Collapse 1829 psi at 3146.0 ft Burst 4310 psi at 0.0 ft Cs .Pump out 53 ton Section 5: pumping schedule Name CW 100 Pause CW100 Pause MUDPUSH II ASL DeepCRETE Pause Water Pause Mud Mud Flow Rate (bbl/min) 5.0 0.0 5.0 0.0 6.0 7.0 6.0 0.0 5.0 0.0 7.0 3.0 Volume (bbl) 10.0 0.0 40.0 0.0 50.0 512.7 92.9 0.0 20.0 0.0 431.0 20.0 Pumping Schedule Stage Time Cum.Vol (min) (bbl). 2.0 10,0 10.0 0,0 8.0 50.0 5.0 0.0 8.3 50.0 73.2 512.7 15.5 92.9 5.0 0.0 4.0 20.0 5.0 0.0 61.6 431.0 6.7 451.0 Inj. Comments Temp. (degF) 80 80 Pressure test lines 80 80 Drop bottom plug 80 80 80 80 Drop top plug 80 80 Switch to rig 80 80 Slow to Bump Total 03:24 1176.6 bbl hr:mn Dynamic Security Checks Frac 7 psi at 80.0 ft Pore 0 psi at 80.0 ft Collapse 1829 psi at 3146.0 ft Burst 4105 si at 0.0 ft Page 7 1J-160 cement,V2cfw;01-25-2007; LoadCase1338Surface;Versionwcs-cem45_69 ~~._ r,~„ €~, a •' Schlumberger CemCADE Preliminary Job Design 9.625" Intermediate Casin Preliminary Job Design based on limited input data. For estimate purposes only. Rig: Doyon 15 Location: West Sak Client: ConocoPhillips Alaska, Inc. Revision Date: 1/25/2007 Prepared by: Maureen Torrie Location: Anchorage, AK Phone: (907) 276-1215 Mobile: (907) 952-0445 email: mtorrie@slb.com Previous Csg. < 13 3/8", 72.0# casing at 3,226' MD < Top of Tail at 5,300' MD < 9 5/8", 40.0# casing in 12 1/4" OH TD at 9,704' MD (3,265' TVD) Volume Calculations and Cement Systems Volumes are based on 25% excess. Tail slurry is designed for 800' MD above target - (4404' MD annular length). Tail Slurry Minimum thickening time: 310 min. (Pump time plus 120 min.) DeepCRETE @ 12.5 ppg - 2.25 ft3/ft 0.3132 ft3/ft x 4404' x 1.25 (25% excess) = 1724.2 ft3 0.4257 ft3/ft x 80' (Shoe Joint) = 34.1 ft3 1724.2 ft3 + 34.1 ft3 = 1758.3 ft3 1758.3 ft3/ 2.25 ft3/sk = 781.5 sks Round up to 790 sks BHST = 75~, Estimated BHCT = 60`F. (BHST calculated using a gradient of 2.6`F/100 ft. below the permafrost) PUMP SCHEDULE Pump Rate Stage Stage Time Cumulative Stage (bpm) Volume (min) Time (bbl) (min) CW 100 5 50 10.0 10.0 Drop Bottom Plug 10.0 20.0 MudPUSH II 5 75 15.0 35.0 Tail Slurry 5 317 63.4 98.4 Drop Top Plug 10.0 108.4 Water 5 20 4.0 112.4 Switch to Rig Pumps 5.0 117.4 Displacement 7 690 98.6 216.0 Slow Rate 3 20 6.7 222.7 MUD REMOVAL Recommended Mud Properties: 9.3 ppg, Pv < 15, TY < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 11.0 ppg MudPUSH" II, Pv = 19-22, TY = 22-29 Centralizers: Recommend 1 perjoint across zones of interest for proper cement placement. ORIGINAL ~ ~ Schlumberger CemCAD E*well cementing recommendation for 9-5/8 Intermediate Operator : CPAI Well 1J-180 DLI Country :USA Field West Sak State :Alaska Prepared for :Mike Greener Location Proposal No. : V2 (WP06) Service Point Prudhoe Bay Date Prepared :January 25, 2007 Business Phone (907) 659-2434 FAX No. (907) 659-2538 Prepared by Phone E-Mail Address Maureen Torrie 1-907-265-6336 mtorrie@slb.com ~G~,~~ ' ; s;,. ,n C ~.q VAT E Y Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumbergercan assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wel Is might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Mark of Schlumberger ~~~~A~ • • Client CPAI Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581ntermediate Section 1: well description Configuration :Casing Stage :Single Rig Type :Land Mud Line : 0.0 ft Total MD :9800.0 ft BHST : 75 degF Bit Size : 12 1/4 in Previous String MD OD Weight ID ft in Ib/ft in 3600.0 13 3/8 68.0 12.415 Landing Collar MD :9624.0 ft Casing/liner Shoe MD :9704.0 ft ~cl r~~r Casing/Liner MD OD Joint Weight ID Grade Collapse Burst Thread (ft) (in) (ft) (Ib/ft) (in) (psi) (psi) 9704.0 9 5/8 40.0 40.0 8.835 L-80 2780 4920 IFJ 1J-160 cement,V2.cfw;01d5-2007; LoadCase9581ntermediate;Versionwcs-cem45_69 Page 2 ORIGINAL Client CPAI Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581ntermediate Mean OH Diameter :12.250 in Mean Annular Excess :25.0 Mean OH Equivalent Diameter: 12.823 in Total OH Volume :974.9 bbl (including excess) Max. Deviation Angle : 92 deg Max. DLS :13.726 deg/100ft MD ft Directional Survey Data TVD Deviation Azimuth ft de de Dogleg Sev. de /100ft 0.0 0.0 0.0 0.0 0.000 40.0 40.0 0.0 0.0 0.000 100.0 100.0 0.0 0.0 0.000 200.0 200.0 0.0 0.0 0.000 300.0 300.0 0.0 0.0 0.000 400.0 400.0 2.5 267.0 -2.500 500.0 499.7 5.0 267.0 2.500 600.0 599.1 7.5 267.0 2.500 702.1 700.0 10.1 267.0 2.499 800.0 795.8 14.0 267.0 4.002 900.0 891.9 18.0 267.0 4.000 1000.0 985.9 22.0 267.0 4.000 1100.0 1077.2 26.0 267.0 4.000 1200.0 1165.5 30.0 267.0 4.000 1300.0 1250.3 34.0 267.0 4.000 1400.0 1331.3 38.0 267.0 4.000 1500.0 1407.9 42.0 267.0 4.000 1600.0 1479.8 46.0 267.0 4.000 1629.3 1500.0 47.1 267.0 3.990 1667.2 1525.8 47.1 267.0 0.000 1700.0 1548.1 47.1 267.0 0.000 1729.3 1568.0 47.1 267.0 0.000 1800.0 1615.1 49.2 267.4 2.998 1856.8 1651.6 50.9 267.7 3.001 1900.0 1678.4 52.2 267.9 3.010 2000.0 1737.6 55.2 268.3 3.003 2100.0 1792.5 58.2 268.8 2.991 2200.0 1843.0 61.2 269.2 3.000 2300.0 1889.0 64.1 269.5 3.009 2400.0 1930.2 67.1 269.9 2.998 2423.5 1939.2 67.8 270.0 2.994 2500.0 1966.7 70.1 270.3 2.999 2600.0 1998.3 73.1 270.6 2.996 2700.0 2024.9 76.1 270.9 3.006 2768.3 2040.1 78.1 271.1 3.002 2800.0 2046.7 78.1 271.1 -0.000 2900.0 2067.3 78.1 271.1 0.000 3000.0 2087.9 78.1 271.1 0.000 3100.0 2108.5 78.1 271.1 0.000 3200.0 2129.1 78.1 271.1 0.000 3226.5 2134.5 78.1 271.1 0.000 3300.0 2149.7 78.1 271.1 0.000 3317.2 2153.2 78.1 271.1 0.000 3400.0 2170.3 78.1 271.1 0.000 3500.0 2190.9 78.1 271.1 0.000 3600.0 2211.5 78.1 271.1 0.000 3700.0 2232.1 78.1 271.1 0.000 ~clr~~r iJ-160 cement,V2cfw;01d5-2007; LoadCase9581ntermediate;Versionwcs-cem45_89 Page 3 ORIGINAL • • Client CPAI Well iJ-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581ntermediate MD (ft Directional Survey Data ND Deviation Azimuth ft deg de Dogleg Sev. (de /100ft 3800.0 2252.7 78.1 271.1 0.000 3900.0 2273.3 78.1 271.1 0.000 4000.0 2293.9 78.1 271.1 0.000 4100.0 2314.5 78.1 271.1 0.000 4200.0 2335.1 78.1 271.1 0.000 4300.0 2355.7 78.1 271.1 0.000 4400.0 2376.3 78.1 271.1 0.000 4500.0 2396.9 78.1 271.1 0.000 4600.0 2417.5 78.1 271.1 0.000 4700.0 2438.1 78.1 271.1 0.000 4800.0 2458.7 78.1 271.1 0.000 4900.0 2479.3 78.1 271.1 0.000 5000.0 2499.9 78.1 271.1 0.000 5100.0 2520.5 78.1 271.1 0.000 5200.0 2541.1 78.1 271.1 0.000 5300.0 2561.8 78.1 271.1 0.000 5400.0 2582.4 78.1 271.1 0.000 5500.0 2603.0 78.1 271.1 0.000 5600.0 2623.6 78.1 271.1 0.000 5700.0 2644.2 78.1 271.1 0.000 5800.0 2664.8 78.1 271.1 0.000 5863.4 2677.8 78.1 271.1 0.000 5904.8 2686.4 78.1 271.1 0.000 6000.0 2706.3 77.7 268.2 -2.996 6100.0 2727.9 77.4 265.2 -3.000 6200.0 2750.0 77.0 262.1 -3.002 6300.0 2772.7 76.7 259.0 -2.995 6400.0 2795.9 76.5 256.0 -3.007 6500.0 2819.5 76.3 252.9 -3.001 6600.0 2843.4 76.1 249.8 -2.997 6672.4 2860.9 75.9 247.6 -3.005 6700.0 2867.6. 75.9 246.7 -2.993 6800.0 2892.1 75.8 243.6 -2.998 6900.0 2916.6 75.7 240.5 -2.996 6925.6 2922.9 75.7 239.7 -3.033 7000.0 2941.3 75.7 237.4 -2.995 7100.0 2965.9 75.7 234.3 3.004 7200.0 2990.5 75.8 231.2 2.996 7300.0 3015.0 75.9 228.2 2.997 7400.0 3039.3 76.0 225.1 3.000 7500.0 3063.3 76.2 222.0 3.004 7595.1 3085.9 76.4 219.1 3.000 7600.0 3087.0 76.4 218.9 2.995 7700.0 3110.3 76.6 215.8 2.996 7800.0 3133.2 76.9 212.8 3.003 7900.0 3155.6 77.3 209.7 3.000 8000.0 3177.3 77.6 206.6 2.997 8100.0 3198.5 78.0 203.6 3.006 8164.2 3211.7 78.3 201.7 2.988 8198.8 3218.7 78.4 200.6 3.003 8200.0 3218.9 78.4 200.6 3.285 8218.8 3222.7 78.5 200.0 2.996 8243.8 3227.7 78.5 200.0 0.000 8273.6 3233.6 78.5 199.1 3.002 8275.0 3233.9 78.7 199.0 13.726 Sclr~~r iJ-160 cement,V2.cfw;01d5-2007; LoadCase9581ntermediate;Versionwcs-cem45_89 Page 4 ORIGINAL • • Client CPAI Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country : USA Loadcase 9581ntermediate MD ft Directional Survey Data TVD Deviation Azimuth ft deg) de Dogleg Sev. de /100ft 8290.1 3236.6 80.5 197.9 13.622 8296.6 3237.7 80.5 197.9 0.000 8300.0 3238.2 80.5 197.9 0.000 8310.1 3239.9 80.5 197.9 0.000 8350.0 3245.9 82.3 195.8 6.987 8400.0 3251.5 84.6 193.2 7.005 8450.0 3255.2 86.9 190.6 6.988 8500.0 3256.9 89.3 187.9 6.995 8550.0 3256.5 91.6 185.3 7.012 8560.3 3256.1 92.1 184.8 6.947 8600.0 3254.7 92.1 184.8 0.000 8700.0 3251.0 92.1 184.8 0.000 8800.0 3247.4 92.1 184.8 0.000 8849.2 3245.6 92.1 184.8 0.000 8900.0 3244.2 91.1 182.5 -4.992 8953.6 3243.7 90.0 180.0 -5.011 9000.0 3244.1 89.0 179.0 -3.003 9100.0 3247.6 86.9 176.9 -2.997 9182.1 3253.3 85.2 175.1 -3.003 9200.0 3254.8 85.2 175.1 -0.000 9309.7 3264.0 85.2 175.1 0.000 9400.0 3269.6 87.7 176.2 2.997 9500.0 3271.2 90.4 177.3 2.998 9565.4 3269.7 92.3 178.1 3.009 9565.8 3269.7 92.3 178.1 0.000 9600.0 3268.3 92.3 178.1 0.000 9700.0 3264.4 92.3 178.1 0.000 9800.0 3260.5 92.3 178.1 0.000 Formation Data MD Frac. Pore Name Lithology ft Ib/ al Ib/ al 1700.0 12.50 8.20 Permamfrost 6200.0 12.50 8.20 Ugnu C 7200.0 12.50 8.40 Ugnu B 7500.0 12.50 8.40 Ugnu A 8100.0 12.50 8.40 K-13 9970.0 12.50 8.40 TD Sandstone Geothermal Temperature Profile MD TVD Temperature Gradient ft ft de F de F/100ft 0.0 0.0 25 0.0 1700.0 1549.9 30 0.3 9704.0 3263.9 75 1.5 9800.0 3260.5 74 1.5 9970.0 3252.8 74 1.5 iJ-160 cement, V2c5w;01-25dOD7; LoadCase9581ntermediate;Versionwcs-cem45_89 ~cing~r Page 5 • • Client CPAI Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581ntermediate Section 2: centralizer placement Top of centralization :5000.0 ft Bottom Cent. MD :9694.0 ft Casing Shoe :9704.0 ft NB of Cent. Used :115 NB of Floating Cent. :0 Schl~mb~rg~r Centralizer Placement Bottom MD Nbr. Cent. I Cent. Name Code Min. STO @ Depth ft Joint % ft 6224.0 0 0/0 0.0 6229.4 7224.0 25 1/1 ALPINE 958 ASB 0.0 7205.8 7904.0 0 0/0 0.0 7224.0 9704.0 90 2/1 ALPINE 958 ASB 0.0 7912.2 Centralizer Description Centralizer Tests Cent. Name Code Casing Max. Min. OD Rigid Origin Hole Size Running Restoring OD OD (in) (in) Force Force in in Ibf Ibf ALPINE 958 ASB 9 5/8 13.625 10.813 No Weatherford 12.250 485.00 1967.00 (1) -Centralizer pertormance data is based on tests by WEATHERFORD as per the current API 10D specifications ft % deg (x 1000) ft 0 50 100 ~ ~ -Deviation 0 0 0 v °o 0 w °o 0 N Pipe StarxJoff i....-, ..._, .-i... I ..., .... Deviation Hori. Departure 1J~160 cement, V2.cfw:01~25-2007; Loadcase 9581ntermediate; Version wcs-cem45_89 Page 6 ORIGINAL • • Client CPAI Scl~~rg~r Well 1J-180 DLI String 9-5/8lntermediate District : Prudhoe Bay Country USA Loadcase 9581ntermediate Section 3: fluid description Mud DESIGN Fluid No: 1 Density : 9.30 Ib/gal Rheo. Model : HERSCHEL_B. k : 1.44E-2 Ibf.s^n/ft2 At temp. : 80 degF n :0.508 Ty :6.091bf/100ft2 Gel Strength :76.85 Ibf/100ft2 MUD Mud Type : WBM Job volume :709.8 bbl Water Type :Fresh VOLUME FRACTION Solids :95.0 Oil : 0.0 °lo Water : 5.0 CW100 DESIGN Fluid No: 2 Density : 8.32 Ib/gal Rheo. Model : HERSCHEL_B. k : 6.68E-3 Ibf.s^n/ft2 At temp. : 80 degF n :0.177 Ty :O.OOIbf/100ft2 Gel Strength : (Ibf/100ft2) Job volume :50.0 bbl MUDPUSH II DESIGN Fluid No: 3 Density : 11.00 Ib/gal Rheo. Model : HERSCHEL_B. k : 8.59E-2 Ibf.s^n/ft2 At temp. : 80 degF n :0.279 Ty :11.821bf/100ft2 Gel Strength : (Ibf/100ft2) Job volume :75.0 bbl DeepCRETE DESIGN Fluid No: 4 Density : 12.50 Ib/gal Rheo. Model : HERSCHEL_B. k : 8.69E-3 Ibf.s^n/ft2 At temp. : 80 degF n :0.833 Ty :O.OOIbf/100ft2 Gel Strength : (Ibf/100ft2) DESIGN BLEND Name : G Dry Density : 199.77 Ib/ft3 Sack Weight : 94 Ib BASE FLUID Type :Fresh water SLURRY Mix Fluid :7.558 gal/sk Yield :2.25 ft3/sk Porosity :44.9 Density :8.321b/gal Job volume :313.1 bbl Quantity :781.35 sk Solid Fraction :55.1 Base Fluid :7.418 gal/sk 1J-160 cement,V2cfw;01d5-2007; LoadCase9561ntermediate;Versionwcs-cem45_89 ~ , ~ ~ ~ ~~ Page 7 • Client CPAI ~clrg~r Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581ntermediate Section 4: fluid sequence Original fluid Mud 9.30 Ib/gal k : 1.44E-2 Ibf.s^n/ft2 n :0.508 Tv :6.09 Ibf/100ft2 Displacement Volume 729.8 bbl Total Volume 1167.9 bbl TOC 5300.0 ft Fluid Sequence Name Volume Ann. Len Top Density Rheology bbl ft ft Ib/ al CW 100 50.0 732.6 3491.8 8.32 k:6.68E-3 Ibf.s^n/ft2 n:0.177 Tv:0.00 Ibf/100ft2 MUDPUSH II 75.0 1075.6 4224.4 11.00 k:8.59E-2 Ibf.s^n/ft2 n:0.279 Tv:11.82 Ibf/100ft2 DeepCRETE 313.1 4404.0 5300.0 12.50 k:8.69E-31bf.s^n/ft2 n:0.833 Tv:0.001bf/100ft2 Water 20.0 9360.2 8.33 k:6.94E-31bf.s^n/ft2 n:0.281 Tv:0.071bf/100ft2 Mud 709.8 0.0 9.30 k:1.44E-21bf.s^n/ft2 n:0.508 Tv:6.091bf/100ft2 Static Security Checks Frac 369 psi at 3600.0 ft Pore 125 psi at 3600.0 ft Collapse 2521 psi at 9470.5 ft Burst 4912 psi at 4224.4 ft Cs .Pum out 52 ton Section 5: pumping schedule Name Flow Rate (bbl/min) Volume (bbl) Pumping Schedule Stage Time Cum.Vol (min) (bbl). Inj. Temp. de F Comments CW100 5.0 10.0 2.0 10.0 80 Pause 0.0 0.0 10.0 0.0 80 Pressure test lines CW100 5.0 40.0 8.0 50.0 80 Pause 0.0 0.0 5.0 0.0 80 Drop bottom plug MUDPUSH II 5.0 75.0 15.0 75.0 80 DeepCRETE 6.0 313.1 52.2 313.1 80 Pause 0.0 0.0 5.0 0.0 80 Drop top plug Water 5.0 20.0 4.0 20.0 80 Pause 0.0 0.0 5.0 0.0 80 Switch to rig Mud 7.0 689.8 98.5 689.8 80 Mud 3.0 20.0 6.7 709.8 80 Slow to Bum Total 03:31 1167.9 bbl hr:mn Dynamic Security Checks Frac 111 psi at 9704.0 ft Pore 125 psi at 3600.0 ft Collapse 2432 psi at 165.4 ft Burst 4438 si at 0.0 ft 1J-160 cement,V2.cfw;01-25-2007; Loadcase 9581ntermediate;Versionwcs-cem45_69 Page 8 ORIGINAL Client CPAI Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581nterm ediate ft o ~ -~ ~ 0 0 V S~hlu~6~rgcr It~gal 10 12 14 A4n. kydrostatic °o ~ - Max. Dynamic fv5n. Dynamic --~ Frac _ - Pore ' 'rn Hydrostatic '. ~-~ 4. N S o 0 250 Time (min) 0 0 o- 0 0 0 N Fluid Sequence 0 0 o_ X `-~ O :N Q N N 11 ~_ ~ m _ `J/U4 n L J ~~ r 100 195 150 175 200 22E Time (min) m ~_ N N ~ N N ~ O ~ ~ C C Q Time (min) Page 9 1J-160 cement,V2.cfw;01-25-2007; Loadcase 9581ntermediate;Versionwcs-cem45_69 ORIGINAL • Client CPAI Well 1J-180 DLI String 9-5/8lntermediate District Prudhoe Bay Country USA Loadcase 9581ntermediate Section 6: WELLCLEAN II Simulator ~ era pro 0 100 01 - Mud Contamination - lMcontarrinated Slurry 0 0 0 v 0 0 0 N Fluid Sequence Cement Coverage Uncontaminated Slurry Fluids Concentrations 5000 5500 8000 6500 7000 7500 ° 8000 5500 ~1ud Q MUDPUSH II 0 '~/ater CW100 ~ DeepCRETE Schi~~lb~rg~r deg Deviation Risk Mud on the Wall z° r3 5000 ~ I ' 5000 5540- I 5500 8400- J b000 6500_ l~ IJ 5500 7000 - 1 ( ., 7oao 7500 - ~ ~ 7500 ° 8000 - 8000 ° 8500- 8500 9000- 9000 9507- 9500 ~ o ` • ~ o z ~ High ' ` Low ~ Medium ~ None Page 10 1J-160 cement, V2.cfw; 0145-2007 ; LoadCase 9581ntermediate ; Version wcs-cem45_69 oR~Gi~A~ n O Insulated Conductor In Casing, 20", 94#, K55 x 34".0.312" WT tr +/ 80' IDID \ - ~ . U~ z A ",0 ~ A F ~ rn s~ „~fD„ ~- ~ !' v"o- o s o r y ~' 'i .~ L O i '' a ;: R 3 '~~ bb ~z;~ 13-3/8", 68#, L-80, BTC, R3 3,31 T MD / 2, 153' Tb'D ~~ L 78.1 I degrees TD 16" hole Top of Ugnu C Cad S,8G3' MD / 2,678' TVD ~ Lateral Entry Module #2 (LEM), Bakcr, with seal bore and ZXP packer @ x,xxx' MD, z,xzx' TVD Lateral Entry Module #1 (LEM), Baker, with seal bore and ZXP -~ packer (rid x,xxs' MU, x,xxx' TVD Top of West Sak B @ 8,631' MD / 3,303' TVD ~ Tubing, 4-'/n" IBTM1I, from LEM to A2 Liner, with seal stem and - CAMCO 3.562" "DB" nipple. Top of West Sak A4 (n1 8,851' MD / 3,343' TVD ~ Seal bore and ZXP packer for A2 liner +/- 8,731' MD, 3,320' TVD 9-5/8", 40#, L-80, BTCM, R3 Csg (~~704'MD/3472'TVD ~ 87 degrees TD 12-I/4" hole Wellhead /'t'ubing Ilead /Tree, 10-3/4" x 4-'.i'. S,000 ksi Tubing String: 41/2", 12.6 #, L-80, IBTM (1) 3.875" DB nipple set +/- 500' - (1) Gas Lift Mandrel, CAbICO 4-1/2" x ]" Model RBG-2, ~ +/- 2,400' TVD. (I) Gas Lift Mandrel, CAMCO 4-1/2" x I" Model KBG-2, above sliding sleeve - (1) Sliding Sleeve, with 3.812" nipple, I joint above seals) 160 L2 "D" Sand Window (a3 8,273' MD / 3,233' TVD 78.5 degrees "D" Liner, 4-I/2", 11.6#, L8Q BTCbf, R2 160 LI "B" Sand Window @, 8,663' MD / 3,309' TVD 79.3 degrees ~ "B" Liner, 4-1/2", 11.6#, L80, BTCM, R2 A2 Sand Liner, 4- V2", I I b#, L30, BTCM, RZ r` IJ-160 L2: 6-3/4" D sand lateral TD 14,457 MD / 3,173' TVD Angle 91 degrees IJ-lG0 LI: 6-3/4" `B" sand lateral TD 14,466' MD / 3,249' TVD Angle 9l degrees 6-3/4 A2 sand lateral - TD 14,478' M1ID / 3,407 TVD Angle 91 degrees ~ ~ 4 ~~ Thomas Maunder wrote, On 2/1/2007 10:13 AM: Thanks Mike. Don't need a ghost from the past showing up. So far as I know, there was no problem drilling 34-11-10-1 until they drilled into the overpressured Kuparuk. It was "felt" (don't know that anything formal was ever done) that the gas had migrated along faults from the 1 B pad area. I am reviewing the file we have and there are hand-written reports from the rig in it. You can access the file on-line from the AOGCC web site. Tom Maunder, PE .-- AOGCC ~~~~,5 Greener, Mike R. wrote, On 2/1/2007 10:08 AM: I found. ozrt some information about the KL1 P 34- I l -10-1 pertaining to the llnderground blowout that well suffered. that you called me about. C7eology reports that the I~L~P 34-11-10-1 penetration afthe `'Vest Sak sands is in tl~c fault block just north of ivllere our intermediate casing for the 1 J-1 Ei0 penetrates the West Sak Sands. They feel the faults are sealing and the gas that was lost f~roln the underground blo~~%out would not affect us. Also, the 1 E-1.70 well's toe penetrated. into the fault block that the KUP 3~-1 1-10-1 is in. We dial not experience any has influx or other wellbore problems while d:rillil~g or while running the liner. This is nat to say that the gas lost to the West Sak is gone, but I suspect that it may have lnigl-ated up dip al~d could be a factor in future wells to the west (i.e. West Sak development to the west). I have pulled the well flea for. the KUI' 3~-l l -10-1 to see what .happened on that well when. they dl°illed into the Koparuk but the daily drilling reports are missing. We are currently searching the list of prcviaus check out persons to llullt them do~~~n. The 34-11-10-1 PA report shows it was plugged in 1.989. My plan fc3rcval•d tt~r the drilling of the 1 J-1 Fi0 will be to .have the rig schedule a pre-drill i meetitlg with all personnel ola t}~e rig before we drill :into the K-13 to get evet-~Tone's aw=areness up about possible well events that could happen and our reaCtl®n t0 them. This will also be covered in the :pre-spud meeting on location. Nike Greener «Greener, Mike R..vcf» 1 of 1 2/2/2007 1:21 PM _..._-_~_._.~-...~~~ ..,_.-...n~,~.d..,.~ _,.~...~. SHARON K. ALLSUP-DRAKE CONOCOPHILLIPS ATO 1530 700 G ST. DATE~D~~K~~ ~$6-1551/441 ANCHORAGE AK 99501 G PAY 70 THE STS TE D! ~L~ S~~ ~" (~'I ~ i ~ (VO. O~ ORDER OF (77~ ~~ _~ ~_J p, ~~ ~ G~-~7~(1~7'S ~'"T^ ~~'' bbLLARS W ~.,,~.~,~~. JPMorganChase ~ j valia up To 5000 uonar~ JPMorgan Chase Bank, N.A. Columbus, OH MEMO ~~ ~:t74~, l L5.51 L~:5.28 74 7 190 79 2 7!!' L L73 • • TRANSMITTAL LETTER CHECKLIST WELL NAME 1L~~ PTD# 20 ~ -!'~~ Development ''Service Exploratory Stratigraphic Test Non-Conventional Well Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. API No. 50- - - API number are , between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( 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. Please note the following special condition of this permit: Non-Conventional production or production testing of coal bed methane is not allowed Weil for (name of well) until after (Company NameZhas designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Compan~Zmust contact the Commission to obtain advance approval of such water well testing ro ram. Rev: 1/25/06 C:\j ody\transmittal_checkl ist • ~ I1 y ~ ~ ~ ~ ~ ~ : m ° , ~ o , o ~ ~ ~ a`i ~ i ~ ~ Q m: ~: ai, m: ~~ ~ 4 : ao c: ~ , ~: ~, a, c O ~ oa N, ui 3. N' >, otS, , m, ; m: : OO D. ! Y, m : W fn ~: ~ s: U: ~ pi ~ i ~ ~ ~ N: ~ ~ , p~ U ~ ~, ~ fl. ~: , rn n v: 3: a ~ : O ~ ~: >a N: O o ~ ~ a ~ ~, o C• m, O: Q. $ _: ~ : a: : ~: m rn O ~: m c m, a' a~: _ ~, o; ~~ ~ ~ ~ $ ~ 7. 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C, C ` E : ,n r _ >, „-: Y N O M' , f C o C~ , >: ~ V: a: ~~ C .. : 4 O ~: 02f' +y„' ~' y: c L' N y' fl= o, o: N L O. rn m c C ~ ~ Y~ Q Y O O a 7 ~ ~ ~ ~ - O -o, °: a m: ~ ~ ~ ~ N o o: Q, ~ o O rn °: : m ~y '~ ~: Q, ~ m: • C, o, ~: a, ' ~ , ~ a, •3, i ~ y: > ~ y, m~ ~ ~ Y O •a~ •y 4. g ~: m m: .5: o , o ~ ~ ° a' co' m, ° Y m o o , y: m: o, ~: i~ ~~ m: Q m, ~: y. ' T o: o o, m: ~ ~n ~ ~ Y ~ O~ o ~~ a C~ C~ N~ ~ m > ~ ~~ O~ O~ N o . c~ N' y - d S ~ ~' 0' ~m .. ~: O~ 3, ~ ~: O: ~, I L, ~: 3, V a>: 3 .O ~ Q I U ~ f6: : : °, m m p a: m: 01 N, m ~ m ~ ~, D1 ~ ~ ; ~: . . a m: ~ ~: . a: ~: f0 a. ~, N. y' ' c ~' ~ m: ~: y M ca ' : ~' ~-: o: y: L ~' y, rn N: ~ °~' a fl: 3, O ~ y' o' C a>' 3 0 >i m' a~ : o' c w o o a fl: 0: ~+: ~: m: a c: c 'a: 'a: >, , 3 ~ a m, .Q a, 3 a: a~ > a~, ~: ..: ~, ` a .~ ~, v. o ..: o. o ~ o ~: v `t ~ a~ o y: Q .a m ~ m: o, o rn c . o a L ~~ y m a U 0 Q. 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' ~', m; ~~ ~', o ~ U c a, ~, ~, ~; ~; ~ : cn; ~; O, O, a; a; U ¢; a, z; ~ ~ : U ~, U, U, U; U, Q, "=; Q, ~ a m, m, U, , y ~, ,, ~ a, q cn, cn, U w a ' _ ~ ~ o N ~ '~ ~~~~ ' O ~ _ N N N O M M M M O ~ N __..-__- M 'ti tfi CO I~ O _ _ O ____._-~. ~ __- . --~ r N N N N N N M M N M M M M U _ ~ ___ U c r` o N I I 0 / r` 0 N tJ C O ~ C O '+ m ~ O li ! R Q N ~ ~ (/- N ~i _ ~ p 0 O ~ y O w ~ a + ~ CM ~ I 01 C: N M ~ y ° ~~ W ~ Q p ~~ . O Q ~ ~ O G. p U ~ ~ a a ~- cn a w a a w ~ o ~ aw a~ o. a ~ s Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Wetl History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special efi(ort has been made to chronologically organize this category of information. • 1716000313200755N.txt Sperry-Sun Drilling Services LIS scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Fri May 25 14:41:53 2007 Reel Header Service name ............. LISTPE Date . ................... 07/05/25 Ori in ................... STs Ree~ Name. .... ........ UNKNOWN Continuation Number...... 01 Previous Reel Name....... UNKNOWN Comments .................STS LIS writing Library. Scientific Technical services Tape Header Service name .............LISTPE Date . ...................07/05/25 Origin ...................STs Tape Name. .... ........UNKNOWN Continuation Number......01 Previous Tape Name......,UNKNOWN Comments .................STS LIS writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER Kuparuk River Unit west Sak MWD/MAD LOGS WELL NAME: 1J-160 API NUMBER: 500292334400 OPERATOR: ConocoPhillips Alaska Inc. LOGGING COMPANY: Sperry Drilling Services TAPE CREATION DATE: 25-MAY-07 ]OB DATA MWD RUN 3 706 NUMBER: w-0004877337 LOGGING ENGINEER: T. MCGUIRE OPERATOR WITNESS: M. THORNTON SURFACE LOCATION SECTION: 35 TOWNSHIP: 11N RANGE: l0E FNL: FSL: 2016 FEL: 2541 FWL: ELEVATION (FT FROM MSL O) KELLY BUSHING: DERRICK FLOOR: 122.29 GROUND LEVEL: 81.00 WELL CASING RECORD Page 1 US.~- ao~ "b(~. `~ t 51 ~5 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING REMARKS: 1716000313200755N.txt OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 12.250 13.375 3551.0 1. ALL DEPTHS ARE BIT DEPTHS UNLESS OTHERWISE NOTED. THESE DEPTHS ARE MEASURED DEPTH (MD). 2. ALL VERTICAL DEPTHS ARE TRUE VERTICAL DEPTH (TVD). 3. MWD RUNS 1 & 2 WERE DIRECTIONAL ONLY - NO DATA ARE PRESENTED. 4. MWD RUN 3 COMPRISED DIRECTIONAL, DUAL GAMMA RAY (DGR) UTILIZING GEIGER- MUELLER TUBE DETECTORS, ELECTROMAGNETIC WAVE RESISTIVITY PHASE-4 (EWR4), COMPENSATED THERMAL NEUTRON POROSITY (CTN), AZIMUTHAL LITHO-DENSITY (ALD), ACOUSTIC CALIPER (ACAL), PRESSURE-WHILE-DRILLING (PWD), AND GEO-PILOT ROTARY STEERABLE BHA (GP). NOTE THAT ALD HOLE SIZE INDICATOR (HSI) WAS USED FOR CTN CORRECTION DUE TO ACAL SHOWING UNDERGAUGE HOLE. 5. DEPTH SHIFTING OF MWD DATA WAS WAIVED PER E-MAIL, DATED 12/16/04, FROM M. WERNER (CPAI) TO R. KALISH (SDS). MWD DATA ARE CONSIDERED PDC. 6. MWD RUNS 1-3 REPRESENT WELL 1J-160 WITH API#: 50-029-23344-00. THIS WELL REACHED A TOTAL DEPTH (TD) OF 10271'MD/3456'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED. SEXP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA SHALLOW SPACING). SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (SHALLOW SPACING). SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM SPACING). SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP SPACING). SFXE = SMOOTHED FORMATION EXPOSURE TIME (DEEP SPACING). TNPS = SMOOTHED THERMAL NEUTRON POROSITY (SANDSTONE LITHOLOGY, HSI-DERIVED). CTFA = SMOOTHED AVERAGE OF FAR DETECTOR'S COUNT RATE. CTNA = SMOOTHED AVERAGE OF NEAR DETECTOR'S COUNT RATE. ACAL = ACOUSTIC CALIPER. HSI = ALD HOLE-SIZE INDICATOR. SBD2 = SMOOTHED BULK DENSITY-COMPENSATED (LOW-COUNT BIN). SC02 = SMOOTHED STANDOFF CORRECTION (LOW-COUNT BIN). SNP2 = SMOOTHED NEAR DETECTOR ONLY PHOTOELECTRIC ABSORPTION FACTOR (LOW-COUNT BIN). Page 2 1716000313200755N.txt PARAMETERS USED IN POROSITY LOG PROCESSING: HOLE SIZES: HSI-DERIVED - 12.25~~ BIT MUD WEIGHT: 9.2 - 9.5 PPG MUD SALINITY: 500 - 700 PPM CHLORIDES FORMATION WATER SALINITY: 5500 - 9000 PPM CHLORIDES FLUID DENSITY: 1.0 G/CC MATRIX DENSITY: 2.65 G/CC LITHOLOGY: SANDSTONE File Header Service name... .......STSLIB.001 Service Sub Level Name... version Number. ........1.0.0 Date of Generation.......07/05/25 Maximum Physical Record..65535 File Type. ............LO Previous File Name.......ST5L26.000 Comment Record FILE HEADER FILE NUMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH GR 3525.0 10235.0 FET 3540.0 10227.5 NPHI 3540.0 10180.5 PEF 3540.0 10198.0 RPX 3540.0 10227.5 RPM 3540.0 10227.5 CALA 3540.0 10184.0 RPD 3540.0 10227.5 DRHO 3540.0 10198.0 RHOB 3540.0 10198.0 NCNT 3540.0 10180.5 FCNT 3540.0 10180.5 RPS 3540.0 10227.5 ROP 3561.5 10271.0 BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH MERGED DATA SOURCE PBU TOOL CODE BIT RUN NO MERGE TOP MERGE BASE MwD 3 3525.0 10271.0 REMARKS: MERGED MAIN PASS. Data Format specification Record Data Record Type... ..........0 Data Specification Block Type.....0 Logging Direction .................Down optical log depth units...........Feet Page 3 • 17160003132007SSN.txt Data Reference Point ..............undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Absent value ......................-999 Depth Units. .. .. .. ..... Datum specification Block sub-type...0 Name service order units size Nsam Rep code offset channel DEPT FT 4 1 68 0 1 CALA MWD INCH 4 1 68 4 2 FCNT MWD CNTS 4 1 68 8 3 NCNT MWD CNTS 4 1 68 12 4 RHOB MWD G/CM 4 1 68 16 5 DRHO MWD G/CM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 RPM MWD OHMM 4 1 68 28 8 RPS MWD OHMM 4 1 68 32 9 RPX MWD OHMM 4 1 68 36 10 FET MWD HOUR 4 1 68 40 11 GR MwD API 4 1 68 44 12 PEF MWD BARN 4 1 68 48 13 ROP MWD FT/H 4 1 68 52 14 NPHI MWD PU-S 4 1 68 56 15 First Last Name Servi ce Unit Min Max Mean Nsam Reading Reading DEPT FT 3525 10271 6898 13493 3525 10271 CALA MWD INCH 10.18 14.32 12.3316 13289 3540 10184 FCNT MWD CNTS 548.07 3866.85 1073.61 13282 3540 10180.5 NCNT MWD CNTS 127381 225203 173250 13282 3540 10180.5 RHOB MWD G/CM 0.071 2.889 2.1515 13317 3540 10198 DRHO MWD G/CM -4.72 0.316 0.0555032 13317 3540 10198 RPD MWD OHMM 4.45 2000 16.5842 13376 3540 10227.5 RPM MWD OHMM 3.74 1258.18 15.6195 13376 3540 10227.5 RPS MWD OHMM 3.08 178.44 14.1407 13376 3540 10227.5 RPX MWD OHMM 2.63 77.6 11.2262 13376 3540 10227.5 FET MWD HOUR 0.1 100.94 0.779126 13376 3540 10227.5 GR MWD API 19.59 121.33 71.3661 13421 3525 10235 PEF MWD BARN -0.32 12.99 2.11335 13317 3540 10198 ROP MWD FT/H 3.35 1068.15 220.925 13420 3561.5 10271 NPHI MWD Pu-S 7.23 107.7 40.1111 13282. 3540 10180.5 First Reading For Entire File..........3525 Last Reading For Entire File...........10271 File Trailer Service name... .......STSLIB.001 service sub Level Name... version Number. ........1.0.0 Date of Generation.......07/05/25 Maximum Physical Record..65535 File Type ................L0 Next File Name...........STSLIB.002 Physical EOF File Header Page 4 t 1~16000313200755N.txt Service name... .......STSLIB.002 service sub Level Name... version Number. ........1.0.0 Date of Generation.......07/05/25 Maximum Physical Record..65535 File Type. ............LO Previous File Name.......STSLI6.001 Comment Record FILE HEADER FILE NUMBER: 2 RAW MWD curves and log header data for each bit run in separate files. BIT RUN NUMBER: 3 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 3525.0 10235.0 PEF 3540.0 10198.0 RPX 3540.0 10227.5 FET 3540.0 10227.5 RPS 3540.0 10227.5 NPHI 3540.0 10180.5 RPD 3540.0 10227.5 DRHO 3540.0 10198.0 RPM 3540.0 10227.5 RHOB 3540.0 10198.0 NCNT 3540.0 10180.5 FCNT 3540.0 10180.5 GALA 3540.0 10184.0 RoP 3561.5 10271.0 LOG HEADER DATA DATE LOGGED: 13-MAR-07 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 72.13 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 10271.0 TOP LOG INTERVAL (FT): 3560.0 BOTTOM LOG INTERVAL (FT): 10271.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 76.3 MAXIMUM ANGLE: 87.3 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 76571 EWR4 ELECTROMAG. RES IS. 4 78633 CTN COMP THERMAL NE UTRON 158416 ALD Azimuthal Litho -Dens 220637 ACAL Acoustic Calipe r 727406 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 12.250 DRILLER'S CASING DEPTH (FT): 3551.0 BOREHOLE CONDITIONS MUD TYPE: LSND Page 5 171600031320075SN.txt MUD DENSITY (LB/G): 9.10 MUD VISCOSITY (S): 60.0 MUD PH: 9.4 MUD CHLORIDES (PPM): 700 FLUID LOSS (C3): 5.6 RESISTIVITY (OHMM) AT TEMP ERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): 2.300 70.0 MUD AT MAX CIRCULATING TERMPERATURE : 1.430 116.6 MUD FILTRATE AT MT: 2.600 70.0 MUD CAKE AT MT: 3.000 70.0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format specification Record Data Record Type... ..... .....0 Data Specification Block Type .....0 Logging Direction.. ....... .....Down Optical log depth units...... .....Feet Data Reference Point ......... .....undefin ed Frame Spacing....... ....... .....60 .lIN Max frames per record ........ .....Undefin ed Absent value ................. .....-999 Depth Units. .. .. ..... Datum specification Block sub -type...0 Name service order units size Nsam Rep Code offset Channel DEPT FT 4 1 68 0 1 CALA MWD030 INCH 4 1 68 4 2 FCNT MWD030 CNTS 4 1 68 8 3 NCNT MWD030 CNTS 4 1 68 12 4 RHOB MWD030 G/CM 4 1 68 16 5 DRHO MWD030 G/CM 4 1 68 20 6 RPD MwD030 OHMM 4 1 68 24 7 RPM MWD030 OHMM 4 1 68 28 8 RPS MWD030 OHMM 4 1 68 32 9 RPX MWD030 OHMM 4 1 68 36 10 FET MWD030 HOUR 4 1 68 40 11 GR MwD030 API 4 1 68 44 12 PEF MwD030 BARN 4 1 68 48 13 ROP MwD030 FT/H 4 1 68 52 14 NPHI MWD030 Pu-S 4 1 68 56 15 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3525 10271 6898 13493 3525 10271 CALA MwD030 INCH 10.18 14.32 12.3316 13289 3540 10184 FONT MWD030 CNTS 548.07 3866.85 1073.61 13282 3540 10180.5 NCNT MWD030 CNTS 127381 225203 173250 13282 3540 10180.5 RHOB MWD030 G/CM 0.071 2.889 2.1515 13317 3540 10198 DRHO MWD030 G/CM -4.72 0.316 0 .0555032 13317 3540 10198 RPD MwD030 OHMM 4.45 2000 16.5842 13376 3540 10227.5 RPM MwD030 OHMM 3.74 1258.18 15.6195 13376 3540 10227.5 Page 6 i ~ 1~160003132007SSN.txt RPS MWD030 OHMM 3.08 178.44 14.1407 13376 3540 10227.5 RPX MWD030 OHMM 2.63 77.6 11.2262 13376 3540 10227.5 FET MWD030 HOUR 0.1 100.94 0.779126 13376 3540 10227.5 GR MWD030 API 19.59 121.33 71.3661 13421 3525 10235 PEF MWD030 BARN -0.32 12.99 2.11335 13317 3540 10198 ROP MWD030 FT/H 3.35 1068.15 220.925 13420 3561.5 10271 NPHI MWD030 Pu-s 7.23 107.7 40.1111 13282 3540 10180.5 First Reading For Entire File..........3525 Last Reading For Entire File...........10271 File Trailer Service name... .......STSLIB.002 service sub Level Name... version Number. ........1.0.0 Date of Generation.......07/05/25 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.003 Physical EoF Tape Trailer Service name .............LISTPE Date . ...................07/05/25 Origin ...................STS Tape Name. .... ........UNKNOWN Continuation Number......01 Next Tape Name...........UNKNOWN Comments .................STS LIS writing Library. Scientific Techni cal Services Reel Trailer Service name .............LISTPE Date . ...................07/05/25 Ori9in ...................STS Reel Name. .... ........UNKNOWN Continuation Number......01 Next Reel Name...........UNKNOWN Comments .................STS LIS Writing Library. Scientific Techni cal Services Physical EOF Physical EOF End Of LIS File Page 7
